Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page i TABLE OF CONTENTS

1.0 INTRODUCTION ............................................................................................................ 1-1

2.0 BASELINE DATA .......................................................................................................... 2-1 2.1 Emission Units That Constitute the FMMI BART-Eligible Source ........................ 2-1 2.1.1 Electric Furnace ................................................................................... 2-1 2.1.2 Converters ........................................................................................... 2-2 2.2 Existing Control Measures ................................................................................... 2-3 2.2.1 Double-Contact Acid Plant ................................................................... 2-3 2.2.2 Vent Fume Scrubber ............................................................................ 2-4 2.2.3 Converter Mouth Covers ...................................................................... 2-4 2.2.4 Pollution Prevention ............................................................................. 2-5 2.3 BART-Eligible Baseline Emissions ...................................................................... 2-5 2.3.1 Acid Plant Tail Gas Stack .................................................................... 2-5 2.3.2 Vent Fume Stack ................................................................................. 2-7 2.3.3 Smelter Fugitives ................................................................................. 2-8 2.3.4 Summary of BART-eligible Baseline Emissions .................................. 2-8

3.0 BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS ...................................... 3-1 3.1 Identification of Available Retrofit Control Technologies ...................................... 3-1 3.1.1 Sulfur Dioxide ...................................................................................... 3-2 3.1.2 Nitrogen Oxides ................................................................................... 3-6 3.2 Elimination of Technically Infeasible Options ....................................................... 3-7 3.2.1 Sulfur Dioxide ...................................................................................... 3-8 3.2.2 Nitrogen Oxides ................................................................................... 3-8 3.3 Evaluation of Control Effectiveness of Remaining Control Technologies .......... 3-11 3.3.1 Sulfur Dioxide .................................................................................... 3-11 3.3.2 Nitrogen Oxides ................................................................................. 3-14 3.4 Evaluation of Impacts ......................................................................................... 3-15 3.4.1 Sulfur Dioxide .................................................................................... 3-15 3.4.2 Nitrogen Oxides ................................................................................. 3-21 3.4.3 Summary of Impacts Evaluation and Determination of Control Level Representing BART ........................................................................... 3-23 3.5 BART Determination .......................................................................................... 3-26 3.5.1 SO 2 Emissions, Acid Plant Tail Gas Stack ........................................ 3-26 3.5.2 SO 2 Emissions, Vent Fume Stack ..................................................... 3-26 3.5.3 NO X Emissions .................................................................................. 3-26

4.0 References .................................................................................................................... 4-1Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page ii 

### Appendices

Appendix A Baseline Emissions Calculation

Appendix B Emission Reduction and Cost Effectiveness Calculations

Appendix C Eric Partelpoeg, PhD, Analysis of SO 2 Emissions AllocationsFreeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 1-1 1.0 INTRODUCTION

Freeport-McMoRan Miami Inc. (FMMI) requested that AMEC conduct a Best Available Retrofit Technology (BART) analysis for the sulfur dioxide (SO 2 ) and nitrogen oxide (NO X ) units that constitute the BART eligible source at FMMI’s copper smelting facility in Claypool, Arizona (Miami Smelter). AMEC’s BART analysis was conducted in accordance with the procedures contained in the U.S. Environmental Protection Agency’s (USEPA) “Guidelines for BART Determinations under the Regional Haze Rule” (BART Guidelines) under Title 40 of the Code of Federal Regulations (CFR) Part 51, Appendix Y. According to USEPA’s BART Guidelines, a case-by-case BART analysis consists of the following five basic steps:

1. Identify All Available Retrofit Control Technologies,
2. Eliminate Technically Infeasible Options,
3. Evaluate Control Effectiveness of Remaining Control Technologies,
4. Evaluate Impacts and Document the Results, and
5. Evaluate Visibility Impacts.

This report documents AMEC’s five-step BART analysis for the SO 2 and NO X units that constitute FMMI’s BART-eligible source. Section 2 provides baseline data, including an overview of the SO 2 and NO X units, current emission control practices, and baseline emissions. Section 3 identifies available retrofit control technologies; evaluates their technical feasibility, control effectiveness, and impacts; and concludes the analysis with recommendations for BART. References are listed in Section 4.Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 2-1 2.0 BASELINE DATA

2.1 Emission Units That Constitute the FMMI BART-Eligible Source

The emission units that constitute the FMMI BART-eligible source have previously been identified as FMMI’s Electric Furnace, Converte rs No. 2 through No. 5, and Double-Contact Acid Plant (78 FR 46142). As explained by USEPA’s BART Guidelines, “BART eligible sources” are those sources which have the potential to emit 250 tons or more of a visibility-impairing air pollutant, were put in place between August 7, 1962 and August 7, 1977, and whose operations fall within one or more of 26 specifically listed source categories. USEPA’s BART Guidelines set forth the following step-by-step process for identifying the emission units that constitute the BART-eligible source:

1. Identify the emission units in the BART categories.
2. Identify the start-up dates of those emission units.
3. Compare the potential emissions from units identified in Steps 1 and 2 to the 250 ton/year cutoff.
4. Identify the emission units and pollutants that constitute the BART eligible source.

Because FMMI’s Double-Contact Acid Plant is a control device for the reduction of SO 2 emissions, it should not be identified as an emission unit in the “primary copper smelter” BART category in Step 1. As USEPA’s BART Guidelines explain:

Sources are not BART-eligible if the only change at the plant during the relevant time period was the addition of pollution controls. For example, if the only change at a copper smelter during the 1962 through 1977 time period was the addition of acid plants for the reduction of SO 2 emissions, these emission controls would not by themselves trigger a BART review.

Accordingly, the emission units that constitute the FMMI BART-eligible source include only the Electric Furnace and Converters No. 2 through No. 5. FMMI’s Double-Contact Acid Plant will be addressed in this BART analysis as an existing control for the reduction of SO 2 emissions.

2.1.1 Electric Furnace

The Electric Furnace is used as a slag (residual ferrosilicates and other compounds) separation device. It can potentially be used as a primary sm elting vessel in the event that the Isa furnace goes down, but at a greatly reduced concentrate feed rate by comparison. The Electric Furnace receives a matte/slag mixture by launders (a refractory-lined channel used to convey molten metallurgical material by gravity) from the IsaSmelt ® (Isa) furnace and slag returned from the converters by ladle. There are two separate launder systems. The purpose of the Electric Furnace is to separate the matte/slag mixture through retention time and density differences.Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 2-2 After the copper matte settles to the bottom of the Electric Furnace, the slag on the top of the bath is removed from the process by launder into slag pots and transferred by a Kress Hauler (a specialized truck) to the slag storage area. Matte is tapped from the Electric Furnace by launder into ladles and transported by crane to the converters. Six electrodes in the furnace maintain the bath temperature through resistive heating by passing a current through the slag layer. Electrode seals are installed on the furnace arch around each electrode to reduce air infiltration. A furnace off-take is located at the matte end of the furnace. Sonic water sprays cool the gas exiting the furnace via the off-take. The flue gases in the off-take are subsequently passed to the Double-Contact Acid Plant.

The Electric Furnace normally uses electricity to keep the molten materials hot by resistive heat (passing electricity through the molten slag layer). Natural gas must periodically be used in certain situations (e.g., electrical outages, electrode breakage, cold furnace startup after the bath has been lowered to a level below the travel limit of the electrodes). Maximum natural gas usage during these scenarios is estimated at 15,000 standard cubic feet per hour (approximately 15 MMBtu/hr). Natural gas has not been used in the Electric Furnace since
2008.

Process off-gas from the Electric Furnace is captured in an off-take duct, cooled with water sprays, and then combined with Isa furnace and converter process off-gases that are routed to the Double-Contact Acid Plant, which serves as a control device for SO 2 emissions. Captured process fugitive emissions from the Electric Furnace matte tapping launders/ladles, and Electric Furnace slag tapping launders/ladles are collected by the vent fume system. These gases pass through a scrubber for SO 2 emissions control and then through wet electrostatic precipitators (WESP) prior to venting through the Vent Fume Sta ck. Emissions that are not captured by the process off-gas or vent fume capture system s exit through a roofline vent located above the furnace.

2.1.2 Converters

Converting of matte to blister copper occurs in four Hoboken Converters (No. 2 through No. 5). The Inspiration Converter (No. 1) is no longer operable. The conversion of matte to blister copper is performed by blowing air into the molten matte through tuyeres. Oxygen in the air reacts with iron and sulfur, producing slag and SO 2 gas. The blast air rate can vary per copper charge. Silica is added to the bath to complete the slag formation process (converts the iron compounds to iron silicate).

Converting is accomplished in a two-step proce ss: a slag blow to remove iron and part of the sulfur, and a copper blow to remove the remaining sulfur to produce blister copper. The oxidation reactions are exothermic (heat pr oducing) and “cold dope” can be added during the process to control the bath temperature. “Cold dope” consists of secondary or intermediate copper-containing solid materials (e.g., reverts, buttons, copper scrap, etc.). The normalFreeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 2-3 converter operations require three hot converters (two blowing and one in standby). Slag from the converters is returned to the Electric Furnace by ladle. Blister copper is transferred by ladle to one of the two anode furnaces (in batches) and on occasion to the mold vessel for temporary storage.

Each Hoboken converter is equipped with an integral side flue at one end of the furnace for withdrawal of the off-gas. Shaped like an inverted "U", this flue, or siphon, rotates with the converter, as does the cylindrical duct to whic h it is connected. The cylindrical duct is connected by an airtight rotating joint to a fixed vertical duct that leads to the gas cleaning system. The Hoboken thus provides a direct lin k at all times between the converter and the gas off-take, regardless of its operating position. Hoboken converters generate only minimal fugitive emissions because the converter is operated under ze ro or slightly negative draft. At slight negative draft, air from outside of the converter is sucked into the mouth and exits through the converter siphon with the gas stream containing the SO 2 generated during blowing. Slight negative or zero draft prevents fugitive emi ssions from the mouth of the converter.

The converters do not require supplemental heat as the exothermic reaction in the vessel provides the necessary heat for the process. Natural gas must periodically be used in certain situations (e.g., to maintain heat when the converters are on standby, vessel pre-heat during cold startups, and burn-out of accretions in the dome section). Maximum natural gas usage during these scenarios is estimated at 20,000 standard cubic feet per hour (approximately 20 MMBtu/hr) per converter based on data from 2007 through 2012. Normal natural gas use during the period is estimated at 11,400 standard cubic feet per hour (approximately 11 MMBtu/hr) per converter. Natural gas is never used when the converter is processing matte.

Process off-gas from the converters is collected and conveyed through the side-flue intake on each converter vessel. The process off-gas is cooled by water sprays, and then combined with Isa and Electric Furnace process off-gases before being routed to the Double-Contact Acid Plant for control of SO 2 emissions. Uncaptured emissions exit through roofline vents located above the converters.

2.2 Existing Control Measures

2.2.1 Double-Contact Acid Plant

The process off-gases from the Isa, Electric Furnace, and converters are combined and passed to radial flow scrubbers and a packed gas cooling tower. The gases are then passed through a set of primary and secondary WESPs and then vented to the Double-Contact Acid Plant. The Double-Contact Acid Plant utilizes the following unit operations to remove SO 2 from the flue gas and produce sulfuric acid:

 Drying tower;Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 2-4  Four catalyst beds containing potas sium-promoted vanadium pentoxide (V 2 O 5 ) catalyst which converts SO 2 to SO 3 ;

 Cesium-promoted V 2 O 5 catalyst in the first and fourth catalyst beds to improve conversion of SO 2 to SO 3 when the bed temperatures are less than the activation temperature for the potassium-promoted catalyst. Catalyst volumes are based on vendor specification for the pressure drop and temperature of the beds;

 Two SO 3 absorption towers for sulfuric acid production;

 Heat exchangers, strong acid coolers, and cooling water towers (evaporative & air-to-air) to dissipate heat from the Acid Plant; and

 A natural gas-fired preheater to heat the c onverter beds during startup, or when catalystbed temperatures fall below desired values (the Acid Plant Preheater is not BARTeligible).

The gases from the Double-Contact Acid Plant are routed to the Tail Gas Stack. The Tail Gas Stack is equipped with a scrubber that is used as necessary to reduce SO 2 concentrations in the tail stack to help ensure compliance with the SO 2 limit imposed by New Source Performance Standards (NSPS) at 40 CFR 60 Subpart P. The scrubber currently uses magnesium oxide and/or magnesium hydroxide as a scrubbing agent, but also has the capability to use soda ash and caustic, with modifications. The scrubber typically operates approximately 440 hours per year. The Double-Contact Acid Plant is expected to achieve an overall SO 2 removal efficiency of better than 99 percent.

2.2.2 Vent Fume Scrubber

A scrubber similar in design to the Tail Gas Stack Scrubber is used to remove SO 2 from the flue gas captured by the Vent Fume Collection Sy stem. The scrubber is operated continuously and currently uses magnesium oxide and/or magnes ium hydroxide as a scrubbing agent, but also has the capabilities to use soda ash and caustic, with modifications. The Vent Fume Scrubber is expected to achieve a removal efficiency of better than 60 percent.

2.2.3 Converter Mouth Covers

Actuated mouth covers are in the process of being installed on all four Hoboken Converters (Nos. 2 through 5). The covers are anticipated to improve the efficiency of the side flue intake capture system and reduce potential process off-gas leakage during blowing operations into the Converter Aisle. The mouth covers are also anticipated to reduce heat loss from the vessel by reducing infiltration in the converter mouth during blowing operations or in a ‘hot’ standby mode. The additional off-gas captured as a result of the mouth covers installation will be routed to the Double-Contact Acid Plant, reducing process fugitive SO 2 emitted from the converters and through the roofline by 80 percent. The project will also result in more efficient operation of the converters, which in turn will result in a reduction of natural gas use required for burnout ofFreeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 2-5 accretions and heating during standby. Therefore, a reduction in anticipated actual NO X emissions is also expected although no attempt is made to quantify the NO X reduction in this analysis.

2.2.4 Pollution Prevention

The Electric Furnace typically uses electricity to provide needed heat. Use of the electrodes reduces the need for fossil fuels and is therefore considered to be a pollution prevention measure because it minimizes SO 2 and NO X emissions from the Electric Furnace. Similarly, the converters do not require supplemental heat as the exothermic reaction in the vessel provides the necessary heat for the process.

As noted previously, natural gas must be used in these vessels in certain situations. Natural gas is an inherently low-sulfur fuel compared to other available alternatives such as coal and oil. Combustion of natural gas also results in reduced NO X emissions compared to coal and oil.

2.3 BART-Eligible Baseline Emissions

Figure 1 presents a schematic of emissions from the various emission units located at FMMI. The figure illustrates that emissions from the units that constitute the BART-eligible source are vented through the Tail Gas Stack, the Vent Fume Stack, and roofline vents. 1 However, emissions from other units are also vented through the same release points. Because emissions testing has historically been perfo rmed at the release points for compliance demonstration purposes, potential emissions from the facility have traditionally been quantified by release point rather than by specific emission unit venting to the release point. Accordingly, for purposes of establishing baseline emissions for the units that constitute the BART-eligible source, the emissions from the release points mu st be speciated or allocated by emission unit.

