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Public Act 099-0906 |
SB2814 Enrolled | LRB099 19990 EGJ 44389 b |
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AN ACT concerning regulation.
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Be it enacted by the People of the State of Illinois,
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represented in the General Assembly:
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Section 1. Findings.
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(a) In 2011, the General Assembly encouraged and enabled |
the State's largest electric utilities to undertake |
substantial investment to refurbish, rebuild, modernize, and |
expand Illinois' century-old electric grid. Among those |
investments were the deployment of a smart grid and advanced |
metering infrastructure platform that would be accessible to |
all retail customers through new, digital smart meters. This |
investment, now well underway, not only allows utilities to |
continue to provide safe, reliable, and affordable service to |
the State's current and future utility customers, but also |
empowers the citizens of this State to directly access and |
participate in the rapidly emerging clean energy economy while |
also presenting them with unprecedented choices in their source |
of energy supply and pricing. |
To ensure that the State and its citizens, including |
low-income citizens, are equipped to enjoy the opportunities |
and benefits of the smart grid and evolving clean energy |
marketplace, the General Assembly finds and declares that |
Illinois should continue in its efforts to build the grid of |
the future using the smart grid and advanced metering |
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infrastructure platform, as well as maximize the impact of the |
State's existing energy efficiency and renewable energy |
portfolio standards. Specifically, the Generally Assembly |
finds that:
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(1) the State should encourage: the adoption and |
deployment of cost-effective distributed energy resource |
technologies and devices, such as photovoltaics, which can |
encourage private investment in renewable energy |
resources, stimulate economic growth, enhance the |
continued diversification of Illinois' energy resource |
mix, and protect the Illinois environment; investment in |
renewable energy resources, including, but not limited to, |
photovoltaic distributed generation, which should benefit |
all citizens of the State, including low-income |
households;
and |
(2) the State's existing energy efficiency standard |
should be updated to ensure that customers continue to |
realize increased value, to incorporate and optimize |
measures enabled by the smart grid, including voltage |
optimization measures, and to provide incentives for |
electric utilities to achieve the energy savings goals.
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(b) The General
Assembly finds that low-income customers |
should be included
within the State's efforts to expand the use |
of distributed
generation technologies and devices. |
Section 1.5. Zero emission standard legislative findings. |
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The General Assembly finds and declares:
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(1) Reducing emissions of carbon dioxide and other air |
pollutants, such as sulfur oxides, nitrogen oxides, and |
particulate matter, is critical to improving air quality in |
Illinois for Illinois residents.
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(2) Sulfur oxides, nitrogen oxides, and particulate |
emissions have significant adverse health effects on |
persons exposed to them, and carbon dioxide emissions |
result in climate change trends that could significantly |
adversely impact Illinois.
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(3) The existing renewable portfolio standard has been |
successful in promoting the growth of renewable energy |
generation to reduce air pollution in Illinois. However, to |
achieve its environmental goals, Illinois must expand its |
commitment to zero emission energy generation and value the |
environmental attributes of zero emission generation that |
currently falls outside the scope of the existing renewable |
portfolio standard, including, but not limited to, nuclear |
power.
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(4) Preserving existing zero emission energy |
generation and promoting new zero emission energy |
generation is vital to placing the State on a glide path to |
achieving its environmental goals and ensuring that air |
quality in Illinois continues to improve.
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(5) The Illinois Commerce Commission, the Illinois |
Power Agency, the Illinois Environmental Protection |
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Agency, and the Department of Commerce and Economic |
Opportunity issued a report dated January 5, 2015 titled |
"Potential Nuclear Power Plant Closings in Illinois" (the |
Report), which addressed the issues identified by Illinois |
House Resolution 1146 of the 98th General Assembly, which, |
among other things, urged the Illinois Environmental |
Protection Agency to prepare a report showing how the |
premature closure of existing nuclear power plants in |
Illinois will affect the societal cost of increased |
greenhouse gas emissions based upon the Environmental |
Protection Agency's published societal cost of greenhouse |
gases.
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(6) The Report also included analysis from PJM |
Interconnection, LLC, which identified significant adverse |
consequences for electric reliability, including |
significant voltage and thermal violations in the |
interstate transmission network, in the event that |
Illinois' existing nuclear facilities close prematurely. |
The Report also found that nuclear power plants are among |
the most reliable sources of energy, which means that |
electricity from nuclear power plants is available on the |
electric grid all hours of the day and when needed, thereby |
always reducing carbon emissions.
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(7) Illinois House Resolution 1146 further urged that |
the Report make findings concerning potential market-based |
solutions that will ensure that the premature closure of |
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these nuclear power plants does not occur and that the |
associated dire consequences to the environment, electric |
reliability, and the regional economy are averted.
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(8) The Report identified potential market-based |
solutions that will ensure that the premature closure of |
these nuclear power plants does not occur and that the |
associated dire consequences to the environment, electric |
reliability, and the regional economy are averted.
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The General Assembly further finds that the Social Cost of |
Carbon is an appropriate valuation of the environmental |
benefits provided by zero emission facilities, provided that |
the valuation is subject to a price adjustment that can reduce |
the price for zero emission credits below the Social Cost of |
Carbon. This will ensure that the procurement of zero emission |
credits remains affordable for retail customers even if energy |
and capacity prices are projected to rise above 2016 levels |
reflected in the baseline market price index. |
The General Assembly therefore finds that it is necessary |
to establish and implement a zero emission standard, which will |
increase the State's reliance on zero emission energy through |
the procurement of zero emission credits from zero emission |
facilities, in order to achieve the State's environmental |
objectives and reduce the adverse impact of emitted air |
pollutants on the health and welfare of the State's citizens.
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Section 3. The Illinois Administrative Procedure Act is |
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amended by changing Section 5-45 as follows: |
(5 ILCS 100/5-45) (from Ch. 127, par. 1005-45) |
Sec. 5-45. Emergency rulemaking. |
(a) "Emergency" means the existence of any situation that |
any agency
finds reasonably constitutes a threat to the public |
interest, safety, or
welfare. |
(b) If any agency finds that an
emergency exists that |
requires adoption of a rule upon fewer days than
is required by |
Section 5-40 and states in writing its reasons for that
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finding, the agency may adopt an emergency rule without prior |
notice or
hearing upon filing a notice of emergency rulemaking |
with the Secretary of
State under Section 5-70. The notice |
shall include the text of the
emergency rule and shall be |
published in the Illinois Register. Consent
orders or other |
court orders adopting settlements negotiated by an agency
may |
be adopted under this Section. Subject to applicable |
constitutional or
statutory provisions, an emergency rule |
becomes effective immediately upon
filing under Section 5-65 or |
at a stated date less than 10 days
thereafter. The agency's |
finding and a statement of the specific reasons
for the finding |
shall be filed with the rule. The agency shall take
reasonable |
and appropriate measures to make emergency rules known to the
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persons who may be affected by them. |
(c) An emergency rule may be effective for a period of not |
longer than
150 days, but the agency's authority to adopt an |
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identical rule under Section
5-40 is not precluded. No |
emergency rule may be adopted more
than once in any 24-month 24 |
month period, except that this limitation on the number
of |
emergency rules that may be adopted in a 24-month 24 month |
period does not apply
to (i) emergency rules that make |
additions to and deletions from the Drug
Manual under Section |
5-5.16 of the Illinois Public Aid Code or the
generic drug |
formulary under Section 3.14 of the Illinois Food, Drug
and |
Cosmetic Act, (ii) emergency rules adopted by the Pollution |
Control
Board before July 1, 1997 to implement portions of the |
Livestock Management
Facilities Act, (iii) emergency rules |
adopted by the Illinois Department of Public Health under |
subsections (a) through (i) of Section 2 of the Department of |
Public Health Act when necessary to protect the public's |
health, (iv) emergency rules adopted pursuant to subsection (n) |
of this Section, (v) emergency rules adopted pursuant to |
subsection (o) of this Section, or (vi) emergency rules adopted |
pursuant to subsection (c-5) of this Section. Two or more |
emergency rules having substantially the same
purpose and |
effect shall be deemed to be a single rule for purposes of this
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Section. |
(c-5) To facilitate the maintenance of the program of group |
health benefits provided to annuitants, survivors, and retired |
employees under the State Employees Group Insurance Act of |
1971, rules to alter the contributions to be paid by the State, |
annuitants, survivors, retired employees, or any combination |
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of those entities, for that program of group health benefits, |
shall be adopted as emergency rules. The adoption of those |
rules shall be considered an emergency and necessary for the |
public interest, safety, and welfare. |
(d) In order to provide for the expeditious and timely |
implementation
of the State's fiscal year 1999 budget, |
emergency rules to implement any
provision of Public Act 90-587 |
or 90-588
or any other budget initiative for fiscal year 1999 |
may be adopted in
accordance with this Section by the agency |
charged with administering that
provision or initiative, |
except that the 24-month limitation on the adoption
of |
emergency rules and the provisions of Sections 5-115 and 5-125 |
do not apply
to rules adopted under this subsection (d). The |
adoption of emergency rules
authorized by this subsection (d) |
shall be deemed to be necessary for the
public interest, |
safety, and welfare. |
(e) In order to provide for the expeditious and timely |
implementation
of the State's fiscal year 2000 budget, |
emergency rules to implement any
provision of Public Act 91-24
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or any other budget initiative for fiscal year 2000 may be |
adopted in
accordance with this Section by the agency charged |
with administering that
provision or initiative, except that |
the 24-month limitation on the adoption
of emergency rules and |
the provisions of Sections 5-115 and 5-125 do not apply
to |
rules adopted under this subsection (e). The adoption of |
emergency rules
authorized by this subsection (e) shall be |
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deemed to be necessary for the
public interest, safety, and |
welfare. |
(f) In order to provide for the expeditious and timely |
implementation
of the State's fiscal year 2001 budget, |
emergency rules to implement any
provision of Public Act 91-712
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or any other budget initiative for fiscal year 2001 may be |
adopted in
accordance with this Section by the agency charged |
with administering that
provision or initiative, except that |
the 24-month limitation on the adoption
of emergency rules and |
the provisions of Sections 5-115 and 5-125 do not apply
to |
rules adopted under this subsection (f). The adoption of |
emergency rules
authorized by this subsection (f) shall be |
deemed to be necessary for the
public interest, safety, and |
welfare. |
(g) In order to provide for the expeditious and timely |
implementation
of the State's fiscal year 2002 budget, |
emergency rules to implement any
provision of Public Act 92-10
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or any other budget initiative for fiscal year 2002 may be |
adopted in
accordance with this Section by the agency charged |
with administering that
provision or initiative, except that |
the 24-month limitation on the adoption
of emergency rules and |
the provisions of Sections 5-115 and 5-125 do not apply
to |
rules adopted under this subsection (g). The adoption of |
emergency rules
authorized by this subsection (g) shall be |
deemed to be necessary for the
public interest, safety, and |
welfare. |
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(h) In order to provide for the expeditious and timely |
implementation
of the State's fiscal year 2003 budget, |
emergency rules to implement any
provision of Public Act 92-597
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or any other budget initiative for fiscal year 2003 may be |
adopted in
accordance with this Section by the agency charged |
with administering that
provision or initiative, except that |
the 24-month limitation on the adoption
of emergency rules and |
the provisions of Sections 5-115 and 5-125 do not apply
to |
rules adopted under this subsection (h). The adoption of |
emergency rules
authorized by this subsection (h) shall be |
deemed to be necessary for the
public interest, safety, and |
welfare. |
(i) In order to provide for the expeditious and timely |
implementation
of the State's fiscal year 2004 budget, |
emergency rules to implement any
provision of Public Act 93-20
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or any other budget initiative for fiscal year 2004 may be |
adopted in
accordance with this Section by the agency charged |
with administering that
provision or initiative, except that |
the 24-month limitation on the adoption
of emergency rules and |
the provisions of Sections 5-115 and 5-125 do not apply
to |
rules adopted under this subsection (i). The adoption of |
emergency rules
authorized by this subsection (i) shall be |
deemed to be necessary for the
public interest, safety, and |
welfare. |
(j) In order to provide for the expeditious and timely |
implementation of the provisions of the State's fiscal year |
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2005 budget as provided under the Fiscal Year 2005 Budget |
Implementation (Human Services) Act, emergency rules to |
implement any provision of the Fiscal Year 2005 Budget |
Implementation (Human Services) Act may be adopted in |
accordance with this Section by the agency charged with |
administering that provision, except that the 24-month |
limitation on the adoption of emergency rules and the |
provisions of Sections 5-115 and 5-125 do not apply to rules |
adopted under this subsection (j). The Department of Public Aid |
may also adopt rules under this subsection (j) necessary to |
administer the Illinois Public Aid Code and the Children's |
Health Insurance Program Act. The adoption of emergency rules |
authorized by this subsection (j) shall be deemed to be |
necessary for the public interest, safety, and welfare.
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(k) In order to provide for the expeditious and timely |
implementation of the provisions of the State's fiscal year |
2006 budget, emergency rules to implement any provision of |
Public Act 94-48 or any other budget initiative for fiscal year |
2006 may be adopted in accordance with this Section by the |
agency charged with administering that provision or |
initiative, except that the 24-month limitation on the adoption |
of emergency rules and the provisions of Sections 5-115 and |
5-125 do not apply to rules adopted under this subsection (k). |
The Department of Healthcare and Family Services may also adopt |
rules under this subsection (k) necessary to administer the |
Illinois Public Aid Code, the Senior Citizens and Persons with |
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Disabilities Property Tax Relief Act, the Senior Citizens and |
Disabled Persons Prescription Drug Discount Program Act (now |
the Illinois Prescription Drug Discount Program Act), and the |
Children's Health Insurance Program Act. The adoption of |
emergency rules authorized by this subsection (k) shall be |
deemed to be necessary for the public interest, safety, and |
welfare.
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(l) In order to provide for the expeditious and timely |
implementation of the provisions of the
State's fiscal year |
2007 budget, the Department of Healthcare and Family Services |
may adopt emergency rules during fiscal year 2007, including |
rules effective July 1, 2007, in
accordance with this |
subsection to the extent necessary to administer the |
Department's responsibilities with respect to amendments to |
the State plans and Illinois waivers approved by the federal |
Centers for Medicare and Medicaid Services necessitated by the |
requirements of Title XIX and Title XXI of the federal Social |
Security Act. The adoption of emergency rules
authorized by |
this subsection (l) shall be deemed to be necessary for the |
public interest,
safety, and welfare.
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(m) In order to provide for the expeditious and timely |
implementation of the provisions of the
State's fiscal year |
2008 budget, the Department of Healthcare and Family Services |
may adopt emergency rules during fiscal year 2008, including |
rules effective July 1, 2008, in
accordance with this |
subsection to the extent necessary to administer the |
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Department's responsibilities with respect to amendments to |
the State plans and Illinois waivers approved by the federal |
Centers for Medicare and Medicaid Services necessitated by the |
requirements of Title XIX and Title XXI of the federal Social |
Security Act. The adoption of emergency rules
authorized by |
this subsection (m) shall be deemed to be necessary for the |
public interest,
safety, and welfare.
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(n) In order to provide for the expeditious and timely |
implementation of the provisions of the State's fiscal year |
2010 budget, emergency rules to implement any provision of |
Public Act 96-45 or any other budget initiative authorized by |
the 96th General Assembly for fiscal year 2010 may be adopted |
in accordance with this Section by the agency charged with |
administering that provision or initiative. The adoption of |
emergency rules authorized by this subsection (n) shall be |
deemed to be necessary for the public interest, safety, and |
welfare. The rulemaking authority granted in this subsection |
(n) shall apply only to rules promulgated during Fiscal Year |
2010. |
(o) In order to provide for the expeditious and timely |
implementation of the provisions of the State's fiscal year |
2011 budget, emergency rules to implement any provision of |
Public Act 96-958 or any other budget initiative authorized by |
the 96th General Assembly for fiscal year 2011 may be adopted |
in accordance with this Section by the agency charged with |
administering that provision or initiative. The adoption of |
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emergency rules authorized by this subsection (o) is deemed to |
be necessary for the public interest, safety, and welfare. The |
rulemaking authority granted in this subsection (o) applies |
only to rules promulgated on or after July 1, 2010 ( the |
effective date of Public Act 96-958 ) through June 30, 2011. |
(p) In order to provide for the expeditious and timely |
implementation of the provisions of Public Act 97-689, |
emergency rules to implement any provision of Public Act 97-689 |
may be adopted in accordance with this subsection (p) by the |
agency charged with administering that provision or |
initiative. The 150-day limitation of the effective period of |
emergency rules does not apply to rules adopted under this |
subsection (p), and the effective period may continue through |
June 30, 2013. The 24-month limitation on the adoption of |
emergency rules does not apply to rules adopted under this |
subsection (p). The adoption of emergency rules authorized by |
this subsection (p) is deemed to be necessary for the public |
interest, safety, and welfare. |
(q) In order to provide for the expeditious and timely |
implementation of the provisions of Articles 7, 8, 9, 11, and |
12 of Public Act 98-104, emergency rules to implement any |
provision of Articles 7, 8, 9, 11, and 12 of Public Act 98-104 |
may be adopted in accordance with this subsection (q) by the |
agency charged with administering that provision or |
initiative. The 24-month limitation on the adoption of |
emergency rules does not apply to rules adopted under this |
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subsection (q). The adoption of emergency rules authorized by |
this subsection (q) is deemed to be necessary for the public |
interest, safety, and welfare. |
(r) In order to provide for the expeditious and timely |
implementation of the provisions of Public Act 98-651, |
emergency rules to implement Public Act 98-651 may be adopted |
in accordance with this subsection (r) by the Department of |
Healthcare and Family Services. The 24-month limitation on the |
adoption of emergency rules does not apply to rules adopted |
under this subsection (r). The adoption of emergency rules |
authorized by this subsection (r) is deemed to be necessary for |
the public interest, safety, and welfare. |
(s) In order to provide for the expeditious and timely |
implementation of the provisions of Sections 5-5b.1 and 5A-2 of |
the Illinois Public Aid Code, emergency rules to implement any |
provision of Section 5-5b.1 or Section 5A-2 of the Illinois |
Public Aid Code may be adopted in accordance with this |
subsection (s) by the Department of Healthcare and Family |
Services. The rulemaking authority granted in this subsection |
(s) shall apply only to those rules adopted prior to July 1, |
2015. Notwithstanding any other provision of this Section, any |
emergency rule adopted under this subsection (s) shall only |
apply to payments made for State fiscal year 2015. The adoption |
of emergency rules authorized by this subsection (s) is deemed |
to be necessary for the public interest, safety, and welfare. |
(t) In order to provide for the expeditious and timely |
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implementation of the provisions of Article II of Public Act |
99-6, emergency rules to implement the changes made by Article |
II of Public Act 99-6 to the Emergency Telephone System Act may |
be adopted in accordance with this subsection (t) by the |
Department of State Police. The rulemaking authority granted in |
this subsection (t) shall apply only to those rules adopted |
prior to July 1, 2016. The 24-month limitation on the adoption |
of emergency rules does not apply to rules adopted under this |
subsection (t). The adoption of emergency rules authorized by |
this subsection (t) is deemed to be necessary for the public |
interest, safety, and welfare. |
(u) In order to provide for the expeditious and timely |
implementation of the provisions of the Burn Victims Relief |
Act, emergency rules to implement any provision of the Act may |
be adopted in accordance with this subsection (u) by the |
Department of Insurance. The rulemaking authority granted in |
this subsection (u) shall apply only to those rules adopted |
prior to December 31, 2015. The adoption of emergency rules |
authorized by this subsection (u) is deemed to be necessary for |
the public interest, safety, and welfare. |
(v) In order to provide for the expeditious and timely |
implementation of the provisions of Public Act 99-516 this |
amendatory Act of the 99th General Assembly , emergency rules to |
implement Public Act 99-516 this amendatory Act of the 99th |
General Assembly may be adopted in accordance with this |
subsection (v) by the Department of Healthcare and Family |
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Services. The 24-month limitation on the adoption of emergency |
rules does not apply to rules adopted under this subsection |
(v). The adoption of emergency rules authorized by this |
subsection (v) is deemed to be necessary for the public |
interest, safety, and welfare. |
(w) (v) In order to provide for the expeditious and timely |
implementation of the provisions of Public Act 99-796 this |
amendatory Act of the 99th General Assembly , emergency rules to |
implement the changes made by Public Act 99-796 this amendatory |
Act of the 99th General Assembly may be adopted in accordance |
with this subsection (w) (v) by the Adjutant General. The |
adoption of emergency rules authorized by this subsection (w) |
(v) is deemed to be necessary for the public interest, safety, |
and welfare. |
(x) In order to provide for the expeditious and timely |
implementation of the provisions of this amendatory Act of the |
99th General Assembly, emergency rules to implement subsection |
(i) of Section 16-115D, subsection (g) of Section 16-128A, and |
subsection (a) of Section 16-128B of the Public Utilities Act |
may be adopted in accordance with this subsection (x) by the |
Illinois Commerce Commission. The rulemaking authority granted |
in this subsection (x) shall apply only to those rules adopted |
within 180 days after the effective date of this amendatory Act |
of the 99th General Assembly. The adoption of emergency rules |
authorized by this subsection (x) is deemed to be necessary for |
the public interest, safety, and welfare. |
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(Source: P.A. 98-104, eff. 7-22-13; 98-463, eff. 8-16-13; |
98-651, eff. 6-16-14; 99-2, eff. 3-26-15; 99-6, eff. 1-1-16; |
99-143, eff. 7-27-15; 99-455, eff. 1-1-16; 99-516, eff. |
6-30-16; 99-642, eff. 7-28-16; 99-796, eff. 1-1-17; revised |
9-21-16.) |
Section 5. The Illinois Power Agency Act is amended by |
changing Sections 1-5, 1-10, 1-20, 1-25, 1-56, and 1-75 as |
follows: |
(20 ILCS 3855/1-5) |
Sec. 1-5. Legislative declarations and findings. The |
General Assembly finds and declares: |
(1) The health, welfare, and prosperity of all Illinois |
citizens require the provision of adequate, reliable, |
affordable, efficient, and environmentally sustainable |
electric service at the lowest total cost over time, taking |
into account any benefits of price stability. |
(2) (Blank). The transition to retail competition is |
not complete. Some customers, especially residential and |
small commercial customers, have failed to benefit from |
lower electricity costs from retail and wholesale |
competition. |
(3) (Blank). Escalating prices for electricity in |
Illinois pose a serious threat to the economic well-being, |
health, and safety of the residents of and the commerce and |
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industry of the State. |
(4) It To protect against this threat to economic |
well-being, health, and safety it is necessary to improve |
the process of procuring electricity to serve Illinois |
residents, to promote investment in energy efficiency and |
demand-response measures, and to maintain and support |
development of clean coal technologies , generation |
resources that operate at all hours of the day and under |
all weather conditions, zero emission facilities, and |
renewable resources. |
(5) Procuring a diverse electricity supply portfolio |
will ensure the lowest total cost over time for adequate, |
reliable, efficient, and environmentally sustainable |
electric service. |
(6) Including cost-effective renewable resources and |
zero emission credits from zero emission facilities in that |
portfolio will reduce long-term direct and indirect costs |
to consumers by decreasing environmental impacts and by |
avoiding or delaying the need for new generation, |
transmission, and distribution infrastructure. Developing |
new renewable energy resources in Illinois, including |
brownfield solar projects and community solar projects, |
will help to diversify Illinois electricity supply, avoid |
and reduce pollution, reduce peak demand, and enhance |
public health and well-being of Illinois residents. |
(7) Developing community solar projects in Illinois |
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will help to expand access to renewable energy resources to |
more Illinois residents. |
(8) Developing brownfield solar projects in Illinois |
will help return blighted or contaminated land to |
productive use while enhancing public health and the |
well-being of Illinois residents. |
(9) (7) Energy efficiency, demand-response measures, |
zero emission energy, and renewable energy are resources |
currently underused in Illinois. These resources should be |
used, when cost effective, to reduce costs to consumers, |
improve reliability, and improve environmental quality and |
public health. |
(10) (8) The State should encourage the use of advanced |
clean coal technologies that capture and sequester carbon |
dioxide emissions to advance environmental protection |
goals and to demonstrate the viability of coal and |
coal-derived fuels in a carbon-constrained economy. |
(11) (9) The General Assembly enacted Public Act |
96-0795 to reform the State's purchasing processes, |
recognizing that government procurement is susceptible to |
abuse if structural and procedural safeguards are not in |
place to ensure independence, insulation, oversight, and |
transparency. |
(12) (10) The principles that underlie the procurement |
reform legislation apply also in the context of power |
purchasing. |
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The General Assembly therefore finds that it is necessary |
to create the Illinois Power Agency and that the goals and |
objectives of that Agency are to accomplish each of the |
following: |
(A) Develop electricity procurement plans to ensure |
adequate, reliable, affordable, efficient, and |
environmentally sustainable electric service at the lowest |
total cost over time, taking into account any benefits of |
price stability, for electric utilities that on December |
31, 2005 provided electric service to at least 100,000 |
customers in Illinois and for small multi-jurisdictional |
electric utilities that (i) on December 31, 2005 served |
less than 100,000 customers in Illinois and (ii) request a |
procurement plan for their Illinois jurisdictional load. |
The procurement plan shall be updated on an annual basis |
and shall include renewable energy resources and, |
beginning with the delivery year commencing June 1, 2017, |
zero emission credits from zero emission facilities |
sufficient to achieve the standards specified in this Act. |
(B) Conduct the competitive procurement processes |
identified in this Act to procure the supply resources |
identified in the procurement plan . |
(C) Develop electric generation and co-generation |
facilities that use indigenous coal or renewable |
resources, or both, financed with bonds issued by the |
Illinois Finance Authority. |
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(D) Supply electricity from the Agency's facilities at |
cost to one or more of the following: municipal electric |
systems, governmental aggregators, or rural electric |
cooperatives in Illinois.
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(E) Ensure that the process of power procurement is |
conducted in an ethical and transparent fashion, immune |
from improper influence. |
(F) Continue to review its policies and practices to |
determine how best to meet its mission of providing the |
lowest cost power to the greatest number of people, at any |
given point in time, in accordance with applicable law. |
(G) Operate in a structurally insulated, independent, |
and transparent fashion so that nothing impedes the |
Agency's mission to secure power at the best prices the |
market will bear, provided that the Agency meets all |
applicable legal requirements. |
(H) Implement renewable energy procurement and |
training programs throughout the State to diversify |
Illinois electricity supply, improve reliability, avoid |
and reduce pollution, reduce peak demand, and enhance |
public health and well-being of Illinois residents, |
including low-income residents. |
(Source: P.A. 97-325, eff. 8-12-11; 97-618, eff. 10-26-11; |
97-813, eff. 7-13-12.)
|
(20 ILCS 3855/1-10)
|
|
Sec. 1-10. Definitions. |
"Agency" means the Illinois Power Agency. |
"Agency loan agreement" means any agreement pursuant to |
which the Illinois Finance Authority agrees to loan the |
proceeds of revenue bonds issued with respect to a project to |
the Agency upon terms providing for loan repayment installments |
at least sufficient to pay when due all principal of, interest |
and premium, if any, on those revenue bonds, and providing for |
maintenance, insurance, and other matters in respect of the |
project. |
"Authority" means the Illinois Finance Authority. |
"Brownfield site photovoltaic project" means photovoltaics |
that are: |
(1) interconnected to an electric utility as defined in |
this Section, a municipal utility as defined in this |
Section, a public utility as defined in Section 3-105 of |
the Public Utilities Act, or an electric cooperative, as |
defined in Section 3-119 of the Public Utilities Act; and |
(2) located at a site that is regulated by any of the |
following entities under the following programs: |
(A) the United States Environmental Protection |
Agency under the federal Comprehensive Environmental |
Response, Compensation, and Liability Act of 1980, as |
amended; |
(B) the United States Environmental Protection |
Agency under the Corrective Action Program of the |
|
federal Resource Conservation and Recovery Act, as |
amended; |
(C) the Illinois Environmental Protection Agency |
under the Illinois Site Remediation Program; or |
(D) the Illinois Environmental Protection Agency |
under the Illinois Solid Waste Program. |
"Clean coal facility" means an electric generating |
facility that uses primarily coal as a feedstock and that |
captures and sequesters carbon dioxide emissions at the |
following levels: at least 50% of the total carbon dioxide |
emissions that the facility would otherwise emit if, at the |
time construction commences, the facility is scheduled to |
commence operation before 2016, at least 70% of the total |
carbon dioxide emissions that the facility would otherwise emit |
if, at the time construction commences, the facility is |
scheduled to commence operation during 2016 or 2017, and at |
least 90% of the total carbon dioxide emissions that the |
facility would otherwise emit if, at the time construction |
commences, the facility is scheduled to commence operation |
after 2017. The power block of the clean coal facility shall |
not exceed allowable emission rates for sulfur dioxide, |
nitrogen oxides, carbon monoxide, particulates and mercury for |
a natural gas-fired combined-cycle facility the same size as |
and in the same location as the clean coal facility at the time |
the clean coal facility obtains an approved air permit. All |
coal used by a clean coal facility shall have high volatile |
|
bituminous rank and greater than 1.7 pounds of sulfur per |
million btu content, unless the clean coal facility does not |
use gasification technology and was operating as a conventional |
coal-fired electric generating facility on June 1, 2009 (the |
effective date of Public Act 95-1027). |
"Clean coal SNG brownfield facility" means a facility that |
(1) has commenced construction by July 1, 2015 on an urban |
brownfield site in a municipality with at least 1,000,000 |
residents; (2) uses a gasification process to produce |
substitute natural gas; (3) uses coal as at least 50% of the |
total feedstock over the term of any sourcing agreement with a |
utility and the remainder of the feedstock may be either |
petroleum coke or coal, with all such coal having a high |
bituminous rank and greater than 1.7 pounds of sulfur per |
million Btu content unless the facility reasonably determines
|
that it is necessary to use additional petroleum coke to
|
deliver additional consumer savings, in which case the
facility |
shall use coal for at least 35% of the total
feedstock over the |
term of any sourcing agreement; and (4) captures and sequesters |
at least 85% of the total carbon dioxide emissions that the |
facility would otherwise emit. |
"Clean coal SNG facility" means a facility that uses a |
gasification process to produce substitute natural gas, that |
sequesters at least 90% of the total carbon dioxide emissions |
that the facility would otherwise emit, that uses at least 90% |
coal as a feedstock, with all such coal having a high |
|
bituminous rank and greater than 1.7 pounds of sulfur per |
million btu content, and that has a valid and effective permit |
to construct emission sources and air pollution control |
equipment and approval with respect to the federal regulations |
for Prevention of Significant Deterioration of Air Quality |
(PSD) for the plant pursuant to the federal Clean Air Act; |
provided, however, a clean coal SNG brownfield facility shall |
not be a clean coal SNG facility. |
"Commission" means the Illinois Commerce Commission. |
"Community renewable generation project" means an electric |
generating facility that: |
(1) is powered by wind, solar thermal energy, |
photovoltaic cells or panels, biodiesel, crops and |
untreated and unadulterated organic waste biomass, tree |
waste, and hydropower that does not involve new |
construction or significant expansion of hydropower dams; |
(2) is interconnected at the distribution system level |
of an electric utility as defined in this Section, a |
municipal utility as defined in this Section that owns or |
operates electric distribution facilities, a public |
utility as defined in Section 3-105 of the Public Utilities |
Act, or an electric cooperative, as defined in Section |
3-119 of the Public Utilities Act; |
(3) credits the value of electricity generated by the |
facility to the subscribers of the facility; and |
(4) is limited in nameplate capacity to less than or |
|
equal to 2,000 kilowatts. |
"Costs incurred in connection with the development and |
construction of a facility" means: |
(1) the cost of acquisition of all real property, |
fixtures, and improvements in connection therewith and |
equipment, personal property, and other property, rights, |
and easements acquired that are deemed necessary for the |
operation and maintenance of the facility; |
(2) financing costs with respect to bonds, notes, and |
other evidences of indebtedness of the Agency; |
(3) all origination, commitment, utilization, |
facility, placement, underwriting, syndication, credit |
enhancement, and rating agency fees; |
(4) engineering, design, procurement, consulting, |
legal, accounting, title insurance, survey, appraisal, |
escrow, trustee, collateral agency, interest rate hedging, |
interest rate swap, capitalized interest, contingency, as |
required by lenders, and other financing costs, and other |
expenses for professional services; and |
(5) the costs of plans, specifications, site study and |
investigation, installation, surveys, other Agency costs |
and estimates of costs, and other expenses necessary or |
incidental to determining the feasibility of any project, |
together with such other expenses as may be necessary or |
incidental to the financing, insuring, acquisition, and |
construction of a specific project and starting up, |
|
commissioning, and placing that project in operation. |
"Delivery services" has the same definition as found in |
Section 16-102 of the Public Utilities Act. |
"Delivery year" means the consecutive 12-month period |
beginning June 1 of a given year and ending May 31 of the |
following year. |
"Department" means the Department of Commerce and Economic |
Opportunity. |
"Director" means the Director of the Illinois Power Agency. |
"Demand-response" means measures that decrease peak |
electricity demand or shift demand from peak to off-peak |
periods. |
"Distributed renewable energy generation device" means a |
device that is: |
(1) powered by wind, solar thermal energy, |
photovoltaic cells or and panels, biodiesel, crops and |
untreated and unadulterated organic waste biomass, tree |
waste, and hydropower that does not involve new |
construction or significant expansion of hydropower dams; |
(2) interconnected at the distribution system level of |
either an electric utility as defined in this Section, an |
alternative retail electric supplier as defined in Section |
16-102 of the Public Utilities Act, a municipal utility as |
defined in this Section that owns or operates electric |
distribution facilities 3-105 of the Public Utilities Act , |
or a rural electric cooperative as defined in Section 3-119 |
|
of the Public Utilities Act; |
(3) located on the customer side of the customer's |
electric meter and is primarily used to offset that |
customer's electricity load; and |
(4) limited in nameplate capacity to less than or equal |
to no more than 2,000 kilowatts. |
"Energy efficiency" means measures that reduce the amount |
of electricity or natural gas consumed in order required to |
achieve a given end use. "Energy efficiency" includes voltage |
optimization measures that optimize the voltage at points on |
the electric distribution voltage system and thereby reduce |
electricity consumption by electric customers' end use |
devices. "Energy efficiency" also includes measures that |
reduce the total Btus of electricity , and natural gas , and |
other fuels needed to meet the end use or uses. |
"Electric utility" has the same definition as found in |
Section 16-102 of the Public Utilities Act. |
"Facility" means an electric generating unit or a |
co-generating unit that produces electricity along with |
related equipment necessary to connect the facility to an |
electric transmission or distribution system. |
"Governmental aggregator" means one or more units of local |
government that individually or collectively procure |
electricity to serve residential retail electrical loads |
located within its or their jurisdiction. |
"Local government" means a unit of local government as |
|
defined in Section 1 of Article VII of the Illinois |
Constitution. |
"Municipality" means a city, village, or incorporated |
town. |
"Municipal utility" means a public utility owned and |
operated by any subdivision or municipal corporation of this |
State. |
"Nameplate capacity" means the aggregate inverter |
nameplate capacity in kilowatts AC. |
"Person" means any natural person, firm, partnership, |
corporation, either domestic or foreign, company, association, |
limited liability company, joint stock company, or association |
and includes any trustee, receiver, assignee, or personal |
representative thereof. |
"Project" means the planning, bidding, and construction of |
a facility. |
"Public utility" has the same definition as found in |
Section 3-105 of the Public Utilities Act. |
"Real property" means any interest in land together with |
all structures, fixtures, and improvements thereon, including |
lands under water and riparian rights, any easements, |
covenants, licenses, leases, rights-of-way, uses, and other |
interests, together with any liens, judgments, mortgages, or |
other claims or security interests related to real property. |
"Renewable energy credit" means a tradable credit that |
represents the environmental attributes of one megawatt hour a |
|
certain amount of energy produced from a renewable energy |
resource. |
"Renewable energy resources" includes energy and its |
associated renewable energy credit or renewable energy credits |
from wind, solar thermal energy, photovoltaic cells and panels, |
biodiesel, anaerobic digestion, crops and untreated and |
unadulterated organic waste biomass, tree waste, and |
hydropower that does not involve new construction or |
significant expansion of hydropower dams , and other |
alternative sources of environmentally preferable energy . For |
purposes of this Act, landfill gas produced in the State is |
considered a renewable energy resource. "Renewable energy |
resources" does not include the incineration or burning of |
tires, garbage, general household, institutional, and |
commercial waste, industrial lunchroom or office waste, |
landscape waste other than tree waste, railroad crossties, |
utility poles, or construction or demolition debris, other than |
untreated and unadulterated waste wood. |
"Retail customer" has the same definition as found in |
Section 16-102 of the Public Utilities Act. |
"Revenue bond" means any bond, note, or other evidence of |
indebtedness issued by the Authority, the principal and |
interest of which is payable solely from revenues or income |
derived from any project or activity of the Agency. |
"Sequester" means permanent storage of carbon dioxide by |
injecting it into a saline aquifer, a depleted gas reservoir, |
|
or an oil reservoir, directly or through an enhanced oil |
recovery process that may involve intermediate storage, |
regardless of whether these activities are conducted by a clean |
coal facility, a clean coal SNG facility, a clean coal SNG |
brownfield facility, or a party with which a clean coal |
facility, clean coal SNG facility, or clean coal SNG brownfield |
facility has contracted for such purposes. |
"Service area" has the same definition as found in Section |
16-102 of the Public Utilities Act. |
"Sourcing agreement" means (i) in the case of an electric |
utility, an agreement between the owner of a clean coal |
facility and such electric utility, which agreement shall have |
terms and conditions meeting the requirements of paragraph (3) |
of subsection (d) of Section 1-75, (ii) in the case of an |
alternative retail electric supplier, an agreement between the |
owner of a clean coal facility and such alternative retail |
electric supplier, which agreement shall have terms and |
conditions meeting the requirements of Section 16-115(d)(5) of |
the Public Utilities Act, and (iii) in case of a gas utility, |
an agreement between the owner of a clean coal SNG brownfield |
facility and the gas utility, which agreement shall have the |
terms and conditions meeting the requirements of subsection |
(h-1) of Section 9-220 of the Public Utilities Act. |
"Subscriber" means a person who (i) takes delivery service |
from an electric utility, and (ii) has a subscription of no |
less than 200 watts to a community renewable generation project |
|
that is located in the electric utility's service area. No |
subscriber's subscriptions may total more than 40% of the |
nameplate capacity of an individual community renewable |
generation project. Entities that are affiliated by virtue of a |
common parent shall not represent multiple subscriptions that |
total more than 40% of the nameplate capacity of an individual |
community renewable generation project. |
"Subscription" means an interest in a community renewable |
generation project expressed in kilowatts, which is sized |
primarily to offset part or all of the subscriber's electricity |
usage. |
"Substitute natural gas" or "SNG" means a gas manufactured |
by gasification of hydrocarbon feedstock, which is |
substantially interchangeable in use and distribution with |
conventional natural gas.
|
"Total resource cost test" or "TRC test" means a standard |
that is met if, for an investment in energy efficiency or |
demand-response measures, the benefit-cost ratio is greater |
than one. The benefit-cost ratio is the ratio of the net |
present value of the total benefits of the program to the net |
present value of the total costs as calculated over the |
lifetime of the measures. A total resource cost test compares |
the sum of avoided electric utility costs, representing the |
benefits that accrue to the system and the participant in the |
delivery of those efficiency measures and including avoided |
costs associated with reduced use of natural gas or other |
|
fuels, avoided costs associated with reduced water |
consumption, and avoided costs associated with reduced |
operation and maintenance costs , as well as other quantifiable |
societal benefits, including avoided natural gas utility |
costs, to the sum of all incremental costs of end-use measures |
that are implemented due to the program (including both utility |
and participant contributions), plus costs to administer, |
deliver, and evaluate each demand-side program, to quantify the |
net savings obtained by substituting the demand-side program |
for supply resources. In calculating avoided costs of power and |
energy that an electric utility would otherwise have had to |
acquire, reasonable estimates shall be included of financial |
costs likely to be imposed by future regulations and |
legislation on emissions of greenhouse gases. In discounting |
future societal costs and benefits for the purpose of |
calculating net present values, a societal discount rate based |
on actual, long-term Treasury bond yields should be used. |
Notwithstanding anything to the contrary, the TRC test shall |
not include or take into account a calculation of market price |
suppression effects or demand reduction induced price effects. |
"Utility-scale solar project" means an electric generating |
facility that: |
(1) generates electricity using photovoltaic cells; |
and |
(2) has a nameplate capacity that is greater than 2,000 |
kilowatts. |
|
"Utility-scale wind project" means an electric generating |
facility that: |
(1) generates electricity using wind; and |
(2) has a nameplate capacity that is greater than 2,000 |
kilowatts. |
"Zero emission credit" means a tradable credit that |
represents the environmental attributes of one megawatt hour of |
energy produced from a zero emission facility. |
"Zero emission facility" means a facility that: (1) is |
fueled by nuclear power; and (2) is interconnected with PJM |
Interconnection, LLC or the Midcontinent Independent System |
Operator, Inc., or their successors. |
(Source: P.A. 97-96, eff. 7-13-11; 97-239, eff. 8-2-11; 97-491, |
eff. 8-22-11; 97-616, eff. 10-26-11; 97-813, eff. 7-13-12; |
98-90, eff. 7-15-13.)
