Regulatory Developments and Implications for CCUS Deployment

7/26/2019 Regulatory Developments and Implications for CCUS Deployment

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D I N A K R U G E R

K R U G E R E N V I R O N M E N T A L S T R A T E G I E S L L C

J U N E 1 3 , 2 0 1 6

An Overview of thePolicy Landscape for CCUS


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2

The Regulatory Frameworkfor CCUS


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Overview

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!

EPA Office of Water, Underground Injection Control(UIC) Program, under the Safe Drinking Water Act:! Role of Class II Wells! Role of Class VI Wells!

Potential for transition of Class II Enhanced Recovery (ER) wells toClass VI

! EPA Resource Conservation and Recovery Act (RCRA):! Approach on Class VI wells

!

EPA Office of Air & Radiation: GHG Reporting Program(GHGRP)!

Accounting Requirements for quantifying CO2 sequestration in ClassII and Class VI wells

!

California Air Resources Board QuantificationMethodology


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EPAs Underground InjectionControl Program


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Description of Class II and Class VI

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! Class II UIC wells are used by the oil and gas industry.!Where CO2 enhanced oil recovery (EOR) is practiced,

CO2 can be incidentally stored in the formation.! EPA recognizes that CO2 is often stored in the Class II

setting.

! Class VI is a relatively new class of UIC well, designedfor CO2 storage in deep saline formations! The Class VI rule was promulgated in December 2010.

! To date, only a few Class VI wells have been permitted.! The requirements for Class VI well are more stringent

than the Class II program.


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Class II to Class VI Transition

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!

December 2013: EPA issued guidance on ontransitioning Class II EOR wells to Class VI.! This guidance created significant concern and confusion in the

regulated community (EOR operators and state UIC directors).

!

April 2015: EPA issued a memo outlining the keyprinciples in the Class VI rule related to the transition ofClass II ER wells to Class VI.! This memo has clarified the approach and reduced concern.

! Link to the memo:

http://water.epa.gov/type/groundwater/uic/class6/upload/class2eorclass6memo.pdf


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EPAs Transition Principles (#1 3)

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! Geologic storage of CO2 can continue to bepermitted under the UIC Class II program.

!

Use of anthropogenic CO2 in EOR operations doesnot necessitate a Class VI permit.

!

Class VI site closure requirements are not requiredfor Class II CO2 injection operations.


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Transition Principles (#4)

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! The key factor in determining the potential needto transition a CO2 EOR operation from Class II toClass VI is the increased risk to [Underground

Sources of Drinking Water]related to the significantstorage of CO2 in the reservoir, where the regulatory

tools of the Class II program cannot successfullymanage the risk.

!

Transition to Class VI should only be considered ifthe Class II tools are insufficient to manage the

increased risk.


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Transition Principles (#5 6)

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!

The Class II and Class VI directors should work togetherto address the potential need for transition of anyindividual operation from a Class II to a Class VI permit.! The Class II program director (in most cases a state official) will have

the relevant data on pressure and volume of CO2 injected into ClassII EOR operations, which will influence any transition decision.

! The best implementation approach is for states toadminister both the Class II and the Class VI UIC

programs. EPA encourages states to apply for Class VIprimacy.! No states have been granted primacy to date. North Dakota is

awaiting EPAs decision.


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The RCRA ConditionalExemption Rule


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RCRAs Conditional Exemption

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! The rule allows for a conditional exemptionfor CO2 streams that are hazardous, providedthese hazardous CO2 streams are:

1. Captured from emissions sources (e.g., notnatural domes);

2. Injected into UIC Class VI wells; and,

3.

Meet certain other conditions.! Issued in January 2014.


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Specific Requirements

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1. Transportation of the CO2 stream must be incompliance with applicable Dept. of Transportationrequirements.

2.

Injection of the CO2 stream must be in compliancewith the applicable requirements for Class VI wells.

3. No other hazardous wastes may be mixed or co-injected with the CO2 stream.

4.

Generators of CO2 and UIC Class VI well ownersmust sign a certification statement that the

conditions of the exclusion are met.


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Why did EPA promulgate this rule?

