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S. HRG. 113–1 

NATURAL GAS RESOURCES 

HEARING 

BEFORE THE

COMMITTEE ON 

ENERGY AND NATURAL RESOURCES 

UNITED STATES SENATE 

ONE HUNDRED THIRTEENTH CONGRESS 

FIRST SESSION 

TO

EXPLORE OPPORTUNITIES AND CHALLENGES ASSOCIATED WITH 

AMERICA’S NATURAL GAS RESOURCES 

FEBRUARY 12, 2013 

( 

Printed for the use of the 

Committee on Energy and Natural Resources 

(II) 

COMMITTEE ON ENERGY AND NATURAL RESOURCES 

RON WYDEN, Oregon, Chairman 

TIM JOHNSON, South Dakota 

MARY L. LANDRIEU, Louisiana 

MARIA CANTWELL, Washington 

BERNARD SANDERS, Vermont 

DEBBIE STABENOW, Michigan 

MARK UDALL, Colorado 

AL FRANKEN, Minnesota 

JOE MANCHIN, III, West Virginia 

CHRISTOPHER A. COONS, Delaware 

BRIAN SCHATZ, Hawaii 

MARTIN HEINRICH, New Mexico 

LISA MURKOWSKI, Alaska 

JOHN BARRASSO, Wyoming 

JAMES E. RISCH, Idaho 

MIKE LEE, Utah 

DEAN HELLER, Nevada 

JEFF FLAKE, Arizona 

TIM SCOTT, South Carolina 

LAMAR ALEXANDER, Tennessee 

ROB PORTMAN, Ohio 

JOHN HOEVEN, North Dakota 

JOSHUA SHEINKMAN, Staff Director 

SAM E. FOWLER, Chief Counsel 

KAREN K. BILLUPS, Republican Staff Director 

PATRICK J. MCCORMICK III, Republican Chief Counsel 

(III) 

C O N T E N T S 

STATEMENTS 

Page 

Beinecke, Frances, President, Natural Resources Defense Council, New York, 

NY ......................................................................................................................... 29 

Eisenberg, Ross, Vice President, Energy and Resources Policy, National Association of Manufacturers ..................................................................................... 21 

Gerard, Jack N., President and Chief Executive Officer, American Petroleum 

Institute ................................................................................................................ 51 

Hickenlooper, John W., Governor of Colorado, Denver, CO ................................. 7 

Landrieu, Hon. Mary L., U.S. Senator From Louisiana ....................................... 3 

Liveris, Andrew N., Chairman and Chief Executive Officer, The Dow Chemical Company, Midland, MI ................................................................................. 13 

Medlock, Kenneth B., III, James A. Baker III, and Susan G. Baker, Fellow 

in Energy and Resource Economics, and Senior Director, Center for Energy 

Studies, James A. Baker III Institute for Public Policy, Rice University, 

Houston, TX .......................................................................................................... 42 

Murkowski, Hon. Lisa, U.S. Senator From Alaska ............................................... 4 

Wyden, Hon. Ron, U.S. Senator From Oregon ...................................................... 1 

APPENDIXES 

APPENDIX I 

Responses to additional questions .......................................................................... 95 

APPENDIX II 

Additional material submitted for the record ........................................................ 121 

(1) 

NATURAL GAS RESOURCES 

TUESDAY, FEBRUARY 12, 2013 

U.S. SENATE, COMMITTEE ON ENERGY AND NATURAL RESOURCES, Washington, DC. 

The committee met, pursuant to notice, at 10 a.m. in room SD– 

366, Dirksen Senate Office Building, Hon. Ron Wyden, chairman, 

presiding. 

OPENING STATEMENT OF HON. RON WYDEN, U.S. SENATOR 

FROM OREGON 

The CHAIRMAN. As the witnesses come in, I want to note to my 

colleagues this is going to be, even by Senate scheduling, a hectic 

morning. We anticipate having votes at 11 o’clock. We will go from 

now until about 11:15 on the hearing topic, which is natural gas 

challenges and opportunities. We will take a break at 11:15 for 

what I anticipate will be about an hour. 

When it comes to natural gas, America is truly the land of opportunity. 

First it’s an economic opportunity. An affordable, stable gas supply provides a competitive advantage for American business that 

can spark a U.S. manufacturing renaissance. Second, it is an environmental opportunity. Gas is 50 percent cleaner than other fossil 

fuels, and it is a major reason why American CO2 emissions have 

actually gone down in recent years. 

Finally, it’s an energy security opportunity. For the first time in 

decades, our Nation will be able to rely on its own U.S. energy resources, especially new oil and gas development from shale instead 

of being dependent on imports from the Middle East and other 

parts of the world that haven’t always had our best interests at 

heart. 

This is a major change for American energy policy. Thirty-six 

years ago the predecessor to this committee called the Interior an 

Insular Affairs Committee, and they held hearings on natural gas 

as the country faced a supply emergency that triggered shortages 

across the Northeastern United States. During that supply emergency hundreds of thousands of people were laid off as commerce 

and industry reduced hours or simply shut down altogether. 

We in the Northwest, particularly Senator Cantwell and I, note 

that the committee at that time was chaired by our legendary Senator, Henry ‘‘Scoop’’ Jackson, and the committee released a report 

prepared by the Department of Defense predicting that liquefied 

natural gas imports would account for 10 percent of the country’s 

gas supply. 

2 

The view expressed in that 1997–1977 committee report has 

dominated American energy policy until just a few years ago. In 

2005, Congress, over the objection of some, swept aside the ability 

of States to even approve the siting of LNG import terminals. As 

recently as 2007, when the Congress last enacted major legislation 

the focus was still overwhelmingly on energy scarcity. 

Today, the outlook could not be more different. Instead of scarcity and shortages, the prediction is that domestic production will 

soon outstrip American demand. 

Given the dramatic change in the outlook for natural gas supply, 

it is clearly time for a fresh look at our current policies and to start 

thinking about how to update those policies to reflect a very new 

reality. 

As part of today’s hearing, the committee is interested in hearing 

from the witnesses what they think is needed to safeguard the advantages of affordable, stable gas supplies for our country. Now 

some of our witnesses are going to say the best approach is that 

the market will take care of things. Others are going to say caution 

is in order. Just a few years ago investors were still betting on 

building new natural gas import terminals. They now face, in communities across the country, billions of dollars worth of stranded 

investment. 

It is hard to see the logic behind replacing that kind of speculation on gas imports with similar speculation on gas exports. 

My own view is we have to make sure we don’t miss this opportunity for our Nation’s economy and millions of unemployed workers who are now looking for good paying, family-wage jobs in the 

American manufacturing sector. 

As the CEO of Dow Chemical, Mr. Andrew Liveris will testify 

that if unfettered exports drive the price of gas back toward the 

$10 per thousand cubic feet (mcf) price America has seen in recent 

years, that would essentially eliminate any competitive advantage 

for American manufacturers and investment that could be made 

here at home, and it will essentially advantage overseas opportunities. 

Instead of a manufacturing renaissance, major gas consumers 

could find themselves hit hard with energy price hikes and forced 

to side line job-creating efforts. 

It’s also important to keep in mind that the guidance the Energy 

Department now uses for evaluating gas export applications was 

originally created almost a quarter century ago for import policy. 

It seems to me that it’s now time to have a serious discussion 

as to whether the guidelines that are now in place at the Energy 

Department for approving export applications are what they need 

to be. A recent study commissioned by the Department of Energy 

to examine the impact of natural gas exports, in my view, raised 

more questions than it answered. 

Now export policy is not the only issue on the table. It would also 

be a missed opportunity if the environmental benefits that natural 

gas can provide in terms of reduced CO2 emissions were lost, lost 

because of inadequate attention to issues such as fracking, methane emissions flaring, and underground aquifers. 

Communities across the country have already been in touch with 

the committee to share their thoughts and concerns about whether 

3 

the hydraulic fracturing process that’s used to produce shale gas 

near their communities could result in the contamination of their 

groundwater supplies. That type of situation would not only be 

tragic for the affected community, but also could lead to citizens? 

pressure to shut down not only unsafe production, but also operations that were safe. 

Colorado’s Governor, who is here with us, the Honorable John 

Hickenlooper, who has been on the front lines in terms of grappling 

with these issues, is going to testify today on how he’s worked to 

strike a balance between the economic and environmental interests 

in regulating natural gas production in his State. Governor, we are 

anxious to hear about how your approach could be a model for the 

country. 

Here’s my bottom line. Let’s see if there is an economic and environmental sweet spot where U.S. gas producers can make enough 

money to continue producing, and U.S. manufacturers have an affordable, stable supply of natural gas and where the environment 

is not only protected, but actually benefits from greater use of natural gas to lower CO2 emissions. 

Today’s hearing gives us a chance to look at these and other 

issues. I look forward to hearing from our witnesses. 

Senator Murkowski and I have talked about these issues on a 

number of occasions, and I’ve worked very closely with her. Senator 

Murkowski, it’s going to be a pleasure to serve with you during this 

session, and please go forward with any comments you’d like to 

make. 

[The prepared statement of Senator Landrieu follows:] 

PREPARED STATEMENT OF HON. MARY L. LANDRIEU, U.S. SENATOR FROM LOUISIANA

First, let me thank you all for taking time to appear today before this committee 

to share your expertise on the issue of natural gas development. You are here today 

because it is vital that we treat our newfound wealth of natural gas in a fashion 

which protects the interests of states, like Colorado, represented here by Governor 

Hickenlooper, manufacturing, represented by Mr. Liveris of Dow and Mr. Eisenberg 

of the National Association of manufacturers, the environmental community, represented by Ms. Beinecke and finally our producers, represented by Mr. Gerard. 

This wealth of natural gas is extraordinary, with estimates indicating America 

currently has 317 trillion cubic feet of proven, accessible reserves, and a further 

2,000 tcf in total resource base estimates. 

This is enough to fulfill our current demand, a little over 24 bcf per day, for over 

100 years. 

Louisiana ranks second in natural gas production, behind only Texas, with 29 tcf 

in 2011, representing 10% of total national production. 

This increased production has a direct impact on our economy, supporting 2.8 million jobs nationally, along with tens of billions in new investment. 

In Louisiana, Methanex Corporation, which moved its last U.S. plant overseas in 

1999, is now spending over $1 billion to move a methanol plant from Chile to Ascension parish, near Baton Rouge. This plant will produce the raw materials for everything from windshield washer fluid to paints and sealants, even wrinkle free shirts. 

Williams, a petrochemical company based in Tulsa, is planning a new $400 ethylene plant also in Ascension parish, where they will supply our plastics manufacturers. 

Finally, CF Industries, one of the world’s largest producers of nitrogen fertilizer, 

is looking to spend $2.1 billion to build a new fertilizer plant in Ascension. 

That’s over $3.5 billion being invested in one parish in Louisiana, all thanks to 

our new abundance of domestic natural gas. 

Statewide, this could add over 200,000 new jobs, in addition to the 81,000 already 

supported by natural gas development. 

4 

Of course, that isn’t the whole story; nationwide, these same petrochemical, plastics, steel and fertilizer industries are planning to invest upwards of $80 billion in 

new plants and new capabilities. 

One of the most important topics in our conversation about how best to approach 

this new wealth of natural gas is the issue of exports, specifically liquefied natural 

gas, to nations around the world. There are strong arguments to be made on each 

side, for and against the expansion of these exports, and I am sensitive to both. 

I believe, however, that there is enough domestic production, and the capacity for 

enough production increase to support our vital manufacturing industry and allow 

for responsible levels of export. 

The recent NERA study, commissioned by DOE, supports this view, and indicates 

that it is possible for a level of export to exist that both incentivizes increased production while at the same time continuing to provide our domestic consumers with 

reliable, low-cost natural gas. 

I look forward to your testimonies, and to working with my colleagues to develop 

a commonsense approach to managing our natural gas supply. 

STATEMENT OF HON. LISA MURKOWSKI, U.S. SENATOR 

FROM ALASKA 

Senator MURKOWSKI. Thank you Mr. Chairman. 

I’m pleased that for the first hearing of the 113th Congress that 

we are focusing on natural gas, the opportunities that natural gas 

clearly presents within the energy discussion as we look at our energy mix, our energy portfolio. 

I think it is absolutely clear that much of the economic stimulus 

that we have seen—the jobs that have been created in recent 

years—is coming from our States that are providing opportunities 

within the natural gas sector. 

So, I’m pleased that that’s our focus today. 

I welcome all of our witnesses. 

Without a doubt, the new technology that we are seeing has enabled a natural gas boom that has changed our energy landscape 

and the outlook for our economy. 

I have often said, this natural gas just didn’t all of a sudden migrate to these areas. It’s been there for a long time. But what has 

changed is our ability to access this resource using the new technology. 

Natural gas is now an abundant, affordable, clean source of energy, providing great opportunities for economic growth, and an energy security. 

Mr. Chairman, you mentioned, the position that we have moved 

to as a Nation, when we look at our energy sources just a few years 

ago, we were talking about the scarcity of our resources. We have 

now moved from a discussion about scarcity to one of abundance. 

This requires us to look critically and perhaps rethink some of 

the conversations that we have had about energy. 

Last week I introduced a proposal in a document about 115 

pages, Energy 20–20, that I hope will spur us to conversations 

about energy and how we should be looking differently at energy 

because of exactly this—this paradigm shift, going from one of scarcity to relative abundance. Our resource base estimates have increased 44 percent for natural gas in less than 5 years. That’s pretty incredible. 

Production is up, prices are low. 

There’s been a positive impact on our greenhouse gas emissions. 

5 

In addition, our allies overseas are now looking at the United 

States, they want our natural gas, and we’ve got enough resources 

to help make that happen. 

For these reasons though, we have to be thoughtful. 

I would certainly agree in how we proceed in dealing with the 

issues that impact natural gas. 

There are several pending reports and studies looking at hydraulic fracturing. We need to make sure that these efforts are reasonable, based on sound science and they don’t result in unnecessary 

and overly burdensome regulatory requirements. 

I think we need to take a very close look, a critical look, at existing State regulations before we move to impose blanket Federal 

rules that perhaps might cause more problems than they solve. 

I’ve had an opportunity to be out in the Bakken Region. 

I’ve been out in the Marcellus with my colleague, Senator 

Manchin, talking with my friends down in Texas about the Eagle 

Ford. 

The fact of the matter is we’ve got different geology all around 

the country. 

So when you’re talking about a one-size-fits-all approach, maybe 

we need to look a little more critically at that. 

We also need to be careful about intervening in efforts to export 

our LNG. There’s a long established regulatory process for natural 

gas exports through the Department of Energy and through the 

FERC. This includes environmental review under NEPA. So before 

we reinvent the wheel, I think we need to look at existing laws and 

regulations and determine if and where there are deficiencies. 

The debate on this issue has focused on the impacts to domestic 

natural gas prices and supply, but I think we also need to include 

within this discussion an understanding of the role that the market 

forces will play, not only on domestic prices, but the number of 

projects that may actually be built. These are mega projects that 

we are dealing with, in every sense of the word, ranging from $8 

billion to $25 billion, depending on the amount of existing infrastructure. 

Up in Alaska, we’re talking about a project of about $65 billion. 

This is real money. 

Gas is a global commodity, and other countries, including Canada, are already moving forward. 

So I don’t think that dragging our feet is an option here, if we 

want to export our LNG. 

We should also not forget the positive impacts that exports would 

have on our trade imbalance and the geopolitical benefits of exporting to our allies. 

There are also other issues to discuss related to the natural gas 

industry, but I’d certainly be remiss if I didn’t bring up the dire 

need for new pipeline infrastructure to move our natural gas resources to domestic markets and consumers. 

We need to address the roadblocks that prevent many of these 

projects from moving forward. 

I do hope that this hearing is just the start of a very important 

discussion on these and many other issues impacting our natural 

gas industry. 

6 

With that, I look forward to the comments from the witnesses 

that have gathered here this morning, and thank them for coming 

before the committee. 

The CHAIRMAN. Thank you for an excellent statement Senator 

Murkowski. 

I think all of us would agree that in a big and diverse country 

people have different impressions of the energy challenge. 

I know that I will never forget when I went to Alaska and you 

served me a graham cracker treated with LNG, 

Senator MURKOWSKI. Dinner. 

The CHAIRMAN. and that, uh, 

Senator MURKOWSKI. You’re still alive to tell the story. 

The CHAIRMAN [continuing]. I lived to tell about it. 

So let’s move now to our witnesses. Let me introduce them. The 

Honorable John Hickenlooper, Governor of Colorado; Mr. Andrew 

Liveris, Chairman and Chief Executive Officer of Dow Chemical; 

Mr. Ross Eisenberg, Vice President of the National Association of 

Manufacturers; Ms. Frances Beinecke of the Natural Resources Defense Council; Dr. Kenneth Medlock, a senior director for energy 

studies at the Baker Institute at Rice; and Mr. Jack Gerard, 

Ppresident of the American Petroleum Institute. 

I would like to let a couple of our colleagues, Senator Udall and 

Senator Stabenow, introduce witnesses. 

Why don’t we begin with you, Senator Udall, since Governor 

Hickenlooper will be first, and then we’ll go to Senator Stabenow. 

Senator Udall. 

Senator UDALL. Thank you Senator Wyden, Senator Murkowski. 

It’s great to start this new Congress off on this footing and with 

this important topic. 

It’s a true pleasure and treat for me to introduce our Governor, 

John Hickenlooper. 

I know our other Senator, Michael Bennett, with whom I have 

a strong working relationship, shares the sentiments I’m going to 

share with the committee. 

The Governor brings a great deal of policy expertise to natural 

gas legislation and the issues that we’re discussing here today. 

John, I would tell you in part you’re among friends. 

There are 4 former Governors on the energy committee: Senator 

Alexander, Senator Hoeven, Senator Risch and Senator Manchin, 

and I know they share the experiences you’ve had leading an important State. 

The Governor is a geologist. 

He worked in the energy industry long before he became Denver’s mayor and Colorado’s Governor. By the way, I should mention, Mr. Chairman, that the Governor was in another energy industry between his days as a geologist and a public servant. 

He started what’s now recognized known as the No. 1 Craft 

Brewing industry in the country. 

Colorado ranks No. 1 for beer production. 

We also have a very robust Craft Brewing sector, if you will, and 

the Governor became a very successful businessman and restaurateur. 

We are an all-of-the-above energy State. 

7 

The Governor’s work is keeping us on the forefront of energy innovation and a creator of jobs in the energy industry. 

I’m really pleased he’s here, as he can talk directly and firsthand 

about the opportunities that we face, but also the lessons from the 

challenges that are in front of Colorado today. 

So, again Governor, it’s good to have you here. Thank you for 

taking time from a very busy schedule that you have. 

I know our legislature is in session. It has 120 days to get up 

to mischief, as we sometimes do here in the Congress. 

So I really appreciate you taking the time to join us here in 

Washington, DC. So welcome. It’s great to see you here. 

The CHAIRMAN. Senator Udall, thank you. We will not compare 

Oregon and Colorado now on the brew pub issue. That will be 

later. 

Senator Stabenow. 

Senator STABENOW. Good morning. 

First Mr. Chairman, you look great sitting there, and welcome to 

the committee as our chairman. I know you and our ranking member are going to do great work leading us. 

It’s my great pleasure to introduce Andrew Liveris. I said before 

I corrected it, Ron is—Andrew Liveris, who is the CEO of Dow 

Chemical Company. 

I think that doesn’t really describe what Dow’s about, though, because under Mr. Liveris’ leadership, Dow has really become an energy and advanced manufacturing leader in the country. 

So I’m very pleased that you’re here in this very important discussion. 

Mr. Liveris came to Dow in Australia in 1976 and moved up as 

president of Asia and Pacific operations to be chairman in 2006 

and has a very deep knowledge of the importance of natural gas 

as a source of energy in manufacturing, as well as chemical feedstock to make so many of the products that we use every day. 

He also serves on the President’s Export Council and a number 

of other positions. 

So welcome. It’s wonderful to have you with us. 

We are very proud to have you located in Michigan and touching 

so many important areas of innovation for the future. 

The CHAIRMAN. Thank you Senator Stabenow. 

We welcome all our witnesses. 

We’d like you to try to see if you could stay in the vicinity of 6 

minutes for your remarks. I know that there’s always a compulsion 

to, you know, read everything. If you’d like to just summarize your 

views, that’ll be accepted, and we’ll make your prepared statement 

a part of the record in its entirety. 

Governor, welcome. 

STATEMENT OF JOHN W. HICKENLOOPER, GOVERNOR OF 

COLORADO, DENVER, CO 

Governor Hickenlooper. Thank you Chairman Wyden. Senator 

Udall, thank you for your kind introduction. 

The truth is I’m—I refer to myself as a recovering geologist these 

days. 

It is true I went from one fluid to another in my business career. 

8 

Ranking Member Murkowski, thank you again for your efforts on 

behalf of energy and this country and to the rest of the Senate Energy and Natural Resources Committee. 

Thank you for allowing us this opportunity. 

The 3 interconnected issues right now facing our country—obviously the economy is undergoing a steady recovery, but we still 

have high unemployment, a deficit makes investment difficult, 

we’re vulnerable to shocks from overseas and our productivity increases continue to demonstrate there are a lot of people out of 

work. 

At the same time the Persian Gulf is more volatile than ever, 

and we see our national security—40 years after our first energy 

crisis, the oil is controlled by unfriendly regimes in many cases. A 

national security issue that remains. 

Last, climate change. We’ve seen some serious drought and 

wildfires that remind us in Colorado of what the potential threat 

is from climate change. 

I’m not about to get into a discussion of how fast the climate is 

changing or what the causes are, but I think these 3 issues: the 

economic recovery, the national security, and climate are tough 

challenges, but the crux of each of them is energy. 

We recognize that domestic energy creates jobs, that less foreign 

imported oil enhances our national security and that we have a 

much cleaner energy that will lead to ability to protect our environment. 

The key, of course, is to thread each of these needles. 

Energy independence used to be a catch phrase, right, that people would throw around, but I think we are legitimately on the 

threshold of achieving it for the first time in my lifetime. 

You know I studied geology back in the—I’m not trying to date 

myself—back in the 1970s when plate tectonics were just being 

begun to be believed and yet what we’ve seen in the last decade 

is truly transformational. 

In 2005, 60 percent of our oil was imported. Last year, 41 percent 

was imported. That trend is going to go further. 

Wind and solar, some of the alternative energies, have added diversity to our energy portfolio. Twenty years ago that was ridiculed, and now we see it very—in a very real sense. 

I think our future is more secure with energy that’s renewable, 

that’s sustainable. 

One way that that happens is by integrating, as Senator Udall 

mentioned, a kind of all-of-the-above policy. 

We see that having cheaper natural gas means that we’re more 

competitive as a country. My friend, Mr. Liveris, Liveris, we all 

have that challenge. Try having a name like Hickenlooper, Andrew, 

and you’ll see. 

But we see that chemical industries, the American fertilizer industries, a lot of these associated industries beginning to really 

take off. 

Foreign investment in electricity-intensive industries also is coming home for the first time in decades largely because of inexpensive natural gas. 

It’s also worth pointing out that carbon emissions, because of inexpensive natural gas and the conversion of older, inefficient elecVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00012 Fmt 6633 Sfmt 6602 G:\DOCS\80132.TXT 80132
9 

trical generation plants fueled by coal, are per capita—CO2 emissions are the lowest since Eisenhower turned over the White House 

to John Kennedy. 

We are, as a country,—even though we didn’t ratify the Kyoto 

Protocols—we are half way toward compliance, and we have reduced our carbon emissions in the United States more than all that 

other signatories to the Kyoto Protocols. 

This really is game-changing. 

When I was a geologist this was unheard of. We’d find a big field, 

and we’d think, well, we’re going to adjust how the value of coal— 

the value of oil, or the value of gas was going to be projected. 

This has been a technological revolution. 

We did fracking when I was a geologist. I—The first well I sat 

back in 1981 was a—we did a hydraulic fracking enterprise on 

that. 

What’s happened is we’ve had better technology, the discovery of 

massive—these tight shale and shale oil deposits. 

The real transformation here is that we could see a natural gas 

supply that is legitimately a hundred years long, and we continue 

as the technology continues to improve, we find more gas at lower 

cost. 

At the same time, this has brought exploration to the doorstep 

of communities that didn’t have to deal with it before, and I think 

the issues around health and safety, of increased drilling, I mean 

these are industrial processes as they come close to our—closer to 

our schools, our homes and neighborhoods, we really have to take 

full advantage of the technology by insuring that we have the absolute strongest safeguards that you could possibly have and that includes regulations that capture methane emissions, that we reduce 

flaring of these emissions, make sure that we don’t have any, I 

mean zero, fugitive methane, and that we protect our precious 

groundwater. 

We passed years ago, or a year ago, regulations that required 

disclosure of the composition of fracking fluids so that we could 

protect intellectual property but at the same time reassure the 

public. 

We worked with the NRDC, the Environmental Defense Fund, 

Halliburton and several large service companies. 

At one point in my office, I’m not sure how this happened, but 

the new frack fluid is made with food additives, and somehow we 

all took a swig of frack fluid-the new frack fluid, and it was not 

terribly tasty, but again, I’m still alive to—like Senator Wyden 

coming back from Alaska is still alive to tell the story. 

What we’re trying to do is create a national model for how do we 

regulate gas extraction. We want to make sure we have, anytime 

we’re remotely near neighborhoods, that we have green completions 

of drilling sites, robust groundwater manage—monitoring. We’re 

going—making it mandatory for testing both before and after wells 

are drilled, that we have appropriate setbacks and that we focus 

on well bore integrity, make sure that we don’t have communication around that well. We’re pursuing each of these in Colorado 

and try to move aggressively to implement the EPA’s greenhouse 

emissions regulations. 

10 

Simultaneously we’re engaging on the universities and doing the 

most comprehensive study of air quality around some of these large 

fields to really be able to give facts instead of estimates around a 

lot of these issues. 

But recognizing that we are creating thousands of jobs by having 

these—this energy created and extracted at home, we are increasing our national security, and we are dramatically reducing 

ground—greenhouse gas emissions. 

I think our focus is to make sure that we continue this momentum that we seize upon this opportunity in such a way that we can 

have a regulatory environment that is comprehensive and rigorous, 

but at the same time allows us to continue these advances. 

One primary goal throughout this is to make sure that we have 

sufficient public involvement in the creation of these rules and having industry have a voice, as well, so that we are in all ways balanced and that we can be transparent to the level that the public 

can feel that they are not working that they are not working 

against an unseen villain. 

[The prepared statement of Governor Hickenlooper follows:] 

PREPARED STATEMENT OF JOHN W. HICKENLOOPER, GOVERNOR, OF COLORADO, DENVER, CO 

Mr. Chairman and members of the committee, thank you for this opportunity to 

offer Colorado’s perspective on energy policy, as it relates to natural gas, the focus 

of this hearing. 

Our economy is making a steady recovery, but we are still fragile. Too many 

Americans are out of work and the worldwide competition for jobs is a great challenge. The international situation is still volatile, particularly in the Persian Gulf. 

And record-setting high temperatures over the last decade remind us that climate 

change could have profoundly negative impacts on our planet. 

Economic prosperity, national security and climate: Three generational challenges 

of tremendous importance. 

Energy is at the crux of all these challenges. 

If we get energy policy right, we’ll make progress on all three. 

Responsible development of natural gas—the subject of this hearing—is fundamental to a successful energy strategy. 

Natural gas has made American industry more competitive. We have seen new 

investment in energy-intensive companies. American chemical and fertilizer industries are growing because of inexpensive natural gas. Foreign investment in electricity-intensive industries has also been flowing into the country, as natural gas 

helps keep utility rates low, even as domestic coal remains cheaper. 

We are on target to be a net exporter of natural gas by 2020. 

Domestic development of shale gas and oil, homegrown renewable energy and efficiency strategies are leading us toward energy independence. With less reliance on 

foreign sources, our exposure to the impacts of global events is reduced. Our oil imports are falling—to approximately 40 percent of our consumption, down from 60 

percent as recently as 2006. By next year, imported oil is projected to make up just 

32 percent of demand. More energy dollars will stay home, our dependence on foreign supplies will decrease. 

A revolution in shale gas has brought welcome news. Inexpensive gas is driving 

down carbon emissions in the United States. Last year, the U.S. Energy Information 

Agency found CO2 emissions in the first four months of 2012 had fallen to 1992 levels. When you consider that our population has grown by 57 million since then, it 

translates to per capita carbon emissions at the lowest level since President Eisenhower left office in 1961. 

Inexpensive natural gas, its associated efficiencies, and its limited environmental 

impact are leading utilities to switch from coal to gas. David Victor, Vice-Chairman 

on the World Economic Forum’s Global Agenda Council on Energy Security, has 

written that this shift means U.S. emissions in 2012 are projected to be approximately 450 million tons lower than otherwise. That number is double the global impact of all the Kyoto treaty’s signatories combined, including the European Union. 

This month, the Environmental Protection Agency reported that U.S. power plants 

11 

in 2011 produced 4.5 percent less CO2 than in 2010, a drop the agency attributed 

to the benefits in switching from coal to gas, as well as increasing use of renewable 

energy. 

This emerging data is nothing short of transformative. By improving extraction 

technologies and extending natural gas to new markets and new applications—including transportation—we can not only make the U.S. economy stronger and enhance our security and independence, but we can take significant steps toward reducing climate-warming emissions. 

This doesn’t mean abandoning a strategy focused on renewable energy; quite the 

opposite. 

We must chart a parallel path, continuing investments in wind, solar and other 

renewable sources of energy, including conservation and efficiency. A coherent strategy for the future cannot be dependent on one fuel source. We need a diverse energy 

portfolio that drives the economy, and at the same time prepares for future contingencies. 

This is the approach that President Obama has rightly championed—an ‘‘all-ofthe-above’’ strategy—one that encourages domestic oil and gas production, continues 

investment in clean energy research and technologies, and partners with industry 

for dramatically more efficient automobiles. It is a forward-looking strategy that 

combines American ingenuity with a commitment to sustainability. 

Colorado is moving forward with our own version of an ‘‘all-of-the-above’’ strategy, 

and natural gas is a significant part of our energy mix. We are also more broadly 

utilizing our abundant renewable sources, as well as working on legislation and 

other initiatives to mine efficiency and conservation for all they are worth. 

We believe Colorado presents a model for the nation. Our approach is balanced. 

We are reaping the benefits of advanced technologies, not just in shale gas but also 

in renewable energy. We are encouraging efforts to make coal a cleaner source of 

energy, but while that research continues, we will work with the resources at hand. 

Colorado has a long and proud history of oil and gas development. Our first oil 

well dates back to when Abraham Lincoln was president. 

We rank fifth in natural gas production and tenth in oil production. Our diverse 

hydrocarbon resources encompass a variety of shale, tight sand, coal bed methane, 

and other formations that span the state. This landscape has changed over the 

years, and has taken a significant turn as operators combine improvements in hydraulic fracturing and horizontal drilling to unlock reserves of oil and gas in formations, such as the Niobrara in Colorado, historically considered impractical for extraction. 

As a former geologist, I have some experience with this technology. We worked 

on so-called ‘‘frack jobs’’ when I was in the industry in the 1980s. The industry, incidentally funded by billions of federal research dollars in the 1990’s, has made great 

advances since that time. 

Colorado also has a history of creativity in its approach to energy. In 2004, we 

became the first state in the country to launch a renewable energy standard 

through a statewide voter initiative, one our legislature has strengthened in years 

since to become—at 30 percent—the second highest in the country. In 2010, we 

passed the landmark Clean Air Clean Jobs Act which switches much of our electrical generation from coal power plants to natural gas, thereby addressing both climate and air quality, and reducing water consumption. 

Natural gas and renewable sources are proving to be ideal partners, since gas efficiently cycles on and off to pair with intermittent resources such as wind and solar 

power. 

We are achieving these energy goals across party lines. Gov. Mary Fallin of Oklahoma and I are leading a bipartisan effort to promote the use of natural gas as a 

transportation fuel for state vehicles. What started with Oklahoma and Colorado a 

little over a year ago has now expanded to 22 states representing every region of 

the country. 

With a little effort we see the potential for including the federal government and 

perhaps Canadian provinces and other partners to build a market for large vehicle 

fleets using natural gas. 

These initiatives target larger and heavy duty vehicles. Converting from diesel 

power to compressed natural gas reaps the biggest benefit in reductions of carbon, 

particulates and other pollutants. We are also finding ways to expand the fueling 

infrastructure, so trash haulers, delivery vehicles, buses, and trucks have more options for refueling. 

Electric vehicles also hold tremendous promise, particularly for automobile consumers in the future, and we should pursue their development. But we do not need 

to pick winners and losers at the start of the game. Let’s continue to pursue a comprehensive approach and let the market work. 

12 

The expansion of natural gas certainly brings regulatory challenges. As development moves into more urbanized areas we must be responsive to public concerns 

about the health and safety of industrial processes near homes and schools. Working 

together state and local governments can minimize hazards through effective oversight and enforcement. 

As patterns and the extent of oil and gas activities change due to constantly evolving technologies and economic demands, our regulatory approach has to adapt. 

Mr. Chairman, to put it bluntly, natural gas has a place in making us more secure and is addressing climate change, but we’ll need to make sure that the production side is as protective of our environment and human health as possible. 

Our goal in Colorado is to be accountable for the highest ethical and environmental standards with a regulatory structure based on three principals—namely, 

that our regulations are reasonable, scientifically-based, and protective of health 

and safety. 

Our aim is to reduce emissions including the capture of methane, and with, by 

necessity, the strictest rules in the country to protect air and water. 

In 2008, Governor Bill Ritter secured legislative support for restructuring the 

composition of Colorado’s Oil and Gas Conservation Commission, reducing industry 

representation and diversifying membership. This revamped commission embarked 

on a sweeping 18-month overhaul of regulations that produced new protections for 

the environment. These rules have become the basis for regulatory initiatives in 

other states and even other countries, the latest being Ukraine. 

A year ago, working with such diverse partners as the Environmental Defense 

Fund and Halliburton, we passed regulations requiring disclosure of chemicals in 

hydraulic fracturing fluid. As described in a recent edition of The Economist these 

rules suggest an international model for disclosure, protecting trade secrets and intellectual property, while providing a basis for public accountability. 

Colorado now requires mandatory water testing near drilling and completion sites 

both before and after operators conduct their activities. We are one of just three 

states in the country that has rules for mandatory groundwater sampling and the 

only state that requires post-drilling sampling. 

This month we are also finalizing rules to reduce the impacts of drilling near communities. These rules increase the minimum distances between drilling sites and occupied buildings and require the most stringent mitigation requirements in the 

country to ensure work occurs with the least disturbance to nearby residents, with 

‘‘green completions’’ required within 1,000 ft. of hospitals or schools. 

In partnership with our universities, we are launching a comprehensive study of 

the impacts of natural gas drilling on air quality and public health. This comes after 

several steps in recent years to reduce the pollutants that originate at oil and gas 

facilities, including requirements for emission-control devices to capture the emissions that can otherwise escape prior to a pipeline connection. 

Increased communication is central to our regulatory reform. Our Commission has 

two staff members dedicated exclusively to local government outreach and other 

staff members have devoted significant time working with government officials. We 

formed a task force to develop protocols for local government engagement that will 

further address the impacts of development. 

Our new rules also include extensive notice and outreach requirements on the 

part of operators, both to local government representatives and citizens. All this has 

resulted in greater collaboration between our state regulators and officials at the 

local level, reinforcing what we know to be true about most difficult problems, 

namely, that conversation at the front-end reduces problems at the back-end. 

In short, the natural gas revolution and growth of renewable energy technologies, 

present Colorado and the country with an extraordinary opportunity: to create jobs, 

to make us more secure, more energy-independent, and to do a better job of protecting the environment by reducing greenhouse gas emissions. 

These are mission critical goals for our country. 

Mr. Chairman, the history of Colorado is largely a story about American energy. 

From mining to oil exploration in the last century, and, in this century, leading a 

green energy revolution, Colorado has lessons to offer the country. 

Our first oil well dates back to when Abraham Lincoln was president. 

Of course, with the country torn apart by war, Mr. Lincoln faced deeper challenges than crafting bipartisan energy policy, but his second address to Congress 

has wisdom we can still draw from. He said, ‘‘We can succeed only by concert. It 

is not ‘can any of us imagine better?’ but ‘can we all do better?’ The dogmas of the 

quiet past are inadequate to the stormy present. The occasion is piled high with difficulty, and we must rise with the occasion. As our case is new, so we must think 

anew, and act anew. We must disenthrall ourselves, and then we shall save our 

country.’’ 

13 

We should—all of us—no matter our perspective or experience—disenthrall ourselves from bias and ideology to find a new path forward. 

Our future depends on how well we find this path together. 

We know you share this view and look forward to this morning’s hearing. 

The CHAIRMAN. Governor, we are at 7 minutes, and I know the 

Senators want to ask you questions. 

Governor HICKENLOOPER. Sure. 

The CHAIRMAN. Would you like to wrap up? 

Governor HICKENLOOPER. Yes. I was at that point right there 

just saying that as long as we can maintain a focus on sciencebased applications and make sure we have the competing interest 

at the table, I think that we’ll be able to continue the pursuit of 

these innovations. 

The CHAIRMAN. Well said. 

Mr. Liveris. 

STATEMENT OF ANDREW N. LIVERIS, CHAIRMAN AND CHIEF 

EXECUTIVE OFFICER, THE DOW CHEMICAL COMPANY, MIDLAND, MI 

Mr. LIVERIS. Thank you Mr. Chairman, Senator Murkowski, distinguished members of the committee. 

Senator Stabenow, thank you for that great introduction. 

