Pennsylvania
DEPARTMENT OF ENVIRONMENTAL
PROTECTION

February 24/

2017

Senator Joe Scamati

Senator Jake Corman

Senate of Pennsylvania

Senate of Pennsylvania

Senate Post Office Box 203025

Senate Post Office Box 203034

Hamsburg, PA 17120-3025

Harrisburg, PA 17120-3034

Senator Gene Yaw

Senate of Pennsylvania
Senate Post Office Box 203023

Harrisburg, PA 17120-3023
Dear Senators Scamati, Gorman, and Yaw:

It was ourpleasure to meetwithyou to discuss yourconcerns overthe proposed General Permit
for Unconventional Natural Gas Well Site Operations and Remote Pigging Stations (GP-5A) and
proposed revisions to the General Permit forNatural Gas Compression Stations, Processing
Plants, and Transmission Stations (GP-5). The Department of Environmental Protection (DEP)'s
goal through these general permits is to decrease confusion over the federal requirements, clearly
establish Best Available Technology (BAT) for significant emission sources, and establish a
consistentand predictableprocess to ensure appropriate controls of emission sources are
employed.

You requested the DEFs rationale and justification in a number of areas related to these proposed
general permits; the DEP's responses may be found in the enclosure. DEP believes that proposed
GP-5A and the proposed revisions to GP-5 balance the needs of industry for cost-effective

operations and ^e needs ofthe public for enhanced environmental protection.
1would like to stress that these are draft proposals. Despite meeting with 22 stakeholders in 27
meetings over an 11-month period, the DEP recognizes that there are still valuable opportunities
to leam more through the formal public commentprocess, which extends until June 5,2017.
If you have any additional questions or concerns, please feel free to contact George Hartenstein,
Acting Deputy Secretary of Waste, Air, Radiation, and Remediation, by e-mail at

ghartenste@pa.gov or by phone at 717.772.2725.
Sincerely,

Patrick McDonnell
Acting Secretary
Enclosure

Secretary

Rachel Carson State Office Building   P.O. Box20631 Harrisburg, PA17105-2063 1717.787.28141 www.dep.pa.gov

 1)

Other than the unconventional oil and gas industry, what other industry sectors were
evaluated for inclusion as part of DEP 's methane emission reduction strategy?

The DEP looked at a wide variety of methane sources as part of the methane
reduction strategy. The Summary of Green House Gas Emissions by Gas in 
shows that the largest key sources of anthropogenic methane emissions include natural gas
and oil systems coal mining land?lls enteric fermentation
?om domestic livestock wastewater and manure management Of
all these major categories, natural gas and oil systems is the only category that has shown
signi?cant growth, increasing threefold from the 19905. The other major categories are
either ?at or down from the 19903.

Currently there are no federal regulations that require the reduction of methane emissions
from coalbeds. While there are technologies available to reduce and use these gases, there
are complicating factors relating to widespread use of these technologies. Some of those
factors include the gas quality, especially the concentration of methane, and the presence
of other contaminants. In addition, methane poses an explosive risk to miners. For these
reasons, the DEP did not consider any reduction strategies for this sector.

The US Environmental Protection Agency (EPA) published regulations that included the
reduction of methane from new municipal solid waste land?lls on August 29, 2016. EPA
also established emission guidelines under 40 CFR Part 60 Subpart Cf for the reduction of
methane from existing municipal solid waste land?lls on August 29, 2016. These federal
regulations are incorporated by reference in 25 Pa. Code ?122.3. The DEP reviewed the
federal regulations and how they affect the 44 municipal solid waste land?lls in
The DEP found that existing permit limits for these facilities were already
much more stringent than the federal requirement. Therefore, no additional regulation
was required.

There are no federal regulations that require the reduction of methane emissions ?-om
domestic livestock or manure management Under Section 4.1 (relating to Agricultural
Regulations) of the Air Pollution Control Act (APCA), the DEP is unable to
deve10p rules or regulations on agricultural commodities, including livestock, unless
required by the Clean Air Act (CAA) or a regulation promulgated under the CAA.
Therefore, the DEP did not consider these sources any further as part of the methane
reduction strategy.