|
(20 ILCS 3855/1-20)
|
Sec. 1-20. General powers of the Agency. |
(a) The Agency is authorized to do each of the following: |
(1) Develop electricity procurement plans to ensure |
adequate, reliable, affordable, efficient, and |
environmentally sustainable electric service at the lowest |
total cost over time, taking into account any benefits of |
price stability, for electric utilities that on December |
31, 2005 provided electric service to at least 100,000 |
customers in Illinois and for small multi-jurisdictional |
|
electric utilities that (A) on December 31, 2005 served |
less than 100,000 customers in Illinois and (B) request a |
procurement plan for their Illinois jurisdictional load. |
Except as provided in paragraph (1.5) of this subsection |
(a), the electricity The procurement plans shall be updated |
on an annual basis and shall include electricity generated |
from renewable resources sufficient to achieve the |
standards specified in this Act. Beginning with the |
delivery year commencing June 1, 2017, develop procurement |
plans to include zero emission credits generated from zero |
emission facilities sufficient to achieve the standards |
specified in this Act. |
(1.5) Develop a long-term renewable resources |
procurement plan in accordance with subsection (c) of |
Section 1-75 of this Act for renewable energy credits in |
amounts sufficient to achieve the standards specified in |
this Act for delivery years commencing June 1, 2017 and for |
the programs and renewable energy credits specified in |
Section 1-56 of this Act. Electricity procurement plans for |
delivery years commencing after May 31, 2017, shall not |
include procurement of renewable energy resources. |
(2) Conduct competitive procurement processes to |
procure the supply resources identified in the electricity |
procurement plan, pursuant to Section 16-111.5 of the |
Public Utilities Act , and, for the delivery year commencing |
June 1, 2017, conduct procurement processes to procure zero |
|
emission credits from zero emission facilities, under |
subsection (d-5) of Section 1-75 of this Act . |
(2.5) Beginning with the procurement for the 2017 |
delivery year, conduct competitive procurement processes |
and implement programs to procure renewable energy credits |
identified in the long-term renewable resources |
procurement plan developed and approved under subsection |
(c) of Section 1-75 of this Act and Section 16-111.5 of the |
Public Utilities Act. |
(3) Develop electric generation and co-generation |
facilities that use indigenous coal or renewable |
resources, or both, financed with bonds issued by the |
Illinois Finance Authority. |
(4) Supply electricity from the Agency's facilities at |
cost to one or more of the following: municipal electric |
systems, governmental aggregators, or rural electric |
cooperatives in Illinois. |
(b) Except as otherwise limited by this Act, the Agency has |
all of the powers necessary or convenient to carry out the |
purposes and provisions of this Act, including without |
limitation, each of the following: |
(1) To have a corporate seal, and to alter that seal at |
pleasure, and to use it by causing it or a facsimile to be |
affixed or impressed or reproduced in any other manner. |
(2) To use the services of the Illinois Finance |
Authority necessary to carry out the Agency's purposes. |
|
(3) To negotiate and enter into loan agreements and |
other agreements with the Illinois Finance Authority. |
(4) To obtain and employ personnel and hire consultants |
that are necessary to fulfill the Agency's purposes, and to |
make expenditures for that purpose within the |
appropriations for that purpose. |
(5) To purchase, receive, take by grant, gift, devise, |
bequest, or otherwise, lease, or otherwise acquire, own, |
hold, improve, employ, use, and otherwise deal in and with, |
real or personal property whether tangible or intangible, |
or any interest therein, within the State. |
(6) To acquire real or personal property, whether |
tangible or intangible, including without limitation |
property rights, interests in property, franchises, |
obligations, contracts, and debt and equity securities, |
and to do so by the exercise of the power of eminent domain |
in accordance with Section 1-21; except that any real |
property acquired by the exercise of the power of eminent |
domain must be located within the State. |
(7) To sell, convey, lease, exchange, transfer, |
abandon, or otherwise dispose of, or mortgage, pledge, or |
create a security interest in, any of its assets, |
properties, or any interest therein, wherever situated. |
(8) To purchase, take, receive, subscribe for, or |
otherwise acquire, hold, make a tender offer for, vote, |
employ, sell, lend, lease, exchange, transfer, or |
|
otherwise dispose of, mortgage, pledge, or grant a security |
interest in, use, and otherwise deal in and with, bonds and |
other obligations, shares, or other securities (or |
interests therein) issued by others, whether engaged in a |
similar or different business or activity. |
(9) To make and execute agreements, contracts, and |
other instruments necessary or convenient in the exercise |
of the powers and functions of the Agency under this Act, |
including contracts with any person, including personal |
service contracts, or with any local government, State |
agency, or other entity; and all State agencies and all |
local governments are authorized to enter into and do all |
things necessary to perform any such agreement, contract, |
or other instrument with the Agency. No such agreement, |
contract, or other instrument shall exceed 40 years. |
(10) To lend money, invest and reinvest its funds in |
accordance with the Public Funds Investment Act, and take |
and hold real and personal property as security for the |
payment of funds loaned or invested. |
(11) To borrow money at such rate or rates of interest |
as the Agency may determine, issue its notes, bonds, or |
other obligations to evidence that indebtedness, and |
secure any of its obligations by mortgage or pledge of its |
real or personal property, machinery, equipment, |
structures, fixtures, inventories, revenues, grants, and |
other funds as provided or any interest therein, wherever |
|
situated. |
(12) To enter into agreements with the Illinois Finance |
Authority to issue bonds whether or not the income |
therefrom is exempt from federal taxation. |
(13) To procure insurance against any loss in |
connection with its properties or operations in such amount |
or amounts and from such insurers, including the federal |
government, as it may deem necessary or desirable, and to |
pay any premiums therefor. |
(14) To negotiate and enter into agreements with |
trustees or receivers appointed by United States |
bankruptcy courts or federal district courts or in other |
proceedings involving adjustment of debts and authorize |
proceedings involving adjustment of debts and authorize |
legal counsel for the Agency to appear in any such |
proceedings. |
(15) To file a petition under Chapter 9 of Title 11 of |
the United States Bankruptcy Code or take other similar |
action for the adjustment of its debts. |
(16) To enter into management agreements for the |
operation of any of the property or facilities owned by the |
Agency. |
(17) To enter into an agreement to transfer and to |
transfer any land, facilities, fixtures, or equipment of |
the Agency to one or more municipal electric systems, |
governmental aggregators, or rural electric agencies or |
|
cooperatives, for such consideration and upon such terms as |
the Agency may determine to be in the best interest of the |
citizens of Illinois. |
(18) To enter upon any lands and within any building |
whenever in its judgment it may be necessary for the |
purpose of making surveys and examinations to accomplish |
any purpose authorized by this Act. |
(19) To maintain an office or offices at such place or |
places in the State as it may determine. |
(20) To request information, and to make any inquiry, |
investigation, survey, or study that the Agency may deem |
necessary to enable it effectively to carry out the |
provisions of this Act. |
(21) To accept and expend appropriations. |
(22) To engage in any activity or operation that is |
incidental to and in furtherance of efficient operation to |
accomplish the Agency's purposes, including hiring |
employees that the Director deems essential for the |
operations of the Agency. |
(23) To adopt, revise, amend, and repeal rules with |
respect to its operations, properties, and facilities as |
may be necessary or convenient to carry out the purposes of |
this Act, subject to the provisions of the Illinois |
Administrative Procedure Act and Sections 1-22 and 1-35 of |
this Act. |
(24) To establish and collect charges and fees as |
|
described in this Act.
|
(25) To conduct competitive gasification feedstock |
procurement processes to procure the feedstocks for the |
clean coal SNG brownfield facility in accordance with the |
requirements of Section 1-78 of this Act. |
(26) To review, revise, and approve sourcing |
agreements and mediate and resolve disputes between gas |
utilities and the clean coal SNG brownfield facility |
pursuant to subsection (h-1) of Section 9-220 of the Public |
Utilities Act. |
(27) To request, review and accept proposals, execute |
contracts, purchase renewable energy credits and otherwise |
dedicate funds from the Illinois Power Agency Renewable |
Energy Resources Fund to create and carry out the |
objectives of the Illinois Solar for All program in |
accordance with Section 1-56 of this Act. |
(Source: P.A. 96-784, eff. 8-28-09; 96-1000, eff. 7-2-10; |
97-96, eff. 7-13-11; 97-325, eff. 8-12-11; 97-618, eff. |
10-26-11; 97-813, eff. 7-13-12.) |
(20 ILCS 3855/1-25)
|
Sec. 1-25. Agency subject to other laws. Unless otherwise |
stated, the Agency is subject to the provisions of all |
applicable laws, including but not limited to, each of the |
following: |
(1) The State Records Act. |
|
(2) The Illinois Procurement Code, except that the |
Illinois Procurement Code does not apply to the hiring or |
payment of procurement administrators , or procurement |
planning consultants , third-party program managers, or |
other persons who will implement the programs described in |
Sections 1-56 and pursuant to Section 1-75 of the Illinois |
Power Agency Act. |
(3) The Freedom of Information Act. |
(4) The State Property Control Act. |
(5) (Blank). |
(6) The State Officials and Employees Ethics Act.
|
(Source: P.A. 97-618, eff. 10-26-11.) |
(20 ILCS 3855/1-56) |
Sec. 1-56. Illinois Power Agency Renewable Energy |
Resources Fund ; Illinois Solar for All Program . |
(a) The Illinois Power Agency Renewable Energy Resources |
Fund is created as a special fund in the State treasury. |
(b) The Illinois Power Agency Renewable Energy Resources |
Fund shall be administered by the Agency as described in this |
subsection (b), provided that the changes to this subsection |
(b) made by this amendatory Act of the 99th General Assembly |
shall not interfere with existing contracts under this Section. |
(1) The Illinois Power Agency Renewable Energy |
Resources Fund shall be used to purchase renewable energy |
credits according to any approved procurement plan |
|
developed by the Agency prior to June 1, 2017. |
(2) The Illinois Power Agency Renewable Energy |
Resources Fund shall also be used to create the Illinois |
Solar for All Program, which shall include incentives for |
low-income distributed generation and community solar |
projects, and other associated approved expenditures. The |
objectives of the Illinois Solar for All Program are to |
bring photovoltaics to low-income communities in this |
State in a manner that maximizes the development of new |
photovoltaic generating facilities, to create a long-term, |
low-income solar marketplace throughout this State, to |
integrate, through interaction with stakeholders, with |
existing energy efficiency initiatives, and to minimize |
administrative costs. The Agency shall include a |
description of its proposed approach to the design, |
administration, implementation and evaluation of the |
Illinois Solar for All Program, as part of the long-term |
renewable resources procurement plan authorized by |
subsection (c) of Section 1-75 of this Act, and the program |
shall be designed to grow the low-income solar market. The |
Agency or utility, as applicable, shall purchase renewable |
energy credits from the (i) photovoltaic distributed |
renewable energy generation projects and (ii) community |
solar projects that are procured under procurement |
processes authorized by the long-term renewable resources |
procurement plans approved by the Commission. |
|
The Illinois Solar for All Program shall include the |
program offerings described in subparagraphs (A) through |
(D) of this paragraph (2), which the Agency shall implement |
through contracts with third-party providers and, subject |
to appropriation, pay the approximate amounts identified |
using monies available in the Illinois Power Agency |
Renewable Energy Resources Fund. Each contract that |
provides for the installation of solar facilities shall |
provide that the solar facilities will produce energy and |
economic benefits, at a level determined by the Agency to |
be reasonable, for the participating low income customers. |
The monies available in the Illinois Power Agency Renewable |
Energy Resources Fund and not otherwise committed to |
contracts executed under subsection (i) of this Section |
shall be allocated among the programs described in this |
paragraph (2), as follows: 22.5% of these funds shall be |
allocated to programs described in subparagraph (A) of this |
paragraph (2), 37.5% of these funds shall be allocated to |
programs described in subparagraph (B) of this paragraph |
(2), 15% of these funds shall be allocated to programs |
described in subparagraph (C) of this paragraph (2), and |
25% of these funds, but in no event more than $50,000,000, |
shall be allocated to programs described in subparagraph |
(D) of this paragraph (2). The allocation of funds among |
subparagraphs (A), (B), or (C) of this paragraph (2) may be |
changed if the Agency or administrator, through delegated |
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authority, determines incentives in subparagraphs (A), |
(B), or (C) of this paragraph (2) have not been adequately |
subscribed to fully utilize the Illinois Power Agency |
Renewable Energy Resources Fund. The determination shall |
include input through a stakeholder process. The program |
offerings described in subparagraphs (A) through (D) of |
this paragraph (2) shall also be implemented through |
contracts funded from such additional amounts as are |
allocated to one or more of the programs in the long-term |
renewable resources procurement plans as specified in |
subsection (c) of Section 1-75 of this Act and subparagraph |
(O) of paragraph (1) of such subsection (c). |
Contracts that will be paid with funds in the Illinois |
Power Agency Renewable Energy Resources Fund shall be |
executed by the Agency. Contracts that will be paid with |
funds collected by an electric utility shall be executed by |
the electric utility. |
Contracts under the Illinois Solar for All Program |
shall include an approach, as set forth in the long-term |
renewable resources procurement plans, to ensure the |
wholesale market value of the energy is credited to |
participating low-income customers or organizations and to |
ensure tangible economic benefits flow directly to program |
participants, except in the case of low-income |
multi-family housing where the low-income customer does |
not directly pay for energy. Priority shall be given to |
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projects that demonstrate meaningful involvement of |
low-income community members in designing the initial |
proposals. Acceptable proposals to implement projects must |
demonstrate the applicant's ability to conduct initial |
community outreach, education, and recruitment of |
low-income participants in the community. Projects must |
include job training opportunities if available, and shall |
endeavor to coordinate with the job training programs |
described in paragraph (1) of subsection (a) of Section |
16-108.12 of the Public Utilities Act. |
(A) Low-income distributed generation incentive. |
This program will provide incentives to low-income |
customers, either directly or through solar providers, |
to increase the participation of low-income households |
in photovoltaic on-site distributed generation. |
Companies participating in this program that install |
solar panels shall commit to hiring job trainees for a |
portion of their low-income installations, and an |
administrator shall facilitate partnering the |
companies that install solar panels with entities that |
provide solar panel installation job training. It is a |
goal of this program that a minimum of 25% of the |
incentives for this program be allocated to projects |
located within environmental justice communities. |
Contracts entered into under this paragraph may be |
entered into with an entity that will develop and |
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administer the program and shall also include |
contracts for renewable energy credits from the |
photovoltaic distributed generation that is the |
subject of the program, as set forth in the long-term |
renewable resources procurement plan. |
(B) Low-Income Community Solar Project Initiative. |
Incentives shall be offered to low-income customers, |
either directly or through developers, to increase the |
participation of low-income subscribers of community |
solar projects. The developer of each project shall |
identify its partnership with community stakeholders |
regarding the location, development, and participation |
in the project, provided that nothing shall preclude a |
project from including an anchor tenant that does not |
qualify as low-income. Incentives should also be |
offered to community solar projects that are 100% |
low-income subscriber owned, which includes low-income |
households, not-for-profit organizations, and |
affordable housing owners. It is a goal of this program |
that a minimum of 25% of the incentives for this |
program be allocated to community photovoltaic |
projects in environmental justice communities. |
Contracts entered into under this paragraph may be |
entered into with developers and shall also include |
contracts for renewable energy credits related to the |
program. |
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(C) Incentives for non-profits and public |
facilities. Under this program funds shall be used to |
support on-site photovoltaic distributed renewable |
energy generation devices to serve the load associated |
with not-for-profit customers and to support |
photovoltaic distributed renewable energy generation |
that uses photovoltaic technology to serve the load |
associated with public sector customers taking service |
at public buildings. It is a goal of this program that |
at least 25% of the incentives for this program be |
allocated to projects located in environmental justice |
communities. Contracts entered into under this |
paragraph may be entered into with an entity that will |
develop and administer the program or with developers |
and shall also include contracts for renewable energy |
credits related to the program. |
(D) Low-Income Community Solar Pilot Projects. |
Under this program, persons, including, but not |
limited to, electric utilities, shall propose pilot |
community solar projects. Community solar projects |
proposed under this subparagraph (D) may exceed 2,000 |
kilowatts in nameplate capacity, but the amount paid |
per project under this program may not exceed |
$20,000,000. Pilot projects must result in economic |
benefits for the members of the community in which the |
project will be located. The proposed pilot project |
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must include a partnership with at least one |
community-based organization. Approved pilot projects |
shall be competitively bid by the Agency, subject to |
fair and equitable guidelines developed by the Agency. |
Funding available under this subparagraph (D) may not |
be distributed solely to a utility, and at least some |
funds under this subparagraph (D) must include a |
project partnership that includes community ownership |
by the project subscribers. Contracts entered into |
under this paragraph may be entered into with an entity |
that will develop and administer the program or with |
developers and shall also include contracts for |
renewable energy credits related to the program. A |
project proposed by a utility that is implemented under |
this subparagraph (D) shall not be included in the |
utility's ratebase. |
The requirement that a qualified person, as defined in |
paragraph (1) of subsection (i) of this Section, install |
photovoltaic devices does not apply to the Illinois Solar |
for All Program described in this subsection (b). |
(3) Costs associated with the Illinois Solar for All |
Program and its components described in paragraph (2) of |
this subsection (b), including, but not limited to, costs |
associated with procuring experts, consultants, and the |
program administrator referenced in this subsection (b) |
and related incremental costs, and costs related to the |
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evaluation of the Illinois Solar for All Program, may be |
paid for using monies in the Illinois Power Agency |
Renewable Energy Resources Fund, but the Agency or program |
administrator shall strive to minimize costs in the |
implementation of the program. The Agency shall purchase |
renewable energy credits from generation that is the |
subject of a contract under subparagraphs (A) through (D) |
of this paragraph (2) of this subsection (b), and may pay |
for such renewable energy credits through an upfront |
payment per installed kilowatt of nameplate capacity paid |
once the device is interconnected at the distribution |
system level of the utility and is energized. The payment |
shall be in exchange for an assignment of all renewable |
energy credits generated by the system during the first 15 |
years of operation and shall be structured to overcome |
barriers to participation in the solar market by the |
low-income community. The incentives provided for in this |
Section may be implemented through the pricing of renewable |
energy credits where the prices paid for the credits are |
higher than the prices from programs offered under |
subsection (c) of Section 1-75 of this Act to account for |
the incentives. The Agency shall ensure collaboration with |
community agencies, and allocate up to 5% of the funds |
available under the Illinois Solar for All Program to |
community-based groups to assist in grassroots education |
efforts related to the Illinois Solar for All Program. The |
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Agency shall retire any renewable energy credits purchased |
from this program and the credits shall count towards the |
obligation under subsection (c) of Section 1-75 of this Act |
for the electric utility to which the project is |
interconnected. |
(4) The Agency shall, consistent with the requirements |
of this subsection (b), propose the Illinois Solar for All |
Program terms, conditions, and requirements, including the |
prices to be paid for renewable energy credits, and which |
prices may be determined through a formula, through the |
development, review, and approval of the Agency's |
long-term renewable resources procurement plan described |
in subsection (c) of Section 1-75 of this Act and Section |
16-111.5 of the Public Utilities Act. In the course of the |
Commission proceeding initiated to review and approve the |
plan, including the Illinois Solar for All Program proposed |
by the Agency, a party may propose an additional low-income |
solar or solar incentive program, or modifications to the |
programs proposed by the Agency, and the Commission may |
approve an additional program, or modifications to the |
Agency's proposed program, if the additional or modified |
program more effectively maximizes the benefits to |
low-income customers after taking into account all |
relevant factors, including, but not limited to, the extent |
to which a competitive market for low-income solar has |
developed. Following the Commission's approval of the |
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Illinois Solar for All Program, the Agency or a party may |
propose adjustments to the program terms, conditions, and |
requirements, including the price offered to new systems, |
to ensure the long-term viability and success of the |
program. The Commission shall review and approve any |
modifications to the program through the plan revision |
process described in Section 16-111.5 of the Public |
Utilities Act. |
(5) The Agency shall issue a request for qualifications |
for a third-party program administrator or administrators |
to administer all or a portion of the Illinois Solar for |
All Program. The third-party program administrator shall |
be chosen through a competitive bid process based on |
selection criteria and requirements developed by the |
Agency, including, but not limited to, experience in |
administering low-income energy programs and overseeing |
statewide clean energy or energy efficiency services. If |
the Agency retains a program administrator or |
administrators to implement all or a portion of the |
Illinois Solar for All Program, each administrator shall |
periodically submit reports to the Agency and Commission |
for each program that it administers, at appropriate |
intervals to be identified by the Agency in its long-term |
renewable resources procurement plan, provided that the |
reporting interval is at least quarterly. |
(6) The long-term renewable resources procurement plan |
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shall also provide for an independent evaluation of the |
Illinois Solar for All Program. At least every 2 years, the |
Agency shall select an independent evaluator to review and |
report on the Illinois Solar for All Program and the |
performance of the third-party program administrator of |
the Illinois Solar for All Program. The evaluation shall be |
based on objective criteria developed through a public |
stakeholder process. The process shall include feedback |
and participation from Illinois Solar for All Program |
stakeholders, including participants and organizations in |
environmental justice and historically underserved |
communities. The report shall include a summary of the |
evaluation of the Illinois Solar for All Program based on |
the stakeholder developed objective criteria. The report |
shall include the number of projects installed; the total |
installed capacity in kilowatts; the average cost per |
kilowatt of installed capacity to the extent reasonably |
obtainable by the Agency; the number of jobs or job |
opportunities created; economic, social, and environmental |
benefits created; and the total administrative costs |
expended by the Agency and program administrator to |
implement and evaluate the program. The report shall be |
delivered to the Commission and posted on the Agency's |
website, and shall be used, as needed, to revise the |
Illinois Solar for All Program. The Commission shall also |
consider the results of the evaluation as part of its |
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review of the long-term renewable resources procurement |
plan under subsection (c) of Section 1-75 of this Act. |
(7) If additional funding for the programs described in |
this subsection (b) is available under subsection (k) of |
Section 16-108 of the Public Utilities Act, then the Agency |
shall submit a procurement plan to the Commission no later |
than September 1, 2018, that proposes how the Agency will |
procure programs on behalf of the applicable utility. After |
notice and hearing, the Commission shall approve, or |
approve with modification, the plan no later than November |
1, 2018. |
As used in this subsection (b), "low-income households" |
means persons and families whose income does not exceed 80% of |
area median income, adjusted for family size and revised every |
5 years. |
For the purposes of this subsection (b), the Agency shall |
define "environmental justice community" as part of long-term |
renewable resources procurement plan development, to ensure, |
to the extent practicable, compatibility with other agencies' |
definitions and may, for guidance, look to the definitions used |
by federal, state, or local governments. |
(b-5) After the receipt of all payments required by Section |
16-115D of the Public Utilities Act, no additional funds shall |
be deposited into the Illinois Power Agency Renewable Energy |
Resources Fund unless directed by order of the Commission. |
(b-10) After the receipt of all payments required by |
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Section 16-115D of the Public Utilities Act and payment in full |
of all contracts executed by the Agency under subsections (b) |
and (i) of this Section, if the balance of the Illinois Power |
Agency Renewable Energy Resources Fund is under $5,000, then |
the Fund shall be inoperative and any remaining funds and any |
funds submitted to the Fund after that date, shall be |
transferred to the Supplemental Low-Income Energy Assistance |
Fund for use in the Low-Income Home Energy Assistance Program, |
as authorized by the Energy Assistance Act. to procure |
renewable energy resources. Prior to June 1, 2011, resources |
procured pursuant to this Section shall be procured from |
facilities located in Illinois, provided the resources are |
available from those facilities. If resources are not available |
in Illinois, then they shall be procured in states that adjoin |
Illinois. If resources are not available in Illinois or in |
states that adjoin Illinois, then they may be purchased |
elsewhere. Beginning June 1, 2011, resources procured pursuant |
to this Section shall be procured from facilities located in |
Illinois or states that adjoin Illinois. If resources are not |
available in Illinois or in states that adjoin Illinois, then |
they may be procured elsewhere. To the extent available, at |
least 75% of these renewable energy resources shall come from |
wind generation. Of the renewable energy resources procured |
pursuant to this Section at least the following specified |
percentages shall come from photovoltaics on the following |
schedule: 0.5% by June 1, 2012; 1.5% by June 1, 2013; 3% by |
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June 1, 2014; and 6% by June 1, 2015 and thereafter. Of the |
renewable energy resources procured pursuant to this Section, |
at least the following percentages shall come from distributed |
renewable energy generation devices: 0.5% by June 1, 2013, |
0.75% by June 1, 2014, and 1% by June 1, 2015 and thereafter. |
To the extent available, half of the renewable energy resources |
procured from distributed renewable energy generation shall |
come from devices of less than 25 kilowatts in nameplate |
capacity. Renewable energy resources procured from distributed |
generation devices may also count towards the required |
percentages for wind and solar photovoltaics. Procurement of |
renewable energy resources from distributed renewable energy |
generation devices shall be done on an annual basis through |
multi-year contracts of no less than 5 years, and shall consist |
solely of renewable energy credits. |
The Agency shall create credit requirements for suppliers |
of distributed renewable energy. In order to minimize the |
administrative burden on contracting entities, the Agency |
shall solicit the use of third-party organizations to aggregate |
distributed renewable energy into groups of no less than one |
megawatt in installed capacity. These third-party |
organizations shall administer contracts with individual |
distributed renewable energy generation device owners. An |
individual distributed renewable energy generation device |
owner shall have the ability to measure the output of his or |
her distributed renewable energy generation device. |
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(c) (Blank). The Agency shall procure renewable energy |
resources at least once each year in conjunction with a |
procurement event for electric utilities required to comply |
with Section 1-75 of the Act and shall, whenever possible, |
enter into long-term contracts on an annual basis for a portion |
of the incremental requirement for the given procurement year. |
(d) (Blank). The price paid to procure renewable energy |
credits using monies from the Illinois Power Agency Renewable |
Energy Resources Fund shall not exceed the winning bid prices |
paid for like resources procured for electric utilities |
required to comply with Section 1-75 of this Act. |
(e) All renewable energy credits procured using monies from |
the Illinois Power Agency Renewable Energy Resources Fund shall |
be permanently retired. |
(f) The selection of one or more third-party program |
managers or administrators, the selection of the independent |
evaluator, and the procurement processes described in this |
Section are exempt from the requirements of the Illinois |
Procurement Code, under Section 20-10 of that Code. The |
procurement process described in this Section is exempt from |
the requirements of the Illinois Procurement Code, pursuant to |
Section 20-10 of that Code. |
(g) All disbursements from the Illinois Power Agency |
Renewable Energy Resources Fund shall be made only upon |
warrants of the Comptroller drawn upon the Treasurer as |
custodian of the Fund upon vouchers signed by the Director or |
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by the person or persons designated by the Director for that |
purpose. The Comptroller is authorized to draw the warrant upon |
vouchers so signed. The Treasurer shall accept all warrants so |
signed and shall be released from liability for all payments |
made on those warrants. |
(h) The Illinois Power Agency Renewable Energy Resources |
Fund shall not be subject to sweeps, administrative charges, or |
chargebacks, including, but not limited to, those authorized |
under Section 8h of the State Finance Act, that would in any |
way result in the transfer of any funds from this Fund to any |
other fund of this State or in having any such funds utilized |
for any purpose other than the express purposes set forth in |
this Section.
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(h-5) The Agency may assess fees to each bidder to recover |
the costs incurred in connection with a procurement process |
held under this Section. Fees collected from bidders shall be |
deposited into the Renewable Energy Resources Fund. |
(i) Supplemental procurement process. |
(1) Within 90 days after the effective date of this |
amendatory Act of the 98th General Assembly, the Agency |
shall develop a one-time supplemental procurement plan |
limited to the procurement of renewable energy credits, if |
available, from new or existing photovoltaics, including, |
but not limited to, distributed photovoltaic generation. |
Nothing in this subsection (i) requires procurement of wind |
generation through the supplemental procurement. |
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Renewable energy credits procured from new |
photovoltaics, including, but not limited to, distributed |
photovoltaic generation, under this subsection (i) must be |
procured from devices installed by a qualified person. In |
its supplemental procurement plan, the Agency shall |
establish contractually enforceable mechanisms for |
ensuring that the installation of new photovoltaics is |
performed by a qualified person. |
For the purposes of this paragraph (1), "qualified |
person" means a person who performs installations of |
photovoltaics, including, but not limited to, distributed |
photovoltaic generation, and who: (A) has completed an |
apprenticeship as a journeyman electrician from a United |
States Department of Labor registered electrical |
apprenticeship and training program and received a |
certification of satisfactory completion; or (B) does not |
currently meet the criteria under clause (A) of this |
paragraph (1), but is enrolled in a United States |
Department of Labor registered electrical apprenticeship |
program, provided that the person is directly supervised by |
a person who meets the criteria under clause (A) of this |
paragraph (1); or (C) has obtained one of the following |
credentials in addition to attesting to satisfactory |
completion of at least 5 years or 8,000 hours of documented |
hands-on electrical experience: (i) a North American Board |
of Certified Energy Practitioners (NABCEP) Installer |
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Certificate for Solar PV; (ii) an Underwriters |
Laboratories (UL) PV Systems Installer Certificate; (iii) |
an Electronics Technicians Association, International |
(ETAI) Level 3 PV Installer Certificate; or (iv) an |
Associate in Applied Science degree from an Illinois |
Community College Board approved community college program |
in renewable energy or a distributed generation |
technology. |
For the purposes of this paragraph (1), "directly |
supervised" means that there is a qualified person who |
meets the qualifications under clause (A) of this paragraph |
(1) and who is available for supervision and consultation |
regarding the work performed by persons under clause (B) of |
this paragraph (1), including a final inspection of the |
installation work that has been directly supervised to |
ensure safety and conformity with applicable codes. |
For the purposes of this paragraph (1), "install" means |
the major activities and actions required to connect, in |
accordance with applicable building and electrical codes, |
the conductors, connectors, and all associated fittings, |
devices, power outlets, or apparatuses mounted at the |
premises that are directly involved in delivering energy to |
the premises' electrical wiring from the photovoltaics, |
including, but not limited to, to distributed photovoltaic |
generation. |
The renewable energy credits procured pursuant to the |
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supplemental procurement plan shall be procured using up to |
$30,000,000 from the Illinois Power Agency Renewable |
Energy Resources Fund. The Agency shall not plan to use |
funds from the Illinois Power Agency Renewable Energy |
Resources Fund in excess of the monies on deposit in such |
fund or projected to be deposited into such fund. The |
supplemental procurement plan shall ensure adequate, |
reliable, affordable, efficient, and environmentally |
sustainable renewable energy resources (including credits) |
at the lowest total cost over time, taking into account any |
benefits of price stability. |
To the extent available, 50% of the renewable energy |
credits procured from distributed renewable energy |
generation shall come from devices of less than 25 |
kilowatts in nameplate capacity. Procurement of renewable |
energy credits from distributed renewable energy |
generation devices shall be done through multi-year |
contracts of no less than 5 years. The Agency shall create |
credit requirements for counterparties. In order to |
minimize the administrative burden on contracting |
entities, the Agency shall solicit the use of third parties |
to aggregate distributed renewable energy. These third |
parties shall enter into and administer contracts with |
individual distributed renewable energy generation device |
owners. An individual distributed renewable energy |
generation device owner shall
have the ability to measure |
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the output of his or her distributed renewable energy |
generation device. |
In developing the supplemental procurement plan, the |
Agency shall hold at least one workshop open to the public |
within 90 days after the effective date of this amendatory |
Act of the 98th General Assembly and shall consider any |
comments made by stakeholders or the public. Upon |
development of the supplemental procurement plan within |
this 90-day period, copies of the supplemental procurement |
plan shall be posted and made publicly available on the |
Agency's and Commission's websites. All interested parties |
shall have 14 days following the date of posting to provide |
comment to the Agency on the supplemental procurement plan. |
All comments submitted to the Agency shall be specific, |
supported by data or other detailed analyses, and, if |
objecting to all or a portion of the supplemental |
procurement plan, accompanied by specific alternative |
wording or proposals. All comments shall be posted on the |
Agency's and Commission's websites. Within 14 days |
following the end of the 14-day review period, the Agency |
shall revise the supplemental procurement plan as |
necessary based on the comments received and file its |
revised supplemental procurement plan with the Commission |
for approval. |
(2) Within 5 days after the filing of the supplemental |
procurement plan at the Commission, any person objecting to |
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the supplemental procurement plan shall file an objection |
with the Commission. Within 10 days after the filing, the |
Commission shall determine whether a hearing is necessary. |
The Commission shall enter its order confirming or |
modifying the supplemental procurement plan within 90 days |
after the filing of the supplemental procurement plan by |
the Agency. |
(3) The Commission shall approve the supplemental |
procurement plan of renewable energy credits to be procured |
from new or existing photovoltaics, including, but not |
limited to, distributed photovoltaic generation, if the |
Commission determines that it will ensure adequate, |
reliable, affordable, efficient, and environmentally |
sustainable electric service in the form of renewable |
energy credits at the lowest total cost over time, taking |
into account any benefits of price stability. |
(4) The supplemental procurement process under this |
subsection (i) shall include each of the following |
components: |
(A) Procurement administrator. The Agency may |
retain a procurement administrator in the manner set |
forth in item (2) of subsection (a) of Section 1-75 of |
this Act to conduct the supplemental procurement or may |
elect to use the same procurement administrator |
administering the Agency's annual procurement under |
Section 1-75. |
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(B) Procurement monitor. The procurement monitor |
retained by the Commission pursuant to Section |
16-111.5 of the Public Utilities Act shall: |
(i) monitor interactions among the procurement |
administrator and bidders and suppliers; |
(ii) monitor and report to the Commission on |
the progress of the supplemental procurement |
process; |
(iii) provide an independent confidential |
report to the Commission regarding the results of |
the procurement events; |
(iv) assess compliance with the procurement |
plan approved by the Commission for the |
supplemental procurement process; |
(v) preserve the confidentiality of supplier |
and bidding information in a manner consistent |
with all applicable laws, rules, regulations, and |
tariffs; |
(vi) provide expert advice to the Commission |
and consult with the procurement administrator |
regarding issues related to procurement process |
design, rules, protocols, and policy-related |
matters; |
(vii) consult with the procurement |
administrator regarding the development and use of |
benchmark criteria, standard form contracts, |
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credit policies, and bid documents; and |
(viii) perform, with respect to the |
supplemental procurement process, any other |
procurement monitor duties specifically delineated |
within subsection (i) of this Section. |
(C) Solicitation, pre-qualification, and |
registration of bidders. The procurement administrator |
shall disseminate information to potential bidders to |
promote a procurement event, notify potential bidders |
that the procurement administrator may enter into a |
post-bid price negotiation with bidders that meet the |
applicable benchmarks, provide supply requirements, |
and otherwise explain the competitive procurement |
process. In addition to such other publication as the |
procurement administrator determines is appropriate, |
this information shall be posted on the Agency's and |
the Commission's websites. The procurement |
administrator shall also administer the |
prequalification process, including evaluation of |
credit worthiness, compliance with procurement rules, |
and agreement to the standard form contract developed |
pursuant to item (D) of this paragraph (4). The |
procurement administrator shall then identify and |
register bidders to participate in the procurement |
event. |
(D) Standard contract forms and credit terms and |
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instruments. The procurement administrator, in |
consultation with the Agency, the Commission, and |
other interested parties and subject to Commission |
oversight, shall develop and provide standard contract |
forms for the supplier contracts that meet generally |
accepted industry practices as well as include any |
applicable State of Illinois terms and conditions that |
are required for contracts entered into by an agency of |
the State of Illinois. Standard credit terms and |
instruments that meet generally accepted industry |
practices shall be similarly developed. Contracts for |
new photovoltaics shall include a provision attesting |
that the supplier will use a qualified person for the |
installation of the device pursuant to paragraph (1) of |
subsection (i) of this Section. The procurement |
administrator shall make available to the Commission |
all written comments it receives on the contract forms,
|
credit terms, or instruments. If the procurement |
administrator cannot reach agreement with the parties |
as to the contract terms and conditions, the |
procurement administrator must notify the Commission |
of any disputed terms and the Commission shall resolve |
the dispute. The terms of the contracts shall not be |
subject to negotiation by winning bidders, and the |
bidders must agree to the terms of the contract in |
advance so that winning bids are selected solely on the |
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basis of price. |
(E) Requests for proposals; competitive |
procurement process. The procurement administrator |
shall design and issue requests for proposals to supply |
renewable energy credits in accordance with the |
supplemental procurement plan, as approved by the |
Commission. The requests for proposals shall set forth |
a procedure for sealed, binding commitment bidding |
with pay-as-bid settlement, and provision for |
selection of bids on the basis of price, provided, |
however, that no bid shall be accepted if it exceeds |
the benchmark developed pursuant to item (F) of this |
paragraph (4). |
(F) Benchmarks. Benchmarks for each product to be |
procured shall be developed by the procurement |
administrator in consultation with Commission staff, |
the Agency, and the procurement monitor for use in this |
supplemental procurement. |
(G) A plan for implementing contingencies in the |
event of supplier default, Commission rejection of |
results, or any other cause. |
(5) Within 2 business days after opening the sealed |
bids, the procurement administrator shall submit a |
confidential report to the Commission. The report shall |
contain the results of the bidding for each of the products |
along with the procurement administrator's recommendation |
|
for the acceptance and rejection of bids based on the price |
benchmark criteria and other factors observed in the |
process. The procurement monitor also shall submit a |
confidential report to the Commission within 2 business |
days after opening the sealed bids. The report shall |
contain the procurement monitor's assessment of bidder |
behavior in the process as well as an assessment of the |
procurement administrator's compliance with the |
procurement process and rules. The Commission shall review |
the confidential reports submitted by the procurement |
administrator and procurement monitor and shall accept or |
reject the recommendations of the procurement |
administrator within 2 business days after receipt of the |
reports. |
(6) Within 3 business days after the Commission |
decision approving the results of a procurement event, the |
Agency shall enter into binding contractual arrangements |
with the winning suppliers using the standard form |
contracts. |
(7) The names of the successful bidders and the average |
of the winning bid prices for each contract type and for |
each contract term shall be made available to the public |
within 2 days after the supplemental procurement event. The |
Commission, the procurement monitor, the procurement |
administrator, the Agency, and all participants in the |
procurement process shall maintain the confidentiality of |
|
all other supplier and bidding information in a manner |
consistent with all applicable laws, rules, regulations, |
and tariffs. Confidential information, including the |
confidential reports submitted by the procurement |
administrator and procurement monitor pursuant to this |
Section, shall not be made publicly available and shall not |
be discoverable by any party in any proceeding, absent a |
compelling demonstration of need, nor shall those reports |
be admissible in any proceeding other than one for law |
enforcement purposes. |
(8) The supplemental procurement provided in this |
subsection (i) shall not be subject to the requirements and |
limitations of subsections (c) and (d) of this Section. |
(9) Expenses incurred in connection with the |
procurement process held pursuant to this Section, |
including, but not limited to, the cost of developing the |
supplemental procurement plan, the procurement |
administrator, procurement monitor, and the cost of the |
retirement of renewable energy credits purchased pursuant |
to the supplemental procurement shall be paid for from the |
Illinois Power Agency Renewable Energy Resources Fund. The |
Agency shall enter into an interagency agreement with the |
Commission to reimburse the Commission for its costs |
associated with the procurement monitor for the |
supplemental procurement process. |
(Source: P.A. 97-616, eff. 10-26-11; 98-672, eff. 6-30-14.) |
|
(20 ILCS 3855/1-75) |
Sec. 1-75. Planning and Procurement Bureau. The Planning |
and Procurement Bureau has the following duties and |
responsibilities: |
(a) The Planning and Procurement Bureau shall each year, |
beginning in 2008, develop procurement plans and conduct |
competitive procurement processes in accordance with the |
requirements of Section 16-111.5 of the Public Utilities Act |
for the eligible retail customers of electric utilities that on |
December 31, 2005 provided electric service to at least 100,000 |
customers in Illinois. Beginning with the delivery year |
commencing on June 1, 2017, the Planning and Procurement Bureau |
shall develop plans and processes for the procurement of zero |
emission credits from zero emission facilities in accordance |
with the requirements of subsection (d-5) of this Section. The |
Planning and Procurement Bureau shall also develop procurement |
plans and conduct competitive procurement processes in |
accordance with the requirements of Section 16-111.5 of the |
Public Utilities Act for the eligible retail customers of small |
multi-jurisdictional electric utilities that (i) on December |
31, 2005 served less than 100,000 customers in Illinois and |
(ii) request a procurement plan for their Illinois |
jurisdictional load. This Section shall not apply to a small |
multi-jurisdictional utility until such time as a small |
multi-jurisdictional utility requests the Agency to prepare a |
|
procurement plan for their Illinois jurisdictional load. For |
the purposes of this Section, the term "eligible retail |
customers" has the same definition as found in Section |
16-111.5(a) of the Public Utilities Act. |
Beginning with the plan or plans to be implemented in the |
2017 delivery year, the Agency shall no longer include the |
procurement of renewable energy resources in the annual |
procurement plans required by this subsection (a), except as |
provided in subsection (q) of Section 16-111.5 of the Public |
Utilities Act, and shall instead develop a long-term renewable |
resources procurement plan in accordance with subsection (c) of |
this Section and Section 16-111.5 of the Public Utilities Act. |
(1) The Agency shall each year, beginning in 2008, as |
needed, issue a request for qualifications for experts or |
expert consulting firms to develop the procurement plans in |
accordance with Section 16-111.5 of the Public Utilities |
Act. In order to qualify an expert or expert consulting |
firm must have: |
(A) direct previous experience assembling |
large-scale power supply plans or portfolios for |
end-use customers; |
(B) an advanced degree in economics, mathematics, |
engineering, risk management, or a related area of |
study; |
(C) 10 years of experience in the electricity |
sector, including managing supply risk; |
|
(D) expertise in wholesale electricity market |
rules, including those established by the Federal |
Energy Regulatory Commission and regional transmission |
organizations; |
(E) expertise in credit protocols and familiarity |
with contract protocols; |
(F) adequate resources to perform and fulfill the |
required functions and responsibilities; and |
(G) the absence of a conflict of interest and |
inappropriate bias for or against potential bidders or |
the affected electric utilities. |
(2) The Agency shall each year, as needed, issue a |
request for qualifications for a procurement administrator |
to conduct the competitive procurement processes in |
