ERCOT Public November 17, 2014

ERCOT Analysis of the

Impacts of the Clean Power Plan
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 1

ERCOT Analysis of the 

Impacts of the Clean Power Plan 

The Electric Reliability Council of Texas (ERCOT) is the independent system operator (ISO) for the Texas 

Interconnection, encompassing approximately 90% of electric load in Texas. ERCOT is the independent 

organization established by the Texas Legislature to be responsible for the reliable planning and 

operation of the electric grid for the ERCOT interconnection. Under the North American Electric 

Reliability Corporation (NERC) reliability construct, ERCOT is designated as the Reliability Coordinator, 

the Balancing Authority, and as a Transmission Operator for the ERCOT region. ERCOT is also registered 

for several other functions, including the Planning Authority function.

In June 2014, the U.S. Environmental Protection Agency (EPA) proposed the Clean Power Plan, which 

calls for reductions in the carbon intensity of the electric sector. The Clean Power Plan would set limits 

on the carbon dioxide (CO2) emissions from existing fossil fuel-fired power plants, calculated as state 

emissions rate goals. For Texas, EPA has proposed an interim goal of 853 lb CO2/MWh to be met on 

average during 2020-2029, and a final goal of 791 lb CO2/MWh to be met from 2030 onward. EPA 

calculated the state-specific goals using a set of assumptions about coal plant efficiency improvements, 

increased production from natural gas combined cycle units, growth in renewables generation, 

preservation of existing nuclear generation, and growth in energy efficiency. 

ERCOT has evaluated the potential implications of the proposed Clean Power Plan for grid reliability and 

conducted a modeling analysis of the impacts to generation resources and electricity costs in the ERCOT 

region. Based on this analysis, ERCOT anticipates that implementation of the proposed Clean Power Plan 

will have a significant impact on the planning and operation of the ERCOT grid. ERCOT estimates that 

the proposed CO2 emissions limitations will result in the retirement of between 3,300 MW and 8,700 

MW of coal generation capacity, could result in transmission reliability issues due to the loss of 

generation resources in and around major urban centers, and will strain ERCOT’s ability to integrate new 

intermittent renewable generation resources. The Clean Power Plan will also result in increased energy 

costs for consumers in the ERCOT region by up to 20% in 2020, without accounting for the costs of 

transmission upgrades, procurement of additional ancillary services, energy efficiency investments, 

capital costs of new capacity, and other costs associated with the retirement or decreased operation of 

coal-fired capacity in ERCOT. This summary report describes the results of ERCOT’s analyses.

1. Summary of ERCOT Concerns with the Clean Power Plan

ERCOT approaches this analysis from the perspective of an independent grid operator in a competitive 

market which has achieved significant success in using competition to drive efficient outcomes. Existing 

market policies and investments in transmission in ERCOT have incentivized market participants to 

maximize the efficiency of the generating fleet and develop new technologies including renewable 

generation. With recent investments in transmission, more than 11 GW of wind capacity have been 

successfully integrated into the ERCOT grid. The ERCOT region maintains a forward-looking open market 

and provides affordable and reliable electricity to consumers in Texas.

ERCOT’s primary concern with the Clean Power Plan is that, given the ERCOT region’s market design and 

existing transmission infrastructure, the timing and scale of the expected changes needed to reach the 

CO2 emission goals could have a harmful impact on reliability. Specifically, implementation of the Clean 

Power Plan in the ERCOT region, particularly to meet the Plan’s interim goal, is likely to lead to reduced 

grid reliability for certain periods and an increase in localized grid challenges. There is a natural pace of 

change in grid resources due to advancing cost effective technologies and changing market conditions. 
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 2

This pace can be accelerated, but there is a limit to how fast this change can occur within acceptable 

reliability constraints. It is unknown based on the information currently available whether compliance 

with the proposed rule can be achieved within applicable reliability criteria and with the current market 

design. Nevertheless, there are certain grid reliability and management challenges that ERCOT will face 

as a result of the resource mix changes that the proposed rule will induce:

• The anticipated retirement of up to half of the existing coal capacity in the ERCOT region will 

pose challenges to reliable operation of the grid in replacing the dispatchable generation 

capacity and reliability services provided by these resources. 

• Integrating new wind and solar resources will increase the challenges of reliably operating all 

resources, and pose costs to procure additional regulating services, improve forecast accuracy, 

and address system inertia issues. 

• Accelerated resource mix changes will require major improvements to ERCOT’s transmission 

system, posing significant costs not considered in EPA’s Regulatory Impact Analysis.

These issues highlight the need for the final rule to include a process to effectively manage electric 

system reliability issues that may arise due to implementation of the Clean Power Plan, as well as 

include more implementation timeline flexibility to address each state’s or region’s unique market 

characteristics. With respect to the need to manage reliability issues, ERCOT supports the ISO/RTO 

Council (IRC) proposal for the inclusion of a reliability safety valve process in the context of the CO2 rule, 

as well the need for states to consult with ISOs/RTOs during the development of State Plans. 

2. Results of ERCOT Modeling

This summary report draws on results from an ongoing analysis of the expected impacts of several 

recently finalized and proposed environmental regulations on grid reliability in the ERCOT region. The 

study uses stakeholder-vetted planning processes and methodologies consistent with the regional LongTerm System Assessment studies conducted by ERCOT. A full report on this environmental regulatory 

impact study will be released in mid-December 2014. 

The sections that follow describe the modeling methodology and summarize the results from the 

modeling analysis. Next, the modeling results are compared to those obtained by EPA in its analysis of 

the Clean Power Plan. This is followed by a discussion of the impacts of these results for grid reliability 

and transmission infrastructure. The report concludes with a discussion of cost impacts.

2.1. Modeling Methodology

ERCOT evaluated the proposed Clean Power Plan using two methodologies. First, ERCOT considered a 

scenario with the Clean Power Plan limits applied as a constraint, to allow the long-term simulation 

model to select the most cost-effective way to achieve the proposed carbon intensity from electric 

generating resources. Second, a carbon emission fee was used to cause the system to achieve the 

proposed standard over the allotted compliance period. The benefit of the first approach is that it would 

be expected to minimize the overall cost to the system, and should lead to results that are comparable 

to the methodology utilized by the EPA in its analysis of the rule impacts. However, it may not be a 

change that is achievable within the current electricity market design in ERCOT. For this reason, ERCOT 

also modeled emissions fee scenarios. Though a carbon price is not an explicit component of EPA’s 

proposal, it is one option that Texas could use to comply with the limits, and is included here in order to 
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 3

assess the system impacts of a potential approach to compliance. In both cases, ERCOT evaluated the 

limits in the Clean Power Plan by applying the proposed emissions rate limits for Texas (in lb/MWh) to 

the ERCOT system.

