1 
  
 State of Oregon Department of Environmental Quality  
Notice of Proposed Rulemaking  
August 2 2, 2023  
Climate 2023 Rulemaking  
 
 
This package contains the following documents:  
• Notice of Rulemaking  
• D
raft Rules – Edits Highlighted 
• Draft Rules – Edits Included (final clean version)  
 
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2 
 Table of Contents 
Introduction ............................................................................................................... 3 
Request for Other Options  ........................................................................................ 3 
Overview  ................................................................................................................... 4 
Procedural Summary  ................................................................................................ 5 
Summary of proposed changes  ................................................................................ 7 
Statement of need .................................................................................................. 21 
Rules affected, authorities, supporting documents  ................................................. 30 
Documents relied on for rulemaking ....................................................................... 31 
Fee Analysis  ........................................................................................................... 32 
Statement of fiscal and economic impact  ................................................................ 33 
Statement of Cost of Compliance ........................................................................... 41 
Documents relied on for Fiscal and Economic impact  ............................................ 45 
Advisory committee fiscal review  ............................................................................ 46 
Housing cost  ........................................................................................................... 47 
Racial Equity  ........................................................................................................... 48 
Environmental Justice Considerations  .................................................................... 49 
Federal relationship  ................................................................................................ 50 
Land use  ................................................................................................................. 54 
EQC Prior Involvement  ........................................................................................... 56 
Advisory Committee  ................................................................................................ 57 
Public Engagement  .................................................................................................  59 
Accessibility Information  ......................................................................................... 61 
Draft Rules –  Edits Highlighted  ............................................................................... 62 
Draft Rules –  Edits Included  ................................................................................. 210  3 
  
Introduction  
 
DEQ invites public input on proposed permanent rule amendments to chapter 340 of the Oregon Administrative Rules .  DEQ is proposing rule amendment s to chapter 340, D ivision s 
215, 272, 271, 216, and 12. 
• Greenhouse Gas Reporting Program, Division 215 
• Third Party Verification, Division 272  
• Climate Protection Program, Division 271  
• Air Contaminant Dis charge Program, Division 216 
• Enforcement Procedure and Civil Penalties, Division 12  
 
Request for Other Options 
 DEQ is proposing these rule amendment s to support implementation of the Climate 
Protection Program, Greenhouse Gas Reporting Program , and Third Party Verification  
Program . Based on agency  experience  implementing these programs , the proposed rule 
amendments  provide regulate d entities with addition al clarification on  compl ying with 
program  requirements , propose program adjustments to incorporate newly regulated entities 
more effectively , and support robust greenhouse gas emission reporting. These options  were 
informed  by input and comments provided by the r ulemaking a dvisory c ommittee, public 
comments submitted by a variety of stakeholders, including input provided by the Equity 
Advisory Committee for the Climate Protection Program Community Climate Investments program . 
 During the public comment period, DEQ requests input on any part of the proposed rule 
amendments and is specifically requesting input on other options for the following:  
 
• Approaches for accounting of exported fuels from intermediate storage that ensure 
accurate accounting and are less burdensome  than the proposed amendments  (see 
OAR 340 -215-0110(4)(b) ). 
• Refinements or clarifications to the reporting of biogas, biomethane, and hydrogen through the use of  book and claim accounting in Division 215 that maintain accurate 
and verifiable reporting and assurance of avoiding double claims on supply or use of those fuels .  
• Modifications to compliance instrument distribution methodology for liquid fuels 
and propane  supplier s regulated under  the Climate Protection Program (see OAR 
340-271-0420 and 340- 271-0430).  
• Suggestions for how compliance instrument holding limits for  covered fuel supplier s 
regulated by the Climate Protection Program  could be implemented (see OAR 340 -
271-0420 and 340- 271-0430) . 
• Use of subcontractors to meet minimum lead verifier requirements for the purpose of 
approving third party verification bodies (see OAR 340 -272-0210 ( 3)(a) and OAR  
340-272-0300 (3)(b)) .  4 
 • Circumstances under which modifications at an industrial facility would trigger a 
BAER assessment  under the Climate Protection Program (see OAR- 340-271-0310).  
 
Overview  
 The Climate 2023 R ulemaking is a joint rulemaking  of DEQ’s teams that implement the 
Greenhouse Gas Reporting Program (GHG RP), Third Party Verification ( TPV) and Climate 
Protection Program (CPP). The rule making propose s a variety of clarifications to program 
requirements and a limited number of p rogram  modifications . The rulemaking incorporates  
process improvements and technical clarifications for regulated companies while continuing to support the goals of these program s. DEQ is conducting a  joint rulemaking , inclusive of 
amendments to multiple divisions , due to the interconnectedness of these three programs.  
 Proposed rule amendments include  revisions to how DEQ distributes compliance 
instruments to fuel suppliers regul ated by the Climate Protection Program, clarifying exempt 
and covered emissions for natural gas utilities regulated by the Climate Protection Program, additional requirements and clarifications for regulated entities reporting and supplying biomethane and hydrogen, new reporting requirements for electricity sector suppliers to 
implement the state’s Clean Energy Targets, and improvements to the Third party  
Verification process for emissions.  
 
Greenhouse Gas Reporting Program, Division 215  
 In 2008, the Oregon E nvironmental Quality C ommission (EQC)  adopted the initial GHG RP  
rules to provide DEQ with the authority to collect comprehensive data on Oregon’s greenhouse gas emissions. The rules govern the collection of annual greenhouse gas emissions data and related information from certain entities, including large industrial emitters, fuel suppliers, and electric utilities. Data collected through th is program supports 
implementation of Oregon’s GHG emissions mitigation programs , is used to inform  policy 
development and decision makers,  and is the data used to t rack progress towards Oregon’s 
emission reduction goals. This rulemaking propose s amendment s to the GHG RP rules to 
support improved implementation of the program  by increasing  the clarity  of the rules , 
adding definitions , and specifically  address ing recordkeeping and reporting requirements 
associated with reporting contractual deliveries of specific fuels, including biomethane.  
 
Third Party Verification, Division 272  
 The EQC  adopted Third Party Verification rules in 2019 in order to add an additional layer 
of certainty to the accuracy of data reported to the Greenhouse Gas Reporting and Clean Fuels Programs. These rules govern administration of third party verification, from DEQ approval of verifiers and verification bodies, to third party verification procedures to be followed by entities and verification service providers. This rulemaking proposes an 
expansion of third party verification requirements to all regulated entitie s subject to the 
Climate Protection Program rules (Division 271) and to all electricity service suppliers, 
regardless of emissions level. Additionally, the proposed amendments clarify third party 5 
 verification requirements for reporters of biomethane and hydrogen, propose minor 
implementation improvements to streamline the administration of the program for stakeholders, add clarity to existing requirements, add new definitions, and correct typos.  
Climate Protection Program, Division 271  & Air 
Contaminant Di scharge Permits, Division 216   
 Adopted by the EQC in December 2021, the Climate Protection Program sets a declining limit, or cap, on greenhouse gas emissions from fossil fuels used throughout Oregon, including from the use of diesel, gasoline, natural gas and propane used in transportation, residential, commercial and industrial settings .  Entities  subject to the declining emission 
caps (covered fuel suppliers) include liquid fuels and propane suppliers and natural gas utilities (local distribution compa nies).  The program also regulates site- specific emissions at 
certain manufacturing facilities  (stationary sources)  not covered by the emissions cap , such 
as emissions from industrial processes, with a best available emissions reduction (BAER) approach.    For natural gas utilities , this rulemaking proposes clarification s to ensure that emissions 
from natural gas delivered by a utility , whether combusted or oxidized, are covered 
emissions  for natural gas utilities . For liquid fuels and propane  fuel supplier s, this 
rulemaking propose s mo difications to  the compliance instrument distribution methodology  
in tandem with modifications to the reserve for compliance instruments  to better incorporate 
new fuel suppliers and proposes a holding limit for compliance instruments .  For stationary 
sources, this rulemaking de lineates the circumstances under which modifications at a facility 
would trig ger a  BAER assessment , proposes a new source category for an Air Contaminant 
Discharge Permit (ACDP) related to BAER, and specifies additional requir ements for public 
comment during a BAER process.  
  
Procedural Summary 
More information  
 Information about this rulemaking is on this rulemaking’s web page: 
Climate 2023 
Rulemaking . 
 
Public Hearings  
 DEQ plans to hold one public hearing  virtually.  
 Date:  Sept . 18, 2023 
Time: 4 p.m.  PT 
Join via Zoom
  
 6 
 How to comment on this rulemaking proposal  
 
DEQ is asking for public comment on the proposed rules. Anyone can submit comments 
about this rulemaking by email, regular mail, or at the public hearing.  
Comment deadline  
 DEQ will only consider comments on the proposed rules that DEQ receives by 4 p.m., on Sept. 22, 2023. 
 
Submit comment by email to: 
Climate.2023@deq.oregon.gov   
 
Note for public university students:  
 ORS 192.345(29) allows Oregon public university and OHSU students to protect their university email addre sses from disclosure under Oregon’s public records law. If you are an 
Oregon public university or OHSU student, you may omit your email address when you complete the online form to submit a comment.  
 
By mail  
 Oregon DEQ Attn: Elizabeth Elbel and Nicole Sin gh 
700 NE Multnomah St., Room 600 Portland, OR 97232-4100  
Sign up for rulemaking notices 
 Get email or text updates about this rulemaking by s igning up on the rulemaking website: 
https://www.oregon.gov/deq/rulemaking/Pages/climate2023.aspx
. 
 
What will happen next?  
 DEQ will include a written response to comments in a staff  report DEQ will submit to the 
Environmental Quality Commission. DEQ may modify the rule proposal based on the comments  received .  
 Proposed rules only become effective if the Environmental Quality Commission adopts them. DEQ intends to submit the proposed rule changes to the EQC on or after Oct . 11, 
2023. 
  7 
 Summary of proposed changes 
 
Greenhouse Gas Reporting Program, Division 215  
 
Proposed amendments to the GHG RP rules include clarifying language in the existing rules, adding or updating definitions, adding new requirements to improve data quality, clarifying or expanding upon existing requirements and proposing new enforcement rul es applicable to 
covered fuel suppliers subject to the Climate Protection Program.  
 A specific goal of this rulemaking includes proposing language to expand upon the existing requirements f or reporting contractual deliveries of biomethane  and hydrogen by s pecifying 
the requirements f or use and reporting of book and claim accounting. For example , the 
proposed rule language  address es how to  accurately  identify and account for regulated 
emissions  in systems that comingle regulated emissions with carbon dioxide  emissions from 
combustion of biomass derived fuels , which are exempt from most air quality regulation 
under O RS 468A.020(3)(a) , including the Climate Protection Program.  
 To further this goal, DEQ is soliciting feedback from stakeholders related to the reporting of biogas, biomethane and hydrogen. Based on initial feedback from our rules advisory committee meetings, which include comments from committee members and the public, DEQ is proposing amendments to Division 215 related to the reporting of these fuels, including:  
 
• Refining the definition of biomethane to exclusively refer to fuel produced from biomass -derived feedstock. Amendments eliminate the conflation of the ter ms 
biomethane and renewable natural gas (RNG). RNG is a term which encompasses a broader range of natural gas substitutes, including some synthetic fuels produced from fossil fuel feedstocks .   
• Clarifying current provisions that allow for contractual deliv ery of these fuels to 
specify the use of book and claim accounting when gas is injected into the natural gas transmission and distribution network connected to Oregon. 
• Clarifying eli gibility requirements including gas quality, time of injection  and 
geographical requirements , including  specifying that  fuel must be injected into a 
pipeline during the same emissions data year as it is reported, and that fuel must be injected into a  natural gas  transmission and distribution pipeline network connected 
to Oregon.  
• Creating requirements for attestation and retirement of environmental attributes related to these reported fuels.  
• Expanding upon the reporting and recordkeeping requirements  for such fuels . For 
example, requiring reporting of source and type of biomass d erived feedstock (s) 
used, fuel production processes, and the fuels’ carbon intensity. 
• Allowing for the use of electronic tracking of claims on environmental attributes 
associated with reported fuels.  
 8 
 In addition to these amendments , DEQ is proposing new requirements for entities subject to 
third party verification. These entities must now develop and maintain GHG data m onitoring 
plans. Previously this requirement only applied to entities that also reported to EPA ’s 
reporting program . The proposed requirement would impact entities across sectors and 
would ensure that these entities employ standardized best practice in maintaining data 
systems.  
 Several  of the proposed clarifying and technical amendments to GHG RP rules impact 
specific sectors such as stationary sources, fuel suppliers or electricity suppliers. Those are 
best described by sector and summarized below:  
 
• Amendments impacting stationary sources include clarifying the use of DEQ 
applicability requirements and EPA quantification methodology for reporting unde r 
Division 215, defining the term “carbon dioxide supplier ” and related reporting 
requirements, and technical amendments for reporting emissions from foam -blowing 
activities. Stationary sources may also report the use of biogas, biomethane and 
hydrogen and are impacted by proposed amendments  related to reporting  of those 
fuels.   
• Amendments impacting fuel suppliers include updates to the definition s of “position 
holder ” and “related entity. ” Amendments clarify requirements  for accounting for, 
reporting, and documentation of exported fuels. DEQ is also proposing additional 
enforcement language applicable to fuel suppliers who misreport emissions  under 
Division 215, and that are subject to Division 271. 
• Amendments impacting nat ural gas suppliers include clarifying reporting 
requirements for biomethane and hydrogen. Local distribution companies would also be subject to the newly proposed enforcement rules  under Division 215 for 
misreporting emissions that impact compliance  under Division 271.    
• Amendments impacting electricity suppliers include clarifying the use of a cost 
allocation methodology approved by the Oregon Public Utility Commission for 
multiju risdictional electricity supplier reporting. The proposal also includes new 
requirements to identify certain facilities related to the evaluation of c lean energy 
targets.  
 
Third Party Verification, Division 272  
 
DEQ’s proposed amendments to the Third Part y Verification rules include an expansion of 
the third party verification requirements to cover all regulated entities subject to the Climate Protection Program rules (Division 271) and all electricity service suppliers, regardless of emissions level. The proposed amendments also clarify third party verification requirements 
for reporters of biomethane and hydrogen, add new definitions, and suggest improvements to the verification rules that simplify implementation.  
 Amendments to Division 272 include:  
• Expansion of third party verification applicability to all regulated entities subject to 
the Climate Protection Program rules (Division 271), regardless of emissions level. 9 
 The majority of these entities are already subject to third party verification under the 
existing requirements . 
• Expansion of third party verification applicability to all electricity service suppliers, regardless of emissions level. The majority of these entities are already subject to 
third party verification under the existing requirements . 
• Amending minimum lead verifier requirements for the approval of verification 
bodies to allow subcontractors to be used to meet these requirements , and adding a 
definition of subcontractor. DEQ’s existing regulations contain strict provisions for 
verific ation body applications, and all verifiers regardless of employment status with 
a verification body are subject to DEQ’s application, training and exams 
requirements for verifiers before approval is issued . 
• Addition of language to clarify third party verif ication requirements for reporting of 
biomethane and hydrogen, including information that must be reviewed by the 
verifier.  
• Clarifying  edits to existing requirements, including regarding  submission of forms, 
timing of site visits, and timelines for submiss ion of required information.  
 
Climate Protection Program, Division 271  & Air 
Contaminant Discharge Program, Division 216  
 
Proposed changes to the Climate Protection Program are intended to better align staff resources and timelines with the GHG RP and T PV, more quickly incorporate new covered 
fuel suppliers into the annual distribution of compliance instruments , and provide greater 
clarity where needed for compliance entities on program require ments while continu ing to 
support  emissions reduction targets  and a  competitive market  for compliance instruments.  
 For covered fuel suppliers  that are local distribution companies  this rulemaking proposes 
clarifications to ensure that emis sions from natural gas delivered by a utility, whether 
combusted or oxidized, are covered emissions .  For  covered fuel suppliers that are liquid 
fuels and propane suppliers , DEQ is  proposing changes to the annual  compliance instrument 
distribution methodology, modifications  to the compliance instrument reserve, the addition 
of holding limits for compliance instruments , and modifications to the timeline for the 
distribution of compliance instruments and demonstratio n of compliance.  Specifically, as 
relates to the distribution  and holding of compliance instruments DEQ is proposing to:  
 
• Stop using the three -year evaluation period currently used by DEQ to determine the 
number of compliance instruments annually distributed to each liquid fuels and 
propane supplier . 
• Use the most recent unverified emissions data (prior calendar year) submitted by fuel 
suppliers to the Greenhouse Gas Reporting Program  to determine the number of 
compliance instruments annual ly distributed to each liquid fuels and propane 
supplier . 
• Apply a verified  emission data correction factor in  the subsequent annual distribution 
of compliance instruments if the verified emissions on which the prior year’s 10 
 distribution was made are differe nt from the unverified emissions on which that 
distribution was originally based.  
• Delineat e the m ethodology for distributing compliance instruments from the 
compliance instrument reserve.  
• Remov e the limitation on the number of compliance instruments that DEQ can 
distribute to a liquid fuels and propane supplier  from the compliance  instrument 
reserve.  
• Calculat e a compliance instrument holding limit reduction for each covered fuel 
supplier following the  end of a compliance period, but prior to the required 
demonstration of compliance . 
o Each f uel supplier would be notified by DEQ in October 2025 of its 
calculated holding limit and whether they would exceed the holding limit 
based on the number of compliance instruments they are holding at the time 
of that notice. The deadline for covered fuel suppliers to comply with 
individual holding limits would be November 22, 2025.  
o Any adjustments to an  annual compliance instrument distribution due to a 
holdi ng limit reduction (essentially a covered fuel supplier that exceeds its 
individual  holding lim it) would be applied for the first time in the 2026 
annual compliance instrument distribution.  
o The c ompl iance instrument holding limit reduction is the number of 
compliance instruments held by  a fuel supplier that exceeds one and a half 
times the fuel supplier’s sum of compliance obligations for  each year of  the 
compliance period that just ended (See Table 1) .  
• Adjust the timeline for requests from the co mpliance instrument reserve, the annual 
distribution of compliance instruments by DEQ , and demonstration of compliance  to 
accommodate these changes. (See Figure 1 , Figure 2 , and Figure 3).  
 
 11 
  
 
Figure 1: Proposed Timeline for Distribution of 2024 Compliance Instruments  
 
 
Figure 2: Proposed Timeline for Distribution of 2025 Compliance Instruments  
 
 
12 
 Table 1: Holding limit reduction calculation example  
Company  Total Emissions 
Obligation  
(MT CO2e)  Compliance 
Instrument 
Holding Limit  Compliance 
Instruments Held 
on November 22 Holding Limit 
Reduction  for 
Next Annual 
Distribution  
Fuel Supplier A 12,000,000 18,000,000 17,000,000 0 
Fuel Supplier B 750,000 1,125,000 1,300,000 175,000 
 
 
Figure 3: Timeline: Applying Proposed Compliance Instrument Holding Limits  
 
 For stationary sources, this rulemaking delineates the circumstances under which modifications at a facility would trigger a BAER assessment . Specifically, the proposed rule 
amendments would require stationary sources that are proposing a modification to their 
facility or permit to go through BAER before receiving approval for the modification if:  
 
• The modification the source is  proposing requires a modification to their ACDP or 
Title V air permit, or the source is requ esting approval of construction that is a Type 
2, 3 or 4 change under OAR 340-210-0225. 
13 
 • The modification would increase the source’s PTE of BAER  covered emissions by 
10,000 MT CO2e /year or more . 
• The source’s PTE BAER covered emissions after the modification would be 25,000 
MT CO2e per calendar year  or more . 
• The source is not already subject to BAER (it hasn’t had  actual BAER covered 
emissions  of 25,000 MT CO2e or more in any year); and 
• DEQ determines that the modification would represent a significant change to the 
equipment or processes that emit covered emissions at the source. 
 
Sources with  actual BAER covered emissions of 25,000 MT CO2e/year or more are already 
subject to BAER as exi sting sources, and DEQ would not require them to go through BAER 
prior to approval of a modification.  This rulemaking also specifies additional requirements for public comment during the BAER process. This rulemaking also proposes a new air quality permitting requirement for 
stationary sources that are not currently required to obtain an air quality permit but have the 
capacity to emit 25,000 MT CO2e or more of BAER covered emissions. Such sources would be required to get a Basic ACDP and either go through the BAER process or  request 
a permit limit to set  their PTE for covered emissions  to less than 25,000 MT CO2e per year , 
 
Rules Summary 
 As OAR 166 -500-0030(1)(e) requires, the following are included to provide a brief 
summary of the proposed new rules and existing rules affected by this rulemaking.  
OAR Chapter 340, Division 215 
 
Rule 
Number  Rule Title  Explanation  
340-215-0020 Definitions  This rulemaking  update s existing 
definitions and add s new definitions . 
340-215-0030  Applicability  This rulemaking p ropose s amendments to 
clarify reporting applicability, particularly  
for solid waste landfills . 
340-215-0034  Changes in Ownership and 
Cessation of Reporting 
Requirements  This rulemaking proposes amendments to  
clarify reporting and notification requirements when a change of ownership 
for a regulated entity occurs.  
340-215-0040  Greenhouse Gas 
Registration and Reporting Requirements  This rulemaking proposes amendments to 
address requirements for reporting related 
entity information and clarifies reporting of 
contractual deliverie s of biomethane and 
hydrogen  using book and claim accounting . 
340-215-0042  Recordkeeping 
Requirements  This rulemaking proposes amendments to 
update the requirements for GHG data 14 
 monitor ing plans for certain entities , 
expand the requirements for recordkeeping 
of exported fuel products and adds  
requirements for recordkeeping related to the reporting of biogas, biomethane and 
hydrogen. This includes book and claim 
accounting requirements re lated to 
reporting contractual delivers of certain 
fuels.  
340-215-0044  Emissions Data Reports  This rulemaking proposes amendments to  
clarify when individual reports must be submitted  by a regulated entity and the 
information required when reporting 
biomass -derived fuel s or hydrogen. The 
proposed rules specifically address the 
reporting of biomethane  and hydrogen and 
the use of book and claim accounting.  
340-215-0046 Reporting Deadlines  This rulemaking proposes amendments to  
clarify when reports must be submitted and 
the deadlines that apply to new 
recordkeeping requirements . 
340-215-0105 Requirements for Air 
Contamination Sources  This rulemaking proposes amendments to 
clarify quantification methodology requirements and exemptions  for reporting 
by stationary sources . The proposed 
amendments address reporting  by carbon 
dioxide suppliers , in-state producers of 
goods containing fluorinated greenhouse gases, and entities reporting biogas, 
biometha ne or hydrogen use.   
340-215-0110  Requirements for Fuel 
Suppliers and In- State 
Producers  This rulemaking proposes amendments to 
clarify reporting requirements  for position 
holders  and propose new notification and 
recordkeeping requirements for exported 
fuels.  
340-215-0115  Requirements for Natural 
Gas Suppliers and In -State 
Producers  This rulemaking proposes amendments to 
clarify  the reporting  and recordkeeping 
requirements for  reporting contractual 
deliveries of biomethane and hydrogen by natural gas suppliers  using book and claim 
accounting.  
340-215-0120  Requirements for 
Electricity Suppliers  This rulemaking p ropose s amendments  to 
clarify that a cost allocation methodology 
approved by the Oregon Public Utility 
Commission  must be used for  
multijurisdictional electricity supplier  15 
 reporting . Amendments also propose  
requirements for identifying PURPA 
Qualifying Facilities reported to DEQ.   
340-215-0130  Separate Violations  This rulemaking proposes  a new rule that 
would identify each metric ton of 
emissions  misreported by a  covered fuel 
supplier that  impacted applicability 
determinations, compliance instrument distribution, or compliance obligations under Division 271, as a separa te violation 
under Division 215 . 
 
OAR Chapter 340, Division 272 
 
Rule 
Number  Rule Title  Explanation  
340-272-0020  Definitions  This rulemaking adds a new definition  for 
subcontractor.  
340-272-0100  General Requirements for 
Verification of Reports and 
Fuel Pathway Applications This rulemaking proposes an amendment 
to clarify that the verification body may submit the conflict of interest assessment 
on behalf of the responsible entity . 
340-272-0110  Requirements for 
Verification of CFP Reports and Fuel Pathway Applications Submitted under OAR Chapter 340, 
Division 253  This rulemaking proposes amendments 
clarifying CFP fuel transaction types subject to verification . 
340-272-0120  Requirements for 
Verification of GHG Reporting Program Emissions Data Reports Submitted under OAR 
Chapter 340, Division 215  This rulemaking proposes amendments to 
expand third party verification applicability to all entities subject to the Climate Protection Program and all electric companies and electricity service suppliers 
regardless of emissions level . 
340-272-0210  Applications and Criteria 
for DEQ Approval of Verification Bodies and Verifiers  This rulemaking proposes an amendment 
allowing subcontractors to meet minimum lead verifier requirements for the p urposes 
of qualifying verification bodies and ensures that subcontractors used for this 
purpose are DEQ approved . 
340-272-0220  DEQ Review and 
Approval of Verification 
Bodies and Verifiers  This rulemaking proposes minor clari fying  
edits to this section .   
340-272-0300  Requirements for 
Verification Services  This rulemaking removes language 
specifying that subcontractors may not be 16 
 used to meet minimum lead verifier 
requirements or act as independent 
reviewers  and clarifies requirements for 
subcontracting verification  services . 
340-272-0350  DEQ Review and 
Approval of Verification and Re -verification 
Requirements  This rulemaking proposes minor clari fying  
edits to this section .     
340-272-0405  Notice of Verifi cation 
Services  This rulemaking proposes amendments to 
clarify the timing of the site visit and require verifiers in training to be included 
on the form . 
340-272-0415  Verification Plan  This rulemaking corrects typo(s) in this 
section.  
340-272-0445  Log of  Issues  This rulemaking corrects typo(s) in this 
section.  
340-272-0450  Material Misstatement 
Assessments for CFP Fuel Pathways and Quarterly Fuel Transactions Submitted Under OAR 
Chapter 340, Division 253  This rulemaking corrects typo(s) in this 
section.  
340-272-0455  Material Misstatement 
Assessments for CFP Project Reports Submitted Under OAR Chapter 340, 
Division 253  This rulemaking corrects typo(s) in this 
section.  
 
340-272-0460  Material Misstatement 
Assessments for Emissions Data Submitted U nder 
OAR Chapter 340, 
Division 215  This rulemaking corrects typo(s) in this 
section.  
 
340-272-0470  Review of Operations and 
Emissions for Emissions 
Data Reports Submitted 
under OAR Chapter 340, 
Division 215  This rulemaking proposes amendments 
adding verif ication requirements for 
biomethane and hydrogen reporting.  
340-272-0495  Independent Review and 
Completion of Verification Services  This rulemaking proposes  amendment s 
requir ing verifiers in training to be listed in 
the verification report and to  update  to 
gender neutral language.  
340-272-0500  Requirements for Conflict 
of Interest Evaluation  This rulemaking proposes minor clarifying 
edits to this section.  
   17 
  
OAR Chapter 340, Division 271 
 
Rule 
Number  Rule Title  Explanation  
340-271-0010  Purpose and Scope  Adding "(6) If any dates under this division 
occur on a Saturday, Sunday, or a state 
holiday, the deadline is extended to the 
following business day"  
340-271-0020  Definitions  Update definition of “New source” for 
BAER, add definition of “Existing source”. Delete definition of “Evaluation period”. Edit definition of “Best available emissions reduction order”. De lete de finition for 
“Related Entity”.  
340-271-0110  Covered Entity and 
Cove red Emissions 
Applicability  Revision s to covered emissions for local 
distribution companies . Paragraph 
(4)(b)(B) revised to remove emissions from 
non- combustion related processes and replace with  emissions avoided where the 
use of natural gas results in greenhouse gas emissions captured and stored, if sufficiently documented by information provided to DEQ .  
Revisions to covered emissions for stationary sources.  Subsection (5)(a) revised primarily to identify that existing stationary sources un dertaking some 
modifications are covered stationary 
sources . 
340-271-0120  
 Changes in Covered Entity 
Ownership and Changes to Related Entities  Revisions to limit some requirements to  
liquid fuels and propane suppliers (covered 
fuel suppliers that are not local distribution 
companies ). 
340-271-0130  Cessation of Covered 
Entity Applicability  Cessation requirements for related entities 
revised to apply only to liquid fuels and 
propane suppliers (covered fuel suppliers 
that are not local distribution companies).  
340-271-0150  Covered Entity Permit 
Requirements  For a covered fuel supplier, revisions to  
dates to apply to DEQ for a CPP permit. 
Revisions to limit some requirements to 
liquid fuels and propane suppliers (covered 
fuel supplier that are not local distribution 
companies). For BAER, if modification 18 
 trigge rs BAER process, facility can’t 
construct the modification or emit covered 
emissions from the modification before 
receiving a  BAER order . Clarification of 
how BAER permit conditions get 
incorporated into ACDP and Title V 
permits.  
340-271-0310  Best Availab le Emissions 
Reduction Assessments for 
Covered Stationary Sources  Additional criteria that determine when a 
stationary source modification is required to go through BAER. Edits to list of information that must be included in a BAER assessment. Restriction that source cannot be required to go through BAER more than once every 5 years doesn’t apply 
to modifications.  
340-271-0320  Best Available Emissions 
Reduction Order  Specify that DEQ will provide 30 day 
public notice and public comment period when draft BAER assessment is received and when DEQ publishes draft BAER 
order.  
340-271-0330  Compliance with a BAER 
Order  For existing sources going through BAER, 
extend deadline to submit a permit modification application from 30 days to 90 days (or longer if  specified in the BAER 
order) after DEQ issues the final BAER 
order  
340-271-0420  Distribution of Compliance 
Instruments to Covered Fuel Suppliers  DEQ will distribute compliance 
instruments from a n annual  cap no later 
than June 30 of the calendar year of that 
cap. Revision s to the annual compliance 
instrument distribution methodology for covered fuel suppliers that are not local 
distribution companies  include  using 
unverified emissio n data from the prior 
calendar year as reported by covered f uel 
supplier s under  OAR chapter  340, division-
215, in place of the current three -year 
evaluation periods. E ach subsequent  annual 
compliance instrument distribution  from 
the applicable cap will then be adjusted as 
needed  in the following year using verified 
information ( the verified emission s data 
corrections factor ).  Proposed a dditions  
describe how  DEQ would  incorporate any 
compliance instrument holding limit 19 
 reduction s into annual compliance 
instrument distribution.  Revisions to 
remove the maximum limit on the number 
of compliance instruments DE Q can 
distribute from the reserve per fuel supplier per year. Revisions to clarify how DEQ will determine the number of compli ance 
instruments to distribute from the reserve to each fuel supplier making a reques t and 
when. Revisions to the eligibility for a distribution from the compliance instrument reserve for related entiti es to a 
covered fuel supplier.   
340-271-0430  Holding  Compliance 
Instruments  Revisions to include a compliance 
instrument holding limit reduction to be 
assessed  following the end of a compliance 
period, but prior to demonstration of compliance. Compliance instrument holding limit reduction is the number of 
compliance instruments above one and a 
half times the fuel supplier’s annual compliance obligation(s) for each year of a compliance period held by the fuel supplier 
on the  date of assessment. The compliance 
instrument holding limit reduction is 
applied to the distribution of compliance 
instruments in the subsequent year ‘s 
annual distribution.  
340-271-0450  Demonstration of 
Compliance  Revision to change 25 days after DEQ 
notifica tion to 40 days after DEQ 
notificatio n with a covered fuel supplier 
having to demonstrate compliance by 
December 9 of the year following the end 
of each compliance period, or  40 days after 
DEQ’s notification , whichever is later.  
340-271-8100  Program Review  Goals for stationary sources revised to 
change total covered emissions from 
combustion of sol id or gas eous fuels to 
total covered emissions from use of solid 
or ga seous fuels.   
340-271-9000  Tables  Table 5. Compliance instrument 
distribution evaluation periods repealed 
effective x/x/2023 . 20 
  
OAR Chapter 340, Division 216 
 
Rule 
Number  Rule Title  Explanation  
340-216-0025  Types of Permits  Include OAR chapter 340, divisions 269 -
272 in the reference to the rules  that a 
source with  a Basic ACDP must comply 
with.  
340-216-8010  Table 1 Activities and 
Sources Add new Basic ACDP source category for 
facilities with capacity to emit covered 
emissions > 25,000 metric tons CO2e per year, and that are not otherwise requir ed to 
obtain an air quality permit.  
340-216-8020  Table 2 Air Contaminant 
Discharge Permits  Specify that fees for the new Basic ACDP 
source category would be the same as for 
Basic category type #8 . 
 
OAR Chapter 340, Division 12 
 
Rule 
Number  Rule Title  Explanation  
340-012-0054  Air Quality Classification 
of Violations   Adds failure to submit 5 -year BAER report 
as a Class I violation.  
340-012-0135  Selected Magnitude 
Categories  Makes it a major magnitude violation to 
fail to timely submit a complete and 
accurate emissions data report under the 
Oregon Greenhouse Gas Reporting Program, OAR chapter 340, division 215, where the untimely, incomplete or inaccurate reporting impacts the distribution of compliance instruments  
under the Climate Protection Program, 
OAR chapter 340, division 271 . 
 
  21 
 Statement of need 
 
The rules or categories below follow the order of description above in the summary of proposed changes but with some additional detail.  
Proposed Rule or Topic  Discussion  
Updates to the Greenhouse Gas Reporting Program Rules  
GHG RP clarifying definitions , terms,  deadlines and requirements  
What need would the proposed rule address?  Through implementation DEQ has identified 
several areas in the current rule that  require 
additional guidance, need clarification and where added specificity would improve interpretation of the rule and compliance 
with reporting.  
How would the proposed rule address the 
need?  This rulemaking proposes several changes 
that update or  add definitions, add language 
to clarify applicability  and make the 
requirements of the rules clearer.  
How will DEQ know the rule addressed the 
need? DEQ will provide outreach and te chnical 
support related to these updates and expects 
that these clarifying  amendments will reduce 
the need for additional guidance and increase 
the accuracy of reported data and ease of 
compliance with the rules . 
GHG RP Reporting of biogas, biomethane , and hydrogen  
What need would the proposed rule address?  Currently, the GHG RP rules lack detail and 
specificity related to the definition of biomethane and the reporting of contractual deliveries of biomethane and hydrogen injected into the natural gas pipe line system.
  
Since carbon dioxide e missions from 
combustion of biomass derived fuels are 
exempt from most air quality regulation  
under ORS 468 A.020(3)(a), DEQ needs an 
accurate way to identify and account for these emissions to implement that 
exemption .  
How would the proposed rule address the 
need?  This rulemaking clarifies the  definition of 
biomethane and the  use of book and claim 22 
 accounting  to identify and account for 
biomass derived fuels comingled in natural 
gas systems. It creates requirements related to the recordkeeping, 
environmental attribute 
claims, reporting and verification of these fuels . This requ ired information  provides 
DEQ with information necessary to identify, 
verify , and appropriately account for 
emissions from  these biomass derived fuel s.   
How will DEQ know the rule addressed the 
need? Entities reporting these fuel types will have 
to submi t specific information identifying 
and substantiating  claims related to the 
reporting of these fuel types including attestations of the environmental attributes of these fuels.  DEQ will have the 
information needed to identify and verify emissions from biomass derived fuels for 
regulatory purposes.  
GHG RP Requiring GHG data monitoring plans 
What need would the proposed rule address?  Regulated entities without well documented 
practices produce more errors and experience more challenges when responding to questions related to reporting 
from third  party verifiers or DEQ . 
Undocumented practices also often lead to errors or omissions when new staff take on 
reporting role s.  
How would the proposed rule address the 
need?  GHG data monitoring plans require 
documentation for reporting.  They provide specific information regarding the applicability, requirements and quality assurance and quality control procedures for a facil ity subject to GHG RP rules. They 
outline the specific methodology used at a facility including report types and 
procedures.  Requiring that an entity 
maintain a plan ensures that their practices and procedures are being documented and 
reporting is consist ent from year to year.   
How will DEQ know the rule addressed the 
need? Entities with well documented GHG data 
monitoring plans should  be more responsive 
to third party verifiers and should experience 23 
 fewer  data reporting issues  because of  
increased documentation of reporting 
practices and requirements specific to their 
company or business.  
GHG RP sector specific methodology requirements  
What need would the proposed rule address?  There are several areas in the GHG RP rule 
where additional specificity or language in the rule are needed to address unique or specific accounting and documentation requirements. Two exa mples of th ese 
include the reporting of exported fuel from intermediate storage and the accounting of GHG emissions by multijurisdictional 
entities.  
How would the proposed rule address the 
need?  The proposed amendments more clearly 
address the methodology required for use in these specific circumstances.  The rules propose an accounting, reporting and recordkeeping methodology for exported fuels and more clearly specify the use of a cost allocation approach approved by the Public Uti lity Commission for use by 
multijurisdictional entities.   
How will DEQ know the rule addressed the 
need? DEQ expects tha t the amended rules will 
decrease the need for added guidance and technical assistance to regulated entities 
using these methodologies .  For example, if 
the Oregon PUC adopted an updated methodology our rules now specify the use of that methodology, aligning with the ORS 468A.280, the st atute that authorize s 
reporting for electricity suppliers.    
GHG RP separate violation  
What need would the proposed rule address?  Emissions data from certain fuel suppliers is 
used by the Climate Protection Program to determine applicability, distribute  compliance instruments,  and determine 
compliance obligations. Errors reported by these companies under GHG RP  directly 
impact Climate Protection Program 24 
 implementation  in a manner  commensurate 
with the magnitude of the error .  
How would the proposed rule address the 
need?  The proposed rules would identify each 
metric ton of misreported GHG emissions as 
a separate violation  of reporting rules , 
allowing DEQ to appropriately enforce against an entity that misreport s data that 
impa cts the Climate Protection Progra m.   
How will DEQ know the rule addressed the 
need? DEQ expects a reduction in errors associated 
with reported emissions and a reduced number of corrections through third party verification . Should misreporting occur, 
DEQ expects to respond with enforcement that commensurately addresses the impact of 
the misreported emissions data.  
Updates to Division 272 Third Party Verification Program Rules  
Applicability Expansion of Third Party Verification Requirements  
What need would the proposed rule address?  Electricity service suppliers  subject to 
Oregon’s Clean Energy Targets are not 
currently subject to  third party verification. 
Additionally, under the existing rules, there are unique situations where Climate Protection  Program participants may  not be 
subject to third party verification.  
How would the proposed rule address the 
need?  Proposed amendments would expand 
applicability of third party verification requirements to all entities subject to the Climate Protection Program and to all electricity service suppliers, regardless of 
emissions level.  
How will DEQ know the rule addressed the 
need? Because third party verification requires 
annual submission of a verification statement, DEQ will be able to track 
compliance year to year.  
Amendment of minimum lead verifier requirements for verification bodies  
What need would the proposed rule address?  
 Under the current regulation, verification 
bodies must have a minimum of two DEQ-approved lead verifiers employed with them to maintain approval to provide services in 
Orego n. However, DEQ is aware that some 25 
 potential verification bodies use  only 
subcontractors for their verification work.  
How would the proposed rule address the 
need? 
 By removing language stating that 
subcontractors may not be used to meet 
minimum lead verifier requirements, verification bodies using a subcontracting 
model would be eligible to apply for DEQ approval. This change would allow additional verification bodie
s the opportunity 
to apply to provide verification services in 
Oregon.  
How will DEQ know the rule addressed the 
need? 
 DEQ opens an application period for new 
verification bodies at least once every three years, so the number of new verification bodies brought in by this change could be 
easily quantified.  
Verification requirements for biomethane and hydrogen reporting  
What need would the proposed rule address?  
 Amendments are needed to ensure  complete 
and accurate  reporting of biomethane or 
hydrogen under  Division 215 .  
How would the proposed rule address the 
need? 
 The proposed amendments identify the 
requirements and data elements for verifying reporting of these fuel types. The amendments clarify the responsibilities  of 
the entity and ver ifier with respect to the 
verification  of biomethane and hydrogen 
reporting.  
How will DEQ know the rule addressed the 
need? 
 The entity will either report correct 
information by the reporting deadline, which would be third party verified, or their reporting would be corrected as part of the 
third party verification process.  
Implementation improvements  
What need would the proposed rule address?  
 DEQ has identified third party verification 
program elements where modifications to the 
rule would result in  improved procedures, 
including areas of the regulation that can be clarified and simplified for administration  
purposes. 
 26 
 How would the proposed rule address the 
need? 
 Proposed amendments  simplify process by  
allow ing verification bodies to submit 
conflict of interest documentation on their 
clients’ behalf and clarify ing timing of site 
visits.  
 
How will DEQ know the rule addressed the 
need? 
 DEQ expects more accurate form 
submissions and fewer submissions of forms 
prior to submission of reporting.  
Updates to Division 271 Local Distribution Companies  
What need would the proposed rule address?  Local distribution companies regulated by 
the program need to have a clear 
understanding of their covered emissions and their compliance obligations under the 
program. Local distribution companies and 
their business customers require this certainty to develop compliance strategies and implement appropriate business decisions. Without that understanding, local 
distribution c ompanies and their customers 
cannot make appropriate business decisions 
and implement cost- effective emissions 
reduction strategies in a timely manner.  
How would the proposed rule address the 
need?  The proposed rule amendment provides 
additional clarity and ensures that emissions from natural gas delivered by a local distribution company, whether combusted or oxidized, are covered emissions for local 
distribution companies.  
How will DEQ know the rule addressed the 
need?  DEQ will notify covered fuel supplier s of 
their compliance obligations. Local distribution companies will demonstrate 
accurate understanding of the ir covered 
emissions  and compliance obligations.  
Updates to Division 271 Liquid Fuels and Propane Fuel Suppliers  
What need would the proposed rule address?  The distribution of compliance instruments 
to liquid fuels and propane suppliers needs 
to reflect those companies’ positions in the 
Oregon fuel market. Their positions change 27 
 regularly, and thus the data used to assess 
companies’  positions needs to be as 
contemporaneous as possible.  Currently, 
new fuel suppliers may need to make 
requests from the compliance instrument reserve for multiple years due to a lack of emissions data and the number of compliance instruments available through the reserve is limited . Due to the length of 
the evaluation period, new covered fuel suppliers may need to operate for 4 years before they would maximize their compliance instrument distribution in the annual distribution of compliance instruments. This could also result in DEQ  
distributing more instruments from the reserve over time as compared to incorporating new covered fuel suppliers into the annual distribution process sooner.  
Distributions from the compliance instrument reserve could potentially treat emissions increases differently. DEQ is 
proposing to no longer allow a reserve distribution for new covered fuel suppliers that are related entities to another covered fuel supplier that is already receiving compliance instruments from the annual compliance instrument distrib ution.  
 
Proposed amendments also address the need to incorporate more program features to prevent potential market manipulation or 
compliance instrument hoarding.  
How would the proposed rule address the 
need?  Changes to use the most recent emission s 
data, updating the key programmatic 
timeline, removing the three -year evaluation 
period, and changes to the reserve for 
compliance instruments and addition of 
holding limits would help address these needs. Proposed change to eligibility for compl iance instrument distribution helps 
ensure that emissions increase due to 
expansion is treated the same whether done 28 
 within a currently covered fuel supplier or 
through an acquisition.  
How will DEQ know the rule addressed the 
need? DEQ would note differen ces in the number 
of compliance instrument distributed to each 
covered fuel suppler. DEQ would notice a decrease in the number of covered fuel 
suppliers that would need to make a request 
from the compliance instrument reserve for more than one calendar year and possibly a decrease in request s to the compliance 
instrument reserve overall.   
Updates to Division 271 BAER Rules  
What need would the proposed rule address?  The current BAER rules do not require 
BAER review of modifications, even if they 
would result in a large increase in BAER 
covered emissions.  
How would the proposed rule address the 
need?  The rules add a requirement for certain 
modifications to go through BAER prior to 
DEQ approval.  
How will DEQ know the rule addressed the 
need? DEQ will be able to require modifications 
that meet the criteria to go through the 
BAER process.  
Updates to Division 216 Rules  
What need would the proposed rule address?  If a source has low emissions of non -GHG 
pollutants, they would not currently be required to have an air permit and therefore cannot be required to go through the BAER process, even if they have very high 
emissions of BAER covered em issions.  
How would the proposed rule address the 
need?  The proposed rules would add a new source 
category that requires sources with a high capacity to emit BAER covered emissions to get a Basic ACDP air permit if they are not already required to have another type of air 
permit.  
How will DEQ know the rule ad dressed the 
need? 
 DEQ does not know if there are any sources 
in this source category. If some sources are 
identified in the future, DEQ will be able to 29 
 require them to get a permit and go through 
BAER.  
 
  30 
 Rules affected, authorities, supporting 
documents 
 
Lead division  
 
Office of Greenhouse Gas Programs  
 
Program or activity  
 
Oregon Climate Protection Program, Greenhouse Gas Reporting Program and Third Party Verification Program  
 
Chapter 340 action  
 
Adopt  
340-215-0130      
Amend  
340-012-0054  340-012-0135  340-215-0020  340-215-0030  340-215-0034  
340-215-0040  340-215-0042  340-215-0044  340-215-0046  340-215-0105  
340-215-0110  340-215-0115  340-215-0120  340-216-0025  340-216-8010  
340-216-8020  340-271-0010  340-271-0020  340-271-0110  340-271-0120  
340-271-0130  340-271-0150  340-271-0310  340-271-0320  340-271-0330  
340-271-0420  340-271-0430  340-271-0450  340-271-8100  340-271-9000  
340-272-0020  340-272-0100  340-272-0110  340-272-0120  340-272-0210  
340-272-0220  340-272-0300  340-272-0405  340-272-0415  340-272-0450  
340-272-0455  340-272-0460  340-272-0470  340-272-0495  340-272-0500  
340-272-0350  340-272-0445     
 
Statutory Authority - ORS  
468.020  468.065  468.130   468A.025   468A.040  
 468A.050   468A.135   468A.266   468A.271   468A.277  
468A.280      
 
Statutes Implemented - ORS  
468.020  468.065  468.100  468.135   468A.020  
 468A.025   468A.040   468A.050   468A.135   468A.266  
 468A.271   468A.277   468A.280    
 31 
  
Documents relied on for rulemaking 
 
We note that we have also separately listed, below, the documents we relied on in developing the fiscal impact and rac ial equity statements.  
  
 
 Document title  Document location  
California Air Resources Board, Cap -and-
Trade Regulation (2018), Title 17, Division 
3, Chapter 1, Subchapter 10, Article 5  https://ww2.arb.ca.gov/sites/default/files/202
1-02/ct_reg_unofficial.pdf 
Environmental Protection Agency, 40 Code 
of Federal Regulations, Part 98, Mandatory 
Greenhouse Gas Reporting  https://www.ecfr.gov/current/title -40/chapter -
I/subchapter -C/part -98?toc=1 
Midwest Renewable Energy Tracking 
System, Operating Procedures  https://www.mrets.org/wp -
content/uploads/2021/01/M -RETS-
Oper ating -Procedures -9-2021.pdf  
Order 20 -227, Rulemaking Regarding the 
2019 Senate Bill 98 Renewable Natural Gas 
Programs, Oregon Public Utility 
Commission  https://apps.puc.state.or.us/orders/2020ords/2
0-227.pdf 
Oregon Clean Fuels Program Rules, OAR 
chapter 340, division 253  https://secure.sos.state.or.us/oard/displayDivi
sionRules.action?selectedDivision=1560  
State of Washington Cap and Invest 
Program, Revised Code of Washington, 
Title 70A, Chapter 70A.65  https://ecology.wa.gov/air -climate/climate -
commitment -act/cap -and-invest 32 
 Fee Analysis 
The proposed rule  amendments  would not create any new fees or change any existing fees .  
However, the proposed rule  amendments  would add a source category to OAR 340- 216-
8010 Table 1, Part A .  Stationary  sources in that source category, if any, would be required 
to apply for and comply with a Basic Air Contaminant Discharge Permit (ACDP).  DEQ is 
not aware of any facilities that would be in this source category and therefore affected by this change .  If there are such facilities, they would be required to pay application fees and 
annual fees associated with a Basic ACDP. The application fee is currently $180, and current annual fees are $1 ,879/year, including ACDP, Cleaner Air Oregon, and Greenhouse 
Gas Rep orting fees .  There are no fees associated with a BAER assessment or BAER order, 
but in some cases complying with a BAER order may require a stationary source  to submit a 
Notice of Construction or permit modification application , including applicable fees.  Fees 
for submitting a Notice of Construction or permit modification application are listed in OAR 340-216-8020 Table 2 and OAR 340 -220-0050 and depend on the source ’s DEQ air permit 
type and the type of modification.  
 
 
 33 
 Statement of fiscal and economic impact  
 
Fiscal and Economic Impact of the proposed updates  
 
The discussion below categorizes fiscal  and economic  impacts  of the proposed rule 
amendments by rules  division , followed by a more detailed discussion of anticipated fiscal  
and economic impacts on different types of  regulated entit ies. 
 
Greenhouse Gas Reporting Program, Division 215  
 Greenhouse gas reporting rules require the reporting of annual GHG emissions data and related information, as well as the retention of records to substantiate reporting.  Most of the amendments proposed to Division 215 during this rulemaking clarify reporting and recordkeeping requirements .  Those amendments are intended to add more precise language 
to the rule, while not changing or creating new requirements .  DEQ anticipates that 
clarifying edits should result in little to no fiscal or economic impact to regulated entities.  
DEQ anticipates de  minimus fiscal impacts related to a regulated entity’s  need to read rule 
amendments  and ensure compliance based on updated rule language.  
 DEQ believes that expanding requirements for developing and maintaining a GHG data monitoring plan to all entities required to obtain third party verification will have a moderate fiscal impact.  The  impact is limited to reporters not currently maintaining plans including 
some fuel and electricity suppliers .  DEQ has also received comment that some entities 
voluntarily develop these plans .  Fiscal impacts would be limited to entities who must obtain 
verification services but that are not currently required to, or voluntarily develop, these plans. GHG monitoring plans are required by EPA for all entities that report to the federal greenhouse gas reporting program. Based on EPA’s statement  of costs for  recordkeeping 
and r eporting in the Regularity  Impact Regulatory Impact Analysis for the Mandatory 
Reporting of Greenhouse Gas Emissions Final Rule (GHG Reporting)  DEQ estimated costs 
to comply with new recordkeeping requirements as ranging from $0 to $2, 417 per year . This 
value is inclusive of developing GHG monitoring plans  and adjusted for inflation .
  
 
Third Party Verification , Division 272 
 Amendments proposed to Division 272 may minimally  impact costs of third party 
verification to entities currently subject to Division 272 requirements .  One proposed 
change, allowing subcontractor s to meet the minimum lead verifier requirements for 
verification bodies, may allow for additional verification bodie s to apply to perform services 
in Oregon.  Increasing the pool of available verification bodies may lead to decreased costs for entities subject to the program and result in a positive fis cal impact for those regulated 
entities . 
 DEQ is also proposing to e xpand the applicability of verification to all entities who have 
compliance obligations under Division 271 and electricity suppliers .  Most regulated entities  
with compliance obligations under Division 271 are already required to obtain verification .  34 
 DEQ anticipates this amendment to impact one new  Electricity Service Supplier.  During the 
Greenhouse Gas Reporting and Third Party  Verification 2019 rulemaking DEQ requested 
comment on the cost of obtaining third party verification  of emissions reports . Based on  
responses to this request , DEQ estimates that the cost of third party verification of a single 
report  ranges from $4,000 to $10,000. 
 
The remaining amendments impact stakeholders in specific sectors.  They are more easily 
described from a sector perspective. For this reason, staff have described amendments with a fiscal impact to specific regulated sectors in the sections that follow.  
 
Climate Protection Program , Division 271  
 The Climate Protection Program uses two approaches to reducing greenhouse gas emissions.  Fuel suppliers are subject to declining emissions caps and certain stationary sources that meet a threshold for applicability are subject to a best available emissions reduction (BAER) approach.  Covered fuel suppliers i nclude natural gas utilities (local distribution companies) 
and suppliers of liquid fuels and propane (non- natural gas suppliers) that meet or exceed a  
GHG emissions  threshold for inclusion.  BAER covered emissions include industrial process 
and other emis sions not included in the emissions cap that applies to covered fuel suppliers’ 
emissions.  BAER sources are required to prepare a BAER assessment and then comply with a BAER order issued by DEQ.  
 The proposed rule amendments do not change the program’s applicability requirements or emissions caps for covered fuel suppliers, so DEQ does not anticipate significant fiscal impacts to these entities as compared to the current rules.  The proposed rule amendments do include changes to how DEQ distributes complia nce instruments to liquid fuels and 
propane suppliers in the program.  This would result in individual changes to the number of compliance instruments distributed by DEQ to each liquid fuels and propane supplier.  However, the overall number of instruments  distributed each year by DEQ would not 
change under the proposed amendments . See fiscal and economic impacts to regulated 
entities by sector below for additional discussion.  
 The proposed rule amendments would require some stationary sources that are maki ng 
modifications to their facilities to go through the BAER process .  Potential fiscal impacts 
related to the BAER process are discussed below.  
 
DEQ has determined that there are no direct fiscal impacts to natural gas utilities (local distribution compani es) from the proposed rule amendments for the Climate Protection 
Program. However, data reported to the Greenhouse Gas Reporting Program is used to implement the Climate Protection Program, including determining covered emissions and compliance obligations . The Climate Protection Program is designed to offer various options 
and flexibility mechanisms for covered entities to comply and reduce emissions.  Switching 
supply of fossil natural gas to supply of biomethane is one of these potential compliance 
pathw ays for natural gas utilities. T he proposed rule amendments for the Greenhouse Gas 
Reporting Program for natural gas suppliers on the reporting of these fuels, are directly related to potential compliance costs and fiscal impacts for natural gas utilities . As the 35 
 Greenhouse Gas Reporting program currently allows for the use of book and claim 
accounting for reporting biomethane,  DEQ has determined that these proposed amendment s 
will not have fiscal impacts for natural gas util ities, wit h some limited exceptions. See f iscal 
and e conomic impacts to regulated entities by sector below for additional  discussion.   
 
Air Contaminant Discharge Permits, Division 216  
 
The proposed changes would introduce a new source category that may require some  
sources that are not currently required to have a DEQ air permit to get a Basic ACDP. The impacts of this on affected stationary sources, if any, are described below in the description of impacts to the stationary source sector. DEQ is not aware of any st ationary sources that 
would be required to get a permit due to this change, but if some are identified in the future, those sources  would need to obtain a permit , which would require DEQ to process permit 
applications, review reports, and perform inspectio ns. 
 
Fiscal and Economic  impacts  to regulated entities  by 
sector : 
 The categories below  are organized by regulated entity  and amended division.  
 
Natural Gas Suppliers 
 
Greenhouse Gas Reporting Program, Division 215 
 Amendments to Division 215 include more detailed reporting and recordkeeping 
requirements for the reporting of biogas, biomethane , and hydrogen. Since these 
amendments increase the information required for reporting and require attestation of environmental attributes , DEQ anticipates direct fiscal and economic impacts  to regulated 
entities  reporting these fuel types .  For example, the proposed attestation documentation 
requirements for environmental attributes or calculation and reporting of ca rbon intensity 
values may increase costs associated with obtaining and reporting those data and documents .   
 DEQ estimates , based on publicly available information for renewable thermal credit 
tracking systems, that direct cost s of additional reporting requirements for biomethane , 
could be at least $2,200 annually for reporters  using electronic tracking systems , plus $0.10 
per MMBtu of biomethane reported under these rules . This estimate does not include  
additional internal staff c osts for documenting co mpliance . Entities not using electronic 
tracking systems will also have costs associated with obtaining and maintaining the required documentation for reporting of biomethane and hydrogen. These costs may vary depending 
on contracting requirements and conditions. DEQ does not have specific information to 
estimate the additional costs associated with recordkeeping and reporting outside of the 
available information on electronic tracking system s.  
 DEQ also anticipates increased costs to entities reporting these fuel types who must also  
obtain verification services.  Proposed amendments to Division 272 require verifiers to 36 
 review in detail the documentation that substantiates reporting of these fuel typ es.  This 
additional requirement will increase  time and  costs associated with third party verification . 
DEQ does not have information to estimate the increased costs associated with verification 
of these fuel types .  
 
The proposed Division 215 amendment s clarify  the definition of biomethane .  The amended 
definition no longer includes synthetic methane, produced from non- biogenic sources , as 
biomethane.   For reporting purposes, under Division 215, DEQ does not anticipate fi scal 
impacts from the amendment of the definition . 
 
Climate Protection Program, Division 271 
 
DEQ is proposing to make permanent the temporary rule  amendment  to OAR- 340-271-0110 
that w as adopted by the Environmental Quality Commission on November  17, 2022.  This 
proposed rule amendment provides further clarification that emissions from natural gas 
delivered by a natural gas utility  to a customer that uses that gas in a manner that results in 
direct greenhouse gas emissions, are covered emissions for that local distribution company .  
The proposed rule amendment ensures that emissions from natural gas delivered by a natural 
gas utility , whether combusted or oxidized, are covered emissions for local distribution 
companies . DEQ has determined that there are no significant  fiscal impacts from this 
proposed rule  amendment . 
 
Data reported to the Greenhouse Gas Reporting Program is used to implement the Climate 
Protection Program, inclu ding determining covered emissions and compliance obligations. 
Proposed rule amendments for Greenhouse Gas Reporting Program, D ivision 215 for natural 
gas suppliers are directly related to potential compliance costs and fiscal impacts for natural 
gas utili ties.  As the proposed 215 amendment s generally add additional clarif ication without 
changing reporting requirement s for biomethane,  DEQ anticipates limited impacts on the 
availability of biomethane supply.  Therefore, DEQ does not anticipate related fiscal impacts 
for natural gas utilities  regulate d by the Climate Protection  Program , with some limited 
exceptions . 
 The proposed rule amendments change how synthetic gas using fossil fuel feedstocks  (non-
biogenic  waste carbon di oxide)  is reported and used to demonstrate compliance under the 
Climate Protection Program.  Currently , the Greenhouse Gas Reporting Program rule  could 
be interpreted to exempt supply of that fossil fuel gas from generating a com pliance 
obligation, while the proposed rule amendment would make that gas generate a compliance 
obligation. In the future, if synthetic gas using fossil fuel feedstocks becomes readily 
available. this proposed change could increase what otherwise would be future compliance 
costs for natural gas suppliers.  
 The proposed rule amendmen ts require  attestations from counterparties involved in a gas 
utilities procurement of the biomethane,  could also exclude some sources of biomethane and 
reduce supply, which would increase associated compliance costs . DEQ does not have any 
information to estimate  how the  attestation  requirements  might impact bio methane supply 37 
 and associated costs, nor does DEQ have information to estimate potential fut ure impac ts on 
available supply of synthetic methane  using fossil fuel feedstocks.    
 
 
Liquid Fuels and Propane  Suppliers  
 
Greenhouse Gas Reporting Program, Division 215 
 
Amendments to Division 215 for fuel suppliers primarily clarify reporting requirements .  
DEQ anticipates no , or very minimal,  fiscal impact from those clarifying amendments . De 
minimis fisc al impacts may be experienced by regulated entities to review and ensure 
compliance with the revisions of the rules.  However, there are two situations where DEQ 
anticipates fuel suppliers may experience fiscal impacts associated with proposed amendments .  First, a s described in the introduction, fuel suppliers required to obtain 
verification services that are not currently maintaining GHG monitoring plans may  incur 
costs associated with developing and maintaining those plans as described  above .  
 Secondly, DEQ is proposing amendments to the reporting and documentation of exported fuel products .  These amendments include new notification and recordkeeping requi rements 
for fuel suppliers .  These amendments would require a fuel supplier to notify an Oregon 
position holder if the records issued at the terminal did not accurately reflect the delivery destination .  For example, if terminal records indicated the fuel was delivered in Oregon but 
the supplier diverted that fuel for delivery out of state , the amendments would require the 
fuel supplier in this situation to notify the position holder and, if requested, provide documentation to the position holder of the export .  This amendment would increase costs 
associated with record management, reconciliation, and staff time related to notifying impacted position holders. DEQ does not have any specific information available to estimate 
the costs associated with the amend ments to the recordkeeping and reporting of exported 
fuels . Due to different business structures  and existing accounting practices companies may 
experience a range of costs and some may experience no fiscal impact related to these 
specific amendments . DEQ believes that any fiscal impact would only minimally increase 
costs associated with  reporting  exported fuels.   
 
Climate Protection Program, Division 271 
 
Proposed a mendments to Division 271 for liquid fuels and propane suppliers  include  
changing the methodology for the annual distribution of  compliance instruments by reducing 
the evaluation period for each distribution to one year  and using only the prior year of self -
reported emissions da ta.  Other changes include adding or adjusting dates for requests from 
the compliance instrument reserve  and the annual compliance instrument distribution, 
removing the  limitation on the number of compliance instruments that can be distributed 
from the reserve to individual fuel suppliers , and more detail on how distributions from the 
reserve will be calculated.  As these proposed rule amendments do not change the program’s 
overall applicability thresholds or the emissions  cap, DEQ does not expect the proposed rule 
amendment s to have different  aggregated  fiscal impacts on all fuel suppliers  than do the 
current rules.  38 
  
These proposed amendments will however  change the number of compliance instruments 
that each individual fuel supplier would have received in the annual distribution if the 
methodology had remained unchanged.  Newly  covered fuel suppliers will be incorporated 
into the annual compliance distributions more rapidly  and will correspondingly rely less on 
reserve distributions. C hanging from  a three -year to a one -year evaluation period will also 
invariably affect the number of instruments DE Q distributes  to each fuel supplier .  Some 
fuel suppliers will receive relatively fewer instruments while other companies will receive 
relatively more .  However , the total number of instruments distributed by DEQ would not 
change .  Therefore , DEQ anticipates there will be some potential negative and positive fiscal 
impacts to individual  fuel suppliers, but that overall compliance costs across the regulated 
companies should remain the same.  While DEQ does not have this emissions data, DEQ 
anticipates the most significant differences would be for those fuel supplier s with the 
greatest difference between t he most recent year of emissions data and three- year average 
emissions .  For the 2024 compliance distribution as proposed,  if an individual fuel supplier’s 
2023 emission s were lower than their average emissions for the three -year evaluation period 
(either 2019 -2022 or 2020- 2023)  then that fuel supplier woul d be expected to receive fewer 
compliance instruments . 
 
Stationary Sources 
 
Greenhouse Gas Reporting Program, Division 215 
 
Amendments to Division  215 for stationary sources focus on clarifying re porting 
requirements.  DEQ anticipates that p roposed rule amendments that clarify but do not 
modify calculation s, data needs, and recordkeeping requirements for stationary sources  
should not have a fiscal or economic impact .  For example, DEQ anticipates no fiscal impact  
resulting from the clarification of reporting emissions from foam blowing operations  since 
amendments clarify, but do not change the requirement or data needs . 
 Since stationary sources in Oregon may report the use of biogas, biomethane, or hydrogen 
DEQ anticipates fiscal impacts resulting from the proposed amendments to recordkeeping and reporting of those fuels as described in the Natural Gas Suppliers section.  Fiscal or economic impacts resulting from the amendments for reporting these fuel types are 
related to increased recordkeeping required for reporting those fuels and increased costs related to obtaining or developing data elements or records.  For example, the proposed 
attestation documentation requirements for environmental attributes or calculation and reporting of carbon intensity values may increase costs associated with obtaining and retaining those data and documents .  As described earlier,  based on in formation available for 
current electronic tracking systems, DEQ estimates the cost of these requirements to be at 
least $2,200 annually for regulated entities using electronic tracking systems, plus $0.10 per 
MMBtu of biomethane reported under these rules . This estimate does  not include  additional 
internal staff costs for documenting compliance  or costs associated with directly contracting 
for the delivery of these fuels outside of an electronic tracking system .  DEQ also anticipates 
increased costs to ent ities reporting these fuel types who must also obtain verification 39 
 services.  Proposed amendments to Division 272 specifically require verifiers to review the 
documentation that substantiates reporting of biomethane and hydrogen.  This increases the 
time n eeded to conduct verification services which may have a fiscal impact.  DEQ does not 
have adequate information to estimate the incremental costs to verification of these fuel 
types through third party verification.  
 
Climate Protection Program, Division 271 
 
Current rules require that existing and new sources with BAER covered emissions above a 
threshold would be required to prepare a BAER assessment and comply with a BAER order .  
In addition to current requirements, the proposed rule amendments  would require some 
sources that are making modifications to their facilities to go through that process .  Facilities 
would be required to go through the BAER process before completing their proposed 
modification if the modification meets several conditions, including:  
 
• The modification would increase their potential to emit (PTE) BAER covered 
emissions by 10,000 metric tons of CO2e or more ; 
• After the modification, the facility’s PTE BAER covered emissions would be 25,000 metric tons of CO2e or more ; 
• The source is not already subject to BAER (it hasn’t had actual BAER covered 
emissions of 25,000 metric tons of CO2e or more in any year) ; and  
• DEQ determines that the modification represents a significant change to the 
equipment or processes that emit covered emissions at the source.  
 
Sources going through the BAER process would have costs for preparing the BAER 
assessment, including staff time and /or hiring consultants .  For the 2021 Climate Protection 
Program rulemaking DEQ  estimated that preparing a BAER assessment may take 
approximately 150- 300 hours of  facility staff time and/or consultant  time .  At a rate of $200 
per hour , estimated costs are cost  $30,000- $ 60,000.  After having completed the BAER 
process, facilities have to submit an a nnual progress report  and five-year BAER  reports.  If 
new emissions reduction strategies are identified, DEQ may require a source to update their 
BAER assessment .  The costs for submitting an annual  report, five -year BAER reports and 
updating a BAER assessment are expected to be the same or less than writing a new BAER 
assessment . 
 
Facilities complying with a BAER order may have costs including installation of additional 
equipment  as well as costs to monitor, keep records, and provide reports to DEQ about air 
pollution emitted by their facility .  The specific actions, if any, that a facility would be 
required to take would depend on the results of DEQ’s site -specific analysis of the BAER 
assessment and emission reduction options  at the site.  Costs to implement strategies that 
reduce greenhouse gas emissions will vary by strategy, business, and industry. DEQ can 
consider strategies to reduce covered emissions that are available, feasible, and cost -
effective for that individual sou rce. For the 2021 Climate Protection Program, DEQ 
contracted with ICF to analyze program options to reduce greenhouse gas emission s. As pa rt 
of the study,  ICF assum ed cost ranges for an  industrial station ary source  to reduce 40 
 emissions .  The study assumed a range between  $47 to $190 (2020$) per metric ton of 
emissions reduced.  
 
Air Contaminant Discharge Permits, Division 216 
 
The proposed rule amendments would add a source category to OAR 340- 216-8010 Table 1, 
Part A.  Sources in that source categ ory, if any, would be required to apply for and comply 
with a Basic Air Contaminant Discharge Permit (ACDP).  DEQ is proposing this amendment because in the future, if a source has low emissions of non -GHG pollutants, they 
would not currently be required t o have an air permit and therefore cannot be required to go 
through the BAER process, even if they have very high emissions of BAER covered 
emissions. This source category is defined as those sources that are not currently required to 
have a DEQ ACDP or Ti tle V air permit but have a capacity to emit 25,000 metric tons 
CO2e or more of greenhouse gases that qualify as “covered emissions” under the Best 
Available Emissions Reduction program. “Covered emissions” is defined at OAR 340 -271-
0020.  
 DEQ is not awar e of any facilities that would be in this source category and therefore 
currently affected by this change.  If there are such facilities, they would be required to pay 
application fees and annual fees associated with a Basic ACDP.  The application fee is 
currently $180, and current annual fees are $1879/year, including ACDP, Cleaner Air 
Oregon, and Greenhouse Gas Reporting fees.  Such facilities may also have expenses for 
complying with the conditions of the Basic ACDP, including costs to monitor, keep records, 
and provide reports to DEQ about air pollution emitted by their facility.  Such facilities 
could request a permit limit to set their PTE of covered emissions below the BAER 
threshold of 25,000 metric tons CO2e , or they could go through the BAER proces s. If going 
through the BAER process, they would also have expenses related to preparing a BAER 
assessment and complying with a BAER order. 
 
Electricity Suppliers  
 
Greenhouse Gas Reporting Program, Division 215 
 
As discussed in the introduction to amendments to Division 215, DEQ expects the proposed 
amendments requiring GHG data monitoring plans for all entities subject to verification to have a fiscal impact  to entities currently not maintaining these plans .  In addition to 
requirements to main tain a GHG data monitoring plan, DEQ is proposing that plans 
developed by electricity suppliers contain additional information.  Since GHG data monitoring plans are currently not required for electricity suppliers and these plans have more detailed require ments , the amendments  may h ave a greater f iscal impact to e lectricity 
suppliers subject to verification  than to other sectors . As stated above, DEQ estimated costs 
to comply with new GHG data monitoring plan  recordkeeping requirements , based on  
information published by  EPA , as ranging from $0 to $2,417 per year.  
 
Third Party Verification, Division 272 
 41 
 The proposed amendments  to DEQ’s third party verification rules would expand third party 
verification applic ability to all electricity service suppliers , regardless of their reported 
emissions level .  Though most electricity service suppliers already exceed the verification 
thresholds in Division 272, this change is anticipated to require one  new electricity service 
supplier to contract for verification services .  This amendment would have a fiscal impact . 
DEQ’s current estimation of the cost of verification, based on comments from the initial 
rulemaking process and limited disclosures made by verification bodies as part of the 
conflict of interest assessment process, is between  $4000- $10,000 annuall y. Electricity 
supplier verifications are likely closer to the bottom of this range based on the complexity of 
their reporting.  
 
Third Party Verifi ers 
 
Third Party Verification, Division 272 
Fiscal impacts to verification bodies of the proposed changes to Division 272 are anticipated 
to be minimal .  Expanding third party verification applicability to include all electricity 
service suppliers and all entities regulated by the Climate Protection Program will add a few 
new potential clients for verification bodies over time .  Allowing subcontractors to m eet 
minimum lead verifier requirements for verification bodies could potentially allow more companies to become verification bodies .  DEQ assumes an increase in the number of 
business available to provide verification services in Oregon could have a minor negative  
impact on  the prices that verification bodies are able to charge for services.  
 
Statement of Cost of Compliance 
 
State agencies  
 For DEQ, implementing the proposed amendments  to Division 215 will require new 
processes  and updates to existing reporting systems to collect new required data and 
information .  Implementation of all amendments will require outreach, engagement and 
training for regulated entities and third party  verifiers.  
 The proposed amendments to the BAER rules would require Climate Protection Program staff to review some Notices to Construct and proposed permit modifications to determine whether  they  trigger the BAER process .  If any facilities are required to get Basic ACDP 
permits because of the proposed new source category, then DEQ staff time would be required for permit writing, report review, inspections, and enforcement.  
 
Local governments  
 Some  local governments are owners or operators of air permitted facilities reporting as 
regulated entities under Division 215.  Local governments subject to Division 215 reporting or BAER requirements under Division 216 or 271 would experience direct impacts described  in the fiscal and economic section above for stationary source s. 
 42 
 Public  
 
While t he public would not incur any direct fiscal impacts associated with the proposed rule 
amendments , DEQ is including a discussion of potential indirect impacts to the public from 
these proposed rule amendment s in response to input provide d by the advisory committee 
and in public comment.   
 Previous analysis of the Climate Protection Program discussed program impacts to the 
public, both potential  costs and benefits , and projected significant health benef its across 
Oregon, large ly due to reductions in co-pollutants  as greenhouse gas emission s decline . This 
was shown to be  especially beneficial for  environmental justice communities since these 
communities  are disproportionately impacted by air pollution . A qualitative co -benefits and 
equity assessment found that overall, the Climate Protection Program could result in positive co-benefits and equity benefits. The assessment was for five indicators (local air quality; 
ecosystem health & resilience; energy security; employ ment & workforce development; 
housing burden) and for five identified communities of concern (communities of color, tribal nations, elderly populations, low -income urban communities, low -income rural 
communities). The design and implementation of the C ommu nity Climate I nvestment funds 
was a key driver of these results. The Community Climate Investment p rogram play s a 
pivotal rule in achieving these outcomes by helping to provide a voluntary flexibility option for compliance entities while prioritizing  green house gas emission reduction projects that 
benefit environmental  justice communities .  
 DEQ recognizes that any proposed rule amendment that might increase compliance costs for 
individual fuel suppliers regulated by these programs could  be passed o n to c ustomers.  
While DEQ does not anticipate that the CPP rules amendments will increase overall 
compliance costs for liquid fuels and propane suppliers  as DEQ is not changing the program 
emission caps and the total number of compliance instruments distributed . DEQ recognizes 
that some individual fuel suppliers may experience changes in the number of compliance instruments received from DEQ and this may increase costs for customer s of individual fuel 
suppliers . This woul d be of additional concern for environment al justice communities that 
have fewer  options to trans ition to other fuel sources and who spend a larger portion on their 
household budgets on energy and fuels.   
 DEQ has received several comments  on the  indirect impacts of the proposed rule 
amendments related to  biomethane particularly in the  clarification on the  book and claim 
accounting approach for biomethane .  One of the ways that natural gas utilities  can comply 
with Climate Protection Program is b y reducing covered emissions associated with natural 
gas by increasing their use of biomethane (a biomass derived fuel).  Increased use of biomethane, demand response, increased electrification, hydrogen, future technologies, and 
Community  Climate I nvestmen ts can all drive down demand for natural gas and support 
compliance  for natural gas utilities.  DEQ has received input that ensuring a supply of 
biomethane by continuing to allow for a book and claim approach is an important factor in managing compliance costs for natural gas utilities as biomethane  supply is limited. Other 
comments have emphasized  that an indirect impact of the book and claim accounting 
approach is that other benefits such a s potential job creation and other associa ted economic 43 
 and potential emission reductions benefits are not realized in the state of Oregon.  DEQ 
received feedback that increased use of book and claim accounting for biomethane may 
result in higher costs for utilities and their customers as compared to other decarbonization strategies.  While the Climate Protection Program was designed to provide compliance 
entities with options on how to comply to help mitigate adverse cost impact s, DEQ received 
comment that the continued used of book and claim accounting for biomethane might  
impact how many Community Climate Investment credits a natural gas utility may choose to purchase and CCI  funds , a key tool to prioritize benefits to Oregon's ’ environmental  justice 
communities . 
 
Large businesses - businesses with  more than 50 
employees 
Based on 2022 Greenhouse Gas Reporting Program data , DEQ anticipates that 69 large 
businesses may be directly impacted  by the proposed rule amendments .  The impacts 
discussed in the fiscal and economic section above apply to large businesses as follows : 
• DEQ anticipate s that expanding the verification applicability under Division 272 will 
impact one  large business. 
• Large businesses that report  biogas, biomethane or hydrogen may incur cost 
described above related to the reporting of those fuel types .  Currently  20 large 
businesses report those fuel types under D ivision 215, including one  natural gas 
utility  and 19 stationary sources.  
• Large business that are stationary sources would be required to go through the BAER 
process for modifications  that meet the criteria in the rule .  DEQ does not have an  
estimate of how many modifications may trigger this requirement.  Ho wever, DEQ 
anticipates that only a small per centage of stationary sources would be affected .  
Currently 14 out of approximately 2,500 sources with DEQ air permits are known to 
be subject to BAER requirements.  
• It is possible that there are large businesses that would be required to get a new Basic 
ACDP due to the proposed new source category in OAR 340 -216-8010 Table 1.  
However, DEQ is not currently aware of any.  
• Large business required to obtain verification services may incur costs associated 
with developing and maintaining GHG data monitoring plans .  DEQ estimates that 
there are approximately 48 large  businesses, not currently maintaining plans, that 
may be impacted by this amendment . 
 
Small businesses – businesses with 50 or fewer 
employees 
 
a. Estimated number of small businesses and types of businesses and 
industries with small businesses subject to proposed rule.  
 
Based on current Oregon Department of Employment data DEQ estimates that18 small businesses may be directly affected by the amendme nts.  The impacts described above apply 
to: 44 
 • DEQ estimates that 4 currently approved verification bodies may be small 
businesses.  These verification bodies  may incur fiscal impacts described above and 
related to amendments to Division 272.  
• DEQ estimates th at small businesses that are stationary sources  may experience 
impacts  described above associated with reporting of biogas, biomethane or 
hydrogen.  Currently two stationary source s, identified as a small business es, report 
biogas.  
• No small businesses are expected  to be impacted by amendments to GHG 
monitoring plans  or by expanding verification applicability . 
• Small businesses that are fuel suppliers may be impacted by amendments requiring 
additional recordkeeping and notification to position holders of exported fuel .  DEQ 
estimates that approximately 12 small business may be impacted  by these 
amendments. 
• Small business that are stationary sources would be required to go through the BAER 
process for modifications that meet the criteria in the rule .  DEQ does not have an  
estimate of how many modifications may trigger this requirement.  However, DEQ 
anticipates that only a small percentage of stationary sources would be affected.  
• It is possible that there are small businesses that would be required to get a new 
Basic ACDP due to the proposed new source category in OAR 340- 216-8010 Table 
1.  However, DEQ is not currently aware of any.  
 
b. Projected reporting, recordkeeping and other administrati ve activities, 
including costs of professional services, required for small businesses to 
comply with the proposed rule.  
 
Small businesses may incur minimal recordkeeping or other administrative costs associated 
with rule amendments to Division 215 for obt aining and maintaining records required for the 
reporting of biogas, biomethane and hydrogen.  DEQ also anticipates that small businesses 
may experience a dministrative costs related to n otification requirements  for fuel diversions 
when fuel is exported.  
 
If required to go through the BAER process, a small business would have  to prepare a 
BAER assessment, which DEQ estimated earlier in this document to cost about $30,000. 
 
Facilities complying with a BAER order may have costs including installation of additional 
equipment as well as costs to monitor, keep records, and provide reports to DEQ about air 
pollution emitted by their facility .  The specific actions, if any, that a facility would be 
required to take would de pend on the results of DEQ’s site -specific analysis of the BAER 
assessment and emission reduction options at the site.  
 
If a small business were required to get a Basic ACDP due to the proposed changes  to 
Division 216, that facility would have recordkeeping and reporting costs associated with 
complying with that permit.  
 45 
 c. Projected equipment, supplies, labor and increased administration required 
for small businesses to comply with the proposed rule.  
 
The proposed rule amendments to Division 215 and 272 include no additional requirements for equipment, supplies or labor for small businesses.  These business es may experience 
some increase in  administrative costs as described above.   
 Facilities complying with a BAER ord er may have costs including installation of additional 
equipment as well as costs to monitor, keep records, and provide reports to DEQ about air pollution emitted by their facility .  The specific actions, if any, that a facility would be 
required to take would depend on the results of DEQ’s site- specific analysis of the BAER 
assessment and emission reduction options at the site.  For the 2021 Climate Protection 
Program, DEQ contracted with ICF to analyze program options to reduce greenhouse gas emissions. As  part of the study, ICF assumed cost ranges for an industrial stationary source 
to reduce emissions.  The study assumed a range between $47 to $190 (2020$) per metric ton of emissions reduced. Cost is one of several  factors considered by DEQ when 
determining which emissions reductions measures to include in a BAER order.  
d. Describe how DEQ involved small businesses in developing this proposed 
rule.  
 
DEQ ha d a representative for small business fuel suppliers  on the advisory committee.  DEQ 
sent notifications about the rulemaking to potentially impacted companies, including small businesses.  DEQ held public comment periods at each of the three advisory committee meetings offering members of the public opportunities to provide comment.  After each 
committee meeting DEQ requested written comment from stakeholders , including small 
businesses, on the topics discussed. 
 
Documents relied on for Fiscal and Economic impact 
 
Document title  Document location  
List of GHG RP regulated entities for 2021 https://www.oregon.gov/deq/ghgp/Pages/GHG -
Emissions.aspx  
 
Oregon Employment Department 
Small Oregon Business  Q1 2021  List DEQ 700 NE Multnomah St. STE 600 Portland 
OR 97232  
Oregon Greenhouse Gas Reporting 
Program data  https://www.oregon.gov/deq/ghgp/Pages/GHG -
Emissions.aspx   
Climate Protection Program  List of 
Covered Fuel Suppliers  https://www.oregon.gov/deq/ghgp/Documents/C
PP-CoveredEntities.pdf  
Stationary Sources subject to BAER 
in Climate Protection Program  https ://www.oregon.gov/deq/ghgp/cpp/Pages/Sta
tionary -Sources.aspx  46 
 Greenhouse Gas Reporting and Third 
Party Verification 2019 , Staff Report  https://www.oregon.gov/deq/EQCdocs/0507202
0_ItemC_GHGrules.pdf  
Regulatory Impact Analysis for the 
Mandatory Reporting of Greenhouse 
Gas Emissions Final Rule (GHG R  https://www.epa.gov/sites/default/files/2015 -
07/documents/regulatoryimpactanalysisghg.pdf  
  
Advisory committee fiscal review   
 
ORS 183.33 requires  DEQ to ask for the committee’s feedback on:  
• Whether the proposed rule amendments would have a fiscal impact  
• If yes, the extent of the impact, and how DEQ might mitigate any impacts  
• Whether the proposed rule amendments would have a  significant adverse impact on 
small businesses, and if yes, how might DEQ reduce that impact.  
 Would the draft rule have a fiscal impact?  
 The committee reviewed the draft fiscal and economic impact statement . DEQ received 
specific comments that the draft fiscal impact statement only included a limited discussion 
of indirect impacts to the public.  In response to these comments, DEQ incorporated 
additional discussion on indirect fiscal impacts to the p ublic and communities in Oregon.  
 What would the extent of the impact be?  
 DEQ received several comments that agreed with the description of impacts related to reporting of biomethane and hydrogen. Some members went on to express concern that , if 
DEQ modi fied the existing approach for biomethane and hydrogen reporting, that currently 
allows for book and claim reporting, costs may increase,  and this may impact energy costs.  
Other committee members stated  that a llowing for the use of  out-of-state biomethane or 
hydrogen projects  as compliance under the Climate Protection Program  may not be  
economical and  could create higher compliance costs for utilities and consumers than other 
decarbonization strategies.  
 
