February 2015

New Mandatory GHG Reporting for the Oil and Gas Industry

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On January 14, 2015, the Obama Administration announced an update to its March 2014 “Strategy to Reduce Methane Emissions from the Oil and Gas Sector” (Strategy). Within this announcement it was revealed that the Administration would be taking a host of future actions in order to achieve their methane reduction goals, including the following:

Proposing and setting standards for methane and ozone-forming emissions from new and modified sources.
Implementing new guidelines to reduce volatile organic compounds (VOC).
Considering enhancement of leak detection and emissions reporting.
Leading by example on public lands.
Reducing methane emissions while improving pipeline safety.
Driving technology to reduce natural gas losses and improving emissions quantification.
Modernizing natural gas transmission and distribution infrastructure.
Releasing a Quadrennial Energy Review (QER).

If you are a member of the oil and gas industry, you’ve probably been following updates concerning the Administration’s Strategy, as well as the related activity concerning U.S. Environmental Protection Agency’s (U.S. EPA’s) development of future amendments to the industry’s New Source Performance Standards (NSPS). The NSPS amendments, which are anticipated to be proposed this summer, are expected to impose first-time direct limits on methane from certain oil and gas operations and add new equipment types (including hydraulically fractured oil wells, pneumatic pumps, and leaks from new and modified well sites and compressor stations) to those types of sources already covered by the standards. But while amendments to the NSPS loom on the horizon, oil and gas operations are being immediately impacted from another direction – U.S. EPA’s Mandatory Greenhouse Gas (GHG) Reporting Rule promulgated at 40 CFR Part 98.

On October 30, 2009, U.S. EPA published the original version of 40 CFR Part 98 for the purpose of collecting GHG information from a broad range of industry sectors. The 2009 rule, which finalized reporting requirements for 29 source categories, did not initially include the Petroleum and Natural Gas Systems source category. A subsequent rule was published on November 30, 2010 which finalized requirements for the Petroleum and Natural Gas Systems source category at 40 CFR Part 98, Subpart W. Since Subpart W’s promulgation roughly four (4) years ago, it has already been revised eight (8) times by U.S. EPA, most recently on November 25, 2014. On December 9, 2014, additional amendments were also proposed which would add new industry segments and add reporting requirements to those already required under the rule.

With industry facing an upcoming annual March 31, 2015 deadline to submit 40 CFR Part 98 GHG reports, let’s dig into the recent November 25 and December 9, 2014 rulemakings and discuss who it will impact and when, what has changed, and what actions affected entities can take to both ensure compliance with the final November 25, 2014 rule and understand the potential impact of the December 9, 2014 proposed amendments.

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Determining If Your Facility Is Affected

To determine if your oil and gas facility is required to report under 40 CFR Part 98, Subpart W you need to determine whether you meet the reporting thresholds of 40 CFR §98.231 and which of the following eight (8) Subpart W industry segments is appropriate for your facility to report pursuant to:

(1) Offshore petroleum and natural gas production.

(2) Onshore petroleum and natural gas production.

(3) Onshore natural gas processing.

(4) Onshore natural gas transmission compression.

(5) Underground natural gas storage.

(6) Liquefied natural gas (LNG) storage.

(7) LNG import and export equipment.

(8) Natural gas distribution.

Let’s discuss the implications to these industry segments in the context of each recent rulemaking action.

November 25, 2014 Final Amendments

The November 25, 2014 final amendments became effective January 1, 2015 and are widespread in scope – revising calculation methods, monitoring and data reporting requirements, terms and definitions, and technical and editorial errors. The rulemaking impacts each of the eight (8) existing industry segments.

