K&

L Gates O

il & G

as Overview

Oil & Gas Experience

Contents Our Firm

World Office Map

A Brief Firm Overview of Our Firm

Value Proposition

K&L Gates Offices

Energy, Infrastructure and Resources Brochure

Oil & Gas Industry Description

International Oil & Gas Brochure

Upstream and Midstream Oil & Gas Brochure

Asia Oil & Gas Brochure

Alaska Oil and Gas Brochure

Our Team

K&L Gates Oil & Gas Practitioners

Additional Materials

“K&L Gates Represents Oil and Gas Producers in Major Pennsylvania Supreme Court Victory”, Oil & Gas Alert, by David R. Overstreet, V. Abe Delnore, April 4, 2012.

“Final Implementation of Pennsylvania’s Gas and Hazardous Liquids Pipelines Act”, Oil & Gas Alert, by Daniel P. Delaney, George A. Bibikos, Bryan D. Rohm, March 2, 2012.

“Two Birds by the Pit: Courts Split Over Well Operator Liabilities under the Federal Migratory Bird Treaty Act”, Oil & Gas Alert, by George A. Bibikos, Tad J. Macfarlan, Stephen J. Matzura, February 21, 2012.

“Pennsylvania Legislation Authorizing Counties to Levy Unconventional Gas Well Fee Signed Into Law”, Oil and Gas Alert, by Raymond P. Pepe, February 15, 2012.

“New Pennsylvania Oil and Gas Law Targets Unconventional Gas Operations for Heightened Regulatory Oversight”, Oil & Gas Alert, by Tad J. Macfarlan, R. Timothy Weston, Craig P. Wilson, February 14, 2012.

“Pennsylvania’s Oil and Gas Act Amended to Require ‘Uniformity’ with Respect to Municipal Ordinances Regulating Oil and Gas Operations”, Oil & Gas Alert, by K&L Gates includes lawyers practicing out of more than 40 offices located in North America, South America, Europe, Asia and the Middle East, and represents numerous GLOBAL 500, FORTUNE 100, and FTSE 100 corporations, in addition to growth and middle market companies, entrepreneurs, capital market participants and public sector entities. For more information about K&L Gates or its locations and registrations, visit www.klgates.com. This publication is for informational purposes and does not contain or convey legal advice. The information herein should not be used or relied upon in regard to any particular facts or circumstances without first consulting a lawyer. ©2012 K&L Gates LLP. All Rights Reserved. K&L Gates LLP

K&L Gates LLP

Christopher R. Nestor, Walter A. Bunt, Jr., David R. Overstreet, February 9, 2012.

“Pennsylvania’s New Gas and Hazardous Liquids Pipeline Act”, Oil and Gas Alert,by Daniel P. Delaney, George A. Bibikos, Bryan D. Rohm, January 3, 2012.

“EPA to Require Chemical Disclosure under TSCA by Hydraulic Fracturing Fluid Manufacturers”, Oil & Gas Alert, by Cliff L. Rothenstein, Tad J. Macfarlan, December 2, 2011.

“PaDEP Issues Interim Guidance on Air Aggregation, Moves Away From ‘Functional Interdependence’ Test”, Oil & Gas Alert, by David R. Overstreet, Tad J. Macfarlan, November 11, 2011.

“Ohio EPA Releases Draft General Permit for Oil and Gas Well-Site Production Operations”, Oil and Gas Alert, by Bryan D. Rohm, David R. Overstreet, Craig P. Wilson, November 3, 2011.

“Battles Over the Federal Policies Regulating Hydraulic Fracturing”, Public Policy and Law Alert, by Cliff L. Rothenstein, Michael W. Evans, Cindy L. O'Malley, October 17, 2011.

“Third Circuit Gives Natural-Gas Producers Important Ammunition for Obtaining Expedited Injunctive Relief from the Courts”, Oil and Gas Alert, by Nicholas Ranjan, George A. Bibikos, October 10, 2011.

“Is Marcellus Shale a ‘Mineral,’ and Who Owns the Natural Gas in the Shale?”, Oil and Gas Alert, by George A. Bibikos, Bryan D. Rohm, September 20, 2011.

“West Virginia Governor Orders WVDEP to Enact Marcellus Shale-Specific Regulations”, Oil and Gas Alert, by Brian P. Anderson, R. Timothy Weston, July 29, 2011.

“North Carolina Takes a Step Closer to Shale Gas Production”, Oil & Gas Alert, by Stanford D. Baird, James L. Joyce, July 22, 2011.

“The Chesapeake Bay Foundation Settlement – Changing Directions for E&S Regulation of Oil & Gas Projects”, Oil and Gas Alert, by R. Timothy Weston, July 6, 2011.

“Why the Public Utility Commission's Laser Northeast Decision Will Not Lead to Regulation of All Natural Gas Gathering and Transportation Pipelines in Pennsylvania”, Oil and Gas Alert, by Daniel P. Delaney, July 1, 2011.

OnStream, K&L Gates' Newsletter for the International Oil & Gas Industry, K&L Gates Oil & Gas Publication, Summer 2011.

“A New Conservation Law for Pennsylvania?”, Oil & Gas Alert, by George A. Bibikos. May 10, 2011.

Water and Wastewater Issues in Conducting Operations in a Shale Play – The Appalachian Basin Experience, Rocky Mountain Mineral Law Foundation, Development Issues in Major Shale Gas Plays, by R. Timothy Weston, December 2010.

our firm

Global legal counsel in more than 40 fully integrated officeson four continents.

United StatesAnchorage, Austin, Boston, Charleston, Charlotte, Chicago,

Dallas, Fort Worth, Harrisburg, Los Angeles, Miami, Newark,

New York, Orange County, Palo Alto, Pittsburgh, Portland,

Raleigh, Research Triangle Park, San Diego, San Francisco,

Seattle, Spokane, Washington, D.C.

South AmericaSão Paulo

EuropeBerlin, Brussels, Frankfurt, London, Milan, Moscow,

Paris, Warsaw

Middle EastDoha, Dubai

AsiaBeijing, Hong Kong, Shanghai, Singapore, Taipei, Tokyo

A Brief Overview of Our Firm

K&L Gates operates at the critical

crossroads of the 21st century, offering

clients experienced legal counsel at the

intersection of globalization, regulation,

and innovation.

A Brief Overview of Our FirmK&L Gates delivers legal services on an integrated and global

basis, with nearly 2,000 lawyers located in more than 40 cities

across four continents.

We represent a broad array of leading global corporations in

every major industry, capital markets participants, and ambitious

middle-market and emerging growth companies. We also serve

public sector entities, educational institutions, philanthropic

organizations, and individuals. Our lawyers counsel clients on their

most sophisticated legal challenges in all areas of corporate and

regulatory law as well as litigation.

We are leaders in legal issues relating to industries critical

to the economies of both the developed and developing

worlds—technology, manufacturing, energy, transportation,

telecommunications, financial services, and life sciences,

among others.

We encourage our lawyers to provide

pro bono legal representation and

to participate in other charitable,

community, educational, and

professional activities. In addition,

we actively recruit professionals

whose business and life experiences

reflect the diversity of our clients

and our communities. At K&L

Gates, we believe diversity of

opinions, attitudes, experiences, and

perspectives makes for a stronger

work envrionment and more creative

client solutions.

Apply a Global PerspectiveK&L Gates is positioned at strategic intersections of the global economy, with one

of the largest contingents of lawyers and offices across the United States of any

law firm and strong local presence in key capital cities and world commercial

and financial centers. Our extensive latticework of lawyers, practices, and offices

creates a worldwide network to serve our clients’ growing international needs.

With approximately 300 lawyers based in Berlin, Brussels, Frankfurt, London,

Milan, Moscow, Paris, and Warsaw, K&L Gates is located in Europe’s largest

economies. We are well-situated to meet clients’ legal challenges arising under the

U.K., German, French, Belgian, Italian, Russian, Polish, and EU legal regimes.

Our lawyers’ on-the-ground experience and knowledge enable them to give clients

valuable insights into local business policies and practices. We have advised

clients at every stage of their development in Europe, from local start-ups to mid-

sized overseas companies looking to enter the market to experienced global busi-

nesses with well-established operations in the region.

K&L Gates also has one of the largest international practices in Asia of any U.S.

law firm, with comprehensive coverage in Greater China. Our commitment to the

region began in 1996 with the opening of our Hong Kong office. Since then, we

have steadily built our Asia practice to more than 100 legal professionals in our

offices in Beijing, Hong Kong, Shanghai, Singapore, Taipei, and Tokyo. Our lawyers

in Asia are noted for their seamless service to clients across multiple jurisdictions

as well as their innovative approach to intellectual property issues, dealings with

government authorities, litigation and dispute resolution, and transactional matters.

Our Doha and Dubai offices serve as hubs for our work in the Middle East, a

key crossroad for international trade and finance. Our team in the Gulf Region

serves Middle Eastern clients both domestically and abroad, as well as interna-

tional clients doing business in the Middle East. We assist our clients in an array

of matters, including projects and construction, corporate, dispute resolution,

finance, energy and infrastructure, and media and technology, among others.

Our São Paulo, Brazil office is a strategic location from which K&L Gates serves

clients’ needs in South America. Our lawyers in São Paulo offer distinct capabilities

in international finance and capital markets, investment management, construction

and project development, tax, and arbitration.

Our corporate and transactional prac-

tice is one of the most substantial in

the profession. Each year, we complete

hundreds of mergers and acquisi-

tions and public and private debt

and equity offerings. Our lawyers in

the United States, Europe, Asia, and

South America are highly experienced

in cross-border mergers and acquisi-

tions, securities, regulatory, tax, and

financing transactions. We maintain a

balance between company-side and

capital-markets clients in virtually every

industry segment.

Several publications have acknowl-

edged our lawyers as leaders in their

fields. We are routinely ranked among

leading law firms in the area of fund

client representations in the mutual

fund industry. Private Equity Analyst

regularly ranks K&L Gates as one of

the “most active law firms” worldwide

for both private equity/venture capital

transactions and fund formation. We

are also recognized as a leader in

the investment management finance

industry, hedge funds, and ESOPs.

We have a sophisticated and growing

global finance practice in areas

including structured finance; secu-

ritization; derivatives; structured

products; CDOs; real estate finance;

municipal finance; and mezzanine,

leveraged, and acquisition finance.

In support of our work with emerg-

ing growth companies, we have a

substantial alternative capital markets

practice, including AIM listings,

PIPEs, reverse takeovers, and SPACs.

Our lawyers are also highly regarded

for their integrity and experience in the

arena of corporate governance, includ-

ing independent corporate investiga-

tions. Our experience includes serving

as lead examiner in both the New

Century and WorldCom bankruptcies

and in the internal CBS investigation of

the “60 Minutes” story involving former

President George W. Bush’s National

Guard service.

Our tax-exempt organizations practice

represents some of the world’s largest

and best-known private and corporate

foundations and other charitable

organizations. We advise these organi-

zations on a wide variety of corporate

and tax issues related to their creation,

operation, and dissolution.

The K&L Gates private clients prac-

tice represents individuals including

business owners, entrepreneurs,

executives, celebrities, and artists in

lifetime tax planning, wills, probate,

administration of estates, and tax and

trust litigation.

We also have extensive experience

in all areas of real estate law, offer-

ing national coverage in the United

States through 24 offices as well as a

comprehensive practice in the United

Kingdom, Germany, Dubai, and certain

key markets in Asia. Our clients

call upon us to help solve the entire

spectrum of their real estate legal

needs, including development and

construction, leasing and acquisitions,

financing matters, tax advice and entity

structuring, sustainable development

issues, real estate services, and real

estate litigation.

Private Equity Analyst regularly ranks K&L Gates

as one of the “most active law firms”

worldwide for both private equity/venture

capital transactions and fund formation.

Understand Critical Business Issues

Businesses and individuals across the

globe turn to K&L Gates to handle their

“must win” disputes. Our litigation and

dispute resolution lawyers are at their

best when handling complex, multidi-

mensional commercial and regulatory

disputes. They are tough, innovative,

and committed to our clients’ interests.

Our dispute resolution practice

includes international arbitrations,

civil and criminal trials, deal litiga-

tion, domestic and international class

actions, and appellate work. We have

helped resolve disputes in the most

nuanced and complex areas, including

intellectual property, construction law,

product liability, employment, toxic

tort, antitrust and trade regulation, and

securities enforcement.

Litigation is clearly not the answer to

every dispute. We routinely partner

with clients to resolve disputes through

arbitration, mediation, or other alter-

native dispute resolution techniques

when they are the best solution to

promote our clients’ business objec-

tives. K&L Gates has handled arbitra-

tions administered by virtually all of

the major international and U.S.- and

U.K.-based institutions. To reduce the

risk of future litigation, we also work

with clients to develop compliance

programs and provide training.

Our dispute resolution lawyers are

recognized as among the foremost

practitioners in their fi eld. We have

been rated a leading practice in the

representation of corporate policy-

holders in the insurance coverage

area and as a leading litigation fi rm for

the fi nancial services sector. Addition-

ally, our litigation engagements have

helped to shape intellectual property

law in the fast-moving technology

sector. Our acclaimed e-Discovery

Analysis and Technology (e-DAT)

Group also continues to pave the way

nationally and internationally in the

exploding fi eld of e-discovery.

In our role as national coordinating

counsel for companies facing mass tort

challenges, we have at once mounted

successful defenses and achieved

cost-saving effi ciencies for our clients.

Our litigation and dispute resolution

capabilities and extraordinary achieve-

ment within DuPont’s Global Primary

Law Firm Network have earned us the

DuPont Meeting the Challenge Award

six times.

Creatively Resolve Disputes

Guided by a desire to improve

effi ciency and reduce costs for

clients, our e-Discovery Analysis and

Technology (e-DAT) Group uses and

helped develop Attenex Patterns™,

a document mapping software

used to review massive amounts of

electronic records. We rely on similar

effective applications of technology

to deliver enhanced services and

increased global integration to clients

throughout the fi rm. In recognition

of our technological innovations, CIO

magazine awarded the fi rm its annual

CIO Award in 2011, 2007, 2004,

2003, and 2002.

Navigate the Regulatory and Policy MazeK&L Gates’ regulatory lawyers guide clients through regulations set forth by govern-

ments at all jurisdictional levels in the United States, Europe, Asia, and other venues

around the world. Our lawyers bring unique perspective to regulatory matters, having

held positions with agencies such as the Securities and Exchange Commission, the

Federal Communications Commission, the Federal Trade Commission, the Depart-

ment of Justice, and the Environmental Protection Agency.

The firm’s regulatory and policy practice cuts across the many disciplines that

require highly specialized knowledge and experience to address governmental

regulation of the private markets. One of our key regulatory practices is in the

diversified financial services area. We represent a large majority of the major finan-

cial institutions and securities firms in a variety of disciplines, and our investment

management and consumer financial services practices are perennial leaders.

Drawing on the combined experience of our securities enforcement group, our

lawyers counsel companies in a variety of matters involving corporate compliance,

internal investigations, and white collar crime. The many SEC alumni within our

practice provide the institutional insight and connections needed to deal with our

clients’ compliance needs.

The K&L Gates Global Government

Solutions® initiative brings together

our firm’s diverse practices and teams

to proactively influence regulatory

change and other governmental

actions, develop business solutions

to regulatory issues, and vigorously

defend enforcement actions around

the globe. With more than 400

experienced professionals who have

served in government agencies on four

continents, K&L Gates is equipped to

assist clients with virtually any legal

issue involving government.

Our policy group is the largest of any

fully integrated global law firm. The

group of over 60 bipartisan lawyers and

policy professionals includes former

U.S. House and Senate members,

former Republican and Democratic

counsel, and staff to the House and

Senate leadership committees.

We represent clients’ interests before

the U.S. Congress, the courts, the

executive branch, and regulatory agen-

cies. The public policy group strives to

understand a policy issue from every

direction—substantively and politi-

cally—and to use the collective knowl-

edge and more than 500 years of the

team’s government experience to help

clients achieve their objectives.

K&L Gates’ public finance lawyers

serve as bond counsel for well over

250 financings per year with Thomson

Reuters ranking the firm sixth in bond

counsel competitive offerings in the first

half of 2011. Additionally, The Bond

Buyer ranked K&L Gates first in Oregon,

second in Alaska and Washington, and

second in the Far West region for the

dollar volume of bond issues handled in

the first half of 2011.

Our environmental lawyers help clients

develop financially sensible solutions

that address environmental regula-

tions. In the past several years, we

have handled more than 400 distinct

environmental matters in the United

States alone.

K&L Gates also fields an international

energy, infrastructure, and resources

practice, advising clients in matters

involving litigation, international arbi-

tration, mergers and acquisitions,

Foreign Corrupt Policy Act, concession

deals, permitting, and downstream

construction projects.

In another rapidly evolving area,

K&L Gates’ U.S. food and drug prac-

tice offers comprehensive legal and

regulatory counsel to companies and

other organizations regulated under the

federal Food, Drug, and Cosmetic Act.

Other active regulatory practice areas

include data protection, anti-money

laundering, communication, government

contracts, antitrust/competition, health

care, school districts, and transportation.

K&L Gates lawyers advise and rep-

resent some of the world’s most

prominent companies on cutting-edge

IP issues, infl uencing technology and

intellectual property law as our clients

shape their industries.

More than 225 of our lawyers, includ-

ing approximately 105 registered

patent lawyers, many with engineer-

ing or advanced science degrees,

devote their practice to protecting and

commercializing clients’ intellectual

property assets, whether in the form

of patents, trademarks, copyrights, or

trade secrets. In addition to our tradi-

tional IP work, we are at the forefront of

intellectual property asset monetization,

using capital markets and other fi nan-

cial transactions to achieve our clients’

goals. In 2011, IP Today ranked K&L

Gates second out of more than 200

fi rms and individuals who represented

trademark registrations in 2010, based

on the number of registrations issued.

Our patent litigation lawyers bring not

only knowledge of the patent laws

and an understanding of the substan-

tive technical issues embraced by the

patent, but also the skill and resources

to manage large, complex commercial

litigation. K&L Gates patent lawyers have

been involved in cases spanning a broad

spectrum of technologies, from hospital

equipment and medical devices to com-

puter networking equipment to sports

equipment and outdoor clothing.

Our lawyers have literally written the book

on electronic commerce, helping clients

in all industries address new issues

raised by electronic contracting, fi nancial

regulations, privacy, and Internet issues.

K&L Gates ranked No. 2 in IP Today’s 2011

list of the busiest trademark practices

in the United States.

Uncover and Protect Value

Establishing and maintaining

a diverse, fully inclusive, and

community-minded workforce is

essential to a strong law firm. At

K&L Gates, we are committed to

fostering these values to enrich the

experience of our lawyers, reflect the

communities in which we live and

work, and better serve our clients.

Our Value Proposition

At K&L Gates, we understand that a law fi rm

with the resources to counsel on a variety of

issues around the world can help you gain

two valued assets: time and peace of mind.

In today’s 24-hour global marketplace, your ability to tackle legal challenges

quickly, in locations both far and near, is crucial.

At K&L Gates, we understand that a law fi rm with the resources to counsel on a

variety of issues around the world can help you gain two valued assets: time and

peace of mind. By working with one fi rm as preferred legal counsel, you have a

cost-effective partner that knows your business, your industry, your strengths,

and your challenges.

Through our experience as preferred legal counsel for companies such as

DuPont, United Technologies, and Philips, we are strongly positioned to serve

as an effective and comprehensive service provider. We offer a broad global

platform, ensuring that we can meet our clients’ legal needs no matter the issue

or location. As a matter of course, we collaborate with clients, using standard

tools and systems to build a successful legal team.

Drawing on our worldwide resources and seamless service capabilities, we

deliver value to our clients through effi cient and effective representations.

Our Value Proposition

Our Experience as Preferred Legal CounselFor more than a decade, K&L Gates

has been part of DuPont’s Global

Primary Law Firm Network. Prior to

1992, DuPont had more than 350 law

fi rms and scores of service providers

and consultants. During a three-and-

a-half year convergence process,

the company transformed this group

into a select legal network, with each

member serving as a true long-term

strategic colleague. K&L Gates worked

with DuPont throughout the process

and was chosen to become a part of

the network.

We have served as counsel to DuPont

on insurance coverage litigation, com-

mercial litigation, outsourcing and

commercial transactions, real estate,

and investment management issues.

Our service to the company earned the

fi rm DuPont’s Meeting the Challenge

Award six times, recognizing K&L

Gates for its progressive policies and

legal performance.

Our Global PlatformK&L Gates is positioned at strategic intersections of the global economy, with

strong local presence in key capital cities and world commercial and fi nancial

centers. Our nearly 2,000 lawyers across more than 40 fully integrated offi ces and

dozens of signifi cant practice areas create a worldwide network to serve our clients’

growing international needs. This global presence enables clients to mobilize their

outside legal team quickly in response to diverse legal issues around the globe

through the services of one law fi rm, with one phone call.

In the United States, we have coast-to-coast coverage with East Coast offi ces

from Boston to Miami, including New York, Newark, Pittsburgh, Harrisburg,

Washington, D.C., Charlotte, Charleston, Raleigh, and Research Triangle Park;

West Coast offi ces from Anchorage to San Diego, with lawyers also based in Los

Angeles, Orange County, San Francisco, Palo Alto, Portland, Seattle, and Spokane;

and offi ces in major cities in between, including Chicago, Dallas, Fort Worth,

and Austin. Our Asia presence includes Hong Kong, Beijing, Shanghai, Taipei,

Singapore, and Tokyo, while in Europe we are located in London, Paris, Berlin,

Brussels, Frankfurt, Milan, Moscow, and Warsaw. We operate out of the Middle

East from offi ces in Doha and Dubai and serve clients in South America from our

São Paulo offi ce.

We strive to understand

the client’s business,

its objectives,and its priorities.

Our Approach to Client Relationships Successful preferred provider relation-

ships require the active involvement

of both parties. We approach client

relationships with a one-company,

one-team mentality, consistently

seeking proactive ways to add value to

our client work. We constantly strive to

listen to and strengthen our relation-

ships with our clients so we can con-

tinue to be responsive to their business

needs domestically and abroad.

Thanks to this philosophy, the BTI

Consulting Group recognized K&L

Gates as a leader in client service on

the 2012 BTI Client Service A-Team

survey. The fi rm is also the fi rst and

only law fi rm to receive PPG Industries’

Excellent Supplier Award.

PlanningOpen communication is at the core of successful business relationships. This

consists of mutual feedback, including a candid discussion of each party’s core

competencies. We engage in joint planning sessions with the client, set goals and

objectives for the relationship, develop standardized procedures for handling all

cases and matters, and identify expectations. Our goal is a work plan that allocates

resources in the best-suited and most cost-effective manner for the specifi c issue

at hand, and in keeping with the clients’ larger business objectives.

Accountability

We recognize that our clients are in the best position to defi ne satisfaction, to set

priorities on service matters, and to evaluate our performance in those areas. To

that end, we conduct regular appraisals and monitor all of our professionals to

ensure that our performance continues to satisfy our clients’ requirements and that

we provide consistent, measurable, fi rst-class service throughout our relationship.

We use the information gained from these appraisals as benchmarks for future

improvement. We also use these periodic reviews to explore additional opportuni-

ties to increase value and reduce costs.

On a per-matter basis, accountability to get the job done rests with a single lawyer

or a small group of lawyers approved by the client. While a client may regularly

communicate with a primary relationship partner, and a team of lawyers may be

working for a client, we designate a responsible lawyer for each matter.

Staffing As a global law firm with nearly 2,000

lawyers located in more than 40 offices

in North America, Europe, Asia, the

Middle East, and South America our

seamless cross-office capabilities

ensure that K&L Gates staffs its client

engagements with the most experi-

enced and cost-effective personnel

regardless of location.

Our ability to match resources to a par-

ticular matter’s demands, neither over-

nor under-staffing any project, is key to

successful engagements. As a result,

work often is performed, in coordina-

tion with inside counsel, by K&L Gates

lawyers from across our network of

offices. A core cross-disciplinary team,

consisting of a relationship manager and

supervising partners from each applica-

ble practice area, works closely with in-

house counsel to understand business

needs and objectives and to provide

ongoing performance monitoring.

Client Teams Client teams serve as our mechanism

to manage large clients across the firm,

without added cost to the client. While

we have supported informal client teams

for decades, K&L Gates has invested in

developing and sustaining a formal client

team initiative that is devoted to providing

even greater service to our clients. This

initiative places a high level of emphasis

on understanding the ongoing needs

of our clients through the consistent

analysis of information about clients, their

industries, and current socioeconomic

trends in the marketplace.

Client teams comprise lawyers in mul-

tiple offices and practices across the

firm, and are not limited only to those

lawyers that currently work for a client.

In this way, the firm can share thoughts

and ideas related to the business of a

client, without focusing only on those

areas that we currently serve. At no

additional expense to the client, team

members actively collaborate on ways

the firm can add value to the client

relationship, whether that is creating

an in-house CLE program, developing

an alert/white paper on a critical legal

topic, or conducting a face-to-face

client feedback interview to learn more

about the key issues the client consid-

ers most relevant.

Clients also benefit from the substantial

investment in technology K&L Gates has

made over the years. Teams have devel-

oped client extranets and enhanced

internal communications through the

use of intranets, customer relationship

management tools, and news alert

systems to track information and cases

related to our clients.

In 2009 and 2010,

K&L Gates was named among

the top 250 companies in

the InformationWeek 500.

Technology Continuous investment in the use of

technology is crucial to keeping pace

with our clients’ requirements for

enhanced communication and service

delivery. Consequently, our systems and

processes are state-of-the-art and fully

tested for efficiency, reliability,

and practicality.

Our sophisticated extranet enables

clients to view and share documents

with their K&L Gates client team.

Created to provide real-time access to

information and materials related to

legal matters in progress, our extranet

is a password-protected, client-specific

portal that contains a calendar of events,

document and image libraries, matter-

related contacts, and billing history. The

platform is highly customizable and can

be adapted to the particular needs of a

client or case.

In recognition of our technological inno-

vations, CIO magazine awarded the firm

its annual CIO Award in 2011, 2007,

2004, 2003, and 2002. In 2010, for a

second consecutive year, K&L Gates

was named among the top 250 com-

panies in the InformationWeek 500, an

annual listing of the United States’ most

innovative users of business technol-

ogy. The firm was one of only three law

firms ranked.

Transparency Keeping surprises to a minimum is

a key tenet of our client relationship

approach. Through regular commu-

nication, we strive to keep our clients

fully informed about matters as they

develop, advising them on what will

happen and preparing them for what

might happen. We do the same with

respect to fees and staffing. This com-

munication takes the form of informal

updates and reports in the format that

best suits our clients’ preferences.

Early Cost AssessmentFor many litigation engagements, K&L

Gates employs an Early Cost Assessment

(ECA) strategy to evaluate, plan, and

implement cost-effective litigation reso-

lution strategies. The ECA approach is a

collaborative effort with in-house counsel

to build a strategic litigation plan with

a corresponding budget and a realistic

defi nition of what constitutes a favorable

resolution of a case. K&L Gates uses the

ECA process to ensure proactive lawyer-

ing, and consideration and evaluation of

resolution options, early and often.

Alternative Fee ArrangementsWe approach alternative fee arrange-

ments (AFAs) by collaborating with our

clients so we are both held accountable

and rewarded for high-quality legal work

delivered economically, predictably, and

in accordance with our clients’ expecta-

tions and internal budgeting demands.

K&L Gates has been proactive in devel-

oping and implementing a variety of

AFAs for a wide array of engagements.

Our Value-added ServicesWe regularly produce seminars designed to update our clients on recent changes

in the law, new areas of practice, and emerging trends. We encourage our clients to

participate in our in-house programs, either in person or via webcast. In addition, we

present programs, customized to clients’ particular needs, on-site at clients’ places of

business. Seminar topics range from employment law updates to the latest in mort-

gage banking regulations to risk management issues applicable to every company.

Our e-DAT lawyers who address issues relating to e-discovery and records manage-

ment are some of our most active presenters. They also offer a training module and

foldering guide for email users, a training module for litigation holds,

and an interactive instructional program for training corporate personnel about

e-discovery issues.

In addition, we have built a broad collection of work product that practice groups

can use to a client’s advantage. One of the benefi ts of a substantial fi rm that spans

four continents is that we have the resources to maintain state-specifi c, multi-state,

national, and international surveys, databases, analyses, and other work product.

Several practice groups within the fi rm also maintain blogs with in-depth information on

topics ranging from construction law to climate change to cloud computing. Two of our

most notable blogs are our e-Discovery Law blog at www.ediscoverylaw.com, and our

Consumer Financial Services Watch blog at www.consumerfi nancialserviceswatch.com.

We have built a broad collection of

work product that practice groups

can use to a client’s advantage.

Our Commitment to DiversityWe know that clients’ needs can best be met by a diverse workforce. To that end,

K&L Gates has implemented a number of programs to promote diversity.

In 2011, K&L Gates expanded the responsibilities of its diversity team. A new

Firmwide Director of Diversity and Inclusion was appointed and charged with tasks

that are global in scope and focus on eliminating barriers to inclusion within the main-

stream working environment wherever our lawyers reside.

Minority, women, disabled, and GLBT lawyers continue to become increasingly engaged

at K&L Gates by taking on leadership roles that include service on the Management

Committee and its Executive Committee and as Practice Group Coordinators.

Establishing and maintaining a diverse and fully inclusive workforce is essential to a

strong law fi rm. At K&L Gates, we are committed to fostering diversity to enrich the

experience of our lawyers, refl ect the communities in which we live and work,

and better serve our clients.

Drawing on our worldwide resources

and seamless service capabilities, we

deliver value to our clients through

efficient and effective representations.

K&L Gates Off ices

Anchorage420 L Street, Suite 400 Anchorage, Alaska 99501+1.907.276.1969 Fax +1.907.276.1365

Austin111 Congress Avenue, Suite 900Austin, Texas 78701+1.512.482.6800Fax +1.512.482.6859

Beijing Suite 1009-1011, Tower C1Oriental Plaza, No.1 East Chang An AvenueDongcheng District, Beijing 100738 China+86.10.5817.6000Fax +86.10.8518.9299

BerlinMarkgrafenstraße 42 10117 Berlin, Germany+49.(0)30.220.029.0Fax +49.(0)30.220.029.499

Boston State Street Financial Center, One Lincoln StreetBoston, Massachusetts 02111+1.617.261.3100Fax +1.617.261.3175

Brussels Brussels City Centre Stephanie Square Avenue Louise 65, box 111050 Brussels, Belgium +32.(0)2.535.7774Fax +32.(0)2.535.7910

Charleston4000 Faber Place DriveSuite 300North Charleston, South Carolina 29405 +1.843.323.4240Fax +1.843.628.4823

Charlotte Hearst Tower, 214 North Tryon Street,47th FloorCharlotte, North Carolina 28202+1.704.331.7400Fax +1.704.331.7598

Chicago70 West Madison Street, Suite 3100Chicago, Illinois 60602+1.312.372.1121 Fax +1.312.827.8000

Dallas1717 Main Street, Suite 2800Dallas, Texas 75201+1.214.939.5500Fax +1.214.939.5849

Doha Al Fardan Offi ce Tower Offi ce 950, 9th Floor PO Box 31316 West Bay, Doha, Qatar +974.4410.1863Fax +974.4410.1864

DubaiCurrency House, Level 4 Dubai International Financial Centre P.O. Box 506826, DubaiUnited Arab Emirates+971.(0)4.427.2700Fax +971.(0)4.447.5225

Fort Worth D.R. Horton Tower, 301 Commerce,Suite 3000Fort Worth, Texas 76102 +1.817.347.5270Fax +1.817.347.5299

FrankfurtOpernTurm Bockenheimer Landstraße 2−4 60306 Frankfurt am Main, Germany+49.69.94.51.96-0Fax +49.69.94.51.96-499

Harrisburg 17 North Second Street, 18th Floor Harrisburg, Pennsylvania 17101+1.717.231.4500Fax +1.717.231.4501

Hong Kong 44th Floor, Edinburgh Tower, The Landmark15 Queen’s Road Central, Hong Kong+852.2230.3500Fax +852.2511 9515

London One New ChangeLondon EC4M 9AF, England+44.(0)20.7648.9000Fax +44.(0)20.7648.9001

Los Angeles 10100 Santa Monica Boulevard, 7th FloorLos Angeles, California 90067+1.310.552.5000Fax +1.310.552.5001

Miami Southeast Financial Center 200 South Biscayne Boulevard, Suite 3900Miami, Florida 33131+1.305.539.3300Fax +1.305.358.7095

Milan piazza San Marco, 120121 MilanoItalia+39.02.3030.291Fax +39.02.3030.2933

Moscow 4th Lesnoy PereulokBuilding 4, 5th FloorMoscow, 125047, Russia+7.495.643.1700Fax +7.495.643.1701

Newark One Newark Center, Tenth Floor Newark, New Jersey 07102+1.973.848.4000Fax +1.973.848.4001

New York 599 Lexington AvenueNew York, New York 10022+1.212.536.3900Fax +1.212.536.3901

Orange County 1900 Main Street, Suite 600 Irvine, California 92614+1.949.253.0900Fax +1.949.253.0902

Palo Alto 630 Hansen WayPalo Alto, California 94304+1.650.798.6700Fax +1.650.798.6701

Paris116 avenue des Champs-Elysées75008 Paris, France+33.(0)1.58.44.15.00Fax +33.(0)1.58.44.15.01

Pittsburgh K&L Gates Center210 Sixth AvenuePittsburgh, Pennsylvania 15222+1.412.355.6500Fax +1.412.355.6501

Portland 222 SW Columbia Street, Suite 1400Portland, Oregon 97201+1.503.228.3200 Fax +1.503.248.9085

Raleigh4350 Lassiter at North Hills Avenue,Suite 300Raleigh, North Carolina 27609+1.919.743.7300Fax +1.919.743.7358

Research Triangle Park430 Davis Drive, Suite 400Morrisville, North Carolina 27560 +1.919.466.1190Fax +1.919.831.7040

San Diego3580 Carmel Mountain Road, Suite 200San Diego, California 92130+1.858.509.7400Fax +1.858.509.7466

San Francisco 4 Embarcadero Center, Suite 1200San Francisco, California 94111+1.415.882.8200Fax +1.415.882.8220

São Paulo Rua Iguatemi 151, conjunto 281Ed. Spazio Faria LimaSão Paulo, SP 01451-011 Brazil+55 11 3704 5700Fax +55 11 3958 0611

Seattle 925 Fourth Avenue, Suite 2900Seattle, Washington 98104+1.206.623.7580Fax +1.206.623.7022

Shanghai Suite 3705, Park Place1601 Nanjing Road West, Jing An DistrictShanghai, 200040, China+86.21.2211.2000Fax +86.21.3251.8918

Singapore10 Collyer Quay #37-01 Ocean Financial Centre Singapore 049315+65 6507 8100 Fax +65 6507 8111

Spokane618 West Riverside, Suite 300Spokane, Washington 99201+1.509.624.2100Fax +1.509.456.0146

Taipei 30/F, 95 Tun Hwa S. Road, Sec. 2 Taipei, 106, Taiwan+886.2.2326.5188Fax +886.2.2325.5838

Tokyo Kasumigaseki Common Gate West Tower 35F3-2-1 Kasumigaseki, Chiyoda-kuTokyo 100-0013, Japan +81.3.6205.3600Fax +81.3.3597.6421

WarsawAl. Jana Pawła II 2500 854 Warsaw, Poland+48.22.653.4200Fax +48.22.653.4250

Washington, D.C. 1601 K Street, NWWashington, D.C. 20006+1.202.778.9000Fax +1.202.778.9100

ENERGY, INFRASTRUCTURE & RESOURCES

If capital is the lifeblood of the global economy, infrastructure is its beat-

ing heart. The supply of energy, extraction of resources and development of

infrastructure forms the basis of all economic development globally. K&L Gates

serves clients involved in every aspect of the global energy, infrastructure, and

resources space through a wide variety of legal disciplines. We serve project

sponsors and developers in power generation, renewable energy, oil & gas,

mining, transportation, and social infrastructure—as well as development

banks, government agencies, and contractors involved in fi nancing, building,

and operating energy and infrastructure projects.

Oil & Gas

Our comprehensive oil and gas practice has extensive experience in both conventional and unconventional formations throughout North America and Europe. In the Middle East and Asia our lawyers work on a range of engagements in the upstream and down-stream sectors, including oil and gas fi eld development, petrochemical and refi nery developments, and energy trading.

Mining and Metals

Our experience in mining and metals spans natural resources development, conserva-tion, and management companies – in-cluding coal, aggregates, minerals, and base and precious metals. We advise on due diligence, negotiation, and transaction documentation for capital markets and cor-porate transactions for mining and metals companies; and advise on regulatory and operational issues involved in obtaining, renewing, and transferring mining, water, air, and other permits and entitlements.

K&L Gates serves clients involved

in every aspect of the global energy,

infrastructure, and resources

space through a wide variety of

legal disciplines.

Our global platform includes lawyers with experience across a broad range of disciplines, including project fi nance and development, public-private partnerships, construction, energy and environmental regulation, corporate fi nance, mergers and acquisitions, government contracting, and public policy. Our team has extensive expe-rience in cross-border investment, develop-ment, acquisitions and dispute resolution.

Sectors ServedPower Generation and Transmission

K&L Gates lawyers assist power sector cli-ents in meeting the growing global demand for energy, including renewable energy. Our clients include independent power produc-ers, alternative energy project developers and producers, investor-owned and publicly owned utilities, emerging businesses in the smart energy sector, power marketers, members of the nuclear power industry, industrial and commercial energy custom-ers, municipalities, investors, lenders, developers, and contractors. We advise on all aspects of fi nancing, constructing, and operating power generation facilities, and on regulatory and commercial aspects of power sales, transmission, asset acquisi-tion and divestiture, and energy industry mergers and acquisitions. We assist clients developing Clean Development Programme power production facilities in obtaining carbon fi nance, and assist many other mar-ket participants in emissions trading and renewable energy credits.

Water, Wastewater, and Reclaimed Water Projects

Our team has considerable experience in the siting, permitting, construction, opera-tion, and implementation of water, waste-water, and reclaimed water projects across North America, Europe, and the Middle East, including innovative public-private partnerships, mergers and acquisitions, and asset transfers. We have worked on major water projects, ranging from traditional water source development, treatment, and distribution system development to high-tech desalination and high-quality reclaimed water services.

Transportation

K&L Gates has extensive global experience representing project sponsors, govern-ment agencies, contractors, and suppliers on transportation infrastructure projects and transportation service agreements. We have represented companies on project management, design, construction, opera-tion, finance, and maintenance projects for intercity and metropolitan rail systems; electrified light rail and streetcar systems; subway and heavy rail systems; freight rail projects; urban and regional bus systems; paratransit or other specialized roadway transit services; highway, bridge, tunnel, and toll road projects; and port and station facilities. We represent owners and opera-tors in all major sectors of the maritime industry — containerships, roll-on/roll-off vessels, liquid and dry bulk cargo vessels,

passenger cruise vessels, and specialized vessels such as power-generating barges, tugs, mobile offshore drilling units, offshore supply vessels, fishing, dredging, and recreational boats. Our maritime clients also include ports, marinas, shipyards, invest-ment and financing entities.

Telecommunication Facilities

K&L Gates advises a wide range of telecom-munications infrastructure and service providers – from local telephone companies to wireless operators, and domestic and international backbone providers to broad-band service providers – on all aspects of network build-out and operations.

Social Infrastructure

We have advised on a wide range of social infrastructure projects -- encompassing hospitals and health care systems, educa-tional and research systems, social welfare systems (including social housing, extra care housing, and adult social care facili-ties), and emergency services.

Infrastructure Funds and Investors

K&L Gates has extensive experience in establishing infrastructure funds and their subsequent investments, including AIM listing of funds. In addition, our team has worked with institutional investors in their commitments to infrastructure investment funds. We advise on the regulations involv-ing trading and hedges in commodities, including assistance with internal inves-tigations and litigation. We also work with multilaterals, lenders, development banks, and other debt and equity providers in con-nection with the financing and acquisition of infrastructure projects globally.

Our Construction and Engineering lawyers have current

or completed projects in more than 80 countries–including

the BRIC and several CEE countries–ranging from

complex energy and infrastructure projects to

libraries and monuments.

Service AreasProject Development and Finance

K&L Gates’ project finance lawyers address the legal and commercial requirements applicable to structuring, developing, con-structing, and operating economically and legally independent projects and facilities. In developing and structuring projects, we assist in multiple sectors, including gover-nance arrangements and tax-efficient entity structures. We are familiar with international procurement laws, such as the EU procure-ment directives, which increasingly impact international projects. In the financing phase, our lawyers implement traditional project financing, structured finance, tax-able and tax-advantaged debt, equity, and intercreditor arrangements.

Public-Private Partnerships (P3)

Our global Public-Private Partnerships (P3) practice advises governments, sponsors, project entities, third-party equity inves-tors, banks, construction contractors, and facilities management providers on projects in 60 countries around the world. The lawyers in our P3 practice have advised in an extensive number of sectors – including communications, education, energy, health and social care, hospitality, housing, muse-ums, parking systems, prisons, rail, roads and bridges, ports, science and research, stadiums, waste management, water, waste-water, and reclaimed water.

Construction and Engineering

Our Construction and Engineering law-yers are involved from the early stages of finance, development, and design through implementation, construction, and project close-out. We advise project owners and contractors on all aspects of negotiation and documentation of engineering, procure-ment, and construction contracts, as well as resolution of construction-related disputes. We advise global construction and service companies on international project issues such as anti-bribery statutes, international arbitration, and more.

Energy and Environmental Regulatory

We advise global infrastructure, energy, and resource clients with the many energy and environmental regulations facing major re-source extraction, infrastructure, and power generation projects. We work with clients to successfully navigate regulatory require-ments and maintain good relationships with regulatory agencies, elected officials, non-governmental organizations, and the public. We also advise on competition and antitrust regulation in the energy and resources sectors, including approval of mergers and acquisitions, rate and cost allocation mat-ters, and other administrative matters.

Capital Markets and Corporate Transactions

Our offices in the global financial centers of London, New York, Hong Kong, Shanghai, Singapore, Tokyo and Berlin offer energy, infrastructure, and resources clients deep experience in accessing traditional and non-traditional capital markets, including debt and equity investment, listing on AIM and other exchanges, and complex tax-equity investments. In addition, we assist clients in monetizing tax credits, emissions credits, and other carbon trading instruments.

Government Solutions and Securi-ties Enforcement

Companies with international business face risks resulting from improper pay-ments to foreign government person-nel, prohibited by laws such as the U.S. Foreign Corrupt Practices Act (FCPA), the U.K.’s recently amended Bribery Act, and similar laws enacted by member states of the Organization for Economic Cooperation and Development (OECD). Some laws also criminalize corrupt payments in business transactions between private parties. Our team advises on development of compli-ance policies and procedures, counsels on liabilities in connection with M&A and other transactions, and assists with internal or governmental investigations into allegations of non-compliance.

1000

3

Learn more about our Energy, Infrastructure & Resources practice at klgates.com.

United Kingdom, Europe & AfricaPaul Tetlow

+44.(0).207.360.8101

paul.tetlow@klgates.com

AsiaMaria Tan Pedersen

+852.2230.3598

maria.pedersen@klgates.com

Middle EastPaul M. Simpson

+971.4.427.2721

paul.simpson@klgates.com

Contacts:United StatesElizabeth Thomas

+1.206.370.7631

liz.thomas@klgates.com

Michael G. Zanic

+1.412.355.6219

michael.zanic@klgates.com

Oil and Gas K&L Gates’ oil and gas team includes lawyers located across our global office network representing clients with operations in virtually all of the major oil and natural gas-producing regions around the world. Our lawyers have handled challenging energy-related project engagements in North and South America; Western, Central, and Eastern Europe; Russia; the Middle East; and Asia. Our comprehensive oil and gas practice in the United States is recognized for its extensive experience in both conventional and unconventional formations throughout North America, in particular for its work in Pennsylvania, Texas, Louisiana, and the Gulf of Mexico, including the largest on-shore domestic shale plays - the Barnett Shale in Texas, the Haynesville Shale in Texas and Louisiana, and the Marcellus Shale formation in the Appalachian Basin. This experience is strongly complemented by significant pipeline and utility regulatory experience. In the Middle East and Asia our lawyers work on a range of engagements in the upstream and downstream sectors, including oil and gas field development, petrochemical and refinery developments, and energy trading. The interdisciplinary team of lawyers in our oil and gas group addresses the myriad of legal issues involved with exploring for, producing, transporting, trading, storing, marketing, and processing natural gas, coal bed methane, oil, and other petroleum products. Our lawyers have experience in an array of practice areas including: arbitration litigation and dispute resolution; facility siting and permitting; environmental regulation; real estate, land use, planning, and zoning; water rights and water management; mergers and acquisitions and finance; public policy; FERC and public utility commission regulation; insurance coverage; construction and engineering; and intellectual property. Our lawyers understand both the legal and business issues facing the oil and gas sector. Many were industry professionals in legislative, regulatory, and corporate roles prior to joining K&L Gates. Their experience and knowledge gained in those roles has provided a unique and valuable perspective in handling a wide range of matters for our oil and gas clients. To support the rapidly growing oil and gas industries in Texas and the Appalachian Basin, we have instituted annual regional seminars dedicated to the Barnett and Marcellus shale plays focused on regulatory, infrastructure, water management, and financial concerns as well as legislative and litigation issues.

AREAS OF PRACTICE

Arbitration Litigation and Dispute Resolution K&L Gates has represented clients in judicial and administrative proceedings involving a wide variety of issues, including: leasehold and surface use disputes; royalty payment issues concerning crude oil, natural gas, and natural gas liquids; joint operating and participation agreement disputes and taxation issues; drilling issues; personal injury actions; challenges to municipal regulation of oil and gas development; coal bed methane issues; and storage rights disputes.

The firm regularly appears in proceedings before state utility commissions in the Mid-Atlantic and the Western United States and before various federal agencies, including the Department of Energy, the Federal Energy Regulatory Commission, the Federal Trade Commission, the U.S. Department of Justice, the Bonneville Power Administration, the Western Area Power Administration, the National Energy Board of Canada, and the Federal Communications Commission. We have also represented clients in proceedings before environmental agencies, including the Pennsylvania Environmental Hearing Board, the Susquehanna River Basin Commission, and the Delaware River Basin Commission. Moreover, our lawyers regularly appear in state courts, federal district courts, state appellate courts, and federal appellate courts on oil and gas matters. K&L Gates also regularly represents clients in the oil and gas industry in both domestic and international arbitrations. Our lawyers have conducted successful international commercial and investment treaty arbitration proceedings in the United States, Europe, Latin America, and Asia under a variety of trade association and international arbitration center rules including United Nations Commission on International Trade Law (UNCITRAL), London Court of International Arbitration (LCIA), London Maritime Arbitrators Association (LMAA), Grain and Feed Trade Association (GAFTA), China International Economic and Trade Arbitration Commission (CIETAC), Indonesian National Arbitration Board (BANI), Hong Kong International Arbitration Centre (HKIAC), Singapore International Arbitration Centre (SIAC), International Chamber of Commerce (ICC), American Arbitration Center (AAA), International Arbitral Centre of the Austrian Federal Economic Chamber (VIAC), International Centre for Dispute Resolution (ICDR), and International Centre for Settlement of Investment Disputes (ICSID). We also have a proven track record in ad hoc arbitrations under the rules and with investment treaty cases under Multilateral and Bilateral Investment Treaties acting on behalf of both investors and respondent sovereign states . Perhaps as importantly, by working with clients at the earliest stages of proposed projects, transactions, and other business initiatives, K&L Gates has helped numerous clients avoid or curtail lengthy regulatory or judicial proceedings.

Environmental Regulation Our lawyers versed in national and state environmental programs have assisted companies across the oil and gas industry with environmental permitting, negotiations with state and federal environmental agencies, and representation before environmental boards. Understanding the interplay between multiple programs and agencies, we have helped producers, midstream developers, and interstate pipeline operators frame strategies and approaches for more cost-effective and efficient siting, development, and implementation of contemplated projects. We have represented these clients in review and advocacy of regulatory positions dealing with air, water, and solid waste permitting as well as potential impacts to threatened or endangered species and other protected resources - issues that may substantially affect bottom-line performance and project viability – and we have counseled clients in defense of compliance and enforcement proceedings.

Real Estate, Land Use, Planning, and Zoning K&L Gates real estate and land use attorneys represent oil and gas operators throughout the United States, including developments in the major unconventional shale plays

involving the Barnett and Haynesville Shales in the Gulf region and the Marcellus Shale formation in the Appalachian Basin. We provide clients with strategic advice to address competing surface and mineral development issues. Our regulatory experience takes us from the capitol to council chambers, dealing with state, county, and municipal regulations. Among other things, we assist in obtaining local permits, challenging attempts by municipalities to regulate oil and gas activities, and commenting on proposed ordinances and regulations. With production and transportation occurring more often in urbanized areas, our attorneys can help to navigate operators and carriers through the maze of localized regulations they might not typically encounter in undeveloped areas. We also represent interstate and intrastate pipeline operators in the development, permitting, and construction of storage facilities and transportation pipelines.

Water Rights and Water Management Water resource concerns are a crucial issue for our oil and gas clients. In the United States, we have counseled a substantial number of producers through regulatory, permitting, and enforcement proceedings involving water resource and wastewater regulatory agencies, including the Susquehanna River Basin Commission, the Delaware River Basin Commission, the Pennsylvania Department of Environmental Protection, the New York State Department of Environmental Conservation, and the West Virginia Department of Natural Resources. New regulatory approaches are rapidly evolving, as these agencies have announced new policy, guidance, administrative, or permitting approaches to shale well drilling and development activities. We have actively assisted industry coalitions in responding to regulatory developments. We have also represented clients concerning claims of diminution of water quality and quantity and compressor station contamination cases involving polychlorinated biphenyls, mercury, and other substances.

Mergers & Acquisitions and Finance We have advised numerous clients in connection with the acquisition and disposition of oil and gas producing and exploration properties, fee mineral interests, and royalty interests in every significant producing basin in the United States and many in Europe, Asia, and the Middle East. These transactions have ranged from straight-forward asset deals to complex joint venture arrangements and multi-step, tax-advantaged structures that facilitated our clients’ successful bidding efforts. We have also assisted gas utilities with regulatory diligence on possible acquisitions. Acting as primary counsel or as special maritime counsel, the firm has represented clients in the offshore exploration, production, and transportation of oil and gas. Additionally, we have assisted clients in a number of transactions involving construction, financing (both construction and permanent), mortgaging, sale, and chartering of various types of oil rigs, supply boats, crew boats, lift boats, and crude and product tankers. We have also advised various clients on the acquisition of other oil and gas exploration and production (E&P) and oil field services companies. The U.S. News & World Report “Best Law Firms” rankings recognized the K&L Gates Corporate practice as a national first-tier corporate law practice. In addition, we work closely with our clients in the energy industry, and their lenders, project sponsors, developers, and agents, to employ sophisticated financing techniques in support of their projects. We have acted as lead counsel for the structuring and negotiation of various project financing transactions, including electrical generating,

Liquefied Natural Gas (LNG) facilities, natural gas storage, and transmission projects. Our oil and gas lawyers advise clients concerning oil and gas exploration and development, and regularly structure private placements of securities in the fossil fuels exploration sector.

Public Policy The K&L Gates oil and gas team has profound experience helping natural gas producers in the major U.S. shale plays—including the Barnett, Marcellus, and Haynesville—navigate through the threats and opportunities posed by local, state, and federal policy. We assist our clients in the legislative and regulatory processes by helping them understand what motivates legislators and by actively seeking solutions to meet our clients’ public policy needs. Our team is deeply involved with and has decades of experience working with legislative leaders, committee chairs, rank-and-file lawmakers, state regulators, and governor’s offices in key states. We also work with federal officials in Congress and with federal agencies, such as the Department of Energy, the Department of the Interior, the Environmental Protection Agency, and the Federal Energy Regulatory Commission, on the development of regulatory policies of national and regional significance, as well as effectively resolving individual permitting and enforcement disputes. This allows K&L Gates to be uniquely positioned to offer clients a coordinated strategy between their legal and policy priorities. We are prepared to develop a strategic public policy plan based upon client substantive priorities and preferred public profile—high, medium, or low. Our team members are highly effective in developing public policy strategies drawing on their prior experience in both industry and government. Various team members have held senior positions in both the industry (for example, as Senior Government Affairs Representative for Amoco Corporation, and as President of Columbia Gas of Pennsylvania and Columbia Gas of Maryland) and in the legislative and executive branches of the federal and state governments. Our team includes past members of Congress from the U.S. Senate (including Chair of the Senate Appropriations Subcommittee on Interior, Environment, and Related Agencies which has jurisdiction over lands issues) and the House (including a 20-year veteran of Congress representing a district within the Marcellus Shale area and a past Chair of four House Appropriations Committees), as well as senior staff in Congress such as a Chief Tax Counsel for the U.S. Senate Finance Committee, Chief Counsel for the Senate Environment Committee, and professional staff of the Energy and Environment Subcommittee of the U.S. House Committee on Science and Technology. Others bring strong executive branch experience, including a former Secretary of Legislation in the Pennsylvania Governor’s Office, an Associate General Counsel for the U.S. Environmental Protection Agency, and senior political appointees in the U.S. Department of Energy.

Insurance Coverage We have provided representation, advice, and trial work concerning the availability of insurance coverage for virtually all aspects of on-shore and off-shore oil and gas and energy-related operations, including, without limitation, potential liability arising from loss or damage to platforms, drilling rigs, and pipelines; accidental releases of hydrocarbons into the environment; business interruption; operation of former manufactured gas plants, product pipelines, and processing plants; and the sale or release of products that have allegedly caused property damage or bodily harm.

Construction and Engineering The lawyers in our Construction and Engineering practice have a complete understanding of the oil and gas industry, from the early stages of finance, development, and design through implementation, construction, and project close-out. Our lawyers draw upon their legal and technical experience to work with clients to minimize disputes and accomplish common project goals on a local, national, and international scale. With full-time, dedicated construction lawyers resident in most major of our offices, K&L Gates has one of the largest and most geographically diverse and technically skilled practices in the world. Many of the group’s lawyers have worked in the construction, engineering, architecture, and building materials industries or in the government agencies that interact with the oil and gas industry. This practical, real-world experience, combined with the breadth of the practice, allows our lawyers to anticipate, address, and help prevent the myriad of problems that can arise during any phase of a construction project in both the private and public sectors. Additionally, the substantive knowledge of applicable laws, rules, and regulations possessed by our construction and engineering lawyers, combined with our experience in the industry, enables the firm to deliver high-quality legal services in a personal, results-oriented, and cost-efficient manner. The U.S. News & World Report “Best Law Firms” rankings recognized the K&L Gates Construction and Engineering practice as a national first-tier construction law practice.

Energy and Utilities K&L Gates’ interdisciplinary Energy and Utilities practice leverages experience on a spectrum of issues facing the dynamic energy industry and the changing field of utility operations. Lawyers across our global offices work together to guide our clients through strategic decisions and the regulatory maze toward implementation of their business objectives. In the United States, we are experienced in representing clients before state public utility commissions and the Federal Energy Regulatory Commission (FERC), as well as other regulatory agencies, such as the Commodities Futures Trading Commission (CFTC). From project development and finance, alternative energy resources, hydropower licensing, mergers and acquisitions, antitrust, and legislative advocacy to smart grid and other new energy technologies, we have the experience and creativity to meet the challenge and get results.

Intellectual Property K&L Gates has over 225 lawyers, including more than 100 registered patent lawyers and agents with engineering or advanced science degrees, who devote their practice to obtaining protection for intellectual property assets in the form of patents, trademarks, and copyrights. These lawyers not only counsel clients regarding how best to protect their intellectual property, they fully handle the appropriate application and registration processes. They also advise clients on intellectual property matters in connection with licensing, technology transfer, infringement, and validity opinions and the intellectual property aspects of business transactions and financings such as mergers and acquisitions, venture capital, private equity investment, and public offerings. They bring their broad range of substantive technical knowledge to their work in each of these areas.

Our Chemistry/Materials Science industry group includes our clients involved in chemicals, oil and gas production, magnetic media and metals, alloys, and ceramics, including high-temperature superconductors. Materials science brings together metallurgy, ceramics, polymer science, the chemistry of solids, and other diverse fields concentrating on many of the basic elements of manufactured products. We have over 25 licensed patent lawyers with technical backgrounds in chemistry, chemical engineering, metallurgy, and materials science, and the biological sciences. Many of our lawyers also have significant industrial experience, which affords them additional insight into the unique intellectual property legal issues that confront businesses in the oil and gas industry.

REPRESENTATIVE EXPERIENCE Mid-Atlantic/Environmental Regulatory

K&L Gates provides regulatory advice, among other counsel, to the Marcellus Shale Coalition that consists of leading producers in the development of the Marcellus Shale in Pennsylvania.

Mid-Atlantic/Arbitration Litigation and Dispute Resolution K&L Gates represented Rex Energy in defense of a putative class action involving claims for breach of contract, tortious interference with contract, civil conspiracy, and alter ego arising out of alleged breach of oil and gas leases.

Mid-Atlantic/Mergers & Acquisitions and Finance K&L Gates represented the Special Committee of the Board of Directors at Atlas Energy, a publicly traded, limited liability company, in the connection with the exploration of strategic alternatives available to the company and the resulting merger with its parent company, Atlas America.

Mid-Atlantic/Arbitration Litigation and Dispute Resolution K&L Gates has represented industry interests in a series of key court cases including Kilmer v. Elexco Land Services Company, 63 MAP 2009; Range Resources—Appalachia, LLC, et al. v. Salem Township, et al., 600 Pa. 231 (2009); Belden & Blake Corp. v. Commonwealth of Pennsylvania, Dep’t of Conservation and Natural Resources, 600 Pa. 559 (2009). We represented Southwestern Energy Production Company in Kilmer v. Elexco Land Services Company, where the case persuaded the Pennsylvania Supreme Court to exercise extraordinary jurisdiction to definitively interpret the Pennsylvania Minimum Royalty Act (MRA). K&L Gates persuaded the unanimous court to adopt the industry’s interpretation of the statute, and it held that the royalty required by the MRA may be measured at the wellhead. We represented Range Resources and other producers against Salem Township when the municipality attempted to regulate and restrict Range Resource’s development of oil and gas. The Pennsylvania Supreme Court held such regulation to be improper and preempted in Range Resources – Appalachia, LLC, et al. v. Salem Township, et al. We represented Belden & Blake Corporation in Belden & Blake Corp. v. Commonwealth of Pennsylvania, Dep’t of Conservation and Natural Resources when the Pennsylvania Department of Conservation and Natural Resources attempted to block their development of its oil and gas interests in state parks. The Pennsylvania Supreme Court stated that the state was precluded in doing so and would have to pay damages.

Mid-Atlantic/Environmental Regulatory K&L Gates advised several producers on drilling potential in New York state and assisted with commenting on the General Environmental Impact Statement being prepared by the NYSDEC.

Mid-Atlantic/Environmental Regulatory K&L Gates serves as regulatory and permitting counsel to several producers of natural gas including the most active driller of new wells in the United States. K&L Gates advises and represents these companies with respect to a wide range of regulatory and permitting matters involved in the development of the Marcellus Shale.

Mid-Atlantic/Environmental Regulatory K&L Gates is regulatory and permitting counsel to the developer of a significant gathering line and midstream transmission system in the Marcellus Shale region. - Wilson

Mid-Atlantic/Environmental Regulatory K&L Gates represented Cabot Oil & Gas Corporation in various environmental and regulatory matters including dozens of lawsuits seeking to invalidate natural-gas leases.

Mid-Atlantic/Environmental Regulatory/Water Rights & Water Management K&L Gates advised Pennsylvania General Energy on various permitting and regulatory issues concerning natural gas well siting and facility development, including water, wastewater, wetlands, environmental releases, and erosion and sedimentation control issues.

Gulf Region/Insurance Coverage K&L Gates represented Murphy Oil USA, Inc., a subsidiary of Murphy Oil Corporation (Murphy), from El Dorado, Ark., in disputes with certain of its excess insurers, Swiss Re International Se, Arch Reinsurance Company, HDI-Gerling AG and Zurich Insurance Company (Underwriters), arising out of losses valued in excess of $430 million suffered in connection with a crude oil spill at Murphy’s Meraux, La., refinery caused by Hurricane Katrina. The spill (which has been characterized as the largest Katrina-related environmental release) and concomitant property damage and related alleged injuries and harm resulted in over 26 class action lawsuits filed against Murphy by residents of St. Bernard Parish, La., all of which were consolidated into one action styled Turner v. Murphy Oil USA, Inc. A settlement of the lawsuit was approved by the Federal Court in January 2007. Since the settlement of the Turner litigation, Underwriters have instituted four related London-based arbitration proceedings. Shortly thereafter, Murphy Oil filed a coverage action in Arkansas federal court and obtained a temporary restraining order enjoining arbitration, but this Arkansas action was ultimately dismissed for lack of jurisdiction. All four arbitration tribunals were then consolidated and fully constituted in October 2007 in London. Murphy sought insurance coverage for the class action settlement and related claims. After a full hearing on all issues in late 2009, the tribunal issued its confidential award and a final disposition regarding costs.

Gulf Region/Insurance Coverage K&L Gates represented Anglo-Suisse Offshore Partners (“ASOP”) against a number of excess underwriters in a case filed in Harris County (Houston), Texas, seeking coverage for wreck removal and decommissioning expenses incurred in connection with offshore platforms and pipelines destroyed during Hurricane Katrina. The policy at issue sat excess of ASOP’s first party energy package policy for wreck removal coverage and carried an aggregate limit of $50 million. The case was successfully tried to a jury in Houston in February, 2010. A settlement was reached before the jury reached a verdict.

