[Federal Register Volume 67, Number 84 (Wednesday, May 1, 2002)]
[Rules and Regulations]
[Pages 21868-21901]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 02-10404]
[[Page 21867]]
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Part IV
Environmental Protection Agency
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40 CFR Parts 51, 52, et al.
Response to Court Remand on NOX SIP Call and Section 126
Rule; Final Rule
Federal Register / Vol. 67, No. 84 / Wednesday, May 1, 2002 / Rules
and Regulations
[[Page 21868]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 51, 52, 96, and 97
[FRL-7203-3]
Response to Court Remand on NOX SIP Call and Section
126 Rule
AGENCY: Environmental Protection Agency (EPA).
ACTION: Response to court remand of rules.
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SUMMARY: In today's document, EPA is responding to two court decisions
directing EPA to reconsider heat input growth rates projected and used
in setting nitrogen oxides (NOX) emission budgets in two
rules designed to reduce interstate transport of ozone and
NOX, an ozone precursor. After reviewing the heat input
growth rates and considering the court decisions and additional
comments, EPA has decided to continue to use the heat input growth
rates developed in the rules. One rule, the NOX State
Implementation Plan Call (NOX SIP Call) under Section 110 of
the Clean Air Act (CAA), set ozone season NOX emission
budgets based, in part, on emissions reductions calculated for large,
fossil fuel-fired electric generating units (EGUs) in 22 States and the
District of Columbia. The second rule, issued in response to petitions
by northeastern States under Section 126 of the CAA (Section 126 Rule),
included ozone season NOX emission budgets for EGUs in 12
States and the District of Columbia. The U.S. Court of Appeals for the
District of Columbia Circuit (the Court) remanded the heat input growth
rates to EPA to either properly justify the growth rates currently used
by EPA or to develop and justify new growth rates. After reviewing the
matter, EPA believes that the methodology used in developing the heat
input growth rates and the resulting growth rates are reasonable based
on the information available at the time the rules were issued,
confirmed by new information concerning activity to date.
ADDRESSES: Documents relevant to this action are available for
inspection at the Docket Office, located at 401 M Street, SW.,
Waterside Mall, Room M-1500, Washington, DC 20460, between 8:00 a.m.
and 5:30 p.m., Monday through Friday, excluding legal holidays. A
reasonable fee may be charged for copying.
FOR FURTHER INFORMATION CONTACT: General questions, and questions on
technical issues concerning today's notice should be addressed to Kevin
Culligan, Office of Atmospheric Programs, Clean Air Markets Division,
U.S. Environmental Protection Agency, 1200 Pennsylvania Ave., NW.
(6204N), Washington, DC 20460, telephone (202) 564-9172, e-mail at
[email protected]. Questions on legal issues concerning today's
notice should be addressed to Howard J. Hoffman, Office of General
Counsel, U.S. Environmental Protection Agency, 1200 Pennsylvania Ave.,
NW. (2344A), Washington, DC 20460, telephone (202) 564-5582, e-mail at
[email protected] or Dwight C. Alpern, Clean Air Markets Division,
U.S. Environmental Protection Agency, 1200 Pennsylvania Ave., NW.
(6204N), Washington, DC 20460, telephone (202) 564-9151, e-mail at
[email protected].
SUPPLEMENTARY INFORMATION: In today's notice, EPA is responding to two
rulings by the Court directing EPA to reconsider growth rates for heat
input (i.e., fossil fuel use) for the ozone season (May 1-September 30)
projected and used in setting State NOX emission budgets in
two rules designed to reduce interstate transport of ozone and
NOX.\1\ On May 15, 2001, the Court issued a decision in
Appalachian Power v. U.S. EPA, 249 F.3d 1032 (D.C. Cir. 2001)
concerning the Section 126 Rule (``Section 126 Decision''). As part of
that decision, the Court remanded the heat input growth rates that EPA
used to calculate NOX emission budgets set in response to
several petitions by northeastern States under Section 126 of the CAA.
The Court remanded these growth rates to EPA to either properly justify
the growth rates currently used by EPA or to develop and justify new
growth rates. On June 8, 2001, the Court issued a similar decision in
Appalachian Power v. U.S. EPA, 251 F.3d 1026 (D.C. Cir. 2001)
concerning heat input growth rates used to develop NOX
emission budgets used in the NOX SIP Call related to
interstate transport of ozone (``Technical Amendments Decision''). The
Court raised concerns about EPA's explanation of the methodology for
developing projected heat input growth rates and about States for which
heat input for EGUs had already exceeded the heat input that EPA
projected for 2007.
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\1\ Unless otherwise stated, all references in this notice to
actual or projected ``heat input'' or ``heat input growth rates''
concern heat input during the ozone season for EGUs.
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In response to the Court's decisions, EPA has reviewed the heat
input growth rates for EGUs and the methodology used to develop those
growth rates. Based on that review, EPA believes that the heat input
growth rates and the methodology used to develop them were reasonable.
Furthermore, in response to the Court's and commenters' concerns, EPA
has also reviewed new information concerning current activity. This
notice explains why EPA thinks that the growth rates were reasonable
based on the information that EPA had available at the time of the
original rulemakings, as confirmed by new information.
Availability of Related Information
The official record for the Section 126 rulemaking has been
established under docket number A-97-43. The official record for the
NOX SIP Call rulemaking has been established under docket
number A-96-56. The public version of both records, including printed,
paper versions of electronic comments, which does not include any
information claimed as confidential business information, is available
for inspection from 8:00 a.m. to 5:30 p.m., Monday through Friday,
excluding legal holidays. The rulemaking record is located at the U.S.
Environmental Protection Agency, 401 M Street, SW, Waterside Mall, Room
M-1500, Washington, DC 20460. In addition, the Federal Register
rulemakings and associated documents are located at http://www.epa.gov/ttn/rto/, and certain documents are located at http://www.epa.gov/airmarkets/fednox/126noda2/index.html.
Outline
I. Background
A. NOX SIP Call
B. Section 126 Rule
C. Technical Amendments
II. Court Decisions
A. Section 126 Decision
B. Technical Amendments Decision
III. Notices of Data Availability
IV. States Addressed in Today's Notice
A. NOX SIP Call
B. Section 126 Rule
V. EPA's Explanation of Heat Input Growth Rate Methodology and
Response to Court Remand and Public Comments
A. Overview
B. Description of EPA's Methodology
1. EPA's Methodology for Determining State NOX
Emission Budgets and Heat Input Growth Rates
2. Use of Consistent Heat Input Growth Rates for Different Parts
of EPA's Analysis
C. Justification for EPA's Methodology and Reasonableness of
EPA's Underlying Assumptions
1. Court's and Commenters' Concerns
2. EPA Reasonably Decided to Develop State NOX
Emission Budgets by Using Heat Input Growth Rates.
3. State Heat Input Growth Rates Based on IPM Outputs for 2001-
2010 Were Reasonably Representative of 1997-2007 Heat Input Growth.
4. EPA Did Not ``Double Count'' Electricity Demand Reductions
Under CCAP.
[[Page 21869]]
5. EPA's Assumptions Regarding the Location of New Units Were
Reasonable.
D. Actual Heat Input Compared to EPA's Projections of Heat Input
1. Court's and Commenters' Concerns
2. EPA's Heat Input Projections for the Region Are Consistent
With Actual Heat Input Data.
3. EPA's Heat Input Growth Rates and 2007 Projections for Most
States are not Disputed by Commenters.
4. Historical Data Show That a State's Heat Input Can Decrease
Significantly Over Multi-Year Periods.
5. Approach of Using Recent State Heat Input to Project Future
State Heat Input is not Statistically Sound.
6. EPA's Heat Input Projections do not Implicitly Assume
Negative Growth in Electricity Generation.
7. Even if There Were a Substantial Risk that EPA's State Heat
Input Projection Would be Less Than a State's Actual 2007 Heat
Input, This Would not Make EPA's Projection Unreasonable.
8. Commenters Overstated the Impacts of Actual State Heat Input
Exceeding Projected State Heat Input.
9. Discussion of Individual States for Which EPA's Heat Input
Growth Rates are Disputed by Commenters.
10. No Heat Input Growth Methodology has Been Presented That
Would Have Results That Better Comport With Actual Heat Input.
E. Procedural Issues
1. Notice-And-Comment Rulemaking
2. Petition To Reconsider
I. Background
A. NOX SIP Call
In October 1998, EPA issued the NOX SIP Call--a final
rule under Section 110(k)(5) of the CAA, 42 U.S.C. 7410(k)(5)--
requiring 22 States and the District of Columbia (``upwind States'') to
revise their SIPs to impose additional controls on NOX
emissions.\2\ See Finding of Significant Contribution and Rulemaking
for Certain States in the Ozone Transport Assessment Group Region for
Purposes of Reducing Regional Transport of Ozone, 63 FR 57,356 (Oct.
27, 1998). EPA concluded that emissions from the upwind States
``contribute significantly'' to ozone nonattainment in downwind States,
in violation of section 110(a)(2)(D)(i). Under the NOX SIP
Call, upwind States are required to reduce emissions by amounts that
would allow meeting NOX emission budgets. EPA determined
these budgets by projecting NOX emissions to 2007 for all
source categories and then reducing those amounts by the emissions
reductions achievable using the controls that EPA determined to be
highly cost effective. EPA defined highly cost-effective controls as
those controls capable of removing NOX at an average cost of
$2,000 or less per ton. For EGUs, EPA determined that it was highly
cost effective to achieve an average emission rate of 0.15 lb/mmBtu,
based on projected 2007 fossil fuel use (i.e., heat input). Projected
2007 heat input for each State was calculated by applying ozone season
heat input growth rates developed by EPA for each State for EGUs
(referred to as ``State heat input growth rates'') to baseline (the
higher of 1995 or 1996) EGU heat input.
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\2\ The States were: Alabama, Connecticut, Delaware, Georgia,
Illinois, Indiana, Kentucky, Maryland, Massachusetts, Michigan,
Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania,
Rhode Island, South Carolina, Tennessee, Virginia, West Virginia,
and Wisconsin.
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EPA recommended that a State could meet the State's NOX
emission budget in part by establishing a cap-and-trade program for
NOX emissions from EGUs. Covered sources would be required
to hold NOX allowances at least equal to their
NOX emissions and could either obtain additional allowances
or reduce emissions, e.g., by installing additional controls. The total
number of allowances distributed to EGUs would equal the EGU portion of
the NOX emission budget, i.e., the projected 2007 heat input
multiplied by a NOX emission rate of 0.15 lb/mmBtu. States
had the option of adopting approaches other than a cap-and-trade
program to meet the budgets.
B. Section 126 Rule
On January 18, 2000, EPA issued a final rule to control emissions
of NOX under Section 126 of the CAA, 42 U.S.C. 7426. In the
rule, EPA made final its findings that stationary sources of
NOX emissions in 12 upwind States and the District of
Columbia contribute significantly to ozone nonattainment in
northeastern States.\3\ This finding triggered direct Federal
regulation of stationary sources of NOX in the upwind
States. The Section 126 Rule further established a cap-and-trade
program for NOX emissions within each upwind jurisdiction,
including NOX emissions from EGUs. This program was
essentially the same as that suggested by EPA for State implementation
in the NOX SIP Call. EPA determined the total number of
NOX allowances to be distributed to EGUs in each individual
State based on the same methodology used in the NOX SIP Call
(i.e., projected 2007 heat input multiplied by a NOX
emission rate of 0.15 lb/mmBtu).
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\3\ The States were: Delaware, Indiana, Kentucky, Maryland,
Michigan, North Carolina, New Jersey, New York, Ohio, Pennsylvania,
Virginia, and West Virginia.
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C. Technical Amendments
When EPA promulgated the NOX SIP Call on October 27,
1998, EPA reopened public comment on the accuracy of data upon which
the emission inventories and budgets were based (63 FR 57,427). On
December 24, 1998, EPA extended the comment period ``for emission
inventory revisions to 2007 baseline sub-inventory information used to
establish each State's budget in the NOX SIP Call'' and
further explained that it was seeking comment on the relevant data and
assumptions so the Agency could correct errors and update information
used to compute the 2007 budgets. (Correction and Clarification to the
Finding of Significant Contribution and Rulemaking for Purposes of
Reducing Regional Transport of Ozone, 63 FR 71,220, Dec. 24, 1998). EPA
also announced that it would reopen the comment period on equivalent
inventory data for the section 126 rulemaking because the rules relied
upon the same inventories. Id.
Subsequently, EPA published two Technical Amendments revising the
NOX SIP Call emission budgets. In the first Technical
Amendment, EPA made some modifications to source-specific 1995 and 1996
emissions data, which resulted in changes in the 2007 NOX
emission budgets (Technical Amendment to the Finding of Significant
Contribution and Rulemaking for Certain States for Purposes of Reducing
Regional Transport of Ozone, 64 FR 26,298, May 14, 1999). In the second
Technical Amendment, EPA made more corrections based upon additional
public comments it received and EPA's own internal review of the
accuracy of its data and calculations (Technical Amendment to the
Finding of Significant Contribution and Rulemaking for Certain States
for Purposes of Reducing Regional Transport of Ozone, 65 FR 11,222,
Mar. 2, 2000). EPA also explained that the March 2000 Technical
Amendment was ``necessary to make the NOX SIP Call inventory
consistent with the inventory adopted'' by the EPA in the Section 126
rule, as the two rules were to be based upon the same inventory. Id.
II. Court Decisions
A. Section 126 Decision
On May 15, 2001, the Court ruled on a number of challenges to EPA's
Section 126 Rule. See Appalachian Power v. EPA, 249 F.3d 1032. While
the Court's decision largely upheld the Section 126 Rule, the Court
remanded two issues to EPA. The Court remanded the Section 126 Rule to
EPA to allow EPA to (1)
[[Page 21870]]
Properly justify either the current or new State heat input growth
rates for EGUs used in calculating projected State heat input for 2007
and (2) either properly justify or alter its categorization of
cogenerators that sell electricity to the electricity grid as EGUs.
With regard to heat input growth rates, the Court was concerned that
EPA may have used inconsistent growth rates in different parts of the
Agency's analysis and that some States already had heat input exceeding
the levels projected by EPA for 2007. EPA is responding to the remand
related to the categorization of cogenerators in a separate rulemaking
(Interstate Ozone Transport: Response to Court Decisions in
NOX SIP Call, NOX SIP Call Technical Amendments,
and Section 126 Rules, 67 FR 8396, Feb. 22, 2002).
B. Technical Amendments Decision
On June 8, 2001, the Court ruled on a number of challenges to EPA's
Technical Amendments. See Appalachian Power v. EPA, 251 F.3d 1026. In
its decision, the Court remanded to EPA the same issues as in the
Section 126 Decision concerning (1) State heat input growth rates for
EGUs and (2) cogenerators. The Court cited its decision in the Section
126 Decision. Id., 251 F.3d at 1034.
III. Notices of Data Availability
A Notice of Data Availability (NODA) of documents that EPA was
considering in response to the remand concerning heat input growth
rates was published on August 3, 2001, 66 FR 40609). These documents
were placed in the NOX SIP Call and section 126 Rule
dockets. The new documents contain, among other things, information and
data on more recent electricity sales and generation. The information
and data were not available when the two rules were promulgated. Table
1 of the NODA contains actual heat input values for the 1995-2000 ozone
seasons for the District of Columbia and 21 States, which are subject
to the NOX SIP Call and include the States subject to the
Section 126 Rule. Comments on the new information and data were
requested. Thirty-four comments were received.
The NODA explains that there are substantial fluctuations in State
heat input for EGUs on a year-by-year basis. Some of the reasons
mentioned for these fluctuations are forced outages, variations in
energy costs, weather, and economic conditions. A discussion of the
growth rate methodology used by EPA to develop State heat input growth
rates for EGUs and of the rationale for different components of the
methodology is included in the NODA. EPA states in the NODA that the
Agency's preliminary view is that the new data and the existing record
in the NOX SIP Call and Section 126 rulemakings appear to
confirm the reasonableness of the heat input growth rates used by EPA
in developing NOX emission budgets for EGUs.
A second NODA was published on March 11, 2002, 67 FR 10844.
Documents referenced in this NODA include, among other things, 2001
ozone season heat input data and 1960-2000 annual heat input data and
1970-1998 ozone season heat input data for the District of Columbia and
21 States, which are subject to the NOX SIP Call. One
comment was received on this notice. In the March 11, 2002 NODA, EPA
stated that it might place additional documents in the docket, with
notice thereof provided on a particular website. EPA did so at various
times after March 11, 2002. EPA also stated that if the Agency decided
to confirm its previously adopted heat input growth rates, it intended
to issue its response to the remand by March 29, 2002.
EPA received a comment on the March 11, 2002 NODA stating that
there was no reason to expect that EPA would take additional comments
into consideration since the Agency would be issuing its response by
March 29, 2002. The commenter also asserted that both NODA's failed to
explain the relevance of the documents that were added to the docket.
On March 29, 2002, EPA informed the commenter in writing that the
Agency's response to the remand would be issued on or about April 17,
2002 and that the Agency would consider comments submitted sufficiently
in advance. In addition, EPA noted that additional documents would be
placed in the docket. EPA also identified the purposes for which the
data referenced in the March 11, 2002 NODA had been added to the
docket. (Docket # A-96-54, Item # XV-E-2.) Copies of all these
documents and information were placed in the docket. EPA subsequently
received a second comment that was similar to the first comment, and
EPA referred the commenter to the relevant documents and information in
the docket. Finally, EPA received a third comment stating that the data
referenced in the March 29, 2002 NODA were highly germane and supported
EPA's heat input growth rate methodology.
IV. States Addressed in Today's Notice
At the outset, it should be established which States should be
addressed in today's notice on the heat input growth rate issue, in
light of the Court's decisions vacating EPA's rules with respect to
certain States and EPA's response to those vacaturs.
A. NOX SIP Call
As noted above, the NOX SIP Call covered 22 States and
the District of Columbia. In reviewing the NOX SIP Call, the
Court vacated the NOX SIP Call for Georgia and Missouri on
the ground that there was insufficient record evidence concerning
portions of those States. Michigan v. EPA, 213 F.3d 663, 685 (D.C.
Cir., 2000). The record included modeling by the Ozone Transport
Assessment Group (OTAG)-- a partnership among EPA, 37 eastern States
and the District of Columbia, industry, and environmental groups--that
divided the eastern U.S. into two grids, the ``fine grid'' and the
``coarse grid.'' The grids did not track State boundaries, and Georgia
and Missouri were split between the fine and coarse grids. OTAG stated
that, based on air quality impacts, it was recommending NOX
emission controls for the fine grid area but not the coarse grid area.
In light of OTAG's recommendations, the Court concluded that EPA had
not sufficiently explained the basis for including the entire States of
Georgia and Missouri, rather than simply the fine grid portions. The
Court vacated and remanded the NOX SIP Call for these States
for agency reconsideration. The Court also vacated the rule for
Wisconsin on grounds not relevant here. Id. at 681.
On February 22, 2002, EPA issued a notice of proposed rulemaking in
response to the Court's remand, (67 FR 8396). In that notice, EPA
stated that the Agency does not intend to proceed at this time with
further action evaluating whether NOX emissions should be
reduced for ozone transport reasons in Wisconsin or the coarse grid
portions of Georgia and Missouri. In addition, EPA noted that, while
not addressed by the Court, Alabama and Michigan also are divided
between the fine grid and the coarse grid in OTAG's modeling. EPA
stated that it would therefore treat all four States the same and
include in the NOX SIP Call only counties that are fully
within the fine grid portions of the four States. EPA proposed partial
State NOX emission budgets for Alabama, Georgia, Michigan,
and Missouri using the State heat input growth rates established for
the whole States.
EPA has taken the position that a single heat input growth
methodology should be consistently applied to each State, and EPA
received numerous comments disputing the application of EPA's heat
input growth methodology to these four States, as well as to three
[[Page 21871]]
other States (i.e., Illinois, Virginia, and West Virginia).
Consequently, in the context of responding to the remand on the heat
input growth issue in today's notice, EPA's analysis of the
reasonableness of that methodology and the resulting heat input growth
rates includes Alabama, Georgia, Michigan, and Missouri. As noted
below, for Alabama, Georgia, and Missouri, EPA has evaluated the
reasonableness of the methodology with respect to both the entire State
and the fine grid portion alone. For Michigan, EPA evaluated the
methodology for the entire State and not for the fine grid portion
alone because the amount of NOX emissions in the coarse grid
portion was trivial for present purposes.\4\
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\4\ EPA is not analyzing the reasonableness of the growth
methodology with respect to Wisconsin because the Court vacated the
NOX SIP Call for that State and EPA does not intend, at
present, to further evaluate Wisconsin in the context of ozone
transport.
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B. Section 126 Rule
As noted above, the Section 126 Rule covered 12 States and the
District of Columbia. Of the four States that EPA proposed to include
only partially in the NOX SIP Call, only Michigan is subject
to the Section 126 Rule. As discussed above, the NOX
emission budget for Michigan changes very little when the coarse grid
portion of the State is excluded, and EPA has therefore analyzed the
heat input growth only for the entire State. In addition, with regard
to the three other States concerning which EPA received adverse
comments on its heat input projections, the Section 126 Rule covers
Virginia and West Virginia, but not Illinois. As a result, strictly
speaking, the validity of EPA's growth rate methodology for the Section
126 Rule should not depend on its application to Alabama, Georgia,
Missouri, Illinois, or any other State covered under the NOX
SIP Call, but not the Section 126 Rule.
V. EPA's Explanation of Heat Input Growth Rate Methodology and
Response to Court Remand and Public Comments
A. Overview
After a thorough review, EPA has concluded that its methodology for
developing State heat input growth rates, and the resulting growth
rates themselves, were reasonable in light of the record developed for
the NOX SIP Call and Section 126 Rule, and remain reasonable
in light of new information concerning current activity that has since
become available. The reasons are summarized below and explained more
fully in the remainder of this notice.
1. EPA believes that its methodology was reasonable in light of the
record for the NOX SIP Call and the Section 126 Rule, based
on the following considerations: a. EPA's methodology for projecting
future heat input was logical and was consistently applied to all
NOX SIP Call States. EPA used an actual State heat input
baseline (the higher of 1995 or 1996 levels) in view of year-to-year
variability of State heat input. EPA applied to each State's baseline a
heat input growth rate estimated using the Integrated Planning Model
(the IPM), a state-of-the-art model for analyzing future electricity
markets. EPA's use of the IPM was upheld by the Court.
b. Contrary to the Court's understanding, EPA used consistent State
heat input growth rates (i.e., growth rates based on 2001-2010 heat
input growth determined using IPM projections for 2001 and 2010)
throughout the analysis for the NOX SIP Call and the Section
126 Rule. EPA did not use, or even have available, 1996-2000 heat input
growth rates determined using IPM projections for 1996 and 2000. EPA
acknowledges that the Court's misunderstanding on this point stemmed
from inadvertently confusing statements EPA made in the record.
c. The specific assumptions that EPA made in using the IPM to
develop State heat input growth rates were reasonable. These included
assumptions that: (i) Heat input growth rates during 2001-2010 are
reasonably representative of heat input growth during 1996-2007; (ii)
electricity demand projections should be reduced to take account of
demand reductions under the Climate Challenge Action Program (CCAP);
and (iii) the use of available data on new units and the historical
distribution of generating capacity among States could be used to
project the location of new units.
2. The State heat input growth rates and projections were generated
using a reasoned methodology and reasonable assumptions, along with
data that went through full public review (and were not at issue in the
Court remands), and this suggests that the resulting heat input
projections are reasonable. To confirm this, and to respond to concerns
expressed by the Court and commenters about the plausibility of EPA's
projections based on recent, actual heat input data, EPA has examined
the projections in light of historical heat input data and new heat
input data that have become available since the Agency developed the
projections. EPA believes that its heat input projections remain
plausible and reasonable based on the following considerations:
a. The State heat input amounts projected by EPA are reasonably
consistent with the actual heat input data that have become available
since the projections were made. On a regionwide basis, EPA's projected
heat input for 2000 and 2001 are 0.1% lower and 2.0% higher
respectively than actual regional heat input. Further, for most States,
EPA's heat input growth rates have not been specifically challenged.
Commenters have disputed EPA's heat input growth rates for seven out of
the 22 jurisdictions under the NOX SIP Call on the ground
that the States involved had recent heat input amounts exceeding, or
close to, EPA's 2007 heat input projections. However, recently, heat
input for several of these States declined significantly. Moreover,
State heat input is quite variable from year-to-year and so, in one
year or over several years, may increase and then decrease. Indeed,
there have been many instances in the past when State heat input has
decreased significantly for the last year of a multi-year period as
compared to the first year of such period. Consequently, the fact that
a State's recent heat input exceeds, or is close to, EPA's 2007 heat
input projection does not by itself demonstrate that the projection, or
the underlying heat input growth rate, is unreasonable.
b. Commenters who argue that EPA's 2007 projection is unreasonable
based on recent heat input data are in effect asserting that predicting
a State's 2007 heat input based on trends in recent, short-term heat
input data is a better methodology than the one employed by EPA. Some
commenters explicitly recommended this approach. In response, EPA
examined this approach using historical annual heat input data and
found that in most States, recent, short-term data is an unreliable
predictor of a State's heat input in the future. Therefore, EPA
believes that its methodology, using a state-of-the-art model that
takes into account many factors, including the dynamics of regional
electricity markets, is more rational.
c. Contrary to the Court's understanding, EPA's 2007 heat input
projections do not assume negative growth in electricity generation.