2.3.1 Acid Plant Tail Gas Stack

BART-eligible baseline emissions for the Tail Gas Stack are based on actual emissions reported to the Arizona Department of Environmental Quality (ADEQ) for 2011 and 2012. The total SO 2 emissions reported to ADEQ were measured by the Continuous Emissions Monitoring System (CEMS) installed on the Tail Gas Stack. The total NO X emissions were estimated based on the results of semi-annual stack tests performed on the Tail Gas Stack (i.e., a total of four stack tests).

1 Because USEPA’s BART Guidelines do not generally recommend that emissions reflecting periods of start-up, shutdown, and malfunction be used for visibility impact modeling, the Acid Plant Bypass Stack has not been included in the baseline emissions analysis.Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 2-7 The allocation of Tail Gas Stack SO 2 emissions to the emission units is based on a sulfur balance of the material in the Isa, Electric Furnace, and converters. Data available for March and April 2013 were evaluated and determined to be representative of normal smelter operations (Partelpoeg, 2014). The analysis concluded that SO 2 emissions are allocated as follows:

 Isa = 67 percent,

 Converters = 31 percent, and

 Electric Furnace = 2 percent.

The allocation of Tail Gas Stack NO X emissions to the emission units is based on analysis of natural gas consumption in the Isa, Electric Fur nace, and converters. Natural gas consumption data available for 2007 to 2012 were evaluated and determined to be representative of normal smelter operations. The analysis concluded that NO X emissions are allocated as follows:

 Isa = 99 percent,

 Converters = 0.9 percent, and

 Electric Furnace = 0.04 percent.

These figures were applied to the reported Tail Gas Stack emissions of SO 2 and NO X . The resulting emissions are presented in Table 2-1.

2.3.2 Vent Fume Stack

BART-eligible baseline emissions for the Vent Fume Stack are based on actual emissions reported to ADEQ for 2011 and 2012. The total SO 2 emissions reported to ADEQ were measured by the CEMS installed on the Vent Fume Stack. The Vent Fume System does not collect process fugitive emissions from areas that would produce NO X emissions. Consequently, there are no baseline NO X emissions for the Vent Fume Stack.

The allocation of Vent Fume Stack SO 2 emissions to the emission units is based on an analysis of the open surface area of molten metal-bearing materials associated with the Isa and Electric Furnace (Partelpoeg, 2014). The analysis concluded that SO 2 emissions are allocated as follows:

 Isa = 39 percent, and

 Electric Furnace = 61 percent.

These figures were applied to the reported Vent Fume Stack emissions of SO 2 . The resulting emissions are presented in Table 2-1.Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 2-8 2.3.3 Smelter Fugitives

BART-eligible baseline SO 2 emissions were estimated based on average hourly emission rates (lb/hr) measured in 2012 from the roof monitors (Trinity, 2013). Direct measurements are preferred over the historic use of a mass balance approach and represent the best data available for estimating baseline emissions. BART-eligible baseline NO X emissions are derived from actual emissions reported to ADEQ for 2011 and 2012 and based on natural gas consumption in the smelter building and AP-42 emission factors for natural gas combustion.

The roofline study of SO 2 emissions showed that SO 2 emissions are allocated as follows (Trinity, 2013):

 Isa = 24 percent,

 Converters = 53 percent,

 Electric Furnace = 4 percent, and

 Anode Furnaces = 19 percent.

The allocation of fugitive NO X emissions to the emission units is based on analysis of natural gas consumption in the smelter. Natural gas consumption data available for 2007 to 2012 were evaluated and determined to be representative of normal smelter operations. The analysis concluded that NO X emissions are allocated as follows:

 Isa = 4.1 percent,

 Converters = 40.2 percent,

 Electric Furnace = 1.6 percent, and

 Anode Furnaces = 54.1 percent.

These figures were applied to the reported fugitive emissions of SO 2 and NO X . The resulting emissions are presented in Table 2-1.

2.3.4 Summary of BART-eligible Baseline Emissions

In accordance with USEPA BART Guidelines, bas eline emissions should reflect a realistic depiction of anticipated annual emissions for the units that constitute the BART-eligible source. As quantified per the discussion above, the annual BART-eligible baseline emissions are summarized in Table 2-1. A more detailed calculation table is provided in Appendix A.Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 2-9 Table 2-1. Calculated Baseline Emissions for the FMMI BART-Eligible Source

SO 2 (tpy) NO X (tpy)

Emission Point Electric
Furnace Converters Total Electric
Furnace Converters Total
Acid Plant Tail Gas Stack 10.9 344 355 0.1 1.7 1.8
Vent Fume Stack 316 - 316 - - - Smelter Process Fugitives 41.3 109 151 0.8 19.1 19.9
Total 369 453 822 0.9 20.8 21.7Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-1 3.0 BEST AVAILABLE RETROFIT TECHNOLOGY ANALYSIS

USEPA’s visibility regulations at 40 CFR 51 Subpart P define “BART” as follows:

Best Available Retrofit Technology (BART) means an emission limitation based on the degree of reduction achievable through the application of the best system of continuous emission reduction for each pollutant which is emitted by . . . [a BART-eligible source]. The emission limitation must be established, on a case-by-case basis, taking into consideration the technology available, the costs of compliance, the energy and non-air quality environmental impacts of compliance, any pollution control equipment in use or in existence at the source, the remaining useful life of the source, and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology.

According to USEPA’s BART Guidelines at 40 CFR 51 Appendix Y, design, equipment, work practice, operation standard, or combination of these types of standards can be established as BART when technical or economic limitations in the application of measurement methodologies make conventional emission limits infeasible.

The five basic steps of a case-by-case BART anal ysis as set forth in USEPA’s BART Guidelines

are: Step 1: Identify all available retrofit control technologies;
Step 2: Eliminate technically infeasible options;
Step 3: Evaluate control effectiveness of remaining control technologies;
Step 4: Evaluate impacts and document the results; and
Step 5: Evaluate visibility impacts.

3.1 Identification of Available Retrofit Control Technologies

It is important to recognize that FMMI’s smelting process is unique in the United States. No other actively operating or decommissioned primary copper smelter in the US uses or used the IsaSmelt ® process. As a result, neither the U SEPA’s RACT/BACT/LAER Clearinghouse (RBLC) nor air permits issued to other primary copper smelters provide information specific to the technology employed at FMMI. Nevertheless, t he production processes used at other primary copper smelters are analogous and emission control determinations for these processes may be transferable. Similarly, emission controls used at other industry sources such as coal-fired power plants and sulfuric acid production facilities may be transferable.

To identify potential BART options, AMEC reli ed on USEPA’s RBLC, air permits for facilities likely to have analogous processes, and technical journals such as that published by the Air &Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-2 Waste Management Association (AWMA). As such, the analysis is a reasonably comprehensive compilation of potentially available retrofit control technologies.

3.1.1 Sulfur Dioxide

The following identifies both available retrofit c ontrol technologies and other retrofit control measures that could possibly reduce SO 2 emissions from the emission units that constitute the FMMI BART-eligible source. A retrofit control measure could include, for example, the improved capture of SO 2 emissions that can then be routed to an existing control device such as the Vent Fume Scrubber or the Acid Plant.

3.1.1.1 Absorption

Absorption methods for SO 2 control include wet scrubbers (such as those used at FMMI), dry scrubbers (spray dryer absorbers or SDA), and dry sorbent injection (DSI). All of these technologies rely on control of sulfur dioxide through an acid-base reaction that occurs in the flue gas. SO 2 is acidic in nature. Absorption techniques utilize bases as the reagent (typically alkaline minerals such as lime or caustic soda) in a neutralization reaction that produces a salt. This salt is precipitated and removed from the combustion gases for off-site disposal.

Wet Scrubbers

The advantage of a wet scrubber system is that it is capable of higher SO 2 removal rates (attaining higher levels of SO 2 removal when there is heavy loading) than alternative absorption technologies. The disadvantages are that the construction materials are more costly and the waste products result in environmental impacts (the need for wastewater handling and treatment) and often require special handling. Wet scrubber systems are more complex (and thus more expensive) to operate.

Wet scrubbers can use a variety of alkaline minerals for the neutralization reaction. The most common uses slaked lime or limestone as the reagent. Another uses a sodium-based reagent such as sodium hydroxide. The advantage of t he lime scrubber is the lower cost of the reagent; however, large amounts of liquid and solid waste are generated. The sodium-based scrubber generates less waste; however, this waste is more difficult to treat. Magnesium-based reagents, such as those presently used at FMMI, are another option.

In these systems, the flue gas is passed through a reaction vessel and passed through thereagent which neutralizes the acid gases. The reaction kinetics favor neutralization of sulfurbased acid gases and mists over any neutralization of halogenated and organic acids. Some reagent is constantly purged from the reaction vessel (blowdown) and replenished with fresh reagent (makeup) to maintain the acid gas neutralizing capabilities. The treatment and disposal of this liquid waste stream must be considered in the design and costing of the system.Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-3 Due to the increased pressure drop across the wet scrubber, a new induced draft fan (ID fan) is usually required in retrofit situations. The increased draft losses caused by the pressure drop across the wet scrubber must be considered in selecting the ID fan and any increases in backpressure at the precipitator must be evaluated. In many instances a new stack must also be considered.

All materials of construction downstream of a wet scrubber must be constructed of very corrosion-resistant material, such as stainless steel. Moreover, the addition of moisture to the flue gas can drastically reduce flue gas temperatures, and may require a reheating process before the gas leaves the stack to avoid excess condensation inside the stack.

Dry Scrubbers (Spray Dry Absorbers)

Dry scrubbers rely on reagents sprayed into the scrubber reaction vessel with minimal water so that the byproduct is dry and can be handled us ing conventional ash handling equipment. The scrubber, commonly referred to as a Spray Dryer Absorber (SDA), removes SO 2 from the flue gas by injecting atomized lime slurry into the scrubber vessel via very fine nozzles. The waste product from the scrubber is dry lime because most of the liquid is evaporated in the vessel. It is a common misconception to consider a dry scrubber as having no water in the process, when in fact this technology requires water to produce the lime slurry. The evaporated water can cause a prominent water vapor plume from the stack under most weather conditions.

Like wet scrubbers, dry scrubbers rely on the use of alkaline minerals (reagent) to neutralize acid gases such as SO 2 . In these systems, a small amount of water is mixed with the reagent to form a slurry which is atomized and sprayed into the flue gas. The acid gases react with the alkaline material in the slurry and are neutralized. The sensible heat of flue gas vaporizes the water and the neutralized material, now a solid, is removed by a downstream PM control device. Factors affecting this neutralization process include quality of the slurry, droplet size of the atomized slurry, flue gas temperature, and contact time of the flue gas with the atomized slurry. To a substantial degree, the size of the reaction vessel determines the retention time. Due to increase in the volumetric capacity of the flue gas from vaporization of water in the slurry, a larger reaction vessel is required for a dry scrubber than a wet scrubber to effect the same contact time of the flue gas.

In normal operation a dry scrubber increases the particulate matter (PM) load of the flue gas, thereby requiring a location upstream of a PM control device. This, along with the need for a larger reaction vessel, makes retrofitting a dry scrubber at an existing facility generally more difficult than a wet scrubber. In the specific case of FMMI, there are no attractive retrofit applications for a dry scrubber. The primary off-gas control includes the acid plant and its associated existing wet scrubber, both of which are located downstream of PM control equipment. The vent fume system includes a we t scrubber located upstream of PM control equipment, and as such a dry scrubber would effect ively serve as a replacement technology forFreeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-4 the wet scrubber rather than a retrofit technology. In the case of vent fume wet scrubber replacement, the additional PM loading would also require an upgrade of the PM control device.

Generally, dry scrubbers are not as efficient as wet scrubbers for the removal of sulfur-based acid gases, although they typically achieve at least 80 percent removal rates in traditional applications with high levels of SO 2 in the flue gas. Dry scrubbers can achieve 80-90% reductions with the addition of a baghouse for typical applications with significant sulfur loading. A cake of unreacted reagent accumulates on the bags, offering additional removal or requiring less reagent than a dry scrubber/ESP combination.

Dry Sorbent Injection

Dry sorbent injection (DSI) has been used in mostly research-type applications as a lesser cost option to retrofitting existing coal fired boilers with flue gas desulfurization (FGD) requirements. Like scrubber technologies, DSI neutralizes the acid gases through the use of alkaline reagents. DSI injects the reagent directly into the furnace or flue gas path. However, even distribution of the reagent can be difficult to achieve and contact time with the reagent is reduced compared to wet and dry scrubbing techniques. Reagent injection into the furnace allows for more residence time for the reagent. Potential side effects may include slagging, and corrosion or erosion of boiler internals. Injection of reagent just prior to the PM control device is the most common option employed. However, significantly reduced contact time can result in lower acid gas removal efficiencies and overloading of existing PM control devices.

In this type of system, dry reagent is convey ed from a storage silo through a blower/metering system. A short contact time is expected and the PM loading into the PM control device is increased considerably. The increased PM loading often requires further control of PM. In the specific case of FMMI, there are no attractive retrofit applications for DSI. The primary off-gas control includes the acid plant and its associated existing wet scrubber, both of which are located downstream of PM control equipment. The vent fume system includes a wet scrubber located upstream of PM control equipment, and as such a dry scrubber would effectively serve as a replacement technology for the wet scrubber. In the case of a replacement of the vent fume wet scrubber, the additional PM loading would also require an upgrade of the PM control device.

Amine Systems

A regenerable aqueous dimethylaniline (DMA) reagent was used to control SO 2 emissions from the reverberatory furnace located at the former Ajo Smelter in Ajo, Arizona. The absorbed gas was dried by sulfuric acid, compressed, and condensed to a liquid form. Liquid SO 2 was stored under pressure and then vaporized to supplement t he acid plant operation whenever necessary. CANSOLV ® is a similar patented technology that uses an aqueous amine reagent to achieve selective absorption of SO 2 from a variety of gas streams. The technology has been used toFreeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-5 reduce SO 2 emissions from acid plant ta il gas at a lead smelter in India. An amine scrubber system is incompatible with the existing scrubb er systems in use at FMMI and would therefore constitute a replacement technology for the Acid Plant Tail Gas Stack and for the Vent Fume Stack.

Hydrogen Peroxide Systems

Hydrogen peroxide reagent can be used in scrubbers to convert SO 2 directly to sulfuric acid, which is recycled to the acid plant. Outotec’s Peracidox ®

process is an example that has been applied to sulfuric acid plants. Tail gas is washed in a two-stage scrubber with dilute sulfuric acid in which the hydrogen peroxide is dissolv ed. The hydrogen peroxide is introduced into the acid circuit of the first scrubbing stage at a stoichiometric rate proportional to the SO 2 to be removed. The scrubber overflow consists of dilute sulfuric acid with an optimum concentration 50 percent sulfuric acid by weight. The sulfuric acid is introduced into the final or intermediate absorber of the main acid plant in place of process water. A hydrogen peroxide scrubber system is incompatible with the existing scrubb er systems in use at FMMI and would therefore constitute a replacement technology for the Acid Plant Tail Gas Stack and for the Vent Fume Stack.