accordance with Section 16-111.5 of the Public Utilities |
Act. In order to qualify an expert or expert consulting |
firm must have: |
(A) direct previous experience administering a |
large-scale competitive procurement process; |
(B) an advanced degree in economics, mathematics, |
engineering, or a related area of study; |
(C) 10 years of experience in the electricity |
sector, including risk management experience; |
(D) expertise in wholesale electricity market |
rules, including those established by the Federal |
Energy Regulatory Commission and regional transmission |
|
organizations; |
(E) expertise in credit and contract protocols; |
(F) adequate resources to perform and fulfill the |
required functions and responsibilities; and |
(G) the absence of a conflict of interest and |
inappropriate bias for or against potential bidders or |
the affected electric utilities. |
(3) The Agency shall provide affected utilities and |
other interested parties with the lists of qualified |
experts or expert consulting firms identified through the |
request for qualifications processes that are under |
consideration to develop the procurement plans and to serve |
as the procurement administrator. The Agency shall also |
provide each qualified expert's or expert consulting |
firm's response to the request for qualifications. All |
information provided under this subparagraph shall also be |
provided to the Commission. The Agency may provide by rule |
for fees associated with supplying the information to |
utilities and other interested parties. These parties |
shall, within 5 business days, notify the Agency in writing |
if they object to any experts or expert consulting firms on |
the lists. Objections shall be based on: |
(A) failure to satisfy qualification criteria; |
(B) identification of a conflict of interest; or |
(C) evidence of inappropriate bias for or against |
potential bidders or the affected utilities. |
|
The Agency shall remove experts or expert consulting |
firms from the lists within 10 days if there is a |
reasonable basis for an objection and provide the updated |
lists to the affected utilities and other interested |
parties. If the Agency fails to remove an expert or expert |
consulting firm from a list, an objecting party may seek |
review by the Commission within 5 days thereafter by filing |
a petition, and the Commission shall render a ruling on the |
petition within 10 days. There is no right of appeal of the |
Commission's ruling. |
(4) The Agency shall issue requests for proposals to |
the qualified experts or expert consulting firms to develop |
a procurement plan for the affected utilities and to serve |
as procurement administrator. |
(5) The Agency shall select an expert or expert |
consulting firm to develop procurement plans based on the |
proposals submitted and shall award contracts of up to 5 |
years to those selected. |
(6) The Agency shall select an expert or expert |
consulting firm, with approval of the Commission, to serve |
as procurement administrator based on the proposals |
submitted. If the Commission rejects, within 5 days, the |
Agency's selection, the Agency shall submit another |
recommendation within 3 days based on the proposals |
submitted. The Agency shall award a 5-year contract to the |
expert or expert consulting firm so selected with |
|
Commission approval. |
(b) The experts or expert consulting firms retained by the |
Agency shall, as appropriate, prepare procurement plans, and |
conduct a competitive procurement process as prescribed in |
Section 16-111.5 of the Public Utilities Act, to ensure |
adequate, reliable, affordable, efficient, and environmentally |
sustainable electric service at the lowest total cost over |
time, taking into account any benefits of price stability, for |
eligible retail customers of electric utilities that on |
December 31, 2005 provided electric service to at least 100,000 |
customers in the State of Illinois, and for eligible Illinois |
retail customers of small multi-jurisdictional electric |
utilities that (i) on December 31, 2005 served less than |
100,000 customers in Illinois and (ii) request a procurement |
plan for their Illinois jurisdictional load. |
(c) Renewable portfolio standard. |
(1) (A) The Agency shall develop a long-term renewable |
resources procurement plan that shall include procurement |
programs and competitive procurement events necessary to |
meet the goals set forth in this subsection (c). The |
initial long-term renewable resources procurement plan |
shall be released for comment no later than 160 days after |
the effective date of this amendatory Act of the 99th |
General Assembly. The Agency shall review, and may revise |
on an expedited basis, the long-term renewable resources |
procurement plan at least every 2 years, which shall be |
|
conducted in conjunction with the procurement plan under |
Section 16-111.5 of the Public Utilities Act to the extent |
practicable to minimize administrative expense. The |
long-term renewable resources procurement plans shall be |
subject to review and approval by the Commission under |
Section 16-111.5 of the Public Utilities Act. |
(B) Subject to subparagraph (F) of this paragraph (1), |
the long-term renewable resources procurement plan shall |
include the goals for procurement of renewable energy |
credits to meet at least the following overall percentages: |
13% by the 2017 delivery year; increasing by at least 1.5% |
each delivery year thereafter to at least 25% by the 2025 |
delivery year; and continuing at no less than 25% for each |
delivery year thereafter. In the event of a conflict |
between these goals and the new wind and new photovoltaic |
procurement requirements described in items (i) through |
(iii) of subparagraph (C) of this paragraph (1), the |
long-term plan shall prioritize compliance with the new |
wind and new photovoltaic procurement requirements |
described in items (i) through (iii) of subparagraph (C) of |
this paragraph (1) over the annual percentage targets |
described in this subparagraph (B). |
For the delivery year beginning June 1, 2017, the |
procurement plan shall include cost-effective renewable energy |
resources equal to at least 13% of each utility's load for |
eligible retail customers and 13% of the applicable portion of |
|
each utility's load for retail customers who are not eligible |
retail customers, which applicable portion shall equal 50% of |
the utility's load for retail customers who are not eligible |
retail customers on February 28, 2017. |
For the delivery year beginning June 1, 2018, the |
procurement plan shall include cost-effective renewable energy |
resources equal to at least 14.5% of each utility's load for |
eligible retail customers and 14.5% of the applicable portion |
of each utility's load for retail customers who are not |
eligible retail customers, which applicable portion shall |
equal 75% of the utility's load for retail customers who are |
not eligible retail customers on February 28, 2017. |
For the delivery year beginning June 1, 2019, and for each |
year thereafter, the procurement plans shall include |
cost-effective renewable energy resources equal to a minimum |
percentage of each utility's load for all retail customers as |
follows: 16% by June 1, 2019; increasing by 1.5% each year |
thereafter to 25% by June 1, 2025; and 25% by June 1, 2026 and |
each year thereafter. |
For each delivery year, the Agency shall first |
recognize each utility's obligations for that delivery |
year under existing contracts. Any renewable energy |
credits under existing contracts, including renewable |
energy credits as part of renewable energy resources, shall |
be used to meet the goals set forth in this subsection (c) |
for the delivery year. |
|
(C) Of the renewable energy credits procured under this |
subsection (c), at least 75% shall come from wind and |
photovoltaic projects. The long-term renewable resources |
procurement plan described in subparagraph (A) of this |
paragraph (1) shall include the procurement of renewable |
energy credits in amounts equal to at least the following: |
(i) By the end of the 2020 delivery year: |
At least 2,000,000 renewable energy credits |
for each delivery year shall come from new wind |
projects; and |
At least 2,000,000 renewable energy credits |
for each delivery year shall come from new |
photovoltaic projects; of that amount, to the |
extent possible, the Agency shall procure: at |
least 50% from solar photovoltaic projects using |
the program outlined in subparagraph (K) of this |
paragraph (1) from distributed renewable energy |
generation devices or community renewable |
generation projects; at least 40% from |
utility-scale solar projects; at least 2% from |
brownfield site photovoltaic projects that are not |
community renewable generation projects; and the |
remainder shall be determined through the |
long-term planning process described in |
subparagraph (A) of this paragraph (1). |
(ii) By the end of the 2025 delivery year: |
|
At least 3,000,000 renewable energy credits |
for each delivery year shall come from new wind |
projects; and |
At least 3,000,000 renewable energy credits |
for each delivery year shall come from new |
photovoltaic projects; of that amount, to the |
extent possible, the Agency shall procure: at |
least 50% from solar photovoltaic projects using |
the program outlined in subparagraph (K) of this |
paragraph (1) from distributed renewable energy |
devices or community renewable generation |
projects; at least 40% from utility-scale solar |
projects; at least 2% from brownfield site |
photovoltaic projects that are not community |
renewable generation projects; and the remainder |
shall be determined through the long-term planning |
process described in subparagraph (A) of this |
paragraph (1). |
(iii) By the end of the 2030 delivery year: |
At least 4,000,000 renewable energy credits |
for each delivery year shall come from new wind |
projects; and |
At least 4,000,000 renewable energy credits |
for each delivery year shall come from new |
photovoltaic projects; of that amount, to the |
extent possible, the Agency shall procure: at |
|
least 50% from solar photovoltaic projects using |
the program outlined in subparagraph (K) of this |
paragraph (1) from distributed renewable energy |
devices or community renewable generation |
projects; at least 40% from utility-scale solar |
projects; at least 2% from brownfield site |
photovoltaic projects that are not community |
renewable generation projects; and the remainder |
shall be determined through the long-term planning |
process described in subparagraph (A) of this |
paragraph (1). |
For purposes of this Section: |
"New wind projects" means wind renewable |
energy facilities that are energized after June 1, |
2017 for the delivery year commencing June 1, 2017 |
or within 3 years after the date the Commission |
approves contracts for subsequent delivery years. |
"New photovoltaic projects" means photovoltaic |
renewable energy facilities that are energized |
after June 1, 2017. Photovoltaic projects |
developed under Section 1-56 of this Act shall not |
apply towards the new photovoltaic project |
requirements in this subparagraph (C). |
(D) Renewable energy credits shall be cost effective. |
For purposes of this subsection (c), "cost effective" means |
that the costs of procuring renewable energy resources do |
|
not cause the limit stated in subparagraph (E) of this |
paragraph (1) to be exceeded and, for renewable energy |
credits procured through a competitive procurement event, |
do not exceed benchmarks based on market prices for like |
products in the region. For purposes of this subsection |
(c), "like products" means contracts for renewable energy |
credits from the same or substantially similar technology, |
same or substantially similar vintage (new or existing), |
the same or substantially similar quantity, and the same or |
substantially similar contract length and structure. |
Benchmarks shall be developed by the procurement |
administrator, in consultation with the Commission staff, |
Agency staff, and the procurement monitor and shall be |
subject to Commission review and approval. If price |
benchmarks for like products in the region are not |
available, the procurement administrator shall establish |
price benchmarks based on publicly available data on |
regional technology costs and expected current and future |
regional energy prices. The benchmarks in this Section |
shall not be used to curtail or otherwise reduce |
contractual obligations entered into by or through the |
Agency prior to the effective date of this amendatory Act |
of the 99th General Assembly. |
(E) For purposes of this subsection (c), the required |
procurement of cost-effective renewable energy resources |
for a particular year commencing prior to June 1, 2017 |
|
shall be measured as a percentage of the actual amount of |
electricity (megawatt-hours) supplied by the electric |
utility to eligible retail customers in the delivery year |
ending immediately prior to the procurement, and, for |
delivery years commencing on and after June 1, 2017, the |
required procurement of cost-effective renewable energy |
resources for a particular year shall be measured as a |
percentage of the actual amount of electricity |
(megawatt-hours) delivered by the electric utility in the |
delivery year ending immediately prior to the procurement, |
to all retail customers in its service territory. For |
purposes of this subsection (c), the amount paid per |
kilowatthour means the total amount paid for electric |
service expressed on a per kilowatthour basis. For purposes |
of this subsection (c), the total amount paid for electric |
service includes without limitation amounts paid for |
supply, transmission, distribution, surcharges, and add-on |
taxes. |
Notwithstanding the requirements of this subsection |
(c), the total of renewable energy resources procured under |
the procurement plan for any single year shall be subject |
to the limitations of this subparagraph (E). Such |
procurement shall be reduced for all retail customers based |
on the amount necessary to limit the annual estimated |
average net increase due to the costs of these resources |
included in the amounts paid by eligible retail customers |
|
in connection with electric service to no more than the |
greater of 2.015% of the amount paid per kilowatthour by |
those customers during the year ending May 31, 2007 or the |
incremental amount per kilowatthour paid for these |
resources in 2011. To arrive at a maximum dollar amount of |
renewable energy resources to be procured for the |
particular delivery year, the resulting per kilowatthour |
amount shall be applied to the actual amount of |
kilowatthours of electricity delivered, or applicable |
portion of such amount as specified in paragraph (1) of |
this subsection (c), as applicable, by the electric utility |
in the delivery year immediately prior to the procurement |
to all retail customers in its service territory. The |
calculations required by this subparagraph (E) shall be |
made only once for each delivery year at the time that the |
renewable energy resources are procured. Once the |
determination as to the amount of renewable energy |
resources to procure is made based on the calculations set |
forth in this subparagraph (E) and the contracts procuring |
those amounts are executed, no subsequent rate impact |
determinations shall be made and no adjustments to those |
contract amounts shall be allowed. All costs incurred under |
such contracts shall be fully recoverable by the electric |
utility as provided in this Section. |
(F) If the limitation on the amount of renewable energy |
resources procured in subparagraph (E) of this paragraph |
|
(1) prevents the Agency from meeting all of the goals in |
this subsection (c), the Agency's long-term plan shall |
prioritize compliance with the requirements of this |
subsection (c) regarding renewable energy credits in the |
following order: |
(i) renewable energy credits under existing |
contractual obligations; |
(i-5)funding for the Illinois Solar for All |
Program, as described in subparagraph (O) of this |
paragraph (1); |
(ii) renewable energy credits necessary to comply |
with the new wind and new photovoltaic procurement |
requirements described in items (i) through (iii) of |
subparagraph (C) of this paragraph (1); and |
(iii) renewable energy credits necessary to meet |
the remaining requirements of this subsection (c). |
(G) The following provisions shall apply to the |
Agency's procurement of renewable energy credits under |
this subsection (c): |
(i) Notwithstanding whether a long-term renewable |
resources procurement plan has been approved, the |
Agency shall conduct an initial forward procurement |
for renewable energy credits from new utility-scale |
wind projects within 160 days after the effective date |
of this amendatory Act of the 99th General Assembly. |
For the purposes of this initial forward procurement, |
|
the Agency shall solicit 15-year contracts for |
delivery of 1,000,000 renewable energy credits |
delivered annually from new utility-scale wind |
projects to begin delivery on June 1, 2019, if |
available, but not later than June 1, 2021. Payments to |
suppliers of renewable energy credits shall commence |
upon delivery. Renewable energy credits procured under |
this initial procurement shall be included in the |
Agency's long-term plan and shall apply to all |
renewable energy goals in this subsection (c). |
(ii) Notwithstanding whether a long-term renewable |
resources procurement plan has been approved, the |
Agency shall conduct an initial forward procurement |
for renewable energy credits from new utility-scale |
solar projects and brownfield site photovoltaic |
projects within one year after the effective date of |
this amendatory Act of the 99th General Assembly. For |
the purposes of this initial forward procurement, the |
Agency shall solicit 15-year contracts for delivery of |
1,000,000 renewable energy credits delivered annually |
from new utility-scale solar projects and brownfield |
site photovoltaic projects to begin delivery on June 1, |
2019, if available, but not later than June 1, 2021. |
The Agency may structure this initial procurement in |
one or more discrete procurement events. Payments to |
suppliers of renewable energy credits shall commence |
|
upon delivery. Renewable energy credits procured under |
this initial procurement shall be included in the |
Agency's long-term plan and shall apply to all |
renewable energy goals in this subsection (c). |
(iii) Subsequent forward procurements for |
utility-scale wind projects shall solicit at least |
1,000,000 renewable energy credits delivered annually |
per procurement event and shall be planned, scheduled, |
and designed such that the cumulative amount of |
renewable energy credits delivered from all new wind |
projects in each delivery year shall not exceed the |
Agency's projection of the cumulative amount of |
renewable energy credits that will be delivered from |
all new photovoltaic projects, including utility-scale |
and distributed photovoltaic devices, in the same |
delivery year at the time scheduled for wind contract |
delivery. |
(iv) If, at any time after the time set for |
delivery of renewable energy credits pursuant to the |
initial procurements in items (i) and (ii) of this |
subparagraph (G), the cumulative amount of renewable |
energy credits projected to be delivered from all new |
wind projects in a given delivery year exceeds the |
cumulative amount of renewable energy credits |
projected to be delivered from all new photovoltaic |
projects in that delivery year by 200,000 or more |
|
renewable energy credits, then the Agency shall within |
60 days adjust the procurement programs in the |
long-term renewable resources procurement plan to |
ensure that the projected cumulative amount of |
renewable energy credits to be delivered from all new |
wind projects does not exceed the projected cumulative |
amount of renewable energy credits to be delivered from |
all new photovoltaic projects by 200,000 or more |
renewable energy credits, provided that nothing in |
this Section shall preclude the projected cumulative |
amount of renewable energy credits to be delivered from |
all new photovoltaic projects from exceeding the |
projected cumulative amount of renewable energy |
credits to be delivered from all new wind projects in |
each delivery year and provided further that nothing in |
this item (iv) shall require the curtailment of an |
executed contract. The Agency shall update, on a |
quarterly basis, its projection of the renewable |
energy credits to be delivered from all projects in |
each delivery year. Notwithstanding anything to the |
contrary, the Agency may adjust the timing of |
procurement events conducted under this subparagraph |
(G). The long-term renewable resources procurement |
plan shall set forth the process by which the |
adjustments may be made. |
(v) All procurements under this subparagraph (G) |
|
shall comply with the geographic requirements in |
subparagraph (I) of this paragraph (1) and shall follow |
the procurement processes and procedures described in |
this Section and Section 16-111.5 of the Public |
Utilities Act to the extent practicable, and these |
processes and procedures may be expedited to |
accommodate the schedule established by this |
subparagraph (G). |
(H) The procurement of renewable energy resources for a |
given delivery year shall be reduced as described in this |
subparagraph (H) if an alternate retail electric supplier |
meets the requirements described in this subparagraph (H). |
(i) Within 45 days after the effective date of this |
amendatory Act of the 99th General Assembly, an |
alternative retail electric supplier or its successor |
shall submit an informational filing to the Illinois |
Commerce Commission certifying that, as of December |
31, 2015, the alternative retail electric supplier |
owned one or more electric generating facilities that |
generates renewable energy resources as defined in |
Section 1-10 of this Act, provided that such facilities |
are not powered by wind or photovoltaics, and the |
facilities generate one renewable energy credit for |
each megawatthour of energy produced from the |
facility. |
The informational filing shall identify each |
|
facility that was eligible to satisfy the alternative |
retail electric supplier's obligations under Section |
16-115D of the Public Utilities Act as described in |
this item (i). |
(ii) For a given delivery year, the alternative |
retail electric supplier may elect to supply its retail |
customers with renewable energy credits from the |
facility or facilities described in item (i) of this |
subparagraph (H) that continue to be owned by the |
alternative retail electric supplier. |
(iii) The alternative retail electric supplier |
shall notify the Agency and the applicable utility, no |
later than February 28 of the year preceding the |
applicable delivery year or 15 days after the effective |
date of this amendatory Act of the 99th General |
Assembly, whichever is later, of its election under |
item (ii) of this subparagraph (H) to supply renewable |
energy credits to retail customers of the utility. Such |
election shall identify the amount of renewable energy |
credits to be supplied by the alternative retail |
electric supplier to the utility's retail customers |
and the source of the renewable energy credits |
identified in the informational filing as described in |
item (i) of this subparagraph (H), subject to the |
following limitations: |
For the delivery year beginning June 1, 2018, |
|
the maximum amount of renewable energy credits to |
be supplied by an alternative retail electric |
supplier under this subparagraph (H) shall be 68% |
multiplied by 25% multiplied by 14.5% multiplied |
by the amount of metered electricity |
(megawatt-hours) delivered by the alternative |
retail electric supplier to Illinois retail |
customers during the delivery year ending May 31, |
2016. |
For delivery years beginning June 1, 2019 and |
each year thereafter, the maximum amount of |
renewable energy credits to be supplied by an |
alternative retail electric supplier under this |
subparagraph (H) shall be 68% multiplied by 50% |
multiplied by 16% multiplied by the amount of |
metered electricity (megawatt-hours) delivered by |
the alternative retail electric supplier to |
Illinois retail customers during the delivery year |
ending May 31, 2016, provided that the 16% value |
shall increase by 1.5% each delivery year |
thereafter to 25% by the delivery year beginning |
June 1, 2025, and thereafter the 25% value shall |
apply to each delivery year. |
For each delivery year, the total amount of |
renewable energy credits supplied by all alternative |
retail electric suppliers under this subparagraph (H) |
|
shall not exceed 9% of the Illinois target renewable |
energy credit quantity. The Illinois target renewable |
energy credit quantity for the delivery year beginning |
June 1, 2018 is 14.5% multiplied by the total amount of |
metered electricity (megawatt-hours) delivered in the |
delivery year immediately preceding that delivery |
year, provided that the 14.5% shall increase by 1.5% |
each delivery year thereafter to 25% by the delivery |
year beginning June 1, 2025, and thereafter the 25% |
value shall apply to each delivery year. |
If the requirements set forth in items (i) through |
(iii) of this subparagraph (H) are met, the charges |
that would otherwise be applicable to the retail |
customers of the alternative retail electric supplier |
under paragraph (6) of this subsection (c) for the |
applicable delivery year shall be reduced by the ratio |
of the quantity of renewable energy credits supplied by |
the alternative retail electric supplier compared to |
that supplier's target renewable energy credit |
quantity. The supplier's target renewable energy |
credit quantity for the delivery year beginning June 1, |
2018 is 14.5% multiplied by the total amount of metered |
electricity (megawatt-hours) delivered by the |
alternative retail supplier in that delivery year, |
provided that the 14.5% shall increase by 1.5% each |
delivery year thereafter to 25% by the delivery year |
|
beginning June 1, 2025, and thereafter the 25% value |
shall apply to each delivery year. |
On or before April 1 of each year, the Agency shall |
annually publish a report on its website that |
identifies the aggregate amount of renewable energy |
credits supplied by alternative retail electric |
suppliers under this subparagraph (H). |
(I) The Agency shall design its long-term renewable |
energy procurement plan to maximize the State's interest in |
the health, safety, and welfare of its residents, including |
but not limited to minimizing sulfur dioxide, nitrogen |
oxide, particulate matter and other pollution that |
adversely affects public health in this State, increasing |
fuel and resource diversity in this State, enhancing the |
reliability and resiliency of the electricity distribution |
system in this State, meeting goals to limit carbon dioxide |
emissions under federal or State law, and contributing to a |
cleaner and healthier environment for the citizens of this |
State. In order to further these legislative purposes, |
renewable energy credits shall be eligible to be counted |
toward the renewable energy requirements of this |
subsection (c) if they are generated from facilities |
located in this State. The Agency may qualify renewable |
energy credits from facilities located in states adjacent |
to Illinois if the generator demonstrates and the Agency |
determines that the operation of such facility or |
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facilities will help promote the State's interest in the |
health, safety, and welfare of its residents based on the |
public interest criteria described above. To ensure that |
the public interest criteria are applied to the procurement |
and given full effect, the Agency's long-term procurement |
plan shall describe in detail how each public interest |
factor shall be considered and weighted for facilities |
located in states adjacent to Illinois. |
(J) In order to promote the competitive development of |
renewable energy resources in furtherance of the State's |
interest in the health, safety, and welfare of its |
residents, renewable energy credits shall not be eligible |
to be counted toward the renewable energy requirements of |
this subsection (c) if they are sourced from a generating |
unit whose costs were being recovered through rates |
regulated by this State or any other state or states on or |
after January 1, 2017. Each contract executed to purchase |
renewable energy credits under this subsection (c) shall |
provide for the contract's termination if the costs of the |
generating unit supplying the renewable energy credits |
subsequently begin to be recovered through rates regulated |
by this State or any other state or states; and each |
contract shall further provide that, in that event, the |
supplier of the credits must return 110% of all payments |
received under the contract. Amounts returned under the |
requirements of this subparagraph (J) shall be retained by |
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the utility and all of these amounts shall be used for the |
procurement of additional renewable energy credits from |
new wind or new photovoltaic resources as defined in this |
subsection (c). The long-term plan shall provide that these |
renewable energy credits shall be procured in the next |
procurement event. |
Notwithstanding the limitations of this subparagraph |
(J), renewable energy credits sourced from generating |
units that are constructed, purchased, owned, or leased by |
an electric utility as part of an approved project, |
program, or pilot under Section 1-56 of this Act shall be |
eligible to be counted toward the renewable energy |
requirements of this subsection (c), regardless of how the |
costs of these units are recovered. |
(K) The long-term renewable resources procurement plan |
developed by the Agency in accordance with subparagraph (A) |
of this paragraph (1) shall include an Adjustable Block |
program for the procurement of renewable energy credits |
from new photovoltaic projects that are distributed |
renewable energy generation devices or new photovoltaic |
community renewable generation projects. The Adjustable |
Block program shall be designed to provide a transparent |
schedule of prices and quantities to enable the |
photovoltaic market to scale up and for renewable energy |
credit prices to adjust at a predictable rate over time. |
The prices set by the Adjustable Block program can be |
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reflected as a set value or as the product of a formula. |
The Adjustable Block program shall include for each |
category of eligible projects: a schedule of standard block |
purchase prices to be offered; a series of steps, with |
associated nameplate capacity and purchase prices that |
adjust from step to step; and automatic opening of the next |
step as soon as the nameplate capacity and available |
purchase prices for an open step are fully committed or |
reserved. Only projects energized on or after June 1, 2017 |
shall be eligible for the Adjustable Block program. For |
each block group the Agency shall determine the number of |
blocks, the amount of generation capacity in each block, |
and the purchase price for each block, provided that the |
purchase price provided and the total amount of generation |
in all blocks for all block groups shall be sufficient to |
meet the goals in this subsection (c). The Agency may |
periodically review its prior decisions establishing the |
number of blocks, the amount of generation capacity in each |
block, and the purchase price for each block, and may |
propose, on an expedited basis, changes to these previously |
set values, including but not limited to redistributing |
these amounts and the available funds as necessary and |
appropriate, subject to Commission approval as part of the |
periodic plan revision process described in Section |
16-111.5 of the Public Utilities Act. The Agency may define |
different block sizes, purchase prices, or other distinct |
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terms and conditions for projects located in different |
utility service territories if the Agency deems it |
necessary to meet the goals in this subsection (c). |
The Adjustable Block program shall include at least the |
following block groups in at least the following amounts, |
which may be adjusted upon review by the Agency and |
approval by the Commission as described in this |
subparagraph (K): |
(i) At least 25% from distributed renewable energy |
generation devices with a nameplate capacity of no more |
than 10 kilowatts. |
(ii) At least 25% from distributed renewable |
energy generation devices with a nameplate capacity of |
more than 10 kilowatts and no more than 2,000 |
kilowatts. The Agency may create sub-categories within |
this category to account for the differences between |
projects for small commercial customers, large |
commercial customers, and public or non-profit |
customers. |
(iii) At least 25% from photovoltaic community |
renewable generation projects. |
(iv) The remaining 25% shall be allocated as |
specified by the Agency in the long-term renewable |
resources procurement plan. |
The Adjustable Block program shall be designed to |
ensure that renewable energy credits are procured from |
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photovoltaic distributed renewable energy generation |
devices and new photovoltaic community renewable energy |
generation projects in diverse locations and are not |
concentrated in a few geographic areas. |
(L) The procurement of photovoltaic renewable energy |
credits under items (i) through (iv) of subparagraph (K) of |
this paragraph (1) shall be subject to the following |
contract and payment terms: |
(i) The Agency shall procure contracts of at least |
15 years in length. |
(ii) For those renewable energy credits that |
qualify and are procured under item (i) of subparagraph |
(K) of this paragraph (1), the renewable energy credit |
purchase price shall be paid in full by the contracting |
utilities at the time that the facility producing the |
renewable energy credits is interconnected at the |
distribution system level of the utility and |
energized. The electric utility shall receive and |
retire all renewable energy credits generated by the |
project for the first 15 years of operation. |
(iii) For those renewable energy credits that |
qualify and are procured under item (ii) and (iii) of |
subparagraph (K) of this paragraph (1) and any |
additional categories of distributed generation |
included in the long-term renewable resources |
procurement plan and approved by the Commission, 20 |
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percent of the renewable energy credit purchase price |
shall be paid by the contracting utilities at the time |
that the facility producing the renewable energy |
credits is interconnected at the distribution system |
level of the utility and energized. The remaining |
portion shall be paid ratably over the subsequent |
4-year period. The electric utility shall receive and |
retire all renewable energy credits generated by the |
project for the first 15 years of operation. |
(iv) Each contract shall include provisions to |
ensure the delivery of the renewable energy credits for |
the full term of the contract. |
(v) The utility shall be the counterparty to the |
contracts executed under this subparagraph (L) that |
are approved by the Commission under the process |
described in Section 16-111.5 of the Public Utilities |
Act. No contract shall be executed for an amount that |
is less than one renewable energy credit per year. |
(vi) If, at any time, approved applications for the |
Adjustable Block program exceed funds collected by the |
electric utility or would cause the Agency to exceed |
the limitation described in subparagraph (E) of this |
paragraph (1) on the amount of renewable energy |
resources that may be procured, then the Agency shall |
consider future uncommitted funds to be reserved for |
these contracts on a first-come, first-served basis, |
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with the delivery of renewable energy credits required |
beginning at the time that the reserved funds become |
available. |
(vii) Nothing in this Section shall require the |
utility to advance any payment or pay any amounts that |
exceed the actual amount of revenues collected by the |
utility under paragraph (6) of this subsection (c) and |
subsection (k) of Section 16-108 of the Public |
Utilities Act, and contracts executed under this |
Section shall expressly incorporate this limitation. |
(M) The Agency shall be authorized to retain one or |
more experts or expert consulting firms to develop, |
administer, implement, operate, and evaluate the |
Adjustable Block program described in subparagraph (K) of |
this paragraph (1), and the Agency shall retain the |
consultant or consultants in the same manner, to the extent |
practicable, as the Agency retains others to administer |
provisions of this Act, including, but not limited to, the |
procurement administrator. The selection of experts and |
expert consulting firms and the procurement process |
described in this subparagraph (M) are exempt from the |
requirements of Section 20-10 of the Illinois Procurement |
Code, under Section 20-10 of that Code. The Agency shall |
strive to minimize administrative expenses in the |
implementation of the Adjustable Block program. |
The Agency and its consultant or consultants shall |
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monitor block activity, share program activity with |
stakeholders and conduct regularly scheduled meetings to |
discuss program activity and market conditions. If |
necessary, the Agency may make prospective administrative |
adjustments to the Adjustable Block program design, such as |
redistributing available funds or making adjustments to |
purchase prices as necessary to achieve the goals of this |
subsection (c). Program modifications to any price, |
capacity block, or other program element that do not |
deviate from the Commission's approved value by more than |
25% shall take effect immediately and are not subject to |
Commission review and approval. Program modifications to |
any price, capacity block, or other program element that |
deviate more than 25% from the Commission's approved value |
must be approved by the Commission as a long-term plan |
amendment under Section 16-111.5 of the Public Utilities |
Act. The Agency shall consider stakeholder feedback when |
making adjustments to the Adjustable Block design and shall |
notify stakeholders in advance of any planned changes. |
(N) The long-term renewable resources procurement plan |
required by this subsection (c) shall include a community |
renewable generation program. The Agency shall establish |
the terms, conditions, and program requirements for |
community renewable generation projects with a goal to |
expand renewable energy generating facility access to a |
broader group of energy consumers, to ensure robust |
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participation opportunities for residential and small |
commercial customers and those who cannot install |
renewable energy on their own properties. Any plan approved |
by the Commission shall allow subscriptions to community |
renewable generation projects to be portable and |
transferable. For purposes of this subparagraph (N), |
"portable" means that subscriptions may be retained by the |
subscriber even if the subscriber relocates or changes its |
address within the same utility service territory; and |
"transferable" means that a subscriber may assign or sell |
subscriptions to another person within the same utility |
service territory. |
Electric utilities shall provide a monetary credit to a |
subscriber's subsequent bill for service for the |
proportional output of a community renewable generation |
project attributable to that subscriber as specified in |
Section 16-107.5 of the Public Utilities Act. |
The Agency shall purchase renewable energy credits |
from subscribed shares of photovoltaic community renewable |
generation projects through the Adjustable Block program |
described in subparagraph (K) of this paragraph (1) or |
through the Illinois Solar for All Program described in |
Section 1-56 of this Act. The electric utility shall |
purchase any unsubscribed energy from community renewable |
generation projects that are Qualifying Facilities ("QF") |
under the electric utility's tariff for purchasing the |
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output from QFs under Public Utilities Regulatory Policies |
Act of 1978. |
The owners of and any subscribers to a community |
renewable generation project shall not be considered |
public utilities or alternative retail electricity |
suppliers under the Public Utilities Act solely as a result |
of their interest in or subscription to a community |
renewable generation project and shall not be required to |
become an alternative retail electric supplier by |
participating in a community renewable generation project |
with a public utility. |
(O) For the delivery year beginning June 1, 2018, the |
long-term renewable resources procurement plan required by |
this subsection (c) shall provide for the Agency to procure |
contracts to continue offering the Illinois Solar for All |
Program described in subsection (b) of Section 1-56 of this |
Act, and the contracts approved by the Commission shall be |
executed by the utilities that are subject to this |
subsection (c). The long-term renewable resources |
procurement plan shall allocate 5% of the funds available |
under the plan for the applicable delivery year, or |
$10,000,000 per delivery year, whichever is greater, to |
fund the programs, and the plan shall determine the amount |
of funding to be apportioned to the programs identified in |
subsection (b) of Section 1-56 of this Act; provided that |
for the delivery years beginning June 1, 2017, June 1, |
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2021, and June 1, 2025, the long-term renewable resources |
procurement plan shall allocate 10% of the funds available |
under the plan for the applicable delivery year, or |
$20,000,000 per delivery year, whichever is greater, and |
$10,000,000 of such funds in such year shall be used by an |
electric utility that serves more than 3,000,000 retail |
customers in the State to implement a Commission-approved |
plan under Section 16-108.12 of the Public Utilities Act. |
In making the determinations required under this |
subparagraph (O), the Commission shall consider the |
experience and performance under the programs and any |
evaluation reports. The Commission shall also provide for |
an independent evaluation of those programs on a periodic |
basis that are funded under this subparagraph (O). The |
procurement plans shall include cost-effective renewable |
energy resources. A minimum percentage of each utility's |
total supply to serve the load of eligible retail |
customers, as defined in Section 16-111.5(a) of the Public |
Utilities Act, procured for each of the following years |
shall be generated from cost-effective renewable energy |
resources: at least 2% by June 1, 2008; at least 4% by June |
1, 2009; at least 5% by June 1, 2010; at least 6% by June 1, |
2011; at least 7% by June 1, 2012; at least 8% by June 1, |
2013; at least 9% by June 1, 2014; at least 10% by June 1, |
2015; and increasing by at least 1.5% each year thereafter |
to at least 25% by June 1, 2025. To the extent that it is |
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available, at least 75% of the renewable energy resources |
used to meet these standards shall come from wind |
generation and, beginning on June 1, 2011, at least the |
following percentages of the renewable energy resources |
used to meet these standards shall come from photovoltaics |
on the following schedule: 0.5% by June 1, 2012, 1.5% by |
June 1, 2013; 3% by June 1, 2014; and 6% by June 1, 2015 and |
thereafter. Of the renewable energy resources procured |
pursuant to this Section, at least the following |
percentages shall come from distributed renewable energy |
generation devices: 0.5% by June 1, 2013, 0.75% by June 1, |
2014, and 1% by June 1, 2015 and thereafter. To the extent |
available, half of the renewable energy resources procured |
from distributed renewable energy generation shall come |
from devices of less than 25 kilowatts in nameplate |
capacity. Renewable energy resources procured from |
distributed generation devices may also count towards the |
required percentages for wind and solar photovoltaics. |
Procurement of renewable energy resources from distributed |
renewable energy generation devices shall be done on an |
annual basis through multi-year contracts of no less than 5 |
years, and shall consist solely of renewable energy |
credits. |
The Agency shall create credit requirements for |
suppliers of distributed renewable energy. In order to |
minimize the administrative burden on contracting |
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entities, the Agency shall solicit the use of third-party |
organizations to aggregate distributed renewable energy |
into groups of no less than one megawatt in installed |
capacity. These third-party organizations shall administer |
contracts with individual distributed renewable energy |
generation device owners. An individual distributed |
renewable energy generation device owner shall have the |
ability to measure the output of his or her distributed |
renewable energy generation device. |
For purposes of this subsection (c), "cost-effective" |
means that the costs of procuring renewable energy |
resources do not cause the limit stated in paragraph (2) of |
this subsection (c) to be exceeded and do not exceed |
benchmarks based on market prices for renewable energy |
resources in the region, which shall be developed by the |
procurement administrator, in consultation with the |
Commission staff, Agency staff, and the procurement |
monitor and shall be subject to Commission review and |
approval. |
(2) (Blank). For purposes of this subsection (c), the |
required procurement of cost-effective renewable energy |
resources for a particular year shall be measured as a |
percentage of the actual amount of electricity |
(megawatt-hours) supplied by the electric utility to |
eligible retail customers in the planning year ending |
immediately prior to the procurement. For purposes of this |
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subsection (c), the amount paid per kilowatthour means the |
total amount paid for electric service expressed on a per |
kilowatthour basis. For purposes of this subsection (c), |
the total amount paid for electric service includes without |
limitation amounts paid for supply, transmission, |
distribution, surcharges, and add-on taxes. |
Notwithstanding the requirements of this subsection |
(c), the total of renewable energy resources procured |
pursuant to the procurement plan for any single year shall |
be reduced by an amount necessary to limit the annual |
estimated average net increase due to the costs of these |
resources included in the amounts paid by eligible retail |
customers in connection with electric service to: |
(A) in 2008, no more than 0.5% of the amount paid |
per kilowatthour by those customers during the year |
ending May 31, 2007; |
(B) in 2009, the greater of an additional 0.5% of |
the amount paid per kilowatthour by those customers |
during the year ending May 31, 2008 or 1% of the amount |
paid per kilowatthour by those customers during the |
year ending May 31, 2007; |
(C) in 2010, the greater of an additional 0.5% of |
the amount paid per kilowatthour by those customers |
during the year ending May 31, 2009 or 1.5% of the |
amount paid per kilowatthour by those customers during |
the year ending May 31, 2007; |
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(D) in 2011, the greater of an additional 0.5% of |
the amount paid per kilowatthour by those customers |
during the year ending May 31, 2010 or 2% of the amount |
paid per kilowatthour by those customers during the |
year ending May 31, 2007; and |
(E) thereafter, the amount of renewable energy |
resources procured pursuant to the procurement plan |
for any single year shall be reduced by an amount |
necessary to limit the estimated average net increase |
due to the cost of these resources included in the |
amounts paid by eligible retail customers in |
connection with electric service to no more than the |
greater of 2.015% of the amount paid per kilowatthour |
by those customers during the year ending May 31, 2007 |
or the incremental amount per kilowatthour paid for |
these resources in 2011. |
No later than June 30, 2011, the Commission shall |
review the limitation on the amount of renewable energy |
resources procured pursuant to this subsection (c) and |
report to the General Assembly its findings as to |
whether that limitation unduly constrains the |
procurement of cost-effective renewable energy |
resources. |
(3) (Blank). Through June 1, 2011, renewable energy |
resources shall be counted for the purpose of meeting the |
renewable energy standards set forth in paragraph (1) of |
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this subsection (c) only if they are generated from |
facilities located in the State, provided that |
cost-effective renewable energy resources are available |
from those facilities. If those cost-effective resources |
are not available in Illinois, they shall be procured in |
states that adjoin Illinois and may be counted towards |
compliance. If those cost-effective resources are not |
available in Illinois or in states that adjoin Illinois, |
they shall be purchased elsewhere and shall be counted |
towards compliance. After June 1, 2011, cost-effective |
renewable energy resources located in Illinois and in |
states that adjoin Illinois may be counted towards |
compliance with the standards set forth in paragraph (1) of |
this subsection (c). If those cost-effective resources are |
not available in Illinois or in states that adjoin |
Illinois, they shall be purchased elsewhere and shall be |
counted towards compliance. |
(4) The electric utility shall retire all renewable |
energy credits used to comply with the standard. |
(5) Beginning with the 2010 delivery year and ending |
June 1, 2017 year commencing June 1, 2010 , an electric |
utility subject to this subsection (c) shall apply the |
lesser of the maximum alternative compliance payment rate |
or the most recent estimated alternative compliance |
payment rate for its service territory for the |
corresponding compliance period, established pursuant to |
|
subsection (d) of Section 16-115D of the Public Utilities |
Act to its retail customers that take service pursuant to |
the electric utility's hourly pricing tariff or tariffs. |
The electric utility shall retain all amounts collected as |
a result of the application of the alternative compliance |
payment rate or rates to such customers, and, beginning in |
2011, the utility shall include in the information provided |
under item (1) of subsection (d) of Section 16-111.5 of the |
Public Utilities Act the amounts collected under the |
alternative compliance payment rate or rates for the prior |
year ending May 31. Notwithstanding any limitation on the |
procurement of renewable energy resources imposed by item |
(2) of this subsection (c), the Agency shall increase its |
spending on the purchase of renewable energy resources to |
be procured by the electric utility for the next plan year |
by an amount equal to the amounts collected by the utility |
under the alternative compliance payment rate or rates in |
the prior year ending May 31. |
(6) The electric utility shall be entitled to recover |
all of its costs associated with the procurement of |
renewable energy credits under plans approved under this |
Section and Section 16-111.5 of the Public Utilities Act. |
These costs shall include associated reasonable expenses |
for implementing the procurement programs, including, but |
not limited to, the costs of administering and evaluating |
the Adjustable Block program, through an automatic |
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adjustment clause tariff in accordance with subsection (k) |
of Section 16-108 of the Public Utilities Act. |
(7) Renewable energy credits procured from new |
photovoltaic projects or new distributed renewable energy |
generation devices under this Section after the effective |
date of this amendatory Act of the 99th General Assembly |
must be procured from devices installed by a qualified |
person in compliance with the requirements of Section |
16-128A of the Public Utilities Act and any rules or |
regulations adopted thereunder. |
In meeting the renewable energy requirements of this |
subsection (c), to the extent feasible and consistent with |
State and federal law, the renewable energy credit |
procurements, Adjustable Block solar program, and |
community renewable generation program shall provide |
employment opportunities for all segments of the |
population and workforce, including minority-owned and |
female-owned business enterprises, and shall not, |
consistent with State and federal law, discriminate based |
on race or socioeconomic status. |
(d) Clean coal portfolio standard. |
(1) The procurement plans shall include electricity |
generated using clean coal. Each utility shall enter into |
one or more sourcing agreements with the initial clean coal |
facility, as provided in paragraph (3) of this subsection |
(d), covering electricity generated by the initial clean |
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coal facility representing at least 5% of each utility's |
total supply to serve the load of eligible retail customers |
