20171114Hausman Direct - Redacted.pdf

RECETVED
2tt1S0Y lt+ P6 q: 16
SI ERRA
CLUB
,rirlrtf#Jffih\8*'o*
November 14,2Ol7
Via Hand Delivery and U.S. Mail
Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
427 W. Washington St.
Boise,ID 83702-5983
diane.holt @ puc.idaho.gov
Re: Case Nos. AVU-E-17-01/AVU-G-17-01: Direct Testimony of E;zra D. Hausman, Ph.D.
on Behalf of Sierra Club
Please find enclosed the Direct Testimony of Ezra D. Hausman, Ph.D. on Behalf of Sierra Club
in the above mentioned case. The public version of this document was hand delivered and
served upon all party representatives for this proceeding via e-mail. The confidential portion of
this document was hand delivered and served upon all eligible party representatives via U.S.
Mail.
Please do not hesitate to contact me if you have any questions or need other materials. Thank
you.
Sincerely
/s/ Alexa Zimbalist
Alexa Zimbalist
Legal Assistant
Sierra Club Environmental Law Program
2101 Webster Street, Suite 1300
Oakland, CA946l2
Phone: [phone]
alexa.zimbalist @ sierraclub.org
{
CERTIFICATE OF SERVICE
I hereby certify that on this 14th day of November 2Ol7,I delivered true and correct
copies of the foregoing DIRECT TESTIMONY OF EZRA D. HAUSMAN, PH.D. ON BEHALF
OF SIERRA CLUB to the following persons via the method of service noted. The public version
of this document was served upon parties via email, and the confidential portion of this
document was served upon all eligible party representatives via U.S. Mail or FedEx.
Hand Delivery:
Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
427 W. Washington St.
Boise, ID 83702-5983
diane.holt @ puc. idaho. gov
(Original and eight copies provided)
Email:
David J. Meyer (C)
Vice President & Chief Counsel, Reg. & Gov't
Affairs
Avista Corporation
PO Box3727
l4l1 East Mission Avenue
Spokane, WA99220-3727
david. meyer@ av istacorp.com
Peter J. Richardson (C)
Gregory M. Adams (C)
Richardson Adams PLLC
515 N.27th Street
P0 Box 7218
Boise. lD 83702
peterrichardsonadams.com
greg @ richardsonadams.com
Carol Haugen (C)
601 W. Riverside Avenue, Suite I100
Spokane, WA 99201
carol.haugen @ clearwaterpaper.com
Marvin Lewallen (C)
MA Lewallen & Associates, LLC
7408 SW Mapleleaf St.
Portland, OR97223
[e-mail]
Kelly Norwood
Vice President - State & Federal Regulation
Avista Utilities
POBox3727
l4l I East Mission Avenue
Spokane, W499220-3727
kel ly. norwood @ avistacorp.com
Dr. Don Reading (C)
6070 Hill Road
Boise, ID 83703
dreadin g @ mindspring.com
Brad M. Purdy
Attorney at Law
2019 N. 17ft Street
Boise, lD 83702
[e-mail]
{
'
Nathan Smith (C)
803 Mill Road
Lewiston, ID 83501
nathan. smith @ c learwaterpaper.com
j ohn.jacobs @ clearwaterpaper.com
david. wrn @ clearwaterpaper. com
Matthew A. Nykiel
Idaho Conservation League
PO Box 2308
102 S. Euclid #207
Sandpoint, ID 83864
mnykiel @ idahoconservation. org
Dean J. Miller
36208 Warm Springs Ave.
Boise, ID 83716
deanj miller@ cableone.net
Benjamin J. Otto
Idaho Conservation League
710 N 6'h Street
Boise, ID 83701
botto @ idahoconservation.org
Dated this l4th day of November, 2017
Ronald L. Williams
Williams Bradbury, P.C.
PO Box 338
Boise,ID 83701
ron @ williamsbradbury.com
Larry A. Crowley, Director
The Energy Strategies Institute, Inc
5549 S. Cliffsedge Ave.
Boise,ID 83716
[e-mail]
Brandon Karpen (C)
Deputy Attorney General
Idaho Public Utilities Commission
47 2West Washington Street
Boise,ID 83702
/s/ Alexa Zimbalist
Alexa Zimbalist
Legal Assistant
Sierra Club Environmental Law Program
2101 Webster St., Suite 1300
Oakland, CA94612
Phone: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION DBA AVTSTA
UTILITIES FOR AUTHORITY TO
INCREASE ITS RATES AND CHARGES FOR
ELECTRIC AND NATURAL GAS SERVICE
IN IDAHO
CASE NOS. AVU-E-17-01
AVU-G-17-01
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DIRECT TESTIMONY OF
EZRA D. HAUSMAN, PH.D.
ON BEHALF OF SIERRA CLUB
REDACTED
November 14,2017
Table of Contents
I. Professional Qualifications and Purpose of Testimony
II. Capital Investments in Colstrip Units 3 and 4 Were lmprudent..
III. Useful Life for Colstrip Units 3 and 4
IV. Recommendations
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Exhibit List
Exhibit No. 601 Resume of Ezra D. Hausman, Ph.D
Exhibit No. 602 Avista's Responses to Sierra Club Production Requests 1-3, l-5,3-6
Supplemental2 and3-7
Exhibit No. 603 Avista's Confidential Response to Sierra Club Production Request l-4
Exhibit No. 604 Colstrip Business Plans 20 I 5 -20 19, 20 I 6-2020, 20 17 -202 1, Avista' s
Confidential Attachments A-C to Sierra Club Production Request l-3
Exhibit No. 605 Capital Project Authorization Forms, Avista's Confidential Attachment G
to Sierra Club Production Request 1-3 (excerpt)
Exhibit No. 606 Colstrip 3&4 Ownership and Operation Agreement, Avista's Confidential
Attachment A to Sierra Club Production Request 1-5 (excerpt)
Exhibit No. 607 Avista's Confidential Supplemental Attachment A to Sierra Club
Supplemental Production Request 3-6
Exhibit No. 608 Protection of Visibility: Amendments to Requirements for State Plans
(Final Rule), 82 Fed. Reg. 3078 (Jan. 10, 2Ol7) (excerpt)
Exhibit No. 609 Protection of Visibility: Amendments to Requirements for State Plans
(Proposed Rule), 81 Fed. Reg. 26942 (May 4,2016) (excerpt)
Exhibir No. 610 Approval and Promulgation of Implementation Plans; State of Montana;
State Implementation Plan and Regional Haze Federal Implementation
Plan,JT Fed. Reg. 51864 (Sep. 18, 2012) (excerpt)
Exhibit No. 611 Montana Department of Environmental Quality, "Regional Haze S-Year
Progress Report," August 2017, Chapter 2 (excerpt)
Exhibit No. 612 Washington Utilities and Transportation Commission Dockets UE-
I 70033ruG - fl 0034, Initial Post-Settlement-Hearing Brief of the State of
Montana in Support of the Proposed Multiparty Settlement Stipulation and
Agreement (Oct. 18, 2017) (excerpt)
Exhibit No. 613 Portland General Electric Tariff Schedule 146 - Colstrip Power Plant
Operating Life Adjustment
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Professional Oualifications and Purpose of Testimonv
Please state your name, occupation, and business address.
My name is Ezra D. Hausman, Ph.D. I am an independent consultant doing
business asEzra Hausman Consulting, operating from offices at77 Kaposia Street,
Auburndale, Massachusetts 02466.
Are you providing any exhibits with your testimony?
Yes. I am sponsoring Exhibit Nos. 601-613.
What is your educational and professional background?
I hold a BA in Psychology from Wesleyan University, an MS in Environmental
Engineering from Tufts University, an SM in Applied Physics from Harvard
University, and a PhD in Atmospheric Chemistry from Harvard University. I have
been involved in analysis of both regulated and restructured electricity markets
for approximately 20 years.
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t4 I have worked as an independent consultant and expert based on my expertise and
experience in energy economics and environmental science since 2014. From
2005 until early 2014, I was employed at Synapse Energy Economics, Inc., a
research and consulting company located in Cambridge, Massachusetts, where I
served most recently as Vice President and Chief Operating Officer. From 1998
through 2OO4l served as a Senior Associate at Tabors Caramanis and Associates
(TCA) of Cambridge, Massachusetts. ln 2004, TCA was acquired by Charles
River Associates (CRA), where I remained until 2005.
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I provide expert consulting services in several areas relating to energy markets
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and energy market regulation on the state, regional, and federal levels; energy
dispatch and planning modeling, quantification of the economic and
environmental benefits of displaced emissions; and treatment of energy efficiency
and renewable energy in electricity and capacity markets. I have provided
testimony and./or appeared before public utility commissions or legislative
committees in Arizona, Illinois, Iowa, Kansas, Louisiana, Maryland,
Massachusetts, Minnesota, Mississippi, Missouri, New Hampshire, New Jersey,
Nevada, South Dakota, Vermont, and Washington State, as well as at the federal
level. I have also provided expert representation for stakeholders at the PJM ISO,
the California ISO, the Midwest ISO, and at the FERC. While most of my
testimony and analytical work has centered on issues concerning electricity
market economics, I have also brought my expertise as a scientist to bear on cases
involving energy efficiency programs and greenhouse gas regulation and
mitigation in the electric sector.
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l5 I have provided a detailed resume as Exhibit No. 601
16 a. Have you previously testified before the Idaho Public Utilities Commission?
t] A. No.
l8 O. What is the purpose of your testimony in this proceeding?
l9 A. My testimony is provided in response to both the initial filing by Avista
20 Corporation ("Avista" or "Company") and the proposed multiparty Stipulation
2l and Settlement filed with the Commission on October 20,2017 ("Settlement
Agreement"), I address three issues of relevance to this proceeding concerning the
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treatment of Avista's shares of Units 3 and 4 of the Colstrip coal-fired electric
generating plant in eastern Montana:
1) Avista approved capital expenditures totaling $3,040,933 (Avista's share) to
install Smartburn controls for emissions of nitrogen oxides ("NOx") as part of
the Colstrip capital budgets in2015-2017. These capital expenditures at
Colstrip were unnecessary and imprudent. The Smartburn projects are not
required for any reliability, economic, or regulatory purpose, were the result
of poor oversight and management by Avista, and did not result in a
significant reduction in NOx emissions at the units. ldaho ratepayers should
not be responsible for these unnecessary and imprudent expenditures.
2) Avista's review process for capital projects at Colstrip Units 3 and 4 is
fundamentally flawed. Of relevance to this proceeding, Avista provided only a
cursory explanation for over $24 million in capital spending at Colstrip that it
is seeking to include in rate base. Avista also included in rate base in a prior
proceeding capital expenditures for projects that were not in service at the
time the relevant rates went into effect.
3) Avista is using an unrealistic end-of-life date for the Colstrip units for
depreciation purposes, leading to the likelihood of stranded assets and/or
intergenerational inequities in the future.
Is the Settlement Agreement as currently proposed in the public interest?
No. The Settlement Agreement is not in the public interest because it fails to
remove from rate base capital spending at Colstrip Units 3 and 4 that was
unnecessary and imprudent. Although Sierra Club supports the efforts of parties
to reach a settlement agreement on the majority of issues presented in the rate
case, it is not in the public interest to condone Avista's lax oversight and poor
management of capital spending at the Colstrip coal plant in Montana. Unless
those practices are addressed and remedied, Idaho ratepayers will be compelled to
pay for those imprudent capital expenditures for years to come, and they will be at
risk of continued imprudent spending on a coal plant that is nearing the end of its
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useful life.
What are your recommendations for the Commission in this case?
I recommend that the Commission either reject the stipulation or condition its
approval on the Parties' acceptance of the following:
1) A finding by the Commission that Smartburn NOx controls installed on
Colstrip Units 3 and 4 were unnecessary and imprudent. The Commission
should make the following adjustments to Avista's rate base pursuant to
this finding:
a. Remove $1,047,417 from Avista's rate base on a going-forward
basis for costs associated with the Smartburn installation on
Colstrip Unit 3. There was no economic or regulatory benefit from
this capital expenditure, and Idaho ratepayers should not be
required to pay for it. Moreover, based on the first months of
available emissions data, there appears to be little or no
environmental benefit from the project.
b. Remove $1,993,516 from Avista's rate base on a going-forward
basis for costs associated with the Smartburn installation on
Colstrip Unit 4, and included in rate base in its prior rate case in
Case No. AVU-E-16-03. The Unit 4 Smartburn project should be
removed because, as with the Smartburn controls on Unit 3, there
was no economic or regulatory benefit from the capital expenditure,
and little if any environmental benefit. Furthermore, based on the
record in this proceeding, this figure appears to have included at
least a portion of the spending on the project at Unit 3, which was
not yet used and useful when rates from Case No. AVU-E-16-03
went into effect on January 1,2017.
2) Direction to Avista to adopt and exercise more rigorous review and
approval procedures for future capital expenditures at Colstrip Units 3 and
4. As Colstrip nears the end of its useful life, I recommend that the
Commission guard against unnecessary or imprudent spending at Colstrip
by requiring Avista to thoroughly review and justify any and all capital
projects that increase the plant balance. The Commission should make
clear that the company can no longer take a passive role with respect to
capital investment decisions in these units, and cannot assume that this
Commission will simply rubber-stamp decisions of the Colstrip Owner's
Committee without proof that Avista is making its best efforts to act in the
interests of Idaho ratepayers.
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3) If the Settlement Agreement is rejected, either by the Commission or after
modification by the settling parties such that this proceeding returns to
litigation, I recommend that the Commission hold open this rate case and
consolidate the proceeding with Avista's next depreciation filing. Avista
should have included in this proceeding updated end-of-life assumptions
for Colstrip Units 3 and 4 that reflect the realities of today's coal and
electric industry economics, and the likelihood of future carbon constraints
that will adversely or fatally impact coal plants such as Colstrip.
4) If the Commission accepts the Settlement Agreement, the Commission
should make clear that nothing in this proceeding precludes further
adjustments to rates pursuant to Avista's upcoming depreciation filing.
Are you recommending a change to the revenue requirement proposed by
the Settlement Agreement?
No. While the changes to rate base that I recommend would normally flow
through to reduce annual revenue requirement, I am not recommending a change
to revenue requirements or rates in this proceeding. Settlement agreements
necessarily represent a compromise among the parties. The majority of issues
included in the Settlement Agreement have nothing to do with Colstrip, and
therefore I hesitate to disturb a revenue requirement agreement that reflects a
balance among the interests of a diverse group of stakeholders.
However, allowing Avista to include its imprudent Colstrip expenditures in rate
base would have a much longer-lasting detrimental impact on Idaho ratepayers. [f
left unchallenged, Avista's wasteful spending on capital projects at Colstrip will
stay on the books for years. Implicitly approving those imprudent actions by
unconditionally accepting the Settlement Agreement would be against the public
interest because it would condone behavior that puts ratepayers at risk of further
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imprudent spending. The Commission need not disturb the annual revenue
requirement agreed upon in the Settlement Agreement, but it should require
Avista to remove the outstanding cost of Smartburn at both Colstrip units from
rate base for purposes ofall future proceedings.
Capital Investments in Colstrip Units 3 and 4 Were Imprudent
Please describe the capital expenditures at Colstrip Units 3 and 4 that are at
issue in the current rate case.
Avista's application included a total of $24.29 million for capital additions at
Colstrip for years 2Ol7-2Ol9.r In the Settlement Agreement, according to Staff,
all of the capital additions budgeted for 2019 and "most" of the proposed
additions in 2018 were removed.2 In addition, Avista requested to add $1,04'l,4ll
to rate base for recovery of its share of the cost of installing Smartburn technology
on Colstrip Unit 3 that went into service in June 20fi.3
Does your testimony address other capital projects at Colstrip that were not
included in the Company's current filing?
Yes. In Avista's previous general rate case (Case No. AVU-E-16-03), Avista
sought approval to include $1,993,516 million in rate base for Smartburn
technology on Colstrip Unit 4.4 That case was resolved in a settlement, and the
merits of specific capital investments were never adjudicated or deemed prudent
I Direct Testimony of Scott J. Kinney at p.31.
2 Direct Testimony of Randy Lobb at p.10.
3 Avista Response to SC PR 3-7(b), Exhibit No. 602, page 8 of 8.
a Avista Response to SC PR 3-6(b), Exhibit No. 602, page 5 of 8.
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I by the Commission. However, these past expendihrres in 2015 and 2016 on
Smartbrun projects at Colstrip Urdt 4 suffer from the same deficiencies as the
later investurent at Unit 3.
What are the Smartburn capital projects that you are challenging in this
proceeding?
Colstrip, like all coal-fu'ed power plants, emits pollution that is harmftrl to public
health and the environment. Smartburn is a fonn of emissions control teclurology
irxtalled by the Colstrip owners between 2015 and 2017 onColskip Units 4 and 3
that purportedly would teduce the emission of oxides of nitogen. co--only
referred to as "NOx", which is harmful to human health arrd causes visibility
impainnents in the environment. Smartburn is a far less effective, but also less
expensive, means of reducing NOx emissions than installing Selective Catalytic
Reduction ("SCR").
W'hen were the Smartburn controls completed at Colstrip Units 3 and 4?
According to Avista's responses to Sierra Club's production requests, the
installation of Smartburn on Unit 4 was completed on June 30, 2016, and on Unit
3 on Jrme 30,20n.5
How much did the Smartburn projects cost?
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'Avista Response to SC PR 3-6(b) and 3-7O), Exhibit No. 602, pages 5 and 8 of 8.
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basis at Units 4 and 3, respectively.6 Avista's share for these two projects totaled
$3"040,933, "not including any overheads [sic] incurred by Avista."7
When were these costs incurred?
The following confidential table shows the annual expenditures on each
Smartbrun project, according to the 2016 Capital h"oject Authorization forms
provided by Avista during discovery.
ConIid@ Cqsh Flow for Smartburn Capital Proiects at
Unit 4
Smartburn
These two projects are summalized in Confidential Exhibit No. 605, which is
extracted from Confidential Attachrnent G to Avista's response to Sierra Club
Production Request I-3.
How much of the capital expenditure is Avista claiming in this rate case?
It appears that Avista is only claiming its share of the final year {2A17) of capital
spending for Smartburn at Unit 3 ($1,047,417).8 In its previotrs rate case, Case No.
AVU-E-16-03 Avista included nearly hro-thirds of its slmre of the total Smarbum
spending forbothunits, or ($1,993,516).e Because The Smartburn controls at
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6 SC PR l-3C, Confidential Attachment c, p. 4l and 50 of 74. Exhibit No. 605.
' Arri*t Response to SC PR 3-6(b), Exhibit No. 602. page 5 of 8.
8 Arirt" Resporxe to SC PR 3-7(b). Exhibit No. 602. page 8 of 8.
' Arirta Response to SC PR 3-6(b) aud 3-7O). Exhibit No. 602, pages 5 and 8 of 8 (strowing that Avista
included 66%o of total Smartburn expendihues in its 2016 rate case. and 34o/o in the current 2017 rate case).
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Unit 3
Smartburn I I I20152016 2017
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Units 3 and 4 should cost roughly the same amount, this suggests that Avista
included a portion of spending on Unit 3 Smartburn in rates beginning January 1,
2Ol7 . As noted above, the Unit 3 Smartburn did not go into service until June
2017; thus it appears Avista was charging ratepayers for this project before it
went into service.
Were the Colstrip owners required to install these projects?
No. The projects appear to be completely unnecessary. There were and are no
regulatory or statutory compliance obligations that required Colstrip Units 3 and 4
to reduce emissions of NOx in 2016 and2OlT . There is no evidence provided by
Avista in this docket that these projects improved the economics or production
capabilities of Colstrip Units 3 and 4. Finally, the emissions data from Colstrip
show that there has been almost no change in the average emissions of NOx from
either unit since the installation of the Smartburn controls.
What was the Company's justification for these two projects?
Sierra Club specifically asked Avista in discovery the following question about
Smartburn controls for each of Unit 3 and Unit 4: "Please provide a narrative
description of what Avista understands its regulatory obligations are today that
necessitate the installation of [Smartburn NOx controls], including but not limited
to compliance deadlines and emissions limit."l0In response to Sierra Club's data
request, Avista provided only a vague and cursory justification for the Smartburn
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r0 Avista Response to SC PR 3-6(h) and 3-7(d), Exhibit No. 602, pages 5-6 and 8 of 8
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projects. Avista did not include any specific compliance deadlines, nor did it
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include any specific NOx emission limits that Colstrip Units 3 or 4 were required
to meet.
Instead, Avista included a general description of the Regional Haze Program,
which is a regulation under the federal Clean Air Act that is intended to eliminate
man-made visibility degradation in Class I areas by the year 2O64.t ' Ho*erer, as
discussed in more detail below, there are no enforceable current or planned
compliance obligations under the RegionalHaze Rule that are applicable to
Colstrip Units 3 and 4.
Along with this general reference to the Regional Haze Program, Avista provided
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the following explanation
Anticipating that Colstrip Units 3 & 4 could be ordered to install Selective
Catalytic Reduction (SCR) during the 2017 review period, the Colstrip
Owners' proactively installed the Smart Burn technology to reduce the
formation of Nitrous Oxides (NOx) in combustion zone for two major benefits:
o Make proactive and verifiable NOx reductions ando Optimize the size, scope and ammonia use of any future SCR
installation.t2
Avista also provided several documents as attachments pertaining to various
unrelated rules and actions dating back to 20ll. Avista then supplemented its
response on October 26,3oll (nearly seven weeks after the original discovery
" Avista's response included a reference to emissions limitations and pollution controls for Colstrip Units I
and 2 from a September 18,2012 Final Implementation Plan (FIP) finalized by EPA. However, Avista does
not own any portion of Units 1 and2, and those units are not at issue in this proceeding.
'' Avista Response to SC PR 3-6(d), Exhibit No. 602, page 6 of 8.
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request and after the Settlement Agreement was filed) to include a series of
confidential emails between Avista employees and other Colstrip o*ners.''
Is Avista's explanation reasonable?
No. Avista's narrative response suggests that the controls were installed
proactively because Colstrip 3 & 4 could be required as part of the Regional Haze
Program to install a different and much more expensive and more effective type
of pollution control -SCR - at some point in the future. However, there is no
discussion or explanation as to why or how installing Smartburn tn2016 and20ll
was required. Even if Smartburn-like technology can help to "optimize the size,
scope and ammonia use of any future SCR installation" as Avista suggests, it is
clearly imprudent to make that investment up to a decade before SCR rncy be
required.
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for Smartburn controls is that the Colstrip owners believed that somehow
installing Smartburn controls in 2016 and2OlT could help avoid the requirement
for more effective and expensive controls sometime in the next decade. If this was
the strategy Avista and the other owners relied on, it is unlikely to be successful,
as the discussion below of regulatory actions related to the "Reasonable Progress"
phase of the Regional Haze Rule will demonstrate. lnstalling the Smartburn
controls today is unlikely to have any material impact on any future compliance
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't SC PR 3-6C, Supplemental Confidential Attachment A, Exhibit No. 607
I obligations at Colstrip Units 3 and 4.
Absent any evidence or support for the Smartburn capital projects at Colstrip
Units 3 and 4, the Commission must conclude that these discretionary
expenditures were imprudent and remove these costs from rate base. Even if the
Commission finds that speculating on future regulatory actions was a reasonable
use of ratepayer money, the actual environmental data coming from Colstrip Units
3 and 4 show that the controls have thus far been largely, and predictably,
ineffective at reducing NOx emissions.
The Smartburn Proiects Were Sienificant Discretionarv Capital Proiects
that Were Not Required to Meet anv Existins Compliance Oblisation
How did Avista describe the Smartburn projects in its filing to the ldaho
Public Utilities Commission?
Avista did not specifically identify the Smartburn projects in its application or
testimony in this proceeding. Instead, it appears that Avista lumped the Smartburn
projects in with other capital spending at Colstrip that it describes as "ongoing
capital expenditures associated with normal outage activities on Units 3 & 4 at
Colstrip."la Avista described these costs as "mandatory and compliance" capital
projects, including "Environmental Must-Do", a category that that "typically includes
projects done for compliance with laws, rules, and contract requirements that are
external to the Company (e.g. State and Federal laws, Settlement Agreements, FERC,
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NERC, and FCC rules, and Commission Orders, etc.)."rs
Mr. Kinney's direct testimony stated that additional details can be found in
Exhibit No.4, Schedule 3.16 Did you review that exhibit?
Yes. In Exhibit No. 4 at Schedule 3, page 90 of 180, Mr. Kinney provided only a
three page "Business Case Justification Narrative" addressing all capital spending
at Colstrip Units 3 and 4 for the years 2017 through 2019. The Business Case
Justification stated that "Colstrip Capital is required as part of ongoing operations
of the facility."lT That same document included four categories of project: (1)
ENVMD- Environmental Must Do, (2) Sustenance, (3) Regulatory, (4) Reliability
Must Do.
In your opinion, would you characterize the Smartburn projects as required
"Mandatory and Compliance" projects or "Environmental Must Do"
projects?
Neither. I would describe them as discretionary and ineffective, and at best
premature. As discussed in detail below, there was and still is no legal compliance
obligation that required Colstrip Units 3 or 4 to reduce NOx in 2016 or 2017, or
any future date. The projects should therefore not be considered "Mandatory and
Compliance" or "Environmental Must Do" projects and instead should be
evaluated as discretionary projects. As such, Avista should have been required to
demonstrate that investing the substantial capital resources in Colstrip was
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'5 Kinney Direct Testimony at p.30.
'6 Kinney Direct Testimony at p.31.
'' Kinney, Exhibit No.4, Schedule 3, page 90 of 180.
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Sierra Club
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somehow in the interests of ratepayers, or should have exercised its right as a
participating owner to object to the project and attempt to have it removed from
the capital spending plan.
a. Avista's Exhibit No. 4, Schedule 3 stated that discretionary items are
reviewed by Talen (the plant operator) in a hurdle rate analysis.ls Was a
hurdle rate analysis completed for the Smartburn controls?
A. I ,n response to Sierra Club's production request l-3, Avista provided
numerous "Capital Project Authorization Forms" for individual projects. !
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13 a.Compared to other capital projects, how significant were the Smartburn
control projects?
The Smartburn controls represented a significant portion of the capital outlays for
Colstrip in 2015, 2016 and 2017. The following table shows the annual cash flow
for Smartburn at Colstrip compared to the total projected capital costs at Colstrip
Units 3 and 4, according to the business plan provided by Avista, for each of the
years 201 5, 2016, and 2017 .
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't Kinney, Exhibit No. 4, Schedule 3, page 9l of 180.
'' SC PR l-3C, Confidential Attachment G, p. 4l and 50 of 74, Exhibit No. 605
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Sierra Club
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J As can be seer in Table 2, Smartburn accounted for! tof of total
projected CapEx at Colship Units 3 and 4 for each of the years 2015, 2016, and
2017.
\trhat is the Regional llaze Rule referenced by Altsta and how does it affect
Colstrip Units 3 and 4?
Congress established "as a national goal the prevention of any ftlhre, and the
remedying of any existirrg, impairment of visibility in mandatory class I Federal
areas which impairment results from uranmade air pollution." 42 U.S,C. $
Tael(a)(1).
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12 In 1990, after finding that the U.S. Envilonmental Protection Agency ("EPA") and
the states had not made adequate progress toward reducing visibility impaimreut
in the nation's Class I ar"as,22 Congress amended the Clean Ail Act to curb
emissions that may reasonably be anticipated to cause or contribute to visibility
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'o SC PR l-3C, Confrdential Attachrnents A{. Exhibit No. 604. Values shown are for the frst year of each
capital expenditure plan.2' See T"bl" I Above. Data from SC PR l-3C. Coafidential Attacbment G, p. 4l and 50 of 74. Exhibit No.
605.t'Area. desipated as mandatory Class I Federal areas (or Class I for short) consist of national parks
exceeding 6.000 acres, national wildemess areas and national memorial parks exceeding 5,000 acres. aud
all intemational parks that were in existence on August 7, 1977. See 42 U.S.C. $ 7a72@).
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Siena Club
Total 3&4
2015 2016 2017 Total
Confidential Table 2: Smartburn Cash FIow as a Percentage of Total
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impairment at national parks and wilderness areas. Id. 5 7492.
Congress delegated implementation of the Clean Air Act's visibility program to
EPA. In 1999, EPA promulgated the RegionalHaze Rule, which requires the
states to make incremental, "Reasonable Progress" toward eliminating human-
caused visibility impairment at each Class I area by 2064.40 C.F.R. $
51.308(dX1), (d)(3). In the 1999 regulations, EPA recognized that visibility
impairing pollution was a regional problem that required regional solutions; the
regulations create the necessary region-wide scheme to restore Class I areas to
natural conditions. Furthermore, the regionalhaze regulations require evaluation
of all sources of visibility impairment.
In order to achieve the goal of natural visibility in Class I areas, individual states
are subject to implementation plans that must contain "emission limits, schedules
of compliance and other measures as may be necessary to make reasonable
progress toward the national goal." 42 U.S.C. $ 7491(bX2). The Regional Haze
Rule includes several interlocking measures designed to make "Reasonable
Progress" towards achieving natural visibility by 2064. These measures include
requirements to (1) develop Reasonable Progress goals based on the evaluation of
any and all sources contributing to visibility impairment; (2) determine baseline
and natural visibility conditions; (3) create a long-term strategy for compliance
with Reasonable Progress; and (4) implement the best available retrofit
technology (BART) for some of the oldest sources of haze-causing pollutanls. Id.',
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Sierra Club
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40 C.F.R. $ 51.308(d), (e).
What actions have the state and EPA taken to implement the Regional Haze
Rule in Montana?
On September 18, 2012, the EPA issued a final Federal Implementation Plan
("FIP")23 to address regional haze inMontana.2a Under the Regional Haze Rule,
Colstrip Units 1 and2 were required to undergo a BART analysis. Units built
after 1977 such as Colstrip Units 3 and 4 are not "BART eligible" units,2s but they
still fall under the Reasonable Progress requirement. The Montana FIP addressed
both the BART analysis at Colstrip Units I and2, and Montana's obligations
under Reasonable Progress that apply to Units 3 and 4.
What subsequent state or federal actions are necessary under the Regional
Haze Rule?
Under Reasonable Progress, states are required to report in five-year intervals that
they are making progress toward achieving natural visibility conditions by 2064.
ln developing these Reasonable Progress goals and the emission reductions
needed to meet them, the state must develop a long-term strategy that considers
four factors: (1) the costs of compliance, (2) the time necessary for compliance,
(3) the energy and non-air quality environmental impacts of compliance, and (4)
23 If a state fails to develop its own State Implementation Plan ("SIP"), the EPA develops a Federal
Implementation Plan.
'o 17 Fed. Reg. 57864 (Sep. 18, 2012), Exhibir No. 610.
" In response to Sierra Club PR 3-6(11, Avista provided two attachments (SC PR 3-6 A and B) that
purportedly discussed a "BART analysis" for Colstrip Units 3 and 4. That analysis was not actually
conducted under the Regional Haze Rule, but instead was part of a requirement in Colstrip Unit 3 and 4's
prevention of significant deteriorate ("PSD") permit.
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Sierra Club
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the remaining useful life of any potentially affected sources. 42 U.S.C. $
Taer@)(r); 40 C.F.R. $ 51.308(0(2Xi).
3 States are required to submit periodic plans demonstrating how they have and will
continue to make progress towards achieving their visibility improvement goals.
The first state plans were due in20O7 and covered the 2008-2018 planning
period.26 The second planning period covers 2018-2028. Prior to 2017, states
faced a requirement to submit comprehensive State Implementation Plan ("SlP")
revisions in 2018 to address the second planning period. However, a recent
Regional Haze Rule changed the deadline for states to submit their next
comprehensive Region alHaze Plan SIP revisions from 2018 to 202L " This
change gives states more time to submit comprehensive SIP revisions, but
otherwise the Reasonable Progress requirements remain the same, including the
2O28 enddate of the second planning period.28
Were any emissions reduction required at Colstrip Units 3 and 4 in 2016 or
2017 under the EPA's FIP implementing the Regional Haze Rule?
No. EPA's 2012 Montana FIP, which EPA issued because Montana declined to
issue a SIP in 2006, specifically concluded "not to require additional emission
controls on Colstrip Units 3 and 4 in the relevant planning period" (i.e. 2008-
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26 See,82 Fed. Reg.3078,3080 (Jan. 10,2017), Exhibit No. 608, page 3 of4.27 82Fed. Reg. 3078 at 3080 (Jan. 10,2017), Exhibir No.608, page 3 of 4.
