Addressing the Effects of Environmental Regulations:

Market Factors, Integrated Analyses, and Administrative 

Processes

Introduction

As state commissions consider how best to respond to new and pending environmental regulations

affecting the utility industry in their states and regions, the Regulatory Assistance Project (RAP) is 

producing a series of memoranda to assist states in dealing with some of the likely questions expected 

to arise.

Here we consider the role that utility market factors such as the price of natural gas, can play in the

context of emerging environmental regulations and in regulatory compliance strategies. Utilities will 

consider both regulatory compliance and market fundamentals in their business decisions regarding 

existing power plants. The comments provided here seek to highlight the positive aspects of looking at 

resource choices in an integrated manner. States that consider methodologies and approaches that help 

in understanding the full value of various available resources, thereby ensuring investment in the most 

suitable resource choice at least-cost to customers and society, could earn dividends on their advanced 

planning and avoid costly duplication of effort later. Finally, we provide brief descriptions and 

characterizations of various “process” approaches being employed by several states. The examples of 

state processes share one feature; they assume that a process that encourages consideration of 

alternatives and allows for stakeholder review will encourage better overall utility performance in an 

uncertain environment.

The memo is divided into the following sections:

 Market Factors Affecting Coal

 Benefits of an Integrated Analysis

 Other Review Processes

Market Factors Affecting Coal

As states conduct their own investigations into the effects of federal environmental regulations, it is 

critical to recognize that the activity of the Environmental Protection Agency (EPA) will be only one of 

the several significant groups of issues that are compelling companies to consider closing, retrofitting, or 

replacing older, smaller and less-efficient coal plants. Although distinguishing company decisions due to 

market factors from decisions based on regulatory compliance costs is more easily said than done, 

regulators nevertheless need to recognize the degree to which economic factors are driving retirement
and investment decisions by utility companies. According to Sue Tierney in her article, Why Coal Plants 

Retire: Power Market Fundamentals as of 2012, 

New environmental requirements can put financial pressures on coal plant operators, but power 

market fundamentals, and especially tightened gas‐to‐coal price differentials and lower 

electricity demand, have contributed significantly to the recent business decisions of some coal 

plant owners to retire some of their marginal plants. Many market observers report continued 

pressure on the coal fleet in the near term, at a minimum, due to these economic drivers.1

This means that the economic case for continued operation of a coal plant could largely come down to 

the price differential between coal and its most likely alternative--natural gas: the lower the price of gas, 

the greater the risk to coal plant revenues. Lower gas prices, due to more domestic production, 

significant storage levels, and new pipeline projects have affected electricity prices across the country. In 

February 2012, the Analysis Group reported:

Natural gas prices fell from $4.37/mmBtu in 2010 to $3.98/mmBtu in 2011, the lowest annual 

average price for natural gas since 2002. Today, the spot market is trading at about 

$2.50/mmBtu.2

While gas prices have been dropping, coal prices have remained high. According to the Energy 

Information Agency (EIA), “[d]elivered coal prices to the electric power sector have increased steadily 

over the last 10 years and this trend continued in 2011, with an average delivered coal price of $2.40 per 

mmBtu (a 5.8 percent increase from 2010).”3

According to the Brattle Group, natural gas prices rather than pending environmental regulations are

changing power market conditions and having the greatest effects on existing coal generation. They 

write that the energy market and potential environmental regulations have changed “substantially” 

since they studied the “potential for coal plant retirements in December 2010.”4They indicate that the 

“decrease in spot and forward gas prices combined with low demand for power have caused projected 

energy margins and the cost of replacement power to decrease, altering the economics for coal units 

towards retirement versus retrofit decisions.”5

 

1Why Coal Plants Retire: Power Market Fundamentals as of 2012, Susan Tierney, Feb. 2012, at 12, 

http://www.analysisgroup.com/uploadedFiles/News_and_Events/News/2012_Tierney_WhyCoalPlantsRetire.pdf

(Why Coal Plants Retire).

2

Id. at 3, citing to Henry Hub prices set out in the Energy Information Administration, “2011 Brief: Energy 

commodity price trends varied widely during 2011,” Today in Energy, January 9, 2012. In December 2012, EIA 

identified the 2012 annual natural gas price as $2.85 per MCF.