in 2015 and each year thereafter, as described in paragraph |
(3) of this subsection (d), subject to the limits specified |
in paragraph (2) of this subsection (d). It is the goal of |
the State that by January 1, 2025, 25% of the electricity |
used in the State shall be generated by cost-effective |
clean coal facilities. For purposes of this subsection (d), |
"cost-effective" means that the expenditures pursuant to |
such sourcing agreements do not cause the limit stated in |
paragraph (2) of this subsection (d) to be exceeded and do |
not exceed cost-based benchmarks, which shall be developed |
to assess all expenditures pursuant to such sourcing |
agreements covering electricity generated by clean coal |
facilities, other than the initial clean coal facility, by |
the procurement administrator, in consultation with the |
Commission staff, Agency staff, and the procurement |
monitor and shall be subject to Commission review and |
approval. |
A utility party to a sourcing agreement shall |
immediately retire any emission credits that it receives in |
connection with the electricity covered by such agreement. |
Utilities shall maintain adequate records documenting |
the purchases under the sourcing agreement to comply with |
this subsection (d) and shall file an accounting with the |
load forecast that must be filed with the Agency by July 15 |
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of each year, in accordance with subsection (d) of Section |
16-111.5 of the Public Utilities Act. |
A utility shall be deemed to have complied with the |
clean coal portfolio standard specified in this subsection |
(d) if the utility enters into a sourcing agreement as |
required by this subsection (d). |
(2) For purposes of this subsection (d), the required |
execution of sourcing agreements with the initial clean |
coal facility for a particular year shall be measured as a |
percentage of the actual amount of electricity |
(megawatt-hours) supplied by the electric utility to |
eligible retail customers in the planning year ending |
immediately prior to the agreement's execution. For |
purposes of this subsection (d), the amount paid per |
kilowatthour means the total amount paid for electric |
service expressed on a per kilowatthour basis. For purposes |
of this subsection (d), the total amount paid for electric |
service includes without limitation amounts paid for |
supply, transmission, distribution, surcharges and add-on |
taxes. |
Notwithstanding the requirements of this subsection |
(d), the total amount paid under sourcing agreements with |
clean coal facilities pursuant to the procurement plan for |
any given year shall be reduced by an amount necessary to |
limit the annual estimated average net increase due to the |
costs of these resources included in the amounts paid by |
|
eligible retail customers in connection with electric |
service to: |
(A) in 2010, no more than 0.5% of the amount paid |
per kilowatthour by those customers during the year |
ending May 31, 2009; |
(B) in 2011, the greater of an additional 0.5% of |
the amount paid per kilowatthour by those customers |
during the year ending May 31, 2010 or 1% of the amount |
paid per kilowatthour by those customers during the |
year ending May 31, 2009; |
(C) in 2012, the greater of an additional 0.5% of |
the amount paid per kilowatthour by those customers |
during the year ending May 31, 2011 or 1.5% of the |
amount paid per kilowatthour by those customers during |
the year ending May 31, 2009; |
(D) in 2013, the greater of an additional 0.5% of |
the amount paid per kilowatthour by those customers |
during the year ending May 31, 2012 or 2% of the amount |
paid per kilowatthour by those customers during the |
year ending May 31, 2009; and |
(E) thereafter, the total amount paid under |
sourcing agreements with clean coal facilities |
pursuant to the procurement plan for any single year |
shall be reduced by an amount necessary to limit the |
estimated average net increase due to the cost of these |
resources included in the amounts paid by eligible |
|
retail customers in connection with electric service |
to no more than the greater of (i) 2.015% of the amount |
paid per kilowatthour by those customers during the |
year ending May 31, 2009 or (ii) the incremental amount |
per kilowatthour paid for these resources in 2013. |
These requirements may be altered only as provided by |
statute. |
No later than June 30, 2015, the Commission shall |
review the limitation on the total amount paid under |
sourcing agreements, if any, with clean coal facilities |
pursuant to this subsection (d) and report to the General |
Assembly its findings as to whether that limitation unduly |
constrains the amount of electricity generated by |
cost-effective clean coal facilities that is covered by |
sourcing agreements. |
(3) Initial clean coal facility. In order to promote |
development of clean coal facilities in Illinois, each |
electric utility subject to this Section shall execute a |
sourcing agreement to source electricity from a proposed |
clean coal facility in Illinois (the "initial clean coal |
facility") that will have a nameplate capacity of at least |
500 MW when commercial operation commences, that has a |
final Clean Air Act permit on the effective date of this |
amendatory Act of the 95th General Assembly, and that will |
meet the definition of clean coal facility in Section 1-10 |
of this Act when commercial operation commences. The |
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sourcing agreements with this initial clean coal facility |
shall be subject to both approval of the initial clean coal |
facility by the General Assembly and satisfaction of the |
requirements of paragraph (4) of this subsection (d) and |
shall be executed within 90 days after any such approval by |
the General Assembly. The Agency and the Commission shall |
have authority to inspect all books and records associated |
with the initial clean coal facility during the term of |
such a sourcing agreement. A utility's sourcing agreement |
for electricity produced by the initial clean coal facility |
shall include: |
(A) a formula contractual price (the "contract |
price") approved pursuant to paragraph (4) of this |
subsection (d), which shall: |
(i) be determined using a cost of service |
methodology employing either a level or deferred |
capital recovery component, based on a capital |
structure consisting of 45% equity and 55% debt, |
and a return on equity as may be approved by the |
Federal Energy Regulatory Commission, which in any |
case may not exceed the lower of 11.5% or the rate |
of return approved by the General Assembly |
pursuant to paragraph (4) of this subsection (d); |
and |
(ii) provide that all miscellaneous net |
revenue, including but not limited to net revenue |
|
from the sale of emission allowances, if any, |
substitute natural gas, if any, grants or other |
support provided by the State of Illinois or the |
United States Government, firm transmission |
rights, if any, by-products produced by the |
facility, energy or capacity derived from the |
facility and not covered by a sourcing agreement |
pursuant to paragraph (3) of this subsection (d) or |
item (5) of subsection (d) of Section 16-115 of the |
Public Utilities Act, whether generated from the |
synthesis gas derived from coal, from SNG, or from |
natural gas, shall be credited against the revenue |
requirement for this initial clean coal facility; |
(B) power purchase provisions, which shall: |
(i) provide that the utility party to such |
sourcing agreement shall pay the contract price |
for electricity delivered under such sourcing |
agreement; |
(ii) require delivery of electricity to the |
regional transmission organization market of the |
utility that is party to such sourcing agreement; |
(iii) require the utility party to such |
sourcing agreement to buy from the initial clean |
coal facility in each hour an amount of energy |
equal to all clean coal energy made available from |
the initial clean coal facility during such hour |
|
times a fraction, the numerator of which is such |
utility's retail market sales of electricity |
(expressed in kilowatthours sold) in the State |
during the prior calendar month and the |
denominator of which is the total retail market |
sales of electricity (expressed in kilowatthours |
sold) in the State by utilities during such prior |
month and the sales of electricity (expressed in |
kilowatthours sold) in the State by alternative |
retail electric suppliers during such prior month |
that are subject to the requirements of this |
subsection (d) and paragraph (5) of subsection (d) |
of Section 16-115 of the Public Utilities Act, |
provided that the amount purchased by the utility |
in any year will be limited by paragraph (2) of |
this subsection (d); and |
(iv) be considered pre-existing contracts in |
such utility's procurement plans for eligible |
retail customers; |
(C) contract for differences provisions, which |
shall: |
(i) require the utility party to such sourcing |
agreement to contract with the initial clean coal |
facility in each hour with respect to an amount of |
energy equal to all clean coal energy made |
available from the initial clean coal facility |
|
during such hour times a fraction, the numerator of |
which is such utility's retail market sales of |
electricity (expressed in kilowatthours sold) in |
the utility's service territory in the State |
during the prior calendar month and the |
denominator of which is the total retail market |
sales of electricity (expressed in kilowatthours |
sold) in the State by utilities during such prior |
month and the sales of electricity (expressed in |
kilowatthours sold) in the State by alternative |
retail electric suppliers during such prior month |
that are subject to the requirements of this |
subsection (d) and paragraph (5) of subsection (d) |
of Section 16-115 of the Public Utilities Act, |
provided that the amount paid by the utility in any |
year will be limited by paragraph (2) of this |
subsection (d); |
(ii) provide that the utility's payment |
obligation in respect of the quantity of |
electricity determined pursuant to the preceding |
clause (i) shall be limited to an amount equal to |
(1) the difference between the contract price |
determined pursuant to subparagraph (A) of |
paragraph (3) of this subsection (d) and the |
day-ahead price for electricity delivered to the |
regional transmission organization market of the |
|
utility that is party to such sourcing agreement |
(or any successor delivery point at which such |
utility's supply obligations are financially |
settled on an hourly basis) (the "reference |
price") on the day preceding the day on which the |
electricity is delivered to the initial clean coal |
facility busbar, multiplied by (2) the quantity of |
electricity determined pursuant to the preceding |
clause (i); and |
(iii) not require the utility to take physical |
delivery of the electricity produced by the |
facility; |
(D) general provisions, which shall: |
(i) specify a term of no more than 30 years, |
commencing on the commercial operation date of the |
facility; |
(ii) provide that utilities shall maintain |
adequate records documenting purchases under the |
sourcing agreements entered into to comply with |
this subsection (d) and shall file an accounting |
with the load forecast that must be filed with the |
Agency by July 15 of each year, in accordance with |
subsection (d) of Section 16-111.5 of the Public |
Utilities Act; |
(iii) provide that all costs associated with |
the initial clean coal facility will be |
|
periodically reported to the Federal Energy |
Regulatory Commission and to purchasers in |
accordance with applicable laws governing |
cost-based wholesale power contracts; |
(iv) permit the Illinois Power Agency to |
assume ownership of the initial clean coal |
facility, without monetary consideration and |
otherwise on reasonable terms acceptable to the |
Agency, if the Agency so requests no less than 3 |
years prior to the end of the stated contract term; |
(v) require the owner of the initial clean coal |
facility to provide documentation to the |
Commission each year, starting in the facility's |
first year of commercial operation, accurately |
reporting the quantity of carbon emissions from |
the facility that have been captured and |
sequestered and report any quantities of carbon |
released from the site or sites at which carbon |
emissions were sequestered in prior years, based |
on continuous monitoring of such sites. If, in any |
year after the first year of commercial operation, |
the owner of the facility fails to demonstrate that |
the initial clean coal facility captured and |
sequestered at least 50% of the total carbon |
emissions that the facility would otherwise emit |
or that sequestration of emissions from prior |
|
years has failed, resulting in the release of |
carbon dioxide into the atmosphere, the owner of |
the facility must offset excess emissions. Any |
such carbon offsets must be permanent, additional, |
verifiable, real, located within the State of |
Illinois, and legally and practicably enforceable. |
The cost of such offsets for the facility that are |
not recoverable shall not exceed $15 million in any |
given year. No costs of any such purchases of |
carbon offsets may be recovered from a utility or |
its customers. All carbon offsets purchased for |
this purpose and any carbon emission credits |
associated with sequestration of carbon from the |
facility must be permanently retired. The initial |
clean coal facility shall not forfeit its |
designation as a clean coal facility if the |
facility fails to fully comply with the applicable |
carbon sequestration requirements in any given |
year, provided the requisite offsets are |
purchased. However, the Attorney General, on |
behalf of the People of the State of Illinois, may |
specifically enforce the facility's sequestration |
requirement and the other terms of this contract |
provision. Compliance with the sequestration |
requirements and offset purchase requirements |
specified in paragraph (3) of this subsection (d) |
|
shall be reviewed annually by an independent |
expert retained by the owner of the initial clean |
coal facility, with the advance written approval |
of the Attorney General. The Commission may, in the |
course of the review specified in item (vii), |
reduce the allowable return on equity for the |
facility if the facility wilfully fails to comply |
with the carbon capture and sequestration |
requirements set forth in this item (v); |
(vi) include limits on, and accordingly |
provide for modification of, the amount the |
utility is required to source under the sourcing |
agreement consistent with paragraph (2) of this |
subsection (d); |
(vii) require Commission review: (1) to |
determine the justness, reasonableness, and |
prudence of the inputs to the formula referenced in |
subparagraphs (A)(i) through (A)(iii) of paragraph |
(3) of this subsection (d), prior to an adjustment |
in those inputs including, without limitation, the |
capital structure and return on equity, fuel |
costs, and other operations and maintenance costs |
and (2) to approve the costs to be passed through |
to customers under the sourcing agreement by which |
the utility satisfies its statutory obligations. |
Commission review shall occur no less than every 3 |
|
years, regardless of whether any adjustments have |
been proposed, and shall be completed within 9 |
months; |
(viii) limit the utility's obligation to such |
amount as the utility is allowed to recover through |
tariffs filed with the Commission, provided that |
neither the clean coal facility nor the utility |
waives any right to assert federal pre-emption or |
any other argument in response to a purported |
disallowance of recovery costs; |
(ix) limit the utility's or alternative retail |
electric supplier's obligation to incur any |
liability until such time as the facility is in |
commercial operation and generating power and |
energy and such power and energy is being delivered |
to the facility busbar; |
(x) provide that the owner or owners of the |
initial clean coal facility, which is the |
counterparty to such sourcing agreement, shall |
have the right from time to time to elect whether |
the obligations of the utility party thereto shall |
be governed by the power purchase provisions or the |
contract for differences provisions; |
(xi) append documentation showing that the |
formula rate and contract, insofar as they relate |
to the power purchase provisions, have been |
|
approved by the Federal Energy Regulatory |
Commission pursuant to Section 205 of the Federal |
Power Act; |
(xii) provide that any changes to the terms of |
the contract, insofar as such changes relate to the |
power purchase provisions, are subject to review |
under the public interest standard applied by the |
Federal Energy Regulatory Commission pursuant to |
Sections 205 and 206 of the Federal Power Act; and |
(xiii) conform with customary lender |
requirements in power purchase agreements used as |
the basis for financing non-utility generators. |
(4) Effective date of sourcing agreements with the |
initial clean coal facility. |
Any proposed sourcing agreement with the initial clean |
coal facility shall not become effective unless the |
following reports are prepared and submitted and |
authorizations and approvals obtained: |
(i) Facility cost report. The owner of the initial |
clean coal facility shall submit to the Commission, the |
Agency, and the General Assembly a front-end |
engineering and design study, a facility cost report, |
method of financing (including but not limited to |
structure and associated costs), and an operating and |
maintenance cost quote for the facility (collectively |
"facility cost report"), which shall be prepared in |
|
accordance with the requirements of this paragraph (4) |
of subsection (d) of this Section, and shall provide |
the Commission and the Agency access to the work |
papers, relied upon documents, and any other backup |
documentation related to the facility cost report. |
(ii) Commission report. Within 6 months following |
receipt of the facility cost report, the Commission, in |
consultation with the Agency, shall submit a report to |
the General Assembly setting forth its analysis of the |
facility cost report. Such report shall include, but |
not be limited to, a comparison of the costs associated |
with electricity generated by the initial clean coal |
facility to the costs associated with electricity |
generated by other types of generation facilities, an |
analysis of the rate impacts on residential and small |
business customers over the life of the sourcing |
agreements, and an analysis of the likelihood that the |
initial clean coal facility will commence commercial |
operation by and be delivering power to the facility's |
busbar by 2016. To assist in the preparation of its |
report, the Commission, in consultation with the |
Agency, may hire one or more experts or consultants, |
the costs of which shall be paid for by the owner of |
the initial clean coal facility. The Commission and |
Agency may begin the process of selecting such experts |
or consultants prior to receipt of the facility cost |
|
report. |
(iii) General Assembly approval. The proposed |
sourcing agreements shall not take effect unless, |
based on the facility cost report and the Commission's |
report, the General Assembly enacts authorizing |
legislation approving (A) the projected price, stated |
in cents per kilowatthour, to be charged for |
electricity generated by the initial clean coal |
facility, (B) the projected impact on residential and |
small business customers' bills over the life of the |
sourcing agreements, and (C) the maximum allowable |
return on equity for the project; and |
(iv) Commission review. If the General Assembly |
enacts authorizing legislation pursuant to |
subparagraph (iii) approving a sourcing agreement, the |
Commission shall, within 90 days of such enactment, |
complete a review of such sourcing agreement. During |
such time period, the Commission shall implement any |
directive of the General Assembly, resolve any |
disputes between the parties to the sourcing agreement |
concerning the terms of such agreement, approve the |
form of such agreement, and issue an order finding that |
the sourcing agreement is prudent and reasonable. |
The facility cost report shall be prepared as follows: |
(A) The facility cost report shall be prepared by |
duly licensed engineering and construction firms |
|
detailing the estimated capital costs payable to one or |
more contractors or suppliers for the engineering, |
procurement and construction of the components |
comprising the initial clean coal facility and the |
estimated costs of operation and maintenance of the |
facility. The facility cost report shall include: |
(i) an estimate of the capital cost of the core |
plant based on one or more front end engineering |
and design studies for the gasification island and |
related facilities. The core plant shall include |
all civil, structural, mechanical, electrical, |
control, and safety systems. |
(ii) an estimate of the capital cost of the |
balance of the plant, including any capital costs |
associated with sequestration of carbon dioxide |
emissions and all interconnects and interfaces |
required to operate the facility, such as |
transmission of electricity, construction or |
backfeed power supply, pipelines to transport |
substitute natural gas or carbon dioxide, potable |
water supply, natural gas supply, water supply, |
water discharge, landfill, access roads, and coal |
delivery. |
The quoted construction costs shall be expressed |
in nominal dollars as of the date that the quote is |
prepared and shall include capitalized financing costs |
|
during construction,
taxes, insurance, and other |
owner's costs, and an assumed escalation in materials |
and labor beyond the date as of which the construction |
cost quote is expressed. |
(B) The front end engineering and design study for |
the gasification island and the cost study for the |
balance of plant shall include sufficient design work |
to permit quantification of major categories of |
materials, commodities and labor hours, and receipt of |
quotes from vendors of major equipment required to |
construct and operate the clean coal facility. |
(C) The facility cost report shall also include an |
operating and maintenance cost quote that will provide |
the estimated cost of delivered fuel, personnel, |
maintenance contracts, chemicals, catalysts, |
consumables, spares, and other fixed and variable |
operations and maintenance costs. The delivered fuel |
cost estimate will be provided by a recognized third |
party expert or experts in the fuel and transportation |
industries. The balance of the operating and |
maintenance cost quote, excluding delivered fuel |
costs, will be developed based on the inputs provided |
by duly licensed engineering and construction firms |
performing the construction cost quote, potential |
vendors under long-term service agreements and plant |
operating agreements, or recognized third party plant |
|
operator or operators. |
The operating and maintenance cost quote |
(including the cost of the front end engineering and |
design study) shall be expressed in nominal dollars as |
of the date that the quote is prepared and shall |
include taxes, insurance, and other owner's costs, and |
an assumed escalation in materials and labor beyond the |
date as of which the operating and maintenance cost |
quote is expressed. |
(D) The facility cost report shall also include an |
analysis of the initial clean coal facility's ability |
to deliver power and energy into the applicable |
regional transmission organization markets and an |
analysis of the expected capacity factor for the |
initial clean coal facility. |
(E) Amounts paid to third parties unrelated to the |
owner or owners of the initial clean coal facility to |
prepare the core plant construction cost quote, |
including the front end engineering and design study, |
and the operating and maintenance cost quote will be |
reimbursed through Coal Development Bonds. |
(5) Re-powering and retrofitting coal-fired power |
plants previously owned by Illinois utilities to qualify as |
clean coal facilities. During the 2009 procurement |
planning process and thereafter, the Agency and the |
Commission shall consider sourcing agreements covering |
|
electricity generated by power plants that were previously |
owned by Illinois utilities and that have been or will be |
converted into clean coal facilities, as defined by Section |
1-10 of this Act. Pursuant to such procurement planning |
process, the owners of such facilities may propose to the |
Agency sourcing agreements with utilities and alternative |
retail electric suppliers required to comply with |
subsection (d) of this Section and item (5) of subsection |
(d) of Section 16-115 of the Public Utilities Act, covering |
electricity generated by such facilities. In the case of |
sourcing agreements that are power purchase agreements, |
the contract price for electricity sales shall be |
established on a cost of service basis. In the case of |
sourcing agreements that are contracts for differences, |
the contract price from which the reference price is |
subtracted shall be established on a cost of service basis. |
The Agency and the Commission may approve any such utility |
sourcing agreements that do not exceed cost-based |
benchmarks developed by the procurement administrator, in |
consultation with the Commission staff, Agency staff and |
the procurement monitor, subject to Commission review and |
approval. The Commission shall have authority to inspect |
all books and records associated with these clean coal |
facilities during the term of any such contract. |
(6) Costs incurred under this subsection (d) or |
pursuant to a contract entered into under this subsection |
|
(d) shall be deemed prudently incurred and reasonable in |
amount and the electric utility shall be entitled to full |
cost recovery pursuant to the tariffs filed with the |
Commission. |
(d-5) Zero emission standard. |
(1) Beginning with the delivery year commencing on June |
1, 2017, the Agency shall, for electric utilities that |
serve at least 100,000 retail customers in this State, |
procure contracts with zero emission facilities that are |
reasonably capable of generating cost-effective zero |
emission credits in an amount approximately equal to 16% of |
the actual amount of electricity delivered by each electric |
utility to retail customers in the State during calendar |
year 2014. For an electric utility serving fewer than |
100,000 retail customers in this State that requested, |
under Section 16-111.5 of the Public Utilities Act, that |
the Agency procure power and energy for all or a portion of |
the utility's Illinois load for the delivery year |
commencing June 1, 2016, the Agency shall procure contracts |
with zero emission facilities that are reasonably capable |
of generating cost-effective zero emission credits in an |
amount approximately equal to 16% of the portion of power |
and energy to be procured by the Agency for the utility. |
The duration of the contracts procured under this |
subsection (d-5) shall be for a term of 10 years ending May |
31, 2027. The quantity of zero emission credits to be |
|
procured under the contracts shall be all of the zero |
emission credits generated by the zero emission facility in |
each delivery year; however, if the zero emission facility |
is owned by more than one entity, then the quantity of zero |
emission credits to be procured under the contracts shall |
be the amount of zero emission credits that are generated |
from the portion of the zero emission facility that is |
owned by the winning supplier. |
The 16% value identified in this paragraph (1) is the |
average of the percentage targets in subparagraph (B) of |
paragraph (1) of subsection (c) of Section 1-75 of this Act |
for the 5 delivery years beginning June 1, 2017. |
The procurement process shall be subject to the |
following provisions: |
(A) Those zero emission facilities that intend to |
participate in the procurement shall submit to the |
Agency the following eligibility information for each |
zero emission facility on or before the date |
established by the Agency: |
(i) the in-service date and remaining useful |
life of the zero emission facility; |
(ii) the amount of power generated annually |
for each of the years 2005 through 2015, and the |
projected zero emission credits to be generated |
over the remaining useful life of the zero emission |
facility, which shall be used to determine the |
|
capability of each facility; |
(iii) the annual zero emission facility cost |
projections, expressed on a per megawatthour |
basis, over the next 6 delivery years, which shall |
include the following: operation and maintenance |
expenses; fully allocated overhead costs, which |
shall be allocated using the methodology developed |
by the Institute for Nuclear Power Operations; |
fuel expenditures; non-fuel capital expenditures; |
spent fuel expenditures; a return on working |
capital; the cost of operational and market risks |
that could be avoided by ceasing operation; and any |
other costs necessary for continued operations, |
provided that "necessary" means, for purposes of |
this item (iii), that the costs could reasonably be |
avoided only by ceasing operations of the zero |
emission facility; and |
(iv) a commitment to continue operating, for |
the duration of the contract or contracts executed |
under the procurement held under this subsection |
(d-5), the zero emission facility that produces |
the zero emission credits to be procured in the |
procurement. |
The information described in item (iii) of this |
subparagraph (A) may be submitted on a confidential basis |
and shall be treated and maintained by the Agency, the |
|
procurement administrator, and the Commission as |
confidential and proprietary and exempt from disclosure |
under subparagraphs (a) and (g) of paragraph (1) of Section |
7 of the Freedom of Information Act. The Office of Attorney |
General shall have access to, and maintain the |
confidentiality of, such information pursuant to Section |
6.5 of the Attorney General Act. |
(B) The price for each zero emission credit |
procured under this subsection (d-5) for each delivery |
year shall be in an amount that equals the Social Cost |
of Carbon, expressed on a price per megawatthour basis. |
However, to ensure that the procurement remains |
affordable to retail customers in this State if |
electricity prices increase, the price in an |
applicable delivery year shall be reduced below the |
Social Cost of Carbon by the amount ("Price |
Adjustment") by which the market price index for the |
applicable delivery year exceeds the baseline market |
price index for the consecutive 12-month period ending |
May 31, 2016. If the Price Adjustment is greater than |
or equal to the Social Cost of Carbon in an applicable |
delivery year, then no payments shall be due in that |
delivery year. The components of this calculation are |
defined as follows: |
(i) Social Cost of Carbon: The Social Cost of |
Carbon is $16.50 per megawatthour, which is based |
|
on the U.S. Interagency Working Group on Social |
Cost of Carbon's price in the August 2016 Technical |
Update using a 3% discount rate, adjusted for |
inflation for each year of the program. Beginning |
with the delivery year commencing June 1, 2023, the |
price per megawatthour shall increase by $1 per |
megawatthour, and continue to increase by an |
additional $1 per megawatthour each delivery year |
thereafter. |
(ii) Baseline market price index: The baseline |
market price index for the consecutive 12-month |
period ending May 31, 2016 is $31.40 per |
megawatthour, which is based on the sum of (aa) the |
average day-ahead energy price across all hours of |
such 12-month period at the PJM Interconnection |
LLC Northern Illinois Hub, (bb) 50% multiplied by |
the Base Residual Auction, or its successor, |
capacity price for the rest of the RTO zone group |
determined by PJM Interconnection LLC, divided by |
24 hours per day, and (cc) 50% multiplied by the |
Planning Resource Auction, or its successor, |
capacity price for Zone 4 determined by the |
Midcontinent Independent System Operator, Inc., |
divided by 24 hours per day. |
(iii) Market price index: The market price |
index for a delivery year shall be the sum of |
|
projected energy prices and projected capacity |
prices determined as follows: |
(aa) Projected energy prices: the |
projected energy prices for the applicable |
delivery year shall be calculated once for the |
year using the forward market price for the PJM |
Interconnection, LLC Northern Illinois Hub. |
The forward market price shall be calculated as |
follows: the energy forward prices for each |
month of the applicable delivery year averaged |
for each trade date during the calendar year |
immediately preceding that delivery year to |
produce a single energy forward price for the |
delivery year. The forward market price |
calculation shall use data published by the |
Intercontinental Exchange, or its successor. |
(bb) Projected capacity prices: |
(I) For the delivery years commencing |
June 1, 2017, June 1, 2018, and June 1, |
2019, the projected capacity price shall |
be equal to the sum of (1) 50% multiplied |
by the Base Residual Auction, or its |
successor, price for the rest of the RTO |
zone group as determined by PJM |
Interconnection LLC, divided by 24 hours |
per day and, (2) 50% multiplied by the |
|
resource auction price determined in the |
resource auction administered by the |
Midcontinent Independent System Operator, |
Inc., in which the largest percentage of |
load cleared for Local Resource Zone 4, |
divided by 24 hours per day, and where such |
price is determined by the Midcontinent |
Independent System Operator, Inc. |
(II) For the delivery year commencing |
June 1, 2020, and each year thereafter, the |
projected capacity price shall be equal to |
the sum of (1) 50% multiplied by the Base |
Residual Auction, or its successor, price |
for the ComEd zone as determined by PJM |
Interconnection LLC, divided by 24 hours |
per day, and (2) 50% multiplied by the |
resource auction price determined in the |
resource auction administered by the |
Midcontinent Independent System Operator, |
Inc., in which the largest percentage of |
load cleared for Local Resource Zone 4, |
divided by 24 hours per day, and where such |
price is determined by the Midcontinent |
Independent System Operator, Inc. |
For purposes of this subsection (d-5): |
"Rest of the RTO" and "ComEd Zone" shall have |
|
the meaning ascribed to them by PJM |
Interconnection, LLC. |
"RTO" means regional transmission |
organization. |
(C) No later than 45 days after the effective date |
of this amendatory Act of the 99th General Assembly, |
the Agency shall publish its proposed zero emission |
standard procurement plan. The plan shall be |
consistent with the provisions of this paragraph (1) |
and shall provide that winning bids shall be selected |
based on public interest criteria that include, but are |
not limited to, minimizing carbon dioxide emissions |
that result from electricity consumed in Illinois and |
minimizing sulfur dioxide, nitrogen oxide, and |
particulate matter emissions that adversely affect the |
citizens of this State. In particular, the selection of |
winning bids shall take into account the incremental |
environmental benefits resulting from the procurement, |
such as any existing environmental benefits that are |
preserved by the procurements held under this |
amendatory Act of the 99th General Assembly and would |
cease to exist if the procurements were not held, |
including the preservation of zero emission |
facilities. The plan shall also describe in detail how |
each public interest factor shall be considered and |
weighted in the bid selection process to ensure that |
|
the public interest criteria are applied to the |
procurement and given full effect. |
For purposes of developing the plan, the Agency |
shall consider any reports issued by a State agency, |
board, or commission under House Resolution 1146 of the |
98th General Assembly and paragraph (4) of subsection |
(d) of Section 1-75 of this Act, as well as publicly |
available analyses and studies performed by or for |
regional transmission organizations that serve the |
State and their independent market monitors. |
Upon publishing of the zero emission standard |
procurement plan, copies of the plan shall be posted |
and made publicly available on the Agency's website. |
All interested parties shall have 10 days following the |
date of posting to provide comment to the Agency on the |
plan. All comments shall be posted to the Agency's |
website. Following the end of the comment period, but |
no more than 60 days later than the effective date of |
this amendatory Act of the 99th General Assembly, the |
Agency shall revise the plan as necessary based on the |
comments received and file its zero emission standard |
procurement plan with the Commission. |
If the Commission determines that the plan will |
result in the procurement of cost-effective zero |
emission credits, then the Commission shall, after |
notice and hearing, but no later than 45 days after the |
|
Agency filed the plan, approve the plan or approve with |
modification. For purposes of this subsection (d-5), |
"cost effective" means the projected costs of |
procuring zero emission credits from zero emission |
facilities do not cause the limit stated in paragraph |
(2) of this subsection to be exceeded. |
(C-5) As part of the Commission's review and |
acceptance or rejection of the procurement results, |
the Commission shall, in its public notice of |
successful bidders: |
(i) identify how the winning bids satisfy the |
public interest criteria described in subparagraph |
(C) of this paragraph (1) of minimizing carbon |
dioxide emissions that result from electricity |
consumed in Illinois and minimizing sulfur |
dioxide, nitrogen oxide, and particulate matter |
emissions that adversely affect the citizens of |
this State; |
(ii) specifically address how the selection of |
winning bids takes into account the incremental |
environmental benefits resulting from the |
procurement, including any existing environmental |
benefits that are preserved by the procurements |
held under this amendatory Act of the 99th General |
Assembly and would have ceased to exist if the |
procurements had not been held, such as the |
|
preservation of zero emission facilities; |
(iii) quantify the environmental benefit of |
preserving the resources identified in item (ii) |
of this subparagraph (C-5), including the |
following: |
(aa) the value of avoided greenhouse gas |
emissions measured as the product of the zero |
emission facilities' output over the contract |
term multiplied by the U.S. Environmental |
Protection Agency eGrid subregion carbon |
dioxide emission rate and the U.S. Interagency |
Working Group on Social Cost of Carbon's price |
in the August 2016 Technical Update using a 3% |
discount rate, adjusted for inflation for each |
delivery year; and |
(bb) the costs of replacement with other |
zero carbon dioxide resources, including wind |
and photovoltaic, based upon the simple |
average of the following: |
(I) the price, or if there is more than |
one price, the average of the prices, paid |
for renewable energy credits from new |
utility-scale wind projects in the |
procurement events specified in item (i) |
of subparagraph (G) of paragraph (1) of |
subsection (c) of Section 1-75 of this Act; |
|
and |
(II) the price, or if there is more |
than one price, the average of the prices, |
paid for renewable energy credits from new |
utility-scale solar projects and |
brownfield site photovoltaic projects in |
the procurement events specified in item |
(ii) of subparagraph (G) of paragraph (1) |
of subsection (c) of Section 1-75 of this |
Act and, after January 1, 2015, renewable |
energy credits from photovoltaic |
distributed generation projects in |
procurement events held under subsection |
(c) of Section 1-75 of this Act. |
Each utility shall enter into binding contractual arrangements |
with the winning suppliers. |
The procurement described in this subsection |
(d-5), including, but not limited to, the execution of |
all contracts procured, shall be completed no later |
than May 10, 2017. Based on the effective date of this |
amendatory Act of the 99th General Assembly, the Agency |
and Commission may, as appropriate, modify the various |
dates and timelines under this subparagraph and |
subparagraphs (C) and (D) of this paragraph (1). The |
procurement and plan approval processes required by |
this subsection (d-5) shall be conducted in |
|
conjunction with the procurement and plan approval |
processes required by subsection (c) of this Section |
and Section 16-111.5 of the Public Utilities Act, to |
the extent practicable. Notwithstanding whether a |
procurement event is conducted under Section 16-111.5 |
of the Public Utilities Act, the Agency shall |
immediately initiate a procurement process on the |
effective date of this amendatory Act of the 99th |
General Assembly. |
(D) Following the procurement event described in |
this paragraph (1) and consistent with subparagraph |
(B) of this paragraph (1), the Agency shall calculate |
the payments to be made under each contract for the |
next delivery year based on the market price index for |
that delivery year. The Agency shall publish the |
payment calculations no later than May 25, 2017 and |
every May 25 thereafter. |
(E) Notwithstanding the requirements of this |
subsection (d-5), the contracts executed under this |
subsection (d-5) shall provide that the zero emission |
facility may, as applicable, suspend or terminate |
performance under the contracts in the following |
instances: |
(i) A zero emission facility shall be excused |
from its performance under the contract for any |
cause beyond the control of the resource, |
|
including, but not restricted to, acts of God, |
flood, drought, earthquake, storm, fire, |
lightning, epidemic, war, riot, civil disturbance |
or disobedience, labor dispute, labor or material |
shortage, sabotage, acts of public enemy, |
explosions, orders, regulations or restrictions |
imposed by governmental, military, or lawfully |
established civilian authorities, which, in any of |
the foregoing cases, by exercise of commercially |
reasonable efforts the zero emission facility |
could not reasonably have been expected to avoid, |
and which, by the exercise of commercially |
reasonable efforts, it has been unable to |
overcome. In such event, the zero emission |
facility shall be excused from performance for the |
duration of the event, including, but not limited |
to, delivery of zero emission credits, and no |
payment shall be due to the zero emission facility |
during the duration of the event. |
(ii) A zero emission facility shall be |
permitted to terminate the contract if legislation |
is enacted into law by the General Assembly that |
imposes or authorizes a new tax, special |
assessment, or fee on the generation of |
electricity, the ownership or leasehold of a |
generating unit, or the privilege or occupation of |
|
such generation, ownership, or leasehold of |
generation units by a zero emission facility. |
However, the provisions of this item (ii) do not |
apply to any generally applicable tax, special |
assessment or fee, or requirements imposed by |
federal law. |
(iii) A zero emission facility shall be |
permitted to terminate the contract in the event |
that the resource requires capital expenditures in |
excess of $40,000,000 that were neither known nor |
reasonably foreseeable at the time it executed the |
contract and that a prudent owner or operator of |
such resource would not undertake. |
(iv) A zero emission facility shall be |
permitted to terminate the contract in the event |
the Nuclear Regulatory Commission terminates the |
resource's license. |
(F) If the zero emission facility elects to |
terminate a contract under this subparagraph (E, of |
this paragraph (1), then the Commission shall reopen |
the docket in which the Commission approved the zero |
emission standard procurement plan under subparagraph |
(C) of this paragraph (1) and, after notice and |
hearing, enter an order acknowledging the contract |
termination election if such termination is consistent |
with the provisions of this subsection (d-5). |
|
(2) For purposes of this subsection (d-5), the amount |
paid per kilowatthour means the total amount paid for |
electric service expressed on a per kilowatthour basis. For |
purposes of this subsection (d-5), the total amount paid |
for electric service includes, without limitation, amounts |
paid for supply, transmission, distribution, surcharges, |
and add-on taxes. |
Notwithstanding the requirements of this subsection |
(d-5), the contracts executed under this subsection (d-5) |
shall provide that the total of zero emission credits |
procured under a procurement plan shall be subject to the |
limitations of this paragraph (2). For each delivery year, |
the contractual volume receiving payments in such year |
shall be reduced for all retail customers based on the |
amount necessary to limit the net increase that delivery |
year to the costs of those credits included in the amounts |
paid by eligible retail customers in connection with |
electric service to no more than 1.65% of the amount paid |
per kilowatthour by eligible retail customers during the |
year ending May 31, 2009. The result of this computation |
shall apply to and reduce the procurement for all retail |
customers, and all those customers shall pay the same |
single, uniform cents per kilowatthour charge under |
subsection (k) of Section 16-108 of the Public Utilities |
Act. To arrive at a maximum dollar amount of zero emission |
credits to be paid for the particular delivery year, the |
|
resulting per kilowatthour amount shall be applied to the |
actual amount of kilowatthours of electricity delivered by |
the electric utility in the delivery year immediately prior |
to the procurement, to all retail customers in its service |
territory. Unpaid contractual volume for any delivery year |
shall be paid in any subsequent delivery year in which such |
payments can be made without exceeding the amount specified |
in this paragraph (2). The calculations required by this |
paragraph (2) shall be made only once for each procurement |
plan year. Once the determination as to the amount of zero |
emission credits to be paid is made based on the |
calculations set forth in this paragraph (2), no subsequent |
rate impact determinations shall be made and no adjustments |
to those contract amounts shall be allowed. All costs |
incurred under those contracts and in implementing this |
subsection (d-5) shall be recovered by the electric utility |
as provided in this Section. |
No later than June 30, 2019, the Commission shall |
review the limitation on the amount of zero emission |
credits procured under this subsection (d-5) and report to |
the General Assembly its findings as to whether that |
limitation unduly constrains the procurement of |
cost-effective zero emission credits. |
(3) Six years after the execution of a contract under |
this subsection (d-5), the Agency shall determine whether |
the actual zero emission credit payments received by the |
|
supplier over the 6-year period exceed the Average ZEC |
Payment. In addition, at the end of the term of a contract |
executed under this subsection (d-5), or at the time, if |
any, a zero emission facility's contract is terminated |
under subparagraph (E) of paragraph (1) of this subsection |
(d-5), then the Agency shall determine whether the actual |
zero emission credit payments received by the supplier over |
the term of the contract exceed the Average ZEC Payment, |
after taking into account any amounts previously credited |
back to the utility under this paragraph (3). If the Agency |
determines that the actual zero emission credit payments |
received by the supplier over the relevant period exceed |
the Average ZEC Payment, then the supplier shall credit the |
difference back to the utility. The amount of the credit |
shall be remitted to the applicable electric utility no |
later than 120 days after the Agency's determination, which |
the utility shall reflect as a credit on its retail |
customer bills as soon as practicable; however, the credit |
remitted to the utility shall not exceed the total amount |
of payments received by the facility under its contract. |
For purposes of this Section, the Average ZEC Payment |
shall be calculated by multiplying the quantity of zero |
emission credits delivered under the contract times the |
average contract price. The average contract price shall be |
determined by subtracting the amount calculated under |
subparagraph (B) of this paragraph (3) from the amount |
|
calculated under subparagraph (A) of this paragraph (3), as |
follows: |
(A) The average of the Social Cost of Carbon, as |
defined in subparagraph (B) of paragraph (1) of this |
subsection (d-5), during the term of the contract. |
(B) The average of the market price indices, as |
defined in subparagraph (B) of paragraph (1) of this |
subsection (d-5), during the term of the contract, |
minus the baseline market price index, as defined in |
subparagraph (B) of paragraph (1) of this subsection |
(d-5). |
If the subtraction yields a negative number, then the |
Average ZEC Payment shall be zero. |
(4) Cost-effective zero emission credits procured from |
zero emission facilities shall satisfy the applicable |
definitions set forth in Section 1-10 of this Act. |
(5) The electric utility shall retire all zero emission |
credits used to comply with the requirements of this |
subsection (d-5). |
(6) Electric utilities shall be entitled to recover all |
of the costs associated with the procurement of zero |
emission credits through an automatic adjustment clause |
tariff in accordance with subsection (k) and (m) of Section |
16-108 of the Public Utilities Act, and the contracts |
executed under this subsection (d-5) shall provide that the |
utilities' payment obligations under such contracts shall |
|
be reduced if an adjustment is required under subsection |
(m) of Section 16-108 of the Public Utilities Act. |
(7) This subsection (d-5) shall become inoperative on |
January 1, 2028. |
(e) The draft procurement plans are subject to public |
comment, as required by Section 16-111.5 of the Public |
Utilities Act. |
(f) The Agency shall submit the final procurement plan to |
the Commission. The Agency shall revise a procurement plan if |
the Commission determines that it does not meet the standards |
set forth in Section 16-111.5 of the Public Utilities Act. |
(g) The Agency shall assess fees to each affected utility |
to recover the costs incurred in preparation of the annual |
procurement plan for the utility. |
(h) The Agency shall assess fees to each bidder to recover |
the costs incurred in connection with a competitive procurement |
process.
|
(i) A renewable energy credit, carbon emission credit, or |
zero emission credit can only be used once to comply with a |
single portfolio or other standard as set forth in subsection |
(c), subsection (d), or subsection (d-5) of this Section, |
respectively. A renewable energy credit, carbon emission |
credit, or zero emission credit cannot be used to satisfy the |
requirements of more than one standard. If more than one type |
of credit is issued for the same megawatt hour of energy, only |
one credit can be used to satisfy the requirements of a single |
|
standard. After such use, the credit must be retired together |
with any other credits issued for the same megawatt hour of |
energy. |
(Source: P.A. 98-463, eff. 8-16-13; 99-536, eff. 7-8-16.) |
Section 10. The Illinois Procurement Code is amended by |
changing Section 20-10 as follows:
|
(30 ILCS 500/20-10)
|
(Text of Section from P.A. 96-159, 96-588, 97-96, 97-895, |
and 98-1076) |
Sec. 20-10. Competitive sealed bidding; reverse auction.
|
(a) Conditions for use. All contracts shall be awarded by
|
competitive sealed bidding
except as otherwise provided in |
Section 20-5.
|
(b) Invitation for bids. An invitation for bids shall be
|
issued and shall include a
purchase description and the |
material contractual terms and
conditions applicable to the
|
procurement.
|
(c) Public notice. Public notice of the invitation for bids |
shall be
published in the Illinois Procurement Bulletin at |
least 14 calendar days before the date
set in the invitation |
for the opening of bids.
|
(d) Bid opening. Bids shall be opened publicly in the
|
presence of one or more witnesses
at the time and place |
designated in the invitation for bids. The
name of each bidder, |
|
the amount
of each bid, and other relevant information as may |
be specified by
rule shall be
recorded. After the award of the |
contract, the winning bid and the
record of each unsuccessful |
bid shall be open to
public inspection.
|
(e) Bid acceptance and bid evaluation. Bids shall be
|
unconditionally accepted without
alteration or correction, |
except as authorized in this Code. Bids
shall be evaluated |
based on the
requirements set forth in the invitation for bids, |
which may
include criteria to determine
acceptability such as |
inspection, testing, quality, workmanship,
delivery, and |
suitability for a
particular purpose. Those criteria that will |
affect the bid price
and be considered in evaluation
for award, |
such as discounts, transportation costs, and total or
life |
cycle costs, shall be
objectively measurable. The invitation |
for bids shall set forth
the evaluation criteria to be used.
|
(f) Correction or withdrawal of bids. Correction or
|
withdrawal of inadvertently
erroneous bids before or after |
award, or cancellation of awards of
contracts based on bid
|
mistakes, shall be permitted in accordance with rules.