State heat input (i.e., fossil fuel use for generation) can decrease
while electricity generation increases in the State or in the region as
a whole. Within a State, electricity generation does not necessarily
vary with heat input because: (i) Significant amounts of
[[Page 21872]]
electricity are produced using non-fossil fuel generation; and (ii)
efficiency improvements (e.g., from replacement of old units with new,
more efficient units) make it possible to produce more electricity with
less heat input. Further, electricity is generated and sold on a
regional, not on a State-by-State basis. Heat input and electricity
generation may decrease in one State because that State is importing
more electricity generated in another State in the region. This is
consistent with increased electricity generation in the region as a
whole.
d. EPA's heat input projections are simply required to be
reasonable, not to match perfectly actual heat input. This is because
the Courts recognize that predictions of the results of complex
activities (in this case, future State heat input, which will result
from operation of the regional electricity market) will not necessarily
match actual, future results exactly. To require such perfection would
be to preclude the use of projections or of a model to develop such
projections. EPA's heat input projections thus should not be considered
unreasonable even if there were a substantial risk that they would turn
out to be less than States' actual 2007 heat input, in light of all the
other circumstances. In this case, unavoidable limitations on the
accuracy of heat input projections result from: (i) The complexity of
the electricity marketing system, which cannot be modeled perfectly
because of the necessity to use simplifying assumptions about factors
(e.g., fuel prices and electricity demand in the future) affecting
future heat input; (ii) the necessity to make State-by-State
projections of heat input even though electricity is generated and sold
on a regional basis; and (iii) significant variability--on a year-to-
year and several year basis--inherent in State heat input. Therefore,
EPA's heat input projections should not be considered unreasonable in
the current context, even if there were a substantial risk that they
would turn out to be less than States' actual 2007 heat input.
e. Commenters overstated the impacts of a State's 2007 heat input
exceeding EPA's 2007 heat input projection for that State. The
NOX SIP Call and the Section 126 Rule limit NOX
emissions, not heat input. Even if a State's actual heat input for 2007
turns out to exceed the projected heat input, NOX emissions
would increase at a much lower rate than heat input because the vast
majority of new units are, and will continue to be, gas-fired with very
low NOX emission rates and high efficiency. The impact on
the stringency of the NOX emission budget and on the State
economy therefore would be much less than claimed by commenters.
Further, the NOX SIP Call and the Section 126 Rule are being
implemented through a NOX cap-and-trade program that further
mitigates the cost impact of any differences between projected and
actual State heat input.
f. No commenter has identified an alternative methodology for
developing State heat input growth rates that would be likely to yield
growth rates that would comport better with actual heat input data than
the growth rates under EPA's methodology. In light of the variability
of State heat input, it is quite possible that any alternative
methodology for predicting State heat input will result in projected
values for some States that will not match actual heat input in some
future year.
g. Commenters failed to show that EPA's heat input growth rate for
any of the seven individual States for which adverse comments were
received (Alabama, Georgia, Illinois, Michigan, Missouri, Virginia, and
West Virginia) are unreasonable. The heat input for several of the
States has already decreased to levels below or only slightly above
EPA's projection. In addition, the comments failed to address the fact
that, in the past, each State has had many multi-year periods when heat
input has declined significantly for the last year, as compared to the
first year of such periods. Further, in arguing that economic growth or
planned new capacity prove that heat input will increase substantially
for particular States, the commenters limited the information they
provided to statewide data and failed to provide regional data. As a
result, these comments are not persuasive because any particular
State's heat input is determined by regional, not just that individual
State's, demand and supply.
B. Description of EPA's Methodology
1. EPA's Methodology for Determining State NOX Emission
Budgets and Heat Input Growth Rates
EPA used a multi-step procedure to determine for each State the
portion of the NOX SIP Call emissions budget attributable to
EGUs. In brief, EPA started with the State's baseline of the higher of
EGU heat input for 1995 and 1996 and grew that amount to the 2007 level
using the projected heat input growth rate for that State based on the
IPM. Then, EPA determined the appropriate level of NOX
emissions control (which was the same level for each State) and applied
this level to each State's projected 2007 heat input. The result was
each State's NOX emissions budget for EGUs.
Throughout the methodology, EPA relied on the IPM. The IPM
simulates the operation of the electricity market in the continental
U.S. by using inputs (such as electricity demand and fuel and emission
control costs) and by modeling electricity generation, transmission,
and distribution on a subregional basis. The IPM projects the least
cost scenario for the region for generating electricity consistent with
this set of inputs. This scenario includes projections of which units
operate at what levels, which units install emission controls, and what
type, when, and where new units are built.
To develop the State heat input growth rates, EPA first conducted
an IPM run (the ``base case run''). This base case run was designed to
yield, as outputs, projections of the heat input necessary to generate
electricity sufficient to meet projected electricity demand in the 2001
and 2010 ozone seasons. To conduct this run, EPA used, as model inputs,
assumptions regarding, among many other things: (i) electricity demand
in 2001-2020, which EPA calculated by determining actual electricity
demand in 1997 and applying growth rates in electricity demand for
1997-2020; (ii) reductions in electricity demand based on the CCAP,
discussed below; (iii) NOX emission control requirements and
associated costs; (iv) location and costs of projected new units; and
(v) fuel costs. For this base case run, EPA assumed no additional
NOX emission controls would be required for ozone transport
purposes (62 FR 60318, 60347, Nov. 7, 1997).
With these inputs, the base case run produced, as outputs, the
sources of electricity generation for years selected by EPA, including
2001, 2007, 2010, and 2020. In addition, the outputs included the
amounts of heat input used by the fossil-fuel-fired sources in those
years, the projected NOX emissions for the 2007 ozone
season, and the total cost for generating electricity for the 2007
ozone season.
EPA used the 2001 and 2010 heat input to generate heat input growth
rates for each State. For example, the base case run projected that
Virginia's base case 2001 and 2010 heat input would be 194,000,000
mmBtu and 243,000,000 mmBtu, respectively. An annual heat input growth
rate was then mathematically determined. For Virginia, this annual
growth rate is 1.025.
Then, EPA applied each State's annual heat input growth rate to the
baseline heat input for the State (the higher of the 1995 or 1996
actual heat input for EGUs) to develop the State's
[[Page 21873]]
emission budget for 2007 (63 FR 57406-57408). For example, for
Virginia, the 1995 heat input was 154,233,310 mmBtu, the 1996 heat
input was 172,633,028 mmBtu, and so EPA used the 1996 heat input as the
baseline heat input. For West Virginia the opposite occurred. The 1995
heat input was 347,687,307 mmBtu, and the 1996 heat input was
341,738,426 mmBtu, and so EPA used the 1995 heat input as the baseline
heat input.
Then, EPA applied to each State's baseline amount--which EPA
treated as the 1996 value even if the higher heat input amount actually
occurred in 1995--that State's annual heat input growth rate to
determine the projected 2007 heat input. For Virginia, this computation
(172,633,028 mmBtu multiplied by 1.025 over an 11-year period) yielded
227,875,597 mmBtu.
Next, EPA used projected 2007 heat input to test the cost
effectiveness of various NOX emission control levels. First,
EPA selected a set of NOX emissions control levels as
candidates to be tested for appropriateness. The levels tested were,
0.12 pounds of NOX per mmBtu of heat input (lbs/mmBtu), 0.15
lb/Btu, 0.2 lb/Btu, and 0.25 lb/Btu. Then, EPA applied one of the
control levels to each State's projected 2007 heat input. For example,
for Virginia the 2007 projected heat input of 227,875,597 mmBtu was
multiplied by 0.15 lb/mmBtu to obtain an EGU NOX emission
budget of 34,181,340 pounds or 17,091 tons. In this manner, EPA
calculated the NOX emission budget for each State based on
the level of NOX emissions control to be tested. Then, EPA
summed each State's NOX emissions budget to determine the
regionwide NOX emissions budget for the NOX
control level tested.
Then, EPA conducted another IPM run (the ``cost-effectiveness
run'') to determine the cost effectiveness of meeting the regionwide
NOX emission budget for the control level tested. For this
run, EPA included in the model each of the assumptions that were used
in the base case run. However, EPA added one additional assumption,
i.e., the requirement that total NOX emissions for EGUs in
the NOX SIP Call region could not exceed the regionwide
NOX emission budget (i.e., the sum of the State
NOX emission budgets for EGUs developed using the 2001-2010
heat input growth rates from the base case run and the specified level
of NOX emission controls being tested). This cost-
effectiveness run yielded, as an output, the total cost of generating
electricity for the 2007 ozone season for the control level. EPA
repeated this process for each control level tested.
EPA then performed, for each NOX emission control level,
three calculations to determine the cost per ton of NOX
emissions reduced, of meeting the regionwide NOX emission
budget associated with that control level. First, EPA subtracted the
total NOX emissions in the cost-effectiveness run from the
total NOX emissions in the base case run to calculate the
tons of NOX reduced due to the imposition of the control
level. Second, EPA subtracted the total cost of generating electricity
in the base case run from the total cost in the cost-effectiveness run
to calculate the total cost of meeting the regionwide budget. Third,
EPA divided the total cost of meeting the budget by the total tons
reduced due to the imposition of the control level to calculate the
cost effectiveness of meeting the budget associated with the control
level (in dollars per ton). For example, the cost effectiveness of
meeting the 0.15 lb/mmBtu control level was $1,440 per ton of
NOX emissions reduced in 2007 (Regulatory Impact Analysis
for the NOX SIP Call, FIP, and Section 126 Petitions, Volume
1: Costs and Economic Impacts, September 1998, at p. ADD-2). Of course,
the cost effectiveness was a higher dollar amount for more restrictive
control levels (e.g., 0.08 lb/mmBtu) and a lower dollar amount for less
restrictive control levels (e.g., 0.2 lb/mmBtu).
Finally, EPA evaluated the cost-effectiveness level for each
control level against certain criteria and selected 0.15 lb/mmBtu as
the highly cost effective level for EGUs. The basis for this selection,
which is not at issue in today's notice, is discussed at 63 FR 57401-2.
Having selected 0.15 lb/mmBtu, EPA set, as the NOX
emission budget for EGUs for each State in the NOX SIP Call,
the State's budget associated with that control level. For example, for
Virginia, the NOX emission budget for EGUs was 17,091 tons.
For the Section 126 Rule, which imposed requirements on individual
EGUs in certain States, but did not impose statewide control
limitations, EPA used the same State NOX emission budgets
that were developed for the NOX SIP Call. For the individual
EGUs in a given State, EPA allocated a total amount of allowances equal
to the amount of tons of NOX in the State NOX
emission budget for EGUs. Individual EGUs were allocated a
proportionate share of the State NOX emission budget based
on its share of the total heat input for EGUs in that State.
2. Use of Consistent Heat Input Growth Rates for Different Parts of
EPA's Analysis
One concern that the Court had about the reasonableness of EPA's
approach was the belief that EPA ``utilized one set of growth-rate
projections to set allowance budgets, [and] another to assess emission
reduction costs.'' Appalachian Power v. EPA, 249 F.3d at 1054. The
Court therefore believed that ``EPA had other ways of generating 2007
utilization projections.'' Id. The above description of EPA's multi-
step procedure makes clear that, in fact, EPA utilized only IPM heat
input growth rate projections for 2001-2010. The methodology required
(i) developing many inputs in the IPM, including assumptions about
growth in electricity demand during 1997-2020; (ii) conducting an IPM
base case run and a set of cost effectiveness runs; and (iii) using IPM
outputs to make various computations. However, at any step that
required IPM generated heat-input growth rate projections--whether for
purposes of determining a budget or for purposes of determining the
cost effectiveness of control levels--EPA used only the projections for
2001-2010, and not any other period.
EPA respectfully observes that the Court's views to the contrary
are misperceptions that resulted from what EPA now realizes was EPA's
own inadvertently confusing statement by EPA in the Response to Comment
document for the Section 126 Rule. The Response to Comment document
states, in relevant part:
The budgets were constructed using growth rates for 1996-2007
that were consistent with the growth rates in IPM for 2001-2010,
which may be higher or lower than the growth rates for the years
1996-2001. EPA's analysis of the costs of complying with these
budgets, however, was conducted using IPM, which incorporates
internally consistent growth assumptions--i.e., the growth for 1996
through 2001 is based on IPM assumptions for 1996 through 2001, and
the growth for 2001 through 2010 is based on IPM assumptions for
2001 through 2010. These IPM growth forecasts are consistent with
the NERC forecasts.
Docket # A-97-43, Item # VI-C-01, ``Response to Significant
Comments on the Proposed Findings of Significant Contribution and
Rulemaking on Section 126 Petitions for Purposes of Reducing Interstate
Ozone Transport,'' April 1999 at p. 112.
The first two sentences in the response refer to ``growth rates,''
``growth assumptions,'' or ``growth,'' but unfortunately fail to
provide further clarification as to what type of ``growth'' is being
referenced. The first sentence
[[Page 21874]]
indicates that, for budget purposes, EPA determined the ``growth
rates'' for 1996-2007 based on ``the growth rates in IPM for 2001-
2010.'' The second sentence indicates that, for cost analysis purposes,
EPA used ``growth'' for 1996-2001 ``based on IPM assumptions for 1996
through 2001'' and ``growth'' for 2001 through 2010 ``based on IPM
assumptions for 2001 through 2010.'' However, the response fails to
explain that the references in the first sentence to ``growth rates''
are to growth in heat input, which is an output from IPM runs for the
years 2001 and 2010, while the references in the second sentence to the
``growth assumptions'' and ``growth'' for 1996-2001 and 2001-2010 are
to growth in electricity demand, which is an input into the IPM. The
third sentence confirms that the ``growth assumptions'' in the second
sentence are--like the ``North American Electric Reliability Council
(NERC) forecasts''--for electricity demand.
The second sentence of the Response to Comment document should not
be read to indicate that EPA had available IPM-generated growth rates
in heat input for the 1996-2001 period. It is simply not true that EPA
had that data available. Rather, EPA had available IPM-generated heat
input data for only 2001-2010, and EPA developed the budgets and cost
analyses in the manner described in section V.B.1 of this notice.
Therefore, of course, EPA did not use such data ``to assess emission
reduction costs'' and could not have used such data as another way ``of
generating 2007 utilization projections.'' Appalachian Power v. EPA,
249 F.3d at 2054.\5\
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\5\ The portion of EPA's brief on the growth rate issue in
Appalachian Power v. EPA reflects the confusing response to
comments. As discussed above and contrary to the suggestion in the
brief (at 71-2), the cost-effectiveness run and EPA's cost-
effectiveness analysis did not use ``1996-2001 growth rates'' for
heat input.
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C. Justification for EPA's Methodology and Reasonableness of EPA's
Underlying Assumptions
1. Court's and Commenters' Concerns
While upholding in general EPA's use of the IPM and not finding
that any specific assumptions or other aspects of EPA's methodology
were unreasonable, the Court stated that ``even in the face of evidence
[i.e., actual State heat input in excess of EPA's projection]
suggesting the EPA's projections were erroneous, EPA never explained
why it adopted this particular methodology.'' Appalachian Power v. EPA,
249 F.3d at 1053.
Moreover, commenters raised concerns about certain assumptions that
EPA made in the IPM, or in using the results from the IPM, to develop
heat input growth rates. In particular, commenters were concerned
about:
(1) The assumption that State-by-State heat input growth rates,
derived from the IPM outputs for 2001 and 2010, were reasonably
representative of, and reasonably used to calculate, heat input growth
rates for 1996 to 2007.
(2) The assumption that electricity demand projections were
reasonably reduced by reductions under the CCAP; and
(3) The assumption that the locations of new units were reasonably
projected using currently available data on new units and the
historical distribution of generating capacity.
As discussed below, EPA believes that its methodology and, in
particular, all of the challenged assumptions had a reasonable basis.
2. EPA Reasonably Decided To Develop State NOX Emission
Budgets by Using Heat Input Growth Rates
As noted above, EPA's methodology for projecting 2007 heat input
was based, in essence, on establishing a baseline based on actual heat
input, and then applying an IPM-determined growth rate to that
baseline. The overall approach of using an actual baseline and applying
a growth rate was reasonable and consistent with the way EPA projected
utilization for other stationary source categories. (Docket # A-96-56,
Item # X-B-09, ``Development of Emission Budget Inventories for
Regional Transport NOX SIP Call'', U.S. EPA, Office of Air
Quality Planning and Standards, May 1999.)
Starting with an actual baseline obviously constitutes a reasonably
accurate starting point for the calculation. Because of the year-to-
year variability in heat input, as discussed below, EPA decided to
allow each State to use the higher of two years as the baseline. EPA
initiated the NOX SIP Call rulemaking in 1997, and so EPA
selected as the two years 1995 and 1996. EPA's approach overstated
total actual heat input for the region. Since some States had higher
heat input in one year and other States had higher heat input in the
second year, the total of the States' baselines exceeded the total heat
input for the States in either of the years.
Applying to that baseline an IPM-generated heat input growth rate
is also reasonable because the IPM provides a reasonably accurate
method of predicting growth in heat input. The model has been
thoroughly vetted through public comment in several rulemakings and
generally has been upheld by the Court in both the NOX SIP
Call Decision and an earlier decision. Appalachian Power v. EPA, 247
F.3d at 1052-53; Appalachian Power v. EPA, 135 F.3d 791, 814-15 (D.C.
Cir., 1998). As discussed below, EPA's approach of determining the
growth rate of State heat input from one modeled year (here, 2001) to a
later modeled year (here, 2010) minimized the effect of necessary,
simplifying assumptions used by the IPM and thereby increased the
accuracy of the determination.
EPA considered alternative ways to handle heat input growth in
determining State NOX emission budgets. For example, EPA
considered not allowing for heat input growth at all. Under this
method, EPA would base each State's NOX emission budget on
heat input as of a selected year for which historical data was
available, without accounting for changes in future heat input. In the
NOX SIP Call, EPA rejected this method, explaining that
although it would have been simpler, it ``may be viewed as less
equitable for States with significantly higher projected utilization,''
(62 FR 60318, 60351, Nov. 7, 1997).
EPA also considered using, as the State NOX emission
budget for each State, the amount of NOX emissions that the
IPM projected for the State in 2007 in the cost-effectiveness run.\6\
EPA did not use this approach for several reasons. First, this approach
would have made it difficult to accommodate changes in the State
inventory of EGUs as EPA received better information regarding existing
units. EPA undertook multiple notice-and-comment rulemakings to obtain
the most accurate data possible about existing units and received new
data through each rulemaking. It was relatively simple for EPA to use
this new information to adjust the State's 1995 and 1996 emission
inventories, and thus the State's baseline, and then apply projected
future growth from the IPM to adjust the State's NOX
emission budget. If instead EPA had used the IPM 2007 projected heat
input, then, each time new data were received, EPA would have had to
rerun the IPM for 2007 with the State inventory of EGUs revised to
include the new information. It would have taken significant resources
and time to change the IPM on several occasions to reflect this new
information.
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\6\ In addition, EPA considered, but rejected, the approach of
using a single, uniform heat input growth rate in developing all of
the State NOX emission budgets. (See section D.IV.10 of
this notice.)
---------------------------------------------------------------------------
Further, the IPM is likely to be more accurate in projecting State-
by-State
[[Page 21875]]
rates of change of an output from one year in an IPM run to another
year in that IPM run (here, growth in State heat input from 2001-2010)
than in predicting an actual output State-by-State in a particular year
(here, actual heat input in 2007). This is because modeling of complex
activities requires the use of simplifying assumptions in order to make
the model feasible--from the standpoint of resources and time--to run.
This is particularly true here, where EPA must develop State-by-State
projections of heat input that results from complex activities (i.e.,
the operation of the regional electricity market). (See sections V.C.3
and V.D.7 of this notice.) Because the same assumptions were made for
every year modeled, calculating differences between two model years
reduces any inaccuracies caused by these assumptions. Therefore, EPA
believes that, on a State-by-State basis, the IPM is likely to be more
accurate in projecting rates of change between modeled years.
For these reasons, EPA decided that the approach of applying an
IPM-generated heat input growth rate for each State to a baseline State
heat input based on historical data would be a reasonably accurate
predictor of the State's actual heat input in 2007 and a more accurate
predictor, and significantly simpler and less costly from an
administrative standpoint, than IPM's projection of the State's 2007
heat input.
3. State Heat Input Growth Rates Based on IPM Outputs for 2001-2010
Were Reasonably Representative of 1996-2007 Heat Input Growth
a. EPA's Methodology. A number of commenters suggested that instead
of using heat input growth rates based on 2001 to 2010 projections, EPA
should have used State heat input growth rates based on 1996 data and
2007 projections. EPA believes that relying on the IPM projections for
2001 to 2010 is reasonably accurate.
Although EPA had information on, and projections of, annual growth
rates in regionwide electricity demand from 1995 or 1996 to 2007 (which
EPA used as inputs to the IPM), EPA was not aware of any projected heat
input growth rates for that period for each State in the NOX
SIP Call region that were developed using a consistent set of
assumptions. See, e.g., 63 FR 57409. Since, as discussed in section
V.D.6 of this notice, electricity is generated, transmitted, and
distributed on a regional basis, consistent assumptions about regional
and subregional factors (e.g., demand for electricity, fuel costs, and
cost of new units) must be used to develop the heat input growth rates
for all States. The Court has already upheld EPA's decision to rely on
an internally consistent methodology for determining heat input, as
opposed to recommendations by various commenters favoring State-
specific growth rates that would have been inconsistent with each
other. Appalachian Power v. EPA, 249 F.3d at 1052-53.
Since EPA was not aware of any available consistent set of heat
input growth rate projections, EPA developed its own projections. EPA
decided to use the heat input values from IPM runs for 2001 and 2010 to
calculate a long term heat input growth rate for each State. Because,
as discussed above, the IPM is a comprehensive model of the electricity
market, EPA believes that it provides reasonable heat input growth rate
projections. Further, EPA believes that heat input growth rates for the
nine-year period 2001-2010 were reasonably representative of the
eleven-year period 1996-2007 because, among other things, the periods
overlap and are of similar length. In addition, EPA believes that the
assumptions used in the IPM runs for 2001 and 2010 are reasonably
applicable to the 1996-2001 period as well as 2001-2007. (See section
V.D.7 of this notice discussing assumptions in the IPM.) In fact, out
of the many assumptions in the IPM, commenters have pointed to only a
few that they believe differ pre- and post-2001. As discussed below,
EPA examined the assumptions discussed by commenters and maintains that
these assumptions do not differ in any way that would affect the
reasonableness of the heat input growth rates.
EPA considered developing heat input growth rates based on data
developed by OTAG. OTAG developed a heat input growth projection
separately for each individual State for the years 1990 to 2007 without
considering the interactions among the individual States. EPA chose to
use the IPM growth rates because, unlike the OTAG growth projections,
the IPM's were not developed separately for each State, but were
developed by analyzing performance of the electric industry as a
regionwide system. Therefore, the IPM growth rates are a more
internally consistent set of growth rates than the OTAG growth rates,
(62 FR 60353).
b. Cost of adding run years. Some commenters questioned why EPA did
not program the IPM to provide outputs for 1996 in order to generate
1996-2007 heat input growth rates (in lieu of 2001-2010 growth rates)
using the IPM. EPA believes that its decision to program the IPM
beginning with 2001 was reasonable.
As explained by the Court in the Section 126 Decision:
[T]he EPA has ``undoubted power to use predictive models'' so
long as it ``explain[s] the assumptions and methodology used in
preparing the model'' and ``provide[s] a complete analytic defense''
should the model be challenged. Small Refiner Lead Phase-Down Task
Force v. EPA, 705 F.2d 506, 535 (D.C. Cir. 1983) * * * (citations
and internal quotation marks omitted). That a model is limited or
imperfect is not, in itself, a reason to remand agency decisions
based upon it.
Ultimately * * * we must defer to the agency's decision on how
to balance the cost and complexity of a more elaborate model against
the oversimplification of a simpler model. We can reverse only if
the model is so oversimplified that the agency's conclusions from it
are unreasonable. Id.
Appalachian Power v. EPA, 294 F.3d at 1052.
The IPM was programed to model specified years starting with 2001.
EPA selected these run years to provide information not just for the
NOX SIP Call and Section 126 Rule, but also for several
other programs over the next few years, including implementation
programs for the recently revised National Ambient Air Quality
Standards for ozone and fine particles. (Regulatory Impact Analysis for
the NoX SIP Call, FIP and Section 126 Petitions, Volume 1:
Costs and Economic Impacts, September 1998, at p.4-2., http://www.epa.gov/ttn/rto/sip/related.html#doc.) Adding more run years (e.g.,
1996) would not have provided information useful for those other
programs, but would have added significant complexity and costs to the
modeling.
The model consists of model plants that represent individual
generating units (e.g., fossil-fuel-fired boilers, nuclear units and
hydro-electric units) that comprise the inventory of electricity
producers. Duplicating precisely each of the boilers and generators
would be impracticable; accordingly, the model aggregates the fossil-
fuel fired units into a series of model plants and aggregates the non-
fossil-fuel fired units into separate model plants. (Docket # A-96-56,
Item # V-C-03, Report on Analyzing Electric Power Generation Under the
Clean Air Act Amendments, at p. 5.)
For each run year, EPA provides various inputs (i.e., constraints),
such as the requirement to meet a certain electricity demand for each
season and each geographic subregion modeled. In addition, for each run
year, the model provides variables, which are values based on the
inputs, such as the level of electricity generation from each model
[[Page 21876]]
plant and the level of emission controls at a model plant. For each
year the model is run, the model must optimize (i.e., determine the
least cost scenario, including fuel mix, emission controls, and amount
of operation) for every model plant to reach each constraint in the
model. The IPM includes thousands of constraints and variables.
The complexity of the model--its simulations, inputs, and
variables--means that each additional run year adds many more
calculations to the model, a task that requires time and resources. To
keep the model manageable, meet time schedules, and conserve resources,
adding an additional run year would have meant simplifying other
assumptions within the model. In other words, because the number of
equations would be increased by adding constraints and variables
associated with a new run year, other ways would have had to be found
to reduce the number of equations. This would have meant either
reducing the number of (i) model plants; (ii) constraints, such as the
number of subregions, which determines the number of electricity demand
constraints; or (iii) variables, such as NOX emission
control technology options.
