Annual Report%3A The Costs and Benefits of Renewable Resource Procurement in Illinois Under the Illinois Power Agency and Illinois Public Utilities Acts

              2012
Submitted to the Illinois General
Assembly and the Illinois Commerce
Commission Pursuant to PA 97-0658
Illinois Power Agency
3/30/2012
Annual Report: The Costs and Benefits of Renewable
Resource Procurement in Illinois Under the
Illinois Power Agency and Illinois Public Utilities Acts
www.illinois.gov/IPA
March 30, 2012
The Honorable Members of the Illinois General Assembly
State House
Springfield, Illinois
The Honorable Chairman and Commissioners of the Illinois Commerce Commission
527 E. Capitol Avenue
Springfield, Illinois
Dear Honorable Members of the Illinois General Assembly and the Illinois Commerce
Commission:
Pursuant to 20 ILCS 3855/1-75(c)(5) and 220 ILCS 5/16-115D(d)(4) as amended by
Public Act 97-0658, the Illinois Power Agency submits the attached Annual Report on
The Costs and Benefits of Renewable Resource Procurement in Illinois Under the
Illinois Power Agency and Illinois Public Utilities Acts.
The data and analyses contained herein provide important insight into the impacts of
Illinois’ Renewable Portfolio Standards on electricity consumers and on the State
overall, as well as policy guidance on future renewable resource procurement activity.
Sincerely,
Arlene A. Juracek
Arlene A. Juracek
Acting Director
IPA
ILLINOIS POWER AGENCY Pat Quinn, Governor
Arlene A. Juracek, Acting Director
160 North LaSalle Street, Suite N-506, Chicago, Illinois 60601
Table of Contents
I. EXECUTIVE SUMMARY AND KEY FINDINGS ...................................................................................... 1
Key Findings .............................................................................................................................. 3
II. INTRODUCTION AND BACKGROUND .................................................................................................... 5
A. History of the Illinois Power Agency ................................................................................. 5
B. History of the Renewable Portfolio Standard................................................................... 6
1. Electric Utilities’ Compliance with the RPS ............................................................................ 6
2. Alternative Retail Electric Suppliers’ Compliance with the RPS ................................ 10
C. Report Methodology ......................................................................................................... 12
III. RENEWABLE RESOURCE PROCUREMENT IMPACT .................................................................... 13
A. Cost Comparison ............................................................................................................... 13
1. ComEd ................................................................................................................................................. 15
2. Ameren ............................................................................................................................................... 16
B. Cost/Benefit Comparison ................................................................................................. 16
1. Economic Benefits .......................................................................................................................... 17
2. Environmental Benefits ................................................................................................................ 22
C. Rate Impacts on Eligible Retail Customers ..................................................................... 23
1. ComEd ................................................................................................................................................. 24
2. Ameren ............................................................................................................................................... 25
D. Rate Impacts on Customers of Alternative Retail Electric Suppliers ........................... 26
IV. ALTERNATIVE COMPLIANCE PAYMENT MECHANISM FUND REPORT .............................. 28
A. Total Amount of ACPs Received ...................................................................................... 29
B. Amount of ACPs used to purchase RECs ......................................................................... 29
C. Balance in RERF attributable to ACPs ............................................................................. 30
D. Future Use of the ACP‐Funded RERF .............................................................................. 32
V. APPENDICES ................................................................................................................................................. 33
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ANNUAL REPORT ON THE COSTS AND BENEFITS OF RENEWABLE
RESOURCE PROCUREMENT IN ILLINOIS UNDER THE ILLINOIS
POWER AGENCY AND ILLINOIS PUBLIC UTILITIES ACTS
MARCH 30, 2012
I. Executive Summary and Key Findings
Public Act 97-0658, effective January 13, 2012, establishes new reporting
requirements for the Illinois Power Agency (IPA), shown below:
Utility Renewable Resource Costs and Benefits
Beginning April 1, 2012, and each year thereafter, the Agency shall prepare a
public report for the General Assembly and Illinois Commerce Commission
that shall include, but not necessarily be limited to:
(A) a comparison of the costs associated with the Agency's procurement
of renewable energy resources to (1) the Agency's costs associated with
electricity generated by other types of generation facilities and (2) the
benefits associated with the Agency's procurement of renewable energy
resources; and
(B) an analysis of the rate impacts associated with the Illinois Power
Agency's procurement of renewable resources, including, but not
limited to, any long-term contracts, on the eligible retail customers of
electric utilities.
The analysis shall include the Agency's estimate of the total dollar impact that
the Agency's procurement of renewable resources has had on the annual
electricity bills of the customer classes that comprise each eligible retail
customer class taking service from an electric utility. The Agency's report shall
also analyze how the operation of the alternative compliance payment
mechanism, any long-term contracts, or other aspects of the applicable
renewable portfolio standards impacts the rates of customers of alternative
retail electric suppliers.
Alternate Retail Electric Supplier (ARES) Renewable Resource Costs and
Benefits
Beginning April 1, 2012 and by April 1 of each year thereafter, the
Illinois Power Agency shall submit an annual report to the General Assembly,
the Commission, and alternative retail electric suppliers that shall include,
but not be limited to:
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(A) the total amount of alternative compliance payments (ACP)
received in aggregate from alternative retail electric suppliers by
planning year for all previous planning years in which the alternative
compliance payment was in effect;
(B) the amount of those payments utilized to purchased renewable
energy credits itemized by the date of each procurement in which the
payments were utilized; and
(C) the unused and remaining balance in the Agency Renewable
Energy Resources Fund attributable to those payments.
This report, dated March 30, 2012, is submitted in accordance with this Act. Its
analysis includes the costs and benefits associated with the following renewable resource
purchases facilitated by the IPA under procurements either mandated by the legislature or
conducted in accordance with Illinois Commerce Commission (ICC) reviewed and approved
IPA procurement plans, described below:
Ameren Illinois Company (Ameren) Procurements
05/18/09 Renewable Energy Credit (REC) Procurement
05/18/10 REC Procurement
12/10/10 20-Year Bundled REC and Energy Procurement
05/18/11 REC Procurement
02/16/12 Rate Stability REC Procurement
Commonwealth Edison Company (ComEd) Procurements
05/11/09 REC Procurement
05/18/10 REC Procurement
12/10/10 20-Year Bundled REC and Energy Procurement
05/18/11 REC Procurement
02/16/12 Rate Stability REC Procurement
Deliveries under some of these procurement events are for future delivery periods
(i.e. beginning June 1, 2012 and later). For these, there is discussion of the costs. However,
only those procurements that have resulted in delivery under historic periods are analyzed
in terms of specific rate impacts. This is because future rates are not known until all of the
laddered underlying energy purchases are made for those future delivery periods and
factored into future utility supply charges.
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Key Findings
 In the ComEd territory, the cost of purchasing renewable energy resources ranged
from a low of 0.095 cents per kilowatt-hour to a high of 1.927 cents per kilowatt-hour.
The current price trend is downward and the purchases represent a low of
0.05% to a high of 0.81% of the total rates paid for electricity. In the Ameren
territory, the cost of purchasing renewable energy resources ranged from a low of
0.092 cents per kilowatt-hour to a high of 1.586 cents per kilowatt-hour. The current
price trend is downward and the purchases represent a low of 0.05% to a high of
0.83% of the total rates paid for electricity.
 The Illinois Power Agency has been presented with evidence that the Illinois
Renewable Portfolio Standards (RPS) appear to have enabled significant job creation
and economic development opportunities as well as environmental benefits. Care
must be taken, however, to not optimistically extrapolate these results without limit,
as factors such as market prices for energy, transmission constraints, and
uncertainty in the load serving responsibility will affect the cost-effectiveness of
near term future additions to the renewable resource generation stock in Illinois. In
particular, care must be taken to avoid the creation of new stranded costs through
long-term contracts until such time as the effects of retail utility load shifts due to
factors such as municipal aggregation can be assessed.
 Renewable resources, in particular wind, have played a dramatic role in reducing
electric energy prices in Illinois and the entire Eastern Interconnection, as measured
by the impact on Locational Marginal Prices (LMPs). Modeling work commissioned
by the IPA and corroborated by similar findings in Massachusetts suggests that for
2011, the integration of renewable resources into the power grid has lowered Illinois’
average LMPs by $1.30 per mega-watt hour (MWh), from $36.40 to $35.10 per MWh.
The aggregate result is a savings of $176.85 million in total load payment for
generation in Illinois. While this does not directly translate to dollar for dollar
savings in consumer bills for the same time period, due to the fact that utility
consumers are served via a portfolio of resources of different vintage, it points out
the magnitude of the benefits accruing to all consumers in lowered underlying
electric energy cost drivers. Over time, the effect of lower LMPs due to growing
renewable capacity will be reflected in procurement outcomes.
 The ACP mechanism is a useful construct with which to effect compliance with RPS
standards in a way that is competitively neutral because it allows an opportunity for
the additional costs of renewable resources to be the same, on an average cents per
kilowatt-hour (kWh) basis, regardless of whether a customer takes electricity supply
from a utility or an ARES. The IPA intends to include an analysis and proposal for
the use of the ACP-funded IPA Renewable Energy Resources Fund (RERF) in its
2013 Procurement Plan, to be filed in the fall of 2012. Under the Energy
Infrastructure Modernization Act (EIMA), the IPA must include specific amounts of
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distributed generation in RERF purchases.1 In particular, conducting parallel utility
and ARES distributed generation procurements holds promise, as this is an, as yet,
unfulfilled mandate. It should be noted that the minimum required term length for
distributed generation contracts is 5 years. Unless the General Assembly can
prevent “borrowing” from the RERF, which serves to deplete the dollars available for
their legislatively stated purpose, any long-term contractual arrangements based on
the flow of funds from the ACP mechanism is a risky proposition.
 An alternative use of the ARES-funded RERF, to be examined in the 2013
Procurement Plan, may be to offset the migration risks of municipal aggregation to
utility REC contract obligations. That is, as load shifts to ARES from utilities, it is
appropriate for ARES-provided funding to assist with covering contractual purchase
obligations for both existing and future utility REC contracts.
 New legislation currently before the General Assembly, SB 678, as amended,
proposes to do away with the ACP mechanism, instead requiring the IPA to
facilitate base RPS compliance for all retail electric customers regardless of supplier.
While this proposal removes volume risk, it raises issues of monopsony and
inefficient markets which should be further examined before adoption. Furthermore,
until legislative certainty is achieved around this proposal, it is not advisable to use
existing RERF funds to underwrite any long-term contractual commitments for
renewable resources.
1 Public Act 97-0616, amending 20 ILCS 3855/1-10, 20 ILCS 3855/1-56.
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II. Introduction and Background
A. History of the Illinois Power Agency
The IPA was established in 2007 by Public Act 95-0481 (IPA Act), to improve the
process of procuring electricity for Illinois residential and small commercial customers of
the state’s largest electric utilities, the Ameren Illinois Company (Ameren) and
Commonwealth Edison Company (ComEd).2 The IPA’s goals and objectives are to
accomplish each of the following:
 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 residential and
small commercial customers of Ameren and ComEd. The procurement plan is
updated on an annual basis and includes renewable energy resources sufficient to
achieve the renewable portfolio standards.
 Conduct competitive procurement processes to procure the supply resources
identified in the procurement plan.
 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.
 Supply electricity from any Agency facilities at cost to one or more of the following:
municipal electric systems, governmental aggregators, or rural electric cooperatives
in Illinois.
The IPA has also been authorized to implement other legislative initiatives, such as
developing sourcing agreements for clean coal facilities,3 substitute natural gas plans,4 and
feedstock procurement for these facilities if developed.5
The Agency is an independent agency under the jurisdiction of the Executive Ethics
Commission, and its operations are self-funded through bidder and supplier fees, as well as
earnings from the Illinois Power Agency Trust Fund, established in accordance with the
State Finance Act.6
Per the IPA Act and the Illinois Public Utilities Act (PUA), beginning June 1, 2008,
ComEd and Ameren are required to procure power for residential and small commercial
2 20 ILCS 3855/1-5. MidAmerican may choose to also participate in this process, but does not at
present.
