November 2014

Economic Analysis: Proposed 

Revisions to the Health and 

Environmental Protection 

Standards for Uranium and 

Thorium Mill Tailings Rule

(40 CFR Part 192)

Draft Report

U.S. Environmental Protection Agency

Office of Radiation and Indoor Air

Radiation Protection Division 

1200 Pennsylvania Avenue

Washington, DC 20460

EPA 402-R-14-003
_________________________________

RTI International is a trade name of Research Triangle Institute.

RTI Project Number

0212979.003.017

Economic Analysis: Proposed 

Revisions to the Health and 

Environmental Protection 

Standards for Uranium and 

Thorium Mill Tailings Rule

(40 CFR Part 192)

November 2014

Draft Report

Valentine (Val) T. Anoma

U.S. Environmental Protection Agency

Office of Radiation and Indoor Air

1200 Pennsylvania Avenue

Washington, DC 20460

Prepared by

RTI International

3040 E. Cornwallis Road

Research Triangle Park, NC 27709
iii

CONTENTS

Section Page

1 Introduction................................................................................................................... 1-1

1.1 Background for the Proposed Rule ...................................................................... 1-1

1.2 Statement of Need for Policy Action ................................................................... 1-2

1.2.1 Protection of Human Health and the Environment.................................. 1-2

1.2.2 Need for Regulatory Intervention Because of Market Failure................. 1-2

1.3 Organization of the Report................................................................................... 1-3

2 Profile of the Affected Industry: Uranium Extraction and Processing ......................... 2-1

2.1 Introduction.......................................................................................................... 2-1

2.1.1 Uranium Extraction and Processing Sector, NAICS 212291 .................. 2-1

2.1.2 Uranium Shipments ................................................................................. 2-2

2.2 Supply of Uranium............................................................................................... 2-2

2.2.1 Production Process................................................................................... 2-5

2.2.2 Inputs Used in ISR Uranium Production ................................................. 2-8

2.2.3 Production Costs...................................................................................... 2-8

2.2.4 Pollution Control...................................................................................... 2-9

2.3 Demand for Uranium ......................................................................................... 2-10

2.3.1 Characteristics of the Product (Yellowcake) ......................................... 2-10

2.3.2 Uses and Consumers.............................................................................. 2-11

2.3.3 Substitutes.............................................................................................. 2-12

2.4 Industry Organization ........................................................................................ 2-12

2.4.1 Market Structure .................................................................................... 2-12

2.4.2 Small Businesses.................................................................................... 2-14

2.5 Market for U3O8 ................................................................................................. 2-15

2.5.1 U.S. Consumption.................................................................................. 2-15

2.5.2 U.S. Uranium Production....................................................................... 2-17

2.5.3 International Trade................................................................................. 2-19
iv

2.5.4 Market Prices......................................................................................... 2-21

2.5.5 Industry Trends...................................................................................... 2-22

2.5.6 Projections.............................................................................................. 2-22

3 The Proposed Rule and its Estimated Costs ................................................................. 3-1

3.1 Description of Proposed Regulation .................................................................... 3-1

3.1.1 Groundwater Protection Standards.......................................................... 3-1

3.1.2 Monitoring Requirements........................................................................ 3-2

3.1.3 Other Regulatory Alternatives for Long-Term Monitoring 

Considered but Rejected .......................................................................... 3-5

3.2 Estimated Incremental Costs of Compliance with Proposed Rule ...................... 3-6

3.2.1 Technical Approach: Conceptual Site Model Facility............................. 3-7

3.3 Estimated National Costs of Proposed Rule ...................................................... 3-24

3.4 Uncertainties and Limitations............................................................................ 3-27

4 Benefits Analysis .......................................................................................................... 4-1

4.1 Conceptual Framework and Methods for Valuing Groundwater Resources 

and Groundwater Protection ................................................................................ 4-1

4.2 The Benefits of Proposed Changes in Monitoring Requirements ....................... 4-4

4.2.1 Reducing Potential Human Health Risks Associated with 

Contaminant Exposures........................................................................... 4-5

4.2.2 Protecting Groundwater Resources for Future Generations.................... 4-6

4.2.3 Avoiding Potential Future Remediation Costs ........................................ 4-7

4.3 Setting Groundwater Protective Standards........................................................ 4-10

4.4 Comparison of Benefits and Costs of the Proposed Rule .................................. 4-11

4.5 Caveats and Uncertainties.................................................................................. 4-11

5 Economic Impact Analysis ........................................................................................... 5-1

5.1 National Costs...................................................................................................... 5-1

5.2 Market Impact Assessment.................................................................................. 5-3

5.2.1 Market Simulation Model........................................................................ 5-3
v

5.2.2 Characteristics of Market Demand for Uranium ..................................... 5-5

5.2.3 Characteristics of Market Supply............................................................. 5-5

5.2.4 Impacts of the Proposed Rule .................................................................. 5-6

5.3 Summary of Economic Impact Results................................................................ 5-6

5.4 Employment Impacts of the Proposed Rule......................................................... 5-7

5.5 Impacts on Small Entities .................................................................................... 5-8

5.6 Uncertainties...................................................................................................... 5-11

6 Statutory and Executive Order Reviews....................................................................... 6-1

6.1 Synopsis............................................................................................................... 6-1

6.2 Executive Order 12866: Regulatory Planning and Review and Executive 

Order 13563: Improving Regulation and Regulatory Review ............................. 6-1

6.3 Paperwork Reduction Act.................................................................................... 6-4

6.4 Regulatory Flexibility Act ................................................................................... 6-4

6.5 Unfunded Mandates Reform Act (UMRA) ......................................................... 6-6

6.6 Executive Order 13132: Federalism .................................................................... 6-6

6.7 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments........................................................................................................ 6-6

6.8 Executive Order 13045: Protection of Children from Environmental 

Health Risks and Safety Risks............................................................................. 6-6

6.9 Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution or Use .................................... 6-7

6.10 National Technology Transfer and Advancement Act ........................................ 6-7

6.11 Executive Order 12898: Federal Actions to Address Environmental Justice 

in Minority Populations and Low-Income Populations....................................... 6-8

7 Conclusions................................................................................................................... 7-1

References..................................................................................................................................1
vi

Appendixes

A Unit Costs for Wells and Borings................................................................................ A-1

B Summary of Unit Costs for Sampling and Analysis.....................................................B-1

C Simulation of Remobilized Uranium from a Restored ISR Mine.................................C-1

D Sensitivity Analysis: Estimated Costs and Economic Impacts.................................... D-1
vii

LIST OF FIGURES

Number Page

2-1 Diagram of ISR Uranium Operation............................................................................. 2-6

2-2 Schematic Diagram of a Wellfield Showing Typical Injection/Production Well 

Patterns, Monitoring Wells, Manifold Buildings, and Pipelines.................................. 2-7

2-3 Location of ISR Uranium Production......................................................................... 2-18

3-1 ISL/ISR Conceptual Site Model Applicable to Current Practice and 30-Year 

Monitoring .................................................................................................................... 3-8

3-2 ISL/ISR Conceptual Site Model Applicable to Geochemical Modeling Scenario....... 3-9

4-1 Main Components of the Total Economic Value (TEV) of Groundwater

Resources...................................................................................................................... 4-2

5-1 Market Equilibrium Without and With Regulations..................................................... 5-4
viii

LIST OF TABLES

Number Page

2-1 U.S. U3O8 Shipments (Million Pounds)........................................................................ 2-3

2-2 Total U.S. Amount of U3O8 Produced (Million Pounds U3O8).................................... 2-4

2-3 Domestic Uranium Industry Production Expenditures ($Million) ............................. 2-11

2-4 Owner Companies for ISR Facilities: Existing and Planned...................................... 2-14

2-5 Uranium Purchased by U.S. COOs, 1994–2013 (Million Pounds U3O8

Equivalent).................................................................................................................. 2-16

2-6 Total Amount U3O8 Produced in the United States (Thousand Pounds U3O8) .......... 2-17

2-7 In situ Recovery Plants in the United States, and Status (2013)................................. 2-19

2-8 Weighted-Average Price of Uranium Purchased by U.S. COOs Based on 

Contract Type.............................................................................................................. 2-21

3-1 1 to Subpart F of Part 192—Maximum Concentration of Constituents for 

Groundwater Protection at ISR Facility Sites............................................................... 3-2

3-2 ISR Conceptual Mine Unit: Current Practice ............................................................. 3-12

3-3 ISR Conceptual Mine Unit: 30-Year Stability Shortened with Geochemical 

Modeling..................................................................................................................... 3-14

3-4 ISR Conceptual Mine Unit: 30-Year Stability with No Provision to Shorten............ 3-17

3-5 ISR Conceptual Mine Unit: Annual Monitoring Cost by Scenario and Phase 

(Thousand $2011)....................................................................................................... 3-21

3-6 ISR Conceptual Mine Unit: Annualized Monitoring and Capital Costs for 

Current Practice and Each Regulatory Scenario (Thousand $2011) .......................... 3-23

3-7 Estimated Total Acreage of All Wellfields at ISR Sites............................................. 3-25

3-8 Total Average Annualized Incremental Costs for Individual ISR Operations 

(Thousand 2011$)....................................................................................................... 3-26

3-9 Estimated Average National Incremental Cost Summary (Thousand 2011$)............ 3-27

3-10 Incremental Total Capital Costs (Thousand 2011$)................................................... 3-27

4-1 Summary of Avoided Remediation Cost Estimates for Model Facility with Postrestoration Groundwater Contamination (million 2011 $) ......................................... 4-10

5-1 Projected U.S. Uranium Market Conditions, 2015....................................................... 5-3

5-2 Market Impacts of Proposed Rule based on Average Costs, 2014............................... 5-7

5-3 Estimated Impacts of the Proposed Rule on Small Entities.......................................... 5-9

7-1 Comparison of Costs of Complying with the Proposed Rule and Costs of 

Remediating Contaminated Groundwater (Million 2011$).......................................... 7-4
ES-1

EXECUTIVE SUMMARY

Section 206 of the Uranium Mill Tailings Radiation Control Act of 1978 (UMTRCA) 

requires the U.S. Environmental Protection Agency (EPA) to develop health and environmental 

standards for both Title 1 sites (inactive uranium mills) administered by the U.S. Department of 

Energy and Title II sites (present and future operations) licensed by the U.S. Nuclear Regulatory

Commission (NRC) or its Agreement States. EPA is proposing revisions to its regulations at 40 

CFR Part 192 for in situ recovery/in situ leaching (ISR) facilities that produce uranium by

injecting and extracting a solution that dissolves the uranium from the porous minerals in which 

it is found. ISR uranium production represents an increasing share of uranium production and 

poses special groundwater protection challenges compared with conventional uranium 

production abroad and particularly in the United States, because it solubilizes and mobilizes 

uranium and other constituents and changes the geochemistry within the aquifer containing the 

uranium deposit. If geochemistry and groundwater conditions are not restored after ISR 

operations cease and the restoration is not stable over time, the groundwater in aquifers 

surrounding the wellfield may become contaminated with uranium and other constituents. 

Currently, facilities monitor groundwater for only a year or two after the restoration effort is 

complete before decommissioning the site. This duration of monitoring may not be long enough 

to detect instability or trends in constituent concentrations over time, which poses a risk of 

contaminating groundwater resources and potentially exposing human or ecological receptors to 

hazardous constituents. Accordingly, EPA is proposing to add a new subpart to 40 CFR Part 192, 

establishing additional monitoring requirements during all phases at an ISR facility:

■ Pre-operational monitoring: measuring background groundwater concentrations and 

establishing initial regulatory approved restoration goals

■ Operational monitoring: monitoring to detect any excursions of contaminated 

groundwater to adjacent aquifers, either beside, above, or below the exempted aquifer

■ Restoration monitoring: monitoring to document the progress of restoration through 

groundwater sampling

■ Post-restoration stability monitoring, which has two parts:

– Stability monitoring: monitoring, conducted after restoration efforts have ended to 

establish that wellfield groundwater characteristics are stable and meet restoration 

goals (at least 3 years) 

– Long-term stability monitoring: monitoring and statistical analyses to show that 

the concentration of each monitored constituent is not increasing with time and 

that the concentration is not statistically different from the restoration goals
ES-2

EPA’s proposed rule requires careful pre-operational monitoring to ensure that 

restoration goals are set appropriately, taking into account seasonal and other variability in 

analyte concentrations. The proposed rule also identifies the minimum 13 constituents that 

should be monitored and causes the standards to update automatically if standards under the Safe 

Drinking Water Act or the Resource Conservation and Recovery Act are updated.

1 Probably the 

most significant requirements in the proposed rule pertain to post-restoration stability

monitoring. As noted above, currently ISR facilities monitor groundwater for periods of 6

months to 2 years before beginning the decommissioning process. EPA’s proposed rule requires 

stability monitoring sufficient to demonstrate statistically with 95% confidence that wellfield 

conditions are stable and then continued long-term stability monitoring for 30 years, with 

provisions for shortening the monitoring duration based on geochemical modeling. EPA is 

proposing a provision that would allow the regulatory agency to shorten the monitoring period if 

the operator can both demonstrate geochemical stability through monitoring and support a 

conclusion of long-term stability through geochemical modeling. Geochemical modeling has the 

potential to provide confidence that a geochemical mechanism exists to prevent uranium and 

other constituents from remobilizing and migrating to aquifer locations that may be used for 

drinking water and, thus, provides additional assurance beyond that provided by longer 

monitoring periods and statistical modeling. Throughout this document, EPA uses the term 

“proposed rule” to refer to this set of monitoring requirements, along with other requirements 

such as corrective action in the event that an excursion is detected and more comprehensive 

monitoring at the preoperational phase. EPA also considered two other regulatory options for 

long-term stability monitoring:

■ 30 years of long-term stability monitoring with no potential to change the duration 

■ a narrative standard with no fixed monitoring period

EPA chose to propose the standard that includes geochemical modeling because it has the 

potential to demonstrate that groundwater conditions will remain stable; the other two 

alternatives do not. Because the uranium deposits for which ISR methods are appropriate were 

created initially due to chemically reducing geological conditions, EPA considers it likely that 

many ISR facilities will be able to demonstrate, through geochemical modeling and monitoring, 

the existence of geochemical conditions that would promote long-term stability. However, EPA 

 

1 Once an ISR facility is licensed and permitted, standards existing at the time of licensing are applied to the facility, 

but new license applications would be subject to the updated standards.
ES-3

recognizes that in some cases, sampling and geochemical modeling will reveal that geological 

conditions would not guarantee long-term stability. In those cases, the regulatory agency may

refuse to grant a license to conduct ISR operations; alternatively, the regulatory agency would 

likely require additional restoration and/or a 30-year monitoring period to demonstrate that 

conditions are stable. EPA estimated the costs that would be incurred should the owner/operator 

be required to monitor for 30 years in addition to conducting geochemical analyses.2

EPA examined the costs that could be incurred by ISR facilities to comply with two 

regulatory options, the proposed rule and the option characterized by 30 years of long-term 

stability monitoring with no potential to shorten the duration, under a variety of costing scenarios 

(see Appendix D for details on the range of costs). In addition, EPA estimated costs for a “worst 

case” scenario, under which post-operational geochemical modeling does not provide assurance 

that conditions would remain stable over time; in this case, EPA assumes that the facility would 

be required to continue long-term stability monitoring for 30 years to ensure that conditions 

remain stable. For reasons explained in Section 3, however, EPA believes this situation would be 

unlikely to arise; thus, the impacts of this third scenario are presented only in Appendix D. EPA 

did not estimate costs for the narrative standard with no fixed monitoring period because the 

specific compliance requirements and costs would be defined on a case-by-case basis and are,

thus, too uncertain to model. 

To estimate the incremental costs of compliance under each option considered, EPA used 

a model facility approach and developed a conceptual mine unit (CMU) derived from a section 

of one wellfield at an existing ISR facility. EPA then estimated the monitoring that such a mine 

unit would undertake under current practice and under each of the regulatory alternatives. The 

incremental costs for the CMU (computed as the costs under a regulatory alternative minus the 

costs under current practice) were then scaled up to costs that would be incurred by actual ISR 

facilities based on relative total acreage of wellfields at actual facilities to the acreage of the 

CMU. Total annualized costs for each regulatory option and cost scenario considered, annualized 

at 7%, are shown in Table ES-1. EPA presents low, average, and high monitoring cost estimates 

 

2

In tables such as ES-1 and throughout this report, the regulatory alternatives are described in terms of the required 

long-term stability monitoring; in fact, EPA expects that compliance requirements of the preoperational, 

operational, restoration, and stability monitoring may differ among the alternatives as well. The long-term 

stability monitoring requirements are used as a shorthand description of the regulatory alternative. The assumed 

requirements of each alternative are described in detail, along with the baseline regulatory requirements typically 

in practice at ISR facilities in the absence of the rule, and are presented in Tables 3-1 through 3-4, and the 

estimated costs under each alternative for the CMU are shown in Table 3-5.
ES-4

for each regulatory alternative. EPA computed estimated facility costs as if all wellfield acreage 

at ISR facilities in the country were simultaneously affected. EPA recognizes the fact that at 

many ISR facilities, there are wellfields in all stages of ISR operations from planning to 

decommissioned, so monitoring activities would not typically be required at every wellfield 

simultaneously. Thus, EPA’s costs are believed to overestimate costs that would be incurred by 

actual facilities. Further, EPA’s analysis defines these costs as incremental to the costs of current 

practice at ISR facilities; because many of the compliance requirements may already be 

embodied in license requirements, this may overestimate the incremental costs of the rule. 

However, EPA has chosen to analyze the costs and economic impacts under these conservatively 

high costing assumptions. As shown in Table ES-1, EPA estimates that nationally the cost of the 

proposed regulatory alternative ranges from $11.6 million to $17.9 million per year, depending 

on the cost scenario.

Table ES-1. Estimated Range of National Compliance Costs by Regulatory Alternative and 

Costing Scenario (Million 2011$)

Regulatory Alternative Low Average High

30 years with geochemical modeling to shorten 11.631 13.465 15.226

30 years with no shortening 12.865 15.072 17.901

EPA then examined the potential impact of the proposed rule on the market for uranium. 

Uranium is relatively homogeneous, so buyers do not care which mine or ISR facility produced 

it; the market for uranium is an international market, with suppliers and demanders in many 

countries. The United States has historically been the largest user of uranium for electricity

production but has generally produced only a small share of the uranium it consumes, and 

foreign suppliers have provided the remaining 80% to 90%. Going forward, the U.S. Energy

Information Administration (EIA) projects that the worldwide demand for uranium will grow 

substantially over the next 20 years, due largely to increased demand from China and India; 

prices are also projected to increase to approximately $64 per pound U3O8 by 2018. Owners and 

operators of U.S. civilian nuclear power reactors (“civilian owner/operators” or “COOs”) 

purchased a total of 57.4 million pounds of uranium during 2013 at a weighted-average price of 

$51.99 per pound U3O8. Seventeen percent of the U3O8 delivered in 2013 was U.S.-origin 

uranium at a weighted-average price of $56.3 per pound (EIA, 2014b). EPA projects the 2015 

U.S. price of uranium will be $57.00.
ES-5

The proposed rule would increase the cost of producing uranium at ISR facilities by

between $1.30 and $2.00 per pound, depending on the alternative and whether low, average, or 

high costs of compliance are considered. Because domestically produced uranium is a small 

share of the total U.S. supply (about 17% in 2013) and ISR operations are not the only suppliers 

of domestic uranium, ISR facility operators would have only a limited ability to pass these costs 

along to their customers. As a result, EPA estimates that the price of uranium is likely to increase 

by between $0.21 and $0.32 per pound as a result of the proposed rule.

EPA estimated the impact of the proposed rule on the market for uranium using a 

simplified model of the U.S. market for uranium in 2015, the base effective date for the proposed 

rule. The model estimated, based on the unit cost of the proposed rule and characteristics of the 

supply and demand for uranium in the United States, changes in the quantity of uranium 

purchased by U.S. COOs of nuclear power plants, changes in the domestic sales of uranium and 

imports, and changes in the market price for uranium. EPA found that overall the market 

quantity of uranium purchased for use in electric generation would decline by less than 0.1% and 

the market price would increase by approximately 0.5%. Domestic ISR facilities would decrease 

their production by approximately 3% to 6%, and imports of uranium would increase by less 

than 1%. Because the cost of uranium is a very small share of the cost of electricity, EPA 

estimates that the cost of generating electricity would increase by less than 0.1%. Table ES-2 

summarizes the estimated market impacts based on the unit cost of the proposed rule under lowcost and higher cost sets of assumptions. As expected, the low-cost assumptions have a smaller 

impact on the market for uranium than the average-cost assumptions, while the high-cost 

assumptions have a greater effect on the market.

Although the national total annual cost of the proposed rule (approximately $13.5 million 

to $15.1 million based on average costs) is well below the $100 million threshold that is one of 

the criteria used to identify a significant regulatory action, the industry has only a small number 

of companies operating a small number of ISR operations. EPA used existing ISR operations and 

the companies that own them as models for the types of facilities and companies that would 

potentially be affected by the proposed rule. EPA thus estimated the ISR facilities would incur 

annual costs of compliance between $262,000 and $12.7 million, depending on the scale of the 

operation, the alternative, and the costing assumption used. For small firms owning ISR 

facilities, EPA estimated cost-to-sales ratios between 0.6% and 2.2%, which would likely not be 

significant based on the criteria for significance in EPA’s final Regulatory Flexibility Act

(RFA)/Small Business Regulatory Enforcement Fairness Act (SBREFA) guidance (EPA, 2006). 

Because EPA estimates that compliance costs would not cause a significant impact and because 
ES-6

only a few small businesses (10 or fewer, based on current information) would be affected by the 

proposed rule, EPA concluded that the rule would not have a significant impact on a substantial 

number of small entities.

Table ES-2. Estimated Impacts on the U.S. Market for Uranium, 2014a

Baseline With Proposed Rule

Low Average High

Supply (million pounds) 57,630 57,616 57,614 57,612

U.S. origin 9,451 9,089 9,032 8,977 

Foreign origin 48,179 48,527 48,582 48,635

Price $57.00 57.21 57.24 57.27

Change in price $ 0.21 $ 0.24 $ 0.27

Percentage changes

Market quantity -0.02% -0.03% -0.03%

U.S. origin -3.8% -4.4% -5.0%

Foreign origin 0.7% 0.8% 0.9%

Price 0.4% 0.4% 0.5%

Incremental cost per pound of uranium $1.30 $1.50 $1.70

aCosts and economic impacts are based on the proposed rule (30-year stability with geochemical modeling to 

shorten), and low, average, and high monitoring cost estimates. Market impacts based on other costing 

assumptions are provided in Appendix D.

EPA’s qualitative benefits assessment presents a discussion of the expected effects of the 

proposed rule on human and environmental health. EPA expects that the improved monitoring 

program proposed will reduce the risk of contaminating valuable groundwater resources, thus 

also reducing potential exposure to radiological and nonradiological contaminants in 

groundwater and potentially in surface water to which affected aquifers discharge. Because the 

major risk of exposure to radiological constituents is cancer, the proposed rule has the potential 

to reduce cancer risks.

If uranium and other constituents remobilize in groundwater over time, and if monitoring 

ends too soon and sites are prematurely decommissioned, it is possible that groundwater in 

surrounding aquifers could be contaminated, and it might be many years before the 

contamination is detected. EPA simulated groundwater contamination using its CMU model 

facility under varying assumptions and estimated the costs of corrective action to remediate the 

groundwater contamination. Based on these simulations, the cost of remediation would far 
ES-7

exceed the costs of complying with the proposed rule, both on an annual and total basis. For the 

model facility simulations, this subset of benefits (avoided remediation costs) exceeded the costs 

of complying with the proposed rule. Further, if contamination were detected after 

decommissioning, the costs of remediation could be borne by the taxpayer or the land owner

rather than the uranium company owner/operator (if, for example, the company no longer exists 

or so much time has passed that the association is not made between the contamination and the

former ISR operation). EPA was unable, however, to estimate potential avoided costs of 

remediation on a national scale and thus was unable to quantify the rule’s net benefits 

nationwide.
1-1

Section 1

INTRODUCTION

1.1 Background for the Proposed Rule

In accordance with Section 206 of the Uranium Mill Tailings Radiation Control Act of 

1978 (UMTRCA) Section 206, the U.S. Environmental Protection Agency (EPA) is authorized 

to develop generally applicable standards for the protection of public health, safety, and the 

environment from radiological and nonradiological hazards associated with the processing, 

possession, transfer, and disposal of by-product material (tailings or wastes) at sites where ores 

are processed primarily for their uranium content. In 1983, EPA promulgated regulations at 40 

CFR Part 192, Health and Environmental Protection Standards for Uranium and Thorium Mill 

Tailings, in response to the statutory requirements of UMTRCA. When the Agency promulgated 

40 CFR Part 192, uranium recovery from ore was based almost exclusively on the conventional 

milling process, where a few pounds of uranium were recovered for each ton of ore mined and 

processed, and large quantities of radioactive by-product material, or “tailings,” accumulated in 

impoundments at the mill site. Concern that these impoundments would be a continuing source 

of radiation exposure unless properly reclaimed was the driving force behind the passage of 

UMTRCA, which mandated how they should be managed to avoid releases of radioactive 

material or other hazardous constituents to ground or surface water.

EPA last revised its regulations for uranium and thorium milling in 1995. Since 40 CFR 

Part 192 was promulgated, there has been a shift in uranium recovery technology from 

conventional mining and milling to in situ recovery (ISR) where, in a sense, a portion of the 

milling process is conducted underground within the ore body. In the ISR process (sometimes 

referred to as in situ leaching [ISL]),3oxidizing chemical solutions called lixiviants are pumped 

underground through an array of wells into the ore body, where the uranium is dissolved in 

place. The uranium-rich solutions are pumped to the surface where the uranium is extracted 

(EPA, 2012b).

EPA has reviewed the existing 40 CFR Part 192 standards to determine if the 

requirements are appropriate for ISR. As a result of this review, EPA determined that the 

requirements should be revised and is proposing a new subpart that establishes groundwater

restoration goals and monitoring requirements at ISR facilities.

 

3 Throughout the rest of this report, the abbreviation ISR is used for simplicity; ISL is another widely used 

abbreviation for this uranium extraction and processing method.
1-2

1.2 Statement of Need for Policy Action

1.2.1 Protection of Human Health and the Environment

EPA has concluded, after reviewing the current language in 40 CFR Part 192, that Part 

192 needs to be revised to specifically address the environmental risks posed by ISR uranium 

operations. The ISR process directly alters groundwater chemistry through injecting the aquifer 

in which the uranium is found with mobilizing agents. Mobilizing uranium in the formation can 

also liberate other elements, potentially contaminating surrounding aquifers. If such 

contamination occurs, the contaminants have the potential to move with the groundwater, 

reducing the quality of valuable groundwater resources and possibly ultimately reaching drinking 

water wells or surface water. To ensure that public health, safety, and the environment are 

protected, EPA must ensure that groundwater restoration is adequate after ISR operations cease; 

this is particularly important because current Nuclear Regulatory Commission (NRC) regulations 

allow ISR operators to terminate their licenses soon after restoration is complete (sometimes less 

than 1 year), essentially ending oversight of the site. After that, they may either sell the property

or, if leased, return it to its owners. EPA’s research (U.S. EPA, 2012a) indicates that there is a 

risk that the groundwater may once again become contaminated with uranium or other 

constituents after restoration and stability monitoring ends. For example a U.S. Geological 

Survey case study of pilot ISR projects documented that some constituent concentrations 

increased after the end of stability monitoring. (USGS, 2009) More recently, research conducted 

by U.S. Department of Energy’s Office of Legacy Management found that groundwater flushing 

at UMTRCA sites is slower and more complex than originally thought. (Shafer et al., 2014) 

Depending on the exposure pathways, contaminated groundwater may pose a risk to human 

health, livestock health, or the environment. Thus, EPA has concluded that current standards in 

40 CFR Part 192 should be revised to require, among other things, an adequate post-restoration 

monitoring period.

1.2.2 Need for Regulatory Intervention Because of Market Failure

In general, regulatory intervention is required only when markets fail to allocate 

resources efficiently. For markets to allocate resources efficiently, both buyers and sellers must 

have access to full information about the transaction; there must be many buyers and sellers so 

that neither buyers nor sellers have power to control prices; and the market must impose all the 

social costs of the transaction on the buyers and sellers in the market. In some situations, 

however, these conditions do not occur, and markets fail to allocate resources efficiently. One 

such market failure occurs in cases where a production or consumption activity imposes an 

external cost on members of society who are neither buyers nor sellers in the market for the good 
1-3

or service produced. In cases of external costs, or “externalities,” some costs are imposed on 

members of society who are not part of the market. Because the market is not affected by these 

costs, it fails to allocate resources efficiently, and government must intervene to make the 

outcome more efficient. Environmental pollution that results from a production process is an 

example of an external cost borne by members of society who are neither producers nor 

consumers of the good whose production is generating the pollution.

In the case of ISR uranium operations, a key market failure that requires regulatory

intervention is the potential for operations to contaminate groundwater aquifers. If groundwater

quality is not adequately restored and adequately monitored during and after the operating 

period, the ISR operations have the potential to degrade groundwater resources and to expose 

humans and ecological receptors to contaminated groundwater or surface water, imposing costs 

on members of society who are neither buyers nor sellers in the market for uranium. Further, if 

the contamination is discovered after an operation is decommissioned and its license terminated, 

and perhaps after the company that owned it is out of business, the costs of remediating the 

contamination may be incurred by the landowner or the taxpayer of the state in which the mine 

was located, rather than by the mine owners and operators, a violation of the “polluter pays” 

principal generally used to “internalize” the external costs of a polluting activity.

In the proposed rule, EPA is proposing to establish groundwater monitoring requirements 

for several phases of an ISR operation, including pre-operational monitoring to establish baseline 

groundwater conditions, ISR operation, wellfield restoration, and post-restoration stability

monitoring to establish that restored groundwater quality is stable. In addition, if contamination 

is identified during the monitoring, the proposed rule requires the ISR facility owners and 

operators to undertake corrective action to correct the contamination and then to monitor to 

demonstrate that it has been successfully corrected.

1.3 Organization of the Report

The remainder of this economic analysis is organized as follows:

■ Section 2 presents a profile of the uranium production industry.

