DRAFT 111(d) Design Comments

(working draft)

This is a draft whitepaper that attempts to summarize the most challenging 

issues and explore possible approaches to “design” of the to-be-proposed 

“existing source” GHG/ CO2 rule that is scheduled to be issued on June 1, 2014.

Date: December __, 2013

DRAFT whitepaper

• Introduction

Thank you for this opportunity to comment on the “design” for the proposed rule 

scheduled to be promulgated by June 1, 2014, regarding the standards of performance 

for greenhouse gas (GHG) emissions (primarily, if not exclusively, for carbon dioxide 

(CO2) GHG emissions) from existing electric generation sources under Clean Air Act 

(CAA) § 111(d).

President Obama’s June 25, 2013, presidential order requires EPA Administrator 

McCarthy to initiate “...direct engagement with States, as they will play a central role in 

establishing and implementing standards for existing power plants, and ...leaders in the 

power sector ... [and] non-governmental organizations [NGOs], ... on issues informing 

the design of the program” for regulating CO2 from existing electric generating units 

(EGUs). (Emphasis supplied.) 

Even though CAA § 111(d) was part of the original 1970 CAA amendments, this is the 

first major national rulemaking initiated under § 111(d). It is a good idea to do this 

unusual pre-proposed-rule step to solicit public comment on the underlying “design” of 
the rule for several reasons:

• The legal and technical issues are challenging and complex, and address 

national and global issues of environmental concern. Even though the primary 

law in question was part of the original 1970 Clean Air Act (CAA) Amendments, 

there are really no meaningful or relevant judicial or agency interpretations of 

either § 111(d), or its implementing rules (40 C.F.R. §§ 60.20-60.29), that provide 

precedent or shed light on its meaning, or how it should be applied to this issue. 

• Further, until the commencement of this rulemaking, the implementing rules have 

not been meaningfully updated since the rulemaking at 40 Fed. Reg. 53340 

(November 17, 1975), in spite of significant amendments to the language of § 

111(d) and § 111(a)(1) (the definition of “standard of performance”) under the 

1977 and the1990 CAA Amendments. 

Because of the national and international importance of this rulemaking and the issues it 

addresses, as well as the lack of meaningful precedent, this unusual initial public 

comment opportunity on the design, scope, and structure of this rule constitutes a wise 

public policy choice that is consistent with the notice and comment structure of CAA 

rulemaking requirements and its underlying administrative and constitutional law.

These comments will be divided into four categories:

• Comments on the legal and technical design of the rulemaking consistent with 

the structure set forth in § 111;

• Comments regarding the different kinds of issues facing regions, states, 

companies, and sources experiencing increasing demand and electricity load 

growth, stable demand but not electricity load growth, and decreasing demand 

and diminishing electricity loads; 

• Comments on EPA’s September 23, 2013 questions asked in “Considerations in 

the Design of a Program to Reduce Carbon Pollution from Existing Power 

Plants”; and

• How cooperative federalism should be designed to work under§ 111.

• Legal Issues that this whitepaper does not take a position on in this preproposed-rule stage of the rulemaking, and which are reserved for a later 

date

• Granting of Certiorari Petition in Utility Air Regulatory Group v. E.P.A.

On October 15, 2013, Utility Air Regulatory Group v. E.P.A, the United States Supreme 

Court consolidated six certiorari petitions and granted certiorari on this specific issue:

“Whether EPA permissibly determined that its regulation of greenhouse gas 

emissions from new motor vehicles triggered permitting requirements under the 

Clean Air Act for stationary sources that emit greenhouse gases.”

At the same time, the Supreme Court rejected related certiorari petitions to review 

EPA's findings that GHGs endanger public health and welfare, EPA’s tailpipe GHG 

rules, and EPA’s rule to "tailor" the statutory permit thresholds for when a facility 

needs a PSD permit. Those issues are now resolved issues of law. 

The author has not yet determined its position in regard to the issue for which 

certiorari has been granted in Utility Air Regulatory Group v. E.P.A. In making these 
At the same time, the Supreme Court rejected related certiorari petitions to review 

EPA's findings that GHGs endanger public health and welfare, EPA’s tailpipe GHG 

rules, and EPA’s rule to "tailor" the statutory permit thresholds for when a facility 

needs a PSD permit. Those issues are now resolved issues of law. 

The author has not yet determined its position in regard to the issue for which 

certiorari has been granted in Utility Air Regulatory Group v. E.P.A. In making these 

comments, the author does not waive, and reserves its right to modify, its comments 

based on and in response to the Supreme Court’s ultimate decision in Utility Air 

Regulatory Group v. E.P.A.

• The different House and Senate provisions of § 111(d) that were 

both enacted into law under the 1990 Clean Air Act Amendments 

The 1990 CAA Amendments made two separate amendments to the same language 

in § 111(d), both of which were included in the final bill that was signed by the 

President. In its “Revision of December 2000 Regulatory Finding on the Emissions of 

Hazardous Air Pollutants From Electric Utility Steam Generating Units and the 

Removal of Coal- and Oil-Fired Electric Utility Steam Generating Units From the 

Section 112(c) List,” EPA summarized the legislative history of this amendment as 

follows:

The first amendment, which is the House amendment, is contained in section 

108(g) of Public Law 101-549. That section amends section 111(d)(1)(A)(i) of 

the 1977 CAA by striking the words “or 112(b)(1)(A)” from the 1977 CAA and 

inserting in its place the following phrase: “or emitted from a source category 

which is regulated under section 112.” The second amendment to section 

111(d), which is the Senate amendment, is labeled a “conforming amendment” 

and is set forth in section 302 of Public Law 101-549. That section amends 

CAA section 111(d)(1) of the 1977 CAA by striking the reference to “112(b)(1)

(A)” and inserting in its place “112(b).” The two amendments are reflected in 

parentheses in the Statutes at Large as follows:

The Administrator shall prescribe regulations which shall establish a 

procedure similar to that provided by section 7410 of this title under 

which each State shall submit to the Administrator a plan which (A) 

establishes standards of performance for any existing source for any air 

pollutant (i) for which air quality criteria have not been issued or which is 

not included on a list published under section 7408(a) (or emitted from a 

source category which is regulated under section 112) [House 

amendment,] (or 112(b)) [Senate Amendment,] but (ii) to which a 

standard of performance under this section would apply if such existing 

source were a new source. * * *

EPA made the following interpretation of the above “two amendments” language of § 

111(d) in the “delisting rule”:

[I]n an effort to give some effect to both amendments, we reasonably interpret 

the amendments as follows: Where a source category is being regulated under 

section 112, a section 111(d) standard of performance cannot be established to 

address any HAP listed under section 112(b) that may be emitted from that 

particular source category. Thus, if EPA is regulating source category X under 

section 112, section 111(d) could not be used to regulate any HAP emissions 

from that particular source category. This is a reasonable interpretation of the 

amendments to section 111(d) because it gives some effect to both 

amendmentsFirstit gives effect to the Senate's desire to focus on HAP listed 
g pgg§ 

111(d) in the “delisting rule”:

[I]n an effort to give some effect to both amendments, we reasonably interpret 

the amendments as follows: Where a source category is being regulated under 

section 112, a section 111(d) standard of performance cannot be established to 

address any HAP listed under section 112(b) that may be emitted from that 

particular source category. Thus, if EPA is regulating source category X under 

section 112, section 111(d) could not be used to regulate any HAP emissions 

from that particular source category. This is a reasonable interpretation of the 

amendments to section 111(d) because it gives some effect to both 

amendments. First, it gives effect to the Senate's desire to focus on HAP listed 

under section 112(b), rather than applying the section 111(d) exclusion to nonHAP emitted from a source category regulated under section 112, which a 

literal reading of the House amendment would do. Second, it gives effect to the 

House's desire to increase the scope of EPA's authority under section 111(d) 

and to avoid duplicative regulation of HAP for a particular source category. See 

136 Cong. Rec. H12911, 12934 (daily ed. Oct. 26, 1990) (the conferees 

adopted section 112(n)(1)(A) “because of the logic of basing any decision to 

regulate on the results of scientific study and because of the emission 

reductions that will be achieved and the extremely high costs that electric 

utilities will face under other provisions of the new Clean Air Act 

amendments.”).

In dicta the court of appeals in New Jersey v. EPA stated that is was EPA’s view that § 

111(d) “cannot be used to regulate sources listed under section 112.” The above 

language from the “delisting rule,” however, suggests that EPA’s view of the “two 

amendments” language as advanced in that case may not be the position stated by 

the court of appeals in dicta at the end of New Jersey v. EPA, but rather may be EPA’s 

position as stated in the preamble to the “delisting rule” quoted above. This is a close 

enough legal issue that no one can predict with certainty how courts will ultimately 

decide this unique issue of statutory construction.

The author has not yet determined its/his/her legal position in regard to this “two 

amendments” issue outlined above, although this issue may become a key contested 

legal issue in any legal challenge to this rulemaking. The author will wait to see what 

EPA proposes in this rulemaking before taking a legal position on this issue. But 

among the factors the author will weigh in determining its/his/her position on this issue 

after the rule is proposed are the following factors related to how this provision is 

interpreted in the context of § 111 and the CAA interpreted as a whole pursuant to the 

well-established rules of statutory construction:

• Will EPA’s position as proposed in this rulemaking in June 2014 be consistent 

with its interpretation in the “delisting rule”?

• Will the rulemaking respect the “separation of powers” built into the 

“cooperative federalism” provisions of the CAA in general, and into § 111(d) in 

particular, by allowing states to 1) exercise their discretion to set standards of 

performance on a source-by-source basis if they so choose, 2) to determine 

“remaining useful life” of each unit based on consideration of established 

engineering and accounting principles that go to the issue of remaining useful 

life, and 3) to consider the five factors set forth in the definition of “standard of 

performance” at § 111(a)(1) in setting source-by-source standards of 

performance consistent with EPA’s “regulations” and guidelines?

• Comments on the legal and technical design of the rulemaking to make it 

consistent with the structure set forth in § 111.

• Legal design
“remaining useful life” of each unit based on consideration of established 

engineering and accounting principles that go to the issue of remaining useful 

life, and 3) to consider the five factors set forth in the definition of “standard of 

performance” at § 111(a)(1) in setting source-by-source standards of 

performance consistent with EPA’s “regulations” and guidelines?

• Comments on the legal and technical design of the rulemaking to make it 

consistent with the structure set forth in § 111.

• Legal design

The options that are available for design of the GHG existing source rulemaking are 

dependent on the options that the language of § 111(d) sets forth. This section will discuss 

some of the key language and history of § 111, and what its legal structure may and may not 

allow relating to design.

• Cooperative federalism

The Clean Air Act is neither a pure federal top down nor a pure state bottom up law. “A 

primary goal” of the Clean Air Act “is to encourage or otherwise promote reasonable 

Federal, State, and local governmental actions ... for pollution prevention.” “Federal 

financial assistance and leadership is essential for the development of cooperative 

Federal, State, regional, and local programs to prevent and control air pollution.” But 

CAA § 101 makes clear that “air pollution control at its source is the primary 

responsibility of States and local governments.” “This ‘cooperative federalism’ structure 

is a defining feature” of the Clean Air Act.

• CAA § 111(d)(1) is unique under the Clean Air Act because 

States, not the EPA Administrator, set the standards of 

performance for each existing source under the State’s “plan,” 

rather than EPA setting a single national standard of 

performance as under § 111(b)

Under every other major provision of the Act but § 111(d), “[t]he Clean Air Act authorizes 

the Environmental Protection Agency ... to establish air quality standards and 

empowers the states to achieve those standards.”

Under § 111(d)(1), however, States, not EPA, set the “standards of performance” in 

each State plan. The EPA Administrator’s role is to “prescribe regulations which shall 

establish a procedure” (emphasis supplied) “under which each State shall submit to the 

Administrator a plan ... which establishes standards of performance for any existing 

source for any air pollutant,” which pollutant, essentially, 1) has not been regulated as a 

criteria pollutant under CAA § 108(a) or CAA § 112, but 2) for which the Administrator 

has made an endangerment finding and established a “new source” standard of 

performance under § 111(b).

From the very beginning, the “new source” performance standard under CAA § 111(b) & 

(c) of the 1970 CAA amendments established a requirement for uniform Federal 

standards of performance for new sources falling within categories of sources listed by 

the EPA Administrator, and preempted State authority to set such standards for new

sources, while allowing the State to implement and enforce such standards, provided 

the State establishes an adequate procedure for doing so.
But CAA § 111(d) of the 1970 CAA amendments did not preempt State authority to set 

emission standards for “existing sources”; rather, CAA § 111(d) of the 1970 CAA 

amendments reversed for existing sources the roles played by EPA and the States for 

new sources. Under CAA § 111(d)(1) of the 1970 CAA amendments, as noted above, 

the EPA Administrator is mandated to develop regulations “which shall establish a 

procedure” under which the State must develop a plan (similar to a state implementation 

plan under CAA § 110) which “establishes emission standards for any existing source 

for any air pollutant” which falls into the category of pollutants and sources identified in 

CAA § 111(d)(1)(A)(i & ii). 

As discussed below, the 1977 CAA Amendments changed the authority for what States 

may establish under § 111(d) from “emission standards” to “standards of performance.”

Thus, § 111(d) currently provides that “States,” not EPA, should set the “standards of 

performance” for “existing sources” consistent with the “cooperative federalism” division 

of authority between EPA and the States. Under § 101(a)(3), “air pollution control at its 

source is the primary responsibility of States and local governments.” Under 111(d) 

States set a “standard of performance” for each source under each state plan, rather 

than EPA setting a single national standard that applies to all new sources per the 

language of § 111(b). Since the “existing source” standard is a “source” standard, not a 

national standard, Congress assigned this responsibility to States as part of their 

obligation to address “air pollution control at its source.” 

In sum, CAA § 111 of the 1970 CAA amendments assigned different and contrasting 

roles to the EPA Administrator and the States for establishing emission standards for 

new sources compared to existing sources. For new sources, CAA § 111(b) preempts 

State authority to establish emission standards, and instead establishes uniform Federal 

standards of performance for new sources within the relevant category of sources. CAA 

§ 111(c) allows States to implement and enforce such standards, provided the State 

establishes an adequate procedure for doing so, but the State has no authority or 

discretion to set standards of performance for new sources. 

In contrast, under the 1970 CAA § 111(d), the EPA Administrator established the 

procedure by which States set emission standards for existing sources, and the States 

then establish those emission standards under separate individual State plans which 

are submitted to the EPA Administrator in a way that is “similar” to the way plans are 

submitted under CAA § 110. The responsibility of the State to set the emission 

standards for existing sources was not preempted under CAA § 111(d), as it was for 

new sources under CAA § 111(b). Rather, State authority to set emission standards 

was reaffirmed under CAA § 111(d), provided that the procedure for establishing those 

emission standards is followed, and the plan is submitted in accordance with that 

procedure.

Nothing in any of the subsequent amendments to CAA § 111 has preempted State 

authority to set emission standards for existing sources, or changed the basic structure 

or procedure that applies for States to set such emission limitations for existing sources. 

Although the 1977 and 1990 CAA amendments added to and changed CAA § 111(d) 
(e.g., substituted “standards of performance” for “emission standards”), and the 

definition of “standard of performance” under CAA § 111(a)(1) has changed, those 

changes have re-enforced, rather than weakened, State authority under CAA § 111(d). 

Any regulation of GHGs from existing sources under CAA § 111(d) must respect the 

States’ primacy to set emission standards (now “standards of performance” under the 

1977 CAA amendments as explained below) for existing sources subject to the 

procedure established by the EPA Administrator and the EPA Administrator’s review of 

the final State plan under a process similar to the process set forth in CAA § 110. 

