Oregon Environmental News
Mar 31 2015 - Portland, OR
Jul 15 2015 - Portland, OR
Oregon Proposes Numerous Updates to Air Quality Regulations
Monday, June 30, 2014
On June 16, 2014, the Oregon Department of Environmental Quality (DEQ) proposed various updates to its air quality permitting rules and related emission standards. DEQ’s proposal will streamline, reorganize, and update the air quality permit rules, including the state’s Source Sampling Manual and Continuous Monitoring Manual. The proposed rulemaking package includes the following general regulatory updates:
- Change the statewide particulate matter (PM) emission standards and the preconstruction permitting program to assist Oregon with complying with EPA’s National Ambient Air Quality Standard (NAAQS) for fine PM (PM2.5);
- Incorporate additional state air quality designations;
- Expand preconstruction permitting flexibility for small facilities;
- Allow DEQ to use technology such as teleconferencing for public meetings to improve community outreach; and
- Improve program implementation by proposing minor amendments to the woodstove replacement program (i.e., Heat Smart) and gasoline dispensing facility rules.
Among these proposed changes, the updated PM emission standards, adjusted permitting requirements for emergency generators and small oil and gas-fired combustion equipment, and new state air quality designations could potentially affect a large number of industrial sources in Oregon. As such, additional detail is provided for each of these updates:
- The current PM and opacity rules distinguish between units installed before and after 1970. Specifically, a pre-1970 unit is currently subject to limits of 0.2 grains per dry standard cubic foot (gr/dscf) and 40 percent opacity, whereas post-1970 units are subject to limits of 0.1 gr/dscf and 20 percent opacity. DEQ is proposing that the grain-loading requirement for all units (both pre- and post-1970) that are currently emitting less than 0.080 gr/dscf (based on a representative compliance source test conducted prior to the rule filing date) be reduced to 0.10 gr/dscf. Note the additional significant figure relative to the current grain-loading standard, which is included for consistency with federal guidance. For sources that are currently emitting more than 0.080 gr/dscf (based on a representative compliance source test conducted prior to the rule filing date), DEQ proposes a standard of 0.15 gr/dscf for pre-1970 units and a standard of 0.14 gr/dscf for post-1970 units. However, the grain-loading standard for equipment or modes of operation that are used less than 876 hours per year (i.e., less than 10 percent of the year) will remain at 0.20 gr/dscf. Furthermore, the proposed opacity standard for all sources will be reduced to 20 percent based on a six-minute block average, with the exceptions for wood-fired boilers. The proposal allows for a five-year transition period to comply with the revised standards. This transition period would end no later than January 1, 2020, but the proposal provides the option for a one-year extension, if necessary. As such, the current grain-loading and opacity standards will apply through the end of 2019, unless an extension is granted; however, new sources installed after this rulemaking takes effect will be subject to a grain-loading standard of 0.10 gr/dscf immediately upon startup. Additionally, the proposal provides an option for industrial facilities to request a source-specific limit, if boiler or multiclone optimization does not enable a source to meet the proposed standards by 2020. This provision ensures that the proposed rules will not require any sources to replace a boiler or convert fuel types to meet the proposed standards.
- The proposed rules remove emergency generators and small natural gas or oil-fired equipment from the list of categorically insignificant activities if either of the following apply: (1) The units are above size thresholds that make them subject to emission limits (e.g., under the new federal NESHAP standard for Reciprocating Internal Combustion Engines (RICE)) and (2) aggregate emissions from the units are greater than the state’s de minimis levels. If equipment at an industrial facility no longer qualifies as a categorically insignificant activity, then DEQ would add these sources to the facilities’ existing permits. If a facility has been relying on this insignificant designation to avoid permitting, then this proposed change may trigger permitting for these sources alone. For example, DEQ identified one business in Oregon that operates eight small boilers that qualify for the current insignificant designation based on the boilers’ individual rated capacities. However, when emissions from these boilers are added together, they total approximately 12 tons per year of NOx, which is well over the de minimis threshold for NOx of 1 ton per year. Consequently, this business will no longer qualify for the categorically insignificant exemption, and will need to obtain a permit for operating these boilers when the proposed rules are implemented.
