© Copyright 2015 by K&L Gates LLP. All rights reserved.

David L. Wochner, PartnerK&L Gates LLP – Washington, DCTel. +1.202.778.9014david.wochner@klgates.com

U.S. Environmental Standards and Regulations for Shale Gas Development

U.S.-China Shale Gas Training ProgramEnvironmental Policy and Technology for Shale Gas DevelopmentDecember 3-4, 2015, Beijing, China

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Global Oil and Gas Counsel Across Five Continents

US REGULATORY CONSIDERATIONS

Natural gas activities impacted Environmental issues in the upstream natural gas sector Federal role in US shale gas regulation and

management Current issues impacting shale gas development Lessons learned from U.S. shale gas development

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OIL & GAS INDUSTRY ACTIVITIES IMPACTED BY ENVIRONMENTAL REGULATION Upstream – extraction and production

Facility siting Facility design Drilling and development activities Long-term operations

Midstream – gathering, processing, and transportation Facility siting and design (pipelines, compressor stations,

dehydration stations, etc.) Long-term operations

Downstream – exports, end uses, electric generation, petrochemical facilities

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ENVIRONMENTAL ISSUES IN THE OIL AND GAS E&PSECTOR Environmental assessment and planning Well pad siting and design / support facility siting and design Well construction – casing and cementing standards Hydraulic fracturing fluid chemical composition & disclosure Water withdrawal – location, amount & conditions Flowback and produced water management (storage, treatment &

disposal) Drill cutting and waste management Surface management of chemicals Emergency and contingency planning / training / response Air emissions (during construction, operations, transportation) Liability issues – for pre-existing conditions on land, releases during

development & operations; stray gas Response to community & environmental group concerns

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FEDERAL ROLE IN US SHALE GAS REGULATION

Most oil and natural gas well regulation in the United States is focused at state agency level Substantial experience accumulated over many decades in state

environmental and oil & gas management agencies

Historically, there has been relatively limited US federal agency involvement in regulation of upstream oil and gas production

Over the last few years the US federal government is increasingly involved, incrementally regulating and investigating various aspects of unconventional production activities

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THE AGENCIES – US EPA

Assessment of the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources – July 2015 Draft Study Indicates that EPA “did not find evidence [of] widespread, systemic

impacts on drinking water resources” from hydraulic fracturing Draft is currently undergoing peer review by the agency’s scientific

advisory board hydraulic fracturing panel The panel has held a series of public teleconferences and meetings -

next one is scheduled for December 3, 2015 Proposed rules/draft guidance regulating air emissions, including

methane and VOCs, from oil and gas sources – August 18, 2015 Establish control techniques guidelines (CTGs) for VOC emissions from

existing oil and gas sources in ozone nonattainment areas Amend the definition of “adjacent” for the purpose of EPA’s

determination whether to aggregate emissions from interconnected oil and gas sources.

Public comment period is scheduled to close on December 4, 2015

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THE AGENCIES – US EPA

Amendments to EPA GHG reporting program for oil and gas sources On October 22, 2015, EPA finalized amendments to its GHG

reporting program rules for oil and gas sources Expands the scope of the GHG reporting program to gathering

and boosting systems, completions and workovers of oil wells with hydraulic fracturing, and blowdowns of natural gas transmission pipelines

EPA’s “Waters of the United States” (WOTUS) rule EPA released the final WOTUS rule on May 27, 2015 Industry’s position is that it dramatically expands the definition of

the Clean Water Act jurisdiction to areas that are often dry Highly political and currently subject to significant litigation in

multiple federal trial and appellate courts

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THE AGENCIES – US EPA

Effluent Limitation Guidelines (ELGs) for the Oil and Gas Extraction Point Source Category On March 31, 2015, EPA released a proposed rule that would

prohibit the discharge of oil and gas wastewater to POTWs (which is generally consistent with current industry practice)

EPA Response to Environmental Integrity Project (EIP) Petition to add upstream oil and gas operations to Toxic Release Inventory (TRI) under EPCRA EPA’s October 22, 2015 response indicates that it plans to

propose a rule that would make natural gas processing facilities subject to the TRI reporting program, but not other upstream oil and gas sources