This means that the EPA Administrator does not have authority to set a single national 

emission rate or standard under § 111(d) as suggested by some NGOs for the design of 

this rulemaking. Rather, as the plural “standards” language in § 111(d) makes clear, 

under § 111(d) it is States that set “standards of performance” under the “plan” they 

submit to the Administrator: the Administrator does not set those standards. Any legal 

design that does not follow this clear and unambiguous reversal of roles under the CAA 

fails to comply with the plain language of § 111(d)(1).

• The 1977 Amendments to § 111(d)(1) changed the authority of 

States from requiring them to set “emission standards” to 

requiring them to set “standards of performance”—a change 

that gives both the Administrator and States much more 

flexibility in the kinds of standards that can be set, since the 

definition of “standard of performance” is much broader and 

more flexible than the term “emission standards” 

The 1977 amendments to CAA § 111(d) made the following changes to the language of 

§ 111(d):

 (b)(1) Section 111(d)(1) of such Act // 42 USC 7411. // is 

amended by striking out “emissions standards” in each place 

it appears and inserting in lieu thereof “standards of 

performance” and by adding at the end thereof the following 

new sentence: ” Regulations of the administrator under this 

paragraph shall permit the State in applying a standard of 

performance to any particular source under a plan submitted 

under this paragraph to take into consideration, among other 

factors, the remaining useful life of the existing source to 

which such standard applies.”.

1977 CAA § 111(d) [42 U.S.C.A. § 7411(d)]. 

The HOUSE REPORT NO. 95-294 of the 1977 CAA Legislative History explains the 

reasons for these changes:

Clarification of Section 111(d)

This section is also intended to clarify the basis for standard-
setting for existing sources under section 111(d) of the Act. 

Under the committee bill, the standards in the section 111(d) 

State plan would be based on the best available means (not 

necessarily technological) for categories of existing sources 

to reduce emissions. The Administrator would establish 

guidelines as to what the best system for each such 

category of existing sources is. However, the State would be 

responsible for determining the applicability of such 

guidelines to any particular source or sources. The 

Administrator's guidelines must take into account the 

remaining useful life of existing sources. Unless the State 

decides to adopt and enforce more stringent standards, the 

State plan would be expected to take into account the 

remaining useful life of the source (or sources).

The definition of “standard of performance” at § 111(a)(1) is much broader and more 

flexible than the term “emission standards.” If EPA is to design its rules to have the 

“flexibility” required in the President’s June 25th order, EPA should design the rule to be 

for “standards of performance,” rather than “emission standards.” As noted next, EPA 

has failed to amend its rules implementing § 111(d)(1) to reflect the change in the 

standard from being an emission standard to a standard of performance. Further, EPA 

has failed to adopt in its rules the guidelines that take into account the remaining useful 

life of existing sources and “other factors.” These oversights should be corrected in the 

design of the new rule in this rulemaking.

• Failure of the implementing rule to change its provisions from 

“emission standards” under the 1970 CAA Amendments to 

“standard of performance” under the 1977 Amendments or to 

establish a guideline to address “remaining useful life” or 

“”other factors” in the rule.

The implementing rules for § 111(d), 40 C.F.R. §§ 60.20-60.29, have not been 

meaningfully updated since the rulemaking at 40 Fed. Reg. 53340 (November 17, 

1975). A review of the rule shows that 40 C.F.R. §§ 60.20-60.29 does not follow the 

requirements of §§ 111(a) or 111(d). Here are several examples:

• The language of 40 C.F.R. § 60.21(c) refers to the pre-1977 language of 111(d) 

noted above, which required States to set “emission standards” under 111(d), 

rather than “standards of performance.”

• The language of 40 C.F.R. § 60.21(e) is based on the narrower 1970 definition of 

“standard of performance,” rather than the current 111(a)(1) definition of 

“standard of performance,” or even the 1977 CAA Amendment definition of 

“standard of performance.” Further, it should be a “standard of performance” 

guideline, not an emission guideline.

• 40 C.F.R. § 60.22(b)(5) should be a “standard of performance” guideline, rather 

than an emission guideline, and the remainder of (b)(5) should be updated to 
reflect the current definition of “standard of performance” at § 111(a)(1), rather 

than the 1970 Amendment version upon which § 60.22(b)(5) is based.

• Every instance of “emission standards” in 40 C.F.R. § 60.24 should be replaced 

with “standard of performance” to reflect the 1977 change to § 111(d).

• Again, every instance of “emission standards” in 40 C.F.R. § 60.25 should be 

replaced with “standard of performance” to reflect the 1977 change to § 111(d).

• Again, every instance of “emission standards” in 40 C.F.R. § 60.26 should be 

replaced with “standard of performance” to reflect the 1977 change to § 111(d).

• Again, every instance of “emission standards” in 40 C.F.R. § 60.27 should be 

replaced with “standard of performance” to reflect the 1977 change to § 111(d). 

Further, the stringency of the requirements in 40 C.F.R. § 60.27 are inconsistent 

with States’ authority to consider “remaining useful life” and “other factors” under 

the second sentence added by the 1977 CAA Amendments to § 111(d). The 

“other factors” would include the five factors that the definition of “standard of 

performance” allows to be considered (e.g., “the cost of achieving such reduction 

and any nonair quality health and environmental impact and energy 

requirements”).

• Again, every instance of “emission standards” in 40 C.F.R. § 60.28 should be 

replaced with “standard of performance” to reflect the 1977 change to § 111(d). 

And, once again, the stringency of the requirements in 40 C.F.R. § 60.28 are 

inconsistent with States’ authority to consider “remaining useful life” and “other 

factors” under the second sentence added by the 1977 CAA Amendments to § 

111(d).

Finally, no provision of 40 C.F.R. §§ 60.20-60.29 permits the State to consider 

“remaining useful life” or “other factors” such as those contained in the definition of 

“standard of performance” when it establishes “standards of performance” for “any 

existing source” under its plan. The second sentence of 111(d) makes it mandatory that 

the “[r]egulations” allow States to consider these factors. That sentence provides:

Regulations of the Administrator under this paragraph shall permit the State in 

applying a standard of performance to any particular source under a plan 

submitted under this paragraph to take into consideration, among other factors, 

the remaining useful life of the existing source to which such standard applies.

Because it is mandatory under § 111(d)(1) that the “[r]egulations of the Administrator ... 

shall permit the State in applying a standard of performance to any particular source 

under a plan submitted under this paragraph to take into consideration, among other 

factors, the remaining useful life of the existing source to which such standard applies,” 

the failure to include those factors in the design of the regulations in this rulemaking will 

make those regulations legally deficient. As the 1977 Act’s legislative history makes 

clear, “[t]he Administrator's guidelines must take into account the remaining useful life of 

existing sources. Unless the State decides to adopt and enforce more stringent 

standards, the State plan would be expected to take into account the remaining useful 

life of the source (or sources).”

Since “remaining useful life” is a term of art in engineering, accounting, and tax law and 
regulations, the author suggests that EPA look to those established meanings in 

establishing guidelines for States to consider when determining remaining useful life of 

existing sources.

• Change of “best system of continuous emission reduction” to 

“best system of emission reduction”

The 1977 CAA Amendment definition of “standard of performance” provided for “the 

application of the best system of continuous emission reduction” rather than “the 

application of the best system of emission reduction” as provided under the current 

1990 amendment definition. 

As noted previously, the 1977 Act’s legislative history provides that “the standards in the 

section 111(d) State plan would be based on the best available means (not necessarily 

technological) for categories of existing sources to reduce emissions. The Administrator 

would establish guidelines as to what the best system for each such category of existing 

sources is. However, the State would be responsible for determining the applicability of 

such guidelines to any particular source or sources.” The removal of the word 

“continuous” in the 1990 Act’s amendments makes it even clearer that the best available 

means for reducing emissions is “not necessarily technological.” 

• The five categories of “other factors” in the definition of 

“standard of performance”

The definition of “standard of performance” provides for the consideration of the 

following factors:

The term “standard of performance” means 

• a standard for emissions of air pollutants 

• which reflects the degree of emission limitation achievable 

• through the application of the best system of emission reduction which 

• (taking into account the cost of achieving such reduction and any nonair 

quality health and environmental impact and energy requirements) 

• the Administrator determines has been adequately demonstrated.

The last phrase—“the Administrator determines has been adequately demonstrated”—

appears to refer back to “through the application of the best system of emission 

reduction.” This is, again, confirmed in the statement of legislative intent for 111(d) in 

the 1977 Act, which provides: 

The Administrator would establish guidelines as to what the best system for each 

such category of existing sources is. However, the State would be responsible for 

determining the applicability of such guidelines to any particular source or 

sources. 

This is further confirmed by considering other related 1977 CAA Amendments. The 

definition under CAA § 169(3) of “best available control technology” or BACT enacted 
under the 1977 Act allows a State to “tak[e] into account energy, environmental, and 

economic impacts and other costs” in determining BACT. 

Likewise, the definition under CAA § 169A of “best available retrofit technology” or 

BART enacted under the 1977 Act also allows a State to “take into consideration the 

costs of compliance, the energy and non-air quality environmental impacts of 

compliance,” as well as “remaining useful life of the source” (among other factors) in 

determining BART. 

Construing all of these 1977 Act provisions and history together, as well as the “other 

factors” language in the second sentence of § 111(d), it is apparent that it was 

Congress’s intent that States in determining the “standards of performance” for “any 

existing source” under § 111d)(1) should take into consideration “among other factors” 

under 111(d), the “cost of achieving such reduction and any nonair quality health and 

environmental impact and energy requirements” as provided as one of the factors in the 

definition of “standard of performance” at § 111(a)(1).

In summary, in designing the rule and guidelines for this rulemaking, States should be 

allowed to “tak[e] into account the cost of achieving such reduction and any nonair 

quality health and environmental impact and energy requirements,” “among other 

factors” under 111(d)(1), in determining the “standard of performance” for “any existing 

source” in this rulemaking. 

• Remaining useful life 

The mandatory “shall” language in § 111(d)(1) creates a non-discretionary duty for the 

EPA Administrator to include in the § 111(d) regulations authority for States to consider 

the remaining useful life of the existing source to which such standard applies:

Regulations of the Administrator under this paragraph shall permit the State in 

applying a standard of performance to any particular source under a plan 

submitted under this paragraph to take into consideration, among other factors, 

the remaining useful life of the existing source to which such standard applies.

As noted above, this sentence was added to § 111(d)(1) as part of the 1977 Clean Air 

Act amendments. It is worth emphasizing again that the 1977 amendments to CAA § 

111(d) made the following changes to the language of § 111(d):

 (b)(1) Section 111(d)(1) of such Act // 42 USC 7411. // is 

amended by striking out “emissions standards” in each place 

it appears and inserting in lieu thereof “standards of 

performance” and by adding at the end thereof the following 

new sentence: ” Regulations of the administrator under this 

paragraph shall permit the State in applying a standard of 

performance to any particular source under a plan submitted 

under this paragraph to take into consideration, among other 

factors, the remaining useful life of the existing source to 
which such standard applies.”.

1977 CAA § 111(d) [42 U.S.C.A. § 7411(d)]. 

As noted in the previous section above, these additions were made as part of other 

1977 CAA Amendments that gave authority to States to consider costs, energy impacts, 

and remaining useful life in several different contexts. The 1977 CAA Amendments 

gave to States:

• Primary authority to take into account the cost of achieving any pollution 

reduction, and any non-air quality health and environmental impacts and energy 

requirements in determining BACT (CAA § 169(3)), BART (CAA § 169A(g)(2)), 

and the 1977 CAA definition of “standard of performance” (CAA § 111(a)(1)(C)); 

and 

• Primary authority to determine “remaining useful life” of existing sources under 

both “existing source” NSPS (CAA § 111(d)(1)) and both BART and “reasonable 

progress” for existing sources under Regional Haze (CAA §169A(g)(1) & (2)).

These amendments thus appear to give States primary authority to consider all of the 

above factors in each of the above 1977 amendments to the Act.

The term “remaining useful life” is not defined in the CAA, but is a term of art often used 

in engineering, in accounting and tax law, and sometimes by economists. It would seem 

that the best course of action would be to allow States to consider those various 

meanings in these different contexts when determining “remaining useful life,” because 

engineering, accounting, and economic factors are all relevant to determining how long 

it may be useful to allow a facility to continue to operate for its intended and designed 

purpose as a baseload, peaking or intermediate power source for the grid. Thus, it is 

suggested that States be allowed to consider, as required by § 111(d), an EGU’s 

“remaining useful life” based on consideration of the following factors: 

• Scientific, engineering, accounting, and economic factors relevant to determining 

the “remaining useful life” of the existing EGU in question. 

In other words, the EPA Administrator’s regulations should allow States to consider the 

commonly accepted factors that are accepted within scientific, engineering, and 

accounting communities for determining “remaining useful life,” as well as relevant 

economic information and data that go to that issue, such as projected load growth or 

decline in an EGU’s service territory.

• Technical design

A key phrase in the definition of “standard of performance” is the phrase “best system of 
emission reduction.” Neither the word ”system,” nor the phrase “emission reduction,” are 

defined in § 111, its implementing rules, or other provisions of the CAA. So this 

discussion can focus on the technical and policy issues regarding the meaning of 

“system” and “emission reduction,” rather than statutory and rule definitions, legislative 

and preamble history, and case law interpreting the meaning of various provisions of the 

law that were addressed in the discussion of possible “legal design” above.

What the phrase “best system of emission reduction” as a whole means in the context 

of the rest of the language of § 111(a)(1) and § 111(d)(1) will be discussed later. 

In EPA’s September 23, 2013 questions asked in “Considerations in the Design of a 

Program to Reduce Carbon Pollution from Existing Power Plants,” at least two 

underlying issues emerge: 

• (the “system” question) whether the rule should measure emissions at a “source” 

level or across a “system”; and 

• (the “emission reduction” question) whether the rule should measure “emission 

reduction” by the “rate” of emissions (in lbs/MWh) or by the “mass” of emissions 

(in tons)? 

As explained below, the word “systems” and the term “emission reduction” seem to 

allow either a “source” or a “system” approach, or both, and either a “rate” or a “mass” 

approach, or both. 

Further, for the reasons explained below, it makes sense for EPA to design an approach 

that allows States and regulated entities to choose either a “rate” or a “mass” approach 

(or a combination thereof), and either a “source” or a “system” approach (or a 

combination thereof).

Later these comments will address the specific questions asked in the September 23rd

EPA questions on “design” of the rule. 

This section, however, will discuss in more detail the various technical and policy issues 

related to the possible reasonable meanings that can be given to the word “system” and 

the phrase “emission reduction.” As noted above, this analysis is relevant to determining 

the meaning under the rule of the longer phrase/term-of-art “best system of emission 

reduction” under § 111(a)(1), although in the context of § 111 and the CAA as a whole, 

the possible reasonable interpretations of the phrase “best system of emission 

reduction” are more limited than the possible meanings that could be given those terms 

standing alone without context. But one of the important steps in this process is to first 

define and understand the key terms—“system” and “emission reduction”—so that a 

meaningful and rational policy can be designed.

• The meaning of the word “system” as it applies to electricity

• Definition of “system”
The primary definition or “sense” of the word “system” is “a regularly interacting or 

interdependent group of items forming a unified whole.”

A system [bold in original] is an interconnected set of elements that is coherently 

organized in a way that achieves something. If you look at that definition 

closely... you can see that a system must consist of three kinds of things: 

elements, interconnections, and a function or purpose [italics in original].

“The least obvious part of the system, its function and purpose, is often the most crucial 

determinant of the system’s behavior,” and its defining element. For example, for an 

electricity generation, transmission and distribution system, its function and purpose is 

to generate, transmit, and distribute electricity to end-users, and the defining element of 

an electricity generation, transmission and distribution system is, of course, electricity.

