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Permitting Frequently Asked Questions

(FAQ)

These FAQs are intended to serve as general guidance and are in no way a formal statement of Department policy.  Unique operating conditions may result in different determinations and may require a site specific analysis to accurately determine requirements and applicability.  


DRAFT FAQ Documents

The Bureau has prepared draft versions of the following Frequently Asked Question (FAQ) documents for review and comment.  If interested, please provide comments to Kerry Carr by e-mail or at (505) 476-4339.

DRAFT FAQ on Compressor Engine Streamline Permitting


Tank-Flashing Emissions

Q. What are tank-flashing emissions?

Q. Do I need to estimate my tank-flashing emissions?

Q. Are there exemptions or thresholds for reporting flash emissions?

Q. What is the timing of submittals and the circumstances and methods of submittals?

Q. How will the Air Quality Bureau address VOC flash emissions in permits?

Q. If a tank is at a facility, but is not connected to the source being permitted, or a tank is adjacent to the new source or source being modified, do the tank-flashing emissions need to be estimated?

Q. How do I estimate my tank-flashing emissions?

Q. Do I need to perform individual gas or liquid sampling to estimate flash emissions for each stock tank or pigging operation?

Q. Where do I enter my tank-flashing emissions data on the permit application forms?

Q. Do I include tank-flashing emissions data for Title V insignificant activities?


Permit and NOI Processing

Q. We need to change our equipment list at our facility, possibly add some, but we will still qualify for an NOI.  Do we need to resubmit the NOI applications showing the changes or is there an easier way to do this?  What’s the best way to authorize the change?


Grandfathering

Q. I have a source/plant/facility with a PER greater than 10 PPH/25 TPY, existed prior to August 31, 1972, has not been modified since and is considered grandfathered. If the plant shuts down for more than five years, will it need a permit to start up?

Q. If a grandfathered unit is shut down, removed from the permitted site and wants to rebuild within five years would it need a permit?


Limiting Operating Scenarios in Permits

Q. Are there any restrictions on operating scenarios?


Permit Fees

General Fee Questions

Q. Are NOIs (20 NMAC 2.73) subject to a filing, permit or annual fee?

Q. What is a fee unit?

Q. I have 25 fee units in my application; am I charged for all 25 units?

Q. I have two sources at my facility that are exempt; one is exempted under 202.A and the other is exempted under 202.B. How many fee units are there?

Q. What are fee points?

Q. How much will I be charged for each fee point?

Q. How much is the permit filing fee?

Q. During the permit application process, when do I need to pay my permit fee?

Q. As a small business with only a few employees, am I required to pay the full permit fee?

Q. After paying the permit fee and obtaining a permit, are there any other fees associated with a construction permit?

Q. If a facility has had no revisions to its permit except an Administrative Permit Revision (20.2.72.219.A NMAC) that was issued after the effective date of March 2, 2001 (20.2.75.4 NMAC), is it subject to an annual fee?

Q. If my application for a permit or request for a re-location of a permitted facility is denied, am I obligated to pay the full fee associated with my request?

Q. If I withdraw my application for a permit before the Department takes final action, am I obligated to pay the full fee associated with my request?


Rock Crushers, Screening Plants and Asphalt Plants

Q. Are all of the conveyors and stackers on my rock crushing, screening plant or asphalt plant considered a fee unit?

Q. I have two conveyors dropping material together onto a single conveyor. How many fee units are counted?

Q. I have a conveyor dropping material onto a stockpile. Is this a fee unit?

Q. I have a front-end loader feeding a hopper or stockpile. Is this a fee unit?

Q. Is there a fee for re-locating my portable plant to another location?


Compressor Engines 

Q. I have three identical engines at a compressor station. Are all three engines considered a separate fee unit?

Q. I am applying for a portable streamline permit for ten identical compressor engines. Since I am only submitting one permit application for all ten engines, do I need to pay the $500 filing fee for each portable engine?


Dehydrators

Q. A natural gas dehydrator has several emissions points. Is each emission point considered a fee unit?


Operating Scenarios 

Q. I have five engines at my compressor station. I am applying for a permit, which allows different operating scenarios; i.e., the permit allows me to simultaneously operate engines #1, 2, & 3 or 3, 4, & 5. How many fee units are there?


Phased Construction

Q. I have one engine previously permitted. If I add a second engine, the first engine will need a catalytic converter to meet emission limits. How many fee units are there?


Petroleum Storage Tanks

Q. I have five storage tanks at my facility. How many fee units are there?


General Construction Permits (GCPs)

Q. How many fee points is a GCP charged?

Q. Does a GCP permit registration require a filing fee?

Q. How many fee units are charged for a technical review of an existing GCP-2, GCP-3, and GPC-5?

Q. What fees are required to revise an existing GCP-1 or GCP-4 permit registration?

Q. Do I need to redo our public notice when we revise our GCP-1 or GCP-4 permits?

Q. If a source has more than one permit for the same equipment, such as a GCP #2 and a regular permit for a crusher spread, what is the annual fee?