ERCOT modeled four distinct scenarios over the timeframe 2015-2029 to evaluate the implications of 

the Clean Power Plan on reliability in the region:

1. Baseline – This scenario estimates a baseline of the ERCOT system under current market trends 

against which anticipated Clean Power Plan changes will be compared.

2. CO2 Limit – This scenario applied the limits in the Clean Power Plan to the ERCOT system to 

determine the most cost-effective way to comply with the limits. This scenario did not place a 

price on CO2 emissions.

3. $20/ton CO2 – This scenario applied a $20/ton price on carbon dioxide emissions to the ERCOT 

system. With a $20/ton CO2 price, the ERCOT system attains an emission intensity of 904 lb 

CO2/MWh in 2020 and 877 lb CO2/MWh in 2029 – above both the interim and final goals.

4. $25/ton CO2 – This scenario applied a $25/ton price on carbon dioxide emissions to the ERCOT 

system. With a $25/ton CO2 price, the ERCOT system attains an emission intensity of 840 lb 

CO2/MWh in 2020 and 792 lb CO2/MWh in 2029 – below the interim goal and approximately 

meeting the final goal.1

It should be noted that ERCOT did not require the system to maintain a specific reserve margin in the 

modeled scenarios. The target reserve margin criterion in ERCOT is not binding and it is possible that 

market conditions will result in a lower reserve margin than the recommended level. By contrast, EPA’s 

modeling, described later, required that ERCOT maintain a 13.75% reserve margin. This difference in 

assumptions results in different amounts of capacity additions, and has implications for grid reliability. 

This study uses stakeholder-vetted assumptions consistent with ERCOT’s Long Term System Assessment 

(LTSA).2 These assumptions include the anticipated expiration of the Production Tax Credit (PTC) and 

phase out of the Investment Tax Credit (ITC). Natural gas price projections are based on an average of 

the Energy Information Administration (EIA) Annual Energy Outlook (AEO) 2014 forecast and the 

forecast from Wood Mackenzie, shown in Figure 1. The same natural gas price assumptions were 

applied in all scenarios.

 1 ERCOT did not attempt to calculate a carbon price to precisely meet the emissions limits. Instead, ERCOT found a carbon price range within 

which the system is anticipated to achieve the Clean Power Plan emissions standards.

2 For more information, visit ERCOT’s Regional Planning Group (RPG) website at http://www.ercot.com/committees/other/rpg/index.html. 
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 4

Figure 1: Natural Gas Price Assumptions

ERCOT assumed capital costs consistent with those used in the LTSA, with the exception of solar capital 

costs. After review of information provided by stakeholders and updated reports by the National 

Renewable Energy Laboratory (NREL) and Lazard, it is clear that solar capital costs continue to decline at 

a rapid rate. To be more in line with these lower costs, solar capital costs were lowered in the near term 

years of this study to reflect this latest information. ERCOT estimated solar capital costs based on a 

review of information provided by Lazard,3 Solar Energy Industries Association,4 and Citi Research.5

Figure 2 displays the solar capital costs used by ERCOT in this analysis. Capital costs for all other 

generation technologies were taken from the EIA AEO 2014.

Figure 2: ERCOT Solar Capital Costs

 3 Lazard. Lazard’s Levelized Cost of Energy Analysis – Version 8.0, September 2014. Available from 

http://www.lazard.com/pdf/levelized%20cost%20of%20energy%20-%20version%208.0.pdf. 4 Greentech Media, Inc and Solar Industries Association. U.S. Solar Market Insight Report. Q1 2014. Confidential Report. 5 Citi Research. Launching on the Global Power Sector: The Sun Will Shine but Look Further Downstream. February 6, 2013. Confidential Report.

 $-

 $1.00

 $2.00

 $3.00

 $4.00

 $5.00

 $6.00

 $7.00

$/MMBTU

Year

Natural Gas Price Assumptions

 -

 500

 1,000

 1,500

 2,000

 2,500

$/KW

Year

ERCOT Solar Capital Costs
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 5

Table 1: Baseline Capacity 

Assumptions

Fuel Type Capacity (MW)

Nuclear 5,200 

Coal 19,900

Natural Gas 58,900

Wind 16,700

Solar 250

Hydro 500

Other 1,000

Total 102,450 

With regard to the generation fleet, ERCOT modeled the capacity listed in ERCOT’s May 2014 Capacity, 

Demand, and Reserves (CDR) report,6 with the addition of planned generation resources that had 

started construction by Summer 2014, as well as the full capacity of Private Use Networks (PUNs).7

 

Table 1 shows the baseline capacity assumptions used in the modeling. Generation from wind and solar 

resources was modeled based on wind and solar production profiles that estimate the amount of wind

and solar resources available for every hour of the year, based on the 2010 weather year. For wind, 

ERCOT used county-specific wind production profiles provided by AWS Truepower. The solar production 

profiles were provided by URS and are based on data from weather stations in West Texas. 

Within the scenarios, ERCOT varied some assumptions pertaining to 

implementation of the Clean Power Plan and compliance with other 

environmental regulations. First, scenarios 2-4 required compliance 

with the Cross-State Air Pollution Rule (CSAPR) limits, imposed as a 

limit in Scenario 2 and as an emission fee in scenarios 3 and 4.8 Second, 

due to data availability limitations, ERCOT was only able to model 

through 2029. In scenario 2, to approximate compliance with the final 

goal in the Clean Power Plan, ERCOT applied the final CO2 limit as a 

constraint over 2028-2029, and the interim CO2 limit over 2020-2027. 

In this scenario, the ERCOT interconnection was required to meet the 

applicable emission rate goal in each year; the other scenarios did not 

include this requirement. 