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!After evaluating the existing regulatory frameworkfor CO2 generators, CO2 transportation and CO2injection in Class VI wells, EPA concluded that:

regulations under RCRA would not provide additionalprotections for CO2 streams injected for purposes of geologicsequestration.

! Put another way, EPA concluded that the UIC Class

VI framework was sufficiently protective and thatadditional regulation under RCRA would beredundant and unnecessary.


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What about UIC Class II Wells?

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!

Most CO2 injection today occurs in Class II wells, withthe primary purpose of conducting EOR.

!

EPA states in the preamble to the the RCRA rule:[T]his conditional exemption is not intended to affect the regulatorystatus of CO2 streams that are injected into wells other than UIC ClassVI wells. [I]n the light of the several public comments on this issue,EPA does note that (based on the limited information provided in publiccomments) should CO2 be used for its intended purpose as it is injectedinto UIC Class II wells for the purpose of EOR/EGR, it is EPAsexpectation that such an injection process would not generally be a wastemanagement activity.

!

Put simply, where EOR is taking place in Class II wells,CO2 is treated as a commodity.

!

In this scenario, the CO2 stream is not considered awaste, and it is not covered under RCRA.


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EPAs Greenhouse GasReporting Program (GHGRP)


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GHGRP Requirements for Carbon Capture

! CO2 Suppliers applicability under Subpart PP:(1) Facilities with production processes that capture CO2 in

order to sequester it or otherwise inject it underground.

(2)

Facilities with CO2 production wells.(3) Importers or exporters of CO2, if the amount exceeds 25,000

tons.

!

Information reported under Subpart PP:! The mass of CO2 captured and supplied for CO2 storage, either

on-site (at the capture facility) or off-site.

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Requirements for Geologic Sequestration of CO2

!Applicability for CO2 sequestration accountingrequirements under Subpart RR :!All UIC Class VI wells must report under Subpart RR.

"

R&D facilities that apply to EPA for an exemption do not have to

report.!Any EOR operator using UIC Class II wells can opt into

Subpart RR.

! Subpart RR Requirements:! Development and implementation of an EPA-approved

Monitoring, Reporting, and Verification (MRV) plan.!Annual reporting of the amount of CO2 sequestered, along

with supporting information.

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Requirements for Injectors of Carbon Dioxide

!

CO2 Injector Applicability under Subpart UU:

!A well or group of wells injecting CO2 for EOR, including Class

II wells and wells with a R&D exemption under Subpart RR.

!

Information Reported:! Covered facilities must report basic information on the amount

of CO2 injected (including volume and source).

! Note: Subpart UU is not designed to serve as anaccounting framework for CO2 storage, because the

amount of CO2 injected does not provide sufficientinformation to quantify CO2 sequestration amounts.

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Californias RegulatoryApproach


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Californias Regulatory Framework

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!

CCS is covered under the Regulation for the CaliforniaCap on Greenhouse Gas Emissions and Market-BasedCompliance Mechanisms.

!

The CCS rule applies to CO2 suppliers, which have acompliance obligation based on the amount of CO2 intheir emissions data report.

! The regulation requires use of an [Air Resources Board]-approved carbon capture and geologic sequestration

quantification methodology that ensures that theemissions reductions are real, permanent, quantifiable,verifiable, and enforceable. See 98.852(g)


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The CA Regulatory Process

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!

In April 2016, the Air Resources Board (ARB) initiated aRegulatory Adoption Process to develop a QuantificationMethodology (QM) for CCS, using an informaldevelopment process of:! Public workshops, technical and policy discussions! Stakeholder outreach! Draft proposals! Per ARB: This process can take several years.

!

Rule-making proceedings include:! 45-day public notice and comment on proposed regulations

! Public hearings! Responses to relevant comments! Submission of the rulemaking action to the CA Office of

Administrative Law


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Key Topics being considered by ARB

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! Accounting and reporting protocols.! Evaluating existing frameworks and data verification requirements.

! Site selection and characterization.! Identifying and assessing long- and short-term risks.! Defining the Area of Review.! Requirements for remedial action, monitoring and contingency plans.

!