There was agreement  from several RAC members that increased verification, reporting and 
recordkeeping requirements will increase costs and have a fiscal impact on regulated 
entities . RAC members did not provide comment or estimates on th ose costs . DEQ 
anticipates that these co sts will be unique to each regulated entity, depending on their 
reporting circumstances and doesn’t have sufficient information to estimate the range of those costs.  
  Would the proposed rule amendments have  a significant adverse impact on small 
busines ses and if so, what are recommendations for potential mitigation?  
 DEQ did not receive specific comment s stating significant adverse impacts to small 
businesses.  47 
  
The committee members were asked to review and provide comment on the draft fiscal and 
economic impact statement during the  third meeting of the advisory committee on June 27, 
2023.  
  
Housing cost  
 
As ORS 183.534 requires, DEQ evaluated whether the proposed rule  would have an effect 
on the development cost of a 6,000- square -foot parcel and construction of a 1,200- square-
foot detached, single -family dwelling on that parcel.   DEQ determined the proposed rule 
amendments will have no impact on the supply of housing or land for residential 
development .  The proposed rule  amendment s will not impact the cost of labor or 
administration related to such development . 
 
  48 
 Racial Equity 
 
These proposed rule amendments will support implementation of DEQ’s Climate Protection Program, Greenhouse Gas Reporting Program, and Third Party Verification program.  
  The Climate Protection Program supports racial equity by reducing greenhouse gas 
emissions from sources in Oregon, achieving co- benefits from reduced emissions of other 
air contaminants, and enhancing public welfare for Oregon communities, particularly environmental justice communities .  Environmental justice communities include Oregon’s 
communities of color and tribal communities along with other commu nities traditionally 
underrepresented in public processes, and disproportionately harmed by pollution and 
environmental and health hazards.  
  The proposed rule amendments incorporate additional process improvements and technical clarifications for regulate d companies while continuing to support these programs’ overall 
implementation.  
 Proposed rule amendments for the Climate Protection Program include clarifications on how the BAER approach is incorporated into the modification process for stationary source s and 
clarifications to ensure that emissions from natural gas delivered by a natural gas utility, whether combusted or oxidized, are covered emissions .  Other proposed rule amendment s 
change how DEQ would distribute compliance instruments to liquid fuels and propane suppliers, but do not change the annual emissions caps or fuel supplier s regulated by the 
program.  Proposed rule amendments for the Greenhouse Gas Reporting Program and Third Party Verification program include changes to improve the quality of  collected emissions 
data and changes to account for  biomass derived fuels specifically for accounting of 
biomethane and biomethane injected into natural gas pipelines.  While these proposed amendments  are expected to improve  the implementation of t hese 
three programs , DEQ has not identified any significant positive  or negative implications for 
racial equity.  DEQ received comment that air pollution from industrial facilities  continues  to 
disproportional ly impact  environmental justice communities, particularly Black 
communities  and other  communities of color. While prop osed change s to incorporate 
modification s at industrial facilities into BAER are helpful , DEQ would need to make 
additional changes to these proposed rule amendments  for BAER to have a positive impact 
on racial equity.  
  49 
 Environmental Justice Considerations 
 
As stated above , the Climate Protection Program is designed to reduce greenhouse gas 
emissions from sources in Oregon, achieve co -benefits from reduced  emissions of other air 
contaminants, and enhance public welfare for Oregon communities, particularly environmental justice communities.  
  
The program:  
• Requires that covered entities reduce greenhouse gas emissions.  
• Supports reduction of emissions of other  air contaminants that are not greenhouse 
gases.  
• Prioritizes reduction of greenhouse gases and other air contaminants in 
environmental justice communities.  
• Provides covered entities with compliance options to minimize disproportionate 
business and consumer  economic impacts associated with meeting the Climate 
Protection Program requirements; and  
• Allows covered fuel suppliers to comply with the Climate Protection Program 
requirements in part through contributing community climate investment funds to support projects that reduce greenhouse gas emissions and prioritize benefits for environmental justice communities in Oregon . 
 Environmental justice communities are communities of color, communities experiencing lower incomes, tribal communities, rural communities, coastal communities, communities with limited infrastructure and other communities traditionally underrepresented in public processes and disproportionately harmed by environmental and health hazards, including seniors, youth, and persons with disabilities . 
 These proposed rule amendments will support implementation of DEQ’s Climate Protection Program, as well as the Gre enhouse Gas Reporting, and Third Party Verification program s 
that enable implementation of the C limate P rotection Program .  Insofar as these proposed 
amendments support and could improve that implementation,  the proposed amendment s 
would continue to suppor t the overall goals of th e Climate Protection Program.  
 
 
 50 
 Federal relationship  
 
Relationship to federal requirements  
 
Relationship to federal requirements ORS 183.332, 468A.327 and OAR 340- 011-0029 
require DEQ to attempt to adopt rules that correspond with existing equivalent federal laws and rules unless there are reasons not to do so.  
 
Climate Protection Program, Divis ion 271  
 The proposed Climate Protection Program rule amendments are in addition to federal requirements since there are no federal regulations that require the mandatory reduction of greenhouse gas emissions from the Climate Protection Program’s covered e ntities . 
 DEQ determin ed that  there are scientific, economic, technological  and other reasons for 
exceeding applicable federal requirements in these amendments, for the same  following  
reasons that apply generally to the original adoption of the Climate Protection Program . 
Climate change caused by greenhouse gas emissions has detrimental effects on the overall public health, safety and welfare of the State of Oregon .  Programs , like  the Climate 
Protection Program, that reduce greenhouse gas emissions are a key tool to help address the 
worsening effects of climate change caused by the use  of fossil fuels. Oregon is already 
experiencing effects such as more frequent and intense wildfires, drought and more frequent heat waves, extended fire seasons, and reduced snowpack that supplies fresh water for 
rivers, streams, and reservoirs . These changes have a disproportionate impact on 
environmental justice communities in Oregon, including communities of color, communities with lower incomes, tribal communities, rural communities, coastal communities, 
communities with limited infrastructure and other communities traditionally underrepresented in public processes and typically disproportionately harmed by environmental and healt h hazards, including seniors, youth and persons with disabilities.  
 Transitioning from fossil fuels to renewable fuels, such as electricity  and renewable diesel, 
and reduc ing the emissions from use the fossil fuels  will benefit Oregon's economy by 
providi ng new opportunities for producing energy in- state and associated economic and job 
benefits. There are also newer technologies and alternatives  that are becoming available that 
can help reduce greenhouse gas emission s that result from the use of fuels and energy, such 
as the use of hydrogen. Reducing greenhouse gas  emission s from fossil fuels will also 
reduce emissions of  other air contaminants and improve public health in Oregon 
communities.  Investments to reduce greenhouse gas emissions th rough the Commun ity 
Climate Investment component of the Climate Protection Program will also generate associated economic benefits  such as job development in addition to reducing emissions, 
particularly in environmental justice communities.  
 DEQ adopted the Climate Prote ction Program to reduce greenhouse gas emissions from 
sources in Oregon, achieve co -benefits from reduced emissions of other air contaminants as 
greenhouse ga ses emission are reduced , and to enhance public welfare for Oregon 51 
 communities, particularly environmental justice communities disproportionately burdened 
by the effects of climate change and air contamination. Despite being a leader in establishing  
programs to track and reduce  greenhouse  gas emission, Oregon’s emission s are not 
declining and are falling further behind emissions reduction targets ad opted by the 
Legislature in 2007.  The Climate Protection Program will address a significant portion of 
Oregon’s greenhouse gas emissions and  the program’s emission cap decline of 50% by 2035 
and 90% by 2050 are critical to achieving Oregon ’s emissions reduction goals.  
 
Greenhouse Gas Reporting Program, Division 215  
 
Since EPA collects data and information under the federal GHG Reporting Program , the 
proposed rules for GHG RP, OAR chapter 340, division 215, are “ in addition to the federal 
requirements.”   EPA’s program  is limited to collecting  data from  large  sources, emitting 
over 25,000 MTCO2e , and collects data from suppliers at the national and not state level. 
Due to the limitations for the federal program, DEQ determined that there are scientific, environmental, and technological reasons to require reporting beyond federal requirements . 
Specifically, t o accurately account for all greenhouse gas emissions occurring at the state 
level, such as those associated with small sources and fuel suppliers, state reporting rules 
must require additional reporting, beyond what is required by EPA . Imposing the se 
additional requirements ensures that Oregon has complete data and information to inform environmental state policy related to greenhouse gas emissions , for the same environmental, 
scientific, economic, technological and other reasons explained above reg arding the Climate 
Protection Program. Where possible DEQ has aligned reporting methodology, timelines,  and 
requirements so that sources that must report to both EPA and DEQ may use information submitted to EPA to inform compliance with DEQ’s  rules . 
 
Third  party Verification, Division 272 
 
Since  reports submitted to EPA differ in scope and  data requirements  than those submitted 
to Oregon’s  GHG RP , and EPA does not require independent verification of reported data, 
Oregon’s  third  party verification  requirements , OAR 340 chapter 340, division 272 are also  
“in addition to the federal requirements. ” DEQ determined that there are scientific and 
environmental reasons to require additional verification since third party verification of 
environmental data improves data reliability and provide s assurances that emitters of GHG 
emissions are accurately calculating emissions and correctly meeting Oregon specific requirements.   These additional requirements are also needed for the same environ mental, 
scientific, economic, technological and other reasons explained above regarding the Climate Protection Program.  
 
What alternatives did DEQ consider if any?  
 
Climate Protection Program, Division 271 
 In des igning  the Climate Protection Program, Division 2 71, DEQ considered multiple  
alternative program elements , including but not limited to  point of regulation for covered 
emission s, applicability  thresholds  for covered entities,  annual program caps, methodology 52 
 for distributing compliance instruments to covered fuel suppliers, compliance periods, 
banking and trading of compliance instruments, Community Climate Investment credits as a 
voluntary compliance option for covered fuel suppliers , component s of a BAER assessment 
for stationary sources , timeline for stationary sources to conduct BAER  assessments,  and 
considerations and elements of a BAER order.  DEQ incorporated alternative s into the rules 
based on input and comments provided by the rulemaking advisory committee, affected 
parties, stakeholders, community- based organizations, and the public . DEQ also  received 
comments and input on alternatives fro m affected parties, stakeholders, and community -
based organizations in an eighteen- month public engagement process  prior the release of the 
Notice of Proposed Rulemaking for the Climate Protection  Program.  
 For the proposed rule amendments for this rulemaking, DEQ considered alternatives  to the 
proposed amendments for the  distri bution of compliance instruments. For example, DEQ 
consider ed replacing the three -year evaluation period with a two year or a one -year period.  
DEQ also considered using the most recent  verified  Greenhouse Gas Reporting emissions 
data instead of proposing to use the most recent unveri fied Greenhouse Gas Reporting 
emissions data and incorporating an emissions data correction factor.  DEQ considered 
alternative methodologies for calculating distributions from the compliance instrument  
reserve, and alternative  dates for requests from the compliance  instrument  reserve and 
distribution of compliance instruments by DEQ.  DEQ also considered  alternatives for the 
proposed addition of holding limits for compliance instruments, including whether holding limits should be applied as a percentage of t he annual program caps or the total number of 
compliance instruments in distribution .  DEQ also considered applying and  enforcing 
holding limits on an annual basis instead of at the end of each compliance period and 
considered alternatives to the number of compliance instruments held in excess of each 
covered fuel supplier’s sum of compliance obligation s. DEQ did not believe these 
alternative options for distributing compliance instruments and holding limits addressed the 
needs detailed above . 
 
For proposed amendment s on modification at a facility that would trigger a BAER 
assessment, DEQ considered alterative lower emission s thresholds for the proposed 
requirement  that the modification  would increase the source’s PTE of BAER covered 
emissions by 10,000 MT CO2e /year or more ( for example 5,000 CO2e MT or lower). DEQ 
also considered alternatives to the modification  process for existing BAER sources. DEQ 
did not believe these alternatives addressed the needed identified above , specifically that a  
lower emission s threshol d for this requirement woul d unnecessarily delay the modification 
process for some stationary sources.  
 
Greenhouse  Gas Reporting Program, Division 215  
 In designing the GHG RP , Division 215, DEQ has considered alternative options  to 
threshold applicability, methodology and requirements and  has incorporated alternative 
approaches into the rule based on input from past advisory committees and outreach to affected stakeholders.  The program strives to collect comprehensive and verifiable 
greenhouse  gas emissions data while minimizing the reporting and recordkeeping burdens to 
regulated entities.  Documentation of this is in the rulemaking record  available from DEQ . 53 
  
DEQ’s greenhouse gas reporting rules align with EPA methodology when possible, 
includ ing requiring the use of EPA quantification methodology for reporting emissions from 
stationary sources and the use of EPA emission factors for the reporting of liquid fuels and 
natural gas. During this rulemaking DEQ proposed alternatives to federal requi rements 
when EPA rules were not sufficient for  addressing state level data needs. This includes 
clarifying amendments for reporting by fuel and electricity suppliers or for stationary 
sources with unique process emissions, such as foam blowing . DEQ did not explore 
alternatives to these amendments  because they are directly related to state specific data 
needs not addressed by federal rules.  
 
For this rulemaking DEQ specifically considered alternatives  for the reporting of 
biomethane and hydrogen. F ederal GHG reporting  rules  lack methods  for reporting 
emissions based on  contractual delivery of these fuels , required for reporting under  Division 
215. To address this need DEQ considered several  alternatives . The alternative approaches 
considered  different delivery or geog raphic constraints, pipeline injection requirements, 
reported data elements and documentation requirements. These alternatives were discussed  
at the RAC #2 meeting.  
 
DEQ selected the proposed requirements because  they ensure that biomass -derived fuels 
injected into natural gas pipeline s with a physical pathway to Oregon c ould be identified and 
treated in accordance with state air quality regulation requirements . Additionally, 
biomethane injected in Oregon, but acc ounted for in other jurisdictions , would not be double 
counted.  
 
DEQ did not adopt the alternatives consider ed because further restriction  of geographic 
constraints or increased transmission requirements would not  increase certainty of physical 
delivery of  the fuel  or reduce duplicative claims  on that gas in other jurisdictions. 
Additionally, expanding geographic constraints to allow for all resources across North 
America would allow for reporting of gas that is physically unable to reach  Oregon.  
 
Third party Verification, Division 272  
 
DEQ considered alternatives to third party verification during the Greenhouse G as 
Reporting and Third part y Verification 2019 rulemaking. Alternatives considered at that 
time are described in the notice for that rulemaking.  
 For this  rulemaking , DEQ is proposing to expand third party verification requirements to 
entities regulated by Oregon emissions mitigation programs , not already subject to third 
party verification . DEQ is also proposing amendments to clarify rule language and improve 
implementation . DEQ considered  not expanding the verification requirements . However,  
that option was not selected be cause  the entities  identified  have existing emission reduction 
compliance requirements that rely on data submitted to DEQ . Third party verification of that 
data increases the reliability and accuracy of compliance and ensures the integrity of 
Oregon’s GHG emissions tracking .  DEQ did not consider alternatives to rule clarifications 
or amendments that addressed improved implementation .  54 
  
Land use 
 
Land -use considerations  
 
In adopting new or amended rules, ORS 197.180 and OAR 340- 018-0070 require DEQ to 
deter mine whether the proposed rules significantly affect land use. If so, DEQ must explain 
how the proposed rules comply with statewide land -use planning goals and local 
acknowledged comprehensive plans.  Under OAR 660 -030-0005 and OAR 340 Division 18, DEQ considers that rules affect land 
use if:  
• The statewide land use planning goals specifically refer to the rule or program, or  
• The rule or program is reasonably expected to have significant effects on:  
• Resources, objects, or areas identified in the statewide planning goals, or  
• Present or future land uses identified in acknowledge comprehensive plans  
 DEQ determined whether the proposed rules involve programs or actions that affect land use by reviewing its Statewide Agency Coordination plan. The plan describes the programs that DEQ determined significantly affect land use. DEQ considers that its programs specifically relate to the following statewide goals:  
 
Goal  Title 
5 Natural Resources, Sce nic and Historic Areas, and Open Spaces  
6 Air, Water and Land Resources Quality  
11 Public Facilities and Services  
16 Estuarine Resources  
19 Ocean Resources  
 Statewide goals also specifically reference the following DEQ programs:  
 
• Nonpoint source discharge water quality program – Goal 16 
• Water quality and sewage disposal systems – Goal 16 
• Water quality permits and oil spill regulations – Goal 19 
 
Determination  
 DEQ determined that these proposed rule amendments will affect land use under OAR 660-030-0050.  Specifically, DEQ rules have identified that the issuance of air quality permits 
and authorizations are DEQ land use actions, as provided in OAR 340- 018-0030(1).  This 
rulemaking includes rule amendments that relate to issuance of air quality perm its and 
authorizations, particularly as related to the implementation of the BAER program element and the amendments to division 216 rules that require that a new category of air contamination source obtain a Basic ACDP.  Though these proposed amendments w ill affect 55 
 land use, the proposed amendments fall within current DEQ procedures to ensure 
consistency with state land use planning goals.  
  
The proposed rule amendments would be consistent with state land use law because any 
stationary sources that has received a Climate Protection Program permit addendum will 
already have demonstrated land use compliance when they obtained or will obtain their 
underlying Air Quality permit. The air quality permit programs require that a new business 
provide a Land Use Compatibility Statement from local government when applying for a permit. This assures that the business has an approved use for the property where it is 
located. Existing permittees have provided Land Use Compatibility Statements, which are 
on file with DEQ. A facility that applies for a Basic ACDP due to the proposed new source 
category in OAR 340- 216-8010 Table 1 would also have to provide a LUCS.  
 
  56 
 EQC Prior Involvement  
 
The EQC adopted a temporary rule for the Climate Protection Program at its meeting on Nov. 17, 2022. The purpose of the temporary rule was to clarify exemptions to the covered 
emissions of natural gas local distribution companies, as described in OAR 340- 271-
0110(4)(b)(B).   
In addition, DEQ plans to provide  a rule development  update on the Climate 2023 
rulemaking at the September  2023 EQC meeting , and the  Commission’s  feedback , in 
addition to both oral and written comments received from the public, will be considered by 
DEQ when it develops  final proposed rules .  
 
 
 57 
 Advisory Committee 
 
Background 
 
DEQ convened an advisory committee for the Climate 2023 Rulemaking.  In selecting 
committee members for the advisory committee some key considerations for DEQ included : 
• Size – Large enough to repre sent affected parties and scope of potential rule changes, 
but small enough so members had opportunity to provide expertise and share 
experiences. Since the rulemaking encompasses three different programs , the scop e 
of the rulemaking affected  several distinct groups of affected  entities , including 
companies with emission reporting and verification requirements, fuel suppliers 
regulated by the Climate Protection  Program, both natural gas utilities  and liquid 
fuels and  propane suppliers, and electricity sector suppliers . Some  regulated entities  
were potentially  affected by multiple program changes while others only by a small 
number of potential changes.  
• Engagement- Recognize the degree to which committee members are regulated by 
these DEQ programs or have engaged on the development and implementation of these programs in Oregon  
• Balance – Balancing representation of affected parties and stakeholders so a range of 
perspectives and experience are shared  
• Capacity – Identifying topics and program issues where individual committee  
members participation and feedback might be most impactful, supporting members 
in effectively  participating  on the committee , identifying  committee members  with 
extensive networks, including connections to communities based and environmental justice organizations to leverage  those connections to inform this rulemaking process  
and encourage public comment 
The advisory committee met three times  in the Spring and Summer. The committee’s web 
page is located at: Climate 2023 Rulemaking
. 
 
The committee members were:  58 
 Rulemaking Name Advisory Committee  
Name  Representing  
Alex Marcucci  Trinity Consultants  
Carra Sahler  Green Energy Institute (Lewis and Clark)  
Chris Huiard  Space Age  
Jeremy Price  HF Sinclair  
Jim Verburg  Western States Petroleum Association  
Marissa Bach  Shell Trading US Company  
Mary Moerlins  Northwest Natural  
Michelle Detwiler  Renewable Hydrogen Alliance  
Mike Freese  Oregon Fuels Association  
Nora Aptor  Oregon Environmental Council  
Norma Job  Ash Grove Cement Company  
Sam Wade  Coalition for Renewable Natural Gas  
Spencer Gray  Northwest & Intermountain Power Producers 
Coalition  
Zepure Shahumyan  PacifiCorp  
 
Meeting notifications 
 
To notify people about the advisory committee’s activities, DEQ:  
• Sent GovDelivery bulletins, a free e -mail subscription service, to the following 
subscribers lists:  
o Clean Fuels Program  
o Climate Protection Program  
o Greenhouse Gas Programs  
o Greenhouse Gas Reporting 
o Third Party Verification Program  
• Added advisory committee announcements to DEQ’s calendar of public meetings at DEQ Calendar
. 
 
Committee discussions  
 In addition to the recommendations described under the Statement of Fiscal and Economic Impact section above, the committee was asked to discuss and provide input on the proposed amendments for this rulemaking , Advisory committee agendas, meeting materials , 
presentations and  summaries are available on the rulemaking webpage . 
 The advisory committee was also asked to review and provide input on the draft racial equity statement and environmental justice considerations The public was also invited to provide verbal and written comment. Comments received from this meeting are available on the Climate 2023 rulemaking website here
.   59 
 Public Engagement 
 
Public notice  
 
DEQ provided notice of the proposed rulemaking and rulemaking hearing by:  
• On Au g. 22, 2023, fil ing notice with the Oregon Secretary of State for publication in 
the September 2023 Bulletin  
• Posting the Notice, Invitation to Comment and Draft Rules on the web page for this 
rulemaking, located at : Climate 2023 Rulemaking  
Emailing approximately 26,700 interested parties on the following DEQ lists through GovDelivery: 
o DEQ Public Notices  
o Rulemaking 
o Air Quality  Permits  
o Clean Fuels Program  
o Climate Protection Program  
o Greenhouse Gas Programs  
o Greenhouse Gas Reporting 
o Third Party Verification Program  
o Title V  Permit Program  
• Emailing approximately  2,982 stakeholders on the  
o Greenhouse Gas Reporting contact list for all reporting entitie s 
o Climate Protection Program contact list for all covered entities  
o DEQ Air Contaminant Discharge Permit holders  
o EPA Title V permit holders  
o Third party verification contact list for all approved verifiers  
• Emailing the following key legislators required under ORS 183.335: 
o Senator Rob Wagner, Senate President  
o Representative Dan Rayfield, House Speaker  
o Senator Janeen Sollman, Chair  of Senate Energy and Environment  
o Representative Pam Marsh, Chair  of House Committee on Climate, Energy 
and Environment 
• Emailing the Department of Land Conversation and Development required under OAR 340 -018-0070(3) and OAR 660-030-0005(2) 
• Emailing advisory committee members  
• Posting on the DEQ event calendar: DEQ Calendar
 
  
  60 
 Public Hearing  
 
DEQ plans to hold one p ublic hearing  virtually  only. Anyone can attend the  hearing by 
webinar or teleconference.  
 Date: Sept . 18, 2023 
Time: 4 p.m.  PT 
Join via Zoom
  
 DEQ will consider all comments and testimony received before the closing date. DEQ will summarize all comments and respond to comments in the Environmental Quality Commission staff report.  
 
 
 61 
 Accessibility Information 
 
You may review copies of all documents referenced in this announcement electronically. To 
schedule a review of all websites and documents referenced in this announcement, contact Elizabeth Elbel or Nicole Singh at Climate.2023@deq.oregon.gov
. Please notify D EQ of 
any special physical or language accommodations or if you need information in large print, Braille or another format, or any other arrangements necessary to accommodate a disability. 
To make these arrangements, contact DEQ, Portland, at 503-229- 5696 or call toll- free in 
Oregon at 1-800-452-4011, ext. 5696; fax to 503-229- 6762; or email to 
deqinfo@deq.oregon.gov . Hearing impaired persons may call 711. 
Translation or other f ormats  
Español   |  한국어  |  繁體中文  |  P усский  |  Ti ếng Vi ệt  |  اﻟﻌﺮﺑﯿﺔ  
Contact: 800-452-4011  |  TTY: 711  |  deqinfo@deq.state.or.us   
DEQ does not discriminate on the basis of race, color, national origin, disability, age or sex 
in administration of its programs or activities.  
Visit DEQ’s Civil Rights and Environmental Justice page . 
  62 
 Draft Rules – Edits Highlighted 
 
Key to Identifying Changed Text:  
Deleted Text  
New/inserted text  
Text deleted from one location  - and moved to another location  
 
Enforcement Procedure and Civil Penalties, Division 12  
 
340-012-0054  
 
Air Quality Classification of Violations  
 (1) Class I : 
 
(a) Constructing a new source or modifying an existing source without first obtaining a 
required New Source Review/Prevention of Significant Deterioration (NSR/PSD) permit;  
 (b) Constructing a new source, as defined in OAR 340-245-0020, without first obtaining a required Air Contaminant Discharge Permit that includes permit conditions required under OAR 340 -245-0005 through 340-245-8050 or without complying with Cleaner Air Oregon 
rules under OAR 340-245-0005 through 340-245-8050;  (c) Failing to conduct a source risk assessment, as required under OAR 340-245-0050;  (d) Modifying a source in such a way as to require a permit modification under OAR 340-245-0005 through 340- 245-8050, that would increase risk above permitted levels under 
OAR 340 -245-0005 through 340-245-8050 without first obtaining such approval from DEQ; 
 (e) Operating a major source, as defined in OAR 340 -200-0020, without first obtaining the 
required permit;  (f) Operating an existing source, as defined in OAR 340-245-0020, after a submittal deadline under OAR 340 -245-0030 without having submitted a complete application for a 
Toxic Air Contaminant Permit Addendum required under OAR 340-245-0005 through 340-245-8050;  (g) Exceeding a Plant Site Emission Limit (PSEL);  
 (h) Exceeding a risk limit, including a Source Risk Limit, applicable to a source under OAR 340-245-0100;  (i) Failing to install control equipment or meet emission limits, operating limits, work practice requirements, or performance standards as required by New Source Performance 63 
 Standards under OAR 340 division 238 or National Emission Standards for Hazardous Air 
Pollutant Standards under OAR 340 division 244;  
 
(j) Exceeding a hazardous air pollutant emission limitation;  
 (k) Failing to comply with an Emergency Action Plan;  
(l) Exceeding an opacity or emission limit (including a grain loading standard) or violating an operational or process standard, that was established under New Source Review/Prevention of Significant Deterioration (NSR/PSD); 
 
(m) Exceeding an emission limit or violating an operatio nal or process standard that was 
established to limit emissions to avoid classification as a major source, as defined in OAR 340-200-0020;  
 
(n) Exceeding an emission limit or violating an operational limit, process limit, or work 
practice requirement that was established to limit risk or emissions to avoid exceeding an 
applicable Risk Action Level or other requirement under OAR 340- 245-0005 through 340-
245-8050;  
 
(o) Exceeding an emission limit, including a grain loading standard, by a major source, as 
defined in OAR 340- 200-0020, when the violation was detected during a reference method 
stack test;  
 (p) Failing to perform testing or monitoring, required by a permit, permit attachment, rule or 
order, that results in failure to show compliance with a Plant Site Emission Limit or with an 
emission limitation or a performance standard established under New Source 
Review/Prevention of Significant Deterioration, National Emission Standards for Hazardous 
Air Pollutants, New Source Performance Standards, Reasonably A vailable Control 
Technology, Best Available Control Technology, Maximum Achievable Control 
Technology, Typically Achievable Control Technology, Lowest Achievable Emission Rate, Toxics Best Available Control Technology, Toxics Lowest Achievable Emission Rat e, or 
adopted under section 111(d) of the Federal Clean Air Act;  
 (q) Causing emissions that are a hazard to public safety;  
 
(r) Violating a work practice requirement for asbestos abatement projects;  
 
(s) Improperly storing or openly accumulating friable asbestos material or asbestos -
containing waste material;  
 
(t) Conducting an asbestos abatement project, by a person not licensed as an asbestos 
abatement contractor;  
 (u) Violating an OAR 340 division 248 disposal requirement for asbes tos-containing waste 
material;  
 64 
 (v) Failing to hire a licensed contractor to conduct an asbestos abatement project;  
 
(w) Openly burning materials which are prohibited from being open burned anywhere in the state by OAR 340- 264-0060(3), or burning materials  in a solid fuel burning device, 
fireplace, trash burner or other device as prohibited by OAR 340- 262-0900(1);  
 
(x) Failing to install certified vapor recovery equipment;  
 
(y) Delivering for sale a noncompliant vehicle by a vehicle manufacturer in violatio n of 
Oregon Low Emission and Zero Emission Vehicle rules set forth in OAR 340 division 257;  
 
(z) Exceeding an Oregon Low Emission Vehicle average emission limit set forth in OAR 
340 division 257;  
 
(aa) Failing to comply with Zero Emission Vehicle (ZEV) sales requirements, or to meet 
credit retirement and/or deficit requirements, under OAR 340 division 257; 
 (bb) Failing to obtain a Motor Vehicle Indirect Source Permit as required in OAR 340 division 257;  
 
(cc) Selling, leasing, or renting a noncompliant vehicle by an automobile dealer or rental car 
agency in violation of Oregon Low Emission Vehicle rules set forth in OAR 340 division 
257; 
 (dd) Violating any of the clean fuel standards set forth in OAR 340- 253-0100(6) and in 
Tables 1 and 2 of OAR 340- 253-8010; 
 (ee) Committing any action related to a credit transfer that is prohibited in OAR 340 -253-
1005(8);  
 
(ff) Inaccurate reporting that causes illegitimate credits to be generated in the Oregon Clean Fuels Program, OAR chapter 340, division 253, or that understates a registered party’s true compliance obligation in deficits under such program;  
 (gg) Misstating material information or providing false information when submitting an 
application for a carbon intensity score under OAR 340- 253-0450, OAR 340- 253-0460, or 
OAR 340 -253-0470, or when submitting an application for advance credits under OAR 340-
253-1100;  
 
(hh) Failing to timely submit a complete and accurate annual compliance report under OAR 
340-253-0650;  
 
(ii) Failing to timely submit a complete and accurate emissions data report under OAR 340 -
215-0044 and OAR 340- 215-0046;  
 65 
 (jj) Submitting a verification statement to DEQ prepared by a person not approved by DEQ 
under OAR 340- 272-0220 to perform verification services;  
(kk) Failing to timely submit a v erification statement that meets the verification 
requirements under OAR 340- 272-0100 and OAR 340- 272-0495;  
 
(ll) Failing to submit a revised application or report to DEQ according to OAR 340 -272-
0435;  
(mm) Failing to complete re -verification according to OAR 340 -272-0350(2);  
 
(nn) Failing to timely submit a Methane Generation Rate Report or Instantaneous Surface 
Monitoring Report according to OAR 340- 239-0100;  
 (oo) Failing to timely submit a Design Plan or Amended Design Plan in accordance with OAR 340 -239-0110(1);  
 
(pp) Failing to timely install and operate a landfill gas collection and control system 
according to OAR 340- 239-0110(1);  
 (qq) Failing to operate a landfill gas collection and control system or conduct performance 
testing of a landfill gas control device according to the requirements in OAR 340- 239-
0110(2);  
 (rr) Failing to conduct landfill wellhead sampling under OAR 340- 239-0110(3);  
 (ss) Failing to comply with a landfill compliance standard in OAR 340- 239-0200;  
 
(tt) Failing to conduct monitoring or remonitoring in accordance with OAR 340- 239-0600 
that results in a failure to demonstrate compliance with a landfill compliance standard in 
OAR 340 -239-0200 or the 200 ppmv threshold in OAR 340- 239-0100(6)(b) or OAR 340-
239-0400(2)(c);  
 (uu) Failure to take corrective actions in accordance with OAR 340 -239-0600(1);  
 (vv) Failing to comply with a landfill gas collection and control system permanent shutdown and removal requirement in OAR 340- 239-0400(1);  
 (ww) Delivering for sale a new noncompliant on highway heavy duty engine, truck or trailer 
in violation of rules set forth under OAR 340 division 261;  
 
(xx) Failing to notify DEQ of changes in ownership or operational control or changes to 
related entities under OAR 340 -271-0120;  
 
(yy) Owning or operating a covered entity, identified in OAR 340- 271-0110, after a 
submittal deadline under OAR 340- 271-0150(1)(a) or OAR 340- 271-0330(1)(b) without 
having submitted a complete application for a Climate Protection Progr am permit or Climate 
Protection Program permit addendum required under OAR 340 -271-0150;  66 
  
(zz) Emitting covered emissions from a covered entity, as identified in OAR 340 -271-0110, 
that is a new source, as defined in OAR 340 -271-0020, without having been is sued a BAER 
order under OAR 340-271-0320 and a permit issued under OAR 340-271-0150(3)(c);  
(aaa) Failing to submit a BAER assessment , or an updated BAER assessment , or a 5- year 
BAER report  according to OAR 340-271-0310; 
 (bbb) Failing to comply with a BAE R order issued under OAR 340-271-0320. 
 (ccc) Failing to comply with a condition in a permit, Climate Protection Program permit, or Climate Protection Program permit addendum issued according to OAR 340-271-0150 that requires the reduction of greenhouse ga s emissions;  
 (ddd) Failing to demonstrate compliance according to OAR 340-271-0450;  (eee) Failing to comply with the requirements for trading of compliance instruments under OAR 340 -271- 0500 or 340-271-0510; 
 (fff) Submitting false or inaccurate information on any application or submittal required under OAR chapter 340, division 271;  (ggg) Failing to register as a regulated party in the Oregon Clean Fuels Program under OAR 340-253-0100(1) and (4); or  
(hhh) Failing by a fuel producer to inform DEQ if its  operational carbon intensity exceeds its 
certified carbon intensity as described in OAR 340-253- 0450(9)(e)(D) when credits 
generated from those certified carbon intensity values generated illegitimate credits as 
described in OAR 340-253- 1005(7). . 
 (2) Class II: 
 (a) Constructing or operating a source required to have an Air Contaminant Discharge Permit (ACDP), ACDP attachment, or registration without first obtaining such permit or registration, unless otherwise classified;  
 (b) Violating the terms or c onditions of a permit, permit attachment or license, unless 
otherwise classified;  
 (c) Modifying a source in such a way as to require a permit or permit attachment modification from DEQ without first obtaining such approval from DEQ, unless otherwise class ified;  
 (d) Exceeding an opacity limit, unless otherwise classified;  
 67 
 (e) Exceeding a Volatile Organic Compound (VOC) emission standard, operational 
requirement, control requirement or VOC content limitation established by OAR 340 
division 232;  
 
(f) Failin g to timely submit a complete ACDP annual report or permit attachment annual 
report;  
 
(g) Failing to timely submit a certification, report, or plan as required by rule, permit or permit attachment, unless otherwise classified;  
(h) Failing to timely submit a complete permit application, ACDP attachment application, or 
permit renewal application;  
 (i) Failing to submit a timely and complete toxic air contaminant emissions inventory as required under OAR 340 -245-0005 through 340- 245-8050;  
 
(j) Failing to comply with the open burning requirements for commercial, construction, 
demolition, or industrial wastes in violation of OAR 340- 264-0080 through 0180;  
 (k) Failing to comply with open burning requirements in violation of any provision of OAR 
340 division 264, unless otherwise classified; or burning materials in a solid fuel burning 
device, fireplace, trash burner or other device as prohibited by OAR 340- 262-0900(2). 
 
(l) Failing to replace, repair, or modify any worn or ineffective component or de sign element 
to ensure the vapor tight integrity and efficiency of a stage I or stage II vapor collection system;  
 
(m) Failing to provide timely, accurate or complete notification of an asbestos abatement 
project;  
 
(n) Failing to perform a final air cleara nce test or submit an asbestos abatement project air 
clearance report for an asbestos abatement project;  
 (o) Violating on road motor vehicle refinishing rules contained in OAR 340 -242-0620;  
 (p) Failing to comply with an Oregon Low Emission Vehicle reporting, notification, or 
warranty requirement set forth in OAR division 257; 
 
(q) Failing to receive Green -e certification for Renewable Energy Certificates used to 
generate incremental credits when required by OAR 340- 253-0470;  
 
(r) Failing to register as an aggregator or submit an aggregator designation form under OAR 
340-253-0100(3) and (4)(c);  
 
(s) Failing to keep complete and accurate records under OAR 340 -253-0600;  
 68 
 (t) Failing to ensure that a registered party has the exclusive right to the enviro nmental 
attributes that it has claimed for biomethane, biogas, or renewable electricity either directly 
as a fuel or indirectly as a feedstock under OAR chapter 340, division 253 by either the registered party, the fuel producer, and/or fuel pathway holder ; 
 (u) Failing to timely submit a complete and accurate quarterly report under OAR 340 -253-
0630;  
 (v) Violating any requirement under OAR chapter 340, division 272, unless otherwise 
classified;  
(w) Violating any requirement under OAR chapter 340, division 239, unless otherwise 
classified;  
 
(x) Failing to comply with the reporting notification or warranty requirements for new 
engines, trucks, and trailers set forth in OAR chapter 340, division 261;  
 
(y) Violating any requirement under the Climate Protection Program, OAR chapter 340, 
division 271, unless otherwise classified;  
 
(z) Violating any condition in a permit, Climate Protection Program permit, or Climate 
Protection Program permit addendum issued according to OAR 340- 271-0150, unless 
otherwise classified;  
 (aa) Failing to notify DEQ of a change of ownership or control of a registered party under 
OAR chapter 340, division 253; or  
 
(3) Class III : 
 
(a) Failing to perform testing or monitoring required by a permit, rule or order where missing data can be rec onstructed to show compliance with standards, emission limitations 
or underlying requirements;  
 (b) Constructing or operating a source required to have a Basic Air Contaminant Discharge Permit without first obtaining the permit;  
 
(c) Modifying a source in such a way as to require construction approval from DEQ without 
first obtaining such approval from DEQ, unless otherwise classified;  
 (d) Failing to revise a notification of an asbestos abatement project,  when necessary, unless 
otherwise classifi ed; 
 (e) Submitting a late air clearance report that demonstrates compliance with the standards 
for an asbestos abatement project;  
 69 
 (f) Licensing a noncompliant vehicle by an automobile dealer or rental car agency in 
violation of Oregon Low Emission Vehicle rules set forth in OAR Chapter 340, division 257;  (g) Making changes to a submitted quarterly or annual report under OAR Chapter 340, division 253 without DEQ approval under OAR 340-253-0650(4); or  (h) Failing to upload transactions to a quarterly report by the 45-day deadline under OAR 340-253-0630.  [Note: Tables and Publications referenced are available from the agency.]  
Statutory/Other Authority: ORS 468.020, 468A.025 & 468A.045 Statutes/Other Implemented: ORS 468.020 & 468A.025 History:  
DEQ 16 -2022, amend filed 09/23/2022, effective 09/23/2022
 
DEQ 11 -2022, minor correction filed 08/09/2022, effective 08/09/2022  
DEQ 27 -2021, amend filed 12/16/2021, effective 12/16/2021  
DEQ 17 -2021, amend filed 11/17/2021, effective 11/17/2021  
DEQ 16 -2021, amend filed 10/04/2021, effective 10/04/2021  
DEQ 14 -2020, amend filed 05/07/2020, effective 05/07/2020  
DEQ 199 -2018, amend filed 11/16/2018, effective 01/01/2019  
DEQ 197 -2018, amend filed 11/16/2018, effective 11/16/2018  
DEQ 13 -2015, f. 12-10- 15, cert. ef. 1-1-16 
DEQ 1 -2014, f. & cert. ef. 1-6-14 
DEQ 2 -2011, f. 3-10-11, cert. ef. 3- 15-11 
DEQ 6 -2006, f. & cert. ef. 6-29-06 
DEQ 4 -2006, f. 3-29-06, cert. ef. 3- 31-06 
Renumbered from 340- 012-0050, DEQ 4-2005, f. 5-13-05, cert. ef. 6-1- 05 
DEQ 6 -2001, f. 6-18-01, cert. ef. 7-1-01 
DEQ 19 -1998, f. & cert. ef. 10-12- 98 
DEQ 22 -1996, f. & cert. ef. 10-22- 96 
DEQ 21 -1994, f. & cert. ef. 10-14- 94 
DEQ 13 -1994, f. & cert. ef. 5-19-94 
DEQ 4 -1994, f. & cert. ef. 3-14-94 
DEQ 20 -1993(Temp), f. & cert. ef. 11 -4-93 
DEQ 19 -1993, f. & cert. ef. 11-4-93 
DEQ 21 -1992, f. & cert. ef. 8-11-92 
DEQ 2 -1992, f. & cert. ef. 1-30-92 
DEQ 31 -1990, f. & cert. ef. 8-15-90 
DEQ 15 -1990, f. & cert. ef. 3-30-90 
DEQ 4 -1989, f. & cert. ef. 3-14-89 
DEQ 22 -1988, f. & cert. ef. 9-14-88 
DEQ 22 -1984, f. & ef. 11-8-84 
DEQ 5 -1980, f. & ef. 1-28-80 
DEQ 78, f. 9-6-74, ef. 9-25-74 
 70 
 340-012-0135  
 
Selected Magnitude Categories  
 (1) Magnitudes for selected Air Quality violations will be determined as follows:  
 (a) Opacity limit violations:  
 (A) Major — Opacity measurements or readings of 20 percent opacity or more over the 
applicable limit, or an opacity violation by a federal major source as defined in OAR 340 -
200-0020;  
(B) Moderate — Opacity measurements or readings greater than 10 percent opacity and less than 20 percent opacity over the applicable limit; or  
 (C) Minor — Opacity measurements or readings of 10 percent opacity or less over the 
applicable limit.  
 (b) Operating a major source, as defined in OAR 340 -200-0020, without first obtaining the 
required permit: Major — if a Lowest Achievable Emission Rate (LAER) or Best Available 
Control Technology (BACT) analysis shows that additional controls or offsets are or were needed, otherwise apply OAR 340- 012-0130. 
 (c) Exceeding an emission limit established under New Source Review/Prevention of Significant Deterioration (NSR/PSD): Major — if exceeded the emission limit by more than 
50 percent of the limit, otherwise apply OAR 340 -012-0130.  
 
(d) Exceeding an emission lim it established under federal National Emission Standards for 
Hazardous Air Pollutants (NESHAPs): Major — if exceeded the Maximum Achievable 
Control Technology (MACT) standard emission limit for a directly -measured hazardous air 
pollutant (HAP), otherwise a pply OAR 340- 012-0130. 
 (e) Exceeding a cancer or noncancer risk limit that is equivalent to a Risk Action Level or a Source Risk Limit if the limit is a Risk Action Level established under OAR 340 -245-0005 
through 340 -245-8050: Major, otherwise apply OAR 340-012-0130. 
 (f) Air contaminant emission limit violations for selected air pollutants: Magnitude determinations under this subsection will be made based upon significant emission rate (SER) amounts listed in OAR 340 -200-0020. 
 (A) Major:  
 (i) Exceeding the annual emission limit as established by permit, rule or order by more than 
the annual SER; or  
 
(ii) Exceeding the short -term (less than one year) emission limit as established by permit, 
rule or order by more than the applicable short -term SER.  71 
  
(B) Mo derate:  
 
(i) Exceeding the annual emission limit as established by permit, rule or order by an amount 
from 50 up to and including 100 percent of the annual SER; or  
 
(ii) Exceeding the short -term (less than one- year) emission limit as established by permit,  
rule or order by an amount from 50 up to and including 100 percent of the applicable short -
term SER.  
 
(C) Minor:  
(i) Exceeding the annual emission limit as established by permit, rule or order by an amount less than 50 percent of the annual SER; or  
 
(ii) Exceeding the short -term (less than one year) emission limit as established by permit, 
rule or order by an amount less than 50 percent of the applicable short -term SER.  
 
(g) Violations of Emergency Action Plans: Major — Major magnitude in all cases.  
 
(h) Violations of on road motor vehicle refinishing rules contained in OAR 340- 242-0620: 
Minor — Refinishing 10 or fewer on road motor vehicles per year.  
 (i) Asbestos violations — These selected magnitudes apply unless the violation does not 
cause the pot ential for human exposure to asbestos fibers:  
 
(A) Major — More than 260 linear feet or more than 160 square feet of asbestos -containing 
material or asbestos -containing waste material;  
 
(B) Moderate — From 40 linear feet up to and including 260 linear feet  or from 80 square 
feet up to and including 160 square feet of asbestos -containing material or asbestos -
containing waste material; or  
 
(C) Minor — Less than 40 linear feet or 80 square feet of asbestos -containing material or 
asbestos -containing waste mater ial. 
 
(D) The magnitude of the asbestos violation may be increased by one level if the material 
was comprised of more than five percent asbestos.  
 (j) Open burning violations:  
 
(A) Major — Initiating or allowing the initiation of open burning of 20 or more  cubic yards 
of commercial, construction, demolition and/or industrial waste; or 5 or more cubic yards of 
prohibited materials (inclusive of tires); or 10 or more tires;  
 
(B) Moderate — Initiating or allowing the initiation of open burning of 10 or more, but less 
than 20 cubic yards of commercial, construction, demolition and/or industrial waste; or 2 or 72 
 more, but less than 5 cubic yards of prohibited materials (inclusive of tires); or 3 to 9 tires; 
or if DEQ lacks sufficient information upon which to make a determination of the type of waste, number of cubic yards or number of tires burned; or  (C) Minor — Initiating or allowing the initiation of open burning of less than 10 cubic yards 
of commercial, construction, demolition and/or industrial waste; or les s than 2 cubic yards of 
prohibited materials (inclusive of tires); or 2 or less tires.  
 (D) The selected magnitude may be increased one level if DEQ finds that one or more of the following are true, or decreased one level if DEQ finds that none of the following are true:  (i) The burning took place in an open burning control area;  (ii) The burning took place in an area where open burning is prohibited;  (iii) The burning took place in a non-attainment or maintenance area for PM10 or PM2.5; or  (iv) The burning took place on a day when all open burning was prohibited due to meteorological conditions.  
 (k) Oregon Low Emission Vehicle Non- Methane Gas (NMOG) or Green House Gas (GHG) 
fleet average emission limit violations:  
 (A) Major — Exceeding the limit by  more than 10 percent; or  
 
(B) Moderate — Exceeding the limit by 10 percent or less. 
 (l) Oregon Clean Fuels Program violations:  
 (A) Violating the clean fuel standards set forth in OAR 340 -253-0100(6) and Tables 1 and 2 
of OAR 340 -253- 8010: Major  
 (B) Failing to register under OAR 340-253-0100(1) and (4): Major;  (C) Failing to timely submit a complete and accurate annual compliance report or quarterly report under OAR chapter 340, division 253: Major;  (D) Generating an illegitimate credit under OAR chapt er 340, division 253: Major; 
 (E) Committing any action related to a credit transfer that is prohibited under OAR 340 -253-
1005(8): Major.  
(m) Failing to timely submit a complete and accurate emissions data report under the Oregon Greenhouse Gas Reporting Program, OAR chapter 340, division 215, where the untimely, incomplete or inaccurate reporting impacts applicability , distribution of 73 
 compliance instruments,  or any compliance obligation under the Climate Protection 
Program, OAR chapter 340, division 271: Major. 
 
(n) Oregon Climate Protection Program violations:  
 (A) Failing to demonstrate compliance according to OAR 340 -271-0450: Major. 
 (B) Failing to comply with a BAER order issued under OAR 340-271-0320: Major  (C) Failing to comply with a condition in a permit, Climate Protection Program permit, or Climate Protection Program permit addendum issued according to OAR 340-271-0150 that requires the reduction of greenhouse gas emissions: Major.  
(D) Failing to obtain a BAER order under OAR 340-271-0320 or a permit issued under OAR 340 -271-0150(3)(c), for a covered entity, as identified in OAR 340-271-0110, that is a 
new source, as defined in OAR 340-271-0020: Major.  (2) Magnitudes for selected Water Quality violations will be determined as follow s: 
 (a) Violating wastewater discharge permit effluent limitations:  
 (A) Major:  
 (i) The dilution (D) of the spill or technology based effluent limitation exceedance was less than two, when calculated as follows: D = ((QR /4) + QI)/ QI, where QR is the estimated receiving stream flow and QI is the estimated quantity or discharge rate of the incident; 
 
(ii) The receiving stream flow at the time of the water quality based effluent limitation (WQBEL) exceedance was at or below the flow used to calculate the WQ BEL; or  
 (iii) The resulting water quality from the spill or discharge was as follows:  
 (I) For discharges of toxic pollutants: CS/D was more than CAcute, where CS is the concentration of the discharge, D is the dilution of the discharge as determined unde r 
(2)(a)(A)(i), and CAcute is the concentration for acute toxicity (as defined by the applicable water quality standard);  
 (II) For spills or discharges affecting temperature, when the discharge temperature is at or above 32 degrees centigrade after two se conds from the outfall; or  
 (III) For BOD5 discharges: (BOD5)/D is more than 10, where BOD5 is the concentration of the five-day Biochemical Oxygen Demand of the discharge and D is the dilution of the discharge as determined under (2)(a)(A)(i).  
 (B) Modera te: 
 74 
 (i) The dilution (D) of the spill or the technology based effluent limitation exceedance was 
two or more but less than 10 when calculated as follows: D = ((QR /4)+ QI )/ QI, where QR 
is the estimated receiving stream flow and QI is the estimated quantity or discharge rate of the discharge; or  
 (ii) The receiving stream flow at the time of the WQBEL exceedance was greater than, but 
less than twice, the flow used to calculate the WQBEL.  
 
(C) Minor:  
 (i) The dilution (D) of the spill or the technology based effluent limitation exceedance was 
10 or more when calculated as follows: D = ((QR/4) + QI)/ QI, where QR is the receiving 
stream flow and QI is the quantity or discharge rate of the incident; or  
(ii) The receiving stream flow at the time of the WQBEL exceedance was twice the flow or 
more of the flow used to calculate the WQBEL.  
 
(b) Violating numeric water quality standards:  
 (A) Major:  
 
(i) Increased the concentration of any pollutant except for toxics, dissolved oxygen, pH, and 
turbidity , by 25 percent or more of the standard;  
 
(ii) Decreased the dissolved oxygen concentration by two or more milligrams per liter below 
the standard;  
 
(iii) Increased the toxic pollutant concentration by any amount over the acute standard or by 
100 percent or more of the chronic standard;  
 
(iv) Increased or decreased pH by one or more pH units from the standard; or  
 (v) Increased turbidity by 50 or more nephelometric turbidity units (NTU) over background.  (B) Moderate:  
 
(i) Increased the concentration of any  pollutant except for toxics, pH, and turbidity by more 
than 10 percent but less than 25 percent of the standard;  
 
(ii) Decreased dissolved oxygen concentration by one or more, but less than two, milligrams per liter below the standard;  
 (iii) Increased th e concentration of toxic pollutants by more than 10 percent but less than 
100 percent of the chronic standard;  
 (iv) Increased or decreased pH by more than 0.5 pH unit but less than 1.0 pH unit from the 
standard; or  75 
  
(v) Increased turbidity by more than 20 but less than 50 NTU over background. 
 
(C) Minor:  
 (i) Increased the concentration of any pollutant, except for toxics, pH, and turbidity, by 10 
percent or less of the standard;  
 
(ii) Decreased the dissolved oxygen concentration by less than one mi lligram per liter below 
the standard;  
 
(iii) Increased the concentration of toxic pollutants by 10 percent or less of the chronic 
standard;  
(iv) Increased or decreased pH by 0.5 pH unit or less from the standard; or  
 
(v) Increased turbidity by 20 NTU or le ss over background.  
 
(c) The selected magnitude under (2)(a) or (b) may be increased one or more levels if the violation:  
 
(A) Occurred in a water body that is water quality limited (listed on the most current 303(d) 
list) and the discharge is the same pol lutant for which the water body is listed;  
 
(B) Depressed oxygen levels or increased turbidity and/or sedimentation in a stream in 
which salmonids may be rearing or spawning as indicated by the beneficial use maps 
available at OAR 340- 041-0101 through 0340;  
 
(C) Violated a bacteria standard either in shellfish growing waters or during the period from 
June 1 through September 30; or  
 
(D) Resulted in a documented fish or wildlife kill.  
 (3) Magnitudes for selected Solid Waste violations will be determined as follows:  
 (a) Operating a solid waste disposal facility without a permit or disposing of solid waste at 
an unpermitted site:  
 
(A) Major — The volume of material disposed of exceeds 400 cubic yards;  
 
(B) Moderate — The volume of material disposed of is greater than or equal to 40 cubic 
yards and less than or equal to 400 cubic yards; or  
 
(C) Minor — The volume of materials disposed of is less than 40 cubic yards.  
 
(D) The magnitude of the violation may be raised by one magnitude i f the material disposed 
of was either in the floodplain of waters of the state or within 100 feet of waters of the state.  76 
  
(b) Failing to accurately report the amount of solid waste disposed:  
 
(A) Major — The amount of solid waste is underreported by 15 pe rcent or more of the 
amount received;  
 
(B) Moderate — The amount of solid waste is underreported by 5 percent or more, but less 
than 15 percent, of the amount received; or  
 
(C) Minor — The amount of solid waste is underreported by less than 5 percent of th e 
amount received.  
 
(4) Magnitudes for selected Hazardous Waste violations will be determined as follows:  
(a) Failure to make a hazardous waste determination;  
 
(A) Major — Failure to make the determination on five or more waste streams;  
 
(B) Moderate — Fai lure to make the determination on three or four waste streams; or  
 
(C) Minor — Failure to make the determination on one or two waste streams.  
 
(b) Hazardous Waste treatment, storage and disposal violations of OAR 340 -012-
0068(1)(b), (c), (h), (k), (l), (m), (p), (q) and (r):  
 
(A) Major:  
 
(i) Treatment, storage, or disposal of more than 55 gallons or 330 pounds of hazardous 
waste; or  
 
(ii) Treatment, storage, or disposal of at least one quart or 2.2 pounds of acutely hazardous waste.  
 (B) Moderate:  
 (i) Treatment, storage, or disposal of 55 gallons or 330 pounds or less of hazardous waste; or  
 (ii) Treatment, storage, or disposal of less than one quart or 2.2 pounds of acutely hazardous 
waste.  
 
(c) Hazardous waste management violations classified in OAR 3 40-012-0068(1)(d), (e) (f), 
(g), (i), (j), (n), (s) and (2)(a), (b), (d), (e), (h), (i), (k), (m), (n), (o), (p), (r) and (s):  
 
(A) Major:  
 
(i) Hazardous waste management violations involving more than 1,000 gallons or 6,000 
pounds of hazardous waste; or  77 
  
(ii) Hazardous waste management violations involving at least one quart or 2.2 pounds of 
acutely hazardous waste.  
 
(B) Moderate:  
 
(i) Hazardous waste management violations involving more than 250 gallons or 1,500 
pounds, up to and including 1,000 gallons or 6,000 pounds of hazardous waste; or  
 
(ii) Hazardous waste management violations involving less than one quart or 2.2 pounds of 
acutely hazardous waste.  
 (C) Minor: Hazardous waste management violations involving 250 gallons or 1,500 pounds 
or less of hazardous waste and no acutely hazardous waste.  
 
(5) Magnitudes for selected Used Oil violations (OAR 340 -012-0072) will be determined as 
follows:  
 
(a) Used Oil violations set forth in OAR 340 -012-0072(1)(f), (h), (i), (j); and (2)(a) through 
(h): 
 (A) Major — Used oil management violations involving more than 1,000 gallons or 7,000 
pounds of used oil or used oil mixtures;  
 
(B) Moderate — Used oil management violations involving more than 250 gallons or 1,750 
pounds, up to and including 1,000 gallons or 7,000 pounds of used oil or used oil mixture; or  
 
(C) Minor — Used oil management violations involving 250 gallons or 1,750 pounds or less 
of used oil or used oil mixtures.  
 
(b) Used Oil spill or disposal violations set forth in OAR 340 -012-0072(1)(a) through (e), 
(g) and (k).  
 (A) Major — A spill or disposal involving more than 420 gallons or 2,940 pounds of used 
oil or used oil mixtures;  
 (B) Moderate — A spill or disposal involving more than 42 gallons or 294 pounds, up to and 
including 420 gallons or 2,940 pounds of used oil or used oil mixtures; or  
 
(C) Minor — A spill or disposal of used oil involving 42 gallons or 294 pounds or less of 
used oil or used oil mixtures.  
 
[NOTE: Tables & Publications referenced are available from the agency.]  
Statutory/Oth er Authority:  ORS 468.065 & 468A.045 
Statutes/Other Implemented: ORS 468.090 -  468.140 & 468A.060 
History:  78 
 DEQ 16 -2022, amend filed 09/23/2022, effective 09/23/2022  
DEQ 27 -2021, amend filed 12/16/2021, effective 12/16/2021  
DEQ 14 -2020, amend filed 05/07/2020, effective 05/07/2020  
DEQ 199 -2018, amend filed 11/16/2018, effective 01/01/2019  
DEQ 197 -2018, amend filed 11/16/2018, effective 11/16/2018  
DEQ 13 -2015, f. 12-10- 15, cert. ef. 1-1-16 
DEQ 1 -2014, f. & cert. ef. 1-6-14 
DEQ 6 -2006, f. & cert. ef. 6-29-06 
DEQ 4 -2006, f. 3-29-06, cert. ef. 3- 31-06 
Renumbered from 340- 012-0090, DEQ 4-2005, f. 5-13-05, cert. ef. 6-1- 05 
DEQ 1 -2003, f. & cert. ef. 1-31-03 
DEQ 19 -1998, f. & cert. ef. 10-12- 98 
DEQ 4 -1994, f. & cert. ef. 3-14-94 
DEQ 21 -1992, f. & cert. ef. 8-11-92 
 
  79 
 Greenhouse Gas Reporting Program, Division 215 
 
340-215-0020  
Definitions  
The definitions in OAR 340-200-0020 and this rule apply to this division. If the same term is 
defined in this rule and OAR 340-200- 0020, the definition in this rule applies to this 
division. 
(1) “Air contamination source” has the meaning given the term in ORS 468A.005. 
(2) “Asset -controlling supplier” or “ACS” means a person that owns or operates inter-
connected electricity generating facilities or has exclusive rights to claim electricity from these facilities even though it does not own them, and that has been designated by DEQ as an asset -controlling supplier under OAR 340-215-0120(7) and received a DEQ-published 
emission factor. Asset controlling suppliers are specified sources.  
(3) “Barrel” means a volume equal to 42 U.S. gallons. 
(43) “Biogas” means gas that is produced from the breakdown of biomass in the absence of 
oxygen, including anaerobic digestion, anaerobic decomposition, and thermochemical decomposition. 
(5
4) “Biogenic CO2 emissions” means carbon dioxide emissions generated as the result of 
biomass or biomass -derived fuel combustion or oxidation. 
(65) “Biomass” means non -fossilized and biodegradable organic material originating from 
plants, animals, and micro-organisms, including products, byproducts, residues, and waste 
from agriculture, forestry, and related industries, as well as the non -fossilized and 
biodegradable organic fractions of industrial and municipal wastes, including gases and liquids recovered from the decompo sition of non-fossilized and biodegradable organic 
matter.  
(7
6) “Biomass fuels” or “biofuels” or “biomass- derived fuels” means fuels derived from 
biomass.  
(87) “Biomethane” or “Renewable Natural Gas” means refined biogas, or another synthetic 
stream of methane  produced  from biomass feedstock renewable resources, that has been 
upgraded to meet pipeline quality stand ards or transportation fuel grade requirements, such 
that it may blend with, or substitute for, natural gas. a near -pure methane content product. 
Biomethane can be directly injected into natural gas pipelines or combusted in natural gas-
fueled vehicles.  
(8) “Book and Claim” refers to  the accounting methodology where the environmental 
attributes of an energy source are detached from the physical molecules when they are 
commingled into a common transportation and distribution system for that form of energy. 80 
 The detached attributes are t hen assigned by the owner to the same form and amount of 
energy when it is used. For the purposes of this division, the common transportation and 
distribution system must be connected to Oregon. 
(9) “Bulk transfer/terminal system” means a fuel distribution  system consisting of one or 
more of refineries, pipelines, vessels, and terminals. Fuel storage and blending facilities that 
are not fed by pipeline or vessel are considered outside the bulk transfer system. 
(10) “Busbar” means a power conduit of a facili ty with electricity generating units that 
serves as the starting point for the electricity transmission system.  
(11) “Carbon dioxide supplier” means a facility with production process units or production 
wells that capture, extract, or produce CO₂ for on-s ite use, commercial application, or for 
purposes of supplying CO₂ to another entity or facility, or that capture the CO₂ stream in 
order to utilize it for geologic sequestration, where capture refers to the initial separation and 
removal of CO₂ from a manufacturing process or any other process. The definition does not 
include transportation , distribution , purification, compression, or processing of CO2. 
(1112) “Cease to operate” for the purposes of this division means the air contamination 
source regulated entity did not operate any GHG –emitting processes for an entire year. 
Continued operation of space heaters and water heaters as necessary until operations are 
restarted in a subsequent year does not preclude a source from meeting this definition.  
(1213) “C.F.R.” means Code of Federal Regulations  and unless otherwise expressly 
identified refers to the December 9, 2016 edition. 
(1314) “Cogeneration unit” means a unit that produces electric energy and useful thermal 
energy for industrial, commercial, or heating and cooling purposes, through the sequential or simultaneous use of the original fuel energy and waste heat recovery.  
(1
5) “Compressed natural gas” or “CNG” means natural gas stored inside a pressure vessel 
at a pressure greater than the ambient atmospheric pressure outside of the vessel , (though not 
to the point of liquefaction), typically to pressures ranging from 2900 to 3600 pounds per 
square inch . 
(1416) “Consumer -owned utility” means a people’s utility district organized under ORS 
Chapter 261, a municipal utility organized under ORS Chapter 225 or an electric cooperative organized under ORS Chapter 62. 
(15
17) “Data year” means the calendar year in wh ich emissions occurred. 
(1618) “Designated representative” means the person responsible for certifying, signing, and 
submitting a greenhouse gas emissions data report, and any registration or report required to 
be submitted under this division, on behalf of a regulated entity. For owners or operators of Oregon Title V Operating Permits the designated representative is the responsible official and certification must be consistent with OAR 340-218-0040(5). 81 
 (1719) “Direct emissions” means emissions fro m an air contamination stationary  source, 
including but not limited to fuel combustion activities, process related emissions, and 
fugitive emissions. 
(18) “Distillate fuel oil” means one of the petroleum fractions produced in conventional 
distillation opera tions and from crackers and hydrotreating process units. The generic term 
distillate fuel oil includes kerosene, kerosene -type jet fuel, diesel fuels (Diesel Fuels No. 1, 
No. 2, and No. 4), and fuel oils (Fuel Oils No. 1, No. 2, and No. 4). 
(1920) “EIA” means the Energy Information Administration. The Energy Information 
Administration (EIA) is a statistical agency of the United States Department of Energy.  
(2021) “Electricity generating unit” means any combination of physically connected 
generator(s), react or(s), boiler(s), combustion turbine(s), or other prime mover(s) operated 
together to produce electric power. (21
22) “Electricity service supplier” has the meaning given that term in ORS 757.600. 
(2223) “Electricity supplier” means persons that import, sell, allocate, or distribute 
electricity to end users in the state, including but not limited to the following types of 
entities:  
(a) Investor-owned utilities; 
(b) Electricity service suppliers; and  
(c) Consumer-owned utilities. 
(2324) “Emissions data report” means the report prepared and submitted to DEQ that 
provides the information required to be reported under this division. The emissions data 
report is for the year prior to the year in which the report is due, also known as the data year.  
(2 5) “Export” means to transport fuel from locations within Oregon to locations  outside of 
the state, by any means of transport, other than in the fuel tank of a vehicle for the purpose 
of propelling the vehicle.   
(2426) “Fuel supplier” means a supplier of petroleum products, liquid petroleum gas, 
biomass- derived fuels, or natural gas including operators of interstate pipelines, or liquefied 
natural gas. 
(2527) “Fluorinated heat transfer fluids” is a fluorinated GHG that has the meaning given to 
that term in 40 C.F.R. 98.98. 
(28) “Environmental Attribute ,” for the purposes of reporting biogas, biomethane, and 
hydrogen under this division , means the formal recognition of the biomass -derived attributes 
or that  the use of the fuel results in lower greenhouse gas emissions.  Such formal 82 
 recognition may include verified emission reductions, voluntary emission reductions, 
offsets, allowances, credits, avoided compliance costs, emission rights and authorizations 
under any law or regulation, or any other comparable emission registry, trading system, or 
reporting or reduction program for greenhouse gas emissions that is established, certified, 
maintained, or recognized by any international, governmental, or nongovernmental agency.   
(2629) "Global warming potential” or "GWP" means the ratio of the time -integrated 
radiative forcing from the instantaneous release of one kilogram of a trace substance relative 
to that of one kilogram of carbon dioxide (the reference gas). The GWP s used for emissions 
calculation and reporting are specified in 40 C.F.R. part 98, subpart A, Table A–1- Global 
Warming Potentials  as published in the Code of Federal Reg ulations referenced in this 
division. 
(3027) “Greenhouse gas” or “GHG” means carbon dioxide (CO2), methane (CH4), nitrous 
oxide (N20), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and other fluorinated greenhouse gases or fluorinated GHG as defined in 40 C.F.R. part 98. 
(31) “Gross generation” or “ g
 ross power generated” means the total electrical output of the 
generating facility or unit, expressed in megawatt hours (MWh) per year. 
(2832) “High er heat value” or “HHV” means the high or gross heat content of the fuel with 
the heat of vaporization included. The water vapor is assumed to be in a liquid state. 
(2933) “Hydrofluorocarbons” (HFCs) means gaseous chemical compounds containing only 
hydrogen, carbon, and fluorine atoms. 
(34) “Hydrogen” means diatomic molecular hydrogen. 
(3035) To “Import” means owning electricity or fuel from locations outside of Oregon at the 
time electricity is brought into this state through transmission equipment or at the time fuel 
is brought into this state by any means of transport, other than fuel brought into this state in the fuel tank of a vehicle used to propel the vehicle. 
(31
36) “Importer” means : 
(a) Aany person, company, or organization of record that for any reason brings a product 
into Oregon from outside of the state ; or 
(b) With respect to any biomethane, the person who owns the biomethane when it is either 
physically transported into Oregon or when it is  contractually delivered for use in Oregon 
through a book and claim accounting methodology.. 
(3237) “In -state producer” means:  
(a) With respect to any liquid fuel, the person who makes the fuel in Oregon; or 83 
 (b) With respect to any gaseous biomass- derived fuelbiomethane , the person who refines, 
treats, or otherwise processes biogas into biomethane produces the fuel  in Oregon; or 
(c) With re spect to any natural gas, the person who owns or operates one or more wells 
producing natural gas in Oregon.. 
(3338) “Interstate pipeline” means a natural gas pipeline delivering natural gas across state 
boundaries for use in Oregon and that is subject to rate regulation by the Federal Energy 
Regulatory Commission (FERC).  
(3439) “Investor -owned utility” means a utility that sells electricity and that a corporation 
with shareholders operates.  
(3540) “Large natural gas end users” means any end user receiving greater than or equal to 
460,000 Mscf during the previous year. 
(4 1) “Liquefied natural gas” or “LNG” means natural gas that is  liquefied.  
(4236) “Local distribution company” or “LDC” means a legal entity that owns or operates 
distribution pipelines and that physically delivers natural gas to end users in the state. This 
includes public utility gas corporations and intrastate pipelines engaged in the retail sale, delivery, or both of natural gas. This excludes interstate pipelines. 
(37
43) “Multi -jurisdictional utility” means a utility that is an electricity retail provider to 
customers in a service territory that is at least partially located in Oregon and at least one 
other state.  
(3844) “Metric ton,” “tonne,” “metric tonne,” or “MT” means a common international 
measurement for mass, equivalent to 2204.6 pounds or 1.1 short tons. 
(3945) “MMBtu” means million British thermal units.  
(4046) “Mscf” means one thousand standard cubic feet.  
(47) “Natural gas”  means a naturally occurring mixture derived from anthropogenic or fossil 
sources of gaseous hydrocarbons and other compounds consisting primarily of methane. For 
the purposes of this division the term includes natural gas in all gaseous and liquid forms. 
(4148) “Natural gas marketer” means a person that arranges for the purchasing or selling of 
natural gas but that does not own physical assets in Oregon used in the supply of natural gas 
such as pipelines.  
(4249) “Natural gas supplier” means any person that imports, sells, produces, or distributes 
natural gas to end users in Oregon. 84 
 (50) “Net generation” or “net power generated” means the gross generation minus station 
service or unit service power requirements, expressed in megawatt hours (MWh) per year. In 
the case of cogeneration, this value is intended to include internal consumption of electricity 
for the purposes of a production process, as well as power put on the grid. 
(4351) “Perfluorocarbons” (PFCs) mean s gaseous chemical compounds containing only 
carbon and fluorine atoms. 
(4452) “Position holder” means any person that has an ownership interest in a specific 
amount of fuel in the inventory of a terminal as reflected in the records of the terminal 
operator  or a terminal operator that owns fuel in its terminal. This does not include inventory 
held outside of a terminal, retail establishments, or other fuel suppliers not holding inventory 
at a fuel terminal.  
(4553) “Power contract” as used for the purposes of documenting specified versus 
unspecified sources of electricity means a written document, including associated verbal or electronic records if included as part of the written power contract, arranging for the procurement of electricity. A power contract for a specified source is a contract that is contingent upon delivery of power from a particular facility, unit, or asset-controlling supplier’s system that is designated at the time the transaction is executed. Power contracts may be, but are not limited to, power purchase agreements, enabling agreements, electricity transactions, and tariff provisions, without regard to duration, or written agreements to import or export on behalf of another person. 
(46
54) “Pre -charged equipment” has the meaning  in 40 C.F.R. 98.438. 
(4755) “Preference sales” means power distributed by Bonneville Power Administration to 
Oregon consumer-owned utilities, other than “surplus” power as that term is defined in 16 
U.S.C. 839c(f) (2017).  
(4856) “Rack” means a mechanism f or delivering fuel from a refinery or terminal into a 
truck, trailer, railroad car, or other means of non- bulk transfer.  
(4957) “Regulated entity” means any person subject to requirements to register and report 
under this division, as identified in OAR 340-215-0030. 
(5058) “Related entity” means any direct or indirect parent company, direct or indirect 
subsidiary, or company that shares ownership of a direct or indirect subsidiary, or company 
under  full or partial common ownership or control. 
(5159) “Retail  sales” means electricity sold to retail end users.  
(5260) “Shut down” means that the regulated entity has evidence that all industrial 
operations of a regulated entity are permanently shut down, including but not limited to, 
decommissioning and cancelling air permits. Permanent shutdown may include continued 85 
 operations of space heaters and water heaters as necessary to support decommissioning 
activities.  
(5361) “Specified source of electricity” or “specified source” means a facility or unit which 
is allowed to be claimed as the source of electricity delivered. The regulated entity must have either full or partial ownership in the facility or unit, or a written power contract to procure electricity generated by that facility or unit. Specified facilities or units include cogeneration systems. Specified source also means electricity procured from an asset -
controlling supplier recognized by DEQ. 
(54
62) “Terminal” means a fuel storage and distribution facility that is supplied by pipeline 
or vessel, or a facility is  collocated where the fuel is produced and stored, and from which 
fuel may be removed at a rack.  In-state fuel production facilities that have distribution 
equipment that allow them to distribute directly to retail sites or end users meet the 
definition of a terminal.  
(5563) “Thermal energy” means the thermal output produced by a combustion source used 
directly as part of a manufacturing process, industrial or commercial process, or heating or 
cooling application, but not used to produce electricity. 
(5664) “Transmission loss correction factor” or “TL” means the correction to account for 
transmission losses between the busbar and receipt, which is either known if measured at the 
busbar, or is the default factor equal to 1.02. 
(5765) “Unspecified source of electricity” or “unspecified source” means a source of 
electricity that is not a specified source at the time of entry into the transaction to procure the 
electricity. For the purposes of this division, electricity imported, sold, allocated, or distributed to end users in this state through an energy imbalance market or other centralized market administered by a market operator is considered to be an unspecified source. 
(58
66) “Verification” means a systematic and documented process for evaluation o f an 
emissions data report as conducted by DEQ or in accordance with OAR chapter 340, 
division 272. 
(5967) “Year” means calendar year.  
Statutory/Other Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, amend filed 05/07/2020, effective 05/07/2020
 
DEQ 5 -2019, amend filed 01/24/2019, effective 01/24/2019  
DEQ 124 -2018, minor correction filed 04/11/2018, effective 04/11/2018  
DEQ 12 -2015, f. & cert. ef. 12-10- 15 
DEQ 11 -2011, f. & cert. ef. 7-21-11 
DEQ 12 -2010, f. & cert. ef. 10-27- 10 
DEQ 13 -2008, f. & cert. ef. 10-31- 08 86 
  
340-215-0030  
Applicability  
(1) This division applies to all persons identified in sections (2) through (6) of this rule, 
except as provided in OAR 340-215-0032 and 340-215-0034. 
(2) Air contamination Stationary  sour ces and e lectric power system facilities . Any person 
that owns or operates a source listed in subsections (a) through (c) must register and report in compliance with this division, if the source’s direct GHG emissions meet or exceed 2,500 MT CO2e during th e previous year. Once a source’s direct GHG emissions meet or exceed 
2,500 MT CO2e during a year, the person that owns or operates the source must annually register and report in each subsequent year, regardless of the amount of the source’s direct GHG emi ssions in future years, except as provided in OAR 340-215-0032 and OAR 340-
215-0034. 
(a) Any source required to obtain a Title V Operating Permit.  
(b) Any source required to obtain an Air Contaminant Discharge Permit. 
(c) The following sources not otherwise listed in subsection (a) or (b):  
(A) Solid waste disposal facilities required to obtain a permit issued under OAR chapter 
340, divisions 93 through 96, excluding facilities that meet all of the following conditions: 
(i) both D did not accept waste during the previous year ; and  
(ii) A are not required to report greenhouse gas emissions to EPA under 40 C.F.R. part 98;  
and 
(iii) Are not required to report methane generation rates under OAR chapter 340, division 
239. 
(B) Wastewater treatment facil ities required to obtain an individual National Pollutant 
Discharge Elimination System permit issued under OAR chapter 340, division 45; and 
(C) Electric power system facilities as defined in 40 C.F.R. part 98 subpart DD located in 
Oregon and owned or operated by investor-owned utilities. 
(3) Fuel suppliers and in -state producers.  
(a) Except as provided in subsection (b), the following persons that import, sell, or distribute 
fuel for use in the state, must register and report in compliance with this division:  
(A) Any dealer, as that term is defined in ORS 319.010 that is subject to the Oregon Motor Vehicle and Aircraft Fuel Dealer License Tax under OAR chapter 735, division 170; 87 
 (B) Any seller, as that term is defined in ORS 319.520, that is subject to the Oregon Use 
Fuel Tax under OAR chapter 735, division 176; 
(C) Any person that produces, imports, sells, or distributes at least 5,500 gallons of gasoline, 
distillate fuel oil, biofuels, or aircraft fuel during a year for use in the state and that is not subject to the Oregon Motor Vehicle and Aircraft Fuel Dealer License Tax or the Oregon Use Fuel Tax under OAR chapter 735, divisions 170 and 176; and 
(D) Any person that imports propane for use in the state if the person’s total imports brought 
into the state  are equal to or more than 10,500 gallons of propane in a year. 
(b) Persons listed in paragraphs (3)(a)(B) and (C) are not required to register and report fuel that is separately reported under this division by dealers described in paragraph (3)(a)(A). 
(4) Natural gas suppliers. Any person, including but not limited to local distribution companies, interstate pipelines, and owners or operators of facilities, that either produce s 
natural gas, compressed natural gas, or liquefied natural gas in Oregon, or tha t imports , sell s, 
or distribute s natural gas, compressed natural gas, or liquefied natural gas to end users in the 
state, must register and report in compliance with this division.  
(5) Electricity suppliers. All investor -owned utilities, multi- jurisdictional utilities, electricity 
service suppliers, consumer -owned utilities, and other persons that import, sell, allocate, or 
distribute electricity to end users in the state must register and report in compliance with this division. 
(6) Petroleum and natural g as systems. Any person that owns or operates a facility 
physically located in Oregon that contains petroleum and natural gas systems industry 
segments listed in 40 C.F.R. 98.230(a)(1) through (10) must register and report in compliance with this division, as applicable under subsections (a) though (e):  
(a) For a facility, as defined in 40 C.F.R. 98.6 that contains the industry segments listed in 40 C.F.R. 98.230(1), (3), (4), (5), (6) or (7), if the facility’s greenhouse gas emissions meet or exceed 2,500 MT CO2e per year .; 
(b) For a facility with respect to onshore petroleum and natural gas production as defined in 40 C.F.R. 98.238, if emission sources specified in 40 C.F.R. 98.232(c) meet or exceed 2,500 MT CO2e per year .; 
(c) For a facility with respect to natural gas distribution as defined in 40 C.F.R. 98.238, if 
emission sources specified in 40 C.F.R. 98.232(i) meet or exceed 2,500 MT CO2e per year .; 
(d) For a facility with respect to onshore petroleum and natural gas gathering and boosting as defined in 40 C.F.R. 98.238, if emission sources specified in 40 C.F.R. 98.232(j) meet or exceed 2,500 MT CO2e per year .; 88 
 (e) For a facility with respect to the onshore natural gas transmission pipeline segment as 
defined in 40 C.F.R. 98.238, if emission sources specified in 40 C.F.R. 98.232(m) meet or exceed 2,500 MT CO2e per year. 
Statutory/Other Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, amend filed 05/07/2020, effective 05/07/2020
 
DEQ 5 -2019, amend filed 01/24/2019, effective 01/24/2019  
DEQ 12 -2015, f. & cert. ef. 12-10- 15 
DEQ 11 -2011, f. & cert. ef. 7-21-11 
DEQ 12 -2010, f. & cert. ef. 10-27- 10 
DEQ 13 -2008, f. & cert. ef. 10-31- 08 
 