Currently, the federal regulations related to waste water treatment do not address methane
emissions. In fact, the federal regulations only relate to sewage sludge incineration and
not the emissions from the water treatment tanks, weirs, or digesters which are the
primary sources of methane emissions. Because there are no federal regulations related to
methane in the wastewater treatment industry, the DEP did not consider these sources any
further as part of the methane reduction strategy.

2)

3)

What legal justification does DEP rely upon for imposing methane limitations on only the
unconventional oil and gas industry?

The pr0posed GP- 5A and proposed revisions to GP- 5 are authorized by both federal and
state law. EPA developed several regulations that apply to oil and natural gas production
sites, natural gas compression stations, processing plants, and transmissions stations; these
are 40 CFR Part 60, Subparts 0000, and 0000a and 40 CFR Part
60 Subparts HH and Some of these regulations require the control of methane
emissions from sources at these facilities. Other pollutants that are regulated under these
standards include volatile organic compounds (V DOS) and hazardous air pollutants
(HAPs). These regulations apply to all oil and gas operations in the country. The DEP 15
required to implement these federal regulations under Section 4 of the APCA, 35 P. S.
?4004. That section provides that the DEP 1s required to implement the provisions of the
CAA 1n In addition, these federal regulations are also incorporated by
reference into the Code and, as a result, are also law. See 25
Pa. Code ??122.1, 124.1, and 

The conventional oil and gas industry was considered brie?y for inclusion in the
permitting process. However, conventional gas wells only represent approximately 4% of
total gas production' 1n and a majority are existing sources. Existing
sources, including conventional wells can be addressed through regulatory requirements
that EPA issued on October 27, 2016.

What cost or economic impact analysis was conducted for each of the proposed permits?

The DEP used the analysis developed by EPA in its rulemaking ?and also developed its
own independent analysis. As provided under the APCA and its implementing
regulations, the DEP is required to ensure that emissions ?'om new sources are controlled
using Best Available Technology (BAT). See 35 RS. ?4006.6(c) and 25 Pa. Code ?127.1.
In a BAT analysis for a general permit, .the DEP examines control techniques and control
devices that reduce emissions, evaluating the technical and economic feasibility of the
best control ?rst; If the best control is not technically or economically feasible, the second
best 18 evaluated; this continues until either all controls are ruled out, or one is found to be
technically and economically feasible.

The DEP conducted a BAT analysis for each oil and gas source category, examining the
technical and economic feasibility of control measures, at the time the original GP-5 was
issued, when conditional exemption category number 38 (Exemption 38) was established,
and for the proposed general permits. The terms and conditions of the general permits and
Exemption 38 are based on the BAT analysis Conducted at that time. Each source will
continue to follow the terms and conditions set at the time of its construction, unless it is
modi?ed or reconstructed.

4)

The BAT analyses are detailed in the Technical Support Document (T SD) which
can be found online in eLibrary at

The TSD is a
comprehensive analysis that details the scienti?c, engineering, and costs rationale for the
air permitting requirements for air pollution sources and the associated air pollution
controls covered by the General Permits.

What evidence does DEP have to substantiate that the existing GP 5, Category 38
Exemption process is not ?mctz'onz'ng properly?

Through the implementation of Exemption 38, the DEP discovered a high noncompliance
rate among operators with this provision. For example, since 2013, over 3,000 wells have
been drilled and there is a documented 28% noncompliance rate with Exemption 38. This
is unusually high, and one that was unexpected by the DEP due to the outreach conducted
prior to creating Exemption 38 and the extensive outreach when the DEP started to detect

a compliance issue.

The DEP developed an FAQ sheet, developed implementation instructions, developed
compliance demonstration instructions, held webinars, and held informational meetings
with operators to inform them of their reporting obligations under Exemption 38.
Unfortunately, the use of this conditional exemption has not lived up to the 
expectations. For that reason, DEP decided to propose the GP-SA for unconventional
natural gas well sites. Additionally, operators have underreported the emissions ?om
remote pigging operations which have led to the DEP to include these operations in the
GP-SA.

The development of general permits for these sources in is not unique.
Several states, including Alaska, Louisiana, Texas, Ohio, West Virginia, and Colorado,
have general permits for oil and gas production facilities in place. Operators in
also Operate in these states; consequently, these operators are accustomed to
being regulated in this manner.