Site injection operations.! Injection well design for Class II vs. Class VI wells.! Injection quantity and pressure limits.! Monitoring, reporting and active site management.

!

Site Closure/Post-Closure.! Decommissioning and timeframe for ongoing monitoring.

!

Long-Term Stewardship, including responsibility andfinancial liability.


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ARB Concerns with CO2-EOR

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! Potential for overall increased oil production, inconflict with CAs oil reduction goals.

! Uncertainty with site closure, unclear responsibilities

for permanent CO2 sequestration.! Maximizing CO2 storage vs. oil production.

!

ARB plans to include requirements that are more

strict than Class II or similar.


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D I N A K R U G E R


J U N E 1 4 , 2 0 1 6

EPAs First Approved MRV Plan:

An Overview of theApproach and Process

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Overview of Presentation

! Requirements of MRV Plans under GHGRP SubpartRR MRV of the Clean Air Act

!

Approach taken in Oxys MRV Plan

! Process that led to MRV Plan approval

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Basic Information

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! EPA approved the first MRV plan under Subpart RRof the Greenhouse Gas Reporting Program (GHGRP)on December 22, 2015.

!

The MRV plan was submitted by OccidentalPetroleum Co.

! Oxy opted in to the requirements of Subpart RR.

! The MRV plan covers Oxys Denver Unit.


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Required MRV Plan Elements

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1. Facility Information2. Project Description3. Monitoring Area and

Timeframes4. Potential Leakage Pathways to

Surface5. Considerations for Site-Specific

Variables6. Baseline Determinations7. Sequestration Volume

Calculation8. MRV Plan Implementation

Schedule9. QA Program10. Records Retention

The most critical (and challenging)elements in the MRV plan are:3. Monitoring Area and

Timeframes;4. Potential Leakage Pathways to

Surface;5.

Considerations for Site-SpecificVariables; and

6. Baseline Determinations.

Significant time was spent:

! Developing strong approaches;! Responding to EPA questions and

ideas;! Revising, as necessary; and! Ensuring that these elements were

fully and clearly described in theplan.


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Each MRV Plan will be Unique

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! EPA does not require the use of any single approach/technique all MRV Plans.

!

The operator must identify appropriate site-specific

monitoring and quantification approaches/techniques.

! The selected approaches/techniques will bedetermined based on site conditions, such as:! Geology

! Likely leakage pathways! Current site monitoring approaches

! Other


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The Basis for Occidentals Approach

1. Knowledge of the subsurface, gained through CO2EOR experience.

2. Oxys standard operating procedures for CO2-EOR.

3.

The operating history at the Denver Unit.4. The flexibility to tailor the MRV plan for specific

site characteristics, as provided in Subpart RR.

5.

Feedback from EPA during the process of

developing the MRV plan.

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Key Elements Supporting the MRV Plan

1. Denver Unit has a strong containment zone with nofaults or fractures.

2. Denver Unit is most updip in the Wasson Field,

which will tend to keep CO2 in the formation overtime.

3. Key focus of Oxys risk assessment is existingwellbores, implemented via:

! Compliance with regulatory requirements.!A rigorous program of subsurface performance and well bore

monitoring.

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Very Low Risk for Most Theoretical Leakage Pathways

! Faults

! Natural and InducedSeismicity

! Previous Operations

! Overfill through

Lateral Spill Points

! Dissolution of CO2 intoFormation Fluid and

Subsequent Migration

!

Drilling Through theCO2 Area

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Key Elements (2)


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Monitoring Information Management

! Leakage detection via:

! Daily visual inspections ateach facility and usingaerial inspections.

! Use of H2S monitors wornby all personnel and fixedmonitors at the Denver

Unit CO2 Recovery Plant.! Monitoring of injection

and productionperformance.

! Piggy-backing on CO2-

EOR Control Systems:! Use of automated data

systems for performanceevaluation and incident

tracking.

! Developing criteria toidentify those events thatcould involve CO2

leakage.

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Key Elements (3)


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OXY EPA

! Shared draft MRV plan withEPA in late Spring 2014.

! Revised draft and resubmitteda few more times.

! Submitted final version in lateSummer 2015.

! EPA provided feedback oninitial draft.