3 20 ILCS 3855/1-75(d).
4 220 ILCS 5/9-220(h).
5 20 ILCS 3855/1-78.
6 30 ILCS 105/6z-75.
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customers according to a plan developed by the IPA and approved by the Illinois Commerce
Commission (Commission or ICC).7 Notably, the procurement plan only addresses the
electricity needs for residential and small commercial customers for ComEd and Ameren,
referred to as “Eligible Retail Customers.”8 Each year, by July 15th, ComEd and Ameren
will provide load forecasts to the IPA covering the 5-year procurement planning period
along with supporting data and assumptions for provided load scenarios. For Eligible Retail
Customers, the IPA is required to prepare and receive comments on a draft Procurement
Plan by August 15th of each year, and file its proposed Procurement Plan with the
Commission for its consideration and approval.9 The Procurement Plan shall identify the
portfolio of demand-response and power and energy products to be procured.
The annual IPA procurement process shall include each of the following components:
 Solicitation, pre-qualification, and registration of bidders;
 Standard contract forms and credit terms and instruments;
 Establishment of a market-based price benchmark;
 Request for proposals competitive procurement process; and
 A plan for implementing contingencies in the event of supplier default or failure of
the procurement process to fully meet the expected load requirement due to
insufficient supplier participation, Commission rejection of results, or any other
cause.10
B. History of the Renewable Portfolio Standard
1. Electric Utilities’ Compliance with the RPS
Since 2009, the IPA’s annual electricity procurement plans have included purchase
of renewable energy resources sufficient to meet the RPS applicable to the eligible load of
ComEd and Ameren. The RPS calls for the procurement of the following quantity of
renewable energy resources as a mandatory part of each utility’s annual supply:
 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;
7 20 ILCS 3855/1-20(a) and 220 ILCS 5/16-111.5(d).
8 220 ILCS 5/16-111.5; see also page 10 of this Report.
9 220 ILCS 5/16-111.5(d).
10 20 ILCS 3855/1-20(a).
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 At least 7% by June 1, 2012;
 At least 8% by June 1, 2013;
 At least 9% by June 1, 2014; and
 At least 10% by June 1, 2015.
This obligation increases by at least 1.5% each year thereafter to at least 25% by
June 1, 2025.11 The obligation of each electric utility is determined by applying the required
percentage to the amount of eligible retail sales from the immediately prior planning year.
Eligible “renewable energy resources” include energy and its associated renewable
energy credits or stand-alone 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, hydropower that does not involve new
construction or significant expansion of hydropower dams, and other alternative sources of
environmentally preferable energy.12 The RPS is also subject to specific directives on the
type and location of eligible resources:
 Resource Limitations: To the extent that it is 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 solar
photovoltaics on the following schedule:
o 0.5% by June 1, 2012,
o 1.5% by June 1, 2013;
o 3% by June 1, 2014; and
o 6% by June 1, 2015 and thereafter.
11 20 ILCS 3855/1-75(c).
12 Landfill gas produced in Illinois is also considered a renewable energy resource, but the law
specifically excludes 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. 220 ILCS 3855/1-10.
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Figure 1: Illinois RPS % Requirements and Generation Preferences
 Geographic Limitations: Until June 1, 2011, in-state resources were granted
preference unless there were not enough cost-effective resources within Illinois, in
which case renewable energy resources from adjoining states (Indiana, Missouri,
Kentucky, Wisconsin, Michigan, and Iowa) could be considered.13 If sufficient cost-effective
resources were not available, resources could be purchased from elsewhere.
Since June 1, 2011 resources from either Illinois or adjoining state resources receive
equal preference before procurement from other states can be considered.
 Cost- Effectiveness: All renewable energy resources procured through the IPA must
be “cost effective,” which means that the costs of procuring those resources do not
cause the statutory spending cap to be exceeded and that the costs do not exceed
benchmarks based on market prices for renewable energy resources in the region.14
The statutory spending cap operates as a maximum allowable percentage impact on
the amounts paid by eligible retail customers. Starting out at a small level,
beginning in 2012, the IPA’s procurement of eligible resources under the RPS cannot
cause the amounts paid by these customers to increase by more than the greater of
2.015% of the amount paid per kilowatt-hour during the year ended May 31, 2007
13 220 ILCS 3855/1-75(c)(3).
14 20 ILCS 3855/1-75(c). The Commission reviewed the statutory spending cap in June 2011 and
found that the cap “does not unduly constrain the procurement of cost-effective renewable energy
resources and that such a limitation remains appropriate.” See Ill. Commerce Comm’n, Report to the
Ill. General Assembly Concerning Spending Limits on Renewable Energy Resource Procurement at ii
(June 2011). The Commission’s Report also found that the IPA Act’s cap on price increases “will not
unduly constrain future purchases of renewable energy.” Id.
0
5
10
15
20
25
June
2008
June
2009
June
2010
June
2011
June
2012
June
2013
June
2014
June
2015
June
2016
June
2017
June
2018
June
2019
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2025
RPS
Wind
Photovoltaics
Distributed Generation
Page 9 of 33
(including supply, transmission, distribution, surcharges, and taxes), or the
incremental amount per kilowatt-hour paid for these resources in 2011. These limits
are used, in conjunction with updated load forecasts from the utilities, to calculate a
renewable resource budget in total dollars for each renewable resource procurement
conducted by the IPA. While the cost-effectiveness spending caps have not limited
purchases for the 2009-2011 period, two factors may cause limits on available
spending budgets to constrain future purchases. These include dramatic reductions
in utility load-serving obligations due to municipal aggregation and the inclusion of
solar photovoltaic (PV) RECs, which are significantly more expensive than wind. It
is possible that Alternate Compliance Payments made by alternate suppliers may be
used to assist in mitigating load migration risk. This will be examined in the 2013
Procurement Plan. The impacts of PV REC purchases on the cost-effectiveness
calculations will also be closely monitored.
 Distributed Generation Requirement: A Distributed Generation component is
mandated for deliveries beginning June 1, 2013, meaning that of the renewable
energy resources procured pursuant to the RPS, 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.15 The law
defines distributed generation as a device that is powered by a renewable resource,
connected at the distribution system level of an electric utility, ARES, municipal
utility or rural electric cooperative, located on the customer side of the customer’s
meter, used primarily to offset that customer’s electricity load and limited in
nameplate capacity to no more than 2,000 kilowatts. The new standard also requires
that, 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 PV. 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 RECs. The
IPA has begun a workshop process to assist with defining the Distributed
Generation procurement to be included in its proposed 2013 Procurement Plan.
Eligible Retail Customers, that is, those customers for whom the IPA directs
procurement of energy supply, are defined as retail customers that purchase power and
energy from the utility under fixed price bundled service tariffs excluding:
 Customer classes whose service is declared or deemed competitive under Section 113
of the PUA;
 Self-generating customers;
15 20 ILCS 3855/1-56.
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 Hourly priced customers (however, an amount equal to the ACP, described below, is
added to the procurement budget to allow RPS compliance for utility supply to
hourly priced customers); and
 Customers otherwise ineligible for bundled service.16
For ComEd, eligible retail customer classes include17:
SF Single Family Non-Space Heating
MF Multi Family Non-Space Heating
SFSH Single Family Space Heating
MFSH Multi Family Space Heating
WH Watt Hour, Non Residential, Less Than 2000 kWh per Billing Period
Small Small Load, Non Residential, Less than 100 kW Peak Demand
DD Dusk to Dawn Lighting Delivery
GL General Lighting Delivery
For Ameren, eligible retail customer classes include18:
DS-1 Residential
DS-2 Non Residential, Less than 150 kW Peak Demand
DS-3a Non Residential, Between 150-400 kW Peak Demand
DS-5 Lighting
QF Qualifying Facilities19
2. Alternative Retail Electric Suppliers’ Compliance with the RPS
In 1997, Public Act 90-561, the “Electric Service Customer Choice and Rate Relief
Act,” restructured electricity markets and phased in a competitive retail electric supply
market in Illinois.20 All customers of ComEd and Ameren were given the option to purchase
electricity from an ARES or their local utility. In 2007, the PUA was amended to direct
ComEd and Ameren to file tariffs establishing utility consolidated billing (UCB) and
16 220 ILCS 5/16-111.5.
17 Ill. Commerce Comm’n, Docket 10-0563, Final Order at 19 (Dec. 21, 2010).
18 Id.
19 Ameren must procure energy from any qualifying facility meeting the requirements of Rider QF –
Qualifying Facilities. Such qualifying purchases are considered to be preexisting purchase and shall
be recovered in Accrued Expenses for the Purchase Electricity Adjustment. Ill. Commerce Comm’n,
Docket 10-0563, Final Order at 19 (Dec. 21, 2010).
20 220 ILCS 5/16-101(a).
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purchase of receivables (POR) service.21 The General Assembly passed these measures to
“promote fair and open competition in the provision of electric power and energy and to
prevent anticompetitive practices in the provision of electric power and energy,” which they
found in the best interest of Illinois energy consumers.22
Ameren filed UCB/POR tariffs in September of 2008 and the Commission submitted
a final order in August of 2009.23 ComEd filed its corresponding tariffs in January of 2010,
and the Commission submitted a final order in December of 2010.24 Although the
residential and small business electricity market had technically been open to competition
for a number of years, it was not until the UCB/POR process was established that
residential customers began to contract with ARES in significant numbers. In January of
2011, 1,188 ComEd residential customers received supply service from an ARES; one year
later, that number had grown to 270,727. In Ameren territory, 163 residential customers
received supply service from an ARES in January of 2011, which increased in one year to
46,078.25
The renewable energy obligation for ARES is measured as a percentage of the actual
amount of metered electricity (megawatt-hours) supplied by the ARES in the compliance
year. ARES must meet at least 50% of their renewable energy resource obligations through
the Alternate Compliance Payment (ACP) mechanism.26 The remaining 50% of the
obligation may be met with additional ACP payments, by procuring renewable energy, or by
procuring RECs sufficient to comply with the RPS. ARES must utilize the PJM
Interconnection’s (PJM) Environmental System Generation Attribute Tracking System
(PJM-GATS) or the Midwest Renewable Energy Tracking System (M-RETS) used within
the territory covered by the Midwest Independent System Transmission Operator (MISO).
27 ACPs are remitted by ARES directly to the ICC, and the ICC forwards that money to the
21 220 ILCS 5/16-118(b) and (c). The POR mechanism mandated that ARES would have an option to
have the utility purchase uncollectible receivables for power and energy service for two unpaid
billing cycles per residential or small business customer, provided the customer was returned to the
electric utility and the ARES made reasonable collection efforts on the account. The UCB mechanism
mandated that ARES would have an option to have the utility produce and provide customers with a
single bill including both delivery service provided by the utility and energy service provided by the
ARES, and to identify the ARES the customer is receiving service from.
22 220 ILCS 5/16-118(a).
23 Ill. Commerce Comm’n, Consolidated Dockets 08-0619, 08-0620, and 08-0621, Final Order at 2
(Aug. 19, 2009).
24 Ill. Commerce Comm’n, Docket 10-0138, Final Order at 2 (Dec. 15, 2010). Certain aspects of this
Final Order are the subject of appeals to the Illinois Appellate Court.
25 See, e.g. “Supply Options Chosen by Customers of Ameren Illinois Company d/b/a Ameren Illinois -
Rate Zone I As of January 31, 2012” (ICC Electric Switching Statistics) published by the ICC and
available at http://www.icc.illinois.gov/electricity/switchingstatistics.aspx.
26 220 ILCS 5/16-115D(a)(2) and (d)(3).