Gulf Region/Arbitration Litigation and Dispute Resolution In April 2009, K&L Gates successfully obtained a $640 million arbitration award on

behalf of clients Astra Oil Trading NV and affiliates in a proceeding against the U.S. subsidiaries of Brazilian oil company Petroleo Brasileiro, S.A.–Petrobras. The arbitration tribunal ordered Petrobras to pay approximately $640 million to Astra to resolve a dispute over Astra's right to compel Petrobras to purchase the ownership interests of Astra and its affiliates in a Texas oil refinery and related trading partnership. Petrobras had refused to recognize its obligation to purchase these interests, but the Panel rejected Petrobras' position. Confirmation proceedings are underway.

Pacific Northwest/Environmental Regulatory K&L Gates represented Northwest Pipeline GP in permitting multiple additions to the company’s interstate natural gas pipeline system in the Pacific Northwest, including preemption of conflicting state authorizations and successful negotiation of conditions of state-administered federal authorizations such as 401 water quality certifications and coastal zone consistency concurrences.

Pacific Northwest/Environmental Regulatory K&L Gates represents Pacific Connector Gas Pipeline, LLC, in permitting and related litigation concerning a proposed interstate pipeline extending from a proposed LNG terminal facility in southwestern Oregon to the California-Oregon border near Malin, Ore.

Pacific Northwest/Mergers & Acquisitions and Finance K&L Gates represents Northwest Pipeline GP in right-of-way acquisition for additions to the company’s interstate natural gas pipeline system in the Pacific Northwest.

Pacific Northwest/Arbitration Litigation and Dispute Resolution K&L Gates represents Northwest Pipeline GP in litigation involving quality of transported natural gas.

Pacific Northwest/Environmental Regulatory Represented North Baja Pipeline Company in development of a new, greenfield interstate pipeline extending from Arizona, through California, and into Mexico.*

Pacific Northwest/Environmental Regulatory Advised Gas Transmission Northwest Corporation with respect to multiple system expansions, including commercial contracting matters as well as securing federal certificate approvals.*

Pacific Northwest/Environmental Regulatory Advised TransCanada Pipelines Ltd. with respect to development of a proposed joint venture to build a new interstate pipeline extending from the Rocky Mountain area to the Pacific Northwest.*

Pacific Northwest/Environmental Regulatory Represented Gas Transmission Northwest Corporation with respect to development of the proposed Palomar Pipeline.*

International – Non-U.S./Arbitration Litigation and Dispute Resolution K&L Gates acted for a U.S. oilfield developer in arbitration proceedings against a Thai engineering contractor relating to the supply of a wellhead platform for use in an oilfield offshore Thailand. The contractor claimed sums in respect of numerous variation order requests. Our clients counter claimed for delay costs, rectification, unlawful retention of documentation and equipment, poor quality and/or negligent and/or inefficient work, and liquidated damages. The dispute was governed by English law and referred to rapid adjudication in London. We were ultimately

* Work done by K&L Gates lawyer prior to joining the firm

successful in reaching a negotiated settlement for the client with payment of a fraction of the sums being claimed.

International – Non-U.S./Arbitration Litigation and Dispute Resolution K&L Gates acted in arbitration proceedings for one of the world’s largest owners/operators of oil rigs under the VIAC rules in Vietnam following a dispute with a state oil company in relation to disputed operating/stand-by rates to be applied under a drilling contract following a loss of pressure/slumping incident in the White Tiger oil field offshore Vietnam.

International – Non-U.S./Mergers & Acquisitions and Finance K&L Gates has acted for Halliburton on several global cross-border acquisitions and disposals of production services companies and businesses.

International – Non-U.S./Mergers & Acquisitions and Finance K&L Gates advised several of the world's leading energy conglomerates on the establishment of joint ventures in Russia.

International – Non-U.S./Mergers & Acquisitions and Finance K&L Gates advised a major integrated Russian oil company on the acquisition of various downstream assets in Russia and abroad.

International – Non-U.S./Construction & Engineering K&L Gates represented an energy company in negotiation of a concession with the Jordanian government for the design and construction of an oil shale project (including supporting infrastructure and feedstock/off take pipelines) with an estimated project cost $1.6 billion.

International – Non-U.S./Mergers & Acquisitions and Finance K&L Gates advised a Jordanian oil shale exploration company on its $31 million pre-IPO fundraising.

INTERNATIONAL OIL & GAS EXPERIENCE

K&L Gates’ international oil and gas practice is built on a sophisticated and detailed

understanding of the legal aspects of exploring for, producing, transporting, storing, market-

ing, and processing crude oil, natural gas, coal bed methane, and petroleum products. We

represent all participants in the oil and gas industry, including governments and government-

owned enterprises, producers, drilling contractors, pipeline operators, natural gas liquids

processing companies, purchasers, gas marketing companies, and commercial lenders.

The strength and capability of the K&L Gates team is evident in the range of challenging energy projects on which our lawyers have worked. Our integrated approach to the practice of law brings added value to our clients with deal pro-gression supported at both the individual office level and through firmwide practice areas. Our lawyers understand both the legal and commercial issues facing the oil and gas sector. We advise clients on a broad range of corporate, commercial and financial matters including:

• Project development and finance

• Cross-border mergers, acquisitions and divestitures

• Bidding arrangements

The following pages show just a sample of the breadth and depth of K&L Gates’ non-U.S. oil and gas experience across the globe.

Europe • Acted on behalf of Halliburton on

several global cross border acquisitions and disposals of production services companies and businesses.

• Advised several of the world’s leading energy conglomerates on the establish-ment of joint ventures in Russia.

• Advised a major integrated Russian oil company on the acquisition of various downstream assets in Russia and abroad.

• Advised on public law matters regard-ing the planned construction of a gas pipeline between Poland and Denmark crossing the German continental shelf.

• Represented a French oil service company in developing and establish-ing a $100 million worldwide sales rep-resentation distributorship network that minimized taxation and other liabilities for operations.

• Advised a U.S. oil and gas exploration company on the structuring and incor-poration of its UK subsidiary.

“The strength and capability of the

K&L Gates team is evident in the

range of challenging energy projects...”

• Acquisition and disposal of production titles

• Transportation of petroleum

• Sub-sea and floating production facilities

• Joint venture arrangements

• LPG and crude sales

• Royalties and petroleum taxes

• Environmental compliance

• International arbitration

• Gas distribution and trading licenses

• Advised a U.S. oil and gas exploration and production company on its $100 million placing and admission to AIM, and $30 million secondary fundraising and renegotiation of $60 million bank facility.

• Advised an AIM listed independent oil and gas exploration and produc-tion company on two acquisitions and readmission to AIM.

• Represented a European national oil company in bidding for properties in the North Sea.

• Represented a U.S. company in the establishment of a joint venture with a Russian partner for the provision of oil field services in Russia.

• Represented one of the world’s largest oil companies in the establishment of a joint venture for the exploration and production of oil and gas in Russia.

• Represented a major Russian oil company on the acquisition of over $800 million worth of downstream assets.

• Represented a major Russian oil company in the establishment of a joint venture for petroleum product delivery with one of the leading oil companies in Eastern Europe.

• Represented a major Russian oil company in the sale of an offshore drilling rig.

• Advised oil brokerages in issues relating to large scale Russian crude oil consignments.

• Represented Poland’s major oil and gas company related to certain exploration projects within and outside of Poland.

• Represented Polish oil and gas produc-ers in matters related to the preparatory stage of construction of an LNG termi-nal and the construction of pumping stations for gas terminals.

• Advised a UK oil and gas exploration company with operations focused in West Africa, on its initial placing and admission to AIM and various second-ary fundraisings including a £120 million placing of its shares.

• Advised an AIM listed gas independent on its acquisition of a company that constituted a reverse takeover under the AIM Rules.

• Advised a UK oil and gas exploration company in connection with various private placements of its shares.

• Advised a UK company on its pro-forma agreements for the sale and purchase of crude oil.

• Advised KBR, Inc. on the $280 million disposal of its production services busi-ness in 25 jurisdictions to a manage-ment team.

• Advised Halliburton Company on the acquisition of PSL Energy Services Limited in various jurisdictions in Europe, the Middle East and the Asia-Pacific Region.

• Advised Halliburton Company on its acquisition of Protech Centerform, a provider of casing centralization.

• Advised Halliburton Company in rela-tion to its contested public bid for oil services company Expro International.

• Advised a large international industrial company on the $515 million disposi-tion of a petroleum subsidiary.

• Advised a private equity fund in the $355 million sale of a midstream gas gathering and transmission company.

• Advised Halliburton Company in its acquisition of an outstanding equity interest in WellDynamics B.V.

• Advised Halliburton Company in the sale of its membership interests in Enventure Global Technology LLC.

• Represented KBR, Inc. on the £350 million sale of Devonport Management Limited.

• Represented a Cyprus-based invest-ment fund in the acquisition of oil and gas producing assets in Western Siberia from an international oil major.

• Represented a Russian gas producer in an $8 billion acquisition of production and LNG assets in Sakhalin area.

• Represented a Russian gas producer in an asset swap with an international energy major.

• Represented a U.S. investor in the $110 million acquisition of a natural gas producer in Western Siberia.

• Represented a consortium of oil com-panies in a major oil field and pipeline project in Azerbaijan, with particular emphasis on their operations in Russia, Azerbaijan and Georgia.

• Represented a Swiss trading house on standard contracts for oil and refined prod-ucts sales in South Eastern Asia region.

• Represented a major U.S. oil company in their corporate, IP and regulatory issues relating to a project involving the construction and operation of a chain of gas stations and convenience stores through a joint venture in Moscow.

Asia • K&L Gates acted for a U.S. oilfield

developer in arbitration proceedings against a Thai engineering contractor relating to the supply of a wellhead platform for use in an oil field offshore Thailand. The contractor claimed sums in respect of numerous variation order requests. Our clients counterclaimed for delay costs, rectification, unlawful retention of documentation and equip-ment, poor quality and/or negligent and/or inefficient work, and liquidated damages. The dispute was governed by English law and referred to rapid adju-dication in London. We were ultimately successful in reaching a negotiated settlement for the client with payment of a fraction of the sums being claimed.

• Acted in arbitration proceedings for one of the world’s largest owners/opera-tors of oil rigs under the VIAC rules in Vietnam following a dispute with a state oil company in relation to disputed operating/stand-by rates to be applied under a drilling contract following a loss of pressure/slumping incident in the White Tiger oil field offshore Vietnam.

• Represented a Singapore-based holding company in relation to upstream aspects of a greenfield LNG project in Asia.

• Advised an Indonesian company that was formed to build and operate LNG plants on various aspects of the 2 million tonne per annum LNG project in Sulawesi, Indonesia, including drafting a gas supply agreement and an opera-tion agreement for the LNG plant.

• Represented a major Chinese oil company in the evaluation and negotia-tion of the purchase of a working inter-est in an oil property in Ecuador.

• Acted for the Singapore branch of a large European bank as arranger for a variety of syndicated loan agreements for project financing, including advis-ing on various aspects of inter-creditor agreements, subscription agreements, indemnity deeds, common terms agreements and inter-company loans.

• Advised an onshore exploration and production company in India on the financing for design and construc-tion of a $2.14 billion oil refinery in Gujarat, India.

• Advised a private bank in India as the lenders on documentation of numerous facilities for the Essar Group, includ-ing project financing of a bulk terminal at Hazira Port (India), recommending reserved discretions for the lenders under various project agreements and preparing parent company guarantees.

• Negotiated and drafted construction contracts for a naphtha cracker plant in Vadinar (India).

• Negotiated the construction of two $300 million trains for LNG in Indonesia for a U.S. consortium of oil companies.

• Represented a global energy group in negotiating production sharing con-tracts for Vietnamese offshore explora-tion blocks.

• Advised a major Australian oil and gas exploration and production company with global interests on various aspects of the upstream petroleum industry in Vietnam, including the negotiation of a production sharing contract.

• Represented an independent upstream exploration and production (E&P) company focused on Asia in the prepa-ration of bid documentation for oil and gas exploration permits in Laos.

• Advised an onshore exploration and production company in India on aspects of a production sharing con-tract with the Myanmar government.

• Advised a company involved in the exploration and production of oil and gas primarily in Indonesia on the mon-etization of natural gas produced from the Sebaya gas field in East Java.

• Advised the government on the moneti-zation of natural gas produced from gas fields in East Java.

• Represented a global group of energy and petrochemical companies in draft-ing gas sales agreements and provided ongoing advice in transactions with the Indonesian government.

• Represented an American multinational oil and gas corporation to form a joint venture with a local partner for operat-ing gas stations in Taiwan and advised client on petroleum and lube oil import and distribution related issues and prepared relevant agreements.

• Advised a Singapore-based holding company on its $270 million sale to a gas production and distribution infrastructure company.

• Advised a U.S. purchaser on a short-term LNG sale from a field in Papua New Guinea.

Middle East • Advised a Kuwaiti petrochemicals

company on the development of a major olefins project in Kuwait.

• Represented a Saudi petrochemicals company related to conducting a due diligence review and redrafting of In Kingdom and Out of Kingdom catalyst sales agreements.

• Advised a South American oil company on the effect of a trading company’s insolvency under the laws of the United Arab Emirates.

• Represented an oil exploration company in connection with the dis-posal of a portfolio of working interests in the Middle East.

• Represented a Japanese oil exploration company on corporate and commercial aspects of its Middle East operations, including advice on bids to acquire assets across the region.

• Represented an energy company in negotiation of a concession with the Jordanian government for the design and construction of an oil shale project (including supporting infrastructure and feedstock/off take pipelines) with an estimated project cost of $1.6 billion.

• Represented a privately owned Canadian energy development company as developer of an LNG storage facility in Oman.

• Advised a Jordanian oil shale explo-ration company on its $31 million pre-IPO fundraising.

• Advised and assisted an oil field ser-vices company’s Middle East location in connection with the establishment of its investment and business vehicle in Abu Dhabi, UAE.

• Represented a BVI company providing offshore oil and gas fields services, in the acquisition of all business of a sole proprietorship licensed in Abu Dhabi.

• Represented an onshore and offshore oil and gas field services contractor, in the acquisition of National Services Contracting.

• Represented the foreign partner on the creation of an oil and gas sector joint venture based in Abu Dhabi with an approximate value in excess of $1 billion.

North America (Non-U.S.) • Advised a Latin American state-owned

petroleum company in connection with all of its U.S. operations, including transfer of supply contracts having a value in excess of $2.0 billion.

• Represented a Toronto Stock Exchange-listed, Canadian independent oil and gas E&P company in connec-tion with its acquisition of a U.S.-based owner of non-operated oil and gas assets in Texas, Oklahoma, Kansas and Colorado.

• Advised a mid-continent-based oil field services company in connection with the $330 million sale of 93% of its equity interests to a Toronto Stock Exchange-listed Canadian oil field services company.

• Represented a Calgary-based indepen-dent energy company in the acquisi-tion of $81 million of Alberta petroleum production and exploration assets.

• Represented a Calgary-based indepen-dent energy company in the acquisition of an Alberta partnership with petro-leum production and exploration assets in a multi-step, tax-advantaged transac-tion for $182 million.

• Represented a Mexican oil and gas exporter on the negotiation of a terminal use agreement for an LNG terminal.

• Represented a Mexican oil and gas equipment manufacturer in forming joint ventures with numerous U.S.-based oil field equipment manufactur-ers to develop technology and equip-ment for sale and use in Mexico, Latin America and the U.S.

“We represent all participants in

the oil and gas industry...”

• Represented a major manufacturer of petroleum based consumer products in developing a distribution/agency network in Central America.

• Acted as special U.S. maritime counsel to major domestic oil producer in sale-leaseback of its half-interest in Panamanian-flag deepwater oil produc-tion facility in the Gulf of Mexico.

• Assisted a Latin American state-owned petroleum company to extend a $1.4 billion joint venture with a global group of energy and petro-chemicals companies.

• Represented a Mexican oil and gas pro-ducer in connection with its proposed privatization of certain refining assets and related joint venture agreements with international oil and gas majors.

• Advising the agent and lead lender on a $135 million construction of a 300 megawatt power plant, natural gas pipeline and related facilities in the Dominican Republic.

• Advising a major Mexican industrial company in connection with the regula-tion, development, and finance of a number of natural gas-fired proj-ects in Mexico.

• Advised a Texas-based independent oil and gas E&P company in the $60 million acquisition of producing and undrilled federal leases in the Gulf of Mexico.

• Represented a Texas-based indepen-dent oil and gas E&P company in the $810 million acquisition of producing and undrilled federal leases in the Gulf of Mexico in two contemporane-ous transactions.

South America • Acted as special U.S. maritime counsel

to lessor in $65 million sale-lease-back of two Brazilian oil production platforms.

• Representing the contractor in the world’s largest offshore oil and gas project under a single turnkey contract off the coast of Brazil with an original value of approximately $2.5 billion.

• Represented the national oil company of Argentina in the privatization of $750 million in assets. This required analysis of the applicable laws, rules, decrees and regulations of the country and the creation of appropriate entities to accomplish Argentina’s objectives.

• Represented the national integrated oil and gas company of Trinidad and Tobago in the transfer of its supply contracts valued over $2 billion.

• Served as special project finance counsel to a major multinational oil company in connection with the devel-opment and financing of a $1.5 billion LNG liquefaction and port facility in Trinidad and Tobago.

• Represented two companies in disputes with a leading state-owned oil and gas company in South America arising out of a $3 billion turnkey contract for engineering, procurement, installation, construction, and startup of two oil and gas field production facilities.

• Acting on behalf of Halliburton Company in connection with a wide range of assignments including, in particular, the interlinked $4 billion ICC arbitrations concerning offshore drilling platforms located off the coast of South America.

Africa • Represented a developer in a $2 billion

gas-to-liquids project in Nigeria.

• Secured successful agreements for petroleum exploration and development in Gabon, Guinea and the Ivory Coast for an independent U.S. oil company.

• Represented a U.S. company in struc-turing credit support arrangements for the financing of exploration and pro-duction activities in Equatorial Guinea.

• Advised a publicly listed energy and natural gas company on the London Stock Exchange with respect to a greenfield LNG project in Nigeria consisting of four trains each having a capacity of 5.2 million MT per annum.

• Advised a UK oil and gas exploration company with operations focused in West Africa, on its acquisition of an interest in Block 1 of the Nigeria-Sao Tome Joint Development Zone.

• Advised an Indian oil company on the proposed acquisition of a part interest in a company with upstream oil and gas interests in Africa, including preparing share purchase agreement, sharehold-ers agreement, funding agreement and crude oil purchase agreement.*

• Represented a bank as arranger of an adjustable borrowing base revolving credit facility for the development of off-shore oil fields located in West Africa.*

• Represented an Indian oil company in relation to the upgrade and refurbishment of an oil refinery in North Africa on a build-operate-lease-transfer (BOLT) basis.*

• Represented an Indian oil company in rela-tion to the construction of a multi-product pipeline in North Africa on a build-operate-lease-transfer (BOLT) basis and structuring for a prospective project financing.*

• Represented a “supermajor” in relation to the refurbishment and expansion of an existing liquefaction plant and ter-minal facilities in North Africa as part of an integrated project including natural gas production, transportation and processing, and the production and marketing of LNG and condensates.*

• Advised a prominent African national oil company in relation to the establish-ment of a joint venture with a number of European oil companies to develop an offshore gas development.*

• Assisted an international oil company in relation to the renegotiation and extension of concessions for, and the restructuring of participations in, various upstream developments in Libya based on the new Exploration & Production Sharing Agreement (EPSA-IV).*

• Represented an international oil company in relation to various issues arising from a prior acquisition of various upstream interests in Libya under Exploration & Production Sharing Agreements.*

• Advised a U.S. oilfield services company in relation to a succession of commercial arrangements for the provision of specialist drilling services (including DD, LWD and MWD), and of proprietary drilling tools and methods, on various field developments in Egypt and elsewhere, including the drafting and negotiation of drilling and well services contracts.*

* Work done by K&L Gates lawyer prior to joining the firm.

1003

5

For more information about our International (Non-U.S.) Oil & Gas Experience, please contact any of the lawyers listed below:

MoscowWilliam M. Reichert

+7.495.643.1712

william.reichert@klgates.com

SingaporeRaja Bose

+65.6507.8125

raja.bose@klgates.com

TaipeiChristina C.Y. Yang

+886.2.2326.5198

christina.yang@klgates.com

TokyoRobert E. Melson, Jr.

+81.3.6205.3602

robert.melson@klgates.com

WarsawTomasz Dobrowolski

+48.22.653.4221

tomasz.dobrowolski@klgates.com

Contacts:BeijingRose W. Zhu

+86.10.5817.6110

rose.zhu@klgates.com

DubaiPaul de Cordova

+971.4.427.2704

paul.decordova@klgates.com

LondonMathew C. Kidwell

+44.(0)20.7360.8141

mathew.kidwell@klgates.com

“Our integrated approach to

the practice of law brings

added value to our clients...”

Australia/Oceania • Represented one of the world’s largest diversified natural resources companies in the

negotiation of joint operation agreements and production sharing contracts for projects in the North West Shelf, Australia.

• Represented a global group of energy and petrochemicals companies in negotiating the sale and purchase of a petroleum title in the North West of Australia and drafted a deed of coordination for petroleum exploration following acquisition of the title.

• Represented an oil and gas major on the purchase of an offshore title in Western Australia and in negotiation of a joint operating agreement.

• Advised one of the world’s largest integrated energy companies based in the U.S. on environmental issues relating to the Gorgon project, the largest single resource natural gas project in Australia.

• Advised Woodside, Australia’s largest publicly traded oil and gas exploration and pro-duction company, on various aspects of the Pluto LNG project including negotiation of 15-year sales agreements with two companies.

• Advised a publicly listed energy and natural gas company on the London Stock Exchange in relation to the farm-in of gas exploration permits and associated gas sales agreements in Western Australia.

K&L GATES OIL AND GAS PRACTICE UPSTREAM AND MIDSTREAM

K&L Gates has for decades represented clients in the oil and gas industry. K&L

Gates attorneys have experience in matters covering the full spectrum of opera-

tional and corporate issues related to the exploration, production, transportation,

storage and processing of oil, gas, and other petroleum products and related

power generation. We have represented asset and entity buyers and sellers,

producers, farmors amd farmees, trade associations, pipeline operators, storage

and distribution systems, product purchasers, drilling contractors, service com-

panies, public utilities, and commercial lenders in oil and gas related matters.

While K&L Gates attorneys have an impressive track record of closing large transactions in the oil and gas industry, our expertise begins at the operational level. K&L Gates attorneys have gained an in-depth understanding of the oil and gas business from assisting clients in negotia-tions covering everything from leasing and drilling to marketing, processing, transpor-tation and storage. It is this base of detailed operational knowledge and experience that separates K&L Gates from other national and global firms.

including Arkansas, Colorado, Kansas, Louisiana, Mississippi, New Mexico, North Dakota, Oklahoma, Pennsylvania, Texas, Wyoming, and the Gulf of Mexico.

We have also represented both lenders and borrowers in reserve based financing arrangements, both syndicated loans and one bank financings. Such representation required our attorneys to develop efficient, practical, and accurate methods to verify title for wells, leases, and facilities.

The oil and gas industry has a unique vocabulary and mentality. At K&L Gates, we speak the language and understand the business. These pages show just a sample of the breadth and depth of K&L Gates’ domes-tic oil and gas transactional experience.

Joint Venture Transactions• Represented independent operators in

farming out, over a ten year period, several New Mexico state leases and Federal leases to various companies, such as Devon, Samson Resources, and Forest Oil.

• Representing independent operators in the negotiation of joint ventures with an international oil service company by which the service company contributed 30% of the costs of drilling and comple-tion in return for a net profits interest and a commitment to use its well drilling and completion services.

“...K&L Gates attorneys have an

impressive track record

of closing large transactions...”

Our understanding of the operations and business of oil and gas makes K&L Gates uniquely effective when it comes to han-dling A&D, corporate, joint venture, and financing transactions for clients in the oil and gas industry. K&L Gates oil and gas attorneys have handled billions of dollars in A&D and joint venture transactions, ranging from the straight-forward to the innova-tive and complex. These seven, eight and nine-figure deals have dealt with assets and operations in every significant petroleum producing region in the United States,

Mergers, Acquisitions, and Corporate Transactions• Represented a private E&P company in

the divestiture of the company through a stock sale for in excess of $100 million.

• Represented a Texas-based independent oil and gas E&P company in the $100 million plus acquisition of producing gas units in East Texas and related financing.

• Represented a private equity fund seller of mid-stream gas gathering and transmission company in a $355 million transaction.

• Represented a Dallas-based indepen-dent energy company in the divestiture of California petroleum producing assets for $30 million.

• Represented a Dallas-based independent energy company in the acquisition of Oklahoma petroleum producing assets for $108 million.

• Represented the sellers of a CO2 pipeline and marketing company transporting CO2 from Colorado to the Permian Basin for EOR projects.

• Represented a private equity fund in its acquisition of the Gulf of Mexico opera-tions and related vessels and other assets of an offshore oilfield dive boat company.

• Represented Texas-based independent oil and gas companies in the acquisition by farmout and lease and subsequent sale of proved producing and undevel-oped properties.

Operational Matters• Represented client in connection with

multiple acquisitions of large mineral lease tracts, fee mineral interests and overriding royalty interests in the Fayette-ville Shale play in Northwestern Arkansas.

• Represented a Texas-based independent in the leasing of properties in the Permian Basin and the drafting and negotiation of subsequent participation agreements with industry partners for the development of such properties.

• Represented a platform owner/producer in $54 million removal of an offshore producing platform and wells toppled by Hurricane Rita, including negotiation of related dive boat, lift boat and well control service contracts.

• Represented producers in the negotiation of various drilling and joint development contracts both onshore and offshore.

• Represented producers in connection with swaps, collars and other physical and financial hedging arrangements for petroleum production.

• Represented producers in the nego-tiation of various petroleum product marketing agreements.

• Represented producers and processors in various percent-of-proceeds and volume fee-based processing contracts.

• Represented numerous mineral owners and residential developers in connection with leasing oil, gas and other minerals.

• Represented numerous companies in dealing with landowners or royalty holders in resolving various non-litigated disputes over royalty payment issues, land use matters, and leasing transactions.

Equity and Debt Financing• Represented an established management

team in obtaining funding from private equity firm to establish a platform company for the acquisition of gas pipelines.

• Represented senior secured lenders in an out of court reorganization of a multi-company financing in which one of the key elements was the interpretation/revi-sion of a gathering agreement among affiliated parties for gas in south-eastern Kansas.

• Represented numerous financial institu-tions in connection with reserved-based loans secured by oil and gas production in multiple jurisdictions.

K&L Gates oil and gas attorneys also

work seamlessly with the firm’s pro-

fessionals in environmental and regu-

latory compliance, securities matters,

land use, litigation, utilities and power

generation, and other issues encoun-

tered by oil and gas clients.

To learn more about our global law firm and our Oil and Gas practice, visit klgates.com.

Contact:Patrick S. Galvin+1.907.777.7603

patrick.galvin@klgates.com

Michael C. McLean +1.412.355.6458

michael.mclean@klgates.com

ASIA OIL AND GAS PRACTICE

K&L Gates has one of the largest dedicated oil and gas practices of any global

law firm. We seek to combine experience and knowledge of local markets and

practices with international standards and practices. With more than 40 offices

in key markets in Asia, the United States, Europe, South America, and the

Middle East, we offer a broad national and global platform with on-the-ground

local capability in our markets, equipping us to meet our clients’ legal needs—

no matter the issue or location.

Our Asia NetworkK&L Gates has six offices in Asia: Beijing, Hong Kong, Shanghai, Singapore, Taipei, and Tokyo. Our international oil and gas team based out of our Asia offices is built on a sophisticated and detailed understand-ing of the legal aspects of exploring for, producing, transporting, storing, refining, processing, and trading crude oil, natural gas, gas condensate, coal bed methane, and other petroleum products. Our lawyers frequently draw upon our resources in the United States, Europe, and the Middle East for complex cross-border transactions and disputes.

financing, rigs and floating platforms, FPSOs, FSOs, FSRUs, and LNG liquefac-tion projects and financing.

Midstream: we participate in all phases of midstream project development and operation, including site identification and right-of-way acquisition, procurement and supply contracting, project authorization, and regulatory compliance, development, permitting and construction of transporta-tion pipelines and gas storage facilities; treating, processing, and fractionation of natural gas products in the negotiation of upstream and downstream contracts; and natural gas supply and transportation contracts.

Downstream: our work includes LNG regasification project development and finance, the development of third party access regimes and terms of conditions of access to LNG terminals, LNG and gas supply agreements and the trading and financing of petroleum products, LNG, and gas.

“Our lawyers understand both the

legal and commercial issues facing

the oil and gas sector.”

Sector Specific AdviceWe represent all participants in the oil and gas industry, including governments and government-owned corporations, produc-ers, drilling contractors, pipeline operators, sub-sea contractors, natural gas liquids processing companies, purchasers, and commercial lenders. Our work in this sector covers every stage of the supply chain, including:

Upstream: our exploration and produc-tion activities include license acquisitions and sales and farm-in transactions and their financing, negotiating concession agreements, joint operating agreements and joint bidding agreements, services contracts relating to drilling, vessel

Our ExperienceThe strength and capability of the K&L Gates Asia oil and gas practice group is evident in the range of challenging energy projects on which our lawyers have worked. Our integrated approach to the practice of law brings added value to our clients with deal progression supported at both the individual office level and through firmwide practice areas. Our lawyers understand both the legal and commercial issues facing the oil and gas sector. We advise clients on a broad range of corpo-rate, commercial, and financial matters, including:

• Acquisition and disposal of production titles

• Asset and trade finance

• Bidding arrangements

• Construction, engineering, and EPC contracts

• Cross-border mergers, acquisitions, and divestitures

• Environmental compliance

• Gas distribution and trading licenses

• International Arbitration and Commercial Disputes

• Joint Venture arrangements

• LPG, LNG, and crude sales

• Project development and finance

• Public-Private Partnerships (PPPs)

• Royalties and petroleum taxes

• Sub-sea and floating production facilities

• Transportation of petroleum

Representative WorkSoutheast Asia

• Advising a large Vietnamese oil company in connection with a US$1-billion bid to acquire assets in Vietnam.

• Advised the Indonesian government on the monetization of natural gas pro-duced from gas fields in East Java.

• Advised an international consortium proposing to construct the first oil refinery in Vietnam.

• Advised the national gas pipeline company of Indonesia on its sale of a strategic stake to a consortium of foreign investors.

• Advised on various aspects of the upstream petroleum industry in Vietnam, including the negotiation of a production sharing contract.

• Acted as owner’s Indonesian counsel for a US$450-million petrochemical project financing in East Java.

• Acted as purchaser’s counsel for US$80-million acquisition of Pertamina oil and gas production sharing contractor.

• Acted for a U.S. oil field developer in arbitration proceedings against a Thai engineering contractor relating to the supply of a wellhead platform for use in an oil field offshore Thailand.

• Acted in arbitration proceedings for one of the world’s largest owners/opera-tors of oil rigs under the VIAC rules in Vietnam following a dispute with a state oil company in relation to disputed operating/stand-by rates to be applied under a drilling contract following a loss of pressure/slumping incident in the White Tiger oil field offshore Vietnam.

• Acted in arbitration proceedings for a Singapore government owned shipyard in connection with a US$150-million dispute relating to a conversion of an oil rig in Rotterdam.

• Acted for a Nigerian crude oil trading company against an Indonesian state company in respect of alleged breach of a crude oil purchase contract.

• Acted in arbitration proceedings for a U.S. oil and gas equipment supplier in relation to a US$10-million claim against its Indonesian agent for breach of contract and various FCPA violations.

• Acted in arbitration proceedings for a Norwegian oil and gas company against an Australian contractor in relation to the fabrication, supply and installation of three topside process modules on an FPSO being converted at a Singapore yard.

• Acting for an Indonesian coal company in a US$50-million claim against an Indonesian SOE in relation to breach of a coal concession agreement and subsequent enforcement proceedings in Singapore.

• Acting for a U.S. oil field developer in a dispute with a Thai engineering contractor relating to the supply of a wellhead platform for use in an oil field offshore Thailand.

• Acting for the charterers of an FPSO in a dispute with the owners/operators as a result of serious operational issues following its deployment offshore Philippines.

• Acting for the contractors in relation to a dispute arising out of a contract for the provision of topside modules on an EPC contract for installation on an FPSO facility.

• Acting in potential ad hoc arbitra-tion proceedings for an oil and gas company in relation to a drill ship conversion and upgrading contract in respect of disputes against a shipyard.

• Advising a U.S. oil rig owner in defend-ing a claim from damage sustained to an oil platform as a result of a malfunctioning crane and pursuing counterclaims for ‘wait on weather’ and ‘standby time’ whilst demobilizing offshore Indonesia.

Greater China (China, Hong Kong, Taiwan)

• Advised China National Offshore Oil Corporation (CNOOC) on its US$3-billion acquisition of a 20-percent indi-rect interest in Pan American Energy LLC, the second largest upstream oil and gas producer in Argentina.

• Advised CNOOC on its US$212.5-million sale of entire shares in its BVI subsidiary to Talisman.

• Advised a major Chinese state-owned enterprise on its proposed acquisi-tion of oil and gas assets in Argentina, Bolivia, and Chile.

• Participated in disputes resolution regarding oil field investment in South America.

• Acted in arbitration proceedings for the world’s largest rig owner/operator in an unliquidated claim against a Chinese state-owned oil company concerning a drilling contract in relation to a well control incident on one of their rigs deployed offshore Myanmar.

• Advising a major U.S. oil rig owner in respect of its rights and liabilities in connection with the total loss of the BOP package and 52 riser joints after its rig sustained severe typhoon damage offshore Hong Kong resulting in a multi-party dispute.

• Advising a Norwegian owner and opera-tor of FPSOs and its various subsidiar-ies in Singapore in a US$100-million dollar dispute with a Chinese shipyard in relation to various FPSO construction projects and other agreements with the China yard.

Central and South Asia (India, Pakistan, Bangladesh, Sri Lanka)

• Advised an Indian oil company on the proposed acquisition of a partial interest in a company with upstream oil and gas interests in Africa, including preparing share purchase agreement, shareholders agreement, funding agreement, and crude oil purchase agreement.

• Advised an Indian oil company in relation to the construction of a multi-product pipeline in North Africa on a build-operate-lease-transfer (BOLT) basis and structuring for a prospective project financing.

• Advised a “supermajor” as developer of a greenfield LNG port, regasification, and gas transportation facility in India.

1015

9

• Advised an Indian oil company in relation to the expansion and refurbish-ment of a major refinery in the MENA region on a BOLT basis.

• Negotiated and drafted construction contracts for a Naphtha Cracker plant in Vadinar (India) and advised on aspects of the design and construct contract for the US$2.14-billion oil refinery in Gujarat, India.

Northern Asia (Eastern Russia, Japan and Korea)

• Advised a Japanese government-controlled entity on its participation in an international consortium of sponsors for the development of the Kovykta gas and gas condensate field in Irkutsk Region, East Siberia, Russia.

• Advised a U.S. oil major on the international legal framework for the construction of a submarine pipeline for the export of gas from Sakhalin Island, Far East Russia, to Japan, including Russian customs, tax, and public international laws.

• Advised the European Bank for Reconstruction and Development (EBRD), the U.S. Export-Import Bank, JBIC and ECGD as secured lenders to the Sakhalin II PSA Project on Sakhalin Island, Far East Russia. The Sakhalin II project includes off-shore extraction facilities for crude oil and gas, onshore transportation pipelines, and an LNG plant.

• Represented the EBRD in a five-year US$8-million loan to finance the initial development of an Arctic oil field in the Komi Republic in the Northeast part of European Russia by a small inde-pendent operator committed to envi-ronmental improvements and trans-parency. The borrower was Russia’s Pechora Energy, a 100-percent subsid-iary of UK registered Concorde Oil and Gas plc.

• Conducted a due diligence review of a mid-sized oil and gas Russian company based in Irkutsk. Reviewed its licenses, project documentation, real estate rights to use the surface area above its oil fields, title to its extraction facilities and pipelines, and environmen-tal and other compliance.

Learn more about our Asia Oil & Gas practice at klgates.com.

SingaporeMike Pollen

+65.6507.81204

mike.pollen@klgates.com

Hong KongMaria Tan Pedersen

+852.2230.3598

maria.pedersen@klgates.com

TaipeiChristina Yang

+886.2.2326.5198

christina.yang@klgates.com

BeijingRose Zhu

+86.10.5817.6110

rose.zhu@klgates.com

Contacts:

SingaporeRaja Bose

+65.6507.8125

raja.bose@klgates.com

Tokyo and MoscowSergey Milanov

+81.3.6205.3604 (Tokyo)

+7.495.643.1700 (Moscow)

sergey.milanov@klgates.com

“Our lawyers understand both the legal

and commercial issues facing the

oil and gas sector.”

• Representation of a U.S.-based oil company in relation to liquidation of a Japanese subsidiary.

• Advised Korean and Japanese sponsors and drafted engineering, procurement, and construction contracts for an LNG reception, storage, regasification, and delivery terminal located in Manzanillo, Mexico.

Note: Some of the transactions were com-pleted by K&L Gates lawyers while at their previous firms.

AlAskA Oil And GAs PrActice

Alaska’s vast oil and gas reserves account for a large proportion of current

United States domestic production, yet Alaska’s oil and gas potential remains

largely under explored. However, that is beginning to change. Renewed inter-

est in both offshore and onshore prospects, the application of technological

breakthroughs in the development of unconventional oil and gas resources,

and a surprisingly attractive state fiscal system are bringing new exploration

and development to Alaska’s oil and gas basins.

Since it opened in 1979, the Anchorage office of K&L Gates has represented a variety of participants in the Alaska oil and gas market, including exploration and production (E&P) companies, support services providers, local utilities, and the state of Alaska. As a result, K&L Gates has extensive knowledge and experience in the full range of Alaska oil and gas issues including leasing, permitting, royalty, taxation, unitization, transactions, and contracting.

K&L Gates’ oil and gas practice is built on a sophisticated and detailed understand-ing of the legal aspects of exploring for, producing, transporting, storing, market-ing, and processing oil, natural gas, and coal bed methane. Our oil and gas team is experienced in all areas of law associated with development and production of Alaska resources including:

• OilandGasLeases&Licensing

• Permitting

• TaxIssues

work on a range of engagements in the upstream, midstream, and downstream sectors, including oil and gas field development, petrochemical and refinery developments, and energy trading.

Inadditiontoouroil&gasexperience,our broader energy, infrastructure, and resources practice area leverages experi-ence from many fields to address these industries’ unique challenges. Lawyers throughout our offices work together to guide clients through strategic decisions, policy initiatives, commercial transac-tions, project financing and development, regulatory compliance, tax matters, credit trading, and litigation.

Permitting and taxation are the two primary issues with oil and gas development in Alaska. K&L Gates has unsurpassed expe-rience in both these challenging areas, with a broad knowledge of the complicated world of permitting in Alaska, and an insider’s understanding of the state’s taxa-tion and credit programs. We also assist our clients in navigating the dynamic busi-ness environment in Alaska, with extensive contacts among the service industry, Native Corporations, state and municipal governments,andenergyutilities.Inshort,K&L Gates provides comprehensive legal counsel in all areas affecting oil and gas development in Alaska.

• Litigation

• MediationandArbitration

• WaterUseandReuse

• SurfaceUseAgreements

• PublicPolicy

• MunicipalOrdinances

• AlaskaNativeCorporations

• MergersandAcquisitions

• BusinessEstablishmentandOperations

K&L Gates’ oil and gas team includes lawyers in Alaska and across our global office network. Our team represents clients with operations in major oil and natural gas-producing regions around the world. Our comprehensive oil and gas practice in the United States is recognized for its extensive experience in both conventional and unconventional formations throughout NorthAmerica.Thisexperienceisstronglycomplemented by significant pipeline and utility regulatory experience. Our lawyers

For more information about our Alaska Oil & Gas Practice, please contact:

contacts:

Patrick S. Galvin+1.907.777.7603

patrick.galvin@klgates.com 1030

6

our team

K&L Gates LLP K&L Gates Oil & Gas Practitioners Page 1

K&L Gates Oil and Gas Practitioners Below is a list of K&L Gates partners, of counsel, associates and government affairs counselors/advisors who practice primarily in the oil and gas industry. Their biographies can be found at www.klgates.com.

Lawyer Office Practice Phone Email Tom Birsic Pittsburgh Insurance Coverage 412.355.6538 thomas.birsic@klgates.com Walter Bunt Pittsburgh Litigation 412.355.8906 walter.bunt@klgates.com John Englert Pittsburgh Regulatory 412.355.8331 john.englert@klgates.com Mark Feczko Pittsburgh Litigation 412.355.6274 mark.feczko@klgates.com Donald Kortlandt

Pittsburgh Real Estate 412.355.6515 donald.kortlandt@klgates.com

Theodore McConnell

Pittsburgh Corporate, M&A and Securities

412.355.6566 ted.mcconnell@klgates.com

Michael McLean

Pittsburgh Corporate, M&A and Securities

412.355.6458 michael.mclean@klgates.com

Terrence Murphy

Pittsburgh Regulatory/Public Policy 412.355.6339 terry.murphy@klgates.com

Pierce Richardson

Pittsburgh Real Estate 412.355.6786 pierce.richardson@klgates.com

Henry Snyder Pittsburgh Tax 412.355.6720 henry.snyder@klgates.com Kristen Stewart

Pittsburgh Corporate, M&A and Securities

412.355.8925 kristen.stewart@klgates.com

George Bibikos

Harrisburg Litigation 717.231.4577 george.bibikos@klgates.com

Daniel Delaney

Harrisburg Energy & Utilities 717.231.4516 dan.delaney@klgates.com

David Fine Harrisburg Litigation 717.231.5820 david.fine@klgates.com Peter Gleason Harrisburg Public Policy 717.231.2892 peter.gleason@klgates.com Chris Nestor Harrisburg Litigation 717.231.4812 chistopher.nestor@klgates.com David Overstreet

Harrisburg Litigation 717.231.4517 david.overstreet@klgates.com

Timothy Weston

Harrisburg Energy/Environmental 717.231.4504 tim.weston@klgates.com

Craig Wilson Harrisburg Litigation 717.231.4509 craig.wilson@klgates.com Patrick Galvin

Anchorage Regulatory 907.777.7603 patrick.galvin@klgates.com

Jack Erskine Austin Public Policy 512.482.6875 jack.erskine@klgates.com Keith Shuley Austin Environmental 512.482.6887 keith.shuley@klgates.com John Cox Dallas Corporate, M&A and

Securities 214.939.5599 john.cox@klgates.com

Martin Garza Dallas Municipal Regulation 214.939.5802 martin.garza@klgates.com Bobby Majumder

Dallas Corporate, M&A and Securities

214.939.5945 bobby.majumder@klgates.com

William Hyatt

Newark Environmental/Energy 973.848.4045 william.hyatt@klgates.com

Brian Montag Newark Environmental/Energy 973.848.4044 brian.montag@klgates.com John Spinello Newark Regulatory,

Environmental 973.848.4061 john.spinello@klgates.com

K&L Gates LLP K&L Gates Oil & Gas Practitioners Page 2

Lawyer Office Practice Phone Email B. David Naidu

New York Regulatory, Environmental/Energy

212.536.4864 david.naidu@klgates.com

Donald Stever New York Environmental/Energy 212.536.4861 don.stever@klgates.com Gordon Peery Orange County Financial Services 949.623.3535 gordon.peery@klgates.com Carl Fink Portland Energy/FERC 503.226.5725 carl.fink@klgates.com Stanford Baird

Raleigh Environmental/Energy 919.743.7334 stanford.baird@klgates.com

Barry Hartman

Washington DC Environmental/Litigation 202.778.9338 barry.hartman@klgates.com

Cliff Rothenstein

Washington DC Regulatory/Public Policy 202.778.9381 cliff.rothenstein@klgates.com

Hon. Jim Walsh

Washington DC Regulatory/Public Policy 202.778.9321 jim.walsh@klgates.com

Rose Zhu Beijing Corporate, M&A and Securities

+86.10.5817.6110 rose.zhu@klgates.com

Paul de Cordova

Dubai Litigation +971.4.427.2804 paul.decordova@klgates.com

Patricia Tiller Dubai Litigation +971.4.427.2711 patricia.tiller@klgates.com Mathew Kidwell

London/Dubai Litigation +44.(0)20.7360.8141 (London)/ +971.4.427.2700 (Dubai)

mathew.kidwell@klgates.com

Howard Kleiman

London Corporate, M&A and Securities

+44.(0)20.7360.8142

howard.kleiman@klgates.com

Jeremy Landau

London Corporate, M&A and Securities

+44.(0)20.7360.8114

jeremy.landau@klgates.com

Georgy Borisov

Moscow Corporate, M&A and Securities

+7.495.643.1700 georgy.borisov@klgates.com

William Reichert

Moscow Corporate, M&A and Securities

+7.495.643.1712 william.reichert@klgates.com

Raja Bose Singapore Litigation +65.6507.8125 raja.bose@klgates.com Michael James Pollen

Singapore Litigation +65.6507.8120 mike.pollen@klgates.com

Christina Yang

Taipei Corporate, M&A and Securities

+886.2.2326.5198 christina.yang@klgates.com

Tomasz Dobrowolski

Warsaw Regulatory +48.22.653.4221 tomasz.dobrowolski@klgates.com

K&L Gates LLP K&L Gates Oil & Gas Practitioners Page 3

K&L Gates Supporting Lawyers Biographies for the K&L Gates partners listed below can be found at www.klgates.com.

Lawyer Office Practice Phone Email Richard Paciaroni Pittsburgh Construction 412.355.6767 richard.paciaroni@klgates.com Jason Richey Pittsburgh Construction 412.355.6260 jason.richey@klgates.com Matthew Smith London Construction 44.(0).20.7360.8

246 matthew.smith@klgates.com

Jeremy Davis London Corporate, M&A and Securities

44.(0).20.7360.8133

jeremy.davis@klgates.com

Jacqueline Fu Taipei Corporate, M&A and Securities

886.2.2326.5125 jacqueline.fu@klgates.com

Richard Herbert London Corporate, M&A and Securities

44.(0).20.7360.8104

richard.herbert@klgates.com

Robert Langer New York/Moscow

Corporate, M&A and Securities

212.536.4818 (New York)/ 7.495.643.1700 (Moscow)

robert.langer@klgates.com

David Luther Dallas Corporate, M&A and Securities

214.939.5535 david.luther@klgates.com

Ronald West Pittsburgh Corporate, M&A and Securities

412.355.6752 ronald.west@klgates.com

Owen Waft Dubai Corporate, M&A and Securities

971.4.427.2714 owen.waft@klgates.com

James Green London Energy 44.(0).20.7360.8105

james.green@klgates.com

Thomas Carey Chicago Environmental 312.807.4365 tom.carey@klgates.com Gail Conenello Newark Environmental 973.848.4048 gail.conenello@klgates.com John “Jack” Krill Harrisburg Environmental 717.231.4505 john.krill@klgates.com Steven Epstein New York Finance 212.536.4830 steve.epstein@klgates.com Charlie Harris Pittsburgh Finance 412.355.6730 charles.harris@klgates.com John Sylvester Pittsburgh Insurance Coverage 412.355.8617 john.sylvester@klgates.com Michael Zanic Pittsburgh Insurance Coverage 412.355.6219 michael.zanic@klgates.com Michael Brodowski, Ph.D.

Boston Intellectual Property 617.261.3113 michael.brodowski@klgates.com

Roberto Capriotti Pittsburgh Intellectual Property 412.355.6423 roberto.capriotti@klgates.com George Dickos Pittsburgh Intellectual Property 412.355.6785 george.dickos@klgates.com Stephen Glazier Washington

DC Intellectual Property 202.778.9045 stephen.glazier@klgates.com

William Kuss Pittsburgh Intellectual Property 412.355.6323 william.kuss@klgates.com Rick Hosking Pittsburgh Litigation 412.355.8612 richard.hosking@klgates.com Cliff Hutchinson Dallas Litigation 214.939.5444 cliff.hutchinson@klgates.com Ian Meredith London Litigation 44.(0).20.7360.8

171 ian.meredith@klgates.com

Linda Moore Dallas Litigation 214.939.4908 linda.moore@klgates.com Charles Rysavy Newark Litigation 973.848.4053 charles.rysavy@klgates.com David Seidler Fort Worth Litigation 817.347.5275 david.seidler@klgates.com Dan Trocchio Pittsburgh Litigation 412.355.6284 dan.trocchio@klgates.com

K&L Gates LLP K&L Gates Oil & Gas Practitioners Page 4

Lawyer Office Practice Phone Email Paul Simpson Dubai/Doha Project Development

and Finance 971.4.427.2721 (Dubai)/ 974.4424.6100 (Doha)

paul.simpson@klgates.com

Eugene Segrest Dallas Real Estate 214.939.4991 eugene.segrest@klgates.com Ronald Aulbach Pittsburgh Tax 412.355.6249 ron.aulbach@klgates.com Stephen Barge Pittsburgh Tax 412.355.8330 steve.barge@klgates.com Scott Newman New York Tax 212.536.4054 scott.newman@klgates.com

additional materials

K&L Gates Articles and Alerts

“K&L Gates Represents Oil and Gas Producers in Major Pennsylvania Supreme Court Victory”, Oil & Gas Alert, by David R. Overstreet, V. Abe Delnore, April 4, 2012.

“Final Implementation of Pennsylvania’s Gas and Hazardous Liquids Pipelines Act”, Oil & Gas Alert, by Daniel P. Delaney, George A. Bibikos, Bryan D. Rohm, March 2, 2012.

“Two Birds by the Pit: Courts Split Over Well Operator Liabilities under the Federal Migratory Bird Treaty Act”, Oil & Gas Alert, by George A. Bibikos, Tad J. Macfarlan, Stephen J. Matzura, February 21, 2012.

“Pennsylvania Legislation Authorizing Counties to Levy Unconventional Gas Well Fee Signed Into Law”, Oil and Gas Alert, by Raymond P. Pepe, February 15, 2012.

“New Pennsylvania Oil and Gas Law Targets Unconventional Gas Operations for Heightened Regulatory Oversight”, Oil & Gas Alert, by Tad J. Macfarlan, R. Timothy Weston, Craig P. Wilson, February 14, 2012.

“Pennsylvania’s Oil and Gas Act Amended to Require ‘Uniformity’ with Respect to Municipal Ordinances Regulating Oil and Gas Operations”, Oil & Gas Alert, by Christopher R. Nestor, Walter A. Bunt, Jr., David R. Overstreet, February 9, 2012.

“Pennsylvania’s New Gas and Hazardous Liquids Pipeline Act”, Oil and Gas Alert,by Daniel P. Delaney, George A. Bibikos, Bryan D. Rohm, January 3, 2012.

“EPA to Require Chemical Disclosure under TSCA by Hydraulic Fracturing Fluid Manufacturers”, Oil & Gas Alert, by Cliff L. Rothenstein, Tad J. Macfarlan, December 2, 2011.

“PaDEP Issues Interim Guidance on Air Aggregation, Moves Away From ‘Functional Interdependence’ Test”, Oil & Gas Alert, by David R. Overstreet, Tad J. Macfarlan, November 11, 2011.

“Ohio EPA Releases Draft General Permit for Oil and Gas Well-Site Production Operations”, Oil and Gas Alert, by Bryan D. Rohm, David R. Overstreet, Craig P. Wilson, November 3, 2011.

“Battles Over the Federal Policies Regulating Hydraulic Fracturing”, Public Policy and Law Alert, by Cliff L. Rothenstein, Michael W. Evans, Cindy L. O'Malley, October 17, 2011.

“Third Circuit Gives Natural-Gas Producers Important Ammunition for Obtaining Expedited Injunctive Relief from the Courts”, Oil and Gas Alert, by Nicholas Ranjan, George A. Bibikos, October 10, 2011.

“Is Marcellus Shale a ‘Mineral,’ and Who Owns the Natural Gas in the Shale?”, Oil and Gas Alert, by George A. Bibikos, Bryan D. Rohm, September 20, 2011.

K&L Gates includes lawyers practicing out of more than 40 offices located in North America, South America, Europe, Asia and the Middle East, and represents numerous GLOBAL 500, FORTUNE 100, and FTSE 100 corporations, in addition to growth and middle market companies, entrepreneurs, capital market participants and public sector entities. For more information about K&L Gates or its locations and registrations, visit www.klgates.com. This publication is for informational purposes and does not contain or convey legal advice. The information herein should not be used or relied upon in regard to any particular facts or circumstances without first consulting a lawyer. ©2012 K&L Gates LLP. All Rights Reserved. K&L Gates LLP

K&L Gates LLP

“West Virginia Governor Orders WVDEP to Enact Marcellus Shale-Specific Regulations”, Oil and Gas Alert, by Brian P. Anderson, R. Timothy Weston, July 29, 2011.

“North Carolina Takes a Step Closer to Shale Gas Production”, Oil & Gas Alert, by Stanford D. Baird, James L. Joyce, July 22, 2011.

“The Chesapeake Bay Foundation Settlement – Changing Directions for E&S Regulation of Oil & Gas Projects”, Oil and Gas Alert, by R. Timothy Weston, July 6, 2011.

“Why the Public Utility Commission's Laser Northeast Decision Will Not Lead to Regulation of All Natural Gas Gathering and Transportation Pipelines in Pennsylvania”, Oil and Gas Alert, by Daniel P. Delaney, July 1, 2011.

OnStream, K&L Gates' Newsletter for the International Oil & Gas Industry, K&L Gates Oil & Gas Publication, Summer 2011.

“A New Conservation Law for Pennsylvania?”, Oil & Gas Alert, by George A. Bibikos. May 10, 2011.

Water and Wastewater Issues in Conducting Operations in a Shale Play – The Appalachian Basin Experience, Rocky Mountain Mineral Law Foundation, Development Issues in Major Shale Gas Plays, by R. Timothy Weston, December 2010.

K&L Gates Represents Oil and Gas Producers in Major Pennsylvania Supreme Court Victory

April 4, 2012 Practice Group(s): Energy, Infrastructure and Resources Oil & Gas By David R. Overstreet and V. Abe Delnore

On March 26, 2012, the Pennsylvania Supreme Court issued its long-awaited decision in T.W. Phillips Gas & Oil Co. v. Jedlicka, ___ A.3d ___, Docket No. 19 WAP 2009 (Pa. March 26, 2012). In a major victory for Pennsylvania’s oil and gas producers and K&L Gates, the Court held that, under standard oil and gas lease language requiring that oil or gas be “produced in paying quantities,” any operational profit suffices to hold the lease, and even if a well experiences periods of unprofitability, the producer’s subjective good faith in continuing to operate suffices to hold the lease. The decision thus affirms the validity of many older leases that have been held by continuous, albeit low-level, production for decades in regions that are now experiencing a new wave of development.

The dispute arose out of a 1928 lease of oil and gas rights in a 163-acre tract in North Mahoning Township, Indiana County, Pennsylvania, under which defendant T.W. Phillips Gas & Oil Co. was lessee. The lease would last “for the term of two years, and as long thereafter as oil or gas is produced in paying quantities.” The tract was subsequently subdivided. Plaintiff Ann Jedlicka came to own 70 acres, on which lay one of the four wells originally drilled in 1929. In 2004, T.W. Phillips assigned the leasehold to codefendant PC Exploration, Inc., who promptly drilled four further wells on Jedlicka’s property and planned to drill four more.

The litigation began in 2005, when Jedlicka filed declaratory judgment action in the Court of Common Pleas of Indiana County, Pennsylvania. Jedlicka argued that T.W. Phillips and PC Exploration had not “produced in paying quantities” for the entire lease term because, in 1959, the wells had recorded a $40 loss. Jedlicka identified no other period in which the wells had not shown a profit. Nonetheless, Jedlicka sought to have the lease declared canceled as to her property. T.W. Phillips and PC Exploration, on the other hand, argued that the lease remained valid because it had paid a profit over any longer term and because they had operated in good faith.

The trial court held a nonjury trial on April 16, 2007, at the conclusion of which the court held that the lessees had produced gas “in paying quantities” throughout the life of the lease, notwithstanding the 1959 loss. The trial court noted its reliance on Young v. Forest Oil, 45 A. 1 (Pa. 1899), for the proposition that courts owe deference to a lessee’s good faith judgment that a well is producing “in paying quantities.”

Jedlicka appealed to the Superior Court, which affirmed in a decision dated December 29, 2008. T.W. Phillips Gas & Oil Co. v. Jedlicka, 964 A.2d 13 (Pa. Super. Ct. 2008). The Pennsylvania Supreme Court granted Jedlicka’s petition for appeal to consider whether the Superior Court had misapplied Young.

After able handling by trial counsel, T.W. Phillips and PC Exploration retained K&L Gates as appellate counsel at the Superior and Supreme Court phases. Pittsburgh-based K&L Gates partner Walter Bunt assembled a team for briefing and argued the case on April 10, 2010.

K&L Gates Represents Oil and Gas Producers in Major Pennsylvania Supreme Court Victory

Although it took nearly two years for the Pennsylvania Supreme Court to issue its decision affirming, the result was a clear win for lessees, affirming the continuing vitality of both well-established Pennsylvania precedent and thousands of oil and gas leases across the Commonwealth.

Justice Todd, writing for a four-justice majority, held that the courts below had properly applied Young, especially when that case was read in conjunction with another one that was decided the same day, Colgan v. Forest Oil Co., 45 A. 119 (Pa. 1899), which emphasized the deference lessors and courts owed to lessees’ business judgment. Justice Todd’s opinion synthesizes Young and Colgan to present the following test:

[W]e hold that, if a well consistently pays a profit, however small, over operating expenses, it will be deemed to have produced in paying quantities. Where, however, production on a well has been marginal or sporadic, such that, over some period, the well’s profits do not exceed its operating expenses, a determination of whether the well has produced in paying quantities requires consideration of the operator’s good faith judgment in maintaining operation of the well.

Jedlicka, slip op., at 22. The Court did not define precisely over what period profitability should be judged, holding that this would have to be determined on a case-by-case basis.

Significantly, although the Court cited some cases from other jurisdictions, it expressly did not adopt the “prudent operator” standard, which would have injected an objective standard into Pennsylvania’s long-standing “subjective good faith” test. Rather, the Jedlicka decision emphasizes that the actual lessee’s own situation and conduct are what matters. This emphasis on the lessee’s perspective, the Court reasoned, is necessary to protect lessees from lessors who seek to terminate leases on the basis of isolated, long-ago periods of unprofitability, which is how the Court characterized Jedlicka’s lawsuit. Id. at 23.

The Court thus held that, in this specific case, Jedlicka had failed to establish the lessees’ lack of good faith. Id. at 24. The Court also suggested that the trial court could have properly found that a single year was not a reasonable period over which to assess profitability, in which case the good faith inquiry would not have been necessary. Id.

Justice Eakin wrote a short concurring opinion, in which he observed that the lease language in question had originally been introduced to benefit the lessee. Justice Eakin strongly rejected Jedlicka’s contention that showing a one-year period of unprofitability could throw a “paying quantities” lease into question. Thus, he would not have reached the question of T.W. Phillips’ good faith.

Justice Saylor, alone, dissented. Justice Saylor would have inverted the majority’s test and held that, in order to hold a lease by production, the lessee must show both that the well is profitable and that lessee is operating according to objective standards of good faith. Justice Saylor would therefore have remanded for further factual development.

Justice Orie Melvin, who had been part of the Superior Court panel that heard this case, recused herself.

The Jedlicka decision thus vastly circumscribes the number of situations in which a decades-old business decision or market condition will reach forward and invalidate a lease. The decision gives comfort to those Pennsylvania producers operating old leases.

Jedlicka is the fourth oil and gas case K&L Gates has successfully litigated before the Pennsylvania Supreme Court in recent years, following Kilmer v. Elexco Land Services Company, Range

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K&L Gates Represents Oil and Gas Producers in Major Pennsylvania Supreme Court Victory

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Resources-Appalachia, LLC, et al. v. Salem Township, et al., and Belden & Blake Corp. v. Commonwealth of Pennsylvania, Department of Conservation and Natural Resources. In each case, the Pennsylvania Supreme Court reaffirmed Pennsylvania’s long-standing pro-development policies. This victory marks a “hat trick” for Walter Bunt, who also argued Range Resources-Appalachia and Belden & Blake. Pittsburgh associate Michael Ross assisted in Jedlicka.

Authors: David R. Overstreet david.overstreet@klgates.com +1.412.355.8263

V. Abe Delnore abe.delnore@klgates.com +1.412.355.6425

Final Implementation of Pennsylvania’s Gas and Hazardous Liquids Pipelines Act

March 2, 2012 Practice Group(s): Energy, Infrastructure and Resources Oil & Gas

By Daniel P. Delaney, George A. Bibikos, Bryan D. Rohm

Introduction On February 17, 2012, the Pennsylvania Public Utility Commission (“PUC”) issued a final implementation order (the “Final Implementation Order”) to implement the recently enacted Gas and Hazardous Liquids Pipelines Act (the “Act”). A general overview of the Act is described in a prior alert. The Final Implementation Order sets forth determinations regarding the Act and provides final registration materials for pipeline operators that are subject to the Act.

Prior to the adoption of the Final Implementation Order, the PUC issued a tentative implementation order (the “Tentative Implementation Order”), along with proposed registration and reporting forms and invited public comment thereto. In addition to seeking public comment, the PUC held a conference call during which the PUC staff discussed its implementation of the Act with industry stakeholders.

The Final Implementation Order adopts much of the Tentative Implementation Order, and addresses and clarifies issues that were identified to the Tentative Implementation Order via written comments and the conference call held by the PUC.

What Are Some of the Key Aspects of the Implementation Orders? Registration requirements. Pipeline operators subject to the Act must register annually with the

PUC. However, the Act does not indicate when registrations are due or what information is required to be submitted with each registration. The Final Implementation Order provides that pipeline operators shall file an initial registration form by March 16, 2012. The initial registration form is attached to the Final Implementation Order and should be submitted via the PUC’s eFile system. (Entities with multiple U.S. DOT Operator ID numbers must register each as a separate pipeline operator.)