28 See, Proposed Amendments to Requirements for State Plans, 8l Fed. Reg. 26942,26965 (May 4,2016),
Exhibit No. 609, page 3 of 5; see, also,82 Fed. Reg. 3078, 3080 (Jan. 1 0, 20 I 7), Exhibit No. 608, page 3 of
4 ("Other than the one-time change to the next due date for periodic comprehensive SIP revisions, no
change is being made for due dates for future periodic comprehensive SIP revisions").
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Sierra Club
I 2018) and that "[w]hether additional emission reductions from reasonable
progress sources, including Colstrip Units 3 and 4, are necessary will be re-
evaluated in subsequent planning periods."2e There was no compliance deadline
or emissions limit set, or any requirement for additional NOx controls at Colstrip
Units 3 or 4, for 2Ot6 or 2017 or any future year.
Did the State of Montana determine that Colstrip Units 3 and 4 were
required to install environmental retrofits under the Reasonable Progress
requirements for Montana?
No. The Montana Department of Environmental Quality (MDEQ) has concluded
that nothing further is required from Colstrip Units 3 and 4 during the current
evaluation period. In MDEQ's most recent "RegionalHaze 5-Year Progress
Report" in August 2Ol7 , Colstrip Units 3 and 4 are listed among Montana sources
"for which the Montana FIP analysis did not result in emission limits."3o The
report goes on to note that while Smartburn was installed on Colstrip units 3 and 4
in 2016 and207'7, this was done "in the absence of regulatory emission limits in
the Montana FIP."31
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1l Simply put, there was no federal or state requirement for the Colstrip owners to
l8 spend on NOx pollution controls between 2015 and 2017.
'n 'l'l Fed. Reg. 57864, 57902 (Sep. 18,z}l2),Exhibit No. 610, page 4 of 5.
30 Regional Haze 5-Year Progress Report, August 2017, atp.2-7, Exhibit No. 6l I (full report available at:
https://deq.mt.gov/Portals/l l2lPublic/PublicComment/Documents/RegionalHaze_ProgressReport-S-
2o17.pdf).
3t Id. at p.2-8.
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lQ.Have you seen evidence of when the Colstrip co-owners, including Avista,
believed Colstrip Units 3 and 4 might require upgrades to reduce NOx
emissions under the Reasonable Progress rule?
Yes. Avista itself acknowledged in its recently completed 2Ol7 IRP that the
Regional Haze Rule will not affect Colstrip Units 3 and 4 at this time. The IRP
states, "Colstrip Units 3 and 4 are not currently affected, although the units will be
evaluated for Reasonable Progress at the next review period in September 2011.
Avista does not anticipate any material impacts on Colstrip Units 3 and 4 at this
time."32
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However, Avista and other Colstrip owners do acknowledge that further controls
will likely be required in the next planning period - and have made statements
indicating that they expect SCR controls - not Smartburn - will be required in the
next planning period (2018-2028). For example, PacifiCorp's 2015 IRP included
an assumption that it will incur costs to install SCR at Colstrip 3 and 4 in2023
and2022, respectively.33 Portland General Electric's 2016 IRP assumed that SCR
would be required by 2027 in order to meet Reasonable Progress requirements.3a
Avista's ownZOll IRP base scenario assumed an SCR would be necessary in
32 Avista 2017 IRP atp.7-6 (available at: https://www.myavista.com/about-us/our-company/integrated-
resource-planning).
33 PacifiCorp 2015 IRP, Vol. l, footnote to Table 7.2 atp.l48: "Colstrip 3&4 SCR 2023t2022" is
"common to all scenarios".
https://www.pacificorp.com/content/dam/pacificorp/doc/Energy_Sources/Integrated_Resource_Plan/2Ol5l
RP/Pacifi Corp_20 I 5IRP-Vol I -MainDocument.pdf.
3a Portland General Electric 2016IRP, Ch.3, p.78 (available at: https://www.portlandgeneral.com/our-
company/energy-strategy/resource-planning/integrated-resource-planning).
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Sierra Club
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1 2A28; the Company also evaluated a sensitivity case with SCR in 2023.35
2 Avista provided a series of e-nuils on this topic in its confidential supplemental
response to Sierra Club Production Request 3-6. It is clear from these e-mails thatJ
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l0 a.Given this evidence, how would you characterize the decision by Avista and
the other Colstrip owners to install Smartburn technology at flnits 3 and 4?
It is clear from the record that the Smartbura installations on Units 3 and 4 were
elective, as they were not mandated by any federal or state law or nrle, and that
any investurert ir techlology to reduce NOx emissions at these urits in 2016 and
2017 was premature at best.
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Future Compliance Period.
18 a.Avista states that it "proactively installed Smart Burn technology" because it
"Anticipat[ed] that Colstrip Llnits 3 & 4 coultl be ordered to install Selectivet9
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Sierra Club
" Avista 2017 IRP atp.l}-? and l2-6.
'u SC PR 3-6C Supplemental Attachment A, Exhibit No. 607
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Catalytic Reduction (SCR) during the2017 review period..."3'Is this
approach reasonable?
No. Avista appears to be saying that it installed Smartburn in2O16-2017 in order
to avoid a possible future requirement to install SCR at some undefined date.
Avista provides no analysis whatsoever showing that gambling over $3 million in
ratepayer money on this risky and speculative "pre-compliance" strategy is likely
to pay off. If this was indeed Avista's strategy, it is a poor one because the
Smartburn controls are unlikely to have any material impact on the ultimate
control technology that will be required at Colstrip Units 3 and 4.
Why do you conclude that installing Smartburn is unlikely to avoid a future
SCR requirement?
Avista, Talen, and the other co-owners should have known that Smartburn would
not be an effective way to achieve meaningful reductions in NOx emissions at
Units 3 and 4. Both general industry experience3s and Talen's own experience at
Colstrip Unit2, demonstrate that in the absence of SCR, Smartburn technology is
capable of achievinB NO* emission levels of 0.15 lbs/IVIMBtu. This is very close
to the levels that were already being achieved at Colstrip Units 3 and 4.
As seen tn Figure 1, there was only a very small reduction in the emission rate at
each unit, if any, after the in-service date for Smartburn at Unit 4 (June 30, 2016)
" sc PR 3-6(d), Exhibit No. 602, pages 5-6 of 8.
38 See, for example, Power Engineering, 2003, "Combustion Control Techniques Achieve 0.15 lb/lvlMBtu
NO, Levels Without SCR." Available at http://www.power-eng.com/articles/prinUvolume-107/issue-
l/f'eatures/combustion-control-techniques-achieve-015-lb-mmbtu-nosubx-sub-levels-without-scr html.
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Sierra Club
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and Unit 3 (June 30,2Ol1). Prior to the installation of Smartburn, both Units 3
and 4 were averaging about 0.16 lbs NOx/mmbtu. After installing Smartburn,
based on the data available thus far, the average rate dropped to about 0.15 lbs
NOx/mmbtu.
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Sierra Club
Unit 3 NOx Emissions
0.20
0.18
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0.12
0.10
0"08
0.06
0.04
0.02
0.00
)
6
=:
€
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,.oX4"o1d,.p14*"i*t*{"1*"i*{sioiolsls,
Unit 4 NOx Emissions
0.20
0.18
0.16
0.14
0.12
0.to
0.08
0.o5
0,04
0.o2
0.@."Sk}*Mffit-$-Ft'
Ftgure l. NO* mrission rnte at Colstrip Units 3 (top) and 4 (bottom) before and after
installation of Smartbunt technologt. Shaded region is post-installation. Data
source; US EPA Air lularkets Program Data (AMPD)3e
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Sierra Club
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re Available at https://arrpd.epa.gor'/ampd/
1Q Does this decrease in emissions mean that Colstrip will be able to avoid
further NOx controls on these units?
No. The Smartburn controls achieved only a very small reduction in NOx
pollution from Colstrip Units 3 and 4, as shown in Figure,l. Other pollution
control technologies, such as SCR, are far more effective at reducing the amount
of NOx pollution from coal plants such as Colstrip. The EPA will determine at a
later date whether further NOx controls will be required on the units, and I have
seen no indication that Smartburn technology is an acceptable alternative to more
effective and expensive controls such as SCR or SNCR.a0
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10 Further, Colstrip is by far the largest single source of emissions in Montana. It
would be highly unlikely - and essentially noncompliant - for Montana to ignore
Colstrip Units 3 and 4 in its long-term strategy. That means Montana will still
need to apply the four statutory factors mentioned earlier to determine whether
emissions controls, such as SCR, must be installed on Colstrip Units 3 and 4.
Nothing about installing Smartburn in2016-2017 affects any of those factors.
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3) Even if Smartburn mieht be a useful component of a possible future SCR
proiect. it is illosical and imprudent to install it up to a decade in advance.
18 a.Avista claimed that the Smartburn controls will "optimize" the installation of
SCR at Colstrip in the future. Is this a reasonable justification for the
Company's investments in this technology in 2016 and 2017?
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a0 Selective Non-Catalytic Reduction
lA.No. Part of Avista's explanation for this investment was that it would "optimize
the size, scope and arnrnsflia use of any futgre SCR installation."4l However, that
does not explain why Avista would believe investment in these projects to be
prudeut in 2016 and2017. This futtue conrpliance obligation is speculative, so it
is not known if the Smartbum technology will ultimately be operating in concert
with other NOx control technology such as SCR. If SCR is required, it could be
up to a decade into the filtrue. It is uot pnrdent to spend ratepayer money today on
the chance that it will somehow be a useftil component for ftlhue technology that
may or may not ever be installed.
As noted above. Avista was fully aware that the timing of any requilement to
install SCR controls on Colstrip Units 3 and 4 was and remains speculative.
Intemal Avista emails show that Talen was assuming the cost of SCR on Colstrip
Unit 3 alone was o'Giveo the tenuous ecouomic sifuation facing
Colstrip, it is likely that, were SCR controls required to continue operating these
units in the firhue, a lower cost compliance altemative may well be to forgo
combustion of coal at Colstrip. Pursuing a non-coal altemative would mean tlmt
any investment in Smartburn technologies installed in 2016 and 2017 would no
longer be used or useful in any sense. and would not have been prudent because
they were never required for any environmental compliance requirement, did not
meaningfirlly reduce emissions, and were never used to "optimize" anything.
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Siena Club
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Finally, even if SCR is ultimately required, and if today's Smartburn does
somehow turn out to be the logical technology for optimizing the SCR controls of
the 2020s, Avista has presented no explanation for why it should have been
installed in 2016 and 2Ol7 .If Smartburn is a prudent and reasonable component
of SCR installation, then Avista should have considered it as part of the overall
cost of the SCRs, if and when they are required.
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7 0.Is there an environmental benefit to installing Smartburn controls as soon as
possible?
Not much. As I have shown, the Smartburn controls on Units 3 and 4 have
produced little if any reduction in NOx emissions. Much more effective and
expensive SCR technology would be required to achieve significant reductions in
NOx emissions as long as Colstrip continues to operate as a coal-fired power
plant. An even greater environmental benefit could be realized were Avista and
the other co-owners to responsibly plan for the retirement of Colstrip. My client,
the Sierra Club, routinely advocates before environmental agencies to require
polluting facilities to install stringent pollution controls. But that does not mean it
is appropriate to spend tens of millions of dollars on unnecessary and ineffective
capital expenditures at coal plants, or even to invest in effective controls when
lower cost and lower risk alternatives are available. With the current low price of
cleaner and cheaper generating technology, utilities are frequently able to achieve
even more environmental benefits at lower cost if they instead rely on other,
cleaner alternatives.
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Avista's Review Process and Request for Recoverv of Colstrip Costs is
Unreasonable
What is the process by which capital investments such as the Smartburn
technology on Units 3 and 4 are approvetl by Avista and the other co-owners.
ln response to Sierra Club Production Request l-5 (Exhibrt No. 602), Avista
explained as follows
After thefirst of a giva year, Talen updates the existing capitol plan to
include projects carried forward from a prior .vear. It also odds in all newly
proposed capital projects lhat \sere not parl of the prior yeor's 2 v*ear
projection. Talen's nranagement teom vets all of the projects to ensure that the
projects that are included as proposed capital projects are justified and
priortti:ecl and included fursed on a financial anafitsis or are required for
environnrcntal, regul a tory, o r s ofety rnasons.' 3
Did Talen prolide a financial analysis in support of the Smartburn
installations on Units 3 and 4?
16 A. As noted above, Talen identified these projects as
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though there was no mandate requiring them and, as far as I have been able to
detemrine, no financial analysis was perfonned.
Does Avista have veto power over capital projects at the Colstrip plant?
No. Accordilg to Avista's confidential response to Sierra Club Production
Request l-4 (Exhibit No. 603):
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o'sc PR l-5(c), ExhibitNo. 602. pages 3-4 of 8
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Did Avista object to the Smartburn projects at issue here?
No. According to the Company, "Avista didn't vote 'no' or any of the Colstrip
3&4 projects inchrded in the rate case application.'+5
To your knowledge, has Avista qqI objected to a proposed capital
expentliture at Colstrip?
No. When asked whether Avista had ever voted "no" or ary capital project at
Colship, Avista responded that it does not keep individual project records, but
that it "do[es] not recall an rnstance at this time.'#
Why is it important for a minority shareholder like Alista to perform an
independent evaluation of capital investments in the Colstrip units?
Althoupfi Avista is a minority owner of each of the units, the Company does have
an opporturity and an obligation to review and, if appropriate, object to capital
investments if it believes they are unwarranted or not in the interest of Idaho
mtepayers. However, it has never exercised this right, or at least it cannot recall a
time that it has objected to any capital spending at Colstrip.
As a regulated utilify in the state of Idaho, Avista has an obligation to ensure that
ratepayer fiurds are spent prudently, and that any capital investments ale made in
the context of least-cost plannilg to reliably meet customer needs, and subject to
t2 A.
nn sc PR 1-4(b), Exhibit 603.u' sc PR I -5(d). Exhibit No. 602. page 4 of I
oo sc PR l-5(0, ExhibitNo.602, page 4 of 8.
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known - not speculative - regulatory requirements.4T This responsibility includes
the responsibility to refrain from making imprudent capital investments. As I have
demonstrated, the Smartburn pollution controls are a good example of imprudent
capital spending. The controls are not required by any state or federal mandate,
and they have not been shown to be in the interest of ratepayers, and they have
been largely and predictably ineffective at reducing NOx emissions.
Would it be futile for Avista as a minority owner to oppose those capital
expenditures?
Avista claims that it is not able to veto any specific project by itself. According to
the ownership agreement provided by Avista in response to Sierra Club PR 1-5(a),
At a minimum,
Avista should have at least identified its concerns and raised them with the other
co-owners, particularly Puget Sound Energy, PacifiCorp, and Portland General
Electric, who all operate as regulated utilities and have a responsibility to ensure
prudent spending on behalf of their ratepayers.
o' C7. L the Matter of ldaho Power Company's Application for a Certificate of Public Convenience and
necessity for the Inyestment in Selective Catalytic Reduction Controls on lim Bridger Units 3 and 4, Case
No. IPC-E- I 3- 16, Order No. 32929 at p.9- l0 (finding that Idaho Power had presented a sufficient analysis
showing that expenditures were the least-cost, leasrrisk alternative to both reduce environmental effects
and allow reliance electric service to continue).nt SC PR 1-5C Attachment A, Exhibit No. 606, Section l7 "Project Committee."
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Sierra Club
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Regardless of whether Avista voting "no" would affect the ultimate outcome, the
utility still had an obligation to protect the interests of its customers. This
responsibility cannot be abdicated, nor should recovery of and on such capital
projects be approved, merely because Avista's minority stature does not give it a
veto power over such expenditures. The Company should provide a full
justification for any such expenditure, including a cost-benefit analysis and a
credible analysis of alternatives for meeting its customers' specific needs, exactly
as it would were it were the sole owner of the units.
If Avista had voted "no" on the Smartburn capital projects, and despite those
objections the other co-owners overruled the Company and installed the projects
anyway, then it might be reasonable for the Commission to conclude that Avista's
management had acted prudently within the bounds of its authority under the
contract. That is not what happened here. Avista was presented with an
unnecessary and imprudent project that it affirmatively approved. The costs of
that imprudent capital project should therefore be removed from Avista's rate
base. The Commission need not reach the question in this proceeding of what it
would have done had Avista been overruled, because in this instance Avista never
bothered to object to the project.
Do you have any concerns with the timing and manner in which Avista
presented the capital costs of Smartburn to the Commission?
Yes. [n both this proceeding and its prior rate case in AVU-E-16-03, Avista
lumped the costs of Smartburn controls in with other more routine capital projects
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at Colstrip. There was no separate analysis discussing the urique sihration that
allegedly required the installation of Smartburn. This is fioubling because, as
discussedabove,Smartbturraccoturtedfo',bo..tfofColstrip3and4,s
annual capital budget each year from 2015-2017. Avista should have called out
these costs more explicitly in its applicatiorr and testimony to allow for a thorough
review of those costs, particularly considering that the costs were based on a
novel and speculative compliance strategy.
Why was Avista's requested capital expense for Smartburn at Unit 4 in the
2016 rate case nearly twice as expensive ($1,993,516) as the current request
for Smartburn controls at Unit 3 ($1,047,417)?
Avista appears to have combined some or all of the 2016 project costs for Units 3
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15 Avista frout-loaded recovery of those costs by claiming neally two-tb"irds of those
costs as part of Urut 4 and the remainiug orre-third as part of Unit 3.50
I)o you have any concerns with this discrepancy in timing?
Yes. According to the Commission's order approving the 2016 rate case
sefflement, the test-year for that proceeding was based on a 12-month period
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o' SC PR 1-3C, Confideatial Attacbment G. p. 4l and 5o of 74. Exhibit No. 605.
'o Ao'ista Response to SC PR 3-6(b) and 3-7(b). Exhibit No. 602, pages 5 and 8 of 8
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I ending December 3l,2Ol5 with rates that became effective on January l,2Ol7.sl
That means that the Smartburn project for Colstrip Unit 3 was not complete until
a full l8 months after the test year in AVU-E-16-03 and that Idaho ratepayers
were paying for the project for a full 6 months before it was in service.
2
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5 Adjustments to rate base should not be made for plant additions unless and until
those projects actually go into service before the higher rates go into effect.52
While some allowance can be made for capital additions that fall outside the test
year, which would account for the 2016 project costs of Smartburn on Unit 4
being included in the last rate case's 2015 test year, this does not justify Avista
including expenses for Smartburn Unit 3 in the prior rate case because that project
was not expected to be completed until June 2017, six months after rates went
into effect.
Are you suggesting that the Commission should revise its prior order
approving the 2016 rate case settlement?
No. As discussed in more detail below, I am recommending that the Commission
remove the total costs from rate base for the Smartburn capital project at both
Units 3 and4. However, I am not suggesting that the Commission try to recover
any of the revenues collected by Avista from January 1,2017 through today. The
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made to test year accounts and rate base to reflect known and measurable changes so that test year totals
accurately reflect anticipated amounts for the future period when rates will be in effect.")(emphasis
added)(internal quotations omitted).
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2
.,
revenue requirement in both the 2016 rate case and the current proceeding were
the result of a negotiated settlement. There is no need to revisit whether the
agreed upon revenue requirement was appropriate.
While I am not recommending that the Commission attempt to claw-back any
previously collected revenue, it is nevertheless entirely appropriate to adjust the
Company's rate base on a going forward basis now that the presence of imprudent
expenditures has been identified. The 2016 rate case proceeding settled without a
direct or implicit finding of fact or law regarding the prudence of capital
expenditures at Colstrip Unit 4.53 The Commission would therefore not be
overturning any agreed-upon prudence finding related to Smartburn on Unit 4.
ln the alternative, if the Commission declines to remove capital costs related to
Smartburn on Unit 4, it should at a minimum address the discrepancy in timing
whereby Avista claimed twice the costs for Smartburn on Unit 4 than it now
claims on Unit 3. The capital costs attributable to Smartburn on each unit should
be roughly the same.
I also raise the issue here to provide further evidence that Avista's management of
Colstrip expenditures has been deficient. In order to avoid similar problems in the
future, the Commission should require a more rigorous review of capital
s3 Paragraph 20 of the 2016 Stipulation expressly provided that "No findings of fact or conclusions of law
other than those stated herein shall be deemed to be implicit in this Stipulation." Mot. for Approval of
Stipulation and Settlement, filed Oct.24,2016 in Docket AVU-E-16-03.
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expenditures at Colstrip in future proceedings.
2 lY. Useful Life forColqtrrp tlurtc 3 34d rl
3 a.
A.
Do you have concerns with the end of life assumptions Avista is making with
regard to Colstrip Units 3 and 4?
Yes. Avista requested a substantial amount of capital spending ($24.29 million)
on Colstrip Units 3 and 4 in its application for the years 2017-2019. While the
Settlement Agreement removed all of the capital additions budgeted for 2019 and
"most" of the proposed additions in 20l8,sa the overall rate of spending at
Colstrip continues to reflect an assumption that the plant will essentially run
indefinitely. This is an assumption that is no longer reasonable to make given the
current economic environmental facing Colstrip.
How do end-of-life assumptions for Colstrip affect rates in this proceeding?
The capital expenditures that Avista requested to include in rate base, and the
increases allowed in rate base under the Settlement Agreement, will be paid for by
ratepayers based on the depreciation scheduled for each asset. For each capital
project, a shorter depreciation schedule generally means a higher depreciation
expense, which increases the Company's revenue requirement.
Did Avista propose any changes to its depreciation schedules in this
proceeding?
No. For Colstrip and other non-transportation assets, Avista relied on depreciation
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sa Direct Testimony of Randy Lobb at p.10
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schedules based on a depreciation study completed nearly seven years ago, on
December 31, 2010.5s
Why is an outdated depreciation study a concern?
The depreciation schedules relied on by Avista, particularly with respect to the
Colstrip units, are stale. The Company should have studied and revised its
depreciation assumptions before submitting its general rate case. That update
would have allowed the Commission and other parties a more accurate analysis of
revenue requirement based on more up-to-date assumptions. Having failed to
update its depreciation schedules, it is now likely that Avista will soon return to
the Commission to request yet another rate increase to account for a faster rate of
depreciation.
Is it reasonable to require Avista to use an updated depreciation study in this
proceeding?
Avista's witness, Karen Schuh, stated in her direct testimony that "Avista's next
depreciation study is currently underway and is expected to be completed towards
the end of 2017 ."s6 This suggests that Avista had already begun the process of
updating its depreciation assumptions. Had Avista finished that study and
submitted it along with this proceeding (or at the same time) the Commission
could have consolidated multiple issues impacting revenue requirement and rates
into a single docket.
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ss Direct Testimony of Karen Schuh at p.10.
56 Direct Testimony of Karen Schuh at p.9.
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1Q.
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How does the Settlement Agreement impact your recommendation that
Avista be required to consolidate its general rate case with its upcoming
depreciation filing?
In my opinion, it may have been premature for parties to agree to a revenue
requirement in this proceeding without addressing whether and how rates may
change again soon in an upcoming depreciation proceeding. However, I do not
want to second-guess the rationale for each party's decision to settle. If the
Commission accepts the Settlement Agreement, it should make clear that nothing
in this proceeding precludes Avista or any other party from arguing that rates
could change to reflect updated depreciation schedules.
If, on the other hand, the Settlement Agreement is not accepted, the Commission
should require Avista to file its depreciation study and consolidate that proceeding
with this rate case so that the Commission and parties will be better able to
understand the full extent of the proposed rate increases.
Why do you conclude that rates are likely to go up in Avista's next
depreciation case?
As discussed in more detail below, Avista's current depreciation schedules for
Colstrip Units 3 and 4 are based on unrealistically long operating life assumptions.
If Avista follows the trend of its other Colstrip owners such as Puget Sound
Energy, Portland General Electric, and PacifiCorp, it will likely accelerate the
depreciation schedule at Colstrip. All else equal, that would lead to an increase in
rates.
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What is Avista's current end-of-life assumption for Colstrip Units 3 and 4 for
depreciation purposes?
Avista's most recently completed depreciation study was produced in December
2010 by the consulting firm Gannett Fleming, Inc; this study was provided to
Sierra Club as Attachment A to Sierra Club Production Request 2-5. The Gannett
Fleming study used retirement dates of December 2034 for Colstrip Unit 3 and
December 2036 for Colstrip Unit 4.
What was the basis of this projected end-of-life date?
According to the Gannett Fleming Study (p.I-4), although there were a number of
analytical and judgment-related considerations, "retirement data for the years
1989 through 2010 were used in the actuarial life table computations which were
the primary statistical support of the service life estimates."
Is this a reasonable approach? Why or why not?
While this approach may have been more reasonable in 2OlO, it is certainly not
reasonable today. The economic and regulatory environment for coal today is
manifestly different from the economic conditions during the time period
referenced by Gannett Fleming, rendering such a statistical analysis irrelevant to
estimating the future lives of the Colstrip units.
Throughout the 20th century and into the first decade of the 21't, there were very
few retirements of coal plants, as demand for power grew exponentially and the
availability and cost of coal made it more attractive to utilities than alternative
energy sources. In addition, the environmental and public health impacts of coal
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combustion were less well-known than they are today, and./or were considered an
acceptable cost of this engine of economic growth. In 1970, the US Congress
passed the Clean Air Act and began the process of requiring coal plants to install
pollution controls to reduce the environmental and health impacts of their
emissions. However, Congress exempted many existing coal plants from strict
emissions control requirements. This loophole had the perverse consequence of
actually prolonging the life of many coal plants that lacked modern pollution
controls, as companies sought to avoid the costs associated with the technology
that would be required on new, or substantially refurbished, coal-fired power
plants.
Since around 2010 the rate of coal plant retirements has increased dramatically. In
much of the country the growth in demand for electricity has slowed or even
halted due to factors such as stringent appliance energy efficiency standards,
along with utility-run energy efficiency programs. (The US Department of
Energy's Annual Energy Outlook (AEO) for 2017 projects a total increase in
electricity consumption of just 2.OVo in the Western region of the United States by
2035 over 2015 levels, despite an804Vo increase in electricity demand for
transportation.sT; More recent environmental regulations have required existing
coal-fired plants to reduce their emissions of harmful and haze-inducing
pollutants, in addition to better management of their water use, their impact on
57 US Department of Energy, Energy Information Administration, Annual Energy Outlook for 2Ol7
Available at https ://www.eia. gov/outlooks/aeo/.
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aquatic life, and disposal of combustion residuals (a.k.a. ash). These mandates
often necessitate costly equipment upgrades for plants to continue operating.
At the same time, the availability of natural gas has increased with the
development and widespread use of hydraulic fracturing, and the current and
expected cost of gas has dropped to the point where it is often cost-preferable to
coal as a generation fuel. The cost of renewable energy sources has also
plummeted, while the demand for renewable-sourced energy has increased as a
result of state Renewable Portfolio Standards and other policies. AE'O 2017
projects an increase in renewable generation of 8l.ZVo over 2015 levels by 2035,
replacing notjust coal (decrease of 77.8Vo) but also natural gas (decrease of
46.4Vo.)
Finally, coal-fired plants such as Colstrip are very large point-sources of carbon
dioxide (COz) and other greenhouse gases, which have well-documented and
extremely harmful long-term impacts on the Earth's climate and environment,
human health, and economic well-being. The United States currently lags other
countries in federal policies to address this threat. However, numerous states,
including western states such as Washington, Oregon, and California, are moving
aggressively to reduce the greenhouse gas emissions associated with electricity
production and other economic activity, transforming the regional electricity
market by pushing the generation mix away from high-carbon sources such as
Colstrip and towards cleaner generating technologies. There has also been
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widespread recognition throughout the electric industry that the United States will
ultimately implement policies that impose a price on greenhouse gas emissions, as
the deleterious effects of global climate change become increasingly difficult to
ignore or deny.
These factors have led to conditions where many coal plants cannot compete
economically, and even more cannot justify continued investments in either
environmental upgrades or other significant capital improvements given their
long-term outlook. As a result, coal plants have been retired, or repowered to burn
gas, at an unprecedented rate over the last decade. As tallied by the Sierra Club,
732 units at259 coal plants have retired or committed to retire since 2010,
representing almost 5OVo of 2010 coal capacity in the United States.58 Today, even
larger, younger coal plants are struggling to survive the economic competition
from cleaner, cheaper energy sources.t'
0. Has the wave of coal plant retirements you describe reached Montana?
A. Yes. The other two Colstrip units, Units 1 and2, will be retired in2022.The 2022
retirement date represents a dramatic acceleration of retirement relative to that
unit's owners' previous projections - Puget Sound Energy, for example was
previously using a retirement date of 2035 for Units I and2, based on a
settlement of that company's 2007 rate case. While Units 1 and2 are older and
s8 http://content.sierraclub. orglcoall.
5e See, for example, E&E News, April 27 , 2011: "Big Young Power Plants are Closing. Is it a new trend?"
Available at https://www.eenews.neUstories/ I 060053677 .
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less efficient than Units 3 and 4, the newer units are subject to the same regulatory
and economic pressures that have rendered the older units uneconomic in the
longer term.
What end-of-life assumptions should Avista have used in this proceeding and
in its upcoming depreciation study?
Based on my analysis, including testimony I recently prepared for the Washington
Utilities and Transportation Commission, I believe that Colstrip is likely to go out
of service by 2025. [n this proceeding and the upcoming depreciation filing, I
recommend that Avista at a minimum accelerate its end-of-life assumption for
both Colstrip Units to 2027. This schedule would match the depreciation schedule
recently proposed by Puget Sound Energy and would more closely align with
depreciation schedule changes made recently by other co-owners.
What end-of-life considerations affect the other (non-Avista) owners of
Colstrip Units 3 and 4?
Puget Sound Energy (PSE), which owns 25Vo of Units 3 and 4, recently reached a
settlement agreement before the Washington Utilities and Transportation
Commission that requested, among other things, approval of a depreciation
schedule that assumed a remaining useful life of Colstrip Units 3 and 4 through
December 31,2027 . Several parties, including UTC Stafl industrial customers,
Sierra Club and the Montana Attorney General signed on to this settlement in
support of a2027 depreciation date. While the settling parties continue to disagree
on a precise retirement date for the units in that proceeding, they all agreed that
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accelerating depreciation to 2027 was reasonable. The Montana Attorney
General's post-hearing brief described the accelerated depreciation date as
follows
Working to ameliorate cost uncertainty, which the adjusted depreciation
schedule for Units 3 & 4 does, is in the public interest generally and the
interest of Washington ratepayers specifically. December 31. 2027. is a
lawful and well-supported depreciation date that arose from
thoughtful negotiations among diverse interests.60
The Washington UTC's order on the PSE settlement is still pending.
In addition, Portland General Electric (PGE) owns 20Vo of each unit and Pacific
Power's parent company PacifiCorp owns 107o of each unit. Both companies
serve customers in Oregon and are required by the Oregon Clean Electricity and
Coal Transition Act to eliminate coal from their portfolios serving Oregon
customers by 2030. While there is a carve-out from the legislation allowing PGE
to continue using power from Colstrip until no later than2O35,6' PGE has
nevertheless shortened its depreciable end-of-life assumption for Units 3 and 4
from2042 to 2030 pursuant to this ru1e.62 PacifiCorp also serves customers in
Washington, where it recently requested and received permission to set its
depreciation rate for the Washington-jurisdictional share of Colstrip Units 3 and 4
o Washington Utilities and Transportation Commission Dockers UE-170033 Nc-l7m34,Initial Posr
Settlement-Hearing Brief of the State of Montana in Support of the Proposed Multiparty Settlement
StipulationandAgreement(Oct. 18,2Ol7) atp.7(emphasisadded),ExhibitNo.6l2,page6of 6.6t See 786 Oregon Legislative Assembly, 2016 Regular Session, Enrolled Senate Bill 1547 for bill text
(https://olis.leg.state.or.us/liil2}l6F.ltDownloads/I,IeasureDocument/SB 1547lEnrolled) and Oregon Clean
Electricity & Coal Transition Plan (SB 15478) for a summary (https://www.portlandgeneral.com/-
/media/public/our-company/news-room/documents/oregon-clean-electricity-plan-summary.pdl).
62 Schedule 146 of PGE's Oregon tariff, Exhibir No. 613.
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using an end of life date of 2032.63
Talen Energy, the independent generating company that co-owns and operates
Colstrip Units 3 and 4, purchases coal from the Rosebud coal mine adjacent to the
plant, owned by Westmoreland Coal. In Westmoreland Coal's most recently-fled
SEC Form 10-K,64 the company reported that the "estimated mine life with
current plan" for Rosebud ends in 2024. The same document states that the
current contract to supply coal to Colstrip Units 3 and 4 expires in 2019.65
Does this support your conclusion that Colstrip is tikely to stop operating by
2025?