- The proposed rules establish two new state air quality designations, “sustainment” and “reattainment.”
- The “sustainment” designation would apply to areas that are in danger of failing to meet at least one NAAQS, but for which EPA has not yet applied the nonattainment area designation. By establishing these areas as “sustainment”, DEQ’s goal is to provide communities more opportunity to avoid the nonattainment designation by working with DEQ to improve air quality. For example, DEQ would provide incentives to new or modified facilities to obtain emission offsets for problem pollutants.
- The “reattainment” designation would apply to a federally designated nonattainment area that is currently meeting all NAAQS, but for which EPA has not yet redesignated the area as attainment. By establishing these areas as “reattainment”, DEQ’s goal is to allow communities to discontinue costly elements of an attainment plan when those elements are no longer necessary to improve or protect air quality. For example, new and modified facilities within a “reattainment” area would be subject to less stringent air permitting requirements than are typical for nonattainment areas, unless DEQ has identified the facility as a significant contributor to air quality problems.
DEQ’s proposal contains numerous additional modifications to the air quality regulations. As such, it is recommended that Oregon sources review the Notice of Proposed Rulemaking issued on June 16, 2014 in detail to identify other areas that may impact the sources operations. DEQ requested that the Environmental Quality Commission (EQC) approve the proposed rules for incorporation into Oregon’s State Implementation Plan (SIP). With EQC’s approval, DEQ would then submit the proposed rules to the EPA to be included in revisions to Oregon’s SIP, as required under the Clean Air Act. DEQ is currently requesting feedback on the ability of industrial sources to meet the new PM grain-loading and opacity standards, the stringency of Lane Regional Air Protection Agency (LRAPA) rules relative to comparable DEQ rules, and any alternative strategies to achieve the proposal’s goals. DEQ plans to hold a statewide public hearing on this proposed rulemaking package, which will be accessible to the public at locations in Portland, Bend, and Medford. DEQ will consider all oral and written comments received at the hearing, as well as all other comments received by the close of the public comment period on July 31, 2014 at 5:00 PM.
Please contact Maren Seibold of Trinity Consultants at (253)867-5600 or firstname.lastname@example.org if you have any questions about this proposal or if you would like to discuss its potential implications on your facility’s operations.
Various Oregon Regulatory Updates:
Friday, January 24, 2014
DEQ Proposes Incorporation of Various Federal Standards. The Oregon Department of Environmental Quality (DEQ) recently proposed to align Oregon rules with changes to federal air quality regulations. Specifically, DEQ’s proposal would adopt the following new federal standards:
- Area source National Emission Standards for Hazardous Air Pollutants (NESHAP) for boilers, but only for sources required to have a Title V permit or Air Contaminant Discharge Permit (ACDP)
- Major and area source NESHAP for standards for stationary internal combustion engines, but only for sources required to have a Title V permit or ACDP
- Major source NESHAP for boilers and process heaters
- New Source Performance Standards (NSPS) for stationary internal combustion engines, but only for sources required to have a Title V permit or ACDP
- NSPS for nitric acid plants
- NSPS for crude oil and natural gas production, transmission, and distribution
- Federal emission guidelines for commercial and industrial solid waste incineration units
- Federal plan for hospital, medical, and infectious waste incinerators
This proposal also includes the adoption of amended federal NSPS and NESHAP standards for various source categories including electric utility steam generating units, chemical manufacturing, Portland cement manufacturing, and others. Sources in Oregon are already subject to these new and amended federal standards; therefore, DEQ’s proposal would change the responsibility for enforcement of these rules from EPA to DEQ. For those area sources not required to have a DEQ permit, EPA would retain responsibility for enforcement for the aforementioned standards.