In addition, some operators have expressed a preference for the certainty that a general
permit provides as opposed to the permit exemption in place now. The conditions for
eligibility under Exemption 38 are signi?cantly more numerous than other categories in
the Permit Exemption List. It is likely that these numerous conditions contributed to the
industry?s confusion over the compliance requirements for Exemption 38. Moving to a
general permit from Exemption 38 will reduce confusion and- improve industry?s
compliance rates with the regulatory requirements. In addition, greater compliance means
fewer enforcement actions by the DEP.

Proposed revisions related to are based on updates to the federal requirements and
the four years of experience with the current GP-S.

5)

6)

Will current sites operating under the existing GP 5, Category 38 Exemption be
grandfathered, or will they be required to apply for a new GP5 or If they are not
grandfathered how does DEP justify essentially revoking authorization for an existing
facility to operate?

The DEP is not revoking permits for existing facilities to operate. Facilities that were
constructed and operated under the current GP-S will continue to follow those terms and
conditions and, as such, are grandfathered. When the current GP-S expires, a?er its ?ve-
year term, the operator will be required to obtain a new permit. As long as any existing
equipment is not modi?ed or new equipment installed, the new permit will contain the
same federal and state requirements, except for any new recordkeeping or reporting
updates. Once an operator modi?es existing equipment or adds new equipment, that
modi?ed or new equipment is subject to any updated federal and state requirements.

As with GP-S, the DEP is not revoking authorizations to operate under Exemption 38.
Facilities that were constructed and operated under the cturent Exemption 38 will
continue to follow those conditions unless a new well is drilled or hydraulically ?-actured,
an existing well is hydraulically refractured, or if new equipment is added. Under those
conditions, the operator will be required to apply for a however, the existing
equipment will continue to follow the Exemption 38 requirements established at the time
of construction.

DEP seeks to impose new standards and limitations on the emission of methane. It appears
that DEP is regulating methane emissions without speci?c statutory or rulemaking
authority. What speci?c authority is DEP relying upon to impose these standards?

The DEP regulates methane under existing statutory and regulatory authority. As
previously mentioned, EPA developed several regulations that apply to sources at
unconventional natural gas well site operations, natural gas compression stations,
processing plants, and transmission stations. Some of these regulations require the control
of methane emissions ?'om these sources. Under Section 4 of the APCA, 35 PS. 4004,
the DEP is required to implement the provisions of the CAA in In addition,
these federal regulations are also incorporated by reference into the Code
and, as a result, are also law. See 25 Pa. Code 122.1, 124.1, and

127.35 As required under the APCA and its implementing regulations, the DEP is
required to ensure that emissions from new sources are controlled using BAT. 35 PS. 
4006.6(c) and 25 Pa. Code 127.1.

However, it is important to clarify that there is no methane limitation established in the
proposed general permits. The 200 tons per year (tpy) methane standard in the general
permit is actually a control threshold, above which an operator must control the source?s
emissions. That means there is no cap or limit on the amount of methane that can be
emitted, but any emissions over 200 tpy must be controlled. The requirement to control
methane above that threshold is based on the recently promulgated federal regulations
under 40 CFR Part 60 Subpart 00003, and the BAT requirement.

7)

.8)

9)

How do the permit limitations imposed in the revised GP5 and proposed comport
with the state 's Air Pollution Control Act, and specifically Section 4.2(b) of the Act?

Section 4.2(b) applies to regulations promulgated by the Environmental Quality Board.
Neither GP-S nor GP-SA proposes any new regulatory requirements. All of the provisions
of the pr0posed general permits implement existing regulatory authority. As a result,
Section 4.2(b) does not apply to the general permit process. The general permit program
and process is authorized under Section 6.1(f) of the APCA, 35 PS. 4006.1(t) and its
implementing regulations under 25 Pa. Code Chapter 127, Subchapter H. The DEP is also
authorized to require that new sources demonstrate in the plan approval application that
the sources will reduce or control emissions of air pollution using BAT. See 35 PS. 
4006.6(c) and 25 Pa. Code 127.1.