When developing the model, EPA had to decide ``how to balance the
cost and complexity of a more elaborate model against the
oversimplification of a simpler model.'' Small Refiner Lead Phase-Down
Task Force v. EPA, 705 F. 2d 506, 535 (D.C. Cir., 1983). Balancing
these factors, EPA decided to develop the IPM to start in 2001. Under
these circumstances, the model adequately served the needs of several
programs--the NOX SIP Call, the Section 126 Rule, and other
programs. Moreover, EPA believed that heat input growth rates for the
years 2001 to 2010 were reasonably representative of growth during the
period 1996 through 2007. In EPA's judgment, any further refinement in
the heat input growth rate that may have resulted from adding a 1996
run year would not have merited the additional time and cost and may
have been offset by the increase in model inaccuracy that may have
resulted from the consequent need to further simplify or otherwise
limit the model. Therefore, EPA decided, on balance, that it was
reasonable to use 2001-2010 heat input growth rates to develop the 2007
State NOX emission budgets.
c. Consistency of assumptions. Some commenters questioned whether
the 2001-2010 heat input growth rate was representative of growth
during 1996-2007, alleging that specific assumptions in the IPM were
different for those two time periods and would result in different heat
input growth rates for those periods.
As noted above, one of the inputs for the base case and cost-
effectiveness IPM runs for 2001 and 2010 was projected electricity
demand. To determine electricity demand, EPA began with available
information for actual annual electricity demand for 1997, projected
the increases out to the IPM run years, and then reduced those
projections to take account of reductions in electricity demand
expected to result from CCAP. CCAP is a Federal program started in 1993
to significantly reduce emissions of carbon dioxide (CO2)
and thereby address concerns about global climate change. Since
consumption of fossil fuel to generate electricity is a significant
contributor to CO2 emissions, a major component of CCAP was
a broad set of voluntary programs designed to reduce electricity demand
and generation.
Commenters claimed that the assumptions for electricity demand
reductions due to CCAP for the years 2001-2010 differed from what would
have been used for the years 1996-2001. According to a commenter:
[b]ecause EPA's assumed CCAP reductions increased by almost 300%
from 2001 to 2010 . . . the electricity demand growth rate that EPA
used in its analysis decreased substantially from 2001 to 2010. Thus
the record establishes that EPA itself assumed vastly different
electricity demand growth rates for the 1996-2000 period than the
2001-2010 period * * *
In fact, however, the commenter's conclusion is contradicted by the
record. The data in the record supporting IPM runs shows that EPA
assumed electricity demand growth rates of 1.6% for 1997-2000 and 1.8%
for 2001-2010. Actual electricity demand in 1996 was 3,305 billion
KWh.\7\ EPA's projected electricity demand without accounting for CCAP
was 3,575 billion KWh for 2001 and 4,198 billion KWh for 2010. EPA
projected that CCAP would result in electricity demand reductions of
100 billion KWh for 2001, and 389 billion KWh for 2010 (Analyzing
Electric Power, Appendix 2 at A2-2). After subtracting projected CCAP
electricity demand reductions from assumed electricity demand, EPA
projected electricity demand of 3,475 billion KWh for 2001,and 3,809
billion KWh for 2010. This resulted in an annual growth rate for
adjusted electricity demand of 1.03% for 1996-2001 and 1.07%, for 2001-
2010. (Docket # A-96-56, Item # XV-C-22.) In short, while EPA assumed
somewhat lower CCAP reductions in 1996-2001 than in 2001-2010, the
Agency also assumed lower electricity demand growth without CCAP
adjustments in 1996-2001 than in 2001-2010. The net result was that
EPA's projected electricity demand growth rates after CCAP adjustments
were very similar for 1996-2001 and 2001-2010.\8\
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\7\ Note that while EPA started its electric demand forecasts
using NERC forecasts for the year 1997, EPA used here the actual
electricity demand for 1996 in order to demonstrate the effective
growth rate for 1996-2001, which is referenced by the commenters.
\8\ In addition, EPA notes that since the CCAP reductions are
assumed to occur on a nationwide basis, any assumptions regarding
CCAP would not have been the cause of State-by-State variation in
heat input growth rates.
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4. EPA Did Not ``Double Count'' Electricity Demand Reductions Under
CCAP
As noted above, one input into the IPM was electricity demand. EPA
projected electricity demand by starting with certain industry-
sponsored forecasts for demand and then reducing them by projected CCAP
demand reductions in accordance with a multi-agency task force's
projections, made for purposes of a U.S. Department of State report on
the subject.
EPA received comments on the August 3, 2001 NODA alleging that EPA
failed to explain, and, indeed, double counted the projected
electricity demand reductions under CCAP. According to commenters, the
double counting led EPA to underestimate projected heat input for 2007.
The EPA believes that its CCAP assumptions are well supported by the
record and that no double counting occurred.
a. EPA's Methodology for Determining Electricity Demand. EPA
started with electricity demand forecasts from the NERC, which is a
voluntary association of most of the large electricity generators and
sellers in the U.S. and whose purpose is to promote the reliability and
security of the electricity system. NERC divides the continental U.S.
into regions, each of which has its own council comprised of
representatives of the utilities generating and selling electricity in
the region. Each utility makes forecasts of electricity demand by its
end-use customers and of electricity supply available to that utility
and submits these forecasts to the appropriate NERC region. NERC
compiles the individual utilities' demand and supply projections by
region and reports the compiled projections to the Energy Information
Agency (EIA).\9\ Since NERC forecasted
[[Page 21877]]
electricity demand out to only 2006 at the time that EPA was developing
the IPM for the NOX SIP Call, EPA used the NERC electricity
demand projections for 1996 to 2006 and extended them to 2010 using a
1995 forecast by DRI, a private consulting group. (Analyzing Electric
Power, Appendix 2 at A2-3.)
---------------------------------------------------------------------------
\9\ EIA is an independent agency within the U.S. Department of
Energy (DOE) that is responsible for, among other things,
collecting, compiling, and reporting information on the U.S.
electricity industry.
---------------------------------------------------------------------------
Then, EPA reduced these electricity demand projections by the
amounts of demand reductions expected to occur as a result of CCAP. As
described above, CCAP, a Federal program established in 1993, includes
a broad collection of voluntary programs designed to reduce electricity
demand and generation to reduce CO2 emissions. Some of these
programs were in existence before CCAP's establishment in 1993 and were
incorporated into CCAP, along with a new set of programs. CCAP was
updated in 1995, a process that included revised estimates of the
effectiveness of its programs, based on public input solicited through
a Federal Register notice (60 FR 44022, Aug. 24, 1995) and a public
hearing held on September 22, 1995. See Review of Climate Change Action
Plan: Request for Public Comment; Notice of Meeting, 60 FR 44022,
August 24, 1995 (Council on Environmental Quality solicitation of
public comment).
In 1997, the U.S. Department of State (``State Department'')
developed and issued a report, Climate Action Report, setting forth the
expected results from CCAP. The report was developed to fulfill an
obligation under the 1992 United Nations Framework Convention on
Climate Change.\10\ The State Department first issued a draft report
and requested public comment on two occasions, in December 1996 and May
1997. (See Preparation of Second U.S. Climate Action Report: Request
for Public Comments, 62 FR 25988, May 12, 1997). After considering the
comments received, the State Department issued the final report in
1997. The report presented a consensus view of the Federal agencies
involved, including EPA, the U.S. DOE, and the State Department.
---------------------------------------------------------------------------
\10\ Parties to the 1992 United Nations Framework Convention on
Climate Change (including the U.S.) agreed to submit reports
detailing their emissions of greenhouse gases (such as
CO2) and any strategies to reduce those emissions.
---------------------------------------------------------------------------
In particular, to determine the effectiveness of the CCAP programs,
an interagency work group polled the program managers at EPA, DOE, the
U.S. Department of Transportation, and the U.S. Department of
Agriculture who were responsible for the various CCAP programs. The
program managers provided estimates of reductions for each CCAP
program, generally expressed in billion kilowatt hours (billion KWh) of
electricity usage and mmBtu of heat input, or other units of measure
appropriate for the program. The workgroup compiled and reviewed those
projections (Docket # A-96-56, Item # XIV-F-03). EPA used those
estimates to reduce the NERC-based electricity demand projections for
2001 through 2020. (See Analyzing Electric Power, Appendix 2, at A2-3).
In addition, DOE used those estimates to project the amount of
greenhouse gas emissions reductions that would result from the CCAP
programs. These emissions reductions and other types of savings were
included in the State Department's Climate Action Report.
b. The record contains sufficient documentation of the additional
CCAP demand reductions that EPA took into account. Some commenters
claimed, in response to the August 3, 2001 NODA, that EPA did not
provide adequate documentation to explain how the electricity demand
reductions under CCAP were derived.
EPA notes that this issue--as well as the issue of double-counting
of CCAP demand reductions, discussed below--was not raised in any of
the rulemakings to this point or brought to the Court's attention in
either the Section 126 or the Technical Amendments cases. Commenters
had a full opportunity to raise the issues during the development of
the NOX SIP Call and Section 126 Rule. In fact, some of the
parties raising the issues now claimed, in comments in the
NOX SIP Call and Section 126 rulemakings, that no CCAP
electricity demand reductions should be considered in projecting
electricity demand. These commenters based these claims on the ground
that CCAP was a voluntary, rather than a mandatory, program. Thus,
these commenters clearly had the opportunity during the earlier
rulemakings to raise the issues concerning CCAP that they are raising
only now.
The lack of attention to these issues by commenters during the
earlier rulemakings has some impact on the extent to which the record
addresses them. Had commenters raised these issues earlier, EPA would
have been obliged to respond, and the record would have included that
dialogue. Thus, if the commenters view the record as deficient, their
failure to raise this issue at several earlier junctures should be
considered. Moreover, it is questionable whether EPA is required, at
this point, to address these issues in light of the commenters' earlier
opportunities.
Even so, EPA maintains that its assumptions about the CCAP demand
reductions are well supported. The IPM documentation shows the amount
of actual electricity demand in 1997, and the amount of projected
electricity demand from 1997 to 2010 (and beyond), all expressed in
billion Kwh, (IPM basecase modeling runs, http://www.epa.gov/capi/ipm/npr.htm). As noted above, EPA based these projections on information
supplied by NERC. In addition, other IPM documentation shows the total
amount of CCAP reductions, expressed in billion kwh, for 2001 through
2010 (and beyond) (Analyzing Electric Power, Appendix 2 at A2-2).
These total amounts of CCAP reductions ``were taken from the
supporting analysis that was done to forecast future U.S. carbon
emissions from the power industry that appeared in the U.S. Department
of State's Climate Action Report, July 1997,'' (Analyzing Electric
Power, Appendix 2 at A2-3). Specifically, this supporting analysis
consisted of a spreadsheet, entitled ``CCAP Inputs for April 1997
Update,'' developed by the above-described interagency work group
tasked with projecting the amount of reductions for each CCAP program,
(Docket # A-96-56, Item # XIV-F-03). The workgroup solicited
information from the various agencies charged with administering CCAP
programs and, based on that information, prepared the spreadsheet. No
commenter requested this information during the NOX SIP Call
and Section 126 rulemakings until the comment period for the August 3,
2001 NODA. At that time, EPA provided the spreadsheet--annotated to
reflect the adjustment related to the NERC forecasts, described below--
to commenters when requested and placed it in the docket, (Letter from
John Seitz to Andrea Bear Field, August 31, 2001, Docket #A-96-56, Item
#XIV-F-01, included as Attachment D to Docket Item #A-96-56-XIV-D-31).
The spreadsheet identifies the amount of reductions, expressed in
billion Kwh and mmBtu of each of the dozen or so relevant CCAP
programs, for the years 2000 and 2010 (as well as 2020). The amount of
reductions from these programs for 2010--after the adjustment related
to the NERC forecasts, described below--equals the amount included for
that year in Analyzing Electric Power, Appendix 2 at A2-2. Moreover,
the IPM documentation states that ``EPA did a linear interpolation'' to
determine the amount of CCAP reductions assumed for years between 2000
and 2010, including 2001, (Analyzing Electric Power, Appendix 2 at A2-
3).
One commenter claimed that it was not clear how EPA converted the
CO2
[[Page 21878]]
reductions cited in the State Department's Climate Action Report into
the electricity demand reductions set forth in Analyzing Electric Power
or the spreadsheet used by EPA to adjust the NERC electricity demand
forecasts. Actually, the CO2 reductions in the State
Department report were based on the electricity demand reductions in
the spreadsheet, not the other way around. As noted above, these
electricity demand reductions were developed by the agencies involved
in implementing CCAP and then were converted to CO2
reductions for purposes of the State Department report, using a U.S.
DOE model (the Integrated Dynamic Energy Analysis Simulation (IDEAS))
of the U.S. energy system. These values were then included in the
proposed and final versions of that report.\11\
---------------------------------------------------------------------------
\11\ A commenter questioned the accuracy of the projections of
reductions attributable to the programs on the spreadsheet because
those projections were done a program-by-program basis, without
consideration of the interactive effects of the programs. The IDEAS
model run, noted above, in effect considered those interactive
effects on the programs and provided as an output the total
electricity savings expressed in billion Kwh (along with other
outputs, including the emissions reductions). The total electricity
savings indicated by the IDEAS model run are virtually identical to
the total amounts projected on a program-by-program basis. (Docket
#A-96-56, XIV-F-03).
---------------------------------------------------------------------------
c. Commenters failed to prove their claim that NERC and EIA
projections already included the CCAP demand reductions that EPA took
into account. Commenters suggested that the NERC electricity demand
forecasts that EPA adjusted for certain CCAP reductions already assumed
those reductions. According to commenters, the NERC members that
supplied the information used in the NERC forecasts would have been
aware of, and in some cases participated in, CCAP programs and so
``would have * * * taken into account'' CCAP programs in the
information supplied to NERC. The commenters emphasized that NERC
projected electricity demand growth at an annual rate of 1.7%, which is
higher than EPA's projection of 1.1%, and therefore concluded that EPA,
by purportedly double-counting CCAP reductions, underestimated
electricity demand. The commenters made a similar point with respect to
electricity demand forecasts by EIA, emphasizing that in 1997, EIA
projected electricity demand growth at 1.6% annually, and that, in
making this projection, EIA explicitly noted that it was taking account
of CCAP.
As discussed below, after weighing all the evidence in the record
relevant to the claim that EPA double-counted CCAP demand reductions,
EPA concludes that no such double-counting occurred and that commenters
failed to show otherwise.
(i) NERC Forecasts
When EPA developed electricity demand forecasts for the
NOX SIP Call and the Section 126 Rule, the NERC forecasts
did not mention the energy efficiency programs as a factor that was
considered. NERC explained only that it considered an ``economic
variable, weather and a random component that expresses unknown
determinants of net energy for load.'' (Docket # A-96-56, Item # XV-C-
23, Peak Demand and Energy Projection Bandwidths: 1997-2006
projections, p. 4, Load Forecasting Work Group of the Engineering
Committee North American Electric Reliability Council, June 1997).
Consequently, EPA had to exercise its best judgement in determining the
extent to which the NERC forecasts took into account CCAP demand
reductions. Rather than assuming, from the absence of any affirmative
statements by NERC about CCAP reductions, that NERC did not consider
any CCAP reductions, EPA took the more conservative approach of
assuming that some of the reductions were likely to have been
considered by NERC. (See Docket # A-96-56, Item # XIV-F-03.) EPA
reduced the NERC electricity demand forecasts only to take account of
the additional CCAP demand reductions beyond those EPA believed were
included in the NERC forecasts. EPA believed that it was appropriate to
factor in these additional CCAP demand reductions ``given the extensive
Administration, State, and business efforts underway and the promising
early results that EPA has seen in some of the CCAP's programs that
have substantially lowered electric energy use and saved money for many
businesses.'' (Responses to Significant Comments on the Proposed
Finding of Significant Contribution and Rulemaking for Certain States
in the Ozone Transport Assessment Group (OTAG) Region for Purposes of
Reducing Regional Transport of Ozone, September 1998, at 182).
In applying this approach to CCAP reductions, EPA did not factor in
reductions from either the Green Lights Program or the Energy Star-
Products Office Equipment Program, which existed before CCAP and that
were simply put under the umbrella of CCAP when CCAP was established in
1993. Green Lights was one of EPA's earliest voluntary energy
efficiency programs and was aimed at encouraging the use of energy
efficient lighting products. This program was expanded under CCAP.
Similarly, the Energy Star Products program included a pre-1993 program
to encourage the purchase of energy efficient office equipment. EPA
assumed that because Green Lights and Energy Star Products-Office
Equipment were pre-existing programs, they were better established and
their benefits more predictable by the utilities in forecasting demand;
as a result, EPA assumed that the NERC forecasts were more likely to
have already taken their reductions into account. These two programs
were categorized as commercial programs and were projected to result in
over 89 billion Kwh in reduced electricity demand by 2010. (Docket # A-
96-56. Item # XIV-F-01). By comparison, the remaining CCAP commercial
programs resulted in reduced electricity demand of 119.6 billion Kwh.
Id. Therefore, EPA assumed that the NERC forecasts accounted for over
42 percent of the reductions from the commercial CCAP programs,
including the pre-1993 programs.
EPA also decided not to include reductions from a fuel cells
program and renewable energy program, which were projected to total
24.5 billion Kwh by 2010, both for reasons of erring on the side of the
conservative (not including those reductions had the effect of
increasing electricity demand) and because adding them would have
created some technical modeling complexities. Specifically, EPA would
have had to decide at what level, and where, to allocate this capacity
among the States within and outside of the NOX SIP Call
region. EPA decided, rather than make that judgment, to err on the side
of the conservative by assuming that the fuel cell program and
renewable energy program did not reduce electricity. In addition, the
emission factors for fuel cells and biomass facilities that could have
been employed were highly uncertain. (See Docket # A-96-56, Item # XIV-
F-01).
Nor did EPA factor in reductions from the Climate Challenge
program, which was initiated in 1994 as part of CCAP. Under Climate
Challenge, utilities agreed to voluntarily reduce emissions of
CO2 through projects for, e.g., improving electricity
generation or transmission efficiency. Because Climate Challenge was
specifically directed towards utilities, EPA assumed that the utilities
submitting their demand estimates to NERC would be familiar with the
program and would be more likely to have taken demand reductions from
that program into account. In any event, the Climate Action Report
workgroup did not assign a specific amount of reductions to this
program.
[[Page 21879]]
All told, EPA assumed that CCAP programs would result in 389
billion Kwh in reductions by 2010 and further assumed that an
additional 113.5 billion Kwh from CCAP programs and their pre-1993
predecessors, or 22.6% of the total, had already been included in the
NERC estimates. Thus, it is evident that EPA conservatively assumed
that NERC took into account demand reductions from some CCAP programs,
even though NERC's documentation did not indicate that any CCAP
reductions were taken into account and no utility commenter provided
documentation that the demand forecasts they submitted to NERC assumed
any CCAP reductions.\12\
---------------------------------------------------------------------------
\12\ Many other CCAP programs generated energy savings but in
ways other than reducing electricity demand, so that EPA did not
take into account benefits from these programs either.
---------------------------------------------------------------------------
On the other hand, EPA did factor into the electricity demand
projections the reductions from the CCAP programs initiated in 1993 or
later that were aimed at a broader group of potential participants than
only utilities. Some of the largest of these programs included (i)
WasteWise (a voluntary program designed to reduce municipal waste
through waste prevention and recycling); (ii) Motor Challenge (a
program designed to help industry realize electricity savings by
providing industry with the technical expertise concerning management
of electric motor systems and purchase of more energy efficient
electric motors); (iii) Rebuild America (a program designed to
encourage partnerships of various types of companies and
organizations--ranging from builders to local governments--to retrofit
existing public housing as well as commercial and multifamily buildings
to be more energy efficient); (iv) Energy Star Buildings (a program
designed to encourage individual building owners, developers, and
others to make comprehensive, energy-efficient building upgrades); and
(v) Residential Appliance Standards (a program under which DOE would
establish by rulemaking standards for improved energy-efficient
appliances such as room air conditioners, refrigerators, water heaters,
and others). (Docket # A-96-56, Item # XIV-F-01; Climate Action Report,
Appendix A). Because such programs were relatively new and were geared
primarily to companies other than utilities, it is less likely that
utilities would have included demand reductions from these programs in
their electricity demand projections.
A commenting group of utilities argued that the NERC forecasts
likely already included the CCAP reductions that EPA used to adjust
those forecasts, resulting in double-counting. The commenting utility
group noted that some utilities participated in two CCAP programs
(i.e., WasteWise and Motor Challenge) and speculated that the
participating utilities ``would have'' included CCAP reductions in
developing the information provided for the NERC forecasts.
However, utilities comprise only a small number of companies
participating in WasteWise and Motor Challenge. In 1996, WasteWise
involved over 600 partners, representing over 30 industries, including
some utilities. (Docket # A-96-56, Item # X-V-C-24, Wastewise, Third
Year Progress Report, USEPA, November, 1997, at p.2.) Motor Challenge
is aimed primarily at industrial end-users, not utilities, (60 FR
61443-47, Nov. 29, 1995). Thus, the commenter's evidence that a few
utilities were among the many participants in these two programs
provides a very weak basis for speculating that the NERC forecasts
included CCAP demand reductions factored in by EPA. Similarly, many
other CCAP programs, including the Rebuild America and Energy Star
Buildings programs, were generally directed at entities other than
utilities.
Moreover, except for Climate Challenge, the CCAP programs are
designed to achieve electricity demand reductions from a wide range of
electricity end-users (i.e., residential, commercial, and industrial
end-users) and were relatively new--only a few years old when the
utilities reported their 1997 demand estimates to NERC. The interagency
workgroup had estimated amounts of demand reductions from these
programs on a national basis, but had not broken those estimates down
to the NERC region level that was the basis for individual utilities'
reports to NERC. Accordingly, it appears that the individual utilities
would have had relatively little experience in analyzing the extent to
which their particular customers followed the CCAP programs and would
not have had any other source of information for quantifying the CCAP
demand reductions in their respective regions.\13\
---------------------------------------------------------------------------
\13\ For example, the Residential Appliance Program depended on
a series of DOE regulations establishing standards for numerous
appliances. By 1997, DOE had not yet promulgated the first of these
regulations. As of 1997, the DOE program manager would nevertheless
be in a position to estimate the impact of this program on a
national level for future years, but individual utilities estimating
electricity demand in their areas would not be in a position to do
so.
---------------------------------------------------------------------------
For these reasons, it seems reasonable to conclude that as of 1997,
the only CCAP program reductions that utilities are likely to have
included in their reports to NERC would have been the few older
programs or those primarily targeting utilities, and not the many other
CCAP programs. Indeed, while a commenting group of utilities speculated
that utilities must have taken CCAP into account in submitting their
electricity demand information to NERC in 1997, EPA did not receive any
direct evidence from the utilities that made the submissions stating
(much less demonstrating) that their submissions actually took into
account any specific CCAP programs or otherwise reflected any specific
demand reductions.\14\ Particularly, in light of the silence of the
individual utilities about what CCAP reductions they actually included
(as distinguished from speculation about what they would have
included), EPA maintains that its assumptions about what CCAP
reductions were included are reasonable.
---------------------------------------------------------------------------
\14\ Indeed, several commenters critical of EPA's electricity
demand assumptions nevertheless acknowledged that it is unclear to
what extent individual utilities incorporated CCAP programs into
their demand projections. (Docket # A-96-56, Item # XIV-D-14,
Michigan, Attachment, p. 5, and Item # XIV-D-31, UARG, Attachment H,
p. 7).
---------------------------------------------------------------------------
In addition, the argument that utilities accounted for all CCAP
reductions is undercut by utilities' comments in the NOX SIP
Call proceeding. Several utilities commented that because CCAP
reductions are voluntary, such reductions should not be considered when
making future demand assumptions. Given this view of the CCAP
reductions, it seems doubtful that these utilities would have
considered, in their demand forecasts submitted to NERC, the CCAP
reductions factored in by EPA. Moreover, an analysis, included in
comments by the utility group on whether the NOX SIP Call
would have an impact on the reliability of the region's electricity
supply in meeting electricity demand, did not take into account any
demand reductions under CCAP (Responses to Significant Comments on the
Proposed Finding of Significant Contribution and Rulemaking for Certain
States in the Ozone Transport Assessment Group (OTAG) Region for
Purposes of Reducing Regional Transport of Ozone, September 1998, at
181-82; see also Docket # A-96-56, Item # V-J-66, UARG briefing
entitled ``The Impact of EPA's Regional SIP Call on the Reliability of
the Electric Power Supply in the Eastern United States,'' September 11,
1998.)
Finally, one utility commenter stated that NERC's forecasts were
unlikely to consider CCAP demand reductions. The commenter explained:
[[Page 21880]]
NERC's reliability planning mission suggests just the opposite.
NERC projections of future demand growth are used to determine how
much capacity is needed to meet demand to ensure electric system
reliability. The projections are a compilation of individual utility
projections sent to each of the NERC regional councils to ensure
adequate supply exists to meet demand in each region. The
projections must be conservative and err on the side of overstating
demand to avoid supply shortfalls--it is of little consequence if
NERC overestimates demand, but of potentially great consequence if
it underestimates it. For this reason, although the compiled nature
of NERC's forecasts makes it virtually impossible to assess its
underlying assumptions, it is reasonable to assume NERC projections
largely ignore new, uncertain electricity demand dampening impacts,
such as voluntary programs with no clear track record of affecting
electricity consumption. (See Docket # A-96-56, Item # XIV-E-01,
Letter from Mark Brownstein, Public Service Electric & Gas, Sept.