Pursuant to the preamble of the November 25, 2014 final rulemaking, the final amendments are not expected to impart significant additional burden to reporters and in the following circumstances are actually expected to reduce burden or have no impact:

The ability to now use either site-specific composition data or a default gas composition for natural gas transmission compression, underground natural gas storage, LNG storage, LNG import and export, and natural gas distribution facilities.
For well venting from liquids unloading, the ability for the measurement period to now differ slightly from the standard calendar year combined with annualizing the resulting venting data for facilities that calculate emissions using a recording flow meter.
The option to now use a site-specific compressibility factor for calculating emissions from blowdown vents and for conversion of volumetric emissions at actual conditions to standard conditions.
The revised calculation methods for onshore production storage tanks that now require quantification of emissions from well pad gas-liquid separator liquid dump valves only if the dump valve is determined to not be closing properly.
The inclusion of a term to account for situations where part of the associated gas from a well goes to a sales line while another part of the gas is flared or vented.
The removal of the requirement to consider vented compressor emissions routed to a flare in the compressor emissions total and retention of the requirement to report uncontrolled vented emissions from compressors.
The reduction of the number of measurements required to quantify centrifugal and reciprocating compressor emissions routed to a common vent manifold or flare header. Only a single annual emissions measurement at the common vent for groups of manifolded compressors is now required as opposed to emissions measurements for each individual compressor routed to the common vent.
The revised requirements for conducting measurements in the “not-operating-depressurized mode” once every three (3) years or at the next scheduled depressurized shutdown (for centrifugal compressors) or at the next scheduled shutdown when the compressor rod packing is replaced (for reciprocating compressors).
The revised calculation methods for the natural gas distribution segment to clarify the calculation methodologies and reporting requirements for above grade metering-regulating stations.
The removal of the existing Best Available Monitoring Method (BAMM) provisions in 40 CFR §98.234(f) and the transitional BAMM provisions that apply for (portions of) the 2015 calendar year.
The ability to now use optical gas imaging as a screening tool to detect emissions from reciprocating and centrifugal compressors.
The providing of new missing data procedures as guidance for reporters when a measurement is inadvertently missed.

However, U.S. EPA also asserts within the November 25, 2014 preamble that in the following cases the final amendments may increase a reporter’s burden:

Revision of the calculation and reporting requirements for completions and workovers which now differentiate between completions and workovers with different well type combinations in each sub-basin category.
Revision of the calculation and reporting requirements for onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export to include emissions from flare stacks.
The addition of 247 new data elements (many of which are typically already collected by reporters, related to data that are already being reported, or are readily available to reporters), the substantial revision of 13 data elements, and the deletion of 34 data elements that were historically required to be reported.

With an effective date of January 1, 2015, those reporting currently under Subpart W should immediately ensure that they are fluent in what has specifically changed because all data collected for the current calendar year must be monitored, recorded, and calculated in accordance with the November 25, 2014 provisions beginning January 1, 2015. The first report to be submitted in accordance with the November 25, 2014 provisions will be due on March 31, 2016.

Calculation Methods and Impact

The table, Summary of Subpart W Calculation Method Revisions provides a concise summary of the calculation methods (per industry segment) that experienced revision on November 25, 2014 and illustrates their vast impact – each calculation method applicable to each respective industry segment has been revised.

U.S. EPA asserted within the November 25, 2014 preamble that removing the existing provisions would not add burden to existing Subpart W reporters because all reporters had been complying with the historic monitoring methods of 40 CFR §98.234 without utilizing the historic BAMM provisions. However, each reporter should evaluate this on a case-by-case basis and determine if any action needs to be taken as an effect. If a request for a transitional BAMM extension was not filed by January 30, 2015, the option for a reporter to utilize the new transitional BAMM provisions expires on March 30, 2015 and that reporter must obtain the necessary equipment to conduct measurements as required under the revised rule by April 1, 2015. Regarding Subpart W monitoring requirements, the revisions do not impact the monitoring provisions specified at 40 CFR §98.234 concerning how to conduct leak detections; operate and calibrate flow meters, composition analyzers, or pressure gauges; use calibrated bags (i.e., vent bags); high volume samplers; or the Peng Robinson Equation of State. However, reporters will recall that revised monitoring requirements are also incorporated throughout the 40 CFR §98.233 calculation methods and for that reason it is critical for a reporter to review what monitoring requirements have specifically changed from both a 40 CFR §98.233 and §98.234 standpoint. Further, the November 25, 2014 revisions are extremely impactful in that they remove the historic provisions of Subpart W related to BAMM and replace them with special transitional BAMM provisions that only apply during the period January 1 through March 30, 2015. This transitional BAMM applies for certain parameters that cannot reasonably be measured according to the rule’s updated monitoring and quality assurance/quality control (QA/QC) requirements.