340-215-0034  
Changes in Ownership and Cessation of Reporting Requirements  
(1) Cessation of reporting for reduced emissions.  
(a) A regulated entity is no longer required to report if the regulated entity retains records as required in subsection (b), makes the report required in subsection (c), and if any of the following are applicable:  
(A) Direct total reported emissions for air contamination stationary  sources required to 
register and report under OAR 340-215-0030(2) are less than 2,500 MT CO2e per year for a consecutive three year period. If total reported emis sions for a n air contamination stationary  
source meets or exceeds 2,500 MT CO2e in any year after the reporting cessation requirements have been met, persons that own or operate the air contamination stationary  
source must resume reporting as required under this division;  
(B) Fuel suppliers, including natural gas suppliers, and in- state producers that cease to 
supply fuel in Oregon after submitting an emissions data report for the year in which they ceased to supply fuel in Oregon, provided that: 
(i) Fuel suppliers and in -state producers that cease to have a reporting obligation due to a 
change in ownership or that cease to do business in Oregon sale or relinquishment of a 
permanent inventory position at a terminal must continue to report emissions from the 
reportable fuel transactions that occurred prior up to the date of to the change in ownership 
or up to the date the business ceases to operate in the stateand within the calendar year  prior 
to the change ; and 
(ii) If a fuel supplier or in -state producer supplies fuel in Oregon in any year after the 
reporting cessation requirements have been met, the fuel supplier must resume reporting as required under this division; 89 
 (C) Electricity suppliers that cease to supply electricity in Oregon, after submitting an 
emissions data report for the year in which they ceased to supply electricity in Oregon. If an electricity supplier provides electricity in Oregon in any year after the reporting cessation requirements have been met, the electricity supplier must  resume reporting as required under 
this division.  
(b) Persons that cease reporting under this section and are no longer subject to reporting under this division must retain the records required under OAR 340-215-0042 for a period of five years following t he last year that they were subject to reporting, including all 
production information, fuel use records, emission calculations and other records used to document greenhouse gas emissions. Persons meeting cessation requirements specified in paragraph (1)(a )(A) must retain records for each of the three consecutive years that the 
person does not meet or exceed the emission threshold for a period of five years following the last year they met the cessation requirements; and  
(c) Persons that meet the applicable  cessation of reporting requirements of this section must 
notify DEQ in writing of their reason(s) for ceasing to report no later than the applicable reporting deadline for the year.  
(2) Cessation of reporting for when a stationary source is permanently  shut down air 
contamination sources . If the operations of a n air contamination stationary  source are 
changed such that all applicable greenhouse gas emitting processes and operations permanently  cease to operate or are shut down, then: 
(a) The person that owns or operates the air contamination stationary  source must submit an 
emissions data report for the year in which the source’s greenhouse gas emitting processes and operations ceased to operate;  
(b) The person that owns or operates the air contamination st
 ationary source must submit a 
written notification to DEQ that announces the cessation of reporting and certifies to the cessation of all greenhouse gas emitting processes and operations no later than the reporting deadline of the year following the cessation of o perations or permanent shutdown; and 
(c) This section does not apply to seasonal operational cessations, other temporary cessation of operations, or solid waste disposal facilities that are required to report under 40 C.F.R. part 98. 
(3) Changes in ownership or operational control. If a regulated entity undergoes a change of 
ownership or operational control, the following requirements apply regarding reporting and providing notice to DEQ: 
(a) The new person that owns or operates the regulated entity must notify DEQ in writing of the ownership or operational control change  within 30 calendar days of the ownership or 
operation control change , including providing the following information:  
(A) T the name of the previous owner or operator;  90 
 (B) T the name of the new owner or operator;  
(C) The date of ownership or operator change ;, 
(D) and The  name of a new designated representative ;. 
(E) The name of persons managing data and records required to be reported by this division; 
and 
(F) Any changes to information repo rted in compliance with OAR 340 -215-0040(6).  
(b) Reporting responsibilities. Except as specified in paragraph (B) below and OAR 340-
215-0034(1)(a)(B)(i), t The person that owns or operates the regulated entity at the time of a 
reporting deadline specified in this division has the responsibility for complying with the 
requirements of this division, and: 
(A) Except as specified in  OAR 340 -215-0034(3)(b)  paragraph (B), I if an ownership change 
takes place during the year, reported data must not be spl it or subdivided for the year, based 
on ownership. A single annual emissions data report must be submitted by the person that 
owns or operates the regulated entity at the time of the applicable reporting deadline current 
owner or operator ; and 
(B) If an ownership change to a fuel supplier or in -state producer takes place during the 
year, reported data may be subdivided for the year in compliance with OAR 340-215-
0034(1)(a)(B)(i) provided that the pe rson that owns or operates the regulated entity at the 
time of the applicable reporting deadline  ensures that all the requirements of this division are 
met by the prior owner or operator.   
(B) Fuel suppliers that cease to have emissions subject to reporting under this division as a 
result of an ownership change that affects supplier operations retain the responsibility for 
complying with the requirements of this division.  
(4) Any person specified in OAR 340-215-0030 that has ceased reporting under this rule 
must resume reporting for any future year during which any of the greenhouse gas emitting 
processes or operations resume operation and are subject to reporting as required by this 
division. 
Statutory/Other Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-215-0040  
Greenhouse Gas Registration and Reporting Requirements 91 
 (1) Each registration or emissions data report submitted by a regulated entity according to 
this division must contain certification by a designated representative of the truth, accuracy, and completeness of the submission. This certification and any other certific ation required 
under this division must state that, based on information and belief formed after reasonable inquiry, the statements and information in the document are true, accurate, and complete. The certification must contain the following statement: “B ased on information and belief 
formed after reasonable inquiry, I certify under penalty of perjury that the statements and information submitted are true, accurate and complete.”  
(2) DEQ may require a regulated entity to submit or make available additional  information if 
the materials submitted with the emissions data report are not sufficient to determine or verify greenhouse gas emissions and related information. Regulated entities must provide within 14 calendar days of notification, unless a different s chedule is approved by DEQ, any 
and all information that DEQ requires for the purposes of assessing applicability, verifying or investigating either or both actual and suspected sources of greenhouse gas emissions, and to ascertain compliance and noncompli ance with rules in this division.  
(3) Calculating total greenhouse gas emissions. Total carbon dioxide equivalent emissions (CO2e) must be calculated as the sum of the CO2, CO2 from biomass -derived fuels, CH4, 
N2O, and each fluorinated GHG required to be r eported in an emissions data report in 
compliance with this division using equation A-1 in 40 C.F.R. 98.2. 
(4) Alternative calculation methods. Regulated entities may petition DEQ to use calculation 
methods other than those specified in this division. Regulated entities must receive written DEQ approval to use alternative calculation methods prior to reporting. 
(5) Third -party verification of emissions data reports. Regulated entities must comply with 
the requirements of OAR chapter 340, division 272 for third -party verification of emissions 
data reports, as applicable.  
(6) Fuel suppliers and in- state producers Regulated entities must report legal names and 
addresses of all related entities subject to this division annually by the reporting deadline 
specif ied in OAR 340-215-0046(1)(c) any Oregon DEQ regulations and, if known, indicate 
which related entity may also be a regulated entity reporting under this division.  
(7) A regulated entity may only use book and claim accounting to report contractual 
deliverie s of biomethane or hydrogen injected into a pipeline when:  
(a) The pipeline is part of the natural gas transmission and distribution network connected to 
Oregon; and 
(b) No person has used or claimed the environmental attributes of such biomethane or 
hydrogen in any other program or jurisdiction with the exception of: 
(A) The federal Renewable Fuel Standard Program, any reporting required under OAR 
chapter 340, division 253, or the program under OAR chapter 340, division 271; or  92 
 (B) With DEQ written approv al, any other program or jurisdiction where DEQ has 
confirmed that the claim on the environmental attributes can be made for the same use and 
volume of biomethane or its derivatives as is being claimed under this division.  
to report  when: 
(a)The pipeline;  and 
(b)No person has used or claimed  of such biomethane or hydrogen 
Statutory/Other Authority: ORS 468A.050 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, amend filed 05/07/2020, effective 05/07/2020
 
DEQ 5 -2019, amend filed 01/24/2019, effective 01/24/2019  
DEQ 125 -2018, minor correction filed 04/11/2018, effective 04/11/2018  
DEQ 12 -2015, f. & cert. ef. 12-10- 15 
DEQ 11 -2011, f. & cert. ef. 7-21-11 
DEQ 12 -2010, f. & cert. ef. 10-27- 10 
DEQ 13 -2008, f. & cert. ef. 10-31- 08 
 
340-215-0042  
Recordkeeping Requirements  
(1) Each regulated entity subjec t to the requirements under OAR chapter 340, division 272 
must retain all records as required by this rule, and any records or other materials maintained under any applicable requirements of 40 C.F.R. part 98, in paper or electronic format, or both, for a period of at least seven years.  
(2) Each regulated entity not subject to the requirements under OAR chapter 340, division 272 must retain all records as required by this rule, and any records or other materials maintained under any applicable requirements of 40 C.F.R. part 98, in paper or electronic format, or both, for a period of at least five years.  
(3) Each regulated entity must retain records sufficient to document and allow for verification of each emissions data report submitted to DEQ and make such information available for verification upon request. This includes, but is not limited to the following: 
(a) A list of all units, operations, processes, and activities for which GHG emission were 
calculated, as applicable;  
(b) The data and information used to calculate emissions for each unit, operation, process, and activity, categorized by fuel or material type. These data include, but are not limited to the following: 93 
 (A) The GHG emissions calculations and methods used;  
(B) Analytical results for the development of site -specific emissions factors;  
(C) The results of any analyses for high heat value, carbon content, and other fuel or 
feedstock parameters conducted or as required under 40 C.F.R. part 98, if applicable; and 
(D) Any facility operating data or process information used for the GHG emission 
calculations;  
(c) Records of supporting documentation required by or used to prepare the emissions data report, including but not limited to underlying monitoring and metering data, invoices of receipts or deliveries, fuel use records, production information, sales transaction data, electricity or fuel transaction data, calibration records, and any other relevant information;  
(d) Any annual emissions data report(s) submitted to DEQ, including any revised emissions data report(s);  
(e) Documentation to support any revision(s) made to any emissions data report(s); 
(f) Records of supporting documentation and calculations for any missing data computations 
according to 40 C.F.R. part 98, or o therwise. Retain a record of the cause of the event and 
the corrective actions taken to restore malfunctioning monitoring equipment; 
(g) The results of all required certification and quality assurance tests of continuous monitoring systems, fuel flow meters, and other instrumentation used to provide data to calculate emissions reported under this division; and 
(h) Maintenance records for all continuous monitoring systems, flow meters, and other instrumentation used to provide data to calculate emissions rep orted under this division; and.  
(i) The GHG data monitoring plan required under OAR 340-215-0042(11).  
(4) Regulated entities reporting biomass -derived fuels  or hydrogen, as required under OAR  
340-215-0044(5), must retain supporting documentation that authenticates the purchase 
quantity and quality of  the hydrogen or  gaseous or liquid biomass- derived fuel between 
parties. This supporting documentation: 
(a) May include, but is not limited to, documentation from each upstream party, invoices, 
b
ills of lading,  shipping reports, balancing reports, storage reports, in-kind nomination 
reports, allocation, contracts confirming the source of fuel supplied in the state, attestations, information on the environmental attributes associated with the sale or use of the f uel, 
renewable thermal credit records, or any combination therein ; and 
(b) When reporting biogas, biomethane, or hydrogen, must include attestations from each 
upstream party collectively demonstrating that no other upstream party can make a claim on 94 
 environmental attributes that are being reported under this division. The quantity of energy 
covered by the environmental attributes must match or exceed the energy of fuel reported 
under this division. 
(5) When reporting direct d elivery of biogas, biomethane, or hydrogen in Oregon regulated 
entities must retain documentation that shows the fuel type and quantity directly delivered 
from the point of origin to the point of use in Oregon. 
(6) When reporting contractual deliveries of biomethane or hydrogen using book and claim 
accounting the regulated entity must retain and make available:  
(a) Records demonstrating the specific quantity of gas claimed was injected into a pipeline 
that is part of the natural gas transmission and distrib ution network connected to Oregon  in 
the current data year and link those environmental attributes to a corresponding quantity of 
gas withdrawn for use in Oregon; 
(b) Records demonstrating the quality of the fuel reported; 
(c) Records documenting the fuel production facility, the facility’s production and 
purification process, facility location and feedstock(s). This may include, but is not limited 
to, documentation of feedstock production and schemata of the production method; 
(d) Records demonstrating the full lifecycle carbon intensity of the reported fuel including 
all records supporting the estimation of the reported carbon intensity value required under 
OAR 340 -215-0044(5)(b)( I); 
(e) If using an electronic tracking system approved by DEQ for book and claim accounting, 
records demonstrating the retirement of all environmental attributes of that fuel that are 
being reported under this division. The quantity of energy covered by the environmental 
attributes must match or exceed the energy of fuel reported under this division; and 
(f) Records demonstrating that the retired or claimed environmental attribute was generated 
from gas injected into the  pipeline within the same reporting data year; and  
(g) Any records used in the reporting of information required under OAR 340-215-0044(5) 
(b) Must be made available to DEQ for verification upon request. 
(57) Each regulated entity that is an in-state producer or fuel supplier, including a natural 
gas supplier, must retain records for exported products . Records must  to demonstrate 
delivery to a final destination outside Oregon , indicate the amount delivered, type of fuel 
delivered, delivery date and identify the state the fuel was delivered to. This may include, 
but is not limited to, product transfer documents, bills of lading, invoices, contracts, meter 
tickets, and rail inventory sheets.. Documentation must be made available for verification 
upon request. 95 
  
(68) Each regulated entity that is an electricity supplier must retain documentation 
supporting claims of specified sources of electricity. Supporting documentation must be 
made available for verification upon request  
(79) Electricity suppliers that sell wholesale electricity must maintain records for each sale 
of specified or unspecified source sales. Documentation must be made available for 
verification upon request. 
(810) Each person designated by DEQ as an asset -controlling supplier must retain 
documentation to confirm that the power sold by the supplier originated from the supplier’s 
fleet of facilities and either that the fleet is under the supplier’s operational control or that the supplier has exclusive rights to market electricity for the fleet or facility. Documentation 
must be made available for verification upon request.  
(911) Regulated entities subject to 40 C.F.R. part 98 federal requirements and any entity 
subject to the requirements under OAR chapter 340, division 272, except electricity 
suppliers, must complete and retain the a written GHG data monitoring plan as required 
bythat meets the requirements of 40 C.F.R. part 98.3(g)(5). The GHG data monitoring plan 
must be made available for verification upon request.  Electricity suppliers subject to OAR 
chapter 340, division 272 must complete and retain a written GHG data monitoring plan 
with the following information: 
(a) Information to allow the verification team to develop a general understanding of entity 
boundari es, operations, and electricity transactions;  
(b) Reference to management policies or practices applicable to reporting under this 
division; 
(c) List of key personnel involved in compiling data and preparing the emissions data report; 
(d) Documentation of training practices and policies applicable to reporting under this 
division for electricity suppliers;  
(e) Query data to determine the quantity of electricity (MWh) reported and query 
description;  
(f) Reference to other independent or internal data management systems and records, 
including written power contracts and associated verbal or electronic records, full or partial 
ownership, invoices, and settlements data used to document whether reported transactions 
are specified or unspecified;  
(g) Description of steps taken and calculations made to aggregate data into reporting 
categories;  96 
 (h) Records of preventive and corrective actions taken to address verifier and DEQ findings 
of past nonconformances and material misstatements;  
(i) Log of emissions data rep ort modifications; and  
(j) A written description of an internal audit program that includes emissions data report 
review and documents ongoing efforts to improve the GHG data management. 
(12) Regulated entities must make all records required to be created  and retained under this 
division, including all required documentation described in this division, available for 
review and verification upon written request by DEQ within 14 calendar days of 
notification, unless a different schedule is approved by DEQ. 
 
Statutory/Other Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-215-0044  
Emissions Data Reports  
(1) Regulated entities must monitor emissions and submit emissions data reports to DEQ following the requirements specified in this division. Individual emissions data reports are identified as follows:  
(a) An individual emissions data report must be submitted by  and for  each air contamination 
source stationary sour ce and electric power system facili ty required to register and report 
under OAR 340-215-0030(2)  for each individual permitted source or facility identified 
under that section ; 
(b) An individual emissions data report including emissions from all electric power system facilities located in Oregon must be submitted by an investor-owned utility required to register and report under OAR 340-215-0030(2)(c)(C); 
(c) An individual emissions data report must be submitted by each fuel supplier and in- state 
producer required to register and report under OAR 340-215-0030(3); (d) An individual emissions data report must be submitted by each natural gas supplier and 
in-state producer required to register and report under OAR 340-215-0030(4); 
(e) An individual emissions data report must be submitted by each electricity supplier required to register and report under OAR 340-215-0030(5) and by any third- party that 
reports on behalf of a consumer -owner utility. A third -party reporting on behalf of a 97 
 consumer- owned utility must also include all information described under OAR 340 -215-
0120(4) and (5), as applicable; 
(f) An individual emissions data report submitted by each asset -controlling supplier seeking 
designation by DEQ must include all information described under OAR 340-215-0120(7);  
and 
(g) An individual emissions data report must be submitted by the owner or operator of a 
facility containing petroleum and natural gas systems required to register and report under 
OAR 340 -215-0030(6) and must include all emissions and related information described in 
OAR 340 -215-0125.;  
(2) When monitoring emissions and submit ting emissions data r eports, Rregulated entities 
must:  
(a) Utilize registration and reporting tools approved and issued by DEQ for all certifications and submissions; 
(b) Submit and certify completed registration and emissions data reports. A separate emissions data report must be submitted for each sector emission data report type identified 
in OAR 34 0-215-0044this rule , as applicable,  and for each individual air contamination 
source stationary source , and must include all data and information as required by OAR 340-
215-0105 through OAR 340-215-0125, as applicable; and 
(c) Submit and certify any revisions to emissions data reports. If a regulated entity identifies 
a
n error in a submission, or is notified of such an error, the regulated entity must submit a 
revision to correct the error within 45 calendar days of discovery. Regulated entities subject 
to the requirements under OAR chapter 340, division 272 must submit revisions in 
compliance with division 272. 
(3) Emissions data reports submitted to DEQ must include the following information: 
(a) Facility name or supplier name (as appropriate), facility or supplier ID number, and 
physical street address of the facility or supplier, including the city, state, and zip code; 
(b) Year and months covered by the report; 
(c) Date of submittal;  
(d) All information required by this division to calculate and report greenhouse gas 
emissions;  
(e) Annual emissions of each greenhouse gas, as required under this division; and 
(f) A certification from the designated representative as required under OAR 340-215-0040(1). 98 
 (4) Increases or decreases in emissions. In addition to the requirements of section (3), i If a 
regulated entity subject to OAR 340-215- 0105 submits an emissions data report that 
indicates emissions equaled or exceeded 25 ,000 MT CO2e during the previous year, then the 
regulated entity must include the following information in the emissions data report: 
(a) Whether a change in operations or status resulted in an increase or decrease of more than 
five percent in emissions of greenhouse gases in relation to the previous data year; and  
(b) If there is an increase or decrease of more than five percent in emissions of greenhouse gases in relation to the previous year, the regulated entity must provide a brief narrative 
descriptio n of what caused the increase or decrease in emissions. Include in this description 
any changes in air contamination source to the regulated entity’s  permit status.  
(5) When R reporting biomass- derived fuels  orand hydrogen, the following requirements also 
apply: . 
(a) In addition to the requirements of section (3), a regulated entity reporting biomass-
derived fuels or hydrogen must retain records as required by OAR 340-215-0042, and 
separately identify, calculate, and report : 
(A) aAll direct emissions of biogenic  CO2 resulting from the combustion of biomass-
derived fuels , as provided in this section..; and 
(B) All direct emissions of biogenic CO2 resulting from the oxidation of biomass -derived 
fuels ; 
(b) When reporting fuels where biomass and fossil feedstocks are processed in the same 
facility to produce the fuel, persons may request  DEQ approval of a methodology for the 
attribution of the biogenic feedstock to determine the amount of the final reported product 
that may be reported as biogenic. Regulated entities must receive written DEQ approval to 
use the attribution methodology prior to reporting; .  
(bc) When reporting fuel combustion and emissions from gaseous or liquid biomass-derived 
fuels  or use of hydrogen, report the following information for each contracted delivery: 
(A) The type and quality of the gas, including the high heating value of the claimed gas; 
(AB) Name and address of all intermediary and directthe  vendor (s) from which the fuel is 
purchased;  
(BC)  Name, address, and facility type of the facility from which the fuel wasis produced; 
and 
(CD) Annual amount contractually delivered , disaggregated by each vendor , in MMBtu for 
biomethane, kilograms for hydrogen and standard cubic feet for other gaseous fuels, and 
gallons for liquid fuels.; 99 
 (E) Feedstock(s) used to produce the gas;  
(F) Method(s) used to produce the gas; 
(G) Month and year in which the gas was produced; 
(H) Method of delivery to Oregon;  
(I) The lifecycle carbon intensity, as defined in OAR  chapter  340, division 253, of the 
pathway for the contractually delivered biomethane or hydrogen. Lifecycle carbon  intensity 
values must be estimated using the methodology and tools described in OAR  chapter  340, 
division 253. U pon request from a regulated entity showing good cause to use a different 
method than one described in OAR chapter  340, division 253, DEQ may approve another 
methodology; 
(J) Based on the quantity of biomethane or hydrogen reported using book and claim 
accounting, the amount of natural gas use displaced in Oregon (MMBtu); 
(K) Name and air permit source identification number for the final end user of the gas in 
Oregon, if applicable; and 
(L) Records demonstrating that no other party can make a claim on environmental attributes 
that are being reported under this division. The quantity of energy covered by the 
environmental attributes  must match or exceed the volume of fuel reported under this 
division. Records must demonstrate that the retired renewable thermal credits or claimed 
environmental attributes were generated within the same reporting data year; and  
(d) R egulated entities reporting cont ractual deliveries of gas using  book and claim 
accounting must also:  
(A) Report the specific type and volume of gas claimed as injected into a natural gas 
pipeline and delivered to Oregon in the reporting data year; 
(B) Report the point of injection into a pipeline connected to Oregon; 
(C) If using an electronic tracking system approved by DEQ for book and claim accounting, 
the regulated entity must submit records showing the retirement of all environmental 
attributes of the gas that are bei ng reported under this division; and  
(e) Retain and make available sufficient records to allow for verification of all reporting 
requirements in this section, including but not limited to those described in OAR 340-215-
0040(7) and OAR 340-215-0042. 
(6) Re gulated entities subject to the requirements of 40 C.F.R. 98.3(i) must meet those 
requirements for data used in developing emissions data reports. 100 
 Statutory/Other Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
  
340-215-0046  
Reporting Deadlines  
(1) Reporting deadlines. 
(a) Air contamination Stationary  sources and electric power system facilities required to 
register and report under OAR 340-215-0030(2) must register and submit annual emissions data reports to DEQ under OAR 340-215-0044 by the due date for the annual report for non-greenhouse gas emissions specified in the source’s Title V Operating Permit or Air Contaminant Discharge Permit, or by March 31 of each year, whichever is later.  
(b) The following regulated entities must register and submit annual emissions data reports to DEQ by March 31 of each year: 
(A) Natural gas suppliers required to register and report under OAR 340 -215-0030(4);  and 
(B) Petroleum and natural gas systems required to register and report under OAR 340 -215-
0030(6) .; 
(c) Fuel suppliers and in -state prod ucers required to register and report under OAR 340-215-
0030(3) must submit annual registration register and submit an annual emissions data report s 
to DEQ by April 30 of each year .; 
(d) Electricity suppliers required to register and report under OAR 340-215- 0030(5) must 
submit an annual registration register  and submit an annual emissions data report to DEQ by 
June 1 of each year .; 
(2) Electricity suppliers required to register and report under OAR 340-215- 0030(5) must 
retain documentation supporting claims of each specified source of electricity as required by OAR 340 -215-0042(6) beginning in 2022 for data year 2021, and in each year thereafter 
(i.e., those persons do not have to report that information in reports submitted in 2021) .; and  
(3) Regulated entities reporting GHG emissions from biomass -derived fuels or hydrogen 
may request DEQ approval for exemptions from any of the requirements of OAR 340-215-
0042(4) through (7) and OAR 340-215-0044(5) for the 2023 data year. DEQ will not 
approve exemptions that would impact the quantification of emissions reported under this 
division. DEQ will consider requests for exemptions based on the regulated entity’s inability 
to implement necessary changes in time to comply with those requirements. Regulated 
entities must submit requests for exemptions under this section no later than February 1, 101 
 2024, and must receive written DEQ approval of exemptions prior to filing 2023 data year 
reports required under this division. Starting in 2025 for data year 2024, and each year 
thereafter, regulated entities must report and retain records as described in OAR 340 -215-
0042(4) through (7) and OAR 340-215-0044(5), as applicable, and DEQ will not approve 
any exemptions to those requirements.  
 GHG emissions from.  
(34) DEQ may extend the reporting deadlines or and  effective dates described in this rule  as 
DEQ deems necessary and will issue notice of any extension s..; and  
(5) If a reporting deadline  described in this rule occurs on a Saturday, Sunday, or an Oregon 
state holiday, the deadline is extended to the following business day. 
 
Statutory/Other Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-215-0105  
Requirements for Air Contamination Stationary  Sources and E lectric P ower S ystem 
Facilities  
Regulated entities required to register and report to DEQ under OAR 340-215-0030(2) must: 
(1) Unless otherwise specified in this rule, Calculate c alculate and all report all  greenhouse 
gasGHG emissions for which there are using quantification methodologies described in 40 
C.F.R. part 98 subparts C through UU or in this division, using methodologies described in 
such rules. and  report  Such reports must include all data and information described in such 
rules. 40 C.F.R. part 98 subparts C through UU, as applicable, unless otherwise specified in 
this rule. Emissions data reports submitted to DEQ must include all emissions with 
calculation methodology in 40 C.F.R. part 98 subparts C through UU or listed in this 
division, This division, however, describes the reporting applicability requirements and the 
applicability provisions of 40 C.F.R. part 98 subparts C through UU shall not be used. Such 
reports but may exclude emissions from categorically insignificant activities  as defined in 
OAR 340 -200-0020. If categorically insignificant activities cannot be separated from other 
activities, entities may report aggregate emissions that include categorically insignificant activities . In addition: ; 
(a) Regulated entities that are in -state producers may exclude data and information described 
in 40 C.F.R. part 98 subpart MM and NN from an individual emissions data report described 
in OAR 340 -215-0044(1)(a) but  must comply with OAR 340-215-0110 and OAR 340-215-
0115, as applicable; and 102 
 (b) Regulated entities that are carbon dioxide suppliers must report data and information 
described in 40 C.F.R. part 98 subpart PP; . 
(2) As applicable, separately report fuel type s, quantities, and emissions from fuel 
combustion reported utilizing 40 C.F.R. part 98, subpart H - Cement Production, subpart W 
- Petroleum and Natural Gas Systems, and subpart AA - Pulp and Paper Manufacturing quantification methodology; 
(3) Provide supplemental documentation, including data inputs for equations to describe 
how emissions are calculated. Data inputs include but are not limited to fuel throughput, emission factors, and production volumes or product usage used to calculate emissions; 
(4) For air contamination stationary  sources and electric power system facilities that include 
electricity generating units, cogeneration units, or both that meet the applicability requirements of section OAR 340-215- 0030(2), follow the requirements of subparts C and D 
of 40 C.F.R. part 98, as applicable, in reporting emissions and other data from electricity generating and cogeneration. In addition, such regulated entities must report the following information: 
(a) Information for each facility as defined in 40 C. F
 .R. 98.6, including separately for each 
facility under the same air contamination source quality  permit: name, address, and contact 
person and phone number; (b) If applicable, report facility identification numbers assigned by the U.S. Energy 
I
nformation Administration, California Air Resources Board and Federal Energy Regulatory 
Commission’s Public Utility Regulatory Policies Act of 1978 (“ PURPA”)  Qualifying 
Facility program;  
(c) Report net and gross electricity generated in megawatt -hours; and 
(d) Regulated entities that own or operate a cogeneration unit must report the thermal energy in MMBtu generated by a combustion source that is used directly as part of a manufacturing, industrial or commercial process, or as part of as heating or cooling application, separately for the following categories: generated thermal energy provided to end users outside the air 
contaminationstationary  source facility boundary and generated thermal energy for on- site 
industrial applications not related to electricity generation;  
(5) An investor- owned utility that owns or operates electric power system facilities as 
defined in 40 C.F.R. part 98 subpart DD in Oregon must report emis sions utilizing 
calculation methodologies in 40 C.F.R. part 98 subpart DD and must submit an emissions data report including all emissions from electric transmission and distribution equipment and servicing inventory physically located in Oregon for the previous year; 
(6) For in -state producers of goods containing fluorinated greenhouse gases in pre- charged 
equipment or closed -cell foams, report the mass of each fluorinated greenhouse gas in all 103 
 goods produced in a year and comply with 40 C.F.R. part 98 subpart QQ in reporting 
emissions to DEQ as modified below: 
(a) Report total mass in metric tons of each fluorinated greenhouse gas contained within pre-
charged equipment or closed cell foams;  
(b) For each type of pre-charged equipment with a unique combination of charge size and charge type, report the identity of the fluorinated greenhouse gas used as a refrigerant or electrical insulator, charge size, holding charge, where applicable and number produced; 
(c) For closed –cell foams the identity of the fluorin ated greenhouse gas in the foam, the 
density of the fluorinated GHG in the foam (kilograms of fluorinated greenhouse gas per cubic feet), and the volume of foam produced ( cubic feet tons) for each type of closed–cell 
foam with a unique combination of F- GHG density and identity; and 
(d) Calculate greenhouse gas emissions from foam blowing operations using the following equation. When the blowing agent is a blend of gases, emissions must be calculated separately for each constituent of the blowing agent used during the foam manufacture 
manufactur ing process :. 
FCO2e  = ∑ {[(TFP × (ATi + ASi) × BAFi) + (FP × BAFi × MFLi )] × GWPi} × 0.907185 
CO2e = ∑{[(Qi × FYLEi)+ (Qi × ALi ×(Y -1))+ (Qi × Li)]× GWPi}/2204.62 
For the purposes of the calculation in this subsection (d), the following definitions apply:  
“FCO2e ” means annual total mass of fluorinated greenhouse gas emissions of carbon 
dioxide equivalent (metric tons); 
 
“TFP” means total amount of foam produced (ton s); 
 
“ATi” means average percent blowing agent , i, in trim (tons); 
 
“ASi” means average percent blowing agent , i, in scrap  (tons); 
 
“BAFi” means percent of blowing agent, i, constituent in foam (tons); 
 
“FP” means finished product (tons) ; 
 
“MFLi” means mass fraction loss from off gassing curve for blowing agent, i, approved by 
DEQ (tons/year) ; 
 
“GWPi” means global warming potential for each constituent of the blowing agent found in 
table A -1 of 40 C.F.R. part 98; and  
 104 
 “0.907185” is applied to convert tons to metric tons; and.  
 
“Qi” means quantity of blowing agent, i, (in pounds) used to manufacture the foam; 
“FYLEi” means first -year loss emission factor associated with the foam application;  
“ALi” means annual loss emission factor associated with the foam application; 
“Y” means number of years remaining in the project;  
“Li” means quantity of blowing agent, i, released during product output including all 
processes (such as foam shaping, grinding, trimming, and shaving) leading to product 
formation;  
“2204.62” is applied to convert pounds to metric tons conversion; and 
“GWPi” means GWP for each GHG from table A -1 of 40 C.F.R. part 98; 
(e) Regulated entities that use fluorinated gasses described in table A -1 of 40 C.F.R. part 98 
as blowing agents in foam blowing operations may request DEQ approva l of alternate 
emissions calculation methods for this operation, process, or activity as described in OAR 
340-215-0040(4). Regulated entities must receive written DEQ approval to use the 
petitioned emissions calculation methods prior to reporting; .    
(7) Calculate and report emissions of biogenic CO2 that originate from biomass- derived 
fuels separately from other greenhouse gas emissions. Report and retain information 
described in OAR 340-215-0042(4) and OAR 340-215-0044(5), as applicable, and uU se the 
following procedures when calculating emission s from biomass -derived fuels that are 
intermixed with fossil fuels:  
(a) When calculating emissions from the combustion of municipal solid waste (MSW) or 
any other fuel for which the biomass fraction is not known, follow the procedures specified in 40 C.F.R . 98.33(e)(3) to specify a biomass fraction;  
(b) When calculating emissions from a biomethane biomass-derived gas , reported using 
book and claim accounting, and natural gas mixture as described in 40 C.F.R. 98.33(a)(2) 
calculate emissions based on contract ual deliveries of biomethane the biomass -derived gas , 
with the remainder of emissions being from natural gas , calculated according to the 
applicable methodology in 40 C.F.R. part 98;  and 
(c) When calculating emissions from a biomethane and natural gas mixture as described in 
40 C.F.R. 98.33(a)(4) using a continuous emission monitoring system (CEMS), or when 
calculating those emissions according to Subpart D of 40 C.F.R. part 98, calculate the 
biomethane emissions as described above, with the remainder of emission being from 
natural gas; 105 
 (cd) When calculating emissions from a biogas and natural gas mixture using 40 C.F.R. 
98.33(a)(4) or the carbon content method described in 40 C.F.R. 98.33(a)(3) or when 
calculating those emissions according to subpart D of 40 C.F.R. part 98, calculate biogas emissions using a carbon content method as described in 40 C.F.R. 98.33(a)(3), with the remainder of emissions being from natural gas ;. 
(8) When  reporting hydrogen using book and claim accounting, report the energy, volume, 
and the total emissions that would have resulted from the full combustion or oxidation of the 
displaced gaseous fuel using the following procedures: 
(a) When reporting hydrogen that displaces a gaseous fuel that is combusted, calculate and 
report the equivalent energy and volume of the gaseous fuel. Report the emissions that 
would have resulted from the full combustion of that fuel using applicable methodology in 
40 C.F.R. part 98; and 
(b) When reporting hydrogen that displaces a gaseous fuel or feedstock that is used in a non-
combustion process, calculate and report the amount of fuel or feedstock that is displaced by 
the reported amount of hydrogen. A stationary source must receive  prior written DEQ 
approval to use its calculation method s to determine the amount of displaced fuel or 
feedstock  it reports. Report the emissions that would have resulted from the non-combustion 
use of the fuel that was disp laced using applicable methodology in 40 C.F.R. part 98. 
 
(98) When reporting emissions from the combustion of natural gas, report the name(s) of the 
supplier(s) of natural gas to the facility, including information identifying the seller of natural gas, natural gas customer account, and the annual MMBtu delivered to each account according to billing statements (10 therms = 1 MMBtu); and  
(10
9) Report the air permit numbers and NAICS codes according to 40 C.F.R. 98.3(c)(10). 
Statutory/Other Authority: ORS 468A.050 Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-215-0110  
Requirements for Fuel Suppliers and In- State Producers 
Fuel suppliers and in- state producers including but not limited to gasoline, distillate fuel oil, 
propane, and aircraft fuel dealers required to register and report under OAR 340 -215-
0030(3), but not including natural gas suppliers, must: 
(1) Report all quantities of fuel disbursed for use in the state by fuel type, regardless of 
whether the fuel is intended for transportation or non -transportation use and regardless of 106 
 whether the fuel is  subject to state or federal fuel taxes. Such reports must include the fuel 
type and quantity imported, sold, or distributed for use in this state during the previous year 
and quantities must be reported in standard cubic feet for gaseous fuels and gallons for 
liquid fuels. In addition:  
(a) Fuel suppliers and in -s tate producers who report renewable biomass- derived fuels must 
provide supporting documentation as required under OAR 340-215-0044(5); and 
(b) Meeting the requirements of this division does not repla ce the requirements that must be 
met in order to satisfy the requirements of OAR chapter 340 , division 253 for any given fuel 
supplier subject to the Oregon Clean Fuels Program (CFP);  
(2) For reporting of regulated fuels as defined under OAR chapter 340, division 253, comply 
with OAR chapter 340 division 253 and submit quarterly and annual reports. In annual 
reports, persons dealing in regulated fuels as defined by OAR 340-253- 0200(2) may further 
report fuel volumes by individual fuel type as defined in 40 C.F.R. part 98 subpart MM. If volumes are not reported by individual fuel type, default emission factors defined in 40 C.F.R. part 98 subpart MM must be used for emissions calculation purposes; 
(3) For reporting all other fuels not reported as regulated f
 uels under section ( 32) including, 
but not limited to, importers and producers of opt- in fuels and small importers of finished 
fuels as defined by OAR 340-253-0040(86), report fuel imported or produced in the state 
during the previous year by fuel type as defined in 40 C.F.R. part 98 subpart MM. Report as follows:  
(a) For fuel imported outside of the bulk system r Re
 port the type and quantity in temperature 
corrected (net) gallons of fuel the fuel supplier held title to or owned at the time the fuel is 
brought into Oregon from out of state or produced in Oregon that is delivered directly to intermediate storage, retail, or end users ,. Exclude fuel imported outside of the bulk system 
and del ivered to a terminal storage facility in Oregon; 
(b) Oregon position holders must r Report the type and quantity in temperature corrected 
(net) gallons of fuel owned and dispersed from terminals in Oregon as reflected in the 
records of the terminal operatora position holder . This applies to the fuel supplier owning 
the fuel at the loading rack as it is being dispensedExclude fuel that is transferred ;: 
(A) From one terminal storage facility in Oregon to another terminal storage facility in 
Oregon; and 
(B) Between entities within the terminal. Regulated entities must only report fuel that is 
owned as it is disbursed from the terminal;  
(c) If formulations are unknown for a given quantity of gasoline, report that quantity of gasoline using the fuel type “Gasoline formulation unknown.” If distillate or residual fuel oil numbers are unknown for a given quantity of distillate fuel oil, report that quantity using the fuel type “Diesel type unknown;” and 107 
 (d) Regulated entities must e Exclude fuel for which a final de stination outside of Oregon 
can be demonstrated; and ; gallons that the regulated entity imported or dispensed as a 
position holder in Oregon and that were subsequently exported out of state. Exported 
volumes must be excluded based on documentation that mee ts the requirements of this 
division, as typically provided in a bill of lading or product transfer document. Regulated 
entities must report all volumes of fuel imported or dispensed from a position holder in 
Oregon that are not documented as exported;  
(4)(a) Fuel suppliers exporting fuel dispensed from a terminal in Oregon (each an 
“exporter”) must notify the position holder owning title to that fuel as it was dispensed if the 
product transfer documents  issued at the terminal do not accurately reflect the state where 
the fuel was ultimately delivered.  The notification must:  
(A) Occur 30 calendar days prior to the reporting deadline; and  
(B) Include fuel types, volumes and delivery destination, based on documentation; 
(b) For fuel that was (i) delivered from the terminal to an intermediate storage location and 
then exported after being dispensed from intermediate storage, (ii) commingled with the 
same type of fuel, and (iii) purchased from multiple position holders, the exporter must 
inform position holders of the exports using the following method: The exporter must 
calculate the total exports from that intermediate storage tank by calendar quarter and fully 
tabulate which position holders it purchased fuel from and that was delivered to intermediate 
storage for that quarter. The exporter must then apportion the exported gallons to the 
position holders based on the percentage of fuel that the exporter purchased from each of the 
position holders in the calendar quarter. The entity exporting the fuel must pr ovide written 
documentation to the position holder that it used this method to apportion the exports.  
Documentation must be made available to DEQ and the impacted position holder within 14 
calendar days of a request from either DEQ or the position holder; and.  
(54) For all fuel suppliers and in -state producers, calculate and report the CO2, CO2 from 
biomass-derived fuels, CH4, N2O, and CO2e emissions in metric tons that would result 
from the complete combustion or oxidation of the annual quantity of fuel i mported, sold, or 
distributed for use in this state. In such reports, GHG emissions must be calculated as follows:  
(a) Utilize emission quantification methodology prescribed in 40 C.F.R. part 98 subpart MM and equation MM-1 as specified in 40 C.F.R. 98.393(a)(1) to calculate the CO2 emissions and CO2 from biomass- derived fuels that would result from the complete combustion of the 
fuel reported under this division; 
(b) Calculate CH4 and N2O emissions using equation C–8 and Table C-2 as required in 40 
C.F.R. 98.33(c)(1); and  
(c) Utilize a DEQ assigned emission factor for fuel and emission types not listed in 40 C.F.R. part 98. 108 
 Statutory/Other Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-215-0115  
Requirements for Natural Gas Suppliers and In -State Producers  
Natural gas suppliers and in -state producers required to register and report under OAR 340-
215-0030(4) must: 
(1) Report the information required including the volume (Mscf), energy (MMBtu), type of natural gas , biomethane or hydrogen and associated emissions for all gas imported, sold, 
produced or distributed for use in the state for the previous year, and: 
(a) If the regulated entity has developed reporter -specific emission factors or high heating 
values, then report the following:  
(A) Information used to develop the reporter -speci fic emission factor(s) and/or higher 
heating value(s);  
(B) The developed emission factor(s); and  
(C) The developed higher heating value(s); 
(b) For the purposes of this section large natural gas end users are end users receiving greater than or equal to 460,000 Mscf of natural gas during the year; and  
(c) Report biomethane  contractually delivered to Oregon  as specified under OAR 340-215-
0044(5);  and 
(d) Natural gas suppliers contractually delivering hydrogen to end users in Oregon must also 
report information as specified under OAR 340 -215-0044(5); . 
(2) For local distribution companies, calculate and report greenhouse gas emissions using 
quantification methodologies and report data and information described in 40 C.F.R part 98 
subpart NN for suppliers of natural gas and natural gas liquids, as applicable, unless otherwise specified in this rule including the following: 
(a) In addition to submitting all information needed to meet the requirements of 40 C.F.R. 98.406(b)(1) through (b)(7), report the annual MMBtu of natural gas associated with the volumes reported;  109 
 (b) Report the amount of natural gas delivered to each large natural gas end us er separately 
in the state including customer information required in 40 C.F.R. 98.406(b)(12), and source 
identification number if available; and  
(c) Report identifying information for each natural gas marketer contracting use of the distribution system du ring the year including company name , and address; 
(3) For interstate pipeline owners and operators, report the total amount of natural gas delivered to end users in the state for use in the state, excluding gas delivered to an Oregon local distribution co mpany, and: 
(a) Report the annual amount of natural gas delivered to each large natural gas end user separately in the state including customer information required in 40 C.F.R. 98.406(b)(12), and source identification number(s) if available. In instances where multiple end users are downstream of a delivery point that registers at least 460,000 Mscf annually report the total gas delivered and identifying information for each user downstream of the delivery point; and 
(b) Report identifying information for each natural gas marketer contracting use of the 
distribution system during the year including company name, and address; 
(4) IFor i mporters of natural gas, compressed natural gas, or liquefied natural gas into the 
state by any means other than a pipeline distribution system or interstate pipeline ,, including 
but not limited to imports by rail or truck, and in-state producers of natural gas or 
biomethane must separately  report : 
(a) Tthe total amount of natural gas, compressed natural gas, and liquefied natural gas and 
biomethane imported or produced and delivered of sold for into the state for use in the state, 
excluding volumes delivered to an Oregon local distribution company or inje cted into an 
interstate pipeline; and .  
(b) T Such regulated entities must report the total amount of natural gas, compressed natural 
gas, or liquefied natural , or biomethane  delivered to each large natural gas end user in the 
state including customer information required in 40 C.F.R. 98.406(b)(12), and source 
identification number if available; and  
(5) For regulated entities that own or operate facilities that make liquefied natural gas or 
compressed natural gas products report the total annual amount of natural gas delivered or 
sold for use in the state, excluding volumes delivered to an Oregon local distribution 
company, report the annual amount of natural gas delivered to each large natural gas end 
user in the state including customer information required in 40 C.F.R. 98.406(b)(12), and 
source identification number if available; and  
(65) For all natural gas suppliers, calculate and report the CO2, biogenic CO2 from any 
repor ted biomass-derived fuel, CH4, N2O, and CO2e emissions in metric tons that would 
result from the complete combustion or oxidation of the annual quantity of natural gas 110 
 imported, sold, or distributed for use in this state. Calculate and report greenhouse ga s 
emissions for the previous year utilizing emission quantification methodology prescribed in 
40 C.F.R. part 98 and as follows: 
(a) Calculate greenhouse gas emissions separately for natural gas, compressed natural gas and liquefied natural gas  and biomethane ; 
(b) Calculate and report CO2 emissions as follows:  
(A) Local distribution companies must utilize quantification methodologies and report all data elements as required by 40 C.F.R. 98 subpart NN - Suppliers of Natural Gas and Natural Gas liquids for the  total volume of gas supplied in the state; and  
(B) All other natural gas suppliers including interstate pipeline owners or operators, importers of natural gas, and owners or operators of facilities in-state producers that make 
natural gas products must cal culate and report using calculation methodology 1 as specified 
in 40 C.F.R. 98.403(a)(1); 
(c) Calculate and report CH4 and N2O emissions from natural gas imported, sold, or distributed for use in this state using equation C-8 and table C-2 as required in 40 C.F.R. 98.33(c)(1) for all fuels subject to reporting;  
(d) CO2 emissions from biomass -derived fuel are based on the fuel the natural gas supplier 
contractually purchased on behalf of and contractually delivered  to end users . Emissions 
from biomethane are calculated using the methods for natural gas required by this section, including the use of the emission factor for natural gas in 40 C.F.R. 98.408, table NN-1. Natural gas suppliers who report emissions from biomethane must   report informat ion 
required by OAR 340-215- 0044(5) and provide retain  supporting documentation as required 
under OAR 340-215- 00424(5) ; and 
(e) Not report data or emissions for exported products  for which a final destination outside 
Oregon can be demonstrated. 
Statutory/O ther Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-215-0120  
Requirements for Electricity Suppliers  
Electricity suppliers required to register and report under OAR 340 -215- 0030(5) must report 
information and emissions related to the generation of electricity delivere d or distributed to 
end users in this state during the previous year, regardless of whether the electricity was generated in this state or imported. Such reports must; 111 
 (1) Report the megawatt -hours (MWh) and greenhouse gas emissions from the generation of 
electricity from unspecified sources and from each specified source delivered or distributed 
to end users in Oregon during the previous year, as follows:  
(a) For unspecified sources, report the MWh of electricity and calculate and report the 
associated GHG emissions according to section (5)(a). Separately identify the MWh for 
power purchased from any energy imbalance market(s) or other centralized market(s);  
(b) For specified sources of electricity, report as follows:  
(A) Report specified sources when one of the following applies:  
(i) The electricity supplier is a facility or unit operator, full or partial owner, party to a power 
contract for a fixed percentage of generation from the facility or generating unit, party to a 
tolling agreement and rents a facility or unit from the owner or is an exclusive power 
deliverer that is not a retail provider and that has prevailing rights to claim electricity from the specified source; or  
(ii) The electricity supplier has a power contract for electricity from a DEQ -approved asset -
controlling supplier (ACS) or generated by a facility or unit, subject to meeting all other 
specified source requirements and can provide documentation that the contract was 
designated at the time the transaction was executed; and  
(B) Electricity suppliers reporting specified sources must:  
(i) Report the MWh of electricity disaggregated by facility or unit, and by fuel type or ACS, 
as measured at the busbar. If not measured at the busbar, report the amount of electricity 
delivered i n Oregon, including estimated transmission losses using the default transmission 
loss correction factor of 1.02;  
(ii) Report the GHG emissions associated with the electricity calculated according to 
subsection (5)(b); and  
(iii) Report details about each sp ecified facility, unit, or ACS, including fuel type or types 
and information about the seller, including company name and contact information;  
(c) For electricity suppliers that are multi- jurisdictional utilities that deliver or distribute 
electricity in O regon, report total MWh and greenhouse gas emissions from the generation 
of electricity from specified and unspecified sources in the utility’s service territory or power system as required by subsections (a) and (b), and also report the following:  
(A) Who lesale electricity purchased and taken from specified sources (MWh);  
(B) Wholesale electricity purchased from unspecified sources (MWh);  
(C) Wholesale electricity sold from specified sources (MWh); and  112 
 (D) Retail sales (MWh) to customers in Oregon’s portion of the utility’s service territory or 
power system; and  
(d) For electricity suppliers that are not multi -jurisdictional utilities, proportionally adjust all 
resources on an annual basis to account for the sale of power to the wholesale market that is not known to be just specified or unspecified;  and 
(e) Electric companies and electricity service suppliers as defined in ORS 757.600 subject to 
ORS 469A.210 must separately report and identify electricity (MWh) and greenhouse gas 
emissions associated with el ectricity acquired from net metering of customer resources or a 
qualifying facility under the terms of the Federal Energy Regulatory Commission’s Public 
Utility Regulatory Policies Act of 1978 (“ PURPA”)  Qualifying Facility program;  
(2) Use DEQ approved and published emission factors for calculating and reporting GHG emissions, including;  
(a) The emission factor for calculating emissions from unspecified power is 0.428 MT CO2e/MWh;  
(b) Electricity supplie rs reporting specified source power provided by a multi- jurisdictional 
utility or DEQ -approved ACS must calculate emissions using a system emission factor 
published by DEQ, which will be calculated by DEQ according to subsection (6)(b); 
(c) Electricity suppliers reporting specified source power from a specific facility or unit must 
calculate emissions using emission factors published by DEQ, which will be calculated according to subsection (6)(a); and 
(d) For reporting emissions from specified sources for w hich DEQ has not published an 
approved emission factor, electricity suppliers may propose facility- specific or unit -specific 
anthropogenic and biogenic emission factors expressed as metric tons of carbon dioxide 
equivalent (MT CO2e) per megawatt -hour of generation. Such a proposal to DEQ must 
include documentation describing how the proposed facility- specific or unit -specific 
emission factors are derived, including the necessary information for verification of these calculations. DEQ may adopt the proposed emission factors or may develop and assign facility -specific or unit- specific emission factors for the specified source. The regulated 
entity may use such an emission factor only if approved by DEQ; 
(3) For utilities that do not receive electricity from other sources and who serve load 
exclusively in Oregon, a third-party report from the Bonneville Power Administration (BPA), reporting the preference sales provided to Oregon consumer- owned utilities may 
satisfy such regulated party’s obligations under this division. If BPA does not report this information to DEQ, those consumer- owned utilities must report the information as required 
by this division; 
(4) For a consumer-owned utility, a third-party may submit the registration and report, and the report may in clude information for more than one consumer-owned utility, provided that 113 
 the report contains all information required under this division for each individual 
consumer-owned utility, and: 
(a) The consumer -owned utility must notify DEQ at least 30 calendar days prior to the 
reporting deadline that a third -party will be reporting on its behalf. This notification must 
include the name and contact information for the third -party; 
(b) This notification may include notice that the third -party will report on behal f of the 
consumer- owned utility for future years;  
(c) For any future year in which there is a change in the third -party reporting on behalf of 
the consumer-owned utility, the consumer- owned utility must provide notification to DEQ at 
least 30 calendar days prior to the reporting deadline; 
(d) Third -parties reporting on behalf of a consumer- owned utility must notify DEQ and 
request authorization from DEQ prior to submitting any reports. This notification must include identifying information of the consumer-owned utility; and 
(e) Each consumer -owned utility must ensure that reports submitted on its behalf meet all 
requirements of this division; 
(5) Calculate and report greenhouse gas emissions as follows:  
(a) Emissions reported for electricity associated with unspecified sources must be calculated 
using the following equation: 
CO2e = MWh × TL × EFunsp 
For the purposes of this calculation, “EFunsp” means default emission factor for unspecified 
electricity equal to 0.428 MT CO2e/MWh; 
(b) Emissions  reported for electricity associated with specified sources must be calculated 
using the following equation: CO2e = MWh × TL × EFsp 
For the purposes of this calculation, “EFsp” means facility -specific, unit- specific, or ACS 
system emission factor published  by DEQ; and 
(c) Emissions reported by a multi- jurisdictional utility may be calculated according to a cost 
allocation methodology approved by the Oregon Public Utility Commission (OPUC) using 
the following equation:  
CO2e = MWhMJOR × TL × EFMJ  
For the purp oses of this calculation, the following definitions apply:  114 
 “MWhMJOR” means total megawatt -hours of electricity delivered to retail customers in 
Oregon; 
“EFMJ” means multi -jurisdictional utility system emission factor calculated according to 
equation (6)( bc) (MT CO2e/MWh);  
(6) For electricity suppliers, use emission factors calculated and published by DEQ for 
calculating and reporting emissions, as follows: 
(a) DEQ will calculate facility -specific or unit- specific emission factors using the following 
equation:  
EFsp = Esp /EG  
For the purposes of this calculation, the following definitions apply:  
“EFsp” means the facility -specific or unit specific emission factor;  
“Esp” means CO2e emissions for a specified facility or unit for the report year (MT CO2e);  
“EG” means net generation from a specified facility or unit for the report year;  
(b) DEQ will calculate multi -jurisdictional utility and asset -controlling supplier system 
emission factors using the following equations: 
EFSYS = Sum of System Emissions MT CO2e ÷ Su m of System MWh  
Sum of System Emissions MT CO2e = ∑Esp + ∑(PEsp × EFsp) + ∑(PEunsp × EFunsp) - 
∑(SEsp × EFsp)  
Sum of System MWh = ∑EGsp + ∑PEsp + ∑PEunsp - ∑SEsp  
For the purposes of the calculations, the following definitions apply: 
“ΣEsp” means Emissions from Owned Facilities. Sum of CO2e emissions from each 
specified facility/unit in the supplier’s fleet, consistent with section (5)(b) (MT CO2e);  
“ΣEGsp" means Net Generation from Owned Facilities. Sum of net generation for each 
specified facility/unit in the supplier’s fleet for the data year as reported to DEQ under this 
division (MWh);  
“PEsp” means Electricity Purchased from Specified Sources. Amount of electricity purchased wholesale and taken from specified sources by the supplier for the data year as reported to DEQ under this division (MWh); 115 
 “PEunsp” means Electricity Purchased from Unspecified Sources. Amount of electricity 
purchased wholesale from unspecified sources by the supplier for the data year as reported to DEQ under this division (MWh); 
“SEsp” means Electricity Sold from Specified Sources. Amount of wholesale electricity sold 
from specified sources by the supplier for the data year as reported to DEQ under this 
division (MWh);  
“EFsp” means CO2e emission factor as defined for each specified  facility or unit calculated 
consistent with section (5)(b) (MT CO2e/MWh);  
“EFunsp” means default emission factor for unspecified sources calculated consistent with section (5)(a) (MT CO2e/MWh);  and 
(c) DEQ will calculate multi -jurisdictional utility syste m emission factors consistent with a 
cost allocation methodology approved by the Oregon Public Utility Commission using the 
following equation:  
EFMJ = Sum of System Emissions MT CO2e ÷ Sum of System MWh  
Sum of System Emissions MT CO2e = ∑Esp + ∑(PEsp × EFs p) + ∑(PEunsp × EFunsp) - 
∑(SEsp × EFsp)  
Sum of System MWh = ∑EGsp + ∑PEsp + ∑PEunsp - ∑SEsp  
For the purposes of the calculations, the following definitions apply: 
“ΣEsp” means Emissions from Owned Facilities allocated to serve retail customers in 
Oregon pursuant to a cost allocation methodology approved by the Oregon Public Utility 
Commission. Sum of CO2e emissions from each specified facility/unit in the supplier’s 
fleet, consistent with section (5)(b) (MT CO2e); 
“ΣEGsp" means Net Generation from Owned Fa cilities  allocated to serve retail customers in 
Oregon pursuant to a cost allocation methodology approved by the Oregon Public Utility 
Commission. Sum of net generation for each specified facility/unit in the supplier’s fleet for 
the data year as reported to DEQ under this division (MWh); 
“PEsp” means Electricity Purchased from Specified Sources allocated to serve retail 
customers in Oregon pursuant to a cost allocation methodology approved by the Oregon 
Public Utility Commission . Amount of electri city purchased wholesale and taken from 
specified sources by the supplier for the data year as reported to DEQ under this division 
(MWh);  
“PEunsp” means Electricity Purchased from Unspecified Sources allocated to serve retail 
customers in Oregon pursuant to a cost allocation methodology approved by the Oregon 116 
 Public Utility Commission . Amount of electricity purchased wholesale from unspecified 
sources by the supplier for the data year as reported to DEQ under this division (MWh); 
“SEsp” means Electricity So ld from Specified Sources  consistent with a cost allocation 
methodology approved by the Oregon Public Utility Commission. Amount of wholesale 
electricity sold from specified sources by the supplier for the data year as reported to DEQ 
under this division ( MWh);  
“EFsp” means CO2e emission factor as defined for each specified facility or unit calculated 
consistent with section (5)(b) (MT CO2e/MWh);  
“EFunsp” means default emission factor for unspecified sources calculated consistent with 
section (5)(a) (MT CO2 e/MWh);  and 
 
(7) For a person that owns or operates inter- connected electricity generating facilities or has 
exclusive rights to claim electricity from these facilities even though it does not own them 
may request that DEQ designate them as an asset -contro lling supplier, and:  
(a) Persons seeking designation by DEQ as an asset -controlling supplier must annually 
adhere to the requirements of this division, or be removed from asset- controlling supplier 
designation; 
(b) In addition to submitting the applicable information as required by this rule, persons 
seeking designation by DEQ as an asset -controlling supplier must also submit the following 
by June 1 of each year: 
(A) General business information, including business name and contact information; 
(B) A list of officer names and titles;  
(C) Wholesale electricity purchased and taken from specified sources (MWh);  
(D) Wholesale electricity purchased from unspecified sources (MWh);  
(E) Wholesale electricity sold from specified sources (MWh); and  
(F) An attestation,  in writing and signed by designated representative of the applicant that 
the information submitted is true, accurate, and complete; and  
(c) DEQ will calculate and publish a supplier- specific system emission factor according to 
subsection (6)(b) for designated asset -controlling suppliers.  
Statutory/Other Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468 & 468A 117 
 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020  
 
340-215-0130  
 
Separate Violations  
Each metric ton of greenhouse gas emissions not reported according to the requirements of 
this division by a covered fuel supplier, as defined in OAR 340-271-0020, that affects 
applicability determinations, compliance instrument distribution, or compliance obligations 
under the Oregon Climate Protection Program, OAR Chapter 340 Division 271, is a separate 
violation of this division.  
 
  118 
 Air Contaminant Discharge Program, Division 216 
 
340-216-0025  
 
Types of Permits  
 (1) Construction ACDP:  (a) A Construction  ACDP may be used for approval of Type 3 changes specified in OAR 
340-210- 0225 at a source subject to the ACDP permit requirements in this division.  
 (b) A Construction ACDP is required for Type 3 changes specified in OAR 340-210-0225 at sources subject to  the Oregon Title V Operating Permit requirements.  
 (2) General ACDP. A General ACDP is a permit for a category of sources for which individual permits are unnecessary in order to protect the environment, as determined by DEQ. An owner or operator of a sou rce may be assigned to a General ACDP if DEQ has 
issued a General ACDP for the source category and:  
 (a) The source meets the qualifications specified in the General ACDP;  
 (b) DEQ determines that the source has not had ongoing, recurring, or serious compliance problems; and  (c) DEQ determines that a General ACDP would appropriately regulate the source.  
 (3) Short Term Activity ACDP. A Short Term Activity ACDP is a letter permit that authorizes the activity and includes any conditions placed upon the method or methods of operation of the activity. DEQ may issue a Short Term Activity ACDP for activities included in OAR 340-216-0054.  
(4) Basic ACDP. A Basic ACDP is a permit that authorizes the regulated source to operate in conformance with the rules contained in OAR chapter 340, divisions 200 to 268272. 
 (a) Owners and operators of sources and activities listed in Part A of OAR 340-216-8010 must at a minimum obtain a Basic ACDP.  
 (b) Any owner or operator of a source required to obtain a Basic ACDP may choose to obtain either a Simple or Standard ACDP.  (5) Simple ACDP.  
 
(a) Owners and operators of sources and activities listed in OAR 340-216-8010 Part B that do not qualify for a General ACDP and are not required to obtain a Standard ACDP must, at a minimum, obtain a Simple ACDP. The owner or operator of a source required to obtain a Simple ACDP may choose to obtain a Standard ACDP. 119 
  
(b) A Simple ACDP is a permit that contains:  
 
(A) All relevant applicable requirements for source operation,  including general ACDP 
conditions for incorporating generally applicable requirements;  
 
(B) PSELs at less than the SER for all regulated pollutants emitted at more than the de 
minimis emission level according to OAR chapter 340, division 222; and  
(C) Test ing, monitoring, recordkeeping, and reporting requirements sufficient to determine 
compliance with the PSEL and other emission limits and standards, as necessary.  
 
(6) Standard ACDP:  
 
(a) Applicability.  
 
(A) The owner or operator of a source listed in Part C of OAR 340 -216-8010 must obtain a 
Standard ACDP;  
 
(B) The owner or operator of a source listed in Part B of OAR 340 -216-8010 that does not 
qualify for a General ACDP or Simple ACDP must obtain a Standard ACDP; 
 
(C) The owner or operator of a source not required to obtain a Standard ACDP may choose 
to apply for a Standard ACDP.  
 (b) A Standard ACDP is a permit that contains:  
 
(A) All applicable requirements, including general ACDP conditions for incorporating 
generally applicable requirements;  
 (B) PSELs for all regulated pollutants emitted at more than the de minimis emission level 
according to OAR chapter 340, division 222; and  
 
(C) Testing, monitoring, recordkeeping, and reporting requirements sufficient to determine compliance with the PSEL and other emission limits and standards, as necessary.  
 
(7)(a) Notwithstanding the other provisions of this division that establish the eligibility of a 
source for different types of ACDPs, DEQ may determine, pursuant to the standards 
described in subsecti on (b), that the owner or operator of a source is ineligible for certain 
types of ACDP and must be issued a different type of ACDP; 
 
(b) DEQ will make a determination about which type of ACDP that the owner or operator of 
source must obtain based upon the following considerations:  
 (A) The nature, extent, toxicity and impact on human health and the environment of the source's emissions;  
 120 
 (B) The complexity of the source and the rules applicable to that source;  
 
(C) The complexity of the emission controls, potential threat to human health and the environment if the emission controls fail, and the source’s capacity;  
 (D) The location of the source and its proximity to places where people live and work; and  
 (E) The compliance history of the source, including by the source’s:  
(i) Current corporate officers, managers, members of the board of directors, general partners 
or similar persons, provided that the person exercises or will exercise substantial control on 
behalf of or over the facility that is the subject of the application or permit;  
 (ii) Parent corporations, or similar business entities, that exercise substantial control over the facility that is the subject of the application or permit; and  
 
(iii) Subsidiary corporations, or similar business entities, over which the applicant or 
permittee exercises substantial control.  
 
[NOTE: This rule is included in the State of Oregon Clean Air Act Implementation Plan as 
adopted by the EQC under OAR 340 -211-0040.]  
 
[NOTE: All tables are found in OAR 340 -216-8010, - 8020, - 8030.]  
 
 
340-216-8010  
Table 1 Activities and Sources 
The following source categories must obtain a permit as required by OAR 340- 216-0020  
Applicability and Jurisdiction.  
Part A: Basic ACDP  
1 Autobody repair or painting shops painting more than 25 automobiles in a year and that 
are located inside the Portland AQMA.  
2 Concrete manufacturing including redi -mix and CTB, both stationary and portable, more 
than 5,000 but less than 25,000 cubic ya rds per year output.  
3 Crematory incinerators with less than 20 tons/year material input.  
4 Individual natural gas or propane -fired boilers with heat input rating between 9.9 and 29.9 
MMBTU/hour, constructed after June 9, 1989, that do not use more than 9,999 gallons per 
year of #2 diesel oil as a backup fuel.  121 
 5 Prepared feeds for animals and fowl and associated grain elevators more than 1,000 
tons/year but less than 10,000 tons per year throughput.  
6 Rock, concrete or asphalt crushing, both stationary and portable, more than 5,000 
tons/year but less than 25,000 tons/year crushed.  
7 Surface coating operations whose actual or expected usage of coating materials is greater 
than 250 gallons per month but does not exceed 3,500 gallons per year, excluding so urces 
that exclusively use non- VOC and non -HAP containing coatings, e.g., powder coating 
operations.  
8 Sources subject to permitting under Part B of this table, number 85 if all of the following 
criteria are met: a. The source is not subject to any catego ry listed on this table other than 
Part B number 85; b. The source has requested an enforceable limit on their actual emissions, if the source were to operate uncontrolled, to below Part B number 85 of this table as applicable depending on the source’s location through one or both 
9 All stationary sources not listed elsewhere in this table  that have the capacity to emit 
25,000 metric tons of CO2e or more of covered emissions as defined at OAR 340-271-0020 
in a year.  
Part B: General, Simple or Standard ACDP  
1 Aerospace or aerospace parts manufacturing subject to RACT under OAR chapter 340, division 232.  
2 Aluminum, copper, and other nonferrous foundries subject to an area source NESHAP 
under OAR chapter 340, division 244.  
3 Aluminum production – primary.  
4 Ammonia manufacturing.  
5 Animal rendering and animal reduction facilities.  
6 Asphalt blowing plants.  7 Asphalt felts or coating manufacturing.  
8 Asphaltic concrete paving plants, both stationary and portable.  
9 Bakeries, commercial over 10 tons of VOC emissions per year.  
10 Battery separator manufacturing.  
11 Lead-acid battery manufacturing and re- manufacturing.  122 
 12 Beet sugar manufacturing.  
13 Oil -fired boilers and other fuel burning equipment whose total heat input rating at the 
source is over 10 MMBTU/hour; or individual natural gas, propane, or butane -fired boilers 
and other fuel burning equipment 30 MMBTU/hour or greater heat input rating.  
14 Building paper and building board mills.  
15 Calcium carbide manufacturing.  
16 Can or drum coating subject to RACT under OAR chapter 340, division 232.2  
17 Cement manufacturing.  
18 Cereal preparations and associated grain elevators 10,000 or more tons/year throughput.1  
19 Charcoal manufacturing.  
20 Chlorine and alkali manufacturing.  
21 Chrome plating and anodizing subject to a NESHAP under OAR chapter 340, division 
244.  
22 Clay ceramics manufacturing subject to an area source NESHAP under OAR chapter 
340, division 244.  
23 Coffee roasting, roasting 30 or more green tons per year.  
24 Concrete manufacturing including redi -mix and CTB, both stationary and portable, 
25,000 or more cubic yards per year output.  
25 Crematory incinerators 20 or m ore tons/year material input.  
26 Degreasing operations, halogenated solvent cleanings subject to a NESHAP under OAR 
chapter 340, division 244.  
27 Electrical power generation from combustion, excluding units used exclusively as 
emergency generators and units less than 500 kW.  
28 Commercial ethylene oxide sterilization, excluding facilities using less than 1 ton of 
ethylene oxide within all consecutive 12- month periods after December 6, 1996.  
29 Ferroalloy production facilities subject to an area source N ESHAP under OAR chapter 
340, division 244.  
30 Flatwood coating subject to RACT under OAR chapter 340, division 232.2  123 
 31 Flexographic or rotogravure printing subject to RACT under OAR chapter 340, division 
232.2  
32 Flour, blended and/or prepared and associated grain elevators 10,000 or more tons/year 
throughput.1  
33 Galvanizing and pipe coating, except galvanizing operations that use less than 100 tons of zinc/year.  
34 Bulk gasoline plants, bulk gasoline terminals, and pipeline facilities.  
35 Gasol ine dispensing facilities, excluding gasoline dispensing facilities with monthly 
throughput of less than 10,000 gallons of gasoline per month
3.  
36 Glass and glass container manufacturing subject to a NSPS under OAR chapter 340, 
division 238 or a NESHAP under OAR chapter 340, division 244.  
37 Grain elevators used for intermediate storage 10,000 or more tons/year throughput.1  
38 Reserved.  
39 Gray iron and steel foundries, malleable iron foundries, steel investment foundries, steel 
foundries 100 or more to ns/year metal charged, not elsewhere identified.  
40 Gypsum products manufacturing.  
41 Hardboard manufacturing, including fiberboard.  
42 Hospital sterilization operations subject to an area source NESHAP under OAR chapter 
340, division 244.  
43 Incinerators with two or more tons per day capacity.  
44 Lime manufacturing.  
45 Liquid storage tanks subject to RACT under OAR chapter 340, division 232.2  
46 Magnetic tape manufacturing.  
47 Manufactured home, mobile home and recreational vehicle manufacturing.  
48 Marine vessel petroleum loading and unloading subject to RACT under OAR chapter 
340, division 232.  
49 Metal fabrication and finishing operations subject to an area source NESHAP under OAR 
chapter 340, division 244, excluding facilities that meet all the following:  124 
 a. Do not perform any of the operations listed in OAR 340- 216-0060(3)(b)(V)(i) through 
(iii);  
b. Do not perform shielded metal arc welding (SMAW) using metal fabrication and 
finishing hazardous air pollutant (MFHAP) containing wire or rod; and  
c. Use less than 100 pounds of MFHAP containing welding wire and rod per year.  
50 Millwork manufac turing, including kitchen cabinets and structural wood members, 
25,000 or more board feet/maximum 8 hour input.  
51 Molded plastic container manufacturing, using extrusion, molding, lamination, and foam 
processing and molded fiberglass container manufactur ing, excluding injection molding.  
52 Motor coach, travel trailer, and camper manufacturing.  
53 Motor vehicle and mobile equipment surface coating operations subject to an area source 
NESHAP under OAR chapter 340, division 244, excluding motor vehicle sur face coating 
operations painting less than 10 vehicles per year or using less than 20 gallons of coating 
and 20 gallons of methylene chloride containing paint stripper per year, mobile equipment 
surface coating operations using less than 20 gallons of coat ing and 20 gallons of methylene 
chloride containing paint stripper per year, and motor vehicle surface coating operations 
registered pursuant to OAR 340- 210-0100(2).  
54 Natural gas and oil production and processing and associated fuel burning equipment.  
55 Nitric acid manufacturing.  
56 Nonferrous metal foundries 100 or more tons/year of metal charged.  
57 Organic or inorganic chemical manufacturing and distribution with ½ or more tons per 
year emissions of any one criteria pollutant, sources in this category with less than ½ 
ton/year of each criteria pollutant are not required to have an ACDP.  
58 Paint and allied products manufacturing subject to an area source NESHAP under OAR chapter 340, division 244.  
59 Paint stripping and miscellaneous surface coating operations subject to an area source 
NESHAP under OAR chapter 340, division 244, excluding paint s tripping and 
miscellaneous surface coating operations using less than 20 gallons of coating and also using less than 20 gallons of methylene chloride containing paint stripper per year.  
60 Paper or other substrate coating subject to RACT under OAR chapter  340, division 232.
2  
61 Particleboard manufacturing, including strandboard, flakeboard, and waferboard.  125 
 62 Perchloroethylene dry cleaning operations subject to an area source NESHAP under 
OAR chapter 340, division 244, excluding perchloroethylene dry cle aning operations 
registered pursuant to OAR 340- 210-0100(2).  
63 Pesticide manufacturing 5,000 or more tons/year annual production.  
64 Petroleum refining and re -refining of lubricating oils and greases including asphalt 
production by distillation and the reprocessing of oils and/or solvents for fuels.  
65 Plating and polishing operations subject to an area source NESHAP under OAR chapter 
340, division 244.  
66 Plywood manufacturing and/or veneer drying.  
67 Prepared feeds manufacturing for animals and fowl  and associated grain elevators 10,000 
or more tons per year throughput.  
68 Primary smelting and/or refining of ferrous and non- ferrous metals.  
69 Pulp, paper and paperboard mills.  
70 Rock, concrete or asphalt crushing, both stationary and portable, 25,000 or more 
tons/year crushed.  
71 Sawmills and/or planing mills 25,000 or more board feet/maximum 8 hour finished 
product.  
72 Secondary nonferrous metals processing subject to an Area Source NESHAP under OAR 
chapter 340, division 244.  
73 Secondary smelt ing and/or refining of ferrous and nonferrous metals.  
74 Seed cleaning and associated grain elevators 5,000 or more tons/year throughput.1  
75 Sewage treatment facilities employing internal combustion engines for digester gasses.  
76 Soil remediation facilities, both stationary and portable.  
77 Steel works, rolling and finishing mills.  
78 Surface coating in manufacturing subject to RACT under OAR chapter 340, division 
232.2  
79 Surface coating operations with actual emissions of VOCs, if the source were to operate uncontrolled, of 10 or more tons/year.  126 
 80 Synthetic resin manufacturing.  
81 Tire manufacturing.  
82 Wood furniture and fixtures 25,000 or more board feet/maximum 8 hour input.  
83 Wood preserving (excluding waterborne).  
84 All other sources, both stationary and portable, not listed herein that DEQ determines an 
air quality concern exists or one which would emit significant malodorous emissions.  
85 All other sources, both stationary and portable, not listed herein which would have the 
capacity of 5 or more tons per year of direct PM2.5 or PM10 if located in a PM2.5 or PM10 
nonattainment or maintenance area, or 10 or more tons per year of any single criteria 
pollutant.4  
86 Chemical manufacturing facilities subject to 40 C.F.R. part 63 subpart VVVVVV.  
87 Stationary internal combustion engines if:  
a. For emergency generators and firewater pumps, the aggregate engine horsepower rating is 
greater than 30,000 horsepower; or  
b. For any individual non -emergency or non- fire pump engine, the engine is subject to 40 
CFR part 63, subpart ZZZZ and is rated at 500 horsepower or more, excluding two stroke lean burn engines, engines burning exclusively landfill or digester gas, and four stroke engines located in remote areas; or  
c. For any individual non -emergency engine, the engine is subject to 40 CFR part 60, 
subpart IIII and:  
A. The engine has a displacement of 30 liters or more per cylinder; or  
B. The engine has a displacement of less than 30 liters per cylinder and is rated at 500 
horsepower or more and the engine and control device are either not certified by the manufacturer to meet the NSPS or not operated and maintained according to the manufacturer’s emission -related instruct ions; or  
d. For any individual non -emergency engine, the engine is subject to 40 CFR part 60, 
subpart JJJJ and is rated at 500 horsepower or more and the engine and control device are either not certified by the manufacturer to meet the NSPS or not operated and maintained according to the manufacturer’s emission -related instructions.  
88 All sources subject to RACT under OAR chapter 340, division 232, BACT or LAER under OAR chapter 340, division 224, a NESHAP under OAR chapter 340, division 244, a 127 
 NSPS und er OAR chapter 340, division 238, or State MACT under OAR 340- 244-0200(2), 
except sources:  
a. Exempted in any of the categories above;  
b. For which a Basic ACDP is available; or  
c. Registered pursuant to OAR 340-210-0100(2).  
89 Pathological waste inci nerators.  
90 Landfills with more than 200,000 tons of waste in place and calculated methane 
generation rate is less than 664 metric tons per year which are subject to the requirements in OAR 340 division 239. 
 
1 Applies only to Special Control Areas  
2 Portland AQMA, Medford -Ashland AQMA or Salem -Keizer in the SKATS only  
3 “monthly throughput” means the total volume of gasoline that is loaded into, or dispensed from, all gasoline 
storage tanks at the gasoline dispensing facility during a month. Monthly throughput is calculated by summing 
the volume of gasoline loaded into, or dispensed from, all gasoline storage tanks at the gasoline dispensing 
facility during the month, plus the total volume of gasoline loaded into, or dispensed from, all gasoline storage  
tanks at the gasoline dispensing facility during the previous 11 months, and then dividing that sum by 12  
4 A source subject to permitting from this category may be able to obtain a Basic ACDP under Part A number 8 
of this table. For sources that meet th e criteria of Part A number 8 of this table, the enforceable production or 
hours limitation in an issued ACDP may be used to demonstrate a permit is not required by Part B number 85 of this table irrespective of the term ‘uncontrolled’.
 
Part C: Standard ACDP  
1 Incinerators for PCBs, other hazardous wastes, or both.  2 All sources that DEQ determines have emissions that constitute a nuisance.  
3 All sources electing to maintain the source’s netting basis.  
4 All sources that request a PSE L equal to or greater than the SER for a regulated pollutant.  
5 All sources having the potential to emit 100 tons or more of any regulated pollutant, 
except GHG, in a year.  
6 All sources having the potential to emit 10 tons or more of a single hazardous air pollutant 
in a year.  128 
 7 All sources having the potential to emit 25 tons or more of all hazardous air pollutants 
combined in a year.  
8 Landfills with more than 200,000 tons of waste in place and calculated methane generation 
rate is greater than or equal to 664 metric tons per year which are subject to the requirements 
in OAR 340 division 239. 
 
NOTE: For the history of these tables prior to 2014 see the history under OAR 340- 216-
0020. This history is also shown below:  
DEQ 9 -2013(Temp), f. & cert. ef. 10- 24-13 thru 4 -22-14  
DEQ 4 -2013, f. & cert. ef. 3- 27-13  
DEQ 14- 2011, f, & cert. ef. 7- 21-11  
DEQ 13 -2011, f. & cert. ef. 7- 21-11  
DEQ 11 -2011, f. & cert. ef. 7- 21-11  
DEQ 5 -2011, f. 4- 29-11, cert. ef. 5- 1-11  
DEQ 1 -2011, f. & cert. ef. 2- 24-11  
DEQ 12 -2010, f. & cert. ef. 10- 27-10  
DEQ 10 -2010(Temp), f. 8- 31-10, ce rt. ef. 9 -1-10 thru 2- 28-11  
DEQ 9 -2009(Temp), f. 12- 24-09, cert. ef. 1 -1-10 thru 6- 30-10  
DEQ 8 -2009, f. & cert. ef. 12- 16-09  
DEQ 15 -2008, f. & cert. ef 12- 31-08  
DEQ 8 -2007, f. & cert. ef. 11- 8-07  
DEQ 7 -2007, f. & cert. ef. 10- 18-07  
DEQ 4 -2002, f. & c ert. ef. 3 -14-02  
DEQ 6 -2001, f. 6- 18-01, cert. ef. 7- 1-01  
DEQ 14 -1999, f. & cert. ef. 10- 14-99, Renumbered from 340- 028-1720  129 
 DEQ 22 -1996, f. & cert. ef. 10- 22-96 
DEQ 19 -1996, f. & cert. ef. 9- 24-96  
DEQ 22 -1995, f. & cert. ef. 10- 6-95  
DEQ 22 -1994, f. &  cert. ef. 10 -4-94  
DEQ 19 -1993, f. & cert. ef. 11- 4-93  
DEQ 12 -1993, f. & cert. ef. 9- 24-93, Renumbered from 340 -020-0155  
DEQ 4 -1993, f. & cert. ef. 3- 10-93  
DEQ 27 -1991, f. & cert. ef. 11- 29-91  
DEQ 12 -1987, f. & cert. ef. 6- 15-87  
DEQ 3 -1986, f. & cert. ef. 2- 12-86  
DEQ 11 -1983, f. & cert. ef. 5- 31-83  
DEQ 23 -1980, f. & cert. ef. 9- 26-80  
DEQ 20 -1979, f. & cert. ef. 6- 29-79  
DEQ 125, f. & cert. ef. 12- 16-76  
DEQ 107, f. & cert. ef. 1 -6-76, Renumbered from 340- 020-0033  
DEQ 63, f. 12- 20-73, cert. ef. 1 -11-74  
DEQ 47, f. 8- 31-72, cert. ef. 9- 15-72 
 
340-216-8020  
Table 2 — Air Contaminant Discharge Permits  
(1) Sources referred to in Table 1 of OAR 340- 216-8010 are subject to air contaminant 
discharge permit fees in Table 2. Title V sources may be subject to the Cleaner Air Oregon 
annual fees and the specific activity permit fees in Table 2, if applicable.  
(2) Requests for waiver of fees must be made in writing to the Director, on a case -by-case 
basis, and be based upon financial hardship. Applicants for waivers must describe the reason for the request and certify financial hardship. The Director may waive part or all of a fee.  130 
  
OAR 340 -216-8020 
Table 2  
Air Contaminant Discharge Permits 
Part 1. Initial Permitting Application Fees: (in addition to first annual fee)  
Short Term Activity ACDP  $4,500.00  
Basic ACDP  $180.00  
Assignment to General ACDP 1 $1,800.00  
Simple ACDP  $9,000.00  
Construction ACDP  $14,400.00  
Standard ACDP  $18,000.00  
Standard ACDP (Major NSR or Type A State NSR)  $63,000.00  
1. DEQ may waive the assignment fee for an existing source requesting to be assigned to a 
General ACDP because the source is subject to a newly adopted area source NESHAP as 
long as the existing source requests assignment within 90 days of notification by DEQ.  
Part 2. Annual Fees: (Due date 12/11 for 1/1 to 12/31 of the following year)  
(applicable July 1, 2022)  
Registration – Motor vehicle surface coating operations  $288.00  
Registration - Dry cleaners using perchloroethylene  $216.00  
Short Term Activity ACDP  $0 
Basic ACDP  (A) #1 -7  
OAR 340 -216-8010 Table 1 
Part A  $648.00 
 
(B) #8 -9  
OAR 340 -216-8010 Table 1 
Part A  $1,469.00 
General ACDP  (A) Fee Class One  $1,469.00  
(B) Fee Class Two  $2,644.00 
(C) Fee Class Three  $3,818.00 
(D) Fee Class Four  $734.00  
(E) Fee Class Five  $245.00 
(F) Fee Class Six  $490.00 
Simple ACDP  (A) Low Fee  $3,917.00  
131 
  
OAR 340 -216-8020 
Table 2  
Air Contaminant Discharge Permits 
(B) High Fee  $7,834.00 
Standard ACDP  $15,759.00  
Greenhouse Gas Reporting, as required by OAR chapter 340, 
Division 215 7.31% of the 
applicable ACDP 
annual fee in Part 2  
Part 3. Cleaner Air Oregon Annual Fees: (Due date 12/11 for 1/1 to 12/31 of 
the following year)  
Basic ACDP  (A) #1 -7  
OAR 340 -216-8010 Table 1 
Part A  $151.00 
(B) #8 -9  
OAR 340-216-8010 Table 1 
Part A  $302.00 
General ACDP  (A) Fee Class One  $302.00  
(B) Fee Class Two  $544.00  
(C) Fee Class Three  $786.00  
(D) Fee Class Four  $151.00  
(E) Fee Class Five  $50.00  
(F) Fee Class Six  $100.00  
Simple ACDP  (A) Low Fee  $806.00  
(B) High Fee  $1,612.00  
Standard ACDP $3,225.00  
1. DEQ may extend the payment due date for dry cleaners or gasoline dispensing facilities 
until March 1st.  
Part 4. Specific Activity Fees:  
Notice of Intent to Construct Type 21 $720.00 
Permit Modification  
 (A) Non -Technical  $432.00  
(B) Basic Technical  $540.00  
132 
  
OAR 340 -216-8020 
Table 2  
Air Contaminant Discharge Permits 
(C) Simple Technical  $1,800.00  
(D) Moderate 
Technical  $9,000.00 
(E) Complex 
Technical  $18,000.00 
Toxic Air Contaminant 
Permit Addendum 
Modification  (A) Non -Technical  $432.00 
(B) Basic Technical  $432.00  
(C) Simple Technical  $1,440.00  
(D) Moderate 
Technical  $7,200.00 
(E) Complex 
Technical  $14,440.00 
Major NSR or Type A State NSR Permit Modification  $63,000.00  
Modeling Review (outside Major NSR or Type A State NSR)  $9,000.00  
Public Hearing at Source's Request  $3,600.00  
State MACT Determination  $9,000.00  
Compliance Order Monitoring 2 $180.00/month  
Part 5. Late Fees:  
8-30 days late  5% 
31-60 days late  10% 
61 or more days late  20% 
1. The Type 2 Notice of Intent to Construct does not apply to existing Basic ACDP or 
General ACDP sources.  
.2. This is a one- time fee payable when a compliance order is established in a permit or a 
DEQ order containing a compliance schedule becomes a fina l order of DEQ and is based 
on the number of months DEQ will have to oversee the order. 
NOTE : See history of this table under OAR 340 -216-0020.  
 