After |
bid opening, no
changes in bid prices or other provisions of |
bids prejudicial to
the interest of the State or fair
|
competition shall be permitted. All decisions to permit the
|
correction or withdrawal of bids
based on bid mistakes shall be |
supported by written determination
made by a State purchasing |
officer.
|
(g) Award. The contract shall be awarded with reasonable
|
|
promptness by written notice
to the lowest responsible and |
responsive bidder whose bid meets
the requirements and criteria
|
set forth in the invitation for bids, except when a State |
purchasing officer
determines it is not in the best interest of |
the State and by written
explanation determines another bidder |
shall receive the award. The explanation
shall appear in the |
appropriate volume of the Illinois Procurement Bulletin. The |
written explanation must include:
|
(1) a description of the agency's needs; |
(2) a determination that the anticipated cost will be |
fair and reasonable; |
(3) a listing of all responsible and responsive |
bidders; and |
(4) the name of the bidder selected, the total contract |
price, and the reasons for selecting that bidder. |
Each chief procurement officer may adopt guidelines to |
implement the requirements of this subsection (g). |
The written explanation shall be filed with the Legislative |
Audit Commission and the Procurement Policy Board, and be made |
available for inspection by the public, within 30 calendar days |
after the agency's decision to award the contract. |
(h) Multi-step sealed bidding. When it is considered
|
impracticable to initially prepare
a purchase description to |
support an award based on price, an
invitation for bids may be |
issued
requesting the submission of unpriced offers to be |
followed by an
invitation for bids limited to
those bidders |
|
whose offers have been qualified under the criteria
set forth |
in the first solicitation.
|
(i) Alternative procedures. Notwithstanding any other |
provision of this Act to the contrary, the Director of the |
Illinois Power Agency may create alternative bidding |
procedures to be used in procuring professional services under |
Section 1-56, subsections subsection (a) and (c) of Section |
1-75 and subsection (d) of Section 1-78 of the Illinois Power |
Agency Act and Section 16-111.5(c) of the Public Utilities Act |
and to procure renewable energy resources under Section 1-56 of |
the Illinois Power Agency Act. These alternative procedures |
shall be set forth together with the other criteria contained |
in the invitation for bids, and shall appear in the appropriate |
volume of the Illinois Procurement Bulletin.
|
(j) Reverse auction. Notwithstanding any other provision |
of this Section and in accordance with rules adopted by the |
chief procurement officer, that chief procurement officer may |
procure supplies or services through a competitive electronic |
auction bidding process after the chief procurement officer |
determines that the use of such a process will be in the best |
interest of the State. The chief procurement officer shall |
publish that determination in his or her next volume of the |
Illinois Procurement Bulletin. |
An invitation for bids shall be issued and shall include |
(i) a procurement description, (ii) all contractual terms, |
whenever practical, and (iii) conditions applicable to the |
|
procurement, including a notice that bids will be received in |
an electronic auction manner. |
Public notice of the invitation for bids shall be given in |
the same manner as provided in subsection (c). |
Bids shall be accepted electronically at the time and in |
the manner designated in the invitation for bids. During the |
auction, a bidder's price shall be disclosed to other bidders. |
Bidders shall have the opportunity to reduce their bid prices |
during the auction. At the conclusion of the auction, the |
record of the bid prices received and the name of each bidder |
shall be open to public inspection. |
After the auction period has terminated, withdrawal of bids |
shall be permitted as provided in subsection (f). |
The contract shall be awarded within 60 calendar days after |
the auction by written notice to the lowest responsible bidder, |
or all bids shall be rejected except as otherwise provided in |
this Code. Extensions of the date for the award may be made by |
mutual written consent of the State purchasing officer and the |
lowest responsible bidder. |
This subsection does not apply to (i) procurements of |
professional and artistic services, (ii) telecommunications |
services, communication services, and information services, |
and (iii) contracts for construction projects, including |
design professional services. |
(Source: P.A. 97-96, eff. 7-13-11; 97-895, eff. 8-3-12; |
98-1076, eff. 1-1-15.)
|
|
(Text of Section from P.A. 96-159, 96-795, 97-96, 97-895, |
and 98-1076)
|
Sec. 20-10. Competitive sealed bidding; reverse auction.
|
(a) Conditions for use. All contracts shall be awarded by
|
competitive sealed bidding
except as otherwise provided in |
Section 20-5.
|
(b) Invitation for bids. An invitation for bids shall be
|
issued and shall include a
purchase description and the |
material contractual terms and
conditions applicable to the
|
procurement.
|
(c) Public notice. Public notice of the invitation for bids |
shall be
published in the Illinois Procurement Bulletin at |
least 14 calendar days before the date
set in the invitation |
for the opening of bids.
|
(d) Bid opening. Bids shall be opened publicly in the
|
presence of one or more witnesses
at the time and place |
designated in the invitation for bids. The
name of each bidder, |
the amount
of each bid, and other relevant information as may |
be specified by
rule shall be
recorded. After the award of the |
contract, the winning bid and the
record of each unsuccessful |
bid shall be open to
public inspection.
|
(e) Bid acceptance and bid evaluation. Bids shall be
|
unconditionally accepted without
alteration or correction, |
except as authorized in this Code. Bids
shall be evaluated |
based on the
requirements set forth in the invitation for bids, |
|
which may
include criteria to determine
acceptability such as |
inspection, testing, quality, workmanship,
delivery, and |
suitability for a
particular purpose. Those criteria that will |
affect the bid price
and be considered in evaluation
for award, |
such as discounts, transportation costs, and total or
life |
cycle costs, shall be
objectively measurable. The invitation |
for bids shall set forth
the evaluation criteria to be used.
|
(f) Correction or withdrawal of bids. Correction or
|
withdrawal of inadvertently
erroneous bids before or after |
award, or cancellation of awards of
contracts based on bid
|
mistakes, shall be permitted in accordance with rules.
After |
bid opening, no
changes in bid prices or other provisions of |
bids prejudicial to
the interest of the State or fair
|
competition shall be permitted. All decisions to permit the
|
correction or withdrawal of bids
based on bid mistakes shall be |
supported by written determination
made by a State purchasing |
officer.
|
(g) Award. The contract shall be awarded with reasonable
|
promptness by written notice
to the lowest responsible and |
responsive bidder whose bid meets
the requirements and criteria
|
set forth in the invitation for bids, except when a State |
purchasing officer
determines it is not in the best interest of |
the State and by written
explanation determines another bidder |
shall receive the award. The explanation
shall appear in the |
appropriate volume of the Illinois Procurement Bulletin. The |
written explanation must include:
|
|
(1) a description of the agency's needs; |
(2) a determination that the anticipated cost will be |
fair and reasonable; |
(3) a listing of all responsible and responsive |
bidders; and |
(4) the name of the bidder selected, the total contract |
price, and the reasons for selecting that bidder. |
Each chief procurement officer may adopt guidelines to |
implement the requirements of this subsection (g). |
The written explanation shall be filed with the Legislative |
Audit Commission and the Procurement Policy Board, and be made |
available for inspection by the public, within 30 days after |
the agency's decision to award the contract. |
(h) Multi-step sealed bidding. When it is considered
|
impracticable to initially prepare
a purchase description to |
support an award based on price, an
invitation for bids may be |
issued
requesting the submission of unpriced offers to be |
followed by an
invitation for bids limited to
those bidders |
whose offers have been qualified under the criteria
set forth |
in the first solicitation.
|
(i) Alternative procedures. Notwithstanding any other |
provision of this Act to the contrary, the Director of the |
Illinois Power Agency may create alternative bidding |
procedures to be used in procuring professional services under |
subsections subsection (a) and (c) of Section 1-75 and |
subsection (d) of Section 1-78 of the Illinois Power Agency Act |
|
and Section 16-111.5(c) of the Public Utilities Act and to |
procure renewable energy resources under Section 1-56 of the |
Illinois Power Agency Act. These alternative procedures shall |
be set forth together with the other criteria contained in the |
invitation for bids, and shall appear in the appropriate volume |
of the Illinois Procurement Bulletin.
|
(j) Reverse auction. Notwithstanding any other provision |
of this Section and in accordance with rules adopted by the |
chief procurement officer, that chief procurement officer may |
procure supplies or services through a competitive electronic |
auction bidding process after the chief procurement officer |
determines that the use of such a process will be in the best |
interest of the State. The chief procurement officer shall |
publish that determination in his or her next volume of the |
Illinois Procurement Bulletin. |
An invitation for bids shall be issued and shall include |
(i) a procurement description, (ii) all contractual terms, |
whenever practical, and (iii) conditions applicable to the |
procurement, including a notice that bids will be received in |
an electronic auction manner. |
Public notice of the invitation for bids shall be given in |
the same manner as provided in subsection (c). |
Bids shall be accepted electronically at the time and in |
the manner designated in the invitation for bids. During the |
auction, a bidder's price shall be disclosed to other bidders. |
Bidders shall have the opportunity to reduce their bid prices |
|
during the auction. At the conclusion of the auction, the |
record of the bid prices received and the name of each bidder |
shall be open to public inspection. |
After the auction period has terminated, withdrawal of bids |
shall be permitted as provided in subsection (f). |
The contract shall be awarded within 60 calendar days after |
the auction by written notice to the lowest responsible bidder, |
or all bids shall be rejected except as otherwise provided in |
this Code. Extensions of the date for the award may be made by |
mutual written consent of the State purchasing officer and the |
lowest responsible bidder. |
This subsection does not apply to (i) procurements of |
professional and artistic services, (ii) telecommunications |
services, communication services, and information services,
|
and (iii) contracts for construction projects, including |
design professional services. |
(Source: P.A. 97-96, eff. 7-13-11; 97-895, eff. 8-3-12; |
98-1076, eff. 1-1-15 .) |
Section 15. The Public Utilities Act is amended by changing |
Sections 5-117, 5-202.1, 8-103, 8-104, 16-107, 16-107.5, |
16-108, 16-108.5, 16-111.1, 16-111.5, 16-111.5B, 16-111.7, |
16-115D, 16-119A, 16-127, and 16-128A and by adding Sections |
8-103B, 9-107, 16-107.6, 16-108.10, 16-108.11, 16-108.12, |
16-108.15, and 16-108.16 as follows: |
|
(220 ILCS 5/5-117) |
Sec. 5-117. Supplier diversity goals. |
(a) The public policy of this State is to collaboratively |
work with companies that serve Illinois residents to improve |
their supplier diversity in a non-antagonistic manner. |
(b) The Commission shall require all gas, electric, and |
water companies with at least 100,000 customers under its |
authority , as well as suppliers of wind energy, solar energy,
|
hydroelectricity, nuclear energy, and any other supplier of
|
energy within this State, to submit an annual report by April |
15, 2015 and every April 15 thereafter, in a searchable Adobe |
PDF format, on all procurement goals and actual spending for |
female-owned, minority-owned, veteran-owned, and small |
business enterprises in the previous calendar year. These goals |
shall be expressed as a percentage of the total work performed |
by the entity submitting the report, and the actual spending |
for all female-owned, minority-owned, veteran-owned, and small |
business enterprises shall also be expressed as a percentage of |
the total work performed by the entity submitting the report. |
(c) Each participating company in its annual report shall |
include the following information: |
(1) an explanation of the plan for the next year to |
increase participation; |
(2) an explanation of the plan to increase the goals; |
(3) the areas of procurement each company shall be |
actively seeking more participation in in the next year; |
|
(4) an outline of the plan to alert and encourage |
potential vendors in that area to seek business from the |
company; |
(5) an explanation of the challenges faced in finding |
quality vendors and offer any suggestions for what the |
Commission could do to be helpful to identify those |
vendors; |
(6) a list of the certifications the company |
recognizes; |
(7) the point of contact for any potential vendor who |
wishes to do business with the company and explain the |
process for a vendor to enroll with the company as a |
minority-owned, women-owned, or veteran-owned company; and |
(8) any particular success stories to encourage other |
companies to emulate best practices. |
(d) Each annual report shall include as much State-specific |
data as possible. If the submitting entity does not submit |
State-specific data, then the company shall include any |
national data it does have and explain why it could not submit |
State-specific data and how it intends to do so in future |
reports, if possible. |
(e) Each annual report shall include the rules, |
regulations, and definitions used for the procurement goals in |
the company's annual report. |
(f) The Commission and all participating entities shall |
hold an annual workshop open to the public in 2015 and every |
|
year thereafter on the state of supplier diversity to |
collaboratively seek solutions to structural impediments to |
achieving stated goals, including testimony from each |
participating entity as well as subject matter experts and |
advocates. The Commission shall publish a database on its |
website of the point of contact for each participating entity |
for supplier diversity, along with a list of certifications |
each company recognizes from the information submitted in each |
annual report. The Commission shall publish each annual report |
on its website and shall maintain each annual report for at |
least 5 years.
|
(Source: P.A. 98-1056, eff. 8-26-14.)
|
(220 ILCS 5/5-202.1)
|
Sec. 5-202.1. Misrepresentation before Commission; |
penalty.
|
(a) Any person or corporation, as defined in Sections 3-113 |
and 3-114 of
this Act, who knowingly misrepresents facts to the |
Commission in response to any Commission contact, inquiry or |
discussion or knowingly aids another in doing
so in response to |
any Commission contact, inquiry or discussion or knowingly |
permits another to
misrepresent facts through testimony or the |
offering or withholding of
material information in any
|
proceeding shall be subject to a civil penalty. Whenever
the |
Commission is of
the opinion that a person or corporation is |
misrepresenting or has
misrepresented facts,
the Commission |
|
may initiate a proceeding to determine
whether a |
misrepresentation has in fact occurred. If the Commission finds
|
that a person or corporation has violated this Section, the |
Commission shall
impose a penalty of not less than $1,000 and |
not greater than $500,000 . Each
misrepresentation of a fact
|
found by the
Commission shall constitute a separate and |
distinct violation. In determining
the amount of the penalty to |
be assessed, the Commission may consider any
matters of record |
in aggravation or mitigation of the penalty, as set forth in
|
Section 4-203, including but not limited to the following:
|
(1) the presence or absence of due diligence on the |
part of the violator
in attempting to comply with the Act;
|
(2) any economic benefits accrued, or expected to be |
accrued, by the
violator because of the misrepresentation; |
and
|
(3) the amount of monetary penalty that will serve to |
deter further
violations by the violator and to otherwise |
aid in enhancing
voluntary compliance with the Act.
|
(b) Any action to enforce civil penalties arising under |
this Section
shall
be undertaken pursuant to Section 4-203.
|
(c) For purposes of this Section, "Commission," as defined |
in Section 3-102, refers to any Commissioner, agent, or |
employee of the Illinois Commerce commission, and also refers |
to any other person engaged to represent the Commission in |
carrying out its regulatory or law enforcement obligations. |
(Source: P.A. 93-457, eff. 8-8-03.)
|
|
(220 ILCS 5/8-103)
|
Sec. 8-103. Energy efficiency and demand-response |
measures. |
(a) It is the policy of the State that electric utilities |
are required to use cost-effective energy efficiency and |
demand-response measures to reduce delivery load. Requiring |
investment in cost-effective energy efficiency and |
demand-response measures will reduce direct and indirect costs |
to consumers by decreasing environmental impacts and by |
avoiding or delaying the need for new generation, transmission, |
and distribution infrastructure. It serves the public interest |
to allow electric utilities to recover costs for reasonably and |
prudently incurred expenses for energy efficiency and |
demand-response measures. As used in this Section, |
"cost-effective" means that the measures satisfy the total |
resource cost test. The low-income measures described in |
subsection (f)(4) of this Section shall not be required to meet |
the total resource cost test. For purposes of this Section, the |
terms "energy-efficiency", "demand-response", "electric |
utility", and "total resource cost test" shall have the |
meanings set forth in the Illinois Power Agency Act. For |
purposes of this Section, the amount per kilowatthour means the |
total amount paid for electric service expressed on a per |
kilowatthour basis. For purposes of this Section, the total |
amount paid for electric service includes without limitation |
|
estimated amounts paid for supply, transmission, distribution, |
surcharges, and add-on-taxes. |
(a-5) This Section applies to electric utilities serving |
500,000 or less but more than 200,000 retail customers in this |
State. Through December 31, 2017, this Section also applies to |
electric utilities serving more than 500,000 retail customers |
in the State. |
(b) Electric utilities shall implement cost-effective |
energy efficiency measures to meet the following incremental |
annual energy savings goals: |
(1) 0.2% of energy delivered in the year commencing |
June 1, 2008; |
(2) 0.4% of energy delivered in the year commencing |
June 1, 2009; |
(3) 0.6% of energy delivered in the year commencing |
June 1, 2010; |
(4) 0.8% of energy delivered in the year commencing |
June 1, 2011; |
(5) 1% of energy delivered in the year commencing June |
1, 2012; |
(6) 1.4% of energy delivered in the year commencing |
June 1, 2013; |
(7) 1.8% of energy delivered in the year commencing |
June 1, 2014; and |
(8) 2% of energy delivered in the year commencing June |
1, 2015 and each year thereafter. |
|
Electric utilities may comply with this subsection (b) by |
meeting the annual incremental savings goal in the applicable |
year or by showing that the total cumulative annual savings |
within a 3-year planning period associated with measures |
implemented after May 31, 2014 was equal to the sum of each |
annual incremental savings requirement from May 31, 2014 |
through the end of the applicable year. |
(c) Electric utilities shall implement cost-effective |
demand-response measures to reduce peak demand by 0.1% over the |
prior year for eligible retail customers, as defined in Section |
16-111.5 of this Act, and for customers that elect hourly |
service from the utility pursuant to Section 16-107 of this |
Act, provided those customers have not been declared |
competitive. This requirement commences June 1, 2008 and |
continues for 10 years. |
(d) Notwithstanding the requirements of subsections (b) |
and (c) of this Section, an electric utility shall reduce the |
amount of energy efficiency and demand-response measures |
implemented over a 3-year planning period by an amount |
necessary to limit the estimated average annual increase in the |
amounts paid by retail customers in connection with electric |
service due to the cost of those measures to: |
(1) in 2008, no more than 0.5% of the amount paid per |
kilowatthour by those customers during the year ending May |
31, 2007; |
(2) in 2009, the greater of an additional 0.5% of the |
|
amount paid per kilowatthour by those customers during the |
year ending May 31, 2008 or 1% of the amount paid per |
kilowatthour by those customers during the year ending May |
31, 2007; |
(3) in 2010, the greater of an additional 0.5% of the |
amount paid per kilowatthour by those customers during the |
year ending May 31, 2009 or 1.5% of the amount paid per |
kilowatthour by those customers during the year ending May |
31, 2007; |
(4) in 2011, the greater of an additional 0.5% of the |
amount paid per kilowatthour by those customers during the |
year ending May 31, 2010 or 2% of the amount paid per |
kilowatthour by those customers during the year ending May |
31, 2007; and
|
(5) thereafter, the amount of energy efficiency and |
demand-response measures implemented for any single year |
shall be reduced by an amount necessary to limit the |
estimated average net increase due to the cost of these |
measures included in the amounts paid by eligible retail |
customers in connection with electric service to no more |
than the greater of 2.015% of the amount paid per |
kilowatthour by those customers during the year ending May |
31, 2007 or the incremental amount per kilowatthour paid |
for these measures in 2011.
|
No later than June 30, 2011, the Commission shall review |
the limitation on the amount of energy efficiency and |
|
demand-response measures implemented pursuant to this Section |
and report to the General Assembly its findings as to whether |
that limitation unduly constrains the procurement of energy |
efficiency and demand-response measures. |
(e) Electric utilities shall be responsible for overseeing |
the design, development, and filing of energy efficiency and |
demand-response plans with the Commission. Electric utilities |
shall implement 100% of the demand-response measures in the |
plans. Electric utilities shall implement 75% of the energy |
efficiency measures approved by the Commission, and may, as |
part of that implementation, outsource various aspects of |
program development and implementation. The remaining 25% of |
those energy efficiency measures approved by the Commission |
shall be implemented by the Department of Commerce and Economic |
Opportunity, and must be designed in conjunction with the |
utility and the filing process. The Department may outsource |
development and implementation of energy efficiency measures. |
A minimum of 10% of the entire portfolio of cost-effective |
energy efficiency measures shall be procured from units of |
local government, municipal corporations, school districts, |
and community college districts. The Department shall |
coordinate the implementation of these measures. |
The apportionment of the dollars to cover the costs to |
implement the Department's share of the portfolio of energy |
efficiency measures shall be made to the Department once the |
Department has executed rebate agreements, grants, or |
|
contracts for energy efficiency measures and provided |
supporting documentation for those rebate agreements, grants, |
and contracts to the utility. The Department is authorized to |
adopt any rules necessary and prescribe procedures in order to |
ensure compliance by applicants in carrying out the purposes of |
rebate agreements for energy efficiency measures implemented |
by the Department made under this Section. |
The details of the measures implemented by the Department |
shall be submitted by the Department to the Commission in |
connection with the utility's filing regarding the energy |
efficiency and demand-response measures that the utility |
implements. |
A utility providing approved energy efficiency and |
demand-response measures in the State shall be permitted to |
recover costs of those measures through an automatic adjustment |
clause tariff filed with and approved by the Commission. The |
tariff shall be established outside the context of a general |
rate case. Each year the Commission shall initiate a review to |
reconcile any amounts collected with the actual costs and to |
determine the required adjustment to the annual tariff factor |
to match annual expenditures. |
Each utility shall include, in its recovery of costs, the |
costs estimated for both the utility's and the Department's |
implementation of energy efficiency and demand-response |
measures. Costs collected by the utility for measures |
implemented by the Department shall be submitted to the |
|
Department pursuant to Section 605-323 of the Civil |
Administrative Code of Illinois, shall be deposited into the |
Energy Efficiency Portfolio Standards Fund, and shall be used |
by the Department solely for the purpose of implementing these |
measures. A utility shall not be required to advance any moneys |
to the Department but only to forward such funds as it has |
collected. The Department shall report to the Commission on an |
annual basis regarding the costs actually incurred by the |
Department in the implementation of the measures. Any changes |
to the costs of energy efficiency measures as a result of plan |
modifications shall be appropriately reflected in amounts |
recovered by the utility and turned over to the Department. |
The portfolio of measures, administered by both the |
utilities and the Department, shall, in combination, be |
designed to achieve the annual savings targets described in |
subsections (b) and (c) of this Section, as modified by |
subsection (d) of this Section. |
The utility and the Department shall agree upon a |
reasonable portfolio of measures and determine the measurable |
corresponding percentage of the savings goals associated with |
measures implemented by the utility or Department. |
No utility shall be assessed a penalty under subsection (f) |
of this Section for failure to make a timely filing if that |
failure is the result of a lack of agreement with the |
Department with respect to the allocation of responsibilities |
or related costs or target assignments. In that case, the |
|
Department and the utility shall file their respective plans |
with the Commission and the Commission shall determine an |
appropriate division of measures and programs that meets the |
requirements of this Section. |
If the Department is unable to meet incremental annual |
performance goals for the portion of the portfolio implemented |
by the Department, then the utility and the Department shall |
jointly submit a modified filing to the Commission explaining |
the performance shortfall and recommending an appropriate |
course going forward, including any program modifications that |
may be appropriate in light of the evaluations conducted under |
item (7) of subsection (f) of this Section. In this case, the |
utility obligation to collect the Department's costs and turn |
over those funds to the Department under this subsection (e) |
shall continue only if the Commission approves the |
modifications to the plan proposed by the Department. |
(f) No later than November 15, 2007, each electric utility |
shall file an energy efficiency and demand-response plan with |
the Commission to meet the energy efficiency and |
demand-response standards for 2008 through 2010. No later than |
October 1, 2010, each electric utility shall file an energy |
efficiency and demand-response plan with the Commission to meet |
the energy efficiency and demand-response standards for 2011 |
through 2013. Every 3 years thereafter, each electric utility |
shall file, no later than September 1, an energy efficiency and |
demand-response plan with the Commission. If a utility does not |
|
file such a plan by September 1 of an applicable year, it shall |
face a penalty of $100,000 per day until the plan is filed. |
Each utility's plan shall set forth the utility's proposals to |
meet the utility's portion of the energy efficiency standards |
identified in subsection (b) and the demand-response standards |
identified in subsection (c) of this Section as modified by |
subsections (d) and (e), taking into account the unique |
circumstances of the utility's service territory. The |
Commission shall seek public comment on the utility's plan and |
shall issue an order approving or disapproving each plan within |
5 months after its submission. If the Commission disapproves a |
plan, the Commission shall, within 30 days, describe in detail |
the reasons for the disapproval and describe a path by which |
the utility may file a revised draft of the plan to address the |
Commission's concerns satisfactorily. If the utility does not |
refile with the Commission within 60 days, the utility shall be |
subject to penalties at a rate of $100,000 per day until the |
plan is filed. This process shall continue, and penalties shall |
accrue, until the utility has successfully filed a portfolio of |
energy efficiency and demand-response measures. Penalties |
shall be deposited into the Energy Efficiency Trust Fund. In |
submitting proposed energy efficiency and demand-response |
plans and funding levels to meet the savings goals adopted by |
this Act the utility shall: |
(1) Demonstrate that its proposed energy efficiency |
and demand-response measures will achieve the requirements |
|
that are identified in subsections (b) and (c) of this |
Section, as modified by subsections (d) and (e). |
(2) Present specific proposals to implement new |
building and appliance standards that have been placed into |
effect. |
(3) Present estimates of the total amount paid for |
electric service expressed on a per kilowatthour basis |
associated with the proposed portfolio of measures |
designed to meet the requirements that are identified in |
subsections (b) and (c) of this Section, as modified by |
subsections (d) and (e). |
(4) Coordinate with the Department to present a |
portfolio of energy efficiency measures proportionate to |
the share of total annual utility revenues in Illinois from |
households at or below 150% of the poverty level. The |
energy efficiency programs shall be targeted to households |
with incomes at or below 80% of area median income. |
(5) Demonstrate that its overall portfolio of energy |
efficiency and demand-response measures, not including |
programs covered by item (4) of this subsection (f), are |
cost-effective using the total resource cost test and |
represent a diverse cross-section of opportunities for |
customers of all rate classes to participate in the |
programs. |
(6) Include a proposed cost-recovery tariff mechanism |
to fund the proposed energy efficiency and demand-response |
|
measures and to ensure the recovery of the prudently and |
reasonably incurred costs of Commission-approved programs. |
(7) Provide for an annual independent evaluation of the |
performance of the cost-effectiveness of the utility's |
portfolio of measures and the Department's portfolio of |
measures, as well as a full review of the 3-year results of |
the broader net program impacts and, to the extent |
practical, for adjustment of the measures on a |
going-forward basis as a result of the evaluations. The |
resources dedicated to evaluation shall not exceed 3% of |
portfolio resources in any given year. |
(g) No more than 3% of energy efficiency and |
demand-response program revenue may be allocated for |
demonstration of breakthrough equipment and devices. |
(h) This Section does not apply to an electric utility that |
on December 31, 2005 provided electric service to fewer than |
100,000 customers in Illinois. |
(i) If, after 2 years, an electric utility fails to meet |
the efficiency standard specified in subsection (b) of this |
Section, as modified by subsections (d) and (e), it shall make |
a contribution to the Low-Income Home Energy Assistance |
Program. The combined total liability for failure to meet the |
goal shall be $1,000,000, which shall be assessed as follows: a |
large electric utility shall pay $665,000, and a medium |
electric utility shall pay $335,000. If, after 3 years, an |
electric utility fails to meet the efficiency standard |
|
specified in subsection (b) of this Section, as modified by |
subsections (d) and (e), it shall make a contribution to the |
Low-Income Home Energy Assistance Program. The combined total |
liability for failure to meet the goal shall be $1,000,000, |
which shall be assessed as follows: a large electric utility |
shall pay $665,000, and a medium electric utility shall pay |
$335,000. In addition, the responsibility for implementing the |
energy efficiency measures of the utility making the payment |
shall be transferred to the Illinois Power Agency if, after 3 |
years, or in any subsequent 3-year period, the utility fails to |
meet the efficiency standard specified in subsection (b) of |
this Section, as modified by subsections (d) and (e). The |
Agency shall implement a competitive procurement program to |
procure resources necessary to meet the standards specified in |
this Section as modified by subsections (d) and (e), with costs |
for those resources to be recovered in the same manner as |
products purchased through the procurement plan as provided in |
Section 16-111.5. The Director shall implement this |
requirement in connection with the procurement plan as provided |
in Section 16-111.5. |
For purposes of this Section, (i) a "large electric |
utility" is an electric utility that, on December 31, 2005, |
served more than 2,000,000 electric customers in Illinois; (ii) |
a "medium electric utility" is an electric utility that, on |
December 31, 2005, served 2,000,000 or fewer but more than |
100,000 electric customers in Illinois; and (iii) Illinois |
|
electric utilities that are affiliated by virtue of a common |
parent company are considered a single electric utility. |
(j) If, after 3 years, or any subsequent 3-year period, the |
Department fails to implement the Department's share of energy |
efficiency measures required by the standards in subsection |
(b), then the Illinois Power Agency may assume responsibility |
for and control of the Department's share of the required |
energy efficiency measures. The Agency shall implement a |
competitive procurement program to procure resources necessary |
to meet the standards specified in this Section, with the costs |
of these resources to be recovered in the same manner as |
provided for the Department in this Section.
|
(k) No electric utility shall be deemed to have failed to |
meet the energy efficiency standards to the extent any such |
failure is due to a failure of the Department or the Agency.
|
(l)(1) The energy efficiency and demand-response plans of |
electric utilities serving more than 500,000 retail customers |
in the State that were approved by the Commission on or before |
the effective date of this amendatory Act of the 99th General |
Assembly for the period June 1, 2014 through May 31, 2017 shall |
continue to be in force and effect through December 31, 2017 so |
that the energy efficiency programs set forth in those plans |
continue to be offered during the period June 1, 2017 through |
December 31, 2017. Each such utility is authorized to increase, |
on a pro rata basis, the energy savings goals and budgets |
approved in its plan to reflect the additional 7 months of the |
|
plan's operation, provided that such increase shall also |
incorporate reductions to goals and budgets to reflect the |
proportion of the utility's load attributable to customers who |
are exempt from this Section under subsection (m) of this |
Section. |
(2) If an electric utility serving more than 500,000 |
retail customers in the State filed with the Commission, |
under subsection (f) of this Section, its proposed energy |
efficiency and demand-response plan for the period June 1, |
2017 through May 31, 2020, and the Commission has not yet |
entered its final order approving such plan on or before |
the effective date of this amendatory Act of the 99th |
General Assembly, then the utility shall file a notice of |
withdrawal with the Commission, following such effective |
date, to withdraw the proposed energy efficiency and |
demand-response plan. Upon receipt of such notice, the |
Commission shall dismiss with prejudice any docket that had |
been initiated to investigate such plan, and the plan and |
the record related thereto shall not be the subject of any |
further hearing, investigation, or proceeding of any kind. |
(3) For those electric utilities that serve more than |
500,000 retail customers in the State, this amendatory Act |
of the 99th General Assembly preempts and supersedes any |
orders entered by the Commission that approved such |
utilities' energy efficiency and demand response plans for |
the period commencing June 1, 2017 and ending May 31, 2020. |
|
Any such orders shall be void, and the provisions of |
paragraph (1) of this subsection (l) shall apply. |
(m) Notwithstanding anything to the contrary, after May 31, |
2017, this Section does not apply to any retail customers of an |
electric utility that serves more than 3,000,000 retail |
customers in the State and whose total highest 30 minute demand |
was more than 10,000 kilowatts, or any retail customers of an |
electric utility that serves less than 3,000,000 retail |
customers but more than 500,000 retail customers in the State |
and whose total highest 15 minute demand was more than 10,000 |
kilowatts. For purposes of this subsection (m), "retail |
customer" has the meaning set forth in Section 16-102 of this |
Act. The criteria for determining whether this subsection (m) |
is applicable to a retail customer shall be based on the 12 |
consecutive billing periods prior to the start of the first |
year of each such multi-year plan. |
(Source: P.A. 97-616, eff. 10-26-11; 97-841, eff. 7-20-12; |
98-90, eff. 7-15-13.)