Currently, the DEP has 18 air quality general permits available for use by a wide range of
industrial sources and activities. The DEP used the process under the APCA and
Subchapter to develop each of those general permits. It is the process the DEP has been
using to develop general permits since Subchapter was last amended in 1994. It is the
same process that the DEP is using to develop the proposed GP-5 and GP-SA.

How was the methane limitation imposed in each of these permits arrived at?

As previously mentioned, there is no methane limitation established in the pemiit. The
methane standard in the general permit is a control threshold, above which an operator
must control the source?s emissions. The requirement to control methane above that
threshold is based on the recently promulgated federal regulations under 40 CFR Part 60
Subpart 0000a, and the BAT requirement. The control threshold for methane
was calculated to be equivalent to the 2.7 tpy signi?cance threshold for VOCs that was
originally established in 1979 as de minimus level below which the DEP believes does not
warrant additional measures for control. The DEP included the methane threshold
calculation in the TSD posted along with the draft GP-SA and the draft revised GP-S for
rev1ew.

Based on information from the emission inventory, there are approximately 31,224
sources at 4,960 well pad facilities and 4,285 sources at 493 compressor stations. Of
these, only 24 sources located at well pads and 61 sources located at compressor stations
exceeded 200 tons of methane in .2014. Of those 85 sources that emitted 200 tons or more
of methane, 53 would be required to install controls based on the methane control
threshold in the proposed permits only if controls are not already installed. In the
aggregate, that means less than 0.1% of all oil and gas sources in would be
required to install controls for methane emissions alone.

What scienti?c studies or analysis did DEP utilize to quantify the unconventional oil and
gas industry's contributions to total methane emissions, ambient air quality, or public health .
and environmental impacts?

In developing the general permits, the DEP relied primarily on determination that
methane must be regulated to protect the public health and environment. The DEP used
the Summary of Green House Gas Emissions by Gas in to determine the
approximate methane emissions contributable to the oil and natural gas industry. Other
sources include the references listed in the TSD.

Nationally, the ?nal standards for new and modi?ed sources are expected to reduce
510,000 short tons of methane in 2025, the equivalent of reducing 11 million metric tons
of carbon dioxide. Natural gas that is recovered as a result of the rule can be used on site
or sold. EPA estimates the ?nal rule will yield climate bene?ts of $690 million in 2025,
which will outweigh estimated costs of $530 million in 2025.

Reductions in VOCs and I-IAPs are also expected to yield bene?ts. Nationally, the
standards are expected to reduce 210,000 short tons of ozone-forming VOCs in 2025,
along with 3,900 tons of HAPs, such as benzene, toluene, and xylene.
Ozone is linked to a variety of serious public health effects, including reduced lung
function, asthma attacks, asthma development, emergency room visits and
hospitalizations, and early death from respiratory and cardiovascular causes. Air toxics
are known or suspected to cause cancer and other serious health effects.

In air emissions from the oil and gas sector continue to increase. Between
2012 and 2014, the air emissions inventory for unconventional natural gas and mid-stream
facilities shows that HAPs have increased by 23%, VOCs have increased by 35%, and
has increased by 19%. Through the application of BAT, DEP intends to reverse the
increase in emissions from this industrial sector, and as a result, yield environmental and
public health improvements.

In 2013, DEP revised GP-S and developed Exemption 38 both of which required the
implementation of enhanced leak detection and repair (LDAR) requirements which served
to reduce methane emissions as a collateral bene?t. These enhanced requirements have
improved air quality in the state.

By operation of law under Section 184 of the federal CAA, is part of the
Ozone Transport Region because it faces unique air pollution challenges. By de?nition,
the entire state of is nonattainment with the ozone air quality standard.
Consequently, industry is subject to more stringent permit requirements
under the CAA and APCA. Operators do not need to contend with this additional
stringency in other states where they Operate such as West Virginia, Colorado, and Ohio.
Regardless, position as the only major natural gas producing state in the
Ozone Transport Regionmeans that enhanced pollution controls are necessary to protect .
the air resources of the state.

10)

II)

12)

Wat scienti?c studies or analysis did DEP utilize to establish the speci?c emission
limitations contained within the permit criteria?