Jurisdiction of the Act over farm taps. Pipelines that are located in Class 1 locations that have no distribution service are not within the Act’s jurisdiction. However, farm taps are a type of distribution service regulated under the Federal pipeline safety laws, regardless of class location. Commentators to the Tentative Implementation Order requested that the PUC determine that all operators in Class 1 areas transporting gas from conventional wells be excluded from the Act, regardless of the existence of farm taps. The Final Implementation Order clarifies the PUC’s position that an entire pipeline should not be treated as subject to assessment under the Act due to the existence of a farm tap. Nevertheless, operators of pipelines in Class 1 locations with farm taps are still required to register with the PUC as pipeline operators under the Act. However, the PUC has adjusted the registration form to provide that pipelines in Class 1 areas need to report the total mileage and the number of farm taps.

Mixed gas situations. Commentators to the Tentative Implementation Order requested that the PUC adopt threshold requirements for the amount of natural gas from unconventional wells in a

Final Implementation of Pennsylvania’s Gas and Hazardous Liquids Pipelines Act

pipeline that would trigger the Act’s jurisdiction over pipelines in Class 1 areas serving unconventional wells. The Final Implementation Order adopts a threshold requirement of at least 50% of gas in a pipeline that originates from unconventional wells. If so, the pipeline is a Class 1 area serving unconventional wells and is subject to reporting requirements under the Act.

Steel products. Registration requires that pipeline operators disclose the country of manufacture for all “tubular steel products” used in the exploration, gathering or transportation of natural gas or hazardous liquids within the Commonwealth. The Final Implementation Order clarifies that this reporting requirement only applies to pipeline operators who are subject to the Act, and despite ambiguity in the Act, operators and producers who are not pipeline operators do not have steel product reporting requirements. The Tentative Implementation Order further defines “tubular steel products” to mean “the actual pipe to be used in the transportation of gas and excludes valves as well as other facilities or equipment.” Steel pipe used on the well pad and in downhole operations will not be subject to this reporting requirement. However, the Final Implementation Order does provide that pipeline operators are required to comply with the country of manufacture reporting requirements for pipelines in Class 1 areas that are not otherwise subject to the Act by March 16, 2012. Measurements are to be made in feet. To establish a pipe’s country of origin, pipeline operators may rely on the country of origin indicated on invoices or the stamp on the actual pipe itself. The Final Implementation Order allows a pipeline operator to utilize the results of a “Material Test Report” in this determination. Country of origin registrations will be limited to pipe that was installed in the prior calendar year. For “tubular steel products” whose country of manufacture is unknown, a pipeline operator will be required to report the length of the unknown pipe.

Hazardous liquids. Commentators to the Tentative Implementation Order observed that the draft registration form was not conducive for reporting regarding hazardous liquids pipelines. In the Final Implementation Order, the PUC confirms that non-public utility hazardous liquids pipelines within Pennsylvania must be registered as part of the Act. However, the PUC acknowledges that it does not yet have an agreement with PHMSA for the PUC to perform inspections of such hazardous liquids pipelines. Therefore, for the 2011 – 2012 fiscal year, the PUC will require registration of hazardous liquids pipelines, but will not conduct any inspections until the PUC and PHMSA enter into an agreement regarding such inspections. Consequently, the PUC will not assess hazardous liquids pipelines for the 2011 – 2012 assessment year. In anticipation of reaching an agreement with PHMSA for the 2012 – 2013 assessment year, an attachment to the registration form has been added for reporting mileage for hazardous liquids pipelines.

Annual report of pipeline miles by county. The Act provides that on or before March 31 of each year, pipeline operators subject to the Act must file annual reports disclosing the pipeline operator’s total miles of regulated pipeline in the Commonwealth during the prior calendar year. The Tentative Implementation Order provides that the registration shall include the location of the pipeline, broken down by class location and approximate aggregate miles of pipeline. The Final Implementation Order clarifies that mileage should be reported to the nearest 1/10th of a mile.

Jurisdiction over landfill gas distribution systems. Commentators sought guidance regarding the PUC’s jurisdiction over landfill gas distribution systems. In the Final Implementation Order, the PUC indicates that pipeline systems on a landfill site are not subject to jurisdiction under the Act. However, any pipeline outside of the landfill site could be subject to the PUC’s jurisdiction if it otherwise meets the Act’s jurisdictional requirements.

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Final Implementation of Pennsylvania’s Gas and Hazardous Liquids Pipelines Act

Assessments. The Act authorizes the PUC to recover the cost of regulation based on the number of miles of regulated pipeline. The Tentative and Final Implementation Orders provide that the PUC will determine its annual costs (excluding costs otherwise reimbursed by the Federal Government) based upon its fiscal year (July 1 through June 30). For the 2011 – 2012 and 2012 – 2013 fiscal years, the annual assessment will be estimated by the PUC. Invoices for the 2011 – 2012 fiscal year will be issued on March 30, 2012, with payment requested to be made by April 16, 2012, but in any event no later than April 30, 2012. Invoices for the 2012 – 2013 fiscal year will be issued in July 2012, with payment due within 30 days of the postmark date of the invoice. Beginning in the 2013 – 2014 fiscal year, the PUC will begin assessing in accordance with its approved budget, and conduct an initial reconciliation for any over or under-collection of assessments for 2011 – 2012 and/or 2012 – 2013.

What Are the Key Dates Adopted in the Final Implementation Order? March 16, 2012. Initial registrations are due.

March 30, 2012. Invoices for the 2011 – 2012 assessment will be issued.

April 30, 2012. Payments for the 2011 – 2012 fiscal year assessment are due.

July 2012. Invoices for the 2012 – 2013 assessment will be issued. Payments will be due within 30 days of the postmark date of the invoice.

What Should Pipeline Operators Do? Registration. Pipeline operators should begin preparing initial registrations in order to meet the

March 16, 2012 deadline. Questions about jurisdiction, mixed gas situations, and steel products registration should be directed to experienced counsel to ensure that the initial registration is completed properly.

Assessments. Pipeline operators should examine their assessment invoice carefully and be prepared to file objections, if necessary, with the assistance of experienced counsel, within 15 days of receiving the notice.

Authors: Daniel P. Delaney dan.delaney@klgates.com +1.717.231.4516

George A. Bibikos george.bibikos@klgates.com +1.717.231.4577

Bryan D. Rohm bryan.rohm@klgates.com +1.412.355.8682

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Final Implementation of Pennsylvania’s Gas and Hazardous Liquids Pipelines Act

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Two Birds by the Pit: Courts Split Over Well Operator Liabilities under the Federal Migratory Bird Treaty Act

February 21, 2012 Practice Group(s): Energy, Infrastructure and Resources Oil & Gas By George A. Bibikos, Tad J. Macfarlan, Stephen J. Matzura

Introduction A recent federal court decision in North Dakota focuses on an issue of concern to oil and gas operators nationwide – whether unintended fatalities of migrating birds at well sites can give rise to criminal liability under the Migratory Bird Treaty Act (“MBTA”).1 The North Dakota district court dismissed criminal charges brought by the United States Fish and Wildlife Service (“FWS”) against several operators for unintended bird deaths that occurred near reserve pits at well sites. The court’s decision in United States v. Brigham Oil & Gas, L.P.2 represents the narrow view that the MBTA should only impose criminal liability on those who deliberately “take” or “kill” migratory birds, but not those engaged in lawful activities that happen to result in unintended deaths of migratory birds. Other federal courts have taken a different view, interpreting the MBTA as imposing criminal liability for reasonably foreseeable migratory bird fatalities proximately caused by otherwise lawful conduct, including well-site operations. As the Brigham Oil & Gas decision illustrates, the courts that have imposed criminal penalties for unintended bird deaths have struggled to define the scope of liability under the MBTA.

The federal government has appealed the decision to the Eighth Circuit Court of Appeals.3 Operators may wish to consider ways to weigh in, such as participating as an amicus party, to offer additional industry perspectives to the Eighth Circuit as it prepares to decide this important and developing issue on appeal.

The Migratory Bird Treaty Act The key issue for operators with respect to the MBTA is whether unintended bird deaths that result from well-site operations can lead to criminal liability. Section 703 of the MBTA provides that “it shall be unlawful at any time, by any means or in any manner, to pursue, hunt, take, capture, [or] kill . . . any migratory bird” protected under the Act, or “any part, nest, or egg of any such bird.” The key words are “take” and “kill.” The statute does not define those words, and the implementing regulations merely add shooting, wounding, trapping, and collecting to the list of prohibited acts. Given the lack of clear guidance in the statute and regulations, courts have interpreted the statute on a case-by-case basis and reached different conclusions about whether otherwise lawful conduct that results in an unintended bird death constitutes a violation of the Act.

1 Migratory Bird Treaty Act, 16 U.S.C. §§ 703-712 (“MBTA” or “the Act”). 2 United States v. Brigham Oil & Gas, L.P., No. 4:11-po-005, -009, -004, 2012 U.S. Dist. LEXIS 5774 (D.N.D. Jan. 17, 2012). 3 United States v. Brigham Oil & Gas, L.P., No. 12-1376 (8th Cir.).

Two Birds by the Pit: Courts Split Over Well Operator Liabilities under the Federal Migratory Bird Treaty Act

The differences in judicial interpretation of the MBTA are highlighted in other contexts that may influence court decisions and impact the oil and gas industry. For example, in a habitat-destruction case in the Marcellus Shale region, a district court in Pennsylvania endorsed a narrow reading of the MBTA, explaining that “the loss of migratory birds as a result of timber sales . . . do[es] not constitute a ‘taking’ or ‘killing’ within the meaning of the MBTA.” 4 In contrast, courts in other oil-and-gas-producing areas have interpreted the MBTA broadly. For instance, a federal court in Colorado held that, if the government established proximate cause, an electricity provider could be criminally liable for the unintended electrocution of birds from power lines that supplied electricity to oil fields.5

Cases in the Oil and Gas Context In the 1970s, the government first demonstrated its willingness to prosecute the oil and gas industry under the MBTA for bird deaths resulting from pits at well sites. These cases were resolved without meaningful court interpretations of the Act. Recently, however, several courts have addressed the scope of criminal liability under the MBTA for unintended bird deaths at oil and gas well sites, with differing outcomes.

No liability under the Act for unintended migratory bird deaths at well sites.

In New Mexico and Louisiana, federal district courts have taken a narrow view of liability under the MBTA for bird fatalities at well sites. In United States v. Ray Westall Operating, Inc., fifty dead birds had been discovered in the operator’s evaporation pit. The pit was covered by chicken wire, but a technical malfunction caused overflow water to pool above the level of the sagging netting. The federal district court concluded “that Congress intended to prohibit only conduct directed towards birds and did not intend to criminalize negligent acts or omissions that are not directed at birds, but which incidentally and proximately cause bird deaths.”6 As a result, the court held that the operator was not liable under the Act.

Similarly, a federal district court in Louisiana found that the MBTA and its implementing regulations were “not intended to apply to commercial ventures where, occasionally, protected species might be incidentally killed as a result of totally legal and permissible activities, as happened here.”7 Thirty-five Brown Pelicans had died in the space between the outer wall of a wellhead and the inner wall of a “caisson,” a steel structure designed to protect the wellhead from damage due to contact with boats. The court’s opinion suggests that liability might attach when a “prohibited act” leads to bird deaths, highlighting the importance of regulatory compliance.

Strict liability under the Act for activities that “proximately cause” migratory bird deaths at well sites.

The United States Court of Appeals for the Tenth Circuit (which includes Colorado, Kansas, New Mexico, Oklahoma, Utah, and Wyoming) has concluded that operators are strictly liable for unintended bird deaths “proximately caused” by well-site activities.8 In United States v. Apollo Energies, Inc., dead birds had been found in the defendants’ heater-treaters. The court found it inconsequential that one of the operators had attempted (unsuccessfully) to prevent birds from entering the equipment. Instead, the critical question was whether it was reasonably foreseeable that 4 Curry v. U.S. Forest Service, 988 F. Supp. 541 (W.D. Pa. 1997). 5 United States v. Moon Lake Electric Ass’n, Inc., 45 F. Supp. 2d 1070 (D. Colo. 1999). 6 United States v. Ray Westall Operating, Inc., No. CR 05-1516-MV, 2009 U.S. Dist. LEXIS 130674 (D.N.M. Feb. 25, 2009). 7 United States v. Chevron USA, Inc., No. 09-CR-0132, 2009 U.S. Dist. LEXIS 102682 (W.D. La. Oct. 30, 2009). 8 United States v. Apollo Energies, Inc., 611 F.3d 679 (10th Cir. 2010).

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Two Birds by the Pit: Courts Split Over Well Operator Liabilities under the Federal Migratory Bird Treaty Act

migratory birds would die because of the equipment. The court held operators strictly liable for any bird deaths that occurred after they had been put on notice of the threat posed by heater-treaters. Under a broad reading of the Tenth Circuit’s decision, nearly every migratory bird death at an oil and gas site may be criminally punishable under the MBTA.

United States v. Brigham Oil & Gas, L.P. Against this back-drop, the court in Brigham Oil & Gas addressed the issue of MBTA liability for bird deaths near reserve pits. The government alleged that two of the well-operator defendants’ reserve pits were not netted when inspected by the FWS. While there was no indication whether the third company’s reserve pit was netted, it had allegedly overflowed, releasing fluid into a nearby wetland where dead birds were found. The court dismissed charges against all defendants, holding “that the use of reserve pits in commercial oil development is legal, commercially useful activity that stands outside the reach of the [MBTA].”

The following are some key elements of the court’s opinion:

The court endorsed a narrow reading of the Act. Relying on Eighth Circuit precedent interpreting the MBTA in other contexts, the court concluded that “take” and “kill” meant only “physical conduct of the sort engaged in by hunters and poachers, conduct which was undoubtedly a concern at the time of the statute’s enactment in 1918.” Because oil and gas development is not like hunting and poaching, the court held that these lawful activities cannot give rise to liability under the MBTA even if they incidentally cause the death of a protected migratory bird.

The court construed all doubt in favor of the accused. The court also relied upon the venerable interpretative maxim that an ambiguous criminal statute should be construed narrowly and in favor of defendants in cases of uncertain application (the “rule of lenity”).

The court rejected a broader reading that would criminalize lawful behavior. The court noted that a reading of the statute that allowed liability for any activity that “proximately causes” bird deaths would mean criminalizing many everyday activities, such as driving a vehicle, owning a building with windows, and cutting brush and trees, all of which are perfectly legal but may cause the death of a protected migratory bird.

Conclusion Brigham Oil & Gas represents another small step in favor of a narrow interpretation of the MBTA. However, the court’s decision should not be construed as settling the scope of MBTA liability. As noted, some courts have reached different conclusions about the scope of liability under the MBTA, and there remains no reliable indication of how broadly or narrowly the federal courts will apply the MBTA to incidental bird deaths at oil and gas well sites.

In light of the government’s appeal, the Brigham Oil & Gas case is now in the hands of the Eighth Circuit. Given that the court’s decision may influence interpretations of the Act in other regions that have substantial oil and gas activities, the industry should consider opportunities to participate as an amicus party in this case. In addition, there may be other opportunities for stakeholders to participate in agency interpretations or legislation that will address the issue going forward. In the meantime, until greater clarity develops, the industry should be mindful of potential liabilities under the MBTA and possible means of reducing those risks by limiting attraction and exposure of migrating birds.

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Two Birds by the Pit: Courts Split Over Well Operator Liabilities under the Federal Migratory Bird Treaty Act

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Authors: George A. Bibikos george.bibikos@klgates.com +1.717.231.4577

Tad J. Macfarlan tad.macfarlan@klgates.com +1.717.231.4513

Stephen J. Matzura stephen.matzura@klgates.com +1.717.231.5842

Additional Contact R. Timothy Weston timothy.weston@klgates.com +1.717.231.4504

Pennsylvania Legislation Authorizing Counties to Levy Unconventional Gas Well Fee Signed Into Law

February 15, 2012 Practice Group(s): Energy, Infrastructure and Resources Oil & Gas By Raymond P. Pepe

Summary On February 14, 2012, Pennsylvania’s Governor, Tom Corbett, signed into law legislation (House Bill 1950)1 authorizing counties to impose a fee on persons holding permits to sever natural gas for sale, profit or commercial use in the Commonwealth.2 The fee is imposed annually on each bore hole spud in the immediately prior year and applies only to wells drilled to produce gas from “unconventional” shale formations which require hydraulic fracture treatments or multilateral bore holes to produce gas at economic flow rates.3 The legislation takes effect immediately.

The fee applies to wells developed for the production of all types of hydrocarbon gases, including associated gas or casing head gas from oil fields, non-associated gas from reservoirs that do not contain significant quantities of crude oil, and gas produced from coal beds, shale beds and other formations, but does not apply to coal bed methane, or to wells used to recover gas from storage sites from which the gas did not originate.

The obligation to pay the fee arises when the drilling actually begins regardless of when the well is completed and applies regardless of whether and when the well produces any natural gas.4 Once the obligation to pay the fee arises, it continues annually for a period of 15 years unless the obligation to pay the fee is suspended because the well is capped or fails to produce more than 90,000 cubic feet of gas per day during any calendar month within two years,5 or the well is plugged.6

Within 60 days after the effective date of the legislation, i.e., on or before April 14, 2012, the fee may be imposed by the adoption of an ordinance by the governing body of any Pennsylvania county which

1 House Bill 1950, Printer’s No. 3948. The text of the legislation is available at: http://www.legis.state.pa.us/cfdocs/legis/PN/Public/btCheck.cfm?txtType=HTM&sessYr=2011&sessInd=0&billBody=H&billTyp=B&billNbr=1950&pn=3048. 2 The fee is imposed upon “every producer.” 58 Pa.C.S. § 2302(b). A “producer” is a person “that holds a permit or other authorization to engage in the business of severing natural gas for sale profit or commercial use from an unconventional gas well in this Commonwealth.” 58 Pa.C.S. § 2301. 3 As used in the legislation, an “unconventional formation” is a “geologic shale formation existing below the base of the Elk Sandstone or its geologic equivalent stratigraphic interval where natural gas generally cannot be produced at flow rates or in economic volumes except by vertical or horizontal well bores stimulated by hydraulic fracture treatments or by using multilateral well bores or other techniques to expose more of the formation to the well bore.” 58 Pa.C.S. § 3201. 4 The fee applies to “unconventional gas wells spud in this Commonwealth.” 58 Pa.C.S. § 2302(b). The term “spud” is defined to mean “the actual start of drilling of an unconventional gas well.” 58 Pa.C.S. § 2301. 5 The obligation to pay the fee is suspended “if a spud unconventional gas well begins paying the fee … and is subsequently capped or does not produce natural gas in quantities greater than a stripper well within two years after paying the initial fee.” 58 Pa.C.S. § 2302(b.1). A “stripper well” is a well “incapable of producing more than 90,000 cubic feet of gas per day during any calendar month, including production from all zones and multilateral well bores at a single well, without regard to whether to production is separately metered.” 58 Pa.C.S. § 3201. 6 The obligation to pay the fee ceases upon certification by the Department of Environmental Protection that a gas well has ceased production and has been plugged according to the department’s regulations. 58 Pa.C.S. § 3201(e).

Pennsylvania Legislation Authorizing Counties to Levy Unconventional Gas Well Fee Signed Into Law

has an unconventional gas well located within its borders. If a county fails to enact an ordinance imposing the fee, however, the fee may be imposed by the adoption of resolutions by at least half the municipalities in the county, or by municipalities representing 50% of the population of the county, not later than 120-days after the effective date of the legislation, i.e., on or before June 13, 2012.

Once imposed by counties or municipalities, the fee is collected by the Public Utility Commission (“PUC”) and 60% of its proceeds are returned to the counties and municipalities where wells are located. Counties failing to impose the fee by April 14, 2012, however, lose eligibility for the distribution of fee revenues for 2013, but may regain distributions by the adoption of an ordinance imposing the fee beginning in the year following the adoption of the ordinance.7

Funds not distributed to counties and municipalities are allocated for use by a number of Commonwealth agencies and programs, including the Unconventional Gas Well Fund, county conservation districts, the Fish and Boat Commission, Department of Environmental Protection, the Pennsylvania Emergency Management Agency, the State Fire Commission, the Marcellus Legacy Fund, the Housing Affordability and Enhancement Fund, and the PUC.

Amounts of Fees Imposed The fee is applied for a period of 15 years following its imposition for existing nonconventional wells,8 or for 15 years following the commencement of drilling for new wells. The amount of the fee varies based upon (1) the number of years after either the commencement of drilling for new wells or the year the fee is imposed for existing wells; (2) the average annual price of natural gas as determined using the New York Mercantile Exchange average settled price for near-month contracts on the last trading day of each month; (3) the Consumer Price Index for All Urban Consumers; and (4) whether a well has a single vertical bore. The schedule of fees for 2012 is listed below, and will be adjusted annually beginning in 2013 based upon the CPI.

Average Annual Price of Natural Gas per MMBtu Years Following Commencement of Drilling or Adoption of the Fee

Not More Than $2.25

Greater Than $2.25 and Less Than $3.00

Greater Than $2.99 and Less Than $5.00

Greater Than $4.99 and Less Than $6.00

More Than $5.99

Year One $40,000 $45,000 $50,000 $55,000 $60,000

Year Two $30,000 $35,500 $40,000 $45,000 $55,000

Year Three $25,000 $30,000 $40,000 $50,000

Year 4 to 1 $10,000 $15,000 $20,000

Year 11 to 15 $5,000 $10,000

7 Without the imposition of a resolution imposing the fee, counties appear to lose eligibility for distributions even if the fee is imposed by the action of municipalities within the county. 8 Section 2302(b) provides the following: “The fee adopted under subsection (a), (a.1) or (a.4) is imposed on every producer and shall apply to unconventional gas wells spud in this Commonwealth regardless of when spudding occurred. Unconventional gas wells spud before the fee is imposed shall be considered to be spud in the calendar year prior to the imposition of the fee for purposes of determining the fee under this subsection.” (emphasis added).

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Pennsylvania Legislation Authorizing Counties to Levy Unconventional Gas Well Fee Signed Into Law

Wells consisting of single vertical bore developed using hydraulic fracing and which produce quantities greater than a “stripper well,” i.e., more than 90,000 cubic feet of gas per day during a calendar month, are subject to 20% of the otherwise applicable fee, but are not subject to the fee for years 11 to 15. The fee is not required for any well that has ceased production and has been plugged in accordance with the regulations of the Department of Environmental Protection.

The 15 year period during which fee payments are required is extended if a well is re-stimulated more than ten years after originally being drilled by hydraulic fracing, using additional multilateral well bores, deeper drilling or other techniques to expose more of the formation to the well bore and the re-stimulation increases production by more than 90,000 cubic feet of gas per day during a calendar month. Re-stimulation extends the period for which the fee is due for 15 years commencing with the year in which re-stimulation occurs.

If a producer begins paying the fee for a well, and the well is subsequently capped or does not produce quantities greater than a “stripper well” within two years after paying the initial fee, the fee is suspended. Following suspension, if a well resumes generating quantities greater than a stripper well, the fee is reinstated, but calendar years during which the fee was suspended are not considered a year following drilling or imposition of the fee for purposes of applying the fee schedule.

The rationale for varying the amount of the fee based on how many years have elapsed since drilling began is based on the recognition that greater governmental costs are incurred during the development of new wells, especially during the time producers haul of sand, fracing fluid and waste water used in fracing, and that as wells age, they become significantly less productive and valuable assets. Notwithstanding this rationale, however, the legislation imposes the same fees on wells drilled prior to the imposition of the fee, regardless of when the wells were developed and how productive or socially costly the wells continue to be, as are imposed on new wells. For example, wells drilled to penetrate the Onondaga Formation or below under the Oil and Gas Conservation Act of 1961, which required fracing to produce gas in economic flow volumes, may be subject to the fee. Similarly, subject to the limited exceptions provided for stripper wells and wells that are capped or plugged, all wells that fit into a given fee category based on the number of years elapsed since either the commencement of drilling, or the imposition of the fee, whichever occurs later, are subject to same fees, regardless of their productivity. In addition, the same fees are imposed on wells that fit into a given fee category, regardless of whether wells utilize hydraulic fracing or other unconventional gas extraction technologies.

Administration For drilling commenced prior to January 1, 2012, the fee is due by September 1, 2012, and by September 1st of each year thereafter. For drilling commenced on or after January 1, 2012, the fee is due by April 1, 2013, and by April 1st of each year thereafter. When paying the fee, each producer is required to submit a report identifying the number of nonconventional wells located in each municipality within a county that has imposed the fee and the date each well was “spud” (i.e.,. the date drilling commenced).

To pay for the costs directly attributable to administering the fee program, the PUC may impose an administrative charge not to exceed $50 per spud unconventional well. The PUC is also required within 30 days the legislation is signed into law, i.e., by March 15, 2012, to estimate its costs directly attributable to administering the fee program, less amounts collected from the PUC’s administrative fee, through June 30, 2012, and assess these costs on all producers. By June 30, 2012, and by June 30th of each subsequent year, the PUC is also required to estimate and assess its administrative costs

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Pennsylvania Legislation Authorizing Counties to Levy Unconventional Gas Well Fee Signed Into Law

upon producers for the upcoming year. Fees and costs assessments must be paid within 30 days of receipt of notice of the amount due from the PUC.

Within 14 days of the effective date of the legislation, i.e., by February 28, 2012, the Department of Environmental Protection is required to provide the PUC, and counties upon request, a list of all unconventional wells drilled in the Commonwealth. This list must be updated monthly. The Department of Environmental Protection is also prohibited from issuing drilling permits to any producers failing to pay fees when due, and is required to suspend permits issued to producers failing to pay any fees not subject to pending appeals. To enable the Department of Environmental Protection to enforce these requirements, the PUC is authorized to provide information to the department regarding fees owed and paid.

The PUC is given broad authority to make all inquiries and determinations necessary to calculate and collect the fee and its administrative charges and assessments, and to issue enforcement orders. The PUC may challenge the amount of a fee due within three years after a producer’s report is filed which accompanies the fee payment. If no report is filed, or a producer files a false or fraudulent report “with intent to evade the fee,” an assessment of the amount due may be made at any time. Enforcement orders issued by the PUC are subject to appeal to the Commonwealth Court. Producers have a “duty to comply” with enforcement orders issued by the PUC, and upon failure to comply may be punished by a court of competent jurisdiction.

When assessments are made for unpaid or underpaid fees, the PUC is require to add interest payments in amounts specified by the PUC and penalties of 5% per month, but not more than 25% of the amount due. The PUC is also authorized to assess civil penalties of $2,500 for each violation of any of the requirements of the House Bill 1950 at any time up to three years after the violation. Unpaid fees, fines, interest and penalties constitute a lien “upon the property of the producer” after judgment in favor of the Commonwealth is entered and docketed in the county in which the property is located.

The PUC is also given broad authority to conduct examinations, including access to all relevant books and records of a producer; the power to require the preservation of records for up to three years from the calendar years to which the records relate; the power to examine employees under oath and the power to compel the production of books and records. All information obtained by the PUC is confidential and may not be disclosed, except in accordance with a judicial order or as provided by law.

Legal Issues Raised by the Legislation

Fee vs. Tax While House Bill 1950 purports to enact a fee rather than a tax because of political opposition to the imposition of any new taxes, it is unclear whether the amounts imposed under the new statute constitute fees or taxes for purposes of legal requirements limiting each. Under Pennsylvania law, fees generally may not exceed the reasonably estimated costs of providing governmental services,9 while taxes are subject to the “uniformity clause” of the Pennsylvania Constitution and the equal protection requirements of the 14th Amendment to the United States Constitution.10

9 Rizzo v. City of Philadelphia, 668 A.2d 236, 238 (Pa. Cmwlth. 1995) (Fees are legally collectible so long as the amounts charged “are reasonably proportional to the costs of the regulation or the services performed.”). 10 Art. VIII, § 1 of the Pennsylvania Constitution provides that “[a]ll taxes shall be uniform, upon the same class of subjects, within the territorial limits of the authority levying the tax, and shall be levied and collected under general laws.” The 14th Amendment to the United States Constitution adopted in 1866 provides that “[n]o State shall make or enforce any law which shall … deny any person within its jurisdiction the equal protection of the laws.” While initially the 14th

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Pennsylvania Legislation Authorizing Counties to Levy Unconventional Gas Well Fee Signed Into Law

In determining whether a law imposes a tax or a fee, the characterization of the imposition by the law itself may be disregarded, if the intent of the law is otherwise clear. In this regard, levies imposed to pay for the general expenses of government, or earmarked for certain programs that have a broad benefit to the public, are generally regarded as taxes rather than fees.

The Uniformity Clause To the extent the unconventional gas well fee is determined to be a tax, Pennsylvania judicial precedent interpreting the uniformity clause of the State Constitution is unpredictable. Under the uniformity clause, although like persons are to be treated alike, the General Assembly has the power to create different classifications as long as a classification bears a reasonable relationship to a legitimate state purpose.11 A classification, even if discriminatory, is reasonable if the classification “is based upon some legitimate distinction between the classes that provides a non-arbitrary and reasonable and just basis for the different treatment.”12 Valid classifications for the purpose of taxation may be based on “the existence of differences recognized in the business world, on the want of adaptability of the subjects to the same method of taxation, upon the impracticability of applying to them the same methods so as to produce justice and reasonably uniform results, or upon well grounded considerations of public policy.”13 Distinctions in tax statutes are permissible if they are based upon “reasonable consideration of differences of policy and [bear] a reasonable and just relation to the act in which it is proposed.”14

The difficulty with applying these general rules concerning uniformity often arises in determining whether classifications that may be otherwise permissible for certain purposes reasonably further legitimate public policy objectives embodied in a taxing statute. This task is made more difficult because objectives justifying classifications are frequently not well articulated in taxing statutes, and courts are not limited to evaluating the reasonableness of classifications based upon legislative pronouncements. Instead “a reviewing court is free to hypothesize reasons the legislature might have had for the classification.”15 Given this discretion, it is not surprising that different courts at different times may arrive at differing conclusions based on similar factual scenarios. For example, while a corporate net income tax based on federal taxable income was found not to violate uniformity requirements, 16 a personal income tax based on federal taxable income was found by the State Supreme Court to violate the Uniformity Clause.17

Applying principles of uniformity to the unconventional gas well fee is potentially challenging because the fee is not imposed on all wells or varied based on a small number of factors. Instead exemptions from the fee are provided under different conditions to stripper wells, capped wells, vertical wells and plugged wells; the amount of the fee may vary within the same year on similar types of facilities; and the law treats single vertical bore wells differently from other wells. In this regard, provisions of the law providing that “unconventional wells spud before the fee is imposed shall be Amendment was not applied to laws imposing taxes, since 1890 it has been interpreted as prohibiting state taxes which impose “clear and hostile discriminations against particular persons and classes.” Bells Gap R.R. v. Pennsylvania, 134 U.S. 232, 236-37 (1890). 11 Harrisburg School District v. Zogby, 574 Pa. 121, 137, 828 A.2d 1079, 1088 (2003). 12 Leonard v. Thornburgh, 507 Pa. 317, 321, 489 A.2d 1349, 1350 (1985). 13 Allegheny County v. Al Monzo, 509 Pa. at 38, 500 A.2d at 1102, quoting Wisconsin v. J.C. Penney Co., 311 U.S. 435, 444 (1940). 14 Philadelphia v. Smith, 412 Pa. 262, 268, 194 A.2d 177, 180 (Pa. 1963). 15 Harrisburg School District v. Zogby, 574 Pa. at 137-38, 828 A.2d at 1089. 16 Commonwealth v. Budd Co., 379 Pa. 159, 108 A.2d 563 (1954), appeal dismissed, 349 U.S. 935 (1955). 17 Amidon v. Kane, 444 Pa. 38, 279 A.2d 53 (1971).

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Pennsylvania Legislation Authorizing Counties to Levy Unconventional Gas Well Fee Signed Into Law

considered as spud in the calendar year prior to the imposition of the fee,” may be particularly problematic.

Retroactivity Issues The treatment of existing wells in the same manner as new wells, regardless of how many years prior to imposition of the fee the wells were drilled, may also raise questions about whether the fee is being unlawfully imposed retroactively on the drilling of existing wells. In general, taxes may not be imposed retroactively to a date sooner than the first day of the legislative session prior to the session in which a tax is imposed.18

Interpretation Issues Significant interpretive issues regarding the imposition of the unconventional gas well fee may also arise. For example, questions may arise regarding whether particular wells are used for the production of natural gas from “unconventional formations.” The fee is imposed on wells drilled for the production of gas from any “geologic shale formation below the base of the Elk Sandstone or its geologic equivalent stratigraphic interval.” Questions may arise about the location of the Elk Sandstone or what constitutes a geologic equivalent stratigraphic interval.

It is likewise unclear how the exemptions for capped wells, stripper wells and plugged wells will be applied. With respect to capped wells or stripper wells, it is unclear whether the exemption applies after the fee has been paid for a two or a three year period.19 With respect to plugged wells, the legislation does not clarify when the exemption takes effect. Finally, with respect to all wells eligible for exemptions, the legislation does not clarify whether, and in what circumstances, refunds may be available for fees paid unnecessarily.

Questions may similarly arise about whether the 80% discount for vertical wells applies to all nonconventional vertical wells, or only to vertical wells that have been fraced. Generally, the fee applies to wells drilled for the purpose of producing gas from formations that require fracing, multilateral well bores or similar technologies to sever gas at economic flow rates regardless of whether such procedures are used, but the 20% fee on vertical wells applies only to wells that utilize fracing.

Administrative Procedure Questions Significant issues relating to administrative procedures also may arise. For example, it is unclear whether petitions for refunds of improperly paid taxes must be filed with the PUC or with the Board of Finance and Revenue; whether petitions for reassessment may be filed with the PUC; and whether appeals of tax assessments before the Commonwealth Court are subject to de novo review in the same manner as all other tax assessments. Likewise, it is unclear whether enforcement orders of the PUC, especially those regarding tax assessments, will be stayed pending administrative review in the same

18 Commonwealth v. Budd Co., 108 A.2d at 569 (citing Welch v. Henry, 305 U.S. 134 (1938). 19 To qualify for the special tax provisions applicable to stripper wells, a well must not have generated more than stripper well volumes within two years of paying the initial fee. For example, for a well in existence prior to January 1, 2012, the initial fee is required to be paid on September 1, 2012. If the well does not produce more than stripper well volumes by January 1, 2014, the fee is suspended. It is unclear, however, whether the suspension applies immediately to the fee due on January 1, 2014, in which only the 2012 and 2013 fee would have been paid, or whether the suspension takes effect the following year. The resolution of this issue may depend on whether the stripper well provisions constitute a tax exemption, which must be strictly construed against the taxpayer under Pennsylvania law, or an exclusion from the scope of the tax, which must be strictly construed as a limitation on the ability of the Commonwealth to impose a tax.

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Pennsylvania Legislation Authorizing Counties to Levy Unconventional Gas Well Fee Signed Into Law

7

manner as other taxes, or whether the assessments must first be paid under threat of contempt and only challenged through petitions for refunds filed with the PUC or the Board of Finance and Revenue.

In order to implement its responsibilities to administer the fee, the PUC may adopt policies and regulations which resolve some of these issues and provide guidance to producers regarding reporting, recordkeeping and other requirements necessary for the administration of the fee.

Conclusion The impact fee provisions of the new law present a wide range of interesting and potentially troublesome legal issues, interpretation questions, and unresolved administrative procedure quandaries that will need to be worked through in the months, and perhaps years, ahead. Passage of House Bill 1850 is merely the first step in what is expected to be a long, and perhaps uncertain, process of implementing and administering an impact fee arrangement in Pennsylvania.

Authors: Raymond P. Pepe raymond.pepe@klgates.com +1.717.231.5988

New Pennsylvania Oil and Gas Law Targets Unconventional Gas Operations for Heightened Regulatory Oversight

February 14, 2012 Practice Group(s): Energy, Infrastructure and Resources Oil & Gas By Tad J. Macfarlan; R. Timothy Weston; Craig P. Wilson

Introduction On February 14, 2012, Pennsylvania Governor Tom Corbett signed into law a sweeping reform of the key environmental protection regime that governs natural gas operations. 58 Pa.C.S. §§ 2301-3504 (“the new Act” or “the recodified Act”)1 provides a wide-ranging update to and recodification of the Commonwealth’s Oil and Gas Act (the “old Act”). In addition to extensive revisions to the old Act’s environmental regulatory provisions, the new Act also addresses drilling fees and local regulation of the industry, each discussed in companion alerts.

The old Act (58 P.S. §§ 601.101-601.605) is recodified as a new Chapter 32 (58 Pa.C.S. §§ 3201-3274) of the new Act, which will be located in the Pennsylvania Consolidated Statutes (Pa.C.S.). While the new Act still applies to all oil and gas operations in the state, much of the new language in Chapter 32 targets unconventional (i.e., shale) natural gas drilling operations that utilize hydraulic fracturing. The industry should quickly become familiar with the updates to discern their effect on existing operations and enable meaningful participation in forthcoming regulatory revisions. Some of the most important amendments, detailed more fully below, include:

Increased setbacks and well siting restrictions

New chemical disclosure and reporting obligations

Additional well permitting procedures, plans, and approvals

New water supply protections

Increased bonding requirements

Stricter enforcement mechanisms

The Oil and Gas Act First enacted in 1984, the old Oil and Gas Act has long provided many of the key environmental safeguards that shape the operations of natural gas drillers in the Commonwealth. To implement the old Act, the Environmental Quality Board (“EQB”) has adopted oil and gas well regulations at 25 Pa. Code Chapter 78, and those rules govern administration of the regulatory program by the Pennsylvania Department of Environmental Protection (“DEP”). The Chapter 78 regulations, which were overhauled in February 2011, fill-out the Act’s currently effective requirements. Thus, changes to the old Act will necessarily mean changes to the regulations, at least where the regulations are inconsistent with the new Act’s updated language.

1 The new Act was referred to as “House Bill 1950” prior to enactment.

New Pennsylvania Oil and Gas Law Targets Unconventional Gas Operations for Heightened Regulatory Oversight

Summary of Key Changes Implemented by the New Act Chapter 32 of the new Act largely tracks the language of the old Oil and Gas Act. However, it introduces a number of important revisions and additions in an effort to manage the perceived risks associated with unconventional gas operations.2 The remainder of this article describes the amendments that may have the greatest effect on operators.

Setbacks and Well Siting Restrictions The new Act expands and clarifies existing setbacks:3

Protected Resource Old Setback New Setback for Unconventional Wells

Buildings & water wells 200 feet from the well 500 feet from the vertical well bore

Water well, surface water intake, reservoir, or other water supply extraction point used by a water purveyor

None

(but 200 feet water well setback may apply)

1,000 feet from the vertical well bore

Streams, springs, wetlands, and other bodies of water

100 feet from the well site or well

300 feet from the well bore and 100 feet from the edge of the well site/disturbance area

In addition to the setbacks, (1) a wastewater pit or impoundment is prohibited within the 100 year floodplain and (2) a tank containing hazardous materials, chemicals, or waste is prohibited within the floodway.4

For each of these setbacks and siting restrictions, the opportunity to obtain a variance or waiver remains, and the new Act clarifies that variances will be granted if the operator demonstrates compliance with measures prescribed by DEP.5

Chemical Disclosure and Reporting Obligations The recodified Act includes a new section on fracturing fluid chemical disclosure, requiring all operators to complete a chemical disclosure form and post the form on the chemical disclosure registry in accordance with yet to be promulgated regulations.6 In essence, this section makes mandatory chemical disclosure on the FracFocus website. The new provisions allow for trade secret and confidential proprietary information claims to be made by operators, vendors, and service providers, and describe how such claims will be handled by DEP. Also, a new “safe-harbor” provision clarifies that operators will not be required to disclose chemicals that are not disclosed to it by the fluid manufacturer, vendor, or service provider. 7

By January 1, 2013, DEP is required to determine whether the chemical disclosure registry (FracFocus) is searchable and sortable by geographic area, chemical ingredient, chemical abstract

2 Additionally, even sections that have not been substantively amended have been stylistically reworded, so that the potential exists for new interpretations in the courts and regulatory agencies. 3 58 Pa.C.S. § 3215. 4 58 Pa.C.S. § 3215(f). 5 Compare the Oil and Gas Act, § 601.205(a) with 58 Pa.C.S. § 3215(a). 6 58 Pa.C.S. § 3222.1. 7 58 Pa.C.S. § 3222.1(c)(1).

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New Pennsylvania Oil and Gas Law Targets Unconventional Gas Operations for Heightened Regulatory Oversight

service number, time period and operator.8 If it is not, DEP is required to (1) investigate the feasibility of making the chemical disclosure information available on its own website in searchable and sortable form, and (2) report to the General Assembly on whether additional resources may bneeded to implement such a

e project.

The new Act also partially codifies the Chapter 78 regulations that govern the reporting of chemicals in completion reports, but the statutory language differs from the existing rule language.9 For instance, where the current rules require the completion report to include “[t]he percent by volume of each chemical additive in the stimulation fluid,” the new Act requires “[t]he maximum concentration, in percent by mass, of each chemical intentionally added to the stimulation fluid.”

Permitting Procedures, Plans, and Approvals The recodified Act establishes several new permitting requirements, plans, and approvals:

Notice of Application: Unconventional well permittees will be required to send notice of their application to all surface landowners and water purveyors whose water supplies are within 3000 feet of the vertical well bore (up from 1000 feet), and also to all “storage operators” within the same 3000 foot radius.10 A “storage operator” is a person who operates a “storage reservoir,” a subsurface area into which gas can be injected for storage purposes.11

Containment Plans: Applicants will be required to develop and submit a containment plan, in accordance with practices set forth in the new Act and further regulations to be promulgated by the EQB.12

Water Management Plans: Withdrawal or use of water for drilling or hydraulic fracturing an unconventional well will require a DEP-approved water management plan (“WMP”).13 Plans approved by a regional water commission (such as the Delaware and Susquehanna River Basin Commissions) will be presumed to be satisfactory, but DEP will have the authority to establish additional requirements as necessary to comply with state law. Moreover, in the Ohio River Basin, there is no existing regional water withdrawal regulatory body, and thus DEP will have the lead in review and approval of WMPs.

The new Act also grants DEP new authority when considering a permit application:

Written Comments by Municipalities and Storage Operators: DEP may consider written comments by (1) the municipality in which an unconventional well is located and (2) storage operators within 3000 feet of the proposed well bore.14

Permit Conditions Based on Impact to Public Resources and Ensuring Optimal Development: EQB will promulgate regulations for DEP to utilize for conditioning a well permit based on its impact to certain public resources (such as parks, forests, rare and endangered species habitats and archeologic and historic resources, and sources of drinking water), and for ensuring optimal development of oil and gas resources and respecting property rights of oil and gas owners.15 Notably, there may be some tension between these factors to be used in conditioning

8 58 Pa.C.S. § 3222.1(b)(6). 9 Compare 25 Pa. Code § 78.122(b)(6) with 58 Pa.C.S. § 3222(b.1)(1). 10 58 Pa.C.S. § 3211(b)(2). 11 58 Pa.C.S. § 3203. 12 58 Pa.C.S. § 3218.2. 13 58 Pa.C.S. § 3211(m). 14 58 Pa.C.S. §§ 3212.1, 3215(d). 15 58 Pa.C.S. § 3215(e).

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New Pennsylvania Oil and Gas Law Targets Unconventional Gas Operations for Heightened Regulatory Oversight

well permits (for example, promoting optimum development of oil and gas resources, while addressing impacts on public resources). While unstated, this provision necessitates a balancing of these concerns by the agency.

Protective Measures for Storage of Hazardous Chemicals: DEP may establish protective measures for storage of hazardous chemicals and materials within 750 feet of any stream, spring, or other body of water.16

Water Supply Protections The recodified Act includes a variety of new and revised provisions aimed at protecting water supplies, including the following:17

Rebuttable Presumption of Responsibility: The rebuttable presumption of responsibility for pollution of a water supply will be extended to 2,500 feet from the vertical well bore (increased from the former 1,000 feet) and 12 months (compared to the former 6 months) from the later of completion, drilling, stimulation, or alteration.18 When the presumption applies, operators shall provide a temporary water supply if the user is without a readily available alternative source of water.

Water Contamination Telephone Hotline: DEP will establish a new toll-free telephone number that persons may use to report cases of water contamination.19

Notification of Contamination to Public Drinking Water Facilities: DEP will notify any public drinking water facility that could be affected by a spill, upon receiving notification and after investigation of the spill.20

Treatment and Discharge of Wastewater: DEP will ensure that any facility which seeks an NPDES permit for treating and discharging wastewater from and oil and gas activities is operated by a competent and qualified individual.21

Publication of Contamination: DEP will now be required to publish on its website any “confirmed cases of subterranean water supply contamination that result from hydraulic fracturing.”22

Wastewater Fluid Recordkeeping: Unconventional well operators that transport wastewater fluid will be required to maintain fives years of wastewater fluid records detailing:

o the volume of wastewater fluids;

o the person or company that transported the wastewater fluids;

o each location where wastewater fluids were disposed of or transported, broken down by volume; and

o The method of disposal.23

16 58 Pa.C.S. § 3215(d.1). 17 58 Pa.C.S. § 3218. 18 58 Pa.C.S. § 3218(c). 19 58 Pa.C.S. §§ 3218(b.2) & (b.3). 20 58 Pa.C.S. § 3218.1. 21 58 Pa.C.S. § 3218(b.5). 22 58 Pa.C.S. § 3218(b.4). 23 58 Pa.C.S. § 3218.3.

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New Pennsylvania Oil and Gas Law Targets Unconventional Gas Operations for Heightened Regulatory Oversight

Bonding Bonding requirements will be increased, with bond amounts based on well bore length and number of wells operated, as follows:24

Well Bore Length Number of

Wells Bond Amount Maximum

Bond 50 or less $4,000/well $35,000

51 - 150 $35,000 + $4,000/well in

excess of 50 wells $60,000

151 - 250 $60,000 + $4,000/well in

excess of 150 wells $100,000 less than 6,000 feet

more than 250

$100,000 + $4,000/well in excess of 250 wells $250,000

25 or less $10,000/well $140,000

26 - 50 $140,000 + $10,000/well in

excess of 25 wells $290,000

51 - 150 $290,000 + $10,000/well in

excess of 50 wells $430,000 6,000 feet or greater

more than 150

$430,000 + $10,000/well in excess of 150 wells $600,000

EQB will adjust the amount of the bonds required every two years to reflect the projected costs to the Commonwealth of plugging the well.

Stricter Enforcement Mechanisms The new Act increases the amount of both civil and criminal penalties for violations.25

Violation Type Old Maximum New Maximum

Criminal penalty for a general violation (summary offense)

$300 $1,000

Civil Penalty at an unconventional well site

$25,000 plus $1,000/day $75,000 plus $5,000/day

Additionally, a new enforcement mechanism will require that DEP post inspection reports on its website, detailing the nature of any alleged violations, the operator’s response, the status of the violation, and the remedial steps taken by the operator and DEP.26

Other Amendments In addition to the revisions discussed above, the new Act includes amendments involving the following topics: (1) pre-drilling erosion and sediment control inspections;27 (2) a two year extension

24 58 Pa.C.S. § 3225. 25 58 Pa.C.S. § 3255-56. 26 58 Pa.C.S. § 3262. 27 58 Pa.C.S. § 3258.

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New Pennsylvania Oil and Gas Law Targets Unconventional Gas Operations for Heightened Regulatory Oversight

for well site restoration;28 (3) air emissions reporting;29 (4) corrosion control requirements;30 (5) gathering lines;31 (6) well control emergency cost recovery;32 and (7) well control emergency response specialists 33.

Interaction with Local Regulations The above-mentioned revisions may have a significant effect on the ability of local governments to regulate the natural gas industry, in light of the new Act’s preemption provisions. As discussed in our companion alert, the new Act preserves the old Act’s preemptive effect over all local ordinances “that contain provisions which impose conditions, requirements or limitations on the same features of oil and gas operations regulated by Chapter 32 or that accomplish the same purposes as set forth in Chapter 32.”34 Thus, to the extent that these new provisions expand the realm of state regulation, that expansion should result in a decrease in the matters that are open to local regulation.

The new Act also introduces a new provision that establishes broad preemptive effect of all “environmental acts,” which may include the recodified Oil and Gas Act. “Notwithstanding any other law to the contrary, environmental acts are of statewide concern and, to the extent that they regulate oil and gas operations, occupy the entire field of regulation, to the exclusion of all local ordinances. The Commonwealth by this section, preempts and supersedes the local regulation of oil and gas operations regulated by the environmental acts, as provided in this chapter.” 35 “Environmental acts” are defined as “[a]ll statutes enacted by the Commonwealth relating to the protection of the environment or the protection of public health, safety and welfare, that are administered and enforced by [DEP] or by another Commonwealth agency, including an independent agency, and all Federal statutes relating to the protection of the environment, to the extent those statutes regulate oil and gas operations.”36 The recodified Oil and Gas Act seems to fit within this broad definition; it (1) was enacted by the Commonwealth, (2) is administered by DEP, (3) relates to the protection of the environment and public health, and (4) regulates oil and gas operations. Thus, it may “occupy the entire field of regulation, to the exclusion of local ordinances,” whether or not those ordinances regulate the same features or accomplish the same purposes as set forth in Chapter 32.

Finally, a new section on uniformity requires that “all local ordinances regulating oil and gas operations shall allow for the reasonable development of oil and gas resources.”37 Specific requirements are set forth defining what a local ordinance may and may not do in order to ensure that reasonable development is allowed. 38 For instance, there is a prohibition on any local ordinance that increases the setbacks set forth in Chapter 32 and discussed above.39 However, this same provision allows that “[a] local ordinance may impose setback distances that are not regulated by or set forth in Chapter 32 . . . if the setbacks are no more stringent than those for other industrial uses . . . .” The list of permissible and impermissible types of local regulation contained in the uniformity section should be consulted to help determine the scope of allowable local regulation.

28 58 Pa.C.S. § 3216. 29 58 Pa.C.S. § 3227. 30 58 Pa.C.S. § 3218.4. 31 58 Pa.C.S. § 3218.5. 32 58 Pa.C.S. § 3254.1. 33 58 Pa.C.S. § 3219.1. 34 58 Pa.C.S. § 3302. 35 58 Pa.C.S. § 3303. 36 58 Pa.C.S. § 3301. 37 58 Pa.C.S. § 3304(a) (emphasis added). 38 58 Pa.C.S. § 3304(b). 39 58 Pa.C.S. § 3304(b)(11). 6

New Pennsylvania Oil and Gas Law Targets Unconventional Gas Operations for Heightened Regulatory Oversight

7

Conclusion Pennsylvania’s new oil and gas legislation significantly revamps the environmental protection regime governing the Commonwealth’s expanding natural gas industry. Well siting, design, development, and operations will be impacted in a myriad of ways. The details of how these provisions are interpreted and implemented will require close attention and active involvement by industry stakeholders throughout the process.

Authors: Tad J. Macfarlan tad.macfarlan@klgates.com +1.717.231.4513

R. Timothy Weston tim.weston@klgates.com +1.717.231.4504

Craig P. Wilson craig.wilson@klgates.com +1.717.231.4509

Pennsylvania’s Oil and Gas Act Amended to Require "Uniformity" with Respect to Municipal Ordinances Regulating Oil and Gas Operations

February 9, 2012 Practice Group(s): Energy, Infrastructure and Resources Oil & Gas

By Christopher R. Nestor, Walter A. Bunt, Jr., and David R. Overstreet

On February 8, 2012, the Pennsylvania General Assembly passed House Bill 1950, which makes a series of reforms to the Commonwealth’s Oil and Gas Act, 58 P.S. §§ 601.101 et seq. Among the reforms to the Act are provisions attempting to supply “uniformity” with respect to local municipal ordinances relating to oil and gas operations and to further clarify the scope of preemption under the Act. This alert discusses the uniformity reforms, and related provisions, in House Bill 1950.

Background - Preemption Under the Oil and Gas Act. Currently, Section 602 of the Oil and Gas Act, 58 P.S. § 601.602, preempts local ordinances that attempt to regulate oil and gas wells except for ordinances adopted pursuant to the Municipalities Planning Code (the “MPC”) or Flood Plain Management Act (“FPMA”). Even ordinances adopted pursuant to the MPC or FPMA have significant limitations. An ordinance adopted pursuant to the MPC or FPMA is preempted if (1) the ordinance “contain[s] provisions … that accomplish the same purposes as set forth in” the Act; or (2) the ordinance “contain[s] provisions which impose conditions, requirements or limitations on the same features of oil and gas well operations regulated by” the Act.

The Pennsylvania Supreme Court, in a series of cases decided in 2009, concluded that municipal ordinances will be preempted by Section 602 of the Act when they comprehensively regulate oil and gas development, when they have the same “purposes” as the Act or when they impose conditions, requirements or operations on the same “features” of oil and gas operations as does the Act. See Huntley & Huntley, Inc. v. Borough Council of the Borough of Oakmont, 964 A.2d 855 (Pa. 2009), and Range Resources – Appalachia, LLC v. Salem Township, 964 A.2d 569 (Pa. 2009).

While Huntley and Range provided some guidance to industry and municipalities regarding the scope of preemption under Section 602 of the Act, the decisions also left many questions unanswered. Since those decisions, there has been a proliferation of inconsistent and varying “zoning” ordinances adopted by municipalities across the Commonwealth directed specifically at oil and gas development, many of which are overtly hostile to such development. Those ordinances, in turn, have spawned additional litigation over the scope and effect of Section 602 of the Act and, in some cases, have impeded oil and gas development in certain municipalities in the Commonwealth.

House Bill 1950 and Local Ordinances Relating to Oil and Gas Development. Sections 3301 through 3309 of House Bill 1950 contain extensive revisions to the municipal ordinance provisions of the Oil and Gas Act. Notably, and explained further below, the legislation requires municipalities to allow drilling in all zoning districts, with one exception: municipalities can preclude siting of a gas well in a residential zone if a well site cannot be placed so that the wellhead is at least 500 feet from any existing building. The legislation also makes the Pennsylvania Public

Pennsylvania’s Oil and Gas Act Amended to Require "Uniformity" with Respect to Municipal Ordinances Regulating Oil and Gas Operations

Utility Commission (“PUC”) the arbiter of whether a local zoning ordinance is “reasonable.” Prior iterations of the legislation had the Attorney General’s office in that role.

The new legislation contains an expansive definition of “oil and gas operations,” which include the following:

well location assessment, including seismic operations, well site preparation, construction, drilling, hydraulic fracturing and site restoration associated with an oil or gas well of any depth;

water and other fluid storage or impoundment areas used exclusively for oil and gas operations;

construction, installation, use, maintenance and repair of: (i) oil and gas pipelines; (ii) natural gas compressor stations; and (iii) natural gas processing plants or facilities performing equivalent functions; and

construction, installation, use, maintenance and repair of all equipment directly associated with the foregoing to the extent that: (i) the equipment is necessarily located at or immediately adjacent to a well site, impoundment area, oil and gas pipeline, natural gas compressor station or natural gas processing plant; and (ii) the activities are authorized and permitted under the authority of a federal or Commonwealth agency.

See House Bill 1950, § 3301.

Section 3302 of House Bill 1950 preserves the language of current Section 602 of the Act, 58 P.S. § 601.602, discussed above, and the preemption of local ordinances afforded thereby. Section 3303 of the Bill, however, adds an additional, and broad, preemption provision to the Act with respect to oil and gas operations regulated by environmental acts:

Notwithstanding any other law to the contrary, environmental acts are of Statewide concern and, to the extent that they regulate oil and gas operations, occupy the entire field of regulation, to the exclusion of all local ordinances. The Commonwealth by this section, preempts and supersedes the local regulation of oil and gas operations regulated by the environmental acts, as provided in this chapter.

See House Bill 1950, § 3303.1 For purposes of Section 3303, “environmental acts” means “[a]ll statutes enacted by the Commonwealth relating to the protection of the environment or the protection of public health, safety and welfare, that are administered and enforced by [the Pennsylvania Department of Environmental Protection] or by another Commonwealth agency, including an independent agency, and all Federal statutes relating to the protection of the environment, to the extent those statutes regulate oil and gas operations.”

In addition to both preserving and expanding the scope of preemption of local ordinances purporting to regulate “oil and gas operations,” House Bill 1950 contains additional provisions mandating uniformity among municipal ordinances regulating such activities. Building upon, and consistent with, Section 603(i) of the MPC, 53 P.S. § 10603(i), House Bill 1950 requires that all local ordinances regulating oil and gas operations allow for the “reasonable development” of oil and gas resources. See House Bill 1950, § 3304. To that end, House Bill 1950 mandates that local ordinances regulating oil and gas operations:

1For purposes of these provisions of the Act, a “local ordinance” is any ordinance or other enactment, including a provision of a home rule charter, adopted by a municipality that regulates oil and gas operations. See House Bill 1950, § 3301.

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Pennsylvania’s Oil and Gas Act Amended to Require "Uniformity" with Respect to Municipal Ordinances Regulating Oil and Gas Operations

must allow well and pipeline location assessment operations, including seismic operations and related activities conducted in accordance with applicable federal and state laws and regulations relating to the storage and use of explosives;

may not impose conditions, requirements or limitations on the construction of oil and gas operations that are more stringent than those imposed on construction activities for other industrial uses within the municipality;

may not impose conditions, requirements or limitations on the heights of structures, screening and fencing, lighting or noise relating to permanent oil and gas operations that are more stringent than those imposed on other industrial uses or other land development within the zoning district where the oil and gas operations are located;

must have a review period for permitted uses that does not exceed 30 days for complete submissions or that does not exceed 120 days for conditional uses;2

must authorize oil and gas operations, other than activities at impoundment areas, compressor stations and processing plants, as a permitted use in all zoning districts. A municipality can, however, prohibit, or permit only as a conditional use, wells or well sites located in a residential district if the well site cannot be placed so that the wellhead is at least 500 feet from any existing building. Additionally, in a residential district, the following limitations apply: (i) a well site may not be located so that the outer edge of the well pad is closer than 300 feet from an existing building; and (ii) oil and gas operations, other than the placement, use and repair of oil and gas pipelines, water pipelines, access roads or security facilities, may not take place within 300 feet of an existing building;

must authorize impoundment areas used for oil and gas operations as a permitted use in all zoning districts, subject to the limitation that the edge of any impoundment area may not be located closer than 300 feet from an existing building;

must authorize natural gas compressor stations as a permitted use in agricultural and industrial zoning districts and as a conditional use in all other zoning districts, if the natural gas compressor building meets the following standards: (i) the building is located 750 feet or more from the nearest existing building or 200 feet from the nearest lot line, whichever is greater, unless waived by the owner of the building or adjoining lot; and (ii) the noise level does not exceed a noise standard of 60dbA at the nearest property line or the applicable standard imposed by federal law, whichever is less;

must authorize natural gas processing plants as a permitted use in an industrial zoning district and as a conditional use in agricultural zoning districts if the natural gas processing plant building meets the same requirements applicable to natural gas compressor buildings, above;

may impose restrictions on vehicular access routs for overweight vehicles only as authorized under 75 Pa.C.S. (relating to vehicles) or the MPC;

2 As defined in House Bill 1950, a “permitted use” is a “use which, upon submission of a written notice to and receipt of a permit issued by a zoning officer or equivalent official, is authorized to be conducted without restrictions other than those set forth in [Section 3304 of House Bill 1950, relating to uniformity of local ordinances.]” See House Bill 1950, § 3301. In short, a “permitted use” is a use permitted by right in a zoning district, as opposed to a use permitted by a conditional use or special exception approval process. A zoning district typically provides for certain uses by right. Other uses are provided by special exception or conditional use. The uses permitted by special exception or by conditional use, while they are permissible and legitimate uses within the district, require additional scrutiny by the body granting their approval.

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Pennsylvania’s Oil and Gas Act Amended to Require "Uniformity" with Respect to Municipal Ordinances Regulating Oil and Gas Operations

may not impose limits or conditions on subterranean operations or hours of operation of compressor stations and processing plants or hours of operation for the drilling of oil and gas wells or the assembly or disassembly of drilling rigs; and

may not increase the setback distances set forth in the Oil and Gas Act. A municipality may, however, impose setback distances that are not regulated by or set forth in the Act so long as those setbacks are no more stringent than those for other industrial uses within the municipality.

In addition to mandating the uniformity described above, House Bill 1950 provides procedures for determining whether a municipal ordinance violates the MPC or the Oil and Gas Act. First, House Bill 1950 allows a municipality, prior to the enactment of a local ordinance, to make a written request to the PUC to review the proposed ordinance and issue an opinion on whether it violates the MPC or the Act. See House Bill 1950, § 3305(a). The PUC has 120 days from receipt of such a request to issue its opinion, which is purely “advisory in nature and not subject to appeal.” Id.

Second, an owner or operator of an oil and gas operation, or a person residing within the municipality, who is aggrieved by the enactment or enforcement of a local ordinance may request that the PUC review the ordinance and determine whether it violates the MPC or the Act. See House Bill 1950, § 3305(b). Participation in the PUC’s review is limited to the foregoing parties and the adopting municipality. Within 120 days of receiving a request for review by an aggrieved owner or operator of an oil and gas operation, or municipal resident, the PUC must issue an order determining whether the challenged ordinance violates the MPC or the Act. The PUC’s order is subject to de novo review by the Commonwealth Court. A petition seeking such review must be filed with the Commonwealth Court within 30 days of the date of service of the PUC’s order. Id.3

In addition to the PUC ordinance vetting process, House Bill 1950 provides that any person who is aggrieved by the enactment or enforcement of a local ordinance that violates the MPC or the Act may, notwithstanding any provision of 42 Pa.C.S. Chapter 85 (relating to actions against local parties), bring an action directly in Commonwealth Court to invalidate the ordinance or enjoin its enforcement. See House Bill 1950, § 3306. An aggrieved person may bring such an action without first obtaining review of the ordinance by the PUC. Id. The Commonwealth Court has the power to award attorneys fees and costs in connection with such an action. Specifically, if the Commonwealth Court determines that the local government enacted or enforced a local ordinance with willful or reckless disregard of the MPC or the Act, it may order the local government to pay the plaintiff reasonable attorneys fees and other reasonable costs incurred by the plaintiff in connection with the action. See House Bill 1950, § 3307. Alternatively, if the court determines that the action by the plaintiff is frivolous or was brought without substantial justification in claiming that the challenged ordinance is contrary to the MPC or the Act, it may order the plaintiff to pay the local government reasonable attorneys fees and costs incurred by the local government in defending the action. Id.

