K&L Gates Oil & Gas 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
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.
K&L Gates LLP
ou r f irm
Global legal counsel in more than 40 fully integrated offices
on four continents.
United States
Europe
Anchorage, Austin, Boston, Charleston, Charlotte, Chicago,
Berlin, Brussels, Frankfurt, London, Milan, Moscow,
Dallas, Fort Worth, Harrisburg, Los Angeles, Miami, Newark,
Paris, Warsaw
New York, Orange County, Palo Alto, Pittsburgh, Portland,
Raleigh, Research Triangle Park, San Diego, San Francisco,
Seattle, Spokane, Washington, D.C.
Middle East
Doha, Dubai
South America
Asia
São Paulo
Beijing, 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 Firm
K&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.
Apply a Global Perspective
K&L Gates is positioned at strategic intersections of the global economy, with one
We encourage our lawyers to provide
of the largest contingents of lawyers and offices across the United States of any
pro bono legal representation and
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.
to participate in other charitable,
community, educational, and
professional activities. In addition,
With approximately 300 lawyers based in Berlin, Brussels, Frankfurt, London,
Milan, Moscow, Paris, and Warsaw, K&L Gates is located in Europe’s largest
we actively recruit professionals
economies. We are well-situated to meet clients’ legal challenges arising under the
whose business and life experiences
U.K., German, French, Belgian, Italian, Russian, Polish, and EU legal regimes.
reflect the diversity of our clients
Our lawyers’ on-the-ground experience and knowledge enable them to give clients
and our communities. At K&L
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-
Gates, we believe diversity of
sized overseas companies looking to enter the market to experienced global busi-
opinions, attitudes, experiences, and
nesses with well-established operations in the region.
perspectives makes for a stronger
K&L Gates also has one of the largest international practices in Asia of any U.S.
work envrionment and more creative
law firm, with comprehensive coverage in Greater China. Our commitment to the
client solutions.
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 international 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.
Understand Critical Business Issues
Our corporate and transactional prac-
We have a sophisticated and growing
zations on a wide variety of corporate
tice is one of the most substantial in
global finance practice in areas
and tax issues related to their creation,
the profession. Each year, we complete
including structured finance; secu-
operation, and dissolution.
hundreds of mergers and acquisi-
ritization; derivatives; structured
tions and public and private debt
products; CDOs; real estate finance;
and equity offerings. Our lawyers in
municipal finance; and mezzanine,
the United States, Europe, Asia, and
leveraged, and acquisition finance.
South America are highly experienced
In support of our work with emerg-
in cross-border mergers and acquisi-
ing growth companies, we have a
tions, securities, regulatory, tax, and
substantial alternative capital markets
financing transactions. We maintain a
practice, including AIM listings,
balance between company-side and
PIPEs, reverse takeovers, and SPACs.
capital-markets clients in virtually every
industry segment.
Our lawyers are also highly regarded
for their integrity and experience in the
Several publications have acknowl-
arena of corporate governance, includ-
edged our lawyers as leaders in their
ing independent corporate investiga-
fields. We are routinely ranked among
tions. Our experience includes serving
leading law firms in the area of fund
as lead examiner in both the New
client representations in the mutual
Century and WorldCom bankruptcies
fund industry. Private Equity Analyst
and in the internal CBS investigation of
regularly ranks K&L Gates as one of
the “60 Minutes” story involving former
the “most active law firms” worldwide
President George W. Bush’s National
for both private equity/venture capital
Guard service.
transactions and fund formation. We
are also recognized as a leader in
the investment management finance
industry, hedge funds, and ESOPs.
The K&L Gates private clients practice 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, offering 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
Our tax-exempt organizations practice
issues, real estate services, and real
represents some of the world’s largest
estate litigation.
and best-known private and corporate
foundations and other charitable
organizations. We advise these organi-
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.
Creatively Resolve Disputes
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, multidimensional commercial and regulatory
disputes. They are tough, innovative,
Our dispute resolution lawyers are
recognized as among the foremost
practitioners in their field. We have
been rated a leading practice in the
representation of corporate policyholders in the insurance coverage
area and as a leading litigation firm for
Guided by a desire to improve
efficiency and reduce costs for
and committed to our clients’ interests.
the financial services sector. Additionally, our litigation engagements have
clients, our e-Discovery Analysis and
Our dispute resolution practice
helped to shape intellectual property
Technology (e-DAT) Group uses and
includes international arbitrations,
law in the fast-moving technology
civil and criminal trials, deal litiga-
sector. Our acclaimed e-Discovery
helped develop Attenex Patterns™,
tion, domestic and international class
Analysis and Technology (e-DAT)
actions, and appellate work. We have
Group also continues to pave the way
used to review massive amounts of
helped resolve disputes in the most
nationally and internationally in the
electronic records. We rely on similar
nuanced and complex areas, including
exploding field of e-discovery.
effective applications of technology
In our role as national coordinating
to deliver enhanced services and
counsel for companies facing mass tort
increased global integration to clients
intellectual property, construction law,
product liability, employment, toxic
tort, antitrust and trade regulation, and
a document mapping software
securities enforcement.
challenges, we have at once mounted
Litigation is clearly not the answer to
cost-saving efficiencies for our clients.
of our technological innovations, CIO
every dispute. We routinely partner
Our litigation and dispute resolution
magazine awarded the firm its annual
with clients to resolve disputes through
capabilities and extraordinary achieve-
arbitration, mediation, or other alter-
CIO Award in 2011, 2007, 2004,
ment within DuPont’s Global Primary
native dispute resolution techniques
Law Firm Network have earned us the
when they are the best solution to
DuPont Meeting the Challenge Award
promote our clients’ business objec-
six times.
tives. K&L Gates has handled arbitrations 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.
successful defenses and achieved
throughout the firm. In recognition
2003, and 2002.
Navigate the Regulatory and Policy Maze
K&L Gates’ regulatory lawyers guide clients through regulations set forth by govern-
The K&L Gates Global Government
ments at all jurisdictional levels in the United States, Europe, Asia, and other venues
Solutions® initiative brings together
around the world. Our lawyers bring unique perspective to regulatory matters, having
held positions with agencies such as the Securities and Exchange Commission, the
our firm’s diverse practices and teams
Federal Communications Commission, the Federal Trade Commission, the Depart-
to proactively influence regulatory
ment of Justice, and the Environmental Protection Agency.
change and other governmental
The firm’s regulatory and policy practice cuts across the many disciplines that
actions, develop business solutions
require highly specialized knowledge and experience to address governmental
to regulatory issues, and vigorously
regulation of the private markets. One of our key regulatory practices is in the
defend enforcement actions around
diversified financial services area. We represent a large majority of the major financial 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,
the globe. With more than 400
experienced professionals who have
served in government agencies on four
continents, K&L Gates is equipped to
internal investigations, and white collar crime. The many SEC alumni within our
assist clients with virtually any legal
practice provide the institutional insight and connections needed to deal with our
issue involving government.
clients’ compliance needs.
Our policy group is the largest of any
K&L Gates also fields an international
fully integrated global law firm. The
energy, infrastructure, and resources
group of over 60 bipartisan lawyers and
practice, advising clients in matters
policy professionals includes former
involving litigation, international arbi-
U.S. House and Senate members,
tration, mergers and acquisitions,
former Republican and Democratic
Foreign Corrupt Policy Act, concession
counsel, and staff to the House and
deals, permitting, and downstream
Senate leadership committees.
construction projects.
We represent clients’ interests before
In another rapidly evolving area,
the U.S. Congress, the courts, the
K&L Gates’ U.S. food and drug prac-
executive branch, and regulatory agen-
tice offers comprehensive legal and
cies. The public policy group strives to
regulatory counsel to companies and
understand a policy issue from every
other organizations regulated under the
direction—substantively and politi-
federal Food, Drug, and Cosmetic Act.
cally—and to use the collective knowledge 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 regulations. In the past several years, we
have handled more than 400 distinct
environmental matters in the United
States alone.
Other active regulatory practice areas
include data protection, anti-money
laundering, communication, government
contracts, antitrust/competition, health
care, school districts, and transportation.
Uncover and Protect Value
K&L Gates lawyers advise and rep-
Our patent litigation lawyers bring not
resent some of the world’s most
only knowledge of the patent laws
prominent companies on cutting-edge
and an understanding of the substan-
IP issues, influencing technology and
tive technical issues embraced by the
intellectual property law as our clients
patent, but also the skill and resources
shape their industries.
to manage large, complex commercial
More than 225 of our lawyers, including approximately 105 registered
patent lawyers, many with engineering or advanced science degrees,
devote their practice to protecting and
commercializing clients’ intellectual
litigation. K&L Gates patent lawyers have
been involved in cases spanning a broad
spectrum of technologies, from hospital
equipment and medical devices to computer networking equipment to sports
equipment and outdoor clothing.
property assets, whether in the form
Our lawyers have literally written the book
of patents, trademarks, copyrights, or
on electronic commerce, helping clients
trade secrets. In addition to our tradi-
in all industries address new issues
tional IP work, we are at the forefront of
raised by electronic contracting, financial
intellectual property asset monetization,
regulations, privacy, and Internet issues.
using capital markets and other financial transactions to achieve our clients’
goals. In 2011, IP Today ranked K&L
Gates second out of more than 200
firms and individuals who represented
trademark registrations in 2010, based
on the number of registrations issued.
K&L Gates ranked No. 2 in IP Today’s 2011
list of the busiest trademark practices
in the United States.
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 firm
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.
Our Value Proposition
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 firm 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 firm 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 efficient and effective representations.
Our Global Platform
K&L Gates is positioned at strategic intersections of the global economy, with
strong local presence in key capital cities and world commercial and financial
centers. Our nearly 2,000 lawyers across more than 40 fully integrated offices and
dozens of significant practice areas create a worldwide network to serve our clients’
Our Experience as
Preferred Legal
Counsel
growing international needs. This global presence enables clients to mobilize their
For more than a decade, K&L Gates
outside legal team quickly in response to diverse legal issues around the globe
has been part of DuPont’s Global
through the services of one law firm, with one phone call.