  
133 
 Climate Protection Program, Division 271  
 
340-271-0010  
Purpose and Scope  
(1) This division establishes rules and requirements for the Climate Protection Program for 
certain air contamination sources that emit greenhouse gases or that cause greenhouse gases to be emitted. 
(2) Climate change caused by anthropogenic greenhouse gas emissions has det rimental 
effects on the overall public welfare of the State of Oregon. Reducing greenhouse gas 
emissions and mitigating climate change will improve the overall public welfare of Oregon. In particular, reducing greenhouse gas emissions will improve the welf are of environmental 
justice communities.  
(a) Fuel combustion and industrial processes result in emissions of greenhouse gases, which are air contaminants that cause climate change;  
(b) Reducing greenhouse gas emissions may also reduce emissions of other a ir 
contaminants, which may improve air quality for Oregon communities; and 
(c) Environmental justice communities in Oregon are disproportionately burdened by air 
contamination, including through disproportionate risk of the impacts of climate change. 
(3) T he purposes of the Climate Protection Program are to reduce greenhouse gas emissions 
from sources in Oregon, achieve co -benefits from reduced emissions of other air 
contaminants, and enhance public welfare for Oregon communities, particularly 
environmental  justice communities disproportionately burdened by the effects of climate 
change and air contamination. To support these purposes, this division:  
(a) Requires that covered entities reduce greenhouse gas emissions;  
(b) Supports reduction of emissions of ot her air contaminants that are not greenhouse gases;  
(c) Prioritizes reduction of greenhouse gases and other air contaminants in environmental justice communities;  
(d) Provides covered entities with compliance options to minimize disproportionate business and consumer economic impacts associated with meeting the Climate Protection Program 
requirements; and  
(e) Allows covered fuel suppliers to comply with the Climate Protection Program requirements in part through contributing community climate investment funds to support 
projects that reduce greenhouse gas emissions and prioritize benefits for environmental justice communities in Oregon. 134 
 (4) DEQ administers this division in all areas of the State of Oregon and subject to the 
requirements in this  division and OAR 340-200-0010(3), LRAPA is designated by the EQC 
to implement OAR 340 -271- 0150(3) of this division within its area of jurisdiction.  
(5)(a) Whenever the DEQ Director has good cause to believe that any person is engaged or is about to engage in any acts or practices which constitute a violation of this division, the Director may authorize DEQ to institute actions or proceedings for legal or equitable remedies to enforce compliance thereto or to restrain further violations.  
(b) The proceedings authorized by subsection (a) may be instituted without the necessity of prior DEQ notice, hearing and order. 
(c) The provisions of this section are in addition to and not in substitution of any other civil 
or criminal enforcement provisions available to D EQ. This includes, without limitation, the 
authority to impose civil penalties and issue orders according to ORS Chapter 468.090 to 468.140 and OAR chapter 340, divisions 11 and 12. 
(6) If a ny dates  under this division occur on a Saturday, Sunday, or a state holiday, the 
deadline is extended to the following business day 
Statutory/Other Authority: ORS 468.020, 468A.025, 468A.040, 468A.050, 468A.135 & 468.100 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468A.050, 468A.135, 468.035, 468A.010, 468A.015, 468A.045 & 468.100 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-0020  
Definitions  
The definitions in OAR 340-200-0020, OAR 340-215-0020, and this rule apply to this 
division. If the same term is defined in this rule and either or both OAR 340-200-0020 and 
OAR 340-215- 0020, the definition in this rule applies to this division. If the same term is 
defined in OAR 340-200-0020 and OAR 340-215-0020, but not in this rule, then the definition in OAR 340 -215-0020 applies to this division. 
(1) “Air contamination source”  has the meaning given the term in ORS 468A.005. Air 
contamination sources include, without limitation, stationary sources, fuel suppliers, in- state 
producers, and local distribution companies. 
(2) “Best available emissions reduction order” or “BAER order” means a DEQ order establishing required actions the owner or operator of a covered stationary source must take to limit covered emissions from the covered stationary source. The BAER order will identify 
the conditions and requirements that must be include d in the CPP permit addendum.  135 
 (3) “Biomass -derived fuels” has the meaning given the term in OAR 340- 215-0020. 
Biomass- derived fuels include, without limitation, biomethane, biodiesel, renewable diesel, 
renewable propane, woody biomass, and ethanol.  
(4) “Ca p” means the total number of compliance instruments generated by DEQ for each 
calendar year.  
(5) “Climate Protection Program permit addendum” or “CPP permit addendum” means 
written authorization that incorporates the requirements of this division into a pe rmit by 
amending an Air Contaminant Discharge Permit or a Title V Operating Permit.  
(6) “Climate Protection Program permit” or “CPP permit” means a permit issued to a 
covered fuel supplier according to this division.  
(7) “Community climate investment credi t” or “CCI credit” or “credit” means an instrument 
issued by DEQ to track a covered fuel supplier’s payment of community climate investment funds, and which may be used in lieu of a compliance instrument, as further provided and 
limited in this division.  
(8) “Community climate investments,” “community climate investment funds” or “CCI 
funds” means money paid by a covered fuel supplier to a community climate investment 
entity to support implementation of community climate investment projects and any interest  
that accrues on the money while it is held by a CCI entity or subcontractor. 
(9) “Community climate investment entity” or “CCI entity” means a nonprofit organization 
that has been approved by DEQ as a CCI entity and that has entered into a written agreeme nt 
with DEQ consistent with OAR 340 -271-0920 to implement projects supported by 
community climate investment funds.  
(10) “Compliance instrument” means an instrument issued by DEQ that authorizes the emission of one MT CO2e of greenhouse gases. Compliance i nstruments may not be divided 
into fractions.  
(11) “Compliance obligation” means the total quantity of covered emissions from a covered fuel supplier rounded to the nearest metric ton of CO2e.  
(12) “Compliance period” means a period of multiple consecutive  calendar years, as 
described in OAR 340- 271-0440. 
(13) “Covered emissions” means the greenhouse gas emissions described in any of 
subsections OAR 340- 271-0110(3)(b), (4)(b) and (5)(b), for which covered entities may be 
subject to the requirements of this division.  
(14) “Covered entity” means an air contamination source subject to the requirements of this 
division. A covered entity may be either a covered fuel supplier, a covered stationary source, 
or both.  136 
 (15) “Covered fuel supplier” means an air contamination source that is either:  
(a) A fuel supplier or in -state producer as described in OAR 340 -271-0110(3); or 
(b) A local distribution company as described in OAR 340-271-0110(4). 
(16) “Covered stationary source” means an air contamination source described in OAR 340-
271-0110(5). 
(17) “Designated representative” means the person responsible for certifying, signing, and 
submitting any registration, report, or form required to be submitted according to this division, on behalf of a covered entity. For the owner or operator of a covered stationary source with an Oregon Title V Operating Permit, the designated representative is the responsible official and certification must be consistent with OAR 340 -218-0040(5). 
(18) “Environmental justice communities”  means communities of color, communities 
experiencing lower incomes, tribal communities, rural communities, coastal communities, communities with limited infrastructure and other communities traditionally underrepresented in public processes and adversely harmed by environmental and health hazards, including seniors, youth and persons with disabilities. 
(19) “Evaluation period” means a period of multiple consecutive calendar years, as 
described in Table 5 in OAR 340-271-9000, that DEQ uses to evaluate the number of 
compliance instruments to distribute to each covered fuel supplier that is not a local 
distribution company.  
(19) ”Existing source” means a source that is operating under the authority of either a 
current Air Contaminant Discharge Pe rmit or Title V Operating Permit or, when the term of 
an issued permit has expired, under the authority of OAR 340-216-0082(1) or OAR 340-
218-0120(2) and 340- 218-0130(2).  
(20) “New source” means a source that is not operating under the authority of either a 
current Air Contaminant Discharge Permit or Title V Operating Permit or, when the term of 
an issued permit has expired, under the authority of OAR 340-216-0082(1) or OAR 340 -
218-0120(2) and 340- 218-0130(2).  by December 31, 2021 did not commence construction 
and did not submit all necessary applications to DEQ according to OAR chapter 340 
divisions 210 and 216. 
(21) “Nominal electric generating capacity” has the meaning given in ORS 469.300. 
(22) “Shut down” means that all operations of a covered entity are permanently shut down, including but not limited to decommissioning and cancelling air permits. Permanent shutdown may include continued operations of space heaters and water heaters as necessary to support decommissioning activities. 137 
 (23) “Related entity” means any direct or indirect parent company, direct or indirect 
subsidiary, company that shares ownership of a direct or indirect subsidiary, or company 
under full or partial common ownership or control. 
Statutory/Other Authority: ORS 4 68.020, 468A.025, 468A.040 & 468A.050 
Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468A.050, 468.035, 
468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-0110  
Covered Entity and Covered Emissions Applicability  
(1) Calculations of covered emissions, compliance obligations and distribution of compliance instruments will be based on emissions data and information in emissions data reports submitted by a person described in this rule and required according to OAR chapter 340, division 215, which may be subject to verification according to OAR chapter 340, division 272. For any person that does not submit sufficient information in compliance with OAR chapter 340, divisions 215 and 272, calculations will be informed by additional best data available to DEQ. For any person that has not registered and reported according to division 215, such calculations will be based on the best data available to DEQ, following all reporting requirements and assumptions that would be applicable had the person reported according to that division.  
(2) A covered entity is subject to the requirements of this division for its covered emissions described in this rule. A person remains a covered entity until cessation is met according to OAR 340 -271-0130. 
(3) Appli cability for fuel suppliers and in -state producers. A person is a covered fuel 
supplier if the person is described in subsection (a) and has annual covered emissions described in subsection (b) in any applicability determination calendar year that equal or exceed the threshold for applicability listed in Table 1 in OAR 340-271-9000. All persons that are related entities must aggregate their emissions together to determine applicability and each becomes a covered fuel supplier if applicability is met. When a pplicability is met, 
each person is a covered fuel supplier beginning with the calendar year a person becomes a covered fuel supplier, as provided in Table 1 in OAR 340-271-9000. Once a person is a covered fuel supplier, the person remains a covered fuel supplier until the person has met the cessation requirements according to OAR 340-271-0130. 
(a) The person is a fuel supplier or in -state producer that imports, sells, or distributes fuel for 
use in Oregon, and is one or more of the following: 
(A) A dealer,  as that term is defined in ORS 319.010 that is subject to the Oregon Motor 
Vehicle and Aircraft Fuel Dealer License Tax in OAR chapter 735, division 170; 138 
 (B) A seller, as that term is defined in ORS 319.520, that is subject to the Oregon Use Fuel 
Tax in O AR chapter 735, division 176;  
(C) A person that produces, imports, sells, or distributes gasoline or distillate fuel oil for use 
in Oregon and that is not subject to the Oregon Motor Vehicle and Aircraft Fuel Dealer 
License Tax or the Oregon Use Fuel Tax i n OAR chapter 735, divisions 170 and 176; or  
(D) A person that either produces propane in Oregon or imports propane for use in the state.  
(b) Except as provided in paragraph (B), covered emissions include emissions described in 
paragraph (A). 
(A) Covered emissions include emissions of anthropogenic greenhouse gases in metric tons 
of CO2e that would result from the complete combustion or oxidation of the annual quantity 
of propane and liquid fuels (including, for example and without limitation, gasoline and 
petroleum products) imported, sold, or distributed for use in this state.  
(B) Covered emissions do not include:  
(i) Emissions that are from the combustion of biomass -derived fuels;  
(ii) Emissions that are from the combustion of fuels used for avia tion including, for example 
and without limitation, aviation gasoline, kerosene -type jet fuel, and alternative jet fuel; and  
(iii) Emissions described in 40 CFR part 98 subpart W – Petroleum and Natural Gas Systems.  
(4) Applicability for local distribution  companies. A person is a covered fuel supplier if the 
person is described in subsection (a) and has annual covered emissions described in subsection (b) in 2018 or any subsequent calendar year, unless the person has met the 
cessation requirements accordin g to OAR 340 -271-0130. 
(a) The person is a local distribution company that either produces natural gas, compressed 
natural gas, or liquefied natural gas in Oregon, or that imports, sells, or distributes natural 
gas, compressed natural gas, or liquefied nat ural gas to end users in the state.  
(b) Except as provided in paragraph (B), covered emissions include emissions described in 
paragraph (A). 
(A) Covered emissions include emissions of anthropogenic greenhouse gases in metric tons 
of CO2e that would result from the complete combustion or oxidation of the annual quantity of natural gas imported, sold, or distributed for use in this state. 
(B) Covered emissions do not include:  
(i) Emissions that are from the combustion of biomass -derived fuels;  139 
 (ii) Emissions described in 40 CFR part 98 subpart W – Petroleum and Natural Gas 
Systems;   
(iii) Emissions that result from non -combustion- related processes that use natural gas, as 
determined by DEQ ; Emissions avoided where the use of natural gas results in greenhouse 
gas emissions captured and stored, if sufficiently documented by information provided to 
DEQ; and 
(iv) Emissions from natural gas delivered to an air contamination source that is an electric power generating plant with a total nominal electric generating c apacity greater than or 
equal to 25 megawatts. 
(5) Applicability for stationary sources. A person is a covered stationary source if the person 
is described in subsection (a), unless the person has met the cessation requirements according to OAR 340-271-0130. 
(a) The person is one or more either or both of the following:  
(A) The person owns or operates an existing source required to obtain either a Title V 
Operating Permit or an Air Contaminant Discharge Permit and that has  actual  annual 
covered emissions described in subsection (b) that equal or exceed 25,000 MT CO2e in 2018 or in any subsequent calendar year; or  
(B) The person owns or operates a new source, or proposes to own or operate a new source, required to obtain either or both a Title V Operating Permit or an Air Contaminant 
Discharge Permit and that has a potential to emit annual covered emissions described in 
subsection (b) that will equal or exceed 25,000 MT CO2e per in any calendar year ; or. 
(C) The person owns or operates a n existing source that  is not a covered stationary source 
under (A), proposes to make a modification under OAR 340-216- 0040(3), OAR 340-218-
0170, OAR 340-218-0180, or OAR 340-218-0190, or a Type 2, 3 or 4 change under OAR 
340-210-0225 to  their source  and:   
(i) The modification would i ncrease the source’s potential to emit covered emissions 
described in subsection (b) by 10,000 MT  CO2e per calendar year or more , and; 
(ii) After the modification , the source’s  potential to emit covered emissions described in 
subsection (b) would equal  or exceed 25,000 MT CO2e per calendar year.  
(b) Except as provided in paragraph (B), covered emissions include emissions described in paragraph (A). 
(A) Covered emissions include emissions of anthropogenic greenhouse gases in metric tons of CO2e that are from either or both processes or the combustion of solid or gaseous fuels, including emissions from combustion for both energy production and processes. 140 
 (B) Covered emissions do not include: 
(i) Emissions that are from the combustion of biomass -derived fuels;  
(ii) Biogenic CO2 emissions from solid fuels;  
(iii) Emissions that are from the combustion of liquid fuels or propane; (iv) Emissions from natural gas, compressed natural gas, or liquefied natural gas used on -
site that was delivered by a local distribution company; 
(v) Emissions described in 40 CFR part 98 subpart HH – Municipal Solid Waste Landfills;  
(vi) Emissions described in 40 CFR part 98 subpart TT – Industrial Waste Landfills;  
(vii) Emissions from an air contamination source that is owned or operated by an interstate 
natural gas pipeline that is operating under authority of a certificate of public convenience and necessity issued by the Federal Energy Regulatory Commission; and 
(viii) Emissions from an air contamination source that is an electric power generating plant 
with a total nominal electric gen erating capacity greater than or equal to 25 megawatts.  
Statutory/Other Authority: ORS 468.020, 468A.025, 468A.040 & 468A.050 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468A.050, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 18 -2022, temporary amend filed 11/18/2022, effective 11/18/2022 through 05/16/2023
 
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021  
 
340-271-0120  
Changes in Covered Entity Ownership and Changes to Related Entities  
(1) Changes in ownership or operational control. 
(a) If a covered entity undergoes a change in ownership or operational control, the new 
person that owns or operates the covered entity must notify DEQ in writing within 30 days of the ownership or operational control change. The person must submit a complete and accurate notification, including providing the following information: 
(A) The name of the previous owner or operator; 
(B) The name of the new owner or operator;  
(C) The date of ownership or operator change; 141 
 (D) Name of the designated representative;  
(E) If the covered entity is a covered fuel supplier that is not a local distribution company 
Iinformation about each person that was a related entity prior to the change in ownership or 
operational control , subject to any regulations  and that wa s required to report emissions 
according to in  OAR chapter 340, d ivision 215, including legal name, full mailing address, 
and whether each is a covered fuel supplier and holds a CPP permit; and 
(F) If th e covered entity is a covered fuel supplier that is not a local distribution company, 
Iinformation about each person that is a related entity after the change in ownership or 
operational control , and that is required to report emissions according subject to any 
regulations in  to OAR chapter 340, division 215, including legal name, full mailing address, 
and whether each is a covered fuel supplier and holds a CPP permit. 
(b) The covered entity continues to be a covered entity following a change in ownership or 
operational control, until it meets the cessation re quirements in OAR 340-271-0130. Any 
other covered entity that was a related entity also continues to be a covered entity following the change in ownership or operational control, until it meets the cessation according to OAR 340 -271-0130. 
(c) Following a c hange in ownership or operational control, a covered fuel supplier that 
holds a compliance instrument or CCI credit according to OAR 340-271-0430 or OAR 340-271-0830 continues to hold the compliance instrument or CCI credit according to each rule, as applicable.  
(2) Changes to related entities of covered fuel suppliers.  
(a) If a person subject to any regulations in OAR chapter 340, division 215, becomes a new 
related entity to a covered fuel supplier that is not a local distribution company due to a 
change in ownership or operational control, the designated representative of the covered fuel supplier must notify DEQ in writing , on a form approved by DEQ, within 30 days of the 
ownership or operational control change. The designated representative must submit a complete and accurate notification, including providing the following information:  
(A) Information about the new related entity, including legal name, full mailing address, and whether the person is a covered fuel supplier and holds a CPP permit; 
(B) The  name of the previous owner or operator of the new related entity; 
(C) The name of the new owner or operator of the new related entity;  
(D) The date of ownership or operator change for the new related entity; and 
(E) Information about all other related entities subject to any regulations in OAR chapter 
340, including legal names, full mailing addresses, and whether each is a covered fuel supplier and holds a CPP permit. 142 
 (b) If the person that is the new related entity to a covered fuel supplier identified in 
paragraph (a)(A) is not already a covered fuel supplier, the person:  
(A) Becomes a covered fuel supplier beginning with the date of ownership or operator change; 
(B) Must apply to DEQ for a CPP permit according to OAR 340-271-0150(1) (a)(B); and  
(C) If the person is a covered fuel supplier, the person will have compliance obligations 
beginning with covered emissions from the calendar year in which the ownership or operator change occurred.  
Statutory/Other Authority: ORS 468.020, 468A.025, 468A.040 & 468A.050 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468A.050, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-0130  
Cessation of Covered Entity Applicability  
(1) Cessation for covered fuel suppliers.  
(a) A pers on that is a covered fuel supplier as described in OAR 340 -271-0110 remains a 
covered fuel supplier until the person receives written notification from DEQ after either or both: 
(A) The person’s annual covered emissions are 0 (zero) MT CO2e for six consecu tive 
calendar years; . If the person is not a local distribution company, the covered emissions of 
the person’s related entities must also be 0 (zero) MT CO2e for the same six consecutive 
calendar years;  or 
(B) The person was designated a covered fuel supplier in OAR 340-271-0110(3) , the sum of  
and its annual covered emissions and the annual covered emissions of its related entities are 
less than 25,000 MT CO2e for six consecutive calendar years and the person applies to DEQ according to subsection (c).  
(b) After a covered fuel supplier identified according to paragraph (a)(A) demonstrates c
ompliance with compliance obligations for the years up to and including the years 
described in paragraph (a)(A), DEQ will notify the designated representative of the covered fuel supplier in writing that cessation is met.  143 
 (c) In order for cessation according to paragraph (a)(B) to take effect, a covered fuel supplier 
must apply to cease being a covered fuel supplier by submitting the following information to DEQ on a f orm approved by DEQ: 
(A) Information about the covered fuel supplier, including:  
(i) Name and full mailing address, and website; and  
(ii) Designated representative’s contact information including name, title or position, phone number, and email address; 
(B) I f the person is not a local distribution company I information about each related entity 
required to report emissions according to subject to any regulations in OAR chapter 340 , 
division 215, for each of the six consecutive calendar years, including legal name, full 
mailing address, and whether each is a covered fuel supplier and holds a CPP permit; 
(C) Information about remaining requirements that must be met according to this division at the time the application is submitted to DEQ; and  
(D) The following attestation, signed by the designated representative of the covered fuel supplier: 
I certify under penalty of perjury under the laws of the State of Oregon that to the best of my 
knowledge and belief, the information provided in this form is true, accurate, and complete. [Covered fuel supplier] meets the eligibility for cessation as a covered fuel supplier according to Oregon Administrative Rules chapter 340, division 271. I understand that ceasing to be a covered fuel supplier means that [covered fuel supplier] will also cease to hold any compliance instruments and CCI credits. 
(d) After the covered fuel supplier applying for cessation according to paragraph (a)(B) and 
subsection (c) demonstrates compliance with compliance obligations for the years up to and including the years described in paragraph (a)(B), DEQ will notify the designated representative of the covered fuel supplier in writing that the application for cessation is approved and t hat cessation is met.  
(e) A person that ceases to be a covered fuel supplier according to this section must comply with all remaining applicable recordkeeping requirements of this division from the last date on which the person was a covered fuel supplier. 
(f) When a person ceases to be a covered fuel supplier:  
(A) The cessation does not change the compliance obligation for any year for which the 
person has already demonstrated compliance;  
(B) Any remaining compliance instruments held by the person will be retired, held in reserve, or distributed by DEQ according to OAR 340-271-0430(3); and 144 
 (C) Any remaining community climate investment credits held by the person will be 
canceled according to OAR 340-271-0830(1)(c). 
(2) Cessation for covered stationary sources.  
(a) A person that is a covered stationary source as described in OAR 340 -271-0110 remains 
a covered stationary source until either of the following occur: (A) The person’s operations are changed such that all greenhouse gas emitting pro cesses and 
operations cease to operate or are shut down. In order for cessation to take effect, the person 
must submit a written notification to DEQ certifying the cessation of all greenhouse gas emitting processes and operations; or  
(B) The person’s cover ed emissions are less than 25,000 MT CO2e for five consecutive 
calendar years and the person has fully complied with any applicable BAER order and any related reporting requirements and has submitted any remaining required BAER assessment and five- year BAE R report. In order for cessation to take effect, DEQ will notify the 
covered stationary source that cessation is met.  
(b) This section does not apply to seasonal operational cessations or other temporary cessation of operations.  
(c) A person that ceases to  be a covered stationary source according to this section must 
comply with all remaining applicable recordkeeping requirements of this division from the last date on which the person was a covered stationary source.  
(3) Any person that ceases to be a cover ed entity according to this rule must resume meeting 
the requirements of this division for any future year in which applicability is met.  
Statutory/Other Authority: ORS 468.020, 468A.025, 468A.040 & 468A.050 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468A.050, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-0150  
Covered Entity Permit Requirements  
(1) A person described in either or both OAR 340-271-0110(3) or (4) must apply for a CPP permit as provided in this section. 
(a) Th e person must apply for a CPP permit according to subsections (b) and (c) by the 
following deadlines: 145 
 (A) If DEQ notifies the person in writing that the person is a covered fuel supplier, then the 
person must apply to DEQ for a CPP permit within 30 days of the notification or by another date DEQ specifies in the notification that is at least 30 days after the date of the notification;  
(B) If DEQ does not provide a notification according to paragraph (A), then the person must apply to DEQ for a CPP pe rmit by whichever is later of:  
(i) February 14 of the calendar year a person becomes a covered fuel supplier; or 
(ii) April  March  15 31 of the year after the first applicability determination calendar year 
that the person’s  emissions equal or exceed the threshold in Table 1 in OAR 340-271-
9000becomes a covered fu el supplier ; or 
(C) If there was a change in ownership or operational control according to OAR 340-271-0120(2), then the person must apply to DEQ for a CPP permit within 45 days of the change in ownership or operational control. 
(b) A person that submits a CPP permit application to DEQ must submit a complete and 
accurate application. The application for a CPP permit must be submitted to DEQ using a form approved by DEQ and include: 
(A) Identify ing information about the covered fuel supplier including name, full mailing 
address, and website, and designated representative’s contact information including name, 
title or position, phone number, and email address; 
(B) If the person is a covered fuel supplier that is not a local distribution company, 
Iinformation about each related entity  required to report emissions according to  subject to 
any regulations in OAR chapter 340,  division 215, including legal name, full mailing 
address, and whether each is a covered fuel supplier and holds a CPP permit; and 
(C) The following attestation, signed by the designated representative of the person considered a covered fuel supplier; 
I certify under penalty of perjury under the laws of the State of Oregon that to  the best of my 
knowledge and belief, the information provided in this form is true, accurate, and complete. 
[Covered entity] meets the Climate Protection Program applicability requirements described in OAR 340-271-0110 and requests a permit with the under standing that [covered entity] 
must comply with such permit as provided in Oregon Administrative Rules chapter 340, division 271. 
(c) DEQ may issue a CPP permit to a covered fuel supplier that submits a complete and accurate application. The permit may contain all applicable provisions of this division and 
such other conditions as DEQ determines are necessary to implement, monitor and ensure compliance with this division.  146 
 (2) New and modified stationary sources  
(a) The owner or operator of a new source that is a covered stationary source may not emit 
any covered emissions prior to being issued a BAER order and a permit according toas 
described in  subsection (3)(c)  and OAR 340-271-0330(1) . 
(b) The owner or operator of a n existing  source that is proposing a modification and is 
required to complete a BAER assessment under OAR 340-271-0310(1)(c) may not construct 
the modification or emit any covered emissions from the modification prior to being issued a 
BAER order and approved permit modification as described in  subsection (3)(d).  
(3)(a) The owner or operator of a n existing  covered stationary source required to apply for a 
CPP permit addendum according to OAR 340-271- 0330(1) must s ubmit a complete and 
accurate application to DEQ or LRAPA, as applicable, that complies with and includes 
information identified in this section.   
(a) The application must include the following: 
(A) Identifying information about the covered stationary source, including name and the name of the person that owns or operates the covered stationary source, full mailing address, the physical address of the covered stationary source, and a description of the nature of business being operated, the name, phone number and email address of the designated representative who is responsible for compliance with the permit, the permit number for an existing source, and the SIC or NAICS code of the covered stationary source; 
(B) The name of a person authorize d to receive requests from DEQ for additional data and 
information; 
(C) The date DEQ notified the owner or operator of the covered stationary source of the 
BAER order established according to OAR 340-271-0320; 
(D) A BAER implementation plan that includes the following: 
(i) Identification of the actions that the owner or operator of the covered stationary source 
will take to comply with the BAER order; and  
(ii) The schedule for implementing the requirements in the BAER order, consistent with any deadlines pr ovided by DEQ in the BAER order, if applicable, and including an estimate of 
when all requirements from the BAER order will be completed; 
(E) Any other information requested by DEQ; and 
(F) The following attestation, signed by the designated representative of the covered 
stationary source;  147 
 I certify under penalty of perjury under the laws of the State of Oregon that to the best of my 
knowledge and belief, the information provided in this form is true, accurate, and complete. [Covered entity] meets the Climate Protection Program applicability requirements described in OAR 340-271-0110 and requests a permit with the understanding that [covered entity] must comply with such permit as provided in Oregon Administrative Rules chapter 340, division 271. 
(b) DEQ or LRAPA, as applicable, may issue a CPP permit addendum to the owner or operator of a covered stationary source that submits a complete and accurate permit modification application  under subsection (a), consistent with the requirements of OAR 
chapter 340, divisions 216 and 218, as applicable. The CPP permit addendum will be issued as a Category I I permit action according to OAR chapter 340, division 209. A CPP permit 
addendum will amend the covered stationary source’s Air Contaminant Discharge Permit or Title  V Operating Permit  until the requirements in the addendum can be incorporated into 
the operating permit . The CPP permit addendum may will contain all applicable provisions 
of this division and such other conditions as DEQ or LRAPA, as applicable, determines are necessary to implement, monitor and ensure compliance with the permit and this division.  
(c) If DEQ or LRAPA approves an application for an Air Contaminant Discharge Permit or T
itle V Operating Permit submitted by the owner or op erator of a new source, then DEQ or 
LRAPA, as applicable, will incorporate the CPP conditions into the new operating permit 
Air Contaminant Discharge Permit or Title V Operating Permit and will not issue a separate 
CPP permit addendum. Such CPP conditions may contain will include all applicable 
provisions of this division and such other conditions as DEQ or LRAPA, as applicable, determines are necessary to implement, monitor and ensure compliance with the permit and this division.  
(d) If DEQ or LRAPA approv es a
 n application for a modification of an Air Contaminant 
Discharge Permit or Title V Operating Permit submitted by the owner or operator of a n 
existing source that is required to undertake a BAER assessment  described in OAR 340-271-
0310(1)(c), then DEQ or LRAPA, as applicable, will incorporate the CPP conditions into the 
modified  Air Contaminant Discharge Permit or Title V Operating Permit and will not issue a 
separate CPP permit addendum. Such CPP conditions will include  all applicable provisions 
of this division and such other conditions as DEQ or LRAPA, as applicable, determines are 
necessary to implement, monitor and ensure compliance with the permit and this division.  
Statutory/Other Authority: ORS 468.020, 468A.025, 468A.040 & 468A.135 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468A.135, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
 148 
 340-271-0310  
Best Available Emissions Reduction Assessments for Covered Stationary Sources 
(1) Requirement to conduct a BAER assessment.  
(a) When notified in writing by DEQ, the owner or operator of a covered stationary source 
described in OAR 340-271-0110(5)(a)(A) must submit a complete and accurate BAER assessment according to this rule. The owner or operator of the covered stationary source must submit a complete BAER assessment to DEQ not later than nine months following the date of DEQ’s notice, unless DEQ has identified a later deadline in its notice or DEQ approves an extension according to section (6).  
(b) The owner or operator of a new source described in OAR 340-271- 0110(5)(a)(B) must 
submit a complete and accurate BAER assessment completed according to this rule with its permit application submitted according to OAR chapter 340, division 216, or its notice of construction application submitted according to OAR chapter 340, division 210. 
(c) Modifications .  
(A) A s ource that is a covered stationary source described in OAR 340 -271-0110(5)(a)(C) 
must complete a BAER assessment if notified in writing by DEQ. DEQ will require a BAER 
assessment at the time of the modification only if DEQ determines that the modification 
represents a significant change to the equipment or processes that emit covered emissions at 
the source. 
(B) If the modification described in OAR 340 -271-0110(5)(a)(C) is a notice of construction 
for a Type 2 change required under OAR 340-210-0230, DEQ will notify the source not 
later than 60 days after submittal of the notice of construction if a BAER assessment is 
required. Upon receipt of that notification, the owner or operator of the source must submit a 
complete and accurate BAER assessment completed ac cording to this rule and an 
application for a permit modification submitted according to OAR chapter 340, division 216 
or 218, as applicable. Notwithstanding OAR 340-210-0225(2) and (3), such permit 
modification application is a Type 3 change as described in OAR chapter 340, division 210. 
(2) BAER assessment requirements. BAER assessments submitted to DEQ must include the following:  
(a) A description of the covered stationary source’s production processes and a flow chart of each process;  
(b) Identification  of all fuels, processes, equipment, and operations that contribute to the 
covered stationary source’s covered emissions, including: 
(A) Estimates of annual average covered emissions identified in OAR 340 -271-0110(5)(b). 
For existing covered stationary sources, estimates must be of current annual average covered 149 
 emissions. For new sources  and existing sources proposing a modification , estimates must 
be of anticipated annual average potential to emit covered emissions. Emissions must be 
identified in MT CO2e, following methodologies identified in OAR chapter 340, division 
215. This must also include and distinguish quantities and covered emissions of each fuel 
used to control air contaminants that are not greenhouse gases; and 
(B) Estimates of current a nnual average and anticipated type and annual quantity of all fuels 
used or proposed to be used by the covered stationary source , and anticipated annual average 
fuel usage for new sources ; 
(c) Identification and description of all available fuels, processes , equipment, technology, 
systems, actions, and other strategies, methods and techniques for reducing covered 
emissions described in OAR 340 -271-0110(5)(b). Strategies considered must include but are 
not limited to the strategies used by other sources in this state or in other jurisdictions that produce goods of comparable type, quantity, and quality; and 
(d) An assessment of each of the following for each strategy identified in subsection (c): 
(A) An estimate of annual average covered emissions reductions achieved if the strategy 
were implemented compared to the emissions estimated in paragraph (b)(A);  
(B) Environmental and health impacts, both positive and negative, if the strategy were implemented, including any impacts on air contaminants that are not gre enhouse gases and 
impacts to nearby communities;  
(C) Energy impacts if the strategy were implemented, including whether and how the strategy would change energy consumption at the covered stationary source, including impacts related to any fuel use that re sults in anthropogenic greenhouse gas emissions. Any 
energy-related costs must be included in the economic impacts assessment in paragraph (D), not the energy impacts assessment;  
(D) Economic impacts if the strategy were implemented, including operating costs and the costs of changing existing processes or equipment or adding to existing processes and equipment. Any energy- related costs must be included in the economic impacts assessment, 
not the energy impacts assessment in paragraph (C). The economic impacts assessment must include both costs and cost savings (benefits);  
(E) An estimate of the time needed to fully implement the strategy at the covered stationary source; and  
(F) A list of the information, resources, and documents used to support development of the BAER assessment, including, if available, links to webpages that provide public access to supporting documents. 
(3) Upon receipt of a BAER assessment described in section (2), DEQ will review the submittal and if DEQ determines that any  additional information, corrections, or updates are 150 
 required then DEQ may provide the owner or operator of the covered stationary source with 
a written request to provide such information by a certain date or DEQ may issue the BAER order based on the information it has available. If DEQ requests that the owner or operator of the covered stationary source revise its BAER assessment according to this section, the owner or operator must provide such information no later than the deadline provided by DEQ.  
(4) Five year BAER reports.  
(a) Every five years following the date that DEQ issued a BAER order, the owner or 
operator of a covered stationary source must submit to DEQ a five year BAER report that 
includes an update of the information described in subsection s (2)(a) through (c).  
(b) If one or more new strategies are identified in a five year BAER report required in subsection (a) that have not previously been evaluated in a BAER assessment, DEQ may notify the owner or operator of the covered stationary source and require that it conduct a complete BAER assessment according to section (2) and submit it to DEQ. Such complete BAER assessment must also include:  
(A) Evaluation of any new strategies identified and any previously identified strategies using any new i nformation available at the time the assessment is being conducted; and  
(B) Current status and analysis of the implementation of requirements in any prior BAER order(s).  
(5) When notified in writing by DEQ, the owner or operator of a covered stationary sou rce 
identified in section (1) may be required to conduct and submit an updated complete BAER assessment conducted according to this rule, in accordance with the following: 
(a) DEQ may not require the owner or operator of a covered stationary source to comp lete 
an updated BAER assessment within five years of the date of submission of the most recently completed BAER assessment  unless the source is proposing a modification and is 
required to complete a new BAER assessment under OAR 340 -271-0310(1)(c) . However , if 
DEQ determines the owner or operator of a covered stationary source submitted information that it knew or should have known was false, inaccurate, or incomplete to DEQ, then DEQ may require the owner or operator of the covered stationary source to com plete an updated 
BAER assessment within five years of the date of submission of the most recently completed BAER assessment;  
(b) The updated BAER assessment must include assessment of new strategies and previously identified strategies and any new informat ion available at the time the assessment 
is being conducted;  
(c) The owner or operator of the covered stationary source must include current status and analysis of the implementation of requirements in any prior BAER order; and  151 
 (d) The owner or operator of the covered stationary source must submit the updated BAER 
assessment to DEQ not later than nine months following the date of DEQ’s notice, unless DEQ has identified a later deadline in the notice or DEQ approves an extension according to section (6). 
(6) The owner or operator of a covered stationary source required to conduct a BAER 
assessment as described in sections (1) or (5) may request an extension of time to complete the BAER assessment by providing DEQ with a written request no fewer than 30 day s prior 
to the submittal deadline. DEQ may grant an extension based on the following criteria: 
(a) The owner or operator of the covered stationary source has demonstrated progress in 
completing the submittal; and 
(b) A delay is necessary, for good cause sh own by the owner or operator of the covered 
stationary source, related to obtaining more accurate or new data, performing additional 
analyses, or addressing changes in operations or other key parameters, any of which are likely to have a substantive impact on the outcomes of the BAER assessment.  
Statutory/Other Authority: ORS 468.020, 468A.025, 468A.040 & 468A.050 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468A.050, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-0320  
DEQ Best Available Emissions Reduction Order  
(1) DEQ may issue a BAER order for each owner or operator of a covered stationary source that must submit a BAER assessment as provided in OAR 340 -271-0310. A BAER order 
will establish the action s that the owner or operator of a covered stationary source must take 
to reduce covered emissions and the timeline on which the actions must be taken. 
(2) In establishing the requirements in a BAER order for a covered stationary source, DEQ 
may consider any information it deems relevant, and must consider the following:  
(a) Information submitted in a BAER assessment;  
(b) The fuels, processes, equipment, technology, systems, actions, and other strategies, methods and techniques that maximize covered emissions reductions;  
(c) The fuels, processes, equipment, technology, systems, actions, and other strategies, methods and techniques for reducing covered emissions used by sources in this state or in other jurisdictions that produce goods of comparable type, quantity, and quality; 152 
 (d) A reasonable schedule and amount of time necessary to implement a strategy under 
consideration by DEQ to reduce covered emissions;  
(e) Environmental, public health, and energy impacts of a strategy under consideration by DEQ to reduce covered emissions, including but not limited to air quality impacts for nearby communities and impacts related to switching to cleaner energy resources, zero -emissions 
energy resources, or renewable fuels;  
(f) Economic impacts of a strategy under consideration by DEQ to reduce covered emissions including, but not limited to, costs so great that a new source could not be built or an 
existing source could not be operated, and cost- effectiveness of different strategies that 
would achieve similar covered emissions reductions; 
(g) Processes and operations currently in use by and at the covered stationary source and the 
remaining useful life of the covered stationary source;  
(h) Whether a strategy under consideration by DEQ to reduce covered emissions is achievable, technically feasible, commercially available, and cost -effective;  
(i) Whether a strategy under consideration by DEQ to reduce covered emissions has an impact on the type or quality of good(s) produced by and at the covered stationary source, i f 
applicable; and 
(j) Input from the public and community organizations from nearby the covered stationary source.  Upon receipt of a BAER assessment, DEQ will  provide public notice with a copy of 
the BAER assessment  and a minimum of 30 days to submit writt en comments. DEQ also 
will provide public notice with a copy of DEQ’s  draft BAER order and a minimum of 30 
days to submit written comments . 
(3) For the owner or operator of a covered stationary source required to register and report according to OAR chapter 340, division 215, DEQ will consider emissions data reports to assess whether covered emissions reductions are being achieved when establishing the requirements in a BAER order or for determining when to notify the owner or operator of a covered stationary source to conduct and submit an updated complete BAER assessment as described in OAR 340-271-0310(5). 
(4) DEQ may verify information submitted in a BAER assessment.  
(5) DEQ may consult with industry experts and third- party organizations before iss uing a 
BAER order.  
(6) DEQ will notify the owner or operator of a covered stationary source of a BAER order in 
writing. A BAER order is effective 30 days from the date of the notification unless, within that time, DEQ receives a written request for a heari ng from the owner or operator of the 
covered stationary source according to section (7). 153 
 (7) The owner or operator of a covered stationary source may file with DEQ a written 
request for a contested case hearing to challenge a BAER order issued according to section (6). The request must be filed in writing within 30 days of the date that DEQ issued the BAER order and must state the grounds for the request. The hearing will be conducted as a contested case hearing in accordance with ORS 183.413 through 183.470 and OAR chapter 340, division 11. 
(8) DEQ will provide a public status update if DEQ has not yet issued a BAER order after 
18 months of the date on which DEQ notified the owner or operator of a covered stationary source that it must conduct a BAER assessment.  
Statutory/Other Authority: ORS 468.020, 468A.025 & 468A.040 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-0330  
Compliance with a BAER Order  
(1) The owner or operator of a covered stationary source for which DEQ has issued a BAER order according to OAR 340-271-0320 must: 
(a) Comply with the requirements in the BAER order; and  
(b) For an existing source that is required to complete a BAER assessment under OAR 34 0-
271-0310(1)(a), S submit to DEQ or LRAPA, as applicable, a complete permit modification 
application for a CPP permit addendum according to OAR 340-271-0150(3) not later than 
390 days after the date that the BAER order is final and effective , or a  later  date  specified in 
the BAER order . 
(2) Reporting requirements.  
(a) The owner or operator of a covered stationary source that has been issued a CPP permit addendum or operating permit that includes provisions related to a BAER order must submit an annual progress report to DEQ describing the progress in implementing the requirements in the BAER order. The annual progress reports are due to DEQ on or before February 15 of each year following the date that the notice of the BAER order is final and effective. The annual progress report must include: 
(A) A description of the progress achieved in implementing the requirements in any BAER 
order; 
(B) A schedule indicating dates for future increments of progress;  154 
 (C) A description of any increases or decreases in covered emissions that have occurred at 
the covered stationary source since the submission date of the most recently conducted complete BAER assessment; and  
(D) An estimate of when all implementation of requirements of the BAER order will be complete.  
(b) The owner or operator of a covered stationary source must submit a BAER order completion report to DEQ no later than 60 days after implementation of all requirements in the BAER order are complete, except for items related to continuous and ongoing requirements. The report must include:  
(A) The final increments of progress achieved in fully implementing the requirements in the BAER order and the date the final increments of progress were achieved;  
(B) A summary of the actions taken to fully implement the  requirements in the BAER order; 
and 
(C) An estimate of the resulting covered emissions reductions that will be achieved now that 
the requirements in the BAER order are being implemented.  
Statutory/Other Authority: ORS 468.020, 468A.025 & 468A.040 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-0420  
Distribution of Compliance Instruments to Covered Fuel Suppliers  
(1) DEQ will distribute compliance instruments according to this rule. DEQ will distribute compliance instruments from a cap according to sections (2) , (3), through (4) , and (6)  no 
later than March 31June 30 of the calendar year of that cap. 
(2) Annual distribution of compliance instruments to covered fuel suppliers that are local distribution companies. DEQ will annually distribute to each local distribution company, or to its successor(s) due to a change in ownership or operation, the number of compliance instruments from the calendar year’s c ap stated in Table 4 in OAR 340-271-9000. 
(3) DEQ will establish a compliance instrument reserve for covered fuel suppliers that are new to the program and are not local distribution companies. DEQ will hold, according to subsection (4)(a), a subset of com pliance instruments in the reserve from the caps identified 
in Table 2 in OAR 340-271-9000. Once a compliance instrument is held in the reserve, it 155 
 remains in the reserve until DEQ determines, at its discretion, to undertake one of the 
following actions:  
(a) DEQ distributes the compliance instrument according to section (5) to a covered fuel supplier that is not a local distribution company; 
(b) DEQ retires the compliance instrument because the compliance instrument reserve 
exceeds the size described in Tab le 3 OAR 340 -271- 9000, provided that after such 
retirement the size of the compliance instrument reserve will equal or exceed the reserve size described in Table 3; or  
(c) DEQ distributes the compliance instrument to a covered fuel supplier that is not a l ocal 
distribution company because the size of the compliance instrument reserve exceeds the reserve size described in Table 3 in OAR 340 -271-9000. DEQ will only distribute 
compliance instruments from the reserve according to this subsection if there are at  least 
10,000 compliance instruments to distribute and if the remaining size of the reserve after this distribution will equal or exceed the reserve size described in Table 3 in OAR 340 -271-
9000. DEQ will calculate the number of compliance instruments to distribute to each covered fuel supplier that is not a local distribution company according to subsection (4)(b), 
except “total compliance instruments to distribute” means the total number of compliance instruments DEQ is distributing from the reserve according to this subsection.  
(4) Annual distribution of compliance instruments to covered fuel suppliers that are not local distribution companies. DEQ will annually distribute compliance instruments from the applicable calendar year’s cap to covered fuel suppliers that are not local distribution companies as follows: 
(a) If the size of the compliance instrument reserve is less than the reserve size described in 
Table 3 in OAR 340-271- 9000 for the calendar year, then DEQ will calculate the differen ce 
and hold in the compliance instrument reserve that quantity of compliance instruments. Otherwise, the number of compliance instruments in the reserve will not be changed.  
(b) Except for compliance instruments identified in Table 4 in OAR 340 -271-9000 for 
distribution according to section (2) and the compliance instruments held in the reserve according to section (3) and subsection (4)(a), DEQ will calculate the number of compliance instruments to distribute to each covered fuel supplier that is not a local distribution company as described in this subsection, based on available information emissions  data from 
the prior calendar year as reported by each  covered fuel supplier as required by OAR chapter 
340, division  215, and subject to DEQ’s initial review for errors, but prior to completion of 
third -party verification  as required by OAR chapter  340, division 272.f rom the evaluation 
period described in Table 5 in OAR 340-271-9000. If a A person that becomes a covered fuel 
supplier after DEQ has distributed the compliance instruments for that year will not receive 
a distribution under this subsection.or its related entities do not have available information 
for one or more years of the evaluation period, DEQ may exclude the covered fuel supplier 
and its emissions from this calculation. If the covered fuel supplier is excluded, then the 156 
 distribution for the covered fuel supplier will be addressed using the methodology described 
in section  (5). 
(A) Prior to each calculation of compliance instrument distribution in OAR 340 -271-
0420(4)(b) (B), DEQ will apply a “Verified emissions data correction factor” to the annual 
compliance instrument distribution of each covered fuel supplier.  DEQ will re calculate the 
compliance instrument distribution from the previous year using third-party verified 
emissions data. If DEQ determines that the reported emission data used for the previous 
year’s compliance instrument distribution resulted in a lesser or greater number of 
compliance instruments being distributed to a covered fuel supplier, when compared to the 
recalculation using the third -party verified data, DEQ will increase or reduce, respectively, 
the number of compliance instruments distributed to the c overed fuel supplier by an equal 
amount in the current compliance instrument distribution. 
(BA) DEQ will use the following formula to calculate the number of compliance 
instruments to distribute to each covered fuel supplier:  
Number of Compliance Instruments = (T otal compliance instruments to distribute * 
([Covered fuel supplier covered emissions + covered fuel supplier biofuel emissions] / Total 
emissions) ) ± Verified emissions d ata correction factor  – Compliance instrument holding 
limit reduction  
(BC) As used in the formula in paragraph ( AB): 
(i) “Total compliance instruments to distribute” means the cap for the calendar year, according to Table 2 in OAR 340-271-9000, minus the number of compliance instruments identified in Ta ble 4 in OAR 340-271-9000; and minus the number of compliance 
instruments held in the compliance instrument reserve;  
(ii) “Covered fuel supplier covered emissions” means the sum of a covered fuel supplier’s covered emissions for during the evaluation period prior calendar year; 
(iii) “Covered fuel supplier biofuel emissions” means emissions described in OAR 340 -271-
0110(3)(b)(B)(i) that result from the complete combustion or oxidation of the annual quantity of biomass-derived fuels that the covered fuel supplier imported, sold, or distributed for use in the state for during the evaluation period prior calendar year; and  
(iv) “Total emissions” means the sum of “covered fuel supplier covered emissions” and “covered fuel supplier biofuel emissions” for during the evaluation period prior calendar 
year for all covered fuel suppliers whose compliance instrument distribution is calculated 
according to this section .; and 
(v) “Verified emissions data correction factor” means a correction applied as a result of 
changes to reported data since the previous distribution of compliance instruments, as 
described in OAR 340-271-0420(4)(b)(A); and 157 
 (vi) “Compliance instrument holding limit reduction” means the number of compliance 
instruments described in OAR 340 -271- 0430(2).  If the compliance instrument holding limit 
reduction exceeds the number of compliance instruments that a covered fuel supplier would 
have received in the distribution before subtracting the compliance instrument holding limit 
reduction, then the covered fuel supplier will not receive any compliance instruments in the 
distribution, and a compliance instrument holding limit reduction equal to the amount by 
which it exceeded the number of compliance instruments that a covered fuel supplier would 
have received in the distribution before subtracting the compliance instrument holding limit 
will be applied in the following year. 
(CD) DEQ will distribute a number of compliance instruments to each covered fuel supplier 
using the formula in paragraph ( BA) and rounded down to the nearest whole number. 
(DE) Any remaining compliance instruments not distributed due to rounding will be held in 
the compliance instrument reserve.  
(5) Distribution from compliance instrument reserve for new covered fuel suppliers that are 
not local distribution companies.  
(a) A covered fuel supplier is eligible for a distribution from the compliance instrument reserve if it is not a local distribution company and if:  
(A) The covered fuel supplier was excluded from the distribution in section (4) due to a lack 
of sufficient available information ; or 
(B) tThe person becomes a covered fuel supplier after DEQ has distributed the compliance 
instruments for that year according to section (4) . was not included in the distribution of 
compliance instruments for that year according to section (4).  
(b) For all calend ar years after 2024, a covered fuel supplier meeting the requirements of 
subsection  (a) is not eligible for a distribution of compliance instruments from the reserve if 
the person is a related entity to a covered fuel supplier that received a distribution of 
complia nce instruments under section (4).  
(cb) A covered fuel supplier identified according to subsection (a) and not ineligible under 
subsection (b)  may request a distribution of compliance instruments from the reserve by 
submitting an application to DEQ, on a form approved by DEQ, that includes the information described in paragraphs (A) through (D) , no later than June 1 of the  year after  
the calenda r year of the annual distribution of compliance instruments from which the 
covered fuel supplier was not included. The covered fuel supplier must submit a separate 
application for each year for which it is seeking distribution of compliance instruments from the reserve.  
(A) Information about the covered fuel supplier, including:  
(i) Name and full mailing address; and  158 
 (ii) Designated representative’s contact information including name, title or position, phone 
number, and email address;  
(B) The calendar year of covered emissions for which compliance instruments are requested;  
(C) The reason for the request, including description of eligibility according to subsection (a); and  
(D) The following attestation, signed by the designated representative of the covered fuel supplier: 
I certify under penalty of perjury under the laws of the State of Oregon that I am a 
representative of [covered fuel supplier], am authorized to submit this application on its behalf, and that, to the best of my knowledge and belief, the information provided in this form is true, accurate, and complete. [Covered fuel supplier] is a covered fuel supplier in the year indicated in this application and requests compliance instruments from the reserve according to t he information included in this application.  
(c) DEQ will review an application submitted according to subsection (b) to ensure that it meets the requirements of this section. DEQ will inform the applicant either that the submitted application is complete or that additional specific information is required to make the application complete. If the application is incomplete, DEQ will not consider the application further until the applicant provides the additional information requested by DEQ.  
(d) If DEQ appro ves an application, DEQ may will distribute one or more compliance 
instruments to the covered fuel supplier from the reserve no later than June 15 of the year 
after the calendar year of the annual distribution of compliance instruments from which the 
covered fuel supplier was not included. In determining the number of DEQ will distribute  
compliance instruments  to distribute  from the reserve to the covered fuel supplier, DEQ may 
consider as follows : 
(A) The number of compliance instruments the covered fuel supplier might have received 
according to section (4) if DEQ had sufficient available information to include the covered 
fuel supplier in that calculation;  
(B) The number of compliance instruments in the reserve at that time;  
(AC) A maximum distribution amount that will not exceed the covered fuel supplier’s 
covered emissions in that calendar year using emissions data from the prior calendar year as 
reported by each covered fuel supplier as required by OAR 340, division 215, and s ubject to 
DEQ’s initial review for errors, but prior to completion of third -party verification as 
required by OAR 340, division 272; and 
(BD) A maximum distribution amount that will not exceed 300,000 compliance instruments 
per covered fuel supplier per year.I f there are fewer compliance instruments in the reserve at 
the time of distribution than have been requested by all covered fuel suppliers who are 159 
 approved for a reserve distribution  for a calendar year, DEQ shall allocate compliance 
instruments  in the reserve  according to the ratio of each covered fuel  supplier’s covered 
emissions in that calendar year  to the total covered emissions from all covered fuel suppliers 
in that calendar year .  
(6) Each year, the sum of all compliance instruments that are not distributed to fuel suppliers 
in the distribution under section OAR 340-271-0420(4) as a result of compliance instrument 
holding limit reductions will be distributed to all covered fuel suppliers that did not have any 
compliance instrument holding limit reduction using the formula described in paragraph 
OAR 340 -271-0420(4)(b)(B ), except that, for purposes of such redistribution, “total 
compliance instruments to distribute” means the total number of compliance instruments 
that DEQ did not distribute to fuel suppliers in the general distribution under section OAR 
340-271- 0420(4) as a result of compliance instrument holding limit reductions. Such 
additional distribution of compliance instruments shall be made at the same time  as the 
distribution described in section OAR 340-271-0420(4). Any remaining compliance 
instruments not distributed due to rounding will be held in the compliance instrument 
reserve.  
(76) Upon distribution of compliance instruments according to sections (2), (4), and (5), and 
(6), DEQ will notify the designated representative of each covered fuel supplier in writing of 
the availability of compliance instruments.  
(87) DEQ will track distributed compliance instruments.  
Statutory/Other Authority: ORS 468.020, 468A.025 & 468A.040 
Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-0430  
Holding Compliance Instruments  
(1)When DEQ distributes a compliance instrument to a covered fuel supplier according to 
OAR 340 -271-0420 or when a covered fuel supplier acquires a compliance instrument 
according to OAR 340-271-0500, the covered fuel supplier may continue to hold the compliance instrument until any of the following apply: 
(a1
) The covered fuel supplier uses the compliance instrument toward its demonstration of 
compliance with a compliance obligation according to OAR 340-271-0450; 
(b2) The covered fuel supplier transfers the compliance instrument to another covered fuel 
supplier according to OAR 340-271-0500; or 160 
 (c3) The covered fuel supplier has ceased being a covered fuel supplier according to OAR 
340-271-0130. When this occurs, DEQ may, at its discretion: 
(ia) Retire the compliance instrument; or  
(iib) If the covered fuel supplier is not a local distribution company:  
(A) Hold the compliance instrument in the compliance instrument reserve described in OAR 
340-271-0420(3); or 
(B) Distribute the compliance instrument to a covered fuel supplier that is not a local 
distribution company. DEQ will only distribute the compliance instrument if there are at least 10,000 compliance instruments to distribute. DEQ will calculate the number of compliance ins truments to distribute to each covered fuel supplier according to OAR  340-
271-0420(4)(b), except “total compliance instruments to distribute” means the total number 
of compliance instruments DEQ is distributing according to this paragraph.  
(2) For each covered fuel supplier  that is not a local distribution company , a compliance 
instrument holding limit reduction will be calculated on November 22 of the year following 
the end of each compliance period, or 25 days after DEQ’s notification in OAR 340-271-
0450( 1), whichever is later. A covered fuel supplier’s compliance instrument holding limit 
reduction is the number of compliance instruments  from any prior year held by the covered 
fuel supplier on that date that exceeds one and a half times  the sum of the covered fuel 
supplier’s annual compliance obligation(s) for each year of the prior compliance period. In 
the year subsequent to the year after the end of a compliance period, if a fuel supplier did not 
receive any compliance instruments in the d istribution under section OAR 340-271-0420(4) 
in the prior year because its compliance instrument holding limit reduction exceeded the 
number of compliance instruments that it otherwise would have been distributed, then the 
fuel supplier’s compliance instrument holding limit reduction will be reduced as provided in 
subparagraph OAR 340-271-0420(4)(b)(B)(vi), and such reduced compliance instrument 
holding limit reduction will be used in the subsequent year’s compliance instrument 
distribution calculation under section OAR 340-271-0420(4).  
 
Statutory/Other Authority: ORS 468.020, 468A.025 & 468A.040 
Statutes /Other Implemented:  ORS 468.020, 468A.025, 468A.040, 468.035, 468A.010, 
468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-0450  
Demonstration of Compliance 161 
 (1) DEQ will determine a covered fuel supplier’s total compliance obligation for a 
compliance period as the sum of the covered fuel supplier’s annual compliance obligation(s) 
for each year of the compliance period. DEQ will base its determinations on emissions calculated according to OAR 340-271-0110(1). DEQ will notify the covered fuel supplier of its determina tion. 
(2) A covered fuel supplier must demonstrate compliance according to this rule by December 9 November 28 of the year following the end of each compliance period, or 4025 
days after DEQ’s notification described in section (1), whichever is later.  
(3) To demonstrate compliance for a compliance period, a covered fuel supplier must submit the following to DEQ: 
(a) For each metric ton of CO2e of the total compliance obligation , either a compliance 
instrument or a CCI credit, subject to the following limitations: 
(A) A covered fuel supplier may only submit compliance instruments that DEQ distributed 
from the caps for the calendar years of the applicable compliance period or from caps for earlier compliance periods; and  
(B) The quantity of CCI credits used to demonstrate compliance as a percentage of the total compliance obligation for the applicable compliance period may not exceed the allowable percentage specified in Table 6 in  OAR 340 -271-9000. 
(b) A demonstration of compliance form, approved by DEQ that includes: 
(A) Name and full mailing address of the covered fuel supplier;  
(B) Designated representative’s contact information including name, title or position, phone 
number, a nd email address;  
(C) Identification of the compliance period and calendar year(s) for which the covered fuel supplier is demonstrating compliance; 
(D) The total compliance obligations in metric tons of CO2e for the compliance period and 
listed separately for each calendar year in the compliance period; 
(E) The total number of compliance instruments the covered fuel supplier is submitting to DEQ to demonstrate compliance, and separately the total number submitted from each calendar year’s cap;  
(F) The total  number of CCI credits the covered fuel supplier is submitting to DEQ to 
demonstrate compliance; and 
(G) The following attestation, signed by the designated representative of the covered fuel supplier: 162 
 I certify under penalty of perjury under the laws of t he State of Oregon that I am a 
representative of [covered fuel supplier], am authorized to submit this report on its behalf, 
and that, to the best of my knowledge and belief, the information provided in this form is true, accurate, and complete. It is the intent of [covered fuel supplier] to use the quantity of compliance instruments and credits listed on this form and submitted to DEQ for the demonstration of compliance. I certify that [covered fuel supplier] has not exceeded the allowable use of CCI credi ts. If any portion of these compliance obligations remain unmet 
after this submission, I understand that [covered fuel supplier] must still demonstrate compliance with the remaining portion and may be subject to enforcement action. 
(4) Each metric ton of CO2e of a compliance obligation for which a covered fuel supplier 
does not demonstrate compliance according to this rule is a separate violation of this division. 
(5) If a change in ownership of a covered fuel supplier occurs, the person that owns or 
opera tes the covered fuel supplier as of December 31 in the final year of a compliance 
period is responsible for demonstration of compliance according to this rule for each annual compliance obligation during the compliance period. Compliance obligations may not be split or subdivided based on ownership changes during the compliance period or during any year within the compliance period. 
Statutory/Other Authority: ORS 468.020, 468A.025 & 468A.040 
Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-8100  
Program Review 
(1) DEQ will report to the EQC on community climate investments. DEQ will submit the 
first report to the EQC by August 30, 2024 and every two years thereafter. DEQ w ill share 
each report with current members of the equity advisory committee after submission to the EQC. Each community climate investment report will include:  
(a) A review of community climate investments, including:  
(A) CCI credits distributed to covered  fuel suppliers;  
(B) CCI credits used by covered fuel suppliers to demonstrate compliance; 
(C) Estimates of annual greenhouse gas emissions reductions that are anticipated to be 
achieved by completed projects that CCI entities have reported to DEQ by March  31 of the 
year DEQ is reporting to the EQC; 163 
 (D) Estimates of annual non- greenhouse gas air contaminant emissions reductions that are 
anticipated to be achieved by completed projects that CCI entities have reported to DEQ by 
March 31 of the year DEQ is rep orting to the EQC;  
(E) Calculation of the average anthropogenic greenhouse gas emissions reductions achieved 
per CCI credit distributed based on (A) and (C) and whether reductions of approximately 
one MT CO2e or more of anthropogenic greenhouse gas emissions for the average CCI credit distributed by DEQ was achieved; and  
(F) Description of community benefits achieved; and 
(b) DEQ’s recommendations regarding any necessary or desirable changes to the CPP 
provisions relating to CCIs, including, without limitation, recommendations on changes to 
the CCI credit contribution amounts described in Table 7 in OAR 340- 271-9000 necessary 
to assure that the use of CCI funds is reducing anthropogenic greenhouse gas emissions in Oregon by an average of at least one MT CO2e per CCI credit distributed by DEQ, as well 
as recommendations on how to best achieve the purposes of CCIs described in OAR 340-
271-0900, if applicable.  
(2) DEQ will report to the EQC on implementation of the Climate Protection Program. DEQ 
will sub mit the first report to the EQC five years after the date of adoption of this division 
and at least once every five years thereafter. Each program review report will include:  
(a) A review of the Climate Protection Program, including:  
(A) Summary of covered  fuel suppliers’ demonstrations of compliance for compliance 
periods that have occurred since program start, including:  
(i) Caps for each year and compliance period;  
(ii) Compliance obligations for each year and compliance period;  
(iii) Compliance instrume nts submitted for each compliance period; and  
(iv) CCI credits submitted for each compliance period;  
(B) Summary of the distribution of compliance instruments, including the size of the 
compliance instrument reserve at the start and end of each program year that has occurred 
and compared to Table 3 in OAR 340- 271-9000;  
(C) Summary of activity relating to trading of compliance instruments for each program year that has occurred;  
(D) Summary of covered stationary source requirement activities that have occurr ed since 
program start or since the most recently submitted report to the EQC, whichever is later, including:  164 
 (i) The number of existing stationary sources that DEQ has notified in writing that must 
complete a BAER assessment;  
(ii) The number of BAER assessments received or anticipated to be received by DEQ;  
(iii) A brief summary of any BAER order issued and the required actions that must be taken by the owner or operator of a covered stationary source that has been issued a BAER order; 
(iv) A brief summary of the status of any covered stationary source activities regarding 
implementation of requirements in a BAER order; and  
(v) Review of any changes in annual covered emissions from current covered stationary 
sources to assess whether covered emissions are being reduced;  
(E) Whether emission reductions from covered stationary sources align with the priorities described in section (3). This will be assessed in program reviews beginning after 2029.  
(F) A current list of covered entities by name and wheth er each is a covered fuel supplier or 
covered stationary source; and 
(G) Description of any enforcement actions taken that involved civil penalties, if applicable; 
and 
(b) DEQ’s recommendations regarding any potential changes to the CPP including, for 
exam ple and without limitation, recommendations regarding potential changes to best 
achieve the goals described in section (3) for covered stationary sources.  
(3) CPP goals for covered stationary sources described in OAR 340-271-0110(5) are to: 
(a) Reduce total covered emissions from covered stationary sources; and  
(b) Reduce total covered emissions from covered stationary sources that are the result of use 
combustion of solid or gaseous fuels by 50 percent by 2035 from the average of 2017 
through 2019 emissions.  
(4) If the average annual statewide retail cost of gasoline, diesel or natural gas in Oregon 
increases year -over-year by an amount that is more than 20 percent higher than the average 
change in cost for the same fuel over the same period in Washington, Idaho, and Nevada, DEQ will investigate the cause(s) of the increase and report to the EQC regarding whether changes to the rules in this division should be made that would ameliorate a relative increase in costs in Oregon. If necessary, DEQ will consider recommending rule changes, such as changes to caps and distribution of additional compliance instruments, changes to the compliance instrument reserve, or changes to the allowable usage of CCI credits.  
Statutory/Other Authority: ORS 468.020, 468A.025 & 468A.040 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468.035, 468A.010, 165 
 468A.015 & 468A.045 
History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021  
 
340-271-9000  
Tables  
(1) Table 1. Thresholds for applicability described in OAR 340-271-0110(3). 
(2) Table 2. Oregon Climate Protection Program caps. 
(3) Table 3. Compliance instrument reserve size.  
(4) Table 4. Compliance instrument distribution to cove red fuel suppliers that are local 
distribution companies.  
(5) Table 5. Compliance instrument distribution evaluation periods.R EPEALED effective 
x/x/xxxxx/x/2023] . 
(6) Table 6. Covered fuel supplier allowable usage of community climate investment credits 
to demonstrate compliance as described in OAR 340-271-0450(3). (7) Table 7. CCI credit contribution amount.  
[ED. NOTE: To view attachments referenced in rule text, click here to view rule.]
 
Statutory/Other Authority: ORS 468.020, 468A.025 & 468A.040 
Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 166 
 OAR 340 -271-9000 
Table 1  
Thresholds for  
applicability described in OAR 340 -271-0110(3)   
Applicability 
determination calendar 
year(s)  Threshold for 
applicability to 
compare to annual 
covered emissions Calendar year a 
person becomes a 
covered fuel supplier 
Any year from 2018 through 2022  200,000 MT CO2e  2022  
2023  200,000 MT CO2e  2023  
2024  200,000 MT CO2e  2024  
Any year from 2021 through 2025  100,000 MT CO2e  2025  
2026  100,000 MT CO2e  2026  
2027  100,000 MT CO2e  2027  
Any year from 2024 through 2028  50,000 MT CO2e  2028  
2029  50,000 MT CO2e  2029  
2030  50,000 MT CO2e  2030  
Any year from 2027 through 2031  25,000 MT CO2e  2031  
2032  25,000 MT CO2e  2032  
Each subsequent year 25,000 MT CO2e  Each subsequent year 
 
167 
 OAR 340-271-9000  
 
Table 2  
Oregon Climate Protection Program caps  
Calendar year  Cap 
2022  28,081,335  
2023  27,001,283  
2024  25,921,232  
2025  25,763,209  
2026  24,637,057  
2027  23,510,904  
2028  23,013,190  
2029  21,842,149  
2030  20,671,108  
2031  19,910,424  
2032  18,688,088  
2033  17,465,752  
2034  16,243,416  
2035  15,021,080  
2036  14,219,956  
2037  13,418,831  
2038  12,617,707  
2039  11,816,583  
2040  11,015,459  
2041  10,214,334  
2042  9,413,210  
2043  8,612,086  
2044  7,810,962  
2045  7,009,837  
2046  6,208,713  
168 
 2047  5,407,589  
2048  4,606,465  
2049  3,805,340  
2050 and each calendar year thereafter  3,004,216  
 169 
 OAR 340-271-9000  
 
Table 3  
Compliance instrument reserve size  
Calendar year(s) of the cap  Reserve size  
2022  400,000 compliance instruments  
2023 through 2030  800,000 compliance instruments  
2031 through 2040  500,000 compliance instruments  
2041 and each calendar year thereafter  250,000 compliance instruments  
170 
   
OAR 340 -271-9000  
 
Table 4  
Compliance instrument distribution to covered fuel suppliers  
that are local distribution companies  
Calendar year  Compliance 
instruments to 
distribute to 
Avista Utilities  Compliance 
instruments to 
distribute to 
Cascade 
Natural Gas 
Corporation  Compliance 
instruments to 
distribute to 
Northwest 
Natural Gas 
Company  
2022  703,373  743,707  5,759,972  
2023  676,320  715,103  5,538,434  
2024  649,267  686,499  5,316,897  
2025  622,214  657,895  5,095,359  
2026  595,161  629,291  4,873,822  
2027  568,109  600,687  4,652,285  
2028  541,056  572,083  4,430,747  
2029  514,003  543,478  4,209,210  
2030  486,950  514,874  3,987,673  
2031  459,897  486,270  3,766,135  
2032  432,845  457,666  3,544,598  
2033  405,792  429,062  3,323,061  
2034  378,739  400,458  3,101,523  
2035  351,686  371,854  2,879,986  
2036  332,930  352,021  2,726,387  
2037  314,173  332,189  2,572,787  
2038  295,416  312,357  2,419,188  
2039  276,660  292,525  2,265,589  
2040  257,903  272,693  2,111,990  
2041  239,147  252,860  1,958,390  
2042  220,390  233,028  1,804,791  
2043  201,633  213,196  1,651,192  
2044  182,877  193,364  1,497,593  
2045  164,120  173,532  1,343,993  
171 
  
  
OAR 340 -271-9000  
Table 5  
Compliance instrument distribution evaluation periods  
  
Calendar years of 
emissions for 
evaluation period  Year in which evaluation 
occurs to determine 
distribution of 
compliance instruments  Calendar year of the 
cap 
2018 through 2020  2021  2022  
2019 through 2021  2022  2023  
2020 through 2022  2023  2024  
Each subsequent three year 
period Each subsequent year  Each subsequent year  
 
 2046  145,364  153,699  1,190,394  
2047  126,607  133,867  1,036,795  
2048  107,850  114,035  883,196  
2049  89,094  94,203  729,596  
 2050 and each 
calendar year 
thereafter  70,337  74,371  575,997  
172 
 OAR 340-271-9000  
 
Table 6  
Covered fuel supplier allowable usage of community climate  
investment credits to demonstrate compliance as  
described in OAR 340-271-0450 (3) 
Compliance period  Allowable percentage of total 
compliance obligation(s) for which 
compliance may be demonstrated 
with CCI credits  
Compliance period 1 (2022 through 2024)  10%  
Compliance period 2 (2025 through 2027)  15%  
Compliance period 3 (2028 through 2030), and for 
each compliance period thereafter  20% 
 
173 
 OAR 340-271-9000  
Table 7  
CCI credit contribution amount  
Effective date CCI credit contribution amount in 
2021 dollars, to be adjusted 
according to OAR 340-271-0820 (3) 
March 1, 2023  $107  
March 1, 2024  $108  
March 1, 2025  $109  
March 1, 2026  $110  
March 1, 2027  $111  
March 1, 2028  $112  
March 1, 2029  $113  
March 1, 2030  $114  
March 1, 2031  $115  
March 1, 2032  $116  
March 1, 2033  $117  
March 1, 2034  $118  
March 1, 2035  $119  
March 1, 2036  $120  
March 1, 2037  $121  
March 1, 2038  $122  
March 1, 2039  $123  
March 1, 2040  $124  
March 1, 2041  $125  
March 1, 2042  $126  
March 1, 2043  $127  
March 1, 2044  $128  
March 1, 2045  $129  
174 
 March 1, 2046  $130  
March 1, 2047  $131  
March 1, 2048  $132  
March 1, 2049  $133  
March 1, 2050  $134  
 
