Emergency Application — North Dakota, et al., Applicants v. Environmental Protection Agency, et al.

Supreme Court briefAug 16, 2024

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Mercury Emissions: Lignite Coals

Mercury Fuel Content (lbs/TBtu)

Coal Lake

Coulee

Kinneman

Creek

Hagel A Coal Hagel B Coal

Seam

Tavis Coal

Seam

Coyote Quality Coteau DH

Data

Figure 6-1. Mercury Content Variability for Eight North Dakota Lignite Mines

3.5

Fuel Sulfur Content (%)

2.5

1.5

0.5

Coal Lake

Coulee

Kinneman

Creek

Hagel A Coal Hagel B Coal

Seam

Tavis Coal

Seam

Coyote Quality Coteau DH

Data

Figure 6-2. Fuel Sulfur Content Variability for Eight North Dakota Lignite Mines

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Aalikalinity Ratio (CA+NA/S)

Approximate

Range for

PRB Coal

Coal Lake Coulee Kinneman Creek

Hagel A Coal

Seam

Hagel B Coal

Seam

Tavis Coal Seam

Coyote Quality Coteau DH Data

Figure 6-3. Fuel Alkalinity/Sulfur Ratio for Eight North Dakota Mines

Figure 6-1 compares the Hg content and variability to the fixed value of 7.7-7.8 lbs/TBu,

assumed by EPA as representing North Dakota lignite, as summarized in Table 11 of the Tech

Memo. Figure 6-1 shows – with the exception of the Tavis seam – all mean values of Hg content

exceed EPA’s assumed value that serves as the basis of EPA’s evaluation. More notably, the 75 th

percentile value of Hg for each seam - slightly more than one standard deviation variance from

the mean – in all cases significantly exceeds the value assumed by EPA.

Of note is that the variability of Hg depicted in Figure 6-1 is not necessarily observed only over

extended periods of time – such as months or quarters – it can be witnessed over period of days

or weeks. This is attributable to the sharp contrast in Hg content of seams that are

geographically proximate and thus are mined within an abbreviated time period. Figure 6-4

presents a physical map showing the location of “boreholes” in a lignite field with imbedded text

describing (in addition to the borehole code) the Hg content as ppm. The text boxes report this

Hg content in terms of lbs/TBtu. These example boreholes – separated by typically 660 feet- and

the factor of 3 to 6 variation of Hg content present a meaningful visualization of Hg variability in

a lignite mine, and the consequences for the delivered fuel.

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10.70

lbs/TBtu

19.23

lbs/TBtu

2.97 lbs/TBtu

Figure 6-4. Spatial Variation of Hg in a Lignite Mine

Data from Figure 6-1 is summarized in Table 6-1 for units at four stations in North Dakota –

Coal Creek, Antelope Valley, Coyote, and Leland Olds. Both Figures 6-1 and Table 6-1 show

Hg variability exceed that assumed by EPA in their evaluation. Table 6-1 shows that achieving a

1.2 lbs/TBu requires an Hg removal rate of approximately 93-95% for unavoidable instances

where coal Hg content is at the 95th percentile of observed value. The approximate 93-95% Hg

removal requirements well exceed the 85% Hg removal based on the IPM-assigned Hg content.

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Coyote Upper Belauh

Kinneman Creek,

Hagel A, Hagel B

Freedom

Coyote

Creek

Freedom

Antelope

Valley

Coyote

Leland

Olds

UTAV, HGB1 and

HGA1/HGA2 (Mostly

Haga A seam)

Freedom Mine Belauh

Seam

Seams

Falkirk

Mine

Coal

Creek

Station

7.81

IPM

Designated

Hg Rate

(lbs/TBtu)

Table 6-1. Hg Variability for Select North Dakota Reference Stations

7.79

7.76

7.80

Inferred

EIA 2021

Hg Rate

(lbs/TBtu)

23.0

19.2

23.0

Hg Fuel

Content

at 95th

Percentile

(lbs/TBtu)

25.1

94.8

93.8

94.8

95.2

Hg Removal (%)

for 1.2 lbs/TBtu

95 Percentile

Mercury Emissions: Lignite Coals

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6.2

Texas Gulf Coast Mines and Generating Units

Figures 6-5 to 6-7 present data from Texas and Mississippi lignite mines describing the content

and variability for Hg, sulfur, and the (Ca + Na)/S metric, as delivered to generating units in

Texas. Analogous to the data cited for North Dakota, the “box and whisker” depiction represents

the same metrics.

Mercury Fuel Content (lbs/TBtu)

MS_Mine

TX_Mines

Figure 6-5. Mercury Variability for Two Gulf Coast Sources: Mississippi, Texas

Table 6-2 compares the Hg removal required to meet the proposed 1.2 lbs/TBtu rate considering

the variability of Hg in Texas and Mississippi coals, in

instead of the IPM-assigned Hg coal

content. For three Texas plants that fired 100% lignite – Major Oak Units 1 and 2, Oak Grove

Units 1 and 2, and San Miguel – EPA assigned inlet Hg values from 12.44 to 14.88 lbs/TBtu,

implying Hg removal of 90-92% to achieve 1.2 lbs/TBtu. However, based on the 95th percentile

value of the Texas lignite Hg values from Figure 6-5, the required Hg removal would be 96

96-97

97%.

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1.60

1.40

Fuel Sulfur Content (%)

1.20

1.00

0.80

0.60

0.40

0.20

0.00

MS_Mine

TX_Mines

Figure 6-6. Sulfur Variability for Mississippi, Texas Lignite Mines19.1

4.5

4.0

Approximate

Range for

PRB Coal

Aalikalinity Ratio (CA+NA/S)

3.5

3.0

2.5

2.0

1.5

1.0

0.5

0.0

MS_Mine

TX_Mines

Figure 6-7. Fuel Alkalinity/Sulfur Ratio for Mississippi, Texas Lignite Mines

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14.88

12.44

14.65

Mines

Calvert

Kosse Strip

Red Hills

San Miguel

Lignite

Major Oak 1,2

Oak Grove 1, 2

Red Hills 1, 2

San Miguel

Station

IPM

Designated

Hg Rate

(lbs/TBtu)

14.65

14.62

12.4

14.6

Inferred

EIA 2021

Hg Rate

(lbs/TBtu)

14.62

Table 6-2. Hg Variability for Select Texas Reference Stations

38.1

67.6

38.12

Hg Fuel Content

at 95th Percentile

(lbs/TBtu)

96.9

98.2

96.9

Hg Removal (%) for 1.2

lbs/TBtu at

95th Percentile

Mercury Emissions: Lignite Coals

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6.3 Role of Flue Gas SO3

EPA equates PRB and lignite coal in terms of constituents that affect Hg capture by carbon

sorbent. Data from North Dakota and Gulf Coast mines, displayed in the previous Figures 6-1 to

6-7, show these fuels also contain higher sulfur content than PRB - by a factor or two or more.

This relationship is verified by data acquired from EIA Form 960, as provided by power station

owners. These fuel data, combined with inherent alkalinity, identifies the problematic role of

flue gas SO3 content.

6.3.1 EIA Hg-Sulfur Relationship

Figure 6-8 compares the seam-by

by-seam Hg and sulfur content from various power stations firing

lignite coals, representing approximately 60 lignite mines and 40 PRB mines. Figure 6-8 shows,

even excluding the outlier values of Hg (approximating 50 lbs/TBtu), lignite presents

significantly

ly greater variability in Hg and sulfur than PRB. Moreover, lignite coals have a much

higher sulfur content than PRB and in many instances have twice the Hg content. The higher

sulfur content of lignite equates to greater production rates of sulfur SO 3.

Lignite

Subbituminous

Fuel Mercury Content (lbs/TBtu)

0.1

0.2

0.3

0.4

0.5

0.6

Fuel Sulfur Content (%)

0.7

0.8

0.9

Figure 6-8. Lignite Hg and Sulfur Content Variability: 2021 EIA Submission

An additional factor is the amount of “inherent” alkalinity compared to sulfur – with higher

value surpassing the SO3 content in flue gas. As introduced previously, one metric of this feature

is the ratio of Na and Ca to sulfur – on a mole basis.

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Figures 6-3 and 6-7 show North Dakota and Gulf Coast lignite present a similar ratio of

alkalinity to sulfur content as does PRB – approximating a value of 2. By this metric, lignite

fuels in Figure 6-3 present similar means to “buffer” SO 3 as PRB. Notably, Texas lignite in

Figure 6-7 is disadvantaged in this metric as the alkalinity to sulfur ratio is half that of PRB –

reducing the buffering” effect of inherent ash.

Consequently, the higher sulfur content of lignite combined with equal or lower total alkali

relative to sulfur allows measurable levels of SO 3 in lignite-generated flue gas, as evidenced by

field measurements. EPA does not recognize this distinguishing difference, and states the

following regarding lignite and subbituminous coal: 30

As mentioned earlier, EGUs firing subbituminous coal in 2021 emitted Hg at an average annual

rate of 0.6 lb Hg/TBtu with measured values as low as 0.1 lb/TBtu. Clearly EGUs firing

subbituminous coal have found control options to demonstrate compliance with the 1.2 lb/TBtu

emission standard despite the challenges presented by the low natural halogen content of the

coal and production of difficult-to-control elemental Hg vapor in the flue gas stream.

This passage contains two major flaws – that the effectiveness of Hg removal techniques with

PRB-generated flue gas can be replicated with lignite, and that average annual Hg emission rates

are the metric for comparison. EPA fails to recognize that Hg removal in PRB is in the presence

of very little (essentially unmeasurable) SO3, and 30-day rolling averages exhibit variability not

captured by the annual average.

6.3.2 SO3: Inhibitor to Hg Removal

The ability of SO3 to interfere with sorbent Hg removal is well-known. 31 Most notably, EPA’s

contractor for the technology assessments used in the IPM 32 – Sargent & Lundy –for EPA issued

assessment on Hg control technology. This document states33

With flue gas SO3 concentrations greater than 5 - 7 ppmv, the sorbent feed rate may be

increased significantly to meet a high Hg removal and 90% or greater mercury removal may not

be feasible in some cases. Based on commercial testing, capacity of activated carbon can be cut

by as much as one half with an SO3 increase from just 5 ppmv to 10 ppmv.

This passage from the S&L technology assessment – funded by EPA to support the IPM model describes that Hg absorption capacity of carbon can be cut in half by an increase in SO 3 from 5

to 10 ppm. In addition, the presence of SO3 asserts a secondary role in terms of gas temperature

– units with measurable SO3 are designed with higher gas temperature at the air heater exit –

typically where sorbent is injected – to avoid corrosion. Special-purpose tests on a fabric filter

Tech Memo page 21

Sjostrom 2019. See graphics 21-25

Documentation for EPA’s Power Sector Modeling Platform v6: Using the Integrated Planning Model,

May 2018.

IPM Model – Updates to Cost and Performance for APC Technologies: Mercury Control Cost

Development Methodology, Prepared by Sargent & Lundy, Project 12847-002, March 2013.

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pilot plant showed an increase in gas temperature from 310ºF to 340ºF lowered sorbent Hg

removal from 81% to 68%.34 Th

The role of SO3 is not considered in assumed carbon injection rates

for EPA’s economic analysis in Tables 12 and 13 of the Tech Memo.

Publicly available field test data demonstrate the role of SO3 on carbon sorbent effectiveness.

Figure 6-9 presents results from a lignite-fired plant describing Hg removal across the ESP with

sorbent injection.35 This 900 MW unit is reported to fire a higher sulfur lignite in which more

than 20 ppm of SO3 in flue gas is observed preceding the air heater, subsequently decreasing to

10 ppm SO3 existing the air heater.

Figure 6-9. Sorbent Hg Removal in ESP in Lignite-Fired Unit: Effect of Injection Location

Data in Figure 6-9 show the role of SO3 in compromising sorbent performance - highest Hg

removal is attained with lower SO3 (downstream APH) with 60-68% Hg removal achieved (at an

injection rate corresponding to 0.6 lbs/MACF).

Attaining a total system 92% Hg removal – the target as described by EPA – is likely not

achievable given the trajectory of the curves as shown in Figure 6-9.

6.4 EPA Cost Calculations Ignore FGD

EPA ignores the major role of wet or dry FGD in removing Hg – a fundamental flaw in their

analysis. EPA’s premise that sorbent addition is the sole compliance technology is incorrect – 18

of 22 units in the lignite fleet listed in Table 9 of the RTR Tech Memo are equipped with FGD.

Sjostrom 2016. See graphic 16.

Satterfield, J., Optimizing ACI Usage to Reduce Costs, Increase Fly Ash Quality, and Avoid Corrosion,

presentation to the Powerplant Pollutant and Effluent Control Mega Symposium, August, 2018.

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Of these 18 units, 4 are equipped with dry FGD and 14 with wet FGD. This process equipment

asserts a major role in Hg removal as discussed in the next section.

The calculation of cost-effectiveness for the model plant as presented in Section (e)(i) of the

RTR Tech memo addresses only sorbent addition, thus does not reflect the Hg compliance

strategy of 18 units in the lignite fleet. EPA assumes (a) upgrade of sorbent from “conventional”

activated carbon to the halogenated form, and (b) increasing sorbent injection from 2.5 to 5.0

lbs/MAFH elevates Hg reduction from 73% to 92%.36 This assumption is not relevant – at least

in this specific form – to 18 of 22 units in the lignite fleet, as wet or dry FGD will contribute to

Hg removal. EPA’s approach could underestimate the cost per ton incurred, as tons of Hg

removed by the FGD could be credited to sorbent injection (the denominator of the $/ton

calculation is larger than it should be).

The variable of FGD Hg removal cannot be ignored, and undermines the legitimacy of the cost

estimates as Hg removed by FGD cannot be ascribed to sorbent injection. Thus, depending on

how or if the sorbent injection rate changes, costs could increase beyond EPA’s estimate (as the

denominator in the $/ton calculation is reduced.

6.5

Conclusions

•

EPA’s proposal that Hg emissions of 1.2 lbs/TBtu can be attained for lignite-fired units

by increasing sorbent injection rate and adding halogens (to compensate for loss of

refined coal) is incorrect, as it assumes sorbent injection Hg removal observed with PRB

is achievable on lignite.

•

Flue gas generated from lignite exhibits measurable SO3 in quantities that– as

summarized by EPA’s contractor for IPM model inputs - reduce the effectiveness of

sorbent by 50% and in some cases presents a barrier to 90% Hg removal.

•

Accounting for the variability of Hg content in lignite for most North Dakota and Texas

lignite fuels, more than 90% Hg removal is required to meet 1.2 lbs/MBtu, exceeding the

nominally 80% removal estimated by EPA, and over a 30-day rolling average basis is

unlikely to be attained.

•

EPA’s calculation of cost–effectiveness for lignite fuels ignores the role of FGD, present

in 18 of the 22 reference stations, in removing Hg. The result of this erroneous

assumption could be an under-estimation of the cost for additional Hg removal.

EPA uses the incorrect constant in the calculation of gas flow rate to translate sorbent injection from a

mass per time basis (lb//hr) to mass per unit volume of gas (lbs/MACF). The calculation on page 24 uses

the value of 9,860 scf/MBtu to quantify flue gas generated from lignite coal. Per EPA-454/R-95-015

(Procedure for Preparing Emission Factor Documents, OAQPS, November 1997) this value reflects the

dry volume of gas produced from lignite coal, per MBtu. The flue gas rate that is processed by the

environmental controls is the authentic “wet” basis and about 20% higher per MBtu (12,000 scf/MBtu).

Use of the correct, latter constant lowers the value of sorbent per MACF by the same magnitude.

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7. Mercury Emissions: Non-Low Rank Fuels

Section 7 addresses EPA’s proposal to retain the present Hg limit of 1.2 lbs/TBtu for units firing

bituminous and subbituminous coals.

EPA recognizes that Hg emission rates - as determined on an annual average basis - have

decreased significantly since the initial MATS rule was issued, with bituminous–fired units

averaging 0.4 lbs/TBtu (and ranging between 0.2 and 1.2 lbs/TBtu) and subbituminous-fired

units averaging 0.6 lbs/TBtu (ranging between 0.1 to 1.2 lbs/TBtu).37 EPA states these Hg

emission rates represent between a 77 and 98% Hg removal from an assumed Hg inlet value of

5.5 lbs/TBtu. EPA notes they did not acquire detailed information on compliance steps such as

the type of sorbent injected, the rate of sorbent injection, and the role of SCR NOx control and

wet FGD and the myriad factors that determine Hg removal “co-benefits.”

This section addresses the reported Hg removal and basis for EPA’s position.

7.1 Hg Removal

EPA’s discussion of the annual average of Hg removal does not consider the 30-day rolling

average, the more challenging metric to attain – and the metric mandated for compliance. The

30-day rolling average reflects variability in Hg coal content and process conditions, both of

which can experience daily or hourly changes, which obviously is not captured in annual

averages.