Primary Law Firm Network. Prior to
1992, DuPont had more than 350 law
In the United States, we have coast-to-coast coverage with East Coast offices
firms and scores of service providers
from Boston to Miami, including New York, Newark, Pittsburgh, Harrisburg,
and consultants. During a three-and-
Washington, D.C., Charlotte, Charleston, Raleigh, and Research Triangle Park;
a-half year convergence process,
West Coast offices from Anchorage to San Diego, with lawyers also based in Los
the company transformed this group
Angeles, Orange County, San Francisco, Palo Alto, Portland, Seattle, and Spokane;
into a select legal network, with each
and offices in major cities in between, including Chicago, Dallas, Fort Worth,
member serving as a true long-term
and Austin. Our Asia presence includes Hong Kong, Beijing, Shanghai, Taipei,
strategic colleague. K&L Gates worked
Singapore, and Tokyo, while in Europe we are located in London, Paris, Berlin,
with DuPont throughout the process
Brussels, Frankfurt, Milan, Moscow, and Warsaw. We operate out of the Middle
and was chosen to become a part of
East from offices in Doha and Dubai and serve clients in South America from our
the network.
São Paulo office.
We have served as counsel to DuPont
on insurance coverage litigation, commercial litigation, outsourcing and
commercial transactions, real estate,
and investment management issues.
We strive to understand
the client’s business,
its objectives,and its priorities.
Our service to the company earned the
firm DuPont’s Meeting the Challenge
Award six times, recognizing K&L
Gates for its progressive policies and
legal performance.
Our Approach to
Client Relationships
Successful preferred provider relation-
Planning
ships require the active involvement
Open communication is at the core of successful business relationships. This
of both parties. We approach client
consists of mutual feedback, including a candid discussion of each party’s core
relationships with a one-company,
competencies. We engage in joint planning sessions with the client, set goals and
one-team mentality, consistently
objectives for the relationship, develop standardized procedures for handling all
seeking proactive ways to add value to
cases and matters, and identify expectations. Our goal is a work plan that allocates
our client work. We constantly strive to
resources in the best-suited and most cost-effective manner for the specific issue
listen to and strengthen our relation-
at hand, and in keeping with the clients’ larger business objectives.
ships with our clients so we can continue to be responsive to their business
needs domestically and abroad.
Accountability
We recognize that our clients are in the best position to define satisfaction, to set
Thanks to this philosophy, the BTI
priorities on service matters, and to evaluate our performance in those areas. To
Consulting Group recognized K&L
that end, we conduct regular appraisals and monitor all of our professionals to
Gates as a leader in client service on
ensure that our performance continues to satisfy our clients’ requirements and that
the 2012 BTI Client Service A-Team
we provide consistent, measurable, first-class service throughout our relationship.
survey. The firm is also the first and
We use the information gained from these appraisals as benchmarks for future
only law firm to receive PPG Industries’
improvement. We also use these periodic reviews to explore additional opportuni-
Excellent Supplier Award.
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
Client Teams
As a global law firm with nearly 2,000
Client teams serve as our mechanism
lawyers located in more than 40 offices
to manage large clients across the firm,
in North America, Europe, Asia, the
without added cost to the client. While
Middle East, and South America our
we have supported informal client teams
seamless cross-office capabilities
for decades, K&L Gates has invested in
ensure that K&L Gates staffs its client
developing and sustaining a formal client
engagements with the most experi-
team initiative that is devoted to providing
enced and cost-effective personnel
even greater service to our clients. This
regardless of location.
initiative places a high level of emphasis
Our ability to match resources to a particular matter’s demands, neither overnor under-staffing any project, is key to
successful engagements. As a result,
work often is performed, in coordina-
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.
tion with inside counsel, by K&L Gates
Client teams comprise lawyers in mul-
lawyers from across our network of
tiple offices and practices across the
offices. A core cross-disciplinary team,
firm, and are not limited only to those
consisting of a relationship manager and
lawyers that currently work for a client.
supervising partners from each applica-
In this way, the firm can share thoughts
ble practice area, works closely with in-
and ideas related to the business of a
house counsel to understand business
client, without focusing only on those
needs and objectives and to provide
areas that we currently serve. At no
ongoing performance monitoring.
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 considers most relevant.
Clients also benefit from the substantial
investment in technology K&L Gates has
made over the years. Teams have developed 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.
Transparency
Technology
Continuous investment in the use of
related contacts, and billing history. The
Keeping surprises to a minimum is
technology is crucial to keeping pace
platform is highly customizable and can
a key tenet of our client relationship
with our clients’ requirements for
be adapted to the particular needs of a
approach. Through regular commu-
enhanced communication and service
client or case.
nication, we strive to keep our clients
delivery. Consequently, our systems and
processes are state-of-the-art and fully
tested for efficiency, reliability,
and practicality.
In recognition of our technological innovations, CIO magazine awarded the firm
its annual CIO Award in 2011, 2007,
2004, 2003, and 2002. In 2010, for a
Our sophisticated extranet enables
second consecutive year, K&L Gates
clients to view and share documents
was named among the top 250 com-
with their K&L Gates client team.
panies in the InformationWeek 500, an
Created to provide real-time access to
annual listing of the United States’ most
information and materials related to
innovative users of business technol-
legal matters in progress, our extranet
ogy. The firm was one of only three law
is a password-protected, client-specific
firms ranked.
portal that contains a calendar of events,
document and image libraries, matter-
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 communication takes the form of informal
updates and reports in the format that
best suits our clients’ preferences.
We have built a broad collection of
work product that practice groups
can use to a client’s advantage.
Early Cost Assessment
Our Value-added Services
For many litigation engagements, K&L
We regularly produce seminars designed to update our clients on recent changes
Gates employs an Early Cost Assessment
in the law, new areas of practice, and emerging trends. We encourage our clients to
(ECA) strategy to evaluate, plan, and
participate in our in-house programs, either in person or via webcast. In addition, we
implement cost-effective litigation reso-
present programs, customized to clients’ particular needs, on-site at clients’ places of
lution strategies. The ECA approach is a
business. Seminar topics range from employment law updates to the latest in mort-
collaborative effort with in-house counsel
gage banking regulations to risk management issues applicable to every company.
to build a strategic litigation plan with
Our e-DAT lawyers who address issues relating to e-discovery and records manage-
a corresponding budget and a realistic
ment are some of our most active presenters. They also offer a training module and
definition of what constitutes a favorable
foldering guide for email users, a training module for litigation holds,
resolution of a case. K&L Gates uses the
and an interactive instructional program for training corporate personnel about
ECA process to ensure proactive lawyer-
e-discovery issues.
ing, and consideration and evaluation of
resolution options, early and often.
In addition, we have built a broad collection of work product that practice groups
can use to a client’s advantage. One of the benefits of a substantial firm that spans
Alternative Fee Arrangements
four continents is that we have the resources to maintain state-specific, multi-state,
We approach alternative fee arrange-
national, and international surveys, databases, analyses, and other work product.
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’ expectations and internal budgeting demands.
K&L Gates has been proactive in developing and implementing a variety of
AFAs for a wide array of engagements.
Several practice groups within the firm 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.consumerfinancialserviceswatch.com.
Our Commitment to Diversity
We 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 mainstream 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 firm. At K&L Gates, we are committed to fostering diversity to enrich the
experience of our lawyers, reflect 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 Offices
Anchorage
Charlotte
Harrisburg
420 L Street, Suite 400
Anchorage, Alaska 99501
+1.907.276.1969
Fax +1.907.276.1365
Hearst Tower, 214 North Tryon Street,
47th Floor
Charlotte, North Carolina 28202
+1.704.331.7400
Fax +1.704.331.7598
17 North Second Street, 18th Floor
Harrisburg, Pennsylvania 17101
+1.717.231.4500
Fax +1.717.231.4501
Austin
111 Congress Avenue, Suite 900
Austin, Texas 78701
+1.512.482.6800
Fax +1.512.482.6859
Hong Kong
Chicago
70 West Madison Street, Suite 3100
Chicago, Illinois 60602
+1.312.372.1121 Fax
+1.312.827.8000
Beijing
Suite 1009-1011, Tower C1
Oriental Plaza, No.1 East Chang An
Avenue
Dongcheng District, Beijing 100738 China
+86.10.5817.6000
Fax +86.10.8518.9299
London
Dallas
1717 Main Street, Suite 2800
Dallas, Texas 75201
+1.214.939.5500
Fax +1.214.939.5849
One New Change
London EC4M 9AF, England
+44.(0)20.7648.9000
Fax +44.(0)20.7648.9001
Los Angeles
Doha
Berlin
44th Floor, Edinburgh Tower, The Landmark
15 Queen’s Road Central, Hong Kong
+852.2230.3500
Fax +852.2511 9515
Markgrafenstraße 42
10117 Berlin, Germany
+49.(0)30.220.029.0
Fax +49.(0)30.220.029.499
Al Fardan Office Tower
Office 950, 9th Floor
PO Box 31316 West Bay, Doha, Qatar
+974.4410.1863
Fax +974.4410.1864
Boston
Dubai
State Street Financial Center, One Lincoln
Street
Boston, Massachusetts 02111
+1.617.261.3100
Fax +1.617.261.3175
Currency House, Level 4
Dubai International Financial Centre
P.O. Box 506826, Dubai
United Arab Emirates
+971.(0)4.427.2700
Fax +971.(0)4.447.5225
Brussels
Brussels City Centre
Stephanie Square
Avenue Louise 65, box 11
1050 Brussels, Belgium
+32.(0)2.535.7774
Fax +32.(0)2.535.7910
Fort Worth
Charleston
Frankfurt
4000 Faber Place Drive
Suite 300
North Charleston, South Carolina 29405
+1.843.323.4240
Fax +1.843.628.4823
OpernTurm
Bockenheimer Landstraße 2−4
60306 Frankfurt am Main, Germany
+49.69.94.51.96-0
Fax +49.69.94.51.96-499
D.R. Horton Tower, 301 Commerce,
Suite 3000
Fort Worth, Texas 76102
+1.817.347.5270
Fax +1.817.347.5299
10100 Santa Monica Boulevard, 7th Floor
Los Angeles, California 90067
+1.310.552.5000
Fax +1.310.552.5001
Miami
Southeast Financial Center
200 South Biscayne Boulevard, Suite 3900
Miami, Florida 33131
+1.305.539.3300
Fax +1.305.358.7095
Milan
piazza San Marco, 1
20121 Milano
Italia
+39.02.3030.291
Fax +39.02.3030.2933
Moscow
4th Lesnoy Pereulok
Building 4, 5th Floor
Moscow, 125047, Russia
+7.495.643.1700
Fax +7.495.643.1701
Newark
Research Triangle Park
Taipei
One Newark Center, Tenth Floor
Newark, New Jersey 07102
+1.973.848.4000
Fax +1.973.848.4001
430 Davis Drive, Suite 400
Morrisville, North Carolina 27560
+1.919.466.1190
Fax +1.919.831.7040
30/F, 95 Tun Hwa S. Road, Sec. 2
Taipei, 106, Taiwan
+886.2.2326.5188
Fax +886.2.2325.5838
New York
San Diego
Tokyo
599 Lexington Avenue
New York, New York 10022
+1.212.536.3900
Fax +1.212.536.3901
3580 Carmel Mountain Road, Suite 200
San Diego, California 92130
+1.858.509.7400
Fax +1.858.509.7466
Orange County
San Francisco
Kasumigaseki Common Gate West Tower
35F
3-2-1 Kasumigaseki, Chiyoda-ku