3

Id. citing to EIA, Short‐Term Energy Outlook, February 7, 2012: “U.S. Coal Prices.”

4 Metin Celebi, Frank Graves, and Charles Russell, “Potential Coal Plant Retirements: 2012 Update,” The Brattle 

Group, Inc., October 2012, at 1, citing to Metin Celebi, Frank C. Graves, Gunjan Bathla, and Lucas Bressan, 

“Potential Coal Plant Retirements Under Emerging Environmental Regulations,” The Brattle Group, Inc., December, 

2010. 

5

Id.
In addition to collapsing coal and gas price differentials, slower than expected economic growth has 

caused a drop in demand for relatively more expensive coal plants that previously had been economic to 

operate. Prices have also moderated due to a decrease in forecasted electricity demand due to energy 

efficiency and other demand-side management programs. In PJM, for example, demand response and 

energy efficiency are beginning to play a significant part in PJM’s capacity auctions. These demand-side 

resources, plus renewable resources, constitute approximately 10 percent of the resources clearing 

PJM’s 2014‐2015 forward capacity auction.6The market has accepted these resources as less costly than 

other more traditional supply-side resources. These lower priced alternatives could be good news for 

ratepayers by lowering overall utility costs, to the degree the regulatory process requires their inclusion 

in company resource choice analyses.

Of course, in addition to wider market factors, it also appears that a generating plant’s age and relative 

efficiency are important factors that should also be considered in evaluating resource choices. The 

Analysis Group cites to several examples from FirstEnergy7and American Electric Power8that strongly 

suggest that these factors play a significant role in generation plant retirement decisions being made by 

companies.

While the political rhetoric associated with retirements points to EPA regulations as being the cause of 

generation retirements, it is important to recognize the role that market factors are playing in company 

decisions to retire resources, and that there are less expensive alternatives to some existing generation.

The Benefits of Integrated Analysis

Planning is not new to the utility industry; many utilities have performed resource planning for internal 

purposes or to comply with regulatory requirements, over the course of several decades. What has 

come to be known as “integrated resource planning” (IRP) or simply “least-cost planning” is built on 

principles of comprehensive and holistic analysis.9IRP was developed by utility regulators because they 

saw that traditional utility planning and investment decisions often overlook alternative resources, 

including end-use efficiency and renewables, whose economic and environmental characteristics could 

provide significant system benefits in the form of cost- and risk-reduction.

The central value in having a utility plan ahead, whether or not as part of a formal regulatory process, 

lies in being able to identify the best resource mix for the utility and its consumers before capital is 

committed and expenditures are made. The “least-cost” criterion implies the optimal resource mix is the

lowest total cost over the planning horizon, given the risks faced. And, the best resource mix is one that 

 

6

“Why Coal Plants Retire” at 8, citing to PJM, “Demand Resources and Energy Efficiency Continue to Grow in PJM’s 

RPM Auction,” News release, May 13, 2011.

7

Id. at 10

8

Id. at 11.

9

See, e.g., “Best Practices Guide: Integrated Resource Planning For Electricity,” Prepared for: Energy and 

Environment Training Program Office of Energy, Environment and Technology Global Bureau, Center for the 

Environment, United State Agency for International Development.
remains cost-effective across a wide range of futures and sensitivity cases that also minimize the 

adverse environmental consequences associated with its execution.10

In the context of an investigation into the effects of pending environmental regulations, the ideal 

position for a state to be in is one in which the state requires the utilities to submit regular resource 

plans. This is because there are existing stakeholder processes for the review of resource planning 

inputs, assumptions, and outputs. Approximately thirty-nine states require their utilities to file IRPs.11 In 

a process to review the potential effects of EPA regulations on a company, a regulator could request 

that the utilities update their plans to reflect costs associated with, among other things, current market 

dynamics and likely costs associated with various environmental compliance strategies.

In the absence of a resource planning requirement, planning efforts have to start somewhat from 

scratch and must be completed in a quicker time frame in order to ensure that utility expenditures—and 

by extension their requests for retail cost recovery—will be the lowest possible given the 

circumstances.12 This approach would consider a full range of feasible supply-side and demand-side 

options and assess them against a common set of planning objectives and criteria. The key, however, is 

to have an integrated approach that looks at all potentially available choices.