15, 2001, at p. 8)
(ii) EIA Forecasts
Several commenters pointed out that NERC's electricity demand
forecast (1.8% demand growth per year) and EIA's electricity demand
forecast (1.7% demand growth per year) are similar and higher than
EPA's forecast. Emphasizing that EIA explicitly took CCAP reductions
into account, commenters suggested that the EIA forecast factored in
the proper amount of CCAP demand reductions and that the similarity of
the EIA and NERC forecasts therefore shows that the NERC forecasts
already properly factored in such demand reductions.
However, EIA's explanation, in the Annual Energy Outlook for 1998,
of its electricity demand forecast indicated that while EPA factored
into its forecasts all the CCAP demand reductions projected by the
State Department's Climate Action Report, described above, EIA factored
into its forecasts only a small portion of those reductions. This
different treatment of CCAP reductions explains much of the difference
in demand reductions between EIA and EPA.
The Climate Action Report organizes virtually all of the CCAP
programs that affect electricity demand into three categories:
residential, commercial, and industrial, (Climate Action Report, Table
1-2). The report indicates that the residential and commercial programs
were expected to generate reductions of carbon emissions totaling 53
million metric tons by 2010. Id. Not including the reductions from
programs that EPA assumed were included in the NERC estimates, EPA
reduced projected electricity demand in 2010 due to these programs by
282.5 billion KWh (Docket # A-96-56, Item # XIV-F-01). EIA, however,
reduced projected electricity demand in 2010 from these programs by
much less. In explaining its analysis of the impact of CCAP residential
and commercial programs, EIA stated:
Other CCAP programs which could have a major impact on
residential energy consumption are the Environmental Protection
Agency's (EPA) Green Programs. These programs which are cooperative
efforts between the EPA and home builders and energy appliance
manufacturers encourage the development and production of highly
energy-efficient housing and equipment. At fully funded levels,
residential CCAP programs are estimated by program sponsors to
reduce carbon emissions by approximately 28 million metric tons by
the year 2010. For the reference case, carbon reductions are
estimated to be 8 million metric tons, primarily because of
differences in the estimated penetration of energy-saving
technologies. * * *
At fully funded levels, commercial CCAP programs are estimated
by program sponsors to reduce carbon emissions by approximately 25
million metric tons by the year 2010. For the reference case, carbon
reductions are estimated to be just over 9 million metric tons in
2010, primarily because of differences in estimated penetration of
energy-saving technologies.
(Annual Energy Outlook 1998 (AEO98), Energy Information Administration,
December 1997 at 209-10).
In other words, EIA believed that CCAP residential and commercial
programs would be about one-third as effective at reducing energy use
(including electricity use) as the State Department and EPA and other
sponsors projected and included the lower estimate of the energy use
reductions in the ``reference case'' on which EIA based its electricity
demand forecasts.
EIA similarly assumed much fewer energy savings from CCAP
industrial programs than EPA believed based on the Climate Action
Report. As EIA explained:
For their annual update, the program offices estimated that full
implementation of these programs would reduce industrial electricity
consumption by 20 billion kilowatt hours * * * However since the
energy savings associated with the voluntary programs are, to a
large extent, already contained in the AEO98 baseline total CCAP
energy savings were reduced. Consequently, CCAP is assumed to reduce
electricity consumption by 9 billion kilowatt hours. Id. at 210.
EIA essentially assumed that CCAP industrial programs resulted in
relatively few additional energy saving activities beyond those
activities that industrial companies were already carrying out and that
were therefore already reflected in the ``AEO98 baseline'' or
``reference case'' on which EIA based its electricity demand forecasts.
By comparison, the State Department analysis projected that industrial
CCAP programs would generate reductions of 96.4 billion Kwh (counting
an adjustment from programs categorized as commercial) (Docket # A-96-
56, Item # XIV-F-01). Thus, EIA projected that these industrial
programs would generate savings of less than one-tenth the amount that
EPA did.
As discussed above, EPA's more aggressive assumptions were taken
from the supporting analysis for the State Department's Climate Action
Report, which included reduction estimates that were developed through
interagency consultation and were subject to public comment. EPA
believes it was appropriate to use them.
Some commenters suggest that EPA should assess whether the CCAP
demand reductions are still justified based on any new information that
has become available since EPA issued the Section 126 Rule and the
Technical Amendments. EPA believes that it is appropriate for the
Agency to rely on the information that was available during the
rulemakings that resulted in those rules. However, EPA notes that
commenters did not provide any specific information showing that EPA's
projected CCAP demand reductions were incorrect.\15\ Further, new,
current information provides some confirmation that EPA's projected
CCAP demand reductions were reasonable. A recent report, (Docket # A-
96-56, Item # XV-C-25, The Power of Partnerships Energy Star and Other
Voluntary Programs--2000 Annual Report, EPA , 2001 at p. 6) states that
the Energy Star Program, which promotes highly efficient equipment such
as energy efficient refrigerators, dish washers, and windows, has
exceeded the level forecasted by CCAP for 2000 by more than 20 percent
of the forecasted level in the CCAP.\16\ Furthermore, EPA has expanded
CCAP to cover other uses of electricity (e.g., at hospitals) that will
increase savings further. (See Docket # A-96-56, Item # XV-C-26, EPA
Administrator Launches New Energy
[[Page 21881]]
Star Rating Tool for Hospitals, Honors First Hospital to Earn Energy
Star Label, November 15, 2001.)
---------------------------------------------------------------------------
\15\ A commenter stated that CCAP has not generated the expected
level of reductions because it did not achieve its goal of reducing
U.S. greenhouse gas emissions to 1990 levels. However, the amounts
of reductions projected by the Climate Action Report for particular
CCAP programs affecting electricity demand, which are the ones
relevant for present purposes, were far less than would be necessary
to reduce overall U.S. greenhouse gas emissions to 1990 levels.
\16\ Only a small part of the Energy Star reductions were
considered to be included in the NERC forecasts because they
involved programs in existence before 1993.
---------------------------------------------------------------------------
In short, commenters failed to show that the EIA electricity demand
forecast properly factored in the CCAP demand reductions, much less
that the NERC forecast (which was higher than the EIA forecast) already
included the CCAP demand reductions that EPA used to reduce the NERC
forecast.
(iii) Consistency With Regional Heat Input
Finally, EPA notes that ``the electricity demand reductions [under
CCAP] were distributed evenly throughout the United States, and
therefore have no influence on the share of the total amount of
NOX emissions that each State receives,'' (63 FR 57414). Any
overestimation of the CCAP demand reductions would therefore be likely
to result in regionwide projections of heat input being lower than
actual levels, rather than in only a few States' projections being
lower than actual levels. Yet, as explained below, EPA's heat input
projections have been reasonably accurate on a regionwide basis. EPA's
projections were 0.1% lower than actual regionwide heat input for 2000
and 2% higher than actual regionwide heat input for 2001. This
indicates that the CCAP assumptions were reasonable and did not lead to
``stark disparities between [EPA's] projections and real world
observations.'' Appalachian Power v. EPA, 249 F.3d 1054.\17\
---------------------------------------------------------------------------
\17\ EPA also notes that the Agency's use of assumed CCAP
reductions did not significantly affect the cost effectiveness of
the NOX emissions reductions on which the State
NOX emission budgets are based and did not change whether
the reductions met EPA's cost effectiveness criteria. As explained
in the NOX SIP Call, EPA examined the impact of the CCAP
reductions and found that ``even if the Agency did not assume the
CCAP reductions, it was still highly cost effective to develop a
regional level NOX budget for the electric power
industry, based on the level of control that EPA has assumed,'' (63
FR 57414). (See also Regulatory Impact Analysis for the Regional
NOX SIP Call, at 6-24 and 6-25, September 1998).
---------------------------------------------------------------------------
5. EPA's Assumptions Regarding the Location of New Units Were
Reasonable
Commenters on EPA's August 3, 2001 NODA expressed concern about the
methodology that EPA used to assign new units to individual States.\18\
The IPM divided the country into geographic regions that are based on
NERC regions. These regions are further subdivided to account for
transmission bottlenecks or areas that have different environmental
requirements. These regions and subregions do not correspond to State
boundaries, in many cases. For example, part of Illinois and part of
Missouri is split between two NERC Regions, the East Central
Reliability Area Council (ECAR) and the Mid America Interconnected
Network. Similarly, Virginia and Kentucky are split between ECAR and
the Southern Electric Reliability Council (SERC). While Alabama and
Georgia are both located entirely within the SERC Region, in IPM they
have been further subdivided into multiple IPM subregions to more
closely match the constraints within the electric distribution system.
The IPM runs indicated which new units would operate in which
subregions but did not specify in which States in these subregions. In
order to develop State budgets, EPA had to develop a methodology to
disaggregate these new units from the subregional level to the State
level.
---------------------------------------------------------------------------
\18\ This issue, like the CCAP issues, was raised by commenters
for the first time in response to the August 3, 2001 NODA and was
not raised in any earlier rulemaking or before the Court.
Nevertheless, EPA is addressing all these issues on the merits in
today's notice.
---------------------------------------------------------------------------
Under EPA's methodology, new units that had commenced construction
or received financing, at the time that the model was updated (i.e., in
1998) for use in the NOX SIP Call and the Section 126 Rule,
were included in the State in which they existed or were planned.
Second, new units that had not commenced construction or received
financing at that time, but that were projected by the IPM to be built
were assigned to an individual State based on the share of the
subregion's generation capacity (both fossil and non-fossil) that was
located in the State. EPA maintains that this was a reasonable approach
that took into account the then most current, available information on
new unit construction and financing.
EPA also notes that the only alternative approach suggested by
commenters was to use new information on the commencement of
construction and financing of new units. To the extent that this type
of information was available at the time that EPA updated the IPM
(i.e., in 1997) for use in the NOX SIP Call and the Section
126 Rule, EPA did use such information. However, EPA rejects the
approach of now using new information of this type, for units that have
been more recently built or are currently being built, that was not
available when the IPM was updated. EPA believes that it reasonably
relied on the most current information available around the time the
IPM was updated and that it would not be reasonable to require the
Agency to redo its analysis whenever, as inevitably occurs, more recent
information becomes available. Imposing such a requirement would be a
prescription for endless rulemaking.
It should also be noted that, while coal-fired and nuclear units
make up about 77% of existing electricity generation capacity (with
gas- and oil-fired units making up 13% and hydroelectric and renewal
facilities making up the rest), the only new units projected by the IPM
in the runs for the NOX SIP Call (and applicable to the
Section 126 Rule) were gas-fired units. Because new gas-fired units
will likely have very high levels of NOX control and much
lower NOX emissions as compared to existing units (see
discussion of new units' low NOX emissions in section V.D.8
of this notice), these units will have a much smaller impact on
NOX emissions than do existing units. Therefore, even if
some new units locate in different States than those projected by the
IPM, those units will not significantly increase the NOX
emissions in the States where they locate and so will not significantly
increase the stringency of the NOX emission reduction
requirements for other units in such States. In conclusion, EPA
believes that its heat input growth rate methodology--including the
challenged assumptions on new unit location, electricity demand, and
representativeness of the 2001-2007 heat input growth rates--is
reasonable.
D. Actual Heat Input Compared to EPA Projections of Heat Input
1. Court's and Commenters' Concerns
The Court expressed concern about the perceived discrepancies
between EPA's heat input projections and actual heat input data. The
Court stated: ``In Michigan and West Virginia, for example, actual
utilization in 1998 already exceeded the EPA's projected levels for
2007. This, on its face, raises questions about the reliability of the
EPA's projections.'' (Appalachian Power v. EPA, 249 F.3d at 1053). The
Court added that ``[f]urther growth projections that implicitly assume
a baseline of negative growth in electricity generation over the course
of a decade appear arbitrary, and the EPA can point to nothing in the
record to dispel this appearance.'' Id.
Commenters expressed similar concerns. Through the August 13, 2001
NODA, EPA put in the docket data indicating ozone season heat input for
each State in the NOX SIP Call region for the years 1997-
2000. Commenters pointed out that this data indicated that in 2000,
actual heat input for four other States--Alabama, Georgia, Illinois,
and Missouri--exceeded EPA's projected heat input for the year 2007.
Commenters claimed that this showed
[[Page 21882]]
that EPA's heat input growth rates and projections were unreasonable.
Through the March 11, 2002 NODA, EPA put in the docket comparable data
for the year 2001 and, subsequently, put in annual data for each State
for 1960-2000. (See Docket # A-96-56, Item #'s XV-C-18 and XV-C-19).
After careful review of these and other data in the record and the
Court's and commenters' concerns, EPA concludes that the available,
actual heat input does not indicate that the Agency's heat input growth
methodology is unreasonable.
2. EPA's Heat Input Projections for the Region Are Consistent With
Actual Heat Input Data
EPA's heat input projections for EGUs for the NOX SIP
Call region (21 States and the District of Columbia), taken as a whole,
are consistent with the actual heat input data that are available. EPA
projected heat input for 2007 by applying State heat input growth rates
to 1995 or 1996 baseline heat input. Although 2007 is the only year for
which EPA was projecting heat input and for which EPA established
NOX emission budgets for EGUs, the EPA methodology can be
applied to yield heat input values for other years, such as 2000 and
2001. When compared with actual heat input data now available for 2000
and 2001, EPA projections for those years are consistent with the
actual data.
Specifically, EPA's projections for total regionwide heat input for
EGUs are 6,250,350,678 mmBtu for 2000 and 6,328,056,922 mmBtu for
2001.\19\ These projections are 0.1% lower and 2% higher respectively
than actual regionwide heat input for EGUs for 2000 and for 2001 (see
Table 1).
---------------------------------------------------------------------------
\19\ As noted in the August 3, 2001 NODA, EPA's methodology
called for projecting 2007 heat input, not heat input at interim
points in time. However, for purposes of responding to concerns
about the reasonableness of the methodology, it is useful to examine
what the methodology would project if applied to interim points in
time when data concerning actual heat input are available.
---------------------------------------------------------------------------
In commenting on the data presented by the August 3, 2001 NODA,
which included the actual heat input values for years up to 2000,
commenters stated that the closeness of the regionwide projection for
2000 and actual regionwide heat input did not cast doubt on their view
that EPA's heat input growth methodology provided unreasonably low
growth rates. Rather, commenters asserted, the closeness was ``pure
coincidence'' resulting from EPA using an inflated 1995-1996 baseline
and applying to it a ``less-than-reasonable'' heat input growth rate.
According to the commenters, in subsequent years, EPA's regionwide
projection would diverge significantly from actual regionwide heat
input.
The actual heat input values for 2001 became available after the
submission of comments on the August 3, 2001 NODA and were put in the
docket. As noted above, the regionwide, actual heat input for 2001
remains quite close to, and in fact is a little lower than, the EPA's
regionwide heat input projection for 2001. Of course, regionwide
electricity demand, and so regionwide heat input, in the 2001 ozone
season were probably somewhat lower than they otherwise would have been
because of the unusual reduction in economic activity immediately after
the September 11, 2001 terrorist attacks. Even so, regionwide
electricity demand still grew slightly over 2000 ozone season levels.
(Docket #A-96-56, Item # XV-C-12, summarizing EIA electricity sales
data for the ozone season for the NOX SIP Call States during
1995-2001). With the continued closeness of EPA's projected and the
actual values for regionwide heat input, it is difficult to give the
commenters' assertion of ``pure coincidence'' much credence. Moreover,
as discussed above, EPA's methodology for developing heat input growth
rates, and the assumptions underlying the methodology, are reasonable,
and so it is logical to expect that the heat input projections
resulting from that methodology are reasonable.
3. EPA's Heat Input Growth Rates and 2007 Projections for Most States
Are Not Disputed by Commenters
EPA's heat input growth rates and 2007 projections for most States
in the NOX SIP Call region, and for most States covered by
the Section 126 Rule, are not specifically disputed by commenters. Of
the 21 States and the District of Columbia covered by the
NOX SIP Call, or recently proposed to be covered, the heat
input growth rates and 2007 projections for only seven States (Alabama,
Georgia, Illinois, Michigan, Missouri, Virginia, and West Virginia) are
disputed by commenters. Of the 12 States and the District of Columbia
covered by the Section 126 Rule, these values for only three States
(Michigan, Virginia, and West Virginia) are disputed by commenters.
As noted above, petitioners and the Court raised concerns about
EPA's growth rates and projections for Michigan and West Virginia,
stating that EPA's State heat input growth rates resulted in State
projections for 2007 below the 1998 actual heat input values.
Subsequently, in comments on the August 3, 2001 NODA, commenters raised
concerns that the heat input growth rates for five other States
(Alabama, Georgia, Illinois, Missouri, and Virginia) were too low
because, for each State, the actual heat input in 2000 exceeded or were
close to EPA's 2007 projection. For the remaining 15 jurisdictions in
the NOX SIP Call region, EPA's heat input growth rates and
projections were not disputed by any petitioner and are not disputed in
any comments on the August 3, 2001 and March 11, 2002 NODA's or on any
other documents added to the docket concerning the remand on growth
rates.
The fact that no objections have been raised with respect to the
majority of the States is an indication of the reasonableness of EPA's
heat input growth methodology. Further, as discussed below, all of the
States about which the Court or commenters expressed concern have
recently had decreases in their heat input, in some cases to levels
below EPA's 2007 projections. Also as discussed below, because in a
number of instances State annual heat input has decreased significantly
over multi-year periods, the fact that a State has recently had heat
input exceeding or close to EPA's 2007 projections does not mean that
the projection is unreasonable.
4. Historical Data Show That a State's Heat Input Can Decrease
Significantly Over Multi-Year Periods
As noted above, the Court indicated significant doubt that a
State's heat input could decrease over a long period of years. The
Court seemed to be concerned that underlying a decrease in State heat
input would have to be a decrease in electricity generation.
Consequently, the Court questioned the reasonableness of EPA's heat
input growth rate methodology because the methodology resulted in a
State exceeding its 2007 level nine years in advance. However,
historical heat input data shows that, on many occasions, State annual
and ozone season heat input has decreased significantly for the last
year, as compared to the first year, of multi-year periods.
Table 1 below shows the ozone season heat input for EGUs for 1995-
2001 for each State in the NOX SIP Call region. For each
ozone season, EPA summed the heat input data for Acid Rain Program
units, as reported to EPA under 40 CFR part 75, and for other EGUs, as
reported to EIA.
BILLING CODE 6560-50-P
[[Page 21883]]
[GRAPHIC] [TIFF OMITTED] TR01MY02.000
BILLING CODE 6560-50-C
[[Page 21884]]
This ozone season data shows decreases in State heat input for
several States for the last year, as compared to the first year, of
multi-year periods of 3 to 6 years.\20\ For example, during 1995
through 2001, Delaware, Georgia, Illinois, Indiana, Massachusetts,
Maryland, Michigan, North Carolina, Ohio, Pennsylvania, Virginia, and
West Virginia had decreases in heat input for the last year, as
compared to the first year, of the 3-year period 1998-2001. Heat input
decreases for other multi-year periods occurred during 1995 through
2001 for Delaware (6-year period 1995-2001), North Carolina (5-year
period 1996-2001), New Jersey (3-year period 1995-1998), New York (6-
year period 1995-2001), Pennsylvania (6-year period 1995-2001) Rhode
Island (4-year period 1996-2000), and Tennessee (6-year period 1995-
2001).
---------------------------------------------------------------------------
\20\ EPA, of course, recognizes that there also can be
significant increases in State heat input over multi-year periods.
However, commenters suggested that significant decreases could not
occur. The point is that, since significant decreases can occur, the
fact that State's recent heat input exceeds or is close to EPA's
2007 projection does not make the projection unreasonable.
---------------------------------------------------------------------------
EPA also examined long-term, fossil fuel use data. The long-term
data from EIA show fossil fuel use (in mmBtu) on an annual, not an
ozone season, basis for the 21 States subject to the NOX SIP
Call for 1960-2000.\21\ (Because of the large amount of data, the full
set of 1960-2000 annual data is provided in Docket #A-96-56, Item #XV-
C-18, rather than being included in today's notice.) These data
demonstrate that decreases in State annual heat input, like decreases
in State ozone season heat input, are not unusual.
---------------------------------------------------------------------------
\21\ EIA collected, on a long term historical basis, monthly and
annual plant-by-plant data on quarterly and heat content of fuel
used. EIA used these data to determine annual heat input for each
State and did not determine State heat input on an ozone season
basis. EPA notes that its analysis does not include the District of
Columbia, for which a full set of historical, annual heat input data
was not available. However, the heat input growth rate for the
District of Columbia is not disputed by commenters.
---------------------------------------------------------------------------
Specifically, the 1960-2000 annual heat input data show significant
decreases in State annual heat input for the last year, as compared to
the first year, of multi-year periods of 3 to 10 years (or longer). In
fact, all but one of the 21 States under the NOX SIP Call
has had significant decreases in annual heat input over many multi-year
periods ranging from 3 to 10 years; one of the States (Indiana) has had
such decreases over multi-year periods, within that range, of only 3-
years. Tables 2, 3, 4, 5, 6, 7 ,8, and 9 summarize this information by
showing the largest percentage decreases (for the last year, as
compared to the first year, of multi-year periods) that the listed
States have had in annual heat input over 3-year, 4-year, 5-year, 6-
year, 7-year, 8-year, 9-year and 10-year periods respectively.
Table 2.--Largest Decreases in State Annual Heat Input Over Three Years
------------------------------------------------------------------------
% decrease
State 3-year in heat
period input
------------------------------------------------------------------------
Alabama....................................... 1979--1982 17
Connecticut................................... 1989--1992 6
Delaware...................................... 1995--1998 24
Georgia....................................... 1989--1992 9
Illinois...................................... 1986--1989 17
Indiana....................................... 1979--1982 3
Kentucky...................................... 1997--2000 8
Massachusetts................................. 1997--2000 42
Maryland...................................... 1978--1981 26
Michigan...................................... 1979--1982 19
Missouri...................................... 1990--1993 12
New Jersey.................................... 1989--1992 46
New York...................................... 1990--1993 34
North Carolina................................ 1981--1984 17
Ohio.......................................... 1979--1982 11
Pennsylvania.................................. 1996--1999 14
Rhode Island.................................. 1990--1993 88
South Carolina................................ 1981--1984 19
Tennessee..................................... 1979--1982 16
Virginia...................................... 1979--1982 35
West Virginia................................. 1988--1991 13
------------------------------------------------------------------------
Table 3.--Largest Decreases in State Annual Heat Input Over Four Years
------------------------------------------------------------------------
% decrease
State 4-year in heat
period input
------------------------------------------------------------------------
Alabama....................................... 1980--1984 9
Connecticut................................... 1989--1993 55
Delaware...................................... 1996--2000 25
Georgia....................................... 1988--1992 12
Illinois...................................... 1984--1988 18
Indiana....................................... None None
Kentucky...................................... 1996--2000 5
Massachusetts................................. 1989--1993 34
Maryland...................................... 1978--1982 23
Michigan...................................... 1979--1983 19
Missouri...................................... 1989--1993 13
New Jersey.................................... 1989--1993 48
New York...................................... 1990--1994 37
North Carolina................................ 1983--1987 48
Ohio.......................................... 1979--1983 12
Pennsylvania.................................. 1980--1984 14
Rhode Island.................................. 1989--1983 86
South Carolina................................ 1980--1984 15
Tennessee..................................... 1978--1982 24
Virginia...................................... 1979--1983 35
West Virginia................................. 1989--1993 14
------------------------------------------------------------------------
Table 4.--Largest Decreases in State Annual Heat Input Over Five Years
------------------------------------------------------------------------
% decrease
State 5-year in heat
period input
------------------------------------------------------------------------
Alabama....................................... 1977--1982 15
Connecticut................................... 1989--1994 55
Delaware...................................... 1993--1998 28
Georgia....................................... 1987--1992 14
Illinois...................................... 1983--1988 23
Indiana....................................... None None
Kentucky...................................... 1995--2000 2
Massachusetts................................. 1989--1994 35
Maryland...................................... 1976--1981 24
Michigan...................................... 1978--1983 17
Missouri...................................... 1988--1993 13
New Jersey.................................... 1989--1994 44
New York...................................... 1989--1994 40
North Carolina................................ 1982--1987 25
Ohio.......................................... 1979--1984 11
Pennsylvania.................................. 1980--1985 13
Rhode Island.................................. 1988--1993 90
South Carolina................................ 1981--1986 14
Tennessee..................................... 1977--1982 23
Virginia...................................... 1977--1982 38
West Virginia................................. 1988--1993 12
------------------------------------------------------------------------
Table 5.--Largest Decreases in State Annual Heat Input Over Six Years
------------------------------------------------------------------------
% decrease
State 6-year in heat
period input
------------------------------------------------------------------------
Alabama....................................... 1976--1982 11
Connecticut................................... 1989--1994 52
Delaware...................................... 1993--1999 28
Georgia....................................... 1985--1991 14
Illinois...................................... 1983--1989 25
Indiana....................................... None None
Kentucky...................................... 1993--1999 2
Massachusetts................................. 1989--1995 37
Maryland...................................... 1974--1980 27
Michigan...................................... 1976--1982 13
Missouri...................................... 1987--1993 9
New Jersey.................................... 1989--1995 45
New York...................................... 1990--1996 44
North Carolina................................ 1981--1987 29
Ohio.......................................... 1977--1983 8
Pennsylvania.................................. 1980--1986 15
Rhode Island.................................. 1987--1993 91
South Carolina................................ 1977--1983 11
Tennessee..................................... 1976--1982 24
Virginia...................................... 1977--1983 38
West Virginia................................. 1985--1991 11
------------------------------------------------------------------------
Table 6.--Largest Decreases in State Annual Heat Input Over Seven Years
------------------------------------------------------------------------
% decrease
State 7-year in heat
period input
------------------------------------------------------------------------
Alabama....................................... 1975--1982 8
Connecticut................................... 1986--1993 53
Delaware...................................... 1993--2000 31
Georgia....................................... 1985--1992 17
Illinois...................................... 1981--1988 22
[[Page 21885]]
Indiana....................................... None None
Kentucky...................................... 1993--2000 1
Massachusetts................................. 1989--1996 40
Maryland...................................... 1974--1981 37
Michigan...................................... 1975--1982 15
Missouri...................................... 1984--1991 7
New Jersey.................................... 1989--1996 54
New York...................................... 1989--1996 47
North Carolina................................ 1981--1988 27
Ohio.......................................... 1977--1984 7
Pennsylvania.................................. 1980--1987 14
Rhode Island.................................. 1986--1993 89
South Carolina................................ 1977--1984 6
Tennessee..................................... 1976--1983 15
Virginia...................................... 1976--1983 38
West Virginia................................. 1984--1991 10
------------------------------------------------------------------------
Table 7.--Largest Decreases in State Annual Heat Input Over Eight Years
------------------------------------------------------------------------
% decrease
State 8-year in heat
period input
------------------------------------------------------------------------
Alabama....................................... 1974-1982 12
Connecticut................................... 1986-1994 52
Delaware...................................... 1991-1999 29
Georgia....................................... 1984-1992 11
Illinois...................................... 1980-1988 28
Indiana....................................... None None
Kentucky...................................... None None
Massachusetts................................. 1992-2000 41
Maryland...................................... 1974-1982 35
Michigan...................................... 1974-1982 13
Missouri...................................... 1984-1992 11
New Jersey.................................... 1984-1992 53
New York...................................... 1988-1996 42
North Carolina................................ 1980-1988 24
Ohio.......................................... 1976-1984 5
Pennsylvania.................................. 1991-1999 12
Rhode Island.................................. 1985-1993 88
South Carolina................................ 1978-1986 2
Tennessee..................................... 1976-1984 13
Virginia...................................... 1977-1985 36
West Virginia................................. 1985-1993 11
------------------------------------------------------------------------
Table 8.--Largest Decreases in State Annual Heat Input Over Nine Years
------------------------------------------------------------------------
% decrease
State 9-year in heat
period input
------------------------------------------------------------------------
Alabama....................................... 1973-1982 17
Connecticut................................... 1984-1993 51
Delaware...................................... 1991-2000 33
Georgia....................................... 1984-1993 3
Illinois...................................... 1990-1989 31
Indiana....................................... None None
Kentucky...................................... None None
Massachusetts................................. 1991-2000 47
Maryland...................................... 1972-1981 31
Michigan...................................... 1974-1983 13
Missouri...................................... 1984-1993 20
New Jersey.................................... 1984-1993 54
New York...................................... 1987-1996 35
North Carolina................................ 1981-1990 26
Ohio.......................................... 1979-1988 2
Pennsylvania.................................. 1990-1999 14
Rhode Island.................................. 1984-1993 88
South Carolina................................ None None
Tennessee..................................... 1973-1982 18
Virginia...................................... 1974-1983 35
West Virginia................................. 1984-1993 9
------------------------------------------------------------------------
Table 9.--Largest Decreases in State Annual Heat Input Over Ten Years
------------------------------------------------------------------------
% decrease
State 10-year in heat
period input
------------------------------------------------------------------------
Alabama....................................... 1973-1983 9
Connecticut................................... 1983-1993 48
Delaware...................................... 1988-1998 31
Georgia....................................... None None
Illinois...................................... 1979-1989 32
Indiana....................................... None None
Kentucky...................................... None None
Massachusetts................................. 1990-2000 48
Maryland...................................... 1972-1982 28
Michigan...................................... 1973-1983 11
Missouri...................................... 1983-1993 16
New Jersey.................................... 1983-1993 55
New York...................................... 1989-1999 31
North Carolina................................ 1980-1990 23
Ohio.......................................... None None
Pennsylvania.................................. 1989-1999 21
Rhode Island.................................. 1983-1993 88
South Carolina................................ 1973-1983 6
Tennessee..................................... 1973-1983 8
Virginia...................................... 1972-1982 36
West Virginia................................. 1981-1991 6
------------------------------------------------------------------------
Although the longer term EIA annual heat input data and EPA's
shorter term ozone season data show the same types of multi-year period
decreases, EPA conducted further analysis in order to confirm that
ozone season and annual State heat input have similar fluctuations.