It does in part. I also base my conclusion on the observation that during the last
several years coal plants have been trending toward earlier retirements than
anticipated, resulting in large undepreciated balances for resources that are no
longer used and useful. Colstrip Units 1 and2 are excellent examples of this
phenomenon, and the owners of these units and their regulatory commissions are
struggling to accommodate not only large undepreciated balances but also
inadequate decommissioning funds. Further, as discussed above, I think it is likely
that EPA will require installation of expensive SCR technology on these units in
the mid-2020s in order to continue "Reasonable Progress" in reducing regional
63 See final order in Washington Utilities and Transportation Commission Docket No UE-152253,
September 1,2016.
6a Available at: https://www.sec.gov/Archives/edgar/data/1064551N0010645517000012/wlb-
123116_lOk.htm. See table on page 10.
65 tbid., p.3+.
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haze. Based on the magnitude of costs required for SCR, and the continued
improvements in the cost and performance of cleaner energy sources, the units
may well shut down rather than install those controls.-1
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While it is certainly possible that the companies and commissions setting end-of-
life for Units 3 and 4 closer to 2030 have gotten it right this time around, I find it
much more likely that economic pressures and the opportunity to avoid capital
improvements and maintenance expenses will lead the co-owners to retire the
units several years earlier than that.
Why is it important to use a realistic estimate of end-of-life for depreciation
purposes?
It is a fundamental principle of utility economic regulation that customers who get
the benefit of a resource should be the same customers who pay for it. Although
this can rarely be achieved with precision, using a realistic end-of-life date for
depreciation purposes ensures that, to the best of anyone's ability, the customers
who benefit from the energy and capacity provided by Units 3 and 4 will both pay
off the outstanding plant balance, and fully fund the eventual decommissioning of
these units. If a utility is allowed to assume an unrealistically long lifetime for
depreciation purposes, future ratepayers or utility shareholders will have to make
up the shortfall for a resource from which they are receiving no benefit - a
phenomenon often called intergenerational inequity.
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accounting practice to periodically update depreciation rates to recognize
additions to investment in plant assets and to reflect changes in asset
characteristics, technology, salvage, removal costs, life span estimates and other
factors that impact depreciation rate calculations."66I agree with this assessment;
however, Avista should have made those updates before filing its present request
to increase rates.
V. Recommendations
a. What are your recommendations for the Commission in this proceeding?
A. The Commission should conclude that Avista acted imprudently when it agreed to
capital expenditures to install Smartburn at Colstrip Units 3 and 4 in the absence
of any existing or anticipated compliance obligation, any showing of benefits for
ratepayers, and little to no benefit in terms of reducing NOx emissions. These
capital expenditures, totaling $3,040,933, should be removed from rate base on a
going forward basis.
The Commission should also direct Avista to adopt and exercise more rigorous
review and approval procedures for future capital expenditures at Colstrip Units 3
and 4. Avista cannot abdicate its responsibility to act in the best interests of its
customers by claiming that it has no control over Colstrip expenditures as a
minority owner. Avista should also provide more detailed and specific
justification for significant Colstrip capital expenditures rather than simply
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66 Direct Testimony of Karen Schuh at p. 10.
combining all capital costs into a single category that it claims is for "Mandatory
2 and Compliance" purposes.
.,Finally, if the Settlement Agreement is rejected, the Commission should hold
open this general rate case until Avista has completed and submitted its pending
depreciation study. The Commission should then allow parties an opportunity to
address that depreciation study and any impacts that the results will have on rates
in this proceeding.
Do your recommendations require the Commission to reject the Settlement
Agreement?
No. Under Rule 276 of the Commission's Rules of Procedure, the Commission
may state additional conditions under which the settlement will be accepted.
Adopting my recommendations above need not disturb the agreed upon revenue
requirement and rate spread in the Settlement Agreement. The adjustments I
recommend to rate base are on a forward-going basis only. That is, the
Commission need only issue a determination that the Smartburn capital projects
were imprudent and require Avista to exclude those expenditures from rate base
in all future proceedings. In doing so, the Commission would protect future
ratepayers from harm while still maintaining the benefits of the Settlement
Agreement currently before the Commission.
Does this conclude your direct testimony?
Yes.
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2t A.
Eznn Hausvaru Corusulrrruc
Ezra D. Hausman, Ph.D.
I am an independent consultant in energy and environmental economics
I have worked for 20 years as an electricity market expert with a focus on market design and
market restructuring, environmental regulation in electricity markets, and pricing of energy,
capacity, transmission, losses and other electricity-related services. I have performed market
analysis, offered expert testimony, led workshops and working groups, made presentations and
participated on panels, and provided other support to clients in a number of areas, including:
o Economic analysis, price forecasting, and asset valuation in electricity markets
o Dispatch and planning model analyses, and review of modeling studies
o Electricity and generating capacity market design and analysis
o Demand-side resource program analysis
o lntegrated Resource Planning and portfolio analysis
o Economic analysis of environmental and other regulations, including regulation of
greenhouse gas emissions, in electricity markets
o Quantification, regulation and mitigation of greenhouse gas emissions associated with
the supply and demand sides of the U.S. electricity sector
o Quantification of the economic and environmental benefits of displaced emissions
associated with energy efficiency and renewable energy initiatives
o Expert representation/participation in stakeholder processes
o Clean Air Act determinations and enforcement.
I have prepared reports and offered other expert services on these and other related topics for
clients including federal and state agencies; offices of consumer advocate; legislative bodies;
cities and towns; non-governmental organizations; foundations; industry associations; and
resource developers.
I previously served as Vice President and Chief Operating Officer of Synapse Energy Economics,
lnc. of Cambridge, Massachusetts. ln addition to my consulting portfolio, this management role
entailed responsibility for day-to-day operations of the company including overseeing finance,
HR, communications & marketing, quality assurance, client service, and professional
development of staff. I had overall responsibility for ensuring that project managers and project
teams had the tools, information, and training they needed to successfully serve client's needs
and to produce high-quality deliverables on time and on budget. I was also a resource available
to any of our clients to address any issues of customer service, quality, or any other issues.
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I hold a Ph.D. in atmospheric science from Harvard University, an S.M. in applied physics from
Harvard University, an M.S. in water resource engineering from Tufts University, and a B.A. in
psychology from Wesleyan U n iversity.
PROFESSIONAL EXPERIENCE
Ezra Hausman Consulting, Newton, MA. President, March 2OL4- Present.
I provide research, analysis, expert testimony, and policy support services in regulatory,
litigation, and stakeholder processes covering a wide range of electric sector and electriciuty
market issues. The focus of my consulting work includes:
o lnteraction of air quality and environmental regulations with electricity markets
o Analysis and implementation of the Clean Power Plan and other greenhouse gas rules
o Clean Air Act enforcement support
o Long-term electric power system planning and market design
o EnerBv efficiency and renewable energy programs and policies
o Avoided emissions analysis
o Regulation and mitigation of greenhouse gas emissions
o Consumer and environmental protection
o Efficient pricing of generating and transmission capacity
o Market power and market concentration analysis in electricity markets
o Economic analysis of electricity industry regulation and restructuring
Synapse Energy Economics lnc., Cambridge, MA.
Chief Operating Officer, March 2OLL- February 2OL4;
Vice President, July 2009 - February 2OL4;
Senior Associate, 2005-2009.
o Conducted research, wrote reports, and presented expert testimony pertaining to
consumer, environmental, and public policy implications of electricity industry
regulation. Provided expert support and representation in planning, greenhouse gas
mitigation, and other stakeholder processes.
o As Vice President and Chief Operating Officer, I was also responsible for day-to-day
operations of the company, quality assurance, client service, and professional
development of staff.
Charles River Associates (CRAI, Cambridge, MA. Senior Associate,2004-2005
CRA acquired Tobors Coramanis & Associotes in October, 2004.
Tabors Caramanis & Associates, Cambridge, MA. Senior Associate, L998-2O04
As a member of the modeling group, developed and maintained dispatch modeling capability in
support of electricity market consulting practice.
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Performed modeling and analysis of electricity markets, generation and transmission systems.
Projects included:
o Several market transition cost-benefit studies for development of Locational Marginal
Price (LMP) based markets in US electricity markets
o Long-term market forecasting studies for valuation of generation and transmission
assets,
o Valuation of financial instruments relating to transmission system congestion and losses
o Modeling and analysis of hydrologically and electrically interconnected hydropower
system operations
o Natural gas market analysis and price forecasting studies
o Co-developed an innovative approach to hedging financial risk associated with
transmission system losses of electricity
o Designed, developed and ran training seminars using a computer-based electricity
market simulation game, to help familiarize market participants and students in the
operation of LMP-based electricity markets.
o Developed and implemented analytical tools for assessment of market concentration in
interconnected electricity markets, based on the "delivered price test" for assessing
market accessibility in such a network
o Performed regional market power and market power mitigation studies
o Performed transmission feasibility studies for proposed new generation and
transmission projects in various locations in the US
o Provided analytical support for expert testimony in a variety of regulatory and litigation
proceedings, including breach of contract, bankruptcy, and antitrust cases, among
others.
Global Risk Prediction Network, lnc., Greenland, NH. Vice President, 1997-1998
Developed private sector applications of climate forecast science in partnership with
researchers at Columbia University. Specific projects included a statistical assessment of grain
yield predictability in several crop regions around the world based on global climate indicators
(Principal lnvestigator); a statistical assessment of road salt demand predictability in the United
States based on global climate indicators (Principal lnvestigator); a preliminary design of a
climate and climate forecast information website tailored to the interests of the business
community; and the development of client base.
Hub Data, lnc., Cambridge, MA. Financia! Software Consultant, 1986-1987, L993-L997
Responsible for design, implementation and support of analytic and communications modules
for bond portfolio management software; and developed software tools such as dynamic data
compression technique to facilitate product delivery, Windows interface for securities data
products.
Abt Associates, lnc., Cambridge, MA. Environmental Policy Analyst, 1990-1991
Quantitative risk analysis to support federal environmental policy-making. Specific areas of
research included risk assessment for federal regulations concerning sewage sludge disposal
Case No. AVU-E-1 7-01 /AVU-G-1 7-01
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and pesticide use; statistical alternatives to Most-Exposed-lndividual risk assessment paradigm;
and research on non-point sources of water pollution.
Massachusetts Water Resources Authority, Charlestown, MA. Analyst, 1988-1990
Applied and evaluated demand forecasting techniques for the Eastern Massachusetts service
area. Assessed applicability of various techniques to the system and to regional planning needs;
and assessed yield/reliability relationship for the eastern Massachusetts water supply system,
based on Monte-Carlo analysis of historical hydrology.
Somerville High School, Somerville, MA. Math Teacher, 1986-1987
Courses included trigonometry, computer programming, and basic math.
EDUCATION
Ph.D., Earth and Planetary Sciences. Harvard University, Cambridge , MA, L997
S.M., Applied Physics. Harvard University, Cambridge, MA, 1993
M.S., Civil Engineering. Tufts University, Medford, MA, 1990
8.A., Wesleyan University, Psychology. Middletown, CT, 1-985
FELLOWSH I PS, AWARDS AN D AFFILIATIONS
UCAR Visiting Scientist Postdoctoral Fellowship, L997
Postdoctoral Research Fellowship, Harvard University, 1997
Certificate of Distinction in Teaching, Harvard University, L997
Graduate Research Fellowship, H a rva rd U n iversity, L99L-L997
Invited Participant, UCAR Globa! Change lnstitute, 1993
House Tutor, Leverett House, Harvard University, 1991-1993
Graduate Research Fellowship, Massachusetts Water Resources Authority, 1989-1990
Teoching Fellowships:
Harvard University: Principles of Meosurement ond Modeling in Atmospheric Chemistry;
Hydrology; lntroduction to Environmentol Science and Public Policy; The Atmosphere.
Wesleyan University: lntroduction to Computer Progromming; Psychological Stotistics;
Playwriting ond Production.
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Community Seruice
Acodemic Mentor and Athletic Cooch, SquashBusters Boston ,20L4 - Ongoing
Judge, Cleantech Open innovation competitions, 2O75-2OL6
P re si d e nt, Bu rr Elementary School Parent Teacher Organ izatio n, 2OO5-2O07
EXPERT TESTIMONY AND SERVICES
Washington Utilities and Transportation Commission (Dockets UE-170033 and
UG-170034|- Ongoing
Expert witness on behalf of the Sierra Club in Puget Sound Energy (PSE) rate case.
Clean Power Plan Modeling in PJM and MISO - Ongoing
Participation on behalf of the Sustainable FERC Project in ISO initiative to modelscenarios for
state compliance with federal greenhouse gas mitigation rules.
California !SO/PacifiCorp Market lntegration - Ongoing
Technical support to Sierra Club in stakeholder review and participation in all relevant
proceedings in California.
New Jersey Board of Public Utilities - 2014-Ongoing
Expert witness on behalf of the New Jersey Division of Rate Counsel, reviewing and providing
testimony on cost effectiveness and program design of various New Jersey gas utility energy
efficiency programs.
United States Department of Justice - US District Court Dallas, TX Division (U.S. vs. Luminant
Generation Company, LLC, and Big Brown Power Company, LLC) - Ongoing
Expert witness on behalf of the United States Department of Justice on clean air act
enforcement case.
United States Department of Justice - US District Court for the Eastern District of Missouri
(Civil Action No. 4:11-CV-00O771 - 2013-2016
Expert witness on behalf of the United States Department of Justice on successful prosecution
of clean air act case.
Missouri Public Service Commission (Case No. EO-2015-0084) -20L4-2O15
Expert services in support of Sierra Club's participation in integrated resource planning process.
Missouri Public Service Commission (File No. ER-2014-0258) -20L4-2015
Expert witness on behalf of the Sierra Club in Ameren Missouri rate case.
Arizona Corporation Commission (Docket No. E-013 45 A-LL-O2241 - 2Ot4
Expert witness on behalf of the Sierra Club regarding Arizona Public Service petition for rate
treatment for acquisition of an additional ownership share of the Four Corners generating
units.
Missouri Public Service Comission (Docket No. ET-2014-00851 -2OL3
Testimony on behalf of the Missouri Solar Energy lndustries Association regarding Union
Electric (dlbla Ameren Missouri) motion to suspend payment of solar rebates.
Missouri Public Service Comission (Docket No. ET-2014-0059 and ET-2014-0071) -zOLg
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Testimony on behalf of the Missouri Solar Energy lndustries Association regarding Kansas City
Power and Light Company's motions to suspend payment of solar rebates.
Eastern lnterconnect Planning Co!!aborative (EIPC) - 2OL2-2OL?
Expert support on behalf of coalition of NGO stakeholders in transmission and resource
planning process, including development and review of modeling assumptions and interim
results, and development of comments.
Puget Sound Energy (PSE) - 2OL2-2OL3
Expert participant in PSE's 2013 IRP stakeholder process on behalf of the Sierra Club.
Washington Utilities and Transportation Commission (Docket Nos. UE-111048 and UG-
1110491 -zOLt
Testimony on behalf of the Sierra Club regarding the cost of operating the Colstrip power plant
and other power procurement issues.
Kansas Corporation Commission (Docket No. 11-KCPE-581-PREI - 2011
Presented written and live testimony on behalf of the Sierra Club regarding Kansas City Power
and Light request for predetermination of ratemaking principles.
Vermont Department of Public Service - zOLl
Provided scenario analysis of the costs and benefits of various electric energy resource
scenarios in support of the state Comprehensive Energy Plan.
Massach usetts Depa rtment of En ergy Resou rces - 2OO9 -2OL1.
Served as expert analyst and modeling coordinator for analysis related to implementation of
the Massachusetts Global Warming Solutions Act.
lowa Office of Consumer Advocate - 2010-Present
Assisted Consumer Advocate in evaluating a proposed power purchase agreement for the
output of the Duane Arnold nuclear power station.
Missouri Public Service Commission (Docket No. EW-2010-01871- 2010
Expert participant on behalf of the Sierra Club in stakeholder process to develop a "demand
side investment mechanism" in Missouri.
Louisiana Public Service Commission (Docket No. R-28271 Subdocket B) - 2009-2010
Expert participant on behalf of the Sierra Club in Renewable Portfolio Standard Task Force
considering RPS for Louisiana.
Joint Fiscal Committee of the Vermont Legislature - 2008-2010
Serving as lead expert advising the Legislature on economic issues related to the possible
recertification of the Vermont Yankee nuclear power plant.
Town of Littleton, NH - 2006-2010
Serving as expert witness on the value of the Moore hydroelectric facility.
Case No. AVU-E-1 7-01IAVU-G-1 7-01
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Nevada Public Service Commission (Docket No. 08-05014) - August 2008
Presented prefiled and live testimony on behalf of Nevadans for Clean Affordable Reliable
Energy regarding the proposed Ely Energy Center and resource planning practices in Nevada.
Mississippi Public Service Commission (Docket No. 2008-AD-1581- August 2008
Presented written and live testimony on behalf of the Sierra Club regarding the resource plans
filed by Entergy Mississippi and Mississippi Power Company.
Kansas House of Representatives - Committee on Energy and Utilities - February 2008
Presented testimony on behalf of the Climate and Energy Project of the Land lnstitute of Kansas
on a proposed bill regarding permitting of power plants. Focus was on the risks and costs
associated with new coal plants and on their contribute to global climate change.
Vermont Public Service Board (Docket No. 7250! - 2006-2008
Prepared report and testimony in support of the application of Deerfield Wind, LLC. For a
Certificate of Public Good for a proposed wind power facility.
towa Utilities Board (Docket No. GCU-O7-LI-- October, 2OO7 -January 2008
Presented wrtten and live testimony on behalf of the lowa Office of Consumer Advocate
regarding the science of global climate change and the contribution of new coal plants to
atmospheric COz.
Nevada Public Service Commission (Docket No. 07-06049) - October 2OO7
Presented prefiled direct testimony on behalf of Nevadans for Clean Affordable Reliable Energy
regarding treatment of carbon emissions costs and coal plant capital costs in utility resource
planning.
Massachusetts GeneralCourt, Joint Committee on Economic Development and Emerging
Technologies - July 2007
Presented written and live testimony on climate change science and the potentia! benefits of a
revenue-neutral carbon tax in Massachusetts.
Town of Rockingham, VT -2006-2007
Served as expert witness on the value of the Bellows Falls hydroelectric facility.
South Dakota Public Utilities Commission (Case No EL05-22| - June 2006
Minnesota Public Utilities Commission (Docket TR-05-1275)- December 2006
Submitted prefiled and live testimony on the contribution of the proposed Big Stone ll coal-
fired generator to atmospheric COz, global climate change and the environment of South
Dakota and Minnesota, respectively.
Arkansas Public Service Commission (Docket No. 05-070-Ul- October 2005
Submitted prefiled direct testimony on inclusion of new wind and gas-fired generation
resources in utility rate base.
Federal Energy Regulatory Commission (Docket Nos. ER055-1410-000 and EL05-148-0001-
May-Sept 2006
o Participant in settlement hearings on proposed capacity market structure (the
Reliability Pricing Model, or RPM) on behalf of State Consumer Advocates in
Pennsylvania, Ohio and the District of Columbia
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o lnvited participant on technical conference panel on PiM's proposed Variable Resource
Requirement (VRR) curve
o Filed Pre- and post-conference comments and affidavits with FERC
o Participated in numerous training and design conferences at PJM on RPM
implementation.
lllinois Pollution Control Board (Docket No. R2006-0251- June-Aug 2006
Prefile and live testimony presented on behalf of the lllinois EPA regarding the costs and
benefits of proposed mercury emissions rule for lllinois power plants.
Long lsland Sound LNG Task Force - January 2006
Presentation of study on the need for and alternatives to the proposed Broadwater LNG
storage and regasification facility in Long lsland Sound.
lowa Utilities Board (Docket No. SPU-05-15) - November 2005
Presented written and live testimony on whether lnterstate Power and Light's should be
permitted to sell the Duane Arnold Energy Center nuclear facility to FPLE Duane Arnold, lnc., a
subsidiary of Florida Power and Light.
PUBLICATIONS AN D REPORTS
Hausman, E., Risks and Opportunities for PacifiCorp - State Level Findings: Utah, Produced on
behalf of the Sierra Club, Octob er 2074.
Hausman, E., Risks and Opportunities for PacifiCorp - State Level Findings: Oregon, Produced on
behalf of the Sierra Club, Octob er 20L4.
Hausman, E., Risks and Opportunities for PacifiCorp in a Carbon Constrained Economy,
Produced on behalf of the Sierra Club, October 2OL4.
Luckow, P., E. Stanton, B. Biewald, J. Fisher, F. Ackerman, E. Hausman, 2013 Carbon Dioxide
Price Forecast, Synapse Energy Economics, November 2OL3.
Stanton, E., T. Comings, K. Takahashi, P. Knight, T. Vitolo, E. Hausman, Economic lmpacts of the
NRDC Carbon Standard: Background Report prepared for the Natural Resources Defense
Council, Synapse Energy Economics for NRDC, June 2013
Comings T., P. Knight, E. Hausman, Midwest Generation's lllinois Coal Plants: Too Expensive to
Compete? (Report Update) Synapse Energy Economics for Sierra Club, April 2013
Stanton E., F. Ackerman, T. Comings, P. Knight, T. Vitolo, E. Hausman, Will LNG Exports Benefit
the United States Economy? Synapse Energy Economics for Sierra Club, January 2013
Chang M., D.White, E. Hausman, Risks to Ratepayers: An Examination of the Proposed William
States Lee lll Nuclear Generation Station, and the lmplications of "Early Cost Recovery"
Legislation, Synapse Energy Economics for Consumers Against Rate Hikes, December 2012
Case No. AVU-E-1 7-01 /AVU-G-1 7-01
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Wilson R., P. Luckow, B. Biewald, F. Ackerman, and E.D. Hausman,2072 Corbon Dioxide Price
Forecost, Synapse Energy Economics, October 2OL2.
Fagan B., M. Chang, P. Knight, M. Schultz, T. Comings, E.D. Hausman, and R. Wilson, Ihe
Potentiol Rote Effects of Wind Energy and Tronsmission in the Midwest ISO Region. Synapse
Energy Economics for Energy Future Coalition, May 2012.
Hausman, E.D., T. Comings, "Midwest Generation's lllinois Coal Plants: Too Expensive to
Compete? Synapse Energy Economics for Sierra Club, April 20L2.
Hausman, E.D., T. Comings, and G. Keith, Moximizing Benefits: Recommendotions for Meeting
Long-Term Demand for Stondard Offer Service in Maryland. Synapse Energy Economics for
Sierra Club, January 20L2.
Keith G., B. Biewald, E.D. Hausman, K. Takahashi, T. Vitolo, T. Comings, and P. Knight, Toward a
Sustoinoble Future for the U.S. Power Sector: Beyond Business as Usuol 201L Synpase Energy
Economics for Civil Society lnstitute, November 20lt.
Chang M., D. White, E.D. Hausman, N. Hughes, and B. Biewald, Big Risks, Better Alternotives: An
Exominotion of Two Nucleor Energy Projects in the U.5. Synpase Energy Economics for Union of
Concerned Scientists, October ZOLL.
Hausman E.D., T. Comings, K. Takahashi, R. Wilson, and W. Steinhurst, Electricity Scenorio
Analysis for the Vermont Comprehensive Energy Plon 2011. Synapse Energy Economics for
Vermont Department of Public Service, September ZOLL.
Wittenstein M., E.D. Hausman, lncenting the Old, Preventing the New: Flaws in Copocity Morket
Design, and Recommendotions for lmprovement. Synapse Energy Economics for American
Public Power Association, June IOLL.
Johnston 1., E.D. Hausman, B. Biewald, R. Wilson, and D. White. 2077 Carbon Dioxide Price
Forecast. Synapse Energy Economics White Paper, February 2017.
Hausman 8.D., V. Sabodash, N. Hughes, and J. l. Fisher, Economic lmpact Analysis of New
Mexico's Greenhouse Gos Emissions Rule. Synapse Energy Economics for New Energy Economy,
February }OLL.
Hausman E.D., J. Fisher, L. Mancinelli, and B. Biewald. Productive ond Unproductive Costs of COz
Cap-ond-Trade: lmpocts on Electricity Consumers and Producers. Synapse Energy Economics for
National Association of Regulatory Utility Commissioners, NationalAssociation of State Utility
Consumer Advocates, National Rural Electric Cooperative Association, and American Public
Power Association, July 2009.
Peterson P., E. Huasman, R. Fagan, and V. Sabodash, Report to the Ohio Office of Consumer
Counsel, on the volue of continued participotion in RTOs. Filed under Ohio PUC Cose No. 09-90-
EL-COI, May 2009.
Schlissel D., L. Johnston, B. Biewald, D. White, E. Hausman, C. James, and J. Fisher,
Synopse 2008 COz Price Forecosts. July 2008.
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Hausman E.D., J. Fisher and B. Biewald, Anolysis of lndirect Emissions Benefits of Wind, Londfill
Gos, ond Municipal Solid Woste Generation. Synapse Energy Economics Report to the Air
Pollution Prevention and Control Division, National Risk Management Research Laboratory, U.S.
Environmental Protection Agency, July 2008.
Hausman E.D. and C. James, Cop ond Trode COz Regulotion: Efficient Mitigotion or o Give-owoy?
Synapse Enegy Ecomics presentation to the ELCON Spring Workshop, June 2008.
Hausman E.D., R. Hornby and A. Smith, Biloterol Controcting in Dereguloted Electricity Markets.
Synapse Energy Economics for the American Public Power Association, April 2008.
Hausman E.D., R. Fagan, D. White, K. Takahashi and A. Napoleon, LMP Electricity Markets:
Morket Operotions, Market Power and Value for Consumers. Synapse Energy Economics for the
American Public Power Association's Electricity Market Reform lnitiative (EMRI) symposium,
"Assessing Restructured Electricity Markets" in Washington, DC, February 2007.
Hausman E.D. and K. Takahashi, The Proposed Broodwoter LNG lmport Terminol Response to
Droft Environmental lmpact Statement and Updote of Synopse Anolysis. Synapse Energy
Economics for the Connecticut Fund for the Environment and Save The Sound, January 2007.
Hausman E.D., K. Takahashi, D. Schlissel and B. Biewald, The Proposed Broodwoter LNG lmport
Terminol: An Analysis ond Assessment of Alternotives. Synapse Energy Economics for the
Connecticut Fund for the Environment and Save The Sound, March 2006.
Hausman E.D., P. Peterson, D. White and B. Biewald, RPM 2006: Windfoll Profits for Existing
Base Lood Units in PJM: An Updote of Two Case Studies. Synapse Energy Economics for the
Pennsylvania Office of Consumer Advocate and the lllinois Citizens Utility Board, February 2006.
Hausman E.D., K. Takahashi, and B. Biewald, The Glebe Mountoin Wind Energy Project:
Assessment of Project Benefits for Vermont ond the New England Region. Synapse Energy
Economics for Glebe Mountain Wind Energy, LLC., February 2006.
Hausman E.D., K. Takahashi, and B. Biewald, The Deerfield Wind Project: Assessment of the
Need for Power ond the Economic ond Environmentol Attributes of the Project. Synapse Energy
Economics for Deerfield Wind, LLC., January 2006.
Hausman E.D., P. Peterson, D. White and B. Biewald, An RPM Cose Study: Higher Costs for
Consumers, Windfall Profits for Exelon. Synapse Energy Economics for the lllinois Citizens Utility
Board, October 2005.
Hausman E.D. and G. Keith, Calculating Displaced Emissions from Energy Efficiency ond
Renewoble Energy lnitiatives. Synapse Energy Economics for EPA website 2005
Rudkevich A., E.D. Hausman, R.D. Tabors, J. Bagnal and C Kopel, Loss Hedging Rights: A Finol
Piece in the LMP Puzzle. Hawaii lnternational Conference on System Sciences, Hawaii, January,
2005 (accepted/.
Hausman E.D. and R.D. Tabors,The Role of Demand Underscheduling in the Colifornia Energy
Crisis. Hawaii lnternational Conference on System Sciences, Hawaii, January 2004.
Case No. AVU-E-1 7-01 /AVU-G-1 7-01
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Hausman E.D. and M.B. McElroy, The reorgonizotion of the globol carbon cycle ot the lost
gl a ci o I te rm i n oti on. G loba I Biogeoch em ica I Cycles, 1 i (21, 37 1-38L, 1999.
Norton F.1., E.D. Hausman and M.B. McElroy, Hydrospherictransports, the oxygen isotope
record, and tropicolseo surfoce temperotures during the last glacial maximum.
Paleoceanography, 72, 75-22, L997 .
Hausman E.D. and M.B. McElroy, Variotions in the oceonic carbon cycle over glacioltronsitions:
a time-dependent box model simulation. Presented at the spring meeting of the American
Geophysical Union, San Francisco, 1995.
PRESENTATIONS AND WORKSHOPS
Americon Public Power Association: lnvited expert participant in APPA's roundtable discussion
of the current state of the RTO-operated electricity markets. October 2013.
Colifornia Long-Term Resource Adequocy Summit (Sponsored by the California ISO and the
California Public Utility Commission): Panelist on "Applying Alternative Models to the California
Market Construct." February 26, 2OL3.
ELCON 2077 Fail Workshop: "Do RTOs Need a Capacity Market?" October 2Ot7.
Horuord Electricity Policy Group: Presentation on state action to ensure reliability in the face of
capacity market failure. February 2OLL.
NASUCA 2070 Annuol Conference.'"Addressing Climate Change while Protecting Consumers."
November 2OLO.
NASUCA Consumer Protection Committee; Briefing on the Synapse report entitled, "Productive
and Unproductive Costs of COz Cap-and-Trade." September 2009.
NARUC 2OO9 Summer Meeting: lnvited speaker on topic: "Productive and Unproductive Costs
of CO2 Cap-and-Trade." July, 2009.
NASUCA 2(n8 Mid-Yeor Meeting: lnvited speaker on the topic, "Protecting Consumers
in a Warming World, Part ll: Deregulated Markets." June 2008.
Center lor Climote Strategies: Facilitator and expert analyst on state-level policy options for
mitigating greenhouse gas emissions. Serve as facilitator/expert for the Electricity Supply (ES)
and Residential, Commercial and lndustrial (RCl) Policy Working Groups in the states of
Colorado and South Carolina. 2OO7-2OO8.
NASUCA 2@7 Mid-Yeor Meetino: lnvited speaker on the topic, "Protecting Consumers
in a Warming World" June 2007.
ASHRAE Workshop on estimoting greenhouse gas emissions from buildings in the design
phose: Participant expert on estimating displaced emissions associated with energy efficiency in
building design. Also hired by ASHRAE to document and produce a report on the workshop.
April,2OO7.
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Assessing Restructured Electricity Morkets An American Public Power Associotion Symposium:
lnvited speaker on the history and effectiveness of Locational Marginal Pricing (LMP) in
northeastern United States electricity markets, February, 2OO7.
ASPO-USA 2006 Notionol Conference; lnvited speaker and panelist on the future role of LNG in
the U.S. naturalgas market, October, 2006.
Morket Design Working Group: Participant in FERC-sponsored settlement process for designing
capacity market structure for PJM on behalf of coalition of state utility consumer advocates,
July-August 2006.
NASUCA 2(N6 Mid-Yeor Meeting: lnvited speaker on the topic, "How Can Consumer Advocates
Deal with Soaring Energy Prices?" June 2006.
Soundwoters Forum, Stomford, C7; Participated in a debate on the need for proposed
Broadwater LNG terminal in Long lsland Sound, June 2006.
Energy Modeling Forum: Participant in coordinated academic exercise focused on modeling US
and world natural gas markets, December 2004.
Mossochusetts lnstitute of Technology (MlT): Guest lecturer in Technology and Policy Program
on electricity market structure, the LMP pricing system and risk hedging with FTRs. 2002-2005.
LMP: The Ultimate Hands-On Seminar. Two-day seminar held at various sites to explore
concepts of LMP pricing and congestion risk hedging, including lecture and market simulation
exercises. Custom seminars held for FERC staff, ERCOT staff, and various industry groups. 2003-
2004.
Learning to Live with Locotionol Marginal Pricing: Fundomentols ond Honds-On Simulation.
Day-long seminar including on-line mock electricity market and congestion rights auction,
December 2002.
LMP in Californio. Led a series of seminars on the introduction of LMP in the California
electricity market, including on-line market simulation exercise. 2OO2.
Resume updated June 2017
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED
CASE NO.: AVU-E-17-01 / AVU-G-17-01 WITNESS:
REQUESTER: Sierra Club RESPONDER:
TYPE: Production Request DEPARTMENT:
REQUEST NO.: Sierra Club-l-3 TELEPHONE:
Case No. AVU-E-1 7-01 /AVU-G-1 7-0 1
E. Hausman, Sierra Club
Page 1 of 8
08t23t20t7
Scott Kinney
Tom Dempsey
Thermal Operations
(so9) 495-4960
REQUEST:
Reference Exhibit No. 4 (Kinney), Schedule 3 pages 90-91. Section L 1 states: "The current
operator provides the annual business plan and capital budgets to the owner group every
September."
a. Provide the annual business plan and capital budgets for the past three years (2015 ,2016,2017).
b. Provide the 2018 business plan and capital budget when it is available next month.
c. Provide all "individual project summaries" related to the Colstrip 3&4 Capital Projects.