Figure 1 emphasizes the importance of planning in an integrated manner by looking ahead to all likely 

environmental costs that may be candidates for inclusion in utility rates. The figure compares the cost of 

power from an existing coal plant without retrofit, with two levels of retrofit, and with carbon costs. 

Fig. 1

13

 

10 “Electric Regulation in the US: A Guide,” Jim Lazar, March 2011 at 73.

11 According to “A Brief Survey of State Integrated Resource Planning Rules and Requirements,” by Rachel Wilson 

and Paul Peterson, April 2011, 39 of 50 states have a rule or requirement for long-term resource planning or 

procurement.

12 Economist Paul Chernick has dubbed this approach, “Integrated Environmental-Compliance Planning.” See 

discussion of Oklahoma process below. 

13 Incorporating Environmental Costs in Electric Rates Working to Ensure Affordable Compliance with Public Health 

and Environmental Regulations, by Jim Lazar and David Farnsworth, October 2011 at page 23.
The first bar shows only the operating costs of the plant under existing regulations. The second bar adds

the capital recovery of the remaining investment in the plant; most utilities and some regulators would 

consider these “sunk” costs and not a part of a forward-looking economic analysis. The third bar adds a 

rough amount for the costs of meeting current SO2 and NOx emissions regulations. The fourth bar, 

likewise, adds a rough amount for the costs of meeting potential mercury, ash, and water regulations. 

The last bar adds a rough amount for the costs of meeting potential CO2 regulations. The point of this 

illustrative example is not to assign specific values to each element but to indicate the rough order of 

magnitude of these costs.

The “fully renovated” power plant in this illustrative example would have costs of about $0.11/kWh, 

compared with $0.03/kWh for the current operating costs and $0.036 for the current fully allocated 

costs, including a return on the existing investment. This renovated cost is well above the estimated cost 

of energy efficiency, wind, and geothermal generation and approaching the cost of solar and nuclear 

generation. In this example, the utility and the regulator would clearly want to consider whether it is 

cost-effective to consider plant renovation, given potential future exposure.

Examples of Review Processes

The following discussion looks at models of processes several jurisdictions and one regional organization 

employed to explore these interconnected environmental, energy, and ratepayer issues. These 

processes are briefly described with an emphasis on the potential role of utility stakeholders (e.g., 

utilities, regulators, and consumer advocates) and other participants (e.g., state environmental 

agencies).

14 This section also looks at opportunities to coordinate with other state agencies. Below, we 

discuss processes in Colorado, Michigan, Oklahoma, and the Midwest ISO.

Colorado

Colorado, the seventh largest coal producing state in the U.S., passed the “Clean Air Clean Jobs Act” 

(“the Act”) in April 2010, targeting regional haze and ozone, and establishing a 70-80 percent reduction 

target for NOx from 2008 levels. Denver and Colorado’s “Front Range” had been designated under the 

Clean Air Act as “non-attainment” areas for ground-level ozone, a pollutant created through the 

interaction of NOx, VOCs, and sunlight.

 

14 There are additional processes that have not been considered here. See, e.g., Iowa Utilities Board Docket NOI2011-0003, “Utility Coal Plant Planning,” a process designed to gather “Information Related to the Potential Impact 

of the New EPA Regulations on Iowa Generation Plants,” 

https://efs.iowa.gov/efs/ShowDocketSummary.do?docketNumber=NOI-2011-0003. The comments submitted in 

Docket NOI-2011-0003 by the Iowa Office of Consumer Advocate (OCA) provide an excellent list of processes 

including, (1) MISO’s analysis of regional impacts on utility sector; (2) Minnesota’s collaborative and modeling 

efforts with EPA; (3) the Colorado Clean Air Clean Jobs Act, all of which are discussed here. The OCA comments 

also discuss models of regulatory compliance considered in Kentucky and Georgia. Iowa OCA comments of 

December 15, 2011, Section 3, pages 11-19.
In the absence of final federal regulations, the Act anticipated new EPA standards for criteria air 

pollutants (NOx, SO2, and particulates), mercury, and CO2, and required the utility company15 to: (a) 

consult with Colorado Department of Public Health and Environment (DPHE) on its plan to meet current 

and “reasonably foreseeable EPA clean air rules,” and (b) submit a coordinated multi-pollutant plan to 

the state Public Utility Commission (PUC).