  175 
 Third Party Verification, Division 272 
 
340-272-0020  
 
Definitions  
The definitions in this rule and in OAR 340-200-0020, OAR 340-215-0020, and OAR 340-253-0040, and the acronyms in OAR 340-253-0060 apply to this division. If the same term is defined in this rule and another division, the definition in this rule applies to this division.  
(1) “Adverse verification statement” means a verification statement from a verification body that (either or both): 
(a) It cannot say with reasonable assurance the submitted report or fuel pathway application 
is free of a material misstatement; or 
(b) The submitted report or fuel pathway application contains correctable errors and thus is 
not in conformance with the requirements to fix such errors according to OAR 340 -272-
0435. 
(2) “California ARB” means California Air Resources Board.  
(3) “CFP” means the Oregon Clean Fuels Program established under OAR chapter 340, 
divisondivision 253. 
(4) “Confl ict of interest” means a situation in which, because of financial or other activities 
or relationships with other persons or organizations, a verification body is unable or potentially unable to provide an impartial verification statement of a potential client’s report or fuel pathway application, or the verification body’s objectivity in providing verification services is or might be otherwise compromised.  
(5) “Correctable errors” means errors identified by the verification team that affect data in the submitted report or fuel pathway application , application, which result from a 
nonconformance with OAR chapter 340, division 215 or OAR chapter 340, division 253, as applicable. Differences that, in the professional judgment of the verification team, are the result of differing but reasonable methods of truncation or rounding or averaging, where a specific procedure is not prescribed by this division, OAR chapter 340, division 215, or OAR chapter 340, division 253, are not considered errors and therefore do not require correction.  
(6) “DEQ” means Oregon Department of Environmental Quality. 
(7) “Difference in CI” means the absolute value result of the reported operational CI minus the verifier’s calculation of CI for material misstatement of carbon intensity ass essments for 
a CFP fuel pathway application or annual report. The verifier’s calculation of CI is based on 176 
 site-specific data inputs modified to include discrepancies, omissions, and misreporting 
found during the course of verification services.  
(8) “Full verification” means all verification services as required under OAR 340 -272-
0300(1).  
(9) “GHG Reporting Program” means the Oregon Greenhouse Gas Reporting Program 
established under OAR chapter 340, division 215. 
(10) “Independent reviewer” means a lead ver ifier within a verification body that has not 
participated in providing verification services for a responsible entity for the current 
reporting year and provides an independent review of verification services provided to the 
responsible entity.  
(11) “Lead  verifier” means a person that has met the requirements to perform such role 
under OAR 340- 272-0210 and has been approved by DEQ under OAR 340- 272-0220 to act 
as the lead of a verification team providing verification services as described by this 
division.  
(12) “Less intensive verification” means all verification services required for full 
verification, except for site visit(s) as described under OAR 340 -272-0420, and only 
requiring data checks and document reviews based on the analysis and risk assessment in the 
most recent sampling plan developed as part of the most current full verification.  
(13) “Material misstatement” means any discrepancy, omission, misreporting, or 
aggregation of the three, identified in the course of verification services that leads a 
verification team to believe that reported data or a submitted report or fuel pathway 
application contains one or more errors, as described in OAR 240- 272-0450, OAR 240- 272-
0455, and OAR 240- 272-0460, as applicable.  
(14) “Member” means any employee or su bcontractor of the verification body or related 
entities of the verification body and includes any individual with majority equity share in the 
verification body or its related entities. 
(15) “Nonconformance” means the failure to meet the applicable requir ements of this 
division or the failure to meet requirements of OAR chapter 340, division 215 or OAR 
chapter 340, division 253, as applicable, to calculate or report data or submit a fuel pathway 
application.  
(16) “Positive verification statement” means a v erification statement from a verification 
body attesting that it can say with reasonable assurance that the submitted report or fuel 
pathway application is free of material misstatement and that it conforms to the requirements 
of this division, OAR chapter  340, division 215, or OAR chapter 340, division 253, as 
applicable.  177 
 (17) “Professional judgment” means decisions based on professional qualifications and 
relevant greenhouse gas accounting and auditing experience. 
(18) “Qualified positive verification sta tement” means a statement from a verification body 
attesting that it can say with reasonable assurance that the submitted report or fuel pathway 
application is free of material misstatement and has been corrected or modified in conformance with OAR 340-272-0435, but may include one or more other nonconformance(s) with the requirements of this division, OAR chapter 340, division 215, or OAR chapter 340, division 253, as applicable, which do not result in a material misstatement.  
(19) “Quarterly review” means  a review process conducted by the verification team after 
quarterly data is submitted and before annual data is submitted and verified. 
(20) “Reasonable assurance” means high degree of confidence in the accuracy and truth of a 
conclusion. 
(211) “Reported emissions reductions” means the total of all greenhouse gas emissions 
reductions reported in a CFP project report.  
(222)“Reported Operational CI Value” means the absolute value of the operational CI 
submitted in a CFP fuel pathway application or annual report used for material misstatement of carbon intensity assessments.  
(23
3) “Reported quarterly fuel transaction quantity for fuel pathway code” means the total of 
all reported fuel quantities for each fuel pathway code for each transaction type for each quarter in a CFP quarterly report for which the verifier is conducting a material misstatement of quarterly fuel quantity assessment.  
(24
4) “Responsible entity” means a person that is subject to or voluntarily agrees to be 
subject to the requirement s of OAR 340 -272-0110, OAR 340-272-0120, or both. 
(255) “Sector specific verifier” means a person that has met the requirements to perform 
such a role under OAR 340-272-0210 and has been approved by DEQ under OAR 340-272-0220 to act as a sector specific verifier in providing verification services as described by this division. This may include, but is not limited to, demonstrating specialized experience in transactions, oil and gas systems, or process emissions.  
(26) “Subcontractor” means an i n
 dividual or business firm contracting to perform part or all 
of another’s contract.  
(2726) “Total reported emissions” means the total annual greenhouse gas emissions in a 
GHG Reporting Program emissions data report. 178 
 (287) “Validation statement” means the final statement produced by a verification body 
attesting whether a fuel pathway application is free of material misstatement and whether it 
conforms to the requirements of California ARB’s Low Carbon Fuel Standard.  
(2928) “Verification” or “third -party ve rification” means a systematic, independent, and 
documented process for evaluation of a report or fuel pathway application according to this division. 
(3
029) “Verification body” means a business entity that has met the requirements under 
OAR 340-272-0210 and has been approved by DEQ under OAR 340-272-0220 to provide 
verification services and produce verification statements as described by this division. 
(310) “Verification services” means services provided during full verification or less 
intensive verification, including but not limited to reviewing a report or fuel pathway 
application submitted by a responsible entity, assessing compliance with DEQ regulations, 
ensuring accuracy according to the standards specified by DEQ, and submitting a verification statement(s) to DEQ.  
(32
1) “Verification statement” means the final statement produced by a verification body 
attesting whether a report or fuel pathway application submitted by a responsible entity is free of or contains material misstatement a nd whether it does or does not conform to the 
applicable requirements. 
(33
2) “Verification team” means all persons working for a verification body, including all 
subcontractors, to provide verification services.  
(343) “Verifier” means an individual person that has met the requirements to perform such 
role under OAR 340-272-0210 and has been approved by DEQ under OAR 340-272-0220 to 
provide verification services as described by this division. 
Statutory/Other Authority: ORS 468.020, 468A.050, 468A.266, 468A.271, 468A.277 & 468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050, 468A.265 through 468A.277 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0100  
 General Requirements for Verification of Reports and Fuel Pathway Applications  
(1) The annual third party verification requirements set forth in this division apply beginning in 2022 for reports with data for calendar year 2021, and in each year thereafter. Quarterly review conducted as part of annual verification services that meet the requirements of this division may begin in 2022 for reports with data for the year 2022. 179 
 (2) Each re sponsible entity must:  
(a) Engage the services of a verification body to perform verification under this division; 
(b) Do the following before verification services begin: 
(A) Conduct a conflict of interest evaluation in coordination with the verification body 
according to OAR 340-272-0500 and develop a conflict of interest mitigation plan, if needed, according to OAR 340-272-0500. Submit both the evaluation and the plan, as 
applicable, to DEQ  Ensure both a complete and accurate conflict of interest evaluation and 
conflict of interest mitigation plan, as applicable, are submitted to DEQ , and receive from 
DEQ approval in writing to proceed with verification services; and  
(B) Submit to DEQ the report that is to be verified and attest that the data and information submitted to DEQ in the report is true, accurate, and complete; 
(c) Ensure that a verification statement is submitted to DEQ from the verification body for 
each report identified under OAR 340-272-0110 and OAR 340-272-0120 by the deadline 
specified under section (3); and 
(d) Ensure the requirements of this division are met, including but not limited to, ensuring 
that verification services are provided in compliance with the requirements of OAR 340-272-0300 and that a potential for a conflict of interest is evaluated, monitored, and mitigated 
according to  
OAR 340 -272-0500; 
(3) Verification deadlines. 
(a) Each responsible entity must ensure that a positive, qualified positive, or adverse 
verification statement is received by DEQ from a verification body by August 31 of the year a report is submitted, for the following reports, as applicable: 
(A) Any CFP report, as applicable under OAR 340-272-0110; and (B) An y GHG Reporting Program emissions data report described under OAR 340-215-
0044(1) (a) through (d), and (g), as applicable under OAR 340-272-0120. 
(b) Each responsible entity must ensure that a positive, qualified positive, or adverse 
verification statement is received by DEQ from a verification body by September 30 of the year a report is submitted, for each GHG Reporting Program emissions data report described under OAR 340-215-0044(1)(e) and (f), as applicable under OAR 340-272-0120. 180 
 (c) DEQ may extend ve rification deadlines in subsections (a) or (b) as necessary and will 
issue notice of any extensions.  
(4) Requirements for full or less intensive verification for certain responsible entities.  
(a) Responsible entities required to engage the services of a verification body to perform 
annual verification of CFP quarterly reports under OAR 340- 272-0110(3), GHG Reporting 
Program emissions data reports under OAR 340- 272-0120(1), or both must engage the 
services of a verification body to provide full verification,  as described by this division, in 
the first year that verification is required under section (1), in 2023, and then in at least every 
third year thereafter, if subsection (b) is applicable. Full verification is required in any year 
where subsection (b) does not apply.  
(b) Responsible entities required to engage the services of a verification body to perform 
annual verification of CFP quarterly reports under OAR 340- 272-0110(3), GHG Reporting 
Program emissions data reports under OAR 340- 272-0120(1), or both may engage the 
services of a verification body to provide less intensive verification in place of full 
verification, for up to two years out of every three year period, if:  
(A) There has not been a change in the verification body;  
(B) A positive verification statement was issued for the previous year; and  
(C) No change of operational control of the responsible entity occurred in the previous year.  
(c) A verification body may choose to provide full verification, at its discretion, in instances 
where the responsible entity has made changes in sources, significant changes in emissions, 
significant changes in data management systems, or any combination therein, occurred 
compared to the previous year, based on the professional judgment of the verification body. 
(A) The verification body must provide reasons why it opted for full verification to the 
responsible entity and to DEQ.  
(B) The verification body must provide justification in the verification report if it did not opt 
for full verification in instances whe re the total reported emissions differ by greater than 25 
percent relative to the previous year’s emissions.  
(5) Verification body and verifier rotation requirements.  
(a) A responsible entity must not use the same verification body or verifier(s) to perfor m 
verification for a period of more than six consecutive years.  
(b) A responsible entity must wait at least three years before re- engaging the previous 
verification body or verifier(s) to perform verification.  181 
 Statutory/Other Authority: ORS 468.020, 468A.050, 468A.266, 468A.271, 468A.277 & 
468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050, 468A.265 through 468A.277 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0110  
 Requirements for Verification of CFP Reports and Fuel Pathway Applications Submitted under OAR Chapter 340, Division 253  
(1) Optional verification of CFP fuel pathway (carbon intensity or CI) applications. 
(a) Fuel pathway applicants supplying site -specific CI data for the fuel pathway application 
are not required to meet the requirements of this division or engage the services of a verification body to perform verification for each fuel pathway application submitted under OAR chapter 340, division 253. 
(b) Fuel pathway applications that have been verified according to the requirements of this 
division, including site visit(s), will be prioritized for approval by  DEQ.  
(A) Fuel pathway applicants that choose to engage the services of a verification body to perform verification may do so once a list of approved verification bodies and verifiers qualified to verify CFP fuel pathway applications is made available on D EQ’s website 
according to OAR-340-272-0220(1)(d)(B). 
(B) Fuel pathway applicants submitting fuel pathway applications to DEQ that have been 
verified according to the requirements of this division must submit the verification statement at the same time that  the application is submitted.  
(C) A fuel pathway application submitted to DEQ that includes an adverse verification statement will not be considered.  
(c) Fuel pathway applications submitted to DEQ that have been verified under California ARB’s Low Carbon Fuel Standard may submit to DEQ materials relating to that verification.  
(A) Fuel pathway applications submitted to DEQ that include a positive or qualified positive validation statement under California ARB’s Low Carbon Fuel Standard will be prioritized for approval by DEQ. 
(B) Fuel pathway applications submitted to DEQ that include an adverse validation 
statement under California ARB’s Low Carbon Fuel Standard will not be considered.  182 
 (C) Any verification statements for the fuel pathway under California AR B’s Low Carbon 
Fuel Standard must also be submitted at the same time that the fuel pathway application and 
validation statement are submitted to DEQ.  
(2) Annual verification of CFP annual fuel pathway (carbon intensity or CI) reports. 
(a) Applicability. Th e following persons must meet the requirements of this division and 
engage the services of a verification body for the purposes of annual verification under this 
division, including required site visit(s), for each annual fuel pathway report submitted under OAR chapter 340, division 253, except as otherwise provided under subsection (b): 
(A) Holders of certified fuel pathways that supplied site -specific CI data for pathway 
certification and are required to update site- specific CI data on an annual basis; an d 
(B) Specified source feedstock suppliers and other persons with site- specific CI data that 
apply for separate DEQ recognition as a joint applicant under OAR chapter 340, division 
253 and elect to be responsible for separate verification. 
(b) Exemptions. Holders of approved fuel pathways that do not generate at least 6,000 total 
credits and deficits during the previous calendar year for the quantity of fuel produced at a given production facility and reported in the CFP are not subject to the requirements of this 
division for that year.  
(c) Verification schedule. Responsible entities that are subject to the subsection (a) requirement to engage the services of a verification body to perform verification of annual fuel pathway reports (CI) must ensure a fuel pathway verification statement for each fuel pathway report is submitted to DEQ according to OAR 340-272-0100. 
(A) Quarterly review of operational CI data is optional and may only be included as part of 
annual verification services if the fuel pathway holder submits quarterly data to DEQ. Quarterly review may only be conducted after the fuel pathway holder submits the report and attests that the statements and information submitted are true, accurate, and complete. Quarterly review does not replace the requ irements for the verification team to consider all 
quarterly data submitted during annual verification. Quarterly review must meet the requirements for verification under this division, but a verification statement and verification report are not submitted  after quarterly review.  
(B) Facilities with California pathways recertified in Oregon. A responsible entity that must meet the requirements of this division for the purposes of annual verification for any fuel production facility that is also subject to a nnual or deferred verification under California 
ARB’s Low Carbon Fuel Standard must submit its verification statement to DEQ within ten calendar  days of its comparable submittal to California ARB. If the responsible entity 
received an adverse verification statement, it must also submit the log of issues at the same time it submits the verification statement to DEQ.  183 
 (i) For responsible entities that operate facilities with one or more Oregon fuel pathway 
codes that are a recertification of California fuel pa thway codes, the verification statement 
submitted to California ARB must be submitted to DEQ according to the verification deadline specified under OAR 340-272-0100. 
(ii) For responsible entities that operate facilities with one or more fuel pathway codes that 
are not a recertification of California fuel pathway codes, but have active California fuel pathway codes, the fuel pathway holder must ensure the following: 
(I) That when verification services are provided, the inputs and annual operational carbon 
intensity are confirmed under OR -GREET as required under OAR 340-272-0450; and 
(II) That a fuel pathway verification statement for each annual fuel pathway report is submitted to DEQ according to OAR 340-272-0100. 
(C) If a fuel pathway holder is eligible for deferred verification under the California 
program, the fuel pathway holder must notify DEQ before April 30 of each year. If fuel from the facility generates 6,000 or more total credits and deficits in Oregon, then the fuel pathway holder must engage the services of a verification body to perform verification and ensure a fuel pathway verification statement for each annual fuel pathway report is submitted to DEQ according to OAR 340-272-0100. 
(3) Annual verification of CFP quarterly reports.  
(a) Applicability. The following persons must meet the requirements of this division and 
engage the services of a verification body for the purposes of annual verification under this division, including required site visit(s), for CFP quarterly reports submitted under O AR 
chapter 340, division 253, except as otherwise provided under subsection (b): 
(A) Regulated parties, credit generators, and aggregators subject to OAR 340 -253-0100. The 
scope of verification services is limited to the transaction types under paragraph ( B), 
including associated corrections submitted into CFP quarterly and annual reports. (B) Except as provided in subsection (b), reporters of volumes for any of the following 
transaction types must engage the services of a verification body to perform verification for the following transaction types:  
(i) All liquid fuels, including:  
(I) Production in Oregon; 
(II) Import; Out of State Production for Import;  
(III) Export; All Import transactions ; 184 
 (IV) Gain of inventory; Exports, other than Position Holder Sales for Export or export 
transactions reported on behalf of an unregistered exporter;  
(V) Loss of inventory; Gain of inventory;  
(VI) Not used for Transportation, and Loss of inventory;  
(VII) Transactions used to claim exempt uses under OAR 340-253-0250; Not used for 
transportation; and   
(VIII) Transactions used to claim exempt uses under OAR 340-253-0250; 
(ii) NGV fueling; and  
(iii) Propane fueling.  
(b) Exemptions. The following are not subject to the requirements of this division:  
(A) Persons that do not g enerate 6,000 or more total credits and deficits , in the aggregate, 
during the previous calendar year. For the purposes of this rule, any credits or deficits 
generated by persons that are related entities or share full or partial common ownership or 
operational control must be aggregated together to determine whether or not the exemption 
applies; 
(B) Persons reporting fuel transactions only in one or more of the transaction types : Export, 
Position Holder Sale for Export, Gain of inventory, Loss of inventory, and Not used for 
transportation , if all of  the following conditions are met: 
(i) All such transactions do not generate 6,000 or more total credits and deficits , in the 
aggregate, during the previous calendar year; 
(ii) The person did not report any liquid fuel using the transaction types: Production in 
Oregon or Import into Oregon; and 
(iii) The person did not report any NGV fueling transactions. 
(c) Verification schedule. Responsible entities under subsection (a) required to engage the 
services of a verification body to perform annual verification of CFP quarterly reports must 
ensure a transactions data verification statement is submitted to DEQ according to OAR 340-272-0100. 
(d) Optional quarterly review. Quarterly review of a CFP quarterly report is optional and does not replace the requirements for the verification team to consider all quarterly data submitted during annual verification. Quarterly review must meet the requirements of this division, but a verification statement and verification report are not submitted after quarterly review.  185 
 (4) Annual verification of CFP annual project reports.  
(a) Applicability. The following persons must meet the requirements of this division and 
engage the services of a verification body for the purposes of annual verification, including required site visit(s), for CFP project reports required to be submitted as a condition of a fuel pathway’s continued approval under OAR 340-253-0450(9)( eD)(E): 
(A) Project operators; and  
(B) Joint applicants.  
(b) Verification s chedule. Responsible entities under subsection (a) required to engage the 
services of a verification body to perform verification of CFP project reports must ensure a project report verification statement is submitted annually to DEQ according to with OAR 340-272-0100. 
Statutory/Other Authority: ORS 468.020, 468A.266, 468A.271 & 468A.277 
Statutes/Other Implemented: ORS 468A.010, 468A.015 & 468A.265 through 468A.277 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0120  
 Requirements for Verification of GHG Reporting Program Emissions Data Reports Submitted under OAR Chapter 340, Division 215  
(1) Annual verification of GHG Reporting Program emissions data reports.  
(a) Applicability. The following persons must meet the requirements of this division and engage the services of a verification body for the purposes of annual verification of the entire emissions data report, including required site visit(s), for each separate emissions data report submitted under OAR chapter 340, division 215, except as otherwise provided under subsection (b): 
(A) A regulated entity that submits an emissions data report as descr ibed under OAR 340-
215-0044(1) that indicates emissions equaled or exceeded 25,000 metric tons of CO2e, 
excluding CO2 from biomass- derived fuels; and  
(B) A third party that is not the Bonneville Power Administration (BPA) that registers and submits an emis sions data report on behalf of a consumer- owned utility for emissions, data, 
and information submitted for each individual utility with emissions that equaled or exceeded 25,000 metric tons of CO2e, excluding CO2 from biomass- derived fuels and 
excluding em issions associated with preference power purchased from BPA; and 186 
 (C) A regulated entity that submitted an emissions data report that indicated emissions 
exceeded the threshold in paragraph (A) in the previous year, but that submits an emissions data report that indicates emissions are reduced below that applicability threshold in the 
current reporting year ;. 
(D) All regulated entit ies subject to the Climate Protection Program requirements described 
under OAR chapter 340, division 271, regardless of emissions reported ; and. 
(E) All regulated entities that are  electric  compan ies and electricity service suppliers as 
defined in ORS 757.600, regardless of emissions reported . 
(b) Exemptions. The following are not subject to the requirements of this division: 
(A) A regulated entitiy entity  that is not an electric company and not subject to requirements 
under OAR chapter 340, division 215 and that  submits an emissions data report as described 
under OAR 430340-215- 0044(1) that indicates emissions were le ss than 25,000 metric tons 
of CO2e, excluding CO2 from biomass-derived fuels. For the purposes of this rule, any GHG emissions in emissions data reports as described under OAR 340 -215-0044(1)(c) 
submitted by fuel suppliers or in -state producers that are related entities or share full or 
partial common ownership or operational control must be aggregated together to determine 
whether or not the exemption applies; 
(B) An emissions data report as described under OAR 340- 2 15-0044(1)(a) that includes 
emissions data and information described in 40 C.F.R. part 98 subpart HH – Municipal Solid 
Waste Landfills;  
(C) An emissions data report as described under OAR 340- 2 15-0044(1)(d) submitted by a 
natural gas supplier that is an interstate pipeline; and  
(D) A ny e missions data report as described under OAR 340- 215-0044(1)(e) submitted by 
Bonneville Power Administration (BPA) acting as a third -party reporter on behalf of any 
consumer-owned utility, as allowable under OAR 340- 215-0120(4). 
(c) Verification schedul e. Responsible entities that are subject to the subsection (a) 
requirement to engage the services of a verification body to perform verification of emissions data reports must ensure a verification statement for each emissions data report is submitted to D EQ according to OAR 340-272-0100. 
(A) These requirements are in addition to the requirements in 40 C.F.R. 98.3(f). 
(B) An asset -controlling supplier that submitted an emissions data report to DEQ as 
described under OAR 340- 215-0044(1)(f) that includes the same data and information 
reported to and verified under California ARB's Mandatory Reporting of Greenhouse Gas Emissions program may submit the same verification statement to DEQ. If an adverse verification statement is received, a current issues log must also be submitted to DEQ. 187 
 (2) Cessation of verification requirement.  
(a) Responsible entities must have an emissions data report verified for the first year that the 
report indicates emissions are reduced below the applicability threshold defined in parag raph 
(1) 
(a)(A). An emissions data report is not subject to verification in any following year 
thereafter where emissions remain below the threshold.  
(b) A responsible entity that meets the verification cessation requirements for two consecutive years must  notify DEQ in writing in the second year that it is ceasing the 
verification requirement according to this paragraph and provide the reason(s) for cessation of verification. The notification must be submitted no later than the applicable reporting deadline under OAR chapter 340, division 215 for that year. 
(c) If in any subsequent year after meeting verification cessation requirements an emissions 
data report meets the applicability requirements of subsection (1)(a), the responsible entity must have the em issions data report verified according to the requirements of this division, 
and verification must continue until the cessation requirement is met again.  
Statutory/Other Authority: ORS 468.020, 468A.050 & 468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
340-272-0210  
 Applications and Criteria for DEQ Approval of Verification Bodies and Verifiers  
(1) Application for approval. A business entity or person seeking DEQ approval or renewal of DEQ approval to perform verification under this division as a verification body or verifier must submit an application to DEQ, on a form approved by DEQ, that includes the following information:  
(a) For verifier applications, a statement about whether the application is for approval as a verifier, a lead verifier, or a sector specific verifier;  
(b) A statement about which specific types of emissions data reports submitted under OAR chapter 340, division 215, fuel pathway applications or specific types of CFP reports submitted under OAR chapter 340, division 253, or any combination therein, for which the applicant is seeking approval to perform verification; 
(c) Documentation demonstrating that the person or business entity holds the accreditation 
requirements described in section (2);  
(d) Additional information as required by sections (2) through (7), as applicable;  188 
 (e) A certification that the person or business entity agrees to comply with and be subject to 
the requirements of this division in relation to all verification work for responsible entities; and 
(f) Any other information requested by DEQ that DEQ determines is relevant to determine 
whether to approve the applicant.  
(2) Application information and accreditation criteria for approval. Any person or business entity that wants to perform verification under this division must provide  documentation that 
the person has met all the following criteria for approval, as applicable for the type of verification approval the applicant seeks:  
(a) The person or business entity holds an active accreditation under at least one of the following programs:  
(A) California ARB’s Low Carbon Fuel Standard program (LCFS); 
(B) California ARB's Mandatory Reporting of Greenhouse Gas Emissions program (MRR); 
(C) American National Standards Institute for Greenhouse Gas Validation/Verification 
Bodies (ANSI); or  
(D) A substantially equivalent program to one of the programs described in paragraphs (A), (B), or (C), and approved by DEQ; 
(b) To provide verification services for CFP reports or fuel pathway applications submitted 
under OAR chapter 340, division 253, the person or business entity must hold accreditation under California ARB’s LCFS, or a substantially equivalent program approved by DEQ; 
(c) To provide verification services for emissions data reports submitted under OAR chapter 
340, division 215, the person or business entity must hold accreditation under California ARB’s MRR, ANSI, or a substantially equivalent program approved by DEQ; and 
(d) All applicants must submit additional information in the application with details of accreditatation accreditation  and verification experience, including but not limited to, 
recognition or designation as a lead verifier or sector specific verifier, and sector specific accreditations by California ARB or organization -level sector accreditations by ANSI, as 
applicable, t o demonstrate qualifications to provide verification services for specific types of 
emissions data reports submitted under OAR chapter 340, division 215, fuel pathway applications or specific types of CFP reports submitted under OAR chapter 340, division 253, or any combination therein. 
(3) Application information and criteria for approval for a verification body. To be approved 
a
s a verification body, the applicant must also submit the following information to DEQ in 
the application: 189 
 (a) A list of all veri fication staff and subcontractors and a description of their duties and 
qualifications, including DEQ -approved verifiers on staff. The applicant must demonstrate 
staff qualifications by listing each individual’s education, experience, professional licenses, 
accreditations, status as verifier, lead verifier, or sector specific verifier, and other relevant information. A verification body must employ and or retain at least two lead verifiers , which 
may include retention as ; lead verifiers may be  subcontract ors. Any subcontractor used to 
meet minimum lead verifier requirements must be approv ed as a l ead verifie r by DEQ. 
(b) A list of any judicial proceedings, enforcement actions, or administrative actions filed against the verification body within the previous five years, with an explanation as to the nature of the proceedings; 
(c) Documentation that demonstrates that the body maintains a minimum of four million 
U.S. dollars of professional liability insurance; 
(d) Identification of services provided by  the verification body, the industries that the body 
serves, and the locations where those services are provided;  
(e) A detailed organizational chart that includes the verification body, its management 
structure, and any related entities; and  
(f) The verification body’s internal conflict of interest policy that identifies activities and limits to monetary or non -monetary gifts that apply to all employees and procedures to 
monitor potential conflicts of interest.  
(4) Application information and criteria for approval as a verifier. To be approved as a verifier, the applicant must also submit the following information to DEQ in the application:  
(a) Applicants must indicate their employer or affiliated verification body on the application; and 
(b) Applicants must must demonstrate verification qualifications by providing information 
on education, experience, professional licenses, accreditations, status as verifier, lead verifier, or sector specific verifier, and other relevant information or oth er personal 
development activities that demonstrate communication, technical, and analytical skills necessary to perform verification. Evidence demonstrating necessary skills may include, but is not limited to:  
(A) A bachelor’s level college degree or equivalent in engineering, science, technology, business, statistics, mathematics, environmental policy, economics, or financial auditing; or  
(B) Work experience in a professional role involved in emissions data management, emissions technology, emissions inventories, environmental auditing, financial auditing, life cycle analysis, transportation fuel production, or other technical skills necessary to perform verification.  190 
 (5) Application information and criteria for approval as a lead verifier for the GHG 
Repo rting Program. To be approved as a lead verifier for verification of emissions data 
reports submitted under OAR chapter 340, division 215, in addition to submitting 
information as required by section (4), the applicant must also submit documentation to 
DEQ in the application indicating that at least one of the following qualifications are met:  
(a) The verifier is accredited as a lead verifier by California ARB for the Mandatory 
Reporting of Greenhouse Gas Emissions program;  
(b) The verifier is designated as  a lead verifier by the ANSI- accredited verification body 
with which it is employed or affiliated; or  
(c) The verifier is designated as a lead verifier by a substantially equivalent program to one of the programs described in subsection (a) or (b), and tha t is approved by DEQ.  
(6) Application information and criteria for approval as a lead verifier for the CFP. To be 
approved as a lead verifier for verification of CFP reports or fuel pathway applications 
submitted under OAR chapter 340, division 253, in addition to submitting information as 
required by section (4), the applicant must also submit the following documentation to DEQ 
in the application:  
(a) Indication that the applicant is accredited as a lead verifier by California ARB for the 
Low Carbon Fuel S tandard program, or is designated as a lead verifier by a substantially 
equivalent program approved by DEQ;  
(b) To be approved as a lead verifier for verification of CFP fuel pathway applications or annual fuel pathway reports, the applicant must also subm it documentation to DEQ in the 
application that demonstrates experience in alternative fuel production technology and 
process engineering; and  
(c) To be approved as a lead verifier for verification of CFP project reports and quarterly 
reports submitted by producers and importers of gasoline or diesel, the applicant must 
submit documentation to DEQ in the application that demonstrates experience with oil and 
gas systems. This evidence may include accreditation as an oil and gas systems sector specific verifi er. 
(7) Application information and criteria for approval as a sector specific verifier. To be approved as a sector specific verifier, in addition to submitting information as required by section (4), the applicant must also submit documentation to DEQ in the application 
demonstrating at least two years of professional experience related to the sector in which the 
individual is seeking approval.  
(8) Verification training and exam requirements.  
(a) To be approved by DEQ, applicants must take DEQ -approved general verification 
training, sector specific verification training, CFP specific verification training, and GHG 191 
 Reporting Program specific verification training, as made available and deemed applicable 
by DEQ based on the application submitted to DEQ and for the type of approval the applicant has requested. 
(b) Applicants must receive a passing score of greater than an unweighted 70 percent on an 
exit examination.  
(A) If the applicant does not pass the exam after the training, the applicant may retake the exam a second time.  
(B) Only one retake of the examination is allowed before the applicant must retake the applicable training.  
Statutory/Other Authority: ORS 468.020, 468A.050, 468A.266, 468A.271, 468A.277 & 468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050, 468A.265 through 468A.277 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0220  
 DEQ Review and Approval of Verification Bodies and Verifiers  
(1) DEQ application review and approval process for verification bodies and verifiers.  
(a) After receipt of an application under OAR 340 -272- 0210, DEQ will inform the applicant 
either that a submitted application is complete or that additional specific information is 
required to make the application complete. If the application is incomplete, DEQ will not consider the application further until the applicant provides the additional  information 
requested by DEQ. 
(b) DEQ will review submitted applications to prescreen and ensure all requirements are 
met. DEQ will notify an applicant in writing which verification training(s) and exam(s) are required to be completed according to OAR 340-272-0210(8). An applicant may choose to take trainings and exams in addition to those required by DEQ. 
(c) DEQ will not consider or issue final approval until DEQ finds an application for 
approval as a verification body or verifier is complete and meets all applicable requirements under OAR 340-272-0210(1) and all required verification training(s) and exam(s), as deemed applicable by DEQ under subsection (b), have been completed according to OAR 340-272-0210(8). 192 
 (d) Following completion of the application process and all applicable training and 
examination requirements, DEQ will notify the applicant in writing if approval has been granted or denied. 
(A) DEQ may issue approval to verification bodies, verifiers, lead verifiers, and sector 
specific verifiers that apply and meet the criteria under OAR 340 -272-0210 and successfully 
complete verification training(s) and exam(s) as required under OAR 340 -272-0210(8). 
(B) DEQ approval will be limited to certain report types, data types, sources of emissi ons, or 
sectors, according to the information in the application and the qualifications of the 
applicant and based on DEQ’s determination of whether the applicant demonstrates, to 
DEQ’s satisfaction, sufficient knowledge of the relevant methods and require ments in this 
division, OAR chapter 340, division 215, and OAR chapter 340, division 253, as applicable. 
(C) DEQ will maintain a current list of approved verification bodies, verifiers, lead verifiers, 
and sector specific verifiers on DEQ’s website.  
(e) DE Q approval is valid for a period of three years from the date the approval is issued by 
DEQ. The applicant may re-apply for approval as a verification body, verifier, lead verifier, or sector specific verifier  at any time,  following the same application procedures according 
to OAR 340-272-0210 and must satisfy all DEQ training and examination requirements applicable at the time of re -application.  
(2) Requirements to maintain DEQ approval.  
(a) Except as provided under subsection (c) below, a verification body, verifier, lead verifier, or sector specific verifier must  notifiy notify DEQ within 30 calendar days of when it no 
longer meets the requirements for approval under OAR 340-272- 0210, as applicable.  
(b) A verification body must notify DEQ of any verifier staffing changes within 30 calendar 
days of any such change as these changes are considered an amendment to the verification body’s approval. 
(c) DEQ must be notified immediately if a verification body or verifier loses or withdraws from accreditation under any program specified or approved under OAR 340-272-0210(2)(a). 
(d) Within 20  calendar  days of being notified of any nonconformance in another voluntary 
or mandatory greenhouse gas emissions reporting program or fuels program, a DEQ-approved verification body or verifier must provide written notice to DEQ of the non-conformance, including a copy of any written notification of nonconformance from the agency or body that administers the program, and information about any corrective actions taken by the verification body or verifier. That notification must include reasons for the corrective action and the type of corrective action. The verification body or verifier must provide additional information to DEQ upon request. 193 
 (e) Verification bodies and verifiers must provide in a reasonably timely manner any and all 
information that DEQ reasonably requires for the purpose of evaluating continued compliance with the requirements of this division, including the  criteria for approval.  
(3) Modification, suspension, or revocation of DEQ approval. 
(a) DEQ may modify, suspend, or revoke an approval to perform verification if a 
verification body or verifier: 
(A) Fraudulently obtained or attempted to obtain accreditation under any program specified 
under OAR 340-272-0210(2)(a); 
(B) Fraudulently obtained or attempted to obtain approval from DEQ under this division;  
(C) Failed at any time to satisfy the eligibility criteria and requirements specified under 
OAR 340 -272-0210; 
(D) Does not satisfy the requirements to maintain approval according to section (2); 
(E) Provided verification services that failed to meet the requirements under OAR 340 -272-
0300(1) and (3);  
(F) Violated the conflict of interest requirements under OAR 340-272-0500; or 
(G) Knowingly or recklessly submitted false or inaccurate information or verification 
statement(s) to DEQ.  
(b) A verifier or verification body that is subject to a DEQ action to modify, suspend, or revoke an approval to perform verificatio n may contest DEQ’s action by providing DEQ 
with a written request for a hearing within 20 calendar days of being notified of DEQ’s 
action. 
(A) The hearing will be conducted as a contested case under ORS 183.413 through 183.470 and OAR chapter 340, division 11. 
(B) Any DEQ action taken in subsection (a) will remain in place pending the outcome of the 
contested case.  
(c) A verification body or verifier that has had approval to perform verification revoked may re-apply according to OAR 340-272- 0210 after the applicant demonstrates to DEQ that the 
cause of the revocation has been resolved.  
(4) Voluntary withdrawal from DEQ approval. An approved verification body or verifier may request to voluntarily withdraw its approval by providing a written notice to DEQ requesting such withdrawal. 194 
 Statutory/Other Authority: ORS 468.020, 468A.050, 468A.266, 468A.271, 468A.277 & 
468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050, 468A.265 through 468A.277 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0300  
 Requirements for Verification Services  
(1) Verification services provided and completed must meet the requirements of OAR 340 -
272-0405 through OAR 340-272-0495, as applicable to the type of CFP report or fuel pathway application submitted under OAR chapter 340, division 253 or emissions data report submitted under OAR chapter 340, division 215. 
(2) Requirements for responsible entities.  
(a) Responsible entities must engage the services of a verif ication body that meets the 
requirements and criteria under OAR 340-272-0210 and has been approved by DEQ under 
OAR 340 -272-0220 to perform verification under this division for the type of verification 
services applicable to the responsible entity.  
(b) A responsible entity that has been notifednotified  by DEQ or by it’s verification body 
that the verification body’s DEQ approval has been suspended or revoked, must engage the services of a different DEQ -approved verification body to perform verification. 
(c) Each responsible entity must ensure that the verification services provided on its behalf 
meet the requirements of this division.  
(d) Records retention and availability requirements.  
(A) Responsible entities must retain records necessary for completing verification services and records requested by the verification team according to the recordkeeping requirements of OAR chapter 340, division 215 or OAR chapter 340, division 253, as applicable. 
(B) Responsible entities must retain for verification purposes and make available to the 
verification team the following: 
(i) All information and documentation used to calculate and report emissions, fuel 
quantities, and fuels and electricity transactions;  
(ii) All data and information required by or submitted under OAR chapter 340, division 215 or OAR chapter 340, division 253; and 195 
 (iii) Other data and information as necessary in order for verification services to be 
completed. 
(C) Responsible entities must maintain documentation to support any revisions made to the 
initial report or fuel pathway application submitted to DEQ as a result of verification. 
Documentation for all submittals must be retained by the responsible entity in paper or electronic format for a period of at least seven years.  
(3) Requirements for verification bodies and verifiers.  
(a) Eligibility to perform verification.  
(A) A verification body or verifier must meet the requirements and criteria of OAR 340 -
272-0210 and must have DEQ approval under OAR 340-272-0220 to be eligible to perform verificatio n under this division. 
(B) Verifiers must be employed by, or contracted with a DEQ- approved verification body in 
order to provide verification services under this division.  
(b) Subcontracting. 
(A) Any verification body that elects to subcontract a portion of verification services must 
meet the following requirements:  
(i) The verification body must assume full responsibility for verification services provided 
by subcontractor verifiers; 
(ii) A verification body may not use subcontractors to meet the minimum lead verifier 
requirements as specified under OAR 340-272- 0210(3)(a); and A verification body that 
engages a subcontractor shall be responsible for demonstrating an acceptable level of 
conflict of interest, as provided in OAR 340-272-0500, between its subcontractor and the 
reporting entity for which it will provide verification services; 
(iii) A ver ification body that engages a subcontractor is responsible for ensuring  the 
subcontractor shall not further subcontract or outsource verification services for a reporting 
entity.  
(iii) A verification body may not use a subcontractor as the independent reviewer. 
(B) All subcontractors must apply for and meet the requirements and criteria for DEQ approval under OAR 340-272-0210 and be approved by DEQ under OAR 340-272-0220 in order to provide the verification services for which the subcontractor has been engaged by the verification body. 
(c) If a verification body receives a final determination frinfrom DEQ under OAR 340 -272-
0220(3) that is described in paragraphs (A) through (C) below,, then the verification body 196 
 must provide written notification all responsible entities with which it is currently engaged 
to provide verification services or that have received verification services from it within the past six months of DEQ’s final determination within ten calendar days of receiving such 
final determination, and the verification body may not continue to provide verification services until the verification body receives DEQ approval to recommence such services under OAR 340-272-0220: 
(A) Any modification relevant to the verification services provided;  
(B) Suspension of DEQ approval of the verification body or any of its verifiers, lead verifiers, sector specific verifiers, or subcontractors; or  
(C) Revocation of DEQ approval of the verification body or any of its verifiers, lead verifiers, sector specific verifiers, or subcontractors.  
(d) Recor ds retention.  
(A) Verification bodies that provide verification services under this division must retain documentation relating to verification in paper or electronic format for a period of at least seven years following the submission of each verification  statement.  
(B) The documentation must allow for a transparent review of how a verification body reached its conclusion in the verification statement, including independent review. At a minimum, the documentation retained must include: 
(i) Report(s) or fue l pathway application(s) submitted by the responsible entity to DEQ for 
which verification services are being provided;  
(ii) Contracts for verification;  
(iii) Verification plan(s);  
(iv) Sampling plan(s);  
(v) Verification report(s); 
(vi) Verification statement(s); and  
(vii) Any other documentation, calculations, and verification notes developed as part of 
providing and completing verification services.  
Statutory/Other Authority: ORS 468.020, 468A.050, 468A.266, 468A.271, 468A.277 & 468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050, 468A.265 through 468A.277 & 468A.280 197 
 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020  
 
340-272-0405  
 
Notice of Verification Services  
(1) Before a verification body commences any verification services for the responsible entity, the responsible entity must ensure the verification body submits a notice of verification services to DEQ that meets the requirements of this rule. The notice of 
verification services must be submitted after DEQ has provided a determination that the potential for a conflict of interest is acceptable as specified under OAR 340 -272-0500(7) and 
that verification services may proceed.  
(a) If the conflict of interest evaluation submitted by the responsible entity and the notice of verification services submitted by the verification body are submitted at the same time, verification services may not begin until DEQ has determined the potential for conflict of 
interest is acceptable in writing.  
(b) Except as provided in subsection (a), the verification body may begin verification services for the responsible entity after the notice of verificat ion services is received by 
DEQ but  must allow a minimum of 14 calendar days advance notice of a site visit unless an 
earlier date is approved by DEQ. The site visit may not take place prior to the applicable 
regulatory deadline for the reporting type to be verified, except under the conditions listed in 
OAR 340 -272-0420(2)(a).  
(2) The verification notice must include the following information:  
(a) A list of the staff designated to provide verification services as a verification team, including the names of each individual, the lead verifier, and all subcontractors, and a description of the roles and responsibilities each member will have during verification. The independent reviewer must also be listed separately . The list must include any verifiers in 
training who will participate on the verification team. ; 
(b) Documentation that the verification team has the skills required to provide verification services for the responsible entity and type of report or fuel pathway application requiring verification. When required by DEQ, the notice must include a demonstration that the verification team includes at least one individual approved by DEQ as a sector specific verifier that is not also the independent reviewer, but may be the lead verifier; a nd 
(c) General information about the responsible entity, including the following, as applicable: 
(A) Name and list of facilities and other locations that will be subject to verification, and contact, address, telephone number, and e- mail address for each facility;  198 
 (B) The industry sector, North American Industry Classification System (NAICS) code, or 
source identification number for reporting facilities under OAR chapter 340, division 215.; 
(C) The CFP ID(s) for the responsible entity under OAR chapte r 340, division 253.; 
(D) The date(s) of the site visit if full verification is being provided and if required under 
OAR 340 -272-0420, with physical address and contact information.; and 
(E) A brief description of expected verification services to be provided, including expected completion date and whether quarterly review is planned in the context of an annual verification requirement.  
(3) The responsible entity must ensure the verification body submits an updated notice of verification services to DEQ immediately if any of the information under section (2) changes after the notice of verification services is submitted to DEQ. When an updated notice of verification services is submitted to DEQ, the conflict of interest must be reevaluated,  and information must be resubmitted according to OAR 240-272-0500. 
Verification services must be suspended until DEQ approves the resubmitted conflict of interest evaluation information in writing.  
Statutory/Other Authority: ORS 468.020, 468A.050, 468A.266, 468A.271, 468A.277 & 468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050, 468A.265 through 468A.277 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0415  
 Verification Plan  
(1) Verification services must include the development of a verification plan that meets the requirements of this rule.  
(2) All verification plans must contain information o n the timing of verification services, 
including: 
(a) Dates of proposed meetings and interviews with with personnel of the responsible entity;  
(b) Dates of proposed site visits;  
(c) Types of proposed document and data reviews and, for CFP reports submitted under OAR chapter 340, division 253, how quarterly review is planned in the context of an annual verification requirement, as applicable; and  199 
 (d) Expected date for completing verification services.  
(3) In addition to the information required unde r section (2), verification plans for 
verification services provided for CFP reports and fuel pathways applications submitted 
under OAR chapter 340, division 253 must also include the following information from the 
responsible entity:  
(a) Information to allow the verification team to develop an understanding of facility or 
entity boundaries, operations, accounting practices, type of CFP report(s) the person is responsible for, CFP regulatory sections the responsible entity is subject to, other renewable 
or low carbon fuels markets the responsible entity participates in, and other mandatory or 
voluntary auditing programs the responsible entity is subject to, as applicable;  
(b) Information regarding the training or qualifications of personnel involved in devel oping 
the report(s) or fuel pathway application(s);  
(c) Description of the specific methodologies used to quantify and report data, including but 
not limited to calibration procedures and logs for measurement devices capturing site -
specific data;  
(d) Information about the data management system and accounting procedures used to 
capture and track data for each fuel pathway application and each type of CFP report as 
needed to develop the verification plan;  
(e) Information about the entities in the supply chai n upstream and downstream of the fuel 
producer that contribute to site -specific CI data, including a list of feedstock suppliers and 
contact names with physical addresses;  
(f) Evidence demonstrating that any joint applicants are being separately verified; and  
(g) Previous CFP verification reports, as applicable, and other audit reports including reports 
from production or management system certifications and internal audits.  
(4) In addition to the information required under section (2), verification plans for 
verification services provided for GHG Reporting Program emissions data reports submitted under OAR chapter 340, division 215 must also include the following information from the 
responsible entity:  
(a) Information to allow the verif ication team to develop a general understanding of facility 
or entity boundaries, operations, emissions sources, and electricity or fuel transactions, as applicable;  
(b) Information regarding the training or qualifications of personnel involved in developi ng 
the emissions data report;  200 
 (c) Description of the specific methodologies used to quantify and report greenhouse gas 
emissions, electricity and fuel transactions, and associated data as needed to develop the verification plan;  
(d) Information about the d ata management system used to track greenhouse gas emissions, 
electricity and fuel transactions, and associated data as needed to develop the verification plan; and 
(e) Previous GHG Reporting Program verification reports. 
Statutory/Other Authority: ORS 468 .020, 468A.050, 468A.266, 468A.271, 468A.277 & 
468A.280 
Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050, 468A.265 through 468A.277 & 468A.280 History:  
DEQ 14-2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0450  
 Material Misstatement Assessments for CFP Fuel Pathways and Quarterly Fuel Transactions Submitted under OAR Chapter 340, Division 253  
(1) The verificat ion team must conduct separate assessments of material misstatement on 
each calculated operational CI value and each quarterly fuel transaction quantity for each fuel pathway code (expressed in units from the applicable sections of OAR  chatper chapter  
340 division 253). Material misstatement assessments are not conducted for quarterly review.  
(2) Assessments of material misstatement of carbon intensity must meet all the requirements of this section.  
(a) Each fuel pathway CI is subject to data ch ecks under OAR 340-272-0430 and must be 
assessed separately for material misstatement of its carbon intensity. The inputs and annual operational carbon intensity for fuel pathway codes that are not a recertification of a California Fuel Pathway Code(s) but  have an active California Fuel Pathway Code(s) must 
be assessed.  
(b) Material misstatement of carbon intensity includes any discrepancy as described in paragraph (A) of this subsection, omission as described in paragraph (B) of this subsection, or misrepo rting as described in paragraph (C) of this subsectiob,subsection,  or aggregation 
of the three, identified in the course of verification services that leads a verification team to believe that the reported operational CI (grams of carbon dioxide equivalent per megajoule or gCO2e/MJ) in a CFP fuel pathway application or report contains one or more errors that, individually or collectively, result in an overstatement or understatement more than five 201 
 percent of the reported operational CI, or 2 gCO2e/MJ, which ever absolute value expressed 
in gCO2e/MJ is greater.  
(A) Discrepancies include any differences between the reported site-specific CI inputs and 
the verifier’s calculated site -specific CI inputs subject to data checks under OAR 340-272-
0430. 
(B) Omissions include any site- specific CI inputs or associated source data the verifier 
concludes must be part of a fuel pathway application or report but were not included. 
(C) Misreporting includes duplicate, incomplete, or other CI input data the verifier 
concludes should or should not be part of a fuel pathway application or report. 
(c) One or more material misstatements of carbon intensity will result in a finding of 
material misstatement for the fuel pathway application or report.  
(d) A controlled version of the Simplified CI Calculator for Tier 1 pathways, a DEQ -
approved OR-GREET for Tier 2 pathways, or another substantially equivalent model approved by DEQ for the specific fuel pathway application under OAR 340-253-0400(1), as applicable, must be populated to ass ess whether a fuel pathway application or report 
contains a material misstatement of carbon intensity.  
(e) The following equations for percent error, relative error threshold, and absolute error threshold must be used to determine whether any reported oper ational CI value contains a 
material misstatement of carbon intensity and must be included in the final verification report according to OAR 340-272-0495. 
Percent error (CI) = (∑ | Difference in CI | ÷ | Reported Operational CI |) × 100%  
Relative error threshold (CI) = | Difference in CI | ≥ 0.05 × |Reported Operational CI Value|  
Absolute error threshold (CI) = | Difference in CI | ≥ 2 g CO2e/MJ  
(3) Assessments of material misstatement of quarterly fuel quantity for each fuel pathway 
code must meet all the requirements of this section.  
(a) Each aggregated quarterly fuel quantity for each fuel pathway code is subject to data checks under OAR 340-272- 0430 and must be assessed separately for material misstatement 
of quarteryquarterly  fuel quantity. 
(b) Material misstatement of quarterly fuel quantity includes any discrepancy as described in paragraph (A) of this subsection, omission as described in paragraph (B) of this subsection, or misreporting as described in paragraph (C) of this subsection, or aggregation of the three, identified in the course of verification services that leads a verification team to believe that the reported fuel quantity for each fuel pathway code per quarter in a CFP quarterly report 202 
 contains one or more errors that, individually or collectively, result in an overstatement or 
understatement greater than five percent.  
(A) Discrepancies include any differences between the fuel quantity for the fuel pathway code reported and the verifier’s review of calculation o f fuel quantity subject to data checks 
under OAR 340-272-0430. 
(B) Omissions include any fuel quantity the verifier concludes must be part of a quarterly 
report but was not included. 
(C) Misreporting includes duplicate, incomplete, or other fuel quantity data the verifier 
concludes should or should not be part of a quarterly report. 
(c) One or more material misstatements of quarterly fuel quantity will result in a finding of 
material misstatement for the annual verification of the quarterly fuel quantity fo r each fuel 
pathway code. 
(d) The following equation for percent error must be used to determine whether any 
quarterly fuel quantity for each fuel pathway code contains a material misstatement of quarterly fuel quantity and must be included in the final ve rification report according to 
OAR 340 -272-0495. 
Percent error (fuel quantity) =  
(∑(DiscrepenciesDiscrepancies + Omissions + Misreporting) ÷ Reported quarterly fuel 
transaction quantity for fuel pathway code) × 100%  
(e) When evaluating material misstatemen t of quarterly fuel quantity, correctly substituted 
missing data must be deemed to be accurate, regardless of the amount of missing data. 
Statutory/Other Authority: ORS 468.020, 468A.266, 468A.271 & 468A.277 
Statutes/Other Implemented: ORS 468A.010, 468A.015 & 468A.265 through 468A.277 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0455  
 Material Misstatement Assessments for CFP Project Reports Submitted under OAR Chapter 340, Division 253 
(1) The verification team must conduct separate assessments of material misstatement of project data for each CFP project report submitted under OAR chapter 340, division 253. The assessments of material misstatement of projet project  data must meet all of the 
requirements of this rule.  203 
 (2) Material misstatement of project data includes any discrepancy as described in 
subsection (a) of this section, omission as described in subsection (b) of this section, or misreporting as described in subsection (c) of this section, or aggregation of the three, identified in the course of verification services that leads a verification team to believe that the project report conta ins one or more errors that, individually or collectively, result in an 
overstatement greater than five percent of the responsible entity’s reported emissions reductions. 
(a) Discrepancies include any differences between the reported emissions reductions a nd the 
verifier’s calculated value based on data checks under OAR 340 -272-0430. 
(b) Omissions include any emissions, excluding any emissions reductions, the verifier 
concludes must be part of a project report, but were not included. 
(c) Misreporting includ es duplicate, incomplete, or other emissions or emissions reductions 
data the verifier concludes should or should not be part of a project report. 
(3) A material misstatement of project data is not found when discrepancies, omissions, or 
misreporting, or an aggregation of the three, result in an understatement of reported emissions reductions in the project report. 
(4) The following equation for percent error must be used to determine whether the 
greenhouse gas reductions quantified and reported in the proj ect report contain a material 
misstatement of project data and must be included in the final verification report according to OAR 340 -272-0495. 
Percent error (project data) = (∑(DiscrepenciesDiscrepancies  + Omissions + Misreporting) ÷ 
Reported emissions reduction) × 100%  
(5) Any discrepancies, omissions, or misreporting found must include the positive or negative impact on the reported emissions reductions when entered in the equation in section (4). 
(6) When evaluating material misstatement of project data, correctly substituted missing data must be deemed to be accurate, regardless of the amount of missing data.  
Statutory/Other Authority: ORS 468.020, 468A.266, 468A.271 & 468A.277 Statutes/Other Implemented: ORS 468A.010, 468A.015 & 468A.265 through 468A.277 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
340-272-0460  
 
Material Misstatemen t Assessments for Emissions Data Submitted under OAR 
Chapter 340, Division 215 204 
 (1) The verification team must conduct separate assessments for material misstatement of 
total reported emissions for each emissions data report submitted under OAR chapter 340, division 215. The assessments of material misstatement of emissions data must meet all of the requirements of this rule.  
(2) Material misstatement of emissions data includes any discrepancy as described in subsection  
(a) of this section, omission as described in subsection (b) of this section, or misreporting as 
described in subsection (c) of this section, or aggregation of the three, identified in the 
course of verification services that leads a verification team to believe that the total reported 
emissi ons (metric tons of CO2e) in a GHG Reporting Program emissions data report 
contains errors greater than five percent.  
(a) Discrepancies include any differences between the reported emissions and the verifier’s review of emissions for a data source subject to data checks under OAR 340-272-0430. 
(b) Omissions include any emissions the verifier concludes must be part of an emissions 
data report but were not included.  
(c) Misreporting includes duplicate, incomplete, or other emissions the verifier concludes should or should not be part of an emissions data report. 
(3) Each emissions data report is subject to data checks under OAR 340 -272-0430 and must 
be assessed separately for material misstatement of emissions data.  
(4) The following equation for percent error must be used to determine whether the total 
reported emissions in an emissions data report contain a material misstatement of emissions data and must be included in the final verification report according to OAR 340-272-0495. 
Percent error (emissions) = (∑(DiscrepenciesDiscrepancies + Omissions + Misreporting) ÷ 
Total reported emissions) × 100%  
(5) When evaluating material misstatement, correctly substituted missing data must be deemed to be accurate, regardless of the amount of missing data. 
Statutory/Other Authority: ORS 468.020, 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
340-272-0470  
 
Review of Operations and Emissions for Emissions Data Reports Submitted under OAR Chapter 340, Division 215  205 
 (1) Verification services for verification of GHG Reporting Prog ram emissions data reports 
submitted under OAR chapter 340, division 215 must include review that meets all of the 
requirements of this rule.  
(2) Facility operations must be reviewed to identify applicable greenhouse gas emissions sources, and the review m ust: 
(a) Be conducted by the verification team;  
(b) Include a review of the emissions inventory and each type of emissions source to ensure that all sources specified under OAR 340-215-0030 are included in the emissions data report, as applicable; and  
(c) Review the reported current primary and any secondary (if reported) NAICS codes to ensure they accurately represent the NAICS -associated activities for the facility. The review 
of these NAICS codes and associated activities must be docu mented in the sampling plan. If 
the reported NAICS code(s) is determined to be inaccurate and the responsible entity does not submit a revised emissions data report to correct the current NAICS code(s), the result will be an adverse verification statement.  
(3) Electricity transaction records must be reviewed, including but not limited to written power contracts and any other applicable information required to confirm reported electricity procurements and deliveries. Documentation retained by the responsible entity to support claims of specified sources of electricity, as required under OAR 340-215-0042(6) must be reviewed to ensure it is sufficient to support the claim. Verifiers must use professional judgment to determine whether the records reta ined authenticate the claim.  
(4) Information regarding increases or decreases in emissions, as required under OAR 340 -
215-0044(4) must be reviewed to ensure it is reported in conformance with the requirements 
of that division, however, the narrative descri ption itself is not subject to the verification 
requirements of this division. 
(5) Supporting documentation retained by the responsible entity to authenticate the purchase of gaseous or liquid biomass- derived fuels  or hydrogen, as required under OAR 340-215-
0042(4) must be reviewed to ensure it is sufficient to authenticate the purchase. Verifiers must use professional judgment to determine whether the records retained authenticate the purchase and fuel type.  
(a) For biomethane  
 and hydrogen reported under O AR chapter 340, division 215 the verifier 
must: 
(A) Examine all applicable nomination, invoice, scheduling, allocation, transportation, 
storage, in-kind fuel purchase and balancing reports from the producer to the reporting entity 
and have reasonable assur ance that the reporting entity is contractually receiving the 
identified fuel;  206 
 (B) Determine that the biomethane  met pipeline quality standards;  
(C) Review documentation that confirms the  gas was contractually delivered to Oregon; 
(D) Review attestations regarding environmental attributes confirming that no other party 
can make a claim on attributes that are being reported under OAR  chapter  340, division 215;  
(E) If book and claim accounting methodology was used to report contractual deliveries of 
gas, the verifier must also review documentation to confirm the reported quantity of gas was 
injected into a natural gas pipeline network connected to Oregon within the emissions data 
year;  and 
(F) If an electronic tracking system approved by DEQ is used for book and claim, the 
verifier must review records  from the tracking system showing the retirement of all 
environmental attributes of that fuel that are being reported under division  215. 
Statutory/Other Authority: ORS 468.020, 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0495  
 Independent Review and Completion of Verification Services  
(1) Verification statement. The verification body must complete a verification statement(s) upon completion of verification services, provide its statement to the responsible entity, and submit its statement to DEQ by the applicable verification deadline spe cified under OAR 
340-272-0100(3). Each positive, qualified positive, or adverse verification statement must describe the findings of the verification; and  
(a) For every qualified positive verification statement, the verification body must explain the 
nonconformances contained within the report or fuel pathway application and cite the 
sections(s) in OAR chapter 340, division 215, or OAR chapter 340, division 253, as applicable, that corresponds to the nonconformance and why the nonconformances do not result in a material misstatement; and  
(b) For every adverse verification statement, the verification body must explain all nonconformances or material misstatements leading to the adverse verification statement and cite the sections(s) in OAR chapter 340, division 215, or OAR chapter 340, division 253, as applicable, that corresponds to the nonconformance(s) and material misstatement(s). 
(2) Independent review. The verification body must have the verification services and findings of the verification team indepen dently reviewed by an independent reviewer before 
each verification statement is completed. The independent reviewer must be employed by 207 
 the verification body and must be a lead verifier not involved in verification services for the 
responsible entity duri ng that reporting year or for that fuel pathway application period but 
does not need to be a sector specific verifer verifier . The independent reviewer must: 
(a) Serve as a final check on the verification team’s work to identify any significant concerns, in cluding: 
(A) Errors in planning; 
(B) Errors in data sampling; and  
(C) Errors in judgment by the verification team that are related to the draft verification 
statement;  
(b) Maintain independence from the verification services by not making specific recommendations about how the verification services should be performed; and 
(c) Review documents applicable to the verification services provided and identify any 
failure to comply with requirements of this division, OAR chapter 340, division 215, OAR 
chapter 340, division 253, and with the verification body’s internal policies and procedures for providing verification services, as applicable. The independent reviewer must concur with the verification findings before the verification body issues the verifi cation statement.  
(3) As part of completing verification services, the verification body must:  
(a) Provide the responsible entity with the following: 
(A) A detailed verification report, that must at a minimum include:  
(i) A list of all verification team members that provided verification services, including 
identification of verifiers, lead verifiers, sector specific verifiers, verifiers in training and the 
independent reviewer; 
(ii) A detailed description of the facility  or entity including all data sources and boundaries; 
(ii) A detailed description of the accounting procedures and data management systems, including data acquisition, tracking, and emissions calculation, as applicable;  
(iii) The verification plan; 
(iv) Th e detailed comparison of the data checks conducted during verification services; 
(v) The log of issues identified in the course of verification services and their resolution; 
(vi) Any qualifying comments on findings during verification services; 208 
 (vii) Findings of omissions, discrepancies, and misreporting, and the material misstatement 
calculations required under OAR 340-272- 0450, OAR 340-272-0455, or OAR 340-272-
0460, as applicable; and 
(viii) For CFP reports submitted under OAR chapter 340, division 253, a detailed 
description of entities in the supply chain contributing CI parameters; and 
(B) The verification statement(s); and  
(b) Have a final discussion with the responsible entity explaining the verification team’s 
findings and  notify the responsible entity of any unresolved issues noted in the issues log 
before the verification statement is finalized.  
(4) Attestations in the verification statement. The verification statement must contain the following attestations:  
(a) The verification body must attest w hether it has found the submitted report or fuel 
pathway application to be free of material misstatement, and whether the report or fuel pathway application is in conformance with the requirements of this division, OAR chapter 340, division 215, and OAR chapter 340, division 253, as applicable; 
(b) The lead verifier on the verification team must attest that the verification team has 
carried out all verification services as required by this division; and  
(c) The lead verifier that has performed the independent review of verification services and findings must attest to  his or her their independent review on behalf of the verification body 
and his or her their concurrence that the findings are true, accurate, and complete. 
(5) Procedures for potential adverse verification statement and petition process.  
(a) Before the verification body submits an adverse verification statement to DEQ, the verification body must  notify the responsible entity of the potential of an adverse 
verification statement, and the responsible entity must be provided at least 14 calendar days 
to make modifications to correct any material misstatements or nonconformance found by 
the verificat ion team. When a verification body has provided notification to a responsible 
entity under this subsection: 
(A) The responsible entity must make modifications to correct any material misstatements or 
nonconformance found by the verification team; 
(B) The modified report and verification statement must be submitted to DEQ before the applicable verification deadline specified in OAR 340 -272-0100(3), even if the responsible 
entity makes a request to DEQ according to subsection (b); and 209 
 (C) The verification body must provide notice to DEQ of the potential for an adverse 
verification statement at the same time it notifies the responsible entity and include in its notice to DEQ the current issues log. 
(b) When a verification body has provided notice under subsecti on (a) and the responsible 
entity and the verification body cannot reach agreement on modifications that result in a 
positive or qualified positive verification statement because of a disagreement on the requirements of this division, the responsible entity may petition DEQ before the verification deadline and before the verification statement is submitted to make a final decision as to the verifiability of the submitted report or fuel pathway application. When the responsible entity files such petition with DEQ:  
(A) The responsible entity must submit all information it believes is necessary for DEQ to make a determination with its petition; 
(B) The responsible entity and the verification body must submit to DEQ within ten calendar 
days any additional information requested by DEQ; 
(C) DEQ will review the information submitted and  based on the requirements of this 
division and that information, will make a determination on whether modifications are necessary in order for the verification body to issue a positive or qualified positive verification statement, or if such a statement could be issued without modifications; and  
(D) DEQ will notify both the responsible entity and the verification body of its determination.  
Statutory/Other Authority: ORS 468.020, 468A.050, 468A.266, 468A.271, 468A.277 & 468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050, 468A.265 through 468A.277 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
  210 
 Draft Rules – Edits Included  
 
Enforcement Procedure and Civil Penalties, Division 12  
 
340-012-0054  
 
Air Quality Classification of Violations  
(1) Class I:  
(a) Constructing a new source or modifying an existing source without first obtaining a 
required New Source Review/Prevention of Significant Deterioration (NSR/PSD) permit;  
(b) Constructing a new source, as defined in OAR 340- 245-0020, without first obtaining a 
required Air Contaminant Discharge Permit that includes permit conditions required under OAR 340 -245-0005 through 340- 245-8050 or without complying with Cleaner Air Oregon 
rules under OAR 340- 245-0005 through 340- 245-8050;  
(c) Failing to conduct a source risk assessment, as required under OAR 340 -245-0050;  
(d) Modifying a source in such a way as to require a permit modification under OAR 340-245-0005 through 340- 245-8050, that would increase risk above permitted levels under 
OAR 340 -245-0005 through 340- 245-8050 without first obtaining such approval from DEQ;  
(e) Operating a major source, as defined in OAR 340 -200-0020, without first obtaining the 
required permit;  
(f) Operating an existing source, as defined in OAR 340- 245-0020, after a submittal 
deadl ine under OAR 340 -245-0030 without having submitted a complete application for a 
Toxic Air Contaminant Permit Addendum required under OAR 340- 245-0005 through 340-
245-8050;  
(g) Exceeding a Plant Site Emission Limit (PSEL);  
(h) Exceeding a risk limit, inclu ding a Source Risk Limit, applicable to a source under OAR 
340-245-0100;  
(i) Failing to install control equipment or meet emission limits, operating limits, work practice requirements, or performance standards as required by New Source Performance 
Standards under OAR 340 division 238 or National Emission Standards for Hazardous Air 
Pollutant Standards under OAR 340 division 244;  
(j) Exceeding a hazardous air pollutant emission limitation;  
(k) Failing to comply with an Emergency Action Plan;  211 
 (l) Exceeding an opacity or emission limit (including a grain loading standard) or violating 
an operational or process standard, that was established under New Source Review/Prevention of Significant Deterioration (NSR/PSD); 
(m) Exceeding an emission limit or violating an operational or process standard that was 
established to limit emissions to avoid classification as a major source, as defined in OAR 340-200-0020;  
(n) Exceeding an emission limit or violating an operational limit, process limit, or work 
practi ce requirement that was established to limit risk or emissions to avoid exceeding an 
applicable Risk Action Level or other requirement under OAR 340- 245-0005 through 340-
245-8050;  
(o) Exceeding an emission limit, including a grain loading standard, by a ma jor source, as 
defined in OAR 340- 200-0020, when the violation was detected during a reference method 
stack test;  
(p) Failing to perform testing or monitoring, required by a permit, permit attachment, rule or order, that results in failure to show complian ce with a Plant Site Emission Limit or with an 
emission limitation or a performance standard established under New Source 
Review/Prevention of Significant Deterioration, National Emission Standards for Hazardous 
Air Pollutants, New Source Performance Stand ards, Reasonably Available Control 
Technology, Best Available Control Technology, Maximum Achievable Control 
Technology, Typically Achievable Control Technology, Lowest Achievable Emission Rate, 
Toxics Best Available Control Technology, Toxics Lowest Achie vable Emission Rate, or 
adopted under section 111(d) of the Federal Clean Air Act;  
(q) Causing emissions that are a hazard to public safety;  
(r) Violating a work practice requirement for asbestos abatement projects;  
(s) Improperly storing or openly accumul ating friable asbestos material or asbestos -
containing waste material;  
(t) Conducting an asbestos abatement project, by a person not licensed as an asbestos 
abatement contractor;  
(u) Violating an OAR 340 division 248 disposal requirement for asbestos -conta ining waste 
material;  
(v) Failing to hire a licensed contractor to conduct an asbestos abatement project;  
(w) Openly burning materials which are prohibited from being open burned anywhere in the 
state by OAR 340- 264-0060(3), or burning materials in a solid fuel burning device, 
fireplace, trash burner or other device as prohibited by OAR 340- 262-0900(1);  
(x) Failing to install certified vapor recovery equipment;  212 
 (y) Delivering for sale a noncompliant vehicle by a vehicle manufacturer in violation of 
Oregon L ow Emission and Zero Emission Vehicle rules set forth in OAR 340 division 257;  
(z) Exceeding an Oregon Low Emission Vehicle average emission limit set forth in OAR 340 division 257;  
(aa) Failing to comply with Zero Emission Vehicle (ZEV) sales requirements , or to meet 
credit retirement and/or deficit requirements, under OAR 340 division 257; 
(bb) Failing to obtain a Motor Vehicle Indirect Source Permit as required in OAR 340 
division 257;  
(cc) Selling, leasing, or renting a noncompliant vehicle by an automobile dealer or rental car agency in violation of Oregon Low Emission Vehicle rules set forth in OAR 340 division 
257; 
(dd) Violating any of the clean fuel standards set forth in OAR 340- 253-0100(6) and in 
Tables 1 and 2 of OAR 340- 253-8010;  
(ee) Committing  any action related to a credit transfer that is prohibited in OAR 340 -253-
1005(8);  
(ff) Inaccurate reporting that causes illegitimate credits to be generated in the Oregon Clean Fuels Program, OAR chapter 340, division 253, or that understates a registere d party’s true 
compliance obligation in deficits under such program;  
(gg) Misstating material information or providing false information when submitting an 
application for a carbon intensity score under OAR 340- 253-0450, OAR 340- 253-0460, or 
OAR 340 -253-0470, or when submitting an application for advance credits under OAR 340-
253-1100;  
(hh) Failing to timely submit a complete and accurate annual compliance report under OAR 340-253-0650;  
(ii) Failing to timely submit a complete and accurate emissions data report under OAR 340-215-0044 and OAR 340- 215-0046;  
(jj) Submitting a verification statement to DEQ prepared by a person not approved by DEQ 
under OAR 340- 272-0220 to perform verification services;  
(kk) Failing to timely submit a verification statement that meets the verification 
requirements under OAR 340- 272-0100 and OAR 340- 272-0495;  
(ll) Failing to submit a revised application or report to DEQ according to OAR 340 -272-
0435;  
(mm) Failing to complete re -verification according to OAR 340-272-0350(2);  
(nn) Failing to timely submit a Methane Generation Rate Report or Instantaneous Surface Monitoring Report according to OAR 340- 239-0100;  213 
 (oo) Failing to timely submit a Design Plan or Amended Design Plan in accordance with 
OAR 340 -239-0110(1); 
(pp) Failing to timely install and operate a landfill gas collection and control system according to OAR 340- 239-0110(1);  
(qq) Failing to operate a landfill gas collection and control system or conduct performance 
testing of a landfill gas control device according to the requirements in OAR 340- 239-
0110(2);  
(rr) Failing to conduct landfill wellhead sampling under OAR 340- 239-0110(3);  
(ss) Failing to comply with a landfill compliance standard in OAR 340- 239-0200;  
(tt) Failing to conduct monitoring or re monitoring in accordance with OAR 340- 239-0600 
that results in a failure to demonstrate compliance with a landfill compliance standard in 
OAR 340 -239-0200 or the 200 ppmv threshold in OAR 340- 239-0100(6)(b) or OAR 340-
239-0400(2)(c);  
(uu) Failure to take c orrective actions in accordance with OAR 340 -239-0600(1);  
(vv) Failing to comply with a landfill gas collection and control system permanent shutdown and removal requirement in OAR 340- 239-0400(1);  
(ww) Delivering for sale a new noncompliant on highway hea vy duty engine, truck or trailer 
in violation of rules set forth under OAR 340 division 261;  
(xx) Failing to notify DEQ of changes in ownership or operational control or changes to 
related entities under OAR 340- 271-0120;  
(yy) Owning or operating a covered entity, identified in OAR 340- 271-0110, after a 
submittal deadline under OAR 340- 271-0150(1)(a) or OAR 340- 271-0330(1)(b) without 
having submitted a complete application for a Climate Protection Program permit or Climate Protection Program permit addendum required under OAR 340- 271-0150;  
(zz) Emitting covered emissions from a covered entity, as identified in OAR 340 -271-0110, 
that is a new source, as defined in OAR 340 -271-0020, without having been issued a BAER 
order under OAR 340- 271-0320 and a permit is sued under OAR 340- 271-0150(3)(c);  
(aaa) Failing to submit a BAER assessment, updated BAER assessment, or a 5 -year BAER 
report according to OAR 340- 271-0310;  
(bbb) Failing to comply with a BAER order issued under OAR 340- 271-0320. 
(ccc) Failing to comply w ith a condition in a permit, Climate Protection Program permit, or 
Climate Protection Program permit addendum issued according to OAR 340- 271-0150 that 
requires the reduction of greenhouse gas emissions;  
(ddd) Failing to demonstrate compliance according to OAR 340 -271-0450;  214 
 (eee) Failing to comply with the requirements for trading of compliance instruments under 
OAR 340 -271-0500 or 340- 271-0510;  
(fff) Submitting false or inaccurate information on any application or submittal required under OAR chapter 340, division 271;  
(ggg) Failing to register as a regulated party in the Oregon Clean Fuels Program under OAR 
340-253-0100(1) and (4); or  
(hhh) Failing by a fuel producer to inform DEQ if its operational carbon intensity exceeds its 
certified carbon intensity a s described in OAR 340 -253-0450(9)(e)(D) when credits 
generated from those certified carbon intensity values generated illegitimate credits as described in OAR 340- 253-1005(7). . 
(2) Class II:  
(a) Constructing or operating a source required to have an Air Contaminant Discharge 
Permit (ACDP), ACDP attachment, or registration without first obtaining such permit or registration, unless otherwise classified;  
(b) Violating the terms or conditions of a permit, permit attachment or license, unless otherwise classi fied; 
(c) Modifying a source in such a way as to require a permit or permit attachment modification from DEQ without first obtaining such approval from DEQ, unless otherwise classified;  
(d) Exceeding an opacity limit, unless otherwise classified;  
(e) Exceeding a Volatile Organic Compound (VOC) emission standard, operational requirement, control requirement or VOC content limitation established by OAR 340 division 232;  
(f) Failing to timely submit a complete ACDP annual report or permit attachment annua l 
report;  
(g) Failing to timely submit a certification, report, or plan as required by rule, permit or permit attachment, unless otherwise classified;  
(h) Failing to timely submit a complete permit application, ACDP attachment application, or 
permit renewa l application;  
(i) Failing to submit a timely and complete toxic air contaminant emissions inventory as 
required under OAR 340 -245-0005 through 340- 245-8050;  
(j) Failing to comply with the open burning requirements for commercial, construction, 
demolition, or industrial wastes in violation of OAR 340- 264-0080 through 0180;  215 
 (k) Failing to comply with open burning requirements in violation of any provision of OAR 
340 division 264, unless otherwise classified; or burning materials in a solid fuel burning devic e, fireplace, trash burner or other device as prohibited by OAR 340- 262-0900(2). 
(l) Failing to replace, repair, or modify any worn or ineffective component or design element to ensure the vapor tight integrity and efficiency of a stage I or stage II vapor collection system;  
(m) Failing to provide timely, accurate or complete notification of an asbestos abatement 
project;  
(n) Failing to perform a final air clearance test or submit an asbestos abatement project air 
clearance report for an asbestos abatement project;  
(o) Violating on road motor vehicle refinishing rules contained in OAR 340 -242-0620;  
(p) Failing to comply with an Oregon Low Emission Vehicle reporting, notification, or 
warranty requirement set forth in OAR division 257; 
(q) Failing to receive G reen-e certification for Renewable Energy Certificates used to 
generate incremental credits when required by OAR 340- 253-0470;  
(r) Failing to register as an aggregator or submit an aggregator designation form under OAR 
340-253-0100(3) and (4)(c);  
(s) Failing to keep complete and accurate records under OAR 340- 253-0600;  
(t) Failing to ensure that a registered party has the exclusive right to the environmental 
attributes that it has claimed for biomethane, biogas, or renewable electricity either directly 
as a fuel or indirectly as a feedstock under OAR chapter 340, division 253 by either the 
registered party, the fuel producer, and/or fuel pathway holder;  
(u) Failing to timely submit a complete and accurate quarterly report under OAR 340 -253-
0630;  
(v) Violatin g any requirement under OAR chapter 340, division 272, unless otherwise 
classified;  
(w) Violating any requirement under OAR chapter 340, division 239, unless otherwise classified;  
(x) Failing to comply with the reporting notification or warranty requirements for new 
engines, trucks, and trailers set forth in OAR chapter 340, division 261;  
(y) Violating any requirement under the Climate Protection Program, OAR chapter 340, 
division 271, unless otherwise classified;  
(z) Violating any condition in a permit, Cl imate Protection Program permit, or Climate 
Protection Program permit addendum issued according to OAR 340- 271-0150, unless 
otherwise classified;  216 
 (aa) Failing to notify DEQ of a change of ownership or control of a registered party under 
OAR chapter 340, division 253; or 
(3) Class III: 
(a) Failing to perform testing or monitoring required by a permit, rule or order where missing data can be reconstructed to show compliance with standards, emission limitations or underlying requirements; 
(b) Constructing or o perating a source required to have a Basic Air Contaminant Discharge 
Permit without first obtaining the permit;  
(c) Modifying a source in such a way as to require construction approval from DEQ without 
first obtaining such approval from DEQ, unless otherwi se classified;  
(d) Failing to revise a notification of an asbestos abatement project,  when necessary, unless 
otherwise classified;  
(e) Submitting a late air clearance report that demonstrates compliance with the standards for an asbestos abatement project; 
(f) Licensing a noncompliant vehicle by an automobile dealer or rental car agency in 
violation of Oregon Low Emission Vehicle rules set forth in OAR Chapter 340, division 
257; 
(g) Making changes to a submitted quarterly or annual report under OAR Chapter 340, 
division 253 without DEQ approval under OAR 340-253-0650(4); or 
(h) Failing to upload transactions to a quarterly report by the 45-day deadline under OAR 
340-253-0630. 
[Note: Tables and Publications referenced are available from the agency.]  
Statutory/Other Authority: ORS 468.020, 468A.025 & 468A.045 
Statutes/Other Implemented: ORS 468.020 & 468A.025 
History:  
DEQ 16 -2022, amend filed 09/23/2022, effective 09/23/2022
 
DEQ 11 -2022, minor correction filed 08/09/2022, effective 08/09/2022  
DEQ 27 -2021, amend filed 12/16/2021, effective 12/16/2021  
DEQ 17 -2021, amend filed 11/17/2021, effective 11/17/2021  
DEQ 16 -2021, amend filed 10/04/2021, effective 10/04/2021  
DEQ 14 -2020, amend filed 05/07/2020, effective 05/07/2020  
DEQ 199 -2018, amend filed 11/16/2018, effective 01/01/2019  
DEQ 197 -2018, amend filed 11/16/2018, effective 11/16/2018  
DEQ 13 -2015, f. 12-10- 15, cert. ef. 1-1-16 
DEQ 1 -2014, f. & cert. ef. 1-6-14 
DEQ 2 -2011, f. 3-10-11, cert. ef. 3- 15-11 
DEQ 6 -2006, f. & cert. ef. 6-29-06 217 
 DEQ 4 -2006, f. 3- 29-06, cert. ef. 3- 31-06 
Renumbered fro m 340 -012-0050, DEQ 4- 2005, f. 5- 13-05, cert. ef. 6- 1-05 
DEQ 6 -2001, f. 6- 18-01, cert. ef. 7- 1-01 
DEQ 19 -1998, f. & cert. ef. 10- 12-98 
DEQ 22 -1996, f. & cert. ef. 10- 22-96 
DEQ 21 -1994, f. & cert. ef. 10- 14-94 
DEQ 13 -1994, f. & cert. ef. 5- 19-94 
DEQ 4 -1994, f. & cert. ef. 3 -14-94 
DEQ 20 -1993(Temp), f. & cert. ef. 11- 4-93 
DEQ 19 -1993, f. & cert. ef. 11- 4-93 
DEQ 21 -1992, f. & cert. ef. 8- 11-92 
DEQ 2 -1992, f. & cert. ef. 1- 30-92 
DEQ 31 -1990, f. & cert. ef. 8- 15-90 
DEQ 15 -1990, f. & cert. ef. 3- 30-90 
DEQ 4 -1989, f. & cert. ef. 3 -14-89 
DEQ 22 -1988, f. & cert. ef. 9- 14-88 
DEQ 22 -1984, f. & ef. 11- 8-84 
DEQ 5 -1980, f. & ef. 1 -28-80 
DEQ 78, f. 9- 6-74, ef. 9 -25-74 
 
340-012-0135  
 
Selected Magnitude Categories 
(1) Magnitudes for selected Air Quality violations will be determined as follows:  
(a) Opacity limit violations:  
(A) Major — Opacity measurements or readings of 20 percent opacity or more over the 
applicable limit, or an opacity violation by a federal major source as defined in OAR 340 -
200-0020;  
(B) Moderate — Opac ity measurements or readings greater than 10 percent opacity and less 
than 20 percent opacity over the applicable limit; or  
(C) Minor — Opacity measurements or readings of 10 percent opacity or less over the 
applicable limit.  
(b) Operating a major source, as defined in OAR 340- 200-0020, without first obtaining the 
required permit: Major — if a Lowest Achievable Emission Rate (LAER) or Best Available 
Control Technology (BACT) analysis shows that additional controls or offsets are or were 
needed, otherwise apply OAR 340- 012-0130. 218 
 (c) Exceeding an emission limit established under New Source Review/Prevention of 
Significant Deterioration (NSR/PSD): Major — if exceeded the emission limit by more than 
50 percent of the limit, otherwise apply OAR 340 -012-0130.  
(d) Exceeding an emission limit established under federal National Emission Standards for Hazardous Air Pollutants (NESHAPs): Major — if exceeded the Maximum Achievable 
Control Technology (MACT) standard emission limit for a directly -measured hazardous air 
pollutant (HAP), otherwise apply OAR 340- 012-0130. 
(e) Exceeding a cancer or noncancer risk limit that is equivalent to a Risk Action Level or a Source Risk Limit if the limit is a Risk Action Level established under OAR 340 -245-0005 
through 340 -245-8050: Maj or, otherwise apply OAR 340- 012-0130. 
(f) Air contaminant emission limit violations for selected air pollutants: Magnitude determinations under this subsection will be made based upon significant emission rate (SER) amounts listed in OAR 340 -200-0020. 
(A) Major:  
(i) Exceeding the annual emission limit as established by permit, rule or order by more than 
the annual SER; or  
(ii) Exceeding the short -term (less than one year) emission limit as established by permit, 
rule or order by more than the applicable short -term SER.  
(B) Moderate:  
(i) Exceeding the annual emission limit as established by permit, rule or order by an amount 
from 50 up to and including 100 percent of the annual SER; or  
(ii) Exceeding the short -term (less than one- year) emission limit as established by permit, 
rule or order by an amount from 50 up to and including 100 percent of the applicable short -
term SER.  
(C) Minor:  
(i) Exceeding the annual emission limit as established by permit, rule or order by an amount 
less than 50 percent of the annual SER; or  
(ii) Exceeding the short -term (less than one year) emission limit as established by permit, 
rule or order by an amount less than 50 percent of the applicable short -term SER.  
(g) Violations of Emergency Action Plans: Major — Major magnitude i n all cases.  
(h) Violations of on road motor vehicle refinishing rules contained in OAR 340- 242-0620: 
Minor — Refinishing 10 or fewer on road motor vehicles per year.  
(i) Asbestos violations — These selected magnitudes apply unless the violation does not 
cause the potential for human exposure to asbestos fibers:  219 
 (A) Major — More than 260 linear feet or more than 160 square feet of asbestos -containing 
material or asbestos -containing waste material;  
(B) Moderate — From 40 linear feet up to and including 260 l inear feet or from 80 square 
feet up to and including 160 square feet of asbestos -containing material or asbestos -
containing waste material; or  
(C) Minor — Less than 40 linear feet or 80 square feet of asbestos -containing material or 
asbestos -containing wa ste material.  
(D) The magnitude of the asbestos violation may be increased by one level if the material 
was comprised of more than five percent asbestos.  
(j) Open burning violations:  
(A) Major — Initiating or allowing the initiation of open burning of 20 o r more cubic yards 
of commercial, construction, demolition and/or industrial waste; or 5 or more cubic yards of 
prohibited materials (inclusive of tires); or 10 or more tires;  
(B) Moderate — Initiating or allowing the initiation of open burning of 10 or more, but less 
than 20 cubic yards of commercial, construction, demolition and/or industrial waste; or 2 or 
more, but less than 5 cubic yards of prohibited materials (inclusive of tires); or 3 to 9 tires; 
or if DEQ lacks sufficient information upon which to make a determination of the type of 
waste, number of cubic yards or number of tires burned; or  
(C) Minor — Initiating or allowing the initiation of open burning of less than 10 cubic yards 
of commercial, construction, demolition and/or industrial waste; or  less than 2 cubic yards of 
prohibited materials (inclusive of tires); or 2 or less tires.  
(D) The selected magnitude may be increased one level if DEQ finds that one or more of the following are true, or decreased one level if DEQ finds that none of the following are true:  
(i) The burning took place in an open burning control area;  
(ii) The burning took place in an area where open burning is prohibited;  
(iii) The burning took place in a non -attainment or maintenance area for PM10 or PM2.5; or  
(iv) The burning took place on a day when all open burning was prohibited due to meteorological conditions.  
(k) Oregon Low Emission Vehicle Non- Methane Gas (NMOG) or Green House Gas (GHG) 
fleet average emission limit violations:  
(A) Major — Exceeding the limit by more than 10 percent; or  
(B) Moderate — Exceeding the limit by 10 percent or less.  
(l) Oregon Clean Fuels Program violations:  220 
 (A) Violating the clean fuel standards set forth in OAR 340 -253-0100(6) and Tables 1 and 2 
of OAR 340 -253-8010: Major  
(B) Failing to re gister under OAR 340- 253-0100(1) and (4): Major;  
(C) Failing to timely submit a complete and accurate annual compliance report or quarterly 
report under OAR chapter 340, division 253: Major;  
(D) Generating an illegitimate credit under OAR chapter 340, divi sion 253: Major;  
(E) Committing any action related to a credit transfer that is prohibited under OAR 340 -253-
1005(8): Major.  
(m) Failing to timely submit a complete and accurate emissions data report under the Oregon Greenhouse Gas Reporting Program, OAR chapter 340, division 215, where the 
untimely, incomplete or inaccurate reporting impacts applicability, distribution of 
compliance instruments, or any compliance obligation under the Climate Protection 
Program, OAR chapter 340, division 271: Major.  
(n) Oregon Climate Protection Program violations:  
(A) Failing to demonstrate compliance according to OAR 340 -271-0450: Major.  
(B) Failing to comply with a BAER order issued under OAR 340- 271-0320: Major  
(C) Failing to comply with a condition in a pe rmit, Climate Protection Program permit, or 
Climate Protection Program permit addendum issued according to OAR 340- 271-0150 that 
requires the reduction of greenhouse gas emissions: Major.  
(D) Failing to obtain a BAER order under OAR 340- 271-0320 or a permi t issued under 
OAR 340 -271-0150(3)(c), for a covered entity, as identified in OAR 340- 271-0110, that is a 
new source, as defined in OAR 340- 271-0020: Major.  
(2) Magnitudes for selected Water Quality violations will be determined as follows:  
(a) Violating w astewater discharge permit effluent limitations:  
(A) Major:  
(i) The dilution (D) of the spill or technology based effluent limitation exceedance was less 
than two, when calculated as follows: D = ((QR /4) + QI)/ QI, where QR is the estimated 
receiving stre am flow and QI is the estimated quantity or discharge rate of the incident; 
(ii) The receiving stream flow at the time of the water quality based effluent limitation 
(WQBEL) exceedance was at or below the flow used to calculate the WQBEL; or  
(iii) The resu lting water quality from the spill or discharge was as follows:  
(I) For discharges of toxic pollutants: CS/D was more than CAcute, where CS is the concentration of the discharge, D is the dilution of the discharge as determined under 221 
 (2)(a)(A)(i), and CAcu te is the concentration for acute toxicity (as defined by the applicable 
water quality standard);  
(II) For spills or discharges affecting temperature, when the discharge temperature is at or 
above 32 degrees centigrade after two seconds from the outfall; o r 
(III) For BOD5 discharges: (BOD5)/D is more than 10, where BOD5 is the concentration of 
the five -day Biochemical Oxygen Demand of the discharge and D is the dilution of the 
discharge as determined under (2)(a)(A)(i).  
(B) Moderate:  
(i) The dilution (D) of the spill or the technology based effluent limitation exceedance was 
two or more but less than 10 when calculated as follows: D = ((QR /4)+ QI )/ QI, where QR 
is the estimated receiving stream flow and QI is the estimated quantity or discharge rate of 
the discharge; or  
(ii) The receiving stream flow at the time of the WQBEL exceedance was greater than, but less than twice, the flow used to calculate the WQBEL.  
(C) Minor:  
(i) The dilution (D) of the spill or the technology based effluent limitation exceedan ce was 
10 or more when calculated as follows: D = ((QR/4) + QI)/ QI, where QR is the receiving 
stream flow and QI is the quantity or discharge rate of the incident; or  
(ii) The receiving stream flow at the time of the WQBEL exceedance was twice the flow or  
more of the flow used to calculate the WQBEL.  
(b) Violating numeric water quality standards:  
(A) Major:  
(i) Increased the concentration of any pollutant except for toxics, dissolved oxygen, pH, and 
turbidity, by 25 percent or more of the standard;  
(ii) De creased the dissolved oxygen concentration by two or more milligrams per liter below 
the standard;  
(iii) Increased the toxic pollutant concentration by any amount over the acute standard or by 
100 percent or more of the chronic standard;  
(iv) Increased or decreased pH by one or more pH units from the standard; or  
(v) Increased turbidity by 50 or more nephelometric turbidity units (NTU) over background. 
(B) Moderate:  
(i) Increased the concentration of any pollutant except for toxics, pH, and turbidity by more 
than 10 percent but less than 25 percent of the standard;  222 
 (ii) Decreased dissolved oxygen concentration by one or more, but less than two, milligrams 
per liter below the standard;  
(iii) Increased the concentration of toxic pollutants by more than 10 percent but less than 100 percent of the chronic standard;  
(iv) Increased or decreased pH by more than 0.5 pH unit but less than 1.0 pH unit from the 
standard; or  
(v) Increased turbidity by more than 20 but less than 50 NTU over background. 
(C) Minor:  
(i) Increased the concentration of any pollutant, except for toxics, pH, and turbidity, by 10 
percent or less of the standard;  
(ii) Decreased the dissolved oxygen concentration by less than one milligram per liter below the standard;  
(iii) Increase d the concentration of toxic pollutants by 10 percent or less of the chronic 
standard;  
(iv) Increased or decreased pH by 0.5 pH unit or less from the standard; or  
(v) Increased turbidity by 20 NTU or less over background.  
(c) The selected magnitude under ( 2)(a) or (b) may be increased one or more levels if the 
violation:  
(A) Occurred in a water body that is water quality limited (listed on the most current 303(d) list) and the discharge is the same pollutant for which the water body is listed;  
(B) Depressed  oxygen levels or increased turbidity and/or sedimentation in a stream in 
which salmonids may be rearing or spawning as indicated by the beneficial use maps 
available at OAR 340- 041-0101 through 0340;  
(C) Violated a bacteria standard either in shellfish growing waters or during the period from 
June 1 through September 30; or  
(D) Resulted in a documented fish or wildlife kill.  
(3) Magnitudes for selected Solid Waste violations will be determined as follows:  
(a) Operating a solid waste disposal facility witho ut a permit or disposing of solid waste at 
an unpermitted site:  
(A) Major — The volume of material disposed of exceeds 400 cubic yards;  
(B) Moderate — The volume of material disposed of is greater than or equal to 40 cubic 
yards and less than or equal to 400 cubic yards; or  
(C) Minor — The volume of materials disposed of is less than 40 cubic yards.  223 
 (D) The magnitude of the violation may be raised by one magnitude if the material disposed 
of was either in the floodplain of waters of the state or within 100 feet of waters of the state.  
(b) Failing to accurately report the amount of solid waste disposed:  
(A) Major — The amount of solid waste is underreported by 15 percent or more of the 
amount received;  
(B) Moderate — The amount of solid waste is underreported  by 5 percent or more, but less 
than 15 percent, of the amount received; or  
(C) Minor — The amount of solid waste is underreported by less than 5 percent of the 
amount received.  
(4) Magnitudes for selected Hazardous Waste violations will be determined as follows:  
(a) Failure to make a hazardous waste determination;  
(A) Major — Failure to make the determination on five or more waste streams;  
(B) Moderate — Failure to make the determination on three or four waste streams; or  
(C) Minor — Failure  to make the determination on one or two waste streams.  
(b) Hazardous Waste treatment, storage and disposal violations of OAR 340 -012-
0068(1)(b), (c), (h), (k), (l), (m), (p), (q) and (r):  
(A) Major:  
(i) Treatment, storage, or disposal of more than 55 gall ons or 330 pounds of hazardous 
waste; or  
(ii) Treatment, storage, or disposal of at least one quart or 2.2 pounds of acutely hazardous 
waste.  
(B) Moderate:  
(i) Treatment, storage, or disposal of 55 gallons or 330 pounds or less of hazardous waste; or  
(ii) Treatment, storage, or disposal of less than one quart or 2.2 pounds of acutely hazardous 
waste.  
(c) Hazardous waste management violations classified in OAR 340 -012-0068(1)(d), (e) (f), 
(g), (i), (j), (n), (s) and (2)(a), (b), (d), (e), (h), (i), (k), (m),  (n), (o), (p), (r) and (s):  
(A) Major:  
(i) Hazardous waste management violations involving more than 1,000 gallons or 6,000 
pounds of hazardous waste; or  
(ii) Hazardous waste management violations involving at least one quart or 2.2 pounds of 
acutely haza rdous waste.  224 
 (B) Moderate:  
(i) Hazardous waste management violations involving more than 250 gallons or 1,500 
pounds, up to and including 1,000 gallons or 6,000 pounds of hazardous waste; or 
(ii) Hazardous waste management violations involving less than one quart or 2.2 pounds of 
acutely hazardous waste.  
(C) Minor: Hazardous waste management violations involving 250 gallons or 1,500 pounds or less of hazardous waste and no acutely hazardous waste.  
(5) Magnitudes for selected Used Oil violations (OAR 340 -012-0072) will be determined as 
follows:  
(a) Used Oil violations set forth in OAR 340 -012-0072(1)(f), (h), (i), (j); and (2)(a) through 
(h): 
(A) Major — Used oil management violations involving more than 1,000 gallons or 7,000 
pounds of used oil or used oil m ixtures;  
(B) Moderate — Used oil management violations involving more than 250 gallons or 1,750 pounds, up to and including 1,000 gallons or 7,000 pounds of used oil or used oil mixture; or 
(C) Minor — Used oil management violations involving 250 gallons or 1,750 pounds or less 
of used oil or used oil mixtures. 
(b) Used Oil spill or disposal violations set forth in OAR 340 -012-0072(1)(a) through (e), 
(g) and (k).  
(A) Major — A spill or disposal involving more than 420 gallons or 2,940 pounds of used 
oil or used oil mixtures;  
(B) Moderate — A spill or disposal involving more than 42 gallons or 294 pounds, up to and 
including 420 gallons or 2,940 pounds of used oil or used oil mixtures; or 
(C) Minor — A spill or disposal of used oil involving 42 gallons or 294 pounds or less of 
used oil or used oil mixtures.  
[NOTE: Tables & Publications referenced are available from the agency.]  
Statutory/Other Authority: ORS 468.065 & 468A.045 
Statutes/Other Implemented: ORS 468.090 - 468.140 & 468A.060 History:  
DEQ 16 -2022, amend filed 09/23/2022, effective 09/23/2022
 
DEQ 27 -2021, amend filed 12/16/2021, effective 12/16/2021  
DEQ 14 -2020, amend filed 05/07/2020, effective 05/07/2020  
DEQ 199 -2018, amend filed 11/16/2018, effective 01/01/2019  
DEQ 197 -2018, amend filed 11/16/2018, effective 11/16/2018  
DEQ 13 -2015, f. 12-10- 15, cert. ef. 1-1-16 
DEQ 1 -2014, f. & cert. ef. 1-6-14 225 
 DEQ 6 -2006, f. & cert. ef. 6- 29-06 
DEQ 4 -2006, f. 3- 29-06, cert. ef. 3 -31-06 
Renumbered from 340 -012-0090, DEQ 4- 2005, f. 5- 13-05, cert. ef. 6- 1-05 
DEQ 1 -2003, f. & cert. ef. 1- 31-03 
DEQ 19 -1998, f. & cert. ef. 10- 12-98 
DEQ 4 -1994, f. & cert. ef. 3- 14-94 
DEQ 21 -1992, f. & cert. ef. 8- 11-92 
  226 
 Greenhouse Gas Reporting Program, Division 215  
 
340-215-0020  
Definitions  
The definitions in OAR 340- 200-0020 and this rule apply to this division. If the same term is 
defined in this rule and OAR 340- 200-0020, the definition in this rule applies to this 
division.  
(2) “As set-controlling supplier” or “ACS” means a person that owns or operates inter -
connected electricity generating facilities or has exclusive rights to claim electricity from 
these facilities even though it does not own them, and that has been designated by D EQ as 
an asset -controlling supplier under OAR 340- 215-0120(7) and received a DEQ -published 
emission factor. Asset controlling suppliers are specified sources.  
(3) “Biogas” means gas that is produced from the breakdown of biomass in the absence of 
oxygen, i ncluding anaerobic digestion, anaerobic decomposition, and thermochemical 
decomposition. 
(4) “Biogenic CO2 emissions” means carbon dioxide emissions generated as the result of 
biomass or biomass -derived fuel combustion or oxidation.  
(5) “Biomass” means non -fossilized and biodegradable organic material originating from 
plants, animals, and micro- organisms, including products, byproducts, residues, and waste 
from agriculture, forestry, and related industries, as well as the non -fossilized and 
biodegradable or ganic fractions of industrial and municipal wastes, including gases and 
liquids recovered from the decomposition of non -fossilized and biodegradable organic 
matter.  
(6) “Biomass fuels” or “biofuels” or “biomass -derived fuels” means fuels derived from 
bioma ss. 
(7) “Biomethane” means refined biogas, or another synthetic stream of methane produced 
from biomass feedstock , that has been upgraded to meet pipeline quality standards or 
transportation fuel grade requirements, such that it may blend with, or substitute for, natural gas.  
(8) “Book and Claim” refers to the accounting methodology where the environmental 
attributes of an energy source are detached from the physical molecules when they are commingled into a common transportation and distribution system f or that form of energy. 
The detached attributes are then assigned by the owner to the same form and amount of energy when it is used. For the purposes of this division, the common transportation and distribution system must be connected to Oregon.  227 
 (9) “Bul k transfer/terminal system” means a fuel distribution system consisting of one or 
more of refineries, pipelines, vessels, and terminals. Fuel storage and blending facilities that 
are not fed by pipeline or vessel are considered outside the bulk transfer system.  
(10) “Busbar” means a power conduit of a facility with electricity generating units that 
serves as the starting point for the electricity transmission system.  
(11) “Carbon dioxide supplier” means a facility with production process units or production 
wells that capture, extract, or produce CO₂ for on- site use, commercial application, or for 
purposes of supplying CO₂ to another entity or facility, or that capture the CO₂ stream in 
order to utilize it for geologic sequestration, where capture refers to the initial separation and 
removal of CO₂ from a manufacturing process or any other process. The definition does not 
include transportation, distribution, purification, compression, or processing of CO2. 
(12) “Cease to operate” for the purposes of this div ision means the regulated entity  did not 
operate any GHG –emitting processes for an entire year. Continued operation of space 
heaters and water heaters as necessary until operations are restarted in a subsequent year 
does not preclude a source from meeting this definition.  
(13) “C.F.R.” means Code of Federal Regulations  and unless otherwise expressly identified 
refers to the December 9, 2016 edition . 
(14) “Cogeneration unit” means a unit that produces electric energy and useful thermal 
energy for industrial, commercial, or heating and cooling purposes, through the sequential or 
simultaneous use of the original fuel energy and waste heat recovery.  
(15) “Compressed natural gas” or “ CNG” means natural gas stored inside a pressure vessel 
at a pressure greater than the ambient atmospheric pressure outside of the vessel , (though not 
to the point of liquefaction), typically to pressures ranging from 2900 to 3600 pounds per square inch . 
(16) “Consumer -owned utility” means a people’s utility district organiz ed under ORS 
Chapter 261, a municipal utility organized under ORS Chapter 225, or an electric 
cooperative organized under ORS Chapter 62.  
(17) “Data year” means the calendar year in which emissions occurred.  
(18) “Designated representative” means the person responsible for certifying, signing, and 
submitting a greenhouse gas emissions data report, and any registration or report required to 
be submitted under this division, on behalf of a regulated entity. For owners or operators of 
Oregon Title V Opera ting Permits the designated representative is the responsible official 
and certification must be consistent with OAR 340- 218-0040(5).  
(19) “Direct emissions” means emissions from a stationary  source, including but not limited 
to fuel combustion activities,  process related emissions, and fugitive emissions.  228 
 (20) “EIA” means the Energy Information Administration. The Energy Information 
Administration (EIA) is a statistical agency of the United States Department of Energy.  
(21) “Electricity generating unit” me ans any combination of physically connected 
generator(s), reactor(s), boiler(s), combustion turbine(s), or other prime mover(s) operated 
together to produce electric power.  
(22) “Electricity service supplier” has the meaning given that term in ORS 757.600. 
(23) “Electricity supplier” means persons that import, sell, allocate, or distribute electricity 
to end users in the state, including but not limited to the following types of entities:  
(a) Investor- owned utilities;  
(b) Electricity service suppliers; and  
(c) Consumer -owned utilities.  
(24) “Emissions data report” means the report prepared and submitted to DEQ that provides 
the information required to be reported under this division. The emissions data report is for the year prior to the year in which the re port is due, also known as the data year.  
(25) “Export” means to transport  fuel from locations within Oregon to locations  outside of 
the state, by any means of transport, other than in the fuel tank of a vehicle for the purpose 
of propelling the vehicle.
  