The vast majority of emission limitations established in the GP-S and GP-SA are federal
requirements. In certain limited instances the DEP went beyond the federal requirements
through the application of BAT. The scienti?c review and analysis related to the
permit requirements centered on publically available literature that was primarily used by
EPA to warrant the regulation of methane to protect the public health and environment.
The EPA analysis covered emissions and engineering costs, bene?ts of emission
reductions, and economic impact analysis. In addition, the DEP did its own independent
analysis in the TSD that also looked at engineering, technology, and cost evaluations.

The TSD includes the ratiOnale for the air permitting requirements for air pollution
sources and the associated air pollution controls covered by the General Permits. The
TSD describes sources in common to all types of facilities, sources 'speci?c to GP-SA
eligible facilities, and sources speci?c to GP-S eligible facilities.

What evidence does DEP have to substantiate its inference that the unconventional natural
gas industry has not taken prudent steps to minimize ?tgitive emissions of the very product
which it seeks to sell?

The DEP does not infer that the unconventional natural gas industry has not taken the
required steps to minimize ?igitive emissions as required under Exemption 38 and the
existing GP-S. However, the current program under Exemption 38 requires that the
Operator comply with the federal noti?cation, recordkeeping, and reporting requirements
of 40 CPR Part60, Subpart(s) 0000 and 00003. Those federal requirements are
incorporated into the proposed GP-SA.

The general permit program will serve to unify the requirements and clarify operator
obligations under the regulations. In addition, requiring each site to submit a report to the
DEP under their general permit authorization number helps the DEP track compliance.

Why do the permit limitations also include temporary sources? It appears that the permit
process fails to contemplate the well construction, drilling and completion process ?which

is temporary in nature compared to the production phase of a well.

Even though drilling, hydraulic ?acturing, and completion operations are temporary in
nature, these Operations emit air pollution and must be regulated under both federal and
law. The general permit outlines the operator?s obligations and requires
information about those temporary operations necessary to determine compliance with the
existing requirements, including the applicable federal regulations and the general
permit requirements. 



13)

14)

15)

What fees must accompany each permit application? Mat analysis was done to justi?z the
amount of each fee? What authority does DEP have to impose a fee outside of the
rulemaking process?

No fees are being imposed outside of the rulemaking process. The fees are prescribed in
25 Pa. Code ?127.702(i) (regarding establishing plan approval fees for general permits);
(regarding application fees of $1,700 for sources subject to federal regulations); 25
Pa. Code ?127.703 (regarding establishing operating permit fees for general permits);
and (regarding operating permit application fees of $3 75 for minor facilities).
Therefore, each general permit application must be accompanied by a fee of $2,075 as
detailed in Section Condition 7 of the permits. The analysis performed to justify these
fees was part of the rulemaking that established these fee provisions in 1994.

DEP has referenced climate change as the primary driver behind its methane reduction
strategy. What tangible climate change bene?ts will the citizens of realize due
to the imposition of these new requirements? Wat is this analysis based on?

The reference to climate change in its methane reduction strategy is due to 
rationale for promulgating new regulations to address methane emissions from both new
and modi?ed sources in the oil and gas sector. As the DEP previously mentioned, the
general permits incorporate these federal requirements in order to ensure that all new and
modi?ed oil and gas facilities in are in compliance. These federal
regulations are also incorporated as law in the Code.
Additionally,.the DEP is rethired to implement the CAA as provided under Section 4 of
the APCA.

As previously discussed, the ?nal federal standards for new and modi?ed sources are
expected to reduce 510,000 short tons of methane, 210,00 short tons of VOC, and 3,900
short tons of HAP nationally in 2025. The methane reductions will yield estimated net
climate bene?t of $160 million in 2025. The reductions in VOCs and HAPS will yield
collateral public health bene?ts such as reduced rates of asthma, hospitalizations,
premature death, cancer, and tonic response related to ozone and air toxics reductions.

DEP has stated that it intends to review and issue administratively and technically complete

GP 5 and permits in 30 days. However, DEP currently fails to review and issue most

of its general permits within the prescribed time?'ame. For example, many existing GP5
permits that are to be reviewed and issued within 30 days are taking in excess of 6 to 12
months, or more, to process, with signi?cant deviations based upon DEP regional o?ice.
How can the regulated community rely upon a 30-day processing time?ame for these
proposed permits?