Specifically, EPA used EIA monthly data on fuel quantity (which was
available for years starting with 1970) and generic heat content
factors in order to derive estimated ozone season heat input data for
1970-1998. [See Docket # A-96-56, Item # XV-C-19 (explaining how EPA
derived estimated ozone season data and providing that estimated
data)]. Because of the nature of the simplifying assumptions that EPA
made in order to derive long-term ozone season data, EPA's analysis in
this notice relies primarily on the long-term State annual heat input
data, not the derived long-term State ozone season heat input data.
However, EPA believes that the latter data confirm EPA's annual-data
analysis because the long-term ozone season data show multi-year
decreases in State heat input that are very similar in length and
magnitude to those shown by the long-term State annual heat input data.
Id.
In summary, historical data show that heat input (whether for the
ozone season or the entire year) in individual States is quite variable
and has decreased significantly over multi-year periods on a number of
occasions. EPA respectfully submits that the data provide a basis for
the Court to reconsider its concern that the fact that heat input
values for some States for certain years have already exceeded EPA's
2007 heat input projections supports objections to the reasonableness
of EPA's heat input growth methodology.
5. Approach of Using Recent State Heat Input To Project Future State
Heat Input Is Not Statistically Sound
Commenters claimed that, because the recent heat input for seven
States (Alabama, Georgia, Illinois, Michigan, Missouri, Virginia, and
West Virginia) has exceeded or been close to EPA's 2007 heat input
projections, EPA's projections are unreasonable. In making this claim,
commenters implicitly assumed that future heat input can reasonably be
projected using a relatively short period of years of actual State heat
input data.
In order to test the validity of this assumption, EPA simulated
that approach using historical annual heat input data for the 21
NOX SIP Call States for 1960-2000 (or in some States where
less data was available, from 1970-2000). Using this data, EPA used 6
years worth of historical data (e.g., 1960-1966) to project annual heat
input for the sixth year after the 6-year period (e.g, 1972). EPA did
this on a rolling basis, using historical 6-year periods from 1960 to
1994 (or 1970 to 1994), to project annual heat input for the years 1972
(or 1982) to 2000. EPA tested how well the historical data predicted
future annual heat input value by comparing the projected value with
the actual value for the same year. Specifically, EPA performed an r-
squared test on the actual annual heat input vs. the projected annual
heat input for the same year. This test provides a measure of how much
a change in one variable (here, actual annual heat input) is related to
a change in a second variable (here, projected annual heat input). For
instance, an r-squared value of 1 implies that all of the change in the
first variable
[[Page 21886]]
is related to change in the second value. Conversely, an r-squared
value of 0 implies that none of the change in the first variable is
related to change in the second variable.
EPA found that, in testing the actual annual heat input data vs.
the projected annual heat input data for each State, 10 States
(including Illinois, Michigan and Virginia) out of the 21
NOX SIP Call States had r-squared values below 0.12. An
additional six States (including Missouri and West Virginia) had r-
squared values below 0.32. Because the r-squared test showed that less
than one-third of the variability in projected annual heat input can be
explained by the variability in actual annual heat input for 16 of the
NOX SIP Call States, EPA believes that it is clear that
historical heat input cannot be used as a reliable indicator of future
heat input. Moreover, the r-squared values for the remaining States
were: Alabama, 0.63; Georgia 0.42; Indiana, 0.80; Kentucky, 0.67; New
Jersey (0.59). Except for Indiana, this indicates only a weak
correlation between actual heat input data and projected heat input
data because 33% to 58% of the variability of projected heat input data
cannot be explained by the variability in actual heat input data. Even
in Indiana where the correlation was strongest, the projections ranged
from 13.4% below the actual value to 10.9% above the actual value. For
Alabama, 15 of the 29 projections were more than 10% above or below the
actual value, and the projections ranged from 26.7% below the actual
value to 27.9% above the actual value. (See Docket # A-96-56, Item #'s
XV-C-19 and XV-C-20.) For other States, disparities between the
projected values and the actual values were even wider. The variability
in the projections for the States where concerns have been raised are
summarized below.
------------------------------------------------------------------------
Number of
projections off
State by more than Range of projections
10%
------------------------------------------------------------------------
Alabama....................... 15 of 29....... -26.7% to 27.3%
Georgia....................... 14 of 29....... -50.9% to 37.0%
Illinois...................... 21 of 29....... -46.4% to 40.1%
Michigan...................... 25 of 29....... -33.4% to 54.6%
Missouri...................... 23 of 29....... -36.4% to 31.9%
Virginia...................... 25 of 29....... -60.2% to 71%
West Virginia................. 21 of 29....... -44.0% to 37.9%
------------------------------------------------------------------------
In short, historical State heat input for a relatively short period of
years is not a reliable method for predicting future State heat input.
6. EPA's Heat Input Projections Do Not Implicitly Assume Negative
Growth in Electricity Generation
In Appalachian Power v. EPA, 249 F.3d at 1053, the Court expressed
concern that, for States whose actual heat input for EGUs already
exceeded EPA's projections for 2007, EPA's projection ``implicitly
assume a baseline of negative growth in electricity generation.''
Although the Court expressed concern about electricity generation, it
should be recalled that in the NOX SIP Call and Section 126
Rule, the regulatory requirements were computed with reference to heat
input, and not electricity generation. Accordingly, in expressing
concern about electricity generation, the Court apparently was
concerned that a decrease in heat input would necessarily mean a
decrease in electricity generation and that a projection of a heat
input decrease would implicitly assume decreased electricity
generation.
In response, EPA respectfully submits that fossil-fuel use at the
State level--which is at issue in the present case--is but one factor
associated with electricity generation. Many other factors affect
electricity generation as well. Accordingly, EPA respectfully submits
that a decrease in State heat input (whether actual or projected) does
not implicitly mean a decline in electricity generation.
Indeed, State heat input can decrease while electricity generation
in the State or in the region increase. There are at least two reasons
why this can happen. First, even within a State, heat input does not
necessarily correlate with electricity generation because of
electricity generated using non-fossil fuel sources and increased
efficiency of fossil fuel generation. Second, because electricity is
sold on a regionwide basis, electricity generation can decrease in one
State and increase in another State, with increased electricity being
sold and used in the first State.
a. State heat input does not necessarily correlate with electricity
generation in the State. Electricity generation in a State can increase
at the same time that heat input (i.e., fossil fuel use) decreases in
that State. One reason for this is that significant amounts of
electricity can be generated from non-fossil sources, such as nuclear
units or hydro-electric facilities.
Commenters suggested that heat input will have to increase in the
next several years because nuclear power plants are already operating
at near capacity. This may be generally correct on a regionwide basis,
and EPA projects increased regionwide heat input in 2007. However, this
is not true on a State-by-State basis for all States. For example, in
Illinois several nuclear power plants recently received approval by the
Nuclear Regulatory Commission to increase their generation capacity.
Four units (Dresden Units 2 and 3 and Quad Cities Units 1 and 2) plan
to increase their capacity by 17 to 18% in 2002 and 2003.\22\ Carrying
out these plans will tend to reduce heat input, while increasing
electricity generation. Further, two units at the Cook Nuclear Plant in
Michigan underwent an extended, unexpected outage in 1998-2000. The
outage of the two units tended to increase fossil fuel use, and
bringing them back online tended to decrease fossil fuel use. An
increase in nuclear generation can reduce heat input without reducing
total electricity generation in a State.
---------------------------------------------------------------------------
\22\ See http://www.nrc.gov/reading-rm/doc-collections/news/archive/01-136.html.
---------------------------------------------------------------------------
Heat input can also decrease, without decreasing electricity
generation, because the efficiency of fossil-fuel fired electricity
generating units can be increased, allowing generation of the same
amount of electricity with use of less fossil fuel. One way this can
occur is through replacement of existing boilers, which are on average
between 33% and 35% efficient at converting fossil fuel to electricity,
with combined cycle turbines, which can be up to 60% efficient. For
example, on February 25, 2000, Illinois approved a permit for Ameren
Corporation to replace two coal-fired units at the Grand Tower
Generating Station with two combined cycle gas turbines.\23\
---------------------------------------------------------------------------
\23\ See http://yosemite.epa.gov/r5/il_permt.nsf/
50d44ae9785337bf8625666c0063caf4/b04c4b1ab67564e48625685d0068df82/
$FILE/99080101fnl.PDF; and http://www.dom.com/operations/station-fossil/unit.html.
---------------------------------------------------------------------------
Efficiency can also be improved through modifications at existing
generation facilities. For example, improvements can be made to the
boiler that allow better transfer of heat from the burning coal to the
steam used to power the turbine-generators; the
[[Page 21887]]
efficiency of auxiliary equipment such as fans can be improved; the
efficiency of the turbine generators that convert the steam to
electricity can be improved; and combustion optimization software,
which can reduce NOX emissions while increasing efficiency,
can also be added.\24\ Greater efficiency, whether from improvements to
existing facilities or from new units, can result in the same or more
electricity generation in a State with less heat input. EPA notes that
the incentives for companies that generate electricity for sale to
improve the efficiency of electricity generation has increased with
deregulation of electricity generation and increased competition in the
electricity market.
---------------------------------------------------------------------------
\24\ See http://www.sargentlundy.com/fossil/plant.asp; and
http://www.pegasustec.com/docs/NICE3.pdf.
---------------------------------------------------------------------------
b. Electricity is generated and sold on a regional, not on a State-
by-State basis. Electricity generation may decrease in one State but,
because electricity is generated and sold on a regional basis, the
decrease may simply reflect the fact that customers are using
electricity generated in another State. Three factors--the deregulation
of electricity generation, the restructuring of the electricity
industry, and the efforts of the Federal Energy Regulatory Commission
to promote market-based rates of electricity and nondiscriminatory
access for all electricity supplies to the transmission system--have
resulted in significant amounts of electricity being generated in one
State and sold in another. For example, in 1993, West Virginia
generated three times the amount of electricity sold in that State, and
in 1999, Alabama generated one and a half times the amount of
electricity sold in that State. Historically, electricity was generated
and sold by vertically integrated utilities providing for generation,
transmission, and distribution for all customers in a designated
franchise service area, which often was within a single State.
With electricity deregulation, restructuring, and Federal policies
promoting competition and open transmission access, the industry has
been changing ``from a vertically integrated and regulated monopoly to
a functionally unbundled industry with a competitive market for power
generation.'' The Changing Structure of the Electric Power Industry
1999: Mergers and Other Corporate Combinations, Energy Information
Administration, December 1999 at pg. 5. Non-utilities are participating
in the electricity market to an increasing extent by generating
electricity for sale to utilities or to end-users. The Changing
Structure of the Electric Power Industry 2000: An Update, Energy
Information Administration, October 2000 at pp. ix, xi, and 117.
Significant amounts of new generating capacity (about 82% of total
capacity additions in 1998) have been built by non-utilities in order
to generate electricity for sale in the regional electricity market.
Id. at xi.
7. Even if There Were a Substantial Risk That EPA's State Heat Input
Projection Would Be Less Than a State's Actual 2007 Heat Input, This
Would Not Make EPA's Projection Unreasonable
For the reasons discussed above, commenters failed to show that
having recent State heat input exceeding or close to EPA's 2007 heat
input projection means that the actual 2007 State heat input will
exceed EPA's 2007 projection. However, EPA believes that, even if they
had shown that there was a substantial risk that the actual heat input
would turn out to exceed the projection in 2007, this would not make
EPA's projection unreasonable. Projections may not match perfectly
actual, future values and are not required to do so. See Appalachian
Power v. EPA, 249 F.3d at 1052 (stating that the fact that ``a model is
limited or imperfect is not, in itself, a reason to remand agency
decisions based upon it''). If the projections of the results of
complex activities (here, State heat input resulting from the operation
of the regional electricity market) were required to match actual,
future results, this would, in effect, preclude the use of projections
or a model to develop such projections.
In this case, where EPA developed State heat input growth rates
using the IPM and applied them to a State baseline to project 2007
State heat input, there are unavoidable sources of variability between
projections and actual, future heat input data. These sources of
variability are: the necessity to make simplifying assumptions in a
model; the necessity to model regional activities (i.e., electricity
generation, transmission and distribution) but make State-by-State
projections of heat input resulting from those activities; and the
inherent, year-to-year variability of actual State heat input.
a. Models, such as the IPM, necessarily contain simplifying
assumptions. The IPM simulates the complex operation of the electricity
generation, transmission, and distribution sector. Like any model
designed to simulate complex phenomena, the IPM must use simplifying
assumptions in order to make it feasible to construct and run the
model. Furthermore, the model uses inputs that are themselves
projections (e.g., electricity demand and fuel costs). Because of these
simplifying assumptions and projected inputs, the results from the IPM,
like those from any model, may well differ from reality. For example,
the IPM assumes typical electricity demand each year, which reflects
typical conditions like typical weather and typical economic growth.
The basis for assuming typical conditions is the assumption that
periods of high or low demand or hot or cold weather tend to average
out over time. In reality, of course, there are years of unusually warm
weather or unusually high economic growth, resulting in unusually high
electricity demand. For example, in 1998, large parts of the
NOX SIP Call region experienced particularly warm weather,
and the country experienced an economic boom. The model will not
predict extra heat input in such years.
The IPM accounts for unplanned outages in a similar way. It assumes
that, on average, plants will be available some portion of time less
than 100%. The model also includes assumptions about a capacity reserve
margin, thereby assuring that the costs of building plants that may be
needed to meet demand are accounted for. However, the model does not
assume that any specific units are out for any extended length of time.
In reality, unplanned outages do not affect every unit for the same
amount of time every year. Therefore, the model will not predict
exactly the dispatch pattern of units in the real world. These
differences could be substantial in a year or more. For example, if
several large nuclear units went out of service in one geographic
region for an extended period of time (as was the case, discussed
below, when two units at the Cook Nuclear Plant went out of service
during 1998 through 2000), fossil fuel-fired units might have a
significant increase in heat input to provide the electricity that
would otherwise have been generated by the nuclear units. The model
would not predict this large increase in heat input.
The IPM also picks the optimum way to minimize costs given the
constraints that have been included in the model. In the real world,
different people and different companies may have differing viewpoints
about what future constraints may be. This may lead them to act
differently than the model projected. For instance, the model is given
specific constraints regarding the projected future demand for
electricity. It assumes that there are just enough units to meet that
demand plus a reserve
[[Page 21888]]
margin. In the real world, future demand is less certain, and this can
lead to construction of fewer or more units than projected by the IPM.
For any particular State, a series of events may occur that differ
from the model's assumptions, such as a period of higher electricity
demand first caused by warmer weather than assumed in the model,
followed by a period of higher economic activity than assumed in the
model. This series of events may lead, over a year or more, to actual
heat input that is higher than modeled for that State. In subsequent
periods, the different-than-modeled factors may return to levels closer
to those modeled, so that heat input returns to levels closer to those
modeled.
In short, in designing the IPM, EPA necessarily made many
assumptions. These assumptions may well result in differences between
projected and actual State heat input for a specific year or specific
years. However, this would not make the heat input projection
methodology or the resulting heat input projection unreasonable.
b. While the electricity industry functions on a region-wide basis,
budgets must be established on a State-by-State basis. Another source
of differences between projected and actual State heat input is that,
while NOX emission budgets must be projected on a State-by-
State basis, electricity is generated and sold on a regionwide, not
State-by-State, basis. As discussed above in section V.D.6 of this
notice, deregulation of electricity generation, restructuring of the
electric industry, and Federal policies promoting market-based
electricity prices and open access to transmission have resulted in
development of a regional electricity market. The IPM necessarily
models electricity generation and sales on a regional basis in order to
reflect the regional nature of the electricity sector. For instance, as
explained above, the model divides the U.S. into subregions based on
the NERC regions and on transmission constraints, not based on State
boundaries. (See section V.C.5 of this notice discussing subregions in
the IPM.)
However, EPA had to develop State-by-State NOX emission
budgets under the NOX SIP Call. EPA used those same budgets
under the Section 126 Rule in order to allow a single cap-and-trade
program to be developed and implemented under both the NOX
SIP Call and the Section 126 Rule. EPA had to disaggregate regionally-
developed heat input projections down to the State level in order to
establish State NOX emission budgets, and this
disaggregation may well create additional differences between projected
and actual State heat input. These differences should not be taken to
indicate that the heat input growth methodology or the resulting
projections are unreasonable.
c. Actual State heat input is inherently variable. State heat input
is quite variable, as discussed in section V.D.4 of this notice. This
is because heat input results from the activities of the complex,
regional electricity market. The variability of State heat input from
year to year may well result in additional differences between
projected and actual State heat input for any particular year. Again,
these differences should not be taken as an indication of
unreasonableness of the heat input growth methodology or the
projections.
8. Commenters Overstated the Impacts of Actual State Heat Input
Exceeding Projected State Heat Input
Even if EPA's heat input projections turn out to be lower for some
States than actual 2007 heat input, the impacts of any such differences
will not be as significant as commenters suggest. This is because the
impacts will be mitigated by: (i) The fact that much of heat input
growth will come from new, very low NOX emission units; and
(ii) the flexibility provided by the NOX cap-and-trade
program.
a. Higher than projected State heat input will not mean
proportionately higher NOX emissions. Commenters claimed
that EPA's projections underestimate heat input for certain States and
would result in sources in those States facing underestimated, and so
overly stringent, NOX emissions budgets. Commenters also
stated that underestimated State heat input would cause electric supply
interruptions. In addition, commenters suggested that underestimated
State heat input would jeopardize or prohibit economic growth in those
States by increasing EGU operating costs and jeopardizing access to
adequate electricity by preventing new EGUs from locating in the
State.\25\
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\25\ One commenter claimed EPA's heat input growth methodology
thereby results in ``draconian economic sanctions'' and a ``no-
growth policy'' for Michigan. As discussed below in section V.D.9 of
this notice, there is no basis for claiming that EPA's heat input
growth rate underestimates Michigan's future heat input. In fact,
Michigan's actual heat input has never exceeded EPA's 2007
projection and, since 1998, has declined to where for 2001 it is
8.7% below that projection.
---------------------------------------------------------------------------
The NOX SIP Call and the Section 126 Rule limit units'
NOX emissions, not their heat input. EPA anticipates that,
as State heat input grows from 1996 to 2007, a State's total EGU
NOX emissions will grow at a much slower rate than heat
input because of the addition of new, very low NOX emission
units accounting for much of the increased heat input. The vast
majority of new units added since 1996 are or will be gas-fired
combustion turbines and combined cycle units that include gas-fired
combustion turbines and duct burners. Because NOX emissions
from these units will be very low and significantly below the 0.15 lbs/
mmBtu level used to set the State NOX emission budgets for
EGUs, the rate of increase in NOX emissions in any State
will be significantly less than the actual 1996-2007 growth rate in
State heat input.
Specifically, EPA projects that gas-fired generation will increase
at a greater rate than coal-fired generation. (See Analyzing Electric
Power at pg. 7, Table 1, Winter 1998 Base Case Forecast for the U.S. of
Electric Power Generation by Fuel Type (billion KWh), which indicates
that coal generation will increase by 85 billion KWh between 2001 and
2005 and by 95 billion KWh between 2001 and 2007, while oil/gas
generation \26\ will increase by 95 billion KWh between 2001 and 2005
and 158 billion KWh between 2001 and 2007.) \27\ In other words, EPA
projects that gas-fired generation will increase at a rate 1.66 times
faster than coal-fired generation (for every 3 Mwh increase in coal-
fired generation, there would be a 5 Mwh increase in gas-fired
generation.) Because gas-fired combined cycle units are more efficient
than coal units, heat input from both categories of units will increase
at a similar rate, even though generation from the gas-fired units will
increase at a faster rate. This projected trend of increasing use of
gas-fired combined-cycle use is consistent with observed results. For
example, for the years 2000-2004, electric utilities reported plans to
add 38,051 MW of generating capacity in new units. Ninety-three percent
of this total is gas-fired capacity (Inventory of Electric Utility
Power Plants in the U.S. 1999, Energy Information Administration,
September 2000, at pg. 1). This is a continuation of the trend in 1997-
1999, when most new capacity for utilities (81% in 1997 and 88% in 1998
and 1999) has been gas-fired combustion turbines and combined cycle
units.\28\
---------------------------------------------------------------------------
\26\ Oil/gas units are included in the same category because
many units that burn one fuel can also burn the other. However, as
the analysis points out, more inefficient oil/gas boilers are being
retired and most of the increase in generation comes from highly
efficient, highly controlled natural gas combined cycle units.
Analyzing Electric Power at 8.
\27\ EPA notes that oil generation will account for a trivial
amount of oil/gas generation.
\28\ Inventory of Power Plants in the U.S. as of January 1,
1998, EIA, December 1998, at pg. 3; Inventory of Electric Utility
Power Plants in the U.S. 1999 With Data as of January 1, 1999, EIA,
November 1999, at pg. 1; Inventory of Electric Utility Power Plants
in the U.S. 1999, EIA, September 2000 at pg. 1.
---------------------------------------------------------------------------
[[Page 21889]]
New EGUs are subject to new source review requirements and,
therefore, are well controlled. New combined cycle turbines generally
are permitted at 9 ppm or less (i.e., less than 0.035 lb/mmBtu).\29\
This means these new units will emit about one-fifth of the average
0.15 lb/mmBtu NOX emission rate assumed for EGUs in the
NOX SIP Call and Section 126 Rules. Most existing combined-
cycle units are controlled to levels similarly below 0.15 lb/mmBtu.
Consequently, NOX emissions will grow at a much lower rate
than heat input as these units come online.
---------------------------------------------------------------------------
\29\ See EPA Region 4 National Combustion Spreadsheet maintained
at http://www.epa.gov/region4/air/permits/national_ct_list.xls.
