PUBLIC UTILITY COMMISSION STUDY

MARCH 31, 2011

EPA Contract No. EP-W-07-064

Work Assignment No. 3-11

Prepared For:

SRA International, Inc.

652 Peter Jefferson Parkway, Suite 300

Charlottesville, VA 22911

Submitted By: M.J. Bradley & Associates LLC
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TABLE OF CONTENTS

Executive Summary ......................................................................................................................... 1

Section I. State Public Utility Commissions and Electricity Sector Regulation: Context, Core 

Responsibilities and Basic Structure................................................................................................ 5

A. Introduction......................................................................................................................... 5

B. State Public Utility Commissions and the Regulation of Traditional Electric Utilities......... 6

C. Federal Regulation: The Federal Energy Regulatory Commission ...................................... 7

D. Deregulation and Redrawing Jurisdictional Lines ............................................................... 8

E. Reliability: Responsibilities PUCs, NERC, and FERC ........................................................... 12

Section II. State Regulatory Commissions and Pollution Control Strategies: Sources of Authority 

and Types of Regulatory Approvals............................................................................................... 15

A. The Ratemaking Process and Cost Recovery for Pollution Control Projects..................... 15

B. Beyond the Rate Case: Tools to Enhance the Chances and Timing of Cost Recovery ...... 18

Section III. Timing Analysis............................................................................................................ 24

A. Ratemaking and Regulatory Lag Time ............................................................................... 24

B. Pre-Construction PUC Approval Times.............................................................................. 25

Section IV. Case Studies................................................................................................................. 30

A. Colorado Case Study.......................................................................................................... 30

B. Indiana Case Study ............................................................................................................ 44

C. Maryland Case Study......................................................................................................... 55

D. Florida Case Study ............................................................................................................. 62

E. Georgia Case Study............................................................................................................ 67

F. West Virginia Case Study................................................................................................... 76

Conclusions.................................................................................................................................... 85

Appendix A. Role of National Umbrella Organizations: NARUC and NASUCA ............................. 87

Appendix B. NERC Reliability ......................................................................................................... 89

Appendix C. Details of States for Timing Analysis......................................................................... 94

Appendix D. Details of Cases Used in Timing Analysis.................................................................. 99

Appendix E. Intervenors in Colorado Case Study ........................................................................ 112

Appendix F. Relevant Articles..................................................................................................... 114

Glossary ....................................................................................................................................... 115
1

EXECUTIVE SUMMARY 

This Public Utility Commission (PUC) Study examines the regulatory role PUCs play in approving 

air pollution control modifications by electric utilities. The Study examines the length of time 

required for relevant PUC approvals, which is important to EPA as the Agency contemplates 

regulatory timeframes for pending rules affecting power plants. To understand the sphere of 

influence of the PUC, it is necessary to explore the universe of active regulatory bodies, the 

history of how electric utilities were regulated and deregulated, and the rate structures central 

to PUC work. This analysis chose six PUC dockets as case studies to deepen the understanding 

of how the PUC process shapes utilities’ ultimate approach to compliance with environmental 

regulation. 

To provide context for the case studies, this report first explores the boundaries of electricity 

regulation among the Federal Energy Regulatory Commission (FERC), the North American 

Electric Reliability Corporation (NERC) and the PUCs. In general, all of the electricity flowing 

through interstate commerce is regulated by FERC and its designated authorities. When 

electricity is distributed to end-use customers in a state, it is regulated by the PUC. In states 

that have not deregulated their utility sector, the PUC sets the terms of cost recovery for both 

the electricity generation assets and distribution assets of public utilities through customer 

rates. In deregulated states, the PUC regulates cost recovery for electric distribution generation 

assets, but electric generation assets have been “decoupled” and recovery of capital investment 

is left to the market, not PUCs. 

PUC authority over pollution control projects falls into two categories: rate recovery (the 

recovery of shareholders’ investment in the project from ratepayers) and siting review. The 

traditional mechanism for rate recovery – the general rate case – is almost always undertaken 

after the project is complete. Pollution control projects are substantial capital investments and 

can take several years to complete. Waiting for the rate case to determine the overall price tag 

and whether utility shareholders will recover their investments is not always efficient for 

shareholders or optimal for ratepayers.

Decreasing the lag time for recouping capital costs is important to utilities’ credit ratings and can 

also reduce the risk of “rate shocks” – large spikes in rates that can occur if recovery is deferred 

until the next general rate case. To address this dilemma, PUCs may require or allow preapprovals that address the core prudence issues prior to undertaking the project. Thus, a more 

expedient rate recovery may be allowed. This is done through cost recovery mechanisms 

specific to environmental costs or through the use of general recovery mechanisms, such as 

construction work in progress (CWIP). 

Another common PUC pre-approval is the certification of public convenience and necessity 

(CPCN), which reviews project siting and often includes additional environmental criteria. The 

certification process is used to ensure that regulated entities are acting in the public interest and 
2

adhering to applicable rules and regulations. There are many variations of CPCNs. PUCs that 

use CPCNs typically require them to be completed prior to plant modification. 

Since PUC approvals are common before a control can be fitted to a power plant, we considered

the length of these cases. We examined over 100 cases in 10 states. In these cases, utilities 

sought PUC pre-approvals for a determination on either siting or a cost recovery mechanism. 

The average time for an approval was seven months, as shown in Figure ES-1. The majority of 

cases (58 percent) took six months or less; only six cases took over a year. While the PUC 

process can vary in length, it is clear from the case studies that when deadlines were imposed by 

the legislature, negotiations – even when complicated – were resolved relatively quickly. 

Utilities that need to, or choose to, seek pre-approval from a PUC before breaking ground on 

their compliance strategies for EPA’s upcoming regulations should find that the process can 

usually be completed well within a year based on these data. These timeframes do not reflect 

time a utility may spend preparing a case before the docket is opened. 

Figure ES-1. Length of PUC Pre-Construction Approvals

The case studies offer insights into the PUC processes covering a wide geographic area. At the 

core of the PUC process surrounding environmental controls is the determination of which 

compliance strategy is most advantageous for ratepayers. Since there are often several ways to 

comply with environmental regulations, the ultimate strategy adopted by a utility can be 

influenced by the PUC process. 
3

The Colorado case study examines the dynamics that unfold when compliance includes 

accelerated retirement of multiple coal-fired units and the addition of new natural gas-fired 

capacity. This case was highly contentious. Intervening stakeholders with varied interests in the

electric industry participated, including: coal interests, gas interests, Independent Power 

Producers (IPPs), environmental groups, and large retail or commercial electricity customers. 

Because many of the intervenors were linked to national trade associations, the arguments 

heard in the Colorado case may be echoed in PUCs across the nation as PUCs begin to consider 

environmental compliance alternatives. The utility was responding to a state law, the Clean Air 

Clean Jobs Act, designed to help reduce air pollutants and expedite fuel switching from coal to 

natural gas.

1

 Absent that dynamic, it may have been difficult for the PUC to approve such a 

large volume of fuel switching and construction of new natural gas-fired capacity since the 

capital cost of adding new gas-fired capacity exceeded the addition of post combustion controls 

on existing coal-fired generation. The final PUC order in the Colorado case included several 

modifications to the installation schedule and altered the compliance plan and timing for one of 

the largest coal units under consideration.

In contrast, Indiana has a state law, the Indiana Coal and Clean Coal Technology statute, 

explicitly designed to provide incentives for local utilities to continue using Indiana coal by 

offering favorable financing terms through the PUC. The Indiana case examined a utility’s 

response to EPA’s Clean Air Interstate Rule (CAIR) and Clean Air Mercury Rule (CAMR). All of the 

upgrades in the Indiana case were post-combustion controls placed on coal-fired generators. 

The final PUC order denied the utility’s initial proposal by eliminating the mercury controls as 

too expensive, and substituted the federal CAMR allowance strategy that the D.C. Circuit 

ultimately eliminated. The PUC also modified the financing terms. The case took well over a 

year to resolve, during which time there was considerable regulatory uncertainty. 

The Maryland case study is a rare example of a CPCN siting approval in a deregulated state. This 

case was also driven by a state law, the Healthy Air Act. While no rate negotiations took place, 

the process took about 10 months for siting approval, which included all necessary air permits. 

One of the core missions of a PUC in a regulated state is to make determinations regarding cost 

recovery for environmental expenditures. We examined a variety of innovative rate issues that 

are of importance to a utility’s ability to recoup, in an expedited manner, their costs of 

complying with EPA’s upcoming regulations. The Georgia case represents the first time that 

projected environmental costs at a Georgia utility were addressed using an accelerated 

environmental cost recovery mechanism. The Florida case study looks at a PUC denial of a 

preferred financing approach to new clean generation facilities. The utility was contemplating 

modernization plans to reduce emissions by shutting down coal and oil units and building stateof-the-art natural gas facilities. The PUC denied the initial proposal, electing to use a future rate 

case. Lastly, the West Virginia case study examines the use of a unique financing mechanism for 

utilities, called securitization, in which bonds were created and sold to finance environmental 

 

1

The law specifically required the utility to examine the replacement of 900 MW of coal-fired generation.
4

upgrades. Securitization was sought as a way to help reduce the compliance costs for 

ratepayers and to protect the credit rating of the utility. The docket showcased a significant 

level of effort on the part of the PUC to develop the knowledge to utilize securitization, which 

was newly authorized by the legislature.

These examples collectively show that the PUC process can have a substantial effect on 

compliance planning and the resulting generation fleet. PUC determinations on both rate cases 

and compliance options appear to have been shaped by the underlying state code or the 

positions brought forward by intervenors during the process. More often than not, the final 

order was different from the utility’s original proposal. Frequently, the changes were significant, 

but not fundamental in nature. The intervenors often vigorously contested the amount of 

capital costs that could be placed in an environmental rider or recovered via CWIP. Among the 

most seemingly influential groups of intervenors on rate issues were the large industrial or retail 

customers, such as manufacturing facilities. In the Colorado, Indiana, and Florida cases, the 

intervenors’ detailed scrutiny of cost recovery plans seemed to have an impact on the PUC’s 

rate recovery decision. Nearly all of the case studies were controversial and received local 

media attention. This is not surprising given the PUC’s role as, essentially, the crucible for 

approving capital-intensive upgrades to be paid for by ratepayers.

For the upcoming suite of new regulations, including Utility Maximum Available Control 

Technology (MACT), the Clean Air Transport Rule (Transport Rule), Greenhouse Gas Best 

Available Control Technology (BACT), and Greenhouse Gas New Source Performance Standards 

(NSPS), the PUCs are likely to be examining a wide range of potentially acceptable mitigation 

strategies. They might benefit from a best practices document that can identify various 

approaches, their average costs, and a discussion of the full range of estimated benefits. The 

National Association of Regulatory Utility Commissioners (NARUC) would be well-suited to 

collaborate with EPA on such a document and could assist in arranging PUC input and 

dissemination.
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SECTION I. STATE PUBLIC UTILITY COMMISSIONS AND ELECTRICITY SECTOR REGULATION: 

CONTEXT, CORE RESPONSIBILITIES AND BASIC STRUCTURE 

A. Introduction

This Section provides an overview of the major regulatory agencies overseeing the electric 

sector, including PUCs, and their lines of responsibility. A brief history of how the electric sector 

evolved is included. This Section was designed to provide context for Section II, which examines

the various instruments that PUCs use in ratemaking and approving major modifications to 

power plants. 

Regulation of utilities was a response to the growth of, and the public’s dependence on, 

railroads and utility companies.2 These industries held substantial economic power because 

they were natural monopolies.3 An unregulated monopoly can dictate prices and extract higher 

profits at the expense of consumers. To curb this possibility, state and federal governments 

developed a regulatory apparatus to balance the need for the market to supply the services of 

natural monopolies while ensuring that these services are priced fairly and provided safely to 

everyone that requests them. The regulatory apparatus has evolved as the electricity sector has 

evolved and become deregulated in many states.

Historically, electric utilities were vertically integrated companies, meaning they owned the 

power generation, transmission grid, and distribution assets (e.g., substations, transformers,

and the distribution power lines to end users) in their service territory. These capital-intensive 

assets create high barriers to entry and give incumbents a natural monopoly over the 

generation, transmission, and distribution of electricity. Federal and state governments allow 

these monopolies to exist, but in exchange, the utility agrees to provide reliable and safe 

service, without discrimination, to any and all customers in its exclusive territories and agrees to 

have the prices it charges (rates) and the rate of return it earns on investments set by 

regulators. Regulators, in turn, agree to allow the utility to recover any costs that are 

“prudently” incurred in order to earn a “fair” return on its investment.

The regulation of the electric industry is split between states and the federal government. 

Federal agencies, largely the Federal Energy Regulatory Commission (FERC), have jurisdiction 

over the aspects of the industry that cross state lines – e.g., wholesale power transactions and 

interstate transmission of power including regional grid reliability. State agencies, which this 

report refers to collectively as state public utility commissions or PUCs, have jurisdiction over in-

 

2

Eric Filipink. Serving the Public Interest: Traditional vs. Expansive Utility Regulation. NRRI Report. 

October 2, 2009. 

3

A natural monopoly arises when a single supplier has an overwhelming cost advantage over potential 

competitors, with electric utilities as a classic example.
6

state power sales and the distribution of power to end users. The following section discusses 

the role and oversight responsibilities for a traditional PUC. 

B. State Public Utility Commissions and the Regulation of Traditional Electric Utilities

The first PUCs were established in New York and Wisconsin in 1907. Since then, every state has 

adopted some form of state utility regulation. With respect to electricity, the authority of state 

utility regulatory commissions typically includes:

Setting the electricity rates that customers are charged;

Issuing certificates of public convenience and necessity (CPCN) that permit the 

construction of new power plants and transmission lines and modifications of existing 

power plants (i.e.,, siting authority);

Overseeing the distribution of electricity at the retail level;

Creating standards for safety and quality of service (commonly referred to as reliability); 

Preventing discrimination among customer classes; and 

Providing a public venue for making electric utility decisions. 

The majority of state commissioners are appointed to their positions for multi-year terms by 

their governor or legislature, while commissioners in 13 states are elected. For example, the

governors in Minnesota, New Hampshire, and Texas each appoint commissioners to six-year, 

staggered terms. In each of these states, the governor designates one of the commissioners to 

serve as chair. In Florida, the commissioners are appointed to four-year terms, while in 

Wisconsin, commissioners are elected to five-year terms. Figure 1 illustrates which states elect 

their PUC commissioners and which states appoint them.

Elected

Appointed

Figure 1. Elected and Appointed PUC Commissioners (Source: NARUC)
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C. Federal Regulation: The Federal Energy Regulatory Commission 

Today, electricity market oversight resides in multiple places and varies depending on the state. 

Since the Federal Energy Regulatory Commission (FERC) oversees and enforces electricity 

markets in every state, we will start this discussion with FERC. FERC is an independent federal

agency that regulates the interstate transmission of electricity, natural gas, and oil, among other 

responsibilities. Five FERC Commissioners are appointed to five-year terms by the President; no 

more than three Commissioners of the same political party can serve simultaneously. Since 

FERC is an independent agency, there is no Congressional review of FERC. However, the 

Government Accounting Office (GAO) has authority to examine FERC's effectiveness. Table 1

outlines general FERC authorities relevant to electricity markets and also specifies where FERC 

does not have authority.

Table 1. FERC Authorities in Electricity Markets (Source: FERC)

FERC Authority Issues NOT within FERC Authority

Regulates the transmission and wholesale 

sales of electricity in interstate commerce.

Reviews certain mergers and acquisitions 

and corporate transactions by electricity 

companies.

Reviews the siting application for electric 

transmission projects under limited 

circumstances.

Protects the reliability of the high voltage 

interstate transmission system through 

mandatory reliability standards.

Monitors and investigates energy markets.

Enforces FERC regulatory requirements 

through imposition of civil penalties and 

other means.

Enforces accounting and financial 

reporting regulations and conduct of 

regulated companies. 

Regulation of retail electricity and natural 

gas sales to consumers.

Approval for the physical construction of 

electric generation facilities.

Regulation of activities of municipal 

power systems, federal power marketing 

agencies such as the Tennessee Valley 

Authority, and most rural electric 

cooperatives.

Regulation of nuclear power plants by the 

Nuclear Regulatory Commission.

Reliability problems related to failures of 

local distribution facilities.

Maintenance, including tree trimmings 

near local distribution power lines in

residential neighborhoods. 

Market oversight and reliability enforcement are FERC’s most-recognized functions. FERC 

provides market oversight by tracking the ten designated electricity markets in the U.S. The

geographic outlines of these electric power markets are shown in Figure 2. FERC and its 
8

designees analyze and oversee market functions in each of these electricity markets.4 Reliability 

oversight will be examined in Subsection E.5 

Figure 2. FERC Electric Power Markets (Source: FERC)

D. Deregulation and Redrawing Jurisdictional Lines

Since the early 1980s, nearly half of the states have broken away from the traditional mold by 

partially deregulating their utilities. The delivery of electricity to consumers and the associated 

charges remain regulated in all states. In deregulated states, generation and transmission assets 

have been divested to separate, non-regulated entities. This section will briefly review the 

federal and state actions that led to deregulation – which shifted the bulk of the oversight 

responsibilities from the PUCs to FERC and its designated Regional Transmission Organizations 

(RTOs). 

The utility industry began morphing in 1978 when Congress passed the Public Utility Regulatory 

Policies Act (PURPA), which was designed to promote renewable resources and reduce the use 

of foreign oil. The Act requires investor-owned utilities to buy electricity from certain non-utility 

generators at the price the utilities would have had to pay to develop their own resources –

their so-called “avoided cost.” Competition in the electric industry was further expanded when 

Congress passed the Energy Policy Act (EPAct) in 1992, which mandated open access to 

 

4

FERC’s analyses for these markets can be found at http://www.ferc.gov/market-oversight/mktelectric/overview.asp. 

5

Details regarding FERC’s electricity oversight functions can be found on FERC’s website at 

http://www.ferc.gov/.
9

transmission lines. A major effect of that legislation was to allow independent power producers 

(IPPs) access to transmission lines. In 1996, FERC issued Orders 888 and 889, which further

mandated open transmission lines. FERC also created Independent System Operators (ISOs) to 

ensure transmission access across state lines and mandated the unbundling of utility charges.6 

As transmission lines became more accessible, competition among power producers, both 

regulated and independent, increased.

7

 In this way, FERC Orders 888 and 889 helped spark 

deregulation, starting in California, as a way to further foster competition in the electricity 

market.

Deregulation entails the unbundling of vertically integrated electric utilities into separate 

generation, transmission, and distribution companies. While the distribution portion remains 

with the regulated utility, transmission and generation assets are either divested entirely or 

transferred to affiliates of the regulated utility. Thus, the traditional utility would become 

multiple companies – a deregulated power producer with generation assets, a deregulated 

transmission company, and a regulated distribution company that delivers electricity to end 

users (Figure 3). Distribution assets link end users with the transmission grid. The electricity 

distribution company is often still known as the “utility” and is often the main name seen on 

electricity bills. Once a traditional utility is broken up, the PUC no longer regulates electricity 

generation assets. The PUC retains jurisdiction over retail electricity sales to end-use 

consumers.8 

 

6

FERC Order 888 ordered "functional unbundling" of wholesale generation and transmission services, 

which means that each utility must state separate rates for its wholesale generation, transmission, and 

ancillary services, and must take transmission of its own wholesale sales and purchases under a single 

general tariff applicable equally to itself and others. 

7

FERC. Regional Transmission Organizations (RTO)/Independent System Operators (ISO).

http://www.ferc.gov/industries/electric/indus-act/rto.asp.

8

The U.S. Supreme Court interpreted the 1935 Federal Power Act as requiring that wholesale sales of 

electricity are classified as interstate sales subject to federal jurisdiction. New York et al. v. Federal Energy 

Regulatory Commission et al. Certiorari to the United States Court of Appeals for the District of Columbia 

Circuit No. 00-568. Argued October 3, 2001 - Decided March 4, 2002. 

Figure 3. Bulk Power Schematic (Source: NERC)
10

Traditionally, electric utilities owned all components of the electric power system shown in

Figure 3. In a deregulated state, the generating stations (black; left of figure), the transmission 

lines (blue), and the distribution system (green) are split into three separate companies, of 

which only the distribution system remains regulated by the PUC.

Deregulation has been met with mixed reviews by customers, elected officials, and some 

industry participants due to higher than expected electricity costs and other complexities. As a 

result, some deregulated states have begun to investigate the possibility of re-regulation.9 

Figure 4 shows which states have deregulated their electric power industries, as well as several 

that have suspended further deregulation. In order to manage new independent power 

producers and new transmission grid users, FERC Order 2000 encouraged the creation of 

voluntary Regional Transmission Organizations (RTOs) to replace PUC oversight of the 

transmission grid. The RTOs were created as non-governmental, independent oversight bodies. 

FERC also delegated market oversight and rate oversight to RTOs where they exist. FERC’s 

general position is that just and reasonable wholesale market costs can best be achieved 

through greater competition and market forces.

10

 

The Energy Policy Act of 2005 (EPAct 2005) transformed a number of aspects of electricity 

industry oversight, in addition to significant mandates in other areas. Under EPAct 2005, FERC 

gained new authorities to prevent energy market manipulation as well as to manage electric 

reliability and infrastructure (see the NERC discussion in Section E). To help alleviate congestion 

 

9

Tyson Slocum. The Failure of Deregulation: History, Status, and Needed Reforms. Public Citizen. March 

2007. http://www.ftc.gov/bcp/workshops/energymarkets/background/slocum_dereg.pdf.

10 U.S. Government Accountability Office. Electricity Markets: FERC’s Role in Protecting Consumers. June 

2003.

Figure 4. Electricity Restructuring by State (Source: EIA)
11

on the electricity transmission grid, EPAct 2005 allows FERC to site transmission lines in critical 

areas, and provides FERC with the authority to override state siting procedures. The Act also 

requires FERC to review repeal of 1930s-era restrictions on mergers and acquisitions by energy 

holding companies. 

Regulated and Deregulated States

While FERC has some authority in every state, oversight responsibilities vary by state depending 

on whether electricity generation and transmission are deregulated. For those states that have 

not deregulated their utilities, PUCs retain traditional oversight functions including rate 

oversight of retail and wholesale power sales within the state, in-state transmission, and in-state 

reliability. For those states that have deregulated the electric sector, oversight functions are 

now distributed over a patchwork of various governmental and independent, non-governmental 

bodies. These responsibilities in deregulated states are as follows:

Wholesale power sales and unbundled transmission sales are regulated by FERC, and by 

extension, the relevant RTOs where applicable.

Retail rates for end consumers are still regulated by the states, generally through PUCs,

but wholesale prices for electricity are set by the market.

PUCs may still retain some authority over building new generation and making large 

capital investments, such as installing pollution control technologies or taking 

generation off line.

Municipal utilities and electric cooperatives are regulated by local elected officials or 

boards of directors.

In addition to the regulatory agencies that we have discussed, there are some nongovernmental organizations that are active in the PUC arena. Two primary groups are the 

National Association of Regulatory Utility Commissioners and the National Association of State 

Utility Consumer Advocates. More detail on these groups is described in Appendix A.
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E. Reliability: Responsibilities PUCs, NERC, and FERC

Electricity reliability responsibility encompasses multiple organizations including PUCs, the 

North American Electric Reliability Corporation (NERC), FERC, and others. FERC created NERC 

based on its authorization by the 2005 Energy Policy Act, as the electric reliability organization 

to establish and enforce its reliability standards for the bulk-power system in the U.S. Since 

electrons cannot be stored and cannot be routed in specific directions (they flow toward the 

path of least resistance), generation and transmission need to be tightly coordinated, 

monitored, and controlled on a real time basis to ensure ample and consistent electricity flow. 

Power supply and demand must be balanced with ample reserve capacity along the 

interconnected grid. NERC is the organization designated by FERC to develop and enforce a 

portfolio of standards and regulations to ensure the reliability of electricity in North America.11 

NERC sets and enforces a suite of reliability standards, such as infrastructure coordination, 

maintenance, and protection standards, for the bulk power system. The bulk power system 

refers to power generators, transmission lines, and interconnections among neighboring 

transmissions systems that generate and transmit electricity over high-voltage transmission 

lines. It does not include the distribution system. PUCs are the organizations that generally 

monitor and enforce reliability issues in the distribution grid, where electricity is delivered to 

end users.

The reliability standards proposed by NERC must be approved by FERC to become legally 

binding.12 NERC works with eight regional entities to develop, enforce, and monitor compliance 

with reliability standards. The eight regional entities carry out compliance enforcement 

activities on behalf of NERC.13 The regional entities are shown in Figure 5, and include:

Florida Reliability Coordinating Council (FRCC)

Midwest Reliability Organization (MRO)

Northeast Power Coordinating Council (NPCC)

Reliability First Corporation (RFC)

SERC Reliability Corporation (SERC)

Southwest Power Pool Regional Entity (SPP RE)

Texas Reliability Entity (TRE)

Western Electricity Coordinating Council (WECC)

Figure 5 also illustrates the states these entities encompass. Members of the regional entities 

come from every aspect of the electric industry: investor-owned utilities; federal power 

agencies; rural electric cooperatives; state, municipal and provincial utilities; independent 

power producers; power marketers; and end-use customers. Since each region has unique 

 

11 NERC Website. Accessed November 2010. http://www.nerc.com/.

12 NERC. Company Overview. Accessed November 2010, http://www.nerc.com/page.php?cid=1|7.

13 NERC. Compliance: Regional Programs. Accessed November 2010. 

http://www.nerc.com/page.php?cid=3|23.
13

generating assets and issues, there are regional reliability standards for each region. NERC 

oversees these programs for consistency and fairness. 

NERC works with and applies standards to a whole variety of electricity groups in addition to the 

eight regional entities described above. For example, NERC groups large bulk power systems, 

like the one shown in Figure 3, together as “Balancing Authorities.” These Balancing Authorities 

are responsible for meeting many of NERC’s reliability standards for the bulk power system, 

including the real-time balance of supply and demand for electricity. There are currently 134 

Balancing Authorities in the U.S. that operate within Balancing Authority Areas. These areas are 

not spread evenly among the regional entities, as shown in Figure 5. 

Figure 5 Regional Entities and Balancing Authorities

NERC has developed an array of reliability standards that affect different entities14 depending 

on the nature and scope of the requirements.

15

 Some of NERC’s standards pertain to Balancing 

Authorities, or Reliability Coordinators, and others pertain to Transmission Operators. To 

illustrate the extent of reliability standards and the various entities that meet these standards, 

Appendix B includes a subset of NERC’s reliability standards. Despite the volumes of reliability 

 

14 NERC. Reliability Standards for the Bulk Electric System of North America. Accessed November 2010.

http://www.nerc.com/files/Reliability_Standards_Complete_Set.pdf.

15 Depending on the nature and scope of the standard, it could apply to all or some of the following 

entities: Reliability Coordinator, Balancing Authority, Interchange Authority, Transmission Service 

Provider, Transmission Owner, Transmission Operator, Generator Owner, Generator Operator, Load 

Serving Entity, NERC, or Regional Entity.
14

standards that exist, capacity reserve is one of the most often discussed reliability metrics. 

Typically, the capacity reserve is set between 12 and 15 percent and is enforced by the regional 

entities.

In addition to developing and seeing to the enforcement of reliability standards, NERC also 

compiles annual reliability assessments of the bulk power system. These include long-term 

reliability assessments as well as summer and winter assessments. In addition to these annual 

and regular assessments, NERC also issues special assessments as needed. A timely example is 

NERC’s special assessment of EPA’s upcoming regulations impacting the power sector. In that 

special report, NERC examined the potential reduction in generation that would result from the 

retirement of specific coal-fired units in response to the Utility Maximum Achievable Control 

Technology (MACT), the Clean Air Transport Rule (Transport Rule), regulation of Coal 

Combustion Residuals (CCR), and the Clean Water Act Section 316(b) regulating Cooling Water 

Intake Structures.

16

 

 

16 NERC. 2010 Special Reliability Scenario Assessment: Resource Adequacy Impacts of Potential U.S. EPA 

Regulations. October 2010. http://www.nerc.com/files/EPA_Scenario_Final.pdf.
15

SECTION II. STATE REGULATORY COMMISSIONS AND POLLUTION CONTROL STRATEGIES:

SOURCES OF AUTHORITY AND TYPES OF REGULATORY APPROVALS

Two functions of PUCs, ratemaking and siting authority, provide the most common jurisdictional 

hooks over pollution control strategies. Ratemaking comes into play in traditionally regulated 

states, where generation assets are still regulated, when the utility seeks to recover the costs of 

a project. This is traditionally done through a general rate case in which cost recovery is sought 

after the investment is made and the project is in service. The PUC determines whether the rate 

increase request should be granted, denied, or revised. 

Rate cases are an after-the-fact review, which can create a lengthy “regulatory lag” between 

shareholders’ substantial investment and the time when the rate increase by the PUC is 

approved and shareholders can begin to see a return. To address regulatory lag, PUCs often 

have a number of additional tools at their disposal that can be utilized to increase the certainty 

of a project’s ultimate approval and to accelerate the cost recovery process. These tools include 

siting certification, a process by which the PUC ensures that major utility decisions such as 

investment in new power plants, construction projects, or pollution control installations, are 

necessary and in the public interest. Certification can take place in both regulated and 

deregulated states, with deregulated states focusing on issues such as reliability and 

environmental issues and leaving issues such as need and cost largely to the market. 

A. The Ratemaking Process and Cost Recovery for Pollution Control Projects

Ratemaking Overview

The ratemaking process is a complicated, multi-step procedure that begins when the utility files 

a rate case with the PUC to recover new costs from major new infrastructure projects (e.g., a 

pollution control retrofit or plant fuel conversion) or an unexpected increase in operating or 

maintenance expenses. The two basic elements in the ratemaking process are (1) establishing 

the revenue requirement and (2) setting the rates that customers must pay (rate design).

Step 1. Establishing the Revenue Requirement. The revenue requirement is the total annual 

revenue a utility requires to recover all of the costs of serving its customers, including a fair 

return on shareholders’ investment of capital. In simple form, the revenue requirement consists 

of:

Revenue Requirement = Utility Expenses + (Rate of Return * Rate Base)

In this formula, the money spent by a utility falls into two categories, expenses (such as the cost 

of procuring fuel for a power plant) and capital investments, such as pollution control 

equipment. The rate base is the aggregate of shareholders’ outstanding capital investments. 

The rate of return on the rate base is determined by the utility’s cost of capital – the fair market 
16

return for shareholders’ investment. The rate of return is allowed, but not guaranteed. If costs 

exceed the expectations of the rate case, the shareholders may earn a lower return. 

Step 2. Setting the Rates (Rate Design). This process typically starts by apportioning relative 

cost burdens among different customer classes (e.g., residential, commercial, and industrial) and 

then designing a rate structure for each class that will result in meeting the revenue 

requirement. This includes dividing the rates into different schedules or charges (e.g., basic 

charge, energy charge (per kWh), and a demand charge (per kW)). An energy charge is similar 

to a metered use rate, while the demand charge is based on projected capacity needed to meet 

the customers’ peak demand.

Cost Recovery and the Rate Case

Ratemaking is a dynamic process, because the markets and the conditions in which the utilities 

operate and to which they must respond to are constantly changing. Rates are set to meet the 

conditions prevailing at the time and need to be reset as conditions change. Pollution controls 

provide an example. As environmental requirements change, utilities must invest in the 

equipment and strategies needed for compliance, which may require substantial capital outlays. 

If such expenses were not contemplated in the previous rate case, there will be a “revenue 

deficiency,” meaning that the revenue generated through the current rates will not be sufficient 

to meet the current revenue requirement. As a result, shareholders will, in effect, be receiving 

less than their approved fair rate of return until the deficiency is remedied.17

Filing a rate case is the traditional method for curing a revenue deficiency. Historically, the 

capital investment aspects of the rate case are reviewed after-the-fact, i.e., the investment has 

been made and the project entered into service before the case is filed. The PUC determines

whether the investment was prudent. The prudence review is based on the conditions 

prevailing when the decisions were made and often includes questions such as: 

Are the costs incurred to meet the needs of customers?

