The Illinois General Assembly is considering legislation to require Illinois consumers to fund the construction and operation of another coal gasification plant, the “Taylorville Energy Center” (TEC), proposed by Nebraska-based Tenaska, Inc. Passage of SB678 would be the third legislative authorization of a coal gas project in the past year, each to be funded through decades of mandatory energy purchases by Illinois residents and businesses. Never before has the General Assembly required consumers to pay for the construction of specific power plants. As the state legislature is poised to consider funding TEC-- the largest and most expensive of the three coal plants – this report analyzes the cumulative financial impact of these mandates on Illinois consumers.
The plants approved in 2011 – to be built by Leucadia National Corporation and Power Holdings LLC – will produce synthetic natural gas (SNG) from coal, while TEC would produce both synthetic natural gas and electricity.1 Each of the three plants would be designed to allow separation and underground storage of a portion of their carbon dioxide emissions. However, none of the projects are bound by their promises to capture carbon dioxide and none have enforceable CO2 emissions limits.
Illinois utility customers would be required to buy the plants’ energy output over a period of decades, at a price sufficient to exceed their costs and assure their owners a substantial profit. How much Illinois consumers will ultimately pay for these plants depends on the performance of two sets of variables over the contract periods: the cost of building, fueling and operating the facilities versus the cost of alternative market-based power. Using publicly available energy market data and information provided by the developers of the projects, state regulators, and independent experts, this report projects the eventual net costs of the three coal gasification plants under existing and proposed statutes.
The projected above-market costs for the three coal plants amounts to $8.1 billion over their first decade of operation, an average of $803 million per year in higher energy costs than would otherwise be paid by Illinois residents and businesses. Using futures market data inflated at historically average levels to project market prices, the total above-market costs to be borne by Illinois consumers over the contract lifetimes project to $21.3 billion. About half of the above-market costs are associated with the Tenaska plant, the most expensive of the three and the only one still awaiting legislative approval. When all three plants are operating, residential customers can expect to see a first year rate increase totaling $458 million.2 Over the first decade of operations, projected residential rate hikes total $1,413 per household.3
Coal Gasification and Job Creation
Mandatory consumer-funding of coal gasification plants is intended by the General Assembly to create jobs, particularly in the coal mining industry in central and southern Illinois. However, the economic viability of these plants has plummeted with the falling price of natural gas, and the projected consumer subsidies that will be needed to finance and operate them are ballooning.
According to the developers, construction jobs to build the plants will total 4,600 for maximum periods of 3.5 years. Based on the developers’ estimates of coal usage, 1,552 long-term jobs would be created in the coal industry and in operation and maintenance of the plants. However, an accurate accounting of the net jobs effect would also take into account the consequences of redirecting potentially billions of Illinois consumer dollars into higher energy costs instead of discretionary spending. A full assessment would also include the effects of higher energy bills for Illinois employers and units of government, and resulting increases in property and/or sales taxes to cover these costs. Even if there were no such offsetting job effects to diminish the economic value of the plants, the estimated subsidy for each directly created new job averages $449,000 per job-year over the life of the contracts.
TEC’s net costs are the highest of the three facilities, with subsidies estimated to average $531,000 per job-year. After construction is completed, the $353 million projected average annual subsidy for Tenaska amounts to $945,000 per year for each of its 374 long-term jobs.