• “Stock” and “flow”

Almost all systems consist of two crucial elements: “stock” and “flow.” “A stock [bold in 

original] is the foundation of any system. Stocks are the elements of the system that you 

can see, feel, count, or measure at any given time.” Generally you cannot see 

electricity (lightning and electric arcs being arguable exceptions), but you can feel it 

(generally not recommended), and certainly electricity can be counted and measured. 

Any wholesale or retail electricity provider is involved in the business of counting and 

measuring electricity in kilowatts (KWs) and megawatts (MWs) during the generation, 

purchase, and sale of each unit of electricity. In fact, one of the two factors that the 

author will recommend that EPA measure and track in this rulemaking will be the gross 

and net electricity generated by each defined “source” and “system” that is regulated 

under this rulemaking.

“Flow systems have two basic features (properties). There is the current that is flowing 

(for example, fluid heat, mass, or information) and the design through which it flows. A 

lightning bolt, for example, is a flow system for discharging electricity from a cloud.” In 

the case of an electricity generation, transmission, and distribution system, the current 

that is flowing is, obviously, electricity, and the “design through which it flows” is the 

generation, transmission, and distribution system.

For most types of stocks (i.e., when the stock is a physical object, not a form of 

electromagnetic energy), “[a] stock is the memory of the history of changing flows within 

the system”: the “stock” available to the “system” is the sum of the net inflow of that 

stock into the system minus the net outflow from the system. Two common examples 

show how this works. 

The first example is a hydroelectric dam system. The stock is the amount of water 

behind the dam that available for the generation of electricity, which is the sum of the 

inflow of the water behind the dam that has accumulated minus the sum of both the 

outflow of water from the dam through the turbines plus any evaporation.
The second example of a stock is a retail store such as a retail grocery or sporting 

goods store. The amount of groceries, sporting goods, or other “stock” available for 

sale to the public is the net of the amount of groceries or sporting goods brought into the 

store for sale minus the amount of groceries sold from the store (hopefully with 

minimum spoilage or theft).

The problem with electricity as a “stock” is that electricity cannot be stored for future use 

as a “stock” in the same way that physical things such as water behind a dam or 

groceries in a grocery store can be stored. Without the development of technologies 

like pump storage or battery storage, which are not sufficiently developed technologies 

at this time for significant storage of electricity as a “stock,” electricity will not be stored 

in any meaningful amounts as a “stock” on the existing electrical grid. Rather, electricity 

is different from physical stocks in that it is produced and transferred as a “stock” almost 

instantaneously (technically, at the speed of light). 

This creates a problem for renewables such as wind or solar, because they can be 

produced only at certain times, which may or may not be exactly when they are needed. 

This is why those resources have to be backed up by natural gas or another form of 

peaking generation that can be produced whenever it is needed to match the changing 

demand on the system. This is also why wind and solar do not work for baseload 

power: they are not available most of the time because they do not run on an alwaysready-to-use and low-cost fuel supply (which is why coal and nuclear have been the 

most reliable low-cost baseload form of power for several decades). In sum, electricity 

is the “stock” in the electricity stock-and-trade business, but it presents a different set of 

issues because, unlike physical objects, it is difficult to store (dams and batteries being 

notable exceptions), and it has to be designed as a “system” to be available when 

needed (which means, for a reliable and robust generation, transmission, and 

distribution system, there needs to be different kinds of generation for different kinds of 

purposes and needs).

There are three other elements and factors that are crucial to understanding systems 

and how they work: 1) information flow, 2) feedback loops, and 3) limiting factors.

• Information flow

Both information and the flow of information determine how a system operates and 

changes. For the most part, “the interconnections in systems operate through the flow of 

information.” “Everything that moves, whether animate or inanimate, is a flow system,” 

including information. Because information within a system defines and influences how 

that system persists, responds, evolves, and changes, “[i]nformation holds systems 

together and plays a great role in determining how they operate.” Further, systems 

either continue to operate smoothly or break down in large part because of the quality 

and timeliness of the information that governs their operation, and “most of what goes 

wrong in systems goes wrong because of biased, late, or missing information.” 

Within an electrical generation, transmission, and distribution system, the critical 

information flow is the information that matches and adjusts the generation of electricity 
at one end of the system to the demand for the electricity at the other end of the system. 

For the past several decades, most of the demand on the system has been supplied by 

baseload generation (primarily coal and nuclear), and the minute-by-minute and hourby-hour fluctuations in demand on the system as a whole has been “chased” by peaking 

generation (primarily natural gas, and, when available, peaking hydro). And the person 

or entity in charge of operating the system tracks the information about changes in 

electricity generation and demand, and determines which generation resources to turn 

on or turn off, and in which order, primarily based on the availability of that resource and 

its cost. Baseload generation, for example, runs the most because it is available most 

of the time and it has the lowest cost per unit of electricity produced. 

Determining which information will be relevant in determining how the system will be 

operated is a key issue in any system. For example, although EPA has no authority to 

mandate it under § 111, either by happenstance or by design, some NGOs and states 

appear to be considering the possibility of making carbon-intensity of the resource 

another bit of information, another factor, in addition to cost and availability, that 

potentially may be used by the operator of the system to determine in which order 

resources will be called on to produce electricity, or by the producer in evaluating the 

cost-effectiveness and availability of a lower-carbon-intensity generation resource. 

Whether states or regions may use environmental dispatch, rather than economic 

dispatch, to determine which generation resources will run and in which order, will be 

discussed in the last section of this whitepaper relating to cooperative federalism as it 

related to § 111. But many new “information” issues arise when wind and solar are 

added to the existing generation system. 

Wind and solar disrupt the existing generation system in many new ways because they 

are not available when they are needed in the same way that baseload coal and nuclear 

or natural gas peaking are available. They are valuable as “fuel displacers” when they 

are available, but their availability changes with each gust of wind or passing cloud. The 

system must be constantly adjusted to “chase” them against changing demand when 

they are available; and when they are not, the system must have other forms of 

baseload, intermediate, and peaking power to meet the load at those times. One of the 

biggest challenges is how “chasing” these renewable resources will impact the ability to 

run existing baseload generation in a cost-effective and reliable manner. 

Take away half the load of a baseload source because of fuel displacement from 

renewable resources, and it may no longer be possible to run baseload in a costeffective manner. So either the capital-investment becomes stranded because the 

baseload resource has to be shut down for economic reasons, or the cost of electricity 

from the resource has to be increased to pay it for being “available” when it is needed, 

even though it isn’t running. Otherwise the economic “externality” of adding wind and 

solar to the existing system is completely borne by the existing resources without any 

compensation (and by the end-users, who must now pay for the increased costs for 

having other forms of generation either constructed or standing idle while the wind 

blows and the sun shines). The problem is that back-up generation (whether baseload 

or peaking) has costs that must be paid for whether or not they are running, and wind, 

solar and other renewables decrease the time that other resources will run, thus 
spreading the remaining un-depreciated capital costs of those existing resources over 

fewer generation hours.

How this new information relating to these new resources on the system will be 

processed so that the evolving generation system may continue to operate efficiently to 

provide reliable, low-cost electricity is a key underlying issue.

• Feedback loops

A system runs itself through feedbacks (which are a special form of information that 

allows a system to adapt). And because systems by definition flow, morph and change, 

a system has to have “feedback loops” which allow it to evolve and adapt as the system 

changes in response to the conditions affecting the system for the system to survive. 

For example, on an electric system, there must be a feedback loop that allows the 

supply of electricity (the stock) to increase or decrease as the demand for that electricity 

increases or decreases. 

“A feedback loop is a closed chain of causal connections from a stock, through a 

set of decisions or rules or physical laws or actions that are dependent on the 

level of the stock, and back again through a flow to change the stock.”

Physical stocks “generally change slowly, even when the flows into and out of them 

change suddenly,” and such “[s]tocks allow inflows and outflows to be decoupled and to 

be independent and temporarily out of balance with each other.” Thus, physical “stocks 

act as delays or buffers or shock absorbers in systems.”

So, for the hydroelectric dam example discussed above, the water stored behind the 

dam is a stored stock that acts as a buffer or shock absorber for high and low inflows 

into the dam, and, as long as water remains stored behind the dam, a feedback loop 

can be created that decouples the inflow of water into the dam from the release of water 

through the turbines to generate electricity—a stock that is sold as it is generated, but 

which currently cannot be easily stored (again, pump storage, battery storage, and other 

options like compressed air being notoriously inefficient and largely unavailable 

exceptions). 

Similarly, for fossil fuel plants, a coal pile or a ready supply of natural gas are equivalent 

to water stored behind a dam as potential energy that can be called upon to act as a 

buffer or shock absorber to changing demands for electricity on a system. And feedback 

loops can be created that can quickly call on a “spinning reserve” that is available on a 

coal generation unit running at near capacity, or a quickly available natural gas 

combustion turbine peaking unit that can be ramped up and running at its highefficiency-full-capacity in a short period of time, depending on the CT and the ambient 

temperature that day.

Unfortunately, there are no readily available ways to store wind and sunlight in the same 

way that water behind a dam or coal in a coal pile can be stored. Further, for some 

forms of baseload and intermediate generation such as coal and combined-cycle 
natural gas, it can take several hours to warm the boiler, activate pollution controls, and, 

in the case of the combined cycle, warm its heat recovery steam generator (HRSG), 

sufficiently for them to even begin generating electricity let alone be fully operational for 

pollution control, if they are called upon to back up wind and solar from a cold start. 

This example demonstrates that “[t]he information delivered by a feedback loop—even 

nonphysical feedback—can only affect future behavior; it can’t deliver a signal fast 

enough to correct behavior that drove the current feedback. Even nonphysical 

information takes time to feedback into the system.”

One possible solution to the “cold start” problem is to create a feedback loop rule for the 

system that backs down coal, combined-cycle natural gas, and simple-cycle natural gas 

to minimum capacity levels when wind and solar are available on the system, rather 

than shut them off. But this creates another set of issues. For example, at 60 percent 

loads or less, coal, combined-cycle natural gas, and simple-cycle natural gas become 

significantly less efficient, so their rate of CO2 emissions, in pounds per mega-watt hour 

(lbs/MWh), become significantly greater. So if EPA or the State would set a 

performance standard based an assumption that these coal and natural gas sources 

would be operating at their highest efficiency full-load rate of emissions, but in fact they 

operate with significantly less efficiency because they are being backed down in favor of 

wind and solar, the result may be manifold:

• Because they are operating at lower load levels where they emit CO2 at a higher 

rate in lbs/MWh than when operating at higher loads, fossil-fuel generation will 

likely exceed the rate in lbs/MWh set in their permits if permit rate levels are set 

on the assumption that these facilities were going to operate at their highest-fullload efficiency. EPA and States, therefore, may have to set up a procedure that 

will allow different rate standards for different load levels, or EPA and the States 

with primacy will create the perverse result that these facilities will violate their 

permit rate limits whenever they back down for wind, solar, hydro, or demand 

side management. Or, in the alternative, EPA and States can allow companies 

to average across their systems and include all generation resources and 

megawatt conservation steps to avoid punishing fossil-fuel sources, which are 

most efficient at high loads, for backing down for lower-carbon-intensity forms of 

generation.

• For the same reason, additional startups and shutdowns caused by solar, wind, 

and other green resources will result in additional CO2 emissions, as well as 

emissions of other regulated pollutants, because of the additional startups and 

shutdowns, as well as ramping up and down, from fossil-fuel generation 

compared to the amount and rate of CO2 emissions in lbs/MWh that would occur 

if these fossil fuel resources ran as they were designed to be run as baseload 

resources to be most efficient and to release pollutants at the lowest possible 

rate—at full load.

• Operating these fossil fuel resources at a less efficient rate (i.e., it will take more 

fuel to produce each megawatt hour (MWh) because they will be operating at 

lower, less efficient rates than when operating at full capacity), and at lower loads 
(i.e., they will be producing fewer megawatt hours to sell each hour, even though 

their capital costs and debt servicing, labor costs, etc., will remain the same or 

increase), will result in an increased cost on a per-megawatt-hour basis for 

almost all fossil-fuel resources that are either “backed down” or “shut down and 

started up” more often because of the changed dynamics of the whole system 

resulting from adding significant amounts of wind and solar generation to the 

system.

• The additional startups and shutdowns, and the constant ramping up and 

backing down, of both coal and natural gas based generation will cause 

increased stress and wear-and-tear on the metals and components of those 

generation resources, which will result in increased numbers of forced outages, 

increased maintenance costs and reliability issues, and, perhaps, shorter useful 

lives for those facilities because of all of these factors.

Further, none of these added costs or new externalities to the system will be charged 

against the resources on the system that are causing them—the solar and wind and 

other new resources that have been added to the system and changed how it functions 

and operates. In a perfect system, the fair thing to do would be to add up the increased 

emissions and costs added to these traditional baseload and peaking facilities, and 

charge them to the wind and solar facilities that are disrupting the existing system and 

causing these increased rates of emission, and increased costs. These built-forbaseload and built-for-peaking facilities are now being run neither as baseload nor as 

peaking facilities. Instead, they are running in less efficient and in more expensive 

modes because of the addition of these new untraditional “green” resources to the 

system.

The above are all examples of fundamental properties of systems and feedback loops, 

and how they may impact the electricity system consistent with established principles 

about how systems work:

• System structure is the source of system behavior. System behavior reveals itself 

in a series of events over time.

• Complex behaviors of systems often arise as the relative strengths of feedback 

loops shift, causing first one loop and then another to dominate behavior.

• A stock-maintaining balancing feedback loop must have its goal set appropriately 

to compensate for draining or inflowing processes that affect the stock. 

Otherwise, the feedback process will fall short or exceed the target for the stock. 

For example, bringing on wind and solar at such a rate that it financially 

bankrupts the coal and natural gas resources that are backing them up when 

wind and solar are not available may cause the whole system to crash: setting 

the appropriate goal and the appropriate rate to achieve it are both key.

• Many relationships in systems are nonlinear. Their relative strengths shift in 

disproportionate amounts as the stocks in the system shift. Nonlinearities in 

feedback systems produce shifting dominance of loops and many complexities in 

system behavior. Some of the complexities of adding wind and solar to the 

existing system are outlined above.

• Because of imperfect knowledge and data and delayed and biased feedbacks, 

the limited rationality of each actor in a system may lead to decisions that do not 
further the welfare of the system as a whole. The degree of rationality of any 

actor in the system is “determined by the information, incentives, disincentives, 

goals, stresses and constraints impinging on that actor.” Because actors do not 

have perfect knowledge, and feedback loops cannot be perfectly designed, 

imperfect actors with imperfect knowledge are not likely at the beginning to 

optimize management and maximize welfare across the system as a whole. That 

is why it is critical to build learning into a system as complex as the national 

electricity generation, transmission, and distribution system, and to realize how 

much we don’t know about the possible effects of the changes that are being 

proposed. “What’s appropriate when you’re learning is small steps, constant 

monitoring, and a willingness to change course as you find out more about where 

it’s leading.”

• Systems need to be managed not only for productivity and stability, they also 

need to be managed for resilience—the ability to recover from perturbation, the 

ability to restore or repair themselves. In the case of existing generation and the 

existing generation grid, resiliency is maintained by allowing low-cost, reliable, 

existing generation to continue to operate through its remaining useful life, which 

means setting performance standards for such resources that are achievable 

through using technologies and systems that are available, after considering 

other factors such as the “cost of achieving such reduction and any nonair quality 

health and environmental impact and energy requirements” as required by the 

definition of standard of performance at § 111(a)(1). 

• Limiting factors 

“At any given time, the input that is most important to a system is the one that is most 

limiting.” A “limiting factor” is a “necessary system input”: “the one limiting the activity of 

the system at a particular moment.”