(26) “Fuel supplier” means a supplier of petroleum products, liquid petroleum gas, biomass -
derived fuels, or natural gas including operators of  interstate pipelines, or liquefied natural 
gas. 
(27) “Fluorinated heat transfer fluids” is a fluorinated GHG that has the meaning given to 
that term in 40 C.F.R. 98.98. 
(28) “Environmental Attribute,” for the purposes of reporting biogas, biomethane, and 
hydrogen under this division, means the formal recognition of the biomass -derived attributes 
or that the use of the fuel results in lower greenhouse gas emissions. Such formal 
recognition may include verified emission reductions, voluntary emission reducti ons, 
offsets, allowances, credits, avoided compliance costs, emission rights and authorizations under any law or regulation, or any other comparable emission registry, trading system, or reporting or reduction program for greenhouse gas emissions that is e stablished, certified, 
maintained, or recognized by any international, governmental, or nongovernmental agency.  
(29) "Global warming potential” or "GWP" means the ratio of the time -integrated radiative 
forcing from the instantaneous release of one kilogra m of a trace substance relative to that of 
one kilogram of carbon dioxide (the reference gas). The GWPs used for emissions 229 
 calculation and reporting are specified in 40 C.F.R. part 98, subpart A, Table A –1-Global 
Warming Potentials.  
(30) “Greenhouse gas” o r “GHG” means carbon dioxide (CO2), methane (CH4), nitrous 
oxide (N20), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs), perfluorocarbons 
(PFCs), and other fluorinated greenhouse gases or fluorinated GHG as defined in 40 C.F.R. 
part 98.  
(31) “Gross generation” or “gross power generated” means the total electrical output of the generating facility or unit, expressed in megawatt hours (MWh) per year.  
(32) “High heat value” or “HHV” means the high or gross heat content of the fuel with the 
heat of vaporiz ation included. The water vapor is assumed to be in a liquid state.  
(33) “Hydrofluorocarbons” (HFCs) means gaseous chemical compounds containing only 
hydrogen, carbon, and fluorine atoms. 
(34) “Hydrogen” means diatomic molecular hydrogen. 
(35) To “Import” means owning electricity or fuel from locations outside of Oregon at the 
time electricity is brought into this state through transmission equipment or at the time fuel 
is brought into this state by any means of transport, other than fuel brought into this state in 
the fuel tank of a vehicle used to propel the vehicle.  
(36) “Importer” means:  
(a) Any person that brings a product into Oregon from outside of the state ; or 
(b) With respect to any biomethane, the person who owns the biomethane when it is either 
physically transported into Oregon or  when it is  contractually delivered for use in Oregon 
through a book and claim accounting methodology. 
(37) “In -state producer” means:  
(a) With respect to any liquid fuel, the person who makes the fuel in Oregon; or  
(b) With respect to any gaseous biomass- derived fuel, the person who refines, treats, or 
otherwise produces the fuel  in Oregon; or  
(c) With respect to any natural gas, the person who owns or operates one or more wells 
producing natural gas in Oregon. 
(38) “Interstate pipeline” means a natural gas pipeline delivering natural gas across state 
boundaries for use in Oregon and that is subject to rate regulation by the Federal Energy 
Regulatory Commission (FERC).  230 
 (39) “Investor -owned utility” means a utility tha t sells electricity and that a corporation with 
shareholders operates.  
(40) “Large natural gas end users” means any end user receiving greater than or equal to 
460,000 Mscf during the previous year.  
(41) “Liquefied natural gas” or “LNG” means natural gas t hat is  liquefied.  
(42) “Local distribution company” or “LDC” means a legal entity that owns or operates 
distribution pipelines and that physically delivers natural gas to end users in the state. This 
includes public utility gas corporations and intrastate pipelines engaged in the retail sale, delivery, or both of natural gas. This excludes interstate pipelines.  
(43) “Multi -jurisdictional utility” means a utility that is an electricity retail provider to 
customers in a service territory that is at least part ially located in Oregon and at least one 
other state.  
44) “Metric ton,” “tonne,” “metric tonne,” or “MT” means a common international 
measurement for mass, equivalent to 2204.6 pounds or 1.1 short tons.  
(45) “MMBtu” means million British thermal units.  
(46) “Mscf” means one thousand standard cubic feet.  
(47) “Natural gas”  means a naturally occurring mixture derived from anthropogenic or fossil 
sources of gaseous hydrocarbons and other compounds consisting primarily of methane. For the purposes of this divis ion the term includes natural gas in all gaseous and liquid forms.  
(48) “Natural gas marketer” means a person that arranges for the purchasing or selling of 
natural gas but that does not own physical assets in Oregon used in the supply of natural gas 
such as pipelines.  
(49) “Natural gas supplier” means any person that imports, sells, produces, or distributes 
natural gas to end users in Oregon. 
(50) “Net generation” or “net power generated” means the gross generation minus station 
service or unit service pow er requirements, expressed in megawatt hours (MWh) per year. In 
the case of cogeneration, this value is intended to include internal consumption of electricity for the purposes of a production process, as well as power put on the grid.  
(51) “Perfluorocarbo ns” (PFCs) means gaseous chemical compounds containing only carbon 
and fluorine atoms.  
(52) “Position holder” means any person that has an ownership interest in a specific amount 
of fuel in the inventory of a terminal as reflected in the records of the ter minal operator  or a 
terminal operator that owns fuel in its terminal. This does not include inventory held outside 231 
 of a terminal, retail establishments, or other fuel suppliers not holding inventory at a fuel 
terminal.  
(53) “Power contract” as used for the purposes of documenting specified versus unspecified 
sources of electricity means a written document, including associated verbal or electronic records if included as part of the written power contract, arranging for the procurement of electricity. A p ower contract for a specified source is a contract that is contingent upon 
delivery of power from a particular facility, unit, or asset- controlling supplier’s system that 
is designated at the time the transaction is executed. Power contracts may be, but ar e not 
limited to, power purchase agreements, enabling agreements, electricity transactions, and tariff provisions, without regard to duration, or written agreements to import or export on behalf of another person. 
(54) “Pre -charged equipment” has the meani ng in 40 C.F.R. 98.438. 
(55) “Preference sales” means power distributed by Bonneville Power Administration to 
Oregon consumer-owned utilities, other than “surplus” power as that term is defined in 16 U.S.C. 839c(f) (2017).  
(56) “Rack” means a mechanism for  delivering fuel from a refinery or terminal into a truck, 
trailer, railroad car, or other means of non -bulk transfer.  
(57) “Regulated entity” means any person subject to requirements to register and report under this division, as identified in OAR 340-215-0030. 
(58) “Related entity” means any direct or indirect parent company, direct or indirect 
subsidiary, company that shares ownership of a direct or indirect subsidiary, or company under full or partial common ownership or control. 
(59) “Retail sales” means electricity sold to retail end users.  
(60) “Shut down” means that the regulated entity has evidence that all industrial operations of a regulated entity are permanently shut down, including but not limited to, decommissioning and cancelling air permits. Permanent shutdown may include continued operations of space heaters and water heaters as necessary to support decommissioning activities.  
(61) “Specified source of electricity” or “specified source” means a facility or unit which is allowed to be claimed  as the source of electricity delivered. The regulated entity must have 
either full or partial ownership in the facility or unit, or a written power contract to procure electricity generated by that facility or unit. Specified facilities or units include c ogeneration 
systems. Specified source also means electricity procured from an asset -controlling supplier 
recognized by DEQ.  
(62) “Terminal” means a fuel storage and distribution facility that is supplied by pipeline or vessel, or a facility collocated wher e the fuel is produced and stored, and from which fuel 232 
 may be removed at a rack.  In-state fuel production facilities that have distribution equipment 
that allow them to distribute directly to retail sites or end users meet the definition of a 
terminal.  
(63) “Thermal energy” means the thermal output produced by a combustion source used directly as part of a manufacturing process, industrial or commercial process, or heating or cooling application, but not used to produce electricity. 
(64) “Transmission loss correction factor” or “TL” means the correction to account for 
transmission losses between the busbar and receipt, which is either known if measured at the busbar, or is the default factor equal to 1.02. 
(65) “Unspecified source of electricity” or “unspecified source” means a source of 
electricity that is not a specified source at the time of entry into the transaction to procure the electricity. For the purposes of this division, electricity imported, sold, allocated, or distributed to end users in this state through an energy imbalance market or other centralized market administered by a market operator is considered to be an unspecified source. 
(66) “Verification” means a systematic and documented process for evaluation of an 
emissions data report  as conducted by DEQ or in accordance with OAR chapter 340, 
division 272. 
(67) “Year” means calendar year.  
Statutory/Other Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, amend filed 05/07/2020, effective 05/07/2020
 
DEQ 5 -2019, amend filed 01/24/2019, effective 01/24/2019  
DEQ 124 -2018, minor correction filed 04/11/2018, effective 04/11/2018  
DEQ 12 -2015, f. & cert. ef. 12-10- 15 
DEQ 11 -2011, f. & cert. ef. 7-21-11 
DEQ 12 -2010, f. & cert. ef. 10-27- 10 
DEQ 13 -2008, f. & cert. ef. 10-31- 08 
 
340-215-0030  
Applicability  
(1) This division applies to all persons identified in sections (2) through (6) of this rule, except as provided in OAR 340-215-0032 and 340-215-0034. 
(2) Stationary  sources and e lectric power system facilities . Any person that owns or operates 
a source listed in subsections (a) through (c) must regi ster and report in compliance with this 
division, if the source’s direct GHG emissions meet or exceed 2,500 MT CO2e during the 
previous year. Once a source’s direct GHG emissions meet or exceed 2,500 MT CO2e 233 
 during a year, the person that owns or operates the source must annually register and report 
in each subsequent year, regardless of the amount of the source’s direct GHG emissions in 
future years, except as provided in OAR 340- 215-0032 and OAR 340- 215-0034. 
(a) Any source required to obtain a Title V Operating Permit.  
(b) Any source required to obtain an Air Contaminant Discharge Permit.  
(c) The following sources not otherwise listed in subsection (a) or (b):  
(A) Solid waste disposal facilities required to obtain a permit issued under OAR chapter 
340, di visions 93 through 96, excluding facilities that meet all of the following conditions:  
(i) D id not accept waste during the previous year ; and  
(ii) A re not required to report greenhouse gas emissions to EPA under 40 C.F.R. part 98;  and 
(iii) Are not requir ed to report methane generation rates under OAR chapter 340, division 
239. 
(B) Wastewater treatment facilities required to obtain an individual National Pollutant 
Discharge Elimination System permit issued under OAR chapter 340, division 45; and 
(C) Electric power system facilities as defined in 40 C.F.R. part 98 subpart DD located in 
Oregon and owned or operated by investor -owned utilities.  
(3) Fuel suppliers and in -state producers.  
(a) Except as provided in subsection (b), the following persons that impor t, sell, or distribute 
fuel for use in the state, must register and report in compliance with this division:  
(A) Any dealer, as that term is defined in ORS 319.010 that is subject to the Oregon Motor 
Vehicle and Aircraft Fuel Dealer License Tax under OAR chapter 735, division 170;  
(B) Any seller, as that term is defined in ORS 319.520, that is subject to the Oregon Use Fuel Tax under OAR chapter 735, division 176;  
(C) Any person that produces, imports, sells, or distributes at least 5,500 gallons of gasoline, distillate fuel oil, biofuels, or aircraft fuel during a year for use in the state and that is not subject to the Oregon Motor Vehicle and Aircraft Fuel Dealer License Tax or the Oregon 
Use Fuel Tax under OAR chapter 735, divisions 170 and 176; a nd 
(D) Any person that imports propane for use in the state if the person’s total imports brought 
into the state are equal to or more than 10,500 gallons of propane in a year. 234 
 (b) Persons listed in paragraphs (3)(a)(B) and (C) are not required to register and report fuel 
that is separately reported under this division by dealers described in paragraph (3)(a)(A). 
(4) Natural gas suppliers. Any person, including but not limited to local distribution 
companies, interstate pipelines, and owners or operators of facilities, that either produce 
natural gas, compressed natural gas, or liquefied natural gas in Oregon, or that import, sell, or distribute natural gas, compressed natural gas, or liquefied natural gas to end users in the state, must register and report i n compliance with this division.  
(5) Electricity suppliers. All investor -owned utilities, multi- jurisdictional utilities, electricity 
service suppliers, consumer -owned utilities, and other persons that import, sell, allocate, or 
distribute electricity to end users in the state must register and report in compliance with this division. 
(6) Petroleum and natural gas systems. Any person that owns or operates a facility 
physically located in Oregon that contains petroleum and natural gas systems industry segments listed in 40 C.F.R. 98.230(a)(1) through (10) must register and report in compliance with this division, as applicable under subsections (a) though (e):  
(a) For a facility, as defined in 40 C.F.R. 98.6 that contains the industry segments listed in 40 C.F.R. 98.230(1), (3), (4), (5), (6) or (7), if the facility’s greenhouse gas emissions meet or exceed 2,500 MT CO2e per year. 
(b) For a facility with respect to onshore petroleum and natural gas production as defined in 
40 C.F.R. 98.238, if emission sources specified in 40 C.F.R. 98.232(c) meet or exceed 2,500 MT CO2e per year . 
(c) For a facility with respect to natural gas distribution as defined in 40 C.F.R. 98.238, if emission sources specified in 40 C.F.R. 98.232(i) meet or exceed 2,500 M T CO2e per year . 
(d) For a facility with respect to onshore petroleum and natural gas gathering and boosting as defined in 40 C.F.R. 98.238, if emission sources specified in 40 C.F.R. 98.232(j) meet or exceed 2,500 MT CO2e per year. 
(e) For a facility with  respect to the onshore natural gas transmission pipeline segment as 
defined in 40 C.F.R. 98.238, if emission sources specified in 40 C.F.R. 98.232(m) meet or 
exceed 2,500 MT CO2e per year. 
Statutory/Other Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemented:  ORS 468 & 468A 
History:  
DEQ 14 -2020, amend filed 05/07/2020, effective 05/07/2020
 
DEQ 5 -2019, amend filed 01/24/2019, effective 01/24/2019  
DEQ 12 -2015, f. & cert. ef. 12-10- 15 
DEQ 11 -2011, f. & cert. ef. 7-21-11 235 
 DEQ 12 -2010, f. & cert. ef. 10- 27-10 
DEQ 13 -2008, f. & cert. ef. 10- 31-08 
 
340-215-0034  
Changes in Ownership and Cessation of Reporting Requirements  
(1) Cessation of reporting for reduced emissions.  
(a) A regulated entity is no longer required to report if the regulated entity retains records as 
required in subsection (b), makes the report required in subsection (c), and if any of the following are applicable:  
(A) Direct total reported emissions for stationary  sources required to register and report 
under OAR 340- 215-0030(2) are less than 2,500 MT CO2e per year for a consecutive three 
year period. If total reported emissions for a stationary  source meets or exceeds 2,500 MT 
CO2e in any year after the reporting cessation requirements have been met, persons that own or operate the stationary  source must resume reporting as required under this division;  
(B) Fuel suppliers, including natural gas suppliers, and in- state producers that cease to 
supply fuel in Oregon after submitting an emissions data report for the year in which they ceased to supply fuel in Oregon, provided that:  
(i) Fuel suppliers and in -state producers that cease to have a report ing obligation due to a 
change in ownership or that cease to do business in Oregon must continue to report 
emissions from the reportable fuel transactions that occurred up to the date of the change in 
ownership or up to the date the business ceases to oper ate in the state; and  
(ii) If a fuel supplier or in -state producer supplies fuel in Oregon in any year after the 
reporting cessation requirements have been met, the fuel supplier must resume reporting as 
required under this division;  
(C) Electricity suppli ers that cease to supply electricity in Oregon, after submitting an 
emissions data report for the year in which they ceased to supply electricity in Oregon. If an electricity supplier provides electricity in Oregon in any year after the reporting cessation  
requirements have been met, the electricity supplier must resume reporting as required under this division.  
(b) Persons that cease reporting under this section and are no longer subject to reporting under this division must retain the records required under OAR 340 -215-0042 for a period 
of five years following the last year that they were subject to reporting, including all production information, fuel use records, emission calculations and other records used to document greenhouse gas emissions. Persons m eeting cessation requirements specified in 
paragraph (1)(a)(A) must retain records for each of the three consecutive years that the person does not meet or exceed the emission threshold for a period of five years following the last year they met the cessat ion requirements; and 236 
 (c) Persons that meet the applicable cessation of reporting requirements of this section must 
notify DEQ in writing of their reason(s) for ceasing to report no later than the applicable 
reporting deadline for the year.  
(2) Cessation o f reporting when a stationary source is permanently shut down. If the 
operations of a stationary  source are changed such that all applicable greenhouse gas 
emitting processes and operations permanently  cease to operate or are shut down, then:  
(a) The perso n that owns or operates the stationary  source must submit an emissions data 
report for the year in which the source’s greenhouse gas emitting processes and operations 
ceased to operate;  
(b) The person that owns or operates the stationary  source must submit  a written notification 
to DEQ that announces the cessation of reporting and certifies to the cessation of all greenhouse gas emitting processes and operations no later than the reporting deadline of the 
year following the cessation of operations or permanent shutdown; and 
(c) This section does not apply to seasonal operational cessations, other temporary cessation 
of operations, or solid waste disposal facilities that are required to report under 40 C.F.R. 
part 98.  
(3) Changes in ownership or operational c ontrol. If a regulated entity undergoes a change of 
ownership or operational control, the following requirements apply regarding reporting and providing notice to DEQ:  
(a) The new person that owns or operates the regulated entity must notify DEQ in writing  of 
the ownership or operational control change  within 30 calendar days of the ownership or 
operation control change , including providing the following information:  
(A) T he name of the previous owner or operator;  
(B) T he name of the new owner or operator;  
(C) The date of ownership or operator change ; 
(D) The name of a new designated representative;  
(E) The name of persons managing data and records required to be reported  by this division; 
and 
(F) Any changes to information reported in compliance with OAR 340- 215-0040(6).  
(b) Reporting responsibilities. T he person that owns or operates the regulated entity at the 
time of a reporting deadline specified in this division has  the responsibility for complying 
with the requirements of this division, and:  237 
 (A) Except as specified in paragraph (B), i f an ownership change takes place during the 
year, reported data must not be split or subdivided for the year, based on ownership. A 
single annual emissions data report must be submitted by the person that owns or operates the regulated entity at the time of the applicable reporting deadline ; and 
(B) If an ownership change to a fuel supplier or in -state producer takes place during the 
year, reported data may be subdivided for the year in compliance with OAR 340-215-0034(1)(a)(B)(i) provided that the pe rson that owns or operates the regulated entity at the 
time of the applicable reporting deadline  ensures that all the requirements of this division are 
met by the prior owner or operator.   
(4) Any person specified in OAR 340-215-0030 that has ceased reporting under this rule must resume reporting for any future year during which any of the greenhouse gas emitting processes or operations resu me operation and are subject to reporting as required by this 
division. 
Statutory/Other Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-215-0040  
Greenhouse Gas Registration and Reporting Requirements 
(1) Each registration or emissions data report submitted by a regulated entity according to 
this division must contain certification by a designated representative of the truth, accuracy, and completeness of the submission. This certification and any other certific ation required 
under this division must state that, based on information and belief formed after reasonable inquiry, the statements and information in the document are true, accurate, and complete. 
The certification must contain the following statement: “B ased on information and belief 
formed after reasonable inquiry, I certify under penalty of perjury that the statements and 
information submitted are true, accurate and complete.”  
(2) DEQ may require a regulated entity to submit or make available additional  information if 
the materials submitted with the emissions data report are not sufficient to determine or verify greenhouse gas emissions and related information. Regulated entities must provide within 14 calendar days of notification, unless a different s chedule is approved by DEQ, any 
and all information that DEQ requires for the purposes of assessing applicability, verifying or investigating either or both actual and suspected sources of greenhouse gas emissions, and to ascertain compliance and noncompli ance with rules in this division.  
(3) Calculating total greenhouse gas emissions. Total carbon dioxide equivalent emissions (CO2e) must be calculated as the sum of the CO2, CO2 from biomass -derived fuels, CH4, 
N2O, and each fluorinated GHG required to be r eported in an emissions data report in 
compliance with this division using equation A-1 in 40 C.F.R. 98.2. 238 
 (4) Alternative calculation methods. Regulated entities may petition DEQ to use calculation 
methods other than those specified in this division. Regulated entities must receive written DEQ approval to use alternative calculation methods prior to reporting. 
(5) Third -party verification of emissions data reports. Regulated entities must comply with 
the requirements of OAR chapter 340, division 272 for th ird-party verification of emissions 
data reports, as applicable.  
(6) Fuel suppliers and in -state producers must report legal names and addresses of all related 
entities subject to this division annually by the reporting deadline specified in OAR 340-
215-0046(1)(c). 
(7) A regulated entity may only use book and claim accounting to report contractual 
deliveries of biomethane or hydrogen injected into a pipeline when:
 
(a) The pipeline is part of the natural gas transmission and distribution network connected to Oregon; and 
(b) No person has used or claimed the environmental attributes of such biomethane or 
hydrogen in any other program or jurisdiction with the exception of: 
(A) The federal Renewable Fuel Standard Program, any reporting required under OAR 
chapter 340, division 253, or the program under OAR chapter 340, division 271; or  
(B) With DEQ written approval, any other program or jurisdiction where DEQ has 
confirmed that the claim on the environmental attributes can be made for the same use and volume of biomethane or its derivatives as is being claimed under this division.  
 
Statutory/Other Authority: ORS 468A.050 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, amend filed 05/07/2020, effective 05/07/2020
 
DEQ 5 -2019, amend filed 01/24/2019, effective 01/24/2019  
DEQ 125 -2018, minor correction filed 04/11/2018, effective 04/11/2018  
DEQ 12 -2015, f. & cert. ef. 12-10- 15 
DEQ 11 -2011, f. & cert. ef. 7-21-11 
DEQ 12 -2010, f. & cert. ef. 10-27- 10 
DEQ 13 -2008, f. & cert. ef. 10-31- 08 
 
340-215-0042  
Recordkeeping Requirements  239 
 (1) Each regulated entity subject to the requirements under OAR chapter 340, division 272 
must retain all records as required by this rule, and any records or other materials maintained 
under any applicable requirements of 40 C.F.R. part 98, in paper or electronic format, or both, for a period of at least seven years.  
(2) Each regulated entity not subject to the requirements under OAR chapter 340, division 272 must retain all records as required by this rule, and any records or other materials maintained under any applicable require ments of 40 C.F.R. part 98, in paper or electronic 
format, or both, for a period of at least five years.  
(3) Each regulated entity must retain records sufficient to document and allow for verification of each emissions data report submitted to DEQ and make  such information 
available for verification upon request. This includes, but is not limited to the following: 
(a) A list of all units, operations, processes, and activities for which GHG emission were 
calculated, as applicable;  
(b) The data and informatio n used to calculate emissions for each unit, operation, process, 
and activity, categorized by fuel or material type. These data include, but are not limited to 
the following: 
(A) The GHG emissions calculations and methods used;  
(B) Analytical results for the development of site -specific emissions factors;  
(C) The results of any analyses for high heat value, carbon content, and other fuel or 
feedstock parameters conducted or as required under 40 C.F.R. part 98, if applicable; and 
(D) Any facility operating d ata or process information used for the GHG emission 
calculations;  
(c) Records of supporting documentation required by or used to prepare the emissions data 
report, including but not limited to underlying monitoring and metering data, invoices of 
receipts or deliveries, fuel use records, production information, sales transaction data, 
electricity or fuel transaction data, calibration records, and any other relevant information;  
(d) Any annual emissions data report(s) submitted to DEQ, including any revised emissions 
data report(s);  
(e) Documentation to support any revision(s) made to any emissions data report(s);  
(f) Records of supporting documentation and calculations for any missing data computations 
according to 40 C.F.R. part 98, or otherwise. Retain a r ecord of the cause of the event and 
the corrective actions taken to restore malfunctioning monitoring equipment;  240 
 (g) The results of all required certification and quality assurance tests of continuous 
monitoring systems, fuel flow meters, and other instrum entation used to provide data to 
calculate emissions reported under this division;  
(h) Maintenance records for all continuous monitoring systems, flow meters, and other 
instrumentation used to provide data to calculate emissions reported under this divisi on; and  
(i) The GHG data monitoring plan required under OAR 340 -215-0042(11).  
(4) Regulated entities reporting biomass -derived fuels  or hydrogen, as required under OAR  
340-215-0044(5), must retain supporting documentation that authenticates the purchase 
quantity and quality of  the hydrogen or  gaseous or liquid biomass -derived fuel between 
parties. This supporting documentation:  
(a) May include, but is not limited to, documentation from each upstream party, invoices, bills of lading, shipping reports, balan cing reports, storage reports, in -kind nomination 
reports, allocation, contracts confirming the source of fuel supplied in the state, attestations, information on the environmental attributes associated with the sale or use of the fuel, 
renewable thermal credit records, or any combination therein ; and 
(b) When reporting biogas, biomethane, or hydrogen, must include attestations from each 
upstream party collectively demonstrating that no other upstream party can make a claim on 
environmental attributes that are being reported under this division. The quantity of energy 
covered by the environmental attributes must match or exceed the energy of fuel reported under this division.  
(5) When reporting direct delivery of biogas, biomethane, or hydrogen in Oregon regulated 
entities must retain documentation that shows the fuel type and quantity directly delivered 
from the point of origin to the point of use in Oregon. 
(6) When reporting contractual deliveries of biomethane or hydrogen using book and claim 
accounting t he regulated entity must retain and make available:  
(a) Records demonstrating the specific quantity of gas claimed was injected into a pipeline 
that is part of the natural gas transmission and distribution network connected to Oregon in 
the current data year and link those environmental attributes to a corresponding quantity of 
gas withdrawn for use in Oregon;  
(b) Records demonstrating the quality of the fuel reported;  
(c) Records documenting the fuel production facility, the facility’s production and 
purification process, facility location and feedstock(s). This may include, but is not limited to, documentation of feedstock production and schemata of the production method;  241 
 (d) Records demonstrating the full lifecycle carbon intensity of the reported fuel including 
all records supporting the estimation of the reported carbon intensity value required under 
OAR 340 -215-0044(5)(b)( I); 
(e) If using an electronic tracking system approved by DEQ for book and claim accounting, 
records demonstrating the retirement of all environmental attributes of that fuel that are 
being reported under this division. The quantity of energy covered by the e nvironmental 
attributes must match or exceed the energy of fuel reported under this division;  
(f) Records demonstrating that the retired or claimed environmental attribute was generated 
from gas injected into the pipeline within the same reporting data ye ar; and  
(g) Any records used in the reporting of information required under OAR 340- 215-0044(5)  
(7) Each regulated entity that is an in -state producer or fuel supplier, including a natural gas 
supplier, must retain records for exported products . Records must  demonstrate delivery to a 
final destination outside Oregon, indicate the amount delivered, type of fuel delivered, delivery date and identify the state the fuel was delivered to . This may include, but is not 
limited to, product transfer documents, bills  of lading, invoices, contracts, meter tickets, and 
rail inventory sheets.  
(8) Each regulated entity that is an electricity supplier must retain documentation supporting 
claims of specified sources of electricity.  
(9) Electricity suppliers that sell whole sale electricity must maintain records for each sale of 
specified or unspecified source sales.  
(10) Each person designated by DEQ as an asset -controlling supplier must retain 
documentation to confirm that the power sold by the supplier originated from the  supplier’s 
fleet of facilities and either that the fleet is under the supplier’s operational control or that 
the supplier has exclusive rights to market electricity for the fleet or facility.  
(11) Regulated entities subject to 40 C.F.R. part 98 federal r equirements and any entity 
subject to the requirements under OAR chapter 340, division 272, except electricity 
suppliers, must complete and retain a  written GHG data monitoring plan that meets the 
requirements of 40 C.F.R. part  98.3(g)(5). The GHG data monitoring plan must be made 
available for verification upon request. Electricity suppliers subject to OAR chapter 340, 
division 272 must complete and retain a written GHG data monitoring plan with the following information:  
(a) Information to allow the verif ication team to develop a general understanding of entity 
boundaries, operations, and electricity transactions;  
(b) Reference to management policies or practices applicable to reporting under this division;  242 
 (c) List of key personnel involved in compiling d ata and preparing the emissions data report;  
(d) Documentation of training practices and policies applicable to reporting under this 
division for electricity suppliers;  
(e) Query data to determine the quantity of electricity (MWh) reported and query descri ption;  
(f) Reference to other independent or internal data management systems and records, including written power contracts and associated verbal or electronic records, full or partial ownership, invoices, and settlements data used to document whether reported transactions are specified or unspecified;  
(g) Description of steps taken and calculations made to aggregate data into reporting categories;  
(h) Records of preventive and corrective actions taken to address verifier and DEQ findings of past nonconformances and material misstatements;  
(i) Log of emissions data report modifications; and  
(j) A written description of an internal audit program that includes emissions data report 
review and documents ongoing efforts to improve the GHG data management. 
(12) Regulated entities must make all records required to be created and retained under this 
division, including all required documentation described in this division, available for 
review and verification upon written request by DEQ within 14 calendar days of notification, unless a different schedule is approved by DEQ. 
 
Statutory/Other Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-215-0044  
Emissions Data Reports  
(1) Regulated entities must monitor emissions and submit emissions data reports to DEQ following the requirements specified in this division. Individual emissions data reports are 
identified as follows:  243 
 (a) An individual emissions data report must be submitted by  and for  each stationary source 
and electric power system facili ty required to register and report under OA R 340- 215-
0030(2);  
(b) An individual emissions data report including emissions from all electric power system 
facilities located in Oregon must be submitted by an investor -owned utility required to 
register and report under OAR 340- 215-0030(2)(c)(C);  
(c) A n individual emissions data report must be submitted by each fuel supplier and in- state 
producer required to register and report under OAR 340- 215-0030(3);  
(d) An individual emissions data report must be submitted by each natural gas supplier and 
in-state producer required to register and report under OAR 340- 215-0030(4);  
(e) An individual emissions data report must be submitted by each electricity supplier 
required to register and report under OAR 340- 215-0030(5) and by any third- party that 
reports on beha lf of a consumer -owner utility. A third -party reporting on behalf of a 
consumer -owned utility must also include all information described under OAR 340 -215-
0120(4) and (5), as applicable;  
(f) An individual emissions data report submitted by each asset -controlling supplier seeking 
designation by DEQ must include all information described under OAR 340- 215-0120(7);  
and 
(g) An individual emissions data report must be submitted by the owner or operator of a 
facility containing petroleum and natural gas systems required to register and report under 
OAR 340 -215-0030(6) and must include all emissions and related information described in 
OAR 340 -215-0125. 
(2) When monitor ing emissions and submit ting emissions data reports, r egulated entities 
must:  
(a) Utilize registration and reporting tools approved and issued by DEQ for all certifications 
and submissions;  
(b) Submit and certify completed registration and emissions data reports. A separate 
emissions data report must be submitted for each emission data report type id entified in this 
rule, as applicable,  and for each individual stationary source , and must include all data and 
information as required by OAR 340 -215-0105 through OAR 340- 215-0125, as applicable; 
and 
(c) Submit and certify any revisions to emissions data r eports. If a regulated entity identifies 
an error in a submission, or is notified of such an error, the regulated entity must submit a 
revision to correct the error within 45 calendar days of discovery. Regulated entities subject 
to the requirements under OAR chapter 340, division 272 must submit revisions in 
compliance with division 272. 244 
 (3) Emissions data reports submitted to DEQ must include the following information: 
(a) Facility name or supplier name (as appropriate), facility or supplier ID number, an d 
physical street address of the facility or supplier, including the city, state, and zip code;  
(b) Year and months covered by the report;  
(c) Date of submittal;  
(d) All information required by this division to calculate and report greenhouse gas 
emissions ; 
(e) Annual emissions of each greenhouse gas, as required under this division; and  
(f) A certification from the designated representative as required under OAR 340 -215-
0040(1).  
(4) Increases or decreases in emissions. I f a regulated entity subject to OAR 340- 215-0105 
submits an emissions data report that indicates emissions equaled or exceeded 25,000 MT 
CO2e during the previous year, then the regulated entity must include the following 
information in the emissions data report:  
(a) Whether a change in operations or status resulted in an increase or decrease of more than 
five percent in emissions of greenhouse gases in relation to the previous data year; and  
(b) If there is an increase or decrease of more than five percent in emissions of greenhouse 
gases in relation to the previous year, the regulated entity must provide a brief narrative 
description of what caused the increase or decrease in emissions. Include in this description 
any changes to the regulated entity’s  permit status.  
(5) When r eporting biomass -derived fuels  and hydrogen, the following requirements also 
apply:  
(a) In addition to the requirements of section (3), a regulated entity reporting biomass -
derived fuels or hydrogen must retain records as required by OAR 340- 215-0042, and 
separately identify, calculate, and report : 
(A) All direct emissions of biogenic  CO2  resulting from the combustion of biomass -derived 
fuels ; and  
(B) All direct emissions of biogenic CO2 resulting from the oxidation of biomass -derived 
fuels ; 
(b) When reporting fuels where biomass and fossil feedstocks are processed in the same 
facility to produce the fuel, persons may request  DEQ approval of a methodology for the 
attribution of the biogenic feedstock to determine the amount of the final reported product 245 
 that may be reported as biogenic. Regulated entities must receive written DEQ approval t o 
use the attribution methodology prior to reporting;   
(c) When reporting emissions from gaseous biomass -derived fuels  or use of hydrogen, report 
the following information for each contracted delivery:  
(A) The type and quality of the gas, including the high heating value of the claimed gas;  
(B) Name and address of all intermediary and direct  vendor (s) from which the fuel is 
purchased;  
(C) Name, address, and facility type from which the fuel was  produced;  
(D) Annual amount contractually del ivered , disaggregated  by each vendor , in MMBtu for 
biomethane, kilograms for hydrogen and standard cubic feet for other gaseous fuels;  
(E) Feedstock(s) used to produce the gas;  
(F) Method(s) used to produce the gas;  
(G) Month and year in which the gas was produced;  
(H) Method of delivery to Oregon;  
(I) The lifecycle carbon intensity, as defined in OAR chapter 340, division 253 of the 
pathway for the contractually delivered biomethane or hydrogen. Lifecycle carbon  intensity 
values must be estimated using the methodology and tools described in OAR chapter 340, 
division 253. U pon request from a regulated entity showing good cause to use a different 
method than one described in OAR chapter 340, division 253, DEQ may a pprove another 
methodology;  
(J) Based on the quantity of biomethane or hydrogen reported using book and claim 
accounting, the amount of natural gas use displaced in Oregon (MMBtu);  
(K) Name and air permit source identification number for the final end user of the gas in 
Oregon, if applicable; and 
(L) Records demonstrating that no other party can make a claim on environmental attributes 
that are being reported under this division. The quantity of energy covered by the 
environmental attributes  must match or e xceed the volume of fuel reported under this 
division. Records must demonstrate that the retired renewable thermal credits or claimed 
environmental attributes were generated within the same reporting data year; and  
(d) R egulated entities reporting contract ual deliveries of gas using book and claim 
accounting must also:  246 
 (A) Report the specific type and volume of gas claimed as injected into a natural gas 
pipeline and delivered to Oregon in the reporting data year; 
(B) Report the point of injection into a pip eline connected to Oregon;  
(C) If using an electronic tracking system approved by DEQ for book and claim accounting, 
the regulated entity must submit records showing the retirement of all environmental attributes of the gas that are being reported under this division ; and  
(e) Retain and make available sufficient records to allow for verification of all reporting requirements in this section, including but not limited to those described in OAR 340-215-0040(7) and OAR 340-215-0042. 
(6) Regulated entities sub ject to the requirements of 40 C.F.R. 98.3(i) must meet those 
requirements for data used in developing emissions data reports. Statutory/Other Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-215-0046  
Reporting Deadlines  
(1) Reporting deadlines. 
(a) Stationary  sources and electric power system facilities required to register and report 
under OAR 340-215-0030(2) must register and submit annual emissions data reports to 
DEQ under OAR 340 -215-0044 by the due date for the annual report for non-greenhouse 
gas emissions speci fied in the source’s Title V Operating Permit or Air Contaminant 
Discharge Permit, or by March 31 of each year, whichever is later. 
(b) The following regulated entities must register and submit annual emissions data reports 
to DEQ by March 31 of each year:  
(A) Natural gas suppliers required to register and report under OAR 340 -215-0030(4); and 
(B) Petroleum and natural gas systems required to register and report under OAR 340 -215-
0030(6). 
(c) Fuel suppliers and in -state producers required to register a nd report under OAR 340-215-
0030(3) must register and submit an annual emissions data report to DEQ by April 30 of 
each year . 247 
 (d) Electricity suppliers required to register and report under OAR 340-215- 0030(5) must 
register and submit an annual emissions d ata report to DEQ by June 1 of each year. 
(2) Electricity suppliers required to register and report under OAR 340-215- 0030(5) must 
retain documentation supporting claims of each specified source of electricity as required by 
OAR 340 -215- 0042(6) beginning i n 2022 for data year 2021, and in each year thereafter 
(i.e., those persons do not have to report that information in reports submitted in 2021). 
(3) Regulated entities reporting GHG emissions from biomass -derived fuels or hydrogen 
may request DEQ approval for exemptions from any of the requirements of OAR 340-215-
0042(4) through (7) and OAR 340-215-0044(5) for the 2023 data year. DEQ will not 
approve exemptions that would impact the quantification of emissions reported under this division. DEQ will consider requests for exemptions based on the regulated entity’s inability to implement necessary changes in time to comply with those requirements. Regulated entities must submit requests for exemptions under this section no later than February 1, 2024, and must receive written DEQ approval of exemptions prior to filing 2023 data year reports required under this division. Starting in 2025 for data year 2024, and each year thereafter, regulated entities must report and retain records as described in OAR 340 -215-
0042(4) through (7) and OAR 340-215-0044(5), as applicable, and DEQ will not approve any exemptions to those requirements.  
(4) DEQ may extend the  reporting deadlines and effective dates described in this rule as 
DEQ deems necessary and will issue notice of any extension. 
(5) If a reporting deadline  described in this rule occurs on a Saturday, Sunday, or an Oregon 
state holiday, the deadline is extended to the following business day. Statutory/Other Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemente d: ORS 468 & 468A 
History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-215-0105  
Requirements for Stationary  Sources and E lectric P ower S ystem F acilities  
Regulated entities required to register and report to DEQ under OAR 340-215-0030(2) must: 
(1) Unless otherwise specified in this rule, c alculate and report  all GHG emissions for which 
there are quanti fication methodologies described in 40 C.F.R. part 98 subparts C through 
UU or in this division, using methodologies described in such rules.  Such reports must 
include all data and information described in such rules. This division, however, describes 
the reporting applicability requirements and the applicability provisions of 40 C.F.R. part 98 subparts C through UU shall not be used. Such reports may exclude emissions from categorically insignificant activities. If categorically insignificant activities c annot be 248 
 separated from other activities, entities may report aggregate emissions that include 
categorically insignificant activities . In addition:  
(a) Regulated entities that are in -state producers may exclude data and information described 
in 40 C.F.R. part 98 subpart MM and NN from an individual emissions data report described in OAR 340 -215-0044(1)(a) but  must comply with OAR 340- 215-0110 and OAR 340- 215-
0115, as applicable; and  
(b) Regulated entities that are carbon dioxide suppliers must report data and information 
described in 40 C.F.R. part 98 subpart  PP; 
(2) As applicable, separately report fuel types, quantities, and emissions from fuel 
combustion reported utilizing 40 C.F.R. part 98, subpart H -  Cement Production, subpart W 
- Petroleum and Natural Gas Systems, and subpart AA -  Pulp and Paper Manufacturing 
quantification methodology;  
(3) Provide supplemental documentation, including data inputs for equations to describe 
how emissions are calculated. Data inputs include but are not limited to fuel th roughput, 
emission factors, and production volumes or product usage used to calculate emissions;  
(4) For stationary  sources and electric power system facilities that include electricity 
generating units, cogeneration units, or both that meet the applicability requirements of section OAR 340- 215-0030(2), follow the requirements of subparts C and D of 40 C.F.R. 
part 98, as applicable, in reporting emissions and other data from electricity generating and cogeneration. In addition, such regulated enti ties must report the following information: 
(a) Information for each facility as defined in 40 C.F.R. 98.6, including separately for each 
facility under the same air quality permit: name, address, and contact person and phone 
number;  
(b) If applicable, report facility identification numbers assigned by the U.S. Energy Information Administration, California Air Resources Board and Federal Energy Regulatory 
Commission’s Public Utility Regulatory Policies Act of 1978 (“ PURPA”)  Qualifying 
Facility program;  
(c) Report net and gross electricity generated in megawatt -hours; and  
(d) Regulated entities that own or operate a cogeneration unit must report the thermal energy 
in MMBtu generated by a combustion source that is used directly as part of a manufacturing, 
industrial or commercial process, or as part of as heating or cooling application, separately 
for the following categories: generated thermal energy provided to end users outside the 
stationary  source facility boundary and generated thermal energy for on- site industrial 
applications not related to electricity generation;  
(5) An investor -owned utility that owns or operates electric power system facilities as 
defined in 40 C.F.R. part 98 subpart DD in Oregon must report emissions utilizing 249 
 calculation methodologi es in 40 C.F.R. part 98 subpart DD and must submit an emissions 
data report including all emissions from electric transmission and distribution equipment and 
servicing inventory physically located in Oregon for the previous year;  
(6) For in -state producers of goods containing fluorinated greenhouse gases in pre -charged 
equipment or closed -cell foams, report the mass of each fluorinated greenhouse gas in all 
goods produced in a year and comply with 40 C.F.R. part 98 subpart QQ in reporting emissions  to DEQ as modified below:  
(a) Report total mass in metric tons of each fluorinated greenhouse gas contained within pre-
charged equipment or closed cell foams;  
(b) For each type of pre -charged equipment with a unique combination of charge size and 
charge t ype, report the identity of the fluorinated greenhouse gas used as a refrigerant or 
electrical insulator, charge size, holding charge, where applicable and number produced;  
(c) For closed –cell foams the identity of the fluorinated greenhouse gas in the foa m, the 
density of the fluorinated GHG in the foam (kilograms of fluorinated greenhouse gas per 
cubic feet), and the volume of foam produced ( tons) for each type of closed–cell foam with a 
unique combination of F -GHG density and identity;  
(d) Calculate gre enhouse gas emissions from foam blowing operations using the following 
equation. When the blowing agent is a blend of gases, emissions must be calculated 
separately for each constituent of the blowing agent used during the foam manufactur ing 
process : 
FCO2e  = ∑ {[(TFP × (ATi + ASi) × BAFi) + (FP × BAFi × MFLi )] × GWPi} × 0.907185 
For the purposes of the calculation in this subsection (d), the following definitions apply:  
“FCO2e ” means annual total mass of fluorinated greenhouse gas emissions of carbon 
dioxi de equivalent  (metric tons);  
 
“TFP” means total amount of foam produced (tons);  
 
“ATi” means average percent blowing agent , i, in trim (tons) ; 
 “ASi” means average percent blowing agent , i, in scrap  (tons) ; 
 
“BAFi” means percent of blowing agent, i, consti tuent in foam (tons);  
 
“FP” means finished product (tons) ; 
 
“MFLi” means mass fraction loss from off gassing curve for blowing agent , i, approved by 
DEQ (tons/year) ; 
 250 
 “GWPi” means global warming potential for each constituent of the blowing agent found in 
table A -1 of 40 C.F.R. part 98; and  
 
“0.907185” is applied to convert tons to metric tons ; and  
(e) Regulated entities that use fluorinated gasses described in table A -1 of 40 C .F.R. part  98 
as blowing agents in foam blowing operations may request  DEQ approval of  alternate 
emissions calculation methods for this operation, process, or activity as described in OAR 
340-215-0040(4). Regulated entities must receive written DEQ approval to use the 
petitioned emissions calculation methods prior to reporting;     
(7) Calculate and report emissions of biogenic CO2 that originate from biomass -derived 
fuels separately from other greenhouse gas emissions. Report and retain information described in OAR 340- 215-0042(4) and OAR 340- 215-0044(5), as applicable, and use the 
following procedures when calculating emissions from biomass -derived fuels that are 
intermixed with fossil fuels:  
(a) When calculating emissi ons from the combustion of municipal solid waste (MSW) or 
any other fuel for which the biomass fraction is not known, follow the procedures specified 
in 40 C.F.R. 98.33(e)(3) to specify a biomass fraction;  
(b) When calculating emissions from a biomass -derived gas, reported using book and claim 
accounting, and natural gas mixture calculate emissions based on contractual deliveries of the biomass -derived gas,  with the remainder of emissions being from natural gas, calculated 
according to the applicable methodology in 40 C.F.R. part 98; and 
(c) When calculating emissions from a biogas and natural gas mixture using 40 C.F.R. 
98.33(a)(4) or the carbon content method described in 40 C.F.R. 98.33(a)(3) or when 
calculating those emissions according to subpart D of 4 0 C.F.R. part 98, calculate biogas 
emissions using a carbon content method as described in 40 C.F.R. 98.33(a)(3), with the 
remainder of emissions being from natural gas ; 
(8) When reporting hydrogen using book and claim accounting, report the energy, volume , 
and the total emissions that would have resulted from the full combustion or oxidation of the 
displaced gaseous fuel using the following procedures:  
(a) When reporting hydrogen that displaces a gaseous fuel that is combusted, calculate and report the equ ivalent energy and volume of the gaseous fuel. Report the emissions that 
would have resulted from the full combustion of that fuel using applicable methodology in 
40 C.F.R. part 98; and  
(b) When reporting hydrogen that displaces a gaseous fuel or feedstock that is used in a non-
combustion process, calculate and report the amount of fuel or feedstock that is displaced by the reported amount of hydrogen. A stationary source must receive prior written DEQ 
approval to use its calculation methods to determine the amount of displaced fuel or 
feedstock it reports. Report the emissions that would have resulted from the non- combustion 
use of the fuel that was displaced using applicable methodology in 40 C.F.R. part 98.  251 
  
(9) When reporting emissions from the combustion of natural gas, report the name(s) of the 
supplier(s) of natural gas to the facility, including information identifying the seller of natural gas, natural gas customer account, and the annual MMBtu delivered to each account according to billing statements (10 therms = 1 MMBtu); and  
(10) Report the air permit numbers and NAICS codes according to 40 C.F.R. 98.3(c)(10). 
Statutory/Other Authority: ORS 468A.050 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-215-0110  
Requirements for Fuel Suppliers and In- State Producers 
Fuel suppliers and in-state producers including but not limited to gasoline, distillate fuel oil, propane, and aircraft fuel dealers required to register and report under OAR 340 -215-
0030(3), but not including natural gas suppliers, must: 
(1) Report all quantities of fuel disbursed in the state by fuel type, regardless of whether the 
fuel is intended for transportation or non -transportation use and regardless of whether the 
fuel is subject to state or federal fuel taxes. Such reports must include the fuel type and quantity imported, sold, or distributed in this state during the previous year and quantities must be reported in standard cubic feet for gaseous fuels and gallons for liquid fuels. In addition: 
(a) Fuel suppliers and in -state producers who report biomass -derived fuels must provide 
supporting documentation as required under OAR 340-215-0044(5); and 
(b) Meeting the requirements of this division does not replace the requirements that must be 
met in order to satisfy the requirements of OAR chapter 340 , division 253 for any given fuel 
suppl ier subject to the Oregon Clean Fuels Program (CFP);  
(2) For reporting of regulated fuels as defined under OAR chapter 340, division 253, comply 
with OAR chapter 340 division 253 and submit quarterly and annual reports. In annual reports, persons dealing in regulated fuels as defined by OAR 340-253- 0200(2) may further 
report fuel volumes by individual fuel type as defined in 40 C.F.R. part 98 subpart MM. If volumes are not reported by individual fuel type, default emission factors defined in 40 C.F.R. part 98 subpart MM must be used for emissions calculation purposes; 
(3) For reporting all other fuels not reported as regulated fuels under section (2) including, 
but not limited to, importers and producers of opt- in fuels and small importers of finished 
fuels as defined by OAR 340-253-0040(86), report fuel imported or produced in the state 252 
 during the previous year by fuel type as defined in 40 C.F.R. part 98 subpart MM. Report as 
follows:  
(a) For fuel imported outside of the bulk system r eport the type and quantity in temperature 
corrected (net) gallons of fuel the fuel supplier held title to or owned at the time the fuel is 
brought into Oregon from out of state or produced in Oregon that is delivered directly to 
intermediate storage, retail, or end users . Exclude fuel imported outside of the bulk system 
and delivered to a terminal storage facility in Oregon; 
(b) Oregon position holders must r eport the type and quantity in temperature corrected (net) 
gallons of fuel owned and dispersed from terminals in Oregon as  reflected in the records of 
the terminal operator. Exclude fuel that is transferred:  
(A) From one terminal storage facility in Oregon to another terminal storage facility in 
Oregon; and  
(B) Between entities within the terminal. Regulated entities must only report fuel that is owned as it is disbursed from the terminal;  
(c) If formulations are unknown for a given quantity of gasoline, report that quantity of 
gasoline using the fuel type “Gasoline formulation unknown.” If distillate or residual fuel oil 
numbers are unknown for a given quantity of distillate fuel oil, report that quantity using the 
fuel type “Diesel type unknown;” and 
(d) Regulated entities must e xclude ;  gallons that  the regulated entity imported or dispensed 
as a position holder in Oregon and that were subsequentl y exported out of state . Exported 
volumes must be excluded based on documentation that meets the requirements of this 
division, as typically provided in a b ill of lading or product transfer document. Regulated 
entities must report all volumes of fuel imported or dispensed from a position holder in 
Oregon that are not documented as exported;  
(4)(a) Fuel suppliers exporting fuel dispensed from a terminal in Ore gon (each an 
“exporter”) must notify the position holder owning title to that fuel as it was dispensed if the 
product transfer documents  issued at the terminal do not accurately reflect the state where 
the fuel was ultimately delivered.  The notification must:  
(A) Occur 30 calendar days prior to the reporting deadline; and  
(B) Include fuel types, volumes and delivery destination, based on documentation;  
(b) For fuel that was (i) delivered from the terminal to an intermediate storage location and then exported after being dispensed from intermediate storage, (ii)  commingled with the 
same type of fuel, and (iii) purchased from multiple position holders, the exporter must 
inform position holders of the exports using the following method: The exporter must 
calculate the total exports from that intermediate storage tank by calendar quarter and fully 
tabulate which position holders it purchased fuel from and that was delivered to inter mediate 253 
 storage for that quarter. The exporter must then apportion the exported gallons to the 
position holders based on the percentage of fuel that the exporter purchased from each of the position holders in the calendar quarter. The entity exporting the fuel must provide written documentation to the position holder that it used this method to apportion the exports.  Documentation must be made available to DEQ and the impacted position holder within 14 calendar days of a request from either DEQ or the posi tion holder; and 
(5) For all fuel suppliers and in- state producers, calculate and report the CO2, CO2 from 
biomass-derived fuels, CH4, N2O, and CO2e emissions in metric tons that would result from the complete combustion or oxidation of the annual quantity of fuel imported, sold, or distributed for use in this state. In such reports, GHG emissions must be calculated as follows:  
(a) Utilize emission quantification methodology prescribed in 40 C.F.R. part 98 subpart MM and equation MM-1 as specified in 40 C.F.R. 98.393(a)(1) to calculate the CO2 emissions and CO2 from biomass- derived fuels that would result from the complete combustion of the 
fuel reported under this division; 
(b) Calculate CH4 and N2O emissions using equation C–8 and Table C-2 as required in 40 
C.F.R. 98.33(c)(1); and  
(c) Utilize a DEQ assigned emission factor for fuel and emission types not listed in 40 C.F.R. part 98. 
Statutory/Other Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-215-0115  
Requirements for Natural Gas Suppliers and In -State Producers  
Natural gas suppliers and in -state producers required to register and report under OAR 340-
215-0030(4) must: 
(1) Report the information required including the volume (Mscf), energy (MMBtu), type of 
natural gas , biomethane or hydrogen and associated emissions for all gas imported, sold, 
produced or distributed for use in the state for the previous year, and: 
(a) If the regulated entity has developed reporter -specific emission factors or high heating 
values, then report the following:  
(A) Information used to develop the reporter -specific emission factor(s) and/or higher 
heating value(s);  254 
 (B) The developed emission factor(s); and  
(C) The developed higher heating value(s);  
(b) For the purposes of this section large natural gas end users are end users receiving 
greater than or equal t o 460,000 Mscf of natural gas during the year;  
(c) Report biomethane  contractually delivered to Oregon  as specified under OAR 340 -215-
0044(5);  and 
(d) Natural gas suppliers contractually delivering hydrogen to end users in Oregon must also 
report information as specified under OAR 340 -215-0044(5) ; 
(2) For local distribution companies, calculate and report greenhouse gas emissions using 
quantification  methodologies and report data and information described in 40 C.F.R part 98 
subpart NN for suppliers of natural gas and natural gas liquids, as applicable, unless 
otherwise specified in this rule including the following: 
(a) In addition to submitting all information needed to meet the requirements of 40 C.F.R. 
98.406(b)(1) through (b)(7), report the annual MMBtu of natural gas associated with the 
volumes reported;  
(b) Report the amount of natural gas delivered to each large natural gas end user separately 
in the state including customer information required in 40 C.F.R. 98.406(b)(12), and source 
identification number if available; and  
(c) Report identifying information for each natural gas marketer contracting use of the 
distribution system during the year including company name and address;  
(3) For interstate pipeline owners and operators, report the total amount of natural gas 
delivered to end users in the state for use in the state, excluding gas delivered to an Oregon local distribution company, and:  
(a) Report the annual amount of natural gas delivered to each large natural gas end user separately in the state including customer information required in 40 C.F.R. 98.406(b)(12), 
and source identification number(s) if available. In instances where multip le end users are 
downstream of a delivery point that registers at least 460,000 Mscf annually report the total 
gas delivered and identifying information for each user downstream of the delivery point; 
and 
(b) Report identifying information for each natural  gas marketer contracting use of the 
distribution system during the year including company name, and address;  
(4) Importers of natural gas, by any means other than a pipeline distribution system or 
interstate pipeline , and in- state producers of natural gas or biomethane must separately  
report : 255 
 (a) The total amount of natural gas, compressed natural gas, liquefied natural gas and 
biomethane imported or produced and delivered of sold for use in the state, excluding 
volumes delivered to an Oregon local distribution company or injected into an interstate pipeline; and  
(b) The total amount of natural gas, compressed natural gas, liquefied natural, or biomethane 
delivered to each large natural gas end user in the state including customer information required in 40 C.F.R. 98.406(b)(12), and source identification number if available; and 
(5) For all natural gas suppliers, calculate and report the CO2, biogenic CO2 from any 
reported biomass-derived fuel, CH4, N2O, and CO2e emissions in metric tons that would 
result f rom the complete combustion or oxidation of the annual quantity of natural gas 
imported, sold, or distributed for use in this state. Calculate and report greenhouse gas emissions for the previous year utilizing emission quantification methodology prescribed in 40 C.F.R. part 98 and as follows: 
(a) Calculate greenhouse gas emissions separately for natural gas, compressed natural gas 
liquefied natural gas and biomethane ; 
(b) Calculate and report CO2 emissions as follows:  
(A) Local distribution companies must utilize quantification methodologies and report all data elements as required by 40 C.F.R. 98 subpart NN - Suppliers of Natural Gas and Natural Gas liquids for the total volume of gas supplied in the state; and  
(B) All other natural gas suppliers including  interstate pipeline owners or operators, 
importers of natural gas, in-state producers must calculate and report using calculation 
methodology 1 as specified in 40 C.F.R. 98.403(a)(1); 
(c) Calculate and report CH4 and N2O emissions from natural gas importe d, sold, or 
distributed for use in this state using equation C-8 and table C-2 as required in 40 C.F.R. 
98.33(c)(1) for all fuels subject to reporting;  
(d) CO2 emissions from biomass -derived fuel are based on the fuel the natural gas supplier 
purchased and contractually delivered . Emissions from biomethane are calculated using the 
methods for natural gas required by this section, including the use of the emission factor for natural gas in 40 C.F.R. 98.408, table NN-1. Natural gas suppliers who report emissions from biomethane must report information required by OAR 340-215-0044(5) and retain supporting documentation as required under OAR 340-215-0042; and 
(e) Not report data or emissions for exported products. 
Statutory/Other Authority: ORS 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 256 
 340-215-0120  
Requirements for Electricity Suppliers  
Electricity suppliers required to register and report under OAR 340 -215-0030(5) must report 
information and emissions related to the generation of electricity delivered or distributed to 
end users in this state during the previous year, regardless of whether the electricity was generated in this state or imported. Such reports must;  
(1) Report the megawatt -hours (MWh) and greenhouse gas emissions from the generation of 
electricity from unspecified sources and from each sp ecified source delivered or distributed 
to end users in Oregon during the previous year, as follows:  
(a) For unspecified sources, report the MWh of electricity and calculate and report the associated GHG emissions according to section (5)(a). Separately id entify the MWh for 
power purchased from any energy imbalance market(s) or other centralized market(s);  
(b) For specified sources of electricity, report as follows:  
(A) Report specified sources when one of the following applies:  
(i) The electricity supplier is a facility or unit operator, full or partial owner, party to a power contract for a fixed percentage of generation from the facility or generating unit, party to a tolling agreement and rents a facility or unit from the owner or is an exclusive power deliverer that is not a retail provider and that has prevailing rights to claim electricity from the specified source; or  
(ii) The electricity supplier has a power contract for electricity from a DEQ -approved asset -
controlling supplier (ACS) or generated by a facility or unit, subject to meeting all other specified source requirements and can provide documentation that the contract was designated at the time the transaction was executed; and  
(B) Electricity suppliers reporting specified sources must:  
(i) Rep ort the MWh of electricity disaggregated by facility or unit, and by fuel type or ACS, 
as measured at the busbar. If not measured at the busbar, report the amount of electricity delivered in Oregon, including estimated transmission losses using the default  transmission 
loss correction factor of 1.02;  
(ii) Report the GHG emissions associated with the electricity calculated according to subsection (5)(b); and  
(iii) Report details about each specified facility, unit, or ACS, including fuel type or types and information about the seller, including company name and contact information;  
(c) For electricity suppliers that are multi- jurisdictional utilities that deliver or distribute 
electricity in Oregon, report total MWh and greenhouse gas emissions from the gen eration 257 
 of electricity from specified and unspecified sources in the utility’s service territory or 
power system as required by subsections (a) and (b), and also report the following:  
(A) Wholesale electricity purchased and taken from specified sources (MWh);  
(B) Wholesale electricity purchased from unspecified sources (MWh);  
(C) Wholesale electricity sold from specified sources (MWh); and  
(D) Retail sales (MWh) to customers in Oregon’s portion of the utility’s service territory or 
power system;  
(d) For electricity suppliers that are not multi -jurisdictional utilities, proportionally adjust all 
resources on an annual basis to account for the sale of power to the wholesale market that is 
not known to be just specified or unspecified;  and 
(e) Electric compani es and electricity service suppliers as defined in ORS 757.600 subject to 
ORS 469A.210 must separately report and identify electricity (MWh) and greenhouse gas emissions associated with electricity acquired from net metering of customer resources or a 
qualifying facility under the terms of the Federal Energy Regulatory Commission’s Public 
Utility Regulatory Policies Act of 1978 (“ PURPA”)  Qualifying Facility program;  
(2) Use DEQ approved and published emission factors for calculating and reporting GHG 
emissi ons, including;  
(a) The emission factor for calculating emissions from unspecified power is 0.428 MT 
CO2e/MWh;  
(b) Electricity suppliers reporting specified source power provided by a multi -jurisdictional 
utility or DEQ -approved ACS must calculate emissions using a system emission factor 
published by DEQ, which will be calculated by DEQ according to subsection (6)(b);  
(c) Electricity suppliers reporting specified source power from a specific facility or unit must calculate emissions using emission f actors published by DEQ, which will be calculated 
according to subsection (6)(a); and  
(d) For reporting emissions from specified sources for which DEQ has not published an approved emission factor, electricity suppliers may propose facility- specific or uni t-specific 
anthropogenic and biogenic emission factors expressed as metric tons of carbon dioxide 
equivalent (MT CO2e) per megawatt -hour of generation. Such a proposal to DEQ must 
include documentation describing how the proposed facility -specific or unit -specific 
emission factors are derived, including the necessary information for verification of these 
calculations. DEQ may adopt the proposed emission factors or may develop and assign 
facility -specific or unit -specific emission factors for the specified s ource. The regulated 
entity may use such an emission factor only if approved by DEQ;  258 
 (3) For utilities that do not receive electricity from other sources and who serve load 
exclusively in Oregon, a third -party report from the Bonneville Power Administratio n 
(BPA), reporting the preference sales provided to Oregon consumer -owned utilities may 
satisfy such regulated party’s obligations under this division. If BPA does not report this 
information to DEQ, those consumer -owned utilities must report the information as required 
by this division;  
(4) For a consumer -owned utility, a third- party may submit the registration and report, and 
the report may include information for more than one consumer -owned utility, provided that 
the report contains all information requ ired under this division for each individual 
consumer -owned utility, and:  
(a) The consumer -owned utility must notify DEQ at least 30 calendar days prior to the 
reporting deadline that a third -party will be reporting on its behalf. This notification must 
include the name and contact information for the third -party;  
(b) This notification may include notice that the third -party will report on behalf of the 
consumer -owned utility for future years;  
(c) For any future year in which there is a change in the third -party reporting on behalf of 
the consumer -owned utility, the consumer -owned utility must provide notification to DEQ at 
least 30 calendar days prior to the reporting deadline;  
(d) Third -parties reporting on behalf of a consumer -owned utility must notify DE Q and 
request authorization from DEQ prior to submitting any reports. This notification must 
include identifying information of the consumer- owned utility; and  
(e) Each consumer -owned utility must ensure that reports submitted on its behalf meet all 
requir ements of this division;  
(5) Calculate and report greenhouse gas emissions as follows:  
(a) Emissions reported for electricity associated with unspecified sources must be calculated using the following equation:  
CO2e = MWh × TL × EFunsp 
For the purposes of this calculation, “EFunsp” means default emission factor for unspecified 
electricity equal to 0.428 MT CO2e/MWh;  
(b) Emissions reported for electricity associated with specified sources must be calculated 
using the following equation:  
CO2e = MWh × TL × EFs p 259 
 For the purposes of this calculation, “EFsp” means facility -specific, unit -specific, or ACS 
system emission factor published by DEQ; and 
(c) Emissions reported by a multi- jurisdictional utility may be calculated according to a cost 
allocation methodology approved by the Oregon Public Utility Commission (OPUC) using 
the following equation:  
CO2e = MWhMJOR × TL × EFMJ  
For the purposes of this calculation, the following definitions apply:  
“MWhMJOR” means total megawatt -hours of electricity delivere d to retail customers in 
Oregon;  
“EFMJ” means multi -jurisdictional utility system emission factor calculated according to 
equation (6)( c) (MT CO2e/MWh);  
(6) For electricity suppliers, use emission factors calculated and published by DEQ for 
calculating and  reporting emissions, as follows:  
(a) DEQ will calculate facility -specific or unit -specific emission factors using the following 
equation:  
EFsp = Esp /EG  
For the purposes of this calculation, the following definitions apply:  
“EFsp” means the facility -speci fic or unit specific emission factor;  
“Esp” means CO2e emissions for a specified facility or unit for the report year (MT CO2e);  
“EG” means net generation from a specified facility or unit for the report year;  
(b) DEQ will calculate asset -controlling suppl ier system emission factors using the 
following equations:  
EFSYS = Sum of System Emissions MT CO2e ÷ Sum of System MWh  
Sum of System Emissions MT CO2e = ∑Esp + ∑(PEsp × EFsp) + ∑(PEunsp × EFunsp) -  
∑(SEsp × EFsp)  
Sum of System MWh = ∑EGsp + ∑PEsp + ∑PEunsp -  ∑SEsp  
For the purposes of the calculations, the following definitions apply:  260 
 “ΣEsp” means Emissions from Owned Facilities. Sum of CO2e emissions from each 
specified facility/unit in the supplier’s fleet, consistent with section (5)(b) (MT CO2e);  
“ΣEGsp"  means Net Generation from Owned Facilities. Sum of net generation for each 
specified facility/unit in the supplier’s fleet for the data year as reported to DEQ under this division (MWh);  
“PEsp” means Electricity Purchased from Specified Sources. Amount of  electricity 
purchased wholesale and taken from specified sources by the supplier for the data year as 
reported to DEQ under this division (MWh);  
“PEunsp” means Electricity Purchased from Unspecified Sources. Amount of electricity 
purchased wholesale from unspecified sources by the supplier for the data year as reported 
to DEQ under this division (MWh);  
“SEsp” means Electricity Sold from Specified Sources. Amount of wholesale electricity sold 
from specified sources by the supplier for the data year as repor ted to DEQ under this 
division (MWh);  
“EFsp” means CO2e emission factor as defined for each specified facility or unit calculated 
consistent with section (5)(b) (MT CO2e/MWh);  
“EFunsp” means default emission factor for unspecified sources calculated consistent with 
section (5)(a) (MT CO2e/MWh);  and 
(c) DEQ will calculate multi -jurisdictional utility system emission factors consistent with a 
cost allocation methodology approved by the Oregon Public Utility Commission using the following equation:  
EFMJ = Sum of System Emissions MT CO2e ÷ Sum of System MWh  
Sum of System Emissions MT CO2e = ∑Esp + ∑(PEsp × EFsp) + ∑(PEunsp × EFunsp) -  
∑(SEsp × EFsp)  
Sum of System MWh = ∑EGsp + ∑PEsp + ∑PEunsp -  ∑SEsp  
For the purposes of the calculations, the following definitions apply:  
“ΣEsp” means Emissions from Owned Facilities allocated to serve retail customers in 
Oregon pursuant to a cost allocation methodology approved by the Oregon Public Utility 
Commission . Sum of CO2e emissions from each specified facility/unit in the supplier’s 
fleet, consistent with section (5)(b) (MT CO2e); 
“ΣEGsp" means Net Generation from Owned Facilities  allocated to serve retail customers in 
Oregon pursuant to a cost allocation methodology approved by the Oregon Public Utility 261 
 Commission . Sum of net generation for each specified facility/unit in the supplier’s fleet for 
the data year as reported to DEQ under this division (MWh);  
“PEsp” means Electricity Purchased from Specified Sources allocated to serve retail 
customers in Oreg on pursuant to a cost allocation methodology approved by the Oregon 
Public Utility Commission . Amount of electricity purchased wholesale and taken from 
specified sources by the supplier for the data year as reported to DEQ under this division (MWh);  
“PEuns p” means Electricity Purchased from Unspecified Sources allocated to serve retail 
customers in Oregon pursuant to a cost allocation methodology approved by the Oregon Public Utility Commission . Amount of electricity purchased wholesale from unspecified 
sources by the supplier for the data year as reported to DEQ under this division (MWh);  
“SEsp” means Electricity Sold from Specified Sources consistent with a cost allocation methodology approved by the Oregon Public Utility Commission. Amount of wholesale electricity sold from specified sources by the supplier for the data year as reported to DEQ 
under this division (MWh);  
“EFsp” means CO2e emission factor as defined for each specified facility or unit calculated 
consistent with section (5)(b) (MT CO2e/MWh);  
“EFunsp” means default emission factor for unspecified sources calculated consistent with 
section (5)(a) (MT CO2e/MWh);  and 
 
(7) For a person that owns or operates inter -connected electricity generating facilities or has 
exclusive rights to claim electricity from these facilities even though it does not own them 
may request that DEQ designate them as an asset -controlling supplier, and:  
(a) Persons seeking designation by DEQ as an asset -controlling supplier must annually 
adhere to the requirements of this di vision, or be removed from asset -controlling supplier 
designation;  
(b) In addition to submitting the applicable information as required by this rule, persons 
seeking designation by DEQ as an asset -controlling supplier must also submit the following 
by June  1 of each year:  
(A) General business information, including business name and contact information;  
(B) A list of officer names and titles;  
(C) Wholesale electricity purchased and taken from specified sources (MWh);  
(D) Wholesale electricity purchased from  unspecified sources (MWh);  262 
 (E) Wholesale electricity sold from specified sources (MWh); and  
(F) An attestation, in writing and signed by designated representative of the applicant that 
the information submitted is true, accurate, and complete; and  
(c) DEQ  will calculate and publish a supplier- specific system emission factor according to 
subsection (6)(b) for designated asset -controlling suppliers.  
Statutory/Other Authority: ORS 468A.050 & 468A.280 Statutes/Other Implemented: ORS 468 & 468A History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-215-0130  
 Separate Violations  
Each metric ton of greenhouse gas emissions not reported according to the requirements of this division by a covered fuel supplier, as defined in OAR 340-271-0020, that affects applicability determinations, compliance instrument distribution, or compliance obligations under the Oregon Climate Protection Program, OAR Chapter 340 Division 271, is a separate violation of this division.
 