To aid in this review, it will be helpful for each reporter to note that the transitional 2015 BAMM provisions included within the November 25, 2014 rulemaking are only intended for the following types of data:

Well-related measurement data that cannot reasonably be measured for well venting for liquids unloading and gas well venting during well completions and workovers with hydraulic fracturing, from wells not previously measured.
Reciprocating compressor blowdown valve, isolation valve, and rod packing venting from manifolded vents, when conducting “as found” measurements according to revised 40 CFR §98.233(p)(4) or (p)(5).
Centrifugal compressor blowdown valve, isolation valve, and wet seal oil degassing venting from manifolded vents, when conducting “as found” measurements according to revised 40 CFR §98.233(o)(4) or (o)(5).

Lastly, in addition to the revisions noted above, U.S. EPA also finalized confidentiality determinations for certain new and substantially revised Subpart W data elements as part of the November 25, 2014 rulemaking action.

Final Thoughts On Rulemaking

December 9, 2014 Proposed Amendments

If finalized as proposed, the December 9, 2014 proposed amendments would affect reporters belonging to the existing “Onshore Petroleum and Natural Gas Production” industry segment, and would also add two (2) new Subpart W industry segments: an “Onshore Petroleum and Natural Gas Gathering and Boosting” segment and an “Onshore Natural Gas Transmission Pipeline” segment. U.S. EPA intends to finalize the December 9, 2014 proposed amendments by the end of 2015, with an effective date of January 1, 2016. If finalized according to this schedule, all data collected for the 2016 calendar year would need to be monitored, recorded, and calculated in accordance with the future rulemaking beginning January 1, 2016. The first report to be submitted in accordance with the future rulemaking would be due on March 31, 2017.

Under the proposed rulemaking, “Onshore Petroleum and Natural Gas Production” segment reporters would be required to monitor and report emissions and data elements associated with oil well (not just gas well) completions and workovers with hydraulic fracturing, and would also have to report Well Identification Numbers associated with individual oil and gas wells, and for certain pieces of equipment that are associated with individual oil and gas wells (e.g., acid gas removal units, dehydrators, tanks, and flares). Members of the oil and gas industry that perform oil well completions and workovers with hydraulic fracturing are advised to keep in mind that U.S. EPA’s incorporation of a requirement to report emissions from these activities has the potential to increase the amount of emissions that would count towards determining applicability to Subpart W. In fact, U.S. EPA expects 50 new reporters to exceed the reporting threshold for Subpart W based upon this future requirement, in addition to the estimated 246 existing reporters that would also be affected. On the other hand, the proposed reporting of Well Identification Numbers is not expected to have significant impact because reporters should already be tracking and maintaining Well Identification Numbers associated with measurements used for other existing Subpart W input data.

Under the proposed December 9, 2014 rulemaking, U.S. EPA would add a new “Onshore Petroleum and Natural Gas Gathering and Boosting” segment that would require the reporting of emissions data and related data elements for equipment used by gathering pipeline systems that move petroleum and natural gas from the well to either larger gathering pipeline systems, natural gas processing plants, natural gas transmission pipelines, or natural gas distribution pipelines. U.S. EPA expects approximately 200 new reporters to become subject to Subpart W if the “Onshore Petroleum and Natural Gas Gathering and Boosting” segment requirements are finalized as proposed. If you fall into this camp, it’s hopefully not completely surprising news, given that reporting from gathering and boosting stations was actually proposed in the original version of Subpart W, but delayed given U.S. EPA’s need to address extensive commenting around the implications of ownership and boundaries.

Under the proposed rulemaking, U.S. EPA would add a new “Onshore Natural Gas Transmission Pipeline” segment that would require the reporting of emissions data and related data elements associated with transmission pipeline blowdown activities. In the case of the new “Onshore Natural Gas Transmission Pipeline” segment, U.S. EPA expects approximately 150 new reporters to become subject to Subpart W if requirements for this new segment are finalized as proposed.