Any physical entity with multiple inputs and outputs—a population, a production 

process, an economy—is surrounded by layers of limits. As the system 

develops, it interacts with and affects its own limits. The growing entity and its 

limited environment together form a coevolving dynamic system.

Examples of a “limiting factors” for a fossil-fuel EGUs are their permit restrictions or 

limits for air emissions. The permit limit for a particular pollutant often contains either an 

emission rate limit or an emission mass limit or both. A permit that restricts sulfur 

dioxide (SO2) emissions, for example, may have a “rate” limit in pounds per hour, and a 

mass limit in tons allowed per year under the acid rain program. An EGU permitted as a 

minor source for hazardous air pollutants (HAPs) may have a total ton “mass” limit for 

all HAPs that it may not exceed on an annual or rolling twelve-month basis, plus a “rate 
limit” for a particular HAP (e.g., the rate limit for mercury (Hg) under the recent MATS 

rulemaking). 

So there would be nothing unusual for this “existing source” CO2 rulemaking to create a 

design that would allow “rate” limiting factors or limits (expressed in lbs/MWh) for some 

types of sources, systems, states, or regions (for example, as discussed further below, 

for systems experiencing demand or load growth), and “mass” (i.e., total annual ton) 

limits for other types of sources, systems, states, or regions (for example, as discussed 

further below, for systems experiencing diminishing demand or load). Further, those 

options could be placed in a “menu” guideline which would allow a regulated source, 

system, or State to pick the appropriate type of limit (mass or rate) for the particular 

source, system, or State in question.

Of course there are all sorts of other limiting factors for EGUs besides permit limits. For 

solar power for example, a limiting factor is the amount of sun that is available at any 

particular time at any particular solar generation facility location; the same is true of 

wind—the amount of wind limits generation at that particular time at that wind farm. For 

coal, a limiting factor is the amount of coal available at the generation site; for natural 

gas, a limiting factor is the amount of gas available by pipeline, so when many natural 

gas sources are placed on a single pipeline, that region may become particularly 

vulnerable if the pipeline becomes unavailable. All forms of generation have as a limiting 

factor the amount of transmission capacity available to take power to customers. Other 

limiting factors for electricity are supply and demand:

 [I]t takes several years to build an electric power plant ... [D]elays make it 

impossible to build exactly the right number of power plants to supply rapidly 

changing demand for electricity. Even with immense effort at forecasting, almost 

every electricity industry in the world experiences long oscillations between 

overcapacity and undercapacity. A system just can’t respond to short-term 

changes when it has long-term delays. That’s why a massive central-planning 

system, such as the Soviet Union or General Motors, necessarily functions 

poorly. 

This suggests one of the reasons to avoid the temptation to make this rulemaking into a 

form of massive central planning for all electricity in the United States: § 111(d) gives the 

Administrator no authority to engage in such an exercise, and, because of the long lead 

times for planning and replacing generation resources, and their long useful lives, 

prematurely forcing closure of existing sources with remaining useful lives may remove 

one of the principle buffers on the system against rapid changes in supply and demand 

for electricity.

In this particular rulemaking, the language of § 111(d), the definitions in § 111(a), 

and the different and potentially opposing roles assigned to the EPA 

Administrator and the States under § 111(b) compared to § 111(d), are all legal 

“limiting factors” to how EPA may design this rulemaking. Under § 111(b), the 

Administrator establishes “Federal standards of performance for new sources” for 
any “category of sources” which “causes, or contributes significantly to, air 

pollution which may reasonably be anticipated to endanger public health or 

welfare.” Under § 111(d), the EPA Administrator’s role is limited to prescribing 

“regulations which establish a procedure ... under which each State ... 

establishes standards of performance for any existing source for any pollutant” 

which falls into the category set forth in CAA § 111(d)(1)(A)(i & ii). 

It is clear and unambiguous that the Administrator’s role is different under § 111(b) 

compared to § 111(d): the Administrator has no authority to issue Federal standards of 

performance for existing sources. Suggestions on design of this rulemaking by NGOs 

and others that urge the Administrator to directly or indirectly establish Federal 

standards of performance for existing sources should be rejected because they exceed 

the Administrator’s authority. Any regulation under § 111(d) that fails to respect and 

follow this legal “limiting factor” under the language of the statute will likely fail to 

withstand legal scrutiny by the courts. 

• The crucial step of defining the boundaries of a system

• Defining System Boundaries 101 

“[E]very flow system is part of a bigger flow system, shaped by and in service to the 

world around it.” And everything—from the smallest quarks, atoms and single-celled 

organisms, to the earth’s oceans, atmosphere and biosphere, to the solar system, Milky 

Way Galaxy and the cluster of galaxies of which each of these smaller systems are a 

part—is a flow system. Yet “[i]t is hard to think in terms of systems, and we eagerly 

warp our language to protect ourselves from the necessity of doing so.”

[S]ystems rarely have real boundaries. Everything, as they say, is connected to 

everything else, and not neatly. There is no clearly determinable boundary 

between the sea and the land, between sociology and anthropology, between an 

automobile’s exhaust and your nose. There are only boundaries of word, thought, 

perception, and social agreement—artificial, mental-model boundaries.

The key step, for tracking changes within any particular system, is to clearly define its 

boundaries. “Precision is the foundation of both language and science. The definition of 

a word, like [the definition of the] boundaries of a thermodynamic system, spells out 

exactly what it is and what it is not.” “We define the system by drawing a sharp and 

precise boundary around the entity in question ... Inside the boundary is the system we 

have decided to look at ... Outside the boundary is everything else: the rest of the 

world. This ‘other system’ in thermodynamics is called the ‘environment,’ or the 

‘ambient.’” Precisely defining the boundaries of a system allows measurement of 

changes of the state of the system within its boundaries, and measurement of changes 

in stock—what is flowing into and out of the system.

The defined system can be either an “open” system (e.g., a system boundary set up to 

measure the amount of water behind a dam or in a pot of boiling water) or a “closed” 

system (e.g., a system boundary set up to measure the temperature of a room, a 
building, or a swimming pool). Although the boundaries of a system are always arbitrary 

in the sense of being selected for a specific purpose (among all possible human 

purposes that could have been selected), selecting clearly defined boundaries is what 

allows either the “state” of a system (e.g., the temperature of a room, or the average 

temperature of all the rooms in a building), or the “change” occurring within a system 

(how much the temperature is going up or down over time), to be measured. 

Within the fields of science and engineering, as Lord Kelvin noted, "[t]o measure is to 

know." "If you cannot measure it, you cannot improve it." "In physical science the first 

essential step in the direction of learning any subject is to find principles of numerical 

reckoning and practicable methods for measuring some quality connected with it. I often 

say that when you can measure what you are speaking about, and express it in 

numbers, you know something about it; but when you cannot measure it, when you 

cannot express it in numbers, your knowledge is of a meagre and unsatisfactory kind; it 

may be the beginning of knowledge, but you have scarcely in your thoughts advanced 

to the state of Science, whatever the matter may be." In sum, clearly defined boundaries 

allow the crucial step of measurement of states and of changes within any system.

Yet, although it is critical that boundaries be defined so that the different measurements 

of state (e.g., current temperature or current mass) or change (e.g., rate of flow into and 

out of the system) can occur, it is equally important that different kinds of boundaries be 

drawn for different kinds of systems, so that each system’s boundaries coincide with the 

particular function or purpose that has been identified for that system (as defined). 

There are several rules of thumb that apply to defining system boundaries:

• “There are no separate systems. The world is a continuum. Where to draw a 

boundary around a system depends on the purpose of the discussion—the 

questions we want to ask.”

• “The lesson of boundaries is hard even for systems thinkers to get. There is no 

single, legitimate boundary to draw around a system. We have to invent 

boundaries for clarity and sanity; and boundaries can create problems when we 

forget that we have artificially created them.”

• “The greatest complexities arise exactly at boundaries”—in large part because 

boundaries are artificially drawn, systems evolve, and the reasons for drawing 

the boundaries may change.

• The crucial step in defining any system and drawing its boundaries is to ask the 

question or questions that result in “the right boundary for thinking about a 

problem.” For any human-designed or human-influenced system, the crucial 

question to ask when defining and drawing a system’s boundaries is this: 

• What is that system’s purpose if it is a human-designed system; and

• What is that system’s function if it is a non-human, natural system.

• “When you define the boundaries too narrowly, the system surprises you”—often 

in non-intuitive ways. 

• For example, demand-side management may require more efficient 

electro-technologies to be manufactured, but the result may be not only 

less demand per each individual electro-technology used in a business or 

home, but also result in more or larger electro-technologies to be used in 
the business or home because more technologies can be run for the same 

price—so the result of greater demand-side efficiency may not always be 

a drop in overall demand. 

• For example, increasing the cost of electricity for pollution control may not 

only reduce the direct health effects caused by pollution, but also drive up 

the costs of electro-technologies manufactured for and used at hospitals, 

the costs of heating and lighting hospitals and clinics, the costs of 

manufacturing and transporting medications, etc., in ways that drive up the 

cost of health care significantly more than the small marginal benefit of 

reducing pollution a tiny bit more at great economic cost to an electricity 

generator or a generation system as a whole; further, the same reduction 

in pollution may be available simply by changing how the system 

operates, rather than putting on the marginally-(in)effective pollution 

controls at a very high economic cost. This issue may be particularly 

relevant to carbon capture and sequestration technologies.

• Similarly, increasing the economic cost of the electricity that heats or cools 

schools, and that is needed to manufacture and operate the electrotechnologies to help children learn so that they are ready to compete in 

the world economy that will likely exist when they become adults, may 

increase the costs enough that some schools and school districts may no 

longer be able to afford to provide those electro-technology resources to 

their children.

• For all such complex systems, the key is to monitor the system as a 

whole, and to find the “Goldilocks Zone” for accomplishing the various 

goals and purposes of the system or systems involved: not too little, not 

too much, but “just right.” And finding “just right” almost always involves 

building learning into the system as it matures and grows. No child is born 

a full-grown adult, and no system is born as a fully functional unit. Those 

who think fully functioning systems can be designed, top-down, to work 

perfectly from the start are destined to be disappointed: witness the new 

health care insurance system currently coming on-line nationally. 

• “System analysts often fall into the opposite trap: making boundaries too large. 

They ... produc[e] ... diagrams [or enormously complicated rules] that cover 

several [hundred] pages with small print and many arrows connecting everything 

with everything. ... [This] results in enormously complicated analyses, which 

produce piles of information that may only serve to obscure the answers to the 

questions at hand. For example, modeling the earth’s climate in full detail is 

interesting for many reasons, but may not be necessary for figuring out how to 

reduce a country’s CO2 emissions to reduce climate change.”

• “The right boundary for thinking about a problem rarely coincides with the 

boundary of an academic discipline, or with a political boundary. ... Ideally, we 

would have the mental flexibility to find the appropriate boundary for thinking 

about each problem. We are rarely that flexible. We get attached to the 

boundaries our minds happen to be accustomed to.”

• “It’s a great art to remember that boundaries are of our own making, and they 

can and should be reconsidered for each new discussion, problem, or purpose. 
It’s a challenge to stay creative enough to drop the boundaries that worked for 

the last problem and to find the most appropriate set of boundaries for the next 

question. It’s also a necessity, if problems are to be solved well.”

In summary, for any system, it is important not only to have clearly defined boundaries, 

but also to have flexibility in setting boundaries, so that both a system’s boundaries, and 

what is measured inside those boundaries, match the purpose or function of each 

system (and each system’s sub-systems). In designing any system, and defining its 

boundaries, it is best to choose the design that is most simple, yet still accomplishes the 

system’s defined purpose. This concept is a variation on Ockham’s razor—“entities 

should not be multiplied unnecessarily”—and echoes a famous scientific maxim: “as 

simple as possible, but not simpler.” 

But the goal of simplicity is “often impeded by faulty assumptions and by a limited 

creative vision for alternatives.” The trick is always to build flexibility into the system so 

that systems can evolve as the factors affecting them change, and to allow balance and 

diversity as systems mature. It is, in fact, a quality of almost all systems that during 

periods of rapid growth those systems are low-diversity systems dominated by a few 

entities with less-robust-and-complex structures “specialized for quick capture of energy 

and materials.” But when lower growth occurs because of (for example) lower 

availability of key resources, a higher “diversity of cooperating units develops, with 

better efficiency and division of labor” resulting, overall, in “more diversity, more 

controls, and longer-lasting structures.” This appears to be true of economic systems, 

various kinds and levels of biological systems and ecosystems, transportation systems, 

and electricity generation systems—for starters.

With these guiding principles in mind, what is the simplest design that could give legal 

and technical structure to this rulemaking? Based on the above analysis, the crucial 

questions for designing this rulemaking are these:

• What are the legal and technical limiting factors that apply to design?

• What should be measured in each system?

• How should the different system boundaries be defined?

• What flexibility should be built into the system to allow for different 

boundaries when different purposes are identified? 

• For example, what are differences in purposes and goals between 

federal, regional, and state regulatory bodies, and between different 

sizes and kinds of electricity generation systems (EGSs)? 

• Can a system be designed that allows flexibility of boundaries (as 

long as each boundary is clearly defined) at each level (federal, 

regional, state, and regulated EGS), and for each kind of EGS 

(those with growing electricity demand, those with stable demand, 

and those with declining demand)?

• A suggestion for an “as simple as possible, but not simpler” regulatory 

system
• What are the legal and technical limiting factors that apply to 

design? 

In this case, the purpose of the to-be-proposed regulatory system is to regulate CO2

emissions from “existing sources” as defined at § 111(a)(6) according to the 

requirements and options set forth in § 111(d). So far this whitepaper has discussed 

various legal and technical “limiting factors” that set boundaries on the possible 

regulatory system that EPA may design under the language of § 111(d) and the 

definitions that apply to it under § 111(a). Those limiting factors have been discussed in 

detail above, and need not be repeated. The remaining sections of this whitepaper will 

discuss issues that arise, and possible options for addressing them, within the universe 

of possible options for design allowed by § 111(d) discussed in the preceding sections of 

this whitepaper.

Based on the above analysis of legal and technical options available under§ 111(d), a 

general outline for a procedure to develop “standards of performance” for each 

qualifying “existing source” EGU under § 111(a)(6) and § 111(d) might include these 

steps:

• States define what are the “fenceline” boundaries of “existing sources”—the 

EGUs—that are to be regulated under this rule (e.g., what is the boundary of 

each “existing source” if several EGUs are at a single location); then 

• States determine what to measure and how to measure the appropriate-for-thatsource reduction in the “rate” or “mass” of emissions from each “existing source” 

based on an appropriate “baseline” and an appropriate procedure and set of 

guidelines developed by the EPA Administrator that allow States to consider, 

among other factors, “remaining useful life” and the five factors outlined in the 

definition of “standard of performance” at § 111(a)(1); and then, if States so 

choose, 

• Using flexibility and discretion, States may define the boundaries of any larger 

“system” that the EGU is a part of, 

• e.g., other contiguous units at the same location bubbled together 

as a system, or, 

• e.g., all forms of generation owned or operated by a cooperative as 

a system to generate electricity as an EGS for a defined set of 

customers considered together,

• to determine reductions in either rate or mass, or both, for either

• an EGU standing alone, or

• across an entire defined system (EGS) as a whole, 

• or both, 

• by comparing 

• the reduction of potential outside-the-boundary reductions in rate or 

mass of emissions when the system is operated as a whole, 

• to potential before or after achievable inside-the-fenceline emission 

reductions that are identified by the regulating State pursuant to § 

111(d),
• (EPA should allow this as a “better-than-inside-the-fenceline” 

alternative to requiring reductions to each EGU separately if 

outside-the-fenceline reductions for an EGS are greater than 

inside-the-fenceline reductions for an EGU (or the combination of 

EGUs within the EGS), either in mass or rate, or both), 

• that may be used as an alternative way to achieve “best-system-ofemission-reduction” standards of performance for an existing source 

within a larger defined “system” (EGS),

• also according to a procedure and guidelines provided by the EPA Administrator.