Figures 7-1 and 7-2 report two metrics of Hg emission rate variability. 38 Figure 7-1 presents the

mean and standard deviation of Hg annual average emissions for eleven categories of control

technology and fuel rank. For six of these eleven categories, the sum of the mean and the

standard deviation approach the Hg limit of 1.2 lbs/TBtu.

Figure 7-2 describes for six categories of control technology and 2 or 3 fuel ranks (depending on

the technology) the number of units that for at least one operating day exceed 1.2 lbs/TBtu on a

30-day rolling average. Figure 7-2 shows for all categories of control technology and fuel rank

experience 10% to 20% of units exceed this 30-day average.

In summary, EPA’s report of annual Hg emission rate - significantly reduced compared from

2012 – does not provide a basis for further reductions as annual data does not account for

variability.

Prepublication Version, page 85

Cichanowicz, J. E. et. al., Mercury Emissions Rate: The Evolution of Control Technology

Effectiveness, Presented at the Power Plant Pollutant and Effluent Control MEGA Symposium: Best

Practices and Trends, August 20-23, 2018, Baltimore, MD.

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1.40

Mean

Standard Deviation

Hg Emission Rate (lbs/TBtu)

1.20

1.00

0.80

0.60

0.40

0.20

0.00

Figure 7-1. Mean, Standard Deviation of Annual Hg Emissions: 2018

N=151

Bituminous

Units with >= 1 30-Day

Variance

Subbituminous

Lignite

N=76

N=63

N=28

N=31

N=35

N=41

N=33

N=6

N=2

N=0

N=12

N=10

N=6

N=3

N=5

N=0

N=3

ESP Only

FF Only

Dry FGD

Dry FGD /

SCR

Wet FGD

Wet FGD /

SCR

Figure 7-2. Mean, Standard Deviation of Annual Hg Emissions: 2018

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7.2 Role of Fuel Composition and Process Conditions

Hg emissions are defined by variability in coal composition and process conditions, the latter

including sorbent type, and injection rate, and the “co-benefit” Hg removal imparted by SCR

NOx control and wet or dry FGD.

Although EPA did not elicit detailed process information from owners via Section 114, several

key insights are presented in a 2018 survey conducted by ADA.39

7.2.1 Coal Variability

EPA cites observing for Hg emissions “a control range of 98 to 77 percent (assuming an average

inlet concentration of 5.5 lb/TBtu).”40 It is not clear if EPA assigns the average Hg content value

of 5.5 lbs/TBtu to both bituminous and subbituminous coal, or solely the latter.

Figure 7-3 shows an average value of 5.5 lbs/TBtu does not represent either coal rank well.

Figure 7-3 presents – on an annual average basis – data from more than 70 units reporting Hg

content to the EIA. Numerous units report up to 10 lbs/TBtu - almost twice the average value

EPA assigns, with 10 additional units reporting Hg content exceeding 10 lbs/TBtu. Northern

Appalachian bituminous coals appear to contain higher Hg content than coals from other regions.

Figure 7-3. Annual Average of Fuel Hg, Sulfur Content in Coal

Sjostrom, S. et. al., Mercury Control in the U.S.: 2018 Year in Review

RTR Tech Memo, page 19.

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Consequently, EPA’s calculation of 98 to 77% Hg removal is likely inaccurate as the assumed

coal Hg content is too low.

7.2.2 Process Conditions

The process conditions for Hg removal: sorbent composition, sorbent injection rate, and the “cobenefits” of SCR NOx control and wet FGD are highly variable, due to a combination of factors.

The following provides several examples.

Refined Coal. The absence of Refined Coal – no longer a viable option - complicates projecting

future Hg emissions. A survey of Hg compliance activities for 2018 reported Refined Coal as a

compliance step;41 EIA fuel records show this trend persisted through 2021. EPA’s assumption

that adding halogens to the fuel or flue gas compensates for the unavailability of Refined Coal is

speculative and without basis. Without assurances of the benefits from the halogen content of

Refined Coal, it is not possible to assess the viability of lowering Hg emissions.

Sorbent Injection. Sorbent injection is a key compliance step for 70% of subbituminous-fired

units, for some augmented with coal additives and Refined Coal. For bituminous-fired units,

18% of coal use is treated by some combination of sorbent injection and coal additives.

As described by EPA, increasing the rate of sorbent injection increases Hg removal – but with

diminishing returns as sorbent mass is added. An example of this relationship is provided by fullscale tests at Ameren’s PRB-fired Labadie Unit 3. These tests explored the effectiveness of both

conventional and brominated activated carbon. These tests, purposely conducted in PRBgenerated flue gas to define sorbent performance in the absence of SO 3, show Hg removal of

90% or more is feasible and that halogen addition can lower sorbent rate. 42

This relationship is complicated by the role of Refined Coal, coal additives, and (as described

below) the contribution of “co-benefits”. Devising a reasoned prediction of Hg removal under

variable conditions, including coal composition and the impact of changing sorbents is not

possible with current available information.

SCR, FGD Co-Benefits. The capture of Hg by wet FGD – in many cases prompted by the role

of SCR catalysts to oxidize elemental Hg – can be a primary mean for Hg capture. However,

such co-benefits are highly variable, and depend on the ratio of elemental to oxidized Hg in the

flue gas, and the consequential Hg “re-emission” by a wet FGD. There are means to remedy this

variability in some instances, but broad success cannot be assured. Without the specifics of FGD

design and operation, Hg removal via wet FGD cannot be predicted.

Sjostrom, S. et. al., Mercury Control in the U.S.: 2018 Year in Review. Hereafter Sjostrom 2019.

Senior, C. et. al., Reducing Operating Costs and Risks of Hg Control with Fuel Additives, Presentation

to the Power Plant Pollutant Control and Carbon Management Mega Symposium, August 16-18, 2016.

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Hg Re-Emission. The fate of Hg entering a wet FGD is uncertain. 43 If in the oxidized state, Hg

upon entering the FGD solution can (a) remain in solution and be discharged with the FGDcleansing step of “blowdown” (b) precipitate as a solid and be removed with the byproduct

(typically gypsum), or (c) be reduced from the oxidized to the elemental state, thus re-emitted in

the flue gas. Several means to minimize Hg re-emission exist, including injection of sulfite and

controlling the scrubber liquor oxidation/reduction potential (ORP). These means can limit Hg

remission but are additional process steps that are superimposed upon the task of achieving high

efficiency SO2 removal. The extent these means can be universally applied without

compromising SO2 removal is uncertain.

Role of Variability Due to Load Changes. An in-plant study showed that increasing load for a

wet FGD-equipped unit can elevate Hg re-emission, eventually exceeding 1.2 lbs/TBtu. 44 This

observation can be due to loss of the control over the ORP, defined in the previous paragraph as

a key factor in FGD Hg removal. Chemical additives can adjust ORP but complete and

autonomous control may not be available. For example, in a systematic evaluation of FGD

operating variables conducted at a commercial power station, factors such as limestone

composition and the extent to which units must operate in zero-water discharge – as perhaps

mandated by the pending Effluent Limitation Guideline – can affect ORP and thus Hg-reemission.45

Upsets in wet FGD process conditions can prompt Hg re-emission. Specifically, one observer

noted two units that “….experienced a scrubber reemission event causing the mercury stack

emissions to increase dramatically above the MATS limit and significantly higher than the

incoming mercury in the coal and the event lasting for several days.” 46 This high Hg event was

eventually remedied over the short-term operation, but long-term performance is not available.

7.3 Conclusions: Mercury Emissions - Non-Low Rank Coals

There is inadequate basis to further lower the Hg emissions rate below the present limit of 1.2

lbs/TBtu, as variability in fuel and process operations outside the control of the operator can

elevate emissions to approach or in some cases exceed that rate.

Gadgil, M., 20 Years of Mercury Re-emission – What do we Know?, Presentation to the Power Plant

Pollutant Control and Carbon Management Mega Symposium, August 16-18, 2016.

Blythe, G. et. al., Maximizing Co-Benefit Mercury Capture for MATS Compliance on Multiple CoalFired Units, Presentation to the Power Plant Pollutant Control and Carbon Management Conference Mega

Symposium, August 16-18, 2016.

Blyte, G. et. al., Investigation of Toxics Control by Wet FGD Systems, Presentation to the Power Plant

Pollutant Control and Carbon Management Conference Mega Symposium, August 16-18, 2016.

Pavlisch, J. et. al., Managing Mercury Reemission and Managing MATS compliance Using a sorbent

Approach, Presentation to the Power Plant Pollutant Control and Carbon Management Conference Mega

Symposium, August 16-18, 2016.

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EPA IPM Results: Evaluation and Critique

EPA IPM RESULTS: EVALUATION AND CRITIQUE

EPA used the Integrated Planning Model (IPM) to establish a Baseline Scenario from which to

measure compliance impacts of the proposed rule. This Baseline Scenario is premised upon

IPM’s Post-IRA 2022 Reference Case. In this Post-IRA simulation, IPM evaluated a number of

tax credit provisions of the Inflation Reduction Act of 2022 (IRA), which address application of

Carbon Capture and Storage (CCS) and other means to mitigate carbon dioxide (CO 2). These are

the (i) New Clean Electricity Production Tax Credit (45Y); (ii) New Clean Electricity Investment

Credit (48E); Manufacturing Production Credit (45X); CCS Credit (45Q); Nuclear Production

Credit (45U); and Production of Clean Hydrogen (45V). Also, the Post-IRA 2022 Reference

Case includes compliance with the proposed Good Neighbor Policy (Transport Rule). 47

A critique of EPA’s methodology and findings is described subsequently.

8.1 IPM 2030 Post-IRA 2022 Reference Case: A Flawed Baseline

The IPM Post-IRA 2022 Reference Case for the years 2028 and 2030 comprises a flawed

baseline to measure compliance impacts of the proposed rule. This flawed baseline centers

around IPM projected coal retirements in both 2028 and 2030 as well as units projected to deploy

CCS in 2030. Specifically, IPM has erroneously retired numerous coal units expected to operate

beyond 2028 and 2030 based upon current announced retirement plans; consequently, these units

are subject to the proposed rule beginning in 2028. There are numerous challenges and

limitations to deploying CCS as EPA has projected on 27 coal units in 2030. These units would

also be subject to the proposed. Consequently, IPM’s compliance impacts of the proposed rule is

likely understated.

8.1.1 Analytical Approach

This analysis identifies those units IPM modeled as coal retirements, CCS retrofits and coal to

gas (C2G) conversions in both 2028 and 2030, and compares them to announced plans for unit

retirements, technology retrofits and C2G conversions. To identify errors for 2028, the parsed

file for the 2028 Post-IRA 2022 Reference Case was used. Since EPA did not provide a parsed

In addition to the IRA and GNP, the Post-IRA 2022 Reference Case takes into account compliance

with the following: (i) Revised Cross-State Air Pollution Rule (CSAPR) Update Rule; (ii) Standards of

Performance for Greenhouse Gas Emissions from New, Modified and Reconstructed Stationary Sources:

Electric Utility Generating Units; (iii) MATS Rule which was finalized in 2011; (iv) Various current and

existing state regulations; (v) Current and existing RPS and Current Energy Standards; (vi) Regional

Haze Regulations and Guidelines for Best Available Retrofit Technology (BART); and, (vii) Platform

reflects California AB 32 and RGGI. Three non-air federal rules affecting EGUs: (i) Cooling Water

Intakes (316(b) Rule; (ii) Coal Combustion Residuals (CCR), which reflects EPA’s July 29, 2020 position

on retrofitting or closure of surface impoundments; and, (iii) Effluent Limitation Guidelines, which

includes the 2020 Steam Electric Reconsideration Rule (cost adders were applied starting in 2025).

(Page 225 of Total)

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EPA IPM Results: Evaluation and Critique

file of the 2030 Post-IRA 2022 Reference Case, an abbreviated parsed file was created using four

different IPM files. These are: (i) 2028 parsed file of the Post-IRA 2022 Reference Case; (ii)

Post-IRA 2022 Reference Case RPE File for the year 2030; (iii) Post-IRA 2022 Reference Case

RPT Capacity Retrofits File for the year 2030; and, (iv) National Electrical Energy Data System

(NEEDS) file for the Post-IRA 2022 Reference Case. These parsed files allow identifying IPM

modeled retirements in 2028 and 2030, CCS retrofits in 2030 and C2G in both 2028 and 2030.

These modeled retirements and conversions were compared to announced information in the

James Marchetti Inc ZEEMS Data Base.

8.1.2 Coal Retirements

The 2028 IPM modeling run retired 112 coal units (53.6 GW) from 2023 to 2028. In the 2030

analysis, IPM retired an additional 52 coal units (25.5 GW). The total number of retirements for

the two modeling run years is 164 coal units (79.1 GW).

Table 8-1 summarizes the IPM retirement errors in the 2028 and 2030 modeling runs.

Specifically, IPM incorrectly retired 29 coal units (14.0 GW) by 2028 and an additional 23 coal

units (14.1 GW) in 2030. In addition, there are 3 coal units (1.6 GW) that EPA listed in the

NEEDS file as being retired before 2028 that will operate beyond 2030. In total, there are 55

coal units that IPM erroneously retired in the 2028 and 2030 modeling runs that will be operating

and subject to some aspect of the proposed rule beginning in 2028.

Table 8-1. Coal Retirement Errors

Year

2028

2030

Total

Description

Retiring after 2028

Retiring after 2030

NEEDS retirements that should be in the 2030 modeling

platform

Number

Tables 8-2 to 8-6 lists each of the coal units IPM has incorrectly retired, incorrectly deployed

CCS, or switched to natural gas.

(Page 226 of Total)

410a

No.

RegionName

WECC_Arizona

SPP West

MISO_Arkansas

SERC_Central_TVA

MISO_Minn/Wisconsin

MISO_Missouri

SERC_VACAR

ERCOT_Rest

WECC_Utah

PJM_Dominion

PJM_AP

WECC_Wyoming

StateName

Arizona

Arkansas

Kentucky

Minnesota

Missouri

North Carolina

Texas

Utah

Virginia

West Virginia

Wyoming

ORISCode

6177

6138

6641

1379

6090

2103

2107

2712

298

7790

8069

7213

3943

6101

UnitID

U1B

3A.3B

4A, 4B

LIM1

LIM2

1-1

BW91

PlantName

Coronado

Flint Creek

Independence

Shawnee

Sherburne County

Labadie

Sioux

Roxboro

Limestone

Bonanza

Huntington

Clover

Fort Martin

Wyodak

Capacity

380

528

809

842

134

876

593

487

694

698

831

858

458

450

440

437

552

546

332

(Page 227 of Total)

Document #2058570

EIA 860 has retirement December 2029

Unit is planned to retire in 2030,

Retire in 2032 - 2023 IRP (3/31/23)

Dominion 2023 IRP - Retirement Date 2040 (5/1/23)

EPA Settlement on wastewater upgrades (8/9/22). 2020 IRP through 2035

EPA Settlement on wastewater upgrades (8/9/22). 2020 IRP through 2036

Retire in 2039 - IRP (3/31/23)

2022 Carbon Reduction Plan per PSC retirement Jan. 1, 2028-34 (12/30/22).

2023 Carbon Reduction Plan per PSC retirement Jan. 1, 2028-34 (12/30/22).

Observation

To be retired by 2032 and continued seasonal curtailemts,

Retire January 1, 2039 - Entergy LL 2023 IRP (March 31, 2023).

Agreement with Sierra Club and NPCA to cease coal by Dec 31, 2030.

TVA planning assumption retirement (5/21) - December 31, 2033

PSC approved closure (2/8/22). Upper Midwest Resource Plan (6/25/21) for 2030.

2022 IRP Update retire in 2042 (6/24/22).

2022 IRP Update (6/24/22) retirement in 2036

2022 IRP Update (6/24/22) - To be retired in 2030

Table 8-2. IPM Coal Retirement Errors: 2028 Post-IRA 2022 Reference Case Run

EPA IPM Results: Evaluation and Critique

USCA Case #24-1119

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411a

(Page 228 of Total)

RegionName

1 WECC_Arizona

2 FRCC

3 FRCC

4 SERC_Southeastern

5 SERC_Southeastern

6 PJM West

7 MISO_Iowa

8 SPP North

9 SPP North

10 SERC_Central_Kentucky

11 SERC_Central_Kentucky

12 SERC_Central_Kentucky

13 SPP North

14 SPP North

15 SERC_VACAR

16 SERC_VACAR

17 SERC_VACAR

18 SERC_VACAR

19 MISO_MT, SD, ND

20 SERC_VACAR

21 SERC_VACAR

22 SERC_VACAR

23 SERC_VACAR

24 PJM West

25 PJM West

26 PJM_AP

27 PJM_AP

StateName

Arizona

Florida

Georgia

Indiana

Iowa

Kansas

Kentucky

Missouri

North Carolina

North Dakota

South Carolina

West Virginia

ORISCode

6177

628

6257

1040

1167

6068

1241

1356

6065

6195

8042

2727

8222

6249

3935

3954

UnitID

U2B

Region Name

1 SPP_N

2 MIS_LA

3 WECC_WY

State Name

Kansas

Louisiana

Wyoming

ORIS

Plant

1241

6190

4158

Unit ID

3-1, 3-2

BW44

Plant Name

La Cygne

Brame Energy Center

Dave Johnston

Capacit

y (MW)

736

626

330

NEEDS

Retirement

2025

2027

Year

Retire in 2039 - 2023 IRP (3/31/23).