DEQ Increases Air Contaminant Discharge Fees and GHG Reporting Fees. DEQ published a temporary rule to increase annual ACDP fees by 20 percent. The permit invoices issued by DEQ in October 2013 included this 20 percent increase. The permit fees are not adjusted annually for inflation and were last increased in 2007. Although the Greenhouse Gas (GHG) reporting program is separate from the ACDP program, the GHG reporting fee is based on the ACDP fee. To avoid increasing the GHG reporting fee for permit holders as a result of this ACDP fee increase, the temporary rule also revises the GHG reporting fee from 15 percent to 12.5 percent of the ACDP fee. The temporary rule is set to expire on April 22, 2014. DEQ plans to propose permanent rules for adoption in 2014.
DEQ Amends and Adopts Regulations Regarding NAAQS and PSD Increments. DEQ recently adopted a rule to incorporate new and revised air quality standards into the state air quality regulations and the Oregon State Implementation Plan (SIP). Specifically, the rule incorporates the primary one-hour National Ambient Air Quality Standard (NAAQS) for NO2, the primary one-hour NAAQS for SO2, the primary and secondary NAAQS for lead, as well as the new one-hour Significant Impact Levels (SILs) for NO2 and SO2 into the state regulations.
Proposed Rule Aligns Oregon Regulations with Federal Hazardous Chemical Reporting Requirements. In December 2013, the Department of State Police and the Office of State Fire Marshal published a proposed rule to align state regulations codified under OAR 837-085 with federal standards concerning hazardous chemical reporting codified under 40 CFR 370. Therefore, Toxic Release Inventory (TRI) reporting requirements for Oregon facilities will be consistent with federal requirements.
DEQ Increases Permit Fees for NPDES and WPCF Permits. DEQ recently adopted a rule to increase most water quality permitting fees by 2.9 percent. Specifically, permit application and annual fees will increase for most National Pollutant Discharge Elimination System (NPDES) and Water Pollution Control Facilities (WPCF) permits.
If you have any questions about how these proposed and adopted rules may impact environmental requirements for your facility, please contact Maren Seibold of Trinity Consultants at (253) 867-5600 or email@example.com.
Registration for Oregon Clean Fuels Program Due June 30th – Possible Impacts to Suppliers in Surrounding States
Friday, June 07, 2013
The CFP applies to entities that import, produce, sell, supply or offer certain regulated transportation fuels for sale in Oregon. Entities that are subject to the Oregon Clean Fuels Program (CFP) must submit an application for registration to the Department of Environmental Quality (DEQ) by June 30, 2013. Since this program applies to importers of fuel, it will potentially affect fuel suppliers in surrounding states (e.g., Washington, Idaho, and California) as well as Oregon suppliers.
The purpose of the CFP is to mitigate Oregon's GHG emissions by reducing the carbon intensity of fuels used in Oregon by at least 10% below 2010 levels. Fuel suppliers will eventually accomplish this reduction by comparing the carbon intensity of their fuels to a declining carbon intensity schedule, calculating corresponding surpluses and shortfalls relative to this schedule, and reconciling any shortfalls by obtaining credits in a market-based system. However, the current phase of the CFP program (Phase 1, codified under OAR 340-253) is intended only to gather information necessary to establish the second phase of the program, which will include a declining carbon intensity schedule for each fuel. Accordingly, regulated parties are not required to balance surpluses and shortfalls at this time.