■ Section 3 describes the proposed rule and the estimated costs of complying with it.

■ Section 4 presents a qualitative discussion of the benefits of the proposed rule.

■ Section 5 describes the estimated economic impacts of the proposed rule.
1-4

■ Section 6 describes analyses EPA conducted to assess impacts of statutes and 

Executive Orders.

■ Section 7 presents EPA’s conclusions.
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Section 2

PROFILE OF THE AFFECTED INDUSTRY: URANIUM EXTRACTION AND 

PROCESSING

This section describes the uranium extraction and processing industry, with particular 

emphasis on ISR producers. The section provides background information that supports EPA’s 

economic impact assessment and also EPA’s assessment of possible impacts on small entities 

under the Regulatory Flexibility Act and the Small Business Regulatory Enforcement Fairness 

Act (RFA/SBREFA).

The section is organized as follows. Section 2.1 provides a brief introduction to the 

domestic uranium extraction and processing industry. Section 2.2 describes processes involved 

in extracting and processing uranium using the ISR process. Section 2.3 describes the products 

and users of finished uranium oxide concentrate or yellowcake (U3O8) products. Section 2.4 

discusses the organization of the industry as a whole, including facility- and company-level data. 

Within this section, small businesses are identified so that EPA can evaluate the impact of the 

proposed rule on these businesses under the requirements of SBREFA. Section 2.5 assesses 

market-level data on quantities and prices. The section discusses projections and trends within 

the uranium production industry.

2.1 Introduction

This section examines the market for uranium, including an examination of the 

production processes, production costs, and quantities or uranium supplied. In addition, th is 

section examines the demand for uranium. The uranium extraction and processing sector 

produces uranium which, after undergoing conversion and enrichment, can be used as fuel in 

nuclear reactors. The industry being examined includes facilities that extract uranium using a 

variety of technologies and facilities that process the raw uranium into U3O8, or “yellowcake,” 

which is then shipped to uranium conversion, enrichment, and fuel fabrication facilities. The 

main users (demanders) of uranium are utilities that operate nuclear reactors. Both supply and 

demand for uranium are discussed below.

2.1.1 Uranium Extraction and Processing Sector, NAICS 212291

Establishments engaged in the extraction and processing of uranium to produce fuel for 

electricity generation form the core of the industry. Fuel for nuclear power plants is the primary 

commercial use for uranium (EIA, 2014a). The U.S. industry falls under the North American 

Industry Classification System (NAICS) code of uranium-radium-vanadium mining (212291) 

(NAICS, 2012). Facilities in this industry extract uranium from uranium deposits and process it, 
2-2

producing uranium oxide concentrate or yellowcake, with the chemical formula U3O8. According 

to the 2009 Statistics of U.S. Businesses, a total of 28 establishments were operating under this 

NAICS code (Census, 2011).

2.1.2 Uranium Shipments

In 2013, a total of 4.7 million pounds of uranium concentrate were shipped in the U.S. 

industry, which is 0.8 million pounds more than in 2012 (Table 2-1). Shipments of uranium 

concentrate have fluctuated widely over the last 21 years for a variety of reasons, including 

changes in international demand for and supply of uranium.

2.2 Supply of Uranium

Uranium can be produced using conventional mining methods (underground or open-pit 

mining), coupled with either conventional milling or heap leaching. Conventional milling entails 

grinding the ore, placing it in a tank, and exposing it to an acid or alkaline solution to leach the 

uranium out of the ore. Heap leaching entails placing a pile of the ground ore on a pad and 

pouring the leaching solution over it. The uranium, in the form of U3O8 or “yellowcake,” is then 

physically separated from the other materials in the ore, chemically extracted, precipitated out of 

the solution, concentrated, dried, and packaged for shipment.

Alternatively, instead of conventional mining and milling, uranium can be produced 

using the ISR process. Some uranium ore bodies are located within porous material such as 

gravel or sandstone that is saturated in groundwater. The ore is accessible through mobilizing the 

uranium and pumping it out (World Nuclear Association [WNA], 2012a). Where the ore body is 

amenable to use of the ISR technology, uranium can be recovered economically without the 

extensive surface facilities, ore pads, large waste volumes, or expectations of long-term site 

maintenance associated with conventional milling. In the ISR process, oxidizing chemical 

solutions called lixiviants are pumped through an array of injection wells into the ore body where 

the uranium is solubilized. The uranium-rich solutions are pumped to the surface through 

extraction wells, then piped or transported to a processing plant where the uranium is recovered 

from the solution through an ion exchange process, and further processed prior to shipment, 

similar to the processing described in the previous paragraph. The solutions are then recharged 

with the lixiviant chemicals and pumped back into the ore body to recover additional uranium 

(EPA, 2012b). Any waste water that is not reinjected into the ore body may be injected into a 

deep well for disposal, sent to an impoundment or evaporation pond on site, or treated prior to 

land disposal.
2-3

Table 2-1. U.S. U3O8 Shipments (Million Pounds)

Year Uranium Concentrate Shipments 

1993 3.4

1994 6.3

1995 5.5

1996 6.0

1997 5.8

1998 4.9

1999 5.5

2000 3.2

2001 2.2

2002 3.8

E2003 1.6

2004 2.3

2005 2.7

2006 3.8

2007 4.0

2008 4.1

2009 3.6

2010 5.1

2011 4.0

2012

2013

3.9

4.7

E = Estimated data.

Note: The 2003 annual production and shipment amounts were estimated by rounding to the nearest 200,000 pounds 

to avoid disclosure of individual company data.

Source: U.S. Energy Information Administration: 1993–2002-Uranium Industry Annual 2002 (May 2003), Table 

H1 and Table 2. 2003–2012-Form EIA-851A, “Domestic Uranium Production Report” (2003–2014).

After extracting and processing, the final product of the ISR operation is uranium oxide 

concentrate (U3O8), commonly referred to as yellowcake (U.S. NRC, 2012b). Often, the 

extraction and processing are done at the ISR site. In some cases, one facility extracts the 

uranium and sends it to be processed in another location. One example of this is the La 

Palangana facility in Duval County, Texas, which extracts the uranium and sends it to the 

Hobson Processing Plant, located about 100 miles away in Karnes County, Texas, for processing 

and packaging. Section 2.2.1 provides more detail about the ISR uranium extraction process.
2-4

Total U.S. production of uranium is the sum of uranium produced using each technology. 

Table 2-2 presents historical data on quantities of U3O8 produced.

Table 2-2. Total U.S. Amount of U3O8 Produced (Million Pounds U3O8)

Year Mine Production of Uranium Uranium Concentrate Production

1993 2.1 3.1

1994 2.5 3.4

1995 3.5 6.0

1996 4.7 6.3

1997 4.7 5.6

1998 4.8 4.7

1999 4.5 4.6

2000 3.1 4.0

2001 2.6 2.6

2002 2.4 2.3

E2003 2.2 2.0

2004 2.5 2.3

2005 3.0 2.7

2006 4.7 4.1

2007 4.5 4.5

2008 3.9 3.9

2009 4.1 3.7

2010 4.2 4.2

2011 4.1 4.0

2012 4.3 4.1

2013 4.6 4.7

E = Estimated data.

Source: U.S. Energy Information Administration: Form EIA-851A, “Domestic Uranium Production Report,” 2003–

2014.

Production of yellowcake is the first step in a multistep process to produce nuclear fuel. 

The yellowcake is shipped to conversion facilities that convert it into uranium hexafluoride 

(UF6), which in turn is shipped to facilities that enrich it and fabricate it into fuel assemblies for 

nuclear power plants.

Total domestic supply is a sum of the annual amount of uranium mined in the United 

States and processed into yellowcake and the amount of uranium that was stockpiled in previous 
2-5

years and during the current year is converted to yellowcake. The annual amount of uranium 

mined and the amount processed into U3O8 do not always match; for example, in 1993 only 2.1 

million pounds of uranium-equivalent was extracted, while 3.1 million pounds were actually 

processed into U3O8. The discrepancy is largely due to quantities of uranium added to 

inventories or taken out of inventories in response to market forces.

2.2.1 Production Process

The ISR process has been used since the 1960s in the United States for extracting 

uranium from sandstone type uranium deposits that were not suitable for open pit or underground 

mining. Many sandstone deposits are amenable to uranium extraction by ISR, which is now a 

well-established technology that accounted for more than 28% of the world’s uranium 

production in 2009. The basic requirement for ISR is that the mineralization is located in watersaturated permeable formations that allow effective confinement of mining solutions (commonly

confined between impermeable clay-rich strata) (DRET, 2010).

Figure 2-1 shows a simplified diagram of an ISR uranium operation. Uranium is 

extracted by means of an acid or alkaline leaching solution (lixiviant) that is pumped down 

injection wells into the permeable mineralized zone to mobilize uranium from the ore body. The 

uranium-rich solution is pumped to the surface via nearby recovery wells, and the uranium is 

recovered in the processing plant by hydrometallurgical processing, typically ion exchange or 

solvent extraction (particularly for highly saline waters). The mining solution is regenerated and 

recycled (DRET, 2010). The recovered uranium undergoes further processing and packaging and 

is shipped off site in the form U3O8, or yellowcake, to a facility where it will be converted into 

UF6. Next, the UF6 will be enriched to increase the amount of 235U, after which it will undergo 

fabrication into fuel for nuclear reactors (NRC, 2012a).

The life cycle of an ISR facility involves the following stages:

■ Exploration and development to establish that a commercially viable operation is 

possible.

■ Establishment of site baseline conditions for ISR (mining) of the ore body.

■ Recovery of uranium from the ore body.

■ Restoration of the groundwater to predetermined conditions.

■ Demonstration that restored groundwater is stable.
2-6

■ Long-term stability monitoring of the groundwater to ensure groundwater quality

remains stable.

■ Decommissioning of mined area and surface facilities.

Figure 2-1. Diagram of ISR Uranium Operation

Source: DRET, 2010, p. 3.

During ISR operations, the most common injection/pumping patterns are five and seven 

spot (NRC, 2003). The shape of the mineralized ore body and surface topography, however, may 

give rise to other patterns (NRC, 1997). A typical five-spot pattern contains four injection wells 

and one recovery well. The dimensions of the pattern vary depending on the mineralized zone, 

but the injection wells are generally between 40 and 150 feet apart. To effectively recover the 

uranium and also to complete the groundwater restoration, the wells are often completed so that 

they can be used as either injection or recovery wells. During recovery operations, a slightly 

greater volume of water will be recovered from the mineralized zone aquifer than was injected to 

create a cone of depression or a flow gradient toward the recovery wells. This practice is 

intended to minimize excursions of leachate outside the production area. Groundwater
2-7

monitoring is necessary to detect any excursions of lixiviant outside the mining area during 

operations. Figure 2-2 shows typical well arrangements using five- and seven-spot patterns and 

illustrates a typical wellfield. Piping connecting the individual wells to the header house may be 

run underground or on the surface.

Figure 2-2. Schematic Diagram of a Wellfield Showing Typical Injection/Production 

Well Patterns, Monitoring Wells, Manifold Buildings, and Pipelines

Source: NRC, 2009

Three types of wells are present at uranium ISR facilities during the operational 

(leaching) phase (see Figure 2-2), sometimes further classified by their location:

■ Injection wells—Wells used to inject solutions into an ore-bearing aquifer to mobilize 

uranium.

■ Extraction wells—Wells used to extract uranium-enriched solutions from the orebearing aquifer; also known as “production wells”; note that injection wells and 

extraction wells can be converted from one use to another.

■ Monitoring wells—Wells used to obtain water samples for the purpose of 

determining the amounts, types, and distribution of constituents in the groundwater. 

Wells are located in the production zone, around the perimeter of the production zone 
2-8

(horizontal excursion monitoring wells), and in overlying and underlying aquifers 

(vertical excursion monitoring wells).

Some of these wells will be used to define initial baseline conditions, to monitor the 

progress of restoration, and to determine whether long-term stability has been achieved. Injection 

wells at ISR facilities are defined as Class III wells and are regulated under 40 CFR Part 146—

Underground Injection Control Program: Criteria and Standards. Part 146 establishes 

construction, operating, and monitoring requirements that EPA must approve.

2.2.2 Inputs Used in ISR Uranium Production

This section summarizes briefly the inputs used to produce uranium at ISR facilities.

■ Uranium resource. The most critical input is the uranium deposit itself; mining firms 

invest heavily in exploration and discovery of potentially economically viable 

uranium deposits.

■ Availability of skilled, well-trained engineers and workers is another critical element, 

although operating an ISR facility is not labor intensive once the facility has been 

constructed.

■ Capital equipment used to produce uranium at an ISR facility includes the production 

and monitoring wells, pipelines, and a building for administration, processing and 

packaging equipment, and storing the product. Additional surface facilities may

include evaporation ponds and storage tanks, as well as deep-well injection for 

disposal of spent liquids. Upfront capital costs of construction can be considerable, 

but according to the World Nuclear Association (WNA), they are much lower when 

compared with conventional mining (WNA, 2012a).

■ Materials, including chemicals for the lixiviant solution, and water.

2.2.3 Production Costs

Production costs at ISR uranium facilities depend on the prices and quantities of the 

inputs shown above. Although ISR facilities are expected to be the focus of the Part 192 

revisions, we also looked at base costs for conventional mills and heap leach facilities. In 

general, current conventional mine and mill costs per pound of yellowcake produced are higher 

than ISR facility costs per pound of yellowcake. Numerous factors contribute to this range (e.g., 

capital investment requirements, ore grade, mining or recovery costs, distance to the mill or 

processing facility, long-term liabilities, and milling/processing costs). The lower cost of ISR 

technology per pound of uranium produced has led to its increased use over the past few 

decades.
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2.2.4 Pollution Control

In addition to the cost of constructing and operating an ISR facility, additional costs are 

incurred to implement pollution controls, especially groundwater protection monitoring and 

remediation (where necessary).

During operations, there is a risk that the lixiviant and/or some mobilized constituent may

spread beyond the wellfield, which poses a risk of groundwater contamination outside the 

facility. Monitoring wells are positioned around the production zone of the wellfield to detect 

any “excursion” of constituents beyond the wellfield. If excursions are detected, the operator will 

take corrective actions to remediate the excursion, such as stopping injection while continuing to 

pump water out of the wells near the excursion. When mining is no longer economically viable, 

the operator will stop injecting lixiviant and begin restoring the ore zone aquifer to preoperational conditions to the extent practicable. (Pre-operational conditions will have been 

characterized by sampling the groundwater before operations begin.) The wellfield will be 

flushed with clean water (consuming a substantial amount of water) and will frequently be 

treated with reducing agents to attempt to restore the pre-operational geochemistry and 

immobilize any remaining uranium or other constituents. Then, groundwater conditions are 

monitored to ensure that they remain stable. When sufficient time has passed that the 

owner/operators can demonstrate that groundwater conditions are stable, the wells are plugged 

and abandoned, pipes and other infrastructure are removed, surface facilities are removed and 

shipped off site for disposal, and the site is decommissioned, including termination of the 

radioactive materials license.

Throughout the process, adequate monitoring is critical to protecting groundwater quality 

and thus human health and the environment. The proposed rule will modify the current practice 

for monitoring to more fully establish baseline conditions, monitoring to demonstrate restoration, 

and monitoring to demonstrate that the restored water quality is stable. The revised provisions 

and the associated costs of complying with them are described in Section 3.

Under current requirements, ISR operators must monitor groundwater conditions during 

pre-operational baseline characterization, facility operations, groundwater restoration, and 

stability monitoring. Provisions of the proposed rule will affect facility requirements during preoperational monitoring, operations, restoration, and stability monitoring. Current monitoring 

practice in the industry is described below.
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■ Pre-operational Monitoring: To restore the groundwater to the condition it was 

prior to the mining operations, ISR facility operators must collect samples to 

characterize the pre-operational groundwater.

■ Monitoring for Excursions during Operations: During operations, as discussed 

above, groundwater conditions surrounding the wellfield will be monitored for 

excursions of lixiviant ingredients or mobilized constituents, using wells outside the 

wellfield both horizontally and vertically.

■ Restoration Monitoring: During groundwater restoration, monitoring is used to 

measure the progress of the restoration, as well as to demonstrate compliance with the 

restoration goals. Several alternatives for demonstrating compliance have been 

evaluated.

■ Stability Monitoring: To demonstrate that the restored groundwater will remain 

stable below the restoration goals, ISR facility operators must collect groundwater

samples. Historically, stability monitoring has continued for less than a year; recently

licenses have begun to require stability monitoring of 1 year or longer (EPA, 2012a).

Table 2-3 provides summary expenditures by domestic uranium producers (including 

both conventional and ISR facilities) by expenditure category for the period 2003 to 2013.

2.3 Demand for Uranium

2.3.1 Characteristics of the Product (Yellowcake)

Demand for yellowcake is derived from the demand for nuclear energy, which in turn is 

derived from the demand for electricity. Yellowcake is a primary input into nuclear energy

production, which ultimately uses nuclear fuel products. The direct demanders of yellowcake are 

generally conversion facilities.

Downstream processing operations must occur before the U3O8, or yellowcake, is able to 

be used as a fuel. The next step in the process is termed conversion and includes the refinement 

of yellowcake to eliminate impurities. The U3O8 is converted to gaseous uranium hexafluoride 

(UF6). At this stage in the process, UF6 is extremely corrosive, particularly when moist. The 

material is transferred to steel cylinders with thick walls. The cylinders are shipped to 

enrichment facilities.
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Table 2-3. Domestic Uranium Industry Production Expenditures ($Million)

Year 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Drilling W 10.6 18.1 40.1 67.5 81.9 35.4 44.6 53.6 66.6 49.9

Production W 27.8 58.2 65.9 90.4 221.2 141.0 133.3 168.8 186.9 168.2

Total land and 

other

31.3 48.4 59.7 115.2 178.2 164.4 104.0 99.5 96.8 99.4 90.6

Land NA NA NA 41.0 77.7 65.2 17.3 20.2 19.6 16.8 14.6

Exploration NA NA NA 23.3 50.3 50.2 24.2 34.5 43.5 33.3 21.6

Reclamation NA NA NA 50.9 50.2 49.1 62.4 44.7 33.7 49.3 54.4

Total Expenditures W 86.9 136.0 221.2 336.2 467.6 280.5 277.3 319.2 352.9 308.7

Drilling: All expenditures directly associated with exploration and development drilling.

Production Land and Other: All expenditures for land; geological research; geochemical and geophysical surveys; 

costs incurred by field personnel in the course of exploration, reclamation, and restoration work; and overhead 

and administrative charges directly associated with supervising and supporting field activities. All expenditures 

for mining, milling, processing of uranium, and facility expense.

NA = Not available

W = Data withheld to avoid disclosure of individual company data.

Notes: Expenditures are in nominal U.S. dollars. Totals may not equal sum of components because of independent 

rounding. Expenditures refer to all U.S. uranium production, including conventional mines and mills.

Source: U.S. Energy Information Administration: Form EIA-851A, “Domestic Uranium Production Report” (2003–

2013).

The enrichment process uses gaseous UF6 as a feed. After this process is concluded, two 

products are formed: the actual product that contains higher levels of 235U and the “tails” with 

lower levels of 235U. The enriched 235U product is now ready to be processed and fabricated into 

a reactor fuel. Uranium dioxide (UO2) powder is produced. The powder is processed and formed 

into ceramic pellets. The pellets are loaded into fuel rods and pressurized with helium gas and 

finally sealed (WNA, 2012c).

2.3.2 Uses and Consumers

The primary end use for uranium is as fuel for nuclear power plants. U.S. civilian nuclear 

power reactors are the end users of uranium. They are also referred to as “civilian 

owner/operators” or COOs (EIA, 2013c). Over the last 20 years, about 20% of the country’s total 

energy supply has been generated by nuclear power. The Energy Information Administration 

(EIA), in its Reference case, projects that the output of nuclear power will increase, partially due 

to the Energy Policy Act of 2005, which guarantees construction loans to nuclear power plants. 

By 2040, the EIA projects that nuclear capacity will increase by about 10.4 gigawatts, with 

approximately 9.7 gigawatts coming from new reactors and 0.7 gigawatts coming from power 

uprates at existing reactors (EIA, 2014a). In February 2012, NRC voted to approve the 
2-12

Combined Operating License (COL) to build two new Westinghouse AP1000 reactors, Vogtle 

Units 3 and 4. In March 2012, NRC voted to approve the COL to build two new AP1000 

reactors, Virgil C. Summer Units 2 and 3. The Vogtle and Virgil C. Summer units are expected 

to be online between 2016 and 2018. In addition to the four new AP1000 reactors, the Tennessee 

Valley Authority anticipates completion of the construction of Watts Bar Unit 2 in late 2015.

These five reactors are the first to be constructed in the United States in over 30 years and will 

account for approximately 5.5 GWe of the projected 9.7 GWe projected to be online by 2040.

Thirty-one other countries also generate nuclear power, but the largest generator remains the 

United States. France is the second largest country in terms of usage, followed by Russia and 

Japan.

2.3.3 Substitutes

Uranium produced by conventional mines and mills is a perfect substitute for uranium 

produced by ISR facilities. Similarly, imported U3O8 would be a perfect substitute for uranium 

produced by ISR facilities. Imported low-enriched-uranium (LEU) and downblended LEU would 

be substitutes for LEU produced using domestic uranium.4 Other fuels used to generate 

electricity, and other forms of energy, are imperfect substitutes for uranium. This analysis 

focuses on the market for uranium, not the market for electricity or the market for energy, so 

these imperfect substitutes are not explicitly considered.

2.4 Industry Organization

This section describes the organization of the uranium mining and milling industry, 

including the market structure and the characteristics of the facilities and firms producing 

uranium oxide in the United States.

2.4.1 Market Structure

Market structure describes the way in which suppliers and demanders of a commodity

interact; markets may range from perfectly competitive (many sellers and buyers of a 

homogeneous product, none large enough to affect market price by their actions) to monopolistic 

(only one supplier who sets the price and quantity in the market to maximize his profit). The 

market for grain is an example of a perfectly competitive market; individual farmers or 

purchasers are “price-takers,” deciding what quantity to sell or buy based on a market price they

 

4

See discussion of international trade in uranium and the Megatons-to-Megawatts agreement with Russia, below. 

When the Megatons-to-Megawatts program ends, Russia is expected to sell the United States uranium from their 

production sector.
2-13

take as given. Electric utilities are examples of regulated monopolies; only a single electric 

utility serves each geographic market, and its rates are set through negotiation with regulatory

bodies. Most markets actually fall somewhere between these two extreme examples. The market 

for uranium is global, imperfectly competitive, and highly regulated.

2.4.1.1 Barriers to Entry

Globally, there are relatively few suppliers of yellowcake, and only six facilities are 

currently operating in the United States. The small number of facilities indicates that firms 

wishing to enter the uranium market face several barriers to entry. Barriers facing potential 

entrants in the United States include the following:

■ They must have access to a uranium deposit, which are limited in number. Uranium is 

a scarce resource, and a significant ore body must first be located, which requires 

investing considerable time and money.

■ They must obtain a license from the NRC or an Agreement State. The NRC regulates 

ISR facilities. The NRC has developed a suite of regulations to reduce threats to 

human health and the environment, such as 10 CFR Part 20, 10 CFR Part 40, and 

Appendix A of 10 CFR Part 40, which are based on EPA regulations at 40 CFR Part 

192 (NRC, 2013). To begin extracting uranium at an ISR facility, the potential 

supplier must go through many time-consuming and costly steps. The applicant must 

follow NRC’s regulatory guides that present guidance on various aspects of the 

process, such as license applications, environmental impact statements and analyses, 

calculation models, financial assurance and construction requirements. Each of these 

steps is also expensive and requires substantial amounts of time. The environmental 

impact statement is part of the National Environmental Policy Act process, which 

may be duplicated by Bureau of Land Management requirements if the project is on 

public lands.

■ Prior to getting a license from the NRC, the applicant must also get an aquifer 

exemption from the EPA’s Underground Injection Control Program, or its delegated 

agency, which can be the state or the regional EPA office.

Some states have additional barriers, such as Virginia’s moratorium on uranium mining 

and milling5(Virginia Statute 45.1-283). Agreement State regulations may be stricter than NRC 

regulations, which can be important with respect to protecting groundwater resources.

 

5

In 1982, the Virginia General Assembly passed Statute 45.1-283, which states “permit applications for uranium 

mining shall not be accepted by any agency of the Commonwealth prior to July 1, 1984, and until a program for 

permitting uranium mining is established by statute.”
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2.4.2 Small Businesses

The RFA as amended by SBREFA requires federal departments and agencies to evaluate 

if and/or how their regulations affect small business entities. Specifically, the agency must 

determine if a regulation is expected to have a significant economic impact on a substantial 

number of small entities. Small entities include small businesses, small organizations, and small 

governmental jurisdictions. The business is defined as the owner company, rather than the 

facility; the size of the owner company determines the resources it has available to comply with 

the rule.

If a rulemaking is determined to have a significant economic impact on a substantial 

number of small entities, then the agency must conduct a formal regulatory flexibility analysis. 

However, if the agency determines that a rulemaking does not have a significant economic 

impact on a substantial number of small entities, then it makes a certification of that finding and 

presents the analyses that it made to arrive at that conclusion. The ISR uranium operations fall 

under the NAICS code of uranium-radium-vanadium mining (212291) (NAICS, 2012). For 

NAICS 212291, the Small Business Administration (SBA) (2012) defines a small business as

one having fewer than 500 employees.

Because the proposed revisions to Part 192 do not involve conventional mills, the 

economic impact analysis focuses on ISR facilities. In 2013, there were six ISR facilities in 

operation (EIA, 2014b): Crow Butte and Smith Ranch-Highland-Reynolds owned by Cameco 

Resources; Alta Mesa owned by Mestena Uranium, LLC; Willow Creek owned by Uranium 

One, Inc.; Hobson-La Palangana owned by Uranium Energy Corp.; and Lost Creek owned by 

Ur-Energy. Because they have fewer than 500 employees, Mestena Uranium, LLC, Ur-Energy,

and Uranium Energy Corp. are considered small businesses according to the criteria for NAICS 

212291, while both Cameco Resources and Uranium One, Inc. are large businesses. 

Table 2-4. Owner Companies for ISR Facilities: Existing and Planned

Parent Company Facility Name

Number of 

Employees

Annual Revenue 

(Million $)

Small 

Business?

Cameco Corporation Crow Butte, Smith RanchHighland3,300 2,400 No

Mestena Uranium Alta Mesa 125 x Yes

Uranium One, Inc. Willow Creek, Moore Ranch, 

Antelope-Jab

2,200 530.4 No

Uranium Energy Corp. Hobson-La Palangana, Goliad 98 9.00 Yes

(continued)
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Table 2-4. Owner Companies for ISR Facilities: Existing and Planned (continued)

Parent Company Facility Name

Number of 

Employees

Annual Revenue 

(Million $)

Small 

Business?

Powertech Uranium Corp. Dewey-Burdock 25 5.04 Yes

Uranerz Uranium Corp. Nichols Ranch 54 0.00 Yes

Strata Energy/Peninsula 

Energy Ltd

Ross <30 0.85a Yes

Uranium Resources Crownpoint, Kingsville Dome, 

Rosita, Vasquez, Church Rock

37 x Yes

Ur-Energy Lost Creek 51 x Yes

Bayswater E&P Reno Creek x x Yes

x = No annual sales data

Note: ISR projects listed in italics are not currently in operation; see Table 2-7 for status. Those in regular print were 

operating during the summer of 2013.

Sources: Data on total number of employees and annual sales were gathered from Hoover’s, U.S. Securities and 

Exchange Commission, and various company annual reports and websites (Cameco, 2013; Uranium One, 

2013; Uranium Energy Corporation, 2013; Peninsula Energy Ltd, 2013;Uranerz Energy Corporation 2013; 

Uranium Resources, Inc.2013, Ur-Energy 2013).

In addition to the six ISR facilities listed above, several ISR facilities are in various 

stages of planning or licensing (see Table 2-4); most of these are also owned by small 

businesses. Thus, of the existing or planned ISR uranium recovery facilities identified in Table 2-

4, most are owned by small businesses. Of the 10 owner companies listed in Table 2-4, 8 are 

small, based on available information about their employment.

EPA recognizes that several of the small businesses have investors in some of their ISR 

operations that are large businesses. Although the presence of these large company investors may

provide additional resources for complying with the rule, EPA nevertheless evaluated the potential 

for small business impacts based on data for the small business that is the owner of the operation.

2.5 Market for U3O8

2.5.1 U.S. Consumption

In 2012, U.S. COOs of nuclear power plants purchased a total of 57 million metric tons 

of U3O8 equivalent, an increase of 0.7% from the prior year (see Table 2-5). The majority of the 

U3O8 equivalent (approximately 80%) was purchased through the use of short-, medium-, and 

long-term contracts. Under these contract types, at least one delivery is set to occur after a year 

following the date the contract was established. The remaining uranium sales were purchased 

through the use of spot contracts, which are one-time deliveries, set to occur within a year of the 
2-16

contract’s signing date. While the weighted-average prices of uranium purchased by U.S. COOs 

dropped slightly as well, from $54.99 per pound in 2012 to $51.99 in 2012 (see Table 2-8), spot 

prices have dropped since early 2011. The spot price for uranium fell to $43.83 in 2013 (Table 2-

8); for contracts signed in 2013 by U.S. COOs, the long-term contract price was approximately

$43.20 (U.S. EIA, 2014c).

Table 2-5. Uranium Purchased by U.S. COOs, 1994–2013 (Million Pounds U3O8

Equivalent)

Delivery Year Spot Contracts

Short-, Medium-, and 

Long-Term Contracts Total Purchased

1994 8.5 29.8 38.3

1995 13.6 29.8 43.4

1996 9.1 38.3 47.3

1997 5.5 36.5 42.0

1998 7.8 34.9 42.7

1999 8.0 40.0 47.9

2000 10.4 39.1 51.8

2001 14.4 40.0 55.4

2002 8.6 41.4 52.7

2003 8.2 46.7 56.6

2004 9.2 53.3 64.1

2005 6.9 58.8 65.7

2006 6.3 59.4 66.5

2007 6.6 43.7 51.0

2008 8.7 42.8 53.4

2009 8.1 41.0 49.8

2010 8.2 37.9 46.6

2011 12.0 42.3 54.8

2012 8.1 48.9 57.0

2013 11.3 46.1 57.4

Sources: U.S. Energy Information Administration: 1994–2002-Uranium Industry Annual, Tables 10, 11 and 16. 