Observations

2022 IRP Update to be retired in 2032

No plans to retire. Evaluating CCS

Capacity Observations

382

To be retired by 2032 and contined seasonal curtailments

To be retired in 2034 (2020 Sustainability Report)

712

710

To be retired in 2034 (2020 Sustainability Report)

860

ELG Compliance - Wastewater Treatment - No Announced Retirement

860

ELG Compliance - Wastewater Treatment - No Announced Retirement

Biased to peak load duty. 2020 IRP Base Case has retirement May 31, 2034

163

ELG compliance options for FGDW and BATW, possible 2028 retirement

To be retired at the end of 2039 (2021 IRP)

728

662

To be retired at the end of 2039 (2021 IRP)

474

To be retired 2034

485

To be retired 2037.

465

To be retired 2037.

700

To be retired at the end of 2039 (2021 IRP)

184

Beyond 2030 retirement date - new 2022 IRP

1110

1/1/2036 retirement per 2022 Carbon Reduction Plan

1110

1/1/2036 retirement per 2022 Carbon Reduction Plan

658

2022 Carbon Reduction Plan accepted by PSC retirement Jan. 1, 2033 (12/30/22)

660

2022 Carbon Reduction Plan accepted by PSC retirement Jan. 1, 2033 (12/30/22)

429

Active perl reliablity concerns in MISO. End of depreciable life - 2041

275

2023 IRP: operate unit through 2030 for reliability (4/19/23)

285

2024 IRP: operate unit through 2030 for reliability (4/19/23)

285

2025 IRP: operate unit through 2030 for reliability (4/19/23)

285

2026 IRP: operate unit through 2030 for reliability (4/19/23)

800

Approved ELG upgrades to keep plant open until 2040.

800

Approved ELG upgrades to keep plant open until 2040.

554

Dominion 2023 IRP - Retirement Date 2044 (5/1/23)

555

Dominion 2023 IRP - Retirement Date 2044 (5/1/23)

Filed: 06/07/2024

No.

PlantName

Coronado

Crystal River

Scherer

Whitewater Valley

Muscatine Plant #1

Jeffrey Energy Center

La Cygne

Ghent

Iatan

John Twitty

Belews Creek

Marshall (NC)

Coyote

Winyah

John E Amos

Mt Storm

Document #2058570

Table 8-4 Units in the NEEDS to Be Operating in 2028

No.

Table 8-3. IPM Coal Retirement Errors: 2030 Post IRA 2022 Reference Case Modeling Run

EPA IPM Results: Evaluation and Critique

USCA Case #24-1119

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412a

(Page 229 of Total)

Region Name

1 ERCOT_Rest

2 ERCOT_Rest

3 ERCOT_Rest

4 ERCOT_Rest

5 ERCOT_Rest

6 FRCC

7 MISO_Indiana

8 PJM West

9 PJM West

10 PJM West

11 SERC_Southeastern

12 SPP_WAUE

13 SPP_WAUE

14 SPP_WAUE

15 WECC_Arizona

16 WECC_Arizona

17 WECC_Colorado

18 WECC_Colorado

19 WECC_Utah

20 WECC_Utah

21 WECC_Utah

22 WECC_Utah

23 WECC_Wyoming

24 WECC_Wyoming

25 WECC_Wyoming

26 WECC_Wyoming

27 WECC_Wyoming

StateName

Texas

Florida

Indiana

Kentucky

West Virginia

Alabama

North Dakota

Arizona

Colorado

Utah

Wyoming

ORISCode

6179

7097

6180

6183

645

6113

6018

3948

6002

6469

2817

8223

470

6021

6165

8069

8066

6204

UnitID

BLR2

SM-1

BB04

BW73

BW74

Laramie River Station

Comanche (CO)

Craig (CO)

Hunter

Huntington

Jim Bridger

Laramie River Station

Springerville

East Bend

Mitchell (WV)

James H Miller Jr

Antelope Valley

Leland Olds

Gibson

PlantName

Fayette Power Project

J K Spruce

Oak Grove (TX)

San Miguel

Big Bend

RegionName

StateName ORISCode

SPP West (Oklahoma, Arkansas

Arkansas, Louisiana)

56564

PJM West

Kentucky 6041

ERCOT_Rest

Texas

56611

UnitID

S01

PlantName

John W Turk Jr Power Plant

H L Spurlock

Sandy Creek Energy Station

Year

2030

2028

2030

Capacity Observations

609 Retire Jan 1, 2068 - SWEPCO 2023 IRP (March 29, 2023)

510 No announced C2G or co-firing

933 No announced conversion

Convert to natural gas in 2030 - 2023 IRP (3/31/23)

Retire in 2032 - 2023 IRP (3/31/23).

To be retired Dec 31 2030 (10/31/22)

To be retired Dec 2029 - Electric Resource Plan (12/1/20)

Retire in 2031- 2023 IRP (3/31/23)

Board voted to convert to natural gas by 2027 (1/23/23)

Observations

Filed: 06/07/2024

No.

Capacity

286.05

537.93

572.77

570.97

237.74

292.27

594.24

399.00

537.77

477.05

289.22

288.38

279.16

281.05

501.15

305.66

319.80

292.44

314.06

311.54

354.02

349.78

385.22

382.92

383.45

Document #2058570

Table 8-6 Units IPM Erroneously Predicts Switch to Natural Gas

No.

Table 8-5 Units IPM Predicts CCS By 2030

EPA IPM Results: Evaluation and Critique

USCA Case #24-1119

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EPA IPM Results: Evaluation and Critique

8.1.3 Coal CCS

Table 8-5 identifies the 27 units IPM projected to retrofit CCS by 2030; none of these have been

involved in any Front-End Engineering and Design (FEED) Studies. However, 9 of the units

identified by IPM will be either be retired or converted to natural gas in and around 2030. There

are major questions addressing infrastructure and project implementation that present challenges

to IPM’s CCS projection for 2030. Indeed, it is next to impossible for these units to be in

position to retrofit CCS by 2030.

8.1.4 Coal to Gas Conversions (C2G)

The 2028 IPM modeling run converted 36 coal units to gas (14.3 GW). In the 2030 IPM

modeling run an additional 2 coal units (1.5 GW) were converted to gas (Turk and Sandy Creek).

As shown in Table 8.6, three of these units have no announced plans to convert to gas by 2028 or

2030 and will be subject to the proposed rule.

8.2 Summary

The major issues associated with EPA’s IPM modeling of the 2028 and 2030 Post-IRA 2022

Reference Case are summarized as follows:

•

The 2028 and 2030 Baseline (Post-IRA 2022 Reference Case) used to measure the

compliance impacts of proposed rule is flawed and needs to be revised

Most notably, IPM erred in retiring 55 coal units that will be subject to the proposed rule

beginning in 2028.

IPM retrofitted 27 units with CCS in 2030, 19 of which will be subject to the proposed

rule. It is next to impossible for these units to retrofit CCS by 2030.

The IPM modeled compliance impacts for the proposed rule in 2028 and 2030 is very

likely understated.

(Page 230 of Total)

414a

(Page 231 of Total)

Colstrip 3

Labadie 2

Labadie 1

Labadie 4

Labadie 3

Note: Colstrip costs reflect EPA's approch of retrofitting a fabric

filter, as an ESP is not installed at that site.

Colstrip 4

D B Wilson Martin Lake Mt Storm 3 Martin Lake Walter Scott Mt Storm 1,

Jr Energy

Filed: 06/07/2024

Appendix A

Document #2058570

100

120

140

160

Figure A-1.. Unit ESP Investment (per EPA’s Cost Assumptions):

Assumptions) PM of 0.010 lbs/MBtu

Appendix A: Additional Cost Study Data

Potential Investment for 0.010 lbs/MBtu, $M

USCA Case #24-1119

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415a

(Page 232 of Total)

ESP Typical

East Bend

General James M Gavin

Gibson

Martin Lake 2

Milton R Young

Mt Storm

ESP Minor

Alcoa/Warrick

Big Bend

Coronado

Crystal River

Jeffrey Energy Center

Laramie River Station

Martin Lake

San Miguel

Seminole

Labadie

Martin Lake 1

ESP Major Upgrade

D B Wilson

Clover Power Project

Ghent

Gilberton Power/John B Rich

H L Spurlock

Iatan

Marion

Mt Carmel Cogen

St Nicholas Cogen Project

Walter Scott Jr Energy Center

WPS Westwood Generation LLC

FF Cleaning

Boswell Energy Center

Table A-1. Technology Assignment for 0.010 lbs/MBtu PM Rate: Industry Study

FF Retrofit

Colstrip 3, 4

Appendix A

USCA Case #24-1119

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Appendix A

Table A-2 Technology Assignment for 0.006 lbs/MBtu PM Rate: Industry Study

FF O&M Enhancement

Antelope Valley

Bonanza

FF Retrofit

Alcoa/Warrick

Belews Creek

FF Retrofit

Laramie River Station

Leland Olds 1, 2

Boswell Energy Center Clay Boswell

Clover Power Project

Comanche

Ghent

Gilberton Power/John B Rich

H L Spurlock

Huntington

Iatan

Louisa

Marion

Mt Carmel Cogen

Oak Grove 1

Sandy Creek Energy Station

Scrubgrass Generating 1, 2

St Nicholas Cogen Project

Twin Oaks Power 1, 2

Walter Scott Jr Energy Center

Weston

WPS Westwood Generation LLC

Big Bend

Cardinal

Colstrip 3, 4

Coronado 1, 2

Crystal River 4, 5

D B Wilson

East Bend

General James M Gavin

Gibson 1, 3

Gibson

Independence

IPL - AES Petersburg

James H Miller Jr

Jeffrey Energy Center 1, 2, 3

Jim Bridger 3, 4

Labadie 1 -4

Martin Lake 1-3

Merrimack

Milton R Young

Monroe 1, 2

Mt Storm 1, 2

Naughton

Nebraska City

R D Green

R S Nelson

Sam Seymour Fayette 1, 2

San Miguel

Schiller

Seminole

Trimble County

Whelan Energy Center

White Bluff 1, 2

(Page 233 of Total)

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Appendix B

Appendix B: Example Data Chart

Appendix A presents additional examples of units for which EPA’s PM sampling and evaluation

approach distorted results. These charts contain both mean and 99 th percentile data. Data is

presented for the following units, for which observations are offered as follows:

•

TVA Gallatin Unit 1. EPA selected 0.0030 lbs/MBtu as the reference PM rate, using Q4

of 2019. Few of the 16 quarters that report lower PM emissions.

•

TVA Gallatin Unit 2. EPA selected 0.0031 lbs/MBtu as the reference PM rate, also using

Q4 of 2019. Few of the 16 quarters that report lower PM, similar to Unit 1.

•

TVA Gallatin Unit 3. EPA selected 0.0016 lbs/MBtu as the reference PM rate, again

using Q4 of 2019. Only one quarter (Q3 of 2019) reports lower PM rate.

•

TVA Gallatin Unit 4. EPA selected 0.0022 lbs/MBtu as the reference PM rate, using Q1

of 2021. Of the 14 quarters reporting data, two quarters report PM rates equal to this rate,

while two are below this rate.

•

LG&E/KU Ghent 1. EPA selected 0.005 lbs/MBtu as the reference PM rate, using Q2 of

2019. This PM rate represents that reported in previous quarters, but with one exception

all subsequent quarters through 2021 report higher PM.

•

LG&E/KU Mill Creek Unit 4. EPA selected 0.0035 lbs/MBtu as the reference PM rate,

using Q4 of 2021. With the exception of the previous quarter, this value is the lowest of

any reported since 2017 by a significant margin.

•

Alabama Power Gaston Unit 5. EPA selected 0.005 lbs/MBtu as the reference PM rate,

using Q1 of 2021. Data for this unit is displayed from Q1 2017 through Q4 2022. Of the

24 reporting quarters (1Q 2017 through 4QW 2022) only 6 quarters have lower PM rates.

•

Alabama Power Miller Unit 1. EPA selected 0.004 lbs/MBtu as the reference PM rate,

using Q3 of 2017. Data for this unit is displayed from Q1 2017 through Q4 2022. The

designated rate represents a significant reduction from approximately half of the

reporting quarters since Q1 2020.

(Page 234 of Total)

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Appendix B

PM Emission Rate, Mean and 99th Percentile (lbs/MBtu)

0.018

TVA Gallatin Unit 1

Mean PM Rate

99th Percentile Rate

0.016

0.014

0.012

0.010

0.008

EPA Reference

Quarter

0.006

0.004

0.002

0.000

18 Q1 18 Q2 18 Q3

1 Q4

19 Q1 19 Q2 19 Q3 19 Q4 20 Q1 20 Q2 20 Q3 20 Q4 21 Q1 21 Q2 21 Q3 21 Q4

2018

2019

2020

2021

PM Emission Rate, Mean and 99th Percentile (lbs/MBtu)

0.018

TVA Gallatin Unit 2

Mean PM Rate

99th Percentile Rate

0.016

0.014

0.012

0.010

0.008

EPA Reference

Quarter

0.006

0.004

0.002

0.000

18 Q1 18 Q2 18 Q3

2018

(Page 235 of Total)

1 Q4

19 Q1 19 Q2 19 Q3 19 Q4 20 Q1 20 Q2 20 Q3 20 Q4 21 Q1 21 Q2 21 Q3 21 Q4

2019

2020

2021

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Appendix B

PM Emission Rate, Mean and 99th Percentile (lbs/MBtu)

0.012

TVA Gallatin Unit 3

Mean PM Rate

99th Percentile Rate

0.010

0.008

0.006

EPA Reference

Quarter

0.004

0.002

0.000

18 Q1 18 Q2 18 Q3

1 Q4

19 Q1 19 Q2 19 Q3 19 Q4 20 Q1 20 Q2 20 Q3 20 Q4 21 Q1 21 Q2 21 Q3 21 Q4

2019

2018

2020

2021

PM Emission Rate, Mean and 99th Percentile (lbs/MBtu)

0.012

TVA Gallatin Unit 3

Mean PM Rate

99th Percentile Rate

0.010

0.008

0.006

EPA Reference

Quarter

0.004

0.002

0.000

18 Q1 18 Q2 18 Q3

2018

(Page 236 of Total)

1 Q4

19 Q1 19 Q2 19 Q3 19 Q4 20 Q1 20 Q2 20 Q3 20 Q4 21 Q1 21 Q2 21 Q3 21 Q4

2019

2020

2021

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Appendix B

PM Emission Rate, Mean and 99th Percentile (lbs/MBtu)

0.020

Mean PM Rate

99th Percentile Rate

Ghent Unit 1

0.015

0.010

EPA Reference

Quarter

0.005

0.000

PM Emission Rate, Mean and 99th Percentile (lbs/MBtu)

0.030

Mean PM Rate

99th Percentile Rate

Mill Creek Unit 4

0.025

0.020

0.015

0.010

EPA Reference

Quarter

0.005

0.000

(Page 237 of Total)

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Appendix B

0.025

Mean PM Rate

99th Percentile Rate

Gaston Unit 5

PM Emission Rate (lbs/MBtu)

0.020

0.015

EPA Reference

Quarter

0.010

0.005

0.000

0.025

Mean PM Rate

99th Percentile Rate

Miller Unit 1

PM Emission Rate (lbs/MBtu)

0.020

0.015

0.010

EPA Reference

Quarter

0.005

0.000

(Page 238 of Total)

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Appendix B

0.035

Mean

PM Emission Rate (lbs/MBtu)

0.030

Trimble County 1

99th

0.025

0.020

0.015

0.010

EPA Reference

Quarter

0.005

0.000

(Page 239 of Total)

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ATTACHMENT C

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MEMORANDUM

Date:

December 16, 2011

Subject:

Emission Reduction Costs for Beyond-the-floor Mercury Rate for Existing Units

Designed to Burn Low Rank Virgin Coal

From:

Kevin Culligan, SPPD/OAQPS

To:

EPA-HQ-OAR-2009-0234

For the final rule, EPA has recalculated the beyond the floor control costs for existing

units designed to burn low rank virgin coal using a methodology similar to that used in the IPM

analysis done for the MATS proposal. In the final rule, we have not recalculated control costs

based on the other methodology used in the proposal which used ACI capital and operating costs

provided in the ICR. We have not used that approach because it was based upon an assumption

that all units would need to have a baghouse (also known as a fabric filter – FF – either existing

or newly installed) in order to meet the MACT PM standard and that the ACI would be used with

the baghouse. EPA has considered and used additional information demonstrating that high

levels of mercury removal can be achieved with injection of brominated activated carbon and the

addition of a FF is not necessary. Furthermore, based on additional analysis related to the PM

standard, EPA believes that most lignite units will not need to install new FF, therefore, EPA

believes a costing methodology based on this assumption would be inappropriate.