Tokyo 100-0013, Japan
+81.3.6205.3600
Fax +81.3.3597.6421
1900 Main Street, Suite 600
Irvine, California 92614
+1.949.253.0900
Fax +1.949.253.0902
4 Embarcadero Center, Suite 1200
San Francisco, California 94111
+1.415.882.8200
Fax +1.415.882.8220
Palo Alto
São Paulo
630 Hansen Way
Palo Alto, California 94304
+1.650.798.6700
Fax +1.650.798.6701
Rua Iguatemi 151, conjunto 281
Ed. Spazio Faria Lima
São Paulo, SP 01451-011 Brazil
+55 11 3704 5700
Fax +55 11 3958 0611
Paris
116 avenue des Champs-Elysées
75008 Paris, France
+33.(0)1.58.44.15.00
Fax +33.(0)1.58.44.15.01
Seattle
925 Fourth Avenue, Suite 2900
Seattle, Washington 98104
+1.206.623.7580
Fax +1.206.623.7022
Pittsburgh
K&L Gates Center
210 Sixth Avenue
Pittsburgh, Pennsylvania 15222
+1.412.355.6500
Fax +1.412.355.6501
Shanghai
Suite 3705, Park Place
1601 Nanjing Road West, Jing An District
Shanghai, 200040, China
+86.21.2211.2000
Fax +86.21.3251.8918
Portland
222 SW Columbia Street, Suite 1400
Portland, Oregon 97201
+1.503.228.3200 Fax
+1.503.248.9085
Raleigh
4350 Lassiter at North Hills Avenue,
Suite 300
Raleigh, North Carolina 27609
+1.919.743.7300
Fax +1.919.743.7358
Singapore
10 Collyer Quay
#37-01 Ocean Financial Centre
Singapore 049315
+65 6507 8100
Fax +65 6507 8111
Spokane
618 West Riverside, Suite 300
Spokane, Washington 99201
+1.509.624.2100
Fax +1.509.456.0146
Warsaw
Al. Jana Pawła II 25
00 854 Warsaw, Poland
+48.22.653.4200
Fax +48.22.653.4250
Washington, D.C.
1601 K Street, NW
Washington, D.C. 20006
+1.202.778.9000
Fax +1.202.778.9100
ENERGY, INFRASTRUCTURE & RESOURCES
If capital is the lifeblood of the global economy, infrastructure is its beating 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 financing, building,
and operating energy and infrastructure projects.
Our global platform includes lawyers
with experience across a broad range of
disciplines, including project finance and
development, public-private partnerships,
construction, energy and environmental
regulation, corporate finance, mergers and
acquisitions, government contracting, and
public policy. Our team has extensive experience in cross-border investment, development, acquisitions and dispute resolution.
K&L Gates serves clients involved
in every aspect of the global energy,
infrastructure, and resources
space through a wide variety of
legal disciplines.
Sectors Served
Power Generation and Transmission
K&L Gates lawyers assist power sector clients in meeting the growing global demand
for energy, including renewable energy. Our
clients include independent power producers, 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 customers, municipalities, investors, lenders,
developers, and contractors. We advise on
all aspects of financing, constructing, and
operating power generation facilities, and
on regulatory and commercial aspects of
power sales, transmission, asset acquisition and divestiture, and energy industry
mergers and acquisitions. We assist clients
developing Clean Development Programme
power production facilities in obtaining
carbon finance, and assist many other market participants in emissions trading and
renewable energy credits.
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 downstream sectors, including oil and gas field
development, petrochemical and refinery
developments, and energy trading.
Mining and Metals
Our experience in mining and metals spans
natural resources development, conservation, and management companies – including coal, aggregates, minerals, and
base and precious metals. We advise on
due diligence, negotiation, and transaction
documentation for capital markets and corporate 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.
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, investment and financing entities.
Telecommunication Facilities
K&L Gates advises a wide range of telecommunications infrastructure and service
providers – from local telephone companies
to wireless operators, and domestic and
international backbone providers to broadband service providers – on all aspects of
network build-out and operations.
Social Infrastructure
Water, Wastewater, and Reclaimed
Water Projects
Our team has considerable experience in
the siting, permitting, construction, operation, and implementation of water, wastewater, 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, government agencies, contractors, and suppliers
on transportation infrastructure projects
and transportation service agreements. We
have represented companies on project
management, design, construction, operation, 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 operators in all major sectors of the maritime
industry — containerships, roll-on/roll-off
vessels, liquid and dry bulk cargo vessels,
We have advised on a wide range of social
infrastructure projects -- encompassing
hospitals and health care systems, educational and research systems, social welfare
systems (including social housing, extra
care housing, and adult social care facilities), 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 involving trading and hedges in commodities,
including assistance with internal investigations and litigation. We also work with
multilaterals, lenders, development banks,
and other debt and equity providers in connection 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 Areas
Construction and Engineering
Project Development and Finance
Our Construction and Engineering lawyers 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, procurement, 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.
K&L Gates’ project finance lawyers address
the legal and commercial requirements
applicable to structuring, developing, constructing, and operating economically and
legally independent projects and facilities.
In developing and structuring projects, we
assist in multiple sectors, including governance arrangements and tax-efficient entity
structures. We are familiar with international
procurement laws, such as the EU procurement directives, which increasingly impact
international projects. In the financing
phase, our lawyers implement traditional
project financing, structured finance, taxable 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 investors, 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, museums, parking systems, prisons, rail, roads
and bridges, ports, science and research,
stadiums, waste management, water, wastewater, and reclaimed water.
Energy and Environmental Regulatory
We advise global infrastructure, energy, and
resource clients with the many energy and
environmental regulations facing major resource extraction, infrastructure, and power
generation projects. We work with clients
to successfully navigate regulatory requirements and maintain good relationships with
regulatory agencies, elected officials, nongovernmental 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 matters, 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 nontraditional 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 Securities Enforcement
Companies with international business
face risks resulting from improper payments to foreign government personnel, 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 compliance 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.
Learn more about our Energy, Infrastructure & Resources practice at klgates.com.
Contacts:
United Kingdom, Europe & Africa
Paul Tetlow
+44.(0).207.360.8101
paul.tetlow@klgates.com
Michael G. Zanic
+1.412.355.6219
michael.zanic@klgates.com
Asia
Maria Tan Pedersen
+852.2230.3598
maria.pedersen@klgates.com
Middle East
Paul M. Simpson
+971.4.427.2721
paul.simpson@klgates.com
10003
United States
Elizabeth Thomas
+1.206.370.7631
liz.thomas@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 gasproducing 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 MidAtlantic 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 fulltime, 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, resultsoriented, 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
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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.
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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
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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
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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, marketing, 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 governmentowned 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 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 corporate, commercial and
financial matters including:
•A
cquisition 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
• Project development and finance
•Cross-border mergers, acquisitions
and divestitures
• Bidding arrangements
“The strength and capability of the
K&L Gates team is evident in the
range of challenging energy projects...”
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 establishment 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 regarding 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 establishing a $100 million worldwide sales representation distributorship network that
minimized taxation and other liabilities
for operations.
• Advised a U.S. oil and gas exploration
company on the structuring and incorporation of its UK subsidiary.
• 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 production 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 producers in matters related to the preparatory
stage of construction of an LNG terminal 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 secondary 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 proforma agreements for the sale and
purchase of crude oil.
• Advised KBR, Inc. on the $280 million
disposal of its production services business in 25 jurisdictions to a management team.
• Advised Halliburton Company on the
acquisition of PSL Energy Services
Limited in various jurisdictions in
Europe, the Middle East and the AsiaPacific Region.
• Advised Halliburton Company on its
acquisition of Protech Centerform, a
provider of casing centralization.
• Advised Halliburton Company in relation to its contested public bid for oil
services company Expro International.
• Advised a large international industrial
company on the $515 million disposition 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 investment 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 companies 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 products 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 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
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/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.
• 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 operation agreement for the LNG plant.
• Represented a major Chinese oil
company in the evaluation and negotiation of the purchase of a working interest 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 advising on various aspects of inter-creditor
agreements, subscription agreements,
indemnity deeds, common terms
agreements and inter-company loans.
• A
dvised an onshore exploration and
production company in India on the
financing for design and construction 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, including 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 contracts for Vietnamese offshore exploration 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 preparation 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 contract with the Myanmar government.
• Advised a company involved in the
exploration and production of oil and
gas primarily in Indonesia on the monetization of natural gas produced from
the Sebaya gas field in East Java.
• Advised the government on the monetization of natural gas produced from gas
fields in East Java.
• Represented a global group of energy
and petrochemical companies in drafting 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 operating 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 disposal 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 exploration company on its $31 million
pre-IPO fundraising.
• Advised and assisted an oil field services 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.
“We represent all participants in
the oil and gas industry...”
North America (Non-U.S.)
•A
dvised 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.