2003–2013-Form EIA-858, “Uranium Marketing Annual Survey.”

As shown in Table 2-6, domestic production of U3O8 is a small share of total COO 

purchases. Some comes from domestic inventories, but the majority of uranium purchased by

COOs is from foreign sources.
2-17

Table 2-6. Total Amount U3O8 Produced in the United States (Thousand Pounds U3O8)

Production Total Mine Production Total Mines and Sources

2003 E2,200 4

2004 2,452 6

2005 3,045 10

2006 4,692 11

2007 4,541 12

2008 3,879 17

2009 4,145 20

2010 4,237 9

2011 4,114 11

2012 4,335 12

2013 4,577 12

E = Estimated data.

Source: U.S. Energy Information Administration: Form EIA-851A, “Domestic Uranium Production Report” (2003–

2013).

2.5.2 U.S. Uranium Production

In the United States, uranium producers are concentrated in the West and Southwest, 

including the states of Texas, New Mexico, Arizona, Utah, Colorado, Wyoming, South Dakota, 

and Nebraska. Figure 2-3 shows the approximate locations of uranium production facilities 

(including not only operating ISR facilities, but also those that are currently on standby or preoperational).
2-18

Figure 2-3. Location of ISR Uranium Production

Source: EPA, 2012a

Table 2-7 provides a list of ISR facilities in the United States, together with their 

location, capacity, and operating status. As shown in the table, there are six currently operating 

or producing ISR facilities in the United States; several others are licensed or partially licensed. 

Of the 23.1 million pounds capacity shown in the table, U.S. facilities have typically produced 

less than 10 million pounds per year over the past 10 years.
2-19

Table 2-7. In situ Recovery Plants in the United States, and Status (2013)

In situ Recovery Project Name State 

Production 

Capacity (pounds 

U3O8 per year) Status

Operating, Summer 2013

Crow Butte Nebraska 1,000,000 Operating

Smith Ranch-Highland Wyoming 5,500,000 Operating

Alta Mesa Texas 1,500,000 Operating

Hobson-La Palangana Texas 1,000,000 Operating

Willow Creek (Christensen Ranch and 

Irigaray)

Wyoming 1,300,000 Operating

Lost Creek Wyoming 2,000,000 Operating

Not Operating, Summer 2013

Crownpoint New Mexico 1,000,000 Partially permitted and licensed

Church Rock New Mexico 1,000,000 Partially permitted and licensed

Dewey Burdock South Dakota 1,000,000 Developing

Ross Wyoming 3,000,000 Partially permitted and licensed

Kingsville Dome Texas 1,000,000 Restoration

Rosita Texas 1,000,000 Restoration

Vasquez Texas 800,000 Restoration

Nichols Ranch ISR Wyoming 2,000,000 Under construction

Goliad ISR Uranium Texas 1,000,000 Permitted and licensed

Antelope-Jab Wyoming 2,000,000 Developing

Moore Ranch Wyoming 500,000 Permitted and licensed

Reno Creek Wyoming -- Developing

Total Domestic Production Capacity: 26,600,000

– = No data reported.

a According to owner company (Ur-Energy, Uranium Energy Corporation) websites.

Notes: Production capacity for 2011. An operating status of “Operating” indicates the in-situ leach plant usually was 

producing uranium concentrate at the end of the period. The Hobson ISR Plant processed uranium concentrate 

that came from La Palangana. Hobson and La Palangana are co-owned, but not co-located, and are considered in 

this analysis as one project. Christensen Ranch and Irigaray are part of the Willow Creek Project.

Source: U.S. Energy Information Administration: Form EIA-851A, “Domestic Uranium Production Report” (2007–

2013).

2.5.3 International Trade

Uranium is a relatively homogeneous commodity that is valued for its energy content, 

and the market for uranium is genuinely an international market. Uranium produced in the 

United States may be sold abroad or sent abroad for processing and then returned to the United 

States. Typically, domestic-origin uranium has been a relatively small share of total uranium 
2-20

purchased in the United States. In addition to uranium mined abroad, low-enriched uranium for 

use in fuel fabrication facilities is also imported, especially from Russia.

In 1993, the United States and Russia entered into a government-industry agreement 

whereby Russian nuclear weapons containing HEU are dismantled and converted to LEU for use 

as fuel in nuclear power reactors domestically (United States Enrichment Corporation [USEC], 

2012). A commercial company, USEC, has acted on behalf of the U.S. government. 

Techsnabexport (TENEX) is the commercial agent for the Russian government. Since the 

program’s inception, ~12,380 metric tons of HEU have been converted. In 2013, purchases 

under the program ended (USEC, 2014).

In 2013, TENEX will begin to supply LEU under a new contract with USEC. The new 

amount that will be supplied will increase until it reaches approximately one-half the currently

supplied levels (under the Megatons to Megawatts Program) in 2015. Within the agreement, 

there is an option to scale up to the currently supplied levels through the year 2022. Under the 

new contract, Russia will be supplying commercially enriched uranium instead of uranium from 

dismantled weapons (World Nuclear News, 2011; Pravda, 2012).

2.5.3.1 Imports

Most of the uranium used by COOs domestically is purchased from foreign suppliers. In 

2012, the 9.8 million pounds of U3O8 produced in the United States amounted to only 17.0% of 

the total 57.5 million pounds of U3O8 purchased. Kazakhstan, Russia, and Uzbekistan comprised 

40% of total deliveries. The share of uranium that is of foreign origin has fluctuated over time 

(EIA, 2013c).

2.5.3.2 Exports

In addition to imports of uranium into the United States, the NRC licenses exports of 

processed uranium from the United States. In 2012, of 18.0 million pounds delivered to foreign 

suppliers and utilities, only 4.8 million pounds of the uranium exported was of U.S. origin. The 

remaining 13.2 million pounds exported were of foreign-origin uranium6(EIA, 2013c).

 

6 Note that data provided for production, imports, exports, and purchases in a given year appear inconsistent. This 

occurs because some production may go into inventory, and some purchases may be from inventory.
2-21

2.5.4 Market Prices

Uranium is traded under various contractual arrangements, including spot contracts and 

short-, medium-, and long-term contracts. Contract prices and spot prices vary, with spot prices 

being much more volatile than contract prices. Table 2-8 presents historical data on uranium 

prices. Most contracts are based not based on the spot price but rather the long-term price. It 

should be noted that uranium is not traded on recognized exchanges; rather the price is set by

two independent companies based on their market research. Contract prices exhibit more 

stability than spot prices. In 2007, the spot price rose to more than $88 per pound, while the 

weighted average short-, medium-, and long-term contract price was less than $25 per pound. In 

2011, however, the spot price and weighted average price had converged to within $2 per pound, 

and in 2012 the spot price and weighted average price were within $5 per pound (EIA, 2013c). In 

2013, the difference between the spot price and weighted average price increased again to 

approximately $10 per pound.

Table 2-8. Weighted-Average Price of Uranium Purchased by U.S. COOs Based on 

Contract Type

Delivery Year Total Purchased Spot Contracts

Short, Medium, and 

Long-Term Contracts

1994 10.40 9.01 NA

1995 11.25 10.30 NA

1996 14.12 14.22 NA

1997 12.88 11.61 NA

1998 12.14 10.56 NA

1999 11.63 9.52 NA

2000 11.04 8.54 11.70

2001 10.15 7.92 10.96

2002 10.36 9.29 10.58

2003 10.81 10.10 10.94

2004 12.61 14.77 12.24

2005 14.36 20.04 13.70

2006 18.61 39.48 16.38

2007 32.78 88.25 24.45

2008 45.88 66.95 41.59

2009 45.86 46.45 45.74

2010 49.29 43.99 50.43

2011 55.64 54.69 55.90
2-22

Delivery Year Total Purchased Spot Contracts

Short, Medium, and 

Long-Term Contracts

2012 54.99 51.04 55.65

2013 51.99 43.83 54.00

Sources: U.S. Energy Information Administration: 1994–2002-Uranium Industry Annual, Tables 10, 11, and 16. 

2003–2013-Form EIA-858, “Uranium Marketing Annual Survey.”

2.5.5 Industry Trends

In March 2011, a massive earthquake and tsunami struck the coast of Japan, causing 

more than 20,000 deaths and leading to the Fukushima Daiichi nuclear power plant meltdown. 

The disaster was the largest of its kind since the Chernobyl accident in 1986. In the aftermath of 

the disaster, the viability and safety of nuclear power were questioned. The event led to a 

comprehensive examination of energy policies throughout the world. One year later, however, 

the EIA (2013b) reported that the nuclear power industry is in fact projected to expand, with 

greater safeguards being established to protect from future disasters (WNA, 2012b).

Worldwide, demand for uranium is projected to grow as nations such as China and India 

increase their use of nuclear power. Meanwhile, exploration for new sources of uranium is 

ongoing, both in the United States and elsewhere. Several years ago, the U.S. Nuclear Waste 

Technical Review Board (U.S. NWTRB, 2010) examined the supply and demand for uranium, 

and noted that 2009 uranium resources were sufficient to meet 2009 levels of demand for 90 

years. The overall impact on future uranium prices depends on whether demand for uranium or 

supply of uranium grows more rapidly.

The largest uranium producers globally are Kazakhstan (36%), Canada (17%), and 

Australia (11%) (WNA, 2012d). The United States accounts for close to 3% of world production.

2.5.6 Projections

The EIA, in its 2014 Annual Energy Outlook (EIA, 2014a), provides projections about 

energy production and use through the year 2040, under a variety of assumptions about 

economic growth and other future conditions. In its reference case projections, EIA projects that 

energy supplied from uranium will grow over the period 2011 to 2040 from 8.26 quadrillion Btu 

to 8.49 quadrillion Btu, a rate of growth of approximately 0.2% per year. Applying the reference 

case rate of growth to 2012 uranium purchases, projected 2040 uranium purchases by COOs 

would be approximately 65 million pounds. As noted above, increasing demand for uranium 

from China and other countries is expected over the long term, in spite of recent developments 

such as the Fukushima tsunami and the global economic downturn. Similarly, the price of 
2-23

uranium is projected to increase over the next few years as demand increases and the Megatons 

to Megawatts program ends. Under the Megatons to Megawatts program, a 20-year agreement 

between USEC (representing the United States government) and Techsnabexport (TENEX, 

representing the Russian government), weapons-grade highly enriched uranium from Russian 

nuclear warheads (HEU) was processed and down-blended to low-enriched uranium and sold to 

USEC for use as nuclear fuel. On average, The Megatons to Megawatts program supplied about 

13% of world uranium requirements during this period. The program ended in 2013. (See WNA, 

2013 for more information.) Although a follow-on agreement with TENEX permits USEC to 

continue to purchase uranium from Russia, future uranium purchased will be from conventional 

supplies and the expected quantity will be smaller. Assuming that the global economy recovers 

from its recession and planned nuclear energy projects go forward, demand for uranium is 

projected to increase, while supplies may lag (although uranium reserves are estimated to be 

ample to meet projected needs, they will need to be extracted and processed to supply the 

market, and development and production has slowed during 2011 to 2012). Longer term, the 

price is projected to increase. The Australian Bureau of Research and Energy Economics, cited 

by the Australian Uranium Association, projects the price of uranium to rise to about $64 per 

pound by 2018 (Australian Uranium Association, 2013) . If either the recovery from the global 

recession lags or excess demand for uranium is slower to develop, these prices might not be 

realized by 2018, but they do represent likely levels going forward.
3-1

Section 3

THE PROPOSED RULE AND ITS ESTIMATED COSTS

EPA reviewed the existing regulations affecting ISR uranium projects and concluded that 

40 CFR Part 192 should be amended to add a subpart F that specifically addresses groundwater

protection at ISR operations, which are now the dominant form of uranium extraction in the 

United States. The ISR process presents different environmental concerns than conventional 

milling; ISR does not result in large volumes of waste materials or the need for permanent 

impoundments. However, the process directly alters groundwater chemistry, posing the 

challenge of groundwater restoration and long-term stabilization after ISR operations end. In 

developing the proposed rule, EPA’s objective was to provide long-lasting protection of 

groundwater aquifers surrounding ISR wellfields. EPA’s proposed rule specifies how to 

determine pre-operational background conditions that will be used to set appropriate restoration 

goals, applicable standards, and alternative concentration limits. The proposed rule also provides 

specifications for long-term groundwater stability monitoring to ensure that ISR sites do not 

become a source of groundwater contamination after the operation is terminated. In addition, the 

proposed rule explicitly requires corrective action if monitoring reveals that constituents have 

left the exempted aquifer during operations or have become mobile again after restoration is

complete.

3.1 Description of Proposed Regulation

EPA’s proposed regulation includes provisions addressing three issues: pre-operational 

monitoring to establish baseline conditions, establishing and updating groundwater protection 

standards, and monitoring to demonstrate that the restored water quality is stable. Below, we 

describe these three aspects of the proposed rule. EPA considered several regulatory options 

before selecting its preferred approach to each issue.

3.1.1 Groundwater Protection Standards

EPA’s proposed rule identifies the minimum 13 constituents for which groundwater

protection standards must be met: arsenic, barium, cadmium, chromium, lead, mercury, 

selenium, silver, nitrate (as N), molybdenum, combined radium-226 and radium-228, uranium 

(total), and gross alpha-particle activity (excluding radon and uranium). The concentration of 

each listed constituent must remain at or below the most protective standards under the Safe 

Drinking Water Act (SDWA), values from Resource Conservation and Recovery Act (RCRA) 

standards, or Table 1 to subpart A of Part 192, except in cases where the measured preoperational wellfield background concentration (commonly referred to in the industry as 
3-2

“baseline”) is higher than the most stringent value in the applicable regulations. In such cases, 

the measured background concentration will serve as the restoration goal. The proposed 

language allows for the regulatory agency to set standards for additional constituents as 

necessary, consistent with site conditions, and provides clarity and consistency by referring to 

existing standards under each act at the time of licensing. Under the proposed rule, Subpart F 

standards would automatically update if any of the referenced standards (SDWA or RCRA) were 

revised (see Table 3-1).

Table 3-1. Table 1 to Subpart F of Part 192—Maximum Concentration of Constituents 

for Groundwater Protection at ISR Facility Sites

Constituent Maximum

Arsenic

Barium

Cadmium

Chromium

Lead

Mercury

Selenium

Silver

Nitrate (as N)

Molybdenum

Radium-226 and radium-228 (combined)

Uranium (total)

Gross alpha particle activity (excluding radon and uranium)

The restoration goal is the primary or secondary 

MCL listed in 40 CFR 141.61, 141.62, 141.66, 

141.80, and 143.3, the maximum concentration of 

hazardous constituents for groundwater protection 

under 264.94, or the maximum constituent 

concentration specified in Table 1 to subpart A of 

this Part, whichever is most stringent.

Where a background concentration is determined to 

be higher, the background concentration will serve 

as the restoration goal.

3.1.2 Monitoring Requirements

To ensure that groundwater in the vicinity of ISR operations is protected, EPA’s 

proposed rule specifies groundwater monitoring requirements for each phase of the ISR 

operation.

3.1.2.1 Pre-operational Monitoring: Adequate Characterization of Groundwater Prior to 

Uranium Recovery

EPA’s proposed rule specifies requirements for thorough pre-operational monitoring at 

ISR sites. This monitoring serves several purposes. To design and operate an ISR facility, the 

chemical composition and hydrology of the groundwater in and around the ore body must first be 

rigorously characterized. Defining the configuration of the ore zone and designing the production 

zone for uranium recovery require detailed subsurface information obtained from geophysical 
3-3

investigations, including but not limited to logs and cores (U.S. EPA, 2013). In addition, the 

groundwater in the production zone is also characterized to determine the proposed chemical 

composition of the lixiviant and to determine pre-operational groundwater chemistry by which to 

set restoration goals for the post-production phase of the ISR operation (i.e., the efforts to return 

the groundwater chemical conditions in the production zone to those that existed prior to the 

uranium recovery efforts). EPA’s proposed rule requires:

■ A sufficient number of wells, at appropriate locations and depths, to be installed in 

such a manner as to yield representative samples in order to define the groundwater

flow regime and measure pre-operational hydrogeochemical conditions and water 

quality for use in statistical tests during licensing, operations, restoration, stability,

and long-term stability.

■ The pre-operational background monitoring effort must include immediately

overlying aquifers, immediately underlying aquifers, and background monitoring 

inside and outside of the exempted aquifer, including both the up- and down-gradient 

areas outside of the production zone.

■ During the monitoring effort, relevant data documenting geology, hydrology, and 

geochemistry for radiological and nonradiological constituents shall be collected, 

both in the production zone and in surrounding areas that may be affected by the ISR 

operations.

– The monitoring effort must be of sufficient duration of no less than 1 year and of 

sufficient scope to adequately characterize temporal and spatial variations in 

groundwater and to account for impacts of well installation and development on 

background concentrations of constituents and values of indicator parameters, 

where applicable.

– Pre-operational monitoring must be focused on determining background 

concentrations of constituents and indicator parameters in point of compliance 

wells within the proposed production zone, in immediately overlying and 

immediately underlying aquifers, and outside the production zone, in wells within 

the exempted aquifer and in up-gradient and down-gradient wells within nonexempt portions of the adjacent aquifer.

– The owner/operator must employ appropriate statistical techniques to analyze 

background concentrations measured in individual wells within the proposed 

production zone for the purpose of determining restoration goals for groundwater

restoration and long-term stability. As determined by the owner/operator and 

approved by the regulatory agency, background concentration limits may be 

representative of individual wells, multiple wells, or all wells within the proposed 

production zone.
3-4

3.1.2.2 Operational Phase Monitoring

The proposed rule requires monitoring during the operational phase to detect excursions. 

The rule calls for monitoring of indicator parameters in horizontal and vertical monitoring wells. 

If an excursion is detected, corrective action must be undertaken and all constituents listed in 

Table 3-1 must be monitored until the excursion is controlled.

3.1.2.3 Restoration Phase Monitoring

During the active restoration phase, all constituents listed in Table 1 of this subpart or 

otherwise specified by the regulatory agency must be monitored through quarterly sampling or 

other time interval specified by the regulatory agency. Indicator parameters must be monitored in 

horizontal and vertical excursion wells. If an excursion is detected, corrective action must be 

undertaken, and all constituents listed in Table 3-1 must be monitored until the excursion is 

controlled.

3.1.2.4 Stability Phase Monitoring

The proposed rule requires that constituents be monitored throughout the stability phase 

of an ISR facility in points of compliance wells in the production zone, as determined by the 

regulatory agency, including

■ all constituents listed in Table 1 of the new subpart and

■ any additional constituents required by the regulatory agency, such as constituents 

and parameters necessary for geochemical calculations of the groundwater chemistry

in order to demonstrate that a stable groundwater chemistry has been achieved after 

restoration; components of the lixiviant fluids injected during uranium recovery and 

any fluids injected during restoration; or metals potentially mobilized by the uranium 

recovery process.

The owner/operator must collect sufficient data and apply appropriate statistical methods 

to demonstrate that the aquifer conditions within the production zone are stable (i.e., there are no 

temporal trends in the constituent concentration data considering natural variation in 

compositions). Stability must be demonstrated for 3 consecutive years at a 95% confidence level 

and based on sampling no less frequently than quarterly.

If the owner/operator demonstrates 3 consecutive years of stable concentrations of 

constituents but is unable to meet the restoration goal for one or more of these constituents, the 

owner/operator may request an alternate concentration limit (ACL) from the regulatory agency. 

The regulatory agency may then approve an ACL or it may require that the owner/operator 

resume active restoration efforts in an attempt to bring down the constituent concentrations.
3-5

3.1.2.5 Long-Term Stability Phase Monitoring

After stability has been demonstrated, EPA’s proposed rule requires that owner/operators 

continue quarterly monitoring to ensure that groundwater conditions remain stable.

The proposed rule requires long-term stability monitoring to be maintained for a period 

of 30 years. The regulatory agency may shorten the long-term stability monitoring period if, after 

stability is documented for a period of 3 consecutive years, the owner/operator demonstrates

through hydrogeological and geochemical modeling of the site that the subsurface conditions 

within the production zone will remain stable into the future. In evaluating such modeling, the 

regulatory agency must determine that there is a reasonable expectation that restoration goals 

will not be exceeded and that subsurface conditions in the future will not cause the 

remobilization of uranium, radium, or other constituents into the groundwater and their migration 

beyond the boundaries of the production zone. The owner/operator must notify the regulatory

agency and undertake corrective actions if, during the course of long-term stability monitoring, 

one or more monitored groundwater constituents exceeds a groundwater protection standard or

shows statistically significant increasing trends that would threaten groundwater quality if left 

unabated. The proposed rule also specifies the components of a corrective action program.

3.1.3 Other Regulatory Alternatives for Long-Term Monitoring Considered but Rejected

EPA also considered two additional regulatory alternatives:

■ Requiring long-term stability monitoring to continue for 30 years without the 

opportunity to use hydrogeological and geochemical modeling to shorten the 

monitoring period. This alternative was not selected for proposal because EPA felt it 

was unnecessarily burdensome, because modeling may be able to demonstrate that 

geochemical mechanisms exist to prevent uranium and other constituents from 

remobilizing and migrating beyond the boundaries of the production zone. In 

addition, while monitoring for 30 years would enable a determination about whether 

the wellfield chemistry is remaining stable over a longer period of time, it does not 

provide any assurance that the groundwater will remain stable after 30 years, such as 

geochemical modeling may be able to do.

■ Using a narrative long-term stability monitoring standard, with no fixed duration. 

EPA chose not to propose this regulatory alternative because statistical analyses alone 

would provide no assurance that groundwater systems will remain chemically stable 

over a longer period of time. In addition to being somewhat ambiguous, a narrative 

standard poses a higher risk of prematurely terminating the license.

This analysis examines the costs of complying with the proposed rule and the costs of 

complying with the required 30-year long-term stability regulatory alternative. In addition, EPA 
3-6

recognizes that it is possible that geochemical modeling may demonstrate that geological 

conditions in and around the wellfield may not ensure long-term stability; in this case, if 

operations have begun at the ISR facility, EPA expects that the regulatory agency would require 

30 years of long-term stability monitoring to ensure that conditions are stable within the 

wellfield. EPA also estimated the cost of geochemical modeling, followed by an extended 30-

year period of long-term stability monitoring.

3.2 Estimated Incremental Costs of Compliance with Proposed Rule

EPA reviewed the existing regulations affecting ISR facilities and concluded that 40 CFR 

Part 192 should be amended to add a subpart F that specifically addresses groundwater

protection at ISR operations, which are now the dominant form of uranium extraction in the 

United States. The ISR process directly alters groundwater chemistry, posing the challenge of 

groundwater restoration and long-term stabilization after ISR operations end. EPA is evaluating 

the range of cost estimates associated with proposed groundwater monitoring options. The 

current costs associated with groundwater monitoring at ISR facilities under the existing 

regulatory scheme were calculated and then compared against three groundwater monitoring 

scenarios that implement alternative groundwater monitoring approaches proposed by the 

regulation:7

■ 30-year post-restoration stability monitoring with option to reduce monitoring 

duration using hydrogeological and geochemical modeling

■ 30-year post-restoration stability monitoring with no option for shortening the 

duration

In addition, costs were considered for a third monitoring scenario that is not a regulatory

option but rather a worst case scenario for an owner/operator under the proposed regulatory

approach:

■ Geochemical modeling followed by 30 years of required stability monitoring

EPA does not consider that this worst-case scenario is likely to occur. The proposed 

regulatory approach requires thorough characterization of hydrogeochemical conditions within 

the production zone and down-gradient during the pre-operational phase. EPA expects that, if the 

 

7 Throughout the document, the cost estimates are labeled based on the long-term stability monitoring phase 

requirements for convenience. As shown below in Tables 3-2 through 3-7, requirements and estimated costs for 

other phases also differ among alternatives and between alternatives and current practice. 
3-7

conditions are found to be insufficiently reducing (so that any constituents carried down-gradient 

by groundwater would not be stabilized there), the owner-operator might decide not to develop 

the deposit and the licensing agency would likely not grant the license. This worst-case scenario 

would only occur if the sampling and geochemical modeling conducted after operations are 

complete gives a negative signal, after geochemical modeling during pre-operations signaled that 

development would be safe. Thus, this worst case likely overestimates the costs that a site would 

incur. Because EPA regards this worst case as unlikely, and because it does not represent a 

regulatory alternative, EPA presents the estimated impacts under the worst case scenario only in 

Appendix D.

A third regulatory alternative was considered by EPA but not analyzed in this economic 

analysis. EPA also considered a narrative standard with no fixed monitoring period. The actual 

compliance activities that might be required under this alternative would depend entirely on 

negotiations between the owner/operator and the licensing agency. Because they would be site

specific and thus uncertain, EPA concluded that it would not be possible to assess what the 

compliance requirements and associated costs for a given facility would be. For this reason, 

although EPA considered this regulatory approach, its costs and impacts are not analyzed in this 

document.

Although the above scenarios address proposed monitoring requirements during the 

stability monitoring phase, these changes also affect the numbers of wells and analytical 

constituents that must be monitored during earlier phases of an ISR project. These costs have 

also been estimated as they relate to each of the scenarios.

3.2.1 Technical Approach: Conceptual Site Model Facility

A conceptual model was used to help frame the costs for each of these scenarios that are 

described below. The design of one production unit and the hydrogeology of the associated 50-

sand ore bearing layer within Wellfield-E at the Highland Site in Wyoming were used as a basis 

for constructing the CMU model. The CMU model (Figure 3-1) was developed based on the 

actual design of the Wellfield-E production and mine units (Cameco Resources, 2008) but also 

considering standard wellfield design practice (NRC, 2003). The conceptual model was used as a 

basis for developing the costing scenarios. A general layout of the CMU model for the different 

scenarios showing the well locations is provided in Figures 3-1 and 3-2.

3.2.1.1 Conceptual Mine Unit (CMU) Model Description

The CMU area, inside the perimeter monitoring well ring, is approximately 200 acres 

with a 44-acre production area. Approximately 243 wells (166 injection and 77 extraction wells) 
3-8

were assumed for the production area of the CMU model. This assumes that a 5-spot pattern was 

used for the wellfield grid with a well spacing of approximately 120 feet, which is similar to the 

design of the production units in Wellfield-E. A distance of approximately 600 feet from the 

edge of the production unit was used to locate the perimeter-well ring. This was consistent with 

the configuration and design of Wellfield-E. The spacing of perimeter wells was also patterned 

after the Wellfield-E design.

Figure 3-1. ISL/ISR Conceptual Site Model Applicable to Current Practice and 30-Year 

Monitoring

Note: Site model is loosely based on actual conditions for one production area within Wellfield E of the Highland 

Ranch site. Configuration of the perimeter well ring has been adjusted.

Sandstone aquifers were assumed to be overlying and underlying the ore zone (also 

sandstone) aquifer. For simplicity of modeling, it was assumed that laterally continuous shale 

beds served to hydraulically separate the aquifers from the consolidated ore sand. Such a 

stratigraphy is typical of ISR situations. The ore zone sandstone layer was assumed to have an 

average thickness of approximately 35 feet with an average base-of-bed depth of about 600 feet.

The overlying aquifer base-of-bed average depth is approximately 490 feet below ground 
3-9

surface, and the underlying aquifer top-of-bed depth is approximately 650 feet below land 

surface. These depths are roughly similar to the Highland site geology (Michel and Hoffman, 

1991). The 60-sand and 40-sand aquifers, overlying and underlying the 50-sand aquifer unit,

respectively, are also ore sand layers at the Highland site, and production units for one or both of 

these sands are co-located within the boundaries of and near Wellfield-E; however, operational 

strategy that may be used when mine units are co-located was not considered in the CMU model 

or modeled scenarios because these considerations would make the model very site specific, and 

a more generalized model of an ISR wellfield was needed. The concept of these scenario 

analyses was to make assessments of a generic nature but framed within the bounds of 

characteristics associated with actual sites. In practice, the size of the prospective ore zone and 

the configuration of the production wells will be determined by site-specific conditions.

Figure 3-2. ISL/ISR Conceptual Site Model Applicable to Geochemical Modeling 

Scenario

Note: Site model is loosely based on actual conditions for one production area within Wellfield E of the Highland 

Ranch site. Configuration of the perimeter well ring has been adjusted and ore zone monitoring wells have 

been added down-gradient. 
3-10

Assumptions used for evaluating groundwater monitoring costs included:

■ the number of wells to be sampled

■ the duration of the period of sampling (or operation phase)

■ the sampling frequency (i.e., weekly, biweekly, monthly, quarterly) and

■ the list of parameters that must be sampled.

The duration of groundwater stability monitoring would in reality be site specific and is 

typically specified in the license(s) (U.S. EPA, 2012a); however, past and current practice 

assumed a monitoring and sampling period between 6 months and approximately 2 years. 

Typically one injection, extraction, or other ore zone well is monitored per acre of the production 

unit along with the perimeter monitoring wells surrounding the mining unit. Additional 

monitoring wells were also assumed for other ISR phases for the geochemical modeling 

scenario, which assumes that additional geochemical characterization would be needed. Samples 

are generally collected on at least a quarterly basis during the stability phase for the same 

analytes that were sampled during baseline monitoring. The specific lists of chemical analytes 

that operators sample are those specified in the NRC’s ISR Standard Review Plan (NRC, 2003) 

along with analytes required by regulating state agencies. Stability sampling would be extended 

to a minimum of 30 years under the proposed rule unless it could be demonstrated using 

appropriate geostatistical tests, and a minimum of 3 years of stability monitoring data, that the 

groundwater chemistry has reached baseline levels (or other regulatory supported groundwater

quality standards) and is stable at those levels for at least 3 years. Geochemical testing and 

monitoring would also be required by the proposed rule to further demonstrate and ensure longterm stability of groundwater quality in and around the wellfield. A demonstration of 

geochemical stability based on monitoring data and a geochemical model would allow the 

regulator to require less than a 30-year post-restoration monitoring period. In this analysis of the 

proposed rule, EPA assumes that the long-term stability monitoring phase is reduced to 7 years. 