Except for the first two, all the remaining bullets are added to suggest a possible 

procedure to allow greater outside-the-fenceline reductions where appropriate. This 

admittedly adds several layers of complexity to the system—and creates a challenging 

“but-not-simpler” component. But even the many commenters who say the 

Administrator’s authority is limited solely to within-the-fenceline CO2 emission 

reductions (this whitepaper, in fact, is saying something very close to that), are also 

often saying that States should also be allowed to consider outside-the-fenceline 

reductions to meet inside-the-fenceline emission reduction requirements. This 

whitepaper attempts to outline a procedure and design that may allow that.

In sum, if the factors that are tracked are kept simple enough, if the boundaries of each 

EGU and system are clearly defined (by the relevant regulatory body), and if the 

baselines for each EGU and system are clearly established—then figuring the 

baselines, the boundaries, and the amount of emission reductions (either in rate or 

mass) from a baseline for any particular well-defined EGU or EGS can be relatively 

easy and simple to understand. The remainder of this whitepaper will attempt to 

suggest a possible design for such a system, and to give relevant examples of difficult 

issues and possible ways to address them.

• What should be measured in each system?

MWhs and TTs. To keep things as simple as possible, it is suggested that each system 

regulated be required to report two basic things: 1) megawatt hours (MWhs) produced 

from each “existing-source” EGU, from each additional electricity generation resource 

(EGR) on a system that doesn’t fall into the definition of an “existing-source EGU,” and 

from each identified and clearly defined electricity generation system (EGS) as a whole; 

and 2) total mass of CO2 emissions (reported in tons, or fractions thereof)—total tons 

(TTs)—produced by each “existing-source” EGU, by each additional EGR on a system 

that doesn’t fall into the definition of an “existing-source EGU,” and by each identified 

and clearly defined EGS as a whole. 

Since the Clean Air Act has required the reporting of CO2 emissions from both existingsource EGUs and new-source EGUs for a long time (~15 years), data for each EGU is 

likely available from EPA for establishing baselines for each different EGU and for 

different regulatory groupings of EGUs, depending on which State they are located in, 

and the defined purpose for drawing a “boundary” around that particular regulatory 
grouping (e.g., they are all owned or operated as a system by the same cooperative, 

independent power producer, or state-regulated investor-owned utility). 

Similarly, all operating EGUs and EGRs of all sorts (coal, natural gas, nuclear, 

hydroelectric, wind, solar, geothermal, waste heat, etc.) are required to report their 

MWhs produced each year to the United States Energy Information Administration 

(EIA). So, for example for the year 2010 the total net generation in MWhs from all EGUs 

and EGRs in the United States was approximately 4.125 billion MWhs, and the total net 

retail sales in the United States was approximately 3.754 billion MWhs.

Rate of Emissions. For any generation system, once the TTs and total MWhs 

generated (either gross or net sold at retail) are known, a “rate” of emissions can be 

calculated by dividing TTs by MWhs (TTs/MWhs) to get a rate in tons per MWh for any 

boundary-defined EGU, EGR, or EGS. Further, the rate of emissions in pounds per 

MWh (lbs/MWh) can be calculated for any EGU, EGR, or EGS by multiplying TTs/MWhs 

by 2,000 (the number of pounds in a ton). 

So, for example, an EGU that emitted 75 tons of CO2 in a year to produce 100 MWhs of 

electricity would have a “rate” of emissions in tons per MWh of .75 TTs/MWhs (75/100), 

which can be converted to lbs/MWh by multiplying it by 2,000 (75/100 x 2,000 = 1,500 

lbs/MWh). 

Likewise, for example, an EGS that emitted a combined 5,000 TTs from all the EGUs 

and EGRs within its defined system and produced a combined 10,000 MWhs of 

electricity from its combined EGUs and EGRs would have a “rate” of emissions in tons 

per MWh across the EGS of .50 TTs/MWhs (5,000/10,000), which can be converted to 

lbs/MWh by multiplying it by 2,000 (5,000/10,000 x 2,000 = 1,000 lbs/MWh). 

Determining the amount of achievable reductions from each existing EGU. Since 

111(d) applies to “existing sources” and this rulemaking applies to “existing source” 

EGUs, the required emission reductions are limited to achievable emission reductions 

from existing EGUs as determined by the State according to a procedure and guidelines 

established by EPA in this rulemaking. Further, EPA’s regulations must allow States to 

consider, among other factors, the remaining useful life of the existing EGU, in setting 

the standard of performance. States may be more stringent than EPA’s regulations 

require them to be, so the law appears to allow EPA to give guidance on how that may 

occur, and may also give guidance on how the “best system of emission reduction” may 

go outside the fenceline to achieve required and discretionary reductions in either mass 

or rate of emissions.

Measurement in reduction of rate or mass from a baseline. To measure emission 

reductions (either as a “rate” (TTs/MWhs) or as “mass” (TTs)) from any particular EGU, 

EGR, or EGS, or any set or subset of a group of EGUs, EGRs, and EGSs, it is 

necessary to set a baseline from which a reduction of rate or mass (or both) can be 

measured. States and regulated entities should be given flexibility to choose a baseline 

among several options that best suits a particular EGU or EGS. 
For example, a State, a utility, or a cooperative that has made significant reductions in 

rate or mass of emissions from the President’s suggested baseline year of 2005 (for 

example by either retiring certain facilities or adding significant amounts of low-carbonintensity generation to its portfolio), may opt to choose a reduction in rate or mass from 

a 2005 year baseline, and opt to choose a higher rate or mass of reduction from that 

baseline as its permit standard because of discretionary outside-the-fenceline 

reductions (for example, a percentage (e.g., 10% or 17%) reduction in rate or mass 

across its entire generation fleet of EGUs and EGRs combined into a single EGS, in 

exchange for, perhaps, no reductions inside the fenceline for particular EGUs with 

significant remaining useful life, and that are part of a system with significant growing 

demand for electricity across the entire system). 

But for a single EGU that doesn’t have the option to retire because of significant 

“remaining useful life” and significant recent capital investment to, for example, comply 

with Regional Haze by adding best available retrofit technology (BART), the State 

should be allowed to take such factors into consideration as provided by § 111(d), and 

may opt to choose a reduction in rate or mass from a more recent baseline (say the 

year this rule goes into effect), and opt to choose a lower rate or mass of reduction from 

that baseline as its permit standard for that particular EGU (for example, a percentage 

(e.g., 3%) reduction in rate or mass within the fenceline of that particular EGU based on 

a detailed engineering study and a consideration of the economic and financial factors 

that may be considered under the definition to “standard of performance” that are 

relevant to that EGU and its customers).

A baseline—based on, for example, 2005 or the year this rule goes into effect—may not 

represent “normal source operation” for a particular EGU or EGS. EPA could allow, in 

its regulations, some flexibility in baselines to allow some adjustment for outages or 

other factors that disrupt normal source operation. For example, EPA could develop 

regulations, and States could give regulated entities the option to choose, for any 

particular EGU or EGS, one of these options:

• Baseline mass and rate for each EGU and EGS. For each EGU and EGS:

• The EGU or EGS shall calculate and report the total MWhs produced by 

the EGU or EGS in the baseline year, the TTs of CO2 for each EGU or 

EGS, and the rate of emissions calculated as TTs/MWhs for each EGU or 

EGS, for its baseline year, to the EPA and the State or States with primacy 

over the program.

• Each EGU or EGS may pick as its baseline year any one of the following:

• The year 2005; or

• The highest consecutive twenty-four month average rate and mass 

of emissions between 2004-2006, converted to an annual rate and 

mass; or

• The year the rule becomes effective; or

• The highest consecutive twelve-month average rate and mass of 

emissions taken from the full calendar year this rulemaking 
becomes effective and the full calendar year preceding the 

calendar year that this rule becomes effective.

In summary, the following should be defined and measured for each defined system:

• The boundaries of each EGU or EGS;

• The required emission reduction in mass or rate within the fenceline of each 

existing EGU (most likely an achievable percentage of reduction from a baseline) 

as determined by the State according to regulations promulgated by the 

Administrator; 

• The baseline date and baseline emissions for each defined EGU or EGS;

• Baseline emissions will include original MWhs produced, TTs, and rate of 

emissions within the relevant EGU or EGS;

• A way of periodically reporting current emissions;

• Current emissions will include current MWhs produced, TTs, and rate of 

emissions within the relevant EGU or EGS.

• How should the different system boundaries be defined?

The most important thing that EPA has to build into the design of this rulemaking is to 

allow flexibility both to States, and to regulated utilities, cooperatives, and merchant 

power providers, to define the boundaries of systems so that electricity generation and 

delivery systems can choose the most cost effective way to make emission reductions 

across a system as a whole, while maintaining availability, reliability, and system service 

in accordance with other federal and State laws. Flexibility should be built into the 

system to allow for different boundaries depending on the role of the regulatory body 

under the law, and the facts relevant to the State (pursuant to the Administrator’s 

guidelines) in determining the relevant and appropriate boundaries for each EGU or 

EGS in question.

The point of the lengthy discussion above regarding drawing system boundaries was to 

establish a few of the critical steps in defining a system’s boundary:

• To define a system’s boundaries, first define its purpose. 

• For example, for non-profit electric cooperatives, the purpose of an EGU is 

to provide low-cost, reliable, and available electricity to its memberowners. So to achieve any emission reduction required by the State from 

a defined EGU under this rulemaking, the rule should be designed and 

structured to allow the most-cost effective way to make that reduction 

across a defined system (either an EGU or an EGS).

• Clearly defined boundaries allow measurement of changes in the system.

• In this case, for any EGU or EGS, clearly defined boundaries will allow 

establishment of all the basic things needed to keep this rulemaking 

simple: a baseline year; baseline MWhs, TTs, and rate of emissions; and 

current MWhs, TTs, and rate of emissions, for each EGU or EGS defined 

under a State’s program.

• “Flexibility” becomes more than an empty promise when the rules allow each 
State to set appropriate (and flexible, while remaining clearly defined) boundaries 

for EGUs and EGSs after considering the factors that §§ 111(a) & (d) allow 

States to consider according to procedures and guidelines established by the 

Administrator.

The best way to demonstrate how this may work is to give a hypothetical example.

Example of flexible boundaries for EGU with 20 years of remaining useful life: A 

small, independent utility or cooperative has just one EGU. It is a coal-fired EGU that is 

30 years old, has recently installed BART controls, historically operated at a 90% 

availability and 90% load factor, and, during the year this rulemaking went into effect, 

this EGU generated 100 MWhUnits of electricity, emitted 100 TTsUnits of CO2, so its 

emission rate during the year the rule went into effect was 1.00 TTs/MWh or 2,000 lbs/

MWh. When this EGU is not available, the utility buys the power it needs to serve its 

customers off the power market it is connected to.

The State and the utility agree that the baseline date for this facility will be the year this 

rulemaking went into effect, so this EGU’s baselines are 100 MWhUnits of electricity, 

100 TTsUnits of CO2, and a 1.00 TTs/MWh emission rate. The State has asked the 

EGU for a projection of electricity demand within its service territory, and the EGU has 

predicted its demand will remain stable for the next 20 years. The State has examined 

what efficiency and operational efficiency reductions are achievable within the fenceline 

of the EGU, and has determined that a 5% average reduction in the CO2 emission rate 

is achievable with appropriate technology and operational changes, so the emission 

rate under the permit is established to be .95 TTs/MWh on a three-year-rolling annualaverage basis. Since the load on the system is projected to be stable and the EGU is 

not part of a larger fleet, the EGU will not be operated more often to displace emissions 

form a less efficient coal-fired EGU that is part of a larger EGS. 

The State also determined the remaining useful life of the facility by considering 

appropriate engineering and other factors submitted in a life-assessment study as 

required by the to-be-developed EPA regulations, and determined that the remaining 

useful life of the facility is 20 years. So the EGU will have to reduce both the rate and 

the mass of its CO2 by 5% from the baseline for the next 20 years. Also, as allowed by 

§ 111(a)(1) and EPA’s to-be-developed regulations, the State took into account “the cost 

of achieving such reduction and any nonair quality health and environmental impact and 

energy requirements,” and determined that this facility has been operated efficiently and 

at a very low economic margin (essentially at cost), so to remain economically viable 

through its next 20 years of remaining useful life, it could not be forced by regulation to 

operate at less than 85% availability or 85% capacity, below which levels it becomes 

economically unviable to continue to operate this EGU as a built-for-baseload resource. 

The State gives the EGU 6 months to submit a plan to meet these emission reductions. 

Although EPA’s to-be-developed regulations cannot require it, those regulations allow 

the State and the regulated entity to opt to do periodic review to make adjustments in 
the permit based on changes in the market, new technologies, and other factors through 

the remaining useful life of the EGU. In this case, the State and the EGU agree to opt 

for a periodic review every 5 years.

The utility immediately goes out for bids to make the required 5% efficiency 

improvements required under the State’s proposed 111(d) plan for this EGU. The 

lowest bid will require a minimum $150 million capital investment to achieve the 

required reductions, and the contractor who gave the lowest bid is willing to guarantee 

only a 3% reduction from the EGU. The utility also has the option to secure a 20-year 

contract to purchase wind generation from a wind farm that is being constructed in the 

utility’s service territory. Instead of making the capital improvements, the utility 

proposes in its compliance plan to the State to form an EGS, with 95% of its 100 

MWhUnits load to be supplied by the EGU and the other 5% (5 MWhUnits) supplied by 

a contract to purchase power from the new wind farm. Although the EGU still emits at 

the rate of 1.00 TTs/MWh, the combined wind-contract and EGU form an EGS that 

emits at the state-required rate of .95 TTs/MWh [(95 MWhUnits x 1.00 TTs/MWh) + (5 

MWhUnits x 0.00 TTs/MWh) = 95 TTsUnits/100 MWhUnits = .95 TTs/MWh]. The State 

approves this plan.

Five years later, the periodic review shows a 5% growth in load within the EGU’s service 

territory. The utility proposes to amend its plan to include 5 MWUnits of combined solar/

natural gas simple-cycle peaking power within its EGS. The State agrees to let them 

add these 5 MWhUnits at a combined solar/gas CO2 intensity rate of .25 TTs/MWhs, so 

the combined CO2 intensity allowed across the EGS’s entire 105MWhUnit load is now 

an emission rate of .9166 TTs/MWhs [(5 x .25 TTsUnits solar/gas) + (100 x .95 TTsUnits 

coal/wind) = 96.25 TTsUnits/105 MWhUnits = .9166 TTs/MWhs].

Five years later, the periodic review shows a combined projected 20 MWhUnit load 

growth in the Utility’s service territory, so the utility proposes to amend its EGS to 

include an additional 20 MWUnit natural gas combined-cycle unit at a CO2 intensity rate 

of .50 TTs/MWhs. The State agrees to this and amends the EGS to allow an emission 

rate across the entire EGS of .85 TTs/MWhs [(5 x .25 TTsUnits solar/gas) + (100 x .95 

TTsUnits coal/wind) + (20 x .50 TTsUnits gas/combined-cycle) = 106.25 TTsUnits/125 

MWhUnits = .85 TTs/MWhs].

Finally, there is a projected 10 MWhUnit load decline in the Utility’s service territory for 

the final 5-year periodic review under the 20 year remaining useful life of the EGU. 