27 The PJM interconnection coordinates the movement of wholesale electricity in all or parts of 13
states and the District of Columbia, including the ComEd service territory. MISO coordinates the
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RERF administered by the IPA for use in purchasing RECs. The IPA is directed to
purchase and retire renewable resources at a price not to exceed the winning bid prices for
like resources under the IPA's procurements for electric utilities.28 Thus the IPA central
procurement model used for RPS compliance by electric utilities effectively extends to at
least 50% (and possibly more) of the load served by ARES. The ACP rate, which is
essentially the average price of RECs purchased for the utilities, fluctuates from year to
year based on the results of IPA procurement events. Nevertheless, because the ACP is tied
to the average prices for renewable resources purchased by the utilities, the mechanism
allows for competitive neutrality with respect to RPS compliance costs passed through to all
retail electric customers.
C. Report Methodology
This Report draws upon publicly available data regarding electric utility load,
procurement results, and ACP fund reporting. Although the RPS has been in place since
June 1, 2008, the Agency was not required to conduct a renewable energy resource
procurement event until 2009, for delivery beginning June 1, 2009. Given the statutory
directive to examine “the Agency’s procurement,”29 this report focuses its analysis on the
years 2009 through 2011. There is no specific definition of either “costs” or “benefits” in the
IPA Act. For the purposes of this report, “costs” are the final amount settled for a renewable
resource as publicly reported, and “benefits” are both quantitative and qualitative economic
and societal impacts.
The Report also includes estimates of bill impacts based on eligible customer class
load, numbers of customers and bill estimates contained in publicly available utility tariff
and rate case filings.30 For the purposes of determining the total bill impact, presented as
both a percentage of an average customer bill for that class and in cents per kilowatt-hour,
this Report includes the same costs included in the statutory RPS spending cap: “the total
amount paid for electric service [which] includes without limitation amounts paid for
supply, transmission, distribution, surcharges, and add-on taxes.”31
The IPA would like to thank ComEd, Ameren and the Staff of the Illinois Commerce
Commission for their assistance in preparing this Report. The IPA also would like to thank
Adica, its procurement planning consultant, for its assistance in preparing this Report.
movement of wholesale electricity in all or parts of 11 Midwestern states, including the Ameren
service territory.
28 See 20 ILCS 3855/1-56(d) and (e)
29 See 20 ILCS 3855/1-75(c)(5).
30 For ComEd, this includes ICC Dockets 07-566 and 10-0467; for Ameren, this includes ICC Dockets
07-0585, 09-0306 and 11-0279 (later withdrawn).
31 20 ILCS 3855/1-75(c)(2).
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III. Renewable Resource Procurement Impact
A. Cost Comparison
“[T]he Agency shall prepare a public report … that shall include … a
comparison of the costs associated with the Agency’s procurement of renewable
energy resources to … the Agency’s costs associated with electricity generated
by other types of generation facilities.” 32
Results are presented for each electric utility below. In order to place the costs of
renewable resources and conventional supply resources on a level footing, procurement
costs are compared by year of delivery to the utility’s customers. For each delivery year, the
following costs are tabulated:
 The actual average cost of RECs procured by the Agency in that year’s procurement;
and
 The actual average cost of energy (and for Ameren capacity) procured by the Agency
from conventional supply sources in that year’s procurement.33
Although long-term power purchase agreements (LTPPA), which include bundled
long-term renewable energy and the associated RECs, were procured in 2010, their delivery
does not being until June 1, 2012.34 The price of these bundled energy and REC products is
noted in the tables but not included in the calculations since delivery has not begun.
Similarly, the RECs procured by the utilities under the 2012 Rate Stability Procurement do
not begin delivery until June 2013. The price of these REC products is noted in the tables
but not included in the calculations since delivery has not begun.
Although the Agency’s costs associated with procuring RECs are compared to the
Agency’s costs associated with procuring energy from conventional supply sources below, it
should be noted that these costs are not for equivalent products. RECs represent only the
value of the environmental attributes of a certain amount of energy produced from
renewable energy resources, not the value of the underlying energy. On the other hand, the
values shown for energy produced from conventional supply sources represent actual
energy prices procured for use by the end customer. In general, except for the LTPPAs, the
REC costs are additive to the conventional supply costs when calculating individual
customer rate and bill impacts.
The ICC has approved the IPA’s procurement of RECs to comply with the entirety of
the utilities’ RPS-mandated volumes:
32 20 ILCS 3855/1-75(c)(5)(A).
33 Detailed calculations and data sources are available in Appendix 1.
34 Ill. Power Agency, Ill. Commerce Comm’n Docket 09-0373, Motion for Leave to File Supplemental
Recommendation for the Procurement Plan, Appendix K at 7 (Nov. 9, 2009).
Page 14 of 33
 For the 2009 procurement, the ICC approved the IPA’s plan to purchase RECs for
delivery from June 2009 – May 2010 to fulfill the RPS mandate for that period and
stated that “the IPA is not permitted to undertake the acquisition of multi-year or
long-term renewable resources.”35
 For the 2010 procurement, the ICC again agreed with the IPA’s proposal to procure
RECs on a short-term basis, for delivery from June 2010 – May 2011.36 The ICC
additionally found that the 2010 LTPPA “will supplement the short-term REC
acquisition,” and approved the IPA’s revised plan to enter into LTPPAs for
renewable energy supplies “outside of the RPS.”37
 For the 2011 procurement, the ICC found that “a REC is a renewable energy
resource and therefore fully meets the requirement of Section 1-20 of the IPA Act
requiring the procurement of renewable energy,” and approved the IPA’s plan to
procure unbundled one-year RECs for delivery from June 2011-May 2012.38
For the 2012 procurement, to be conducted later this Spring, the IPA proposed to
include one-year RECs and to procure the minimum unbundled RECs required under the
solar and wind REC carve-outs, taking into account LTPPA volumes for delivery from June
2012 – May 2013, and the ICC agreed with the IPA’s proposal.39 Future REC purchase
volumes for delivery beginning June 1, 2013 will be revised downward pursuant to Public
Act 97-0616, which required the IPA to conduct the separate Rate Stability Procurement of
renewable energy resources in February 2012.40 These latter resources are for delivery June
1, 2013 through December 31, 2017. Their costs are indicated in this report but not their
rate impacts, which are unknown at this time.
35 Ill. Commerce Comm’n, Docket 08-0519, Final Order at 45 (Jan. 7, 2009).
36 Ill. Commerce Comm’n, Docket 09-0373, Final Order at 127 (Dec. 28, 2009).
37 Ill. Commerce Comm’n, Docket 09-0373, Final Order at 126, 115, 43 (Dec. 28, 2009).
38 Ill. Commerce Comm’n, Docket 10-0563, Final Order at 83 (Dec. 21, 2010).
39 Ill. Commerce Comm’n, Docket 11-0660, Final Order at 84 (Dec. 21, 2011); Ill. Power Agency, Ill.
2012 Power Procurement Plan Updated at 53 (Feb. 17, 2012).
40 Ill. Power Agency, Ill. Commerce Comm’n Docket 11-0660, 2012 Power Procurement Plan Updated
at 60 (Feb. 17, 2012).
Page 15 of 33
1. ComEd
Delivery
Year
Avg. Cost of RECs
Procured by IPA in
the Delivery Year
(¢/kWh)
Avg. Cost of
Conventional Supply
Procured by IPA in the
Delivery Year (¢/kWh)
June 2009 – May 2010 1.927 3.281
June 2010 – May 2011 0.488 3.344
June 2011 – May 2012 0.095 3.684
June 2009‐May 201241 0.743 3.412
2010 LTPPA42 5.518 N/A
2012 Rate Stability43 0.128 3.257
Figure 2: Relative Cost Comparison of RECs and Conventional Supply on a Cents
per Kilowatt-hour Basis for ComEd44
41 Load-weighted average.
42 The procurement cost noted for the long-term procurement reflects the average weighted price of
delivery of bundled RECs and energy from renewable energy resources, including a 2% escalator
each year. The entire contract term is June 2012 – May 2032. See ICC Approves Results of
Renewable Energy RFP, News from the Ill. Commerce Comm’n (Dec. 15, 2010).
43 Load-weighted average of the first year of delivery, June 2013-May 2014.
44 This is a relative cost comparison and NOT a calculation of rate impacts. Each year had different
volumes of peak and off-peak energy secured in different months and the number of RECs procured
is a small percentage of the amount of kWh of energy supplied (determined by the RPS for that
particular delivery year). Sections III(C) and III(D) below provide an analysis of rate impacts, which
factors in the RPS’ effect on volume.
Page 16 of 33
2. Ameren
Delivery Year
Avg. Cost of RECs
Procured by IPA in
the Delivery Year
(¢/kWh)
Avg. Cost of
Conventional Supply
Procured by IPA in the
Delivery Year45
(¢/kWh)
June 2009 – May 2010 1.586 3.682
June 2010 – May 2011 0.405 3.114
June 2011 – May 2012 0.092 3.234
June 2009‐May 201246 0.623 3.378
2010 LTPPA47 5.044 N/A
2012 Rate Stability48 0.343 2.951
Figure 3: Relative Cost Comparison of RECs and Conventional Supply on a Cents
per Kilowatt-hour Basis for Ameren49
B. Cost/Benefit Comparison
“[T]he Agency shall prepare a public report … that shall include … a
comparison of the costs associated with the Agency’s procurement of renewable
energy resources to … the benefits associated with the Agency’s procurement of
renewable energy resources.”50
This is of necessity a combination of a quantitative and qualitative analysis. The
costs are described in Section III (A) above, and the benefits are described below.
45 Includes costs of both energy and capacity resources, procured through IPA-managed
procurements and required to meet MISO capacity rules.
46 Load-weighted average.
47 The procurement cost noted for the long-term procurement reflects the average weighted price of
delivery of bundled RECs and energy from renewable energy resources, including a 2% escalator
each year. The entire contract term is June 2012 – May 2032. See ICC Approves Results of
Renewable Energy RFP, News from the Ill. Commerce Comm’n (Dec. 15, 2010).
48 Load-weighted average of the first year of delivery, June 2013-May 2014.
49 This is a relative cost comparison and not a calculation of rate impacts. The number of RECs
procured is a small percentage of the amount of kWh of energy supplied (determined by the RPS for
that particular delivery year). Sections III(C) and III(D) below provide an analysis of rate impacts,
which factors in the RPS’ effect on volume.
50 20 ILCS 3855/1-75(c)(5)(A).
Page 17 of 33
1. Economic Benefits
Illinois currently ranks fourth in the country for overall installed wind capacity in
the U.S. according to the American Wind Energy Association (AWEA).51 AWEA also found
that Illinois ranked second to California for most new wind energy capacity installed in
2011, and led the nation in number of new turbines installed with 404.52 Various categories
of economic benefits are attributable to wind energy, including the impact on electricity
prices, economic development, and local economies. Critics of wind energy point to factors
that may offset some of the purported benefits of this renewable energy resource, including
government subsidization of the industry, reduced land values, wear and tear on local roads
during the construction of turbines, future decommissioning costs, and that the variable
nature of this resource could increase spinning reserve requirements. While the market
modeling software applied by IPA’s procurement planning consultant evaluates the impact
of wind energy on spinning reserve requirements, the Agency is unaware of any method to
accurately and reliably quantify the other negative impacts for comparison with alternative
energy sources. Nevertheless, these impacts should be considered in any policy discussion
regarding renewable energy resources.
a. Impact on Electricity Prices
General Price Impacts
Illinois State University’s Center for Renewable Energy concluded that because
wind is both an inexhaustible energy source and is free from fuel price volatility, it can
contribute to the nation’s energy security.53 Wind power can lead to more stable electricity
prices, which benefit customers in the long run, by diversifying supply portfolios and
softening impacts from fuel price volatility. The U.S. Department of Energy also
characterizes renewable energy as a resource for hedging against risks posed by electricity
price volatility, particularly through the purchase of long-term, fixed-price supply contracts
for renewable energy resources directly with developers or generators. 54 (The Illinois Power
Agency notes that local conditions in Illinois, especially load uncertainty due to municipal
aggregation and the inexpensive prices associated with near-term RECs have pointed
towards the IPA recommending the use of one-year RECs as the more cost effective
alternative to meet RPS requirements at this time.) Using renewable energy can also
reduce the risk of disruptions in fuel supplies, like natural gas, resulting from
51 Wind Energy Facts – Illinois, published by the American Wind Energy Association (January 2012).
52 Id.
53 Economic Impact: Wind Energy Development in Illinois, Center for Renewable Energy, Illinois
State University (2011) at 10.