For this analysis, EPA calculated beyond-the-floor costs for mercury controls by

assuming injection of brominated activated carbon at a rate of 3.0 lb/MACF for units with ESPs

and injection rates of 2.0 lb/MACF for units with baghouses (also known as fabric filters). The

rate of 2.0 lb/MACF for fabric filters is consistent with the rate assumed in all other IPM

analyses for this rule. The rate of 3.0 lb/MACF for units with ESPs is lower than the rate of 5.0

lb/MACF assumed in the IPM analysis. EPA believes that this rate is appropriate, because a

higher rate would likely result in reductions beyond those needed to meet the BTF standard of

4.0 lb/TBtu. Figure 1 in "Activated Carbon Injection for Mercury: Overview" 1 suggests that >

90% control can be achieved at lignite-fired units at a < 2.0 lb/MACF injection rate for units with

installed FF and using treated (i.e., brominated) AC. The figure also suggests that > 90% Hg

control can be achieved at lignite-fired units at < 3.0 lb/MACF injection rate for units with

installed ESPs and using treated AC. As Table 1 below shows, based on the IPM analysis, all

units would need to achieve reductions of less than 90%, therefore lower assumed injection rates

are appropriate.

Fuel Processing Technology 89 (2010) 1310

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Table 1 – Emission Reduction Rates Required to Meet Standard of 4 lb/TBtu.

Plant Name

Big Brown

Lewis & Clark

Martin Lake

Monticello

R M Heskett

Leland Olds

Milton R Young

Stanton

Limestone

Dolet Hills

Coal Creek

Laramie River Station

Antelope Valley

Twin Oaks Power One

Pirkey

Coyote

Great River Energy Spiritwood Station

Unit ID Hg Controls Existing Controls

ACI

Cold-side ESP + Fabric Filter + SNCR

ACI

Cold-side ESP + Fabric Filter + SNCR

ACI

Wet Scrubber

ACI

Cold-side ESP + Wet Scrubber

ACI

Cold-side ESP + Wet Scrubber

ACI

Cold-side ESP + Wet Scrubber

ACI

Cold-side ESP + SNCR + Wet Scrubber

Cold-side ESP

Cold-side ESP + Cyclone

Cold-side ESP

Cold-side ESP + SCR + Wet Scrubber

Cold-side ESP

Fabric Filter + Dry Scrubber

LIM1

Cold-side ESP + Wet Scrubber

LIM2

Cold-side ESP + Wet Scrubber

Fabric Filter + Dry Scrubber

Fabric Filter

Cold-side ESP + Wet Scrubber

Fabric Filter + Dry Scrubber

Cold-side ESP + Fabric Filter + SNCR + Dry Scrubber

Base

Reduction

Policy

Hg lbs/Tbtu Required, % Hg lbs/Tbtu

9.09

55.98

1.01

9.09

55.98

1.01

7.68

47.92

0.75

5.41

26.09

0.56

5.41

26.09

0.56

5.41

26.09

0.56

6.30

36.53

0.96

7.81

48.77

0.45

4.76

16.00

0.75

7.68

47.93

0.77

7.81

48.77

0.78

4.21

4.93

0.75

4.21

4.93

0.75

7.81

48.77

0.78

7.51

46.76

0.75

6.75

40.76

1.13

6.75

40.76

1.13

8.33

51.98

1.35

4.21

5.07

0.76

4.21

5.07

0.76

5.31

24.71

0.56

5.31

24.71

0.56

7.51

46.76

0.75

7.51

46.76

0.75

5.82

31.33

1.35

5.82

31.33

1.35

7.59

47.27

1.35

7.64

47.66

0.75

7.68

47.92

0.75

EPA also assumed a disposal cost of $25/ton for ash comingled with activated carbon.

This cost is consistent with a range of studies. DOE/NETL, in a recent study examining the

costs of ACI, assumed total disposal costs of $17/ton for non-hazardous fly ash. They assumed

$35/ton for fly ash that would have otherwise been sold for beneficial reuse (lost revenue of

$18/ton plus disposal costs of $17/ton for non-hazardous fly ash). 2 In an EPA study, $25 - $30

per ton were assumed as total disposal costs.3

EPA recently modeled site-specific disposal costs for the RIA 4 for the proposed rule

regulating coal combustion residuals (CCRs), including fly ash. Those costs were examined for

units burning low rank virgin coal. The disposal costs varied by state/region. For Texas the

incremental costs attributable to Hg control were $18.13/ton, while for North Dakota and

Montana, the incremental costs attributable to Hg control were $32.31/ton.

Environmental Sci. Technol. 2007, 41, 1365].

Environmental Sci. Technol. 2006, 1385

Regulatory Impact Analysis For EPA’s Proposed RCRA Regulation Of Coal Combustion Residues (CCR)

Generated by the Electric Utility Industry. Prepared by US Environmental Protection Agency Office of Resource

Conservation & Recovery (ORCR) (formerly Office of Solid Waste) 1200 Pennsylvania Avenue NW (Mailstop

5305P) Washington DC, 20460 USA. Available at http://www.regulations.gov/ docket number EPA-HQ-RCRA2009-0640-0003, Appendix H.

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Based on these key assumptions, EPA projects an average reduction cost of $27,017 per

pound of Hg removed. Unit by unit costs are provided in Table 2.

Table 2 – Unit by unit cost estimates for achieving an emission rate of 4 lb/TBtu Hg

Plant Name

Unit ID

Capacity

(MW)

Heat Rate Existing PM

(Btu/kWh) Controls

Big Brown

575

11001

Big Brown

575

10931

Lewis & Clark

52.3

13787

Martin Lake

750

11512

Martin Lake

750

11202

Martin Lake

750

10784

Monticello

750

11246

R M Heskett

29.37

11985

R M Heskett

75.5

11386

Leland Olds

221

448

11404

11021

Milton R Young

250

10661

Milton R Young

455

10661

Stanton

130.3472 10990

Stanton

57.35278 10320

Limestone

LIM1

831

10102

Limestone

LIM2

858

10108

(Page 243 of Total)

Cold-side ESP +

Fabric Filter +

SNCR

Cold-side ESP +

Fabric Filter +

SNCR

Wet Scrubber

Cold-side ESP +

Wet Scrubber

Cold-side ESP +

Wet Scrubber

Cold-side ESP +

Wet Scrubber

Cold-side ESP +

SNCR + Wet

Scrubber

Cold-side ESP

Cold-side ESP +

Cyclone

Cold-side ESP

Cold-side ESP +

SCR + Wet

Scrubber

Cold-side ESP +

SCR + Wet

Scrubber

Cold-side ESP

Fabric Filter +

Dry Scrubber

Cold-side ESP +

Wet Scrubber

Cold-side ESP +

(Base to

Policy) Hg

remv'd (lbm)

(2007$) unit

S/lbm Hg

Total

Cost

-396

3954

1565723

-393

3980

1565723

-31

22920

704682

-332

32175

10671737

-323

32174

10383770

-311

32309

10038209

-359

29249

10487787

-17

38871

652353

-22

53992

1206545

-109

-217

25792

23822

2812406

5176973

-64

51542

3272935

-116

49018

5665257

-77

26601

2050240

-31

30538

935770.1

-372

29034

10797351

-384

28982

11134608

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Coal Creek

554

11219

Coal Creek

560.3

10818

565

11312

570

10953

Antelope Valley

450

10988

Antelope Valley

450

11206

152

9497

153

10364

Coyote

427

11639

Pirkey

675

10693

Laramie River

Station

Laramie River

Station

Twin Oaks Power

One

Twin Oaks Power

One

Filed: 06/07/2024

Wet Scrubber

Cold-side ESP +

Wet Scrubber

Cold-side ESP +

Wet Scrubber

Cold-side ESP +

Wet Scrubber

Cold-side ESP +

Wet Scrubber

Fabric Filter +

Dry Scrubber

Fabric Filter +

Dry Scrubber

-162

48056

7781365

-158

47982

7576786

-235

34742

8170580

-230

34737

7980115

-264

22315

5888636

-269

22269

5993120

Fabric Filter

-50

38215

1900963

Fabric Filter

-55

37778

2064287

-228

22122

5043515

-349

26185

9140141

-46

11694

535381.6

-351

27064

9500464

Fabric Filter +

Dry Scrubber

Cold-side ESP +

Wet Scrubber

Great River Energy

Spiritwood Station

8937

Cold-side ESP +

Fabric Filter +

SNCR + Dry

Scrubber

Dolet Hills

650

10674

Cold-side ESP +

Wet Scrubber

Total

Average

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-5948

1.61E+08

27016

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ATTACHMENT D

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Minnkota Power Cooperative, Inc.

Milton R. Young Station Unit 2

Particulate & Mercury Control

Technology Evaluation & Risk

Assessment for Proposed MATS Rule

Final

June 23, 2023

Project No.: A14559.010

S&L Nuclear QA Program Applicable:

 Yes

 No

55 East Monroe Street

Chicago, IL 60603-5780 USA

312-269-2000

www.sargentlundy.com

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1.INTRODUCTION

1.1. PURPOSE

Sargent

& Lundy (S&L) was retained by Minnkota Power Cooperative, Inc. (Minnkota) to evaluate potential

filterable particulate matter (PM) and mercury (Hg) emissions reductions in response to the proposed rule to

amend the National Emission Standards for Hazardous Air Pollutants (NESHAP) for Coal-and Oil-Fired

Electric Utility Steam Generating Units (EGUs), commonly known as Mercury and Air Toxics Standards

(MATS) published on April 24, 2023 that would require additional filterable PM and Hg emissions reductions

on the Milton R. Young (MRY) Station Unit 2. These proposed revisions are the result of EPA’s review of the

residual risk and technology review (RTR) from May 22, 2020. Based on the proposed rule, EPA is planning

to revise the filterable PM standards from 0.030 lb/MMBtu to 0.010 lb/MMBtu and is soliciting comments to

consider even more stringent standard of 0.006 lb/MMBtu or lower. For lignite-fired units, EPA is also

proposing to revise and tighten mercury emission standard from 4.0 lb/TBtu to 1.2 lb/TBtu to make it same as

other units firing bituminous and subbituminous coal.

S&L reviewed the existing MRY Unit 2 PM and Hg control technologies to determine potential optimizations

that could achieve incremental emission reductions as well as consider new PM and Hg control technologies.

S&L prepared an evaluation of available control technologies including technical feasibility and effectiveness,

and costs based on the current emissions from the unit. S&L’s evaluation was completed based on past

experience on similar projects, as well as input from established original equipment manufacturers (OEMs)

regarding predicted performance for the lignite application at MRY Unit 2.

1.2. FACILITY BACKGROUND

The MRY station is located approximately seven (7) miles southeast of Center, North Dakota or forty (40)

miles northwest of Bismarck, North Dakota on ND Highway 25 at 3401 24th Street SW, Center, North Dakota

58530. MRY station provides energy to the Midcontinent Independent System Operator (MISO) system. MRY

station consists of two (2) units. Both MRY units are lignite-fired Babcock and Wilcox (B&W) cyclone boilers.

The Unit 1 single wall cyclone boiler was placed into service in 1970 and has a typical output capacity rating

of 257 MWg (gross). The Unit 2 opposed wall cyclone boiler (Carolina type, radiant pump assisted natural

circulation) was placed into service in 1977 and has a typical output capacity rating of 470 MWg (gross). Both

boilers fire North Dakota lignite coal supplied from BNI Coal, Ltd.’s Center Mine located in close proximity to

the plant. Both units utilize selective non-catalytic reduction (SNCR) and separated overfire air (SOFA)

systems for NOx control, fuel additive (halide injection) system and non-halogenated powdered activated

carbon (PAC) for Hg control, dry electrostatic precipitators (ESP) for PM emissions control, and wet flue gas

desulfurization (WFGD) systems for sulfur dioxide (SO2) control.

1.3. DIFFERENCES IN MRY UNIT 1 AND 2 DESIGN & OPERATION

MRY Unit 1 and 2 have the same air pollution control equipment in series; however, the design of the

equipment differ in ways other than unit MWg size. Of particular note, the Unit 2 ESP design attributes are

superior to Unit 1, with use of a wider plate spacing (12 vs. 9 inches), and a higher specific collection area

(375 ft2/1000 actual cubic feet per minute (acfm) vs. 288 ft2/1000 acfm). However, the Unit 2 ESP design

consists of the first 2 fields' specific corona power = 160 W/1000 acfm and the last 2 fields = 240 W/1000 acfm,

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which is consistent with historic ESP designs where transformer-rectifier (T/R) sets were typically selected to

provide lower current density at the inlet sections, where the dust concentration will tend to suppress the

corona current, and to provide higher current density at the outlet sections, where there is a greater percentage

of fine particles. In comparison, the Unit 1 ESP design does not follow this approach, with all fields’ specific

corona power = 493 W/1000 acfm and is currently achieving significantly lower PM emissions than Unit 2. The

single Unit 1 WFGD vessel has four (4) slurry recycle pumps (SRPs). Each of the two (2) WFGD vessels on

Unit 2 have five (5) SRPs.

Furthermore, manual cleaning of the boiler on Unit 1 is also able to include air preheater (APH) cleaning,

whereas the large hoppers below the Unit 2 APH prevent APH washes from being completed during shortterm boiler cleaning outages. The Unit 1 offline cleaning occurs on average every 110-115 days and requires

the unit to be offline typically for three (3) days. The Unit 2 offline cleaning (only including APH tube rodding)

occurs on average every 85-90 days and requires the unit to be offline typically for four (4) days.

1.4. CU

CURRENT BASELINE EMISSIONS

Minnkota provided the past five (5) years of emissions to establish baseline emissions used for this evaluation.

The baseline emissions were developed using data submitted by Minnkota to the EPA between January 01,

2018 through December 31, 2022 as part of emissions reporting requirements. For PM emissions, a 30-boiler

operating day rolling average was selected as the baseline PM emission calculation methodology to be in-line

with the permit reporting requirements. For Hg emissions, the maximum 30-boiler operating day experienced

during the evaluation period was selected as the baseline Hg emission.

Table 1-1 — Baseline Unit 2 PM & Hg Emissions

Parameter

Units

Unit 2

PM Emissions

lb/MMBtu

0.015

Hg Emissions

lb/TBtu

3.90

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2.PARTICULATE TECHNOLOGY EVALUATION

As part of this evaluation, PM control technologies were evaluated based on achieving post-upgrade emissions

limits in accordance with the proposed emissions included in the April 24, 2023, MATS proposed rule, 0.010

lb/MMBtu and potentially 0.006 lb/MMBtu. The description and assessment of each control option are

discussed in the sections below.

2.1. OP

OPTIONS TO REACH 0.010 LB/MMBTU

2.1.1.Increased Boiler Cleaning Outages

When manual cleaning of the boiler occurs, the following unit operation indicates reduced economizer outlet

temperatures and subsequently APH outlet temperatures. The fly ash resistivity is reduced at lower

temperatures making it easier to capture in the ESP. The decrease in temperature would also slightly reduce

the volumetric flow through the ESP, which may also allow for improved flow and velocity through the ESP,

subsequently improving the ESP overall performance. Although scheduling short term outages to complete

cleaning of the boiler on a regular basis (regardless of near-term long-term outages) has shown the ability to

maintain emissions below the baseline emissions, a PM emission of 0.010 lb/MMBtu likely cannot be achieved

and therefore this option was not considered further.

2.1.2.Flow & Distribution Devices

Uniform gas and dust distribution to each ESP casing will allow for uniform treatment/conditions of each casing

to facilitate optimal performance of each. Concentrated flow and/or dust to a casing will require that casing to

work harder than the others, ultimately contributing to and/or causing other operating inefficiencies within the

ESP to reduce its PM removal capabilities. Replacement of existing inlet and outlet flow & dust distribution

devices to achieve the latest standards of the Institute of Clean Air Companies (ICAC) Publication No. EP-7

will improve the ESP overall performance. Implementation of other flow correction devices to minimize

sneakage between cells and/or around collecting fields as well as to minimize particle re-entrainment from

hoppers and collecting surfaces when rapped can also be implemented, as required, to meet best industry

practices, if not already implemented as part of ESP designs.

A detailed assessment including computational flow dynamic (CFD) analysis and physical flow model studies

would be performed to determine the design and placement of all flow and dust distribution devices. New

designs of perforated plates (with rappers) would be implemented to allow for the easy removal of fly ash into

the first field hopper to minimize the potential fly ash accumulation in the inlet plenum. Although PM emissions

reductions are expected to be achieved with this option, a PM emission of 0.010 lb/MMBtu likely cannot be

achieved and therefore this option was not considered further.

2.1.3.Increased Power Supply

In an ESP, the collection efficiency is proportional to the amount of corona power supplied to the unit, assuming

the corona power is applied effectively (maintains a good sparking rate). The resulting corona current charges

the PM in the flue gas which are then attracted to the grounded, oppositely charged collecting plates. For a

given flow rate, the collection efficiency will increase as the corona power is increased. To achieve a high

collection efficiency, corona power is usually between 100 and 500 W/1000 acfm, but newer ESP installations

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have been designed for as much as 800-900 W/1000 acfm.