Finally, in the baseline scenario ERCOT assumed energy efficiency 

savings at 1% of load for all modeled years, consistent with current 

levels of energy efficiency as measured by the Electric Utility Marketing Managers of Texas (EUMMOT).9

For scenarios 2-4, ERCOT assumed growth in energy efficiency savings to a level of 5% by 2029. EPA’s 

building blocks assumed Texas could achieve a cumulative 9.91% savings from energy efficiency by 2029. 

ERCOT did not elect to use the energy efficiency savings level estimated by EPA because this level of 

energy efficiency is not consistent with current trends in energy efficiency in Texas.10 ERCOT’s more 

moderate assumption is consistent with the approach taken by the Mid-Continent Independent System 

Operator (MISO) in its analysis of the impacts of the Clean Power Plan.11 MISO modeled three energy 

efficiency assumptions: base energy efficiency trends, EPA’s Building Block 4, and 50% of EPA’s Building 

Block 4. ERCOT’s approach of using 5% is consistent with the third assumption modeled by MISO, and 

represents a moderate, and more realistic, energy efficiency growth assumption, between the current 

level of savings and EPA’s goal. 

 6 ERCOT’s Report on the Capacity, Demand, and Reserves in the ERCOT Region is available at 

http://www.ercot.com/gridinfo/resource/index.html. 7 In addition to PUN capacity, ERCOT also separately modeled PUN load.

8 ERCOT assumed an SO2 emission price of $800/ton, an ozone season NOx emission price of $1,600/ton, and an annual NOx emission price of 

$1,000/ton. ERCOT estimated these prices based on a series of model iterations as part of this study.

9 EUMMOT’s Energy Efficiency Accomplishments Report is available at http://www.texasefficiency.com/index.php/publications/reports. 10 For information about energy efficiency trends in Texas, visit the EUMMOT website at http://www.texasefficiency.com/. 11 MISO. GHG Regulation Impact Analysis, July 30, 2014. Available from 

https://www.misoenergy.org/Library/Repository/Meeting%20Material/Stakeholder/PAC/2014/20140730/20140730%20PAC%20Item%2012a%

20GHG%20Regulation%20Impact%20Analysis.pdf. 
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 6

Table 2: Unit Retirements by 2029

Generation 

Technology Type Baseline CO2 Limit

CO2

$20/ton

CO2

$25/ton

Retired Gas Steam (MW) 2,000 1,600 1,600 1,300

Retired Coal (MW) 800 4,100 4,100 6,500

Total Retirements (MW) 2,800 5,700 5,700 7,800

Table 3: Capacity Additions by 2029

Generation

Technology Type Baseline CO2 Limit

CO2

$20/ton

CO2

$25/ton

Wind (MW) 0 3,400 2,800 3,500

Solar (MW) 9,900 12,500 12,600 13,500

Combined Cycle (MW) 0 0 0 1,300

Combustion Turbine (MW) 4,600 1,000 1,000 1,000

Total (MW) 14,500 16,900 16,400 19,300

2.2. Summary of Modeling Results

The modeling results for the four scenarios indicate incremental unit retirements and incremental 

renewable capacity additions in the CO2 limit and carbon price scenarios compared to the baseline. In 

the CO2 limit and carbon price scenarios, the model retired 2,900 MW to 5,000 MW of capacity 

incremental to retirements in the 

baseline, as shown in Table 2. 

Most of the incremental 

retirements were coal units, with 

between 3,300 MW and 5,700 

MW of incremental coal unit 

retirements compared to the 

baseline. The amount of 

incremental coal retirements in 

the carbon scenarios is higher than the total amount of incremental retirements because of natural gas 

steam retirements that occur in the baseline but not in the carbon scenarios. The fewer retirements of 

natural gas steam units in the carbon scenarios reflects the impact of both the CSAPR and carbon 

dioxide limits on production from coal units, improving the economics of natural gas steam units during 

this period. Note that in the baseline, 800 MW of coal capacity retires, corresponding to the announced 

retirement of CPS Energy’s J. T. Deely units 1 and 2 in 2018. 

The CO2 limit and carbon price scenarios also resulted in between 5,500 and 7,100 MW incremental 

renewable capacity additions compared to the baseline, which itself saw 9,900 MW of new solar 

capacity.12 As noted previously, ERCOT assumed the expiration of the PTC as per current law, which is 

the reason there are no wind capacity additions in the baseline scenario. All three scenarios built less 

natural gas-fired capacity compared to the baseline. Table 3 summarizes the capacity additions for each 

scenario. 

As shown in Figure 3, the 

retiring coal and gas steam 

capacity would be replaced by 

solar, wind, and natural gasfired capacity by 2029, taking 

into account the contribution of 

energy efficiency measures. 

However, within the modeled 

timeframe there are some 

years for which the ERCOT 

capacity reserve margin may be 

considerably less than historically targeted for reliability, as capacity retires before new resources come 

online and energy savings from energy efficiency measures begin to materialize. In the model results, 

these shortages occur towards the beginning of the compliance timeframe, between 2020 and 2022. 

During this timeframe, the modeled retirements and capacity additions result in a reserve margin 2 to

3% below the reserve margin in the baseline scenario for these years, in the CO2 limit and $20/ton CO2

 12 The solar capacity additions modeled in this study are consistent with the results of ERCOT’s 2013 Long-Term Transmission Analysis, which 

indicated that large amounts of solar would be economic in ERCOT after 2020. For more information, visit ERCOT’s Long-Term Study Task Force 

website at http://www.ercot.com/committees/other/lts/index.html.
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 7

Table 4: Generation Mix in 2020 (% of MWh)

Fuel Type Baseline CO2 Limit

CO2

$20/ton

CO2

$25/ton

Natural Gas (%) 44 60 60 63

Coal (%) 32 14 14 11

Wind (%) 12 15 15 16

Solar (%) < 1 < 1 < 1 < 1

Nuclear (%) 10 10 10 10

Other (%) 1 < 1 < 1 < 1

Table 5: Generation Mix in 2029 (% of MWh)

Fuel Type Baseline CO2 Limit

CO2

$20/ton

CO2

$25/ton

Natural Gas (%) 45 53 53 55

Coal (%) 29 16 16 13

Wind (%) 11 14 14 14

Solar (%) 6 7 7 8

Nuclear (%) 9 9 9 9

Other (%) < 1 < 1 < 1 < 1

scenarios.13 By 2029, the reserve margin in these scenarios is comparable to the baseline scenario. The 

reserve margins are generally higher in the $25/ton CO2 scenario, because the increased price on CO2

results in increased capacity additions. As previously described, ERCOT did not require the simulation 

model to maintain a specific reserve margin in the four scenarios. 