During the restoration phase, groundwater chemical compositions are also monitored to follow 

the course of the restoration effort and identify when constituents of particular interest appear to 

be reaching a relatively constant level. At that point the restoration effort may be ending and 

stability phase monitoring may be appropriate.

Tables 3-2 through 3-6 summarize specific assumptions about the CMU configuration 

used in estimating the costs for each proposed groundwater monitoring scenario considered. The 

number of wells that are sampled during each operational phase (i.e., pre-operational, operations, 
3-11

restoration, stability, and long-term stability monitoring) is assumed to vary among scenarios as 

indicated in the tables. These numbers were selected based on professional judgment about the 

data needs for each of the scenarios examined. The total number of wells also varies for each 

groundwater monitoring scenario. Unit costs assumed for construction of a well are summarized 

in Appendix A.

The assumed numbers of wells, duration, and frequency of groundwater monitoring were 

combined with the analytical costs for the required parameter lists and the cost for groundwater

sample collection, as summarized in Appendix B (Sampling and Analysis Unit Costs), to 

calculate the groundwater monitoring costs by operational phase under

■ current practice (Table 3-2),

■ 30-year long-term stability monitoring with potential to shorten based on geochemical 

modeling (Table 3-3), and

■ 30-year long-term stability monitoring with no potential to shorten (Table 3-4).8

As shown in Table 3-2, under current practice, pre-operational monitoring was assumed 

to last for 1 year, sampling from 85 wells for constituents required by the NRC and by

Agreement States. In contrast, under the regulatory alternatives examined in both Tables 3-3 and 

3-4, samples are drawn from 100 wells, and the full suite of constituents is analyzed. In addition, 

under the proposed rule (30 years long-term stability monitoring with potential to shorten using 

geochemical modeling), we assumed that 10 additional wells, located down-gradient from the 

wellfield, are also sampled to gather data on the geochemistry of the groundwater in that area for 

use in modeling (for a total of 110 wells in Table 3-3). During operations under current practice, 

we assumed that 41 wells are sampled; under the proposed rule, we assumed that 56 wells are 

sampled, including 15 additional vertical excursion wells. ISR extraction operations were 

assumed to last for 6 years. The 6-year duration is consistent with the range of times seen at ISR 

sites; actual duration of uranium extraction depends on site-specific conditions. After extraction 

operations end, the facility is assumed to begin restoration of groundwater to pre-operational 

characteristics. This process involves flushing the production area with clean water (the extracted 

water is often processed by reverse osmosis techniques before the water is reinjected to continue 

 

8 EPA also analyzed the costs that might be incurred if geochemical modeling failed to demonstrate conditions 

favorable for long-term stability. These costs combine the costs estimated for the proposed rule under Phases 1 

through 4 and the costs of Phase 5 (long-term stability monitoring) estimated for the 30-year long-term stability 

monitoring alternative.
3-12

Table 3-2. ISR Conceptual Mine Unit: Current Practice

Well Type

Numbers 

of Wells

Sampling

Parameters

Parameter Analysis Cost (Thousand $2011)

Period Frequency Average Low Median High

Phase 1: Pre-operations

1 extraction/injection wells 

(EW/IW) (1 well per acre) 

44 1 year Quarterly

(4 events)

NRC and state 200 160 198 247

Down gradient ore zone 

monitoring wells (OZ-MW)

0 0 0 0 0

All perimeter ore zone wells 

(OZ-PW)

26 118 95 117 146

All vertical excursion wells 

(OW/UW)

15 68 55 68 84

Total wells sampled 85 386 309 383 478

Phase 2: Operations

All perimeter ore zone wells 

(OZ-PW)

26 6 years Biweekly

(156 

events)

Indicator parameters 2,327 2,137 2,293 2,587

Vertical excursion wells 

(Overlying/underlying wells: 

OW/UW)

15 1,343 1,233 1,323 1,493

Total wells sampled 41 6 3,670 3,370 3,616 4,080

Phase 3: Restoration (or 

compliance monitoring)

All extraction wells (EW) 77 2 years Quarterly

(8 events)

Indicator parameters 353 325 348 393

Down-gradient perimeter 

wells (OZ-PW)

6 28 25 27 31

(continued)
3-13

Table 3-2. ISR Conceptual Mine Unit: Current Practice (continued)

Well Type

Numbers 

of Wells

Sampling

Parameters

Parameter Analysis Cost (Thousand $2011)

Period Frequency Average Low Median High

Down-gradient ore zone 

monitoring wells (OZ-MW)

0 0 0 0 0

Total wells sampled 83 381 350 375 424

Phase 4: Stability (or postrestoration)

All extraction wells (EW) 77 6 months Quarterly

(2 events)

NRC and state 175 140 173 216

Down-gradient perimeter 

wells (OZ-PW)

6 14 11 14 17

Monitoring wells (OZ-MW) 0 0 0 0 0

Total wells sampled 83 189 151 187 233

Duration 

of 

Activities

Total 

Number of 

Sampling 

Events

9.5 years 170 Total costs: 4,626 4,180 4,562 5,213

Note: The “Well Type,” “Sampling Period,” “Sampling Frequency,” and “Parameters” criteria were based on discussions with the ISR project team during a 

phone conference on 3/26 and 4/16/2013. Total parameter costs include indirect labor, direct labor, travel, fee (8%), and contingency (10%).

1 There are approximately 243 injection (166) and extraction (77) wells shown in the model production area.

2 The “full suite” of chemical parameters includes EPA, NRC, and state required parameters. Based on parameter lists provided in the BID for Revision of 40

CFR Part 192, Revision 6, November 26, 2012. Indicator parameters are Alkalinity, Conductivity, TDS, Chloride, Uranium, and Radium 226 and Radium 228.

3 Range for duration of operations provided by EPA as documented during WA 2-04, Task 2B (contract No. EP-D-10-042).
3-14

Table 3-3. ISR Conceptual Mine Unit: 30-Year Stability Shortened with Geochemical Modeling

Well Type

Numbers 

of Wells

Sampling

Parameters

Parameter Analysis Cost (Thousand $2011)

Period Frequency Average Low Median High

Phase I: Pre-operations

Extraction/injection wells 

(EW/IW) (1 well per acre) 

44 1 year Quarterly

(4 events)

Full suite plus 

geochemical parameters 

and modeling

253 205 250 312

Down-gradient ore zone 

monitoring wells (OZ-MW)

10 58 47 57 71

All perimeter ore zone wells 

(OZ-PW)

26 150 121 148 184

All vertical excursion wells 

(OW/UW)

30 173 140 170 213

Total wells sampled 110 633 512 625 781

Phase 2: Operations

All perimeter ore zone wells 

(OZ-PW)

26 6 years Biweekly

(156 events)

Indicator parameters 2,327 2,137 2,293 2,587

Vertical excursion wells 

(Overlying/underlying wells: 

OW/UW)

30 2,685 2,466 2,646 2,986

Total wells sampled 56 5,013 4,603 4,940 5,573

Phase 3: Restoration

All extraction wells (EW) 77 2 years Quarterly

(8 events)

Indicator parameters 353 325 348 393

Down-gradient perimeter wells 

(OZ-PW)

6 28 25 27 31

(continued)
3-15

Table 3-3. ISR Conceptual Mine Unit: 30-Year Stability Shortened with Geochemical Modeling (continued)

Well Type

Numbers 

of Wells

Sampling

Parameters

Parameter Analysis Cost (Thousand $2011)

Period Frequency Average Low Median High

Down-gradient ore zone 

monitoring wells (OZ-MW)

10 46 42 45 51

Total wells sampled 93 427 392 421 475

Phase 4: Stability

All production unit wells 

(IW/EW)

77 3 years Quarterly

(12 events)

Full suite plus 

geochemical parameters

1,330 1,075 1,312 1,639

All perimeter ore zone wells 

(OZ-PW)

26 Indicator Parameters 242 196 239 298

All vertical excursion wells 

(OW/UW)

30 Indicator Parameters 403 326 398 497

Total wells sampled 133 1,716 1,430 1,692 2,068

Phase 5: Long-Term Stability

All extraction wells (EW) 77 7 years Quarterly

(28 events)

Full suite plus 

geochemical parameters 

and modeling

3,105 2,509 3,062 3,825

Down-gradient perimeter wells 

(OZ-PW)

6 242 196 239 298

Monitoring wells (OZ-MW) 10 403 326 398 497

Total wells sampled 93 3,750 3,031 3,698 4,619

(continued)
3-16

Table 3-3. ISR Conceptual Mine Unit: 30-Year Stability Shortened with Geochemical Modeling (continued)

Well Type

Numbers 

of Wells

Sampling

Parameters

Parameter Analysis Cost (Thousand $2011)

Period Frequency Average Low Median High

Duration 

of 

Activities

Total 

Number of 

Sampling 

Events

19 years 208 Total Costs: 11,539 9,968 11,375 13,515

Note: The “Well Type,” “Sampling Period,” “Sampling Frequency,” and “Parameters” criteria were based on discussions with the ISR project team during a 

phone conference on 3/26 and 4/16/2013. Total parameter costs include indirect labor, direct labor, travel, fee (8%), and contingency (10%).

1 There are approximately 243 injection (166) and extraction (77) wells shown in the model production area.

2 The “full suite” of chemical parameters includes EPA, NRC, state, and additional parameters needed for geochemical modeling. Based on parameter lists 

provided in the BID for Revision of 40 CFR Part 192, Revision 6, November 26, 2012. Indicator Parameters are Alkalinity, Conductivity, TDS, Chloride, 

Uranium, and Radium 226 and Radium 228.

3 Range for duration of operations provided by EPA as documented during WA 2-04, Task 2B (contract No. EP-D-10-042).
3-17

Table 3-4. ISR Conceptual Mine Unit: 30-Year Stability with No Provision to Shorten

Well Type

Numbers 

of Wells

Sampling

Parameters

Parameter Analysis Cost (Thousand $2011)

Period Frequency Average Low Median High

Phase I: Pre-operations

1 Extraction/injection wells 

(EW/IW) (1 well per acre) 

44 1 year Quarterly

(4 events)

Full suite 227 182 225 281

Down-gradient ore zone 

monitoring wells (OZ-MW)

0 0 0 0 0

All perimeter ore zone wells 

(OZ-PW)

26 134 107 133 166

All vertical excursion wells 

(OW/UW)

30 155 124 153 191

Total wells sampled 100 516 413 512 638

Phase 2: Operations

All perimeter ore zone wells 

(OZ-PW)

26 6 years Biweekly

(156 events)

Indicator parameters 2,327 2,137 2,293 2,587

Vertical excursion wells 

(Overlying/Underlying wells: 

OW/UW)

30 2,685 2,466 2,646 2,986

Total wells sampled 56 5,013 4,603 4,940 5,573

Phase 3: Restoration (or 

Compliance Monitoring)

All extraction wells (EW) 77 2 years Quarterly

(8 events)

Indicator parameters 353 325 348 393

Down-gradient perimeter 

wells (OZ-PW)

6 28 25 27 31

(continued)
3-18

Table 3-4. ISR Conceptual Mine Unit: 30-Year Stability with No Provision to Shorten (continued)

Well Type

Numbers 

of Wells

Sampling

Parameters

Parameter Analysis Cost (Thousand $2011)

Period Frequency Average Low Median High

Down-gradient ore zone 

monitoring wells (OZ-MW)

0 0 0 0 0

Total wells sampled 83 381 350 375 424

Phase 4: Stability (Postrestoration)

All production unit wells 

(IW/EW)

77 3 years Quarterly

(12 events)

Full suite 1,110 954 1,182 1,387

All perimeter ore zone wells 

(OZ-PW)

26 Indicator parameters 179 164 176 199

All vertical excursion wells 

(OW/UW)

30 Indicator parameters 207 190 204 230

Total wells sampled 133 1,495 1,308 1,562 1,816

Phase 5: Long-Term Stability

All extraction wells (EW) 77 30 years Quarterly

(120 events)

Full suite 11,910 9,535 11,818 14,728

Down-gradient perimeter 

wells (OZ-PW)

6 928 743 921 1,148

Monitoring wells (OZ-MW) 0 0 0 0 0

Total wells sampled 83 12,838 10,278 12,739 15,876

(continued)
3-19

Table 3-4. ISR Conceptual Mine Unit: 30-Year Stability with No Provision to Shorten (continued)

Well Type

Numbers 

of Wells

Sampling

Parameters

Parameter Analysis Cost (Thousand $2011)

Period Frequency Average Low Median High

Duration 

of 

Activities

Total 

Number of 

Sampling 

Events

42 years 300 Total Costs 20,243 16,952 20,128 24,325

Note: The “Well Type,” “Sampling Period,” “Sampling Frequency,” and “Parameters” criteria were based on discussions with the ISR project team during a 

phone conference on 3/26 and 4/16/2013. Total parameter costs include indirect labor, direct labor, travel, fee (8%), and contingency (10%).

1 There are approximately 243 injection (166) and extraction (77) wells shown in the model production area.

2 The “full suite” of chemical parameters includes EPA, NRC, and state required parameters. Based on parameter lists provided in the BID for Revision of 40

CFR Part 192, Revision 6, November 26, 2012. Indicator parameters are Alkalinity, Conductivity, TDS, Chloride, Uranium, and Radium 226 and Radium 228.

3 Range for duration of operations provided by EPA as documented during WA 2-04, Task 2B (contract No. EP-D-10-042).
3-20

the restoration process) and frequently introducing reducing agents to attempt to recreate the 

conditions that caused the deposit to form in the first place. Under all scenarios, wellfield 

restoration is assumed to last 2 years. Under current practice and under the 30-year alternative, 

83 wells are sampled for the purpose of obtaining data needed to construct a geochemical model 

of the groundwater chemistry. Under the proposed rule, 10 additional down-gradient ore zone 

monitoring wells are sampled for the purpose of constructing a geochemical model. Thus, during 

pre-operations, operations, and restoration, EPA’s costing assumptions result in somewhat higher 

costs under the proposed rule than would be incurred under current practice.

The major differences between current practice and the regulatory alternatives that were 

considered occur after restoration is assumed to be completed. Under current practice, facilities 

typically monitor conditions for 6 months to 2 years (we assumed 6 months), before 

decommissioning the wellfield and petitioning to have their license terminated. As discussed 

above, examination of the data has led EPA to conclude that this may not be a sufficiently long 

period of time to ensure that, as natural oxygenated groundwater begins to infiltrate the wellfield, 

uranium, radium, and other constituents may not remobilize. Thus, the two regulatory

alternatives examined incorporate a considerably longer period of post-restoration stability

monitoring. Initially, EPA’s proposed rule requires that sufficient data be collected to 

demonstrate with 95% confidence that conditions are stable for a period of at least 3 years. The 

data required would depend on site-specific conditions; based on the model site, EPA has 

assumed for the purposes of estimating costs that monitoring all production wells for the full 

suite of constituents and monitoring perimeter and vertical excursion wells for indicator 

parameters, on a quarterly basis for 3 years, would develop enough information to provide a 95% 

level of confidence that conditions are stable. Finally, both regulatory alternatives specify a 

period of long-term stability monitoring to ensure that conditions remain stable. Under the 

proposed rule, facilities have the option of reducing the 30-year long-term stability monitoring 

period by demonstrating through sampling and hydrogeochemical modeling that conditions 

down-gradient are sufficiently reducing that any constituents remobilized would be trapped 

down-gradient, preventing widespread contamination beyond the production zone. In the 

analysis, EPA assumes that this period of sampling and modeling (the long-term stability

monitoring period) lasts for 7 years.9In practice, this period may be longer or shorter depending 

on the natural variation observed in the monitoring data collected over that period and during the 

 

9 The assumption was made based on EPA’s professional judgment that 7 years represents a reasonable mid-range 

value, because EPA has reviewed at least one case study showing that monitoring with geochemical modeling at 

an ISR site has taken 15 years.
3-21

preceding stability phase monitoring. The larger the natural variation observed, the longer it 

would take to demonstrate that temporal trending is not present in the data. Under the other 

regulatory alternative, facilities would be required to conduct long-term stability monitoring for a 

period of 30 years, with no possibility for shorting the duration. Thus, the capital and analysis 

costs are higher under the proposed rule (as shown in Table 3-5), but the duration is much longer 

under the 30-year alternative.

Table 3-5 summarizes the differences in anticipated costs by phase, comparing the 

estimated costs under current practice with the estimated costs of the regulatory option being 

proposed and for another regulatory option considered but not selected. Costs for each phase are 

estimated to be lower under current practice than under the regulatory alternatives. Postrestoration stability monitoring, in particular, is estimated to have higher annualized costs and 

longer duration under the regulatory alternatives relative to current practice. Comparing the 

regulatory alternatives to each other, annualized costs are estimated to be higher for the proposed

rule, because it entails more wells and cores, geochemical modeling, and analyzing for more 

constituents. Only the operations phase has estimated costs that do not differ between the two 

alternatives. Although it does not appear in Table 3-5, the other difference between the two 

alternatives is that the selected alternative (30 years of long-term stability monitoring with the 

possibility to shorten the duration using geochemical modeling) is estimated to have a shorter 

duration than the alternative that was not selected (30 years of long-term stability monitoring 

with no potential to shorten the duration).

Table 3-5. ISR Conceptual Mine Unit: Annual Monitoring Cost by Scenario and Phase 

(Thousand $2011)

Current Practice

Low Average High

Phase 1. Pre-operational $309 $386 $478

Phase 2: Operations $562 $612 $680

Phase 3. Restoration $175 $191 $212

Phase 4. Stability $151 $189 $233

30-Year Stability with Geochemical Modeling

Phase 1. Pre-operational $512 $633 $781

Phase 2: Operations $767 $835 $929

Phase 3. Restoration $196 $213 $237

Phase 4: Stability $477 $572 $689

Phase 5. Long-term stability $433 $536 $660

(continued)
3-22

Table 3-5. ISR Conceptual Mine Unit: Annual Monitoring Cost by Scenario and Phase 

(Thousand $2011) (continued)

Current Practice

Low Average High

30-Year Stability with No Provision to Shorten

Phase 1. Pre-operational $413 $516 $638

Phase 2: Operations $767 $835 $929

Phase 3. Restoration $175 $191 $212

Phase 4: Stability $436 $498 $605

Phase 5. Long-term stability $343 $428 $529

3.2.1.2 Annualized Capital Costs and Incremental Costs of the Rule for the CMU

After the capital (well construction) and monitoring costs were estimated for the CMU 

under each regulatory alternative for each phase of ISR operations, the next step involves 

comparing the costs of each alternative with the costs incurred under current practice. To do this, 

EPA created a time series of monitoring costs under the current practice and under the three 

regulatory alternatives. EPA then annualized the capital cost under current practice and under the 

three regulatory alternatives, using a 7% interest rate and an assumed loan duration of 15 years 

(for current practice, which in our illustration is expected to have an overall duration of between 

10 and 15 years) or 20 years (for all regulatory alternatives). In each year, total annualized costs 

of compliance are the sum of the monitoring cost for that year and the annualized capital cost 

estimated to be incurred in that year. To measure the cost impact of each regulatory alternative, 

EPA computed the incremental compliance cost by subtracting the costs of compliance under the 

regulatory alternative minus the costs that would be incurred absent the proposed rule. For each 

stream of costs, EPA computed the total sum across all years and the discounted present value of 

each stream of costs using a 3% and a 7% discount rate. Finally, to obtain a single annualized 

cost value for current practice and for each regulatory alternative, EPA annualized the costs 

using a 7% interest rate over a period of 42 years. This treats all the costs in an equivalent 

manner and provides a single uniform annualized value for the monitoring costs under each 

regulatory alternative, which can be added to the annualized capital cost to provide a total 

annualized value that is uniform across time. Table 3-6 shows the annual cost, the sum, and the 

discounted values under 3% and 7% discount rates for monitoring costs, capital costs, and 

incremental costs.
3-2

3

Table 3-6. ISR Conceptual Mine Unit: Annualized Monitoring and Capital Costs for Current Practice and Each Regulatory 

Scenario (Thousand $2011)

With-Regulation Monitoring 

Costs Annualized Well Costs

Incremental Total Annualized 

Costs by Scenario, Relative to 

Current Practice

Current 

Practice

30 year, 

Geochemical 

Modeling

30-Year 

LongTerm 

Stability

Geochemical 

Modeling, 

Extended

Current 

Practice

30 year, 

Geochemical 

Modeling

30-Year 

LongTerm 

Stability

Geochemical 

Modeling, 

Extended

30 year, 

Geochemical 

Modeling

30-Year 

LongTerm 

Stability

Geochemical 

Modeling, 

Extended

Summed cost $4,626 $11,739 $20,243 $20,935 $8,418 $10,684 $10,522 $10,684 $9,379 $17,721 $20,935

NPV, 3% $4,029 $9,087 $12,155 $12,703 $6,699 $7,947 $7,703 $7,947 $6,306 $9,130 $12,703

NPV, 7% $3,396 $6,787 $7,487 $7,908 $5,111 $5,659 $5,429 $5,659 $3,939 $4,409 $7,908

Notes:

Capital costs are annualized as follows: 

Current Practice capital costs are annualized at 7% over 15 years, reflecting assumption that operations at a site would last at most 15 years.

Geochemical capital costs are annualized at 7% over 20 years, consistent with expected life of capital equipment.

30-year capital costs are annualized at 7% over 20 years, with an assumed 10% of wells requiring replacement after 20 years.

Incremental total annualized costs subtract the estimated annualized monitoring and capital costs for each regulatory scenario minus the estimated annualized 

monitoring and capital costs under current practice.
3-24

3.3 Estimated National Costs of Proposed Rule

The final step in estimating the costs of the rule and evaluating how they compare with

the costs of current practice requires extrapolating from the costs estimated for the CMU to 

estimated costs that apply to ISR facilities projected to exist in 2014. As mentioned in Section 2, 

above, six ISR facilities currently operate: La Palangana, Alta Mesa, Willow Creek (Christensen 

and Irigaray), Crow Butte, Lost Creek, and Smith Ranch-Highland-Reynolds. Several other ISR 

facilities are in various stages of licensing and are not in operation. The cast of ISR facilities in 

operation can be expected to vary over time, depending on uranium market conditions and how 

long it takes to extract the uranium from deposits at each facility. EPA has chosen to use the 

existing ISR operations in 2013 and the companies that own them as models for ISR facilities 

and owner companies likely to exist in the future and thus be affected by the proposed rule. EPA 

had some information about existing ISR facilities, but not sufficient information to estimate 

their costs on a facility-specific or wellfield-specific basis. Thus, it was necessary to extrapolate 

or scale up the costs estimated for the CMU to estimate costs that would be incurred by existing 

ISR facilities.

EPA examined three possible bases on which to extrapolate the CMU costs to estimate 

the costs that would be incurred at ISR facilities:

■ facility capacity

■ uranium production

■ wellfield acreage

After considering these options, as described below, EPA determined that extrapolation based on 

wellfield acreage is the most reasonable basis.

Facility capacity is reported by the EIA in its Uranium Production Report, so it is 

available for all planned and actual ISR facilities. However, facility capacity is measured in 

terms of the production capacity of the processing plant. Although this may be correlated to the 

size and complexity of the wellfield, and thus to the capital and operating costs of monitoring, 

the link is not close and would not seem to provide a reliable method of scaling site-specific 

costs to nationwide estimates.

Uranium production at a particular facility may vary widely from year to year because of

changing conditions in the uranium market or facility-specific factors. We do not, however, 
3-25

expect monitoring requirements or costs to vary significantly from year to year, although we 

recognize that they vary depending on the phase of the ISR operation.

Some correlation can generally be assumed between the size of the wellfield and the 

numbers of wells required for monitoring and, therefore, between the size of the wellfield and 

the corresponding well and groundwater sampling costs. Thus, EPA chose to use wellfield 

acreage as the basis on which to scale up costs from the CMU to the facility level. EPA obtained 

maps of wellfields or used available published information for the five existing ISR facilities to 

estimate the acreage of each wellfield. There is a large variation in the size of existing wellfields 

based on the information available from a variety of sources. Individual wellfield size for the 

sites considered ranges between approximately 7 acres and 750 acres. The total acreage of all the 

individual wellfields at each of the ISR sites considered is shown in Table 3-7. 

The costs that would be incurred by each ISR facility under current practice and under 

each regulatory alternative were estimated based on the ratio of the ISR facility’s total wellfield 

acreage to that of the CMU (see Table 3-7).

Table 3-7. Estimated Total Acreage of All Wellfields at ISR Sites

ISR Operation Acres

La Palanganaa210

Alta Mesa 330

Willow Creek 409

Crow Butte 1,524

Smith Ranch-Highlands-Reynolds 6,582

Lost Creek 254

Conceptual model unit 202

a Palangana total acreage scaled up by 50% to estimate area including PAA3.

Note: Most site acreages computed using site map and planimeter.

Table 3-8 shows estimated costs for each of the ISR facilities, based on the total acreage 

of the wellfield at each facility. EPA recognizes that not all the wellfields at all facilities may be 

in the same phase of uranium recovery at a given time; some may be in a planning stage, others 

actively being mined, while others are undergoing restoration and still others may be 

decommissioned. To evaluate potential impacts based on a conservatively high range of costs, 

we estimated costs using 100% of wellfield acreage at each facility to analyze the economic 

impacts of the proposed rule; generally, this overstates annual costs. An uncertainty in this 
3-26

approach relates to the potential for ISR sites to contain multiple ore zones within the same 

surface area (i.e., ore bodies located at different depths and separated by isolating beds), thereby

allowing sequential uranium recovery within the same surface footprint. In that situation, acreage 

Table 3-8. Total Average Annualized Incremental Costs for Individual ISR Operations 

(Thousand 2011$)

Regulatory Scenario

30 year, Geochemical 

Modeling to Shorten

30 Years, No 

Shortening

Geochemical 

Modeling, Extended

Cost per acre $1.45 $1.62 $1.86

ISR operation

La Palangana $304 $340 $390

Alta Mesa $477 $534 $613

Willow Creek $591 $661 $759

Crow Butte $2,205 $2,468 $2,832

Smith Ranch-HighlandReynolds $9,521 $10,657 $12,229

Lost Creek $367 $411 $472

National Cost $13,465 $15,072 $17,296

would not be as closely correlated with costs of complying with the rule. Facility-level 

incremental total annualized costs are estimated to range from $304,000 to $9.52 million10 under 

the proposed rule (30-year with geochemical shortening option), and from $340,000 to $10.7

million under the required 30-year monitoring option, when costs are calculated based on the 

entire wellfield acreage. Facility-level incremental total annualized costs were also estimated for 

the worst case scenario, under the proposed regulatory approach, to be from $390,000 to $12.2

million with the failure of geochemical modeling to predict a stabilized condition in the wellfield 

then requiring 30-years of long-term monitoring.

National costs computed using this assumption are $13.5 million for the proposed rule, 

30 years with geochemical modeling, and $15.1 million under the 30-year long-term stability

monitoring alternative. Under the scenario where geochemical modeling is followed by 30 years 

of long-term stability monitoring, average national total annualized costs are estimated to be 

$17.3 million. The well costs and the duration and frequency of sampling assumed for costing 

 

10 This represents the sum of estimated costs for Smith Ranch, Highland, and Reynolds.
3-27

these scenarios are different. The geochemical scenario incorporates additional well and boring 

costs and assumes fewer years of sampling are needed. The frequency of sampling is consistent 

between the scenarios considered but the geochemical modeling scenario accounts for additional 

constituents that will need to be sampled and monitored. Labor and other routine costs were held 

constant between the scenarios considered. Table 3-9 presents summary values for national-level 

costs, including annualized, summed, and discounted present value of costs. Finally, national 

well development capital costs are presented in Table 3-10. The well development costs for 

geochemical modeling with required 30-year monitoring are based on the well development 

costs for geochemical modeling.

Table 3-9. Estimated Average National Incremental Cost Summary (Thousand 2011$)

Regulatory Scenario

30 Year, 

Geochemical 

Modeling to 

Shorten 30 Years

Geochemical 

Modeling, 

Extended

Total annualized cost $13,465 $15,072 $17,296

Total cost, summed across LOM $431,284 $814,903 $854,177

Present value, 3% discount rate $289,991 $419,826 $456,257

Present value, 7% discount rate $181,135 $202,754 $232,673

Scaled up from CMU costs to national costs based on estimated total acreage. LOM is life of mine.

Table 3-10. Incremental Total Capital Costs (Thousand 2011$)

Cost, $

30 years with geochemical modeling $25,203

30 years long-term stability monitoring $19,339

Scaled up from CMU costs to national costs based on estimated total acreage.

3.4 Uncertainties and Limitations

EPA illustrated three regulatory alternatives using a CMU. As part of this exercise, we 

assumed the duration of each phase of the ISR monitoring operation. These durations are 

reasonable, but arbitrary assumptions. All could be longer, and all except the 30-year postmonitoring schedule under those regulatory alternatives could be shorter.

A major set of uncertainties arises from the process used to extrapolate from the 

estimated costs of each regulatory alternative at the CMU to costs that would be incurred by 

other ISR facilities. Due to limited resources and data accessibility, EPA’s cost estimates are 
3-28

based on a model facility approach, with the model derived from the characteristics of a single 

wellfield at one ISR facility. Additional data collection could help to refine these cost estimates; 

however, despite these limitations we believe that the cost estimates presented here would 

generally approximate those for mine units characteristic of other ISR sites. EPA also recognizes 

that compliance actions required at a particular site depend on the characteristics of the site; the 

characteristics of the CMU may not closely correspond to characteristics of other existing or new 

ISR facilities. Thus, the costs actual ISR facilities incur may differ from the costs described here. 

Further, EPA is using existing ISR facilities as models for future ISR facilities that may be 

subject to the proposed rule at different times in the future. Although future ISR facilities may

differ in various ways from existing ISR facilities, EPA nevertheless believes that the existing 

facilities provide the best guide available as to what future ISR facilities may be like.