As an incentive for municipalities to review their existing ordinances and legislate accordingly, House Bill 1950 provides that if the PUC, the Commonwealth Court or Supreme Court issues an order that a local ordinance violates the MPC or the Act, the municipality becomes immediately ineligible to receive funds collected by the impact fee provisions of House Bill 1950. See House Bill 1950, § 3308. The municipality will remain ineligible to receive such funds until it repeals the challenged ordinance or the order is reversed on appeal.

3 House Bill 1950 provides that PUC opinions and orders under the foregoing provisions are not subject to 2 Pa.C.S. Chapter 5, Subchapter A (relating to the practice and procedure of Commonwealth Agencies), 65 Pa.C.S. Chapter 7 (relating to open meetings), or 66 Pa.C.S. Chapter 3, Subchapter B (relating to investigations and hearings.). See House Bill 1950, § 3305(c). Additionally, the PUC is given broad authority to hire staff, issue orders and adopt both temporary and permanent regulations to carry out its review functions. See House Bill 1950, § 3305(d).

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Pennsylvania’s Oil and Gas Act Amended to Require "Uniformity" with Respect to Municipal Ordinances Regulating Oil and Gas Operations

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The provisions of House Bill 1950 apply retroactively to the enforcement of any local ordinances existing on the effective date of the Bill. See House Bill 1950, § 3309. Municipalities with existing ordinances relating to oil and gas operations are afforded 120 days from the effective date of the Bill to review their ordinances and bring them into compliance with the Act. Id.

Authors: Christopher R. Nestor christopher.nestor@klgates.com +1.717.231.4812

Walter A. Bunt, Jr. walter.bunt@klgates.com +1.412.355.8906

David R. Overstreet david.overstreet@klgates.com +1.412.355.8263

Pennsylvania’s New Gas and Hazardous Liquids Pipeline Act

January 3, 2012 Practice Group(s): Energy, Infrastructure and Resources Oil & Gas

By Daniel P. Delaney, George A. Bibikos, Bryan D. Rohm

Introduction Reacting to the influx of new gathering pipeline, midstream and other facilities in Pennsylvania, the General Assembly passed and the Governor signed House Bill 344, creating the “Gas and Hazardous Liquids Pipelines Act” (the “Act”). The Act subjects pipeline operators who transport “gas” or “hazardous liquids” to existing federal safety regulations and imposes additional administrative measures, such as registration and reporting requirements and the imposition of annual “assessments” on pipeline operators subject to the new legislation. In addition, the Act expands the jurisdiction of the Pennsylvania Public Utility Commission (“PUC”) to enforce pipeline safety regulations in Pennsylvania.

What does the Act do? The PUC historically exercised its authority to enforce federal pipeline safety standards only on statutorily-defined “public utilities” that operate pipeline facilities in Pennsylvania. However, the agency otherwise lacked the authority to enforce those standards on unregulated pipeline entities. Now, the Act authorizes the PUC to enforce federal pipeline safety regulations on all “pipeline operators,” broadly defined to include any person that “owns or operates equipment or facilities in this Commonwealth for the transportation of gas or hazardous liquids by pipeline or pipeline facility regulated under federal pipeline safety laws.”1 The term “pipeline” is expansively defined to include not only the pipeline itself, but also compressor stations, metering stations and appurtenant facilities. The terms “gas” and “hazardous liquids” include not only natural gas, but also such materials as liquefied natural gas, landfill gas, petroleum, natural gas liquids, ethane and other materials classified as “hazardous” under the federal pipeline safety laws. As a result, most operators of pipelines and related facilities in Pennsylvania will be subject to the PUC’s safety regulation.

What are some of the key provisions of the Act? The Act is fairly straightforward. The key provisions include:

Federal standards. The Act incorporates federal pipeline safety standards and authorizes the PUC to enforce those standards on pipeline operators.

Investigation authority. The Act gives the PUC authority to investigate and enforce federal pipeline safety standards. The PUC has announced plans to expand the pipeline safety team within the agency.

1 Section 101 of HB 344, which creates the Act, defines the Federal Pipeline Safety Laws as “[t]he provisions of 49 U.S.C. Ch. 601 . . . the Hazardous Liquid Pipeline Safety Act of 1979 . . . the Pipeline Safety Improvement Act of 2002 . . . and the regulations promulgated under the acts.”

Pennsylvania’s New Gas and Hazardous Liquids Pipeline Act

Registration requirements. Pipeline operators subject to the Act must register with the PUC.2 The Act does not indicate when registrations are due or what information is required to be submitted with each registration. However, the Act does give the PUC authority to develop an application for registration and charge registration fees.

Steel products. The initial registration (and each annual renewal) requires that the operator disclose the country of manufacture for all “tubular steel products” used in the exploration, gathering or transportation of natural gas or hazardous liquids within the Commonwealth.3 The Act does not provide an exemption to disclosure requirements for tubular steel products that were installed prior to the effective date of the Act. However, the Act does give the PUC authority to develop a disclosure form for this portion of the registration. In developing the forms, the PUC could presumably accommodate existing pipelines for which the pipes’ country of manufacture is unknown.

Annual reports. On or before March 31 of each year, pipeline operators subject to the Act must file annual reports disclosing the pipeline operator’s total miles of regulated pipeline in the Commonwealth during the prior calendar year.4

Assessments. The PUC is an independent agency that is generally self-funded. Pursuant to Section 510 of the Pennsylvania Public Utility Code, the PUC makes annual assessments on all entities subject to its jurisdiction and recovers from those entities their proportionate share of the costs of regulation. The Act incorporates the assessment process of Section 510 and authorizes the PUC to determine by regulation or order annual assessments against pipeline operators to recover the cost of regulation based on the number of miles of regulated pipeline.5

Civil penalties. The Act authorizes the PUC to assess and recover civil penalties of the greater of: (i) $10,000 per violation for each day the violation persists; or (ii) a penalty provided for under the federal pipeline safety laws.6

No ratemaking authority; no effect on definition of “public utility.” The Act does not give the PUC any additional jurisdiction for purposes of establishing rates or any matters other than the safety and additional requirements created by the Act. The Act does not give the PUC additional authority to determine the status of or regulate a pipeline operator as a public utility as defined in the Public Utility Code.

What should operators do? The Act takes effect 60 days from the date of the Governor’s signature and imposes requirements that require initial planning and preparation. For example:

Safety standards. Although pipeline facilities that will be subject to the new legislation already meet or exceed federal safety standards, pipeline operators should assure that proposed facilities meet or exceed those standards to avoid administrative liability under the Act.

Work with the PUC on regulations and forms. Gathering system and other pipeline facility operators, as well as others in the industry, will want to engage actively with the PUC in the

2 Section 301(C)(1) of HB 344. 3 Section 301(D) of HB 344. 4 Section 503(D) of HB 344. 5 Section 503(B)(1) of HB 344. 6 Section 502(A) of HB 344.

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Pennsylvania’s New Gas and Hazardous Liquids Pipeline Act

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development of regulations and forms to implement the Act. Issues such as how to address steel product origin requirements, the format and content of reports, and other matters need to be fleshed-out with active input from industry stakeholders.

Gather information to comply with administrative measures. Pipeline operators should be sure they have identified all the information required by the Act for registration and reporting and be prepared to submit that information in the manner prescribed by the PUC for the purposes described in the Act, bearing in mind that the Act creates a March 31 deadline for annual reporting.

Prepare for assessments. As noted, the Act incorporates the assessment procedures contained in Section 510 of the Public Utility Code. Pipeline operators must object to individual assessments issued by the PUC within 15 days of receiving the assessment. Within 30 days of receiving the assessment, the pipeline operator must submit payment. In the recent past, the PUC’s assessments frequently have been the subject of litigation before the agency and the Pennsylvania appellate courts. The issue in controversy has frequently involved the over-allocation of the agency’s total overhead costs on particular utility classes. Similar issues may arise in the agency’s calculation of the pipeline assessments. Pipeline operators should examine the assessment notice carefully and be prepared to file objections if necessary, with the assistance of experienced counsel, within 15 days of receiving the notice. Payment of the assessment would still be required within 30 days of receiving the assessment notice, but the submittal of the objection preserves the opportunity to receive a refund of any overpayment of assessments.

Authors:

Daniel P. Delany dan.delaney@klgates.com +1.717.231.4516

George A. Bibikos george.bibikos@klgates.com +1.717.231.4577

Bryan D. Rohm bryan.rohm@klgates.com +1.412.355.8682

EPA to Require Chemical Disclosure under TSCA by Hydraulic Fracturing Fluid Manufacturers

December 2, 2011 Practice Group(s): Energy, Infrastructure and Resources Oil & Gas By Cliff L. Rothenstein and Tad J. Macfarlan

On the day before Thanksgiving, the U.S. Environmental Protection Agency (“EPA”) quietly issued a letter bound to have significant impacts on the oil and gas industry, announcing its intent to develop and issue regulations under the Toxic Substances Control Act (“TSCA”) governing the disclosure and evaluation of chemicals used in hydraulic fracturing operations.

By letter dated November 23, 2011, EPA partially granted an Earthjustice petition seeking regulation of hydraulic fracturing fluids under TSCA, 15 U.S.C. §§ 2601-2697. This decision came on the heels of a November 2, 2011 rejection of another portion of the same petition. The combined response means that EPA plans to propose rules that would require (1) manufacturers and processors of hydraulic fracturing fluids to maintain records and submit reports to EPA on chemical composition, along with related environmental, health, and exposure information, and (2) manufacturers, processors, and distributors of hydraulic fracturing fluids to submit to EPA all existing health and safety studies related to hydraulic fracturing chemicals. However, EPA will not require the development of test data on hydraulic fracturing fluid chemicals, nor will it regulate the broader universe of chemical substances and mixtures used in oil and gas exploration and production (“E&P chemicals”). Given the stakes involved for both environmental and industry groups, legal challenges to EPA’s decisions can reasonably be anticipated.

Current Regulation of Chemical Disclosure Most states require some degree of chemical disclosure under their programs regulating the natural gas industry, which vary widely in both form and content. As public debate continues to intensify over the use of hydraulic fracturing processes to gain access to the ample reserves of natural gas in the Marcellus Shale, many companies have moved to the very public disclosure of hydraulic fracturing fluid contents via the online datasite “FracFocus,”: while more states are considering stricter rules on chemical disclosure by natural gas operators. See Tex. Nat. Res. Code Ann. § 91.851 and proposed 16 TAC § 3.29; New York’s proposed 6 NYCRR § 560.3(c), § 750-3.11(e)(1)(ii), § 750-3.12(b), and § 750-3.13(e). Because trade secret protections under state regulatory regimes are often more extensive than under TSCA, application of TSCA’s reporting requirements to hydraulic fracturing fluid producers may threaten to expose otherwise confidential, proprietary information.

However, limited disclosure of hydraulic fracturing chemicals is already required under current federal law through the development of material safety data sheets under the Occupational Safety and Health Act.. EPA is also currently conducting a comprehensive study on the potential impacts of hydraulic fracturing on drinking water supplies. The final study plan indicates that significant attention will be paid to hydraulic fracturing fluid composition, storage, injection processes, flowback, and disposal. Finally, EPA has recently proposed Clean Air Act standards that would require reductions of air emissions at new or modified wells drilled to extract natural gas using hydraulic

EPA to Require Chemical Disclosure Under TSCA by Hydraulic Fracturing Fluid Manufacturers

fracturing, and also announced that it is developing Clean Water Act effluent guidelines to control wastewater produced from hydraulic fracturing operations.

The Earthjustice Petition On August 15, 2011, Earthjustice submitted a petition to EPA pursuant to TSCA § 21, arguing that existing regulations provided the public with too little information on the perceived threat posed by hydraulic fracturing fluids. The petition requested four specific regulatory actions:

Adopt a rule pursuant to TSCA § 4 to require manufacturers and processors of E&P chemicals to develop test data sufficient to evaluate the toxicity and potential for health and environmental impacts of all substances and mixtures that they manufacture and process.

Adopt a rule pursuant to TSCA § 8(a) requiring manufacturers and processors of E&P chemicals to maintain records and submit reports to EPA disclosing the identities, categories, and quantities of E&P chemicals, descriptions and byproducts of E&P chemicals, all existing data on potential or demonstrated environmental health effects of E&P chemicals, and the number of individuals potentially exposed to E&P chemicals.

Request, pursuant to TSCA § 8(c) and its implementing regulations, submission of copies of any information related to significant adverse reactions to human health or the environment alleged to have been caused by E&P chemicals manufactured, processed, or distributed by the nine primary manufacturers, processors, and distributors of E&P chemicals (identified by name) in the United States.

Adopt a rule pursuant to TSCA § 8(d) to require submittal of all existing, not previously reported health and safety studies related to the health and/or environmental effects of E&P chemicals.

With regard to its § 4 request, Earthjustice claimed that its petition had developed a sufficient factual record to support each of two statutorily prescribed findings, either of which would force EPA to develop a rule requiring testing of the chemical substance or mixture in question: (1) the substance or mixture may present an unreasonable risk of injury to health or the environment, and (2) the substance or mixture is or will be produced in substantial quantities, and there is or may be significant or substantial human exposure to the substance or mixture. In either case, in order to have the authority to develop testing rules, EPA must also find that (1) there are insufficient data and experience to be able to reasonably determine the effects of the substance or mixture on health or the environment and (2) testing of the substance or mixture is necessary to develop such data.

With regard to its § 8(d) request, Earthjustice asserted that submission of health and safety studies was necessary to ensure that the chemical substances and mixtures do not present an unreasonable risk of injury to health or the environment – this coincides with the demonstration that Earthjustice would need to make in court to successfully challenge an EPA decision to deny a § 8 petition. Presumably, Earthjustice considered its other two § 8 requests to be supported by this same rationale.

EPA’s Denial of the Petition with Regard to Testing EPA tersely denied the § 4 request on November 2, 2011, stating that Earthjustice had failed to set forth sufficient facts to support the required findings set forth above for issuance of a test rule covering all E&P chemicals. Thus, EPA does not plan to require manufacturers and processors to conduct their own original testing. The response letter, however, suggested that “TSCA may be a valuable authority to provide a national picture of the chemical substances and mixtures used in

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EPA to Require Chemical Disclosure Under TSCA by Hydraulic Fracturing Fluid Manufacturers

hydraulic fracturing,” and therefore EPA would consider and conduct additional analyses on the § 8(a) and § 8(d) requests.1

EPA’s Grant of the Petition with Regard to Recordkeeping and Reporting As foreshadowed in its November 2 letter, EPA partially granted the § 8(a) and § 8(d) requests on November 23, 2011, but only with regard to hydraulic fracturing fluids (not the entire universe of E&P chemicals). EPA will issue an advance notice of proposed rulemaking with the expectation that any forthcoming rules “would focus on providing aggregate pictures of the chemical substances and mixtures used in hydraulic fracturing.”

The § 8(a) rule will likely require the maintenance of records and reporting with respect to the following information:

The common or trade name, the chemical identity, and the molecular structure of each chemical substance or mixture.

The categories or proposed categories of use of each such substance or mixture.

The total amount of each such substance and mixture manufactured or processed, reasonable estimates of the total amount to be manufactured or processed, the amount manufactured or processed for each of its categories of use, and reasonable estimates of the amount to be manufactured or processed for each of its categories of use or proposed categories of use.

A description of the byproducts resulting from the manufacture, processing, use, or disposal of each such substance or mixture.

All existing data concerning the environmental and health effects of such substance or mixture.

The number of individuals exposed, and reasonable estimates of the number who will be exposed, to such substance or mixture in their places of employment and the duration of such exposure.

The manner or method of its disposal, and in any subsequent report on such substance or mixture, any change in such manner or method.

Meanwhile, the § 8(d) rule would require the submission of any existing “health and safety study,” broadly defined in EPA’s regulations. “Not only is information which arises as a result of a formal, disciplined study included, but other information relating to the effects of a chemical substance or mixture on health or the environment is also included. Any data that bear on the effects of a chemical substance on health or the environment would be included. Chemical identity is part of, or underlying data to, a health and safety study.”

Significantly, EPA declared that its effort “would not duplicate, but instead complement, the well-by-well disclosure programs of states.” Furthermore, EPA expressed its desire to minimize reporting burdens and costs, take advantage of existing information, and avoid duplication of efforts.

Companies potentially subject to the anticipated TSCA reporting requirements, and other stakeholders in the oil and gas industry, will want to engage with EPA and others in the Administration and Congress to ensure that any proposed rule considers existing state requirements and minimizes burdens. EPA has indicated that it intends to convene a stakeholders group to seek involvement by various interests; and industry representatives (E&P chemical producers as well as service companies)

1 EPA apparently did not act on Earthjustice’s § 8(c) request to require the nine named primary manufacturers, processors, and distributors of E&P chemicals to report allegations of significant adverse reactions to human health or the environment – nor has EPA given an indication that it will do so in the future.

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EPA to Require Chemical Disclosure Under TSCA by Hydraulic Fracturing Fluid Manufacturers

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will want to assure they have a seat at that table. Given the ever-growing body of state regulations and industry practices related to hydraulic fracturing fluid chemical disclosure, many may question whether EPA needs to move under TSCA at this time – days and dollars lost in the development of and compliance with duplicative regulations are not well spent.

Authors: Cliff L. Rothenstein cliff.rothenstein@klgates.com +1.202.778.9381

Tad J. Macfarlan Tad.macfarlan@klgates.com +1.717.231.4513

PaDEP Issues Interim Guidance on Air Aggregation, Moves Away from "Functional Interdependence" Test

November 11, 2011 Practice Group(s): Energy, Infrastructure and Resources Oil & Gas By David R. Overstreet and Tad J. Macfarlan

Effective October 12, 2011, the Pennsylvania Department of Environmental Protection (“PaDEP”) is utilizing a new guidance for determining when various wells, compressor units and other equipment in the oil and gas industry constitute a single facility or source. This interim, non-binding policy statement entitled “Guidance for Performing Single Source Determinations for Oil and Gas Industries” is open for public comment through November 21, 2011. The new state guidance provides clarity on how PaDEP will answer a question of great significance to the Pennsylvania oil and gas industry: Should a widely dispersed collection of well production pads, connected by pipeline to a central processing or compressor station, be considered a single facility for the purpose of air emission regulation?

Like regulators in Texas, Oklahoma, Louisiana and West Virginia before it, PaDEP has indicated that it will generally answer this question in the negative. Because the components of these operations are not located on “adjacent” properties, as required by state and federal law, they will be regulated separately. PaDEP grounded its decision on (1) the plain meaning of the term “adjacent,” which relates to physical proximity and (2) its determination that these operations do not comport with the “common sense notion of a plant.” Emissions from individual well pads rarely exceed the requisite thresholds to qualify as major sources. Thus, unless their emissions are aggregated with other units, these facilities will not be required to comply with the stringent requirements of Pennsylvania’s Preventions of Significant Deterioration (“PSD”), New Source Review (“NSR”), and Title V operating permit programs. As discussed below, in taking this approach, PaDEP has departed from EPA staff guidance which has taken an expansive view of what is adjacent based on factors which have little to nothing to do with how close one unit might be to another.

The Regulatory Background In Pennsylvania, any person who wishes to construct, install or operate an “air contamination source” must first gain approval from PaDEP. In lieu of obtaining individual permits, PaDEP has created the Pennsylvania General Plan Approval and/or General Operating Permit for Natural Gas, Coal Bed Methane or Gob Gas Production or Recovery Facilities (“GP-5”), which provides a (relatively) streamlined process for oil and natural gas companies to request authorization to construct and operate a production facility. GP-5, however, expressly excludes from the ambit of its coverage any facility that triggers more strenuous PSD or NSR review. As mandated by the federal Clean Air Act (“CAA”), the Commonwealth of Pennsylvania has created regulatory regimes implementing the federal PSD, NSR, and Title V permitting programs. (The Pennsylvania rules have incorporated by reference the federal PSD program in its entirety; with regard to NSR and Title V, PaDEP has enacted its own regulations that meet the federal minimal requirements.) These programs impose significantly more onerous requirements on oil and gas industry permittees than does a GP-5 application.

PaDEP Issues Interim Guidance on Air Aggregation, Moves Away from "Functional Interdependence" Test

To trigger PSD, NSR, and Title V requirements, an emitter must first qualify as a “major facility” or “major stationary source” of emissions. The state and federal regulations establish threshold emissions rates that, if exceeded, will qualify a source or facility as “major.” Because all of Pennsylvania is considered in “non-attainment” with respect to the ozone ambient air quality standards, the key thresholds are those for oxides of nitrogen (NOx ) and volatile organic compounds (VOCs), where the triggers are a potential to emit more than 100 tons per year and 50 tons per year, respectively. For many oil and gas operations, individual well pads, compressor stations, and processing facilities do not exceed these thresholds. However, if emissions from each component are aggregated, the combined emissions levels would trigger PSD, NSR and Title V review. Thus, the “single source” determination is critical for both regulator and regulated community.

Under Pennsylvania law, to be considered a single facility or source, pollutant emitting activities must (1) belong to the same industrial grouping, (2) be located on one or more contiguous or adjacent properties, and (3) be under the control of the same person. (For NSR purposes, the first prong was left out of the definition of “facility” in the Pennsylvania regulations, but the second and third prongs remain the same.) Each prong must be satisfied for a single source determination to be made. The requirements under federal law are essentially the same where the United States Environmental Protection Agency (“EPA”) is the permitting authority (such as Indian country and states that have not been delegated permitting authority).

Moreover, the preamble to EPA’s PSD regulations, in which the three-part test first appeared, provides additional texture to the analysis. The definition of “source” (1) must carry out reasonably the purposes of the PSD program, (2) is meant to approximate a common sense notion of a “plant,” and (3) should not result in the aggregation of pollutant-emitting activities that as a group would not fit within the ordinary meaning of “building,” “structure,” “facility,” or “installation.” These interpretive guides grew out of a 1980 decision of the Court of Appeals for the D.C. Circuit, Alabama v. Costle, in which the court rejected EPA’s prior definition of a stationary source. Thus, these additional considerations carry the authority of a judicial decree.

The requirement that sources be located on “contiguous or adjacent” properties has been subject to differing interpretations by permitting authorities across the nation in relation to the oil and gas industry. The debate is highlighted here by investigating (1) PaDEP’s recently issued interim guidance and (2) EPA’s contrary position in a case pending before the U.S. Court of Appeals for the Sixth Circuit, Summit Petroleum Corp. v. EPA (No. 10-4572).

PaDEP’s Guidance While the interim guidance does not carry the weight of a duly promulgated regulation, it is significant nonetheless because it indicates the manner in which PaDEP intends to interpret its regulations with regard to the oil and gas industry. PaDEP expressed several important positions in this guidance:

PaDEP is agreeing with other state regulators who read the words “contiguous or adjacent” in harmony with their plain meaning. Both the common understanding and dictionary definitions of these terms refer to spatial distance and proximity. Thus, when conducting a “contiguous or adjacent” analysis, PaDEP will not consider interrelatedness or interdependence among oil and gas operation components, such as an extraction well and a compressor station on other property some distance away, in determining adjacency (though this may be taken into account in the analysis under the other prongs). Instead, PaDEP will simply ask whether the extraction, processing and/or compression facilities are close to one another – which, in most cases, they are not. This interpretation will result in determinations that approximate with the common sense notion of what constitutes a “plant”; sources many miles apart will not be aggregated.

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PaDEP Issues Interim Guidance on Air Aggregation, Moves Away from "Functional Interdependence" Test

As a rule of thumb, PaDEP is adopting a quarter mile as the cut-off point demarcating properties that are adjacent from those that are not. Properties located a quarter mile or less apart will be considered contiguous or adjacent properties; properties located beyond this quarter mile range may only be considered contiguous or adjacent on a case-by-case basis. This approach provides much desired certainty and clarity to industry.

PaDEP explicitly found EPA’s guidance to be non-dispositive.

EPA’s Interpretation of “Adjacent” Before the U.S. Court of Appeals for the Sixth Circuit Meanwhile, EPA’s Region 5 has moved towards the opposite end of the interpretive spectrum. In the currently active Summit Petroleum litigation before the Sixth Circuit, Region 5 has argued for the application of the “functional interdependence” test. Summit Petroleum involves a somewhat unusual fact pattern (which may limit the precedential value of any forthcoming decision) in which EPA acted as the permitting authority for Summit’s facilities located on Indian country. Summit brought suit when EPA determined that all of Summit’s approximately 100 wells should be aggregated. The wells range from 500 feet to eight miles away from Summit’s central sweetening plant.

Region 5 has argued that the word “adjacent” must be interpreted with reference to context, and adjacency determinations should not be based solely upon physical distance. The context that Region 5 would consider includes the interdependence of oil and gas sources and the broad geographic scope of air pollution. Presumably, the more related and dependent the facilities, the less physically near they must be in order to find that the properties on which they are located are adjacent to each other.

EPA notes that it rejected in 1980 a proposed definition that used the concepts of proximity and control as the sole criteria for aggregating pollutant-emitting activities, because that “definition would fail to approximate a common sense notion of a ‘plant,’ since in a significant number of cases it would group activities that ordinarily would be regarded as separate.” (emphasis added). EPA’s original concern was grouping unrelated facilities that happened to be located on the same property. In the oil and gas context, however, a focus on proximity threatens no such outcome. In fact, it would accomplish just the opposite – ensuring that activities ordinarily regarded as separate are considered separately.

Notably, Region 5’s current position is not the one it espoused under the Bush Administration, as captured in the January 12, 2007 guidance entitled “Source Determinations for Oil and Gas Industries” (“Wehrum Memorandum”). The Wehrum Memorandum endorsed a view more aligned with PaDEP’s current position, through its focus on spatial proximity and rejection of “operational dependence” as a driving factor. This guidance was withdrawn and replaced on September 22, 2009 by the “Withdrawal of Source Determinations for Oil and Gas Industries (“McCarthy Memorandum”). The McCarthy Memorandum emphasizes that source determinations should rely foremost on the application of the three criteria on a case-by-case basis, and also on the 1980 PSD rule preamble and the decisions of Regional Offices in prior determinations and guidance documents.

Conclusion While this article has focused on the Summit litigation and interim DEP guidance, oil and gas industry single source determination issues are currently pending before a variety of tribunals and administrative bodies. For example, questions regarding single source determinations are before the

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PaDEP Issues Interim Guidance on Air Aggregation, Moves Away from "Functional Interdependence" Test

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U.S. District Court for the Middle District of Pennsylvania (Citizens for the Future of Penn. v. Ultra Resources, Inc., 4:11-cv-01360-JEJ), though threshold issues threaten to derail the challenge to PaDEP’s decision not to aggregate prior to resolution on the merits. Additionally, the Clean Air Council ("CAC") has recently submitted a letter to EPA Region 3 urging the regional office to intervene in PaDEP's implementation of its guidance. CAC's position that PaDEP has failed to fulfill its duties under the federal CAA represents another iteration of the familiar dispute over the meaning of adjacency and attempts to exalt EPA guidance and staff memos to the status of regulations. It is important for oil and gas operators to be mindful of the continuing precedential developments in these matters; interpretive decisions will provide invaluable insight into the contours of the regulatory landscape that their businesses must operate within.

Authors: David R. Overstreet david.overstreet@klgates.com +1.412.355.8263

Tad J. Macfarlan tad.macfarlan@klgates.com +1.717.231.4513

Ohio EPA Releases Draft General Permit for Oil and Gas Well-Site Production Operations

November 3, 2011 Practice Group(s): Energy, Infrastructure and Resources Oil & Gas By Bryan D. Rohm, David R. Overstreet and Craig P. Wilson

Introduction On October 20, the Ohio Environmental Protection Agency (“Ohio EPA”) published for public review and comment a draft air pollution general permit for oil and gas well site production operations (“Draft GP”), together with an accompanying qualifying criteria document, which includes a new section covering natural gas micro turbines. The Draft GP is intended to streamline the permitting process to facilitate the marked increase in the development of the Utica and Marcellus shale formations in Ohio. Ohio EPA will receive public comments on the Draft GP through November 28, 2011, and expects to issue a final general permit for use by the end of 2011.

Background An earlier version of this draft general permit has been available for unofficial comment from Ohio EPA since June 2011. In July 2011, Ohio EPA released a second version of this draft general permit dated July 29, 2011, which was opened for official public comment. Eleven official public comments were received and published on Ohio EPA’s website on October 3, 2011. The Draft GP follows and implements some of the proposed comments made to the July 2011 version.

Purpose The Draft GP applies to air emissions from the production phase of oil and gas operations. The Draft GP covers emissions from: (i) dehydration systems; (ii) natural gas-fired spark-ignition engines; (iii) diesel engines; (iv) micro turbines; (v) unpaved roadways; (vi) petroleum liquids and recovered-water storage tanks and loading; (vii) natural gas-fired turbine generator sets; (viii) combustion devices/flares; and (ix) equipment/pipeline leaks. (Ohio EPA has taken the position that emissions from the drilling and completion phases are temporary, of limited duration or de minimis, and, therefore, generally are exempt from permitting requirements.) The Draft GP identifies the law or regulation applicable to each type of source and lists the emission limitations, operational restrictions, monitoring and recordkeeping requirements, reporting requirements, and testing requirements.

A goal of the Draft GP is to streamline the permitting process and allow operators to receive authorizations in as little as two weeks. In addition, Ohio EPA is “exercising its discretion not to penalize a company for failing to obtain an air permit before installing an oil and gas well as long as the company applies for the general permit within thirty (30) days of the general permit becoming available.”

Ohio EPA Releases Draft General Permit for Oil and Gas Well-Site Production Operations

What Is New In the October 20, 2011 Draft GP?

A prominent difference between the July 29, 2011 version and the October 20, 2011 Draft GP is the addition of a new section regulating natural gas micro turbines.1 Natural gas micro turbines offer a low emission alternative to diesel powered generators and will now be covered under the Draft GP, but will be limited to a maximum capacity of 200 kW.

Other notable additions or changes incorporated into the Draft GP are: (i) an express accommodation of uncertified engines; (ii) a requirement to maintain manufacturers’ operating manuals or instructions at a central location (rather than requiring them on-site); (iii) an increase in combined total horsepower to 1,800 (from 1,500) for spark ignition internal combustion engines; (iv) varying stack height for spark ignition internal combustion engines based on engine size; (v) modified requirements for the development of a leak detection and repair program to monitor and repair leaks from equipment covered under the Draft GP; (vi) a decrease in the minimum inspection frequency for unpaved roads to monthly (from daily); (vii) a limitation of the Draft GP to unpaved roadways less than 3 miles in length (the prior draft covered all unpaved roads, regardless of length); (viii) various changes to emissions limits and testing standards; and (ix) an increase in the number and capacity of storage tanks covered.

In recent comments, several operators suggested removing all regulation of unpaved roads from the Draft GP. Although Ohio EPA reduced the monitoring frequency of unpaved roads from daily to monthly, there still remains concern surrounding: (i) the need for and burden of dust abatement in rural, unpopulated areas; and (ii) monitoring non-oil and gas related traffic on unpaved, public roads. In what appears to be an effort to mitigate the burden of maintaining dust abatement on public roads, the Draft GP limits dust abatement requirements to unpaved roads that do not exceed 3 miles in length. However, Ohio EPA did not eliminate entirely the requirement for dust abatement on unpaved roads in rural unpopulated areas.

Conclusion Operators with current or planned Marcellus/Utica shale development in Ohio who believe they will be impacted by the final general permit should review and provide suggestions regarding the Draft GP. The comment period closes on November 28, 2011. Ohio EPA is offering two ways to submit comments: (i) via email to cheryl.suttman@epa.state.oh.us; or (ii) via mail to Cheryl Suttman, Attn: General Permits, Ohio EPA – DAPC, P.O. Box 1049, Columbus, Ohio 43216-1049.

Authors: Bryan D. Rohm bryan.rohm@klgates.com +1. 412.355.8682

David R. Overstreet david.overstreet@klgates.com +1. 412.355.8263

Craig P. Wilson craig.wilson@klgates.com +1. 717.231.4509 1 Ohio Environmental Protection Agency, October 20, 2011 Draft Version of the Ohio EPA Air Program Oil and Gas Well-Site Production Operations General Permit Terms and Conditions, pp. 31-34, available at http://www.epa.ohio.gov/portals/27/genpermit/NG.GP3mhb.docx (last visited Oct. 26, 2011).

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Ohio EPA Releases Draft General Permit for Oil and Gas Well-Site Production Operations

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Battles Over the Federal Policies Regulating Hydraulic Fracturing By Cliff L. Rothenstein, Michael W. Evans, Cindy L. O’Malley

Natural gas is a clean and abundant fuel source, offering significant potential for achieving energy independence, reducing greenhouse gas emissions, and creating jobs, especially in rural America. The ability to extract natural gas from shale formations by using hydraulic fracturing promises greater opportunities for natural gas development, and is rapidly becoming the extraction method of choice, but not without some controversy over the potential impacts to the environment.

Pennsylvania’s Marcellus Shale region has become ground zero in this debate for industry and environmentalists alike. According to some estimates, by 2020 this region could produce more than 13 billion cubic feet of natural gas per day, creating 200,000 jobs and generating $1 billion annually in state and local tax revenues. These benefits, however, are possible only if the issues over hydraulic fracturing can be resolved in a way that permits further development. National, state and local environmental groups are questioning the safety of hydraulic fracturing, and using legal and political means in an effort to win over states, the Administration and some in Congress. They are making progress in these efforts.

Congressional Activity As we near the end of the first session of the 112th Congress, the debate over hydraulic fracturing is breaking largely along partisan lines, cast as a choice between federal or state environmental regulations. In the U.S. federal legislative arena, Members of Congress, industry leaders and environmental groups are squaring off and drawing their lines in the sand.

A number of Democrats, supported by environmental groups, have introduced the so called

“FRAC Act,” which would require greater federal controls over hydraulic fracturing, including disclosures of the chemicals used in this process.

On the other side of the issue are oil and gas industry leaders, key House committee chairmen and members of the Congressional Natural Gas Caucus, who support state oversight of the industry and express concerns that federal regulations will raise energy costs, suppress job creation and hinder the nation’s ability to become energy independent.

Although hydraulic fracturing has quickly become a divisive issue in Congress, much of the activity over the future of environmental regulations is actually playing out within the Obama Administration, and in state capitals.

October 17, 2011 Practice Group: Public Policy and Law

Battles Over the Federal Policies Regulating Hydraulic Fracturing

2

Inside the Administration In Washington, the White House Council on Environmental Quality is coordinating department policies on hydraulic fracturing, and the U.S. Environmental Protection Agency (EPA), the Department of Interior (DOI) and the Department of Energy (DOE) are moving forward on several fronts.

Environmental Protection Agency Activities Hydraulic Fracturing Study – Of particular interest is EPA’s congressionally mandated hydraulic

fracturing study to evaluate the potential impacts of hydraulic fracturing on drinking water and waste water. Initial results are not expected until the end of 2012, but the study could be a regulatory game changer.

Treatment of Wastewater – In response to a recent controversy over wastewater discharges in Pennsylvania, EPA is actively working with state regulators to develop guidance for the treatment of wastewater, and to set contaminant limits for the discharge of wastewater.

Aggregation of Air Emissions – With little fanfare, EPA is also moving toward a new approach for aggregating air emissions by entities engaged in multiple activities under common ownership. This could result in especially significant changes, potentially requiring large numbers of air permits and New Source Reviews for hydraulic fracturing operations.

SDWA Permitting of Diesel Fuel – Finally, EPA is stepping up its enforcement activity and its review of the use of diesel fuel in hydraulic fracturing. Of particular note is EPA’s soon to be released guidance for permitting hydraulic fracturing operating under the Safe Drinking Water Act (SDWA). Although the SDWA largely eliminated authority to regulate hydraulic fracturing operations, EPA may permit such operations that use diesel fuel and is now considering a broad definition of diesel fuel, thereby extending the reach of the SDWA.

Department of Interior and Department of Energy Activities DOI is actively considering new policies and regulations that would tighten controls on hydraulic

fracturing operations, including mandatory disclosure of chemicals used in hydraulic fracturing on public lands, and the use of best practices for waste disposal and well integrity.

DOE Secretary Steven Chu also created a panel to craft best industry practices for mitigating a host of environmental impacts of hydraulic fracturing.

State Actions In addition to these federal actions, many states are beginning to tighten the regulatory grip on hydraulic fracturing operations.

Several states, including New York, New Jersey and Maryland, have imposed or are considering a moratorium on drilling permits.

Battles Over the Federal Policies Regulating Hydraulic Fracturing

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The Pennsylvania legislature has also considered numerous bills to further control natural gas development in the state.

Wyoming and Texas have enacted new requirements for drillers to disclose the quantity and composition of toxic fluids used in hydraulic fracturing and California is considering similar legislation.

The New York Attorney General recently filed a lawsuit to require a full environmental review of proposed hydraulic fracturing in the Delaware River Basin.

International Developments Hydraulic fracturing is not confined to our borders, nor is the controversy.

France became the first country to ban hydraulic fracturing when its Government voted to halt the process on June 30 of this year. A report issued to the French Government this past spring actually highlighted the benefits of hydraulic fracturing including the economic benefits, and suggested alternative drilling techniques. Environmental groups, however, took issue with the report, stating it was heavily influenced by the country’s energy lobby. Mounting pressure from these opposition groups led to a Senate vote to ban the practice. Some are speculating if the EU follow suit.

In Canada the exploration of Natural Gas is moving at a quick pace, with companies seeking to establish wells in new areas, such as New Brunswick. New Brunswick just introduced a preliminary regulatory framework for exploration, and the Canadian government recently launched two separate reviews on the impacts of hydraulic fracturing. These developments come as Quebec has halted hydraulic fracturing operations.

The Future These developments leave much uncertainty about the development of hydraulic fracturing operations. While calls for overly stringent federal controls on hydraulic fracturing are not likely to prevail, it is also unlikely that these issues will be left solely to state regulation. The stringency, scope and of combination of federal and state regulation in this area will be resolved through the political and regulatory processes. For now, there remains a window of opportunity for companies involved in natural gas development to help shape the regulatory future.

Authors:

Cliff L. Rothenstein Michael W. Evans Cindy L. O’Malley Government Affairs Advisor Partner Government Affairs Counselor cliff.rothenstein@klgates.com michael.evans @klgates.com cindy.omalley@klgates.com +1.202.778. 9381 +1.202.661.3807 +1.202.661.6228

Battles Over the Federal Policies Regulating Hydraulic Fracturing

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Third Circuit Gives Natural-Gas Producers Important Ammunition for Obtaining Expedited Injunctive Relief from the Courts

October 10, 2011 Practice Group(s): Energy, Infrastructure and Resources Oil & Gas By J. Nicholas Ranjan and George A. Bibikos

Introduction A federal court of appeals in the Marcellus Shale area has provided natural-gas producers an important tool to use when surface owners interfere with their rights to drill. In Minard Run Oil Co. v. U.S. Forest Service, --F.3d --, 2011 WL 4389220 (3d Cir. Sept. 20, 2011), the Third Circuit’s precedential opinion underscored that natural-gas producers may be able to establish the irreparable harm necessary to obtain an injunction or temporary restraining order simply by demonstrating that they have been prevented from drilling without meeting a more demanding standard. The court’s decision was noteworthy in two respects.

First, the court provided additional support for natural-gas producers and other mineral owners to obtain a temporary restraining order or other injunctive relief from the courts in order to stop others from impeding drilling efforts. Oftentimes, producers are thrust into disputes with surface owners and governmental actors who have taken steps to hinder drilling. Unfortunately, producers many times are required to resort to litigation in order to press their rights, including asking courts for emergency injunctive relief, which includes proving to the court that they have suffered “irreparable harm.”

In Minard Run, the court expressly recognized that irreparable harm can result simply from the fact that a producer is prevented from exercising its right to drill, a holding that provides natural-gas producers more ammunition for obtaining emergency injunctive relief in order to prevent governmental actors, surface owners, and other entities from taking any action that might hinder a producer’s ability to extract natural gas. Indeed, after Minard Run, a producer may be able to argue that it has suffered “irreparable harm”—a key element in obtaining an injunction—any time it has been prevented from extracting natural gas.

Second, the court reaffirmed the well-established principle that, where the mineral estate and surface estate are severed, the mineral estate remains the “dominant” estate. In other words, the mineral owner retains the right to use as much surface land as reasonably necessary to extract minerals, and the mineral owner need not obtain consent or approval before entering land to mine for minerals.

The Court’s Decision On June 1, 2009, Minard Run Oil Company, as well as several other parties, brought suit against the U.S. Forest Service (the “Service”)—the surface owner of the property in the region—among other related persons and entities. Minard Run’s complaint alleged that, as a result of a prior settlement agreement between the Service and some environmental groups, the Service had imposed a de facto drilling ban in the region until an environmental impact study could be completed. Minard Run challenged the Service’s authority to implement a change in policy under the National Environmental Policy Act and the Administrative Procedure Act.

Third Circuit Gives Natural-Gas Producers Important Ammunition for Obtaining Expedited Injunctive Relief from the Courts

The district court agreed with Minard Run, and it granted a preliminary injunction that enjoined the Service from altering its prior policy and requiring the environmental impact study as a precondition to the exercise of oil and gas rights in the region.

The Third Circuit affirmed the district court’s opinion. The court initially reaffirmed the well-established principle that, where the mineral estate and surface estate are severed, the mineral estate remains the “dominant” estate. The court stated that “[a]lthough the mineral owner must show ‘due regard’ to the rights of the surface owner, the mineral owner need not obtain consent or approval before entering land to mine for minerals.” Against this legal backdrop, the court held that the National Environmental Policy Act and the Administrative Procedure Act did not permit the Service to enact its de facto drilling ban.

The Third Circuit also affirmed the district court’s preliminary-injunction order. In addressing whether Minard Run and the other plaintiffs established irreparable harm sufficient to obtain a preliminary injunction, the court held that they did. Specifically, the Court concluded that “where interests involving real property are at stake, preliminary injunctive relief can be particularly appropriate because of the unique nature of the property interest.” The court reasoned that, under Pennsylvania law, oil and gas resources are subject to the “rule of capture,” which permits an owner to extract oil and gas even when extraction depletes a single oil or gas reservoir lying beneath adjoining lands. Accordingly, because a moratorium on new drilling deprived mineral owners in the region from being the first to capture the oil and gas, the court found that the drilling ban would cause these owners to potentially lose oil and gas to other landowners drilling on adjoining private lands that are not subject to the moratorium. The court held that depriving Minard Run and other mineral-rights owners of the unique oil and gas extraction opportunities afforded them by their mineral rights constituted irreparable harm.

Conclusion The Third Circuit’s decision in Minard Run is noteworthy in its discussion of the Service’s statutory authority in enacting its de facto drilling ban. But the decision has broader significance to natural-gas producers because of its reaffirmation of the dominance of the mineral estate and its holding that producers and other mineral-estate owners can obtain emergency relief and establish “irreparable harm” by simply showing that they have been denied extraction opportunities.

Authors:

J. Nicholas Ranjan nicholas.ranjan@klgates.com +1.412.355.8618

George A. Bibikos george.bibikos@klgates.com +1.717.231.4577

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Third Circuit Gives Natural-Gas Producers Important Ammunition for Obtaining Expedited Injunctive Relief from the Courts

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Is Marcellus Shale a “Mineral,” and Who Owns the Natural Gas in the Shale?

September 20, 2011 Practice Group(s): Energy, Infrastructure and Resources Oil & Gas

Introduction In Butler v. Charles Powers Estate1 the Pennsylvania Superior Court recently decided preliminary matters in the case in a way that potentially opens the door for operators who acquired tens of thousands of deeds or leases to be stripped of their rights to drill for shale gas. In Butler, the Superior Court remanded a case to the trial court for further proceedings to determine whether the heirs of a grantor who reserved only “minerals” and “petroleum oils” in a deed also reserved natural gas from the Marcellus shale formation. Although the decision at this point is not definitive and has the potential for more bark than bite, it suggests a possible exception to the longstanding “Dunham Rule” that those in the oil and gas industry have long relied upon in acquiring natural gas rights. For example, if after remand, Pennsylvania courts ultimately rule that the word “mineral” in a deed includes the Marcellus shale formation, and whoever owns the shale formation owns the gas, then the tens of thousands of deeds or leases acquired by producers in Pennsylvania may suddenly have a meaning that was never contemplated or intended. For this reason, the oil and gas industry should keep a keen eye on the proceedings and find ways to participate in the decision-making process to be sure that the industry’s perspective – not just the perspective of the individual parties in the case – is properly heard and understood.

What is the “Dunham Rule”? Pennsylvania courts interpret deeds and reservations in accordance with the parties’ intent. For over a century, Pennsylvania courts have applied the so-called Dunham Rule. Under the Dunham Rule2, Pennsylvania courts have held that a grant or reservation of “minerals” in a deed generally does not mean that the parties intended to grant or reserve the oil or gas. About 80 years later, the Pennsylvania Supreme Court in Highland v. Commonwealth3 held that, to rebut the Dunham presumption, one must present “clear and convincing” evidence that the parties to the conveyance intended to include natural gas within the word “minerals.”

What happened in Butler? Butler involved an 1881 deed in which the grantor (Mr. Powers) excepted and reserved to himself “one half of the minerals and Petroleum Oils.” The Butlers (heirs to the grantee) brought an action against the heirs of Mr. Powers to quiet title to the natural gas. The heirs of Mr. Powers, in turn, sought a declaratory judgment that they owned the natural gas by virtue of the reservation of “minerals.”

The Butlers preliminarily objected to the request for declaratory relief and argued that, under the Dunham rule, the heirs of Mr. Powers only reserved the “minerals” and “petroleum oils” such that Mr.

1 ---A.3d---, 2011 WL 3906897 (Pa. Super. Ct. Sep. 7, 2011). 2 101 Pa. 36 (Pa. 1882). 3 161 A.2d 390 (Pa. 1960), cert. denied, 364 U.S. 901 (1960).

Is Marcellus Shale a “Mineral,” and Who Owns the Natural Gas in the Shale?

Powers did not reserve the natural gas. Applying the Dunham Rule, the trial court agreed with the Butlers and held that (through the chain of title) they now own the natural gas as a matter of law. The Powers heirs appealed.

On appeal, the heirs of Mr. Powers argued that (1) Dunham and Highland only apply to grants or reservations of conventional “wild” gas, not “unconventional” gas from a shale formation; (2) the Marcellus shale is a “mineral”; and (3) producing gas from the Marcellus shale is similar to producing coalbed methane from a vein of coal. The rule for coalbed methane is that whoever owns the coal owns the coalbed methane.4

Arguing by analogy, the Powers heirs argued that whoever owns the shale owns the shale gas.

What did the Superior Court decide? The Superior Court remanded the case for further proceedings. The court seemed interested in a number of issues that are peculiar to modern production of gas from “tight” shale formations. For example, the court noted potential similarities between coalbed methane and shale gas, in that they both can contain natural gas that the court characterized as not “ferae naturae,” or free flowing “wild” gas. The Superior Court further analogized shale gas to coalbed methane, noting that the development of gas from both coal and shale requires fracturing to release the gas. Ultimately, the Superior Court remanded the case for further proceedings to understand: (1) whether the Marcellus shale is a “mineral”; (2) whether gas from the Marcellus shale constitutes the type of natural gas contemplated in Dunham and Highland; and (3) whether Marcellus shale is similar to coal to the extent that whoever owns the shale, owns the shale gas.

What are the concerns? Although the court remanded the case for further proceedings and made no definitive pronouncements of law, the Superior Court’s decision raises a number of significant concerns:

Parties’ Intent. The issue in any case involving deed interpretation is the intent of the parties. The deed in Butler is 130 year old. It seems very likely that the original parties could not have anticipated the ability to develop natural gas from a shale formation. The court, however, seems to be inviting a reading of the intent of the parties to a century-old deed through a modern lens that could not reflect their knowledge and intent at the time of the conveyance.

Definition of “minerals.” Although there is no precise definition of the term in the case law, the courts have held that the word “mineral” as used in conveyances means something that is mined and sold (e.g., coal).5

The Marcellus shale is a gas-bearing rock formation buried thousands of feet beneath the surface of the earth. In this sense, such shale rock is not typically thought of as something that is (or even can be) mined and sold and seems to fall outside of the meaning of “minerals” as parties ordinarily use that word in deeds and other conveyances.

The wild-gas vs. trapped-gas distinction. To some extent, all natural gas is restricted depending upon subsurface pressures and the permeability of the rock or other formations (e.g., tight sands) in which the gas is contained. The movement (flow) of the gas is governed by the relative characteristics of the rock formations in which it is contained. Gas within shale formations is not really different. When the shale is penetrated (whether by vertical or horizontal wells), gas is released and at that point flows freely, other formations may have higher porosity, permeability

4 U.S. Steel Corp. v. Hoge, 468 A.2d 1380 (Pa. 1983). 5 Silver v. Bush, 62 A. 832, 833 (Pa. 1906).

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Is Marcellus Shale a “Mineral,” and Who Owns the Natural Gas in the Shale?

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and transmissivity, but these are geologic characteristics that involve a matter of degree. If shale gas is to be treated differently than “wild” gas for purposes of determining the parties’ intent in a deed, how will the courts determine whether gas is “wild” enough to qualify for the Dunham presumption? It seems the Superior court is inviting a rule that will inevitably lead to much litigation involving experts to determine where to draw the line within a continuum of geologic parameters that govern gas movement when the focus should be on whether the parties intended to convey (or reserve) natural gas rights regardless of the source rock or how freely the gas flows.

Analogy to coalbed methane. The rule for coalbed methane as it developed in Pennsylvania is a unique one. Historically, coal operators had to maintain control over the methane gas trapped in coal beds to avoid dangerous conditions while mining the coal. In addition, the methane historically had no commercial value. For these reasons, courts held that when parties conveyed “gas,” by deed or lease, they could not have intended to convey coalbed methane. The court seems to have overlooked the history and policy reasons underlying the coalbed methane rule and the dissimilarities between coalbed methane and development of shale gas.

What should the industry do? The oil and gas industry should attempt to get involved in the case so that its interests are properly heard and understood. If, for example, the Pennsylvania Supreme Court exercises its discretion to accept any appeal from the Butlers, interested parties will have the opportunity to file amicus briefs during the appeal. If the case proceeds on remand, development of the record will be particularly important. The issues identified by the Superior Court will be developed from the perspective of the individual parties to the case and not from the perspective of the industry. It seems clear that the courts may benefit from the perspective of the oil and gas industry in cases that call for the application of well settled rules that govern the ownership of natural gas rights.

Authors: George A. Bibikos george.bibikos@klgates.com +1.717.231.4577

Bryan D. Rohm bryan.rohm@klgates.com +1.412.355.8682

Contact: David R. Fine david.fine@klgates.com +1. 717.231.5820

West Virginia Governor Orders WVDEP to Enact Marcellus Shale-Specific Regulations On July 12, 2011, acting West Virginia Governor, Earl Ray Tomblin, issued Executive Order No. 4-11 (the “Order”), prescribing the course of future regulation of oil and gas operations in the Marcellus Shale in West Virginia.1 The Order confirms a number of existing policies and practices and directs the West Virginia Department of Environmental Protection (“WVDEP”) to promulgate additional environmental regulations to govern Marcellus Shale operations.

Highlights of the Order include the following:

1. Prohibition of land application of return fluids from completion activities.

2. Requirement for written approval from WVDEP prior to disposal of return fluids from completion activities at any publicly-owned wastewater treatment plant.

3. Enactment of emergency rules by DEP to address the following:

• Contents and procedures for well permit applications. For well-sites with three acres or more of surface disturbance (excluding pipelines, gathering lines and roads), the Order requires the operators to have the following:

a. An erosion and sediment control plan certified by a registered professional engineer;

b. A site construction plan certified by a registered engineer; and

c. A comprehensive well-site safety plan.

• Rules concerning water withdrawals. Well work permit applications must include an estimate of the volume of water to be used in drilling, fracturing or stimulation. Where applications project a withdrawal of West Virginia waters in excess of 210,000 gallons in any month, the application must also include a comprehensive water management plan. Well operators that withdraw more than 210,000 gallons of water from sources in West Virginia will be required to comply with specific recordkeeping and reporting requirements.

• Water protection. New rules will contain specific measures to protect the quantity and quality of surface water and ground water during drilling, after drilling, and during reclamation.

• Notice to Municipality. Well work permit applicants that seek to drill the first horizontal Marcellus Shale well on a well pad located within any municipality will be mandated to publish public notice of the filing of the application.

4. For horizontal well sites that either (a) contain three acres or more of surface disturbance (excluding pipelines, gathering lines and roads), or (b) will require water withdrawal from the State of West Virginia in excess of 210,000 gallons in any month, operators will be required to dispose

1 A press release from the Governor’s office, which contains a link to the text of the Order can be found at: http://www.governor.wv.gov/newsroom/pressreleases.

July 29, 2011 Practice Group: Oil & Gas

West Virginia Governor Orders WVDEP to Enact Marcellus Shale-Specific Regulations

2

of “drill cuttings” and “drilling mud” in an approved solid waste facility or manage those materials on-site in accordance with DEP specifications.

Although existing West Virginia rules may not contain some of these specifics, many of the items included in the Order reflect or are consistent with industry standards and current practices in West Virginia. Moreover, by adopting these practices, West Virginia appears to be moving closer to procedures in neighboring Pennsylvania, as for example with respect to erosion and sediment control plan and water management plan requirements. Nonetheless, operators doing business in West Virginia should review their policies and procedures for compliance with the Order and continue to monitor the activities of the WVDEP in regard to the development and promulgation of rules pursuant to the Order.

Authors: Brian P. Anderson brian.anderson@klgates.com

+1.412.355.8966

R. Timothy Weston tim.weston@klgates.com

+1.717.231.4504

July 22, 2011 Practice Group: Oil & Gas

North Carolina Takes a Step Closer to Shale Gas Production

Overview and Background North Carolina is not traditionally thought of as an oil and gas state. However, legislation enacted in June sets in motion a process that could result in the authorization of horizontal drilling and hydraulic fracturing – game-changing technologies that have turned shale deposits in other parts of the country into top resource plays. Furthermore, a study by the North Carolina Geological Survey has found that potential shale gas reserves, once thought to be inadequate for commercial production, may be much larger than historically estimated. If the advanced technologies employed in other states become legal in North Carolina, the state’s shale basins could become an important regional gas play. If not, the state’s shale gas will remain in the ground.

The Legislation The North Carolina General Assembly passed two bills in June with provisions requiring state agencies to study shale gas exploration and production and to develop an outline for a regulatory framework to permit shale gas production. The first bill, House Bill 242, was signed into law by Governor Bev Perdue and is now Session Law 2011-276. The second bill, Senate Bill 709, was vetoed by Governor Perdue for unrelated reasons and currently awaits an override vote. Each takes a slightly different approach to reforms and to studying further substantive changes.

House Bill 242 directs the North Carolina Department of Environment and Natural Resources (“DENR”), the Department of Commerce, and the Department of Justice to “study the issue of oil and gas exploration in the State and the use of directional and horizontal drilling and hydraulic fracturing for that purpose.” The study will review the issues from several different angles, including analysis of potential economic impacts, environmental impacts, social impacts, consumer protection, and potential oversight and administrative issues. As part of this process, DENR must hold at least two separate public hearings by February 1, 2012. DENR must make its full report to the General Assembly by May 1, 2012 and must include specific legislative proposals, including regulatory requirements to address environmental issues associated with hydraulic fracturing.

House Bill 242 also makes a number of minor updates to the Oil and Gas Conservation Act and adds a number of protections for landowners who lease subsurface rights for gas development. The law requires compensation of landowners for any damage to water supplies in use prior to natural gas activities on the property and requires gas developers to indemnify adjacent property owners for property damage. The law also establishes a lease termination provision by which gas leases will automatically terminate after ten years, unless oil or gas is being produced by the end of the initial ten-year term and commercial production has not stopped for a period of six months or more. Other protections include a requirement that the gas developer provide written notice to the landowner including an exploration or development plan prior to commencement of gas exploration or production.

North Carolina Takes a Step Closer to Shale Gas Production

A related bill, Senate Bill 709, the Energy Jobs Act, was vetoed by the Governor. Nevertheless, the Senate has overridden the veto, and the House will take up the override issue next week. The potential implications of this bill are worthy of note. The provisions of the Energy Jobs Act dealing with shale gas also require DENR to provide a comprehensive report by May 1, 2012. This report is to outline the commercial potential of shale gas resources within the state and the regulatory framework necessary to develop shale gas in North Carolina. Additionally, DENR would be required to review all North Carolina natural gas laws and regulations and to review federal laws and the laws of Texas, Pennsylvania, and Arkansas as reference points for a new state regulatory framework. The legislation also calls for an inventory of water supplies and an evaluation of water supply availability in the areas with known or suspected shale gas. If the Energy Job Act becomes law, this study would be consolidated with the study required by House Bill 242.

The North Carolina Shale Gas Resource North Carolina’s shale reserves are located in two Triassic period river basins deep under the surface: the Deep River Basin and the Dan River Basin, shown in green below. The Deep River Basin is made up of the Sanford sub-basin in Chatham, Lee, and Moore counties; the Durham sub-basin in Chatham, Wake, Orange, Durham, and Granville Counties; and the Wadesboro sub-basin in Montgomery, Richmond, and Anson Counties. The Dan River Basin crosses Stokes and Rockingham Counties, and continues north into Virginia, where it is known as the Danville Basin.

These areas contain organic-rich shales that may yield commercially viable quantities of natural gas. In fact, the North Carolina Geologic Survey estimates that North Carolina may have enough shale gas to meet the state’s current level of energy demand for 40 years.

Although geologic conditions in these basins are not ideal, similar conditions have yielded profitable operations in the Barnett Shale in Texas, the Haynesville Shale in Louisiana, and the Marcellus Shale in several northeastern states, thanks to horizontal drilling and hydraulic fracturing, higher energy prices, and an increased demand for natural gas.

2

North Carolina Takes a Step Closer to Shale Gas Production

Economic Development Potential The potential economic impact of shale gas production could be profound in North Carolina. Development of a shale gas industry could add thousands of jobs, significant payments to landowners, and large revenue streams to the state in the form of royalty payments. Furthermore, natural gas development is capital intensive, and substantial investments could be made in the counties where the shale deposits are located.

By way of illustration, it is estimated that the recent natural gas boom in the Marcellus Shale region of Pennsylvania, West Virginia, New York, and Ohio supported nearly 140,000 jobs, $1.1 billion in state and local tax revenues, and $11.2 billion in the regional equivalent of gross domestic product in 2010. Of course, the North Carolina shale gas play is estimated to be a fraction of the size of the Marcellus Shale, but these figures indicate that the economic development potential of shale gas in North Carolina is significant.

Additionally, domestic shale gas production reduces American dependence on foreign gas and oil, increasing energy independence. Natural gas, which burns cleaner than other fossil fuels, is widely touted as a transition fuel from coal and oil to renewable energy sources.

Legal and Environmental Issues The prospect of shale gas development in North Carolina raises a long list of legal and environmental issues. Like all oil and gas wells, the drilling and completion process engenders concerns regarding casing and cementing protocols to seal off and protect shallow fresh groundwater zones and prevent gas migration between penetrated formations. The process of hydraulic fracturing, one of the techniques that makes shale plays viable, uses high-pressure injection of water, sand, and usually small amounts of chemical additives (such a surfactants) deep underground to create fractures in the shale to unlock the natural gas within. The process uses large volumes of water and generates significant amounts of wastewater as well, which raises water resource and wastewater management issues. Air emissions, well construction standards and inspections, solid waste handling, storm water management, sedimentation and erosion control, pre-drilling surveys of nearby water supplies and related protections of public and private water supplies, and numerous other issues are implicated.

Other significant legal and administrative issues would be raised as well. Permit requirements, severance taxes or state royalties, landowner protection issues, local land use policies, mineral rights and leasing, and the adequacy of roads and other infrastructure are just some of the issues that would require attention if shale gas production were to become a reality in North Carolina. Part of North Carolina’s challenge will be in establishing workable programs, standards and regulatory approaches that address these issues, providing predictable rules of the road while facilitating use of these potentially important energy resources.

3

North Carolina Takes a Step Closer to Shale Gas Production

4

Conclusion Although the recent legislation does not legalize hydraulic fracturing in North Carolina, it moves the state significantly closer to shale gas development and sets a path for a regulatory framework for horizontal drilling and hydraulic fracturing. All of the legal, environmental, and policy issues associated with this resource will be debated in the next two years in North Carolina. K&L Gates LLP has vast experience assisting natural gas developers in Texas and has led the way on important legal issues in Pennsylvania and throughout the Marcellus Shale. As such, we are uniquely qualified to assist with the environmental, legal, regulatory, and policy issues related to the potential development of shale gas in North Carolina.

Authors:

Stanford D. Baird stanford.baird@klgates.com 919.743.7334

James L. Joyce jim.joyce@klgates.com 919.743.7336

July 6, 2011

Oil & Gas

The Chesapeake Bay Foundation Settlement – Changing Directions for E&S Regulation of Oil & Gas ProjectsOn July 1, the Chesapeake Bay Foundation (“CBF”), Pennsylvania Department of Environmental Protection (“DEP”) and two natural gas operators filed a stipulation of settlement with the Environmental Hearing Board (“EHB”) concluding CBF’s broadside challenge to DEP’s erosion and sedimentation (“E&S”) control program for the oil and gas industry.[1]  While preserving many essential elements of the current general permit program, the settlement proposes some significant program modifications that will be rolled out in the form of a proposed replacement “ESCGP-2” general permit, prioritized preconstruction meeting and inspection procedures, and proposed policies governing pit and tank siting.  All involved in oil and gas development and operations have an important stake in understanding and shaping these changes in the DEP E&S management program.