The Act mandated that DPHE participate in the PUC process, and conditioned PUC action on the DPHE’s 

review of utility proposals, affirmatively linking the two agencies’ actions. This mandate resulted in the 

PUC not being able to approve a plan that the DPHE did not agree would meet future Clean Air Act 

requirements, and the company not being able to build anything without the PUC’s approval and 

issuance of a certificate of public convenience. The Act also required the DPHE Air Quality Control 

Commission to incorporate approved plans into Colorado’s State Implementation Plan (SIP) for 

addressing regional haze for ultimate EPA approval.

Colorado utilities are not required to adopt any particular plan, just one that meets DPHE’s 

requirements and meets with PUC approval. The Act encourages utilities to enter into long-term 

contracts for natural gas supplies by providing protection against possible future prudence challenges by 

stakeholders. It also allows utilities to recover, in rates, costs associated with approved long term 

contracts, “notwithstanding any change in the market price during the term of the agreement.” 

The Act encourages companies to evaluate alternative compliance scenarios, but requires each company 

to develop and evaluate an “all emissions control” case, (i.e., a scenario calling for installation of 

pollution controls on the coal fleet, plus an assessment of different ranges of retirements). 

In the administrative process, Public Service of Colorado (Xcel) was given four months to report to the 

PUC with analysis results and a proposed compliance plan. The company divided its analysis into four 

steps (See Table 1). In Step 1, “data collection,” the company identified: (a) the coal plants for which the 

company might take “action” (i.e., install controls, retire, or retrofit for fuel switching); (b) emission 

control options and associated costs; (c) possible generation technologies that would replace retired 

capacity; and (d) transmission reliability requirements. 

Step 2 was “scenario development.” This involves developing combinations of various actions on coal 

plants, assessing replacement generation (i.e., developing “Capacity Portfolios”), and testing the 

feasibility of approaches for reducing emissions while maintaining reliable service.

 

15 The “Clean Air – Clean Jobs Act, ” HB 10-1365, requires “[b]oth of the state’s two rate-regulated utilities, Public 

Service Company of Colorado (PSCo), and Black Hills/Colorado Electric Utility Company LP, ... to submit an air 

emissions reduction plan by August 15, 2010, that cover[s] the lesser of 900 megawatts or 50% of the utility’s coalfired electric generating units.” Legal Memorandum, Office of Legislative Legal Services, March 16, 2011, on H.B. 

10-1365 and Regional Haze State Implementation Plan, 

http://www.leg.state.co.us/clics/clics2011a/cslFrontPages.nsf/FileAttachVw/SIP/$File/SIPMeetingMaterials.pdf
In Step 3, “dispatch modeling of scenarios,” the company to used its “dispatch modeling” capability to 

evaluate the effects of various scenarios (articulated partly by statute, the company, the PUC, and 

stakeholders) on the company’s entire system. 

Step 4 involved the development of sensitivity analyses. At this step, the company performs analyses by 

varying certain key assumptions to see how the scenarios it developed and modeled under Steps 2 and 3 

would perform in different futures.

Table 1. Public Service of Colorado’s Analysis

1. Data Collection

• Identify Candidate Coal Units

• Emission Control Options and Costs

• Replacement Capacity Options

• Transmission Reliability Requirements

2. Scenario Development

• Meet NOx Reduction Targets

• Feasibility of Emission Controls

• Replace Retired Coal MW

• Transmission Needs Analysis

3. Dispatch Modeling of Scenarios

• Long-term Capacity Expansion Plan

• Cost of Transmission Fixes

• Coal and Gas Price Forecasts

• Customer Load Forecasts

4. Sensitivity Analysis

• Construction Costs

• Coal and Gas Prices

• Emissions Costs (NOx, SO2, CO2)

• Replacement MW for retirements

• Addition of renewable resources

The overall undertaking required cooperation between the regulatory commission and Colorado’s 

environmental regulator, and significant effort by Public Service of Colorado. The process, including a 

PUC investigation, company analysis of alternative compliance strategies, issuance of a final 

order, and subsequent adoption of changes to Colorado’s SIP occurred in less than eight months, 

demonstrating the feasibility of such a cooperative effort and the ability of decision makers to address 

the challenges related to maintaining system reliability while responding to (as yet unarticulated) health 

and environmental regulatory compliance challenges.