Because the EGU is nearing the end of its remaining useful life, the utility submits a 

plan revision to address this shrinking load by agreeing to make this reduction at the 

EGU, provided the State allows it to keep its emission rate of .95 TTs/MWh for the 

combined coal/gas resource. The State agrees to this plan, so the emission rate over 

the final five years of the 20-year-remaining-useful-life plan for the EGU/EGS is .8413 

TTs/MWhs [(5 x .25 TTsUnits solar/gas) + (90 x .95 TTsUnits coal/wind) + (20 x .50 

TTsUnits gas/combined-cycle) = 96.75 TTsUnits/115 MWhUnits = .8413 TTs/MWhs].

At the end of its remaining useful life, the EPA and the State have adopted regulations 
which now allow them to evaluate GHG BACT across an entire EGS, rather than on a 

source-by-source basis. The projected MWhUnit load for the next ten years is 120 

MWhUnits, and the State determines that for similarly-sized EGSs with similar 

resources, BACT for the EGS as a system is an emission rate of .40 TTs/MWhs. The 

utility proposes a mix of wind, solar, nuclear, and natural gas resources that meets this 

BACT requirement, but to cost-effectively provide for reliability when these resources 

aren’t available, the original EGU needs to be available for emergencies and pipeline 

and plant outages. The State approves a plan with an emission rate of an emission rate 

of .40 TTs/MWhs which allows the original EGU to run up to 8 MWhUnits during the first 

five years, and 4 MWhUnits the second five years, with an opportunity to petition for 

more MWhUnits if the original EGU retrofits to co-fire with natural gas or biomass.

In sum, as this example shows, the ability to form an EGS may allow the option to 

average down the rate and mass of emissions over an EGU’s remaining useful life in a 

cost-effective manner. This option may also allow resources to transition to a lowercarbon-intensity mix of resources over time, with less initial and overall economic impact 

to the EGU and its customers. Thus, this is an option that EPA should consider building 

into the design of this rulemaking.

EPA’s role. EPA’s primary role under §§ 111(a) & (d) is to establish procedures and 

guidelines that will give the flexibility to States and regulated utilities to make 

meaningful, cost-effective reductions in the rate and mass of CO2 emissions, while still 

providing reliable and affordable electricity to customers. Flexible boundaries (in both 

space and time—see above example) are the key to innovation, and to responding to 

changes in the system over time.

State’s role. The State’s primary role is to examine each EGU separately to determine 

remaining useful life and achievable emission reductions within the fenceline of each 

EGU. The State should also examine electricity generation, transmission, and 

distribution systems as a whole, and determine, based on procedures and guidelines 

adopted by the Administrator, ways to use flexibility to make meaningful and costeffective reductions across systems (EGSs) as a whole.

A baseball analogy. Baseball scouts can make statistical comparisons between 

players, teams, and leagues by tracking the same statistical factors for each player, 

team, and league.

For example, slugging percentage is calculated by adding up the total bases (combined 

bases from singles, doubles, triples, and home runs) for a player, team, or league, and 

dividing that by the total at-bats for a player, team, or league. 

Similarly, carbon intensity is calculated by adding up the total tons of CO2 emitted (e.g., 

wind, solar, natural gas, coal, nuclear) for an existing unit, company, state, or region, 

and dividing that by the total MWhs produced by an existing unit, company, state or 

region. 

A baseball commissioner or fan can calculate the slugging percentage for any player, 
group of players, team, group of teams, league or group of leagues simply by adding up 

the total bases for any player or group, and dividing that total by the total at-bats for any 

player or group. 

Similarly, the EPA, States, and companies can calculate carbon intensity by adding up 

the total tons of CO2 emitted (e.g., wind, solar, natural gas, coal, nuclear) for a unit, 

company, state, or region, and dividing that by the total MWhs produced by a unit, 

company, state or region.

A baseball commissioner or fan can also calculate the total bases for any player, group 

of players, team, group of teams, league, or group of leagues simply by adding up the 

total bases for any player or group. Similarly, the EPA, States, and companies can 

calculate the total tons of CO2 emitted (e.g., wind, solar, natural gas, coal, nuclear) for a 

unit, company, state, or region, simply by adding them up for any resource or group of 

resources.

A baseball commissioner can change the average slugging percentage for players and/

or teams by changing any number of factors: how high the pitching mound is, how close 

it is to the plate, how hard the baseball is, what types of bats are allowed, how close or 

far away the fences are in any park, whether the league tests for performance 

enhancing drugs, how old the players are, how many games are played each season, 

etc. Then, the commissioner can compare how those changes have impacted slugging 

percentage and total bases in his or her league compared to other leagues, and make 

additional appropriate changes for the good of the game as a whole, and in this 

particular league.

There are two points to be made about this analogy as it applies to existing-source 

generation. 

First, by focusing on two simple factors—TTs emitted and MWhs produced—

comparisons between units, companies and States becomes simple. Further, it is not 

double counting to look at different groupings (different boundaries) for different 

purposes. For example, looking at an existing source’s rate of, and total, emissions 

standing alone, does not preclude looking at those same emissions as parts of larger 

groups (e.g., an EGS, or all of the generation resources located within a State)—any 

more than looking at a single player’s slugging percentage and total bases standing 

alone precludes looking at his slugging percentage and total bases as part of a team 

and league as a whole. 

Second, allowing States maximum flexibility to explore different ways to reduce the 

mass and rate of emissions within their State will, most likely over time, reveal the most 

efficient ways to reduce emissions—which will be different in different states and 

regions because the mix, age, and type of systems and resources are different in each 

State and region. At some point, Congress may choose to set a policy for the nation as 

a whole. At that point, they will have much data and many alternatives to compare, 

which may allow Congress appropriately design the next revision of the Clean Air Act to 

specifically address greenhouse gases in the best way on a national and global scale. 
In short, flexibility and experimentation at this stage is not a bad thing.

For example, power hitters’ slugging percentages may go up in leagues that would limit 

them to 3 at-bats per game (they would no longer have to face fresh, specialized relief 

pitchers at the end of each game), but their total numbers of doubles and home runs 

would likely decrease. Likewise, coal resources that are backed down for wind, for 

example, will most likely increase their rate of emissions (because they are less efficient 

in TTs/MWh when running at less than full load), but would most likely decrease their 

total mass of emissions in tons.

The key to allowing these different approaches is to allow flexibility in drawing and 

changing boundaries around groups of resources to allow the most efficient “system” to 

evolve and change over time as the circumstances affecting the system change over 

time, while at the same time keeping the purpose of the rules and rule-changes in mind

—e.g., (in a baseball purist’s league) reducing the slugging percentage or total bases 

across a league, or (on a carbon-intensity-lowering system) the rate or tons of 

emissions across a system. 

• The meaning of the phrase “emission reduction” 

The previous sections have explored options for interpreting the word “system” in the 

phrase “best system of emission reduction” in § 111(a)(1). The noun phrase “emission 

reduction” will be explored with much more brevity in this section. 

An “emission reduction” can be either a reduction in the rate of emissions, in the mass 

of emissions, or both. Under § 111(b), the standards of performance established by EPA 

have generally been achievable rates of emissions based on available pollution control 

technologies. 

It would seem to follow that one of the options EPA should give to States under the 

procedure and guidelines established by this rulemaking should be to allow States to 

set rate-based standards of performance for CO2 emissions from existing EGU 

sources. 

But for reasons explained above and below, it may sometimes make more sense to 

allow the option to set mass-based standards of performance, especially when an 

existing source is operating at less than full load for whatever reason. An example 

given above is a coal unit that is being backed off from full load for wind generation: in 

such a case, its rate of emissions is likely to go up in TTs/MWhs because it is less 

efficient at lower loads than at full load, but its mass of emissions is likely to go down 

because of overall fewer MWhs generated (and less fuel used to generate those 

MWhs). In such a circumstance, a State should be allowed to change the rate of 

emissions depending on the percent of capacity being used while operating, or to allow 

the utility to form an EGS, so the rate of emissions can be averaged across the system 

as a whole.
Although Chevron deference generally applies to an agency’s interpretation of the 

scope of its authority when a statute is ambiguous, “[w]here Congress has established a 

clear line, the agency cannot go beyond it; and where Congress has established an 

ambiguous line, the agency can go no further than the ambiguity will fairly allow.”

In this case, the noun phrase “emission reduction” would fairly allow the EPA 

Administrator to set up a set of procedures and guidelines that would allow States to set 

standards of performance that are either rate-based or mass-based or both. Further, 

the regulations should allow different kinds of EGSs to allow emission reductions not 

only at EGU levels, but also across systems as a whole. This will allow States and 

utilities to identify the most efficient and cost-effective emission reductions while 

preserving the ability of systems as a whole to provide reliable and affordable electricity 

to customers.

• Comments regarding the different kinds of issues facing regions, states, 

companies, and sources.

• Differences between systems in equilibrium, shrinking systems, and 

growing systems.

There are essentially three types of systems: systems where inflows exceed outflows 

(growing systems); systems where outflows exceed inflows (shrinking systems); and 

systems where inflows and outflows are approximately equal (systems in equilibrium). 

For this rulemaking, there are different kinds of issues for EGUs with stable demand for 

electricity in their service territories, those with declining demand, and those with 

growing demand.

• EGUs with stable demand for electricity.

For EGUs with stable demand for electricity, a rate-based measurement of emission 

reductions is interchangeable with a mass-based measurement. As the “Example of 

flexible boundaries for EGU with 20 years of remaining useful life” above shows for the 

first five-year period, a 5% reduction in the rate of emissions equals a 5% reduction in 

the mass of emissions. As that example shows, even in that case the most costeffective way to make reductions may be to allow the formation of an EGS to make the 

reductions across a larger system.

• EGUs with declining demand for electricity.

 An EGU standing alone may experience declining demand for numerous reasons:

• An economic recession, declining population, industries moving or changing, or 

other similar demand-affecting developments in its service territory.

• Demand displacement and fuel displacement by wind, solar, natural gas or 

another lower-carbon-intensity resource.

• Mega-watt hours (MWhs) avoided because of efficiency, smart grid, and other 

demand-side management (DSM) measures.
As noted several times above, when a coal resource is backed down to less than full 

load by wind or another non-fossil-fuel resource, its rate of emissions is likely to go up 

because at lower loads rates of emissions in TTs/MWhs are likely to go up, while the 

mass of emissions in total tons are likely to go down. The EPA Administrator’s 

procedures and guidelines under this rulemaking should allow States to use a massbased approach for declining demand areas, because that may be the most efficient 

way to reduce emissions in such areas.

Further, whether fuel displacement for a fossil-fuel form of generation is occurring 

because of wind, solar, or DSM, the EPA Administrator’s procedures and guidelines 

under this rulemaking should allow States the option to use those avoided emissions as 

part of an EGS, to average those emissions down across an entire system. If new, 

carbon-free resources are not allowed to be considered, it will be impossible for existing 

sources to displace emissions by adding new green resources to cost-effectively 

displace CO2 emissions from existing high-carbon-intensity EGUs, or to bring down 

rates or masses of emissions down across an entire generation fleet. So it is critical 

that the EPA Administrator allow States to choose such options in her procedures and 

guidelines.

• EGUs with growing demand for electricity.

In areas with growing demand for electricity, it is easier to average the rate of emissions 

down across an EGS by adding new low-carbon intensity generation resources, but 

nearly impossible to reduce the mass of emissions in an area of high load growth. This 

is easiest to show by an example.

Example: Imagine the same coal-fired EGU that is 30 years old, has recently installed 

BART controls, historically operated at a 90% availability and 90% load factor, and, 

during the year this rulemaking went into effect, this EGU generated 100 MWhUnits of 

electricity, emitted 100 TTsUnits of CO2, so its emission rate during the year the rule 

went into effect was 1.00 TTs/MWh or 2,000 lbs/MWh. However, in this case its load is 

projected to grow 100% in the next five years, to 200 MWhUnits. To meet this load 

growth, the utility or cooperative proposes to build 125 MWUnits of wind that will 

operate at a projected 40% capacity (for a net 50 MWhUnits of annual wind production 

at 0.00 TTs/MWhs carbon-intensity) backed up by 100 MWUnits of simple-cycle and 

combined-cycle natural gas capacity (at 0.50 TTs/MWhs carbon-intensity run on 

average at 50% capacity across the fleet to back up the new wind generation), so that 

the average carbon-intensity to meet the 100 MWhUnits of load growth will be 0.25 TTs/

MWh or 500 lbs/MWh.

If an EGS is formed with the existing EGU, the mass of emissions across the entire 

EGS will increase to 125 TTs (100 TTUnits from the coal EGU plus .25 TTUnits from the 

new natural gas/wind combination), but the rate of emissions will decrease across the 

entire EGS from 1.00 TTs/MWh (2,000 lbs/MWh) to 0.625 TTs/MWh 1,250 lbs/MWh) 

(i.e., 125 TTUnits/200 MWhUnits). Then, when the existing EGU reaches the end of its 
remaining useful life, it can be replaced with a lower-carbon-intensity resource or set of 

resources. In load-growth areas, this approach will allow the transition of the 

combination of resources serving an area from high-carbon-intensity to low-carbonintensity without causing stranded investment or premature retirement of resources with 

significant remaining useful life.

• The “major modification” issue. 

The Administrator did not address “major modifications” to existing sources in setting 

CO2/GHG performance standards under § 111(b) for new sources. Several issues 

relating to new source review (NSR) need to be addressed in this § 111(d) “existing 

source” rule and its proposed guidelines for States:

• Is a technology GHG-emission-reduction efficiency improvement by definition a 

“major modification”? If it is not a major modification, it is excluded from new 

source review (NSR).

• Is a “method of operation” change within an EGS that results in a reduction of 

emissions across the EGS system as a whole, even though an “existing source” 

that has undergone a major efficiency improvement may, standing alone, 

increase the mass of its emission at the same time that its rate of emissions 

decrease?

• Example: an existing coal-based EGU that is part of a fleet of coal-based 

resources undergoes a major efficiency improvement that increases its 

efficiency 5 percent. Because it now it the most-fuel-efficient coal 

resource on the fleet and produces the same amount of electricity using 

less fuel than other resources, and also because operating it more than 

other resources will bring the average rate of emissions down across the 

entire fleet, Company A or the RTO (regional transmission organization) of 

which it is a part, call on it to operate at higher loads more of the time than 

other resources in the fleet. The result is:

• A lower “rate” of emissions from the now-more-efficient existing 

source;

• An increase in the “mass” of emissions from the same now-moreefficient existing source because it is called on to operate at higher 

loads and more often than it was before the efficiency 

improvements;

• A decrease in both “mass” and “rate” of emissions across the entire 

coal fleet, because the more efficient coal generation resource is 

now displacing the less efficient coal resource in the operation of 

the fleet as a whole.

• The transferable “market-based instruments” issue.

The President’s June 25th order requires the EPA administrator to look at ways to allow 

“market-based instruments” as part of this rulemaking. The easiest way to allow 
“market-based instruments” is to allow the transfer of any MWh of generation between 

any two EGSs only if it is transferred with the carbon-intensity of the generation that 

produced it.

Example: An EGS last year produced 50 MWhUnits of natural-gas-based power at a 

carbon-intensity of 0.50 TTs/MWhs, and 51 MWhUnits of wind-based power at a carbonintensity of 0.00 TTs/MWhs. Since this EGS’s State permit requires it to meet a carbonintensity of 0.25 TTs/MWhs, the EGS can trade the extra 1 MWhUnit of wind-based 

power and still meet its permit rate-based limit. So the first EGS transfers this 1 

MWhUnit with a carbon-intensity of 0.00 TTs/MWhs to another EGS that needs to 

average down the rate of emissions across its system that year. Even after it makes 

this transfer, the first EGS still meets its permit rate requirement of 0.25 TTs/MWhs. 

This type of system will reward an EGS that produces extra low-carbon-intensity power, 

and make that extra production an asset that can be traded or transferred with the sale 

of the low-carbon-intensity power.