Increasing the power delivered into the ESP casing for this option would be done by replacing the T/R sets

with higher rated power supplies, e.g. switch mode power supplies (SMPS), also referred as high frequency

T/R sets, or 3-phase power supplies. Replacement of the T/R sets will require new cables, as the existing

cables for 2-phase will need to be upgraded to accommodate 3-phase; cables are assumed to be able to be

pulled while the unit continues to operate. Further assessment would be required to determine all electrical

infrastructure modifications required, including the ability to reuse the existing MCC and T/R set controls.

Although PM emissions reductions are expected to be achieved with this option, a PM emission limit of 0.010

lb/MMBtu with adequate operating margin likely cannot be achieved and therefore this option was not

considered further.

2.1.4.Additional ESP Field

As ESP performance does depend on the number of fields in the direction of flue gas flow, the addition of

another field will increase the amount of power that can be supplied to the ESP and provide incremental

removal of the filterable PM. As approximately 80% of the ash is expected to be collected in the first field, with

decreasing degrees of particulate removal in the following fields, the last field in the ESP casing is expected

to have the least amount of fly ash removed. This option can be implemented by either increasing the

sectionalization of the last field (adding a T/R set) or potentially by utilizing the ESP outlet nozzle to retrofit

another independently operated ESP field.

Sectionalization in the direction of gas flow is not feasible without a rebuild of the fields to be sectionalized as

the current high voltage frames span the entire length of the field. Therefore, this option is only feasible if a

new field is added at either the inlet or outlet of the existing ESP casing (assuming space available). However,

the retrofit implications of this option would be considered to be a large capital retrofit project in lieu of an

equipment optimization. This option is not anticipated to provide significant enough cost savings compared to

the other large capital retrofit options that will be evaluated later in this evaluation. Therefore, this option is not

considered further.

2.1.5.Additional ESP Casing

Installation of additional ESP casings in parallel to the existing Unit 2 ESP casings would increase the specific

collecting area (SCA) and improve the velocity and treatment time of the existing ESP casings. The smaller

wing ESP casings would be installed adjacent to the existing ESP casings, one added to north of Casing A

and one added to the south of Casing B. The new wing casings will utilize a separate support structure and

new power supplies to be independent, stand-alone structures. It is anticipated that modifications to the inlet

and outlet ductwork would be required to evenly balance the flow to the new casings. The hoppers of the new

ESP casings would be tied into the existing fly ash handling system. Although PM emissions reductions are

expected to be achieved with this option, a PM emission limit of 0.010 lb/MMBtu with adequate operating

margin likely cannot be achieved and therefore this option was not considered further.

2.1.6.ESP Rebuild

Rebuilding the existing Unit 2 ESP would involve replacement of all internals, while only reusing the outer

shell/walls, hoppers, support structures, and ash conveying system. To accomplish the rebuild of the ESP

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casings, the roof, T/R sets, high voltage bus ducts, top end frames, intermediate roof beams, the top section

of the inlet and outlet nozzles and all internal components of the existing ESPs will be removed, and replaced

with new equipment. The flow distribution and correction devices in the inlet and outlet plenums would be

replaced to optimize the flue gas and fly ash distribution to the casings. The hot and cold roofs would also be

replaced as well to accommodate construction activities.

Before moving forward with rebuild, a structural integrity and thickness study should be completed on the

entire structure to ensure that the steel has not thinned as a result of normal long-term option. The design of

the support structure (casing, structural members, and determination of ESP loads to steel), support steel and

foundation will need to be reviewed to verify if acceptable for reuse or if modifications are required for the

weight change in the ESP casings as a result of the rebuild, which may result in additional reinforcement

required. The existing ash handling systems would be reused without requiring any modifications for the

incremental increase in the amount of ash collected. It would be assumed that the complete rebuild of the ESP

casings and optimization of the flow distribution/collection devices in the inlet and outlet nozzles should be

capable of achieving no net increase in the current pressure drop across the ESP and therefore would not

require modifications or replacement of the existing ID fans.

The level of rebuild and repair to the existing ESP casings will require a longer construction outage, most likely

requiring a twelve (12) week outage, if not longer. Limited access to the Unit 2 casings will also limit the

construction sequence, and may cause delays, further extending the outage. Winter weather conditions

experienced at the site could also prolong the construction process. Additional construction personnel would

likely be required to complete work in multiple areas in an effort to reduce the outage duration.

With this option, the PM emissions are estimated to potentially achieve an emission rate of 0.008 lb/MMBtu.

However, vendors would likely have to complete a more detailed qualitative study in order to provide a

guarantee and would require baseline testing to qualify ESP inlet and outlet emissions.

2.2. OPTIONS TO REACH 0.006 LB/MMBTU

To achieve PM emissions that would allow for compliance with the more stringent proposed standard, a

baghouse would be required. It should be noted that a baghouse will likely not provide sufficient operating

margin to achieve the proposed 0.006 lb/MM

MMBtu emission rate. It will likely be challenging to obtain a guarantee

below 0.006 lb/MMBtu from baghouse OEMs. However, a baghouse is not considered to be economically

feasible 1 and is therefore not evaluated further. The baghouse installation options that could be considered,

described below, and the expected timeline for implementation of this control option, described in Table 2-2,

are included for reference only.

•

Conversion of ESP to Baghouse:

o The existing ESP casings would be reused and ESP internals and all roof mounted equipment

would be removed. A vertical partition wall, running in the direction of gas flow from the hopper

bend line to the tube sheet, would be constructed in the center of each ESP casing.

Polishing Baghouse (Downstream of ESP):

o The existing ESP would continue to operate. Due to the reduced inlet ash loading, a polishing

A high-level estimation of the cost effectiveness of a baghouse retrofit on MRY Unit 2 is approximately $162k/ton,

based on the annualized capital and O&M costs ($/yr) divided by the annual reduction in annual emissions (ton/yr).

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•

baghouse can be designed using a 6.0 air-to

to-cloth (AC

AC) ratio, which allows for a reduced

footprint compared to a 4.0 AC ratio sized to handle the entire unit fly ash loading.

o There is not adequate space available adjacent to the existing ESP casings for placement of

a baghouse. Therefore, long tie-in ductwork will be required to route flue gas to an open area

where the baghouse can be constructed. As such, the reduced size of the polishing baghouse

is not anticipated to provide significant enough cost savings when compared to a baghouse

that utilizes a 4.0 AC ratio.

Baghouse (Primary PM Collection):

o The existing ESP would be abandoned in place (could be demolished at a later date). As

mentioned previously, long tie-in ductwork will be required to route flue gas to an open area

where the baghouse can be constructed while the unit continues to operate in order to

minimize the tie-in outage duration.

A baghouse is expected to have a pressure drop of 8 in. w.c., but could be higher depending on the location

of the baghouse in relation to the tie-in to the existing flue gas path. The current axial fans are already operated

very close to their stall curve, and do not have any pressure drop operating margin. Therefore, either

replacement of the existing ID fans or installation of new booster fans would be required to accommodate the

additional pressure drop through the baghouse.

2.3. PARTICULATE EMISSIONS SUMMARY

Table 2-1 below provides a summary of the post-upgrade achievable emission rate for the feasible PM control

option evaluated to achieve a proposed PM emission limit of 0.010 lb/MMBtu. The estimated emission rates

included in the following tables are considered to be representative of an average emission rate that could be

achieved under normal operating conditions. The emission rates provided should not be construed to

represent an enforceable regulatory or proposed permit limit. Corresponding regulatory and/or permit limits

must be evaluated on a control system-specific basis taking into consideration normal operating variability

(i.e., a minimum additional 20% margin would likely be needed to account for operating margin).

Table 2-1 — Unit 2 PM Emissions Summary

Parameter

Baseline (Dry ESP)

ESP Rebuild

Control

Efficiency Note 1

Projected

Emissions Note 2

(lb/MMBtu)

Expected Emissions

(ton/year)

0.015

254

46.7%

0.008

135

Note 1 – Control efficiency is based on incremental improvement achieved with the option in addition to baseline dry ESP

operation (e.g. not to be misconstrued as a total percent removal from uncontrolled PM emissions).

Note 2 – No compliance margin is included in these estimates. The emissions rate projections should not be used as an

achievable limit for these upgrades.

2.4. TIMELINE FOR INSTALLATION

A high-level implementation schedule that outlines the time needed for the project steps necessary for the

implementation of the feasible control options are summarized below. It should be noted that although a

baghouse is not considered to be economically feasible, the control option is included in the summary below

for reference on the expected timeline required for implementation of this control option. Other project-related

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activities, such as the time needed to obtain internal project approval, financing or permitting, if required, are

not included. It should be noted that these time frames are separate from the regulatory time frames for EPA

to take final action on the Proposed MATS RTR.

Lead times of equipment that would be used in these types of retrofits have been observed to be double or

triple the lead times typically provided by suppliers before the COVID pandemic, with longer durations

observed for electrical and instrumentation and control equipment. With continued supply-chain issues, it is

anticipated that longer and longer lead times may be required that are difficult to quant

ntify at this time.

Therefore, timelines represented are estimated based on past project durations and not reflective of postpandemic market delays nor the limited number of experienced OEMs capable of providing the equipment.

Table 2-2 — PM Control Implementation Schedule

Design/

Specification/

Procurement

Detail Design/

Fabrication

Construction/

Commissioning/

Startup

Minimum

Total

(months)

ESP Rebuild

Baghouse

PM Control Option

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3.MERCURY TECHNOLOGY EVALUATION

3.1. MERCURY EMISSIONS BACKGROUND

3.1.1.Mercury Speciation

Mercury (Hg) is contained in varying concentrations in different coal supplies. During combustion, Hg is

released in the form of elemental Hg in the high temperature combustion zone of a boiler. As the combustion

gases cool, a portion of the elemental Hg transforms or oxidizes to ionic Hg

Hg. However, the amount of elemental

Hg that oxidizes is dependent on the cooling rate of the gas and the presence of halogens in the flue gas.

Ultimately, there are three possible forms of Hg

Hg:

•

Elemental (Hg0):

o The conversion of elemental Hg to the other forms depends upon several factors including

cooling rate of the gas, presence of halogens or sulfur trioxide (SO 3) in the flue gas, amount

and composition of fly ash, presence of unburned carbon, and the installed APC equipment.

o Hg0 is insoluble in water and therefore removal requires injected sorbents or must be

converted to another form to be captured, depending on the installed APC equipment.

Ionic or Oxidized (Hg

Hg++ or Hg2+):

o In contrast to elemental Hg

Hg, ionic Hg is highly water soluble, allowing for collection in water

streams that may be utilized in certain APC equipment and subsequently leave the process

with the solid by-product or as a constituent in the purge water.

Particulate-bound:

o Particulate-bound Hg typically is bound to fly ash or unburned carbon. Particulate-bound Hg

is efficiently removed from the flue gas by the particulate control device, making it desirable

to convert as much Hg as possible to particulate-bound Hg

Hg.

o High SO3 levels have been shown to inhibit the binding of ionic Hg to fly ash or Hg sorbents.

The addition of halogens increase the conversion of elemental and ionic Hg to particulatebound Hg

Hg.

The proportion of the various Hg forms is referred to as Hg speciation. As such, Hg speciation testing has

indicated that the distribution of Hg species varies with coal type. The effectiveness of post-combustion Hg

control technologies is highly influenced by the Hg speciation in the flue gas, with gaseous oxidized (or ionic)

Hg compounds (i.e. HgCl2) being easier to capture by downstream APC equipment.

3.1.2.Lignite Coal Variability

Industry experience has shown that lignite coal deposits vary significantly in quality, including fuel combustion

performance, mineral content, and Hg content, resulting in a coal that can change on a day-to

to-day basis

depending on the coal seam being mined at the time. For example, during the 2005 Energy & Environmental

Research Center (EERC) sixty (60) day testing on MRY Unit 2, 2 the coal samples analyzed ranged from 6.22

Refer to the EERC “Large-Scale Mercury Control Technology Testing for Lignite-Fired Utilities - Oxidation Systems for

Wet FGD” report (Cooperative Agreement No. DE-FC26-03NT41991) dated March 2007 for further details on the testing

completed from March 15, 2005 to May 15, 2005 on MRY Unit 2.

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lb/TBtu to 10.9 lb/TBtu (Hg content varied from 0.05 to 0.25 ppm, and averaged 0.112 ± 0.014 ppm on a dry

coal basis). As such, units firing lignite coal with lower heating values have to accommodate frequently

changing coal quality and require a wide range of flexibility to account for instances of firing high Hg seams of

coal to consistently achieve adequate operating margin below the required Hg emission limit. 3

The variability of the projected lignite coal quality received from the Center Mine from 2025 through 2036 is

shown in Table 3-1.

Table 3-1 — Center Mine Ultimate Coal Analyses (As-Received)

Fuel Parameter

Units

Average

Minimum

Maximum

Carbon

wt.%

40.53

39.73

41.24

Hydrogen (fuel-based)

wt.%

2.78

2.71

2.82

Nitrogen

wt.%

0.30

0.26

0.34

Sulfur

wt.%

0.86

0.68

1.07

Oxygen (by difference)

wt.%

9.97

9.47

10.83

Moisture

wt.%

38.83

38.53

39.25

Ash

wt.%

6.73

6.00

7.87

Higher Heating Value (HHV)

Btu/lb

6,625

6,489

6,739

Mercury Content

ppm

0.091

0.053

0.184

Estimated Hg Emission

lb/TBtu

8.41

4.79

17.42

3.1.3.Hg

Hg Removal with ESPs

For ACI on ESP applications, 80% of Hg capture occurs in the flue gas, and 20% occurs on the dust within

the ESP (as the dust on the collecting plates are consistently removed as part of the process). Therefore, for

ESP applications, achieving ideal mixing and residence time to allow for elemental Hg to oxidize to ionic Hg

and for Hg to be adsorbed on the carbon particles (of the PAC or unburned carbon content in the fly ash) is

critical. It should be noted that this ratio is the exact opposite for baghouse applications, i.e. 20% capture induct and 80% capture on the dust of the filter cake accumulated in the baghouse. For this reason, fabric filters

can result in extremely high Hg capture and can improve the capture with any Hg sorbent.

3.1.4.Existing System Limitations

Documented evidence of a lignite unit achieving 1.2 lb/TBtu or below has not been found/reviewed at the time

of this report. Minnkota personnel recently completed short-term parametric testing in May 2023 to determine

the Hg emissions that could be achieved by maximizing the existing fuel additive and PAC injection. Even

when maximizing the fuel additive rate in addition to maximizing the non-halogenated ACI addition, an

emission rate of 1.2 lb/TBtu was not able to be achieved. Due to the variability of the coal, a longer period of

testing would be required to gauge the Hg emissions that could be achieved just using the capacity within the

existing equipment.

Based on Response of Minnkota Power Cooperative Clean Air Act Section 114 Request, dated July 29, 2022.

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3.2. INCREMENTAL HG CONTROL ON A LIGNITE UNIT

As mentioned previously, S&L is not aware of any documented evidence of a lignite unit achieving 1.2 lb/TBtu

or below. As such, the following sections describe issues that need to be resolved/tested to establish if it is

feasible to achieve a 1.2 lb/TBtu Hg emission rate with sufficient operating margin on a lignite unit and if so,

develop an overall Hg compliance approach that likely would consist of a suite of control approaches. It should

be noted that any achievable Hg emission should not be construed to represent an enforceable regulatory or

proposed permit limit. Corresponding regulatory and/or permit limits must be evaluated on a control systemspecific basis taking into consideration normal operating and coal variability (i.e., a minimum additional 20%

margin or higher would likely be needed

ed to account for coal fluctuations and operating margin).

3.2.1.Increased Oxidation of Elemental Hg

Recent 2011 Hg speciation data measured at the Unit 2 stack, with no control technologies, indicated the Hg

emissions consisted of approximately 98.3% elemental Hg

Hg, 0.8% oxidized Hg

Hg, and 0.9% particulate Hg

Hg.

Recent operating data from a retired Hg process monitor indicates that the Unit 2 Hg emissions, with the

currently installed Hg control technologies, consisted of approximately 86% elemental Hg

Hg, and 14% oxidized

Hg. Because the current Hg emissions are made up mostly of elemental Hg, the unit emissions would benefit

from an increased amount of halogen in an attempt to oxidize the elemental Hg in the flue gas. The additional

halogen (chlorine, iodine, and bromine) can be added to the PAC, to the coal, or both.

The current fuel additive injection could be increased and/or replaced with a different halogen-based additive.

In addition, the current non-halogenated PAC would be replaced with a more expensive halogenated PAC.