|
(220 ILCS 5/8-103B new) |
Sec. 8-103B. Energy efficiency and demand-response |
measures. |
(a) It is the policy of the State that electric utilities |
are required to use cost-effective energy efficiency and |
demand-response measures to reduce delivery load. Requiring |
investment in cost-effective energy efficiency and |
|
demand-response measures will reduce direct and indirect costs |
to consumers by decreasing environmental impacts and by |
avoiding or delaying the need for new generation, transmission, |
and distribution infrastructure. It serves the public interest |
to allow electric utilities to recover costs for reasonably and |
prudently incurred expenditures for energy efficiency and |
demand-response measures. As used in this Section, |
"cost-effective" means that the measures satisfy the total |
resource cost test. The low-income measures described in |
subsection (c) of this Section shall not be required to meet |
the total resource cost test. For purposes of this Section, the |
terms "energy-efficiency", "demand-response", "electric |
utility", and "total resource cost test" have the meanings set |
forth in the Illinois Power Agency Act. |
(a-5) This Section applies to electric utilities serving |
more than 500,000 retail customers in the State for those |
multi-year plans commencing after December 31, 2017. |
(b) For purposes of this Section, electric utilities |
subject to this Section that serve more than 3,000,000 retail |
customers in the State shall be deemed to have achieved a |
cumulative persisting annual savings of 6.6% from energy |
efficiency measures and programs implemented during the period |
beginning January 1, 2012 and ending December 31, 2017, which |
percent is based on the deemed average weather normalized sales |
of electric power and energy during calendar years 2014, 2015, |
and 2016 of 88,000,000 MWhs. For the purposes of this |
|
subsection (b) and subsection (b-5), the 88,000,000 MWhs of |
deemed electric power and energy sales shall be reduced by the |
number of MWhs equal to the sum of the annual consumption of |
customers that are exempt from subsections (a) through (j) of |
this Section under subsection (l) of this Section, as averaged |
across the calendar years 2014, 2015, and 2016. After 2017, the |
deemed value of cumulative persisting annual savings from |
energy efficiency measures and programs implemented during the |
period beginning January 1, 2012 and ending December 31, 2017, |
shall be reduced each year, as follows, and the applicable |
value shall be applied to and count toward the utility's |
achievement of the cumulative persisting annual savings goals |
set forth in subsection (b-5): |
(1) 5.8% deemed cumulative persisting annual savings |
for the year ending December 31, 2018; |
(2) 5.2% deemed cumulative persisting annual savings |
for the year ending December 31, 2019; |
(3) 4.5% deemed cumulative persisting annual savings |
for the year ending December 31, 2020; |
(4) 4.0% deemed cumulative persisting annual savings |
for the year ending December 31, 2021; |
(5) 3.5% deemed cumulative persisting annual savings |
for the year ending December 31, 2022; |
(6) 3.1% deemed cumulative persisting annual savings |
for the year ending December 31, 2023; |
(7) 2.8% deemed cumulative persisting annual savings |
|
for the year ending December 31, 2024; |
(8) 2.5% deemed cumulative persisting annual savings |
for the year ending December 31, 2025; |
(9) 2.3% deemed cumulative persisting annual savings |
for the year ending December 31, 2026; |
(10) 2.1% deemed cumulative persisting annual savings |
for the year ending December 31, 2027; |
(11) 1.8% deemed cumulative persisting annual savings |
for the year ending December 31, 2028; |
(12) 1.7% deemed cumulative persisting annual savings |
for the year ending December 31, 2029; and |
(13) 1.5% deemed cumulative persisting annual savings |
for the year ending December 31, 2030. |
For purposes of this Section, "cumulative persisting |
annual savings" means the total electric energy savings in a |
given year from measures installed in that year or in previous |
years, but no earlier than January 1, 2012, that are still |
operational and providing savings in that year because the |
measures have not yet reached the end of their useful lives. |
(b-5) Beginning in 2018, electric utilities subject to this |
Section that serve more than 3,000,000 retail customers in the |
State shall achieve the following cumulative persisting annual |
savings goals, as modified by subsection (f) of this Section |
and as compared to the deemed baseline of 88,000,000 MWhs of |
electric power and energy sales set forth in subsection (b), as |
reduced by the number of MWhs equal to the sum of the annual |
|
consumption of customers that are exempt from subsections (a) |
through (j) of this Section under subsection (l) of this |
Section as averaged across the calendar years 2014, 2015, and |
2016, through the implementation of energy efficiency measures |
during the applicable year and in prior years, but no earlier |
than January 1, 2012: |
(1) 7.8% cumulative persisting annual savings for the |
year ending December 31, 2018; |
(2) 9.1% cumulative persisting annual savings for the |
year ending December 31, 2019; |
(3) 10.4% cumulative persisting annual savings for the |
year ending December 31, 2020; |
(4) 11.8% cumulative persisting annual savings for the |
year ending December 31, 2021; |
(5) 13.1% cumulative persisting annual savings for the |
year ending December 31, 2022; |
(6) 14.4% cumulative persisting annual savings for the |
year ending December 31, 2023; |
(7) 15.7% cumulative persisting annual savings for the |
year ending December 31, 2024; |
(8) 17% cumulative persisting annual savings for the |
year ending December 31, 2025; |
(9) 17.9% cumulative persisting annual savings for the |
year ending December 31, 2026; |
(10) 18.8% cumulative persisting annual savings for |
the year ending December 31, 2027; |
|
(11) 19.7% cumulative persisting annual savings for |
the year ending December 31, 2028; |
(12) 20.6% cumulative persisting annual savings for |
the year ending December 31, 2029; and |
(13) 21.5% cumulative persisting annual savings for |
the year ending December 31, 2030. |
(b-10) For purposes of this Section, electric utilities |
subject to this Section that serve less than 3,000,000 retail |
customers but more than 500,000 retail customers in the State |
shall be deemed to have achieved a cumulative persisting annual |
savings of 6.6% from energy efficiency measures and programs |
implemented during the period beginning January 1, 2012 and |
ending December 31, 2017, which is based on the deemed average |
weather normalized sales of electric power and energy during |
calendar years 2014, 2015, and 2016 of 36,900,000 MWhs. For the |
purposes of this subsection (b-10) and subsection (b-15), the |
36,900,000 MWhs of deemed electric power and energy sales shall |
be reduced by the number of MWhs equal to the sum of the annual |
consumption of customers that are exempt from subsections (a) |
through (j) of this Section under subsection (l) of this |
Section, as averaged across the calendar years 2014, 2015, and |
2016. After 2017, the deemed value of cumulative persisting |
annual savings from energy efficiency measures and programs |
implemented during the period beginning January 1, 2012 and |
ending December 31, 2017, shall be reduced each year, as |
follows, and the applicable value shall be applied to and count |
|
toward the utility's achievement of the cumulative persisting |
annual savings goals set forth in subsection (b-15): |
(1) 5.8% deemed cumulative persisting annual savings |
for the year ending December 31, 2018; |
(2) 5.2% deemed cumulative persisting annual savings |
for the year ending December 31, 2019; |
(3) 4.5% deemed cumulative persisting annual savings |
for the year ending December 31, 2020; |
(4) 4.0% deemed cumulative persisting annual savings |
for the year ending December 31, 2021; |
(5) 3.5% deemed cumulative persisting annual savings |
for the year ending December 31, 2022; |
(6) 3.1% deemed cumulative persisting annual savings |
for the year ending December 31, 2023; |
(7) 2.8% deemed cumulative persisting annual savings |
for the year ending December 31, 2024; |
(8) 2.5% deemed cumulative persisting annual savings |
for the year ending December 31, 2025; |
(9) 2.3% deemed cumulative persisting annual savings |
for the year ending December 31, 2026; |
(10) 2.1% deemed cumulative persisting annual savings |
for the year ending December 31, 2027; |
(11) 1.8% deemed cumulative persisting annual savings |
for the year ending December 31, 2028; |
(12) 1.7% deemed cumulative persisting annual savings |
for the year ending December 31, 2029; and |
|
(13) 1.5% deemed cumulative persisting annual savings |
for the year ending December 31, 2030. |
(b-15) Beginning in 2018, electric utilities subject to |
this Section that serve less than 3,000,000 retail customers |
but more than 500,000 retail customers in the State shall |
achieve the following cumulative persisting annual savings |
goals, as modified by subsection (b-20) and subsection (f) of |
this Section and as compared to the deemed baseline as reduced |
by the number of MWhs equal to the sum of the annual |
consumption of customers that are exempt from subsections (a) |
through (j) of this Section under subsection (l) of this |
Section as averaged across the calendar years 2014, 2015, and |
2016, through the implementation of energy efficiency measures |
during the applicable year and in prior years, but no earlier |
than January 1, 2012: |
(1) 7.4% cumulative persisting annual savings for the |
year ending December 31, 2018; |
(2) 8.2% cumulative persisting annual savings for the |
year ending December 31, 2019; |
(3) 9.0% cumulative persisting annual savings for the |
year ending December 31, 2020; |
(4) 9.8% cumulative persisting annual savings for the |
year ending December 31, 2021; |
(5) 10.6% cumulative persisting annual savings for the |
year ending December 31, 2022; |
(6) 11.4% cumulative persisting annual savings for the |
|
year ending December 31, 2023; |
(7) 12.2% cumulative persisting annual savings for the |
year ending December 31, 2024; |
(8) 13% cumulative persisting annual savings for the |
year ending December 31, 2025; |
(9) 13.6% cumulative persisting annual savings for the |
year ending December 31, 2026; |
(10) 14.2% cumulative persisting annual savings for |
the year ending December 31, 2027; |
(11) 14.8% cumulative persisting annual savings for |
the year ending December 31, 2028; |
(12) 15.4% cumulative persisting annual savings for |
the year ending December 31, 2029; and |
(13) 16% cumulative persisting annual savings for the |
year ending December 31, 2030. |
The difference between the cumulative persisting annual |
savings goal for the applicable calendar year and the |
cumulative persisting annual savings goal for the immediately |
preceding calendar year is 0.8% for the period of January 1, |
2018 through December 31, 2025 and 0.6% for the period of |
January 1, 2026 through December 31, 2030. |
(b-20) Each electric utility subject to this Section may |
include cost-effective voltage optimization measures in its |
plans submitted under subsections (f) and (g) of this Section, |
and the costs incurred by a utility to implement the measures |
under a Commission-approved plan shall be recovered under the |
|
provisions of Article IX or Section 16-108.5 of this Act. For |
purposes of this Section, the measure life of voltage |
optimization measures shall be 15 years. The measure life |
period is independent of the depreciation rate of the voltage |
optimization assets deployed. |
Within 270 days after the effective date of this amendatory |
Act of the 99th General Assembly, an electric utility that |
serves less than 3,000,000 retail customers but more than |
500,000 retail customers in the State shall file a plan with |
the Commission that identifies the cost-effective voltage |
optimization investment the electric utility plans to |
undertake through December 31, 2024. The Commission, after |
notice and hearing, shall approve or approve with modification |
the plan within 120 days after the plan's filing and, in the |
order approving or approving with modification the plan, the |
Commission shall adjust the applicable cumulative persisting |
annual savings goals set forth in subsection (b-15) to reflect |
any amount of cost-effective energy savings approved by the |
Commission that is greater than or less than the following |
cumulative persisting annual savings values attributable to |
voltage optimization for the applicable year: |
(1) 0.0% of cumulative persisting annual savings for |
the year ending December 31, 2018; |
(2) 0.17% of cumulative persisting annual savings for |
the year ending December 31, 2019; |
(3) 0.17% of cumulative persisting annual savings for |
|
the year ending December 31, 2020; |
(4) 0.33% of cumulative persisting annual savings for |
the year ending December 31, 2021; |
(5) 0.5% of cumulative persisting annual savings for |
the year ending December 31, 2022; |
(6) 0.67% of cumulative persisting annual savings for |
the year ending December 31, 2023; |
(7) 0.83% of cumulative persisting annual savings for |
the year ending December 31, 2024; and |
(8) 1.0% of cumulative persisting annual savings for |
the year ending December 31, 2025. |
(b-25) In the event an electric utility jointly offers an |
energy efficiency measure or program with a gas utility under |
plans approved under this Section and Section 8-104 of this |
Act, the electric utility may continue offering the program, |
including the gas energy efficiency measures, in the event the |
gas utility discontinues funding the program. In that event, |
the energy savings value associated with such other fuels shall |
be converted to electric energy savings on an equivalent Btu |
basis for the premises. However, the electric utility shall |
prioritize programs for low-income residential customers to |
the extent practicable. An electric utility may recover the |
costs of offering the gas energy efficiency measures under this |
subsection (b-25). |
For those energy efficiency measures or programs that save |
both electricity and other fuels but are not jointly offered |
|
with a gas utility under plans approved under this Section and |
Section 8-104 or not offered with an affiliated gas utility |
under paragraph (6) of subsection (f) of Section 8-104 of this |
Act, the electric utility may count savings of fuels other than |
electricity toward the achievement of its annual savings goal, |
and the energy savings value associated with such other fuels |
shall be converted to electric energy savings on an equivalent |
Btu basis at the premises. |
In no event shall more than 10% of each year's applicable |
annual incremental goal as defined in paragraph (7) of |
subsection (g) of this Section be met through savings of fuels |
other than electricity. |
(c) Electric utilities shall be responsible for overseeing |
the design, development, and filing of energy efficiency plans |
with the Commission and may, as part of that implementation, |
outsource various aspects of program development and |
implementation. A minimum of 10%, for electric utilities that |
serve more than 3,000,000 retail customers in the State, and a |
minimum of 7%, for electric utilities that serve less than |
3,000,000 retail customers but more than 500,000 retail |
customers in the State, of the utility's entire portfolio |
funding level for a given year shall be used to procure |
cost-effective energy efficiency measures from units of local |
government, municipal corporations, school districts, public |
housing, and community college districts, provided that a |
minimum percentage of available funds shall be used to procure |
|
energy efficiency from public housing, which percentage shall |
be equal to public housing's share of public building energy |
consumption. |
The utilities shall also implement energy efficiency |
measures targeted at low-income households, which, for |
purposes of this Section, shall be defined as households at or |
below 80% of area median income, and expenditures to implement |
the measures shall be no less than $25,000,000 per year for |
electric utilities that serve more than 3,000,000 retail |
customers in the State and no less than $8,350,000 per year for |
electric utilities that serve less than 3,000,000 retail |
customers but more than 500,000 retail customers in the State. |
Each electric utility shall assess opportunities to |
implement cost-effective energy efficiency measures and |
programs through a public housing authority or authorities |
located in its service territory. If such opportunities are |
identified, the utility shall propose such measures and |
programs to address the opportunities. Expenditures to address |
such opportunities shall be credited toward the minimum |
procurement and expenditure requirements set forth in this |
subsection (c). |
Implementation of energy efficiency measures and programs |
targeted at low-income households should be contracted, when it |
is practicable, to independent third parties that have |
demonstrated capabilities to serve such households, with a |
preference for not-for-profit entities and government agencies |
|
that have existing relationships with or experience serving |
low-income communities in the State. |
Each electric utility shall develop and implement |
reporting procedures that address and assist in determining the |
amount of energy savings that can be applied to the low-income |
procurement and expenditure requirements set forth in this |
subsection (c). |
The electric utilities shall also convene a low-income |
energy efficiency advisory committee to assist in the design |
and evaluation of the low-income energy efficiency programs. |
The committee shall be comprised of the electric utilities |
subject to the requirements of this Section, the gas utilities |
subject to the requirements of Section 8-104 of this Act, the |
utilities' low-income energy efficiency implementation |
contractors, and representatives of community-based |
organizations. |
(d) Notwithstanding any other provision of law to the |
contrary, a utility providing approved energy efficiency |
measures and, if applicable, demand-response measures in the |
State shall be permitted to recover all reasonable and |
prudently incurred costs of those measures from all retail |
customers, except as provided in subsection (l) of this |
Section, as follows, provided that nothing in this subsection |
(d) permits the double recovery of such costs from customers: |
(1) The utility may recover its costs through an |
automatic adjustment clause tariff filed with and approved |
|
by the Commission. The tariff shall be established outside |
the context of a general rate case. Each year the |
Commission shall initiate a review to reconcile any amounts |
collected with the actual costs and to determine the |
required adjustment to the annual tariff factor to match |
annual expenditures. To enable the financing of the |
incremental capital expenditures, including regulatory |
assets, for electric utilities that serve less than |
3,000,000 retail customers but more than 500,000 retail |
customers in the State, the utility's actual year-end |
capital structure that includes a common equity ratio, |
excluding goodwill, of up to and including 50% of the total |
capital structure shall be deemed reasonable and used to |
set rates. |
(2) A utility may recover its costs through an energy |
efficiency formula rate approved by the Commission under a |
filing under subsections (f) and (g) of this Section, which |
shall specify the cost components that form the basis of |
the rate charged to customers with sufficient specificity |
to operate in a standardized manner and be updated annually |
with transparent information that reflects the utility's |
actual costs to be recovered during the applicable rate |
year, which is the period beginning with the first billing |
day of January and extending through the last billing day |
of the following December. The energy efficiency formula |
rate shall be implemented through a tariff filed with the |
|
Commission under subsections (f) and (g) of this Section |
that is consistent with the provisions of this paragraph |
(2) and that shall be applicable to all delivery services |
customers. The Commission shall conduct an investigation |
of the tariff in a manner consistent with the provisions of |
this paragraph (2), subsections (f) and (g) of this |
Section, and the provisions of Article IX of this Act to |
the extent they do not conflict with this paragraph (2). |
The energy efficiency formula rate approved by the |
Commission shall remain in effect at the discretion of the |
utility and shall do the following: |
(A) Provide for the recovery of the utility's |
actual costs incurred under this Section that are |
prudently incurred and reasonable in amount consistent |
with Commission practice and law. The sole fact that a |
cost differs from that incurred in a prior calendar |
year or that an investment is different from that made |
in a prior calendar year shall not imply the imprudence |
or unreasonableness of that cost or investment. |
(B) Reflect the utility's actual year-end capital |
structure for the applicable calendar year, excluding |
goodwill, subject to a determination of prudence and |
reasonableness consistent with Commission practice and |
law. To enable the financing of the incremental capital |
expenditures, including regulatory assets, for |
electric utilities that serve less than 3,000,000 |
|
retail customers but more than 500,000 retail |
customers in the State, a participating electric |
utility's actual year-end capital structure that |
includes a common equity ratio, excluding goodwill, of |
up to and including 50% of the total capital structure |
shall be deemed reasonable and used to set rates. |
(C) Include a cost of equity, which shall be |
calculated as the sum of the following: |
(i) the average for the applicable calendar |
year of the monthly average yields of 30-year U.S. |
Treasury bonds published by the Board of Governors |
of the Federal Reserve System in its weekly H.15 |
Statistical Release or successor publication; and |
(ii) 580 basis points. |
At such time as the Board of Governors of the |
Federal Reserve System ceases to include the monthly |
average yields of 30-year U.S. Treasury bonds in its |
weekly H.15 Statistical Release or successor |
publication, the monthly average yields of the U.S. |
Treasury bonds then having the longest duration |
published by the Board of Governors in its weekly H.15 |
Statistical Release or successor publication shall |
instead be used for purposes of this paragraph (2). |
(D) Permit and set forth protocols, subject to a |
determination of prudence and reasonableness |
consistent with Commission practice and law, for the |
|
following: |
(i) recovery of incentive compensation expense |
that is based on the achievement of operational |
metrics, including metrics related to budget |
controls, outage duration and frequency, safety, |
customer service, efficiency and productivity, and |
environmental compliance; however, this protocol |
shall not apply if such expense related to costs |
incurred under this Section is recovered under |
Article IX or Section 16-108.5 of this Act; |
incentive compensation expense that is based on |
net income or an affiliate's earnings per share |
shall not be recoverable under the
energy |
efficiency formula rate; |
(ii) recovery of pension and other |
post-employment benefits expense, provided that |
such costs are supported by an actuarial study; |
however, this protocol shall not apply if such |
expense related to costs incurred under this |
Section is recovered under Article IX or Section |
16-108.5 of this Act; |
(iii) recovery of existing regulatory assets |
over the periods previously authorized by the |
Commission; |
(iv) as described in subsection (e), |
amortization of costs incurred under this Section; |
|
and |
(v) projected, weather normalized billing |
determinants for the applicable rate year. |
(E) Provide for an annual reconciliation, as |
described in paragraph (3) of this subsection (d), less |
any deferred taxes related to the reconciliation, with |
interest at an annual rate of return equal to the |
utility's weighted average cost of capital, including |
a revenue conversion factor calculated to recover or |
refund all additional income taxes that may be payable |
or receivable as a result of that return, of the energy |
efficiency revenue requirement reflected in rates for |
each calendar year, beginning with the calendar year in |
which the utility files its energy efficiency formula |
rate tariff under this paragraph (2), with what the |
revenue requirement would have been had the actual cost |
information for the applicable calendar year been |
available at the filing date. |
The utility shall file, together with its tariff, the |
projected costs to be incurred by the utility during the |
rate year under the utility's multi-year plan approved |
under subsections (f) and (g) of this Section, including, |
but not limited to, the projected capital investment costs |
and projected regulatory asset balances with |
correspondingly updated depreciation and amortization |
reserves and expense, that shall populate the energy |
|
efficiency formula rate and set the initial rates under the |
formula. |
The Commission shall review the proposed tariff in |
conjunction with its review of a proposed multi-year plan, |
as specified in paragraph (5) of subsection (g) of this |
Section. The review shall be based on the same evidentiary |
standards, including, but not limited to, those concerning |
the prudence and reasonableness of the costs incurred by |
the utility, the Commission applies in a hearing to review |
a filing for a general increase in rates under Article IX |
of this Act. The initial rates shall take effect beginning |
with the January monthly billing period following the |
Commission's approval. |
The tariff's rate design and cost allocation across |
customer classes shall be consistent with the utility's |
automatic adjustment clause tariff in effect on the |
effective date of this amendatory Act of the 99th General |
Assembly; however, the Commission may revise the tariff's |
rate design and cost allocation in subsequent proceedings |
under paragraph (3) of this subsection (d). |
If the energy efficiency formula rate is terminated, |
the then current rates shall remain in effect until such |
time as the energy efficiency costs are incorporated into |
new rates that are set under this subsection (d) or Article |
IX of this Act, subject to retroactive rate adjustment, |
with interest, to reconcile rates charged with actual |
|
costs. |
(3) The provisions of this paragraph (3) shall only |
apply to an electric utility that has elected to file an |
energy efficiency formula rate under paragraph (2) of this |
subsection (d). Subsequent to the Commission's issuance of |
an order approving the utility's energy efficiency formula |
rate structure and protocols, and initial rates under |
paragraph (2) of this subsection (d), the utility shall |
file, on or before June 1 of each year, with the Chief |
Clerk of the Commission its updated cost inputs to the |
energy efficiency formula rate for the applicable rate year |
and the corresponding new charges, as well as the |
information described in paragraph (9) of subsection (g) of |
this Section. Each such filing shall conform to the |
following requirements and include the following |
information: |
(A) The inputs to the energy efficiency formula |
rate for the applicable rate year shall be based on the |
projected costs to be incurred by the utility during |
the rate year under the utility's multi-year plan |
approved under subsections (f) and (g) of this Section, |
including, but not limited to, projected capital |
investment costs and projected regulatory asset |
balances with correspondingly updated depreciation and |
amortization reserves and expense. The filing shall |
also include a reconciliation of the energy efficiency |
|
revenue requirement that was in effect for the prior |
rate year (as set by the cost inputs for the prior rate |
year) with the actual revenue requirement for the prior |
rate year (determined using a year-end rate base) that |
uses amounts reflected in the applicable FERC Form 1 |
that reports the actual costs for the prior rate year. |
Any over-collection or under-collection indicated by |
such reconciliation shall be reflected as a credit |
against, or recovered as an additional charge to, |
respectively, with interest calculated at a rate equal |
to the utility's weighted average cost of capital |
approved by the Commission for the prior rate year, the |
charges for the applicable rate year. Such |
over-collection or under-collection shall be adjusted |
to remove any deferred taxes related to the |
reconciliation, for purposes of calculating interest |
at an annual rate of return equal to the utility's |
weighted average cost of capital approved by the |
Commission for the prior rate year, including a revenue |
conversion factor calculated to recover or refund all |
additional income taxes that may be payable or |
receivable as a result of that return. Each |
reconciliation shall be certified by the participating |
utility in the same manner that FERC Form 1 is |
certified. The filing shall also include the charge or |
credit, if any, resulting from the calculation |
|
required by subparagraph (E) of paragraph (2) of this |
subsection (d). |
Notwithstanding any other provision of law to the |
contrary, the intent of the reconciliation is to |
ultimately reconcile both the revenue requirement |
reflected in rates for each calendar year, beginning |
with the calendar year in which the utility files its |
energy efficiency formula rate tariff under paragraph |
(2) of this subsection (d), with what the revenue |
requirement determined using a year-end rate base for |
the applicable calendar year would have been had the |
actual cost information for the applicable calendar |
year been available at the filing date. |
For purposes of this Section, "FERC Form 1" means |
the Annual Report of Major Electric Utilities, |
Licensees and Others that electric utilities are |
required to file with the Federal Energy Regulatory |
Commission under the Federal Power Act, Sections 3, |
4(a), 304 and 209, modified as necessary to be |
consistent with 83 Ill. Admin. Code Part 415 as of May |
1, 2011. Nothing in this Section is intended to allow |
costs that are not otherwise recoverable to be |
recoverable by virtue of inclusion in FERC Form 1. |
(B) The new charges shall take effect beginning on |
the first billing day of the following January billing |
period and remain in effect through the last billing |
|
day of the next December billing period regardless of |
whether the Commission enters upon a hearing under this |
paragraph (3). |
(C) The filing shall include relevant and |
necessary data and documentation for the applicable |
rate year. Normalization adjustments shall not be |
required. |
Within 45 days after the utility files its annual |
update of cost inputs to the energy efficiency formula |
rate, the Commission shall with reasonable notice, |
initiate a proceeding concerning whether the projected |
costs to be incurred by the utility and recovered during |
the applicable rate year, and that are reflected in the |
inputs to the energy efficiency formula rate, are |
consistent with the utility's approved multi-year plan |
under subsections (f) and (g) of this Section and whether |
the costs incurred by the utility during the prior rate |
year were prudent and reasonable. The Commission shall also |
have the authority to investigate the information and data |
described in paragraph (9) of subsection (g) of this |
Section, including the proposed adjustment to the |
utility's return on equity component of its weighted |
average cost of capital. During the course of the |
proceeding, each objection shall be stated with |
particularity and evidence provided in support thereof, |
after which the utility shall have the opportunity to rebut |
|
the evidence. Discovery shall be allowed consistent with |
the Commission's Rules of Practice, which Rules of Practice |
shall be enforced by the Commission or the assigned hearing |
examiner. The Commission shall apply the same evidentiary |
standards, including, but not limited to, those concerning |
the prudence and reasonableness of the costs incurred by |
the utility, during the proceeding as it would apply in a |
proceeding to review a filing for a general increase in |
rates under Article IX of this Act. The Commission shall |
not, however, have the authority in a proceeding under this |
paragraph (3) to consider or order any changes to the |
structure or protocols of the energy efficiency formula |
rate approved under paragraph (2) of this subsection (d). |
In a proceeding under this paragraph (3), the Commission |
shall enter its order no later than the earlier of 195 days |
after the utility's filing of its annual update of cost |
inputs to the energy efficiency formula rate or December |
15. The utility's proposed return on equity calculation, as |
described in paragraphs (7) through (9) of subsection (g) |
of this Section, shall be deemed the final, approved |
calculation on December 15 of the year in which it is filed |
unless the Commission enters an order on or before December |
15, after notice and hearing, that modifies such |
calculation consistent with this Section. The Commission's |
determinations of the prudence and reasonableness of the |
costs incurred, and determination of such return on equity |
|
calculation, for the applicable calendar year shall be |
final upon entry of the Commission's order and shall not be |
subject to reopening, reexamination, or collateral attack |
in any other Commission proceeding, case, docket, order, |
rule, or regulation; however, nothing in this paragraph (3) |
shall prohibit a party from petitioning the Commission to |
rehear or appeal to the courts the order under the |
provisions of this Act. |
(e)
Beginning on the effective date of this amendatory Act |
of the 99th General Assembly, a utility subject to the |
requirements of this Section may elect to defer, as a |
regulatory asset, up to the full amount of its expenditures |
incurred under this Section for each annual period, including, |
but not limited to, any expenditures incurred above the funding |
level set by subsection (f) of this Section for a given year. |
The total expenditures deferred as a regulatory asset in a |
given year shall be amortized and recovered over a period that |
is equal to the weighted average of the energy efficiency |
measure lives implemented for that year that are reflected in |
the regulatory asset. The unamortized balance shall be |
recognized as of December 31 for a given year. The utility |
shall also earn a return on the total of the unamortized |
balances of all of the energy efficiency regulatory assets, |
less any deferred taxes related to those unamortized balances, |
at an annual rate equal to the utility's weighted average cost |
of capital that includes, based on a year-end capital |
|
structure, the utility's actual cost of debt for the applicable |
calendar year and a cost of equity, which shall be calculated |
as the sum of the (i) the average for the applicable calendar |
year of the monthly average yields of 30-year U.S. Treasury |
bonds published by the Board of Governors of the Federal |
Reserve System in its weekly H.15 Statistical Release or |
successor publication; and (ii) 580 basis points, including a |
revenue conversion factor calculated to recover or refund all |
additional income taxes that may be payable or receivable as a |
result of that return. Capital investment costs shall be |
depreciated and recovered over their useful lives consistent |
with generally accepted accounting principles. The weighted |
average cost of capital shall be applied to the capital |
investment cost balance, less any accumulated depreciation and |
accumulated deferred income taxes, as of December 31 for a |
given year. |
When an electric utility creates a regulatory asset under |
the provisions of this Section, the costs are recovered over a |
period during which customers also receive a benefit which is |
in the public interest. Accordingly, it is the intent of the |
General Assembly that an electric utility that elects to create |
a regulatory asset under the provisions of this Section shall |
recover all of the associated costs as set forth in this |
Section. After the Commission has approved the prudence and |
reasonableness of the costs that comprise the regulatory asset, |
the electric utility shall be permitted to recover all such |
|
costs, and the value and recoverability through rates of the |
associated regulatory asset shall not be limited, altered, |
impaired, or reduced. |
(f) Beginning in 2017, each electric utility shall file an |
energy efficiency plan with the Commission to meet the energy |
efficiency standards for the next applicable multi-year period |
beginning January 1 of the year following the filing, according |
to the schedule set forth in paragraphs (1) through (3) of this |
subsection (f). If a utility does not file such a plan on or |
before the applicable filing deadline for the plan, it shall |
face a penalty of $100,000 per day until the plan is filed. |
(1) No later than 30 days after the effective date of |
this amendatory Act of the 99th General Assembly or May 1, |
2017, whichever is later, each electric utility shall file |
a 4-year energy efficiency plan commencing on January 1, |
2018 that is designed to achieve the cumulative persisting |
annual savings goals specified in paragraphs (1) through |
(4) of subsection (b-5) of this Section or in paragraphs |
(1) through (4) of subsection (b-15) of this Section, as |
applicable, through implementation of energy efficiency |
measures; however, the goals may be reduced if the |
utility's expenditures are limited pursuant to subsection |
(m) of this Section or, for a utility that serves less than |
3,000,000 retail customers, if each of the following |
conditions are met: (A) the plan's analysis and forecasts |
of the utility's ability to acquire energy savings |
|
demonstrate that achievement of such goals is not cost |
effective; and (B) the amount of energy savings achieved by |
the utility as determined by the independent evaluator for |
the most recent year for which savings have been evaluated |
preceding the plan filing was less than the average annual |
amount of savings required to achieve the goals for the |
applicable 4-year plan period. Except as provided in |
subsection (m) of this Section, annual increases in |
cumulative persisting annual savings goals during the |
applicable 4-year plan period shall not be reduced to |
amounts that are less than the maximum amount of cumulative |
persisting annual savings that is forecast to be |
cost-effectively achievable during the 4-year plan period. |
The Commission shall review any proposed goal reduction as |
part of its review and approval of the utility's proposed |
plan. |
(2) No later than March 1, 2021, each electric utility |
shall file a 4-year energy efficiency plan commencing on |
January 1, 2022 that is designed to achieve the cumulative |
persisting annual savings goals specified in paragraphs |
(5) through (8) of subsection (b-5) of this Section or in |
paragraphs (5) through (8) of subsection (b-15) of this |
Section, as applicable, through implementation of energy |
efficiency measures; however, the goals may be reduced if |
the utility's expenditures are limited pursuant to |
subsection (m) of this Section or, each of the following |
|
conditions are met: (A) the plan's analysis and forecasts |
of the utility's ability to acquire energy savings |
demonstrate that achievement of such goals is not cost |
effective; and (B) the amount of energy savings achieved by |
the utility as determined by the independent evaluator for |
the most recent year for which savings have been evaluated |
preceding the plan filing was less than the average annual |
amount of savings required to achieve the goals for the |
applicable 4-year plan period. Except as provided in |
subsection (m) of this Section, annual increases in |
cumulative persisting annual savings goals during the |
applicable 4-year plan period shall not be reduced to |
amounts that are less than the maximum amount of cumulative |
persisting annual savings that is forecast to be |
cost-effectively achievable during the 4-year plan period. |
The Commission shall review any proposed goal reduction as |
part of its review and approval of the utility's proposed |
plan. |
(3) No later than March 1, 2025, each electric utility |
shall file a 5-year energy efficiency plan commencing on |
January 1, 2026 that is designed to achieve the cumulative |
persisting annual savings goals specified in paragraphs |
(9) through (13) of subsection (b-5) of this Section or in |
paragraphs (9) through (13) of subsection (b-15) of this |
Section, as applicable, through implementation of energy |
efficiency measures; however, the goals may be reduced if |
|
the utility's expenditures are limited pursuant to |
subsection (m) of this Section or, each of the following |
conditions are met: (A) the plan's analysis and forecasts |
of the utility's ability to acquire energy savings |
demonstrate that achievement of such goals is not cost |
effective; and (B) the amount of energy savings achieved by |
the utility as determined by the independent evaluator for |
the most recent year for which savings have been evaluated |
preceding the plan filing was less than the average annual |
amount of savings required to achieve the goals for the |
applicable 5-year plan period. Except as provided in |
subsection (m) of this Section, annual increases in |
cumulative persisting annual savings goals during the |
applicable 5-year plan period shall not be reduced to |
amounts that are less than the maximum amount of cumulative |
persisting annual savings that is forecast to be |
cost-effectively achievable during the 5-year plan period. |
The Commission shall review any proposed goal reduction as |
part of its review and approval of the utility's proposed |
plan. |
Each utility's plan shall set forth the utility's proposals |
to meet the energy efficiency standards identified in |
subsection (b-5) or (b-15), as applicable and as such standards |
may have been modified under this subsection (f), taking into |
account the unique circumstances of the utility's service |
territory. For those plans commencing on January 1, 2018, the |
|
Commission shall seek public comment on the utility's plan and |
shall issue an order approving or disapproving each plan no |
later than August 31, 2017, or 105 days after the effective |
date of this amendatory Act of the 99th General Assembly, |
whichever is later. For those plans commencing after December |
31, 2021, the Commission shall seek public comment on the |
utility's plan and shall issue an order approving or |
disapproving each plan within 6 months after its submission. If |
the Commission disapproves a plan, the Commission shall, within |
30 days, describe in detail the reasons for the disapproval and |
describe a path by which the utility may file a revised draft |
of the plan to address the Commission's concerns |
satisfactorily. If the utility does not refile with the |
Commission within 60 days, the utility shall be subject to |
penalties at a rate of $100,000 per day until the plan is |
filed. This process shall continue, and penalties shall accrue, |
until the utility has successfully filed a portfolio of energy |
efficiency and demand-response measures. Penalties shall be |
deposited into the Energy Efficiency Trust Fund. |
(g) In submitting proposed plans and funding levels under |
subsection (f) of this Section to meet the savings goals |
identified in subsection (b-5) or (b-15) of this Section, as |
applicable, the utility shall: |
(1) Demonstrate that its proposed energy efficiency |
measures will achieve the applicable requirements that are |
identified in subsection (b-5) or (b-15) of this Section, |
|
as modified by subsection (f) of this Section. |
(2) Present specific proposals to implement new |
building and appliance standards that have been placed into |
effect. |
(3) Demonstrate that its overall portfolio of |
measures, not including low-income programs described in |
subsection (c) of this Section, is cost-effective using the |
total resource cost test or complies with paragraphs (1) |
through (3) of subsection (f) of this Section and |
represents a diverse cross-section of opportunities for |
customers of all rate classes, other than those customers |
described in subsection (l) of this Section, to participate |
in the programs. Individual measures need not be cost |
effective. |
(4) Present a third-party energy efficiency |
implementation program subject to the following |
requirements: |
(A) beginning with the year commencing January 1, |
2019, electric utilities that serve more than |
3,000,000 retail customers in the State shall fund |
third-party energy efficiency programs in an amount |
that is no less than $25,000,000 per year, and electric |
utilities that serve less than 3,000,000 retail |
customers but more than 500,000 retail customers in the |
State shall fund third-party energy efficiency |
programs in an amount that is no less than $8,350,000 |
|
per year; |
(B) during 2018, the utility shall conduct a |
solicitation process for purposes of requesting |
proposals from third-party vendors for those |
third-party energy efficiency programs to be offered |
during one or more of the years commencing January 1, |
2019, January 1, 2020, and January 1, 2021; for those |
multi-year plans commencing on January 1, 2022 and |
January 1, 2026, the utility shall conduct a |
solicitation process during 2021 and 2025, |
respectively, for purposes of requesting proposals |
from third-party vendors for those third-party energy |
efficiency programs to be offered during one or more |
years of the respective multi-year plan period; for |
each solicitation process, the utility shall identify |
the sector, technology, or geographical area for which |
it is seeking requests for proposals; |
(C) the utility shall propose the bidder |
qualifications, performance measurement process, and |
contract structure, which must include a performance |
payment mechanism and general terms and conditions; |
the proposed qualifications, process, and structure |
shall be subject to Commission approval; and |
(D) the utility shall retain an independent third |
party to score the proposals received through the |
solicitation process described in this paragraph (4), |
|
rank them according to their cost per lifetime |
kilowatt-hours saved, and assemble the portfolio of |
third-party programs. |
The electric utility shall recover all costs |
associated with Commission-approved, third-party |
administered programs regardless of the success of those |
programs. |
(4.5)Implement cost-effective demand-response measures |
to reduce peak demand by 0.1% over the prior year for |
eligible retail customers, as defined in Section 16-111.5 |
of this Act, and for customers that elect hourly service |
from the utility pursuant to Section 16-107 of this Act, |
provided those customers have not been declared |
competitive. This requirement continues until December 31, |
2026. |
(5) Include a proposed or revised cost-recovery tariff |
mechanism, as provided for under subsection (d) of this |
Section, to fund the proposed energy efficiency and |
demand-response measures and to ensure the recovery of the |
prudently and reasonably incurred costs of |
Commission-approved programs. |
(6) Provide for an annual independent evaluation of the |
performance of the cost-effectiveness of the utility's |
portfolio of measures, as well as a full review of the |
multi-year plan results of the broader net program impacts |
and, to the extent practical, for adjustment of the |
|
measures on a going-forward basis as a result of the |
evaluations. The resources dedicated to evaluation shall |
not exceed 3% of portfolio resources in any given year. |
(7) For electric utilities that serve more than |
3,000,000 retail customers in the State: |
(A) Through December 31, 2025, provide for an |
adjustment to the return on equity component of the |
utility's weighted average cost of capital calculated |
under subsection (d) of this Section: |
(i) If the independent evaluator determines |
that the utility achieved a cumulative persisting |
annual savings that is less than the applicable |
annual incremental goal, then the return on equity |
component shall be reduced by a maximum of 200 |
basis points in the event that the utility achieved |
no more than 75% of such goal. If the utility |
achieved more than 75% of the applicable annual |
incremental goal but less than 100% of such goal, |
then the return on equity component shall be |
reduced by 8 basis points for each percent by which |
the utility failed to achieve the goal. |
(ii) If the independent evaluator determines |
that the utility achieved a cumulative persisting |
annual savings that is more than the applicable |
annual incremental goal, then the return on equity |
component shall be increased by a maximum of 200 |
|
basis points in the event that the utility achieved |
at least 125% of such goal. If the utility achieved |
more than 100% of the applicable annual |
incremental goal but less than 125% of such goal, |
then the return on equity component shall be |
increased by 8 basis points for each percent by |
which the utility achieved above the goal. If the |
applicable annual incremental goal was reduced |
under paragraphs (1) or (2) of subsection (f) of |
this Section, then the following adjustments shall |
be made to the calculations described in this item |
(ii): |
(aa) the calculation for determining |
achievement that is at least 125% of the |
applicable annual incremental goal shall use |
the unreduced applicable annual incremental |
goal to set the value; and |
(bb) the calculation for determining |
achievement that is less than 125% but more |
than 100% of the applicable annual incremental |
goal shall use the reduced applicable annual |
incremental goal to set the value for 100% |
achievement of the goal and shall use the |
unreduced goal to set the value for 125% |
achievement. The 8 basis point value shall also |
be modified, as necessary, so that the 200 |
|
basis points are evenly apportioned among each |
percentage point value between 100% and 125% |
achievement. |
(B) For the period January 1, 2026 through December |
31, 2030, provide for an adjustment to the return on |
equity component of the utility's weighted average |
cost of capital calculated under subsection (d) of this |
Section: |
(i) If the independent evaluator determines |
that the utility achieved a cumulative persisting |
annual savings that is less than the applicable |
annual incremental goal, then the return on equity |
component shall be reduced by a maximum of 200 |
basis points in the event that the utility achieved |
no more than 66% of such goal. If the utility |
achieved more than 66% of the applicable annual |
incremental goal but less than 100% of such goal, |
then the return on equity component shall be |
reduced by 6 basis points for each percent by which |
the utility failed to achieve the goal. |
(ii) If the independent evaluator determines |
that the utility achieved a cumulative persisting |
annual savings that is more than the applicable |
annual incremental goal, then the return on equity |
component shall be increased by a maximum of 200 |
basis points in the event that the utility achieved |
|
at least 134% of such goal. If the utility achieved |
more than 100% of the applicable annual |
incremental goal but less than 134% of such goal, |
then the return on equity component shall be |
increased by 6 basis points for each percent by |
which the utility achieved above the goal. If the |
applicable annual incremental goal was reduced |
under paragraph (3) of subsection (f) of this |
Section, then the following adjustments shall be |
made to the calculations described in this item |
(ii): |
(aa) the calculation for determining |
achievement that is at least 134% of the |
applicable annual incremental goal shall use |
the unreduced applicable annual incremental |
goal to set the value; and |
(bb) the calculation for determining |
achievement that is less than 134% but more |
than 100% of the applicable annual incremental |
goal shall use the reduced applicable annual |
incremental goal to set the value for 100% |
achievement of the goal and shall use the |
unreduced goal to set the value for 134% |
achievement. The 6 basis point value shall also |
be modified, as necessary, so that the 200 |
basis points are evenly apportioned among each |
|
percentage point value between 100% and 134% |
achievement. |
(7.5) For purposes of this Section, the term |
"applicable
annual incremental goal" means the difference |
between the
cumulative persisting annual savings goal for |
the calendar
year that is the subject of the independent |
evaluator's
determination and the cumulative persisting |
annual savings
goal for the immediately preceding calendar |
year, as such
goals are defined in subsections (b-5) and |
(b-15) of this
Section and as these goals may have been |
modified as
provided for under subsection (b-20) and |
paragraphs (1)
through (3) of subsection (f) of this |
Section. Under
subsections (b), (b-5), (b-10), and (b-15) |
of this Section,
a utility must first replace energy |
savings from measures
that have reached the end of their |
measure lives and would
otherwise have to be replaced to |
meet the applicable
savings goals identified in subsection |
(b-5) or (b-15) of this Section before any progress towards |
achievement of its
applicable annual incremental goal may |
be counted.