U.S. EPA has also proposed confidentiality determinations for new data reporting elements within the December 9, 2015 action, specifically proposing to determine that none of the new data reporting elements are entitled to confidential protection.

As stated already, U.S. EPA intends to finalize the December 9, 2014 proposed amendments by the end of 2015, with an effective date of January 1, 2016. Given this intended schedule, it’s prudent for existing “Onshore Petroleum and Natural Gas Production” segment reporters to familiarize themselves with what has been proposed to change for that segment and also important for facilities with either gathering pipeline systems or transmission pipeline blowdown activities to evaluate what may be required in the future if new industry segments are added as proposed. U.S. EPA accepted comments on the December 9, 2014 amendments through February 24, 2015.

While U.S. EPA is not proposing to incorporate new provisions involving advanced innovative monitoring methods through this proposed rulemaking, they are in the process of assessing potential opportunities for incorporating remote sensing technologies and other innovational technologies into subsequent versions of the rule and are using the current commenting period as an opportunity to solicit data concerning the benefits, costs, and potential problem areas, as well as their “Discussion Paper on Potential Implementation of Alternative Monitoring under the GHGRP” in Docket ID No. EPA-HQ-OAR-2014-0831.

As you’ll see, whether you are a current reporter under Subpart W or one of the several hundred facilities expected to trigger reporting once the December 9, 2014 proposed amendments are finalized, there are a number of actions that are likely warranted in the short-term. For more information on the impact of the recent Subpart W amendments on your particular facility, or the regulation and reporting of GHG within the oil and gas industry in general, please contact ALL4.

Got Lead? Lead Reporting Rule Finalized

If you’ve “got lead” at your facility, then you’ll want to read this blog regarding the recently published final rule on reporting of lead (Pb) emissions. The final rule published on February 19, 2015 (80 FR 8787) amends the emissions inventory reporting requirements in 40 CFR Part 51, Subpart A [Air Emissions Reporting Requirements (AERR)] to align the point source reporting threshold for Pb emissions sources in the AERR with the National Ambient Air Quality Standard (NAAQS) for Pb and the associated revisions to Pb Ambient Air Monitoring Requirements (Appendix D to 40 CFR Part 58).

The following actions were taken in the final rule:

Lowered the threshold for reporting Pb emissions as point sources,
Eliminated the requirement to report emissions from wildfires and prescribed fires, and
Replaced a requirement for reporting mobile source emissions with a requirement for reporting input parameters that can be used to run the U.S. EPA models that generate emissions estimates.

U.S. EPA lowered the point source threshold for Pb emissions to 0.5 tons per year (tpy) of actual emissions in order to match the requirements of the Pb Ambient Air Monitoring Requirements rule, which required monitoring agencies to install and operate source-oriented ambient monitors near sources emitting 0.50 tpy or more of actual Pb emissions by December 27, 2011. The monitoring and now AERR criteria are based on actual emissions rather than the potential-to-emit (PTE) approach taken for other criteria pollutant and precursor thresholds.

For other Pb considerations, you may want to revisit our May 2013 blog post for more thoughts on Pb emissions. In the meantime, now is an opportune time to revisit your Pb emission factor selection and emissions estimates while compiling your 2014 annual reported emissions. Specifically:

If you have emission units that emit Pb, take a close look at the facility-wide total emissions. If you are close to the 0.5 tpy threshold, review the emission factors that you use to develop the annual emission inventory and make sure that the data are the most current data that reflect existing operations. Doing this now will also help you refine your Toxic Release Inventory (TRI) reports due in July 2015 – perhaps an updated emission factor means you no longer need to report lead emissions in your TRI.

Think about developing new data for Pb emissions. Have you changed the way your process operates? Have you installed a new air pollution control system? Have you changed the filters that you use? Are the Pb emission factors that you rely on more than 10 years old? If you can answer yes to any of these questions, it may be time to develop some new data or review other available data.
“Own” your inventory. The inventory for your facility is available for everyone to see and is being used in ways that you probably didn’t think of – so recognize this and act accordingly. Take the time and spend the resources to update your facility’s inventory to reflect the best and most current data for your facility.