Figure 3: Capacity Additions and Retirements by 2029

With the modeled retirements and capacity 

additions, the generation mix in the 

modeling results shifts towards increased 

generation from natural gas and renewable 

generation resources, and decreased 

generation from coal generation resources. 

Table 4 and Table 5 show the generation 

mix in 2020 and 2029, respectively, across 

the four scenarios. In 2020, natural gasfired units contribute 60% or more of total 

energy in the carbon scenarios, up from 

44% in the baseline. Coal generation 

correspondingly decreases to 11 to 14%, 

from a baseline of 32% of total generation. 

By 2029, renewable generation accounts 

for 21 to 22% of total generation in the 

three CO2 scenarios, up from 17% of total 

2029 generation in the baseline scenario. 

 13 The ERCOT reserve margin is calculated using wind capacity contribution values of 12% for non-coastal resources and 56% for coastal 

resources, consistent with the ERCOT Board approved methodology outlined in Nodal Protocol Revision Request (NPRR) 611. The data used to 

calculate the wind capacity contribution is available on the ERCOT website at http://www.ercot.com/gridinfo/resource/index.html. For solar 

capacity, ERCOT assumes a 70% capacity contribution based on the modeled solar output during peak hours (16:00 to 18:00) as a percentage of 

total installed capacity. 

-10

-5

0

5

10

15

20

25

Baseline CO2 Limit CO2 $20/ton CO2 $25/ton

Capacity (GW)

Scenario

Capacity Additions and Retirements by 2029

Retired Coal

Retired Gas Steam

Wind

Combustion Turbine

Combined Cycle

Solar
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 8

Table 6: Carbon Dioxide Emissions Intensity

CO2 Intensity Baseline

CO2

Limit

CO2

$20/ton

CO2

$25/ton

2020 CO2 Intensity (lb/MWh) 1,175 853 905 840

2029 CO2 Intensity (lb/MWh) 1,089 791 877 792

The modeling results indicate significantly higher generation from natural gas-fired resources under the 

Clean Power Plan. This trend is most distinct early in the compliance period, before the bulk of solar 

capacity additions and energy efficiency savings materialize. In 2020, natural gas consumption by the 

power sector is 35 to 50% higher annually in the carbon scenarios compared to the baseline, as shown in 

Figure 4. By 2029, natural gas consumption is 15 to 20% above the amount consumed annually in the 

baseline. 

Figure 4: Natural Gas Consumption in 2020

The four scenarios resulted in 

different levels of carbon 

intensity. As noted previously, the 

$20/ton CO2 scenario resulted in 

a carbon intensity above both the 

interim and final emissions limits 

in the Clean Power Plan, while the 

$25/ton CO2 scenario resulted in a carbon intensity below the interim goal and approximately meeting 

the final goal (see Table 6 and Figure 5). In the baseline scenario, ERCOT’s carbon intensity is at 1,175 

lb/MWh in 2020 and 1,089 lb/MWh in 2029. The projected emissions intensity for ERCOT in the baseline 

is below the Clean Power Plan emissions rate goals for 19 other states, an indication of the impact that 

existing market policies and investments in transmission in Texas have had on maximizing the efficiency 

of the generating fleet and integrating new technologies including renewable generation.

0

50,000

100,000

150,000

200,000

250,000

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Natural Gas Consumption (GBTU)

Month

Natural Gas Consumption in 2020

Baseline CO2 Limit $20/ton CO2 $25/ton CO2
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 9

Figure 5: CO2 Emissions Intensity

2.3. Comparison to EPA’s Modeling Results

EPA conducted an analysis of the Clean Power Plan by applying the carbon limits to the U.S. electric 

system, and allowing their simulation model to solve for the most cost-effective solution. The results 

referenced here are for EPA’s “Option 1 State Compliance” scenario, as compared to the base case.14

EPA’s modeling results predict that there may be 9 GW of coal unit retirements in ERCOT due to the 

Clean Power Plan – most occurring before the initial 2020 compliance date. ERCOT’s modeling predicted

up to 6 GW of coal unit retirements, but ERCOT believes that there could be up to 9 GW of coal unit 

retirements resulting from the Clean Power Plan due to additional factors not considered in the model 

(discussed in Section 3.1). Similarly, both EPA’s and ERCOT’s modeling saw a major shift in the 

generation mix in 2020 to comply with the interim goal, with substantially increased production from 

natural gas generation resources and substantially decreased production from coal generation 

resources. However, EPA’s modeling resulted in much fewer renewable capacity additions compared to 

ERCOT’s results and significantly more new natural gas generating capacity. The lower amount of 

renewable capacity additions is due to EPA’s use of higher capital cost assumptions for new solar 

capacity. The larger amount of natural gas capacity additions is due in part to EPA’s modeling 

requirement that ERCOT maintain a 13.75% reserve margin, as discussed previously. EPA’s modeling 

predicts more than 10 GW of new natural gas capacity by 2030 in the state compliance scenario, 

whereas ERCOT’s carbon scenarios added 1 to 2 GW of new natural gas capacity. 

3. Impact on Reliability

The modeling results raise two reliability concerns associated with implementation of the Clean Power 

Plan in ERCOT. These concerns are associated with the impacts of unit retirements and increased levels 

of renewable generation on the ERCOT grid. 