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THE AGENCIES – US EPA

EPA Inspector General Evaluation of EPA and State Regulation of Hydraulic Fracturing – July 16, 2015 Office of Inspector General’s final report identifies two issues in

need of improvement by EPA: (1) oversight of permit issuance for hydraulic fracturing using diesel fuels; and (2) a plan for responding to comments on a proposed rule regarding regulation of hydraulic fracturing chemicals

Permitting Guidance for oil and gas hydraulic fracturing activities using diesel fuels Final guidance released on February 11, 2014

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THE AGENCIES – US EPA

Study of induced seismicity related to underground injection disposal wells – February 6, 2015 EPA announced in January 2012 it was preparing a

“considerations document” of induced seismicity issues, focusing on well sites in West Virginia, Arkansas, and Texas

EPA Inspector General Evaluation of Efforts to Address Methane Emissions From Natural Gas Distribution Pipelines – July 25, 2014 Final report evaluates what actions EPA has taken to reduce

methane emissions from leaking distribution pipelines and recommends the agency consider whether further regulations are needed

Also suggests EPA work with the PHMSA to deal with methane leaks

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THE AGENCIES – US DEPARTMENT OF ENERGY

"Blueprint for a Secure Energy Future" – Spring 2011 President Obama directed the DOE Secretary of Energy Advisory Board

(SEAB) Natural Gas Subcommittee to make recommendations to improve the safety and environmental performance of natural gas hydraulic fracturing

The Subcommittee issued a report on August 18, 2011, recommending actions that federal and state agencies and industry should be taking to ensure safer operating practices

SEAB Task Force on FracFocus 2.0 – March 2014 Major recommendations include modifying FracFocus to accept

“systems” disclosure and commissioning a third party audit FracFocus accommodated many of the recommendations and

FracFocus 3.0 was announced on February 26, 2015 DOE consideration of unconventional production in LNG export

proceedings

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THE AGENCIES – US DEPARTMENT OF THE INTERIOR

BLM Rules on Hydraulic Fracturing on Federal Lands BLM’s final rules regulating hydraulic fracturing on federal lands were

published in the federal register on March 26, 2015 Focus is on disclosure of chemicals used in the fracturing process,

wellbore integrity and water use and disposal of flow back water On September 30, 2015, the U.S. District Court for the District of

Wyoming issued an order preliminarily enjoining BLM’s rules On November 27, 2015, Environmental groups appealed the court’s

order issuing the injunction to the 10th Circuit Court of Appeals Participation of U.S. Geological Survey in the interagency hydraulic

fracturing coordinating programs with DOE and EPA Venting and flaring

BLM has announced plans to develop new regulations on the conditions under which venting and flaring of gas production may be authorized during drilling or production operations on federal lands

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THE AGENCIES – FERC

FERC has jurisdiction over the construction and operation of interstate natural gas pipelines and LNG import and export facilities

The Sierra Club and several national and local environmental organizations have challenged repeatedly FERC’s failure to consider alleged impacts of upstream hydraulic fracturing activities when it is conducting an environmental review of midstream (pipelines) and downstream (LNG terminals) infrastructure They allege that FERC improperly failed to consider upstream “induced”

environmental impacts of hydraulic fracturing due to increased demand for natural gas for shipping on pipelines or exports through coastal facility

More generally, NGOs have increasingly targeted FERC with protests and letter-writing campaigns

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THE AGENCIES – MISCELLANEOUS AGENCIES

Department of Homeland Security Evaluating whether to allow barges carrying wastewater from hydraulic

fracturing on U.S. rivers Department of Health and Human Services

Centers for Disease Control and Prevention (CDC) has called for a wider study of potential public health effects of natural gas development

Agency for Toxic Substances and Disease Registry (ATSDR) participated in the analysis of groundwater samples from oil and gas incidents Wyoming and Pennsylvania and issued health consultations for the sites

Department of Agriculture George Washington National Forest included in its draft Forest Plan a

ban on horizontal drilling Securities and Exchange Commission

In August 2011, the SEC began requesting information from publicly-traded natural gas companies regarding hydraulic fracturing chemicals

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CONTINUING AND EVOLVING ISSUES What is appropriate role of federal vs state government?