Another uncertainty is the cost savings a facility may experience if it applies for and 

receives an ACL. EPA recognizes that ISR facilities that are attempting to restore and stabilize 

an ISR site may determine that they are unable to return contaminant concentration levels for all 

constituents to baseline/pre-operational levels as required. In that situation, facilities may apply 

for an alternative concentration limit for those constituents. Receiving approval of ACLs would 

likely enable the facility to stop its restoration/stabilization activities, rather than continuing 

efforts to achieve pre-operational levels of all constituents. This arrangement would likely reduce 

the number of years over which the site would have to be monitored. Obtaining an ACL would 

also entail some additional effort and cost associated with negotiating the ACL with the licensing 

agency. As an example of such costs, if a constituent (e.g., radium or a trace metal) remains 

above the restoration goal, the owner/operator may make an argument that the adverse health 

effects of the higher concentration level are not significant. In that example, a dose assessment 

would be part of the operator’s case to obtain an ACL and such an assessment would entail costs 

to gather data and perform the assessment. EPA does not have enough information to enable it to 

estimate the cost savings associated with ACLs, but we do recognize that there could be cost 

savings, relative to extensive efforts to achieve pre-operational levels for all constituents.

Requirements for licensing are described in 10 CFR Part 171.16, and financial assurance 

requirements for ISR operations are described in 10 CFR Part 40, Appendix A, Criterion 9. 

EPA’s proposed rule will not change the substance of the requirements affecting ISR facilities, 

but it will potentially change the duration over which a facility is subject to the requirements and 

thus incurs the costs. Because both types of requirements are set for the entire facility (although 

they vary depending on the activities currently under way at a facility), as long as any activity is 

under way at a facility, the facility will incur the costs of complying with the requirements. 
3-29

License fees range from $35,400 to $40,000 per year, but drop to zero if only decommissioning 

is occurring. Financial assurance costs continue through decommissioning, but decline as more 

of the site is decommissioned. Throughout the life of an ISR operation, the costs associated with 

licensing and financial assurance would, in EPA’s assessment, be unaffected by the proposed 

rule, until only one wellfield is still in operation or undergoing decommissioning. . The longer 

duration of monitoring required would cause the firms to incur the costs associated with financial 

assurance for a longer period of time (potentially 30 years). However, as the number of 

wellfields in operation declines, and the amount of radioactive material onsite declines, the 

magnitude of the financial assurance required would decline proportionally. EPA thus believes 

that the additional costs associated with payment of license fees and financial assurance would 

be small relative to other incremental costs and thus we did not include them in our quantitative 

estimate of costs and impacts.
4-1

Section 4

BENEFITS ANALYSIS

The benefits from revising Part 192 will primarily result from measures to prevent future 

occurrences of groundwater contamination and protection of groundwater resources for future 

generations. By requiring owners and operators of ISR facilities to take actions that ensure the 

long-term stability of geochemical conditions in on-site and nearby aquifers, the revisions will 

(1) help preserve the quality and quantity of increasingly scarce groundwater resources in the 

U.S., (2) reduce potential human and environmental health risks associated with contaminant 

exposures, and (3) avoid potential future remediation costs, which would be required if the 

existence and migration of groundwater contaminants were not detected prior to 

decommissioning the site. In addition, by incorporating constituent-specific standards that are 

flexibly referenced to SDWA and RCRA standards for groundwater contaminants, the proposed 

revisions will reduce the Agency’s administrative burden from periodically reviewing and 

revising standards to ensure consistency. In so doing, they will also incorporate recently revised 

and more protective standards for arsenic and uranium, which will also contribute to reduced 

risks to human health and the environment.

Due to data limitations and resource constraints the monetary value of these benefits 

cannot be fully quantified and aggregated across ISR sites in the U.S. However, it is possible to 

provide a detailed qualitative discussion and partially quantified description of the expected 

benefits of the proposed rule. The purpose of this chapter is to assist decision makers by 

providing this discussion and description of benefits.

4.1 Conceptual Framework and Methods for Valuing Groundwater Resources and 

Groundwater Protection

Water is vital to a productive and growing economy in the United States, directly and 

indirectly affecting the production of goods and services in many sectors. Current economic 

literature provides many insights into the importance of water to various sectors, including 

agriculture, tourism, fishing, manufacturing, and energy production, but this information is 

dispersed and, in many cases, incomplete. To take stock of what is currently known and where 

the main knowledge gaps lie, EPA has been conducting a study on the importance of water in the 

U.S. economy (U.S. EPA, 2012d). The main objectives of the study include (1) summarizing 

existing knowledge about the role and importance of water to the U.S. economy; (2) providing 

information that supports private and public sector decision-making, and (3) identifying areas 

with additional research needed. The draft findings show that, although water plays an essential 

and vital role in the economy, it is enormously difficult to place a monetary value on its 
4-2

contribution, in part because the value of water varies greatly both within and across sectors of 

the economy.

Although groundwater resources play a vital role in the U.S. economy, the economic 

value of these resources extends beyond their current contribution to market production. To 

understand and fully account for the contributions of groundwater to human well-being is useful 

to refer to the concept of “total economic value” (TEV) (Young, 2005). As shown in Figure 4-1, 

TEV includes both use and nonuse values.

Figure 4-1. Main Components of the Total Economic Value (TEV) of Groundwater

Resources

Use values include the well-being that is derived from direct use of the resource by 

individuals or households, for example as a source of drinking water. It also includes values from 

indirect use, such as through groundwater’s contribution to the production of goods or services 

people enjoy (e.g., agricultural commodities). As noted in a 1997 National Academy of Sciences 

study of groundwater valuation (NAS, 1997), use values for groundwater can also be divided 

into extraction value and in-situ value (also described as consumptive vs. nonconsumptive use 

values). Extraction value is widely recognized, and includes the value of groundwater used for 

drinking water, industrial water supply, and agriculture. Values for in-situ services are (or were 

in 1997) less well-known. They represent services or values that occur or exist as a consequence 

of water remaining in place within the aquifer. They include the capacity of groundwater to 

(1) buffer against periodic shortages in surface water supplies; (2) prevent or minimize 

subsidence of the land surface from groundwater withdrawals; (3) protect against sea water 

intrusion; (4) protect water quality by maintaining the capacity to dilute and assimilate 

groundwater contaminants; (5) facilitate habitat and ecological diversity; and (6) provide 
4-3

discharge to support recreational activities. One potential additional source of use values is 

“option value,” which refers to the value that humans derive today from preserving the option to 

use the resource (directly or indirectly) in the future.

Nonuse values refer to well-being derived from the resource that is not associated with an 

individual’s current or future use of the resource. Two main types of nonuse values are (1) the 

“existence” value that individuals may derive simply from knowing that a resource exists and is 

being protected, even if they do not or have no intention to use the resource directly or indirectly 

and (2) the “bequest” value individuals derive from know that a resource is being preserved for 

future generations to use.

One of the main challenges with valuing groundwater resources and their services is that 

they are typically not privately owned or exchanged in markets. As a result, one cannot rely on 

market prices for groundwater to infer its values. To address this problem, which is common for 

many public goods and natural resources, economists have developed variety of nonmarket 

valuation method. These methods are typically divided into two main categories: revealed and 

stated preference methods.

To infer nonmarket use values, revealed preference (RP) methods rely on information 

from market activities or other human behaviors that are related to the resource of interest. For 

example, the value of groundwater as an irrigation resource can be inferred from the value it 

contributes to products sold in agricultural markets. Similarly, the value of protecting 

groundwater quality as a source of household drinking water may be inferred from substitute 

sources of drinking water (e.g., bottled water prices) or from differences in housing prices in 

areas with different groundwater quality. Unfortunately, RP methods cannot be used to estimate 

nonuse values for natural resources, because they require a behavioral connection to the resource 

of interest in order to infer values.

The value of protecting groundwater quality may also, in some cases, be inferred from 

the avoided future costs of restoring the resource. This approach, which is sometimes grouped 

with RP methods, is meaningful if there is a high likelihood that (1) restoration activities will be 

implemented if groundwater contamination occurs and (2) restoration activities will not be 

needed if the groundwater is protected.

Stated preference (SP) methods employ household surveys to more directly measure 

people’s nonmarket values. To address the lack of existing markets for the good or service of 

interest, SP surveys present respondents with hypothetical markets or scenarios and elicit their 
4-4

willingness to pay (WTP) for defined changes (e.g., improvement in groundwater quality). One 

of the main advantages of SP methods is that they allow researchers to specifically define the 

nonmarket “commodity” of interest. Moreover, unlike RP methods, they can be used to capture 

and estimate nonuse value. The main drawback of these methods is that it is difficult to validate 

WTP estimates based on responses to hypothetical conditions.

A number of studies have used SP methods to estimate U.S. households’ WTP for 

protecting and improving groundwater quality; however, most of these studies were conducted in 

the 1980’s and 1990’s. Using meta-analysis, Poe et al. (2001) reviewed and synthesized key

findings from this empirical literature. In particular, they identified and analyzed 105 WTP 

estimates from 12 studies. They found that the types of groundwater changes described and 

analyzed in these SP studies varied widely, and consequently the mean annual WTP estimates 

also varied significantly from $46 to $1,316 (in 1997 dollars). Using a consumer price index 

adjustment, this range is equivalent to $64 to $1,844 in 2011 dollars.

Poe et al. used regression methods to investigate the main determinants of this variation 

in WTP. For example, they differentiated between studies that focused mainly on use-related 

values associated with drinking water protection and those that used a broader environmental 

perspective and included nonuse values related to aquifer protection. They found that including a 

nonuse perspective had a significantly positive effect on WTP. They also differentiated studies 

that specifically mentioned cancer risks associated with groundwater contamination. They found 

that WTP estimates were higher in these studies, but only at a moderate level of statistical 

significance.

4.2 The Benefits of Proposed Changes in Monitoring Requirements

The purpose of the proposed change in monitoring requirements, including requiring 

improved characterization of groundwater prior to uranium recovery and more extensive 

restoration and post-restoration stability monitoring, is to reduce the probability and magnitude 

of potential groundwater contamination incidents resulting from ISR operations.

Currently NRC allows ISR operators to terminate their license at the end of a relatively 

short (one to two years) stability monitoring phase. However, this practice means that any later 

contamination might not be detected and corrected in a timely manner. If oversight at these 

facilities ends before groundwater conditions have in fact stabilized, there is the potential for 

ongoing contamination.
4-5

Thus, the proposed rule’s provisions help to ensure that any potential excursions 

occurring after the completion of production operations are detected and corrected. As a result, 

they would ensure that groundwater and, potentially, the surface water to which it discharges, 

remain at levels the groundwater was restored to. Stability period monitoring ensures that the 

long-term trends in the groundwater concentrations stay within the target restoration 

concentrations ensuring the stability of the aquifer water quality and class of use required by 

regulatory authorities (Davis, 2007). This monitoring reduces the probability of water quality

degradation within the exempted aquifer, prevents further degradation of the overlying or 

underlying aquifer, and reduces the probability of aquifer degradation outside the ore zone. By

ensuring that groundwater conditions within the exempted aquifer are in fact stable, the proposed 

stability monitoring program will reduce the likelihood of undetected degradation of conditions 

in the exempted aquifer and adjacent aquifers. Thus, the proposed stability monitoring program 

would result in a higher probability that adverse human health and environmental impacts will be 

avoided.

There are several potential benefits associated with preventing groundwater

contamination due to post-restoration exceedances/excursions at ISR facilities. The following 

discussion describes three main areas and offers insights into the potential magnitude of these 

benefits.

4.2.1 Reducing Potential Human Health Risks Associated with Contaminant Exposures

If excursions occur from ISR facilities and aquifers are contaminated, the main potential 

risks for human health would be those associated with exposures to radionuclides in well water 

used for drinking or agriculture in areas located down-gradient from an ISR site. Most 

importantly, EPA considers all radionuclides to be known (category A) human carcinogens, and 

exposures to radiation can cause cancers in almost all tissues and organs in humans.11

To evaluate the potential human health risks that would occur if groundwater

contamination were to result from ISR operations, EPA evaluated a number of exposure 

scenarios and pathways (U.S. EPA, 2012c). The findings of this analysis indicate that the 

migration of contaminants into aquifers in the vicinity of an ISR site has the potential to cause 

significant exposures and risks for selected receptors. For example, the maximum of the 

estimated adult cancer risks from these scenarios was an increased latent cancer fatality risk of 

 

11 See for example EPA’s Users Guide for Radionuclide Carcinogenicity, found at 

http://www.epa.gov/radiation/heast/docs/heast_ug_0401.pdf
4-6

almost 5 in 1000 per year of exposure. However, due to the slowness of the groundwater

transport process, it could take several decades or more for the contaminants to reach downgradient wells that could potentially be used by humans. Also, the exposure scenarios examined 

in the analysis deal with failures of the ISR operations during the operating phase, such as leaks 

from extraction wells into overlying potable water aquifers or surface spills during operations. 

These scenarios can pose exposure risks, but implementing a robust regulatory regime during 

operations (the responsibility of the NRC or Agreement States) would minimize the potential for 

significant exposures.

Estimating the monetary value of health benefits from the proposed rule requires 

estimates of the expected number of cancer cases and fatalities that would be avoided. To 

estimate the benefits of avoided mortality risks from its programs and policies, EPA recommends 

multiplying the number of avoided deaths by a “value of statistical life” (VSL) concept, with a 

central default estimate of $8 million per avoided premature death. This VSL estimate is based 

on a review and synthesis of findings from several empirical nonmarket valuation studies, which 

estimate individuals’ WTP to reduce their own probability of premature death. Unfortunately, 

due to uncertainties and data limitations, including lack of certainty regarding the size of future 

populations in proximity to ISR operations, it is not possible to estimate these population-level 

risk changes for this rule; however, the VSL of $8 million at least provides a point of reference 

for understanding the potential value of health benefits of the proposed rule. It is also worth 

noting that the unit value for avoided cancer fatalities may be even higher than the $8 million 

VSL. Economic studies of VSL suggest that people value reductions in cancer risks by more than 

similar reductions in noncancer risks of mortality, because individuals fear the pain and other 

symptoms associated with cancer more than they fear, for example, traffic or work-related 

accidental death (U.S. EPA, 2010). Moreover, as previously described, the findings from the Poe 

et al. (2001) meta-analysis of groundwater valuation studies suggest that individuals place a 

particularly high value on avoiding groundwater contamination when cancer risks are involved.

4.2.2 Protecting Groundwater Resources for Future Generations

As described above, groundwater resources provide a wide variety of extractive, in-situ

uses, and nonuse values and services to human populations in the U.S.; however, the ability to 

sustain these services over the long term is being threatened by groundwater scarcity. Due to 

population growth and technological advances, the pace of groundwater extraction in the U.S. 

has increased significantly in the last 75 years (Reilly et al, 2008). As a result, declining 

groundwater resources are a growing concern in many parts of the country. Continuing 
4-7

population growth and the additional threats to water resources posed by climate change only

serve to reinforce these concerns.

Growing scarcity also means that existing groundwater stocks are becoming increasingly 

valuable. Therefore, even though the aquifers in the vicinity of ISR operations are currently 

providing relatively little extractive value (due to their locations in relatively sparsely populated 

areas), there are potentially significant longer term benefits to protecting these resources for 

future generations. The fact that ISR operations are mostly located in arid regions of the country

where water scarcity is a chronic problem further underscores the significance of these benefits.

Empirical evidence regarding these “bequest” values for protecting groundwater

resources is limited; however, the Poe et al. (2001) meta-analysis provides some insights into the 

magnitude of these nonuse values. In particular, valuation studies that focused broadly on aquifer 

protection, rather than more specifically on use values associated with drinking water protection, 

had average WTP estimates that were larger by $531-$736 per household.

4.2.3 Avoiding Potential Future Remediation Costs

Under current conditions, due to limited post-restoration monitoring by ISR operations, 

the potential exists for groundwater contamination to occur and go undetected over a long period 

of time. Such processes could occur if the initial injection of oxidizing agents into the deposit 

also destroyed the natural reducing capacity in the host rock that immobilized the uranium 

initially. Later injection of chemical reducing agents may then only produce a temporary 

reduction of uranium mobilized by the lixiviant injection. Over time the influx of oxidized 

groundwater from up gradient of the deposit may remobilize the uranium, radium, or other 

constituents, and result in contaminant migration down gradient.

If such contamination does occur and is only discovered after a long delay, extensive and 

costly remediation would most likely be required to remove the contaminants from the aquifer 

and reduce human health and environmental risks to acceptable levels. As the time period before 

detection increases, it is also likely that the spatial extent of contamination and the corresponding 

remediation costs would increase. A long delay before detection could also decrease the 

likelihood that the ISR owners/operators will be held responsible for the cleanup costs and 

instead the burden could be shifted to future taxpayers.

Consequently, one of the expected benefits of the proposed rule will be to increase the 

likelihood of detecting mobilized uranium, radium, or other constituents at an early stage and 

therefore avoiding costs associated with more extensive remediation activities. To analyze these 
4-8

avoided remediation costs, we used the model facility described in Section 3, and applied the 

parameters of this facility to develop cost estimates for alternative remediation scenarios. 

Appendix C provides a detailed description of the methods and assumptions used to construct 

these remediation cost estimates. Note that this is an illustration of potential costs and cost 

savings associated with the proposed rule for a model mine unit; because we have no idea of 

which (if any) wellfields would experience a remobilization after restoration, EPA is unable to 

estimate national cost savings from reduced remediation costs. 

As described in Appendix C, EPA used different assumptions about groundwater flow to 

estimate distance from the location where the constituents are first mobilized to the nearest 

monitoring well, and hence how long it would take for contamination to be detected. In addition, 

a variety of Kd

12 values were used, to reflect a variety of assumptions about how readily 

constituents are transported in groundwater. For purposes of this discussion, we focus on 

calculations assuming that Kd = 6.0E-06 m3/gm. The Kd variable is a site specific measurement 

and limited examples were found for actual ISR sites that were measured either as part of 

baseline or after restoration was completed. The value selected for modeling purposes was a 

referenced (F.J. Pearson Jr., C.J. Noronha, and R.W. Andrews, 1983) Kd measured at a roll front 

sandstone site and was used as a representative general condition.

To evaluate the potential magnitude of the benefits associated with avoided remediation 

cost, we compare two main scenarios. The first scenario represents conditions without the 

proposed rule. Under this scenario, contamination is detected after the site is decommissioned 

and the license is terminated.13 Three situations are examined: a small plume that is 

approximately 10% of the wellfield, or a larger plume that fills the entire wellfield. Once 

contamination is detected, this scenario estimates that remediation activities would continue for a 

period of 30 years (small plume) or 60 to 75 years (larger plume), involving pumping and 

treatment of contaminated groundwater from approximately 70 wells. For the larger plume, costs 

and duration vary depending on assumed direction of groundwater flow; we examine two 

possible directions because the current direction appears to be different from historical direction, 

possibly because of other mining activities in the area. Estimated total annualized costs of this 

 

12 Sorption partition coefficient that controls the degree of linear sorption represented by the model.

13 The actual time of detection depends on when someone drills a well in this location and tests the water at the 

correct time to detect the plume. In fact, if the facility has been decommissioned, it could be a long time before 

someone drills a well into the contaminated aquifer.
4-9

scenario range from $1.45 million (small plume) to $10.3 to $10.5 million (large plume).14

Because the site has been decommissioned and the license terminated, remediation costs might

be borne by the taxpayer. Total costs, as shown in Table 4-1, range from $35.3 million for a 

small plume to $586 million for a large plume, where the groundwater flows along the length of 

the wellfield.

The second scenario represents conditions with the proposed rule. In this case,

contamination is assumed to be detected during long-term stability monitoring. We use costs for 

the 30-year with no geochemical modeling alternative, and assume that monitoring within the 

wellfield detects an increased concentration of constituents ten years into the 30 year period. 

When the remobilized constituents are detected, the licensing agency would require the 

owner/operator to resume restoration activities, in an effort to achieve restored, stable conditions. 

To estimate the costs of this additional restoration, we use the estimated restoration costs for the 

original restoration phase. We assume that the second restoration would be successful and no 

further remobilization of constituents is detected. After this second restoration, the facility would 

monitor to ensure that constituent levels are stable at 95% confidence for 3 years, then continue 

to monitor to ensure that stability is maintained for 30 years. EPA estimates that the cost of these 

activities would total $27.1 million.

The resulting estimates of avoided remediation costs for the model facility are 

summarized in Table 4-1. The summary costs for each scenario are expressed as a lump sum 

value, computed by summing costs across time. The avoided remediation costs are calculated as 

the difference between the two scenarios. Therefore, for this example facility and postrestoration contamination profile, the estimated benefits from the proposed rule include a value 

of at least $8.2 million to nearly $560 million in avoided remediation costs, including both 

capital/well development costs and annual costs. 

In addition, the proposed rule is expected to shift the burden of required groundwater

cleanups from future taxpayers to the owners and operators of ISR facilities. By requiring ISR 

operations to conduct more extensive long-term stability monitoring, it is more likely that 

movement of contaminants will be detected in the short term while owners and operators are still 

responsible for the site. Conversely, it is less likely that contamination episodes will go 

undetected for years into the future and be detected only after the facility has been 

 

14 Note that these costs do not include costs of scoping efforts to identify the size of the plume and develop a 

remediation strategy.
4-10

decommissioned, thus reducing the probability of larger and taxpayer funded remediation 

activities.

Table 4-1. Summary of Avoided Remediation Cost Estimates for Model Facility with 

Post-restoration Groundwater Contamination (million 2011 $)

Plume Size and 

Groundwater Flow 

Direction

Sum of Costs Over Time

Without-regulation 

Scenario

(A)

With-Regulation: 

Compliance and 

Additional Restoration

(B)

Avoided Remediation 

Costs

(A) − (B)

Small Plume $35.3 $27.1 $8.20

Large Plume, Transverse $481.0 $27.1 $453.1

Large Plume, Along $586.1 $27.1 $559.0

Further, the proposed rule, with its geochemical modeling and monitoring components, 

provides both the regulator and the public with evidence that restored wellfield conditions will 

remain stable into the future and that the operator can be released from a 30-year long-term 

stability monitoring requirement and the site decommissioned, with greater confidence in its 

long-term safety than could be achieved based on monitoring alone.

4.3 Setting Groundwater Protective Standards

The second component of the revised regulation aligns the groundwater standards to 

current regulatory criteria (i.e., primary and secondary maximum contaminant levels (MCLs) 

under the SDWA and/or maximum concentration of hazardous constituents for groundwater

protection under RCRA). The primary benefit to households of revising the standards will be 

reduced risk of adverse human health and environmental impacts.

As proposed, the revisions will reduce the need for EPA to update the regulations each 

time a standard changes and avoid the rulemaking process for each update, thus reducing future 

regulatory burden on both EPA and the regulated community. Rather, EPA would take comment 

during the rulemaking process for the primary rule that is being changed. Currently the list of 

groundwater standards is out of date and not aligned to SDWA and RCRA. Aligning the 

standards will ensure that the standards stay current with other regulations and increase the 

probability that society will be protected from risks to human health and the environmental. The 

requirement requires that regulators and operators update their plans based on the latest 
4-11

standards, but it relieves EPA of the costs associated with updating the regulation each time a 

standard is changed and ensures that there are no lags in updating the standards, which would 

potentially expose the public to risks.

4.4 Comparison of Benefits and Costs of the Proposed Rule

Since EPA conducted a qualitative assessment of the benefits of the proposed rule, a 

direct quantitative comparison of total benefits and costs is not possible. However, the analysis 

described in this section does provide some limited insights into the relative magnitude of costs 

and benefits. In particular, for the model facility with a defined excursion of groundwater

contamination, the estimated net present value of avoided remediation costs is at least $35.0

million, whereas the NPV of monitoring costs plus a second remediation has an estimated NPV 

of $11.0 million, based on average costs and using a 3% discount rate. Therefore, for this 

example, the cost avoidance benefits exceed the costs. Whether this relationship holds at an 

aggregate level, however, depends importantly on (1) the likelihood of groundwater

contamination events across all sites and (2) the similarity of conditions at other sites to those at 

the model facility.

4.5 Caveats and Uncertainties

Although the proposed rule is expected to provide substantial benefits by helping to 

ensure that potential groundwater contamination occurrences from ISR operations are promptly

detected and addressed, it is not possible to reliably quantify the total magnitude of these 

benefits. One of the main sources of uncertainty is a lack of adequate data and models for 

estimating a full probability distribution of all alternative groundwater contamination scenarios 

across all current and future ISR sites. Instead, to provide a general understanding of avoided 

remediation costs and avoided health risks, EPA has examined a limited number of groundwater

contamination scenarios at a defined site to illustrate the magnitude of potential remediation 

costs. It should not be assumed that all restored ISR wellfields will fail in the long-term. A 

second important source of uncertainty is for estimating benefits is the very long term nature of 

potential groundwater contamination episodes. Although future generations will certainly benefit 

from avoided contamination, it is very difficult to reliably predict the size and locations of 

potentially affected future populations.
5-1

Section 5

ECONOMIC IMPACT ANALYSIS

EPA examined the economic impacts that may result from the proposed rule, using 

information about the industry and estimated incremental costs that would result from the 

proposed rule and from one additional regulatory alternative, and employing accepted economic 

analysis methods.

5.1 National Costs

EPA first estimated the total annualized national cost of the proposed rule, as a measure 

of the overall impact the proposed rule might have on the uranium industry and the national 

economy. As described in Section 3, EPA estimated the incremental annual costs of monitoring 

for ISR facilities; EPA first estimated the costs under current practice and under two regulatory 

alternatives for a conceptual mine unit (CMU) model facility. Incremental costs were computed 

by subtracting the estimated base case costs from estimated costs under the two regulatory

alternatives. EPA then scaled up the estimated incremental costs for the CMU to costs that would 

be incurred by facilities such as the five ISR facilities expected to be operating in 2014, the 

effective date of the proposed rule, based on the ratio of the wellfield acreage at each facility to 

the wellfield acreage of the CMU. EPA illustrated the range of costs that may result from the 

proposed rule using average, low, and high costs of monitoring. This approach makes the 

conservative high-cost assumption that all wellfields at each facility would be in some stage of 

pre-operations, operations, restoration, stability, or long-term stability monitoring (and thus 

affected by the proposed rule) in 2015.

Estimated national total annualized costs based on average monitoring costs are shown in 

Table 3-9, above, and used in this analysis. National costs based on low and high monitoring 

costs are shown in Appendix D. Depending on the assumptions used to compute the national 

costs, EPA’s cost estimates varied widely, ranging from $11.6 million to more than $17.9

million. EPA examined the potential costs of the provisions of the proposed rule (30-year 

stability monitoring with the potential to reduce the duration if geochemical modeling 

demonstrated that wellfield conditions would remain stable); EPA also examined the potential 

costs of one regulatory alternative that was considered and rejected: 30-year stability monitoring 
5-2

with no potential to reduce the monitoring duration.15 EPA chose to propose 30-year long-term 

stability monitoring with geochemical modeling because this standard has the advantage of being 

less costly than the 30-year monitoring alternative, and it demonstrates that conditions will 

remain stable or that conditions down-gradient will trap any mobilized constituents, thus 

ensuring that groundwater quality is protected. The regulatory alternative of 30-year stability 

monitoring with no provision to reduce the duration was rejected because it is generally expected 

to be more costly and less protective than the proposed alternative; even monitoring for 30 years 

does not guarantee that wellfield conditions will not degrade in the future. The remainder of the 

economic impact analysis thus focuses on the impacts of EPA’s proposed rule. Analytical results 

for the 30-year stability monitoring with no provision for shortening are found in Appendix D. In 

addition, Appendix D provides results of a simulation reflecting the possibility that geochemical 

monitoring will reveal geochemical conditions in and around the wellfield that would not 

guarantee long-term stability—a “worst case” cost scenario. If that occurred, we expect 

regulators to require 30 years of long-term stability monitoring. EPA analyzed the costs and 

economic impacts that would occur if all ISR facilities had this experience, although that is 

unlikely to occur in actuality. As noted in Section 3 above, this scenario would only be realized 

if pre-operational monitoring and geochemical modeling indicated the site was safe to develop, 

but post-operational sampling and modeling gave a different result. If pre-operational sampling 

and modeling indicated that conditions are not sufficiently reducing to ensure long-term stability, 

EPA expects that either the owner operator would choose not to develop, or the licensing 

authority would not issue a license. Thus, this worst case is unlikely to occur.

Based on the proposed 30-year long-term stability monitoring with geochemical 

modeling using average monitoring costs and assuming that all wellfields are affected, EPA 

estimated that national total annual costs of complying with the proposed rule would be 

approximately $13.5 million (see Appendix D for the range of national costs estimated for the 

geochemical modeling alternative). Compared with the U.S. economy as a whole, these total 

annual costs are not extremely large. However, the uranium industry is small, with relatively few 

firms. Compared with the industry sales (estimated to be $3.0 billion in 2015 based on a uranium 

price of $57 per pound), these estimated total annualized costs comprise about 0.4% of estimated 

2015 sales. EPA thus conducted a more in-depth assessment of potential impacts on the market 

for uranium and on firms in the industry.

 

15 EPA also considered another regulatory alternative: a narrative standard with no fixed monitoring period. Because 

the compliance requirements under this alternative would be determined by the licensing body and thus 

extremely site and case specific, EPA did not estimate costs or impacts for this alternative.
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5.2 Market Impact Assessment

To illustrate likely impacts of the proposed rule on the market for uranium, EPA 

developed a simplified model of the U.S. market for uranium, using projected quantities of 

uranium purchased by COOs in 2015, the effective date of the proposed rule. The U.S. Energy

Information Administration projects that uranium purchases by U.S. COOs will increase between 

2010 and 2040 at a rate of 0.2% per year. Using this rate of growth, EPA estimates that in 2015, 

COO purchases will have grown from 57.4 million pounds (2013) to 57.6 million pounds. Over 

the period 2000 to 2013, the share of COO purchases supplied by U.S.-origin uranium averaged 

16.4% (EIA, 2014b). Assuming that the share of that quantity coming from domestic-origin 

uranium in 2015 reflects this historical pattern, EPA estimated that in 2015, COOs will purchase 

9.45 million pounds of domestic-origin uranium. Using the projected market price and quantity, 

EPA applied the costs of complying with the proposed rule and simulated market responses, 

including changes in market price and quantity, and changes in the share of the market 

represented by domestic supply and imports. Table 5-1 shows projected 2015 conditions in the 

U.S. uranium market, which estimate quantities and prices without the proposed rule, and form 

the basis for the market impact simulations.