3.1. Impact of Unit Retirements

As previously described, the model retired between 3,300 and 5,700 MW of coal-fired capacity in the 

carbon scenarios, relative to the baseline. However, these results represent a lower bound on the 

 14 EPA’s modeling run files are available from http://www.epa.gov/airmarkets/powersectormodeling/cleanpowerplan.html. 

0

200

400

600

800

1,000

1,200

1,400

Baseline CO2 Limit $20/ton CO2 $25/ton CO2

CO2 Emissions Intensity (lb/MWh)

Scenario

Carbon Dioxide Emissions Intensity

2020 2029

853

lb/MWh

791 

lb/MWh
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 10

number of potential coal unit retirements due to the logic used to retire units in the model, generic unit 

cost information, and the impacts of other factors not considered by the model. ERCOT directed the 

model to retire capacity at the point when generic operating and fixed costs exceed revenues. However,

in the modeling results for the carbon scenarios, there are several units operating at low revenues 

and/or low capacity factors that would likely be retired, especially when other non-modeled factors are 

taken into account. One important factor not considered in the modeling is the capital and operating 

cost impacts of other pending environmental regulations including the Mercury and Air Toxics Standard, 

the Regional Haze program, the 316(b) Cooling Water Intake Structures Rule, and the coal ash rules.

Based on a review of capacity factors and operating revenues for the remaining coal units ERCOT 

anticipates the retirement of an additional 2,000 MW of coal capacity and the seasonal mothball of 

1,000 MW of coal capacity beyond what is specified in the model output, compared to the $25/ton CO2

modeled scenario. These results indicate the overall impact to the current coal fleet will be the 

retirement or seasonal mothballing of between 3,300 MW and 8,700 MW.

The accelerated retirement or suspended operations of coal resources would pose challenges to 

maintaining the reliability of the ERCOT grid. Coal resources provide essential reliability services, 

including reactive power and voltage support, inertial support, frequency response, and ramping 

capability. The retirement of coal resources will require reliability studies to determine if there are any 

voltage/reactive power control issues that can only be mitigated by those resources; how to replace 

frequency response, inertial support, and ramping capability provided by retiring units; and the 

necessity of potential transmission upgrades, which will be discussed later in this document.

The model also predicted the retirement of 1,300 to 1,600 MW of natural gas steam capacity in the 

carbon scenarios, which is less than the 2,000 MW retired in the baseline scenario. The fewer 

retirements of natural gas steam units in the carbon scenarios reflects the impact of both the CSAPR and 

carbon dioxide limits on production from coal units, which improves the economics of natural gas steam 

units during this period. However, as with coal resources, there are a number of factors that may result 

in additional natural gas steam unit retirements compared to those found by the model. ERCOT 

estimates that an additional 1,500 to 4,500 MW of natural gas steam capacity may be at risk of 

retirement based on low net revenues in the model results combined with the need to comply with the 

316(b) rule, CSAPR, and other environmental regulations. 

The modeling results indicate that generation from retiring coal capacity will in large part be replaced by 

increased production from existing natural gas capacity. Though ERCOT is not currently affected by 

natural gas supply issues, the increased use of natural gas nationally could lead to increased market 

dislocations, such as seen in the winter of 2013-2014. Depending on the magnitude of these issues, 

there could be implications for maintaining reliable natural gas supply in ERCOT for electric generation 

in the future.

It should also be noted that prospective compliance with the Clean Power Plan in 2020 will impact 

decisions generation resources make now about investments to comply with other pending 

environmental regulations. With the implementation of the Clean Power Plan to consider, owners of 

generation resources in Texas may choose to retire units early rather than install control technology 

retrofits for compliance with the Mercury and Air Toxics Standard (MATS), the Regional Haze Program, 

or the 316(b) Cooling Water Intake Structures rule. For example, the compliance date for the MATS rule 

is April 2015, but several coal-fired units in Texas have received a one-year compliance extension from 

the Texas Commission on Environmental Quality (TCEQ). The pending market impacts due to the Clean 

Power Plan could result in resource owners deciding to retire these units rather than invest in the 

retrofit technology required to achieve compliance with MATS. Similarly, it is anticipated that EPA will 
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 11

issue a Federal Implementation Plan (FIP) for Texas for the Regional Haze program in the coming weeks. 

Depending on the FIP requirements, generators may need to make similar decisions about whether to 

make significant investments in control technology retrofits or instead retire their units, in light of

eventual compliance with the Clean Power Plan. With earlier retirements of fossil fuel-fired capacity, 

ERCOT could experience the aforementioned grid reliability challenges well before the Clean Power 

Plan’s first compliance date in 2020. 

3.2. Impact of Renewables Integration

Integrating new wind and solar resources will increase the challenges of reliably operating the ERCOT 

grid. In 2013, almost 10% of the ERCOT region’s annual generation came from wind resources. In order 

to accommodate this level of intermittent generation, ERCOT has needed to evaluate impacts on 

operational reliability and improve wind output forecasting capabilities. The increased penetration of 

intermittent renewable generation, as projected by these modeling results, will increase the challenges 

of reliably operating all generation resources. If there is not sufficient ramping capability and 

operational reserves during periods of high renewable penetration, the need to maintain operational 

reliability could require the curtailment of renewable generation resources. This would limit and/or 

delay the integration of renewable resources, leading to possible non-compliance with the proposed 

rule deadlines. 

Based on the $25/ton CO2 scenario, intermittent renewable generation sources will contribute 22% of 

energy on an annual basis in 2029. However, during 628 hours of the year intermittent generation will 

serve more than 40%15 of system load. During 128 hours instantaneous renewable penetration will be 

higher than 50%, and the peak instantaneous renewable penetration from the model results is 61%. The 

significant change from present experience is that the highest renewable penetration hours will be 

driven by maximum solar production during relatively high wind periods. These periods occur during the 

day (8 a.m. to 5 p.m.), as opposed to early morning hours (usually 2 to 4 a.m.), as currently experienced 

in ERCOT. The high instantaneous renewable penetration hours in 2029 occur year round except for the 

July-September period. Figure 6 shows generation output by fuel type for the days with the highest 

instantaneous penetration of renewables in 2029 in the $25/ton CO2 scenario. 