What issues warrant uniformity or a floor of regulatory standards? What issues require flexibility to address differing conditions across

nation and geologic regions? What is appropriate role of local vs. state government? What is role of government standards vs. industry best practice

development? The long process for statutory and regulatory enactments

Legal challenges to authority of agencies to consider and regulate shale gas-related issues

Nexus between shale gas development and need for infrastructure to take that gas to market

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LESSONS FROM NORTH AMERICA & OTHER REGIONS Shale gas development is a progressive learning / adaptive

management process No regulations are perfect Environmental analysis / risk management require application of

both common sense and cumulative experience The public is a major stakeholder Industry’s reputation rests on the performance of every player –

embracing best practices is essential Integrated, comprehensive, and predictable environmental

regulations are critical to successful and environmentally beneficial development

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Questions?

ADDITIONAL REGULATORY MATERIALS

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Well Pad & Support Facility Siting

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TYPICAL WELLPAD

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WELL PAD SITING FOR UNCONVENTIONAL OIL AND GAS Average well pad = ~5 acres

(2000 m²), 2-3 acres after drilling Multiple wells – 4-8+ per

well pad State regulated

Laterals = 1.6-2.5 km Surface area impact is small

fraction of area tapped Lateral location, direction and

distance depend on formation characteristics

Horizontal drilling design gives some flexibility in well pad siting and impact avoidance

Access roads, gathering lines22

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SITING CONSTRAINTS

Federal law constraints Wetlands & “waters of the United States” - Clean Water Act §404 Endangered Species Act – designated habitats and avoidance of “takes”

States: Most establish siting constraints and setbacks from sensitive uses, with

provision for variances and exceptions under certain circumstances Examples:

1000 ft. from a water well, surface water intake, reservoir 200 ft. from a public park, forest, game land or wildlife area Areas that will impact threatened or endangered species 100 ft. from wetland > 1 acre in size Not in floodplain without variance and special designs 200/500 ft. from a building, absent landowner consent

Other issues Identification of closed / abandoned wells in area

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Facility Design and Construction

WELL CONSTRUCTION STANDARDS Casing & cementing – the most

critical element Example of modern standards = PA:

25 Pa. Code §§78.81-78.87 Casing and cementing plan for

every well Casing pipe standards Surface hole drilled on air,

freshwater, or freshwater based drilling fluid

Multi-string casing: conductor pipe; surface casing; intermediate casing; production casing

Surface casing to 50 ft. below fresh groundwater, cemented back to surface

Centralizers required every 150 ft.

Where cement circulation lost, additional casing strings required

Cement compressive strength standards (1200 psi in 72 hrs.)

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WELL PAD DESIGN & CONSTRUCTION

Requirements for erosion & sedimentation control plans and permits Partial exemption in Federal Clean Water Act § 402(l)(2) for discharges

composed entirely of stormwater from oil and gas exploration, production, processing and transmission operations which “are not contaminated by contract with, and do not come into contact with, ay overburden, raw material, intermediate products, finished product, byproduct or waste products ….”

State permitting mandates exceed CWA (E.g., 25 Pa. Code Ch. 102) State regulations

Impoundment design and lining systems Containment for tanks and chemical storage

Federal regulations Mandates of Federal Clean Air Act §112(r) “general duty” clause Oil Pollution Control Act – requirements for SPCC plans and

containment around tanks storing “oil”

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Chemical Use & Disclosure

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CHEMICAL DISCLOSURE REQUIREMENTS IN U.S.