•R
epresented a Toronto Stock
Exchange-listed, Canadian independent
oil and gas E&P company in connection 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 Exchangelisted Canadian oil field services
company.
•R
epresented a Calgary-based independent energy company in the acquisition of $81 million of Alberta petroleum
production and exploration assets.
•R
epresented a Calgary-based independent energy company in the acquisition
of an Alberta partnership with petroleum production and exploration assets
in a multi-step, tax-advantaged transaction 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 manufacturers to develop technology and equipment for sale and use in Mexico, Latin
America and the U.S.
• 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 production facility in the Gulf of Mexico.
• Assisted
a Latin American stateowned petroleum company to extend
a $1.4 billion joint venture with a
global group of energy and petrochemicals companies.
• Represented a Mexican oil and gas producer 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 regulation, development, and finance
of a number of natural gas-fired projects 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 independent oil and gas E&P company in the
$810 million acquisition of producing
and undrilled federal leases in the
Gulf of Mexico in two contemporaneous transactions.
South America
• Acted as special U.S. maritime counsel
to lessor in $65 million sale-leaseback 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 development 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 structuring credit support arrangements for
the financing of exploration and production 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, shareholders 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 offshore 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 buildoperate-lease-transfer (BOLT) basis.*
• Represented an Indian oil company in relation to the construction of a multi-product
pipeline in North Africa on a build-operatelease-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 terminal 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 establishment 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).*
•R
epresented 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.
“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 production 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.
For more information about our International (Non-U.S.) Oil & Gas Experience, please contact any of the
lawyers listed below:
Beijing
Rose W. Zhu
+86.10.5817.6110
rose.zhu@klgates.com
Moscow
William M. Reichert
+7.495.643.1712
william.reichert@klgates.com
Tokyo
Robert E. Melson, Jr.
+81.3.6205.3602
robert.melson@klgates.com
Dubai
Paul de Cordova
+971.4.427.2704
paul.decordova@klgates.com
Singapore
Raja Bose
+65.6507.8125
raja.bose@klgates.com
Warsaw
Tomasz Dobrowolski
+48.22.653.4221
tomasz.dobrowolski@klgates.com
London
Mathew C. Kidwell
+44.(0)20.7360.8141
mathew.kidwell@klgates.com
Taipei
Christina C.Y. Yang
+886.2.2326.5198
christina.yang@klgates.com
10035
Contacts:
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 operational 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 companies, 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 negotiations covering everything from leasing and
drilling to marketing, processing, transportation and storage. It is this base of detailed
operational knowledge and experience that
separates K&L Gates from
other national and global firms.
Our understanding of the operations and
business of oil and gas makes K&L Gates
uniquely effective when it comes to handling 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 innovative 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,
“...K&L Gates attorneys have an
impressive track record
of closing large transactions...”
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’ domestic 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 completion in return for a net profits interest and
a commitment to use its well drilling and
completion services.
Mergers, Acquisitions, and
Corporate Transactions
• Represented producers in the negotiation
of various drilling and joint development
contracts both onshore and offshore.
• Represented
a private E&P company in
the divestiture of the company through a
stock sale for in excess of $100 million.
• Represented producers in connection
with swaps, collars and other physical
and financial hedging arrangements for
petroleum production.
•R
epresented 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 producers and processors in
various percent-of-proceeds and volume
fee-based processing contracts.
• Represented
a Dallas-based independent energy company in the divestiture
of California petroleum producing assets
for $30 million.
• Represented numerous mineral owners
and residential developers in connection
with leasing oil, gas and other minerals.
• 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 operations 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 undeveloped properties.
K&L Gates oil and gas attorneys also
Operational Matters
work seamlessly with the firm’s pro-
• Represented
client in connection with
multiple acquisitions of large mineral
lease tracts, fee mineral interests and
overriding royalty interests in the Fayetteville Shale play in Northwestern Arkansas.
fessionals in environmental and regulatory compliance, securities matters,
land use, litigation, utilities and power
generation, and other issues encountered by oil and gas clients.
• Represented producers in the negotiation of various petroleum product
marketing agreements.
• 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 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 multicompany financing in which one of the
key elements was the interpretation/revision of a gathering agreement
among affiliated parties for gas in southeastern Kansas.
• Represented numerous financial institutions in connection with reserved-based
loans secured by oil and gas production
in multiple jurisdictions.
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 Network
Sector Specific Advice
K&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 understanding 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.
We represent all participants in the oil and
gas industry, including governments and
government-owned corporations, producers, 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 production 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 lawyers understand both the
legal and commercial issues facing
the oil and gas sector.”
financing, rigs and floating platforms,
FPSOs, FSOs, FSRUs, and LNG liquefaction 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 transportation 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 Experience
The 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 corporate, 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 Work
Southeast 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 produced 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/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.
• 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 arbitration 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 defending 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$3billion acquisition of a 20-percent indirect interest in Pan American Energy
LLC, the second largest upstream oil
and gas producer in Argentina.
• Advised CNOOC on its US$212.5million sale of entire shares in its BVI
subsidiary to Talisman.
• Advised a major Chinese state-owned
enterprise on its proposed acquisition 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 operator of FPSOs and its various subsidiaries 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 multiproduct 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.
“Our lawyers understand both the legal
and commercial issues facing the
oil and gas sector.”
• Advised an Indian oil company in
relation to the expansion and refurbishment of a major refinery in the MENA
region on a BOLT basis.
•N
egotiated 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 governmentcontrolled 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.
•A
dvised 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 independent operator committed to environmental improvements and transparency. The borrower was Russia’s
Pechora Energy, a 100-percent subsidiary of UK registered Concorde Oil and
Gas plc.
• 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: S
ome of the transactions were completed by K&L Gates lawyers
while at their previous firms.
• 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 environmental and other compliance.
Learn more about our Asia Oil & Gas practice at klgates.com.
Singapore
Raja Bose
+65.6507.8125
raja.bose@klgates.com
Singapore
Mike Pollen
+65.6507.81204
mike.pollen@klgates.com
Taipei
Christina Yang
+886.2.2326.5198
christina.yang@klgates.com
Tokyo and Moscow
Sergey Milanov
+81.3.6205.3604 (Tokyo)
+7.495.643.1700 (Moscow)
sergey.milanov@klgates.com
Hong Kong
Maria Tan Pedersen
+852.2230.3598
maria.pedersen@klgates.com
Beijing
Rose Zhu
+86.10.5817.6110
rose.zhu@klgates.com
10159
Contacts:
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 interest 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 understanding of the legal aspects of exploring for,
producing, transporting, storing, marketing, 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:
• Oil and Gas Leases & Licensing
• Permitting
• Tax Issues
• Litigation
• Mediation and Arbitration
• Water Use and Reuse
• Surface Use Agreements
• Public Policy
• Municipal Ordinances
• Alaska Native Corporations
• Mergers and Acquisitions
• Business Establishment and
Operations
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
North America. This experience is strongly
complemented by significant pipeline and
utility regulatory experience. Our lawyers
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.
In addition to our oil & gas experience,
our broader energy, infrastructure, and
resources practice area leverages experience from many fields to address these
industries’ unique challenges. Lawyers
throughout our offices work together to
guide clients through strategic decisions,
policy initiatives, commercial transactions, 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 experience 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 taxation and credit programs. We also assist
our clients in navigating the dynamic business environment in Alaska, with extensive
contacts among the service industry,
Native Corporations, state and municipal
governments, and energy utilities. In short,
K&L Gates provides comprehensive legal
counsel in all areas affecting oil and gas
development in Alaska.