Final Area Designations for the 2012 Annual PM2.5 Standard

As recounted in Dan Dix’s historic 4 the Record Article, on December 14, 2012, U.S. EPA announced the revised annual National Ambient Air Quality Standard (NAAQS) for fine particulate matter (PM2.5; PM with a diameter less than or equal to 2.5 microns). In this announcement, U.S. EPA reduced the primary annual PM2.5 standard from 15.0 micrograms per cubic meter (μg/m3) to 12.0 μg/m3, which is based on the three (3)-year average of the annual arithmetic mean. Using air quality monitoring data collected for calendar years 2011 through 2013, U.S. EPA has now promulgated initial area designations for most areas of the U.S. with respect to the 2012 annual PM2.5 NAAQS.

Before we look at the specific designations, let’s take look at a regulatory timeline for this ruling. Back on December 18, 2014, U.S. EPA issued final area designations for the 2012 annual PM2.5 NAAQS. On January 15, 2015 the boundaries for air quality designations for the 2012 annual PM2.5 NAAQS were published in the Federal Register. In this ruling, U.S. EPA announced that the final PM2.5 designation decisions will be effective 90 days following the date of publication of the January 15, 2015 Federal Register [i.e. April 15, 2015]. While this date is fast approaching, there is another regulatory date that is also quickly approaching. If a state chooses to submit complete, quality assured certified monitoring data from the 2014 calendar year to U.S. EPA by February 27, 2015 that suggests a change of designation status is appropriate for any area within that state, upon agreement from U.S. EPA, the designation promulgated in the January 15, 2015 Federal Register will be withdrawn and another designation will be issued that reflects the inclusion of 2014 data [i.e., a three (3)-year period based on 2012 through 2014].

Now let’s take a look into the specific area designations based on the 2012 annual PM2.5 NAAQS. U.S. EPA has designated areas as nonattainment, unclassifiable, or unclassifiable/attainment. A complete listing of the initial designations for states and territories can be found on the U.S. EPA website located here. U.S. EPA has designated 14 areas in six (6) states as “nonattainment.” These areas include counties with monitors measuring a violation of the standard as well as nearby counties contributing to a violation by emitting PM2.5 pollution, or precursor pollutants that form PM2.5 [e.g. sulfur dioxide (SO2), nitrogen oxides (NOX), volatile organic compounds (VOC), and ammonia (NH3)]. These nonattainment areas have been initially classified as “Moderate.” In addition, U.S. EPA has designated three (3) areas as unclassifiable because these areas have ambient air quality sites that lack complete data for the 2011 through 2013 calendar years. U.S. EPA also has deferred initial area designations for ten (10) areas where available data are insufficient to determine whether the area(s) are meeting or are not meeting the 2012 annual PM2.5 NAAQS. U.S. EPA is using additional time to assess relevant information and promulgate initial designations for these unclassifiable areas through a separate rulemaking action.

What does this mean for area(s) designated as nonattainment? As required in the Clean Air Act (CAA), these areas are subject to planning and emission reduction requirements. Within the next several months, U.S. EPA intends to propose an implementation rule to assist states in developing implementation plans for meeting the 2012 annual PM2.5 NAAQS. These implementation plans must be submitted to the U.S. EPA within 18 months of effective date of the area designations. In addition, these areas are also subject to additional New Source Review (NSR) preconstruction requirements. As always, consider how these new area designations may affect your facility and know where your facility stands with regards to the 2012 annual PM2.5 NAAQS.

These ongoing issues with respect to PM2.5 continue to underscore a message that ALL4 has been shouting since 2012 – if you do not know where your facility stands with respect to compliance with the 2012 annual PM2.5 NAAQS, it is imperative to conduct modeling now to evaluate the feasibility of future expansion projects.

Stay tuned on updates concerning future 2012 annual PM2.5 NAAQS rulemaking/designations.

2015 Shaping Up to Be Busy in the World of Air Toxics

Our August 2014 4 The Record newsletter focused on air toxics, and specifically the residual risk and technology review (RTR) process required by the Clean Air Act (CAA). Our discussions on how the RTR process can alter the landscape of regulatory requirements for National Emission Standards for Hazardous Air Pollutants (NESHAPs) are proving to be timely, as this topic was on the agenda for the U.S. Environmental Protection Agency (U.S. EPA) and Air & Waste Management Association (A&WMA) information exchange meeting in December 2014. However, regulatory developments this month may have an even larger impact on NESHAPs for the coming years, making our newsletter seem almost prophetic.