Transfer of Permits, Notices of Intent, and Equipment

Q. What is the policy for transfer of permits and equipment?

Q. What is the permit transfer policy in the event that a portion of a non-portable source is sold or removed?

Q. What is the permit transfer policy for portable equipment involved in the construction industry, such as concrete batch plants, crushing and screening plants, and asphalt plants?

Q. What are some other situations that relate to permits for concrete batch plants, crushing and screening plants and asphalt plants?

Q. What is the policy if permitted equipment is moved out of the Department's jurisdiction?

Q. What is the permit transfer policy for portable engines or equipment set(s) permitted under the streamline permit provisions of the NSR permit rule (20.2.72.301 NMAC)?

Q. What are the transfer requirements for Notices of Intent (NOI)?


Ethanol Plants

Q. How is the state of New Mexico going to implement the recently promulgated EPA rule on ethanol plants?


Opacity Based Emission Calculations

Q. Does the Department accept opacity based emission calculations?

Technical FAQ

Q: We have a permit condition for the fuel gas to have no more than 0.1 grains total sulfur per dry standard cubic foot.  What would this equate to in ppm H2S?

Installing Units Authorized by an Old Permit

Q:  I have a permit issued more than five years ago that allows installation of a unit that I have not installed yet.  20.2.72.211.B NMAC says “The Department may cancel a permit if the construction or modification is not commenced within two years...”  Since the times in 20.2.72.211.B NMAC [two year action] and 20.2.72.211.A [five year action] have passed, can I still install this unit? 

Relocation Modeling

Q:  Relocation Modeling:  When can I model for relocation set back distances?

Emission Factors

Q:  Paved Road Emission Factors:  Which AP-42 emission factors should I use for paved roads?

NOI Excess Emissions

Q:  Do I need to report malfunction excess emissions if I have a NOI?


Answers to FAQs

Tank-Flashing Emissions

Q. What are tank-flashing emissions?

A. Tank-flashing emissions occur when crude oil or condensate is exposed to temperature increases or pressure drops. In natural gas extraction and processing, there are many areas where tank-flashing losses occur, including well sites (where high-pressure liquids are flashed into stock tanks at atmospheric pressure), locations where produced liquids from the production separators dump into stock tanks, when gas lines are "pigged" (or physically purged of condensate), and when gas plant inlet separators dump into storage tanks at atmospheric pressure. Tank-flashing emissions are in addition to working and breathing emissions.

Q. Do I need to estimate my tank-flashing emissions?

A. Yes, for new permit applications, significant revisions and emissions inventories, tank-flashing emissions must be estimated and provided to the Department on the appropriate forms. The Universal Application form, which is used for New Source Review (NSR) permits and Notices Of Intent (NOI), contains requirements for identifying tank-flashing emissions data. Also, the Title V operating permit application form has similar requirements.

In addition to already permitted sites, tank-flashing emissions can occur at facilities where other emissions are below permit levels - these facilities may have been issued a Notice Of Intent or a determination of No Permit Required in the past. These facilities must estimate their tank-flashing emission along with all other emission sources to determine the applicable permitting mechanism. Including tank-flashing emissions, a minor source with a permit pursuant to 20.2.72 NMAC may now be subject to the Title V or PSD permit program. Similarly, a source with a determination of No Permit Required may need to submit a Notice of Intent under 20.2.73 NMAC, or may be subject to the Title V or PSD permitting programs.

Considering that tank-flashing emissions "can be reasonably passed through a stack", they are considered normal process emissions, not fugitive.

The Department's authority to collect this information is in the following state regulations: 20.2.72.203.A(3) NMAC, 20.2.70.300.D(5) NMAC, and 20.2.73.300.C(4) NMAC

Q. Are there exemptions or thresholds for reporting flash emissions?

A.  For facilities with permits (either NSR or Title V), the current regulations do not allow any exemptions other then those listed in Section 202 of 20.2.72 NMAC for NSR permits or in the list of Insignificant Activities for Title V facilities referenced in Section 300.D(5) and (6) of 20.2.70 NMAC.

Facilities without permits do not need to submit information for a tank or combination of tanks (tank battery) that have a total throughput of no more than 12 barrels per day of black oil (API gravity less than 40 degrees). This threshold is based on studies by the Colorado Department of Public Health and Environment that each barrel per day of throughput of this oil will result in an average emission of 2 tons per year of volatile organic compounds.

Q. What is the timing of submittals and the circumstances and methods of submittals?

A. As of January 2003, the Air Quality Bureau required by letter that all Title V sources submit current estimates of flash emissions using the method that is appropriate to the source. Non-Title V sources have a similar obligation to evaluate flash emissions. All sources (both Title V and non-Title V) must submit the appropriate permit application if flash emissions cause the source to exceed an applicability threshold.

The AQB's emission inventory for year 2002 required all major and minor sources with permits to submit emissions from flashing of oil and gas liquids by April 1, 2003.

The AQB will not normally re-open a NSR or Title V permit nor request that the owner/operator revise such a permit solely to incorporate VOC emissions from flashing operations.

If a pre-existing and now-known VOC flash emission would exceed a VOC emission limit in a NSR or Title V permit the owner/operator may wish to revise that permit. NSR permits would be revised using either the technical revision process at 20.2.72.219.B(1)(b) NMAC or as a significant revision at 20.2.72.219.D NMAC. Title V permits would be revised using a minor modification process at 20.2.70.404.B NMAC.