3.1.1.2 Sulfuric Acid Plant

A sulfuric acid plant is an available control technology that is commonly used to reduce SO 2 emissions from smelters, as is the case at FMMI which specifically uses a double-contact process. Process off-gases must first be cleaned to remove impurities such as PM and water vapor. Because dust can fill the voids in the catalyst material and reduce its activity, cyclones,scrubbers, or electrostatic precipitators are used to remove the material before the process offgas enters the acid plant’s drying tower.

Available retrofit control technologies for SO 2 emissions include improvements in the efficiency of the existing Acid Plant’s conversion of SO 2 to SO 3 . In most cases, the improvements would be most readily addressed by equipment replacement rather than retrofits, such as converter beds, heat exchangers, and SO 3 coolers. Cesium-promoted catalyst can also be charged to the converter beds, although FMMI is already usi ng cesium-promoted catalyst in the vendorrecommended first and fourth beds. The volume of cesium-promoted catalyst currently used by FMMI is based on vendor specifications for the current pressure drop and temperature of the catalyst beds. Greater volumes of cesium-promoted catalyst can only be achieved with additional upgrades of the acid plant, such as increased fan capacity to address increased pressure drop and increased cooling capacity to ensure the bed temperatures are in the activation range of the cesium catalyst.Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-6 3.1.1.3 Enhanced Capture

Enhanced capture of process fugitive emissions is a control measure that can reduce pollutant emissions. For example, the roofline above the Converter Aisle and above the Electric Furnace can be reconfigured to capture process fugitive emissions and route the captured emissions to an existing control device or a new control device.

Additional capture of Electric Furnace fumes at the matte tapping hood could also be used. Select leakages in the existing vent fume system inlet ductwork would be eliminated and active control used to increase ventilation from the existing active matte tapping hoods by 20 percent. The captured SO 2 would be passed to the existing vent fume scrubber resulting in reduced SO 2 emissions.

3.1.1.4 Pollution Prevention

As noted earlier in this report, SO 2 emissions can be reduced by em ploying a low-sulfur fuel such as natural gas and FMMI is actively utilizing this SO 2 control measure. Reduction in sulfur content of smelter raw materials would also be a means of reducing SO 2 emissions. The rawmaterials are received from a number of different locations and the sulfur content of the metalbearing minerals received cannot be readily reduced. Furthermore, the process at FMMI is configured in part based on the sulfur content of raw materials (i.e., smelting is used to extract copper from sulfide ores). For example, the co nverters are configured to rely on the exothermic reaction of sulfur in the vessels.

3.1.2 Nitrogen Oxides

The following identifies both available retrofit c ontrol technologies and other retrofit control measures that would reduce NO X emissions from the FMMI BART-eligible source. Because no NO X controls have been implemented at primary copper smelters, candidate NO X controls were selected as those which are technically demonstrated and commercially available for combustion sources.

3.1.2.1 Combustion Modifications

Combustion modifications for NO X control consist of various techniques to limit NO X formation at the combustion source. Such modifications are arranged to carefully control combustion temperature, available oxygen, and flame turbul ence and residence time at peak temperatures. Common combustion controls include low NO X burners, staged combustion, low-excess-air, burners out-of-service, and flue gas recirculation. These are common technologies employed in boilers, but are impractical and infeasible for us e in the Electric Furnace and Converters. The burners used at FMMI are long pole-style burners where natural gas and oxygen are added at the head, blended down the length of the shaft, and combusted at the tip. The burners must be of retractable design to be quickly inserted and removed from the vessels. The burners areFreeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-7 designed to meet the temperature specifications required for proper operation of the Converters and Electric Furnace.

3.1.2.2 Selective Non-Catalytic Reduction

SNCR uses injection of a NO X reducing reagent, either anhydrous ammonia (NH 3 ), aqueous ammonium (NH 4 + ), or urea (NH 2 C(O)H 2 ), into hot flue gas. The reducing reagent is injected into the flue gas where the flue gas temperature is between 1600°F and 2100°F. The high gas temperatures support high chemical reaction rates so that a catalyst is not required. The reagent reduces NO X to nitrogen and water. In traditi onal boiler installations, SNCR systems often have multiple injection levels to account for shifting of the optimal reaction temperature window (1600°F - 2100°F) as the boiler load changes. This arrangement ensures maximum NO X reduction over varying boiler loads and as the furnace heat exchange characteristics vary. With SNCR, placement of the reagent injection probes is important. If reagent is injected at a point where the flue gas temperature is greater than 2100°F, ammonia or urea will react with oxygen to form additional NO X . At flue gas temperatures less than 1600°F, excessive/ unreacted ammonia passes through the ductwork and is discharged out the stack as ammonia slip.

3.1.2.3 Selective Catalytic Reduction

SCR uses a combination of reducing reagent and a catalyst placed in the flue gas stream to promote the NO X reduction reaction. In a full-scale SCR system, the flue gas is ducted through a separate reactor that contains a catalyst. Traditional SCR using vanadium-titanium catalysts requires flue gas temperatures of 550°F to 750°F for efficient NO X reduction. Zeolite catalysts are available which can operate at temperatures up to 1130°F. With SCR, either aqueous ammonia (after vaporization) or anhydrous ammoni a is injected upstream of a catalyst reactor that is placed in a location where the gas temperature is in the optimal range. The ammonia reacts with NO X on the catalyst to form nitrogen gas and water. The catalyst is installed in the reactor in layers. Catalysts can be installed with a specified number of catalyst layers with provisions for adding future layers if necessary . While SCR systems have the potential for high NO X removal, there are inherent operating concerns associated with their use such as plugging or poisoning of the catalyst, high dependence on proper flue gas temperature for NO X reduction, and some emissions of unreacted ammonia (“ammonia slip”). SCR is capable of NO X reduction efficiencies as high as 80 percent with low corresponding ammonia slip concentrations.

3.2 Elimination of Technically Infeasible Options

Most of the identified SO 2 and NO X control measures are technically feasible, although not in all possible configurations. For example, absorption techniques are not technically feasible upstream of the Acid Plant. The reduction in SO 2 to the Acid Plant would render the Acid Plant ineffective and would additionally require upgrades to the PM control devices upstream of theFreeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-8 Acid Plant. In contrast, a dry scrubber would be technically feasible for the control of captured emissions from a reconfigured converter aisle roofline.

3.2.1 Sulfur Dioxide

3.2.1.1 Concentrate Sulfur Content

The pollution prevention measure of reducing the su lfur content of smelter raw materials is not technically feasible for FMMI. The concentrated ores available to FMMI are sulfide concentrates, and the smelting process is used to separate copper from the ferrous and sulfide components. While smelting sulfide concentrates, most of the energy needed to heat and melt the feed materials is derived from the reaction of oxygen with the sulfur and iron in the concentrate. Because the smelter is specifical ly designed to process sulfide concentrates, a reduction in the sulfur content is not technically feasible.

3.2.1.2 Absorption

Absorption techniques would not be technically feasible in a position upstream of the Acid Plant. Such placement of absorbers, regardless of technology, would render the Acid Plant to be ineffective. Furthermore, dry scrubbers and dry sorbent injection would require a reconfiguration of PM control devices upstream of the Acid Plant. Dry absorption, amine absorption, and hydrogen peroxide absorption techniques located downstream of the acid plant would constitute a replacement of the existi ng Tail Gas Scrubber. While these techniques are feasible downstream of the acid plant, they provide less effective control than the existing Tail Gas Scrubber and consequently the existing wet scrubber is a better control option. Therefore, dry absorption, amine absorption, and hydrogen peroxide absorption techniques located before and after the acid plant are not considered further.

Similarly, the use of dry absorption techniques in the Vent Fume System would require a reconfiguration of PM control devices. Such a retrofit, while not technically infeasible, is impractical in comparison to retrofits that focus on the existing wet scrubber. Furthermore, dry absorption, amine absorption, and hydrogen per oxide absorption techniques provide less effective control than the existing Vent Fume Scrubber and consequently the existing wet scrubber is a better control option. Therefore, dry absorption techniques located in the Vent Fume System are not considered further.

3.2.2 Nitrogen Oxides

3.2.2.1 Combustion Modifications

The use of low-NO X combustion techniques is not technica lly feasible for FMMI. Because the Electric Furnace is a metallurgical reactor that utilizes a unique combustion method, none of the conventional NO X combustion controls are feasible. The efficiency of the slag separationFreeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-9 process in the Electric Furnace is highly dependent upon carefully controlled conditions which cannot be altered without severely affecting the process. Furthermore, the Electric Furnace is predominantly operated using electrical resistance. Natural gas has not been used in the Electric Furnace since 2008. Similarly, the converter requirements for heating and burnout are such that conventional NO X combustion controls are not feasible.

Low NO X burners work by reducing the oxygen level in the primary combustion zone to limit fuel NO X formation, reducing the flame temperature to limit thermal NO X formation, and the residence time at peak temperature to reduce thermal NO X formation. In the case of natural gas, which has a very low fuel nitrogen content, strategies focus on reducing thermal NO X formation. The thermal NO X reduction strategies, particularly flame temperature reduction, is infeasible for the units to operate at specification. In the case of the Electric Furnace, the slag separation requirements are such that the use of low NO X burners is not feasible. Similarly, the burnout requirements in the converters are such that the use of low NO X burners is not feasible. Likewise, other NO X reduction strategies that involve the mixing and dilution of combustion gases with air and flue gas to reduce thermal NO X formation (such as staged combustion and flue gas recirculation) are not feasible technologies.

3.2.2.2 Selective Non-Catalytic Reduction

SNCR has been successfully applied to a number of traditional (boiler/furnace) combustion systems; however, it is not tec hnically feasible upstream of t he Acid Plant. The extremely high flue gas sulfur content and the layout of the flue gas train from the radial flow scrubbers through the Acid Plant are the principal reasons. SO 3 /H 2 SO 4 present at 5,000 to 8,000 ppm in the offgas ahead of the Acid Plant will react with ammonia slip to form condensed ammonium sulfate/ammonium bisulfate (AS/ABS) as the flue gas cools. Equipment fouling, pluggage, and corrosion from AS/ABS formation has plagued high sulfur applications of SCR and SNCR where ammonia slip is not strictly limited to less than 1-2 ppm (Radian, 1991).

Based on 5 ppm ammonia slip and 5,000 ppm SO 3 in the flue gas, thermodynamic calculations show that the upper temperature threshold for AS/ABS formation is approximately 585°F (TRC, 1995). As the gas is cooled below this threshold, rapid reaction of ammonia with SO 3 occurs to form condensed AS/ABS. Condensation would occur within the long run of ductwork leading to the radial flow scrubbers, resulting in rapid pluggi ng of the ductwork with solid/liquid AS/ABS. In addition, rapid corrosion and destruction of the existing carbon steel ductwork would be expected because ammonium bisulfate is highly acidic.

There are a number of additional technical reasons for eliminating SNCR from consideration, including adverse effects of ammonia slip on the gas cleaning and sulfuric acid processes. For these reasons, and because of the unavoidable downstream AS/ABS fouling from this application, SNCR is not technically feasible as a NO X control upstream of the Acid Plant.Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-10 A tail-end SNCR system would avoid most of the identified concerns; however, the energy required for flue gas reheat to achieve temperatures in the range of 1600°F to 2100°F would be excessive by comparison to a tail-end SCR system. A review of RBLC controls on nitric acid and sulfuric acid plants reveals that no plant s are equipped with SNCR systems. Rather, SCR systems are instead used and becaus e SCR systems achieve greater NO X removal than SNCR systems, SNCR systems are not further evaluated for the Acid Plant Tail Gas Stack.

Similarly, the ideal temperature window of 1600°F to 2100°F would not exist in the ductwork of a reconfigured roofline used to enhance capture of process fugitive emissions. The flue gas would need to be reheated for the SNCR reaction to proceed. The need to reheat flue gas does not alone render SNCR as technically infeasible. However, the energy required would be excessive by comparison to a SCR system and because SCR systems achieve greater NO X removal than SNCR systems, SNCR systems are not evaluated further.

3.2.2.3 Selective Catalytic Reduction

SCR could theoretically be retrofitted in several locations ahead of the Acid Plant where the flue gas is at the optimal SCR operating temperatur e. The optimum location would fall between the waste heat recovery boiler and the ESP. However, the SCR catalysts will not withstand the high SO 2 levels in these areas. The maximum SO 2 content for which SCR could be applied is in the range of 2,000 ppm. The flue gas SO 2 concentration ahead of the Acid Plant is typically much greater than 2,000 ppm. Furthermore and as noted for SNCR, ammonia slip concentrations would need to be well maintained at levels less than 2 ppm to prevent AS/ABS fouling problems ahead of the Acid Plant.

SCR is technically feasible downstream of th e existing Acid Plant Tail Gas Scrubber, just upstream of the stack. In this area, a “tail-end” SCR configuration would be required. This configuration would require a heater to reheat the flue gas temperature in the range of 120°F to 160°F up to a minimum of 600°F before treatment with SCR. To lessen the overall cost of the system, a recuperative heat exchanger is usually applied to recover heat from the SCR exit flue gas while simultaneously heating the SCR inlet flue gas. The RBLC does indicate the installation of an SCR unit on a sulfuric acid plant, and therefore a tail-end SCR configuration is retained as a technically feasible option.

SCR is not feasible for a reconfigured roofline vent system because of the particulate matter loading in the flue gas. The particulate loading damages the SCR catalyst through erosion, thermal sintering and particulate deposition. High levels of alkali aerosols, calcium and potassium in particular, have been shown to irre versibly poison SCR catalyst and dramatically reduce its performance. Therefore, SCR is not a feasible technology for reducing NO X emitted to the roofline vent.Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-11 3.3 Evaluation of Control Effectiveness of Remaining Control Technologies

The remaining control measures and technologies identified as technically feasible could potentially be implemented in a variety of ways at FMMI. AMEC identified feasible scenarios for control measures and provides an analysis of control effectiveness (in terms of achievable emissions reductions) for each scenario.

3.3.1 Sulfur Dioxide

Retrofits to the existing wet scrubbers, the existing acid plant, and control measures that include the capture of additional emissions and control of those emissions at existing or new control devices are evaluated below.

The following control measures are considered in the following sections, ranked by the calculated emission reduction from BART-eligible baseline emissions:

 Upgrade Acid Plant Tail Gas Scrubber to caustic reagent (348 tpy),

 Upgrade Vent Fume Scrubber to caustic reagent (299 tpy),

 Continuously operate existing Acid Plant Tail Gas Scrubber (281 tpy),

 Upgrade Acid Plant (266 tpy),

 Capture process fugitive emissions at Converter Aisle Roofline and install New Wet Scrubber (56.2 tpy),

 Capture process fugitive emissions at Electric Furnace Roofline and install New Wet Scrubber (34.8 tpy),

 Increase Acid Plant Tail Gas Scrubber operation (<31 tpy),

 Improve capture of process fugitive em issions from Electric Furnace Matte Tapping Hood and use existing Vent Fume Scrubber (1.0 tpy).