Any entity that is not subject to Oregon's CFP may become an opt-in party by registering with DEQ. Opt-in parties must keep records and submit reports as required by the CFP for opt-in fuels. The following table lists regulated fuels that will trigger CFP requirements, opt-in fuels that trigger requirements if an entity chooses to opt-in to the program, as well as fuels and fuel uses that are exempt from the CFP:
Oregon Clean Fuels Program Fuel Types
Regulated Transportation Fuels
Opt-in Transportation Fuels
Exempt Fuels and Fuel Uses
Fuel types sold or supplied to Oregon that totals aggregate volume of less than 360,000 gasoline gallon equivalents per year (gge) from all providers
Fossil liquefied natural gas that is imported, but not transferred by a natural gas pipeline in Oregon
Fossil liquefied natural gas derived from fuel delivered through a natural gas pipeline
A fuel blend containing ethanol
Fossil compressed natural gas
Fuel produced by R&D or demonstration facility if annual production volume is either (1) less than 10,000 gallons or (2) less than 50,000 gallons and producer uses entire volume in its own vehicles
A fuel blend containing biomass-based diesel or biodiesel
Biogas compressed natural gas
Ethanol or denatured ethanol (i.e., E100)
Biogas liquefied natural gas
Neat biomass-based diesel and biodiesel (i.e., B100)
Liquefied petroleum gas
Fuels sold or supplied for use in aircrafts, racing and military vehicles, locomotives, ocean-going vessels, farm vehicles and tractors, and motor trucks used to transport logs
Any other liquid or non-liquid fuels not listed as opt-in fuels or exempt fuels
A complete registration application must be submitted for each type of fuel that the entity has imported, produced, sold, supplied, or offered for sale on or before July 1, 2013, and for each fuel type that the entity plans to continue to handle in those ways after July 1, 2013. Furthermore, if an entity plans to begin handling a new type of fuel in the aforementioned ways after July 1, 2013, then the entity must submit a complete application to DEQ for that fuel type on or before the date it begins to provide the fuel for use in Oregon. The registration must include company identification information, the fuel types that will be sold, supplied, or offered for sale in Oregon, the producer of each type of fuel, and a proposed carbon intensity value for each fuel type.
The following types of entities are considered initial regulated parties under the CFP:
- Oregon producers: (1) For liquid blendstocks or finished fuels, the person who makes the fuel at an Oregon production facility is considered to be the Oregon producer; (2) for biogas produced in Oregon, the person who refines the gas to pipeline quality is considered to be the Oregon producer.
- Large Oregon importers: Any person who imports more than 250,000 gallons of fuel in a given calendar year into Oregon is classified as a large Oregon importer.
- Small Oregon importers: Any person who imports 250,000 gallons of fuel or less in a given calendar year into Oregon is classified as a large Oregon importer.
If fuel is transferred from one regulated party to another, the regulated party subject to CFP requirements may also change. The specific circumstances for transferring the CFP compliance obligation from one entity to another vary depending on whether the initial regulated party is a large or small Oregon importer. For example, if a Washington refinery sells gasoline to a company that will be importing the fuel into Oregon, then the importer must notify the refinery of its status as an Oregon producer, a large Oregon importer, or a small Oregon importer before actual fuel ownership is transferred from the refinery to the importer.
- Scenario 1: If the importer is designated as a large Oregon importer, then the importer becomes the regulated party and is subject to the CFP registration, recordkeeping, and reporting requirements for that fuel, unless the refinery chooses to remain the regulated party.
- Scenario 2: If the importer is designated as a small Oregon importer, then the refinery remains the regulated party unless the importer chooses to become the regulated party for that fuel.
Considering the potential for transferring a CFP compliance obligation for a given fuel type, producers of regulated transportation fuels in surrounding states should communicate with companies that purchase their fuel to determine whether it will eventually be imported into Oregon (and if so, whether the company importing the fuel will be designated as a large or small Oregon importer), in order to assess whether they are subject to registration, recordkeeping, and reporting requirements.
Each regulated and opt-in party must complete registration, recordkeeping, quarterly reporting, and annual reporting requirements established for Phase 1 of the CFP under OAR 340-253. Entities that satisfy the exemptions listed in the above table must demonstrate that the exemption applies, obtain exemption approval from DEQ, and maintain required documentation as described in OAR 340-253-0250 . Implementation of Phase 2 of the CFP is expected to begin in late 2015 or 2016. Phase 2 will mandate a 10% reduction in the carbon content of certain transportation fuels over a 10-year period. DEQ is asking the state legislature to remove the current 2015 sunset date for the program before they proceed with the development of Phase 2.