BackgroundIn April 2008, DEP adopted the current general permit ESCGP-1 for regulating erosion and sedimentation from earthmoving activities associated with oil and gas projects.  After considerable discussion with the industry, in March 2009, DEP announced a revised process that included an "expedited" review program for the review of E&S plans for oil and gas projects.  Under the expedited program, expedited reviews are provided for E&S plans prepared and certified by licensed professionals who have participated in training conducted by DEP.  Projects eligible for expedited review were originally subject only to review for administrative completeness, with DEP relying on the professional's certification as to substantive compliance. 

In the fall of 2009, CBF – an environmental organization focused on issues relating to nutrient and sediment loadings affecting the Chesapeake Bay – filed a series of appeals with the EHB challenging DEP’s approvals issued respectively to Talisman Energy USA and Ultra Resources for various well pad development and gas pipeline projects in Tioga and Bradford County, PA.  The CBF appeals encompassed a broadside attack on the DEP program, ultimately seeking imposition of full NPDES permitting requirements.  Among other claims, CBF asserted that:

DEP’s general permit program was improperly established and not authorized by regulation (an issue that has since been addressed by recently adopted amendments to Ch. 102). DEP’s March 18, 2009 memo and revisions to forms allowing expedited approvals constituted rulemaking without following the required regulatory process. DEP approved E&S plans without substantive review (citing cases decided under the Federal Clean Water Act requiring substantive review of both individual and general permit applications). Issuance of ESCGP-1 for an entire project area was improper without prior review of plans (e.g., attacking phased approach). The submitted plans failed to meet minimum standards for E&S control. The plans failed to address adequately post-construction stormwater management. DEP failed to follow public participation requirements for NPDES permits. DEP failed to conduct antidegradation analysis as applied to HQ and EV streams. DEP’s approvals allowed encroachments in EV wetlands.

 

 

DEP failed to consider cumulative impacts.

After the appeals were filed, DEP reviewed the challenged ESCGP-1 permits, and ultimately rescinded those approvals because of alleged deficiencies in the original E&S plans.  Most of the projects were subsequently repermitted after submission of revised plans.  However, the CBF appeal challenging the underlying program remained.  Over the ensuing months, DEP and the industry parties (supported by a task force of representatives from a variety of operators) undertook negotiations seeking to find, if possible, a settlement that would address these challenges, while preserving the basic general permit program and a reasonably expeditious process for most projects.

Elements of the SettlementSince the filing of the CBF appeals in 2009, a number of changes have occurred in the regulatory landscape.  First, in August, 2010, the Environmental Quality Board adopted a revised set of E&S regulations, codified at 25 Pa. Code Ch. 102.[2]  Among other rule changes, the new Ch. 102 rules explicitly provide for oil and gas projects involving earth disturbance greater than five (5) acres to obtain a state E&S permit,[3] and also explicitly authorize DEP to issue general permits[4] (such as the ESCGP for oil and gas activities).

The Stipulation of Settlement filed on July 1 sets in motion further changes to the manner in which DEP implements these rules (although some of these changes have already started to be implemented in the field).  Under the settlement:

1. New ESCGP-2. DEP will propose an amended E&S general permit for the oil and gas industry (“ESCGP-2”), providing a 60-day public comment period.  The ESCGP-2 will embrace a revised expedited review procedure for most projects, exclude some types of projects from expedited review, and explicitly authorize a phased permit process for large, multi-step projects.

2. Projects Not Eligible for Expedited Review. Under the revised ESCGP-2, certain projects will be excluded from expedited review, including: (a) projects located in high quality or exceptional value waters; (b) projects in which the well pad will be constructed in or on a floodplain; and (c) earth disturbance activities on land that are “known to be contaminated” by the release of a “regulated substance” as defined under Section 103 of Act 2.

The HQ and EV watershed exclusion from expedited review is likely to have the most significant impact, as an increasing number of well and pipeline projects across the northern tier of Pennsylvania are encountering such special protection waters.

The “well pad” in floodplain exception only applies to a project where the well pad (excluding roads, pipelines, and facilities for fresh water withdrawal, storage and conveyance) is to be located in a floodplain.  The term “floodplain” is defined to be those areas inundated by a 100-year frequency flood.  Where FEMA floodplain maps are available, that will define the floodplain.  In unmapped areas, there is a rebuttable assumption that the floodplain extends 100 feet horizontally from a perennial stream or 50 feet from an intermittent stream.

The “known to be contaminated” exception is intended to apply to situations where existing contamination is already known, and does not mandate that project sponsors undertake “Phase 2” sampling of sites to determine whether or not regulated substances have been released.

3. Expedited Review Process.  An expedited review process would be retained and accorded to most projects where their E&S plans are prepared and certified by professionals (engineers, surveyors, geologists, or landscape architects) licensed in Pennsylvania.  The professional’s seal must be placed on each plan drawing and on the narrative cover.  The timeframe for expedited review would remain

The Chesapeake Bay Foundation Settlement – Changing Directions for E&S Regulation of Oil & Gas Projects

Page 2

14 business days following submission of a notice of intent (“NOI”) for coverage under ESCGP-2.  The one significant departure from the original expedited review procedures, however, would be the type of review accorded to such plans.  Technical staff (rather than administrative staff) would conduct reviews of ESCGP submissions; and the review would be to determine whether the submission is “complete and acceptable” not just “administrative completeness.” 

4. Timeframe for Regular Process Reviews. As noted above, DEP commits to review projects subject to the expedited process within 14 business days following submission of a complete NOI.  For those projects not eligible for expedited review, the settlement calls for DEP to establish as its objective to complete review of submissions within 60 calendar days.

5. Guidelines and Checklists for Oil & Gas Projects.  Concurrent with DEP’s solicitation of comments on the modified ESCGP general permit, the settlement provides for the development of revised checklists and guidelines for review of both expedited and regular projects.  DEP will convene a stakeholders group, composed of representatives from the agency, industry and CBF, to assist in developing such checklists and guidelines.  Once completed, the draft guidelines and checklists will be published for public review and comment, with a minimum 60-day public comment period.

6. Submission Requirements for Special Project Categories. For those projects located in HQ and EV waters, involving well pads in floodplains, or involving known contaminated lands, the new ESCGP will require that E&S plans be prepared and certified by licensed professionals.

7. Phased Permits.  Although CBF originally challenged the entire concept of phased permits, the settlement explicitly allows phased submissions.  Reflecting existing practice, DEP will require that for “phased plans,” the applicant submit a master site plan with the initial application, and then each subsequent phased plan would have a “check list.”  For each subsequent phase, a Pennsylvania Bulletin notice of phase plan approval would be published to set a clear benchmark for any appeals.

8. Preconstruction Meetings.The new 25 Pa. Code §103.5(e) provides for preconstruction meetings for earth disturbance projects unless the permittee has been notified otherwise in writing by DEP.  This requirement is reflected in the settlement, which calls for such preconstruction meetings for oil and gas projects covered by the ESCGP unless DEP provides a notice waiving such a meeting.  Operators must invite DEP to attend such a meeting by providing a notice at least 7 days in advance.  If such notice is provided and a preconstruction meeting is held, but DEP does not attend, the ESCGP-covered project can proceed.  The settlement stipulation establishes priorities for holding such preconstruction meetings, with emphasis placed on sensitive watersheds, areas with highly erodable soils, steep slopes, special geologic risks, floodplains, contaminated lands, and projects conducted by persons with continuing Ch. 102 violations.

9. Inspection Priorities.  Under  the settlement, DEP will monitor and inspect regulated E&S activities associated with oil and gas projects on a routine basis, with inspection frequency based on various factors, including resource availability, project complexity, presence of sensitive resources, continuing violations, and whether DEP has conducted a preconstruction meeting.

10. Tanks, Pits and Impoundments.  DEP will propose a policy regarding its “interpretation” of Section 205(b) of the Oil and Gas Act, the provision that sets a 100 foot setback for well sites from streams and other bodies of water subject to potential waivers. DEP will provide for a 60-day public comment period on this policy statement.  Under DEP’s proposed policy, a well site will not be eligible for a waiver to be closer than 100 feet from a water body if it will have (1) a pit containing cuttings, flowback or produced water, or waste within the floodplain; (2) tanks containing condensate, flowback or produced water within the floodway; or (3) tanks containing condensate,

The Chesapeake Bay Foundation Settlement – Changing Directions for E&S Regulation of Oil & Gas Projects

Page 3

flowback or produced water in the flood fringe, unless adequately floodproofed.  The draft policy is intended to address concerns about storage of wastes within flood prone areas, and provides a clear differentiation between pits and tanks, and between the risks posed in floodway and flood fringe areas.

What’s next? The settlement reflects a step along the process, not an end in itself.  Although the negotiations embraced efforts that included the immediate industry parties (Ultra and Talisman), drawing upon advice from a task force of representatives from various natural gas operators, the settlement calls for subsequent solicitation of public comments.  The CBF settlement stipulation reflects compromises on key concepts, but those concepts will be fleshed out in the proposals that soon will be forthcoming from DEP and subject to stakeholder comment.  Careful review and input from across the broad cross-section of the industry is essential to assure that the final ESCGP and associated policies, guidelines and checklists are understandable, reasonable and workable. 

Notes:[1] The Chesapeake Bay Foundation, Inc. and Ultra Resources, Inc. v. Department of Environmental Protection, et al., EHB Docket No. 2009-116-L (Consolidated), Joint Motion to Dismiss and Stipulation of Settlement (filed July 1, 2011), available at: http://ehb.courtapps.com/efile/documentViewer.php?documentID=10037.

[2] 40 Pa. Bulletin 4861 (August 20, 2011) (effective November 19, 2010).

[3] 25 Pa. Code §102.5(c).

[4] 25 Pa. Code §102.5(m)

R. Timothy Westontim.weston@klgates.com

P +1.717.231.4504

The Chesapeake Bay Foundation Settlement – Changing Directions for E&S Regulation of Oil & Gas Projects

Page 4

July 1, 2011

Oil & Gas

Energy & Utilities

Why the Public Utility Commission's Laser Northeast Decision Will Not Lead to Regulation of All Natural Gas Gathering and Transportation Pipelines in PennsylvaniaOn June 14, 2011, the Pennsylvania Public Utility Commission ("Commission") entered an order in the Laser Northeast case,[1] which indicates that under certain circumstances some natural gas gathering systems might qualify as a public utility.  What is equally clear from the Commission's order, however, is that not all gathering and transportation systems will qualify as public utilities providing service to the public.  The Commission's order remands Laser Northeast's application to an administrative law judge ("ALJ") to decide several issues including whether the issuance of a certificate of public convenience to Laser Northeast would be in the public interest. 

As a result of the Commission's decision, many have raised the question of whether all midstream gathering or transportation services now qualify as public utility service subject to the Commission's jurisdiction.  The answer is no.  A close reading of the decision indicates that the Commission’s jurisdiction over any gathering and transportation pipeline will turn on the facts surrounding each pipeline's operation and the composition of its customers.  The Laser Northeast case reflects the unique characteristics of the service proposed by the Applicant.  That service is likely different from the gathering and transportation service being provided by existing midstream operators in Pennsylvania.

The Laser Northeast ApplicationOn January 19, 2010, Laser Northeast filed an application to supply natural gas gathering and transporting or conveying service by pipeline to the public in certain townships of Susquehanna County, Pennsylvania for compensation.  The application proposed the construction of a gathering and transportation system incorporating a "backbone style" gathering system spanning 33 miles (24 miles in Pennsylvania and 9 miles in New York) with up to six lateral lines ranging in length from approximately one to six miles each.  The system would consist of approximately 178,000 feet of 16" diameter steel pipe with an additional 32,000 feet of 10" or 12" diameter or smaller laterals spanning five townships in Susquehanna County, Pennsylvania and extending into Broome County, New York, to tie in with the Millennium Pipeline.  The Laser Northeast gathering and transportation system would provide gathering and transportation service to natural gas producers in eight townships of Susquehanna County.  The service would be provided to unaffiliated natural gas producers which had entered into gathering and transportation agreements with Laser Northeast.  Laser Northeast would not hold title to the gas moved through its facilities nor engage in marketing of the gas or provide direct sales from its gathering and transportation system before delivery into interstate facilities.  In March 2010, the FERC issued a declaratory order that the Laser Northeast pipeline system will perform a gathering function exempt from the FERC's jurisdiction under Section 1(b) of the Natural Gas Act, 15 U.S.C. § 717(b) (2006).[2]   Following hearings, a Commission ALJ issued a Recommended Decision denying Laser Northeast's application on the basis that the gathering and transportation service was not being provided to the public and therefore did not constitute public utility service under the Public Utility Code.  The ALJ also recommended

 

 

disapproval of a non-unanimous settlement between Laser Northeast, the Commission's Office of Trial Staff and several protestants.  Exceptions or reply exceptions were filed by all of the case parties.

The Commission's DecisionThe Commission disagreed with the ALJ's conclusion that the service proposed by Laser Northeast was not "for the public" and therefore Laser Northeast could not be a public utility.  Under the Commission’s analysis, a natural gas midstream company such as Laser Northeast would qualify as a public utility if it was transporting or conveying natural gas by pipeline or conduit "to or for the public for compensation."[3]  In considering the issue of whether service would be provided for the public, the Commission applied established Pennsylvania court decisions and a previously adopted Commission Statement of Policy containing guidelines for determining public utility status.[4]  Citing Pennsylvania case law, the Commission stated that the test for determining whether a provider’s services are being offered for the public is whether or not a person holds himself out, expressly or impliedly, as engaged in the business of providing his product or service to the public, as a class, or to any limited portion of it, as distinguished from holding himself out as serving or ready to serve only particular individuals.[5]  Citing Laser Northeast's testimony that it would serve any customer in the service area requiring gathering or transportation of gas on its system to the extent capacity exists, the Commission concluded that the natural gas gathering and transportation service proposed by Laser Northeast's operations was intended to provide service to or for the public and therefore did meet the definition of public utility service.  The Commission returned the case to the ALJ to determine whether granting a certificate of public convenience to Laser Northeast to provide the gathering and transportation service was necessary or proper for the service, accommodation, convenience or safety of the public as required by the Public Utility Code.[6]  The Commission also identified several issues concerning Laser Northeast's proposed service and the partial settlement to be examined in additional hearings. 

Impacts of the Laser Northeast DecisionThe Laser Northeast decision does not imply that all gathering companies will require certificates from the Commission.  Although the Commission decided that natural gas gathering and transportation service can meet the definition of public utility service, it also noted that not all gathering and transportation service providers would be considered public utilities subject to the Commission’s jurisdiction.  The order states “[w]hether the Commission will approve an application from a pipeline and issue a certificate of public convenience for the pipeline to be a public utility turns on the specific facts surrounding each pipeline operations, including whether the gathering and transportation services are offered for the public.”  (Order at 28.)  Applying the analysis employed in the Laser Northeast decision, the facts that the Commission would examine in determining whether a natural gas gathering and transportation pipeline met the definition of public utility would be the composition of the pipeline’s customers and how they were selected, and the design of the facility used to provide the gathering and transportation service. 

In determining that the proposed operations of Laser Northeast met the definition of public utility service, the Commission relied not only on the traditional Pennsylvania case law definitions of service to the public,[7] but also considered its Policy Statement at 52 Pa. Code § 69.1401, which identifies the guidelines the Commission will rely upon in determining public utility status.  Those guidelines state that the Commission will consider the status of the utility project or service based on the specific facts of the project’s proposed operations, taking into consideration the following criteria in formulating its decision:

(1) whether the facility is designed or constructed only to serve a specific group of individuals or entities, and others cannot feasibly be served without a significant revision to the project, and

Why the Public Utility Commission's Laser Northeast Decision Will Not Lead to Regulation of All Natural Gas Gathering and

Page 2

(2) whether the service provided is to a single customer or to a defined, privileged and limited group of customers where the provider reserves the choice to select the customers by contractual agreement so that no one among the public, outside of the select group, is privileged to demand service.  62 Pa. Code § 69.1401(c).  Under these guidelines, if either condition is met, then the facility is not providing public utility service. 

Avoiding Regulation as a Public UtilityFollowing the guidelines contained in the Commission’s Policy Statement, the owner of a natural gas gathering and transportation pipeline could avoid regulation as a public utility through the design of its facilities and by a method of identifying and selecting its customers which limits them to a select group.  If the gathering facility is designed and constructed only to serve a single customer or a limited group of customers, and additional customers could not be feasibly served without a significant revision to the facility, these characteristics would support a determination that the facility was constructed to serve only specific individuals and not the general public and was not designed to be a public utility facility.  If the method of selection of the pipeline’s customers is designed to limit the customers to a defined and privileged group selected by the service provider by contractual arrangement and service is limited to this selected group, the described practice of selecting customers would support a determination that the pipeline was not serving the public, but only a defined and privileged group of customers and therefore was not a public utility.  If these practices were followed, the pipeline would not qualify as a public utility under Pennsylvania case law or the Commission’s guidelines. 

In contrast, the evidence produced by Laser Northeast in its application supported the Commission’s determination that it would qualify as a public utility service.  Laser Northeast testified that it was prepared to provide gathering and transportation service to all producers in the service area that requested it to the extent the pipeline had capacity.  The design of the Laser Northeast pipeline incorporated several lateral lines ranging in length from one to six miles and demonstrated an intention to provide service to multiple producers in several locations.  Under the Commission’s guidelines, the facility qualified as a public utility. 

ConclusionThe Commission’s Laser Northeast decision is unlikely to lead to the regulation of all gathering pipelines in Pennsylvania.  The characteristics of the service proposed by the Applicant are different from the service provided by existing midstream gathering and transportation pipelines whose facilities are designed to serve specific groups of providers and whose customers are selected by the service providers by contractual agreement.  The decision follows traditional Pennsylvania case law in determining whether a facility is providing public utility service and also relies upon specific guidelines issued as a Policy Statement by the Commission.  The case law and Policy Statement require that a facility be serving the public, or a limited portion of it, before it will be considered a public utility subject to the jurisdiction of the Public Utility Commission.  The operator of a gathering and transportation pipeline can avoid regulation as a public utility if it designs its system to serve specific customers and not the public, and it reserves the right to select its customers by contractual arrangement, and the customers are limited to a defined, privileged and limited group.  The criteria used by the Commission in its decision are well defined and can guide a pipeline operator in avoiding being designated a public utility.

Notes:[1] Commission Dkt. A-2010-2153371, available at the Commission website at www.puc.state.pa.us. 

[2] In re Laser Marcellus Gathering Company LLC, 130 FERC ¶ 61,162 (2010).

Why the Public Utility Commission's Laser Northeast Decision Will Not Lead to Regulation of All Natural Gas Gathering and

Page 3

[3] Section 102(1)(v) of the Public Utility Code, 66 Pa. C.S. § 102(1)(v), defines a public utility to include a person or corporation transporting or conveying natural gas by pipeline or conduit for the public for compensation.

[4] Section 69.1401 of the Commission's regulations, 52 Pa. Code § 69.1401.

[5] Drexelbrook Associates v. Pennsylvania Public Utility Commission, 418 Pa. 430, 435, 212 A.2d 237, 239 (Pa. 1965); Borough of Ambridge v. Public Service Commission, 108 Pa. Super. 298, 165 A.47 (1933); Waltman v. Pennsylvania Public Utility Commission, 596 A.2d 1221, 1223-4 (Pa. Cmwlth Ct. 1991).

[6] Section 1103(a) of the Public Utility Code, 66 Pa. C.S. § 1103(a), requires the Commission, prior to issuing a certificate of public convenience, to find or determine that the granting of the certificate is necessary or proper for the service, accommodation, convenience, or safety of the public.  The ALJ did not address this issue in the Recommended Decision. 

[7] See Pennsylvania cases cited in footnote 5 and discussion in the Commission Order at 23-8.

Daniel P. Delaneydan.delaney@klgates.com

P +1.717.231.4516

Why the Public Utility Commission's Laser Northeast Decision Will Not Lead to Regulation of All Natural Gas Gathering and

Page 4

Highlighting developments and issues in the international oil and gas industry

OnStreamThe Arab Spring: Insurance Coverage For Losses Arising From Political Change In The Middle East And North Africa The wave of popular uprisings across the Middle East and North Africa - the “Arab Spring”-

has been a catalyst for political reform in several countries. These developments are causing

Oil & Gas companies with operations and other interests in the region to take a fresh look at

their exposure to business risks associated with political discontinuities in these markets.

There are likely to be several insurance policies which may respond to provide policyholders

with fi nancial support during this challenging time, but assessing how various exposures

could fall for coverage under different policies may not be a straight-forward task.

Undertaking this assessment, and taking action to access responsive cover, should be a

priority in the overall risk management response to events in the region, particularly as most

insurance policies require that insurers are given timely notice of actual or potential losses.

Risk exposures for Oil & Gas policyholders in the region

Key exposures are likely to include:

• Loss or damage to physical assets due to strikes, riots and civil unrest, looting, sabotage

and terrorism as well as the consequences of civil war in some territories

• Business interruption losses including consequential losses following damage to assets,

absence of employees expatriated to their home countries, strikes by local workers and

unavailability of pipelines, ports and transportation routes

• Supply chain diffi culties

• Contractual risk, including contract frustration, repudiation or renegotiation, particularly

where major natural resource contracts have been placed with governments in countries

subject to regime change

• Government expropriation of assets

• Currency incontrovertibility and transfer risk, in addition to late payments impairing

cash-fl ow

Summer 2011

Welcome to the fi rst edition of

“OnStream”, K&L Gates’ new

publication for the international oil

and gas industry, highlighting industry

developments and issues touching on

the development of projects around the

world’s major hydrocarbon basins.

In this issue we cover the following topics:Political Risks: Insurance Coverage ... 1

Offshore Environmental Damage

Insurance ...................................... 2

EIA Study: Shale Gas Resources....... 3

LSE-TMX stock exchange merger: a

new era in fundraisings? ................. 4

Recent Developments ...................... 7

K&L Gates LLP

One New Change

London EC4M 9AF

www.klgates.com

T: +44 (0)20 7648 9000

F: +44 (0)20 7648 9001

Continued on page 5

2 OnStream

Neal Brendel and Michael Miguel of K&L

Gates discuss how recent high profi le

offshore energy disasters and judicial

scrutiny have affected insurance coverage

for offshore pollution claims

The offshore exploration and production

energy sector is particularly susceptible

to natural and operational losses that are

catastrophic in nature. Since the mid-1980s,

the standard “energy package” insurance

policy has provided separate coverage for

damages caused by pollution, but it was

a windfall for the insurance industry in as

much as premiums were paid, but claims

generally were not. Now, recent attention

brought on by signifi cant weather events

and high profi le accidents, improvements in

technology and judicial scrutiny has resulted

in insurers acknowledging and indemnifying

offshore environmental damages.

For decades, the insurance industry has

required strict proof that the oil detected

in the ocean or sub-sea soils, even after

a blowout, emanated from an assureds’

covered well. The existence of naturally

occurring seeps, and the high cost of

technology required to prove the source

of the oil, historically resulted in insurers

escaping responsibility for policy payments

for pollution. New affordable technology

means that now an assured is able to satisfy

the insurers’ strict burden of establishing the

source of pollution. The effectiveness of this

new technology was made evident to anyone

with an Internet connection in 2010 who

watched with fascination as the Deepwater

Horizon well in the Gulf of Mexico

discharged oil on a continuous live feed.

The Deepwater Horizon accident had the

effect of heightening public sensitivities

globally to offshore pollution damage. In

the United States, the timing of the disaster

coincided with the maturing of coverage

suits over claims arising from Hurricanes

Ivan and Katrina. Decisions were issued

compelling the fi rst publicly known payments

of full limits of liability by insurers for

offshore pollution, including regulatory

liabilities arising from offshore pollution,

such as the Oil Pollution Act of 1990 (OPA

’90). Indeed, 2010 was a pivotal year

for assureds, as courts found that certain

routinely asserted defenses to coverage

would no longer insulate insurers from

coverage liability or bad-faith claims.

The policy language

Since the mid-1980s, energy package

policies have included, as part of “control of

well” coverage, separate grants protecting

the assured from damages arising from

“seepage and pollution, cleanup and

contamination.” These provisions provide

broad coverage for legal liabilities

(including lease obligations) for the cost of

remedial measures undertaken to address

pollution, and specifi cally include the cost of

or “any attempt at” removing, nullifying or

cleaning up the pollution. These provisions are

found in the standard form Energy Exploration

and Development (EED) form coverage, issued

for use in the London market and now found

in some form in energy package policies

throughout the world.

Many of the crucial terms in the seepage

and pollution grants of coverage, such

as what constitutes a “legal liability” or

“remedial measure,” or what constitutes

an “attempt to nullify” pollution, are

undefi ned. Under the usual rules of contract

construction, these terms should be given

their ordinary meaning or be construed in

favor of the assured, since they are found in

the insurer’s standard-form agreement.

Historical insurer response

The traditional response from the insurance

industry has been to deny coverage for

offshore pollution claims, placing the onus

on the assured to demonstrate that the

offshore pollution originates from a covered

well. The cost of proving the source of

pollution, especially in a deepwater well,

has historically been prohibitive. Recent

technological innovations now make it

easier, and less costly, to deploy remote

operated vehicles that can identify the

location of pollution and assist in tying it

Offshore Environmental Damage Insurance: Not Just Window Dressing Any More

Continued on page 6

Summer 2011 3

Shale gas is being viewed as an

increasingly important source of future

energy, particularly in the US, and

the Energy Information Agency (“EIA”)

sponsored study, ‘World Shale Gas

Resources: An Initial Assessment of 14

Regions Outside the United States’, released

on 5 April 2011, reported that the initial

assessments of 48 shale gas basins in 32

countries suggested that, globally, there is

an estimated 6,622 trillion cubic feet of

shale gas available for use.

Shale gas, as the name suggests is natural

gas produced from shale, as distinct from

gas associated with oil, or gas captured

in tight sands. Traditionally, shale has

been seen as insuffi ciently permeable for

commercial extraction however, recent

technical advances have seen shale gas

along with other unconventional plays such

as coal seam methane become genuine

commercial prospects.

The EIA study reports that it is expected

that by 2035, 46 per cent of all natural

gas production in the US will be shale

gas. Other countries around the world are

just beginning to discover their shale gas

resources and the opportunities to use this

relatively new source of energy.

Countries identifi ed in the study as having

signifi cant shale gas resources included

France, Poland, Turkey, Ukraine, South

Africa, Morocco, Chile, Canada, Mexico,

China, Australia, Libya, Algeria, Argentina

and Brazil. The estimates given in the EIA

study may be conservative, as the study did

not include a number of countries which

may have additional shale gas resources

such as Russia and countries in the Middle

East region. Neither did the study consider

potential offshore resources.

For further information please contact

Laura Atherton (laura.atherton@klgates.com).

EIA Study: Shale Gas Resources

4 OnStream

LSE-TMX Merger – A New Era In Fundraisings For Oil & Gas Companies?

In February 2011 London Stock Exchange

Group plc (LSE) announced its proposed

£4.3 billion merger with TMX Group

Inc. (TMX), the operator of the Toronto

Stock Exchange, in a deal that may have

signifi cant implications for the fi nancing of

natural resources companies in the years to

come. The transaction remains subject to

shareholder and regulatory approvals in both

Canada and the UK and, assuming those

approvals are forthcoming, is expected to

close in the second half of 2011.

Commentators are divided on the reasons for

and merits of the proposed merger, but there

is overwhelming agreement that it is positive

news for oil and gas and other natural

resources companies. The merged group

would constitute the world’s largest exchange

for natural resources and mining companies

with more than 6,700 companies listed on

its exchanges together having a combined

market capital of £3.7 trillion.

The merged group would be joint-

headquartered in London and Toronto and

would operate six equities listing venues

in Canada, the UK and Italy, catering to

issuers of all types and sizes. TMX and LSE

believe the merged group is well placed to

become the primary listing venue for small

and medium sized enterprises with LSE’s AIM

market and TMX’s TSX Venture Exchange

together comprising some 3,600 small to

medium cap and early stage companies.

On announcing the merger Xavier Rolet,

CEO of LSE and the intended CEO of the

merged group said, “We are creating

the world’s largest listings venue for the

commodities, energy and natural resources

sectors as well as a premium market for

small, mid-sized and growth companies.

This new international leader… will be

strongly positioned to capitalise on growth

opportunities in emerging markets and

deliver them to our customers in North

America, Europe and beyond.”

TMX, together with Canada’s banking, legal

and mining communities, have for years

been promoting Toronto as a global centre

for natural resources fi nancing and LSE has

itself long been recognised as a powerhouse

in oil, gas and mining listings. The merged

group is expected to offer unrivalled

experience in dealing with natural resources

companies and be the obvious place to look

for investors interested in the sector.

The proposed merger has attracted a lot

of media attention against a back drop of

soaring commodity prices. The surge in oil,

metal and agricultural commodity prices has

greatly increased the value of the natural

resources sector on global exchanges in

recent years, with oil, gas and mining

companies now accounting for more than

12.5% of the FTSE All-World Index, up from

less than 6% in 2000.

Companies listed on the merged group’s

exchanges are expected to benefit from

improved access to a deeper and more

flexible pool of international capital. Dual

listings are expected to become easier

and more commonplace with companies

listed in London benefiting from improved

access to European and the Middle

Eastern capital and companies listed in

Canada benefiting from improved access

to capital from North America.

For further information please contact Jeremy

Landau (jeremy.landau@klgates.com) or Oliver

Pilkington (oliver.pilkington@klgates.com).

Summer 2011 5

continued from page 1

The Arab Spring: Insurance Coverage For Losses Arising From Political Change In The Middle East And North Africa

Which insurance policies may respond?

Most energy companies carry a portfolio of

insurance policies which may cover financial

losses arising from one or more of these

risks. Potentially responsive policies include:

Onshore/offshore property policies: These

principally cover damage to physical

assets. Business interruption coverage is

usually blended in to provide cover for loss

of revenue and other costs consequent to

property damage. These policies may state

that they are written on an “All Risks” basis,

however certain risks may be excluded from

coverage (such as political unrest, terrorism

and war).

Contingent business interruption insurance:

This can be included as an extension to the

main policy or coverage can be provided

by a stand-alone policy, and applies where

the ability of the policyholder to trade is

impaired by external considerations such

as damage to third party property, loss of

utilities, denial of access and political acts

of local governments and regulators.

Property terrorism: Where available, this

stand-alone coverage may be appropriate

where terrorism risks are excluded from

the main property policy. The definition of

terrorism varies for each policy and insurers

are likely to debate whether particular

events qualify as acts of terrorism,

especially where damage was caused by

insurgents who are now represented by

new governments.

Political risks insurance: These policies

potentially respond where there has been

some form of interference with an asset or

an investment which is politically motivated.

Coverage can include most of the risk

exposures identified above.

Supply chain disruption insurance: This

cover is designed to protect companies

whose operations rely on critical supplies

of goods or raw materials. Coverage can

include loss of supplier, stoppage of supply

or delay in delivery due to political risks,

terrorism, strikes and other forms of civil

unrest as well as transport difficulties.

Accessing cover

Insurance policies usually contain a

number of pre-conditions to recovery. Key

considerations when accessing cover include:

• Notification: A common feature of

insurance policies is a requirement to

give notice of actual or potential losses

within a certain period of time. Prompt

notification of claims is essential as

failure to comply with the notification

provisions of relevant policies may

enable insurers to restrict or deny cover.

• Proof of loss: First party loss policies

typically require the policyholder

to submit a formal presentation of

the claim and relevant underlying

documentation (known as a Proof

of Loss) within a certain time period

following notification. Care needs to

be taken to preserve documents and to

document losses so as to substantiate

the insurance claim.

• 72 hour occurrence clauses: First party

loss policies covering war, riots and

other forms of civil unrest normally

contain an aggregating provision by

which all losses occurring from these

perils within a certain period of time

(usually 72 hours) are treated as one

loss or occurrence in applying the

policy limits and deductibles. The

wording of such clauses may require

careful consideration when presenting

claims to insurers.

• Waiting periods: Many policies also

incorporate language which provides

that certain aspects of coverage only

become available after a defined

period of time (or waiting period) has

elapsed. The period varies for each

policy and can range from a few days

for business interruption cover to as

long as 180 days for some political risk

policies. Policyholders must take care

to ensure that they observe other terms

of the policy during the waiting period,

such as “due diligence” clauses which

require the insured to take all reasonable

precautions to minimize a potential loss

and to keep insurers informed.

In conclusion, policyholders are well

advised to review the terms of any

potentially applicable insurance policies

as soon as possible if business has been

impeded by recent events. If a claimable

loss event occurs, a policyholder should

devote sufficient resources, both internally

and externally, to preserve their ability to

advance a claim against relevant insurers.

For more information on the issues covered

in this article, please contact Frank

Thompson in K&L Gates’ London office

(frank.thompson@klgates.com).

6 OnStream

continued from page 2

Offshore Environmental Damage Insurance: Not Just Window Dressing Any More

back to a well (remember that the location

where pollution is found is often nowhere

near a wellhead, since the point source of

the pollution may be hundreds of feet below

the ocean floor and the migrating oil seeks

the path of least resistance to the surface).

Even after the assured proves the pollution

originates from a covered well, the insurers

often seek to impose further impediments

to coverage. Their arguments take three

generic forms:

(i) “Indemnity policies cover only ‘damages’

not investigation or preventative activities.”

An indemnity insurance policy is meant

to cover damage, not the prevention of

damage. As a result, the assured is not

covered for efforts undertaken to identify

or prevent the pollution before it causes

damage. Using this argument, an insurer

would agree to pay, for example, for a

containment dome to capture oil seeping

into the ocean from a well, but would

not pay for any effort to intervene in any

effort to control or stop the source of the

contamination. Seeking to control the

source of pollution through an “intervention

well” would be categorised as “relief well”

technology, which is exclusively covered

elsewhere and is not pollution control.

In contrast, an assured would argue that

the policy covers its legal obligations

with respect to the identified pollution,

in whatever form those obligations are

manifest. In other words, the legal obligation

is not limited to simply responding to the

pollution once it occurs, but also includes

identifying and controlling the source of

such pollution. Regulators would demand

that the assured both minimizes the ongoing

damage, for example, with a containment

dome, and that the assured locate and stop

the source of the pollution. Further support

for the assureds’ point of view can be found

in policy language that specifically covers

“efforts ... to nullify” the pollution. Certainly

source identification and mitigation would

appear to fall within the plain meaning of

such terms, although historically the insurers

have contested such interpretations.

(ii) “All you really are doing is simple plug

and abandon activities.” An operator

has an obligation, at the end of a lease,

to plug and abandon (P&A) its wells.

Insurers would argue that any effort to stop

pollution from a well by intervening and

plugging it to prevent ongoing pollution is

a mere discharge of the assureds’ lease-

end obligations to P&A, and not related to

pollution control. In contrast, assureds argue

that a policy covering “remedial measures”

would include efforts to intervene in an

out-of-control well. If the insurer wished to

exclude such activities, it was free to do so

by plain and unambiguous policy language

in its standard form.

(iii) “We never intended to cover such

activities.” Probably the most surprising

response from insurers and underwriters has

been the assertion that the EED form was

never intended to cover P&A activities, relief

wells, or to cover preventative measures.

A plain reading of the policy would not

support this conclusion.

Court rulings favouring the assured

In 2010, the United States Federal Court for

the Western District of Louisiana considered

many of these arguments and ruled

resoundingly for the assured and in favour of

coverage in Taylor Energy Company LLC. v.

Underwriters at Lloyd’s (2010 WL 4553482

(W.D. La.)). In Taylor, an offshore production

facility, with 28 operating wells, was toppled

and destroyed by wind and a sub-sea

mudslide caused by Hurricane Ivan. The

facility was deemed a total loss. The U.S.

government issued orders requiring that the

assured investigate the extent of the damage,

control the source, and remedy the pollution

entering the Gulf of Mexico. In addition,

the operator was required to post a bond

of several hundred million dollars to ensure

compliance with the government directives.

Underwriters (over a period of years)

acknowledged coverage and paid limits

under every grant of coverage in the EED

package, save the seepage and pollution

coverage, where they denied coverage

and asserted each of the three arguments

set out above. On the issue of coverage,

the Louisiana federal court decided that the

disputed terms in the insuring agreement

“are unambiguous and provide coverage,”

further stating that the insurers’ interpretation

of its own policy language was “strained

and unsupported by the plain language of

the policy.” Specifically, the Court focused

on the legal obligations of the assured set

forth in the various governmental directives,

which required the assured to take all

necessary actions to “remove the discharge

or to mitigate or prevent the threat of such

discharge.” Also of importance to the

Court was the plain meaning of “remedial

measures,” where the Court adopted a

common sense approach stating that “[t]

he primary remedial measure or corrective

action for seepage is to stop the seepage.”

Lastly, the Court refused to accept any

Summer 2011 7

argument that underwriters had a good-

faith basis for denying coverage, finding

that “coverage is clearly provided by

the Policy” and consequently allowed

the assured’s bad faith claim to stand. A

settlement was reported to the Court one

day after the opinion on coverage was

issued (terms confidential). Consideration

of these issues by the Louisiana federal

court marks the first known instance where

a court has found coverage and required

payment under both seepage and

pollution and OPA ’90 coverage parts.

What Does This Mean?

The combined influence of recent favourable

decisions for assureds, and more affordable

source detection technology now mean

that claims for pollution coverage in energy

package policies have become a more

viable avenue for asset recoveries in the

unfortunate event of catastrophic loss –

whether induced by nature or human events.

Warning: political risks excluded from coverage

A significant percentage of the world’s oil

and gas reserves are located in regions

that can be characterised as unstable

political environments. This instability

raises the prospect of interruption or

damage to offshore operations, which

may result in pollution. Unfortunately,

the standard EED wordings specifically

excludes coverage for loss, damage or

expense resulting from “war terrorist”

activities, which include (inter alia)

insurrection, rebellion, revolution, civil war,

usurped power, or action by governmental

authority, seizure or confiscation.

However, almost every insurer servicing

the exploration and production sector

offers to “complement” its energy

package policies with some form of

political risk cover. Alternatively, political

risk insurance may be available through

Export Credit Agencies (or ECA’s),

multilateral organisations and other

commercial insurers. For complete

protection, an assured should consider

purchasing political risk insurance

to supplement the energy package

policy in situations where the assured’s

operations are located in a politically

unstable region.

Neal Brendel

“The combined influence of recent

favourable decisions for assureds,

and more affordable source detection

technology now mean that claims for

pollution coverage in energy package

policies have become a more viable

avenue for asset recoveries in the

unfortunate event of catastrophic

loss – whether induced by nature or

human events”

Michael Miguel

“Indeed, 2010 was a pivotal year for

assureds, as courts found that certain

routinely asserted defenses to coverage

would no longer insulate insurers from

coverage liability or bad-faith claims”

For further information please contact

Neal Brendel

(neal.brendel@klgates.com) or

Michael Miguel

(michael.miguel@klgates.com).

This article first appeared in ASIAN-

MENA COUNSEL, magazine for the

In-House Community

(www.inhousecommunity.com)

Recent DevelopmentsMiddle East Oil Crisis - Fears grow, at the time of going to press, that the price of oil may rise to the previous high of $147 a barrel unless oil production in Libya by the rebels can be stabilised shortly. Libya is estimated to have lost more than three-quarters of its oil output as a result of the fighting.

Global Economic Forecast Down - International ratings agency, Fitch, has cut its global economic growth forecast for this year. This was substantially due to the 32% increase in crude oil prices between October 2010 and March 2011.

Surge in Japan’s LNG imports expected - As Japan continues to battle against nuclear disaster, there are expectations of an increased level of liquefied natural gas imports into the country to compensate for the longer term loss of nuclear power. In 2009, Japan’s electricity supply was powered 26% by LNG but also 27% by nuclear.

Statoil suspend North Sea projects - Statoil, the Norwegian energy company, has said it will “pause and reflect” before deciding whether to continue developing two North Sea oil projects (on the Mariner and Bressay fields) due to come on-stream from 2016/17 in light of the UK’s most recent budget announcement to impose a £2bn ‘windfall tax’ on oil companies. Other UK producers are also reviewing their investment plans, with Centrica for example warning that it may prune its planned investment in UK North Sea oil fields with the suggestion that it will not re-open its Morecambe Bay gas field after a recent 4 week closure for maintenance. Statoil is also in the news with the recent discovery of significant oil reserves on the North Sea Krafla prospect. Preliminary reports indicate the size of the discovery to be between 12.5 and 56.5 million barrels of recoverable oil equivalent.

BHP Bilton leave the Falklands - BHP Bilton is to transfer its interest in the northern licences in the Falklands to Falkland Oil & Gas. Increased activity is now expected in the region.

For further information please contact Laura Atherton (laura.atherton@klgates.com).

For further information contact:

Anchorage Austin Beijing Berlin Boston Brussels Charlotte Chicago Dallas Dubai Fort Worth Frankfurt Harrisburg Hong Kong London

Los Angeles Miami Moscow Newark New York Orange County Palo Alto Paris Pittsburgh Portland Raleigh Research Triangle Park

San Diego San Francisco Seattle Shanghai Singapore Spokane/Coeur d’Alene Taipei Tokyo Warsaw Washington, D.C.

K&L Gates includes lawyers practicing out of 37 offices located in North America, Europe, Asia and the Middle East, and represents numerous GLOBAL 500, FORTUNE 100, and FTSE 100 corporations, in addition to growth and middle market companies, entrepreneurs, capital market participants and public sector entities. For more information about K&L Gates or its locations and registrations, visit www.klgates.com.

This publication is for informational purposes and does not contain or convey legal advice. The information herein should not be used or relied upon in regard to any particular facts or circumstances without first consulting a lawyer.

©2011 K&L Gates LLP. All Rights Reserved. 1103

14_5

238

Georgy Borisov, Moscow

+7.495.643.1711

georgy.borisov@klgates.com

Walter A. Bunt, Pittsburgh, PA

+1.412.355.8906

walter.bunt@klgates.com

Paul de Cordova, Dubai

+971.4.427.2704

paul.decordova@klgates.com

Tomasz Dobrowolski, Warsaw

+48.22.653.4221

tomasz.dobrowolski@klgates.com

Mathew Kidwell, London and Dubai

London +44.(0)20.7360.8141

Dubai +971.4.427.2700

mathew.kidwell@klgates.com

David Overstreet, Pittsburgh, PA

and Harrisburg, PA

Pittsburgh +1.412.355.8263

Harrisburg +1.717.231.4517

david.overstreet@klgates.com

Michael Pollen, Singapore

+65.6507.8120

mike.pollen@klgates.com

William M. Reichert, Moscow

+7.495.643.1712

william.reichert@klgates.com

Matthew Smith, London

+44.(0)20.7360.8246

matthew.smith@klgates.com

R. Timothy Weston, Harrisburg, PA

+1.717.231.4504

tim.weston@klgates.com

Craig Wilson, Harrisburg, PA

+1.717.231.4509

craig.wilson@klgates.com

Rose Zhu, Beijing

+86.10.5817.6110

rose.zhu@klgates.com

WelcomeFrank Thompson has recently joined the insurance coverage group at K&L Gates LLP in

London from Herbert Smith LLP. His practice is focused on assisting policyholders in accessing

the proceeds of their insurance policies. He regularly conducts policy wording reviews to

assess scope of coverage and fitness for purpose, in addition to advising on notifications/

claims submissions and disputed claims, in the context of various types of insurance,

including Construction All Risks, Delay in Start Up and Operational Property policies in

addition to Political Risks and Property Terrorism covers.

New Professional

Author: George A. Bibikos george.bibikos@klgates.com +1.717.231.4577

Additional Contact: Walter A. Bunt, Jr. walter.bunt@klgates.com +1.412.355.8906 K&L Gates includes lawyers practicing out of 37 offices located in North America, Europe, Asia and the Middle East, and represents numerous GLOBAL 500, FORTUNE 100, and FTSE 100 corporations, in addition to growth and middle market companies, entrepreneurs, capital market participants and public sector entities. For more information, visit www.klgates.com.

Oil and Gas Alert

May 10, 2011

A New Conservation Law for Pennsylvania? In the past two sessions, the Pennsylvania Senate has introduced legislation aimed at creating a new pooling and conservation law that applies to natural gas exploration and production from the Marcellus Shale and other unconventional gas-bearing formations. The latest is SB 447, referred to the Committee on Environmental Resources and Energy on February 11, 2011, which would create the “Unconventional Oil and Gas Unit Establishment Act.” As with most things related to Marcellus Shale development in Pennsylvania, SB 447 has sparked debate, particularly over the so-called “forced pooling” aspect of the legislation. What is often overlooked is that conservation measures like the ones in SB 447 are designed to promote the efficient and economic recovery of natural resources and to protect landowners against the negative consequences of the “rule of capture,” a legal principle still alive and well in Pennsylvania. Although SB 447 is not perfect, it focuses the discussion on a workable and fair conservation law that circumscribes the negative consequences of the rule of capture and achieves the twin aims of preventing wasteful resource development and protecting correlative rights.

What is the rule of capture? Oil and gas conservation laws are fundamentally designed to counter the negative consequences of the “rule of capture.” Under the rule of capture, an owner or his lessee may drill a well and drain all the oil or gas from beneath any adjacent landowner’s property without any incurring any liability.1 In other words, the adjacent landowners cannot sue to recover the natural resource from the capturer, and they are unable to recover money damages for the drainage. Instead, they have essentially one remedy – they (or their lessee) may drill their own well. If they do, they will very likely position their wells as close as possible to property boundaries to increase their chances of draining oil or gas from under their neighbor’s land. If they do not drill a well or delay in drilling a well, they may be deprived of their fair opportunity to develop the natural resources on and under their property. Consequently, the rule of capture often promotes the proliferation of wells – many more wells than are necessary to adequately, efficiently, and economically drain a common source of supply underlying a given area. This is wasteful in several ways. First, it is economically wasteful. If only one well is necessary to drain a reservoir, then drilling additional wells to deplete the same reservoir is a waste of time and money. This is also “physically” wasteful. As more wells pierce a reservoir rock or gas-bearing formation, the reservoir energy decreases. This energy is necessary to push the oil or gas from the subsurface rock to the mouth of the well.

1 Robert E. Hardwicke, The Rule of Capture and Its Implications as Applied to Oil and Gas, 13 TEX. L. REV. 391, 393 (1935); Westmoreland Gas Co. v. DeWitt, 18 A. 724, 725 (Pa. 1889).

May 10, 2011 2

Oil and Gas Alert

Without sufficient pressures in the subsurface, significant amounts of oil and gas reserves may be rendered unrecoverable.

What are conservation laws? Invoking their police powers, state legislatures have responded to the negative consequences of the rule of capture with “conservation laws.” These laws are designed to abolish the rule of capture (at least in large part).2 They are also designed to promote the conservation of oil and gas, prevent physically and economically wasteful drilling, and protect “correlative rights” of interest-holders whose lands overlay a common source of supply.3 Conservation laws tend to vary in complexity from state to state. At the risk of oversimplifying, conservation laws typically create an application process whereby the holder of oil and gas interests (usually a lessee) may propose a drilling “unit.” The statute typically designates a state agency with jurisdiction to (1) order or approve the establishment of these units; (2) integrate the interests of landowners, operators, and other interest holders located within the units; and (3) allocate the costs of the unit well, profits from production after payout, and (in some cases) penalties among various stakeholders in the unit.

• Units. If multiple properties overlay a common source of supply, the rule of capture suggests that each property owner should drill his own well to prevent drainage, potentially resulting in more wells than necessary to drain the reservoir. Conservation laws authorize the state’s designated agency to approve units comprised of multiple properties with regard to the underlying oil reservoirs or gas-bearing formations rather than property boundaries. The units are usually limited in size (e.g., 640 acres) and (sometimes) must be fairly regular in shape. To counteract the drilling of unnecessary wells, the agency sets

2 Griffith v. Gulf Refining Co., 60 So. 2d 518, 520 (Miss. 1952) (“Consequently, the common law rule is now limited and circumscribed by the conservation rules and regulations of the Board … .”). 3 Bruce M., Kramer, Compulsory Pooling and Unitization: State Options in Dealing with Uncooperative Owners, 7 J. Energy L. & Policy 255, 259 (1986).

forth the maximum number of wells per unit, and it may also impose minimum spacing requirements between wells. Conservation laws may also have setback requirements to prevent wells from popping up near adjacent lands that are not included within the unit (which helps prevent against drainage of adjacent lands not included within the unit).

• Integration. Once a proposed unit is established, the effect under most conservation laws is to “integrate” the interests of landowners and other operators in that unit and allocate among them the costs of and (eventually) the compensation from production. Although many focus on the fact that some holders of oil and gas interests may be “forced” into a unit, these integration provisions are actually designed to protect landowners from the rule of capture. To illustrate, the holders of oil and gas interests who are integrated into a unit will be compensated for their share of production from the unit well or wells. Under the rule of capture, however, the oil and gas potentially would be drained from these properties by nearby operations, and oil and gas interest holders would receive nothing.

• Risk Penalties. Once a unit is established, an operator of the unit is selected, either pursuant to the agency’s order or by agreement among the interest holders in the unit. Sometimes, however, interest holders may not wish to participate in the costs of drilling the unit well or wells. For these situations, conservation laws usually impose a “risk” or “nonconsent” penalty on nonconsenting interest holders. These penalties are designed to incentivize interest holders to participate in the costs of the well up front, rather than waiting and seeing whether the well is a producer (and then electing to share in the profits). In this way, the risk penalty is designed to compensate the participants in the well for “carrying” the non-consenting parties and bearing all the risk and expense of drilling a dry hole.

May 10, 2011 3

Oil and Gas Alert

Does Pennsylvania have a conservation law? The Pennsylvania Oil and Gas Conservation Law4 has been on the books since 1961. Its scope, however, is limited. To illustrate, the statute does not apply unless an oil or natural gas well penetrates the Onondaga Horizon at a depth of 3,800 feet or more. The Conservation Law and its implementing regulations do not apply to Marcellus wells because the Marcellus formation overlays the Onondaga Horizon and Marcellus wells typically bottom out within the Marcellus and above the Onondaga. For deeper shale plays that are geologically beneath the Onondaga, such as the Utica Shale, the Conservation Law may apply. The problem, however, is that the Conservation Law has only rarely been used.5 It was written some 50 years ago at a time when the type of unconventional natural gas exploration and development we see today was essentially unheard of. It remains unclear how the law will work with exploration and development of deeper shale formations.

What are the key features of the proposed conservation law in SB 447? If enacted, SB 447 would repeal in large part the current Conservation Law and in effect substantially limit the operation of the rule of capture. Some of the key provisions include the following:

• Legislative intent. The intent of the proposed legislation is to promote the development of unconventional oil and gas resources in accordance with best conservation practices; protect the correlative rights of the parties; and protect the environment.

• Designated agency. The proposed act would confer upon the Pennsylvania Public Utility Commission (“PUC”) the authority to

4 58 P.S. §§ 401 et seq. 5 Only one reported case refers to the use of the Conservation Law (involving the Pineton Field where 19 separate spacing units were established with only one well per spacing unit). Felmont Oil Corp. v. Cavanaugh, 446 A.2d 1280 (Pa. Super. 1982). The case does not discuss how the Conservation Law works except to acknowledge its purposes of preventing waste, protecting correlative rights, and fostering an orderly development of a reservoir.

administer the act and order the establishment of “standard units.”

• Standard units. The proposed act encourages the creation of voluntary units, in which case using the act would be unnecessary. Absent voluntary agreement, the proposed act would authorize the holder of 65% of a “working interest” (i.e., a lessee, or an oil and gas owner) in a proposed unit or “collaborating owners” that make up 65% of the interest in the proposed unit to apply for a “standard unit order.” A “standard unit” is defined as “a unit for the production of oil or natural gas that is not more than 640 acres” (plus a 10% tolerance for survey errors or other acreage discrepancies).

• Application for a standard unit order. A standard unit application must be submitted to the PUC with a variety of information, including (1) names of the interest holders in the proposed unit, (2) plats; (3) a statement of the allocation of interests in the proposed unit; (4) proof of notice provided to specific parties within the unit and owners of adjacent land outside the proposed unit; (5) estimated well costs, along with an authorization for expenditure (“AFE”), and (6) a proposed joint operating agreement.

• Protests to the application. Protests to applications may only be filed by persons with standing, which includes working interest owners, owners of land directly adjacent but outside the proposed unit, owners of potentially “stranded acreage” (acreage that is stranded due to required 250-foot setbacks required by the proposed act), or owners of mineral rights that are proposed to be integrated. Protests must be filed within 20 days from the filing date of the application. The grounds are limited to whether the proposed joint operating agreement including royalty payments are reasonable, whether the applicant acted in good faith, or the owner of a working interest that will be integrated into the proposed unit has the resources and plans to develop acreage outside

May 10, 2011 4

Oil and Gas Alert

the proposed unit in manner consistent with conservation principles.

• Procedure. If a proper protest is filed, the PUC’s office of administrative law judge (“OALJ”) must hold a hearing within 20 days after the close of the protest period unless the parties agree to an extension. After the hearing, the ALJ staff issues recommendations to the commission that may include amendments to the application, the joint operating agreement, or other conditions to protect the correlative rights of the interest holders in the proposed unit. The PUC must then rule on the application within 45 days after the hearing. A direct appeal as of right may be taken to the Commonwealth Court of Pennsylvania, but its standard of review is limited.

• Standard unit order. The PUC must order the establishment of the proposed unit if the applicant demonstrates by a preponderance of the evidence that the proposed unit will (1) minimize “surface disruption” on the property or minimize “environmental impact”; (2) prevent “unnecessary loss of use and benefits of potentially recoverable oil or gas”; and (3) ensure that owners of oil and gas interests have a “fair and reasonable opportunity to obtain an equitable share of oil and gas.”

• Integration. Once a unit order is granted, “all the oil and gas interests within the unit shall be integrated” and royalties “shall be apportioned and paid to royalty interest holders based upon the relative surface acreage of the interests” in the unit (unless the parties agree in writing to deviate from the surface-acreage allocation).

• Consenting parties. If the owner of a “working interest” (i.e., a lessee or an owner of oil and gas interests) has not already voluntarily agreed with the applicant regarding operation of the unit, the working-interest owner may elect to be treated as a “nonconsenting party” or a “consenting party.”

• Nonconsenting parties. If the working-interest owner does not consent, that party is entitled to his or her proportionate share of the profits from the well “after being assessed a risk fee apportioned among all nonconsenting parties at the rate of 300% of their proportionate share of all of the costs incurred by the designated operator.” If the working-interest owner instead elects to consent to the well, that party may will be entitled to his or her proportionate share of the profits; will be subject to the terms of the approved joint operating agreement for the unit; and must contribute at the time of the election a proportionate share of the costs of preparing, drilling, completing, and operating the well.

• Unit operations. In large part, unit operations will be conducted pursuant to a joint operating agreement. In some circumstances, the operating agreement may be modified by the PUC as part of its determination on issuing a standard unit order. The proposed act also limits the designated operator’s ability to propose more than one well per calendar year and limits the interest holders who can request additional drilling on the unit.

What does the future hold? SB 447 is not perfect, and it is unclear whether the legislation will grow legs in this session. At some point, however, lawmakers may pass a new conservation law for Pennsylvania. Accordingly, proposals for a new conservation law should be carefully evaluated and debated. To that end, interested parties would be well served by monitoring current and future proposals, comparing them to conservation laws in other states, identifying what has and has not worked in those other states, and offering suggestions to lawmakers on how to craft a reasonable and workable conservation law that fosters the development of unconventional natural-gas bearing formations in Pennsylvania.

May 10, 2011 5

Oil and Gas Alert

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Rocky Mountain Mineral Law Foundation Development Issues in Major Shale Gas Plays

December 6, 2010

WATER AND WASTEWATER ISSUES IN

CONDUCTING OPERATIONS IN A SHALE PLAY – THE

APPALACHIAN BASIN EXPERIENCE

R. Timothy Weston K&L Gates LLP Harrisburg, PA

This article is for informational purposes only and does not contain or convey legal advice. The information herein should not be used or relied upon in regard to any particular facts or circumstances without first consulting with a lawyer. This paper represents an updated edition of Water Supply and Wastewater Challenges in Marcellus Shale Development, which was originally published in 30 ENERGY & MINERAL LAW INSTITUTE Ch. 15 (2009), which is reprinted by permission from the Energy & Mineral Law Foundation.

Table of Contents

1. Introduction to the Water Supply, Water Resource Impact and Wastewater Challenge .....1

2. The Water Resource Challenge in Perspective....................................................................2

3. Water Rights and Water Withdrawal Regulation ................................................................6

3.1 Overview – What Is the Meaning of Water Rights?................................................7

3.2 “Water Rights” Granted Under Mineral Leases ......................................................9

3.3 Basis of “Water Rights” Under State Law – Common Law and Regulatory Programs ..................................................................................................................9

3.4 Common Law Principles Applicable to Water Withdrawals.................................10

(a) Classifications of Water.............................................................................10

(b) Riparian Rights in Surface Streams, Lakes and Subterranean Streams.....12

(c) Common Law Rights in Percolating Groundwater....................................16

(d) The Restatement Rules for Surface Water and Groundwater....................18

(e) Interaction Between Surface and Ground Water .......................................19

3.5 Regulated Riparian Regimes..................................................................................22

(a) Kentucky....................................................................................................22

(b) New York...................................................................................................24

(c) Ohio............................................................................................................26

(d) Pennsylvania ..............................................................................................27

(e) Virginia ......................................................................................................33

(f) West Virginia .............................................................................................35

(g) The Delaware River Basin Commission....................................................36

(h) Susquehanna River Basin Commission .....................................................41

(i) Great Lakes – St. Lawrence River Basin Water Resources Compact .......46

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4. Protection of Water Supplies .............................................................................................48

4.1 Regulation of the Fracing Process and the Proposed FRAC Act...........................48

4.2 Liability of Gas Well Operators for Impacts on Other Water Users .....................50

(a) Liability for Impacts Caused by Water Supply Development ...................50

(b) Liability for Impacts Caused by Gas Well Development and Operation....................................................................................................51

5. The Flowback / Wastewater Challenge .............................................................................55

5.1 Scope of the Challenge ..........................................................................................55

5.2 Overview of Wastewater Management Issues.......................................................56

5.3 Requirements for Characterizing Flowback Wastewater ......................................56

5.4 Assuring Delivery to Appropriate Facilities ..........................................................58

5.5 Treatment, Reuse and Disposal Technology Choices............................................59

(a) Natural pond evaporation...........................................................................59

(b) Direct reuse for drilling and fracing...........................................................59

(c) Underground injection of flowback & production brines..........................59

(d) Conventional treatment technologies.........................................................60

(e) TDS reduction via reverse osmosis............................................................60

(f) TDS reduction via evaporation ..................................................................61

(g) TDS reduction via crystallization ..............................................................62

(h) Key regulatory questions affecting selection.............................................62

5.6 Regulatory Drivers to Technology Selection – Impending Restrictions on Surface Water Discharges......................................................................................63

(a) Overview....................................................................................................63

(b) The PA TDS Strategy and Pending Regulations .......................................63

6. Legal and Regulatory Issues in Implementing Treatment and Disposal Facilities............66

6.1 Treatment Facility Siting .......................................................................................66

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(a) Zoning and land development regulations.................................................66

(b) State siting restrictions for certain treatment facilities ..............................67

6.2 NPDES Permit Issues ............................................................................................68

(a) Establishing effluent limits ........................................................................68

(b) Special protection waters ...........................................................................69

(c) Impaired waters..........................................................................................70

6.3 Water Quality Construction Permits for Wastewater Facilities.............................72

(a) Pennsylvania ..............................................................................................72

(b) Ohio............................................................................................................72

(c) Delaware River Basin Commission ...........................................................72

6.4 Air Emission Issues for Water Treatment Facilities ..............................................73

(a) What counts as a “source” in defining “major source”..............................74

(b) Potentially applicable air emission regulations..........................................74

6.5 Underground Injection of Wastewater or Treatment Residuals ............................76

(a) Acquiring Rights to Allow Underground Injection ...................................76

(b) Federal Safe Drinking Water Act – Underground Injection Control (“UIC”) Program........................................................................................77

(c) Pennsylvania ..............................................................................................79

(d) Ohio............................................................................................................79

(e) West Virginia .............................................................................................80

(f) New York...................................................................................................80

(g) DRBC.........................................................................................................80

6.6 Residuals Management & Disposition...................................................................81

(a) What are the treatment residuals? ..............................................................81

(b) Categorization of residuals ........................................................................81

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(c) State regulation of residual or industrial waste or beneficial reuse of residuals .....................................................................................................82

6.7 Implementing Wastewater Projects – Transactional Issues...................................84

7. Summarizing Key Challenges to Wastewater Management.............................................84

8. Final Words........................................................................................................................85

1. Introduction to the Water Supply, Water Resource Impact and Wastewater

Challenge

Shale formation development across varying regions of the United States presents both water supply and wastewater challenges of considerable dimensions, whose scope and intensity may depend upon the region involved and competition for associated water resources. This paper focuses on one of those regions – the Appalachian Basin and the current challenges confronting those exploring and developing the Marcellus Shale. Many of the issues discussed, however, will resonate in other parts of the country and similar unconventional development of shale formations wherever they occur.

Development of the extensive natural gas reserves contained in the Marcellus Shale deposits promises to be one of the most important opportunities for the United States for the next several decades. At the same time, exploitation of this gas resource poses interesting water supply, water resource impact, and wastewater challenges which the oil and gas industry has rarely faced before in the Appalachian Basin or elsewhere in the country.

While some traditional oil and gas development has utilized, to a modest extent, water supplies in the drilling and fracing processes, Marcellus Shale exploitation involves orders of magnitude greater water resource requirements. Horizontal drilling techniques, coupled with hydraulic fracturing of deep horizontal extensions, entails water use multiple times greater than traditional wells.

Based on experience in the Barnett Shale and developing experience in the Marcellus Shale play, approximately one to five million gallons of water are required for fracing each gas well, with slickwater frac techniques utilizing as much as 500,000 to 1,000,000 gallons of fluid in each of multiple stages. Over the past year, recycling of flowback water has shown considerable promise in terms of reducing disposal requirements, thereby reducing somewhat the draft on freshwater supplies. But the technology allowing for large-scale reuse of water has encountered some technical and logistical limitations, and it is clear that substantial volumes of fresh water will continue to be required. Thus, the challenge will be to secure adequate and reliable sources of water with appropriate quality characteristics in reasonable proximity to proposed well sites to meet the gas well development requirements.