Detailed calculations of emission reductions are provided in Appendix B.

3.3.1.1 Upgrade Acid Plant Tail Gas Scrubber to Caustic Reagent

As shown in Table 2-1, BART-eligible baseline SO 2 emissions through the Tail Gas Scrubber are estimated to be 355 tpy. Reconfiguring the scrubber to use a caustic reagent is expected to improve the control efficiency to better than 98 percent. The calculation of SO 2 reduction from baseline requires a calculation of the SO 2 loading to the scrubber inlet. A performance test of the scrubber showed a control efficiency of 71 percent as currently operated. As noted previously, the scrubber is used as necessary to meet SO 2 limits imposed by the NSPS at 40 CFR 60 Subpart P, operating 440 hours per year on average. Thus, BART-eligible baseline SO 2 loading to the scrubber amounts to 368 tpy. SO 2 emissions from the upgraded scrubberFreeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-12 would be 7 tpy, assuming a control efficiency of 98 percent can be achieved. BART-eligible baseline SO 2 emissions would be reduced from 355 tpy to 7 tpy, resulting in a reduction of BART-eligible baseline SO 2 emissions by 348 tpy (see Table B-1 for the detailed calculation).

3.3.1.2 Upgrade Vent Fume Scrubber to Caustic Reagent

The existing scrubber with magnesium hydroxi de slurry reagent has an estimated control efficiency in the range of 60 to 65 percent, with BART-eligible baseline SO 2 emissions through the vent fume system estimated to be 316 tpy as shown in Table 2-1. Reconfiguring the scrubber to use a caustic reagent is expected to im prove the control efficiency to better than 98 percent.

The calculation of SO 2 reduction from baseline requires a calculation of the SO 2 loading to the scrubber inlet. A performance test of the scrubber showed a control efficiency of 62 percent as currently operated. Thus, BART-eligible baseline SO 2 loading to the scrubber amounts to 832 tpy. SO 2 emissions from the upgraded scrubber would be 17 tpy, assuming a control efficiency of 98 percent can be achieved. This, BART-eligible baseline SO 2 emissions would be reduced from 316 tpy to 17 tpy, resulting in a reduction of BART-eligible baseline SO 2 emissions by 299 tpy (see Table B-2 for the detailed calculation).

3.3.1.3 Continuously Operate Acid Plant Tail Gas Scrubber

The existing scrubber with magnesium hydroxi de slurry reagent has an estimated control efficiency in the range of 70 to 75 percent. As noted previously, the scrubber is used as needed to help ensure compliance with the NSPS Subpart P limit and is operated 440 hours per year on average. Baseline SO 2 emissions through the Tail Gas Stack are estimated to be 355 tpy based on intermittent operation of the Tail Gas Scrubber. Operating the Tail Gas Scrubber continuously would require capital expenditure for upgrades to the magnesium hydroxide handling system and construction of a new stack made of materials that would be compatible with the continuous use of the existing scrubb er. Continuous operation would also increase operating and maintenance expenditures with the purchase of additional reagent and the handling of additional sludge.

The calculation of SO 2 reduction from baseline requires a calculation of the SO 2 loading to the scrubber inlet. A performance test of the scrubber showed a control efficiency of 71 percent as currently operated. Thus, baseline SO 2 loading to the scrubber amounts to 368 tpy. SO 2 emissions from continuous operation of the scrubber would be 74 tpy. Baseline SO 2 emissions would be reduced from 355 tpy to 74 tpy, resulting in a reduction of baseline SO 2 emissions by 281 tpy (see Table B-3 for the detailed calculation).Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-13 3.3.1.4 Upgrade Acid Plant

The existing acid plant would be upgraded for additional capacity, including additional catalyst loading, and gas and acid cooling. Additional cooling facilitates reduced SO 2 emissions through improved plant operation and allows for increas ed use of cesium-promoted catalyst. The amount of cesium catalyst added to the first pass would be increased to 35 percent of the catalyst load, while the amount of cesium catalyst added to the fourth pass would be increased to 100 percent of the catalyst load for improved conversion. A new maintenance shop would be required for layout reasons as the existing shop would need to be demolished to accommodate the new acid plant equipment.

As shown in Table 2-1, BART-eligible baseline SO 2 emissions through the Tail Gas Scrubber are estimated to be 355 tpy. This control measure, as addressed in this section, would not include an upgrade of the Tail Gas Scrubber. The Acid Plant upgrade would reduce the SO 2 loading to the Tail Gas Scrubber by 70 to 80 percent. Assuming a 75 percent reduction of SO 2 loading to the Tail Gas Scrubber, the Acid Plant upgrade would reduce BART-eligible baseline SO 2 emissions by approximately 266 tpy (see Table B-4 for the detailed calculation).

3.3.1.5 Capture Process Fugitive Emissions at Converter Aisle Roofline, Install New Wet Scrubber

As shown in Table 2-1, BART-eligible baseline SO 2 emissions through the Converter Aisle Roofline are estimated to be 109 tpy. The reconfigured roofline would capture an expected 84.7 percent of SO 2 emissions. The Acid Plant does not have the capacity to handle the additional captured volume of air, and even if it had the capacity, the additional air would dilute the SO 2 concentration entering the Acid Plant, rendering it less effective. Similarly, the Vent Fume Scrubber would not have the capacity to handle the additional volume. Therefore, a new wet scrubber would be constructed to treat the captured emissions. The new wet scrubber would reduce these captured SO 2 emissions to a concentration of 1 ppm or less, equivalent to a controlled emission rate of 53 tpy. BART-eligible baseline SO 2 emissions would be reduced by 56 tpy (see Tables B-5 and B-6 for the detailed calculation).

3.3.1.6 Capture Process Fugitive Emissions at Electric Furnace Roofline, Install New Wet Scrubber

As shown in Table 2-1, BART-eligible baseline SO 2 emissions through the Electric Furnace Roofline are estimated to be 41 tpy. The reconfigured roofline would capture an expected 84.7 percent of SO 2 emissions. The Acid Plant does not have the capacity to handle the additional captured volume of air, and even if it had the capacity, the additional air would dilute the SO 2 concentration entering the Acid Plant, rendering it less effective. Similarly, the Vent Fume Scrubber would not have the capacity to handle the additional volume. Therefore, a new wet scrubber would be constructed to treat the captured emissions. The new wet scrubber wouldFreeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-14 reduce these captured SO 2 emissions to a concentration of 1 ppm or less, equivalent to a controlled emission rate of 6 tpy. BART-eligible baseline SO 2 emissions would be reduced by 35 tpy (see Tables B-5 and B-7 for the detailed calculation).

3.3.1.7 Increase Acid Plant Tail Gas Scrubber Operation

An alternative to continuously operating the Acid Plant Tail Gas Scrubber would be to increase its frequency of use. The scrubber could be run additional hours per year (up to 1,300 hours) without capital expenditure such that cost would be associated with increased purchase of reagent and handling of additional sludge.

The calculation of SO 2 reduction from baseline requires a calculation of the SO 2 loading to the scrubber inlet. A performance test of the scrubber showed a control efficiency of 71 percent as currently operated. Thus, baseline SO 2 loading to the scrubber amounts to 368 tpy. Baseline SO 2 emissions would be reduced by 31 tpy or less, depending on the number of additional operating hours (see Table B-8 for the detailed calculation).

3.3.1.8 Improve Capture of Process Fugitive Emissions at Electric Furnace Matte Tapping Hood

Select leakages in the existing vent fume sy stem ductwork would be eliminated and active control would be used to increase ventilation fr om the existing active matte tapping hoods by 20 percent, reducing SO 2 emissions to the roofline by 4 percent. The additional captured SO 2 would be passed to the existing Vent Fume Scrubber resulting in reduced SO 2 emissions. BART-eligible baseline SO 2 emissions through the Electric Furnace Roofline are estimated to be 41.3 tpy. These BART-eligible baseline SO 2 emissions would be reduced by 1 tpy using the existing Vent Fume Scrubber (see Table B-9 for the detailed calculation).

3.3.2 Nitrogen Oxides

As was noted in the evaluation of technical feasibility, combustion modifications and SNCR will not be evaluated further. SCR is the only NO X control measure to be evaluated further and is determined to be technically feasible only at the Acid Plant Tail Gas Stack.

3.3.2.1 Selective Catalytic Reduction at Acid Plant Tail Gas Stack

A tail-end SCR system would be installed between the Tail Gas Scrubber and the Tail GasStack. A tail-end SCR system has an estimated control efficiency of 75 to 85 percent. BARTeligible baseline NO X emissions through the Tail Gas Stack are 1.8 tpy without SCR control per Table 2-1. Based on a control efficiency of 80 percent, the tail-end SCR system would reduce BART-eligible NO X emissions to 0.4 tpy, resulting in an emissions reduction of 1.4 tpy (see Tables B-10 through B-12 for the detailed calculation).Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-15 3.4 Evaluation of Impacts

The evaluation of impacts includes analysis of cost of compliance, energy impact, and environmental impact. The control measures li sted in Section 3.3 are evaluated further.

3.4.1 Sulfur Dioxide

Cost estimates for the SO 2 control measures were supplied by Hatch except where indicated in the following discussion. Equipment and other direct costs were based on a combination of Hatch engineering experience and consultation with vendors. Other direct costs included distributed control system upgrades (various additional new systems in the facility) and construction distributables (items such as contractor supervision and management, on-site facilities and scaffolding).

Indirect costs were factored as a percentage (38.1 percent) of the total direct cost. These include items essential for implementing the scope: engineering, procurement and construction management (EPCM), pre-operational testing, trav el and relocation, temporary construction facilities and services, first fills, capital and commissioning spares, vendor representatives, freight and third party services.

Contingency was factored as a percentage of the total direct plus indirect cost. A value of 15 percent was applied for this analysis. Contingenc y is a provision for project costs which will occur, but which cannot be defined in sufficient detail for estimating purposes due to the lack of complete, accurate and detailed information, as well as limited engineering which has been performed. Project contingency does not cover cost escalation, scope changes or project exclusions.

Owner’s costs were likewise factored as a percentage of the total direct plus indirect cost. A value of 6.7 percent was applied for this analysis. The Owner’s costs include salaries and expenses associated with the Owner’s team, environmental modeling, permitting fees, legal expenses, abatement costs and other miscellaneous expenses expected to be incurred at the site.

Hatch used a simplified approach for estimating annual operating costs. Annual scrubbing reagent costs were calculated from total estimated SO 2 design reductions (i.e., inclusive of emission units that are not BART-eligible) while all other operating costs were factored as 7.4 percent of partial direct capital cost.

3.4.1.1 Upgrade Acid Plant Tail Gas Scrubber to Caustic Reagent

Costs of Compliance. The Acid Plant Tail Gas Scrubber upgrade requires a new reagent receiving and distribution system and modifica tion of the existing scrubber. Table B-1 shows the calculations, assumptions, and results. The total capital investment is estimated atFreeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-16 approximately $11.63 million. The resulting capital recovery, based on a 15-year equipment life and an interest rate of 7 percent per the USEPA’s OAQPS Control Cost Manual, is estimated to be $1.28 million per year. Annual operating and maintenance costs are estimated to be $1.10 million, resulting in a total estimated annualized cost of $2.38 million per year.

For the BART-eligible baseline SO 2 emission rate of 355 tpy and the estimated control efficiency of 98%, the amount of BART-eligible SO 2 emissions removed would be 348 tpy. The resulting cost-effectiveness is estimated as $6,800 per ton of BART-eligible SO 2 emissions removed. Consequently, the Acid Plant Tail Gas Scrubber upgrade is not considered cost effective for BART purposes.

Energy Impacts. Continuous operation of the scrubber will result in increased energy use compared to existing energy use. The existing scrubber typically operates 440 hours per year. Energy use will increase more-or-less in proportion to the increased hours in operation.

Environmental Impacts. Wet scrubbers create large amounts of scrubber blowdown and solids that must be handled. FMMI reuses all of the generated material, with solids sent back to the smelter and liquids sent to the mine for use in the respective processes. While the upgrade would generate more blowdown than the existing operation, the upgrade is not expected to have environmental impacts that are significant ly different from the existing environmental impacts because of the reuse of the generated materials.

Conclusion. Given the significant economic impact associated with the upgrade of the Acid Plant Tail Gas Scrubber, the scenario was eliminated from further consideration as BART.

3.4.1.2 Upgrade Vent Fume Scrubber to Caustic Reagent

Costs of Compliance. The Vent Fume Scrubber upgrade requires a new reagent receiving and distribution system and modification of the ex isting scrubber. Table B-2 shows the calculations, assumptions, and results. The total capital investment is estimated at approximately $8.55 million. The resulting capital recovery, based on a 15-year equipment life and an interest rate of 7 percent per the USEPA’s OAQPS Control Cost Manual, is estimated to be $0.94 million per year. Annual operating and maintenance costs are estimated to be $0.99 million, resulting in a total estimated annualized cost of $1.93 million per year.

Cost-effectiveness is based on the annualized cost of the control ($/year) divided by the amount of SO 2 that can be controlled (tpy). The result is a measure of control cost in units of dollars per ton. For the BART-eligible baseline SO 2 emission rate of 316 tpy and the estimated control efficiency of 98%, the amount of BART-eligible SO 2 emissions removed would be 299 tpy. The resulting cost-effectiveness is estimated as $6,500 per ton of BART-eligible SO 2 emissions removed. Consequently, the Vent Fume Scrubber upgrade is not considered cost effective for BART purposes.Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-17 Energy Impacts. The scrubber upgrade is not expected to have energy impacts that are significantly different from the existing energy impacts.

Environmental Impacts. Wet scrubbers create large amounts of scrubber blowdown and solids that must be handled. FMMI reuses all of the generated material, with solids sent back to the smelter and liquids sent to the mine for use in the respective processes. While the upgrade would generate more blowdown than the existing operation, the upgrade is not expected to have environmental impacts that are significant ly different from the existing environmental impacts because of the reuse of the generated materials.

Conclusion. Given the significant economic impact associated with the upgrade of the Vent Fume Scrubber, the scenario was eliminated from further consideration as BART.

3.4.1.3 Continuously Operate Acid Plant Tail Gas Scrubber

Costs of Compliance. Continuous operation of the scrubber would require capital investment to install a new wet stack, isolation damper, and ductwork. Table B-3 shows the calculations, assumptions, and results for modifying the scrubber for continuous operation. The total capital investment is estimated at approximately $7.23 million. The resulting capital recovery, based on a 15-year equipment life and an interest rate of 7 percent per the USEPA’s OAQPS Control Cost Manual, is estimated to be $0.79 million per year. Annual operating and maintenance costs are estimated to be $1.55 million, largely due to the continuous use of high-cost magnesium-based reagents, resulting in a total estimated annualized cost of $2.35 million per
year.