Chemical disclosure requirements Hydraulic fracturing chemical disclosure primarily governed by state

laws Federal Emergency Planning & Community Right to Know Law

rules for hazardous chemicals present at sites > certain quantities EPA Toxic Substances Control Act

EPA granted and denied in part an NGO petition under TSCA May 2014 ANPRM – range of options under §8 re disclosure of chemicals used

in hydraulic fracturing

Balancing competing concerns: Public trust and disclosure of risks Information needs of environmental agencies and medical

professionals to manage and address risks or release events Service company concerns for protection of intellectual property

(proprietary recipes and practices)

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EVOLVING STATE CHEMICAL DISCLOSURE LAWS

Some states (e.g., Colorado, North Dakota, Pennsylvania, Texas) require chemical information disclosure to public via www.FracFocus.org Chemical Disclosure Registry or similar website Pennsylvania plans to transition away from FracFocus to a new state-

run online database by June 2016 Other states – information submitted only to state regulatory agency What must be disclosed:

Most: list of chemical ingredients in hydraulic fracturing fluid (CAS #)

Some: submission of material safety data sheets Some: maximum concentration or range of concentrations Exceptions: chemicals not disclosed to operator by mfg, vendor

or service providers, chemicals not intentionally added, chemicals that occur incidentally or unintentionally present in trace amounts

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CHEMICAL DISCLOSURE (CON’T)

When disclosures required: Before fracturing treatment, planned chemical use (a few states) After treatment, actual chemical use – 20-60 days after

completion (majority of states) But: emergency planning rule may separately require certain

disclosures to state and local emergency agencies Trade secret protections:

May limit disclosure to agency May require disclosure to agency but limit disclosure to public

(with exceptions for disclosure to medical personnel) Useful reference: Congressional Research Services, Hydraulic

Fracturing: Chemical Disclosure Requirements (June 2012)

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Chemical disclosure requirements in eastern statesPennsylvania West Virginia Ohio

What must be disclosed Chemical additive information (trade name, CAS#, max concentration, volume of base fluid)

Before: list of anticipated additivesAfter: list of additives actually used, max concentrations, etc. with completion report

Trade name, supplier, and total volume of all substances, including max concentration and CAS# of chemical additives

When Within 30 days of well completion, with completion report

Within “reasonable time” of completion, with completion report

Within 60 days of completion, with well log / completion report

Public disclosure Must submit chemical disclosure registry form on FracFocuswithin 60 days of HF

Disclosure through FracFocus

Disclosure through FracFocus

Trade secret / proprietary information protection

Need not be disclosed except for limited disclosure to health professionals and persons responding to spill or release

Need not be disclosed except for limited disclosure to health professionals and WVDEP during investigation

Trade secrets need not be disclosed except for limited disclosure to health professionals

References 58 Pa.C.S. §3222(b.1), 3222.1; 25 Pa. Code §78.122

W.Va. Code §22-6A-7(e)(5); WVCSR 35-8.

Ohio Rev. Code §1509.10

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Water Withdrawal & Consumption

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WATER RESOURCE REQUIREMENTS FOR SHALE DEVELOPMENT 1-5+ million gallons for each well

25-30% of water emerges as flowback water (much of that in relatively short time period)

Water withdrawn and staged; not drawn all at one time Opportunity to reuse return flow

In NE US, ~ 80% of flowback reported to be reused Still, significant supplemental water required for makeup

From an overall perspective, water requirements for shale gas development are comparatively modest Total of all wells < 1 major power plant; < ½ use of golf courses

But concerns regarding – Impacts to small local streams Cumulative impacts of many withdrawals in a watershed Maintaining a baseline low flow (seasonal impacts)

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APPROACHES TO WATER RIGHTS AND WITHDRAWALS Combination of common law (riparian rights in East, prior appropriation

in West) with increasing shift to regulatory approaches Example: Pennsylvania - requirement for Water Management Plan

approval by PA Dept. of Environmental Protection Identification of sources (by sub-basin) Specific impact questions for each type of source (streams,

groundwater, treated effluent, etc.) Monitoring plan and water withdrawal reporting requirements

Regional regulation in some basins Example: Susquehanna River Basin Commission

Project approval for all shale gas wells Review of both withdrawal and consumptive use Pass-by flow policy based on seasonal stream flow patterns

and % exceedance flow values. Encouragement of shared use and recycling

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KEY ISSUES IN WATER WITHDRAWAL MANAGEMENT Cumulative impact considerations – coordination of withdrawals by

multiple operators potentially impacting same waterbody or watershed

Pass-by flows – when should withdrawals be suspended during low flow periods in order to preserve water for downstream users and in-stream needs (wastewater assimilation and aquatic life) SRBC passby flow policy