Are the costs necessary to provide adequate service?

Are the costs reasonable?

Was the technology selection prudent?

Is the plant investment used and useful?

Will ratepayers derive a benefit?

Is the capital investment consistent with any commission mandated integrated resource 

plan?18

All prudent aspects of the investment will be added to the rate base, while costs deemed 

imprudent will be disallowed and borne by shareholders.

 

17 When utilities seek cost recovery, they are seeking the recovery of two different costs: the cost of 

capital (i.e. a financial return on their shareholders’ investment) and the capital itself (return of 

shareholders’ capital over time). 

18 Lowell E. Alt, Jr. Energy Utility Rate Setting. 2006. 
17

As a general rule, capital investment in pollution controls that are required for compliance will 

be deemed a prudent investment. For example, as stated by the Alabama Public Service 

Commission in a case establishing an environmental compliance cost recovery mechanism:

[Environmental compliance costs] by definition are the product of governmental 

mandates establishing environmental requirements with which Alabama Power, 

by law, must comply. These are not costs that Alabama Power can simply 

choose not to incur, which in turn strongly supports a presumption that they are 

prudent expenditures.19

However, there are often nuances to this general rule that make approval less certain. For 

example, multiple options could be available to reach compliance, each with different costs and 

benefits. In addition, regulatory burdens may be uncertain or undefined, potentially making 

early compliance strategies more of a risk. In another possible scenario, aspects of a nominally 

prudent investment could be deemed imprudent and disallowed (e.g., because of inadequate 

cost controls). For example, a case in Indiana rejected activated carbon injection (ACI) 

technology to reduce mercury emissions, based on the assertion that there were numerous 

mercury emission control technologies under development at the time that could prove to be 

more economical and efficient. For more details see Section IV, Indiana Case Study.

Rate Case Mechanics: An Overview of PUC Procedure20

Although the process for rate cases, as well as other PUC cases, varies from state to state, it 

typically includes the following:

Application. The utility generally initiates a rate case by filing an application or petition 

with the PUC. The application will include the requested changes and supporting 

financial data and may include supporting written testimony. The application may also 

request an interim rate change in order to reduce the impact of the regulatory lag 

between filing and the date that new rates go into effect.

Intervention. Parties affected or otherwise interested in the case will have an 

opportunity to enter into the case. The rules governing intervention and the role that 

various intervenors are permitted to play (from active to passive) vary by state.

Schedule. The PUC or the parties will develop a schedule that include dates for filing of 

testimony, cutoff dates for intervention, dates for public meetings regarding the case, 

discovery deadlines, dates for hearings, and dates for filing of briefs.

 

19 Alabama PSC Docket Nos. 18117 and 18416, Order, Petition to amend Rate CNP (Certified New Plant) to 

provide for the recovery of costs incurred to comply with environmental mandates. October 29, 2004.

20 For additional detail, see Lowell E. Alt, Jr. Energy Utility Rate Setting. 2006. pp 99-108.
18

Audits. State regulatory staff and parties audit the utility’s books and records to 

determine compliance with statutes, tariffs, commission rules, and orders and to 

determine the reasonableness and prudence of the utility’s expenses and investments.

Discovery. Discovery is the process by which parties obtain information from each 

other through written requests and answers. Discovery can be quite extensive, 

generating possibly thousands of data requests in a large general rate case, and often 

spawning disputes that must be resolved by the PUC and the intervening parties before 

moving the case forward. 

Written Testimony. Testimony in the rate case is both written and oral. The utility

typically files written testimony as its direct case. This includes the testimony, 

supporting data, and exhibits necessary to explain and support the utility’s revenue 

requirement request. Testimony from other parties follows to rebut specific aspects of 

the utility’s direct case. 

Hearings. Oral testimony is provided at public hearings, usually by the same people 

providing the written testimony, providing the other parties an opportunity to crossexamine witnesses. It is not uncommon for hearings to be opened to the public to 

include questions and comments from the local community as well. 

Briefing and Orders. Briefs are filed by each party summarizing its position and 

articulating its key arguments. After the briefing is complete, negotiation between the 

utility and intervenors often helps defuse debates. The PUC renders a decision and 

order on the case.

Approval. Once a rate case is approved, the new rates are put into effect and the 

changes are reflected in customer’s bills.

B. Beyond the Rate Case: Tools to Enhance the Chances and Timing of Cost Recovery

Traditionally, cost recovery is approved after the project is complete, through a rate case. 

However, cost recovery via an after-the-fact rate case may put utility shareholders at risk of an 

incomplete recovery, can affect the utility’s creditworthiness, and may put consumers at risk of 

periodic “rate shocks” as several large-cost items accrued over a period of time are rolled into a 

single rate adjustment. 

Over the past two decades, PUCs have addressed this dynamic by developing mechanisms that 

(1) provide more certainty that the rate case will have a favorable outcome through some form 

of pre-approval, and (2) provide some form of early cost recovery without resorting to a full rate 

case in order to reduce regulatory lag. In the context of pollution control projects, these 

mechanisms are often combined as a way to move the projects forward expeditiously while 

reducing overall risk to utilities and ratepayers. 
19

Regulatory Pre-Approvals

State PUCs can provide a number of pre-approvals for pollution control projects. The intent of 

the pre-approval is to assess the prudence of the pollution control strategy before construction 

begins by addressing issues such as the need for pollution controls; selection of alternative, costeffective strategies and technologies; and the range of acceptable costs. While this process 

addresses many critical aspects of prudence review up front, in most cases it does not guarantee 

full cost recovery – the project will still be reviewed on a periodic basis or upon completion to 

ensure that costs remain reasonable and controlled. This section provides an overview of a 

number of pre-approvals that are utilized for pollution control strategies. 

Certification

The certification process is utilized by PUCs to ensure that regulated entities are acting in the 

public interest and adhering to applicable rules and regulations. In the context of electricity 

generation, certification is often used as a siting tool to screen whether a proposed project is 

needed and whether it will serve the public interest – e.g., if the project will meet regulatory 

requirements, enhance reliability and safety, and provide low-cost electricity to ratepayers. 

Certification is most commonly used to review proposals for new power plants, but in many 

states it also applies to other major financial commitments, such as pollution control projects. 

Often the certification is in the form of a Certificate of Public Convenience and Necessity (CPCN).

In thirty states, the certification process includes consideration of environmental protection. 

This process may occur through a full-blown regulatory proceeding, or by acknowledging that 

another state agency with expertise on the issues (e.g., state environmental and public health 

agencies) has undertaken an appropriate review that will be incorporated into the certificate.

21

 

For example, Kentucky requires new generation facilities to be certified by the PUC. As part of 

the process, the project is reviewed by the state's Environmental Cabinet. PUCs may also have a 

role in reviewing compliance with federal environmental standards. Under Michigan law, for 

example, the Michigan Commission must ensure that all electrical power generating facilities in 

the state comply with all federal rules, regulations, and mercury emissions standards.

22

Because the certification inquiry often goes beyond rates and recovery, it may be utilized in 

both regulated and deregulated states. In regulated states, the certification can act as a preapproval for rate recovery by addressing a number of prudence issues, such as need for the 

controls, technology selection, and cost. In deregulated states, rate recovery is not on the table. 

Consequently, issues such as cost tend to be minimized (since the market is expected to dictate 

whether these are reasonable), and the inquiry may focus on issues such as reliability or other 

factors. To the extent that certification review does include environmental issues, PUCs may 

defer to the expertise of state environmental agencies that are also reviewing the project. The 

 

21 Michael Dworkin, et al. The Environmental Duties of Public Utility Commissions. Vermont Journal of 

Environmental Law. 2006.

22 Id.
20

cases studies in Section IV of Maryland and Indiana provide examples of the certification process 

in the deregulated and the regulated contexts.

Resource Plans

Integrated resource plans (IRPs) are comprehensive planning tools used by utilities and other 

energy planners to design reliable and least-cost approaches to providing electric service while 

addressing the risks and uncertainties in the electric utility business. IRPs are usually developed 

periodically through a public process that includes PUC staff, state agencies, customer and 

industry advocacy groups, project developers, and other stakeholders. The plans include an 

assessment of both supply-side and demand-side alternatives, a long-run analysis of 

alternatives, a short-term action plan, full assessment of all risks associated with each 

alternative, and analysis of external costs such as environmental costs and how those costs may 

affect resource choices. The value of a resource plan as a pre-approval depends on the extent 

of the PUCs involvement in developing the plan, whether the PUC provides a formal approval of 

the plan and the extent to which the pollution control strategy adheres to the plan in practice.

Comprehensive Environmental Compliance Plans

Legislatures in some states have mandated that utilities provide plans demonstrating how the 

utilities will meet federal and state air quality compliance obligations. These requirements are 

often coupled with mechanisms for cost recovery. For example, Colorado passed legislation in 

2009 that required “a coordinated plan of emission reductions” from coal-fired power plants 

that “will enable Colorado rate-regulated utilities to meet the requirements of the federal Clean 

Air Act and protect public health and the environment at a lower cost than a piecemeal 

approach.”23 The plan will include the utility’s compliance strategy for all of its coal-fired power 

plants and provide a method for cost recovery. The process for developing the plans is shared 

by the Colorado PUC and the state’s air quality agency, providing multiple points for public 

review and participation. Once the PUC and the state air quality agency approve the plan, they 

must be ratified by the legislature. This comprehensive process essentially guarantees costrecovery for the approved plan as long as actual costs incurred remain within a reasonable 

range of the projections. This process is described in more detail in Section IV, Colorado Case 

Study.

Project Specific Pre-Approvals

States may also use a more targeted approach by allowing pre-approvals for pollution control 

strategies at specific power plants. For example, Minnesota passed legislation in May 2010 

allowing utilities to apply for an “Advance Determination of Prudence.”

24

 Under this process, a 

utility may seek advance prudence review from the PUC prior to making equipment upgrades 

required to comply with state and federal air quality standards. The utility must provide the 

 

23 State of Colorado. House of Representatives. House Bill 10-1365. 67th General Assembly. 2010. 

http://www.leg.state.co.us/clics/clics2010a/csl.nsf/fsbillcont/0CA296732C8CEF4D872576E400641B74?Op

en&file=1365_ren.pdf.

24 2010 Session Laws Chapter No. 373. May 20, 2010.
21

PUC with a description of the project, an implementation schedule, a cost estimate, and a 

description of the utility’s efforts to ensure the lowest reasonable costs. The utility may begin 

recovering the upgrade costs in the next approved rate case after the advance determination of 

prudence. The goal of the program, which is in effect through 2015, is to give lenders comfort 

that the utility has the PUC’s blessing to proceed with the mandated upgrades. Without it, 

utilities might be denied a loan or be required to pay a higher interest rate, leading to higher 

costs and resulting in higher rates to consumers.

Legislatively Mandated Pollution Controls

Other states have been more prescriptive by mandating specific forms of pollution controls 

either generally or for specific power plants. For example, in New Hampshire the state 

legislature developed special legislation for non-divested assets – generation assets that had not 

yet been sold as part of the state’s deregulation program. The legislature provided a general 

pre-approval where the utility would be allowed to modify or retire a unit if the PUC finds “it is 

in the public interest of retail customers of [the utility] to do so, and provides for the cost 

recovery of such modification or retirement.”25 However, the legislature also made a special

finding that a wet scrubber at one plant was in the public interest, providing an incentive to add 

a wet scrubber at that site.

Environmental Cost Recovery Mechanisms

Many states allow utilities to recover costs through a periodic adjustment mechanism instead of 

a general rate case. These rate mechanisms adjust automatically to changes in the utility’s 

underlying related costs. These cost recovery mechanisms go by different names, but are 

generally referred to as “Automatic Adjustment Clauses” or AACs.26

AACs are usually used to address volatile commodity costs arising in wholesale markets, such as 

fuel and purchased power costs. Such costs are outside the control of the utility and, therefore,

the prudence issues surrounding cost increases are narrower. However, capital costs associated 

with mandatory investments, such as the pollution control investments, are increasingly being 

recovered through some form of AAC. As noted above, utilities have little discretion in deciding 

whether they will comply with regulatory mandates, so automatic recovery in some form is 

often allowed because the risk of imprudence is lower. At the same time, improving the 

certainty surrounding recovery will lower the costs of financing the project by protecting the 

debt ratings and creditworthiness of the utility. However, like pre-approvals, AACs do not 

provide complete certainty – the investments are still subject to periodic prudence review 

audits.

A 2006 survey performed by The Brattle Group found that, of the 27 traditionally regulated 

states that currently have AACs, 11 states allow rate adjustments for environmental capital costs 

 

25 RSA 125-O:11, VI

26 The Brattle Group. Electric Utility Automatic Adjustment Clauses: Benefits and Design Considerations. 

Prepared for the Edison Electric Institute. November 2006.
22

and for the cost of emissions allowances.27 These programs go by various names – air quality 

improvement rider, environmental improvement rider, energy cost adjustment, environmental 

cost recovery surcharge, etc., but they tend to have the same basic features: a routine, 

simplified process for recovering environmental costs, by adding them to the rate base or 

setting up a separate surcharge for direct recovery of the costs, that does not require prior 

review and approval but does include after-the-fact auditing and a process for “truing-up” 

expenses on a regular basis. 

Alabama Power’s environmental recovery mechanism provides an example. In October 2004, 

the PUC approved a dedicated recovery mechanism for environmental control compliance 

costs.28 The PUC decided not to require a pre-approval or other prudence review – these 

decisions were left to the state environmental agency, the utility and its parent company. The 

utility is required to provide an environmental control plan to inform the PUC and stakeholders 

of its plans and projected costs, but the plan is not subject to a formal process. With these 

prudence issues addressed, the Alabama process focuses on cost recovery. The utility estimates 

new environmental costs each year and Tariff CNP, one of the charges paid by each rate class, is 

adjusted to reflect the new costs. This includes an annual “true-up” process where the actual 

costs from the previous year are compared to the projections and the difference applied to the 

current year adjustment. 

CWIP

In addition to environment specific mechanisms, some utilities in certain states can also take 

advantage of general capital cost recovery mechanisms, such as “construction work in progress” 

or CWIP. A number of states have adopted this mechanism to address the often substantial 

regulatory lag created by major construction projects where significant costs can accrue over 

several years before the project is placed in service and eligible for rate recovery. The Indiana 

case study provides an example of how CWIP can be used with pre-approvals to increase the 

certainty and pace of rate recovery.

Securitization

Securitization is a financial tool that essentially packages bonds backed by fairly certain recovery 

and sells the bonds on the market as a highly rated security. Securitization can be used by 

utilities to fund pollution control projects by using ratepayer funds as the source for paying the 

return on the investment. This is typically done by placing a special surcharge on customer bills 

dedicated to payment on the bonds. These customer-backed bonds give investors confidence 

that that their investment will have a very high probability of being paid back. Because the risk 

is low, the bonds will be highly rated and the utility will get a lower interest rate than it would 

normally receive by financing the investments through traditional debt finance, ultimately 

 

27 Id.

28 Docket Nos. 18117 and 18416, Order, Petition to amend Rate CNP (Certified New Plant) to provide for 

the recovery of costs incurred to comply with environmental mandates. October 29, 2004.
23

saving ratepayers money. 29 An example of securitization can be found in Section IV, the West 

Virginia case study.

 

29 Edison Electric Institute. State Regulatory Update: Rate Impact Mitigation Measures. June 2010. 

http://www.eei.org/whatwedo/PublicPolicyAdvocacy/StateRegulation/Documents/rate_impact_mitigatio

n.pdf.
24

SECTION III. TIMING ANALYSIS

Discussion of compliance time is often focused around the amount of time required to make the 

physical modifications to install pollution reduction equipment, but in many states, certifications 

and approvals are required before a plant owner can begin construction. In the context of this 

PUC Study, it is worth examining the time requirements of the various PUC processes as they

relate to add-on control installation. However, in some states, no pre-approval is needed and 

the PUC only reviews the project formally when the rate case is filed. 

A. Ratemaking and Regulatory Lag Time

The Edison Electric Institute (EEI) tracks the PUC processes related to its members, investorowned utilities. As part of this service, EEI tracks regulatory lag time, which they define as the 

time between a rate case filing and a decision by the PUC. According to EEI’s data, from Q1 

1990 through Q3 2010, the lag time for rate cases averaged around 10 months.

30

 Figure 6 tracks 

the regulatory lag time for rate cases over the past two decades. Generally, rate cases come to 

the PUC after any equipment included in a rate request has been installed, and these cases do 

not usually include any type of pre-approval for a pollution control project. The mid-1990s and 

early 2000s reflect a high volatility in lag time during the years of frequent deregulation and 

restructuring.

 

30 Edison Electric Institute. Rate Case Summary: Q3 2010 Financial Update. 2010. 

http://www.eei.org/whatwedo/DataAnalysis/IndusFinanAnalysis/Documents/2010_Q3_Rate_Case_Sum

mary_Final.pdf.

Figure 6. EEI Lag Time Analysis 1990-2010
25

B. Pre-Construction PUC Approval Times

While the regulatory lag time for rate requests is illuminating, there are often other mandatory 

or optional PUC approval processes conducted before a project has begun construction. Along 

with permits from the state’s Department of Environmental Protection, utilities or generation 

owners are in some cases required to obtain a construction approval, CPCN, or other certificate

from the PUC. Optional processes also exist in some states in which utilities can apply for 

assurances of cost recovery, ratemaking treatment, or accounting treatment for pollution 

control projects before beginning construction, as discussed in Section II. For example, utilities 

may be able to apply for use of an environmental surcharge to fund the capital costs of future 

projects, for permission to include their construction costs in rates before the project is 

completed (CWIP), for an advance determination that the project is “prudent” and will be 

eligible for cost recovery, or to allow deferred accounting treatment for the costs of a project. 

This type of pre-approval is favored by utilities because it provides more financial certainty

before embarking on an expensive project. The process of obtaining pre-approvals from the 

PUC has important implications for compliance with environmental regulations. If the approval 

process before construction commences is lengthy, it has the potential to delay compliance. 

Even if an approval is not mandated, utilities may find it financially necessary to avail themselves 

of the optional pre-approval processes before beginning a pollution control project.

Methods

To better understand the time required to obtain approvals needed before breaking ground on 

pollution control modifications, this analysis examined pollution control retrofits at existing coal 

plants. Using a database of scrubber installations assembled from EPA and proprietary data 

(Table 2), we identified the states that had one or more scrubber installations in 2010, and 

selected those states for analysis. The states were Alabama, Florida, Georgia, Illinois, Indiana, 

Kentucky, Maryland, Minnesota, Missouri, New Jersey, New York, North Carolina, Ohio, 

Pennsylvania, Virginia, West Virginia, and Wisconsin.

31

 Data from Colorado were also included 

because it was one of the six case studies.

Because the names of approval processes vary from state to state, and docketing systems are 

often difficult to navigate, personal contact with PUC staff was sometimes necessary to obtain 

information about any pre-approvals required for pollution control projects in the state and to 

identify docket numbers of specific cases involving these approvals.

 

31 Though it had nine scrubber upgrades in 2010, Tennessee was excluded from analysis because all of the 

upgrades were at Tennessee Valley Authority plants. TVA is not regulated by the Tennessee Regulatory 

Authority.
26

Table 2. Scrubber Installations by Year

Year Scrubber Came Online

State 2004 2005 2006 2007 2008 2009 2010 2011 2012

No. of 

Scrubbers

Alabama 3 1 1 4 1 10

Arizona 1 1 2

Colorado 2 2

Florida 4 1 5

Georgia 7 2 1 2 12

Illinois 2 3 5

Indiana 2 2 2 2 2 7 17

Iowa 2 1 3

Kentucky 3 1 1 1 2 3 11

Maryland 7 2 9

Massachusetts 1 2 3

Michigan 2 2

Minnesota 1 3 1 5

Missouri 2 2

New Jersey 2 1 3

New York 1 5 6

North Carolina 1 3 5 5 7 1 1 1 24

North Dakota 1 1

Ohio 1 6 4 8 3 22

Pennsylvania 2 2 8 5 17

South Carolina 2 2 3 7

Tennessee 1 9 4 14

Texas 2 2

Utah 1 1

Virginia 1 5 3 9

West Virginia 3 2 1 1 1 8

Wisconsin 1 1 1 3

Wyoming 1 1

No. of Scrubbers 4 4 15 20 38 49 58 16 2 206

This analysis focused specifically on cases dealing with add-on emissions controls for NOX, SO2, 

mercury, and particulate matter. Other types of environmental projects were included only if 

they were included in the same filing as an add-on emissions control. Efforts were made to 

include all cases involving pre-approvals for add-on emissions controls that concluded prior to 

December 31, 2010, and were available in a state’s online docketing system. 

For the states examined, we provide a summary of the type of pre-approvals allowed or 

required for pollution control projects, as well as an analysis of the time between initiation of a 

case and final action. The time taken for construction planning and assessment, or the time 

required to obtain permits from other agencies, are not included in this analysis; it solely reflects 

the time taken by the PUC to review and approve a case prior to construction.
27

Results

PUCs in deregulated states, because they do not have jurisdiction over the generation 

component of electric rates, cannot provide any pre-approval processes for cost recovery of 

emissions control projects; nor, for the most part, do they require construction approvals. For 

example, Pennsylvania does not require or allow any pre-approvals, nor does the partially 

deregulated Ohio. Maryland is an exception; although deregulated, it requires generation 

owners to obtain a CPCN before constructing any emissions controls.

Regulated states, on the other hand, take a wide variety of approaches to certifying emissions 

control projects. Some states, such as Indiana and Florida, have laws specifically authorizing or 

even requiring certain kinds of pre-construction cost recovery for emissions control projects. 

Others, such as Missouri, leave it up to utilities and the PUC to decide the best approach. Table 

3 summarizes the different states’ policies, and lists the average length of pre-construction PUC 

cases.

Table 3. Summary of Timing Analysis Results

Electricity 

Regulation

Pre-Construction 

Certificate

Pre-Approval of Cost 

Recovery32

Average Length of 

Pre-Approval Case

Alabama Regulated Not required Allowed N/A

Colorado Regulated Not required Allowed 6.64

Florida Regulated Not required Required 5.53

Georgia Regulated Not required Allowed 6.02

Illinois Deregulated Not required Not allowed N/A

Indiana Regulated Required Allowed 9.75

Kentucky Regulated Required Allowed 5.65

Maryland Deregulated Required Not allowed 8.00

Minnesota Regulated Not required Allowed 9.77

Missouri Regulated Not required Allowed (limited) 5.05

New Jersey Deregulated Not required Not allowed N/A

New York Deregulated Not required Not allowed N/A

North Carolina Regulated Not required Not allowed N/A

Ohio Partially 

deregulated

Not required Not allowed N/A

Pennsylvania Deregulated Not required Not allowed N/A

Virginia Regulated Not required Not allowed N/A

West Virginia Regulated Required in some 

circumstances

Allowed 11.71

Wisconsin Regulated Required Not allowed 3.79

All states 7.19*

* This is the average of each individual state’s average, not the average of all cases, in order not to weight 

states with a large number of cases more heavily. The average of all cases was 6.33 months, and the 

median was 5.95 months.

 

32 See Appendix C for a more detailed explanation of individual state policies, and reasons for excluding 

certain states from analysis.
28

In several states, including Ohio, North Carolina, Pennsylvania, and Virginia, no approvals are 

required or allowed by the PUC prior to installation of control technologies. These states were

not included in the timing analysis. The absence of these approvals, however, suggests that 

utilities in these states have fewer hurdles prior to construction and, therefore, would be able to 

begin installation of control technologies more quickly once all required environmental permits 

have been received. Most regulated states either require or allow an approval (either a CPCN or 

an authorization pertaining to financial terms) before construction for control technologies 

commences. Figure 7 shows the length of every case examined in the states that require or 

allow a PUC approval before an owner may install a control technology on a facility. The PUC 

process times in some states, like Kentucky, were very consistent. This is due to the fact that 

there is a statute in Kentucky that requires the PUC to process environmental plans within six 

months. Other states, such as Wisconsin and Florida, appeared to have much more variable 

process times. Drawing conclusions from these data is difficult, given that they compare 

different types of cases both between and within states.

Figure 7. PUC Process Time for Approvals Prior to Construction in Ten States
29

The average length of approval across states33 was approximately seven months, and only six of 

the 101 cases took longer than a year. Nonetheless, a great deal of variation did exist in the 

length of cases. Many of the longer cases had multiple intervenors or involved complex issues. 

Several of these approval processes are examined thoroughly in Section IV, which details specific 

examples as case studies.

Detailed summaries of the policies in each state are included in Appendix C, and Appendix D lists

all cases used in the analysis.

 

33 This is the average of each individual state’s average, not the average of all cases, in order not to weight 

states with a large number of cases more heavily. The average of all cases was 6.33 months, and the 

median was 5.95 months.
30

SECTION IV. CASE STUDIES

In order to better explore the similarities and differences between PUC processes, this section 

will provide detailed analysis of six PUC cases in six different states. The case studies are 

centered on the PUC approval process and investigate the docket for a specific control 

technology upgrade or rate case. They illuminate the role of the PUC in shaping policy and 

defining the ultimate compliance strategy that a utility employs. With the exception of 

Maryland, these cases are from states that are not deregulated.

The first three cases spotlight how the PUC authorizes specific control technology choices; they 

include Colorado, Indiana, and Maryland. The second set of cases, including Florida, Georgia, 

and West Virginia, examine new and traditional financing mechanisms for compliance with air 

quality regulations. 

A. Colorado Case Study 

The Colorado case study contains a microcosm of the national debate surrounding fossil fuel 

choices in the U.S. This case includes vigorous stakeholder debate and involves postcombustion controls, early retirement of coal-fired generation, fuel switching, and the 

construction of new natural gas-fired capacity. The rate case aspect of this PUC process is also 

interesting, as it seems to have been modified based on concerns raised by large customer 

intervenors. The negotiations summarized in this case study may help EPA establish 

expectations for similar PUC processes as utilities and legislatures explore innovative 

approaches to upcoming regulations.

Public Utilities Commission of Colorado

The Colorado Public Utilities Commission (PUC) has full economic and regulatory authority over 

intrastate telecommunication services, investor-owned electric, gas and water utilities, as well 

as partial regulatory control over municipal utilities and electric associations. The PUC 

leadership is small in comparison with others; it includes three members who are appointed by 

the Governor and confirmed by the Senate for a term of four years. A director manages the 

staff and daily operations of the PUC. The agency is authorized to employ nearly 100 full time 

employees. The PUC is funded by fees paid by the regulated companies, not by general tax 

revenue. Two-thirds of the funding comes from fees paid by gas, electric, telephone, and water 

utilities. Within the PUC, the Energy Department is responsible for supporting the mission of 

the PUC to assure the availability of safe, reliable, adequate, and efficient electric, gas, and 

steam services to utility customers at rates that are just, reasonable, and not discriminatory. 

Colorado operates under the Western Electricity Coordinating Council (WECC). For a map of the 

WECC operating territory, see Section I, Figure 5. The WECC is the regional entity responsible 

for coordinating and promoting bulk electric system reliability in the Western Interconnection, 

and is the largest and most diverse of the eight RTOs designated by NERC. 
31

Colorado State Code

Much of the authority invested in the PUC, including utility rates, comes from Article 3.2 of the 

Colorado Revised Statutes (CRS). Article 3.2 includes a provision titled “Recovery of Air Quality 

Improvement Costs,” which states that a public utility shall be entitled to fully recover from its 

retail customers the air quality improvement costs that it incurs. In addition, Article 3.2 includes 

a provision stating that for plans that include the conversion or closure of coal generation by 

2015, and that will result in the utility earning less than its authorized return on equity due to a 

lag in the recovery of costs, the PUC will employ mechanisms to allow for cost recovery without 

requiring the utility to file a general rate case. These mechanisms may include a separate rate 

adjustment clause or other mechanisms as determined by the PUC.34 These clauses figure 

prominently in the Colorado Case Study. Like most states that have retained regulation of the 

utility sector, the PUC requires a CPCN, as authorized under Title 40, Article 5. 

Relevant Environmental Regulations

The Clean Air Clean Jobs Act

On March 15, 2010, Colorado Governor Bill Ritter introduced HB1365, the Colorado Clean AirClean Jobs Act (CACJ) in the House of Representatives. The House passed the bill on March 22, 

2010, and the Senate passed it on March 31, 2010. Governor Bill Ritter signed the CACJ into law 

on April 19, 2010. The bill’s lead sponsors were State Representatives Ellen Roberts (R) and Judy 

Solano (D) and Senators Bruce Whitehead (D) and Josh Penry (R).

The CACJ requires Colorado utilities that own or operate coal-fired generating units to develop 

emissions reduction plans for these facilities. These emissions reduction plans must apply to a 

minimum of 900 MW or 50 percent of the utility’s coal-fired capacity, whichever is less, but 

cannot apply to any capacity that the utility is already planning to retire by January 1, 2015. The 

plans are required to reduce NOX emissions at least 70 to 80 percent below 2008 levels by 2017. 

In addition, the Public Service Company of Colorado (PSCo) was required to examine (not 

necessarily implement) the impacts of repowering 900 MW of coal-fired generation. Utilities 

must seek approval from the Colorado PUC for these plans, and were required to submit them 

by August 2010. The CACJ states that the PUC will review the plans and either approve, deny, or 

modify them by December 15, 2010. The plans must be fully implemented by 2017. 

The bill is intended to promote the use of natural gas generation as a means to meet air quality 

requirements. The CACJ urges utilities to give primary consideration to replacing or repowering 

coal generation with natural gas, as well as to consider other low-emitting resources, including 

energy efficiency or replacement or repowering that can be accomplished with reasonable rate 

impacts compared with installing emission controls on coal-fired generating units. Among other 

 

34 State of Colorado. House of Representatives. House Bill 10-1365. 67th General Assembly. 2010. 

http://www.leg.state.co.us/clics/clics2010a/csl.nsf/fsbillcont/0CA296732C8CEF4D872576E400641B74?Op

en&file=1365_ren.pdf.
32

considerations, when evaluating utility emissions reduction plans, the PUC will deliberate 

whether the proposed scenarios promote Colorado economic development. 

This bill is the cornerstone for the Colorado case study. It did not pass the Colorado legislature 

without significant debate. Several officials opposed the bill. The Moffat County Commission 

sent a letter of opposition to state legislators on March 2010, and State Representative Randy 

Baumgardner and Senator Al White also opposed the bill. White said the bill would harm the 

coal industry in Northwest Colorado and could mean a loss of jobs at Twentymile Coal Company, 

which supplies coal to the power plants impacted by the bill.35

Summary

This case study explores the dynamics within the PUC process regarding early retirement for 

coal units and fuel switching from coal to natural gas. An added benefit of this case study is its 

recent completion, which makes it a timely example. 

The case study features the Public Service Company of Colorado’s (PSCo) plan for achieving 

compliance with Colorado’s “Clean Air Clean Jobs Act,” HB1365. The details of HB1365 are 

described in the previous section on Relevant Environmental Regulations, but it should be noted 

again that the bill requires full compliance by 2017. The timeline for the major modifications at 

PSCo was very compressed. The CACJ Act was signed into law in April 2010. It required an 

emissions reduction plan to be submitted to the PUC by August 13, 2010, and required the 

Commission to review the plan and enter an order by December 15, 2010. PSCo’s initial 

emissions reduction plan included early retirement of some coal-fired units, switching from coal 

to natural gas in multiple units, converting some units from boilers to synchronous condensers, 

constructing new combined-cycle natural gas units, and placing post combustion controls on 

some units. PSCo also included specific financial requests for recouping costs associated with all 

of the modifications proposed. The financial mechanisms requested included approval of a 

specific rate rider and tariff sheets to allow return on construction work in progress (CWIP), and 

recovery of incremental 2011 plant-related costs, like accelerated depreciation and removal 

expenses offset by reduced rate base starting in January 2011. 