For the baseline SO 2 emission rate of 355 tpy and the estimated control efficiency of 80%, the amount of BART-eligible SO 2 emissions removed would be 281 tpy. The resulting costeffectiveness is estimated as $8,300 per ton of BART-eligible SO 2 emissions removed. Consequently, the continuous operation of the Acid Plant Tail Gas Scrubber is not considered cost effective.

Energy Impacts. Continuous operation of the scrubber will result in increased energy use compared to existing energy use.

Environmental Impacts. Wet scrubbers create large amounts of scrubber blowdown and solids that must be handled. FMMI reuses all of the generated material, with solids sent back to the smelter and liquids sent to the mine for use in the respective processes. While the continuous operation would generate more blowdown than the existing operation, the continuous operation is not expected to have environmental impacts that are significantly different from the existing environmental impacts because of the reuse of the generated materials.Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-18 Conclusion. Given the significant economic impact associated with the continuous operation of the Acid Plant Tail Gas Scrubber, the option wa s eliminated from further consideration as BART.

3.4.1.4 Upgrade Acid Plant

Costs of Compliance. The existing acid plant would be upgraded for additional capacity, including additional catalyst loading, gas and acid cooling, and an additional blower. Additional cooling facilitates reduced SO 2 emissions through improved plant operation. The amount of cesium-promoted catalyst added to the first pass would be increased to 35 percent of the catalyst load, while the amount of cesium-promoted catalyst added to the fourth pass would be increased to 100 percent of the catalyst load for improved conversion. A new maintenance shop would be required for layout reasons as the existing shop would need to be demolished to accommodate the new acid plant equipment.

Table B-4 shows the calculations, assumptions, and results. The total capital investment is estimated at approximately $114.84 million. The resulting capital recovery, based on a 20-year equipment life and an interest rate of 7 percent per the USEPA’s OAQPS Control Cost Manual, is estimated to be $10.84 million per year. Annual operating and maintenance costs are estimated to be $3.05 million, resulting in a total estimated annualized cost of $13.89 million per
year.

For the BART-eligible baseline SO 2 emission rate of 355 tpy, the amount of BART-eligible SO 2 emissions removed would be 266 tpy. The resulting cost-effectiveness is estimated as $52,200 per ton of BART-eligible SO 2 emissions removed. Consequently, the Acid Plant Tail Gas Scrubber upgrade is not considered cost effective for BART purposes.

Energy Impacts. Energy use will increase as a consequence of adding cooling capacity and the additional blower.

Environmental Impacts. The Acid Plant upgrade would require additional disposal of catalyst compared to existing operations.

Conclusion. Given the significant economic impact associated with the upgrade of the Acid Plant, the scenario was eliminated from further consideration as BART.

3.4.1.5 Capture Process Fugitive Emissions at Converter Aisle Roofline, Install New Wet Scrubber

Costs of Compliance. The Converter Aisle roofline would be reconfigured to capture process fugitive emissions and ductwork would be added to pass the captured emissions to a new wet scrubber. Additional caustic receiving and distribution system capacity would be installed. A new maintenance shop would be required and existing buildings would be demolished toFreeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-19 accommodate new equipment. Tables B-5 and B-6 show the calculations, assumptions, and results. The total capital investment is estimated at approximately $102.85 million. The resulting capital recovery, based on a 15-year equipment life for the wet scrubber and an interest rate of 7 percent per the USEPA’s OAQPS Control Cost Manual, is estimated to be $11.29 million per year. Annual operating and maintenance costs are estimated to be $4.23 million, resulting in a total estimated annualized cost of $15.52 million per year.

For the BART-eligible baseline SO 2 emission rate of 109 tpy, the amount of BART-eligible SO 2 emissions removed would be 56 tpy. The resulting cost-effectiveness is estimated as $276,300 per ton of BART-eligible SO 2 emissions removed. Consequently, the Converter Aisle roofline reconfiguration and associated new wet scrubber are not considered cost effective for BART
purposes.

Energy Impacts. The system would require a signific ant increase in energy consumption, requiring fans to move 1.4 million acfm of captured air and to operate the new wet scrubber.

Environmental Impacts. Wet scrubbers create large amounts of scrubber blowdown and solids that must be handled. FMMI would reuse all of the generated material, with solids sent back to the smelter and liquids sent to the mine for use in the respective processes. While the new wet scrubber would generate considerably more blowdow n than the existing operation, the smelter and mine have capacity to reuse the generated liquids and solids. Therefore, the project is not expected to have significant environmental impacts.

Conclusion. Given the significant economic impact associated with the project, the scenario was eliminated from further consideration as BART.

3.4.1.6 Capture Process Fugitive Emissions at Electric Furnace Roofline, Install New Wet Scrubber

Costs of Compliance. The Electric Furnace roofline would be reconfigured to capture process fugitive emissions and ductwork would be added to pass the captured emissions to a new wet scrubber. Additional scrubber and caustic receiving and distribution system capacity would be installed to accommodate the additional emissions captured at the Electric Furnace roofline. The costs associated with reconfiguration of t he Electric Furnace Roofline was scaled from thecosts associated with reconfiguration of the Converter Aisle Roofline. The engineering “sixtenths” rule of economies of scale (Peters et al., 2002) was used based on the exhaust flows:

Electric Furnace Cost = Converter Aisle Cost × (Electric Furnace Flow / Converter Aisle Flow) 0.6

Tables B-5 and B-7 show the calculations, assumptions, and results. The total capital investment is estimated at approximately $28.56 million. The resulting capital recovery, based on a 15-year equipment life for the wet scrubber and an interest rate of 7 percent per the USEPA’s OAQPS Control Cost Manual, is estimated to be $3.14 million per year. AnnualFreeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-20 operating and maintenance costs are estimated to be $1.17 million, resulting in a total estimated annualized cost of $4.31 million per year.

For the BART-eligible baseline SO 2 emission rate of 41 tpy, the amount of BART-eligible SO 2 emissions removed would be 35 tpy. The resulting cost-effectiveness is estimated as $124,000 per ton of BART-eligible SO 2 emissions removed. Consequently, the Electric Furnace roofline reconfiguration and associated new wet scrubber are not considered cost effective for BART
purposes.

Energy Impacts. The system would require a signific ant increase in energy consumption, requiring a fan to move 165,000 acfm of captured air and to operate the new wet scrubber.

Environmental Impacts. Wet scrubbers create large amounts of scrubber blowdown and solids that must be handled. FMMI would reuse all of the generated material, with solids sent back to the smelter and liquids sent to the mine for use in the respective processes. While the new wet scrubber would generate considerably more blowdow n than the existing operation, the smelter and mine have capacity to reuse the generated liquids and solids. Therefore, the project is not expected to have significant environmental impacts.

Conclusion. Given the significant economic impact associated with the project, the scenario was eliminated from further consideration as BART.

3.4.1.7 Increase Acid Plant Tail Gas Scrubber Operation

Costs of Compliance. Increased operation of the scrubber would not require capital investment but would require increased expenditure for additional reagent, reagent handling, and sludge handling. The scale of the increase is limited by the existing infrastructure as new storage capacity for reagent and sludge would need to be added at some point (this was addressed in Section 3.4.1.4). Annual direct operating and maintenance costs are estimated to increase linearly with increasing SO 2 reduction. Because of this linear relationship, the cost effectiveness is fixed at an estimated $5,500 per ton of BART-eligible SO 2 emissions removed regardless of the scale of increased operation. Consequently, the increased operation of the Acid Plant Tail Gas Scrubber is not considered cost effective.

Table B-8 shows the calculations, assumptions, and results for increasing scrubber operation. The table shows operating hours increased from 440 hours per year to 1,300 hours per year for illustration purposes.

Energy Impacts. Increased operation of the scrubber will result in increased energy use compared to existing energy use.

Environmental Impacts. Wet scrubbers create large amounts of scrubber blowdown and solids that must be handled. FMMI reuses all of the generated material, with solids sent back to theFreeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-21 smelter and liquids sent to the mine for use in the respective processes. While the increased operation would generate more blowdown than the existing operation, the increased operation is not expected to have environmental impacts that are significantly different from the existing environmental impacts because of the reuse of the generated materials.

Conclusion. Given the significant economic impact as sociated with the increased operation of the Acid Plant Tail Gas Scrubber, the option wa s eliminated from further consideration as BART.

3.4.1.8 Improve Capture of Process Fugitive Emissions at Electric Furnace Matte Tapping Hood

Costs of Compliance. Select leakages in the existing v ent fume system ductwork would be eliminated and active control would be used to increase ventilation from the existing active matte tapping hoods by 20 percent, reducing SO 2 emissions to the roofline by 4 percent. The captured SO 2 would be passed to the existing Vent Fume Scrubber resulting in reduced SO 2 emissions. Table B-9 shows the calculations, assumptions, and results. The total capital investment is estimated at approximately $0.52 million. The resulting capital recovery, based on a 20-year equipment life and an interest rate of 7 percent per the USEPA’s OAQPS Control Cost Manual, is estimated to be $49,000 per year. Annual operating and maintenance costs are estimated to be $20,900, resulting in a total estimated annualized cost of $69,900 per year.

For the BART-eligible baseline SO 2 emission rate of 41.3 tpy, the amount of BART-eligible SO 2 emissions removed would be 1 tpy. The resulting cost-effectiveness is estimated as $68,700 per ton of BART-eligible SO 2 emissions removed. Consequent ly, the improved Electric Furnace Matte Tapping Hood capture is not considered cost effective for BART purposes.

Energy Impacts. The improvement would not result in significant additional energy use.

Environmental Impacts. The improvement would not result in significant additional environmental impacts.

Conclusion. Given the significant economic impact associated with the project, the scenario was eliminated from further consideration as BART.

3.4.2 Nitrogen Oxides

The evaluation of impacts includes analysis of cost of compliance, energy impact, and environmental impact. SCR is the only NO X control measure to be evaluated further and is determined to be technically feasible only at the Acid Plant Tail Gas Stack.Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-22 3.4.2.1 Selective Catalytic Reduction at Acid Plant Tail Gas Stack

Costs of Compliance. A cost estimate for a tail-end SCR system was assembled for purposes of determining SCR cost-effectiveness. Vendor costs were obtained for the primary system components, including:

1. the SCR system itself, including reacto r, catalyst, ammonia injection system, and controls,

2. a NO X analyzer which will be required for the ammonia injection control system,
3. a direct-fired heater to reheat the flue gas,
4. a recuperative heat exchanger with a heat recovery of 95 percent to minimize capital and operating costs, and
5. a new induced-draft fan which will be required to overcome the added flue gas pressure drop resulting from the SCR system.

The cost is based in part on a BACT analysis perf ormed previously for the facility (TRC, 1995). The vendor-quoted equipment cost of $2.23 million was escalated to be representative of current costs by applying cost escalation indice s from the Chemical Engineering Plant Cost Index ( Chemical Engineering , October 1996 and December 2013), resulting in an adjusted equipment cost of $3.57 million.

Cost factors and methods are otherwise bas ed on guidance from USEPA (USEPA, 2002). Tables B-10 through B-12 show the calculations, assumptions, and results. The total capital investment is estimated at approximately $7.07 million. The resulting capital recovery, based on a 20-year equipment life and an interest rate of 7 percent, is estimated to be $0.67 million per year. Annual operating and maintenance costs are estimated to be $1.31 million, resulting in a total estimated annualized cost of $1.98 million per year. The capital and operating costs include the necessary heater/heat exchanger equipment to reheat the exhaust gas to the SCR system.

SCR cost-effectiveness is based on the annualized cost of the control ($/year) divided by the amount of NO X that can be controlled (tpy). The result is a measure of control cost in units of dollars per ton. For the BART-eligible baseline NO X emission rate from the Acid Plant of 1.8 tpy and the estimated control efficiency of 80%, the amount of BART-eligible NO X emissions removed would be 1.4 tpy. The resulting cost-effectiveness is estimated as $1.38 million per ton of BART-eligible NO X emissions removed. Installation of SCR is therefore not considered cost effective for BART purposes.

Energy Impacts. The annual energy impacts resulting from using an SCR system would be the use of approximately 36.7 million scf additional cubic feet per year of natural gas to reheat the flue gas and 3.27 million kWh per year of electricity to overcome the increased pressure dropFreeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-23 across the catalyst reactor. The energy im pact from natural gas consumption would be 25.5 million cubic feet of natural gas per ton of BART-eligible NO X controlled. The impact associated with electricity consumption would be 2.27 million kWh per ton of BART-eligible NO X controlled. These values represent significant energy impa cts and are excessive given the level of NO X emissions controlled.

Environmental Impacts. The environmental impacts associated with using SCR are primarily from the required combustion of additional fossil fuel to reheat the flue gas. Firing natural gas in a duct burner would not only increase NO X emissions, the pollutant intended to be controlled by the SCR system, but would also increase CO, VOC, SO 2 , and PM emissions. In addition, a significant amount of greenhouse gas emissions (CO 2 ) would be generated. Estimated emissions from firing the required amount of nat ural gas were calculated using natural gas combustion emission factors from Section 1.4 of USEPA’s AP-42 (USEPA, 1998) as follows:

 NO X 0.92 tpy;

 CO 1.54 tpy;

 VOC 0.10 tpy;

 SO 2 0.01 tpy;

 PM 0.14 tpy; and

 CO 2 2,200 tpy.

Also, SCR catalysts will oxidize some of the inlet SO 2 to SO 3 , possibly creating stack opacity problems from acid mist and condensed ammonium compounds which pass through the heat exchanger. Additionally, an SCR system would gener ate a solid waste stream in the form of spent catalyst that would also have a negative environmental impact.

Conclusion. Given the significant economic, energy , and environmental impacts associated with application of SCR, it was eliminated from further consideration as BART.