West Virginia Water Withdrawal Guidance Tool

Policies and practices to encourage use of “non-fresh” water sources (such as treated wastewater effluent)

Policies and practices to encourage flowback and produced water reuse and recycling

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PENNSYLVANIA WATER WITHDRAWAL REGULATION

Pennsylvania water management plans (58 Pa.C.S. §3211(m))

Oil & gas operator must submit to PaDEP showing sources to be used, and measures to protect environment and other uses

PaDEP review considers quantity, withdrawal rate, timing and passby flow conditions to determine that plan (1) will avoid adverse impact upon quantity and quality of water available to other users; (2) maintain existing uses of water source; (3) not cause adverse impact to water quality in watershed as a whole; and (4) include a reuse plan for fluids used to fracture wells

SRBC, DRBC approved withdrawals are presumed to meet criteria

Section 3211(m)(4) declares that compliance with a DEP-approved water management plan “shall be deemed to satisfy the laws of this Commonwealth.” (Signal – common law restrictions on place of use may be trumped)

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WEST VIRGINIA & OHIO WATER WITHDRAWAL REGULATION West Virginia water management approach (W.Va.CSR 35-8-1 et seq.)

Water management plan required if withdrawals for drilling, fracturing or stimulation of a well will exceed 210,000 gallons in any month Identify source, location and amount of anticipated withdrawals & downstream uses Demonstrate sufficient in-stream flow will be available downstream of withdrawal.

Sufficient in-stream flow is maintained when pass-by flow protective of identified stream use is preserved

WVA Water Withdrawal Guidance Tool – provides real-time data to determine suitability of conditions for withdrawal

Ohio water withdrawal regulation (Ohio Rev. Code §1501.32 et seq.) New requirement for ground and surface water source identification in gas well

applications (Ohio Rev. Code §1509.06(A)(8)(a)) Withdrawal permit program administered by ODNR for Diversions out of Ohio

Basin > 100,000 gpd Withdrawals statewide that would result in a new or increased consumptive use

> 2 mgd averaged over any 30-day period New or increased capacity for withdrawal in Lake Erie watershed ≥ 1 mgd;

withdrawal capacity in high quality waters in Lake Erie watershed ≥ 100,000 gpd (Ohio Rev. Code §1522.12)

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SUSQUEHANNA RIVER BASIN COMMISSION (SRBC)

Project review (18 CFR §§ 806.1-806.16, 806.22) Any withdrawal or consumptive water use for shale gas well Any import of water into basin or export of water from basin Approval by rule process for consumptive uses Streamlined process for water sharing

Recent developments New approach to low flow protection / setting passby flow

conditions Proposed rule restricting withdrawals in headwater streams

(watersheds < 10 sq. mi.) (77 Fed. Reg. 75915 (Dec. 26, 2012)) Basinwide consumptive use study launched to evaluate

cumulative water use and availability by subbasin, targeted for completion in December 2015(http://www.srbc.net/planning/cwuas.htm)

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SRBC’s low flow protection policy & technical guidance1

Old approach – use of Pennsylvania Instream Flow Model for most cold water fish streams; 20% of average daily flow for other streams

New approach – tiered arrangement, with watersheds classified into aquatic resource class (ARC) based on area, with monthly exceedance values

ARC Description Drainage Area (mi2)

De minimis threshold

Passby flow

1 Headwaters ≤ 10 None Monthly P702 Creeks 10-50 5% monthly P95 Monthly P753 Small rivers 50-200 5% monthly P95 Monthly P804 Medium tributary rivers 200-1000 5% monthly P95 Monthly P855 Medium mainstem rivers 1000-5000 10% monthly P95 Monthly P906 Large Rivers ≥5000 10% monthly P95 Monthly P95

1 http://www.srbc.net/policies/lowflowpolicy.htm

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Wastewater Management

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THE FLOWBACK/WASTEWATER CHALLENGE

~ 1-5 million gallons required for a frac job; 25-30% of water emerges as flowback water (much of that in relatively short time period)