Table 5-1. Projected U.S. Uranium Market Conditions, 2015

Market Conditions

Supply (million pounds) 57.630

U.S. Origin Uranium 9.451

Foreign Origin Uranium 48.179

Price $57.00

5.2.1 Market Simulation Model

EPA used a partial equilibrium model of the U.S. market for uranium to analyze the 

impacts of the proposed rule. Market supply is defined as the sum of domestic-origin uranium 

purchased and foreign-origin uranium. Domestic demand for uranium is a function of the 

demand for electricity and is represented by projected purchases of U.S. COOs. Figure 5-1 

illustrates a market in which some suppliers of the product are affected by the proposed rule and 

others (such as foreign suppliers) are not. Promulgation of the proposed rule would increase the 

costs of supplying uranium for ISR facilities, thus shifting their supply curve upward, and the 

market supply curve upward by a lesser amount. As a result, the with-regulation equilibrium 

price is slightly higher, and the with-regulation equilibrium market quantity slightly lower. The 
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unit cost of complying with the rule (the vertical shift in the supply curve for affected facilities) 

is greater than the increase in the market price. Because unaffected facilities respond to the 

increased market price by increasing the quantity of uranium they supply the market, affected 

facilities are unable to pass along much of their increased costs to their customers, and the 

a) Without-Regulation Equilibrium

b) With Regulation Equilibrium

Figure 5-1. Market Equilibrium Without and With Regulations

profitability of their operations declines. Thus, the quantity of uranium supplied by U.S. ISR 

facilities declines, while the quantity of uranium supplied by unaffected suppliers increases. The 

partial equilibrium model used by EPA quantifies estimated market impacts, as described below.
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5.2.2 Characteristics of Market Demand for Uranium

Uranium is an input into the production of electricity. Thus, the demand for uranium is 

derived from the demand for electricity. The responsiveness of the demand for uranium to 

changes in the price of uranium is measured by the elasticity of demand for uranium (computed 

as the percentage change in the quantity of uranium demanded divided by the percentage change 

in its price). Elasticity values are typically negative, because increases in price typically cause 

demanders to want to purchase less of a commodity, if all the other influences on uranium 

demand are held constant. Elasticity values greater than one in absolute value are termed elastic 

and indicate demand that is responsive to changes in price. Elasticity values below one in 

absolute value are termed inelastic. The closer the value is to zero, the less responsive demand is 

to changes in price. EPA’s assessment indicates that the demand for uranium is very inelastic.

Economists compute the elasticity of demand for an input as a function of

■ the elasticity of demand for the final product,

■ the elasticity of substitution between the input and other inputs,

■ the elasticity of supply of other inputs, and

■ the cost share of the input as a share of the cost of the final product, in this case 

electricity.

The elasticity of demand for electricity is low, approximately −0.3. The elasticity of 

substitution between fuels in production of electricity is also low. The cost of uranium typically 

represents between 0.2% and 0.4% of the cost of electricity. Using these values, we estimated the 

elasticity of demand for uranium to be about −0.07%. This very low elasticity value indicates 

that changes in the price of uranium do not result in great changes in the quantity of uranium 

purchased. Another way of looking at this is to say that the demand for uranium responds less to 

changes in its price than to other factors affecting demand, such as the share of electricity

produced using nuclear power, the price of alternative energy sources for electricity generation, 

and operating status of U.S. nuclear power plants, for example.

5.2.3 Characteristics of Market Supply

The responsiveness of supply to changes in price is similarly measured by an elasticity of 

supply, computed as the percentage change in quantity supplied divided by a percentage change 

in price. When price increases, uranium firms will respond by increasing uranium production, 

because at higher prices, more uranium sources will be profitable to operate. Currently, several 

ISR facilities are not operating because the market price has been too low to make operation 
5-6

profitable. Further, several ISR facilities are licensed and permitted but have not been 

constructed. If price rises as projected, some of these sources may be brought online. EPA uses a 

supply elasticity of two to measure the price-responsiveness of both domestic supply and import 

supply. Historically, because of the presence of large stockpiles of uranium, supply has been 

quite responsive to price. However, there is evidence that this is changing, because stockpiles are 

being drawn down. Thus, in the future, uranium supplied will generally be from recent 

production, which is expected to be less responsive to price changes than are supplies drawn 

from inventories or stockpiles. A supply elasticity of two is consistent with values from the 

literature (University of Chicago, 2004; Ux Weekly, 2004).

5.2.4 Impacts of the Proposed Rule

Based on average monitoring costs and assuming 100% of each facility’s wellfields are 

affected simultaneously, implementation of the proposed rule would increase the cost of 

producing uranium at ISR facilities by $1.50 per pound of uranium. Neither the cost of 

production using conventional technologies nor the cost of uranium from foreign sources would 

be affected. Incremental costs of complying with the proposed rule are estimated to be 

approximately 2.6% of baseline market price.

The increased costs incurred by ISR facilities would increase the cost of domestic 

production overall. Given the characteristics of demand and supply described above, economic 

theory would predict that the market price of uranium would increase, and the quantity of 

uranium purchased would fall somewhat. Because imports are a large share of total supply and 

their costs would not be affected by the rule, domestic suppliers of uranium would have a limited 

ability to pass the costs of compliance to their customers through price increases. EPA thus 

estimates that the market price of uranium would increase by only a fraction of the rule’s cost per 

pound, the share of uranium purchased from domestic sources would decline, and the share of 

foreign-origin uranium imports would increase, if all market conditions other than the proposed 

rule are held constant.

5.3 Summary of Economic Impact Results

Table 5-2 shows EPA’s market impact analysis results. These results should be 

interpreted as an illustration of the relative impacts on the U.S. uranium market as a whole and 

on domestic suppliers, demanders, and foreign trade, rather than a specific prediction of market 

outcomes.

Using a 2015 projected baseline, initial market quantity is approximately 57.6 million 

pounds of U3O8, of which an estimated 9.45 million pounds are of domestic origin and 48.2
5-7

million pounds are imported. Baseline price is assumed to be $57 per pound. After the market 

adjusts to costs of compliance with the proposed rule in effect, increasing the costs of ISR 

production by $1.50 per pound, the overall quantity of uranium demanded by U.S. COOs is 

projected to decline by about 15.9 thousand pounds (0.03%), and the price of uranium is 

estimated to increase by approximately $0.24 (0.4%). The quantity of domestic-origin uranium 

purchased is projected to decline to 9.03 million pounds, a decline of approximately 4.4%, while 

COO purchases of foreign-origin uranium are estimated to increase by 0.8%.

Table 5-2. Market Impacts of Proposed Rule based on Average Costs, 2014

Baseline

30 Years, Geochemical Modeling to 

Shorten 30 Years

Supply (million pounds) 57,630 57,614 57,612 

U.S. origin 9,451 9,032 8,982 

Foreign origin 48,179 48,582 48,631 

Price ($/pound) $57.00 $57.24 $57.27 

Change in price $0.24 $ 0.27

Percentage changes

Market quantity −0.03% −0.03%

U.S. origin −4.4% −5.0%

Foreign origin 0.8% 0.9%

Price 0.4% 0.5%

Incremental cost per pound of 

uranium $1.50 

$1.68 

5.4 Employment Impacts of the Proposed Rule

According to the U.S. Census Bureau’s Statistics of U.S. Business (Census, 2013), in 

2011 the uranium and vanadium mining industry had 670 employees. Assuming that 

employment in the uranium and vanadium industry increases at the same rate as production, 

employment in 2015 is projected to be 682.

16

Assessing the impact of the proposed rule on employment requires consideration of 

factors that tend to decrease employment and factors that tend to increase it. Assuming 

 

16 Note that the companies owning operating ISR facilities have more than 1,400 employees; however, not all of 

these employees work in the United States.
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production employment in the U.S. uranium industry declines by approximately the same 

percentage as output is estimated to decline, EPA estimates that production employment in the 

U.S. uranium industry would fall by approximately 30 full-time equivalent employees. However, 

EPA’s assessment is that this computation overestimates the decline in employment. First, 

although ISR is the dominant form of uranium production in the United States, it is less labor

intensive than conventional mines and mills. Not all the industry’s employees work at ISR 

facilities, so the actual reduction in ISR facility employment would be smaller than estimated. 

Further, because of the labor needed to implement the provisions of the proposed rule, EPA 

expects a countervailing increase in employment in the industry. To comply with the proposed 

rule, ISR operations may increase their environmental compliance staff to conduct the additional 

monitoring. To the extent that facilities install more monitoring wells than they would have at 

baseline, well-drilling employment may also increase. In addition, outside the uranium and 

vanadium industry, laboratories that analyze groundwater samples may also increase their 

employment somewhat, in response to an increased demand for analysis. Thus, it is difficult to 

estimate either the direction or the magnitude of overall employment impacts that would result 

from the proposed rule.

5.5 Impacts on Small Entities

Under the RFA, as amended by SBREFA, EPA is required to evaluate the impacts on 

small entities affected by its rulemakings. Small entities include small businesses, small 

governments, and small nonprofits. Small governments and small nonprofits are not expected to 

be affected by the proposed rule; however, two of the firms owning currently operating ISR 

facilities, and five additional firms owning planned or standby facilities are small businesses, 

based on the SBA’s criterion for NAICS 212291: 500 or fewer employees. It is important to note 

that the size determination is made at the owner-company level. Uranium companies frequently

have complicated ownership structures, with several layers of ownership. To accurately assess 

the vulnerability of the firms owning ISR operations, it is the ultimate parent company’s size that 

should be considered. If a small company is actually a subsidiary of a larger company, the impact 

on the larger company is examined. However, where a larger company is a shareholder in a small 

company but the small company is nevertheless an independent entity, EPA evaluated the 

impacts on the small company.

EPA assessed the potential for adverse impacts on small businesses by estimating the 

costs that would be incurred by the firms that own existing facilities, then comparing those 

estimated costs to the firms’ revenues. EPA’s guidance on complying with the RFA and 

SBREFA (2006) establishes criteria for significant impacts: if the proposed rule’s costs are less 
5-9

than 1% of sales, impacts are deemed insignificant. If costs exceed 3% of sales, significant 

impacts are likely. Between 1% and 3% of sales, impacts may or may not be significant. EPA 

adopted these criteria in determining whether the proposed rule’s impacts on small businesses 

are significant.

In Table 5-3, EPA compares the estimated costs for firms owning existing ISR facilities 

to their sales. Of the four firms owning existing ISR facilities, three are small according to the 

SBA’s definition for NAICS 212291, because they have fewer than 500 employees. 

Table 5-3. Estimated Impacts of the Proposed Rule on Small Entities

Parent Company

(ISR Facilities)

Small 

Business

Annual Sales 

(millions USD)

Estimated Cost to Sales Ratio

Low Average High

30 Years with Geochemical Modeling 

to Shorten

Cameco Corporation

(Crow Butte, Smith Ranch-HighlandReynolds)

No $2,400.0 0.4% 0.5% 0.6%

Mestena Uraniuma 

(Alta Mesa)

Yes $28.5 1.4% 1.7% 1.9%

Uranium One, Inc.

(Willow Creek)

No $530.4 0.1% 0.1% 0.1%

Uranium Energy Corp.a 

(Hobson-La Palangana)

Yes $28.5 0.9% 1.1% 1.2%

Ur-Energy (Lost Creek) Yes $57.0 0.6% 0.6% 0.7%

30 Years, No Option to Shorten

Cameco Corporation

(Crow Butte, Smith Ranch-HighlandReynolds)

No $2,400.0 0.5% 0.5% 0.6%

Mestena Uraniuma 

(Alta Mesa) Yes $28.5 1.6% 1.9% 2.2%

Uranium One, Inc.

(Willow Creek) No $530.4 0.1% 0.1% 0.1%

Uranium Energy Corp.a 

(Hobson-La Palangana) Yes $28.5 1.0% 1.2% 1.4%

Ur-Energy (Lost Creek) Yes $57.0 0.6% 0.7% 0.9%

a To assess impacts on the small firms companies based on typical operations, EPA estimated sales revenues based 

on the facility’s estimated production and market price. For the two large firms, 2013 reported sales were used.

small firm, Mestena Uranium, no data on sales are available. EPA estimated Mestena’s 2015

sales revenues by first estimating their production, then multiplying estimated production times

the projected 2015 price of uranium. For Mestena’s Alta Mesa ISR operation, EPA estimated 
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2015 production to be 500,000 pounds. At $57 per pound, which is the projected price of U3O8 in 

2015, Mestena’s estimated revenue from uranium sales would be $28.5 million. Another small 

firm, Uranium Energy Corporation (UEC), reported that it had sold 220,000 pounds of uranium 

in 2013 for $9.0 million. Based on projections that the market for uranium will have recovered 

somewhat by 2015, EPA estimates that UEC also will sell 500,000 pounds of U3O8 in 2015, with 

estimated revenues of $28.5 million. The third small business, Ur-Energy, stated in its 2013 

Annual Report that it planned to sell 1,000,000 pounds of U3O8 from its Lost Creek operation in 

2014. EPA thus assumed that 2015 production at Lost Creek would again be 1,000,000 pounds 

and that Ur-Energy’s revenues for the year would be $57 million. For the two large firms, 

Cameco and Uranium One, EPA used 2013 reported sales as the estimate for 2015 sales.

EPA’s analysis estimates that average estimated costs of complying with the proposed 

rule represent between 0.6% and 1.9% of estimated revenues for the three small businesses, and 

between 0.1% and 0.6% of revenues for the two businesses that are not small. Even using the 

high estimated costs and making the unrealistic assumption that 100% of facilities’ acreage 

would be involved in operations regulated under the proposed rule at a given time, the maximum 

cost-to-sales ratio is 1.9%. For none of the firms analyzed does EPA’s analysis indicate that costs 

of the proposed rule would exceed 2% of company sales revenues. EPA has chosen to analyze 

the possible impacts on companies owning ISR facilities using information about the companies 

that own existing ISR operations because they are believed to be representative of companies 

that may own ISR facilities in the future. EPA examined financial information for some firms 

that own planned facilities. However, it is unclear when and indeed whether these ISR facilities 

may begin producing uranium. Without this information about planned production, EPA was 

unable to include them in the analysis. Thus, the results in Table 5-3 include only firms that own 

existing ISR facilities.

Using these companies as representative of companies that may own ISR facilities 

affected by the proposed rule and estimating revenue for the small firms based on estimated 

production in 2015, EPA found that their costs would be between 0.6% and 1.9% of firm 

revenue, based on average compliance costs, and at most 2.2% based on high-cost estimates. 

Further, EPA estimates that fewer than 10 small businesses would be affected by the proposed 
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rule at any time in the future. Thus, EPA thus does not expect the costs of complying with the 

proposed rule to result in significant impacts to a substantial number of small firms.17

5.6 Uncertainties

For a given ISR operation, the costs of complying with the proposed rule are a function 

of the characteristics of the wellfields at that operation. Unfortunately, EPA does not have 

detailed descriptions of the mine units at existing ISR operations and thus cannot directly 

estimate the costs that would be incurred for individual wellfields. Instead, EPA estimated the 

costs of complying with the proposed rule for a CMU and scaled the costs up, proportional to 

total acreage, to estimate the costs for each ISR facility. This approach implies that costs are a 

function of wellfield size and does not take into account the other facility-specific factors that 

would affect costs. For example, in the case of a site composed of more than one distinct ore 

zone within its footprint, costs would be underestimated because more monitoring and sampling 

would be conducted than assumed in the scaling calculations reported here. Unfortunately, in the 

absence of wellfield-specific data, EPA is unable to assess whether costs for a particular ISR 

facility are overestimated or underestimated.

EPA estimated the costs of undertaking additional monitoring at the pre-operational, 

operational, restoration, stability, and long-term stability monitoring stages. Incremental costs 

were computed by subtracting estimated costs of current compliance practices from the estimated 

costs of compliance under the proposed rule. EPA recognizes that many of the provisions of the 

proposed rule are embodied in existing permits and licenses. Therefore, the incremental costs of 

the proposed rule are somewhat overstated. However, EPA is unable to determine the exact 

magnitude of this effect.

EPA has analyzed the potential economic impacts of the proposed rule and possible 

impacts on both small and large owner companies using information about the projected 2015

conditions in the market for uranium and companies owning existing ISR facilities. The 

proposed rule will take effect in 2015 and affect ISR facilities that operate from that time, going 

forward. Conditions in the uranium market are volatile; the price of uranium and the market 

share of U.S. producers have historically been variable. The market price of uranium is projected 

to increase to about $57 per pound of U3O8 equivalent, from a 2013 price of about $52 per 

 

17 Cost-to-sales ratios for firms owning ISR operations under different regulatory alternatives are shown in Table D3. Even for the highest cost assumptions and the most costly regulatory alternative, costs represent at most 2.7% 

of estimated firm sales. These estimates support EPA’s findings that there would not be a significant economic 

impact to a substantial number of small entities.
5-12

pound. If that occurs, several of the facilities that are currently idle or that are in the process of 

being licensed may begin production. Revenues for firms owning ISR uranium facilities would 

certainly increase, if both production and price rises. However, EPA is unable to estimate how 

those changes would affect estimated market impacts and impacts on small entities and has made 

conservative assumptions about the quantities of U3O8 that would be produced by these facilities. 

Also, although the EIA projects that both purchases of uranium and its price will increase by

2015, the price of uranium has recently been declining, because of the combined influences of 

the Fukushima earthquake and tsunami and the global economic downturn. If the market for 

uranium does not recover as projected, 2015 conditions could reflect lower purchases and prices 

than are estimated in this study. EPA used publicly available sales revenue data for two large 

firms owning ISR facilities. For the small entities, EPA first estimated 2015 production by

estimating 2015 production levels based on their capacity and recently reported production 

levels, adjusted to reflect somewhat higher prices and production in 2015. EPA then estimated 

revenues for these firms by multiplying the estimated production times the projected 2015 price 

of $57 per pound. These estimates are thus based on EPA’s projections of 2015 conditions in the 

uranium market; both production and the price of uranium in 2015 are uncertain.
6-1

Section 6

STATUTORY AND EXECUTIVE ORDER REVIEWS

6.1 Synopsis

This section summarizes the statutory and Executive Order (EO) impact analyses relevant 

for Proposed Revisions to 40 CFR Part 192, Health and Environmental Protection Standards for 

Uranium and Thorium Mill Tailings. For each EO and statutory requirement, we describe both 

the requirements and the way in which our analysis addresses these requirements.

EPA has concluded that ISR uranium facilities, if not adequately monitored during and 

after operations, have the potential to pollute adjacent groundwater aquifers if geochemical 

conditions in the wellfield change after restoration so that uranium is once again mobilized. Such 

pollution would potentially impose costs on people who are neither buyers nor sellers of u ranium 

(thus, external to the market) who may be exposed to pollutants in down-gradient aquifers. 

Externalities such as pollution are one type of market failure, which requires regulatory 

intervention to ensure that social benefits of uranium production exceed social costs of its 

production.

6.2 Executive Order 12866: Regulatory Planning and Review and Executive Order 

13563: Improving Regulation and Regulatory Review

Under EO 12866 (58 FR 51735, October 4, 1993), this action is a “significant regulatory 

action.” The EO defines “significant regulatory action” as one that is likely to result in a rule that 

may “raise novel legal or policy issues arising out of legal mandates, the President’s priorities, or 

the principles set forth in the Executive Order.”

White House Office of Management and Budget Circular A-4, Regulatory Analysis, 

requires government agencies to consider market failure “to the extent permitted by law and 

where applicable.” In market transactions where information is equally available to buyers and 

sellers, all costs and benefits are borne by either buyers or sellers and there are enough buyers 

and sellers to ensure competition, markets will efficiently allocate resources so that, from 

society’s point of view, the net benefits of the market transactions are maximized. However, in 

situations where production of a commodity such as uranium produces pollution, people who are 

external to the market (neither buyers nor sellers in the market) for uranium may be exposed to 

uranium and thus bear costs. These external costs or negative externalities are one example of 

market failure and are the underlying justification for government regulatory intervention in such 

markets. Based on its examination of hydrogeology and geochemistry at ISR sites and its review 

of publicly available information about ISR mining operations, EPA believes that ISR operations 
6-2

pose a risk of contaminating groundwater and having the contamination remain undetected for 

years, if sufficient post-restoration monitoring is not done. Because ISR uranium mining poses 

the potential for external costs and is thus affected by market failure, EPA is required by EO 

12866 to develop this proposed rule and to examine its economic impacts, costs, and benefits to 

ensure that its benefits to society exceed its costs.

Thus, EPA has conducted this economic analysis to examine the costs, benefits, and 

estimated impacts of the proposed rule. EPA’s study estimates that affected ISR operators would 

incur costs to comply with the proposed rule, which would require comprehensive preoperational characterization of the site (including characterization of geochemical conditions 

down-gradient of the production zone), careful monitoring during the operation, restoration of 

groundwater quality, at least 3 years of stability monitoring, and 30 years of long-term stability

monitoring, with the potential to shorten the duration based on modeling and monitoring of 

down-gradient geochemical conditions. Using existing ISR operations as models for ISR 

operations that would be affected by the rule, projecting that 2015 ISR uranium production will 

be 8.95 million pounds, and using average estimated costs of complying with the proposed rule, 

EPA estimates that the proposed rule would increase the average cost of uranium production at 

ISR facilities by approximately $1.50 per pound of uranium and that annual costs incurred by 

individual ISR facilities would vary from $303,000 to $9.5 million, depending on the scale of the 

ISR. Nationally, EPA estimates that the incremental total annual cost of the proposed rule would 

be approximately $13.5 million. Discounted at 7%, the estimated present value of the stream of 

national costs would be approximately $181 million. Discounted at 3%, the estimated present 

value of national costs would be approximately $290 million. EPA also examined the costs that 

would be incurred under a regulatory option that would require 30 years of long-term stability

monitoring with no option for shortening the duration using geochemical modeling. National 

total annualized cost under this alternative is slightly higher, an estimated $15.1 million. The 

estimated discounted present value of costs (discounted at 7%) would be approximately $203

million; discounted at 3%, the estimated present value of costs under this alternative would be 

approximately $420 million. Please see Appendix D for a sensitivity analysis of estimated costs 

and impacts of the proposed rule and the 30-year long-term stabilization monitoring alternative.

EPA conducted a qualitative assessment of the benefits of the proposed rule. The rule 

would require thorough characterization of baseline conditions within the ore zone and 

surrounding aquifers and would put in place an automatic updating feature so that the 

requirements affecting ISR operations are always consistent with requirements of SDWA and 

RCRA. Further, EPA’s proposed rule would require a longer period of monitoring, 30 years, to 
6-3

ensure that conditions in the exempted aquifer had been restored, had achieved steady state, and 

were stable. Further, EPA allows facilities to use geochemical modeling to demonstrate that 

groundwater conditions will remain stable and thereby reduce the duration of stability

monitoring to less than 30 years. These provisions help ensure that, after the ISR operation’s 

license is terminated and the site is closed, groundwater conditions do not deteriorate. 

Groundwater is a valuable resource, particularly in the western United States where ISR uranium 

mining is most common. Although EPA is unable to quantify the value of the groundwater

resources that would be protected by the proposed rule, EPA nevertheless believes that the 

groundwater resources are likely to become more valuable over time. Reducing the risk of 

contamination of groundwater also protects surface water bodies to which it discharges. If 

groundwater near an ISR facility were to become contaminated due to remobilization of uranium 

and other constituents, it might be many years before the contamination was discovered, 

especially under current practice where stability monitoring typically lasts only a year or two.

One way to illustrate the potential benefits of the proposed rule is to estimate the costs of 

corrective action that would be required if contamination occurred. If the proposed rule prevents 

the contamination (or causes it to be discovered sooner), it would reduce the corrective action 

costs incurred to remediate the contamination. EPA estimated potential contamination and 

associated corrective action costs for the CMU under various assumptions. The costs of 

remediation far exceed the costs of complying with the proposed rule, both on an annualized 

basis and as a present value. Using a hydrological model, EPA estimated that cleaning up the 

plume of contamination could require 100 years of pump and treat remediation. In addition, if 

contamination were detected after decommissioning of a site, the costs of remediation could be 

borne by the taxpayer or by the owner of the property, rather than the uranium company

responsible, if the former owner company were no longer in existence. Because we cannot 

anticipate how many ISR operations might experience deteriorating groundwater conditions after 

decommissioning or how long it would be before the contamination would be detected, EPA is 

unable to estimate what the national cost savings resulting from avoided remediation costs might 

be. However, EPA believes they could be substantial.

In addition to cost savings, the proposed rule has the potential to protect human and 

ecosystem health. Since a closed ISR facility has no regulatory oversight, this provision would 

reduce the risks of unintended exposure of human and ecological receptors to chemical and 

radiological constituents. To the extent that such exposures are reduced, associated human health 

risks such as cancer may also be reduced.
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6.3 Paperwork Reduction Act

EPA has determined that this action does not impose an information collection burden 

under the provisions of the Paperwork Reduction Act, 44 U.S.S. 3501 et seq. Burden is defined 

at 5 CFR 1320.3(b).

6.4 Regulatory Flexibility Act

The RFA generally requires an agency to prepare a regulatory flexibility analysis of any

rule subject to notice and comment rulemaking requirements under the Administrative Procedure 

Act or any other statute unless the agency certifies that the rule will not have a significant 

economic impact on a substantial number of small entities. Small entities include small 

businesses, small organizations, and small governmental jurisdictions.

For purposes of assessing the impacts of the proposed rule on small entities, small entity

is defined as (1) a small business whose company has fewer than 500 employees and is primarily 

engaged in leaching or beneficiation of uranium, radium, or vanadium ores as defined by NAICS 

code 212291; (2) a small governmental jurisdiction that is a government of a city, county, town, 

school district, or special district with a population of less than 50,000; and (3) a small 

organization that is any not-for-profit enterprise that is independently owned and operated and is 

not dominant in its field. Of these three categories, only small businesses are potentially affected 

by the proposed rule; no small organizations or small governmental entities have been identified 

that would be impacted by the proposed revisions to Part 192.

This proposed rule is estimated to impact approximately 19 ISR uranium recovery

facilities that are currently operating or may operate in the future. The 19 uranium recovery

facilities are owned by 10 firms, of which eight are believed to be small.

To evaluate the significance of the economic impacts of the proposed revisions to Part 

192, EPA estimated the costs that would be incurred by existing facilities, based on their 

estimated production and EPA’s estimated cost per pound of U3O8. According to EPA’s Final 

Guidance for EPA Rule Writers: Regulatory Flexibility Act as Amended by the Small Business 

Regulatory Enforcement Fairness Act (EPA, 2006), firms for which estimated costs of 

complying with a rulemaking are less than 1% of firm sales are presumed not to incur significant 

impacts. Firms for which costs exceed 3% of firm’s baseline sales are believed to incur 

significant impacts. If costs of compliance are between 1% and 3% of the firm’s revenue, it is 

not certain whether impacts would be significant.
6-5

To analyze the proposed revisions to Part 192, EPA assessed potential impacts to six

currently operating ISRs, believing that they are good proxies for firms that would own affected 

ISR facilities subject to the proposed rule. The operating ISRs are Crow Butte and Smith RanchHighland-Reynolds owned by Cameco Resources, Alta Mesa owned by Mestena Uranium, LLC, 

Willow Creek owned by Uranium One, Inc., Hobson-La Palangana owned by Uranium Energy 

Corp, and Lost Creek owned by Ur-Energy Corporation. Using the fewer than 500 employees’ 

criterion, Mestena Uranium, LLC, Ur-Energy Corporation, and Uranium Energy Corporation are

small businesses, while Cameco Resources and Uranium One, Inc. are both large businesses.

In addition to the six operating ISRs, 12 ISRs have are at some stage of planning or 

licensing, or are undergoing restoration:

■ Dewey-Burdock owned by Powertech Uranium Corp.;

■ Nichols Ranch owned by Uranez Uranium Corp.;

■ Moore Ranch and Antelope-Jab, owned by Uranium One, Inc.;

■ Crownpoint, Kingsville Dome, Rosita, Church Rock, and Vasquez all owned by

Uranium Resources;

■ Ross, owned by Strata Energy/Peninsula Energy Ltd;

■ Goliad, owned by Uranium Energy Corp; and

■ Reno Creek, owned by Bayswater E&P.

All of these companies, except Uranium One, Inc., are small businesses.

Of the facilities identified above, 11 are owned by eight small businesses. EPA’s 

economic impact analysis estimated that for the small firms currently operating ISR facilities, 

costs of the proposed rule would be at most 0.7% of estimated 2015 operating revenues for UrEnergy, at most 1.2% of estimated 2015 operating revenues for Uranium Energy, and at most 

1.9% of estimated 2015 operating revenues for Mestena, if the highest-cost assumptions were 

used. Based on EPA’s criteria for significance, impacts for these firms are not believed to be 

significant. In addition, the number of firms potentially incurring costs to comply with the rule is 

not a substantial number. Thus, EPA concludes that the proposed rule would not result in a 

significant impact to a substantial number of small entities. (See Section 5.5 above for additional 

details.)
6-6

6.5 Unfunded Mandates Reform Act (UMRA)

This rule does not contain a federal mandate that may result in expenditures of $100 

million or more for state, local, and tribal governments, in the aggregate, or the private sector in 

any 1 year. Using the five existing ISR operations as examples of typical ISR facilities, EPA 

estimates that total annual costs of complying with the rule for five such ISR facilities would 

range from $11.6 million to $15.2 million, averaging $13.5 million, assuming geochemical 

modeling to shorten the duration, and between $12.9 and $17.9, averaging $15.1 for required 30-

year duration of long term stability monitoring. The proposed rule imposes no enforceable duties 

on any state, local, or Tribal governments or the private sector. Thus, this rule is not subject to 

the requirements of sections 202 or 205 of UMRA.

This rule is also not subject to the requirements of section 203 of UMRA because it 

contains no regulatory requirements that might significantly or uniquely affect small 

governments because it contains no requirements that apply to such governments nor does it 

impose obligations upon them.

6.6 Executive Order 13132: Federalism

This proposed rule does not have federalism implications. It will not have substantial 

direct effects on the states, on the relationship between the national government and the states, or 

on the distribution of power and responsibilities among the various levels of government, as 

specified in EO 13132. None of the facilities subject to this action are owned and operated by

state governments, and, nothing in the proposed rule will supersede state regulations. Thus, EO

13132 does not apply to this proposed rule.