3.4.3 Summary of Impacts Evaluation and Determination of Control Level Representing BART

Based on the foregoing impacts evaluation, the use of existing control measures is the only remaining BART alternative. Because this constitutes the most stringent control available, an air quality modeling analysis for the purpose of determining visibility impacts is not required according to USEPA’s BART Guidelines. Therefore, the control level representing BART is the use of existing control measures, including the Acid Plant, Acid Plant Tail Gas Scrubber, Vent Fume Scrubber, Converter Mouth Covers, and Polluti on Prevention. A summary of the findings are presented in Table 3-1.Freeport-McMoRan Miami Inc.BART AnalysisMiami, ArizonaMarch 2014Page 3-24Table 3-1. Summary of Best Available Retrofit Technology EvaluationsControl TechnologyBART-EligibleEmission UnitsEmissionReduction(tpy)CostEffectiveness($/ton)CommentsSO2Upgrade Acid Plant Tail GasScrubber to CausticConverters andElectric Furnace348 $6,800 Existing scrubber system upgraded to usecaustic reagent: caustic receiving anddistribution capacity installed, blowdowncapacity installed, new stack to addresschanged chemistry.Upgrade Vent Fume Scrubber toCausticElectric Furnace 299 $6,500 Existing scrubber system upgraded to usecaustic reagent: caustic receiving anddistribution capacity installed, new stack toaddress changed chemistry.Continuously Operate ExistingAcid Plant Tail Gas ScrubberConverters andElectric Furnace281 $8,300 Existing scrubber system upgraded: additionalreagent receiving capacity and blowdowncapacity installed, new stack needed toaddress changed chemistry.Upgrade Acid Plant Converters andElectric Furnace266 $52,200 Existing acid plant upgraded for additionalcapacity: additional catalyst loading, gas andacid cooling, additional blower.Capture Process FugitiveEmissions at Converter AisleRoofline, Install New ScrubberConverters 56 $276,300 Converter Aisle roofline reconfigured tocapture process fugitive emissions, ductworkadded to pass the captured emissions to anew wet scrubber, additional caustic receivingand distribution system capacity installed.Freeport-McMoRan Miami Inc.BART AnalysisMiami, ArizonaMarch 2014Page 3-25Table 3-1. Summary of Best Available Retrofit Technology Evaluations (continued)Control TechnologyBART-EligibleEmission UnitsEmissionReduction(tpy)CostEffectiveness($/ton)CommentsSO2Capture Process FugitiveEmissions at Electric FurnaceRoofline, Install New ScrubberElectric Furnace 35 $124,000 Electric Furnace roofline reconfigured tocapture process fugitive emissions, ductworkadded to pass the captured emissions to anew wet scrubber, additional caustic receivingand distribution system capacity installed.Increased Operation of ExistingAcid Plant Tail Gas ScrubberConverters andElectric Furnace< 31 $5,500 No capital investment; increased reagentpurchase and blowdown handling costs thatare linear with amount of SO2reduced.Limited to capacity of existing reagent andblowdown handling systems.Improve Capture of ProcessFugitive Emissions from ElectricFurnace Matte Tapping HoodElectric Furnace 1 $68,700 Select leakages in the existing vent fumesystem ductwork would be eliminated andactive control would be used to increaseventilation from the existing active mattetapping hoods; additional captured emissionscontrolled by existing Vent Fume Scrubber.NO2SCR at Acid Plant Tail GasStackConverters andElectric Furnace0.4 $1,375,600 SCR installed downstream of Acid Plant TailGas Scrubber. Aqueous ammonia storageand handling system installed. Reheat ofexhaust required which includes significantenergy and environmental impacts.Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 3-26 3.5 BART Determination

After identifying the level of control representing BART, an emission limit representing BART should be established for each BART-eligible emission unit and for each pollutant subject to review. However, a design, equipment, work practice, operational standard, or combination of such standards can be established in cases where technical or economic limitations exist in the application of measurement methods that make a conventional emission limit infeasible.

As noted previously, emissions from the Acid Plant Tail Gas Stack and Vent Fume Stack include commingled emissions from units subject to BART (i.e., the Electric Furnace and the Converters) and units not subject to BART (i.e., the Isa Furnace). Because a continuous emissions monitoring system (CEMS) cannot cont inuously differentiate BART-eligible emissions from those that are not, a convent ional emission limit is not techni cally feasible. Accordingly, the following work practice and operational standards are proposed as representing BART:

3.5.1 SO 2 Emissions, Acid Plant Tail Gas Stack

The recommended BART SO 2 emission limit is a work practice standard that requires the existing use of the Acid Plant, Acid Plant Tail Gas Scrubber, and Converter Mouth Covers to reduce SO 2 emissions. This equipment shall be maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions.

3.5.2 SO 2 Emissions, Vent Fume Stack

The recommended BART SO 2 emission limit is a work practice standard that requires the existing use of the Vent Fume Scrubber to reduce SO 2 emissions. This equipment shall be maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions.

3.5.3 NO X

Emissions

The recommended BART NO X emission limit is a work practice standard that requires the use of natural gas or propane to reduce NO X emissions. The burners associated with the Converters and Electric Furnace shall be operated in accordance with good combustion practices.Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

Page 4-1 4.0 REFERENCES

Chemical Engineering , 1996. Chemical Engineering Plant Cost Index, Chemical Engineering, October 1996.

Chemical Engineering , 2013. Chemical Engineering Plant Cost Index, Chemical Engineering, December 2013.

Partelpoeg, E.H., 2014. Miami Smelter Calculation Summary . January 23, 2014.

Peters, M.S., K. Timmerhaus, and R.E. West. 2002. Plant Design and Economics for Chemical Engineers, 5 th Edition, McGraw-Hill Professional, 2002, pp. 242-243.

Radian, 1991. Ammonium Sulfate and Bisulfate Formation in Air Preheaters , prepared for the USEPA Industrial Environmental Research Laboratory by Radian Corporation, 1991.

TRC, 1995. Class I Air Quality Permit Application for IsaSmelt ®

Modification Cyprus Miami Mining Corporation . October 26, 1995.

Trinity Consultants, 2013. Roofline Study . November 2013.

USEPA, 1998. Compilation of Air Pollutant Emission Factors, Volume I: Stationary Point and Area Sources; Section 1.4, Natural Gas Combustion , AP-42. U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina. July 1998.

USEPA, 2002. Air Pollution Control Cost Manual, 6th Ed. , EPA/452/B-02-001. U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina. January 2002.

USEPA, 2013. RACT/BACT/LAER Clearinghouse (RBLC). U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina. November 2013.Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

APPENDIX A

BART-Eligible Baseline Emissions CalculationsTableA‐1.BARTBaselineEmissionsCapturedSO2ControlledSO22011 2012 Average 2011 2012 Average ELF Converters ELF Converters ELF Converters Total (tpy) (tpy) ELF Converters Total ELF Converters TotalAcid	Plant	Tail	Stack 1,204 985 1,095 198 172 185 1% 31% 0.036% 0.92% 10.9339 350 4.38 10.9 344 355 0.1 1.7 1.8Vent	Fume	Stack 394 510 452 70% 316 316 316 316Smelter	Process	Fugitives 1,036 1,030 1,033 4% 53% 41.3 547 589 438 41.3 109 151Smelter	Combustion	Fugitives 46.6 48.5 47.6 1.6% 40.2%0.8 19.1 19.9TOTALS 2,634 2,525 2,579 245 221 233 369 887 1,255 369 453 822 0.9 20.8 21.7Notes:1.		Emission	unit	allocations	for	SO2	emissions	from	the	AcidPlant	Tail	Gas	Stack	are	from	calculations	performed	by	Dr.	Eric	Partelpoeg	(Partelpoeg,	2014).2.		Emission	unit	allocations	for	SO2	emissions	from	the	VentFume	Stack	are	from	calculations	performed	by	Dr.	Eric	Partelpoeg	(Partelpoeg,	2014).3.		Emission	unit	allocations	for	SO2	emissions	from	smelterfugitives	based	on	emissions	testing	performed	in	2012	(Trinity,	2013).4.		The	Converter	Mouth	Covers	are	expected	to	capture	80	percent	of	the	SO2	process	fugitive	emissions	during	blowing	operations.5.		Emission	unit	allocations	for	NOx	emissions	from	the	AcidPlant	Tail	Gas	Stack	assume	720	hours	per	year	of	Electric	Furnace	venting	of	natural	gas	combustion	emissions	and	100	hoursper	year	of	Converters	venting	of	natural	gas	combustion	emissions.6.		Emission	unit	allocations	for	NOx	emissions	from	smelterfugitives	are	based	on	natural	gas	usage	in	the	smelter	building.7.		The	normal	configuration	of	the	ELF	is	to	operate	with	electrodes.		Natural	gas	is	used	only	when	electrodes	break,	or	during	excessively	cold	weather.		The	ELF	had	no	actual	NOx	emissions	in	2011	or	2012.		The	last	year	in	which	the	ELF	usednatural	gas	was	2007,	and	the	NOx	emissions	presented	above	for	the	ELF	are	representative	of	that	year.BARTBaselineEmissionPointsSO2(tpy) NOx(tpy) SO2NOXSO2(tpy) NOx(tpy)AnnualActualEmissions EmissionUnitAllocations ConverterMouthCoverProjectMouthCoverProject(tpy)SO2EmissionsBeforeConverterFreeport‐McMoRan	Miami	Inc.Page	1	of	13/24/2014Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

APPENDIX B

Emission Reduction and Cost Effectiveness Calculations

Confidential Business InformationUPGRADE OF ACID PLANT TAIL GAS SCRUBBER Capital and Annual Costs

Source Parameters Baseline SO2 emission rate (tpy) 355 Baseline SO2 control efficiency Stack Test Result 71% Baseline scrubber operating hours 440 Baseline scrubber inlet SO2 loading (tpy) 368 SO2 control efficiency Control Efficiency per Hatch (1) 98% SO2 controlled (tpy) 361 SO2 emitted (tpy) 7.4 Baseline SO2 removed (tpy) 348 Operating schedule (hr/yr) 8,760 Item Factor Cost Capital Costs Total Equipment Cost Cost Estimate per Hatch (1) $6,134,000 Direct & Indirect Installation Costs Cost Estimate per Hatch (1) $5,496,000 Total Capital Investment (TCI) $11,630,000

Annual Costs Reagent Costs Cost Estimate per Hatch (1) $653,000 General Costs Cost Estimate per Hatch (1) $451,000 Equipment Life (2) 15 years Interest Rate (2) 7% Capital Recovery Factor 0.110 Capital Recovery $1,277,000
Total Annual Cost $2,381,000

SO2 Reduction (tpy) 348 Cost Effectiveness ($/ton controlled) $6,849

Reference Sources: (1) Control efficiency and cost estimates per Hatch 2014. Direct and indirect installation costs include construction distributables, indirects (EPCM cost,temporary construction facilities, etc.), owners cost and contingency. (2) Section 5, Table 1.3. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002 Table B-1

Freeport

‐ McMoRan Miami Inc. Confidential Business Information Page 1 of 9 3/26/2014UPGRADE OF VENT FUME SCRUBBER Capital and Annual Costs

Source Parameters Baseline SO2 emission rate (tpy) 316 Baseline SO2 control efficiency Stack Test Result 62% Baseline Scrubber inlet SO2 loading (tpy) 832 SO2 control efficiency Control Efficiency per Hatch (1) 98% SO2 controlled (tpy) 815 SO2 emitted (tpy) 16.6 Baseline SO2 removed (tpy) 299 Operating schedule (hr/yr) 8,760 Item Factor Cost Capital Costs Total Equipment Cost Cost Estimate per Hatch (1) $4,512,000 Direct & Indirect Installation Costs Cost Estimate per Hatch (1) $4,042,000 Total Capital Investment (TCI) $8,554,000

Annual Costs Reagent Costs Cost Estimate per Hatch (1) $663,000 General Costs Cost Estimate per Hatch (1) $332,000 Equipment Life (2) 15 years Interest Rate (2) 7% Capital Recovery Factor 0.110 Capital Recovery $939,000
Total Annual Cost $1,934,000

SO2 Reduction (tpy) 299 Cost Effectiveness ($/ton controlled) $6,460

Reference Sources: (1) Control efficiency and cost estimates per Hatch 2014. Direct and indirect installation costs include construction distributables, indirects (EPCM cost,temporary construction facilities, etc.), owners cost and contingency. (2) Section 5, Table 1.3. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002 Table B-2

Freeport

‐ McMoRan Miami Inc. Confidential Business Information Page 2 of 9 3/26/2014CONTINUOUS OPERATION OF ACID PLANT TAIL GAS SCRUBBER Capital and Annual Costs

Source Parameters Baseline SO2 emission rate (tpy) 355 Baseline SO2 control efficiency 71% Baseline scrubber operating hours 440 Baseline Scrubber inlet SO2 loading (tpy) 368 SO2 control efficiency Control Efficiency per Hatch (1) 80% SO2 controlled (tpy) 295 SO2 emitted (tpy) 74 Baseline SO2 removed (tpy) 281 Operating schedule (hr/yr) 8,760 Item Facto r Cos t Capital Costs Total Equipment Cost Cost Estimate per Hatch (1) $3,811,000 Direct & Indirect Installation Costs Cost Estimate per Hatch (1) $3,415,000 Total Capital Investment (TCI) $7,226,000

Annual Costs Reagent Costs Cost Estimate per Hatch (1) $1,272,000 General Costs Cost Estimate per Hatch (1) $280,000 Equipment Life (to be replaced in 2 years) 15 years Interest Rate (2) 7% Capital Recovery Factor 0.110 Capital Recovery $793,000
Total Annual Cost $2,345,000

SO2 Reduction (tpy) 281 Cost Effectiveness ($/ton controlled) $8,334
Reference Sources: (1) Control efficiency and cost estimates per Hatch 2014. Direct and indirect installation costs include construction distributables, indirects (EPCM cost,temporary construction facilities, etc.), owners cost and contingency. (2) Section 5, Table 1.3. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002 Table B-3

Freeport

‐ McMoRan Miami Inc. Confidential Business Information Page 3 of 9 3/26/2014UPGRADE OF ACID PLANT Capital and Annual Costs

Source Parameters Upgrade of Acid Plant Baseline SO2 emission rate (tpy) 355 Baseline SO2 control efficiency Stack Test Result 71% Baseline scrubber operating hours 440 Baseline scrubber inlet SO2 loading (tpy) 368 SO2 Loading Reduction due to Acid Plant Upgrade Control Efficiency per Hatch (1) 75% Future SO2 loading to scrubber (tpy) 92 Operating schedule (hr/yr) 8,760 Existing Acid Plant Tail Gas Scrubber SO2 control efficiency Control Efficiency per Hatch (1) 71% Baseline scrubber operating hours 440 SO2 emitted (tpy) 88.8 Operating schedule (hr/yr) 8,760 Item Factor Cost Capital Costs Total Equipment Cost Cost Estimate per Hatch (1) $60,573,000 Direct & Indirect Installation Costs Cost Estimate per Hatch (1) $54,265,000 Total Capital Investment (TCI) $114,838,000

Annual Costs Reagent Costs (negative; reduced scrubber loading) Cost Estimate per Hatch (1) -$1,404,000 General Costs Cost Estimate per Hatch (1) $4,455,000 Equipment Life 20 years Interest Rate (2) 7% Capital Recovery Factor 0.094 Capital Recovery $10,840,000
Total Annual Cost $13,891,000

SO2 Reduction (tpy) 266 Cost Effectiveness ($/ton controlled) $52,173

Reference Sources: (1) Control efficiency and cost estimates per Hatch 2014. Direct and indirect installation costs include construction distributables, indirects (EPCM cost,temporary construction facilities, etc.), owners cost and contingency. (2) Section 5, Table 1.3. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002 Table B-4

Freeport

‐ McMoRan Miami Inc. Confidential Business Information Page 4 of 9 3/26/2014Table B-5. Aisle Scrubber Calculations

Scrubber Outlet Conditions, Converter Aisle SO2 concentration at scrubber outlet 1 ppmv Exhaust Flow Rate 1,392,718 acfm Exhaust Temperature 70 °F Standard Temperature 68 °F Atmospheric Pressure 26.082 in Hg at 3500 feet elevation Standard Pressure 29.921 in Hg Exhaust Flow Rate 1,209,442 scfm SO2 emission rate 1.52 g/s SO2 emission rate 12.1 lb/hr SO2 emission rate 52.8 tpy