 
  263 
 Air Contaminant Discharge Program, Division 216  
 
340-216-0025  
Types of Permits  
(1) Construction ACDP: 
(a) A Construction ACDP may be used for approval of Type 3 changes specified in OAR 
340-210-0225 at a source subject to the ACDP permit requirements in this division.  
(b) A Construction ACDP is required for Type 3 changes specified in OAR 340- 210-0225 at 
sources subject to the Oregon Title V Operating Permit requirements.  
(2) General ACDP. A General ACDP is a permit for a category of sources for which individual permits are unnecessary in order to protect the environment, as determined by DEQ. An owner or operator of a source may be assigned to a General ACDP if DEQ has issued a General ACDP for the source category and:  
(a) The source meets the qualifications specified in the General ACDP;  
(b) DEQ determines that the source has not had ongoing, recurring, or serious compliance problems; and 
(c) DEQ determines that a General ACDP would appropriately regulate the source.  
(3) Short Term Activity ACDP. A Short Term Activity ACDP is a letter permit that 
authorizes the activity and includes any conditions placed upon the  method or methods of 
operation of the activity. DEQ may issue a Short Term Activity ACDP for activities 
included in OAR 340- 216-0054. 
(4) Basic ACDP. A Basic ACDP is a permit that authorizes the regulated source to operate in conformance with the rules co ntained in OAR chapter 340, divisions 200 to 272. 
(a) Owners and operators of sources and activities listed in Part A of OAR 340- 216-8010 
must at a minimum obtain a Basic ACDP.  
(b) Any owner or operator of a source required to obtain a Basic ACDP may choos e to 
obtain either a Simple or Standard ACDP.  
(5) Simple ACDP.  
(a) Owners and operators of sources and activities listed in OAR 340- 216-8010 Part B that 
do not qualify for a General ACDP and are not required to obtain a Standard ACDP must, at a minimum, ob tain a Simple ACDP. The owner or operator of a source required to obtain a 
Simple ACDP may choose to obtain a Standard ACDP.  264 
 (b) A Simple ACDP is a permit that contains:  
(A) All relevant applicable requirements for source operation, including general ACDP 
conditions for incorporating generally applicable requirements;  
(B) PSELs at less than the SER for all regulated pollutants emitted at more than the de 
minimis emission level according to OAR chapter 340, division 222; and  
(C) Testing, monitoring, recordkeeping, and reporting requirements sufficient to determine 
compliance with the PSEL and other emission limits and standards, as necessary.  
(6) Standard ACDP:  
(a) Applicability.  
(A) The owner or operator of a source listed in Part C of OAR 340- 216-8010 must obtain a 
Standard ACDP;  
(B) The owner or operator of a source listed in Part B of OAR 340 -216-8010 that does not 
qualify for a General ACDP or Simple ACDP must obtain a Standard ACDP; 
(C) The owner or operator of a source not required to obtain a Standard ACDP may choose 
to apply for a Standard ACDP.  
(b) A Standard ACDP is a permit that contains:  
(A) All applicable requirements, including general ACDP conditions for incorporating 
generally applicable requirements;  
(B) PSELs for all regulat ed pollutants emitted at more than the de minimis emission level 
according to OAR chapter 340, division 222; and  
(C) Testing, monitoring, recordkeeping, and reporting requirements sufficient to determine compliance with the PSEL and other emission limits a nd standards, as necessary.  
(7)(a) Notwithstanding the other provisions of this division that establish the eligibility of a 
source for different types of ACDPs, DEQ may determine, pursuant to the standards 
described in subsection (b), that the owner or operator of a source is ineligible for certain 
types of ACDP and must be issued a different type of ACDP; 
(b) DEQ will make a determination about which type of ACDP that the owner or operator of 
source must obtain based upon the following considerations:  
(A) The nature, extent, toxicity and impact on human health and the environment of the 
source's emissions;  265 
 (B) The complexity of the source and the rules applicable to that source;  
(C) The complexity of the emission controls, potential threat to human health and the 
environment if the emission controls fail, and the source’s capacity;  
(D) The location of the source and its proximity to places where people live and work; and  
(E) The compliance history of the source, including by the source’s:  
(i) Current corporate officers, managers, members of the board of directors, general partners 
or similar persons, provided that the person exercises or will exercise substantial control on 
behalf of or over the facility that is the subject of the application or permit; 
(ii) Parent corporations, or similar business entities, that exercise substantial control over the 
facility that is the subject of the application or permit; and  
(iii) Subsidiary corporations, or similar business entities, over which the applicant or 
permittee  exercises substantial control.  
[NOTE: This rule is included in the State of Oregon Clean Air Act Implementation Plan as 
adopted by the EQC under OAR 340 -211-0040.]  
[NOTE: All tables are found in OAR 340 -216-8010, - 8020, - 8030.]  
 
 
340-216-8010  
Table 1 Acti vities and Sources 
The following source categories must obtain a permit as required by OAR 340- 216-0020  
Applicability and Jurisdiction.  
Part A: Basic ACDP  
1 Autobody repair or painting shops painting more than 25 automobiles in a year and that 
are located inside the Portland AQMA.  
2 Concrete manufacturing including redi -mix and CTB, both stationary and portable, more 
than 5,000 but less than 25,000 cubic ya rds per year output.  
3 Crematory incinerators with less than 20 tons/year material input.  266 
 4 Individual natural gas or propane -fired boilers with heat input rating between 9.9 and 29.9 
MMBTU/hour, constructed after June 9, 1989, that do not use more than 9,999 gallons per 
year of #2 diesel oil as a backup fuel.  
5 Prepared feeds for animals and fowl and associated grain elevators more than 1,000 
tons/year but less than 10,000 tons per year throughput.  
6 Rock, concrete or asphalt crushing, both stationary and portable, more than 5,000 
tons/year but less than 25,000 tons/year crushed.  
7 Surface coating operations whose actual or expected usage of coating materials is greater than 250 gallons per month but does not exceed 3,500 gallons per year, excluding so urces 
that exclusively use non- VOC and non -HAP containing coatings, e.g., powder coating 
operations.  
8 Sources subject to permitting under Part B of this table, number 85 if all of the following 
criteria are met: a. The source is not subject to any catego ry listed on this table other than 
Part B number 85; b. The source has requested an enforceable limit on their actual 
emissions, if the source were to operate uncontrolled, to below Part B number 85 of this 
table as applicable depending on the source’s loc ation through one or both 
9 All stationary sources not listed elsewhere in this table that have the capacity to emit 
25,000 metric tons of CO2e or more of covered emissions as defined at OAR 340- 271-0020 
in a year.  
Part B: General, Simple or Standard ACDP  
1 Aerospace or aerospace parts manufacturing subject to RACT under OAR chapter 340, 
division 232.  
2 Aluminum, copper, and other nonferrous foundries subject to an area source NESHAP 
under OAR chapter 340, division 244.  
3 Aluminum production – primary.  
4 Ammonia manufacturing.  
5 Animal rendering and animal reduction facilities.  
6 Asphalt blowing plants.  7 Asphalt felts or coating manufacturing.  
8 Asphaltic concrete paving plants, both stationary and portable.  
9 Bakeries, commercial over 10 tons of V OC emissions per year.  267 
 10 Battery separator manufacturing.  
11 Lead- acid battery manufacturing and re -manufacturing.  
12 Beet sugar manufacturing.  
13 Oil -fired boilers and other fuel burning equipment whose total heat input rating at the 
source is over 1 0 MMBTU/hour; or individual natural gas, propane, or butane -fired boilers 
and other fuel burning equipment 30 MMBTU/hour or greater heat input rating.  
14 Building paper and building board mills.  
15 Calcium carbide manufacturing.  
16 Can or drum coating s ubject to RACT under OAR chapter 340, division 232.2  
17 Cement manufacturing.  
18 Cereal preparations and associated grain elevators 10,000 or more tons/year throughput.1  
19 Charcoal manufacturing.  
20 Chlorine and alkali manufacturing.  
21 Chrome plating and anodizing subject to a NESHAP under OAR chapter 340, division 
244.  
22 Clay ceramics manufacturing subject to an area source NESHAP under OAR chapter 
340, division 244.  
23 Coffee roasting, roast ing 30 or more green tons per year.  
24 Concrete manufacturing including redi -mix and CTB, both stationary and portable, 
25,000 or more cubic yards per year output.  
25 Crematory incinerators 20 or more tons/year material input.  26 Degreasing operations, halogenated solvent cleanings subject to a NESHAP under OAR 
chapter 340, division 244.  
27 Electrical power generation from combustion, excluding units used exclusively as 
emergency generators and units less than 500 kW.  
28 Commercial ethylene oxide steri lization, excluding facilities using less than 1 ton of 
ethylene oxide within all consecutive 12- month periods after December 6, 1996.  268 
 29 Ferroalloy production facilities subject to an area source NESHAP under OAR chapter 
340, division 244.  
30 Flatwood c oating subject to RACT under OAR chapter 340, division 232.2  
31 Flexographic or rotogravure printing subject to RACT under OAR chapter 340, division 
232.2  
32 Flour, blended and/or prepared and associated grain elevators 10,000 or more tons/year throughput.
1  
33 Galvanizing and pipe coating, except galvanizing operations that use less than 100 tons of zinc/year.  
34 Bulk gasoline plants, bulk gasoline terminals, and pipeline facilities.  
35 Gasoline dispensing facilities, excluding gasoline dispensing faci lities with monthly 
throughput of less than 10,000 gallons of gasoline per month
3.  
36 Glass and glass container manufacturing subject to a NSPS under OAR chapter 340, 
division 238 or a NESHAP under OAR chapter 340, division 244.  
37 Grain elevators used f or intermediate storage 10,000 or more tons/year throughput.1  
38 Reserved.  39 Gray iron and steel foundries, malleable iron foundries, steel investment foundries, steel 
foundries 100 or more tons/year metal charged, not elsewhere identified.  
40 Gypsum pr oducts manufacturing.  
41 Hardboard manufacturing, including fiberboard.  
42 Hospital sterilization operations subject to an area source NESHAP under OAR chapter 
340, division 244.  
43 Incinerators with two or more tons per day capacity.  
44 Lime manufactu ring.  
45 Liquid storage tanks subject to RACT under OAR chapter 340, division 232.
2  
46 Magnetic tape manufacturing.  
47 Manufactured home, mobile home and recreational vehicle manufacturing.  269 
 48 Marine vessel petroleum loading and unloading subject to RACT under OAR chapter 
340, division 232.  
49 Metal fabrication and finishing operations subject to an area source NESHAP  under OAR 
chapter 340, division 244, excluding facilities that meet all the following:  
a. Do not perform any of the operations listed in OAR 340- 216-0060(3)(b)(V)(i) through 
(iii);  
b. Do not perform shielded metal arc welding (SMAW) using metal fabrication and 
finishing hazardous air pollutant (MFHAP) containing wire or rod; and  
c. Use less than 100 pounds of MFHAP containing welding wire and rod per year.  
50 Millwork manufacturing, including kitchen cabinets and structural wood members, 25,000 or more board feet/maximum 8 hour input.  
51 Molded plastic container manufacturing, using extrusion, molding, lamination, and foam 
processing and molded fiberglass c ontainer manufacturing, excluding injection molding.  
52 Motor coach, travel trailer, and camper manufacturing.  
53 Motor vehicle and mobile equipment surface coating operations subject to an area source 
NESHAP under OAR chapter 340, division 244, excluding motor vehicle surface coating 
operations painting less than 10 vehicles per year or using less than 20 gallons of coating 
and 20 gallons of methylene chloride containing paint stripper per year, mobile equipment 
surface coating operations using less than 20 gallons of coating and 20 gallons of methylene 
chloride containing paint stripper per year, and motor vehicle surface coating operations 
registered pursuant to OAR 340- 210-0100(2).  
54 Natural gas and oil production and processing and associated fuel burning equipment.  
55 Nitric acid manufacturing.  
56 Nonferrous metal foundries 100 or more tons/year of metal charged.  
57 Organic or inorganic chemical manufacturing and distribution with ½ or more tons per 
year emissions of any one criteria pollutant, s ources in this category with less than ½ 
ton/year of each criteria pollutant are not required to have an ACDP.  
58 Paint and allied products manufacturing subject to an area source NESHAP under OAR 
chapter 340, division 244.  
59 Paint stripping and miscell aneous surface coating operations subject to an area source 
NESHAP under OAR chapter 340, division 244, excluding paint stripping and 270 
 miscellaneous surface coating operations using less than 20 gallons of coating and also using 
less than 20 gallons of meth ylene chloride containing paint stripper per year.  
60 Paper or other substrate coating subject to RACT under OAR chapter 340, division 232.2  
61 Particleboard manufacturing, including strandboard, flakeboard, and waferboard.  
62 Perchloroethylene dry clea ning operations subject to an area source NESHAP under 
OAR chapter 340, division 244, excluding perchloroethylene dry cleaning operations 
registered pursuant to OAR 340- 210-0100(2).  
63 Pesticide manufacturing 5,000 or more tons/year annual production.  
64 Petroleum refining and re -refining of lubricating oils and greases including asphalt 
production by distillation and the reprocessing of oils and/or solvents for fuels.  
65 Plating and polishing operations subject to an area source NESHAP under OAR chapter  
340, division 244.  
66 Plywood manufacturing and/or veneer drying.  
67 Prepared feeds manufacturing for animals and fowl and associated grain elevators 10,000 
or more tons per year throughput.  
68 Primary smelting and/or refining of ferrous and non- ferrou s metals.  
69 Pulp, paper and paperboard mills.  
70 Rock, concrete or asphalt crushing, both stationary and portable, 25,000 or more 
tons/year crushed.  
71 Sawmills and/or planing mills 25,000 or more board feet/maximum 8 hour finished 
product.  
72 Secondary nonferrous metals processing subject to an Area Source NESHAP under OAR chapter 340, division 244.  
73 Secondary smelting and/or refining of ferrous and nonferrous metals.  
74 Seed cleaning and associated grain elevators 5,000 or more tons/year throughput.
1  
75 Sewage treatment facilities employing internal combustion engines for digester gasses.  
76 Soil remediation facilities, both stationary and portable.  
77 Steel works, rol ling and finishing mills.  271 
 78 Surface coating in manufacturing subject to RACT under OAR chapter 340, division 
232.2  
79 Surface coating operations with actual emissions of VOCs, if the source were to operate 
uncontrolled, of 10 or more tons/year.  
80 Synt hetic resin manufacturing.  
81 Tire manufacturing.  
82 Wood furniture and fixtures 25,000 or more board feet/maximum 8 hour input.  
83 Wood preserving (excluding waterborne).  
84 All other sources, both stationary and portable, not listed herein that DEQ determines an 
air quality concern exists or one which would emit significant malodorous emissions.  
85 All other sources, both stationary and portable, not listed herein which would have the 
capacity of 5 or more tons per year of direct PM2.5 or PM10 if loc ated in a PM2.5 or PM10 
nonattainment or maintenance area, or 10 or more tons per year of any single criteria pollutant.
4  
86 Chemical manufacturing facilities subject to 40 C.F.R. part 63 subpart VVVVVV.  
87 Stationary internal combustion engines if:  
a. For emergency generators and firewater pumps, the aggregate engine horsepower rating is greater than 30,000 horsepower; or  
b. For any individual non -emergency or non- fire pump engine, the engine is subject to 40 
CFR part 63, subpart ZZZZ and is rated at 500 horsepower or more, excluding two stroke lean burn engines, engines burning exclusively landfill or digester gas, and four stroke engines located in remote areas; or  
c. For any individual non -emergency engine, the engine is subject to 40 CFR part 60, 
subpart IIII and:  
A. The engine has a displacement of 30 liters or more per cylinder; or  
B. The engine has a displacement of less than 30 liters per cylinder and is rated at 500 
horsepower or more and the engine and control device are either not certified by the manufacturer to meet the NSPS or not operated and maintained according to the manufacturer’s emission -related instr uctions; or  
d. For any individual non -emergency engine, the engine is subject to 40 CFR part 60, 
subpart JJJJ and is rated at 500 horsepower or more and the engine and control device are 272 
 either not certified by the manufacturer to meet the NSPS or not ope rated and maintained 
according to the manufacturer’s emission -related instructions.  
88 All sources subject to RACT under OAR chapter 340, division 232, BACT or LAER 
under OAR chapter 340, division 224, a NESHAP under OAR chapter 340, division 244, a NSPS under OAR chapter 340, division 238, or State MACT under OAR 340- 244-0200(2), except sources:  
a. Exempted in any of the categories above;  
b. For which a Basic ACDP is available; or  
c. Registered pursuant to OAR 340-210-0100(2).  89 Pathological waste incinerators.  
90 Landfills with more than 200,000 tons of waste in place and calculated methane 
generation rate is less than 664 metric tons per year which are subject to the requirements in OAR 340 division 239. 
 
1 Applies only to S pecial Control Areas  
2 Portland AQMA, Medford -Ashland AQMA or Salem -Keizer in the SKATS only  
3 “monthly throughput” means the total volume of gasoline that is loaded into, or dispensed from, all gasoline 
storage tanks at the gasoline dispensing facility during a month. Monthly throughput is calculated by summing 
the volume of gasoline loaded into, or dispensed from, all gasoline storage tanks at the gasoline dispensing 
facility during the month, plus the total volume of gasoline loaded into, or dispensed from, all gasoline storage tanks at the gasoline dispensing facility during the previous 11 months, and then dividing that sum by 12  
4 A source subject to permitting from this category may be able to obtain a Basic ACDP under Part A number 8 
of this table . For sources that meet the criteria of Part A number 8 of this table, the enforceable production or 
hours limitation in an issued ACDP may be used to demonstrate a permit is not required by Part B number 85 of this table irrespective of the term ‘uncontro lled’.
 
Part C: Standard ACDP  
1 Incinerators for PCBs, other hazardous wastes, or both.  
2 All sources that DEQ determines have emissions that constitute a nuisance.  
3 All sources electing to maintain the source’s netting basis.  
4 All sources that request a PSEL equal to or greater than the SER for a regulated pollutant.  273 
 5 All sources having the potential to emit 100 tons or more of any regulated pollutant, 
except GH G, in a year.  
6 All sources having the potential to emit 10 tons or more of a single hazardous air pollutant 
in a year.  
7 All sources having the potential to emit 25 tons or more of all hazardous air pollutants 
combined in a year.  
8 Landfills with more than 200,000 tons of waste in place and calculated methane generation 
rate is greater than or equal to 664 metric tons per year which are subject to the requirements in OAR 340 division 239. 
 NOTE: For the history of these tables prior to 2014 see the history under OAR 340- 216-
0020. This history is also shown below:  
DEQ 9 -2013(Temp), f. & cert. ef. 10- 24-13 thru 4 -22-14  
DEQ 4 -2013, f. & cert. ef. 3- 27-13  
DEQ 14 -2011, f, & cert. ef. 7- 21-11  
DEQ 13 -2011, f. & cert. ef. 7- 21-11  
DEQ 11 -2011, f. & cert. ef. 7- 21-11  
DEQ 5 -2011, f. 4- 29-11, cert. ef. 5- 1-11  
DEQ 1 -2011, f. & cert. ef. 2- 24-11  
DEQ 12 -2010, f. & cert. ef. 10- 27-10  
DEQ 10 -2010(Temp), f. 8- 31-10, cert. ef. 9 -1-10 thru 2- 28-11  
DEQ 9 -2009(Temp), f. 12- 24-09, cert. ef. 1 -1-10 thru 6- 30-10  
DEQ 8 -2009, f. & cert. ef. 12- 16-09  
DEQ 15 -2008, f. & cert. ef 12- 31-08  
DEQ 8 -2007, f. & cert. ef. 11- 8-07  
DEQ 7 -2007, f. & cert. ef. 10- 18-07  274 
 DEQ 4 -2002, f. & cert. ef. 3- 14-02  
DEQ 6 -2001, f. 6- 18-01, cert. ef. 7- 1-01  
DEQ 14 -1999, f. & cert. ef. 10- 14-99, Renumbered from 340- 028-1720  
DEQ 22 -1996, f. & cert. ef. 10- 22-96 
DEQ 19 -1996, f. & cert. ef. 9- 24-96  
DEQ 22 -1995, f. & cert. ef. 10- 6-95  
DEQ 22 -1994, f. & cert. ef. 10- 4-94  
DEQ 19 -1993, f. & cert. ef. 11- 4-93  
DEQ 12 -1993, f. & cert. ef. 9- 24-93, Renumbered from 340 -020-0155  
DEQ 4 -1993, f. & cert. ef. 3- 10-93  
DEQ 27 -1991, f. & cert. ef. 11- 29-91  
DEQ 12 -1987, f. & cert. ef. 6- 15-87  
DEQ 3 -1986, f. & cert. ef. 2- 12-86  
DEQ 11 -1983, f . & cert. ef. 5 -31-83  
DEQ 23 -1980, f. & cert. ef. 9- 26-80  
DEQ 20 -1979, f. & cert. ef. 6- 29-79  
DEQ 125, f. & cert. ef. 12- 16-76  
DEQ 107, f. & cert. ef. 1 -6-76, Renumbered from 340- 020-0033  
DEQ 63, f. 12- 20-73, cert. ef. 1 -11-74  
DEQ 47, f. 8- 31-72, cert. ef. 9- 15-72 
 
340-216-8020  
Table 2 — Air Contaminant Discharge Permits  275 
 (1) Sources referred to in Table 1 of OAR 340- 216-8010 are subject to air contaminant 
discharge permit fees in Table 2. Title V sources may be subject to the Cleaner Air Oregon 
annual fees and the specific activity permit fees in Table 2, if applicable.  
(2) Requests for waiver of fees must be made in writing to the Director, on a case -by-case 
basis, and be based upon financial hardship. Applicants for waivers m ust describe the reason 
for the request and certify financial hardship. The Director may waive part or all of a fee.  276 
  
OAR 340 -216-8020 
Table 2  
Air Contaminant Discharge Permits 
Part 1. Initial Permitting Application Fees: (in addition to first annual fee)  
Short Term Activity ACDP  $4,500.00  
Basic ACDP  $180.00  
Assignment to General ACDP 1 $1,800.00  
Simple ACDP  $9,000.00  
Construction ACDP  $14,400.00  
Standard ACDP  $18,000.00  
Standard ACDP (Major NSR or Type A State NSR)  $63,000.00  
1. DEQ may waive the assignment fee for an existing source requesting to be assigned to a 
General ACDP because the source is subject to a newly adopted area source NESHAP as 
long as the existing source requests assignment within 90 days of notification by DEQ.  
Part 2. Annual Fees: (Due date 12/11 for 1/1 to 12/31 of the following year)  
(applicable July 1, 2022)  
Registration – Motor vehicle surface coating operations  $288.00  
Registration - Dry cleaners using perchloroethylene  $216.00  
Short Term Activity ACDP  $0 
Basic ACDP  (A) #1 -7  
OAR 340 -216-8010 Table 1 
Part A  $648.00 
 
(B) #8 -9  
OAR 340 -216-8010 Table 1 
Part A  $1,469.00 
General ACDP  (A) Fee Class One  $1,469.00  
(B) Fee Class Two  $2,644.00 
(C) Fee Class Three  $3,818.00 
(D) Fee Class Four  $734.00  
(E) Fee Class Five  $245.00 
(F) Fee Class Six  $490.00 
Simple ACDP  (A) Low Fee  $3,917.00  
277 
  
OAR 340 -216-8020 
Table 2  
Air Contaminant Discharge Permits 
(B) High Fee  $7,834.00 
Standard ACDP  $15,759.00  
Greenhouse Gas Reporting, as required by OAR chapter 340, 
Division 215 7.31% of the 
applicable ACDP 
annual fee in Part 2  
Part 3. Cleaner Air Oregon Annual Fees: (Due date 12/11 for 1/1 to 12/31 of 
the following year)  
Basic ACDP  (A) #1 -7  
OAR 340 -216-8010 Table 1 
Part A  $151.00 
(B) #8 -9  
OAR 340 -216-8010 Table 1 
Part A  $302.00 
General ACDP  (A) Fee Class One  $302.00  
(B) Fee Class Two  $544.00  
(C) Fee Class Three  $786.00  
(D) Fee Class Four  $151.00  
(E) Fee Class Five  $50.00  
(F) Fee Class Six  $100.00  
Simple ACDP  (A) Low Fee  $806.00  
(B) High Fee  $1,612.00  
Standard ACDP $3,225.00  
1. DEQ may extend the payment due date for dry cleaners or gasoline dispensing facilities 
until March 1st.  
Part 4. Specific Activity Fees:  
Notice of Intent to Construct Type 21 $720.00 
Permit Modification  
 (A) Non -Technical  $432.00  
(B) Basic Technical  $540.00  
278 
  
OAR 340 -216-8020 
Table 2  
Air Contaminant Discharge Permits 
(C) Simple Technical  $1,800.00  
(D) Moderate 
Technical  $9,000.00 
(E) Complex 
Technical  $18,000.00 
Toxic Air Contaminant 
Permit Addendum 
Modification  (A) Non -Technical  $432.00 
(B) Basic Technical  $432.00  
(C) Simple Technical  $1,440.00  
(D) Moderate 
Technical  $7,200.00 
(E) Complex 
Technical  $14,440.00 
Major NSR or Type A State NSR Permit Modification  $63,000.00  
Modeling Review (outside Major NSR or Type A State NSR)  $9,000.00  
Public Hearing at Source's Request  $3,600.00  
State MACT Determination  $9,000.00  
Compliance Order Monitoring 2 $180.00/month  
Part 5. Late Fees:  
8-30 days late  5% 
31-60 days late  10% 
61 or more days late  20% 
1. The Type 2 Notice of Intent to Construct does not apply to existing Basic ACDP or 
General ACDP sources.  
.2. This is a one- time fee payable when a compliance order is established in a permit or a 
DEQ order containing a compliance schedule becomes a fina l order of DEQ and is based 
on the number of months DEQ will have to oversee the order. 
NOTE : See history of this table under OAR 340 -216-0020.  
 
 
279 
 Climate Protection Program, Division 271  
 
340-271-0010  
Purpose and Scope  
(1) This division establishes rules and requirements for the Climate Protection Program for 
certain air contamination sources that emit greenhouse gases or that cause greenhouse gases to be emitted. 
(2) Climate change caused by anthropogenic greenhouse gas emissions has detrimental 
effects on the overall public welfare of the State of Oregon. Reducing greenhouse gas 
emissions and mitigating climate change will improve the overall public welfare of Oregon. In particular, reducing greenhouse gas emissions will  improve the welfare of environmental 
justice communities.  
(a) Fuel combustion and industrial processes result in emissions of greenhouse gases, which are air contaminants that cause climate change;  
(b) Reducing greenhouse gas emissions may also reduce emi ssions of other air 
contaminants, which may improve air quality for Oregon communities; and 
(c) Environmental justice communities in Oregon are disproportionately burdened by air 
contamination, including through disproportionate risk of the impacts of clim ate change.  
(3) The purposes of the Climate Protection Program are to reduce greenhouse gas emissions from sources in Oregon, achieve co -benefits from reduced emissions of other air 
contaminants, and enhance public welfare for Oregon communities, particula rly 
environmental justice communities disproportionately burdened by the effects of climate 
change and air contamination. To support these purposes, this division:  
(a) Requires that covered entities reduce greenhouse gas emissions;  
(b) Supports reduction of emissions of other air contaminants that are not greenhouse gases;  
(c) Prioritizes reduction of greenhouse gases and other air contaminants in environmental justice communities;  
(d) Provides covered entities with compliance options to minimize disproportionate business and consumer economic impacts associated with meeting the Climate Protection Program requirements; and  
(e) Allows covered fuel suppliers to comply with the Climate Protection Program requirements in part through contributing community clima te investment funds to support 
projects that reduce greenhouse gas emissions and prioritize benefits for environmental justice communities in Oregon. 280 
 (4) DEQ administers this division in all areas of the State of Oregon and subject to the 
requirements in this division and OAR 340-200-0010(3), LRAPA is designated by the EQC to implement OAR 340 -271- 0150(3) of this division within its area of jurisdiction.  
(5)(a) Whenever the DEQ Director has good cause to believe that any person is engaged or is about to engage in any acts or practices which constitute a violation of this division, the Director may authorize DEQ to institute actions or proceedings for legal or equitable remedies to enforce compliance thereto or to restrain further violations.  
(b) The proceedings authorized by subsection (a) may be instituted without the necessity of prior DEQ notice, hearing and order. 
(c) The provisions of this section are in addition to and not in substitution of any other civil 
or criminal enforcement provisions available to DEQ. This includes, without limitation, the authority to impose civil penalties and issue orders according to ORS Chapter 468.090 to 468.140 and OAR chapter 340, divisions 11 and 12. 
(6) If any dates under this division occur on a Saturday, Sunday, or a state holiday, the 
deadline is extended to the following business day 
Statutory/Other Authority: ORS 468.020, 468A.025, 468A.040, 468A.050, 468A.135 & 
468.100 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468A.050, 468A.135, 468.035, 468A.010, 468A.015, 468A.045 & 468.100 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-0020  
Definitions  
The definitions in OAR 340-200-0020, OAR 340-215-0020, and this rule apply to this 
division. If the same term is defined in this rule and either or both OAR 340-200-0020 and 
OAR 340 -215- 0020, the definition in this rule applies to this division. If the same term is 
defined in OAR 340-200-0020 and OAR 340-215-0020, but not in this rule, then the 
definition in OAR 340 -215-0020 applies to this division. 
(1) “Air contamination source” has the meaning given the term in ORS 468A.005. Air 
contamination sources include, without limitation, stationary sources, fuel suppliers, in- state 
producers, and local distribution companies. 
(2) “Best available emissions reduction order” or “BAER order” means a DEQ order 
establishing required actions the owner or operator of a covered stationary source must take to limit covered emissions from the covered stationary source.  281 
 (3) “Biomass -derived fuels” has the meaning given the term in OAR 340 -215-0020. 
Biomass- derived fuels include, without limitation, biomethane, biodiesel, renewable diesel, 
renewable propane, woody biomass, and ethanol.  
(4) “Cap” means the total number of compliance instruments generated by DEQ for each 
calendar ye ar. 
(5) “Climate Protection Program permit addendum” or “CPP permit addendum” means 
written authorization that incorporates the requirements of this division into a permit by amending an Air Contaminant Discharge Permit or a Title V Operating Permit.  
(6) “Climate Protection Program permit” or “CPP permit” means a permit issued to a 
covered fuel supplier according to this division.  
(7) “Community climate investment credit” or “CCI credit” or “credit” means an instrument 
issued by DEQ to track a covered fuel supplier’s payment of community climate investment 
funds, and which may be used in lieu of a compliance instrument, as further provided and 
limited in this division.  
(8) “Community climate investments,” “community climate investment funds” or “CCI 
funds” m eans money paid by a covered fuel supplier to a community climate investment 
entity to support implementation of community climate investment projects and any interest 
that accrues on the money while it is held by a CCI entity or subcontractor. 
(9) “Commun ity climate investment entity” or “CCI entity” means a nonprofit organization 
that has been approved by DEQ as a CCI entity and that has entered into a written agreement 
with DEQ consistent with OAR 340 -271-0920 to implement projects supported by 
community  climate investment funds.  
(10) “Compliance instrument” means an instrument issued by DEQ that authorizes the 
emission of one MT CO2e of greenhouse gases. Compliance instruments may not be divided 
into fractions.  
(11) “Compliance obligation” means the tota l quantity of covered emissions from a covered 
fuel supplier rounded to the nearest metric ton of CO2e.  
(12) “Compliance period” means a period of multiple consecutive calendar years, as described in OAR 340- 271-0440. 
(13) “Covered emissions” means the greenhouse gas emissions described in any of 
subsections OAR 340- 271-0110(3)(b), (4)(b) and (5)(b), for which covered entities may be 
subject to the requirements of this division.  
(14) “Covered entity” means an air contamination source subject to the requirem ents of this 
division. A covered entity may be either a covered fuel supplier, a covered stationary source, or both.  282 
 (15) “Covered fuel supplier” means an air contamination source that is either:  
(a) A fuel supplier or in -state producer as described in OAR 340-271-0110(3); or 
(b) A local distribution company as described in OAR 340-271-0110(4). 
(16) “Covered stationary source” means an air contamination source described in OAR 340-
271-0110(5). 
(17) “Designated representative” means the perso n responsible for certifying, signing, and 
submitting any registration, report, or form required to be submitted according to this 
division, on behalf of a covered entity. For the owner or operator of a covered stationary source with an Oregon Title V Oper ating Permit, the designated representative is the 
responsible official and certification must be consistent with OAR 340 -218-0040(5). 
(18) “Environmental justice communities” means communities of color, communities experiencing lower incomes, tribal communities, rural communities, coastal communities, communities with limited infrastructure and other communities traditionally underrepresented in public processes and adversely harmed by environmental and health hazards, including seniors, youth and persons with disabilities.  
(19) “ Existing source” means a source that is operating under the authority of either a 
current Air Contaminant Discharge Permit or Title V Operating Permit or, when the term of an issued permit has expired, under the authority of OAR 340-216-0082(1) or OAR 340-218-0120(2) and 340- 218-0130(2). 
(20) “New source” means a source that is not operating under the authority of either a current Air Contaminant Discharge Permit or Title V Operating Permit or, when the term of an issued permit has expired, under the authority of OAR 340-216-0082(1) or OAR 340-218-0120(2) and 340- 218-0130(2).   
(21) “Nominal electric generating capacity” has the meaning given in ORS 469.300. 
(22) “Shut down” means that all operations of a covered entity are permanent ly shut down, 
including but not limited to decommissioning and cancelling air permits. Permanent 
shutdown may include continued operations of space heaters and water heaters as necessary to support decommissioning activities. 
Statutory/Other Authority: ORS  468.020, 468A.025, 468A.040 & 468A.050 
Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468A.050, 468.035, 
468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 283 
 340-271-0110  
Covered Entity and Covered Emissions Applicability  
(1) Calculations of covered  emissions, compliance obligations and distribution of 
compliance instruments will be based on emissions data and information in emissions data 
reports submitted by a person described in this rule and required according to OAR chapter 340, division 215, which may be subject to verification according to OAR chapter 340, division 272. For any person that does not submit sufficient information in compliance with OAR chapter 340, divisions 215 and 272, calculations will be informed by additional best data avail able to DEQ. For any person that has not registered and reported according to 
division 215, such calculations will be based on the best data available to DEQ, following all reporting requirements and assumptions that would be applicable had the person reported according to that division.  
(2) A covered entity is subject to the requirements of this division for its covered emissions described in this rule. A person remains a covered entity until cessation is met according to OAR 340 -271-0130. 
(3) Applicability for fuel suppliers and in -state producers. A person is a covered fuel 
supplier if the person is described in subsection (a) and has annual covered emissions described in subsection (b) in any applicability determination calendar year that equal or exceed  the threshold for applicability listed in Table 1 in OAR 340- 271-9000. All persons 
that are related entities must aggregate their emissions together to determine applicability and each becomes a covered fuel supplier if applicability is met. When applicab ility is met, 
each person is a covered fuel supplier beginning with the calendar year a person becomes a covered fuel supplier, as provided in Table 1 in OAR 340- 271-9000. Once a person is a 
covered fuel supplier, the person remains a covered fuel supplier  until the person has met the 
cessation requirements according to OAR 340- 271-0130. 
(a) The person is a fuel supplier or in -state producer that imports, sells, or distributes fuel for 
use in Oregon, and is one or more of the following:  
(A) A dealer, as tha t term is defined in ORS 319.010 that is subject to the Oregon Motor 
Vehicle and Aircraft Fuel Dealer License Tax in OAR chapter 735, division 170;  
(B) A seller, as that term is defined in ORS 319.520, that is subject to the Oregon Use Fuel Tax in OAR chapter 735, division 176;  
(C) A person that produces, imports, sells, or distributes gasoline or distillate fuel oil for use in Oregon and that is not subject to the Oregon Motor Vehicle and Aircraft Fuel Dealer License Tax or the Oregon Use Fuel Tax in OAR chapter 735, divisions 170 and 176; or  
(D) A person that either produces propane in Oregon or imports propane for use in the state.  284 
 (b) Except as provided in paragraph (B), covered emissions include emissions described in 
paragraph (A). 
(A) Covered emission s include emissions of anthropogenic greenhouse gases in metric tons 
of CO2e that would result from the complete combustion or oxidation of the annual quantity 
of propane and liquid fuels (including, for example and without limitation, gasoline and 
petrole um products) imported, sold, or distributed for use in this state.  
(B) Covered emissions do not include:  
(i) Emissions that are from the combustion of biomass -derived fuels;  
(ii) Emissions that are from the combustion of fuels used for aviation including, for example 
and without limitation, aviation gasoline, kerosene -type jet fuel, and alternative jet fuel; and  
(iii) Emissions described in 40 CFR part 98 subpart W – Petroleum and Natural Gas 
Systems.  
(4) Applicability for local distribution companies. A person is a covered fuel supplier if the 
person is described in subsection (a) and has annual covered emissions described in 
subsection (b) in 2018 or any subsequent calendar year, unless the person has met the 
cessation requirements according to OAR 340- 271-0130. 
(a) The person is a local distribution company that either produces natural gas, compressed 
natural gas, or liquefied natural gas in Oregon, or that imports, sells, or distributes natural 
gas, compressed natural gas, or l iquefied natural gas to end users in the state.  
(b) Except as provided in paragraph (B), covered emissions include emissions described in 
paragraph (A). 
(A) Covered emissions include emissions of anthropogenic greenhouse gases in metric tons 
of CO2e that w ould result from the complete combustion or oxidation of the annual quantity 
of natural gas imported, sold, or distributed for use in this state. 
(B) Covered emissions do not include:  
(i) Emissions that are from the combustion of biomass -derived fuels;  
(ii) Emissions described in 40 CFR part 98 subpart W – Petroleum and Natural Gas 
Systems;   
(iii); Emissions avoided where the use of natural gas results in greenhouse gas emissions 
captured and stored, if sufficiently documented by information provided to DE Q; and  285 
 (iv) Emissions from natural gas delivered to an air contamination source that is an electric 
power generating plant with a total nominal electric generating capacity greater than or 
equal to 25 megawatts.  
(5) Applicability for stationary sources. A person is a covered stationary source if the person 
is described in subsection (a), unless the person has met the cessation requirements 
according to OAR 340- 271-0130. 
(a) The person is one or more of the following:  
(A) The person owns or operates an exist ing source that has actual covered emissions 
described in subsection (b) that equal or exceed 25,000 MT CO2e in 2018 or in any 
subsequent calendar year;  
(B) The person owns or operates a new source, or proposes to own or operate a new source, 
that has a p otential to emit covered emissions described in subsection (b) that will equal or 
exceed 25,000 MT CO2e per calendar year; or  
(C) The person owns or operates an existing source that is not a covered stationary source under (A), proposes to make a modificat ion under OAR 340- 216-0040(3), OAR 340- 218-
0170, OAR 340- 218-0180, or OAR 340- 218-0190, or a Type 2, 3 or 4 change under OAR 
340-210-0225 to their source and:  
(i) The modification would increase the source’s potential to emit covered emissions described in  subsection (b) by 10,000 MT CO2e per calendar year or more, and;  
(ii) After the modification, the source’s potential to emit covered emissions described in 
subsection (b) would equal or exceed 25,000 MT CO2e per calendar year. 
(b) Except as provided in pa ragraph (B), covered emissions include emissions described in 
paragraph (A). 
(A) Covered emissions include emissions of anthropogenic greenhouse gases in metric tons 
of CO2e that are from either or both processes or the combustion of solid or gaseous fuels , 
including emissions from combustion for both energy production and processes.  
(B) Covered emissions do not include:  
(i) Emissions that are from the combustion of biomass -derived fuels;  
(ii) Biogenic CO2 emissions from solid fuels;  
(iii) Emissions that are from the combustion of liquid fuels or propane;  
(iv) Emissions from natural gas, compressed natural gas, or liquefied natural gas used on -
site that was delivered by a local distribution company;  286 
 (v) Emissions described in 40 CFR part 98 subpart HH – Muni cipal Solid Waste Landfills;  
(vi) Emissions described in 40 CFR part 98 subpart TT – Industrial Waste Landfills;  
(vii) Emissions from an air contamination source that is owned or operated by an interstate 
natural gas pipeline that is operating under author ity of a certificate of public convenience 
and necessity issued by the Federal Energy Regulatory Commission; and 
(viii) Emissions from an air contamination source that is an electric power generating plant 
with a total nominal electric generating capacity greater than or equal to 25 megawatts.  
Statutory/Other Authority: ORS 468.020, 468A.025, 468A.040 & 468A.050 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468A.050, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 18 -2022, temporary amend filed 11/18/2022, effective 11/18/2022 through 05/16/2023
 
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021  
 
340-271-0120  
Changes in Covered Entity Ownership and Changes to Related Entities  
(1) Changes in ownership or operational control. 
(a) If a covered entity undergoes a change in ownership or operational control, the new 
person that owns or operates the covered entity must notify DEQ in writing within 30 days of the ownership or operational control change. The person must submit a complete and accurate notification, including providing the following information: 
(A) The name of the previous owner or operato r; 
(B) The name of the new owner or operator;  
(C) The date of ownership or operator change; (D) Name of the designated representative;  
(E) If the covered entity is a covered fuel supplier that is not a local distribution company 
information about each person that was a related entity prior to the change in ownership or operational control and that was required to report emissions according to  OAR chapter 340, division 215, including legal name, full mailing address, and whether each is a covered fuel supplier and holds a CPP permit; and 
(F) If the covered entity is a covered fuel supplier that is not a local distribution company, 
information about each person that is a related entity after the change in ownership or 287 
 operational control and that is required to report emissions according  to OAR chapter 340, 
division 215, including legal name, full mailing address, and whether each is a covered fuel 
supplier and holds a CPP permit.  
(b) The covered entity continues to be a covered entity following a change in ownership or 
operational control, until it meets the cessation requirements in OAR 340 -271-0130. Any 
other covered entity that was a related entity also continues to be a covered entity following 
the change in ownership or operational control, until it meet s the cessation according to 
OAR 340 -271-0130. 
(c) Following a change in ownership or operational control, a covered fuel supplier that holds a compliance instrument or CCI credit according to OAR 340- 271-0430 or OAR 340-
271-0830 continues to hold the compliance instrument or CCI credit according to each rule, 
as applicable.  
(2) Changes to related entities of covered fuel suppliers.  
(a) If a person subject to any regulations in OAR chapter 340, division 215, becomes a new related entity to a covered fuel supplier that is not a local distribution company due to a 
change in ownership or operational control, the designated representative of the covered fuel 
supplier must notify DEQ in writing, on a form approved by DEQ, within 30 days of the 
ownership or  operational control change. The designated representative must submit a 
complete and accurate notification, including providing the following information:  
(A) Information about the new related entity, including legal name, full mailing address, and 
whethe r the person is a covered fuel supplier and holds a CPP permit;  
(B) The name of the previous owner or operator of the new related entity;  
(C) The name of the new owner or operator of the new related entity;  
(D) The date of ownership or operator change for the new related entity; and  
(E) Information about all other related entities subject to any regulations in OAR chapter 
340, including legal names, full mailing addresses, and whether each is a covered fuel 
supplier and holds a CPP permit.  
(b) If the person  that is the new related entity to a covered fuel supplier identified in 
paragraph (a)(A) is not already a covered fuel supplier, the person:  
(A) Becomes a covered fuel supplier beginning with the date of ownership or operator change;  
(B) Must apply to DEQ  for a CPP permit according to OAR 340- 271-0150(1)(a)(B); and 288 
 (C) If the person is a covered fuel supplier, the person will have compliance obligations 
beginning with covered emissions from the calendar year in which the ownership or operator change occurred.  
Statutory/Other Authority: ORS 468.020, 468A.025, 468A.040 & 468A.050 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468A.050, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-0130  
Cessation of Covered Entity Applicability  
(1) Cessation for covered fuel suppliers.  
(a) A person that is a covered fuel supplier as described in OAR 340 -271-0110 remains a 
covered fuel supplier until the person receives written notification from DEQ after either or both: 
(A) The person’s annual covered emissions are 0 (zero) MT CO2e for six consecutive 
calendar years. If the person is not a local distribution company, the covered emissions of the person’s related entities must also be 0 (zero) MT CO2e for the same six consecutive calendar years; or 
(B) The person was designated a covered fuel supplier in OAR 340-271-0110(3), the sum of 
its annual covered emissions and the annual covered emissions of its related entities are less than 25,000 MT CO2e for six consecutive calendar years and the person applies to DEQ according to subsection (c).  
(b) After a covered fuel supplier identified according to paragraph (a)(A) demonstrates compliance with compliance obligations for the years up to and including the years 
described in paragraph ( a)(A), DEQ will notify the designated representative of the covered 
fuel supplier in writing that cessation is met.  
(c) In order for cessation according to paragraph (a)(B) to take effect, a covered fuel supplier 
must apply to cease being a covered fuel su pplier by submitting the following information to 
DEQ on a form approved by DEQ: 
(A) Information about the covered fuel supplier, including:  
(i) Name and full mailing address, and website; and  
(ii) Designated representative’s contact information including name, title or position, phone 
number, and email address; 289 
 (B) If the person is not a local distribution company information about each related entity 
required to report emissions according to OAR chapter 340, division 215, for each of the six 
consecutive calendar years, including legal name, full mailing address, and whether each is a covered fuel supplier and holds a CPP permit;  
(C) Information about remaining requirements that must be met according to this division at the time the application is submitted  to DEQ; and  
(D) The following attestation, signed by the designated representative of the covered fuel supplier:  
I certify under penalty of perjury under the laws of the State of Oregon that to the best of my 
knowledge and belief, the information provided in this form is true, accurate, and complete. 
[Covered fuel supplier] meets the eligibility for cessation as a covered fuel supplier 
according to Oregon Administrative Rules chapter 340, division 271. I understand that 
ceasing to be a covered fuel supplie r means that [covered fuel supplier] will also cease to 
hold any compliance instruments and CCI credits. 
(d) After the covered fuel supplier applying for cessation according to paragraph (a)(B) and 
subsection (c) demonstrates compliance with compliance obl igations for the years up to and 
including the years described in paragraph (a)(B), DEQ will notify the designated representative of the covered fuel supplier in writing that the application for cessation is 
approved and that cessation is met.  
(e) A person  that ceases to be a covered fuel supplier according to this section must comply 
with all remaining applicable recordkeeping requirements of this division from the last date 
on which the person was a covered fuel supplier.  
(f) When a person ceases to be a covered fuel supplier:  
(A) The cessation does not change the compliance obligation for any year for which the 
person has already demonstrated compliance;  
(B) Any remaining compliance instruments held by the person will be retired, held in 
reserve, or distr ibuted by DEQ according to OAR 340- 271-0430(3); and  
(C) Any remaining community climate investment credits held by the person will be 
canceled according to OAR 340- 271-0830(1)(c).  
(2) Cessation for covered stationary sources.  
(a) A person that is a covered stationary source as described in OAR 340 -271-0110 remains 
a covered stationary source until either of the following occur:  
(A) The person’s operations are changed such that all greenhouse gas emitting processes and operations cease to operate or are shut down. In order for cessation to take effect, the person 290 
 must submit a written notification to DEQ certifying the cessation of all greenhouse gas 
emitting processes and operations; or  
(B) The person’s covered emissions are less than 25,000 MT CO2e f or five consecutive 
calendar years and the person has fully complied with any applicable BAER order and any related reporting requirements and has submitted any remaining required BAER assessment and five- year BAER report. In order for cessation to take effect, DEQ will notify the 
covered stationary source that cessation is met.  
(b) This section does not apply to seasonal operational cessations or other temporary cessation of operations.  
(c) A person that ceases to be a covered stationary source according to this section must comply with all remaining applicable recordkeeping requirements of this division from the last date on which the person was a covered stationary source.  
(3) Any person that ceases to be a covered entity according to this rule must resum e meeting 
the requirements of this division for any future year in which applicability is met.  
Statutory/Other Authority: ORS 468.020, 468A.025, 468A.040 & 468A.050 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468A.050, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-0150  
Covered Entity Permit Requirements  
(1) A person described in either or both OAR 340-271-0110(3) or (4) must apply for a CPP permit as provided in this section. 
(a) The person must apply for a CPP permit according to subsections (b) and (c) by the 
following deadlines: 
(A) If DEQ notifies the person in writing that the person is a covered fuel supplier, then the 
person must apply to DEQ for a CPP permit within 30 days of the notification or by another date DEQ specifies in the notification tha t is at least 30 days after the date of the 
notification;  
(B) If DEQ does not provide a notification according to paragraph (A), then the person must apply to DEQ for a CPP permit by April 15 of the year after the calendar year that the person becomes a co vered fuel supplier; or  291 
 (C) If there was a change in ownership or operational control according to OAR 340- 271-
0120(2), then the person must apply to DEQ for a CPP permit within 45 days of the change 
in ownership or operational control.  
(b) A person that s ubmits a CPP permit application to DEQ must submit a complete and 
accurate application. The application for a CPP permit must be submitted to DEQ using a form approved by DEQ and include:  
(A) Identifying information about the covered fuel supplier including name, full mailing address, and website, and designated representative’s contact information including name, 
title or position, phone number, and email address;  
(B) If the person is a covered fuel supplier that is not a local distribution company, 
inform ation about each related entity required to report emissions according to OAR chapter 
340, division 215, including legal name, full mailing address, and whether each is a covered fuel supplier and holds a CPP permit; and 
(C) The following attestation, signed by the designated representative of the person 
considered a covered fuel supplier;  
I certify under penalty of perjury under the laws of the State of Oregon that to the best of my 
knowledge and belief, the information provided in this form is true, accurate, and complete. 
[Covered entity] meets the Climate Protection Program applicability requirements described 
in OAR 340 -271-0110 and requests a permit with the understanding that [covered entity] 
must comply with such permit as provided in Oregon Adm inistrative Rules chapter 340, 
division 271. 
(c) DEQ may issue a CPP permit to a covered fuel supplier that submits a complete and 
accurate application. The permit may contain all applicable provisions of this division and 
such other conditions as DEQ dete rmines are necessary to implement, monitor and ensure 
compliance with this division.  
(2) New and modified stationary sources  
(a) The owner or operator of a new source that is a covered stationary source may not emit 
any covered emissions prior to being iss ued a BAER order and a permit as described in 
subsection (3)(c).  
(b) The owner or operator of an existing source that is proposing a modification and is 
required to complete a BAER assessment under OAR 340- 271-0310(1)(c) may not construct 
the modification or emit any covered emissions from the modification prior to being issued a 
BAER order and approved permit modification as described in subsection (3)(d).  
(3)(a) The owner or operator of an existing covered stationary source required to apply for a 
CPP per mit addendum according to OAR 340- 271-0330(1) must submit a complete and 292 
 accurate application to DEQ or LRAPA, as applicable, that complies with and includes 
information identified in this section. The application must include the following:  
(A) Identifying information about the covered stationary source, including name and the 
name of the person that owns or operates the covered stationary source, full mailing address, 
the physical address of the covered stationary source, and a description of th e nature of 
business being operated, the name, phone number and email address of the designated 
representative who is responsible for compliance with the permit, the permit number for an 
existing source, and the SIC or NAICS code of the covered stationary source;  
(B) The name of a person authorized to receive requests from DEQ for additional data and 
information;  
(C) The date DEQ notified the owner or operator of the covered stationary source of the 
BAER order established according to OAR 340- 271-0320;  
(D) A BAER implementation plan that includes the following: 
(i) Identification of the actions that the owner or operator of the covered stationary source 
will take to comply with the BAER order; and  
(ii) The schedule for implementing the requirements in the BA ER order, consistent with any 
deadlines provided by DEQ in the BAER order, if applicable, and including an estimate of 
when all requirements from the BAER order will be completed; 
(E) Any other information requested by DEQ; and 
(F) The following attestatio n, signed by the designated representative of the covered 
stationary source;  
I certify under penalty of perjury under the laws of the State of Oregon that to the best of my 
knowledge and belief, the information provided in this form is true, accurate, and complete. [Covered entity] meets the Climate Protection Program applicability requirements described 
in OAR 340 -271-0110 and requests a permit with the understanding that [covered entity] 
must comply with such permit as provided in Oregon Administrative Rules chapter 340, 
division 271. 
(b) DEQ or LRAPA, as applicable, may issue a CPP permit addendum to the owner or 
operator of a covered stationary source that submits a complete and accurate permit 
modification application under subsection (a), consistent with the requirements of OAR 
chapter 340, divisions 216 and 218, as applicable. The CPP permit addendum will be issued 
as a Category II permit action according to OAR chapter 340, division 209. A CPP permit addendum will amend the covered stationary source’s  Air Contaminant Discharge Permit or 
Title V Operating Permit. The CPP permit addendum will contain all applicable provisions of this division and such other conditions as DEQ or LRAPA, as applicable, determines are 
necessary to implement, monitor and ensu re compliance with the permit and this division.  293 
 (c) If DEQ or LRAPA approves an application for an Air Contaminant Discharge Permit or 
Title V Operating Permit submitted by the owner or operator of a new source, then DEQ or LRAPA, as applicable, will inco rporate the CPP conditions into the new Air Contaminant 
Discharge Permit or Title V Operating Permit and will not issue a separate CPP permit addendum. Such CPP conditions will include all applicable provisions of this division and such other conditions as  DEQ or LRAPA, as applicable, determines are necessary to 
implement, monitor and ensure compliance with the permit and this division.  
(d) If DEQ or LRAPA approves an application for a modification of an Air Contaminant Discharge Permit or Title V Operating  Permit submitted by the owner or operator of an 
existing source that is required to undertake a BAER assessment described in OAR 340 -271-
0310(1)(c), then DEQ or LRAPA, as applicable, will incorporate the CPP conditions into the modified Air Contaminant Di scharge Permit or Title V Operating Permit and will not issue a 
separate CPP permit addendum. Such CPP conditions will include all applicable provisions of this division and such other conditions as DEQ or LRAPA, as applicable, determines are necessary to implement, monitor and ensure compliance with the permit and this division.  
Statutory/Other Authority: ORS 468.020, 468A.025, 468A.040 & 468A.135 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468A.135, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-0310  
Best Available Emissions Reduction Assessments for Covered Stationary Sources 
(1) Requirement to conduct a BAER assessment.  
(a) When notified in writing by DEQ, the owner or operator of a covered stationary source 
described in OAR 340-271-0110(5)(a)(A) must submit a complete and accurate BAER assessment according to this rule. The owner or operator of the covered stationary source must submit a complete BAER assessment to DEQ not later than nine months following the date of DEQ’s notice, unless DEQ has identified a later deadline in its notice or DEQ approves an extension according to section (6).  
(b) The owner or operator of a new source described in OAR 340-271- 0110(5)(a)(B) must 
submit a complete and accurate BAER  assessment completed according to this rule with its 
permit application submitted according to OAR chapter 340, division 216, or its notice of construction application submitted according to OAR chapter 340, division 210. 
(c) Modifications.  
(A) A source that is a covered stationary source described in OAR 340 -271-0110(5)(a)(C) 
must complete a BAER assessment if notified in writing by DEQ. DEQ will require a BAER 294 
 assessment at the time of the modification only if DEQ determines that the modification 
repres ents a significant change to the equipment or processes that emit covered emissions at 
the source.  
(B) If the modification described in OAR 340 -271-0110(5)(a)(C) is a notice of construction 
for a Type 2 change required under OAR 340- 210-0230, DEQ will noti fy the source not 
later than 60 days after submittal of the notice of construction if a BAER assessment is 
required. Upon receipt of that notification, the owner or operator of the source must submit a 
complete and accurate BAER assessment completed accord ing to this rule and an 
application for a permit modification submitted according to OAR chapter 340, division 216 
or 218, as applicable. Notwithstanding OAR 340- 210-0225(2) and (3), such permit 
modification application is a Type 3 change as described in O AR chapter 340, division 210. 
(2) BAER assessment requirements. BAER assessments submitted to DEQ must include the following:  
(a) A description of the covered stationary source’s production processes and a flow chart of 
each process;  
(b) Identification of all fuels, processes, equipment, and operations that contribute to the 
covered stationary source’s covered emissions, including:  
(A) Estimates of annual average covered emissions identified in OAR 340 -271-0110(5)(b). 
For existing covered stationary sources, estimates must be of current annual average covered 
emissions. For new sources and existing sources proposing a modification, estimates must 
be of annual potential to emit covered emissions. Emissions must be identified in MT CO2e, 
following methodologies identified in OAR chapter 340, division 215. This must also 
include and distinguish quantities and covered emissions of each fuel used to control air 
contaminants that are not greenhouse gases; and  
(B) Estimates of current and anticipated type and annual quantity of all fuels used or 
proposed to be used by the covered stationary source;  
(c) Identification and description of all available fuels, processes, equipment, technology, systems, actions, and other strategies, methods and techniqu es for reducing covered 
emissions described in OAR 340 -271-0110(5)(b). Strategies considered must include but are 
not limited to the strategies used by other sources in this state or in other jurisdictions that 
produce goods of comparable type, quantity, a nd quality; and  
(d) An assessment of each of the following for each strategy identified in subsection (c):  
(A) An estimate of annual average covered emissions reductions achieved if the strategy 
were implemented compared to the emissions estimated in parag raph (b)(A);  295 
 (B) Environmental and health impacts, both positive and negative, if the strategy were 
implemented, including any impacts on air contaminants that are not greenhouse gases and 
impacts to nearby communities;  
(C) Energy impacts if the strategy w ere implemented, including whether and how the 
strategy would change energy consumption at the covered stationary source, including impacts related to any fuel use that results in anthropogenic greenhouse gas emissions. Any energy- related costs must be inc luded in the economic impacts assessment in paragraph (D), 
not the energy impacts assessment;  
(D) Economic impacts if the strategy were implemented, including operating costs and the costs of changing existing processes or equipment or adding to existing p rocesses and 
equipment. Any energy- related costs must be included in the economic impacts assessment, 
not the energy impacts assessment in paragraph (C). The economic impacts assessment must 
include both costs and cost savings (benefits);  
(E) An estimate o f the time needed to fully implement the strategy at the covered stationary 
source; and  
(F) A list of the information, resources, and documents used to support development of the BAER assessment, including, if available, links to webpages that provide publ ic access to 
supporting documents.  
(3) Upon receipt of a BAER assessment described in section (2), DEQ will review the submittal and if DEQ determines that any additional information, corrections, or updates are 
required then DEQ may provide the owner or operator of the covered stationary source with 
a written request to provide such information by a certain date or DEQ may issue the BAER 
order based on the information it has available. If DEQ requests that the owner or operator 
of the covered stationary source revise its BAER assessment according to this section, the 
owner or operator must provide such information no later than the deadline provided by 
DEQ.  
(4) Five year BAER reports.  
(a) Every five years following the date that DEQ issued a BAER order, the  owner or 
operator of a covered stationary source must submit to DEQ a five year BAER report that 
includes an update of the information described in subsections (2)(a) through (c).  
(b) If one or more new strategies are identified in a five year BAER report required in 
subsection (a) that have not previously been evaluated in a BAER assessment, DEQ may 
notify the owner or operator of the covered stationary source and require that it conduct a complete BAER assessment according to section (2) and submit it to  DEQ. Such complete 
BAER assessment must also include:  
(A) Evaluation of any new strategies identified and any previously identified strategies using any new information available at the time the assessment is being conducted; and  296 
 (B) Current status and an alysis of the implementation of requirements in any prior BAER 
order(s).  
(5) When notified in writing by DEQ, the owner or operator of a covered stationary source 
identified in section (1) may be required to conduct and submit an updated complete BAER 
assessment conducted according to this rule, in accordance with the following:  
(a) DEQ may not require the owner or operator of a covered stationary source to complete 
an updated BAER assessment within five years of the date of submission of the most recently completed BAER assessment unless the source is proposing a modification and is 
required to complete a new BAER assessment under OAR 340 -271-0310(1)(c). However, if 
DEQ determines the owner or operator of a covered stationary source submitted information 
that it knew or should have known was false, inaccurate, or incomplete to DEQ, then DEQ 
may require the owner or operator of the covered stationary source to complete an updated 
BAER assessment within five years of the date of submission of the most recently  
completed BAER assessment;  
(b) The updated BAER assessment must include assessment of new strategies and previously identified strategies and any new information available at the time the assessment 
is being conducted;  
(c) The owner or operator of the cov ered stationary source must include current status and 
analysis of the implementation of requirements in any prior BAER order; and  
(d) The owner or operator of the covered stationary source must submit the updated BAER assessment to DEQ not later than nine months following the date of DEQ’s notice, unless 
DEQ has identified a later deadline in the notice or DEQ approves an extension according to 
section (6).  
(6) The owner or operator of a covered stationary source required to conduct a BAER 
assessment as described in sections (1) or (5) may request an extension of time to complete 
the BAER assessment by providing DEQ with a written request no fewer than 30 days prior 
to the submittal deadline. DEQ may grant an extension based on the following criteria:  
(a) T he owner or operator of the covered stationary source has demonstrated progress in 
completing the submittal; and  
(b) A delay is necessary, for good cause shown by the owner or operator of the covered stationary source, related to obtaining more accurate or  new data, performing additional 
analyses, or addressing changes in operations or other key parameters, any of which are likely to have a substantive impact on the outcomes of the BAER assessment.  
Statutory/Other Authority: ORS 468.020, 468A.025, 468A.040 & 468A.050 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468A.050, 468.035, 
468A.010, 468A.015 & 468A.045 297 
 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021  
 
340-271-0320  
Best Available Emissions Reduction Order  
(1) DEQ may issue a BAER order for each owner or operator of a covered stationary source 
that must submit a BAER assessment as provided in OAR 340 -271-0310. A BAER order 
will establish the actions that the owner or operator of a covered stationary source must take to reduce covered emissions and the timeline on which the actions must be taken. 
(2) In establishing the requirements in a BAER order for a covered stationary source, DEQ 
may consider any information it deems relevant, and must consider the following:  
(a) Information submitted in a BAER assessment;  
(b) The fuels, processes, equipment, technology, systems, actions, and other strategies, methods and techniques that maximize covered emissions reductions;  
(c) The fuels, processes, equipment, technology, systems, actions, and other strategies, methods and techniques for reducing covered emissions used by sources in this state or in other jurisdictions that produce goods of comparable type, quantity, and quality; 
(d) A reasonable schedule and amount of time necessary to implement a strategy under 
consideration by DEQ to reduce covered emissions;  
(e) Environmental, public health, and energy impacts of a strategy under consideration by DEQ to reduce covered emissions, including but not limited to air quality impacts for nearby communities and impacts related to switching to cleaner energy resources, zero- emissions 
energy resources, or renewable fuels;  
(f) Economic impacts of a strategy under consideration by DEQ to reduce covered emissions including, but not limited to, costs so great that a new source could not be built or an existing source could not be operated, and cost- effectiveness of different strategies that 
would achieve similar covered emissions reductions; 
(g) Processes and operations currently in use by and at the covered stationary source and the 
remaining useful life of the covered stationary source;  
(h) Whether a strategy under consideration by DEQ to reduce covered emissions is achievable, technically feasible, commercially available, and cost -effective;  298 
 (i) Whether a strategy under consider ation by DEQ to reduce covered emissions has an 
impact on the type or quality of good(s) produced by and at the covered stationary source, if 
applicable; and 
(j) Input from the public and community organizations from nearby the covered stationary 
source. Upon receipt of a BAER assessment, DEQ will provide public notice with a copy of the BAER assessment and a minimum of 30 days to submit written comments. DEQ also will provide public notice with a copy of DEQ’s draft BAER order and a minimum of 30 days to s ubmit written comments.  
(3) For the owner or operator of a covered stationary source required to register and report according to OAR chapter 340, division 215, DEQ will consider emissions data reports to assess whether covered emissions reductions are bei ng achieved when establishing the 
requirements in a BAER order or for determining when to notify the owner or operator of a covered stationary source to conduct and submit an updated complete BAER assessment as described in OAR 340-271-0310(5). 
(4) DEQ may  verify information submitted in a BAER assessment.  
(5) DEQ may consult with industry experts and third- party organizations before issuing a 
BAER order.  
(6) DEQ will notify the owner or operator of a covered stationary source of a BAER order in 
writing. A BAER order is effective 30 days from the date of the notification unless, within that time, DEQ receives a written request for a hearing from the owner or operator of the covered stationary source according to section (7). 
(7) The owner or operator of a covered stationary source may file with DEQ a written 
request for a contested case hearing to challenge a BAER order issued according to section (6). The request must be filed in writing within 30 days of the date that DEQ issued the BAER order and must state the grounds for the request. The hearing will be conducted as a 
contested case hearing in accordance with ORS 183.413 through 183.470 and OAR chapter 
340, division 11. 
(8) DEQ will provide a public status update if DEQ has not yet issued a BAER order after 
18 months of the date on which DEQ notified the owner or operator of a covered stationary source that it must conduct a BAER assessment.  
Statutory/Other Authority: ORS 468.020, 468A.025 & 468A.040 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 299 
 340-271-0330  
Compliance with a BAER Order  
(1) The owner or operator of a covered stationary source for which DEQ has issued a BAER 
order according to OAR 340- 271-0320 must:  
(a) Comply with the requirements in the BAER order; and  
(b) For an existing source that is required to complete a BAER assessment under OAR 340 -
271-0310(1)(a), submit to DEQ or LRAPA, as applicable, a complete permit modification 
application for a CPP permit addendum accordin g to OAR 340 -271-0150(3) not later than 
90 days after the date that the BAER order is final and effective, or a later date specified in the BAER order.  
(2) Reporting requirements.  
(a) The owner or operator of a covered stationary source that has been issued a CPP permit addendum or operating permit that includes provisions related to a BAER order must submit an annual progress report to DEQ describing the progress in implementing the requirements in the BAER order. The annual progress reports are due to DEQ  on or before February 15 of 
each year following the date that the notice of the BAER order is final and effective. The annual progress report must include:  
(A) A description of the progress achieved in implementing the requirements in any BAER order;  
(B) A schedule indicating dates for future increments of progress;  
(C) A description of any increases or decreases in covered emissions that have occurred at the covered stationary source since the submission date of the most recently conducted complete BAER a ssessment; and  
(D) An estimate of when all implementation of requirements of the BAER order will be complete.  
(b) The owner or operator of a covered stationary source must submit a BAER order completion report to DEQ no later than 60 days after implementat ion of all requirements in 
the BAER order are complete, except for items related to continuous and ongoing requirements. The report must include:  
(A) The final increments of progress achieved in fully implementing the requirements in the BAER order and the  date the final increments of progress were achieved;  
(B) A summary of the actions taken to fully implement the requirements in the BAER order; and 300 
 (C) An estimate of the resulting covered emissions reductions that will be achieved now that 
the requirements in the BAER order are being implemented.  
Statutory/Other Authority: ORS 468.020, 468A.025 & 468A.040 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-0420  
Distribution of Compliance  Instruments to Covered Fuel Suppliers  
(1) DEQ will distribute compliance instruments according to this rule. DEQ will distribute compliance instruments from a cap according to sections (2), (3), (4), and (6) no later than June 30 of the calendar year of that cap.  
(2) Annual distribution of compliance instruments to covered fuel suppliers that are local distribution companies. DEQ will annually distribute to each local distribution company, or to its successor(s) due to a change in ownership or operation, the number of compliance 
instruments from the calendar year’s cap stated in Table 4 in OAR 340 -271-9000. 
(3) DEQ will establish a compliance instrument reserve for covered fuel suppliers that are new to the program and are not local distribution companies. DEQ will hold, according to subsection (4)(a), a subset of compliance instruments in the reserve from the caps identified in Table 2 in OAR 340-271-9000. Once a compliance instrument is held in the reserve, it remains in the reserve until DEQ determines, at its discretion, to undertake one of the following actions:  
(a) DEQ distributes the compliance instrument according to section (5) to a covered fuel supplier that is not a local distribution company; 
(b) DEQ retires the compliance instrument because the compliance instrument reserve 
exceeds the size described in Table 3 OAR 340 -271- 9000, provided that after such 
retirement the size of the compliance instrument reserve will equal or exceed the reserve size described in Table 3; or  
(c) DEQ distributes the c ompliance instrument to a covered fuel supplier that is not a local 
distribution company because the size of the compliance instrument reserve exceeds the reserve size described in Table 3 in OAR 340 -271-9000. DEQ will only distribute 
compliance instrument s from the reserve according to this subsection if there are at least 
10,000 compliance instruments to distribute and if the remaining size of the reserve after this distribution will equal or exceed the reserve size described in Table 3 in OAR 340 -271-
9000. DEQ will calculate the number of compliance instruments to distribute to each covered fuel supplier that is not a local distribution company according to subsection (4)(b), 301 
 except “total compliance instruments to distribute” means the total number of co mpliance 
instruments DEQ is distributing from the reserve according to this subsection.  
(4) Annual distribution of compliance instruments to covered fuel suppliers that are not local 
distribution companies. DEQ will annually distribute compliance instrumen ts from the 
applicable calendar year’s cap to covered fuel suppliers that are not local distribution companies as follows:  
(a) If the size of the compliance instrument reserve is less than the reserve size described in Table 3 in OAR 340- 271-9000 for the c alendar year, then DEQ will calculate the difference 
and hold in the compliance instrument reserve that quantity of compliance instruments. Otherwise, the number of compliance instruments in the reserve will not be changed.  
(b) Except for compliance instru ments identified in Table 4 in OAR 340 -271-9000 for 
distribution according to section (2) and the compliance instruments held in the reserve according to section (3) and subsection (4)(a), DEQ will calculate the number of compliance instruments to distribu te to each covered fuel supplier that is not a local distribution 
company as described in this subsection, based on emissions data from the prior calendar 
year as reported by each covered fuel supplier as required by OAR chapter 340, division 
215, and subj ect to DEQ’s initial review for errors, but prior to completion of third -party 
verification as required by OAR chapter 340, division 272.  A person that becomes a 
covered fuel supplier after DEQ has distributed the compliance instruments for that year will 
not receive a distribution under this subsection.  
(A) Prior to each calculation of compliance instrument distribution in OAR 340 -271-
0420(4)(b)(B), DEQ will apply a “Verified emissions data correction factor” to the annual 
compliance instrument distribution of each covered fuel supplier. DEQ will recalculate the 
compliance instrument distribution from the previous year using third -party verified 
emissions data. If DEQ determines that the reported emission data used for the previous 
year’s complia nce instrument distribution resulted in a lesser or greater number of 
compliance instruments being distributed to a covered fuel supplier, when compared to the 
recalculation using the third -party verified data, DEQ will increase or reduce, respectively, 
the number of compliance instruments distributed to the covered fuel supplier by an equal 
amount in the current compliance instrument distribution.  
(B) DEQ will use the following formula to calculate the number of compliance instruments 
to distribute to each  covered fuel supplier:  
Number of Compliance Instruments = (Total compliance instruments to distribute * 
([Covered fuel supplier covered emissions + covered fuel supplier biofuel emissions] / Total emissions)) ± Verified emissions data correction factor – Compliance instrument holding 
limit reduction  
(C) As used in the formula in paragraph (B):  302 
 (i) “Total compliance instruments to distribute” means the cap for the calendar year, 
according to Table 2 in OAR 340- 271-9000, minus the number of compliance instru ments 
identified in Table 4 in OAR 340- 271-9000; and minus the number of compliance 
instruments held in the compliance instrument reserve;  
(ii) “Covered fuel supplier covered emissions” means the sum of a covered fuel supplier’s 
covered emissions for the p rior calendar year;  
(iii) “Covered fuel supplier biofuel emissions” means emissions described in OAR 340 -271-
0110(3)(b)(B)(i) that result from the complete combustion or oxidation of the annual 
quantity of biomass -derived fuels that the covered fuel suppli er imported, sold, or 
distributed for use in the state for the prior calendar year;  
(iv) “Total emissions” means the sum of “covered fuel supplier covered emissions” and 
“covered fuel supplier biofuel emissions” for the  prior calendar year for all covere d fuel 
suppliers whose compliance instrument distribution is calculated according to this section; 
and 
(v) “Verified emissions data correction factor” means a correction applied as a result of 
changes to reported data since the previous distribution of com pliance instruments, as 
described in OAR 340- 271-0420(4)(b)(A); and  
(vi) “Compliance instrument holding limit reduction” means the number of compliance instruments described in OAR 340 -271-0430(2).  If the compliance instrument holding limit 
reduction exce eds the number of compliance instruments that a covered fuel supplier would 
have received in the distribution before subtracting the compliance instrument holding limit reduction, then the covered fuel supplier will not receive any compliance instruments in the 
distribution, and a compliance instrument holding limit reduction equal to the amount by 
which it exceeded the number of compliance instruments that a covered fuel supplier would 
have received in the distribution before subtracting the compliance ins trument holding limit 
will be applied in the following year.  
(D) DEQ will distribute a number of compliance instruments to each covered fuel supplier 
using the formula in paragraph (B) and rounded down to the nearest whole number.  
(E) Any remaining complia nce instruments not distributed due to rounding will be held in 
the compliance instrument reserve.  
(5) Distribution from compliance instrument reserve for new covered fuel suppliers that are 
not local distribution companies.  
(a) A covered fuel supplier is eligible for a distribution from the compliance instrument 
reserve if it is not a local distribution company and if  
 303 
 the person was not included in the distribution of compliance instruments for that year 
according to section (4).  
(b) For all c alendar years after 2024, a covered fuel supplier meeting the requirements of 
subsection (a) is not eligible for a distribution of compliance instruments from the reserve if the person is a related entity to a covered fuel supplier that received a distribu tion of 
compliance instruments under section (4)(c).  
A covered fuel supplier identified according to subsection (a) and not ineligible under 
subsection (b) may request a distribution of compliance instruments from the reserve by 
submitting an application to DEQ, on a form approved by DEQ, that includes the 
information described in paragraphs (A) through (D), no later than June 1 of the year after 
the calendar year of the annual distribution of compliance instruments from which the 
covered fuel supplier was  not included. The covered fuel supplier must submit a separate 
application for each year for which it is seeking distribution of compliance instruments from the reserve.  
(A) Information about the covered fuel supplier, including:  
(i) Name and full mailing  address; and 
(ii) Designated representative’s contact information including name, title or position, phone 
number, and email address;  
(B) The calendar year of covered emissions for which compliance instruments are requested;  
(C) The reason for the request , including description of eligibility according to subsection 
(a); and  
(D) The following attestation, signed by the designated representative of the covered fuel supplier:  
I certify under penalty of perjury under the laws of the State of Oregon that I am a 
representative of [covered fuel supplier], am authorized to submit this application on its 
behalf, and that, to the best of my knowledge and belief, the information provided in this 
form is true, accurate, and complete. [Covered fuel supplier] is a cover ed fuel supplier in the 
year indicated in this application and requests compliance instruments from the reserve according to the information included in this application.  
(c) DEQ will review an application submitted according to subsection (b) to ensure th at it 
meets the requirements of this section. DEQ will inform the applicant either that the submitted application is complete or that additional specific information is required to make the application complete. If the application is incomplete, DEQ will n ot consider the 
application further until the applicant provides the additional information requested by DEQ.  304 
 (d) If DEQ approves an application, DEQ will distribute one or more compliance 
instruments to the covered fuel supplier from the reserve no later than June 15 of the year after the calendar year of the annual distribution of compliance instruments from which the covered fuel supplier was not included. DEQ will distribute compliance instruments from the reserve to the covered fuel supplier, as follows:  
(A) A maximum distribution amount that will not exceed the covered fuel supplier’s covered emissions in that calendar year using emissions data from the prior calendar year as reported by each covered fuel supplier as required by OAR 340, division 215, and subject to DEQ’s initial review for errors, but prior to completion of third -party verification as required by 
OAR 340, division 272; and 
(B) If there are fewer compliance instruments in the reserve at the time of distribution than 
have been requested by all covered fuel suppliers who are approved for a reserve distribution for a calendar year, DEQ shall allocate compliance instruments in the reserve according to the ratio of each covered fuel supplier’s covered emissions in that calendar year to the total covered emissions from all covered fuel suppliers in that calendar year.  
(6) Each year, the sum of all compliance instruments that are not distributed to fuel suppliers in the distribution under section OAR 340-271-0420(4) as a result of compliance instrument holding limit reductions will be distributed to all covered fuel suppliers that did not have any compliance instrument holding limit reduction using the formula described in paragraph OAR 340 -271-0420(4)(b)(B), except that, for purposes of s uch redistribution, “total 
compliance instruments to distribute” means the total number of compliance instruments that DEQ did not distribute to fuel suppliers in the general distribution under section OAR 340-271- 0420(4) as a result of compliance instrume nt holding limit reductions. Such 
additional distribution of compliance instruments shall be made at the same time as the distribution described in section OAR 340-271-0420(4). Any remaining compliance 
instruments not distributed due to rounding will be he ld in the compliance instrument 
reserve.  
(7) Upon distribution of compliance instruments according to sections (2), (4), (5), and (6), 
DEQ will notify the designated representative of each covered fuel supplier in writing of the availability of compliance instruments.  
(8) DEQ will track distributed compliance instruments.  
Statutory/Other Authority: ORS 468.020, 468A.025 & 468A.040 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 305 
 340-271-0430  
Holding Compliance Instruments  
(1)When DEQ distributes a compliance instrument to a covered fuel supplier according to 
OAR 340 -271-0420 or when a covered fuel supplier acquires a compliance instrument 
according to OAR 340- 271-0500, the cove red fuel supplier may continue to hold the 
compliance instrument until any of the following apply:  
(a) The covered fuel supplier uses the compliance instrument toward its demonstration of compliance with a compliance obligation according to OAR 340- 271-0450; 
(b) The covered fuel supplier transfers the compliance instrument to another covered fuel supplier according to OAR 340- 271-0500; or  
(c) The covered fuel supplier has ceased being a covered fuel supplier according to OAR 340-271-0130. When this occurs, DEQ may, at its discretion: 
(i) Retire the compliance instrument; or 
(ii) If the covered fuel supplier is not a local distribution company:  
(A) Hold the compliance instrument in the compliance instrument reserve described in OAR 
340-271-0420(3); or  
(B) Dis tribute the compliance instrument to a covered fuel supplier that is not a local 
distribution company. DEQ will only distribute the compliance instrument if there are at 
least 10,000 compliance instruments to distribute. DEQ will calculate the number of compliance instruments to distribute to each covered fuel supplier according to OAR  340-
271-0420(4)(b), except “total compliance instruments to distribute” means the total number 
of compliance instruments DEQ is distributing according to this paragraph.  
(2) For each covered fuel supplier that is not a local distribution company, a compliance 
instrument holding limit reduction will be calculated on November 22 of the year following 
the end of each compliance period, or 25 days after DEQ’s notification in OAR 340 -271-
0450(1), whichever is later. A covered fuel supplier’s compliance instrument holding limit reduction is the number of compliance instruments from any prior year held by the covered 
fuel supplier on that date that exceeds one and a half times the sum  of the covered fuel 
supplier’s annual compliance obligation(s) for each year of the prior compliance period. In 
the year subsequent to the year after the end of a compliance period, if a fuel supplier did not receive any compliance instruments in the dist ribution under section OAR 340- 271-0420(4) 
in the prior year because its compliance instrument holding limit reduction exceeded the number of compliance instruments that it otherwise would have been distributed, then the fuel supplier’s compliance instrume nt holding limit reduction will be reduced as provided in 
subparagraph OAR 340- 271-0420(4)(b)(B)(vi), and such reduced compliance instrument 306 
 holding limit reduction will be used in the subsequent year’s compliance instrument 
distribution calculation under section OAR 340 -271-0420(4).  
 