The key to making a market-based instrument program work is 1) to allow the transfer 

of any MWh of generation between any two EGSs only if it is transferred with the 

carbon-intensity of the generation that produced it, and 2) to allow each EGS to include 

all forms of generation, new and existing, when that generation begins to commercially 

produce power to the grid. To work, the Administrator’s guidelines cannot allow States 

to come up with complicated formulas that favor in-state resources over out-of-state 

resources according to complicated formulas that are not directly proportional to the 

carbon-intensity of the generation resource that produces any particular MWh of power.

A workable system will not give double credits or half credits or any other inaccurate 

measure of the carbon-intensity of the resource that produces it.

• The potential “clean coal” efficiency penalty.

Pollution control equipment requires electricity (or sometimes heat energy) to run it. 

This creates a parasitic load that reduces the efficiency of a pollution-controlled EGU 

compared to an EGU without controls. The EPA administrator should consider 

regulations that will not punish the EGU that uses pollution control by making it less 

efficient.

Example: An EGU produces 100 MWhUnits of electricity without pollution controls. It 

adds pollution controls and still produces 100 MWhUnits of electricity, but now 5 

MWhUnits of its electricity runs pollution control equipment on the EGU. If net 

MWhUnits produced are used to measure efficiency in TTs/MWhs, this EGU’s rate of 

emissions will increase approximately 5%. If the EPA Administrator’s regulations allow 

the gross MWhs produced to be the measure of efficiency in this case, this EGU’s rate 

of emissions will stay the same, and it will not be punished for putting on pollution 

control equipment. 

It is important that this regulation not punish EGU’s for having pollution control 

equipment, so the energy that goes toward pollution control should be included in the 

denominator in calculating the carbon intensity of any EGU when calculating rate as 
TTs/MWhs.

• When should a new source be considered part of the EGS? 

A new source may be added to an EGS when the State approves the inclusion of that 

source in the EGS as part of its permit to construct (by determining that when the 

resource becomes commercially operational, the new source shall at that time become 

a part of the EGS). This will allow the system as a whole to achieve the targets and 

goals set by the State in its plan, its Title V permit to operate, and the State’s 111(d)(1) 

implementation plan. Failure to include new resources as part of the operating system 

will bias system operation and create perverse feedback loops that will make rational 

and prudent operation of the system as a whole impossible because new low-carbonintensity resources would not be available to average down emissions across an EGS 

as a whole. 

• Summary of components and elements of a program that would 

address all of the above issues

• Simplicity and Flexibility. To be flexible yet consistent in tracking the mass and 

rate of emissions from each source (EGU) and electricity generation system 

(EGS), the tracking system must be simple and uniform. To be flexible, the 

system must be simple, at least in terms of what is reported and tracked.

• What is reported and tracked. For each EGU and EGS, the following must be 

tracked and reported to the EPA and to the State with primacy over the program 

where an EGU or EGS (or portion thereof) is located:

• Each EGU must report:

• The gross and net megawatt hours (MWhs) produced on a 

quarterly and annual basis. Gross MWhs are the total MWhs 

produced by an EGU, including MWhs used “inside-the-fence” for 

station service and pollution control equipment, technologies, and 

efficiency measures. Net MWhs are the total MWhs sent by 

transmission and distribution to customers, after subtracting MWhs 

used for station service (but not pollution control).

• Total mass of CO2 emissions (reported in tons, or fractions thereof)

—total tons (TTs)—produced by the EGU on a quarterly and annual 

basis.

• Total MWhs (or fractions thereof) avoided because of efficiency, 

pollution control, and other demand-side-management (DSM) 

measures taken inside-the fence of the EGU, and the TTs avoided 

by such efficiency, pollution control, and other DSM measures, on a 

quarterly and annual basis. 

• Consistent accounting procedures must be developed to assure 

accurate accounting between and among EGUs and EGSs of total 

gross and net MWhs and TTs produced and avoided at each EGU 

and across each EGS as a whole.

• Each EGS must report:
• The gross and net combined MWhs produced separately by each 

EGU or other electricity generation resource (EGR) on its system 

such as wind, solar, hydro, nuclear, geothermal, waste heat, or 

other non-CO2-emitting form of generation, and the combined 

gross and net combined MWhs produced across the entire system, 

on a quarterly and annual basis.

• Total mass TTs of CO2 produced by each EGU, and each EGR on 

its system (even if zero), on a quarterly and annual basis, and the 

total combined mass in TTS of all EGU and EGRs combined within 

its system on a quarterly and annual basis.

• Total combined MWhs (or fractions thereof) avoided because of 

efficiency, pollution control, and other DSM measures taken insidethe fence by each EGU and each EGR, and the total combined 

mass of CO2 emissions avoided by such efficiency, pollution 

control, and other DSM measures by all EGUs and EGRs within the 

EGS combined, on a quarterly and annual basis. 

• Total MWhs (or fractions thereof) avoided because of efficiency, 

pollution control, and other DSM measures taken by each 

transmission system, distribution system, and customer thereof 

within the EGS as a whole, and by each subsystem within the EGS, 

and the total combined mass in TTs of all CO2 emissions avoided 

by such efficiency, pollution control, and other DSM measures by all 

transmission systems, distribution systems, and customers thereof 

within the entire EGS combined, on a quarterly and annual basis.

• Consistent accounting procedures must be developed to assure 

accurate accounting between and among EGUs, EGRs, 

transmission systems, distribution systems, and customers thereof 

of total gross and net MWhs and TTs produced and avoided:

• at each EGU, EGR, transmission system, distribution 

system, and customer thereof, separately; and

• For each EGS system separately (i.e., each EGS will have a 

separate combined total), the total combined gross and net 

MWhs and TTs produced and avoided by all generation, 

transmission, distribution systems (and their qualified 

customers) across the entire EGS as a whole.

• How “emission reductions” are tracked. States may track emission reductions 

for each EGU, and each EGR or EGS or part thereof (if within its borders), either: 

• on a rate basis (calculated in TTs divided by MWhs (TTs/MWhs), 

converted, if so desired, into pounds per MWh (lbs/MWh)); or

• on a mass basis (calculated in TTs or fractions thereof); or

• a combination of both; provided that

• rates and masses are tracked and calculated according to the guidelines 

adopted by the EPA Administrator and approved in the State’s plan.

• For EGUs or EGSs that are serving areas with growing demand for 

electricity, it may be more appropriate to track emission reductions on a 
rate basis, but each State that uses a pure rate-based system to track 

emission reductions from EGUs and EGSs much also track and report the 

total mass of emission reductions in TTs displaced by the EGU or EGS by 

efficiency improvements by comparing and calculating:

• the current rate of emissions in TTs/MWhs for the EGU or EGS with 

the baseline rate of emissions TTs/MWhs for the same EGU or 

EGS; then 

• calculating the TTs of CO2 displaced by the current rate of 

emissions from the EGU or EGS compared to the original baseline 

rate of emissions from the EGU or EGS by:

• 1) multiplying the current year’s MWhs times the original 

baseline rate of emissions to come up with the current TTs at 

baseline rate (this number is the total tons of CO2 that would 

have been emitted from the EGU or system if it had 

continued to produce electricity at its baseline rate of 

emissions); and

• 2) multiplying the current year’s MWhs times the current rate 

of emissions (in TTs/MWhs) to come up with the current TTs; 

then

• Subtract 2) from 1).

• For EGUs or EGSs that are serving areas with stable demand for 

electricity, calculating mass and rate should be interchangeable.

• For EGUs or EGSs that are serving areas with diminishing demand for 

electricity, it may be more appropriate to track emission reductions on a 

mass basis.

• For EGSs that cross state boundaries, the EPA should develop guidelines 

for tracking the changes in mass and rate of emissions for the EGS and 

subsystems within the EGS that are within more than one State’s borders, 

and that therefore may be subject to potentially different requirements 

from different States.

• Determining “emission reductions” from EGUs and EGSs. A State or 

regulating body may determine emission reductions from an EGU, an EGS, or a 

subsystem within an EGS, either:

• On a rate basis; or

• On a mass basis; or 

• A combination of rate and mass, depending on the EGU or the EGS, 

• according to guidelines promulgated by the EPA Administrator and each 

relevant State’s implementing laws, regulations, and plan.

• The reduction required shall be a percentage (___%) reduction from the 

baseline year, and may be either a reduction in the rate of emissions, or 

the mass of emissions, or a combination of both, as determined by the 

State or regulating body, pursuant to guidelines promulgated by the EPA 

Administrator and each relevant State’s implementing laws, regulations, 

and plan.

• The percentage (___%) reduction in rate or mass that a State has the 

option to choose for a baseline date of 2005 is anticipated to be higher 
than the reduction in rate or mass for a baseline date that is selected 

based on the year the rule becomes final. The Administrator should 

include in the guidelines different ranges and factors that should be used 

for the different baseline choice options.

• The Administrator may include in the guidelines options for States to 

consider avoided emissions.

• Comments on EPA’s September 23, 2013 questions asked in 

“Considerations in the Design of a Program to Reduce Carbon Pollution 

from Existing Power Plants”

• What is state and stakeholder experience with programs that reduce 

CO2 emissions in the electric power sector?

State and stakeholder experience with programs that reduce CO2 emissions are as 

varied as the types, ages, and forms of pollution control on various existing EGUs, the 

different types of ownership, financing, and markets (growing, stable, & declining) where 

EGUs are located, and the different types of renewable portfolio standards that each 

State has or doesn’t have that may or may not apply to EGU located in a particular 

State. Since existing programs are so varied, simplicity and flexibility are the keys to 

designing a workable program.

Most states have either mandatory or voluntary renewable portfolio standards as the 

EIA map below shows.

Once a renewable resource is producing electricity, it tends to be used in preference to 

any existing fossil-fuel based EGU in operation for two reasons: it has no fuel cost; and 

usually wind contracts include take or pay provisions, so if a wind resource is available, 

the utility or cooperative with a contract to purchase the wind resource has an obligation 

to purchase power whenever it is available and being produced. For example, as this 

December 2, 2013, EIA graph of generation for Texas shows, wind power continues to 

grow in States with RPSs.
• What actions are states, utilities, and power plants taking today that reduce CO2

emissions from the electric power system? How might these be relevant under 

section 111(d)?

Answer: In general, when wind power or other renewables are added to a 

system, they tend to displace existing fossil-fuel generation by either causing 

them to back down when they are coal resources, or shut down when they are 

simple-cycle gas resources. So it is critical that EPA adopt regulations that allow 

systems that are making these reductions to get credit for them. The electric 

generation system (EGS) option described in this whitepaper is one way that 

EPA could allow this in its regulations by allowing any renewable resource added 

since the baseline date to count as a fuel-displacing resource for an EGS that 

allows the rate and mass of emissions to be reduced across a clearly defined 

system.

• What systems do states and power plants have in place to measure and verify 

CO2 emissions and reductions?

Answer: States with primacy require all major sources of greenhouse gases 

(GHGs)as defined by the tailoring rule to report CO2e GHG emissions. Further, 

almost all major source EGUs have continuous emission monitoring systems 

(CEMS) to measure CO2 emissions on a continuous basis. In addition, EGUs 

must report their megawatt hours produced to the EIA on an annual basis. 

These two reporting requirements together allow the establishment of baselines 

and the tracking of the mass and rate of CO2 emissions from EGUs on a TTs/

MWhs basis as suggested in the whitepaper above.

• How do state programs and measures affect electricity generation and emissions 

at a regional level? How are interstate effects accounted for when measuring the 

progress of a state program? For example, are the multi-state effects of state 

renewable portfolio standards, induce energy efficiency resource standards, 

emissions performance standards, and emissions budget trading programs 

currently accounted for by the state, and if so, how?

Answer: For the reasons discussed above, once renewable resources become a 

part of the system, they tend to displace existing fossil fuel generation when they 

are producing electricity. Since most large systems cross State lines, they tend 

to displace emissions across the entire system, since resources on the system 

generally dispatched according to their cost, which on a system with many types 

of generation is often determined largely by fuel cost. 

To most cost-effectively run their generation fleets, the EPA Administrator’s 

procedures and guidelines under this rulemaking should allow multi-state utilities 

and cooperatives to set up EGSs that allow utilities and cooperatives to make 

reductions in the rate or mass of CO2 emissions across their entire fleet in the 
most efficient and cost-effective manner. The guidelines should discourage 

States from taking actions or designing regulations that violate the dormant 

Commerce Clause or that illegally regulate wholesale electricity sales that cross 

state lines. For example, if a wind resource in one State has a potential capacity 

factor of 45% or higher, and in another State has a wind resource with a potential 

capacity factor of only 30% or less, the utility should be allowed to choose the 

most cost-effective wind resource for its system, and not be forced to choose a 

less efficient renewable generation resource State’s renewable portfolio standard 

discriminates against an out-of-state resource. 

• How should EPA set the performance standard for state plans?

Preceding sections of this whitepaper outline in detail different considerations and 

factors that ought to be considered for inclusion in the procedures and guidelines that 

the EPA Administrator will promulgate through this rulemaking to guide each State’s 

determination of the appropriate standard of performance for each existing EGU within 

its borders. 

• Which approaches to reducing CO2 emissions from power plants should be 

included in the evaluation of the “best system of emission reduction” that is used 

to determine the performance level(s) that state plans must achieve? Should the 

reduction requirement be source- or system-based?

Answer: The phrase “best system of emission reduction” has to be interpreted in 

the context of the rest of the definition of “standard of performance” in § 111(a)

(1), and the obligation of the State to determine the “standard of performance” for 

each “existing source” EGU under § 111(d)(1), including the ability to consider the 

“remaining useful life” of the EGU “among other factors.” Further, the standard 

under the definition at §111(a)(1) must reflect “the degree of emission reduction 

achievable through the application of the best system of emission reduction.” In 

addition, under the definition of “standard of performance,” the Administrator 

must determine that the “best system of emission reduction” has been 

“adequately demonstrated.” Finally the § 111(a(1) definition requires both the 

Administrator and the State to “tak[e] into account the cost of achieving such 

reduction and any nonair quality health and environmental impact and energy 

requirements” in determining a standard of performance. In sum, 1) “the degree 

of emission reduction” required under the standard of performance for the 

existing EGU must be “achievable through the application of the best system of 

emission reduction,” 2) “adequately demonstrated,” 3) ““tak[e] into account the 

cost of achieving such reduction and any nonair quality health and environmental 

impact and energy requirements,” and, under 111(d)(1), 4) allow the State to 

consider “the remaining useful life” of the EGU “among other factors.” 
As discussed in detail above, these statutorily defined “limiting factors” require 

the State to look inside the fenceline to determine “the degree of emission 

reduction” that is “achievable through the application of the best system of 

emission reduction” for a particular EGU. But also, as discussed in detail above, 

States should be given the discretion under the implementing procedures and 

guidelines to look outside the fenceline for the ways to make the reductions in the 

most efficient and cost-effective way. The suggested way to do this is to allow 

the option to make reductions across an EGS rather than an EGU to make 

reductions that are “achievable through the application of the best system of 

emission reduction,” which in many cases may be a method of operation across 

an EGS rather than a pollution control technology.

In short, the rule should be designed to give States the option to make reductions 

for an identified EGU that are either source- or system-based after considering 

the factors set forth in §§ 111(a)(1) & 111(d)(1). 

• How does the amount of flexibility that states are given to include different types 

of programs in their state plans relate to the “best system of emissions reduction” 

that is used to set the performance bar for state plans? For example, if state 

standards to improve end-use energy efficiency were included in state plans, 

should EPA consider potential improvements in end-use energy efficiency in 

setting the performance target for states?