All general permits are required to be issued within 30 days as provided under 25 Pa.
Code The DEP continuously evaluates what resources are necessary to
ensure that the permitting program can meet this regulatory required time?'ame. Instances
where permits took longer than 30 days to issue were typically due to the fact that

16)

17)

operators submitted incomplete or technically de?cient applications or to a complex
federally required emissions analysis known as a single source determination. The DEP
continues to work with operators to ensure that they submit quality applications and is
evaluating the single source determination procedures to ?nd ef?ciencies in the
application process.

The DEP is currently ?nalizing an electronic application system under the mining
program and believes this system can achieve ef?ciency in the permitting process. The
DEP expects the electronic application system will create a more consistent application
environment for consultants and operators. While waiting for the electronic application
system to be expanded to the air program, the DEP will take the necessary steps to ensure
an ef?cient, consistent, and predictable permitting program.

In June 2016, the United States Environmental Protection Agency (US. EPA) ?nalized its
New Source Performance Standards (0000a) to control emissions, including methane,
?om oil and gas sources. US. EPA ?s ?nal rule was adopted after a comprehensive
rulemaking process which included detailed cost-bene?t analysis and a required
demonstration of publ ic health and environmental bene?ts. How do DEP proposed permit
conditions overlay with these new standards, which were adopted after DEP announced its
intention to publish the revised GP5 and Why is 0000a not su??icient?

The vast maj ority of the requirements in and GP-SA are ?om the federal
regulations; however, the federal requirements are the ?oor for determining BAT. The
BAT determination is based on the own engineering and cost analyses, and
experience in implementing the previous general permit and Exemption 38. The general
permit requirements are only different from the federal requirements where the 
BAT analysis shows additional controls are technically and economically feasible.

An example of this is the 98% control ef?ciency for methane, VOC, and HAP for storage
tanks. The federal requirement is for 95% control for VOC. Methane and HAP are

controlled in the similar manner as VOC, and are often simply considered a co-bene?t

reduction. However, 'the DEP examined the effectiveness of control based on Air
Pollution Control: A Design Approach, and determined that 98% control is feasible for
both methane and VOC. The 98% control ef?ciency is also demonstrated as achievable
based on DEP review of control equipment guarantees and control requirements from
other states such as Wyoming, which requires the same level of ef?ciency.

DEP seeks to impose 98% control of emissions for pigging operations. As you know, pigging
operations are critical to maintain proper pipeline pressure, preventing corrosion, inspect
and otherwise maintain the integrity of pzpel ines. What analysis has DEP done to determine
whether such a standard is even practical or attainable?

. Pigging operations were originally deemed a source of minor signi?cance and covered

under Exemption which states that combined VOC from sources at the facility
will be less than 2.7 tpy on a 12?month rolling basis and in the GP-S under Section A
Condition Over time, it came to the attention that pigging emissions were

9

18)

signi?cantly understated by industry based on the number of facilities that reported
emissions over 2.7 tpy VOC from pigging. As a result, the DEP initiated a number of
actions including isSuing orders under the APCA to require operators to submit records
that accurately account for emissions from pigging operations. Based on this information,
the DEP has determined that pigging Operations are a signi?cant source and should be
treated as such with requirements based on the application of BAT, and that remote
pigging stations with emissions above the de minimis level be required to obtain a GP-SA.

The DEP determined that sources considered to be of minor signi?cance, such as those
that are below the 200 tpy methane, 2.7 tpy VOC, 0.5 tpy single HAP, and 1.0 tpy total
HAP thresholds do not require control. Those that exceed this signi?cance threshold in
any way (on one or more of the criteria) are required to control emissions by 98% or more
as determined in the BAT analysis found in Appendix of the TSD. There are
several pigging operations in that are currently controlled by ?ares,
demonstrating that this requirement is technically feasible.

As proposed. the GP5 a must be obtained prior to moving any earth to build a well pad The
time, level of detail and cost associated with preparing a permit application is on par with
preparing some Title Vmajor source air permits. Due to market conditions, it is not unusual
for a year or two to pass between well pad construction and drilling a well and placing it
into production. How, therefore, is it reasonable to require an applicant to estimate
emissions ?'om on-site sources so far in advance? How is an operator to estimate source
emissions related to production when an operator cannot know how much natural gas a
well will produce?