Thirty-five groups were active intervenors in the consideration of this case. The major players 

included coal interests, natural gas interests, independent power producers, as well as large 

retail customers, like Wal-Mart. In addition, state and local governments entered testimony in 

this case, officials both from counties where coal mines are located (Mesa, Garfield, Rio Blanco, 

Moffat and Routt) and counties where natural gas plays are located and slated to expand 

(Weld). The group of intervenors held widely different views on many of the issues explored 

through this process since switching from coal to natural gas for nearly 1,000 MW of generation 

in Colorado would inevitably result in a shift of jobs from the coal industry to the gas industry. 

 

35 Brian Smith. Clean Air, Clean Jobs Act Signed into Law. Craig Daily Press. April 20, 2010. 

http://www.craigdailypress.com/news/2010/apr/20/clean-air-clean-jobs-act-signed-law/.
33

There were many areas of disagreement over PSCo’s emissions reduction plan and financial 

mechanisms spanning from the basic interpretation of the CACJ Act to the minutiae of modeling 

inputs. The procedural questions in this case were also highly contested, including the 

treatment and selection of confidential information, the schedule for intervenors seeking 

discovery, and the timeframes for submitting comments. The fate of one unit in particular, 

Cherokee Unit 4, generated considerable debate. Cherokee Unit 4 (350 MW) was one of the 

largest coal-fired units affected by the PSCo emissions reduction plan. At issue was whether to 

convert the unit to natural gas, retire it and build a new combined-cycle gas facility, or install 

emissions controls on the existing plant. Independent power producers also claimed that 

purchase power agreements could replace the generation at Unit 4. However, the PSCo 

reliability analysis demonstrated that multiple sources of power were needed at Cherokee in 

order to support the load demand in Denver.

In the end, the Commission-approved emissions reduction plan and approved financial 

instruments diverged from the initial proposals submitted by PSCo. The final PUC Order 

required the PSCo emissions reduction plan to be accelerated. The two units being controlled 

(Pawnee and Hayden 1) were ordered to have technologies installed earlier, Cherokee 3 was 

ordered to be retired two years earlier, and Cherokee 4 was ordered to be converted into a 

natural gas-fired unit by 2017. PSCo was denied the environmental cost recovery rider it sought, 

but was permitted to reapply through a rate case. The deferred accounting for accelerated 

depreciation and removal for the retired plants was approved. 

Chronology

The PUC opened the docket on this case on May 7, 2010, one month after the passage of CACJ, 

and closed it on December 15, 2010. The entire process, which included significant energy and 

emissions modeling (STRATEGIST), separate approval on the emissions reduction plan by the 

Colorado Department of Public Health and Environment (CDPHE), several public hearings, 

discovery, and testimony spanned only 8 months. The case was dense with testimonies, 

petitions, and rebuttals. 

Once the docket opened in May, stakeholders began petitioning the PUC to become official 

intervenors in the case. PSCo submitted a motion to limit the official intervenors to 25, 

encouraging some groups to merge so they would not be overwhelmed with discovery requests 

on such an accelerated timeframe. The PUC declined to restrict the number of intervenors and 

the total number included 35 official intervenors and five amicus curiae, though the PUC did 

encourage stakeholders to merge when possible. 

On May 18, 2010, PSCo submitted a motion for reconsideration to limit data requested by the 

PUC to specific plants, to supply emissions data for certain units, for more time to supply all 

needed documents, and to postpone discovery until August. In an unusual alliance, Peabody 

Coal and the Gas intervenors filed separate motions for the PUC to deny the request for 

reconsideration, both insisting that additional data were needed and discovery should begin as 

soon as possible. The Commission granted the bulk of the reconsideration request. 
34

On June 2, 2010, PSCo submitted a response to the Gas intervenors reiterating the need to limit 

the data to plants that will be affected and claimed insufficient time for intervenors to come up 

with plans that include plants not included by PSCo in their analyses. The PUC granted only part 

of the data requests submitted by Peabody Energy and the Gas intervenors. PSCo held a 

modeling workshop on June 11, 2010 to familiarize intervenors with inputs and take 

suggestions. The majority of intervenors submitted complaints to the docket that this process 

was inadequate for full participation.

On July 1, 2010, PSCo submitted its full list of modeling scenarios to the PUC. The plan was 

greeted with multiple petitions from intervenors expressing there were insufficient data to fully 

participate in the process and criticizing the narrow range of scenarios. 

On August 15, 2010, PSCo submitted its draft emissions reduction plan. Testimonies were 

submitted throughout September 2010. In October, CDPHE found that PSCo’s preferred plan 

did not meet the statutory requirements of the CACJ Act, as all reductions would not be 

implemented by December 31, 2017. PSCo modified its preferred approach by the end of 

October, retiring Cherokee 4 earlier. Also in October, the PUC considered a Motion for 

Disqualification concerning the PUC Chairman Binz and Commissioner Baker filed by the Coal 

Mining Association, which was denied. Testimony, rebuttal testimony and supplemental 

testimony regarding the new PSCo preferred approach continued through November 2010. On 

December 15, 2010, as mandated by the CACJ Act, the PUC approved PSCo’s emissions 

reduction plan, a long-term natural gas contract, and certain financial instruments for recouping 

the costs of compliance.

Facility Description

The initial PSCo emissions reduction plan proposed modifications to five of its coal-fired plants, 

affecting 10 units. Two of the units in the plan are only partially owned by PSCo; they are 

located at the Hayden plant. The plants and units affected by the emissions reduction plan are 

listed in Table 4, along with their nameplate capacity, the operation date, and the expected 

retirement date for the unit (as listed in the PUC’s Final Order). The proposed emissions 

reduction plan would impact approximately 1,800 MW of generation.
35

Table 4. Coal-Fired Public Service Plants and Units Affected by the Public Service Compliance 

Plan

Plant Name Unit Nameplate Capacity In-Service Date Expected life

Arapahoe 3 45 MW 1951

4 111 MW 1955

Cherokee 1 107 MW 1957 2017

2 106 MW 1959 2019

3 152 MW 1962 2022

4 352 MW 1968 2028

Hayden* 1 139 MW 1965

2 98 MW 1976

Pawnee 505 MW 1981 2041

Valmont 5 187 MW 1964 2024

*Capacity for the Hayden units represents the amount of capacity owned by Public Service at Hayden, not total capacity.

Source: Final Order, Public Utility Commission of the State of Colorado, Docket 10M-245E.

Modification Description

The PSCo plan detailed nine possible scenarios with different replacement generation portfolios. 

As required by the CACJ Act, PSCo modeled a number of different scenarios capable of achieving 

the emissions reductions and other requirements. PSCo’s preferred approach included the 

retirement of 903 MW of coal-fired generation. New combined-cycle natural gas-fired 

generation was also proposed. They considered their preferred approach to be “the least cost 

plan under our base case, moderate climate change assumptions and to be the lowest cost plan

... assuming no carbon legislation for the first 10 years.” The specific actions at each of the units 

in the approach are detailed in Table 5 below. 
36

Table 5. PSCo Proposed Compliance Plan (August 15, 2010)

Plant Proposed Modifications

Arapahoe Accelerate retirement date for coal-fired generation at Arapahoe Units 3 and 4 

to the end of 2013. For transmission voltage stability, continue to use both 

Arapahoe 3 and 4. Convert Arapahoe 3 to a synchronous condenser (no fuel 

burned).

Convert Arapahoe 4 to natural-gas fired generation at the end of 2013.

Cherokee Retire 213 MW of coal generation at Cherokee (Cherokee 1 and 2) by the end 

of 2011.

Convert Cherokee 2 to a synchronous condenser (no fuel burned) to provide 

Mega Volt Ampere Reactive for voltage stability.

Start construction on replacement generation at Cherokee station, which was 

proposed as an efficient 569 MW (summer rating) 2x1 combined-cycle

generation facility fueled with natural gas. Construction of this replacement 

generation at Cherokee was to be completed by the end of 2015.

Install in 2012 cost-effective emissions controls (selective non-catalytic 

reduction (SNCR) and upgraded 10 low-NOX burners) on the 352 MW Cherokee 

4.

Retire the 152 MW Cherokee Unit 3 by the end of 2017, after the new 2x1 

combined-cycle facility goes into operation and in order to meet the minimum 

emissions reductions required by the Act. Once Cherokee 3 is removed, there 

would be room to construct the 314 MW (summer rating) 1x1 combined-cycle

natural gas facility that will ultimately be used to replace Cherokee 4. This 

facility would go into service by the end of 2022, and Cherokee 4 would be shut 

down in 2022. 

Hayden By the end of 2016, install SCR emissions controls at Hayden. (The plan 

stipulates that these controls would be installed only if required by the Air 

Quality Control Commission in conjunction with the State Implementation Plan 

for regional haze.)

Pawnee By the end of 2016, install SCR emissions controls at Pawnee.

Valmont Close Valmont 5 by the end of 2017. This will end all coal burning at Valmont 

Station.

According to PSCo, the combined actions in Table 5, when fully implemented, would reduce NOX

emissions from the affected generating plants by almost 90 percent, SO2 emissions by 84 

percent, CO2 emissions by 51 percent, and mercury emissions by 85 percent. The preferred plan 

would require an investment of $1.3 billion in generation construction projects in Colorado.

Under the CACJ Act, the plan needed to analyze (not necessarily implement) replacing 900 MW 

of existing coal-fired generation. The PSCo plan met this goal. To support the new natural gasfired capacity envisioned, PSCo worked to develop a long-term natural gas contract. PSCo had 

negotiated a favorable long-term natural gas agreement with Anadarko Energy Services, which 
37

they estimated would save their customers over $100 million over short-term purchases of 

natural gas. This contract was submitted for approval by the PUC. To enable the greater 

quantity of gas to reach the generation stations, PSCo sought recognition by the PUC that new 

gas-fired units would need adequate gas transportation infrastructure and new gas 

transportation infrastructure facilities would need to be constructed.

PSCo requested PUC approval of several specific financial instruments. Chief among those was a 

new adjustment clause, called the Emissions Reduction Adjustment (ERA), to enable CWIP to 

recover costs the Company will incur under the Plan. Rider costs would be rolled into base rates 

as new base rates were set in future rate cases. The rider would commence in January 2011. 

Details regarding this rider and other financial instruments and requests are listed below in 

Table 6.

Table 6. Financial Instruments and Approvals Requested by Public Service

Approval of a new specific investment rider, the Emissions Reduction Adjustment ("ERA") and 

associated tariff sheets to allow current return on capitalized construction work in progress 

(CWIP) at Public Service's weighted average cost of capital including our most recently 

authorized rate of return on equity;

Recovery of incremental depreciation expenses associated with the shortened useful lives of 

Cherokee Units 1, 3, 4 and Valmont Unit 5, as well as the significant portions of Cherokee Unit 2 

starting January 1, 2011;

A finding that the Company's plan satisfies the requirement of "early conversion or closure of 

coal-based generation capacity by January 1, 2015" required by CRS §40-3.2-207 (4);

A finding that the Company has demonstrated "that a lag in recovery of the costs of the plan 

related to the investment required by such plan contributes to a utility earning less than its 

authorized return on equity" under that C.R.S. §40-3.2-207 (4), because the proposed rider does 

not fully compensate the Company for all costs incurred under the plan in the long-term;

A finding that actions needed to implement the approved plan are recoverable consistent with 

the provisions of the CACJ Act even if they occur after December 31, 2017, or in the alternative 

that the Commission considers it in the public interest to extend the recovery mechanisms 

approved by the Commission to the retirement of Cherokee Unit 4 and the construction of its 

replacement;

Studies, Reports, and Testimony

As required by the CACJ Act, PSCo submitted its emissions reduction plan to the PUC on August 

13, 2010. It contained nine emissions reduction scenarios, nine replacement generation 

portfolios, and several “bolt-on” analyses. The benchmark plan retained all coal-fired capacity 

and applied emissions control technologies. One of the scenarios replaced nearly all coal-fired 

generation with gas. The PSCo preferred approach is detailed in Table 5. It included both postcombustion controls and fuel switching. Reliability issues figured prominently in PSCo’s August 

13 report. Arapahoe and Cherokee stations were both seen as integral to reliably powering the 

Denver Metropolitan Area. The transmission system operators rely on power generation and 

voltage support from these sites. PSCo determined that significant generation, in the form of 
38

multiple units, needed to remain at Cherokee to ensure reliable transmission network to serve 

the Denver Metropolitan area load. Seventeen transmission lines run out of the Cherokee 

station for the greater Denver area. Thus, replacement scenarios for natural gas were focused 

on Cherokee. Still, retiring the largest unit at Cherokee and building a new combined-cycle 

generator posed some sequencing issues for PSCo due to limited physical space, so they 

proposed to first control NOX at Cherokee unit 4 with SNCR, which they could do quickly and 

inexpensively. That approach would have enabled PSCo to stage the retirement in a less costly 

way, which would have a lower rate impact on consumers and allow greater flexibility for the 

timing and construction of the replacement generator. PSCo also asserted that this timing 

would have less potential impact on reliability for the Denver area. 

PSCo generates a reserve capacity margin of 16.3 percent of the system’s peak load obligation. 

All scenarios were required to keep this margin consistent. Planned outages, upgrades, 

retirements and replacements needed to be sequenced to maintain the capacity reserve margin. 

A capacity excess across PSCo generation is projected from 2011 to 2015, so many required 

outages were scheduled within that time period when practicable. 

On September 17, 2010, the PUC submitted its independent report on the PSCo’s emissions 

reduction plan. The review pointed out areas in which the PSCo cost estimates seemed high, 

such as SCR in the space-constrained Cherokee Station and at Hayden. The review also found 

the cost estimates for construction of new combined-cycle natural gas plants too low, given the 

constraints of the site.

Key Testimony 

The docket for this case is by far the largest we examined; just the list of documents alone 

exceeds 20 pages and includes over 1,800 submissions. The plan impacts a substantial number 

of coal-fired plants, well over 1,000 MW, and contains plans for a significant shift from coal- to 

natural gas-fired generation. Given the volumes of documents in this docket it was not possible 

to characterize each one. Rather, we examined the docket carefully and attempted to 

characterize the essence of the intervenors’ testimonies. A full listing of the intervenors and a 

summary of the rationale they supplied to the PUC to become official intervenors is available in 

Appendix E. A synopsis of major intervenor testimonies is offered below in Table 7. These 

synopses often combine several of the testimonies submitted by the intervenor. 

Table 7. Synopsis of Intervenor Testimonies

Coal Interests: Peabody Energy, CMA, and ACCCE

The American Council for Clean Coal Electricity (ACCCE) testified that the loss of jobs directly and indirectly related to 

coal generation could cripple the Colorado economy and devastate the people that lose their jobs. ACCCE argued 

that PSCo’s assertion that there would be a net positive effect on the Colorado economy is flawed. ACCCE supports 

the scenario that puts post-combustion control equipment on all facilities to meet goals set forth in CACJ. ACCCE 

also argued that PSCo assumed, in its sensitivities, a $20 per ton charge on carbon escalating at 7 percent per year, 

which exceeds the most recent PSCo IRP assumptions. ACCCE petitioned the PUCs to request that PSCo analyze 

replacing 900MW of coal-fired generation with new supercritical electric generation technologies – which will cost 

consumers less than switching to natural gas.
39

The Colorado Mining Association (CMA) testified that PSCo-projected differential costs among the scenarios were 

not credible, as follows: In November 2007, PSCo sought to reduce its natural gas burning exposure due to price 

volatility. In March 2010, CMA testified that PSCo raised electricity rates by 8 percent due to increases in natural gas 

prices. Forecasted costs of natural gas are higher than forecasts for coal. PSCo forecasts the difference between 

coal and gas prices increases over time. (PSCo asserted that its long-term natural gas contract with Anadarko will 

mute price volatility.) CMA testimony cites a NERC study stating that increased use of natural gas could result in 

interruptions in fuel supply and delivery which could reduce reliability of the bulk power system. CMA advocates for 

using the metric of the levelized cost of electricity, which uses four factors, capital charge, operation and 

maintenance costs, and fuel costs. CMA asserts that the metric is superior as it allocates costs of a generator across 

its useful life. CMA further asserts that switching to natural gas will cost Colorado ratepayers more than PSCo 

estimates and will dampen the CO GDP (by between $3 and $12 billion), by rising costs to CO’s large energy-intensive 

economic sector. CMA estimated that the minimum number of job losses in Colorado resulting from PSCo’s plan 

would be 30,000. The plan would adversely impact the poor, who have fewer resources for higher electricity bills 

and higher costs of other goods and services due to higher energy costs. CMA also commented on PSCo’s modeling 

scenarios as inadequate, since they did not include new supercritical coal fired generation technologies. CMA 

believes that replacing 900MW of existing coal fired generation with supercritical new coal generation technologies 

falls well within the intent of the CACJ Act. In October, CMA filed a motion of disqualification claiming that PUC 

Commissioner Binz and others were involved in closed-door meetings to pass the CACJ Act and are not now acting 

impartially or in the interests of the Colorado ratepayers. This motion was denied, and the Governor’s Office 

weighed in on this issue in support of denying the motion.

Peabody Energy testified that the reliability analyses conducted do not conform with NERC and WECC requirements 

to examine changes in system characteristics, among other issues; that the ERA and CWIP proposals are 

inappropriate; and that the installation of synchronous condensers in lieu of generation is inadequate. The scenario

that controls all the coal-fired generation would cost $1 billion less than PSCo’s preferred approach. Thus the rate 

impacts of PSCo’s preferred scenario are dramatically higher. On July 6, Peabody submitted a rebuttal to PSCo 

modeling assumptions, claiming that natural gas fuel switching costs need to be reconsidered to include life-cycle 

impacts, specifically hydraulic fracturing, or “fracking.” Peabody believes fracking will soon be regulated to protect 

drinking water, which will lead to increased costs for natural gas. The need to better assess natural gas price risks 

and volatility was also stressed. Peabody promoted more “green coal” options for modeling. Further, they stressed

the need for reliability assurances for the plan, in particular demonstrating compliance with FERC, NERC, and WECC 

electric reliability standards, including assessments for transmission operation standards, transmission planning 

standards and voltage and reactive standards. 

(PSCo consistently denied the Gas intervenors’ need to reproduce STRATEGIST, arguing: “The Company has always 

taken the position that the Strategist model data base and inputs are Highly Confidential. Under license agreements, 

Public Service cannot legally provide parties with the STRATEGIST model. In addition, the input files to this model 

contain highly sensitive commercial information, including our projected fuel costs, our incremental heat rates of 

units, our maintenance schedules, and many other strategic operational data.”)

Peabody Energy petitioned the PUC to require Anadarko and Public Service to reveal all aspects of the long-term gas 

contract; the petition was denied.

Environmental Groups: Western Resource Advocates (WRA)

WRA filed an early petition for more data and earlier discovery, and supported a denial of PSCo’s reconsideration 

request. The WRA also petitioned to see more energy efficiency options in the modeling scenarios or bolt-on 

analyses.

Gas intervenors: Noble Energy, Chesapeake, and EnCana

On May 26, the Gas intervenors petitioned to deny PSCo’s request for data clarification, claiming more data are

required to effectively assess all new generation options, ensure that their STRATEGIST modeling has the same 

baseline assumptions, and that more detail on O&M and capital costs is needed. They also submitted that, “The 

scenarios offered by PSCo do not adequately take advantage of available generation from IPPs (540 MW in/around 

Denver).” They stated that PSCo’s modeling approach is insufficient, as “PSCo intends the Plan it will offer to the 

Commission to be the only available alternative ... allowing the intervening parties no reasonable opportunities to 
40

offer alternative solutions or input, and presenting the Commission with an all or nothing approach that denies the 

Commission its statutory and constitutional role.” The Gas intervenors entered the docket multiple times to suggest 

that replacing all coal-fired generation with gas-fired generation would most advantageous to Colorado. The Gas 

intervenors along with the coal interests sought more information regarding the details of the gas contract proposal 

with Anadarko. 

IPPs

The Colorado Independent Energy Association (CIEA) testified that the PSCo scenarios fail to adequately examine the 

use of existing natural gas capacity in the state. In October, CIEA petitioned the PUC that their due process was 

being disrupted by PSCo’s refusal to run STRATEGIST scenarios utilizing more purchased power, because they were in 

fact running the model on additional new truncated emission reduction scenarios. Thermo UNC has existing natural 

gas generation, yet none of the PSCo scenarios envision new contracts with their power. CIEA argued that using 

existing generation would be less expensive for consumers.

Southwest Generation Operating Company testified, using the STRATEGIST model, that power purchase agreements 

would cost ratepayers less than the PSCo self-build scenario.

Large Power Consumers

Wal-Mart testified that it supports the general goals of the plan, but believes that PSCo should develop a base rate 

case, which allows for more systematic consideration of costs, and should not include any costs not associated with 

compliance with CACJ into the ERA rider. PSCo proposes to start the CWIP component as early as January 2011. 

Wal-Mart believes that CWIP exposes ratepayers to risk on the investment prior to any benefits received rather than 

having the investors shoulder the risk after modifications are complete.

Climax petitioned for early discovery and for more data availability. They testified that the cost riders were not 

properly examined for their negative impact on the Colorado economy.

Federal Executive Agencies (FEA): The FEA claims that the ERA mechanism contains two primary cost components, 1) 

the component for the current recovery of weighted average cost of capital associated with CWIP for projects 

ultimately approved for CACJ compliance and 2) the component for the current recovery of the incremental increase 

in depreciation expense due to the early retirement of certain coal-fired steam generation units. The Federal group 

claims that the methodology for the ERA proposed by PSCo is flawed, seemingly attempts to reach beyond the 

authority in the CACJ Act, and will lead to undue enrichment of the Company’s shareholders.

Public Hearings

This case included a total of eighteen hearings from May 27, 2010 to November 20, 2010, 

including two pre-hearing conferences, two public comment hearings, and a status conference. 

The first round of hearings included ten hearings from October 21 through November 3, 2010. 

The PUC instructed parties that this round of hearings should focus on portions of the emissions 

reduction plan that were not impacted by PSCo’s direct testimony. Some of the issues parties

covered in these hearings included fuel costs, foreseeable emission costs, existing scenarios, the 

long-term gas contract, and cost recovery. The second round of hearings included three 

hearings, and was conducted from November 18 through November 20, 2010.

Final Determinations

The Commission examined PSCo’s revised preferred plan along with the competing STRATEGIST 

scenarios supported by the coal, gas, and independent power producers and other testimonies 

it heard. The Commission evaluated fuel cost forecasts, gas price forecasts, and cost forecasts 

for reasonably foreseeable emission regulations (i.e., carbon controls). After much 

disagreement over reasonable costs per ton of CO2, the Commission did not use a specific future 

cost per ton but considered each scenario’s carbon emissions reductions, as well as sensitivity to 
41

carbon prices as model outputs. The final Commission-approved Plan is summarized below in 

Table 8.

Table 8. Approved Commission Plan (December 15, 2010)

Plant Approved Modifications

Arapahoe Unit 3 (45 MW) Retire and convert to synchronous condenser by 2014 and installation 

of 90 MVAR of new shunt capacitors

Unit 4 (111 MW) Convert to from coal-fired to natural gas-fired by 2014

Cherokee Unit 1 (107 MW) Retire by 2011

Unit 2 (106 MW) Retire by 2011 and convert to a synchronous condenser and a 

90MVAR capacitor bank for system stability

Unit 3(152 MW) Retire by 2015

Unit 4 (352 MW) Convert from a coal-fired generation to natural gas-fired generation 

by the end of 2017

Construct new 2X1 CC natural gas plant (to recover generation lost by retirement)

Hayden Unit 1 (139 MW) Application of control technology: selective catalytic reduction by 

2015

Unit 2 (98 MW) Application of control technology: selective catalytic reduction by 2016

Pawnee Application of control technology: selective catalytic reduction, lime spray dryer, and 

sorbent injection controls by 2014

Valmont Unit 5 (187 MW) Retire by 2017

The approved emissions reduction plan diverges from PSCo’s initial preferred approach in the 

following respects:

It requires the installment of emission control technology earlier on Pawnee and Hayden 

Unit 1

It requires the retirement of Cherokee Unit 3 two years earlier (by 2015 rather than 

2017)

It requires the conversion of Cherokee Unit 4 from coal- to natural-gas fired by 2017 

(rather than controlling Unit 4 with SCR and running the plant using coal through 2022).

In the final Order, the Commission recognized the need for adequate gas transportation 

infrastructure, including a new pipeline that will eventually be included in the gas rate base. 

Further, the Commission approved the long-term gas contract with Anadarko. The Commission 

did not approve all of the financial instruments proposed by PSCo, as outlined in Table 9. 

Table 9. Financial Instrument Approvals and Denials (December 15, 2010)

Financial Instrument /Proposal Commission Ruling

Emissions Reduction Adjustment (ERA) 

Rider for CWIP commencing January 2011

Rejected.

Commission will allow “allowance for funds used 

during construction” (AFUDC), and PSCo may 

request actual recovery of CWIP in a general rate 

case.

Deferred accounting for accelerated Approved.
42

Financial Instrument /Proposal Commission Ruling

depreciation and removal (for the retired 

coal-fired plants)

Jurisdictional allocator in the assignment to 

wholesale customers of their proportional 

share of costs

Approved.

The Commission committed to recommending a structure and funding source for a program to 

assist in retraining Colorado mining industry employees if mining jobs are lost as a result of the 

implementation of the emissions reduction plan.

PSCo was required to submit amended CPCNs for the coal-fired generation units slated to retire. 

The CPCN filing requirements were simplified to cost estimates since the deliberations were 

complete. PSCo was also required to submit a simplified CPCN for the new combined cycle 

natural gas plant planned for the Cherokee Station, for ratemaking purposes. A modified CPCN 

was also required for the control technology additions planned at Pawnee and Hayden.

Project Status

Within the PUC’s final order approving PSCo’s emissions reduction plan, a 20-day period was 

provided within which to file applications for rehearing, reargument, or reconsideration (RRR), 

beginning December 15, 2010 and ending January 4, 2011. A number of parties filed such 

applications.

For example, the Office of Consumer Counsel recommended reconsideration of a portion of the 

approval, which stated that Commission staff will determine the structure and funding of a 

retraining program for employees of the Colorado mining industry if jobs are lost as a result of 

PSCo’s emissions reduction plan. OCC contended that “requiring PSCo’s customers to pay for 

the retraining of Colorado mining industry employees who lose their jobs as a result of the 

Commission’s Order is beyond the Commission’s authority granted by the Colorado Legislature 

in the CACJ Act or in any other statute.”

In addition, Peabody Energy Corporation submitted an RRR asserting that the hearing process 

for the proceeding was highly irregular, and that the time constraints imposed by the CACJ 

required the PUC to issue a final decision only 122 days after the date specified for filing the 

utility plan. Peabody further states that it is a denial of due process for the PUC to reduce the 

amount of time allowed for parties to present evidence. 

Gas intervenors in the case, including EnCana Oil & Gas, Noble Energy, Inc., and Chesapeake 

Energy Corporation, also submitted an RRR regarding parts of the case referring to future longterm gas contracts, and determinations regarding the treatment of highly confidential 

information in the proceedings. In addition, the Colorado Independent Energy Association filed 

an RRR requesting the PUC clarify a number of issues relating to Arapahoe Unit 4 and Cherokee 

Unit 4 coal-fired electric generating units, including clarification of the ambiguity in timing for 
43

retirement and replacement of these units. On January 26, 2011, the PUC denied the motions 

for reconsideration of PSCo’s emissions reduction plan.

Reflections

The issues raised by intervenors in this case are likely to be echoed in other PUC processes as 

utilities begin planning compliance strategies for the upcoming Utility MACT standards, the 

Transport Rule, GHG BACT, and GHG NSPS. Adding post combustion controls was a less 

expensive alternative than fuel-switching in nearly all the plants PSCo examined. Without 

explicit support from the legislature in the form of the CACJ Act, it is unclear if a PSCo plan 

retiring 900 MW of coal-fired generation and refueling with natural gas would be approved by 

the PUC or would withstand public opinion, given the impacts on the local mining community. 

Notwithstanding this, Colorado is in a unique position in having both coal and gas resources,

which enabled them to consider job shifts within the state. Of course, construction jobs for the 

new gas plants and new pipelines also figured prominently into the demonstration that 

compliance with the CACJ Act would be beneficial to the state’s economy. 

The intervenors in this case were savvy and well-financed, and were able to run the same model 

PSCo ran to underscore their positions. Prominent lawyers and national trade groups were 

active in the debate. Their participation is likely in future PUC deliberations concerning coalfired generation retirement and fuel switching. 
44

B. Indiana Case Study

Indiana provides a useful example of a state with ample coal resources and its approach to 

pollution controls. This case study examines a large suite of post-combustion control 

technology upgrades and provides a glimpse into compliance planning through the PUC during a 

period of regulatory uncertainty. Some states may already have or may begin to develop laws, 

like Indiana’s, that provide incentives to use local coal resources. The compliance paths for the 

Indiana case study may be imitated by other utilities in response to EPA’s next generation of 

regulations in many states where coal mining and coal-fired generation are both located in the 

state.

Indiana Utility Regulatory Commission

The Indiana Utility Regulatory Commission (IURC) was established in the early 1900s to regulate 

railroad activity. In 1913, the agency was given regulatory responsibility over natural gas, water, 

electric, telephone, and transportation services. As an advocate of neither the public nor the 

utilities, the IURC is required to balance the interests of all parties to ensure the utilities provide 

adequate and reliable service at reasonable prices. These utilities may be investor-owned, 

municipal, not-for-profit, or cooperative utilities. The IURC also oversees natural gas 

transmission and distribution within the state. The state of Indiana has a traditional, regulated 

utility sector and is part of the region served by the Midwest Independent Transmission System 

Operator (MISO). 

The IURC regulates the business of public utilities, including rates, financing, bonding, 

environmental compliance plans, and service territories. The IURC has regulatory authority 

regarding the construction of additional plants and equipment. In addition, the IURC has 

authority to initiate investigations of all utilities’ rates and practices. The IURC promulgates 

rules through a process requiring notice, a public hearing, and Commission adoption, as well as 

approvals from the Attorney General and the Governor.

The IURC consists of four members and one chairman, all appointed by the Governor. Under 

state law, at least one of the members must be an attorney qualified to practice law before the 

Supreme Court of Indiana, and not more than three of the members can belong to the same 

political party. The term of the Chairman and each of the Commissioners is four years, except 

when a member is appointed to fill a vacancy, in which case the appointment is for the 

unexpired term only. 

Attorney General

IURC

Governor’s Office

OUCC DNR Commerce IDEM

Energy Policy

Attorney General

IURC

Governor’s Office

OUCC DNR Commerce IDEM

Energy Policy

Figure 8. Executive Branch of Indiana State Government 
45

Hearing Procedures

A formal proceeding before the IURC begins with the filing of a Petition or Complaint before the 

Commission, or notice of Formal Investigation from the Commission. The matter is scheduled 

for a Prehearing Conference to establish a procedural schedule that includes dates for the filing 

of testimony and the date for the Evidentiary Hearing. In some instances, a public Field Hearing 

may be held in the utility’s largest service territory. Once the utility files its testimony, 

intervening parties to the proceeding and the Office of Utility Consumer Counselor (OUCC) may 

file their testimony, which contains evidence in support of their positions. The utility then has 

an opportunity to file rebuttal testimony in response to the testimony presented by intervening 

parties and the OUCC.