If there is no apparent violation of a VOC limit in a NSR permit by a pre-existing and now-known VOC flash emission, the AQB does not require that the permit be updated, but an owner/operator may update the permit file for that facility by submitting a letter with supporting documents and calculations. This letter will be considered as an emissions inventory submittal under 20.2.73.300.B(4).

As AQB obtains additional experience with flash emissions, it may change its guidance on when these emissions are reported.

Q. How will the Air Quality Bureau address VOC flash emissions in permits?

A. VOC are regulated pollutants for the Title V program and may be included in Title V permits in accordance with 20.2.70.302.A(7) with associated monitoring, recordkeeping, and reporting, as needed.

NSR permits may include similar requirements if the source needs enforceable limits to remain a minor source for federal requirements.

Q. If a tank is at a facility, but is not connected to the source being permitted, or a tank is adjacent to the new source or source being modified, do the tank-flashing emissions need to be estimated?

A. To determine whether the tank-flashing emissions from an adjacent or on-site tank must be estimated, you should consider these criteria:

  1. Is the tank of the same 2 digit SIC industrial grouping as the source? 
  2. Is the tank on contiguous or adjacent land with the source? 
  3. Is the tank under the same common ownership or control as the source?

If the tank meets all these criteria, then tank-flashing emissions must be calculated and included with all other emissions at the source.

Q. How do I estimate my tank-flashing emissions?

A. All tank-flashing emission calculations must be supported with an analysis using the Vasquez-Beggs equations. When these equations are not appropriate for an operating situation, you must supplement the Vasquez-Beggs analysis with results from another estimating method that you believe is more appropriate, or the AQB may request that you do so. Circumstances in which another estimating method may be necessary include, but are not limited to:

  • transportation activities (natural gas compressor stations and pigging operations after change of custody to gas transportation companies) and natural gas processing (condensate from gas processing plants) operations,
  • an operating parameter used in the Vasquez-Beggs calculation exceeds the parameter limits that are valid for the equations (see the Department's Vasquez-Beggs spreadsheet on our website for these limits), or
  • the Vasquez-Beggs equations result in emissions estimates that by themselves are within 50% of an applicability threshold for a permitting program, regulatory program, or a performance standard.

Regardless of the estimating methods used, information provided to the AQB must include:

  • a discussion of the appropriateness of the method to the operating circumstances, considering the relative thresholds (i.e., permit or major source (NSPS, PSD or Title V));
  • the input and output from simulation models and software;
  • all calculations;
  • documentation supporting any assumptions used;
  • descriptions of any sampling methods and conditions;
  • and copies of any lab sample analysis.

Because of all the variables involved (i.e., gas compositions, gas throughput & pressure-drop), the AQB does not recommend a method or specific computer program for estimating tank-flashing emissions. However, listed below are some estimating methods that are available. It is your obligation to estimate as accurately as possible all your tank-flashing emissions and to comply with any appropriate regulatory or permitting programs.

  • Gas Processing and Transportation: There are two relatively common methods for estimating tank-flashing emissions from gas processing plants, gas line "pigging" operations, or other transportation processes - simulator programs such as HYSYS or PROSIM, and an engineering mass balance.
  • Exploration and Production: Vasquez-Beggs, HAPCalc, E&P Tanks, and process simulator programs (such as HYSYS or PROSIM) are four methods for calculating flashing losses from oil and gas extraction petroleum storage (stock) tanks prior to custody transfer to the transportation company. The methods vary in complexity and accuracy. Process simulators should be programmed to use the Peng-Robinson equation of state option; they provide emission estimates that agree closely with laboratory tests.

This guidance does not limit the methods the AQB will accept for tank-flashing estimates. This guidance only describes four methods. Applicants may propose more appropriate, technically-sound methodologies for the Department's approval and incorporation into this guidance. It will be necessary to provide an analysis justifying the appropriateness of any new methodology or model.

As AQB obtains additional experience with flash emissions, it may change its guidance on how these emissions are estimated.

Vasquez-Beggs

The Vasquez-Beggs (VB) equation is the easiest calculation tool to use. It is most appropriate for use on upstream operations, such as stock tanks at wellheads, oil and gas production batteries, and for "black oil" (a heavy, low-volatility oil approximated by a gas to oil ratio of less than 1750 cubic feet and an API gravity less than 40 degrees). It is the default method required by AQB for all facilities with flash emissions. This model only has six input variables: API gravity, volume of produced hydrocarbons, volume of produced gas, separator pressure and temperature, and specific gravity of flash gas.

With the VB equation, tank-flashing losses are calculated as total VOC's (only) and are not speciated into individual chemical compounds or HAPs. It has been shown that tank-flashing estimates of VOCs using the VB equation may be considerably underestimated or overestimated, depending on the numerous variables that affect flash losses. The variability is more apparent when modeling tank-flashing near the wellhead, where the pressure drop is highest and liquid composition is more variable. The VB model does not calculate standing or working losses from storage tanks.