The increased amount of halogen present is expected to increase the amount of elemental Hg that is oxidized

to be more easily captured on the surface area of the PAC and in downstream APC. 4

3.2.2.Increased PAC

It is anticipated that additional halogenated PAC (i.e. more than the current capabilities of the existing

equipment) will need to be injected for the increased amount of oxidized Hg to be efficiently captured. However,

preliminary feedback received from PAC suppliers have indicated that demonstration testing would be required

to determine a PAC dosage rate and the emissions rate that can be achieved when considering the Hg content

variability of the lignite. Therefore, additional modifications that may be required cannot be concluded at this

time; however, it is likely that the existing lances and transport piping would need to be replaced to

accommodate a higher injection rate. As the existing PAC storage silo is shared by Units 1 and 2, it is likely

that a separate silo would be required for Unit 2 to ensure adequate supply, turndown flexibility, and reliability

is achieved to maintain compliance with a defined Hg emission limit.

The degree of increased PAC injection rates can have an impact on the ESP performance as the increased

amount of carbon particles that have low resistivity will decrease the overall resistivity of the fly ash (can cause

particles to rapidly lose their charge on arrival at the collecting plate and become re-entrained). If/when

It should be noted that the existing PAC silo is not currently compatible to store halogenated PAC due to the material of

construction of the fluidizing air nozzles and may also require an internal coating of the silo to prevent corrosion.

Additional assessment will be required to determine modifications required to reuse the existing silo, and may be subject

to the brominated PAC utilized.

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additional testing is completed to determine the supplier recommended brominated PAC injection rate, PM

emissions should also be closely monitored to confirm no longer term impacts are caused by the increased

ACI rate. In order to mitigate potential increases or deviations for the current PM emissions, it would be

reasonable to anticipate some ESP upgrades (operational changes and/or equipment optimizations) to be

required to ensure the ESP maintains its current performance.

3.2.3.Increased Contact

Increasing the degree of flue gas and PAC mixing can optimize the sorbent utilization to ensure adequate

mixing of the oxidized Hg and PAC is achieved, which potentially could result in the use of less PAC to achieve

the same Hg emission rate. Similarly, additional testing and evaluation would be required to determine the

beneficial incremental Hg removal improvement that could be achieved. Additional mixing could be

implemented by either adding static mixers into the flue gas path and/or using a more advanced injection lance

design to increase sorbent dispersion relative to a straight lance design to optimize sorbent usage.

Increased contact time could also be achieved by relocating the injection lances upstream of the APH. 5 Hg

reduction effectiveness with PAC has been shown to be temperature limited, as the absorption capacity of the

carbon is reduced at temperatures above approximately 350°F. Although flue gas temperatures downstream

of the APH are more ideal for capture, temperatures upstream of the APH are within an ideal zone for mercuric

halogens to be formed, taking advantage of the additional halogen introduced with the PAC. Furthermore, for

applications with SO3 concentrations above 5 ppm in the flue gas (as-is on the MRY units), carbon active sites

may be preferentially occupied by SO3. Although adsorption rates slow down above 350°F, injection upstream

of the APH is sometimes considered to lower the impact of SO3 competition. Furthermore, tubular APH designs

will not offer as much mixing compared to Ljungstrom type APHs; therefore, relocating the injection lances

upstream of the APH will likely only achieve added residence time for adsorption to occur in lieu of additional

mixing. Therefore, the high temperature environment and resulting residence time for injection at the APH inlet

would need to be evaluated further.

3.2.4.WFGD Re-Emission Control

Oxidized Hg is highly water soluble and exists in vapor phase at back-end equipment flue gas temperatures.

WFGDs readily capture approximately 90% of oxidized Hg because it is highly soluble, but will not remove

elemental Hg. However, re-emission of Hg is possible in some circumstances when Hg precipitates out in

scrubber solids (mercuric sulfide or equivalent) and the scrubber slurry converts some of the oxidized Hg back

into elemental form. Re

Re-emission of elemental Hg can be mitigated through the use of a sulfide-donating liquid

reagent additive that enhances the Hg capture within

in the WFGD by decreasing soluble Hg in the WFGD slurry.

Testing would be required to determine the amount of re

re-emission currently occurring based on recent

operating conditions.

3.3. MERCURY EMISSIONS SUMMARY

Presently, there is not any publicly available information to determine if improvements to any of the above

categories (individually or in combination) can achieve a Hg emission of 1.2 lb/TBtu or below on a lignite unit.

It should be noted that this approach is patented by Alstom, and use of this approach would need to consider

intellectual property implications.

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Therefore, additional testing would be required to establish if it is feasible to achieve a 1.2 lb/TBtu Hg emission

rate with sufficient operating margin on a lignite unit and if so, develop an overall Hg compliance approach

that likely would consist of a suite of control approaches to achieve th

this rate on MRY Unit 2.

In summary, additional testing would include, but not be limited to, the following:

•

Hg speciation data upstream of the ESP, upstream of the WFGD and at the stack (with no controls,

current operation and maximum capacity of existing Hg control equipment, and test conditions for

other listed items)

Performance with increased concentrations of current fuel additive system, including additional

injection locations, as well as potentially testing other halogen-based fuel additives than what is

currently used.

Performance with halogenated PAC, considering capabilities of existing Hg control equipment and

increased injection rates (while also considering other test conditions for other listed items). Note that

due to the limitations of the existing equipment, a separate test skid will be required to facilitate this

testing campaign.

If WFGD re-emission is determined to be occurring based on Hg speciation upstream and downstream

of the WFGD, the performance of a re-emission additive can also be tested.

As mentioned previously, PAC suppliers have indicated that testing would be required in order to obtain any

guaranteed performance. Therefore, recommended consumption and/or injection rates to determine the

modifications and/or new systems required are not available at this time to develop the subsequent cost of the

suite of Hg controls needed to achieve adequate operating margin below a 1.2 lb/TBtu Hg emission limit on

MRY Unit 2.

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4.SUMMARY

The existing MRY Unit 2 PM and Hg control technologies were found to not be capable of achieving the

proposed emissions included in the April 24, 2023, MATS rule: filterable PM emissions limit of 0.010 lb/MMBtu

and potentially 0.006 lb/MMBtu and Hg emissions limit of 1.2 lb/TBtu.

The evaluation of available PM control technologies found that an ESP rebuild would be required to achieve

the proposed PM emission limit of 0.010 lb/MMBtu considering the need for adequate operating margin.

However, testing to determine the baseline ESP inlet flow profile, ESP inlet and outlet emissions, and amount

of PM removal occurring across the WFGD will likely be required in order for a vendor to complete a detailed

qualitative study required to provide a PM emission guarantee. A baghouse will likely not provide sufficient

operating margin for compliance with the more stringent 0.006 lb/MMBtu proposed emission limit; furthermore,

this alternative was not considered to be economically feasible, and OEMs may not offer a PM emission

guarantee with sufficient operating margin. A significant outage will be required to complete an ESP rebuild

on MRY Unit 2, likely requiring the unit to be offline 12 weeks or longer as part the retrofit. Due to current postpandemic market delays and the limited number of experienced OEMs capable of completing an ESP rebuild,

it is highly likely that the implementation of this large-scale capital project will take longer than the estimated

36-month implementation schedule.

At the time of this evaluation, no evidence or examples demonstrating that an operating lignite unit could

achieve the proposed Hg emission limit of 1.2 lb/TBtu were found. As the Hg content of the lignite coal fired at

MRY Unit 2 can range from as low as 4.8 lb/TBtu to as high as 17.4 lb/TBtu, a wide range of flexibility in Hg

control to account for instances of firing high Hg seams of coal to consistently achieve adequate operating

margin below the proposed Hg emission limit will be required. Additional testing will also be required to

navigate the challenges of Hg speciation, flue gas temperature, flow profile/mixing, residence time, and coal

variability for application on a lignite fired unit to establish if it is feasible to achieve a 1.2 lb/TBtu Hg emission

rate with sufficient operating margin. Furthermore, PAC suppliers have indicated that testing would be required

in order to obtain any guaranteed performance. Once testing is completed, recommended

consumption/injection rates, required flexibility of the suite of Hg control approaches and the subsequent costs

of the modifications and/or new systems required to achieve adequate operating margin below a 1.2 lb/TBtu

Hg emission limit on MRY Unit 2 can be developed.

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ATTACHMENT F

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Analysis of

Proposed EPA MATS Residual Risk and Technology Review and

Potential Effects on Grid Reliability in North Dakota

Claire Vigesaa

aa, Director

North Dakota Transmission Authority

April 3, 2024

Assisted by:

Isaac Orr and Mitch Rolling

Center of the American Experiment

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Contents

Executive Summary....................................................................................................... 3

Section A: North Dakota’s Power Environment .............................................................................. 4

Generation Adequacy, Transmission Capacity & Load Forecast Studies......................... 5

Current North Dakota Generation Resources ............................................................... 6

Electric Generation Market & Utilization ...................................................................... 8

Grid Resource Adequacy and Threats to Growth Opportunities ..................................... 9

Grid Reliability Is Already Vulnerable ......................................................................... 10

NERC’s 2023 Reliability Risk Assessment .................................................................. 11

MISO’s Response to the Reliability Imperative (2024) ................................................. 12

Conclusion: The Long Term Reliability of the MISO Grid is Already Precarious .............. 14

            

Generating Units ......................................................................................................... 14

The Proposed MATS Rule Eliminates the Lignite Subcategory for Mercury Emissions .... 15

The Proposed MATS Rule Will Not Provide Meaningful Human Health or Environmental

 .................................................................................................................. 16

The Administrative Record Indicates the Mercury Standard of 1.2 lb./TBtu is Technically

Unachievable for EGUs using North Dakota Lignite Coal ............................................. 20

The Administrative Record Indicates the Lower PM Standard May Also Not Be Technically

Feasible .................................................................................................................. 23

Section C: Impact of MATS Regulations- Power Plant Economics and Grid Reliability ....... 24

Power Plant Economic Impacts ................................................................................ 24

Grid Reliability Impacts ............................................................................................ 27

Section D: Modeling Results ........................................................................................ 31

Summary ................................................................................................................ 31

Modeling the Reliability and Cost of the MISO Generating Fleet Under Three Scenarios 32

Reliability in each scenario ....................................................................................... 33

Extent of the Capacity Shortfalls ........................................................................... 34

Unserved MWh in Each Scenario ........................................................................... 37

The Social Cost of Blackouts Using the Value of Lost Load (VoLL) ............................ 37

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Hours of Capacity Shortfalls ................................................................................. 39

Cost of replacement generation................................................................................ 39

Conclusion: ................................................................................................................ 48

Appendix 1: Modeling Assumptions .............................................................................. 49

Appendix 2: Capacity Retirements and Additions in Each Scenario ............................. 53

Appendix 3: Replacement Capacity Based on EPA Methodology for Resource Adequacy

.............................................................................................................................. 58

Appendix 4: Resource Adequacy in Each Scenario ..................................................... 59

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Executive Summary

On behalf of the North Dakota Transmission Authority (NDTA), the Center of the American

Experiment prepared this study to analyze the potential impacts of EPA’s proposed revisions to the

Mercury and Air Toxics Standards (MATS) Rule on North Dakota’s power generation and power

grid reliability.

Our primary finding, which is drawn substantially from the Rule’s administrative record, is that

the proposed changes are likely not technologically feasible for lignite-based power generation

facilities, will foreseeably result in the retirement of lignite power generation units, and will

negatively impact consumers of electricity in the Midcontinent Independent Systems Operator

(MISO) system by reducing the reliability of the electric grid and increasing costs for ratepayers.

Our analysis builds upon grid reliability data and forecasts from the Federal Energy Regulatory

Commission (FERC) and the North American Electric Reliability Corporation (NERC), and it

assesses what is likely to happen to grid reliability if the MATS Rule forces some or all of North

Dakota’s lignite power generation units to retire. We determined that the closure of lignite-fired

powered power plants in the MISO footprint would increase the severity of projected future

capacity shortfalls, i.e. rolling blackouts, in the MISO system even if these resources are replaced

with wind, solar, battery storage, and natural gas plants. In reaching that determination, we have

accepted EPA’s estimates for capacity values of intermittent and thermal resources.

Moreover, building such replacement resources would come at a great cost to MISO ratepayers.

The existing lignite facilities are largely depreciated assets that generate large quantities of

dispatchable, low-cost electricity. Replacing these lignite facilities with new wind, solar, natural

gas, and battery storage facilities would cost an additional $1.9 billion to $3.8 billion through 2035,

compared to operating the current lignite facilities under status quo conditions.

MISO residents would also suffer economic damages from the increased severity of rolling

blackouts. Accounting for projected increases in demand for electricity, we assess that if the MATS

Rule goes into effect in the near future, by 2035, the MISO grid will experience up to an additional

73,699 megawatt hours (MWh) of unserved load, with an economic cost of up to $1.05 billion

based on the Value of Lost Load (VoLL) criteria, which can be thought of as the Social Cost of

Blackouts.

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Section A: North Dakota’s Power Environment

North Dakota Transmission Authority (NDTA)

The North Dakota Transmission Authority (NDTA) was established in 2005 by the North Dakota

Legislative Assembly at the behest of the North Dakota Industrial Commission. Its primary

mandate is to facilitate the growth of transmission infrastructure in North Dakota. The Authority

serves as a pivotal force in encouraging new investments in transmission by aiding in facilitation,

financing, development, and acquisition of transmission assets necessary to support the expansion

of both lignite and wind energy projects in the state.

Operating as a 'builder of last resort,' the NDTA intervenes when private enterprises are unable or

unwilling to undertake transmission projects on their own. Its membership, as stipulated by statute,

comprises the members of the North Dakota Industrial Commission, including Governor, Attorney

General, and Agriculture Commissioner.

Statutory authority for the North Dakota Transmission Authority (NDTA) is enshrined in Chapter

17-05 of the North Dakota Century Code. Specifically, Section 17-05-05 N.D.C.C. outlines the

powers vested in the Authority, which include:

1. Granting or loaning money.

2. Issuing revenue bonds, with an upper limit of $800 million.

3. Entering into lease-sale contracts.

4. Owning, leasing, renting, and disposing of transmission facilities.

5. Entering contracts for the construction, maintenance, and operation of transmission

facilities.

6. Conducting investigations, planning, prioritizing, and proposing transmission corridors.

7. Participating in regional transmission organizations.

In both project development and legislative initiatives, the North Dakota Transmission Authority

(NDTA) plays an active role in enhancing the state's energy export capabilities and expanding

transmission infrastructure to meet growing demand within North Dakota. Key to its success is a

deep understanding of the technical and political complexities associated with energy transmission

from generation sources to end-users. The Authority conducts outreach to existing transmission

system owners, operators, and potential developers to grasp the intricacies of successful

transmission infrastructure development. Additionally, collaboration with state and federal

officials is essential to ensure that legislation and public policies support the efficient movement

of electricity generated from North Dakota's abundant energy resources to local, regional, and

national markets.

As the energy landscape evolves with a greater emphasis on intermittent generation resources,

transmission planning becomes increasingly intricate. Changes in the generation mix and the

redistribution of generation resource locations impose strains on existing transmission networks,

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potentially altering flow directions within the network. A significant aspect of the Authority's

responsibilities involves closely monitoring regional transmission planning efforts. This includes

observing the activities of regional transmission organizations (RTOs) recognized by the Federal

Energy Regulatory Commission (FERC), which oversee the efficient and reliable operation of the

transmission grid. While RTOs do not own transmission assets, they facilitate non-discriminatory

access to the electric grid, manage congestion, ensure reliability, and oversee planning, expansion,

and interregional coordination of electric transmission.

Many North Dakota service providers are participants in the Midcontinent Independent System

Operator (MISO), covering the territories of several utilities and transmission developers.

Additionally, some entities are part of the Southwest Power Pool (SPP), broadening the scope of

transmission planning. Together, North Dakota utilities and transmission developers contribute to

a complex system overseeing the transmission of over 200,000 megawatts of electricity across

100,000 miles of transmission lines, serving homes and businesses in multiple states.

MISO and SPP also operate power markets within their respective territories, managing pricing

for electricity sales and purchases. This process determines which generating units supply

electricity and provide ancillary services to maintain voltage and reliability. Overall, the NDTA's

involvement in regional transmission planning and coordination is crucial for ensuring the

reliability, efficiency, and affordability of electricity transmission across North Dakota and beyond.

FERC-Recognized Regional Transmission Organizations and Independent System Operators

(www.ferc.gov)

Generation Adequacy, Transmission Capacity & Load Forecast Studies

The North Dakota Transmission Authority (NDTA) conducts periodic independent evaluations to

assess the adequacy of transmission infrastructure in the state. In 2023, the NDTA commissioned

two generation resource adequacy studies, one for the Midcontinent Independent System Operator

(MISO) and another for the Southwest Power Pool (SPP). Additionally, the NDTA recently

completed a generation resource adequacy study examining the impact of the EPA's proposed

Mercury and Air Toxics Standards (MATS) Rule. A transmission capacity study commissioned by

the NDTA is scheduled for completion in the summer of 2024.