After all parties have filed their testimony, an Evidentiary Hearing is conducted by IURC on the 

date scheduled in the Prehearing Conference. During the Evidentiary Hearing, the parties 

present their direct and rebuttal testimony and witnesses are cross-examined. In every 

proceeding, the Commission issues its decision based on testimonies in the record. Following 

the close of the Evidentiary Hearing, the IURC issues an Order, or decision, on the proceeding. 

Determinations made by the IURC in its Orders may be appealed to the Indiana Court of 

Appeals.

Indiana Office of Utility Consumer Counselor (OUCC)

The Indiana Office of Utility Consumer Counselor (OUCC) is a separate state agency shown in 

Figure 8 that represents the interests of residential, commercial, and industrial utility customers 

in cases before the IURC. The IURC is designated under Indiana law to make decisions in cases 

involving regulated public utilities, and the OUCC serves as the consumers’ legal and technical 

representative. The Consumer Counselor is appointed by the Governor and serves a four-year 

term. The OUCC was an intervenor in the Indiana case study examined below. 

Indiana Code on Public Utility Commissions

There are at least six separate statutes in the Indiana code that contain unique state regulations 

relating to modifications at utilities and associated ratemaking instruments. This section 

reviews relevant statutes within Indiana state code as they pertain to how the PUC process 

occurs in Indiana. 

1. The Environmental Compliance Plan Approval Act36 within Indiana code allows utilities 

to submit a voluntary compliance plan for review and approval by the IURC. This Act 

also presents assurance of cost recovery, ongoing review of a utility's compliance plan, 

and various ratemaking provisions. 

 

36 Indiana State Code. Title 8. Article 1. Chapter 27. 2010. http://www.in.gov/legislative/ic/code/.
46

2. Indiana’s Clean Coal Technology Certificate Statute37 outlines the necessary certification 

for clean coal technology projects, and the associated assurance of cost recovery. This 

statute states that a public utility may not use clean coal technology at a new or existing 

electric generating facility without obtaining a Certificate of Public Convenience and 

Necessity (CPCN) from the IURC. The CPCN will be issued if the clean coal technology 

project offers significant potential to reduce sulfur or nitrogen based pollutants in a 

more efficient manner than conventional technologies in general use as of January 1, 

1989. A public utility is not required to obtain a CPCN for a clean coal technology 

project that constitutes a research and development project. 

3. The Utility Generation and Clean Coal Technology Statute38 lays out the process for 

IURC approval of pollution control technology for existing coal-fired units, as well as the 

process for IURC authorization of financial incentives for these utilities, including the 

recovery of expenses.

4. The Indiana Coal and Clean Coal Technology; Research, Development, and 

Preconstruction Expenses Statute39 states that the IURC shall allow a utility to recover 

expenses, including preconstruction costs, associated with research and development 

designed to increase the use of Indiana coal associated by employing clean coal 

technology. The commission may only allow a utility to recover preconstruction costs as 

operating expenses on a particular project if the commission awarded a CPCN for that 

project. 

5. The “CWIP Statute”40 provides for construction-work-in-progress ratemaking treatment 

for qualified pollution control property. This statute requires that, for ratemaking 

purposes, the IURC add the value of the pollution control project under construction to 

the value of that utility's property.

6. The Depreciation of Clean Coal Technology code41 allows the IURC to authorize the use 

of accelerated depreciation (from 10 to 20 years) for clean coal technology projects, if 

the IURC finds that the facility where the clean coal technology is employed utilizes and 

will continue to utilize Indiana coal as its primary fuel source or is justified in using nonIndiana coal due to economic or governmental requirements. 

Indiana’s statutes for clean coal are unique to the state and are designed to provide incentives 

for clean coal technologies that utilize in-state coal resources from the Illinois basin. 

 

37 Indiana State Code. Title 8. Article 1. Chapter 8.7. 2010. 

38 Indiana State Code. Title 8. Article 1. Chapter 8.8. 2010. 

39 Indiana State Code. Title 8. Article 1. Chapter 2. Section 6.1. 2010. 

40 Indiana State Code. Title 8. Article 1. Chapter 2. Section 6.8. 2010. 

41 Indiana State Code. Title 8. Article 1. Chapter 2. Section 6.7. 2010. 
47

Relevant Environmental Regulations

CAIR/CAMR

The Indiana case, which began in 2004, examines approvals sought to comply with EPA’s Clean 

Air Interstate Rule (CAIR) and the Clean Air Mercury Rule (CAMR).42 

Summary and Chronology

In 2004, PSI Energy (PSI) initially petitioned to modify one unit, Gibson Unit 3, with flue gas 

desulfurization technology (scrubber). This petition was accompanied by a request that the 

IURC approve the CPCN as well as the use of “qualified pollution control property” in order to 

gain certain financial incentives, including the ability to qualify for CWIP ratemaking treatment. 

Five months later, on September 2, 2004, PSI submitted another petition with a two-phased 

plan to add and upgrade scrubbers at multiple plants to comply with EPA’s upcoming CAIR and 

CAMR. This petition contained the following upgrade proposals and, like the earlier petition, 

sought to gain “qualified pollution control property” status for its upgrades for enhanced cost 

recovery mechanisms, like CWIP. During the years this case was under consideration, Duke 

Energy acquired PSI. To reduce confusion, we will refer to the applicant as PSI, which was its 

name when the case originated. PSI’s original Compliance Plan, which was part of its CPCN 

application, is summarized in Table 10. 

Table 10. PSI's Proposed Phase 1 Petition and Compliance Plan (Submitted September 2, 

2004)

Station Compliance Plan Estimated In-service 

Date

Gibson Station Unit 1 - wet scrubber with high-sulfur fuel

Unit 2 - wet scrubber with high-sulfur fuel

Unit 3 - wet scrubber with high-sulfur fuel

Unit 4 - scrubber upgrade

Unit 5 - scrubber upgrade 

Fall 2007

Spring 2007

Fall 2006

Fall 2005

Spring 2008

Cayuga Station Unit 1 - wet scrubber with high-sulfur fuel

Unit 2 - wet scrubber & SCR with high-sulfur fuel

Fall 2008

Spring 2008

Gallagher Units 1 & 2 – common, Activated Carbon Injection 

(ACI) baghouse with lower-sulfur fuel on Units 1-4

Units 3 & 4 - common ACI-baghouse

Spring 2008

Fall 2005

 

42 On July 6, 2010, EPA proposed the Transport Rule, which proposes a response to the Court remand of 

CAIR and will replace CAIR when it is finalized. While the D.C. Circuit Court vacated CAMR, on March 16, 

2011 EPA proposed Utility MACT standards for coal- and oil-fired electric generating units to regulate 

emissions of mercury and other hazardous air pollutants.
48

This plan staggers the upgrades at nine of their plants over several years. The petition 

requested that its earlier petition, regarding Gibson Unit 3, be consolidated for consideration. 

The petition specifically requested authorization in the form of a CPCN for the suite of upgrades 

proposed. PSI’s financial requests are listed in Table 11.

Table 11. Financial Requests Specified in PSI Petition on September 2, 2004

Approving PSI's proposed Phase 1 emissions reduction equipment as qualified pollution control 

property and clean coal and energy projects

Providing assurance of cost recovery of capital investments made pursuant to a Commissionapproved compliance plan

Providing timely recovery of financing, construction and operating costs associated with PSI's

Phase 1 plan, including an initial overall rate of return of 8 percent (with periodic updates to 

PSI'S cost of debt), via PSI'S existing Standard Contract Riders No. 62 and 71

Providing timely recovery of emission allowance costs incurred in connection with compliance 

with the new SO2, NOX, and mercury emissions reduction requirements, via PSI's existing 

Standard Contract Rider No. 63

Authorizing use of accelerated (18-year) depreciation in connection with PSI's environmental 

compliance projects

Authorizing timely recovery of coal and equipment testing costs, and plan flexibility costs

Authorizing timely recovery of Phase I plan development and presentation costs, and Phase 2 

plan development, engineering and preconstructive costs

Granting authority to defer post-in-service carrying costs, depreciation costs, and operation and 

maintenance costs on an interim basis, until the applicable costs are reflected in PSI's rates

Facility Description

This case study references coal-fired Gibson, Cayuga, and Gallagher power plants, originally 

owned by PSI and currently owned by Duke Energy. Gibson Station is the company’s largest 

power plant, with a capacity of 3,145 megawatts. It is a five-unit facility located in Gibson 

County, Indiana, built between 1976 and 1982. Cayuga Station is a three-unit generating facility 

built between 1970 and 1993. Cayuga Station has a capacity of 1,104 megawatts and is located 

in Vermillion County, Indiana. Gallagher Station is a 560 megawatt, four-unit coal-fired 

generating facility completed in 1961. Unit 2 began operating in 1958; Unit 1 in 1959; Unit 3 in 

1960; and Unit 4 in 1961. Gallagher Station is located in Floyd County, Indiana.

Modification Description and Rationale

Table 10 summarizes the available detail from the IURC documents regarding the PSI 

modification description. PSI proposed to modify nine of its plants, the majority of which were 

using high-sulfur coal. These upgrades were proposed in order to comply with EPA’s CAIR and 

CAMR rules. Five plants were slated to be modified with wet FGD systems; these plants would 

then continue to burn high-sulfur coal. Three of those units were at the Gibson plant, and two 

were located at the two units composing the Cayuga Plant. In addition, two scrubber upgrades 
49

were proposed at Gibson. All four units at Gallagher were slated for upgrading their 

electrostatic precipitators with baghouses with the addition of activated carbon injection for 

mercury control (ACI). An SCR unit was proposed for Unit 2 at the Cayuga Plant. That 

modification was not pursued. 

CPCN Application

The CPCN authorization request for the suite of Phase I modifications was contained in PSI’s 

original Petition filed on September 2, 2004. PSI requested that IURC grant granting PSI a CPCN 

for the construction and use of clean coal technology, to the extent required by Ind. Code § 8-1-

8.7-1. The CPCN was granted as part of the Settlement Agreement finalized by the IURC on May 

24, 2006. 

Studies, Reports, and Testimonies

There were numerous intervenors in this case whose testimony seemed to have a direct 

influence on the terms of the Settlement Agreement. The main intervenors included the Office 

of the Utility Consumer Counselor (OUCC), the PSI-Industrial Group, Nucor Steele, and the 

Citizens Action Coalition (CAC) of Indiana along with Hoosier Environmental Council. The PSIIndustrial Group is composed of large industrial facilities and PSI customers, including Eli Lilly, 

Haynes International, International Paper, and Lehigh Cement. In short, the PSI-Industrial 

Group, being substantial customers of PSI’s electricity, commented on the specifics of the rate 

design, the depreciation net salvage value, and the accelerated 18-year depreciation request. 

There were over twenty-five hours of hearings and multiple testimony and rebuttal testimony in 

this case throughout 2004 and 2005.

Testimony

The issues raised within the intervenors’ testimony included a discussion of PSI’s exclusion of 

CO2, energy efficiency, and renewable energy in its compliance analysis. In addition, CAC 

disagreed with PSI's generating plant retirement analysis, testifying that several of PSI's older, 

smaller, less efficient units are candidates for retirement, including the Edwardsport, Gallagher, 

and Wabash River Units. In response, PSI stated that the retirement of Edwardsport was an 

economic possibility, but at Gallagher and Wabash River it was more economical to continue to 

operate the units than retire them. In addition, CAC disagreed that PSI's proposed projects 

constituted clean coal and energy projects as defined in Indiana Code, and asserted that PSI’s 

projects were not entitled to incentives; however, PSI rebutted and the IURC found that PSI’s 

proposed equipment met the applicable definitions of clean coal technology. 

In addition to discussion related to PSI’s Phase I plan, PSI and intervenors discussed PSI’s request 

for authority to recover financing, accelerated depreciation, operation and maintenance, and 

emission allowance costs on a timely basis via PSI’s existing emission allowance cost tracking 

mechanisms, consistent with the Indiana CWIP statute. PSI supported its request for timely cost 

recovery by emphasizing that it continued to face significant environmental compliance costs, 

and timely recovery of costs is important from a credit quality perspective. 
50

In response to testimony from CAC’s witness and the PSI Industrial group, modifications were 

made to the initial proposal. Some of the major changes included:

The ACI component of the four baghouses at Gallagher was dropped – OUCC stated that 

the technology was new and would likely be more cost effective in the future, so PSI 

should postpone adoption of the ACI component. Further, since EPA was proceeding at 

the time with a cap-and-trade approach to mercury control, PSI could forego the ACI 

construction and purchase emission allowances to comply with the mercury rule. 

PSI agreed to use a 20-year depreciation rate as opposed to its originally requested 18-

year depreciation rate.

PSI agreed to use a 10 percent net negative salvage value as opposed to the originally 

requested 20 percent.

The allocation of rates in Rider 62 and 71 would be based on demand (kW-hours, rather 

than kW).

PSI agreed to credit customers through Rider 71 with $120,000 annually to reflect the 

anticipated reduction in operation and maintenance costs associated with removing the 

ESP at Gallagher.

These changes were reflected in a Settlement Agreement, which was eventually reached. 

However, the CAC filed testimony in opposition to the Settlement Agreement citing the lack of 

aggressive renewable energy options, energy efficiency options, shutdown considerations, and 

insufficient attention to carbon emissions. PSI filed a rebuttal based on cost analysis of all 

options. On May 24, 2006, the IURC found the Settlement Agreement well supported by the 

evidence in testimony and believed the Phase I plan to be the most cost effective way to comply 

with EPA’s upcoming regulations. Further, the project was approved for various clean coal 

financial incentives and CWIP. 

Studies

In preparation for anticipated Federal CAIR and CAMR compliance deadlines, PSI engaged in a 

compliance planning process to comply with the SO2, NOX, and mercury emissions reduction 

requirements long before these rules were finalized in 2005. PSI was required to develop a 

Compliance Plan. To do so, PSI engaged in a multiple-stage process, including: developing key 

price forecasts, using an Integrated Planning Model created by ICF Consulting, ranking various 

compliance alternatives by asset value, using Cinergy Corporation's Engineering Screening 

Model, using the STRATEGIST Model to rank integrated resource and environmental compliance 

plans, and analyzing the results based on overall economics, consideration of various levels of 

risk and uncertainties, financing implications, and rate impacts.

Public Hearings

This case consisted of nine total hearings over the course of two years, the first occurring on 

June 7, 2004, and the last on March 29, 2006. There were four preliminary hearings consisting 

of five hours total, and five evidentiary hearings consisting of 29 hours total. 
51

Final Determinations

The IURC made a determination on the full PSI request on May 24, 2006. In response to 

testimony from the intervenors, there were several issues that required further study, 

negotiations, and compromise. The key points of contention were highlighted previously within 

the Testimonies section. A Settlement Agreement was originally proposed on December 9, 

2005. Further testimony and rebuttal were entered into the docket and a Settlement 

Agreement was finally reached, without the consent of the CAC. A summary of the 

compromises contained in the Settlement Agreement regarding the Rate Design is provided in 

Table 12.

Table 12. Areas of Compromise in the Financing and Rate Design for the Settlement 

Agreement

Area of Compromise Final Determination in the Settlement Agreement

Incremental Incentive Return 

on Equity

OUCC opposed PSI’s requested return on equity; however, this request 

was withdrawn in the Settlement Agreement.

Accelerated Depreciation The PSI Industrial Group testified that the accelerated depreciation 

should be 20 years, rather than 18 years (Code allows for anywhere 

between 10 and 20 years). The Settlement Agreement states 20 years.

Depreciation of Net Salvage 

Value

PSI-Industrial Group testified that PSI should use a net negative salvage 

factor of 5 percent as opposed to 20 percent. The Settlement 

Agreement provides a compromise at a 10 percent net negative salvage 

factor for environmental compliance plan equipment.

Rate Design PSI Industrial Group testified that the Riders 62 and 71 should be more 

precise since they are of such a high magnitude, and therefore the 

revenue adjustment factor should be calculated using kilowatts instead 

of kilowatt-hours (shifting from energy-based to demand-based). PSI 

did not think the suggested new calculation would be a benefit to 

Industrial customers (since they have lower load factors), and is a 

departure from normal billing procedures. However, PSI agreed to 

these changes in the Settlement Agreement.

Off-System Sales and 

Allocation of Compliance Plan 

Fixed Costs:

PSI Industrial Group testified that off-system sales should contribute a 

proportionate share of cost recovery for the compliance plan. PSI 

testified that these suggestions lacked specificity and that the 

compliance plan is based on generating sufficient capacity for the native 

load customer needs. Further off-system sales are not firm in nature 

and are already credited to ratepayers in a 50/50 sharing sales profit 

contract (Rider 70). 

In the Settlement Agreement, there was no allocation of fixed costs to 

off-system sales, nor will any modifications be made to PSI's Standard 

Contract Rider No. 70 in this Cause. Variable costs, including emission 

allowance costs, associated with off-system sales, should be allocated 

appropriately to off-system sales.

Updating Jurisdictional 

Percentages:

PSI Industrial Group opposed PSI’s proposal to change Riders 62 and 71 

retail electric jurisdictional allocation percentages to reflect the 
52

Area of Compromise Final Determination in the Settlement Agreement

termination of service. The Settlement Agreement allows those 

allocations to remain intact.

Operation and Maintenance PSI Industrial Group testified that the pollution control costs should not 

be recovered on a forecasted basis, but after-the-fact. PSI testified that 

the current Rider 71 already results in some regulatory lag and Rider 62, 

the CWIP Rider are filed together semi-annually. To recover costs afterthe-fact would increase regulated utilities’ financing costs and result in 

higher costs to serve customers. 

AFUDC Authority to defer post-in-service allowance for funds used during 

construction (AFUDC), depreciation costs, and operation and 

maintenance costs on an interim basis, until the applicable costs are 

reflected in PSI's retail electric rates. For future CWIP and general 

ratemaking purposes, post-in-service AFUDC shall be added to the cost 

of the plant and recovered over a 20-year period.

Table 12 provides additional insights into how utilities use existing riders for rate recovery, as 

discussed in Section II. In addition to the changes outlined in Table 12, PSI also withdrew the 

proposed ACI components at all four units at the Gallagher plant in response to the consumer 

group’s testimony. The proposed SCR at Cayuga Unit 2 was also removed from the final Phase I 

Compliance plan, though we did not see any direct testimony requesting thjs. To date, Cayuga

Unit 2 does not have an SCR system. The final Phase I Compliance Plan that is contained in the 

Settlement Agreement is reproduced below as Table 13.

Table 13. PSI's Final Phase 1 Compliance Plan in Settlement Agreement (Exhibit G1)

Station Compliance Plan Construction Date Estimated Inservice Date

Gibson Station Unit 1 - wet scrubber with high-sulfur fuel

Unit 2 - wet scrubber with high-sulfur fuel

Unit 3 - wet scrubber with high-sulfur fuel

Unit 4 - scrubber upgrade

Unit 5 - scrubber upgrade 

11/2004

11/2004

5/2004

9/2005

10/2006

12/2007

6/2007

12/2006

12/2005

6/2008

Cayuga 

Station

Unit 1 - wet scrubber with high-sulfur fuel

Unit 2 - wet scrubber & SCR with high-sulfur 

fuel

3/2005

3/2005

12/2008

6/2008

Gallagher Unit 1 - baghouse 

Unit 2 - baghouse

Unit 3 - baghouse

Unit 4 - baghouse

4/2006

4/2006

5/2006

5/2006

11/2007

11/2007

5/2008

12/2008
53

Project Status

All of the upgrades listed in the Settlement Agreement and shown in Table 13 have been put in 

place. At the Cayuga Plant, a wet FGD system came online on Unit 1 in 2006, and for Unit 2, a 

wet FGD system came online on Unit 2 in 2008. We confirmed the presence of scrubbers in EPA 

databases as well as on the Duke Energy website. At Gibson Station, wet FGDs with ESP have 

been put on Units 1, 2, and 3. We cannot confirm the scrubber upgrade on Unit 4, but the 

original scrubber came online in 1994. Gibson Unit 5 is co-owned by Wabash Valley Power 

Association and Indiana Municipal Power Agency, and according to the Duke Energy website, all 

five units have sulfur dioxide scrubbers. Also, based on the Duke Energy website, baghouses 

were installed at four units at the Gallagher plant in 2008.

Reflections

This case study provided a good example of a PUC process where the final result is impacted by 

the process based on the testimony of the intervenors. The PSI-Industrial Group was successful 

in achieving many of its recommendations relating to the financing and rate design features PSI 

proposed. The CAC was less successful, perhaps in part because renewables are rarely cost 

effective in the absence of a state RPS, which Indiana has not yet adopted. The CAC also pushed 

for more consideration of carbon, which was factored into the analysis, but the post-combustion 

controls proposed were still cost effective even in the carbon price scenarios modeled. The 

OUCC succeeded in removing the proposed ACI from each of the four units at the Gallagher 

Station where the ESP systems were proposed to be updated using baghouses. While some 

stakeholders may raise concerns that the ESP systems may not achieve the same reductions as 

ACI, the role of these procedures is primarily economic in the regulated environment. The 

OUCC was advocating on behalf of customers’ rates, betting that ACI costs in the future would 

be lower, or that PSI/Duke could meet compliance needs using mercury allowances. Given that 

the D.C. Circuit vacated CAMR, no allowances will be available for compliance with the 

upcoming Utility MACT rule. However, the initial plan stated that the baghouses would be 

constructed with the ability to retrofit with ACI, or another mercury control such as powder 

activated carbon (PAC), as needed.

While reliability is well within the purview of the IURC, and PSI was supplying electric utility 

service to over 700,000 customers, few details were found in the docket regarding the 

shutdown schedule for the nine PSI plants. While PSI did indicate that staggering the shutdowns 

was critical for reliability, there appeared to be little scrutiny regarding reliability.

It is worth noting that PSI did seek to initiate the PUC process and begin its compliance planning 

in mid-2004, prior to final EPA rules limiting emissions (CAIR and CAMR). PSI, the intervenors, 

and the IURC seemed to be able to proceed with deliberations for the PSI Compliance Plan even 

under some regulatory uncertainty. However, the entire process took the better part of two

years. Construction of the scrubbers each took about two to three years. No information was 

available regarding how much time PSI invested in the application process prior to submitting its 
54

initial petition. For example, it is unknown how much time was required to work on the IPM 

modeling that was contained in the Compliance Plan. 

Lastly, it should be noted that the IURC was recently in the press regarding the appearance of a 

“revolving door” between Duke and the IURC. That issue led the Governor to terminate the 

former IURC Chairman. Further fallout regarding the close relationship between Duke and the 

IURC has recently resulted in the resignation of a top official at Duke. For more details on these 

issues, see the articles reproduced in Appendix F.
55

C. Maryland Case Study

The Maryland case was chosen as an example of the CPCN process for post-combustion 

controls. The case features a wet scrubber, pulverized activated carbon injection, needed 

ductwork, and a baghouse installation. The application of these technologies is particularly 

relevant because they are possible compliance strategies for EPA’s upcoming Utility MACT and 

Transport Rule. Lastly, this case study is a good process contrast between a deregulated state 

and the other five regulated states.

Maryland Public Service Commission 

The Maryland General Assembly established the Public Service Commission (PSC) in 1910 as an 

authority to regulate public utilities and certain passenger transportation companies within the 

state. Currently, the PSC regulates gas, electric, telephone communications, water, and sewage 

disposal companies. The PSC has authority on affairs relating to rate adjustments, modifications 

to the type or scope of service, promulgation of new rules and regulations, and the quality of 

utility service. 

Maryland, having a deregulated power sector, is part of the region served by PJM 

Interconnection, LLC (PJM). PJM is a regional transmission organization (RTO) that coordinates 

the movement of wholesale electricity in 13 states (including Maryland) and the District of 

Columbia. 

The Maryland Governor, with the advice and consent of the Senate, appoints the PSC’s 

Chairman and four Commissioners. The terms of the Chairman and each of the Commissioners 

are staggered and five years in length. All terms begin on July 1. 

The PSC sets utility rates for distribution, and supervises and regulates the activities of public 

service companies. In addition, the PSC gathers and maintains records of public service 

companies, reviews plans for service, inspects equipment, audits financial records, promulgates 

and enforces rules and regulations, defends its decisions on appeal to state courts, and 

participates in relevant cases before federal regulatory commissions and federal courts. 

Pursuant to Maryland state law, the PSC releases an annual report highlighting key issues and 

achievements within the state. 

Maryland Code on Public Utility Commissions

As we mention throughout this report, every PUC is unique. Part of what makes each PUC 

unique is the underlying laws that govern the PUC operating procedures. Toward that end, we 

thought it would be helpful to include summaries of some relevant portions of Maryland’s code 

as it relates to PUC approvals in this Section. Under the Annotated Code of Maryland (the MD 

Code), the PSC has the authority to issue a Certificate of Public Convenience and Necessity 

(CPCN) in connection with a company’s application to construct or modify a generating plant or 

to construct or modify transmission lines designed to carry a voltage in excess of 69,000 volts.
56

Section 7-207 of the Maryland Code lays out the state requirements for obtaining a CPCN when 

beginning construction of a generating station or modification. This section defines 

“construction” under Maryland law, and includes details regarding the application process for 

obtaining approval to construct, the public hearing process for applications, and the final action 

of the PSC in granting the Certificate. Specifically, an application must address the effect of the 

generating station, modification, or overhead transmission line on: 

(i) the stability and reliability of the electric system; 

(ii) economics; 

(iii) aesthetics; 

(iv) historic sites; 

(v) aviation safety as determined by the Maryland Aviation Administration and 

the administrator of the Federal Aviation Administration; 

(vi) when applicable, air and water pollution; and 

(vii) the availability of means for the required timely disposal of wastes 

produced by any generating station. 

A CPCN is not required for a company to construct a generating station below 70 MW, although 

a written application for approval is required. 

Section 7-207 of the Code specifies that installation of pollution control equipment, or a change 

in operating method, in order to comply with the Clean Air Act is considered a modification 

requiring a CPCN. It also requires expedited consideration of CPCN applications for 

modifications required to comply with the federal Clean Air Act or Maryland’s Healthy Air Act 

(discussed below). 

Under Section 7-208 of the MD Code, to obtain a CPCN (required under Section 7-207), a person 

must file an application with the PSC at least two years before construction of the facility will 

commence. The PSC may waive the two-year requirement on a showing of good cause. Upon 

receipt of the application, the PSC provides notice to all interested persons, and holds a public 

hearing. Within 90 days of the hearing, the PSC must either deny or grant the Certificate subject 

to conditions the PSC determines to be appropriate. In each Certificate issued, the PSC includes 

the requirements of all applicable federal and state environmental laws and standards.

Relevant Environmental Regulations

Maryland Healthy Air Act

A brief summary of the Maryland Healthy Air Act (HAA) is provided here because it is the main 

regulatory driver for the case study. The HAA is a four-pollutant law that requires the reduction 

of both ozone and fine particulate-related emissions from Maryland’s seven largest coal-fired 

power plants, owned by Allegheny Energy Group, Constellation Energy Group, and Mirant 

Corporation. The HAA was developed for the purpose of bringing Maryland into attainment 
57

with the National Ambient Air Quality Standards (NAAQS) for ozone and fine particulate matter 

by the federal deadline of 2010. 

The HAA and subsequent regulations will reduce NOX by 70 percent in 2009 and 75 percent in 

2012, SOX by 80 percent in 2010 and 85 percent in 2013, and mercury emissions by 80 percent in 

2010 and 90 percent in 2013. The HAA also requires Maryland to become a member of the 

Regional Greenhouse Gas Initiative (RGGI), which was established to reduce carbon dioxide 

emissions. The Maryland Department of the Environment (MDE) has implemented the HAA 

through state regulations. 

Summary and Chronology

On August 23, 2006, Constellation Power Source Generation, Inc. (CPSG) submitted an 

application for a Certificate of Public Convenience and Necessity (CPCN) from the Maryland 

Public Service Commission (MDPSC). The modification request included the installation of air 

pollution control equipment including a wet flue gas desulfurization (FGD) system, a pulverized 

activated carbon injection duct, and a baghouse. In addition, upgrades were proposed on the 

boilers in units 1 and 2 to achieve a higher generating output to compensate for the parasitic 

load to run the air pollution control equipment. CPSG’s application was designed to satisfy the 

requirements of Maryland Healthy Air Act. CPSG requested an expedited CPCN review process. 

Throughout the remainder of 2006 and the first half of 2007, CPSG submitted several technical 

amendments describing revisions to the proposed modifications. Three public hearings were 

held in addition to one pre-hearing. The final CPCN was granted on June 4, 2007, 10 months 

after the formal process began. 

This case study will review the MDPSC procedure for granting the CPCN for CPSG. The bulk of 

the documents associated with this case were found on the MDPSC website in its specified case 

jacket.

Facility Description

Brandon Shores, the largest coal-fired electric generating plant in Maryland, consists of two 

pulverized coal units, with a combined nominal generating capacity of 1,370 MW. Units 1 and 2 

were constructed in 1984 and 1991, respectively. Brandon Shores is located in Anne Arundel 

Country, Maryland. 

Modification Description and Rationale

The modifications CPSG requested included the construction of wet FGD technology and a 

mercury control duct with a baghouse. The components originally requested in the CPCN are 

listed in Table 14.
58

Table 14. Constellation Modification Components

Initially Proposed Project Components

Installation of a wet FGD system and associated facilities (“FGD system”) for each unit.

Installation of a fabric filter baghouse on each unit.

Installation of sorbent injection equipment for removal of mercury and sulfuric acid mist.

Installation of a single dual-flue 400-foot stack that will serve the FGD systems for both units.

Installation of enhancements on the steam turbine to improve efficiency of the steam cycle and 

any necessary enhancements to the transmission interconnection facilities at Brandon Shores.

Upgrades to the existing steam boilers to enhance performance. The upgrades may increase the 

maximum heat input of the units.

Installation of material handling equipment for limestone, other AQCS reagents and gypsum.

Reconfiguration of the coal yard to accommodate coal alternatives created by the installation of 

the FGD systems.

Installation of water and wastewater treatment facilities.

Installation of handling and storage systems for water and wastewater treatment solids and 

fabric filter waste.

The parasitic power demand to operate the control technologies was estimated at 35 MW (total 

both units). To compensate for the lost output, power block enhancements were also proposed 

including an upgrade of the high-pressure turbine steam path components. The results of the 

upgrade would improve heat rate and increase generator output. The proposed power block 

enhancements were estimated to generate an additional 60 MW, which would recover about 35 

MW of parasitic load and provide a potential net gain of about 25 MW of additional power (total 

of both boilers) for the grid.

CPCN Application

CPSG submitted its CPCN application on August 23, 2006. The application consisted of an official 

application document containing all the application filing requirements needed to request that 

the MDPSC grant a CPCN for their proposed modification. It also contained a specific request 

that the review process for the CPCN be expedited to enable compliance with Maryland’s 

Healthy Air Act and have authority by May 1, 2007. The application also contained the requisite 

Environmental Analysis, which reviews and analyses the potential impacts of the project on 

numerous environmental issues, including noise, air quality, archeological and historic sites, 

construction issues, land impacts, waste stream, and leaching issues. 

Two amendments were filed to the Application, one on November 28, 2006, and one on March 

7, 2007. The first amendment included refinements to the design and updated impact 

assessments. The second amendment, filed after the conclusion of the public hearings, 

contained design revisions and supplemental information regarding the stack flue parameters, 
59

the raw water treatment system, the gypsum and limestone materials handling systems, and 

fugitive gas emissions estimates.

Studies, Reports, and Testimonies

The Maryland Department of Natural Resources Power Plant Research Program (PPRP) 

submitted testimony that discussed their findings on the environmental and socioeconomic 

impacts of the proposed modifications. PPRP is the branch of state government responsible for 

coordinating the interagency review of projects requiring a CPCN across the other relevant state 

agencies, which in Maryland include the Department of the Environment (MDE), the 

Department of Agriculture, the Department of Business and Economic Development, the 

Maryland Energy Administration, the Department of Planning, and the Department of 

Transportation. The PPRP then submits a coordinated environmental and economic review to 

the PSC. The involvement of so many different agencies appears to be fairly unique. It is likely 

that such a degree of coordination adds to the PUC process time.