For more information about our Alaska Oil & Gas Practice, please contact:
Patrick S. Galvin
+1.907.777.7603
patrick.galvin@klgates.com
10306
Contacts:
ou r t ea m
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
Tom Birsic
Walter Bunt
John Englert
Mark Feczko
Donald
Kortlandt
Theodore
McConnell
Michael
McLean
Terrence
Murphy
Pierce
Richardson
Henry Snyder
Kristen
Stewart
George
Bibikos
Daniel
Delaney
David Fine
Peter Gleason
Chris Nestor
David
Overstreet
Timothy
Weston
Craig Wilson
Patrick
Galvin
Jack Erskine
Keith Shuley
John Cox
Office
Pittsburgh
Pittsburgh
Pittsburgh
Pittsburgh
Pittsburgh
Practice
Insurance Coverage
Litigation
Regulatory
Litigation
Real Estate
Phone
412.355.6538
412.355.8906
412.355.8331
412.355.6274
412.355.6515
Email
thomas.birsic@klgates.com
walter.bunt@klgates.com
john.englert@klgates.com
mark.feczko@klgates.com
donald.kortlandt@klgates.com
Pittsburgh
412.355.6566
ted.mcconnell@klgates.com
412.355.6458
michael.mclean@klgates.com
Pittsburgh
Corporate, M&A and
Securities
Corporate, M&A and
Securities
Regulatory/Public Policy
412.355.6339
terry.murphy@klgates.com
Pittsburgh
Real Estate
412.355.6786
pierce.richardson@klgates.com
Pittsburgh
Pittsburgh
412.355.6720
412.355.8925
henry.snyder@klgates.com
kristen.stewart@klgates.com
Harrisburg
Tax
Corporate, M&A and
Securities
Litigation
717.231.4577
george.bibikos@klgates.com
Harrisburg
Energy & Utilities
717.231.4516
dan.delaney@klgates.com
Harrisburg
Harrisburg
Harrisburg
Harrisburg
Litigation
Public Policy
Litigation
Litigation
717.231.5820
717.231.2892
717.231.4812
717.231.4517
david.fine@klgates.com
peter.gleason@klgates.com
chistopher.nestor@klgates.com
david.overstreet@klgates.com
Harrisburg
Energy/Environmental
717.231.4504
tim.weston@klgates.com
Harrisburg
Anchorage
Litigation
Regulatory
717.231.4509
907.777.7603
craig.wilson@klgates.com
patrick.galvin@klgates.com
Austin
Austin
Dallas
512.482.6875
512.482.6887
214.939.5599
jack.erskine@klgates.com
keith.shuley@klgates.com
john.cox@klgates.com
Martin Garza
Bobby
Majumder
William
Hyatt
Brian Montag
John Spinello
Dallas
Dallas
Public Policy
Environmental
Corporate, M&A and
Securities
Municipal Regulation
Corporate, M&A and
Securities
Environmental/Energy
214.939.5802
214.939.5945
martin.garza@klgates.com
bobby.majumder@klgates.com
973.848.4045
william.hyatt@klgates.com
Environmental/Energy
Regulatory,
Environmental
973.848.4044
973.848.4061
brian.montag@klgates.com
john.spinello@klgates.com
K&L Gates LLP
Pittsburgh
Newark
Newark
Newark
K&L Gates Oil & Gas Practitioners
Page 1
Lawyer
B. David
Naidu
Donald Stever
Gordon Peery
Carl Fink
Stanford
Baird
Barry
Hartman
Cliff
Rothenstein
Hon. Jim
Walsh
Rose Zhu
Office
New York
Paul de
Cordova
Patricia Tiller
Mathew
Kidwell
Howard
Kleiman
Jeremy
Landau
Georgy
Borisov
William
Reichert
Raja Bose
Michael
James Pollen
Christina
Yang
Tomasz
Dobrowolski
K&L Gates LLP
Phone
212.536.4864
Email
david.naidu@klgates.com
New York
Orange County
Portland
Raleigh
Practice
Regulatory,
Environmental/Energy
Environmental/Energy
Financial Services
Energy/FERC
Environmental/Energy
212.536.4861
949.623.3535
503.226.5725
919.743.7334
don.stever@klgates.com
gordon.peery@klgates.com
carl.fink@klgates.com
stanford.baird@klgates.com
Washington DC
Environmental/Litigation
202.778.9338
barry.hartman@klgates.com
Washington DC
Regulatory/Public Policy
202.778.9381
cliff.rothenstein@klgates.com
Washington DC
Regulatory/Public Policy
202.778.9321
jim.walsh@klgates.com
Beijing
+86.10.5817.6110
rose.zhu@klgates.com
Dubai
Corporate, M&A and
Securities
Litigation
+971.4.427.2804
paul.decordova@klgates.com
Dubai
London/Dubai
Litigation
Litigation
patricia.tiller@klgates.com
mathew.kidwell@klgates.com
London
Corporate, M&A and
Securities
Corporate, M&A and
Securities
Corporate, M&A and
Securities
Corporate, M&A and
Securities
Litigation
Litigation
+971.4.427.2711
+44.(0)20.7360.81
41 (London)/
+971.4.427.2700
(Dubai)
+44.(0)20.7360.81
42
+44.(0)20.7360.81
14
+7.495.643.1700
+7.495.643.1712
william.reichert@klgates.com
+65.6507.8125
+65.6507.8120
raja.bose@klgates.com
mike.pollen@klgates.com
+886.2.2326.5198
christina.yang@klgates.com
+48.22.653.4221
tomasz.dobrowolski@klgates.com
London
Moscow
Moscow
Singapore
Singapore
Taipei
Warsaw
Corporate, M&A and
Securities
Regulatory
howard.kleiman@klgates.com
jeremy.landau@klgates.com
georgy.borisov@klgates.com
K&L Gates Oil & Gas Practitioners
Page 2
K&L Gates Supporting Lawyers
Biographies for the K&L Gates partners listed below can be found at www.klgates.com.
Lawyer
Richard Paciaroni
Jason Richey
Matthew Smith
Office
Pittsburgh
Pittsburgh
London
Practice
Construction
Construction
Construction
Jeremy Davis
London
Jacqueline Fu
Taipei
Richard Herbert
London
Robert Langer
New
York/Moscow
Corporate, M&A and
Securities
Corporate, M&A and
Securities
Corporate, M&A and
Securities
Corporate, M&A and
Securities
David Luther
Dallas
Ronald West
Pittsburgh
Owen Waft
Dubai
James Green
London
Corporate, M&A and
Securities
Corporate, M&A and
Securities
Corporate, M&A and
Securities
Energy
Thomas Carey
Gail Conenello
John “Jack” Krill
Steven Epstein
Charlie Harris
John Sylvester
Michael Zanic
Michael
Brodowski, Ph.D.
Roberto Capriotti
George Dickos
Stephen Glazier
Chicago
Newark
Harrisburg
New York
Pittsburgh
Pittsburgh
Pittsburgh
Boston
William Kuss
Rick Hosking
Cliff Hutchinson
Ian Meredith
Pittsburgh
Pittsburgh
Washington
DC
Pittsburgh
Pittsburgh
Dallas
London
Linda Moore
Charles Rysavy
David Seidler
Dan Trocchio
Dallas
Newark
Fort Worth
Pittsburgh
Litigation
Litigation
Litigation
Litigation
K&L Gates LLP
Phone
412.355.6767
412.355.6260
44.(0).20.7360.8
246
44.(0).20.7360.8
133
886.2.2326.5125
Email
richard.paciaroni@klgates.com
jason.richey@klgates.com
matthew.smith@klgates.com
44.(0).20.7360.8
104
212.536.4818
(New York)/
7.495.643.1700
(Moscow)
214.939.5535
richard.herbert@klgates.com
412.355.6752
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971.4.427.2714
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Environmental
Environmental
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Litigation
Litigation
Litigation
412.355.6323
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44.(0).20.7360.8
171
214.939.4908
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412.355.6284
jeremy.davis@klgates.com
jacqueline.fu@klgates.com
robert.langer@klgates.com
david.luther@klgates.com
tom.carey@klgates.com
gail.conenello@klgates.com
john.krill@klgates.com
steve.epstein@klgates.com
charles.harris@klgates.com
john.sylvester@klgates.com
michael.zanic@klgates.com
michael.brodowski@klgates.co
m
roberto.capriotti@klgates.com
george.dickos@klgates.com
stephen.glazier@klgates.com
william.kuss@klgates.com
richard.hosking@klgates.com
cliff.hutchinson@klgates.com
ian.meredith@klgates.com
linda.moore@klgates.com
charles.rysavy@klgates.com
david.seidler@klgates.com
dan.trocchio@klgates.com
K&L Gates Oil & Gas Practitioners
Page 3
Lawyer
Paul Simpson
Office
Dubai/Doha
Practice
Project Development
and Finance
Eugene Segrest
Ronald Aulbach
Stephen Barge
Scott Newman
Dallas
Pittsburgh
Pittsburgh
New York
Real Estate
Tax
Tax
Tax
K&L Gates LLP
Phone
971.4.427.2721
(Dubai)/
974.4424.6100
(Doha)
214.939.4991
412.355.6249
412.355.8330
212.536.4054
Email
paul.simpson@klgates.com
eugene.segrest@klgates.com
ron.aulbach@klgates.com
steve.barge@klgates.com
scott.newman@klgates.com
K&L Gates Oil & Gas Practitioners
Page 4
a d d it ion a l m at e r ials
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
“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 LLP
April 4, 2012
Practice Group(s):
Energy, Infrastructure
and Resources
Oil & Gas
K&L Gates Represents Oil and Gas
Producers in Major Pennsylvania Supreme
Court Victory
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
2
K&L Gates Represents Oil and Gas Producers in Major
Pennsylvania Supreme Court Victory
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
3
March 2, 2012
Practice Group(s):
Energy, Infrastructure
and Resources
Oil & Gas
Final Implementation of Pennsylvania’s
Gas and Hazardous Liquids Pipelines Act
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.
2
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
3
Final Implementation of Pennsylvania’s Gas and
Hazardous Liquids Pipelines Act
4
February 21, 2012
Practice Group(s):
Energy, Infrastructure
and Resources
Oil & Gas
Two Birds by the Pit: Courts Split Over
Well Operator Liabilities under the Federal
Migratory Bird Treaty Act
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
1
liability under the Migratory Bird Treaty Act (“MBTA”). 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
2
in United States v. Brigham Oil & Gas, L.P. 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
2
Migratory Bird Treaty Act, 16 U.S.C. §§ 703-712 (“MBTA” or “the Act”).
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
4
a ‘taking’ or ‘killing’ within the meaning of the MBTA.” In contrast, courts in other oil-and-gasproducing 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
5
for the unintended electrocution of birds from power lines that supplied electricity to oil fields.
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
6
which incidentally and proximately cause bird deaths.” 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
7
incidentally killed as a result of totally legal and permissible activities, as happened here.” Thirtyfive 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
8
unintended bird deaths “proximately caused” by well-site activities. 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).
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).
5
2
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.
3
Two Birds by the Pit: Courts Split Over Well Operator
Liabilities under the Federal Migratory Bird Treaty Act
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
4
February 15, 2012
Practice Group(s):
Energy, Infrastructure
and Resources
Oil & Gas
Pennsylvania Legislation Authorizing
Counties to Levy Unconventional Gas Well
Fee Signed Into Law
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&bill
Typ=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.
Years Following
Commencement
of Drilling or
Adoption of the
Fee
Average Annual Price of Natural Gas per MMBtu
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
Year 11 to 15
$5,000
$20,000
$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).
2
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 restimulation 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
3
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.”
th
The 14 Amendment to the United States Constitution adopted in 1866 provides that “[n]o State shall make or enforce any
th
law which shall … deny any person within its jurisdiction the equal protection of the laws.” While initially the 14
4
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).
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).
13
15
Harrisburg School District v. Zogby, 574 Pa. at 137-38, 828 A.2d at 1089.
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).
16
5
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).
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.
19
6
Pennsylvania Legislation Authorizing Counties to Levy
Unconventional Gas Well Fee Signed Into Law
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
7
February 14, 2012
Practice Group(s):
Energy, Infrastructure
and Resources
Oil & Gas
New Pennsylvania Oil and Gas Law
Targets Unconventional Gas Operations
for Heightened Regulatory Oversight
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. §§ 32013274) 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
Buildings & water wells
200 feet from the well
Water well, surface water
intake, reservoir, or other water
supply extraction point used by
a water purveyor
None
Streams, springs, wetlands, and
other bodies of water
100 feet from the well site
or well
(but 200 feet water well
setback may apply)
New Setback for
Unconventional Wells
500 feet from the vertical well bore
1,000 feet from the vertical well
bore
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.
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).