I’m Andrew Liveris now and that can go on the public record. 

Thank you here for inviting me here to celebrate our democracy in 

the intersection of government, business, and civil society practiced 

in this chamber under your leadership. 

Your collective leadership is something an individual like me, as 

a foreigner living in this great country, does not take lightly. 

Thank you very much for inviting us to talk about this important 

conversation. 

As already stated, it has the promise of tapping this vast new 

natural gas resource and coming up with a better answer. 

This is being called the Shale Gale. 

It’s afforded America a new competitive advantage, advantages 

which we now are becoming quite familiar with. 

But it does pose us with these challenges, and I believe that our 

democracy can rise to the better answer by having these conversations. 

How much of this natural bounty should we export? 

I’m here because the answer is neither simple nor just obvious. 

It actually isn’t either binary. It’s not binary to talk about a neither-nor proposition here. It’s not binary to talk about for or 

against free trade. 

As you know, the Shale Gale has only fueled the increases in 

natural gas production—not only done that, but it’s provided this 

manufacturing renaissance. 

For companies like Dow, the compounds that make up natural 

gas, as already stated by Senator Stabenow, are the feedstocks for 

vital manufacturing processes that create value across the entire 

economy. 

We use them as the first indispensable ingredient for everything 

that is made and consumed in this country. 

14 

So when natural gas is not sold just as an export, when it’s used 

instead as a building block for these manufactured goods, it creates 

8 times more value across our entire economy—8 times. 

In this way, America’s natural gas bounty is more than a simple 

commodity. It’s a once in a generation opportunity for America to 

export advanced products, not just be to use. 

It’s a unique opportunity to make America’s economy stronger, 

more balanced, more sustainable. 

This is not to say that America ought to keep all of this gas 

onshore’not at all. 

Exports are part of America’s economy. It’s one of the life bloods 

of America’s economy and the world’s economy. 

The U.S. should lead in both the sale and shipment of the raw 

material and the finished goods. 

But the fact is if we shipped half or more of this bounty overseas 

today, as some propose, it’ll have severe, unintended consequences 

on the manufacturing and the sector inside the United States on 

prices. 

Not just domestic companies, because we’re going to have to compete with whatever’s left over. Not just the effect on us. 

It would actually mean higher gas and electricity prices. 

It’ll mean actually higher transportation and utility costs for consumers, as well as industry. 

These higher and more volatile energy prices would also cause 

domestic energy producers to once again to ship operations and to 

ship jobs overseas to ship factories overseas to countries where natural gas is cheaper. 

There are countries where natural gas is cheaper. 

America would sacrifice this once in a generation competitive advantage because gas is not an openly traded commodity. 

It is not and therefore does not have a world price. 

European and Asian natural gas prices are actually indexed directly to oil price, which makes them up to 5 times more expensive 

than in the United States. 

So it’s very easy to see why other Nations want our gas. They 

want to lower their prices. 

What’s harder to see is why would we be willing to do that at 

such a potentially severe cost to the American consumer and the 

American industry. 

Globally, we need to continue our progression to rules-based free 

trade, especially for gas. 

Domestically, we need to choose a more prudent, responsible, balanced approach, an all-of-the-above approach. 

This is now, in our view, a pressing issue. 

As you’re aware, the Natural Gas Act requires the Department 

of Energy to weigh the public interest in evaluating applications to 

export liquefied natural gas. 

Today, they are considering 12 such applications that taken together would permit exports equal to half of today’s U.S. production, in effect exporting our competitive advantage away and importing the world oil price for our domestic sector. 

Our view is that DOE should thoroughly examine each and every 

one of these applications to see what it is on its merits. 

15 

Regulators should consider a full array of criteria, should weigh 

the impact on everything from food prices to home heating bills to 

jobs and job creation. 

Let me be particularly clear. We’re not asking lawmakers to ignore the interests of any stakeholder to the contrary. 

We believe that everyone affected by DOE’s decisions should be 

part and have a voice in informing these choices. 

If we make these decisions cautiously and incrementally, if we 

measure the effects of our decisions and adjust our actions accordingly, then we can achieve not just a win-win, but a quadruple win, 

and believe you me, I really see a quadruple win—really in the 

world of business. 

Firstly, energy producers can win. Energy producers can win like 

those in Alaska because they explore and export more. 

Second, manufacturers win because they, in fact, access these 

fuel and feedstocks at stable, not volatile prices set by some world 

oil cartel. 

Third, the American people win. They win because they will see, 

not just see the huge spikes in utility bills and home heating bills 

like we did a decade ago, but actually will see lower costs and create more jobs for the American consumer. 

Last the U.S. economy wins. The U.S. economy wins because it’ll 

become advantaged and competitive, better balanced, better insulated from price shocks and volatility, more resilient and more robust. 

So the question in front of us, can we do all of this and act in 

the public interest? 

This year is only the 4th or 5th year of a 100-year advantage. 

We have the time. 

Let’s take the time. 

Let’s get this intersection right. 

Let’s manage this with prudence and caution in the public interest. 

Let’s do it in the interest of American workers, American consumers, American industry, American producers. 

Let’s put America first. We should all share that goal. 

I thank you for the opportunity to discuss it. 

[The prepared statement of Mr. Liveris follows:] 

PREPARED STATEMENT OF ANDREW N. LIVERIS, CHAIRMAN AND CHIEF EXECUTIVE

OFFICER, THE DOW CHEMICAL COMPANY, MIDLAND, MI 

The Dow Chemical Company appreciates the opportunity to submit these written 

comments to the Committee on Energy and Natural Resources. Dow is committed 

to sustainable market-based approaches that further the national interest and competitiveness of the United States. 

We applaud the Committee for holding a hearing on opportunities and challenges 

for natural gas. With forward-looking government policy, the shale gas revolution 

presents a once-in-a-lifetime opportunity for the country to further critical national 

goals like economic growth, job creation and investment, energy security and independence. 

About Dow 

Dow was founded in Michigan in 1897 and is one of the world’s leading manufacturers of chemicals, plastics and advanced materials. Dow combines the power of 

science and technology to passionately innovate what is essential to human 

progress. Dow connects chemistry and innovation with the principles of sustainability to help address many of the world’s most challenging problems such as the 

16 

need for clean water, renewable energy generation and conservation, and increasing 

agricultural productivity. Dow’s diversified industry-leading portfolio of specialty 

chemical, advanced materials, agrosciences and plastics businesses delivers a broad 

range of technology-based products and solutions to customers in approximately 160 

countries and in high growth sectors such as electronics, water, energy, coatings and 

agriculture. More information about Dow can be found at www.dow.com. 

Dow is a major user of natural gas and natural gas liquids (NGL), both as an energy source and as feedstock for production of our products. Consequently, we have 

vast experience that can help inform development of thoughtful, constructive policies on the availability and consumption of natural gas. Natural gas plays a critical 

role in the U.S. economy, energy policy and the global competitiveness of the United 

States. In this submission, we will discuss our views on government policies that 

impact natural gas and the effect of those policies on U.S. competitiveness. 

Dow uses natural gas to drive the chemical reactions necessary to turn our feedstocks into useful products, many of which lead to net energy savings. Dow’s global 

hydrocarbon and energy use amounts to the oil equivalent of 850,000 barrels per 

day, approximately the daily energy use of Australia. 

Notwithstanding the challenges of being an energy-intensive manufacturing company, Dow has continually improved its energy and environmental performance, including limiting greenhouse gas emissions, and we are committed to continuous improvement moving forward. Our manufacturing energy intensity, measured in British thermal units (BTUs) per pound of product, has improved more than 40% since 

1990, saving the company more than $24 billion and 5,200 trillion BTUs. Our 2015 

sustainability goals, available at www.dow.com/sustainability/, underscore our energy, climate and other commitments. 

As both a consumer and an innovator in energy efficiency and renewable energy 

technologies, Dow represents a company that believes in an ‘‘all of the above’’ energy 

policy. As important as the promise of natural gas is, we cannot call upon a single 

fuel source to do everything we are asking of it. 

Manufacturing renaissance 

Natural gas is essential for American industry, and growth in shale gas production has been a bright spot for the U.S. economy. Natural gas is an essential component in thousands of everyday consumer products such as cars, appliances, paper, 

steel, plastic products, pharmaceuticals, and in fertilizer for our farms, in addition 

to providing heat, hot water, cooking and electric power to tens of millions of residential consumers. 

Manufacturing in the United States is undergoing a renaissance, facilitated in 

substantial part by reasonable and stable natural gas prices. For the first time in 

over a decade, domestic manufacturers in multiple industries, including petrochemicals, fertilizers, glass, aluminum and steel, are planning to invest in production facilities in the United States. Over 100 new projects have been announced so far, representing approximately $95 billion in new investments. According to Boston Consulting Group, natural gas price reductions could lead to the addition of approximately 5 million manufacturing jobs. This manufacturing renaissance was unimaginable but a few short years ago. 

Dow alone is investing about $4 billion in new U.S. facilities that will create thousands of new American manufacturing jobs. The outlook for affordable U.S. natural 

gas was a significant factor behind our decision to invest on this scale in facilities 

on the U.S. Gulf Coast. To a great extent, continuing optimism for U.S. manufacturing is founded on the prospect of an adequate, reliable and reasonably priced 

supply of natural gas. 

In and of itself, manufacturing is a critical part of a growing, diversified economy 

and a major job creator. Beyond that, however, benefits from a strong manufacturing sector ripple throughout the American economy by creating jobs and increasing investments and spending on research and development. For example: 

• Each job created in the manufacturing sector leads to at least five more jobs 

in the larger economy. 

• Each job in petrochemical manufacturing creates at least eight more jobs in the 

larger economy. 

• Industrial manufacturing creates $8 of value in the larger economy for every 

$1 of natural gas consumed. The manufacturing sector contributes a higher 

value added multiplier to the economy than any other sector or any other use 

of natural gas. 

• Manufacturing firms drive innovation by conducting two-thirds of U.S. research 

and development. 

17 

* All charts have been retained in committee files. 

For these reasons, plentiful and affordable natural gas represents a tremendous 

competitive advantage for American industry. It would be misguided to take actions 

that threaten this advantage. 

Natural gas supply and demand in context 

As with any other commodity, the supply of and demand for natural gas determine its price, and the balance between the two is affected by governmental policies. 

At the same time, U.S. manufacturers are particularly sensitive to natural gas price 

fluctuations. As natural gas prices rise, manufacturers are more likely than other 

sectors of the economy to reduce their consumption. 

Because of this relatively high demand elasticity, manufacturers tend to serve as 

‘‘shock absorbers’’ for the economy when natural gas prices rise. They cut consumption of natural gas, which reduces demand and mutes price volatility for others. 

Gas price increases undermine manufacturing jobs. The United States enjoyed relatively stable natural gas prices from the 1970s to around 2000. Between 2000 and 

2009, however, U.S. industrial gas demand fell 24% as prices rose to highs of almost 

$14.50/MMBtu from a base of roughly $3.50/MMBtu. Job losses in the manufacturing sector totaled approximately 5.4 million between 2000 and 2009, and volatile 

natural gas prices were a significant factor. Manufacturing’s high demand elasticity 

also means that governmental policies that tend to encourage upward pressure on 

natural gas prices affect manufacturers more than other sectors. 

Utilizing natural gas domestically would enhance employment and value added 

throughout the economy. As demonstrated in the chart below*, the effect of deploying 5bcf/day of natural gas in the domestic manufacturing sector would be an increase of $4.9 billion in the national value added (GDP) and a manufacturing employment increase of 180,000 jobs, both directly and through the supply chain. 

In stark contrast, exporting that same 5bcf/day of natural gas overseas as liquefied natural gas (LNG) would lead to a GDP increase of only $2.3 billion and an 

employment increase of only 22,000 jobs. Moreover, even within the construction 

sector the payoff from using natural gas domestically far exceeds the benefits of exporting LNG, as the plant-building construction activity associated with increasing 

the supply of natural gas to energy intensive, trade exposed industries is more than 

four and one-half times greater than the construction activity associated with LNG 

exports. 

Shale gas production has created a short-term focus on expanded supply and the 

effect of that supply on market clearing prices. We believe that focus is misplaced 

because very few policy-making and investment decisions have an impact over such 

a short time horizon. Instead, investment and policy-making should be focused on 

both the medium-and long-term outlook for natural gas. 

In the medium-and long-term, domestic natural gas demand growth is expected 

to be driven by several factors, including: 

• The policy-driven shift in electricity production from coal to natural gas, 

• Increased investments by industry, which uses forty percent of the nation’s natural gas and gas-produced electricity, and 

• Increasing numbers of truck and fleet vehicles that use natural gas in lieu of 

conventional motor fuels. 

Companies in the manufacturing, transportation and utility sectors are already 

making investment decisions based on today’s competitive prices and the outlook for 

affordable and stable natural gas into the future. These decisions will play out over 

the next ten to twenty years. Our assessments indicate that demand for U.S. natural gas may increase by approximately 60 percent above current levels by 2035. 

An important corollary question is whether supply can possibly keep up with this 

new demand. 

Sound policy attracts investments and creates jobs 

Federal policies on environmental regulation, transportation, electric generation, 

exports and taxes will have a major impact on natural gas supply and demand, 

which in turn will have a decisive effect on business investment and job creation 

for manufacturers. Dow supports policies that stimulate economic growth by facilitating adequate and reliable natural gas supplies at reasonable prices. Congress 

should be circumspect about policies that could disrupt natural gas supply and pricing, such as: 

18 

• Policies that focus consumption on one fuel source or that artificially accelerate 

demand ahead of supply, such as regulations that encourage rapid replacement 

of coal fired power plants with natural gas power plants. • Bans or unreasonable limitations on recovering natural gas and oil through hydraulic fracturing. • Exporting LNG without a thorough and inclusive process for evaluating the implications for domestic supply and demand, costs to consumers and manufacturers, jobs and economic growth. 

Advances in hydraulic fracturing have spurred shale gas supply abundance. Hydraulic fracturing technologies have existed for decades, but recent innovation has 

made it possible to more economically recover natural gas from shale deposits. 

While these advances have expanded the supply of natural gas, regulatory authorities at the federal and state levels are scrutinizing the environment effects of this 

production technology. Dow believes that hydraulic fracturing can be done in a safe 

and environmentally responsible way. But overly restrictive environmental regulations or moratoria on hydraulic fracturing could greatly reduce future supplies of 

natural gas, which would have a dramatic impact on the manufacturing sector. A 

governmental policy that incentivizes use and discourages production is a recipe for 

higher prices. 

Likewise, federal and state regulation of electricity generation could affect demand for natural gas. In the power generation sector, a transformation is underway 

as utilities and merchant generators switch from predominantly older coal-fired 

power plants to newer, more efficient natural gas-fired generation. The low price of 

natural gas is driving some of these changes. Because natural gas power plants emit 

fewer greenhouse gases than do coal plants, however, several environmental policies, both enacted and proposed, would also encourage fuel switching. 

Over the last few years, Congress has considered legislation that would establish 

a clean energy standard for domestic power generation or that would tax carbon 

emissions. Such a standard would affect resource allocations and would credit 

sources of generation that are cleaner than coal. Under some policies, natural gasfired generation would qualify for this treatment. We urge caution in considering 

policies that encourage fuel switching between natural gas and coal: electricity producers are already choosing to add gas-fired generation without these additional 

regulations. Unlike power generation, which can rely on other sources such as nuclear, hydro, wind, solar, biomass, demand response or efficiency measures to meet 

capacity requirements, homeowners, farmers and the industrial sector do not always 

have economic alternatives to natural gas. 

EPA rulemakings have increased the cost of owning and operating coal-fired 

power plants. Each of these policies will have the effect of increasing demand for 

electric generation from natural gas-fired power plants, which will put upward pressure on natural gas prices. Such policies should be designed to avoid precipitously 

tipping the supply/demand balance in a way that causes volatility in natural gas 

prices. 

Tax policy also affects supply of and demand for natural gas. For example, as part 

of recent negotiations, some lawmakers have also proposed limits on certain tax incentives that encourage oil and gas exploration and production. Tax policymaking 

should account for the potential impact of policies on the availability and affordability of natural gas. 

As these examples show, government policies may profoundly impact natural gas 

supply and demand, and thus, the manufacturing sector. At Dow, we understand 

that forward-looking, thoughtful public policy is a necessary part of addressing the 

challenges that confront the United States today. At the same time, these policies 

should also focus on renewing and sustaining our newfound American manufacturing advantage, which we believe is critical to ensuring continued economic and 

job growth in the United States and overall U.S. competitiveness. 

Export licensing 

Over 70 years ago, Congress recognized that the import and export of natural gas, 

a finite natural resource, can have critical implications for U.S. prosperity. In the 

Natural Gas Act, Congress charged the executive branch with regulating the import 

and export of natural gas in accordance with the public interest. 

The Department of Energy (DOE) has extensive experience evaluating import applications, but it has had limited experience with export applications. Perhaps not 

surprisingly, there are no clearly established criteria for DOE to apply in determining the public interest with regard to natural gas exporting. 

Dow supports expanded exports and trade. However, we also believe it is crucial 

that DOE have the information and analysis necessary to properly apply the Natural Gas Act requirement that exports be consistent with the public interest. We 

19 

1Dow’s submission is available at http://www.fossil.energy.gov/programs/gasregulation/authorizations/export study/peter molinario em01 24 13.pdf. 2We are encouraged that the Deputy Secretary of Energy recently acknowledged to the Chairman of this Committee that a variety of other topics merit evaluation in connection with LNG 

export application public interest determinations. 

applaud DOE’s recent acknowledgement that an economic study that it commissioned is but one data point in the broad array of considerations that are relevant 

for a public interest determination. In short, Dow supports an approach to such determinations by DOE that is based on objective criteria and metrics, established 

through a public process and applied on an incremental, case-by-case basis in a consistent and balanced manner. 

Today, DOE is considering 16 applications to export LNG. Since the proposed importing countries do not have a particular type of free trade agreement (FTA) with 

the United States, these applications are not covered by the statute’s presumption 

that an FTA represents a determination that the application meets the public interest test. After approving one such application, DOE has temporarily suspended the 

processing of ‘‘non-FTA’’ LNG export applications. Implicitly recognizing that more 

is at stake than can be resolved through its traditional approach to processing export applications, DOE commissioned a report from a private firm to evaluate the 

macroeconomic effects of higher LNG exports. 

As detailed in Dow’s January 24 submission to DOE1, this consultant report is 

fundamentally flawed and underestimates the potential harmful effects of sharply 

higher LNG exports. More broadly, though, commissioning the report should be the 

first step in developing policies that will enable DOE to administer appropriate public interest determinations for LNG export applications. No economic study can account for the full profile of U.S. values that should inform a determination of the 

public interest with regard to natural gas exports. 

The outstanding authorization requests present what is essentially a new challenge. In the modern era, the U.S. government has not faced the need to determine 

the public interest in connection with requests to authorize exports of large volumes 

of natural gas. This Committee should encourage DOE to continue its effort to improve the process for evaluating LNG export applications by providing an opportunity for all affected constituencies and the public at large to comment on how best 

to assess the public interest as it pertains to exports of natural gas. 

Newly discovered sources of natural gas present a great opportunity for the 

United States. At the same time, natural gas remains a finite natural resource with 

important implications for U.S. energy security, energy independence and the environment. Exports can have supply and price effects that have major impacts 

throughout the country. The economic impact of LNG exports is also likely to vary 

by geographic region and by business center. Consequently, public interest determinations should be thorough enough to evaluate nation-wide implications of LNG 

exports as well as localized effects. 

Unchecked LNG export licensing can cause demand shocks, and the resulting 

price volatility can have substantial adverse impacts on U.S. manufacturing and 

competitiveness. In the recent past, the price of natural gas was very high and volatile until the advent of substantial shale gas production. Gas supplies and demand 

are inherently difficult to predict accurately. Thus, Dow urges a cautious, considered, comprehensive and deliberate approach to assessing the public interest. 

Currently, DOE regulations provide for the adjudication of LNG export applications on a case-by-case basis in proceedings that depend on the parties to raise 

issues relevant to a public interest determination and to support their positions with 

persuasive evidence. DOE interprets the Natural Gas Act’s public interest standard 

as creating a rebuttable presumption that a proposed export of natural gas is in the 

public interest. This means that DOE is to approve an application unless those who 

oppose the application can overcome this presumption. 

In its principal order to date authorizing exports of LNG to non-FTA countries, 

DOE identified certain topics as being relevant to its evaluation of the impact of 

LNG exports on the public interest: 

• the domestic need for the natural gas proposed to be exported, 

• whether proposed exports threaten the security of domestic natural gas supplies, and 

• any other issue DOE deems to be important, including whether the export arrangement is consistent with DOE’s policy of promoting competition in the marketplace by allowing commercial parties to freely negotiate their own trade arrangements.2

20 

The topics that DOE has identified for evaluating the public interest are too narrow and vague to capture all of the critical national, regional and local issues at 

stake with LNG exports or to offer any useful guidance. In response to the economic 

study it commissioned, DOE has received more than 370 submissions from a broad 

array of stakeholders covering an equally broad array of topics. The sheer number 

of submitted comments reflects the depth of interest regarding this issue. Unfortunately, the current process provides no assurance that DOE will consider all aspects 

of the public interest in any given proceeding. This is inevitable for an administrative process that depends on arguments and evidence submitted by the parties to 

a specific export application process. These parties are representing their specific interests, and may not adequately represent the totality of the public interest. 

A timely DOE rulemaking process to formulate criteria for determining the public 

interest as it relates to LNG exports could ameliorate some of the shortcomings of 

the current process. All of the major constituencies affected by LNG exports should 

have an opportunity to be heard, which could enable DOE to obtain much broader 

public input and do so efficiently in a single forum. This would increase the likelihood that all relevant considerations will be identified and that cumulative and national effects will be addressed as well as regional effects. The result of such a rulemaking process-establishment of uniform and actionable criteria with measurable 

metrics-would facilitate balanced, comprehensive consideration of the public interest 

by DOE, give parties in individual proceedings advance notice of many of the most 

relevant considerations, and reduce the risk of inconsistent adjudications across applications. DOE would then apply these criteria and metrics incrementally over time 

in individual application proceedings, which would assure fairness and uniformity, 

while allowing DOE to consider changes in circumstances from one application to 

the next. 

More importantly, DOE could adopt a mechanism to balance, in the aggregate, exports and U.S. interests that inform the public interest. A new rule of this kind 

should generally ensure that DOE is presented with adequate and accurate evidentiary records in each licensing proceeding. 

While criteria for determining the public interest should be developed as part of 

the rulemaking described above, we believe the list below provides a good starting 

point for identifying specific, concrete and forward-looking criteria that DOE should 

evaluate in connection with LNG export applications: 

• Domestic manufacturing—How will exports impact natural gas prices and the 

supply/demand balance? Will natural gas supply be reduced? Will there be less 

feedstock for announced investment projects? Will the jobs created by increased 

exports exceed jobs lost by the manufacturing industry? Will additional exports 

displace U.S. consumption? • U.S. consumers—Will exports reduce the supply of natural gas available for 

utilities or affect consumer prices or energy costs? Will utilities decrease fuel 

switching to natural gas? 

• Energy security—Will exports reduce the volume of natural gas available for domestic use or increase the need to rely on imported petroleum? 

• Employment—How many new jobs will be created or existing jobs impacted? 

Are employment gains in the oil and gas sector offset by job losses in other 

areas of the economy affected by relatively higher natural gas prices? 

• International trade—Will exports improve the U.S. balance of trade payments 

sufficiently to offset falling exports in other value-adding sectors of the economy? As to proposed exports to FTA countries, are the exports destined for consumption in the FTA country or will there be transshipment of natural gas to 

non-FTA countries? How can export applications be disposed of in a manner 

consistent with U.S. trade obligations? 

• Environmental—What would the proposed exports’ environmental impact be? 

• Strategic interests—Will the exports support a strategic American ally in a 

meaningful way and consistent with stated policy priorities? Do proposed importing countries accord the United States reciprocal favorable international 

trade treatment? What are the implications for any current or proposed FTA 

negotiations? 

• Price and volatility—How is the LNG contract being priced, and is it linked to 

oil in some manner? What is the expected short and long term impact on natural gas and electricity price volatility? 

• Other regulatory impacts—What is the potential impact of other regulatory decisions on natural gas demand or supply and what is the interplay between 

those impacts and exports of natural gas? 

DOE should apply criteria that result from this rulemaking to applications on a 

case-by-case basis and in an incremental fashion. This would entail evaluating 

21 

whether approving each individual application is in the public interest, and whether 

the incremental impact of approving that application, in light of DOE’s prior approvals, would be consistent with the public interest. Again, the last ten years have seen 

great fluctuations in domestic gas prices, and circumstances can change as drilling 

techniques are improved, sources of consumption are expanded or the condition of 

the economy evolves. 

Forward thinking public policy can spur American industry 

At Dow, we are implementing a comprehensive plan to take advantage of the 

structural change that has occurred in the natural gas market, a market that we 

believe is working. Indeed, we have announced plans to invest in American plants 

based on our belief that natural gas will remain affordable for American industry 

and consumers. We are not alone in our desire to expand our American footprint 

and create thousands of new American manufacturing jobs. 

Forward-thinking policy is essential for maintaining this momentum. Dow wishes 

to support U.S. officials at all levels of government to realize a shared vision of affordable natural gas continuing to revitalize American manufacturing and enhancing U.S. competitiveness. We are in year four or five of a 100 year energy advantage, and a thoughtful, prudent approach to policy-making can ensure that we can 

leverage the competitive advantage to the benefit of all Americans. The country deserves no less. 

We appreciate the opportunity to submit this statement. For more information on 

Dow and our energy plans visit www.dow.com/energy/perspectives. 

The CHAIRMAN. Very good. America first-sums it up. 

Mr. Eisenberg, welcome. 

STATEMENT OF ROSS EISENBERG, VICE PRESIDENT, ENERGY 

AND RESOURCES POLICY, NATIONAL ASSOCIATION OF MANUFACTURERS 

Mr. EISENBERG. Thank you Chairman Wyden. Good morning. 

Good morning Chairman Wyden, Ranking Member Murkowski, and 

members of this committee. My name is Ross Eisenberg. I’m vice 

president of Energy and Resources Policy for the National Association of Manufacturers. 

The NAM is the Nation’s largest industrial trade association, and 

we represent nearly 12,000 small, medium, and large manufacturers in nearly every industrial sector and in all 50 States. Now manufacturers are major energy consumers. We use about 1/3 of the energy consumed in the United States. So for manufacturers, natural 

gas is a critical component of an all-of-the-above energy strategy 

that embraces all forms of domestic energy production, including 

oil, gas, coal, nuclear, energy efficiency, alternative fuels, and renewable energy sources. 

Thirteen years ago, or sorry, 13 months ago, 

PricewaterhouseCoopers, with support from the NAM, released a 

report called Shale Gas, a Manufac-Renaissance in U.S. Manufacturing, and that report found that full-scale and robust development of U.S. shale gas plays could lead to 1 million new manufacturing jobs by the year 2025. Now that’s just manufacturing jobs 

by 2025. In addition, lower feedstock and energy costs could help 

manufacturers reduce manufacturing gas expenses by as much as 

$11.6 billion annually in that same timeframe. PWC’s predictions 

are very quickly becoming a reality. Some are calling it the reindustrialization of America. Almost weekly, we’re seeing companies announce new ventures and facilities to manufacture iron, 

steel, fertilizer, chemicals, plastics, acrylic rosins, diesel fuel, and 

a wide range of other energy-intensive products. 

22 

There’s really no better example of the impact that natural gas 

is having than the announcement last year by a Canadian manufacturer that it plans to actually take apart a working methanol 

plant in Chile and move it to Senator Landrieu’s State of Louisiana. 

The natural gas boom has provided major opportunities to manufacturers across the supply chain. Manufacturers design and construct the drilling facilities, supply machinery and materials for hydraulic fracturing and well completion, and they provide needed infrastructure like pipelines, compression stations, storage facilities, 

and processing facilities. All of this new activity will require roads 

and bridges which, in turn, require concrete, brick, gravel, and 

steel. Drilling sites will need vehicles, fuel, and significant water 

supplies, which will need to be supplied, transported, and treated, 

all by manufacturers. 

Downstream, the possibilities from chemicals to windows to toys 

to electricity are truly endless. 

But let’s not kid ourselves here. None of this is going to happen 

if we can’t get the natural gas out of the ground. We’ve got plenty 

of natural gas, and we believe the free market can generally resolve any disputes over how the gas should be used. 

But if the Federal Government takes an overly prescriptive or reactive approach to permitting, to regulation, or to exports, than our 

natural gas field manufacturing renaissance will be over quicker 

than it began. 

That is the NAM’s message to the committee today. If we truly 

want to create 1 million new manufacturing jobs by 2025, we 

should be encouraging the responsible development of natural gas, 

balanced by reasonable State-based regulation, a manageable permitting process, and a free market approach to potential exports. 

If that happens, we can all be winners. 

States have long been the primary regulators of hydraulic fracturing, and the NAM believes that it should stay that way. Governor Hickenlooper’s testimony today shows that State governments are up to the challenge. Where there’s a perceived efficiency 

in any one State’s regulatory mechanisms, the Federal Government 

should work with the State to fill in those gaps rather than applying a one-size-fits-all Federal rule on States like Colorado where 

really no deficiencies exist. 

The NAM was founded in 1895 on principles of free trade. With 

respect to LNG exports, the NAM fundamentally supports free 

trade and open markets and opposes bans or similar market destroying barriers to exports of natural gas or any other commodity. 

The NAM is not calling for policies that favor LNG exports over 

the use of natural gas domestically nor are we calling for the opposite. What we’re calling for is for the free market to be allowed to 

work. 

The NAM encourages the cost effective use of natural gas to grow 

American manufacturing and believes in a natural gas policy that 

is open—a process that is open, transparent, and objective, and we 

urge policymakers to rely on the best quality of information regarding the impact of LNG exports on economic, environmental, and 

national security interests. 

23 

Finally, the long and complex and often unmanageable permitting process remains a major obstacle, if not the major obstacle, to 

full and robust development of our Nation’s energy resources. For 

instance, the average time to complete an environmental impact 

statement, under the National Environmental Policy Act, takes an 

average of 3.4 years and that gets longer by 37 days with each 

passing year. The developer can then be sued for 6 years after a 

final determination is made. 

Manufacturers really must be able to depend on a predictable, 

reliable, and efficient permitting process. The NAM believes strong 

actions must be taken to streamline the permitting process for energy projects before it is too late. 

To conclude, with the right energy policies in place, manufacturers can experience a true resurgence. Robust development of our 

Nation’s vast natural resources—natural gas resources will help 

drive domestic manufacturing as a critical component of a true allof-the-above energy strategy. 

The NAM stands ready to support the committee’s efforts to promote natural gas development and the manufacturing jobs that it 

will provide. 

Thank you very much for the privilege of testifying today. I look 

forward to any questions. 

[The prepared statement of Mr. Eisenberg follows:] 

PREPARED STATEMENT OF ROSS EISENBERG, VICE PRESIDENT, ENERGY AND

RESOURCES POLICY, NATIONAL ASSOCIATION OF MANUFACTURERS

Good morning, Chairman Wyden, Ranking Member Murkowski and members of 

the Senate Committee on Energy and Natural Resources. My name is Ross 

Eisenberg, and I am vice president of energy and resources policy at the National 

Association of Manufacturers (NAM). I am pleased to share the NAM’s views on the 

importance of America’s natural gas resources and the vital role they can play for 

manufacturing, jobs and the economy. 

The NAM is the nation’s largest industrial trade association, representing nearly 

12,000 small, medium and large manufacturers in every industrial sector and in all 

50 states. Manufacturers are major energy consumers, using one-third of the energy 

consumed in the United States. For manufacturers, natural gas is a critical component of an ‘‘all-of-the-above’’ energy strategy that embraces all forms of domestic energy production, including oil, gas, coal, nuclear, energy efficiency, alternative fuels 

and renewable energy sources. 

The United States has a mix of energy resources and innovative technologies unmatched by any other nation in the world. The United States is the ‘‘Saudi Arabia 

of coal’’ and has for years relied on its dominant coal reserves for baseload power 

generation; more than 100 nuclear power plants cleanly and efficiently produce a 

substantial portion of the nation’s electricity; renewable sources are growing quickly 

and diversifying the nation’s energy portfolio; and advances in energy efficiency continue to cut manufacturers’ energy costs. Most recently, technological breakthroughs 

have made vast domestic deposits of oil and gas cheaply and easily accessible, offshore and onshore. What was once a potential weakness has become a major 

strength for manufacturers. 

Natural Gas—Fueling Growth in the Manufacturing Sector 

The natural gas boom has provided major opportunities for manufacturers across 

the supply chain. Upstream, manufacturers design and construct drilling facilities; 

supply machinery and materials, such as cement and steel for hydraulic fracturing 

and well completion; and perform a wide range of support activities and services for 

the natural gas extraction process. Midstream, manufacturers provide needed infrastructure, such as pipelines, compressor stations, storage facilities and processing 

facilities. And downstream, the possibilities-from chemicals to windows to toys to 

electricity-are truly endless. 

The natural gas manufacturing supply chain extends even further. All of this new 

activity will require roads and bridges, which, in turn, requires concrete, brick, gravVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00027 Fmt 6633 Sfmt 6621 G:\DOCS\80132.TXT 80132
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1 ‘‘Shale Gas Will Fuel a U.S. Manufacturing Boom,’’ MIT Technology Review, Jan. 9, 2013, 

available at http://www.technologyreview.com/news/509291/shale-gas-will-fuel-a-us-manufacturing-boom/. 2 Available at http://www.pwc.com/us/en/industrial-products/publications/shale-gas.jhtml. 

3 ‘‘Encana, Nucor report joint Piceance basin gas drilling program,’’ Oil & Gas Journal, Nov. 

9, 2012, available at http://www.ogj.com/articles/2012/11/encana-nucor-report-joint-piceancebasin-gas-drilling-program.html. 4 ‘‘Mitsubishi Chemical to build $710 million U.S. plant, eyes shale gas cost savings,’’ Reuters, 

Dec. 23, 2012, available at http://www.reuters.com/article/2012/12/23japan-usamitsubishichemical-idUSL4N09X05Z20121223. 5 ‘‘The new boom: Shale gas fueling an American industrial revival,’’ The Washington Post, 

Nov. 14, 2012, available at http://articles.washingtonpost.com/2012-11-14/business/ 

35506130l1lnatural-gas-shale-cf-industries. 6 ‘‘Formosa Plastics U.S.A. Will Invest US$1.7 B. in Expansion,’’ CENS, Dec. 14, 2012, available at http://cens.com/cens/html/en/news/newslinnerl42344.html. 7 ‘‘Shale-Gas Revolution Spurs Wave of New U.S. Steel Plants,’’ Bloomberg, Dec. 31, 2012, 

available at http://www.bloomberg.com/news/2012-12-31/shale-gas-revolution-spurs-wave-of-newu-s-steel-plants-energy.html. 

el and steel. Drilling sites will need vehicles, fuel and significant water supplieswhich will need to be supplied, transported and treated. Site employees will need 

uniforms, and those uniforms will need to be cleaned and maintained. The list goes 

on and on. 

As more natural gas is recovered, domestic manufacturers gain a substantial cost 

benefit relative to their international competitors. Thanks to newfound supply and 

price stability, manufacturers in the United States enjoy natural gas prices considerably lower than in China, India, Brazil, Japan and the United Kingdom.1 This is 

a very important point, since the NAM estimates that due to domestic tax, tort and 

regulatory policies, it is 20 percent more expensive to manufacture in the United 

States than in any of its nine largest trading partners-and that excludes the cost 

of labor. Manufacturers in the United States enjoy a slight competitive advantage 

regarding energy, and with the right policies, this advantage can grow. 

In December 2011, PricewaterhouseCoopers (PwC), with support from the NAM, 

released the report Shale Gas: A renaissance in US manufacturing?2 PwC’s study 

examined what a growing shale gas industry could truly mean for manufacturing 

job creation in the United States. The results are impressive: PwC found that fullscale and robust development of U.S. shale gas plays could result in 1 million new 

manufacturing jobs by 2025. In addition, lower feedstock and energy costs could 

help manufacturers in the United States reduce natural gas expenses by as much 

as $11.6 billion annually in that same time frame. Chemical manufacturers had 

been the largest beneficiaries of this new abundance of natural gas, owing primarily 

to less expensive ethane, a natural gas liquid derived from shale gas. PwC identified 

Bayer Corporation, Chevron Phillips Chemical Company, Formosa Plastics Corporation and Westlake Chemical Corporation as companies taking early advantage of the 

shale gas boom. 

PwC found that the benefits of shale gas for manufacturers were not limited to 

the major natural gas users; the benefits extended throughout the supply chain. According to PwC, companies that sell goods, such as metal tubular products and drilling and power equipment, were likely to experience near-term growth in sales as 

domestic natural gas production rates increased. PwC identified projects by U.S. 

Steel and Vallourec Ohio intended to supply steel pipe and related materials for 

shale gas extraction activities. These higher production levels would also yield benefits higher in the value chain, such as manufacturers of components used in drilling 

equipment. Overall, PwC found that 17 chemical, metal and industrial manufacturers commented in SEC filings in 2011 that shale gas development drove demands 

for their products, compared to none in 2008. 

In the 13 months that have passed since PwC released its study, the impact of 

new supplies of natural gas on manufacturing has become even more pronounced. 