PPRP staff is in contact with the applicant prior to the official application submission to ensure 

an efficient process. According to PPRP testimony, “The PPRP review process usually begins well 

before an application is submitted to the PSC. Once the determination has been made that the 

project will require a CPCN, PPRP meets with the Applicant to identify any major issues and 

generally outline what analysis or fieldwork will need to be accomplished as part of the formal 

application. It is to the benefit of all parties to come to an early agreement regarding various 

studies that need to be performed. The goal is to ensure that any and all concerns are identified 

early in the process so that they can be addressed, either through studies performed by the 

Applicant or by PPRP. This safeguards both the state and the Applicant against serious issues 

coming to light at the last moment, potentially delaying a needed project.” This note suggests 

that there is a pre-application process, which would add time to the front end of the PUC 

process that is not captured in this discussion.

The PPRP’s synthesized report, entitled Environmental Review of Proposed Air Pollution Control 

Project at Brandon Shores, was submitted as direct testimony to the PSC. The review includes 

an assessment of potential impacts to air quality, noise, terrestrial, ecological, ground water, 

surface water, socioeconomic, aesthetic, and cultural resources. The PPRP-coordinated report 

found that the project would comply with all applicable regulatory standards and would not 

result in adverse environmental or socioeconomic conditions. The results of the Environmental 

Review Document were in favor of granting the CPCN, subject to several conditions.

Conditions for CPCN approval by the interagency process were transmitted to the PSC in a letter 

accompanying the Environmental Review on February 5, 2007. The conditions included 16 

pages of technical specifications, including: general provisions, such as access to the facility 

during construction; applicable air quality regulations (PSD, NSR, monitoring, discharge limits, 

New Source Performance Standards [NSPS], National Emission Standards for Hazardous Air 

Pollutants [NESHAP], Best Available Control Technology for carbon monoxide and acid mist, and 

Lowest Achievable Emission Rate for VOCs); other emission limitations and operating 
60

restrictions; testing, recordkeeping and reporting; by-products and waste; water supply and 

water discharge; noise impacts; ecology; and traffic. 

For the Brandon Shores Project, the CPCN also served as the Prevention of Significant 

Deterioration approval, Nonattainment Air New Source Review approval, and air quality 

construction permit.

The Office of Staff Council at the Public Service Commission submitted direct testimony 

regarding the effect that the proposed project would have on the reliability and stability of the 

electric system in Maryland. These are two of the factors required to be considered under 

Sections 7-207 and 7-208 of Maryland Code Law, as described previously. The PUC Reliability 

analysis recommended that the CPCN be granted as it would result in significant environmental 

benefits and it would also be beneficial for the grid. 

With respect to reliability, the PUC noted in its analysis that it was imperative that the plant 

remain online during summer months. As mentioned earlier, Maryland is part of PJM, which has 

experienced spikes in Locational Marginal Prices due to grid congestion during peak summer 

load. The report states that the loss of generation from Brandon Shores during construction 

could be compensated by supplies from other electrical facilities in Maryland and out-of-state 

depending on demand and prevailing grid conditions. The outage would have minimal impacts 

for the grid during the non-summer months. 

The report further noted that the forced outage rate of the plant could increase as a result of 

failures in the scrubber systems, though this possibility would be minimized by the dual 

redundant system being capable of operating units 1 and 2 independently. The most likely 

failure modes could include baghouse filter bag failures, fan motor or pump failures, or 

equipment blockage. Installation of separate air quality control systems also supports this 

redundancy and makes the plant more reliable. The outages for construction were planned for 

the last quarter of 2009 (Unit 1), and the first quarter of 2010 (Unit 2). 

In addition to the PUC process outlined in this section, CPSG was required to notify PJM of the 

planned construction time, during which the units would be offline.43

Public Hearings

Three public hearings and one pre-hearing were held to review this application. On February 

22, 2006, the Maryland PSC held a hearing in the evening to increase public participation. The 

questions discussed at the hearing included the projected length and estimated completion date 

of the project, the plan for the effluent water used in the project, the details of the construction 

and control technology of the stacks, the environmental regulations in place to protect Stoney 

 

43 PJM is responsible for coordinating and approving requests for outages of generation and transmission 

facilities, as necessary, for the reliable operation of the PJM RTO. PJM maintains records of outages and 

outage requests for these facilities. In order to be classified as a Planned Outage, the PJM Member 

submits the initial outage request to PJM through eDART no later than 30 days prior to the Operating Day 

in which the Planned Outage is to begin. (Source: PJM.)
61

Creek from runoff, and questions regarding traffic and noise related to the project. In addition, 

the public discussed air pollution control technology regulated under Maryland’s HAA, signed in 

2006. The hearings for this case did not produce any issues that delayed the approval process. 

Final Determinations

The parties engaged in negotiations to reach agreement on the final recommended licensing 

conditions. These discussions resulted in an Agreement of Stipulation and Settlement, which 

included a list of final recommended conditions for the CPCN on May 14, 2007. The list of final 

recommended conditions was nearly identical to the list of conditions set forth by the PPRP-led 

interagency letter, described above. There was an additional condition that if CPSG was unable 

to secure agreements for the use of all of the synthetic gypsum, it would be properly disposed 

of in accordance with existing rules. Perhaps because the environmental permitting process 

was part and parcel of the PUC process, many detailed environmental issues were explored. 

That inclusion is fairly unique among PUC processes; more often there is a separate 

environmental review and permitting process through the environmental agency. The period of 

appeal for the agreement was shortened to seven days in order to expedite the procedure and 

begin construction. CPSG was also required to certify that it was in compliance with all 

applicable emissions limitations and standards. Additional discussions with MDE were necessary 

to submit the certification. It was granted by MDE on May 23, 2007.

On May 25, 2007, the MDPSC submitted a proposed hearing order to grant the CPCN for CPSG’s 

modifications to the Brandon Shores Plant. This approval took effect on June 4, 2007.

Project Status

The upgrades to the Brandon Shores power plant were completed, and the plants were back 

online, in March 2010. Together, the FGD and baghouse at Brandon Shores are achieving a 95 

percent reduction in SO2 and a 90 percent reduction in mercury emissions. Construction for 

these upgrades began in 2007, and took three years to complete. 

Reflections

The application and award of the CPCN appeared fairly straightforward for a project intended

solely to comply with Maryland’s Healthy Air Act; however, the number of conditions placed on 

the approval extended the process. While CPSG requested that the CPCN application be 

expedited, the application was granted on June 4, 2007, 10 months after the formal application 

was submitted on August 23, 2006. Again, it is significant that the environmental permitting 

process was included within the PUC process, as that can also be time consuming. This 10-

month timeframe does not include the time CPSG spent developing their legal application with 

its 158-page Environmental Analysis. According to Constellation, the company worked on the 

documents for roughly nine months prior to commencing with the official CPCN application. 

Factoring in the front-end work, the total time required for Constellation to receive approval to 

make modifications for meeting the requirements of the Healthy Air Act was 19 months, over a 

year and a half.
62

D. Florida Case Study 

The following case study involving Florida Power & Light was chosen as an example of a process 

whereby the PUC denied a utility’s request for accelerated recovery for new, clean power 

plants. In this case study, we examine the nature of the request and its denial. While the 

original financing piece was rejected, the projects are in fact moving forward, having gone 

through a more traditional rate case PUC approach. 

Florida Public Service Commission

The Florida Public Service Commission (PSC) was created by the Florida Legislature in 1887 to 

provide regulatory oversight to the state’s railroad operations. In 1974, the Legislature gave the 

PSC rate structure jurisdiction over municipal and rural cooperative electric utilities. 

The PSC currently oversees electric, natural gas, telephone, water, and wastewater services 

within the state. The PSC exercises regulatory authority over utilities in terms of rate base and 

economic regulation, competitive market oversight and monitoring of safety, reliability, and 

service issues. During 2009, the PSC regulated five investor-owned electric companies and 

seven investor-owned natural gas utilities. While the PSC does not fully regulate publicly owned 

municipal or cooperative electric utilities, it does have jurisdiction, with regard to rate structure, 

territorial boundaries, bulk power supply operations and planning, over 35 municipally owned 

electric systems and 18 rural electric cooperatives. The PSC has jurisdiction, with regard to 

territorial boundaries and safety, over 27 municipally owned natural gas utilities and also 

exercises safety authority over all electric and natural gas systems operating in the state.

The PSC consists of five members appointed by the Governor and confirmed by the Senate. 

Commissioners serve four-year terms. The Chairman is elected by a majority vote of the 

Commissioners to serve as chair for two years. 

Florida operates under the Florida Reliability Coordinating Council (FRCC), an Independent 

System Operator with delegated authority from the North American Electric Reliability 

Corporation (NERC). The purpose of the FRCC is to ensure and enhance the reliability and 

adequacy of bulk electricity supply in Florida. The FRCC region is within the Eastern Connection 

and includes almost all of Florida, except for areas west of the Apalachicola River, which are 

within the SERC Region. 

Florida State Code 

Before addressing the 2010/2011 rate case, it should be noted that in Florida the costs 

associated with pollution control projects on existing power plants are recovered through the 

Environmental Cost Recovery Clause (ECRC). The ECRC has been in place since 1993, when the 

Florida Legislature passed a law allowing utilities to recover the costs “of the utility’s prudently 

incurred environmental compliance costs, including the costs incurred in compliance with the 

Clean Air Act, and any amendments thereto or any change in the application or enforcement 
63

thereof, through an environmental compliance cost-recovery factor that is separate and apart 

from the utility’s base rates.”44

The ECRC is set on an annual basis, based on a projection of the utility’s environmental 

compliance costs and adjusting for any variation between projected and actual costs in the 

previous year. In FP&L’s most recent ECRC filing, the Florida Public Service Commission (PSC) 

approved environmental recovery costs of over $172 million for calendar year 2011. This 

includes over $43 million for a new project to install electrostatic precipitators on four oil-fired 

units. FP&L is undertaking the project to comply with expected new requirements for the Utility 

MACT standards.

Summary

This case study focuses on a rate case filed by Florida Power & Light (FP&L) in 2009 to adjust 

rates for 2010 and 2011. Unlike the other case studies in this report, which largely focus on 

approvals for and cost recovery of investment in pollution controls on existing power plants, this 

case provides an example of a utility developing a long-range plan for a progressively cleaner 

generation fleet and seeking recovery for those investments through increased base rates and 

an automatic adjustment mechanism. The case study shows that PUCs may be reluctant to 

provide accelerated cost recovery for new power plant projects, preferring to review such 

projects in the context of a general rate case. However, to the extent that such projects deliver 

tangible economic benefits to ratepayers – through reducing fuel costs, for example – the case 

study indicates that interested parties and the PUC were willing to provide accelerated recovery 

up to the level of the cost savings. 

Background: 2005 Rate Case and the Generation Base Rate Adjustment

After nearly 25 years of keeping customer rates flat or in decline, FP&L filed a request in March 

2009 to increase base rates in Florida for the years 2010 and 2011. The request came on the 

heels of FP&L’s 2005 rate case, in which FP&L agreed to hold base rates flat. In return, the PSC 

allowed recovery of expenses for large capital projects that were planned as part of FP&L’s 

efforts to meet demand projections with a newer, cleaner fleet of power plants through a 

mechanism called the Generation Base Rate Adjustment (GBRA). 

The GBRA allows FP&L to increase base rates to recover capital costs associated with new 

generation facilities as those facilities enter into commercial service. In other words, it allows 

FP&L to add completed generation projects to the rate base without filing a new rate case. In 

order to qualify for the GBRA, the project must go through the siting certification process, the 

“Need Determination,” under the Florida Power Plant Siting Act. Once the project receives the 

Need Determination and is then constructed and placed in service, it qualifies for the GBRA. The 

GBRA adjusts the revenue requirement to accommodate the capital costs that were projected in 

the Need Determination.45 In addition to rolling capital costs into the rate base, a separate 

 

44 The Florida Statutes. Title XXVII. Chapter 366. 8255 Environmental Cost Recovery. 2010.

45 Any difference between projected and actual costs would be credited as part of a separate charge.
64

mechanism, the fuel cost recovery clause, also adjusts costs downward for the fuel savings 

expected from the new facilities. In this way, ratepayers receive the financial benefits of the 

new facilities contemporaneously with paying for the costs. 

Facility Description and Modification

From 2006 through 2009, FP&L utilized the GBRA to flow through $387 million to the rate base 

for three projects: Turkey Point Unit 5 (1100 MW combined-cycle natural gas) and West County 

Energy Center Units 1 and 2 (2500 MW combined-cycle natural gas). FP&L projected that its 

power plant upgrades between 2003 and 2009 resulted in over $3 billion in fuel savings.

FP&L’s 2009 Rate Case Requests marked a departure in holding rates constant. In its 2009 filing, 

FP&L asked for an increase in base rates of $1.04 billion in 2010 and $247 million in 2011. FP&L 

explained that the impetus for the increase was largely attributable to two factors: (1) $5.6 

billion in capital expenditures between 2006 and 2010; and (2) a dramatic decline in sales 

growth. Due to a decrease in fuel costs, FP&L projected that customer bills in 2010 would 

actually decrease 4.5 percent from 2009 levels. However, in 2011, FP&L projected that 

customer bills would increase 7 percent from 2009 levels. 

In addition to the rate increase, FP&L also proposed indefinitely extending the GBRA, which was 

set to expire at the end of 2009. Extending the GBRA could have potentially allowed FP&L to 

recover $3.2 billion from 2010-2015 for three planned projects: West County Unit 3 (1250 MW 

combined-cycle natural gas), Cape Canaveral Energy Center (1250 MW combined-cycle natural 

gas), and Riviera Beach Energy Center (1250 MW combined-cycle natural gas). FP&L expected 

that the fuel savings gained from utilizing these new power plants would balance the capital 

costs and minimize bill impacts, showing that overall fuel savings on power plant upgrades 

would yield a savings of $1 billion annually starting in 2014.

Studies, Reports, and Testimony

FP&L’s request to extend the GBRA was opposed by the intervenors and the PSC staff. As 

summarized by the Office of Public Counsel, the GBRA would “*allow+ FPL to create a base-rate 

adder for all generating plant that is placed in service between rate proceedings without the 

regulatory scrutiny that would normally be required for base rate adjustments.” The PSC Staff 

recommended that the PSC should let the GBRA expire at the end of 2009 and examine cost 

recovery for any new power plants in a rate case that “provides for a more rigorous and 

thorough review of the cost and earnings associated with new generating units.”

FP&L responded that the GBRA was not a radical departure from normal ratemaking as 

evidenced by its successful use over the past five years by FP&L as well as the use of a similar 

mechanism by Alabama Power Company that has been in place since 1982. FP&L also noted 

that if the GBRA was not extended, then ratepayers would still receive the benefit of reduced 

fuel costs from new, more efficient power plants but would not be required to pay for that 
65

benefit simultaneously. This would send an incorrect price signal and deny FP&L reasonable 

recovery on a prudent investment.

Final Determinations

The PSC denied FP&L’s request to continue the GBRA, largely adopting the recommendations 

and rationale of the PSC Staff. The PSC concluded:

The record shows that FPL already collects about 61 percent of its total revenues 

through various "pass-through" mechanisms and cost recovery clauses. We are not 

convinced that adding another such mechanism, by permanently implementing a GBRA 

for FPL, would provide advantages over traditional rate case procedures found in 

Section 366.06, F.S. We find no justification in the record for approving a cost-recovery 

mechanism for FPL's new generation that is different from what applies to all other 

investor-owned electric utilities. Approving a GBRA for FPL on a permanent basis would 

constitute a significant change in our general ratemaking policies.

FP&L and a number of intervenors filed motions for reconsideration, but the GBRA was not one 

of the issues challenged. However, over the course of settlement negotiations, cost recovery for

West County Unit 3 entered into the discussions. During the proceedings, this Unit had already 

received a Need Determination and was projected to be completed in June 2011. Instead of 

allowing West County Unit 3 to utilize the GBRA, the parties agreed on a compromise where the 

capital costs of power plant could be recovered through an existing capacity charge once the 

unit was placed in service, but the total amount of recovery would be capped at the level of 

projected fuel savings from the plant. 

Project Status 

The three projects that would have utilized the GBRA have received positive Need 

Determinations and continue to move forward. West County Energy Center Unit 3 has begun 

start-up work and has finished fuel gas piping work. Current projections show that it is still 

scheduled to come online in June 2011.46 The Cape Canaveral coal units were demolished in 

August 2010. The new plant is scheduled to come online in 2013. The Riviera Beach unit is 

scheduled for removal within the next six months and the new units are projected to come 

online in 2014.

Reflections

The use of the already-approved GBRA for new generation absent a typical PSC review process 

was controversial. FP&L was perhaps one step ahead of the PSC in seeking opportunities to add 

capacity, modernize the utility and shrink its carbon emissions – when mandatory carbon limits 

seemed imminent. The public, the intervenors, and the PSC reportedly felt that such a large 

 

46 Dr. Robert Peltier. Top Plant: West County Energy Center, Palm Beach County, Florida. Power Magazine.

Sept. 1, 2010. http://www.powermag.com/gas/Top-Plant-West-County-Energy-Center-Palm-BeachCounty-Florida_2954_p3.html.
66

new investment needed to be vetted through the process of a full rate case. Typically, we 

would expect an initiative of this magnitude to be reviewed through a traditional rate case 

process, which was ultimately how it was resolved. 
67

E. Georgia Case Study 

The Georgia case study is noteworthy as the first attempt by a Georgia utility to use one of the 

more expedient cost recovery mechanisms. Not all of the Commissioners were comfortable 

with the innovation. However, the need for the utility to access capital without damaging its 

credit rating seemed to motivate the remainder of the Commission. The ability to find capital 

and reduce the impact of compliance costs on ratepayers could be a familiar theme as utilities 

advance new strategies to comply with EPA regulations, especially while the U.S. economy 

continues to recover.

Georgia Public Service Commission

The Georgia Public Service Commission was established in 1879 by the Georgia General 

Assembly for the purpose of regulating railroad passenger and freight rates, services and 

operations. As Georgia's population grew and industry expanded, the Commission undertook 

additional responsibilities through regulatory expansion and deregulation. Currently a variety of 

services and utilities are included under the Commission's jurisdiction. 

The PSC consists of five elected Commissioners, supported by approximately 100 staff. The five 

Commissioners of the PSC are elected statewide and serve staggered six-year terms. On an 

annual basis, the chairman of the Commission is selected based on seniority.

Georgia operates under the SERC Reliability Corporation (SERC) region, which covers the bulk 

power system in 16 central and southeastern states. SERC is one of eight regional entities with 

delegated authority from NERC. SERC aims to propose and enforce reliability standards within 

the Southeast. SERC is divided geographically into five diverse sub-regions.

Georgia Rate Case Procedure

Within the Georgia PSC, the rate case filing process begins when the utility requests a rate 

increase, issues a public notice of intent, and files a rate case petition and a request for the 

proposed rates to take effect in 30 days. The Commission then reviews this petition and sets a 

hearing date. 

Following the final session of public hearings, all parties review the transcript and file 

recommendations. At a subsequent administrative session, the Commissioners decide what, if 

any, rate increases to grant and when the new rates will go into effect. The Commissioners 

must make this decision within six months of the original filing date or the utility is legally 

entitled to 100 percent of its request, under bond and subject to refund. After a decision on the 

rate case, the Commission issues a final order. The new rates go into effect 165 to 180 days 

after the initial filing of the rate change request.
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Georgia State Code on Public Service Commissions

Title 46 of Georgia State Code covers all state laws pertaining to Public Utilities. Section 46-2-23 

states that the commission shall have exclusive power to determine what are just and 

reasonable rates and charges to be made by any person, firm, or corporation subject to its 

jurisdiction.47

According to Section 46-3A-10, when setting rates for a certificated capacity resource, the 

Commission shall consider changed revenues and changed risks, if any. The Commission's 

decision in any certification, recertification, modification, or construction review proceeding 

shall be based on evidence of record. The Commission's findings, although subject to judicial 

review, shall not be subject to relitigation in any other proceeding. However, the issuance of a 

certificate shall not preempt any local, state, or federal governmental body from the regulation 

of environmental or safety matters as a result of construction of electric generating plants.

Section 46-3A-7 addresses construction costs as part of a rate base, review of construction work 

in progress (CWIP), verification of expenditures, and recovery of costs of canceled construction. 

Upon the completion of plant construction, a utility can add costs to its rate base that do not 

exceed 100 percent of those approved by the commission. In addition, the commission may 

conduct, or the utility may request that the commission conduct, an ongoing review of plant 

construction as it proceeds. Every one to three years, the utility shall file a progress report and 

any proposed revisions in the cost estimates, construction schedule, or project configuration. 

Within 180 days of such filing, the commission shall approve these expenditures and any 

proposed revisions.

In addition, Section 46-3A-2 of the Georgia State Code includes all laws applicable to filing an 

Integrated Resource Plan (IRP) and obtaining a certificate of public convenience and necessity 

(CPCN) for power plant construction. Every three years, since 1992, utilities are required to file 

an IRP with the Commission. Within 120 days after the filing of each IRP, the Commission shall 

approve and adopt the IRP. A CPCN is required for construction of new generation and 

transmission, as well as for modifications to existing generating plants, but only if the 

modification increases or decreases generation capacity at the facility. A CPCN is not required 

for pollution control modifications. 

Relevant Environmental Regulations 

The environmental controls referenced in this case are required to comply with the Georgia 

Multipollutant Rule, the Clean Air Interstate Rule (CAIR), the Clean Air Mercury Rule (CAMR), the 

Clean Air Visibility Rule, and NAAQS for PM2.5 and ozone.

The Georgia “Multipollutant Control for Electric Utility Steam Generating Units” rule was made 

final on June 27, 2007. The Georgia Environmental Protection Division (EPD) developed this rule 

 

47 Georgia State Code. Title 46. Chapter 2. Article 2. Section 23. 2011. 

http://www.lexisnexis.com/hottopics/gacode/Default.asp.
69

to address several air quality issues within the state. The EPD performed air quality modeling 

related to Atlanta being designated nonattainment with the ozone and fine particulate matter 

Air Quality Standards. This modeling showed that emissions from Plants Scherer and 

McDonough contributed to nonattainment. Therefore, while the Georgia EPD adopted the 

federal CAIR and CAMR regulations, they also developed the Georgia Multipollutant Rule to 

require specific emission control systems that will achieve reductions in mercury, SO2, and NOX

emissions in Georgia. The Multipollutant Rule requires the installation and operation of specific 

air pollution control equipment on specified power plant units. 

Summary and Chronology

This case study examines the rate case filed in 2007 by Georgia Power Company. This rate case 

established the Environmental Compliance Cost Recovery (ECCR) Tariff, which was designed to 

recover environmental compliance costs incurred by Georgia Power as a result of complying 

with federal or state environmental laws, regulations, or permit requirements. 

In Georgia Power’s previous rate case, in 2004, the PSC approved a three-year Accounting 

Order, to remain in effect through December 31, 2007. The PSC has issued Accounting Orders in 

Georgia Power’s rate cases since 1996. An Accounting Order can prescribe financial 

mechanisms that aren’t generally used in a traditional rate case, such as capping rates and 

determining how excess earnings should be accounted for. 

This Accounting Order was approved in December 2007 with rates set to provide an 11.25

percent return on equity. As approved, the Order stated that beginning January 1, 2008, the 

Company shall increase its base rates by $100 million. The three-year term for this Order ended 

on December 31, 2010. 

Within the 2007 rate case, Georgia Power filed for environmental cost recovery through the 

ECCR tariff at a number of its coal-fired power plants, including one plant with two units slated 

for retirement and natural gas retrofit in 2011 and 2012. The final Settlement Agreement 

approved the full amount of costs for the installation of environmental controls on Georgia 

Power’s coal-fired plants, as well as cooling towers on the two units scheduled for retirement.

Facility Description

In the 2007 rate case filing, Georgia Power requested recovery of costs for scrubber, SCR, and 

baghouse installations at their Bowen, Hammond, Scherer, Wansley, and Yates plants. A 

breakdown of the environmental controls being installed at these plants is shown in Table 15, 

taken from an exhibit to the rebuttal testimony of Georgia Power’s Ann P. Daiss.
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Table 15. Projected Year-End Balances for Environmental Controls, 2007-2010

Plant Name Environmental Controls 2007 2008 2009 2010

Bowen

Scrubbers - $609,091 $871,604 $1,064,446

SCR Catalyst $2,160 $2,160 $2,160 $2,160

Hammond

Scrubbers - $296,460 $296,460 $296,460

Scherer

SCRs - $6,000 $8,252 $99,331

Baghouses - $114,031 $146,074 $146,667

Wansley

Scrubbers - $160,960 $289,101 $289, 101

Monitors $8,100 $18,891 $18,891 $18,891

Other Controls

$69,588 $184,832 $207,412 $222,762

Grand Total $79,848 $1,392,424 $1,839,953 $2,139,817

Georgia Power also requested cost recovery of cooling towers for Plant McDonough Units 1 and 

2. The Plant McDonough Units are two steam units with a combined capacity of 517 MW with 

coal-fired boilers that were installed in 1963 and 1964. Plant McDonough is located in Cobb 

County, near downtown Atlanta. 

Georgia Power’s original 2006/2007 Compliance Strategy for McDonough Units 1 and 2 included 

the construction of Selective Catalytic Reduction (SCR) equipment and a shared scrubber on 

both McDonough coal units to comply with the Georgia Multipollutant Rule, CAIR, CAMR, and 

the Clean Air Visibility Rule. However, due to the high cost of maintaining these units, the 

extensive environmental upgrades necessary, and environmental concerns involving emissions 

in Metropolitan Atlanta, in late 2006, Georgia Power proposed to retire Plant McDonough Units 

1 and 2 and replace them with three 840 MW natural gas combined-cycle gas units by 2012. 

During the 2007 rate case proceedings, Georgia Power’s proposal for retirement was in the 
71

process of being reviewed by the PSC in a parallel docket, and the proposal was granted on 

September 4, 2007.

Georgia Power’s Vogtle Nuclear Plant Units 1 and 2 are also discussed in this case in terms of an 

extension of the operating license, and the recovery of decommissioning costs. Vogtle consists 

of two Westinghouse pressurized water reactor units located near Augusta, Georgia on the 

southwest side of the Savannah River. The site is in the eastern sector of Burke County, Georgia, 

and across the river from Barnwell County, South Carolina.

Description of Riders

Under the Settlement Agreement, effective January 1, 2008, Georgia Power was authorized to 

implement the ECCR Tariff. The ECCR tariff was levelized to collect $222.3 million annually 

between January 1, 2008 and December 31, 2010.

Cost Recovery Description 

Environmental Cost Recovery

An issue of contention in this case was the disagreement between Georgia Power and PUC 

Advocacy Staff over the recovery of environmental costs outside the test year period. In a 

traditional rate case, a test year is used to determine the cost for the utility of doing business, 

and thus what its revenue requirements are. Georgia Power’s filing based the company’s 

revenue requirements on the twelve months ending July 31, 2008, with the exception of the 

ECCR, which included projected test year data to support multi-year revenue requirements 

related to environmental expenditures in 2009 and 2010. 

The disagreement focused on whether it was appropriate to recover post-test year costs in the 

context of a rate case. However, because the case was resolved through a three-year 

Accounting Order as opposed to a traditional rate case proceeding, the PSC concluded that the 

environmental compliance costs incurred during the three-year term of the Accounting Order 

could be recovered through the ECCR tariff. 

Commissioner Angela Elizabeth Speir filed a dissenting opinion to the final order in which she 

expressed concerns with the approach taken to the ECCR. Commissioner Speir asserted that the 

Commission erred in approving the recovery of projected environmental costs beyond the test 

year. Instead, she contended, these expenditures should be included in base rates through a 

new rate case (rather than automatically via a separate tariff) after the equipment was in service 

and costs could be determined to have been prudently incurred. In Speir’s opinion, because the 

projected environmental costs “have not been (and will never be) certified by the Commission,” 

they should not be eligible for recovery.

The PSC determined that the final Accounting Order was just and reasonable, and would provide 

benefits to consumers that would not be realized in a traditional rate case order. Under the 

Accounting Order, Georgia Power’s return on equity was capped at 12.5 percent, and any 
72

earnings above this would flow to the benefit of ratepayers. In contrast, under a traditional rate 

case order, the Company could earn well in excess of a 12.5 percent return on equity without 

the ratepayers receiving any rate reductions. This type of accounting order also reduces 

regulatory lag for both the utility and ratepayers, because increased earnings are returned to 

customers right away, rather than in a subsequent rate case.

In addition, the Accounting Order would provide ratepayers with rate stability, as the Stipulation 

prohibits Georgia Power from filing for a rate increase until July 1, 2010. Under a traditional 

rate case order, the Company would be able to file another rate case whenever it deemed 

appropriate. The Commission highlights this aspect of an accounting order to justify its 

approach to the ECCR tariff. The environmental compliance costs that did not fall within the 

test year period for this case could have fallen within the test year period of a subsequent 

traditional rate case filing , and so it is fair to allow recovery of expenditures projected to occur 

within the three-year accounting order period. 

The Order also instituted a true-up mechanism in the event that costs differed from the 

projections. If actual costs were higher than projected, then they could be recovered in a 

subsequent rate case if Georgia Power was earning below the mid-point of the earnings sharing 

band (11.25 percent). Conversely, if costs were lower than projected, a downward adjustment 

rate would be included in the next rate case if Georgia Power was earning at or above 11.25

percent. This allowed the PSC and Georgia Power to use the ECCR to balance earnings within a 

narrow band before resorting to a rate case to address the difference between actual and 

projected costs.

Nuclear Decommissioning Cost Recovery

In a supplemental order regarding Nuclear Decommissioning Costs, Georgia Power requested 

that the PSC issue an Accounting Order to confirm a new level of annual nuclear 

decommissioning expense to be included in the Company’s cost of service. Therefore, within 

the Stipulation, effective January 1, 2008, Georgia Power will begin including in its cost of 

service an amount of annual decommissioning expense reflecting the cost necessary to 

decommission the radioactive portion of the nuclear units based upon the 2006 Nuclear 

Regulatory Commission’s minimum funding requirements. The Stipulation allowed Georgia 

Power to recover the NRC minimum plus an adder for spent nuclear fuel storage. 

Studies, Reports, and Testimony 

Recovery of Environmental Costs

As previously mentioned, another issue of contention within the testimonies focused on the 

recovery of environmental costs outside the test year period, ending July 31, 2008, and whether 

it was appropriate to recover post-test year costs in the context of a traditional rate case 

proceeding. PSC Staff witness Robert J. Henkes recommended that the PSC disallow all post-test 

year environmental investments and expenses included by the Company for the post-test year 

period August 1, 2008 through December 31, 2008. 
73

Base Rate Increases

Jeffrey Pollock testified on behalf of the Georgia Industrial Group (GIG) and the Georgia 

Traditional Manufacturers Association (GTMA) regarding Georgia Power’s base rate increases. 

Members of these two groups are customers of Georgia Power Company and consume large 

quantities of electricity, primarily for manufacturing. Pollock stated that the proposed increase 

in rates will further disadvantage Georgia’s manufacturers in relation to competition in the 

Southeast and overseas. Georgia Power’s three-year rate plan calls for base rate increases of 

4.5 percent effective January 1, 2009 and 1.0 percent increases effective January 1, 2010. 

Pollock testified that GIG and GTMA are recommending that the proposed January 1, 2008 base 

rate increase be cut back by at least $109 million and that further changes should be made to 

the proposed three-year rate plan that would offset the proposed 2009 and 2010 increases.