The calculation program is available in spreadsheet format (EXCEL) and can be downloaded from the NMED website. (/aqb/Vasquez-Beggs-Flashing-Calculations.xls)

HAP-Calc

The HAP-Calc model uses the Vasquez-Beggs method to estimate VOC tank-flashing emissions, so AQB will accept this analysis instead of spreadsheet calculations. In addition to estimating VOC tank-flashing emissions, the HAP-Calc program speciates HAP emissions. The HAP emissions can be estimated by entering site-specific data, or by using default program values. The HAP-Calc program runs in Windows format and costs about $75 through the Gas Research Institute (GRI). Since it uses Vasquez-Beggs as the basis for its calculations, this program may err in the same way compared to process simulators.

E&P Tanks

In addition to tank-flashing losses, the E&P Tanks program estimates tank working and standing losses. The model uses the Peng-Robinson equation of state to estimate tank-flashing losses and speciates between HAP emissions and VOCs. This model is best suited for upstream operations, such as stock tanks at wellheads and tank batteries common to several wellheads, although it will handle a broader range of API gravities (15-68).

The program costs about $300 (in 2002) from the American Petroleum Institute (API) and tends to be more complicated than Vasquez-Beggs to run. Even though this model uses the Peng-Robinson equation of state, evaluations compared with process simulators give somewhat inconsistent results with variations in pressure inputs. It has been shown that the E&P Tanks model may also underestimate or overestimate VOC tank-flashing emissions, but not as much as the Vasquez-Beggs equations.

PROCESS SIMULATORS (HYSYS, PROSIM, etc.)

It has been shown that the HYSYS process simulator estimates tank-flashing emissions (both VOC & HAPs) that compare very closely to laboratory values. Tank-flashing emissions estimates should be performed using the Peng-Robinson equation of state option (there are other equations of state available in the model, but Peng-Robinson is the best for this type of calculation). In addition to a tank-flashing model, HYSYS is a comprehensive process simulator and consequently is very complicated to use and is very costly. As of 2002, the full simulator costs $13,000 a year to own. There are also leasing options. However, AEA Hypertech is currently researching a market for a streamlined version of HYSYS that would only estimate tank-flashing emissions and cost significantly less than the complete simulator.

PROSIM is another process simulator used by engineers to design and optimize plant operations in the oil and gas industry. It provides the Peng-Robinson option to calculate flash emissions also.

For sampling method guidance, see the E&P Tanks manual, Appendix C (Surface Fluid Sampling of Black Oil Reservoirs) on the New Mexico Environment Department website (/aqb/sampling-protocol.pdf).

Q. Do I need to perform individual gas or liquid sampling to estimate flash emissions for each stock tank or pigging operation?

A. The AQB realizes the high cost of taking individual samples from each stock tank or pigging operation. To ensure the accuracy of tank-flashing emission estimates, the chemical analysis of gas and liquid used in the models must be representative of that specific geologic formation or region serviced by the process equipment. In a geologic formation or region where the gas has been sampled throughout and analyses show very similar results, additional gas samples may not be needed. When sampling is limited, and the composition of the gas or liquid from different samples results in significant variation in the emissions analysis, a specific gas and/or liquid sample and analysis may be needed. It is your obligation to evaluate existing samples from a formation or region and decide whether you can rely on them for estimating tank-flashing emissions for your site. You will also want to consider the accuracy of the method and relative permit thresholds.

Q. Where do I enter my tank-flashing emissions data on the permit application forms?

A. Tank-flashing loss emission estimates and data are entered 

  1. for NSR: into Table IV-A and VI-A&B respectively on the Universal application and Section 4 of the streamline compressor station application; and 
  2. for Title V: into Section 7 and Element 6 of the Operating Permit Application Package.

Q. Do I include tank-flashing emissions data for Title V insignificant activities?

A. No, unless the AQB determines on a case-by-case basis that tank-flashing emission estimates and data must be provided to justify the source as insignificant. Pursuant to 20.2.71.111.A(4) NMAC, emission rates from those operations determined to be insignificant activities by the Department shall not be included in the fee calculation.

Permit Processing

Q:  We need to change our equipment list at our facility, possibly add some, but we will still qualify for an NOI.  Do we need to resubmit the NOI applications showing the changes or is there an easier way to do this? What’s the best way to authorize the change?

A.  Any change to the equipment that has emissions would require a new NOI.  An application will need to be submitted to revise the information in the existing NOI.  A $500 fee will need to be included with the application.  In each application, please include the number of the existing NOI for which the revision applies. 

 

Limiting Operating Scenarios in Permits

Q. Are there any restrictions on operating scenarios? 

A.  Yes, there are two possible reasons why multiple operating scenarios may not be permitted.  First, operating scenarios that avoid future permit review of a facility which is modified per 20.2.72.7.P NMAC are contrary to the intent of 20.2.72.200.A.2 NMAC.  Second, multiple complex operating scenarios may result in complex permit conditions and ambiguous situations during enforcement as to which is the current operating scenario, resulting in a permit which is not federally enforceable.  Thus, any permit application with a proposed operating scenario that allows a facility to avoid a future permit modification under 20.2.72.200.A.2 NMAC or which scenarios are too complex to be practicably enforceable, will be ruled incomplete until the applicant withdraws the disallowed operating scenario.  A few examples of operating scenarios that fall into either of these categories are crushing facilities with multiple scenarios with different sets of equipment resulting in different set backs for each set of equipment, and crushing facilities with multiple throughput limits resulting in different set backs.