Regular load forecast studies are also commissioned by the NDTA, with the most recent study

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completed in 2021. This study, conducted by Barr Engineering, provided an update to the Power

Forecast 2019, projecting energy demand growth over the next 20 years. The 2021 update

incorporates factors such as industries expressing interest in locating in North Dakota, abundant

natural gas availability from the Bakken wells, and the potential for carbon capture and

sequestration from various sources. The 2021 update and the full study can be obtained from the

North Dakota Industrial Commission website: Power Forecast Study – 2021 Update,

https://www.ndic.nd.gov/sites/www/files/documents/Transmission-Authority/Publications/taannualreport-21.pdf

The Power Forecast 2021 Update projects a 10,000 GWhr increase in energy demand over the next

two decades under the consensus scenario, requiring approximately 2200 to 2500 MW of

additional capacity to meet demand. These projections are closely tied to industrial development

forecasts and are coordinated with forecasts used by the North Dakota Pipeline Authority. These

projections were highly dependent on industrial development and are premised on new federal

regulations not forcing the early retirement of even more electric generation units.

Meeting this growing demand poses significant challenges for utilities responsible for providing

reliable service. While there is considerable interest in increasing wind and solar generation,

natural gas generation is also essential to provide stability to weather-dependent renewable

sources. Importantly, load growth across the United States is driven by the electrification of

transportation, heating/cooling systems, data centers, and manufacturing initiatives.

Studies consistently highlight the critical importance of maintaining existing dispatchable

generation to prevent grid reliability failures. Ensuring uninterrupted power supply is paramount

for national security, public safety, food supply, and overall economic stability. The NDTA's

ongoing assessments and proactive planning are crucial for meeting the evolving energy needs of

North Dakota while maintaining grid reliability and resilience.

The timing and implementation of resources to meet this growing demand is a significant challenge

for the utilities. Importantly, electric demand growth across the United States over the next several

decades is projected to be dramatic due to the electrification of transportation, home

heating/conditioning, data center and artificial intelligence centers, as well as the effort to bring

manufacturing back to the USA. Studies by NDTA and others all point to the critical need to keep

all existing dispatchable generation online to avoid catastrophic grid reliability failures, and have

been warning that the push to force the retirement of reliable, dispatchable fossil fuel generation

units is occurring before it is projected there will be sufficient intermittent units in place to cover

the anticipated increase in demand. And when demand for electricity exceeds the dispatchable

supply, the foreseeable result will be blackouts or energy rationing.

Current North Dakota Generation Resources

Here is the current breakdown of North Dakota's generation resources:

1. Renewable Generation:

• Wind Generation: North Dakota has 4,250 MW of wind generation capacity in

service, making it a significant contributor to the state's renewable energy portfolio.

The average capacity factor for these generating facilities is 40% to 42%.

• The 4,000 MW of wind generation receives a reduced capacity accreditation in the

ISO of approximately 600 MW since it is intermittent. This is representative of the

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amount that is estimated to be available for the peak demand in the summer.

• Solar Generation: Although North Dakota currently lacks utility-scale solar

generation facilities in operation, some projects are in the queues of regional

transmission organizations like MISO and SPP, indicating potential future

development in this area.

Thermal Coal Generation:

• North Dakota currently operates thermal coal generation at six locations,

comprising a total of 10 generating units with a combined capacity of

approximately 4,048 MW.

• The average capacity factor for these generating plants ranged from 65% to 91% in

2021, excluding the retired Heskett Station.

• Rainbow Energy operates the Coal Creek Station and the DC transmission line that

transports ND produced energy to the Minneapolis region. Rainbow Energy is

assessing a CO2 capture project for the facility. In addition, approximately 400

MW of wind generation is planned for that area of McLean County to utilize the

capacity on the DC line.

Hydro Generation:

• North Dakota has one hydro generation site equipped with 5 units, boasting a total

capacity of 614 MW.

• However, the average capacity factor declined to approximately 43% in 2021 due

to limitations imposed by water flow in the river, particularly during drought years.

Natural Gas Generation:

• North Dakota operates three sites for electric generation utilizing natural gas,

comprising 21 generating units with a total capacity of 596.3 MW.

• These units include reciprocating engines and gas turbines, with variation in

summer capacity influenced by the performance of gas generators in hot weather.

• Total natural gas generation in North Dakota remained steady from 2019 through

2021, amounting to 1.445 GWhr in 2021.

Total Generation:

• The combined total capacity of all types of utility-scale generation in North Dakota

is approximately 8,863 MW.

• Wind generation receives a reduced capacity accreditation in the ISO of

approximately 600 MW due to its intermittent nature, down from 4,250MW of

installed capacity, representing the estimated amount available during peak summer

demand. However, newer installations have demonstrated slightly higher capacity

for accreditation.

This comprehensive overview underscores the diverse mix of generation resources in North

Dakota, with significant contributions from wind, coal, hydro, and natural gas. Continued

assessment and adaptation to evolving energy needs and market dynamics are essential for

ensuring a reliable and sustainable energy future for the state.

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Electric Generation Market & Utilization

In recent decades, North Dakota has emerged as a significant exporter of electricity, primarily

fueled by the development of thermal lignite generation in the western part of the state since the

1960s. Concurrently, transmission infrastructure has been expanded to facilitate the export of

electricity to markets predominantly situated to the east. Moreover, North Dakota has garnered

recognition as an excellent source of wind generation, leading to additional transmission

development to accommodate the transmission of this renewable energy to markets.

According to data from the Energy Information Administration, in 2020, North Dakota generated

a total of 42,705 MWh of electricity from all sources, with 46% of this total being exported beyond

the state's borders over two large high voltage direct current lines (HVDC), which serve load in

the neighboring state of Minnesota and multiple 345kv and 230kv alternating current (AC)

transmission lines serving surrounding states. Wind generation accounted for 31% of North

Dakota's total electricity generation in 2020, highlighting the growing significance of renewable

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energy in the state's energy portfolio. Notably, industrial demand in North Dakota experienced

substantial growth, expanding by nearly 11% in 2020.

While demand for electricity in markets outside of North Dakota, and in most areas within the

state, has remained relatively stable in recent years, the Bakken region has witnessed notable

demand growth. Over the past 16 years, total electricity generation in North Dakota has increased

from 29,936 MWh to 42,705 MWh, with retail sales climbing from 10,516 MWh to 22,975 MWh.

This growth is primarily attributed to the burgeoning development of the Bakken oil fields.

Industrial consumption in North Dakota also witnessed a robust increase of over 11% in 2020,

with power forecasts projecting a continued upward trajectory in demand.

Generation by Type in North Dakota

35000

30000

Thousand MWh

25000

20000

15000

10000

5000

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021

Coal

Natural Gas

Hydroelectric

Wind

Grid Resource Adequacy and Threats to Growth Opportunities

In 2023, both the MISO and SPP grid operators issued warnings about the adequacy of generation

resources to meet peak demand situations. This highlights a growing concern that the desired pace

of change towards a more sustainable energy future is outpacing the achievable pace of

transformation. This concern is underscored by the stark increase in grid events necessitating the

activation of emergency procedures. For instance, prior to 2016, MISO had no instances

requiring the use of emergency procedures, but since then, there have been 48 Maximum

Generation events.

Many experts in the industry project that, despite ambitious goals, realistic scenarios still foresee

a substantial dependence on fossil fuel energy—potentially up to 50%—even by 2050. While

efforts to decarbonize fossil fuel resources are underway, achieving complete carbon neutrality or

a fully renewable energy grid by 2050 appears increasingly unlikely. The scalability and

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affordability of storage technology, particularly for renewable energy sources, remain significant

challenges.

In response to these challenges, Governor Burgum has issued a visionary goal for North Dakota

to achieve carbon neutrality in its combined energy and agriculture sectors by 2030. Governor

Burgum's approach emphasizes innovation over mandates, aiming to attract industries and

technologies that support this goal to the state. The initiative seeks to leverage advancements in

carbon capture and sequestration technologies to retain conventional generation in North Dakota

while also promoting sustainable agricultural practices and other innovative solutions, such as CO2

sequestration from ethanol production and enhanced oil recovery. These efforts demonstrate a

commitment to proactive and pragmatic solutions to address the complexities of achieving carbon

neutrality in the energy and agriculture sectors.

The state's vision for a decarbonized energy generation future faces significant challenges due to

the individual and cumulative impact of expansive federal rulemakings. These regulations would

curtail the flexibility to achieve the 2030 goal through the deployment of carbon capture and

sequestration (CCS) technologies. Furthermore, they would impose financial burdens on electric

cooperatives and utilities with limited resources, diverting investment away from future growth

options toward retrofitting existing facilities with costly emissions technologies to comply with

new federal requirements.

This regulatory burden not only impedes progress towards decarbonization but also introduces

opportunity costs for utilities and cooperatives. The funds that would otherwise be allocated for

future growth and innovation in clean energy solutions are instead diverted to compliance

measures, hindering the state's ability to transition to a more sustainable energy future efficiently

and effectively.

Ultimately, the restrictive nature of these federal rulemakings poses a significant obstacle to North

Dakota's efforts to achieve its decarbonization goals and undermines the state's vision for a cleaner

and more sustainable energy generation landscape. It highlights the need for a balanced approach

to regulation that supports innovation and investment in carbon reduction technologies while also

allowing for continued economic growth and development in the energy sector.

Grid Reliability Is Already Vulnerable

The fragility of grid reliability is already evident as warnings have been issued due to the declining

ratio of dispatchable and intermittent generation supplies. This concerning trend poses significant

threats to public safety, economic stability, and national security. Grid reliability is vital for

ensuring continuous access to essential services, such as food production and military operations.

Dispatchable reliable generation forms the backbone of grid stability, enabling the balancing of

supply and demand fluctuations. Failure to address these reliability concerns will compromise

critical infrastructure and expose society to substantial risks. Urgent action is required to safeguard

grid reliability and mitigate the potential consequences for public safety and national security.

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NERC’s 2023 Reliability Risk Assessment

The North American Electric Reliability Council’s 2023 Reliability Risk Assessment 1 are

concerning as demonstrated in the slides below. The electrification of the US economy, data & AI

center growth and the build it at home initiatives will substantially increase the demand for

electricity generation and transmission.

NERC’s 2023 Summer Reliability Assessment warns that two-thirds of North America is at risk

of energy shortfalls this summer during periods of extreme demand. While there are no high-risk

areas in this year’s assessment, the number of areas identified as being at elevated risk has

increased. The assessment finds that, while resources are adequate for normal summer peak

demand, if summer temperatures spike, seven areas — the U.S. West, SPP and MISO, ERCOT,

SERC Central, New England and Ontario — may face supply shortages during higher demand

levels.

“Increased, rapid deployment of wind, solar and batteries have made a positive impact,” said Mark

Olson, NERC’s manager of Reliability Assessments. “However, generator retirements continue to

increase the risks associated with extreme summer temperatures, which factors into potential

supply shortages in the western two-thirds of North America if summer temperatures spike.”

The North American Electric Reliability Corporation (NERC) recently released its 2023 LongTerm Reliability Assessment (LTRA), which found MISO is the region most at risk of capacity

shortfalls in the years spanning from 2024 to 2028 due to the retirement of thermal resources with

inadequate reliable generation coming online to replace them. 2

NERC. "North American Reliability Assessment." North American Electric Reliability Corporation, May 2023,

https://www.nerc.com/news/Headlines%20DL/Summer%20Reliability%20Assessment%20Announcement%20May

%202023.pdf.

North American Electric Reliability Corporation, “2023 Long-Term Reliability Assessment,” December, 2023,

https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2023.pdf.

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MISO is the region most at risk of rolling blackouts in the near future.

In 2028, MISO is projected to have a 4.7 GW capacity shortfall if expected generator retirements

occur despite the addition of new resources that total over 12 GW, leaving MISO at risk of load

shedding during normal peak conditions. This is because the new wind and solar resources that are

being built have significantly lower accreditation values than the older coal, natural gas, and

nuclear resources that are retiring. 3

MISO’s Response to the Reliability Imperative (2024)

On February 26, 2024, the Midcontinent Independent System Operator (MISO) released “MISO’s

Response to the Reliability Imperative 4,” a report which is updated periodically to reflect changing

conditions in the 15-state MISO region that extends through the middle of the U.S. and into

Canada. MISO’s new report explains the disturbing outlook for electric reliability in its footprint

unless urgent action is taken. The main reasons for this warning are the pace of premature

retirements of dispatchable fossil generation and the resulting loss of accredited capacity and

reliability attributes.

From 2014 to 2024, surplus reserve margins in MISO have been exhausted through load growth

and unit retirements. Since 2022, MISO has been operating near the level of minimum reserve

Midcontinent Independent Systems Operator, “MISO’s Response to the Reliability Imperative,” February, 2024,

https://cdn.misoenergy.org/2024%20Reliability%20Imperative%20report%20Feb.%2021%20Final504018.pdf?v=20

240221104216.

MISO. "MISO’S Response to the Reliability Imperative Updated February 2024." MISO, February 2024,

https://cdn.misoenergy.org/2024%20Reliability%20Imperative%20report%20Feb.%2021%20Final504018.pdf?v=20

240221104216.

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margin requirements. 5

According to the Reliability Imperative, MISO uses an annual planning tool called the OMS-MISO

Survey to compile information about new resources utilities and states plan to build and older

assets they intend to retire. The 2023 survey shows the region’s level of “committed” resources

declining going forward, with a potential shortfall of 2.1 GW occurring as soon as 2025 and

growing larger over time.

MISO lists U.S. Environmental Protection Agency (EPA) regulations that prompt existing coal and

gas resources to retire sooner than they otherwise would as a compounding reason for growing

challenges to grid reliability. From the report, there is a section titled, “EPA Regulations Could

Accelerate Retirements of Dispatchable Resources,” which states:

“While MISO is fuel- and technology-neutral, MISO does have a responsibility to inform

state and federal regulations that could jeopardize electric reliability. In the view of MISO,

several other grid operators, and numerous utilities and states, the U.S. Environmental

Protection Agency (EPA) has issued a number of regulations that could threaten

reliability in the MISO region and beyond.

In May 2023, for example, EPA proposed a rule to regulate carbon emissions from all

existing coal plants, certain existing gas plants and all new gas plants. As proposed, the

rule would require existing coal and gas resources to either retire by certain dates or else

retrofit with costly, emerging technologies such as carbon-capture and storage (CCS) or

co-firing with low-carbon hydrogen.

MISO and many other industry entities believe that while CCS and hydrogen co-firing

technologies show promise, they are not yet viable at grid scale — and there are no

assurances they will become available on EPA’s optimistic timeline. If EPA’s proposed rule

drives coal and gas resources to retire before enough replacement capacity is built with

the critical attributes the system needs, grid reliability will be compromised. The proposed

rule may also have a chilling effect on attracting the capital investment needed to build

new dispatchable resources.”

Despite these reliability warnings issued by MISO, EPA did not consider the reliability impacts of

the proposed MATS rules required emission control upgrades and additions to units. It is likely

that many units that would have to incur millions of dollars to retrofit emissions controls to comply

with this proposal would not do so. 6

In light of these shortcomings, the NDTA contracted with Center of the American Experiment to

model the impacts of the MATS rules on resource adequacy, reliability, and cost of electricity to

consumers. The findings of this analysis are detailed in Section D.

Midcontinent Independent Systems Operator, “MISO’s Response to the Reliability Imperative,” February, 2024,

https://cdn.misoenergy.org/2024%20Reliability%20Imperative%20report%20Feb.%2021%20Final504018.pdf?v=20

240221104216.

Rae E. Cronmiller, “Comments on Proposed National Emission Standards for Hazardous Air Pollution: Coal-and

Oil-Fired Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review,” The National

Rural Electric Cooperative Association, June 23, 2023, Attention Docket ID NO. EPA-HQ-OAR-2018-0794.

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Conclusion: The Long Term Reliability of the MISO Grid is Already

Precarious

As the state agency responsible for the strategic buildout and framework of electricity distribution,

the North Dakota Transmission Authority (NDTA) is deeply concerned about the potential impact

of federal rulemakings on the generation fleet in North Dakota and the ability to support future

growth initiatives. The current strain on the electric transmission system due to load growth is

already posing significant challenges to grid reliability, particularly in areas facing transmission

constraints and limited access to dispatchable generation.

The escalating frequency of grid events requiring emergency procedures, such as the 48 Maximum

Generation events in MISO since 2016 and the increasing number of alerts issued by SPP, over

194 alerts issued in 2022, underscores the urgency of addressing transmission congestion and

bolstering reliable generation capacity. The economic growth and security of North Dakota are

directly tied to the timely development of new transmission facilities in tandem with dependable

dispatchable electric generation.

The impacts of grid strain extend beyond the energy sector, affecting multiple industries,

ratepayers, and overall economic stability. Volatile wholesale prices and transmission congestion

undermine business operations and investment confidence, hindering economic growth and

prosperity. Moreover, reliable electricity supply is critical for essential services, including

Department of Defense facilities, underscoring the broader implications of grid reliability issues.

Achieving a balanced generation portfolio requires careful consideration of reliability and

resilience under all weather conditions, especially amidst the electrification of America and the

imperative to safeguard public welfare and security.