3
2
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 be
needed to implement such a 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).
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).
9
3
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).
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.
17
4
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
Number of
Wells
Well Bore Length
50 or less
$4,000/well
$35,000 + $4,000/well in
excess of 50 wells
$60,000 + $4,000/well in
excess of 150 wells
$100,000 + $4,000/well in
excess of 250 wells
$10,000/well
$140,000 + $10,000/well in
excess of 25 wells
$290,000 + $10,000/well in
excess of 50 wells
$430,000 + $10,000/well in
excess of 150 wells
51 - 150
less than 6,000
feet
151 - 250
more than
250
25 or less
26 - 50
6,000 feet or
greater
Maximum
Bond
Bond Amount
51 - 150
more than
150
$35,000
$60,000
$100,000
$250,000
$140,000
$290,000
$430,000
$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.
58 Pa.C.S. § 3255-56.
58 Pa.C.S. § 3262.
27
58 Pa.C.S. § 3258.
25
26
5
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.
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).
29
6
New Pennsylvania Oil and Gas Law Targets
Unconventional Gas Operations for Heightened Regulatory
Oversight
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
7
February 9, 2012
Practice Group(s):
Energy, Infrastructure
and Resources
Oil & Gas
Pennsylvania’s Oil and Gas Act Amended
to Require "Uniformity" with Respect to
Municipal Ordinances Regulating Oil and
Gas Operations
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:
1
For 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.
2
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.
3
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).
4
Pennsylvania’s Oil and Gas Act Amended to Require
"Uniformity" with Respect to Municipal Ordinances
Regulating Oil and Gas Operations
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
5
January 3, 2012
Practice Group(s):
Energy, Infrastructure
and Resources
Pennsylvania’s New Gas and Hazardous
Liquids Pipeline Act
By Daniel P. Delaney, George A. Bibikos, Bryan D. Rohm
Oil & Gas
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.
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.
3
2
Pennsylvania’s New Gas and Hazardous Liquids Pipeline
Act
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
3
December 2, 2011
Practice Group(s):
Energy, Infrastructure
and Resources
Oil & Gas
EPA to Require Chemical Disclosure under
TSCA by Hydraulic Fracturing Fluid
Manufacturers
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
2
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-bywell 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.
3
EPA to Require Chemical Disclosure Under TSCA by
Hydraulic Fracturing Fluid Manufacturers
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
4
November 11, 2011
Practice Group(s):
Energy, Infrastructure
and Resources
Oil & Gas
PaDEP Issues Interim Guidance on Air
Aggregation, Moves Away from
"Functional Interdependence" Test
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 (NO x ) 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.
2
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
3
PaDEP Issues Interim Guidance on Air Aggregation, Moves
Away from "Functional Interdependence" Test
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
4
November 3, 2011
Practice Group(s):
Energy, Infrastructure
and Resources
Oil & Gas
Ohio EPA Releases Draft General Permit
for Oil and Gas Well-Site Production
Operations
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 WellSite 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).
2
Ohio EPA Releases Draft General Permit for Oil and Gas
Well-Site Production Operations
3
October 17, 2011
Practice Group:
Public Policy and
Law
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.
Battles Over the Federal Policies Regulating Hydraulic Fracturing
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.
2
Battles Over the Federal Policies Regulating Hydraulic Fracturing
 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
Government Affairs Advisor
Michael W. Evans
Partner
Cindy L. O’Malley
Government Affairs Counselor
cliff.rothenstein@klgates.com
+1.202.778. 9381
michael.evans @klgates.com
+1.202.661.3807
cindy.omalley@klgates.com
+1.202.661.6228
3
Battles Over the Federal Policies Regulating Hydraulic Fracturing
4
October 10, 2011
Practice Group(s):
Energy, Infrastructure
and Resources
Oil & Gas
Third Circuit Gives Natural-Gas Producers
Important Ammunition for Obtaining
Expedited Injunctive Relief from the Courts
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 wellestablished 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
2
Third Circuit Gives Natural-Gas Producers Important
Ammunition for Obtaining Expedited Injunctive Relief from
the Courts
3
September 20, 2011
Practice Group(s):
Energy, Infrastructure
and Resources
Oil & Gas
Is Marcellus Shale a “Mineral,” and Who
Owns the Natural Gas in the Shale?
Introduction
In Butler v. Charles Powers Estate 1 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 Rule 2 ,
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. Commonwealth 3 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
2
3
---A.3d---, 2011 WL 3906897 (Pa. Super. Ct. Sep. 7, 2011).
101 Pa. 36 (Pa. 1882).
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
5
U.S. Steel Corp. v. Hoge, 468 A.2d 1380 (Pa. 1983).
Silver v. Bush, 62 A. 832, 833 (Pa. 1906).
2
Is Marcellus Shale a “Mineral,” and Who Owns the Natural
Gas in the Shale?
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
3
July 29, 2011
Practice Group:
Oil & Gas
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. 411 (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.
West Virginia Governor Orders WVDEP to Enact Marcellus
Shale-Specific Regulations
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
2
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 tenyear 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
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
4
July 6, 2011
Oil & Gas
The Chesapeake Bay Foundation
Settlement – Changing Directions for E&S
Regulation of Oil & Gas Projects
On 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.
Background
In 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.
The Chesapeake Bay Foundation Settlement – Changing
Directions for E&S Regulation of Oil & Gas Projects
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 Settlement
Since 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
Page 2
The Chesapeake Bay Foundation Settlement – Changing
Directions for E&S Regulation of Oil & Gas Projects
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,
Page 3
The Chesapeake Bay Foundation Settlement – Changing
Directions for E&S Regulation of Oil & Gas Projects
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 Weston
tim.weston@klgates.com
P +1.717.231.4504
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
Pennsylvania
On 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 Application
On 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
Why the Public Utility Commission's Laser Northeast Decision
Will Not Lead to Regulation of All Natural Gas Gathering and
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 Decision
The 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 Decision
The 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
Page 2
Why the Public Utility Commission's Laser Northeast Decision
Will Not Lead to Regulation of All Natural Gas Gathering and
(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 Utility
Following 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.
Conclusion
The 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).
Page 3
Why the Public Utility Commission's Laser Northeast Decision
Will Not Lead to Regulation of All Natural Gas Gathering and
[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. Delaney
dan.delaney@klgates.com
P +1.717.231.4516
Page 4
OnStream
Highlighting developments and
The Arab Spring: Insurance Coverage For Losses
Arising From Political Change In The Middle East
And North Africa
issues in the international oil
The wave of popular uprisings across the Middle East and North Africa - the “Arab Spring”-
and gas industry
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
Summer 2011
their exposure to business risks associated with political discontinuities in these markets.
Welcome to the first edition of
There are likely to be several insurance policies which may respond to provide policyholders
“OnStream”, K&L Gates’ new
with financial support during this challenging time, but assessing how various exposures
publication for the international oil
could fall for coverage under different policies may not be a straight-forward task.
and gas industry, highlighting industry
Undertaking this assessment, and taking action to access responsive cover, should be a
developments and issues touching on
priority in the overall risk management response to events in the region, particularly as most
the development of projects around the
insurance policies require that insurers are given timely notice of actual or potential losses.
world’s major hydrocarbon basins.
Risk exposures for Oil & Gas policyholders in the region
In this issue we cover
the following topics:
Political Risks: Insurance Coverage ... 1
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,
Offshore Environmental Damage
absence of employees expatriated to their home countries, strikes by local workers and
Insurance ...................................... 2
unavailability of pipelines, ports and transportation routes
EIA Study: Shale Gas Resources....... 3
• Supply chain difficulties
LSE-TMX stock exchange merger: a
• Contractual risk, including contract frustration, repudiation or renegotiation, particularly
new era in fundraisings? ................. 4
where major natural resource contracts have been placed with governments in countries
Recent Developments ...................... 7
subject to regime change
• Government expropriation of assets
• Currency incontrovertibility and transfer risk, in addition to late payments impairing
cash-flow
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
Offshore Environmental Damage Insurance:
Not Just Window Dressing Any More
Neal Brendel and Michael Miguel of K&L
with an Internet connection in 2010 who
or “any attempt at” removing, nullifying or
Gates discuss how recent high profile
watched with fascination as the Deepwater
cleaning up the pollution. These provisions are
offshore energy disasters and judicial
Horizon well in the Gulf of Mexico
found in the standard form Energy Exploration
scrutiny have affected insurance coverage
discharged oil on a continuous live feed.
and Development (EED) form coverage, issued
for offshore pollution claims
The Deepwater Horizon accident had the
for use in the London market and now found
The offshore exploration and production
effect of heightening public sensitivities
in some form in energy package policies
energy sector is particularly susceptible
globally to offshore pollution damage. In
throughout the world.
to natural and operational losses that are
the United States, the timing of the disaster
catastrophic in nature. Since the mid-1980s,
coincided with the maturing of coverage
the standard “energy package” insurance
suits over claims arising from Hurricanes
policy has provided separate coverage for
Ivan and Katrina. Decisions were issued
damages caused by pollution, but it was
compelling the first publicly known payments
a windfall for the insurance industry in as
of full limits of liability by insurers for
an “attempt to nullify” pollution, are
much as premiums were paid, but claims
offshore pollution, including regulatory
undefined. Under the usual rules of contract
generally were not. Now, recent attention
liabilities arising from offshore pollution,
construction, these terms should be given
brought on by significant weather events
such as the Oil Pollution Act of 1990 (OPA
their ordinary meaning or be construed in
and high profile accidents, improvements in
’90). Indeed, 2010 was a pivotal year
favor of the assured, since they are found in
technology and judicial scrutiny has resulted
for assureds, as courts found that certain
the insurer’s standard-form agreement.
in insurers acknowledging and indemnifying
routinely asserted defenses to coverage
offshore environmental damages.
would no longer insulate insurers from
For decades, the insurance industry has
required strict proof that the oil detected
coverage liability or bad-faith claims.