Studies 

A study on plant depreciation was prepared by Charles W. King, president of the economic 

consulting firm Snavely King Majoros O'Connor & Lee, Inc. King testified on behalf of the PSC as 

an Advocacy Staff witness. Based on his study, King recommended that the expected life spans 

of Georgia Power’s steam production plants be set at 60 years, rather than 55 years; that the 

expected life spans of the Vogtle nuclear units 1 and 2 be extended from 50 years to 60 years;

and that the combined cycle turbine/steam plant life spans be set at 45 years rather than 35 

years. These extensions of plant life expectancy adjust the depreciation rates for Georgia 

Power’s facilities, but are not necessarily predictive of the retirement date for these plants. In 

his testimony, King also recommended that nuclear plant dismantlement costs should not be 

collected in depreciation rates, as there is a separate decommissioning fund for each of these 

plants that includes all dismantlement costs.

Public Hearings

In Georgia Power’s 2007 rate case filing, there were a total of six hearings, held from October 1-

3, 2007, and from November 5-7, 2007. There were also two post-hearing briefs. Intervenors in 

these hearings included primarily Public Interest Advocacy Staff of the Commission, as well as 

representatives from Georgia Power. Other intervenors in this proceeding included the 

Consumers’ Utility Counsel Division (CUCD) the Association for Fairness in Rate Making, the 

Commercial Group, the Cable Television Association of Georgia, Georgia Municipal Association, 

Macy’s Inc. f/k/a Federated Department Stores, the Georgia Electric Membership Corporation, 

the Georgia Industrial Group, the Georgia Traditional Manufacturers Association, Inc., the 

Kroger Company, Metropolitan Atlanta Rapid Transportation Authority, Resource Service 

Ministries, Resource Supply Management, Georgia Environmental Facilities Authority of the 

Division of Energy Resources, and the U.S. Department of Defense and All Federal Executive 

Agencies.
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Final Determinations

The final Settlement Agreement approved that, effective January 1, 2008, Georgia Power would 

increase its base rates by $99.7 million and implement the ECCR Tariff. This is the full amount 

originally requested by Georgia Power’s in its rate case filing. Based on testimony described

above, the PSC removed the environmental costs embedded in the test year revenue 

requirements and included them in the ECCR tariff. The ECCR tariff was levelized to collect 

$222.3 million annually between January 1, 2008 and December 31, 2010

The final Settlement Agreement approved the full amount of costs for the installation of 

environmental controls on the company’s coal-fired plants, as well as the McDonough Units 1 

and 2 cooling towers.

Based on Charles King’s testimony regarding his study on plant depreciation, the Settlement 

Agreement extended the Environmental Plant Life on plants receiving environmental controls 

from 55 to 60 years, and specifically extended the life of Georgia Power’s Plant Vogtle from 50 

to 60 years, as it is likely that the Nuclear Regulatory Commission will grant the application to 

renew the license for Plant Vogtle. In addition, the Stipulation includes a supplemental 

Commission order directing the Georgia Power to collect and remit funds for nuclear 

decommissioning with explicit instructions as to the qualified and non-qualified portions of 

those funds.

Project Status

In May 2010, the Georgia PSC voted to allow Georgia Power to defer the retirements of Plant 

McDonough units 1 and 2 for six months and one year, respectively.48 According to Georgia 

Power, the delay will allow Georgia Power to reduce its upcoming rate case filing by 

approximately $250 million. The company proposed the delays because the current forecasted 

loads for 2011 and 2012 were lower than the loads forecasted in 2007, when the project was 

originally approved by the PSC. The load-forecast reduction is a result of the recent economic 

recession. In addition, the company proposed deferring the retirement of the existing coal units 

because there is still a need for generation at the site to maintain transmission reliability. 

The two cooling towers at Plant McDonough, designed to reduce the thermal impact of water 

discharges into the Chattahoochee River, went online in 2008. When the coal-fired units are 

retired, the cooling towers will remain at the site for use with the four combined cycle units that 

are slated to replace them.49

 

48 Georgia Power. PSC Approves McDonough Unit Delays. News Release. May 2010. 

http://www.georgiapower.com/pluggedin/mcdonough_2010_05.asp.

49 PR Newswire. Plant McDonough Cooling Tower to Begin Commercial Operation, Will Improve 

Chattahoochee River Quality. February 21, 2008. http://www.prnewswire.com/news-releases/plantmcdonough-cooling-tower-to-begin-commercial-operation-will-improve-chattahoochee-river-quality57080697.html.
75

According to Georgia Power, as of 2009, all four baghouses at the Scherer plant were expected 

to be in service by January 2010. The first scrubber at Scherer was expected to go into service in 

2011, with the final one going online in 2014. At Plant Bowen, three scrubbers were already in 

service, and the fourth one, on Unit 1, was scheduled for early 2010. A second scrubber at Plant 

Wansley was commissioned in spring 2009. Construction of the SCRs and scrubbers at Plant 

Branch and Plant Yates was scheduled to begin in 2011, with the equipment coming online by 

2014.50

Reflections 

Georgia Power’s 2007 rate case filing represents the first time that projected environmental 

costs at the company’s generating facilities were addressed in an expeditious way using an 

environmental cost recovery mechanism, the ECCR tariff. Despite contention surrounding the 

inclusion of environmental costs outside the test year, the ECCR tariff was approved by the 

Georgia PSC and was continued and enhanced in Georgia Power’s 2010 rate case. 

The rate case examined in this case study revealed less specific information than other case 

studies. Certain background documents that would have provided beneficial information were 

not available in the online docketing system. Specifically, a parallel docket concerning the 

retirement of McDonough Units 1 and 2 was explored, but many of these documents were not 

available to the public online. However, the 2010 rate case offers the public more access to the 

documents in the docket than the 2007 rate case. 

This case was unlike others we examined in that there was little public opposition expressed in 

the testimony relating to the retirement of the coal-fired McDonough Plant Units 1 and 2, or the 

planned natural gas retrofit of these units. Based on the testimony included in the rate case 

docket, replacing coal-fueled McDonough Units 1 and 2 with natural gas-fueled combined cycle 

generating units was accepted as a more cost-effective option than retrofitting the plant with 

environmental controls. However, as previously mentioned, the examination of other 

unavailable documents may have granted more information on this topic. It is also possible that 

any opposition to the retirement of these coal-fired units was offset by the extensive pollution 

control installations occurring simultaneously at Bowen, Branch, Hammond, Scherer, Wansley, 

and Yates plants. According to Georgia Power’s testimony, approximately 90 percent of Georgia 

Power’s coal generation capacity will have controls installed by the end of the program, and the 

construction workforce projected for these projects was expected to total over 2,000 workers.

 

50 Georgia Power. Georgia Power Investing Nearly $2.8 Billion in Georgia during 2009. News Release. 

August 2009. http://www.georgiapower.com/pluggedin/construction_2009_08.asp.
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F. West Virginia Case Study

This case study compares and contrasts two different approaches that have been employed in 

West Virginia to pay for and recover the costs of pollution control retrofits. One case involves a 

classic rate case, while the other examines a relatively new financing option: securitization. 

Securitization is the use of ratepayer-backed bonds to finance a pollution control project,

instead of traditional utility financing. This case study is therefore divided into two Parts. Part I 

examines a classic rate case; Part II looks at the use of securitization to finance emission 

reduction investments.

West Virginia Public Service Commission

The West Virginia Public Service Commission (PSC) supervises and regulates the rates, services, 

operations and other activities of public utilities within West Virginia. The PSC acts upon 

petitions filed by these regulated entities, and complaints filed against them. The PSC was 

created in 1913 by the West Virginia State Legislature to regulate railroads, and since then has 

expanded to regulate companies providing electricity, natural gas, water, telecommunications, 

and sewer service in all fifty-five counties of the State.

The West Virginia PSC consists of three members who are appointed by the Governor with the

advice and consent of the Senate. No more than two commissioners may belong to the same 

political party. Each commissioner serves six-year staggered terms, with one term expiring July 

1 of each odd numbered year. In addition, one commissioner is designated as Chairman of the 

PSC by the Governor and serves as the chief administrative officer of the Commission.

West Virginia operates under the PJM Interconnection. PJM is the world’s largest wholesale 

electricity market, and serves as the regional transmission organization for all or parts of 

Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, 

Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

Relevant Environmental Regulations

The modifications proposed by Appalachian Power Company were designed as a compliance 

strategy in anticipation of emissions reduction requirements for SO2, NOX, and mercury in EPA’s 

CAIR and CAMR rules. 

Part I. Examination of Classic Rate Case in WV PSC

Summary and Chronology

Appalachian Power Company (APCo)51 sought to recover the costs of, among other items, a $1.2 

billion scrubber retrofit program. While the parties to the case agreed that APCo was generally 

entitled to cost recovery for controls needed to comply with the Clean Air Interstate Rule (CAIR), 

they differed over the manner of recovery: APCo wanted recovery approved in advance without 

 

51 APCo also includes Wheeling Power Company.
77

review of actual costs, while the West Virginia Public Service Commission (PSC) and intervenors

pressed for recovery of future costs in a future rate case or, at a minimum, through an annual 

cost recovery mechanism that allowed for the review of actual costs. Ultimately, the parties 

settled on recovery of Construction Work in Progress on an annual basis after a review of the 

costs. 

The rate case lasted 11 months and illuminates how stakeholders can be willing to balance 

concerns about higher rates with the reality that pollution control investments can be 

extraordinary investments requiring innovative recovery mechanisms.

Facility and Modification Description 

American Electric Power Company (AEP) conducted a system-wide review of its power plants to 

develop a company-wide compliance strategy with CAIR and CAMR. Anticipating cuts in SO2 

allowances of as much as 50 percent, AEP and its subsidiary Appalachian Power Company 

(APCo) proposed to install flue gas desulfurization systems (FGDs or “scrubbers”) on four units 

at two coal-fired power plants: Mountaineer and John Amos Units 1, 2 and 3. The units have a 

combined capacity of 4,200 MW (over 50 percent of APCo’s power generation capacity), and are 

summarized in Table 16.

Table 16. Plant Characteristics for APCo Scrubber Projects

Name Capacity (MW) Planned FGD In-Service Date

Mountaineer 1300 January 2007

John Amos 1 1300 January 2009

John Amos 2 800 January 2009

John Amos 3 800 January 2008

APCo’s Cost Recovery Request and Legal Basis

APCo estimated total cost for the projects was $1.27 billion, of which approximately 45 percent,

or $577 million, was allocated to APCo’s West Virginia operations. Historically, cost recovery for 

capital projects in West Virginia follows the traditional model: recovery is deferred until the 

project is in service and a new rate case is filed to recover the costs. However, given the 

extraordinarily high level of investment and the infrequency of general rate cases in West 

Virginia (as of August 2005, APCo’s base rates had not increased for 20 years), APCo was 

concerned about the impact that regulatory lag would have on timely cost recovery. The costs 

of the scrubber projects, when completed, would add $83 million annually to the overall 

revenue requirement used to calculate rates. However, APCo would not be able to add the 

additional revenue requirement to customer rates until the scrubber projects were complete 
78

and a new case filed and approved. Such a delay was not acceptable for the level of investment, 

according to the rebuttal testimony of Terry R. Eads on behalf of APCo:

“In the context of an ordinary rate case and its timing, there can be compensating 

factors, such as decreasing costs offsetting increasing costs, or increased revenues not 

reflected in current rates balancing increased costs not reflected. Here we are dealing 

with non-revenue-producing costs which are so large that nothing can offset or balance 

them. Some appropriate mechanism beyond the ordinary methods used for ordinary 

costs in ordinary circumstances is needed to deal with them.”

In order to recover its costs in a more timely fashion, APCo filed a general rate case on August 

25, 2005. Because the scrubber projects were not yet completed, APCo did not include them in 

the core rate base calculations. Instead, APCo requested a special surcharge that would allow 

automatic recovery of scrubber project costs without filing a new rate case. Essentially, the 

additional revenue requirements created by the scrubber projects would be recovered through 

a special surcharge on the demand portion of each customer’s bill. The surcharge would be 

adjusted upward annually from 2007 through 2009, reflecting the projection that new scrubbers 

would be in service each of those years and therefore eligible for recovery (see Table 17).

Table 17. Projected Additional Revenue Requirements for Scrubber Projects, 2007-2009

Plant 2007 2008 2009

Mountaineer $34,507,573 $33,841,175 $33,179,308

Amos Unit 3 - $10,569,866 $10,354,984

Amos Unit 1&2 - - $39,433,173

Total $34,509,580.00 $44,413,049.00 $82,969,474.00

APCo based its departure from normal cost recovery procedures on a West Virginia statute that 

says, in part:

(b) Upon a finding that it is in the public interest of this state, as provided in section one, 

article one of this chapter, the public service commission shall authorize rate-making 

allowances for electric utility investment in clean coal and clean air technology facilities 

or electric utility purchases of power from clean coal technology facilities located in 

West Virginia which shall provide an incentive to encourage investments in such 

technology ...

(d) The public service commission shall determine, at such time and in such proceeding, 

form and manner as is considered appropriate by the commission, the extent to which 
79

any electric utility investment or purchases of power qualify for incentive rate-making 

pursuant to this section. W.Va. Code 24-2-18.

APCo contended that the “value that these investments bring to the State and its economy in 

terms of capital investment and employment opportunities, both from the utility operations 

themselves and from the mining sector that supplies the coal to be burned, clearly justifies 

special rate consideration under the statutory warrant. Moreover, encouragement of these 

investments will achieve significant benefits to the general public in terms of improving 

environmental quality both within and outside the state.”

Studies Reports and Testimonies

APCo’s proposal was roundly criticized by staff of the PSC, major intervenors and the Consumer 

Advocacy Division (CAD). In their report, the PSC staff flatly rejected the proposal, stating:

“Staff is not in agreement at all with the Companies’ request for estimated and future 

rate making treatment pertaining to the scrubbers. Staff recommends that the scrubber 

costs and investments be reviewed in some type of future rate proceeding if needed by 

the Companies if, and when, the actual costs are known and in service. To do so 

otherwise would be improper rate making treatment.”

Intervenor Kroger Co., owner of a chain of grocery stores in the state, summarized the two core 

objections. First, APCo’s request was not prudent because it would result in “single-issue 

ratemaking.” This occurs when a single cost item is permitted to impact rates in isolation from 

all other rate considerations. As a result, changes in other costs and revenues are not taken into 

consideration, creating a situation where APCo could earn an overall return that is above or 

below the return approved in the rate case.

Second, APCo’s request was not reasonable or prudent because it would approve the amounts 

of cost recovery in advance, without a mechanism for reviewing and adjusting recovery for 

actual costs. According to Kroger, differences between projected and actual costs would only be 

addressed in a future rate proceeding on a prospective basis. As a result, “customers have no 

assurance that the investments they are being asked to fund would be built on the same 

schedule presumed in the charges that are being proposed. Exposing customers to such a 

potential mismatch between cost and benefit is not in the public interest.”

The CAD echoed these concerns in its testimony. However, unlike the other intervenors, the 

CAD agreed that the extraordinary costs of the scrubbers required some form of accelerated 

cost recovery. In order to address issues about single-issue ratemaking and the inability to 

review actual costs before new rates were imposed, the CAD proffered a compromise in which 

APCo would be able to recover Construction Work in Progress (CWIP) costs through an annual 

surcharge. The amount of the surcharge would be subject to review and approval by the PSC 

and the public annually as part of the review of the company’s expanded net energy cost 

recovery mechanism.
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Final Determinations

On July 26, 2006, the PSC approved a settlement of the general rate case. With respect to the 

recovery of pollution control costs, the parties agreed to accept the compromise offered by the 

CAD, with minor modifications, to allow accelerated recovery via a demand surcharge. APCo 

further agreed to file a general rate case in 2010 and, as part of that filing, move all completed 

projects formally into rate base as a further way to address the single-issue ratemaking issue.

Project Status

Three of the four scrubber projects have been completed: the Mountaineer Plant retrofit was 

finished in 2007, Amos Unit 3 was completed in March 2009, and Unit 2 in February 2010. Unit 

1 is expected to go into service in early 2011. In its most recent filing, the pollution control 

projects added approximately $76.5 million to the revenue requirement, about $6.5 million less 

than originally projected. This is largely driven by the fact that Unit 1 has not yet been 

completed. This indicates that the concerns of the stakeholders were valid – the original cost 

recovery requested by APCo would have, in fact, been too high. At the same time, when Unit 1 

is completed, the total revenue requirement will likely end up higher than projected (if the costs 

are similar to Unit 2), lending weight to APCo’s position that it was bearing as much risk as its 

customers. In the end, the case study demonstrates that the compromise reached by the 

parties through the PSC process achieved the intended result: allowing accelerated recovery of 

extraordinary expenditures for APCo, while prudently protecting the interests of APCo’s 

customers. 

Part II. Examination of Securitization Case in the WV PSC

Under the traditional utility financing model, a utility will pay for a major capital project through 

a mixture of two sources: debt and equity. Once the project is included in the rate base, the 

utility will earn a return on capital that covers the interest on the debt and provides for a return 

(profit) on the equity. The return that is required to cover the debt and equity is the “cost of 

capital.” 

Securitization as an alternative financing mechanism is the practice of paying for a capital 

project outside of the utility financing model by selling bonds that are directly backed and paid 

for by ratepayers. The bonds are “secured” by the pollution control equipment and an 

irrevocable promise that ratepayers will make the payments on the bonds through a dedicated 

charge on their bills. Utility shareholders provide no separate guarantee. The ratepayer 

guarantee, enforced by statute and the terms of the financing, minimizes the risk of default, and 

the resulting interest rate should be significantly lower than either the interest on debt incurred 

by utilities or a utility’s return on equity. Thus, the cost of capital using securitization can be 

significantly lower than the traditional utility cost of capital.

While securitization can provide cheaper capital, it can also pose unique risks to ratepayers,

because they are providing funding for a project up front instead of after completion or at 

regular stages of development. Once the bonds are issued, the ratepayers are on the hook 
81

financially no matter what happens with the project. Accordingly, ratepayers have no recourse 

if the investment turns out to be a poor one. 

Moreover, securitization leaves the utility out of the profit earning equation. While this means 

that securitization will not always be a favored financial tool for utilities, it can be useful in 

situations where a utility’s financial position prevents it from raising capital for high-cost 

projects.

West Virginia Code: Securitization Statute

In April 2005, the West Virginia Legislature passed a law authorizing utilities to issue 

“Environmental Control Bonds” (ECBs): bonds dedicated to financing pollution control projects

at the state’s coal-fired power plants.52 The Legislature found that electric utilities in the state 

needed to install and construct emission control equipment at generating facilities in the state 

in order to meet the requirements of existing and anticipated environmental laws and 

regulations. However, the financial condition of some electric utilities made the use of 

traditional utility financing mechanisms to finance the construction and installation of emission 

control equipment difficult or impossible. 

To avoid deferment of the installation of emission control equipment, high financing costs, or a 

shift away from “high-sulfur coal mined in the State,” the Legislature provided for securitization 

of pollution control projects through the issuance of ECBs. The statute permits a utility that is 

applying for a Certificate of Public Convenience and Necessity (CPCN) to install pollution control 

equipment to also apply for a “Financing Order” to issue bonds that will fund the project. The 

Financing Order authorizes the utility to levy an environmental control charge to make 

payments on the bonds. The authorization to levy the charge is an irrevocable until the 

obligation to bondholders is completely discharged.

In order to obtain the financing order, the utility must, among other things:

Describe the environmental control activities and demonstrate that they are necessary 

and preferable to any other alternative; and 

Demonstrate that the environmental control costs are reasonable and the issuance of 

environmental control bonds will “result in overall costs to customers of the qualifying 

utility that [are] lower than would result from the use of traditional utility financing 

mechanisms.”

Once a utility files for a financing order, the PSC is required to render a decision within 270 days.

 

52 West Virginia State Code. Chapter 24. Article 2. Section 4e. Environmental Control Bonds. 2010. 

http://www.legis.state.wv.us/WVCODE/Code.cfm.
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Summary and Chronology

In 2005, Allegheny Power filed for a CPCN for the installation of a scrubber at the Ft. Martin 

generating station. At the same time, they filed a request with the West Virginia PSC to 

authorize the issuance of $382 million in Environmental Control Bonds to pay for the project. 

The bonding mechanism had been created by the West Virginia Legislature to encourage 

investment in pollution controls at the lowest possible cost to ratepayers. After stakeholder

negotiations, the PSC approved a settlement allowing Alleghany Power to issue $365 million in 

Environmental Control Bonds. The process took less than 11 months. Over the subsequent four 

years, the bonding authority was raised twice to a final number of $566.6 million. Allegheny 

Power and the PSC estimate that securitization saved ratepayers between $130 and $170 

million.

Facility Description

The Fort Martin plant is a 1,107 MW coal-fired facility in Maidsville, West Virginia. The facility is 

comprised of two units: Unit 1 has a capacity of 552 MW and Unit 2 a capacity of 555 MW. In 

2003, Ft. Martin Unit 1 emitted over 56,000 tons SO2 in 2003; making it the 10th highest emitter 

in the U.S., and Ft. Martin Unit 2 emitted over 45,000 tons, making it the 21

st highest emitter in 

the U.S.

Modification Description: Alleghany Power’s Proposal, Response and Settlement

Alleghany Power was the first utility to take advantage of the new financing option, filing for a 

CPCN for a scrubber at its Fort Martin plant on March 24, 2005 and then filing for a financing 

order on May 24, 2005. Allegheny Power determined that a scrubber was the most effective 

way to meet its expected obligations under CAIR and CAMR while also maximizing local 

economic benefits. 

Allegheny Power estimated total project costs of $338 million and proposed to issue $382 

million in ECBs. The additional $42 million was based on projected financing costs. However, 

the proposal did not include separate caps for project costs and financing. As a result, if the 

financing costs were lower than projected, the remainder could be used to cover cost overruns. 

Studies, Reports and Testimonies

In general, the proposal was not controversial: the CPCN and choice of using a scrubber were 

not contested, nor was the financing mechanism, since it had been expressly authorized by the 

Legislature. However, stakeholders such as the Consumer Advocate Division (CAD) asked the 

PSC to put in as many controls as possible to limit ratepayer exposure and maximize the benefits 

of using securitization by limiting financing costs. According to the direct testimony of Scott J. 

Rubin on behalf of the CAD:

*T+he companies’ proposal lacks these fundamental protections. As they propose the 

securitization, the Commission would determine the prudence of the project today 

(which is consistent with the CPCN process in West Virginia), but there would be no 
83

further review of the companies’ actual procurement and construction. Similarly, under 

the companies’ proposal, once the Commission approves the securitization order in 

these cases, customers would be obligated to repay the bonds without regard to the 

future used and useful nature of the facilities constructed. That is, under the 

companies’ proposal, there would be nothing to provide a check on the companies’ 

subsequent activities in design, construction, and procurement of the scrubbers.

The CAD requested that the PSC cap the bonds at $355 million, with a $338 million cap on 

project costs and a $17 million cap on financing costs. If costs exceeded the caps, then 

Allegheny Power would be required to either self-finance the additional costs and seek recovery 

through a rate case or file for a new Financing Order. The CAD also recommended that the PSC 

retain a financial advisor to oversee the bonding process and ensure that the financial costs 

were minimized. 

Final Determinations

The parties reached a settlement on January 11, 2006, largely agreeing along the lines of the 

CAD’s proposal, with a cap on project costs of $338 million, a cap on financing costs of $27 

million, and the retention of a financial advisor to guide the PSC in its oversight. In approving 

the settlement on April 7, 2006, the PSC found that that the use of a “wet scrubber will sharply 

reduce the Applicants’ reliance on emission allowances, providing a less volatile environmental 

compliance mechanism for the Applicants” and underscored the need for extensive oversight 

over the securitization process and the integral decision-making role that the PSC and its 

Financial Advisor would play:

The Commission will act through its designated personnel and a financial advisor (the 

“Financial Advisor”) to participate in all aspects of the structuring, marketing, and 

pricing of the Environmental Control Bonds and will make the decision, in conjunction 

with the Applicants, as to whether Environmental Control Bonds will be issued. 

By taking an active, informed role the PSC sought to ensure that risks to ratepayers would be 

minimized and the benefits of securitization – low financing costs – would be maximized.

Project Status 

Construction on the project commenced in September 2006, with a projected completion date 

of November 21, 2009. On October 3, 2006, Allegheny Power petitioned to reopen the case 

based on new engineering estimates that placed project costs at $550 million. Accordingly, 

Allegheny asked for authority to issue bonds for up to $573 million (including $23 million in 

financing costs). After negotiations, the parties to the case settled on, and the PSC agreed to, 

increasing Allegheny’s authority to $466.5 million – $450 million for project costs and $16.5 

million for financing costs. On April 11, 2007, the parties announced a successful $459.3 million 
84

bond offering that would save ratepayers an estimated $130 million over traditional utility 

financing.53

On July 1, 2009, Allegheny again petitioned to reopen the case stating that the cost estimate 

remained $550 million and that seeking cost recovery through traditional means (a rate case) 

would not be in the best interests of ratepayers because it would require Allegheny Power to 

issue its own debt on unfavorable terms. The parties again reached settlement and the PSC 

approved another $105 million in Environmental Control Bonds. On December 23, 2009, an 

additional $85.9 million in bonds were issued.54 On February 4, 2010, Allegheny announced the 

completion of the Fort Martin scrubber project. 

Reflections

APCo’s 2005 rate case lasted 11 months and illuminates how stakeholders can be willing to 

balance concerns about higher rates with the reality that pollution control investments can be 

extraordinary investments requiring innovative recovery mechanisms. Allegheny’s 2005 CPCN 

filing demonstrates how a relatively new concept for funding a pollution control project, 

securitization, can be successfully used. It required clear direction and a promise that 

ratepayers would repay the debt from the West Virginia legislature, along with clear deadlines 

to ensure that the process did not become delayed. Success also required that stakeholders 

were willing to compromise and move constructively on an expedited basis. Even though 

Allegheny Power went back to the PSC twice for authority to issue additional bonds, the 

requests in both instances were approved in approximately three months. In exchange for the 

expedited process, Allegheny Power continued to move forward on the project despite the 

financial uncertainty, and the other stakeholders cooperated with the accelerated process. As a 

result, the project was completed nearly on schedule at a much lower cost to the ratepayers. 

This case further demonstrates how securitization can help overcome financing obstacles faced 

by financially troubled utilities in a way that can reduce overall costs to ratepayers. It also 

shows that this new tool may require multiple PSC processes to set the right level of bonding 

authority, and that West Virginia’s use of clear legislative directions and mandatory deadlines 

for PSC decisions were important in keeping project financing on pace with project 

development.

 

53 West Virginia Public Service Commission. Public Service Commission Of West Virginia (PSC) Projects 

$130 Million In Savings For Ratepayers Through Innovative Bond Sale. April 11, 2007. 

http://saberpartners.com/press/pressreleases/pr_04_12_07.html.

54 Allegheny Energy 10-K, March 1, 2010.
85

Indiana Case Study: PUC Influence on a 

Performance-Based Strategy

As discussed in the Indiana case study, Indiana 

generators were faced with a performance-based 

regulatory limit, in this case a tonnage cap on 

mercury emissions, and had several compliance 

options available including purchasing additional 

allowances to cover anticipated emissions or 

reducing emission through post-combustion 

controls and/or fuel switching. The Indiana PUC 

chose not to approve the utility’s planned mercury 

controls, instead approving the purchase of 

sufficient allowances. However, with CAMR’s 

vacatur in 2008, these plants remain uncontrolled 

for mercury. This case illustrates the current 

tension inherent in the PUC’s mandate to minimize 

immediate rate costs. In retrospect, had the PUC 

approved the controls plan, the PUC would have 

approved expenditures and related cost recovery 

for a regulation that never took effect. On the 

other hand, the utility is now continuing to operate 

plants with no mercury controls installed. 

Additionally, had the utility controlled for mercury 

as planned, it would likely be well-positioned to 

meet upcoming requirements, including the Utility 

MACT. However, would Indiana ratepayers have 

paid more per pound of mercury removed, since 

the technology has advanced somewhat in recent 

years? Now the utility is forced to plan anew for 

regulations that have been known to be 

forthcoming. This case study, as well as the Florida 

case study to a degree, illustrates the hurdles 

utilities face in comprehensively addressing 

upcoming regulatory, legislative, and public 

mandates to transform the generation fleet. 

CONCLUSIONS

This study demonstrated that the PUC process is indeed influential in determining how utilities 

implement environmental compliance strategies. Many of the examples show changes to the 

timing or type of control installations eventually installed. Utilities’ initial financial requests

were often modified due to intervenors’ positions and studies. Thus, PUCs are important 

institutions in shaping compliance solutions and will continue to be as utilities plan for 

compliance with the upcoming Utility MACT and Transport Rule. A deeper understanding of 

PUC procedures is useful and timely.

We examined 101 PUC processes that 

involved an approval prior to construction. 

The majority were completed within six 

months. This subset of observations is not 

conclusive, but it does indicate that most 

pre-construction PUC approvals can be 

processed within a year. These results are 

illuminating as the timeframes for 

compliance with EPA’s new regulations are 

constrained by the text of the relevant Act 

and, in some cases, consent decrees. 

EPA recently agreed in a consent decree to 

propose GHG NSPS and emission guidelines 

for power plants by July 2011 and finalize 

them by the end of May 2012. In addition 

to establishing a floor for GHG BACT, these 

performance standards will likely establish 

the first GHG standards for existing sources. 

To what degree the performance standard

will be examined or altered by PUCs is 

unclear, given that EPA has not proposed

the basis for such a standard or the 

flexibility options that it may allow. EPA has 

signaled that regulators should prioritize 

energy efficiency for the current GHG BACT 

determinations for new and modified 

sources. BACT permits may specify a 

maximum emissions rate and/or other 

performance criteria, and the generator 

must then select the most appropriate suite 

of control measures to attain the BACT 

limits. Energy efficiency upgrades to power 
86

plants can take many forms. Thus, it is hard to predict when an energy efficiency upgrade will 

be subject to a PUC determination. As demonstrated in the case studies, each PUC is unique. 

Some PUCs may require that an energy efficiency upgrade have a CPCN; others may not. In 

some cases, an upgrade may have a significant and distinct capital cost, while in other cases, it 

may be within a maintenance budget and be considered general practice by the utility and 

regulators. Given the wide range of potential upgrades and the variability among PUC 

requirements, it is difficult to generalize about the intersection of the two. A more careful 

review of energy efficiency upgrades, including their nature, size, and expense, could help gauge 

the likelihood that a PUC determination would be triggered. 
87

APPENDIX A. ROLE OF NATIONAL UMBRELLA ORGANIZATIONS: NARUC AND NASUCA

National Association of Regulatory Utility Commissioners

The national organization that brings all the PUCs together is called the National Association of 

Regulatory Utility Commissioners (NARUC). It was founded in 1889, as a nonprofit organization 

composed of governmental agencies engaged in the regulation of utilities and carriers 

(communications, energy, and water utilities) in the fifty states, the District of Columbia, Puerto 

Rico, and the Virgin Islands. NARUC represents the interests of state public utility commissions 

before the three branches of the Federal government, and its membership is composed of state 

public utility commissioners. 

NARUC participates in several collaborative federal efforts with FERC and the Federal 

Communications Commission (FCC), including: 1) the Competitive Procurement Collaborative, 

which provides state and federal policymakers with a venue to discuss the best ways to meet 

the challenges of developing new and economical power supplies; 2) the Demand Response

Collaborative, which serves to explore how federal and state regulators can better coordinate 

their respective approaches to electricity demand response policies and practices; and 3) the 

Smart Response Collaborative, to facilitate the transition to a smart electric grid. 