---------------------------------------------------------------------------
For example, consider the hypothetical case where 1996-2007 heat
input growth would be 10% and about equally divided between generation
from new gas-fired units and increased capacity utilization at existing
coal-fired units. Because emissions from the gas-fired units are only
one-fifth of the 0.15 lb/mmBtu NOX emission rate assumed in
the NOX SIP Call and the Section 126 Rule, NOX
emissions would grow only 1% while heat input would grow 5% at new gas-
fired units. A 5% growth in heat input at existing coal-fired plants
emitting at the 0.15 lb/mmBtu NOX emission rate would result
in a 5% growth in NOX emissions from the coal-fired units in
this example. Thus, the total NOX emissions growth would be
about 6% when total heat input growth was 10%.
In summary, even if State heat input grows at a rate faster than
projected by EPA, NOX emissions will grow at a much slower
rate than State heat input and the impact on the State's EGU
NOX emission budget from the difference between actual and
projected heat input growth will be significantly reduced. This is
reflected in EPA's modeling showing that increased heat input growth
would not significantly increase the cost of meeting the State
NOX EGU budget. Even when electricity demand growth is
assumed to be higher than EPA projected (e.g., with no electricity
demand reductions under CCAP), the average cost of meeting the
NOX EGU budgets only increased $40/ton.
Since higher than projected State heat input growth results in much
less than proportionately higher State NOX emissions, the
commenters greatly overstated the impacts of higher-than-projected
State heat input on the stringency of the NOX emission rate
reflected in the State NOX emission budget. Similarly,
commenters greatly overstated the impacts of higher-than-projected
State heat input on the State economy. Since new units tend to have
very low NOX emissions, higher-than-projected State heat
input will not prevent the location of new units in the State to the
extent suggested by commenters. Moreover, the amount of electricity
available in a State is not tied to the amount of electricity generated
in that State since electricity is generated and sold on a regionwide,
not State-by-State, basis. Therefore, higher than projected State heat
input will not limit the amount of electricity available for
industrial, commercial and residential customers in that State. (See
section V.D.6 discussing that State heat input is not necessarily
correlated with availability of electricity and economic growth in the
State.) Since the commenters ignore the fact that a State's electricity
supply is not limited to the generation capacity in that State and
since, as discussed above, EPA's regional heat input projections are
consistent with actual regional heat input, the commenters failed to
show that underestimated State heat input will prevent access to
adequate electricity supply.
Finally, some commenters claiming that low heat input growth rates
would prevent new units from locating in certain States also claimed
that large numbers of new units are being located in those States and
that this shows that EPA's heat input growth rates are too low.
However, the fact that new units are continuing to be located in these
States indicates that the selected locations in these States continue
to be economically desirable for new units, despite the NOX
emission budgets that EPA established under the NOX SIP Call
in 1998 and modified in the Technical Amendments in 1999. One reason
for this, of course, is that most of these new units are gas-fired
units with very low NOX emission rates.
b. The cap-and-trade program will further limit the impact of
higher than projected State heat input. The NOX SIP Call and
the Section 126 Rule are being implemented through a cap-and-trade
program that will reduce the cost of meeting the State NOX
emission budgets and thus will limit the cost impact of higher than
projected State heat input. Under the NOX SIP Call, each
State is required to revise its SIP to meet the NOX emission
budget for 2007, which was developed using, among other things, the
State's heat input growth rate projected by EPA. Each State has the
option of meeting its NOX emission budget by submitting a
revised SIP that adopts EPA's recommended cap-and-trade program
covering NOX emissions from EGUs. Most States have already
taken this option by submitting a SIP and final regulations adopting
such a program, and EPA has approved a number of State rules, including
Alabama's (66 FR 36919, July 16, 2001) and Illinois' (66 FR 56434, Nov.
8, 2001). West Virginia has developed final regulations adopting EPA's
recommended cap-and-trade program, as have North Carolina, South
Carolina, and Tennessee. Michigan, Virginia, and Ohio have draft
regulations adopting such a program. Only Georgia and Missouri do not
have draft or final regulations since EPA has not yet finalized a rule
responding to the Court's remand of the NOX SIP Call for
those two States. (See Docket A-96-56, Item # XII-K-84).
Under the Section 126 Rule, EPA required affected units to
participate in a cap-and-trade program, which is virtually identical to
the cap-and-trade programs that have been (or are likely to be) adopted
by States under the NOX SIP Call. In fact, EPA has stated
that it intends to integrate the approved SIP trading program with the
Section 126 trading program into a single cap-and-trade program.
Under the cap-and-trade program, the State EGU NOX
budget is allocated among the affected units in the form of
NOX allowances, each allowance providing an authorization to
emit one ton of NOX during the ozone season for which the
allowance is allocated or for any subsequent ozone season. After the
end of each ozone season, the owner or operator of each affected unit
is required to surrender a number of NOX allowances equal to
the number of tons that the unit emitted during that period. Owners or
operators (or any other person) may buy or sell allowances or bank
allowances for use in future years. The ability to trade and bank
allowances provides units in a State flexibility in complying with the
NOX emission limit under the NOX SIP Call and the
Section 126 Rule and thereby limits the impact that higher than
projected heat input would have on the cost of compliance.
Specifically, the owner or operator of a unit with an allowance
allocation lower than the unit's tonnage of NOX emissions
for an ozone season has several compliance options, including the
options of installing and operating additional NOX emission
controls at the unit or of purchasing allowances allocated to other
units in the same State or in other States under the trading program.
The owners or operators will presumably choose the most economically
efficient option. If the cost of allowances in the regionwide market
[[Page 21890]]
for allowances under the trading program is less than the cost of
installing and operating additional controls at the unit, then the
owner or operator will purchase allowances. Assuming, for the sake of
argument, the unit is in a State where actual heat input for the year
exceeds EPA's projected 2007 heat input and actual NOX
emissions exceed the NOX emission budget, the cost impact of
the difference between actual and projected heat input is limited by
the owner's or operator's option to buy allowances, rather than
installing emission controls.\30\
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\30\ Commenters have characterized EPA's preliminary views in
the August 3, 2000 NODA as attempting, in essence, to argue that the
only thing that matters is the regionwide heat input growth rate,
not the individual State growth rates. This is a
mischaracterization. EPA believes that as long as the regionwide
projection is reasonably close to the actual regionwide heat input,
then, as a matter of simple arithmetic, trading opportunities will
likely be present for any State whose actual NOX
emissions exceed its NOX emission budget. As discussed
above, the availability of trading, in turn, limits the impact of
higher than expected heat input.
---------------------------------------------------------------------------
Moreover, as discussed above in section V.D.4 of this notice, State
heat input is quite variable. Even if actual State heat input exceeds
EPA's projected 2007 heat input in one or more years, it is quite
possible that actual State heat input will be less than EPA's projected
2007 heat input in a later year. Under the NOX cap-and-trade
program, the owner or operator in the example above who has to buy
allowances in one year may have excess allowances during the subsequent
year of reduced State heat input. That owner or operator may sell
allowances and thereby offset, at least in part, the cost of buying
allowances in the previous year. EPA is not suggesting that such an
offset of costs will always be available. Rather, EPA notes that the
cap-and-trade program will tend to create the potential to offset in
one year a unit's shortfalls in allocations (whether or not
attributable to higher than projected State heat input) in another
year.
9. Discussion of Individual States for Which EPA's Heat Input Growth
Rates Are Disputed by Commenters
Out of the 21 States and the District of Columbia for which EPA
developed heat input growth rates and heat input projections for EGUs
for 2007, commenters specifically disputed the heat input growth rates
and projections for 7 States, i.e., Alabama, Georgia, Illinois,
Michigan, Missouri, Virginia, and West Virginia. In six States, the
commenters claimed that EPA's heat input growth rates and heat input
projections are unreasonable because these States recently had actual
heat input that exceeded EPA's projected heat input for 2007.\31\ In
the seventh State, Virginia, commenters claimed that the State's heat
input had almostexceeded EPA's projections and would soon do so. With
regard to some States, commenters also suggested that actual data and
projections concerning electricity demand, economic output, population,
and new generating capacity for these individual States support higher
heat input growth rates than the rates adopted for those States by EPA.
---------------------------------------------------------------------------
\31\ In one of those States, Michigan, EPA's heat input
projections have not actually been exceeded.
---------------------------------------------------------------------------
EPA believes that, in general, these comments have common flaws
that prevent them from providing a basis for concluding that EPA's heat
input growth rates are unreasonable for the particular States at issue.
First, several commenters flatly stated or implicitly assumed that
significant negative growth in heat input was not plausible for their
respective States between now and 2007. As noted above, historical heat
input data show that individual State's heat input can decrease
significantly in the last year, as compared to the first year, of
multi-year periods and is quite variable from year-to-year. (See
section V.D.4 of this notice.)
Indeed, the State heat inputs for four of the States that, as
commenters have emphasized, rose to over or nearly over EPA's 2007
projections, have recently decreased to below or nearly below the 2007
projections. Specifically, the heat input of Michigan--which in 1998
was close to EPA's 2007 projection and, along with West Virginia, was
the focus of the Court's concerns about EPA's growth rates--has
declined since 1998 and remained well below EPA's 2007 projection. The
heat input of West Virginia was higher in 1998, and still is slightly
higher, than EPA's 2007 projection but has declined over 8% since 1998.
Georgia's heat input recently increased above EPA's 2007 projections
but decreased in 2001 below that projection. EPA maintains that the
recent heat input decreases and the variability in State heat input
show why the fact that current heat input for a State exceeds, or is
close to, EPA's 2007 heat input projection for the State does not show
that EPA's heat input growth rate and 2007 projection for the State are
unreasonable.
Second, several commenters compared EPA's heat input growth rate
for an individual State with the heat input growth that the State had
during 1996-2000 and either asserted or implied that EPA should project
the State heat input for 2007 using the actual 1996-2000 growth rate.
However, EPA believes that it is inappropriate to project long-term
heat input growth to 2007 based on a short-term historic trend (here,
1996-2000 heat input growth) for several reasons. Because heat input
can vary greatly from year to year because of factors such as the
weather and the economy, short-term trend data can be greatly skewed.
Moreover, as discussed above, in order to test the validity of
using a relatively short period of years of actual State heat input
data to project future State heat input, EPA simulated that approach
using historical annual heat input data for the 21 NOX SIP
Call States for 1960-2000 (or in some States where less data was
available, from 1970-2000). See section V.D.4 of this notice. Based on
this data, EPA used 6 years' worth of historical data (e.g., 1960-1966)
to project annual heat input for the sixth year after the 6-year period
(e.g, 1972). EPA did this on a rolling basis. For 16 States, EPA found
that there was a very little correlation between the predicted value
based on the historical 6-year periods and the actual value for the
sixth year after that period. For four of the remaining five States,
the correlation was weak. In short, the commenters' approach of using
historical State fossil fuel use for a relatively short period of years
is not a reliable method for predicting future State heat input.
Third, in pointing to certain factors concerning each individual
State to support the claim that the State's heat input could not
reasonably be projected to decline, commenters implicitly assumed that
the State's heat input is determined solely by those State-specific
factors, rather than by the operation of the regional electricity
market as a whole. EPA believes that heat input for an individual State
cannot reasonably be projected by considering only the State's
projected electricity demand and other State-specific factors. Because
electricity is generated and sold in a regional electricity market, an
individual State's heat input is not determined, and cannot reasonably
be projected, based solely on factors relating only to that State.
Rather, a State's heat input must be projected using a comprehensive
approach that considers the regional market. Largely for this reason,
EPA used the IPM--which models electricity markets in the continental
U.S. and the regional electricity market for the NOX SIP
Call area--in its analysis for the NOX SIP Call and the
Section 126 Rule, including the analysis for making heat
[[Page 21891]]
input growth projections.\32\ See Appalachian Power v. EPA, 249 F.3d at
1053 (upholding EPA's determination that ``the IPM offered a more
comprehensive and consistent means of allocating emission allowances
than sorting through the various state-specific projections'').
---------------------------------------------------------------------------
\32\ EPA also used the IPM in order to make sure that consistent
assumptions were used for projecting each State's heat input growth.
---------------------------------------------------------------------------
Contrary to this comprehensive approach to projecting individual
State's heat input, commenters presented projections of significant
economic and population growth for individual States. While these
economic and population projections for a State may suggest that there
will be significant growth in electricity demand in that State, these
State-specific factors suggest little about whether the State's
increased electricity demand will be met from in-State EGUs. It may be
met through increased generation from units within the State, which may
increase that State's heat input, or it may be met through increased
generation from units outside the State from which the State imports
electricity, which may increase the heat input for another State. Even
if the electricity demand is met by units in the State that has the
increased demand, the State's heat input may be affected by the amount
of electricity that the State exports to other States, as well as by
the amount of electricity used within the State. The State's heat input
may still decline under these circumstances if such exports decline. In
short, because electricity is generated and sold on a regional basis, a
State's heat input can decrease even as the State's electricity demand
increases. Because the comments on individual States failed to address
these regional factors, the commenters' claims that the respective
State's heat input could not be expected to decline to the level of
EPA's 2007 projection are unpersuasive.
Another State-specific factor on which some commenters relied in
challenging EPA's heat input growth rate for an individual State is the
amount of new capacity that has been permitted or that is under
construction in that State. The commenters assumed that a significant
amount of new, permitted capacity or capacity under construction
necessarily means that the State's heat input will increase
significantly. However, owners and operators may seek permits for units
that, as it turns out, are not actually built. Further, new units that
are built and operated may displace existing units and, since the new
units are likely to be more efficient in converting heat input to
electricity, the State's heat input may actually decline. (See sections
V.D.6 and 8 of this notice discussing that most new units are gas-fired
units and are likely to be more efficient than existing units.)
Moreover, the amount of electricity that the new units produce will
depend on the supply and demand factors in the regional electricity
market, not simply on supply and demand in the State where the units
are located. Thus, projected increased new capacity may potentially be
a factor pointing to increased heat input in the State where the new
capacity is to be located, but, because so many other factors are
involved, that does not necessarily mean heat input will increase in
that State.
In light of the above discussion, EPA does not believe that
commenters have demonstrated that it is unreasonable to project that
the heat input for those States with recent heat input exceeding EPA's
2007 projections will decline by 2007 to the levels projected by EPA.
EPA addresses below the specific comments made about each State whose
heat input growth rate and heat input projection are in dispute.
a. Alabama
(i) Comments
A commenter stated that Alabama's gross State product is projected
to grow at 2.5% per year during 2001-2010. The commenter also noted
that the ``average annual economic growth rate for the region'' was
3.9% per year during 1995-2000, Alabama has recently had ``economic
annual growth'' well over 3%, and seasonal heat input growth for
Alabama has averaged 3.37% per year in 1996-2000. Noting that Alabama's
heat input in 1999 and 2000 exceeded EPA's 2007 heat input projection,
the commenter claimed that ``[n]egative growth between now and 2007 for
Alabama is simply not a plausible scenario.'' The commenter compared
EPA's heat input growth rate to the State's historical heat input
growth rate for 1995-2000. Claiming that nuclear generation increased
during 1995-2000 but is not expected to increase significantly during
2001-2007, the commenter suggested that Alabama's heat input will grow
even more than the historical heat input growth rate. Finally, the
commenter stated that the NOX SIP Call currently applies
only to the northern two-thirds of the State, where most of the State's
population centers are located and most economic growth will be
concentrated. This is cited as another reason why EPA's heat input
growth rate is inadequate and unrealistic.
(ii) Response
EPA notes that in 1999 and 2000, Alabama's ozone season heat input
(389,364,461 mmBtu and 400,689,850 mmBtu) exceeded EPA's 2007 heat
input projection (385,998,780 mmBtu) by 0.9% and 3.8% respecteviely.
However, in 2001 Alabama's heat input (391,665,691 mmBtu) fell 2.5% and
was only 1.4% above EPA's 2007 projection. Further, as discussed above,
EPA intends to include only the northern portion of Alabama in the
NOX SIP Call. When actual heat input for 2001 for northern
Alabama is compared with EPA's recently proposed 2007 projection for
northern Alabama, the actual heat input in northern Alabama
(284,528,783 mmBtu) is 7.9% below EPA's 2007 projection (308,912,352
mmBtu).\33\
---------------------------------------------------------------------------
\33\ EPA calculated the partial State heat input budgets for
large EGUs for Alabama, Georgia, and Missouri by summing the heat
input for 1996, 1995, and 1995 respectively for all such units in
the fine grid counties of the particular State and applying the
appropriate growth rate. This information is in Docket Item XV-C-29
and is consistent with the partial State NOX emission
budgets proposed in 67 Fed. Reg. 8395, 8416, Feb. 22, 2002.
---------------------------------------------------------------------------
Moreover, as discussed above, individual State heat input is quite
variable and can decrease significantly over multi-year periods. In
fact, historical data for 1960-2000 shows that there have been periods
in the past when Alabama's annual heat input decreased significantly
for the last year, as compared to the first year, of a multi-year
period. For example, for the 8-year period 1974-1982 (comparable in
length to the period 1999-2007), Alabama's annual heat input decreased
by 12%.\34\ Ozone season heat input decreased 17% over the same period,
1974-1982. Thus, the fact that Alabama's most recent heat input
exceeded EPA's 2007 projection
[[Page 21892]]
does not mean that the projection is unreasonable.
---------------------------------------------------------------------------
\34\ EPA's review indicates that one out of the 33 eight-year
periods from 1960-2000 had a decrease in annual heat input of well
over 3.8% (Docket # A-96-56, Item # XV-C-18, at 1), while three out
of the 20 eight-year periods from 1970-1998 had a decrease in ozone
season heat input, with a decrease of well over 3.8% for two periods
(Docket # A-96-56, Item # XV-C-19, at 1). Since these periods--
although a minority--indicate that such decreases can occur, EPA
believes that its methodology should not be considered unreasonable
based on the recent State heat input. Moreover, while these long-
term historical data certainly show the potential for such
decreases, the data are otherwise of limited use in projecting
future heat input. As explained in Section V.D.6. of this notice,
the electricity industry has been undergoing deregulation of
generation and restructuring. As a result, trends in the past, as
reflected in the data, may not continue in the future. The IPM
reflects these changes, and by using the IPM in developing heat
input growth rates, EPA has taken these changes into account.
---------------------------------------------------------------------------
Further, while the commenter did not provide the data to support
its claims about Alabama's economic growth or growth in gross State
product, EPA used data from the Bureau of Economic Analysis to evaluate
the commenter's claims. The commenters assumed, but did not
demonstrate, that growth in gross State product necessarily results in
growth in heat input. In fact, data for 1996-1999 for Alabama, as
reflected in Table 10 below, shows that growth in gross State product
does not necessarily result in growth in heat input. For example, in
1997, State heat input declined 0.2% while gross State product grew
3.4%. In 1996, while Gross State Product grew at 2.8%, heat input grew
at a much slower rate of 0.2%. EPA tested the correlation of heat input
growth rate to gross State product growth rate using the r-squared
test, which is described above in section V.D.5 of this notice. EPA
found that the two sets of growth rate data have a r-squared value of
0.12, showing very little correlation between growth in heat input and
growth in gross State product.
Table 10.--Gross Alabama State Product Growth Rate vs. Heat Input Growth
Rate for 1996-1999
------------------------------------------------------------------------
BEA Gross
State Heat input
Year product growth rate
growth rate (percent)
(percent)
------------------------------------------------------------------------
1996.......................................... 2.8 0.2
1997.......................................... 3.4 -0.2
1998.......................................... 2.9 5.6
1999.......................................... 4.2 5.2
------------------------------------------------------------------------
There are several reasons that EPA believes that heat input growth
on a State level does not correlate with economic growth. First,
electricity demand is affected by many variables. This includes not
only economic growth, but also other factors such as weather and
changes in efficiency in the use of electricity.
Second, as discussed above, a State's heat input does not
necessarily correlate with the State's electricity demand. (See section
V.D.6 of this notice discussing that State heat input can decline when
State electricity use increases.) For instance, in the case of Alabama,
the State is generally a net exporter of electricity. In 1999, Alabama
EGUs generated 120,865,327 Mwh of electricity. In that same year, only
80,401,000 Mwh of electricity were sold in Alabama. Therefore, in order
to assess whether electricity generation or heat input in Alabama will
grow, it is necessary to consider not only electricity demand in
Alabama, but also electricity demand and supply in the regional market
for electricity outside of Alabama. The commenter did not provide any
information on future electricity demand and supply outside of Alabama
and how they might affect future generation and heat input in Alabama.
The lack of strong correlation between economic growth and heat
input is confirmed by historical data on electricity demand and heat
input in northern Alabama. Noting that the NOX SIP Call now
covers only the northern part of Alabama (the fine grid counties), the
commenter presented evidence suggesting that the economy and population
are growing faster in the northern part than in the southern part of
the State. The commenter suggested that heat input will therefore grow
faster in northern Alabama than in the State as a whole. EPA reviewed
heat input data for Alabama and found that, despite higher growth in
the economy and population in northern Alabama, heat input has actually
grown faster in the southern part of the State. The data are summarized
in Table 11 below.
Table 11.--Heat Input (mmBtu) in Alabama for 1996-2001
----------------------------------------------------------------------------------------------------------------
Fine grid Outside fine
counties grid counties All counties
----------------------------------------------------------------------------------------------------------------
1995...................................................... 279,392,756 70,666,448 350,059,204
1996...................................................... 280,829,411 70,078,571 350,907,982
1997...................................................... 277,733,999 72,594,373 350,328,372
1998...................................................... 298,464,504 71,513,696 369,978,200
1999...................................................... 318,056,030 71,308,431 389,364,461
2000...................................................... 314,726,690 85,693,161 400,689,850
2001...................................................... 284,528,783 107,136,907 391,665,690
Avg Annual Growth Rate 1996 to 2001....................... 0.4 8.7 2.3
----------------------------------------------------------------------------------------------------------------
Finally, EPA notes that the commenters' claim concerning the effect
of Alabama's nuclear generation on the State's heat input growth rate
appears to be overstated. The commenters stated that nuclear generation
in Alabama increased during 1995-2000 and is not expected to continue
to increase and that therefore the State's heat input will increase at
a greater rate starting in 2001. However, while Alabama's ozone season
nuclear generation increased significantly from 1995 to 1996 (8,371,445
Mwh to 13,161,369 Mwh during the ozone season), EPA used 1996 as the
baseline year for determining Alabama's NOX emission budget.
During 1996-2000, nuclear generation in Alabama grew much less than
during 1995-2000. Nuclear generation was 13,321,089 Mwh in the 1999
ozone season and 13,578,728 Mwh in the 2000 ozone season. Because there
was only limited growth in nuclear generation from 1996 to 2000, there
is no basis for commenters' claim of increased heat input growth in the
future to offset limited growth from nuclear units. Furthermore, the
Nuclear Regulatory Commission is anticipating that applications will be
submitted to increase the generating capacity of two nuclear powered
units at the Brown's Ferry Plant by 14%. (Docket # A-96-56, Item # XV-
C-27.) While these applications do not necessarily mean that nuclear
generation will increase, they cast doubt on the commenters' assertion
that nuclear generation will not grow.
For the above reasons, EPA rejects the commenters' claims that
EPA's heat input growth rate and 2007 heat input projection of Alabama
are unreasonable.
b. Georgia
(i) Comments
Commenters pointed to EPA's data as showing that Georgia's ozone
season heat input increased more than 3.3% per year from 1995 to 2000,
as compared with EPA's projected increase of 1.01% per year through
2007. Further, commenters noted that Georgia's current
[[Page 21893]]
heat input exceeds EPA's 2007 heat input projections and so the State's
heat input will have to decrease by 2007 in order for the projection to
be correct. Commenters cited several factors--i.e., rapid population
growth, projected growth in peak demand for electricity, and rapid
growth in gross State product--to show that Georgia's heat input will
continue to grow faster than EPA projected. Commenters also stated that
the NOX SIP Call will cover only the northern part of
Georgia (the fine grid counties), whose population is growing faster
than in the southern portion of the State. The commenters suggested
that the heat input will therefore grow even faster for the northern
part of Georgia.
(ii) Response
EPA notes that Georgia's heat input in 1998 (403,716,898 mmBtu) and
2000 (420,260,694 mmBtu) exceeded EPA's 2007 heat input projection
(403,368,582 mmBtu). However, in both cases, heat input fell
significantly the next year and was below EPA's 2007 projection.
Georgia's heat input fell 3.9% between 1998 and 1999 and 10.9% between
2000 and 2001. In 2001, the State's heat input (374,355,956 mmBtu) was
7.2% below EPA's 2007 projection. Further, as discussed above, EPA
intends to include only the northern portion of Georgia in the
NOX SIP Call. When actual heat input for northern Georgia
for 2001 is compared with EPA's recently proposed 2007 projection for
northern Georgia, actual 2001 heat input (360,162,148 mmBtu) is 8.2%
below projected heat input (392,215,442 mmBtu).
Moreover, as discussed above, individual State heat input is quite
variable and can decrease significantly over multi-year periods. In the
past, Georgia's annual heat input has decreased significantly for the
last year, as compared to the first year, of multi-year periods and,
for example, decreased by 17% over the seven-year period 1985-1992
(comparable in length to the period 2000-2007).\35\ Ozone season heat
input decreased 9.9% over the same period, 1985-1992.
---------------------------------------------------------------------------
\35\ EPA's review indicates that four out of the 34 seven-year
periods from 1960-2000 had a decrease in annual heat input, with a
decrease of over 4% for three periods (Docket # A-96-56, Item # XV-
C-18, at 10), while two out of the 21 seven-year periods from 1970-
1998 had a decrease in ozone season heat input, with one of those
decreases greatly exceeding 4% (Docket # A-96-56, Item # XV-C-19, at
10). Since these periods--although a minority--indicate that such
decreases can occur, EPA believes that its methodology should not be
considered unreasonable based on the recent State heat input.
Moreover, while these long-term historical data certainly show the
potential for such decreases, the data are otherwise of limited use
in projecting future heat input. As explained in Section V.D.6. of
this notice, the electricity industry has been undergoing
deregulation of generation and restructuring. As a result, trends in
the past, as reflected in the data, may not continue in the future.