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
Historical insurer response
The traditional response from the insurance
The policy language
industry has been to deny coverage for
in the ocean or sub-sea soils, even after
a blowout, emanated from an assureds’
Since the mid-1980s, energy package
covered well. The existence of naturally
on the assured to demonstrate that the
policies have included, as part of “control of
occurring seeps, and the high cost of
offshore pollution originates from a covered
well” coverage, separate grants protecting
technology required to prove the source
well. The cost of proving the source of
the assured from damages arising from
pollution, especially in a deepwater well,
“seepage and pollution, cleanup and
has historically been prohibitive. Recent
contamination.” These provisions provide
technological innovations now make it
broad coverage for legal liabilities
easier, and less costly, to deploy remote
(including lease obligations) for the cost of
operated vehicles that can identify the
remedial measures undertaken to address
location of pollution and assist in tying it
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
offshore pollution claims, placing the onus
pollution, and specifically include the cost of
Continued on page 6
2
OnStream
EIA Study: Shale Gas Resources
Shale gas is being viewed as an
The EIA study reports that it is expected
increasingly important source of future
that by 2035, 46 per cent of all natural
energy, particularly in the US, and
gas production in the US will be shale
the Energy Information Agency (“EIA”)
gas. Other countries around the world are
sponsored study, ‘World Shale Gas
just beginning to discover their shale gas
Resources: An Initial Assessment of 14
resources and the opportunities to use this
Regions Outside the United States’, released
relatively new source of energy.
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.
Countries identified in the study as having
significant shale gas resources included
France, Poland, Turkey, Ukraine, South
Africa, Morocco, Chile, Canada, Mexico,
China, Australia, Libya, Algeria, Argentina
Shale gas, as the name suggests is natural
and Brazil. The estimates given in the EIA
gas produced from shale, as distinct from
study may be conservative, as the study did
gas associated with oil, or gas captured
not include a number of countries which
in tight sands. Traditionally, shale has
may have additional shale gas resources
been seen as insufficiently permeable for
such as Russia and countries in the Middle
commercial extraction however, recent
East region. Neither did the study consider
technical advances have seen shale gas
potential offshore resources.
along with other unconventional plays such
as coal seam methane become genuine
commercial prospects.
For further information please contact
Laura Atherton (laura.atherton@klgates.com).
Summer 2011
3
LSE-TMX Merger – A New Era
In Fundraisings For Oil & Gas
Companies?
In February 2011 London Stock Exchange
and medium sized enterprises with LSE’s AIM
soaring commodity prices. The surge in oil,
Group plc (LSE) announced its proposed
market and TMX’s TSX Venture Exchange
metal and agricultural commodity prices has
£4.3 billion merger with TMX Group
together comprising some 3,600 small to
greatly increased the value of the natural
Inc. (TMX), the operator of the Toronto
medium cap and early stage companies.
resources sector on global exchanges in
Stock Exchange, in a deal that may have
significant implications for the financing of
natural resources companies in the years to
come. The transaction remains subject to
shareholder and regulatory approvals in both
CEO of LSE and the intended CEO of the
merged group said, “We are creating
the world’s largest listings venue for the
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.
commodities, energy and natural resources
Companies listed on the merged group’s
sectors as well as a premium market for
exchanges are expected to benefit from
small, mid-sized and growth companies.
improved access to a deeper and more
This new international leader… will be
flexible pool of international capital. Dual
Commentators are divided on the reasons for
strongly positioned to capitalise on growth
listings are expected to become easier
and merits of the proposed merger, but there
opportunities in emerging markets and
and more commonplace with companies
is overwhelming agreement that it is positive
deliver them to our customers in North
listed in London benefiting from improved
news for oil and gas and other natural
America, Europe and beyond.”
access to European and the Middle
Canada and the UK and, assuming those
approvals are forthcoming, is expected to
close in the second half of 2011.
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.
TMX, together with Canada’s banking, legal
and mining communities, have for years
been promoting Toronto as a global centre
Landau (jeremy.landau@klgates.com) or Oliver
in oil, gas and mining listings. The merged
Pilkington (oliver.pilkington@klgates.com).
experience in dealing with natural resources
would operate six equities listing venues
companies and be the obvious place to look
in Canada, the UK and Italy, catering to
for investors interested in the sector.
OnStream
to capital from North America.
itself long been recognised as a powerhouse
headquartered in London and Toronto and
become the primary listing venue for small
Canada benefiting from improved access
For further information please contact Jeremy
group is expected to offer unrivalled
believe the merged group is well placed to
Eastern capital and companies listed in
for natural resources financing and LSE has
The merged group would be joint-
issuers of all types and sizes. TMX and LSE
4
On announcing the merger Xavier Rolet,
The proposed merger has attracted a lot
of media attention against a back drop of
continued from page 1
• 72 hour occurrence clauses: First party
The Arab Spring: Insurance Coverage For
Losses Arising From Political Change In
The Middle East And North Africa
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
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
Political risks insurance: These policies
loss or occurrence in applying the
potentially respond where there has been
policy limits and deductibles. The
some form of interference with an asset or
wording of such clauses may require
an investment which is politically motivated.
careful consideration when presenting
Coverage can include most of the risk
claims to insurers.
exposures identified above.
risks. Potentially responsive policies include:
Supply chain disruption insurance: This
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,
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.
and war).
Accessing cover
Insurance policies usually contain a
Contingent business interruption insurance:
number of pre-conditions to recovery. Key
This can be included as an extension to the
considerations when accessing cover include:
main policy or coverage can be provided
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
however certain risks may be excluded from
coverage (such as political unrest, terrorism
• Waiting periods: Many policies also
• Notification: A common feature of
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.
by a stand-alone policy, and applies where
insurance policies is a requirement to
the ability of the policyholder to trade is
give notice of actual or potential losses
In conclusion, policyholders are well
impaired by external considerations such
within a certain period of time. Prompt
advised to review the terms of any
as damage to third party property, loss of
notification of claims is essential as
potentially applicable insurance policies
utilities, denial of access and political acts
failure to comply with the notification
as soon as possible if business has been
of local governments and regulators.
provisions of relevant policies may
impeded by recent events. If a claimable
enable insurers to restrict or deny cover.
loss event occurs, a policyholder should
Property terrorism: Where available, this
stand-alone coverage may be appropriate
• Proof of loss: First party loss policies
devote sufficient resources, both internally
and externally, to preserve their ability to
where terrorism risks are excluded from
typically require the policyholder
the main property policy. The definition of
to submit a formal presentation of
terrorism varies for each policy and insurers
the claim and relevant underlying
For more information on the issues covered
are likely to debate whether particular
documentation (known as a Proof
in this article, please contact Frank
events qualify as acts of terrorism,
of Loss) within a certain time period
Thompson in K&L Gates’ London office
especially where damage was caused by
following notification. Care needs to
(frank.thompson@klgates.com).
insurgents who are now represented by
be taken to preserve documents and to
new governments.
document losses so as to substantiate
advance a claim against relevant insurers.
the insurance claim.
Summer 2011
5
continued from page 2
Offshore Environmental Damage
Insurance: Not Just Window Dressing
Any More
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.
back to a well (remember that the location
that the assured both minimizes the ongoing
Underwriters at Lloyd’s (2010 WL 4553482
where pollution is found is often nowhere
damage, for example, with a containment
(W.D. La.)). In Taylor, an offshore production
near a wellhead, since the point source of
dome, and that the assured locate and stop
facility, with 28 operating wells, was toppled
the pollution may be hundreds of feet below
the source of the pollution. Further support
and destroyed by wind and a sub-sea
the ocean floor and the migrating oil seeks
for the assureds’ point of view can be found
mudslide caused by Hurricane Ivan. The
the path of least resistance to the surface).
in policy language that specifically covers
facility was deemed a total loss. The U.S.
“efforts ... to nullify” the pollution. Certainly
government issued orders requiring that the
source identification and mitigation would
assured investigate the extent of the damage,
appear to fall within the plain meaning of
control the source, and remedy the pollution
such terms, although historically the insurers
entering the Gulf of Mexico. In addition,
have contested such interpretations.
the operator was required to post a bond
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”
and abandon activities.” An operator
to plug and abandon (P&A) its wells.
acknowledged coverage and paid limits
Insurers would argue that any effort to stop
under every grant of coverage in the EED
pollution from a well by intervening and
package, save the seepage and pollution
plugging it to prevent ongoing pollution is
coverage, where they denied coverage
a mere discharge of the assureds’ lease-
and asserted each of the three arguments
end obligations to P&A, and not related to
set out above. On the issue of coverage,
pollution control. In contrast, assureds argue
the Louisiana federal court decided that the
that a policy covering “remedial measures”
disputed terms in the insuring agreement
would include efforts to intervene in an
“are unambiguous and provide coverage,”
out-of-control well. If the insurer wished to
further stating that the insurers’ interpretation
exclude such activities, it was free to do so
of its own policy language was “strained
by plain and unambiguous policy language
and unsupported by the plain language of
in its standard form.
the policy.” Specifically, the Court focused
elsewhere and is not pollution control.
activities.” Probably the most surprising
In contrast, an assured would argue that
response from insurers and underwriters has
the policy covers its legal obligations
been the assertion that the EED form was
with respect to the identified pollution,
never intended to cover P&A activities, relief
in whatever form those obligations are
wells, or to cover preventative measures.
manifest. In other words, the legal obligation
A plain reading of the policy would not
is not limited to simply responding to the
support this conclusion.
such pollution. Regulators would demand
OnStream
compliance with the government directives.
Underwriters (over a period of years)
(iii) “We never intended to cover such
identifying and controlling the source of
of several hundred million dollars to ensure
has an obligation, at the end of a lease,
technology, which is exclusively covered
pollution once it occurs, but also includes
6
(ii) “All you really are doing is simple plug
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
argument that underwriters had a good-
risk insurance may be available through
faith basis for denying coverage, finding
Export Credit Agencies (or ECA’s),
that “coverage is clearly provided by
multilateral organisations and other
the Policy” and consequently allowed
commercial insurers. For complete
the assured’s bad faith claim to stand. A
protection, an assured should consider
settlement was reported to the Court one
purchasing political risk insurance
day after the opinion on coverage was
to supplement the energy package
issued (terms confidential). Consideration
policy in situations where the assured’s
of these issues by the Louisiana federal
operations are located in a politically
court marks the first known instance where
unstable region.
a court has found coverage and required
payment under both seepage and
pollution and OPA ’90 coverage parts.