Need to develop representative characterization of flowback and produced waters Example: Marcellus Shale flowback water contains 4-25% salts

(TDS typically exceeds 100,000 mg/l) Other constituents: barium, strontium, naturally occurring radioactive

materials (NORM), oil and gas, trace amounts of chemicals added during hydraulic fracturing

Some flowback (wet gas areas) contains condensate / natural gas liquids

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WASTEWATER MANAGEMENT CHALLENGE (CON’T)

Need to store and manage to avoid releases Lined impoundments Frac tanks Types of secondary containment

TDS is hard to remove economically Streams have limited assimilative capacity Options:

Evaporation (in dry areas, such as Texas) Reverse osmosis (lower TDS water) or evaporation/crystallization

(higher TDS water) Underground injection of brine

Industry’s rapidly evolving solution => recycling and reuse of flowback and produced water in subsequent operations Requires provisions for storage, treatment, blending and

coordinated operations

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A MATRIX OF WASTEWATER MANAGEMENT REGULATIONS

Water quality laws and regulations Federal Clean Water Act State counterpart water quality laws

“Solid waste” laws and regulations Resource Conservation and Recovery Act (RCRA) – hazardous

waste regulation under Subtitle C; other waste regulation under Subtitle D

State waste laws – e.g., Pa. Solid Waste Management Act Safe Drinking Water Act – underground injection control program State oil and gas laws

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FEDERAL CLEAN WATER ACT

Structure: Regulates discharge of “pollutants” via a “point source” to “navigable

waters of the United States” through the NPDES permit system Under CWA §§ 301, 306, 307, EPA sets national technology based

treatment standards (referred to as “effluent limitation guidelines) Under CWA § 303, states must designate protected uses of streams

and establish instream water quality criteria to protect such uses States (or EPA) issue permits for discharges from point sources,

establishing effluent limits based on the more stringent of technology-based limits or limits to protect instream water quality (“water quality based effluent limits”)

Standards: Produced water and drilling fluids may not be discharged to navigable

waters from a well site (EPA ELG, 40 C.F.R. Part 435) Off-site disposal through centralized treatment works allowed – treatment

standards set EPA proposed rule would prohibit discharge of oil and gas waste water to

POTWs (80 Fed. Reg. 18557 (Apr. 7, 2015))

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EXAMPLE OF RECENT STATE REGULATION –PENNSYLVANIA

TDS Discharge Limitations: 25 Pa. Code §95.10 (published Aug. 21, 2010) Treatment requirements for new and expanding loadings of total

dissolved solids (TDS) Wastewater source reduction strategy (maximizing reuse) required for

natural gas operations by 8/22/2011 New discharges from natural gas operations allowed only through

centralized treatment facilities with strict discharge limits (500 mg/l TDS, 250 mg/l Chlorides, 10 mg/l Barium and Strontium)

Continuing debate concerning potential Ch. 93 instream water quality criteria for Chlorides for aquatic life protection

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Underground injection of flowback or treatment residuals

Safe Drinking Water Act – Underground Injection Control (UIC) program Federal Energy Policy Act amendment excludes

from definition of “underground injection” the “underground injection of fluids or propping agents … pursuant to hydraulic fracturing operations related to oil, gas or geothermal production activities.” 42 U.S.C. §300h(d).

But wells used for disposal of brine or waste require UIC permits

Permit program administered by EPA or by authorized state (holding “primacy”)

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UIC (CON’T)

Federal standards (40 C.F.R. Part 146) Class II UIC wells = wells used for disposal of fluid brought to

surface from conventional oil and gas production Requires evaluation of potential impacts within area of endangering

influence (§146.6) Plan for corrective action to prevent fluid movement into drinking

water sources (§144.55, 146.7) Identification of all wells within area of review penetrating formations

affected by pressure increase Demonstration of mechanical integrity Specific construction standards (casing, cementing, logging,

testing) (§146.22) Detailed monitoring requirements (§146.23)

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UIC (CON’T) Pennsylvania

Regulated under 25 Pa. Code §78.18 – provides for permitting of disposal or enhanced recovery wells via Oil & Gas Act well permit