Illinois Gas and Electricity Sources and Markets
By law, utilities in Illinois purchase both natural gas and electricity in competitive wholesale markets or source them in competitive bidding processes, before reselling to consumers without markup. Utilities in the state do not own or operate production facilities. Since initial passage of electric industry restructuring legislation in 1997, Illinois retail energy markets
"All customers of large Illinois utility companies, regardless of supplier, would pay higher energy costs to fund the three new coal plants"
have grown steadily, providing all customers of large utility companies the opportunity to buy from alternative providers. All utility natural gas customers may also purchase from non-utility retail suppliers. Utilities no longer are suppliers to large commercial and industrial electricity customers, as those markets have been deemed fully competitive by the general assembly and the Illinois Commerce Commission (ICC). Regardless of who supplies the energy, utilities remain its distributors and are responsible for providing reliable service to all customers. In the March 2012 primary election, more than 200 communities voted to authorize their local governments to procure electricity on behalf of “aggregated” residents and small businesses. Even before any of these communities move to alternative suppliers, data maintained by the Illinois Commerce Commission (ICC) shows that 411,000 residential customers have switched to the competitive retail electricity market as of April 1, an 84% increase in the first four months of 2012.4
Electric energy is bought and sold in short-term wholesale markets operated by PJM and MISO, the regional system operators covering the ComEd and Ameren service territories. Longer-term energy futures are traded in commodity markets, such as NYMEX. The regional system operators are also responsible for maintaining market mechanisms to assure sufficient generating capacity and reserve margins. The combined peak capacity of PJM (170,481 MW) and MISO (144,400 MW) totals about 315,000 MW, of which TEC’s net peak capacity of 544 MW would represent less than one fifth of 1% (.0017).5
Competition at the wholesale and retail levels has been beneficial to Illinois. Over the 15 years since the introduction of competitive electricity procurement, Illinois electricity costs have moved from 13% above the national average to 10% below the national average.6
Under the coal gasification cost recovery mechanisms, legislated separately for each plant, excess costs will not be uniformly spread among utility customers and could cause distortions in Illinois retail energy markets. In the case of the pending Tenaska legislation, a cap on the amounts paid by residential customers is intended to limit their rate hike exposure. However, responsibility for much of the remaining above-market costs of building and operating the plant would be transferred to commercial and industrial customers, who would have little cost protection under the proposed legislation.7
All customers of large Illinois utility companies, regardless of supplier, would pay higher energy costs to fund the three new coal plants -- how much higher and for how long a period depends on the difference between the ultimate cost of energy from these facilities and the cost of equivalent market-priced energy products.
Market Energy Prices and Prospects
The “Henry Hub” spot market price of natural gas averaged $2.18/MMBtu in March, 2012, and fell below $2/MMBtu in April.8 The Energy Information Administration forecasts 2013 prices averaging $3.40/MMBtu.9 While prices may rise over time, many observers believe that new gas production technologies, along with increased energy efficiency, reduced industrial demand, and warmer winters may mean a very long period of relatively low market prices. Even with a glut of natural gas production and record amounts in storage, the surplus continues to grow because natural gas is usually a byproduct of oil drilling, which is at a 25-year high. That’s why natural gas to be delivered in 2020, eight years down the road, is selling today in the futures market for just over $5/MMBtu.10 In contrast to the falling price of natural gas, the price of coal has been rising, largely due to increased export demand in a growing global market.11 Higher coal prices have the effect of increasing the cost to fuel the coal gasification plants, while lower natural gas prices reduce the value of the SNG produced. Because of relatively high production costs and high BTU content, Illinois coal is 39% more expensive than the national average.12
Power for utility customers is bought through a competitive procurement process conducted by the Illinois Power Agency (IPA) that resulted in average energy costs of $36.40/MWh for ComEd and $42.33/MWh for Ameren for resources procured in the year ending 5/31/2012.13 Long-term contracts approved by the General Assembly in 2007, when market prices were higher, add to the current retail utility prices.14 Wholesale electricity prices are continuing to fall with the declining price of natural gas, the key fuel for electricity production in peak demand periods. The combination of declining prices and the end of the long-term contracts is expected to reduce utility prices as new supplies are procured in 2012 and 2013. Current futures market electricity prices contrast dramatically with the projected costs of energy from the Tenaska project, which the Illinois Commerce Commission estimated to average $213/MWh over the life of the plant. Levelized TEC costs would begin at 357% higher than inflation-adjusted market energy procurement prices for Ameren and ComEd. Over the probable TEC production period of 2017 through 2046, costs for its electricity would average 230% higher than the projected average market-priced procurement of $67/MWh.
Plant Net Cost Analyses
Planned for construction by New York-based Leucadia National Corporation on the site of an old steel mill in Chicago, the “Chicago Clean Energy Project” will produce synthetic natural gas (SNG) from refinery waste and coal.15 Because of the high financial and operational risks of such a facility, it would not be built without a legislative guarantee that its output will be paid for by customers of Illinois gas utility companies for thirty years. The ultimate price to be paid by consumers for Leucadia’s SNG can’t be known because of variables including the cost of coal and fuel feedstock, the interest rate on money borrowed to pay for construction, and the cost of carbon sequestration. All current projections, including those of the developer, indicate that costs to Illinois consumers in the initial decade of production are likely to be far above the current and projected market value of natural gas.