 15 The record in the ERCOT region for wind penetration occurred on March 31, 2014 at 2:00 a.m., when wind resources met 39.44% of load.
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 12

Table 7: Maximum Ramp-up and Ramp-Down

Net Load

Maximum 60-

min Ramp-up 

(MW/60Mins)

Maximum 60-

min Rampdown 

(MW/60Mins)

Maximum 180-

min Ramp-up 

(MW/180Mins)

Maximum 180-

min Rampdown 

(MW/180Mins)

2011 Net Load (actual) 6,267 -6,124 16,058 -18,985

2012 Net Load (actual) 6,563 -7,019 14,997 -15,977

2013 Net Load (JanMay) (actual) 6,247 -5,446 12,200 -14,373

2029 Net Load 

(modeled $25/ton CO2

scenario)

11,074 -11,938 22,221 -22,560

Figure 6: Days with Highest Instantaneous Penetration of Renewables

Due to load growth, the lowest net load (defined as total load minus generation from intermittent

energy resources) in 2029 is higher than current record (14,809 MW in 2014 and 17,611 MW in 2029). 

Therefore, during low net load hours there will be no significant change compared to current operating 

conditions in terms of MW of thermal generation online, inertial response and frequency response 

available during generation trip events. 

Significant increase can be seen in net load ramps compared to current experience. While the net load 

down ramps in 2029 are still largely defined by decreases in load at night, as is the case currently, the 

highest net load up ramps are defined by rapid solar production decline at sunset and simultaneous 

decline in wind production during evening load pick-up. Table 7 displays the maximum ramp-up and 

ramp-down in 2029 in the $25/ton CO2 scenario. Figure 7 shows wind and solar generation output and 

customer demand (load) on the day with the highest three hour net load ramp in 2029 from the $25/ton 

CO2 scenario. 
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 13

Figure 7: Highest Three Hour Net Load Ramping Day

The simulation model assumes perfect foresight and ensures that there is sufficient amount of thermal 

generation with sufficient ramping capability committed to follow such rapid net load ramps. In real 

time operation, however, accommodating the maximum ramps resulting from simultaneous solar and 

wind generation decline would be more challenging. At times, the existing and planned generation fleet 

will likely need to operate for more hours at lower minimum operating levels and provide more frequent 

starts, stops, and cycling over the operating day. It is important that market mechanisms are adopted so 

that the need for flexible generation (with short start-up times and high ramping capability) is reflected 

in real-time energy prices. Market mechanisms to include dispatchable load resources could also help to 

address flexibility needs. Enhancing wind and solar forecasting systems to provide more accurate wind 

and solar generation projections will become increasingly important. Regulation and Non-Spinning 

reserves will need to be increased to address increased intra-hour variability and uncertainty of power 

production from wind and solar. Tools available to system operators must be enhanced to include shortterm (10-min, 30-min, 60-min, 180-min) net-load ramp forecasts and simultaneous assessment of realtime ramping capability of the committed thermal generation to assist operators in maintaining grid 

reliability.16

Though all solar capacity additions predicted by the model were utility-scale, it is likely that a significant 

portion of future solar generation capacity will be embedded in the distribution grid (e.g., rooftop solar 

and small scale utility solar connected at lower voltage levels). ERCOT does not currently have visibility 

of these resources. To produce accurate solar production forecasts, ERCOT would need to have 

information regarding the size and location of distributed solar installations. Additionally, to ensure grid 

 16 These findings are consistent with an assessment conducted by the North American Electric Reliability Corporation (NERC) and California ISO 

(CAISO), Maintaining Bulk Power System Reliability While Integrating Variable Energy Resources, November 2013. Available from 

http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC-CAISO_VG_Assessment_Final.pdf. 

 -

 10,000

 20,000

 30,000

 40,000

 50,000

 60,000

0 2 4 6 8 10 12 14 16 18 20 22 24

MW

Hours

Highest Three Hour Net Load Ramping Day

3/28/2029 between 17:00 and 20:00

Load Wind Solar Net Load
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 14

reliability, there would need to be increased consideration of operational activities on the distribution 

and transmission systems.17

Based on ERCOT’s modeling, the majority of new renewable generation resource additions are 

anticipated to be solar. However, if instead ERCOT sees a large amount of wind resource capacity 

additions, then the reliability impacts may be more severe. Wind production in West Texas results in 

high renewable penetration during early morning hours, when load is lowest. An expansion in wind 

production, rather than solar, may result in lower net loads and significant reliability issues. If ERCOT 

cannot reliably operate the grid with these high renewable penetration levels, then production from 

these resources will be curtailed to maintain operational reliability. Should this occur, it would reduce 

production from renewable resources, leading to possible non-compliance with the proposed rule 

deadlines.

4. Impact on Transmission Infrastructure

As previously noted, ERCOT’s analysis indicates that imposition of the constraints proposed in the Clean 

Power Plan will result in retirement of legacy base-load generation and development of new renewable 

generation resources. These changes to the ERCOT generation mix will likely require significant upgrades 

to the transmission infrastructure of the ERCOT system. 

The retirement of a large amount of coal-fired and/or gas steam resource capacity in the ERCOT region 

would have a significant impact on the reliability of the transmission system. The transmission system is 

currently designed to reliably deliver power from existing generating resources to customer loads, with 

the existing legacy resources that are located near major load centers serving to relieve constraints and 

maintain grid reliability. Retirement of these resources would result in a loss of real and reactive power, 

potentially exceeding thermal transmission limitations and the ability to maintain stable transmission 

voltages while reliably moving power from distant resources to major load centers. A significant amount 

of transmission system improvements would likely be required to ensure transmission system reliability 

criteria are met even if a moderate amount of coal-fired and gas steam resources were to be displaced. 

If new natural gas combined cycle resources were to locate at or near retiring coal-fired and gas steam 

resources, the impact would be lessened.

In the ERCOT region, it takes at least five years for a new major transmission project to be planned, 

routed, approved and constructed. As such, in order for major transmission constraints to be addressed 

in a timely fashion, the need must be seen at least five years in advance. Given the competitiveness of 

the current ERCOT market, unit retirement decisions will likely be made with only the minimum required 

notification (currently 90 days). Reliability-must-run contracts may provide an avenue to maintain 

generation resources necessary to support grid reliability, but these make-whole contracts could incur 

significant market uplift costs, especially if they are needed for several years or if the contracted units 

require capital investments in order to maintain compliance with other environmental regulations.