Programs are operated by the NARUC Grants & Research Department, which receives funding 

from several Federal agencies, including the Environmental Protection Agency, the Department 

of Energy, and the Department of Homeland Security. Recent EPA funding to NARUC has been 

between $50,000 and $100,000 per year. The primary focus of the funding goes to educating 

commissioners about the specifics of energy efficiency policies. This amount of funding is a 

fraction of the amount the Department of Energy gives to NARUC.55 Domestic programs are 

conducted with those agencies along with the New York State Energy Research and 

Development Agency and the Energy Foundation. In addition, NARUC’s research foundation, 

the National Regulatory Research Institute, regularly releases papers on these and other 

subjects.

National Association of State Utility Consumer Advocates

The National Association of State Utility Consumer Advocates (NASUCA) is an organization that 

represents the interests of utility consumers. NASUCA consists of 44 consumer advocates in 40 

states and the District of Columbia. The members of NASUCA are designated by the laws of 

their respective jurisdictions to represent utility consumers before state and federal regulators 

and in the courts. The founders of NASUCA established the organization for state agencies to 

act as independent ratepayer advocates. NASUCA’s original purpose was to provide a forum to 

exchange ideas, improve consumer representation at the state and federal levels, and

encourage greater consumer participation in the regulatory process. Currently, state consumer 

 

55 Call on November 10, 2010 with Joe Bryson, EPA and EPA Grants Award Database.

http://yosemite.epa.gov/oarm/igms_egf.nsf/HomePage?ReadForm.
88

advocates focus on consumer protection issues, such as service quality, reliability, and price 

stability. 

NASUCA’s seven standing and ad-hoc committees develop the policy positions that guide the 

organization’s advocacy activities and other programs NASUCA’s committees include: the 

Officers & Executive Committee, the Electricity Committee, the Telecommunications 

Committee, the Natural Gas Committee, the Water Committee, the Consumer Protection 

Committee, and the Tax and Accounting Committee.
89

APPENDIX B. NERC RELIABILITY 

Table I. Sample of NERC Reliability Standards and Applicability

Reliability 

Standard

Purpose Applicability

Real Power 

Balancing 

Control 

Performance

To maintain Interconnection steady-state frequency within 

defined limits by balancing real power demand and supply in 

real-time.

Balancing 

Authorities

Disturbance 

Control 

Performance

The purpose of the Disturbance Control Standard (DCS) is to 

ensure the Balancing Authority is able to utilize its Contingency 

Reserve to balance resources and demand and return 

Interconnection frequency within defined limits following a 

Reportable Disturbance. Because generator failures are far 

more common than significant losses of load, and because 

Contingency Reserve activation does not typically apply to the 

loss of load, the application of DCS is limited to the loss of 

supply and does not apply to the loss of load.

Balancing 

Authorities, Reserve 

Sharing Groups, 

Regional Reliability 

Organizations

Contingency 

Reserves

Contingency Reserve is required for the reliable operation of 

the interconnected power system. Adequate generating 

capacity must be available at all times to maintain scheduled 

frequency, and avoid loss of firm load following transmission or 

generation contingencies. This generating capacity is necessary 

to replace generating capacity and energy lost due to forced 

outages of generation or transmission equipment.

Balancing Authority, 

Reserve Sharing 

Group

Operating 

Reserves

Regional Reliability Standard to address the Operating Reserve 

requirements of the Western Interconnection.

This criterion 

applies to each 

Responsible Entity 

that is (i) a 

Balancing Authority 

or a member of a 

Reserve Sharing 

Group that does not 

designate its 

Reserve Sharing 

Group as its agent
90

Reliability 

Standard

Purpose Applicability

Sabotage 

Reporting

Disturbances or unusual occurrences, suspected or determined 

to be caused by sabotage, shall be reported to the appropriate 

systems, governmental agencies, and regulatory bodies.

Reliability 

Coordinators, 

Balancing 

Authorities, 

Transmission 

Operators, 

Generator 

Operators, Load

Serving Entities.

Cyber Security 

— Critical 

Cyber Asset 

Identification

NERC Standards CIP-002-2 through CIP-009-2 provide a cybersecurity framework for the identification and protection of 

Critical Cyber Assets to support reliable operation of the Bulk 

Electric System. These standards recognize the differing roles of 

each entity in the operation of the Bulk Electric System, the 

criticality and vulnerability of the assets needed to manage Bulk 

Electric System reliability, and the risks to which they are 

exposed. Business and operational demands for managing and 

maintaining a reliable Bulk Electric System increasingly rely on 

Cyber Assets supporting critical reliability functions and 

processes to communicate with each other, across functions 

and organizations, for services and data. This results in 

increased risks to these Cyber Assets. Standard CIP-002-2 

requires the identification and documentation of the Critical 

Cyber Assets associated with the Critical Assets that support the 

reliable operation of the Bulk Electric System. These Critical 

Assets are to be identified through the application of a riskbased assessment.

Reliability 

Coordinator, 

Balancing Authority, 

Interchange 

Authority, 

Transmission 

Service Provider, 

Transmission 

Owner, 

Transmission 

Operator, 

Generator Owner, 

Generator 

Operator, Load 

Serving Entity, 

NERC, Regional 

Entity.

Generator 

Operation for 

Maintaining 

Network 

Voltage 

Schedules

To ensure generators provide reactive and voltage control 

necessary to ensure voltage levels, reactive flows, and reactive 

resources are maintained within applicable Facility Ratings to 

protect equipment and the reliable operation of the 

Interconnection.

Generator 

Operator, 

Generator Owner.

Data From the 

Regional 

Reliability 

Organization 

Needed to 

Assess

Reliability

To ensure that each Regional Reliability Organization complies 

with planning criteria, for assessing the overall reliability 

(Adequacy and Security) of the interconnected Bulk Electric 

Systems, both existing and as planned.

Regional Reliability 

Organization
91

Reliability 

Standard

Purpose Applicability

System 

Performance 

Following 

Extreme Events 

Resulting in the 

Loss of Two or 

More Bulk 

Electric System 

Elements

System simulations and associated assessments are needed 

periodically to ensure that reliable systems are developed that 

meet specified performance requirements, with sufficient lead 

time and continue to be modified or upgraded as necessary to 

meet present and future System needs.

Planning Authority, 

Transmission 

Planner

Response to 

Transmission 

Limit Violations

To ensure Transmission Operators take actions to mitigate 

(System Operating Limit) SOL and Interconnection Reliability 

Operating Limit IROL violations.

Transmission 

Operators

Reporting 

System 

Operating Limit 

(SOL) and 

Interconnection 

Reliability

Operating Limit 

(IROL) 

Violations

This standard ensures SOL and IROL violations are being 

reported to the Reliability Coordinator so that the Reliability 

Coordinator may evaluate actions being taken and direct 

additional corrective actions as needed.

Transmission 

Operators, 

Reliability 

Coordinators

Monitoring 

System 

Conditions

To ensure critical reliability parameters are monitored in realtime.Transmission 

Operators, 

Balancing 

Authorities, 

Generator 

Operators, 

Reliability 

Coordinators.

Transmission 

Operations

To ensure that the transmission system is operated so that 

instability, uncontrolled separation, or cascading outages will 

not occur as a result of the most severe single Contingency and 

specified multiple Contingencies.

Transmission 

Operators

Planned Outage 

Coordination

Scheduled generator and transmission outages that may affect 

the reliability of interconnected operations must be planned 

and coordinated among Balancing Authorities, Transmission 

Operators, and Reliability Coordinators.

Generator 

Operators, 

Transmission 

Operators, 

Balancing 

Authorities,

Reliability 

Coordinators
92

Reliability 

Standard

Purpose Applicability

Reliability 

Responsibilities 

and Authorities

To ensure reliability entities have clear decision-making 

authority and capabilities to take appropriate actions or direct 

the actions of others to return the transmission system to 

normal conditions during an emergency.

Balancing 

Authorities, 

Transmission 

Operators, 

Generator 

Operators

Distribution 

Providers, Load 

Serving Entities

Capacity 

Benefit Margin

To promote the consistent and reliable calculation, verification, 

preservation, and use of Capacity Benefit Margin (CBM) to 

support analysis and system operations.

Load-Serving 

Entities, Resource 

Planners, 

Transmission 

Service Providers, 

Balancing 

Authorities, 

Transmission 

Planners, when 

their associated 

Transmission 

Service Provider 

maintains CBM

Reliability 

Coordination —

Transmission 

Loading Relief 

(TLR)

The purpose of this standard is to provide Interconnection-wide 

transmission loading relief procedures that can be used to 

prevent or manage potential or actual SOL and IROL violations 

to maintain reliability of the Bulk Electric System.

Reliability 

Coordinators, 

Transmission 

Operators,

Balancing 

Authorities.

Reliability 

Coordination —

Responsibilities 

and Authorities

Reliability Coordinators must have the authority, plans, and 

agreements in place to immediately direct reliability entities 

within their Reliability Coordinator Areas to re-dispatch 

generation, reconfigure transmission, or reduce load to mitigate 

critical conditions to return the system to a reliable state. If a 

Reliability Coordinator delegates tasks to others, the Reliability 

Coordinator retains its responsibilities for complying with NERC

and regional standards. Standards of conduct are necessary to 

ensure the Reliability Coordinator does not act in a manner that 

favors one market participant over another.

Reliability 

Coordinators, 

Regional Reliability 

Organizations, 

Transmission 

Operator, Balancing 

Authorities, 

Generator 

Operators.

Transmission 

Service Providers, 

Load-Serving 

Entities, PurchasingSelling Entities.
93

Reliability 

Standard

Purpose Applicability

Glossary of Terms:

Balancing Authority: The responsible entity that integrates resource plans ahead of time, maintains loadinterchange-generation balance within a Balancing Authority Area, and supports Interconnection 

frequency in real time.

Load-Serving Entity: Secures energy and transmission service (and related Interconnected Operations 

Services) to serve the electrical demand and energy requirements of its end-use customers.

Regional Reliability Organization: 1. An entity that ensures that a defined area of the Bulk Electric System 

is reliable, adequate, and secure. 2. A member of the North American Electric Reliability Council. The 

Regional Reliability Organization can serve as the Compliance Monitor.

Reliability Coordinator: The entity that is the highest level of authority who is responsible for the reliable 

operation of the Bulk Electric System, has the Wide Area view of the Bulk Electric System, and has the 

operating tools, processes and procedures, including the authority to prevent or mitigate emergency 

operating situations in both next-day analysis and real-time operations. The Reliability Coordinator has 

the purview that is broad enough to enable the calculation of Interconnection Reliability Operating Limits, 

which may be based on the operating parameters of transmission systems beyond any Transmission 

Operator’s vision.

Transmission Operator: The entity responsible for the reliability of its “local” transmission system, and 

that operates or directs the operations of the transmission facilities. 
94

APPENDIX C. DETAILS OF STATES FOR TIMING ANALYSIS

Alabama. Only investor-owned utilities are regulated by the Alabama PSC, thus Alabama Power 

is the only utility that falls under their jurisdiction. Alabama Power submits an annual 

environmental compliance plan associated with the Rate CNP portion of their rates. The Rate 

CNP is adjusted annually for cost recovery for, among other things, environmental compliance 

costs in the coming year. The PSC has final jurisdiction over approving this adjustment, but does 

not evaluate particular compliance strategies for their prudence or cost-effectiveness; decisions 

on compliance methods are left to Alabama Power and the Alabama Department of 

Environmental Management. The PSC’s involvement in the approval of environmental upgrades 

and costs is short and perfunctory, and consists only of an annual informal meeting. Because of 

the PSC’s limited involvement, and the fact that there is no formal approval of the 

environmental costs, Alabama was not included in the timing analysis.

Colorado. A number of different types of cases in Colorado have been used to approve 

pollution control projects and their cost recovery. In 1998, the Colorado legislature passed a bill 

encouraging utilities to enter into voluntary agreements with the Colorado Division of Public 

Health and the Environment to reduce emissions below those required by law. This law, 

codified as 40-3.2-102, C.R.S., allows utilities to recover the costs of implementing these 

agreements. In 1998, Public Service Company of Colorado (PSCo) entered into a voluntary 

emissions reduction agreement under this law and was granted cost recovery in a Commission 

order approving the plan. In 2005, PSCo entered into a settlement agreement regarding 

construction of a new coal-fired unit at their Comanche plant; the settlement agreement 

required them to install pollution controls on the existing units at Comanche and allowed them 

cost recovery for the controls. Finally, in 2010, PSCo filed a plan to comply with the state’s new 

Clean Air-Clean Jobs act. Approval of the plan included granting a presumption of need for 

future CPCNs for the pollution control projects, as well as permission to accumulate AFUDC for 

recovery in a future rate case. This example is further explored as a case study in Section IV.

Florida. Utilities in Florida can recover the projected costs of environmental compliance 

through an environmental charge known as the Environmental Compliance Recovery Clause 

(ECRC). The level of this charge is set in an annual proceeding, and past recovery is trued-up to 

actual costs. Utilities must receive approval for any new projects to be included in the ECRC; 

they often do this in the course of the annual ECRC proceeding, but can also file separate cases 

to do so. The disconnect between a Florida utility and the PUC is explored as an example in 

Section IV.

Georgia. Georgia has no process outside of rate cases to approve environmental projects or 

cost recovery. However, in its 2007 rate case, Georgia Power established a separate rider for 

recovery of projected environmental costs, the Environmental Compliance Cost Rider (ECCR). 

The rate case set a value for recovery over the following three years. The ECCR was updated in 

Georgia Power’s 2010 rate case to reflect the next three years of projected costs. Georgia Code 
95

§ 46-3A-7 requires the PSC to decide rate cases within six months, thus both of these cases were 

resolved within that time period. A Georgia rate case is included as a case study in Section IV.

Illinois. Illinois is a deregulated state, and the price of electric generation is set by the market 

rather than the PUC. No CPCN is required for the construction of pollution control retrofits. 

Indiana. In Indiana, utilities are required to obtain a CPCN from the Indiana Utility Regulatory 

Commission before installing “clean coal technology,” i.e., emissions controls for NOX or SO2, at 

a generating facility. Utilities can also apply for a pollution control add-on at a coal plant to be 

considered “qualified pollution control property” (QPCP) and thus eligible to be added to the 

value of the facility for ratemaking purposes. At the same time, utilities can receive preapproval for Construction Work-In-Progress (CWIP) ratemaking treatment, cost recovery for 

capital costs and operations and maintenance, and special accounting treatment for the project.

Our analysis included eleven cases involving CPCN, QPCP, and other ratemaking determinations 

made prior to construction of emissions-control retrofits. All cases except for one took less than 

a year. One case took more than two years; this case and some reasons for its length are 

described in the Indiana Case Study (Section IV). 

Kentucky. Kentucky has both mandatory and optional pre-approvals for environmental 

projects. First, Kentucky requires a CPCN for construction of any “plant, equipment, property, or 

facility” involved in supplying electricity, which includes pollution control equipment. Second, 

utilities can submit an environmental compliance plan (ECP) for approval to the Kentucky PSC, 

which allows them to implement an environmental surcharge to recover the costs of approved 

environmental investments both past and future. Interestingly, Kentucky has also allowed cost 

recovery for pollution control projects outside of Kentucky; in two cases, it has allowed 

Kentucky Power to recover its share of the costs of pollution control projects at facilities 

belonging to other companies in the AEP pool.

Our analysis included cases involving CPCNs for pollution control add-ons, ECPs, or amendments 

to previously existing ECPs. The statute implementing the ECP process (KRS 278.183(2)) requires 

the Commission to complete its proceedings within six months of an ECP application. Because 

of this statute, ECP cases tend to be concluded in close to exactly six months. Applications for 

CPCNs are sometimes filed in the same case as an ECP and sometimes filed separately. When 

they are filed with an ECP, they are concluded in the statutorily required six months. When filed 

separately, there is slightly more variability, but they are generally concluded in six months or 

less. 

Maryland. Maryland is a deregulated state, and therefore the PSC does not offer any 

ratemaking treatment for environmental costs. Maryland utilities are required, however, to file 

for a CPCN at least 180 days before modifying a power plant in a way that changes its emissions, 

which includes emissions controls. Our analysis included the modifications that were 

undertaken in compliance with Maryland’s 2007 Healthy Air Act, which requires NOX and SO2

reductions at coal-fired power plants. This included eight cases of applications for CPCNs for 
96

add-on emissions controls. The average time from application to approval was eight months. It 

is important to note that because of the timeframe allowed for compliance with the Healthy Air 

Act, there was a period from late 2006 to mid-2007 during which multiple CPCN applications 

were being processed simultaneously; nonetheless, the process of approving these technologies 

never took longer than a year. 

Minnesota. Minnesota utilities are allowed to recover specific environmental costs through an 

emissions reduction rider. Initially, utilities were only allowed to recover environmental costs 

outside of a general rate case if they were incurred voluntarily, i.e., they were not required to be 

incurred because of a law, settlement agreement, or other mandate. In 2006, with the passage 

of the Mercury Emissions Reduction Act, utilities were allowed to recover the costs incurred in 

carrying out required Mercury Emissions Reduction Plans, as well as for other emissions 

reduction activities undertaken along with the mercury reductions, even if those reductions 

were required for compliance with an existing mandate. Our analysis involved two cases dealing 

with voluntary emissions reduction programs, and five involving Mercury Emissions Reduction 

Compliance Plans and their associated cost recovery. Additionally, a 2010 law allows utilities to 

apply for an advance determination of prudence for an emissions control project; this provides 

more assurance for the utility that the costs of the project will be recoverable in rates. The first 

case under this new statute, filed by Otter Tail Power Company (Case 10-1082), has not yet been 

decided. 

Missouri. No CPCN is required for pollution control projects in Missouri, and cost recovery is 

only allowed after a project is deemed “used and useful,” i.e., after it is completed. However, 

there are some limited assurances that a company can get from the PUC before they construct a 

project through the filing of regulatory plans. In 2005, three utilities, Kansas City Power & Light 

(KCP&L), Aquila (now KCP&L Greater Missouri Operations), and Empire District Electric 

Company, filed “experimental regulatory plans” with the commission that each contained, 

among other provisions, plans to install environmental upgrades at coal-fired Iatan Unit 1, in 

which each utility has an ownership stake.

The assurances and approvals that each company sought were different. Both Empire and 

KCP&L sought and received assurance from the Commission that their environmental upgrades

would not be excluded from rate base on the grounds that the projects were not “necessary or 

timely” or that they should have used alternative technologies. However, the agreements do 

not preclude the Commission from challenging the prudence of the environmental expenditures 

or proposing recovery of a different dollar amount in the next rate case. In contrast, while 

Aquila sought advance assurance in its first application for approval of its experimental 

regulatory plan that environmental upgrades at Iatan 1 were “necessary, timely, and prudent” 

to serve its customers, it eventually amended its application. Their amended application asked 

only for permission from the Commission to encumber its generating assets in the process of 

receiving a loan to finance the pollution control upgrades. Approval of the three cases took an 

average of 5 months, although it is worth noting that the informal workshop process that 

preceded the filing of KCP&L’s regulatory plan lasted over 9 months. 
97

New Jersey. New Jersey is a deregulated state, and the price of electric generation is set by the 

market rather than the PUC. No CPCN is required for the construction of pollution control 

retrofits. 

New York. New York is a deregulated state, and the price of electric generation is set by the 

market rather than the PUC. No CPCN is required for the construction of pollution control 

retrofits. 

North Carolina. In 2002, North Carolina passed the Clean Smokestacks Act, requiring reductions 

in NOX and SO2 emissions at power plants in the state owned by Duke and Progress Energy 

Carolinas. This bill authorized a specific amount of environmental compliance costs to be 

amortized for each utility, and required the utilities to submit compliance plans to the North 

Carolina Utilities Commission. However, review of the plans was largely left to the state’s 

Department of Environmental and Natural Resources, and the Commission did not issue any 

orders formally approving the compliance plans. The Commission does not issue pre-approvals 

for emissions control projects. Thus, North Carolina was not included in the timing analysis.

Ohio. No project-specific construction approvals are required in Ohio, which is partially 

deregulated. Utilities can recover the costs of environmental investments in their rates through 

the provisions of an Electric Security Plan (ESP) or Market Rate Offer (MRO) – the methods by 

which Ohio utilities now set their rates – but this has traditionally been used to recover the 

cost of past investments rather than planned or projected ones. In AEP Ohio’s most recent ESP 

proposal, however, the company has requested that its existing Environmental Investment 

Carrying Charge Rider be altered to recover projected costs; this has not yet been ruled on. 56 

Thus, there are no data available yet for how long it takes for Ohio utilities to receive approval 

for environmental cost recovery prior to construction.

Pennsylvania. Pennsylvania is a deregulated state, and the price of electric generation is set by 

the market rather than the PUC. No CPCN is required for the construction of pollution control 

retrofits. 

Virginia. The Virginia SCC does not require any siting approvals for pollution control projects. 

Utilities can recover the costs of pollution control projects in two ways: through a base rate case 

or through an environmental and reliability (E&R) rate surcharge. The Virginia SCC has ruled 

that utilities cannot recover projected future costs through the E&R surcharge, because the 

statute requires recoverable costs to have been “prudently incurred,” in the past tense.57 

Projected future costs can be recovered in base rate cases to the extent that they can be 

“reasonably predicted to occur” during the rate year.58 This “reasonably predicted” standard, 

however, is difficult to meet. The Commission has determined in both of Appalachian 

 

56 Ohio PUC Case 11-346-EL-SSO.

57 Application of Appalachian Power Company requesting Commission approval for adjustment of the 

Company’s capped rates. Case No. PUE-2005-00056, Commission Order. October 14, 2005.

58 Virginia State Code § 56-235.2.
98

Company’s rate cases that have included projected pollution control expenses that these 

expenses could not be “reasonably” predicted, and were not eligible for inclusion in base 

rates.59 As a result, there is generally no process by which Virginia utilities can receive preapproval for pollution control projects, and the state was not included in the timing analysis.

West Virginia. Section 24-2-4e of the West Virginia code allows utilities to use a special form of 

financing, called environmental control bonds, to pay for environmental control projects. These 

bonds are backed by assurance of cost recovery from ratepayers. An application for financing 

with these bonds must be filed with along with an application for a CPCN to engage in 

environmental control activities. Only two utilities so far (Monongahela Power and Potomac 

Electric – both d/b/a Allegheny Power) have taken advantage of this provision, and the case 

took slightly over a year to conclude. West Virginia also allows utilities to recover costs on 

pollution control construction, including CWIP, in the more traditional form of cost recovery 

riders. This process was used by Appalachian Power for its Mountaineer and John Amos 

scrubbers, and took slightly less than a year. A detailed discussion of these processes and the 

WV PSC is included as a case study in Section IV.

Wisconsin. In Wisconsin, utilities are required to receive a Certificate of Authority before 

beginning any construction at their facilities, including emissions control projects. In these 

proceedings, the PSC reviews the project, including its proposed costs, although no assurances 

of cost recovery are given nor are utilities allowed to recover any costs before they are incurred. 

The length of these cases tends to vary greatly, generally depending on whether there are 

intervenors and public hearings. Cases with no intervenors can take less than a month, while 

those with intervenors and hearings often last more than a year.

 

59 Application of Appalachian Power Company requesting Commission approval of an increase in electric 

rates. Case No. PUE-2006-00065, Final Order (May 15, 2007); Application of Appalachian Power Company 

for a statutory review of the rates, terms and conditions for the provision of generation, distribution and 

transmission services pursuant to section 56-585.1 A of the Code of Virginia. Case No. PUE-2009-00030, 

Final Order (July 15, 2010).
99

APPENDIX D. DETAILS OF CASES USED IN TIMING ANALYSIS

Table I. Colorado

Owner / Power 

plant(s)

Relevant 

Case 

Numbers

Retrofits60 Approval sought Dates Time from 

application to 

approval 

(days)

PSCo / Arapahoe, 

Cherokee, 

Valmont

98A-511E Sorbent injection at 

Arapahoe 3 and 4 and 

Cherokee 1 and 2; 

FGD at Cherokee 3 

and 4 and Valmont 5. 

Cost recovery (rider 

implemented in later 

case)

Applied 11/12/1998

Approved 6/16/1999

216

PSCo / Comanche 04A-214E

04A-215E

04A-216E

FGD, advanced lowNOX technology, and 

sorbent injection at

Comanche 1 and 2

Determination of 

prudence for cost 

recovery, including 

CWIP

Applied 4/30/2004

Approved 1/21/2005

266

PSCo / Pawnee, 

Hayden

10M-245E SCR, FGD, and sorbent 

injection at Pawnee;

SCR at Hayden 1 and 

2. 

Presumption of need 

for CPCN; accrual of 

AFUDC

Applied 8/13/2010

Approved 12/15/2010

(note: docket opened 

and proceedings 

began 5/7/2010)

124

Table II. Florida

Owner / Power 

plant(s)

Relevant 

Case 

Numbers

Retrofits Approval sought Dates Time from 

application to 

approval 

(days)

Gulf Power / Crist 930613 Precipitator 

upgrades, low-NOX

burners, and over-fire 

air at Crist 6 and 7, 

flue gas conditioning 

at Crist 7

Cost recovery Applied 6/22/1993

Approved 1/12/1994

204

Florida Power & 

Light / Port 

Everglades, 

Riviera, Turkey 

Point

930661 Low-NOX burners at

Port Everglades 1-4, 

Riviera 3 and 4, and 

Turkey Point 1 and 2

Cost recovery Applied 7/7/1993

Approved 10/29/1993

114

Gulf Power / Crist 980345 Low-NOX burners at

Crist 4 and 5

Cost recovery Applied 2/12/1998

Approved 6/9/1998

117

 

60 For all tables in this section, this column includes only add-on pollution control technologies for air 

emissions (NOX, SO2, PM, and HAPs). Other environmental compliance projects (e.g., repowering, ash 

ponds, cooling towers, fuel-switching, installation of monitors) were included in some of these filings but 

not listed in the table.
100

Owner / Power 

plant(s)

Relevant 

Case 

Numbers

Retrofits Approval sought Dates Time from 

application to 

approval 

(days)

Tampa Electric 

Company / Big 

Bend

980693 FGD at Big Bend 1 

and 2 

Cost recovery Applied 5/15/1998

Finalized 4/19/1999 

(note: original decision 

- 1/11/1999 - was 

appealed)

349

Gulf Power / 

Smith

990667 Sodium injection 

system at Smith

Cost recovery Applied 5/24/1999

Approved 10/5/ 1999 

Finalized 11/23/1999

183

Tampa Electric / 

Big Bend

000685 FGD optimization at

Big Bend 1-3

Cost recovery Applied 6/2/2000

Approved 10/18/2000

Finalized 11/13/2000

164

Gulf Power / Crist 020943 Relocation of 

precipitator at Crist 7; 

SCR at Crist 7

Cost recovery Applied 8/30/2002

Approved 10/9/2002

Finalized 11/18/2002

80

Florida Power & 

Light / Manatee

020007 NOX reburn 

technology at

Manatee 1 and 2

Cost recovery Applied 9/9/2002

Approved 12/10/2002

92

Tampa Electric 

Company / Big 

Bend

030226 Separated Overfire 

Air (SOFA) at Big 

Bend 4

Cost recovery Applied 3/5/2003

Approved 6/6/2003

Finalized 7/2/2003

119

Florida Power & 

Light / Port 

Everglades

030007 ESP at Port 

Everglades 1-4

Cost recovery Applied 9/8/2003

Approved 11/25/2003

78

Tampa Electric 

Company / Big 

Bend

040750 Pre-SCR retrofits at

Big Bend 1-3, SCR at 

Big Bend 4

Cost recovery Applied 7/15/2004

Approved 10/11/2004

Finalized 11/4/2004

112

Gulf Power 

Company / Smith

040007 ESP upgrades at

Smith 2 

Cost recovery Applied 9/3/2004

Approved 12/1/2004

89

Tampa Electric 

Company / Big 

Bend

041376 SCRs on Big Bend 1-3, 

alkali injection on Big 

Bend 1-3

Cost recovery Applied 12/7/2004

Approved 5/9/2005

Finalized 6/3/2005

178

Progress Energy 

Florida / Crystal 

River, Anclote

050316 FGD and SCR on 

Crystal River 1, 2, 3

and 5; low NOX 

burners, overfire air, 

and SNCR on Anclote 

1

Eligibility of Phase I 

CAMR/CAIR 

compliance costs for 

recovery in ECRC 

Applied 5/6/2005

Approved 10/14/2005

Finalized 11/9/2005

187

Florida Power & 

Light 

050007 Initial engineering 

work for CAIR 

compliance

Cost recovery Applied 8/8/2005

Approved 12/22/2005

136

Tampa Electric 

Company / Big 

Bend

050958 FGD upgrades at Big 

Bend 1-4

Cost recovery Applied 12/27/2005

Approved 6/11/2007 

(note: original decision 

- 7/10/2006 - was 

appealed)

531
101

Owner / Power 

plant(s)

Relevant 

Case 

Numbers

Retrofits Approval sought Dates Time from 

application to 

approval 

(days)

Progress Energy 

Florida / Crystal 

River, Anclote

060007-EI FGD and SCR at

Crystal River 1 and 2, 

low NOX burners and 

overfire air burners at 

Anclote 1 and 2

Approval of 

CAMR/CAIR 

compliance plan 

(subject to yearly 

update) and inclusion 

of 2005 and 2006 costs 

for cost recovery

Applied 3/31/2006

Approved 11/22/2006

236

Florida Power & 

Light / St. Johns 

River, Scherer, 

Cape Canaveral, 

Port Everglades, 

Putnam, Turkey 

Point

060007-EI SCR at St. Johns River 

1 and 2; FGD, SCR, 

baghouse and 

sorbent injection at 

Scherer 4; low-NOX

burners and reburn 

at Cape Canaveral 1 

and 2, Port 

Everglades 3 and 4, 

and Turkey Point 

Fossil 1 and 2; water 

injection at Putnam 1 

and 2

Approval of 

CAMR/CAIR 

compliance plan 

(subject to revision) 

and inclusion of 2007 

costs for cost recovery

Applied 8/4/2006

Approved 11/22/2006

110

Gulf Power / Crist, 

Daniel, Smith, 

Scholz

060007-EI FGD at Crist and 

Daniel; SCR at Crist 6;

SNCR at Smith, Scholz 

and Daniel; low-NOX

burners at Daniel

(preliminary 

construction)

Preliminary approval of 

CAMR/CAIR 

compliance plan and 

inclusion of 2007 costs 

for cost recovery

Applied 9/1/2006

Approved 11/22/2006

82

Gulf Power / Crist, 

Daniel, Smith, 

Scholz

070007-EI FGD at Crist 4-7 and 

Daniel 1 and 2; SCR at 

Crist 6; SNCR at Smith1 

and 2 and Daniel 1 and 

2; low NOX burners at 

Daniel 1 and 2

Full approval of 

CAMR/CAIR 

compliance plan and 

costs (subject to yearly 

updates)

Applied 3/30/2007

Approved 11/16/2007

231

Gulf Power / Crist 090007-EI ESP upgrade at Crist 6 Cost recovery Applied 8/28/2009

Approved 11/18/2009

82

Gulf Power / 

Daniel

100007-EI SCRs at Daniel 1 and 

2

Inclusion in 

Compliance Program 

and cost recovery

Applied 4/1/2010

Approved 11/15/2010

228
102

Table III. Georgia

Owner / Power 

plant(s)

Relevant 

Case 

Numbers

Retrofits Approval sought Dates Time from 

application to 

approval 

(days)

Georgia Power / 

Bowen, Branch, 

Hammond, 

Scherer, Wansley, 

Yates

25060 FGD at Bowen, 

Hammond, Scherer, 

Wansley and Yates; 

SCRs at Bowen, 

Scherer, and Yates; 

and baghouses at 

Scherer. Unit-level 

data not available.

Cost recovery rider Applied 6/29/2007

Approved 12/31/2007

185

Georgia Power / 

Branch, Scherer

31958 FGD at Branch 3 and

4, Scherer 1-3; SCR at 

Branch 3, Scherer 1-3.