RESPONSE:
Please see Avista's response 1-3C, which contains TRADE SECRET, PROPRIETARY or
CONFIDENTIAL information and exempt from public view and is separately filed under
IDAPA 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code.
a. Avista is providing the Colstrrp 3&4 business plans and capital budgets for 2015, 2016, and
2017. See SC_PR_1-3C Confidential Attachments A-C. Please note, each business plan
received annually provides aS-year plan i.e.2015 business plan provides 2015-2019.
Therefore, outer years within the 5-year plan are updated annually with each subsequent year.
b. The Colstrip units 3&4 2Ol8 Business Plan and capital budget for 2018 will not be approved
and finalized until after November 1't.
c. Avista is providing project summaries for 2015, 2016 and 2017 Colstrip 3&4 capital projects
as requested. See SC_PR_I-3C Confidential Attachments D-J.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
Case No. AVU-E-1 7-01 /AVU-G-1 7-01
E. Hausman, Sierra Club
Page 2 of 8
JURTSDICTION:
CASE NO.:
REQUESTER:
TYPE:
REQUEST NO.:
IDAHO DATE PREPARED: 0812312017
AVU-E-17-01 / AVU-G-17-01 WITNESS: Scott Kinney
Sierra Club RESPONDER: Tom Dempsey
Production Request DEPARTMENT: Thermal OperationsSC-1-4 TELEPHONE: [phone]
REQUEST:
Reference Exhibit No. 4 (Kinney), Schedule 3 pages 90-91. Section 1.1 states: "Avista reviews
these individual projects."
a. Provide all documents, emails, communications, memos, or other internal company documents
related to Avista's review of the Colstrip 3&4 Capital Projects.
b. Describe in detail the review process, including the individuals who are responsible for review
and approval of the individual projects.
RESPONSE:
Please see Avista's response l-4C, which contains TRADE SECRET, PROPRIETARY or
CONFIDENTIAL information and exempt from public view and is separately filed under
IDAPA 31.01.01, Rule 067 and233, and Section 9-340D, Idaho Code.
Page I of I
Case No. AVU-E-1 7-01IAVU-G-1 7-01
E. Hausman, Sierra Club
Page 3 of 8
JURISDICTION
CASE NO.:
REQUESTER:
TYPE:
REQUEST NO.:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
IDAHO DATE PREPARED: 0812312017
AVU-E-17-01 / AVU-G-17-01 WTTNESS: Scott Kinney
Sierra Club RESPONDER: Tom Dempsey
Production Request DEPARTMENT: Thermal Operations
Sierra Club-l-5 TELEPHONE: [phone]
REQUEST:
RESPONSE:
Please see Avista's response 1-5C, which contains TRADE SECRET, PROPRIETARY or
CONFIDENTIAL information and exempt from public view and is separately filed under
IDAPA 31.01.01, Rule 067 and233, and Section 9-34OD,Idaho Code.
a. See SC_PR_I-5C Confidential Attachment A for the current Colstrip Ownership and
Operation Agreement.
b. The current Colstrip Ownership and Operation Agreement provided in question SC
l-5a was in effect at the time the projects included in Avista's application were
approved.
c. Engineering, equipment condition assessment, and all other daily operational activities
and capital planning are provided by Talen as operator of Colstrip 3&4. The following
is a general description of Talen's process:
After the first of a given year, Talen updates the existing capital plan to include projects
carried forward from a prior year. It also adds in all newly proposed capital projects
Page I of2
Reference Exhibit No.4 (Kinney), Schedule 3 pages 90-91. Section 1.1 states:
"Ultimately, the business plan is approved in accordance with the Ownership and Operation
Agreement for units 3&4 that six companies are party to."
a. Provide the currently applicable Ownership and Operation Agreement.
b. If different than (a), provide the Ownership and Operation Agreement in effect at the time the
Colstrip 3&4 Capital Projects at issue in Avista's application were approved by the owners.
c. Describe Avista's understanding of how the decision to include a capital project in the business
plan works in practice.
d. Did Avista raise any concerns or vote "no" on the Colstrip 3&4 Capital Projects at issue in this
application? If so, please provide any record of those objections or concerns.
e. Did any other Colstrip owner raise any concerns of vote "no" on the Colstrip 3&4 Capital
Projects at issue in this application? If so, please provide any record of those objections or
concerns.
f. Has Avista ever voted "no" or otherwise not approved an individual capital project? If so, please
describe when such a vote occurred and whether the capital project was ultimately included in the
business plan.
case No. AVU-E-1 7-o iAvu:c-l 7:o;
E. Hausman, Sierra Cltrb
that were not part of the prior year's 2 year projection. Talen's management team vets page 4 of 8
all ofthe projects to ensure that the projects that are included as proposed capital
projects are justified and prioritized and included based on a financial analysis or are
required for environmental, regulatory, or safety reasons.
d. Avista didn't vote "no" on any of the Colstrip 3&4 projects included in the rate case
application. With respect to projects occurring in 2018 and beyond, no such approval
process has started yet- with the exception of those projects that are multiyear projects
starting rn2017 or prior that continue on into 2018 and beyond.
e. As a matter of general practice, Avista does not maintain records of other companies'
voting positions.
f. Objection: Avista objects to this data request on the ground that it does not include
any defined timeframe and, therefore, the request is overly broad and unduly
burdensome. Without waiving its objections, Avista provides the following response
Avista doesn't maintain any formal documentation regarding previous individual
project approval discussions. If a project that Talen proposed was rejected by the
committee it would be eliminated from the budget. With respect to an instance where
Avista objected to a project that was ultimately included in the budget, we do not recall
an instance at this time.
Page2 of 2
Case No. AVU-E-1 7-01 /AVU-G-1 7-01
E. Hausman, Sierra Club
Page 5 of 8
JURISDICTION
CASE NO:
REQUESTER:
TYPE:
REQUEST NO.:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
IDAHO DATE PREPARED: 10/3112017
AVU-E-17-01/AVU-G-17-01 WITNESS: Scott Kinney
Sierra Club RESPONDER: Thomas Dempsey
Production Request DEPARTMENT: Thermal Operations
Sierra club - 3-6 supplemental 2 TELEPHONE: [phone]
REQUEST:
Reference Avista's response to SC 1-3, Confidential Attachment E, page 33 of 38
a. What is the construction and operation status of [confidential] ("Project ID LOO22I11")? If
it has not been completed, when (month and year) does Avista anticipate it will be
completed?
b. Please provide the dollar amount, if any, from ProjectlD 1002211 I that Avista included in
its rate base request in this proceeding AVU-E-17-01?
c. On what date does Avista anticipate Project ID lOO22l11 was or will be "used and
useful"?
d. The project description states: [confidential] What is the status of the [confidential]
referenced in this project authorization?
e. On what date did the [confidential] referenced by this document come into effect? If that
date has not yet occurred, what date does Avista anticipate they will come into effect?
f. Please provide all memos, reports, emails, or other documents prepared by, reviewed by, or
made available to Avista that support the conclusion that [confidential].
g. Please provide all memos, reports, emails, or other documents prepared by, reviewed by, or
made available to Avista between 2015 and today that discuss any changes to the
referenced [confidential] and/or the referenced [confi dential].
h. Please provide a narrative description of what Avista understands its regulatory obligations
are today that necessitate the installation of Project lD l0O22I1 l, including but not limited
to compliance deadlines and applicable emissions limits.
RESPONSE:
a. Project lD 10022111 has been completed and is in service.
b. This project was completed in June of 2016, included and approved in Avista' prior 2016
GRC (Case No. AVU-E-16-03), and is therefore currently included in base rates as of
January I,2017. Therefore this project is not included in the Company's current base
request in this proceeding. The total cost from Talen for this project is $1,993,516. This
total does not include any overheads incurred by Avista.
c. 613012016
Page I of3
Case No. AVU-E-1 7-01 /AVU'-G-1 7-Ol
E. Hausman, Sierra Clubd. The Region al Haze Program set a national goal of eliminating man-made visibility page 6 of 8
degradation in Class I areas by the year 2064. States are expected to take actions to make
"reasonable progress" to maintain the proper glide-path of pollutant reductions to achieve
the2064 goal. On September 18,2012, the EPA finalized the RegionalHaze federal
implementation plan (FIP) for Montana which included both emission limitations and
pollution controls for Colstrip Units 1 & 2.
Anticipating that Colstrip Units 3 & 4 could be ordered to install Selective Catalytic
Reduction (SCR) during the 2011 review period, the Colstrip Owners' proactively
installed the Smart Burn technology to reduce the formation of Nitrous Oxides (NOx) in
combustion zone for two major benefits:
Make proactive and verifiable NOx reductions and
Optimize the size, scope and ammonia use of any future SCR installation.
Colstrip Units 3 & 4 are currently being evaluated as part of the State of Montana Regional
Haze 5-Year Progress Report (please see:
ll2lPubl 7-2017 for more
information.
e. See answer to "d"
f. The following attachments are provided:
. SC_PR_3-6 Attachment A - PPL - PPL response letter to EPA dated Jan. 3l,20ll
to request for information (Nov. 5, 2010) for additional Reasonable Progress
information for Colstrip Units 3 & 4.
o SC_PR_3-6 Attachment B -Executive - NOx Control supplement to Attachment 2
of PPL.pdf . This attachment includes additional information in regards to NOx
provided by PPL.
o SC_PR_3-6 Attachment C -Earth J -Earth Justice, Montana Environmental
Information Center, Sierra Club and National Parks Conservation Association
comment letter to EPA dated August 22,2011
o SC_PR_3-6 Attachment D -Regional Haze - Colstrip Owners presentation to EPA
dated Nov. 1, 201I. SC_PR_3-6 Attachment E -Federal Reg - EPA issued the Federal Implementation
Plan (FIP) for Montana dated Sept. 18, 2012
o SC_PR_3-6 Attachment E -EPA - EPA issued general principles for next review
period for reasonable progress reports
The Company is in the process of searching for additional material and will supplement
this response with relevant information if and when available.
g. See "f'
h. See answer to "d"
SUPPLEMENTAL RESPONSE:
Please see Avista's response 3-6C, which contains TRADE SECRET, PROPRIETARY or
CONFIDENTIAL information and exempt from public view and is separately filed under
IDAPA 31.01.01, Rule 067 and233, and Section 9-340D, ldaho Code.
Page 2 of 3
Please see SC_PR_3-6C Supplemental Confidential Attachment A for additional material to part f.
Case No. AVU-E-1 7-01IAVU-G-1 7-01
E. Hausman, Sierra Club
Page 7 of 8SUPPLEMENTAL 2 RESPONSE:
Please see Avista's response 3-6C Supplemental 2, which contains TRADE SECRET,
PROPRIETARY or CONFIDENTIAL information and exempt from public view and is
separately filed under IDAPA 31.01.01, Rule 067 and 233, and Section 9-340D,Idaho Code.
The spreadsheet attachment to the email (Gordon Criswell to Tom Dempsey and others) was
inadvertently left out of the previous response (ICNU_PR_3-6C Supplemental). Please see
SC_PR_3-6C Supplemental2 Confidential Attachment A for additional material to part f.
Page 3 of 3
JURISDICTION
CASE NO:
REQUESTER:
TYPE:
REQUEST NO.:
IDAHO
AVU-E- 1 7-0 1/AVU-G- I 7-0 1
Sierra Club
Production Request
Sierra Club - 3-7
DATE PREPARED
WITNESS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
Case No. AVU-E-1 7-01IAVU-G-1 7-01
E. Hausman, Sierra Cl0b
Page 8 of 8
09122t20t7
Scott Kinney
Thomas Dempsey
Thermal Operations
(509) 49s-4960
REQUEST:
Reference Avista's response to SC 1-3, Confidential Attachment G, page 50 of 14
a. What is the construction and operation status of the ("Project lD 10023705")? If it has not
been completed, when (month and year) does Avista anticipate it will be completed?
b. Please provide the dollar amount, if any, from Project ID 10023705 that Avista included in
its rate base request in this proceeding AVU-E-17-01?
c. On what date does Avista anticipate Project ID 10023705 was or will be "used and
useful"?
d. Please provide a narrative description of what Avista understands its regulatory obligations
are today that necessitate the installation of Project ID 10023705, including but not limited
to compliance deadlines and applicable emissions limits.
e. Please provide all memos, reports, emails, or other documents prepared by, reviewed by, or
made available to Avista that support the conclusion that any regulation, statute, or other
requirement requires the installation of Project ID 10023705.
RESPONSE:
a. Project ID 10023705 has been completed and is in service.
b. The total project costs billed from Talen are $1,047,417. This total does not include any
overheads incurred by Avista.
c. 6130l17.
d. See the Company's response to SC_PR_3-6 (d).
e. See the Company's response to SC_PR_3-6 (d).
f. See Avista's response to SC_PR_3-6 (0
g. See Avista's response to SC_PR_3-6 (0
h. See the Company's response to SC_PR_3-6 (d).
-*,"1"^*a
oPoy'Case No. AVU-E-1 7-01IAVU-G-1 7-0
Federal Register/Vol. az, No. 6/Tuesday, January 70, 2077/Rules and RegulatioFs Hausman, Sierra Clul3078e 1 of ,
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Parts 51 and 52
IEPA-HO-OAR-201 5{)531 ; FRL-99s7-{s-
oARI
RtN 2060-A555
Protection of Visibility: Amendments
to Requirements for State Plans
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: The Environmental Protection
Agency (EPA) is finalizing revisions to
requirements under the Clean Air Act
(CAA) for state plans for protection of
visibility in mandatory Class I Federal
areas in order to continue steady
environmental progress while
addressing administrative aspects of the
program. In summary, the revisions
clarify the relationship between long-
term strategies and reasonable progress
goals (RPGs) in state implementation
plans (SIPs) and the long-term strategy
obligation of all states; clarify and
modify the requirements for periodic
comprehensive revisions of SIPs;
modify the set of days used to track
progress towards natural visibility
conditions to account for events such as
wildfires; provide states with additional
flexibility to address impacts on
visibility hom anthropogenic sources
outside the United States (U.S.) and
from certain types of prescribed fires;
modify certain requirements related to
the timing and form of progress reports;
and update, simplify and extend to all
states the provisions for reasonably
attributable visibility impairment, while
revoking most existing reasonably
attributable visibility impairment
federal implementation plans (FIPs).
The EPA also is making a one-time
adjustment to the due date for the next
periodic comprehensive SIP revisions
by extending the existing deadline of
|uly 31, 2018, to July 3L,2O21.
DATES: This final rule is effective on
fanuary "1O,2017.
ADDRESSES: The EPA established Docket
ID No. EPA-HQ-OAR-2015-0531 for
this action. All documents in the docket
are listed inthe http://
www.regulations. gov Web site. Although
Iisted in the index, some information is
not publicly available, e.g., Confidential
Business Information or other
information whose disclosure is
restricted by statute. Certain other
material, such as copyrighted material,
is not placed on the Internet and will be
publicly available only in hard copy.
Publicly available docket materials are
available electronically in http :/ /
vvvvw. re gu I at i o n s. gov.
FOR FURTHER INFORMATION CONTACT: FoT
general information regarding this rule,
contact Mr. Christopher Werner, Office
of Air Quality Planning and Standards,
U.S. Environmental Protection Agency,
by phone at [phone] or by email
at [e-mail],' or Ms,
Rhea Jones, Office of Air Quality
Planning and Standards, U.S.
Environmental Protection Agency, by
phone at [phone] or by email at
[e-mail].
SUPPLEMENTARY INFORMATION:
I. General Information
A. Preamble Glossary of Terms and
Acronyms
The following are abbreviations of
terms used in this document.
AQRV Air quality related value
BART Best available retrofit technology
b"*, Light extinction
CAA Clean Air Act
CFR Code of Federal Regulations
EGU Electric generating unitEPA EnvironmentalProtectionAgency
FIP Federal implementation plan
FLM or FLMs Federal Land Manager or
ManagersICR Information collection request
IMPROVE Interagency monitoring of
protected visual environments
NAAQS National Ambient Air Quality
StandardsNSR New Source ReviewNOx Nitrogen oxides
OMB Office of Management and BudgetPM Particulate matter
PMz.s Particulate matter equal to or less
than 2.5 microns in diameter (fine
particulate matter)
PMro Particulate matter equal to or less than
10 microns in diameter
PRA Paperwork Reduction Act
RHR Regional Haze Rule
RPG Reasonable progress goal
RPO Regionalplanningorganization
SIP State implementation plan
SOz Sulfur dioxideTAR Tribal Authority Rule
URP Uniform rate of progress
B. Entities Affected by This Rule
Entities potentially affected directly
by this rule include state, Iocal and
tribal 1 governments, as well as FLMs
I The EPA's visibility protection regulations may
apply, as appropriate under the Tribal Authority
Rule (TAR) in 40 CFR part 49, to an Indian tribe
that receives a detemination of eligibility for
treatment as a state for purposes of administering
a tribal visibility protection program under section
169,{ of the CAA. No tribe has applied for such
status, and so at present the EPA is responsible for
implementation of the visibiiity protection
regulations in areas of tribal authority. This
responsibility includes, but is not Iimited to,
implementation of the reasonable progress
requirements of 40 CFR 51.308(0, as necessary or
appropriate. These rule changes may impact the
responsible for protection ofvisibility in
mandatory Class I federal areas.2
Entities potentially affected indirectly
by this rule include owners and
operators of sources that emit
particulate matter equal to or less than
10 microns in diameter (PM,u),
particulate matter equal to or less than
2.5 microns in diameter (PMz s or fine
PM), sulfur dioxide (SOz), oxides of
nitrogen (NOx), volatile organic
compounds and other pollutants that
may cause or contribute to visibility
impairment. Others potentially affected
indirectly by this rule include members
of the general public who live, work or
recreate in mandatory Class I areas
affected by visibility impairment.
Because emission sources that
contribute to visibility impairment in
Class I areas also may contribute to air
pollution in other areas, members of the
general public may also be affected by
this rulemaking.
C. Obtaining a Copy of This Document
and Other Related Information
In addition to being available in the
docket, an electronic copy ofthis
Federal Register document will be
posted at http :/ /vvww. epa.gov /visibility.
A "track changes" version of the full
regulatory text that incorporates and
shows the full context of the changes in
this final action is also available in the
docket for this rulemaking. In addition
to the final and regulatory text
documents, other relevant documents
are located in the docket, including
technical support documents referenced
in this preamble.
development and approvability of tribal
implementation plans that tribes may wish to
submit in the future. We encourage states to provide
outreach and engage in discussions with tribes
about their regional haze SIPs as they are being
developed.
2 Areas designated as mandatory Class I Federal
areas consist of national parks exceeding 6,000
acres, wilderness areas and national memorial parks
exceeding 5,000 acres, and all international parks
that were in existence on August 7, 1977. CAA
section 162(a). In accordance with section 169,{ of
the CAA, the EPA, in consultation with the
Department of Interior, promulgated a list of 156
areas where visibility is identified as an important
value. 44 FR 69122 (November 30, 1979). The
extent of a mandatory Class I area includes
subsequent changes in boundaries, such as park
expansions. CAA section 162(a). Although states
and tribes may designate as Class I additional areas
that they consider to have visibility as an important
value, the requirements of the visibility program set
forth in section 169A of the CAA apply only to
"mandatory Class I Federal areas." Each mandatory
Class I Federal area is the responsibility of a
"Federal Land Manager." CAA section 302(i). When
we use the term "Class I area" in this action, we
mean any one of the 156 "mandatory Class I Federal
areas" where visibility has been identified as an
important value, unless the context makes it clear
that additional non-mandatory Federal Class I areas
are also meant to be included.
Case No. AVU-E-1 7-01 /AVU-G-1 7-0
Federal Register/Vol. eZ, No. 6/Tuesday, January 70, 2077/Rules and RegulatiorrEs Hau Ctut
tof ,2
D. ludicial Review
Under CAA section 307(b)(1), judicial
review ofthis final action is available
only by filing a petition for review in
the U.S. Court of Appeals for the District
of Columbia Circuit by March L3,201.7.
Under CAA section 307(dX7XB),
such judicial review is limited to
those objections that were raised
any
only
with
reasonable specificity in timely
comments. Filing a petition for
reconsideration by the Administrator of
this final rule does not affect the finality
of this action for purposes of judicial
review, extend the time in which a
petition for judicial review may be filed,
or postpone the effectiveness of the rule.
Under CAA section 307(bX2), the
requirements established by this final
rule may not be challenged separately in
any civil or criminal proceedings
brought by the EPA to enforce the
requirements.
E. Organization of This Fed.eral
Register Document
The information presented in this
document is organized as follows:
I. General Information
A. Preamble Glossary of Terms and
Acronyms
B. Entities Affected by This Rule
C. Obtaining a Copy of This Document and
Other Related Information
D. Judicial Review
E. Organization of This Federal Register
Document
F. Background on This Rulemaking
II. Executive Summary
III. Overview of Visibility Protection
Statutory Authority, Regulation and
Implementation
A. Visibility in Mandatory Class I Federal
Areas
B. Reasonably Attributable Visibility
Impairment
C. Regional Haze
D. Air Permitting
IV. Final Rule Revisions
A. Ongoing Litigation in Texos v. EPA
B, Cooperative Federalism
C. Clarifications To Reflect the EPA's Long-
Standing Interpretation of the
Relationship Between Long-Term
Strategies and Reasonable Progress Goals
D. Other Clarifications and Changes to
Requirements for Periodic
Comprehensive Revisions of
Implementation PIans
E. Changes to Definitions and Terminology
Related to How Days Are Selected for
Tracking Progress
F. Impacts on Visibility From
Anthropogenic Sources Outside the U.S.
G. Impacts on Visibility From Wildland
Fires
H. Clarification of and Changes to the
Required Content of Progress Reports
I. Changes to Reasonably Attributable
Visibility Impairment Provisions
J. Consistency Revisions Reiated to
Permitting of New and Modified Maior
Sources
K. Changes to FLM Consultation
Requirements
L. Extension ofNext Regional Haze SIP
Deadline From 2018 lo2027
M. Changes to Scheduling of Regional Haze
Progress Reports
N. Changes to the Requirement That
Regional Haze Progress Reports be SIP
Revisions
O. Changes to Requirements Related to the
Grand Canyon Visibility Transport
Commission
V. Environmental Justice Considerations
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act(UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
G. Executive Order 13045: Protection of
Children From Environmental Health
and Safety Risks
H. Executive Order 13211: Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution or Use
I. National Technology Transfer and
Advancement Act
J. Executive Order 12898: Federal Actions
To Address Environmental fustice in
Minority Populations and Low-lncome
Populations
K. Congressional Review Act (CRA)
VII. Statutory Authority
F. Background on This Rulemaking
On May 4,201,6, the EPA proposed
revisions to the 1999 Regional Haze
Rule (RHR),3 which include
clarifications and modifications to the
requirements that states (and, if
applicable, tribes) have to meet as they
implement programs for the protection
of visibility in mandatory Class I
Federal areas, under sections 169r{ and
1698 of the CAA. The EPA held public
hearings on May 19, 2016, in
Washington, DC and on lune 1, 2016, in
Denver, Colorado. States, industry,
private citizens and non-governmental
or8anizations submitted over 1"80,000
comments. Based on EPA's review of
the comments, we are finalizing most of
the proposed revisions, but are also
making some changes to respond to the
concerns raised by commenters. These
include: Changes to the proposed
terminology used to refer to emissions
inventories; changes to the proposed
definitions and terminology related to
3 Here and elsewhere in this document, the terms
"Regional Haze Rule," "1999 Regional Haze Rule"
and "1999 RHR" refer to the 1999 final rule (64 FR
35714), as amended in 2005 (70 FR 39156, July 6,
200s),2006 (71 FR 60631, October 13, 2006) and
2O"t2 (77 FR 33656, l\ae 7,2072).
how days are selected for tracking
progress; changes to the proposed fire-
related definitions and terminology;
changes to the proposed required
content of progress reports; changes to
the proposed deadline for a state
response to a reasonably attributable
visibility impairment certification; the
addition of a requirement for FLMs to
consult with states prior to making a
reasonably attributable visibility
impairment certification; and minor
changes to the requirements for FLM
consultation on SIPs and progress
reports. The EPA is issuing this final
rule under section 307(d) of the CAA.
Section 553(d) of the Administrative
Procedure Act (APA), 5 U.S.C. Chapter
5, generally provides that rules may not
take effect earlier than 30 days after they
are published in the Federal Register.
CAA section 307(dX1) clarifies that:
"The provisions of section 553 through
557 * * * of Title 5 shall not, except as
expressly provided in this section,
apply to actions to which this
subsection applies." Thus, section
553(d) of the APA does not apply to this
rule. The EPA has nevertheless
considered the purposes underlying
APA section 553(d) in making this rule
effective upon publication. The primary
purpose of the 30-day waiting period
prescribed in section 553(d) is to give
affected parties a reasonable time to
adjust their behavior and prepare before
the final rule takes effect. Notably, there
are no specific obligations in the first
thirty days ofthis regulatory action, and
all obligations are established as of a
date certain, rather than being tied to
the effective date.
In addition, section 553(d) allows an
effective date less than 30 days after
publication for a rule that "grants or
recognizes an exemption or relieves a
restriction." An important aspect of this
rule is the 3-year extension for state
planning obligations. This extension is
comparable to the grant of an exemption
or relief from a restriction because it
provides more time for states to meet a
regulatory requirement. It is thus
reasonable to make this action effective
upon publication because states do not
require an additional 30 days to adjust
their behavior and prepare for the rule
going into effect, and in fact will gain
additional time to meet their planning
obligations.
IL Executive Summary
The CAA's visibility protection
program, implemented through the rules
at 40 CFR s1.300 through 51.309, helps
to protect clear views in national parks,
such as Grand Canyon National Park,
and wilderness areas, such as the
Okefenokee National Wildlife Refuge.
Case No. AVU-E-1 7-01IAVU-G-1 7-0
3080 Federal Register/vol. sz, No. 6/Tuesday, January 10, 2017lRules and RegulatioFs Hausman':leJ:a3cJll
Vistas in these areas are often obscured
by visibility-impairing pollutants
caused by emissions from numerous
sources located over a wide geographic
area. States are required to submit
periodic plans demonstrating how they
have and will continue to make progress
towards achieving their visibility
improvement goals. The first state plans
were due in2Oo7 and covered the 2008-
2018 planning period.
The EPA is making changes to the
requirements that states (and, if
applicable, tribes) have to meet for the
second and subsequent implementation
periods as they develop programs for
the protection of visibility in mandatory
Class I areas, consistent with CAA
requirements. Imp lementation of the
EPA's RHR (during the first
implementation period) resulted in
significant reductions in emissions and
associated improvements in visibility in
many Class I areas (see Section III.B of
this document). This final rule supports
continued environmental progress by
retaining much of the 199S RHR,
clarifying or revising certain provisions
of the visibility protection rules in 40
CFR part 51, subpart P, and removing
rule provisions that have been
superseded by subsequent
developments. An overview of the
revisions is provided later, with
additional details throughout this
document.
The EPA is clarifying the relationship
between long-term strategies and RPGs
in state plans and the long-term strategy
obligations of aII states. We are re-
iterating that the CAA requires states to
consider the four statutory factors (costs
of compliance, time necessary for
compliance, energy and non-air quality
environmental impacts and remaining
useful life) in each implementation
period to determine the rate of progress
towards natural visibility conditions
that is reasonable for each Class I area.
The rate of progress in some Class I
areas may be meeting or exceeding the
uniform rate of progress (URP) that
would Iead to natural visibility
conditions by 2064, but this does not
excuse states from conducting the
required analysis and determining
whether additional progress would be
reasonable based on the four factors.
The EPA is revising the RHR to address
a number of issues, as discussed in the
proposal, including: The way in which
a set of days during each year is to be
selected for purposes of tracking
progress towards natural visibility
conditions; aspects of the requirements
for the content of progress reports;
updating, simplifying and extending to
all states the provisions for reasonably
attributable visibility impairment and
revoking FIPs adopted in the 1980s that
require the EPA to assess and address
any existing reasonably attributable
visibility impairment situations in some
states; and revising the requirement for
states to consult with FLMs. other
changes address administrative aspects
ofthe program in order to reduce
unnecessary burden. These include the
following: The EPA is finalizing a one-
time adjustment to the due date for the
next SIPs (from 2018 lo 202L); revising
the due dates for progress reports; and
changing the requirement that progress
reports be submitted as formal SIP
revisions to documents that need not
comply with the procedural
requirements of 40 CFR 51,.L02,40 CFR
51.103 and Appendix V to Part 51-
Criteria for Determining the
Completeness of PIan Submissions. All
of these changes apply to periodic
comprehensive state implementation
plans developed for the second and
subsequent implementation periods and
to progress reports submitted
subsequent to those plans. These
changes do not affect the development
and review of state plans for the first
implementation period or the first
progress reports due under the 1999
RHR.
The rationale for these changes is
described more fully in the descriptions
ofeach change detailed later in this
action as well as in the preamble to the
proposed rule.a The revisions being
finalized are informed by approximately
1.5 years of implementation of the CAA,
numerous outreach sessions and
stakeholder feedback regarding the
regional haze program, and the many
constructive comments we received on
the proposal. The clarifications
regarding the relationship between
RPGs, Iong-term strategies and the long-
term strategy obligation of all states are
intended to ensure appropriate and
consistent understanding of these
requirements as states prepare their
plans for the second implementation
period. These clarifications reflect
EPA's long-standing interpretation of
the RHR, and are now being codified.
The rule revisions related to how days
are selected for visibility progress
tracking will provide the public and
state officials more meaningful
information on how existing and
potential new emission reduction
measures are contributing or could
contribute to reasonable progress in
reducing man-made visibility
impairment. Changes to FLM
consultation requirements will help
ensure that the expertise and
perspective ofthese officials are brought
into the state plan development process
early enough that they can meaningfully
contribute to the state's deliberations.
Collectively, the changes being finalized
now will ensure that the regional haze
program is implemented consistent with
CAA obligations, and ensure successful
implementation during the second
planning period and beyond.
With regard to the extension of the
deadline of |uly 31.,201,8, to luly 31,
2O27, for states' comprehensive SIP
revisions for the second implementation
period, this one-time change will benefit
states by allowing them to obtain and
take into account information on the
effects of a number of other regulatory
programs that will be impacting sources
over the next several years, The change
will also allow states to develop SIP
revisions for the second implementation
period that are more integrated with
state planning for these other programs,
an advantage that was widely confirmed
in early discussions with states and in
comments submitted to the docket for
this rulemaking. We anticipate that this
change will result in greater
environmental progress than if planning
for these multiple programs were not as
well integrated. The end date for the
second implementation period remains
2O28, as was required by the 1999 RHR.
Other than the one-time change to the
next due date for periodic
comprehensive SIP revisions, no change
is being made for due dates for future
periodic comprehensive SIP revisions.
The changes related to progress
reports are intended to make the timing
of progress reports more useful as mid-
course reviews, to clarify the required
content of progress reports for aspects
on which there has been some
confusion, and to allow states to
conserve their administrative resources
and make submission of progress
reports more timely by removing the
requirement that they be submitted as
formal SIP revisions. We are retaining a
requirement that states consult with
FLMs on their progress reports, and that
states offer the public an opportunity to
comment on progress reports before
they are finalized, which are two of the
steps that applied to progress reports
when they were required to be SIP
revisions, and which will help ensure
ongoing accountability for progress
reports. Please note that while the
proposed rule included identical FLM
consultation periods for progress reports
and periodic comprehensive SIP
revisions, FLM consultation
requirements for SIP revisions and
progress reports will differ going
forward. This issue is described more
fully in Section IV.K of this document.4 81 FR 26942 (May a, 2016)
Federal Register/Vol. 82, No. 6/Tuesday, January 1O, 2O17lRules and RegulatioFs Ha Ctut
4of.
Case No. AVU-E-1 7-01IAVU-G-1 7-0
Finally, the 1999 RHR's provisions
related to reasonably attributable
visibility impairment required a
recurring process of assessment and
planning by the states. Experience since
these provisions were promulgated
suggests that situations involving
reasonably attributable visibility
impairment occur infrequently and
therefore that an "as needed" approach
for initiating a state planning obligation
would be a more efficient use of
resources. The EPA is finalizing its
proposal to replace the recurring
process of assessment of reasonably
attributable visibility impairment with
an as-needed approach. The change to
an as-needed approach only applies to
reasonably attributable visibility
impairment-periodic planning for
purposes ofregional haze will continue.