Additionally, over 50% of the electricity generated in North Dakota is exported to neighboring

states, magnifying the ripple effects of any regulations impacting dispatchable electricity

generation resources. By responsibly managing the generation portfolio and prioritizing generation

adequacy, North Dakota and the nation can seize significant opportunities for economic growth,

innovation, and sustainable development.

Section B: The Proposed MATS Rule Will Dramatically

   Lignite Electric Generating Units

The revised MATS Rule includes a proposal to eliminate the “low rank coal” subcategory

established for lignite-powered facilities by requiring these facilities to comply with the same

mercury emission limitation that currently applies to Electric Generating Units (EGUs)

combusting bituminous and subbituminous coals, which is 1.2 pounds per trillion British thermal

units of heat input (lb/TBtu). EPA’s proposal is a substantial lowering of the current mercury

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limitation for lignite fired EGUs, which is 4.0 lb/TBtu. 7,8 The proposal also includes a significant

reduction in the particulate matter standard applicable to all existing units from 0.03 lb/mmBtu to

0.01 lb/mmBtu. Because North Dakota is somewhat unique to the degree in which its power

generation relies upon lignite coal, the compliance costs for this Rule, while likely to substantial

for coal plants all around the country, will be most acutely inflicted upon North Dakota’s lignitebased power generation facilities.

Numerous comments in the administrative record, including from the regulated facilities in North

Dakota and the North Dakota Department of Environmental Quality, provided EPA with notice

that the new emission standards are not technologically feasible, will impose crippling compliance

costs that may require facility retirement, and will result in a significant portion of the dispatchable

power provided by coal-generation facilities being taken off the grid. This report will summarize

some of those concerns in the section that follows, however, a full study of the technological

feasibility of complying with the new emissions standards is beyond the scope of this report. For

purposes of this report, we assume the regulated facilities and state regulator were forthright in

their concerns about the feasibility of lignite-based facilities meeting the new standards.

The Proposed MATS Rule Eliminates the Lignite Subcategory for Mercury

Emissions

Although the Proposed Rule affects all coal electrical generating utilities (EGUs), reducing the

lignite emissions standards to levels of other coal ranks effectively eliminates the lignite subcategory and would have drastic consequences for North Dakota's lignite EGU industry. 9 EPA

original decision to regulate separately a subcategory of lignite units was well-supported with

documented information and a thorough analysis. In its comments filed in this Docket, on June

22, 2023, the North Dakota Department of Environmental Quality (hereafter DEQ) encouraged

EPA to review that prior determination and reaffirm the need for a lignite subcategory and the

associated emissions standards. 10

Specifically, DEQ summarized the original MATS proposal in 2011 and final MATS rule in 2012,

in which EPA presented a body of evidence in support of the lignite category. For example, the

EPA wrote:

“For Hg emissions from coal-fired units, we have determined that different emission

limits for the two subcategories are warranted. There were no EGUs designed to burn

a non-agglomerating virgin coal having a calorific value (moist, mineral matter free

Jason Bohrer, “Comments on National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired

Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review, 88 Fed. Reg. 24854

(Apr. 24, 2023), June 23, 2024.

8 8

J. Cichanowicz et al., Technical Comments on National Emission Standards for Hazardous Air Pollutants: Coaland Oil-fired Electric Utility Steam Generating Units Review of Residual Risk and Technology, (June 2, 2023)

(“Cichanowicz Report”).

EPA characterizes lignite as "low rank virgin coal". 88 Fed. Reg. 24,854, 24,875. For this comment letter, lignite

will be used in place of low rank virgin coal.

David Glatt, P.E., “Comments on the Proposed Rulemaking Titled "National Emission Standards for Hazardous Air

Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units Review of the Residual Risk and Technology

Review" (Docket ID No. EPA-HQOAR-2018-0794),” On Behalf of the North Dakota Department of Environmental

Quality, June 22, 2023.

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basis) of 19,305 kJ/kg (8,300 Btu/lb) or less in an EGU with a height-to-depth ratio

of 3.82 or greater among the top performing 12 percent of sources for Hg emissions,

indicating a difference in the emissions for this HAP from these types of units.

The boiler of a coal-fired EGU designed to burn coal with that heat value is larger

than a boiler designed to burn coals with higher heat values to account for the larger

volume of coal that must be combusted to generate the desired level of electricity.

Because the emissions of Hg are different between these two subcategories, we are

proposing to establish different Hg emission limits for the two coal-fired

subcategories.”

As explained by DEQ, EPA has not provided any scientific justification to support abandoning the

lignite subcategory and requiring those facilities to comply with the emission standards applicable

to other coal types. The most EPA identified in support of its proposal was a reference to

information nearly 30 years old, which predated EPA’s original determination.

The Proposed MATS Rule Will Not Provide Meaningful Human Health or

Environmental B

Section 112(f)(2) of the CAA directs EPA to assess the remaining residual public health and

environmental risks posed by hazardous air pollutants (HAPs) emitted from the EGU source

category. 11 Further regulation under MATS is required only if that residual risk assessment

demonstrates that a tightening of the current HAP emission limitations is necessary to protect

public health with an ample margin of safety or protect against adverse environmental effects.

When reviewing whether to revise the MATS Rule, EPA determined that further regulation of

mercury and other HAPs would be unnecessary to address any remaining residual risk from any

affected EGU within the source category. The stringent standards based on state-of-the-art control

technologies that are currently imposed on coal-fired EGUs have already achieved significant

reductions in HAP emissions. As EPA itself noted, the MATS rule has achieved steep reductions

in HAP emission levels since 2010, including a 90 percent reduction in mercury, 96 percent

reduction in acid gas HAPs, and an 81 percent reduction in non-mercury metal HAPs. 12

Data from EPA and the U.N Global Mercury Assessment show mercury emissions from U.S.

power plants are now so low they accounted for only 0.12 percent of global mercury emissions in

2022, assuming all other sources remained constant at 2018 levels. 13 These data demonstrate that

2, 2023) (“Cichanowicz Report”).

Fact Sheet, EPA’s Proposal to Strengthen and Update the Mercury and Air Toxics Standards for Power Plants,

https://www.epa.gov/system/files/documents/2023-04/Fact%20Sheet_MATS%20RTR%20Proposed%20Rule.pdf

United Nations, “Global Mercury Assessment 2018,” UN Environment Programme, August 21, 2019,

https://wedocs.unep.org/bitstream/handle/20.500.11822/27579/GMA2018.pdf?sequence=1&isAllowed=y

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US mercury emissions from power plants are lower than global cremation emissions, and North

Dakota coal facilities emitted 9.25 times less mercury in 2021 than global cremations in 2018. 14

As the above chart indicates: the annual mercury emissions from global cremations (where the

mercury primarily comes from individuals with dental fillings) exceed the mercury annually

emitted by all coal-fired EGUs in the United States combined, and is orders of magnitude more

than the mercury emissions from all coal-fired EGUs in North Dakota. 15

Moreover, the Administrative Record indicates EPA has performed a comprehensive and detailed

risk assessment that clearly documents the negligible remaining residual risks posed by the very

low amount of HAPs now being emitted by coal-fired EGUs. EPA first performed that risk

assessment in 2020, which concluded that “both the actual and allowable inhalation cancer risks

to the individual most exposed were below 100-in

in-1 million, which is the presumptive limit of

ERM Sustainability Initiative, “Benchmarking Air Emissions of the 100 Largest Power Producers in the United

States,” Interactive Tool, accessed February 29, 2024, https://www.sustainability.com/thinking/benchmarking-airemissions-100-largest-us

us-power-producers/

UN Environmental Programme. (2018). Global Mercury Report 2018, Technical Background Report to the Global

Mercury Assessment. https://www.unenvironment.org/resources/publication/global-mercury-assessment-technicalbackground-report

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acceptability” for protecting public health with an adequate margin of safety. 16 Similarly, EPA’s

risk assessment supports the conclusion that residual risks of HAP emissions from the EGU source

category are “acceptable” for other potential public health effects, including both chronic and acute

non-cancer effects. 17

These conclusions have been confirmed by the detailed reevaluation of the 2020 risk assessment

that the Agency is now completing as part of the current rule-making action. That EPA

reevaluation clearly demonstrates that the 2020 risk assessment did not contain any significant

methodological or factual errors that could call into question the results and conclusions reached

in the 2020 risk assessment. Most notably, EPA used well-accepted approaches and methodologies

for performing a residual risk analysis that adhere to the requirements of the statute and are

consistent with prior residual risk assessments performed by EPA over the years for other industry

sectors. 18

The results from both residual risk assessments can lead to only one rational conclusion: the current

MATS limitations provide an ample margin of safety to protect public health in accordance with

CAA section 112.

The DEQ filed comments addressing these points and asking EPA to provide a better health benefit

justification than the rationale currently included in the Regulatory Impacts Analysis (RIA). 19 In

particular, DEQ noted that EPA cannot rely on non-HAPs' co-benefits to justify the Proposed Rule,

and EPA has not identified any HAP-related benefits that would be sufficient to justify the

Proposed Rule. The agency also voiced skepticism over what it called EPA' s suspect

characterization of the health benefits that it identified, which is quoted below:

While the screening analysis that EPA completed suggests that exposures

associated with mercury emitted from EGUs, including lignite-fired EGUs, are

below levels of concern from a public health standpoint, further reductions in these

emissions should further decrease fish burden and exposure through fish

consumption including exposures to subsistence fishers. 20

DEQ’s well-founded concern is that EPA’s admission that current exposure associated with

mercury is below levels of concern is directly inconsistent with, not support of, EPA’s proposal

for a lower standard.

DEQ commented that this theme, unfortunately, is consistent across the entire "Benefits Analysis"

section of the RIA, citing another example of this inconsistency, which is quoted below:

“Regarding the potential benefits of the rule from projected HAP reductions,

we note that these are discussed only qualitatively and not quantitatively

88 Fed. Reg. at 24,865.

Id. at 24,865-66.

88 Fed. Reg. at 24,865.

Regulatory Impact Analysis for the Proposed National Emission Standards for Hazardous Air Pollutants: Coal- and

Oil-Fired Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review (Apr. 2023),

Docket ID: EPA-HQ-OAR-2018-0794-5837.

Id. At p. 0-8.

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....Overall, the uncertainty associated with modeling potential of benefits of

mercury reduction for fish consumers would be sufficiently large as to

compromise the utility of those benefit estimates-though importantly such

uncertainty does not decrease our confidence that reductions in emissions

should result in reduced exposures of HAP to the general population,

including methylmercury exposures to subsistence fishers located near these

facilities. Further, estimated risks from exposure to non-mercury metal HAP

were not expected to exceed acceptable levels, although we note that these

emissions reductions should result in decreased exposure to HAP for

individuals living near these facilities.” 21

Comments filed by the Lignite Energy Council (LEC) further emphasize the point. LEC stated

that according to the risk review EPA conducted in 2020, which EPA has proposed to reaffirm, the

risks from current emissions of hazardous air pollutants (HAP) emitted by coal-fired power plants

are several orders of magnitude below what EPA deems sufficient to satisfy the Clean Air Act. 22

LEC points out that EPA has for decades found risks to be acceptable with an ample margin of

safety if maximum individual excess cancer risks presented by any single facility is less than “100in-1 million.” In comparison, EPA’s analysis of the coal- and oil-fired electric utility source

category recognizes the risk it presents is now at one tenth of that acceptable level, with a

maximum risk from any individual facility of “9-in-1 million.”

However, even that value vastly overstates the risk associated with coal-fired power plants. The

“9-in-1 million” risk level identified by EPA is only associated with a single, uncontrolled, residual

oil-fired facility located in Puerto Rico. 23 What EPA’s discussion of risk fails to recognize, but its

analysis clearly shows, is that the highest level of risk presented by any coal-fired power plant is

actually “0.3-in-1 million,” more than 300 times lower than the threshold EPA deems acceptable. 24

The level of risk presented by North Dakota lignite-powered plants is lower still. According to

EPA’s risk review, the maximum risks presented by any North Dakota lignite-fired power plant is

“0.08-in-1 million,” yet another order of magnitude lower than the highest risk from any coal-fired

plant, and more than three orders of magnitude lower than EPA’s “acceptable” level of risk with

an “ample margin of safety.”

Id. at pp. 4-1 - 4-2.

Jason Bohrer, “Comments on National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired

Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review, 88 Fed. Reg. 24854

(Apr. 24, 2023), June 23, 2024.

Residual Risk Assessment for the Coal- and Oil-Fired EGU Source Category in Support of the 2020 Risk and

Technology Review Final Rule, Docket ID No. EPA-HQ-OAR-2018-0794-4553, App. 10, Tbls. 1 & 2a (Sept. 2019)

(“Risk Assessment”) (note that Table 2a is printed upside down in the final September 2019 version of the Residual

Risk Assessment posted at www.regulations.gov, which may interfere with search commands; a searchable version of

the same table is available in the December 2018 draft version, Docket ID No. ). See also 84 Fed. Reg. at 2699 (“There

are only 4 facilities in the source category with cancer risk at or above 1-in-1 million, and all of them are located in

Puerto Rico.”).

Jason Bohrer, “Comments on National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired

Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review, 88 Fed. Reg. 24854

(Apr. 24, 2023), June 23, 2024.

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The risks from North Dakota lignite are so low that they are more easily expressed, not in a million,

but in a billion—EPA has determined that the excess cancer risks from all North Dakota lignite

plants fall between 5- and 80-in-1 billion. 25 Moreover, EPA’s analysis indicates that those

maximum risks are not associated with mercury. 26

In fact, EPA’s own analysis confirms the risks from North Dakota lignite-powered plants are so

low they are little more than a rounding error that does not even qualify as a significant digit. In

its analysis of the still low but relatively higher risk from the Puerto Rican oil-fired plants, EPA

determined that one of those facilities presented a risk no greater than “1-in-1 million,” even

though EPA’s modeling actually returned a risk level of “1.09-in-1 million.”6 EPA discarded the

extra “.09,” apparently finding it too small to matter. However, that extra “.09” risk equates to “90in-1 billion,” and it is therefore higher than the entire risk identified for any North Dakota lignite

plant.

The Administrative Record Indicates the Mercury Standard of 1.2 lb./TBtu

is Technically Unachievable for EGUs using North Dakota Lignite Coal

The Administrative Record for the proposed rule suggests EPA made numerous critical mistakes

in assuming lignite fired EGUs can achieve a 1.2 Hg/lb limit with 90% Hg removal. As detailed in

the Cichanowicz Report, Section 6, EPA assumed the characteristics of lignite and subbituminous

coals are similar such that the Hg removal by emission controls capabilities is similar. In this light,

EPA did not consider that the high presence of sulfur trioxide (SO3) in lignite coal combustion flue

gas that significantly limits the Hg emissions reduction potential of emissions controls. 27

Similarly, as noted by LEC, EPA’s proposal references data obtained via an information collection

request as indicative of the level of performance achievable at North Dakota lignite facilities, but

that data only reflects relatively short-term testing that does not fully capture the significant

variability of lignite coals. Also, unlike other types of facilities that may be able to blend coals to

achieve greater consistency in the character of their fuel, all North Dakota lignite units are located

at mine-mouth facilities without access to other coal types, and therefore depend entirely on the

fuel extracted from the neighboring mine. As a result, changes in constituents between seams of

lignite coal can result in a high level of variability in the emission rates that result from use of the

coal as it is mined over time. 28

While LEC agreed with EPA that the injection of activated carbon is the most effective means of

reducing mercury emissions from lignite-powered units, LEC also criticized EPA for ignoring the

well-known diminishing returns of injecting more carbon. With each marginal increase in carbon

Risk Assessment, Tbl. 2a (indicating cancer risks of 8.07e-08, 3.09e-08, 1.31e-08, 1.21e-08, and 5.12e-09 for

Facility NEI IDs 380578086511, 380578086311, 380558011011, 380578086511, 380578086611 (Milton R. Young,

Leland Olds, Coal Creek, Antelope Valley, and Coyote).

Id., at Tbl. 2a (indicating the target organ of the risk associated with the plants identified in note 5 is “respiratory”).

2, 2023) (“Cichanowicz Report”).

Jason Bohrer, “Comments on National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired

Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review, 88 Fed. Reg. 24854

(Apr. 24, 2023), June 23, 2024.

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injection, the incremental increase in emission reduction capability falls. Thus, injecting more and

more carbon will not necessarily result in greater emission reductions beyond a certain injection

level. LEC asked EPA to evaluate the effect of diminishing returns on its conclusion that North

Dakota lignite-powered facilities can achieve the standard designed for all other units of 1.2

lb/TBtu.

EPA does not appear to have taken the above concerns into account in claiming lignite- powered

facilities can achieve the performance levels achieved at subbituminous plants. As a result, EPA

has significantly underestimated the level of control needed to achieve the proposed standard of

1.2 lb/TBtu. Contrary to the analysis EPA relies upon to justify lowering

This text is long and has been trimmed here. Open the source document for the complete record.

This is a copy of a public record, reproduced as it was published. It is not legal advice, and it may not be the version a court would rely on. Check the official source before you cite it.