54 Guide to Purchasing Green Power, United States Department of Energy Office of Renewable
Energy and Energy Efficiency, at 5. (March 2010).
Page 18 of 33
transportation difficulties or international conflict.55 Likewise, wind power is not subject to
the uncertainty surrounding future carbon taxes, unlike fossil fuel-fired power plants.56
Impacts on Locational Marginal Prices
Electricity purchased for either utilities or ARES in Illinois is sourced in regional
competitive wholesale markets. Power for ComEd customers flows through the
transmission grid and wholesale market coordinated by PJM while Ameren is a member of
MISO. Both PJM and MISO are among seven Regional Transmission Operators (RTO)
responsible for reliable flows of energy across the nation’s transmission system. The RTOs
ensure that the electrical system is always perfectly balanced between supply and demand,
by dispatching generation (and load reduction under some circumstances) to meet the
fluctuating load. Which power plants will be used at any time to serve load is generally
determined through operation of wholesale electricity markets by the RTOs.
Wholesale electric energy prices are set for hourly periods based on bidding by
available generators into the regional markets. The bid of the highest cost power plant
needed to satisfy the anticipated demand sets the price for the next hour’s electricity.
However, the actual wholesale price varies from place to place based on the additional
factor of transmission congestion. Transmission congestion occurs when the lowest cost
supply cannot be delivered to a demand location because of physical limitations on the
capacity of the transmission line between the plant and the load center. When this occurs,
other, more costly, plants with access to less constrained transmission lines are used to
supply the load at that location, which increases the cost of electricity in that hour for the
congested area of the system. The price at a node is known as the Locational Marginal Price
(LMP). During peak periods, LMPs rise because of the combined effect of higher cost power
plants being dispatched to meet system load and greater congestion in certain areas.
Construction of new generating capacity, whether renewable or non-renewable, has
the effect of reducing market prices for both energy and capacity by increasing the amount
of available supply. Because of their variable output, which is dependent on weather
conditions, wind and solar resources have lower capacity value than dispatchable power. In
PJM, the average wind capacity factor used to valuate new wind projects in the forward
capacity market has been set at 13%, and solar is set at 38% based on their projected
availability during peak periods. The result is that construction of these renewable
resources has a relatively small downward effect on capacity costs. However, when the sun
is shining or the wind is blowing, the combined output of renewable generators benefits all
customers by bringing down the market price of electric energy for all resources operating
at that time. This is because wind and solar generation can effectively bid in at a zero
variable fuel cost.
55 Id.
56 Economic Impact: Wind Energy Development in Illinois at 10.
Page 19 of 33
The market price effects of renewable resources added to the interconnected electric
system can be estimated using market modeling software. The IPA’s procurement planning
consultant, Adica, employs a proprietary market model57 capable of modeling the entire
Eastern Interconnection58 using data at the nodal level for both load and generation. The
IPA commissioned the consultant to run the model with and without Illinois renewable
generation in order to test the effect on overall LMPs for calendar year 2011.
For calendar year 2011, estimated impacts of a system with and without Illinois
renewable generation are shown below. The most relevant column for this Report is “Total
Load Payment,” representing what consumers would have paid if their rates were strictly
based on hourly LMPs. Furthermore, the model estimates that average LMPs were
significantly affected by the integration of renewable resources into the power grid.
Renewable resources have lowered Illinois’ average LMPs by $1.30 per MWh, from $36.40
to $35.10 per MWh. The aggregate result is a savings of $176.85 million in total load
payment for generation in Illinois. While this does not directly translate to dollar for dollar
savings in consumer bills for the same time period, due to the fact that utility consumers
are served via a portfolio of resources of different vintage, it points out the magnitude of the
benefits accruing to all consumers in lowered underlying electric energy cost drivers. Over
time, the effect of lower LMPs due to growing renewable capacity will be reflected in
procurement outcomes. Similar results were found in Massachusetts, where it has been
reported that “price suppression” due to the addition of new resources provides “measurable
benefits.”59
Year
Renewable
Energy
Integration
Total
Production
Cost
($Million)
Total
Generation
Credit
($Million)
Total
Load
Payment
($Million)
System
Cost
Index
($Million)
Average
LMP
($/MWh)
Cost of
Energy
Import
($Million)
Cost of
Energy
Export
($Million)
2011
No
Renewable
Eenergy
2353.21 5788.84 4973.92 2301.53 36.4 873.58 1900.40
With
Renewable
Energy
2244.04 5531.40 4797.07 2207.59 35.1 873.04 1868.90
Figure 4: Estimated LMP Savings From Renewable Resource Integration60
57 MarSi is a software tool developed by GEMS for electricity market simulations which uses
generator data, transmission network data, and hourly load data to model the effects of changes in
fuel prices, carbon costs, wind and solar penetration, load growth and load growth rate, and
addition/decommissioning/planned outages of generating units and transmission lines.
58 The Eastern Interconnection includes MISO and PJM.
59 “Recent Electricity Market Reforms in Massachusetts: A Report of Benefits and Costs,” published
by the Executive Office of Housing and Economic Development and the Executive Office of Energy
and Environmental Affairs at 23 (July 2011).
60 Locational Marginal Price (LMP) is the cost of supplying the next MW of load at a specific location.
LMP includes the costs associated with generation, transmission, and technical losses in the system.
Page 20 of 33
b. Economic Development
Illinois State University’s Center for Renewable Energy modeled the economic
impact of wind energy upon Illinois’ economy by entering project specific information into
the National Renewable Energy Laboratory’s (NREL) Jobs and Economic Development
Impact (JEDI) model to estimate the income, economic activity, and number of job
opportunities accruing to the state from the project.61 The report found that wind power
leads to the creation of temporary and permanent jobs requiring highly-skilled workers in
the fields of construction, management, and engineering.62 Construction phase jobs
typically last anywhere from 6 months to over a year, while operational phase jobs,
including operations and maintenance positions, last the life of the wind farm, typically 20-
30 years.63
The report also found that the initial spending on the construction and operation of
a wind farm creates a second layer of impacts, which they referred to as “turbine and
supply chain impacts” or “indirect impacts.”64 Indirect impacts occurred both in the
construction and the operation of wind turbines, and included construction spending on
materials and wind farm equipment and other purchases of goods and offsite services and
“expenditures related to on-site labor, materials, and services needed to operate the wind
farms (e.g., vehicles, site maintenance, fees, permits, licenses, utilities, insurance, fuel,
tools and supplies, replacement parts/equipment); the supply chain of inputs required to
produce these goods and services; and project revenues that flow to the local economy in the
form of land lease revenue, property tax revenue, and revenue to equity investors.”65
Production Cost comprises fuel cost, startup cost, and shutdown cost of all generating units in the
system. The total fuel cost includes the cost of supplying the hourly load plus line losses. Wind and
solar units do not contribute to the production cost since their fuel costs are assumed zero.
Generation Credit is the payment to all generating units in the system. The hourly generation credit
of a unit is the MWh generation times the LMP at the generation bus location.
Load Payment is the payment made by the loads in the system. The payment includes that of
consumption plus line losses. The hourly payment of a load is MWh consumption times the LMP at
the load bus location.
System Cost Index: It is defined as {0.7 * Production Cost + 0.3 * (Load Payment – Generation
Credit) }. The System Cost Index quantifies the impact of production cost and congestion on the
system operation cost.
Imported Energy is the sum of hourly power flows injected to Illinois. Exported Energy is the sum of
hourly power flows extracted from Illinois.
The Cost of Imported/Export Energy is the injected/extracted MWh times the LMP at the bus
location where energy is injected/extracted.
61 Economic Impact: Wind Energy Development in Illinois at 17.
62 Economic Impact: Wind Energy Development in Illinois at 23.
63 Id.
64 Economic Impact: Wind Energy Development in Illinois at 18.
65 Id. at 19.
Page 21 of 33
Finally, the report included local spending by employees working directly or indirectly on
the wind farm project who receive their paychecks and then spend money in the
community.66
The analysis also concluded that local wind turbines raise the property tax base of a
county, which can create “a new revenue source for education, fire departments, and other
local government services,”67 since local governments can receive significant amounts of
revenue from permitting fees.68 Benefits to landowners identified included revenue from
leasing their land, which the report found was “usually greater than that from ranching or
farming and it does not require any work from the landowners.”69 As noted above,
however, the IPA believes that some local concerns such as wear and tear on roads during
construction, unfunded decommissioning cost liability and possibly lowered land values
should be considered when evaluating any specific project’s impacts.
c. Impact of Economic Incentives for Wind Energy
In the last few years, the economics of renewable energy have been influenced by
state and federal tax credits and other taxpayer supported incentives. It is unknown
whether these incentives will be modified or will remain available. The following state tax
incentives impact the benefits derived from renewable energy resources:
 An Investment Tax Credit entitles Illinois developers to a 0.5% income tax credit for
investments in qualified property, which may include building, structures, and other
tangible property.70
 A Jobs Tax Credit entitles Illinois employers to a $500 tax credit for hiring
individuals certified as economically disadvantaged.
 A Sales-and-Use Tax Exemption for Building Materials grants Illinois businesses
full exemption from sales-and-use tax without having to apply for enterprise zone
status.71
 Property Tax Valuation of Wind Turbines: The wind energy property assessment
division of the Illinois Property Tax Code specifies wind energy devices larger than
500 kilowatts (kW) that produce power for commercial sale be valued at $360,000
66 Id. at 20.
67 Id. at 11.
68 Id. at 16.
69 Id. at 15.
70 Id. at 13.
71 Pub. Act 96-28 (eff. July 1, 2009) amended the Illinois Enterprise Zone Act, to provide that
businesses that intend to establish a new wind power facility in Illinois may be considered “high
impact businesses” allowing them to claim a full exemption from sales-and-use tax without having to
apply for enterprise zone status. See Economic Impact: Wind Energy Development in Illinois at 13-
14.
Page 22 of 33
per megawatt (MW) of capacity and annually adjusted for inflation according to the
United States Consumer Price Index.72 The depreciation allowance may not exceed
70%. An extension of the law was recently signed and extends the current valuation
methodology until the end of 2016, providing greater certainty for all stakeholders in
wind energy developments.73
At the federal level, the production tax credit (PTC) for wind energy is slated to
expire at the end of 2012, and it is unclear whether it will be renewed. The PTC provides an
income tax credit of 2.2 cents per kilowatt-hour for the production of electricity from utility-scale
turbines. The incentive was created under the Energy Policy Act of 1992, and applies
for the first 10 years of electricity production. Through Section 1603 of the American
Recovery and Reinvestment Act of 2009, wind project developers can choose to receive a
30% investment tax credit (ITC) in place of the PTC. For projects placed in service before
2013, at which construction begins before the end of 2011, developers can elect to receive an
equivalent cash payment from the Department of Treasury for the value of the 30% ITC.
AWEA reports that in the years following expiration, installations dropped between 73 and
93 percent, with corresponding job losses.74
2. Environmental Benefits
The environmental benefits of renewable energy resources are mainly associated
with the benefits of avoiding the use of traditional generation sources which emit regulated
pollutants. For example, the United States Environmental Protection Agency (EPA) has
found that emissions of carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O),
hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6) may
reasonably be anticipated to endanger public health and welfare.75 Traditional generation
from power plants include air emissions responsible for approximately one-third of nitrogen
oxide emissions, two-thirds of sulfur dioxide emissions, and one-third of carbon dioxide
emissions nationally, emissions associated with lung diseases such as asthma and chronic
obstructive pulmonary disorder.76 Renewable energy sources can avoid or reduce these air
emissions, as well as reduce water consumption, thermal pollution, waste, noise, and
adverse land-use impacts.77
Environmental benefits can be measured in terms of annual emission benefits, that
is, the benefits of not using traditional generation sources such as coal or natural gas which
72 35 ILCS 200/10-605.