In addition, in light of our increased
understanding of the interstate nature of
visibility impairment, we are expanding
the applicability of the requirement to
address reasonably attributable visibility
impairment from only states with Class
I areas to all states. If a situation exists
or arises in which a source or a small
number of sources in a state without any
Class I area causes reasonably
attributable visibility impairment at a
Class I area in another state, this
mechanism will ensure adequate
visibility protection.
III. Overview of Visibility Protection
Statutory Authority, Regulation and
Implementation
A. Visibility in Mandatory Class I
Federal Areas
Reduction in visibility caused by
emissions of PMro, PMz s (e.g., sulfates,
nitrates, organic carbon, elemental
carbon and soil dust) and their
precursors (e.9., SO2, NOx and, in some
cases, ammonia and volatile organic
compounds) can take the form of either
visibly distinct layers or plumes of
pollution or more uniform "regional
haze." Fine particle precursors react in
the atmosphere to form PMz s, which
along with directly emitted PMro and
PMz s impairs visibility by scattering
and absorbing light. This light scattering
reduces the clarity, color and visible
distance that one can see. Particulate
matter can also cause serious health
effects in humans (including
death, heart attacks, irregular
premature
heartbeat,
aggravated asthma, decreased lung
function and increased respiratory
symptoms) and contribute to
environmental effects such as acid
deposition and eutrophication.
Data from the existing visibility
monitoring network, the "Interagency
Monitoring of Protected Visual
Environments" (IMPROVE) monitoring
network, show that at the time the RHR
was finalized in 1999, visibility
impairment caused by air pollution
occurred virtually all the time at most
national park and wilderness areas. The
formally defined average visual range 5
in many Class I areas in the western
U.S. was 62-93 miles. In some Class I
areas, these visual ranges may have been
impacted by natural wildfire and dust
episodes in addition to anthropogenic
impacts. In most of the eastern Class I
areas of the U.S., the average visual
range was less than 19 miles.6
Based on visibility data through 20t+,
the visual range has increased 10 to 20
miles (+ to 7 deciviews) 7 since the year
2000 in eastern Class I areas on the 20
percent haziest days. Some western
Class I areas have also experienced
visual range increases of 5 to 10 miles(t to + deciviews) on the 20 percent
haziest days. However, in some areas,
such as Sawtooth Wilderness area in
Idaho, improvements from reduced
emissions from man-made sources have
been overwhelmed by impacts from
wildfire and/or dust events. There are
also some western areas where visibility
has improved only by a slight amount
or made no progress.
B. Reasonably Attributable Visibility
Impairment
In section 16SA ofthe 1977
Amendments to the CAA, Congress
enacted a program for protecting
visibility in the nation's national parks,
wilderness areas and other Class I areas
due to their "great scenic importance." s
Section 16SA(a) of the CAA establishes
as a national goal the "prevention ofany
future, and the remedying of any
existing, impairment of visibility in
mandatory Class I Federal areas which
s Visual range is the greatest distance, in
kilometers or miles, at which a certain dark object
can be discerned against the sky by a typical
observer under certain defined conditions. Visual
range defined in this highly controlled manner is
inversely proportional to Iight extinction (b..J by
particles and gases and is calculated as: Visual
Range = 3.91/b..t (Bennett, M.G., The physical
conditions controlling visibility through the
atmosphere; Quarterly ]ournal of the Royal
Meteorological Society, 1930, 56, 1-29). Light
extinction has units of inverse distance (i.e., Mm - t
or inverse MeSameters (mega = 106)). Under
conditions other than those defined in this
reference, people's ability to discern landscape
features may vary and be different than implied by
the value of the visual range as calculated hom light
extinction using this formula.
o 64 FR 3s715 (fuly l, 1999).
7 The deciview haze index (discussed in more
detail in Section III.B.3 of this document) is
logarithmically related to light extinction and is
used by the regional haze program because it
describes uniform differences in visibility across a
range of visibility conditions.
I H.R. Rep. No. 294, 95th Cong. 1st Sess. at 205
('te77l.
impairment results from manmade air
pollution."
In 1980, the EPA promulgated
regulations to address visibility
impairment in Class I areas, including
but not limited to impairment that is
"reasonably attributable" to a single
source or small group of sources, i.e.,
"reasonably attributable visibility
impairment." s These regulations,
codified at 40 CFR 51.300 through
51.307, represented the first phase in
addressing visibility impairment from
existing sources. They also addressed
potential visibiiity impacts from new
and modified maior sources already
subject to permitting requirements for
purposes of protection of the National
Ambient Air Quality Standards
(NAAQS) and preventing significant
deterioration of air quality.
Notably, not all states were subject to
the 1980 reasonably attributable
visibility impairment requirements.
Under the 1980 rules, the 35 states and
one territory (Virgin Islands) containing
Class I areas were required to submit
SIPs addressing reasonably attributable
visibility impairment. The 1980 rules
required states to (1) develop, adopt,
implement and evaluate long-term
strategies for making reasonable
progress toward remedying existing and
preventing future impairment in the
mandatory Class I areas through their
SIP revisions; (2) adopt certain measures
to assess potential visibility impacts due
to new or modified maior stationary
sources, including measures to notify
FLMs of proposed new source permit
applications, and to consider visibility
analyses conducted by FLMs in their
new source permitting decisions; (3)
conduct visibility monitoring in
mandatory Class I areas, and (+) revise
their SIPs at 3-year intervals to assure
reasonable progress toward the national
visibility goal. In addition, the 1980
regulations provided that an FLM may
certify to a state at any time that
visibility impairment at a Class I area is
reasonably attributable to a single
source or a small number of sources.
Following such a certification by an
FLM, a state was required to address the
requirements for best available retrofit
technology (BART) for BART-eligible
sources considered to be contributing to
reasonably attributable visibility
impairment. AIso, the appropriate
control of any source certified by an
FLM, whether BART-eligible or not,
would be specifically addressed in the
Iong-term strategy for making reasonable
progress toward the national goal of
natural visibility conditions. See the
-nn,
FR ro*, (December 2, 1g8o).
cPo,Case No. AVU-E-1 7-01IAVU-G-1 7-01
E. Hausman, Sierra Club
Page 1 of 5
FEDERAL REGISTER
Vol. 81
No. 86
Wednesday,
May 4, 2016
Part lV
Environmental Protection Agency
40 CFR Parts 51 and 52
Protection of Visibility: Amendments to Requirements for State Plans;
Proposed Rule
Case No. AVU-E-1 7-01 /AVU-G-1 7-01
E. Hausman, Sierra Club26fJ42Federal Register/Vol. 8t, No. 86/Wednesday, May 4, 201,6/Proposed Rules 2of5
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Parts 51 and 52
lE PA-HO-OAR-2O1 5--0531 ; FRL-9935-27-
oARl
RrN 2060-A555
Protection of Visibility: Amendments
to Requirements for State Plans
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
SUMMARY: The Environmental Protection
Agency (EPA) is proposing amendments
to requirements under the Clean Air Act
(CAA) for state plans for protection of
visibility in mandatory Class I federal
areas (Class I areas) in order to continue
steady environmental progress while
addressing administrative aspects of the
program, The EPA amendments would
clarify the relationship between long-
term strategies and reasonable progress
goals in state plans, and the long-term
strategy obligation of all states. The
amendments would also change the way
in which some days during each year
are to be selected for purposes of
tracking progress towards natural
visibility conditions to account for
events such as wildfires; change aspects
of the requirements for the content of
progress reports; update, simplify and
extend to all states the provisions for
reasonably attributable visibility
impairment and revoke existing federal
implementation plans (FIPs) that require
the EPA to assess and address any
existing reasonably attributable
visibility impairment situations in some
states; and add a requirement for states
to consult with Federal Land Managers
(FLMs) earlier in the development of
state plans. The EPA also proposes to
address administrative aspects of the
program by making a one-time
adjustment to the due date for the next
state implementation plans (SIPs),
revising the due dates for progress
reports and removing the requirement
for progress reports to be SIP revisions.
DATES: Comments. Written comments
on this proposal must be received on or
before July 5,2016. Public hearing.The
EPA is holding a public hearing
concerning the proposed rule on May
19, 2016, in Washington, DC. The last
day to pre-register to speak at the
hearing is May 17 ,20L6. Please refer to
SUPPLEMENTARY INFORMAION foT
additional information on submitting
comments and the public hearing.
Informotion collection request. Under
the Paperwork Reduction Act (PRA),
comments on the information collection
provisions are best assured ofhaving
full effect if the Office of Management
and Budget (OMB) receives a copy of
your comments on or before June 3,
2016.
ADDRESSES: Comments: Submit your
comments, identified by Docket ID No.
EPA-HQ-OAR-2015-0531 , at http://
www.regulations.gov. Follow the online
instructions for submitting comments.
Once submitted, comments cannot be
edited or removed from Regulations.gov.
The EPA may publish any comment
received to its public docket. Do not
submit electronically any information
you consider to be Confidential
Business Information (CBI) or other
information whose disclosure is
restricted by statute. Multimedia
submissions (audio, video, etc.) must be
accompanied by a written comment.
The written comment is considered the
official comment and should include
discussion of all points you wish to
make. The EPA will generally not
consider comments or comment
contents located outside of the primary
submission (i.e., on the Web, Cloud, or
other file sharing system). For
additional submission methods, the full
EPA public comment policy,
information about CBI or multimedia
submissions and general guidance on
making effective comments, please visit
h tt p : / / vvvvw 2 . e p a. gov / d o c ket s /
comments.html. Public hearing: A
public hearing will be held at William
)efferson Clinton East building (WJC
East), Room L'117A, in Washington, DC.
Identification is required. If your
driver's license is issued by American
Samoa, Illinois or Missouri, you must
present an additional form of
identification to enter. Enhanced
driver's licenses hom Minnesota and
Washington are acceptable. Please refer
to SUPPLEMENTARY INFORMATION fOT
additional information on the public
hearing and location requirements.
FOR FURTHER INFORMATION CONTACT: FoT
general information on this proposed
rule and Information Collection Request
(ICR), contact Mr. Christopher Werner,
Office of Air Quality Planning and
Standards, U.S. Environmental
Protection Agency, by phone at (919)
541-5133 or by email at
werner. [e-mail]; or Ms.
Rhea fones, Office of Air Quality
Planning and Standards, U.S.
Environmental Protection Agency, by
phone at [phone] or by email at
[e-mail]. F or information on
the public hearing or to register to speak
at the hearing, contact Ms. Pamela Long,
Office of Air Quality Planning and
Standards, U.S. Environmental
Protection Agency, by phone at (919)
541-0641 or by email al long.pam@
epa.gov.
SUPPLEMENTARY INFORMATION :
I. General Information
A. Preamble Glossary of Terms and
Acronyms
The following are abbreviations of
terms used in this document.
AQRV Air quality related valueBART Best available retrofit technology
b.*, Light extinctionCAA Clean Air Act
CFR Code of Federal Regulations
EGU Electric generating unitEPA EnvironmentalProtectionAgencyFIP Federal implementation plan
FLM or FLMs Federal Land Manager or
ManagersICR Informationcollectionrequest
IMPROVE Interagency monitoring of
protected visual environmentsNAAQS National ambient air quality
standards
NO1 Nitrogen oxides
OMB Office of Management and Budget
PM Particulate matter
PMz.s Particulate matter equal to or less
than 2.5 microns in diameter (fine
particulate matter)
PMro Particulate matter equal to or less than
10 microns in diameterPRA Paperwork Reduction Act
PSD Prevention of significant deterioration
RPO RegionalplanningorganizationSIP State implementation plan
SOu Sulfur dioxideTAR Tribal Authority RuleURP Uniform rate of progress
B. Does this action apply to me?
Entities potentially affected directly
by this proposed rule include state,
Iocal and tribal r governments, as well
as FLMs responsible for protection of
visibility in mandatory Class I areas.
Entities potentially affected indirectly
by this proposed rule include owners
and operators of sources that emit
particulate matter equal to or less than
10 microns in diameter (PMto),
particulate matter equal to or less than
2.5 microns in diameter (PM2.5 or fine
1 The Regional Haze Rule may apply, as
appropriate under the Tribal Authority Rule (TAR)
in 40 CFR part 49, to an Indian tribe that receives
a determination of eligibility for treaknent as a state
for purposes of administering a tribal visibility
protection program under section 169A of the CAA.
No tribe has applied for such status, and so at
present the EPA is responsible for implementation
of the Regional Haze Rule in areas of tribal
authority. This responsibility includes, but is not
limited to, implementation of the reasonable
progress requirements of 40 CFR 51.308(0 in
instances where potentially affected sources are
Iocated on tribal land, as necessary or appropriate.
The proposed rule changes may impact the
development and approvability of tribal
implementation plans that tribes may wish to
develop in the future. We encourage states to
provide outreach and engage in discussions with
tribes about their regional haze SIPs as they are
being developed.
Federal Register/Vol. 81, No. 86/Wednesday, May 4, 2076lProposed Rules E. Haus Club
3of5
changes to maintain consistency with
other sections of the Regional Haze Rule
and with the CAA. The first change
involves S 5 1.307(b)(1) concerning
integral vistas, for which we are
proposing deletion of obsolete language
regarding the now-expired identification
period for integral vistas. Instead, the
newly proposed addition of a Iisting of
integral vistas in S 51.304(b) will be
referenced. In section S 51.307(b)(2), the
deletion of a reference to specific
sections of the CAA is proposed in order
to remove unnecessary Ianguage, as the
EPA believes a reference simply to
section "107(d)(1)" is sufficient.
L Changes to FLM Consultation
Requirements
The EPA believes that state
consultation with FLMs is a critical part
of the creation of quality SIPs. As
mentioned earlier, the EPA is proposing
to extend the FLM consultation
requirements of S 51.308(i)(2) to
progress reports that are not SIP
revisions. In addition, the EPA believes
further edits to S 51.308(i)(2) are
necessary because the current
requirement for consultation at least 60
days prior to a public hearing may not
occur sufficiently early in the state's
planning process to meaningfully
inform the state's development of the
long-term strategy. This proposed rule
change would add a requirement that
such consultation occur early enough to
allow the state time for full
consideration of FLM input, but no
fewer than 60 days prior to a public
hearing or other public comment
opportunity. A consultation opportunity
that takes place no less than 120 days
prior to a public hearing or other public
comment opportunity would be deemed
to have been "early enough."
Finally, the EPA notes that pursuant
to the existing provisions of S 51.307(a),
the SIP for every state must require the
new source permitting authority to
consult with FLMs regarding new
source review of any new major
stationary source or major modification
that would be constructed in an area
that is designated attainment or
unclassified that may affect visibility in
any Class I Federal area. As required by
the regulations, that consultation must
include sharing with the FLMs a copy
of all information relevant to the permit
application for the proposed new
stationary source or major modification.
The regulations also specify that this
material must be provided within
particular time frames. AIso, under
S 51.307(bX2), a proposed new maior
source or major modification locating in
a nonattainment area is subject to
review if it may have an impact on
visibility in any mandatory Class I area.
Two EPA guidance documents interpret
the consultation requirement,
particularly with regard to evaluating
whether a proposed new major source
or major modification may affect
visibility in a Class I area and thus
consultation is required.aT The EPA
regional offices can provide additional
assistance to states in ensuring that their
permitting programs meet the
regulations and that the appropriate
consultation is being conducted for
affected permits. No changes are being
proposed to these consultation
requirements.
l. Extension of Next Regional Haze SIP
Deadline From 201.8 to 2021
The EPA is proposing to amend
S 51.308(fl to move the compliance
deadline for the submission of the next
periodic comprehensive SIP revisions
from fuly 37,201,8, to July 31,,2021,.
Under this proposal, states would retain
the option of submitting their SIP
revisions before July 3L,202'1.
Regardless of the date on which a state
chooses to submit its periodic
comprehensive SIP revision, the EPA
would evaluate that SIP using the same
criteria. The EPA is proposing to leave
the end date for the second
implementation period at 2028,
regardless of when SIP revisions are
submitted. We are proposing this
change as a one-time schedule
adjustment. Periodic comprehensive SIP
revisions for the third planning will be
due on fuly 31, 2028, with future
periodic comprehensive SIP revisions
due every 10 years thereafter.
We are proposing this extension of the
due date for periodic comprehensive
SIP revisions to allow states to
coordinate regional haze planning with
other regulatory programs, including but
not Iimited to the Mercury and Air
Toxics Standards,as the 2010 1-hour
SO, NAAQS ,4e the 2OL2 annual PM2 5
NAAQS,So and the Clean Power Plan.sl
With this one-time extension, states
a7 New Source Review Workshop Manual-
Prevention of Significant Deterioration and
Nonattainment Area Permitting (Draft), October
1990, available at: https :/ / ww. epa.gov / sites /
pro d u ct i o n / fi I es / 2 O 1 5 -O 7 / d o cument s /
1990wman.pdf; and Appendix A of Timely
Processing of Prevention of Significant
Deterioration (PSD) Permits when EPA or a PSD-
Delegated Air ABency Issues the Permit, October
201 2, available al: http s : / /ww. e po.gov/ s ites /
productio n/ fi les / 2 0 1 5 -07 / do c uments / timely.p df .
48 77 FR 9304, February 16,2012.
4e 75 FR 35520, June 22, 2O1.O.
so 78 FR 3086, ]anuary 15, 2013.
s1 80 FR 64,662, October 23, 2015. The
compliance deadlines in the CIean Power Plan have
been stayed by the Supreme Court. Order in
Pending Case, West Virginia v. EP,{, No. 15A773
(Feb. 9, 2016).
would be able to gather more
information on the effects of these
programs and develop periodic
comprehensive SIP revisions that are
more integrated with state planning for
these other programs, an advantage that
was widely confirmed in our
discussions with states. The Regional
Haze Rule requires states to address the
impacts of other regulatory programs
when developing their regional haze
SIPs. A number of other regulatory
programs will be taking effect in the
coming years, which presents an
excellent opportunity for states to
coordinate their strategies to address
significant sources of emissions. The
EPA expects this cross-program
coordination to lead to better overall
policies and enhanced environmental
protection.
K. Changes to Scheduling of Regional
Haze Progress Reports
The EPA is proposing to amend the
requirements in 40 CFR 51.308(g) and
(h) regarding the timing of submission
of reports evaluating progress towards
the natural visibility goal. Under the
current rule, regional haze progress
reports are required to be submitted 5
years after submission of periodic
comprehensive SIP revisions. Because
states submitted these first SIP revisions
on dates spread across about a 3-year
period, many of the due dates for
progress reports currently do not fall
mid-way between the due dates for
periodic comprehensive SIP revisions,
as the EPA initially envisioned that they
would. Looking forward, the current
Regional Haze Rule would in many
cases require a progress report shortly
before or shortly after a periodic
comprehensive SIP revision, at which
time it could not be expected to have
much utility as a mid-course review of
environmental progress or much
incremental informational value for the
public compared to the data contained
in that SIP revision.
Complementing the proposed
amendments to 40 CFR 51.308(0
regarding the deadlines for submittal of
periodic comprehensive revisions, we
propose to amend 40 CFR 51.308 (g) and
(h) such that second and subsequent
progress reports would be due by
January 31,2025, July 31,2033, and
every 10 years thereafter, placing one
progress repoft mid-way between the
due dates for periodic comprehensive
SIP revisions. The EPA believes that this
timing provides a good balance between
allowing the implementation of the
most recent SIP revision to have
proceeded far enough since its adoption
for a review to be possible and
worthwhile and having enough time
Case No. AVU-E-1 7-01IAVU-G-1 7-01
remaining before the next
comprehensive SIP revision for state
action to make changes in its rules or
implementation efforts, if necessary,
separately from the actions in that next
SIP.
Regarding the concept of a progress
report also being useful at or near the
time of submission of a periodic
comprehensive SIP revision, as the EPA
envisioned in the 1999 Regional Haze
Rule, we note that although they are
expressed with somewhat different
terminology, in practical terms a
progress report would provide little
additional information beyond that
required to be addressed in a periodic
comprehensive SIP revision. The only
significant additional information
required in a progress report but not
explicitly required in a periodic
comprehensive SIP revision is the
requirement to report on the trend in
visibility over the whole period since
the baseline period of 2000-2004. While
the EPA believes that a state should be
aware of, and share with the public,
information on the trend in visibility
over the whole period since the baseline
period of 2ooo-2oo4, we believe it
would be inefficient to require the
preparation of a separate progress report
for this purpose. Therefore, we are
proposing to limit the requirement for
separate progress reports to the one due
mid-way between periodic
comprehensive SIP revisions, and to
add to the requirement for periodic
comprehensive SIP revisions a
requirement to include this trend
information. The EPA believes this
approach would substantially reduce
administrative burdens and make
progress reports of more informational
use to the public, with no attendant
reduction in environmental protection.
The EPA solicits comment on this and
any alternative approaches to progress
report scheduling.
L. Changes to the Requirement That
Regional Haze Progress Reports Be SIP
Revisions
The EPA is proposing to amend 40
CFR 51.308(g) regarding the
requirements for the form of progress
reports. Under the current regulations,
progress reports must take the form of
SIP revisions that comply with the
procedural requirements of 40 CFR
51.1"O2,40 CFR 51.103 and Appendix V
to Part 51-Criteria for Determining the
Completeness of PIan Submissions. The
EPA included the requirements for
progress reports in the Regional Haze
Rule primarily with an emphasis toward
ensuring that the states remain on track
during the 10 years between periodic
comprehensive SIP revisions. By
requiring progress reports to be in the
form of SIP revisions, the 1999 Regional
Haze Rule ensured an opportunity for
public input on the progress reports,
while specifically pointing out that the
EPA "intends for progress reports to
involve significantly less effort than a
comprehensive SIP revision." 64 FR
357a7 (fu|y 1, 1999). For all SIP
revisions, however, the state must
provide public notice and a public
hearing if requested, and it must
conform to certain administrative
procedural requirements and provide
various administrative material. AIso,
the submission must be made by an
official who is authorized by state law
to submit a SIP revision. As a required
SIP revision, a finding by the EPA that
a state has not submitted a complete
progress report by the deadline would
start a "clock" for the EPA to prepare,
take public comment on, and issue a
progress report like the state was
reouired to submit.
iV" ure proposing that progress
reports need not be in the form of SIP
revisions, but that states must consult
with FLMs and obtain public comment
on their progress reports before
submission to the EPA. We are also
proposing that the SIP revision that
would be due in 202'1, must include a
commitment to prepare and submit
these progress reports to the EPA
according to the proposed revised
schedule (see previous section). These
progress reports would be
acknowledged and assessed by the EPA,
but our review of these reports would
not result in a formal approval or
disapproval of them.
The EPA is proposing these changes
because it believes these reports are not
the kind of state submissions for which
the formality of a SIP revision, and the
accompanying requirement for the EPA
to have to prepare the report within 2
years of finding that a state has failed to
do so, are warranted. It is important to
note that as part of the EPA's review of
the report, we will follow up with the
state on any appropriate next steps.
There are also additional remedies, such
as undertaking a less formal assessment
of the results of the implementation of
the previously submitted SIP, that are
available to the EPA in the event a state
fails to properly submit a progress
report, These changes have been widely
supported by state air agencies in our
pre-proposal consultations because they
would allow more efficient use of state
resources. This option would relieve
states ofthe obligation to follow the
procedural requirements of 40 CFR
5L.L02 and 5t.103. States have
expressed concern that these procedural
requirements are resource-intensive,
and increase the burden on states by
requiring formal procedures be followed
when submitting progress reports. By
avoiding the specific formal steps
required for a SIP revision, including
requirements imposed by state law that
may involve time-consuming steps
beyond those required by the EPA, this
proposal may also reduce the time
between the completion of the technical
analysis in the progress report and when
the final report becomes available to the
EPA and the public. Thus, progress
reports could contain fresher
information on the environmental
progress being made by a state.
Removing the requirement that progress
reports be submitted as SIP revisions is
consistent with regulatory requirements
for similar reports from states for
progress reporting or planning purposes
where control requirements are not
imposed, such as annual monitoring
plans required for planning and
maintenance of state monitoring
networks.52
The EPA invites comment on whether
it should finalize this proposed change.
AIso, the EPA invites comment on
changing the progress report scheduling
as described in the previous section
without making any change to the
requirement that progress reports take
the form of SIP revisions, and vice
versa.
It is important to note that under this
option, states would still be required to
include the required progress report
elements listed in 40 CFR Sr.30B(gX1)
through (g)(6). Also, S 51.308(h) would
continue to require that at the same time
the state is required to submit a progress
report, it must also take one of four
listed actions concerning whether the
SIP is adequate to achieve established
goals for visibility improvement. Where
a state determines that its own SIP is or
may be inadequate to ensure reasonable
progress due to emissions from sources
within the state, the state will continue
to have an obligation to revise its SIP to
address the plan's deficiencies within 1
year of its submission of such a
determination.
Upon receipt of such progress reports,
the EPA would review the reports. In
addition, the EPA intends to create a
system of Iogging progress reports as
they are received, and making them
available to the public. In addition to
putting the public on notice that a
progress report was received by the
EPA, this system would provide the
public an opportunity to view the
contents of the progress report.
Although the EPA would not formally
approve or disapprove a progress report,
-Il-r" +o crR ss.1o(a)(1) and (2).
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the EPA would still have discretion to
assess the adequacy ofthe SIP, relying
in part on the information in the
progress report. Under the CAA, a
discretionary determination that the SIP
is inadequate would create a non-
discretionary duty for the EPA to issue
a SIP call requiring the state to correct
the inadequacy. A failure by the state to
submit a progress report could be
determined by the EPA to constitute
failure to implement the regional haze
SIP, given that we are proposing that
every regional haze SIP include a
commitment to submit the required
progress reports (see next paragraph),
We are proposing that the next
periodic comprehensive SIP revisions
(currently due in 2018 but proposed to
be due in 2021,) would need to include
a commitment for states to provide
progress reports. The 1999 Regional
Haze Rule does not require such a
commitment because the current
requirement for progress reports to be
submitted in the form of SIP revisions
makes such a commitment superfluous.
The EPA solicits comment on this or
alternative approaches to ensuring that
states continue to provide progress
reports.
M. Changes to Requirements Related to
the Grand Conyon Visibility Transport
Commission
Section 51.309 has limited
applicability going forward because its
provisions apply only to 16 Class I areas
covered by the Grand Canyon Visibility
Transport Commission Report, and only
to the first regional haze
implementation period (i.e., through
2018). Nevertheless, certain conforming
amendments at this time are appropriate
to avoid confusion going forward.
Section 51.309(dX4Xv) is proposed to be
amended to correctly refer to the new
S s1.302(b) (in lieu of (e), which no
Ionger exists in the proposed section
S 51.302) and to delete the reference to
BART since it does not appear in
S 51.302(b). The title of S 51.30e(cX10),
Periodic implementation plan revisions,
is proposed to be amended to include
"and progress reports" at the end. This
insertion would complement the
proposed amendments that will no
longer require progress reports be
considered SIP revisions by making
clear from the title ofthe section that it
applies to both SIP revisions and
progress reports. Within S 51.309(cX10),
amendments are proposed that would
preserve the existing requirement that
the progress reports due in 2013 were to
take the form of SIP revisions, but direct
the reader to the provisions of
$ 51.308(g) for subsequent progress
reports. In similar fashion,
S 51.30e(c)(10)(i) and (ii) would be
amended to specifically refer to the
2013 progress reports, while
S s1.309(c)(10)(iii) would point to
S 51.308(g) for subsequent progress
reports. Section 51.309(cXr0)(iv) is
proposed to be added to indicate that
subsequent progress reports are subiect
to the requirements of S 51.308(h)
regarding determinations of adequacy of
existing SIPs.
A final change in section 51.309
appears in S s1.309(gX2)(iii). This
change is purely to correct a
typographical error and the EPA will
therefore not consider comments on this
subsection.
V. Environmental fustice
Considerations
The EPA believes this action would
not have disproportionately high and
adverse human health, well-being or
environmental effects on minority, Iow-
income or indigenous populations
because it would not negatively affect
the level of protection provided to
human health, well-being or the
environment under the CAA's visibility
protection program. When promulgated,
these proposed regulations will revise
procedural and timing aspects of the SIP
requirements for visibility protection
but will not substantively change the
requirement that SIPs provide for
reasonable progress towards the goal of
natural visibility conditions. These SIP
requirements are designed to protect all
segments of the general population.
The EPA acknowledges that the
proposed delay in submitting SIP
revisions hom 2018 lo 2O2L might cause
delays in when sources must comply
with any new requirements. However,
because neither the CAA nor the
existing Regional Haze Rule set specific
deadlines for when sources must
comply with any new requirements in a
state's next periodic comprehensive SIP
revision, states have substantial
discretion in establishing reasonable
compliance deadlines for measures in
their SIPs. Given this, we expect to see
a range of compliance deadlines in the
next round ofregional haze SIPs hom
early in the second implementation
period Io 2O28, depending on the types
of measures adopted, whether or not
these proposed rule changes are
finalized. Thus, the EPA believes the
delay in the periodic comprehensive SIP
revision submission deadline from 2018
to 202L will not meaningfully reduce
the overall progress towards better
visibility made by the end of z02B and
will not meaningfully adversely affect
environmental protection for all general
segments of the population.
VI. Statutory and Executive Order
Reviews
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
This action is a significant regulatory
action that was submitted to the OMB
for review because it raises novel policy
issues. Any changes made in response
to OMB recommendations have been
documented in the docket.
B. Paperwork Reduction Act (PRA)
The information collection activities
in this proposed rule have been
submitted for approval to the OMB
under the PRA. The ICR document that
the EPA prepared has been assigned the
EPA ICR number 2540.O1,. OMB has
previously approved the information
collection activities contained in the
existing regulations and has assigned
OMB control number 2060-0421. You
can find a copy of the ICR in the docket
for this rule, and it is briefly
summarized here.
The EPA is proposing these
amendments to requirements for state
regional haze planning to change the
requirements that must be met by states
in developing regional haze SIPs,
periodic comprehensive SIP revisions,
and progress reports for regional haze.
The main intended effects of this
rulemaking are to provide states with
additional time to submit regional haze
plans for the second implementation
period and to provide states with an
improved schedule and process for
progress report submission. Further
reductions in burden on states include
this proposal's removal of the
requirement for progress reports to be
SIP revisions, clarifying that states are
not required to project emissions
inventories as part of preparing a
progress report, and relieving the state
of the need to review its visibility
monitoring strategy within the context
of the progress report. With all of these
proposed changes considered, the
overall burden on states would
represent a reduction compared to what
would otherwise occur if the provisions
of the current rule were to stay in place.
Total estimated burden is estimated to
be reduced from 10,307 hours (per year)
lo 5,974 hours (per year), and total
estimated cost is expected to be reduced
from $510,498 (per year) to $295,876
(per year). AII states are required to
submit regional haze SIPs and progress
reports under this rule.
Re spon d ents / affecte d e ntiti e s : All
state air agencies.
Respondent's obligation to respond :
Mandatory, in accordance with the
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FEDERAL REGISTER
Vol. 77
No. 1 81
Tuesday,
September 18, 2012
Part lll
Environmental Protection Agency
40 CFR Part 52
Approval and Promulgation of lmplementation Plans; State of Montana;
State lmplementation Plan and Regional Haze Federal lmplementation
Plan; Final Rules
r985
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ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 52
lE PA-R08-OAR-201 1 --08s1 , FR L 971 9-9I
Approval and Promulgation of
lmplementation Plans; State of
Montana; State Implementation Plan
and Regional Haze Federal
lmplementation Plan
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: The Environmental Protection
Agency (EPA) is promulgating a Federal
Implementation Plan (FIP) to address
regional haze in the State of Montana.
EPA developed this FIP in response to
the State's decision in 2006 to not
submit a regional haze State
Implementation Plan (SIP) revision. The
FIP satisfies requirements of the Clean
Air Act (CAA or "the Act") that require
states, or EPA in promulgating a FIP, to
assure reasonable progress towards the
national goal ofpreventing any future
and remedying any existing man-made
impairment of visibility in mandatory
Class I areas. In addition, EPA is
approving one of the revisions to the
Montana SIP submitted by the State of
Montana through the Montana
Department of Environmental Quality
on February 1,7, 201,2, specifically, the
revision to the Montana Visibility PIan
that includes amendments to the
"Smoke Management" section, which
adds a reference to Best Available
Control Technology (BACT) as the
visibility control measure for open
burning as currently administered
through the State's air quality permit
program. This change was made to meet
the requirements of the Regional Haze
Rule. EPA will act on the remaining
February 1,7, 201,2 revisions in the
State's submittal in a future action.
DATES: This final rule is effective
October 1,A,20L2.