Statutory/Other Authority: ORS 468.020, 468A.025 & 468A.040 
Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-0450  
Demonstration of Compliance 
(1) DEQ will determine a covered fuel supplier’s total compliance obligation for a 
compliance period as the sum of the covered fuel supplier’s annual compliance obligation(s) for each year of the compliance period. DEQ will base its determinations on emissions calculated according to OAR 340-271-0110(1). DEQ will notify the covered fuel supplier of 
its determination.  
(2) A covered fuel supplier must demonstrate compliance according to this rule by December 9 of the year following the end of each compliance period, or 40 days after DEQ’s notification described in section (1), whichever is later. 
(3) To demonstrate compliance for a compliance period, a covered fuel supplier must submit 
the following to DEQ: 
(a) For each metric ton of CO2e of the total compliance oblig ation, either a compliance 
instrument or a CCI credit, subject to the following limitations: 
(A) A covered fuel supplier may only submit compliance instruments that DEQ distributed 
from the caps for the calendar years of the applicable compliance period or  from caps for 
earlier compliance periods; and  
(B) The quantity of CCI credits used to demonstrate compliance as a percentage of the total compliance obligation for the applicable compliance period may not exceed the allowable percentage specified in Table 6 in OAR 340-271-9000. 
(b) A demonstration of compliance form, approved by DEQ that includes: 
(A) Name and full mailing address of the covered fuel supplier;  
(B) Designated representative’s contact information including name, title or position, phone 
number, and email address;  307 
 (C) Identification of the compliance period and calendar year(s) for which the covered fuel 
supplier is demonstrating compliance; 
(D) The total compliance obligations in metric tons of CO2e for the compliance period and 
listed separa tely for each calendar year in the compliance period;  
(E) The total number of compliance instruments the covered fuel supplier is submitting to DEQ to demonstrate compliance, and separately the total number submitted from each calendar year’s cap;  
(F) The total number of CCI credits the covered fuel supplier is submitting to DEQ to demonstrate compliance; and 
(G) The following attestation, signed by the designated representative of the covered fuel 
supplier: 
I certify under penalty of perjury under the laws of the State of Oregon that I am a 
representative of [covered fuel supplier], am authorized to submit this report on its behalf, and that, to the best of my knowledge and belief, the information provided in this form is true, accurate, and complete. It is  the intent of [covered fuel supplier] to use the quantity of 
compliance instruments and credits listed on this form and submitted to DEQ for the demonstration of compliance. I certify that [covered fuel supplier] has not exceeded the allowable use of CCI credits. If any portion of these compliance obligations remain unmet after this submission, I understand that [covered fuel supplier] must still demonstrate compliance with the remaining portion and may be subject to enforcement action. 
(4) Each metric ton  of CO2e of a compliance obligation for which a covered fuel supplier 
does not demonstrate compliance according to this rule is a separate violation of this 
division. 
(5) If a change in ownership of a covered fuel supplier occurs, the person that owns or 
operates the covered fuel supplier as of December 31 in the final year of a compliance period is responsible for demonstration of compliance according to this rule for each annual compliance obligation during the compliance period. Compliance obligations may not be split or subdivided based on ownership changes during the compliance period or during any year within the compliance period. 
Statutory/Other Authority: ORS 468.020, 468A.025 & 468A.040 
Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 308 
 340-271-8100  
Program Review  
(1) DEQ will report to the EQC on community climate investments. DEQ will submit the 
first report to the EQC by August 30, 2024 and every two years thereafter. DEQ will share each report with current members of the equity advisory committee after submission to the EQC. Each community climate investment report will include:  
(a) A review of community climate investments, including:  
(A) CCI credits distributed to covered fue l suppliers;  
(B) CCI credits used by covered fuel suppliers to demonstrate compliance;  
(C) Estimates of annual greenhouse gas emissions reductions that are anticipated to be achieved by completed projects that CCI entities have reported to DEQ by March 31 of the year DEQ is reporting to the EQC; 
(D) Estimates of annual non- greenhouse gas air contaminant emissions reductions that are 
anticipated to be achieved by completed projects that CCI entities have reported to DEQ by 
March 31 of the year DEQ i s reporting to the EQC;  
(E) Calculation of the average anthropogenic greenhouse gas emissions reductions achieved per CCI credit distributed based on (A) and (C) and whether reductions of approximately one MT CO2e or more of anthropogenic greenhouse gas em issions for the average CCI 
credit distributed by DEQ was achieved; and  
(F) Description of community benefits achieved; and 
(b) DEQ’s recommendations regarding any necessary or desirable changes to the CPP 
provisions relating to CCIs, including, without li mitation, recommendations on changes to 
the CCI credit contribution amounts described in Table 7 in OAR 340- 271-9000 necessary 
to assure that the use of CCI funds is reducing anthropogenic greenhouse gas emissions in Oregon by an average of at least one MT  CO2e per CCI credit distributed by DEQ, as well 
as recommendations on how to best achieve the purposes of CCIs described in OAR 340-271-0900, if applicable.  
(2) DEQ will report to the EQC on implementation of the Climate Protection Program. DEQ will submit the first report to the EQC five years after the date of adoption of this division and at least once every five years thereafter. Each program review report will include:  
(a) A review of the Climate Protection Program, including:  
(A) Summary of covered f uel suppliers’ demonstrations of compliance for compliance 
periods that have occurred since program start, including:  309 
 (i) Caps for each year and compliance period;  
(ii) Compliance obligations for each year and compliance period;  
(iii) Compliance instruments submitted for each compliance period; and  
(iv) CCI credits submitted for each compliance period;  
(B) Summary of the distribution of compliance instruments, including the size of the 
compliance instrument reserve at the start and end of each program year that has occurred and compared to Table 3 in OAR 340- 271-9000;  
(C) Summary of activity relating to trading of compliance instruments for each program year 
that has occurred;  
(D) Summary of covered stationary source requirement activities that have occurred  since 
program start or since the most recently submitted report to the EQC, whichever is later, 
including:  
(i) The number of existing stationary sources that DEQ has notified in writing that must 
complete a BAER assessment;  
(ii) The number of BAER assessm ents received or anticipated to be received by DEQ;  
(iii) A brief summary of any BAER order issued and the required actions that must be taken 
by the owner or operator of a covered stationary source that has been issued a BAER order;  
(iv) A brief summary o f the status of any covered stationary source activities regarding 
implementation of requirements in a BAER order; and  
(v) Review of any changes in annual covered emissions from current covered stationary 
sources to assess whether covered emissions are bei ng reduced;  
(E) Whether emission reductions from covered stationary sources align with the priorities described in section (3). This will be assessed in program reviews beginning after 2029.  
(F) A current list of covered entities by name and whether each is a covered fuel supplier or 
covered stationary source; and  
(G) Description of any enforcement actions taken that involved civil penalties, if applicable; 
and 
(b) DEQ’s recommendations regarding any potential changes to the CPP including, for 
example and without limitation, recommendations regarding potential changes to best achieve the goals described in section (3) for covered stationary sources.  310 
 (3) CPP goals for covered stationary sources described in OAR 340-271-0110(5) are to: 
(a) Reduce total covered emissions from covered stationary sources; and  
(b) Reduce total covered emissions from covered stationary sources that are the result of use 
of solid or gaseous fuels by 50 percent by 2035 from the average of 2017 through 2019 emissions.  
(4) If the average annual statewide retail cost of gasoline, diesel or natural gas in Oregon increases year -over-year by an amount that is more than 20 percent higher than the average 
change in cost for the same fuel over the same period in Washington, Idaho, and Nevada, DEQ will investigate the cause(s) of the increase and report to the EQC regarding whether changes to the rules in this division should be made that would ameliorate a relative increase in costs in Oregon. If necessary, DEQ will consider rec ommending rule changes, such as 
changes to caps and distribution of additional compliance instruments, changes to the compliance instrument reserve, or changes to the allowable usage of CCI credits.  
Statutory/Other Authority: ORS 468.020, 468A.025 & 468A.040 Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
340-271-9000  
Tables  
(1) Table 1. Thresholds for applicability described in OAR 340-271-0110(3). 
(2) Table 2. Oregon Climate Protection Program caps.  
(3) Table 3. Compliance instrument reserve size.  
(4) Table 4. Compliance instrument distribution to covered fuel suppliers that are local 
distribution companies.  
(5) REPEALED effective x/x/xxxx]. 
(6) Table 6. Covered fuel supplier allowable usage of community climate investment credits 
to demonstrate compliance as described in OAR 340-271-0450(3). 
(7) Table 7. CCI credit contribution amount.  
[ED. NOTE: To view attachments referenced in rule text, click here to view rule.]  311 
 Statutory/Other Authority: ORS 468.020, 468A.025 & 468A.040 
Statutes/Other Implemented: ORS 468.020, 468A.025, 468A.040, 468.035, 468A.010, 468A.015 & 468A.045 History:  
DEQ 27 -2021, adopt filed 12/16/2021, effective 12/16/2021
 
 
OAR 340 -271-9000  
Table 1  
Thresholds for  
applicability described in OAR 340-271-0110(3)  
Applicability 
determination calendar 
year(s)  Threshold for 
applicability to 
compare to annual 
covered emissions Calendar year a 
person becomes a 
covered fuel supplier 
Any year from 2018 through 2022  200,000 MT CO2e  2022  
2023  200,000 MT CO2e  2023  
2024  200,000 MT CO2e  2024  
Any year from 2021 through 2025  100,000 MT CO2e  2025  
2026  100,000 MT CO2e  2026  
2027  100,000 MT CO2e  2027  
Any year from 2024 through 2028  50,000 MT CO2e  2028  
2029  50,000 MT CO2e  2029  
2030  50,000 MT CO2e  2030  
Any year from 2027 through 2031  25,000 MT CO2e  2031  
2032  25,000 MT CO2e  2032  
Each subsequent year  25,000 MT CO2e  Each subsequent year  
 
312 
 OAR 340-271-9000  
 
Table 2  
Oregon Climate Protection Program caps  
Calendar year  Cap 
2022  28,081,335  
2023  27,001,283  
2024  25,921,232  
2025  25,763,209  
2026  24,637,057  
2027  23,510,904  
2028  23,013,190  
2029  21,842,149  
2030  20,671,108  
2031  19,910,424  
2032  18,688,088  
2033  17,465,752  
2034  16,243,416  
2035  15,021,080  
2036  14,219,956  
2037  13,418,831  
2038  12,617,707  
2039  11,816,583  
2040  11,015,459  
2041  10,214,334  
2042  9,413,210  
2043  8,612,086  
2044  7,810,962  
2045  7,009,837  
2046  6,208,713  
313 
 2047  5,407,589  
2048  4,606,465  
2049  3,805,340  
2050 and each calendar year thereafter  3,004,216  
 314 
 OAR 340-271-9000  
 
Table 3  
Compliance instrument reserve size  
Calendar year(s) of the cap  Reserve size  
2022  400,000 compliance instruments  
2023 through 2030  800,000 compliance instruments  
2031 through 2040  500,000 compliance instruments  
2041 and each calendar year thereafter  250,000 compliance instruments  
315 
 OAR 340 -271-9000  
 
Table 4  
Compliance instrument distribution to covered fuel suppliers 
that are local distribution companies  
Calendar year  Compliance 
instruments to 
distribute to 
Avista Utilities  Compliance 
instruments to 
distribute to 
Cascade 
Natural Gas 
Corporation  Compliance 
instruments to 
distribute to 
Northwest 
Natural Gas 
Company  
2022  703,373  743,707  5,759,972  
2023  676,320  715,103  5,538,434  
2024  649,267  686,499  5,316,897  
2025  622,214  657,895  5,095,359  
2026  595,161  629,291  4,873,822  
2027  568,109  600,687  4,652,285  
2028  541,056  572,083  4,430,747  
2029  514,003  543,478  4,209,210  
2030  486,950  514,874  3,987,673  
2031  459,897  486,270  3,766,135  
2032  432,845  457,666  3,544,598  
2033  405,792  429,062  3,323,061  
2034  378,739  400,458  3,101,523  
2035  351,686  371,854  2,879,986  
2036  332,930  352,021  2,726,387  
2037  314,173  332,189  2,572,787  
2038  295,416  312,357  2,419,188  
2039  276,660  292,525  2,265,589  
2040  257,903  272,693  2,111,990  
2041  239,147  252,860  1,958,390  
2042  220,390  233,028  1,804,791  
2043  201,633  213,196  1,651,192  
2044  182,877  193,364  1,497,593  
2045  164,120  173,532  1,343,993  
2046  145,364  153,699  1,190,394  
2047  126,607  133,867  1,036,795  
316 
  
OAR 340-271-9000  
Table 6  
Covered fuel supplier allowable usage of community climate  
investment credits to demonstrate compliance as  
described in OAR 340-271-0450 (3) 
Compliance period  Allowable percentage of total 
compliance obligation(s) for which 
compliance may be demonstrated 
with CCI credits  
Compliance period 1 (2022 through 2024)  10%  
Compliance period 2 (2025 through 2027)  15%  
Compliance period 3 (2028 through 2030), and for 
each compliance period thereafter  20% 
 2048  107,850  114,035  883,196  
2049  89,094  94,203  729,596  
 2050 and each 
calendar year 
thereafter  70,337  74,371  575,997  
317 
 OAR 340-271-9000  
Table 7  
CCI credit contribution amount  
Effective date CCI credit contribution amount in 
2021 dollars, to be adjusted 
according to OAR 340-271-0820 (3) 
March 1, 2023  $107  
March 1, 2024  $108  
March 1, 2025  $109  
March 1, 2026  $110  
March 1, 2027  $111  
March 1, 2028  $112  
March 1, 2029  $113  
March 1, 2030  $114  
March 1, 2031  $115  
March 1, 2032  $116  
March 1, 2033  $117  
March 1, 2034  $118  
March 1, 2035  $119  
March 1, 2036  $120  
March 1, 2037  $121  
March 1, 2038  $122  
March 1, 2039  $123  
March 1, 2040  $124  
March 1, 2041  $125  
March 1, 2042  $126  
March 1, 2043  $127  
March 1, 2044  $128  
March 1, 2045  $129  
318 
 March 1, 2046  $130  
March 1, 2047  $131  
March 1, 2048  $132  
March 1, 2049  $133  
March 1, 2050  $134  
 
  319 
  
Third Party Verification, Division 272  
 
340-272-0020  
 
Definitions  
The definitions in this rule and in OAR 340- 200-0020, OAR 340- 215-0020, and OAR 340-
253-0040, and the acronyms in OAR 340- 253-0060 apply to this division. If the same term 
is defined in this rule and another division, the definition in this rule applies to this division.  
(1) “Adverse verification statement” means a verification statement from a verification body that (either or both):  
(a) It cannot say with reasonable assurance the submitted report or fuel pathway application is free of a material misstatement; or 
(b) The submitted report or fuel pathway application contains correctable errors and thus is 
not in confor mance with the requirements to fix such errors according to OAR 340 -272-
0435. 
(2) “California ARB” means California Air Resources Board.  
(3) “CFP” means the Oregon Clean Fuels Program established under OAR chapter 340, 
division 253.  
(4) “Conflict of intere st” means a situation in which, because of financial or other activities 
or relationships with other persons or organizations, a verification body is unable or potentially unable to provide an impartial verification statement of a potential client’s report 
or fuel pathway application, or the verification body’s objectivity in providing verification services is or might be otherwise compromised.  
(5) “Correctable errors” means errors identified by the verification team that affect data in 
the submitted report  or fuel pathway application, which result from a nonconformance with 
OAR chapter 340, division 215 or OAR chapter 340, division 253, as applicable. 
Differences that, in the professional judgment of the verification team, are the result of differing but re asonable methods of truncation or rounding or averaging, where a specific 
procedure is not prescribed by this division, OAR chapter 340, division 215, or OAR chapter 340, division 253, are not considered errors and therefore do not require correction.  
(6) “DEQ” means Oregon Department of Environmental Quality.  
(7) “Difference in CI” means the absolute value result of the reported operational CI minus the verifier’s calculation of CI for material misstatement of carbon intensity assessments for 320 
 a CFP fuel pa thway application or annual report. The verifier’s calculation of CI is based on 
site-specific data inputs modified to include discrepancies, omissions, and misreporting 
found during the course of verification services.  
(8) “Full verification” means all verification services as required under OAR 340 -272-
0300(1).  
(9) “GHG Reporting Program” means the Oregon Greenhouse Gas Reporting Program 
established under OAR chapter 340, division 215. 
(10) “Independent reviewer” means a lead verifier within a verificatio n body that has not 
participated in providing verification services for a responsible entity for the current 
reporting year and provides an independent review of verification services provided to the 
responsible entity.  
(11) “Lead verifier” means a person that has met the requirements to perform such role 
under OAR 340- 272-0210 and has been approved by DEQ under OAR 340- 272-0220 to act 
as the lead of a verification team providing verification services as described by this division.  
(12) “Less intensive veri fication” means all verification services required for full 
verification, except for site visit(s) as described under OAR 340 -272-0420, and only 
requiring data checks and document reviews based on the analysis and risk assessment in the 
most recent samplin g plan developed as part of the most current full verification.  
(13) “Material misstatement” means any discrepancy, omission, misreporting, or 
aggregation of the three, identified in the course of verification services that leads a 
verification team to bel ieve that reported data or a submitted report or fuel pathway 
application contains one or more errors, as described in OAR 240- 272-0450, OAR 240- 272-
0455, and OAR 240- 272-0460, as applicable.  
(14) “Member” means any employee or subcontractor of the verific ation body or related 
entities of the verification body and includes any individual with majority equity share in the verification body or its related entities. 
(15) “Nonconformance” means the failure to meet the applicable requirements of this 
division or  the failure to meet requirements of OAR chapter 340, division 215 or OAR 
chapter 340, division 253, as applicable, to calculate or report data or submit a fuel pathway 
application.  
(16) “Positive verification statement” means a verification statement from  a verification 
body attesting that it can say with reasonable assurance that the submitted report or fuel pathway application is free of material misstatement and that it conforms to the requirements of this division, OAR chapter 340, division 215, or OAR  chapter 340, division 253, as 
applicable.  321 
 (17) “Professional judgment” means decisions based on professional qualifications and 
relevant greenhouse gas accounting and auditing experience.  
(18) “Qualified positive verification statement” means a statement from a verification body 
attesting that it can say with reasonable assurance that the submitted report or fuel pathway application is free of material misstatement and has been corrected or modified in 
conformance with OAR 340- 272-0435, but may include one  or more other 
nonconformance(s) with the requirements of this division, OAR chapter 340, division 215, 
or OAR chapter 340, division 253, as applicable, which do not result in a material 
misstatement.  
(19) “Quarterly review” means a review process conducted by the verification team after quarterly data is submitted and before annual data is submitted and verified.  
(20) “Reasonable assurance” means high degree of confidence in the accuracy and truth of a conclusion.  
(21) “Reported emissions reductions” means the total of all greenhouse gas emissions 
reductions reported in a CFP project report.  
(22)“Reported Operational CI Value” means the absolute value of the operational CI 
submitted in a CFP fuel pathway application or annual report used for material missta tement 
of carbon intensity assessments.  
(23) “Reported quarterly fuel transaction quantity for fuel pathway code” means the total of all reported fuel quantities for each fuel pathway code for each transaction type for each 
quarter in a CFP quarterly repor t for which the verifier is conducting a material 
misstatement of quarterly fuel quantity assessment.  
(24) “Responsible entity” means a person that is subject to or voluntarily agrees to be 
subject to the requirements of OAR 340- 272-0110, OAR 340- 272-0120,  or both.  
(25) “Sector specific verifier” means a person that has met the requirements to perform such 
a role under OAR 340- 272-0210 and has been approved by DEQ under OAR 340- 272-0220 
to act as a sector specific verifier in providing verification services  as described by this 
division. This may include, but is not limited to, demonstrating specialized experience in 
transactions, oil and gas systems, or process emissions.  
(26) “Subcontractor” means an individual or business firm contracting to perform part or all 
of another’s contract.  
(27) “Total reported emissions” means the total annual greenhouse gas emissions in a GHG 
Reporting Program emissions data report.  322 
 (28) “Validation statement” means the final statement produced by a verification bo dy 
attesting whether a fuel pathway application is free of material misstatement and whether it 
conforms to the requirements of California ARB’s Low Carbon Fuel Standard.  
(29) “Verification” or “third -party verification” means a systematic, independent, an d 
documented process for evaluation of a report or fuel pathway application according to this division. 
(30) “Verification body” means a business entity that has met the requirements under OAR 
340-272-0210 and has been approved by DEQ under OAR 340-272-0220 to provide verification services and produce verification statements as described by this division. 
(31) “Verification services” means services provided during full verification or less 
intensive verification, including but not limited to reviewing a rep ort or fuel pathway 
application submitted by a responsible entity, assessing compliance with DEQ regulations, ensuring accuracy according to the standards specified by DEQ, and submitting a verification statement(s) to DEQ.  
(32) “Verification statement” me ans the final statement produced by a verification body 
attesting whether a report or fuel pathway application submitted by a responsible entity is free of or contains material misstatement and whether it does or does not conform to the applicable requirem ents. 
(33) “Verification team” means all persons working for a verification body, including all subcontractors, to provide verification services.  
(34) “Verifier” means an individual person that has met the requirements to perform such role under OAR 340-272-0210 and has been approved by DEQ under OAR 340-272-0220 to provide verification services as described by this division. 
Statutory/Other Authority: ORS 468.020, 468A.050, 468A.266, 468A.271, 468A.277 & 
468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050, 468A.265 through 468A.277 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
340-272-0100  
 General Requirements for Verification of Reports and Fuel Pathway Applications  
(1) The annual third party verification requirements set forth in this division apply beginning in 2022 for reports with data for calendar year 2021, and in each year thereafter. Quarterly review conducted as part of annual verification services that meet the requirements of this division may begin in 2022 for reports with data for the year 2022. 323 
 (2) Each responsible entity must:  
(a) Engage the services of a verification body to perform verification under this division;  
(b) Do the following before verification services begin:  
(A) Conduct a conflict of interest evaluation in coordination with the verification body 
according to OAR 3 40-272-0500 and develop a conflict of interest mitigation plan, if 
needed, according to OAR 340- 272-0500.  Ensure both a complete and accurate conflict of 
interest evaluation and conflict of interest mitigation plan, as applicable, are submitted to 
DEQ, an d receive from DEQ approval in writing to proceed with verification services; and  
(B) Submit to DEQ the report that is to be verified and attest that the data and information 
submitted to DEQ in the report is true, accurate, and complete; 
(c) Ensure that a verification statement is submitted to DEQ from the verification body for 
each report identified under OAR 340- 272-0110 and OAR 340- 272-0120 by the deadline 
specified under section (3); and  
(d) Ensure the requirements of this division are met, including but not limited to, ensuring that verification services are provided in compliance with the requirements of OAR 340 -
272-0300 and that a potential for a conflict of interest is evaluated, monitored, and mitigated 
according to  
OAR 340 -272-0500;  
(3) Verificat ion deadlines. 
(a) Each responsible entity must ensure that a positive, qualified positive, or adverse 
verification statement is received by DEQ from a verification body by August 31 of the year 
a report is submitted, for the following reports, as applicable:  
(A) Any CFP report, as applicable under OAR 340- 272-0110; and  
(B) Any GHG Reporting Program emissions data report described under OAR 340- 215-
0044(1)  
(a) through (d), and (g), as applicable under OAR 340- 272-0120. 
(b) Each responsible entity must ensure that a positive, qualified positive, or adverse verification statement is received by DEQ from a verification body by September 30 of the 
year a report is submitted, for each GHG Reporting Program emissions data report described 
under OAR 340- 215-0044(1)(e) and (f), as applicable under OAR 340- 272-0120. 
(c) DEQ may extend verification deadlines in subsections (a) or (b) as necessary and will 
issue notice of any extensions.  324 
 (4) Requirements for full or less intensive verification for certain respon sible entities.  
(a) Responsible entities required to engage the services of a verification body to perform 
annual verification of CFP quarterly reports under OAR 340- 272-0110(3), GHG Reporting 
Program emissions data reports under OAR 340- 272-0120(1), or both must engage the 
services of a verification body to provide full verification, as described by this division, in 
the first year that verification is required under section (1), in 2023, and then in at least every third year thereafter, if subsection (b) is applicable. Full verification is required in any year 
where subsection (b) does not apply.  
(b) Responsible entities required to engage the services of a verification body to perform 
annual verification of CFP quarterly reports under OAR 340- 272-0110(3), GHG Reporting 
Program emissions data reports under OAR 340- 272-0120(1), or both may engage the 
services of a verification body to provide less intensive verification in place of full 
verification, for up to two years out of every three year period, if:  
(A) There has not been a change in the verification body;  
(B) A positive verification statement was issued for the previous year; and  
(C) No change of operational control of the responsible entity occurred in the previous year.  
(c) A verification body may choose to provide full verification, at its discretion, in instances 
where the responsible entity has made changes in sources, significant changes in emissions, 
significant changes in data management systems, or any combination therein, occurred 
compared to the previous year, based on the professional judgment of the verification body. 
(A) The verification body must provide reasons why it opted for full verification to the 
responsible entity and to DEQ.  
(B) The verification body must provide justification in the verification report if it did not opt 
for full verification in instances where the total reported emissions differ by greater than 25 percent relative to the previous year’s emissions.  
(5) Verification body and verifier rotation requirements.  
(a) A res ponsible entity must not use the same verification body or verifier(s) to perform 
verification for a period of more than six consecutive years.  
(b) A responsible entity must wait at least three years before re- engaging the previous 
verification body or ver ifier(s) to perform verification.  
Statutory/Other Authority: ORS 468.020, 468A.050, 468A.266, 468A.271, 468A.277 & 468A.280 
Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050, 468A.265 through 
468A.277 & 468A.280 325 
 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020  
 
340-272-0110  
 
Requirements for Verification of CFP Reports and Fuel Pathway Applications Submitted under OAR Chapter 340, Division 253  
(1) Optional verification of CFP fuel pathway (carbon intensity or CI) applications.  
(a) Fuel pathway applicants supplying site -specific CI data for the fuel pathway application 
are not required to meet the requirements of this division or engage the services of a verification body to perform verification for each fuel pathway application submitted under OAR chapter 340, division 253. 
(b) Fuel pathway applications that have been verified according to the requirements of this 
division, including site visit(s), will be prioritized for approval by DEQ. 
(A) Fuel pathway applicants that choose to engage the services of a verification body to 
perform verification may do so once a list of approve d verification bodies and verifiers 
qualified to verify CFP fuel pathway applications is made available on DEQ’s website according to OAR-340-272-0220(1)(d)(B). 
(B) Fuel pathway applicants submitting fuel pathway applications to DEQ that have been 
verified  according to the requirements of this division must submit the verification statement 
at the same time that the application is submitted.  
(C) A fuel pathway application submitted to DEQ that includes an adverse verification statement will not be considered. 
(c) Fuel pathway applications submitted to DEQ that have been verified under California 
ARB’s Low Carbon Fuel Standard may submit to DEQ materials relating to that verification.  
(A) Fuel pathway applications submitted to DEQ that include a positive or qualified positive validation statement under California ARB’s Low Carbon Fuel Standard will be prioritized for approval by DEQ. 
(B) Fuel pathway applications submitted to DEQ that include an adverse validation 
statement under California ARB’s Low Carbon Fu el Standard will not be considered. 
(C) Any verification statements for the fuel pathway under California ARB’s Low Carbon Fuel Standard must also be submitted at the same time that the fuel pathway application and validation statement are submitted to DEQ . 326 
 (2) Annual verification of CFP annual fuel pathway (carbon intensity or CI) reports.  
(a) Applicability. The following persons must meet the requirements of this division and 
engage the services of a verification body for the purposes of annual verificati on under this 
division, including required site visit(s), for each annual fuel pathway report submitted 
under OAR chapter 340, division 253, except as otherwise provided under subsection (b):  
(A) Holders of certified fuel pathways that supplied site -specif ic CI data for pathway 
certification and are required to update site- specific CI data on an annual basis; and  
(B) Specified source feedstock suppliers and other persons with site -specific CI data that 
apply for separate DEQ recognition as a joint applicant  under OAR chapter 340, division 
253 and elect to be responsible for separate verification.  
(b) Exemptions. Holders of approved fuel pathways that do not generate at least 6,000 total credits and deficits during the previous calendar year for the quantity of fuel produced at a 
given production facility and reported in the CFP are not subject to the requirements of this 
division for that year.  
(c) Verification schedule. Responsible entities that are subject to the subsection (a) 
requirement to engage the ser vices of a verification body to perform verification of annual 
fuel pathway reports (CI) must ensure a fuel pathway verification statement for each fuel 
pathway report is submitted to DEQ according to OAR 340- 272-0100. 
(A) Quarterly review of operational C I data is optional and may only be included as part of 
annual verification services if the fuel pathway holder submits quarterly data to DEQ. Quarterly review may only be conducted after the fuel pathway holder submits the report 
and attests that the state ments and information submitted are true, accurate, and complete. 
Quarterly review does not replace the requirements for the verification team to consider all 
quarterly data submitted during annual verification. Quarterly review must meet the 
requirements for verification under this division, but a verification statement and verification 
report are not submitted after quarterly review.  
(B) Facilities with California pathways recertified in Oregon. A responsible entity that must meet the requirements of this  division for the purposes of annual verification for any fuel 
production facility that is also subject to annual or deferred verification under California ARB’s Low Carbon Fuel Standard must submit its verification statement to DEQ within ten 
calendar  days of its comparable submittal to California ARB. If the responsible entity 
received an adverse verification statement, it must also submit the log of issues at the same 
time it submits the verification statement to DEQ.  
(i) For responsible entities that op erate facilities with one or more Oregon fuel pathway 
codes that are a recertification of California fuel pathway codes, the verification statement submitted to California ARB must be submitted to DEQ according to the verification 
deadline specified under OAR 340 -272-0100. 327 
 (ii) For responsible entities that operate facilities with one or more fuel pathway codes that 
are not a recertification of California fuel pathway codes, but have active California fuel 
pathway codes, the fuel pathway holder must ensure the following:  
(I) That when verification services are provided, the inputs and annual operational carbon 
intensity are confirmed under OR -GREET as required under OAR 340- 272-0450; and 
(II) That a fuel pathway verification statement for each annual fuel pa thway report is 
submitted to DEQ according to OAR 340- 272-0100. 
(C) If a fuel pathway holder is eligible for deferred verification under the California 
program, the fuel pathway holder must notify DEQ before April 30 of each year. If fuel 
from the facility  generates 6,000 or more total credits and deficits in Oregon, then the fuel 
pathway holder must engage the services of a verification body to perform verification and 
ensure a fuel pathway verification statement for each annual fuel pathway report is 
subm itted to DEQ according to OAR 340- 272-0100. 
(3) Annual verification of CFP quarterly reports.  
(a) Applicability. The following persons must meet the requirements of this division and engage the services of a verification body for the purposes of annual ver ification under this 
division, including required site visit(s), for CFP quarterly reports submitted under OAR 
chapter 340, division 253, except as otherwise provided under subsection (b):  
(A) Regulated parties, credit generators, and aggregators subject t o OAR 340 -253-0100. The 
scope of verification services is limited to the transaction types under paragraph (B), including associated corrections submitted into CFP quarterly and annual reports.  
(B) Except as provided in subsection (b), reporters of volumes  for any of the following 
transaction types must engage the services of a verification body to perform verification for 
the following transaction types:  
(i) All liquid fuels, including:  
(I) Production in Oregon;  
(II) Out of State Production for Import; 
(III) All Import transactions;  
(IV) Exports, other than Position Holder Sales for Export or export transactions reported on 
behalf of an unregistered exporter;  
(V) Gain of inventory;  
(VI) Loss of inventory;  328 
 (VII) Not used for transportation; and  
(VIII) Transactions used to claim exempt uses under OAR 340 -253-0250;  
(ii) NGV fueling; and  
(iii) Propane fueling.  
(b) Exemptions. The following are not subject to the requirements of this division:  
(A) Persons that do not generate 6,000 or more total cred its and deficits, in the aggregate, 
during the previous calendar year. For the purposes of this rule, any credits or deficits 
generated by persons that are related entities or share full or partial common ownership or 
operational control must be aggregated together to determine whether or not the exemption 
applies;  
(B) Persons reporting fuel transactions only in one or more of the transaction types: Export, 
Position Holder Sale for Export, Gain of inventory, Loss of inventory, and Not used for 
transportatio n, if all of the following conditions are met:  
(i) All such transactions do not generate 6,000 or more total credits and deficits, in the 
aggregate, during the previous calendar year;  
(ii) The person did not report any liquid fuel using the transaction types: Production in 
Oregon or Import into Oregon; and  
(iii) The person did not report any NGV fueling transactions.  
(c) Verification schedule. Responsible entities under subsection (a) required to engage the 
services of a verification body to perform annual verification of CFP quarterly reports must 
ensure a transactions data verification statement is submitted to DEQ according to OAR 
340-272-0100. 
(d) Optional quarterly review. Quarterly review of a CFP quarterly report is optional and does not replac e the requirements for the verification team to consider all quarterly data 
submitted during annual verification. Quarterly review must meet the requirements of this 
division, but a verification statement and verification report are not submitted after qua rterly 
review.  
(4) Annual verification of CFP annual project reports.  
(a) Applicability. The following persons must meet the requirements of this division and engage the services of a verification body for the purposes of annual verification, including 
required site visit(s), for CFP project reports required to be submitted as a condition of a fuel 
pathway’s continued approval under OAR 340- 253-0450(9)(e)(E):  329 
 (A) Project operators; and  
(B) Joint applicants.  
(b) Verification schedule. Responsible entities under subsection (a) required to engage the 
services of a verification body to perform verification of CFP project reports must ensure a project report verification statement is submitted annually to DEQ according to with OAR 340-272-0100. 
Statutory/Other Authority: ORS 468.020, 468A.266, 468A.271 & 468A.277 
Statutes/Other Implemented: ORS 468A.010, 468A.015 & 468A.265 through 468A.277 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0120  
 Requirements for Verification of GHG Reporting Program Emissions Data Reports Submitted under OAR Chapter 340, Division 215  
(1) Annual verification of GHG Reporting Program emissions data reports.  
(a) Applicability. The following persons must meet the requirements of this division and engage the services of a verification body for the purposes of annual verification of the entire emissions data report, including requi red site visit(s), for each separate emissions data 
report submitted under OAR chapter 340, division 215, except as otherwise provided under subsection (b): 
(A) A regulated entity that submits an emissions data report as described under OAR 340-
215-0044(1) that indicates emissions equaled or exceeded 25,000 metric tons of CO2e, excluding CO2 from biomass- derived fuels;  
(B) A third party that is not the Bonneville Power Administration (BPA) that registers and 
submits an emissions data report on behalf of a consumer- owned utility for emissions, data, 
and information submitted for each individual utility with emissions that equaled or 
exceeded 25,000 metric tons of CO2e, excluding CO2 from biomass- derived fuels and 
excluding emissions associated with preference power purchased from BPA;  
(C) A regulated entity that submitted an emissions data report that indicated emissions exceeded the threshold in paragraph (A) in the previous year, but that submits an emissions data report that indicates emissions are reduced  below that applicability threshold in the 
current reporting year;  
(D) All regulated entities subject to the Climate Protection Program requirements described under OAR chapter 340, division 271, regardless of emissions reported; and 330 
 (E) All regulated entities that are electric companies and electricity service suppliers as 
defined in ORS 757.600, regardless of emissions reported.  
(b) Exemptions. The following are not subject to the requirements of this division:  
(A) A regulated entity that is not an electric company and not subject to requirements under 
OAR chapter 340, division 215 and that submits an emissions data report as described under 
OAR 340 -215-0044(1) that indicates emissions were less than 25,000 metric tons of CO2e, 
excluding CO2 from biomass -derived fuels. For the purposes of this rule, any GHG 
emissions in emissions data reports as described under OAR 340 -215-0044(1)(c) submitted 
by fuel suppliers or in -state producers that are related entities or share full or partial common 
ownership or oper ational control must be aggregated together to determine whether or not 
the exemption applies;  
(B) An emissions data report as described under OAR 340- 215-0044(1)(a) that includes 
emissions data and information described in 40 C.F.R. part 98 subpart HH – M unicipal Solid 
Waste Landfills;  
(C) An emissions data report as described under OAR 340- 215-0044(1)(d) submitted by a 
natural gas supplier that is an interstate pipeline; and  
(D) Any emissions data report as described under OAR 340- 215-0044(1)(e) submitted  by 
Bonneville Power Administration (BPA) acting as a third -party reporter on behalf of any 
consumer -owned utility, as allowable under OAR 340- 215-0120(4).  
(c) Verification schedule. Responsible entities that are subject to the subsection (a) requirement to engage the services of a verification body to perform verification of 
emissions data reports must ensure a verification statement for each emissions data report is 
submitted to DEQ according to OAR 340- 272-0100. 
(A) These requirements are in addition to the requirements in 40 C.F.R. 98.3(f).  
(B) An asset -controlling supplier that submitted an emissions data report to DEQ as 
described under OAR 340- 215-0044(1)(f) that includes the same data and information 
reported to and verified under California ARB's Ma ndatory Reporting of Greenhouse Gas 
Emissions program may submit the same verification statement to DEQ. If an adverse 
verification statement is received, a current issues log must also be submitted to DEQ.  
(2) Cessation of verification requirement.  
(a) Re sponsible entities must have an emissions data report verified for the first year that the 
report indicates emissions are reduced below the applicability threshold defined in paragraph 
(1) 
(a)(A). An emissions data report is not subject to verification in any following year 
thereafter where emissions remain below the threshold.  331 
 (b) A responsible entity that meets the verification cessation requirements for two 
consecutive years must notify DEQ in writing in the second year that it is ceasing the verification requirement according to this paragraph and provide the reason(s) for cessation of verification. The notification must be submitted no later than the applicable reporting deadline under OAR chapter 340, division 215 for that year. 
(c) If in an y subsequent year after meeting verification cessation requirements an emissions 
data report meets the applicability requirements of subsection (1)(a), the responsible entity 
must have the emissions data report verified according to the requirements of this division, and verification must continue until the cessation requirement is met again.  
Statutory/Other Authority: ORS 468.020, 468A.050 & 468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0210  
 Applications and Criteria for DEQ Approval of Verification Bodies and Verifiers 
(1) Application for approval. A business entity or person seeking DEQ approval or renewal 
of DEQ approval to perform verification under this division as a verification body or verifier must submit an application to DEQ, on a form approved by DEQ, that includes the following information:  
(a) For verifier applications, a statement about whether the application is for approval as a verifier, a lead verifier, or a sector specific verifier;  
(b) A statement about which specific types of emissions data r eports submitted under OAR 
chapter 340, division 215, fuel pathway applications or specific types of CFP reports submitted under OAR chapter 340, division 253, or any combination therein, for which the applicant is seeking approval to perform verification; 
(c) Documentation demonstrating that the person or business entity holds the accreditation 
requirements described in section (2);  
(d) Additional information as required by sections (2) through (7), as applicable; 
(e) A certification that the person or bus iness entity agrees to comply with and be subject to 
the requirements of this division in relation to all verification work for responsible entities; 
and 
(f) Any other information requested by DEQ that DEQ determines is relevant to determine 
whether to approve the applicant.  332 
 (2) Application information and accreditation criteria for approval. Any person or business 
entity that wants to perform verification under this division must provide documentation that 
the person has met all the following criteria for approval, as applicable for the type of verification approval the applicant seeks:  
(a) The person or business entity holds an active accreditation under at least one of the following programs:  
(A) California ARB’s Low Carbon Fuel Standard program (LCFS); 
(B) California ARB's Mandatory Reporting of Greenhouse Gas Emissions program (MRR); 
(C) American National Standards Institute for Greenhouse Gas Validation/Verification 
Bodies (ANSI); or  
(D) A substantially equivalent program to one of the programs describe d in paragraphs (A), 
(B), or (C), and approved by DEQ;  
(b) To provide verification services for CFP reports or fuel pathway applications submitted 
under OAR chapter 340, division 253, the person or business entity must hold accreditation 
under California A RB’s LCFS, or a substantially equivalent program approved by DEQ;  
(c) To provide verification services for emissions data reports submitted under OAR chapter 
340, division 215, the person or business entity must hold accreditation under California 
ARB’s MR R, ANSI, or a substantially equivalent program approved by DEQ; and 
(d) All applicants must submit additional information in the application with details of 
accreditation and verification experience, including but not limited to, recognition or 
designation as a lead verifier or sector specific verifier, and sector specific accreditations by 
California ARB or organization -level sector accreditations by ANSI, as applicable, to 
demonstrate qualifications to provide verification services for specific types of e missions 
data reports submitted under OAR chapter 340, division 215, fuel pathway applications or 
specific types of CFP reports submitted under OAR chapter 340, division 253, or any combination therein.  
(3) Application information and criteria for approval for a verification body. To be approved 
as a verification body, the applicant must also submit the following information to DEQ in 
the application:  
(a) A list of all verification staff and subcontractors and a description of their duties and 
qualification s, including DEQ -approved verifiers on staff. The applicant must demonstrate 
staff qualifications by listing each individual’s education, experience, professional licenses, 
accreditations, status as verifier, lead verifier, or sector specific verifier, and  other relevant 
information. A verification body must employ or retain at least two lead verifiers, which may include retention as subcontractors. Any subcontractor used to meet minimum lead 
verifier requirements must be approved as a lead verifier by DEQ.  333 
 (b) A list of any judicial proceedings, enforcement actions, or administrative actions filed 
against the verification body within the previous five years, with an explanation as to the 
nature of the proceedings;  
(c) Documentation that demonstrates that th e body maintains a minimum of four million 
U.S. dollars of professional liability insurance;  
(d) Identification of services provided by the verification body, the industries that the body serves, and the locations where those services are provided;  
(e) A d etailed organizational chart that includes the verification body, its management 
structure, and any related entities; and  
(f) The verification body’s internal conflict of interest policy that identifies activities and 
limits to monetary or non -monetary gif ts that apply to all employees and procedures to 
monitor potential conflicts of interest.  
(4) Application information and criteria for approval as a verifier. To be approved as a verifier, the applicant must also submit the following information to DEQ in the application:  
(a) Applicants must indicate their employer or affiliated verification body on the application; 
and 
(b) Applicants must demonstrate verification qualifications by providing information on 
education, experience, professional licenses, accreditations, status as verifier, lead verifier, 
or sector specific verifier, and other relevant information or other personal development 
activities that demonstrate communication, technical, and analytical skills necessary to 
perform verifica tion. Evidence demonstrating necessary skills may include, but is not 
limited to:  
(A) A bachelor’s level college degree or equivalent in engineering, science, technology, 
business, statistics, mathematics, environmental policy, economics, or financial audi ting; or  
(B) Work experience in a professional role involved in emissions data management, 
emissions technology, emissions inventories, environmental auditing, financial auditing, life 
cycle analysis, transportation fuel production, or other technical skil ls necessary to perform 
verification.  
(5) Application information and criteria for approval as a lead verifier for the GHG Reporting Program. To be approved as a lead verifier for verification of emissions data 
reports submitted under OAR chapter 340, division 215, in addition to submitting 
information as required by section (4), the applicant must also submit documentation to DEQ in the application indicating that at least one of the following qualifications are met:  
(a) The verifier is accredited as a lead verifier by California ARB for the Mandatory 
Reporting of Greenhouse Gas Emissions program;  334 
 (b) The verifier is designated as a lead verifier by the ANSI- accredited verification body 
with which it is employed or affiliated; or  
(c) The verifier is des ignated as a lead verifier by a substantially equivalent program to one 
of the programs described in subsection (a) or (b), and that is approved by DEQ.  
(6) Application information and criteria for approval as a lead verifier for the CFP. To be 
approved as  a lead verifier for verification of CFP reports or fuel pathway applications 
submitted under OAR chapter 340, division 253, in addition to submitting information as 
required by section (4), the applicant must also submit the following documentation to DEQ  
in the application:  
(a) Indication that the applicant is accredited as a lead verifier by California ARB for the Low Carbon Fuel Standard program, or is designated as a lead verifier by a substantially 
equivalent program approved by DEQ;  
(b) To be approve d as a lead verifier for verification of CFP fuel pathway applications or 
annual fuel pathway reports, the applicant must also submit documentation to DEQ in the 
application that demonstrates experience in alternative fuel production technology and 
process engineering; and  
(c) To be approved as a lead verifier for verification of CFP project reports and quarterly 
reports submitted by producers and importers of gasoline or diesel, the applicant must 
submit documentation to DEQ in the application that demonst rates experience with oil and 
gas systems. This evidence may include accreditation as an oil and gas systems sector 
specific verifier.  
(7) Application information and criteria for approval as a sector specific verifier. To be 
approved as a sector specific verifier, in addition to submitting information as required by 
section (4), the applicant must also submit documentation to DEQ in the application 
demonstrating at least two years of professional experience related to the sector in which the 
individual is seeking approval.  
(8) Verification training and exam requirements.  
(a) To be approved by DEQ, applicants must take DEQ -approved general verification 
training, sector specific verification training, CFP specific verification training, and GHG Reporting Program specific verification training, as made available and deemed applicable by DEQ based on the application submitted to DEQ and for the type of approval the 
applicant has requested.  
(b) Applicants must receive a passing score of greater than an unweighted  70 percent on an 
exit examination.  
(A) If the applicant does not pass the exam after the training, the applicant may retake the 
exam a second time.  335 
 (B) Only one retake of the examination is allowed before the applicant must retake the 
applicable training.  
Statutory/Other Authority: ORS 468.020, 468A.050, 468A.266, 468A.271, 468A.277 & 468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050, 468A.265 through 468A.277 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0220  
 DEQ Review and Approval of Verification Bodies and Verifiers  
(1) DEQ application review and approval process for ve rification bodies and verifiers.  
(a) After receipt of an application under OAR 340 -272- 0210, DEQ will inform the applicant 
either that a submitted application is complete or that additional specific information is required to make the application complete.  If the application is incomplete, DEQ will not 
consider the application further until the applicant provides the additional information requested by DEQ. 
(b) DEQ will review submitted applications to prescreen and ensure all requirements are 
met. DEQ will notify an applicant in writing which verification training(s) and exam(s) are required to be completed according to OAR 340-272-0210(8). An applicant may choose to take trainings and exams in addition to those required by DEQ. 
(c) DEQ will not consider or issue final approval until DEQ finds an application for 
approval as a verification body or verifier is complete and meets all applicable requirements under OAR 340-272-0210(1) and all required verification training(s) and exam(s), as deemed applicable by DEQ under subsection (b), have been completed according to OAR 340-272-0210(8). 
(d) Following completion of the application process and all applicable training and 
examination requirements, DEQ will notify the applicant in writing if approval has been granted or denied. 
(A) DEQ may issue approval to verification bodies, verifiers, lead verifiers, and sector 
specific verifiers that apply and meet the criteria under OAR 340 -272-0210 and successfully 
complete verification training(s) and exam(s) as require d under OAR 340-272-0210(8). 
(B) DEQ approval will be limited to certain report types, data types, sources of emissions, or sectors, according to the information in the application and the qualifications of the applicant, and based on DEQ’s determination of whether the applicant demonstrates, to 336 
 DEQ’s satisfaction, sufficient knowledge of the relevant methods and requirements in this 
division, OAR chapter 340, division 215, and OAR chapter 340, division 253, as applicable.  
(C) DEQ will maintain a current list of approved verification bodies, verifiers, lead verifiers, 
and sector specific verifiers on DEQ’s website.  
(e) DEQ approval is valid for a period of three years from the date the approval is issued by 
DEQ. The applicant may re -apply for approval as a verification body, verifier, lead verifier, 
or sector specific verifier following the same application procedures according to OAR 340-
272-0210 and must satisfy all DEQ training and examination requirements applicable at the 
time of re -application.  
(2) Requirements to maintain DEQ approval.  
(a) Except as provided under subsection (c) below, a verification body, verifier, lead verifier, 
or sector specific verifier must  notify DEQ within 30 calendar days of when it no longer 
meets the requirements for approval under OAR 340- 272-0210, as applicable.  
(b) A verification body must notify DEQ of any verifier staffing changes within 30 calendar days of any such change as these changes are considered an amendment to the verification 
body’s approval.  
(c) DEQ must b e notified immediately if a verification body or verifier loses or withdraws 
from accreditation under any program specified or approved under OAR 340- 272-
0210(2)(a).  
(d) Within 20 calendar days of being notified of any nonconformance in another voluntary 
or mandatory greenhouse gas emissions reporting program or fuels program, a DEQ -
approved verification body or verifier must provide written notice to DEQ of the non -
conformance, including a copy of any written notification of nonconformance from the agency or body that administers the program, and information about any corrective actions 
taken by the verification body or verifier. That notification must include reasons for the 
corrective action and the type of corrective action. The verification body or veri fier must 
provide additional information to DEQ upon request.  
(e) Verification bodies and verifiers must provide in a reasonably timely manner any and all information that DEQ reasonably requires for the purpose of evaluating continued 
compliance with the requirements of this division, including the criteria for approval.  
(3) Modification, suspension, or revocation of DEQ approval.  
(a) DEQ may modify, suspend, or revoke an approval to perform verification if a verification body or verifier:  
(A) Fraudulently  obtained or attempted to obtain accreditation under any program specified 
under OAR 340- 272-0210(2)(a);  337 
 (B) Fraudulently obtained or attempted to obtain approval from DEQ under this division;  
(C) Failed at any time to satisfy the eligibility criteria and requirements specified under 
OAR 340 -272-0210; 
(D) Does not satisfy the requirements to maintain approval according to section (2); 
(E) Provided verification services that failed to meet the requirements under OAR 340 -272-
0300(1) and (3);  
(F) Violated the conflict of interest requirements under OAR 340 -272-0500; or 
(G) Knowingly or recklessly submitted false or inaccurate information or verification 
statement(s) to DEQ.  
(b) A verifier or verification body that is subject to a DEQ action to modify, suspend, or revoke an approval to perform verification may contest DEQ’s action by providing DEQ with a written request for a hearing within 20 calendar days of being notified of DEQ’s action. 
(A) The hearing will be conducted as a contested case under ORS 183.413 through 183.470 
and OAR chapter 340, division 11. 
(B) Any DEQ action taken in subsection (a) will remain in place pending the outcome of the 
contested case.  
(c) A verification body or verifier that has had approval to perform verification revoked may re-apply according to OAR 340-272-0210 after the applicant demonstrates to DEQ that the 
cause of the revocation has been resolved.  
(4) Voluntary withdrawal from DEQ approval. An approved verification body or verifier may request to voluntarily withdraw its approval by providing a written notice to DEQ requesting such withdrawal. 
Statutory/Other Authority: ORS 468.020, 468A.050, 468A.266, 468A.271, 468A.277 & 
468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050, 468A.265 through 468A.277 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0300  
 Requirements for Verification Services  338 
 (1) Verification services provided and completed must meet the requirements of OAR 340 -
272-0405 through OAR 340- 272-0495, as applicable to the type of CFP report or fuel 
pathway application submitted under OAR chapter 340, division 253 or emissions data 
report  submitted under OAR chapter 340, division 215. 
(2) Requirements for responsible entities.  
(a) Responsible entities must engage the services of a verification body that meets the requirements and criteria under OAR 340- 272-0210 and has been approved by DEQ  under 
OAR 340 -272-0220 to perform verification under this division for the type of verification 
services applicable to the responsible entity.  
(b) A responsible entity that has been notified by DEQ or by it’s  verification body that the 
verification body’s  DEQ approval has been suspended or revoked, must engage the services 
of a different DEQ -approved verification body to perform verification.  
(c) Each responsible entity must ensure that the verification services provided on its behalf 
meet the requirements  of this division.  
(d) Records retention and availability requirements.  
(A) Responsible entities must retain records necessary for completing verification services 
and records requested by the verification team according to the recordkeeping requirements 
of OAR chapter 340, division 215 or OAR chapter 340, division 253, as applicable.  
(B) Responsible entities must retain for verification purposes and make available to the 
verification team the following: 
(i) All information and documentation used to calcula te and report emissions, fuel 
quantities, and fuels and electricity transactions;  
(ii) All data and information required by or submitted under OAR chapter 340, division 215 
or OAR chapter 340, division 253; and 
(iii) Other data and information as necessary  in order for verification services to be 
completed.  
(C) Responsible entities must maintain documentation to support any revisions made to the 
initial report or fuel pathway application submitted to DEQ as a result of verification. Documentation for all su bmittals must be retained by the responsible entity in paper or 
electronic format for a period of at least seven years.  
(3) Requirements for verification bodies and verifiers.  
(a) Eligibility to perform verification.  339 
 (A) A verification body or verifier mus t meet the requirements and criteria of OAR 340 -
272-0210 and must have DEQ approval under OAR 340- 272-0220 to be eligible to perform 
verification under this division.  
(B) Verifiers must be employed by, or contracted with a DEQ -approved verification body in 
order to provide verification services under this division.  
(b) Subcontracting.  
(A) Any verification body that elects to subcontract a portion of verification services must 
meet the following requirements:  
(i) The verification body must assume full respon sibility for verification services provided 
by subcontractor verifiers;  
(ii) A verification body that engages a subcontractor shall be responsible for demonstrating 
an acceptable level of conflict of interest, as provided in OAR 340- 272-0500, between its 
subcontractor and the reporting entity for which it will provide verification services;  
(iii) A verification body that engages a subcontractor is responsible for ensuring the subcontractor shall not further subcontract or outsource verification services for a reporting 
entity.  
(B) All subcontractors must apply for and meet the requirements and criteria for DEQ 
approval under OAR 340- 272-0210 and be approved by DEQ under OAR 340- 272-0220 in 
order to provide the verification services for which the subcontracto r has been engaged by 
the verification body. 
(c) If a verification body receives a final determination from DEQ under OAR 340 -272-
0220(3) that is described in paragraphs (A) through (C) below , then the verification body 
must provide written notification all responsible entities with which it is currently engaged to provide verification services or that have received verification services from it within the past six months of DEQ’s final determination within ten calendar days of receiving such final determination, and the verification body may not continue to provide verification 
services until the verification body receives DEQ approval to recommence such services 
under OAR 340- 272-0220:  
(A) Any  modification relevant to the verification services provided;  
(B) Suspension of DEQ approval of the verification body or any of its verifiers, lead 
verifiers, sector specific verifiers, or subcontractors; or  
(C) Revocation of DEQ approval of the verificati on body or any of its verifiers, lead 
verifiers, sector specific verifiers, or subcontractors.  
(d) Records retention.  340 
 (A) Verification bodies that provide verification services under this division must retain 
documentation relating to verification in paper or electronic format for a period of at least seven years following the submission of each verification statement.  
(B) The documentation must allow for a transparent review of how a verification body reached its conclusion in the verification statement, i ncluding independent review. At a 
minimum, the documentation retained must include: 
(i) Report(s) or fuel pathway application(s) submitted by the responsible entity to DEQ for 
which verification services are being provided;  
(ii) Contracts for verification;  
(iii) Verification plan(s);  
(iv) Sampling plan(s);  
(v) Verification report(s); 
(vi) Verification statement(s); and  
(vii) Any other documentation, calculations, and verification notes developed as part of 
providing and completing verification services.  
Statutory/Other Authority: ORS 468.020, 468A.050, 468A.266, 468A.271, 468A.277 & 
468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050, 468A.265 through 468A.277 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
 
340-272-0405  
 
Notice of Verification Services  
(1) Before a verification body commences any verification services for the responsible entity, the responsible entity must ensure the verification body submits a notice of verification services to DEQ that meets the requirements of this rule. The notice of verification services must be submitted after DEQ has provided a determination that the potential for a conflict of interest is acceptable as specified under OAR 340 -272-0500(7) and 
that verification services may proceed.  341 
 (a) If the conflict of interest evaluation submitted by the responsible entity and the notice of 
verification services submitted by the verification body are submitted at the same time, 
verification servic es may not begin until DEQ has determined the potential for conflict of 
interest is acceptable in writing.  
(b) Except as provided in subsection (a), the verification body may begin verification services for the responsible entity after the notice of verifi cation services is received by 
DEQ, but must allow a minimum of 14 calendar days advance notice of a site visit unless an 
earlier date is approved by DEQ. The site visit may not take place prior to the applicable 
regulatory deadline for the reporting type to be verified, except under the conditions listed in 
OAR 340 -272-0420(2)(a).  
(2) The verification notice must include the following information:  
(a) A list of the staff designated to provide verification services as a verification team, 
including the name s of each individual, the lead verifier, and all subcontractors, and a 
description of the roles and responsibilities each member will have during verification. The 
independent reviewer must also be listed separately. The list must include any verifiers in 
training who will participate on the verification team.  
(b) Documentation that the verification team has the skills required to provide verification 
services for the responsible entity and type of report or fuel pathway application requiring 
verification. When required by DEQ, the notice must include a demonstration that the 
verification team includes at least one individual approved by DEQ as a sector specific 
verifier that is not also the independent reviewer, but may be the lead verifier; and  
(c) General information about the responsible entity, including the following, as applicable:  
(A) Name and list of facilities and other locations that will be subject to verification, and 
contact, address, telephone number, and e -mail address for each facility ; 
(B) The industry sector, North American Industry Classification System (NAICS) code, or source identification number for reporting facilities under OAR chapter 340, division 215.;  
(C) The CFP ID(s) for the responsible entity under OAR chapter 340, division 253.;  
(D) The date(s) of the site visit if full verification is being provided and if required under 
OAR 340 -272-0420, with physical address and contact information.; and  
(E) A brief description of expected verification services to be provided, includin g expected 
completion date and whether quarterly review is planned in the context of an annual verification requirement.  
(3) The responsible entity must ensure the verification body submits an updated notice of verification services to DEQ immediately if a ny of the information under section (2) 
changes after the notice of verification services is submitted to DEQ. When an updated 342 
 notice of verification services is submitted to DEQ, the conflict of interest must be 
reevaluated and information must be resubmitted according to OAR 240-272-0500. Verification services must be suspended until DEQ approves the resubmitted conflict of interest evaluation information in writing.  
Statutory/Other Authority: ORS 468.020, 468A.050, 468A.266, 468A.271, 468A.277 & 468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050, 468A.265 through 468A.277 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0415  
 Verification Plan  
(1) Verification services must include the development of a verification plan that meets the requirements of this rule.  
(2) All verification plans must contain information on the timing of verification services, including: 
(a) Dates of proposed meetings and interviews with  with  personnel of the responsible entity;  
(b) Dates of proposed site visits;  
(c) Types of proposed document and data reviews and, for CFP reports submitted under OAR chapter 340, division 253, how quarterly review is planned in the context of an annual verification requirement, as applicable; and  
(d) Expected date for completing verification services.  
(3) In addition to the information required under section (2), verification plans for 
verification services provided for CFP reports and fuel pathways applications submitted under OAR chapter 340, division 253 must also include the following information from the responsible entity:  
(a) Information to allow the verific ation team to develop an understanding of facility or 
entity boundaries, operations, accounting practices, type of CFP report(s) the person is responsible for, CFP regulatory sections the responsible entity is subject to, other renewable or low carbon fuel s markets the responsible entity participates in, and other mandatory or 
voluntary auditing programs the responsible entity is subject to, as applicable; 
(b) Information regarding the training or qualifications of personnel involved in developing the repor t(s) or fuel pathway application(s);  343 
 (c) Description of the specific methodologies used to quantify and report data, including but 
not limited to calibration procedures and logs for measurement devices capturing site-specific data;  
(d) Information about th e data management system and accounting procedures used to 
capture and track data for each fuel pathway application and each type of CFP report as needed to develop the verification plan; 
(e) Information about the entities in the supply chain upstream and downstream of the fuel 
producer that contribute to site-specific CI data, including a list of feedstock suppliers and contact names with physical addresses;  
(f) Evidence demonstrating that any joint applicants are being separately verified; and  
(g) Previous CFP verification reports, as applicable, and other audit reports including reports from production or management system certifications and internal audits.  
(4) In addition to the information required under section (2), verification plans for verification services provided for GHG Reporting Program emissions data reports submitted under OAR chapter 340, division 215 must also include the following information from the responsible entity:  
(a) Information to allow the verification team to develop a ge neral understanding of facility 
or entity boundaries, operations, emissions sources, and electricity or fuel transactions, as applicable; 
(b) Information regarding the training or qualifications of personnel involved in developing 
the emissions data report ; 
(c) Description of the specific methodologies used to quantify and report greenhouse gas emissions, electricity and fuel transactions, and associated data as needed to develop the verification plan;  
(d) Information about the data management system used t o track greenhouse gas emissions, 
electricity and fuel transactions, and associated data as needed to develop the verification plan; and 
(e) Previous GHG Reporting Program verification reports. 
Statutory/Other Authority: ORS 468.020, 468A.050, 468A.266, 468A.271, 468A.277 & 
468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050, 468A.265 through 468A.277 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 344 
  
340-272-0450  
 
Material Misstatement Assessments for CFP Fuel Pathways and Quarterly Fuel Transactions Submitted under OAR Chapter 340, Division 253  
(1) The verification team must conduct separate assessments of material misstatement on each calculated operational CI value and each quarterly fuel transaction quantity for each fuel pathway code (expressed in units from the applicable sections of OAR  chapter  340 
division 253). Material missta tement assessments are not conducted for quarterly review.  
(2) Assessments of material misstatement of carbon intensity must meet all the requirements of this section.  
(a) Each fuel pathway CI is subject to data checks under OAR 340- 272-0430 and must be 
assessed separately for material misstatement of its carbon intensity. The inputs and annual operational carbon intensity for fuel pathway codes that are not a recertification of a California Fuel Pathway Code(s) but have an active California Fuel Pathway Co de(s) must 
be assessed.  
(b) Material misstatement of carbon intensity includes any discrepancy as described in paragraph (A) of this subsection, omission as described in paragraph (B) of this subsection, or misreporting as described in paragraph (C) of thi s subsection, or aggregation of the three, 
identified in the course of verification services that leads a verification team to believe that the reported operational CI (grams of carbon dioxide equivalent per megajoule or gCO2e/MJ) in a CFP fuel pathway app lication or report contains one or more errors that, 
individually or collectively, result in an overstatement or understatement more than five 
percent of the reported operational CI, or 2 gCO2e/MJ, whichever absolute value expressed in gCO2e/MJ is greater.  
(A) Discrepancies include any differences between the reported site- specific CI inputs and 
the verifier’s calculated site -specific CI inputs subject to data checks under OAR 340 -272-
0430. 
(B) Omissions include any site -specific CI inputs or associated source data the verifier 
concludes must be part of a fuel pathway application or report but were not included.  
(C) Misreporting includes duplicate, incomplete, or other CI input data the verifier 
concludes should or should not be part of a fuel pathway applic ation or report.  
(c) One or more material misstatements of carbon intensity will result in a finding of material misstatement for the fuel pathway application or report.  
(d) A controlled version of the Simplified CI Calculator for Tier 1 pathways, a DEQ -
approved OR -GREET for Tier 2 pathways, or another substantially equivalent model 
approved by DEQ for the specific fuel pathway application under OAR 340- 253-0400(1), as 345 
 applicable, must be populated to assess whether a fuel pathway application or report 
contains a material misstatement of carbon intensity.  
(e) The following equations for percent error, relative error threshold, and absolute error 
threshold must be used to determine whether any reported operational CI value contains a 
material misstatement of carbon intensity and must be included in the final verification 
report according to OAR 340- 272-0495. 
Percent error (CI) = (∑ | Difference in CI | ÷ | Reported Operational CI |) × 100%  
Relative error threshold (CI) = | Difference in CI | ≥ 0.05 × |Reported Operational CI Value|  
Absolute error threshold (CI) = | Difference in CI | ≥ 2 g CO2e/MJ  
(3) Assessments of material misstatement of quarterly fuel quantity for each fuel pathway code must meet all the requirements of this section.  
(a) Each aggregated quarterly fuel quantity for each fuel pathway code is subject to data 
checks under OAR 340- 272-0430 and must be assessed separately for material misstatement 
of quarterly fuel quantity. 
(b) Material misstatement of quarterly fuel quantity includ es any discrepancy as described in 
paragraph (A) of this subsection, omission as described in paragraph (B) of this subsection, 
or misreporting as described in paragraph (C) of this subsection, or aggregation of the three, 
identified in the course of verif ication services that leads a verification team to believe that 
the reported fuel quantity for each fuel pathway code per quarter in a CFP quarterly report 
contains one or more errors that, individually or collectively, result in an overstatement or 
unders tatement greater than five percent.  
(A) Discrepancies include any differences between the fuel quantity for the fuel pathway 
code reported and the verifier’s review of calculation of fuel quantity subject to data checks 
under OAR 340- 272-0430. 
(B) Omission s include any fuel quantity the verifier concludes must be part of a quarterly 
report but was not included. 
(C) Misreporting includes duplicate, incomplete, or other fuel quantity data the verifier 
concludes should or should not be part of a quarterly repo rt. 
(c) One or more material misstatements of quarterly fuel quantity will result in a finding of 
material misstatement for the annual verification of the quarterly fuel quantity for each fuel 
pathway code. 
(d) The following equation for percent error must be used to determine whether any 
quarterly fuel quantity for each fuel pathway code contains a material misstatement of 346 
 quarterly fuel quantity and must be included in the final verification report according to 
OAR 340 -272-0495. 
Percent error (fuel quantity) =  
(∑(Discrepancies + Omissions + Misreporting) ÷ Reported quarterly fuel transaction quantity for fuel pathway code) × 100%  
(e) When evaluating material misstatement of quarterly fuel quantity, correctly substituted missing data must be deemed to be accurate, regardless of the amount of missing data. 
Statutory/Other Authority: ORS 468.020, 468A.266, 468A.271 & 468A.277 
Statutes/Other Implemented: ORS 468A.010, 468A.015 & 468A.265 through 468A.277 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0450  
 Material Misstatement Assessments for CFP Fuel Pathways and Quarterly Fuel Transactions Submitted under OAR Chapter 340, Division 253 
(1) The verification team must conduct separate assessments of material misstatement on 
each calculated operational CI value and each quarterly fuel transaction quantity for each fuel pathway code (expressed in units from the applicable sections of OAR  chapter  340 
division 253). Material misstatement assessments are not conducted for quarterly review.  
(2) Assessments of material misstatement of carbon intensity must meet all the requirements of this section.  
(a) Each fuel  pathway CI is subject to data checks under OAR 340-272-0430 and must be 
assessed separately for material misstatement of its carbon intensity. The inputs and annual operational carbon intensity for fuel pathway codes that are not a recertification of a 
California Fuel Pathway Code(s) but have an active California Fuel Pathway Code(s) must 
be assessed.  
(b) Material misstatement of carbon intensity includes any discrepancy as described in 
paragraph (A) of this subsection, omission as described in paragraph (B) of this subsection, or misreporting as described in paragraph (C) of this subsection, or aggregation of the three, identified in the course of verification services that leads a verification team to believe that the reported operational CI (grams of car bon dioxide equivalent per megajoule or 
gCO2e/MJ) in a CFP fuel pathway application or report contains one or more errors that, individually or collectively, result in an overstatement or understatement more than five percent of the reported operational CI, or 2 gCO2e/MJ, whichever absolute value expressed in gCO2e/MJ is greater.  347 
 (A) Discrepancies include any differences between the reported site- specific CI inputs and 
the verifier’s calculated site -specific CI inputs subject to data checks under OAR 340 -272-
0430. 
(B) Omissions include any site -specific CI inputs or associated source data the verifier 
concludes must be part of a fuel pathway application or report, but were not included.  
(C) Misreporting includes duplicate, incomplete, or other CI input data the verifier 
concludes should or should not be part of a fuel pathway application or report.  
(c) One or more material misstatements of carbon intensity will result in a finding of 
material misstatement for the fuel pathway application or report.  
(d) A cont rolled version of the Simplified CI Calculator for Tier 1 pathways, a DEQ -
approved OR -GREET for Tier 2 pathways, or another substantially equivalent model 
approved by DEQ for the specific fuel pathway application under OAR 340- 253-0400(1), as 
applicable, m ust be populated to assess whether a fuel pathway application or report 
contains a material misstatement of carbon intensity.  
(e) The following equations for percent error, relative error threshold, and absolute error threshold must be used to determine whether any reported operational CI value contains a 
material misstatement of carbon intensity and must be included in the final verification 
report according to OAR 340- 272-0495. 
Percent error (CI) = (∑ | Difference in CI | ÷ | Reported Operational CI |) × 100%  
Relative error threshold (CI) = | Difference in CI | ≥ 0.05 × |Reported Operational CI Value|  
Absolute error threshold (CI) = | Difference in CI | ≥ 2 g CO2e/MJ  
(3) Assessments of material misstatement of quarterly fuel quantity for each fuel pathway 
code must meet all the requirements of this section.  
(a) Each aggregated quarterly fuel quantity for each fuel pathway code is subject to data checks under OAR 340- 272-0430 and must be assessed separately for material misstatement 
of quarterly fuel quantity.  
(b) Material misstatement of quarterly fuel quantity includes any discrepancy as described in paragraph (A) of this subsection, omission as described in paragraph (B) of this subsection, or misreporting as described in paragraph (C) of this subsection, or aggregation of the three, 
identified in the course of verification services that leads a verification team to believe that 
the reported fuel quantity for each fuel pathway code per quarter in a CFP quarterly report 
contains one or more error s that, individually or collectively, result in an overstatement or 
understatement greater than five percent.  348 
 (A) Discrepancies include any differences between the fuel quantity for the fuel pathway 
code reported and the verifier’s review of calculation of fuel quantity subject to data checks under OAR 340-272-0430. 
(B) Omissions include any fuel quantity the verifier concludes must be part of a quarterly 
report, but was not included. 
(C) Misreporting includes duplicate, incomplete, or other fuel quantity data the verifier 
concludes should or should not be part of a quarterly report. 
(c) One or more material misstatements of quarterly fuel quantity will result in a finding of 
material misstatement for the annual verification of the quarterly fuel quantity fo r each fuel 
pathway code. 
(d) The following equation for percent error must be used to determine whether any 
quarterly fuel quantity for each fuel pathway code contains a material misstatement of quarterly fuel quantity and must be included in the final ve rification report according to 
OAR 340 -272-0495. 
Percent error (fuel quantity) =  
(∑(Discrepancies + Omissions + Misreporting) ÷ Reported quarterly fuel transaction quantity for fuel pathway code) × 100%  
(e) When evaluating material misstatement of quarterly fuel quantity, correctly substituted missing data must be deemed to be accurate, regardless of the amount of missing data. 
Statutory/Other Authority: ORS 468.020, 468A.266, 468A.271 & 468A.277 
Statutes/Other Implemented: ORS 468A.010, 468A.015 & 468A.265 through 468A.277 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0455  
 Material Misstatement Assessments for CFP Project Reports Submitted under OAR Chapter 340, Division 253 
(1) The verification team must conduct separate assessments of material misstatement of 
project data for each CFP project report submitted under OAR chapter 340, division 253. The assessments of material misstatement of project data must meet all of the requirements of this rule.  
(2) Material misstatement of project data includes any discrepancy as described in subsection (a) of this section, omission as described  in subsection (b) of this section, or 
misreporting as described in subsection (c) of this section, or aggregation of the three, 349 
 identified in the course of verification services that leads a verification team to believe that 
the project report contains one or more errors that, individually or collectively, result in an overstatement greater than five percent of the responsible entity’s reported emissions reductions. 
(a) Discrepancies include any differences between the reported emissions reductions and the 
verifier’s calculated value based on data checks under OAR 340 -272-0430. 
(b) Omissions include any emissions, excluding any emissions reductions, the verifier concludes must be part of a project report, but were not included. 
(c) Misreporting includes dup licate, incomplete, or other emissions or emissions reductions 
data the verifier concludes should or should not be part of a project report. (3) A material misstatement of project data is not found when discrepancies, omissions, or 
misreporting, or an aggregation of the three, result in an understatement of reported emissions reductions in the project report. 
(4) The following equation for percent error must be used to determine whether the 
greenhouse gas reductions quantified and re ported in the project report contain a material 
misstatement of project data and must be included in the final verification report according to OAR 340 -272-0495. 
Percent error (project data) = (∑(Discrepancies  + Omissions + Misreporting) ÷ Reported 
emissio ns reduction) × 100%  
(5) Any discrepancies, omissions, or misreporting found must include the positive or negative impact on the reported emissions reductions when entered in the equation in section (4). 
(6) When evaluating material misstatement of project data, correctly substituted missing data must be deemed to be accurate, regardless of the amount of missing data.  
Statutory/Other Authority: ORS 468.020, 468A.266, 468A.271 & 468A.277 
Statutes/Other Implemented: ORS 468A.010, 468A.015 & 468A.265 through 468A.277 
History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0460  
 Material Misstatement Assessments for Emi ssions Data Submitted under OAR 
Chapter 340, Division 215 
(1) The verification team must conduct separate assessments for material misstatement of 
total reported emissions for each emissions data report submitted under OAR chapter 340, 350 
 division 215. The assessments of material misstatement of emissions data must meet all of 
the requirements of this rule.  
(2) Material misstatement of emissions data includes any discrepancy as described in 
subsection  
(a) of this section, omission as described in subsection (b) of this section, or misreporting as 
described in subsection (c) of this section, or aggregation of the three, identified in the course of verification services that leads a verification team to believe that the total reported emissions (metric tons of CO2e) in a GHG Reporting Program emissions data report contains errors greater than five percent.  
(a) Discrepancies include any differences between the reported emissions and the verifier’s review of emissions for a data source subject to data checks under OAR 340-272-0430. 
(b) Omissions include any emissions the verifier concludes must be part of an emissions 
data report, but were not included. 
(c) Misreporting includes duplicate, incomplete, or other emissions the verifier concludes 
should or should not be part of an emissions data report. 
(3) Each emissions data report is subject to data checks under OAR 340-272-0430 and must 
be assessed separately for material misstatement of emissions data.  
(4) The following equation for percent error must be used to determine whether the total reported emissions in an emission s data report contain a material misstatement of emissions 
data and must be included in the final verification report according to OAR 340-272-0495. 
Percent error (emissions) = (∑(Discrepancies + Omissions + Misreporting) ÷ Total reported 
emissions) × 100%  
(5) When evaluating material misstatement, correctly substituted missing data must be deemed to be accurate, regardless of the amount of missing data.  
Statutory/Other Authority: ORS 468.020, 468A.050 & 468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0470  
 Review of Operations and Emissions for Emissions Data Reports Submitted under OAR Chapter 340, Division 215  351 
 (1) Verification services for verification of GHG Reporting Program emissions data reports 
submitted under OAR chapter 340, division 215 must include review t hat meets all of the 
requirements of this rule.  
(2) Facility operations must be reviewed to identify applicable greenhouse gas emissions sources, and the review must:  
(a) Be conducted by the verification team;  
(b) Include a review of the emissions inventory and each type of emissions source to ensure 
that all sources specified under OAR 340- 215-0030 are included in the emissions data 
report, as applicable; and  
(c) Review the reported current primary and any secondary (if reported) NAICS codes to 
ensure they  accurately represent the NAICS -associated activities for the facility. The review 
of these NAICS codes and associated activities must be documented in the sampling plan. If the reported NAICS code(s) is determined to be inaccurate and the responsible enti ty does 
not submit a revised emissions data report to correct the current NAICS code(s), the result 
will be an adverse verification statement.  
(3) Electricity transaction records must be reviewed, including but not limited to written 
power contracts and an y other applicable information required to confirm reported 
electricity procurements and deliveries. Documentation retained by the responsible entity to support claims of specified sources of electricity, as required under OAR 340- 215-0042(6) 
must be revie wed to ensure it is sufficient to support the claim. Verifiers must use 
professional judgment to determine whether the records retained authenticate the claim.  
(4) Information regarding increases or decreases in emissions, as required under OAR 340 -
215-0044(4) must be reviewed to ensure it is reported in conformance with the requirements 
of that division, however, the narrative description itself is not subject to the verification requirements of this division.  
(5) Supporting documentation retained by the r esponsible entity to authenticate the purchase 
of gaseous or liquid biomass -derived fuels or hydrogen, as required under OAR 340 -215-
0042(4) must be reviewed to ensure it is sufficient to authenticate the purchase. Verifiers must use professional judgment to determine whether the records retained authenticate the 
purchase and fuel type.  
(a) For biomethane and hydrogen reported under OAR chapter 340, division 215 the verifier must:  
(A) Examine all applicable nomination, invoice, scheduling, allocation, trans portation, 
storage, in- kind fuel purchase and balancing reports from the producer to the reporting entity 
and have reasonable assurance that the reporting entity is contractually receiving the identified fuel;  352 
 (B) Determine that the biomethane met pipeline  quality standards; 
(C) Review documentation that confirms the gas was contractually delivered to Oregon; 
(D) Review attestations regarding environmental attributes confirming that no other party 
can make a claim on attributes that are being reported under OAR chapter 340, division 215;  
(E) If book and claim accounting methodology was used to report contractual deliveries of 
gas, the verifier must also review documentation to confirm the reported quantity of gas was injected into a natural ga s pipeline network connected to Oregon within the emissions data 
year; and  
(F) If an electronic tracking system approved by DEQ is used for book and claim, the verifier must review records from the tracking system showing the retirement of all environmental attributes of that fuel that are being reported under division 215. 
Statutory/Other Authority: ORS 468.020, 468A.050 & 468A.280 
Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020
 
 
340-272-0495  
 Independent Review and Completion of Verification Services  
(1) Verification statement. The verification  body must complete a verification statement(s) 
upon completion of verification services, provide its statement to the responsible entity, and submit its statement to DEQ by the applicable verification deadline specified under OAR 340-272- 0100(3). Each pos itive, qualified positive, or adverse verification statement must 
describe the findings of the verification; and  
(a) For every qualified positive verification statement, the verification body must explain the 
nonconformances contained within the report or fuel pathway application and cite the 
sections(s) in OAR chapter 340, division 215, or OAR chapter 340, division 253, as applicable, that corresponds to the nonconformance and why the nonconformances do not result in a material misstatement; and  
(b) For every adverse verification statement, the verification body must explain all nonconformances or material misstatements leading to the adverse verification statement and cite the sections(s) in OAR chapter 340, division 215, or OAR chapter 340, division 253, as applicable, that corresponds to the nonconformance(s) and material misstatement(s).  
(2) Independent review. The verification body must have the verification services and findings of the verification team independently reviewed by an independent reviewer before each verification statement is completed. The independent reviewer must be employed by 353 
 the verification body and must be a lead verifier not involved in verification services for the 
responsible entity during that reporting year or for that fuel pa thway application period, but 
does not need to be a sector specific verifier. The independent reviewer must:  
(a) Serve as a final check on the verification team’s work to identify any significant concerns, including:  
(A) Errors in planning;  
(B) Errors in data sampling; and  
(C) Errors in judgment by the verification team that are related to the draft verification 
statement;  
(b) Maintain independence from the verification services by not making specific recommendations about how the verification se rvices should be performed; and  
(c) Review documents applicable to the verification services provided, and identify any 
failure to comply with requirements of this division, OAR chapter 340, division 215, OAR 
chapter 340, division 253, and with the verific ation body’s internal policies and procedures 
for providing verification services, as applicable. The independent reviewer must concur 
with the verification findings before the verification body issues the verification statement.  
(3) As part of completing verification services, the verification body must:  
(a) Provide the responsible entity with the following:  
(A) A detailed verification report, that must at a minimum include:  
(i) A list of all verification team members that provided verification services, including 
identification of verifiers, lead verifiers, sector specific verifiers, verifiers in training and the 
independent reviewer;  
(ii) A detailed description of the facility or entity including all data sources and boundaries;  
(ii) A detailed  description of the accounting procedures and data management systems, 
including data acquisition, tracking, and emissions calculation, as applicable;  
(iii) The verification plan; 
(iv) The detailed comparison of the data checks conducted during verification services;  
(v) The log of issues identified in the course of verification services and their resolution; 
(vi) Any qualifying comments on findings during verification services;  354 
 (vii) Findings of omissions, discrepancies, and misreporting, and the material misstatement 
calculations required under OAR 340 -272-0450, OAR 340- 272-0455, or OAR 340- 272-
0460, as applicable; and  
(viii) For CFP reports submitted under OAR chapter 340, division 253, a detailed description of entities in the supply chain contributing C I parameters; and  
(B) The verification statement(s); and  
(b) Have a final discussion with the responsible entity explaining the verification team’s 
findings, and notify the responsible entity of any unresolved issues noted in the issues log before the veri fication statement is finalized.  
(4) Attestations in the verification statement. The verification statement must contain the 
following attestations:  
(a) The verification body must attest whether it has found the submitted report or fuel 
pathway application to be free of material misstatement, and whether the report or fuel 
pathway application is in conformance with the requirements of this division, OAR chapter 340, division 215, and OAR chapter 340, division 253, as applicable;  
(b) The lead verifier on the  verification team must attest that the verification team has 
carried out all verification services as required by this division; and  
(c) The lead verifier that has performed the independent review of verification services and 
findings must attest to  their independent review on behalf of the verification body and their 
concurrence that the findings are true, accurate, and complete. 
(5) Procedures for potential adverse verification statement and petition process.  
(a) Before the verification body submits an a dverse verification statement to DEQ, the 
verification body must notify the responsible entity of the potential of an adverse 
verification statement, and the responsible entity must be provided at least 14 calendar days 
to make modifications to correct any  material misstatements or nonconformance found by 
the verification team. When a verification body has provided notification to a responsible 
entity under this subsection:  
(A) The responsible entity must make modifications to correct any material misstatem ents or 
nonconformance found by the verification team;  
(B) The modified report and verification statement must be submitted to DEQ before the applicable verification deadline specified in OAR 340 -272-0100(3), even if the responsible 
entity makes a request to DEQ according to subsection (b); and 355 
 (C) The verification body must provide notice to DEQ of the potential for an adverse 
verification statement at the same time it notifies the responsible entity, and include in its notice to DEQ the current is sues log. 
(b) When a verification body has provided notice under subsection (a) and the responsible entity and the verification body cannot reach agreement on modifications that result in a positive or qualified positive verification statement because of a  disagreement on the 
requirements of this division, the responsible entity may petition DEQ before the verification deadline and before the verification statement is submitted to make a final decision as to the verifiability of the submitted report or fuel pathway application. When the responsible entity files such petition with DEQ: 
(A) The responsible entity must submit all information it believes is necessary for DEQ to 
make a determination with its petition; 
(B) The responsible entity and the verification body must submit to DEQ within ten calendar 
days any additional information requested by DEQ; 
(C) DEQ will review the information submitted and, based on the requirements of this 
division and that information, will make a determination on whether modifi cations are 
necessary in order for the verification body to issue a positive or qualified positive verification statement, or if such a statement could be issued without modifications; and  
(D) DEQ will notify both the responsible entity and the verificatio n body of its 
determination.  
Statutory/Other Authority: ORS 468.020, 468A.050, 468A.266, 468A.271, 468A.277 & 468A.280 Statutes/Other Implemented: ORS 468A.010, 468A.015, 468A.050, 468A.265 through 468A.277 & 468A.280 History:  
DEQ 14 -2020, adopt filed 05/07/2020, effective 05/07/2020