The growing loads in the ERCOT urban centers are causing continued growth in customer demand and a 

resulting need for new transmission infrastructure. As the units that are at risk of retirement from the 

proposed rule are located near these load centers, future transmission needs would be increased or 

accelerated by the likely retirements. A new 345-kV transmission line is currently planned to be in place 

by 2018 to serve customers in the Houston region, at an estimated cost of more than $590 million. Long-

 17 These findings are consistent with an assessment conducted by the North American Electric Reliability Corporation (NERC) and California ISO 

(CAISO), Maintaining Bulk Power System Reliability While Integrating Variable Energy Resources, November 2013. Available from 

http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC-CAISO_VG_Assessment_Final.pdf. 
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 15

Table 8: Locational Marginal Prices*

Locational Marginal Price Baseline

CO2

$20/ton

CO2

$25/ton

2020 LMP ($/MWh) $49.46 $66.17 $73.58

2029 LMP ($/MWh) $72.02 $81.13 $84.28

2020 LMP % change from baseline n/a 34 49

2029 LMP % change from baseline n/a 13 17

2020 retail energy bill % change n/a 14 20

2029 retail energy bill % change n/a 5 7

*LMPs for the CO2 limit scenario were not available at the time of 

completion of this report. They will be provided in the full report 

published in mid-December. 

term studies indicate a potential need for further upgrades in the mid-2020s.18 The retirement of 

generation resources within the Houston area prior to 2018 would likely result in grid reliability issues 

prior to completion of the proposed project. Retirement of generation after 2018 would accelerate the 

need for additional transmission from the long-term horizon (6-15 years) into the near-term horizon (1-6 

years). 

Similarly in the San Antonio and the Dallas-Fort Worth regions there are multiple new transmission 

projects that are being planned to serve existing load growth. At costs of hundreds of millions of dollars, 

the need for these and similar projects would be accelerated by retirement of legacy units in these 

regions. 

Growth in renewable generation would also likely have a significant impact on transmission 

requirements. Although ERCOT did not estimate the costs of these transmission infrastructure 

improvements in this study, recent projects can be illustrative of the potential costs. In early 2014, the 

transmission upgrades needed to integrate the Texas Competitive Renewable Energy Zones (CREZ) were 

completed: more than 3,600 miles of new transmission lines constructed at a cost of $6.9 billion dollars. 

The project took nearly a decade to complete. The CREZ project has contributed to Texas’ status as the 

largest wind power producer in the U.S. 

While the CREZ transmission upgrades provide transmission capacity beyond current generation 

development, these new circuits will not provide sufficient capacity to reliably integrate the amount of 

renewables necessary to achieve the requirements of the proposed rule. Also, if the locations of new 

renewable generation do not coincide with CREZ infrastructure, further significant transmission 

improvements will be required. Given the need to increase the amount of renewable resources in order 

to achieve the proposed compliance requirements in the Clean Power Plan, it is likely that significant 

new transmission infrastructure would be required to connect new renewable resources. 

5. Impact on Energy Costs

The model output included detailed cost information that can be used to characterize the impact of the 

Clean Power Plan on energy prices in ERCOT. This section discusses the cost impacts for the baseline, 

$20/ton CO2, and $25/ton CO2 scenarios. All cost figures are reported in nominal dollars, except capital 

costs, which are in real 2015 dollars. 

The inclusion of carbon prices resulted 

in higher average locational marginal 

prices (LMPs) compared to the baseline 

scenario, as shown in Table 8.

19 In the 

$20/ton carbon price scenario, the 

average LMP in ERCOT was $66.17 in 

2020 and $81.13 in 2029 – 34% and 13% 

above the baseline scenario LMPs for 

those years, respectively. In the $25/ton 

carbon price scenario, the average LMP 

was $73.58 in 2020 and $84.28 in 2030 

 18 See ERCOT’s 2013 Report on Existing and Potential Electrical System Constraints and Needs, available from 

http://www.ercot.com/content/news/presentations/2014/2013%20Constraints%20and%20Needs%20Report.pdf. 19 LMPs for the CO2 limit scenario were not available at the time of completion of this report. They will be provided in the full 

report published in mid-December. 
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 16

Table 9: Fuel and Emissions Allowance Costs in 2020

Variable Costs Baseline

CO2

Limit

CO2

$20/ton

CO2

$25/ton

Total Fuel and Emissions 

Allowance Costs (billions of 

dollars)

12.9 12.9 16.4 17.0

Total Fuel and Emissions 

Allowance Costs change from 

Baseline (%)

n/a 0 28 32

Average Fuel and Emissions 

Allowance Cost ($/MWh) 30.54 31.82 40.80 41.65

Emissions Allowance Costs 

Only (billions of dollars) 0 0 3.5 4.1

Emissions Allowance Costs as 

percent of Total Fuel and 

Emissions Allowance Costs

(%)

0 0 21 24

Table 10: Fuel and Emissions Allowance Costs in 2029

Variable Costs Baseline

CO2

Limit

CO2

$20/ton

CO2

$25/ton

Total Fuel and Emissions 

Allowance Costs (billions of 

dollars)

17.7 16.8 20.4 20.9

Total Fuel and Emissions 

Allowance Costs change from 

Baseline (%)

n/a -5 15 18

Average Fuel and Emissions 

Allowance Cost ($/MWh) 37.07 36.60 44.28 45.49

Emissions Allowance Costs 

Only (billions of dollars) 0 0 3.8 4.4

Emissions Allowance Costs as 

percent of Total Fuel and 

Emissions Allowance Costs

(%)

0 0 19 21

– 49% and 17% above the baseline scenario estimates. As a general estimate, if wholesale power is 40% 

of the consumer bill, these increases in average LMPs would result in a retail energy price increase of 14 

to 20% in 2020, and 5 to 7% in 2029. The increase in wholesale and consumer energy costs compared to 

the baseline decreases by 2029 due to the addition of new solar capacity, which has virtually no variable 

costs, and the accrual of energy efficiency savings. The costs of investments in energy efficiency are not 

estimated in this study. In their comments to the Public Utility Commission of Texas, EUMMOT 

estimated the cost of achieving the 

level of energy efficiency savings 

estimated by EPA at $1.6 to $2.9 

billion per year in Texas.