The IPM reflects these changes, and by using the IPM in developing
heat input growth rates, EPA has taken these changes into account.
---------------------------------------------------------------------------
Furthermore, as discussed above, EPA does not believe that
commenters have shown that increases in parameters such as population,
economic output, or peak electricity demand in a particular State
necessarily mean that heat input will increase in that State. In fact,
EPA's analysis of the heat input data for the northern and southern
portions of Georgia shows that recently heat input has increased more
in the southern part of the State, where, according to commenters there
has been less growth in population, than in the northern part of the
State. The data are summarized in Table 12 below.
Table 12.--Heat Input (mmBtu) in Georgia for 1995-2001
----------------------------------------------------------------------------------------------------------------
Fine grid Outside fine
counties grid counties All counties
----------------------------------------------------------------------------------------------------------------
1995...................................................... 347,093,311 9,870,035 356,963,346
1996...................................................... 326,944,480 9,032,533 335,977,013
1997...................................................... 342,870,775 8,336,975 351,207,750
1998...................................................... 390,888,493 12,828,405 403,716,898
1999...................................................... 370,011,938 17,769,163 387,781,101
2000...................................................... 399,110,359 21,150,335 420,260,694
2001...................................................... 360,162,148 14,193,808 374,355,956
Avg Annual Growth Rate 1995 to 2001....................... 0.6 6.2 0.8
----------------------------------------------------------------------------------------------------------------
For the above reasons, EPA rejects the commenters' claims that
EPA's heat input growth rate and 2007 heat input projection of Georgia
are unreasonable.
c. Illinois
(i) Comments
Commenters were concerned that EPA initially proposed to establish
the Illinois heat input growth rate at 34%, but then adopted a final
growth rate of 8%. Commenters contended that the 8% growth rate does
not reflect a realistic growth projection for the State, in light of
the actual heat input growth in Illinois during 1995-2000. According to
the commenters, the actual heat input growth for 1995-2000 exceeded
EPA's projected growth rate, and by 1998 Illinois' heat input exceeded
EPA's heat input projection for 2007. Commenters pointed to the 2000
ozone season (described as a relatively mild summer) when heat input
was 15% higher than the 1996 baseline. Commenters suggested that total
growth from 1996 to 2007 could exceed 30%, far above EPA's 8% estimate,
and that the data support a growth of 34% and certainly no lower than
22%. Commenters asserted that it is also not likely that heat input in
the State will decline below 2000 levels because Illinois has approved
an additional 436.6 million mmBtu/ozone season in generating capacity
since 1999 for which construction has been initiated, with an
additional 25.2 million mmBtu pending.
(ii) Response
With regard to EPA's revision of Illinois' annual heat input growth
rate from 34% to 8%, EPA explained in the NOX SIP Call that
the Agency took comment on using two alternative electricity demand
forecasts to develop the State NOX emission budgets and to
perform the cost-effectiveness analysis. One alternative was a 1995
electricity demand forecast, modified by demand reductions under CCAP,
that was used in an IPM run (``1996 IPM Base Case forecast'') and would
have resulted in certain heat input growth rates (``corrected'' growth
rates), including a growth rate of 34% for Illinois. The second
alternative was a 1997 electricity demand forecast, modified by demand
reductions under CCAP, that was used in a later IPM run (``1998 IPM
Base Case forecast'') and resulted in another set of heat input growth
rates (``revised'' growth rates), including a growth rate of
[[Page 21894]]
8% for Illinois. As explained in the NOX SIP Call (63 FR
57409), EPA used the 1998 IPM Base Case forecast (as the base case run
described in section V.B.1 of this notice) and resulting heat input
growth rates because that forecast reflected assumptions that had been
revised based on public comment and that ``lead to a better projection
of electricity generation nationally, by region and by State.'' \36\
---------------------------------------------------------------------------
\36\ EPA stated that the improvements in the 1998 IPM Base Case
forecast included ``using the most recent NERC estimate for regional
electricity demand; the latest available EIA and NERC generation
unit data; updated fuel forecasts; updated assumptions on nuclear,
hydro-electric and import assumptions (with special attention to
differences in summer use); and an increase in the level of detail
in the model to more accurately capture the transmission constraints
that exist for moving power between various regions of the
country.'' Id. In addition, the forecast included updated
assumptions ``on the size and operation of all electricity
generation units of utilities and independent power producers (with
special attention to cogenerators)'' and ``planning reserve margins
and the costs of building new generation capacity.'' Id.
---------------------------------------------------------------------------
EPA notes that Illinois' heat input in 1998 (450,929,580 mmBtu)
exceeded EPA's 2007 heat input projections (409,351,519 mmBtu), by
10.2% and has continued to exceed that projection. However, the State's
heat input peaked in 1998 and has remained below the 1998 level since
then. By 2001, Illinois' heat input (434,282,881 mmBtu) declined by
3.7% from the 1998 level and was 6.1% higher than EPA's 2007
projection. As discussed above, individual State heat input is quite
variable and can decrease significantly over multi-year periods. In the
past, Illinois' annual heat input has decreased significantly for the
last year, as compared to the first year, of multi-year periods and,
for example, decreased 31% over the 9-year period 1981-1990 (comparable
in length to the 1998-2007 period).\37\ Ozone season heat input
decreased 25.8% over the same period, 1981-1990. Thus, the fact that
Illinois' recent heat input exceeded EPA's 2007 projection does not
mean that the projection is unreasonable.
---------------------------------------------------------------------------
\37\ EPA's review indicates that 13 out of the 32 nine-year
periods from 1960-2000 had a decrease in annual heat input, with a
decrease of more than 10.2% in eight of those periods (Docket #A-96-
56, Item #XV-C-18, at 13), while 11 of the 19 nine-year periods from
1970-1998 had a decrease in ozone season heat input, with a decrease
of more than 10.2% in eight of those periods. (Docket #A-96-56, Item
#XV-C-19, at 13). Since these periods--although a minority--indicate
that such decreases can occur, EPA believes that its methodology
should not be considered unreasonable based on the recent State heat
input. Moreover, while these long-term historical data certainly
show the potential for such decreases, the data are otherwise of
limited use in projecting future heat input. As explained in Section
V.D.6. of this notice, the electricity industry has been undergoing
deregulation of generation and restructuring. As a result, trends in
the past, as reflected in the data, may not continue in the future.
The IPM reflects these changes, and by using the IPM in developing
heat input growth rates, EPA has taken these changes into account.
---------------------------------------------------------------------------
Illinois' decreases in heat input over the last few years may be
partly attributed to an increase in nuclear generation in Illinois
since 1998, as shown in Table 13. In both 1997 and 1998, five nuclear
units representing over 5000 MW of capacity (nearly 14% of the total
installed capacity in Illinois) were offline. This resulted in
significantly less generation from nuclear units. It appears that at
least some of the generation was made up by additional fossil-fired
generation. In 1999, when three of the nuclear units returned online,
heat input declined. During this period, electricity demand in Illinois
increased.
Table 13.--Heat Input, Nuclear Generation, and Electricity Sales in Illinois for 1995-2001
----------------------------------------------------------------------------------------------------------------
Nuclear
Year Heat Input generation Electricity
(mmBtu) (Mwh) sales (Mwh)
----------------------------------------------------------------------------------------------------------------
1995............................................................ 347,985,300 35,410,101 55,960,000
1996............................................................ 379,029,184 29,038,573 53,348,000
1997............................................................ 406,127,886 23,038,672 53,357,000
1998............................................................ 450,929,580 25,331,514 58,665,000
1999............................................................ 418,420,171 37,004,253 60,470,000
2000............................................................ 436,052,570 38,287,858 59,834,000
2001............................................................ 434,282,881 38,590,400 60,310,000
----------------------------------------------------------------------------------------------------------------
The commenters did not provide any information on future nuclear
generation in Illinois and how that might affect future generation and
heat input in the State. However, the Nuclear Regulatory Commission
recently approved significant expansions in generating capacity for
several nuclear units in Illinois (i.e., a 17% expansion to about 912
MW each for Dresden 2 and 3 and a 17.8% expansion to about 912 MW each
for Quad Cities 1 and 2). The upgrades are scheduled for completion
during outages in 2002 and 2003. (Docket A-96-56, Item # XV-C-07, ``NRC
Approves Power Uprates for Dresden 2, 3 and Quad Cities 1, 2,'' Nuclear
Regulatory Commission Press Release, December 26, 2001.) Once the
capital investment is made in expanding nuclear capacity, nuclear
generation has relatively low operating costs.\38\ As a result, nuclear
generation in Illinois may well increase in the next 2 years and
therefore may be one factor tending to reduce heat input for the State.
---------------------------------------------------------------------------
\38\ This contrasts with fossil fuel-fired units, whose
operating costs are higher because of the cost of fossil fuel.
---------------------------------------------------------------------------
Another factor that may have been a partial cause of increased heat
input in Illinois and that may change in the future is Illinois'
recently increased exports of electricity to other States. In 1994,
Illinois was exporting 14% of its electricity; by 1999 that number had
reached 19%. Heat input increased along with this increase in export of
electricity. Whether this level of exports will continue will depend on
electricity supply and demand in the regional electricity market. For
example, increases in generation in neighboring States may lead to less
of an export market and therefore a decrease in heat input. The
commenters did not provide any information on future electricity demand
and supply outside of Illinois or how they might affect future
generation and heat input in Illinois.
Finally, the commenters pointed to approval or construction of new
units in Illinois as showing that Illinois heat input will continue to
grow through 2007. However, as discussed above, approval or
construction of new units is not a definitive indicator of increased
heat input in the future.
For the reasons above, EPA rejects the commenters' claims that
EPA's heat input growth rate and 2007 heat input projection for
Illinois are unreasonable.
[[Page 21895]]
d. Michigan
(i) Comments
Commenters stated that Michigan's heat input in 1998 exceeded EPA's
2007 heat input projection. Commenters also stated that the Michigan
Public Service Commission estimates Michigan's growth in electricity
demand to be twice the amount that EPA ``presumed in its calculations''
for the NOX SIP Call and Section 126 Rule and that there is
no basis for the ``presumed'' negative growth in energy demand for
Michigan. Further, commenters pointed to weather as the major reason
for year-to-year variability in Michigan's heat input. Noting the hot
temperatures in 1995, 1998, and 1999 and the cool temperatures in 1996,
1997, and 2000, they stated that weather was the primary cause of the
dramatic increase in heat input in 1998 and the decline in 2000. The
commenters compared the years with similar summer weather patterns to
find an ozone season growth rate of 2.0% or 2.1% per year, which is
much higher than EPA's 1.1% projected annual growth rate. Commenters
also pointed to operational problems at the fossil-fuel fired Monroe
Plant as contributing to the lower State heat input in 2000. Finally,
commenters suggested that the modeling of unit dispatch in the IPM does
not accurately reflect unit dispatching in Michigan because the IPM
dispatches on a national basis.
(ii) Response
EPA notes that Michigan's heat input has never actually exceeded
EPA's 2007 heat input projection. In 1998, Michigan's heat input
(408,239,157 mmBtu) came close to (i.e., 0.4% below) EPA's 2007
projection (410,058,589 mmBtu). Since 1998, Michigan's heat input has
declined each year. Michigan's 2001 heat input (374,318,406 mmBtu) was
8.7% below EPA's 2007 projection. Moreover, as discussed above,
individual State heat input is quite variable and can decrease
significantly over multi-year periods. In the past, Michigan's annual
heat input has decreased significantly for the last year, as compared
to the first year, of multi-year periods and, for example, decreased by
10.9% over the 9-year period 1973-1982 (comparable in length to the
1998-2007 period).\39\ Ozone season heat input decreased 13.4% over the
same period, 1973-1982.
---------------------------------------------------------------------------
\39\ EPA's review indicates that eight out of the 32 nine-year
periods from 1960-2000 had a decrease, or an increase of no more
than 0.4%, in annual heat input (Docket # A-96-56, Item # XV-C-18,
at 28), while 2 of the 19 nine-year periods from 1970-1998 had a
decrease, or an increase of no more than 0.4%, in ozone season heat
input. (Docket # A-96-56, Item # XV-C-19, at 28). Since these
periods--although a minority--indicate that such decreases and small
increases can occur, EPA believes that its methodology should not be
considered unreasonable based on the recent State heat input.
Moreover, while these long-term historical data certainly show the
potential for such decreases and small decreases, the data are
otherwise of limited use in projecting future heat input. As
explained in Section V.D.6. of this notice, the electricity industry
has been undergoing deregulation of generation and restructuring. As
a result, trends in the past, as reflected in the data, may not
continue in the future. The IPM reflects these changes, and by using
the IPM in developing heat input growth rates, EPA has taken these
changes into account.
---------------------------------------------------------------------------
EPA believes that Michigan's decline in heat input in the last few
years may be at least partly attributable to resolution of operational
problems at the Cook Nuclear facility, as reflected in Table 14
below.\40\ The spike in Michigan's heat input in 1998 coincides with
the outage of two nuclear units at the Cook Nuclear Plant in Michigan.
These two units are capable of generating a total of 2285 MW, which
represents over 9% of the capacity in Michigan. Cook Unit 2 did not
return to service until the middle of the 2000 ozone season, and Cook
Unit 1 did not return to service until after the 2000 ozone season.
These outages resulted in significantly less generation from nuclear
plants and coincided with significantly more fossil fuel generation and
heat input in 1998 and 1999. As the nuclear units came back into
service and increased their generation, fossil fuel generation and heat
input in Michigan declined. Under these circumstances, the fact that
Michigan's 1998 heat input came close to EPA's 2007 projection does not
demonstrate that EPA's projection is unreasonable.
---------------------------------------------------------------------------
\40\ It has been suggested that Cook nuclear generation has been
taken up by out-of-state affiliates of Cook and therefore that
Cook's operational problems have not affected fossil-fired
generation in Michigan. However, EPA has not received specific
information purporting to demonstrate this pattern. Indeed, the
Michigan Public Utility Commission has highlighted that the
resumption of normal operations by the Cook Nuclear facility
increases both available generation and the ability to import power,
which suggests that Cook and fossil-fired Michigan generators are
interrelated. Summer 2001, Energy Appraisal, Michigan Public Utility
Commission, http://www.cis.state.mi.us/mpsc/reports/energy/01summer/electric.htm.
Table 14.--Nuclear Generation vs. Total Utility Generation for Michigan
in 1995-2001
------------------------------------------------------------------------
Ozone Season Total Utility
nuclear Ozone Season
Year generation Generation\41\
(Mwh) (Mwh)
------------------------------------------------------------------------
1995.................................... 8,779,412 38,175,367
1996.................................... 12,708,112 41,024,588
1997.................................... 12,804,255 40,660,688
1998.................................... 4,923,916 36,618,364
1999.................................... 6,472,871 38,679,849
2000.................................... 8,195,891 39,550,421
2001.................................... 10,456,684 40,844,263
------------------------------------------------------------------------
\41\ EIA provided generation data for this entire period only for large
utility units. In the State of Michigan, non-utility units make up
about 12% of the generation capacity.
With regard to the comment that EPA's heat input projections are
not consistent with the Michigan Public Utility Commission's
electricity demand projections, EPA notes that electricity demand and
heat input are not necessarily correlated. (See section V.D.6 of this
notice.) For example, from 1988 to 1993, Michigan's electricity sales
grew 6.1% at the same time that the State's heat input dropped 8%.
Several comments suggest that Michigan's 2000 heat input was not
representative because 2000 was a cool summer and that the State's heat
input therefore should be disregarded in considering the reasonableness
of EPA's 2007 heat input projection. The commenters seem to suggest
that the fact that the summer was relatively cool meant that
electricity demand, and so heat input, were lower in Michigan in 2000.
However, EPA notes that Michigan's electricity demand in 1998 was
44,451,681 Mwh and has been higher every year since 1998. In other
words, even though electricity demand has grown since 1998, heat input
has not. As for the comment that operational problems at the Monroe
Power Plant reduced Michigan's heat input in 2000, EPA notes that
Michigan's heat input in 2001 continued to decrease from 2000, even
though there was much less of a decrease in heat input from the Monroe
Power Plant from 2000 to 2001. Furthermore, EPA believes that heat
input should not be evaluated on a plant-by-plant basis, because
declines in heat input for one plant may well be accompanied by
increases in heat input for another plant. For instance, while the
Monroe Power Plant had lower heat input in 2000 than it had in previous
years, heat input from the David E. Karn Plant in Michigan was
significantly higher in 2000 than in previous years, and the amounts of
the decrease in
[[Page 21896]]
Monroe heat input and the increase in Karn heat input were about the
same.
Finally, EPA disagrees with the comment that the modeling of unit
dispatch in the IPM is inaccurate for Michigan because the IPM models
the entire U.S. The IPM divided the U.S. into multiple subregions
(including a subregion comprising most of Michigan). This allows the
model to reflect both local dispatch patterns and the interstate nature
of the electric grid.
For the reasons above, EPA rejects the commenters' claims that
EPA's heat input growth rate and 2007 heat input projection of Michigan
are unreasonable.
e. Missouri
(i) Comments
A commenter noted that Missouri's average actual heat input growth
rate for 1995-2000 exceeded EPA's heat input growth rate by about three
times. The commenter also noted that Missouri's heat input in 1998
exceeded EPA's 2007 heat input projection for the State.
(ii) Response
EPA notes that Missouri's 1999 heat input (335,273,139 mmBtu)
exceeded EPA's 2007 heat input projection (309,316,824 mmBtu)by 8.4%.
Since 1999, Missouri's heat input declined to 332,332,587 mmBtu in 2000
and 329,668,165 mmBtu in 2001, but continued to exceed EPA's
projection. Missouri's 2001 heat input exceeded EPA's 2007 projection
by 6.2%. The heat input decline occurred even though, during this time,
electricity demand in Missouri increased from 31,704,000 Mwh in 1999 to
33,519,000 Mwh in 2000 and 32,539,000 Mwh in 2001. Further, as
discussed above, EPA intends to include only the eastern portion (the
fine grid counties) of Missouri in the NOX SIP Call. When
actual heat input for eastern Missouri for 2001 is compared with EPA's
recently proposed 2007 projection for eastern Missouri, the difference
between the actual 2001 heat input (184,541,335 mmBtu) and the
projected 2007 heat input (178,431,621 mmBtu) narrows to 3.4%.
Table 15.--Heat Input (mmBtu) in Missouri for 1995-2001
----------------------------------------------------------------------------------------------------------------
Outside fine grid
Fine grid counties counties All counties
----------------------------------------------------------------------------------------------------------------
1995............................................. 163,698,735 120,078,167 283,776,902
1996............................................. 159,770,676 116,268,060 276,038,736
1997............................................. 176,843,306 121,262,736 298,106,042
1998............................................. 190,237,705 124,494,173 314,731,878
1999............................................. 200,802,706 134,470,433 335,273,139
2000............................................. 196,392,883 135,939,703 332,332,587
2001............................................. 184,541,335 145,126,830 329,668,165
Avg Annual Growth Rate 1995 to 2001.............. 2.0 3.2 2.5
----------------------------------------------------------------------------------------------------------------
Moreover, as discussed above, individual State heat input is quite
variable, is not necessarily correlated with electricity demand in the
State, and can decrease significantly over multi-year periods. In the
past, Missouri's annual heat input has decreased significantly for the
last year, as compared to the first year, of multi-year periods and,
for example, decreased 11% over the 8-year period 1984-1992 (comparable
in length to the 2000-2007 period).\42\ Ozone season heat input
decreased 9.1% over the same period, 1984-1992. Thus, the fact that
Missouri's most recent heat input exceeded EPA's 2007 projection does
not mean that the projection is unreasonable.
---------------------------------------------------------------------------
\42\ EPA's review indicates that six out of the 33 eight-year
periods from 1960-2000 had a decrease in annual heat input, with a
decrease of 8.4% or more in one of these periods (Docket # A-96-56,
Item # XV-C-18, at 31), while two out of the 20 eight-year periods
from 1970-1998 had a decrease in ozone season heat input, with a
decrease of 8.4% or more in one of these periods (Docket # A-96-56,
Item # XV-C-19, at 31). Since these periods--although a minority--
indicate that such decreases can occur, EPA believes that its
methodology should not be considered unreasonable based on the
recent State heat input. Moreover, while these long-term historical
data certainly show the potential for such decreases, the data are
otherwise of limited use in projecting future heat input. As
explained in Section V.D.6. of this notice, the electricity industry
has been undergoing deregulation of generation and restructuring. As
a result, trends in the past, as reflected in the data, may not
continue in the future. The IPM reflects these changes, and by using
the IPM in developing heat input growth rates, EPA has taken these
changes into account.
---------------------------------------------------------------------------
For the reasons above, EPA rejects the commenter's claims that
EPA's heat input growth rate and 2007 heat input projection of Missouri
are unreasonable.
f. Virginia
(i) Comments
Commenters asserted that there are various data omissions and
errors in the heat input data for baseline year (1995) and for
subsequent years through 1999 for Virginia, particularly as applied to
independent power producers. According to commenters, the lack of heat
input data for several of these facilities resulted in understated
baseline heat input and, in the Section 126 Rule, in understated
allowance allocations for certain units, whose allocations were based
on 1995-1998 heat input. Commenters requested that EPA correct the
allowance allocations in the Section 126 Rule. Commenters also stated
that there has been a substantial increase in Virginia's heat input
between 1995 and 2000 and that the State's heat input in 1997 and 1998
was within 7% of EPA's 2007 heat input projections and within 1.3% in
1999. Commenters predicted that the State's 2007 heat input level will
be 319,087,054 mmBtu, for existing units based on the ``historical
trend'' of heat input, and 395,216,765 mmBtu, based on ``power
generation output,'' as compared to EPA's projection of 228,699,872
mmBtu. Commenters also were concerned that EPA underestimated
Virginia's new generation capacity. Virginia has 12,000 MW of potential
new capacity at various stages of the permitting process. According to
the commenters, EPA's estimate of new generation capacity is
underestimated by over 3,000 MW, and the 5% set aside in the State's
EGU NOX emission budget under the Section 126 Rule is
inadequate to accommodate projected new capacity.
(ii) Response
EPA notes that its 2007 heat input projection for Virginia
(227,875,597 mmBtu) has not been exceeded, though Virginia's 1999 heat
input (225,665,092 mmBtu) was close to (i.e., 1% below) the 2007
projection. Since 1999, Virginia's heat input has declined, and in 2001
the State's heat input (213,583,835 mmBtu) fell to 6.3% below
[[Page 21897]]
EPA's 2007 projection. Moreover, as discussed above, individual State
heat input is quite variable and can decrease significantly over multi-
year periods. In the past, Virginia's annual heat input has decreased
significantly for the last year, as compared to the first year, of
multi-year periods and, for example, decreased 38% over the 6-year
period 1977-1983 (comparable in length to the 2001-2007 period).\43\
Ozone season heat input decreased by 23.9% over 1978 and 1984.\44\
---------------------------------------------------------------------------
\43\ EPA's review indicates that ten out of the 32 nine-year
periods from 1960-2000 had a decrease, or an increase of no more
than 1%, in annual heat input (Docket # A-96-56, Item # XV-C-18, at
58), while 7 of the 19 nine-year periods from 1970-1998 had a
decrease, or an increase of no more than 1%, in ozone season heat
input (Docket # A-96-56, Item # XV-C-19, at 58). Since these
periods--although a minority--indicate that such decreases and small
increases can occur, EPA believes that its methodology should not be
considered unreasonable based on the recent State heat input.
Moreover, while these long-term historical data certainly show the
potential for such decreases and small increases, the data are
otherwise of limited use in projecting future heat input. As
explained in Section V.D.6. of this notice, the electricity industry
has been undergoing deregulation of generation and restructuring. As
a result, trends in the past, as reflected in the data, may not
continue in the future. The IPM reflects these changes, and by using
the IPM in developing heat input growth rates, EPA has taken these
changes into account.
\44\ Monthly data was not available for the year 1983, so a
comparison of the period between 1977 and 1983 cannot be made.
---------------------------------------------------------------------------
Further, as discussed above, because heat input is quite variable,
EPA believes that it is inappropriate to project long-term heat input
growth to 2007 based on a short-term trend like Virginia's heat input
growth for 1995-2000. With regard to comments concerning the new
generation capacity that is at various stages of permitting in
Virginia, projected new units do not necessarily result, as discussed
above, in increased State heat input.
For the reasons above, EPA rejects the commenters' claims that
EPA's heat input growth rate and 2007 heat input projection of Virginia
are unreasonable.
EPA notes that the comments on Virginia's 1996 baseline heat input
and on unit-specific allowances allocations and the size of the set-
aside for new units under the Section 126 Rule are outside the scope of
the remand and today's notice. The Court remanded EPA's heat input
growth rates and 2007 heat input projections and did not address or
remand any issues concerning the data used to calculate State's 1995 or
1996 baseline heat input. In addition, the Court did not remand any
issues concerning the determination of individual units' allowance
allocations or the size of the set-aside for new units. Consistent with
the Court's remand, EPA explained in the August 3, 2001 NODA that EPA
was not seeking comments on the data used to calculate 1995 or 1996
baseline heat input or on allowance allocations, (66 FR. 40616). EPA is
therefore not addressing today the comments on Virginia's 1996 baseline
heat input, unit-specific allowance allocations, and the set-aside for
new units.\45\ However, data for subsequent years were not used in
calculating Virginia's 1996 baseline heat input. EPA has incorporated
the commenters' data corrections for 1997-1999 for purposes of the
Agency's review of Virginia's heat input growth rates.\46\
---------------------------------------------------------------------------
\45\ EPA notes that it previously solicited corrections to
baseline heat input data and responded to requested corrections
through the Technical Amendments in 1999 and 2000. EPA also notes
that, based on the data provided by commenters, the requested
changes to 1996 heat input would have very little impact on
Virginia's EGU NOX emission budget. Virginia's 1996
baseline heat input (which was used to develop the budget) would
increase by 131 tons, and, with the application of EPA's growth
factor of 1.32 for Virginia, the State's EGU NOX emission
budget would increase by 173 tons or 1%.