Notwithstanding anything else set forth in this |
Section,
the difference between the actual annual |
incremental
savings achieved in any given year, including |
the
replacement of energy savings from measures that have
|
expired, and the applicable annual incremental goal shall
|
not affect adjustments to the return on equity for
|
subsequent calendar years under this subsection (g). |
|
(8) For electric utilities that serve less than |
3,000,000 retail customers but more than 500,000 retail |
customers in the State: |
(A) Through December 31, 2025, the applicable |
annual incremental goal shall be compared to the annual |
incremental savings as determined by the independent |
evaluator. |
(i) The return on equity component shall be |
reduced by 8 basis points for each percent by which |
the utility did not achieve 84.4% of the applicable |
annual incremental goal. |
(ii) The return on equity component shall be |
increased by 8 basis points for each percent by |
which the utility exceeded 100% of the applicable |
annual incremental goal. |
(iii) The return on equity component shall not |
be increased or decreased if the annual |
incremental savings as determined by the |
independent evaluator is greater than 84.4% of the |
applicable annual incremental goal and less than |
100% of the applicable annual incremental goal. |
(iv) The return on equity component shall not |
be increased or decreased by an amount greater than |
200 basis points pursuant to this subparagraph |
(A). |
(B) For the period of January 1, 2026 through |
|
December 31, 2030, the applicable annual incremental |
goal shall be compared to the annual incremental |
savings as determined by the independent evaluator. |
(i) The return on equity component shall be |
reduced by 6 basis points for each percent by which |
the utility did not achieve 100% of the applicable |
annual incremental goal. |
(ii) The return on equity component shall be |
increased by 6 basis points for each percent by |
which the utility exceeded 100% of the applicable |
annual incremental goal. |
(iii) The return on equity component shall not |
be increased or decreased by an amount greater than |
200 basis points pursuant to this subparagraph |
(B). |
(C) If the applicable annual incremental goal was |
reduced under paragraphs (1), (2) or (3) of subsection |
(f) of this Section, then the following adjustments |
shall be made to the calculations described in |
subparagraphs (A) and (B) of this paragraph (8): |
(i) The calculation for determining |
achievement that is at least 125% or 134%, as |
applicable, of the applicable annual incremental |
goal shall use the unreduced applicable annual |
incremental goal to set the value. |
(ii) For the period through December 31, 2025, |
|
the calculation for determining achievement that |
is less than 125% but more than 100% of the |
applicable annual incremental goal shall use the |
reduced applicable annual incremental goal to set |
the value for 100% achievement of the goal and |
shall use the unreduced goal to set the value for |
125% achievement. The 8 basis point value shall |
also be modified, as necessary, so that the 200 |
basis points are evenly apportioned among each |
percentage point value between 100% and 125% |
achievement. |
(iii) For the period of January 1, 2026 through |
December 31, 2030, the calculation for determining |
achievement that is less than 134% but more than |
100% of the applicable annual incremental goal |
shall use the reduced applicable annual |
incremental goal to set the value for 100% |
achievement of the goal and shall use the unreduced |
goal to set the value for 125% achievement. The 6 |
basis point value shall also be modified, as |
necessary, so that the 200 basis points are evenly |
apportioned among each percentage point value |
between 100% and 134% achievement. |
(9) The utility shall submit the energy savings data to |
the independent evaluator no later than 30 days after the |
close of the plan year. The independent evaluator shall |
|
determine the cumulative persisting annual savings for a |
given plan year no later than 120 days after the close of |
the plan year. The utility shall submit an informational |
filing to the Commission no later than 160 days after the |
close of the plan year that attaches the independent |
evaluator's final report identifying the cumulative |
persisting annual savings for the year and calculates, |
under paragraph (7) or (8) of this subsection (g), as |
applicable, any resulting change to the utility's return on |
equity component of the weighted average cost of capital |
applicable to the next plan year beginning with the January |
monthly billing period and extending through the December |
monthly billing period. However, if the utility recovers |
the costs incurred under this Section under paragraphs (2) |
and (3) of subsection (d) of this Section, then the utility |
shall not be required to submit such informational filing, |
and shall instead submit the information that would |
otherwise be included in the informational filing as part |
of its filing under paragraph (3) of such subsection (d) |
that is due on or before June 1 of each year. |
For those utilities that must submit the informational |
filing, the Commission may, on its own motion or by |
petition, initiate an investigation of such filing, |
provided, however, that the utility's proposed return on |
equity calculation shall be deemed the final, approved |
calculation on December 15 of the year in which it is filed |
|
unless the Commission enters an order on or before December |
15, after notice and hearing, that modifies such |
calculation consistent with this Section. |
The adjustments to the return on equity component |
described in paragraphs (7) and (8) of this subsection (g) |
shall be applied as described in such paragraphs through a |
separate tariff mechanism, which shall be filed by the |
utility under subsections (f) and (g) of this Section. |
(h) No more than 6% of energy efficiency and |
demand-response program revenue may be allocated for research, |
development, or pilot deployment of new equipment or measures.
|
(i) When practicable, electric utilities shall incorporate |
advanced metering infrastructure data into the planning, |
implementation, and evaluation of energy efficiency measures |
and programs, subject to the data privacy and confidentiality |
protections of applicable law. |
(j) The independent evaluator shall follow the guidelines |
and use the savings set forth in Commission-approved energy |
efficiency policy manuals and technical reference manuals, as |
each may be updated from time to time. Until such time as |
measure life values for energy efficiency measures implemented |
for low-income households under subsection (c) of this Section |
are incorporated into such Commission-approved manuals, the |
low-income measures shall have the same measure life values |
that are established for same measures implemented in |
households that are not low-income households. |
|
(k) Notwithstanding any provision of law to the contrary, |
an electric utility subject to the requirements of this Section |
may file a tariff cancelling an automatic adjustment clause |
tariff in effect under this Section or Section 8-103, which |
shall take effect no later than one business day after the date |
such tariff is filed. Thereafter, the utility shall be |
authorized to defer and recover its expenditures incurred under |
this Section through a new tariff authorized under subsection |
(d) of this Section or in the utility's next rate case under |
Article IX or Section 16-108.5 of this Act, with interest at an |
annual rate equal to the utility's weighted average cost of |
capital as approved by the Commission in such case. If the |
utility elects to file a new tariff under subsection (d) of |
this Section, the utility may file the tariff within 10 days |
after the effective date of this amendatory Act of the 99th |
General Assembly, and the cost inputs to such tariff shall be |
based on the projected costs to be incurred by the utility |
during the calendar year in which the new tariff is filed and |
that were not recovered under the tariff that was cancelled as |
provided for in this subsection. Such costs shall include those |
incurred or to be incurred by the utility under its multi-year |
plan approved under subsections (f) and (g) of this Section, |
including, but not limited to, projected capital investment |
costs and projected regulatory asset balances with |
correspondingly updated depreciation and amortization reserves |
and expense. The Commission shall, after notice and hearing, |
|
approve, or approve with modification, such tariff and cost |
inputs no later than 75 days after the utility filed the |
tariff, provided that such approval, or approval with |
modification, shall be consistent with the provisions of this |
Section to the extent they do not conflict with this subsection |
(k). The tariff approved by the Commission shall take effect no |
later than 5 days after the Commission enters its order |
approving the tariff. |
No later than 60 days after the effective date of the |
tariff cancelling the utility's automatic adjustment clause |
tariff, the utility shall file a reconciliation that reconciles |
the moneys collected under its automatic adjustment clause |
tariff with the costs incurred during the period beginning June |
1, 2016 and ending on the date that the electric utility's |
automatic adjustment clause tariff was cancelled. In the event |
the reconciliation reflects an under-collection, the utility |
shall recover the costs as specified in this subsection (k). If |
the reconciliation reflects an over-collection, the utility |
shall apply the amount of such over-collection as a one-time |
credit to retail customers' bills. |
(l) For the calendar years covered by a multi-year plan |
commencing after December 31, 2017, subsections (a) through (j) |
of this Section do not apply to any retail customers of an |
electric utility that serves more than 3,000,000 retail |
customers in the State and whose total highest 30 minute demand |
was more than 10,000 kilowatts, or any retail customers of an |
|
electric utility that serves less than 3,000,000 retail |
customers but more than 500,000 retail customers in the State |
and whose total highest 15 minute demand was more than 10,000 |
kilowatts. For purposes of this subsection (l), "retail |
customer" has the meaning set forth in Section 16-102 of this |
Act. A determination of whether this subsection is applicable |
to a customer shall be made for each multi-year plan beginning |
after December 31, 2017. The criteria for determining whether |
this subsection (l) is applicable to a retail customer shall be |
based on the 12 consecutive billing periods prior to the start |
of the first year of each such multi-year plan. |
(m) Notwithstanding the requirements of this Section, as |
part of a proceeding to approve a multi-year plan under |
subsections (f) and (g) of this Section, the Commission shall |
reduce the amount of energy efficiency measures implemented for |
any single year, and whose costs are recovered under subsection |
(d) of this Section, by an amount necessary to limit the |
estimated average net increase due to the cost of the measures |
to no more than |
(1) 3.5% for the each of the 4 years beginning January |
1, 2018, |
(2) 3.75% for each of the 4 years beginning January 1, |
2022, and |
(3) 4% for each of the 5 years beginning January 1, |
2026, |
of the average amount paid per kilowatthour by residential |
|
eligible retail customers during calendar year 2015. To |
determine the total amount that may be spent by an electric |
utility in any single year, the applicable percentage of the |
average amount paid per kilowatthour shall be multiplied by the |
total amount of energy delivered by such electric utility in |
the calendar year 2015, adjusted to reflect the proportion of |
the utility's load attributable to customers who are exempt |
from subsections (a) through (j) of this Section under |
subsection (l) of this Section. For purposes of this subsection |
(m), the amount paid per kilowatthour includes,
without |
limitation, estimated amounts paid for supply,
transmission, |
distribution, surcharges, and add-on taxes. For purposes of |
this Section, "eligible retail customers" shall have the |
meaning set forth in Section 16-111.5 of this Act. Once the |
Commission has approved a plan under subsections (f) and (g) of |
this Section, no subsequent rate impact determinations shall be |
made. |
(220 ILCS 5/8-104)
|
Sec. 8-104. Natural gas energy efficiency programs. |
(a) It is the policy of the State that natural gas |
utilities and the Department of Commerce and Economic |
Opportunity are required to use cost-effective energy |
efficiency to reduce direct and indirect costs to consumers. It |
serves the public interest to allow natural gas utilities to |
recover costs for reasonably and prudently incurred expenses |
|
for cost-effective energy efficiency measures. |
(b) For purposes of this Section, "energy efficiency" means |
measures that reduce the amount of energy required to achieve a |
given end use. "Energy efficiency" also includes measures that |
reduce the total Btus of electricity and natural gas needed to |
meet the end use or uses. "Cost-effective" means that the |
measures satisfy the total resource cost test which, for |
purposes of this Section, means a standard that is met if, for |
an investment in energy efficiency, the benefit-cost ratio is |
greater than one. The benefit-cost ratio is the ratio of the |
net present value of the total benefits of the measures to the |
net present value of the total costs as calculated over the |
lifetime of the measures. The total resource cost test compares |
the sum of avoided natural gas utility costs, representing the |
benefits that accrue to the system and the participant in the |
delivery of those efficiency measures, as well as other |
quantifiable societal benefits, including avoided electric |
utility costs, to the sum of all incremental costs of end use |
measures (including both utility and participant |
contributions), plus costs to administer, deliver, and |
evaluate each demand-side measure, to quantify the net savings |
obtained by substituting demand-side measures for supply |
resources. In calculating avoided costs, reasonable estimates |
shall be included for financial costs likely to be imposed by |
future regulation of emissions of greenhouse gases. The |
low-income programs described in item (4) of subsection (f) of |
|
this Section shall not be required to meet the total resource |
cost test. |
(c) Natural gas utilities shall implement cost-effective |
energy efficiency measures to meet at least the following |
natural gas savings requirements, which shall be based upon the |
total amount of gas delivered to retail customers, other than |
the customers described in subsection (m) of this Section, |
during calendar year 2009 multiplied by the applicable |
percentage. Natural gas utilities may comply with this Section |
by meeting the annual incremental savings goal in the |
applicable year or by showing that total cumulative annual |
savings within a multi-year 3-year planning period associated |
with measures implemented after May 31, 2011 were equal to the |
sum of each annual incremental savings requirement from the |
first day of the multi-year planning period May 31, 2011 |
through the last day of the multi-year planning period end of |
the applicable year : |
(1) 0.2% by May 31, 2012; |
(2) an additional 0.4% by May 31, 2013, increasing |
total savings to .6%; |
(3) an additional 0.6% by May 31, 2014, increasing |
total savings to 1.2%; |
(4) an additional 0.8% by May 31, 2015, increasing |
total savings to 2.0%; |
(5) an additional 1% by May 31, 2016, increasing total |
savings to 3.0%; |
|
(6) an additional 1.2% by May 31, 2017, increasing |
total savings to 4.2%; |
(7) an additional 1.4% in the year commencing January |
1, 2018 by May 31, 2018, increasing total savings to 5.6% ; |
(8) an additional 1.5% in the year commencing January |
1, 2019 by May 31, 2019, increasing total savings to 7.1% ; |
and |
(9) an additional 1.5% in each 12-month period |
thereafter. |
(d) Notwithstanding the requirements of subsection (c) of |
this Section, a natural gas utility shall limit the amount of |
energy efficiency implemented in any multi-year 3-year |
reporting period established by subsection (f) of Section 8-104 |
of this Act, by an amount necessary to limit the estimated |
average increase in the amounts paid by retail customers in |
connection with natural gas service to no more than 2% in the |
applicable multi-year 3-year reporting period. The energy |
savings requirements in subsection (c) of this Section may be |
reduced by the Commission for the subject plan, if the utility |
demonstrates by substantial evidence that it is highly unlikely |
that the requirements could be achieved without exceeding the |
applicable spending limits in any multi-year 3-year reporting |
period. No later than September 1, 2013, the Commission shall |
review the limitation on the amount of energy efficiency |
measures implemented pursuant to this Section and report to the |
General Assembly, in the report required by subsection (k) of |
|
this Section, its findings as to whether that limitation unduly |
constrains the procurement of energy efficiency measures. |
(e) The provisions of this subsection (e) apply to those |
multi-year plans that commence prior to January 1, 2018 Natural |
gas utilities shall be responsible for overseeing the design, |
development, and filing of their efficiency plans with the |
Commission . The utility shall utilize 75% of the available |
funding associated with energy efficiency programs approved by |
the Commission, and may outsource various aspects of program |
development and implementation. The remaining 25% of available |
funding shall be used by the Department of Commerce and |
Economic Opportunity to implement energy efficiency measures |
that achieve no less than 20% of the requirements of subsection |
(c) of this Section. Such measures shall be designed in |
conjunction with the utility and approved by the Commission. |
The Department may outsource development and implementation of |
energy efficiency measures. A minimum of 10% of the entire |
portfolio of cost-effective energy efficiency measures shall |
be procured from local government, municipal corporations, |
school districts, and community college districts. Five |
percent of the entire portfolio of cost-effective energy |
efficiency measures may be granted to local government and |
municipal corporations for market transformation initiatives. |
The Department shall coordinate the implementation of these |
measures and shall integrate delivery of natural gas efficiency |
programs with electric efficiency programs delivered pursuant |
|
to Section 8-103 of this Act, unless the Department can show |
that integration is not feasible. |
The apportionment of the dollars to cover the costs to |
implement the Department's share of the portfolio of energy |
efficiency measures shall be made to the Department once the |
Department has executed rebate agreements, grants, or |
contracts for energy efficiency measures and provided |
supporting documentation for those rebate agreements, grants, |
and contracts to the utility. The Department is authorized to |
adopt any rules necessary and prescribe procedures in order to |
ensure compliance by applicants in carrying out the purposes of |
rebate agreements for energy efficiency measures implemented |
by the Department made under this Section. |
The details of the measures implemented by the Department |
shall be submitted by the Department to the Commission in |
connection with the utility's filing regarding the energy |
efficiency measures that the utility implements. |
The portfolio of measures, administered by both the |
utilities and the Department, shall, in combination, be |
designed to achieve the annual energy savings requirements set |
forth in subsection (c) of this Section, as modified by |
subsection (d) of this Section. |
The utility and the Department shall agree upon a |
reasonable portfolio of measures and determine the measurable |
corresponding percentage of the savings goals associated with |
measures implemented by the Department. |
|
No utility shall be assessed a penalty under subsection (f) |
of this Section for failure to make a timely filing if that |
failure is the result of a lack of agreement with the |
Department with respect to the allocation of responsibilities |
or related costs or target assignments. In that case, the |
Department and the utility shall file their respective plans |
with the Commission and the Commission shall determine an |
appropriate division of measures and programs that meets the |
requirements of this Section. |
(e-5) The provisions of this subsection (e-5) shall be |
applicable to those multi-year plans that commence after |
December 31, 2017. Natural gas utilities shall be responsible |
for overseeing the design, development, and filing of their |
efficiency plans with the Commission and may outsource |
development and implementation of energy efficiency measures. |
A minimum of 10% of the entire portfolio of cost-effective |
energy efficiency measures shall be procured from local |
government, municipal corporations, school districts, and |
community college districts. Five percent of the entire |
portfolio of cost-effective energy efficiency measures may be |
granted to local government and municipal corporations for |
market transformation initiatives. |
The utilities shall also present a portfolio of energy |
efficiency measures proportionate to the share of total annual |
utility revenues in Illinois from households at or below 150% |
of the poverty level. Such programs shall be targeted to |
|
households with incomes at or below 80% of area median income. |
(e-10) A utility providing approved energy efficiency |
measures in this State shall be permitted to recover costs of |
those measures through an automatic adjustment clause tariff |
filed with and approved by the Commission. The tariff shall be |
established outside the context of a general rate case and |
shall be applicable to the utility's customers other than the |
customers described in subsection (m) of this Section. Each |
year the Commission shall initiate a review to reconcile any |
amounts collected with the actual costs and to determine the |
required adjustment to the annual tariff factor to match annual |
expenditures. |
(e-15) For those multi-year plans that commence prior to |
January 1, 2018, each Each utility shall include, in its |
recovery of costs, the costs estimated for both the utility's |
and the Department's implementation of energy efficiency |
measures. Costs collected by the utility for measures |
implemented by the Department shall be submitted to the |
Department pursuant to Section 605-323 of the Civil |
Administrative Code of Illinois, shall be deposited into the |
Energy Efficiency Portfolio Standards Fund, and shall be used |
by the Department solely for the purpose of implementing these |
measures. A utility shall not be required to advance any moneys |
to the Department but only to forward such funds as it has |
collected. The Department shall report to the Commission on an |
annual basis regarding the costs actually incurred by the |
|
Department in the implementation of the measures. Any changes |
to the costs of energy efficiency measures as a result of plan |
modifications shall be appropriately reflected in amounts |
recovered by the utility and turned over to the Department. |
The portfolio of measures, administered by both the |
utilities and the Department, shall, in combination, be |
designed to achieve the annual energy savings requirements set |
forth in subsection (c) of this Section, as modified by |
subsection (d) of this Section. |
The utility and the Department shall agree upon a |
reasonable portfolio of measures and determine the measurable |
corresponding percentage of the savings goals associated with |
measures implemented by the Department. |
No utility shall be assessed a penalty under subsection (f) |
of this Section for failure to make a timely filing if that |
failure is the result of a lack of agreement with the |
Department with respect to the allocation of responsibilities |
or related costs or target assignments. In that case, the |
Department and the utility shall file their respective plans |
with the Commission and the Commission shall determine an |
appropriate division of measures and programs that meets the |
requirements of this Section. |
If the Department is unable to meet performance |
requirements for the portion of the portfolio implemented by |
the Department, then the utility and the Department shall |
jointly submit a modified filing to the Commission explaining |
|
the performance shortfall and recommending an appropriate |
course going forward, including any program modifications that |
may be appropriate in light of the evaluations conducted under |
item (8) of subsection (f) of this Section. In this case, the |
utility obligation to collect the Department's costs and turn |
over those funds to the Department under this subsection (e) |
shall continue only if the Commission approves the |
modifications to the plan proposed by the Department. |
(f) No later than October 1, 2010, each gas utility shall |
file an energy efficiency plan with the Commission to meet the |
energy efficiency standards through May 31, 2014. No later than |
October 1, 2013, each gas utility shall file an energy |
efficiency plan with the Commission to meet the energy |
efficiency standards through May 31, 2017. Beginning in 2017 |
and every 4 Every 3 years thereafter, each utility shall file , |
no later than October 1, an energy efficiency plan with the |
Commission to meet the energy efficiency standards for the next |
applicable 4-year period beginning January 1 of the year |
following the filing. For those multi-year plans commencing on |
January 1, 2018, each utility shall file its proposed energy |
efficiency plan no later than 30 days after the effective date |
of this amendatory Act of the 99th General Assembly or May 1, |
2017, whichever is later. Beginning in 2021 and every 4 years |
thereafter, each utility shall file its energy efficiency plan |
no later than March 1 . If a utility does not file such a plan on |
or before the applicable filing deadline for the plan by |
|
October 1 of the applicable year , then it shall face a penalty |
of $100,000 per day until the plan is filed. |
Each utility's plan shall set forth the utility's proposals |
to meet the utility's portion of the energy efficiency |
standards identified in subsection (c) of this Section, as |
modified by subsection (d) of this Section, taking into account |
the unique circumstances of the utility's service territory. |
For those plans commencing after December 31, 2021, the The |
Commission shall seek public comment on the utility's plan and |
shall issue an order approving or disapproving each plan within |
6 months after its submission. For those plans commencing on |
January 1, 2018, the Commission shall seek public comment on |
the utility's plan and shall issue an order approving or |
disapproving each plan no later than August 31, 2017, or 105 |
days after the effective date of this amendatory Act of the |
99th General Assembly, whichever is later . If the Commission |
disapproves a plan, the Commission shall, within 30 days, |
describe in detail the reasons for the disapproval and describe |
a path by which the utility may file a revised draft of the |
plan to address the Commission's concerns satisfactorily. If |
the utility does not refile with the Commission within 60 days |
after the disapproval, the utility shall be subject to |
penalties at a rate of $100,000 per day until the plan is |
filed. This process shall continue, and penalties shall accrue, |
until the utility has successfully filed a portfolio of energy |
efficiency measures. Penalties shall be deposited into the |
|
Energy Efficiency Trust Fund and the cost of any such penalties |
may not be recovered from ratepayers. In submitting proposed |
energy efficiency plans and funding levels to meet the savings |
goals adopted by this Act the utility shall: |
(1) Demonstrate that its proposed energy efficiency |
measures will achieve the requirements that are identified |
in subsection (c) of this Section, as modified by |
subsection (d) of this Section. |
(2) Present specific proposals to implement new |
building and appliance standards that have been placed into |
effect. |
(3) Present estimates of the total amount paid for gas |
service expressed on a per therm basis associated with the |
proposed portfolio of measures designed to meet the |
requirements that are identified in subsection (c) of this |
Section, as modified by subsection (d) of this Section. |
(4) For those multi-year plans that commence prior to |
January 1, 2018, coordinate Coordinate with the Department |
to present a portfolio of energy efficiency measures |
proportionate to the share of total annual utility revenues |
in Illinois from households at or below 150% of the poverty |
level. Such programs shall be targeted to households with |
incomes at or below 80% of area median income. |
(5) Demonstrate that its overall portfolio of energy |
efficiency measures, not including low-income programs |
described in covered by item (4) of this subsection (f) and |
|
subsection (e-5) of this Section , are cost-effective using |
the total resource cost test and represent a diverse cross |
section of opportunities for customers of all rate classes |
to participate in the programs. |
(6) Demonstrate that a gas utility affiliated with an |
electric utility that is required to comply with Section |
8-103 or 8-103B of this Act has integrated gas and electric |
efficiency measures into a single program that reduces |
program or participant costs and appropriately allocates |
costs to gas and electric ratepayers. For those multi-year |
plans that commence prior to January 1, 2018, the The |
Department shall integrate all gas and electric programs it |
delivers in any such utilities' service territories, |
unless the Department can show that integration is not |
feasible or appropriate. |
(7) Include a proposed cost recovery tariff mechanism |
to fund the proposed energy efficiency measures and to |
ensure the recovery of the prudently and reasonably |
incurred costs of Commission-approved programs. |
(8) Provide for quarterly status reports tracking |
implementation of and expenditures for the utility's |
portfolio of measures and , if applicable, the Department's |
portfolio of measures, an annual independent review, and a |
full independent evaluation of the multi-year 3-year |
results of the performance and the cost-effectiveness of |
the utility's and , if applicable, Department's portfolios |
|
of measures and broader net program impacts and, to the |
extent practical, for adjustment of the measures on a going |
forward basis as a result of the evaluations. The resources |
dedicated to evaluation shall not exceed 3% of portfolio |
resources in any given multi-year 3-year period. |
(g) No more than 3% of expenditures on energy efficiency |
measures may be allocated for demonstration of breakthrough |
equipment and devices. |
(h) Illinois natural gas utilities that are affiliated by |
virtue of a common parent company may, at the utilities' |
request, be considered a single natural gas utility for |
purposes of complying with this Section. |
(i) If, after 3 years, a gas utility fails to meet the |
efficiency standard specified in subsection (c) of this Section |
as modified by subsection (d), then it shall make a |
contribution to the Low-Income Home Energy Assistance Program. |
The total liability for failure to meet the goal shall be |
assessed as follows: |
(1) a large gas utility shall pay $600,000; |
(2) a medium gas utility shall pay $400,000; and |
(3) a small gas utility shall pay $200,000. |
For purposes of this Section, (i) a "large gas utility" is |
a gas utility that on December 31, 2008, served more than |
1,500,000 gas customers in Illinois; (ii) a "medium gas |
utility" is a gas utility that on December 31, 2008, served |
fewer than 1,500,000, but more than 500,000 gas customers in |
|
Illinois; and (iii) a "small gas utility" is a gas utility that |
on December 31, 2008, served fewer than 500,000 and more than |
100,000 gas customers in Illinois. The costs of this |
contribution may not be recovered from ratepayers. |
If a gas utility fails to meet the efficiency standard |
specified in subsection (c) of this Section, as modified by |
subsection (d) of this Section, in any 2 consecutive multi-year |
3-year planning periods, then the responsibility for |
implementing the utility's energy efficiency measures shall be |
transferred to an independent program administrator selected |
by the Commission. Reasonable and prudent costs incurred by the |
independent program administrator to meet the efficiency |
standard specified in subsection (c) of this Section, as |
modified by subsection (d) of this Section, may be recovered |
from the customers of the affected gas utilities, other than |
customers described in subsection (m) of this Section. The |
utility shall provide the independent program administrator |
with all information and assistance necessary to perform the |
program administrator's duties including but not limited to |
customer, account, and energy usage data, and shall allow the |
program administrator to include inserts in customer bills. The |
utility may recover reasonable costs associated with any such |
assistance. |
(j) No utility shall be deemed to have failed to meet the |
energy efficiency standards to the extent any such failure is |
due to a failure of the Department. |
|
(k) Not later than January 1, 2012, the Commission shall |
develop and solicit public comment on a plan to foster |
statewide coordination and consistency between statutorily |
mandated natural gas and electric energy efficiency programs to |
reduce program or participant costs or to improve program |
performance. Not later than September 1, 2013, the Commission |
shall issue a report to the General Assembly containing its |
findings and recommendations. |
(l) This Section does not apply to a gas utility that on |
January 1, 2009, provided gas service to fewer than 100,000 |
customers in Illinois. |
(m) Subsections (a) through (k) of this Section do not |
apply to customers of a natural gas utility that have a North |
American Industry Classification System code number that is |
22111 or any such code number beginning with the digits 31, 32, |
or 33 and (i) annual usage in the aggregate of 4 million therms |
or more within the service territory of the affected gas |
utility or with aggregate usage of 8 million therms or more in |
this State and complying with the provisions of item (l) of |
this subsection (m); or (ii) using natural gas as feedstock and |
meeting the usage requirements described in item (i) of this |
subsection (m), to the extent such annual feedstock usage is |
greater than 60% of the customer's total annual usage of |
natural gas. |
(1) Customers described in this subsection (m) of this |
Section shall apply, on a form approved on or before |
|
October 1, 2009 by the Department, to the Department to be |
designated as a self-directing customer ("SDC") or as an |
exempt customer using natural gas as a feedstock from which |
other products are made, including, but not limited to, |
feedstock for a hydrogen plant, on or before the 1st day of |
February, 2010. Thereafter, application may be made not |
less than 6 months before the filing date of the gas |
utility energy efficiency plan described in subsection (f) |
of this Section; however, a new customer that commences |
taking service from a natural gas utility after February 1, |
2010 may apply to become a SDC or exempt customer up to 30 |
days after beginning service. Customers described in this |
subsection (m) that have not already been approved by the |
Department may apply to be designated a self-directing |
customer or exempt customer, on a form approved by the |
Department, between September 1, 2013 and September 30, |
2013. Customer applications that are approved by the |
Department under this amendatory Act of the 98th General |
Assembly shall be considered to be a self-directing |
customer or exempt customer, as applicable, for the current |
3-year planning period effective December 1, 2013. Such |
application shall contain the following: |
(A) the customer's certification that, at the time |
of its application, it qualifies to be a SDC or exempt |
customer described in this subsection (m) of this |
Section; |
|
(B) in the case of a SDC, the customer's |
certification that it has established or will |
establish by the beginning of the utility's multi-year |
3-year planning period commencing subsequent to the |
application, and will maintain for accounting |
purposes, an energy efficiency reserve account and |
that the customer will accrue funds in said account to |
be held for the purpose of funding, in whole or in |
part, energy efficiency measures of the customer's |
choosing, which may include, but are not limited to, |
projects involving combined heat and power systems |
that use the same energy source both for the generation |
of electrical or mechanical power and the production of |
steam or another form of useful thermal energy or the |
use of combustible gas produced from biomass, or both; |
(C) in the case of a SDC, the customer's |
certification that annual funding levels for the |
energy efficiency reserve account will be equal to 2% |
of the customer's cost of natural gas, composed of the |
customer's commodity cost and the delivery service |
charges paid to the gas utility, or $150,000, whichever |
is less; |
(D) in the case of a SDC, the customer's |
certification that the required reserve account |
balance will be capped at 3 years' worth of accruals |
and that the customer may, at its option, make further |
|
deposits to the account to the extent such deposit |
would increase the reserve account balance above the |
designated cap level; |
(E) in the case of a SDC, the customer's |
certification that by October 1 of each year, beginning |
no sooner than October 1, 2012, the customer will |
report to the Department information, for the 12-month |
period ending May 31 of the same year, on all deposits |
and reductions, if any, to the reserve account during |
the reporting year, and to the extent deposits to the |
reserve account in any year are in an amount less than |
$150,000, the basis for such reduced deposits; reserve |
account balances by month; a description of energy |
efficiency measures undertaken by the customer and |
paid for in whole or in part with funds from the |
reserve account; an estimate of the energy saved, or to |
be saved, by the measure; and that the report shall |
include a verification by an officer or plant manager |
of the customer or by a registered professional |
engineer or certified energy efficiency trade |
professional that the funds withdrawn from the reserve |
account were used for the energy efficiency measures; |
(F) in the case of an exempt customer, the |
customer's certification of the level of gas usage as |
feedstock in the customer's operation in a typical year |
and that it will provide information establishing this |
|
level, upon request of the Department; |
(G) in the case of either an exempt customer or a |
SDC, the customer's certification that it has provided |
the gas utility or utilities serving the customer with |
a copy of the application as filed with the Department; |
(H) in the case of either an exempt customer or a |
SDC, certification of the natural gas utility or |
utilities serving the customer in Illinois including |
the natural gas utility accounts that are the subject |
of the application; and |
(I) in the case of either an exempt customer or a |
SDC, a verification signed by a plant manager or an |
authorized corporate officer attesting to the |
truthfulness and accuracy of the information contained |
in the application. |
(2) The Department shall review the application to |
determine that it contains the information described in |
provisions (A) through (I) of item (1) of this subsection |
(m), as applicable. The review shall be completed within 30 |
days after the date the application is filed with the |
Department. Absent a determination by the Department |
within the 30-day period, the applicant shall be considered |
to be a SDC or exempt customer, as applicable, for all |
subsequent multi-year 3-year planning periods, as of the |
date of filing the application described in this subsection |
(m). If the Department determines that the application does |
|
not contain the applicable information described in |
provisions (A) through (I) of item (1) of this subsection |
(m), it shall notify the customer, in writing, of its |
determination that the application does not contain the |
required information and identify the information that is |
missing, and the customer shall provide the missing |
information within 15 working days after the date of |
receipt of the Department's notification. |
(3) The Department shall have the right to audit the |
information provided in the customer's application and |
annual reports to ensure continued compliance with the |
requirements of this subsection. Based on the audit, if the |
Department determines the customer is no longer in |
compliance with the requirements of items (A) through (I) |
of item (1) of this subsection (m), as applicable, the |
Department shall notify the customer in writing of the |
noncompliance. The customer shall have 30 days to establish |
its compliance, and failing to do so, may have its status |
as a SDC or exempt customer revoked by the Department. The |
Department shall treat all information provided by any |
customer seeking SDC status or exemption from the |
provisions of this Section as strictly confidential. |
(4) Upon request, or on its own motion, the Commission |
may open an investigation, no more than once every 3 years |
and not before October 1, 2014, to evaluate the |
effectiveness of the self-directing program described in |
|
this subsection (m). |
Customers described in this subsection (m) that applied to |
the Department on January 3, 2013, were approved by the |
Department on February 13, 2013 to be a self-directing customer |
or exempt customer, and receive natural gas from a utility that |
provides gas service to at least 500,000 retail customers in |
Illinois and electric service to at least 1,000,000 retail |
customers in Illinois shall be considered to be a |
self-directing customer or exempt customer, as applicable, for |
the current 3-year planning period effective December 1, 2013. |
(n) The applicability of this Section to customers |
described in subsection (m) of this Section is conditioned on |
the existence of the SDC program. In no event will any |
provision of this Section apply to such customers after January |
1, 2020.
|
(o) Utilities' 3-year energy efficiency plans approved by |
the Commission on or before the effective date of this |
amendatory Act of the 99th General Assembly for the period June |
1, 2014 through May 31, 2017 shall continue to be in force and |
effect through December 31, 2017 so that the energy efficiency |
programs set forth in those plans continue to be offered during |
the period June 1, 2017 through December 31, 2017. Each utility |
is authorized to increase, on a pro rata basis, the energy |
savings goals and budgets approved in its plan to reflect the |
additional 7 months of the plan's operation. |
(Source: P.A. 97-813, eff. 7-13-12; 97-841, eff. 7-20-12; |
|
98-90, eff. 7-15-13; 98-225, eff. 8-9-13; 98-604, eff. |
12-17-13.) |
(220 ILCS 5/9-107 new) |
Sec. 9-107. Revenue balancing adjustments. |
(a) In this Section: |
"Reconciliation period" means a period beginning with the |
January monthly billing period and extending through the |
December monthly billing period. |
"Rate case reconciliation revenue requirement" means the |
final distribution revenue requirement or requirements |
approved by the Commission in the utility's rate case or |
formula rate proceeding to set the rates initially applicable |
in the relevant reconciliation period after the conclusion of |
the period. In the event the Commission has approved more than |
one revenue requirement for the reconciliation period, the |
amount of rate case revenue under each approved revenue |
requirement shall be prorated based upon the number of days |
under which each revenue requirement was in effect. |
(b) If an electric utility has a performance-based formula |
rate in effect under Section 16-108.5, then the utility shall |
be permitted to revise the formula rate and schedules to reduce |
the 50 basis point values to zero that would otherwise apply |
under paragraph (5) of subsection (c) of Section 16-108.5. Such |
revision and reduction shall apply beginning with the |
reconciliation conducted for the 2017 calendar year. |
|
If the utility no longer has a performance-based formula in |
effect under Section 16-108.5, then the utility shall be |
permitted to implement the revenue balancing adjustment tariff |
described in subsection (c) of this Section. |
(c) An electric utility that is authorized under subsection |
(b) of this Section to implement a revenue balancing adjustment |
tariff may file the tariff for the purpose of preventing |
undercollections or overcollections of distribution revenues |
as compared to the revenue requirement or requirements approved |
by the Commission on which the rates giving rise to those |
revenues were based. The tariff shall calculate an annual |
adjustment that reflects any difference between the actual |
delivery service revenue billed for services provided during |
the relevant reconciliation period and the rate case |
reconciliation revenue requirement for the relevant |
reconciliation period and shall set forth the reconciliation |
categories or classes, or a combination of both, in a manner |
determined at the utility's discretion. |
(d) A utility that elects to file the tariff authorized by |
this Section shall file the tariff outside the context of a |
general rate case or formula rate proceeding, and the |
Commission shall, after notice and hearing, approve the tariff |
or approve with modification no later than 120 days after the |
utility files the tariff, and the tariff shall remain in effect |
at the discretion of the utility. The tariff shall also require |
that the electric utility submit an annual revenue balancing |
|
reconciliation report to the Commission reflecting the |
difference between the actual delivery service revenue and rate |
case revenue for the applicable reconciliation and identifying |
the charges or credits to be applied thereafter. The annual |
revenue balancing reconciliation report shall be filed with the |
Commission no later than March 20 of the year following a |
reconciliation period. The Commission may initiate a review of |
the revenue balancing reconciliation report each year to |
determine if any subsequent adjustment is necessary to align |
actual delivery service revenue and rate case revenue. In the |
event the Commission elects to initiate such review, the |
Commission shall, after notice and hearing, enter an order |
approving, or approving as modified, such revenue balancing |
reconciliation report no later than 120 days after the utility |
files its report with the Commission. If the Commission does |
not initiate such review, the revenue balancing reconciliation |
report and the identified charges or credits shall be deemed |
accepted and approved 120 days after the utility files the |
report and shall not be subject to review in any other |
proceeding.
|
(220 ILCS 5/16-107)
|
Sec. 16-107. Real-time pricing.
|
(a) Each electric utility shall file, on or before May 1,
|
1998, a tariff or tariffs which allow nonresidential retail
|
customers in the electric utility's service area to elect
|
|
real-time pricing beginning October 1, 1998.
|
(b) Each electric utility shall file, on or before May 1,
|
2000, a tariff or tariffs which allow residential retail
|
customers in the electric utility's service area to elect
|
real-time pricing beginning October 1, 2000.
|
(b-5) Each electric utility shall file a tariff or tariffs |
allowing residential retail customers in the electric |
utility's service area to elect real-time pricing beginning |
January 2, 2007. The Commission may, after notice and hearing, |
approve the tariff or tariffs. A customer who elects real-time |
pricing shall remain on such rate for a minimum of 12 months. |
The Commission may, after notice and hearing, approve the |
tariff or tariffs, provided that the Commission finds that the |
potential for demand reductions will result in net economic |
benefits to all residential customers of the electric utility. |
In examining economic benefits from demand reductions, the |
Commission shall, at a minimum, consider the following: |
improvements to system reliability and power quality, |
reduction in wholesale market prices and price volatility, |
electric utility cost avoidance and reductions, market power |
mitigation, and other benefits of demand reductions, but only |
to the extent that the effects of reduced demand can be |
demonstrated to lower the cost of electricity delivered to |
residential customers. A tariff or tariffs approved pursuant to |
this subsection (b-5) shall, at a minimum, describe (i) the |
methodology for determining the market price of energy to be |
|
reflected in the real-time rate and (ii) the manner in which |
customers who elect real-time pricing will be provided with |
ready access to hourly market prices, including, but not |
limited to, day-ahead hourly energy prices. A customer who |
elects real-time pricing under a tariff approved under this |
subsection (b-5) and thereafter terminates the election shall |
not return to taking service under the tariff for a period of |
12 months following the date on which the customer terminated |
real-time pricing. However, this limitation shall cease to |
apply on such date that the provision of electric power and |
energy is declared competitive under Section 16-113 of this Act |
for the customer group or groups to which this subsection (b-5) |
applies. |
A proceeding under this subsection (b-5) may not exceed 120 |
days in length.
|
(b-10) Each electric utility providing real-time pricing |
pursuant to subsection (b-5) shall install a meter capable of |
recording hourly interval energy use at the service location of |
each customer that elects real-time pricing pursuant to this |
subsection. |
(b-15) If the Commission issues an order pursuant to |
subsection (b-5), the affected electric utility shall contract |
with an entity not affiliated with the electric utility to |
serve as a program administrator to develop and implement a |
program to provide consumer outreach, enrollment, and |
education concerning real-time pricing and to establish and |
|
administer an information system and technical and other |
customer assistance that is necessary to enable customers to |
manage electricity use. The program administrator: (i) shall be |
selected and compensated by the electric utility, subject to |
Commission approval; (ii) shall have demonstrated technical |
and managerial competence in the development and |
administration of demand management programs; and (iii) may |
develop and implement risk management, energy efficiency, and |
other services related to energy use management for which the |
program administrator shall be compensated by participants in |
the program receiving such services. The electric utility shall |
provide the program administrator with all information and |
assistance necessary to perform the program administrator's |
duties, including, but not limited to, customer, account, and |
energy use data. The electric utility shall permit the program |
administrator to include inserts in residential customer bills |
2 times per year to assist with customer outreach and |
enrollment. |
The program administrator shall submit an annual report to |
the electric utility no later than April 1 of each year |
describing the operation and results of the program, including |
information concerning the number and types of customers using |
real-time pricing, changes in customers' energy use patterns, |
an assessment of the value of the program to both participants |
and non-participants, and recommendations concerning |
modification of the program and the tariff or tariffs filed |
|
under subsection (b-5). This report shall be filed by the |
electric utility with the Commission within 30 days of receipt |
and shall be available to the public on the Commission's web |
site. |
(b-20) The Commission shall monitor the performance of |
programs established pursuant to subsection (b-15) and shall |
order the termination or modification of a program if it |
determines that the program is not, after a reasonable period |
of time for development not to exceed 4 years, resulting in net |
benefits to the residential customers of the electric utility.
|
(b-25) An electric utility shall be entitled to recover |
reasonable costs incurred in complying with this Section, |
provided that recovery of the costs is fairly apportioned among |
its residential customers as provided in this subsection |
(b-25). The electric utility may apportion greater costs on the |
residential customers who elect real-time pricing, but may also |
impose some of the costs of real-time pricing on customers who |
do not elect real-time pricing , provided that the Commission |
determines that the cost savings resulting from real-time |
pricing will exceed the costs imposed on customers for |
maintaining the program .
|
(c) The electric utility's tariff or tariffs filed
pursuant |
to this Section shall be subject to Article IX.
|
(d) This Section does not apply to any electric utility |
providing service to 100,000 or fewer customers.
|
(Source: P.A. 94-977, eff. 6-30-06.)
|
|
(220 ILCS 5/16-107.5)
|
Sec. 16-107.5. Net electricity metering. |
(a) The Legislature finds and declares that a program to |
provide net electricity
metering, as defined in this Section,
|
for eligible customers can encourage private investment in |
renewable energy
resources, stimulate
economic growth, enhance |
the continued diversification of Illinois' energy
resource |
mix, and protect
the Illinois environment.
|
(b) As used in this Section, (i) "community renewable |
generation project" shall have the meaning set forth in Section |
1-10 of the Illinois Power Agency Act; (ii) "eligible customer" |
means a retail
customer that owns or operates a
solar, wind, or |
other eligible renewable electrical generating facility with a |
rated capacity of not more than
2,000 kilowatts that is
located |
on the customer's premises and is intended primarily to offset |
the customer's
own electrical requirements; (iii) (ii) |
"electricity provider" means an electric utility or |
alternative retail electric supplier; (iv) (iii) "eligible |
renewable electrical generating facility" means a generator |
that is interconnected under rules adopted by the Commission |
and is powered by solar electric energy, wind, dedicated crops |
grown for electricity generation, agricultural residues, |
untreated and unadulterated wood waste, landscape trimmings, |
livestock manure, anaerobic digestion of livestock or food |
processing waste, fuel cells or microturbines powered by |
|
renewable fuels, or hydroelectric energy; (v) and (iv) "net |
electricity metering" (or "net metering") means the
|
measurement, during the
billing period applicable to an |
eligible customer, of the net amount of
electricity supplied by |
an
electricity provider to the customer's premises or provided |
to the electricity provider by the customer or subscriber; (vi) |
"subscriber" shall have the meaning as set forth in Section |
1-10 of the Illinois Power Agency Act; and (vii) "subscription" |
shall have the meaning set forth in Section 1-10 of the |
Illinois Power Agency Act .
|
(c) A net metering facility shall be equipped with metering |
equipment that can measure the flow of electricity in both |
directions at the same rate. |
(1) For eligible customers whose electric service has |
not been declared competitive pursuant to Section 16-113 of |
this Act as of July 1, 2011 and whose electric delivery |
service is provided and measured on a kilowatt-hour basis |
and electric supply service is not provided based on hourly |
pricing, this shall typically be accomplished through use |
of a single, bi-directional meter. If the eligible |
customer's existing electric revenue meter does not meet |
this requirement, the electricity provider shall arrange |
for the local electric utility or a meter service provider |
to install and maintain a new revenue meter at the |
electricity provider's expense , which may be the smart |
meter described by subsection (b) of Section 16-108.5 of |
|
this Act . |
(2) For eligible customers whose electric service has |
not been declared competitive pursuant to Section 16-113 of |
this Act as of July 1, 2011 and whose electric delivery |
service is provided and measured on a kilowatt demand basis |
and electric supply service is not provided based on hourly |
pricing, this shall typically be accomplished through use |
of a dual channel meter capable of measuring the flow of |
electricity both into and out of the customer's facility at |
the same rate and ratio. If such customer's existing |
electric revenue meter does not meet this requirement, then |
the electricity provider shall arrange for the local |
electric utility or a meter service provider to install and |
maintain a new revenue meter at the electricity provider's |
expense , which may be the smart meter described by |
subsection (b) of Section 16-108.5 of this Act . |
(3) For all other eligible customers, until such time |
as the local electric utility installs a smart meter, as |
described by subsection (b) of Section 16-108.5 of this |
Act, the electricity provider may arrange for the local |
electric utility or a meter service provider to install and |
maintain metering equipment capable of measuring the flow |
of electricity both into and out of the customer's facility |
at the same rate and ratio, typically through the use of a |
dual channel meter. If the eligible customer's existing |
electric revenue meter does not meet this requirement, then |
|
the costs of installing such equipment shall be paid for by |
the customer.
|
(d) An electricity provider shall
measure and charge or |
credit for the net
electricity supplied to eligible customers |
or provided by eligible customers whose electric service has |
not been declared competitive pursuant to Section 16-113 of |
this the Act as of July 1, 2011 and whose electric delivery |
service is provided and measured on a kilowatt-hour basis and |
electric supply service is not provided based on hourly pricing |
in
the following manner:
|
(1) If the amount of electricity used by the customer |
during the billing
period exceeds the
amount of electricity |
produced by the customer, the electricity provider shall |
charge the customer for the net electricity supplied to and |
used
by the customer as provided in subsection (e-5) of |
this Section.
|
(2) If the amount of electricity produced by a customer |
during the billing period exceeds the amount of electricity |
used by the customer during that billing period, the |
electricity provider supplying that customer shall apply a |
1:1 kilowatt-hour credit to a subsequent bill for service |
to the customer for the net electricity supplied to the |
electricity provider. The electricity provider shall |
continue to carry over any excess kilowatt-hour credits |
earned and apply those credits to subsequent billing |
periods to offset any customer-generator consumption in |
|
those billing periods until all credits are used or until |
the end of the annualized period.
|
(3) At the end of the year or annualized over the |
period that service is supplied by means of net metering, |
or in the event that the retail customer terminates service |
with the electricity provider prior to the end of the year |
or the annualized period, any remaining credits in the |
customer's account shall expire.