73 Economic Impact: Wind Energy Development in Illinois at 14.
74 Production Tax Credit Fact Sheet, American Wind Energy Association (April 2011).
75 74 Fed. Reg. 66,495 (Dec. 15, 2009).
76 Air Emissions Fact Sheet, U.S. Environmental Protection Agency
http://www.epa.gov/cleanenergy/energy-and-you/affect/air-emissions.html (accessed March 2012).
77 Breath Taking: Premature Mortality due to Particulate Air Pollution in 239 American Cities,
National Resources Defense Council, at 1 (May 1996).
Page 23 of 33
emit restricted pollutants. The same model used to estimate impacts on LMPs was also
used to estimate the generation by fuel type and the associated emissions, with and without
renewable resources. The emission value and emission costs are represented in the table
below both with and without renewable energy integration. As shown, the renewable
energy would reduce CO2 emissions by 5,481,327 tons and nitrous oxide (NOx) by 4,765
tons. The total emission cost reduction is about $75 million with renewable energy
integration (given trading values for allowances/credits are NOx : $10,000/ton, CO2:
$5/ton).
Year
Renewable
Energy
Integration
CO2 (Ton) NOx (Ton) CO2 Cost ($) NOx Cost ($) Total Emission
Cost ($)
2011
No
Renewable
Eenergy 90,386,907.82 78,114.40 451,934,539.12 781,143,959.14 1,233,078,498.27
With
Renewable
Energy 84,905,580.47 73,349.79 424,527,902.36 733,497,897.58 1,158,025,799.94
Figure 5: Emissions Cost Savings From Renewable Resource Integration
C. Rate Impacts on Eligible Retail Customers
“[T]he Agency shall prepare a public report … that shall include … an
analysis of the rate impacts associated with the … Agency’s procurement of
renewable resources, including … any long-term contracts, on the eligible
retail customers of electric utilities. The analysis shall include the Agency’s
estimate of the total dollar impact that the Agency’s procurement of renewable
resources had has on the annual electricity bills of the customer classes that
comprise each eligible retail customer class.” 78
The IPA asked Ameren and ComEd to provide their rate spreadsheets by customer
class for each of the three delivery years examined, breaking out the additional amounts
reflected in the supply charge attributable to renewable resource delivery by delivery
year.79 These spreadsheets provide the rate impact associated with the Agency’s
procurement of renewable resources. When multiplied by the overall billing determinants,
the values from the provided spreadsheets provide the total dollar impact on the annual
electricity bills of each customer class. Results are presented for each electric utility and
corresponding customer class below.
78 20 ILCS 3855/1-75(c)(5).
79 These spreadsheets can be found at Appendix 2.
Page 24 of 33
Because the 2010 LTPPA, the sole “long-term contract” procured by the IPA, begins
delivery on June 1st of 2012, there are not yet any “rate impacts” or “total dollar impacts” on
end-customer “annual electricity bills” that the Agency can analyze.
1. ComEd
SF MF SFSH MFSH WH Small Load
Rate Impact80
June 2009 – May 2010 0.69% 0.61% 0.65% 0.61% 0.63% 0.81%
Total Dollar Impact
June 2009 – May 2010 $18,582,034 $3,715,327 $438,849 $928,246 $458,803 $7,520,576
Rate Impact
June 2010 – May 2011 0.21% 0.18% 0.20% 0.19% 0.20% 0.25%
Total Dollar Impact
June 2010 – May 2011 $6,593,738 $1,389,117 $86,042 $167,408 $156,180 $2,406,481
Rate Impact
June 2011 – May 2012 0.05% 0.05% 0.05% 0.05% 0.04% 0.06%
Total Dollar Impact
June 2011 – May 2012 $1,479,872 $303,030 $36,246 $75,508 $31,140 $423,360
Figure 6: ComEd Rate and Total Dollar Impacts
80 This value represents the amount that RECs cost each customer of that delivery year class as a
percentage of the amount paid for total “annual electricity bills,” except for taxes. Thus, a Rate
Impact of 0.69% means that 0.69% of the total electricity bill (before taxes) of a customer of that class
in that delivery year was spent on satisfying contracts for renewable energy resources.
Page 25 of 33
2. Ameren
DS‐1
Rate Zone I
DS‐1
Rate Zone II
DS‐1 Rate
Zone III
DS‐2 Rate
Zone I
DS‐2 Rate
Zone II
DS‐2 Rate
Zone III
DS‐3 Rate
Zone I
DS‐3
Rate
Zone II
DS‐3 Rate
Zone III
Rate Impact81
June 2009 – May 2010 0.70% 0.69% 0.61% 0.63% 0.65% 0.58% 0.83% 0.78% 0.76%
Total Dollar Impact
June 2009 – May 2010 $2,398,953 $1,264,776 $3,504,771 $852,750 $351,942 $1,127,579 $340,748 $98,348 $361,128
Rate Impact
June 2010 – May 2011 0.22% 0.23% 0.19% 0.21% 0.22% 0.19% 0.28% 0.27% 0.25%
Total Dollar Impact
June 2010 – May 2011 $847,848 $456,896 $1,248,348 $230,026 $100,738 $307,786 $50,575 $21,718 $59,270
Rate Impact82
June 2011 – Feb. 2012 0.06% 0.06% 0.05% 0.06% 0.06% 0.05% 0.08% 0.08% 0.07%
Total Dollar Impact83
June 2011 – Feb. 2012 $170,449 $94,818 $255,827 $42,353 $19,213 $56,506 $7,968 $3,679 $8,898
Values for Ameren customer class DS-5 were unavailable from Ameren at the time this report was compiled. Values for
Ameren customer class QF are not available since Ameren is obligated to purchase energy from this class
Figure7: Ameren Rate and Total Dollar Impacts
.
81 This value equals the ACP rate for the delivery year class divided by the total revenue per kilowatt-hour of the corresponding delivery
year class. The ACP rate is equal to the amount Ameren spent on renewable resources in the delivery year divided by the forecasted load of
eligible customers during that same period. See 220 ILCS 5/16-115D(d)(1). Thus, a Rate Impact of 0.70% means that 0.7% of the total
electricity bill of a customer of that class in that delivery year was spent on satisfying contracts for renewable energy resources.
82 Because this year has not been fully delivered, Rate Impacts are provided until and including February 2012.
83 Because this year has not been fully delivered, Total Dollar Impacts are provided until and including February 2012.
Page 26 of 33
D. Rate Impacts on Customers of Alternative Retail Electric Suppliers
“The Agency’s report shall … analyze how the operation of the alternative compliance
payment mechanism, any long-term contracts, or other aspects of the applicable
renewable portfolio standards impacts the rates of customers of alternative retail
electric suppliers.”84
An ARES may satisfy its RPS requirement entirely through ACPs or through a
combination of an ACP payment and procurement of renewable resources. An ARES must
meet at least 50% of its RPS requirement using the ACP mechanism.85 The law allows
ARES to meet 100% of the RPS with the ACP mechanism, though it appears that most
ARES choose to use the ACP only for 50% of the required RPS. This Report has estimated
the ACP payment based on the actual published ACP rate and the estimated load of ARES
customers.
Delivery Year86
ComEd Usage
Forecast87 (kWh)
ComEd ACP
Rate (¢/kWh)
Ameren Usage
Forecast88 (kWh)
Ameren ACP
Rate
(¢/kWh)
June 2009‐ May 2010 39,469,952,000 0.0764 17,700,274,000 0.0645
June 2010‐ May 2011 35,993,039,000 0.0256 16,525,235,000 0.0211
Figure 8: Actual Published ACP Rates89
Assuming an ARES uses the ACP to meet half its RPS requirement, yet passes
through the costs of the ACP to all its volume sold, the estimated rate impact on ARES
customers would be half the values shown. That is, for an ARES customer in Ameren
territory, the ARES rate impact in delivery year June 2009 to May 2010 would be 0.03225
cents per kilowatt-hour. Since ACPs are based on the utilities’ average cost of REC
procurement, and assuming ARES pay approximately the same amount for renewable
resources they directly procure, the bill impact on ARES and utility customers is similar in
84 20 ILCS 3855/1-75(c)(5).
85 220 ILCS 5/16-115D(d).
86 Because it has not been fully delivered, the ACP rate for delivery year 2011-2012 is not included in
this estimate.
87 This is the forecasted usage of all ComEd customers, not ARES customers.
88 This is the forecasted usage of all Ameren customers, not ARES customers.
89 RPS Alternative Compliance Payment Notices, Illinois Commerce Commission,
http://www.icc.illinois.gov/downloads/public/ACP%20Rate%20History%20as%20of%202012-01-04.pdf
(converted to kWh and cents per kWh).
Page 27 of 33
dollar amount, although the percentage impact may be somewhat higher, given the lower
energy prices currently available from ARES.
Because the 2010 LTPPA, the sole “long-term contract” procured by the IPA, begins
delivery on June 1st of 2012, there are not yet any “rate impacts” or “total dollar impacts” on
ARES customer bills that the Agency can analyze.
Page 28 of 33
IV. Alternative Compliance Payment Mechanism Fund Report
“[T]he Illinois Power Agency shall submit an annual report to the General
Assembly, the Commission, and alternative retail electric suppliers that shall
include …
(A) the total amount of alternative compliance payments received in
aggregate from alternative retail electric suppliers by planning year for
all previous planning years in which the alternative compliance
payment was in effect;
(B) the total amount of those payments utilized to purchased [sic]
renewable energy credits itemized by the date of each procurement in
which the payments were utilized; and
(C) the unused and remaining balance in the Agency Renewable
Energy Resources Fund attributable to those payments.”90
Each ARES is responsible for procuring the same proportion of cost-effective
renewable energy resources as each electric utility, measured as a percentage of prior year
load and with costs calculated on a per kilowatt hour basis.91 At least 60% of the renewable
energy resources procured by an ARES must be from wind generation and, starting June 1,
2015, at least 6% of the renewable energy resources procured must be from solar
photovoltaics.92 If an ARES does not purchase at least these levels of specified renewable
energy resources, then it is required to make additional ACPs. An ARES must meet at least
50% of its renewable resource requirements by making ACPs, and may meet the entirety of
its renewable resource obligation through ACPs.93 All ACPs are placed into the Agency’s
Renewable Energy Resources Fund (“RERF”)94 which could then to be used to purchase
RECs.95 The price paid to procure RECs using monies from the RERF cannot exceed the
winning bid prices paid for like resources procured for electric utilities.96 As of this report
date, most ARES have chosen to meet only the minimum amount of the RPS requirement
(50%) using the ACP mechanism.
90 220 ILCS 5/16-115D(d)(4).
91 220 ILCS 5/16-115D(a).
92 220 ILCS 5/16-115D(a)(3) (the 60% statutory wind energy minimum for ARES is lower than the
75% wind standard for utilities).
93 220 ILCS 5/16-115D(b).
94 Also known as “Illinois Power Agency Fund 836.”
95 20 ILCS 3855/1-56.
96 20 ILCS 3855/1-56(d).
Page 29 of 33
A. Total Amount of ACPs Received
This report must provide the total amount of alternative compliance payments
received in aggregate from alternative retail electric suppliers for each planning year in
which the alternative compliance payment was in effect.97 Under the PUA, a “planning
year” begins on June 1st of each calendar year.98 The ACP mechanism was “in effect” by
September 1, 2010 to require payments by ARES for the period of June 1, 2009 to May 1,
2010.99 Therefore, this report must provide the aggregate total amount of ACPs for
planning years June 2009 – May 2010 and June 2010 – May 2011.