The Illinois Commerce Commission has approved a capital cost of $2.94 billion to build the plant, and Operation and Maintenance costs of $1.88 per million Btu (MMBtu). Total costs estimated by the plant’s developer and spread over the output of the plant amount to $7.35/MMBtu, not including the costs of carbon sequestration and storage, an essential component of the plan. This experimental technology, which has never been deployed at commercial scale, may add a significant but unknown increment to average levelized costs, conservatively estimated here at $1/MMBtu.16 This report therefore estimates the total cost of SNG to be produced by Leucadia as $8.35/MM Btu (in 2010 dollars). The gross cost to Illinois consumers would begin at $415 million in 2017 and escalate each year.17 The net cost paid by customers would be the gross cost minus the market cost of gas, which is projected here using futures market data and historical inflation rates. The gap between today’s spot market gas prices and the likely cost of Leucadia gas is in the range of $6/MMBtu. This gap may shrink over time, but to eliminate excessive costs to customers actual prices at the time of delivery would have to be twice the amount predicted by the futures market.
Even if sometime over the thirty-year term, market prices for natural gas rise above the cost of SNG from Leucadia,
consumers are likely to pay substantial rate hikes in the initial years of the Leucadia contract. In order to address this probable outcome, the legislation provides that rates cannot go up by more than 2.015% in any year to pay for the plant, and the developer is required to set aside $150 million in a “consumer protection reserve account” to pay for costs above the maximum allowable annual rake hike, which Leucadia has calculated as beginning at $174 million. However, the potential consumer rate hike percentage may turn out to be higher than the cap percentage, because the cap is calculated based on a five-year inflation-adjusted average of utility revenues ending in 2010, and gas usage has declined since that period. Assuming average inflation, the $201 million rate hike allowed under the cap in 2017 (when the facility is likely to begin production) would amount to 3.1% relative to 2010 utility revenue.18
The “Leucadia” law has a novel provision that allows utilities a choice of whether or not to purchase Leucadia’s SNG. If a utility signs a contract with Leucadia, it is held harmless for all costs and its customers become obligated to buy the SNG for 30 years. If a utility elects not to buy from Leucadia, it is required to have its gas delivery rates reviewed by the Illinois Commerce Commission three times in the next five years. Because utilities file rate cases only when they believe they can justify rate increases and mandatory rate cases would expose them to potential rate cuts, all utilities were expected to sign up with Leucadia. However, while Nicor and Ameren opted to enter into Leucadia “sourcing agreements,” Peoples Gas and its North Shore Gas affiliate, which serve Chicago and several northern suburbs, chose rate reviews.
Leucadia now asserts that customers of Nicor and Ameren should be required to make up all the costs that Peoples would have paid and it will be up to the courts and perhaps the legislature to decide this issue. But another avenue to recover 100% of Leucadia’s costs from Illinois customers may be paved by the pending Tenaska legislation. SB678 (to be discussed later in this report) has a provision that allows 16% of the output of the Leucadia plant – the amount that would have gone to Peoples – to be purchased to fuel Tenaska’s electricity production. The rate hikes associated with this portion of Leucadia could thereby be transferred from Illinois gas customers to Illinois electric customers.
Projected Rate Increases to Pay for Leucadia
Using the company’s calculation of $174 million as the starting point for the maximum rate hike (in 2010 dollars, which projects to $201 million by an in-service date of 2017), Leucadia could cost Illinois consumers as much as $8.5 billion over the 30-year contract term.19 Based on current futures market prices, historical average inflation rates, and the company’s own cost projections, the projected above-market costs for SNG from Leucadia would total $2.4 billion over the first decade of operation.20 Approximately 67% of the rate hike would be paid by residential customers, who use 42% of the total gas throughput but pay higher distribution rates than larger volume customers.21 This equates to an average rate increase of $446 per household during the plant’s first decade.
Based on the ICC’s projection of 42,064,500 MMBtus of Leucadia output to be purchased by Illinois customers, the rate hike cap would initially allow $4.78/MMBtu in above-market costs to be charged directly to consumers. This means SNG from Leucadia initially could be priced at more than three times the price most Illinois consumers pay for gas today, without exceeding the rate cap.22 If actual above-market costs for Leucadia were higher than that amount, any remainder would be paid out of a $150 million “consumer protection reserve account” set up by Leucadia. After inflation, the rate cap itself is projected to reach $250 million by the end of the plant’s first decade. However, even that level of allowable annual rate hike may not be sufficient to pay for Leucadia’s SNG. If its costs remain almost double today’s futures market prices for 2017 (when the plant is expected to begin production), the reserve account could disappear in the first few years of operation. The law does not directly address what would happen if the account were exhausted. For the purpose of calculating the Leucadia-related rate hike exposure of consumers, this report assumes that the rate cap amount represents the maximum exposure of consumers and any remaining costs after depletion of the account would be covered by the plant’s owners.