Answer: As discussed in the answer to the set of questions above, the phrase 

“best system of emissions reduction” has to be interpreted in the context of the 

rest of the statute of which it is a part to determine its meaning. In that context, 

States should be given flexibility to set achievable standards of performance for 

existing EGUs, and allow States, utilities and cooperatives options so that EGUs 

and EGSs can achieve those reductions in the most cost effective way, while 

continuing to provide affordable and reliable electricity to their customers.

Within that context, fuel displacement by the use of wind or other renewables, as 

well as fuel displacement by demand side management, should be available 

options allowed to States under EPA’s guidelines for making emission reductions 

for a defined EGU as part of a defined EGS that adequately documents such 

reductions according to EPA’s guidelines and the State’s 111(d) implementation 

plan. 

• What should be the form and specificity of the performance level(s) in EPA 

guidelines? (Rate-based or mass-based? Separate levels for each subcategory 

of sources, or one level for the covered sources in the state? A uniform national 

level, or different levels by state/region based on an established evaluation 

process?)

Answer: As discussed throughout this whitepaper, EPA’s role under § 111(d) is to 

set a procedure and guidelines for States to determine standards of performance 

for existing EGUs. Further, as the legal design section of this whitepaper 
summarizes, the role of EPA under § 111(b) is opposite to its role under § 111(d). 

Under § 111(b), the authority of States to set standards of performance for new 

sources is clearly preempted, and EPA sets one national “Federal” standard of 

performance (a single emission rate standard for a defined category) that applies 

to all “new sources” as defined in § 111(a) in that category. In contrast, under § 

111(d), the authority of States to set standards of performance for new sources is 

clearly not preempted, but rather is preserved and retained by the States, and 

the role of EPA under § 111(d) is to develop a “procedure” and “regulations” 

under which States, not the EPA, set “standards of performance” for “existing 

sources,” also as defined in § 111(a). Therefore, any regulation that attempts to 

set a “standard of performance” at a “uniform national level,” as suggested in the 

last question above, would clearly not pass muster under step one of Chevron

analysis, because it is clearly contrary to the plain language of § 111: under § 

111(b), EPA sets a single “Federal” standard of performance (an emission rate) 

that applies to all sources in a category; under § 111(d), States set multiple 

standards of performance for existing sources according to a “procedure” and 

“regulations” promulgated by the EPA Administrator. So, in summary, what § 

111(d) allows is some form of the second half of the last question above: 

“different levels by state/region based on an established evaluation process.”

However, the EPA Administrator’s role in setting “procedure” and “regulations” is 

a significant one, although different than her role under § 111(b). As discussed in 

this whitepaper above, the phrase “emission reduction” as used twice in the 

phrase “the degree of emission reduction achievable through the application of 

the best system of emission reduction” in the definition of “standard of 

performance” at § 111(a)(1), is broad enough to allow either a rate-based or a 

mass-based approach, or both. Further, as discussed above, in areas 

experiencing rapid load growth, a “rate-based” approach makes the most sense, 

because the “rate” of emissions can more easily be reduced by adding lowcarbon-intensity forms of generation (singly or together, as in a wind/natural gas 

combination), but the “mass” of emissions from such an area is nearly impossible 

to reduce because of the rapid load growth. In contrast, in an area experiencing a 

shrinking demand for electricity, it may be easier to reduce the “mass” of 

emissions, because less fossil-fuels are being consumed, but the “rate” of 

emissions may actually increase in such areas because, at less than full loads, 

fossil-fuel generation will emit CO2 at a higher “rate” in TTs/MWh or lbs/MWh—

significantly so when loads are backed to three-quarters or half-load or less. 

Thus, it is of the utmost importance in this rulemaking to give States the flexibility 

to use a rate-based standard in areas experiencing rapid electricity load growth, 

and a mass-based approach in areas experiencing a decline in demand. (And 

sometimes the decline in demand for a particular EGU is caused by the addition 

of wind or other low-carbon-intensity forms of generation as part of an EGS as 

discussed in several places in this whitepaper.)

Further, as described in this whitepaper above, the best “form” to use in this 

rulemaking is to allow a standard that requires a percentage reduction in rate or 
mass from a baseline established for each existing EGU, and, to most costeffectively make those reductions, allow the displacement of emissions from 

high-carbon-intensity existing sources by new low-carbon-intensity generation 

resources (as currently required by many State RPSs). This is an “adequately 

demonstrated” method, as required by § 111(a)(1), for reducing emissions as 

shown, for example, in data and numerous EIA graphs at this link: http://

www.eia.gov/environment/emissions/carbon/?src=email. 

In summary, this rulemaking will allow the maximum flexibility, and be simplest to 

promulgate and develop in the ambitious timeframe set forth in the President’s 

order, by tracking only a couple factors (TTs and MWhs for each EGU and EGS), 

and giving States maximum flexibility to continue on the path that is working to 

reduce both the mass and the rate of CO2 emissions nationally: building lowcarbon-intensity new sources of generation that currently are effectively 

displacing existing-source CO2 emissions by fuel displacement. This process 

may continue to work if it is not supplanted by a misguided top-down rule that 

exceeds EPA’s authority by attempting to establish either a single national 

emission “rate” standard or a national “mass” cap in tons—neither of which the 

Administrator has the authority to promulgate under § 111(d).

• When can emission reductions from existing power plants be achieved, 

considering different reduction strategies?

Answer: This will vary for each EGU, based on the unique circumstances that 

apply to each EGU. A successful program will likely involve allowing States to 

set flexible baselines in the manner outlined in this whitepaper, and to require 

percentage reductions based on what is achievable within the fenceline of each 

EGU. Then, the best alternative is to continue to allow the RPS process to 

continue to work, and not interfere with the supply of low-cost natural gas which 

is displacing higher-carbon-intensity coal generation, and resulting in the 

retirement of a large percentage of coal units that have reached the end of their 

useful lives. 

• How should a state, in applying a standard of performance to any particular 

source, consider a facility’s “remaining useful life” and other factors?

Answer: This whitepaper, at several places above, suggests several options 

consistent with the language of §§ 111(a)(1) & 111(d) regarding how a state 

should apply a standard of performance to any particular source when 

considering a facility’s “remaining useful life” and other factors.

• What requirements should state plans meet, and what flexibility 

should be provided to states in developing their plans?

EPA should apply Ockham’s razor and make the requirements that state plans should 

meet as simple as possible, but not simpler, and should give States maximum flexibility 
to do this within the procedure and guidelines established under this rulemaking. 

Numerous examples and suggestions for doing this are made in this whitepaper above. 

• What level of flexibility should be provided to states in meeting the required level 

of performance for affected EGUs contained in the emission guidelines?

Answer: This whitepaper suggests numerous ways EPA may give States 

flexibility to make effective CO2 reductions from existing EGUs. EPA should 

consider these or similar approaches to provide States flexibility in meeting the 

required level of performance for affected EGUs contained in the emission 

guidelines.

• Can a state plan include requirements that apply to entities other than the 

affected EGUs? For example, must states place all of the responsibility to meet 

the emission performance requirements on the owners or operators of affected 

EGUs, or do states have flexibility to take on some (or all) of the responsibility to 

achieve the required level of emissions performance themselves or assign it to 

others (e.g., to require an increase in the use of renewable energy or require 

end-use energy efficiency improvements, which will result in emissions 

reductions from affected EGUs)?

Answer: The answer to the first question is yes. This whitepaper has attempted 

to give numerous examples of how this could be done through allowing EGSs.

The answer to the second question is that States have flexibility to take on some 

(or all) of the responsibility to achieve the required level of emissions 

performance through the use of EGSs or similar devices as described in this 

whitepaper.

• What components should a state plan have, and what should be the criteria for 

approvability?

Answer: The components of the plan should be simple: determine an achievable 

rate or mass of CO2 emission reductions from an existing EGU, track the TTs 

and MWhs produced, and allow the flexibility to achieve reductions in the most 

cost-effective manner while retaining system reliability through EGSs with flexible 

boundaries that may be changed through periodic review when fundamental 

changes in the system occur (e.g., a change from equilibrium to load growth or 

decline). This whitepaper outlines various components a plan should have and 

ways this could be done.

• Can a state plan include programs that rely on a different mix of emission 

reduction methods than assumed in EPA’s analysis of the “best system of 

emission reduction” that is used to set the performance standard for state plans?
Answer: Yes.

• What should be the process for demonstrating that a state plan will achieve a 

level of emissions performance comparable to the level of performance in the 

EPA emission guidelines?

Answer: The process should set a goal of emissions reduction based on an 

achievable percentage of reduction to be determined by the State for each EGU 

according to guidelines promulgated by the Administrator. The reduction should 

be from a baseline year. Suggestions on a manner and process for doing this 

are set forth throughout this whitepaper.

• What enforceability, measurement, and verification issues might arise, depending 

on the types of state measures and programs that states include in their plans? 

For example, what issues are raised by actions that have indirect affects on EGU 

emissions, such as end-use energy efficiency resource standards, renewable 

portfolio standards, financial assistance programs to encourage end-use energy 

efficiency, building energy codes, etc.)?

Answer: By keeping this rulemaking very simple—tracking only emitted or 

avoided tons of CO2 and the MWhs produced or avoided within an EGU or EGS

—should make measurement, verification, and enforceability as simple as 

practicable. This whitepaper has attempted to give numerous examples of how 

this might be done.

• Do different CO2 reduction methods under different state plan approaches 

necessitate different timelines for the achievement of emission reductions?

Answer: Yes. This whitepaper has attempted to give examples of different ways 

that baselines from which to measure reductions may be established.

• What issues arise from the fact that operation and planning of the electricity 

system is often regional, but CAA section 111(d) calls for state plans? How 

should interstate issues be addressed, where actions in one state may affect 

EGU emissions in another state? For example, where actions have interstate 

impacts, which state would receive credit for the emission reductions in its state 

plan? Could EPA provide for coordinated submittal of state plans that 

demonstrate performance on a regional basis?

Answer: By allowing the flexibility to draw different boundaries around different 

systems, States may limit their jurisdiction to resources within their borders 

(except where compacts are developed between willing States to regulate as a 

group). Where States decide to form a compact, EPA may allow coordinated 

submittal of State plans. States and compacts should be encouraged under their 

plans not to take actions that will violate the dormant Commerce Clause, or 

interfere with the wholesale sale of electricity in interstate commerce.
In addition, EPA’s guidelines should allow a utility or cooperative located in 

several states to establish an EGS that will allow the reduction of CO2 from its 

mix of generation resources, EGUs and EGRs, in the most efficient and costeffective manner.

• What can EPA do to facilitate state plan development and 

implementation?

The most important thing that EPA can do to facilitate state plan development and 

implementation is to develop and a simple and flexible rule that will make achieving the 

ambitious timelines set forth in the President’s order more realistic. This whitepaper has 

attempted to suggest procedures and guidelines that may help make that goal possible.

• What types and amount of guidance and implementation support should be 

provided to states?

Answer: Just as EPA’s procedure and guidelines under this rulemaking must be 

simple and aim at legal and achievable goals, so must each State’s.

• Are there benefits for coordination among neighboring states in the development 

and submittal of state plans? Should EPA facilitate the coordination of multi-state 

plan submittals?

Answer: Yes to both questions.

• Would certain types of measures that might be included in state plans increase 

the need for coordination among states?

Answer: Yes. This is especially true for EGSs formed by utilities or cooperatives 

that cross state lines to most efficiently and cost-effectively make emission 

reductions across a fleet or generation system as a whole.

• Are there model rules that EPA could develop that would assist states, and what 

would those rules cover?

Answer: The executive summary to this whitepaper attempts to set forth the 

elements and procedure that a model rule or set of guidelines should contain.
• How cooperative federalism should be designed to work under § 111 

• Cooperative federalism.

This rulemaking should respect the “separation of powers” built into the “cooperative 

federalism” provisions of the CAA in general, and into § 111(d) in particular, by allowing 

states to 1) exercise their discretion to set standards of performance on a source-bysource basis if they so choose, 2) to determine “remaining useful life” of each unit based 

on consideration of established engineering and accounting principles that go to the 

issue of remaining useful life, and 3) to consider the five factors set forth in the definition 

of “standard of performance” at § 111(a)(1) in setting source-by-source standards of 

performance consistent with EPA’s “regulations” and guidelines.

As Arlington recently determined, although Chevron deference generally applies to an 

agency’s interpretation of the scope of its authority, “[w]here Congress has established a 

clear line, the agency cannot go beyond it; and where Congress has established an 

ambiguous line, the agency can go no further than the ambiguity will fairly allow.” This 

whitepaper has attempted to establish where the clear lines are, and what ambiguities 

may fairly allow where they exist. He author hopes that this is of assistance to the 

Administrator in making these determinations.

Further, as Hodel set forth long ago, “cooperative federalism ... allows the States, within 

limits established by federal minimum standards, to enact and administer their own 

regulatory programs, structured to meet their own particular needs,” instead of 

“commandeer[ing] the legislative processes of the States by directly compelling them to 

enact and enforce a federal regulatory program.” Setting forth a process whereby that 

can be done through this rulemaking has been one of the goals of this whitepaper.

Cooperative federalism is neither a top-down nor a bottom-up process. Rather, as 

accomplished under the Constitution through the separation of powers, cooperative 

federalism in general, and the provisions of § 111(d) in particular, assigns different roles 

to the federal and State participants under § 111(d), and requires each to perform their 

assigned roles within the context that this statute establishes. 

• Dormant Commerce Clause and other federal/state issues

When a state statute or regulation directly regulates or discriminates against interstate 

commerce, it is generally struck down without further inquiry. Such violations of the 

dormant Commerce Clause may take the form either of state laws that interfere with the 

autonomy of other individual states, or of state laws or regulations that discriminate, 

either directly or indirectly, against interstate commerce. A statute or regulation may 

discriminate against interstate commerce in one of four ways: 1) on its face (or facially); 

2) in purpose or intent; 3) as applied; or 4) in effect.
Further, the Federal Power Act (FPA) establishes federal jurisdiction over “the 

transmission of electric energy in interstate commerce and ... the sale of electric energy 

at wholesale in interstate commerce.” In enacting the FPA, Congress intended to vest 

exclusive federal authority to regulate interstate wholesale transactions in the Federal 

Power Commission (the predecessor to FERC). Under the FPA, Congress’s intent was 

to give FERC plenary authority over interstate wholesale rates, and to “ensure states 

don’t interfere with that authority.” Attempts to impose state taxes, externality values, or 

state-directed environmental dispatch are all examples of State acts that would 

potentially violate the dormant Commerce Clause, interfere with interstate wholesale 

sales and transactions, and otherwise interfere with FERC’s plenary authority over such 

transactions.

This rulemaking may potentially provide a regulatory vehicle for States to take actions 

that may, directly or indirectly, discriminate against interstate commerce in ways that 

favor generation resources located in that State over resources located in other States, 

or that may otherwise interfere with interstate wholesale sales and rates. EPA’s 

guidelines should discourage States from taking such unilateral actions, and should 

instead encourage States to form partnerships and compacts that allow emission 

reductions over systems located in several states in an efficient and cost-effective way. 

States should not attempt to regulate resources located outside of their borders and 

jurisdiction without working with the States where those resources are located. EPA’s 

regulations should develop procedures and regulations that allow that to happen in legal 

and rational ways that do not violate the dormant Commerce Clause or other relevant 

federal laws and federal Constitutional provisions. 

• Conclusion

This whitepaper is a working draft that attempts to summarize many of the most 

challenging issues and explore possible approaches to “design” of the to-be-proposed 

“existing source” GHG/CO2 rule that is scheduled to be issued on June 1, 2014. The 

drafters hope it is of some use to the Administrator, States, and others who are 

attempting to design that rulemaking. Its intent is to give others something to respond 

to and work from at this early stage of the rulemaking.