ADDRESSES: EPA has established a
docket for this action under Docket ID
No. EPA-R0B-OAR-201 1-08s 1. All
documents in the docket are listed on
lhe www. re gul ation s. gov Web site,
Although listed in the index, some
information is not publicly available,
e.g., Confidential Business Information
(CBI) or other information whose
disclosure is restricted by statute.
Certain other material, such as
copyrighted material, is not placed on
the Internet and will be publicly
available only in hard copy form.
Publicly available docket materials are
available either electronically through
wvvw.regulations.gov, or in hard copy at
the Air Program, Environmental
Protection Agency (EPA), Region B,
1595 Wynkoop Street, Denver, Colorado
80202-1129. EPA requests that if at all
possible, you contact the individual
Iisted in the FOR FURTHER INFORMATION
CONTACT section to view the hard copy
of the docket. You may view the hard
copy ofthe docket Monday through
Friday, S a.m. to 4 p.m., excluding
Federal holidays.
FOR FURTHER INFORMATION CONTACT:
Scott fackson, Air Program, Mailcode
BP-AR, Environmental Protection
Agency, Region B, 1595 Wynkoop
Street, Denver, Colorado 80202-1,1,29,
[phone], or
lackson. Sc [e-mail].
SUPPLEMENTARY INFORMATION:
Definitions
For the purpose of this document, we
are giving meaning to certain words or
initials as follows:. The words or initials Act or CAA
mean or refer to the Clean Air Act,
unless the context indicates otherwise.o The initials A/F mean or refer to air-
to-fue1.. The initials AIM mean or refer to
Ammonia Limiting Method. The initials AIIM mean or refer to
Administrative Rule of Montana.. The initials ARP mean or refer to
the acid rain program.r The initials AfiS mean or refer to
Air Resources Specialists.r The initials ASOFA mean or refer to
advanced separated overfire air.r The initials BACT mean or refer to
Best Available Control Technology.
o The initials BA.RI mean or refer to
Best Available Retrofit Technology.o The initials CAA mean or refer to
the Clean Air Act.
o The initials CAM mean or refer to
compliance assurance monitoring.o The initials CAMDmean or refer to
EPA Ciean Air Markets Division.
o The initials CAMx mean or refer to
Comprehensive Air Quality Model.o The initials CBl mean or refer to
confidential business information.. The initials CCM mean or refer to
EPA Control Cost Manual.o The initials CCOFA mean or refer to
close-coupled overfire air system.o The initials CDS mean or refer to
circulating dry scrubber.
o The initials CGA mean or refer to
gas cylinder audit.. The initial s CELP mean or refer to
Colstrip Energy Limited Partnership.
o The initials CEMS mean or refer to
continuous emissions monitoring
systems.o The initials CEPCI mean or refer to
Chemical Engineering Plant Cost Index.
o The initials CFAC mean or refer to
Columbia Falls Aluminum Company.r The initials CFB mean or refer to
circulating fl uidized bed,o The initials CI(D mean or refer to
cement kiln dust.
o The initials CMAQ mean or refer to
Community Multi-Scale Air Qualitymodeling system.o The initials CPMS mean or refer to
continuous parametric monitoring
system.
o The initials CO mean or refer to
carbon monoxide.o The initials CPI mean or refer to
Consumer Price Index.
o The initials CRF mean or refer to
Capital Recovery Factor.o The initials CSAPfl mean or refer to
Cross-State Air Pollution Rule.o The initials DAA mean or refer to
Dry Absorbent Addition.. The initials DPCS mean or refer to
digital process control system.o The initials D-Il mean or refer to
Dresser-Rand.. The initials DSI mean or refer to dry
sorbent iniection.o The initials EC mean or refer to
elemental carbon.o The initials EGU mean or refer to
Electric Generating Units.o The words EPA, we, us or our mean
or refer to the United States
Environmental Protection Agency.r The initials ESP mean or refer to
electrostatic precipitator.
o The initials FCCU mean or refer to
fluid catalytic cracking unit.. The initials FGD mean or refer to
flue gas desulfurization.o The initials FGII mean or refer to
flue gas recirculation,
o The initials FlP mean or refer to
Federal Implementation Plan.o The initial s FLMs mean or refer to
Federal Land Managers.o The initial s HAR mean or refer to
hydrated ash reinjection.
o The initials HDSCfl mean or refer to
high-dust selective catalytic reduction.r The initials HC mean or refer to
hydrocarbons.. The initials g,r/scf mean or refer to
grains per standard cubic foot.. The initials IMPROVE mean or refer
to Interagency Monitoring of Protected
Visual Environments monitoring
network.o The initials lPM mean or refer to
Integrated Planning Model.r The initials IWAQM ref.er lo
Interagency Workgroup on Air Quality
Modeling.o The initials LDSCfi mean or refer to
low-dust selective catalytic reduction.. The initials LE4 mean or refer to
Iow excess air.o The initials LNBs mean or refer to
Iow NOx burners.
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. The initials ISD mean or refer to
lime spray drying.o The initials LSFO mean or refer to
limestone forced oxidation.o The initials ITS mean or refer to
Long-Term Strategy.o The initials MACT mean or refer to
maximum achievable control
technology.o The initial s MATB mean or refer to
Montanan's Against Toxic Burning.o The initials MDEQ mean or refer to
Montana's Department of
Environmental Quality.o The initials MDF mean or refer to
medium density fiberboard.o The initial-s ttttSO mean or refer to
Midwest Independent Transmission
System Operator.o The initials MD(J mean or refer to
Montana-Dakota Utilities Company.o The initials MEI mean magnesium-
enhanced lime.o The initials MKF mean or refer to
mid-kiln firing of solid fuel.r The words Montana and Sfofe mean
the State of Montana.o The initial s MSCC mean or refer to
Montana Sulphur and Chemical
Company.r The initials NAAQS mean or refer
to National Ambient Air Quality
Standards.o The initials NC mean or refer to
North Carolina.o The initials ND mean or refer to
North Dakota.o The initials NEI mean or refer to
National Emission Inventorv.o The initials NESHAP rnean or refer
to National Emission Standards for
Hazardous Air Pollutants.o The initials NH: mean or refer to
ammonia,o The initials NO; mean or refer to
nitrogen oxides.o The initials NP mean or refer to
National Park.o The initials NPS mean or refer to
National Parks Service.o The initials NSCfl mean or refer to
non-selective catalytic reduction.o The initials NSPS mean or refer to
New Source Performance Standards.o The initials NITR mean or refer to
National Wildlife Reserve.r The initials OMB mean or refer to
the Office of Management and Budget.o The initials OC mean or refer to
organic carbon.o The initials OFA mean or refer to
overfire air.o The initials PC mean or refer to
pulverized coal.o The initials PH/PC mean or refer to
preheater/precalciner.r The initials PM mean or refer to
particulate matter.o The initials PMz s mean or refer to
particulate matter with an aerodynamic
diameter of less than 2.5 micrometers
(fine particulate matter).o The initials PMto mean or refer to
particulate matter with an aerodynamic
diameter of less than 10 micrometers
(coarse particulate matter).o The initials PMCD mean or refer to
particulate matter control device.o The initials ppb mean or refer to
parts per billion.o The initials ppm mean or refer to
parts per million.o The initials PflB mean or refer to
Powder River Basin.r The initials PSA? mean or refer to
Particulate Matter Source
Apportionment Technology.r The initials PSD mean or refer to
Prevention of Significant Deterioration.o The fraction Q/D means quantity of
emissions over distance.. The initials RAA mean or refer to
relative accuracy audit.r The initial s RATA mean or refer to
relative accuracy test audit.o The initials IIAVI mean or refer to
Reasonably Attributable Visibility
Impairment.
o The initials flICE mean or refer to
Reciprocating Internal Combustion
Engines.. The initials RMC mean or refer to
Regional Modeling Center.o The initials ROFA mean or refer to
rotating opposed fire air.
o The initials IIP mean or refer to
Reasonable Progress.
o The initials fiPG or IIPGs mean or
refer to Reasonable Progress Goal(s).
o The initials ,RPOs mean or refer to
regional planning organizations.r The initials IIRI mean or refer to
rich reagent injection.
o The initials fiSCfl mean or refer to
regenerative selective catalytic
reduction.
o The initials SCOT mean or refer to
Shell Claus Off-Gas Treatment.. The initials SCII mean or refer to
selective catalytic reduction.o The initials SDA mean or refer to
spray dryer absorbers.o The initials SIP mean or refer to
State Implementation Plan.o The initials SMOKE mean or refer to
Sparse Matrix Operator Kernel
Emissions.
o The initials SNCfi mean or refer to
selective non-catalytic reduction.
o The initials Soz mean or refer to
sulfur dioxide.r The initials SOFA mean or refer to
separated overfire air.r The initials SflU mean or refer to
sulfur recovery unit.o The initials TAC mean or refer to
Texas Administrative Code.
o The initials ?ESCfi mean or refer to
tail-end selective catalytic reduction.
o The initials TCEQ mean or refer to
Texas Commission on Environmental
Quality.o The initials tpy mean tons per year.r The initials TSD mean or refer to
Technical Sripport Document.o The initials URP mean or refer to
Uniform Rate of Progress.o The initials USFWS mean or refer to
U.S. Fish and Wildlife Service.o The initials VOC mean or refer to
volatile organic compounds.r The initials WA mean or refer to
Wilderness Area.r The initials WEG mean or refer to
WildEarth Guardians.o The initials WEP mean or refer to
Weighted Emissions Potential.o The initials WETA mean or refer to
Western Environmental Trade
Association.o The initial s WRAP mean or refer to
the Western Regional Air Partnership.o The initial s YELP mean or refer to
Yellowstone Energy Limited
Partnership.
Table of Contents
I. Background
II. Basis for Our Final Action
III. Final Action
IV. Issues Raised by Commenters and EPA's
Responses
A. Comments on Modeling
B. General Comments on BART
C. Comments on Cement Kilns
D. Comments on Ash Grove
E. Comments on Holcim
F. Comments on CFAC
G. Comments on Colstrip Units 1 and 2
H. Comments on Corette
I. Comments on Reasonable Progress and
Long Term Strategy
J. Comments on Colstrip 3 and 4
K. Comments on Devon Energy
L. Comments on Montana Dakota Utilities
M. Comments on Montana Sulphur and
Chemical Company
N. Comments on Health, Ecosystem
Benefits, Other Pollutants, and Coal Ash
O. General Comments Supporting Our
Proposal or for Stricter Controls
P. General Comments That The Proposal Is
Too Stringent
Q. Comments on Visibility Improvement
and Other Causes of Haze
R. Comments on Cost, Economic Impact,
Jobs and Price to Consumers
S. Comments About Other Forms of Energy
T. Other Miscellaneous Comments
V. Changes From Proposed Rule and Reasons
for the Changes
A. Emission Limits for Corette
B. Changes to 40 CFR 52.1396(c)(2)-
Emission Limitations for Cement Kilns:
C. Change to 40 CFR s2.1396(d)-
Compliance date:
D. Change to 40 CFR s2.1396(eX3)-{EMS
for cement kilns:
E. Change to 40 CFR sz.rs96(ex+)(ii)-
Compliance determination methods for
SOz and NOx at cement kilns:
F. Change to 40 CFR 52.1396(f)(1) and(0(z)-{ompliance determinations for
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environmental impacts of compliance;
and remaining useful Iife of any
potentially affected sources. CAA
section r6sA(d(r) and 40 CFR
s1.308(dX1)(iXA). As also explained in
other responses, we also considered
potential visibility improvement in a
general sense by considering the
potential reduction in haze causing
pollutants and also the distance from
the source to the nearest Class I area.
For Colstrip 3 and 4, we also considered
visibility modeling results and have
explained the reasoning for that
decision in another response.
l. Comments on Colstrip Units 3 and 4
Comment: Some commenters agreed
with EPA's conclusion not to require
additional emissions controls at Colstrip
Units 3 and 4. Commenters asserted
that, given the aggressive pollution
control technologies already in place,
EPA properly concluded that additional
controls for Reasonable Progress are not
appropriate.
Response: We acknowledge the
commenters' support for our decision
not to require additional emission
controls on Colstrip Units 3 and 4 in
this planning period. Whether
additional emission reductions from
reasonable progress sources, including
Colstrip Units 3 and 4, are necessary
will be re-evaluated in subsequent
planning periods.
Comment: Various commenters stated
that we underestimated the costs of
SNCR for Colstrip Units 3 and 4.
Response: We disagree that we
underestimated the costs of SNCR for
Colstrip Unit 3 and 4. For a further
explanation, see our response to similar
comments made in relation to SNCR
costs for Colstrip Unit 1 and 2.
Comment: Commenters stated that
they disagree with EPA's cost analysis
for NOx control technologies for
Colstrip Units 3 and 4. In particular,
commenters stated that we
underestimated the capital costs and
cost-effectiveness of these controls.
Commenters referenced cost estimates
submitted by PPL in September 2011
and February 2012, which show much
higher capital costs and cost-
effectiveness than those estimated by
EPA.
Response: We disagree. We have
reiected PPL's cost estimates for NOx
control options for Colstrip Units 3 and
4 for the same reasons that we rejected
them for Colstrip Units 1 and 2. See
previous responses to comments.
Comment: NPS stated that EPA
modeled baseline visibility impacts at
five Class I areas from Colstrip Units 3
& 4 using 2008-2010 emissions, while
PPL modeled visibility impacts using
2001-2003 emissions. NPS agreed with
the PPL modeling approach because it is
consistent with EPA guidance to use the
2001-2003 pre-control emissions.
Response: See our response to a
similar comment made in regard to the
baseline emissions used for Colstrip
Units 1 and 2.
Comment: NPS stated that after EPA
concluded its statutory four-factor
analysis of Colstrip 3 and 4, it created
a new, "Optional Factor: Modeled
Visibility Impacts" fifth factor, only for
Colstrip 3 & 4. NPS further stated that
this "optional" fifth factor is not
required by statute or regulation, and
that EPA only used it on one reasonable
progress source (2 units) and did not
explain what criteria it used to evaluate
it.
Response: As we explained
elsewhere, our RP Guidance allows for
consideration of additional factors such
as visibility impacts or benefits. Given
the large annual emissions of NO1 and
SOz from Colstrip Units 3 and 4
compared to other reasonable progress
sources, we found that it was reasonable
to model the visibility benefits and
consider them when evaluating
controls.
Comment: NPS stated that EPA has
not provided criteria used in making the
determination of what "Costs of
Compliance" are reasonable, and its
determinations vary significantly across
Montana facilities.
Response: As we have explained
elsewhere, while the Regional Haze
Rule and BART Guidelines allow states
to establish thresholds for cost-
effectiveness, we are not required to do
so and have not done so for this action.
Also, our Reasonable Progress
determinations were made based not
just on the cost of compliance, but with
consideration of the four factors along
with additional information that was
pertinent.
Comment: Earthfustice stated that
EPA must set NOx emission limits for
Colstrip Units 3 and 4 based on SCR to
help achieve reasonable progress.
EarthJustice stated that EPA's analysis is
skewed to underestimate the benefits of
SCR, both in terms of control
effectiveness and visibility
improvement, and overestimates the
costs. EarthJustice made claims
regarding our cost analysis for Colstrip
Units 3 and 4 that were very similar to
the claims they made regarding Colstrip
Units L and 2.
Response We disagree. Below we
address each of EarthJustice's arguments
that support their assertion that SCR
must be required for Colstrip Units 3
and 4.
Comment: Earthlustice stated that
EPA underestimated the control
effectiveness of SCR.
Response: See our response to similar
comment made by EarthJustice in regard
to Colstrip Units 1 and 2.
Comment: Earthfustice stated that
EPA overestimated the cost of SCR.
Response: See our response to similar
comment made by Earthfustice in regard
to Colstrip Units 1 and 2.
Comment : EarthJustice claimed that
the visibility benefit of SCR on Units 3
and 4 is substantial and therefore SCR
should be required. EarthJustice noted
that EPA modeled visibility benefits of
SNCR and SCR and found a visibility
benefit of o.273 dv per unit from
application of SCR. EarthJustice stated
that application of SCR at both units
would approximately halve the units'
emissions of visibility impairing
pollutants and would reduce the
number of days of visibility impairment
at Theodore Roosevelt NP to iust 2 days
and would eliminate visibility
impairment caused by Units 3 and 4 at
four other CIass I areas. EarthJustice
stated that, in light of this, we lacked a
basis for our determination to not
impose SCR at Colstrip Units 3 and 4.
EarthJustice noted that, in North Dakota,
we imposed LNB on two units at
Antelope Valley Station based on a
combined visibility benefit of 0.39
deciview, which we stated was
significant even on a unit-by-unit basis
of 0.2 deciview.
Response: We disagree that SCR
should be required based solely on the
modeled visibility benefits. As we
explained in our proposal, we
considered the four factors and the
modeled visibility benefits of controls
and determined that no additional
controls should be required for this
planning period. 77 FR24066. Also, we
stated that specifically, for SCR, the
modeled visibility benefits (o.zz3
deciview and 0.260 deciview) were not
sufficient for us to consider it
reasonable to impose SCR in this
planning period. 77 FR 24066. In
making this determination, we noted
that SCR was the more expensive option
($+,szqlrcn at Unit 3 and $4,607/ton at
Unit 4). The cost of compliance is one
of the four statutory factors, and
EarthJustice has not provided a reason
why it should be ignored. For the same
reason, we reject the comparison with
our North Dakota action. There, the
cost-effectiveness of LNB at Antelope
Valley Station was $586/ton for Unit 1
and $66t/ton at Unit 2. 76 FR 58631.
We explicitly considered these costs in
making our determination to impose
LNB. Here, the cost-effectiveness of SCR
at Colstrip Units 3 and 4 is far above the
Case No. AVU-E-1 7-01 /AVU-G-1 7-01
Federal Register/Vo1.77, No. 181/Tuesday, September 18,2072/Rules and ReguEtiEfr$t'"8 Club
5of5
cost-effectiveness of LNB at Antelope
Valley Units 1 and 2. Thus, the
comparison gives us no basis to change
our determination that SCR should not
be required in this planning period.
Comment: EarthJustice stated that
EPA should set more stringent SO2
emission limits at Colstrip Units 3 and
4 to help achieve reasonable progress.
Earthfustice stated that EPA incorrectly
found that no additional upgrades are
feasible and that sB% SOz removal to
meet an SOz emission limit of 0.05 Ib/
MMBtu at Units 3 and 4, which is
readily achievable at little expense
using MEL.
Response: EarthJustice cites a 1.984
paper presented at the American Power
Conference to support their argument of
a lower emission rate. Colstrip 3 had
only started operation in 1984 and
Colstrip 4 did not commence operation
until 1986,6s the data cited by
Earthfustice cannot be more than short-
term tests of Unit 3 that are not
representative of Ionger term
performance. Annual emissions from
1985 and 1990 emissions from CAMD
can be found in the docket. At the time
these scrubbers were built, wet MEL
scrubbers and wet caustic scrubbers
were the only scrubbers that could
deliver high capture rates (over g0%)
with reasonable reliability. Scrubber
technology has improved and other, less
expensive, reagents are now preferred.
Although Colstrip Units 3 & 4 used MEL
in the past, MEL is not readily available
in the region near the Colstrip plant.
MEL is produced from a blending of
dolomitic lime with high calcium lime
to achieve a lime with a magnesium
content of 3-6% or so. The lime is
produced by calcination of limestone.
Dolomitic limestone is limestone with a
significant amount of dolomite, or
calcium magnesium carbonate. Because
there are no dolomitic limestone
deposits near the Colstrip plant, the
dolomitic lime must be sourced from
remote locations. This increases the cost
of the lime (that is made from the
dolomitic limestone). According to
Carmeuse, a supplier of MEL, the closest
source of dolomitic lime is 1,000 miles
away from the Colstrip plant and
transportation would cost $0.12 per
mile per short ton plus a 24% fuel
surcharge to transport,6a or close to
$150/short ton just for transportation of
the reagent. Because the lime would be
blended in closer to the plant with high
calcium lime at perhaps an B:1 ratio
(reducing magnesium content hom
about 40% to about a-5% this would
63 See EIA Form 860 data.
5a Email from Bob Roden, Carmeuse, to Jim
Staudt, Andover Technologies, July 31, 2012.
result in an increased reagent cost of
$15-S20 per ton. Assuming a high-
calcium lime cost of about $95/ton,65
this raises the cost of reagent by close
to zooh assuming constant reduction.
Reagent use might be improved
somewhat for a given reduction level,
but considering this is a unique
scrubber design, it is difficult to assess
what the impact may be. Regardless,
reliance on a reagent source that is 1,000
miles away may cause operating risks
during the winter months if delivery
was interrupted.
We also note that EarthJustice did not
provide site-specific cost information,
for us to evaluate MEL. The cost of
compliance is one of the factors
required to be considered by CAA
section 169,4'(g)(1) and 40 CFR
51.308(d)(1)(iXA). Based on all four
factors, we continue to find that the
Ievel of performance of the current SOz
removal system for Colstrip Units 3 and
4 is satisfactory for this planning cycle.
We will re-evaluate additional SOz
controls for Colstrip Units 3 and 4 in the
next planning cycle.
Comment: PPL stated that EPA
properly concluded that RPGs do not
require additional emissions controls on
Colstrip Units 3 and 4 and that existing
emissions controls at Units 3 and +
already limit emissions to levels below
the presumptive BART limit. PPL stated
that EPA's RP conclusion should not be
affected by EPA's ultimate
determination with respect to BART
requirements for Colstrip Units 1 and 2
and that no further controls are
warranted based on conclusions
regarding the extent of existing
emissions controls and the cost-
ineffectiveness of further controls.
Response: PPL did not provide
specific information for us to consider
in making a change to our FIP. In any
case, we have not required additional
controls for Colstrip Units 3 and 4 in
our final FIP.
K. Comments on Devon Energy
Comment: MDEQ stated that we failed
to provide information or analysis of
any visibility benefit that would result
from the application of NSCR for Devon
Energy. MDEQ suggested that we must
consider visibility benefits as part of the
Devon Energy reasonable progress
analysis, as the BART Guidelines
include evaluation of visibility impacts
"which would also appear to be
required under the reasonable progress
guidelines."
6s Sargent & Lundy, "lPM Model-Revisions to
Cost and Performance for APC Technologies, SDA
FGD Cost Development Methodology FINAL",
Prepared for US EPA, August 2010 see table 2.
Response: The four reasonable
progress factors are the costs of
compliance, the time necessary for
compliance, the energy and nonair
quality environmental impacts of
compliance, and the remaining useful
Iife ofany potentially affected sources
CAA section 169A(g)(r)and 40 CFR
51.308(dX1)(iXA). Our Reasonable
Progress Cuidance states: "In
determining reasonable progress, CAA
section 169,t(SX1) requires States to
take into consideration a number of
factors. However, you have flexibility in
how to take into consideration these
statutory factors and any other factors
that you have determined to be
relevant." oo As stated in our proposal at
77 FR24069, for Devon, we considered
Q/D and potential reductions in Q/D,which are relevant to the goal of the
Regional Haze Rule, improving
visibility.
Comment: MDEQ commented that
EPA should review the NOx limit for
Devon with respect to its averaging time
and compliance determining method for
practical enforceability.
Response: In the final FIP, we have
made changes to the language in 40 CFR
52.1396 to clarify the requirements for
Devon Energy.
L. Comments on Montana-Dakota
Utilities
Co mment : Montana-Dakota Utilities
(MDU) commented that the company
did not disagree with our Reasonable
Progress determination. MDU stated
that, for EPA's reference, paragraph 3 on
page 1 ofthe Sargent & Lundy IPM
model method document cautions as
follows with respect to the application
of the model to smaller units:
The costs for retrofitting a plant smaller
than 100 MW increase rapidly due to the
economy of size. The older units which
comprise a large proportion of the plants in
this range generally have more compact sites
with very short flue gas ducts running from
the boiler house to the chimney. Because of
the limited space, the SCR reactor and new
duct work can be expensive to design and
install. Additionally, the plants might not
have enough margins in the fans to overcome
the pressure drop due to the duct work
configuration and SCR reactor and therefore
new fans may be required.
MDU stated that Lewis & Clark
Station is a small, 52 MW net capacity
unit. In addition, MDU believes that the
fan margin is not present at Lewis &
Clark Unit 1. to overcome the pressure
drop as discussed in the Sargent &
Lundy guidance.
Response: MDU has not provided the
information that would be necessary for
66 Reasonable Progress Guidance, p. 5-1
STATE OF MONTANA
REGIONAT HAZE
5.YEAR PROGRESS REPORT
Montana Department
of Environmental Quality
Bry
/- ,r
a.L,d
,l r.d
AUGUST 2017
case No. AVU-E-1 7-o i/AVU-c-i 7:oi
E. Hausman, Sierra CIub
Page 2 of 22
Toble of Contents
EXECUTIVE SUMMARY
CHAPTERl. INTRODUCTION
CHAPTER 2. STATUS OF IMPLEMENTATION OF CONTROL MEASURES
I
1-1
2-l
2.1.7.
2.1.2.
2.1.i.
2.7.4.
2.1.5.
2.1.6.
Colstrip Steam Electric Stotion Units 7 ond 2 2-5
2-5
2-6
2-7
2-7
Ash Grove Cement
Oldcostle Cement
lmprovements at Other Sources Referenced in the Montono FIP
Bloine County #1 Compressor Station.....
ldoho.2.2.1.
2.2.2.
2.2.i.
2.2.4.
2.2.5.
3.2.1.
3.2.2.
3.2.3.
2-8
2-9
2-9
2-9
North Dokoto
Oreqon..............
South Dakoto....
Wyoming 2-10
2.3.1. Minor Source Permitting Progrom.
2.i.2. Prevention of Significont Deteriorotion
.................... 2_10
2.3.3. New Source Performance Stondords - 40 CFR Port 60 and Notionol Emission Stondards for Hozordous Air
Pollutants - 40 cFR Port 63.
2.3.4. Montano Smoke Monagement Program.......
..............2-11
..............2-17
2-12
2-122.3.5. Notionol Petroleum Refinery lnitiative
2.3.6. Federol Mobile Source Regulotions ................2-13
2.4.1. Mercury ond Air Toxics Rule 2-13
2-17
2.4.2. Revised Notionol Ambient Air Quolity Standords
2.5.1. Closure/Concellations & Deroting.
2.5.2. Montono Renewable Porcfolio Stondord.
........2-15
........2-17
CHAPTER 3. CHANGES IN EMISSIONS OF VISIBILITY-IMPAIRING POLLUTANTS 3-1
i.1.7. Emissions Reductions ot BART Focilities ............. .......3-2
l.)
Oxides of Nitrogen 3-5
3-7
3-8
4-1
Oxides of Sulfur.......
Porticulate Motter - Coorse ond Fine
()\
CHAPTER 4. VISIBILITY CONDITIONS AND TRENDS.
Data Com p lete ness.......4.1.1.
4.1.2.Review of Stote's Monitoring Strotegy
4-2
4-3
&l(
)
2i C\
.)
.,
Case No. AVU-E-1 7-01IAVU-G-1 7-01
E. Hausman, Sierra Club
Page 3 of 22
.\sst,ssrrr,r't op Visiittt,l"l'r (.t )Nl)I'n()\s vr INIPIIO\:L'. St't r,s
.\r,.rt.r'sls r lt' Wtt.nt.itui (l< lx't tttBL''fI( )\ ..,l, ti
4.3.1. lmpocts of Wildfire Contribution on Worst Visibility Doys 4-8
4.3.2. Visualizing Wildfire lmpocts in Montano.. ...............4-10
4.4...1-12
CHAPTER 5. SIGNIFICANT CHANGES IN ANTHROPOGENIC EMISSIONS POSSIBLY
TMPEDTNG PROGRESS.......... ................ 5-1
5.1.i. Comporison of Reported Emissions to Projected Emissions 5-2
5.2- ()n. ct (] rs Dr'-r-i,r.()1,\Iti\'f tx \I<ts'r-rr.\, NoRli{ D.lr,r lT.r,.rxt> Wt'<)tII\c}............................5-4
5.2.1. Montana 5-4
1.2
+..)
........1-4
5."3 llrttsstr )\s FRO}t Ix'r1;.Rx Vl l( )N it. Sr lUttc.t,.s ............5,8
Analysis of Weother Potterns ...............5-8
Anolysis of Neorby Conodian Sources........ ..............5-12
Contribution to Light Extinction at Medicine 1oke.............. ..........5-17
5.r+...5-20
CHAPTER 6. ASSESSMENT OF CURRENT STRATEGY ...................6-1
5.3.1.
s.i.2.
5.3.3.
Corr-t.L'stox...
6.1.
6.2.
6.3.
6.1.
6.5.
6.6.
6.7.
6.8.
VIsmlt.t'tv H-\s [\II,R( )\'t)D .\'t'.rt.t. Stt'ns ( )N 'l't Iii Blls't'D.lts
,\::'t't tnr )t)( )Gl::\t(. (.< t,rtt,< )NIiN'fS rlrVu I)rir:nli.-\strD
Ytstglt.t'tl'ir,\sN(vi l\tt,Rt)\'F.D.\Tltosl'SI'l"lis()N'tFrE\Xrons'r'l)rr-s..
\ r't L n u. [jrRrs \RE l)tu\-t\G []ip \IR\IF.NT ( )\ 'n lrl Wt lRs'r I) rvs .......
\\jtt.i>t,lnL,s Onscl:Rt' RLot-'c-'ttt )\s I\ ,\xTuR< )t,( )GE.\IC Irtp.rr-'t's ........
.\rl'rt nr )P( )(;F.\IC [:.rttsstt )\s \\'lLL cr lxt tr r.'r. 't r I DI:cRt,-\st: ................
Y ts tttn. r'tt' Irrp rc-rs lrn( )\t Isir:nx-r'rr( )\.\L SouRr-p.s....
Cr xr.t.ustoN: l)gtTitutN t'il( lr t lr ,\ot..r]t.' \(i\"
............6-1
................6-2
'"""""""' (r-3
.. ... ..... ...6-.1
. . .. .., .. 6,s
...............(t 7
................(, I
................6-8
APPENDIX A. MONTANA SMOKE MANAGEMENT PI-AN...... ..........A-1
APPENDIX B. EMISSION II{VENTORY DETAIL............... ..................B-1
APPENDIX C. DETAILED VISIBILITY ANALYSIS c-1
APPENDIX D. DOCUMENTATION OF FEDERAL I.AND MANAGER CONSULTATION &
PUBLIC NOTICE PROCESS .................. D-1
Case No. AVU-E-1 7-01IAVU-G -17 -01
E. Hausman, Sierra Club
Page 4 of 22
Chopter 2. Srarus oF IMeLEMENTATToN oF CorurnoL MEASURES
This chapter focuses on anthropogenic (manmade) emission sources. The following sections describe the
status of the control measures that were included in the Montana FIP to achieve reasonable progress goals
for visibiJity improvement at mandatory Federal Class I Areas in Montana and neighboring states.e Tide 40
of the Code of Federal Regulations (CFR), part 51.308(9)(1) requires "[a] description of the status of
implementauon of all measures included in the implementation plan for achieving" reasonable progress
goals at Class I Areas both within and outside the State that are influenced by emissions from Montana
soutces."'
In the Montana FIP, the Environmental Protection Agency (E,PA) relied upon the implementation of the
Best Available Retrofit Technology (BART) at select facilities. In addition, the Montana FIP relied on
continual emissions reductions over time resulting from both fedetal and state measures in existence at the
time the Montana FIP was developed. 'I'hese additional measures have contributed to an ongoing
reduction in emissions since the baseline period. They were taken into account in projecung an emissions
inventory fot the year 2078 to determine whether Montana was forecast to achieve reasonable progtess
during the initial implementation period."
In the years since 201.2,when the Montana FIP was ptomulgated, further reductions have occutted or will
occur through additional federal and state progtams not otherwise identified in the Montana IIIP, such as
pedodic updates to the National Ambient Ait Quality Standatds CI,JAAQS) and plant closutes. The status
and associated benefits of these regulations and activities are also discussed in this chapter.