Planning Year Funds Received Total ACPs
June 2009 – May 2010 2010 – Quarters 3 and 4 $7,148,261.61
June 2010 – May 2011 2011 – Quarter 3 $5,606,245.18
Aggregate Total $12,754,506.79
Figure 9: Total ACPs Received
B. Amount of ACPs used to purchase RECs
To date, no RECs have been purchased using any RERF funds. Of the $7,148,261.61
in total ACPs received for the June 2009 – May 2010 planning year, the State of Illinois
borrowed $2,000,000 on September 20, 2010 and $4,710,000 on October 15, 2010.100 The
remaining $438,261.61 was not used to purchase RECs and remains in the RERF. The
State is required to repay the borrowed funds within 18 months of borrowing. The State
has repaid $2,000,000 to the RERF and the outstanding $4,710,000 is due for repayment by
April 14, 2012. Because the funds were borrowed from a non-interest earning account, no
interest has been or will be repaid. The IPA respectfully notes that this borrowing occurred
despite legislation which states
“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
97 220 ILCS 5/16-115D(d)(4)(A).
98 See e.g. 220 ILCS 5/16-111.5(b).
99 Pub. Act 96-0033 (eff. 7/10/2009); 220 ILCS 5/16-115D(d)(2).
100 30 ILCS 105/5h(a).
Page 30 of 33
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.”101
While the IPA believes that its use of the RERF is not subject to inclusion in its
Procurement Plans, because the balance in the RERF was substantially depleted at the
time the 2012 Procurement Plan was litigated and approved, there has been no stated plan
regarding use of the RERF’s initial deposits.
In the third quarter of 2011, the IPA received a total of $5,606,245.18 in ACPs for
the June 2010 – May 2011 planning year which, to the extent the funds remain available,
will be used in accordance with the IPA Act.102 The IPA will consider using ACP funds
within the context of its 2013 Procurement Plan. If the State continues to borrow funds
from the RERF, the IPA’s ability to purchase RECs at prices that “do not exceed the
winning bid prices paid for like resources procured for electric utilities” will be limited.103
C. Balance in RERF attributable to ACPs
As of this report date, the RERF balance equals $8,044,506.79. The amount required
to be repaid by the State by April 14, 2012 is $4,710,000. The sum of these two amounts
equals $12,754,506.79, the total amount received in the Agency’s RERF attributable to
ACPs.
101 20 ILCS 3855/1-56(h).
102 20 ILCS 3855/1-56.
103 20 ILCS 3855/1-56(d).
Page 31 of 33
Figure 10: Illinois Power Agency Renewable Energy Resources Fund
Transactions (Amounts in Dollars)
Illinois Power Agency Renewable Energy Resources Fund
Date Transaction Amount Cumulative
balance
9/2010 ACPs received $7,148,261.61 $7,148,261.61
9/2010 Loan to State ‐($2,000,000.00) $5,148,261.61
10/2010 Loan to State ‐($4,710,000.00) $438,261.61
9/2011 ACPs received $5,606,245.18 $6,044,506.79
3/2012 Repayment by State $2,000,000.00 $8,044,506.79
4/2012 Anticipated repayment by State $4,710,000 $12,754,506.79
Figure 11: IPA RERF Balance Sheet
-6,000,000
-4,000,000
-2,000,000
0
2,000,000
4,000,000
6,000,000
8,000,000
10,000,000
12,000,000
14,000,000
Aug
2010
Sept
2010
Oct
2010
Nov
2010
Dec
2010
July
2011
Aug
2011
Sept
2011
March
2012
ARES Funds Deposited Cumulative ARES Payments
State Borrowing State Repayment
Cumulative Balance
Page 32 of 33
D. Future Use of the ACP‐Funded RERF
The ACP mechanism is a useful construct to comply with RPS requirements in a
competitively neutral way. That is, it allows an opportunity for additional customer costs of
renewable resources to be the same, on an average cents per kilowatt-hour basis, whether
the customer takes electricity supply from a utility or an ARES. Despite the fact that the
IPA believes it has the authority to use the RERF outside a Procurement Plan, there are
several alternatives that deserve a full public vetting. The IPA intends to include an
analysis and proposal to use the RERF to procure renewable resources in its 2013
Procurement Plan, to be filed in the fall of 2012. In particular, conducting parallel utility
and ARES Distributed Generation procurements holds promise, as this is a currently
unfulfilled mandate. The minimum required term for Distributed Generation contracts is 5
years. As a cautionary note, unless the General Assembly can prevent the “borrowing” of
RERF monies, which serves to deplete the dollars available for their legislatively stated
purpose, any long-term contractual arrangements based on the flow of funds from ACP
monies could prevent the IPA from meeting its contractual obligations.
An alternative use of the RERF, to be examined in the 2013 Procurement Plan, may
be to offset the migration risks posed by municipal aggregation to utility REC contract
obligations. That is, as load shifts to ARES from utilities, it is appropriate for ARES-provided
funding to assist with contractual purchase obligations for existing and future
utility REC contracts.
One current legislative proposal does away with the ACP mechanism, instead
requiring the IPA to facilitate RPS compliance for all retail electric customers regardless of
supplier.104 ARES would be free to offer their customers a retail product that consists of
more renewable energy resources than required by the RPS. While this proposal removes
risks related to the volume of procurement, it raises issues of monopsony and inefficient
markets which should be further considered. Until legislative certainty is achieved around
this proposal, it is not advisable to use RERF monies to underwrite long-term contracts for
renewable resources.
104 S. B. 678, 97th Gen. Assem. (Ill. 2011).
Page 33 of 33
V. Appendices
Appendix 1a
Ameren Cost Comparison
Year
REC Load‐Weighted
Average (¢/kWh)
Conventional Load‐Weighted
Average (¢/kWh)
2009 ‐ 2010105 1.5860 3.6824
2010 ‐ 2011106 0.4046 3.1145
2011 ‐ 2012107 0.0923 3.2337
Average 0.6230 3.3781
Figure 12: REC and Conventional Load-Weighted Average
IL ‐ PV Price ($/MWh) IL ‐ PV Quantity (MWh) IL ‐ PV Expenditure ($)
95.26 8,065 768,272
OS ‐ PV Price ($/MWh) OS ‐ PV Quantity (MWh) OS ‐ PV Expenditure ($)
99.54 5,100 507,654
Wind Price ($/MWh) Wind Quantity (MWh) Wind Expenditure ($)
1.13 415,655 469,690
Other Price ($/MWh) Other Quantity (MWh) Other Expenditure ($)
0.85 107,200 91,120
Load‐Weighted Average
($/MWh)
Load‐Weighted Average
(¢/kWh)
3.4266 0.3427
Figure 13: 2013-2014 Rate Stability108
105 Data from ICC Public Notice (May 18, 2009); and computed from Figure 14 of this Report.
106 Data from ICC Public Notice (May 24, 2010); and computed from Figure 15 of this Report.
107 Data from ICC Public Notice (May 24, 2011); and computed from Figure 16 of this Report.
108 Data from IPA Public Notice (Feb. 23, 2012).
Date
On peak
Price
($/MWh)
On Peak
System
Supply
Requirements
(MWh)
On Peak
Residual
Volume
(MWh)
On Peak
Expenditure
($)
Off Peak
Price
($/MWh)
Off Peak
System
Supply
Requirements
(MWh)
Off Peak
Residual
Volume
(MWh)
Off Peak
Expenditure
($)
Total
Residual
Volume
(MWh)
Total
Residual
Expenditure
($)
Total
Capacity
Expenditure
($)
Jun‐
09 34.12 961,143 292,380 9,975,995 20.57 718,067 218,436 4,493,228 510,816 14,469,224 581,386
Jul‐
09 42.81 1,156,240 351,728 15,057,485 25.22 892,476 271,491 6,847,008 623,219 21,904,493 15,107,085
Aug‐
09 43.85 1,034,569 314,716 13,800,292 25.59 955,653 290,710 7,439,260 605,426 21,239,552 11,685,572
Sep‐
09 32.89 848,033 257,972 8,484,687 21.86 794,887 241,805 5,285,849 499,776 13,770,536 367,043
Oct‐
09 33.18 785,985 239,097 7,933,226 21.48 687,040 208,998 4,489,268 448,094 12,422,494 103,854
Nov‐
09 30.64 700,927 213,222 6,533,122 22.58 771,588 234,717 5,299,911 447,939 11,833,033 94,486
Dec‐
09 34.34 883,473 268,752 9,228,960 24.46 842,242 256,210 6,266,897 524,963 15,495,857 131,169
Jan‐
10 46.72 828,389 251,996 11,773,250 30.20 982,115 298,759 9,022,533 550,755 20,795,783 183,316
Feb‐
10 45.36 777,887 236,633 10,733,683 29.61 771,204 234,600 6,946,514 471,233 17,680,197 142,547
Mar‐
10 39.57 795,758 242,070 9,578,693 27.27 707,592 215,249 5,869,853 457,319 15,448,547 97,047
Apr‐
10 38.51 688,661 209,491 8,067,486 27.08 601,379 182,939 4,954,001 392,430 13,021,487 82,286
May‐
10 36.58 630,902 191,920 7,020,448 22.28 683,187 207,825 4,630,352 399,746 11,650,800 119,724
Total 10,091,967 3,069,976 118,187,328 9,407,430 2,861,740 71,544,675 5,931,717 189,732,003 28,695,515
Figure 14: 2009 AIC IPA Energy and Capacity Procurement109
109 Data from ICC Public Notices (April 13, 2009) and (May 5, 2009), IPA Procurement Plan Final Order (08-0519), using 30.42% residual factor (page 3)
and total supply from IPA's Petition, Attachment E.
Date
On peak
Price
($/MWh)
On Peak
System
Supply
Requirements
(MWh)
On Peak
Residual
Volume
(MWh)
On Peak
Expenditure
($)
Off Peak
Price
($/MWh)
Off Peak
System
Supply
Requirements
(MWh)
Off Peak
Residual
Volume
(MWh)
Off Peak
Expenditure
($)
Total
Residual
Volume
(MWh)
Total
Residual
Expenditure
($)
Total
Capacity
Expenditure
($)
Jun‐
10 33.09 779,952 209,183 6,921,870 21.85 680,221 182,435 3,986,211 391,618 10,908,080 36,357
Jul‐
10 42.47 962,074 258,028 10,958,460 24.57 923,346 247,641 6,084,549 505,670 17,043,009 662,415
Aug‐
10 42.59 972,635 260,861 11,110,058 24.70 891,295 239,045 5,904,419 499,906 17,014,477 478,826
Sep‐
10 33.96 742,449 199,125 6,762,279 20.71 684,079 183,470 3,799,663 382,595 10,561,942 26,346
Oct‐
10 33.04 616,307 165,294 5,461,298 19.63 631,933 169,484 3,326,979 334,778 8,788,278 13,950
Nov‐
10 33.17 636,263 170,646 5,660,319 21.29 643,953 172,708 3,676,957 343,354 9,337,277 14,063
Dec‐
10 35.91 854,143 229,081 8,226,304 23.32 774,962 207,845 4,846,941 436,926 13,073,245 21,879
Jan‐
11 41.51 817,614 219,284 9,102,482 30.14 925,975 248,346 7,485,163 467,631 16,587,645 21,682
Feb‐
11 41.19 721,585 193,529 7,971,464 29.39 744,639 199,712 5,869,541 393,241 13,841,004 19,124
Mar‐
11 37.67 713,785 191,437 7,211,437 23.89 647,218 173,584 4,146,919 365,021 11,358,356 16,961
Apr‐
11 37.14 554,568 148,735 5,524,023 22.58 563,412 151,107 3,411,998 299,842 8,936,021 13,015
May‐
11 35.50 558,272 149,729 5,315,364 20.13 596,638 160,018 3,221,169 309,747 8,536,532 13,512
Total 8,929,647 2,394,931 90,225,356 8,707,671 2,335,397 55,760,510 4,730,329 145,985,867 1,338,129
Figure 15: 2010 AIC IPA Energy and Capacity Procurement110
110 Data from ICC Public Notices (April 5, 2010) and (May 6, 2010), IPA Procurement Plan (09-0373), using total supply requirements from page 22 and
residual factor of 26.82% from page 4.