Grandfathering

Q. I have a source/plant/facility with a PER greater than 10 PPH/25 TPY, existed prior to August 31, 1972, as not been modified since and is considered grandfathered. If the plant shuts down for more than five years, will it need a permit to start up?

A. Yes

Q. If a grandfathered unit is shut down, removed from the permitted site and wants to rebuild within five years would it need a permit?

A. Yes

Permit Fees

Q. Are NOIs (20 NMAC 2.73) subject to a filing, permit or annual fee?

A. Yes, a NOI is subject to a filing fee, but not a permit fee, nor annual fee.

Q. What is a fee unit? 

A. A fee unit means any equipment or process which generates, creates, or is the source of a regulated air contaminant, which is listed or identified in a construction permit application or application to revise a permit and which requires review and evaluation against state and federal regulations and standards. This definition does not include sources that are exempt under 20.2.72.202 NMAC or sources for which no applicable requirements are identified in the permit. In the case of a permit modification, revision or technical review of an existing permit, the requirements of Subsection A of 20.2.75.110 NMAC apply only to the equipment or process involved in such modification, revision, or review. Different scenarios of operation using the same set of equipment may constitute different fee units, in addition to the fee units corresponding to the equipment itself, depending on the amount of analysis and permit conditions for each scenario.  Certain operating scenarios may not be permissible.  See the “Are there any restrictions on operating scenarios?” FAQ below.

Q. I have 25 fee units in my application; am I charged for all 25 units? 

A. No, the maximum number of fee units that result in a charge is 15.

Q. I have two sources at my facility that are exempt; one is exempted under 202.A and the other is exempted under 202.B. How many fee units are there? 

A. If the source is exempted, either under 202.A or B, no fee unit is charged.

Q. What are fee points? 

A. Fee points are the basis for determining a permit fee. The schedule in 20.2.75 NMAC shows the number of fee points that are assessed for each aspect of a permit review. Fee points are assessed for the number of fee units and applicable regulations and for modeling, PSD, non-attainment and/or toxics review.

Q. How much will I be charged for each fee point? 

A. $315. Starting in January 2006 this amount will be modified annually based upon changes to the Consumer Price Index

Q. How much is the permit filing fee? 

A. All construction permit (20.2.72 NMAC) applications must be submitted with a $500 filing fee, which is deducted from the final permit fee. Registration for a General Construction Permit (GCP) must include the full permit fee of $3,150, for 10 points (this fee will change annually in January 2006).

Q. During the permit application process, when do I need to pay my permit fee? 

A. The applicant is invoiced for the permit fee when the application is ruled administratively complete. You must pay the permit fee within 30 days of the date of the invoice.

Q. As a small business with only a few employees, am I required to pay the full permit fee? 

A. If your business can satisfy the definition of a "Small Business" (as defined in Subsection F of 20.2.75.7 NMAC), the permit fee determined in Paragraph 110.B can be divided in half per 20.2.75.11.C NMAC. The "Small Business" applicant must submit a letter with their permit application certifying that their small business satisfies the definition. Do not submit this certification if you are applying for a GCP permit, because, per 20.2.75.5.F NMAC, the emission limitations in a GCP permit will not allow your facility to qualify for a small business discount.

Q. After paying the permit fee and obtaining a permit, are there any other fees associated with a construction permit? 

A. Yes, all construction permits (20.2.72 NMAC), including registrations under a General Construction Permit, are assessed an annual fee of $1,500. The fee does not apply to sources that are assessed an annual fee for the Title V permit program in accordance with 20.2.71 NMAC. Starting in January 2006 this amount will be modified annually based upon changes to the Consumer Price Index.

Q. If a facility has had no revisions to its permit except an Administrative Permit Revision (20.2.72.219.A NMAC) that was issued after the effective date of March 2, 2001 (20.2.75.4 NMAC), is it subject to an annual fee?

A. No.  Pursuant to 20.2.75 NMAC, Section 2.7.E, administrative revisions are excluded from permit actions that cause a source to be subject to an annual fee.

Q. If my application for a permit or request for a re-location of a permitted facility is denied, am I obligated to pay the full fee associated with my request? 

A. Yes, unless there are extenuating circumstances the full permit fee or re-location fee is due to the Department for processing the request, regardless of the Department's final decision.

Q. If I withdraw my application for a permit before the Department takes final action, am I obligated to pay the full fee associated with my request? 

A. The Department will make a case-by-case determination on whether any fee beyond the filing fee is due. That determination will depend on when in the process you withdraw the application and the amount of work the Department has invested in the process.

Rock Crushers, Screening Plants and Asphalt Plants 

Q. Are all of the conveyors and stackers on my rock crushing, screening plant or asphalt plant considered a fee unit? 

A. Each drop point between conveyors/stackers is considered a fee unit, since each is a source of particulate and opacity testing.