On February 3, 2015, Earthjustice submitted a Notice of Citizen Suit Concerning Clean Air Act Deadlines to U.S. EPA for its failure to implement the RTR process for over 30 NESHAPs. This notice starts a 60-day clock for U.S. EPA to perform its RTR duties; otherwise, the organizations represented by Earthjustice may commence a citizen suit. It would be next to impossible for U.S. EPA to meet this 60-day deadline (which is established by the CAA) given how far behind schedule it already is, and due to its competing resources and its funding issues, particularly within the air toxics program. During the information exchange meeting, U.S. EPA indicated that surface coating NESHAPs will be a major portion of this year’s RTR process. For example, the proposed RTR rule for Aerospace Manufacturing and Rework Facilities was signed on January 22, 2015. In addition, source categories such as Integrated Iron and Steel Manufacturing, Coke Ovens, Publicly Owned Treatment Works, Plywood and Composite Wood Products, and Ethylene Production also are expected to be priorities.

Please take a moment to review the Earthjustice letter for source categories that impact you and stay tuned to our blogs for continuing updates on the RTR regulatory process.

Super Bowl 50 and Boiler MACT Compliance Anxiety

A Super Bowl has just been added to the record books and here at ALL4 we are already planning ahead to Super Bowl week in 2016. And perhaps not for the reasons that you would expect. Super Bowl Sunday 2016 is slated for February 7, 2016, which is one (1) week to the day after your major source Industrial, Commercial, and Institutional Boilers and Process Heaters must be in compliance with the maximum achievable control technology (MACT) requirements at 40 CFR Part 63 Subpart DDDDD. Football fans of two (2) cities will be dealing with their own anxiety in the week leading up to Super Bowl 50. With a little planning over the next few months, you should be able to reduce your own Boiler MACT anxiety and enjoy Super Bowl week festivities. Here are a few tips for you to consider for planning for Boiler MACT compliance.

Review the proposed major source Boiler MACT reconsideration topics. The reconsideration was published in the Federal Register on January 21, 2015. Although the reconsideration is draft, that should not prevent you from strategizing about how to accommodate the proposed changes or even submitting comments on the reconsideration before March 9, 2015. Specifically, have you considered the following:

Whether your qualifying boiler will be impacted by an alternate carbon monoxide (CO) emission limit.
Aspects of the use of particulate matter (PM) continuous parameter monitoring system (CPMS), specifically around how excursions to parametric limits will be evaluated.
Current and revised definitions that affect the startup and shutdown provisions and institute more detailed recordkeeping practices and impact operating procedures.
Vacatur of the affirmative defense provision, which means that protection from civil suits is eliminated if emission excursions result during malfunction periods.
Whether your facility would benefit from becoming a synthetic minor for HAPs, thereby avoiding major source Boiler MACT and become subject to the potentially less stringent area source Boiler MACT? If so, this option is running short on time, since the minor HAP status for your facility must be in place (i.e., permitted and enforceable) by January 31, 2016.

Confirm you have addressed your environmental permitting requirements.

How does your Boiler MACT strategy impact New Source Review (NSR)?
Any chance that a Standard of Performance for New Stationary Sources (NSPS) gets triggered by your Boiler MACT compliance strategy?
Are you combusting and plan to continue combusting a non-hazardous secondary material (NHSM)? Does the NHSM have a non-waste determination?
Are there any wastewater issues with a new emissions control strategy?

If you will be installing continuous emission monitors (CEMs) for Boiler MACT, think about other implications.

Will the new continuous data give you any surprises?
Do you have the data management portion of CEM monitoring covered?

If any of the items above give you pause, do not hesitate to reach out to an ALL4 Boiler MACT team member for guidance and counsel. After all, everyone gets over a Super Bowl loss (unless you live in Philadelphia), but getting over a Boiler MACT loss will have much more serious consequences.