Nucor embarked on plans to develop a $750 million iron facility in Louisiana and 

announced a $3 billion joint venture with Canadian oil and gas producer Encana 

for 20 years of access to its natural gas wells.3 Mitsubishi announced plans to build 

an acrylic-resin processing plant adjacent to a newly constructed ethylene plant.4

Fertilizer manufacturer CF Industries announced that it will spend $2.1 billion to 

expand its fertilizer manufacturing operations.5 Formosa Plastics Corporation increased the size of its Texas ethylene plant included in the 2011 PwC6 report. Even 

foreign manufacturers are now seeking to build operations in the United States. 

Austrian steel manufacturer Voestalpine AG announced in late 2012 it plans to 

build a $661 million steel factory in the United States.7 South African energy company Sasol announced plans to construct America’s first commercial gas-to-liquids 

25 

8 ‘‘Sasol Betting Big on Gas-to-Liquid Plant in U.S.,’’ The New York Times, Dec. 17, 2012, 

available at http://www.nytimes.com/2012/12/18/business/energy-environment/sasol-betting-bigon-gas-to-liquid-plant-in-us.html?pagewanted+all&lr=0. 9 ‘‘Egyptian Bets $1,4 Billion on Natural Gas—In Iowa,’’ The Wall Street Journal, Sept. 5, 

2012, available at http://online.wsj.com/article/ 

SB10000872396390443589304577633932086598096.html. 10 ‘‘The new boom: Shale gas fueling an American industrial revival,’’ The Washington Post, 

Nov. 14, 2012, available at http://articles.washingtonpost.com/2012-11-14/business/ 

35506130l1lnatural-gas-shale-cf-industries. 11 ‘‘Shale Gas Revolution Spurs Wave of New U.S. Steel Plants,’’ Bloomberg, Dec. 31, 2012, 

available at http://www.bloomberg.com/news/2012-12-31/shale-gas-revolution-spurs-wave-of-newu-s-steel-plants-energy.html. 12 Id. 13Fullenbaum, Richard, and John Larson, The Economic and Employment contributions of 

Unconventional Gas Development in State Economies, June 2012, available at http:// 

www.anga.us/media/content/F7D4500D-DD3A-1073-DA3480BE3CA41595/files/ 

statelunconvlgasleconomiclcontribution.pdf.l 14 ‘‘Executive Order—Supporting Safe and Responsible Development of Unconventional Domestic Natural Gas Resources,’’ Apr. 13, 2012. 

plant in Louisiana, an $11 billion-$14 billion venture.8 Egyptian fertilizer manufac- turer Orascom Construction Industries plans to build a $1.4 billion nitrogen fertilizer production plant in Wever, Iowa.9 Canadian methanol producer Methanex announced in 2012 that it will dismantle a methanol plant in Chile and move it to 

Ascension Parish, Louisiana.10 BlueScope Steel Limited, an Australian company, is 

building a steel factory in Ohio in partnership with U.S. manufacturer Cargill.11

And Indian manufacturer Essar Global Limited is planning a steel facility for Minnesota.12

Last June, a report by independent global energy research firm IHS CERA predicted that the share of U.S. natural gas produced from unconventional sources will 

reach 67 percent by 2015 and 79 percent by 203513. This would lead to $3.2 trillion 

in investments to develop the resource and 1.4 million new jobs (on top of the 1 million already created by the industry). These economic benefits are not limited to gasproducing states; non-gas-producing states contributed 18 percent of the total U.S. 

employment generated by unconventional gas activity in 2010. IHS CERA concluded 

that increased unconventional gas activity will contribute to capital investment, job 

opportunities, economic growth, government revenue and lower prices across the 

country. 

Opportunities and Challenges for Natural Gas Development 

This newfound natural gas renaissance has brought with it increased scrutiny 

from our nation’s capital. With increased scrutiny comes a host of policy-related 

issues, from debates over how best to use this valuable new resource to the need 

for federal oversight and regulation. 

1. Federal Regulation 

Whether and how the federal government plans to regulate shale gas continues 

to pose a major concern for manufacturers. By early 2012, no fewer than 12 federal 

agencies were considering some form of oversight or regulation of the practice of hydraulic fracturing. The NAM brought this issue to the White House, and in response, President Obama issued an Executive Order in April 2012 requiring federal 

agencies to better communicate and coordinate with one another.14 The pace of federal oversight appears to have slowed, but there are still a number of regulations 

under development. There is no easier way to limit the job-creating potential of natural gas to manufacturers than to lump so many costly, time-consuming regulations 

onto the drilling process that the gas never gets out of the ground. 

One regulation that greatly concerns manufacturers is the pending disclosure and 

well stimulation rule under development at the Bureau of Land Management 

(BLM). The BLM performed a cost-benefit analysis for the proposed regulation, and 

under virtually every scenario modeled, the rule’s costs outweighed its benefits. The 

BLM recently announced that it has revised the rule and will issue a new proposal 

for public comment. The NAM is cautiously optimistic that the BLM will fix the 

rule, which an economic analysis by John Dunham & Associates for the Western 

Energy Alliance found would cost $1.615 billion for new and existing wells in the 

13 western states that contain the preponderance of the nation’s federal and Indian 

lands. The regulation would impact an estimated 5,058 wells waiting to be permitted or drilled. The study found that Wyoming would see the biggest cost impact 

from the proposed rule, with an average $771.7 million in costs, followed by New 

Mexico with $169.0 million, Utah with $155.2 million and Colorado with $142.7 million. 

26 

15 Economic, environmental and energy security interests are the factors the DOE traditionally considers, although it is within its authority to consider other factors in making the public 

interest determination. 

States have long been the primary regulators of hydraulic fracturing. The NAM 

believes states should continue to be the main regulators of this industry and is concerned that reactive federal regulation could harm any potential gains resulting 

from increased exploration of shale oil and gas. Where there is a perceived deficiency in any one state’s regulatory mechanisms, the federal government should 

work with the state to fill in the gaps rather than imposing a one-size-fits-all federal 

rule on states where no deficiencies exist. In fact, there are existing programs in 

place to ensure that state regulation is sufficient. The State Review of Oil & Natural 

Gas Environmental Regulations (STRONGER) program reviews states’ oil and gas 

regulatory programs and recommends improvements. The Interstate Oil and Gas 

Compact Commission also supports the states with model regulations. There is no 

legitimate reason why the continued operation of these programs will not be sufficient to ensure effective state regulation that meets the federal government’s goals. 

2. Liquefied Natural Gas (LNG) Exports 

The NAM was founded in 1895 on principles of free trade. At the time, the United 

States was in the midst of a deep recession, and many of the nation’s manufacturers 

saw a strong need to export their products. This commitment to free trade and open 

markets continues to be embedded in the NAM’s policies today. Exports have been 

and continue to be a critical source of growth and opportunity for manufacturers 

throughout the United States. The 40 percent increase in goods exports that the 

United States has enjoyed between 2009 and 2011 has enabled many manufacturers 

to sustain and, in some cases, even grow employment during very difficult economic 

times. Export growth is vital not just for those businesses that directly export, but 

for the many suppliers of inputs and services to those businesses throughout every 

state. 

Natural gas liquefaction is a manufacturing process. To convert natural gas to 

LNG, the gas is purified by removing any condensates, such as water, oil and mud, 

as well as other gases, such as carbon dioxide and hydrogen sulfide and trace 

amounts of mercury. The gas is then supercooled in several stages until it is liquefied and ready for shipping. 

The Department of Energy (DOE) has received applications for 15 proposed terminals seeking to export LNG to non-free trade agreement (FTA) countries. While 

most of these proposed terminals have received approval to export to FTA countries, 

only one terminal in the United States-Sabine Pass in Louisiana-has been permitted 

to export to non-FTA countries. Under the Natural Gas Act of 1938, anyone seeking 

to export natural gas must obtain prior authorization to do so from the DOE. The 

Act instructs the DOE to issue an order allowing natural gas exports unless, after 

opportunity for hearing, it finds that the proposed exports would not be consistent 

with public interests. Exports to FTA countries are deemed to be in the public interest and thus enjoy an expedited permitting process. Even for exports to non-FTA 

countries, the public interest of LNG exports is presumed, but this presumption is 

rebuttable on a successful showing that the exports at issue are contrary to the economic, environmental and/or energy security interests15 of the United States. The 

public interest finding is specific to and required for each individual export terminal 

seeking exports to non-FTA countries; thus, each of the 15 pending applicants will 

need to successfully navigate the public interest determination process. 

The NAM believes that LNG exports should be governed by principles of free 

trade and open markets. The NAM also opposes bans or similar market-distorting 

barriers to exports of LNG or any other commodity. 

Natural gas is vitally important to manufacturers and job creation, as well as 

achieving affordable energy in this country. We are committed to increasing our vast 

domestic onshore and offshore energy resources with balanced and sensible regulation. Regarding LNG and natural gas, the NAM’s official policy positions were established in March 2012 by the NAM Board of Directors, with full participation in the 

drafting by both energy producers and users. They are as follows: 

LIQUEFIED NATURAL GAS

The dramatic increase in the domestic natural gas resource base has reduced the likelihood of the need for significant Liquefied Natural Gas 

(LNG) imports. Some now believe the U.S. could eventually become a net 

exporter of natural gas. An adequate supply of natural gas is needed to 

meet the growing demand of the U.S. manufacturing sector in a recovering 

economy. The NAM strongly supports federal and state policies to accommoVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00030 Fmt 6633 Sfmt 6621 G:\DOCS\80132.TXT 80132
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date growth in domestic natural gas production. We further believe abundant domestic natural gas resources can fuel a renaissance in U.S. manufacturing. The NAM fundamentally supports free trade and open markets. 

We support a natural gas policy process that is open, transparent and objective. 

NATURAL GAS AND MANUFACTURING

Industry relies on natural gas for much of its energy needs and as a raw 

material. The NAM believes policies that encourage the cost-effective use 

of natural gas to grow American manufacturing should be encouraged. 

The U.S. economy relies on natural gas for much of its energy needs and 

as a feedstock for commercial products. Natural gas is and will remain an 

important manufacturing commodity because of its scalability, affordability, 

versatility and efficiency. The NAM supports policies at the federal and 

state level that facilitate the responsible and expeditious development of 

natural gas resources, allowing these benefits to contribute to America’s 

economic recovery and to accrue for energy consumers. 

The principles above remain the policy of the NAM on LNG and natural gas. 

As clearly indicated by the policy language above, the NAM is not calling for policies that favor LNG exports over the use of natural gas domestically. Nor are we 

calling for policies that would engineer the opposite. Our policy statements highlight 

the important role domestic natural gas resources can have for the manufacturing 

economy. Natural gas truly does have the potential to be a game-changer that could 

fuel major investments across the manufacturing supply chain, supporting millions 

of jobs and ensuring that the United States remains the world’s top manufacturing 

economy. As our policy makes clear, we believe ‘‘abundant domestic natural gas resources can fuel a renaissance in U.S. manufacturing,’’ and ‘‘encourage the cost-effective use of natural gas to grow American manufacturing.’’ We believe in ‘‘a natural gas policy process that is open, transparent and objective.’’ With that in mind, 

the NAM urges the DOE and policymakers to rely on the best-quality information 

regarding the impact of LNG exports on economic, environmental and energy security interests. 

The NAM also opposes bans on the export of LNG. From the President’s first 

State of the Union address, doubling U.S. exports has been a top U.S. goal. From 

its origins, the United States has been built on exports. In fact, Article I, Section 

9 of the U.S. Constitution provides quite explicitly that ‘‘[n]o Tax or duty shall be 

laid on Articles exported from any State,’’ evincing a strong disinclination to limit 

exports of any product. 

With 95 percent of the world’s consumers living outside of the United States, export bans on any product, including LNG, can be expected to have far-reaching negative effects, including on domestic economic opportunities, employment and ultimately economic growth. The NAM’s policies on international trade, established by 

the NAM Board of Directors in March 2012, form the basis for this position: 

INTERNATIONAL TRADE

The objective of the NAM’s international trade policy is to strengthen 

manufacturing in America and improve the competitiveness of American 

manufacturing in the worldwide economy. Fairly conducted trade provides 

opportunities for growth and expansion of manufacturing in America, increases the range of goods and services available to consumers, enhances 

market-based production globally and contributes to closer understanding 

and cooperation among nations. The NAM believes this objective can best 

be achieved by limiting costs and other impediments imposed on U.S. manufacturers and by pursuing and utilizing a rules-based international trading system that enhances the role of free market forces while seeking to 

eliminate market-distorting governmental intervention. 

WTO DISPUTE SETTLEMENT

The NAM believes all WTO member economies, including the United 

States, should comply with WTO agreements, including the Dispute Settlement Understanding. 

The United States and its G-20 partners have repeatedly expressed their deep 

concern about rising protectionism, including, in particular, export restrictions, 

which began to proliferate globally as the world economy declined in 2008. Export 

restrictions are viewed as one of the fastest-growing forms of distortion in the international trading system. The Organisation for Economic Co-operation and Development (OECD) has been keeping an inventory on export restrictions and has pubVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00031 Fmt 6633 Sfmt 6621 G:\DOCS\80132.TXT 80132
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16The Economic Impact of Export Restrictions on Raw Materials, OECD (Nov. 2010) 17GATT XI:1 states: ‘‘No prohibitions or restrictions other than duties, taxes or other charges, 

whether made effective through quotas, import or export licenses or other measures, shall be 

instituted or maintained by any contracting party on the importation of any product of the territory of any other contracting party or on the exportation or sale for export of any product destined for the territory of any other contracting party.’’ 18Piet deWitt, Carole A. deWitt, ‘‘How Long Does It Take to Prepare an Environmental Impact Statement?’’ Environmental Practice 10(4), December 2008. 

lished analytical work examining the economic concerns with imposing such restrictions.16

The United States has been in the forefront of challenging other countries’ export 

prohibitions, starting with China’s restrictions on raw material exports and more recently China’s restraints on rare earth exports. In the raw materials case the WTO 

found conclusively that China’s raw material export quantitative restrictions were 

contrary to the core international trade disciplines of the WTO, including GATT Articles XI:117 that generally prohibit the use of export bans and quantitative export 

restraints. These obligations apply equally to the United States, China and all other 

WTO members. 

The United States’ ability to challenge other countries’ existing exports restraints 

on agricultural, forestry, mineral and ferrous scrap products-just to name a few-will 

be virtually nonexistent if the United States begins imposing its own export restrictions. Even worse, as the world’s largest economy and largest trading country, U.S. 

actions are often replicated by our trading partners to our own dismay. If the 

United States went down the path of export restrictions, even more countries would 

quickly follow suit and could easily limit U.S. access to other key natural resources 

or inputs that are not readily available in the United States. 

3. Permitting 

The long, complex and often unmanageable permitting process remains a major 

obstacle-if not the major obstacle-to full and robust development of our nation’s energy resources. Natural gas development is no exception. The NAM strongly urges 

this Committee to consider legislation to streamline the permitting process for energy projects. 

Natural gas producers must generally obtain permits that include approval of well 

design, casing and cementing, the well stimulation (hydraulic fracturing) program, 

chemicals used, waste disposal and storage. They now must also comply with EPA 

New Source Performance Standards (NSPS) for emissions. For wells on Federal or 

Indian lands, the BLM proposed rule would add an open-ended new layer of permitting that governs many of the same areas (well construction, water protection, 

chemical disclosure) as the state permits. Those drilling-specific permits must be obtained in addition to other general state and local permits for construction and related activities. 

For an LNG export facility, the permitting process is truly daunting. Applicants 

not only must apply to the DOE for an export license, but also must engage in an 

environmental review of their project under the National Environmental Policy Act 

(NEPA) led by the Federal Energy Regulatory Commission (FERC). Compliance 

with NEPA requires that the project developer first acquire land and begin design 

and engineering plans, a two-year time commitment. The NEPA review process requires the input of up to 20 federal and state agencies coordinated by FERC that 

have a say in the review. During the course of the NEPA review, applicants must 

obtain, among other things, a dredge-and-fill permit from the Army Corps of Engineers (with input from EPA), a Waterway Suitability Assessment from the U.S. 

Coast Guard, air permits from EPA and state agencies, and the usual state and 

local permits for construction and related activities. Detailed project engineering design work and project study is required for compliance with NEPA, requiring tens 

of millions of dollars in up-front capital and a significant commitment in time. The 

average time to complete an environmental impact statement (EIS) under NEPA 

takes an average of 3.4 years, a number that increases by an average of 37 days 

with each passing year.18 Assuming the applicant can make it through this process 

and receives final NEPA approval, the project is still subject to lawsuits from private parties over the substance of the NEPA environmental review for six years. If 

the applicant somehow survives that process, it also must find long-term contracts 

to sell the product and approach the financial community to secure financing 

(roughly $10 billion) to construct and operate the project. All of this is in addition 

to the export license that must also be obtained from DOE at some point during 

the process. 

29 

19 U.S. Department of Transportation v. Public Citizen, 541 U.S. 752, 767 (2004). 

The permitting process appears to be getting worse. The EPA and the Sierra Club 

recently urged FERC to consider the upstream implications of natural gas development when permitting LNG terminals and related pipeline infrastructure in Maryland and Oregon. FERC concluded that upstream natural gas development is not 

a reasonably foreseeable impact of the construction of an export terminal or related 

pipeline infrastructure, a finding consistent with NEPA, which requires a ‘‘reasonably close causal relationship’’ in order for an impact to be relevant.19 However, the 

EPA and other officials are making a similar argument to extend NEPA with respect to coal export facilities in the Pacific Northwest, and negative precedent established in that context could migrate to natural gas permitting. The NAM strongly 

opposes using NEPA to require a cradle-to-grave, lifecycle impact analysis that assesses the impact of the cargo and all similar cargo transported through the region, 

which would create a very dangerous precedent that could be used to block exports 

of all types. 

If manufacturers are to create jobs and boost the economy through natural gas 

development, they must be able to depend on a predictable, reliable and efficient 

permitting process. The NAM believes strong actions must be taken to streamline 

the permitting process for energy projects before it is too late. 

CONCLUSION

With the right energy policies in place, manufacturers could experience a true resurgence. Robust development of our nation’s vast natural gas resources will help 

drive domestic manufacturing as a critical component of a true ‘‘all-of-the-above’’ energy strategy. We must expect that other nations will soon develop the technologies 

and methods to access their own unconventional gas resources, giving the United 

States a relatively limited window of time in which it can truly exploit the current 

cost advantage. The NAM stands ready to support the Committee’s efforts to promote natural gas development and the manufacturing jobs it can provide. 

The CHAIRMAN. Thank you very much Mr. Eisenberg. 

We will be working closely with you. 

Our next witness, Ms. Frances Beinecke, has been a leading advocate for clean air, water, and protecting our land for many years. 

We welcome you. 

STATEMENT OF FRANCES BEINECKE, PRESIDENT, NATURAL 

RESOURCES DEFENSE COUNCIL, NEW YORK, NY 

Ms. BEINECKE. Thank you very much Chairman Wyden, Senator 

Murkowski, and members of the committee. 

Thank you for holding this hearing today and for inviting me on 

this critical to testify on this critical issue. 

We all know that shale gas is changing our Nation’s energy profile. 

If extracted and used in ways that minimize environmental risks, 

natural gas can be one part of a broader strategy to reduce carbon 

emissions while providing potential economic benefits. 

But natural gas cannot be the ultimate answer to our energy future. For that we need clean and renewable power that is used as 

efficiently as possible. 

With stakes this large, it is imperative that we have in place the 

national safeguards necessary to protect our communities, our environment, and the public health from needless and unnecessary 

harm. As of now, we lack such safeguards, and those protections 

we do have are no match for the explosive growth in the use of hydraulic fracturing or fracking in some 30 States across the country. 

NRDC believes we need to put those safeguards in place before 

any further expansion in the use of fracking. 

It is important and essential that we get this right as a country. 

30 

In more than 3 decades as an environmental advocate, I have 

never seen a single issue that has frightened, antagonized, and activated people across the country like the practice of fracking. Families are angered and frustrated by their inability to control 

fracking in their towns and sometimes on their own property. They 

want to know that their water is safe, that their air is clean, and 

that their lands and farms are protected, and they want to know 

that their children are healthy. 

Now against that background, I’d like you to imagine for a moment that someone came to your community today and said they 

had a new technology to try out near your home. It would use massive amounts of fresh water and undisclosed toxic chemicals to 

break up the bedrock deep underground. It would then bring to the 

surface substances known to cause illness and environmental harm 

while polluting the air and creating toxic wastes. If someone said 

that to you today, would your first reaction be to exempt those operations from existing environmental protections and leave control 

to a patchwork across the entire country? Not likely, and yet that’s 

what’s happening with fracking. 

Congress has exempted many fracking activities from the most 

fundamental safeguards we all depend on to protect our environment and health: The Clean Water Act, the Safe Drinking Water 

Act, the Clean Air Act, waste disposal standards, and the National 

Environmental Policy Act. No wonder people across the country are 

worried, and we need to fix that. 

Instead Federal agencies have only just begun, halfheartedly at 

that, to use what authority they do have to protect the public. It’s 

still unclear how much they will ultimately do as Chairman Wyden’s letter to the Bureau of Land Management indicated just last 

week. 

A BLM document leaked to the press later in the week indicated 

that BLM may be going in exactly the wrong direction, weakening 

even proposed disclosure requirements that were initially identified. There is no justification for these exemptions and lack of action. 

We ask this Congress to act and close these dangerous loopholes 

which deprive Americans of the basic protections they have come 

to expect. 

Meanwhile, as I detail in my written testimony, scientific evidence is mounting about the negative impacts of fracking on the 

environment. These include damage to health from air pollution 

that comes from industrializing our landscapes, damage from industrial spills and poorly managed wastewater, and damage to the 

climate from methane leaks and venting. At the very minimum, the 

research shows there is no reason to have a default assumption 

that fracking is harmless or somehow less in need of the kind of 

Federal oversight that has been routine for similar activities for 

decades. 

Yet, we’re not arguing for a complete hands-off approach from 

the public. 

The industry calls for regulation to be left to the States. Let’s be 

clear. We see this as forum shopping. 

States often lack the technical resources or the political wherewithal to enforce adequate safeguards. If a number of States were 

31 

to begin effectively to oversee this industry, companies would come 

running to Washington to demand Federal rules to preempt what 

they would surely call a patchwork of State laws. 

Instead, industry now claims that the specifics of fracking are too 

local to allow for Federal standards. That argument is belied by the 

industry’s own actions because industry has begun working to 

block Local Governments from controlling fracking. 

There is simply no legitimate argument for not using the same 

cooperative federalism model to oversee fracking that is used for all 

the other industrial activities that are covered by Federal law. 

One final but important point, natural gas, even if properly produced and consumed, is not a complete panacea for our energy 

challenges. It is still a fossil fuel. When burned, it produces fossil 

fuel pollution and contributes to climate change. That means that 

even as we work together to put in place the safeguards we need 

to protect our environment and health, we must strengthen those 

policies that promote the energy solutions of tomorrow, including 

efficiency and renewable power. 

We have learned as a country some hard lessons about the consequences of uncontrolled resource extraction. As we confront the 

emerging challenges of fracking, we must learn from our history 

and not repeat mistakes of the past. We must get these protections 

right because we may not get a second chance. 

Thank you for the opportunity to appear today, and I look forward to your questions. 

[The prepared statement of Ms. Beinecke follows:] 

PREPARED STATEMENT OF FRANCES BEINECKE, PRESIDENT, NATURAL RESOURCES

DEFENSE COUNCIL, NEW YORK, NY 

Thank you, Chairman Wyden and Ranking Member Murkowski, for the opportunity to testify today. My name is Frances Beinecke and I am the President of the 

Natural Resources Defense Council (NRDC). I have worked with NRDC for more 

than 30 years. Prior to becoming NRDC’s President in 2006, I served as NRDC’s 

Executive Director for eight years. In addition to my work at NRDC, I was appointed by President Obama in 2010 to the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. 

NRDC is a nonprofit organization of more than 350 scientists, lawyers, and environmental specialists dedicated to protecting public health and the environment in 

the United States and internationally, with offices in New York, Washington D.C., 

Montana, Los Angeles, San Francisco, Chicago, and Beijing. Founded in 1970, 

NRDC uses law, science and the support of 1.3 million members and online activists 

to protect the planet’s wildlife and wild places and to ensure a safe and healthy environment for all living things. 

I. INTRODUCTION

Today’s hearing addresses ‘‘opportunities and challenges for natural gas.’’ This is 

a timely and critically important topic. We all know that shale gas is changing our 

nation’s energy profile. If strong national and state environmental standards for 

natural gas were in place and strictly enforced—that is, standards to protect health 

and limit climate change—natural gas could be one part of a broader strategy to 

reduce carbon emissions, with potential economic gain, even as our country moves 

forward to a clean energy future centered on renewable energy and energy efficiency. We must make sure that the shale gas boom does not distract us from, or 

prevent investment in these crucial clean energy strategies, which represent the 

best path forward. 

32 

1See http://www.nrdc.org/energy/gasdrilling/. 

2 Billionaire Father of Fracking Says Government Must Step Up Regulation, July 19, 2012, 

Christoper Hellman, Forbes, http://www.forbes.com/sites/christopherhelman/2012/07/19/billionaire-father-of-fracking-says-government-must-step-up-regulation/ 3http://www.eia.gov/dnav/pet/hist/ 

LeafHandler.ashx?n=PET&s=ElERTW0lXWCDlNUSlC&f=M 4Fracking Hazards Obscured in Failure to Disclose Wells, Bloomberg, Benjamin Haas (Aug. 

14, 2012), http://www.bloomberg.com/news/2012-08-14/fracking-hazards-obscured-in-failure-todisclose-wells.html 5For that reason, in this testimony, when I refer to hydraulic fracturing or fracking, I am 

referring to all aspects of shale gas production, including site preparation, drilling, fracking, well 

integrity, waste storage and management and air emissions. 

My testimony focuses on the significant environmental, health and community 

risks of natural gas production as it takes place today. NRDC opposes expanded 

fracking until effective safeguards are in place.1

Today, there is an extraordinary mismatch between the ever growing scale of 

fracking—which is occurring in about thirty states—and the limited scope of measures to govern it. Indeed, companies engaged in fracking are not even required to 

provide enough information to enable scientists and the public to fully understand 

the nature or extent of the environmental and health risks fracking poses. 

We can’t eliminate all the risks of natural gas production, but there are many actions the federal government—both Congress and the Administration—as well as 

the states can and must take to reduce them. Now shale gas production is expanding with supersonic speed without having in place even the basic environmental and 

public health requirements that apply to other industries. And the passionate and 

growing community opposition to shale gas production, spurred by concern about its 

environmental and health impacts, is becoming a major challenge for the natural 

gas industry 

Even George P. Mitchell, the Texas oil and gas magnate known as the ‘‘grandfather of fracking,’’ has recognized the need for stronger federal oversight of 

fracking. In an article in Forbes last year, Mitchell was quoted as saying: ‘‘The administration is trying to tighten up controls . . . . I think it’s a good idea. They 

should have very strict controls.’’2

Improved regulation at both the federal and state level can greatly reduce the 

risks presented by shale gas development by, among other things, requiring the use 

of best practices and technologies, coupled with strict enforcement. Some companies 

are already using such practices as green completions, wastewater recycling, closedloop waste management systems, and more in some locations. These methods have 

proved to be both economically and technically feasible. But these practices are not 

being used by all companies in all locations even though they can often save companies money by, for example, capturing more natural gas rather than wasting it and 

by reducing other forms of waste. Rigorous federal standards and requirements to 

improve environmental performance are needed to mandate that all operators employ best practices wherever hydraulic fracturing occurs. 

II. THE ENVIRONMENTAL AND PUBLIC HEALTH CHALLENGES OF NATURAL

GAS PRODUCTION

Oil and natural gas production are expanding across the nation, largely because 

advanced hydraulic fracturing (also known as ‘‘fracking’’) and horizontal drilling 

have made it easier to extract oil and gas from previously inaccessible or uneconomical sites. Fracking involves injecting water and chemicals deep into the earth 

at extremely high pressure to break up layers of rock that harbor deposits of natural 

gas and/or oil. Hundreds of thousands of new oil and gas wells have been drilled 

in the past decade, and oil and gas development is now occurring in about thirty 

states and under consideration in other states.3 According to some reports, about 

90 percent of new wells in North America are fracked.4

Shale gas production comes with the risk of a range of environmental and health 

impacts, including contaminated drinking water supplies; the release of methane, a 

potent greenhouse gas; unhealthy air quality; poorly managed toxic waste disposal; 

impairment of rivers and streams; disruption of communities; and destruction of 

landscapes and wildlife habitat. These impacts stem from all aspects of the shale 

gas extraction process, including hydraulic fracturing itself, site development, well 

construction , water, wastewater and waste management; and well operation, trucking and other activities that result in air emissions-especially emissions of air toxics, 

ozone-forming pollutants and methane, a highly potent greenhouse gas.5

33 

6Ohio EPA investigating dumping of drilling waste water in Youngstown area, Feb. 4, 2013, 

Bob Downing, Beacon Journal, http://www.ohio.com/news/ohio-epa-investigating-dumping-ofdrilling-waste-water-in-youngstown-area-1.370584. 

7 I serve on the Secretary of Energy’s Advisory board, but not the Shale Gas Subcommittee. 

8http://www.shalegas.energy.gov/resources/081111l90ldaylreport.pdf 9Tougher Fracking Regulations Backed by 66%, Poll Shows, Bloomberg, Dec. 13, 2012, Mark 

Drajem, http://www.bloomberg.com/news/2012-12-14/tougher-fracking-regulations-backed-by-66- 

poll-shows.html 10 NRDC Issue Brief, State Hydraulic Fracturing Disclosure Rules and Enforcement: A Comparison (July 2012), Matthew McFeeley, http://www.nrdc.org/energy/files/Fracking-DisclosureIB.pdf 

Real world impacts are occurring right now across the country. Just last week, 

Ohio regulators observed 20,000 gallons of fracking waste being illegally dumped 

into a waterway.6

The risks and impacts of fracking are becoming more widely acknowledged by a 

broad range of stakeholders. In 2011, Department of Energy Secretary Steven Chu 

appointed a Shale Gas Subcommittee of the Secretary of Energy Advisory Board 

(SEAB Shale Gas Subcommittee)7. In their report, the members of this subcommittee, including leading academic experts with a range of perspectives, identified four major areas of concern: possible pollution of drinking water from methane 

and chemicals used in fracturing fluids; air pollution; community disruption during 

shale gas production; and cumulative adverse impacts that intensive shale production can have on communities and ecosystems. The Subcommittee concluded: 

There are serious environmental impacts underlying these concerns and 

these adverse environmental impacts need to be prevented, reduced and, 

where possible, eliminated as soon as possible. Absent effective control, 

public opposition will grow, thus putting continued production at risk.8

The SEAB Subcommittee recommended that the federal government take a series 

of actions to address these issues; many of these recommendations have not yet 

been acted upon. 

Public concern is also increasing. A December 2012 Bloomberg National Poll 

found that 66 percent of Americans want more government oversight of fracking, 

an increase from 56 percent in a September poll9. 

The concerns are well founded. Let’s look in more detail at each of the problems 

and risks associated with fracking. 

A. Chemical Disclosure 

Natural gas producers are not required by any federal law to identify the chemicals in the fracking fluids they are injecting into the ground, and state disclosure 

requirements vary widely. Of the states where fracking takes place, only fourteen 

states require some level of public hydraulic fracturing disclosure and none of these 

provides comprehensive disclosure. An NRDC analysis found that even where some 

disclosure is required, the public is hampered in getting this most basic information 

about fracking. For example, 

• In some states it is difficult for the public to access the information disclosed; 

• Only seven of fourteen states mandate the chemical identification of all additives used in fracking fluids; 

• Only one state has a clear process for evaluating and approving or denying 

trade secret exemption claims; and 

• Only six states provide for access to trade secret information by health care providers.10

In addition, enforcement of state rules is uneven; NRDC has found that state 

agencies have accepted disclosure reports that lack required information. 

The lack of standardized, national disclosure greatly hampers the ability of researchers to study the impacts of fracking on health and the environment. Scientists 

need transparent, thorough and consistent information on what chemicals different 

communities are being exposed to. The variation in disclosure requirements among 

states makes it difficult to do comparative studies and deprives communities of information they have a right to know. 

B. Health Concerns Related to Drinking Water and Air Pollution 

Scientific concern about the health impacts of fracking are growing. In April 2012, 

the Institute of Medicine (IOM), part of the National Academy of Sciences, convened 

a two-day workshop of public health experts that included more than a dozen presentations raising concerns about the health implications from natural gas developVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00037 Fmt 6633 Sfmt 6621 G:\DOCS\80132.TXT 80132
34 

11 Institute of Medicine. 2012. Workshop on the Health Impact Assessment of New Energy 

sources: Shale Gas Extraction. April 30-May 1, 2012. Washington, DC. http://www.iom.edu/Activities/Environment/Environmental HealthRT/2012-APR-30aspx. 12Masten, S. 2012. HHS & NIEHS Activities Related to Hydraulic Fracturing and Natural 

Gas Extraction. Presentation made at the 2012 Shale Gas Extraction Summit: October 2, 2012. 

http://environmentalhealthcollaborative.org/images/ScottPlenary.pdf; ATSDR, Health Consultation: Public Health Implications of Ambient air Exposures to Volatile Organic Compounds as 

Measured in Rural, Urban, and Oil & Gas Development Areas Garfield County Colorado (2008); 

United States Environmental Protection Agency (US EPA). 2012. EPA’s Study of Hydraulic 

Fracturing and Its Potential Impact on Drinking Water Resources. http://www.epa.gov/hfstudy/ 

. 13Occupational Safety Health Administration (OSHA) 2012. Hazard Alert, Worker Exposure 

to Silica During Hydraulic Fracturing. www.osha.gov/dts/hazardalerts/hydrauliclfraclhazardlalert.html; 14Pediatric Environmental Health Specialty Units and the American Academy of Pediatrics. 

2011. PEHSU Information on Natural Gas Extraction and Hydraulic Fracturing for Health Professionals. http://aoec.org/pehsu/documents/hydrauliclfracturinglandlchildrenl2011lhealthlprof.pdf; 15 ATSDR, Health Consultation: Public Health Implications of Ambient Air Exposures to Volatile Organic Compounds as Measured in Rural, Urban, and Oil & Gas Development Areas Garfield County Colorado (2008) 16Osborn, SG, A Vengosh, NR Warner, RB Jackson. 2011. Methane contamination of drinking 

water accompanying gas-well drilling and hydraulic fracturing. Proceedings of the National 

Academy of Sciences, U.S.A. 108:8172-8176. http://www.biology.duke.edu/jackson/pnas2011.pdf. 17See, e.g., USEPA 2011. Draft Investigation of Ground Contamination near Pavillion, Wyoming. EPA 600/R-00/000 18 Bamberger M, Oswald RE. Impacts of gas drilling on human and animal health. New Solut. 

2012;22(1):51–77. 

ment.11 Additionally, government agencies, including the Agency for Toxic Substances Disease Registry (ATSDR) within the Department of Health and Human 

Services (HHS) and the Environmental Protection Agency (EPA), have investigated 

and found risks from individual sites and practices.12 Health-related advisories and 

informational resources have been made available by the National Institute for Occupational Safety and Health (NIOSH), the Occupational Safety and Health Administration (OSHA)13 and the Pediatric Environmental Health Specialty Units 

(PEHSU).14

A growing number of people have reported health problems that they attribute 

to chemical exposures from nearby fracking and production activities. As noted 

above, research is stymied by the lack of disclosure of information on chemicals used 

in fracking. In addition, little if any on-site monitoring is required of emissions into 

air or water. But some of the pollutants associated with fracking are also known 

to cause the same types of respiratory and/or neurological problems that are the 

focus of concern in impacted communities. Some of these chemicals are also wellestablished as carcinogens.15

Fracking also can generate pollution from hazardous substances, including metals, radioactive material, methane and other volatile organic compounds (VOCs), 

that are found in the geologic deposits being exploited and brought to the surface 

in the drilling, fracking, and production processes. 

Chemicals in Drinking Water.—Because fracking is exempt from many environmental monitoring requirements, there are inadequate data on the impact of natural gas production on water contamination. However, data from private wells and 

a published investigation raise concerns that water contamination from fracking is 

creating health risks. Potential contaminants include methane, organic chemicals 

(including benzene, a known carcinogen), metals and radioactive elements. 

A published study from Pennsylvania documented evidence of drinking water contamination with methane associated with shale gas extraction. These researchers 

found increased levels of methane in wells closer to well sites including levels that 

present an explosion hazard for residents.16 Other household-level investigations 

conducted by state and federal agencies have also found methane levels in drinking 

water in homes near drill sites that were caused or are suspected to have been 

caused by oil and gas operations and present an explosion hazard as well as an asphyxiation hazard for residents.17

One study reported severe impacts to livestock, including reproductive abnormalities, acute kidney or liver failure and death, in animals that drank from polluted 

ponds and creeks near fracking operations.18

The same study also documented a family living near a fracking site that reported 

symptoms such as headaches, nosebleeds, and skin rashes; the symptoms subsided 

when the family was relocated, suggesting a causal link with the nearby fracking 

operations. 