Trinity's upcoming webinar (June 12th at 12:00 PM) will provide a more detailed overview of this program. If you have questions or require assistance with evaluating the applicability of the CFP for your operations, please contact Maren Seibold at Trinity Consultants' Seattle office at (253) 867-5600 or firstname.lastname@example.org.
EPA Authorizes GHG Permitting Deferral for Biogenic Sources
Friday, July 01, 2011
On July 1, 2011, EPA signed the Deferral for CO2 Emissions from Bioenergy and Other Biogenic Sources under the Prevention of Significant Deterioration (PSD) and Title V Programs. According to the pre-publication copy of the rule currently available on EPA’s website, the final rule becomes effective immediately upon the date of its publication in the Federal Register, which is expected to follow the rule signing by one to two weeks. EPA justifies this immediate effective date, rather than the typical 30 day delay, by citing that the deferral eliminates uncertainty in the permitting process and that affected parties need not modify their behavior to accommodate the rule.
Although EPA’s deferral will be immediately effective at the federal level, the applicability and effective date of this rule modification in a particular state will vary. The biogenic deferral is effective immediately upon publication for Title V and PSD permitting programs implemented by EPA under 40 CFR part 71 and 40 CFR 52.21, respectively (i.e., delegated programs). However, the deferral is optional for any state, local, or tribal permitting authorities that implement the Title V and PSD permitting programs under 40 CFR part 70 and 40 CFR 51.166, respectively (i.e., SIP-approved programs). Since Oregon’s is a delegated program, the biomass deferral will be immediately effective upon the rule's publication in the Federal Register. Therefore, permits issued after the date of publication will be eligible for the biomass deferral.[i]
Though not mandatory, EPA encourages states that expect to receive permit applications from a number of biomass facilities to submit the necessary SIP revisions or Title V program revisions to implement this three-year deferral. According to EPA, if a state was able to implement the Final Tailoring Rule without making any changes to state regulations, then it is likely that the state will be able to implement the deferral without regulatory changes. If permit program revisions were necessary for a state to implement the Final Tailoring Rule, then revisions will likely be necessary to implement the deferral.
EPA is implementing the deferral by amending the definition of “subject to regulation” in its PSD and Title V regulations. Only biogenic CO2 emissions will be deferred; therefore, a source must still consider other GHGs (e.g., methane and nitrous oxide) emitted from the combustion of biomass fuel when determining whether a stationary source meets the PSD and Title V applicability thresholds. It should also be noted that this action does not affect compliance obligations for biogenic CO2 emissions under EPA’s mandatory GHG reporting rule (codified under 40 CFR 98). Following a technical review of the net carbon cycle impact of biofuels, EPA plans to make additional rules within the three-year deferral period that will establish an approach for accounting for these emissions on a permanent basis.
Since this deferral is intended to temporarily exclude biogenic CO2 emissions from the definition of “subject to regulation,” as that term was defined in the Tailoring Rule, questions may arise regarding whether existing permits will require modification because of the deferral, or whether permits issued during this three-year period will need to be modified after the deferral. According to EPA’s rulemaking package, “this rule does not require that a PSD permit issued during the deferral period be amended or that any PSD requirements in a PSD permit existing at the time the deferral takes effect, such as BACT limitations, be revised or removed from an effective PSD permit for any reason related to the deferral or when the deferral expires.” In other words, if a source is subject to BACT conditions for biogenic CO2 emissions as a result of a PSD permit issued before the effective date of the deferral, the deferral does not require that these conditions be removed. Similarly, unless a separate permitting action is triggered, PSD permits issued during the deferral period need not be modified when the deferral expires and biogenic CO2 emissions are no longer eligible to be excluded.
If the deferral is not effective in a particular state at the time a PSD permit is issued, then the permit must include appropriate BACT limitations for GHGs. EPA’s interim guidance for biogenic CO2 emissions, entitled “Guidance for Determining Best Available Control Technology for Reducing Carbon Dioxide Emissions from Bioenergy Production,” is intended to assist permitting authorities with establishing BACT for biogenic CO2 emissions prior to the effective date of the deferral. Specifically, this document supports the conclusion that the combustion of biomass fuels can be considered BACT for biogenic CO2 emissions at stationary sources.