Scrubber Outlet Conditions, Electric Furnace SO2 concentration at scrubber outlet 1 ppmv Exhaust Flow Rate 164,619 acfm Exhaust Temperature 70 °F Standard Temperature 68 °F Atmospheric Pressure 26.082 in Hg at 3500 feet elevation Standard Pressure 29.921 in Hg Exhaust Flow Rate 142,956 scfm SO2 emission rate 0.18 g/s SO2 emission rate 1.4 lb/hr SO2 emission rate 6.2 tpy

Constants SO2 Molecular Weight 64.06 g/mol Molar Volume 24.055 l/mol at 20C (68F) Mass Conversion 453.5924 g/lb Mass Conversion 2,000 lb/ton Volume Conversion 28.317 l/ft3 Operating Hours 8,760 hr/yr

Freeport

‐ McMoRan Miami Inc. Confidential Business Information Page 5 of 9 3/26/2014CAPTURE PROCESS FUGITIVE EMISSIONS AT CONVERTER AISLE ROOFLINE WITH NEW SCRUBBER Capital and Annual Costs

Source Parameters Baseline SO2 emission rate (tpy) 109 Capture efficiency 85% Inlet SO2 loading (tpy) 92.7 Outlet SO2 concentration (ppm) Outlet concentration per Hatch (1) 1.0 Outlet SO2 emission rate (tpy) 52.8 SO2 control efficiency based on 1 ppm outlet and inlet loading 43.0% Operating schedule (hr/yr) 8,760 Item Factor Cost Capital Costs Total Equipment Cost Cost Estimate per Hatch (1) $54,247,000 Direct & Indirect Installation Costs Cost Estimate per Hatch (1) $48,598,000 Total Capital Investment (TCI) $102,845,000

Annual Costs Reagent Costs Cost Estimate per Hatch (1) $236,000 General Costs Cost Estimate per Hatch (1) $3,990,000 Equipment Life (2) 15 years Interest Rate (2) 7% Capital Recovery Factor 0.110 Capital Recovery $11,292,000
Total Annual Cost $15,518,000

SO2 Reduction (tpy) 56.2 Cost Effectiveness ($/ton controlled) $276,300

Reference Sources: (1) Control efficiency and cost estimates per Hatch 2014. Direct and indirect installation costs include construction distributables, indirects (EPCM cost,temporary construction facilities, etc.), owners cost and contingency. (2) Section 5, Table 1.3. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002 Table B-6

Freeport

‐ McMoRan Miami Inc. Confidential Business Information Page 6 of 9 3/26/2014CAPTURE PROCESS FUGITIVE EMISSIONS AT ELECTRIC FURNACE ROOFLINE WITH NEW SCRUBBER Capital and Annual Costs

Source Parameters Baseline SO2 emission rate (tpy) 41 Capture efficiency 85% Inlet SO2 loading (tpy) 34.9 Outlet SO2 concentration (ppm) Outlet concentration per Hatch (1) 1.0 Outlet SO2 emission rate (tpy) 6.2 SO2 control efficiency based on 1 ppm outlet and inlet loading 82.1% Operating schedule (hr/yr) 8,760 Item Factor Cost Capital Costs Total Equipment Cost Cost Estimate per Hatch (1) and Peters et al (2) $15,064,205 Direct & Indirect Installation Costs Cost Estimate per Hatch (1) and Peters et al (2) $13,495,497 Total Capital Investment (TCI) $28,559,702

Annual Costs Reagent Costs Cost Estimate per Hatch (1) and Peters et al (2) $65,536 General Costs Cost Estimate per Hatch (1) and Peters et al (2) $1,108,009 Equipment Life (3) 15 years Interest Rate (3) 7% Capital Recovery Factor 0.110 Capital Recovery $3,136,000
Total Annual Cost $4,309,546

SO2 Reduction (tpy) 34.8 Cost Effectiveness ($/ton controlled) $124,000

Reference Sources: (1) Control efficiency and cost estimates per Hatch 2014. Direct and indirect installation costs include construction distributables, indirects (EPCM cost,temporary construction facilities, etc.), owners cost and contingency. (2) Peters, M.S., K. Timmerhaus, and R.E. West. 2002. “Plant Design and Economics for Chemical Engineers, 5th Edition,” McGraw- Hill Professional, 2002, pp. 242-243. (3) Section 5, Table 1.3. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002 Table B-7

Freeport

‐ McMoRan Miami Inc. Confidential Business Information Page 7 of 9 3/26/2014INCREASED OPERATION OF ACID PLANT TAIL GAS SCRUBBER Capital and Annual Costs

Source Parameters Baseline SO2 emission rate (tpy) 355 Baseline SO2 control efficiency 71% Baseline scrubber operating hours 440 Baseline Scrubber inlet SO2 loading (tpy) 368 SO2 control efficiency Control Efficiency per Hatch (1) 80% SO2 controlled (tpy) 44 SO2 emitted (tpy) 324 Baseline SO2 removed (tpy) 31 Operating schedule (hr/yr) 1,300
Item Facto r Cos t Capital Costs Total Equipment Cost $0
Direct & Indirect Installation Costs $0 Total Capital Investment (TCI) $0

Annual Costs Reagent Costs Cost Estimate scaled from Hatch (1) $139,049 General Costs Cost Estimate scaled from Hatch (1) $30,608 Equipment Life (to be replaced in 2 years) 15 years Interest Rate (2) 7% Capital Recovery Factor 0.110 Capital Recovery $0
Total Annual Cost $169,657

SO2 Reduction (tpy) 31 Cost Effectiveness ($/ton controlled) $5,549

Reference Sources: (1) Control efficiency and cost estimates per Hatch 2014. Direct and indirect installation costs include construction distributables, indirects (EPCM cost,temporary construction facilities, etc.), owners cost and contingency. (2) Section 5, Table 1.3. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002 Table B-8

Freeport

‐ McMoRan Miami Inc. Confidential Business Information Page 8 of 9 3/26/2014IMPROVE CAPTURE OF PROCESS FUGITIVE EMISSIONS FROM ELECTRIC FURNACE MATTE TAPPING HOOD WITH EXISTING VENT FUME SCRUBBER Capital and Annual Costs

Source Parameters Additional Capture of Electric Furnace Emissions Baseline SO2 emission rate (tpy) 41 SO2 captured Capture per Hatch (1) 4% SO2 captured (tpy) 1.6 SO2 emitted (tpy) 39 Operating schedule (hr/yr) 8,760 Existing Vent Fume Scrubber Additional inlet SO2 emission rate (tpy) 1.6 SO2 control efficiency 62% Additional SO2 controlled (tpy) 1.0 Additional SO2 emitted (tpy) 0.6 Operating schedule (hr/yr) 8,760
Item Facto r Cos t Capital Costs Total Equipment Cost Cost Estimate per Hatch (1) $272,000 Direct & Indirect Installation Costs Cost Estimate per Hatch (1) $244,000 Total Capital Investment (TCI) $516,000

Annual Costs Reagent Costs Cost Estimate per Hatch (1) $900 General Costs Cost Estimate per Hatch (1) $20,000 Equipment Life (2) 20 years Interest Rate (2) 7% Capital Recovery Factor 0.094 Capital Recovery $49,000
Total Annual Cost $69,900

SO2 Reduction (tpy) 1.0 Cost Effectiveness ($/ton controlled) $68,700

Reference Sources: (1) Control efficiency and cost estimates per Hatch 2014. Direct and indirect installation costs include construction distributables, indirects (EPCM cost,temporary construction facilities, etc.), owners cost and contingency. (2) Section 5, Table 1.3. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002 Table B-9

Freeport

‐ McMoRan Miami Inc. Confidential Business Information Page 9 of 9 3/26/2014Table B-10. SCR CalculationsExhaust Flow Calculations - Standard ConditionsTGS Apr-11 Nov-11 May-12 Oct-12 VFS Apr-11 Nov-11 Jun-12 Oct-12Exhaust Flow Rate134,491dscfm Average of 4 stack test measurements, 2011-2012139,356 131,146 126,466 140,997 245,782Exhaust Moisture Content2.90%Average of 4 stack test measurements, 2011-2012, used VFS results to capture appropriate moisture content3.0% 2.4% 2.9% 3.3%Exhaust Flow Rate 138,390 wscfm Calculated139,640 131,940 127,360 142,420 252,898Exhaust Molecular Weight28.52g/mol Average of 4 stack test measurements, 2011-2012, used VFS results to capture appropriate moisture content 28.56 28.50 28.55 28.62 28.51 28.57 28.53 28.48ConstantsNOx Molecular Weight46.01g/mol as NO2NH3 Molecular Weight17.09g/molMolar Volume24.055l/mol at 20C (68F)Mass Conversion453.5924g/lbMass Conversion2,000lb/tonVolume Conversion28.317l/ft3Time Conversion60min/hrOperating Hours8,760hr/yrNOx Control CalculationsUncontrolled NOx Emission Rate 0.41 lb/hr Calculated BART-eligible emission rate (anticipated actual)Uncontrolled NOx Emission Rate1.8tpy BART-eligible emission rate (anticipated actual)Uncontrolled NOx Emission Rate 42.2 lb/hr Calculated total emission rate (anticipated actual)Uncontrolled NOx Emission Rate185tpy Total emission rate (anticipated actual)Uncontrolled NOx Concentration 0.427 ppmdv Calculated, BART-eligible fraction onlyNOx Control Efficiency80%SpecifiedControlled NOx Concentration 0.085 ppmdv Calculated, BART-eligible fraction onlyControlled NOx Emission Rate 0.082 lb/hr Calculated, BART-eligible fraction onlyControlled NOx Emission Rate 0.36 tpy Calculated, BART-eligible fraction onlyNOx Removed 1.4 tpy Calculated, BART-eligible fraction onlyReheat CalculationsSCR Inlet Flow 10,244 lb/min CalculatedSCR Inlet Density 0.074 lb/wscfm CalculatedInlet Temperature71°F Average of 4 stack test measurements, 2011-2012, used VFS results to capture appropriate moisture content 151.5 152.4 153.4 149.670.4 67.1 70.1 76.0SCR Temperature650°F EstimatedExhaust Flow Rate Prior to Reheat 139,124 acfm CalculatedSCR Exhaust Flow Rate 290,997 acfm CalculatedSCR Exhaust Density 0.035 lb/acfm CalculatedAir Heat Capacity0.24Btu/lb·°FSCR Heat Exchanger Recovery95%SpecifiedReheat Requirement 4.27 MMBtu/hr CalculatedReheat Requirement 37,406 MMBtu/yr CalculatedNatural Gas Heat Content1,020Btu/scf AP-42Natural Gas Density0.047lb/scfNatural Gas Mass Required 1,723,592 lb/yr CalculatedNatural Gas Mass Required 3.28 lb/min CalculatedNatural Gas Volume Required 36,672,173 scf/yr CalculatedNatural Gas Volume Required 25,466,786 scf/ton NOx removed CalculatedTotal Exhaust Rate to SCR 10,247 lb/min CalculatedElectricity Consumption CalculationsnNOx0.8Specified∆Pduct3inches water OAQPS Control Cost ManualnTotal6catalyst layers Calculated per OAQPS Control Cost Manual, Section 4, Equation 2.28∆Ptotal1inches water per layer OAQPS Control Cost ManualNatural Gas F-Factor10,610wscf/MMBtu EPA Method 19Equivalent Gas-Fired Boiler Size 783 MMBtu/hr CalculatedEquivalent Inlet NOx 0.05397 lb/MMBtu Calculated, total NOxPower Required 373.3 kW Calculated per OAQPS Control Cost Manual, Section 4, Equation 2.48Electricity Consumption 3,270,343 kW·hr/yr CalculatedElectricity Consumption 2,271,071 kW·hr/ton NOx removed CalculatedFreeport‐McMoRan Miami Inc.Confidential Business InformationPage 1 of 43/26/2014SCR SYSTEM Capital Costs

Source Parameters
SCR location Tail-end after scrubber Uncontrolled NOx emission rate (tpy) 1.80 SCR NOx control efficiency 80% SCR heat recovery 95% Operating schedule (hr/yr) 8,760 Actual flow rate (acfm) 290,997 Standard flow rate (scfm) 138,390 Inlet temperature (°F) 71 SCR temperature (°F) 650 Exhaust moisture content (% by volume) 2.90% Standard flow rate, dry (dscfm) 134,491 Ammonia Slip (assumed) (ppm) 10 Cost escalation factor (Aug. 2013 / Jun. 1996) 1.60
Item Facto r Cos t Equipment Costs Complete System SCR Equipment Cost Cost Quote per TRC (1) $2,234,500 Auxiliary Equipment All included $0 Cost Escalation to 2013 Dollars Reference (2) $1,337,800 Purchased Equipment Cost $3,572,300 Sales Taxes 0.03 x Purchased Equipment Cost (3) $107,200 Freight 0.05 x Purchased Equipment Cost (3) $178,600 Total Equipment Cost $3,858,100
Direct Installation Costs Foundation 0.08 x Total Equipment Cost (3) $308,600 Erection and Handling 0.14 x Total Equipment Cost (3) $540,100 Electrical 0.04 x Total Equipment Cost (3) $154,300 Piping 0.02 x Total Equipment Cost (3) $77,200 Insulation 0.01 x Total Equipment Cost (3) $38,600 Painting 0.01 x Total Equipment Cost (3) $38,600
Total Direct Installation Costs $1,157,400 Direct Capital Cost Total Equipment Cost + Direct Installation Costs $5,015,500
Indirect Installation Costs General Facilities 0.05 x Direct Capital Cost (3) $250,800 Engineering and Home Office Fees 0.1 x Direct Capital Cost (3) $501,600 Process Contingency 0.05 x Direct Capital Cost (3) $250,800
Total Indirect Installation Costs $1,003,200 Total Direct Capital and Indirect Installed Costs $6,018,700 Project Contingencies 0.15 of Total Direct and Indirect (3) $902,800
Total Plant Costs $6,921,500 Preproduction Costs 0.02 of Total Plant Costs (3) $138,400 Inventory Capital Initial ammonia charge (assumes 2 week supply) (3) $5,100 Total Capital Investment (TCI) $7,065,000

Reference Sources: (1) Cost quote of $2,234,500 per TRC 1996. (2) Chemical Engineering Plant Cost Index, Equipment: June 1996 = 427.1; August 2013 = 682.8; ratio = 682.8/427.1 = 1.60 (3) Section 4, Table 2.5. U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina, EPA/452/B-02-001, January, 2002 Table B-11

Freeport

‐ McMoRan Miami Inc. Confidential Business Information Page 2 of 4 3/26/2014SCR SYSTEM Annual Costs