35 

19McKenzie Witter RZ, Newman LS, Adgate JL. 2012. Human Health Risk Assessment of air 

Emissions from Development of Unconventional Natural Gas Resources. Sci Total Environ. 2012 

May 1;424:79-87. 20 Esswein E et al 2012. NIOSH Field Effort to Assess Chemical Exposures in Oil and Gas 

Workers: Health Hazards in Hydraulic Fracturing. Presentation made at IOM Roundtable: The 

Health Impact Assessment of New Energy Sources: Shale Gas Extraction. April 30-May 1, 2012 21Petron G, Frost G Miller BR, Hirsch AI, Montzka SA, Karion A., Trainer M, Sweeney C, 

Andrews AE, Miller L, Kofler J, Bar-Iian A, Dlugokencky EJ, Patrick L, Moore CF, Ryerson TB, 

Siso C, Kolodzey, W, Lang PM, Conway, T, Novelli P, Masarie K, Hall B, Guenther D, Kitzis, 

D, Miller J, Welsh, D, Wolfe D, Neff W, Tans P. 2012. Hydrocarbon emissions characterization 

in the Colorado Front Range: A pilot study. Journal of Geophysical Research, VOL. 117. 22Gilman JB, Lerner BM, Kister WC, de Gouw J, 2013. Source signature of volatile organic 

compounds (VOCs) from oil and natural gas operations in northeastern Colorado. Environ Sci 

Technology DOI: 10. 1021/es304119a 23Litovitz A, Curtright A, Abramzon S, Burger N. Samaras C. 2013. Estimation of regional 

air-quality damages from Marcellus Shale natural gas extraction in Pennsylvania. Environ. Res. 

Lett. 8. 24Olaguer E 2012. The potential near-source ozone impacts of upstream oil and gas industry 

emissions. Journal of Air and Waste Management. 62:8, 966–977 25McKenzie Witter RZ, Newman LS, Adgate LS, Adgate JL. 2012. Human Health Risk Assessment of air Emissions from Development of Unconventional Natural Gas Resources. Sci 

Total Environ. 2012 May 1;424:79–87. 

Studies linking specific health impacts to drinking water contamination resulting 

from fracking operations have not yet been conducted, which illustrates the results 

of under-regulating this industry, but the evidence suggests that current practices 

may be exposing families to unsafe levels of contaminants. 

Air Emissions. Fracking operations release air pollutants that can have health 

consequences at the local and regional level. As with water, researchers are hampered because fracking operations have been exempted from many monitoring requirements. But some of the health complaints reported by people living near 

fracking sites, particularly respiratory and neurological symptoms, are consistent 

with exposure to the chemical contaminants identified in some monitoring reports./ 

19/ All of this underscores the urgent need to require effective pollution control 

equipment and community-level air quality monitoring to better assess the exposures and potential health risks. In the meantime, there is a strong rationale for 

reducing this contamination immediately to prevent potentially harmful exposures. 

The research, monitoring data, and public health expertise available to date indicate that natural gas facilities produce air pollution that can increase health risks. 

These risks increase with proximity, particularly for populations more vulnerable to 

the impacts of air pollution, which include children, elderly, and those with underlying health problems. 

Fracking activities expose communities to a range of harmful air pollutants, including known carcinogens, and respiratory, neurological, immunological and reproductive toxins. These pollutants are present in the diesel emissions released by 

truck traffic and heavy equipment use. Additionally, fracking operations can expose 

communities to silica dust, which causes lung disease. Workplace investigations at 

fracking sites have identified both silica and diesel as posing a health hazard for 

workers exposed on the job site.20 Since state laws allow drilling as close as 100 

feet to residences, sensitive populations, such as children, may also be threatened 

by this pollution. 

VOCs released from natural gas wells and processing facilities have been shown 

to play a significant role in increasing unhealthy air quality, including from groundlevel ozone. In the past year, four published studies have identified pollution from 

oil and gas facilities, where fracking is being deployed, as a source of pollutants contributing to regional ozone in Colorado, Texas, and Pennsylvania.21 22 23 24 Groundlevel ozone is a powerful respiratory toxicant that is well known to aggravate asthma and other respiratory conditions. 

Additionally, a study in Colorado found elevated levels of air pollutants close to 

well sites during well production. Taken together, these pollutants were found to be 

high enough to put nearby residents at risk for respiratory and neurological health 

impacts.25

In addition, proximity to these facilities can also subject individuals to light and 

noise pollution, wastewater spills, noxious odors, and increased health and safety 

risks from explosions and other malfunctions. For this reason, as noted above, separating vulnerable populations from sources of air pollution and other hazards, 

should be an integral part of ensuring health and safety. 

All of these indications of health risks are cause for concern, underscoring the 

need to better protect the public. That means requiring mandatory disclosure of all 

chemicals used in fracking, thorough evaluations of potential health threats, the 

36 

26 U.S. Environmental Protection Agency, Clean Energy-Air emissions, available at http:// 

www.epa.gov/cleanenergy/energy-and-you/affect/air-emissions.html. 27 NRDC, Leaking Profits: The U.S. Oil and Gas Industry Can Reduce Pollution, Conserve Resources, and Make Money by Preventing Methane Waste (Mar. 2012), available at http:// 

www.nrdc.org/energy/leaking-profits.asp. 28 EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2010, Table ES-2, http:/ 

www.epa.gov/climatechange/Downloads/ghgemissions/US-GHG-Inventory-2012-Main-Text.pdf, 29 EPA, Greenhouse Gas Reporting Program, 2011 Data, http://epa.gov.ghgreporting/ghgdata/ 

reported/index.html 30 U.S. Energy Information Administration, Natural Gas Gross Withdrawals and Production, 

2010 data. available at http://www.eia.gov/dnav/ng/nglprodlsumldculNUSla.htm; U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks (1990- 

2009) (Apr. 15, 2012). Net emissions of methane are just over 600 bcf (billions of standard cubic 

feet), while gross withdrawals were approximately 26,800 bcf; this implies a net leakage of approximately 2.3 percent. 31 Robert Howarth et al., ‘‘Methane Emissions from Natural Gas Systems,’’ Background Paper 

Prepared for the National Climate Assessment (reference number 2011-0003) (Feb. 25, 2012), 

available at http://www.eeb.cornell.edu/howarth/Howarth%20et%20al.%20-- 

%20National%20Climate%20Assessment.pdf. 32 NRDC, Leaking Profits: The U.S. Oil and Gas Industry Can Reduce Pollution, Conserve Resources, and Make Money by Preventing Methane Waste (Mar. 2012), available at http:// 

www.nrdc.org/energy/leaking-profits.asp. 33 U.S. Environmental Protection Agency, Federal Register Vol. 77, No. 159, Oil and Natural 

Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews (Aug. 16, 2012), available at https://www.federalregister.gov/articles/2012/08/16/2012-16806/oil-and-natural-gas-sector-new-source-performance-standards-and-national-emission-standards-for. 34 Hydraulic Fracturing Can Potentially Contaminate Drinking Water sources, NRDC, http:// 

www.nrdc.org/water/files/fracking-drinking-water-fs.pdf. 

best possible pollution controls and drilling and fracking standards, and increased 

air and water monitoring both before and after drilling and fracking begin. 

C. Climate Change Impacts 

When natural gas is burned at a power plant to generate electricity, it emits far 

less carbon pollution than coal-based electricity.26 But the production of natural gas 

produces significant methane emissions27 Methane, which makes up as much as 90 

percent of natural gas, is a potent global warming pollutant, trapping at least 25 

times more solar radiation than carbon dioxide over a 100-year period. According 

to both the EPA’s national inventory of greenhouse gas emissions and the EPA’s 

tabulation of individual companies’ emission data reports,28 the oil and gas industry 

is the nation’s second largest industrial emitter of greenhouse gases (mainly methane and carbon dioxide), surpassed only by electric power plants.29

Currently, methane leaks into the atmosphere at many points in the natural gas 

production and distribution process—from wells during extraction, from processing 

equipment while compressing or drying gas, and from poorly sealed equipment 

while transporting and storing it. While much better data are needed, EPA estimates that at least 2 to 3 percent of all natural gas produced by the U.S. oil and 

gas industry is lost to leaks or vented into the atmosphere each year30, and some 

recent studies suggest that the actual leak rate could be much higher.31 Preventing 

the leakage and venting of methane from natural gas facilities would reduce pollution, enhance air quality, improve human health, and conserve energy resources. 

The oil and gas industry can afford methane control technologies. Indeed, cap- turing currently wasted methane for sale could bring in more than $2 billion of additional revenue each year. Ten technically proven, commercially available, and 

profitable methane emission control technologies together can capture up to 80 percent of the methane currently going to waste.32 EPA, other federal agencies, and 

the states should move to require use of these technologies for methane control, and 

industry itself should move quickly to adopt these measures. 

Last year, EPA issued a Clean Air Act rule to curb VOC emissions from new and 

modified sources in the oil and gas industry.33 While this is a step forward, the rule 

is not strong enough and doesn’t cover existing sources. EPA should also regulate 

methane directly, which would achieve much larger emission reductions. 

D. Water Pollution 

In addition to the risk of contaminating drinking water, shale gas extraction can 

pollute streams, rivers, lakes and other waterbodies.34 This can happen in a number 

of ways, including the following: 

1. Depletion of Water Resources.—Large volumes of water are required for 

fracking operations. Fresh water is often taken from local waterbodies. Because 

water can be contaminated when it has been used for fracking, it cannot be easVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00040 Fmt 6633 Sfmt 6621 G:\DOCS\80132.TXT 80132
37 

35Soeder, D.J., and Kappel, W.M., 2009, Water Resources and Natural Gas Production fromt 

he Marcellus Shale: U.S. Geological Survey Fact Sheet 2009-3032, 6 p., available at: http:// 

pubs.usgs.gov/fs/2009/3032/. 36See, e.g., DEP Investigating Lycoming County Fracking Fluid Spill at XTO Energy 

Marcellus Well, http://www.portal.state.pa.us/portal/server.pt/community/newsroom/ 

14287?id=15315&typeid=1. 37 U.S. Government Accountability Office, Energy-Water Nexus: Information on the Quantity, 

Quality, and Management of Water Produced during Oil and Gas Production, GAO-12-156 

(Washington, D.C.: Jan 9, 2012). 38Otton, J.K., 2006, Environmental aspects of produced-water salt releases in onshore and estuarine petroleum-producing areas of the United States: a bibliography: U.S. Geological Survey 

Open-File report 2006-1154, 223p. 39 NRDC, ‘‘Petition for Rulemaking Pursuant to Section 6974(a) of the Resource Conservation 

and Recovery Act Concerning the Regulation of Wastes Associated with the Exploration, Development, or Production of Crude Oil or Natural Gas or Geothermal Energy,’’ September 8, 2010, 

18–23. 40See, e.g., DEP Fines Atlas Resources for Drilling Wastewater Spill in Washington County, 

http://www.portal.state.pa.us/portal/server.pt/community/newsroom/14287?id=13595&typeid=1 41Ohio EPA investigating dumping of drilling waste water in Youngstown area, Feb. 4, 2013, 

Bob Downing, Beacon Journal, http://www.ohio.com/news/ohio-epa-investigating-dumping-ofdrilling-waste-water-in-youngstown-area-1.370584 42http://www.denverpost.com/breakingnews/cil18880544 

ily be returned to these waterbodies. Permanent loss of water from fresh water 

resources can harm water quality and availability and also aquatic species and 

habitat.35

2. Spills and Leaks of Fracking Chemicals and Fluids.—Fluids, including hazardous chemicals and proppants used in the fracking process, are typically 

stored in tanks or pits on site. If not stored properly, they can leak or spill, polluting nearby waterbodies. Fluids can also be stored at a centralized facility 

near multiple wellpads and then be transported to the well by trucks or by pipeline, providing another opportunity for leaks and spills during transit. Fracking 

fluid can also spill during the fracking process. Leaks from tanks, valves, and 

pipes, as a result of mechanical failure or operator error at any point during 

these processes, can and do contaminate groundwater and surface water.36

3. Mismanagement of fracking waste.—After fracking, some of the fracking 

fluid, often referred to as flowback, returns up the wellbore to the surface. In 

addition, naturally occurring fluid is brought to the surface along with the produced oil or gas (referred to as ‘‘produced water’’). This waste, consisting of both 

flowback and produced water, can be toxic, and the oil and gas industry generates hundreds of billions of gallons of it each year.37 In addition to the chemicals that were initially injected, flowback and produced water may also contain 

hydrocarbons, heavy metals, salts,38 and naturally occurring radioactive material. The wastewater is sometimes stored in surface pits. If the pits are inadequately regulated39 or constructed, they run the risk of leaking or overflowing 

and can pollute groundwater and surface water.40 The waste may also be disposed of on the surface, reused in another well, re-injected underground, or 

transported to a treatment facility. Each of these forms of wastewater management carries its own inherent risks, including spills, leaks, earthquakes (in the 

case of underground injection) and threats to groundwater and surface water. 

4. Stormwater Pollution.—During a rainstorm or snowstorm, flowing water 

causes soil erosion and picks up pollutants along the way, including toxic materials and sediment, and these materials can flow into local waterbodies. 

Stormwater from fracking operations can be particularly polluted because of 

chemical and oil and gas residues. (Yet, as is described below, the oil and gas 

industry is exempt from the stormwater permitting requirements of the Clean 

Water Act). 

I must stress that there are numerous examples of these types of water pollution 

impacts occurring. I mentioned that just last week Ohio regulators observed 20,000 

gallons of fracking waste being illegally dumped into a waterway.41 And a September 2011 Denver Post investigation found that four oil and natural gas companies were responsible for 350 spills in Colorado since January, 2010. The Post reported that one of these companies was responsible for three spills in one month 

alone, including benzene, a known carcinogen, and had contaminated both local 

lands and water.42 Ironically, state regulators had lauded these four companies as 

‘‘outstanding operators.’’ Overall, the investigation found that spills took place in 

Colorado at the rate of seven per week and that from January to September 2011, 

more than two million gallons of diesel, oil, drilling wastewater and chemicals were 

spilled, and state regulators issued few fines. A 2012 Post investigation found that 

over a five year period, oil and gas operations were responsible for 2,078 spills and 

38 

43http://www.denverpost.com/environment/cil22154751/drilling-spills-reaching-coloradogroundwater-state-mulls-test 44 Energy Development and Impacts on Wildlife (Sept. 11, 2012), Center for Western Priorities; http://westernpriorities.org/2012/09/11/energy-development-and-impacts-on-wildlife/. 45MISSING 46Whitter R. 2012. Community Impacts of Natural Gas Development and Human Health. 

Presentation made at IOM Roundtable: The Health Impact Assessment of New Energy Sources: 

Shale Gas Extraction. April 30-May 1, 2012 47http://switchboard.nrdc.org/blogs/ksinding/nrdcllauncheslcommunitylfracki.html 48 Energy Policy Act of 2005, Pub. L. No. 109-58, § 322, 42 U.S.C. § 300h(d)(1)(B)(ii). This provision bypassed a court decision that had previously ordered the EPA to regulate hydraulic fracturing under the SDWA. Legal Environmental Assistance Foundation v. United States Environmental Protection Agency, 118 F.3d 1467 (11th Cir. 1997). 

slow releases and that 17 percent of these spills had reached groundwater. In one 

county alone, Weld County, 40 percent of spills reached groundwater.43

E. Impacts on Wildlife Habitat and Sensitive Lands 

Oil and gas development can destroy wildlife habitat and sensitive lands if siting 

does not take these factors into account. Natural gas production operations involve 

extensive road building and construction of wellpads that can fragment and destroy 

habitat and cause species to leave their historic breeding and nesting grounds. Light 

and noise disturb wildlife populations and may drive them to lower quality habitat, 

and runoff and spills can pollute aquatic habitat.44

F. Community Impacts 

Oil and gas development can fundamentally change the nature of communities. 

Fracking is a heavy industrial activity that entails substantial construction, heavy 

truck traffic, traffic accidents, and noise and light pollution45. It often attracts an 

influx of out-of-state workers that can bring increases in crime and violence, sexually transmitted diseases and community strife that can stress local emergency, 

health and other community resources.46

Under many state laws, oil and gas rights take precedence—or are interpreted as 

taking precedence—over surface ownership, so oil and gas wells and the associated 

industrial activity-including chemical and waste storage and disposal-can be located 

in residential or agricultural areas regardless of zoning or even the wishes of individual property owners. To address these issues, NRDC has launched a Community 

Defense initiative to provide legal assistance to localities that seek to hold natural 

gas extraction to appropriate scientific standards, protect their property or exclude 

oil and gas production from their communities.47

III. CONGRESS SHOULD CLOSE FEDERAL LOOPHOLES FOR OIL AND GAS PRODUCTION

The oil and gas industry has succeeded over many years in getting statutory exemptions from standard environmental protection laws and practices. These unjustifiable loopholes appear in the Clean Air Act, Clean Water Act, the Superfund statute, the Resource Conservation and Recovery Act, and the Safe Drinking Water Act, 

among others. 

There is simply no justification for exempting fracking from the basic environmental laws that have applied to other industrial activities for four decades. 

Fracking presents at least as many risks as other regulated activities and has just 

as many interstate implications. Moreover, the current level of disclosure and regulation clearly demonstrates that states lack the technical expertise and political 

wherewithal to govern fracking. Congress must close the loopholes in cornerstone 

federal environmental laws. 

This is not to say that states have no role to play. Under our system of ‘‘cooperative federalism,’’ states can play the lead role in the regulation, permitting, and 

oversight process. They can try out and adopt different regulatory approaches, as 

long as they meet federal minimum requirements. But all citizens deserve the protection of federal standards. 

Some of the key exemptions for oil and gas production facilities in bedrock U.S. 

environmental laws are: 

SAFE DRINKING WATER ACT (SDWA)

Fracking is exempted from the SDWA unless diesel is used in the fracking process, under a provision enacted in the Energy Policy Act of 2005.48 This exemption 

prevents the Safe Drinking Water Act from protecting underground sources of 

drinking water from fracking impacts and exempts the siting, construction, operVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00042 Fmt 6633 Sfmt 6621 G:\DOCS\80132.TXT 80132
39 

49 33 U.S.C. § 1342(l)(2); 33 U.S.C. § 1362(24). 50 42 U.S.C. § 7412(a)(1)-(2); 42 U.S.C. § 7412(n)(4). 51 42 U.S.C. § 6921(b)(2). Under this provision, EPA may act to close this gap under specified 

circumstances, but has not done so. 52 42 U.S.C. § 9601(14). 53 42 U.S.C. § 15942. 54 U.S. Gov’t Accountability Office, GAO-11-941T, Energy Policy Act of 2005: BLM’s Use of 

Section 390 Categorical Exclusions for Oil and Gas Development (2011). 55 Revised Interior rule loops in industry-favored FracFocus, EnergyWire, Feb. 8, 2013, Mike 

Soraghan and Ellen M. Gilmer, http://www.eenews.net/energywire/2013/02/08/1 

ation, maintenance, monitoring, testing, and closing of fracking sites from regulation 

under the SDWA. 

CLEAN WATER ACT

Oil and gas operations are exempt from the stormwater runoff permitting requirements of the Clean Water Act.49 With this exemption, there is no way to know if 

a company has an adequate Storm Water Pollution Prevention Plan in place to reduce the discharge of pollutants to receiving waters, and to eliminate illegal discharges. 

CLEAN AIR ACT

The oil and gas exploration and production industry is exempt from critical Clean 

Air Act requirements to adequately assess, monitor, and control hazardous air pollutants.50 This makes it impossible, under existing regulatory statutes, to perform 

an adequate assessment of air pollution health risks to nearby communities and require adequate safeguards. Excluding this important category of air pollution and 

air contaminants significantly underestimates the health risks posed by this industry. 

HAZARDOUS WASTE MANAGEMENT AND SUPERFUND STATUTES

Oil and gas waste is exempt from the central federal hazardous waste management law—the Resource Conservation and Recovery Act—including testing, treatment and disposal provisions that govern the assessment, control and clean-up of 

hazardous waste.51 Similarly, the oil and gas industry is protected from liability for 

spills under the Comprehensive Environmental Response, Compensation and Liability Act (the Superfund statute), which adopts the same definition of hazardous 

waste.52

NATIONAL ENVIRONMENTAL POLICY ACT (NEPA)

Under a special provision of NEPA, when oil and gas companies lease federal 

lands, they are often exempt from customary environmental review requirements 

applicable to other industries.53 A recent Government Accountability Office study 

found that in a sample from fiscal years 2006-2008, the oil and gas industry received almost 6,900 categorical exclusions (CXs) that waived further environmental 

review under NEPA. Of that total, almost 6,100 of those CXs were used to waive 

requirements for permits to drill.54

IV. BLM’S POTENTIAL ROLE IN PROVIDING NATIONAL LEADERSHIP ON BEST PRACTICES

FOR NATURAL GAS PRODUCTION

Given this Committee’s jurisdiction, I want to stress an important opportunity for 

the Bureau of Land Management (BLM) to show leadership on this issue. The BLM 

oversees approximately 700 million subsurface acres of Federal mineral estate and 

56 million subsurface acres of Indian mineral estate across forty states. As of 2011, 

38.5 million acres of oil and gas resources were leased by the federal government. 

These lands include private property in a split estate situation, or national forests 

that are watersheds for large populations. A March 2012 Department of Interior report found that 56 percent of federal onshore leases were neither in exploration nor 

production-an area about the size of South Carolina. This is the time to minimize 

the impacts that will come with future fracking. As Chairman Wyden noted in his 

recent letter to BLM, new BLM rules must require best practices for fracking and 

protect environmentand health . But the latest indications are that BLM is going 

in exactly the wrong direction. 

A version of the draft rule leaked to the press last week indicates that BLM is 

in the process of weakening disclosure requirements and environmental protections 

in its proposed rule.55

40 

56http://docs.nrdc.org/energy/files/enel12091101a.pdf 57Daniel A. Lashof ET AL., Closing the Power Plant Carbon Pollution Loophole: Smart Ways 

the Clean Air Act Can Clean Up America’s Biggest Climate Polluters, NRDC (Dec. 2012), http:// 

www.nrdc.org/air/pollution-standards/files/pollution-standards-report.pdf. 58Doubling U.S. Energy Productivity by 2030, ALLIANCE COMMISSION ON NATIONAL 

ENERGY EFFICIENCY POLICY (Feb. 7, 2013), http://ase.org/sites/default/files/ 

fulllcommissionlreport.pdf. 

The BLM rule should 

• provide adequate and comprehensive disclosure of chemical and other information to the public; • place sensitive areas off limits; • require safe setbacks for homes, schools, and streams; • establishe strong standards for well construction that ensure mechanical integrity; • require baseline testing of water sources; and • increase the safety of toxic waste management by prohibiting open air pits. 

Details on NRDC’s proposals are available in our comments to the BLM.56

V. CLIMATE CHANGE AND ENERGY POLICY

Federal law and policy must also take into account the need to move the U.S. 

away from the use of fossil fuels, including natural gas. The United States’ largest 

source of climate-changing pollution remains the air emissions from hundreds of existing power plants. We must curb this dangerous source of pollution and do so in 

a way that will build the economy and promote energy efficiency and renewable energy. NRDC has crafted a groundbreaking proposal57 that will help the United 

States create jobs, grow the economy, and curb climate change by reducing emissions from hundreds of existing power plants. NRDC’s proposal shows how EPA, in 

partnership with the states, can set new carbon pollution standards under existing 

authority in the Clean Air Act that will cut existing power plant emissions 26 percent by 2020 (relative to peak emissions in 2005). 

The approach includes an innovative provision that will provide states with flexibility and drive investment in cost-effective electric energy efficiency, substantially 

lowering the cost of compliance, lowering electricity bills, and creating thousands of 

jobs across the country. The benefits of this approach—in saved lives, reduced illnesses, and climate change-exceed the costs by as much as 15-to-one. The Administration should move quickly to finalize the carbon standards they have proposed for 

new power plants and propose a system of regulation for existing plants, building 

on the ideas we have proposed. 

After electric generation, other primary uses of natural gas energy are in buildings and industrial applications. There are many opportunities to use natural gas 

more efficiently in these settings. Enhanced building energy codes and stronger efficiency standards for appliances, equipment and cooling and heating systems are 

among the best ways to use natural gas more efficiently. As is explained in a recent 

report by the Alliance to Save Energy’s Commission on National Energy Efficiency 

Policy (on which I served), it is important that DOE stay on track to meet all of 

its statutory deadlines and responsibilities to strengthen energy efficiency standards 

for natural gas and electric appliances.58 After a strong start at the beginning of 

the last term, DOE has fallen behind on this important responsibility. 

VI. NEXT STEPS: BUILDING THE OVERDUE REGULATORY FRAMEWORK FOR ADDRESSING

THE IMPACTS OF FRACKING

I’ve discussed above the need for Congress to take strong action to protect the environment and health, including by requiring full disclosure of fracking chemicals 

and closing loopholes in existing environmental statutes. And I’ve reviewed the need 

for BLM to issue rules properly governing fracking on public lands. Other significant actions that the federal government should take to limit the damaging impacts 

of fracking include: 

Congress 

• Congress should mandate and fund comprehensive studies on the environmental and health impacts of fracking and on how to address them. EPA is conducting a comprehensive scientific study into the risks of fracking on drinking 

water, due in 2014. This will be the first independent study of its kind. The 

Agency for Toxic Substances and Disease Registry , the National Institute of 

Environmental Health Sciences and the National Institute for Occupational 

Safety and Health should conduct worker and community health investigations. 

41 

• Congress should ensure that both the BLM and EPA have sufficient funding to 

inspect natural gas production facilities and to enforce compliance. These agencies must be able to vigorously investigate complaints. 

• Congress and the Administration should take action to implement the recommendations of the 2011 Shale Gas Subcommittee of the Secretary of Energy 

Advisory Board. 

Bureau of Land Management 

BLM should 

• Revise all of its rules for natural gas production including leasing and management plans to reflect current technologies and the extent of development so it 

protects the resources that are used by Americans for hunting, fishing, hiking, 

and other activities. The BLM is too often allowing oil and gas development 

without conducting the proper environmental analysis or considering the impacts on human health, the environment, wildlife, and vital natural resources. 

• Together with other federal land management agencies, protect the most sensitive public lands, placing them off limits to oil and gas development. This includes important drinking water sources and wilderness quality lands. For example, the George Washington National Forest in Virginia is home to the headwaters of the Potomac and James Rivers which supplies water for approximately four million people, including all of Washington, D.C. and Maryland and 

Virginia suburbs, yet the Forest Service is considering allowing fracking there. 

EPA 

EPA should use its existing authority to the fullest extent possible to address the 

impacts and risks of fracking, including taking the following actions 

• Issue stringent standards to limit methane, carbon dioxide, and hazardous 

emissions from natural gas production from both from new and existing sources. 

Cost-effective technology exists to do so, as noted above. In addition, EPA must 

adopt standards for VOCs and methane from fracked oil wells, which can emit 

huge amounts of this ozone-forming pollutant. 

• Ban the use of diesel in fracking fluid to protect drinking water and 

waterbodies. 

• Issue strong Clean Water Act rules for the discharge of wastewater generated 

by natural gas fracking and production. 

• To the extent possible under existing law, conduct a thorough assessment of air 

toxic emissions, health threats, and available pollution control technology that 

includes all relevant sources of emissions of all contaminants. Based on this assessment, EPA should set strong standards to limit pollution that threatens 

nearby populations from new and existing facilities. 

• Make resources available to state and local clean water agencies as needed for 

the monitoring of groundwater, investigation of drinking water contamination 

and remediation. 

VII. CONCLUSION

This testimony has focused on the scientific and legal issues posed by the expansion of fracking, but in closing I want to bring us back to the experiences and fears 

of real people to underscore what is at stake. On a recent trip to western Pennsylvania, I spoke to many families affected by shale gas production. These families told 

me that they fear that their water is contaminated with toxic substances from shale 

gas operations. They worry the air pollution coming from compressor stations or 

well pads is harming their families. And they believe their property values have 

been compromised. I witnessed two instances of flammable water, one in a field, another in a jug of drinking water. I don’t know what caused them, and sadly the state 

doesn’t seem to have investigated to determine the causes, but I could see how disturbing it was for homeowners to have flaming water. Every single person we spoke 

with had stories of contaminated water or air. 

I sensed a lot of fear in the communities I visited in Pennsylvania. It reminded 

me of when I served on the National Commission on the BP Deepwater Horizon Oil 

Spill and Offshore Drilling and people in Louisiana and Mississippi told me how 

scared they were for the health of their families. They knew they had been exposed 

to oil and to chemicals used in the dispersants, but they didn’t know if that exposure would be harmful or how to keep their families safe. 

I know that we can do better for these families and communities, and hope that 

today’s hearing will provide the basis for positive change 

As I’ve indicated, a lot of action is needed, and it is needed now. The federal government has been asleep at the switch—although it may be more accurate to say 

42 

it’s been anesthetized, given all the exemptions that have been worked into statute. 

NRDC stands ready to assist this Committee in its further deliberations. Thank you 

again for the opportunity to participate in this discussion. 

The CHAIRMAN. Thank you very much Ms. Beinecke. 

I think you’ll find a lot of bipartisan interest on those efficiency 

issues that you made a point of at the end, and we thank you. 

Ms. BEINECKE. Thank you. 

The CHAIRMAN. Dr. Medlock, welcome. 

STATEMENT OF KENNETH B. MEDLOCK, III, JAMES A BAKER, 

III AND SUSAN G. BAKER, FELLOW IN ENERGY AND RESOURCE ECONOMICS, AND SENIOR DIRECTOR, CENTER FOR 

ENERGY STUDIES, JAMES A. BAKER III, INSTITUTE FOR PUBLIC POLICY, RICE UNIVERSITY, HOUSTON, TX 

Mr. MEDLOCK. Thank you for the opportunity to be here. 

I want to begin by just commenting on the State of the regulatory infrastructure that we have in our natural gas industry in 

this country and more broadly, North America. You know, beginning with the Natural Gas Act in the 197—in the late 1970s followed by several FERC orders that were passed up through the 

1990s, we’ve basically seen establishment of a market which arguably is the most efficient market in the world. Basically the reason 

we can say that is because any consumer that needs or has a desire 

to get natural gas in any given point in time, any producer that 

has a desire to actually access a market, the ability is there. 

This is largely the result of the regulatory infrastructure that 

has been put in place. It encourages competition, it encourages entrepreneurship, and it’s basically been the reason why in this country we’ve seen, as it’s been called already in this hearing, the Shale 

Gale emerge in this country. 

So anything that sort of could stand to disrupt this very well 

functioning market, I think would be a detriment to the country 

and to the natural gas industry. 

It was also referenced that, you know, in terms of the number 

of licenses that have been applied for, we’re talking in excess of 30 

billion cubic feet a day at this point, so it’s quite a large number. 

But one thing you have to do is take a step back and realize the 

context in which that volume, that potential volume sets. Namely, 

the global liquefied natural gas market today is just over 30 billion 

cubic feet a day. There is no way that if all of those licenses were 

approved you’d see 30 BCF a day of capacity constructed in this 

country. You’re basically talking about doubling the size of the 

LNG market. So you have to understand and you have to take in 

to the proper context, you know the kind of competition that you’re 

seeing. 

It’s a race to win first move or advantage. It’s exactly what you’d 

expect to see in a competitive market. 

Now when we sort of step sort of beyond what’s happened with 

regard to natural gas and shale gas development in this country, 

we can think about national security issues, which have been also 

referenced and as a matter of fact, we performed a study for the 

International—the Office of International Policy and Affairs of the 

DOE a little over—about 2 years ago now where we looked at the 

broader geopolitical implications of shale, and this is a mouthful, 

43 

and I’m happy to expand in Q&A, but there were 3 countries in 

particular that were most affected by the emergence of shale in 

North America. When you think again about foreign policy objectives of this country, not only in the short-term, but even in the 

immediate-to long-term, this is a mouthful: Russia, Iran, and Venezuela. Those are the 3 countries that most—that were most heavily impacted by shale developments in this country. You take shale 

out of the mix, and those 3 countries really stand to benefit in a 

very dramatic way because of their massive natural gas resources 

and hydrocarbon resources more generally. 

Moving beyond that, when we think about a lot of the things that 

a lot of people have been talking about with regard to gas and to 

transportation, there’s a real potential here for natural gas to displace some oil in our transportation infrastructure, and I think 

that’s a really very important point when we think about national 

security. 

However, there still exists challenges. Moving gas into high use 

vehicles, into fleet systems, this is something that already stands 

to benefit a lot of companies that already own and operate these 

kinds of fleets, like FedEx, UPS. You’re even talking about now 

LNG in long haul trucking. So these sorts of applications are already beginning to occur, not because of policy, but because the 

commercial incentive is there. It’s there right now. So you’re starting to see that migration occur. 

Moving into the cars that you and I drive, that’s going to be a 

little bit more challenging because you’re not talking about vehicles 

that are driven in excess of 20,000 miles a year. You’re talking 

about vehicles that are driven 12 to 13,000 miles a year and that 

matters a tremendous amount when you talk about fuel choice and 

the kinds of capital costs individuals are willing to incur when they 

buy new vehicles. 

On the emissions front, there are studies ongoing with regard to 

natural gas throughout the value chain and what methane leakage 

might mean for the real potential that might be there associated 

with natural gas developments and one of the things that one of 

the studies that’s ongoing—I’m actually very much looking forward 

to seeing the results of is one that’s being conducted by the Environmental Defense Fund. They’re looking at—they’re measuring 

methane leakage not only at the well head, but all the way down 

to the end use. One of the things that I fully expect to see as the 

result of that study, because it’s something that I’ve actually looked 

at a little bit in my past is that what you’ll see is the most egregious source of methane leakage is what we call in locations in the 

market in where we call behind-the-fence. So this is after local distribution companies take charge of the gas and that opens up a tremendous amount of discussion around the appropriate policies for 

how maintenance is performed on systems, not just interstate systems, not just gathering systems, but even behind-the-fence systems, so local distribution companies. 

Finally, on the environmental front, when we talk about the potential for natural gas to reduce or achieve certain climate change 

objectives—emissions objectives. I think we’ve already seen to some 

extent just in 2012 their preliminary data what can actually happen if gas can displace older coal facilities from the generation 

44 

1The techniques have also matriculated into the oil sector triggering an upstream renaissance 

in US oil production driven by light tight oil, or shale oil. In fact, domestic oil production has 

increased year-on-year since 2008, something that has not occurred since the 1960s 

stack and we’re talking about our generation in particular. What 

we actually saw was that in 2012, because of the low price of natural gas, natural gas actually rose to surpass coal share in generation for some period of the year. What that basically resulted in 

was CO2 emissions being as low in this country as they have been 

since 1990. That’s pretty remarkable. What that tells you is that 

natural gas stands to benefit not only domestic manufacturing, not 

only domestic producers to the extent that LNG exports actually do 

occur under a market equilibrium, and I think that’s an important 

point, but it also stands to benefit various environmental objectives. 

Again, if we’re going to think about appropriate policies, I think 

the first thing we need to do is gather more information. Which is 

why I applaud hearings like this and the kinds of things that we’re 

seeing going not only academic, but in the industrial communities, 

as well. 

Thank you. 

[The prepared statement of Mr. Medlock follows:] 

PREPARED STATEMENT OF KENNETH B. MEDLOCK, III, JAMES A. BAKER, III, AND

SUSAN G. BAKER, FELLOW IN ENERGY AND RESOURCE ECONOMICS, AND SENIOR DI- RECTOR, CENTER FOR ENERGY STUDIES, JAMES A. BAKER III INSTITUTE FOR PUBLIC

POLICY RICE UNIVERSITY, HOUSTON, TX 

During the past decade, innovative new techniques involving horizontal drilling 

and hydraulic fracturing have unlocked a vast resource potential and resulted in the 

rapid growth in production of natural gas from shale. According to the US Energy 

Information Administration, gross withdrawals from shale gas wells in the United 

States has increased from virtually nothing in 2000 to over 23 billion cubic feet per 

day (bcfd) in 2011, representing over 29 percent of total gross production in the US. 

Moreover, a recent Baker Institute analysis indicates shale gas production could 

reach over 50 percent of all domestic natural gas production by the 2030s.1

Without doubt, the natural gas supply picture in North America has changed substantially, and it has had a ripple effect around the globe, not only through displacement of supplies in global trade, but also by fostering interest in shale potential in 

other parts of the world. Prior to the innovations leading to the recent increases in 

shale gas production, declining domestic production in the United States and Canada was the consensus view, and was a harbinger of increasing reliance in North 

America on foreign supplies. This resulted in an expectation that prices would rise, 

and that the US would become a major global sink for global supplies. While many 

producers around the world began to invest in capabilities to move liquefied natural 

gas to the US, the late 1990s and early 2000s also witnessed a decline in industrial 

demand for natural gas as gas-intensive manufacturing activities migrated away. 

Thus, the North American gas market was undergoing a shift in preparation for increasing import reliance, higher prices, and reduced domestic demand for industrial 

activities. Even in the power sector, higher prices set the stage for more robust 

growth in renewable energy sources. But, the rapid growth in shale gas production 

has since turned all of these expectations upside down. In fact, there is a valuable 

lesson in what has transpired. Market stresses encourage responses on multiple 

margins, and there is nothing different about what is going on currently. 

To wit, the past few years of rising shale gas production has contributed to lower 

domestic natural gas prices. This, in turn, has encouraged the substitution of natural gas for coal in power generation, and a revitalization of gas-intensive industrial 

demands. There has also been interest in creating new demands, such as the use 

of natural gas in transportation, particularly as the price of crude oil remains well 

above the price of natural gas on an energy equivalent basis. Finally, there has been 

growing interest in developing LNG export capability to capture the arbitrage opportunity that currently exists with domestic natural gas prices substantially below 

prices in Europe and Asia. 

45 

2 Indeed, the US supply elasticity with shale included in the resource base is roughly 5 times 

larger than when it is not included, see Medlock, Kenneth B., ‘‘US LNG Exports: Truth and 

Consequences’’, available at www.bakerinstitute.org (2012). Put another way, the domestic supply curve is very flat. 3Data sourced from IEA Energy Statistics and Balances. Ethanol comprises another 4% with 

natural gas making up the remainder. Note, if pipeline uses are excluded, these values shift 

even more heavily towards oil. 4We could also discuss liquefied natural gas (LNG) options into transportation, but this is primarily for large trucks and local maritime transport. The arguments presented herein still generally apply. 