Cost recovery rider Applied 7/1/2010

Approved 12/29/2010

181

Table IV. Indiana

Owner / Power 

plant(s)

Relevant 

Case 

Numbers

Retrofits Approval sought Dates Time from 

application to 

approval 

(days)

PSI Energy / 

Gibson, Gallagher

41744 SCRs and boiler 

optimization at Gibson 1-

3; SCRs at Gibson 4 and 

5; SNCRs and boiler 

optimization at Gallagher 

1-4

Approval of 

qualified pollution 

control technology 

(QPCP)

Applied 5/17/2000

Approved 2/14/2001

273

Vectren / Culley, 

Warrick, Brown

41864 SCRs at F.B. Culley 3,

Warrick 4, and A.B. 

Brown 2

CPCN for clean coal 

technology (CCT), 

QPCP, rate rider

Applied 11/13/2000

Approved 8/29/2001

289

PSI Energy / 

Gallagher, Wabash, 

Cayuga, others

41744-S1 Low-NOX burners at 

Gallagher 1-4; SNCR at 

Wabash 2-6; SCR at 

Cayuga 1; boiler 

optimization for almost 

all of company’s coalfired units

QPCP Applied 8/14/2001

Approved 7/3/2002

323

42061 CPCN for CCT, 

CWIP, and 

accounting 

treatment

NIPSCO / Michigan 

City, Bailly, 

Schahfer

42150 SCR at Michigan City 12, 

Bailly 7 and 8 and 

Schahfer 14; low NOX

burners and over fired 

air at Schahfer 17 and 

18.

QPCP, CPCN for 

clean coal 

technology, cost 

recovery

Applied 1/4/2002

Approved 11/26/2002

326
103

Owner / Power 

plant(s)

Relevant 

Case 

Numbers

Retrofits Approval sought Dates Time from 

application to 

approval 

(days)

Indianapolis Power 

& Light / 

Petersburg, 

Harding Street, 

Eagle Valley

42170 SCR at Petersburg 2 and 

3 and Harding Street 7; 

SCNR at Harding Street 5 

and 6 and Eagle Valley 6; 

ROFA®/ROTAMIX® at

Eagle Valley 4 and 5; and 

Neural Network at

Petersburg 1, Harding 

Street 5 and 6, and Eagle 

Valley 6.

QPCP, CPCN for 

CCT, cost recovery

Applied 2/1/2002

Approved 11/14/2002

286

Wabash Valley 

Power Cooperative

42174 SCR on Gibson Unit 5

(note: Wabash Valley coowns with PSI; most 

determinations were 

made in cases 41744-S1 

and 42061, above) 

Permission to 

execute notes as 

evidence of 

indebtedness (for 

financing pollution 

control projects)

Applied 2/12/2002, 

2/26/2002

Cases consolidated 

3/26/2002

Approved 8/7/2002

196

42189 QPCP, CPCN, cost 

recovery, 

accounting 

treatment

PSI Energy / 

Gibson, Cayuga and 

Gallagher

42622 FGD at Gibson 1-3 and 

Cayuga 1 and 2, FGD

upgrades at Gibson 4 

and 5, combined ACIbaghouse at Gallagher 1-

4

QPCP, CPCN for 

CCT, approval of 

compliance plan, 

cost recovery, 

accounting 

treatment

Applied 4/23/2004

Approved 5/24/2006

761

Vectren / Warrick, 

Culley

42861 FGD at Warrick 1, fabric 

filter at Culley 3

QPCP, CPCN for 

CCT, cost recovery

Applied 5/16/2005

Approved 2/22/2006

282

NIPSCO / R.M. 

Schahfer

43188 Advanced low-NOX

burners and overfire air 

at Schahfer 15, FGD

upgrades at Schahfer 17 

and 18

QPCP, CPCN for 

CCT, cost recovery, 

accounting 

treatment

Applied 12/8/2006

Approved 7/3/2007

207

Indiana Michigan 

Power / Tanners 

Creek, Rockport

43636 SNCR at Tanners Creek 1-

3, ACI at Rockport 1 and 

2

QPCP, CPCN for 

CCT, cost recovery 

through rate 

adjustment 

mechanism

Applied 1/30/2009

Approved 6/30/2009

151

Duke Energy 

Indiana / Gallagher

43873 Dry Sorbent Injection at 

Gallagher 2 and 4 

CPCN and ongoing 

cost review (no cost 

recovery in this 

filing)

Applied 3/23/2010

Approved 9/8/2010

169
104

Table V. Kentucky

Owner / Power 

plant(s)

Relevant 

Case 

Numbers

Retrofits Approval sought Dates Time from 

application to 

approval 

(days)

Kentucky Utilities / 

Ghent, others

1993-

00465

FGD at Ghent 1, NOx

burner enhancements 

at all Phase I units

Approval of 

environmental 

compliance plan (ECP)

and environmental 

cost recovery (ECR)

Applied 1/20/1994

Approved 7/19/1994

180

Big Rivers Electric 

Cooperative / 

Green and Wilson; 

Henderson 

Municipal EPLS / 

Station 2

1994-

00032

FGD at Henderson 

Municipal ELPS

Station 2; FGD

improvements at 

Green and Wilson; 

low-NOX burners at all 

Phase I units

Approval of ECP and 

ECR

Applied 2/28/1994

Approved 8/31/1994

184

Louisville Gas & 

Electric / Mill 

Creek, Cane Run

1994-

00332

Improving SO2

removal systems at 

Mill Creek 1-4; ESP at 

Cane Run 4; low NOX

burners at Mill Creek 

and Cane Run

Approval of ECP and 

ECR

Applied 10/7/1994

Approved 4/6/1995

181

Kentucky Power / 

Big Sandy; Ohio 

Power / Gavin

1996-

00489

Low-NOX burners at 

Big Sandy Units 1 and 

2; FGD at Gavin

Approval of ECP and 

ECR

Applied 11/27/1996

Approved 5/27/1997

[note: low-NOX 

burners at Big Sandy 

were initially excluded 

from cost recovery, 

and this decision was 

ultimately litigated 

and reversed; case 

began 7/25/1998 and 

ended with settlement 

agreement 6/14/1999]

181

KU and LG&E/ 

Trimble, Mill 

Creek, Ghent, 

Brown

2000-

00112

SCRs at Trimble 

County 1; Mill Creek 3 

and 4; Ghent 1, 3 and 

4; and Brown 3

CPCN Applied 3/3/2000

Approved 6/22/2000

111

EKPC / Spurlock 

and Cooper

2000-

00340

SCRs at Spurlock 1 and 

2, Cooper 2

CPCN Applied 06/30/2000

Approved 11/16/2000

139
105

Owner / Power 

plant(s)

Relevant 

Case 

Numbers

Retrofits Approval sought Dates Time from 

application to 

approval 

(days)

KU / Ghent, 

Brown, Green 

River, Pineville, 

Tyrone

2000-

00439

Low-NOX burners at 

Ghent 2 and 4; SCR at 

Ghent 1, 3 and 4 and 

Brown 3; neural 

network technology, 

overfire air systems 

and burner 

modifications at 

Brown 1 and 2, Ghent 

1 and 2, Green River 

3, Pineville 3, and 

Tyrone 3.

Approval of 

amendment to ECP 

and ECR

Applied 10/20/2000

Approved 4/18/2001

180

LG&E / Trimble 

County, Mill Creek, 

Cane Run

2000-00386 SCRs at Trimble 

County 1 and Mill 

Creek 3 and 4; neural 

network technology, 

overfire air systems 

and burner 

modifications at Cane 

Run 4-6 and Mill 

Creek 1-4.

Approval of 

amendment to ECP 

and ECR

Applied 10/20/2000

Approved 4/18/2001

180

Kentucky Power / 

Big Sandy

2001-

00093

SCR at Big Sandy 2 CPCN Applied 4/6/2001

Approved 7/31/2001

116

LG&E / Mill Creek, 

Cane Run, Trimble 

County

2002-

00147

FGD improvements at

Mill Creek 1-4; ESP 

upgrades at Mill Creek 

2 and 3, Cane Run 1-3, 

and Trimble County 1 

Approval of 

amendment to ECP 

and ECR

Applied 8/12/2002

Approved 2/11/2003

183

Kentucky Power / 

Big Sandy

2002-

00169

Over-fire air with 

water injection and 

boiler tube overlays at 

Big Sandy 1; SCR and 

ESP improvements at 

Big Sandy 2.

Approval of 

amendment to ECP 

and ECR

Applied 9/30/2002

Approved 3/31/2003

182

EKPC / Spurlock, JK 

Smith

2004-

00321

SNCR, baghouse, and 

flash dry absorber at 

Spurlock’s Gilbert 

Unit; ESP at Spurlock 

1; low-NOX burners at 

JK Smith 1-7; SCRs at 

Spurlock 1 and 2

Approval of ECP and 

ECR

Applied 9/17/2004

Approved 3/17/2005

181

KU / Ghent, Brown 2004-

00426

FGD at Ghent 2-4 and 

Brown 1-3

CPCN, approval of 

amendment to ECP 

and ECR

Applied 12/20/2004

Approved 6/20/2005

182
106

Owner / Power 

plant(s)

Relevant 

Case 

Numbers

Retrofits Approval sought Dates Time from 

application to 

approval 

(days)

LG&E / Trimble 

County, Cane Run

2004-

00421

FGD refurbishment 

and improvements at 

Trimble County 1 and 

Cane Run 5 and 6.

Approval of 

amendment to ECP 

and ECR

Applied 12/20/2004

Approved 6/20/2005

182

(Kentucky Power) 

Ohio Power / 

Amos, Cardinal, 

Gavin, Kammer, 

Mitchell, 

Muskingum River, 

Phillip Sporn; I&M 

/ Rockport, 

Tanners Creek

2005-

00068

53 projects located at 

Ohio Power and I&M 

generating stations

Approval of 

amendment to ECP 

and cost recovery for 

upgrades at other 

facilities in AEP pool

Applied 3/8/2005

Approved 9/7/2005

183

EKPC / Spurlock 2005-

00417

FGD at Spurlock 2 CPCN Applied 10/7/2005

Approved 4/18/2006

193

EKPC / Spurlock 2006-

00132

FGD at Spurlock 1 CPCN Applied 3/27/2006

Approved 8/11/2006

137

KU / Ghent, 

Trimble, Brown

2006-

00206

SCR at Ghent 2; KU’s 

share of SCR, ESP and 

FGD at Trimble 2; 

sorbent injection at 

Ghent 1, 3, and 4,;

ESP upgrades at 

Brown

CPCN, approval of 

amendment to ECP 

and surcharge

Applied 6/23/2006

Approved 12/21/2006

181

LG&E / Trimble, 

Mill Creek

2006-

00208

SCR, ESP and FGD at 

Trimble 2; sorbent 

injection at Mill Creek 

3 and 4 and Trimble 1 

Amended compliance 

plan and ECR

Applied 6/23/2006

Approved 12/21/2006

181

(Kentucky Power)

Ohio Power / 

Amos, Cardinal, 

Gavin, Mitchell, 

Sporn; Indiana 

Michigan Power / 

Rockport, Tanners 

Creek

2006-

00307

44 projects located at 

Ohio Power and I&M 

generating stations

Approval of 

environmental 

compliance plan 

amendment and cost 

recovery for upgrades 

at other facilities in 

AEP pool

Applied 7/28/2006

Approved 1/24/2007

180

EKPC / Dale, 

Spurlock, Cooper

2008-

00115

Low-NOX burners at 

Dale 1-4 and Spurlock 

1; FGD at Spurlock 1 

and 2; pollution 

control facilities at 

Spurlock 4

Approval of ECP 

amendment and ECR

Applied 3/28/2008

Approved 9/29/2008

185

EKPC / Cooper 2008-

00472

FGD at Cooper 2 CPCN Applied 11/14/2008

Approved 5/1/2009

168
107

Owner / Power 

plant(s)

Relevant 

Case 

Numbers

Retrofits Approval sought Dates Time from 

application to 

approval 

(days)

KU / E.W. Brown 2009-

00197

SCR at Brown 3 CPCN, approval of 

environmental 

compliance plan 

amendment and 

surcharge

Applied: 6/26/2009

Approved: 12/23/2009

180

EKPC / Cooper, 

Spurlock

2010-

00083

FGD, SCR and fabric 

filter at Cooper 2

Approval of ECP 

amendment and ECR

Applied 3/29/2010

Approved 9/24/2010

179

Table VI. Maryland

Owner / Power 

plant(s)

Relevant 

Case 

Numbers

Retrofits Approval sought Dates Time from 

application to 

approval (days)

Constellation / 

Brandon Shores

9075 FGD, sorbent injection,

and fabric filter at 

Brandon Shores 1 and 2

CPCN Applied 8/23/2006

Approved 6/4/2007

285

Mirant / Chalk Point 9079 SCR at Chalk Point 1 CPCN Applied 10/10/2006

Approved 2/15/2007

128

Constellation / 

Wagner

9083 SNCR at Wagner 2, 

sorbent injection at 

Wagner 2 and 3

CPCN Applied 11/1/2006

Approved 5/8/2007

188

Constellation / Crane 9084 SNCR and sorbent 

injection at Crane 1 and 

2

CPCN Applied 11/2/2006

Approved 7/31/2007

271

Mirant / 

Morgantown

9085 FGD at Morgantown 1 

and 2

CPCN Applied 11/2/2006

Approved 10/22/2007

354

Mirant / Chalk Point 9086 FGD at Chalk Point 1 

and 2

CPCN Applied 11/3/2006

Approved 8/6/2007

276

Mirant / Dickerson 9087 FGD at Dickerson 1-3 CPCN Applied 11/3/2006

Approved 7/19/2007

258

Mirant / Dickerson 9140 SNCR at Dickerson 1-3 CPCN Applied 4/24/2008

Approved 10/27/2008

186
108

Table VII. Minnesota

Owner / Power 

plant(s)

Relevant 

Case 

Numbers

Retrofits Approval sought Dates Time from 

application to 

approval 

(days)

Northern States 

Power / King, High 

Bridge, Riverside

02-633 SCR, FGD and fabric 

filter at King; 

repowering to natural 

gas of High Bridge 

and Riverside, 

including NOX controls

Approval of emissions 

reduction plan and 

cost recovery rider

Applied 7/26/2002

Approved 3/8/2004

591

Minnesota Power / 

Taconite Harbor, 

Laskin

05-1678 Low-NOX burners and 

overfire air at Laskin 1 

and 2; ROFA, SNCR, 

and sorbent injection 

(Mobotec system) at 

Taconite Harbor

Approval of emissions 

reduction plan and 

cost recovery rider

Applied 10/14/2005

Approved 6/13/2006

242

Northern States 

Power / Sherco

06-1315 Preliminary work to 

develop mercury 

compliance plan; 

activated carbon 

injection on Sherco 3.

Deferred accounting 

treatment of costs, 

carrying costs on CWIP

Applied 9/15/2006

Approved 1/31/2007

138

Minnesota Power / 

Boswell

06-1501 ACI, low-NOX burners, 

overfire air, SCR, FGD, 

and fabric filter at

Boswell 3.

Approval of mercury 

emissions reduction 

plan and cost recovery 

rider, return on CWIP

Applied61 10/30/2006

Approved 10/26/2007

361

Northern States 

Power / Sherco 

and King

07-1601

07-1602

ACI at Sherco 3 and 

King.

Approval of mercury 

emissions reduction 

plan (no cost recovery 

approval)

Applied 12/21/2007

Approved 11/6/2008

321

Northern States 

Power / Sherco 

and King

09-847 ACI at Sherco 3 and 

King.

Cost recovery rider, 

return on CWIP

Applied 7/16/2009

Approved 11/4/2009

111

Northern States 

Power / Sherco

09-1456 ACI at Sherco 1 and 2. Approval of mercury

emissions reduction 

compliance plan

Applied 12/21/2009

Approved 11/4/2010

318

 

61 Plan submitted 10/30/2006; petition for approval filed 1/26/2007. If counting from the latter date, the 

process took 273 days.
109

Table VIII. Missouri

Owner / Power 

plant(s)

Relevant 

case 

numbers

Retrofits Approval sought Dates Time from 

application to 

approval 

(days)

Empire / Iatan 1 and 

Asbury

EO-2005-

0263

FGD, SCR, and 

baghouse at Iatan 1; 

SCR at Asbury

Assurance that 

environmental 

upgrade investments 

will not be excluded 

from rate base on 

the ground that they 

were not necessary 

or timely or that 

Empire should have 

used alternative 

technologies.

Applied 2/4/2005

Approved 8/2/2005

179

Aquila / Iatan 1 EO-2005-

0293

FGD, SCR, and 

baghouse at Iatan 1

Permission to 

encumber Missouri 

electric assets for the 

purposes of financing 

pollution control 

upgrades

Applied 3/2/2005

Approved 8/9/2005

160

KCP&L / Iatan 1 and 

La Cygne

EO-2005-

0329

FGD, SCR, and 

baghouse at Iatan 1 and 

La Cygne 1

Assurance that 

environmental 

upgrade investments 

will not be excluded 

from rate base on 

the ground that they 

were not necessary 

or timely or that 

KCP&L should have 

used alternative 

technologies.

Stipulation and 

agreement filed 

3/28/2005

Approved 7/28/2005

(Note: informal 

workshop process 

leading up to 

stipulation and 

agreement began 

5/6/2004 and ended 

2/18/2005)

122

Table IX. West Virginia

Owner / Power 

plant(s)

Relevant 

case 

numbers

Retrofits Approval sought Dates Time from 

application to 

approval 

(days)

Allegheny / Fort 

Martin

05-0402-ECN 

05-0750-EPC

FGD at Fort Martin CPCN, financing 

through 

environmental 

control bonds

CPCN application

3/24/2005

Financing application

5/24/2005

Approved 4/7/2006

379

Appalachian Power 

Company / 

Mountaineer, Amos

05-1278-EPC-PW-42TFGD at Mountaineer 

and Amos 1-3

Cost recovery, 

including CWIP

Applied 8/26/2005

Approved 7/26/2006

334
110

Table X. Wisconsin

Owner / Power 

plant(s)

Relevant 

Case 

Numbers

Retrofits Approval sought Dates Time from 

application to 

approval 

(days)

WPL, WPSC, and 

MG&E / Columbia 

05-CE-109 SCR at Columbia 2 Certificate of authority Applied 4/15/1999

Approved 9/22/1999

160

WEPCO / Oak 

Creek

6630-CE-274 Low-NOX burners and 

overfire air at Oak 

Creek 7 and 8

Certificate of authority Applied 4/12/2000

Approved 5/31/2000

49

WPL and WPSC / 

Edgewater

05-CE-114 Overfire air and 

combustion 

improvements at 

Edgewater 4

Certificate of authority Applied 8/15/2000

Approved 9/27/2000

43

WPL / Edgewater 6680-CE-162 Combustion 

enhancements and 

overfire air at

Edgewater 3

Certificate of authority Applied 4/30/2001

Approved 6/15/2001

46

WPL / Edgewater 05-CE-118 Low-NOX burners and 

combustion 

improvements at

Edgewater 5

Certificate of authority Applied 5/2/2001

Approved 6/15/2001

44

WPL, WPSC, and 

Madison Gas and 

Electric / Columbia

05-CE-119 Combustion 

improvements and 

separated overfire air 

at Columbia 2

Certificate of authority Applied 6/4/2001

Approved 7/3/2001 

29

NSPW / French 

Island

4220-CE-163 FGD and fabric filter 

at French Island 1 and 

2

Certificate of authority Applied 7/30/2001

Approved 8/14/2001

15

WPL, WPSC, and 

Madison Gas and 

Electric / Columbia

05-CE-129 Combustion 

enhancements and 

separated overfire air 

at Columbia 1

Certificate of authority Applied 11/14/2001 

Approved 1/31/2002

78

WPL / Nelson 

Dewey

6680-CE-163 Neural network, 

overfire air and 

combustion 

enhancements at

Dewey 2

Certificate of authority Applied 12/11/2001

Addendum 4/18/2002

Approved 5/28/2002

168

WEPCO / Presque 

Isle

6630-CE-287 TOXECON mercury 

control at Presque Isle 

7-9

Certificate of authority Applied 8/29/2003

Approved 3/12/2004

196

WEPCO / Presque 

Isle

6630-CE-290 Baghouse at Presque 

Isle 5 and 6

Certificate of authority Applied 5/26/2004

Approved 7/30/2004

65

WPL / Nelson 

Dewey

6680-CE-169 Combustion 

enhancements, 

overfire air and neural 

network at Dewey 1

Certificate of authority Applied 9/10/2004

Approved 10/20/2004

40
111

Owner / Power 

plant(s)

Relevant 

Case 

Numbers

Retrofits Approval sought Dates Time from 

application to 

approval 

(days)

WPSC / Weston 6690-CE-190 Overfire air and 

combustion 

modifications at

Weston 3

Certificate of authority Applied 5/27/2005

Approved 8/31/2005

96

WEPCO / Valley 

Power Plant

6630-CE-297 Low-NOX burners and 

overfire air at Valley 1 

and 2

Certificate of authority Applied 5/3/2007

Approved 7/23/2007

81

WEPCO / Oak 

Creek Power Plant

6630-CE-299 FGD and SCR on Oak 

Creek 5-8.

Certificate of authority Applied 6/21/2007

Approved 7/10/2008

385

WPSC / Weston 6690-CE-195 Separated overfire air 

and low NOX burners 

at Weston 1 and 2

Certificate of authority Applied 10/19/2007

Approved 12/13/2007

55

WPSC / Pulliam 6690-CE-196 Separated overfire air 

and low NOX burners 

at Pulliam 5-8

Certificate of authority Applied 10/19/2007

Approved 12/13/2007

55

NSPW / Bay Front 4220-CE-167 Separated overfire air 

and combustion 

enhancements at Bay 

Front 1 and 2

Certificate of authority Applied 2/15/2008

Approved 3/13/2008

27

WEPCO and WPL / 

Edgewater

05-CE-137 SCR on Edgewater 5 Certificate of authority Applied 11/14/2008

Approved 5/27/2010

559
112

APPENDIX E. INTERVENORS IN COLORADO CASE STUDY

Intervenor Name Rationale for Intervenor Status (June 2010)

American Coalition for 

Clean Coal Electricity 

(ACCCE)

ACCCE advocates for new advanced coal technologies. Members include 

coal producers in Colorado and railroad companies that transport coal. 

These companies feel they will be impacted twice by switching to natural 

gas, both through loss of revenues and higher operating costs.

Anadarko Energy Services Buys and sells natural gas. Is an affiliate of Anadarko Petroleum Company 

which produces natural gas for Anadarko Energy Services. Anadarko is 

listed as winning a long-term gas contract with PSCo, which is part of the 

filing PSCo submitted for PUC approval.

Associated Governments 

of CO

Mesa, Garfield, Rio Blanco, Moffat, and Routt Counties contain 63 

percent of the 2,392 coal mining jobs in the State. Average pay is 

$102,077, thus representing a significant portion of tax revenues.

Citizens

City of Boulder, CO PSCo’s Valmont Station is located within the city limits, and the City is 

concerned about air quality and GHG contributions.

City of Denver Ozone nonattainment area; believes that Denver citizens are adversely 

impacted by pollution from Cherokee Station in residential areas.

Climax Molybdenum 

Company with CF&I Steel 

and Evraz Rocky 

Mountain Steel

These companies are large power consumers. Climax is the second 

largest retail electric consumer in the PSCo service area. They are 

concerned about rate increases and potential reliability disruptions.

CO Department of Health Advocates on behalf of public health for the citizens of Colorado.

CO Governors Energy 

Office

Concerned that the Emission Reduction Plan did not follow the spirit of 

the CACJ Act.

CO Interstate Gas Co. 

(CIG)

Owns and operates interstate transmission system for natural gas 

pipeline. Also transports gas from production areas to consumption 

zones.

CO Solar Energy 

Industries

Nonprofit group representing solar energy industries.

Colorado Department of 

Public Health and 

Environment (CDPHE)

Main reviewer of whether the PSCo emission reduction plan satisfies the 

requirements of the CACJ and reasonably foreseeable requirements. 

CACJ also specifies consultations between CDPHE and PSCo.

Colorado Energy 

Consumers

Group of energy consumers concerned about rate increases.

Colorado Independent 

Energy Association (CIEA)

Colorado Mining 

Association (CMA)

CMA is a trade association representing over 900 members including coal 

producers who sell coal to PSCo for Cherokee, Hayden, and Valmont 

stations. Over 2.5 million tons of coal was sold to PSCo’s affected plants 

in 2009.

Colorado Office of 

Consumer Counsel 

(COO)

Advocates on behalf of electricity ratepayers.
113

Intervenor Name Rationale for Intervenor Status (June 2010)

Colorado Oil & Gas 

Association

Trade association looking to expand gas in the Rocky Mountains. States 

that natural gas is one of company’s leading creators of jobs and tax 

revenues, with over 137,000 jobs in Colorado.

Colorado Springs Utilities, 

Tri-State Generation, 

Transmission

Purchasers of wholesale power, they are concerned about future rate 

increases. No mention of existing contracts. They specifically mention 

Craig and Nuca stations, which are not affected by PSCo’s compliance 

plan.

Federal Executive 

Agencies (FEA)

Advocates on behalf of Federal Agencies (not as a representative of the 

U.S. Government). The FEA here represents the Buckley Air Force Base in 

Aurora, CO. FEA is concerned about potential rate increases as it is a 

large power consumer.

Holy Cross Electric 

Association

Public utility, deregulated from Commission rate jurisdiction. Purchases a 

substantial portion of wholesale power from PSCo, via long-term 

contracts which are in place and could be impacted by rate increases as a 

result of the compliance plan.

Intermountain Rural 

Electric (IREA)

Electric association of utilities (deregulated from rates). IREA purchases 

power from PSCo.

Interwest Energy Alliance Trade association for renewable energy sources; supports the use of wind 

and solar generation to replace coal.

Noble Energy, 

Chesapeake, and Encana 

“Gas intervenors”

Noble owns gas plays and sells natural gas. Chesapeake is one of the 

largest producers of natural gas, and Encana delivers gas production and 

has gas plays in Colorado. The Gas intervenors would like to see more gas 

used in Colorado.

Peabody Energy 

Corporation

Corporation whose main businesses include the mining and selling of 

coal. Estimated assets of 196 million tons of coal are mined in Colorado. 

Peabody operates Twentymile mine, near Oak Creek, Colorado. Peabody 

sold 7.8 million tons of coal mined from the Twentymile Mine to PSCo in 

2009, going to Cherokee, Valmont, and Arapahoe plants. They have over 

500 personnel. The coal is low-sulfur. Long-term contracts are in place 

with PSCo that could be disturbed by premature retirements of coal-fired 

boilers. 

School District #1 School District, concerned about children’s health and clean air.

Southwest Generation An IPP that owns gas generation in the area (450 MW) and has power 

purchase agreements with PSCo through 2012.

Thermo Power & Electric 

LLS

Sells power to PSCo from Greenly, a 72 MW natural gas plant. Advocates 

to be part of the solution in the compliance plan.

Walmart and Sam’s West Owns 45 facilities in the PSCo service area, and is a large commercial 

retail customer of PSCo, using about 150 million kWh/yr. Increased 

electricity rates would “dramatically impact Walmart operating costs.”

Weld County, CO County Commissioners of Weld County. The county holds deposits of 

natural gas and is in support of using more gas to fuel the state. 

Western Fuels & 

Colorado Rural Electric 

Association (CREA)

Western Fuels/CREA purchases wholesale power from PSCo and operates 

New Horizon coalmine, which delivers coal to PSCo.

Western Resource 

Advocates

NGO supporting gains in environmental protection.
114

APPENDIX F. RELEVANT ARTICLES

Greenwire. E-Mails Showing Possible Illicit Talks Are the Latest in Duke Scandal. E&E Publishing, 

LLC. March 9, 2011. http://www.eenews.net/Greenwire/2011/03/09/19/.

Greenwire. Top Duke Executive Resigns over E-mail Scandal. E&E Publishing, LLC. December 7, 

2010. http://www.eenews.net/Greenwire/2010/12/07/8/.

John Blair. Daniels Acts To Save Face In Utility Regulation Scandal. Valley Watch. October 6 

2010. http://valleywatch.net/?p=1027.
115

GLOSSARY 

AAC – Automatic Adjustment Clause

ACCCE – American Coalition for Clean Coal Electricity

ACI – Activated carbon injection

AEP – American Electric Power Company

AFUDC – Allowance for Funds Used During Construction

APCo – Appalachian Power Company

CAC – Citizen’s Action coalition

CACJ – Colorado Clean Air-Clean Jobs Act

CAD – Consumer Advocacy Division

CAIR – Clean Air Interstate Rule

CAMR – Clean Air Mercury Rule

CDPHE – Colorado Department of Public Health and Environment

CEM – Continuous Emissions Monitor

CIEA - Colorado Independent Energy Association

CMA – Colorado Mining Association

CO2 – Carbon dioxide

CPCN – Certificate of Public Convenience and Necessity

CPSG – Constellation Power Source Generation, Inc.

CRS – Colorado Revised Statutes

CWIP – Construction Work in Progress

ECB – Environmental Control Bond

ECCR – Environmental Compliance Cost Rider

ECP – Environmental Compliance Plan

ECR – Environmental Cost Recovery
116

ECRC – Environmental Cost Recovery Clause

EEI – Edison Electric Institute

EPA – Environmental Protection Agency

EPAct – Energy Policy Act

ERA – Emissions Reduction Adjustment

ESP – Electrostatic Precipitator

FCC – Federal Communications Commission

FEA – Federal Executive Agencies

FERC – Federal Energy Regulatory commission

FGD – Flue Gas Desulfurization

FP&L – Florida Power & Light

FRCC – Florida Reliability Coordinating Council

GAO – Government Accounting Offices

GBRA – Generation Base Rate Adjustment

GIG – Georgia Industrial Group

GTMA – Georgia Traditional Manufacturers Association

HAA – Healthy Air Act

IRP – Integrated Resource Plan

IPPs – Independent Power Producers

ISO – Independent System Operator

IURC – Indiana Utility Regulatory Commission

KCP&L – Kansas City Power & Light

kWh – Kilowatt-hour

kW – Kilowatt

MACT – Maximum Achievable Control Technology
117

MDE – Maryland Department of the Environment

MDPSC – Maryland Public Service Commission

MISO – Midwest Independent System Operator

MJB&A – M.J. Bradley & Associates

MW – Megawatt

NAAQS – National Ambient Air Quality Standards (NAAQS)

NARUC – National Association of Regulatory Utility Commissioners

NASUCA – National Association of State Utility consumer Advocates

NERC – North American Reliability Corporation

NESHAP – National Emission Standards for Hazardous Air Pollutants

NOX– Nitrogen oxides

NSPS – New Source Performance Standards

NSR – New Source Review

O&M – Operations and Maintenance

OCC – Office of Consumer Counsel

OUCC – Office of Utility consumer Counselor

PAC – Powder Activated Carbon

PJM – PJM Interconnection, LLC

PPRP – Power Plant Research Program

PSCo – Public Service Company of Colorado

PSC – Public Service Commission

PSD – Prevention of Significant Deterioration

PSI – PSI Energy, Inc.

PUC – Public Utility Commission

PURPA – Public Utility Regulatory Policies Act
118

QPCP – Qualified Pollution Control Property

RGGI – Regional Greenhouse Gas Initiative

ROFA – Rotating Overfire Air

RPS – Renewable Portfolio Standard

RRR – Application for Rehearing, Reargument, or Reconsideration 

RTO – Regional Transmission Organization

SCC – State Corporation Commission

SCR – Selective Catalytic Reduction

SERC – Southeastern Electric Reliability Council

SNCR – Selective Non-Catalytic Reduction

SO2 – Sulfur dioxide

VOCs – Volatile Organic Carbons

WECC – Western Electricity coordinating Council

WRA – Western Resource Advocates