On March 12, 2012, the EPA approved Colorado's SIP for addressing regional haze around the state's 

national parks and wilderness areas. According to E&E Greenwire, “the adoption of Colorado's state 
implementation plan -- unlike other states' proposals -- went smoothly in large part because of 

Colorado's 2010 Clean Air-Clean Jobs Act.”

Process Lessons

It is important to note that the Colorado process:

 Took place in less than one year;

 Went ahead, absent certainty as to precisely what EPA regulations would require; and

 Mandated coordination between environmental and energy regulators, due to the subject 

matter of the challenges being addressed by the state.

Michigan

Michigan provides a unique model of regulatory coordination. Executive Directive No. 2009 – 2 requires 

the state environmental regulator, the Michigan Department of Environmental Quality (DEQ), to 

“conduct analysis of electric generation alternatives prior to issuing an air discharge permit.” As part of 

this inquiry, the directive also requires the Michigan Public Service Commission (PSC) to provide DEQ 

with technical assistance.16

The two agencies entered into a memorandum of understanding in which respective roles were 

articulated: DEQ would undertake air quality determinations, and the PSC would provide assistance 

related to determining need for new generation, and analyze alternatives, including options for energy 

efficiency, renewable energy, and other generation.17

Process Lessons

Executive Directive No. 2009 – 2, like Colorado’s Clean Air Clean Jobs Act, underscores the value of

developing a process that links both environmental and energy regulators to analyze company electric 

generation choices.

Oklahoma

In June 2011, the Oklahoma Corporation Commission issued a notice of inquiry (“NOI”) in order to 

examine existing and pending federal regulations and legislation that could impact regulated utilities 

and their customers in the state of Oklahoma.18 The Commission is also examining the potential impact 

of such regulations on the natural gas commodity market in Oklahoma. The primary purpose of the NOI 

is to determine whether any amendments to the rules of the Commission are necessary.

 

16 Executive Directive No. 2009 – 2, “Consideration of Feasible and Prudent Alternatives in the Processing of Air 

Permit Applications from Coal-Fired Power Plants,” http://www.michigan.gov/granholm/0,1607,7-168-36898-

208125--,00.html. 

17 “Statutory and Administrative Review of Power Plants in Michigan,” NARUC Task Force Webinar 3, State Case 

Studies, Greg White, Commissioner, Michigan Public Service Commission, December 17, 2010. 

http://efile.mpsc.state.mi.us/efile/docs/15958/0001.pdf; 

http://www.naruc.org/Publications/White_%20Michigan%20Coal%20Plant%20Review%20Processes.pdf

18 Cause No. PUD 201100077, “In Re: Inquiry of the Oklahoma Corporation Commission to Examine Current and 

Pending Federal Regulations and Legislation Impacting Regulated Utilities in the State of Oklahoma and the 

Potential Impact of Such Regulations on Natural Gas Commodity Markets and Availability in Oklahoma.”
In its first of a series of questions, the Commission asked:

Are there alternative planning processes other than a regulated utility's Integrated Resource 

Plan (IRP) as described in OAC 165:35-37 that could be considered in determining the most 

effective strategy to include a holistic approach to Oklahoma's generation fleet and an analysis 

of the overall cost impact or benefits to ratepayers as it relates to federal mandates, fuel 

switching (converting from one fossil fuel to another type of fossil fuel), renewable portfolio 

standards, fuel diversity, system efficiency improvements, transmission expansions and other 

upcoming issues? If so, what kind?