This paper discusses the feasibility of the pathways for natural gas that have 

emerged in the wake of the shale gas revolution. We begin our discussion with the 

transportation sector, followed by industry, power generation and LNG exports. 

While this is not meant to be exhaustive, it will highlight some key points that must 

be brought forth in any policy discussion around natural gas. Namely, there are 

multiple margins of response to low natural gas prices, and one cannot consider 

each in a silo; the market certainly does not. 

In any case, the domestic supply capability is important in determining the price 

impacts of growth in demand, regardless of the source. According to a recent Baker 

Institute study, commercially viable shale gas resources have rendered the domestic 

supply curve to be very elastic.2 This means that even modest changes in price will 

result in significant changes in production. So, the capacity for the US market to 

absorb large increases in demand without significant upward pressure on price is 

large. In fact, the central tendency of prices is now projected to be between $4.50/ 

mcf and $5.50/mcf over the next few decades. 

Altogether, the aim here is to highlight some critical discussion points when considering the pathways for growth in U.S. natural gas demand. In particular, in traditional end-uses, growth in natural gas demand faces few obstacles other than 

those presented by market forces. In new demand sectors, however, there are substantial barriers to growth, largely due to high fixed infrastructure costs and return 

on investment considerations. Thus, although the potential for growth is large—especially in transportation where current gas use is very low relative to total transportation energy use—realizing that potential will be challenging. 

NATURAL GAS INTO TRANSPORTATION

The transport sector has historically been dominated by crude oil products, to the 

tune of 94% of all transport uses in 20103. So, as a point of departure, we must 

understand how natural gas might penetrate the transportation sector. For the purpose of this discussion, we will focus on two avenues for natural gas into transportation, one direct and the other indirect: 

• Compressed natural gas vehicles (CNGVs) • Electric vehicles (EVs). 

One could argue that other issues should enter the discussion, particularly if the 

goal is to reduce reliance on imported oil. For example, fuel efficiency improvements 

ultimately lower fuel use per mile driven. We could also discuss methanol and gasto-liquids (GTL) technologies, in particular because they both require natural gas 

as a feedstock and could displace crude oil in transportation. Moreover, we cannot 

ignore the developments in light tight oil (LTO) that have been driving U.S. oil production up since 2008, reversing a downward trend that had persisted since the 

early 1970s. But, we will return to all of these options below when discussing the 

considerations that influence investments in different fuel types. 

CNG Vehicles 

Currently, natural gas use in transportation is only 0.13% of total gasoline use. 

So, there is a lot of room for growth. In fact, a ten-fold increase in demand would 

push demand to about 0.9 bcf/day, which is an increase the U.S. market could absorb with relative ease. But, for the low levels of demand that currently exist to 

change, it will take substantial investment in fueling infrastructure and large adoption of compressed natural gas vehicles (CNGV) by consumers.4

One thousand cubic feet of natural gas yields eight gallons of CNG. So, if natural gas price is $4/mcf then the cost of natural gas as a feedstock for CNG production 

is $0.50/gallon. Adding the processing costs for CNG of approximately $1.00/gallon, 

we have an estimated wholesale price of $1.50/gallon. In addition, regional prices 

may differ due to differences in the price of gas, but the price changes by only $0.10/ 

gallon for every $0.80/mcf change in the gas price, so the wholesale price will not 

vary substantially by region. As a basis for comparison, the wholesale price of gasoline on the NYMEX is currently at $3.00/gallon. If these prices persist, the per galVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00049 Fmt 6633 Sfmt 6621 G:\DOCS\80132.TXT 80132
46 

lon fuel cost of CNG is about half the cost of gasoline, before accounting for things 

such as distribution costs, profits, local and national taxes, and lease payments by 

station owners. Assuming all these additional costs are equal for CNG and gasoline, 

we still have a differential between fuels of about $1.50/gallon. 

Despite the preceding cost per gallon comparison, cost per gallon is not the appropriate metric for comparison. We must compare the cost per mile of each fuel option. 

In order to do this for privately-owned vehicles, we need to incorporate the efficiency 

of a CNGV and a comparable gasoline hybrid vehicle. Then, we can calculate the 

annual fuel cost savings for each vehicle type. Importantly, we compare the CNGV 

with the hybrid because these are the two ‘‘next generation’’ technology options currently available. 

If we compare the Honda Civic, for example, we have a gasoline hybrid engine 

efficiency of 44 miles per gallon in the city. The Honda Civic CNGV has a city driving efficiency of 27 miles per gallon. Thus, the cost per mile is $0.0126 lower for 

the Civic CNGV. If we assume annual driving of 12,000 miles, the fuel savings is 

$151/year. Assuming a 7 year vehicle life, we see an undiscounted lifetime savings 

of just over $1,060. The current MSRP for a Civic CNGV is $26,305, and the current 

MSRP for a Civic Hybrid is $24,200, meaning the price difference is currently 

$2,105. Thus, the fuel cost savings does not compensate the higher upfront cost of 

the vehicle. If we discount future savings, the disparity grows. So, the CNGV is not 

the most attractive option to the consumer looking to purchase a vehicle that also 

reduces gasoline demand. If, however, the annual mileage jumps to 24,000 miles per 

year, then the undiscounted fuel cost savings just compensates for the fixed cost differential over seven years. So, high mileage is a prerequisite for the CNGV option 

to make economic sense given these fuel costs. 

The current pricing differential between natural gas and gasoline has been sufficient to promote adoption of CNGVs in commercial fleets. However, commercial fleet 

opportunities are small when compared to the fleet of privately owned motor vehicles. So, while an economic argument can be made for natural gas into high-mileage 

commercial fleets, the same is not true for private vehicles, which, absent a change 

in fixed costs differentials, will limit the movement of natural gas into private vehicles. 

Aside from the cost differences, another issue that stands in the way of large scale 

CNGV adoption is a lack of re-fueling infrastructure. There are currently about 

1,100 CNG fueling stations and 59 LNG fueling stations nationwide. These facilities 

primarily serve large trucks in the case of LNG and light duty trucks in the case 

of CNG. But, the ability to refuel becomes an issue when one considers the current 

consumer driving behaviors. In particular, the flexibility implicit in the existing fuel 

delivery infrastructure (for gasoline) allows drivers the freedom to plan their activities without necessarily planning routes so that they coordinate with re-fueling opportunities. This point is what leads us to the so-called ‘‘chicken-and-egg’’ problem. 

Namely, consumers bear a cost if they have to search for re-fueling stations (a socalled ‘‘search cost’’), and this cost can prevent them from buying a CNG vehicle, 

even if the projected fuel savings compensates for the incremental fixed cost. In 

turn, station owners may be reluctant to install CNG re-fueling capability if CNGVs 

are not prevalent enough in the vehicle stock to guarantee some demand for the station’s services. Hence, the conundrum—how does one overcome this mismatch to ensure coordinated growth in both CNGVs and re-fueling locations? 

Electric Vehicles 

Many of the issues facing CNGV adoption into the private vehicle fleet are also 

faced by EVs, but by differing degrees. Cost of ownership is certainly an issue, as 

most EVs are more expensive than their non-EV counterparts. Of course, the low 

cost of electricity can provide significant fuel savings, but even if EV fuel costs are 

driven down near zero, the projected 7 year undiscounted savings approaches 

$5,600. The base model Ford Focus EV lists an MSRP of $39,200. This compares 

with the gasoline-powered base model Ford Focus MSRP of $16,200. So, just as with 

EVs, the difference in fixed cost is not fully compensated by the fuel savings. Even 

with the federal tax credit of $7,500, the fuel savings is not sufficient. In other 

words, rational individuals who buy an EV are doing so for some additional derived 

benefit. 

Aside from the issue of cost, there are also issues associated with re-fueling. Refueling electric vehicles has both short term and long term components. In the short 

term, the existing generating fleet is sufficient to meet almost any expectation of 

electricity demand growth associated with EV penetration. Moreover, many consumers can re-charge at home, and in some cases re-charging capability is available 

at work and other non-residential locations. But, the availability of non-residential 

re-charging stations is not sufficient to support wider adoption of EVs. As of SepVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00050 Fmt 6633 Sfmt 6621 G:\DOCS\80132.TXT 80132
47 

5For example, the Ford Focus EV has a range of 76 miles and the Nissan Leaf has a range 

of 73 miles. The Tesla S has an estimated range of over 250 miles, but its cost makes it a prohibitive option for most car buyers. 6See ‘‘Energy Market Consequences of Emerging Renewable Energy and Carbon Dioxide 

Abatement Policies in the United States,’’ by Peter Hartley and Kenneth B Medlock III (Sept 

2010), available at www.rice.edu/energy. 7Data sourced from the U.S. Energy Information Administration. 

* All figures have been retained in committee files. 

tember 2012, according to the EIA there were 4,592 non-residential re-charging locations in the U.S., where some locations have multiple charging units. Moreover, 

most of these locations are in only a couple of states. 

The location of re-charging stations becomes a relevant issue primarily when long 

distance travel is desired. Currently, range is limited to less than 100 miles per 

charge in most commercially available EVs on the market today.5 This creates 

logistical issues for consumers who wish to drive more than 100 miles for a weekend 

getaway. 

If we think about the prospects of EVs longer term, investments in charging stations can be made, particularly if consumers show a propensity to buy EVs. However, even if the proverbial ‘‘chicken-and-egg’’ problem of vehicles and infrastructure 

can be overcome, the resulting requirements for new electric generation capacity 

cannot be understated. For instance, if EVs are widely adopted into the vehicle fleet, 

a recent Baker Institute report put the projected growth in power generation requirements are 5%, 12% and 21% higher than the ‘‘business as usual’’ case in 2030, 

2040 and 2050, respectively.6 Given the regulatory burden facing other alternatives, 

the majority of this incremental demand for electricity would likely be met by natural gas. However, it is important to recognize that this incremental demand will 

take decades to materialize, absent government regulations that accelerate the process. 

Some other factors to consider for natural gas into transportation 

There are other costs that exist, some of which are not even in the current discussion. Cost of expanding and upgrading electricity infrastructure can become an 

issue. Effectively, current mechanisms would force non-EV owners to subsidize EV 

expansion. This could become a political issue. Moreover, currently 18.4 cents per 

gallon of gasoline purchased flows into the National Highway Fund to support construction and maintenance of public infrastructure. As the gasoline base diminishes, 

the fund will still need to be solvent, so electricity and natural gas will need to be 

taxed accordingly. Currently, no such tax exists, so it is left out of most breakeven 

calculations for purchase of CNGVs and EVs. In the case CNGVs, assuming refueling infrastructure is added, a tax at the pump can be instituted in much the same 

manner as is currently done with gasoline purchases. But, its implementation will 

almost certainly be protested by early adopters of CNGVs as it could represent an 

ex post unexpected increase in the cost of ownership. 

In the case of EVs, if mechanisms are proposed whereby electricity sales are 

taxed, then again, non-EV owners are subsidizing EV expansion. While centralized 

refueling stations are a possibility, their installation is still a pre-requisite capital 

expense. Moreover, the issue of tax payments is still present. It is more likely that 

EV owners will recharge at home. So, a mechanism to tax the owners of EVs specifically must be considered. Just as with early adopters of CNGVs, any tax implemented will represent an ex post unexpected increase in the cost of ownership, and 

will likely be met with resistance. 

INDUSTRIAL DEMAND FOR NATURAL GAS

There are, of course, also ample opportunities for demand growth in traditional, 

non-transportation end-uses. Power generation and industrial uses make up the 

bulk of natural gas demand on an annual basis. Seasonally, the balance shifts more 

heavily to space heating applications in residential and commercial end-uses, specifically in winter months, but the general trends in annual demand growth are set 

by industrial and power generation uses. In 2012, power generation comprised 

36.1% of annual demand and industrial comprised 32.1%.7 Moreover, the recent low 

price environment has natural gas use in both sectors poised to grow. 

Industrial most recently demand peaked in 1997 (see Figure 1*) reaching levels 

similar to what was witnessed in the early 1970s. It steadily declined thereafter due 

to lower cost natural gas in international locations. Industries such as the ammonia 

and fertilizer industries were heavily favored by lower cost feedstocks elsewhere, 

and the late 1990s and early 2000s saw many of these types of industrial gas consumers shutter operations in the US Gulf Coast region choosing to move abroad. 

48 

8Of course this is only a necessary condition. It may not be sufficient. For example, if contracted coal deliveries continue to pile into inventory, then the shadow value of coal will drop 

toward zero when inventory nears capacity. Then, coal-fired generating stations will operate 

even if the price of natural gas dips below this level. This is, however, distinctly a short run 

phenomenon. 

However, much of this has changed in the last few years, and industrial demand 

has actually grown since 2009, a trend bolstered by low cost natural gas supply due 

to growth in shale gas production. 

An expectation for continued strong supply and stable pricing is being seen in the 

slate of recent announcements by firms to expand their businesses that rely on natural gas as a feedstock and energy source. Dow Chemical, an industrial user of natural gas, has recently announced a number of significant expansion plans in Texas. 

Other industrial firms have also announced plans to expand domestically. Methanex 

has moved forward with plans to relocate its Chilean facility to Geismar, Louisiana, 

and Sasol has announced intent to move forward with a GTL project in Southwest 

Louisiana. In short, if price does stay low and relatively stable, it is possible that 

industrial demand could rise to levels not seen since the mid-1990s. This would represent an over 18% increase in industrial gas demand from its current levels. 

It is important to point out that the long term trend seen in the industrial demand sector bears resemblance to a cycle. Indeed, even the recent growth in industrial demand has been modest in comparison to power generation use. Nevertheless, 

the past few years have seen a renewal of industrial demand for natural gas. Moreover, the planned capital expenditures by gas-intensive industrial players are quite 

large, signaling a substantial comparative advantage exists to siting production in 

the US. 

POWER GENERATION DEMAND FOR NATURAL GAS

Natural gas demand in the power generation sector has substantial growth opportunity through fuel substitution, and it can occur in a relatively short time frame. 

In 2012 we saw a dramatic increase in the use of natural gas in power generation 

through substitution with coal. In fact, the natural gas share of power generation 

in 2012 rose to over 30%, which was up from an annual average of 17.9% just 10 

years ago. This is in stark contrast to coal, which has seen its market share deteriorate from 50.8% to 36% in the same time frame. In fact, much of the drop in coal’s 

share in power generation is directly attributable to grid-level switching to natural 

gas. 

The rise of gas use at the expense of coal was primarily the result of relatively 

low natural gas prices, and the fact that there is sufficient natural gas generating 

capability to allow for large scale, grid-level fuel switching. Much of the existing natural gas fleet that can capitalize on relative price movements was brought into service between 2000 and 2005 (see Figure 2). In fact, natural gas generation capacity 

surpassed the installed capacity of coal in the US in the early 2000s. Moreover, 

most of the capacity that was added employs the latest generation combined cycle 

technology, meaning its thermal efficiency is substantially higher than the majority 

of the existing coal fleet. 

Figure 3 indicates the prices at which existing capacity of natural gas displaces 

coal in power generation when the price of coal is $65/short ton (the average 2012 

NYMEX price of Central Appalachian coal), and the heat rate of the competing natural gas plant is 7,000 btu/kWh (which is representative of about 30 percent of the 

existing natural gas fleet). We see that when the price of natural gas drifts below 

$2.80/mcf, then gas will displace coal capacities with heat rates above 11,000 btu/ 

kWh, meaning roughly 17% of existing coal capacity (or 52 GWs) could be displaced. 

Of course, this example is specific to a coal price of $65/ton, but we can see in general that when gas price falls, we have the possibility to see substantial fuel switching.8 If coal trades at price levels seen in the international marketplace in the last 

few years (over $130/ton), then the parity point for natural gas price to displace 17% 

of coal capacity rises to around $5/mcf. 

If we see the price of natural gas regularly at a competitive advantage to coal in 

power generation then older units of the coal fleet will be retired. Initially, the existing natural gas generation fleet will pick up the slack, but eventually, new builds 

of high efficiency natural gas combined cycle units will be required. This raises the 

natural gas pricing point for parity because a greenfield expansion must include the 

cost of capital. However, when one also accounts for the environmental regulations 

49 

9The current rule-makings the EPA has made are all under various levels of protest in US 

courts. So, it remains to be seen exactly how binding the recent EPA actions may ultimately 

be. 

that the US Environmental Protection Agency (EPA) seeks to impose via recent 

rule-makings, then the competitive balance shifts in favor of natural gas.9

Importantly, the EPAs recent rule-makings are focused on pollutants other than 

carbon dioxide. However, a displacement of coal by natural gas will have a substantial impact on US CO2 emissions. Evidence of this was seen in 2012. The low price 

of natural gas encouraged significant fuel switching to natural gas away from coal, 

and US CO2 emissions were the lowest they have been since 1992. In fact, according 

to the EIA, CO2 emissions where 5,293 million metric tons in 2012 and 5,343 million 

metric tons in 1992. Moreover, this occurred without the EPA rule-makings in force, 

and the real price of electricity was on average lower in 2012 than in 1992, dropping 


med1.eps
50 

19 ‘‘US LNG Exports: Truth and Consequence’’ available at www.bakerinstitute.org. 

from $0.1361/kWh to $0.1187/kWh on an average basis delivered to residential customers. 

The above highlights a substantial opportunity for growth in natural gas demand, 

particularly if resource abundance translates into relatively stable and low prices 

of natural gas. Moreover, increased use of natural gas in power generation, particularly if it comes at the expense of coal, conveys desired environmental benefits. Government action on air and water emissions and mandated pollution control mechanisms will provide a substantial push in this direction. 

LNG EXPORTS

A recent paper by Medlock (2012)19 argues that the volume of LNG exports from 

the US will ultimately be contingent upon domestic market interactions with the 

international market. This is because US LNG exports will occur in a global setting, 

meaning the entire issue must be considered as a classic international trade problem. Only then will any insight be gained with regard to export volumes and thus 

US domestic price impacts. The paper goes on to argue that (a) the impact on US 

domestic prices will not be large if exports are allowed, and (b) the long-term volume of exports from the US will not likely be very large given expected market developments abroad. The bottom line is that the entities involved in LNG export 

projects may be exposed to significant commercial risk. 

Much of this conclusion derives from a relatively straightforward analysis of domestic and international natural gas prices taking into consideration the effects of 

short term deliverability constraints. Indeed, the argument is made that the existing spread in prices between the US, Asia and Europe is transitory. Referencing 

Figure 4 can illustrate this argument. Specifically, spot prices in the UK, US and 

Asia all move together until the middle of 2010. At that point, the US price begins 

to drift below the prices in the UK and Asia. This is largely the result of growth 

in shale gas production in the US. 

A significant break in the pricing relationship between Asia and Europe occurs 

at a specific date, March 11, 2011, the day of the disaster at Fukushima. The Asian 

spot price jumped by almost $2/mmbtu within a week and continued to climb 

through the end of the year with the closure of every nuclear power plant in Japan. 

This was the result of an unexpected demand shock as Japanese utilities scrambled 

to buy any available LNG for power generation. At the same time, the spread between the US and Asia was exacerbated by a negative demand shock in the US. 

Namely, the winter of 2011/12 was one of the warmest on record in the US, resulting in very low winter heating demands. As a result, natural gas inventories remained very robust and the market was oversupplied, leading to a price collapse to 

below $2/mmbtu in April 2012. As a result, the spread between the US and Asia 

rose to as high as $15/mmbtu. The interest in exporting LNG from the US also accelerated during this period. However, it is reasonable to expect Asian price to revert back to its pre-Fukushima relationship with European price as the current deliverability constraints subside—due to new supplies and reactivation of nuclear capacity in Japan. The LNG export opportunity looks a bit more sobering if that occurs. 

Importantly, if we consider a longer term view of regional prices, we can begin 

to understand the potential risk in myopic decision making. Figure 5 indicates annual average price delivered to consumers in Asia, the UK and the US from 1980 

through 2012. We can see from 2000-2008 the US price was rising, and it coincides 

with the period during which LNG regasification capacity was constructed with an 

aim to import LNG to the US. However, the period since 2008 is characterized by 

a wide divergence in regional prices, and this coincides with the emerging interest 

to export LNG. 

One must consider the longer term price relationships because the recent past is 

not a prelude to the future. In fact, the 20 years prior to the 2000s is characterized 

by a relatively stable relationship between the regional market prices that saw 

Asian prices at a consistent but relatively small (to recent history anyway) premium 

to prices in Europe and the US. One must, therefore, question the nature of the recent divergence in regional prices. 

The conclusion reached in the study by Medlock was one of very low export volumes from the US because the pricing premiums that exist today will not likely persist due to new supplies from a variety of sources as well as reactivation of nuclear 

reactors in Japan. In effect, the high prices in Asia encourage responses on many 

margins and thus result in a reduction in price. This follows from the adage, ‘‘the 

best cure for high prices is high prices.’’ 

51 

CONCLUDING REMARKS—BRINGING IT ALL TOGETHER

All the information, when taken together, points to a series of cause-and-effect relationships that present challenges for some margins of response and opportunities 

for others. It will be surprising if ‘‘all of the above’’ actually results in a marketdriven equilibrium. The traditional consuming sectors, specifically industry and 

power generation, face fewer obstacles because the mechanisms for demand 

growth—infrastructure and technology—are already in place. Natural gas into 

transportation may be a mixed outcome, with fleet vehicles—because they are high 

mileage vehicles—being the most successful in migrating natural gas into the fuel 

mix. Absent a policy intervention or a cost reduction, passenger vehicles still face 

hurdles to large scale penetration of CNG due to lower mileage. 

The likelihood of demand pull coming from international sources in the form of 

LNG exports is high, but not in large quantities. This follows from the fact that US 

prices will likely rise to reflect marginal costs and international prices are not likely 

to remain at their current premiums. In fact, if the Asian price reverts back to its 

pre-Fukushima relationship with European price then the margin for profitable export of LNG from the US becomes razor thin. Thus, market forces will ultimately 

limit the volume of US LNG exports. 

So, perhaps what is needed for demand growth for natural gas is a relatively simply prescription—economic growth. Economic growth stimulates demand for electricity and industrial goods, both of which favor natural gas. Moreover, as demands 

in these traditional sectors grow, this will create competition for supplies of natural 

gas for LNG exports and new demands. It is for this reason that the most likely 

demand for the robust supply of natural gas in the US will come from industrial 

and power generation uses. Transportation and LNG exports will likely remain marginal influences at best. 

The CHAIRMAN. Well said doctor. 

Mr. Gerard, welcome. 

STATEMENT OF JACK N. GERARD, PRESIDENT AND CEO OF 

AMERICAN PETROLEUM INSTITUTE 

Mr. GERARD. Thank you Mr. Chairman, Ranking Member Murkowski, and members of the committee. It’s great to be with you 

today. 

In the interest of time, I will abbreviate my statement consistent 

with your earlier counsel Mr. Chairman. 

The invitation to join today is really an opportunity to talk about 

the game-changing opportunity that’s occurring in the United 

States today, one that’s unprecedented and that no one would’ve 

predicted just 5 or 6 short years ago. Today’s hearing opportunities 

challenges natural gas is extremely timely in light of our Nation’s 

emergence now as a super power in energy production. 

This change in the global energy equation is due largely to technological advances in the extraction of natural gas and oil from 

shale formations. These technologies, though they have been 

around for many years, are now being improved dramatically in 

driving America’s 21st century energy renaissance and have the potential to benefit our Nation well beyond what we might consider 

traditional energy policy. In the words of Pulitzer Prize winning 

author, Dan Yergin, just last week he said ‘‘this is the most important energy innovation so far of the 21st century.’’ 

Recent research shows that in the upstream segment of the oil 

and natural gas industry, and I want to emphasize this is just in 

unconventional production of natural gas, we today support 1.7 

million jobs. That number is expected to grow to 2.5 million jobs 

by 2015, 3 million jobs by 2020, and 3.5 million American jobs by 

2035. According to the Bureau of Labor Statistics, jobs in the oil 

and natural gas industry, exploration of production sector pay on 

52 

average more than $100,000 per year, more than twice the national 

average. These are good jobs that our economy desperately needs. 

Currently the entire natural gas and oil industry today in the 

United States supports 9.2 million jobs, we’re responsible for 7.7 

percent of our gross domestic product, and we contribute $86 million a day to the Federal Government. 

In addition to job creation, unconventional natural gas and oil 

paid $62 billion in Local, Federal, and State taxes in 2011. By 

2020, this number is expected to grow to $111 billion. 

On a cumulative basis, unconventional natural gas and oil activity is expected and projected to generate more than $2.5 trillion 

that’s a T, 2.5 trillion in tax revenues between 2012 and 2035. 

We should remember, this isn’t happening in just a vacuum. The 

world is watching us and understands that decisions you will make 

as a committee, and more broadly the Congress, could literally 

alter the geopolitical energy dynamic of the world. 

Case in point, LNG exports which will create thousands of U.S. 

jobs, generate billions in additional revenue, improve our trade deficit, and spur major investment in infrastructure, all while improving our energy security. 

Additionally, the increased use of natural gas is critical to reducing carbon emissions, which many have spoken about already 

today. In fact, as mentioned earlier, carbon emissions are at 1992 

levels due largely to natural gas. 

The question before us is not whether we have the energy to 

grow and to prosper. We clearly do. 

The question is whether we have the political wisdom and foresight to create a national energy policy that harnesses our great 

potential as literally an energy super power. 

We look forward to working with you to make this potential a reality. This hearing is a good start in that process. 

Thank you very much Mr. Chairman for the invitation. 

[The prepared statement of Mr. Gerard follows:] 

PREPARED STATEMENT OF JACK N. GERARD, PRESIDENT AND CEO OF AMERICAN

PETROLEUM INSTITUTE

Good morning Chairman Wyden, ranking member Murkowski and members of the 

committee. Thank you for the invitation to join you as we consider the game changing energy opportunity before us resulting from our abundant domestic natural gas 

supply. 

My name is Jack Gerard, president and CEO of the American Petroleum Institute. We represent all aspects of the oil and natural gas industry with more than 

500 members who supply most of the nation’s energy. 

Today’s hearing, ‘‘opportunities and challenges for natural gas,’’ is extremely timely given our nation’s emergence as a global energy leader. This change in the global 

energy equation is due largely to technological advances in the extraction of natural 

gas and oil from shale formations. These technologies are driving America’s 21st 

century energy renaissance and have the potential to benefit our nation well beyond 

traditional energy policy. 

In the words of Pulitzer Prize winning author Dan Yergin, ‘‘[this is] . the most 

important energy innovation so far of the 21st century.’’ 

Recent research shows that in the upstream segment of the oil and natural gas 

industry alone, unconventional natural gas production supports 1.7 million jobs. 

That number is expected to grow to 2.5 million jobs by 2015; 3 million jobs by 2020 

and 3.5 million jobs by 2035. According to the Bureau of Labor Statistics, jobs in 

the oil and natural gas exploration and production sector pay on average more than 

$100,000 per year, more than twice the national average. These are good jobs our 

economy desperately needs. 

53 

Currently, the entire natural gas and oil industry supports 9.2 million U.S. jobs; 

accounts for 7.7 percent of the U.S. economy and delivers $86 million per day in 

revenue to our government. 

In addition to job creation, unconventional natural gas and oil paid $62 billion in 

local, state and federal government taxes in 2011. By 2020, this number is expected 

to grow to $111 billion. On a cumulative basis, unconventional natural gas and oil 

activity is projected to generate more than $2.5 trillion in tax revenues between 

2012 and 2035. 

And we should remember this isn’t happening in a vacuum. The world is watching 

and understands that our decisions could alter the geopolitical energy equation for 

generations. 

Case in point are LNG exports, which will create thousands of U.S. jobs, generate 

billions of dollar in revenue, improve our trade deficit and spur major investment 

in infrastructure, which will strengthen our energy security. 

Additionally, the increased use of natural gas is critical to reducing greenhouse 

gas emissions. In fact, U.S. carbon emissions are at 1992 levels due largely to increased use of natural gas in the generation of electricity. 

The question before us is not whether we have the energy we need to grow and 

prosper. We do. The question is whether we have the political wisdom and foresight 

to create a national energy policy that harnesses our great potential as an energy 

superpower. We look forward to working with you to make this potential a reality. 

This hearing is a step in the right direction. Thank you for your time and attention. 

The CHAIRMAN. You get the record for the shortest testimony, 

and—— 

Mr. GERARD. Thank you. 

The CHAIRMAN [continuing]. We thank you. 

So we’re going to have votes in a few minutes. 

I’m going to ask just one question to each of you. Senator Murkowski, we’ll get as many colleagues in as we can, and then we’re 

going to break probably around 11:15. 

Here’s my question for each of you that’s willing to comment. I 

think you heard Senator Murkowski and I both talking about the 

importance of working in a bipartisan way. That’s what it’s going 

to take in order to get anything done. What I’d like is to, in effect, 

assess your views on one issue and that is: Is there a way to a natural gas policy where America can have it all? Economic growth, 

lower emissions, cheaper power, and reduced trade deficits certainly are what come to mind. What would each of you recommend 

that the committee do in order to have it all, in effect find that 

sweet spot where we can attain so many of these important objectives to the country? Why don’t we start with you Governor? 

Governor HICKENLOOPER. That’s certainly no easy question. 

Again, I come back to the notion of regulation—appropriate regulation, and my own inclination, obviously being a Governor and 

knowing there are enough former Governors up there is that States 

are the laboratory of democracy and that we are focusing on how 

do we create a rigorous set of regulations that will be—I mean we 

steal from each other every day, and I think the Federal Government Lisa Jackson at EPA’s been a great partner with us in terms 

of trying to push us further and trying to figure out where those 

sweet spots are by using some of the technical expertise that she 

has had at her disposal. But I think that that’s going to take a, you 

know, certain amount of time although we should have our full regulatory environment together within—by the end of this year, and 

at that point we’re still doing testing and measuring the air pollution issues and air quality around these large fields, trying to push 

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line transfers, to convert more of their diesel operations to be 

fueled with LNG. 

I—One of the large exploration companies, Noble Energy in Colorado, they’re based out of Houston, but they are now building their 

own LNG plant in Colorado so that they can sell it and run these 

operations in a more clean fashion. 

The CHAIRMAN. If I can get some others in, Mr. Liveris. 

Governor HICKENLOOPER. Yes. 

Mr. LIVERIS. Yes, Mr. Chairman. 

I had mentioned the quadruple win. We believe that if the American public benefits and we get the benefit of jobs from exports and 

domestic manufacturing, America can be an energy and manufacturing super power. 

All you have to do is follow the current law of the regular regime 

that exists, which is—look at the public interests with each application, take a cautious approach. 

Our numbers suggest somewhere between 5 and 8 bcf a day 

should be what we see in this first little while while we’re in the 

fifth year of these great energy finds. 

I think we also have conversations around responsible regulations. 

We should have a con-responsible supply and making sure demand and supply don’t get out of check like they did 10 years ago. 

We should not let the market, call it the speculators, call it Wall 

Street, call it the financial world, set the price domestically because 

as we all have seen with commodities like oil, that price is set in 

the main by financial markets as much as real supply and demand. 

So there is a way to have it all, I believe. 

The CHAIRMAN. Very good. 

We were just given a reprieve for 15 minutes. So we’re going to 

go until 11:30. Then we’ll take a break. 

Mr. Eisenberg. 

Mr. EISENBERG. Thank you. 

I think this committee is taking a very thoughtful approach to 

the issue. 

I note this is not the very—it’s not the first time this committee’s 

had a hearing on the issue of LNG exports. I mean you did this 

14 months ago. 

You’re taking a very thoughtful and cautious approach to try and 

understand all of the challenges. 

If I could focus on one thing, it would be permitting. In my written testimony, and I’ll walk through it a little bit again, I talk 

about some of the hoops that you really have to jump through to 

actually get an LNG export facility up and running. 

So not only the DOE license is not the final hoop that they have 

to jump through here. They have to engage in a very, very broad 

environmental review of their project led by FERC. 

Compliance with NEPA requires that the developer acquire the 

land and begin design engineering plans. That takes about 2 years. 

Then NEPA requires the input of up to about 20 Federal and State 

agencies, including the Army Corps for dredge and fill permits, 

which we know can be very controversial; a waterway suitability 

assessment from the U.S. Coast Guard; air permits from State and 

55 

EPA agencies; and then the usual State and Local construction permits. 

If they can somehow get through that and get a final EIS, then 

you can be sued for 6 years. 

If you can somehow get through that, then you have to get the 

long-term financing in place and you have to get contracts in place. 

Then when you get the contracts in place, then you have to go find 

$10 billion to go building a facility. 

This is not an easy process. 

I really recommend to try and take on some real legislation to 

try to make the permitting process work faster. 

The CHAIRMAN. Let’s do this Ms. Beinecke and for each of you, 

understand the tradeoffs because if we all just go back to our positions, then it’s going to be hard to find the sweet spot. 

Ms. Beinecke. 

Ms. BEINECKE. Senator I think that one of the key issues is 

gain—how you gain public confidence, and I think having minim 

Federal standards and public disclosure of chemicals. 

There—right now there in the 30 States in which fracking is occurring. There’s only chemical disclosure in 14, and those States 

vary considerably. 

So in order for natural gas to provide the benefit that my colleagues on this panel have identified, you have to figure out how 

you’re going to assure the public that their health and that their 

well-being is protected, and there need to be minimum Federal 

standards that provide that, and they don’t exist now. 

The CHAIRMAN. Very good. 

Mr. Medlock. 

Mr. MEDLOCK. Yes, well, I actually second what Ms. Beinecke 

just said with regard to Federal standards. 

The one place I think the Federal Government could actually 

have a very active role is in promoting transparency. I think that’s 

something that is lacking, with the exception of a few States where 

certain States have actually taken initiatives to make sure transparency regulations are put in place. 

The other thing, and I’ll shift gears here, that I think could really help benefit an all-of-the-above kind of outcome is to allow markets to do what they do, what they’ve always done. They’ve actually resulted, as I mentioned in my testimony, in a very efficient 

natural gas market in this country, and it’s hard to imagine anything that would be adopted that would disrupt that. 

But one thing that we need in this country that would really benefit, not only the immediate-term, but in the long-term, is the ability to store electricity. If we get to that point, it actually changes 

the entire landscape of the energy infrastructure in this country 

and would convey a lot of benefits associated with renewables, associated with natural gas, associated with nuclear power that we 

simply can’t reap right now. 

The CHAIRMAN. You’re spot out on storage. I’m over my time. 

Mr. Gerard, just if you—— 

Mr. GERARD. I’ll be brief. The first thing we can do is remember 

how we got to where we are today. In a very real way we are today 

at a sweet spot. 

56 

We got here because of market conditions and the free market brought us to the point of $3 gas when it was $14 gas just 4 or 

5 years ago. 

So the worst thing for us to do, and this is just where I take 

strong exception with my friend Andrew, is to get government involved in trying to set the price and trying to control the market. 

The market will sort this out and find the equilibrium. 

We will from that we benefit from the improved environment 

with lower emissions, having low cost, affordable natural gas. We’ll generate 2 million jobs, we’ll generate $2.5 trillion in revenue to the Federal Government, all while finding the opportunity 

to literally have it both ways in terms of exports and domestic production. 

The CHAIRMAN. Very good. 

Senator MURKOWSKI. I’m just going to continue on the discussion 

of exports. Several of you have raised the fact that there are multiple applications pending right now. There are 18 that are for export to non-FTA countries and 3 that are for export to FTA countries. 

The suggestion has been, and not necessary with this panel but 

out in the public discussion that somehow or other if all these applications were to be approved, all of a sudden we wouldn’t have 

access to the natural gas in the volumes and the quantities that 

we would hope for this manufacturing renaissance. 

I think it was you, Mr. Eisenberg, that noted some of the difficulties. 

I noted in my opening comments that we’re talking about billions 

of dollars to build out the infrastructure. Was over in Japan a couple of weeks ago. They’re looking at our prices somewhat with 

envy, but when they account for the transportation costs and the 

liquefaction costs, at the end of the day there’s not that much difference between what they’re currently paying and what they 

might pay if they were able to take benefit of export from the 

United States here. 

If I can ask, and Mr. Liveris you had mentioned that potentially 

we could see half of our natural gas being exported if, in fact, all 

of these applications were to be approved. The question is: Do any 

of you believe that we will be in a situation where we will see a 

dozen export applications approved in this near term? 

I throw it out to any of you, given the cost, given the need for 

long-term contracts with other Nations, and the need to obtain financing. 

Mr. Liveris. 

Mr. LIVERIS. I would actually firstly agree with my good friend 

Jack, assuming we’re friends, the conversation about adding jobs is 

what we should be having 2 million plus 5 million, not 2 million 

or 5 million. 

I think this conversation is seen before. 

None of us get the gas price right. Five years ago we had it 

wrong. We were building import terminals. Five years from now, 

what’s it going to be? 

How many terminals should the public interest demand? 

What is the public interest here? 

It is to get volatility and instability out of an energy price. 

57 

We care about agriculture here in this country. 

We care about defense. 

We should care about energy. This opportunity to get it right by 

doing both in the public interest means we should take a crawlwalk-run approach to how many terminals we approve and how 

many of these occur over time. 

As I said in my testimony, we’re in the fifth year of our 100-year 

advantage. You can’t move factories overnight, to state the obvious. Why put at risk the 5 million jobs, the $96 billion worth of investment that are on the books today? Over 60 companies, why put 

that at risk by doing either or? Why transfer the risk? 

So be cautious, do what the public interest demands and the 

DOE application process. 