Source Parameters
SCR location Tail-end after scrubber Uncontrolled NOx emission rate (tpy) 1.8 SCR NOx control efficiency 80% SCR heat recovery 95% Operating schedule (hr/yr) 8,760 Actual flow rate (acfm) 290,997 Standard flow rate (scfm) 138,390 Inlet temperature (°F) 71 SCR temperature (°F) 650 Exhaust moisture content (% by volume) 2.90% Flow rate (dscfm) 134,491 Ammonia Slip (assumed) (ppm) 10 Cost escalation factor (Aug. 2013 / Jun. 1996) 1.60 Cost Item Cost Factor Unit Cost Total Cost
Direct Annual Costs Maintenance OAQPS Section 4, Equation 2.46 (1) 0.015 of TCI $106,000 Replacement Parts Catalyst Volume OAQPS Section 4, Equation 2.28 (1) 5638 cu. ft. Estimated Catalyst Area OAQPS Section 4, Equation 2.25 (1) 303 sq. ft. Estimated Number of Catalyst Layers Estimate based on TRC (2) 6 Catalyst Life From TRC (2) 2 yrs Catalyst Cost Reference (3) $142 /cu. ft. Catalyst Replacement Cost $399,100 Reagent Comsumption (19.2% aqueous ammonia) OAQPS Section 4, Equation 2.32 and 2.33 (1) 85.6 lb/hr Aqueous ammonia costs 19.2% aqueous ammonia delivered (4) $355 /ton $133,000
Utilities Net BTU Reheat Requirement 37,406 MMBtu/yr Natural Gas Fuel Requirement 1020 Btu/scf (AP-42) 36,672,173 scf/yr Natural Gas Fuel Cost 2013 cost of natural gas to facility (5) $0.0050 /scf $182,900 Electricity Requirement OAQPS Section 4, Equation 2.48 (1) 3,270,343 kWhr/yr Electricity Cost 2013 cost of electricity to facility (5) $0.0643 /kWhr $210,300
Indirect Annual Cost Administrative Charges 2% TCI (1) $141,300 Property Taxes 1% TCI (1) $70,700 Insurance 1% TCI (1) $70,700 Equipment Life 20 yrs
Interest Rate 7% Capital Recovery Factor 0.094 Capital Recovery CRF x TCI (1) $666,900
Total Annual Cost $1,980,900 Uncontrolled NOx Emission Rate (tpy) 1.8 NOx Controlled (tpy) 1.4 NOx Emitted (tpy) 0.36 Cost Effectiveness ($/ton controlled) $1,375,600
Reference Sources: (1) U.S. EPA 2002. EPA Air Pollution Control Cost Manual, 6th Ed., Office of Air Quality Planning and Standards, Research Trian gle Park, North Carolina, EPA/452/B-02-001, January, 2002 (2) Vendor quote presented in TRC (1996) showed a pressure drop of 6"; OAPQS indicates 1" pressure drop per layer. (3) UARG 2010. (4) November 2009 benchmark ammonia cost from http://www.icis.com (5) December 2013 site costs. Table B-12

Freeport

‐ McMoRan Miami Inc. Confidential Business Information Page 3 of 4 3/26/2014Emission Annual Factor Emission Pollutant lb/MMscf tpy SO2 0.6 0.011 NOx 50 0.92 CO 84 1.54 PM 7.6 0.14 filterable + condensable VOC 5.5 0.101 CO2 120000 2200 Reheat Emissions Calculation Table B-13

Freeport

‐ McMoRan Miami Inc. Confidential Business Information Page 4 of 4 3/26/2014Freeport-McMoRan Miami Inc. BART Analysis Miami, Arizona March 2014

APPENDIX C

Eric Partelpoeg, PhD, Analysis of SO 2 Emissions Allocations

## Miami Smelter Calculation Summary

January 23, 2014

Prepared by:

Eric Partelpoeg, EHP Consulting Inc. 6038 N Camino Miraval Tucson AZ 85718

(520)615-4030 eric@ehp-consulting.com

### Miami Smelter Calculations January 23, 2014



### 1 

# EHP

Consulting, Inc. 1.0 PROJECT BA CKGRO UND

............................................................................................................ ............................... 2

2.0 EHP CONSULTING INC. RELEVANT EXPERIENCE ....................................................................................... ........ 3

3.0 SMELTER PROCESS GAS DISTRIBUTION .............................................................................................. ................ 4

4.0 ISA / ELF FUGITIVE GAS DISTRIBUTION ........................................................................................... .................... 6

4.1 R ELATIVE CONCENTRATION OF SO 2 IN M OLTEN S TREAMS ......................................................................................... 6

4.2 E XPOSED AREAS OF L AUNDER S YSTEMS ..................................................................................................................... 7

4.3 L AUNDER S YSTEM A CTIVITY

.............................................................................................................................. ........ 7

4.4 E STIMATION OF S OURCES OF ISA/ELF F UGITIVE E MISSIONS ..................................................................................... 7

### Miami Smelter Calculations January 23, 2014



### 2 

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Consulting, Inc. 1.0 PROJECT BACKGROUND



### Freeport McMoRan’s Miami Smelter is located 90 m iles east of Phoenix. Its major unit operations include:
1. An ISASMELT concentrate smelting vessel (referred to as ISA in this report).
2. An Electric furnace (referred as the ELF in this report) that receives the smelted product of the ISA. The smelted product separates into two phases in the ELF—a copper rich matte phase and an iron oxide rich slag phase.
3. Copper converters that process ELF matte to produce blister copper (that is further processed in anode furnaces to produce the smelter’s final product of anode copper). The converting process produces additional slag that is returned to the ELF to recover copper values which settle into ELF matte.
4. An acid plant that is an emissions control pl ant that produces sulfuric acid from sulfur dioxide (SO 2 

### ) generated in the ISA, th e ELF, and the converters.

The Miami Smelter has contracted with EHP Consulting, In c. to estimate:
1. The distribution of SO 2 

### sent to the acid plant from the ISA, ELF, and the converters.
2. The distribution of captured fugitive gases that is attributable to the ISA and the ELF.

This report documents these calculations.

### Miami Smelter Calculations January 23, 2014



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Consulting, Inc. 

### 2.0 EHP CONSULTING INC. RELEVANT EXPERIENCE
EHP Consulting, Inc. (referred to as EHP in this report) is an Arizona based corporation that provides consulting services to the world wide mining indus try. Its principal, Eric Partelpoeg, earned his doctorate in Metallurgical Engin eering in 1985 from the University of Arizona. Dr. Partelpoeg’s experience and expertise that is relevant to the tasks presented in this report include:

1. Expertise in smelter mass and heat bala nces (subject of Ph.D. dissertation) 2. Experience and expertise in acid plant operations. 3. Experience and expertise with the operation of copper smelters and the emission control equipment associated with smelters.

### Miami Smelter Calculations January 23, 2014



### 4 

# EHP

Consulting, Inc. 

### 3.0 SMELTER PROCESS GA S DISTRIBUTION
EHP reviewed Miami Smelter operating data fr om the period March 10, 2013 to April 9, 2013 to estimate the distribution of process gases within the Miami Smelter. This period was selected because it represented typical operating cond itions for the smelter and its acid plant (the data was provided to EHP as part of an effort to evaluate the perfor mance of the Miami acid plant—this evaluation is not included in this report).

The data evaluated to estimate the smelter process gas distribution are: 1. ISA feed rate (which averag ed 87 tph during this period). 2. ISA feed analysis (33.25% sulfur , 26.9% copper, and 28.8% iron). 3. ISA product (matte and slag) analyses (copper, iron, and sulfur) 4. ELF product (matte and slag) analyses (copper, iron and sulfur)

This data was used to: 1. Estimate SO 2 

### in ISA off-gas by subtracting the sulfur content of ISA matte and slag from the inlet sulfur content of ISA feed. 2. Estimate SO 2 

### in ELF off-gas by subtracting the sulfur content of ELF matte and slag from the ELF inputs (ISA matte and slag). While the ELF is primarily a settling furnace, there is some generation of SO 2 

### in the ELF, primarily from reactions th at occur between sulfur in matte and magnetite in slag (both the ISA slag and magnetite th at is contained in the converter slag that is returned to the ELF. This reaction is shown below:

FeS (a component of matte) 

### + 3 Fe 3 

### O 4 (a component of slag) 

### = 10 FeO (a component of slag) 

### + SO 2(evolved from bath)



### This reaction lowers the iron and sulfur conten t in matte which results in a higher copper concentration of ELF matte compared to the IS A matte that enters the ELF. For the data evaluated in this report; in let (ISA) matte grade was 56.8% copper and outlet (ELF) matte grade was 58.8% copper. Note that this reacti on does not likely occur at a continuous and even rate in the ELF—the reaction is promoted by mi xing of matte and slag which occurs primarily during periods when ISA products are transferred to the ELF or converter slag is returned to the ELF. During periods of quiescent settling of matte and slag, the rate of this reaction is lower. 3. Estimate overall sulfur and sulfur dioxide distri bution from the results of Items 1 and 2 above.

Table 3-1 and Table 3-2 summarize the results of these calculations. The first table shows overall sulfur distribution that includes th e sulfur locked up with ELF slag (that is stock-piled on the smelter property) and in the converters’ blister copper product. The sec ond table shows the sources of SO 2 

### reporting to the acid plant. Note that this distribut ion will vary to some extent based on feed sulfur concentration and the extent of react ions that occur in the ELF. In broad terms, the ISA contribution of SO 2 

### to the acid plant is likely to be in the range of 60-70%; converter contribution is likely in the range of 25-35% and ELF contribu tion is likely to be less 2%.

### Miami Smelter Calculations January 23, 2014



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### Table 3-1 Estimat e of Total Sulfur Distribution

Estimated Range of Distribution
Sulfur Output % of Input Low range High range ISA off

‐ gas 66.0% 60% 70%
ELF off

‐ gas 0.8% 0.1% 1.50%
Converter off

‐ gas 30.4% 26% 32%
ELF slag 2.7% 2.00% 3%
Blister Copper 0.1% 0.05% 0.15%
100%



### Table 3-2 Estimate of Sulfur Di oxide Sources to Acid Plant

Percentage to Acid Plant
ISA 68%
Converters 31%
ELF off

‐ gas 1%
100%

### Miami Smelter Calculations January 23, 2014



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# EHP

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### 4.0 ISA / ELF FUGITIVE GAS DISTRIBUTION
ISA smelting vessel fugitive gases and ELF fugitive gases are collected in a common ducting system and scrubbed. These fugitive gases are captured from the following sources:

1. From the launders from which molten ISA vessel products flow to the ELF. 2. From the launders from which ELF matte flows to the matte ladle (this includes emissions captured from the ladle area). 3. From the launders from which ELF slag flows to the slag ladle (this includes emissions captured from the ladle area).

The amount of sulfur dioxide (SO 2 

### ) released from these sources depends on:

1. The concentration of SO 2 

### in the molten flow stream. The SO 2 

### dissolved in the molten stream is largely dependent on the SO 2 

### concentration in the furnace from which the stream originates. 2. The exposed area in the launders from which SO 2 

### can evolve from the molten stream to the atmosphere. 3. The amount of time that the molten stream flow s through the launders (ta pping the furnaces is not a continuous process).

These three factors were used to estimate the source of SO 2 

### scrubbed from the ISA vessel and ELF.

4.1 RELATIVE CONCENTRATION OF SO 2 

### IN MOLTEN STREAMS
The ISA smelting vessel operates with oxygen enrichment and is the major source of SO 2 

### that is processed in the acid plant. The SO 2 

### concentration in the ISA vessel is in the order of twenty volume per cent (20%). This contrasts significantly with the conditions of the ELF. This furnace’s primary duty is to separate the matte and slag solutions that enter it from the ISA vessel. The ELF also receives slag from the converters. This converter sl ag contains copper values that are recovered in the ELF (the copper values settle to the matte phase). The ELF off-gases have been measured in the past. The SO 2 

### concentration has always been lower th an 1% (typically less than 0.25%).

Due to the significant difference between the SO 2 

### concentrations in these furnaces, the amount of SO 2 

### dissolved in these gases (and subjec t to release as fugitiv e gases upon leaving the furnaces) is expected to be different. The solubility of SO 2 

### in molten metals (in particular copper) was studied in the first half of the 20 th 

### century. Both Scaff and Schumaher (“So me Theoretical and Practical Aspects of Gases in Metals”, Metals and Alloys, January 1933) and Floe and Chipman (“Solubility of Sulphur Dioxide in Molten Copper, Februa ry 1941 AIME meeting) conclude that the solubility of SO 2 

### is proportional to the (1/2.5) root of the furnace SO 2 

### pressure (i.e. between a sq uare root and cube root relationship).

Based on this relationship, the dissolved level of SO 2 

### in the ISA molten bath can be expected to be approximately four times higher than the molten bath in the ELF (see Table 4-1).

### Miami Smelter Calculations January 23, 2014



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### Table 4-1 Relative Concentration of Dissolved SO 2 

### in ISA and ELF Molten Solutions

Volume % SO 2 Root of (1/2.5)

ISA 20% 0.53
ELF 0.65% 0.13



### 4.2 EXPOSED AREAS OF LAUNDER SYSTEMS

The exposed area of furnace tapping systems is summarized below.

1. ISA tapping launder: The portion of this launder system that are subject to fugitive emissions (and their subsequent capture and treatment) is limited to a length of 16 feet with a width of approximately 15 inches (for a total of 20 square feet). 2. The ELF matte launder length is 17 feet long and approximately 15 inches wide. In addition to this area, the freefall stream of matte to the la under is a source of fugitive emissions as well as the surface area of matte that coll ects in the launder. EHP has estimated the total area to be approximately 106 square feet. 3. The ELF slag launder system is very similar to the matte system. Total area is also slightly more than 100 square feet.

4.3 LAUNDER SYSTEM ACTIVITY
The Miami Smelter provided EHP and estimate fo r the duration that tapping and skimming systems are active (i.e. molten material is flowing through the system). Based on the Miami data (which was provided as minutes per ladle), EH P has estimated that the ISA ta pping system was active for 1500 hours in 2013. The ELF matte tapping system was estimated to be active for approximately 1900 hours and the ELF slag tapping system was estima ted to be active for approximately 1100 hours in 2013.

4.4 ESTIMATION OF SOURCES OF IS A/ELF FUGITIVE EMISSIONS

The estimates for relative SO 2 

### concentration, exposed areas for em issions, and the active time that each tapping system was active results in the follo wing estimate of the source of captured ISA and ELF fugitive emissions:

 Fugitive emissions associated with ISA activit ies are estimated to account for 30% of the SO 2 

### entering the fugitive emission scrubbing system.

 The balance (70%) of fugitive emissions is li nked to ELF matte and slag tapping activities.

Note that there are other variables that could be incorporated into a study of this subject (i.e. the temperature effect on SO 2 

### solubility, the effect of turbulence of the ladles when matte and slag is

### Miami Smelter Calculations January 23, 2014



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Consulting, Inc. 

### pouring into them, etc.). EHP believes that th e calculated distribution cited above reasonably represents the split of the sources of SO 2 

### to the fugitive gas scrubber system.