In response, one participant, Sierra Club, proposed that the OCC adopt what the NGO called “Integrated 

Environmental-Compliance Planning.”19 It is an approach that, in many ways, works like an IRP. It 

considers supply-side, demand-side, and delivery options in an integrated manner. It focuses, however, 

more closely on the requirements of forthcoming public health and environmental regulations and the 

imminent need to take actions such as retiring, retooling, or investing in new resources. Whether a 

commission employs integrated resource planning or integrated environmental-compliance planning, 

reviewing investments in an integrated manner is the key. According to Sierra Club, this approach will 

help ensure a greater understanding of all options available that might otherwise be missed with a 

narrower approach:

Responding to these requirements piecemeal will result in inefficient and unnecessarily 

expensive decisions. The sheer number and wide coverage of these pending rules mandates that 

the Commission and the utilities consider their potential impact in a comprehensive, rather than 

case-by-case basis, for both planning and cost recovery. The Commission should expect to see 

the anticipated costs and the potential risks of existing and emerging regulations for the whole 

range of pollutants in utility evaluations of their investment proposals. Given the capitalintensive and long-lived nature of investments in the electric industry, if the final form or timing

of a regulation is unknown, the analysis should include both an expected value of the cost of 

compliance and the range of plausible costs.20

Process Lessons

Oklahoma’s process initially looks much like an NOI that any administrative agency around the country 

might undertake. However, one key difference is that the OCC asked up-front if its existing planning 

process is capable of addressing these issues. As noted in the discussion of the Colorado Clean Air Clean 

Jobs Act, an inquiry such as this opens up the possibility of a state- or region-wide view of alternatives.

 

19 Sierra Club, July 18, 2011 at page 5, Oklahoma Corporation Commission. (2011).

20See Comments of Sierra Club in “In Re: Inquiry of the Oklahoma Corporation Commission to Examine Current and 

Pending Federal Regulations and Legislation Impacting Regulated Utilities in the State of Oklahoma and the 

Potential Impact of Such Regulations on Natural Gas Commodity Markets and Availability in Oklahoma,” Cause No. 

PUD 201100077, July 18, 2011, 

http://www.occeweb.com/pu/EPA/Filed%20Comments/2011%2077Sierra%20Club%20NOI%20II%20responses%20

7%2018%2011.pdf
Midwest ISO Analysis21

The Midwest Independent System Operator (MISO) conducted an analysis of potential effects of EPA 

regulations on its system. MISO’s analysis was broken into three phases. Using the Electric Generation 

Expansion Analysis System (EGEAS) model, MISO’s first step looked at the effects of several EPA 

regulations on generation in MISO from a regional perspective. Using results from the first phase, 

MISO’s next step focused on energy and congestion impacts in the MISO system, using a production cost 

model and transmission adequacy model.22 In the third phase, MISO developed compliance and capital 

cost requirements, and analyzed system adequacy, system reliability, and impacts on customer rates.23

Process Lessons

The MISO process recognized:

 The role of market dynamics;

 That gas prices relative to coal are a key driver; and

 The importance, for scheduling purposes, of knowing when a plant will need to go offline 

(whether permanently or for retrofitting), and that this can be modeled but that it also needs to 

be ascertained plant-by-plant from utility companies.

Conclusions

Each of these processes demonstrates how a “directed” conversation between regulators, companies, 

and other stakeholders can be useful to regulatory commissions and provide commission staff and 

others the opportunity to “kick the tires” on modeling assumptions, scenario assumptions, and 

sensitivities related to company environmental compliance choices. Having one party undertake this 

work alone could result in not only a lot of work and expenditure on their part, but also an extremely 

complex collection of data and assumptions that will be less than useful to regulators. Alternatively, a 

transparent approach that explores assumptions whose attributes are generally agreed-upon can be 

more valuable in helping decision-makers with their work. This approach also affords commissions and 

staff the opportunity to make use of the expertise of various stakeholders, thereby making greater use 

of commission staff time and resources.

This review is designed to help regulatory commissions in their responses to new and pending 

environmental regulations affecting the utility industry in their states and regions. The topics considered 

here are likely to arise in any discussion of the effects of environmental regulations on a state’s utility 

sector.

 

21 This discussion is based on a MISO analysis entitled “EPA Impact Analysis Impacts from the EPA Regulations on 

MISO,” October 2011. https://www.midwestiso.org/_layouts/MISO/ECM/Redirect.aspx?ID. 

22 Respectively, the PROMOD IV production cost model and the PSS/E transmission adequacy model.

23 In addition to the above mentioned models, in analyzing system adequacy, MISO also used GE-MARS model.