|
(d-5) An electricity provider shall measure and charge or |
credit for the net electricity
supplied to eligible customers |
or provided by eligible customers whose electric service has |
not
been declared competitive pursuant to Section 16-113 of |
this Act as of July 1, 2011 and whose electric delivery
service |
is provided and measured on a kilowatt-hour basis and electric |
supply service is provided
based on hourly pricing in the |
following manner: |
(1) If the amount of electricity used by the customer |
during any hourly period exceeds the amount of electricity |
produced by the customer, the electricity provider shall |
charge the customer for the net electricity supplied to and |
used by the customer according to the terms of the contract |
or tariff to which the same customer would be assigned to |
or be eligible for if the customer was not a net metering |
customer. |
(2) If the amount of electricity produced by a customer |
during any hourly period exceeds the amount of electricity |
|
used by the customer during that hourly period, the energy |
provider shall apply a credit for the net kilowatt-hours |
produced in such period. The credit shall consist of an |
energy credit and a delivery service credit. The energy
|
credit shall be valued at the same price per kilowatt-hour |
as the electric service provider
would charge for |
kilowatt-hour energy sales during that same hourly period. |
The delivery credit shall be equal to the net |
kilowatt-hours produced in such hourly period times a |
credit that reflects all kilowatt-hour based charges in the |
customer's electric service rate, excluding energy |
charges. |
(e) An electricity provider shall measure and charge or |
credit for the net electricity supplied to eligible customers |
whose electric service has not been declared competitive |
pursuant to Section 16-113 of this Act as of July 1, 2011 and |
whose electric delivery service is provided and measured on a |
kilowatt demand basis and electric supply service is not |
provided based on hourly pricing in the following manner: |
(1) If the amount of electricity used by the customer |
during the billing period exceeds the amount of electricity |
produced by the customer, then the electricity provider |
shall charge the customer for the net electricity supplied |
to and used by the customer as provided in subsection (e-5) |
of this Section. The customer shall remain responsible for |
all taxes, fees, and utility delivery charges that would |
|
otherwise be applicable to the net amount of electricity |
used by the customer. |
(2) If the amount of electricity produced by a customer |
during the billing period exceeds the amount of electricity |
used by the customer during that billing period, then the |
electricity provider supplying that customer shall apply a |
1:1 kilowatt-hour credit that reflects the kilowatt-hour |
based charges in the customer's electric service rate to a |
subsequent bill for service to the customer for the net |
electricity supplied to the electricity provider. The |
electricity provider shall continue to carry over any |
excess kilowatt-hour credits earned and apply those |
credits to subsequent billing periods to offset any |
customer-generator consumption in those billing periods |
until all credits are used or until the end of the |
annualized period. |
(3) At the end of the year or annualized over the |
period that service is supplied by means of net metering, |
or in the event that the retail customer terminates service |
with the electricity provider prior to the end of the year |
or the annualized period, any remaining credits in the |
customer's account shall expire. |
(e-5) An electricity provider shall provide electric |
service to eligible customers who utilize net metering at |
non-discriminatory rates that are identical, with respect to |
rate structure, retail rate components, and any monthly |
|
charges, to the rates that the customer would be charged if not |
a net metering customer. An electricity provider shall not |
charge net metering customers any fee or charge or require |
additional equipment, insurance, or any other requirements not |
specifically authorized by interconnection standards |
authorized by the Commission, unless the fee, charge, or other |
requirement would apply to other similarly situated customers |
who are not net metering customers. The customer will remain |
responsible for all taxes, fees, and utility delivery charges |
that would otherwise be applicable to the net amount of |
electricity used by the customer. Subsections (c) through (e) |
of this Section shall not be construed to prevent an |
arms-length agreement between an electricity provider and an |
eligible customer that sets forth different prices, terms, and |
conditions for the provision of net metering service, |
including, but not limited to, the provision of the appropriate |
metering equipment for non-residential customers.
|
(f) Notwithstanding the requirements of subsections (c) |
through (e-5) of this Section, an electricity provider must |
require dual-channel metering for customers operating eligible |
renewable electrical generating facilities with a nameplate |
rating up to 2,000 kilowatts and to whom the provisions of |
neither subsection (d), (d-5), nor (e) of this Section apply. |
In such cases, electricity charges and credits shall be |
determined as follows:
|
(1) The electricity provider shall assess and the |
|
customer remains responsible for all taxes, fees, and |
utility delivery charges that would otherwise be |
applicable to the gross amount of kilowatt-hours supplied |
to the eligible customer by the electricity provider. |
(2) Each month that service is supplied by means of |
dual-channel metering, the electricity provider shall |
compensate the eligible customer for any excess |
kilowatt-hour credits at the electricity provider's |
avoided cost of electricity supply over the monthly period |
or as otherwise specified by the terms of a power-purchase |
agreement negotiated between the customer and electricity |
provider. |
(3) For all eligible net metering customers taking |
service from an electricity provider under contracts or |
tariffs employing hourly or time of use rates, any monthly |
consumption of electricity shall be calculated according |
to the terms of the contract or tariff to which the same |
customer would be assigned to or be eligible for if the |
customer was not a net metering customer. When those same |
customer-generators are net generators during any discrete |
hourly or time of use period, the net kilowatt-hours |
produced shall be valued at the same price per |
kilowatt-hour as the electric service provider would |
charge for retail kilowatt-hour sales during that same time |
of use period.
|
(g) For purposes of federal and State laws providing |
|
renewable energy credits or greenhouse gas credits, the |
eligible customer shall be treated as owning and having title |
to the renewable energy attributes, renewable energy credits, |
and greenhouse gas emission credits related to any electricity |
produced by the qualified generating unit. The electricity |
provider may not condition participation in a net metering |
program on the signing over of a customer's renewable energy |
credits; provided, however, this subsection (g) shall not be |
construed to prevent an arms-length agreement between an |
electricity provider and an eligible customer that sets forth |
the ownership or title of the credits.
|
(h) Within 120 days after the effective date of this
|
amendatory Act of the 95th General Assembly, the Commission |
shall establish standards for net metering and, if the |
Commission has not already acted on its own initiative, |
standards for the interconnection of eligible renewable |
generating equipment to the utility system. The |
interconnection standards shall address any procedural |
barriers, delays, and administrative costs associated with the |
interconnection of customer-generation while ensuring the |
safety and reliability of the units and the electric utility |
system. The Commission shall consider the Institute of |
Electrical and Electronics Engineers (IEEE) Standard 1547 and |
the issues of (i) reasonable and fair fees and costs, (ii) |
clear timelines for major milestones in the interconnection |
process, (iii) nondiscriminatory terms of agreement, and (iv) |
|
any best practices for interconnection of distributed |
generation.
|
(i) All electricity providers shall begin to offer net |
metering
no later than April 1,
2008.
|
(j) An electricity provider shall provide net metering to |
eligible
customers until the load of its net metering customers |
equals 5% of
the total peak demand supplied by
that electricity |
provider during the
previous year. After such time as the load |
of the electricity provider's net metering customers equals 5% |
of the total peak demand supplied by that electricity provider |
during the previous year, eligible customers that begin taking |
net metering shall only be eligible for netting of energy. |
Electricity providers are authorized to offer net metering |
beyond
the 5% level if they so choose.
|
(k) Each electricity provider shall maintain records and |
report annually to the Commission the total number of net |
metering customers served by the provider, as well as the type, |
capacity, and energy sources of the generating systems used by |
the net metering customers. Nothing in this Section shall limit |
the ability of an electricity provider to request the redaction |
of information deemed by the Commission to be confidential |
business information. Each electricity provider shall notify |
the Commission when the total generating capacity of its net |
metering customers is equal to or in excess of the 5% cap |
specified in subsection (j) of this Section. |
(l) (1) Notwithstanding the definition of "eligible |
|
customer" in item (ii) (i) of subsection (b) of this |
Section, each electricity provider shall consider whether |
to allow meter aggregation for the purposes of net metering |
as set forth in this subsection (l) and for the following |
projects on :
|
(A) (1) properties owned or leased by multiple |
customers that contribute to the operation of an |
eligible renewable electrical generating facility |
through an ownership or leasehold interest of at least |
200 watts in such facility, such as a community-owned |
wind project, a community-owned biomass project, a |
community-owned solar project, or a community methane |
digester processing livestock waste from multiple |
sources , provided that the facility is also located |
within the utility's service territory ; and
|
(B) (2) individual units, apartments, or |
properties located in a single building that are owned |
or leased by multiple customers and collectively |
served by a common eligible renewable electrical |
generating facility, such as an office or apartment |
building , a shopping center or strip mall served by |
photovoltaic panels on the roof ; and .
|
(C) subscriptions to community renewable |
generation projects. |
In addition, the nameplate capacity of the eligible |
renewable electric generating facility that serves the |
|
demand of the properties, units, or apartments identified |
in paragraphs (1) and (2) of this subsection (l) shall not |
exceed 2,000 kilowatts in nameplate capacity in total.
Any |
eligible renewable electrical generating facility or |
community renewable generation project that is powered by |
photovoltaic electric energy and installed after the |
effective date of this amendatory Act of the 99th General |
Assembly must be installed by a qualified person in |
compliance with the requirements of Section 16-128A of the |
Public Utilities Act and any rules or regulations adopted |
thereunder. |
(2) Notwithstanding anything to the contrary, an |
electricity provider shall provide credits for the |
electricity produced by the projects described in |
paragraph (1) of this subsection (l). The electricity |
provider shall provide credits at the subscriber's energy |
supply rate on the subscriber's monthly bill equal to the |
subscriber's share of the production of electricity from |
the project, as determined by paragraph (3) of this |
subsection (l). |
(3) For the purposes of facilitating net metering, the |
owner or operator of the eligible renewable electrical |
generating facility or community renewable generation |
project shall be responsible for determining the amount of |
the credit that each customer or subscriber participating |
in a project under this subsection (l) is to receive in the |
|
following manner: this subsection (l), "meter aggregation" |
means the combination of reading and billing on a pro rata |
basis for the types of eligible customers described in this |
Section.
|
(A) The owner or operator shall, on a monthly |
basis, provide to the electric utility the |
kilowatthours of generation attributable to each of |
the utility's retail customers and subscribers |
participating in projects under this subsection (l) in |
accordance with the customer's or subscriber's share |
of the eligible renewable electric generating |
facility's or community renewable generation project's |
output of power and energy for such month. The owner or |
operator shall electronically transmit such |
calculations and associated documentation to the |
electric utility, in a format or method set forth in |
the applicable tariff, on a monthly basis so that the |
electric utility can reflect the monetary credits on |
customers' and subscribers' electric utility bills. |
The electric utility shall be permitted to revise its |
tariffs to implement the provisions of this amendatory |
Act of the 99th General Assembly. The owner or operator |
shall separately provide the electric utility with the |
documentation detailing the calculations supporting |
the credit in the manner set forth in the applicable |
tariff. |
|
(B) For those participating customers and |
subscribers who receive their energy supply from an |
alternative retail electric supplier, the electric |
utility shall remit to the applicable alternative |
retail electric supplier the information provided |
under subparagraph (A) of this paragraph (3) for such |
customers and subscribers in a manner set forth in such |
alternative retail electric supplier's net metering |
program, or as otherwise agreed between the utility and |
the alternative retail electric supplier. The |
alternative retail electric supplier shall then submit |
to the utility the amount of the charges for power and |
energy to be applied to such customers and subscribers, |
including the amount of the credit associated with net |
metering. |
(C) A participating customer or subscriber may |
provide authorization as required by applicable law |
that directs the electric utility to submit |
information to the owner or operator of the eligible |
renewable electrical generating facility or community |
renewable generation project to which the customer or |
subscriber has an ownership or leasehold interest or a |
subscription. Such information shall be limited to the |
components of the net metering credit calculated under |
this subsection (l), including the bill credit rate, |
total kilowatthours, and total monetary credit value |
|
applied to the customer's or subscriber's bill for the |
monthly billing period. |
(l-5) Within 90 days after the effective date of this |
amendatory Act of the 99th General Assembly, each electric |
utility subject to this Section shall file a tariff to |
implement the provisions of subsection (l) of this Section, |
which shall, consistent with the provisions of subsection (l), |
describe the terms and conditions under which owners or |
operators of qualifying properties, units, or apartments may |
participate in net metering. The Commission shall approve, or |
approve with modification, the tariff within 120 days after the |
effective date of this amendatory Act of the 99th General |
Assembly. |
(m) Nothing in this Section shall affect the right of an |
electricity provider to continue to provide, or the right of a |
retail customer to continue to receive service pursuant to a |
contract for electric service between the electricity provider |
and the retail customer in accordance with the prices, terms, |
and conditions provided for in that contract. Either the |
electricity provider or the customer may require compliance |
with the prices, terms, and conditions of the contract.
|
(n) At such time, if any, that the load of the electricity |
provider's net metering customers equals 5% of the total peak |
demand supplied by that electricity provider during the |
previous year, as specified in subsection (j) of this Section, |
the net metering services described in subsections (d), (d-5), |
|
(e), (e-5), and (f) of this Section shall no longer be offered, |
except as to those retail customers that are receiving net |
metering service under these subsections at the time the net |
metering services under those subsections are no longer |
offered. Those retail customers that begin taking net metering |
service after the date that net metering services are no longer |
offered under such subsections shall be subject to the |
provisions set forth in the following paragraphs (1) through |
(3) of this subsection (n): |
(1) An electricity provider shall charge or credit for |
the net electricity supplied to eligible customers or |
provided by eligible customers whose electric supply |
service is not provided based on hourly pricing in the |
following manner: |
(A) If the amount of electricity used by the |
customer during the billing period exceeds the amount |
of electricity produced by the customer, then the |
electricity provider shall charge the customer for the |
net kilowatt-hour based electricity charges reflected |
in the customer's electric service rate supplied to and |
used by the customer as provided in paragraph (3) of |
this subsection (n). |
(B) If the amount of electricity produced by a |
customer during the billing period exceeds the amount |
of electricity used by the customer during that billing |
period, then the electricity provider supplying that |
|
customer shall apply a 1:1 kilowatt-hour energy credit |
that reflects the kilowatt-hour based energy charges |
in the customer's electric service rate to a subsequent |
bill for service to the customer for the net |
electricity supplied to the electricity provider. The |
electricity provider shall continue to carry over any |
excess kilowatt-hour energy credits earned and apply |
those credits to subsequent billing periods to offset |
any customer-generator consumption in those billing |
periods until all credits are used or until the end of |
the annualized period. |
(C) At the end of the year or annualized over the |
period that service is supplied by means of net |
metering, or in the event that the retail customer |
terminates service with the electricity provider prior |
to the end of the year or the annualized period, any |
remaining credits in the customer's account shall |
expire. |
(2) An electricity provider shall charge or credit for |
the net electricity supplied to eligible customers or |
provided by eligible customers whose electric supply |
service is provided based on hourly pricing in the |
following manner: |
(A) If the amount of electricity used by the |
customer during any hourly period exceeds the amount of |
electricity produced by the customer, then the |
|
electricity provider shall charge the customer for the |
net electricity supplied to and used by the customer as |
provided in paragraph (3) of this subsection (n). |
(B) If the amount of electricity produced by a |
customer during any hourly period exceeds the amount of |
electricity used by the customer during that hourly |
period, the energy provider shall calculate an energy |
credit for the net kilowatt-hours produced in such |
period. The value of the energy credit shall be |
calculated using the same price per kilowatt-hour as |
the electric service provider would charge for |
kilowatt-hour energy sales during that same hourly |
period. |
(3) An electricity provider shall provide electric |
service to eligible customers who utilize net metering at |
non-discriminatory rates that are identical, with respect |
to rate structure, retail rate components, and any monthly |
charges, to the rates that the customer would be charged if |
not a net metering customer. An electricity provider shall |
charge the customer for the net electricity supplied to and |
used by the customer according to the terms of the contract |
or tariff to which the same customer would be assigned or |
be eligible for if the customer was not a net metering |
customer. An electricity provider shall not charge net |
metering customers any fee or charge or require additional |
equipment, insurance, or any other requirements not |
|
specifically authorized by interconnection standards |
authorized by the Commission, unless the fee, charge, or |
other requirement would apply to other similarly situated |
customers who are not net metering customers. The charge or |
credit that the customer receives for net electricity shall |
be at a rate equal to the customer's energy supply rate. |
The customer remains responsible for the gross amount of |
delivery services charges, supply-related charges that are |
kilowatt based, and all taxes and fees related to such |
charges. The customer also remains responsible for all |
taxes and fees that would otherwise be applicable to the |
net amount of electricity used by the customer. Paragraphs |
(1) and (2) of this subsection (n) shall not be construed |
to prevent an arms-length agreement between an electricity |
provider and an eligible customer that sets forth different |
prices, terms, and conditions for the provision of net |
metering service, including, but not limited to, the |
provision of the appropriate metering equipment for |
non-residential customers. Nothing in this paragraph (3) |
shall be interpreted to mandate that a utility that is only |
required to provide delivery services to a given customer |
must also sell electricity to such customer.
|
(Source: P.A. 97-616, eff. 10-26-11; 97-646, eff. 12-30-11; |
97-824, eff. 7-18-12.) |
(220 ILCS 5/16-107.6 new) |
|
Sec. 16-107.6. Distributed generation rebate. |
(a) In this Section: |
"Smart inverter" means a device that converts direct |
current
into alternating current and can autonomously |
contribute to grid support during excursions from normal |
operating voltage and frequency conditions by providing each of |
the following: dynamic reactive and real power support, voltage |
and frequency ride-through, ramp rate controls, communication |
systems with ability to accept external commands, and other |
functions from the electric utility. |
"Subscriber" has the meaning set forth in Section 1-10 of |
the Illinois Power Agency Act. |
"Subscription" has the meaning set forth in Section 1-10 of |
the Illinois Power Agency Act. |
"Threshold date" means the date on which the load of an |
electricity provider's net metering customers equals 5% of the |
total peak demand supplied by that electricity provider during |
the previous year, as specified under subsection (j) of Section |
16-107.5 of this Act. |
(b) An electric utility that serves more than 200,000 |
customers in the State shall file a petition with the |
Commission requesting approval of the utility's tariff to |
provide a rebate to a retail customer who owns or operates |
distributed generation that meets the following criteria: |
(1) has a nameplate generating capacity no greater than |
2,000 kilowatts and is primarily used to offset that |
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customer's electricity load; |
(2) is located on the customer's premises, for the |
customer's own use, and not for commercial use or sales, |
including, but not limited to, wholesale sales of electric |
power and energy; |
(3) is located in the electric utility's service |
territory; and |
(4) is interconnected under rules adopted by the |
Commission by means of the inverter or smart inverter |
required by this Section, as applicable. |
For purposes of this Section, "distributed generation" |
shall satisfy the definition of distributed renewable energy |
generation device set forth in Section 1-10 of the Illinois |
Power Agency Act to the extent such definition is consistent |
with the requirements of this Section. |
In addition, any new photovoltaic distributed generation |
that is installed after the effective date of this amendatory |
Act of the 99th General Assembly must be installed by a |
qualified person, as defined by subsection (i) of Section 1-56 |
of the Illinois Power Agency Act. |
The tariff shall provide that the utility shall be |
permitted to operate and control the smart inverter associated |
with the distributed generation that is the subject of the |
rebate for the purpose of preserving reliability during |
distribution system reliability events and shall address the |
terms and conditions of the operation and the compensation |
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associated with the operation. Nothing in this Section shall |
negate or supersede Institute of Electrical and Electronics |
Engineers interconnection requirements or standards or other |
similar standards or requirements. The tariff shall also |
provide for additional uses of the smart inverter that shall be |
separately compensated and which may include, but are not |
limited to, voltage and VAR support, regulation, and other grid |
services. As part of the proceeding described in subsection (e) |
of this Section, the Commission shall review and determine |
whether smart inverters can provide any additional uses or |
services. If the Commission determines that an additional use |
or service would be beneficial, the Commission shall determine |
the terms and conditions of the operation and how the use or |
service should be separately compensated. |
(c) The proposed tariff authorized by subsection (b) of |
this Section shall include the following participation terms |
and formulae to calculate the value of the rebates to be |
applied under this Section for distributed generation that |
satisfies the criteria set forth in subsection (b) of this |
Section: |
(1) Until the utility files its tariff or tariffs to |
place into effect the rebate values established by the |
Commission under subsection (e) of this Section, |
non-residential customers that are taking service under a |
net metering program offered by an electricity provider |
under the terms of Section 16-107.5 of this Act may apply |
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for a rebate as provided for in this Section. The value of |
the rebate shall be $250 per kilowatt of nameplate |
generating capacity, measured as nominal DC power output, |
of a non-residential customer's distributed generation. |
(2) After the utility's tariff or tariffs setting the |
new rebate values established under subsection (d) of this |
Section take effect, retail customers may, as applicable, |
make the following elections: |
(A) Residential customers that are taking service |
under a net metering program offered by an electricity |
provider under the terms of Section 16-107.5 of this |
Act on the threshold date may elect to either continue |
to take such service under the terms of such program as |
in effect on such threshold date for the useful life of |
the customer's eligible renewable electric generating |
facility as defined in such Section, or file an |
application to receive a rebate under the terms of this |
Section, provided that such application must be |
submitted within 6 months after the effective date of |
the tariff approved under subsection (d) of this |
Section. The value of the rebate shall be the amount |
established by the Commission and reflected in the |
utility's tariff pursuant to subsection (e) of this |
Section. |
(B) Non-residential customers that are taking |
service under a net metering program offered by an |
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electricity provider under the terms of Section |
16-107.5 of this Act on the threshold date may apply |
for a rebate as provided for in this Section. The value |
of the rebate shall be the amount established by the |
Commission and reflected in the utility's tariff |
pursuant to subsection (e) of this Section. |
(3) Upon approval of a rebate application submitted |
under this subsection (c), the retail customer shall no |
longer be entitled to receive any delivery service credits |
for the excess electricity generated by its facility and |
shall be subject to the provisions of subsection (n) of |
Section 16-107.5 of this Act. |
(4) To be eligible for a rebate described in this |
subsection (c), customers who begin taking service after |
the effective date of this amendatory Act of the 99th |
General Assembly under a net metering program offered by an |
electricity provider under the terms of Section 16-107.5 of |
this Act must have a smart inverter associated with the |
customer's distributed generation. |
(d) The Commission shall review the proposed tariff |
submitted under subsections (b) and (c) of this Section and may |
make changes to the tariff that are consistent with this |
Section and with the Commission's authority under Article IX of |
this Act, subject to notice and hearing. Following notice and |
hearing, the Commission shall issue an order approving, or |
approving with modification, such tariff no later than 240 days |
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after the utility files its tariff. |
(e) When the total generating capacity of the electricity |
provider's net metering customers is equal to 3%, the |
Commission shall open an investigation into an annual process |
and formula for calculating the value of rebates for the retail |
customers described in subsections (b) and (f) of this Section |
that submit rebate applications after the threshold date for an |
electric utility that elected to file a tariff pursuant to this |
Section. The investigation shall include diverse sets of |
stakeholders, calculations for valuing distributed energy |
resource benefits to the grid based on best practices, and |
assessments of present and future technological capabilities |
of distributed energy resources. The value of such rebates |
shall reflect the value of the distributed generation to the |
distribution system at the location at which it is |
interconnected, taking into account the geographic, |
time-based, and performance-based benefits, as well as |
technological capabilities and present and future grid needs.
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No later than 10 days after the Commission enters its final |
order under this subsection (e), the utility shall file its |
tariff or tariffs in compliance with the order, and the |
Commission shall approve, or approve with modification, the |
tariff or tariffs within 45 days after the utility's filing. |
For those rebate applications filed after the threshold date |
but before the utility's tariff or tariffs filed pursuant to |
this subsection (e) take effect, the value of the rebate shall |
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remain at the value established in subsection (c) of this |
Section until the tariff is approved. |
(f) Notwithstanding any provision of this Act to the |
contrary, the owner, developer, or subscriber of a generation |
facility that is part of a net metering program provided under |
subsection (l) of Section 16-107.5 shall also be eligible to |
apply for the rebate described in this Section. A subscriber to |
the generation facility may apply for a rebate in the amount of |
the subscriber's subscription only if the owner, developer, or |
previous subscriber to the same panel or panels has not already |
submitted an application, and, regardless of whether the |
subscriber is a residential or non-residential customer, may be |
allowed the amount identified in paragraph (1) of subsection |
(c) or in subsection (e) of this Section applicable to such |
customer on the date that the application is submitted. An |
application for a rebate for a portion of a project described |
in this subsection (f) may be submitted at or after the time |
that a related request for net metering is made. |
(g) No later than 60 days after the utility receives an |
application for a rebate under its tariff approved under |
subsection (d) or (e) of this Section, the utility shall issue |
a rebate to the applicant under the terms of the tariff. In the |
event the application is incomplete or the utility is otherwise |
unable to calculate the payment based on the information |
provided by the owner, the utility shall issue the payment no |
later than 60 days after the application is complete or all |
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requested information is received. |
(h) An electric utility shall recover from its retail |
customers all of the costs of the rebates made under a tariff |
or tariffs placed into effect under this Section, including, |
but not limited to, the value of the rebates and all costs |
incurred by the utility to comply with and implement this |
Section, consistent with the following provisions: |
(1) The utility shall defer the full amount of its |
costs incurred under this Section as a regulatory asset. |
The total costs deferred as a regulatory asset shall be |
amortized over a 15-year period. The unamortized balance |
shall be recognized as of December 31 for a given year. The |
utility shall also earn a return on the total of the |
unamortized balance of the regulatory assets, less any |
deferred taxes related to the unamortized balance, at an |
annual rate equal to the utility's weighted average cost of |
capital that includes, based on a year-end capital |
structure, the utility's actual cost of debt for the |
applicable calendar year and a cost of equity, which shall |
be calculated as the sum of (i) the average for the |
applicable calendar year of the monthly average yields of |
30-year U.S. Treasury bonds published by the Board of |
Governors of the Federal Reserve System in its weekly H.15 |
Statistical Release or successor publication; and (ii) 580 |
basis points, including a revenue conversion factor |
calculated to recover or refund all additional income taxes |
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that may be payable or receivable as a result of that |
return. |
When an electric utility creates a regulatory asset |
under the provisions of this Section, the costs are |
recovered over a period during which customers also receive |
a benefit, which is in the public interest. Accordingly, it |
is the intent of the General Assembly that an electric |
utility that elects to create a regulatory asset under the |
provisions of this Section shall recover all of the |
associated costs, including, but not limited to, its cost |
of capital as set forth in this Section. After the |
Commission has approved the prudence and reasonableness of |
the costs that comprise the regulatory asset, the electric |
utility shall be permitted to recover all such costs, and |
the value and recoverability through rates of the |
associated regulatory asset shall not be limited, altered, |
impaired, or reduced. To enable the financing of the |
incremental capital expenditures, including regulatory |
assets, for electric utilities that serve less than |
3,000,000 retail customers but more than 500,000 retail |
customers in the State, the utility's actual year-end |
capital structure that includes a common equity ratio, |
excluding goodwill, of up to and including 50% of the total |
capital structure shall be deemed reasonable and used to |
set rates. |
(2) The utility, at its election, may recover all of |
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the costs it incurs under this Section as part of a filing |
for a general increase in rates under Article IX of this |
Act, as part of an annual filing to update a |
performance-based formula rate under subsection (d) of |
Section 16-108.5 of this Act, or through an automatic |
adjustment clause tariff, provided that nothing in this |
paragraph (2) permits the double recovery of such costs |
from customers. If the utility elects to recover the costs |
it incurs under this Section through an automatic |
adjustment clause tariff, the utility may file its proposed |
tariff together with the tariff it files under subsection |
(b) of this Section or at a later time. The proposed tariff |
shall provide for an annual reconciliation, less any |
deferred taxes related to the reconciliation, with |
interest at an annual rate of return equal to the utility's |
weighted average cost of capital as calculated under |
paragraph (1) of this subsection (h), including a revenue |
conversion factor calculated to recover or refund all |
additional income taxes that may be payable or receivable |
as a result of that return, of the revenue requirement |
reflected in rates for each calendar year, beginning with |
the calendar year in which the utility files its automatic |
adjustment clause tariff under this subsection (h), with |
what the revenue requirement would have been had the actual |
cost information for the applicable calendar year been |
available at the filing date. The Commission shall review |
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the proposed tariff and may make changes to the tariff that |
are consistent with this Section and with the Commission's |
authority under Article IX of this Act, subject to notice |
and hearing. Following notice and hearing, the Commission |
shall issue an order approving, or approving with |
modification, such tariff no later than 240 days after the |
utility files its tariff. |
(i) No later than 90 days after the Commission enters an |
order, or order on rehearing, whichever is later, approving an |
electric utility's proposed tariff under subsection (d) of this |
Section, the electric utility shall provide notice of the |
availability of rebates under this Section. Subsequent to the |
utility's notice, any entity that offers in the State, for sale |
or lease, distributed generation and estimates the dollar |
saving attributable to such distributed generation shall |
provide estimates based on both delivery service credits and |
the rebates available under this Section.
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(220 ILCS 5/16-108)
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Sec. 16-108. Recovery of costs associated with the
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provision of delivery and other services. |
(a) An electric utility shall file a delivery services
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tariff with the Commission at least 210 days prior to the date
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that it is required to begin offering such services pursuant
to |
this Act. An electric utility shall provide the components
of |
delivery services that are subject to the jurisdiction of
the |
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Federal Energy Regulatory Commission at the same prices,
terms |
and conditions set forth in its applicable tariff as
approved |
or allowed into effect by that Commission. The
Commission shall |
otherwise have the authority pursuant to Article IX to review,
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approve, and modify the prices, terms and conditions of those
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components of delivery services not subject to the
jurisdiction |
of the Federal Energy Regulatory Commission,
including the |
authority to determine the extent to which such
delivery |
services should be offered on an unbundled basis. In making any |
such
determination the Commission shall consider, at a minimum, |
the effect of
additional unbundling on (i) the objective of |
just and reasonable rates, (ii)
electric utility employees, and |
(iii) the development of competitive markets
for electric |
energy services in Illinois.
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(b) The Commission shall enter an order approving, or
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approving as modified, the delivery services tariff no later
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than 30 days prior to the date on which the electric utility
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must commence offering such services. The Commission may
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subsequently modify such tariff pursuant to this Act.
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(c) The electric utility's
tariffs shall define the classes |
of its customers for purposes
of delivery services charges. |
Delivery services shall be priced and made
available to all |
retail customers electing delivery services in each such class
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on a nondiscriminatory basis regardless of whether the retail |
customer chooses
the electric utility, an affiliate of the |
electric utility, or another entity
as its supplier of electric |
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power and energy. Charges for delivery services
shall be cost |
based,
and shall allow the electric utility to recover the |
costs of
providing delivery services through its charges to its
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delivery service customers that use the facilities and
services |
associated with such costs.
Such costs shall include the
costs |
of owning, operating and maintaining transmission and
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distribution facilities. The Commission shall also be
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authorized to consider whether, and if so to what extent, the
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following costs are appropriately included in the electric
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utility's delivery services rates: (i) the costs of that
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portion of generation facilities used for the production and
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absorption of reactive power in order that retail customers
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located in the electric utility's service area can receive
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electric power and energy from suppliers other than the
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electric utility, and (ii) the costs associated with the use
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and redispatch of generation facilities to mitigate
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constraints on the transmission or distribution system in
order |
that retail customers located in the electric utility's
service |
area can receive electric power and energy from
suppliers other |
than the electric utility. Nothing in this
subsection shall be |
construed as directing the Commission to
allocate any of the |
costs described in (i) or (ii) that are
found to be |
appropriately included in the electric utility's
delivery |
services rates to any particular customer group or
geographic |
area in setting delivery services rates.
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(d) The Commission shall establish charges, terms and
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conditions for delivery services that are just and reasonable
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and shall take into account customer impacts when establishing
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such charges. In establishing charges, terms and conditions
for |
delivery services, the Commission shall take into account
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voltage level differences. A retail customer shall have the
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option to request to purchase electric service at any delivery
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service voltage reasonably and technically feasible from the
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electric facilities serving that customer's premises provided
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that there are no significant adverse impacts upon system
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reliability or system efficiency. A retail customer shall
also |
have the option to request to purchase electric service
at any |
point of delivery that is reasonably and technically
feasible |
provided that there are no significant adverse
impacts on |
system reliability or efficiency. Such requests
shall not be |
unreasonably denied.
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(e) Electric utilities shall recover the costs of
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installing, operating or maintaining facilities for the
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particular benefit of one or more delivery services customers,
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including without limitation any costs incurred in complying
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with a customer's request to be served at a different voltage
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level, directly from the retail customer or customers for
whose |
benefit the costs were incurred, to the extent such
costs are |
not recovered through the charges referred to in
subsections |
(c) and (d) of this Section.
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(f) An electric utility shall be entitled but not
required |
to implement transition charges in conjunction with
the |
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offering of delivery services pursuant to Section 16-104.
If an |
electric utility implements transition charges, it shall |
implement such
charges for all delivery services customers and |
for all customers described in
subsection (h), but shall not |
implement transition charges for power and
energy that a retail |
customer takes from cogeneration or self-generation
facilities |
located on that retail customer's premises, if such facilities |
meet
the following criteria:
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(i) the cogeneration or self-generation facilities |
serve a single retail
customer and are located on that |
retail customer's premises (for purposes of
this |
subparagraph and subparagraph (ii), an industrial or |
manufacturing retail
customer and a third party contractor |
that is served by such industrial or
manufacturing customer |
through such retail customer's own electrical
distribution |
facilities under the circumstances described in subsection |
(vi) of
the definition of "alternative retail electric |
supplier" set forth in Section
16-102, shall be considered |
a single retail customer);
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(ii) the cogeneration or self-generation facilities |
either (A) are sized
pursuant to generally accepted |
engineering standards for the retail customer's
electrical |
load at that premises (taking into account standby or other
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reliability considerations related to that retail |
customer's operations at that
site) or (B) if the facility |
is a cogeneration facility located on the retail
customer's |
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premises, the retail customer is the thermal host for that |
facility
and the facility has been designed to meet that |
retail customer's thermal
energy requirements resulting in |
electrical output beyond that retail
customer's electrical |
demand at that premises, comply with the operating and
|
efficiency standards applicable to "qualifying facilities" |
specified in title
18 Code of Federal Regulations Section |
292.205 as in effect on the effective
date of this |
amendatory Act of 1999;
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(iii) the retail customer on whose premises the |
facilities are located
either has an exclusive right to |
receive, and corresponding obligation to pay
for, all of |
the electrical capacity of the facility, or in the case of |
a
cogeneration facility that has been designed to meet the |
retail customer's
thermal energy requirements at that |
premises, an identified amount of the
electrical capacity |
of the facility, over a minimum 5-year period; and
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(iv) if the cogeneration facility is sized for the
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retail customer's thermal load at that premises but exceeds |
the electrical
load, any sales of excess power or energy |
are made only at wholesale, are
subject to the jurisdiction |
of the Federal Energy Regulatory Commission, and
are not |
for the purpose of circumventing the provisions of this |
subsection (f).
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If a generation facility located at a retail customer's |
premises does not meet
the above criteria, an electric utility |
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implementing
transition charges shall implement a transition |
charge until December 31, 2006
for any power and energy taken |
by such retail customer from such facility as if
such power and |
energy had been delivered by the electric utility. Provided,
|
however, that an industrial retail customer that is taking |
power from a
generation facility that does not meet the above |
criteria but that is located
on such customer's premises will |
not be subject to a transition charge for the
power and energy |
taken by such retail customer from such generation facility if
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the facility does not serve any other retail customer and |
either was installed
on behalf of the customer and for its own |
use prior to January 1, 1997, or is
both predominantly fueled |
by byproducts of such customer's manufacturing
process at such |
premises and sells or offers an average of 300 megawatts or
|
more of electricity produced from such generation facility into |
the wholesale
market.
Such charges
shall be calculated as |
provided in Section
16-102, and shall be collected
on each |
kilowatt-hour delivered under a
delivery services tariff to a |
retail customer from the date
the customer first takes delivery |
services until December 31,
2006 except as provided in |
subsection (h) of this Section.
Provided, however, that an |
electric utility, other than an electric utility
providing |
service to at least 1,000,000 customers in this State on |
January 1,
1999,
shall be entitled to petition for
entry of an |
order by the Commission authorizing the electric utility to
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implement transition charges for an additional period ending no |
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later than
December 31, 2008. The electric utility shall file |
its petition with
supporting evidence no earlier than 16 |
months, and no later than 12 months,
prior to December 31, |
2006. The Commission shall hold a hearing on the
electric |
utility's petition and shall enter its order no later than 8 |
months
after the petition is filed. The Commission shall |
determine whether and to
what extent the electric utility shall |
be authorized to implement transition
charges for an additional |
period. The Commission may authorize the electric
utility to |
implement transition charges for some or all of the additional
|
period, and shall determine the mitigation factors to be used |
in implementing
such transition charges; provided, that the |
Commission shall not authorize
mitigation factors less than |
110% of those in effect during the 12 months ended
December 31, |
2006. In making its determination, the Commission shall |
consider
the following factors: the necessity to implement |
transition charges for an
additional period in order to |
maintain the financial integrity of the electric
utility; the |
prudence of the electric utility's actions in reducing its |
costs
since the effective date of this amendatory Act of 1997; |
the ability of the
electric utility to provide safe, adequate |
and reliable service to retail
customers in its service area; |
and the impact on competition of allowing the
electric utility |
to implement transition charges for the additional period.
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(g) The electric utility shall file tariffs that
establish |
the transition charges to be paid by each class of
customers to |
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the electric utility in conjunction with the
provision of |
delivery services. The electric utility's tariffs
shall define |
the classes of its customers for purposes of
calculating |
transition charges. The electric utility's tariffs
shall |
provide for the calculation of transition charges on a
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customer-specific basis for any retail customer whose average
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monthly maximum electrical demand on the electric utility's
|
system during the 6 months with the customer's highest monthly
|
maximum electrical demands equals or exceeds 3.0 megawatts for
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electric utilities having more than 1,000,000 customers, and
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for other electric utilities for any customer that has an
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average monthly maximum electrical demand on the electric
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utility's system of one megawatt or more, and (A) for which
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there exists data on the customer's usage during the 3 years
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preceding the date that the customer became eligible to take
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delivery services, or (B) for which there does not exist data
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on the customer's usage during the 3 years preceding the date
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that the customer became eligible to take delivery services,
if |
in the electric utility's reasonable judgment there exists
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comparable usage information or a sufficient basis to develop
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such information, and further provided that the electric
|
utility can require customers for which an individual
|
calculation is made to sign contracts that set forth the
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transition charges to be paid by the customer to the electric
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utility pursuant to the tariff.
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(h) An electric utility shall also be entitled to file
|
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tariffs that allow it to collect transition charges from
retail |
customers in the electric utility's service area that
do not |
take delivery services but that take electric power or
energy |
from an alternative retail electric supplier or from an
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electric utility other than the electric utility in whose
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service area the customer is located. Such charges shall be
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calculated, in accordance with the definition of transition
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charges in Section 16-102, for the period of time that the
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customer would be obligated to pay transition charges if it
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were taking delivery services, except that no deduction for
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delivery services revenues shall be made in such calculation,
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and usage data from the customer's class shall be used where
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historical usage data is not available for the individual
|
customer. The customer shall be obligated to pay such charges
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on a lump sum basis on or before the date on which the
customer |
commences to take service from the alternative retail
electric |
supplier or other electric utility, provided, that
the electric |
utility in whose service area the customer is
located shall |
offer the customer the option of signing a
contract pursuant to |
which the customer pays such charges
ratably over the period in |
which the charges would otherwise
have applied.
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(i) An electric utility shall be entitled to add to the
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bills of delivery services customers charges pursuant to
|
Sections 9-221, 9-222 (except as provided in Section 9-222.1), |
and Section
16-114 of this Act, Section 5-5 of the Electricity |
Infrastructure Maintenance
Fee Law, Section 6-5 of the |
|
Renewable Energy, Energy Efficiency, and Coal
Resources |
Development Law of 1997, and Section 13 of the Energy |
Assistance Act.
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(j) If a retail customer that obtains electric power and
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energy from cogeneration or self-generation facilities
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installed for its own use on or before January 1, 1997,
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subsequently takes service from an alternative retail electric
|
supplier or an electric utility other than the electric
utility |
in whose service area the customer is located for any
portion |
of the customer's electric power and energy
requirements |
formerly obtained from those facilities (including that amount
|
purchased from the utility in lieu of such generation and not |
as standby power
purchases, under a cogeneration displacement |
tariff in effect as of the
effective date of this amendatory |
Act of 1997), the
transition charges otherwise applicable |
pursuant to subsections (f), (g), or
(h) of this Section shall |
not be applicable
in any year to that portion of the customer's |
electric power
and energy requirements formerly obtained from |
those
facilities, provided, that for purposes of this |
subsection
(j), such portion shall not exceed the average |
number of
kilowatt-hours per year obtained from the |
cogeneration or
self-generation facilities during the 3 years |
prior to the
date on which the customer became eligible for |
delivery
services, except as provided in subsection (f) of |
Section
16-110.
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(k) The electric utility shall be entitled to recover |
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through tariffed charges all of the costs associated with the |
purchase of zero emission credits from zero emission facilities |
to meet the requirements of subsection (d-5) of Section 1-75 of |
the Illinois Power Agency Act. Such costs shall include the |
costs of procuring the zero emission credits, as well as the |
reasonable costs that the utility incurs as part of the |
procurement processes and to implement and comply with plans |
and processes approved by the Commission under such subsection |
(d-5). The costs shall be allocated across all retail customers |
through a single, uniform cents per kilowatt-hour charge |
applicable to all retail customers, which shall appear as a |
separate line item on each customer's bill. Beginning June 1, |
2017, the electric utility shall be entitled to recover through |
tariffed charges all of the costs associated with the purchase |
of renewable energy resources to meet the renewable energy |
resource standards of subsection (c) of Section 1-75 of the |
Illinois Power Agency Act, under procurement plans as approved |
in accordance with that Section and Section 16-111.5 of this |
Act. Such costs shall include the costs of procuring the |
renewable energy resources, as well as the reasonable costs |
that the utility incurs as part of the procurement processes |
and to implement and comply with plans and processes approved |
by the Commission under such Sections. The costs associated |
with the purchase of renewable energy resources shall be |
allocated across all retail customers in proportion to the |
amount of renewable energy resources the utility procures for |