Whether or not warranted, the fracture stimulation process itself has raised concerns regarding the potential impacts to public and private water supplies. Although the fracing process has enjoyed exemptions from underground injection control regulation, environmental and citizen organizations have posed repeated questions regarding disclosure of chemicals used in the process, leading to proposals for repeal or replacement of the current exemption with some form of fracing process regulation at the federal and/or state level.

At the same time, the fracture stimulation of Marcellus and other shale wells results in substantial volumes of flowback wastewaters containing high salt contents and

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other constituents of potential concern. Of the volumes pumped downhole for fracing, a portion (ranging from 25-50%) emerges from the well over time as flowback water, followed by additional production brines. Efforts to obtain representative characterization of Marcellus Shale flowback and produced waters are continuing, and it appears that some variability occurs between different parts of the plan and even between wells in particular areas. Generally, such flowback waters contain 4-25 percent salts (including constituents from the underground formations), plus oil and gas, and chemicals added during the frac. Typical total dissolved solids (“TDS”) concentrations in Marcellus flowback may exceed 100,000 milligrams per liter (“mg/l”) – higher than experienced in some other regions and shale plays.

These high-TDS wastewaters pose a substantial challenge, both in terms of volume and concentrations. A number of eastern streams are already burdened with high TDS concentrations, largely from abandoned mines and acid mine drainage, with limited capacity to assimilate additional loadings, particularly during low flow periods. Other streams, particularly in rural watersheds across the northern portions of Pennsylvania and southern New York, are subject to special protection for their high quality, with discharges strictly regulated under “anti-degradation” standards. Some States, such as Pennsylvania, have moved to impose stringent restrictions on new or increased loadings of TDS from Marcellus Shale development, pointing the way to effective “zero discharge” scenarios for wastewater management. At the same time, environmental organizations have petitioned the U.S. Environmental Protection Agency (“EPA”) to restrict introduction of gas well wastewaters to publicly-owned treatment works (that is, sewage treatment plants) and to establish new effluent guidelines for the oil and gas sector, establishing a no discharge limit for central wastewater treatment facilities receiving oil or gas-related wastewaters.1

Thus, the entire “water balance” of Marcellus Shale development is a critical element to successful pursuit of this play. Concurrently, the acquisition of adequate and reliable supplies of water, coupled with the treatment, reuse and disposition of wastewater, pose key technical, regulatory and legal challenges requiring concerted attention.

2. The Water Resource Challenge in Perspective

From a statewide or basin perspective, water requirements for Marcellus Shale development might appear comparatively modest. The Susquehanna River Basin Commission, for example, estimates that annual consumptive water use for all gas well development, once full-scale development has been reached, will equate to approximately

1 Letter from EarthJustice, et al., to Carey A. Johnston, Water Docket, U.S. Environmental Protection Agency, re: Comments on Final 2008 Effluent Guidelines Program Plan and Suggestions for the 2009 Annual Review: Oil and Gas Exploration, Stimulation, and Extraction, Docket EPA-HQ-OW-2008-0517 (April 7, 2009).

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28 million gallons per day (“mgd”),2 representing approximately three percent of total basin consumptive water use.3 By comparison, the total Marcellus Shale gas well water demand equates to about one-half the basin-wide water use by the recreational sector (golf courses and ski resorts), and less than one nuclear power plant.4 However, in some basins, cumulative consumptive water use (from all uses) poses concerns during drought and low flow events, as eastern States and water management agencies attempt to balance demands by upstream users versus needs for downstream flows to maintain wastewater assimilative capacity, fisheries, salinity control in estuaries, and other environmental conditions.5 At the same time, much of the Marcellus Shale development occurs in areas with smaller headwater streams, many with high quality and cold-water fisheries, where concerns are raised as to the impact of large withdrawals leading to significant streamflow reductions or even depletion. Thus, the location, amount, timing, and conditions of withdrawals, and whether multiple withdrawals are occurring in the same watershed, are a matter of considerable focus.

Although eastern States have traditionally been viewed as water “rich,” particularly by those coming from drier regions, the Appalachian Basin States are not without their own significant water supply challenges and concerns. While supplies are relatively plentiful in “normal” years, the fact is that recurrent droughts have resulted in sometimes painful shortage conditions affecting, to various degrees, the region’s streams and groundwater aquifers, leading to sometimes heated controversy, conflict and litigation.

The Marcellus Shale spans the upper Appalachian Basin, cutting across several important watersheds, including the Delaware, Susquehanna, Ohio, and Great Lakes-St. Lawrence systems.

2 Thomas R. Beauduy, Accommodating a New Straw in the Water: Extracting Natural Gas from the Marcellus Shale in the Susquehanna River Basin, SRBC White Paper available at http://www.srbc.net/programs/projreviewmarcellus.htm. 3 SRBC reports that current “approved” consumptive use totals approximately 563 mgd (id.), but the total current maximum consumptive use in the basin (including both grandfathered uses and those approved by SRBC) has been estimated 882.5 mgd. SRBC, CONSUMPTIVE USE MITIGATION PLAN, SRBC Pub. No. 253 (March 2008) at 5 (available at http://www.srbc.net/planning/CUMP.htm). 4 T. R. Beauduy, supra. 5 The Susquehanna River Basin likewise faces challenges in balancing growing consumptive water use with maintenance of flows in the lower river and into the upper Chesapeake Bay, where such flows are important to both migratory fish habitat and Bay salinity. SRBC, Consumptive Use Mitigation Plan, SRBC Pub. No. 253 (March 2008)

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The eastern side of the Marcellus Shale lies within the upper Delaware Basin, in northeastern Pennsylvania and southern New York. The Delaware Basin watershed forms the major water source for some 15 million residents of the Northeast Metropolitan Corridor from New York City to Wilmington, Delaware, roughly five percent of the nation’s population. In relative terms, the Delaware is a small watershed, encompassing only 13,539 square miles, draining one percent of the United States. The basin encompasses four states, 42 counties, and some 838 municipalities, while its service area extends to encompass the entire New York City and northern New Jersey region. Substantial portions of the upper Basin, including much of the area underlain by the Marcellus Shale, provide the headwaters of high quality streams valued for their trout fisheries, which flow into sections of the River mainstem designated as part of the National Wild and Scenic Rivers System. The juxtaposition of streams with high environmental qualities coupled with stresses placed by an intense and growing population has provided fodder for ample conflict, including several trips by the Basin States to the U.S. Supreme Court6 prior to enactment of a comprehensive multi-state regional water management regime. In the Delaware River Basin, cumulative consumptive water use is a key issue, with drought management programs targeted to maintain river flows during critical periods in order to repel salinity intrusion into the lower Delaware River, in order to protect water supply intakes used by the City of Philadelphia and avoid salt water infiltration into the important Potomac-Raritan-

6 New Jersey v. New York, 283 U.S. 336(1931); New Jersey v. New York, 347 U.S. 995 (1954). For a review of the Delaware River’s water management litigation and regulatory history, see R. T. Weston, Interstate Watershed Management – The Delaware and Susquehanna Basin Experience, ABA Eastern Water Resources: Law, Policy and Technology Conference, Hollywood, Florida (May 6-7, 2004).

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Magothy Aquifer that supplies much of southern New Jersey.7 The Delaware River is at once one of most intensely developed and intensely regulated watersheds in the United States.

Moving westward, the Susquehanna River Basin, which drains 27,500 square miles (including one-half of the land area of Pennsylvania, plus portions of New York and Maryland), represents the longest commercially non-navigable river in North America, and the 16th largest river in the United States. The basin hosts a population of some 4.1 million and supports a service area that extends to the City of Baltimore and many northern Maryland counties outside the basin. The Susquehanna Basin comprises 43 percent of the Chesapeake Bay’s drainage area, supplying a normal flow of about 18 million gallons per minute at Havre de Grace, Maryland. That flow represents 90 percent of the fresh water flow to the upper half of the Bay, and 50 percent of the Bay’s overall fresh water inflow. The basin is experiencing growing volumes of consumptive use. The basin is a major center of electric energy production, from a combination of hydroelectric facilities in the lower basin, and both nuclear and fossil fuel fired steam electric stations throughout the drainage area. Without consideration of Marcellus Shale development, consumptive use of all forms was projected by SRBC to increase to over 645 mgd by the year 2010. The Ohio River Basin, and its major tributary components (including the Monongahela and Allegheny Rivers) which traverse much of the Marcellus Shale area, may be seen by some as less challenged from a water resource perspective. That perception may be based, in part, on the fact that recent decades have not witnessed droughts across the region anywhere near the intensity of either seen in the basins to the east or encountered in the earlier part of the 20th Century. Yet evaluations conducted by the recently completed West Virginia Water Use Survey and Pennsylvania State Water Plan highlight that the Ohio River watershed likewise faces some significant water resource challenges. With more than a few streams and aquifers affected by acid mine drainage, supplies of potable water are limited. In many areas, tight hard rock formations provide limited groundwater storage and transmissive capabilities, further limiting the ability to successfully develop large volume wells or providing highly variable yields between normal and dry years. During the late summer and fall of 2008, these factors were highlighted when extreme low flow in the Monongahela River was accompanied by rising total dissolved solids (“TDS”) concentrations, to the point that instream TDS values exceeded State water quality criteria and secondary drinking water standards. While the major source of the high TDS concentrations derived from acid mine drainage, particularly from abandoned mines in West

7 DRBC, WATER RESOURCES PLAN FOR THE DELAWARE RIVER BASIN (2004), at 17-28 (available at http://www.state.nj.us/drbc/BPSept04/index.htm); see, R.T. Weston, supra.

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Virginia and Pennsylvania,8 some media and public agencies mentioned Marcellus Shale gas development as a potentially contributing factor.9 Western New York, northwestern Pennsylvania, and northern Ohio all lie within the Great Lakes-St. Lawrence Basin. While the Great Lakes are noted as representing the largest single fresh water resource in the world, nevertheless serious water resource controversies have arisen concerning the impacts of interbasin and interlake diversions and large consumptive uses, leading to the recent proposal of a regionwide compact to enact much more stringent water withdrawal regulation. 3. Water Rights and Water Withdrawal Regulation

Those engaged in Marcellus Shale and other shale development activities in the eastern U.S. confront common law water rights issues and water withdrawal regulatory regimes unlike those encountered in most historic oil and gas plays in the southwestern region. Clearly, understanding the applicable legal and regulatory questions and processes will be essential to charting a course to successful implementation of Marcellus development projects.

Against the backdrop described above, we face the key questions:

What “water rights” may shale natural gas developers acquire, either in conjunction with mineral leases or otherwise, to procure the necessary water supplies to support well development? What do those “water

8 Tetra Tech NUS, Inc., Evaluation of High TDS Concentrations in the Monongahela River (January 2009) (available at

http://www.pamarcellus.com/Mon%20River%20High%20TDS%20Study%20Report%20(Final).pdf) 9 PaDEP News Release, DEP Investigates Source of Elevated Total Dissolved Solids in Monongahela River, October 22, 2008, available at http://www.ahs2.dep.state.pa.us/newsreleases; Don Hopey, DEP hopes a flush cleans Mon water, PITTSBURG POST-GAZETTE, October 24, 2008, available at http://ww.post-gazette.com/pg/08298/922462-113.stm; Don Hopey, Drillers, sewer authority want state to lift waste limits, PITTSBURGH POST-GAZETTE, November 22, 2008, available at http://www.post-gazette.com/pg/08327/929978-113.stm; Don Hopey, Drill press: Environmental, sportsmen’s groups want stricter regulation of natural gas projects, PITTSBURG POST-GAZETTE, November 28, 2008, available at http://www.post-gazette.com/pg/08333/931286-113.stm; Don Hopey, Area gas deposits reported to be nation’s largest, PITTSBURG POST-GAZETTE, December 14, 2008, available at http://www.post-gazette.com/pg/08349/935140-113.stm; Don PITTSBURG POST-GAZETTE, December 21, 2008, available at http://www.post-gazette.com/pg/08356/936646-113.stm.

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rights” mean in practical terms of what you can withdraw, how much you can withdraw, and where the water can be used?

What regulatory and permitting programs affect the procurement and development of water supplies to serve gas well drilling and operations?

If water supply withdrawals (either via groundwater wells or surface water intakes) associated with Marcellus Shale developments adversely impact other water users, what liabilities will be imposed on the gas well developer?

If development of a gas well affects the quantity or quality of water supplies used by third parties, what are the gas well operator’s responsibilities?

3.1 Overview – What Is the Meaning of Water Rights?

The concept of “water rights” in the east is subject to many misperceptions. The best way to define “water rights” is to ask two questions:

(1) What can I do? (2) What can someone else do to me?

Consider a hypothetical potential well site development:

Marcellus Development Co. (“MDC”) has acquired a mineral lease on the 200 acre Green Lease. MDC drills Water Well 1 on the Green Lease, but Water Well 1 yields an insufficient supply. Further, operation of Water Well 1 causes interference with the well on the neighboring AABC Manufacturing property, causing the AABC well to produce less than AABC needs to operate.

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Spring Creek

West Run

East Run

Forest Farms

High Acres Estates

Water Well 2 ☼

MDC Green Lease

MDC Gas Well☼ Water Well 1

AABC Manufacturing

☼ AABC Well

MDC seeks an additional source on the 100-acre Forest Farms property about two miles away in the upper watershed of Spring Creek. The Forest Farms property overlies an aquifer known to produce very high quality water with substantial yields. MDC’s plan is to install a 200-foot deep well, with a capacity to extract up to 300,000 gpd.

Forest Farms adjoins West Run, which joins East Run about two miles below Forest Farms to form the mainstem of Spring Creek. The bedrock aquifer underlying Forest Farms provides the source for a number of springs and baseflow in the West Run watershed.

High Acres Estates, a 300-home development, obtains its water supply from a series of springs that are fed by the aquifer underlying the Forest Farms and High Acres area. High Acres is concerned that withdrawals by MDC’s Water Well 2 could reduce the flow of water in the High Acres springs.

The upper and middle portion of Spring Creek is inhabited with varying populations of brook and brown trout, and sections of Spring Creek are frequented by recreational fisherman during the permitted fishing season.

Ripa Environmental Defenders & Development Opposition Group (“REDDOG”) is concerned that the withdrawal and transfer of groundwater from Forest Farms to the East Spring Borough will (1) reduce stream flows in

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In this setting, who has what “water rights” and how are those “water rights” to be reconciled?

3.2 “Water Rights” Granted Under Mineral Leases

At the outset, with respect to the extraction of surface or groundwater from the mineral lease premises to support drilling operations, one must look to the terms of the lease to determine what “rights” (as between the surface owner and mineral rights holder) the well developer may exercise. The specific lease terms will govern the relationship between the surface fee owner and mineral rights holder.

A “typical” lease may have only general language on the topic, such as a clause granting the Lessee “the privilege of using sufficient … water for operating on the premises ….” Ostensibly, such generalized language may accord the Lessee with the right to drill wells and extract water from the leased land for use in drilling and operating a well. Given the large volumes of water involved in Marcellus Shale development, however, it may be wise to consider utilizing more specific and broader provisions.

Notably, a “typical” lease refers to the right to use water “for operating on the premises” – that is, for use on the leasehold. Such a “right,” by its terms, does not authorize extraction of water from one leased parcel for use on another leased parcel. If a developer wishes to obtain the right to withdraw water from one property and move it for use in drilling on another property, different and more explicit provisions must be crafted.

The lease is, of course, just a starting point. Whatever “water rights” may be granted via a lease, those rights will be no greater (although they may be less) than the “water rights” of the landowner granting the lease. Whether operating as a fee owner or a tenant, the scope and nature of rights to withdraw and utilize water will depend on the nature and scope of “water rights” as defined under applicable state law.

3.3 Basis of “Water Rights” Under State Law – Common Law and Regulatory Programs

The law governing withdrawal and use of water in the eastern United States has substantially evolved from principles of common law, particularly riparian rights law, originally borrowed from English precursors. Over the past 250 years, such common law precedent has undergone considerable adjustment and refinement, reflecting the differing circumstances of hydrology in the new world, evolving understanding of hydrologic science, the pressures of the 19th Century’s industrial revolution and

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development through the 20th Century. In a number of eastern states overlying the Marcellus Shale deposits, common law has been supplemented, and to a significant degree supplanted by, statutory enactments establishing regulatory permitting systems (so called “regulated riparian” regimes). In addition to State level legal regimes, a management of water withdrawals and uses is substantially affected by several existing and proposed interstate compacts. Thus, the following overview water rights law is, at best, a synopsis of major themes and concepts, providing an introduction to a framework of laws which is subject to numerous exceptions and nuances between jurisdictions.

3.4 Common Law Principles Applicable to Water Withdrawals

In large part, water rights in both surface and groundwaters in the eastern states overlying the Marcellus Shale are governed by common law, composed of the doctrines and precedents established by courts in cases decided over the past two plus centuries. Although regulatory programs adopted by some states or basin jurisdictions, such as the Susquehanna and Delaware River Basin Commissions, have displaced the courts as the arbiters of many water rights disputes, common law doctrines and traditions remain strong. Because common law rests on individual cases read together, rather than a cohesive code, gaps remain in the court decisions governing water rights, and the common law is always subject to refinement or modification as new cases are litigated.

(a) Classifications of Water

Scientists generally consider all water as part of a unitary hydrologic cycle, and in general, most eastern basin’s ground and surface waters are hydrologically connected and interdependent. However, for purposes of water rights and allocation, the common law of many states attempts to distinguish four different categories of water: (1) diffused surface waters (the sheet flow from rainfall); (2) surface waters in defined streams and lakes; (3) groundwaters in well-defined subterranean streams; and (4) percolating groundwaters.10 Different rules have been developed for each classification in governing the diversion and use of such waters.

As aptly observed by one set of commentators:

Man has coped with the complexity of water by trying to compartmentalize it. … [T]he legal profession … has on occasion borrowed from the criminal code to term some waters “fugitive” and others a “common enemy.” The legal classification of water includes “percolating waters,” “defined underground streams,” “underflow of

10 WATERS AND WATER RIGHTS §§6.02, 19.05 (R.W. Beck and A. K. Kelly eds., 3rd Ed. LexisNexis/Matthew Bender 2009); R.T. Weston and J.R. Burcat, Legal Aspects of Pennsylvania Water Management, WATER RESOURCES IN PENNSYLVANIA: AVAILABILITY, QUALITY AND MANAGEMENT (1990).

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surface streams,” “watercourses,” and “diffuse surface waters”, [even though] all these waters are actually interrelated and interdependent.11

These classifications developed in the nineteenth century because of an early lack of adequate hydrogeologic knowledge, and particularly a perceived inability to predict groundwater behavior. Some courts went so far as to describe the movement of water to and within groundwater aquifers as “secret,” “occult,” and “concealed,”12 reflecting the view of the English court in Acton v. Blundell13 that there could be no liability for interference with percolating groundwater, since “the percolation and flow of underground water are out of sight and are not susceptible of actual observation and proof.”14

Although hydrologic science has progressed substantially, legal doctrines have been slow to accommodate to the now not-so-new knowledge. Some courts have acknowledged, if not embraced, the development of modern hydrogeologic science. For example, even before the beginning of the twentieth century, a Pennsylvania court observed:

It is therefore clear, from the principles and reasoning of all the cases, that the distinction between rights in surface and in subterranean waters is not founded on the fact of their location above or below ground, but on the fact of knowledge, actual or reasonably acquirable, of their existence, location, and course. Geology is a progressive, and now, in many respects, a practical science; and … since the decisions in Acton v. Blundell, and Wheatley v. Baugh, probably more deep wells have been drilled in Western Pennsylvania than has previously been dug in the entire earth in all time. And that which was then held to be necessarily unknown, and merely speculative, as to the flow of water underground, has been, by experience in such cases as this, reduced almost to a certainty.15

Improved scientific knowledge has led some eastern State courts to substantially modify, if not abandon, prior distinctions in the classification of surface and ground waters.16 Yet many other jurisdictions, even where courts recognize the much changed

11 Harold E. Thomas and Luna B. Leopold, Ground Water in North America, 143 SCIENCE 103 (1964). 12 Chatfield v. Wilson, 28 Vt. 49, 54 (Vt. 1856); Frazier v. Brown, 12 Ohio St. 294, 311 (1861). 13 12 Mees. and Wels. 324, 152 Eng. Rep. 1223 (Ex. 1843). 14 Forebell v. City of New York, 164 N.Y. 522, 525, 58 N.E. 644, 645, citing Acton, supra. 15 Collins v. Chartiers Valley Gas Co., 131 Pa. 143, 159, 18 A. 1012 (1889) 16 See, e.g., Cline v. American Aggregates Corp., 15 Ohio St. 3d 384, 474 N.E.2d 324 (1984) (abandoning the absolute dominion rule that had been adopted in Frazier v. Brown

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status of hydrologic science, still reflect outdated classifications of water developed in another era. While little hydrologic or other scientific justification can be offered today for the distinctions between these various artificial classifications of water, a significant plurality, if not majority, of courts and legislatures have continued to adhere to distinctions developed in the nineteenth century.

(b) Riparian Rights in Surface Streams, Lakes and Subterranean Streams

Under the common law of eastern states, rights to withdraw and use waters in surface streams is generally governed by the “riparian rights” doctrine. Although subterranean streams are a very rare occurrence in most jurisdictions, where they exist, the use of water in such subterranean streams, like its surface stream counterpart, is almost always treated under the “riparian” doctrine.17 The details of riparian doctrine vary somewhat from jurisdiction to jurisdiction, and while many of the fundamental principles are shared, subtle but important nuances exist between the laws of eastern states.

The fundamentals of a riparian right is the right of an owner of land adjoining a stream (a “riparian” landowner) to extract and use water from that stream on the adjoining “riparian” land. Each adjoining or overlying landowner has an equal and correlative right to make reasonable use of the water on the land which adjoins a stream. A riparian right is a right of “use” – not ownership of the water, but a right to use the water, subject to the rights of other riparian owners (upstream and downstream) to likewise use the water.

(i) Measure of a Riparian Right – How Much Water Can Be Used

Two main common law doctrines have developed for dealing with riparian water rights in the east: the English common-law rule, also known as the natural flow doctrine, and the reasonable use doctrine.18 The prior appropriation doctrine, prevalent in the western U.S., has basically no application to water law in states east of the Mississippi.

Under the natural flow doctrine, each riparian proprietor of a watercourse has a right "to have the body of water flow as it was wont to flow in nature," qualified only by the right of other riparian proprietors to make limited use of the water.19 Put another

based upon the unknowable and occult nature of percolating groundwater, and shifting to the principles of the RESTATEMENT (SECOND) OF TORTS §858). 17 "Ripa" is Latin for river bank. A "riparian" owner is a person who owns the land along or under a defined stream. 18 WATER AND WATER RIGHTS § 7.02; STOEBUCK & WHITMAN, THE LAW OF PROPERTY (3d ed), §7.4, pp. 422-425. 19 RESTATEMENT (SECOND) OF TORTS, introductory note to §§ 850 to 857, p. 210.

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way, under the natural flow theory, each riparian owner along a waterbody is entitled to have the water flow across the land in its natural condition, without alteration by others of the rate of flow, or the quantity or quality of the water.20

The doctrine permits every owner to consume as much water as needed for "domestic" purposes, which generally means for personal human consumption, drinking, bathing, etc., and for watering domestic animals. Beyond this, the owner may use the water for "reasonable" artificial or commercial purposes, subject to the very large proviso that he may not substantially or materially diminish the quantity or quality of water. Certainly no water may be transported to land beyond the riparian land.21

While the natural flow theory may have served well in the agrarian society and areas of plentiful rainfall where it originated, the rule’s proscription against alteration or diminution of flow was not found well suited when faced with the demands of the industrial revolution – where dams were erected to harness water power, and irrigation and industrial enterprises arose involving consumptive diversions that could measurably change flow volumes. As a result, courts evolved various exceptions and adjustments to the natural flow theory, sometimes retaining reference to its words, while failing to follow its explicit tenants.22

Faced with the realities of industrial and commercial development, many states moved from the strictures of the natural flow theory to what became known as the “American rule” or “reasonable use” doctrine. Under the reasonable use doctrine, “a riparian owner may make any and all reasonable uses of the water, as long [as] they do not unreasonably interfere with the other riparian owners' opportunity for reasonable use.”23 Whether and to what extent a given use is allowed under the reasonable use doctrine depends upon the weighing of factors on the side of the prospective user, and balancing those considerations against similar factors on the side of other riparian owners. No list of factors is exhaustive, because “the court will consider all the circumstances that are relevant in a given case.”24 While in theory no single factor is conclusive, domestic uses are strongly favored and will generally prevail over other uses. Further, while the reasonable use doctrine as applied in some states may allow water to

20 1 WATERS AND WATER RIGHTS § 7.02(c), and cases cited therein at footnote 180. 21 STOEBUCK & WHITMAN at 422, quoted in Michigan Citizens for Water Conservation v. Nestlé Waters North America Inc., 269 Mich. App. 25, 54-55, 709 N.W.2d 174, 194 (2005). 22 1 WATERS AND WATER RIGHTS § 7.02(c); see, e.g., Dimmock v. City of New London, 157 Conn. 9, 245 A.2d 569 (1968) (reciting to the natural flow theory, but refusing to issue injunction prohibiting city’s diversion based upon a balancing of equities). 23 1 WATERS AND WATER RIGHTS § 7.02(c), and cases cited therein at footnote 180. 24 STOEBUCK & WHITMAN at 423; accord 1 WATERS AND WATER RIGHTS § 7.02(d)(3).

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be transported and used on non-riparian lands, such uses may be disfavored over uses on riparian land.25

Thus, under the reasonable use doctrine, each adjoining or overlying landowner has an equal right to make reasonable use of the water on the land which adjoins a surface stream, or overlies the subterranean stream.26 As the reasonable use doctrine was explained by the Michigan Supreme Court, as between two riparian owners, the natural flow rule did not strictly apply because “it is manifest it would give to the lower proprietor superior advantages over the upper, and in many cases give him in effect a monopoly of the stream.”27 Thus, under the reasonable use theory, it is not a diminution in the water quantity or flow that will provide a right of action, if in view of all the circumstances, the withdrawal and actions that cause alleged injury “is not unreasonable.”28 What constitutes a reasonable use is determined on a case-by-case basis, weighing a myriad of factors.29 The weighing of those factors may depend upon whether the dispute involves (1) two competing non-consumptive users; (2) a consumptive user (e.g., agricultural irrigation or industrial withdrawal) competing with one or more non-consumptive users (e.g., downstream boat liveries); or (3) competing consumptive users of similar or different nature.30

25 STOEBUCK & WHITMAN at 424; see also RESTATEMENT (SECOND) OF TORTS, introductory note to §§ 850 to 857, pp. 211-212. 26 1 WATERS AND WATER RIGHTS § 7.02(d). 27 Dumont v. Kellogg, 29 Mich. 420, 422 (1874). 28 Id. 29 The RESTATEMENT (SECOND) OF TORTS §850A attempts to lay out those factors to be weighed in determining a reasonable use, including (1) its purpose; (2) its suitability to the water body; (3) its economic value; (4) its social value; (5) the harm it causes; (6) the potential for coordination with competing uses; (7) its temporal priority relative to competing uses; and (8) the justice of imposing a loss on the use. It should be noted that considerable debate has occurred among legal scholars as to whether the “reasonableness” test is to be determined in the abstract, based upon some form of “objective” standard (as advocated by Frank Trelease, Associate Reporter for the RESTATEMENT (SECOND) OF TORTS), or is fundamentally grounded upon determination of reasonableness as a relative relationship between disputing parties. See 1 WATERS AND WATER RIGHTS § 7.02(d)(1)-(2). As noted by Professor Joe Dellapenna in his insightful summary of the issue, the determination of reasonableness in individual cases almost necessarily requires courts to compare the benefits and costs of one use against the benefit and costs of another, incompatible use, to determine which use is “reasonable.” Id. §7.03(d)(3). Such relative economic comparisons may include additional considerations of the costs to the plaintiff caused by the defendant’s conduct, compared to the cost to the defendant of modifying that conduct to accommodate or mitigate impacts upon the plaintiff. Id. 30 Id. § 7.03.

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Further, the courts in some states, faced with a choice between the English version of riparian doctrine (which favors protecting the natural flow of a stream), and the American rule (which focuses on the reasonable use of the actor, and the reasonable needs of others), have adopted a fusion (or perhaps confusion) of the two rules. For example, Pennsylvania precedent holds that a riparian owner may divert, use, and consume all of the water necessary for household and general domestic uses on the land, even if the flow of the watercourse/subterranean stream is measurably and materially diminished.31 If there is insufficient flow to maintain such domestic uses and other types of use, domestic uses have priority. Other uses, however, are classified as “extraordinary,” including diversions for manufacturing, power generation and recreational use. Under Pennsylvania case law, a riparian owner's use of water for such extraordinary purposes is limited to that quantity which is reasonable in view of the rights of other riparian owners, and which will not materially or perceptibly diminish the flow of the surface or subterranean stream.32

(ii) Can Water Be Transferred Off Riparian Land?

Depending on the jurisdiction, the right to transfer water off of the land adjoining the stream may be limited or even entirely proscribed. Some State cases treat off-land transfers of water withdrawn from a stream to be per se unreasonable,33 while others view such uses as merely disfavored or less favored than on land uses.34 However, the common law in virtually all states limits the “riparian right” to use of water within the same watershed from which it was extracted. For example, in Pennsylvania, a series of cases have ruled that withdrawals for uses off the land of origin (e.g., for a nearby city) are not ordinary and natural.35

At a common law approach where off-land uses are considered “unreasonable” and “unlawful,” liability for damages will be imposed if the withdrawal interferes with 31 Palmer Water Co. v. Lehighton Water Co., 280 Pa. 492, 124 A. 747 (1924) (domestic uses superior to mechanical and manufacturing uses); Philadelphia v. Philadelphia Suburban Water Co., 309 Pa. 130, 163 A. 297 (1932) (diversion for domestic uses superior to public right to navigation). 32 Palmer Water Co., 280 Pa. at 499-501, 124 A. at 750-752 ; see also generally Brown v. Kistler, 190 Pa. 499, 42 A. 885 (1889); Clark v. Pennsylvania R.R., 145 Pa. 438, 22 A. 989 (1891). 33 See Scranton Gas & Water Co. v. Delaware L. & W. R.R., 240 Pa. 604, 88 A. 24 (1913); Irving's Ex'rs. v. Borough of Media, 10 Pa. Super. 132 (1899), aff'd, 194 Pa. 648, 45 A. 482 (1900). 34 Michigan Citizens for Water Conservation, 269 Mich. App. at 57-58, 709 N.W.2d at 196. 35 Rothrauff v. Sinking Spring Water Co., 14 A.2d 87 (Pa. 1940); Hatfield Twp. v. Lansdale Municipal Authority, 19 Pa. D.&C. 2d 281 (C.P. Mont. 1959), aff'd, 168 A.2d 333 (Pa. 1961); Flowers v. Northampton Bucks Cty. Municipal Authority, 57 Pa. D.&C. 2d 274 (C.P. Bucks 1972).

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other users, and the water transfer may be enjoined by court order. Under this approach, development of a water supply well on one property to serve the needs of a Marcellus Shale development on another site would not be allowed, or would expose the enterprise to compensation claims or injunctive suits from other users in the area. The continued validity of this common law doctrine, however, is very much in question, particularly where basin commission permitting programs have been implemented that appear to largely displace the common law.36

(c) Common Law Rights in Percolating Groundwater

Most groundwater in the states overlying the Marcellus Shale is found in aquifers consisting of fresh water within saturated zones slowly percolating through the pore spaces and rock fractures.

As with riparian water law, three main common-law rights have developed with respect to groundwater withdrawal disputes: (i) the English rule of absolute ownership; (ii) the American doctrine of “reasonable use”; and (iii) the so-called doctrine of correlative rights.37

The first doctrine, referred to as the English rule or the absolute ownership rule, was first stated in Acton v Blundell.38 Under this rule, a possessor of land may withdraw as much underground water as he or she wishes, for whatever purposes desired, without liability to neighboring property owners. This absolute ownership rule ostensibly remains the law in a very small minority of states,39 and does not apply to the states encompassing the Marcellus Shale.

In the eastern U.S., including all of the states overlying the Marcellus Shale, the prevalent rule applicable to groundwater disputes is the doctrine of reasonable use, also sometimes called the American Rule.40 However, as interpreted by some state courts, the

36 As a result of State College Borough Water Authority v. Board of Supervisors of Benner Township, 645 A.2d 394 (Pa. Cmwlth. 1994) (“Benner I”), and Levin v. Board of Supervisors of Benner Township, Centre County, 669 A.2d 1063 (Pa. Cmwlth. 1995), aff’d per curium, 689 A.2d 224 (Pa. 1997) (“Benner II”), the continuing viability of the Rothrauff and Hatfield approach is in doubt. After Benner II, although not yet stated by the Pennsylvania courts, the better view may be that approval of a water allocation by the Pennsylvania Department of Environmental Protection, SRBC, or DRBC under their respective statutory powers is an action that accords an exception to the common law rule. 37 2 WATERS AND WATER RIGHTS Ch. 20-22; STOEBUCK & WHITMAN, § 7.5, p. 427. 38 12 Mees & Wels. 324; 152 Eng. Rep. 1223 (Exch, 1843). 39 See Sipriano v Great Spring Waters of America, Inc., 42 Tex. Sup. Ct. 629; 1 SW 3d 75 (Tex, 1999); Maddocks v Giles, 1999 ME 63, 728 A.2d 150, 153 (Me. 1999). 40 Wheatley v. Baugh, 25 Pa. 528, 531 (1855); Williams v. Ladew, 161 A. 283 (Pa. 1894); Pence v. Carney, 52 S.E, 702, 706 (W.Va. 1905); Cline v. American Aggregates Corp., 474 N.E.2d 324 (Ohio 1984) (overturning the common law theory of absolute ownership

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doctrine of reasonable use in the groundwater context is not actually dependent on the reasonableness of the use. Rather, as the doctrine has developed, it generally has been held that virtually all uses of water made upon the land from which it is extracted are “reasonable,” even if they more or less deplete the supply to the harm of neighbors, unless the purpose is malicious or the water simply wasted.41 The impact of the American Rule can sometimes be particularly harsh and surprising to laypersons. As late as 1957, for example, a Pennsylvania court ruled that a mine operator could dewater and lower water tables throughout an entire valley, with no responsibility for injuries to owners of domestic wells whose supply was thereby cut off.42

Under the American doctrine of reasonable use, groundwater use on overlying land is virtually unfettered, but when the question is whether water may be transported off that land for use elsewhere, this is usually found “unreasonable,” though it has sometimes been permitted. As observed recently by the Michigan Court of Appeals, “[a]uthorities are not all agreed, but a principle that seems to harmonize the decisions is that water may be extracted for use elsewhere only up to the point that it begins to injure owners within the aquifer.”43

The third doctrine is a variant of the reasonable use doctrine developed in California, often called the correlative rights doctrine.44 Under the correlative rights theory, owners of land within an aquifer are viewed as having equal rights to put the water to beneficial uses upon those lands. However, an owner's rights do not extend to depleting his neighbor's supply, at least not seriously, and in the event of a water shortage, a court may apportion the supply that is available among all the owners.

Thus, for the developer of Marcellus Shale gas reserves who wishes to use groundwater as a source, the key question becomes what variant of common law does each particular state follow. If situated in a jurisdiction whose law prohibits or strongly disfavors transfer of groundwater off the land where the well is located, siting and

in Frazier v. Brown, 12 Ohio St. 294 (1861) and adopting § 858 of the RESTATEMENT (SECOND) OF TORTS). 41 See, e.g., Wheatley v. Baugh, 25 Pa. 528, 531 (1855); Williams v. Ladew, 161 A. 283 (1894). 42 DiGiacinto v. New Jersey Zinc Co., 27 Lehigh L.J. 307 (C.P. Pa. 1957). With respect to mining impacts on water supplies, the DiGiacinto approach has been explicitly reversed by subsequent legislation. For example, under the Surface Mining Conservation and Reclamation Act and the Non-Coal Surface Mining Conservation and Reclamation Act, the mine operator who contaminates or diminishes a public or private water supply must restore or replace the affected supply. 52 P.S. §1396.4b(f); 52 P.S. §3311(g). 43 Michigan Citizens for Water Conservation, 269 Mich. App. at 59, 709 N.W.2d at 197, quoting STOEBUCK & WHITMAN at 428-429. 44 2 WATERS AND WATER RIGHTS §21.01 et seq.; STOEBUCK & WHITMAN at 429.

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development of supply sources may be challenging, unless one carefully addresses the concerns of the other stakeholders who may have standing to complain.

(d) The Restatement Rules for Surface Water and Groundwater

Various efforts have been made to explain, codify and reform eastern water law, as most notably reflected in the RESTATEMENT (SECOND) OF TORTS. The RESTATEMENT (SECOND) OF TORTS tracks common-law “reasonable use” principles for surface and groundwater use and withdrawal. However, the RESTATEMENT’s enunciation of the principles have not met with universal approval. Some states have cited the RESTATEMENT with approval, while other jurisdictions have either rejected its tenants or only partly embraced its concepts.

As to uses of surface water, a “reasonable use” under the Restatement generally “depends upon a consideration of the interests of the riparian proprietor making the use, of any riparian proprietor harmed by it and of society as a whole.”45 The RESTATEMENT also collects a series of common-law principles and sets forth a non-exclusive list of factors to consider in determining the reasonableness or unreasonableness of the proposed use, including: “(a) [t]he purpose of the use, (b) the suitability of the use to the watercourse or lake, (c) the economic value of the use, (d) the social value of the use, (e) the extent and amount of the harm it causes, (f) the practicality of avoiding the harm by adjusting the use or method of use of one proprietor or the other, (g) the practicality of adjusting the quantity of water used by each proprietor, (h) the protection of existing values of water uses, land, investments and enterprises and (i) the justice of requiring the user causing harm to bear the loss.”46

Similar to the American Rule, “[a] riparian proprietor is subject to liability for making an unreasonable use of the water of a watercourse or lake that causes harm to another riparian proprietor's reasonable use of water or his land.47 For “diffused” surface water, the Restatement provides that “[t]he possessor of land is not subject to liability for a use of surface water on his land that interferes with another person's use of the water, unless the use is made for the primary purpose of causing the harm.”48

Under Section 858 of the RESTATEMENT (SECOND) OF TORTS, landowners withdrawing groundwater generally have no liability for interfering with the use of water by another if the withdraw is “for a beneficial purpose.”49 Liability attaches, however, if “(a) the withdrawal of groundwater unreasonably causes harm to a proprietor of neighboring land through lowering the water table or reducing artesian pressure, (b) the withdrawal of groundwater exceeds the proprietor's reasonable share of the annual supply

45 RESTATEMENT (SECOND) OF TORTS § 850A. 46 Id. 47 Id. § 850. 48 Id. § 864. 49 Id. § 858.

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or total store of groundwater, or (c) the withdrawal of the groundwater has a direct and substantial effect upon a watercourse or lake and unreasonably causes harm to a person entitled to the use of its water.”50

(e) Interaction Between Surface and Ground Water

The separate common law doctrines developed to deal with disputes between competing users of surface water, or between competing uses of groundwater, face a major challenge when confronted with the interplay between surface and groundwater within the hydrologic system. As noted in our hypothetical above, a withdrawal of groundwater may impact springs or the baseflow of nearby streams. Conversely, the withdrawal from some surface water may impact the recharge of groundwater aquifers, or cause salt water movement in an estuary to come in contact with the recharge of a groundwater system (as has been the case with portions of the Potomac-Raritan-Magothy Aquifer in southern New Jersey).

Relatively few cases have tackled the nexus between ground and surface water, and those that have note the difficulty of reconciling sometimes diametrically inconsistent rules governing the two resources.

In Pence v. Carney,51 for example, the West Virginia Supreme Court tackled claims from a landowner whose surface spring (used in a hotel spa) was materially and directly impacted by the pumping of a new well on neighboring land. The evidence of an interconnection between the groundwater and spring/surface water was virtually undisputed. However, the court apparently viewed the matter as involving the application of groundwater law, and in the absence of evidence of an underground stream connecting the well and spring, the interference would not be actionable.52

In contrast, several New York cases opt for a seeming more “absolutist” view toward protecting surface waters. For example, in Stevens v. Spring Valley Water Works and Supply Company, 247 N.Y.S.2d 503 (N.Y. App. Div., 1964), the New York court found a public water supply company liable for damages where evidence indicated that the pumping wells intercepted groundwaters that had formerly fed a stream crossing the plaintiff’s property, causing it to go dry. Resting on the premise that the “right to use and enjoyment of a stream, running in a defined and natural channel, jure naturae, appertains to the riparian landowner,” the court reasoned that the fact that the diversion and 50 Id. Several states have explicitly adopted the RESTATEMENT’s version of the rule. See State v. Michels Pipeline Construction, Inc., 63 Wis. 2d 278, 299, 217 N.W.2d 339, 349 (1974); Henderson v. Wade Sand & Gravel Co., 388 So. 2d 900 (Ala. 1980); Cline v. American Aggregates Corp., 15 Ohio St. 3d 384, 387, 474 N.E.2d 324, 327 (1984). 51 58 W.Va. 296, 52 S.E. 702 (1905). 52 The case contains a discussion of “reasonable use” in the groundwater context, but the focus appears to be more upon the reasonableness of the well owner’s use for support of activities on his land, not the reasonableness of the interference with the spring owner’s rights of flow.

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diminution of the stream was caused by collecting underground waters which fed the stream “does not affect the question.”53 Thus, the New York court applied the riparian doctrine of protecting a stream owner’s interest to “natural flow” to impose liability on what would otherwise have been a fully legitimate groundwater withdrawal.

A 2006 decision by the Ohio Supreme Court, Portage County Board of Commissioners v. Akron,54 provides a different view of the groundwater / surface water connection issue. The court rejected claims of trespass asserted by Akron, as the holder of state-granted rights to take water from the Cuyahoga River. Akron complained that a municipal well field operated by Shalersville drew from an aquifer that would otherwise flow to the river, and therefore, infringed on Akron’s water right. Reasoning that Shalersville had a property interest in the groundwater underlying its land, the court found no basis for Akron’s position that it had “ownership of the groundwater … because it eventually finds its way into the Cuyahoga River ….”55 Interestingly, the Ohio court framed the question solely in terms of “ownership” rights and trespass law, rather than relative use rights involving interconnected resources.

The diametrically opposed approaches of providing essentially no protection to spring flow interferences on the one hand, or absolute protection to stream natural flows on the other, underscore the clash between traditional surface water and groundwater doctrines. On the one hand, the West Virginia and Ohio decisions provide little recognition of the essential support provided to surface flows from groundwater withdrawals. Conversely, the New York and Connecticut court decisions that accord protection against interference with natural stream flows by well pumpage seem to go beyond modern riparian doctrine – affording downstream riparian owners with more protection against stream diminution from well pumping than they might receive from diminution resulting from upstream direct surface water withdrawals.

The clash of doctrines problem is highlighted in the 2005 decision in Michigan Citizens for Water Conservation v. Nestlé Waters North America Inc.,56 where 53 247 N.Y.S. 2d at 511, quoting Smith v. City of Brooklyn, 160 N.Y. 357, 260-261, 54 N.E. 787, 788 (1899). 54 109 Ohio St. 3d 106, 846 N.E.2d 478 (2006). 55 Id. at 125, 846 N.E.2d at 496, citing McNamara v. Rittman, 107 Ohio St.3d 243, 838 N.E.2d 640 (2005) (landowners have property interest in groundwater underlying their lands, and governmental interference with that right can constitute a taking). 56 269 Mich. App. 25, 709 N.W. 2d 174 (2005), affirmed in part and reversed on other grounds, Michigan Supreme Ct. No. 130802, 130803 (July 25, 2007). The Michigan Supreme Court recently addressed only one aspect of the Court of Appeals decision, concerning whether the plaintiffs in that case had standing to bring a claim under the Michigan Environmental Protection Act (“MEPA”) as related to certain lakes, streams and wetlands. A closely divided state Supreme Court found that while the plaintiffs had sufficient standing to assert a MEPA claim as to impacts to Dead Stream and Thompson Lake, they had failed to allege injury in fact with respect to another lake or certain wetlands because there was no evidence that they used those areas or that their

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Michigan’s intermediate Court of Appeals was confronted with claims that groundwater withdrawals for a new bottled water facility would impact water levels in certain wetlands and the flow of the most interestingly named “Dead Stream,” to the alleged detriment of recreational and aesthetic interest of an environmental group’s members. In Michigan Citizens, the court parsed a “reasonable use balancing test” to deal with such cross-resource impacts. The court started with the observation that “in our increasingly complex and crowded society, people of necessity interfere with each other to a greater or lesser extent. For this reason, the ‘right to [the] enjoyment of . . . water . . . cannot be stated in the terms of an absolute right.’”57 The reasonable use balancing test recognizes that

virtually every water use will have some adverse effect on the availability of this common resource. For this reason, it is not merely whether one suffers harm by a neighbor's water use, nor whether the quantity of water available is diminished, but whether under all the circumstances of the case the use of the water by one is reasonable and consistent with a correspondent enjoyment of right by the other.58

Recognizing that the balancing test is a case-specific inquiry, the Michigan Citizens opinion suggests that under Michigan law there are three underlying principles that govern the balancing process. First, the law seeks to ensure a "fair participation" in the use of water for the greatest number of users, and accordingly, a court would attempt to strike a proper balance between protecting the rights of the complaining party and preserving as many beneficial uses of the common resource as are feasible under the circumstances. Second, the law will only protect a use that is itself reasonable. Third, the law will not redress every harm, no matter how small, but will only redress unreasonable harms. Therefore, a plaintiff must be able to demonstrate, not only that the defendant's use of the water has interfered with the plaintiff's own reasonable use, but also that the interference was substantial.59 Applying these principles, the balancing test would involve a weighing of numerous factors, including (1) the purpose of the use; (2) the suitability of the use to the location, including the nature of the water source and its attributes; (3) the extent and amount of the harm; (4) the benefits of the use; (5) the necessity of the amount and manner of the water use; and (6) any other factor that may bear on the reasonableness of the use, such as the impacts on the quantity, quality, and

recreational, aesthetic or economic interests had been injured by the water company’s pumping activities. Mich. Supreme Ct. slip op. at pg. 31. 57 Michigan Citizens for Water Conservation, 269 Mich. App. at 69, 709 N.W.2d at 202 (quoting Hart v. D’Agostini, 7 Mich. App. 319, 321, 151 N.W.2d 826 (1967)). 58 Id. (internal quotes omitted). 59 Michigan Citizens for Water Conservation, 269 Mich. App. at 69-70, 709 N.W.2d at 202-203.

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level of the water.60 The RESTATEMENT (SECOND) OF TORTS §850A recites a similar factor based balancing approach to determination of such water use conflicts.

3.5 Regulated Riparian Regimes

A number of states in eastern U.S., including several in the Appalachian Basin, have moved away from a pure common-law, water-rights arrangement to what has been termed a “regulated riparian” system of water rights management. Traditionally, not many eastern states had regulatory schemes governing water rights; most relied (and many still do) on many of the common-law principles outlined above.61 Western states typically experienced more regulation. Now, however, even eastern states have moved to regulated riparian systems.

The American Society of Civil Engineers published THE REGULATED RIPARIAN MODEL WATER CODE, which provides a comprehensive code designed for adoption by state governments (particularly states east of the Mississippi) “for allocating water rights among competing interests and for resolving other quantitative conflicts over water.”62 As stated in the preface to the Model Code, a number of eastern states have adopted some type of “regulated riparian” system.

An exhaustive review of regulated riparian regimes in individual states (both statutory enactments and regulatory implementation) is well beyond the scope of this paper. The following sections briefly review the current regulatory programs in some jurisdictions within the Appalachian Basin. In addition to state-level regulated riparianism, the Delaware and Susquehanna river basin compacts, and the commissions created under those compacts, establish pervasive basinwide management of water quality and quantity issues, which are discussed below. Also, I have included a short discussion of the Great Lakes – St. Lawrence River Basin Water Resources Compact, which as adopted in 2008 will affect future management of the nation’s largest fresh water resource.

(a) Kentucky

Kentucky is, by and large, a regulated riparian state but still relies to some degree on common law principles.63 In Kentucky, surface water is either “diffused” (which is not “public water” of Kentucky64) or “in a natural watercourse.”65 Groundwater is either “percolating” or is an underground stream.66

60 269 Mich. App. at 71, 709 N.W.2d at 202-03. 61 1 WATERS AND WATER RIGHTS § 9.01. 62 AMERICAN SOCIETY OF CIVIL ENGINEERS, THE REGULATED RIPARIAN MODEL WATER CODE iii (J. Dellapenna ed. 1997) (preface to the Model Code). 63 David Edward Spenard, Kentucky, in 6 WATERS AND WATER RIGHTS 607 (R.E. Beck ed. 2005). 64 Ky. Rev. Stat. § 151.120(2).

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The Water Resources Division of the Kentucky Environmental and Public Protection Cabinet regulates the use and transfer of “public water.”67 “Public water” – defined as “water occurring in any stream, lake, groundwater, subterranean water or body of water in the Commonwealth which may be applied to any useful and beneficial purpose”68 – is subject to permit requirements; other water is not.

(i) Permit System for Water Withdrawals

Since 1966, Kentucky has, by statute, required “any person, business, industry, city, county, water district or other political subdivision desiring to withdraw, divert or transfer public water” in excess of an average daily flow of 10,000 gpd69 to register with the Cabinet and apply for a permit.70 Exceptions to permit requirements include use of public waters by abutting landowners for domestic purposes71 and withdrawals for less than 10,000 gpd.72

(ii) Criteria for Granting Permits

The Cabinet has a duty to issue a permit to an applicant if, after investigation, the applicant has demonstrated the following: (1) “the quantity, time, place or rate of withdrawal of public water will not be detrimental to the public interest”73 (2) the withdrawal will not be detrimental to “the rights of other public water uses”;74 (3) issuing the permit would be “consistent with the administrative regulations promulgated by the Kentucky River Authority”;75 and (4) issuing the permit would be consistent with “the long-range water resource plan and drought response plans developed by the authority.”76

65 Ky. Rev. Stat. § 151.100 (definitions). 66 Id. § 151.100(5); Commonwealth, Dep’t of Highways v. Sebastian, 345 S.W.2d 46, 47 (Ky. 1961) (groundwater presumptively is “percolating”). 67 Id. § 151.120(1). 68 Id. 69 401 Ky. Admin. Regs. 4:010 (2006). 70 Ky. Rev. Stat. § 151.150(1). 71 Id. § 151.210(1). 72 Id. § 151.140. 73 Id. § 151.170(2). 74 Id. § 151.170(2). 75 Id. § 224.70-140. 76 Id.

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(b) New York

(i) Limited Statewide Permit Program for Certain Water Withdrawals

New York’s state level management program with respect to water allocation and withdrawals is limited. Currently, New York’s Water Resources Law (part of the Environmental Conservation Law) requires a permit from the New York Department of Environmental Conservation (“NYSDEC”) for the acquisition, development, use and distribution of water for (i) potable purposes (public water supply), (ii) agricultural irrigation,77 (iii) projects undertaken pursuant to Article 5-D of the County Law (relating to projects by small watershed protection districts); or (iv) multi-purpose projects undertaken pursuant to N.Y. Environmental Conservation Law §15-1101 et seq.78 Such permits are required prior to acquiring water supply or additional water supply from an existing source, using eminent domain to acquire new or additional sources of supply, commencing construction of projects in connection with proposed plans, and certain other activities associated with such regulated uses.79 Notably, the statewide water withdrawal regulatory provisions of the Water Resources Law are limited to public water supply and agricultural irrigation, leaving a substantial range of water using enterprises (including those relating to gas well drilling) outside the purview of the statute.

Separately, New York purports to specially regulate surface and ground water withdrawal projects designed to transport water to points outside the state by establishing a separate permit program for interstate diversions.80

(ii) Regional Permit Programs

In addition to these statewide permitting requirements, the Water Resources Law establishes several regional regulatory programs, including one addressing withdrawals within the Great Lakes/St. Lawrence River watersheds (which includes some sections of western New York covering the Marcellus Shales). New York requires reporting and registration of surface and groundwater withdrawals exceeding 100,000 gpd within the Great Lakes basin.81 Currently, in-basin use is only subject to registration, although the Water Resources Law indicates that if the NYSDEC registers a withdrawal resulting in a consumptive loss in excess of 5 MGD averaged over any 30-day period, the Department is required to implement prior notice and consultation with other Great Lakes states pursuant to the Great Lakes Charter.82 Withdrawals involving an interbasin diversion, 77 Although the statute mentions agricultural irrigation, the NYSDEC regulations are notably silent regarding the regulation of water withdrawals for irrigation. 78 N.Y. Envtl. Conserv. Law § 15-1501 (McKinney 2005). 79 Id. 80 Id. § 15-1505. 81 Id. § 15-1605. 82 Id. §15-1607.

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however, require state approval, as well as approval by the governor of each Great Lakes State pursuant to the Water Resources Development Act of 1986.83

Recently, New York State ratified the Great Lakes-St. Lawrence River Basin Water Resources Compact, discussed below. Under that Compact, New York will be proceeding to develop broader implementing legislation more strictly regulating water withdrawals within the Great Lakes Basin.

(iii) Proposed Regulation Under the Supplemental Generic Environmental Impact Statement

In mid-2008, the NYSDEC determined that prior generic environmental impact reviews conducted under New York’s Environmental Quality Review Act84 for oil and natural gas development activities were not sufficient to address the potential impacts associated with horizontal drilling and development of shale plays. The previously Generic Environmental Impact Statement prepared in 1992 did not contemplate non-conventional drilling and fracing techniques. Starting in mid-2008, New York entered a period of a virtual moratorium on shale gas drilling when a supplemental generic environmental impact statement (“SGEIS”) was prepared and vetted via an extensive public comment process.

NYSDEC issued a draft SGEIS85 in September 2009, inviting public comment on its proposed approach to regulating and mitigating a myriad of issues associated with shale gas development, ranging from water and wastewater, to air concerns. On the subject of water withdrawals, the draft SGEIS noted that while certain water withdrawals are currently regulated by the Delaware and Susquehanna River Basin Commissions (whose programs are described below), NYSDEC believed that neither SRBC or DRBC programs were adequate to regulate surface water withdrawals to product against reduced stream flows that might threaten fish and wildlife resources. The draft SGEIS proposed to regulate withdrawals for natural gas wells, requiring that such withdrawals be suspended when stream flows are less than 30% of the average daily flow (“ADF”) or average monthly flow of the stream. Such a “passby” flow condition would curtain withdrawals on most streams during much of the summer and fall seasons. Likewise, the SGEIS proposed to regulate groundwater withdrawals from locations proximate to streams and surface water bodies to ensure any effects on surface waters were acceptable.

As of this writing, although the public comment period on the draft SGEIS has closed, NYSDEC has not yet announced a final version of the SGEIS. The only clear announcement from the agency has been a press release indicating that any well drilling in the watersheds of the New York City reservoirs and the Skaneateles Lake watershed 83 Pub. L. 99-662, implemented by N.Y. Envtl. Conserv. Law § 15-1613. 84 New York Environmental Conservation Law Art. 8. 85 NYSDEC, Draft Supplemental Generic Environmental Impact Statement on the Oil, Gas and Solution Mining Regulatory Program (Sept. 30, 2009), available at http://www.dec.ny.gov/energy/58440.html.

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serving Syracuse would not be allowed to proceed under the generic EIS, but rather would require individual environmental impact evaluations for each proposed well.86

(c) Ohio

(i) Common Law with Legislative Guidance

Ohio continues, in large part, to rely upon common law doctrines governing surface and groundwater withdrawals. An interesting development, however, is that Ohio’s legislature, in a 1988 statute, provided specific guidance to Ohio courts concerning the determination of “reasonable use.” Ohio Revised Code §1521.17 adopts the principles of the RESTATEMENT (SECOND) OF TORTS, declaring:

(B) In accordance with section 858 of the Restatement (Second) of Torts of the American Law Institute, all of the following factors shall be considered, without limitation, in determining whether a particular use of water is reasonable:

(1) The purpose of the use;

(2) The suitability of the use to the watercourse, lake, or aquifer;

(3) The economic value of the use;

(4) The social value of the use;

(5) The extent and amount of the harm it causes;

(6) The practicality of avoiding the harm by adjusting the use or method of use of one person or the other;

(7) The practicality of adjusting the quantity of water used by each person;

(8) The protection of existing values of water uses, land, investments, and enterprises;

(9) The justice of requiring the user causing harm to bear the loss.

This statute, however, does not authorize the issuance of permits, but simply provides guidance to courts in applying the common law to disputes that may arise.

86 State Decision Blocks Drilling for Gas in Catskills, New York Times (April 23. 2010), available at http://www.nytimes.com/2010/04/24/science/earth/24drill.html.

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(ii) Limited Regulatory Programs

Ohio has adopted a limited permit program focused on large withdrawals, applicable to new or increased consumptive uses of more than 2,000,000 gallons per day averaged over any 30-day period.87 The criteria for permit issuance consider whether (1) public water rights in navigable waters will be adversely affected; (2) the facility’s current and proposed use incorporates maximum feasible conservation practices considering available technology and the nature and economics of various alternatives; (3) if the proposed withdrawal and use will reasonably promote protection of public health, safety and welfare; (4) whether the withdrawal will have a significant adverse impact on the quantity or quality of water resources and related land resources; (5) consistency with regional and state water resource plans; and (6) the sufficiency of water available for the withdrawal and protection of other existing legal uses of water resources.

Ohio Rev. Code §1501.32 prohibits the transfer of water in excess of 100,000 gallons per day out of the Ohio portions of the Lake Erie and Ohio River basins without a permit from the Ohio Department of Natural Resources (“DNR”). Criteria for such permits largely parallel those applicable to large consumptive uses, with the additional element of a required showing that reasonable efforts have been made to develop and conserve water resources in the important basin and that further development of those resources would engender overriding, adverse economic, social or environmental impacts.

Finally, Ohio Rev. Code §1521.16, requires persons who own facilities capable of withdrawing more than 100,000 gallons per day of surface or groundwater to register with the Ohio DNR, and report annually on monthly withdrawal volumes.

(d) Pennsylvania

In large part, in Pennsylvania the right to withdraw water from both surface and groundwaters in Pennsylvania is governed by common law, composed of the doctrines and precedents established by courts in cases decided over the past two centuries.88 With the exception of state laws regulating the withdrawal of surface water by public water

87 Ohio Rev. Code §1501.33. 88 R.T. Weston and J.R. Burcat, Legal Aspects of Pennsylvania Water Management, WATER RESOURCES IN PENNSYLVANIA: AVAILABILITY, QUALITY AND MANAGEMENT (1990). Basin level regulatory programs of the Susquehanna and Delaware River Basin Commissions have largely displaced the courts as the arbiters of water rights issues in the eastern two-thirds of the Commonwealth. However, common law doctrines and traditions remain strong. Because common law rests on individual cases read together, rather than a cohesive code, many gaps remain in the court decisions governing water rights.

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supply agencies, Pennsylvania has no statewide regulatory program mandating the acquisition of permits for withdrawing surface or ground waters. No state statute or regulatory program comprehensively addresses the allocation or use of ground or surface waters among competing users, or provides for long-term management of water resources. A few state statutes have attempted (or been interpreted) to impose regulations and permit requirements on withdrawals from specified sources and particular uses.

Notwithstanding these observations, with the onset of the Marcellus Shale development in 2008, the Pennsylvania Department of Environmental Protection (“PaDEP”) has claimed authority through a combination of the Pennsylvania Oil & Gas Act89 and Pennsylvania Clean Streams Law90 to review and approve “water management plans” governing water sources utilized by Marcellus Shale gas operators.

(i) 1939 Water Rights Act

The 1939 Water Rights Act91 requires that public water supply agencies wishing to withdraw water from surface sources, or to acquire rights in surface sources, first obtain a permit from PaDEP. For these purposes, a “public water supply agency” is defined to include any corporation, municipal or quasi-municipal corporation, district or authority vested with the power, authority, right or franchise to supply water to the public. Traditionally, this has been interpreted to apply to those entities that supply water to the public via pipes (as opposed to bulk or bottled water suppliers). The 1939 Water Rights Act does not regulate industrial, commercial or agricultural water users, and the Act does not cover groundwater withdrawals. It has been estimated that the 1939 Water Rights Act regulates only about 10% of the total surface water withdrawals in the Commonwealth.

(ii) Safe Drinking Water Act

The Pennsylvania Safe Drinking Water Act92 (“SDWA”), the state counterpart to the Federal Safe Drinking Water Act, was enacted primarily to address concerns regarding the quality of Pennsylvania’s drinking water supply. While the regulations adopted under the Pennsylvania SDWA are focused on setting water quality, design, construction and operating standards to assure safe and sanitary potable water, recent case decisions have drastically reinterpreted the statute to include consideration of the impacts of water withdrawals by public water supply systems.93 In terms of withdrawals by oil and gas well operators, however, the SDWA is not applicable.

89 PA. STAT. ANN. tit. 52, §601.101 et seq. (West 1996 and Supp. 2009). 90 PA. STAT. ANN. tit. 35, §691.1 et seq. (West 2003 and Supp. 2009). 91 PA. STAT. ANN. tit. 32, §§631-641 (West 1997). 92 PA. STAT. ANN. tit. 35, §721.1 et seq. (West 2003). 93 Oley Township v. PaDEP and Wissahickon Spring Water, Inc., 1996 EHB 1098.

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(iii) Water Well Drillers License Act

The Water Well Drillers License Act94 does not regulate water use, but focuses on the collection of groundwater information through the mandatory recording and filing of well location, penetrated strata, design and yield data. Water well drillers must obtain a permit from the Department of Conservation and Natural Resources, and each time they drill a well, licensed well drillers must file a completion report with DCNR’s Bureau of Topographic and Geologic Survey.