2.1. Monlono's BART & Reosonoble Progress Meqsures
For cettain large industrial facilities that had the potential to contribute to visibility impairment, the
Regional Haze Rule (RHR) required states, tribes, or trPA to conduct an analysis to determine whether
additional pollution controls must be installed. Specifically, facilities were considered eligible for such
analysis if they (1) had the potential to emit 250 tons ^ year or more of a visibility-impairing pollutant, (2)
were in existence by August 7,7977, but wete not operating before August 7,1962, and (3) fell into one of
26 dtfferent source categoties, such as utility and rndustrial boilets, and large industdal plants like pulp
mills, refineries, and smelters.'2 Facilities that met these definitions were consideted to be "BART-eligible."
e EPA, Approval and Promulgation of Implementation Plans; State of N{ontana; Regional Haze Federal Implementation Plan,
Final Rule,77 Fed. Reg. 57863 (18 Sep.2012),See also: Proposed Rule at 77
Fed. Reg. 23987 (20 {pr.2012),
10 EP-\,40 CFR $ 51.308(9) (2016),
l1 N{arty Wolf and Paula Fields, Technical Nlemorandum ' Final, WRAP PRP18b Emissions Inventory - Revised Point and
Area Source Proiections (29 Apr. 2009, rev. 16 Oct. 2009),
12'Ihese source categories are listed in section 169AG)(7) of the federal Clean Air Act.
2-1
In the Montana FIP, EPA analyzed nine latge stationary sources determined to be BART-eligible. T'hese
BART-eligrble sources,listed in Table 2-1, included coal-fted electtic generattng units, refineries, cement
plants, and other large industrial facilities. 'Ihese sources are also mapped below.
Terrp 2-1. LIST or BART.ELIGIBLE SOunCeS IN MONTANA
Ash Grove Cement Company Portland Cement Plants
Cenex Harvest States Cooperatives, Laurel Refinery Petroleum Refineries
Columbia Falls Aluminum Company, LLC Primary Aluminum Ore Reduction Plants
ExxonMobil Refinery & Supply Company, Billings Refinery Petroleum Refineries
Montana Sulfur & Chemical Company Chemical Process Plants
Oldcastle Cement (formerly Holcim (US), lnc.)Portland Cement Plants
Smurfit-Stone Container Enterprises lnc., Missoula Mill Kraft Pulp Mills and Fossil Fuel Boilers of more than 250
million British Thermal Units hour Heat
Talen Energy- Colstrip Steam Electric Station Units 1 & 2 Fossil-Fuel Fired Steam Electric Plants of more than 250
PPL Montana, LLC)BTUs r hour Heat lnput
Case No. AVU-E-1 7-01 /AVU-G-1 7-01
E. Hausman, Sierra Club
Page 5 ol 22
Talen Energy -JE Corette Steam Electric Station
(formerly PPL Montana, LLC)
FIGURE 2-1. Mep oF MoNTANA BART-ELIGIBLE SoURCES
Fossil-Fuel Fired Steam Electric Plants of more than 250
BTUs per hour Heat lnput
BART-EIigible Source BART Source Category
Montana BART-Elioible Sources
! us r,.r, & Wtd[fe Setorce
f us rores sevce
f Natronal Park serrce
0 56 r10 220 Miles
o BARI Elrgible Soure
{ sutleato aant
lsn O,or"*Camenl
Oldca3lle Cenen,
Refincry
t t6 a
**
CHS - Lrurel
't'
minum Company
lumbi. Falls
r:{i::,}}
ExronMobRefin6ry
Monlana Sulohuril. anc Cnamriat
\-Z * rrrrn Ene,sy
-..P cotitilo Unrtr I & 2,"\' Talan EnarqtJE Cor.lt.
G
I
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case No AVU-E-1 7-o ifivU-c-l 7:o i
E. Hausman, Sierra CIub
Page6 of 22
EPA used air quality modeling conducted by the Western Regional Air Partnership (1MRAP) to estimate
daily visibility impacts above natural conditions at each Class I Area within 300 kilometers ftm), or about
186 miles, of these nine BART-eligible facilities. trPA used a threshold of 1.0 deciview of impact to
determine which sources "cause" and a threshold of 0.5 deciview of impact to determine which sources
"contribute" to visibility impairment. Following modeling, only five operating units were determined to
cause or contribute to visibility impairment and thus only these five were subject to BART.
The Montana FIP included BART determinations for these units, which resulted in new emissions limits
for emissions of visibility-impairing pollutants. The Montana FIP included emissions limits for Ash Gtove
Cement; Oldcasde Cement; Talen Energy Colstrip Steam Electric Station Units 1 and2; and Talen Energy
JE Corette Steam Electric Station. Not all of the facilities determined to be subject to BART were required
to install additional conttols for visibility-impaidng pollutants. According to the federal Clean Air Act, five
factors had to be considered in determining whether and what controls must be applied at each individual
facility. These factors included:
1) cost of the controls;
2) impact of controls on energy avarlability or ^ny non-air quality environmental impacts;
3) remaining useful life of the equipment to be controlled;
4) any existing pollution controls abeady in place; and
5) visibiJity improvement that would result from controlling the emissions.l3
In some cases, the minimal visibility improvement expected to result from the use of pollutant-specific
add-on controls did not justify proposing additional controls. Instead, EPA proposed emission limits that
could be met within the existing operation of the unit.to Prior to BART, many of these facilities had not
been subject to federal pollution control requirements for this particular set of pollutants.
Columbia Falls Alumrnum Company (CFAC) was determined to be subject to BART'; however, the faciJity
did not receive emission limits because it was not in operation at the time the Montana FIP was published
and is now permanendy closed. The JE Corette plant in Billings, a coal-fred electric generaung unit, was
also determined to be subject to BART and received BART limits. Howevet, the facility ceased operation
in April 201,5.In both of these cases, the coresponding Montana Afu Quality Permits (MAQP, have been
revoked. A sixth facility (Blaine County #1 Compressor Station) also received emission limits in the
Montana FIP. This facility was determined to be subject to reasonable progress controls, not BART.
However, as futther discussed below, the determination was in efror, and the source should not have
received emission limits.
Table 2-2 provides a summary of the BART emission limits, the corresponding control technology
prescribed in the Montana FIP, compliance dates, and the status of each control or limit.
r3 EPA,40 CFR 51.308(e) (2016),
r'r EPA,40 CFR 52.1396(c) (2016),
2-3
No. AVU-E-1 7-0 1 /AVU-G-17 -01
E. Hausmatt' Sierra Club
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Case No. AVU-E-1 7-01 /AVU-G-1 7-01
E. Hausman, Sierra Club
Page 8 of 22
The following sections provide further discussion of BART control technology and implementation status.
2.1.1. Co/strip Sfeom Flecfric Stofion Units I cnd 2
OnJune 9,2075, the United States Court of Appeals for the Ninth Circuit vacated the emission limits for
Talen Energy Colstrip Units 1 and2 (and Corette), after the court found the NO. and SOr limits to be
arbitary and capricious, and remanded the determination back to EPA.15 As of this submittal, EPA has
not yet acted on the remand. However, the plant operator did install separated ovetfte air controls on
Units 1 and2 and SmartBurnR technology on Unit 2before the original BART limits were vacated.
In the suiilner of 2076, an agreement was teached between Sierra Club and the owners of the Colstrip
facility. As part of the agreement, Colstrip Units 1 and 2 must shut down no later than July 1,2022. In
addition, the owners agreed that Units 1 and 2 would comply with the following NO. and SO, emission
limits until such time as the units cease operation:
o Unit 1 NO.limit - 0.45 lb/mmBtu (30-day rolling average)
o Unit 2 NO" iimit - 0.20Lb/mmBtu (30-day rolling average)
o Units 7 znd2 SOr limit - 0.40Ib/mmBtu (30-day rolling average)
This Consent Dectee is binding and, as such, these emission limits will continue to be beneficial for
emission reductions until such time as Colstrip Units 1 and 2 cease opetation, at which time all emissions
associated with these units will permanendy cease.'u Emission levels currendy being achieved by Colstrip
Units 1 and 2 are discussed in Chapter 3.
The BART limits fot the JE, Corette faciJity were also remanded under the same court proceeding as
discussed above. That remand howevet, has since been made moot by the shutdown of Corette and
demolition of the facility. The facility ceased opetation in April 2015 and it has been fully decommissioned
since that time.
2.1.2. JE Coretf e
2.1.3. Ash Grove Cemenf
The Montana FIP requited Ash Grove to achieve an SO, Iimit of no more than 1 1.5 lb/ton of clinker no
later than April 16, 2013, and a NO, hmit of no more than 8.0 lb/ton of clinker no later than October 18,
2017.The NO" limit was established assuming the application of Selective Noncatalytic Reduction (SNCR)
and low NO- burners. The facility installed an SNCR system and made modifications to the kiln burnets to
be able to meet the NO" limit.
Undet a Consent Dectee, initiated by EPA pursuant to violations of Sections 113(b) and 167 of the Clean
Air Acq Ash Gtove agteed to achieve a lower SO, limit at the Montana City Plant. Ash Grove also agteed
15 National Parks Conservation Association QJPCA) v. U.S. Environmental Protection Agency (E,PA), No. 12 73710, United
:Jil::,:Z'iXJil,i',.Ti*'i,:i:Hf .:TKfi1?)i cv 00032 Dr-c-rcr-, D \ron (2016).doc 316-1
?(
Case No. AVU-E-1 7-01 /AVU-G-1 7-01
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Page9 of22
to achieve the NO. limit on a fastet timeline, and determine a potentially more stringent NO" Iimit based
on process and control equipment optimization. The setdement required the facility to achieve an SO,
limit of no more than 2.0\b/ton (30-day rolling avetage), required by April 8,2015 (described as the 21,0th
day after September 10,2074),andaninitial NO.limit of no more than 8.0lb/ton (30-day rolling average),
tequired 30 days after September 10.17
Following the process optimization requirements contafuied in Appendix A of the Consent Decree, Ash
Gtove demonstrated the ability to meet an even lower NO* emission limit of 7 .5lb/ton.t8 This permit
Iimit was frnahzed by EPA on December 29,2076, when EPA issued an acceptance letter for an Ash
Grove Demonsffation Report, which had been submitted by Ash Grove to EPA on August 25,2076.1e
This new limit is now in effect and is in the process of being added to Ash Grove's Title V permit.
Although not specifically tequired by the Consent Dectee, Ash Grove installed baghouse control
technology on the kiln exhaust to comply with the Portland cement manufacturing industry National
Emission Standards for Hazardous Air Pollutants OiESHAP) filterable particulate limit of 0.07 lb/ton of
clinker @ased on a 30-day rolling average dudng kiln operation).
Ash Grove is currendy achieving emission levels below limits from the BART determination. The
associated emission reductions are presented in Chapter 3.
2.1.4. Oldcosfle Cemenl
Oldcastle is currendy meeting both the PM and the SO, emissions limits. The facility has engaged a
design/build contractor for the application of SNCR to achieve the NO. limit, and has been pteparing to
commission and optimize the system before the limit becomes effective on October 78,201,7. A plant
shutdown occurred in April 2077 to complete the SNCR installation. As of the drafting of this report,
Oldcasde is in the process of integratrng the system into the plant's control system and optimizing
performance.
The facility entered talks with EPA in mid-2016 to revisit the BARI'determination based on a request
submitted to the Acting Air Ditector of EPA Region 8. Oldcasde expressed coflcerns to L,PA that the
original NO. limit of 6.5|b/ton of clinker may not be able to be achieved consistently, particularly without
a visible detached plume at the site.2(' Based on past experience, the faciliry expressed that any visible
plume ftom the site is likely to cause significant concem from area residents. As part of the request to
IIPA, Oldcasde prepared a revised BART analysis in which the facility requested a revised NO, Iimit of 8.3
17 Consent Decree, United States v. Ash Grove Cement Company, No. 2:13-cv-02299-JTl'I-DJW, D. Kan. (2013), doc.27 as
amended by doc. 28,
r8 Department of Justice, N{ontana City NOx Demonstration Report and Data, No. 90-5-2-1 08221 Ash Grove Cement Co (25
Aug 2016 approved 29 Deo2016).
le Ibid.
20 In the manufacture of Pordand cement, clinket occurs as lumps or nodules, usually 3 millimetres (0.12 in) to 25 millimetres
(0.98 in) in diameter, are produced by sintering (fusing together without melting to the point of liquefaction) limestone and
alumino-sii-icate materials such as clay during the cement kiln stage.
2-6
lb/ton of clinker. EPA reviewed the submitted information and, on April 14, 2017, published a proposed
tevision to the Montana FIP raising the Oldcastle NO.limit from 6.5 to 7.6\b/ton of clinker."
2.1.5. EJcine Counfy #! Ccrnpresso,'Sfcsticn
At the time of the Montana FIP, the Blaine County #1 Compressot Station was operated by Devon
Energy (Devon) and is now operated by Northwestern Energy. In2072, Devon provided comments to
EPA on the Montana FIP limits and four-factor analysis. In setting the Reasonable Ptogress portion of the
Montana FIP, a Q/D analysis threshold calculation was made. In this analysis, Q represents the actual
total tons of NO. and SOr, and D is the distance in kilometers from the facility to the nearest Class I Area.
In the calculation used by EPA's contractor, a distance of 707 kilometets was used for the Blaine County
factltty, when in fact the distance to the nearest Class I Area is 133 kilometers. This correction would drop
the calculated value to a Q/D of 8.7, well below the screening threshold of 10 used in the Montana FIP.
The proper calculation would have prevented inclusion of the Blaine County #1 Compressor Station in
the Montana FIP.
Additionally, the EPA contractor used emission levels ftom the 2002EPA National Emission Inventory.
Devon Energy has atgued thatyear2002 data was not teptesentative of cutrent conditions and over-stated
the emissions, further inflating the Q/D calculation. Further, while the original engines were rich-burn
engines, they were converted to lean-burn engines in the 1990s. Therefore, the Reasonable Progress
determination of nonselective catalytic reduction (NSCR) for engines that are actually lean-burn is not
technically feasible.
In the Apd 14, 2017,proposed revision to the Montana FIP, discussed above, EPA corrected the errors
related to the Blaine Counry #1 Compressor Station. Should the tule be finalized as proposed, the facility
would no longer be subject to the NO* emission Limit of 21..8Lb/hr.
2.i 5.l,rnpro,/einents cl' '-iilre,'.io,Jrces Referenceo in tb,e Mcnioac !iL)
As discussed above, the main control measure included in the Montana FIP was the application of BART
atlarge facilities where retrofit technology was expected to result in reductions of visibility-impairing
emissions. However, by definition, only a narrow set of sources were considered "BART-eligrble" and, of
those eligible sources, only a handful were evefltually given emission limits. The same is true of Reasonable
Progress sources, of several that were analyzed in the Montana FIP, only the Blaine County #1
Compressor Station was presctibed emission lirnits. The group of sources fot which the Montana FIP
analysis did not result in emission limits includes the following:
o CHS, Laurel Refinery
o Colstrip Energy limited Partnership
o Colstrip Steam Electric Station, Unit 3
o Colstrip Steam Electric Station, Unit 4
o Columbia Falls Aluminum Company
r ExxonNfobil, Billings Refinery
o Nfontana Dakota Utilities Levris & Clark Station
o N{ontana Sulfur & Chemical Company
r Plum Creek \Ianufacturing
o Roseburg Forest Products
r Smurfit.StoneContainer
o Yellowstone Energy Limited Partnership
Case No. AVU-E-1 7-01 /AVU-G-1 7-01
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Page 10 of 22
2r EPA, Approval and Promulgation of Air Quality Implementation Plans; N{ontana; Regional Haze Federal Implementation
Plan, Proposed Rule, 82 Fed. Reg. 17948 (14 Apr. 2017),
)1
Case No. AVU-E-1 7-01IAVU-G-1 7-01
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It would be a mistake to assume that, in the absence of regulatory emission limits in the Montana FIP,
these remaining sources have not installed controls ot improved efficiency over the yeats since the
Montana FIP was promulgated. Notable emissions-reducing improvements include the installation of
SmartBurnrt NO* reduction technology on Units 3 and 4 at the Colstrip Steam Electric Station tn 201,6 and
2017, respectively. According to faciJity operatot Talen Energy, these new controls are expected to
improve NO* removal from 80% to 86o/o.22
In addition, although the Montana FIP did flot set reasonable progress emission limits for Montana-
Dakota Utilities (l\4DU) Lewis & Clark Stadon, a coal-fued power plant located in Sidney, MT, the facihty
was upgraded in eady 2076 to comply with other fedetal and state regulations. Upgrades included a mist
eliminator retrofit and installation of sieve trays to reduce filterable PM, which also tesulted in a significant
reduction in SO, emissions."
2.2. Adjocent Stotes' BART lmplementotion
In addition to emission reductions at Montana faciJities, reductions of emissions in neighboring states may
affect visibility in Montana. The following summaries briefly discuss implementation of BART controls in
other states in the region.
2.2.1 . ldoho
Idaho has five (5) Class I Areas, including Hells Canyon Wilderness, Craters of the Moon Wildemess,
Sawtooth Wilderness, and two that are shared with Montana: Selway-Bitterroot Wilderness and
Yellowstone Nauonal Park. Accotding to Idaho's Regional Haze documentation, Idaho had one BART
source, Amalgamated Sugar Company, LI-C GASCO Riley Boilet located in Nampa, Idaho), which was
required to install new emission controls by July 22,2076.24 This faciJity was required to install and operate
low NO- burners after it was determined that Selective Catalyttc Reduction (SCR) was not technically
feasible for the specific process at this facility. There are also two other boilers at this faciJity referred to as
B&!7 Boilers 1. and 2 that also ended up as part of a BART Alternative Conffols option that resulted in a
combined NO.limit for the three boilers. The initial performance test for the new BART limits was
required by December 20,2016.
As part of the BART determination, three non-BART pulp dryers were also shut down at the facility in an
effort to provide the necessary SOrreductions. The rationale behind this is that the approach ptovided
mote improvement in visibility than otherwise would have occutred from the original BART
determination. A second facility in Soda Springs, Idaho, went through a BART analysis but EPA
determined that no additional conftol was requited.
22 Conversation with Gordon Criswell, Environmental and Compliance Director for T'alen Energy (1 1 NIay 2017).
23 Correspondence with the facility (30 May 2017).
2r Idaho Department of Environmental Quality, "Regonal HzzePlzn" (8 Oct.2010),
2-8
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2.2.2. Norfh Dokofo
North Dakota has two Class I Ateas, including the Lostwood \Wilderness and Theodore Roosevelt
National Park, each located in the westem third of the state. To make visibility progress during the frst
implementation period, North Dakota primarily relied on NO. and SO, emission reductions resulting
from controls at existing electric generating units (EGUs). These controls include BART at Coal Creek
Station (2 units), Leland Olds Station (2 units), Milton R. Young Station (2 units), and Stanton Station, as
well as Reasonable Progress controls at Antelope Valley Station (2 units), Coyote Station, and R.M.
Heskett Station.'s The BART emission limits were required to be met by no later than May 7,2077 . On
April6, 201,2,8P1' took action to partially approve and patially disapprove the state's Regional Haze SIP
and finahze a FIP addressing disapproved portions.2t' On September 23,2073, the U.S. Court of Appeals
for the 8'h Circuit ruled that EPA's refusal to consider the existing pollution control technology at the Coal
Cteek Station was arbitrary and capricio.s." Th" court vacated the FIP requiring SNCR at the facility.
2.2.3 Oregon
Oregon has twelve mandatory Class I Areas. Accotding to the Regional Hazel)pdate Plan for Oregon, a
total of five facilities were impacted by BART determinations. Four facilities chose the option of a
fedetally enforceable permrt condition exempting them from BART determinations by reducing visibility
impacts below 0.5 deciviews. The PGE Boardman (Boardman) faciJity BART determination tequired
controls and must cease burning coal by December 31, 2020. Boardman completed installation of BART
SOz controls consistingof a semi-dry flue gas desulfurization system in early 2074 and is requited to
futther reduce SO, emissions in 2018.2' Boardman is being evaluated to run on biomass so its fufure
emissions are uncertain.
2.2.4. Soufh Dakofa
EPA approved South Dakota's Regional Haze State Implementation Plan on April 26,201,2. South Dakota
is home to two of the nation's 156 mandatory federal Class I Areas: Badlands National Park and the Wind
Dave National Park. Each is located in the southwest corner of South Dakota. South Dakota has only one
BART source, which is the Big Stone I coal-fued power plant located in the northeastern corner of South
Dakota. Air pollution controls and limits for this source, established under the BART detetmination, must
be installed and implemented within five years of EPA's approval of South Dakota's Regional Haze SIP
(ApriI26,2017).
The BART detetmination made n2010 requited selective catalyttc reduction (SCR) and separated over-
Ftre at for NO* control, a dry flue gas desulfurrzatton system for SO, control, and a fabic filtet for PM
25 State of North Dakota, "Regronal llaze State Implementation Plan Periodic Progress Report" [at 2015).
26 EPA, Approval and Promulgation of Implementation Plans; North Dakota; Regronal Haze State Implementation Plan;
Federal Implementation Plan for Interstate 1'ransport of Pollution Affecting \risibility and Regronal Hne,77 F'ed. Reg. 20894
(06.\pr.2012),
27 State of North Dakota v. U.S. Environmental Protection Agency (EPA), Nos. 12'1844,12 1961,12-2331, United States
Court of r\ppeals for the Eighth Circuit (2013).
28 Oregon Department of Environmental Quality, "Oregon Regional HazePlar' 5-Year Progress Report and Update" (Feb.
2016),
2-9
Case No. AVU-E-1 7-0 1 /AVU-G-1 7-0 1
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control. The control system was completed in December 2015, well ahead of the 2017 deadlne. Emission
reductions for SO, and NO. associated with the control equipment are expected to result in approximately
an 86o/o and 89oh, reduction in NO" and SO. respectively.2e
2.2.5. ,y'/,t ontnq
Wyoming has seven Class I Areas including Yellowstone National Park, a portion of which is located in
Montana. OnJanaruy 30,2014, EPA published a RegionalHaze FIP for Wyoming, approving the state-
proposed BART limits for PM and/ot NO. for 17 units. The majodty of these limits do not take effect
until future years, extending as late as Decemb er 31,2022. EPA also disapproved the State's proposed
NO. limits for five units and developed new BART limits as part of the FIP for these sources. 'Ihe
compliance date fot these five sources is Match 4,2079. Portions of EPA's final action were appealed and
are s ill pending a fnal determination. Most of the BART derminations tequire SCR and Continuous
Emission Monitoring Systems (CEMS) for NO. control.3o
2.3. Slote & Federol Progroms relied on in lhe Montono FIP
EPA's 2013 guidance for the five-year progress report requests that, in addition to describing the status of
specific control measures that were applied in the Montana FIP, the state should also describe additional
measures that were relied upon to meet the requirements of the RegronalHaze program." This section
descdbes the existing SlP-apptoved state programs and fedeml programs that were included in the
projected 2018 future year emrssions estimate and that have contributed to emissions reductions required
to meet BART limits and Reasonable Progtess Goals EPG$.
Thete are numerous existing programs that are responsible for a continual decline in emissions from
industrial sources. Most of the existing federal measures were incorpotated into the WRAP's 2018
projected emission inventory. These measures should continue to reduce visibiJity-impairing pollutants
over time and are part of Montana's long-term strategy for reaching its progress goals.
2.3.1 . Minor Source Permitting Program
201.3),
EPA granted authodty to the State to implement the state's minor source permitting program, located in
the Administrative Rules of Montana Chaptet 17.8, Subchapter 7 - Petmit, Construction and Opetation of
Au Contaminant Sources. The primary purpose of the permitting program is to assure compliance with
ambient air standards set to protect public health, assure that Best Available Control Technology (BACT)
is utilized to reduce or eliminate air pollution emissions, and to prevent deterioration of clean ai areas.
2e Soutl Dakota Department of Environment and Natural Resources, "South Dakota's Regronal Haze State Implementation
ilf;j:',i;:"t}1o'1r13;.""a1and promurgation or rmplementation prans; State orwyoming; Regional Haze State
Implementation PIan; Federal Implementation Plan for Regional Haze,79 Fed. Reg. 5031 (30Jan. 2014)
31 [iPA, "General Principles for the 5-Year Regional Haze Progress Reports" (Research'l'riangle Park, North Carolina, April
2-10
Case No. AVU-E-1 7-01IAVU-G-1 7-01
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As pat of Montana's SIP, all new emission sources that arc required to obtain a Montana Air Quality
Permit (MAQP) must use BACT. According to Administrative Rules of Montana (ARM) 1,7.8.752, the
owner or operator of a new or modified emitting unit or emitting unit fot which a Montana air quality
permit is required shall install on the new or modified faciJity or emitting unit the maximum air pollution
control capabiJity that is technically practicable and economically feasibl.."'fhir provides that permitted
emission rates are genetally consistent across source categories and that emission rates are minimized.
By requiring BACT even on minor sources, lower emission levels associated with newer equipment, which
teplaces older equipment over time, serves to ptovide emission reductions on a continuing and long-term
basis. While the Minor Soutce Permitting Ptogram did not direcdy influence the 2018 project emission
inventory, use of BACT limits emissions incteases from modifications as new permitted equipment (such
as engines) will genetally have lowet emission rates than the older units being teplaced.
2.3.2, Frc,ver')trcn rl 5igni,'ri:cli .Je ierio ration
In addition to serving other air quality priorities, Montana's Prevention of Significant Detetiotation (?SD)
program also serves to limit visibility impairment from proposed maior stationary sources or major
modifications to existing facilities. Montana's PSD progam has been successfully implemented since 1983
and is fully approved by EPA.tt Th. PSD program requires sources (that meet the definition of new or
major modifications) to model the emissions impacts on Class I Areas within 10 km of the source to
determine if the change in emissions would exceed maximum allowable increases over the minor source
baseline concentrations for PMr.r, PM,,,, SO, and NOr. The PSD New Source Review (t\SR) permitting
program is described in ARM Chapter 17.8, Subchapter 8. 'I'he PSD program also did not di-rectly
influence the projected 2018 emission inventory but served to reduce the gtowth in new emissions by
preventing large increases that could cause significant decline in the Class I Areas.
2.3.3. New Source Performance Sfondords * 40 CFR Part 6A ond Notional
Fmission Stondords for Hazardous Air Pollutonts - 40 CFR Port 63
Montana administers a delegated Clean Air Act Part70, or Tide V, Operating Permit Ptogram, thereby
providing Montana with a mechanism to teceive automatic delegation to implement the New Soutce
Performance Standards OfSPS) and National Emission Standatds for Hazardous Air Pollutants
(I{ESHAP) programs in the State.34 Annually, the State undergoes rulemaking to incorporateby reference
the most recent versions of these standards. l7ithin the NSPS and NESHAP programs are numerous
measures that have reduced visibility-impairing emissions nationally over time. As new standards continue
to be developed, additional emission decreases will be rea\zed. Although in some source categories,
32 AII Administrative Rules of N{ontana discussed in this report can be accessed through the N{ontana Secretary of State web
portal at
33 EPA, Approval and Promulgation of State Implementation Plans - Revision to the Nlontana Prevention of Sigruficant
Deterioration Regulations, 48 Fed. Re9.20231 (5 \Iay 1983),
31 EPA, Clean r\ir r\ct Full Approval of Operating Permit Program; State of N{ontara,65 Fed. Reg. 370a9 (13 Jun. 2000),
2-71,
Case No. AVU-E-1 7-01IAVU-G-1 7-01
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Page 15 of 22
Montana does not have many affected facilities, sources in neighboring states that contribute to visibility
impairment in Montana may be affected, resulting in some visibility benefit.
2.3.4. A,lcnicncr Srnoke Monagernent Prcgran)
Montana implements an EPA-approved Smoke Management Plan (SMP) to tegulate open burning and
ptescribed fte activities. The SMP consists of Montana's ofFrcial open burning rules, as wdtten in the
Administrative Rules of Montana, Tide 77 , Chapter 8, Subchapter 6.'s The SMP considers smoke
management techniques and t1le visibility impacts of smoke when developing, issuing or conditioning
permits, and when making dispersion forecast recommendations. The SMP incorporates BACT as the
visibility conttol measure to meet the requirements of the RHR. The State works closely with the
Montanafldaho Airshed group to coordinate burning activities conducted by the large, majot open
burnets and federal land managers.'n Major burnets in Montana are defined as "afly person, agency,
institution, business, ot industry conducting any open burning that, on a statewide basis, will emit more
than 500 tons per calendar year of carbon monoxide ot 50 tons per calendar yezt of any other pollut^rtt."31
Examples of major open butnets in Montana include the U.S. Forest Service and the Bureau of Land
Management.
During the fall and winter burn seasons, Montana's open burn coordinator and meteorologist are actively
involved in day-to-day bum decisions, and evaluate burn tJpe, size, and location using dispersion forecasts.
Thtough this coordination and the required minor burn permitting included in the SMP, anthropogenic
smoke emissions are closely monitoted and tegulated. In addition, as mentioned above, burners must
follow BACT, which aims to limit smoke impacts due to buming. A full list of BACT requirements for
bumers can be found in ARM 17 .8.601. During open burn season (IVIarch through August) Montana is not
involved in the day-to-day decisions of burnets, although all other aspects of the Montana open burning
rules still apply, including BACT. T'he SMP, as represented by orrr open burning rules, is included as
Appendix A of this document.
: 3,5. Nc iior,.irl Psl,'o/e um P,ef :r,ely lniiicti'te
EPA's national Petroleum Refinery Initiative is an enforcement and compliance strategy to address air
emissions from the nation's petroleum refineries.3s Since 2000, EPA has entered into 17 settlements with
U.S. companies that refine over 75o/o of the nation's petroleum.
f'he initiative has resulted in emission decreases at Montana tefineries, including Calumet, Phillips66, CHS,
Inc., and ExxonMobil. Emission reductions projected to be achieved at these sources were taken into
account in the projected 20i8 emission inventory and will continue to provide for emissions reductions
going forward.
35 \Iontana Department of Environmental Quality (DEQ, ARII Tide 17, Chapter 8, Subchapter 6 - Open Burning,
36 Nlontana/Idaho Airshed Group, Airshed Nlanagement System:r'.\R\t 17.8.601(5),
38 EPA, Petroleum Refinery National Case Results,
2-72
case No. AVU-E-1 7-0 invii-c-r z-o i
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2.3.6. Federal Mobile Source Regu/otions
The Fedetal Motor Vehicle Control Ptogtam has already rcahzed latge emissions teductions in NO-, SO.,
volatile organic compounds (VOCs), and particulate matter (PM). The Federal Tier II vehicle emissions
and fuel standards reduced the sulfur content of diesel fuel from 500 to 15 parts per million (pp-) pltra
Low Sulfur Diesel) 'lr:,2006.3e The reduction in sulfur content allowed diesel engines to be fitted with diesel
oxidation chambers to reduce particulates. Fuel standards for offroad diesel similatly reduced allowable
sulfur content. In 2007, offroad diesel was requfued to meet a maximum sulfur content of 500 ppm, which
was furthet teduced to 15 ppm in 2010. Additional programs include the following:
Federal onroad measutes
'fier 3 vehicle emission standatds and federal low-sulfur gasoline
National low-emission vehicle standards
Heavy-duty diesel standards
Fedetal offroad measures
Lawn and garden equipment
Tiet 3 hearry-duty diesel equipment
Locomod.ve engine s tandards
Compression ignition standards fot vehicles and equipment
Recreational marine engine standards
2.4. Additionol Federol Meosures
In addition to the state and federal measures that wete anticipated in the Montana FIP, new measures have
been promulgated and implemented, in whole or in part, since the development of the Montana FIP and
the projected 2018 emissions inventory. Any reduction that will occur or has akeady occurred as a result of
these new measures will further reduce emissions beyond what was projected toward Montana's
reasonable progress goals. This section details several new federal measures.
2.4. | . I'le:c ilr\,' .lnC ,Air ioxics (rie
On February 76,2012, EPA finalized national standards to reduce mercury and othet toxic ait pollution
from coal and oil-fired power plants as part of 40 CFR 63, Subpat UUUUU - National Emissions
Standards for Hazzrdous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units, also
refered to as the Mercury and Air Toxics Standards O4ATS).4" The final rule estabhshed power plant
emission standards for mercury, acid gases, and non-mercurT metallic toxic pollutants. EPA projected
2015 emissions with the standards in place - emissions of mercury, PMru, SOr, and acid gas will be
3e EPA, Diesel Fuels Standards and Rulemakings,
10 EPA, National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating
Units, 77 FR 9304 (16 Feb.2O12),
2_13
I
!
t
T
Case No. AVU-E-1 7-01 /AVU-G-1 7-01
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reduced by 75, 79,41.,and 8870, tespectively, ftom coal-fired EGUs greater than25 megawatts O4W).0'
Compliance with MATS was required by April 16,2015. Emission teductions that occur as a result of
MATS, both in the form of particles and gases that may form aerosols, will reduce the amount of light
extinction and reduce anthtopogenic causes of haze.