The DEP disagrees that the time, level of detail, and cost associated with preparing a
general permit application is on par with preparing a major source permit application.
Major source applications, like Title V, are case-by-case exercises that can take months to
prepare and can include complex exercises like air quality modeling. Unlike a Title 
application, a general permit application can be ?lled out in a matter of days, because all
of the conditions in the general permit itself are standardized and not subj ect to change.

Additionally, operators are currently required to have well drilling permits and any
erosion and sediment control permits in hand prior to the start of earth moving activities
associated with the construction of a well pad. Accordingly, at this point in time,
operators must have an understanding about gas production and midstream gathering
systems in the area. The DEP also accepts the estimates of air emissions based on vendor
provided emission factors, emission factors derived from stack test results from other
identical sources or estimates based on engineering calculations. Therefore, it is
reasonable to require operators to estimate air emissions for permitting purposes prior to
the construction of a well site.

10

19)

20)

If an operator returns to an existing well pad at afuture site to drill additional wells, must
the site be re -permitted again?

After the general permit is ?nalized, the operator will be required to obtain an
authorization to use the GP-SA to drill new wells at an existing unconventional natural
gas well site. Doing so subjects the entire well site to the general permit, but the
requirements for all existing wells and equipment are identical to those found in
Exemption 38, with the exception of the leak detection and repair (LDAR) requirements.

After the general permit is ?nalized, the operator of a new unconventional natural gas
well site may have to obtain a new authorization to use the GP- 5A to drill a new well,
depending on the information contained within the original application. To illustrate,

. consider two examples where the operator?s engineering analysis determines that the site

can support between four and six wells and the associated equipment

In the ?rst example, the operator obtains authorization for four wells, four separators, a
glycol dehydrator, two tanks, one enclosed ?are, and one pig launcher in the original GP-
5A application. After building the pad up to those speci?cations, the operator decides to
drill two more wells, add two more separators, and another tank. This would require
obtaining a new authorization by submitting a complete application package including
new fees.

In the second example, the operator obtains authorization for six wells, six separators, a -
glycol dehydrator, three tanks, one enclosed ?are, and one pig launcher in the original GP-
5A application. The operator initially only builds four wells, four separators, a glycol
dehydrator, two tanks, one enclosed ?are, and one pig launcher. The operator then
decides to drill the remaining two wells and install the remaining equipment a year later.
No further authorization is needed, as the original application accounted for the additional
equipment as long as there was not a break in construction of more than 18 months, which
is a federal requirement. Ifthe operator decides that the time is not opportune to drill the
remaining wells before the 18-month period, they may notify the DEP of the lapse of
cons?u'uction and request an extension. In either case, no new application or fees are
required.

What authority does DEP rely upon for conditioning receipt of an air quality permit on
adherence to federal state or local noise limitations? What' 1s the correlation between noise
levels and ambient air quality, and the rationale for 1mposing such standards on only the
unconventional oil and gas industry?

An earlier dra? version shared with the Air Quality Technical Advisory Committee

contained a requirement to simply meet any applicable noise requirements, and has been

removed from the current version. While there is no speci?c noise requirement in the

proposed general permits, operators must comply with all applicable law, including local,
state, and federal noise requirements.

ll

21)

What analysis has DEP performed to justijy the ?equency and stringency of many of the
components of the permits, such as a) quarterly leak detection and repair surveys; b)
audio, visual and olfactory observations; c) mandatory reporting of any
malfunction or anomaly, regardless of whether it resulted in any emission; d) quanti?cation
of any leak, regardless of duration, which may impede timely repairs and return to service;
e) burdensome noti?cation, recordkeeping and other reporting requirements typically
mandated through the rulemaking process?

The analyses conducted by the DEP are detailed in the full TSD. However, a brief
summary of those analyses for each of the points above follows:

a) Quarterly LDAR surveys are required under the existing GP-S and for compressor
stations under Subpart 0000a. Subpart 0000a only requires semi-annual surveys for
well sites; however, the BAT analysis shows that quarterly inspections are cost
e??ective. Quarterly inspections result in increased emissions reductions over semi-annual
inspections, thereby saving more product for the operators, and limiting the impact on the
surrounding air quality.