Date
On Peak Residual
Volume (MWh)
On Peak
Expenditure ($)
Off Peak Residual
Volume (MWh)
Off Peak
Expenditure ($)
Total Residual
Volume (MWh)
Total Residual
Expenditure ($)
Total Capacity
Expenditure ($)
Jun‐
11 173,867 6,805,504 191,933 4,858,227 365,800 11,663,731 17,196
Jul‐
11 170,267 7,158,696 157,933 4,089,551 328,200 11,248,247 90,102
Aug‐
11 154,267 6,445,736 174,333 4,529,555 328,600 10,975,291 74,138
Sep‐
11 169,067 6,306,592 175,133 4,392,075 344,200 10,698,667 6,800
Oct‐
11 135,467 4,963,264 136,733 3,537,291 272,200 8,500,555 3,960
Nov‐
11 152,267 5,558,992 136,733 3,537,291 289,000 9,096,283 2,372
Dec‐
11 152,267 5,578,144 177,533 4,546,275 329,800 10,124,419 2,333
Jan‐
12 185,867 7,395,064 175,133 4,675,467 361,000 12,070,531 3,230
Feb‐
12 185,867 7,420,768 175,133 4,675,467 361,000 12,096,235 2,836
Mar‐
12 154,267 5,848,896 156,333 4,044,735 310,600 9,893,631 1,551
Apr‐
12 154,267 5,848,896 136,733 3,537,291 291,000 9,386,187 1,850
May‐
12 138,667 5,215,872 136,733 3,537,291 275,400 8,753,163 3,008
Total 1,926,400 74,546,424 1,930,400 49,960,520 3,856,800 124,506,944 209,375
Figure 16: 2011 AIC IPA Energy and Capacity Procurement111
111 Data from ICC Public Notices (May 9, 2011) and (May 13, 2011), IPA Procurement Plan (09-0373), using total supply requirements from page 22 and
residual factor of 26.82% from page 4.
Appendix 1b
ComEd Cost Comparison
Year
REC Load‐Weighted
Average (¢/kWh)
Conventional Load‐Weighted
Average (¢/kWh)
2009 ‐ 2010112 1.9270 3.2810
2010 ‐ 2011113 0.4879 3.3440
2011 ‐ 2012114 0.0950 3.6838
Average 0.7428 3.4125
Figure 17: REC and Conventional Load-Weighted Average
IL ‐ PV Price ($/MWh) IL ‐ PV Quantity (MWh) IL ‐ PV Expenditure ($)
74.49 8 596
OS ‐ PV Price ($/MWh) OS ‐ PV Quantity (MWh) OS ‐ PV Expenditure ($)
65 1,500 97,500
Wind Price ($/MWh) Wind Quantity (MWh) Wind Expenditure ($)
1.27 1,060,901 1,347,344
Other Price ($/MWh) Other Quantity (MWh) Other Expenditure ($)
0.97 277,500 269,175
Load‐Weighted Average
($/MWh)
Load‐Weighted Average
(¢/kWh)
1.2797 0.1280
Figure 18: 2013-2014 Rate Stability115
112 Data from ICC Public Notice (May 11, 2009); and computed from Figure 19 of this Report.
113 Data from ICC Public Notice (May 24, 2010); and computed from Figure 20 of this Report.
114 Data from ICC Public Notice (May 24, 2011); and computed from Figure 21 of this Report.
115 Data from IPA Public Notice (Feb. 23, 2012).
Date
On peak Price
($/MWh)
On Peak
Residual
Volume (MWh)
On Peak
Expenditure ($)
Off Peak Price
($/MWh)
Off Peak
Residual
Volume (MWh)
Off Peak
Expenditure ($)
Total Volume
(MWh)
Total
Expenditure ($)
Jun‐
09 36.23 721,181 26,128,388 22.07 510,645 11,269,935 1,231,826 37,398,323
Jul‐
09 43.27 992,034 42,925,311 26.10 784,667 20,479,809 1,776,701 63,405,120
Aug‐
09 43.34 810,809 35,140,462 26.05 769,250 20,038,963 1,580,059 55,179,425
Sep‐
09 35.54 580,250 20,622,085 22.73 419,924 9,544,873 1,000,174 30,166,958
Oct‐
09 36.10 441,695 15,945,190 23.99 295,132 7,080,217 736,827 23,025,406
Nov‐
09 36.05 498,817 17,982,353 24.54 424,534 10,418,064 923,351 28,400,417
Dec‐
09 36.41 738,250 26,879,683 24.64 612,182 15,084,164 1,350,432 41,963,847
Jan‐
10 42.45 684,512 29,057,534 26.66 687,473 18,328,030 1,371,985 47,385,565
Feb‐
10 42.04 603,290 25,362,312 26.63 490,520 13,062,548 1,093,810 38,424,859
Mar‐
10 38.05 530,144 20,171,979 25.27 366,810 9,269,289 896,954 29,441,268
Apr‐
10 37.81 365,296 13,811,842 25.05 231,537 5,800,002 596,833 19,611,844
May‐
10 36.21 385,066 13,943,240 21.39 320,393 6,853,206 705,459 20,796,446
Total 7,351,344 287,970,378 5,913,067 147,229,099 13,264,411 435,199,477
Figure 19: 2009 ComEd IPA Energy Procurement116
116 Data from ICC Public Notices (April 29, 2009), ICC Final Order approving IPA Procurement Plan (08-0519).
Date
On peak Price
($/MWh)
On Peak
Residual
Volume (MWh)
On Peak
Expenditure ($)
Off Peak Price
($/MWh)
Off Peak
Residual
Volume (MWh)
Off Peak
Expenditure ($)
Total Volume
(MWh)
Total
Expenditure ($)
Jun‐
10 39.30 509,703 20,031,315 22.65 436,381 9,884,027 946,084 29,915,342
Jul‐
10 45.71 599,535 27,404,732 26.65 590,385 15,733,773 1,189,920 43,138,506
Aug‐
10 45.53 582,879 26,538,473 26.39 529,131 13,963,768 1,112,010 40,502,240
Sep‐
10 38.69 426,793 16,512,606 22.76 406,445 9,250,683 833,237 25,763,288
Oct‐
10 38.07 364,725 13,885,072 23.64 380,340 8,991,238 745,065 22,876,310
Nov‐
10 38.05 403,491 15,352,820 23.60 403,236 9,516,362 806,726 24,869,182
Dec‐
10 39.08 514,944 20,124,009 24.92 455,622 11,354,106 970,566 31,478,115
Jan‐
11 43.20 470,869 20,341,556 29.92 507,020 15,170,046 977,890 35,511,601
Feb‐
11 43.03 418,632 18,013,731 29.84 409,173 12,209,710 827,805 30,223,442
Mar‐
11 41.68 429,896 17,918,080 25.15 389,909 9,806,204 819,805 27,724,284
Apr‐
11 39.88 349,666 13,944,692 24.12 352,462 8,501,393 702,129 22,446,085
May‐
11 39.25 357,403 14,028,056 21.68 376,142 8,154,767 733,545 22,182,823
Total 5,428,535 224,095,142 5,236,246 132,536,076 10,664,781 356,631,218
Figure 20: 2010 ComEd IPA Energy Procurement117
117 Data from ICC Public Notices (April 30, 2010), ICC Final Order approving IPA Procurement Plan (09-0373).
Date
On Peak
Residual
Volume (MWh)
On Peak
Expenditure ($)
Off Peak
Residual
Volume (MWh)
Off Peak
Expenditure ($)
Total Volume
(MWh)
Total
Expenditure ($)