In explaining why it declined to enter into SNG contracts, Peoples/North Shore Gas, the smallest of the three gas utilities to which the law applies, estimated that the combined cost of Leucadia and Power Holdings (discussed below) would add 9% to the cost of gas for its customers over the first decade of their production, a ten-year increase of more than $1 billion for a company providing just 25% of the state’s gas service.23
Unlike in the case of a facility owned by a regulated public utility, customers will undertake the risks of the Leucadia project without receiving all of its potential benefits. Under the law, if market gas prices ever were to rise sufficiently to make Leucadia’s SNG cost-effective, the company would share in any additional profits above its cost of capital, even though utility customers bear most of the risk at the outset. After the first two years of operation, Leucadia’s owners will receive 50% of any net “savings,” and 100% of such savings up to a total of $150 million, if consumers ever reach an overall break-even point on the plant’s costs. It is only after 30 years, calculating retrospectively, that consumers are “guaranteed” $100 million in savings, an amount dwarfed by the multibillion dollar costs of the project.
Power Holdings of Illinois, LLC
The General Assembly passed separate legislation in 2011 to support another SNG plant to be located in Jefferson County.24 Like the Leucadia plant, “Power Holdings of Illinois” will produce synthetic natural gas from coal, to be sold to Illinois consumers at prices that may far exceed wholesale market prices for gas. Power Holdings’ plan includes sequestration of carbon dioxide produced by the coal gasification process, however, the law allows the company to make penalty payments toward energy efficiency programs instead. Because these penalties are capped at $20/ton and can’t exceed $40 million in any year, the plants’ owners may find it less costly to pay the penalties than to capture and sequester the carbon dioxide emissions.
Under the same opt-out provision as in the Leucadia legislation, Peoples/North Shore Gas has elected to undergo regular rate reviews in coming years instead of signing contracts with Power Holdings, while Nicor and Ameren have chosen to purchase the SNG. Initial utility contracts with Power Holdings are limited to ten years under the law and the amount purchased is limited to 15% of the annual system throughput. Because of this limitation, which is not included in the Leucadia legislation, the opt-out by Peoples leaves Power Holdings with 29% of the plant’s output to be sold to non-utility purchasers.
Capital costs to construct the plant are estimated by Power Holdings at $2.3 billion. Costs to consumers for the SNG output is set by the legislation to start at $6.50/MMBtu and after inflation adjustment may not reach more than $9.95 during the first decade of operation. Based on maximum volumes, current futures market prices, and historical average inflation rates, costs to consumers would reach $8.08/MMBtu and above-market costs for SNG would total $2.2 billion over the ten-year contracts with Power Holdings. For an average residential customer, the rate increase projects to $585 for the 10-year contracts. At the end of the contracts, if customers have paid more for the SNG than they would have paid for market-priced gas, the company is required to reimburse them over a period of 15 years, or sell the plant and distribute the proceeds. In this way, the law attempts to ensure that 25 or 30 years from now, tomorrow’s consumers are paid back for expenses incurred today. However, there would likely be little money realized from the operation or sale of the plant if the cost of its SNG were to remain above market prices in the long term, casting doubt on whether this intended consumer protection would be of significant value.
Tenaska (Taylorville Energy Center)
The Taylorville Energy Center (TEC) would be built in Christian County by a joint venture led by Tenaska, a Nebraska-based energy company. Like Leucadia and Power Holdings, it would gasify Illinois coal to produce “pipeline quality” SNG. As a hybrid “Integrated Gasification Combined Cycle” (IGCC) plant, TEC would sometimes use SNG to generate electricity, while at times it would sell the SNG in the natural gas market. To operate at full capacity, the electric generating plant would need to augment its SNG production by purchasing conventional natural gas, raising its maximum electricity output by 70%.25 Even with a high percentage of the electricity produced with conventional gas purchased at market prices, a study by the ICC (undertaken at the direction of the General Assembly in 2010) found that the levelized costs of electricity from TEC would average $213/MWh over the lifetime of the plant. This would be far higher than current forecasts by the Energy Information Administration (EIA) for power from alternative sources, including wind ($97), nuclear ($114), conventional coal ($95), or conventional combined cycle natural gas ($66).26 Tenaska’s projected costs are more than five times as high as today’s market energy procurement costs for ComEd and Ameren of about $40/MWh.30 The actual costs to build TEC are not yet known, and there are no comparable plants in operation. Tenaska initially estimated TEC’s capital costs at $3.5 billion, and the ICC found that amount to be a reasonably accurate forecast.27 The actual capital costs to be recovered in consumers’ electricity rates would be subject to ICC proceedings involving the state’s Capital Development Board and could be adjusted to account for changes in prospective construction costs.28 A similar facility under construction in Indiana has experienced more than $1 billion in cost overruns. Under SB678, one-third of cost overruns could be passed on to consumers, as could additional post-construction capital additions and equipment replacements.