I agree, financing will be difficult. 

I agree, prices will be volatile. 

But why take the risk and let the speculators set the gas price 

like they did 10 years ago, and we all remember the Enron’s and 

what the efficient market did for us 10 years ago. It was hardly efficient. OK. It was very inefficient. 

Senator MURKOWSKI. We can talk about whether or not the public interest determination includes the specific criteria that we need 

to look at. I think that’s going to be an important part of it. 

I have suggested, too, that we need to be very thorough in the 

review. You don’t just willy-nilly grant applications. These all need 

to be recognized for what they might provide. 

Governor, I want to take the balance of my time to talk to you 

because I am interested in what Colorado has done in terms of 

your leadership with the State’s regulatory system. You indicate 

that Colorado could be this national model. You speak very highly 

of what you’ve been able to accomplish in terms of the balance. 

I happen to believe that the other States should be models just 

as Colorado is a model and, again, as a former geologist or a recovering geologist, however you recognize yourself, that in your State 

and in your region you want to make sure that things work for you. 

I guess my question to you is: Given that you feel pretty comfortable with your State’s regulatory system and what you have 

built there, do you think that we need new Federal rules on top 

of what Colorado already has in place to provide for further levels 

of safety or assurance or does it add another layer and perhaps an 

unnecessary regulatory layer? 

Governor HICKENLOOPER. Historically the way the regulatory environment traditionally works in this country is the States are the 

laboratories, and we are now—there are other States that are aggressive in creating their own integrated and comprehensive regulatory environment, and we—for the National Governors Association, you former Governors know how competitive Governors can 

be. But we also collaborate. 

So I—the Republican Governor, Mary Fallin, from Oklahoma, 

she and I went to Detroit last June to try and convince car manuautomobile manufacturers that they should do more compressed 

natural gas vehicles right off the assembly line. 

At the same time, we’re looking at how do we take our regulatory 

environments and have those 30 States where we are facing the 

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lic fracturing, and how can we work together to create a template 

where we would have sufficient flexibility to respond to the different environments in different States, different depth of the 

shale, the different quality of the rock, but at the same time allow 

us to move toward some level of Federal regulation. 

So I think ultimately we will get to that Federal regulation. 

I want to make sure that the States work together in terms of 

making sure we don’t put one State or another at a disadvantage. 

Senator MURKOWSKI. So then, in addition to what you already 

have within your State, you think that additional Federal regulation on top of that is a wise thing? 

Governor HICKENLOOPER. I think what would happen Federal 

regulations would probably be modeled after a group of States. It 

wouldn’t be in addition to. 

They would—we talked to Secretary Salazar when he was with 

the Interior in terms of what the appropriate regulation would be 

for BLM land. What we came up with was Wyoming, Colorado, 

Utah all have fairly strict transparency rules around frack fluids, 

some of the same basic regulatory environments, very aggressive 

about escaped fugitive methane. We got to the point where, and we 

haven’t done this yet, but we’re talking about having one application form that you would send if you wanted to drill a well in Colorado or Wyoming on BLM land. It would be the same form that you 

send in to the State. So you send the same form to the Federal 

Government as to the State. So that—I mean, isn’t that the ultimate goal? 

We’re trying to get different States and the Federal Government 

to work together so we cut the red tape and yet still maintain a 

very, very, very high and rigorous set of regulatory environments. 

Senator MURKOWSKI. Chairman, I’m well over my time, but it 

seems to me that we’re talking about regions, not necessarily one 

level of Federal overlay. 

But I’d like to pursue this conversation further with you if I may. 

The CHAIRMAN. Very good. 

Unless things change now, again, we will go until 11:45, then 

we’re going to have 2 votes, and then we’ll take a break and will 

come back. 

Next in line is Senator Udall, and then Senator Flake is after 

Senator Udall. 

Senator UDALL. Thank you Mr. Chairman, again. Welcome to all 

of you on the panel. 

I want to turn to my Governor who provided an initial, very insightful summary of what’s happening in Colorado. 

We have seen a big economic boost from the current oil and gas 

boom, as the Governor mentioned. 

It’s also brought some challenges. In our neighborhoods and communities we’ve seen additional drilling and concern from our citizenry. I think the Governor and I both believe that there’s a great 

economic opportunity here, but our No. 1 priority is to protect the 

health and well-being of our citizens. 

We hear a lot about fracking and drilling, and there are some efforts underway that have been challenging in Colorado when it 

comes to those communities? rights versus the State’s rights versus 

the industry’s rights. 

59 

Governor would you speak, because I know you’re going to field— 

and have already—some questions on how we balance all of this, 

but speak in particular of the fugitive emissions questions that 

have been raised? 

There was a study that the EPA released last week that concluded that oil and gas operations are the second largest emitter 

of methane in the country. You’ve spoken about the need to eliminate fugitive methane emissions, so we can get that full environmental benefit. 

Would you share with the committee what your vision is for how 

we do that and what the industry’s been saying to you in Colorado? 

Governor HICKENLOOPER. Sure, and thank you Senator for your 

balanced approach on all of this. 

I’m sure you senators all know this, but there’s no one who’s 

climbed more mountains, I mean real mountains, in terms of their 

life and at the same time recognizes and tries to balance the needs 

of our communities for jobs and commerce so that we can protect 

our natural environment at the highest level but still focus on the 

realities of day to day life. 

You know the issue around methane is crucial because it is—fugitive methane is very harmful to our environment and even as you 

burn gasoline, you know compressed natural gas is cleaner than 

gasoline, but if you allow fugitive methane to escape from where 

it’s collected and then during transportation and more importantly 

where it is put into vehicles or used by end, whether it’s commercial facilities or wherever, if that’s escaping, we lose much of the 

environmental benefit. 

The one beauty of this is you don’t have to push industry too far 

to let them recognize this is something that they can sell. Right? 

This is something that they can value and that a higher level of 

regulatory oversight to make sure that they’re—that we measure 

fugitive methane really allows them to benefit long-term by making 

those infrastructure investments. 

We have—we’re doing a $1.5 million project right now through 

Colorado State University. We’re going to go out to a couple of our 

largest fields, but eventually within 2 years we will have measured 

the air quality at different times of the day at different seasons in 

most of our major oil producing parts of the State so that we can 

actually demonstrate what are the real, not just the estimates, but 

what are the real consequences of this and how much methane is 

escaping and get ourselves back down to a zero tolerance. 

Most of the responsible oil and gas producers recognize the imperativeness, and they willingly accept that regulatory environment. 

Senator UDALL. Thank you Governor. 

If I might, I’d like to ask Ms. Beinecke for her thoughts on fugitive emissions. I know, Frances, you’ve really taken a close look at 

this and—— 

Ms. BEINECKE. We have Senator, and thank you for asking. 

Our concern is—I mean we have concerns about all the air emissions coming from natural gas. Methane is of particular concern because of its potency as a climate-forcing emission. So we think that 

the measurement that’s going on now, trying to find out where the 

methane is leaking from, putting forth the technologies to stop it 

60 

as quickly as possible is absolutely imperative to protecting the climate. 

We’re also concerned with the other air emissions coming from 

fracking, particularly coming from the trucking operations—diesels. 

There are people all across the country who are concerned about 

what they’re being exposed to. They don’t know exactly. 

We need ongoing air monitoring, and I’m happy to hear the Governor saying that that’s going to be something Colorado is going to 

be doing because there’s a huge gap between the information that 

the public has and what is happening in their own communities 

and until we, as a country, take that on and address it head on, 

there is—there just a huge conflict between the opportunity that 

people hear of identified with natural gas and the concern that people have about their health and well-being in their own homes. 

I’m just saying that that is growing so quickly across the country. 

We hear from people each and every day, and just a poll that 

Bloomberg did in January shows that 66 percent of people in the 

country wanted stronger protections from fracking and that went 

up from 55 percent in September. 

So, this is an issue that is really exploding in the public mind, 

and they need to know that you will all take on their concerns and 

put in place those safeguards that will assure them that they’re 

protected in the future. 

Senator UDALL. As the Governor pointed out, these are industrial 

processes, and we’ve all become comfortable with the industrial 

zones around our cities and wherever they may be located. But 

when these industrial processes come to people’s backyards and 

school yards and community areas, it really drawns people’s attention. 

I know my time’s expired. 

I want to, for the record, thank the Governor for his comments 

about my mountain climbing exploits, but I also wanted to be clear 

that the great French climber, Lionel Torrace, said that climbers 

are conquistadors of the useless. 

We’ll leave that there, but I did want to comment on natural gas 

exports. I think there’s real potential when it comes to exporting 

natural gas, as long as it doesn’t come at the cost of our land, our 

water, and our air, or consumer energy prices. 

I want to keep exploring the national security implications of exports, especially to our NATO allies. I think there could be a real 

benefit. I sit on the Armed Services Committee, as well as the Intelligence Committee, and I believe there’s more to this question 

that we ought to discuss, and I look forward to continuing that conversation. 

There’s real geopolitical ramifications of this Shale Gale that we 

now have available to us. 

So, again Mr. Chairman, thank you, Ranking Member Murkowski, thank you. 

The CHAIRMAN. Thank you Senator Udall. 

Senator Flake. 

Senator FLAKE. Thanks. 

In the interest of time, I’ll just ask one question. Mr. Liveris in 

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dustry by maintaining affordable gas prices. I think we all agree 

with that. You talk when you look at Dow’s online policy statements, they will tout the benefits of a competitive open market, 

particularly as it pertains to exporting chemicals. Why do open 

markets work there in driving down price and benefits to everybody, but they don’t in terms of producing natural gas and export 

of natural gas? 

Mr. LIVERIS. I’ll try and be brief. 

It is a complex conversation. 

Number 1, open markets we are very much for. 

We are for exports, we are for balanced exports, so we don’t lose 

competitive advantage domestically. 

Gas, as already noted, has to be liquefied and shipped at billions 

and billions of dollars. That is not an open market, that’s a point 

to point contract. There’s probably 30 of these contracts around the 

world from nation states to nation states. 

Not all go to free market NATO allies. These are countries that 

need gas because they don’t have oil. They—actually their equivalent is to import oil. That’s why there is a national security interest. 

But to take gas and actually export it as a primary-10 producers 

in the world that are gas rich, only one of them chooses to disadvantage the domestic sector by not looking at the efficiency of 

the domestic market because it takes so much to make this shippable versus in oil. OK? You actually can leave it home in an efficient market home. 

So how do you actually balance how much of it goes offshore 

versus home is a conversation that should be in a conversation like 

this. 

Domestic manufacturers in places like Saudi Arabia, in places 

like Russia, who actually have top-down policies say I’m going to 

keep the gas home to diversity my economy away from just being 

exposed as an oil exporter and a gas exporter in their 2 cases. 

In a free market democracy, we need to get the balance of all 

stakeholders to the table, but recognize that this is not a commodity world price yet. One day it might be. There may be enough 

LNG traders that’s why I disagree with this market of LNG being 

30 BCF a day. 

If the world energy market is the gas market, the gas will substitute the oil. 

The gas will substitute the coal. 

The gas will substitute ultimately nuclear where nuclear is not 

allowed. 

So it’s the world energy market that this serves. Therefore, it’s 

fairly infinite in that sense. 

So you’ve got to be careful you don’t let the current world energy 

price, which is oil, set the domestic gas price as an unintended consequence. 

So, crawl-walk-run. Let some of this occur. Let the BCFs go up. 

Let it rise as supply rises with responsible regulation. Let’s look at 

the public interest and the effect on the domestic competitiveness 

in both the consumer and the industrial user. Let’s get both of 

them. 

That’s my quadruple win. 

62 

Senator FLAKE. If I understand right, Mr. Gerard, you’re saying 

that the best way to let that happen, to find that balance, is to let 

markets to do that. Is that correct? 

Mr. GERARD. Absolutely. 

In fact, Senator when you look at the reality of what we’re dealing with today, there’s already about 37 to 40 bcf a day capacity 

that exists in the world. The expectation between now and 2025/ 

2030 is that the entire market for LNG is going to be in the 50 to 

60/65 bcf. 

The amount that we’re talking about in the U.S.’s potential proposals or permits is about 30 bcf. 

The potential additional build across the world is 50. 

So if you look at all of the proposal to export LNG today, you’ve 

got 114 bcf potential trying to satisfy a 50 bcf a day market. 

The amount that would leave here, and most of the studies show, 

at most perhaps 5 to 6 bcf. 

The natural gas industry increased our production in the United 

States by 6 bcf in 2 years in the United States, and we’re just at 

the verge of figuring out how to further be more efficient to produce 

even greater volumes. 

The likelihood of this having any significant impact on price, in 

fact all the other independent studies have done show somewhere 

between 2 and potentially 11 percent impact on price, is highly unlikely. 

It’s the market that brought us here today. 

The market will continue to drive the price down. 

The other added advantage is we’re creating jobs in this country, 

great paying jobs, as we try to fulfill the demand on a global basis. 

We shouldn’t overlook that, and we’re really at an opportunity to 

change the equation. 

We’re now the largest producer of natural gas in the world, surpassing Russia. It’s a great opportunity. 

We shouldn’t go slow and let that market dissipate because it 

will be filled by others around the world, and we’re putting at disadvantage our own Americans and others who are prepared to risk 

market capital and to build the facility to export the product. 

Senator FLAKE. Thank you, Mr. Chairman. 

The CHAIRMAN. Senator Franken. 

Senator FRANKEN. Thank you Mr. Chairman. 

Natural gas has contributed to lower U.S. emissions, which is 

great, but oil and gas production is still the second biggest contributor to greenhouse gases and eventually we need to shift more emphasis to renewables. 

When this committee heard testimony from former Lockheed 

Martin CEO, Norman Augustine, on a report by the American Energy Council, we were told that the country has yet to embark on 

a clean energy innovation program deserving of the priorities that 

are at stake. 

Part of that is because my colleagues often criticize government 

support for renewables. They believe it is only the marketplace 

that can determine which technologies will become relevant. 

But the history of fracking tells a very different story. 

The Breakthrough Institute has looked extensively into this. 

They’ve examined the Eastern Gas Shales Project which was an 

63 

initiative of the Federal Government back in 1976 before 

hydrofracking was a mature industry. The Project set up dozens of 

pilot demonstration projects with universities and private gas companies testing, drilling, and fracturing methods. 

This was instrumental in the development of the commercial extraction of natural gas from coal. 

Other tool used in fracking, microseismic imaging, was originally 

developed by Sandia National Laboratory, a Federal energy laboratory. 

The industry is also supported through tax breaks and subsidies. 

In fact, according to former Mitchell Energy Vice President Dan 

Stewart, Mitchell Energy’s first horizontal well was subsidized by 

the Federal Government. Mr. Mitchell said in an interview, and I 

quote, DOE started it and other people took the ball and ran with 

it. You can’t finish DOE’s involvement. 

Anyone here but Mr. Gerard, Mr. Medlock do you agree with Mr. 

Stewart that you can’t dismiss DOE’s role in the development of 

this technology? 

Mr. MEDLOCK. I’m actually 100 percent with that. It’s actually a 

point I’ve made many times in talks that I’ve given. I think it’s actually remarkable how the foresight that was demonstrated by the 

Federal Government back in the 1970s to actually initiate the 

Eastern Gas Shales Project because it didn’t pay off in 5 or 10 

years. It took over 30. 

Now we’re sitting in the midst of talking about what should we 

do with this abundance of natural gas, and it owes its roots to Federal Government programs, so I don’t disagree with that at all. 

Senator FRANKEN. I just want to emphasize that because we hear 

this so often. But then if you look back at the actual history of this, 

this thing that we celebrate now, this abundance of natural gas 

came from the expenditure of Federal dollars. 

We need to do the same thing when it comes to renewables. 

Governor. 

Governor HICKENLOOPER. Senator, I think you’re right on point, 

and I know some of those guys from Mitchell Energy, and they are 

the first to recognize over the 1980s—I remember that I think it 

was 1982 and 1995 that the Federal Government invested over $5 

billion in terms of trying to create this ability to extract shale gas 

from tight shales and to get oil from tight shales. 

Simultaneously, I think also we have to recognize that renewable 

energy such as wind and solar is intermittent and certainly as we 

are faced with challenges on storage we need ways to be able to 

have electrical energy generation go on and off efficiently. 

Natural gas does that at a level that literally almost no other energy can do, so it becomes a perfect partner for solar and wind. 

I think it will prove to be the transition energy that will allow 

us eventually to get to a fully renewable energy environment. 

Senator FRANKEN. Thank you Governor. 

Since I have you, I just want to talk to you a little bit about, and 

I’ll do this very quickly because I’m running out of time, the 2005 

Energy Policy Act exempted underground injections associated with 

fracking from Federal Safe Drinking Water Act jurisdiction. 

The only exemption was from fracking fluids that used diesel. 

64 

Now we’ve had concerns over groundwater contamination that 

have been raised, even documented by EPA in places like Pavilion, 

Wyoming. 

You’ve developed regulations in your State that include disclosure of chemicals that are used. Have these regulations prevented 

your State from sustaining a strong natural gas industry? I think 

I know the answer, but I want to ask it. 

Governor HICKENLOOPER. No, not at all. 

But I think the key there is to make sure that all the actors are 

at the table and so that as you’re recognizing one of the real issues 

when we sat down with executives from Halliburton, they have a 

frack fluid that is made out of food additives. You can drink it. 

We did drink it around the table, almost ritual-like in a funny 

way, but it demonstrated—— 

Senator FRANKEN. Like a pact. 

Governor HICKENLOOPER. Not like a pact. 

It was a demonstration. We had environmental—— 

Senator FRANKEN. Oh. 

Governor HICKENLOOPER.—representatives. We had industry representatives—everybody around the table. 

Senator FRANKEN. It was not like an occult? 

Governor HICKENLOOPER. Not an occult. 

Senator FRANKEN. OK. 

Governor HICKENLOOPER. No, there were no religious overtures—— 

Senator FRANKEN. Yes. 

Governor HICKENLOOPER.—in any sense. 

But I think the key was that there—that that was more expensive that they’ve invested millions of dollars to create what is really 

a benign fluid in every sense. It doesn’t have benzene or any of the 

other components that we generally get from crude oil or hydrocarbons. 

So, but if we were not a—if we were overly zealous in forcing 

them to disclose what they had created, they wouldn’t bring it in 

to our State. 

So it was an alignment of self interest to make sure that we had 

a regulatory environment where they could protect their investment in their intellectual property but at the same time be sufficiently transparent so that the Marmel Defense Fund, the NRDC, 

the representatives of environmental quality were willing to say 

this is sufficiently transparent to—we know we understand what’s 

being pumped into the ground. 

The CHAIRMAN. I don’t want to be Draconian, but we have a 

number of Senators who are trying to get in before the break. 

Senator Franken, I’m going to follow up with, though, because 

you’re making good points. 

Senator FRANKEN. Thank you Mr. Chairman. 

The CHAIRMAN. Senator Lee. 

Senator LEE. Thank you Mr. Chairman, and thanks to all of you 

for coming. 

I appreciate your testimony and the thoughtfulness with which 

you’ve addressed each of these issues. 

I’ve got a few questions. I’d like to start with Mr. Liveris, if I 

could. 

65 

In your testimony you suggest that increased exports are likely 

to bring about upward price pressure on natural gas. 

But it appears to me that you may not have taken into account 

the impact that Mr. Gerard referred to a few minutes ago, the impact that would result from increased demand resulting in higher 

prices resulting in increased production activity. Plus, and likely in 

more production of natural gas, perhaps enough to keep the price 

of gas even, or close to even. 

Is it—is that a correct characterization that Mr. Gerard made, 

that we need to take that into account? 

Mr. LIVERIS. So, I made several points. 

Firstly, the world market for gas does not exist; it’s a world oil 

price. 

The world oil price is currently $117 Brent. 

It’s got nothing to do with the cost of world production. 

It’s got nothing to do with the actually the affordability of oil 

around the world. 

It’s got everything to do with speculation and geopolitics. 

Before you index the domestic gas price to the world oil price domestically and this up-swirl that Mr. Gerard refers to, which is 

why you want to export in the first place, I said we are for exports. 

But we should be very careful that we don’t do what is called 

Dutch Disease. Economic theory brings back the highest price back 

to your domestic sector with unintended consequences. 

Be careful of unintended consequences. 

Have the production. 

Have the exploration. 

Gas prices should rise from where they are today. 

They putting in-locking in wells because the gas price is too low. 

We fully expect domestic gas prices to rise, and that’s not even 

a question of—— 

Senator LEE. You’re OK with that? 

Mr. LIVERIS. Of course, of course. 

Senator LEE. Some of this is going to have—— 

Mr. LIVERIS. There should be a return for everyone here. 

A return for the people who have taken the risk. 

A return for society. 

Let’s use some of this bounty and transition to a low carbon economy, as Senator Franken talked about. 

We’re for an all-of-the-above energy strategy. 

Let’s use natural gas as a transition for our economy first. Let’s 

let that up swirl occur as a reasonable return for everyone and for 

American manufacturing jobs and the American consumer. 

That’s a thoughtful approach to how many of these applications 

to approve. 

Senator LEE. OK, so this is what you are referring to on page 6 

of your written testimony then when you refer to the need to promote and enforce policies that would keep prices at reasonable levels. 

I think reasonable was the term you used. 

Mr. LIVERIS. Absolutely. 

Reasonable meaning to cover the risk of everyone in the value 

chain, including the explorers, including the entrepreneurs, includVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00069 Fmt 6633 Sfmt 6602 G:\DOCS\80132.TXT 80132
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ing the producers, but including society that needs smart regulations so as to produce responsibly. 

Senator LEE. OK. One person’s conception—one person’s concept 

of what is a reasonable price might be different than another’s. 

Mr. LIVERIS. Clearly. 

Senator LEE. Who gets to decide that? 

Isn’t that a highly unavoidably subjective standard? 

Mr. LIVERIS. Senator, you would agree that if I go to a completely 

different world, the world of agriculture, who sets world food 

prices? Does the agricultural sector from every country follow everyone’s rules? 

There is rules-based free trade in everything we do, including my 

products. 

I have standards in Japan I can’t meet because the government 

of Japan sets that standard so I can’t export anything from here 

into Japan. 

The oil industry’s quite familiar with that. 

Senator LEE. OK, so you—— 

Mr. LIVERIS. Who sets the rules is where everyone has to be at 

the table and figures out what the right rule for free trade is. 

Senator LEE. OK, so everyone’s at the table and they do make 

their arguments. 

But you’re suggesting a system in which the rule would ultimately be made by the Department of Energy, and you suggest 

that the Department of Energy should implement a rulemaking 

process that would require the Department of Energy to analyze a 

comprehensive list of criteria before they approve any LNG export? 

That one of those criteria ought to include an identification by 

the wood-be exporter of any jobs that might be lost in the manufacturing industry, is that right? 

Mr. LIVERIS. So the current law, the public interest criteria in 

the Department of Energy is our law, your law, everyone’s law. 

You set the law. 

So the regulatory regime has worked in the past by doing it 

right. 

This is a new found bounty. The criteria should be all-of-theabove: responsible production, does society benefit as a whole, and 

is job creation something that is additive here, can we get job creation in the oil and gas sector and the manufacturing sector, and 

I think that should be one of the criteria that the gov-DOE looks 

at. 

Senator LEE. Should—— 

Mr. LIVERIS. I’m not suggesting—— 

Senator LEE [continuing]. Anyone who wants to export anything 

from the United States also be required before exporting it to prove 

to government officials that it wouldn’t cost any jobs in any other 

industry in the United States? 

Mr. LIVERIS. I didn’t actually answer you by saying it should be 

jobs only. 

It should be all of the criteria: 

Senator LEE. But that should be one of them? 

Mr. LIVERIS [continuing]. Food security, national defense, and energy security, in my view, are national interests. 

67 

So the DOE has public interests for some reasons, and I would 

imagine the national interests being at the highest hierarchy. The 

national interests includes lots of things, of which job creation is 

one of them. 

Senator LEE. OK. I see my time’s expired. 

Thank you very much Mr. Liveris. Thank you, Mr. Chairman. 

The CHAIRMAN. Thank you Senator Lee. 

Senator Stabenow. 

Senator STABENOW. Thank you Mr. Chairman. 

I want to talk more about exports, but I do want to start by 

agreeing with Ms. Beinecke that we’ve got to make sure we have 

the public confidence and the safeguards in place to make sure that 

this—that this actually can be done in a safe, responsible way. 

But I do want to follow up as we talk about public interests. 

I find it interesting conversation that we—that there’s some surprise about talking about the need to not only export a new natural 

resource that’s—we have now, that is an incredible opportunity, 

but also weighing how we leverage that, keep it at a reasonable 

cost basis in order to create American jobs. 

It seems to me that’s what our job is to do, is to find that balance 

to be able to do that. 

When we look at what the DOE is looking at right now in terms 

of their studies and so on, I would follow up. Mr. Liveris you talked 

about the 100 new projects that have been announced at a value 

of over $95 billion and that if we keep natural gas affordable, we’re 

looking at 5 million manufacturing jobs and that’s certainly something that seems to me would be of significant importance in this 

economy as we’re trying to turn around, and manufacturing has 

really been inching along leading the way. 

But when we look at the study that the Department of Energy 

has used, to your knowledge did it include the 100 new projects 

and if not, how would that affect the reliability of that study? 

Mr. LIVERIS. Yes, we thank you Senator Stabenow. 

The study did not include the $96 billion of projects that are now 

on the books. It actually used the EIA re-Demand Scenario as of 

2010–2011. 

These projects were not on the books in States like Senator 

Landrieu’s State. By the way, happy Mardi Gras Senator Landrieu. 

We definitely feel that this study should be reexamined. It’s not 

just us that said it’s flawed. Many people have looked at it and said 

this is a part that needs to be upgraded. 

By the way, I think that we should do 2 or 3 or 4 more studies 

and get everything on the table. I think that’s the whole discussion 

we’re having here because one study does not make a strategy. OK. 

One study does not make the decision. 

I think we have lots of inputs to this decision, not the least of 

them being making sure we have responsible supply. 

Senator STABENOW. Would you discuss a little bit more what you 

think is missing from the DOE approach at this point. What more 

would you like to see considered in the broad consideration of what 

we should be exporting and the approvals of the export terminals? 

Mr. LIVERIS. I think it’s trying to describe almost the 

unforecastable. Just like we were here 5 to 7 years ago. 

68 

I—last time, I only ever testified once before. It was on the issue 

of natural gas, and I was actually trying to help the oil and gas 

industry get more drilling rights offshore and get more drilling 

rights to actually produce more. 

So I understand what restricted supply does to markets, but I 

cannot forecast energy demand. No one can, because it’s geopolitical. 

So what we have to do is in the process look at responsible exports over time that allows the win. I talked about. Job creation 

in the oil and gas sector and the exploration side, job creation 

downstream, and not hurting the American consumer with the unintended consequence of bringing the oil price back to the domestic 

consumers’ electricity bills. 

I think there’s lots of factors that can be put into place in there, 

and you’ve mentioned some of them. We can go into it, and we have 

views on it, but I think that’s what we should study in fulsome detail. 

In the meantime, let’s allow exports to our FTA partners. 

Senator STABENOW. Let me just ask in my final minute, because 

it seems to me Mr. Chairman our goal ought to be to export natural gas, but also export finished products. 

Mr. Liveris you talked about the 8 times factor on a finished 

product. Could you tell us a little bit more about how the components of natural gas are used and how many different things 

around us have those components in it? 

Mr. LIVERIS. So the ingredients of natural gas are what we call 

feedstocks, natural gas liquids. The bounty of shale gas is, thanks 

to our great oil and gas sisters and brothers, they—the bounty, the 

geology, is that the gas is very wet, so-called NGO rich. 

A God-given gift. 

This is very unusual. The gas fields around the world are not as 

rich as these gas fields. 

Therefore there’s a new unintended consequence, which is all the 

ingredients for everything from laptops to smart phones to pharmaceuticals to paints and varnishes to carpets to cosmetics, all the 

vital ingredients, 95 percent of them come from fossil fuels. 

The best and lightest fossil fuel is natural gas for the reasons the 

Governor and others have talked about, and natural gas liquids 

should not be shipped overseas and be burnt in Japanese cooking 

ovens. It should be kept home so we can add value at 8 times by 

building these facilities. 

There’s $4 billion an ounce in Louisiana and Texas alone by Dow 

Chemical, $20 billion by Sasol, $15 billion by Shell to value-add. 

This is a big bet that we’re going to get responsible supply and 

responsible production. 

It’s a risk. It’s a managed risk, as long as we don’t interfere and 

create a new unfettered demand for it overseas and stop all this 

value-add in the country. 

We should be thoughtful on how to have our cake and eat it too 

here by doing all these building blocks, all these jobs, small businesses. 

For every supplier to Dow that is less than $50 million in size, 

I build a community. A hundred and fifty communities in AmerVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00072 Fmt 6633 Sfmt 6602 G:\DOCS\80132.TXT 80132
69 

ica—small businesses benefit from this value-add. That’s why 

there’s a job multiplier of 5. 

For every job I create, 5 jobs get created around me. This is why 

it’s a manufacturing renaissance that I never thought I’d see in my 

career lifetime, right here in America. 

Let’s try and get it right. 

Senator STABENOW. Thank you. 

The CHAIRMAN. With the schedule of the witnesses and what 

we’re dealing with in the Senate today, I’m going to call another 

audible. 

Senator Barrasso is going to be back next. He will have questions 

and other colleagues are going to come back. 

We are going to stay here and just keep going. So if you all will 

indulge us, you can be sure, Mr. Liveris, you are going to get your 

discussion of fulsome detail on this question. 

We’ll stand in recess until Senator Barrasso comes back. 

[Recess.] 

Senator BARRASSO. Thank you for reconvening. 

We’ll ask some questions and then we’re going to try to get back 

and forth to vote so that all of you who have traveled great distances and have spent your time will still have an opportunity to 

share your wisdom and your thoughts with all of the members of 

the committee. This is one of the best attended of our committee 

meetings that I’ve ever seen. 

So there’s obviously a great deal of interest in this, even to the 

point that in Investors Business Daily this morning, front page, 

Natural Gas Exports Where The Jobs Are. We’re focused on obviously jobs and the economy. 

Tonight the President promises in his State of the Union, at least 

the White House Press has promised, that he will pivot to jobs and 

the economy. This is apparently his eighth pivot to jobs over the 

last 4 years. 

So I’m—as someone from the State of Wyoming, a State with exceptional amounts of energy reserves, this is a big issue for us. 

Mr. Eisenberg, I’d like to just ask you if I could, is in your testimony you state, quote, the United States ability to challenge other 

countries? existing export restraints will be virtually nonexistent if 

the United States begins imposing its own export restrictions. You 

go on to say U.S. actions are often replicated by other trading partners, to our own dismay, and if the United States went down the 

path of export restrictions, even more countries would quickly follow suit and could easily limit U.S. access to other key natural resources that are not readily available in the United States. 

So, would you please expand on this, in your comments for the 

committee? 

Mr. EISENBERG. Sure, and thank you for the question. 

I should probably preface that by saying we have a team of international trade experts who would be very happy to support any 

questions for the record beyond what I can answer here today. 

Senator BARRASSO. Great. 

Mr. EISENBERG. But yes, I think if you look, certainly most recently, at the China raw materials case that the U.S. just won, and 

we’re in a situation where if we actually turn around and make the 

70 

exact same argument, then we could basically be laying the foundation for further challenges by others to our commodities overseas. 

So, yes, as I understand it there are significant WTO issues here. 

Senator BARRASSO. Dr. Medlock, the—I’d like to ask you about 

LNG exports to national security, and your comments specifically 

made some focus points there. 

Currently many of our closest allies in Europe are heavily dependent on Russian gas. 

Russia has used its natural gas resources for political leverage 

against these countries. 

Other allies are dependent on Iran’s energy. Turkey, a NATO 

ally, receives 20 percent of its natural gas from Iran. In addition, 

Japan, one of our closest allies in Asia imports significant amounts 

of Iranian oil. 

I’ve introduced bipartisan legislation which is not always that 

common here on Capital Hill-bipartisan legislation to expedite 

LNG exports to our NATO allies, to Japan and to others. 

Would you explain how LNG exports would promote the national 

security interests of the United States and its allies? 

Mr. MEDLOCK. As briefly as possible. 

Yes, in fact one of the—— 

Senator BARRASSO. I thought we’d go until somebody else shows 

up—— 

Mr. MEDLOCK. Sounds good to me. 

Senator BARRASSO. Go ahead. That sounds fine. 

Mr. MEDLOCK. In a nutshell, and you’ve already seen a microcosm of markets changing within Europe alone since what’s happened with shale in North America started to happen. 

In particular, you had players that were invested all the way to 

the upstream end to bring natural gas in the form of LNG to the 

United States that were investing very heavily throughout the 

value chain to do that. 

As soon as shale took off in North America, those supplies basically had to find a place to go, and the first point they were actually directed to was Europe. 

What that did was it created pressure on the existing pricing 

paradigms, the existing contractual relationships between large 

buyers in Europe and Russians, and in particular, gas prime. 

What that has basically led to is a destruction of the preexisting 

pricing paradigm, which was one of oil indexation. 

Now what you’ve actually seen is gas prime relent to a lot of 

their major buyers in Europe and actually allow an element of spot 

indexation in their pricing structures, and what that tells you is 

that when you add liquidity to a market, you change a lot. 

What that means is it begins to challenges the revenue—it begins to challenge the revenue streams the gas primes value so 

much and puts them in a very precarious position because no 

longer do they have a captive customer. Now they actually have to 

think actively about price and negotiate on pricing terms which basically changes their negotiating tactics, not only at the bargaining 

table for natural gas, but also around other geopolitical interests, 

visa vie Belarus, visa vie Georgia. 

71 

So we can think about lots of different things that this begins to 

impact because ultimately they don’t want to lose the market. So 

that’s but one example. 

You can think about this spilling over into Asia, as well, where 

the oil index paradigm has continued to persist until recently when 

you actually see CO Gas actually signing up a long-term contract 

for a cost plus, a Hub plus index, for gas out of the Cheniere facility, it’s a bean pass. 

What do you think they’re going to do with that contract at every 

subsequent pricing negotiation they have? 

They’re going to walk in, they’re going to put it on the table and 

say look, I want a gas index deal because I’ve got one and I’ve got 

a line of suppliers willing to provide it to me. 

It changes everything. 

It’s about liquidity, and that’s something that has been lost in a 

lot of the comments I’ve heard today, as there’s been no discussion 

of what liquidity actually means for the way commodities are 

priced. 

Gas has been indexed to oil because it has not had liquidity. 

That’s something that’s changing in a dramatic way largely because of what’s happened with shale in this country. 

Senator BARRASSO. Thank you, appreciate it. 

Mr. Gerard, I’d like to ask you about natural gas production on 

public lands, Federal public lands. 

Many in Congress are looking for ways to create jobs while at the 

same time raise revenue for the Federal Government. 

We can do this by increasing natural gas production on Federal 

public lands, in my opinion. Right now companies are unfortunately shutting in natural gas production on Federal public lands. 

Workers are losing their jobs. 

Federal revenue is being lost, so would you explain how LNG exports will help create jobs in this country and increase revenues to 

the Federal Government? 

Mr. GERARD. I think there’s 2 issues there Senator. 

The first relates to the public land itself, Federal lands, and of 

course there’s a question there of leases, permits, etcetera. Unfortunately today, production coming off Federal lands generally is 

going down. The number of permits, the number of leases are going 

down. You’re seeing a great disparity being created between Federal land and private land. 

I think the Congressional Research Service sent a report to 

somebody here in the Senate-recently reported that this vast Shale 

Gale we’re talking about, particularly in unconventional resources, 

96 percent of that increase in production in the United States is 

occurring on State and private land. So we’ve got to get the politics 

right and the permitting right, back to the Governor’s earlier comments about the need to be more efficient and thoughtful and actually allow access to the Federal land. 

Now a lot of the resource we’re talking about today excludes the 

potential for resource on the Federal estate. For example, today 85 

percent of the outer continental shelf has been placed off limits. 

We’re not sure just how large that resource could be. 

So when we have estimates talking specifically about natural gas 

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72 

tiples of that if we had true access to the Federal lands to develop 

it there. 

Laws of supply and demand will show that if given the access to 

produce what we have on the Federal estate clearly could help 

meet any demand for LNG exports would once again find the market. 

The issue today is not a supply question. We have abundant supply. It’s a demand question. How do we make sure there are markets in place that we can fill? 

LNG export is a perfect opportunity and that’s why under the 

Natural Gas Act we would strongly encourage the Department of 

Energy to move quickly to approve those. 

The market will sort out who eventually builds those facilities, 

but if we don’t get there quick, for all the other economic reasons 

we talked about, that’s going to be filled by somebody else, and 

we’re going to miss the window. 

Senator BARRASSO. Could you talk a little bit about how the 

BLM’s pending hydraulic fracturing rule could hurt jobs and decrease Federal revenues? 

Mr. GERARD. It goes back to the same issue of our ability to 

produce on the Federal land and back to what Governor 

Hickenlooper had said earlier. 

Historically oil and natural gas have been regulated by the 

States. For the past many, many years there’s been a good relationship between State and Federal Governments, in terms of permitting access to the land and eventually producing the energy on 

those lands. 

When you add multiple layers, particularly Federal layers, that 

potentially conflict, confuse, and further delay, it further discourages the private investment on the Federal land. 

So once again you create a great disparity in where the investment dollars move away from the Federal estate because they 

know there’s a better market opportunity on private and State 

land. 

The days to permit on private land—you’re looking at places like 

North Dakota, today the second largest oil producer in the country. 