Q. I have two conveyors dropping material together onto a single conveyor. How many fee units are counted?

 A. One, since there is only one opacity reading necessary at this drop point.

Q. I have a conveyor dropping material onto a stockpile. Is this a fee unit? 

A. Yes, since there is the potential for one opacity reading.

Q. I have a front-end loader feeding a hopper or stockpile. Is this a fee unit? 

A. No, if the operation is not regulated by a permit condition.

Q. Is there a fee for re-locating my portable plant to another location? 

A. Yes, the basis for the fee is one fee point to cover the costs of processing the request to re-locate, resulting in a fee of $315. This fee must accompany the re-location request. Starting in January 2006 this amount will be modified annually based upon changes to the Consumer Price Index.

Compressor Engines 

Q. I have three identical engines at a compressor station. Are all three engines considered a separate fee unit? 

A. Yes, each engine is considered a separate fee unit.

Q. I am applying for a portable streamline permit for ten identical compressor engines. Since I am only submitting one permit application for all ten engines, do I need to pay the $500 filing fee for each portable engine? 

A. Yes, each portable streamline engine requires a $500 filing fee, since the regulation would require a separate permit for each one; and permit staff will invoice the full permit fee for each one.

Dehydrators 

Q. A natural gas dehydrator has several emissions points. Is each emission point considered a fee unit? 

A. No, a dehydrator is generally considered one fee unit, including emissions from both the still vent and combustion source. If the emissions from the still vent are combusted in a flare, another emission unit would be added for the flare. However, if the emissions from the still vent are directed to a condenser, no additional fee units are assessed because no new emissions are created. If dehydrator emissions are re-injected into the pipeline, no additional fee units are assessed. In the definition, a fee unit must generate, create, or be the source of a regulated air contaminant.

Operating Scenarios 

Q. I have five engines at my compressor station. I am applying for a permit, which allows different operating scenarios; i.e., the permit allows me to simultaneously operate engines #1, 2, & 3 or 3, 4, & 5. How many fee units are there? 

A. Five, the total number of engines. However, if an operating scenario is requested in the application, and it requires additional analysis and permit conditions beyond those required for each individual piece of equipment operated in that scenario, then the scenario itself is considered a fee unit. An engine that operates at different loads would not constitute multiple operating scenarios if each load did not result in all of the actions required by the definition of fee unit in 20.2.75 NMAC: a source of regulated air contaminants, identified in the application, requiring review and evaluation against regulations and standards, and having its own applicable requirements in a permit.

Phased Construction 

Q. I have one engine previously permitted. If I add a second engine, the first engine will need a catalytic converter to meet emission limits. How many fee units are there? 

A. Two, since both engines require review.

Petroleum Storage Tanks 

Q. I have five storage tanks at my facility. How many fee units are there? 

A. Five, assuming none is exempt.

 

General Construction Permit (GCPs) 

Q. How many fee points is a GCP charged? 

A. Ten, regardless of the number of emission units at the site.

Q. Does a GCP permit registration require a filing fee? 

A. Yes. All GCP permit applications for new registrations are charged 10 fee points which includes the filing fee and is due at the time of application submittal.

Q. How many fee units are charged for a technical review of an existing GCP-2, GCP-3, and GCP-5? 

A. For GCP -2, -3, & -5, changes to registrations are only reported to the AQB and require no response by the Department. Therefore, no fee is assessed for these changes.

Q. What fees are required to revise an existing GCP-1 or GCP-4 permit registration?

These permit reviews are a “technical review of an existing permit (20.2.75.7.G. NMAC) and will be assessed a permit fee according to 20.2.75.11.A.1.  An invoice for the balance of the permit fee (less the filing fee) will be submitted with the Department’s determination and due within 30 days of invoicing (20.2.75.12.C NMAC).

Note:  A $500 filing fee should be submitted with the notification of these types of revisions. 

Answer for GCP-1: A permit fee will be assessed for revisions to registrations that require advance notification per Condition IV.B. of the GCP1.

Answer for GCP-4: A permit fee will be assessed for revisions to registrations under Conditions X.3. and/or X.4. of the GCP4 permit.

Q. Do I need to redo our public notice when we revise our GCP-1 or GCP-4 permits?

A.  No public notice is required when submitting an application to update GCP-1 and GCP-4 permits as the public notice that was done for the initial location registration approves the site for a GCP-1 or a GCP-4 type facility.  Thus, modifications allowed under the GCP-1 and GCP-4 permits do not need a subsequent public notice.

Q. If a source has more than one permit for the same equipment, such as a GCP #2 and a regular permit for a crusher spread, what is the annual fee? 

A.  An annual fee would be assessed for each permit.

FAQs for Permit Transfer

Q. What is the policy for transfer of permits and equipment?

A. Generally, the permit is attached to a facility’s physical location, except for portable equipment. The permit authorizes construction and operation of a specific set of equipment that emits regulated pollutants. As a result, the permit is attached to that equipment at a fixed site, and equipment cannot be substituted, except as authorized by the permit, NMED regulation, or written policy. The seller of a facility must notify the Department of the change in ownership of a facility (20.2.72.212.C NMAC). The purchaser of a facility must also notify the Department of the change in ownership (20.2.73.200.E(3)) since every application for a permit constitutes a notice of intent under 20.2.73 NMAC. The transfer of ownership of a facility and its permit is incorporated into the permit as an Administrative Revision for NSR permits (20.2.72.219.A.1.b NMAC) and as an Administrative Amendment for Title V permits (20.2.70.404.A.2 NMAC).