! EPA provided additionalfeedback on subsequent drafts.

! EPA approved the MRV Plan onDecember 22, 2015.

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An Iterative MRV Plan Review Process


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The EPA Process

! Entire approval process took about 18 months.! First 12 months: Oxy was refining the MRV Plan.

! Last 6 months: EPA was developing the approval decision,and briefing up.

! Following an MRV Plan approval, interestedparties have 30 days to appeal to EPAs

Environmental Appeal Board (EAB).! Focus is on the elements of EPAs approval document.

!No appeals were filed on the Denver Unit MRV plan

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A few tips for those considering an MRV Plan

! Review the Oxy plan for the Denver Unit, with thegoal of understanding the general requirements andhow to present the necessary information.

!

Meet with EPA after identifying the site, and aninitial approach for the MRV plan has beendeveloped.

!

Expect significant feedback from EPA, and several

revisions of the plan.! EPAs goal is to ensure that no approved MRV Plan will be

overturned by the Environmental Appeals Board.

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MRV Plan Links36

!Approved MRV Plan for the Denver Unithttps://www.epa.gov/sites/production/files/2015-12/documents/denver_unit_mrv_plan.pdf

! EPAs Decision on the Denver Unit MRV Planhttps://www.epa.gov/sites/production/files/2015-12/documents/denver_unit_final_decision.pdf

Note: The decision document is long, as it contains all of the MRVPlan drafts submitted by Occidental, as well as the revisionsrequested by EPA.


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CCUS Opportunitiesunder EPAs Clean Power Plan


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Key GHG Rules for Power Plants

! Final Rule: Standards of Performance forGreenhouse Gas Emissions from New, Modified, andReconstructed Sources: Electric Utility GeneratingUnits (EGUs).! Published in the Federal Register on October 23, 2015.

! Litigation pending.

! Final Rule: Carbon Pollution Emission Guidelinesfor Existing Stationary Sources: EGUs.

! Published in the Federal Register on October 23, 2015.! Stayed by the Supreme Court on February 9, 2016.

! DC Circuit has decided to hear the case en banc, and willhold oral argument on September 27, 2016.


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The NSPS Final Rule


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CCS in the Final NSPS

! EPA has determined that the Best System ofEmission Reduction (BSER) for new steam units isa highly efficient supercritical pulverized coal unit

with partial CCS.! The required emission rate for new fossil-fired EGUs under the

NSPS is 1,400 pounds CO2 per MWh-gross.

! This is equivalent to the performance of an SCPC unitcapturing about 20% of its carbon pollution.

!

EPAs final BSER is less stringent than the proposedstandard of 1,100 pounds CO2 per MWh-gross.


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NSPS rules set a Standard, not a Market-Based Approach

! New Coal Units:

! Few (if any) new builds areexpected.

! These units would have tomeet the required rate of1,400 pounds CO2/MWh-gross.

! Within the NSPS, there is noincentive to reduce emissionsbelow the standard, becauseNSPS units cannot trade.

! New NGCC Units:

! Many units are likely to bebuilt.

! These units can comply withthe final standard (1,000 lbs-CO2/MWh-gross) withoutCCS.

! As with new coal units,within the NSPS, there is noincentive to reduce emissionsbelow the required standard.

CCS Opportunities under the NSPS


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CCS in the Final NSPS

!

If an affected power plant captures CO2 to meetemissions standard:! The power plant must report under Subpart PP (Suppliers of CO2)

regarding whether the CO2 was injected on-site, or transferred for

off-site injection.! In addition, both on-site and off-site injection of captured CO2 must

be reported under Subpart RR (Geologic Sequestration of CO2).

! Innovative Technology Waivers are available for CCUprojects, based on a demonstration that the project

would store CO2 as effectively as geologic sequestrationwith minimal risk to health and welfare.

!

See 80 FR 64654-55, 60.5505(f) and (g)


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Clean Power Plan Final Rule


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CCS in the Final CPP

!

EPA confirms CCS is an available compliance option.! We are confirming our proposal that CCS is not an element of the

[Best System of Emission Reduction], but it is an availablecompliance measure for a State Plan. 80 FR 64884

!