Estimated costs for TEC do not include any costs of carbon sequestration. Tenaska asserts that carbon capture and storage may be accomplished at zero net cost by selling the carbon dioxide and sending it through a yet-to-be-built pipeline to oil fields in Louisiana, where it could be used for enhanced oil production. Such a pipeline is not currently under construction or being actively planned. This technology has never been deployed at commercial scale, and the Indiana plant has reported that capturing 23% of its carbon dioxide emissions would add $380 million to its capital costs (not including costs to store the carbon).29 TEC will be designed to capture at least 50% of its carbon emissions, which may add significantly to costs. However, SB678 does not require the plant to actually succeed at sequestering carbon dioxide. The maximum penalty to be paid by Tenaska is set by the law at $20 million per year, plus a reduction in its profits if the ICC finds that it “willfully fails to” sequester carbon. Tenaska may eventually decide not to sequester carbon at all because it is less costly to pay the penalties.
Assuming no inflation in construction costs or additional carbon sequestration costs, the ICC estimated TEC’s total costs at $763 million per year, and its annual premium above the cost of market-based energy to average $296 million over 30 years.31 A consultant working for Tenaska estimated the annual premium at $309 million.32 However, during the two years since those studies were conducted, market natural gas prices have plunged. Using more recent data, but still assuming no additional costs beyond those projected by the developer, a study by the NorthBridge Group forecast an annual Illinois electricity rate increase of $400 million to pay TEC’s costs.33 Using current market price data, the estimated premium rises to $410 million. For the purpose of estimating the above-market premium for TEC’s production, this report uses the average of the high and low of these analyses, $353 million per year.
The projected rate increase for residential electricity customers of
Ameren and ComEd amounts to $1.7 billion in Tenaska’s first decade of
operation. An average household would see a total of $382 in higher
electric rates, not including potential cost overruns.
Proponents of the “clean coal” plants assert that they are like the renewable energy resource requirements under which electric utilities buy wind and solar power. However, unlike the coal gasification mandates, Illinois laws to promote renewable energy and energy efficiency contain firm and predictable caps on the maximum costs each year to consumers. There are other crucial differences between renewable resource development and coal gasification. Wind and solar:
Are proven technologies with declining costs that are already far lower than coal gasification;
Produce no pollutants nor hazardous waste, do not use water resources or deplete natural resources, do not cause the environmental damage associated with coal mining, nor do they contribute to global climate change.
Are available in small increments of additional capacity as needed;
Are competitively sourced from multiple providers under Illinois law.
Legislation authorizing construction of the three coal gasification plants amounts to a series of bets, made largely with Illinois consumer dollars, that certain future conditions will be met:
Market energy prices, particularly for natural gas, will rise dramatically in coming decades;
Energy demand will rise steadily, despite advances and investment in energy efficiency and smart grid deployment;
The federal government will enforce significant reductions in carbon dioxide emissions;
The new technologies employed by these plants will work as intended;
Less costly methods of energy production (including from Illinois coal) will not develop.
While some of the above conditions may occur, under conditions existing today these three facilities represent highly speculative and expensive long-term commitments for which the companies themselves bear little risk. Moreover, the legislation and permits governing the plants’ operations suggest that the environmental benefits touted by the plant operators are not likely to materialize. To the extent that lawmakers seek to fund long-term demonstrations of experimental uses of gasification technology, such endeavors should appropriately be undertaken through public-private partnerships, such as the “Futuregen” project, which spread risk to potential beneficiaries instead of putting them on the backs of Illinois energy consumers.
1PA 97-0096 became effective on July 13, 2011, and PA 97-0329 became effective on August 2, 2011.