(iv) Water Resources Planning Act

The Water Resources Planning Act (“WRPA”),95 adopted in 2002, is focused on the preparation and updating of the State Water Plan and regional water plan elements to the state plan. The WRPA mandates the updating of the State Water Plan by March 2008, and periodic updating every five years thereafter. A part of that process involves the required registration and reporting of water use by more significant water users.

The WRPA moves away from the top-down, agency-dominated process toward a more collaborative planning process, with strong input from the regional (basin) level. The Act recognized that with proper planning, Pennsylvania’s water resources are capable of serving multiple uses in a balanced manner. Nothing in the WRPA authorizes or expands PaDEP’s authority to regulate, permit or control water allocations or water withdrawals.

The planning process is built around a Statewide Water Resources Committee, working with six Regional Water Resource Committees and PaDEP, in a multi-step process toward development of water plans for each region and the state. The six Regional Water Resource Committees are aligned on the basis of major watersheds,96 each with a membership appointed to represent a cross-section of stakeholders in the respective basins. The Statewide Committee’s membership includes a combination of six representatives from the regional committees, members appointed by the Governor from major interest segments, and certain state agency officials. The Statewide Committee, in consultation with PaDEP, has the lead in developing policies and guidelines for the preparation of the regional plans and State Water Plan. The regional committees, in turn, are to guide the development of regional components to the state plan. The State Water Plan and regional components are to include a number of mandatory elements, including:

An inventory of ground and surface water resources. An assessment and projection of withdrawal and non-withdrawal demands. Identification of potential water availability problems or conflicts between

users.

94 PA. STAT. ANN. tit. 32, §§645.1 et seq. (West 1997) 95 27 PA. CONS. STAT. §3101 et seq. 96 The WRPA establishes committees for the Ohio, Great Lakes, Upper Susquehanna, Lower Susquehanna, Potomac, and Delaware basins. 27 PA. CONS. STAT. §3113.

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Assessment of public water supply capabilities. Process of identifying projects and practices that conserve water, and process

for giving recognition to such efforts. Identification of practical alternatives for addressing availability problems,

adverse impacts, or use conflicts. Recommended actions, programs, policies, institutional arrangements,

projects and management activities. The WRPA further provides for the designation of “critical water planning areas,”

which are defined as any significant hydrologic unit where existing or future demands exceed or threaten to exceed the safe yield of available water resources.97 For these purposes, “safe yield” is defined on the basis of the amount of water that can be withdrawn from a water resource over a period of time without impairing the long-term utility of a water resource such as dewatering of an aquifer; impairing the long-term water quality of a water resource; inducing a health threat; or causing irreparable or unmitigated impact upon reasonable and beneficial uses of the water resources.98 Such a safe yield is to be determined based upon the predictable rate of natural and artificial replenishment of the water source over a reasonable period of time. In each critical water planning area, the regional water resource committee is to create a special advisory body, and proceed to prepare a critical area plan.99 That critical area plan must identify existing and future reasonable and beneficial uses, include a water availability evaluation, assess water quality issues that have a direct and substantial effect on water availability, identify existing and potential conflicts among users and adverse impacts on uses, and recommend practicable supply-side and demand-side alternatives for resolving such issues.

Ultimately, each regional plan and the entire State Water Plan are approved and must be periodically updated by both the Statewide Water Resources Committee and the Secretary of PaDEP. For the first five-year iteration of the State Water Plan, this process was recently completed with the approval of the plan in March 2009.100 However, the initial plan did not include the designation of any critical water planning areas, as the process of screening those areas had not yet been completed. Now one year later, all six of the regional committees have completed the process of recommending watersheds that might be designated as “critical,” and those recommendations are pending review by the Statewide Committee.

The adopted State Water Plan will have some degree of importance. The State Water Plan is already recognized as a mandatory consideration in some state regulations, such as in the preparation and approval of sewage facility plans under 25 Pa. Code Chapter 71. The WRPA further provides for the general use of the State Water Plan as a

97 27 Pa. Cons. Stat. §3112(a)(6). 98 27 Pa. Cons. Stat. §3102. 99 27 Pa. Cons. Stat. §3112(d). 100 39 Pa. Bulletin 1591 (March 28, 2009)

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policy and guidance document, providing information, objectives, priorities and recommendations to be “considered and weighed” in a broad range of decisions.101 Further, the plan is to be used to: (1) identify and prioritize water resource and water supply development projects; (2) provide information to public and private decision makers; (3) identify opportunities for improving operation of existing infrastructure; (4) guide development and implementation of policies and programs; and (5) guide policies on activities that directly and significantly affect the quantity and quality of water, with the objective of balancing and encouraging multiple uses of water resources.102

To gather and maintain up to date information on water use across the Commonwealth, §3118 of the WRPA requires the registration and reporting of water use by (i) any person who withdraws more than 10,000 gallons per day averaged over any 30-day period from any surface water or groundwater source; (ii) all public water supply agencies regardless of withdrawal amount; and (iii) each hydropower facility regardless of the withdrawal amount.103

In 2008, PaDEP finally promulgated rules under the WRPA governing monitoring, recordkeeping and reporting of water use.104 The rules both expand and further define the registration and reporting requirements. Registration and annual reporting of withdrawals and consumptive use is mandated by any person who withdraws more than 10,000 gpd averaged over any 30-day period from a surface or groundwater source or sources operated as a system, and by any person who obtains more than 100,000 gpd from another person (for example, via the purchase of water from, or a connection to, a public water system).105

For withdrawals, the trigger amounts are determined on the basis of the total amount withdrawn by a person from one or more points of withdrawal operated as a system. Thus, if a company has five wells in a given watershed, and uses them to supply a given facility, the total amount withdrawn over any 30-day period from those five wells must be counted together. Registrations and reports must be filed with PaDEP on forms (hard copy or electronic) provided by the Department.

The WRPA does not mandate metering in all cases. Where alternative methods exist to obtain a reasonably accurate evaluation of withdrawals and uses, the rules may allow for use of those alternative methods to obtain a reasonable estimate or indirect calculation.106 For smaller withdrawals of less than 50,000 gpd (except public water supply systems), the statute requires that the rules provide for use of alternative methods

101 27 Pa. Cons. Stat. §3116. 102 Id. 103 27 PA. CONS. STAT. §3118. 104 25 Pa. Code Ch. 110, 38 Pa. Bulletin 6266 (November 14, 2008). 105 25 Pa. Code §110.201. 106 27 PA. CONS. STAT. §3118(b)(1).

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of estimation or indirect calculation in lieu of direct metering or measurement.107 For most Marcellus Shale project withdrawals, however, metering will be expected.

(v) Regulation of Marcellus Shale Water Use via the Oil & Gas Act and Clean Streams Law

Despite the lack of a clear or comprehensive statutory enactment establishing a water withdrawal regulatory regime, PaDEP has nevertheless asserted the power to review and approve the water sources used in Marcellus Shale gas well development through a combination of the Pennsylvania Oil & Gas Act and the Pennsylvania Clean Streams Law.

The Pennsylvania Clean Streams Law108 does not provide directly for regulation of withdrawals, but focuses on discharges or activities that cause or may cause pollution. PaDEP has claimed under §691.401 (prohibition of other pollution) and §691.402 (potential pollution) to regulate withdrawals from Marcellus Shale wells to avoid depletion of stream flows that may cause “pollution.” Under the Clean Streams Law, “pollution” is broadly defined to include “contamination of any waters of the Commonwealth such as will create or is likely to create a nuisance or to render such waters harmful, detrimental or injurious to public health, safety or welfare, or to domestic, municipal, commercial, industrial, agricultural, recreational, or other legitimate beneficial uses, or to livestock, wild animals, birds, fish or other aquatic life, including but not limited to such contamination by alteration of the physical, chemical or biological properties of such waters ….”109 Citing the Pennsylvania Environmental Hearing Board’s decision in Oley Township v. PaDEP and Wissahickon Spring Water, Inc., supra, PaDEP takes the position that excessive water withdrawals which diminish stream flows and impact the physical, chemical, or biological properties of water bodies constitute pollution or potential pollution allowing the agency to assert regulatory jurisdiction. The manner and method by which it has done so raises some question, however, since the relevant sections of the statute call for PaDEP to either issue orders restraining pollution or potential pollution, or authorize the agency to require “by rule or regulation” to acquisition of permits regulating activities that may cause potential pollution.110 In this instance, PaDEP has not issued regulations on the subject, and has not (except in a few limited instances) issued any orders. Instead, PaDEP has attempted to graft its Clean Streams Law powers with its permitting authority under the Pennsylvania Oil & Gas Act, and has established a water source review system via administrative forms and guidance. The Pennsylvania Oil & Gas Act111 requires permits for the drilling or alteration of any natural gas well. The Act 107 Id. 108 Pa. Stat. Ann. tit. 35, §691.1 et seq. (West 2003). 109 Id. §691.1. 110 See Pa. Stat. Ann. tit. 35, §§691.401, 691.402. 111 Pa. Stat. Ann. tit. 58, §601.101 et seq. (West 1996 and Supp. 2009).

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requires PaDEP, in reviewing permit applications, to consider whether the proposed well would violate any environmental statutes administered by PaDEP (e.g., the Clean Streams Law). During 2008 and early 2009, PaDEP required operators to file an “Addendum” with well permit applications providing plans for water withdrawals. Effective April 2009, PaDEP has created a separate “Water Management Plan” process. Marcellus Shale well permits issued under the Oil & Gas Act now contain a standard condition requiring that any water withdrawn or obtained for fracing purposes be conducted pursuant to a Water Management Plan approved by PaDEP. Water Management Plans must (i) list the proposed sources (surface water, groundwater, wastewater, public water supplies); (ii) provide information about impacts of withdrawals from those various types of sources; and (iii) provide a monitoring and reporting plan. 112

(e) Virginia

(i) Statewide Permit Program for Surface Water Withdrawals

Effective February 6, 2008, Virginia has adopted regulations implementing a statewide permit program for surface water withdrawals via the Virginia Water Protection (“VWP”) permit program.113 Authorized by the Virginia Water Protection Act,114 and administered by the Virginia State Water Control Board (“VaSWCB”), the VWP permit program applies to virtually all new or increased surface water withdrawals involving greater than 10,000 gallons per day.115 Surface water withdrawals are divided into two categories: (1) “major” withdrawals involving greater than 90 million gallons per month,116 and (2) “minor” withdrawals involving more than 10,000 gallons per day but less than the major threshold.

New or expanded surface water supply projects subject to the permit program must publish a preapplication public notice with information on the project, provide an opportunity for public comment, and assist in identifying public concerns and issues prior to filing a permit application.117 Following the “preapplication” phase, a detailed permit application is required, including among other elements an evaluation of

112 See model format and instructions at:

http://www.dep.state.pa.us/dep/deputate/minres/oilgas/new_forms/marcellus/marcellus.htm. 113 9 Va. Admin. Code § 25-210-10 et seq. 114 Va. Code Ann. §§ 62.1-44.15 and 62.1-44.20 115 9 Va. Admin. Code §§ 25-210-50.A (permit requirement) and 25-210-60.B (exclusions for certain surface water withdrawals). 116 Id. § 25-210-10 (definition of “major surface water withdrawal”). 117 Id. § 25-210-75.B.

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beneficial uses and assessment of potential impacts.118 All VWP permits contain conditions mandating that the permittee take reasonable steps to minimize or prevent impacts which may have a “reasonable likelihood of adversely affecting human health or the environment,”119 a phrase which may well expand to addressing impacts on neighboring wells or water supplies. Surface water withdrawal permits are specifically subject to conditions relating to protection of instream flows, with consideration given to the seasonal needs of other water users, seasonal availability of surface water flow, and the cumulative effect of all withdrawals and consumptive uses.120 Surface water withdrawal permits may be issued if the withdrawal is not likely to have a detrimental impact on existing instream and off-stream issues, and will not cause or contribute to (i) significant impairment of state waters, fish or wildlife resources; (ii) adverse impacts on other existing beneficial uses; or (iii) violation of water quality standards.121

(ii) Permit Program for Surface Water Withdrawals from Designated Water Management Areas

A separate permit system in Virginia governing surface water applies only to those areas designated as surface water management areas by the VaSWCB. A surface water management area is “a geographically defined surface water area in which the VaSWCB has deemed the levels or supply of surface water to be potentially adverse to public welfare, health and safety.”122 Within a designated surface water management area, a permit is required for any person to make a withdrawal of surface-water,123 subject to four specific exclusions and certain exemptions.124 Excluded and exempted from the system are any non-consumptive uses, withdrawals of less than 300,000 gallons per month, and withdrawals from a wastewater treatment system permitted by the VaSWCB or the Department of Mines, Minerals and Energy. In addition, a person who has entered into an approved agreement does not need a permit.125 One of the most important exemptions, and one which creates a gap in the effectiveness of the water management area approach, excludes withdrawal in existence as of July 1989, unless the rate of withdrawal is increased.126

Currently, designated surface water management areas have not been established, and thus a special area surface water withdrawal permit program does not include any of

118 Id. § 25-210-80. 119 Id. § 25-210-90.C. 120 Id. § 25-210-110.A. 121 Id. 122 Va. Code Ann. § 62.1-242 (2009). 123 See 9 Va. Admin. Code § 25-220-70A. 124 Id. 125 Id. 126 Id. §25-220-70.C.1.a.

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the Appalachian western areas under which the Marcellus Shale formation is located. However, given the large quantities of water required for Marcellus Shale development, Virginia’s VWP statewide permit program would apply if surface water withdrawals greater than 10,000 gallons per day are contemplated.

(iii) Permit Program for Groundwater Withdrawals from Designated Water Management Areas

Virginia’s groundwater withdrawal permitting program only applies within designated groundwater management areas.127 An area may be designated as a ground-water management area by the VaSWCB if the board finds that groundwater levels in the area are declining or are expected to decline excessively, wells of two or more users are interfering, or may reasonably be expected to interfere substantially with one another, the available groundwater supply has been or may be overdrawn, or groundwater in the area has been or may become polluted. If one of those four criteria are met, and the board finds that public health, safety or welfare require regulatory efforts, the VaSWCB may proceed to define a groundwater management area.128 Within designated management areas, permits are required for any withdrawal of groundwater greater than 300,000 gallons per month. However, a number of exceptions are provided, including exemptions for groundwater remediation projects, and groundwater withdrawals coincident with the extraction of coal, oil, gas or other minerals.129

Currently, Virginia has designated groundwater management areas only in Eastern Virginia and the Eastern Shore area. The areas overlying the Marcellus Shale formation are not encompassed by the groundwater permit program.

(f) West Virginia

Presently, West Virginia has not adopted a regulatory program addressing either surface or groundwater withdrawals.

The Water Resources Protection Act130 establishes a water resource planning program, coupled with a water withdrawal registration and reporting program. The West Virginia Department of Environmental Protection (“WVaDEP”) is entrusted with conducting a water resources survey of consumptive and nonconsumptive surface and groundwater withdrawals across the state. Pursuant to those authorities, in December 2006, WVaDEP issued a Final Report Water Resources Protection Act Water Use Survey131 summarizing water use trends and conditions in the state. The Act imposes an obligation on those withdrawing water in quantities greater than 750,000 gallons per

127 Va. Code Ann. § 62.1-257 (West 2005). 128 Va. Code Ann. § 62.1-257. 129 Va. Code Ann. §§ 62.1-258 – 62.1-259. 130 W. Va. Code § 22-26-1 et seq. 131 http://www.wvdep.org/item.cfm?ssid=11&ss1id=722.

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month from one or more sources to register their water use and to provide WVaDEP with information regarding the location and quantity of water withdrawal, including seasonal withdrawal rates.132 However, the Act does not establish a permitting program, or any standards restricting the withdrawal or use of water. Hence, water withdrawals remain the exclusive province of common law.

Although West Virginia has not adopted a broad-based water withdrawal program, in March 2009, the WVDEP Division of Water & Waste Management issued draft guidance to Marcellus Shale operators indicating that it will require operators to submit anticipated withdrawal information as an addendum to well work permit applications for wells where fluid volumes requiring disposal exceed 5,000 barrels.133 At this point, the WVDEP has not moved beyond this to require actual review and approval of water sources.

As part of its water planning process, West Virginia’s environmental agency has developed a web-based tool that allows prospective water users, including natural gas developers, to identify streams where water may be available either generally or under certain flow conditions, or where withdrawals might present problems.134

(g) The Delaware River Basin Commission

(i) Delaware River Basin Compact

When adopted in 1961, the Delaware River Basin Compact135 was a unique document. It was the first compact not merely consented to by Congress, but in which the Federal Government became a full signatory party. While Federal agencies resisted the proposal, the states persisted in the belief that Federal membership was requisite to the effectiveness of the new regional entity. Congress agreed. The Compact created a new institution, the Delaware River Basin Commission (“DRBC”), composed of the Basin State Governors and a Presidential appointee (each with one alternate). With few exceptions, a vote of the majority binds all.

DRBC is granted broad powers to plan, develop, conserve, regulate, allocate and manage the water and related land resources of the Basin. In providing for the “joint exercise” of the sovereign rights of the signatory parties “in the common interests of the people of the region,”136 DRBC is directed to prepare and adopt a Comprehensive Plan

132 W. Va. Code § 22-26-3. 133 See WVDEP, Draft Industry Guidance, Gas Well Drilling/Completion, Large Water Volume Fracture Treatments (March 13, 2009) (available at http://www.wvdep.org/item.cfm?ssid=11) 134 See http://www.dep.wv.gov/WWE/wateruse/Pages/WaterWithdrawal.aspx. 135 Delaware River Basin Compact, Pub. L. No. 87-328, 75 Stat. 688 (1961). 136 Delaware River Basin Compact §1.3(b).

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“for the immediate and long range development and uses of water resources.”137 The Commission is further empowered to allocate water among the signatory states, providing the allocation could not constitute a prior appropriation of waters or confer any superiority of right.138

DRBC was created as a true management institution, with both regulatory and project development authority. The Compact explicitly recognizes that “[a] single administrative agency is ... essential for effective and economical direction, supervision and coordination of efforts and programs of federal, state and local governments and of private enterprise.”139 The Compact further declares as one of its fundamental purposes the objective “to apply the principal [sic] of equal and uniform treatment to all water users who are similarly situated … without regard to established political boundaries.”140 With these objectives, DRBC is conferred the power to adopt and enforce standards and rules covering the broad spectrum of water quantity and quality issues.141

(ii) DRBC Project Review

As a central mechanism for implementing these regulatory powers, DRBC is authorized under §3.8 of the Compact to regulate and approve any “project” having a substantial effect on the water resources of the Basin, to assure consistency with the Commission-adopted comprehensive plan, and “the proper conservation, development, management or control of the water resources of the basin.” The term “project” is very broadly defined by the Compact to include

any work, service or activity which is separately planned, financed, or identified by the commission, or any separate facility undertaken or to be undertaken within a specified area, for the conservation, utilization, control, development or management of water resources which can be established and utilized independently or as an addition to an existing facility, and can be considered as a separate entity for purposes of evaluation.142

Under this provision, DRBC regulates a broad spectrum of projects that may affect the quality and quantity of water resources within the basin. Projects subject to commission review and approval include, among others:

137 Delaware River Basin Compact §13.1. 138 Delaware River Basin Compact §3.3. 139 Delaware River Basin Compact §1.3(c). 140 Delaware River Basin Compact §1.3(e). 141 Delaware River Basin Compact §§ 3.6(b) (standards for planning, design and operation of all projects and facilities in the basin which affect basin water resources), 5.2 (water quality standards), 5.4 (water quality enforcement), 6.2 (flood plain zoning). 142 Delaware River Basin Compact § 1.2(g).

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All surface and groundwater withdrawals exceeding 100,000 gallons per day (gpd) in any 30-day period.

Construction or alteration of industrial wastewater treatment facilities or domestic sewage treatment facilities involving a design capacity 50,000 gpd.

The diversion (exportation or importation) of water from or to the Delaware River Basin whenever the design capacity is greater than 100,000 gpd.

Impoundment of water. 143

In May 2009, DRBC’s Executive Director issued a “jurisdictional determination”144 extending the Commission’s project review authority to all natural gas extraction projects located in shale formations within the drainage area of special protection waters designated by DRBC (that is, most of the upper and middle Delaware Basin).145 DRBC has defined the “project” to encompass “the drilling pad upon which a well intended for eventual production is located, all appurtenant facilities and activities related thereto and all locations of water withdrawals used or to be used to supply water to the project.”146 Thus, irrespective of the amount of water to be utilized, all Marcellus and other shale gas projects will trigger project review and approval requirements, and DRBC approvals are required prior to commencement of any development activities. More recently, DRBC extended this definition of project to include exploration wells, and announced a moratorium on process gas well drilling projects until regulations are finally adopted setting forth the standards for well project approvals.147

The central criterion governing approval of projects is whether the project proposal is consistent with the Delaware River Basin Comprehensive Plan. More specifically, DRBC is required to approve a project if it determines that the project “would not substantially impair or conflict with the comprehensive plan.”148 The Comprehensive Plan encompasses a wide range of regulations and policies, most of which are now compiled as part of the DRBC Water Code.149 Project review with 143 18 C.F.R. §401.35(b). 144 “Jurisdictional determinations” represent findings by the DRBC Executive Director under 18 C.F.R. §401.35(a) determining that projects of a classification otherwise deemed not to have a substantial effect upon water resources (such as withdrawals of less than 100,000 gpd) are nevertheless found to have or may have a substantial effect on basin water resources and therefore require basin commission review and approval. 145 DRBC, Determination of the Executive Director Concerning Natural Gas Extraction Activities in Shale Formations within the Drainage Area of Special Protection Waters (May 19, 2009) (available at http://www.state.nj.us/drbc/naturalgas.htm). 146 Id. at 2. 147 See notices posted at http://www.state.nj.us/drbc/naturalgas.htm. 148 Id.; see also Delaware River Basin Compact § 3.8. 149 The Delaware River Basin Water Code is currently available on line at: www.state.nj.us/drbc/regula.htm.

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respect to withdrawals includes consideration by DRBC of such factors as the need for the proposed withdrawal, alternative sources available, impacts on other uses in the area and on instream uses downstream of the point of extraction, proposed mitigation measures, implementation of conservation measures, and other issues. DRBC’s general approach to water withdrawals looks at not only individual withdrawal proposals, but the overall cumulative situation in the watershed or aquifer in question.

ater withdrawals.

Fundamentally, DRBC allocates water based upon the doctrine of equitable apportionment.150 During drought emergencies, DRBC has established a series of water use priorities, with first priority being given to uses which sustain human life, health, and safety, and second priority to uses needed to sustain livestock. After those priorities, water is to be allocated based on equitable apportionment, among producers of goods and services, food and fibers, and environmental quality in a manner designed to sustain the general welfare of the basin and its employment at the highest practical level.151

Water conservation policies applied to both new and existing uses. The DRBC Water Code requires maximum feasible efficiency in water use by new industrial, municipal, and agricultural users, and eventual application by existing users of those water-conserving practices and technologies that can feasibly be employed.152 How these criteria will be applied to Marcellus Shale gas well projects remains to be determined; but one should expect DRBC to encourage strongly the maximum feasible reuse of flowback and produced waters, and the minimization of fresh w

Projects involving the export of wastewater from Marcellus Shale well development may engender DRBC project review as to water exports.153 DRBC policy reflects a finding that the waters of the basin are limited in quantity and that the Basin is frequently subject to drought water and drought declarations due to limited water supply storage and streamflow during dry periods. Commission policy “discourages” the exportation of water from the basin. In review of projects involving export of water, DRBC considers assessments of the resource, the economic impacts of the project and of all alternatives to any export or import. Such projects are subject to evaluation of particular factors, including (1) effort to first develop, use and conserve the resources outside of the basin; (2) water resource impacts of each alternative available; (3) economic and social impacts of the import or export of water and each of the available alternatives; (4) the amount, timing and duration of the proposed transfer and its

150 Delaware River Basin Water Code § 2.5.1. 151 Id. § 2.5.2. 152 Id. § 2.1.2A-C. 153 As of this writing, DRBC has not issued specific guidance on whether or not it considers the export of natural gas well flowback water to constitute a water export, but some Commission staff have signaled that DRBC may well consider the transfer of wastewater out of the basin to trigger water export review criteria.

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relationship to passing flow requirements and other hydrologic conditions; and (5) benefits that may accrue to the basin as the result of the proposed transfer.154

Water quality, as well as quantity, impacts are likely to be a significant issue in project reviews of Marcellus Shale well projects. Much of the Delaware Basin containing Marcellus Shale has been designed as “special protection” waters for water quality purposes,155 and is subject to stringent restrictions on both point source discharges and non-point pollution controls (e.g., erosion and sedimentation, and stormwater controls). Minimization of land disturbance, non-point pollution control measures, and management of flowback wastewaters, and cumulative impacts are anticipated to be questions of concern during the review process.

In addition to basinwide project review authority, the Compact grants the Commission special powers to designate “protected areas” where withdrawals are exceeding, or threaten to exceed, available resources or conflict with the Basin comprehensive plan. Growing concerns regarding potential overuse of aquifers in southeastern Pennsylvania led DRBC in 1981 to designate the Southeastern Pennsylvania Groundwater Protected Area.156 Within the area largely defined by Triassic formations, new or increased groundwater withdrawals exceeding 10,000 gpd are subject to strict review, including the requirement for sophisticated pump testing and hydrologic analyses prior to permitting. The aggregate of new and existing withdrawals are managed within “withdrawal limits” for the affected aquifers or sub-basins, to assure that total takings do not exceed the rate of groundwater recharge during normal or dry periods. DRBC has undertaken to further define the “withdrawal limits.” DRBC has established numeric withdrawal limits for each significant sub-basin, based on the 1-in-25-year average annual baseflow rate. Where total withdrawals in a watershed exceed 75% of this value, the watershed is designated as “potentially stressed.” In such potentially stressed sub-basins, the rules require that applicants include one or more programs to mitigate the adverse impacts of a new or expanded withdrawal.

154 Id. § 2.30.4. Given these considerations, the fact is that a number of intra-watershed and interbasin transfers have been implemented, including New York City’s diversion of 800 mgd from the upper basin under the terms of the U.S. Supreme Court’s consent decree in New Jersey v. New York; a 100 mgd transfer by New Jersey to serve the northeastern New Jersey communities; a 60 mgd transfer from the Susquehanna Basin to the City of Chester area (west of Philadelphia); and various municipal system transfers involving communities that straddle the basin divides. Within the basin, numerous withdrawals involve transfers of water between the subbasins and watersheds that comprise the overall Delaware Basin, including transfers that have been specifically undertaken to relieve over-pumping of certain aquifers in developed areas. Thus, discouragement of basin transfers does not amount to a prohibition, and each project is judged on its own merits.

155 See Delaware River Basin Water Code §3.10.3A, incorporated by reference in 18 C.F.R. Part 410. 156 18 C.F.R. Part 430.

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In addition, as part of a protected area permit application, the project sponsor must show that the proposed withdrawal will not “significantly impair or reduce the flow of perennial streams in the area.”157 Under the Protected Area regulations, DRBC takes specific steps to consider and protect existing water users whose wells may be affected by newer, deeper and more powerful neighbors. Where interference is predicted or observed, new users are required to limit withdrawals in order to avoid interference, or to provide compensation (in the form of replacement water supplies) where interference is unavoidable.158 Thus, DRBC attempts to promote efficient development of the resource, while protecting the reasonable expectations and investments of current users.

DRBC is further empowered to declare emergencies and impose restrictions on water withdrawals and diversions (including suspension of State-issued water rights) during such periods.159 In both protected areas, and during emergencies, DRBC’s authority to grant, modify or deny permits is guided by standards found in Compact §10.5, which calls for actions “so as to avoid such depletion of the natural stream flows and groundwaters … as will adversely affect the comprehensive plan or the just and equitable interests and rights of other lawful users of the same source, giving due regard to the need to balance and reconcile alternative and conflicting uses in the event of an actual or threatened shortage of water of the quality required.” In effect, DRBC is granted plenary authority to reallocate and regulate waters within protected areas and during emergencies so as to balance all legitimate uses of water within the basin or particular affected area.

(h) Susquehanna River Basin Commission

(i) Susquehanna River Basin Compact

The Susquehanna River Basin Compact160 was developed nearly a decade after the Delaware Compact, stimulated in part by concerns among some that the thirsts of the eastern seaboard metropolis might cause some (notably New York City) to look to the Susquehanna's headwaters as a new source for diversions. Indeed, at least one such “flood skimming” project was proposed to serve New York.

Although the Compact was adopted in 1970, the Susquehanna River Basin Commission (SRBC) actually came into being in 1972. SRBC is essentially modeled on DRBC, with membership by the United States, New York, Maryland and Pennsylvania.

Although SRBC's powers are nearly identical to those of the Delaware Commission, the emphasis of Commission activities and the development of Basin programs have been different. Notably, the Susquehanna is the largest U.S. river flowing into the Atlantic, and its mixture of urban, suburban, agricultural and forest areas presents 157 18 C.F.R., § 430.13(d)(4). 158 18 C.F.R. §§ 430.13(d)(5), 430.19. 159 Delaware River Basin Compact §§ 10.4, 10.8. 160 Susquehanna River Basin Compact, Pub. L. No. 91-575, 84 Stat. 1509 (1970).

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a far less dense population distribution. However, major water users are found up and down the basin, and the river provides a major source of water for diversions and interbasin transfers that serve portions of the lower Delaware Basin and the Baltimore/northern Maryland metropolitan and suburban areas.

SRBC has developed a fairly sophisticated groundwater management program,161 including regulation of all significant groundwater withdrawals in a program which considers both the aquifer and associated surface water impacts of all proposed well development projects.162

For the past three decades, SRBC has expressed concern for the impact of growing consumptive uses in the basin, and resulting lowering of drought flows for in-stream water quality and water balance in the Chesapeake Bay. Considerable effort has been expended in the past two decades on reallocation/reformulation of storage in existing reservoirs in order to make room for flow augmentation storage.

(ii) Project Review and Regulatory Powers

Specific SRBC regulatory programs target the management of new and increased withdrawals and consumptive uses. SRBC requires project approval for (1) all surface and groundwater withdrawals in excess of 100,000 gpd in any 30-day period;163 (2) any new or increased consumptive water use in excess of 20,000 gpd irrespective of its source of supply;164 and (3) all projects (irrespective of water quantity) involving the withdrawal and consumptive use of water for development of natural gas wells targeting the Marcellus and Utica Shale formations.165 SRBC requires approval of a natural gas project prior to commencing any project construction, defined as either spudding any well or commencing construction of any water-related facility (for example, water withdrawal, water storage, or water conveyance structures).166 Notably, project review may be triggered not only by the drilling of new wells, but also by the “re-completion” of

161 On July 7, 2006, the SRBC published a notice of proposed rulemaking to amend 18 C.F.R. parts 803, 804, and 805. After the comment period, the SRBC made revisions to its proposals, adopted a final rule on December 5, 2006, and published notice of its final rulemaking at 71 Fed. Reg. 78,570 (December 29, 2006). The final rule was set to take effect on January 1, 2007; however, the effective date was temporarily suspended as the result of litigation. Pennsy Supply, Inc. v. SRBC, U.S. Dist. Ct. M.D. Pa., No. 1:06-CV-02454, Order (Dec. 29, 2006) (stay pending further order of court). The temporary suspension has been lifted and the regulations have taken effect. 162 18 C.F.R. § 806.23. 163 18 C.F.R. § 806.4(a)(2)(i). 164 18 C.F.R. § 806.4(a)(3). 165 18 C.F.R. §806.4(a)(8), 73 Fed. Reg. 78618 (Dec. 23, 2008). 166 18 C.F.R. §806.3 (definition of “construction”), as amended at 73 Fed. Reg. 78618, 78620 (Dec. 23, 2008).

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previously developed gas wells to allow for extraction from the Marcellus or Utica Shale formations.

For Marcellus Shale projects, project approvals associated with stream or ground water withdrawals require “dockets” approved by the full Commission following public hearing. Because the Commission meets only 4-5 times per year, this process can be time-consuming and requires a good deal of advance planning. For consumptive water use associated with well projects, however, SRBC has adopted an “approval-by-rule” (“ABR”) procedure which allows Commission staff to issue administrative approvals without the need for action by the full Commission.167 Consumptive use ABRs are required for each well pad, irrespective of whether the water source involves a stream, groundwater well, water purchased from a public water supply system, or use of wastewater, mine water, or another type of water source. Such an ABR may be sought by submission of a notice of intent, coupled with issuance of a prescribed notice to the public, after which SRBC staff will issue an approval usually within 10-14 days.

Although SRBC regulations provide a process for transfer of previously-issued project approvals upon change of ownership of the project, subject to prior notice to SRBC,168 such a transfer may trigger a “review” and modification of the prior approval in a variety of situations, including where the prior approval was more than 10 years old, or where the prior project approval did not include all ground and surface water sources or uses (e.g., some were “grandfathered”).169 Where facilities that did not previously require a project approval because their withdrawal or consumptive use predated the SRBC compact regulations, the new owner must submit a project approval application to SRBC prior to the date of ownership change,170 and the use by the new owner will be subject to SRBC’s full project review process and standards.

SRBC has established particular “standards” governing consumptive uses of water within the Susquehanna Basin,171 which apply to all consumptive uses that involve more than 20,000 gpd over any 30-day period and that were initiated or increased after January 23, 1971. For these purposes, a “consumptive use” is defined to mean the “loss of water transferred through a manmade conveyance system or any integral part thereof (including such water that is purveyed through a public water supply or wastewater system), due to transpiration by vegetation, incorporation into products during their manufacture, evaporation, injection of water or wastewater into a subsurface formation from which it would not reasonably be available for future use in the basin, diversion from the basin, or any other process by which the water is not returned to the waters of the basin undiminished in quantity.”172 Consumptive uses include, for example, virtually 167 18 C.F.R. §806.22(f). 168 18 C.F.R. §806.6. 169 18 C.F.R. §806.6(c)-(d). 170 18 C.F.R. §806.4(c) 171 18 C.F.R. § 806.22. 172 18 C.F.R. § 806.3).

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all water used at a Marcellus Shale well, including water for drilling, fracing, and dust control.

Under the SRBC rules, regulated consumptive users (including all Marcellus Shale projects) must either curtail their consumptive use during “low flow” periods (as may be designated by the Commission), or must provide compensation for that use.173 In practice, such compensation may be provided by one of several methods, including development of storage facilities and provision of releases from those facilities during low-flow periods; purchase of available water supply storage from existing facilities; use of water from a public water supplier that maintains a conservation release or flow-by approved by SRBC; use of groundwater; or other means approved by SRBC.174 In lieu of providing such compensation, a user may provide payments to SRBC under a set fee schedule, and SRBC, in turn, utilizes those funds for the operation of several storage facilities acquired by the Commission to provide for streamflow augmentation during low-flow period.

(iii) Passby Flow and Conservation Release Requirements

As a guide used in administering its project review authority, in late 2002, the SRBC adopted guidelines governing the determination of passby flows and conservation releases for surface and groundwater withdrawal projects.175 The SRBC uses passby flows, conservation releases, and consumptive use compensation to protect aquatic resources, competing users, and instream flow uses downstream from the point of withdrawal.176 Passby flow requirements mandate that, while water is being withdrawn, a specified amount of water must be allowed to pass a certain point downstream from the point of withdrawal.177 Approved surface-water withdrawals from small impoundments, intake dams, continuously flowing springs, or other intake structures in applicable streams will include conditions that require minimum passby flows.178 Additionally, approved groundwater withdrawals from wells that impact streamflow, or for which a reversal of the hydraulic gradient adjacent to a stream (within the course of a 48-hour pumping test) is indicated, also will include conditions that require minimum passby flows.179

173 18 C.F.R. § 806.22(b). 174 18 C.F.R. § 806.22(b). 175 SRBC, Guidelines for Using and Determining Passby Flows and Conservation Releases for Surface-Water and Ground-Water Withdrawal Approvals, Policy No. 2003-001 (November 8, 2002). 176 Id. 177 Id. 178 Id. (emphasis added). 179 Id.

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There are three narrowly tailored exceptions to the SRBC passby flow requirements. First, an exception is provided in cases where the surface-water or groundwater withdrawal, has only a minimal impact in comparison to the natural or continuously augmented flows of a stream or river.180 The SRBC defines minimal impact as 10 percent or less of the natural or continuously augmented Q7-10 low flow of the stream or river.181 Second, an exception may be provided where the project in question requires Commission approval and a passby flow would be required under the guidelines, “but where a passby flow has historically not been maintained.”182 In these cases, withdrawals exceeding 10 percent of the Q7-10 low flow will be permitted whenever flows naturally exceed the passby flow requirement plus the taking.183 When streamflows do not naturally exceed the passby flows, the rate of withdrawal and quantity allowed are reduced to less than 10 percent of the Q7-10 low flow. This procedure is allowed for a period of four years from the approval date, and during this period the project sponsor should develop additional storage or supplies that will allow for withdrawals while still maintaining the passby flow requirement.184 In such cases, within two years from the SRBC approval date, the project sponsor will be required to file a plan outlining the proposed development of additional on-site storage or s 185upplies.

The method of determining passby flow for streams that support trout populations is based upon the SRBC’s Instream Flow Studies Pennsylvania and Maryland (May 1998) publication. That publication reflects studies which applied Instream Flow Incremental Methodology (“IFIM”) to evaluate cold water fish habitat impacts in a sampling of streams in several hydrologic regions of Pennsylvania and Maryland, arriving at a surrogate model to be applied to other streams in assessment predicted “habitat loss.” The SRBC policy pegs the acceptable amount of habitat loss depending upon the classification of the stream. Less than 5% habitat loss is allowed for exceptional value streams. Generally, less than 5% loss (or at most 7.5% habitat loss) is allowed for high quality waters. Passby flows to prevent more than 10 or 15% habitat loss would be imposed on streams with lower classifications supporting trout populations. For areas of the basin that do not support trout populations, the SRBC passby flow policy sets levels generally ranging from 15 to 25 percent of average daily flow.186In no case is the passby flow less than the Q7-10 flow.187

180 Id. 181 Id. at pg. 2. 182 Id. 183 Id. 184 Id. 185 Id. 186 Id. at pg. 6. 187 Id. at pg 3-4.

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In lieu of the “desktop” methodology set forth in the SRBC passby flow policy, the policy allows a project sponsor to provide an instream flow study to demonstrate that lower passby flows and releases will provide an acceptable level of aquatic habitat protection. Exceptions may also be provided if the applicant can demonstrate that there are no viable alternative supplies available, or if after coordination, another acceptable passby flow criterion can be established.188

Conversely, pursuant to SRBC regulations §§ 803.43(a)(1) and 803.44(a)(1), the Commission may increase the passby flow requirement for any project when water quality or sensitive environmental resources may be adversely effected.189

Conservation releases only come into play with surface-water withdrawals made from a large impounding structure.190 A conservation release imposes a requirement to actually augment stream flows by releases from storage. Such augmentation may occur not only during low flow periods, but also during more normal flow regimes. When this is the case, “the conservation release shall be equal to, or greater than, the Commission’s low flow criterion.”191

(iv) Enforcement and Sanctions

SRBC has taken an aggressive enforcement posture in relation to Marcellus Shale gas well projects, as well as other projects subject to basin commission review. The SRBC Compact allows for imposition of civil penalties in an amount up to $1,000 per day for each violation of the Compact and implementing regulations.192 Applying these provisions, SRBC has invoked its enforcement authority in a number of situations where gas well projects were commenced prior to obtaining commission approval, extracting settlements that have ranged upward to around $500,000 per company for situations involving multiple violations. SRBC staff have expressed a view that given the number of communications it has directed to companies engaged in gas well development reminding entities of the basin commission’s jurisdiction, proceeding with project development absent proper approvals will be counted in most cases as “willful.”

(i) Great Lakes – St. Lawrence River Basin Water Resources Compact

The northwestern portion of the Marcellus Shale formation lies within the Great Lakes-St. Lawrence River Basin in sections of western New York, northwestern Pennsylvania, and northeastern Ohio.

188 Id. at pg. 7. 189 Id. at 2. 190 Id. 191 Id. 192 SRBC Compact §15.7.

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In late 2008, Congress provided its consent and the President signed the Great Lakes-St. Lawrence River Basin Water Resources Compact (“GLSL Compact”),193 which had been previously enacted by concurrent legislation adopted by the eight Great Lakes States. The GLSL Compact establishes a statutory and regulatory framework for imposing substantial additional regulatory controls on water withdrawals involving Great Lakes Basin waters, including withdrawals from the lakes themselves, streams within the basin, and groundwaters within the Great Lakes and St. Lawrence River watersheds. The key elements of this program include:

Registration. All existing water withdrawals greater than 100,000 gallons per day in any 30-day period are required to register with their states. Criteria applied through this process will be used to define the “grandfathered” amount of those existing withdrawals (thereby establishing a baseline defining future increases that may trigger permit requirements).

Water Withdrawal Permitting. States are required to establish permitting programs regulating new or increased withdrawals above to-be-defined trigger levels. In the absence of arriving at another trigger, the default would be 100,000 gallons per day over any 30-day period. Such withdrawals may be approved only if they meet prescribed minimum criteria (referred to as the “decision-making standard”).

Decision-Making Standard. The GLSL Compact embraces a decision-making standard, with the commitment that each jurisdiction would review regulated withdrawals consistent with that standard. The decision-making standard in §4.11 of the GLSL Compact requires a determination that the proposed use is reasonable, considering a series of factors, including (a) whether the withdrawal is planned in a fashion that provides for efficient use of the water and will avoid or minimize waste; (b) whether efficient use is being made of existing water supplies; (c) the balance between economic development, social development and environmental protection; (d) the supply potential of the water source, considering quantity, quality, reliability and safe yield of hydrologically interconnected water sources; and (e) the probable degree and duration of any adverse impacts to other lawful consumptive or non-consumptive water uses or to the quantity or quality of the waters and water dependent natural resources, and proposed plans or arrangement for avoidance or mitigation of such impacts. Other criteria require that each withdrawal or consumptive use incorporate “environmentally sound and economically feasible water conservation measures”; and mandate that the withdrawal and consumptive use be implemented so as to ensure that the proposal will result in “no significant individual or cumulate adverse impacts” to the

193 Pub. Law 110-342, 122 Stat. 3749.

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quantity or quality of waters and water dependent natural resources of the basin on the applicable source watershed.

Notably, some aspects of the decision-making standard were controversial as the proposed compact was introduced and debated in several of the state legislatures. In particular, the meaning and scope of the “no significant impact” language has raised considerable questions and concern.

Out-of-Basin Diversions and Intra-Basin Water Transfers. With limited exceptions, the GLSL Compact prohibits out-of-basin diversions of water; and transfers of water between the subbasins of the Great Lakes will be restricted. Subject to some high regulatory standards, use of basin waters by straddling communities will be permitted. All proposals involving out-of-basin diversions or transfers between subbasins of the Great Lakes would be subject to review by a regional body (involving the states and provinces), with a determination of findings to be presented back to the host state or province. Under the GLSL Compact, out-of-basin diversions and transfers between the lakes are further subject to review and approval by a Regional Council, composed of the eight Great Lakes State Governors or their designees.

Significant Consumptive Water Uses: Where withdrawals involve significant consumptive uses of water (> 5,000,000 gpd in any 90-day period), the host state is obligated to provide notice to the other jurisdictions, and invite their comments, which then must be considered in the applicable state permitting agencies.

Water Conservation Measures. States are required to develop and implement voluntary and/or mandatory water conservation measures applicable to both existing and new users. New or increased withdrawals must implement environmentally sound and economically feasible water conservation measures.

The GLSL Compact is currently in its early stages of implementation. Some states (including Pennsylvania194) have adopted statutes setting up permitting programs conforming to the compact’s mandates, but in other jurisdictions (New York and Ohio) those programs are still in the formative stages.

4. Protection of Water Supplies

4.1 Regulation of the Fracing Process and the Proposed FRAC Act

The advent of unconventional drilling techniques, including horizontal drilling and large-scale hydraulic facture stimulation, have lead to a heightened public sensitivity 194 Act of July 4, 2008, P.L. 526, No. 2008-43, Pa. Stat. Ann. tit. 32, §817.23-30 (West Supp. 2009).

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regarding potential impacts on water supplies and the fresh groundwater resources that overlie many shale plays – and that public concern, in turn, has stimulated political proposals that may seriously impact industry activities.

On the one hand, credible studies indicate that the potential for impacts to surface water and fresh groundwater from hydraulic fracturing and horizontal well completions are expected to be minimal because of regulatory requirements by state oil and gas agencies coupled with the practices implemented by gas well operators to ensure fluids are contained.195 Such studies indicate, for example, the deposition environment of the Marcellus Shale, which produced a thick blanket of Devonian-aged shales above the Marcellus, provides a thick sequence of overlying shales to act as a series of confining layers to prevent vertical migration of fracturing fluids upward towards fresh groundwater systems.196 That being said, some environmental groups have produced “studies” and press releases citing a range of chemicals utilized in drilling and fracing fluids, and raising the specter of migration of these chemicals into water systems.197

The Federal Safe Drinking Water Act,198 as amended by the Energy Policy Act of 2005, excludes injection of fluids for fracing purposes from regulation under the underground injection control (“UIC”) program.199 Specifically, hydraulic fracturing is excluded from the definition of “underground injection.”200

In late 2009, bills introduced in the U.S. Senate201 and House202 proposed the Fracturing Responsibility and Awareness of Chemicals (“FRAC”) Act. The proposed FRAC act would turn the exclusion for hydraulic fracturing into an inclusion, thereby bringing all injection of any fluid or propping agents for purposes of hydraulic fracturing operations relating to oil and gas production under the full panoply of UIC permitting and regulation. In addition, the FRAC Act would mandate that EPA or States administering the UIC program require disclosure by operators to the agency and to the public of all

195 A. Daniel Arthur, Brian Bohm and Mark Lane, Hydraulic Fracturing Considerations for Natural Gas Wells of the Marcellus Shale, The Ground Water Protection Forum, 2008 Annual Forum, Cincinnati, OH, September 21-24, 2008. 196 Id. at 16. 197 See, e.g., Environmental Working Group, Drilling Around the Law (2009), available at: http://www.ewg.org/drillingaroundthelaw. 198 42 U.S.C. §300j et seq. 199 See UIC program discussion in Part 6.5 below. 200 32 U.S.C. §300h(d)(1)(B)(ii) (“The term ‘underground injection’ … excludes … the underground injection of fluids or propping agents (other than diesel fuels) pursuant to hydraulic fracturing operations related to oil, gas, or geothermal production activities.” 201 Senate Bill 1215, sponsored by Sen. Robert Casey (D-PA). 202 House Bill 2766, sponsored by Rep. Dianna DeGette (D-CO).

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chemical constituents (but not the proprietary chemical formulas) used in the fracturing process.

If enacted in its current form, there is little doubt that the FRAC Act would stand as a serious impediment to unconventional drilling of shale gas wells – as an extensive geologic and engineering evaluation process is mandated for permitting of most UIC wells, and EPA is hardly staffed in a manner that could manage literally thousands of well applications per year.

Pressure to push forward the FRAC Act has been blunted, to some degree, by the undertaking of a study by EPA of hydraulic fracturing and its impacts, funded with a $1.9 million appropriation in the FY 2010 appropriations act, which mandated a peer-reviewed evaluation. On March 18, 2010, EPA formally announced initiation of that study, with input from the Science Advisory Board.203 The scope and depth of this study remains to be determined, and its work product may take several years to be concluded. In the mean while, the industry must keep a watchful eye on political developments and potential efforts to move forward on the FRAC Act proposal.

4.2 Liability of Gas Well Operators for Impacts on Other Water Users

Marcellus Shale development operations may impact upon other water users (such as neighboring well or stream owners) via several different modes. First, the process of installing and using water sources, whether from surface streams or wells, may affect downstream flows or aquifer supplies to neighboring wells. Second, the process of drilling, fracing or otherwise developing the gas well may theoretically impact the quantity or quality of water supplies, such as by interrupting or causing a change in groundwater flow patterns, or by contributing pollution via improperly controlled movement of gas or well fluids into freshwater horizons.

(a) Liability for Impacts Caused by Water Supply Development

As indicated by the discussion in Part 3, the question of liability for impacts caused by water supply development and withdrawals rests largely on the applicable state law governing “water rights” and water allocation, and substantially is affected by the location and nature of the withdrawal involved.

In those jurisdictions governed primarily or exclusively by common law (western Pennsylvania, Ohio, West Virginia, and Virginia), exposure to liability will depend upon “reasonable use” determinations and point of withdrawal versus use. In situations where adequate water sources can be developed on the same leasehold as the gas production well, the gas developer will enjoy “riparian” rights as to surface waters and “reasonable

203 See EPA Press Release:

http://yosemite.epa.gov/opa/admpress.nsf/e77fdd4f5afd88a3852576b3005a604f/ba591ee790c58d30852576ea004ee3ad!OpenDocument.

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use” rights as to groundwater. Surface water impacts are more likely to involve a weighing of factors, while the groundwater doctrines in most states are less likely to lead to imposition of liability for impacts on other wells unless the impact is reasonably foreseeable and the developer fails to take reasonable steps to avoid or mitigate the impact. On the other hand, where water supplies must be obtained off of the mineral leasehold, old rules in many jurisdictions view water transfers as per se unreasonable, and could readily lead to broader exposure to claims for interference with other water users.

Although “regulatory” regimes governing water withdrawals pose an additional administrative step, they may in the long run serve to benefit major energy developments. Regulated riparian systems, such as administered by SRBC and DRBC, have tended to displace antiquated common law rules that disfavor off-land transfer of water, thereby allowing the tapping of sources which may not be available at the immediate site of use. These permit programs will almost always require consideration of impacts on neighboring wells, springs or surface water supplies, but also provide a more predictable avenue by which such impacts can be assessed and mitigated through appropriate provision of replacement supplies or compensation.

(b) Liability for Impacts Caused by Gas Well Development and Operation

(i) Common Law Liabilities

Absent special statutory arrangements, liability for water supply quantity and quality impacts occasioned by gas well development will rest substantially on common law tort doctrines – principally trespass, nuisance and, where applicable, strict liability rules. Since these and related issues are being addressed by another panel, suffice that we mentioned them here for the sake of completeness.

(ii) Special Statutory and Regulatory Requirements

Some jurisdictions, such as Pennsylvania, have adopted special statutory and regulatory provisions that act as an overlay to, or displacement of, common law rules in regard to impacts from oil and gas well development.

(1) The Pennsylvania Oil & Gas Act – Water Supply Protection Provisions

Section 208 of the Pennsylvania Oil and Gas Act204 imposes an affirmative obligation on well operators to restore or replace affected water supplies. Specifically, section 208(a) declares:

(a) Any well operator who affects a public or private water supply by pollution or diminution shall restore or replace the affected supply with an

204 58 P.S. §601.208.

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alternate source of water adequate in quantity or quality for the purposes served by the supply.

Section 208(a) is notably silent in terms of what activities by a well operator might lead to such an obligation. Section 208(b) provides further clarification, however, in describing the procedures by which any “landowner or water purveyor suffering pollution or diminution of a water supply as a result of the drilling, alteration or operation of an oil or gas well”205 may notify the PaDEP and request an investigation be conducted. Read together, it would appear that the statutory obligation to replace or restore water supply attaches when the impact results from the drilling, alteration or operation of the gas well, and not to impacts resulting from a gas well owner’s development of a separate water supply source on or off the mineral lease area. There are, however, no cases or agency guidance addressing this point.

The Pennsylvania Act sets up a specific process to be followed.206 After receipt of a complaint, PaDEP must undertake an investigation within 10 days. The agency must render a determination within 45 days. If the agency fines or “presumes” that the pollution or diminution of the water supply was caused by drilling, alteration or operation activities, then PaDEP will issue an order to the gas well operator to restore or replace the affected supply, and if necessary provide a temporary replacement.

Pennsylvania’s law creates a presumption that the gas well operator is responsible for pollution of a water supply within 1000 feet of the gas well, where the pollution occurs within six months after completing drilling or alteration of the well.207 This presumption can be overcome if the well operator affirmatively proves one of five defenses:

(1) The pollution existed prior to the drilling or alteration activity as determined by a predrilling or prealteration survey.

(2) The landowner or water purveyor refused to allow the operator access to conduct a predrilling or prealteration survey.

(3) The water supply is not within 1,000 feet of the well.

(4) The pollution occurred more than six months after completion of drilling or alteration activities.

(5) The pollution occurred as the result of some cause other than the drilling or alteration activity.208

205 58 P.S. §601.208(b) (emphasis added). 206 Id.; 25 Pa. Code §78.51. 207 58 P.S. §601.208(c). 208 58 P.S. §601.208(d).

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To utilize either of the first two defenses, the well operator must retain the services of an independent laboratory to conduct a predrilling or prealteration survey of water supplies in the area, and results of that survey must be provided to PaDEP and each water supply owner. Regulations detail the required elements of such a survey, including the notice to be provided to neighboring landowners in the area and specific information which must be collected regarding each well.209

The statute does not create a presumption about impacts on the quantity of neighboring supplies or call for a predrilling or prealteration survey of the quantity aspects of neighboring wells. Nevertheless, a predevelopment survey of water supplies for both water quantity and quality may be prudent as a prophylactic defensive measure.

(2) West Virginia’s Water Protection Regulations

Like Pennsylvania, West Virginia imposes affirmative obligations on well operators that require operators to generally “prevent surface and underground water pollution,”210 as well as imposing specific operational requirements.211 West Virginia also has a waste prevention rule that requires operators “to prevent the pollution of the waters of the state in drilling and producing operations, or in transporting or distributing such products. 212”

In addition to the general pollution prevention requirements imposed in state rules, West Virginia imposes a water supply testing requirement on well operators. Under this rule, operators generally must test water from any wells or springs located within 1000’ from any proposed well.213 Such operators must provide notice to owners of property within 1000’ from any proposed well to give such owners the opportunity to request testing of well or spring water.214 The rules require specific sampling and

209 25 Pa. Code §78.52. 210 W. Va. Code State R. tit. 35, §4-16.5. 211 For example, W. Va. Code State R. tit. 35, §4-11.3 contains “operational criteria” that include the use of fresh water casings for any drilling through “the deepest fresh water horizon (that being the deepest horizon which will replenish itself and from which fresh water or usable water for household, domestic, industrial, agricultural, or public use may be economically and feasibly recovered).” 212 W. Va. Code State R. tit. 35, §4-17.1. 213 W. Va. Code State R. tit. 35, §4-19. 214 W. Va. Code State R. tit. 35, §4-19.2.

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analysis methods.215 And, the rules provide for a right of entry for operators in order to allow such operators to obtain samples for a 216nalysis.

Finally, if a well operator causes or contributes to groundwater contamination, “every reasonable effort shall be made by the operator to identify, remove, or mitigate the source of such contamination.”217 Such efforts can include developing a groundwater remediation plan and conducting groundwater monitoring.218

(3) Ohio’s Water Protection Requirements.

Like West Virginia, Ohio requires well operators to conduct operations “in a manner which will not contaminate or pollute the surface of the land, or water on the surface or in the subsurface.”219

Ohio imposes operational requirements on well operators that are intended to protect groundwater. Ohio, for example, requires operators to construct and maintain drilling pits in such a manner so as to prevent the escape of brine.220 Ohio prohibits brine disposal in surface or groundwater or on land in such quantities that it causes or could reasonably be anticipated to cause damage or injury to public health or safety or the environment, including damage or injury to drinking water.221 In addition, Ohio requires well operators in urban areas to use “best management practices” to minimize and control surface flow of water, sedimentation, and erosion.222 Finally, in response to an incident in which methane gas leaked from a well into 26 homes through a domestic water well, Ohio’s Department of Natural Resources has implemented new permit conditions requiring operators to prevent the accumulation of unsafe gas pressure in the annulus of a well, thereby preventing such gas from entering domestic water supplies.223

215 W. Va. Code State R. tit. 35, §4-19.3. 216 W. Va. Code State R. tit. 35, §4-19.4. This right of entry includes the right to get a court order allowing entry if an owner protects or blocks entry when requested. Id. §4-19.4b. 217 W. Va. Code State R. tit. 35, §4-20. 218 Id. 219 Ohio Admin. Code § 1501: 9-1-07. 220 Ohio Rev. Code § 1509.22(C)(3). Ohio also requires the installation of protective casing to prevent surface or groundwater from entering “fresh water strata.” Ohio Rev. Code § 1509.17. 221 Ohio Rev. Code § 1509.22(A). 222 Ohio Admin. Code § 1501: 9-1-07(B). 223 See Ohio Department of Natural Resources press release, January 18, 2008 (http://www.dnr.state.oh.us/home_page/newsreleasefeed/tabid/18276/EntryID/326/Default.aspx; http://www.ohiodnr.com/mineral/default/tabid/10352/Default.aspx)

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Ohio regulations require applicants for well drilling permits to sample all water wells within 300 feet of the proposed well locations in urbanized areas, but this sampling requirement is not directly tied to a provision creating liability for specific groundwater impacts that may be identified through such sampling.224 However, the general provision prohibiting operators from contaminating groundwater would apply, and that statutory provision might be utilized as part of a common law claim that the operator has violated a “duty” owed to those drawing water from the groundwater that has been contaminated. 5. The Flowback / Wastewater Challenge

5.1 Scope of the Challenge

As noted above, about 3-5 million gallons of water are required to perform a successful hydrofracturing treatment of a Marcellus Shale well. A portion of this water (25-50%) emerges from the well as flowback water, with significant volume in a relatively short period of time. Efforts to obtain representative characterization of Marcellus Shale flowback and produced waters are continuing. What is known from the information available to date is that typical flowback water contains 4-25% salts (including constituents from underground formation), plus oil and gas, plus chemicals added during the frac. Typical total dissolved solids (TDS) may exceed 100,000 milligrams per liter (“mg/l”). Other constituents of concern include barium, strontium, and naturally occurring radioactive material (“NORM”). The following table provides some typical flowback water vs. freshwater constituent values:225

Parameter Typical Surface Water Analysis (mg/l or ppm)

Flowback Analysis (mg/l or ppm)

TDS < 500 20,000 to 300,000 Iron < 2 0 to 25 Oil & Grease < 15 0 to 1,000 Barium < 2 0 to 1,000 Strontium < 4 0 to 5,000 pH 6 to 9 5 to 7.5

Reuse of flowback water requires treatment and/or dilution with fresh water to lower TDS and some other specific constituent concentrations (e.g., sulfates) that could inhibit successful fracture stimulation programs. Of the up to approximately 5 million

224 Ohio Admin. Code § 1501: 9-1-02(F). 225 Mark Gannon (Water and Wastewater Department Manager, Tetra-Tech), Challenges in Water Supply and Flowback Water Management, in K&L Gates Second Annual Appalachian Basin Oil & Gas Seminar, Pittsburgh, PA (April 29, 2009).

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gallons used for each hydrofracture job, industry sources indicate that 1-1.5 million gallons of flowback water resulting from each frac job require handling, treatment, recycling and/or disposal. In addition, over time, additional produced water will be generated from each well – albeit Marcellus Shale wells have been relatively low in produced water per MMCF of gas produced. The notable challenge remains that existing treatment facilities have limited capacity and capability to handle these volumes, constituents and concentrations/loadings. Confounding these hurdles, some eastern streams have limited capacity to assimilate these constituents, while other streams may have high quality / special protection status. Clearly, the industry faces a daunting strategic challenge to identify and develop viable water management methods, facilities and disposal options.

5.2 Overview of Wastewater Management Issues

Addressing the wastewater challenge involves tackling a series of issues, and developing a coherent wastewater management strategy. Among the issues to be addressed are: (1) characterizing flowback wastewaters; (2) developing systems to assure wastewaters are sent to (and reach) appropriate treatment facilities; (3) selecting the appropriate treatment and disposal technologies, both to meet current and future regulatory mandates; (4) identifying and resolving treatment and disposal facility design and permitting issues; and (5) characterizing and managing treatment residuals. These key issues are illuminated in the following sections of this chapter.

5.3 Requirements for Characterizing Flowback Wastewater

A fundamental starting point, both from a legal and practical perspective, requires an appropriate and complete characterization of the constituents in flowback wastewaters, the respective concentrations of those constituents, and the factors that may affect wastewater contents. Although flowback wastewaters from various wells in the Marcellus Shale formations may be similar in general nature, concentrations of certain constituents may be expected to vary over the flowback period, and may also vary to some extent by geographic location. Selecting appropriate treatment technologies and facilities requires a decent understanding by each operator of the range and variability of constituents (including chlorides, metals, NORM, etc.) that may be anticipated from gas wells under development.

In framing characterization efforts, companies need to consider both what information they need to make appropriate technological decisions and applicable regulatory requirements for characterizing wastewater streams.