Jun‐
11 542,400 24,480,544 281,667 7,357,700 824,067 31,838,244
Jul‐
11 493,200 24,781,164 604,867 17,878,276 1,098,067 42,659,440
Aug‐
11 466,000 23,274,492 534,067 15,754,912 1,000,067 39,029,404
Sep‐
11 455,200 19,077,048 289,667 7,001,780 744,867 26,078,828
Oct‐
11 287,200 11,488,488 97,667 2,560,820 384,867 14,049,308
Nov‐
11 438,400 17,134,296 270,467 6,500,660 708,867 23,634,956
Dec‐
11 472,000 19,094,856 505,667 13,519,700 977,667 32,614,556
Jan‐
12 505,600 22,341,456 504,467 16,077,884 1,010,067 38,419,340
Feb‐
12 472,000 20,667,168 443,267 14,010,548 915,267 34,677,716
Mar‐
12 415,600 17,076,312 274,067 7,399,472 689,667 24,475,784
Apr‐
12 257,200 10,624,680 97,667 2,560,820 354,867 13,185,500
May‐
12 313,600 12,722,688 97,667 2,560,820 411,267 15,283,508
Total 5,118,400 222,763,192 4,001,200 113,183,392 9,119,600 335,946,584
Figure 21: 2011 ComEd IPA Energy Procurement118
118 Data from ICC Public Notice (May 18 2011).
Appendix 2a
Ameren Rate Impacts
2009 Plan
Year
2010 Plan
Year
2011 Plan
Year Thru
February
ACP Rate
2009 Plan
Year
ACP Rate 2010
Plan Year
ACP Rate 2011
Plan Year Thru
February
Ratio for
2009 Plan
Year
Ratio for
2010 Plan
Year
Ratio for
2011 Plan
Year Thru
February
Rate Zone I Revenue/kWh Revenue/kWh Revenue/kWh REC/kWh REC/kWh REC/kWh % % %
Fixed
Price
BGS‐1 $0.093 $0.097 $0.097 $0.000645 $0.000211 $0.000058 0.70% 0.22% 0.06%
BGS‐2 $0.102 $0.100 $0.104 $0.000645 $0.000211 $0.000058 0.63% 0.21% 0.06%
BGS‐3 $0.078 $0.076 $0.076 $0.000645 $0.000211 $0.000058 0.83% 0.28% 0.08%
Rate Zone II
Fixed
Price
BGS‐1 $0.093 $0.092 $0.091 $0.000645 $0.000211 $0.000058 0.69% 0.23% 0.06%
BGS‐2 $0.099 $0.095 $0.098 $0.000645 $0.000211 $0.000058 0.65% 0.22% 0.06%
BGS‐3 $0.083 $0.078 $0.077 $0.000645 $0.000211 $0.000058 0.78% 0.27% 0.08%
Rate Zone III
Fixed
Price
BGS‐1 $0.105 $0.110 $0.110 $0.000645 $0.000211 $0.000058 0.61% 0.19% 0.05%
BGS‐2 $0.111 $0.109 $0.113 $0.000645 $0.000211 $0.000058 0.58% 0.19% 0.05%
BGS‐3 $0.085 $0.083 $0.084 $0.000645 $0.000211 $0.000058 0.76% 0.25% 0.07%
Figure 22: Ameren Rate Impact
2009 Plan Year 2010 Plan Year 2011 Plan Year thru February
Rate Zone I Usage (kWh) Dollar Impact Usage (kWh) Dollar Impact Usage (kWh) Dollar Impact
Fixed
Price
BGS‐1 3,719,306,247 $2,398,953 4,018,238,879 $847,848 2,938,771,840 $170,449
BGS‐2 1,322,093,641 $852,750 1,090,170,287 $230,026 730,218,940 $42,353
BGS‐3 528,291,793 $340,748 239,691,632 $50,575 137,385,492 $7,968
Rate Zone II
Fixed
Price
BGS‐1 1,960,893,127 $1,264,776 2,165,385,392 $456,896 1,634,800,380 $94,818
BGS‐2 545,645,845 $351,942 477,428,939 $100,738 331,250,507 $19,213
BGS‐3 152,477,087 $98,348 102,928,279 $21,718 63,435,342 $3,679
Rate Zone III
Fixed
Price
BGS‐1 5,433,753,012 $3,504,771 5,916,341,378 $1,248,348 4,410,818,551 $255,827
BGS‐2 1,748,185,211 $1,127,579 1,458,701,530 $307,786 974,233,854 $56,506
BGS‐3 559,888,368 $361,128 280,899,066 $59,270 153,420,259 $8,898
Figure 23: Ameren Total Dollar Impact
Appendix 2b
ComEd Rate Impacts
Year Jun‐09 Jun‐10 Jun‐11
Customer Group or Subgroup
Summer
PEC
(¢/kWh)
Non‐summer
PEC
(¢/kWh)
Summer
PEC
(¢/kWh)
Non‐summer
PEC
(¢/kWh)
Summer
PEC
(¢/kWh)
Non‐summer
PEC
(¢/kWh)
Residential Non‐Electric Space Heating 6.589 6.435 7.837 7.653 7.154 6.986
Residential Electric Space Heating 5.240 3.978 6.233 4.731 5.690 4.319
Watt‐hour Non‐Electric Space Heating 6.740 6.551 7.953 7.730 7.308 7.104
Demand Non‐Electric Space Heating 6.646 6.507 7.842 7.679 7.207 7.056
Nonresidential Electrical Space Heating 6.337 6.234 7.478 7.357 6.871 6.760
Dusk to Dawn Lighting 2.398 2.865 2.844 3.398 2.590 3.093
General Lighting 6.265 6.245 7.430 7.407 6.765 6.743
Figure 24: ComEd Rate Impact: Purchased Electricity Charges (PECs)
Year Jun‐09 Jun‐10 Jun‐11
Customer Group or Subgroup
Summer
PEC
(¢/kWh)
Non‐summer
PEC
(¢/kWh)
Summer
PEC
(¢/kWh)
Non‐summer
PEC
(¢/kWh)
Summer
PEC
(¢/kWh)
Non‐summer
PEC
(¢/kWh)
Residential Non‐Electric Space Heating 6.511 6.359 7.810 7.628 7.147 6.980
Residential Electric Space Heating 5.179 3.931 6.212 4.715 5.685 4.315
Watt‐hour Non‐Electric Space Heating 6.661 6.474 7.926 7.704 7.302 7.097
Demand Non‐Electric Space Heating 6.568 6.431 7.815 7.652 7.200 7.050
Nonresidential Electrical Space Heating 6.262 6.161 7.452 7.331 6.865 6.754
Dusk to Dawn Lighting 2.370 2.831 2.835 3.386 2.587 3.090
General Lighting 6.192 6.172 7.405 7.381 6.759 6.737
Figure 25: ComEd Rate Impact: Illustrative PECs Without RECs
Year Jun‐09 Jun‐10 Jun‐11
Customer Group or Subgroup
Summer
PEC
(¢/kWh)
Non‐summer
PEC
(¢/kWh)
Summer
PEC
(¢/kWh)
Non‐summer
PEC
(¢/kWh)
Summer
PEC
(¢/kWh)
Non‐summer
PEC
(¢/kWh)
Residential Non‐Electric Space Heating 0.078 0.076 0.027 0.025 0.007 0.006
Residential Electric Space Heating 0.061 0.047 0.021 0.016 0.005 0.004
Watt‐hour Non‐Electric Space Heating 0.079 0.077 0.027 0.026 0.006 0.007
Demand Non‐Electric Space Heating 0.078 0.076 0.027 0.027 0.007 0.006
Nonresidential Electrical Space Heating 0.075 0.073 0.026 0.026 0.006 0.006
Dusk to Dawn Lighting 0.028 0.034 0.009 0.012 0.003 0.003
General Lighting 0.073 0.073 0.025 0.026 0.006 0.006
Figure 26: ComEd Rate Impact: Calculated REC
Jun‐09 Jun‐10 Jun‐11
Annual Average Overall Bill
¢/kWh
Annual Average Overall Bill
¢/kWh
Annual Average Overall Bill
¢/kWh
Residential Delivery Classes
With
RECs
Without
RECs
RECs as % of
Total Bill
With
RECs
Without
RECs
RECS as % of
Total Bill
With
RECs
Without
RECs
RECS as % of
Total Bill
Single Family No Electric Space Heat 11.19 11.12 0.69% 12.55 12.52 0.21% 12.53 12.53 0.05%
Multi Family No Electric Space Heat 12.56 12.49 0.61% 13.96 13.94 0.18% 13.70 13.70 0.05%
Single Family With Electric Space Heat 7.67 7.62 0.65% 8.56 8.55 0.20% 8.07 8.07 0.05%
Multi Family With Electric Space Heat 8.21 8.16 0.61% 9.19 9.17 0.19% 8.56 8.56 0.05%
Overall Residential 11.11 11.04 0.67% 12.46 12.44 0.20% 12.36 12.35 0.05%
Nonresidential Delivery Classes
Watthour 12.46 12.38 0.63% 13.81 13.79 0.20% 14.29 14.28 0.04%
Small Load (< 100 kW) 9.49 9.41 0.81% 10.72 10.69 0.25% 10.66 10.66 0.06%
Figure 27: ComEd Rate Impact: Calculated Bill Impacts of RECs119
119 Overall bill includes fixed supply charges, PJM services charges, delivery services charges (customer charge, standard metering service
charges, distribution facilities charges), other environmental cost recovery and energy efficiency & demand adjustments, and franchise cost
additions. Municipal and state taxes are excluded.
Jun‐09 Jun‐10 Jun‐11
Annual Average Overall Bill
¢/kWh
Annual Average Overall Bill
¢/kWh
Annual Average Overall Bill
¢/kWh
Residential Delivery Classes
With
RECs
Without
RECs
Total Dollar
Impact
With
RECs
Without
RECs
Total Dollar
Impact
With
RECs
Without
RECs
Total Dollar
Impact
Single Family No Electric Space Heat 11.19 11.12 18,582,034 12.55 12.52 6,593,738 12.53 12.53 1,479,872
Multi Family No Electric Space Heat 12.56 12.49 3,715,327 13.96 13.94 1,389,117 13.70 13.70 303,030
Single Family With Electric Space Heat 7.67 7.62 438,849 8.56 8.55 86,042 8.07 8.07 36,246
Multi Family With Electric Space Heat 8.21 8.16 928,246 9.19 9.17 167,409 8.56 8.56 75,508
Overall Residential 11.11 11.04 12.46 12.44 12.36 12.35
Nonresidential Delivery Classes
Watthour 12.46 12.38 458,803 13.81 13.79 156,180 14.29 14.28 31,140
Small Load (< 100 kW) 9.49 9.41 7,520,576 10.72 10.69 2,406,481 10.66 10.66 423,360
Figure 28: ComEd Total Dollar Impact: Calculated Bill Impacts of RECs120
120 From Figure 27 and IPA Procurement Plan Load Forecasts.
Appendix 3
Market Price Simulator (MarSiTM)
Market Price Simulator (MarSiTM)
1. Introduction to MarSi
MarSi is a simulation software package for the actual operation of integrated electricity
and natural gas systems under a wide range of operating conditions. MarSi is developed
by Global Energy Market Solutions (GEMS), Inc. and runs on a single Windows-based
computer. MarSi can optimize security constrained short-term and long-term generation
scheduling, resource allocation, and integrated generation and transmission
maintenance scheduling. MarSi can be used in an electricity market environment or by a
vertically integrated utility for assessing the power system operation strategies and
identifying system bottlenecks that stem out of the interdependency of electricity and gas
infrastructures. The modeling capabilities, input/output characteristics, and potential
applications of MarSi are outlined as follows.
Modules of MarSiTM
 AC Security-Constrained Unit Commitment (SCUC)
 AC Security-Constrained Optimal Power Flow (SCOPF) and Settlement
 LMP Calculation and Settlement
2. Modeling Capabilities of MarSi
MarSi has unique capabilities for the short-term modeling of generating units, electricity
network, and gas network.
1. Generation Resource Management
MarSi has the capability of modeling various types of generation units with very detailed
operating constraints. MarSi accepts both hourly generation bids (stepwise or piecewise
linear, for market-based operation) and generation cost curve (quadratic or piecewise-linear,
for integrated utilities).
 Generation Unit Data
 Scheduled outage parameters
 Thermal units: generation limits, incremental heat rate curves, minimum
up/down times, ramp up/down rates, start-up cost characteristics, multiple
emission constraints, multiple fuel constraints, must on/off, and other operating
constraints
 Wind and Pumped-storage hydro units: Wind unit characteristics, water-conversion
coefficients, volume limits, initial and terminal volumes, discharge
limits, cycle efficiency
 Combined-cycle units: generation limits, incremental heat rate curves, minimum
up/down times, ramp up/down rates, start-up cost characteristics for each
CT/ST configuration, multiple-emission constraints, multiple-fuel constraints, must
on/off, and other operating constraints
 Fuel switching units: heat rate curve for each possible fuel, generating capacity,
minimum up/down time, ramp up/down rates, start-up cost characteristics for
each fuel type, fuel and emission constraints, must on/off conditions
 Cascaded hydro units: topology, water-conversion coefficients, volume limits,
initial and terminal volumes, discharge limits, natural inflows, spillage, delay times
 Generation outage schedule
 System Level Data
 Hourly load forecast
 Spinning reserve requirements
 Operating reserve requirements
 Interruptible loads (cost and schedule)
 Fuel constraints (for all fuel types and individual units)
 Regional emission limits
2. Transmission System Management
MarSi has the capability of modeling full ac electricity network constraints.
 Line flow and bus voltage limits
 Tap-changing and phase-shifting transformers
 Multiple contingencies constraints
 Preventive action and corrective actions for transmission system security
 Transmission outage schedule
3. Gas Network Management
MarSi has the capability of modeling a comprehensive gas network pipelines and gas
network constraints.
 Each pipeline is modeled by several firm and interruptible gas contracts
 Each pipeline may feed several units / generating plants
 Location of pumping stations and pipeline distances (units further down can only
burn a percentage of the total gas in the pipeline)
 Daily and hourly gas limits for each pipeline, each sub-area, each plant, and each
unit.
3. Output Capabilities of MarSi
MarSi optimizes the hourly operating modes of generating units and determines fuel
allocations depending on generating unit, electricity network, and gas network
constraints. Typical output from MarSi include
 Hourly commitment and MW generation dispatch of generating units
 Hourly operating mode (combination of CTs and ST) for combined-cycle units
 Hourly fuel allocation (gas or oil) for each unit with fuel-switching capabilities
 List of constrained electricity transmission lines
 Short-term gas consumptions per pipeline, gas contract, subarea, plant, generating
unit
 List of binding gas constraints for pipelines, gas contracts, subarea, plant, and
generating unit
 Fuel and emission allowance allocation
 Simulation of long-term locational marginal price (LMP)
 LMP-based market scenario analyses.
4. Potential Applications of MarSi
MarSi can be used in a wide variety of scenarios.
(1) Market environment
MarSi can be used by RTOs/ISOs for the daily market simulation as well as the coordination
of generation and transmission outage management.
 Provide market clearing and settlement for the day-ahead market (maximizing
social welfare)
 Optimize long-term generation and transmission outage management.
(2) Integrated utilities
MarSi can be used by vertically integrated utilities for the simulation of optimal daily
operation and the coordination of long-term maintenance scheduling constraints with
short-term operation constraints
 Providing optimal day-ahead or long-term unit commitment and fuel schedule to
minimize system operating cost
 Providing optimal long-term generation and transmission maintenance schedules.
(3) Simulation of interdependencies
MarSi can be used to simulate the interdependency of electricity and natural gas
infrastructures for supporting the social sustainability of energy systems. The following
electric supply risk constraints are examples of such interdependencies that can be
simulated by MarSi:
 Limited gas supply or interruptible gas contracts may impact the dispatch of gas-fired
generating units without dual fuel capability
 An interruption or pressure loss in gas transmission systems could lead to a loss of
multiple gas-fired electric generators and their hourly dispatch
 Outages in gas transmission systems, and inconsistent strategies for the control,
monitoring, and curtailment of energy system infrastructure could lead to additional
outages and further constrain the daily operation of power systems.
Hourly Unit Commitment
Hourly Security-constrained Dispatch and LMPs
Hourly Gas Allocation
For additional information on MarSi, please contact
Global Energy Market Solutions (GEMS), Inc.
10 West 35th Street 10E9
Chicago, IL 60616
ms@gemsenergy.com