6.7 Executive Order 13175: Consultation and Coordination with Indian Tribal 

Governments

This action does not have tribal implications, as specified in EO 13175 (65 FR 67249, 

November 9, 2000). The action imposes requirements on owners and operators of ISR facilities 

and not tribal governments. Although EO 13175 does not apply to this action, EPA sought 

opportunities to provide information to tribes and tribal representatives during the review of 40 

CFR Part 192. EPA specifically solicits additional comment on this proposed action from tribal 

officials.

6.8 Executive Order 13045: Protection of Children from Environmental Health Risks 

and Safety Risks

EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying to those regulatory

actions that concern health or safety risks, such that the analysis required under section 5-501 of 
6-7

the Order has the potential to influence the regulation. Because this action addresses 

environmental standards intended to mitigate health or safety risks, it is subject to EO 13045. We 

evaluated several regulatory strategies for ensuring groundwater restoration and stability at ISR 

facilities and selected the option providing most assurance that groundwater systems will remain 

in a chemically reduced state, thereby limiting contamination of groundwater. The proposed rule 

is expected to reduce children’s risk of exposure to contaminated groundwater by improving 

monitoring to detect and correct contamination.

6.9 Executive Order 13211: Actions Concerning Regulations That Significantly Affect 

Energy Supply, Distribution or Use

This action is not a “significant energy action” as defined in EO 13211 (66 FR 28355, 

May 22, 2001), because it is not likely to have a significant adverse effect on the supply, 

distribution, or use of energy. This proposed rule will not adversely directly affect productivity, 

competition, or prices in the energy sector. EPA projects that the proposed rule would reduce the 

quantity of uranium used in this country to produce electricity by less than 0.1%. The price of 

uranium is projected to increase by only $0.24 (0.4%) per pound, and this is projected to increase 

the cost of producing electricity by less than 0.1%.

6.10 National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement Act (NTTAA) of 

1995 (“NTTAA”), Public Law No. 104-113, 12(d) (15 U.S.C. 272 note) directs EPA to use 

voluntary consensus standards in its regulatory activities unless to do so would be inconsistent 

with applicable law or otherwise impractical. Voluntary consensus standards are technical 

standards (e.g., materials specifications, test methods, sampling procedures, and business 

practices) that are developed or adopted by voluntary consensus standards bodies. NTTAA 

directs EPA to provide Congress, through OMB, explanations when the Agency decides not to 

use available and applicable voluntary consensus standards.

This proposed rulemaking does not involve technical standards of the type indicated in 

NTTAA. Therefore, EPA is not considering the use of any voluntary consensus standards.

We request public comment on this aspect of the proposed rulemaking, and specifically, 

ask you to identify potentially applicable voluntary consensus standards and to explain why such 

standards could be used in this regulation.
6-8

6.11 Executive Order 12898: Federal Actions to Address Environmental Justice in 

Minority Populations and Low-Income Populations

EO 12898 (59 FR 7629, Feb. 16, 1994) establishes federal executive policy on 

environmental justice. Its main provision directs federal agencies, to the greatest extent 

practicable and permitted by law, to make environmental justice part of their mission by

identifying and addressing, as appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies, and activities on minority populations and lowincome populations in the United States.

EPA has determined that this proposed rule will not have disproportionately high and 

adverse human health or environmental effects on minority or low-income populations because it 

increases the level of environmental protection for all affected populations without having any 

disproportionately high and adverse human health or environmental effects on any population, 

including any minority or low-income population. This proposed rule addresses groundwater

restoration, monitoring, and protection of surrounding aquifers and thus decreases the potential 

groundwater contamination to which all affected populations are exposed. Thus, the proposed 

rule is projected to have positive, not adverse, impacts on human health and the environment.
7-1

Section 7

CONCLUSIONS

EPA is proposing revised groundwater monitoring program for ISR facilities that produce 

uranium by injecting and extracting a solution that dissolves the uranium from the porous 

minerals in which it is found. ISR uranium production represents an increasing share of uranium 

production, and poses special groundwater protection challenges, compared to conventional 

uranium production. Currently, facilities are required to monitor groundwater conditions for only 

a short time (generally less than 2 years) after restoration. Case studies of post-restoration 

monitoring conducted by the U.S. Geological Survey (USGS, 2009) have shown that conditions 

may not remain stable within restored wellfields, with concentrations of some constituents 

increasing again. Thus, there is a potential for uranium and other constituents to remobilize over 

time, with the potential for groundwater contamination. Accordingly, EPA is proposing to add a 

new subpart to 40 CFR Part 192, establishing additional monitoring requirements during all 

phases of an ISR facility:

■ Pre-operational monitoring: measuring background groundwater concentrations

■ Operational monitoring: monitoring, to detect any excursions of contaminated 

groundwater to adjacent aquifers, either beside, above, or below the exempted aquifer

■ Restoration monitoring: monitoring to document the progress of restoration through 

groundwater sampling

■ Post-restoration monitoring, which has two parts:

– Stability monitoring: monitoring, conducted after restoration efforts have ended, 

to establish that wellfield groundwater characteristics are stable and meet 

restoration goals (at least 3 years)

– Long-term stability monitoring: monitoring and statistical analyses to show that 

the concentration of each monitored constituent is not increasing with time and 

that the concentration is not statistically different from the restoration goal

Using a model facility approach, EPA estimated the costs that facilities may incur to 

comply with the proposed rule; costs were estimated for each phase of ISR operation under two 

regulatory options, and a range of costing assumptions. Cost data were compiled for each stage 

over the duration of the stage’s monitoring activities for the CMU, then scaled up based on 

relative total wellfield acreage to estimate the costs that would be incurred by existing facilities. 

EPA estimated the acreage of the CMU and scaled estimated CMU costs up to actual facility

costs using the ratio of total wellfield acreage at existing facilities to acreage of the CMU. These 
7-2

estimated facility costs were used to assess impacts on the market for uranium and on firms 

owning ISR facilities.

The market for uranium is an international market, with suppliers and demanders in many 

countries. The United States has historically been the largest user of uranium for electricity

production but has generally produced only a small share of what it consumes, and foreign 

suppliers have provided the remaining 80% to 90%. The uranium market has historically been 

volatile, exhibiting considerable year-to-year variation in both price and domestic production. 

Going forward, the worldwide demand for uranium is projected to grow substantially over the 

next 20 years, due largely to increased demand from China and India; prices are also projected to 

increase to $64 per pound by 2018. The U.S. EIA projects that uranium purchased by COOs of 

nuclear power plants will grow by approximately 0.2% annually. Using this rate of growth, EPA 

projected baseline market conditions in the U.S. uranium market in 2015, the effective date of 

the proposed rule.

EPA estimated the impact of the proposed rule on the market for uranium and found that,

overall, the market quantity of uranium purchased for use in electric generation would decline by

less than 0.1% and the market price would increase by approximately 0.4%. Domestic ISR 

facilities would decrease their production by approximately 4.1%, and imports of uranium would 

increase by less than 1%. Because the cost of uranium is a very small share of the cost of 

electricity, EPA estimates that the cost of generating electricity would increase by less than 

0.1%.

Although the national total annual costs of the proposed rule (approximately $13.5

million, based on average costs) is well below the $100 million threshold that is one of the 

criteria used to identify a significant regulatory action, the industry has only a small number of 

companies operating a small number of ISR operations. EPA used existing ISR operations and 

the companies that own them as models for the types of facilities and companies that would 

likely be affected by the proposed rule. EPA thus estimated the ISR facilities would incur annual 

costs of compliance between $262,000 and $12.7 million depending on the characteristics of the 

ISR facility and the alternative and costing assumptions used; for small firms owning ISR 

facilities, EPA’s analysis estimates cost-to-sales ratios of 0.6% to 2.2%, depending on the size of 

the operation and the costing assumptions used. Because EPA does not estimate costs to exceed 

2.2% of small company sales, and because fewer than 10 small companies would be affected, 

EPA has determined that the proposed rule would not have a significant impact on a substantial 

number of small entities.
7-3

EPA’s qualitative benefits assessment presents a discussion of the expected effects of the 

proposed rule on human and environmental health. EPA expects that the improved monitoring 

program proposed will reduce the risk of contaminating groundwater resources, thus also 

reducing potential exposures to radiological and nonradiological contaminants in groundwater

and potentially in surface water to which affected aquifers discharge. Because the major risk of 

exposure to radiological constituents is cancer, the proposed rule has the potential to reduce 

cancer risks.

If uranium and other constituents remobilize in groundwater over time and if monitoring 

ends too soon and sites are prematurely decommissioned, it is possible that groundwater in 

surrounding aquifers could be contaminated, and it might be many years before the 

contamination is detected. EPA simulated groundwater contamination using its CMU model 

facility under varying assumptions and estimated the costs of corrective action to remediate the 

groundwater contamination. Based on these simulations, the cost of remediation would far 

exceed the costs of complying with the proposed rule, both on an annual and total basis. For the 

model facility simulation, this subset of benefits (avoided remediation costs) exceeded the costs 

of complying with the proposed rule. See Table 7-1 for this comparison. Further, if 

contamination were detected after decommissioning, the costs of remediation could be borne by 

the taxpayer or the land owner, not the uranium company owner/operator (if, for example, the 

former owner company were no longer in existence or if sufficient time had passed that the 

connection between the contamination and the decommissioned mining operation was not 

identified). EPA was unable, however, to estimate potential avoided costs of remediation on a 

national scale and thus was unable to quantify the rule’s net benefits nationwide.
7-4

Table 7-1. Comparison of Costs of Complying with the Proposed Rule and Costs of 

Remediating Contaminated Groundwater (Million 2011$)

Plume Size and Groundwater

Flow Direction

Sum of Costs Over Time

Without-Regulation 

Scenario

(A)

With-Regulation: 

Compliance and 

Additional Restoration (B)

Avoided Costs

(A) − (B)

Small plume $35.3 $27.1 $8.2

Large plume, transverse $481.0 $27.1 $453.9

Large plume, along $586.1 $27.1 $559.0

Annualized Costs

Small plume $1.45 million

Large plume, transverse $10.3 million

Large plume, along $10.5 million

Compliance with proposed rule 

plus additional restoration

$345,000
R-1

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A-1

APPENDIX A:

UNIT COSTS FOR WELLS AND BORINGS

Unit costs were compiled for both wells and geotechnical borings. The number of wells 

and borings varied between the groundwater monitoring scenarios. The following is a summary

of the unit costs used in the cost analysis.

A.1 Mine Unit Wells

The well types considered in the conceptual mine unit (CMU) models developed for the 

groundwater monitoring scenarios evaluated include:

■ Injection wells

■ Extraction wells

■ Perimeter monitoring wells,

■ Excursion monitoring wells in the overlying and underlying aquifers

Additional well types considered for some scenarios included:

■ Down-gradient ore zone monitoring wells,

■ Remediation wells

The total depths of these wells were based on the hydrogeology of the example mine unit 

from the Highland site in Wyoming. Table A-1 below summarizes the well depths of overlying 

and underlying monitoring wells and also the production wells (Michel and Hoffman, 1991). The 

average depth for each well zone (i.e., ore zone, overlying aquifer, and underlying aquifer) was 

used to calculate the unit costs.

EPA (2012b) previously estimated the cost per foot (ft) for well construction. This was 

assumed to include costs for well materials (casing, well screen, caps, etc.), mobilization of drill 

rig and support trucks, drilling time, and surface completion (materials and labor). Range of 

costs for well construction was from $9 to $32 per foot. Higher costs per foot were typically for 

shallower wells. Based on documentation provided by EPA a cost of $30 per foot was assumed 

for any well 500-ft or deeper. Since the wells at the Highland site, on which the CMU model was 

based, are in the 500-foot depth range, the unit cost of $30 per foot was chosen all well types 

considered in the groundwater monitoring and remediation scenarios. Costs of production wells 

were also used for other ore zone wells (i.e., ore zone monitoring wells and remediation wells).
A-2

Table A-1. Depth of Selected Wells and Average Unit Cost

Overlying Wells Underlying Wells Injection/Extraction Wells

Total Depth Well Cost Total Depth Well Cost Total Depth Well Cost

410.4 $12,312 620.5 $18,615 635 $19,050

519.1 $15,573 658 $19,740 624 $18,720

534 $16,020 669 $20,070 559.3 $16,779

435 $13,050 681.3 $20,439 562 $16,860

484 $14,520 689.45 $20,684 597 $17,910

426 $12,780 682 $20,460 602 $18,060

510 $15,300 670 $20,100 618 $18,540

550 $16,500 650 $19,500 596 $17,880

424.5 $12,735 651 $19,530 589 $17,670

540 $16,200 676.8 $20,304 600.5 $18,015

520 $15,600 664.1 $19,923 600 $18,000

545 $16,350 669.6 $20,088 610.5 $18,315

450 $13,500 660 $19,800 602.5 $18,075

668 $20,040 584 $17,520

690 $20,700 596.5 $17,895

594 $17,820

600.4 $18,012

589.9 $17,697

592 $17,760

595 $17,850

600 $18,000

597.1 $17,913

602.5 $18,075

592 $17,760

597 $17,910

612 $18,360

614.6 $18,438

621.3 $18,639

618 $18,540

(continued)
A-3

Table A-1. Depth of Selected Wells and Average Unit Cost (continued)

Overlying Wells Underlying Wells Injection/Extraction Wells

Total Depth Well Cost Total Depth Well Cost Total Depth Well Cost

614 $18,420

625 $18,750

604 $18,120

650 $19,500

645 $19,350

600 $18,000

601 $18,030

571.5 $17,145

588 $17,640

629.6 $18,888

595 $17,850

607 $18,210

586 $17,580

593 $17,790

599.3 $17,979

581.7 $17,451

537 $16,110

585.4 $17,562

592.4 $17,772

612.8 $18,384

631.8 $18,954

602.55 $18,077

591.6 $17,748

591 $17,730

592.5 $17,775

557 $16,710

MAX= 550 $16,500 690 $20,700 650 $19,500

MIN= 410 $12,312 621 $18,615 537 $16,110

MEDIAN= 510 $15,300 669 $20,070 599.3 $17,979

AVERAGE= 488 $14,649 660 $19,795 600 $17,993
A-4

A.2 Geotechnical Borings

Costing information available from the U.S. DOE (2013) for geotechnical boring drilled 

for characterizing the geochemistry for geothermal energy development in the western United 

States was used as a guide for estimating corehole costs. However, due to the way the DOE costs 

were presented and limited time, the estimated costs for geotechnical borings was also based on 

experience and best professional judgment. The costs of a geotechnical boring is related to the 

corehole depth, penetration rate expected, drilling method and technology requirements, the 

number of samples, type of samples taken and the sample method; and there are also regional 

factors that control costs for drilling and construction services (e.g., variation in licensing and 

permitting requirements). Boring costs were only assumed applicable for geochemical modeling. 

Drilling time was assumed to be one day per corehole with a maximum drilling depth of 650-feet 

which is the total average depth assumed for the underlying non-exempt aquifer in the CMU. 

Composite sampling of selective zones in each corehole was assumed resulting in 2 samples per 

corehole, on average, sent to the laboratory for analysis. Costs for core analysis and logging were 

also included. A summary of the boring costs assumptions and the total costs for the boreholes is 

provided in Table A-2.

Table A-2. Summary of Well and Borehole Costs Assumed for Modeled Scenarios

Well Types

Unit Cost

($/well; 

$/core; 

$/day)

CMU Well Totals and Costs

CP 2011$ 30-yr 2011$

30-yr 

with 

Geochem 2011$

OZ-PW $17,993 26 $467,805 26 $467,805 26 $467,805

OZ-IW $17,993 166 $2,986,755 166 $2,986,755 166 $2,986,755

OZ-EW $17,993 77 $1,385,423 77 $1,385,423 77 $1,385,423

OZ-MW $17,993 0 $0 0 $0 10 $179,925

OW $14,649 5 $73,246 10 $146,492 10 $146,492

UW $19,795 10 $197,950 20 $395,900 20 $395,900

Well Totals: 284 $5,111,179 299 $5,382,375 309 $5,562,300

Core Hole $11,316.50 0 $0.00 0 $0.00 8*650ft $90,532.00 

Core Analysis $400.00 0 $0.00 0 $0.00 8 $3,200.00 

Lab Analysis $400.00 0 $0.00 0 $0.00 8 $3,200.00 

Core Totals: 0 $0.00 0 $0.00 $96,932.00 

CP = current practice
A-5

A.3 References

Michel, T.G. and G. Hoffman, July 1991. E-Field 50 Sand Mine Unit Hydrology Test, Highland 

Uranium Project, Power Resources, Inc.; Report for WDEQ/LQD Permit Number 603, 

U. S. Nuclear Regulatory Commission Docket Number 40-8857, SUA-1511; Report by

Power Resources, Inc. and Hydro-Engineering; September 1990, revised July 1991.

U.S. Department of Energy, 2013. Cost and Time Metric Tool (Web Application); National 

Renewable Energy Laboratory; Internet resource: 

http://en.openei.org/wiki/Exploration_Cost_and_Time_Metric

U.S. EPA, March 26, 2012b. Data collected (WA 2-04, Task B) and provided by EPA.
B-1

APPENDIX B:

SUMMARY OF UNIT COSTS FOR SAMPLING AND ANALYSIS

Unit costs were determined for the collection and analysis of a groundwater sample. 

These unit costs were then used for estimating total sampling and analysis costs for each of the 

groundwater monitoring scenarios evaluated. Groundwater sampling and analysis costs are 

summarized for each scenario in Section 3 of the report.

B.1 Analysis Costs

The total laboratory costs are dependent upon the number of parameters that are 

analyzed. EPA recognizes that analytical costs are site specific since the list of parameters 

required for monitoring are a function of the geochemistry of the aquifer units being sampled, as 

well as operational and regulatory requirements. In general, analytes may be required for 

analysis based on EPA or state regulation, to identify excursions, to monitor the condition of the 

lixiviant, and to characterize and model the pre and post-mining geochemistry (U.S. EPA, 

2012a). The groundwater monitoring scenario cost models have assumed full lists of applicable

analytes, and no assumptions were made that would serve to reduce a list of parameters and 

analytes (e.g., based on the Highlands site geochemistry and CMU model) that might be sampled 

due to an assumed monitoring requirement (i.e., state, EPA NRC, etc.).

The lists of parameters and analytes were originally compiled from 4 different sources—

including EPA, NRC, TCEQ, and WDEQ—as seen in Table B-1. A unit cost was developed to 

estimate the cost of analyzing the full suite of 56 parameters, as well as for various subsets, 

including the EPA specified 33 parameters, the 35 parameters from the NRC’s ISL Standard 

Review Plan, and the state specified parameters. EPA collected costs to perform the specific 

analyses required from 12 actual analytical laboratories (TDSHS, 2007; Pace, 2009; BVNA, 

2010; NDHHS, 2010; ELI, 2011; CCAL, 2012; ML, 2013; ELI, 2013; SARA, 2012; ACTI, 

2005; EPA, 2012b). The average, low, median, and high analytical costs for each analyte are 

shown in Table B-1. Average costs were only used in the analysis of the groundwater monitoring 

scenarios; however, the other costs are provided for comparison.
B-2

Table B-1. Analysis Costs for Analytes Generally Required in ISR Groundwater

Monitoring Programs (2011$)

Species

Requirements by Analyte Group Analysis Cost (sample-1)

EPA NRC TCEQ WDEQ UCLj Geochem Average Low Median High

Trace and Minor Elements

Aluminum Yes Yes $13.63 $8.00 $14.40 $19.00

Antimony Yes $13.63 $8.00 $14.40 $19.00

Arsenic Yes Yes Yes Yes $13.63 $8.00 $14.40 $19.00

Barium Yes Yes $13.63 $8.00 $14.40 $19.00

Beryllium Yes $13.63 $8.00 $14.40 $19.00

Boron Yes Yes $13.63 $8.00 $14.40 $19.00

Cadmium Yes Yes Yes Yes $13.63 $8.00 $14.40 $19.00

Chromium Yes Yes Yes $13.63 $8.00 $14.40 $19.00

Cobalt Yes $11.83 $8.00 $10.00 $19.00

Copper Yes Yes $13.63 $8.00 $14.40 $19.00

Fluoride Yes Yes Yes Yes Yes $16.50 $12.00 $15.50 $21.00

Ironi Yes Yes Yes Yes Yes (Total 

and Fe2+)

$13.97 $8.00 $14.40 $19.00

Lead Yes Yes Yes $13.63 $8.00 $14.40 $19.00

Manganese Yes Yes Yes Yes Yes $13.97 $8.00 $14.40 $19.00

Mercury Yes Yes Yes $17.13 $8.00 $14.40 $37.00

Molybdenum Yes Yes Yes Yes $13.63 $8.00 $14.40 $19.00

Nickel Yes Yes $13.63 $8.00 $14.40 $19.00

Selenium Yes Yes Yes Yes $13.63 $8.00 $14.40 $19.00

Silver Yes Yes $13.63 $8.00 $14.40 $19.00

Thallium Yes $13.63 $8.00 $14.40 $19.00

Tin Yes $11.00 $8.00 $10.00 $19.00

Uranium Yes Yes Yes Yes Yes $16.13 $8.00 $16.00 $25.00

Vanadium Yes & 

V2O5

Yes Yes $11.33 $8.00 $10.00 $16.00

Zinc Yes Yes $13.63 $8.00 $14.40 $19.00

(continued)
B-3

Table B-1. Analysis Costs for Analytes Generally Required in ISR Groundwater

Monitoring Programs (2011$) (continued)

Species

Requirements by Analyte Group Analysis Cost (sample-1)

EPA NRC TCEQ WDEQ UCLj Geochem Average Low Median High

Common Constituents

Alkalinity Yes Yes Yes $16.33 $10.00 $16.00 $23.00

Ammonia Yes Yes Yes 

(NH4+)

$23.75 $15.00 $22.50 $35.00

Bicarbonate Yes Yes Yes Yes $13.00 $13.00 $13.00 $13.00

Calcium Yes Yes Yes Yes $12.17 $8.00 $10.00 $19.00

Carbonate Yes Yes Yes Yes $13.00 $13.00 $13.00 $13.00

Chloride Yes Yes Yes Yes Yes Yes $16.17 $10.00 $17.00 $21.00

Magnesium Yes Yes Yes Yes $14.00 $8.00 $10.00 $29.00

Nitrate Yes Yes Yes Yes Yes $20.60 $12.00 $20.00 $30.00

Nitrite Yes Yes $19.83 $12.00 $20.00 $26.00

Phosphatee Yes $23.33 $20.00 $25.00 $25.00

Potassium Yes Yes Yes Yes $14.00 $8.00 $10.00 $29.00

Silica Yes Yes $23.50 $10.00 $26.00 $32.00

Sodium Yes Yes Yes Yes $14.00 $10.00 $14.00 $18.00

Sulfate Yes Yes Yes Yes Yes $16.17 $10.00 $17.00 $21.00

Sulfide Yes Yes Yes $38.00 $35.00 $39.00 $40.00

Chemical and Physical Indicators

Anion/Cation 

Balance

Yes $10.00 $10.00 $10.00 $10.00

Specific 

Conductivity

Yesa Yes Yes Yes $13.67 $10.00 $12.00 $19.00

pH Yes Yesa Yes Yes $11.00 $8.00 $10.00 $17.00

Redox 

Potential

Yes $45.00 $45.00 $45.00 $45.00

Total 

Dissolved 

Solids

Yes Yesb Yes Yes Yes Yes $19.33 $12.00 $18.00 $31.00

Temperature Yes NA NA NA NA

Turbidityf Yes $15.00 $15.00 $15.00 $15.00

Dissolved 

Oxygeng

Yes $18.67 $10.00 $11.00 $35.00

(continued)
B-4

Table B-1. Analysis Costs for Analytes Generally Required in ISR Groundwater

Monitoring Programs (2011$) (continued)

Species

Requirements by Analyte Group Analysis Cost (sample-1)

EPA NRC TCEQ WDEQ UCLj Geochem Average Low Median High

Chemical and Physical Indicators (continued)

Dissolved 

Organic and 

Inorganic 

Carbonh

Yes $39.00 $32.00 $35.00 $50.00

Eh Yes NA NA NA NA

Radiological Parameters

Gross Alpha Yes Yesc Yes Yes $48.33 $40.00 $50.00 $55.00

Gross Beta Yes Yes $45.00 $40.00 $45.00 $50.00

Radium-226 Yes Yesd Yes Yes Yes $77.25 $75.00 $75.50 $83.00

Radium-228 Yes Yesd Yes $83.00 $70.00 $79.00 $104.0

0

Beta + 

Gamma

Yes $75.00 $75.00 $75.00 $75.00

Totals: 33 35 25 28 4 29

a

Field and laboratory determination

b Laboratory only

c Excluding radon, radium, and uranium

d

If site initial sampling indicates the presence of Th-232, then Ra-228 should be considered in the baseline sampling 

or an alternative may be proposed

e

Phosphate costs from Cooperative Chemical Analytical Laboratory, Midwest Laboratories, Energy Laboratories 

Inc.

f Turbidity costs from Cooperative Chemical Analytical Laboratory (http://www.ccal.oregonstate.edu/fees.htm)

g Dissolved oxygen costs from Midwest Laboratories, San Antonio River Authority, and Aquatic & Consulting 

Testing Inc.

h Dissolved Organic and Inorganic Carbon from Cooperative Chemical Analytical Laboratory, two method 

(Combustion-Infrared and Sparge-Infrared) fees were combined for a total cost of analyzing both species 

(http://www.ccal.oregonstate.edu/fees.htm)

i Dissolved and total

j UCL—upper control limit/excursion parameters.
B-5

B.2 Groundwater Sampling Unit Costs

Included in the unit cost for groundwater sampling are the:

■ laboratory analysis costs,

■ labor cost of contractor personnel to collect the sample,

■ expenses for contractor personnel to travel to the site,

■ contractor fees (assumed 8%), and a

■ contingency of 10% of all calculated costs.

These costs were calculated for each analyte group (i.e., EPA, NRC, etc.) and are 

summarized in Table B-2. The following items are not included or considered in the unit costs:

■ materials (e.g., bottles, gloves, and reagents)

■ sample transport to laboratory

■ lodging

■ record keeping,

■ well maintenance during stability monitoring,

■ sample disposal, as well as

■ the impact of using on site personnel, rather than contractor personnel.

Table B-2. Unit Cost for Groundwater Sampling with Analysis Costs (2011$)

Component

Species Analyzed

EPA NRC TCEQ WDEQ Geochem.

Group Analysis (Average Costs) $741 $700 $447 $665 $629

Direct Labor (hr-1) $200 $200 $200 $200 $200

Indirect Labor (hr-1) $46 $47 $47 $47 $47

Travel $26 $26 $26 $26 $26

Fee (8%) $25 $25 $25 $25 $25

Contingency (10%) $34 $34 $34 $34 $34

Total $1,073 $1,032 $779 $997 $961
B-6

These costs, individually and in total, were considered a small portion of the sum of 

analysis and labor costs.

B.3 Parameter References

ACTI (Aquatic & Consulting Testing Inc.), 2005. “Biological and Analytical Chemistry

Services.” Available at: http://www.aquaticconsulting.com/fee%20schedule.pdf 

[Accessed March 23, 2013].

BVNA (Bureau Veritas North America), 2010. “Schedule 66, Scientific Equipment and 

Services,” Number: GS-07F-6029R, Period: 17 Aug 2010 –17 Aug 2015.

CCAL (Cooperative Chemical Analytical Laboratory), 2012. “CCAL Fee Schedule for FY13.” 

Available at: http://www.ccal.oregonstate.edu/fees.htm [Accessed March 23, 2013].

NDHHS (Nebraska Department of Health and Human Services), 2010. “Analyte/Price List, 

Nebraska NDHHS Laboratory 2009-10.”

TDSHS (Texas Department of State Health Services), 2007. “2007 TDSHS Fee Schedule—

Austin Lab,” CLIA ID #: 45D0660644, Tax ID # 32-0113643.

ELI (Energy Laboratories, Inc.), 2011. “Analytical Services 2011.”

ELI (Energy Laboratories Inc.), 2013. “Technical Services and Fee Schedule 2013.” Available 

at: http://www.energylab.com/asp/PricingGuide/docs/ELI_2013_Fee_Schedule_-

_ALL_SECTIONS_v0.pdf [Accessed March 23, 2013].

ML (Midwest Laboratories), 2013. “Schedule of Fees 2013.” Available at: 

https://www.midwestlabs.com/wp-content/uploads/2013/01/Midwest-Labs-Schedule-ofFees-2013.pdf [Accessed March 23, 2013].

Pace (Pace Analytical Services Inc.), 2009. “Minneapolis, MN Laboratory, 2009 Pricing 

Information,” Revised 1/1/09.

SARA (San Antonio River Authority), 2012. “Analytical Services Fee Schedule.” Available at: 

http://www.sara-tx.org/public_services/laboratory_services/docs/Fee-schedule-2012.pdf 

[Accessed March 23, 2013].

U.S. Environmental Protection Agency (EPA), 2012a. Considerations Related to Post Closure 

Monitoring of Uranium In-Situ Leach/In-Situ Recovery (ISL/ISR) Sites: Background 

Information Document for the Revision of 40 CFR Part 192. Radiation Protection 

Division, Office of Air and Radiation.

U.S. Environmental Protection Agency (EPA), 2012b. Data collected (WA 2-04, Task B) and 

provided by EPA. March 26.
C-1

APPENDIX C:

SIMULATION OF REMOBILIZED URANIUM FROM A RESTORED ISR MINE

This appendix documents modeling simulations of a plume that could develop within an 

ore body after ISR mining and restoration have been completed. The scenario represents 

conditions that have destabilized the restored wellfield years after restoration of the production 

unit had been completed. The destabilization is due to a natural influx of oxidized groundwater

from up-gradient of the mine unit that oxidizes the remaining uranium in the wellfield making it 

more mobile, thereby allowing a groundwater contamination plume to develop and allow the 

migration of the constituents down-gradient into the rest of the wellfield and potentially into the 

aquifer below the production zone. For this situation to develop, the mechanisms that were 

responsible for sequestering the uranium initially would have to be destroyed or dramatically 

weakened by the uranium recovery process so that the restoration process amounted to only a 

temporary re-establishment of chemically reducing conditions in the ore zone. For that situation, 

the movement of oxygenated groundwater into the production zone from up-gradient could, over 

time, re-oxidize the uranium and allow migration of the contaminants down-gradient.