20

The LMP reflects the variable cost 

associated with the generation 

resource on the margin. Though this 

measure provides an estimate of 

wholesale energy prices for 

consumers, the increase in 

production costs for generators 

would differ. The model results 

indicate that generators’ variable 

costs (which include fuel and 

emissions allowance costs) in 2020 

will increase by 28 to 32% in the 

$20/ton CO2 $25/ton CO2 scenarios, 

respectively, compared to the 

baseline, as shown in Table 9. The 

variable costs of the carbon 

scenarios reflect the increased cost 

of natural gas generation, and the 

effects of energy efficiency and 

additional renewable generation. By 

2029, these costs are 15 to 18% 

above the baseline for the two 

respective scenarios, as shown in 

Table 10. This increase is due in large 

part to the CO2 emissions price, 

which in 2029 posed a cost of $3.8 

billion in the $20/ton CO2 scenario 

and $4.4 billion in the $25/ton CO2

scenario, comprising 19% and 21% of 

total variable costs for the two respective scenarios.

Note that the information in Table 8, Table 9 and Table 10 do not include the associated costs of 

building or upgrading transmission infrastructure, natural gas infrastructure upgrades, ancillary services 

procurement, energy efficiency investments, and potential Reliability-must-run contracts.

 20 Presentation by Jarrett E. Simon, Director Energy Efficiency, CenterPoint Energy. PUCT Workshop Project 42636: Comments on Proposed EPA 

Rule Regarding Greenhouse Gas Emissions for Existing Generating Units, August 15, 2014. Available from the Public Utility Commission of Texas, 

Docket 42636, Item 21.
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 17

Table 11: Total Capital Cost Investments by 2029

Capital Costs Baseline

CO2

Limit

CO2

$20/ton

CO2

$25/ton

Total Capital Cost (billions of 

2015$) 14 23 22 25

Capital Cost change from baseline 

(billions of 2015$) n/a 8 7 11

Capital Cost change from baseline 

(%) n/a 59 52 77

Additionally, there will be capital 

costs for new generation 

resources built in both the 

baseline and carbon scenario 

cases. As Table 11 shows, the 

capital costs in the carbon 

scenarios are $7 to $11 billion 

higher in the carbon scenarios 

compared to the baseline, or an 

increase of 52 to 77%. Figure 8

displays the capital costs by fuel type. Though not directly reflected in LMPs, these costs will also 

ultimately be reflected in consumers’ energy bills.

Figure 8: Capital Costs of New Capacity by Fuel Type

As previously described, the modeling results showed a decrease in the ERCOT reserve margin in the 

early years of the compliance timeframe. In a recently completed report prepared for the Public Utility 

Commission, the Brattle Group quantified the cost to consumers associated with periods of reduced 

reserve margins.21 These costs include a range of production costs, including the cost of emergency 

generation, the cost of utilizing interruptible customers, the costs of utilizing all of the available ancillary 

services, and the impact to consumers from firm load shedding, all of which increase at lower reserve 

margins. As an example, the retirement of 6,000 MW of generation capacity would be expected to 

reduce the system reserve margin by about 8%. Based on this report, if this change occurred when the 

system reserve margin was approximately 14%, the increased annual system costs at the resulting 6% 

reserve margin would be approximately $800 million higher than would be expected prior to the 

regulatory impact.22

Finally, it should be noted that ERCOT used the same natural gas price assumptions in all four scenarios.

With the increased consumption of natural gas anticipated not only in ERCOT but nationally, natural gas 

 21 The Brattle Group. Estimating the Economically Optimal Reserve Margin in ERCOT, January, 2014. Available from 

http://interchange.puc.texas.gov/WebApp/Interchange/application/dbapps/filings/pgSearch_Results.asp?TXT_CNTR_NO=40000&TXT_ITEM_N

O=649. 22 See Figure 22 of the Brattle Group report (page 48). 

 $-

 $5

 $10

 $15

 $20

 $25

 $30

Baseline CO2 Limit CO2 $20/ton CO2 $25/ton

Billions of 2015$

Scenario

Capital Costs

Combined Cycle Combustion Turbine Solar Wind
© 2014 Electric Reliability Council of Texas, Inc. All rights reserved. 18

prices could increase beyond the levels anticipated in this modeling analysis. This would pose additional 

costs to consumers, which are not captured in this study.

6. Summary

Based on this analysis, it is evident that implementation of the proposed Clean Power Plan will have a 

significant impact on the planning and operation of the ERCOT grid. The proposed CO2 emissions 

limitations will result in significant retirement of coal generation capacity, could result in transmission 

reliability issues due to the loss of fossil fuel-fired generation resources in and around major urban 

centers, and will strain ERCOT’s ability to integrate new intermittent renewable generation resources. If 

the expected retirement of coal resources were to occur over a short period of time, reserve margins in 

the ERCOT region could reduce considerably, leading to increased risk of rotating outages as a last resort 

to maintain operating balance between customer demand and available generation. The need to 

maintain operational reliability (i.e., insufficient ramping capability) could require the curtailment of 

renewable generation resources. This would limit and/or delay the integration of renewable resources, 

leading to possible non-compliance with the proposed rule deadlines. 

As noted previously, ERCOT supports the IRC proposal for inclusion of a reliability safety valve process in 

the context of the CO2 rule, as well as the consideration of electric grid reliability during the 

development of State Implementation Plans. These proposals could help mitigate the potential 

reliability impacts of the Clean Power Plan. 

The Clean Power Plan will also result in increased energy costs for consumers in the ERCOT region. 

Based on ERCOT’s analysis, energy costs for consumers may increase by up to 20% in 2020, without 

accounting for the associated costs of transmission upgrades, natural gas supply infrastructure 

upgrades, procurement of additional ancillary services, energy efficiency investments, capital costs of 

new capacity, and other costs associated with the retirement or decreased operation of coal-fired 

capacity in ERCOT. Consideration of these factors would result in even higher energy costs for 

consumers. 

ERCOT will issue the full report of this environmental regulatory impact study in mid-December 2014. 

The full report will include information about the impacts to ERCOT of several proposed or recently 

finalized environmental regulations, including MATS, CSAPR, the Regional Haze program, the 316(b) 

Cooling Water Intake Structures rule, and the coal ash rules. The report will also provide more details 

about the modeling analysis of the Clean Power Plan. As new information becomes available, ERCOT will 

continue to analyze the impacts of the Clean Power Plan, as well as other regulatory developments that 

may impact the ability to provide reliable electricity to consumers in Texas.