Trinity recommends that potentially affected sources, particularly sources with PSD and Title V permits in progress, communicate with ODEQ to discuss how this deferral may affect their permitting efforts.
 Phone conversation between Mr. David Ogulei, WDOE, and Ms. Linda Nguyen, Trinity Consultants, July 12, 2011.
Recent Changes to Oregon Air Permitting Rules
Thursday, April 21, 2011
On April 21, 2011, the Oregon Department of Environmental Quality (DEQ) adopted new PM2.5 and greenhouse gas permitting rules. These rules replace the temporary rule that DEQ adopted on August 19, 2010. For sources permitted after May 1, 2011, an initial netting basis and Plant Site Emission Limit (PSEL) for PM2.5 and GHG will be established for the source as part of its first permitting action issued after July 1, 2011.
In Oregon’s NSR permitting program, the difference between the new PSEL after a project and the netting basis is used to determine whether a proposed project is required to go through the more stringent PSD permitting program. Originally, the DEQ had proposed several different options for establishing the netting basis for PM2.5 and GHG. In the final rule, different options were chosen for each pollutant.
For PM2.5, the initial netting basis and source-specific PSEL will be the PM2.5 fraction of the source’s current PM10 netting basis. The PM2.5 fraction is defined as the fraction of PM2.5 to PM10 for each emissions unit that is included in the netting basis and PSEL.This approach incorporates PM2.5 into the program without the need to establish a separate baseline period for PM2.5. The DEQ has also proposed that a onetime increase of up to 5 tons in the PM2.5 netting basis may be allowed to avoid making a source retroactively subject to NSR/PSD for PM2.5 (for previously approved modifications that increased PM10 emissions).
For GHG, the initial netting basis will be based on actual greenhouse gas emissions during any consecutive 12-month period during calendar years 2000 through 2010. This 10-year look-back approach is similar to the method used by other states that follow the standard federal PSD rules.
The adopted rules can be referenced here: http://www.deq.state.or.us/regulations/rules.htm.
Setting the netting basis will have important future permitting implications for your facility. If you have any questions or need assistance with setting these emissions levels, please contact Ms. Linda Nguyen at 253-867-5600.
Proposed Changes to Oregon Air Permitting Rules
Wednesday, December 15, 2010
The Oregon Department of Environmental Quality (DEQ) has recently proposed a number of changes to its air permitting rules to incorporate PM2.5 and greenhouse gas (GHG) permitting into its New Source Review (NSR) and Title V permitting programs. For PM2.5, the proposed rules will revise and replace a temporary rule that the DEQ had adopted on August 19, 2010.
After the rules become applicable, sources will be required to establish a netting basis and Plant Site Emission Limit (PSEL) for PM2.5 and for GHG at their next permitting action.In NSR permitting, the difference between the new PSEL after a project and the netting basis is used to determine whether a given project is required to go through the more stringent PSD permitting program.
The DEQ has proposed four options for establishing the netting basis for PM2.5 and GHG.
- Option 1: Set the netting basis proportional to the netting basis used for other pollutants. For PM2.5, the netting basis would be tied on the source’s current PM10 netting basis by using a ratio between the source’s PM2.5 and PM10 emissions. For GHG emissions, the netting basis would be related to the production parameters used to establish the netting basis.
- Option 2: Set a netting basis equal to emissions in 1977/78
- Option 3: Set a netting basis equal to emissions in 2006 or 2007
- Option 4: Use the approach similar to the federal NSR program that would set the netting basis based on any consecutive 24-month period in the past 10 years
The DEQ has recently extended the comment deadline for the proposed rules until December 23, 2010, and has announced plans to recommend adoption of the rules at the April 21-22, 2011 Environmental Quality Commission meeting.