Must submit to DEP a copy of UIC permit and application submitted to EPA under Part 146

Requires control and disposal plan meeting requirements of 25 Pa. Code §91.34

West Virginia Class II permit required under W.Va. Code R. §47-13-13.3

New York Div. of Mineral Resources regulates drilling, operation of brine disposal

wells under NY Envtl. Conservation Law §23-0305(14) DRBC

DRBC invokes project review jurisdiction over UIC wells in the Delaware Basin

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Waste Management

FEDERAL VS. STATE “WASTE” REGULATION Federal RCRA: Produced water and drilling fluids are exempt

from regulation as “hazardous waste” (unused fracturing fluids and hydraulic fluids are not exempt)

State waste management: Typically applies to both hazardous and non-hazardous waste Definition of “solid waste” – includes solid, liquid and

contained gaseous material that is discarded Drill cuttings / wastes subject to state management and

disposal standards Example: PA oil and gas regulations – requirements for waste

management plan PA residual waste management regulations

Current issues: appropriate methods of waste management / TENORM concerns

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AIR EMISSIONS

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AIR EMISSIONS

Sources: Fugitive emissions from piping or tank leaks – VOCs, BTEX

(controlled by flares and vapor recovery units) Tanks, pits or ponds (condensate separation) - VOCs Drilling rig engines (diesel engines) – NOx, CO Compressor station engines – NOx, formaldehyde (controlled

by ultra lean burn engines and oxidizers) Dehydration facilities – small quantities of ethylene glycol

Regulations Complex interplay between federal and state rules

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AIR EMISSION ISSUES

Emission regulation depends on total emissions from facility, and whether facility qualifies as a “major source”

“Major source” definition refers to any source or group of stationary sources “within a contiguous area” and “under common control” 42 U.S.C. §7661(2) (See Pa. definition of “facility” - §121.1)

“Major source” emission thresholds differ depending upon the pollutant, the nature of the source, the area’s attainment status, and the regulatory program at issue

Implication: When will natural gas production / processing facilities (including compressor stations) be considered a single “facility” for determining “major source” status?

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AIR EMISSION ISSUES – “AGGREGATION”

Current EPA Regulations – 3 requirements:(1) Same industrial grouping (same two digit SIC code)(2) Under common control of same entity(3) Contiguous or adjacent properties

EPA Guidance: Consider both distance and “functional interrelatedness” / “functional

interdependence” to determine adjacency (no formula or bright lines)

Sixth Circuit Court of Appeals – Summit Petroleum v. EPA (2012): Do not consider “functional interrelatedness” – only distance EPA attempted to limit the effect of Summit Petroleum to the Sixth

Circuit (KY, MI, OH, TN), but this position was rejected by the D.C. Circuit in NEDACAP v. EPA (May 2014)

In response, EPA has proposed new rules defining “adjacency” specifically for the oil and gas sector – two “co-proposals”:(1) Adjacent if on sites located within ¼ mile of one another(2) Adjacent if separated by less than a ¼ or “if there is an exclusive

functional interrelatedness”

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NEW SOURCE REVIEW (NSR)

Pre-construction permit requirements that apply to “major stationary sources” of “regulated NSR pollutants” New major sources “Major modifications” to “major stationary sources”

Regulated NSR pollutants include: The 6 criteria pollutants (PM, ground-level ozone, carbon

monoxide, sulfur oxides, nitrogen oxides, lead) Other pollutants “subject to regulation” under the CAA Supreme Court in UARG v. EPA (2014): GHG emissions alone cannot trigger major source permitting

requirements, but are subject to best available control technology (BACT) requirements if emissions of another pollutant exceeds major source thresholds

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NSR IN NON-ATTAINMENT AREAS

Applies to sources that exceed major source thresholds for one or more of the 6 criteria pollutants, if the source is in an area that is in non-attainment for that pollutant Major source = potential to emit ≥100 tpy of a regulated NSR pollutant; 50

tpy of VOCs or 100 tpy of NOx in most areas of PA (25 tpy of VOC or NOx in SE PA) [more stringent in portions of NE corridor]