Q. What is the permit transfer policy in the event that a portion of a non-portable source is sold or removed?

A. For a non-portable (site specific) source, such as a compressor station, the permit remains with the location. As a result, the owner/operator of the property on which the source is located retains the permit, and the permit no longer covers the equipment that has been removed from the site. If a site that previously had only one owner/operator with one permit is divided into multiple sites that operate under separate owners, those owners must request that the Air Quality Bureau issue the appropriate documents (Permit, Notice of Intent, or No Permit Required) to assign responsibility.

Q. What is the permit transfer policy for portable equipment involved in the construction industry, such as concrete batch plants, crushing and screening plants, and asphalt plants?

A. For these types of plants, the equipment components described in the permit (crushers, screens, conveyers, stackers, bins, drums, etc) can be sold or removed as individual items. The permit remains with the permittee when any or all of the permitted equipment is sold. The original permittee is responsible for complying with the permit for any equipment that is retained. Only if the original permittee takes the initiative to transfer the permit to the new owner of any amount of equipment that is transferred will the Department recognize the permit transfer. That initiative must include the notification to the Department under 20.2.72.212.C NMAC.

Q. What are some other situations that relate to permits for concrete batch plants, crushing and screening plants and asphalt plants?

A. If equipment is transferred through an intermediate person who did not intend to operate it, the permit remains with the current permittee, unless the permittee takes action to notify the Department that the permit has been transferred. For example, if a bank forecloses on the loan that the permittee used to obtain the equipment and sells the equipment at auction, the permit does not automatically transfer to the bank nor the new owner/operator. Similarly, if a retail dealer rents the equipment to a person who obtains a permit, the permit remains with the permittee when the leased equipment is returned.

Another case is when the current permittee substitutes equipment as specifically authorized by the permit. No permit transfer occurs, even if the main functional unit is exchanged. Under the permit’s authorization the permittee may even substitute every component of the originally authorized equipment at the same time.

Q. What is the policy if permitted equipment is moved out of the Department's jurisdiction?

A. If the permittee moves the equipment covered by a permit out of New Mexico or to Tribal Land or Bernalillo County, the permit remains with the permittee and will be valid when the permittee returns the equipment to New Mexico. Five years from the date the equipment left the jurisdiction of the state’s Air Quality Bureau the permit is cancelled automatically if the equipment has not returned and operated in that jurisdiction in that time.

Q. What is the permit transfer policy for portable engines or equipment set(s) permitted under the streamline permit provisions of the NSR permit rule (20.2.72.301 NMAC)?

A. Multiple portable units in a permit remain permitted for as long as the units are owned by a single permittee. When a unit is sold, it is removed from the permit, but the permit remains in effect for the remaining units. The permittee must notify the Department of units that are sold or removed from a portable permit (20.2.72.212.C NMAC). The portable streamline permit may be transferred to a new owner/operator; however, the transfer must include all the listed equipment and cannot be split between different owners. As described in the first question and answer of this FAQ, both new and old owner/operators must notify the Department

Q. What are the transfer requirements for Notices of Intent (NOI)?

A. The principles for transfer of permits apply to NOIs also. Some significant exceptions follow. The new owner/operator of a non-portable (site-specific) source will notify the Department according to 20.2.73.200.E(3) NMAC. There is no regulatory authority for the Department to cancel a NOI if the equipment has not operated, so moving covered equipment outside the Department’s jurisdiction does not impose any need to return it to keep an NOI from being cancelled. A NOI that includes multiple portable engines will remain with the addressee on the NOI when some of the engines are transferred to another owner, unless that addressee notifies the Department of his desire to convey that NOI to another person, who will become the owner of all the equipment listed in the NOI. New owners of portable engines must apply to the Department for the appropriate authorization to operate the equipment.

FAQs for Ethanol Plants

Q. How is the state of New Mexico going to implement the recently promulgated EPA rule on ethanol plants?

A. On 12 April 2007, USEPA promulgated a new definition of chemical process plants for the purpose of expediting the air quality permitting process for ethanol plant construction.  The change raises the PSD threshold from 100 tons per year to 250 tons per year per pollutant, removing ethanol plants from the list of 28 facility types that have a 100 ton per year threshold.  It also removes ethanol plants from the PSD and Title V list of sources for which fugitive emissions can trigger the applicability of those programs.  The affected federal rules are 40 CFR, Parts 51, 52, 70, 71.  New Mexico is not immediately adopting these changes, but will revise the New Mexico State Implementation Plan in the future as required by USEPA to meet rule deadlines.  Until the State Implementation Plan has been revised, the previous definition and PSD thresholds remain in effect (i.e., ethanol plants with emissions greater than 100 tons per year of any pollutant must submit a PSD permit application and fugitive emissions from an ethanol plant may trigger PSD and Title V applicability).