What Does This Mean?
Neal Brendel
“The combined influence of recent
favourable decisions for assureds,
and more affordable source detection
The combined influence of recent favourable
technology now mean that claims for
decisions for assureds, and more affordable
pollution coverage in energy package
source detection technology now mean
policies have become a more viable
that claims for pollution coverage in energy
avenue for asset recoveries in the
package policies have become a more
unfortunate event of catastrophic
viable avenue for asset recoveries in the
loss – whether induced by nature or
unfortunate event of catastrophic loss –
human events”
whether induced by nature or human events.
Michael Miguel
Warning: political risks
excluded from coverage
“Indeed, 2010 was a pivotal year for
A significant percentage of the world’s oil
routinely asserted defenses to coverage
and gas reserves are located in regions
would no longer insulate insurers from
that can be characterised as unstable
coverage liability or bad-faith claims”
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
assureds, as courts found that certain
For further information please contact
Neal Brendel
(neal.brendel@klgates.com) or
Michael Miguel
(michael.miguel@klgates.com).
expense resulting from “war terrorist”
This article first appeared in ASIAN-
activities, which include (inter alia)
MENA COUNSEL, magazine for the
insurrection, rebellion, revolution, civil war,
In-House Community
usurped power, or action by governmental
(www.inhousecommunity.com)
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
Recent Developments
Middle 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).
political risk cover. Alternatively, political
Summer 2011
7
New Professional
Welcome
Frank 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.
For further information contact:
Georgy Borisov, Moscow
Mathew Kidwell, London and Dubai Matthew Smith, London
+7.495.643.1711 London +44.(0)20.7360.8141 +44.(0)20.7360.8246
georgy.borisov@klgates.com
Dubai +971.4.427.2700
matthew.smith@klgates.com
mathew.kidwell@klgates.com
Walter A. Bunt, Pittsburgh, PA
R. Timothy Weston, Harrisburg, PA
+1.412.355.8906 David Overstreet, Pittsburgh, PA
+1.717.231.4504
walter.bunt@klgates.com
and Harrisburg, PA
tim.weston@klgates.com
Pittsburgh +1.412.355.8263
Paul de Cordova, Dubai
Harrisburg +1.717.231.4517
Craig Wilson, Harrisburg, PA
+971.4.427.2704 david.overstreet@klgates.com
+1.717.231.4509
paul.decordova@klgates.com
craig.wilson@klgates.com
Michael Pollen, Singapore
Tomasz Dobrowolski, Warsaw
+65.6507.8120
Rose Zhu, Beijing
+48.22.653.4221
mike.pollen@klgates.com
+86.10.5817.6110
tomasz.dobrowolski@klgates.com
rose.zhu@klgates.com
William M. Reichert, Moscow
+7.495.643.1712
william.reichert@klgates.com
Anchorage Austin Beijing Berlin Boston Brussels Charlotte Chicago Dallas Dubai Fort Worth Frankfurt Harrisburg Hong Kong London
San Diego
Miami
Moscow
San Francisco
Newark
Seattle
New York
Shanghai
Orange County
Singapore
Palo Alto
Paris
Spokane/Coeur d’Alene
Pittsburgh
Taipei
Tokyo
Portland
Raleigh
Research Triangle Park
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.
110314_5238
Los Angeles
Oil and Gas Alert
May 10, 2011
Author:
A New Conservation Law for Pennsylvania?
George A. Bibikos
george.bibikos@klgates.com
+1.717.231.4577
Additional Contact:
Walter A. Bunt, Jr.
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.”
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.
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).
Oil and Gas Alert
Without sufficient pressures in the subsurface,
significant amounts of oil and gas reserves may be
rendered unrecoverable.
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).
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
•
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 nonconsenting parties and bearing all the risk and
expense of drilling a dry hole.
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.
•
2
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
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).
May 10, 2011
2
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.
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
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.
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.
5
May 10, 2011
3
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
4
Oil and Gas Alert
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May 10, 2011
5
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
3.5
(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
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
- ii -
4.
5.
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
Liability for Impacts Caused by Water Supply Development ...................50
(b)
Liability for Impacts Caused by Gas Well Development and
Operation....................................................................................................51
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
5.6
6.
(a)
(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
Regulatory Drivers to Technology Selection – Impending Restrictions on
Surface Water Discharges......................................................................................63
(a)
Overview....................................................................................................63
(b)
The PA TDS Strategy and Pending Regulations .......................................63
Legal and Regulatory Issues in Implementing Treatment and Disposal Facilities............66
6.1
Treatment Facility Siting .......................................................................................66
- iii -
6.2
6.3
6.4
6.5
6.6
(a)
Zoning and land development regulations.................................................66
(b)
State siting restrictions for certain treatment facilities ..............................67
NPDES Permit Issues ............................................................................................68
(a)
Establishing effluent limits ........................................................................68
(b)
Special protection waters ...........................................................................69
(c)
Impaired waters..........................................................................................70
Water Quality Construction Permits for Wastewater Facilities.............................72
(a)
Pennsylvania ..............................................................................................72
(b)
Ohio............................................................................................................72
(c)
Delaware River Basin Commission ...........................................................72
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
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
Residuals Management & Disposition...................................................................81
(a)
What are the treatment residuals? ..............................................................81
(b)
Categorization of residuals ........................................................................81
- iv -
(c)
6.7
State regulation of residual or industrial waste or beneficial reuse of
residuals .....................................................................................................82
Implementing Wastewater Projects – Transactional Issues...................................84
7.
Summarizing Key Challenges to Wastewater Management.............................................84
8.
Final Words........................................................................................................................85
-v-
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
-1-
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).
-2-
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)
-3-
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).
-4-
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.
-5-
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.postgazette.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.postgazette.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/08356/936646113.stm.
-6-
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.
-7-
East Run
Forest
Farms
West Run
Water Well 2 ☼
High Acres
Estates
MDC Green Lease
Spring Creek
MDC Gas Well
☼ Water Well 1
☼ AABC Well
AABC
Manufacturing

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
-8-
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
-9-
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).
- 10 -
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. Blundell 13 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
- 11 -
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.
- 12 -
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).
- 13 -
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)
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
OF
TORTS,
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.
- 14 -
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).
- 15 -
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
- 16 -
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.
- 17 -
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.
- 18 -
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.
- 19 -
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
- 20 -
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.
- 21 -
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 Kentucky 64 ) or “in a natural watercourse.”65
Groundwater is
66
either “percolating” or is an underground stream.
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).
- 22 -
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 gpd 69 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.
- 23 -
(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.
- 24 -
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 Act 84 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 nonconventional 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 SGEIS 85 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.
- 25 -
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.
- 26 -
(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.
- 27 -
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
Act 89 and Pennsylvania Clean Streams Law 90 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 Act 91 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 Act 92 (“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.
- 28 -
(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:



94
95
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.
PA. STAT. ANN. tit. 32, §§645.1 et seq. (West 1997)
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.
- 29 -




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)
- 30 -
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 30day 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).
- 31 -
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 Law 108 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 Act 111 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).
- 32 -
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.ht
m.
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.
- 34 -
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 groundwater 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 Act 130 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
Survey 131 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.
- 35 -
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 Compact 135 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).
- 36 -
“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.
- 38 -
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.
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 water withdrawals.
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.
- 39 -
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 subbasins, 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.
- 40 -
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 Compact 160 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).
- 41 -
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 instream 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-CV02454, 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).
- 42 -
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).
- 43 -
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. 2003001 (November 8, 2002).
176
Id.
177
Id.
178
Id. (emphasis added).
179
Id.
- 44 -
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 supplies. 185
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. 186 In 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.
- 45 -
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.
- 46 -
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:
193

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 decisionmaking standard, with the commitment that each jurisdiction would
review regulated withdrawals consistent with that standard. The decisionmaking 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
Pub. Law 110-342, 122 Stat. 3749.
- 47 -
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 outof-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 Pennsylvania 194 ) 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).
- 48 -
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. Senate 201 and House 202 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).
- 49 -
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/ba591ee
790c58d30852576ea004ee3ad!OpenDocument.
- 50 -
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 Act 204 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.
- 51 -
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).
- 52 -
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.
- 53 -
analysis methods. 215 And, the rules provide for a right of entry for operators in order to
allow such operators to obtain samples for analysis. 216
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. §419.4b.
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/Defau
lt.aspx; http://www.ohiodnr.com/mineral/default/tabid/10352/Default.aspx)
- 54 -
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
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
6 to 9
5 to 7.5
Parameter
pH
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).
- 55 -
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
- 56 -
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).
- 57 -
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
- 58 -
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
- 59 -
(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.
- 60 -
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 concentration 237 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.
- 61 -
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 households 238 ); 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.
- 62 -

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 rulemaking 241 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&watersu
pplyNav=|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).
- 63 -
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&watersu
pplyNav=|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:
- 64 -
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_com
mittee_%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/AdvCommPortal
Files/WRAC/WRAC-%20TDS%20Task%20Force%20Final%20Report%203-12-10.pdf.
249
40 Pa. Bulletin 2264 (May 1, 2010).
- 65 -
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 noncentralized 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 Act 252 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
- 66 -
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 restrictions 256 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 technologybased 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, environmentallysound 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 units 287 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”) Program 296
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- 40 C.F.R. §§ 144.6(a), 146.5(a)
hazardous fluids (industrial and municipal
40 C.F.R. Part 146, Subparts B,
wastes) into deep isolated formations beneath G
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
Class II
Used to inject brines and other fluids
40 C.F.R. §§ 144.6(b), 146.5(b)
associated with oil and gas production, unless 40 C.F.R. Part 146, Subpart C
classified as hazardous waste at the time of
injection, and for enhanced recovery of oil or
gas and for storage of hydrocarbons.
Class III
Used to inject fluids associated with solution 40 C.F.R. §§ 144.6(c), 146.5(c)
mining of minerals.
40 C.F.R. Part 146, Subpart D
Used to inject hazardous or radioactive
wastes into or above USDWs. As of 1984,
Class IV 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:

7.
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)?
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=|
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