In addition, the DEP has preposed an off-ramp under GP-SA to the federal semi-annual
requirement for operators that consistently show less than 2% of total components at a
facility are leaking. This provides incentive for good maintenance practices and provides
relief for smaller operators that rely on contractors for their inspections.

b) Audio, Visual, and Olfactory (AVO) inspections are required under the
existing GP-S. Many well site operators that the DEP has met with highlighted that a
majority of their leaks are detected during AVO inspections conducted as part of normal
operations on the site. Some operators have said that their personnel conduct walk-
through inspections (AVO inspections) at most sites once per day.

c) The mal?mction reporting requirement in Section A, Condition 10(d)(ii) now
refers to the GP-S Malfunction Reporting Instructions for guidance on how and what to
report. This document was written with signi?cant input from industry.

d) Leak quanti?cation has been included in LDAR requirements under GP-5
and Exemption 38, including instructions on how to quantify a detected leak. In the

. independent cost analysis for LDAR under the proposed GP-SA and GP-S, the

service providers? quotes included both detection and quanti?cation in the cost. DEP will
accept any valid method of quanti?cation. The goal is to get accurate
quanti?cation that can be used in emissions inventory reporting rather than merely relying
on emissions factors, but certainly not to impede repairs.

e) The recordkeeping requirements are the minimum required for the DEP to ensure
compliance with the permit. The reporting requirements merge the state?s annual
compliance certi?cation with the federal annual report required under Subpart 0000a to
eliminate duplication of effort. Operators can submit the reports electronically through
email in lieu of written noti?cations.

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SummaryofGHG Gas In P3111151 vania MMTCOZE)

01-14 27.60 27.31 23.32 30.01 23.94 29.56 29.92 34.97 33.00 29.19 3073 31.59 31.04 30.33 31.52 30.23 2344 29.33 30.41 30.33 34.27 32.74 33.09 35.00
Stationary Combustion 0.52 0.52 0.55 0.52 0.50 0.50 0.51 0.42 0.36 0.36 0.39 0.37 0.36 0.39 033 0.39 0.35 037 0.33 0.39 0.33 0.33 0.36 043
Mobile Combustion 0.34 0.34 0.33 0.32 0.31 0.30 0.29 0.27 0.26 0.24 0.22 0.21 0.19 0.17 016 0.15 0.14 0.12 0.11 0.10 0.10 0.09 0.09 0.09
Coal Mlning 11.25 11.20 1203 13.33 12.60 13.35 13.61 15.51 15.77 1272 1273 11.73 10.31 10.70 10.50 9.40 319 9.92 10.54 11.53 11.73 9.11 9.10 10.63
92:21? 63"? 0" 3.03 3.14 3.15 3.16 3.13 3.17 3.26 6.52 5.70 5.59 6.35 3.77 9.23 3.35 9.56 9.74 10.03 10.30 10.61 10.76 9.43 10.41 1054 10.69
Enteric Fermentation 3.69 3.69 3.76 3.68 3.55 3.53 3.54 3.53 3.50 3.52 3.51 3.45 3.44 3.27 3.31 3.37 3.34 3.43 3.49 3.46 349 3.51 3.52 3.45
Manure Mamement 0.63 0.66 0.62 0.63 0.67 0.67 0.64 0.66 0.73 0.75 0.73 0.77 0.34 0.72 0.77 0.31 0.75 0.31 0.79 0.30 030 0.31 0.31 0.79
Rice Cultivation - - - - - - - - - - - - -
Ciurmitzm?iw'tu'a? 001 0.00 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.00 0.01 0.01 0.00 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01
Forest Fires - 0.03 0.01 0.00 0.02 0.10 0.02 0.11 0.09 0.03 0.07 0.09 0.13
Waste 7.09 7.23 7.34 7.23 7.11 7.02 7.06 7.06 5.69 5.01 4.93 4.96 4.77 5.44 5.49 5.02 4.20 3.51 3.02 1.37 6.73 7.00 7.21 7.40
Wastewater 0.93 0.99 0.99 1.00 1.00 1.00 1.00 1.00 100 1.00 1.32 1.32 1.32 1.32 1.32 1.33 .134 1.35 1.36 1.35 1.36 1.36 1.37 1.37

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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