Opacity Based Emission Calculations

Q. Does the Department accept opacity based emission calculations? 

A.  No, the Department does not accept opacity based emission calculations.   All known opacity based emissions calculations are based on a 1988 technical paper written by D.S. Ensor and M.J. Pilat (Univirsity of Washington) titled “Calculation of Smoke Plume Opacity from Particulate Air Pollutant Properties.”  EPA has never adopted or condoned this method of calculating particulate emissions based on the opacity of a particulate plume.  Although the Department has accepted this method of calculating emissions in the past, without EPA support of this method, support of this method by other states, and positive academic peer review, the Department has lost confidence in the validity of this method of determining particulate emissions from plume opacity measurements and has determined this method is not acceptable, appropriate, or defensible.  The Department will use EPA established AP-42 emission factors for the mineral products industry located at www.epa.gov/ttn/chief/ap42/ch11 .  

 

Technical FAQ

Q: We have a permit condition for the fuel gas to have no more than 0.1 grains total sulfur per dry standard cubic foot.  What would this equate to in ppm H2S?

A: 0.1 grains total sulfur/1SCF translates to approximately 159 ppmv hydrogen sulfide.

http://www.air-dispersion.com/formulas.html is a helpful link that includes conversion formulas.

Also, a “rule of thumb” is that 0.25 grains/100 SCF hydrogen sulfide is approximately 4 ppmv or 0.25 grains/1SCF is approximately 400ppmv. The ratio of molecular weights of sulfur to hydrogen sulfide is approximately 32/34 or 0.94 so I used the formula in the link to find the ppmv total sulfur and then multiplied by 0.94 to find the ppmv of H2S. Using the “rule of thumb” would yield 160 ppmv.

 

Installing Units Authorized by an Old Permit (9/10/10)

Q:  I have a permit issued more than five years ago that allows installation of a unit that I have not installed yet.  20.2.72.211.B NMAC says “The Department may cancel a permit if the construction or modification is not commenced within two years...”  Since the times in 20.2.72.211.B NMAC [two year action] and 20.2.72.211.A [five year action] have passed, can I still install this unit? 

A:   For minor sources subject to 20.2.72 NMAC, the unit can be installed at any time after permit issuance unless the permit states otherwise.  The Department does not require notification beyond what is required in your permit.  If your facility’s PSD permit was issued under 20.2.74 NMAC and if 18 months has lapsed since permit issuance (20.2.74.302.G NMAC), you should contact the Major Source Unit Section Manager, Ned Jerabek, with the specifics of your situation prior to commencing construction.

Q:  Relocation Modeling:  When can I model for relocation set back distances?

A:  There are two opportunities to submit relocation modeling.  First, in addition to your modeling submitted with your permit application for the initial site, you may submit additional modeling to establish separate set back distances for future relocation sites.  The resulting permit will include language establishing the set back conditions for future relocations.  Second, two weeks prior to submitting a relocation application for an existing portable permit, you may submit relocation modeling to establish new set back distances at the proposed site.  This is a general answer.  Be careful to read the current Modeling Guidelines on this subject to ensure you meet all the specific modeling requirements prior to submitting relocation modeling.

Q:  Paved Roads Emission Factors :  Which AP 42 emission factors should I use for paved roads ?

A.  The Department allows the use of paved road emission factors for both permitted and unpermitted facilities.  The new AP 42 published in January of 2011 changed the previous restriction on the use of the equation for vehicles traveling above 10 miles per hour to 1 mph.  This change allows this equation to be more universally applied to facilities.  In the event that site-specific values cannot be obtained, an appropriate value from an industrial road may be selected from the mean values given in AP 42, Table 13.2.1-3.  Facilities using paved factors for NPR or NOI determinations must operate as represented in the application and must maintain the road as paved in order to maintain the facility’s NPR or NOI status.

Alternatively for permit applications, facilities may choose to use unpaved emission factor calculations with a control efficiency of 95% for paving and sweeping.  Permits based on this approach will include conditions assuring continued compliance with maintenance and sweeping.  

Q:  Do I need to report malfunction excess emissions if I have a NOI?

A.  A facility covered solely by a NOI does not need to report excess emissions resulting from a malfunction.

Excess Emission” means the emission of an air contaminant, including fugitive emissions, in excess of the quantity, rate, opacity or concentration specified by an air quality regulation or permit condition.  (20.2.7.6.D NMAC)

"Malfunction" means any sudden and unavoidable failure of air pollution control equipment or process equipment beyond the control of the owner or operator, including malfunction during startup or shutdown.  A failure that is caused entirely or in part by poor maintenance, careless operation, or any other preventable equipment breakdown shall not be considered a malfunction.  (20.2.7.6.E NMAC)

20.2.73 NMAC, which regulates Notices of Intent does not specify a limit.  It establishes a threshold, requiring facilities that emit in excess of, to file and obtain a Notice of Intent.  Even a facility that has 300 tons of a criteria pollutant is required to have an NOI.  Of course, in this case, it is likely the facility will also require either or both a TV and PSD permit.  However, malfunction excess emissions are not in excess of any NOI requirement. 

If a facility, which is classified as a NOI has emissions that are part of normal operations or considered SSM, these emissions will need to be evaluated under the appropriate programs for applicability (Parts 70, 72 and 74).

 

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