The simulations illustrate the potential behavior of a remobilized contamination plume 

for the example mine site in Wyoming with the model setup generally based on actual conditions 

at the Highland site. It should be noted, however, that the model is for illustrative purposes only 

and the results do not suggest that the scenarios developed have or will occur at the example site.

Varying groundwater flow directions were considered for the conceptual mine unit 

(CMU) based on data from Wellfield-E documentation (Michel and Hoffman, 1991). A general

groundwater flow direction, longitudinal with the linear extent of the ore zone, was assumed that 

could have been either induced from nearby pumping centers (e.g., other ISL production units) 

or preferential flow toward abandoned, idle, or active underground mine units that were nearby

(see Fig. 3-1). A typical groundwater flow direction perpendicular to the length or face of the ore 

zone front was also considered for the remediation scenarios.

Even though a more eastward groundwater flow gradient is characteristic of the 50-sand 

unit due to the influence of other nearby pumping or groundwater drainage points, the modeled 

simulations of groundwater flow predict plume migration under ambient conditions that exist 

without any active pumping or extraction at the mine site. The simulations also predict plume 

migration under hypothetical pump and treat remediation scenarios, assuming the remobilized 

plume is discovered and actively remediated. The modeling results were used to support the 

estimation of remediation costs for a generally small and larger sized plume.
C-2

C.1 Background

The ISR mining process involves the injection of oxidizing agents and other chemicals 

(the lixiviants) into the ore zone to mobilize uranium for subsequent extraction. The oxidizing 

agents remove iron sulfides and reactive organic material in addition to uranium. Such naturallyoccurring reducing agents were typically responsible for the original uranium sequestration that 

formed the ore deposit. The restoration process (following the ISR mining) is intended to return 

the aquifer to a chemically reducing environment similar to pre-mine conditions, thereby

immobilizing uranium and other potential contaminants. However, the restoration process can 

have a limited potential to restore reducing conditions, particularly over long time periods. If 

levels of iron sulfides and organics have been reduced significantly by the mining process, 

attempts at restoration may only have a short term effect. The restoration may reduce uranium 

concentrations in groundwater, but unless a strongly chemically reducing environment is in 

place, concentrations may later increase. If more oxidizing groundwater enters the mine unit 

from up-gradient, it can re-oxidize the uranium, thereby increasing concentrations and creating 

an inorganic contaminant plume of uranium plus other metals (e.g., thorium) in groundwater. 

This plume could migrate out of the mine unit and impact down-gradient areas of the aquifer, 

particularly if there is not a strong reducing environment down-gradient, and potentially

impacting beneficial groundwater uses.

Effects of uranium re-mobilization could be mitigated through natural attenuation 

processes that reduce down-gradient concentrations. The key attenuation mechanisms are 

dispersion along the flow path, sorption of uranium on the aquifer materials, and chemical 

reduction. The model simulations include mechanisms of dispersion and linear equilibrium 

sorption. Chemical reduction (and oxidation) processes require more information and more 

complex modeling than attempted for this evaluation.

C.2 Approach

The assessment uses the groundwater flow model MODFLOW (McDonald and 

Harbaugh, 1983) and the groundwater transport model MT3DMS (Zheng and Wang, 1999). 

These codes are well accepted in the technical community and widely used for groundwater and 

contamination fate and transport modeling. Table C-1 provides input parameter values developed 

to represent the case study site.
C-3

Table C-1. Input Parameter Values 

Parameter Value Unit Source

Hydraulic 

Conductivity (K)

2.20 m/day Michel, Thomas G. and George Hoffman (July 1991).

Hydraulic gradient 0.0135 — Michel, Thomas G. and George Hoffman (July 1991).

Porosity 0.20 — Typical

Aquifer top elevation 1351 m Michel, Thomas G. and George Hoffman (July 1991); 

Plate 2-1 and 2-1.

Aquifer bottom 

elevation

1341 m Michel, Thomas G. and George Hoffman (July 1991); 

Plate 2-1 and 2-1.

Head at up-gradient 

plume boundary 

(ambient flow)

1570 m Michel, Thomas G. and George Hoffman (July 1991); 

Plate 4-2, head near up-gradient ore body location

Pore velocity 0.15 m/day Calculated (K*gradient/porosity)

Dispersivity 30 m

2

/day Estimated as 0.1*plume scale*pore velocity; plume 

scale=2000 m (http://www.iowadnr.gov/portals/ 

idnr/uploads/ust/monohydrocarbonsguide.pdf)

Bulk density 2.00E+06 gm/m3 McWorter, David B. and Daniel K. Sunada, 2010

Ore body length 1600 m Based on length of northern ore body and configuration 

of Wellfield E

Ore body width 400 m Based on width of northern ore body and configuration of 

Wellfield E

Initial dissolved 

concentration

0.10 mg/L=gm/m3 Communication with EPA and data from Wellfield E 

annual reports

Target dissolved 

concentration

0.03 mg/L=gm/m3 Communication with EPA

Kd minimum 1.00E-06 m

3

/gm

(0.03 mL/gm)

Pearson et al., 1983 and communication with EPA

Kd maximum 1.00E-05 m

3

/gm

(2200 mL/gm)

Pearson et al., 1983 and communication with EPA

Pumping rate (per 

well)

164 m

3

/day Michel, Thomas G. and George Hoffman (July 1991).

The model domain is rectangular and extends 10,000 m from the ore body in all 

directions. A line of constant head boundary cells along the up-gradient and down-gradient edges 

of the domain. The specified head values were set so that the ambient/background groundwater

flow gradient matched the gradient at the example mine site. A rectangular plume with a similar 

geometry to the ore body (see Figures 3-1 and 3-2) was delineated in the middle of the model 

domain with a concentration of 0.1 mg/L. The simulations predict the time for the plume 

concentrations to decrease below 0.03 mg/L and any associated plume migration.
C-4

The sorption partition coefficient (Kd) controls the degree of linear sorption represented 

by the model. The Kd variable is site specific and limited examples were found for actual ISR 

sites that were measured either as part of baseline or after restoration was completed. The value 

selected for modeling purposes was a referenced (F.J. Pearson Jr., C.J. Noronha, and R.W. 

Andrews, 1983) Kd measured at a roll front sandstone site and was used as a representative 

general condition. This value was varied for the simulations between 1e-6 and 1e-5 m3/gm to 

examine the sensitivity of the projections to the assigned value for this uncertain parameter.

The simulations predict plume migration under two flow-direction scenarios: 

1) groundwater flow oriented parallel to the length of the original ore body; 2) groundwater flow 

oriented transverse to the length of the original ore body. The expected direction of groundwater

flow would be perpendicular to the length of the ore body; however, a scenario was also 

considered with groundwater flow along the length of the ore body that would simulate geologic 

conditions where the modern flow regime was different than when the deposit was formed, and 

for cases where anthropogenic activities had altered the natural groundwater flow in the aquifer. 

The simulations predict plume migration under two flow field scenarios: 1) flow under ambient 

conditions with no groundwater pumping; 2) flow under hypothetical pump and treat scenarios 

that include groundwater injection as well as extraction wells. The pump and treat scenarios were 

selected to reduce plume concentrations below the target concentration (0.03 mg/L) in 100 years 

or less. More aggressive pump and treat designs could result in shorter remediation times. The 

selected scenarios were considered reasonable representations under the idealized model 

conditions. The scenario involving ambient flow rates without the pump and treat remediation is 

an assessment of the potential for natural attenuation mechanisms to contain the contamination 

plume.

With flow parallel to the length of the deposit, the pump and treat scenario includes a line 

of extraction wells through the center of the plume. The scenario also includes lines of extraction 

wells along the upper and lower plume boundaries (see Figure C-1). This configuration induces 

flow between the injection and extraction wells, removing contaminated groundwater and 

injecting treated water. In all scenarios, the total injection rate matches the extraction rate. At 

points of injection is the flow rate is 82 ft/day, and at extraction points the flow rate is 

164 ft3/day. As illustrated in Figure C-1, constituent concentrations are continually lowered over 

time while the plume is contained within the treatment area.
C-5

Figure C-1. Example Simulations with Flow Oriented Parallel to the Strike of the Ore 

Body; Kd=6e-6 m3/gm; Pump and Treat
C-6

With flow perpendicular to the length (or length) of the deposit, the pump and treat 

scenario includes a line of injection wells along the up-gradient plume edge. The scenario also 

includes a line of extraction wells along the down-gradient plume edge (see Figure C-2). This 

configuration induces flow between the injection and extraction wells, removing contaminated 

groundwater and injecting treated water. In all scenarios, the total injection rate matches the 

extraction rate. The flow at injection wells is at 164 ft3/day, and flow from extraction wells is at 

164 ft3/day. As illustrated in Figure C-2, constituent concentrations are continually lowered over 

time while the plume is contained within the treatment area. Water is injected and flows downgradient to the extraction wells, thereby flushing contamination to the extraction wells and 

reducing contaminant concentrations.

C.3 Simulation Results

Table C-2 summarizes the results of the modeling assessment for each scenario. The 

results are very sensitive to the Kd parameter that controls the degree of linear sorption 

represented by the model. Table C-2 includes the calculated retardation factor, which indicates 

how much slower the contaminant plume moves due to sorption when compared to groundwater

flow.

The results illustrate that significant down-gradient migration of a remobilized plume is 

possible before natural attenuation mechanisms reduce concentrations below acceptable levels. 

For this situation, remediation intervention approaches are necessary to prevent large scale 

migration of the contamination. In addition, plume migration times are relatively slow under 

ambient flow conditions (the scenarios with no P&T component), further indicating that active 

remediation efforts would be needed to address the contamination potential. Consistently, pump 

and treat remediation times are relatively slow, requiring decades or longer to reduce 

concentrations to acceptable levels. In any particular field situation, the time frames for oxidizing 

waters to re-enter a well field that was not permanently returned to a strongly reducing chemical 

regime by the restoration process will vary based on site-specific conditions. Reliable prediction 

of when, and if, re-mobilization may take place is not possible without a thorough geochemical 

characterization of site conditions after the restoration process has been completed and continued 

monitoring of those conditions.

For developing the geochemical model, it is important to characterize conditions downgradient from the ore body. As mentioned earlier, chemically reducing conditions in the 

sandstone host rock were responsible for originally sequestering the uranium and the presence of 

these conditions in the portion of the aquifer down-gradient of the ore zone would act as a barrier 
C-7

Figure C-2. Example Simulations with Flow Oriented Perpendicular to the Strike of the 

Ore Body; Kd=6e-6; Pump and Treat
C-8

Table C-2. Simulation Results 

Flow 

Direction

Flow 

Field

Kd

(m3/gm)

Retardatio

n Factor

Number of

Time to Reach 

C<0.03 mg/

L (yr)

Down 

gradient 

Travel 

Distance (m)

Injection 

Wells

Pumping 

Wells

Parallel to 

length of 

deposit

Ambient 

Flow

1.0E-06 11 0 0 >2200a>10000a

6.0E-06 61 0 0 >5000b>4800b

1.0E-05 100 0 0 >5000b>2800b

Pump and 

Treat

1.0E-06 11 20 9 50 0

6.0E-06 61 48 23 75 0

1.0E-05 100 60 29 100 0

Transverse 

to length 

of deposit

Ambient 

Flow

1.0E-06 11 0 0 725 3300

6.0E-06 61 0 0 4750 3800

1.0E-05 100 0 0 >5000b>2800

Pump and 

Treat

1.0E-06 11 20 20 20 0

6.0E-06 61 36 36 60 0

1.0E-05 100 45 45 80 0

a

Plume exits simulation domain before decreasing below 0.03.

b

Simulation ends before plume decreases below 0.03.

to contaminant migration from the ore zone if re-mobilization occurs. In many cases, unmined 

down-gradient materials will maintain reducing conditions with sufficient capacity to immobilize 

a plume. The simulations in this appendix assume oxidizing conditions remain as the plume 

migrates down gradient.

The consequences of re-mobilization illustrated in the simulations supports the use of a 

reasonably long post-restoration long-term stability monitoring period to provide an opportunity

to detect any re-mobilization and address it before the contamination becomes widespread 

through the wellfield. The 30 yr post-restoration stability monitoring period in the proposed rule 

is aimed at providing at least an opportunity to detect re-mobilization if it begins to occur. The 

benefit of developing a geochemical model of the production zone aquifer is also illustrated by

these assessments. If the geochemical reducing capacity of the restored wellfield and downgradient portions of the production aquifer can be shown to minimize the potential for postrestoration remobilization of uranium, the regulator can terminate the license with confidence 

that the full thirty year monitoring period would not be necessary. Conversely, if the 

geochemical model of the system does not indicate a strong chemically reducing environment 

exists at the site, the regulatory agency can consider additional monitoring periods as necessary
C-9

to verify that contamination is not moving out of the restored production zone area and 

potentially beyond the border of the wellfield aquifer. Developing a defensible geochemical 

model of the system can provide significant cost savings for all the alternative situations. If a 

strongly reducing environmental is present, costs can be lowered by early termination of the ISR 

license since re-mobilization is unlikely and the full 30 year monitoring period may not be 

required. If a less effective geochemical situation exists at an ISR site, standard restoration 

activities can be augmented to limit the potential for re-mobilization and monitoring efforts can 

be focused on detecting re-mobilization before it spreads over a wider area, thereby reducing the 

potential for incurring significant remediation costs.

C.4 Estimated Costs of Remediation

The simulation results described above for the pump and treat scenarios were then used to 

estimate the costs of remediating a plume of contamination that might result if conditions within 

a restored mine unit did not remain stable over time. The costs of remediation include the costs 

of the wells (installation and 20% replacement after 20 years) and the costs of treatment. Not 

explicitly included are costs of disposing of treated water since during the pump and treat 

operations, it is assumed that much of this will be re-injected; in addition, treated water could be 

evaporated from holding ponds or used for irrigation in these generally rural areas. None of these 

options would add significant costs. Also omitted from the costs are scoping assessments to 

identify the location and characteristics of the plume. In reality, such scoping would likely be 

needed to determine how to structure the pump and treat remediation. Omitting these costs 

means that our estimated costs of remediation may underestimate actual costs.

This examination of the requirements and costs of remediating a plume of constituents at 

the CMU (under varying scenarios) is meant to illustrate the value of long-term stability

monitoring. Clearly, the potential for remobilization, and creation of contaminant plumes, varies 

widely from site to site. EPA therefore did not attempt to generalize or extrapolate to estimate 

remediation requirements or costs that would be incurred at actual ISR sites. Instead, this is a 

CMU-specific example.

Table C-3 presents the estimated costs of remediation. Annual O&M costs are a function 

of the number of wells (and thus, the estimated wellfield yield); they are estimated based on a 

unit cost of $6.35 per 1000 gallons (EPA, 2001) treated. Capital costs are also a function of the 

number of wells (and the estimated wellfield yield), and are computed based on $30.48 per 

thousand gallons (EPA, 2001) treated. It is assumed that, after 20 years, 20% of the wells will 

need to be replaced. Capital costs are annualized over a period of 20 years at 7% rate of interest. 
C-10

Total annualized costs are the sum of annual O&M costs and annualized capital costs for each 

scenario.

Because higher Kd means the constituents are more difficult to remove (due to the 

tendency for the constituents to adhere to aquifer matrix material), both the number of wells and 

the duration of treatment increase as Kd increases under each scenario (transverse to the length of 

the deposit and along the length of the deposit).

Also included in Table C-3 is a “short” remediation example, intended to represent the 

costs of using pump and treat methods to address increasing constituent concentrations detected 

in only a small area of the wellfield, approximately 20 acres. Fewer wells would be needed, and 

a shorter duration of treatment would be required to remediate the plume. This represents a 

lower-bound estimate of potential pump and treat remediation costs.

Table C-3. Estimated Costs of Remediation (Thousand $2011)

Kd

No. of 

Wells

Annual 

Wellfield 

Yield

(1000 gal)

Costs, $

Pumping 

Duration

(years)

Total 

Annualized 

Remediation 

Costs

Annual

O & M Capital

Annualized

Total

Capital

Transverse 

to length of 

deposit

1.0E-06 40 630,720 4,005 19,224 1,815 20 5,820

6.0E-06 72 1,135,296 7,209 34,604 3,266 60 10,475

1.0E-05 90 1,419,120 9,011 43,258 4,083 80 13,094

Along length 

of deposit

1.0E-06 29 457,272 2,904 13,938 1,316 50 4,219

6.0E-06 71 1,119,528 7,109 34,123 3,221 75 10,330

1.0E-05 89 1,403,352 8,911 42,774 4,038 100 12,949

Short 6.0E-06 10 157,680 1,001 4,806 454 30 1,455

Table C-4 summarizes the overall cost estimates. EPA estimated that contamination 

moving transverse to the length of the deposit would be detected in 6 years after restoration is 

complete, and that contamination moving along the length of the deposit would be detected after 

the site is decommissioned and the license terminated. In fact, a plume of contamination would 

be detected only if and when someone wishing to use groundwater in the area had it tested; the 

longer the time before the plume is detected, the more extensive the area of contamination is 

likely to be, and the more costly it would be to remediate, and greater is the possibility that 

humans or ecological receptors could be exposed to the constituents. If contamination does 

occur, and is detected long after license termination, the costs of remediation could fall on the 

taxpayer, rather than the owner/operator.
C-11

Table C-4. Summary of Estimated Remediation Costs, by Scenario and Kd (Millions 

$2011)

Kd (m3/gm): 1.0E-06 6.0E-06 1.0E-05

Scenario: Transverse to the length of the ore deposit

Summed Costs $99.3 $481.0 $790.1

Scenario: Along the length of the ore deposit

Summed Costs $163.3 $586.1 $968.1

Scenario: Short, assumes small area of contamination is 

detected during long-term stability monitoring

Kd=6.0E-06

Summed Costs $35.3

The summary provided below, for each remediation scenario and assumed Kd, shows that 

costs (either summed across the duration of the pump and treat remediation operations without 

discounting, or present values discounted at 3% or discounted at 7%) increase depending on the 

size of the plume, the direction of groundwater flow, and the Kd. Comparing the estimated total 

summed costs of pump and treat remediation for Kd=6.0E-06 m3/gm (under different scenarios) 

to the cost of complying with the proposed rule, including resuming restoration if contamination 

is discovered during long-term stability monitoring (see Table 4-1 for details) demonstrates the 

advantage of monitoring long enough to detect an upward trend in some constituents while the 

plume is still small so that re-mobilization can be detected and decisions made concerning 

treatment before the contamination becomes widespread and more expensive remedies are 

needed.

C.5 References

McDonald, M.G., and A.W. Harbaugh, 1983. A modular three-dimensional finite-difference 

ground-water flow model. Open-File Report 83-875. U.S. Geological Survey, December 

28.

McWorter, D.B. and D.K. Sunada, 2010. Ground-Water Hydrology and Hydraulics; Water 

Resources Publications, LLC; ISBN-10: 1887201610; ISBN-13: 978-1887201612; 304 

pages.

Michel, T.G. and G. Hoffman, 1991. E-Field 50 Sand Mine Unit Hydrology Test, Highland 

Uranium Project, Power Resources, Inc.; Report for WDEQ/LQD Permit Number 603, 

U. S. Nuclear Regulatory Commission Docket Number 40-8857, SUA-1511; Report by

Power Resources, Inc. and Hydro-Engineering; September 1990, revised July 1991.
C-12

Pearson, F.J., Jr., C. J. Noronha and R.W. Andrews, 1983. “Mathematical Modeling of the 

Distribution of Natural 14-C, 234-U, and 238-U in a Regional Ground-Water System,” 

Radiocarbon, Vol.25, No. 2, 1983, p 291-300.

U.S. Environmental Protection Agency (EPA), 2001. Cost of Analysis for Selected Groundwater

Cleanup Projects: Pump and Treat Systems and Permeable Reactive Barriers; U.S. EPA, 

Office of Solid Waste and Emergency Response; EPA Document No. 542-R-00-013; 

Exhibit 7, page 8, February.

Zheng, C. and P.P. Wang, 1999. MT3DMS: A modular three-dimensional multispecies model 

for simulation of advection, dispersion and chemical reactions of contaminants in 

groundwater systems; Documentation and User’s Guide, Contract Report SERDP-99-1, 

U.S. Army Engineer Research and Development Center, Vicksburg, MS.
D-1

APPENDIX D

SENSITIVITY ANALYSIS: ESTIMATED COSTS AND ECONOMIC IMPACTS

This Appendix presents results of a sensitivity analysis conducted to explore the 

uncertainty around costs of sampling. In Section 3, EPA presented the assumptions for each 

phase of ISR monitoring. These assumptions, shown in Tables 3-2 through 3-5, include a range 

of sampling and analysis costs. They also reflect estimated requirements under two regulatory

alternatives and a “worst case” under which geochemical modeling does not provide assurance 

of future stability, and 30 years of long-term stability monitoring are required, in addition to 

geochemical modeling. As discussed in Section 3 above, EPA does not believe this “worst case” 

is likely to occur, because it would require that geochemical modeling conducted prior to the 

start of operations yields results that indicate that conditions would be stable long-term, but 

geochemical modeling conducted after operations have ended yields the opposite result. In 

reporting the results of the economic impact analysis in the main sections of this document, EPA 

focused on the proposed regulatory option; this appendix provides results for all the costing 

scenarios, under low, average, and high monitoring cost assumptions.

Table D-1 presents estimated costs under each alternative and cost scenario. In general, 

the costs are lowest for the proposed regulatory alternative, which includes 30 years of long term 

stability monitoring, with the potential to shorten the duration if geochemical modeling indicates 

that geochemical conditions in the wellfield and especially down-gradient from the field will 

ensure that restored conditions will remain stable over time. Costs for the other regulatory

alternative, which requires 30 years of long-term stability monitoring with no potential for 

shortening the duration, are slightly higher. Table D-1 also presents the “worst case” scenario, 

which assumes that the geochemical modeling does not provide assurance of stability, so that 30 

years of long term stability monitoring is then required. As ex[ected, these costs are the highest.

Table D-2 presents the results of a market model, which examines how the market for 

uranium (U3O8) would potentially be affected by the costs of complying with the regulation, 

under each alternative and costing scenario. The proposed regulatory alternative increases the 

cost of producing uranium by $1.30 to $1.70 per pound of U3O8. The 30-year long term stability 

monitoring with no potential to reduce duration causes the cost of uranium production to increase 

by an estimated $1.44 to $2.00 per pound. The “worst case” costing scenario causes the cost of 

uranium production to increase by $1.51 to $2.40 per pound. The lower the increase in the unit 

cost, the smaller the effect on the market. In all cases, the market price of U3O8 is projected to 

increase by less than the unit cost, domestic uranium production is projected to decline, and 

imports of uranium are projected to increase.
D-2

Table D-1. Estimated Facility and National Costs, by Costing Scenario (Thousand 2011$)

Low Average High

Proposed Rule: 30-Year Long-term Stability Monitoring 

with Geochemical Modeling to Shorten Duration

ISR Operation

La Palangana $262 $304 $343

Alta Mesa $412 $477 $540

Willow Creek $510 $591 $668

Crow Butte $1,905 $2,205 $2,493

Smith Ranch-Highland-Reynolds $8,224 $9,521 $10,766

Lost Creek $317 $367 $415

Estimated Incremental National Costs

Total Annualized Cost $11,631 $13,465 $15,226

Total Cost, Summed across LOM $379,564 $431,284 $490,514

Present Value, 3% discount rate $253,378 $289,991 $329,385

Present Value, 7% discount rate $156,468 $181,135 $204,822

Required 30-Year Long-Term Stability Monitoring

ISR Operation

La Palangana $290 $340 $404

Alta Mesa $456 $534 $635

Willow Creek $565 $661 $786

Crow Butte $2,107 $2,468 $2,931

Smith Ranch-Highland-Reynolds $9,097 $10,657 $12,658

Lost Creek $351 $411 $488

Estimated Incremental National Costs

Total Annualized Cost $12,865 $15,072 $17,901

Total Cost, Summed across LOM $684,068 $814,903 $975,573

Present Value, 3% discount rate $355,378 $419,826 $500,372

Present Value, 7% discount rate $173,072 $202,754 $240,818

(continued)
D-3

Table D-1. Estimated Facility and National Costs, by Costing Scenario (Thousand 2011$)

(continued)

Low Average High

Geochemical Modeling with 30-Year Long-Term

Stability Monitoring

ISR Operation

La Palangana $305 $390 $484

Alta Mesa $480 $613 $761

Willow Creek $594 $759 $942

Crow Butte $2,217 $2,832 $3,516

Smith Ranch-Highland-Reynolds $9,571 $12,229 $15,182

Lost Creek $369 $472 $586

Estimated Incremental National Costs

Total Annualized Cost $13,536 $17,296 $21,472

Total Cost, Summed across LOM $15,145 $18,575 $22,642

Present Value, 3% discount rate $7,999 $9,922 $12,157

Present Value, 7% discount rate $3,960 $5,060 $6,281

Scaled up from CSM to national costs based on estimated total acreage.

Table D-3 examines the ratio of the estimated costs incurred by companies owning ISR 

facilities to their revenues, to assess the potential financial impacts of complying with the rule on 

firms in the industry, especially small firms. For the two large firms, reported 2013 sales are used 

to estimate 2015 sales. Revenues for two small firms owning currently-operating ISR facilities 

are not publicly available. They are estimated based on the projected 2015 price of uranium 

($57.00 per pound) and their estimated facility production in 2015. A third small firm is publicly

traded (Uranium Energy); its 2013 sales are depressed due to market conditions; because we are 

projecting improved market conditions by 2015, we also estimate sales for this firm, based on 

estimated 2015 facility production and estimated market price. The proposed regulatory

alternative results in cost-to-sales ratios ranging from 0.1% to 1.9%, depending on the costing 

scenario. Even under the “worst case” costing scenario, costs are at most 2.7% of estimated 

company sales under the highest costing assumptions. Because costs are estimated to be less than 

3.0% of company sales for the small businesses owning currently operating ISR facilities, and 

because EPA expects at most 10 small firms may be affected by the rule going forward, EPA 

concludes that the rule will not have a significant impact on a substantial number of small firms.
D-4

Table D-2. Estimated Market Impacts by Regulatory Alternative

With Regulation in Effect

Baseline Low Average High

Proposed Rule: 30-Year Long-Term Stability 

Monitoring with Geochemical Modeling to 

Shorten Duration

Supply (1,000 pounds U3O8) 57,630 57,616 57,614 57,612 

U.S. Origin (1,000 pounds U3O8) 9,451 9,089 9,032 8,977 

ROW (1,000 pounds U3O8) 48,179 48,527 48,582 48,635 

Demand (1,000 pounds U3O8) 57,630 57,616 57,614 57,612 

Price ($/pound U3O8) $57.00 $57.21 $57.24 $57.27 

Change in Price $0.21 $0.24 $0.27 

Percentage Changes

Market Quantity −0.02% −0.03% −0.03%

U.S. Quantity −3.8% −4.4% −5.0%

Imports 0.7% 0.8% 0.9%

Price 0.4% 0.4% 0.5%

Compliance Cost per Pound $1.30 $1.50 $1.70 

Required 30-Year Long-Term Stability 

Monitoring

Supply (1,000 pounds U3O8) 57,630 57,615 57,612 57,609 

U.S. Origin (1,000 pounds U3O8) 9,451 9,050 8,982 8,893 

ROW (1,000 pounds U3O8) 48,179 48,564 48,631 48,715 

Demand (1,000 pounds U3O8) 57,630 57,615 57,612 57,609 

Price ($/pound U3O8) $57.00 $57.23 $57.27 $57.32 

Change in Price $0.23 $0.27 $0.32 

Percentage Changes

Market Quantity −0.03% −0.03% −0.04%

U.S. Quantity −4.2% −5.0% −5.9%

Imports 0.8% 0.9% 1.1%

Price 0.4% 0.5% 0.6%

Compliance Cost per Pound $1.44 $1.68 $2.00 

(continued)
D-5

Table D-2. Estimated Market Impacts by Regulatory Alternative (continued)

With Regulation in Effect

Baseline Low Average High

Geochemical Modeling with 30-Year LongTerm Stability Monitoring

Supply (1000 pounds U3O8) 57,630 57,614 57,610 57,605 

U.S. Origin (1000 pounds U3O8) 9,451 9,029 8,912 8,782 

ROW (1000 pounds U3O8) 48,179 48,585 48,697 48,823 

Demand (1000 pounds U3O8) 57,630 57,614 57,610 57,605 

Price ($/pound U3O8) $57.00 $57.24 $57.31 $57.38 

Change in Price $0.24 $0.31 $0.38 

Percentage changes

Market Quantity −0.03% −0.04% −0.04%

U.S. Quantity −4.5% −5.7% −7.1%

Imports 0.8% 1.1% 1.3%

Price 0.4% 0.5% 0.7%

Compliance Cost per Pound $1.51 $1.93 $2.40 
D-6

Table D-3. Estimated Company Cost-to-Sales Ratios by Regulatory Alternative

Estimated 

2015 Sales 

(millions 

USD) Low Average High

30 Year with Geochemical Modeling

Parent Company

Cameco $2,400.0 0.4% 0.5% 0.6%

Mestena $28.5 1.4% 1.7% 1.9%

Uranium One $530.4 0.1% 0.1% 0.1%

Uranium Energy $28.5 0.9% 1.1% 1.2%

Ur-Energy $57.0 0.6% 0.6% 0.7%

30-Year Stability

Parent Company

Cameco $2,400.0 0.5% 0.5% 0.6%

Mestena $28.5 1.6% 1.9% 2.2%

Uranium One $530.4 0.1% 0.1% 0.1%

Uranium Energy $28.5 1.0% 1.2% 1.4%

Ur-Energy $57.0 0.6% 0.7% 0.9%

Geochem with Required 30 Year

Parent Company

Cameco $2,400.0 0.5% 0.6% 0.8%

Mestena $28.5 1.7% 2.2% 2.7%

Uranium One $530.4 0.1% 0.1% 0.2%

Uranium Energy $28.5 1.1% 1.4% 1.7%

Ur-Energy $57.0 0.6% 0.8% 1.0%