2The in-service dates are not known, but all three plants are expected to be finished by 2017. 3For customers of Peoples/North Shore, which has about ¼ of
the state’s gas customers and has thus far declined to sign contracts
for synthetic gas, the rate hike would be lower and only include Tenaska
5See 2011 PJM State of the Market Report, and 2010 MISO State
of the Market Report:
6EIA data at http://www.eia.gov/electricity/data/state/
7SB678 includes a complicated provision to calculate
commercial/industrial rate hike limits, but the actual amount customers
may pay is open-ended. Increases in variable market-based costs, such as
fuel, that turn out to be higher than initially predicted by Tenaska in
its “reference case,” would be passed through to customers regardless
of rate impact but these increases would not count when calculating the
rate hike that is “deemed” to have occurred. Other changes in operating
and capital costs would not be passed through unless they total more
than $50 million in a year.
8Gas is sold to consumers by the “therm”, a measure of heat
content equal to 100,000 BTUs (British Thermal Units). The price of gas
is typically expressed in dollars-per-million-BTUs or dekatherms.
9EIA data at http://www.eia.gov/forecasts/steo/report/natgas.cfm
11EIA data: http://126.96.36.199/state/state-energy-profiles-data.cfm?sid=IL#Prices
12IPA 2011 Annual Report http://www2.illinois.gov/ipa/Documents/IPA_Annual_Report_2011_final.pdf.
13Electric energy is sold in wholesale markets by the
megawatthour (MWh), which equals 1,000 kilowatt-hours or 1,000,000
watthours. 14Retail prices also include capacity payments and
transmission services. However, an apples-to-apples approach requires
comparison of market energy prices with projected costs of the
gasification plants’ energy output.
15The Leucadia legislation, PA 97-0096, requires that at
least 50% of the feedstock be coal, unless it’s less expensive to use
petroleum coke, in which case the minimum coal percentage falls to 35%
16Leucadia’s projected annual costs for carbon sequestration
technology have not been publicly detailed. Separation of the carbon
stream occurs as part of the SNG process, but compression,
transportation, and storage costs are incremental. Assuming a minimal
net additional cost of $10 per ton of carbon dioxide to sequester,
transport and maintain storage, and Leucadia annual usage of 1.5 million
tons of coal and an equivalent amount of petroleum coke, the cost for
sequestering 90% of the carbon that would be removed from the feedstock
(part would remain in the SNG) would amount to roughly $40 million/year.
Based on the ICC’s estimate of annual output of 42,064,500 MMBtu, the
sequestration cost would be about $1/MMBtu. This is of necessity a
general estimate and the developers have not submitted information as to
the estimated net carbon sequestration costs, which would include total
costs minus potential revenue if the carbon dioxide can be transported
and used for enhanced oil recovery, a highly speculative outcome at this
17Assuming in-service date 0f 1/1/2017 18Inflation averaging 2.433% annually over decade ending in 2011, as per Bureau of Labor Statistics 19See “Substitute Natural Gas Purchase and Sale Agreement” as
filed with ICC in docket 11-0710:
http://www.icc.illinois.gov/docket/files.aspx?no=11-0710&docId=175143 20Assuming inflation of 2.43% and production beginning in 2017. 21See Nicor, Ameren, and Peoples Cost of Service Studies filed in ICC dockets 11-0282, 09-0167 and 08-0363 22The Purchased Gas Adjustment (PGA) price varies widely
between utilities because of their purchasing practices and contracts.
For May, 2012, the Nicor PGA is 22 cents/therm, while the Ameren
companies average over 60 cents/therm. See:
http://citizensutilityboard.org/pga.php 23See http://www.chicagobusiness.com/article/20110909/NEWS11/110909877 24Public Act 097-0239 25The ICC “Analysis of the Taylorville Energy Center Facility
Cost Report” states that of the 602 MW initially planned as peak net
capacity, 354 MW would be produced by SNG and 248 MW from
http://188.8.131.52/oiaf/aeo/electricity_generation.html 26This amount does not include the utility’s costs for
connecting to the plant, which would add to utilities’ regulated revenue
requirements. 27http://newsandtribune.com/local/x94877848/Duke-Energy-seeks-to-pass-cost-overruns-to-customers 28See
and http://www.sourcewatch.org/index.php?title=Edwardsport_Plant 29See “ICC Analysis of Taylorville Energy Center Facility
Cost Report” Attachment B
http://www.icc.illinois.gov/electricity/tenaska.aspx 30End user costs also include capacity charges. 31See ICC TEC Report and “PACE Global Energy Services Rate
Impact Analysis for Taylorville Energy Center”, Exhibit 10.0 at