Montana had previously adopted rules to conttol mercury in response to the proposed federal rulemaking
known as the Clean Air Mercury Rule (CAMR), under which states were originally tequted to adopt a set
of federal market ttading standards for mercury or develop their own "equivalent" standard. Montana
adopted its own mercury standard teferenced as the Montana Mercury Rule.a2'I'he Montana Mercury Rule
(ARM 17 .8.771) was adopted effective October 27,2006, and required compliance with mercury emission
Iimits byJanuary 1,201.0.43 Although CAMR was vacated by the District of Columbia Court of Appeals in
2008, the Montana Mercury Rule was abeady in place by the time MATS was finalized.
There were five affected coal-fted facilities under the Montana Mercury Rule and MATS. These included
the Colstrip Steam Electric Station,J.E. Cotette Steam Electric Station, Montana-Dakota Utilities (I{DU)
Lewis & Clark Plant, Colstrip Energy Limited Patnership, and Rocky Mountain - Hardin.
Colsrip Steam Electric Station
Colstrip's four electric generating units use subbituminous coal and its mercury limit under the Montana
Metcury Rule is 0.9 pounds per trillion British thermal units [b/TBtu) on a 72-monrh rolling avetage.
Colstrip is required to meet a MAf'S limit of 1.2 lbs/TBtu on a 30-day rolling ^verage. The compliance
date for Colstrip was April 76,2075, but the facility was gtanted a or,e-yeat extension to April 16,2076.
The extension provided a full one year gtace period for all required MATS limits, but upgrades were
completed for particulate on Colstrip scrubbers to imptove particulate removal.
Patticulate matter (PNQ emissions may be used as a surrogate for actual heavy metal emissions to meet the
heary metal limits in the MATS rule. Reductions in PM emissions reflect a broad category of particuiate
and gaseous species that conuibute to the PM category. The mercury conuol system installed at Colsuip
to meet Montana's Mercury Rule also allowed Colstrip to meet the MATS requirements for mercury
capture and removal. In addiuon, existing controls on all four units adequately remove acid gases covered
by the MATS rule (using SO, as a surrogate). Upgrades were done on the Unit 1 and 2 scrubbers (sieve
trays installed) for additional PM control and resulted in the secondary benefit of significant SO2
reduction.'Iheses controls at Colstrip have resulted in significant emission reductions from the faciJity.
J.E. Corette Steam Electric Station
The J.E. Corette facitty was also subject to MATS, but opted not to install the required conttol
equipment, resulting in its shutdown in April 2015.
11 Ibid. p.9424.
12 EPA, Clean Air Nlercury Rule,
13 ARNI 17.8.771Nlercury Emission Standards for Mercury-Emitting Generating Units,
2-14
MDU Lewis & Clark Plant
The MDU Lewis & Clark Plant burns lignite coal, a different type of coal than the Colstrip Steam Electric
Station, and therefore has diffetent limits than Colstrip. For this facrlity, the Montana Mercury Rule
requires a limit of 1.5 lb/TBtu on a tolling 12-month aver^ge, and MATS requires 4.0 Ib/TBtu on a rolling
30-day average. MDU Lewis & Clark upgtaded the existing sctubber and installed sieve trays to satisfy the
non-mercury metals emission standard of 0.03 lbs/MMBtu for filterable PM in 2015. The system was fully
operational in eady 2016. These additional controls have resulted in further particulate reductions plus a
co-benefit of significant SO, emission reductions.
Rocky Mountain Power - Hardin
Also known as the Hardin Generating Station, this facility consists of a single coal-fted boiler with single
steam turbine rated at 116 gross megawatts. Hardin must achieve a 0.9Ib/TBu mercury limit on a 12-
month rolling ^ver^ge to comply with the Montana Mercury Rule, and a limit of 1..2lb/TBtu on a 30-day
average to comply with MATS. Hardin installed carbon injection controls to meet the limit in the Montana
Metcury Rule.
Colstrip Energy Limited Partnership (CELP)
This facility often is referred to as the Rosebud Power Plant and also uses coal from the same geograpluc
area as the Colstrip Steam Electtic Station but is able to u :lize a lower grade coal sometimes referred to as
"waste co^\" . The facility has a single coal-fued boiler rated for 39 gross megawatts. CELP began planning
for their compliance with the Montana Mercury Rule as eatly as December 2008, when Montana DIrQ
teceived an application to modify their Montana Air Quality Permit. CELP is meeting the same limits as
Hardin, 0.9 lb/TBtu mercury limit on a l.2-month rolling
^.veta;ge
and a MATS limit of 1.2\b/TBtu on a
30-day average.
2.4.2. Revr3g6'r xclion;l Asrh:t,,r i {;r (iL.;tl,rl'v StoncJord,s
According to EPA, the primary NAAQS serve to protect public health, including "the health of 'sensitive'
populauons such as asthmatics, children, and the elderly." In addition, secondary NAAQS protect public
welfare, "including protection agatnst decreased visibility and damage to animals, crops, vegetation, and
buildings."ao As EPA continues to revise NAAQS, the standards put pressure on states to manage
pollution sources, often resulti.ng in emrssions decreases, including of pollutants responsible fot visibility
impairment.
The following NAAQS revisions have occurted since the baseline period Q000-2004) for the Regional
Haze program. Each of these standards must be taken into accouflt when permitting new or modified
maior sources, including fossil fuel-fired powet plants, boilets, and a variety of other operations. Any
reductions ifl SO2, NO-, or PM* brought about by these tevised standatds will enhance protection of
visibility in Montana Class I Areas.
Case No. AVU-E-1 7-01 /AVU-G-1 7-01
E. Hausman, Sierra Club
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(accessed 14
2-t5
'r1 EPA, "NAAQS 'l'able" (last updated 20 Deo 2016),
Apr.2017).
Case No. AVU-E-1 7-0 1 /AVU-G-1 7-0 1
E. Hausman, Sierra Club
Page 19 of 22
2010 so, NAAQS
OnJune 2,2010, EPA strengthened the SO, NAAQS by revising the ptimary SOz standatd to 75 parts
per billion (ppb) 3-year avera'ge of the 99th percentile of the yearly distribution of 1-hour daily maximum
SO, concentrations. This shott-term standard is signifrcantly more stringent than the revoked standards of
0.140 parts per million (pp-) averaged over 24-hours and 0.030 ppm averaged over a calendar year.
On August 27,2015, EPA released the 2010 SO, Data Requirements Rule (DRR), which instructs states to
evaluate areas surrounding facilities with 2000 tonsf year or more SO, emissionr.ot In Montana, all units at
the Colstrip Steam Electric Station wete modeled under the DRR since the facility exceeds the 2000
tonf year threshold. As a result, Montana tequested to designate Rosebud County as "attainment" fot SOr.
Montana had one arca in Yellowstone County that was designated as nonattainment. The area was
redesignated to attainment under a maintenance plan effective on June 9, 2076.46
2010 NO, NAAQS
Effective on Apdl 12,2070, EPA established a new 1-hour primary standard to supplement the existing
annual standard. This 1-hour standard was set at a level of 100 ppb, based on the 3-year ^ver^ge of the
98th percentile of the yearly distribution of 1-hour daily maximum concenrations.aT Along with the new
standard, EPA set new requirements to monitot NO, levels near major roadways. Montana does not have
a population center with a density high enough to warrant or trigger the near-roadway monitoring
requirement.In 201,2, EPA designated every county in Montana as Unclassifiable/Attainment for the 2010
NO, NAAQS.48
2012 PM2.5 NAAQS
On January 15,2073, EPA published a final rule strengthening the annual NAAQS for fine particles
GMrJ from 15.0 micrograms per cubic meter 1pg/m') to 12.0 prg/^'.0'According to EPA, "Emission
reductions from EPA and states rules already on the books will help 99 petcent of counties with monitors
meet the revised PMru standards without additional emission reductions."s" These rules include many of
+t EPr\, Data Requirements Rule for the 2010 1-Hour Sulfur Dioxide (SO2) Primary National Ambient Air Quality Standard
HJ.lli]:llfj**:lHi?:?:itl'A#il ??^':L- purposes; Redesignation Request and Associated Nraintenance pran ror
Billings, l,IT 2010 SO2 Nonattainment Area, 81 FR 28718 (10 NIay 2016),
'r7 EPA, Primary National Ambient Air Quality Standards for Nitrogen Dioxide; Final Rule, 75 FR 6474 (9 Feb. 2010),
last updated 23 Dec. 2016, ' See also FIPA' "Nitrogen Dioxide Q"lo2) Pollution"'
+8 EPA, Air Quality Designations for the 2010 Pimary Nitrogen Dioxide QiO2) National r\mbient Air Quality Standards; Final
lt?l].I}::1il'"1J-:l;fl1'&** Standards ror particurate lrattet, T8 FR 3086 (15Jan.2013),
vr EPA, "Overview Of E,PA's Revisions to the Air Quality Standards for Particle Pollution (?articulate N{atter),"
(accessed 24 Apr. 2017).
2-16
Case No. AVU-E-1 7-01IAVU-G-1 7-01
E. Hausman, Sierra Club
Page21 of22
the regulations discussed above, such as clean diesel tules for vehicles and fuels, and rules to reduce
pollution from power plants.
2.5. Additionol Slote Meosures
In addition to BART and the federal and state programs discussed previously, there are other state
measures and notewothy changes that will influence the achievement of Montana's 2018 RPGs. As set
forth in detail below, some noteworthy changes in Montana since the Montana FIP submittal include a
power plant closure, two previously planned coal-fred facilities that were flot constructed, stronger
renewable energy portfolio requirements, and attainment of the NAAQS thtoughout the state.
2.5" i. Closure lConcellctions & De"cting
The WRAP projected 2018 emissions estimate included emissions from a number of latge sources that
have closed, were nevet built, or ^re operating at diffetent levels than originally planned. These sources
include a power plant that has been closed (Cotette, discussed in Section 1.1.2), a power plant that was
constructed but at a smaller size than originally planned (X.ocky Mountain Powet - Hardin), and two coal-
fired powet plants that were planned but nevet constructed (Bull Mountain/Roundup Power Project and
Southern Montana Electric, or SME). The latter two permits were eventually permanendy revoked.
The Hardin facility was odginally designed as 160 megawatts OdW), but was eventually permitted at 773
MW; therefore, emissions associated with this faciJity were over-stated by the equivalent of 47 MW. The
Bull Mountain/Roundup plant, with a capaciq of around75O MSf per the WRAP inventory, was never
constructed, and SME was permitted and constructed but never came on-line. Adjusting the 2018
projected emissions inventory to reflect these changes will further reduce emissions toward the RPGs.
2.5.2. Monf ano Renewoble Portfolio Sfondord
The Montana Renewable Power Production and Rural Economic Development Act or the Montana
Renewable Portfolio Standard EPS), was approved by the Montana Legislature in 2005. f'he RPS tequired
pubiic utilities to obtain a percentage of their retail customer sales from renewable resources. Starting in
2008, a public utility was required to acquire renewable energy equal to 570 of its retail sales of electricity in
Montana. 'Ihat percentage increased to 100/o ifl 2010 and to 75o/o n 2015.s1 While new sources of
renewable energy do not direcdy replace electricity from fossil fuel-fred electric generating plants, they
accommodate growth in electricity demand without increasing emissions.
The new sources of generation in Montan^ are shown in Table 2-3, although not all of the power
generated is consumed in Montana. Many of the projects are able to help meet the RPS, but not all were
constructed specifically to meet the requirements of this Act.
5r Nlontana Code Annotated 2015, Title 69, Chapter 3,Part 20, Renewable Power Production and Rural Economic
Development,
2-t7
Case No. AVU-E-1 7-01 /AVU-G-1 7-0 1
E. Hausman, Sierra Club
Page21 of22
Tesl-e 2-3. NEw AND PRoPoSED RENEWABLE GENERATIoN IN MoNTANA AS oF NoVEMBER 201652
Total
2 .t.J. $ir,'iie lrnciemenlcll'cn Picris
The State Implementation Plans (SIPs) for nonattainment and maintenance areas contain control measures
that may also contribute to the reduction of visibility-impairing pollution. Table 2-4. Existing Montana
Nonattainment Areas shows the status of all of the existing nonattainment areas and maintenance ateas in
the state of Montana. For each nonattainmeflt area, the State has drafted a SIP with control measures to
bring the area back into attainment with the associated NAAQS. Curtendy, most nonattainment areas
(primarily PM,,) in Montana are meeting the NAAQS standatds based on ambient monitodng data. A few
of these areas have been redesignated to attainment and are now in compliance with maintenance plans.
Others have been granted a "determination of attainment," indicating that the area is attaining the standard
even though it has not yet been redesignated.
In these areas, control measures (such as fugrtive dust regulations, oxygenated fuel progtams,
transportation control measures, residential wood butning tegulations, woodstove replacement programs,
and winter sanding and sweeping regulations) ensure there ate no large emission increases (without
emissions offsets) and serve to teturn the areas to attainment/unclassifiable. f'hese measures often also
reduce pollutants that contribute to haze.
52 Montana DEQ, Energy Bureau, "Table El. Electric Power Generating Capacity by Company and Plant as of August 2016."
Received 7 Nov. 2016.
2-18
NWI'l Portfolio (wintcr) -'l'ibcr Montana, IJ,(,'l'ibcr l)am I ibcrty Watcr 2004 7.5
\;\)YI,l Qlr -'lwo [)ot Wind \{artinsdalc (.olony Wheadand Wind 2004 0.8
NWI'l Portfolio - Invcncrgy Wind Judith (iap \{trcadand Wind 2005 135.0
NWL QIT - United Matcrials of (]reat lialls, Inc.U\I(]II (-ascadc Wind 2006 9.0
Montana l)akota Utilitics l)iamond Wilkrw Irallon Wind 2007 30.0
N\Yli Ql|lwo [)ot Wind Martinsdale Colony S.NUhcadand Wind 2007 2.0
Naturl,lner ()lacicr 1 &2 'l'oolc Wind 2008 21,0.0
I ;lathcad I ilcctric (-oopcrativc Landfill (ias to l,)ncrgy ljlathcad Landfill
Mcthanc 2009 1.6
NWI', l'}ortfolio -'l'urnbull I Iydro lJ,C l urnbull I Ivdro 'I'cton Watcr 2011 13.0
Naturl,lncr lUmrock 'I'oolc Wind 2012 189.0
N<>rthWcstcrn I,)ncrgy QrIWI'))Spion Kop Judith Rasin Wind 2012 40.0
N\Vli QIr - Oversight Rcsourccs (lordon Buttc Mcagher Wind 2012 9.6
lr.l [. Stoltze Land & Lumber (lo-(lcn Irlathcad lli<>mass 2013 2.5
NWI.I Qlr - (]ranitc (,ounty lrlint (-rcck l)am (]ranitc $Vatcr 2013 2.0
\Iusscllshcll 1 & 2 Whcadand \Uind 2013 20.0NWI'I QIr - ()oldwind (llobal
NWI'l l']ortfolio - NJR (-lcan I,,nergy Vcnturcs l'wo l)ot Wind liarm Whcadand Wind 2014 9.7
Irairficld Wind 'I'cton Wind 2014 10.0NWI,I QIr - WINl)ata LL(-
(lrecnficld Wind 'l'cton Wind 2017 25.0Orccnlticld Wind
716.7
lNt'11,\r.
( )PIrR,\'l'l( )N
(l,\lr,\CI'l\
(Ni\\)C( )t\,{1,,\N\PI"\N'I'(l()uN'tY s( )ul(( lll
] ,aurcl 38-NA 3/3/1e181971 (21-hr)l'hst I ltlcne No Monitor N,\11 / 15/ 1990Sulfur
l)ioxide 2010 (l-hr)tlilling"
75 ppb
53 N,\6/9/2U6;r
N,\1/ s/2005l)articulate
0'}N'I2.5)
1997 (,\nnual)r.ibbv 12 pg/m1 9.8
Kalispcll 87, 84 87. 8.+11 / t5/ 1990
(.olumbia Iialls ,15, .t-l .15, 4,1 11 / 15/ 1e90
\\'hitcflslr 1 06, 98 106.98 10/19/1993
Libbr'58, 57 +5.-15 11/15/1990
\Iissoule 11.65 71,65 11/15/1990
'l'hompson liells 135,97 97,89 1 /20/ 1991
l)articulate
(t,NI10)**1987 (2-l-hr)
Buttc
150 pglm3
52,51 52,15 11/15/1990
Ilillings N,,\Nr\1/22/2002i)
(lreat Iralls N,'\NA 1 /8/2002.5
(.arbon
\[r>n<>xidc 1971 (8-hour)
\lissoula
9 PP.n \,\ir-r\9/11 /2007i6
l,cad 1978 ((ld. Qtr.)I iest I Iclcna 0.15 pglml 0.06 1 / 6/ 1992
' 2l)1.1 I)csrgm Yalue, monitoring ceascd in-func 2l)15.ft I)NL,, I)csisn Yalucs arc thc 2016 lst and 2nd high valucs, onlv l'l\h, flaeacd cvcnts rcmoved ebovc l5o.
to attain or maintain thc NAAQS. Additional infomtion on Montana nonattainmcnt arcas, including dcsignation rcfcrcnccs and currcnt liPA status of arcas, cm bc
found ar
Standard
Yiolatcd
(lurrcnt
Stanclard1)ollutant
case No AVU-E-1 7-oilAvii:G-1 ?:oi
E. Hausman, Sierra Cltb
Page 22 of 22
TEBTB 2-4. EXISTING MONTANA NONATTAINMENT ARens
2.6. Conclusion
In summary, this chapter has described the implementation status of measures ftom the Montana FIP,
including the status of control measures to meet BART requi-rements, the status of significant measures
resultmg from IIPA and state tegulations, as well as measures and facility changes that have occurred since
the WRAP analyses were completed for the Montana FIP. Since the Montana FIP was promulgated in
2012, further reductions have akeady occurred or will occur as a result of additional federal and state
programs not otherwise identified in the Montana FIP, such as periodic updates to the NAAQS and plant
closutes. As discussed in this chapter, these actions and others have led to substantial reductions in both
the actual and proiected emissions of visibility-impairing pollutants from Montana sources. The following
chapter further assesses emissions reductions resultiflg from these measures.
53 EPA, Designation of Areas for Air Quality Planning Purposes; Redesignation Request and Associated Nfaintenance Plan for
Billings, \IT 2010 SO2, 81 Fed. Reg. 28718 (10 NIay 2016),
51 EPA, Approval and Promulgation of Air Quality Implementation Plans; State of Nlontana; Billings Carbon Monoxide
Redesignation to Attainment and l)esignation of Areas for Air Qual-iry Planning Purposes, 67 Fed. Reg. 7966 (21 l;cb. 2002),
55 EPA, Approval and Promulgation of Air Quality Implementation Plans; State of Nfontana; Great Falls Carbon Nlonoxide
Redesignation to Attainment and Designation of Areas for Air Quality Planning Purposes, 67 Fed. Reg. 31143 (9 May 2002),
56 EPA, Approval and Promulgation of Air Quality Implementation Plans; State of Nlontana; N{issoula County Carbon
\fonoxide Redesignation to Attairiment, l)esignation of Areas for Air Quality Planning Pulposes, and Approval of Related
Revisions, T2Fed. Reg.46161 (17 Aug.2007),
2-19
(lonrmunin'201 6 l)csign
\Idue (\\iith I,)l'))t
20161)r:sign
\,'aluc
$\ithout l.il,)){
Nonattairrment r\ttainrncnt/
Nfaintenancc
Case No. AVU-E-1 7-01IAVU-G-1 7-01
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Page 't of 6
BEFORE THE STATE OF WASHINGTON
UTILITIES AND TRANSPORTATION COMMISSION
WASHINGTON UTILITIES AND
TRANSPORTATION COMMIS S ION,
DOCKETS UE- 1 70033 tUG-t7 0034
(Consolidated)Complainant,
PUGET SOUND ENERGY,
Respondent.
Initial Post-Settlement-Hearing Brief of
the State of Montana in Support of
the Proposed Multiparty Settlement Stipulation and Agreement
October l8,2ll7
1
v.
Case No. AVU-E-1 7-01IAVU-d-1 7-01
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TABLE OF CONTENTS
I.INTRODUCTION 1
1
3
3
II. FACTS
m.
IV.
LEGAL STANDARD..
ARGUMENT............
A. Montana's interests in this proceeding are unique, and they inform
Montana's support for the proposed Settlement ...................... 3
B. The proposed Settlement's depreciation schedule balances the
magnitude of rate increases associated with Colstrip depreciation
expenses against a measure of certainty that ratepayers will not pay
for Colstrip Units 3 & 4 for longer than is fair, just, and reasonable......... 5
C. The proposed Settlement's payment arrangements for
decommissioning and remediation of Colstrip Units 1 & 2 are
lawful, supported by the record, and serve the public interest...................1
D. Reserving $5 million of monetized PTCs for community transition
planning in Colstrip, Montana, is legal, supported by the record,
and serves the public interest ...............9
E. The proposed Settlement is legal and serves the public interest,
because it does not purport to release or waive any of PSE's
liabilities for decommissioning and remediation of any Colstrip
Unit t2
V CONCLUSION..t2
I
TABLE OF AUTHORITIES
Case No. AVU-E-1 7-0 1 /AVU-G-1 7-0 1
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Page(s)
t2
Statutes
42 U.S.C. $ 9607(e)
Energy Policy Act of 1992Pub. L. No.
3020 (Oct. 24,1992)
MCA $ 1-r-102..
MCA $ 75-10-701 ................
RCW 80.04.350
RCW 80.80.100.
102-486 $t91,4,2776,106 Stat.
.,3
l0
t2
,.7
11
RCW 80.84.010
Other Authorities
H.R. Rep. No. 102-1018 (1992)..
Mont. Const. Arts. D( $ 1(l), VII and IX.............
ln Re Puget Sound Power & Light Co.,l47 P.U.R.4th 80, Docket Nos
UE -920433, U80920499, and UE-921262 (Sept. 2l, 1993)
wAC 480-07-700
wAC 480-07-700( l ).....
wAC 480-07 -t 50( l ).....
1
l0
ll
.3
.3
.3
1,3
-ll-
Case No. AVU-E-17-01/A 7-01
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Page 4 of 6
l4
15
fiscally responsible way and will prevent or reduce rate shock to PSE ratepayers. In short, the
proposed Settlement addresses those of Montana's interests that the Commission has power to
address while also meeting this Commission's standards for settlement approval.l6
B. The proposed Settlement's depreciation schedule balances the magnitude of rate
increases associated with Colstrip depreciation expenses against a measure of
certainty that ratepayers will not pay for Colstrip Units 3 & 4 for longer than is fair,
just, and reasonable.
For accounting purposes only, 17 the proposed Settlement establishes an accelerated
depreciation schedule for Colstrip Units 3 & 4 ("Units"). That schedule will not force Washington
ratepayers to bear an inordinate rate increase, but it does provide assurance that the depreciation
expense for the Units will be fully and predictably funded.rs Similarly, as other Settling Parties
have recognized through a general consensus of diverse opinions, the adjusted depreciation
schedule minimizes future intergenerational inequities that might arise from the imprecise science
of setting depreciation dates.
Further, by clarifying that the stipulated depreciation schedule for the Units is for
accounting purposes only and does not set a retirement date for them, the Settlement preserves
operational flexibility for an important source of reliable, low-cost baseload power for PSE
customers while implicitly acknowledging that any decision regarding the Units' eventual
retirement must be jointly made by all six of the Units' owners. This operational flexibility
16 Because the proposed Settlement resolves each issue implicating Montana's interests in these consolidated rate
proceedings, Montana's initial post-hearing brief focuses solely on the issue of whether the Commission should
adopt the proposed Settlement. Accordingly, Montana's initial post-hearing brief does not address any of the issues
remaining to be litigated. Further, because the proposed Settlement resolves issues other than those that implicate
Montana's interests, Montana's initial post-hearing brief focuses its support of the proposed Settlement solely on
issues that implicate Montana's interests.
r7 As PSE correctly observed in joint testimony supporting the proposed Settlement, the proposed Settlement's 2027
depreciation date does not equate to a retirement date. Joint Testimony of Puget Sound Energy, Exh. PSE- I JT at
7 :4-12 (Sept. 15, 2017).
18 Settlement [t[t2a-21; see also Settlement Ex. B n.2 & Joint Memorandum in Support of Multiparty Partial
Settlement t[ 13.
5
Case No. AVU-E-1 7-01IAVU-G-1 7-01
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t6
t7
mitigates cost uncertainty that PSE would otherwise face--e.g., the cost of replacement baseload
power-if the proposed Settlement equated the Units' depreciation life with their operational life.le
Public Counsel's witness Roxie M. McCullar disagrees that December 31,2027, is a
reasonable depreciation date for Colstrip Units 3 &. 4.20 Ms. McCullar observes that 2O2l is a
number that falls between 2025 and2035, stating that December 31, 202J "seems early."2rBut
Ms. McCullar's only response is circular and conclusory-i.e., the depreciation date should be
later.22 Ms. McCullar does not acknowledge that depreciation is an imprecise science-as
Mr. Douglas H. Howell noted on behalf of Sierra Club's full support of the proposed Settlement,
"certainty of retirement dates is not required-nor is it advisable-in setting a depreciation date."23
Regulatory uncertainty, particularly in a cyclical industry such as energy, counsels in favor of a
more conservative depreciation end-date in order to avoid intergenerational inequities.
Further, Ms. McCullar mischaracterizes Mr. Bradley G. Mullins' testimony in support of
the proposed Settlement in her own effort to support ,rbrr" Counsel's approach to setting a
depreciation date for Colstrip Units 3 & 4. Specifically, Ms. McCullar focuses on to Mr. Mullins'
remark that ICNU would have preferred a 2O3O depreciation year for Colstrip Units 3 & 4,24 btt
Ms. McCullar ignores the crucial next sentence of Mr. Mullins' testimony: "However, ICNU was
willing to agree to a [December 31, 2027] depreciation date for Units 3 & 4 as part of a broader
Ie Montana maintains that any reading of the proposed Settlement as purporting to establish a retirement date for
Colstrip Units 3 & 4 would not be lawful, because it would be outside this Commission's authority. Accordingly, by
clarifying that depreciation does not equal retirement, the proposed Settlement appears to avoid any question of
legality in that regard.
20 Ms. Mccullar's testimony opposing the proposed Settlement also incorrectly states that December 31,2027, is a
retirement year. Testimony of Roxie M. McCullar, Exh. RMM-l2T at6:12-13 (Sept. 22,2017).
2t Id. at 6:13.
22 Id. at
23 Testimony of Douglas H. Howell, Exh. DHH-lT at I l:5-6 (Sept. 15,2017).
2a Testimony of Bradley G. Mullins, Exh. BGM-l7T at4; see RMM-l2T at 7-8.
6
Case No. AVU-E-1 7-O 1 /AVU-G'-1 7-01
E. Hausman, Sierra Clul:
Page 6 of 6
t8
t9
settlement package."2s This is the Settling Parties' general sentiment regarding the settlement as a
whole, which includes the adjusted depreciation date for Units 3 & 4.26 Public Counsel's
opposition essentially amounts to a preference for a different depreciation date for Units 3 & 4
rather than the date reached in the Settlement among PSE and stakeholders of notably diverse
interests.2T
Working to ameliorate cost uncertainty, which the adjusted depreciation schedule for Units
3 & 4 does, is in the public interest generally and the interest of Washington ratepayers specifically.
December 31,202J, is a lawful and well-supported depreciation date that arose from thoughtful
negotiations among diverse interests. The depreciation date for Units 3 & 4 satisfies this
Commission's standards for settlement approval. Public Counsel's opposition does nothing to aid
the Commission's decision process regarding this component of the proposed Settlement. The
Commission should adopt the December 3 1, 2027 , depreciation date for Units 3 &. 4 as part of an
unconditional approval of the proposed Settlement.
C.The proposed Settlement's payment arrangements for decommissioning and
remediation of Colstrip Units I & 2 are lawful, supported by the record, and serve
the public interest.
The proposed Settlement outlines a lawful use of hydro-related Treasury Grants and
Production Tax Credits ("PTCs") which is supported by the record, because those assets will be
split between (1) a dedicated retirement account pursuant to RCW 80.04.350 to fund and recover
prudently incurred decommissioning and remediation costs for Colstrip Units 1 &2 and (2) a non-
25 BGM-l7T at 4.
26 See, e.g., Testimony of Ali Al-Jabir, Exh. AZA-7T at 2-3 (FEA witness characterizing the proposed Settlement as
a "reasonable compromise" among the Settling Parties).
27 Notably, Ms. McCullar did not review workpapers supporting depreciation rates for Colstrip Units 3 & 4. RMM-
l2T at8:20-21 . Literally, then, Public Counsel has stated no real basis to oppose the proposed Settlement's
negotiated depreciation date for Units 3 & 4.
7
a Case No. AVU-E-1 7-01 /AVU-G-1 7-01
E. Hausman, Sierra Club
Portland General Electric Company page 1 of 2
P.U.C. Oreqon No. E-18 Orioinal Sheet No. 146-1
SCHEDULE 146
COLSTRIP POWER PLANT
OPERATING LIFE ADJUSTMENT
PURPOSE
This schedule establishes the mechanism to implement in rates the Company's share of the
revenue requirement effect of the change in the Colstrip Power Plant Units 3 and 4 and
associated common facilities currently assumed end of depreciable life year trom 2042 to 2030
as specified in 2016 Oregon Laws, Chapter 28 (SB 1547), Section 1. This schedule is
implemented as an "automatic adjustment clause" as defined in ORS 757.210.
APPLICABLE
To all bills for Electricity Service except Schedules 76R, 485, 489, 490, 491, 492, 495 and
576R.
ADJUSTMENT RATES
Schedule 146 Adjustment Rates will be set based on an equal percent of Energy Charge
revenues applicable at the time of any filing that revises rates pursuant to this schedule.
Schedule
7
15/515
321532
38/538
47
491549
75/575
Secondary
Primary
Subtransmission
83/583
85/585
Secondary
Primary
89/589
Secondary
Primary
Subtransmission
Adiustment Rate
0.035 0 per kWh
0.028 0 per kWh
0.032 0 per kWh
0.030 0 per kWh
0.038 @ per kWh
0.037 0 per kWh
0.030
0.029
0.029
0.032
0.031
0.030
0.030
0.029
0.029
0 per kwh
0 per kWh
0 per kWh
0 per kWh
0 per kWh
0 per kWh
0 per kWh
@ per kWh
0 per kwh
Advice No. 16-15
lssued October 12,2016
James F. Lobdell, Senior Vice President
Effective for service
on and after January 1,2017
'l
Case No. AVU-E-1 7-01IAVU-G-1 7-01
E. Hausman, Sierra Ciub
Page 2 of 2Portland General Electric Company
P.U.C. Oreqon No. E-18 Oriqinal Sheet No. 146-2
SCHEDULE 1 46 (Concluded)
ADJUSTMENT RATE (Continued)
Schedule
90/590
91/591
921592
95/595
Adiustment Rate
0.028 0 per kWh
0.028 0 per kWh
0.028 0 per kwh
0.028 0 per kWh
DETERMINATION OF ADJUSTMENT AMOUNT
Any revision to this schedule's Adjustment Rates requires Commission authorization (by order,
approval of a filing, acknowledgement of an lntegrated Resource Plan's Action Plan, or approval
of a depreciation study) to revise for rate setting and accounting purposes, the end of
depreciable life assumption of 2042 tor the Colstrip Power Plant Units 3 and 4 and associated
common facilities. The revised Adjustment Rates will be set to recover an Adjustment Amount
rellecting the change in depreciation revenue requirements.
The Adjustment Amount is the difference between the Colstrip Power Plant Units 3 and 4 and
associated common facilities depreciation/amortization revenue requirement for the year 2017
as determined in UE 294 that reflects a plant end of depreciable life date of 2042, and the same
depreciation/amortization revenue requirement determination using a plant end of depreciable
life assumption of 2030. The depreciation/amortization revenue requirement change
computation will use the Commission-authorized tax rates, revenue sensitive cost rates, rate of
return, and return on equity rates. Only changes to depreciation expense, amortization expense
and related Schedule M and rate base adjustments as of the date of the filing revisions to this
rate schedule are included in the depreciation/amortization revenue requirements.
The Adjustment Rates will be updated annually to reflect the subsequent year's change in the
Colstrip Power Plant Units 3 and 4 depreciation revenue requirement, if the Company has not
incorporated the revised depreciable life into base rates in a general rate case or other
proceeding.
The docket reference numbers and dates in this schedule will be revised as necessary to a
subsequent docket if no change to the Colstrip Power Plant Units 3 and 4 and associated
common facilities depreciable life occurs prior to a subsequent general rate case order.
TERM
This schedule will terminate at the date that base rates include the revised end of life
assumption or when all remaining investment in the Colstrip Power Plant Units 3 and 4 and
associated facilities have been recovered.
Advice No. 16-15
lssued October 12,2016
James F. Lobdell, Senior Vice President
Etfective for service
on and after January 1,2017