It takes days or weeks to get a permit compared to months, and 

in some instances years, to get a permit on Federal land. It’s a big 

difference and something that ought to be looked at by the committee. 

Senator BARRASSO. Mr. Eisenberg, I want to get back to you. You 

talked about the National Association of Manufacturers and how 

they strongly oppose using NEPA to require cradle-to-grave 

lifecycle impact analysis that assesses the impact of exported cargo. 

Explain the EPA’s asked Federal agencies to conduct such an 

analysis for LNG export terminals and coal export facilities in the 

Pacific Northwest, You go on to state that such a move would create a very dangerous precedent that could be used to block exports 

of all types. 

So the question is: would you please elaborate on the types of exports that could be negatively impacted by the EPA’s proposal? 

Mr. EISENBERG. I mean, we’re—thank you very much for that 

question, Senator. 

73 

We are very worried that if we get a precedent that requires a 

lifecycle cradle-to-grave environmental impact analysis that the 

possibilities truly are endless for what you could block to export. 

Looking at the coal export projects in the Pacific Northwest, 

what some have called for up there is to go all the way back, to 

take an exam-underneath the impacts of the mining, which are already permitted things, the transportation, the construction of the 

port, the shipping overseas, and then the ultimate burning of the 

commodity. 

It would be a significant change in law and policy to look at the 

environmental impact of cargo, and this is something that can, I 

think, all manufacturers really have a concern about because 

where do you draw that line? Is it agriculture, I mean you could 

really bend this in a way—— 

Senator BARRASSO. Could it be automobiles? 

Mr. EISENBERG. It could be automobiles. It could be planes 

Senator BARRASSO. It could be airplanes, heavy equipment, tractors. 

Mr. EISENBERG. Anything. 

So manufacturers are very, very concerned about heading down 

that path for no matter what that commodity is. 

Senator BARRASSO. Thank you very much. 

Mr. Liveris you argue that we shouldn’t export LNG so we can 

create jobs here in the United States, and you say that you just 

want to see natural gas exported in solid form products instead of 

liquid form. You say you want to give American companies the opportunity to add value to natural gas and earn a higher return for 

the resource. 

Why shouldn’t, you know, the Federal Government set up a policy to benefit manufacturers higher up on the value chain? 

You know, why shouldn’t you just limit exports of chemicals so 

that domestic manufacturers can add value to them before they’re 

shipped overseas, and the question is where you draw that line, 

isn’t it? 

Mr. LIVERIS. Actually in my testimony Senator I didn’t actually 

say that it’s either or. In fact I went to great lengths to say it’s and. 

I think we should do both. 

We should export LNG, and I think definitely we should look at 

the public interests with respect to our NATO allies. 

That’s something we should have on the table. 

But in addition, let’s put the power of the and in place. 

Let’s look at the unintended consequences of a non rules-based 

free trade market, gas. One day it may well have the liquidity to 

be a rules-based free trade market, but today it does not. OK? 

The unintended consequence of trying to do one or the other is 

you transfer the risk away and you let the risk be assumed by 

American manufacturers and consumers to the positive of someone 

else being de-risked overseas. 

Let’s do both. Let’s have exports and look at the intended—unintended consequences on domestic consumers. 

Senator BARRASSO. Mr. Medlock, can I ask you to respond to 

what Mr. Liveris just said? 

Mr. MEDLOCK. Sure. 

74 

Liquidity is something that is gained as markets mature, as you 

have more entrance of suppliers and demanders and that’s precisely what we’re seeing in natural gas markets around the world 

right now. 

If you do anything to impede that progress than you slow that 

progress of liquidity, you actually end up creating rents along 

pieces of the value chain. 

In this particular case, let’s say hypothetically there was a cap 

placed on the amount of LNG that could be exported that was a 

nonmarket cap. Basically what you do is you provide rents to those 

first movers, the ones who actually build the export infrastructure 

because the prices will never adjust abroad to actually bring them 

down so that you actually end up with super profits basically for 

companies involved in the export business. 

So, I would not promote that because by actually limiting how liquidity grows you actually support certain elements of the value 

chain which is not competitive, to be quite frank. 

Senator BARRASSO. Thank you. 

Senator Coons. 

Senator COONS. Thank you very much Senator Barrasso, and 

thank you to the panel for a chance to be with you. 

I’m excited that this first energy committee hearing is focusing 

on such a basic question about how we embrace the broad energy 

future in front of us. 

Let me start if I might with Mr. Eisenberg and Mr. Liveris, from 

NAM and from Dow. 

Just regarding the potential approaches for how to balance the 

factors that you’ve spoken to: the competing environmental, economic, and national security interests. You note that policymakers 

should aspirationally rely on the best quality information, on objective material, and on metrics that allow making the best decision 

in a public policy process. This is because of the inherently limited 

nature of projections and modeling, particularly for world market 

conditions, especially in energy. 

What type of systems do you suggest might be put in place to 

evaluate ongoing and potential impacts intended—not intended, 

even while the DOE and FERC licensing processes are underway. 

In your view, if we phase in licensing for export of natural gas, 

what would be the most prudent timing in which you would phase 

that at? 

Mr. EISENBERG. Thank you. 

I do think, and as you know in our testimony we do call for the 

best quality information in this process, and I think it’s important, 

and this is a question that Senator Wyden raised in his comments 

on the DOE study, which are that they used the 2011 Annual Energy Outlook Statistics, and we absolutely agreed that that should 

be updated. 

But at the same time that can be updated while the permitting 

process is ongoing. Right now we are building none. We are permitting none. We have a complete moratorium. So let’s get on with it 

and continue to have the best quality information for the fact-specific determinations that DOE must make as they go through this 

licensing process. 

75 

You know, there is, as Mr. Liveris said, there are 2 studies that 

DOE has done on this matter. There—I read them over the weekend. There are no shortages of studies out there that Delloyd and 

IHS and others are doing on this issue, and I appreciate and am 

happy with the continuing dedication to understanding the impact 

of this. 

But that’s not a reason not to let the free market work. We—our 

policy says that we fundamentally believe in free trade and open 

markets, and we do. We view it with respect to this and just about 

any other commodity. 

So we think we can have it all here, and we do think that we 

should strive to have the best quality information. 

But it shouldn’t be a reason to continue with the moratorium. 

Senator COONS. Thank you. 

Mr. LIVERIS. Senator Coons, I’m all for studies and consultants. 

I’m all for academia, but they don’t buy gas. 

I buy, as Dow, more gas than most countries. OK? So we are a 

significant purchaser of this risk and, therefore, when you fool with 

this risk by not having the public interest in mind in its totality, 

you have to get your criteria right by looking at all the angles. 

All the angles did not get looked at 10 years ago when we deregulated power in the19 90s in the Clinton era. It had an unintended consequences to the domestic sector. 

We had gas prices spiking as high as $15 and $18 and $20 per 

million BTU. 

Manufacturing was fleeing the country. Factories were being announced across the world. It wasn’t labor offshoring. It was energy 

offshoring. 

Energy is the lifeblood of an economy in all of its forms. 

In its value-added form, the one that Senator Stabenow asked 

me about, the consumer, the home heating bill of the consumer, in 

all of its forms. 

So be careful of one or 2 or 3 studies giving you the absolute criteria. As you said in your comments and Chairman Wyman made 

comment, as well, no one gets this right. 

We’re in the 4th or 5th year of trying to understand what this 

bounty is. Can we produce it responsibly across the country? There 

are regions that differ already. We know that. The geology is different. We don’t know how much supply we have. 

Let’s be careful testing our country on when a market gets to 

maturity on liquidity risk. Why should we take the liquidity risk 

as a country in a totality while someone overseas benefits from our 

bounty. 

Be measured in the criteria, let’s crawl-walk-run through these 

applications. 

Exports should be allowed. They should be allowed through our 

FTA partners, that’s the public interest. 

Develop the criteria as we go along. 

Figure out what the unintended consequences are. 

I want to clarify I said over and over, there is no such thing as 

free trade. It’s rules-base free trade. 

There is no GATT, there is no Doha. Why? Countries don’t agree 

on the rules. 

76 

What rules are we agreeing to here when we decide to approve 

12 applications overnight? 

Be careful that we look at this treasure and set the rules with 

America in mind. That’s all. 

Senator COONS. Thank you Mr. Liveris. 

I’m very sympathetic to the strong perspective you’ve presented 

that urges us to focus on job opportunities and on the difference in 

portability between natural gas and petroleum. 

Natural gas is distributed throughout the United States largely 

by a robust, nationwide network of more than 300,000 miles of 

pipelines, and we have a remarkable transmission capacity in the 

United States. If I understand right, we’ve had a more than 50 percent increase in pipeline capacity since 1995, and I just wondered, 

Mr. Gerard, if you had any comment about the policies that have 

been adopted that have helped facilitate that creation of that significant robust nationwide transmission infrastructure? 

Mr. GERARD. It’s a great question Senator. One that we, I believe, need to turn our thoughts to more often. For example, the infrastructure issue in the United States will help facilitate to continue to drive prices down for commodities, particularly for oil and 

natural gas. 

Yet today we find ourselves hamstrung in some circumstances, I 

think as Mr. Eisenberg spoke of earlier in permitting processes. 

But that infrastructure that exists today needs to be expanded to 

truly seize the opportunity we have before us to become an energy 

super power. 

Where Andrew and I might take a strong difference is there are 

other aspects of this view that we need to think of, as well. That’s 

the job creation opportunity in the oil and gas sector itself and the 

opportunity to have it all. 

But the government can’t better—can’t understand that risk any 

better than the private sector can. So the worst thing for us to do 

is to get the Government in the process to try to determine through 

an export mechanism what that price should be. 

If the market signal to my people is that there’s going to be a 

limitation on where that demand might go, they then pull back on 

their rig counts, on the production itself. So you have a reverse adverse multiplier effect throughout the economy because you’re limiting potential demand where that market can go. 

As I mentioned earlier, we shouldn’t underestimate supply is not 

the issue. We have a vast supply, and it’s by and large due to our 

modern techniques and technologies. 

It’s really a question of demand and if we get the government involved in limiting demand through slow walk processes, review 

after review after review, we’re then at a disadvantage in the global market because there are others pursuing that market very aggressively and providing liquidity to the natural gas market. 

Senator COONS. One of the mechanisms, if I might Mr. Gerard, 

that I understand has made possible the financing and construction 

of a world class transmission and terminal system in this country 

is a tax structure called Master Limited Partnerships. 

In your view have master limited partnerships been essential to 

deploying and developing the natural gas infrastructure of the 

country? 

77 

Mr. GERARD. Yes, they’ve been very important to us. In fact I 

know there’s talk now of potentially looking at the renewable space 

in the energy development, something we and the oil and gas industry strongly support and spend billions of dollars to try to figure 

out those new technologies. 

But yes, they are important because they allow us to bring in investors and others, not to put their resource at risk, so that we can 

bring these commodities to the marketplace. 

Senator COONS. Does that strike you as a structure that might 

be able to support both natural gas, oil development as it has in 

the past, and renewables? It would literally be an all-of-the-above 

financing strategy. 

Mr. GERARD. I know folks are looking at it and I understand you 

are as well Senator. 

We’d be happy to get some people much smarter than I am to 

take a close look at that and come back to you with some details 

on how that might be viewed in the marketplace. 

Senator COONS. Thank you. I’d be grateful. 

Mr. GERARD. Thank you. 

Senator COONS. Before I yield the gavel to Senator Alexander, I’d 

just if I might—a question to Dr. Medlock and Ms. Beinecke. I also 

chair the Africa Subcommittee on Foreign Relations, and I’m interested in what you think of the potential impact of natural gas development on Africa. They’re fully exploiting both the dramatic new 

offshore gas discoveries and the potential for shale gas, which exists in many places across the continent. 

What positive or negative consequences might there be for U.S. 

businesses and technology export and how might this affect development trajectory of the continent? 

Ms. BEINECKE. I’m going to defer to Dr. Medlock on that because 

I don’t—haven’t looked at the issues in Africa, and so I don’t, we 

don’t have an opinion on that. 

Mr. MEDLOCK. So, at a very high level, certainly the discoveries 

off the east coast of Africa: Tanzania, Mozambique, those portend 

to really convey a tremendous economic benefit to a region of the 

world that needs it. 

There are large shale gas resources that have been identified in 

Algeria, already a large gas producer and supplier to Europe, but 

also in South Africa, an area that hasn’t really seen a lot of natural 

gas development in the past. 

So the potential for, you know, the conveyance of benefit is definitely there. 

I think the thing that you really have to think about that differentiates Africa from the United States is the regulatory overlay. 

In particular, when you think about the mechanisms in place in 

the United States to really insure the safety of the general public, 

the safety of the environment, the safety of the workers involved 

in these activities, those mechanisms don’t exist, more or less, anywhere else in the world the way they do here. 

So I think, you know, a real understanding of how to carry what 

we’ve learned in this country, being such a large oil and gas producer for so many years abroad we really will sort of help to allow 

the development in a responsible way of those resources. 

78 

Senator MURKOWSKI [presiding]. Senator Coons, we’re over time. 

I’m sorry. 

Senator Alexander. 

Senator ALEXANDER. Thanks Madame Chairman. Thanks to the 

witnesses. I see the chairman and the ranking member here. I 

want to thank them both not just for the subject of the hearing, 

but for the even-handed way in which they’ve pursued this, and I 

really appreciate that. I’m looking forward to working with them 

on this committee. 

Just an observation and then a question. The observation is 

maybe one thing we can agree on here is that energy research is 

a good thing. I mean it’s hard to think of—well this is an overstatement, it’s hard to think of an important technological advantage 

over the last couple of years that hasn’t had some government research and as the earlier discussion went back and forth with unconventional gas clearly the Department of Energy Demonstration 

Project, maybe even the Tax Credit, the Sandia laboratories work 

on mapping all of that was essential, but I keep thinking that-that 

maybe we actually have an energy policy in the United States and 

don’t know it and it boils down to government sponsored research, 

private ownership of property, entrepreneurial attitude, big market 

and free market and that all of those things have suddenly given 

us what amounts to a terrific advantage in energy. 

I was in Germany recently, and they’ve got a big complicated 

CAP and trade. They’re closing their nuclear plants. They’re buying 

nuclear power from France. They’re subsidizing Chinese solar panels and they’re buying coal from the United States so we-we’ve 

ended up with a pretty sensible policy and the one thing it would 

seem to me that it would encourage that would be doubling the 

amount of Federal dollars we spend on research for such things as 

what do we do with CO2 from coal plants, how do we get a better 

battery that’s been mentioned by several people in terms of storage, etcetera. 

Now here’s my question: Do we really have a problem here? I 

have 3 images in my mind. 

One is this weekend I went quail hunting in south Texas and we 

didn’t find any quail because of the drought. But what we found— 

I hadn’t been there in 3 years in that section. We were in the midst 

of the Eagle Ford shale and there were 5 motels where there was 

one, there were oil rigs everywhere, there were new networks of 

roads, there were big lakes, big trucks going back and forth. I 

mean it’s an astonishing thing, gas flares everywhere so it’s easy 

to see the great production value and the dollars that come in 

North Dakota and south Texas in our economy from this production. Now that’s one image. 

The second image is Australia last year where they’re selling 

their gas to Asia at 5 times our price. Not only are they selling it 

to Asia at 5 times their, our price, they’re paying 5 times our price 

for their own gas because they’re paying the world price for natural 

gas. I think back to Tennessee about the number of workers at 

Eastman Chemical, about the farmers we have, about the auto jobs 

we have, about the truckers we have, and I see the enormous, incredible advantage the United States has at the moment from having a domestic price of natural gas. It’s really a Godsend, and it’s 

79 

very unusual, and I think our policy got us there, but I think we 

should examine it very, very carefully which is what we’re doing 

today. I suspect it’s a much bigger source of jobs than the production value of oil and gas is in the United States. The production 

value of all the farmers, all the chemical companies, all the manufacturers in our State is a huge advantage. 

Then the third image I have is the United States going into Iraq 

because of oil and because Iraq had gone into Kuwait and there we 

are. So while I’m a big free market, free enterprise person, I also 

see the value of the domestic price. I don’t want to lose that. I also 

see the national security consequences of this. 

So my question is, though, do we really have a problem? 

One witness said that we might not export more than 5 or 6 bcf. 

That’s about 10 percent of what we produce today, if I’m correct. 

Is that about right? At what point at what percentage of exports, 

and let me just go down the line and ask this question. If we don’t 

have time today to do it, maybe you could write me out—the question has an A and B part. A—at what point—at what percentage 

of exports begins—do we begin to lose the domestic price advantage 

of natural gas that we have today and No. 2, under present policies 

if you had to make a guess, what would be the range of the percent 

of our natural gas production that we’d be exporting in 10 years? 

Mr. LIVERIS. I can’t help but pass up the comment on my home 

country of Australia who’s desperately got it wrong. OK? 

It’s one of the only gas rich countries of the world that, in fact, 

has the phenomena you just talked about. So, one sector exports 

from the Northwest shelf of Australia, the oil price bleeds back into 

the Southeast corner of Australia, manufacturing is collapsed, and 

2 of the 5 most expensive cities in the world are Sydney and Melbourne. The retail prices are through the roof. 

So if you want a poster child for getting it wrong, and this may 

cause me never to get back to my home country but I’m going to 

say it, my home country is the poster child. 

So, the questions. Is there a number? It’s unknowable and 

unforecastable which is why I believe the process has to work with 

the public interests as its lens. Every single one of these applications as you build up these terminals from one to 2 to 3, from 2 

billion mcf to 3 to 4 to 5, the market will send a signal. I’m a free 

marketer, but the market sends signals like it did in 01–02 when 

the market read there wasn’t enough gas to meet current demand, 

the price went through the roof. 

Eastman and other companies like Eastman suffered the consequences. 

So we’ve got to be careful. The market will work. 

But don’t just flood the market with one answer. It’s not an either or. Don’t do 12 bcf. Don’t do 20 bcf. 

Senator, I can’t give you the exact number. I’m not that smart. 

All I can tell you is this is not an open market. As I said, LNG, 

you have to work hard to make LNG work. 

So I would think that as these terminals get built, we’ll get the 

better of job creation upstream and job creation downstream. I already indicated that’s a 5 times multiple. 

We can get the farmers to win, we can get the Eastmans to win, 

we can get the consumer to win, and we can have exports. 

80 

The CHAIRMAN [presiding]. Thank you Senator Alexander. 

Senator Heinrich. 

Senator HEINRICH. Thank you Mr. Chair—— 

Senator ALEXANDER. Mr. Chairman can I ask that the witnesses 

answer that question in writing after the hearing? 

The CHAIRMAN. Yes, that would be great. 

Senator ALEXANDER. Thank you. 

The CHAIRMAN. Senator Heinrich. 

Senator HEINRICH. I want to thank Senator Alexander for his 

comments about basic research and development. Obviously Sandia 

National labs played a real role in the fracking phenomena, but 

also in a whole range of energy development and research over the 

years and that ought to be something I think we can agree on that 

that is a good thing. 

I want to ask our witnesses today about something that hasn’t 

received a whole lot of attention yet but Mr. Liveris touched on it 

during Senator Stabenow’s comments, and I want to drill down a 

little further and get people’s thoughts on this and maybe Mr. 

Liveris, Mr. Medlock, and anyone else who wants to comment, it’s 

the issue of wet versus dry gas and we’re talking about natural gas 

here today, but that means many different things and certainly 

what gas provides these feedstocks that have been discussed as a 

lever, a job, as a lever to create more jobs than just the energy production. 

Then we also have in New Mexico we have basins that some are 

wet and some are dry. So what I wanted to ask is do our policies 

and does the market, and I’m not going to describe this particular 

market as a free market because I don’t think it is yet, but do our 

policies both at the Federal level and then do the economics recognize the distinctions between these different products between natural gas liquids, natural gas and the fact that it may have very different ramifications to export dry gas to be used as an energy support versus exporting gas that is rich with these natural gas liquids 

that are so important for the manufacturing sector, and how do we 

make sure that as we move forward that both our policies and economics align with those job creation goals. Mr. Liveris and 

then—— 

Mr. LIVERIS. Yes, I think it’s a very, very educated question Senator, so thank you for asking it. 

It allows me to make a new point and that is exactly your point. 

Wet gas, the LPGs, propane and butane, do have a market. The 

market tends to work. It’s the fuel equivalent of cooking oil and 

home heating oil so if you extract propane and butane, yes it can 

go to petrochemicals and other uses but it has a heating market. 

That market is out there and it’s working. No one is suggesting 

anything different. 

The real toggle in this conversation is that other ingredient that 

only chemical engineers like me talk about and that’s called ethylene. Ethylene is unfortunately—can stay in the gas. It doesn’t get 

rejected. 

It can go to Japanese power stations and when they set the BTU 

speck they like to keep it in because it gives them more BTUs. 

They like to pay the domestic, they like to pay a gas price for a 

rich ingredient. 

81 

Some of these countries actually extract it and add value to their 

own countries. So I think every country in the world who extracts 

ethylene goes to the trouble of answering your question in a very 

educated way. They put aside the ethylene for their domestic economy. 

Now that sounds like interrupting free markets doesn’t it? But 

ethylene doesn’t trade. There is no real world ethylene price. I can 

get ethylene in Saudi Arabia at a very different price than I can 

get it in the United States. 

That’s where I think we have to be very measured on what we 

export, but that opens up a whole new line of questioning, and I’m 

happy to answer it at some future time. 

Senator HEINRICH. Mr. Medlock. 

Mr. MEDLOCK. Just real briefly with all of the longer chain hydrocarbons which you’re talking about here gas processors when 

they actually see the gas at gathering systems come to them will 

make a decision about the value of extraction versus the value of 

leaving a certain component of those longer chain hydrocarbons in 

the stream. 

In a situation where the ethylene price and the propane price 

and the butane prices are actually elevated sufficiently enough, 

then you’ll see them extracted. You’ll see leaner gas. 

It has to be within a particular range if it’s going to be pipeline 

inspected in the U.S., but there is a market mechanism that actually drives how high that gas is in effect. 

Senator HEINRICH. Is that highly dependent on that sort of the 

state of infrastructure and the local conditions because many of 

these things are being produced in places that don’t have the long 

history of infrastructure that say the basins in the Southwest like 

New Mexico and Colorado have? I mean—— 

Mr. MEDLOCK. Oh certainly it does, certainly it does. You’re talking about gas coming on line say in south Texas. This is an interesting example actually, what’s happened in the Eagle Ford and 

what it’s done to actual NGL prices at Mont Belview. 

You’ve seen a massive disconnect between where Mont Belview 

NGL prices have been in the past couple of years relative to where 

they were in, previously in relation to crude oil prices and it’s because you’ve got a lot of NGLs coming into the market that are 

being extracted because there’s high value associated with them. 

But what that’s done is it’s led to a glut in that particular market and so it argues for infrastructure. 

Mr. GERARD. Senator I’d just like to say quickly, yes, it does have 

a market because if you watch our rig count, you’ll see it move 

from what we call the dry gas to the wet gas. I would also add one 

of the great benefits, particularly the manufacturing sector today, 

more specifically even to chemicals, is that we are now at record 

highs, unprecedented highs for natural gas liquids production in 

the United States. 

It’s a very significant development by and large as part of associated development with natural gas. 

Senator HEINRICH. Mr. Chairman, I yield back. 

The CHAIRMAN. I thank my colleague. 

82 

We appear to have another vote, so I think we’ll go with Senator 

Manchin at this time and obviously Senator Cantwell’s great expertise in this area, so we want to get her in too. 

Senator Manchin. 

Senator MANCHIN. Thank you so much Mr. Chairman and Ranking Member Murkowski. 

Let me just say first of all as one of the greatest concerns I think 

all of you, and I think I know that Mr. Liveris that you said I’m 

more concerned about how we start getting priced, who controls the 

American pricing, and once you go into that overseas market you 

lose your ability to set your own destiny. Is that correct? Is that 

probably one of the—I mean people are coming to me and saying 

you know you keep telling us how much oil you’re developing now 

in America but our gas prices haven’t gone down. How come? 

Mr. LIVERIS. Yes, the ultimate point here is that energy, its fungible price around the world basis is oil. 

Make no mistake. Everything else is domestic, nuclear, even coal 

tracks oil. 

Senator MANCHIN. Has OPEC always controlled the pricing of 

oil? 

I mean we developed our Nation on oil we found. We have a 

State that was rich in oil back at the turn of the 19th century/20th 

century. 

Mr. LIVERIS. State-owned enterprises own 75 percent of the 

world’s oil reserves and 50 percent of the production. 

So State-owned enterprises (OPEC) from the early 1970s to this 

very day sets the world price based on supply. 

They regulate supply. You know this, right? 

Senator MANCHIN. I don’t think anybody in the gas industry 

want that to happen to gas prices, would you? 

Mr. GERARD. Senator, let me respond to that if I can first as it’s 

been predicted due to this great technology we’ve been talking 

about, this game-changing opportunity. 

Experts now predict if we continue down this road that the free 

market has brought us, the United States will surpass Saudi Arabia as the No. 1 oil producer in the world in 7 short years by 2020. 

We can ultimately have an impact and it all comes back to the free 

market. 

That’s why we’ve got to be very sensitive and mindful of attempting to intervene or to manage price or spots in the marketplace. 

Senator MANCHIN. When you, and I’m so sorry we’ve been running back and forth in committees but I’ve been keeping up with 

what was going on here, you all do agree that basically this is our 

last great chance to have this type of a find in energy that could 

be game-changing for our country. A renaissance in manufacturing, 

transportation fuel, and what I think the question was asked by 

the Chairman, where’s the sweet spot? 

What I think we’re saying is how can we work with you on exporting certain amounts, give us a timeframe to build up the demand in this market here in the United States? 

Can you all live with something like that? 

Mr. GERARD. Senator, most of us believe we’re just at the front 

end of this Gale, if you will, both on shale gas and oil, that we 

haven’t yet fully appreciate, just recently there was an announceVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00086 Fmt 6633 Sfmt 6602 G:\DOCS\80132.TXT 80132
83 

ment in California at Monterey which some estimate to be an oil 

reserve 4 times larger than what we found in North Dakota. 

Senator MANCHIN. But that didn’t do us any good at all because 

the price is still $4 a gallon. At $3.50 to $4 a gallon so you can find, 

until the cows come home. 

Mr. GERARD. It all comes back to supply and demand. It comes 

back to what we produce and how we put that into that global marketplace. Trust me—— 

Senator MANCHIN. To be on a level with a consumer in America 

today hearing reports that we have more energy now and we’re 

about to be a net exporter, and yet they haven’t seen any of their 

costs come down? 

Mr. GERARD. No, let’s use natural gas as a price as a great—as 

an example. That’s a great question. 

Today as a result of the natural gas price coming from about $14 

to $3, the average family in America that consumes natural gas 

costs have gone down $1,000 a year. That’s estimated to increase 

to a couple thousand dollars year as we become even more energy 

efficient. 

Senator MANCHIN. OK. 

Mr. GERARD. So there is a very significant consumer-positive consumer impact, not to mention the environmental benefits, etcetera, 

as the Chairman’s—— 

Senator MANCHIN. I think finally the question I want to try to 

get to—I’m looking for the—I guess as the Chairman keeps saying 

the sweet spot. There’s got to be an area where we can say OK we 

can with the prudent measures we have with the anticipated reserves we have export this much. We can dedicate this much time 

to develop the markets in America. We can transform our 

transportational fuels. 

I’ve always said that I thought every State when I was a Governor if someone said listen, we’ll help you transfer all of your commercial fleet which would be our school buses, our mass transportation, our State road vehicles into gas-propelled vehicles working 

out of bulk stations. It would be the most cost-effective thing we 

could do. We could develop that within a 5-year period. We could 

have a renaissance in manufacturing. We have the crackers as 

we’re talking about. If that’s a possibility we need some time to develop that. That’s what I would be asking for. 

What is the time period? If we don’t hit that mark, and let’s say 

it’s 10 years, then we should open up the market completely. If we 

can’t get our act together, go for it gentlemen—and ladies, I’m 

sorry. Let’s just do this. 

Mr. GERARD. Senator, Senator, I guess the thing that concerns 

me in your comment is how you manage that, that development. 

Where we are today, the opportunity’s been created that no one 

would have predicted 5 or 6 years ago because the market found 

that equilibrium. It found the opportunity to put the downward 

pressure on the price. 

The same is true of the discussion that we’re having. The market 

will find that. Let’s let the market fine-tune that recognizing we 

have a vast supply in the United States which is what’s driving 

that price today in this country. 

84 

The CHAIRMAN. My colleague and I are going to miss the vote. 

We’re going to let you all have about a 10 minute recess and then 

we’re going to come back. 

Senator Manchin’s asking important questions we need to continue to dig into. 

Thank you all. 

[Recess.] 

The CHAIRMAN [Presiding]. The committee will come to order. 

Senator Manchin was practically in mid-sentence so he is going 

to raise his additional question and then Senator Cantwell. 

Senator MANCHIN. I think where I am—if I can get an answer. 

Has anyone come to an agreement identified on a reserve, an 

amount of reserves that we have, proven reserves that we have and 

how many years based on demand right now? Because I read yesterday that no one can agree on anything—brightest people in the 

country. 

Mr. GERARD. It continues to change Senator. In fact—— 

Senator MANCHIN. OK. 

Mr. GERARD. Six/seven years ago someone estimated that it was 

about 20 to 30 years. Most recently the EIA has estimated that it’s 

at least 90–95 years. Other independent analysis—ICF, etcetera 

have estimated it’s 150 years, and there’s some who’ve believe it’s 

200–300 years worth of supply at current levels of consumption. So 

that’s—— 

Senator MANCHIN. That’s a good thing. 

Mr. GERARD. It’s evolving quickly because of breakthrough technology as we define more resource. It’s going up dramatically 

quickly. 

Senator MANCHIN. Here it is. I am—I come from the private sector. I’m a free trader, and I’m concerned. I’m concerned that we’re 

going to lose this opportunity of a lifetime, generational if more, if 

not more. 

But there has to be a balance too. That’s what we keep looking 

for, that balance. So if we’re saying we had a 10-year window and 

we come to an agreement with the industry that as government, 

we come to an agreement for a 10-year window that will have X 

amount of exporting while we develop the demand in this country 

basically on transportational, manufacturing and other things that 

we can develop that was left us that will come back, I think Mr. 

Liveris’ company has been all over the world and they’re coming 

back because of this energy, and making sure that we never get 

caught in a world pricing such as an OPEC. Those are the concerns 

I would have as a citizen of this great country and definitely as a 

U.S. Senator from my constituents. 

I think that’s what we’re asking, and I’ll use this as a hypothetically. Let’s say we agree to 5 bcf a day, just for the sake of 

throwing a figure out. How—what are we exporting now? 

Mr. GERARD. Virtually none. Small—— 

Senator MANCHIN. OK. So 5 billion, 5 billion, 5 bcf a day is pretty 

substantial, correct? 

Mr. GERARD. Less than 10 percent of what we currently produce 

and consume. 

Senator MANCHIN. OK. So 10—so if you’re going to err on the 

side of caution while we’re building up our consumption in this 

85 

country, I’m not saying that’s a hard rock figure, but let’s just say 

for, and we have a 10-year window, f we can’t get our act together 

and have an energy policy that works for this country, then all bets 

should be off, and you should be able to do whatever you have to 

do. 

That’s what I think we’re kind of talking about and asking if 

that’s a possible—and I understand sitting, if I was sitting where 

you, I would be cautious about that. 

Mr. GERARD. I don’t want to comment on your ability to get an 

energy policy in the next 10 years but—— 

Senator MANCHIN. No, no we’ve got to move quicker than that. 

Mr. GERARD. But let me respond this way Senator. I think the 

key is to look at the market fundamentals. 

Senator MANCHIN. Yes. 

Mr. GERARD. What happened today, and I can’t overstate this, 

what is happening today is unprecedented in the history of our 

country in terms of our opportunity to become energy secure and 

self sufficient. Just think back 5 or 6 years ago nobody was having 

this conversation. Today we’re the world’s No. 1 gas producer. 

It’s now estimated through this advancement in technology, we’ll 

be the world’s No. 1 oil producer by 2020, 7 short years. That’s how 

significant this is. 

That’s why we’re very reluctant to go down a road where we say, 

well, let’s take this great opportunity that indicates where you’ve 

got vast supplies, and now let’s bring the Government in and see 

where we can manage the development of the market. 

Senator MANCHIN. Do you think it’s a fair evaluation when you 

look at all of the human sacrifices this country has made because 

of our lack of independence on energy? 

It’s a tremendous price we’ve paid in human life and value, if you 

would. 

Mr. GERARD. I think the point, Senator, is if we’ve, again, going 

back to the supply, we’ve got ample supply, we’ve got vast supplies 

as far as the eye can see. 

What we’re seeing domestically, and those job numbers we’re 

talking about are so realistic. Production in Pennsylvania. Who 

would’ve thought? Pennsylvania is a huge natural gas State today. 

Your good State today, as you know, is on the verge of a major 

breakthrough to become a big producer. Pennsylvania production 

has gone up 526 percent. 

Senator MANCHIN. We’re trying to create the jobs in West Virginia to use the product you’re unleashing. 

Mr. GERARD. I understand, I understand. I’m just using that as 

an example because of what’s happening all across the country 

where we least expect it, Ohio, etcetera, etcetera. We’re creating 

hundreds of thousands of new jobs, and we don’t need to view it 

as we used to view it in terms of scarcity. We don’t have a scarce 

resource anymore. It’s abundant. It’s rich. 

Senator MANCHIN. I’ve heard that before. I’ve got to be honest 

with you. 

Mr. GERARD. I understand. 

Senator MANCHIN. I’ve heard it all before. OK. 

Mr. GERARD. I understand. I understand. 

86 

Senator MANCHIN. The bottom line is we have a real golden opportunity to be able to use the product in America, in West Virginia, and other States around that had this find and develop a 

whole new renaissance of jobs, quality jobs. So you can imagine if 

we’re being a little bit—— 

Mr. GERARD. I understand. 

Senator MANCHIN [continuing]. Cautious about this. We want to 

work with you, Sir. I can assure you. 

Thank you. 

Mr. GERARD. Thank you. 

The CHAIRMAN. Thank you Senator Manchin. 

Senator Cantwell. 

Senator CANTWELL. Thank you Mr. Chairman. I have been back 

and forth between votes because first of all I wanted to make sure 

that I was here to congratulate you on your new leadership position as the chair of this committee, and I certainly look forward to 

working with you and Senator Murkowski because I know you’re 

both very serious about moving legislation. I also think this hearing is an example of the type of process by which you intend to air 

these issues and to move forward. So I thank you for that, and it’s 

definitely worth coming back 2 or 3 times. 

My question—I know I had some questions for Mr. Medlock, but 

I understand how people’s schedules don’t always conform to the 

Senate schedule. 

But Ms. Beinecke you know the NRDC released a study recently 

that found out that by 2025 taxpayers will be forced to spend more 

than $270 billion a year for disaster relief if we don’t tackle climate 

change. While we’re having this conversation about natural gas, I 

don’t know if you can make a further comment on. Don’t we, if 

we’re going to see cost in the future, have to do something better, 

putting a true market price on carbon. 

Ms. BEINECKE. Senator Cantwell. First thank you for the question. 

Clearly we’re seeing climate impacts now. Our study was projecting to the future but here in this country just this year the consequences of Hurricane Sandy which the Senate just passed what 

was it, $60 billion of disaster relief for the New York Metropolitan 

area. It’s a huge expense. The drought that’s been going on in the 

Midwest all year, another huge expense, almost stopped shipping 

in the Mississippi River just a few short weeks ago. The consequences of wildfires in the West; we are having extreme weather 

events all across the country. I was talking to Mr. Liveris earlier 

today about what’s been happening in Australia, his home country, 

where the extreme weather events have been even more serious. 

So climate change is here. We need to take it seriously. 

We have to get to a clean energy future that invests in renewables and efficiency. Even as we use natural gas, it’s not the solution over the long term because it is a fossil fuel. 

We have to develop it as responsibly as possible. There are people who are so alarmed with what’s happening unknowingly to 

their health because of the lack of disclosure and the lack of safeguards. So we have to deal with the consequences now but we— 

and this of course if the committee’s charge to deal with the longterm future of the country and look at what the investments we 

87 

need to make in a cleaner energy future that absolutely minimize 

the impacts of climate change, some of which we will experience. 

Our aim is to insure that this Nation experiences as few as possible and that the planet does, as well. The U.S. is a major contributor so we have a major leadership role to play. 

Senator CANTWELL. Thank you for that. I mean we’re talking 

about this now about what to do price-wise with export and import, 

but to me it seems like a microcosm of a larger issue, which is how 

to put the right signal on in general. Mr. Gerard I just want to ask 

you, you know there’s a lot of discussion about the price today, but 

do you think that people developed natural gas for the export market? Did they have that in mind or were they developing it for the 

domestic market? 

Mr. GERARD. Have export in mind when they developed it did 

you say? 

Senator CANTWELL. Yes. Do you think the decision to invest in 

natural gas in 2010 was driven by the look for large export terminals or do you think they were looking at the domestic market? 

Mr. GERARD. I think the thinking has evolved on that, and my 

sense is that over the past few years, yes, they look more and more 

to look to other markets because our supply is so vast here today 

to meet demand. Otherwise what will happen obviously is we’ll 

begin to cut back on the amount of jobs we create as part of that 

energy production. So while 3 or 4 years ago when this, we were 

all talking about LNG imports at the time, clearly they weren’t 

thinking about exports in that context. But over the past few years, 

as you see the evolution, the change in opportunity, today they 

clearly focus on that as being a potential market opportunity that 

we should take advantage of because it assists us here at home in 

creating the energy, producing the energy, and all the other benefits we’ve talked about to consumers and others. 