\46\ EPA similarly incorporated other specific data corrections
requested by commenters for other States for 1997 or later.
---------------------------------------------------------------------------
g. West Virginia
(i) Comments
Commenters argued that EPA's growth factor for West Virginia is
inaccurate, technically unjustifiable, and significantly lower than the
growth rates assigned to neighboring States. Commenters pointed to the
discrepancy between actual heat input growth during 1995-2000 in West
Virginia (1.84% a year) to EPA's heat input growth rate of 0.25% a
year. According to commenters, extrapolating the 1.84% growth rate to
2007 would result in a 32.3% increase in heat input compared to EPA's
projected 3% increase. Commenters also noted that West Virginia's
actual average heat input for 1998-2000 exceeds EPA's 2007 heat input
projection by 8%. Commenters asserted that in order for EPA's
projections to be reasonably accurate, West Virginia's heat input will
have to decrease as much as 6% over the next 6 years.
Further, commenters described West Virginia as an electricity
exporter and argued that the State can be expected to have heat input
increases commensurate with rising national electricity demand.
Commenters pointed to the actual 1.84% increase in ozone season heat
input from 1995-2000, which they argued is comparable to the projected
1.8% increase in electricity demand over the next 20 years in the
National Energy Policy.
The commenters claimed that the unreasonableness of EPA's
methodology is further demonstrated by comparing West Virginia's heat
input relative to the total heat input for the NOX SIP Call
region. With EPA's heat input growth rates and 2007 heat input
projections, the State was allotted only 5% of the regional heat input,
but use of the 2001 and 2010 IPM heat input projections show West
Virginia with 6.9% and 6.4% respectively of regional heat input. In
addition, commenters noted that the IPM run for 2007 projects heat
input for West Virginia that exceeds EPA's 2007 heat input projection
for the State.
Commenters stated that year-to-year variation in heat input did not
explain the difference between West Virginia's current heat input and
EPA's 2007 heat input projection, which is lower. Commenters asserted
that West Virginia has lower year-to-year variability in heat input
than surrounding States.
Finally, commenters contended that EPA's heat input growth rates
fail to account sufficiently for new EGU units in the State. According
to the commenters, while eight new EGUs with a combined generating
capacity of 5,833 MW have been planned and committed for construction,
EPA projected 1,049 MW of new natural gas fired units to West Virginia
through 2010.
(ii) Response
EPA notes that West Virginia's heat input exceeded EPA's 2007 heat
input projection (358,117,926 mmBtu) beginning in 1997 when it exceeded
EPA's 2007 projection by 1.9%. The State's heat input peaked in 1999
(391,592,231 mmBtu), exceeding EPA's 2007 projection by 9.3%. Since
1999, West Virginia's heat input declined by 8% over the next 2 years,
and the 2001 heat input (360,185,154 mmBtu) exceeded EPA's 2007
projection by only 0.6%. Moreover, as discussed above, individual State
heat input is quite variable and can decrease significantly over multi-
year periods. In the past, West Virginia's annual heat input has
decreased significantly for the last year, as compared to the first
year, of multi-year periods and, for example, decreased 5.5% over the
10-year period 1981-1991 (comparable in length to the 1997-2007 period)
and decreased 10.9% over the 8-year period 1983-1991 (comparable in
length to the 1999-2001 period) \47\ and 13% over 1984-1992.
[[Page 21898]]
Ozone season heat input decreased 9.1% over 1982-1992.\48\ Thus, the
fact that West Virginia's heat input has recently exceeded EPA's 2007
heat input projection does not mean that EPA's projection is
unreasonable.
---------------------------------------------------------------------------
\47\ EPA's review indicates that two out of the 31 ten-year
periods from 1960-2000 had a decrease in annual heat input, with the
largest decrease being 5.5% (Docket # A-96-56, Item # XV-C-18, at
61), while four out of the 18 ten-years periods from 1970-1998 had a
decrease in ozone season heat input, with the largest decrease being
9.1% (Docket # A-96-56, Item # XV-C-19, at 61). Since these
periods--although a minority--indicate that such decreases can
occur, EPA believes that its methodology should not be considered
unreasonable based on the recent State heat input. Moreover, while
these long-term historical data certainly show the potential for
such decreases, the data are otherwise of limited use in projecting
future heat input. As explained in Section V.D.6. of this notice,
the electricity industry has been undergoing deregulation of
generation and restructuring. As a result, trends in the past, as
reflected in the data, may not continue in the future. The IPM
reflects these changes, and by using the IPM in developing heat
input growth rates, EPA has taken these changes into account.
\48\ The periods for decreasing ozone season heat input
obviously differ slightly from the periods for decreasing annual
heat input.
---------------------------------------------------------------------------
Further, while EPA agrees that West Virginia is a significant
exporter of electricity, EPA does not believe that it necessarily
follows that West Virginia's heat input will continue to grow. Since
less than a third of the electricity generated in West Virginia is sold
in West Virginia, the ability to export electricity plays an important
part in the amounts of both electricity generation and heat input in
West Virginia. The level of West Virginia's exports in the future will
depend on electricity supply and demand in the regional electricity
market. The commenters did not provide any information on future
electricity demand and supply outside of West Virginia and how they
might affect future generation and heat input in West Virginia. West
Virginia's heat input declined over 8% during 1999-2001 despite the
fact that electricity sales increased 1.2% in the NOX SIP
Call region.
While commenters provided a graph to demonstrate that West
Virginia's heat input has been less variable than other States' heat
input, that graph covers only 1995-2000 and so fails to show the
variability reflected by the heat input decrease between 2000 and 2001.
Further, since the range of movement, up and down, of lines on a graph
can vary depending on the range of the vertical and horizontal scales
presented in the graph, the variability of the graphed parameter (here,
State heat input) cannot be determined simply by looking at the graph.
Commenters provided no other support for the claim of less variable
heat input. Moreover, the 1995-2001 ozone season data and the 1960-2000
annual heat input data for West Virginia show, contrary to the
commenters, that the State's heat input is quite variable, as reflected
in significant decreases over multi-year periods. (See Tables 2 through
9 above.)
Finally, as discussed above, because heat input is quite variable,
EPA believes that it is inappropriate to project long-term heat input
growth to 2007 based on a short-term trend like West Virginia's heat
input growth for 1995-2000. With regard to comments concerning the heat
input, or percentage share of heat input, projected for West Virginia
by the IPM, EPA maintains that the IPM is more accurate in predicting
the change in State heat input between modeled years than in
pinpointing State heat input for a particular year. (See section V.C.2
of this notice.) With regard to comments concerning the new gas-fired
generation capacity that is planned in West Virginia, projected new
units do not necessarily result, as discussed above, in increased State
heat input.
For the reasons above, EPA rejects the commenters' claims that
EPA's heat input growth rate and 2007 heat input projection of West
Virginia are unreasonable.
10. No Heat Input Growth Rate Methodology Has Been Presented That Would
Have Results That Better Comport With Actual Heat Input
As discussed in detail above, EPA believes that the fact that a
State's recent heat input exceeds a heat input projection for the State
for 2007 does not make the projection unreasonable. However, in light
of the Court's and commenters' concerns over cases where recent actual
State heat input exceeded the 2007 projection, EPA decided to compare
the heat input growth rates and 2007 heat input projections under the
Agency's methodology to those under the alternative heat input growth
methodologies considered previously by EPA or discussed by commenters.
In making this comparison, EPA focused on how the 2007 projections
compared with actual heat input data to date for most of the
NOX SIP Call States. EPA excluded Connecticut,
Massachusetts, and Rhode Island from the comparison of the growth rate
methodologies because they entered into a February 1999 Memorandum of
Understanding in which they reallocated their NOX emission
budgets for EGUs, and effectively reallocated their projected heat
input, among the three States. This agreement, which was implemented in
their SIPs approved on December 27, 2000, rendered moot any potential
issues concerning the 2007 heat input projections used to calculate
their original NOX emission budgets. As discussed below, EPA
found that, while the alternative methodologies resulted in higher 2007
projected heat input for some individual States, overall the
alternative 2007 projections would not comport better than EPA's 2007
projections with the actual heat input data for the NOX SIP
Call States.
The first alternative methodology would involve using heat input
growth rates from OTAG. During the NOX SIP Call rulemaking,
EPA reviewed NOX emission projections by OTAG and converted
them into heat input projections and growth rates. The EPA and OTAG
heat input growth rates are compared in Table 16 below.
Table 16.--Comparison of OTAG and EPA State Heat Input Growth Factors
\49\
------------------------------------------------------------------------
OTAG
State growth EPA growth
rate rate
------------------------------------------------------------------------
AL.......................................... 1.21 1.10
DC.......................................... 1.00 1.36
DE.......................................... 1.15 1.27
GA.......................................... 1.03 1.13
IL.......................................... 1.08 1.08
IN.......................................... 1.12 1.17
KY.......................................... 1.08 1.16
MD.......................................... 1.05 1.35
MI.......................................... 0.94 1.13
MO.......................................... 1.05 1.09
NC.......................................... 1.10 1.21
NJ.......................................... 1.10 1.21
NY.......................................... 1.08 1.05
OH.......................................... 1.04 1.07
PA.......................................... 1.06 1.15
SC.......................................... 1.03 1.43
TN.......................................... 1.13 1.21
VA.......................................... 1.07 1.32
WV.......................................... 1.05 1.03
Region...................................... 1.04 1.1
------------------------------------------------------------------------
\49\ Throughout this notice the term growth rate (expressed in percent)
has been used. In the original rulemaking EPA actually used growth
factors (a factor used to multiply the baseline heat input). Growth
factors can be converted to growth rates by subtracting 1 and
expressing the value in terms of a percent (e.g. a growth factor of
1.08 is equivalent to a growth rate of 8%). In other words, increasing
a baseline heat input by 8% growth rate is equivalent to multiplying
the baseline heat input by a 1.08 growth factor.
Focusing first on the States for which EPA's heat input growth
rates have been disputed by commenters, EPA notes that EPA's State heat
input growth rate is higher than OTAG's for three States (Georgia,
Michigan, and Virginia), lower for three States (Alabama, Missouri, and
West Virginia) and the same for one State (Illinois). Further, as shown
in Table 19 below, the 2007 heat input projection based on OTAG's
growth rates would be exceeded by actual State heat input in a recent
year for ten jurisdictions, as compared to seven jurisdictions when
2007 projections are
[[Page 21899]]
based on EPA's growth rates.\50\ In addition, using OTAG's heat input
growth rates, the overall heat input growth rate for the entire
NOX SIP Call region would be less than the overall growth
rate using EPA's growth rates, and the heat input projections for 2007
for the region would be lower. In summary, using OTAG's growth rates,
rather than EPA's heat input growth rates would result in more States
recently exceeding their 2007 heat input projections and lower heat
input for the region as a whole.\51\
---------------------------------------------------------------------------
\50\ While EPA's 2007 heat input projection was exceeded by New
York's 1999 heat input, no commenter disputed the heat input growth
rate for that State. Moreover, the State's heat input has decreased
since 1999 and is now well below EPA's projection. In fact, heat
input in every year other than 1999 has been lower than the actual
heat input in 1995.
\51\ As discussed in section V.C.3 of this notice, OTAG's
projections also are fundamentally flawed in that they are not based
on consistent assumptions.
---------------------------------------------------------------------------
A second alternative methodology that EPA considered in the
NOX SIP Call rulemaking and that a commenter proposed is use
of a single, regionwide heat input growth factor based on the 2001-2010
heat input growth rate under the IPM (i.e., 1.15%). This would result
in the same projected heat input for the NOX SIP Call region
as a whole, but in a different apportioning of that heat input among
the States in the region. With regard to the States whose heat input is
disputed by commenters, EPA's State heat input growth rate is higher
than under this second alternative for four States (Georgia, Illinois,
Michigan, and Virginia) and lower in three States (Alabama, Missouri,
and West Virginia). Further, as shown in Table 18 below, the 2007 heat
input projection based on the single, regionwide growth rate would be
exceeded in a recent year by actual State heat input for nine
jurisdictions, as compared to seven jurisdictions when 2007 projections
are based on EPA's growth rates. Thus, using this second alternative
methodology, rather than EPA's methodology, would result in additional
States exceeding their 2007 heat input projections.\52\
---------------------------------------------------------------------------
\52\ Further, as a conceptual matter, EPA considers this
alternative less reasonable than EPA's methodology because this
alternative assumes the same amount of heat input growth for each
State, a phenomenon that is demonstrably unrealistic, based on both
historical experience and model projections.
---------------------------------------------------------------------------
During the NOX SIP Call rulemaking, EPA received comment
on a third alternative methodology to project heat input. The commenter
suggested using growth factors based on actual 1996 data and 2007 IPM
projections. These growth rates, which would be applied to 1996 heat
input, are set forth in Table 17 below.
A second alternative methodology that EPA considered in the
NOX SIP Call rulemaking and that a commenter proposed is use
of a single, regionwide heat input growth factor based on the 2001-2010
heat input growth rate under the IPM (i.e., 1.15%). This would result
in the same projected heat input for the NOX SIP Call region
as a whole, but in a different apportioning of that heat input among
the States in the region. With regard to the States whose heat input is
disputed by commenters, EPA's State heat input growth rate is higher
than under this second alternative for four States (Georgia, Illinois,
Michigan, and Virginia) and lower in three States (Alabama, Missouri,
and West Virginia). Further, as shown in Table 18 below, the 2007 heat
input projection based on the single, regionwide growth rate would be
exceeded in a recent year by actual State heat input for nine
jurisdictions, as compared to seven jurisdictions when 2007 projections
are based on EPA's growth rates. Thus, using this second alternative
methodology, rather than EPA's methodology, would result in additional
States exceeding their 2007 heat input projections.\52\
---------------------------------------------------------------------------
\52\ Further, as a conceptual matter, EPA considers this
alternative less reasonable than EPA's methodology because this
alternative assumes the same amount of heat input growth for each
State, a phenomenon that is demonstrably unrealistic, based on both
historical experience and model projections.
---------------------------------------------------------------------------
During the NOX SIP Call rulemaking, EPA received comment
on a third alternative methodology to project heat input. The commenter
suggested using growth factors based on actual 1996 data and 2007 IPM
projections. These growth rates, which would be applied to 1996 heat
input, are set forth in Table 17 below.
Table 17.--Comparison of 1996-2007 State Growth Rates and EPA Heat Input
Growth Rates
------------------------------------------------------------------------
Commenter
State growth EPA growth
rate rate
------------------------------------------------------------------------
AL............................................ 1.07 1.10
DE............................................ 1.53 1.36
DC............................................ 0.40 1.27
GA............................................ 1.11 1.13
IL............................................ 1.25 1.08
IN............................................ 1.09 1.17
KT............................................ 1.13 1.16
MD............................................ 1.08 1.35
MI............................................ 1.24 1.13
MO............................................ 1.33 1.09
NJ............................................ 2.3 1.21
NY............................................ 1.07 1.21
NC............................................ 1.33 1.05
OH............................................ 1.02 1.07
PA............................................ 1.10 1.15
SC............................................ 1.45 1.43
TN............................................ 1.11 1.21
VA............................................ 1.47 1.32
WV............................................ 1.35 1.03
------------------------------------------------------------------------
With regard to the States whose heat input is disputed by
commenters, EPA's State heat input growth rate is higher than under
this third alternative for two States (Alabama and Georgia) and lower
in five States (Illinois, Michigan, Missouri, Virginia, and West
Virginia). Further, as shown in Table 18 below, the 2007 heat input
projection based on the third alternative methodology would be exceeded
by actual State heat input in a recent year for seven jurisdictions.
Thus, using this third alternative methodology would result in the same
number of jurisdictions exceeding their 2007 heat input projections in
a recent year as under EPA's methodology.\53\
---------------------------------------------------------------------------
\53\ As a conceptual matter, EPA considers this alternative less
reasonable than EPA's methodology because it calculates growth
between an actual year of heat input (1996) and a modeled year of
heat input. See section V.C.2 of this notice.
Table 18--States That in a Recent Year Have Exceeded 2007 Heat Input Under Different Projection Methods
----------------------------------------------------------------------------------------------------------------
OTAG growth Uniform growth 1996-2007
State EPA method rate rate growth rate
----------------------------------------------------------------------------------------------------------------
AL.......................................... Exceeded Exceeded Exceeded Exceeded
DC \54\..................................... Exceeded Exceeded Exceeded Exceeded
DE.......................................... ............... ............... ............... Exceeded
[[Page 21900]]
GA.......................................... Exceeded Exceeded Exceeded Exceeded
IL.......................................... Exceeded Exceeded Exceeded ...............
IN.......................................... ............... ............... ............... Exceeded
KY.......................................... ............... Exceeded ............... ...............
MD.......................................... ............... Exceeded Exceeded ...............
MI.......................................... ............... Exceeded ............... ...............
MO.......................................... Exceeded Exceeded Exceeded ...............
NC.......................................... ............... ............... ............... ...............
NJ.......................................... ............... ............... Exceeded ...............
NY.......................................... Exceeded Exceeded ............... Exceeded
OH.......................................... ............... ............... ............... Exceeded
PA.......................................... ............... ............... ............... ...............
SC.......................................... ............... ............... Exceeded ...............
TN.......................................... ............... ............... ............... ...............
VA.......................................... ............... ............... Exceeded ...............
WV.......................................... Exceeded Exceeded ............... ...............
----------------------------------------------------------------------------------------------------------------
\54\ EPA notes that the District of Columbia is unique in that it has only six units and so its heat input is
particularly variable.
Finally, some commenters suggested using more recent data to
develop 2007 heat input projections. One such approach continues to use
EPA's heat input growth rates, but applies them to the 2000 actual
State heat input data, instead of actual data representing the higher
of a State's 1995 or 1996 heat input. While EPA believes that it was
appropriate to use, to the extent feasible, the most up-to-date heat
input data available during the NOX SIP Call and Section 126
rulemakings in order to project 2007 heat input, the 2000 heat input
data that the commenter suggests using became available in 2001 and
was, obviously, not available when EPA issued the NOX SIP
Call (1998), the Section 126 Rule (1999), and the Technical Amendments
(2000). EPA believes that the Agency cannot reasonably be required to
modify the heat input growth rate projections or other aspects of the
NOX SIP Call and Section 126 Rule simply to use future data
that inevitably becomes available with the passage of time. Requiring
EPA to do so would be a prescription for endless rulemaking.
Moreover, in this case, the data involved, i.e., State heat input,
are quite variable from year to year. It therefore seems likely that,
as subsequent years of actual State heat input data become available,
some of the States' heat input may increase in one particular year more
rapidly than reflected in the heat input growth rates and result in
heat input for that year exceeding the new 2007 heat input projections
under this fourth alternative methodology. The fact is that, as the
latest year of actual State heat input data advances, the set of States
with current, actual heat input exceeding 2007 projected heat input may
well change. As discussed above, this already occurred during 1998-
2001, when the set of States with current, actual heat input exceeding
or close to 2007 projected heat input changed somewhat almost every
year. EPA believes that this demonstrates both that the exceedance in a
particular year of a State's 2007 heat input projection does not make
the projection unreasonable and that commenters failed to demonstrate
that EPA's heat input growth methodology is unreasonable.
E. Procedural Issues
As a procedural matter, EPA is responding in today's notice to the
Court's remand in the Section 126 and the Technical Amendments cases of
the heat input growth rate issue by providing a clearer explanation of
the Agency's methodology. Before issuing today's notice, EPA outlined
its proposed response in a notice in the Federal Register, i.e., the
August 3, 2001 NODA (66 FR 40609-16). In that NODA, EPA relied largely
on the existing record, but also pointed to new information that EPA
placed in the docket at that time. EPA received some 30 comments on the
NODA. EPA then developed additional new information and placed that in
the docket through a second NODA dated March 11, 2002 (67 FR 10844-45).
In the March 11, 2002 NODA, EPA also noted that some additional
information might be put in the docket later. EPA did so at various
times after March 11, 2002.
Commenters raised several procedural issues concerning EPA's
response to the Court's remand of the heat input growth rate issue.
1. Notice-and-Comment Rulemaking
Commenters stated that EPA was required to have completed today's
response to the Court's remand through notice-and-comment rulemaking.
EPA believes that its procedure is appropriate for today's response
to the Court's remand. The response to remand does not entail
promulgation of a new or revised rule reflecting new or revised heat
input growth rates. Rather, it involves a clearer explanation, based on
the existing record and confirmed by supplemental information, of the
same heat input growth rates that EPA previously used in the
NOX SIP Call, the Section 126 Rule, and the Technical
Amendments. Under these circumstances, notice-and-comment rulemaking is
not required. See generally National Grain & Feed Ass'n, Inc. v. OSHA,
903 F.2d 308 (5th Cir., 1990).
A notice-and-comment rulemaking would have been appropriate had the
Court vacated the rulemaking with respect to the heat input growth rate
issue, but the Court did not do so in either the Section 126 Decision
or the Technical Amendments Decision. Indeed, in the Section 126 case,
the Court denied a post-decision procedural motion specifically
requesting such a vacatur.
In any event, as a practical matter, an opportunity to comment was
afforded interested parties. By the August 3, 2001 NODA, EPA placed in
the docket additional factual information that it compiled in the
course of responding to the remand, and EPA allowed a 30-day comment
period on that additional information. Many parties commented, and EPA
has responded to those comments in today's notice. The August
[[Page 21901]]
3, 2001 NODA also outlined EPA's preliminary explanation in response to
the remand, interested parties commented on that explanation, and EPA
responded. Further, by the March 11, 2002 NODA, EPA again placed
additional factual information compiled in the course of responding to
the remand. As discussed above, two comments were submitted questioning
whether there was time for submission of comments on the new
information and questioning how the new data related to the response to
remand. EPA thereafter explained to the commenters and the public the
relevance of the documents and stated that the Agency would delay
issuance of the final response to the remands until on or about April
17, 2001 and would consider timely submitted comments. EPA also
received a third comment stating that the data referenced in the March
11, 2002 NODA were highly germane and supported EPA's heat input growth
rate methodology.
A commenter claimed that section 307(d)(1) of the CAA requires that
EPA provide a comment period and hold a hearing on its response to the
remand. EPA disagrees.
Paragraph (1) of subsection (d) of section 307 provides that the
procedural requirements found in subsection (d) apply to the items
listed in subparagraphs (A) through (U). Each of these items refers to
the ``promulgation'' (and, in almost all cases, the ``revision'') of a
regulation or requirement under a provision of the CAA, except for
subparagraph (N), which refers to an ``action of the Administrator
under section 126,'' and subparagraph (U), which is a catch-all
category that refers to ``such other actions as the Administrator may
determine.'' EPA believes that the term ``action'' in subparagraph (N)
is intended to cover both a grant or denial of a request for a finding
under section 126(b), as well as a rulemaking establishing compliance
requirements under section 126(c).
However, EPA does not believe that term should be read so broadly
as to include today's response to the remand. Reading the term
``action'' so broadly would require that every remand response
involving section 126 meet the procedural requirements of section
307(d), while a remand response involving any other provision
referenced in section 307(d)(1) would not have to meet such
requirements so long as the response was not a ``promulgation'' or
``revision'' of a regulation. EPA considers such a unique result for
section 126 to be anomalous and therefore rejects that interpretation
of the term ``action'' in section 307(d)(1)(N).
EPA also notes that, in today's response, the Agency is not taking
any ``action'' under section 126.\55\ Rather, EPA is simply explaining
more clearly the basis for the ``action'' that it took in the section
126 Rule issued in January 2000, i.e., the final rulemaking that
established compliance requirements, including State NOX
budgets for EGUs.
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\55\ Under Federal Register drafting requirements, EPA must have
an ``Action'' caption in every document published in the Federal
Register. The use of caption at the beginning of today's notice does
not make the notice an ``action'' under Section 307(d)(1)(N). The
``Action'' caption is required for all notices, including policy
statements and interpretations for which public notice and comment
and a public hearing are clearly not required.
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2. Petition to Reconsider
Some commenters requested that EPA should treat any of their
comments that EPA considered to be outside the scope of today's notice
as petitions to reconsider and that EPA should respond to such
petitions at the same time that it issues today's notice. Because EPA
is responding on the merits to the comments submitted by these
commenters, this request is moot.\56\
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\56\ One of these commenters argued that EPA should remove any
limit on the size of the Compliance Supplement Pool, which is a pool
of extra allowances established by EPA for each State for use in the
first 2 years of the NOX SIP Call and the section 126
Rule by sources that may not be able to install NOX
emissions in time. Not only is this claim outside the scope of this
notice, but also the Court has already ruled on and upheld EPA's
imposition of the cap on the Compliance Supplement Pool. See
Michigan v. EPA, 213 F.3d at 694.
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However, as discussed in section V.D.8 of this notice, a few
comments by some other commenters are outside the scope of the remand
and of today's response to remand. EPA does not regard the
reconsideration request to apply to these comments.
List of Subjects
40 CFR Part 51
Environmental protection, Administrative practice and procedure,
Air pollution control, Intergovernmental relations, Ozone, Reporting
and recordkeeping requirements.
40 CFR Part 52
Air pollution control, Ozone, Reporting and recordkeeping
requirements.
40 CFR Part 96
Administrative practice and procedure, Air pollution control,
Nitrogen oxides, Ozone, Reporting and recordkeeping requirements.
40 CFR Part 97
Administrative practice and procedure, Air pollution control,
Intergovernmental relations, Nitrogen oxides, Ozone, Reporting and
recordkeeping requirements.
Dated: April 23, 2002.
Christine T. Whitman,
Administrator.
[FR Doc. 02-10404 Filed 4-30-02; 8:45 am]
BILLING CODE 6560-50-P