Flowback water is exempted from the Resource Conservation and Recovery Act (“RCRA”) Subtitle C hazardous waste regulations by virtue of the exemption set forth in 42 U.S.C. §6921(b)(2)(A). Thus, hazardous waste characterization mandates found in 40 C.F.R. Part 261 are not applicable. However, gas well flowback wastewater may be subject to state regulatory regimes governing characterization of “solid wastes” and wastewaters. Pennsylvania provides a prime example. Pennsylvania’s standard gas well

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permit conditions wastewaters to be characterized “in accordance with 25 Pa. Code §287.54” – thus providing a cross-reference to the Commonwealth’s residual waste management rules in 25 Pa. Code Ch. 287. Under the Chapter 287 rules, a generator must use generator knowledge and representative sampling to determine physical and chemical composition of material.226 Section 287.54(a) requires performance of a “detailed analysis that fully characterizes the physical properties and chemical composition” of each waste generated. That analysis may include available information from material safety data sheets (“MSDS”) or similar sources.227 PaDEP Form 26R provides guidance concerning the requirements for chemical analysis of Marcellus Shale drilling, completion and production wastewaters, and calls for analysis of a plethora of constituents.228 Analytic methods must conform with EPA’s standard test methods, and because this information is required to be submitted as part of a state regulatory program, the analyses must be performed by an accredited environmental laboratory.229 The generator of residual waste, including flowback water, must provide this information to receiving waste treatment and management facilities, and the certification of waste characterization must be submitted to PaDEP at least annually by March 1 of each year.230 Records of all analyses, including laboratory quality assurance - quality control (“QA-QC”) procedures must be maintained by the generator and available for PaDEP inspection.231

In turn, facilities receiving flowback water must assure that they can adequate treat and manage the wastewater. Under Pennsylvania and other state’s rules, such

226 25 Pa. Code §287.54(a). A generator may rely on detailed analysis that characterizes waste (company or potentially industry data) within the past five years, if the generator can certify that it is representative. A full chemical analysis is required at a minimum of every five years. Id. §287.54(g). 227 Id. 228 PaDEP Form 26R, Chemical Analysis of Residual Waste Annual Report by the Generator Instructions, Doc. No. 2540-PM-BWM0347 (Rev. 7/2009), available at: http://www.elibrary.dep.state.pa.us/dsweb/View/Collection-10502. The current listing of required constituents includes: Acidity, Alkalinity (Total as CaCO3), Aluminum, Ammonia Nitrogen, Arsenic, Barium, Benzene, Beryllium, Biochemical Oxygen Demand, Boron, Bromide, Cadmium, Calcium, Chemical Oxygen Demand, Chlorides, Chromium, Cobalt, Copper, Ethylene Glycol, Gross Alpha, Gross Beta, Hardness (Total as CaCO3), Iron – Dissolved, Iron – Total, Lead, Lithium, Magnesium, Manganese, MBAS (Surfactants), Mercury, Molybdenum, Nickel, Nitrite-Nitrate Nitrogen, Oil & Grease, pH, Phenolics (Total), Radium 226, Radium 228, Selenium, Silver, Sodium, Specific Conductance, Strontium, Sulfates, Thorium, Toluene, Total Dissolved Solids. Total Kjeldahl Nitrogen, Total Suspended Solids, Uranium, and Zinc. 229 See 27 Pa.C.S. §§4101-4113 (relating to environmental laboratory accreditation) and 25 Pa. Code. Ch. 252. 230 25 Pa. Code §287.54(b). 231 Id. §287.54(e).

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facilities must have a waste acceptance plan; and wastes must have approval from the receiving facility for receipt. Each publicly owned treatment works (“POTW”) (i.e., municipal sewage treatment plant) must obtain NPDES permitting agency approval prior to receipt of new types of industrial wastewater (such as Marcellus Shale wastewaters) that were not reflected in their original NPDES permit application. In this regard, wastewater characterization is required to avoid interference with the POTW’s wastewater treatment processes (for example, by killing or inhibiting the bacteria used to treat biological oxygen demand (“BOD”) materials), to prevent pass-through of the constituents without proper treatment, and to prevent impact on the POTW’s sludge quality and classification (e.g., by adding metals or other constituents that would preclude beneficial land application).

5.4 Assuring Delivery to Appropriate Facilities

All states require POTWs to provide notice to state permitting authorities and to obtain NPDES permit modification if necessary for acceptance of new types of influent sources. Likewise, all or virtually all states required that privately operated wastewater or other waste treatment facilities received prior approval before accepting new waste streams for treatment. Imposition of these obligations on the receiving treatment facilities, however, does not mean that generators can simply rely on the receiving facilities. Some states, such as Pennsylvania, impose direct responsibilities on waste generators to assure that their wastes reach appropriate permitted facilities.

As just one example, the Pennsylvania oil and gas and residual waste rules impose mandates and responsibilities on gas well wastewater generators to send their wastewaters to appropriate permitted facilities. The oil and gas rules at 25 Pa. Code §287.55 require that each gas operator prepare and implement a plan for control and disposal of fluids and wastes. In turn, the residual waste regulations in 25 Pa. Code §287.6 declare that a generator may not consign or transfer residual waste “which is at any time subsequently” stored, treated, processed or disposed of or discharged at an unpermitted facility. Under this provision, PaDEP takes the view that if wastewater is delivered to an unpermitted facility – even if the generator did not specify that facility – the generator may be held responsible. Under 25 Pa. Code §287.55, each Marcellus Shale operator is mandated to maintain for at least five years certain residual waste generator records, including the types and amounts of waste generated, date waste generated, and information regarding processing or disposal facility. Further, oil and gas well operator annual reports require specific information concerning wastewater disposition.

Considering these various generator responsibilities, manifests per se are not required, but operators must clearly consider how they will track waste shipments to meet the above requirements. Many operators have developed forms (such as bills of lading, logs, and the like) to consign wastewaters to designated treatment facilities and to obtain follow-up confirmation of delivery.

Finally, note should be made of the potential consequences for failing to consider and deliver wastewaters to properly permitted facilities. Under state oil and gas, water

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quality and solid waste laws, significant penalties may be imposed on generators whose waste is delivered to unpermitted facilities. In Pennsylvania, for example, violation of the residual waste rules exposes a generator to both criminal prosecution and civil penalties in the amount of up to $25,000 per day for each violation.232 Beyond such regulatory sanctions, however, mismanagement of wastewater raises potential for significant cleanup liabilities if materials are mishandled.

5.5 Treatment, Reuse and Disposal Technology Choices

Marcellus Shale flowback and production wastewater presents some significant challenges in terms of selecting effective and implementable treatment, reuse and/or disposal technologies. A brief overview of the potential choices and some of their constraints may be helpful.

(a) Natural pond evaporation

Natural pond evaporation is often utilized in Texas and other parts of the dry southwest. However, in the eastern U.S. where average rainfall frequently exceeds 40 inches per year, and precipitation and evaporation rates are nearly equivalent, natural pond evaporation is impractical.

(b) Direct reuse for drilling and fracing

The ability to directly use flowback or production wastewater in Marcellus Shale drilling and fracing depends on desired water quality characteristics, which can vary between drilling firms and techniques. Any reuse of such wastewater needs to address a series of technical items, including oil/condensate separation, solids and bacteria removal, and sulfides control. In order to avoid problems in the drilling process, reuse of such wastewater usually requires some treatment be applied. Certainly, however, a potential exists for mixing treated flowback wastewater with fresh water to attain desired TDS / chlorides values allowing reuse; and a variety of operators are experimenting with such techniques.

(c) Underground injection of flowback & production brines

The underground injection of gas well wastewaters is again an option utilized frequently in other parts of the nation. In the east, geologic constraints coupled with some significant regulatory and permitting hurdles have resulted in only a very small number of underground wells currently to be permitted to date in Appalachian Basin states. Some of the legal/regulation aspects of underground injection are discussed further in Part 6.5 below.

232 Pa. Stat. Ann. tit. 35, §§6018.605-6018.606

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(d) Conventional treatment technologies

Conventional wastewater treatment technologies, such as pH adjustment, metals precipitation, membrane filtration, and oil / water separation, might be applied to flowback and production wastewaters to address certain constituents, but these conventional technologies do not address the TDS / chlorides challenge. Conventional treatment technologies alone are not a solution.

(e) TDS reduction via reverse osmosis

Reverse osmosis (“RO”) is a technology that utilizes pressure to force a solution through a membrane, retaining the solute (salt laden solution) on one side and allowing the pure solvent (water) to pass to the other side. TDS reduction via RO is effective for certain wastewaters up to a TDS concentration of approximately 40,000 ppm.

Moreover, RO membranes are prone to fouling and premature failure if wastewaters contain any of a variety of interfering constituents. Membrane fouling by organics, silica, calcium carbonate and calcium sulfate is a common problem with RO systems. Anti-scaling agents are used to minimize scaling and cleaning chemicals must be used regularly to maintain membrane efficiency. However, even with the use of these chemicals, the RO membranes eventually plug and the membranes must be replaced.

RO treatment is moderately energy intensive. The energy requirement for the RO membrane system (not including the necessary pretreatment units) treating brackish wastewater averages 9.6 kWh/1000 gallons of produced water. Expressed as the power requirements for treating the influent flow,233 the average energy use is 13.7 kWh/1000 gallons. Based on a Department of Energy/EPA report,234 electrical energy generation in the U.S. results in approximately 1.341 lb of carbon dioxide per kWh.235 Thus, a 100,000 gpd RO plant would consume 500,050 kilowatt hours per year, equating to 335 tons of CO2 emissions per year.

RO systems engender both high capital and O&M costs. At this point, because of the limitations of RO units to handle effectively TDS values above 40,000 ppm, however, any cost estimate for Marcellus Shale wastewaters is probably irrelevant.

RO treatment results in recovery of only 30-60% of the incoming water volume in the form of a treated water effluent containing less than 500 ppm of TDS. Conversely, 40-70% of the incoming wastewater is left in the form of a more concentrated, higher-

233 Assuming 30% reject flow. 234 Department of Energy and Environmental Protection Agency, Carbon Dioxide Emissions from the Generation of Electric Power in the United States (July 2000). 235 This value reflects an average of electrical generation from all sources: coal, natural gas, nuclear, wind, etc. If all electrical energy was from coal, the carbon dioxide generation rate is 2.095 lb/kWh.

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TDS “brine” – often referred to as “reject” water. The TDS salts do not go away; they are only more concentrated in a somewhat smaller volume of wastewater.

The key constraint for RO is that it is only effective up to TDS/chloride levels of approximately 40,000 ppm. Typical Marcellus Shale flowback wastewaters exhibit TDS levels well in excess of this concentration. Hence, although some vendors are promoting RO systems, many knowledgeable wastewater engineers believe RO is not a feasible or effective option for typical Marcellus Shale wastewaters.

(f) TDS reduction via evaporation

TDS reduction via evaporation (also known as thermal distillation) has been espoused as another available technology, which may be deployed via either mobile or centralized waste treatment configurations. Basically, the technology requires heating volumes of high-TDS water to evaporate a portion of the water, converting it to steam which may then be recovered through condensation, while leaving behind more concentrated brine solutions. Heat sources for evaporation systems may involve either electricity or fossil-fuel (using oil or natural gas and various heat transfer systems).

In almost all cases, evaporation systems require pretreatment to remove various constituents, such as inorganic chemicals, ammonia, and suspended solids, which will cause fouling of the process and to prevent scaling. Solids removal by membrane filtration may be required before the water is sent to the evaporator. Other pretreatment may be required including activated carbon for organics removal. Fouling of heat exchanger surfaces can greatly reduce distillation efficiency — calcium sulfate and calcium carbonate are the most common cause of such fouling.236 If this type of fouling will potentially occur, calcium removal by chemical precipitation will be required upstream of the membrane filtration system. Sulfates in the wastewater will also pose a particular issue, as efforts must be undertaken to prevent sulfates from fouling the evaporative process.

Evaporation is moderate to highly energy intensive. The literature indicates that energy requirements for all three potential thermal processes (multi-stage flash distillation, multi-effect distillation, and mechanical vapor compression) are essentially independent of the influent salt concentration237 and are high — the average energy use for the most efficient thermal process (thermal or mechanical vapor compression) is 43.2 kwh/1000 gallons of product water (39 kWh/1000 gallons influent water). At that rate, 100,000 gpd of wastewater would require an estimated 3,900 kWh of thermal/electrical energy to remove TDS.

236 J. E. Miller, “Review of Water Resources and Desalination Technologies,” SAND 2003-0800, Sandia National Laboratories, Albuquerque, NM (2003) (costs adjusted to 2009 values). 237 J. E. Miller, supra.

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Similar to RO technology, evaporation units leave significant volumes of residuals. A typical evaporation facility will recover 60-65% of the wastewater in the form of distilled water, leaving 40% of the volume as saturated TDS wastewater. Thus, the availability of a viable option for disposal of significant volumes of concentrated brine remains even after application of evaporation technology.

(g) TDS reduction via crystallization

Evaporation/crystallization takes the process one step further to evaporate the concentrated brine to produce a salt cake. Influent feed to the crystallizer is further heated through a heat exchanger to promote flash boiling of the brine, with the resulting vapor passing through a heat exchanger/condenser system. If the system works as desired, the resulting concentrate produces salt crystals and cake, which are removed and dewatered through a centrifuge system.

Often referred to as “zero liquid discharge” (“ZLD”), evaporation/crystallization does not destroy the TDS, it only changes it into a different type of residual posing a somewhat different dispositional challenge.

Evaporation/crystallization is a highly energy intensive method of treatment. The power consumption of a 1,000,000 gallon per day facility handling brines from Marcellus Shale wells, for example, has been projected at 10 megawatts plus more than 30,000 cubic feet of natural gas per hour. Thus, to treat 1,000,000 gallons per day of wastewater would require some 87,600,000 kilowatt hours of electricity annually (the equivalent electric demand of some 11,300 households238); plus 262,800,000 ft3 of natural gas annually. Using EPA’s emissions factor of 1.341 pounds of carbon dioxide emissions per kwh, the annual electric demand for just one such evaporation/crystallization facility equates to nearly 60,000 tons of CO2 emissions per year.

The projected cost of ZLD treatment is substantial. Cost estimates for centralized wastewater treatment facilities utilizing evaporation/crystallization for oil and gas brines indicate capital cost estimates ranging from $90-100 million for a 1 MGD facility. O&M costs for such a facility are estimated at approximately $15-20 million annually.239

(h) Key regulatory questions affecting selection

In evaluating these alternatives, and framing a wastewater technology strategy, operators need to consider a number of questions that define the “regulatory drivers” to technology selection.

238 Based on the U.S. Department of Energy, Energy Information Administration’s Middle Atlantic Household Electricity Report (December 22, 2005) using 2001 data, electric consumption in 15 million Mid-Atlantic region households totaled 116 billion kwh, or an average of 7,733 kwh annually per household. (http://www.eia.doe.gov/emeu/reps/enduse/er01_mid-atl.html (last visited June 6, 2009)). 239 Mark Gannon, supra.

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What are the allowable discharge levels (loadings and concentrations)?

Are there differences in regulatory treatment between on-site treatment vs. centralized facilities?

What rules govern the management, disposition or beneficial use of residuals?

What are today’s requirements?

What will be the likely future requirements - the regulatory trends?

5.6 Regulatory Drivers to Technology Selection – Impending Restrictions on Surface Water Discharges

(a) Overview

A forceful driver to the industry’s scramble to select and implement wastewater management technologies, including increased recycling and reuse of flowback water, arises from proposals from some states to impose severe restrictions upon surface water discharges from high-TDS sources.

One leader to date has been Pennsylvania, which in April 2009 issued a “Permitting Strategy for High Total Dissolved Solids (TDS) Wastewater Discharges” (the “PA TDS Strategy”),240 followed by proposed rulemaking241 and most recently a final rulemaking package adopted effective August 21, 2010.242 Similarly, the New York DEC’s draft Supplemental Generic Impact Statement for shale gas development proposes stringent regulation of TDS-containing wastewaters, including changes to state-issued discharge permits issued to POTWs to limit the acceptance of such brines in order to avoid interference and pass-through conditions.

(b) The PA TDS Strategy and Pending Regulations

The PA TDS Strategy starts with a description of the “problem.” The Strategy cites to several studies relating to the impacts of TDS,243 and PaDEP refers to streams

240 Available at: http://www.depweb.state.pa.us/watersupply/cwp/view.asp?a=1260&Q=545730&watersupplyNav=|30160 241 39 Pa. Bulletin 6467 (November 7, 2009). 242 See 40 Pa. Bulletin 4835 (August 21, 2010). 243 PaDEP, Trihalomethane Speciation and the Relationship to Elevated Total Dissolved Solid Concentrations Affecting Drinking Water Quality at Systems Utilizing the Monongahela River as a Primary Source During the 3rd and 4th Quarters of 2008 (February 2009); PaDEP, Cause and Effect Survey, South Fork Tenmile Creek (February 2009); PaDEP, Aquatic Survey of Lower Dunkard Creek, (October-November 2008).

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with relatively high TDS concentrations in certain low flow conditions, and hence limited available assimilative capacity, pointing to the Monongahela River and the West Branch Susquehanna River as primary examples.

The PA TDS Strategy called for adopting and implementing by January 1, 2011, two types of new standards: (1) a new treatment standard for high TDS sources; and (2) new instream water quality criteria for constituents that affect aquatic life or other protected uses.

(i) Proposed Treatment Standards

Under the PA TDS Strategy, PaDEP initially proposed a new end-of-pipe treatment “technology based” standard to be inserted into 25 Pa. Code Chapter 95 for all “high TDS sources.” This element of the strategy was moved forward through a notice of proposed rulemaking which was published in the Pennsylvania Bulletin for public comment during the fall of 2009.244 The initially proposed Chapter 95 amendments would have imposed treatment standards on any new or expanded source of “high-TDS wastewater” – defined as any source that includes a TDS concentration that exceeds 2,000 mg/l or a TDS loading that exceeds 100,000 pounds per day.245 This would effectively encompass all Marcellus Shale wastewaters. The initial proposed rules would establish a treatment standard, to be effective by January 2011, limiting all “new” high TDS sources to effluent limits of 500 mg/l of TDS, 250 mg/l of Total Chlorides, and 250 mg/l of Total Sulfates (in each case, stated as a monthly average).246 Oil and gas wastewaters would additionally be subject to effluent limits on both total Barium and Strontium of 10 mg/l as a monthly average.

The proposed Ch. 95 regulations met with a broad concern and opposition from various regulated sectors well beyond the oil and gas industry, including power generation, refineries, coal mining, pharmaceuticals, and food processing establishments. Responding to the concern that a “one-size-fits-all” approach was unjustified, PaDEP convened a TDS Stakeholders Subcommittee to its standing Water Resources Advisory Committee composed of representatives of various sectors and public interest organizations to examine various options. Although the Stakeholders Group failed to develop a consensus recommendation, valuable information was provided concerning the conditions and impacts of the proposed rules on various sectors,247 and several alternatives were brought forth for consideration.248

The studies cited in the PA TDS Strategy have been posted at: http://www.depweb.state.pa.us/watersupply/cwp/view.asp?a=1260&Q=545730&watersupplyNav=|30160. 244 39 Pa. Bulletin 6467 (November 7, 2009). 245 Proposed 25 Pa. Code §95.10(a). 246 Proposed 25 Pa. Code §95.10 247 Copies of the sector presentations are available at:

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The final Ch. 95 adopted by the Environmental Quality Board in May 2010 and published finally on August 21, 2010, varied substantially from the original proposal. The central elements of the pending final rules are:

Within one year of the effective date, each natural gas well operator must adopt and implement a source reduction strategy identifying the methods and procedures to maximum recycling and reuse of flowback or production fluid either to fracture other natural gas wells or for other beneficial uses. The strategy must be updated annually.

New or expanding treated discharges of wastewater resulting from the fracturing, production, field exploration, drilling or well completion of natural gas wells may be authorized under NPDES permits only if: (1) the discharges are from centralized waste treatment (“CWT”) facilities; (2) the discharge meets monthly average effluent standards of 500 mg/l TDS, 250 mg/l Chlorides, 10 mg/l Barium, and 10 mg/l of Strontium; and (3) any CWT discharging to a POTW must meet the same treatment standards for TDS, chlorides, barium and strontium prior to the water reaching the POTW.

Other industries will be subject to an effluent limitation of 2000 mg/l of TDS as a monthly average applied to any new or expanding mass loading of TDS, with certain exclusions and allowances for variances if certain criteria are met.

If particular watersheds approach 75% of their TDS assimilative capacity as measured at the nearest downstream water supply intake, PaDEP may undertake a wasteload allocation process and impose more stringent loadings on all TDS discharges to that watershed.

(ii) Potential Instream Criteria

Second, under the PA TDS Strategy, PaDEP has been developing new instream water quality criteria for the components of TDS that contribute to osmotic pressure. As of this writing, PaDEP has proposed a new instream criteria for Chlorides of 230 mg/l as a 4-day average and 860 mg/l as a 1-hour average.249 Both are stated as being aimed at aquatic life protection. If adopted, these criteria would affect the permitting of both new and existing discharges. Such instream criteria are applied in calculating whether new or existing discharges at each particular point of a stream, when combined with existing http://www.portal.state.pa.us/portal/server.pt/community/water_resources_advisory_committee_%28wrac%29/14017/wrac_taskforce_on_chapter_95/631764. 248 See TDS Stakeholders Subcommittee comments are available at: http://files.dep.state.pa.us/PublicParticipation/Advisory%20Committees/AdvCommPortalFiles/WRAC/WRAC-%20TDS%20Task%20Force%20Final%20Report%203-12-10.pdf. 249 40 Pa. Bulletin 2264 (May 1, 2010).

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instream background concentrations of Chlorides at low flow (Q7-10) conditions, would cause an instream exceedance of the standard. If so, a water quality based effluent limit (“WQBEL”) will be developed to limit Chlorides in the discharge.250 Such WQBELs, by definition, may be more stringent than technology-based effluent limitations.

6. Legal and Regulatory Issues in Implementing Treatment and Disposal Facilities

6.1 Treatment Facility Siting

Centralized brine treatment facilities, particularly those using sophisticated ZLD evaporation/crystallization technologies, are substantial complexes, involving a myriad of influent storage, treatment, residuals handling and other equipment. Mobile equipment designed for use at or near new gas well sites may be less extensive, but in combination with associated tankage, impoundments and ancillary equipment, even these non-centralized facilities can be significant. Siting issues are, therefore, an important consideration.

(a) Zoning and land development regulations

Zoning and land development regulations may govern the location and allowable configuration of treatment units, by both restricting the zoning districts where such activities can take place and/or their design (e.g., setbacks from property boundaries, land coverage, screening, and other standards). Zoning and land development plan approval processes can be lengthy and complex, especially for situations involving conditional use and special exception zoning approvals requiring hearings before municipal governing bodies or zoning hearing boards. Such zoning and land development regulations and processes will vary by state and locality; and the applicable rules in each jurisdiction must be reviewed as part of the overall site selection and design process.

In some instances, local zoning regulations may be preempted or partly preempted by applicable state laws. In Pennsylvania, for example, municipalities exercise zoning powers under the Pennsylvania Municipalities Planning Act,251 but Section 602 of the Oil & Gas Act252 preempts certain local regulation of gas well development operations. In a

250 See discussion below in Part 6.2(a)(ii). 251 Pa. Stat. Ann. tit. 53, §§10101 et seq. (West 1997 and Supp. 2009). 252 Pa. Stat. Ann. tit. 58, §601.602 (West 1996). Section 602 of the Oil & Gas Act provides:

Except with respect to ordinances adopted pursuant to the … Municipalities Planning Code, and the …. Flood Plain Management Act, all local ordinances and enactments purporting to regulate oil and gas well operations regulated by this act are hereby superseded. No ordinances or enactments adopted pursuant to the aforementioned acts shall contain provisions which impose conditions, requirements or limitations on the same features of oil and gas well operations regulated by this act or that

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set of companion cases decided in early 2009, the Pennsylvania Supreme Court ruled that the Oil & Gas Act preempted municipal ordinances which attempt to regulate the same aspects of gas well development and operations as regulated by PaDEP (such as well design, bonding, certain setbacks, and environmental standards), but allowed communities to control the location of gas wells within certain zoning districts through traditional zoning regulations.253 The Supreme Court noted that in using zoning controls, municipalities might not be allowed to (i) increase the specific setback requirements contained in the Oil & Gas Act;254 or (ii) use “conditional use” zoning approval procedures to impose “conditions addressed to features of well operations regulated by the [Oil & Gas] Act.”255

The preemptive impact of the Pennsylvania Oil & Gas Act may extend, in some cases, to wastewater treatment facilities. Where treatment processes are developed at the gas well site, arguably those wastewater operations would be part of the gas well operations regulated under the Act. On the other hand, centralized wastewater treatment facilities located off of gas well sites are regulated under other state environmental laws, but not the Oil & Gas Act, and would presumably not partake of any preemptive provisions in the Oil & Gas Act.

(b) State siting restrictions for certain treatment facilities

In addition to traditional zoning and land use regulations, certain state laws may impose additional restrictions or standards guiding the siting of particular treatment facilities. Again, Pennsylvania provides an example in its residual waste regulations, which may, under certain circumstances, apply to brine water treatment facilities.

Pennsylvania residual waste rules establish siting restrictions256 for those “residual waste processing facilities” that require individual permits under the Solid Waste Management Act.257 The term “residual waste” explicitly includes all “liquid” waste from industrial, mining and agricultural operations, which broadly would include any industrial wastewater.258 However, the residual waste siting standards do not apply to captive processing facilities and wastewater treatment facilities that qualify for the

accomplish the same purposes as set forth in this act. The Commonwealth, by this enactment, hereby preempts and supersedes the regulation of oil and gas wells as herein defined.

253 See Range Resources-Appalachia, LLC v. Salem Twp., 964 A.2d 869 (Pa. 2009); Huntley & Huntley, Inc. v. Borough Council of the Borough of Oakmont, 964 A.2d 855 (Pa. 2009): 254 Huntley & Huntley, 964 A.2d at 864 n.10. 255 Huntley & Huntley, 964 A.2d at 866 n.11. 256 25 Pa. Code §297.202. 257 Pa. Stat. Ann. tit. 35, §6018.101 et seq. (West 2003). 258 Pa. Stat. Ann. tit. 35, §6018.102 (definition of “residual waste”).

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“permit-by-rule” contained in 25 Pa. Code §287.102(b)-(c). On-site treatment facilities would presumably qualify for the “captive processing” permit-by-rule, while centralized wastewater treatment facility that discharge under an NPDES or that discharge to a POTW under pretreatment standards would qualify under the §287.102(c) permit-by-rule.

A true “zero liquid discharge” facility, however, would not apparently meet the eligibility criteria for the residual waste processing facility permit-by-rule, and thus could trigger the siting standards for facilities mandating individual permits. Those siting standards would exclude such treatment facilities from: (1) the 100-year floodplain absent DEP approved floodproofing; (2) 100 feet from exceptional value wetland; (3) 100 feet from other wetlands; (4) 300 feet from occupied dwelling, absent owner waiver; (5) 100 feet from perennial stream; (6) 50 feet from property line; and (7) 300 yards from school building, park or playground.259

6.2 NPDES Permit Issues

As most readers are aware, any discharges to surface waters of the United States via “point sources” are subject to requirements under the Federal Clean Water Act (“CWA”) for the procurement of National Pollutant Discharge Elimination System (“NPDES”) permits.260 NPDES permits describe "effluent limitations" – how much of which pollutants can be discharged in compliance with the law.

(a) Establishing effluent limits

The CWA and counterpart state water quality programs employ two primary types of regulatory controls: water quality standards and technology-based standards. Water quality standards describe permissible instream concentrations of various parameters (such as dissolved oxygen, dissolved solids, and various chemicals), designed to protect the designated uses of a stream. These water quality standards vary depending on the use of the water. For example, a stream classified as “recreational” or “cold water fisheries” would receive greater protection than one classified as agricultural. Technology-based standards focus on the method used to treat effluent before it is introduced into a body of water. These standards set a level of effluent quality that is achievable using certain prescribed levels of pollution control technology. Thus, if technology exists which permits treatment of effluent to a level cleaner than required to meet the water quality standards for the receiving body of water, the higher technology-based standards control. Conversely, if the technology-based standards are not sufficient to assure achievement of the instream water quality standards, then more stringent water quality-based effluent limits (“WQBELs”) will be imposed.

259 25 Pa. Code §297.202. 260 33 U.S.C. §1342.

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(i) Technology-based effluent limitations

Most, but not all, technology-based effluent limitations are based upon federal categorical treatment standards established for particular categories and subcategories of industries. These standards, found at 40 C.F.R. Parts 401, 405-471, prescribe different treatment and performance standards for existing sources and new sources, based upon several statutory formulations as to what those requirements are to achieve.

Treatment facilities and discharges at gas well sites are subject to Part 435 effluent guidelines (“ELG”) for the onshore oil and gas extraction subcategory.261 Those rules allow no discharge of wastewater pollutants absent a “fundamentally different factors” variance. In contrast, centralized wastewater treatment facilities are regulated by ELGs set forth in 40 C.F.R. Part 437.

For units not subject to a federal ELG, the permitting agency (in most cases the state) will establish technology-based effluent limits defining best conventional control technology (BCT), best available demonstrated technology for new sources (“BADT”), and best available technology currently available (BAT) for toxics and non-conventional pollutants, as determined by “best professional judgment.”

In addition to the federal technology-based standards and those established by permitting agencies based on best professional judgment, states may by regulation establish state-based treatment standards. The final 25 Pa. Code §95.10 Pennsylvania treatment standards, discussed above, are one such example.

(ii) Water quality based effluent limits

If technology-based standards alone are insufficient to protect instream water quality, effluent limits designed to attain and protect instream water quality criteria may be imposed as additional requirements in the NPDES permit. The water quality standards are based on the actual or intended use of the body of water (i.e., agriculture, recreation, cold water or warm water fish, etc.) as designated in state water quality criteria.262 In most cases, such water-quality based effluent limitations (“WQBELs”) are calculated based on assimilative capacity at design flow of 7-day, 10-year low flow (“Q7-10”).

(b) Special protection waters

The concept of “special protection” waters is incorporated as part of regulations adopted under both state regulations and the federal Clean Water Act. Under the federal Clean Water Act, states are required to classify their streams and other bodies of water. At a minimum, states must provide protection for existing instream uses and the level of water quality necessary to maintain those existing uses.263 Where the quality of the

261 40 C.F.R. §435.30-.32 262 See, e.g., 25 Pa. Code §§93.3, 93.4, 93.7; 40 C.F.R. Part 131. 263 40 C.F.R. §131.12(a)(1).

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waters exceed levels necessary to support propagation of fish, shellfish, wildlife, and recreation in and on the water, the state must maintain and protect that water quality at a higher level, with certain exceptions, under what are commonly called the “antidegradation” provisions.264

As an example, in Pennsylvania, these antidegradation provisions are reflected in 25 Pa. Code §§ 93.4a-93.4d. Pennsylvania recognizes two classifications of “special protection” waters that are subject to the antidegradation requirements: high quality (“HQ”) waters and exceptional value (“EV”) waters. As to HQ waters, new or increased point source discharges (discharges via a pipe or conveyance) must pass a rigorous review, including: (1) a demonstration that there are no feasible, environmentally-sound and cost-effective non-discharge alternatives;265 (2) in the absence of a feasible, environmentally-sound and cost-effective non-discharge alternative, a demonstration that the project sponsor is using the “best available combination of cost-effective treatment, land disposal, pollution prevention and wastewater reuse technologies” (referred to as “ABACT”);266 and (3) a showing either that the proposed discharge will not cause any reduction of water quality, or that any such lowering of water quality “is necessary to accommodate important economic or social development in the area where the waters are located.”267 The permitting criteria for EV waters are even more stringent. Like HQ waters, these criteria require (i) evaluation and selection of any feasible, environmentally-sound non-discharge alternative, and (ii) use of ABACT where there is no feasible and cost-effective non-discharge alternative.268 However, even if those two criteria are met, the third criterion mandates without exception no lowering of existing water quality.269 In other words, there is no option for utilizing social or economic benefits to justify a lowering (even slightly) of instream quality. Given these stringent criteria, obtaining permits for discharge of wastewaters associated with gas well development in special protection waters will be an extremely difficult, if not nearly impossible, task.

(c) Impaired waters

At the other end of the spectrum, one faces the issue of waters that are currently counted as “impaired,” in the sense that they do not presently meet instream water quality criteria.

264 40 C.F.R. §131.12(a)(2)-(3); See, e.g., The Raymond Proffitt Foundation v. U.S. EPA, 930 F.Supp. 1088 (E.D. Pa. 1996). 265 25 Pa. Code §93.4c(b)(1)(i). 266 25 Pa. Code §93.4c(b)(1)(i)(B). 267 25 Pa. Code §83.4c(b)(1)(iii). 268 25 Pa. Code §93.4c(b)(1)(i). 269 25 Pa. Code §93.4a(d).

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As a legacy of a variety of developments and conditions, a number of Appalachia region streams are challenged, and currently unable to achieve water quality standards. Under Section 303(d) of the Clean Water Act,270 states are required to identify these “impaired” waters where technology-based effluent limitations required under CWA §301 and other pollutant control requirements are not stringent enough to achieve instream water quality standards. Pennsylvania’s §303(d) list, for example, includes over 14,000 miles of streams as “impaired.”271 The prime causes of such impairment are abandoned mine drainage, siltation, and nutrients, followed by a variety of other causes. The process for identifying and correcting water impairments under the federal Clean Water Act Section 303(d) involves three distinct phases. First, the water is assessed to determine if it is or is not meeting water quality standards. Second, total maximum daily loads (“TMDLs”) are developed to correct pollution problems. Third, plans, programs, and regulatory steps must be taken to implement the TMDL objectives.

Under this three-step process, the key step is the development of a TMDL. A TMDL is the amount of pollutant loading that a waterbody can assimilate and still meet water quality standards. A TMDL is the “sum of individual waste load allocations for point sources, load allocations for non-point sources and natural water quality and a margin of safety express in terms of mass per time, toxicity or other appropriate measures.”272 Thus, TMDLs are to account for all sources of pollutants (both natural and manmade), and allocate loadings among those contributing sources to form a budget of how much loading can come from each source without causing an exceedance of instream objectives. TMDLs are to be developed for the sources and causes of impairment identified on the 303(d) list. Thus, allocations are made to the appropriate sources of pollutant loading, with individual waste load allocations made to specific point sources, coupled with allocations of allowable loadings from non-point sources. At this point, DEP has completed TMDLs only for a fraction of the identified impaired waters. The final stage in the process involves the development and implementation of implementation or restoration plans – with specific steps to be taken to control point and non-point sources to achieve the wasteload allocations provided in the TMDL. These implementation plans will, in most cases, involve the imposition of more stringent effluent limitations, higher best management practices, and other measures to conform to the wasteload allocation for each point source or category of non-point sources. By definition, such TMDL reductions go beyond “technology,” and may impose

270 33 U.S.C. §1313(d). 271 PaDEP, 2008 Pennsylvania Integrated Water Quality Monitoring and Assessment Report at 3 and 32 (Table 2), available at: http://www.depweb.state.pa.us/watersupply/cwp/view.asp?a=1261&q=535678. 272 25 Pa. Code §96.1.

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requirements that necessitate much more than “end of the pipe” solutions (i.e., changes in processes, materials, equipment and practices).

6.3 Water Quality Construction Permits for Wastewater Facilities

Beyond NPDES permits, some jurisdictions require separate design reviews and pre-construction permits for wastewater treatment facilities.

(a) Pennsylvania

Pennsylvania maintains a separate construction permitting program for industrial wastewater treatment works. Under Section 308 of the Clean Streams Law,273 what is known as a Water Quality Management (Part II) Permit must be obtained for any construction, expansion or alteration of an industrial wastewater treatment facility. The application for such a Part II permit must be accompanied by an engineer’s report, plans and specifications clearly showing what is proposed and the basis of design for the contemplated treatment equipment and units.274 Such plans must be prepared and sealed by a registered professional engineer.275

(b) Ohio

Ohio requires a Permit to Install (“PTI”) prior to the construction or installation of either municipal or industrial wastewater treatment facilities or works for disposal of treatment sludges.276 Designs prepared and certified by a professional engineer must be submitted to the Ohio Environmental Protection Agency (“Ohio EPA”).277 Among the criteria for review, Ohio EPA is required to determine whether the proposed system will “[e]mploy the best available technology.”278

(c) Delaware River Basin Commission

The installation or expansion of an industrial wastewater treatment plant discharging to any surface or ground waters within the Delaware River Basin must obtain a “project approval,” from the DRBC. Under Section 3.8 of the Delaware River Basin Compact,279 DRBC requires a project approval for the construction or alteration of any facilities directly discharging industrial wastewater to groundwater or surface water

273 35 P.S. §691.308. 274 25 Pa. Code §91.23. 275 25 Pa. Code §91.23(b)-(d). 276 Ohio Rev. Code. §§6111.44-6111.45; Ohio Admin. Code Ch. 3745-42. 277 Ohio Admin. Code § 3745-42-03. 278 Id. § 3745-42-04(A)(3). 279 32 P.S. §815.101.

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having a design capacity greater than 50,000 gpd.280 Industrial wastewater treatment facilities discharging within the drainage areas of waters classified as “outstanding basin waters” or “significant basin waters” under the DRBC water quality regulations281 have a lower 10,000 gpd threshold triggering project approval requirements.282 DRBC reviews project approval applications for consistency with the Delaware River Basin Comprehensive Plan, composed of the compendium of regulations, policies, and plans adopted by DRBC to manage the quality and quantity of basin water resources. The Comprehensive Plan includes standards that are, in some cases, more stringent than counterpart state water quality rules, such as standards governing increases in in-stream TDS concentrations.283 With respect to groundwater, DRBC water quality rules establish a “policy” to prevent degradation of groundwater quality. In implementing that policy, DRBC requires the best water management determined to be practicable; and no quality change will be considered which, in DRBC’s judgment, may be injurious to any designated present or future ground or surface water use or would result in concentrations at any point in excess of drinking water standards.284

6.4 Air Emission Issues for Water Treatment Facilities

Although perhaps not immediately obvious, water treatment facilities can often be the source of regulated air emissions. As examples, emissions triggering permitting issues may arise from electric generators or heat sources used for evaporation/crystallization technology, and treatment chemical or residuals storage may also engender particulate or other emission issues.

The nature and degree of emission regulation depends on total emissions from the facility, and whether facility qualifies as a “major source.”

280 18 C.F.R. §401.35(a)(5). 281 The DRBC water quality regulations are published as part of the Delaware River Basin Water Code, which is available on the DRBC website at: http://www.state.nj.us/drbc/drbc.htm. 282 18 C.F.R. §401.35(a)(5). 283 See Delaware River Basin Water Code §§3.20 and 3.30 (prescribing stream quality objectives for interstate and intrastate streams; generally establishing for most areas outside of the tidal estuary TDS limitations of 133% of background or 500 mg/l, whichever is less) 284 Delaware River Basin Water Code §3.40.4.

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(a) What counts as a “source” in defining “major source”

The federal “major source” definition refers to any source or group of stationary sources “within a contiguous area” and “under common control.”285 EPA interpretations look to the distance between facilities, functional relationships, interdependence, and common control factors, with no formula or bright lines defining what units or areas may be counted as part of a single “major source.”

EPA’s approach to defining a “major source” has potentially significant implications in the context of gas well wastewater operations. Water treatment facilities and natural gas production / processing facilities (including compressor stations) may all be considered a single “facility” for determining “major source” status, especially if (i) the water treatment facility is at or near the gas well site, and (ii) the water treatment facility is under control of the gas well operator.

(b) Potentially applicable air emission regulations

A thorough review of the potentially applicable air emission requirements is well beyond the scope of this chapter. Hopefully, it will suffice to not a few of the potentially applicable items to be considered. Permits. In most instances, federal and/or state laws require permits prior to the commencement of construction of any new air emission source or air pollution control device.286 Depending on the other requirements triggered by the source, the process for obtaining such constructions permits can be extended and complicated.

New Source Performance Standards (“NSPS”). NSPS are emission standards established by the U.S. Environmental Protection Agency that apply to facilities in a specific category, and establish emission limitations to all new facilities constructed after trigger date for that category. As one example, NSPS standards have been set for industrial-commercial-institutional steam generating units287 and for small industrial-

285 42 U.S.C. §7661(2). See, also, EPA Title V permit regulations at 40 C.F.R. §70.2, stating:

Major source means any stationary source (or any group of stationary sources that are located on one or more contiguous or adjacent properties and are under common control of the same person (or persons under common control) belonging to a single major industrial grouping and that are described in paragraphs (1), (2) or (3) of this definition. …

(emphasis added). 286 See, e.g., 25 Pa. Code §127.11 et seq. (plan approval requirements); N.Y. Comp. Codes R. & Regs. tit. 6, §201-5.1 et seq. 287 40 C.F.R. Part 60, Subpart Db.

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commercial-institutional steam generating units,288 which may apply to certain forms of evaporation and crystallization units.

New Source Review in Non-Attainment Areas. Under the federal Clean Air Act, major sources which have emissions greater than certain quantities of certain air contaminants within areas which fail to meet national ambient air quality standards are required to undergo pre-construction new source review (“NSR”) and meet stringent emission limits.289 In the Appalachian region, all of Pennsylvania and New York are part of the Ozone Transport Region and considered at least “moderate” non-attainment of the precursors of ozone: volatile organic compounds (“VOCs) and nitrogen oxides (“NOx”). Some areas closer to the New York and Southeastern Pennsylvania metropolitan areas are classified as even more severely non-attainment. In most of Pennsylvania and New York, a major source is one emitting 50 tpy of VOCs or 100 tpy of NOx . In the more serious non-attainment areas, the trigger drops to 25 tpy of VOC or NOx. If a facility exceeds these NSR triggers, a permit is required before commencement of any construction. New major sources, or major sources undergoing a major modification, must implement the technology capable of meeting the Lowest Achievable Emission Rate (“LAER”) plus obtain offsets for all VOC or NOx emissions.

NSR in Attainment Areas - Prevention of Significant Deterioration (“PSD”). In areas where current ambient air meets national ambient air quality standards, new major sources of any criteria pollutant must undergo special reviews known as prevention of significant determination (“PSD”).290

PSD analysis involves determining whether the increase of pollutant emissions is significant, and substantially relies upon an emissions impact analysis. That analysis, in turn, may require ambient monitoring for up to one year to prepare for necessary modeling. The requisite modeling must demonstrate that the cumulative emissions from the proposed new source, coupled with existing permitted sources, will not cause exceedance of national ambient air quality standards. Further, as part of PSD evaluation, the source must show that it is implementing best available control technology (“BACT”).291

Hazardous Air Pollutants. If a source involves emissions of any identified hazardous air pollutants, the source must demonstrate that it will implement Maximum Achievable Control Technology (“MACT”) requirements.292

State Technology Standards. Beyond federal requirements, states may impose their own air emission technology mandates. As one example, Pennsylvania’s air

288 40 C.F.R. Part 60, Subpart Dc. 289 42 U.S.C. §§7501-7515; 40 C.F.R. §52.24 290 40 C.F.R. §§ 51.165-51.166, 52.21. 291 40 C.F.R. §52.21(j). 292 42 U.S.C. §7412(d); see generally 40 C.F.R. Part 63.

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regulations generally require that every newly permitted source carry out “best available technology” – which is judged by PaDEP staff based on either agency guidance or professional judgment.293

6.5 Underground Injection of Wastewater or Treatment Residuals

Injection of wastewaters into underground formations is a frequent practice other shale plays, such as the Barnett Shale development in Texas. Not surprisingly, many operators assume that similar underground injection practices are available in the Appalachian Basin. To date, however, underground injection of wastewater has been slow to develop, in part due to geologic constraints and in part as a result of legal and regulatory hurdles. This section discusses a few of those hurdles.

(a) Acquiring Rights to Allow Underground Injection

The first gating question involves the acquisition of necessary rights and permissions from involved property owners for the injection of wastewaters into underground horizons. While a typical natural gas lease accords the operator with certain rights to undertake activities ancillary to gas well drilling and development,294 such as injecting fluids for fracing, the typical lease probably does not contain language permitting injection and permanent disposal of wastewaters into formations below the land. Just as courts have held that the right to gas storage is separate from the right of gas extraction,295 and must be conveyed via explicit language, one would expect that rights to inject wastewaters would need to be obtained via separate conveyances or leases, or through clear and distinct language in the gas drilling lease.

In framing and negotiating an appropriate injection and disposal lease agreement, a number of issues must be considered.

First, of course, is what lands and property interests are potentially affected and who must be approached to grant associated injection and disposal rights. From a technical perspective, predicting the horizontal area that may be utilized for wastewater disposal (i.e., where the wastewater will flow to once injected) is not a simple matter. For example, the U.S. EPA has established a presumed zone of endangering influence based on a calculation of the area under which the injected fluid may move in the formation used for disposal. It is a fairly involved equation, with a number of variables and some assumptions and default settings. Given the layering and fracturing of formations that may be utilized for injection, the area of disposal may well not be a neat circle around an injection well, and consideration may need to be given to differential/preferential flow directions. At the same time, because of the split of surface

293 25 Pa. Code §127.12(a)(5). 294 See Belden & Blake Corp. v. Pa. Department of Conservation & Natural Resources, 969 A.2d 528, 532-33 (Pa. 2009); Chartiers Block Coal. Co. v. Mellon, 25 A. 597, 598 (Pa. 1893). 295 Pomposini v. T.W. Phillips Gas and Oil Co., 580 A.2d 776, 778-79 (Pa. Super. 1990).

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and mineral estates throughout much of the Appalachian Basin, occasioned by past coal, oil and gas activities, the surface owner of the land may not hold the rights, or the only rights, to the formations being impacted. Certain mineral holders may also be implicated.

Beyond the issue of “from whom” and “where” injection right might need to be obtained, injection and disposal leases should address with some care what activities are contemplated. Items to be considered, for example, include: (1) what strata are allowed for injection (e.g., below a certain depth); (2) rights not only for placement of the injection facilities, but also monitoring wells and other activities; (3) allowance for entry and inspection by governmental regulatory agencies; and (4) what steps will be taken if the surface owner’s water supplies or lands are impacted.

(b) Federal Safe Drinking Water Act – Underground Injection Control (“UIC”) Program296

Part C of the federal Safe Drinking Water Act (“SDWA”) establishes the federally mandated UIC program.297 Under the SDWA, a permit is required for any “underground injection,” defined as “the subsurface emplacement of fluids by well injection.”298 An amendment to the SDWA added by the Energy Policy Act modified the definition of “underground injection,” providing a limited exemption for the “underground injection of fluids or propping agents (other than diesel fuels) pursuant to hydraulic fracturing operations related to oil, gas, or geothermal activities.”299 This exemption is limited, however, to fluid injection for hydraulic fracturing activities, and does not extend to the disposal of any wastes, including drill cuttings, flowback water, or production brines. The UIC permit program is administered either by EPA or by states who have obtained EPA approval of programs meeting certain requirements (referred to as “primacy”). The basic federal rules governing UIC activities are set forth in 40 C.F.R. Part 144, while detailed permitting criteria and standards governing underground injection are found in Part 146. EPA’s current rules categorize UIC wells into five classes, based on similarity in the fluids injected, activities, construction, injection depth, design, and operating techniques. The five classes are:

296 The author would like to thank his colleague, Christopher Nestor, Partner in K&L Gates’ Harrisburg Office, for contributing substantially to the following discussion of federal and state UIC regulations. 297 42 U.S.C. §300h et seq. 298 Id. §300h(b)(1) and (d). 299 Id. §300h(d)(B)(ii).

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Class Use Citations

Class I

Used to place radioactive, hazardous or non-hazardous fluids (industrial and municipal wastes) into deep isolated formations beneath the lowermost underground sources of drinking water (USDW). According to EPA, there are no known radioactive waste disposal wells operating in the United States.300

40 C.F.R. §§ 144.6(a), 146.5(a) 40 C.F.R. Part 146, Subparts B, G

Class II

Used to inject brines and other fluids associated with oil and gas production, unless classified as hazardous waste at the time of injection, and for enhanced recovery of oil or gas and for storage of hydrocarbons.

40 C.F.R. §§ 144.6(b), 146.5(b) 40 C.F.R. Part 146, Subpart C

Class III Used to inject fluids associated with solution mining of minerals.

40 C.F.R. §§ 144.6(c), 146.5(c) 40 C.F.R. Part 146, Subpart D

Class IV

Used to inject hazardous or radioactive wastes into or above USDWs. As of 1984, these wells are banned unless authorized under a federal or state groundwater remediation project.301

40 C.F.R. §§ 144.6(d), 146.5(d)

For our purposes, the focus is upon Class II UIC wells, covering wells used for

disposal of fluid brought to surface from conventional oil and gas production. The applicable federal standards establish a myriad of requirements predicate to permitting, and governing subsequent operation, of such wells.

Planning for UIC wells requires evaluation of potential impacts within an “area of endangering influence.”302 That area is defined based upon a specified formula which considers a number of geologic and technical factors. The permit application must include a plan for corrective action to prevent fluid movement into drinking water sources;303 and an identification of all wells within area of review penetrating formations affected by pressure increase. Any proposed UIC well must be constructed to meet

300 See http://www.epa.gov/OGWDW/uic/wells_class1.html#what_is. 301 See 40 C.F.R. § 144.13. 302 40 C.F.R. §146.6. 303 40 C.F.R. §§144.55, 146.7.

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specific casing, cementing, logging and testing standards;304 and subsequently tested to demonstrate mechanical integrity.305 All Class II wells are subject to detailed, long-term monitoring requirements.306

(c) Pennsylvania

Currently, Pennsylvania does not have primacy for the federal UIC program, and hence EPA Region III is the permitting authority for issuing such permits in the Commonwealth.307 Pennsylvania, however, regulates wells utilized for disposal of oil and gas drilling and production fluids via rules adopted pursuant to the Pennsylvania Oil & Gas Act and Clean Streams Law, set forth in 25 Pa. Code § 78.18. PaDEP has consistently stated that two permits are required for disposal injection wells: a well permit from PaDEP pursuant to § 78.18 and a UIC permit from EPA.308

As part of the application for a state permit, the UIC well operator must (1) file an application for a well drilling permit under the Oil & Gas Act;309 (2) submit to PaDEP a copy of the UIC permit and application submitted to EPA under 40 C.F.R. Part 146;310 and (3) submit a control and disposal plan meeting requirements of 25 Pa. Code §91.34.311

(d) Ohio

Ohio is a primacy state for all classes of wells.312 The Ohio EPA regulates Class I, IV, and V wells under its Division of Drinking and Ground Waters, and the Ohio Department of Natural Resources (“Ohio DNR”) regulates Class II and Class III injection wells through its Division of Oil and Gas UIC Program.313

304 40 C.F.R. §146.22. 305 40 C.F.R. §146.8. 306 40 C.F.R. §146.23. 307 See 40 C.F.R. §§ 147.1950-147.1955. 308 See PaDEP, Bureau of Oil and Gas Mgmt., Oil and Gas Wastewater Permitting Manual at 35 (2001); PaDEP, Bureau of Oil and Gas Mgmt., Fact Sheet, Injection Wells for Disposal and Enhanced Recovery (Rev. April 2009). 309 25 Pa. Code §78.18(a)(1), cross-referencing permits under §78.11. 310 Id. §78.18(a)(2). 311 Id. §78.18(a)(3). 312 See 40 C.F.R. §§ 147.1800-147.1801. 313 Id. See also http://www.epa.state.oh.us/ddagw/uic.html.

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Ohio EPA’s regulations implementing Ohio’s UIC program for Class I, IV and V wells are consistent with the federal UIC program.314 With respect to Class II wells, the Ohio DNR is authorized to adopt rules and issue orders regarding the storage and disposal of “brine and other waste substances” pursuant to Ohio Rev. Code. §1509.22(C). For these purposes, “brine” means all saline geological formation water resulting from, obtained from, or produced in connection with the exploration, drilling, or production of oil or gas.315 Regulations governing produced water management have been codified at Ohio Admin. Code Ch. 1501:9-3 (saltwater operation) and Ch.1501:9-5 (enhanced recovery) of the Ohio Administrative Code. Notably, Ohio’s oil and gas law states that the Ohio injection well regulations are to be interpreted as no more stringent than the federal UIC regulations, unless a stricter interpretation is essential to ensure that underground sources of drinking water will not be endangered.316

(e) West Virginia

West Virginia has been granted primacy under the federal UIC program. The West Virginia Department of Environmental Protection’s Office of Oil and Gas issues Class II UIC wells for brine and fluid disposal under W.Va. Code R. §47-13-13.3. The West Virginia rules substantially parallel the federal UIC regulations.317

(f) New York

New York does not have primacy under the federal UIC program; but the N.Y. Department of Environmental Conservation’s Division of Mineral Resources regulates drilling, operation of brine disposal wells under N.Y. Environmental Conservation Law §23-0305(14). A well permit is required from the Division of Mineral Resources for any brine disposal well deeper than 500 feet. This includes any operation to drill, deepen, plug back or convert a well. Regardless of well depth, the NYSDEC Division of Water must be contacted for a determination of whether a State Pollution Discharge Elimination System (“SPDES”) permit is necessary to operate any brine disposal well. The NYSDEC indicates that only six UIC wells have been permitted in New York to date for the disposal of brines produced from oil and gas well drilling.318

(g) DRBC

As noted above, DRBC has invoked project review jurisdiction over all activities associated with the development of Marcellus Shale gas wells in the portions of the basin

314 See Ohio Rev. Code §§ 6111.043 et seq. (establishing program for regulation of the injection of sewage, industrial waste, hazardous waste, and other wastes into wells); Ohio Admin. Code §3745-34-04 (classification of wells, Classes I - V). 315 Ohio Rev. Code § 1509.01(U). 316 Ohio Rev. Code § 1509.22(D). 317 See W.Va. Code R. §47-13-1 et seq. 318 NYSDEC, Brine Disposal Well Summary, http://www.dec.ny.gov/energy/29856.html.

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which drain to special protection waters (that is, virtually all of the area underlain by Marcellus Shale).319 This project review authority would ostensibly extend to installation and operation of UIC wells in the Delaware Basin.

6.6 Residuals Management & Disposition

(a) What are the treatment residuals?

The potentially available treatment technologies all engender the generation of significant treatment residuals, and the management and disposition of those residuals could be as substantial a challenge as treatment of the flowback and produced wastewaters.

The substantial residual streams from various treatment units include the following: (1) low-TDS or distilled water; (2) sludges (from pretreatment for metals and suspended solids removal); (3) high TDS concentrated brine (from RO units and evaporation units); and (4) salt or salt cake (from crystallizer units).

The volume of these residuals can be substantial. Evaporation systems result in somewhat recovery rates of approximately 60%, but still leave an estimated 40% of the wastewater in the form of a concentrated brine. Thus, an oil and gas produced water treatment plant handling 1,000,000 gallons of influent wastewater (in the range of a typical flowback water volume from a single horizontal well) would produce an estimated 400,000 gallons per day of concentrated brine. That equates to 80 plus tanker trucks per day of saturated brine residuals to be taken for ultimate disposition. Likewise, crystallization ZLD does not make TDS go away, but instead leaves a large quantity of residuals to be managed. Depending on the influent chlorides concentration, a 1,000,000 gpd crystallization plant handling Marcellus Shale brines is anticipated to produce some 400-520 tons per day (146,000-190,000 tons/year) of salt cake.

(b) Categorization of residuals

Before determining the appropriate handling and disposition of such residuals, the first task involves classifying the materials. Are they hazardous waste or alternatively subject to some other waste regime?

Under RCRA, an exemption is accorded for drilling fluids, produced waters, and other wastes associated with the exploration, development or production of crude oil and natural gas.320 This leads to the question, are treatment residuals resulting from physical or chemical treatment of such residuals likewise eligible for the RCRA exemption?

319 See discussion of the DRBC Executive Director’s jurisdictional determination at Part 3.5(g)(ii), supra. 320 42 U.S.C. §6921(b)(2)(A).

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EPA’s interpretations of the exemption suggest that residuals from reclamation of exempt exploration and production wastes are exempt.321

As a result, most residuals resulting from treatment of flowback or produced fluids from a gas well would probably be classified a “residual” or “industrial” waste under state solid waste management laws, unless they qualify under state regulations as a “product” or “coproduct” or otherwise obtain some form of general permit or other state determination that the material is not a waste or no longer a waste.

(c) State regulation of residual or industrial waste or beneficial reuse of residuals

State regulations concerning the management of non-hazardous waste can vary significantly between jurisdictions. An example or two is provided for illustration.

(i) Pennsylvania

Pennsylvania has adopted an extensive set of regulations governing the management of non-hazardous waste produced from industrial and other non-municipal processes, referred to as “residual waste.”322 The Pennsylvania residual waste rules distinguish between a “waste” and a “coproduct.” A “coproduct” is a material of a physical character and chemical composition that is consistently equivalent to an intentionally manufactured product or produced raw material, if use presents no greater threat to health and the environment.323 It is potentially possible that salt produced from a crystallizer ZLD unit, if it meets all specifications for a use such as road salt application, might be found to meet the definition of a “coproduct” and thus fall outside of the waste management regime.

Alternatively, Pennsylvania provides the vehicle of “general permits” to allow for “beneficial use” of residual waste.324 A beneficial use general permit may be initiated by either an individual or industry-wide application, or on PaDEP’s own motion. The process for review and approval of such a general permit requires submission of descriptions of the waste to be covered, a complete chemical analysis, a description of the proposed beneficial use (e.g., road salt use), a detailed narrative and schematic of the production process from which the waste material was derived, proposed concentration limits for contaminants in the material, and a detailed demonstration of the efficacy of the

321 See 58 Fed. Reg. 15284, 15285 (March 22, 1993) (“[T]he Agency has consistently taken the position that wastes derived from the treatment of an exempt waste, including any recovery of product from an exempt waste, generally remain exempt from the requirements of RCRA Subtitle C. Treatment of, or product recovery from, E&P exempt wastes prior to disposal does not negate the exemption.”) 322 See 25 Pa. Code Chapters 287-299. 323 25 Pa. Code §§ 287.1 and 287.8-287.9. 324 25 Pa. Code §287.611 et seq.

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material for the proposed beneficial use.325 After a public notice and comment period, PaDEP may issue a general permit if it finds that the proposed beneficial use will be conducted in a manner that will not harm or present a threat to public health, safety, welfare or the environment through exposure to constituents in the material during the proposed use or after such use, and that the proposed use of the waste as a substitute for an ingredient in an industrial process or as a substitute for a commercial product will not present a greater harm or threat than the product or ingredient which the waste is replacing.326 Under this criteria, PaDEP will consider not only near term issues, but potentially longer term impacts (e.g., the relative risks resulting from runoff of “beneficial use” salt applied to roads compared to commercial grade salt). The general permit, if issued, will allow utilization of the material for a prescribed use, subject to various operating, reporting and recordkeeping conditions.327 Following issuance of such a general permit, any other person who wishes to undertake the same use may apply for coverage under the general permit, by submitting a request for registration seeking a determination of applicability from PaDEP.328

As of this writing, Pennsylvania has not tackled the issue of issuing either a coproduct or beneficial use general permit for the residuals resulting from treatment of gas well flowback or produced water. This remains an issue where there remains a number of open questions.

(ii) West Virginia

West Virginia had adopted rules, albeit less elaborate, which would similarly allow for beneficial use of non-hazardous waste materials. Under the West Virginia regulations, the Secretary of the W.Va. DEP may issue a beneficial use permit for the “use of a non-hazardous material for a specific beneficial purpose where it is done in a manner that protects groundwater and surface water quality, soil quality, air quality, human health, and the environment.”329 The W.Va. DEP will evaluate the analysis of the material and other information demonstrating its beneficial use characteristics, including an evaluation of the potential impact to human health and the environment from the proposed method of use.330 The beneficial uses contemplated in the West Virginia rule are focused upon land application in accordance with a list of location standards and restrictions,331 although the rules do not explicitly limit beneficial uses to land application situations.

325 25 Pa. Code § 287.621(b). 326 25 Pa. Code §287.624. 327 25 Pa. Code §§ 287.287.624, 287.631. 328 25 Pa. Code §§ 287.641-287.643. 329 W. Va. Code R. § 33-8-2.4. 330 W. Va. Code R. § 33-8-3.1.a. 331 W. Va. Code R. §§ 33-8-3.1 and 33-8-3.2.

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6.7 Implementing Wastewater Projects – Transactional Issues

At the same time as tackling the technical and regulatory issues associated with managing Marcellus Shale wastewaters, there are a number of important structuring and transactional issues that the legal and business teams must embrace. Among these are:

Who will develop, finance, own & operate such facilities?

Should the gas well operator develop a captive facility?

Are there advantages to joining forces with other gas operators?

Are viable commercial operators willing to develop such facilities, and under what arrangements can capacity be assured?

What arrangements are required to cover high fixed capital & operating costs?

If engaging a contractor or vendor to install or operate the wastewater system, how will the parties allocate risks associated with:

Permit and construction timing vs. regulatory imperatives governing discharges?

Variable wastewater production rates?

Variable wastewater characteristics (flowback vs. production waters; differences in frac fluids and geographic areas)?

Processing viability?

Process and equipment durability?

Changes in law and regulations?

Energy and chemical costs?

Residuals disposition (residual quality; cost changes; liability risks for product use; liability issues at disposal sites)?

7. Summarizing Key Challenges to Wastewater Management

As seen from the above dissertation, the challenges to adopting and implementing a viable wastewater management strategy are myriad and complex – an intertwined array of technical, legal, regulatory, and transactional issues. To take a step back, however, some of the overarching items to keep in mind:

Choosing the right technology. As Marcellus Shale development proceeds, operators will need technologies and facilities that provide

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Regulatory uncertainty and flux. As E&P companies are driving forward, the rules of the road are still being written. Important aspects of the regulatory roadmap are still in development, as exemplified by the PA TDS Strategy. Thus, one can’t just look at current regulations, but must look ahead to the possible regulatory landscape of coming years in order to make choices and frame investments that will be cost-effective and support the overall development plan.

Permitting time frames. Permitting processes are not simple, and their respective time frames can be extensive. The permitting of major wastewater facilities will consume considerable time. Some typical timeframes for major permits are:

Zoning and land development approvals (3-6 months)

NPDES permits (6-12 months, more of TMDLs or load allocations)

Water quality facility construction permits (90-120 days)

Air quality construction permits (6-12 months; plus 12 months of studies if PSD monitoring and modeling required)

Residual waste beneficial use general permits (200 days for new general permits; 60 days for eligibility determination under existing general permits)332

These time frames pose serious challenges to the industry in attempting to meet aggressive regulatory schedules, such as those seen in PaDEP’s TDS Strategy. Industry, in turn, must consider whether regulatory agencies modify procedures to accommodate their imperatives, or otherwise how can such mandates be adjusted.

8. Final Words

Leaving the sagebrush plains of Texas above the Barnett Shales for the “green” climes of the Appalachian Basin and the Marcellus Shale and similar shale plays in the east, one might have the impression that water resource issues are left behind. If this paper has one point, it is – tis not so. The Marcellus Shale and other shales of the eastern U.S. represent a marvelous and exciting energy development opportunity, and also a water resources and wastewater management challenge that will require strategic planning and legal/regulatory finesse.

332 See PaDEP, Guide to DEP Permits and Other Authorizations (2007), available at: http://www.depweb.state.pa.us/dep/cwp/view.asp?a=3&q=461114&depNav=|