Affected EGUs may utilize retrofit CCS technology toreduce reported stack CO2 emissions from the EGU.

!

Retrofitting CCS on an existing unit should not beconsidered a modification, which would bring the unit

into the NSPS.! Footnote 898: Addition of retrofit CCS technology should not

trigger CAA section 111(b) applicability for modified or reconstructedsources. 80 FR 64883


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CCS in the CPP (continued)

!

Following the requirements of the NSPS and CPP will notlead to a change in the UIC well class.! Footnote 901: Under final requirements , any well receiving CO2

captured from an affected EGU, be it a Class VI or a Class II well,

must report under Subpart RR. A UIC Class II wells regulatorystatus does not change because it received such CO2, nor does itchange by virtue of reporting under Subpart RR. 80 FR 64883

!

Affected EGUs that apply CCS under a State Plan mustmeet the same requirements as new units that implement

CCS under the Final NSPS.! Specifically, Subparts PP and RR of the GHGRP, as described on

slide 7.


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CCS Opportunities: Rate-Based Trading

!

New sources cannot participate in the CPPs rate-basedtrading approach, per 60.5800(c)(1), 80 FR 64950.

!

CCS retrofits are allowed at existing coal- and gas-fired

units.! The Emission Rate Credits (ERCs) generated by such projects could

be used by the EGU, or sold to other EGUs.

!

The monitoring requirements for ERCs generated byexisting power plants are much less complicated than the

requirements for renewable energy and energy efficiency.! ERC prices alone are unlikely to be high enough to

incentivize CCS retrofits in a rate-based system.


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CCS Opportunities: Mass-Based Trading

! Incentivize CCS retrofits of existing power plants via:! Targeted allowance allocation;

! Establishing allowances set-asides;

!

Using allowance auction revenues.! Bring new sources into the existing source program.

! States that implement this approach would have a largeremissions cap to cover the additional sources.

! This approach would enable both new and existing power

plants to consider developing CCS projects.


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The best way to drive CCS under the CPP

! Create state-level mass-based trading markets thatinclude both new and existing sources.

!

This approach is the most likely to incentivize CCSbecause it:! Establishes a clear price signal on CO2 that will apply to both

new and existing power plants.

! Ensures that all fossil generation new and existing, gas andcoal will have incentives to consider CCS.

! Including new sources will probably lead to higher allowance

prices, which would be helpful for CCS.

!Additional Federal and/or state financial incentivesmay be needed.


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A Brief Discussionon Financial Incentives


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Currently, few incentives for CCS50

!

Tax Credits for Renewables and CCS not comparable.From 2010 2014:! Renewable Federal Revenue Cost : $37.3 billion

! CCS Federal Revenue Cost: $1 billion

!

DOE Budget Outlays from 2012 2016:! Renewables: $2.5 billion

! CCS: $1 billion

Information for this section taken from the National CoalCouncil report Leveling the Playing Field: Policy Parityfor Carbon Capture and Storage Technologies.


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IRC Section 45Q Tax Credit51

!

Promulgated in 2009.

!

Provides a financial incentive to the capturer of the CO2of $20/ton for Class VI injection and $10/ton for Class IIEOR injection.

!

Modifications for the 45Q tax credit are needed:! Lower the limit on CO2 capture to enable smaller sources to

participate. (Currently set at 500,000 tons/year.)

! Provide transferability of the credit between parties in the captureand injection chain of custody.

!

Increase the credit for both Class VI and EOR injection.!

This incentive appears to have the best prospectscurrently.


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Other Financial Incentives52

!

Contracts for Differences (CFD)! DOE could create an approach under which a limited number of

projects could receive financial support from a menu of incentives.! First step would likely be for DOE to lay out how a CFD program

would work.

!

Production and Investment Tax Credits! Available for renewables, but not for CCS.

!

Tax-preferred bonds! Funded by local governments.! Available for renewables, but not for CCS.

!

Master Limited Partnerships! Allows for taxation at the individual level, as opposed to both the

individual and corporate level.! Currently neither renewables nor CCS are eligible.


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Regulatory Developments and Implications for CCUS Deployment