Must implement Lowest Achievable Emission Rate (LAER) + obtain offsets for VOC or NOx emissions

Permit required before commencement of any construction

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NSR IN ATTAINMENT AREAS - PREVENTION OF SIGNIFICANT DETERIORATION (PSD)

Pre-construction permit required for major sources

Emissions impact analysis

May well require ambient monitoring for up to 1 year

Modeling to show cumulative emissions will not cause NAAQS exceedance

Class 1 area impact analysis

Mandate for use of best available control technology (BACT)

Not quite as stringent as LAER

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OPERATING PERMITS

Major stationary sources must also apply for and maintain Title V operating permits

Compiles all requirements that apply to a facility in one federally enforceable permit

More onerous recordkeeping than otherwise would apply

Must be renewed every five years

No new substantive emissions controls

Biennial certification required

Minor sources still must comply with state requirements

State technology standards

PA Best Available Technology (25 Pa. Code §127.12(a)(5))

Some states require pre-construction and/or operating permits for oil and gas facilities as well

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AIR STANDARDS National Emission Standards for Hazardous Air Pollutants

(NESHAP) EPA also regulates hazardous air pollutants (HAPs) Examples: BTEX (benzene, toluene, ethyl benze, xylene);

formaldehyde National Emissions Standards for HAPs (NESHAPs) apply to

specific categories of sources Both new and existing sources Area sources v. major sources HAP emissions are not aggregated – CAA § 112(n)(4)

Maximum Achievable Control Technology (MACT) New Source Performance Standards (NSPS) EPA promulgates NSPS that apply to categories of sources

imder CAA § 111(b) NSPS apply only to new, modified, and reconstructed

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NESHAPS AND NSPS FOR THE OIL AND GAS SECTOR

Issued in 2012, minor amendments in 2013, 2014, and 2015

Directly regulates VOCs, achieves reductions in GHGs as a co-benefit

NSPS – 40 C.F.R. Part 60 Subpart OOOO (“Quad O”) Requires “green completions” at natural gas wells beginning January 1,

2015 Also regulates emissions of VOCs from:

Compressors and pneumatic controllers in the production & processing segments

Storage vessels in the production, processing, transmission, and storage segments

Leaking components (and SO2 emissions) at processing plants NESHAPs (Part 63 Subpart HH & HHH) apply to glycol dehydrators,

storage vessels, and equipment leaks at processing plants

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NEW EPA METHANE AND VOC PROPOSALS Proposed NSPS for Methane and VOCs

Update to 40 CFR Part 60, Subpart OOOO (“Quad-O”) Would directly regulate methane emissions Would impose requirements on new categories of sources, including

hydraulically fractured oil wells and natural gas compressor stations Would impose leak detection and repair (“LDAR”) requirements on well

sites, gathering/boosting stations and compressor stations Would apply only to new/modified/reconstructed sources

Draft Control Techniques Guidelines (CTGs) Would apply to existing oil and gas sources in ozone non-attainment

areas (including all of Pennsylvania) Includes Reasonable Available Control Technology (RACT)

recommendations for controlling VOCs from covered sources Once finalized, states would be required to develop rules imposing

RACT on existing oil and gas facilities Potential future regulation under CAA §111(d)(1)

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GREENHOUSE GAS (GHG) REPORTING RULES

40 C.F.R. Part 98, Subpart W

Reports due annually on March 31

Applies to “facilities” that emit 25,000 metric tons of CO2e / year 25,000 metric ton threshold includes emissions from stationary fuel

combustion, equipment leaks, vented sources, and flares

Should not aggregate emissions from compressor stations along a single transmission pipeline (40 C.F.R. §98.6)

But should aggregate emissions from all well pads owned or operated by same entity in a single hydrocarbon basin (40 C.F.R. §98.238)

EPA finalized revisions to Subpart W in October 2015 that add reporting requirements for gathering and boosting systems, oil wells, and transmission pipeline blowdowns

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Thank You

David L. Wochner, Partner

K&L Gates LLP1601 K Street, NW

Washington, DC 20006202.778.9014

david.wochner@klgates.com