Senator CANTWELL. Oh, I’m just trying to sort through some of 

this because some people are saying, well a lot of people are, I 

think—I don’t know if it was Mr. Tillerson or somebody said, ‘‘well, 

we’re not making any money and this is why.’’ 

So my question was whether you were looking just domestically 

when you had the idea to expand or did you truly have in mind 

these international markets. 

Mr. GERARD. It goes back to the market itself and looked at in 

a global context. Before when we were relying on other imports for 

natural gas there wasn’t focus on the potential export market. 

Today the world has literally changed as we’ve talked about. 

No one would’ve predicted this a few years ago. 

But today we’re looking for all the markets, all the potential for 

the United States to really establish itself as the energy super 

power. 

You know it’s significant that we’ve got an opportunity now to 

become energy secure as a Nation, but much of that with the job 

creation potential, the economic recovery will come because we 

allow the market to work and we allow that demand to be created 

elsewhere that we can meet with this vast supply. 

That’s how we will influence on a more global context the geopolitics. 

88 

Senator CANTWELL. I’m probably in more agreement with you 

than you think on allowing the market to work, but I just think 

the market has to have a true price on carbon as well because it’s 

affecting us. So, I’m more than happy to look at this from a global 

perspective, andI definitely think it’s interesting to see some of the 

applications like in my home State. 

The shipping industry is going to go to natural gas which is welcome but to me it’s going to be a question of what are those domestic applications—again this is why I wanted to direct them to Mr. 

Medlock and I don’t know whether Mr. Eisenberg has something 

to say on that. What are those transportation applications that 

could take us further down the road of diversification in the United 

States, like the shipping industry or truck transportation or other 

things? 

Again, I thank the Chair for the hearing and I look forward to 

how you’re going to untangle all of this. 

The CHAIRMAN. Thank you Senator Cantwell, and to untangle it 

we’re going to need your expertise on global markets and global economics. 

For those of you that don’t know, in another part of our Senate 

life we serve on the Finance Committee and arguably are 2 of the 

most ardent pro-trade members of the committee because, in our 

part of the world, one out of 6 jobs depends on international trade. 

What we try to generally do in the Pacific Northwest is to grow 

things there, make things there, add value to them there, and then 

ship them somewhere. 

So the challenge is how to take that strongly expansionist view 

with respect to trade and apply it in this area. It’s easier said than 

done, but it definitely gets easier if Senator Cantwell is in the room 

because she understands global markets and actually was in the 

private sector dealing with them. 

So I thank my colleague. 

We’re joined by the Senator from North Dakota who has already 

been gracious enough to spend a lot of time educating me on natural gas issues because he lives it every single day in his part of 

the world, and we really appreciate his expertise. Please proceed 

with your questions. 

Senator HOEVEN. Thank you Mr. Chairman and I look forward 

to having you in North Dakota to see what we’re doing there. 

I’m disappointed that Governor Hickenlooper had to go. I wanted 

to commend him on building an energy policy for the State of Colorado that he said is really about developing all-of-the-above. I commend him for doing that. 

So the question I wanted to put before him, but I’ll start by putting before Ms. Beinecke is: What about a States-first approach 

just like that? In other words to have transparency at the Federal 

level and to have certain standards that may be set at the Federal 

level, but then beyond that having a States-first approach to regulation on these issues of energy development. 

From what I heard from Governor Hickenlooper that’s exactly 

what he was talking about so would you support a State-led approach to regulation and give States like Colorado and others the 

flexibility to truly develop their energy resources? 

89 

Ms. BEINECKE. Senator I think that first of all we do have a 

States-first approach because right now the legislation is at the 

State level. What I’m saying is that it’s a patchwork quilt really 

across the 30 States where fracking is going forward. 

Some States have disclosure. What kind of disclosure requirements they have vary considerably. 

There are other different rules on setbacks, on well casings. 

In each State it’s quite different. 

What we’re asking for is that the committee look at what kind 

of Federal standards-minimum should be applied across the country. 

If the States, and I thought Governor Hickenlooper was very eloquent on this point, that the States are working on this every day. 

They’re trying to figure out what the best standards are. There 

may be a standard that the States, that a number of States have 

developed which, in effect, becomes a Federal standard which 

would apply then to all States. 

I think the challenge now is the differentiation and the diversity 

in the 30 States in which fracking is going on and for potentially 

additional States in the future. 

So what we’re looking at from the environmental point of view 

is how do you insure the public that this activity is going on as 

safely as possible, that they have transparency, they have access 

to information, there’s ongoing disclosure and monitoring and that 

the health impacts where there is growing alarm across the country of what they’re being exposed to from water and air pollution, 

that they have the information on what those chemical and what 

those emissions are and that the data’s available and that they are 

confident that the standards that are being set will protect them. 

Senator HOEVEN. Would you say hydraulic fracturing is the same 

everywhere in the United States? 

Are they pursuing the same energy product? 

Are they pursuing the same geological zones so Federal standards—— 

Ms. BEINECKE. The geology differs across the country but the 

technology—— 

Senator HOEVEN. Excuse me. Let me ask my question, please. 

Ms. BEINECKE. I’m sorry. 

Senator HOEVEN. You’re talking about a Federal standard and 

having it the same across the United States. 

But isn’t it true that hydraulic fracturing and what they’re doing 

in different places is different? 

Ms. BEINECKE. Senator I think that in many of our environmental safeguards there’s recognition that there are conditions that 

differ in different parts of the country. 

I mean our State implementation plans are on air quality are differentiated State by State but they’re based on Federal standards 

and most of our environmental laws actually do recognize that the 

conditions in States vary considerably. But it does set a minimum 

standard that the public can be confident is designed to protect 

them and that is a combination of learning from the experience of 

what’s going on in the States, but then looking at what the Federal 

responsibility is and applying that in a way that allows differentiation, but meets a certain standard so the public is protected,—— 

90 

Senator HOEVEN. Are—— 

Ms. BEINECKE [continuing]. I think that our focus here—this 

really is a direct response to what we’re hearing from people all 

over the country. 

Right now they don’t feel protected because they don’t have access to information. 

The growing health concerns are just beginning to be looked at 

by EPA, by the National Institute of Environmental Health, by the 

National Academy of Sciences. 

I thought Mr. Liveris was very eloquent on this point that we’re 

4 or 5 years into a major boom that could take as much as a century. 

Let’s get it right at the start, and that’s really what we’re asking 

for. 

Senator HOEVEN. Mr. Chairman, I’m going to ask for a little leniency on my 5 minutes given the length of time it took to get the 

answer questions and the length of some of the responses. So if you 

would please bear with me for just a minute. 

Mr. Gerard, so in the conversation that Ms. Beinecke and I just 

had clearly whether it’s hydraulic fracturing or other energy development, we develop different types of energy in different places in 

different ways around the country. That argues for a State-led approach with some Federal standard of, you know, basic safety and 

transparency, which I think captures your answer, which is exactly 

the kind of legislation that I’ve tried to put forward. 

Why isn’t that a good approach? What’s the concern with that? 

Why do we run into resistance when we say State-led approach, 

but we have to recognize there are differences in different parts of 

the country and how we produce the energy and what we’re doing 

so you allow flexibility rather than a Federal one-size-fits-all standard? Can you address that for me? 

Mr. GERARD. Yes, I think there are a couple of factors that are— 

and it’s a great point and goes back to Governor Hickenlooper and 

I wished he was still here to address this because he’s dealt with 

it in Colorado where he’s been able to harmonize all those different 

interests. 

But I think part of the conversation is based, in my view, on a 

false premise. That premise is that somehow Washington is the 

best place to regulate. We shouldn’t forget in these States which 

are the incubators of ideas with different hydrology and geology, 

there is no one more highly motivated to protect their water and 

to protect their air than the people who live in those communities, 

governed by their State regulatory activities, etcetera. 

The phenomenon that we see today in the oil and gas business 

is one of increase in terms of activity. Hydraulic fracturing has 

been around for 65 years. We’ve drilled over 1.2 million wells with 

it, and as Lisa Jackson the administrator of EPA has said, here in 

the United States there’s never been a confirmed case of groundwater contamination as a result of hydraulic fracturing. 

So this myth, in my view, of somehow we’ve got to rush in and 

overlay a potential level of regulation that conflicts with the States 

who know best about hydrology, water quality, etcetera, and the 

geology they deal with—with their State geologist, we need to look 

91 

closely and look at those States and say what’s taking place here 

today. 

I’ll tell you the States have moved very quickly. The State of 

Pennsylvania I mentioned earlier, they’ve modified their State’s 

standards, regulatory legislative activity 4 times already to keep up 

with the fast-moving industry. The States have moved quickly. 

Governor Hickenlooper and others—they’re very active, great blessing there, he gets it, he’s a geologist, he’s been part of it and he’s 

been able in a very positive way to bring the different interests together and find the proper role where the States historically have 

led in regulating oil and natural gas. 

Senator HOEVEN. OK, so for each one of you, and I’m wrapping 

up here, but I would like each one of you to respond with a Stateled approach where you have that ultimate Federal backstop because I think this takes into account both your answers. 

How do we get people working? 

We’ve all agreed we need a comprehensive energy plan for this 

country. Governor Hickenlooper talked about it for his State of Colorado. I could spend a long time telling you about our State of 

North Dakota. Senator Murkowski could talk about Alaska. Each 

one is different, but each State is doing amazing things. We all 

want a comprehensive national energy policy, jobs, energy, the 

whole ball of wax, but we’ve got to give the flexibility and empower 

the private investment. 

A State-led approach with this Federal transparency and backstop does exactly that. I’m building off both your answers. 

How do we get consensus built in this committee and this Congress to get this legislation passed which myself and others are 

putting forward? How do we bring people together to get the consensus to do that? States-first approach, State-led approach with 

that Federal transparency and backstop. 

Ms. Beinecke if you could start on that and just an answer from 

each of you, again, how do we get it done? 

Ms. BEINECKE. Senator I think that—— 

Senator HOEVEN. We’ve been talking about it for years, how do 

we get it done? 

Ms. BEINECKE. I would emphasize the important Federal role 

here because I think there is differentiation among the States. 

I thought Governor Hickenlooper really identified what needed to 

happen is you need all the stakeholders at the table. Now the way 

a lot of these standards that have been developed at the States, the 

public is not at the table. The people that have concerns in their 

local communities in some places are not allowed to express those 

concerns. That’s a situation we have in New York State right now. 

So if you have a process that really does bring all the stakeholders 

together to insure that the concerns that the public actually have 

and are very deeply concerned about are addressed as you work 

with the industry to see how this industry is going to be developed, 

that would be a good process. 

I think up until this point a lot of concerned citizens have felt 

they haven’t had a participatory role in the process and they’re 

looking for one. 

Senator HOEVEN. It seems to me that’s what the whole comment 

process is all about that States have when they develop their laws 

92 

and regulations. I think that was what we were trying to do, but 

I’m about trying to reach out and get people working together here. 

Mr. Gerard. 

Mr. GERARD. Senator I’m just going to read 2 quick sentences, 

and this is Lisa Jackson, the administrator of the EPA, the vast 

majority of oil and gas production is regulated at the State level. 

Then she goes on to say, so it’s not to say that there isn’t a Federal 

role, but you can’t start to talk about a Federal role without acknowledging the very strong State role. End quote. 

My counsel would be as we look at the issues, let’s identify the 

real issues, let’s talk about the issues that are really a concern. 

I take strong exception to what Ms. Beinecke said here. There’s 

a very active, transparent process taking place in these States, and 

no place is it more evident than in the State of New York and 

what’s going on up there in terms of citizens being involved, expressing their views and the Governors very active in taking all of 

this in. 

So let’s sort through some of our own perceptions, our own wishes of what should happen. 

Let’s look at the issues in light of the historic regulatory role for 

the States and identify if there is anything there we need to look 

at, but once again defer. 

The States have done this well. Lisa Jackson said they’re this 

well. 

There’s no reason for the Feds to step in, overlay it, and create 

conflict. 

Senator HOEVEN. OK Mr. Eisenberg. Now you’re going to explain 

in 2 sentences how we bring those 2 groups together and get her 

done. 

Mr. EISENBERG. That’s a very good question. 

You know I think the one-size-fits-all approach, I mean there 

needs to be some trepidation on the part of the Federal Government to regulate without understanding the consequences of it. 

How do we get those 2 groups together? Good luck. I mean it’s 

starting—— 

Senator HOEVEN. But it’s the key to a national energy policy that 

works, and Senator Wyden I think if anybody can do it, I think our 

Chairman’s the kind of guy that can build that kind of consensus. 

So we’ve got to figure out how to do this. 

Mr. EISENBERG. Yes, an—I mean, and we’re certainly at the 

NAM certainly willing to work with the committee toward it, toward that sort of goal. 

I mean we would like to see more bipartisanship energy issues. 

We don’t think that energy, and particularly natural gas, should be 

a partisan issue. In fact, on this committee I don’t view it as being 

that. 

But we are certainly willing to work beyond that. 

Senator HOEVEN. We’ll need your help. 

Thank you all very much. 

The CHAIRMAN. I thank the Senator from North Dakota. I don’t 

want to make this a bouquet-tossing contest, but I think the Senator from North Dakota has really put his finger on it because if 

you listen to how you described it, Senator, you talked about Federal transparency. 

93 

You talked about a Federal backstop and, of course, a very strong 

role for the States recognizing that there are differences. When you 

look at the architecture of the environmental laws, you see what 

the Senator from North Dakota described all over the place, essentially these Federal minimum standards and then a wide berth for 

the States to do their thing. 

I was telling Senator Murkowski I came to the U.S. Senate in 

1996, the first new senator from Oregon in 30 years. I had a full 

head of hair and rugged good looks and the first thing I voted for 

which dismayed some of my supporters, was for the Kempthorne 

Amendment, which in effect had what you all are talking about: a 

strong transparency and backstop role, but the States could do 

their own thing. 

So I know that as we go back and forth on this, it looks like the 

gaps are insurmountable. But it looks like you 3 souls have been 

willing to stay here as we got up and came back and we got up and 

we came back. I so appreciate the good faith in terms of desire to 

figure this out and that’s why Senator Murkowski and I are committed. 

I’ll just make 2 last points and let my colleague have the last 

word. On this point with respect to confidence, Ms. Beinecke, which 

I think is central, one of the ideas I have heard has a lot of bipartisan interest from both industry and environmental folks is if we 

can have a strong disclosure program, a program, for example, 

where people are going to really understand ahead of time, for example on fracking fluids and these kinds of things. I’m very interested in following up with you on that, and I think it’s fair to say 

there are a lot of people in industry who see this confidence issue 

as extraordinarily important as well because there’s tremendous 

concern. We’re hearing about it from communities around the country, and if we can get some of these big elements right-like what 

the Senator from North Dakota talked about-how you can figure 

out how to have a strong disclosure program and maybe address 

some of the issues that Governor Hickenlooper brought up in connection with how you do it in addressing various concerns. I think 

we’re on our way. 

The last point I want to make is the reason Senator Murkowski 

and I are putting so much time into this- and we thought together 

about what we ought to proceed on first-is this issue has the potential to be a real American success story where in effect if we work 

together, have all the stakeholders at the table as you, Ms. 

Beinecke, said and the Senator from North Dakota has indicated 

to me he’s more than open to, this has the potential to be an extraordinary success story, a story for the times, an American success story. 

That’s the objective we’re going to take in the committee, and I’m 

going to let the last word go to my friend and colleague, Senator 

Murkowski. 

Senator MURKOWSKI. Is this yours? 

The CHAIRMAN. No. 

Senator MURKOWSKI. See we’re just so close we don’t even know 

which microphone belongs to who. 

Senator Wyden, I want to thank you for your summation comments and also to acknowledge where you have been taking us, 

94 

Senator Hoeven, in this discussion because I think we’ve had an 

opportunity here to have almost 3 hearings. 

We started our overview of what natural gas has brought us in 

terms of the manufacturing renaissance, jobs, and the opportunity 

for reduced emissions. 

As I point out in my Energy 20–20 document, it comes down to 

one bumper sticker and that is ENERGY IS GOOD. I think when 

we’re talking about natural gas we recognize the benefits. 

But we’ve also had a hearing for all intents and purposes talking 

about the issues as they relate to export of this now abundant resource and what that might mean to us and how we might deal 

with some of the concerns that have been raised here. 

One of the things that I heard very clearly around the Dias, we 

want to be careful. We don’t want to run out and do something 

precipitice that we might regret in terms of policy later. Let’s make 

sure that we’ve got our eyes open and are mindful in terms of how 

we advance these issues. 

Then the focus that Senator Hoeven has given us on the issue 

of hydraulic fracking and really what that has meant in terms of 

being able to access a considerable resource, but recognizing that 

in this amazing country of ours that this resource is not just situated in North Dakota. We’ve been utilizing hydraulic fracking on 

the North Slope for decades now without incident. 

What Senator Manchin has been talking about regarding the opportunities in his part of the country, States like Ohio and Pennsylvania where people have been for decades and generations and 

never envisioned themselves as coming from an energy-producing 

State, and now all of a sudden they’re in an energy producing 

State. 

The dynamics that are going on right now within the energy sector are really quite profound so our responsibility is as a committee 

to thoughtfully take up these issues and consider all aspects of 

them, not rushing to judgment, but really allow good thoughtful 

discussion. I think that this is critically, critically important. 

It’s important that we look to our history when we talk about 

LNG exports. I’m always quick to remind folks that we’ve been 

doing it in Alaska for over 40 years now. The longest contract in 

the country for export of anything has been shipping natural gas 

to Japan. It’s been a very quiet success story, and in 4 decades 

they’ve never missed a shipment. It was a remarkable run, and nobody really knows about it. That’s probably a good thing. When it 

doesn’t make the headlines, it’s probably a good thing. 

Mr. Chairman I want to—I want to commend you for how we 

started off our first hearing in this committee. Maybe all of them 

won’t go until well after the expired hour, but I do think what we 

took up here today and the manner in which we addressed it is a 

good marker for how we can move forward on some very difficult 

policy issues, but I think policy issues that have an opportunity to 

really direct the economic future and well-being of our country. 

The CHAIRMAN. Thank you, thank you. 

With that the committee’s adjourned. 

[Whereupon, at 1:10 p.m., the hearing was adjourned.] 

(95) 

1DOE 2012 LNG Export Study at 4. 

2 Id. at 76. 

APPENDIXES 

APPENDIX I 

Responses to Additional Questions 

RESPONSES OF ROSS EISENBERG TO QUESTIONS FROM SENATOR ALEXANDER

Question 1. Given the advantage of low domestic natural gas prices that resulted 

from increased production from unconventional natural gas reserves, do we really 

have a problem since we might only export 10 percent of our natural gas? 

Answer. Thank you for this question. A great deal of the discussion at the hearing 

centered on finding a ‘‘sweet spot’’ for LNG exports. The NAM does not believe it 

is the role of the federal government to find the ‘‘sweet spot.’’ If the market is allowed to work, the ‘‘sweet spot’’ should happen naturally. 

The LNG export study commissioned by the Department of Energy (DOE) from 

NERA Economic Consulting helps illustrate this point. One of NERA’s key findingswhich often goes overlooked-is that in the scenarios NERA believes most likely to 

represent future conditions, we will not export large amounts of LNG because we 

will not have enough international customers willing to buy it at the price at which 

we would have to sell it to make a profit. Specifically, NERA states: 

NERA concluded that in many cases the world natural gas market would 

not accept the full amount of exports specified by FE in the EIA scenarios 

at prices high enough to cover the U.S. wellhead price projected by EIA. In 

particular, NERA found that there would be no U.S. exports in the International Reference case with U.S. Reference case conditions. In the U.S. 

Reference case with an International Demand Shock, exports were projected but in quantities below any of the export limits.1

DOE asked NERA to model price impacts of 6 and 12 billion cubic feet (bcf) of 

exports. NERA concluded that, unless production costs substantially declined or 

international demand spiked, the U.S. would be unable to export the full amount.2

Question 2. At what percentage of exports, compared with the overall U.S. production of natural gas, does the U.S. lose its price advantage of natural gas that we 

have today? 

Answer. Strictly speaking, U.S. consumers of U.S.-produced natural gas will always have a price advantage over foreign consumers of U.S.-produced natural gas 

due to liquefaction and transportation costs. LNG export companies estimate that 

liquefaction and transportation of natural gas adds roughly six dollars per billion 

cubic foot (bcf); domestic consumers of this gas will therefore always have a six dollar price advantage over foreign consumers of this same gas. 

Your question also asks whether there is a point at which LNG exports would 

cause U.S. natural gas prices to rise high enough that domestic manufacturers no 

longer take advantage of it. That is a much more difficult question, and unfortunately one that depends on much more than simply LNG exports. It will depend on 

a multitude of factors, including: whether we can continue to develop our vast natural gas resources efficiently and inexpensively, how much gas we ultimately use 

for electric generation for manufacturing and in the transportation sector, whether 

we will discover even more domestic natural gas reserves, how quickly other nations 

such as China increase their own natural gas production, and whether international 

demand for LNG exports will increase substantially. The NAM firmly believes that 

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tion, a manageable permitting process, and a policy on LNG exports governed by 

free trade and open markets will ensure that the U.S. can export natural gas while 

maintaining a growing and vibrant manufacturing sector. 

Question 3. What are your projections for the amount of natural gas the U.S. will 

be producing in 10 years? 

Answer. The NAM has not made specific projections for the amount of natural gas 

the U.S. will be producing in 10 years. However, the PwC study supported by the 

NAM in December 2011, ‘‘Shale Gas: A Renaissance in U.S. Manufacturing,’’ based 

its projection of one million manufacturing jobs that could be created from shale gas 

development in 2025 on the Energy Information Administration’s estimate of 862 

trillion cubic feet (tcf) of technically recoverable shale gas resources. 

Question 4. Under present policies, if you had to make a guess, what would be 

the range of the percentage of U.S. natural gas production that we would be exporting in 10 years? 

Answer. If the DOE’s current policy-a full moratorium on new export licenseswere allowed to remain in place, we would be exporting the same amount of natural 

gas in 10 years that we do today: none. 

That said, we do expect the DOE to move forward with licensing at some point. 

Again, the NERA study performed for the DOE is helpful because it clearly states 

that current market conditions will not allow for exports even at the 12 bcf level. 

If NERA is correct, the market will ensure that a balance exists between exports 

and domestic availability of natural gas. 

JACK N. GERARD, 

API, February 28, 2013. 

Hon. RONALD WYDEN, 

Chairman, Senate Committee on Energy and Natural Resources, 304 Dirksen Senate 

Building, Washington, DC. 

DEAR CHAIRMAN WYDEN, 

Thank you again for the opportunity to testify before the committee on the gamechanging opportunity that we have before us through the development, use and export of domestic natural gas. The application of the proven technologies of horizontal 

drilling and hydraulic fracturing have allowed the United States to become the global leader in natural gas production, and we are on our way to becoming the global 

leader in oil production. This will enhance our energy security tremendously, considering that the U.S. will rely on natural gas and oil for decades to come for energy 

consumption, and the world will require significantly more natural gas and oil. Domestically, the story is compelling: the upstream oil and natural gas sector is now 

responsible for 1.7 million jobs in the country in unconventional resource development alone. And as I stated in my testimony to the committee, that number is expected to grow to 2.5 million jobs by 2015; 3 million jobs by 2020 and 3.5 million 

jobs by 2035. According to the Bureau of Labor Statistics, jobs in the oil and natural 

gas exploration and production sector pay on average more than $100,000 per year, 

more than twice the national average. As we move forward with this important debate, we must ensure that move down a path that fosters this important economic 

and job growth through responsible development of these resources. 

RESPONSE OF JACK N. GERARD TO QUESTION FROM SENATOR WYDEN

Question 1. Ms. Beinecke noted in her testimony that one of the benefits of natural gas, of course, is that when you burn it; it releases fewer greenhouse gas emissions than resources like coal. This benefit, though, can be offset if more natural 

gas leaks in to the atmosphere. There are conflicting reports about the level of 

methane leakage from natural gas production and transport, ranging from as little 

as 0% leaked to as much as 9% in some reports for some basins. How can we get 

our arms around this question of how much methane is being leaked, and what are 

your thoughts for how we can make sure that leakage is minimized? 

Answer. API is keenly aware of the widely divergent estimates of methane emissions from the U.S. petroleum and natural gas industry and has been working to 

improve methane emission estimates. Methane emissions associated with petroleum 

and natural gas production have been typically assessed by engineering estimation. 

Such estimates are typically used by EPA when compiling the national U.S. Greenhouse Gas (GHG) Inventory and more recently by companies for reporting under the 

mandatory Greenhouse Gas Reporting Program (GHGRP). 

I. In order to make a comparison to ‘‘% leaked’’ as identified in Question 1 

(Senator Wyden), the analysis in section I and II, reports methane emissions 

97 

1 Natural Gas Systems is comprised of sources in production field operations (both onshore 

and offshore); natural gas processing; natural gas transmission and storage (including LNG); 

and natural gas distribution. 2 Calculated based on 239,115 MMscf of CH4 emissions divided by 20,026,832 MMscf natural 

gas withdrawals. 3 Natural gas withdrawals mean EIA’s gross gas withdrawals less associated gas from oil 

wells, which for 2008 withdrawals = 20,026,832 MMscf; 2010 = 20,981,382 MMscf; and 2011 = 

22,571,108; http://www.eia.gov/dnav/ng/nglprodlsumldculNUSla.htm 4 Calculated based on 534,323 MMscf of CH4 emissions divided by 20,981,382 MMscf natural 

gas withdrawals. 5 Calculated based on 346,230 MMscf of CH4 emissions divided by 22,571,108 MMscf natural 

gas withdrawals. 6Petroleum and Natural Gas Systems for EPA’s GHG Reporting Program is comprised of 

sources in petroleum and natural gas production (both onshore and offshore); natural gas processing; natural gas transmission/compression; natural gas distribution; natural gas storage; 

LNG storage, import, and export; and other petroleum and natural gas combustion sources. 7 Natural gas gross withdrawals is taken directly from EIA, which for 2011 = 28,479,026. This 

includes gross withdrawals from oil wells to be consistent with emissions reported under the 

GHGRP, which includes petroleum and natural gas production. http://www.eia.gov/dnav/ng/ 

nglprodlsumldculNUSla.htm 8 Natural Gas Air Quality Study (Final Report), http://fortworthtexas.gov/gaswells/default.aspx?id=87074, Posted July 14, 2011, Updated July 19, 2011 

per production as a comparable percentage.This variability of methane emission 

estimates extends to the official inventory of methane emissions in the annual 

U.S. GHG inventory prepared by EPA and submitted to the UNFCCC. This inventory estimates GHG emissions from various sectors including the Natural 

Gas Systems sector.1 In the 2008 inventory (published in 2010), EPA estimated 

methane emissions from Natural Gas Systems to be 4,591 Gg of methane (96.4 

Tg CO2e) which equates to about 1.2%2 of 2008 natural gas withdrawals3 (production) from the natural gas industry. The 2009 and 2010 inventories (published 2011 and 2012 respectively) estimated significantly higher methane emissions with the 2010 inventory estimating methane emissions of 10,259 Gg 

(215.4 Tg CO2e), equating to about 2.6%4 of natural gas withdrawals from the 

natural gas sector. The majority of this increase was due to different assumptions and methodologies associated with the onshore natural gas production segment. The 2009 inventory played a significant role in public, policy, and regulatory debates surrounding methane emissions from natural gas systems. The 

2011 inventory, released for public review on February 22, 2013, estimates 

methane emissions of 6,646 Gg (139.6 Tg CO2e); equating to about 1.5%5 of natural gas withdrawals from the natural gas sector. 

The emission sources, and their respective methane emissions, included in 

EPA’s calendar year 2011 inventory estimate are shown in the table provided 

in the supplemental technical information that follows on page 16. 

II. Based on the 2011 data reported to EPA under the GHG Reporting Program (which is designed to capture 85-90% of the petroleum and natural gas 

operations in the U.S.) one can also assess a leakage rate for petroleum and 

natural gas operations. The data released in early February 2013 by the U.S. 

EPA indicates that methane emissions for all sources within the Petroleum and 

Natural Gas Systems category6 are 83 million metric tonnes of CO2 equivalents, 

which equates to an average methane leakage rate of about 0.7% of 2011 natural gas gross withdrawals.7

MEASUREMENTS OF METHANE EMISSIONS

In order to gather more information on methane leakage rates, and the adequacy 

of the engineering estimation methods, a series of studies is emerging over the past 

couple of years each providing a snapshot of leakage from a specific region and a 

specific segment of the natural gas system at a specific point in time. 

I. Fort Worth, Texas Study, 20108.—Analysis of reported routine emissions 

from over 250 well sites (with no compressor engines) in Barnett Shale gas well 

sites in the City of Fort Worth was conducted for the City of Fort Worth by 

Eastern Research Group Inc. (ERG). The results revealed a highly-skewed distribution of emissions, with 10% of the well sites accounting for nearly 70% of 

total emissions. Natural gas leak rates were calculated based on operator-reported, daily gas production data at these well sites and ranged from 0% to 5%, 

with six sites out of 203 showing leak rates of 2.6% or greater due to routine 

emissions alone. 

98 

9Petron, G. et al. J. Geophys. Res. 117, D04304 (2012). 

10M. Levi, Revisiting a Major Methane Study, October 2012; http://blogs.cfr.org/levi/2012/10/ 

12/revisiting-a-major-methane-study/ 11 Natural Gas and the Transformation of the U.S. Energy Sector: Electricity. Logan, J., 

Heath, G., Paranhos, E., Boyd, W., Carlson, K., Macknick, J. NREL/TP-6A50-55538. Golden, CO, 

USA: National Renewable Energy Laboratory. 12The Joint Institute for Strategic Energy Analysis is operated by the Alliance for Sustainable 

Energy, LLC, on behalf of the U.S. Department of Energy’s National Renewable Energy Laboratory, the University of Colorado-Boulder, the Colorado School of Mines, the Colorado State University, the Massachusetts Institute of Technology, and Stanford University 13Methane leaks erode green credentials of natural gas, Nature News, 02 January 2013; 

http://www.nature.com/news/methane-leaks-erode-green-credentials-of-natural-gas-1.12123#/b1 14What will it take to get sustained benefits from natural gas? http://www.edf.org/ 

methaneleakage 15See http://www.gpo.gov/fdsys/pkg/FR-2013-02-21/pdf/2013-03988.pdf. 

II. Denver-Julesburg Basin, Colorado, February 20129.—A study by NOAA/ 

University of Colorado scientists published in February 2012 suggested that up 

to 4% of the natural gas produced at a field near Denver was escaping into the 

atmosphere. The study relied on 2008 ambient concentration measurements, 

and estimated a leakage rate based on concentration ratios, using a methodology that remains in dispute. In a comment on this publication, Levi10 questions the authors’ assumptions about the composition of the gas being leaked 

and where it is coming from (methane from natural gas production or other hydrocarbon liquids from condensates). Levi’s analysis underscores the uncertainty about the study’s conclusion regarding methane leakage from natural-gas 

operations elsewhere. 

III. Joint Institute for Strategic Energy Analysis (JISEA), November 

201211.—This study of the Barnett Shale area was conducted by JISEA12 and 

released in November 2012. The study analyzed 2009 emissions inventories of 

regulated air pollutants submitted to the Texas Commission on Environmental 

Quality (TCEQ) from more than 16,000 individual sources in shale gas production and processing sub-sectors. Based on the estimated methane content of this 

produced gas and the assumed average lifetime of production from a well, 

JISEA estimated a methane leakage rate—for the Barnett Shale basin—as 1.3% 

across its life cycle. 

IV. Uinta Basin, Utah, December 201213.—In December of 2012, NOAA described the unpublished results of an airborne ambient measurement study in 

the Uinta Basin, Utah. The data was collected as part of a broad investigation 

of air quality in the Uinta Basin, using ground-based equipment and an aircraft 

to make detailed measurements, including methane concentrations. Using what 

we believe are simplified mass calculations and assumptions along with the aircraft concentration measurements, the researchers suggest that the rate of 

methane leakage may be as high as 9% of total production, when compared to 

industry production data. A paper detailing the study methodologies, data, and 

results has not yet been published or released. 

V. University of Texas/EDF Study14.—A measurement campaign was conducted in 2012 by the University of Texas at Austin (in collaboration with nine 

petroleum and natural gas industry corporate partners and EDF—Environmental Defense Fund) to quantify emissions from natural gas production. Our 

understanding is the results of this study will be published later in 2013. 

CONCLUSIONS

Engineering estimation methods, source measurement methods, and ambient concentration measurement studies have inherent limitations and are associated with 

a considerable level of uncertainty. Each piece of information taken alone cannot 

provide an accurate picture of system-wide leakage, due to spatial and temporal variability. Great care is needed not to rely on partial data provided by various studies 

to-date, hence indicating the need for additional investigations. 

Most notably, the science of estimating leakage rates from ambient concentration 

data is still evolving. The uncertainties and limitations of the various methodologies 

being used have yet to be independently validated and as such cannot be viewed 

as definitive measurements at this time. They should also be viewed as snapshots 

in time and location. 

As Jeff Tollefson states in the journal Nature15, ‘‘Whether the high leakage rates 

claimed in Colorado and Utah are typical across the U.S natural-gas industry remains unclear. The NOAA data represent a ’small snapshot’ of a much larger picture that the broader scientific community is now assembling.’’ API and its members 

99 

recognize the need to improve both the scientific understanding of the range of data 

being collected as well as operating practices that would minimize methane leakage. 

Furthermore, it should be noted that implementation of the final Oil and Natural 

Gas Sector New Source Performance Standard (NSPS OOOO) will achieve significant reductions of methane as a co-benefit from regulating volatile organic compound (VOC) emissions. EPA estimated that the final rule will reduce methane by 

the equivalent of 19 to 33 million tonnes of CO2. The use of Reduced Emission Completions (RECs) in the final rule, a process developed by industry to minimize emissions and maximize resource recovery, will significantly reduce emissions resulting 

from completion of gas wells. Over the long term, this rule will have an ever-broadening impact on our operations as new sources are regulated. 

API recommends four steps: 

1. Collaborative efforts between industry, government and academia to agree 

upon a common set of methane measurement methods and ‘best practices’ for 

relating ambient concentration measurements to source emissions in the field. 

2. In-depth analysis of newly emerging data—from different studies around 

the country—to assess the range and regional variability of potential methane 

leakage and quantify the economic benefits from its capture for sale. 

3. Collaboration between EPA, the industry, and stakeholders to mine the 

data reported under the GHGRP to improve methane emission estimates in the 

U.S. GHG Inventory along with improving the accuracy of methodologies in the 

GHGRP. 

4. Evaluation of the impact of recently promulgated new source performance 

standards (NSPS) for the Petroleum and Natural Gas sector to forecast expected 

methane emissions reduction trends once the new regulations are fully implemented in 2015 and beyond. 

RESPONSE OF JACK N. GERARD TO QUESTION FROM SENATOR LANDRIEU

Question 1. It is obvious that everyone testifying today recognizes the importance 

of environmental protection and responsible production. While regulation is a vital 

part of ensuring that natural gas production proceeds in a responsible fashion, it 

is also vital that industry play an active role in self-regulation. What efforts are you 

aware of that industry has undertaken to ensure that they operate in a safe and 

responsible manner? 

Answer. The industry’s commitment to excellence and continuous improvement in 

hydraulic fracturing operations is evident in its work to develop best practices for 

oil and gas operations. More than 65 of API’s standards and recommended practices 

for completion of wells apply to hydraulic fracturing operations. And over the past 

several years, API has developed three additional new guidance documents uniquely 

tailored to hydraulic fracturing in order to offer additional guidance to operators. 

The API standards process, its work applicable to hydraulic fracturing operations, 

and recent outreach efforts are described below. 

1. API’s Standards Program. 

API’s standards program has been a recognized leader in the development and 

dissemination of industry standards since 1924. New API standards, certifications, 

and practices are developed through a broad-based, formal consensus process that 

allows companies, regulators, organizations, and other stakeholders to participate in 

an interactive dialogue, addressing both cutting-edge issues and regulatory needs. 

API is accredited by the American National Standards Institute (ANSI), and API 

undergoes regular program audits by ANSI. API’s standards process utilizes the 

ANSI-approved API Procedures for Standards Development. This process ensures 

that there is openness in participation on API standardization committees; committee balance between users, manufacturers, contractors/consultants and government; consensus based documents (does not mean unanimity); and due process, 

within which all comments and objections must be considered. API standards are 

considered ‘‘American National Standards’’ for adhering to this process. 

In part because of this openness and consistency, API’s standards are the most 

widely cited in the petroleum and natural gas industries. More than 100 standards 

have been cited 270 times in U.S. federal regulations and 184 standards have been 

cited more than 3,300 times in U.S. state regulations. Without specific codification 

in state or federal legislation, the standards are not mandatory; however, they are 

widely respected indicators of strong operations and therefore routinely mandated 

by companies, service providers, and their insurers even where compliance is not 

legally required. 

API’s standards are evergreen and reviewed a minimum of once every five years. 

Announcements of upcoming standards work programs such as formalizing the curVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00103 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
100 

rent hydraulic fracturing guidance are made in the U.S. Federal Register through 

an agreement with the U.S. National Institute of Standards and Technology, as well 

as API’s own Web site to encourage diverse participation. 

2. Work Applicable to Hydraulic Fracturing. 

The industry understands that the integrity of wells and effective wastewater 

management is central to producing natural gas safely and responsibly. API’s existing body of rigorous internationally recognized good practice supplements the extensive federal and state regulation governing virtually every aspect of resource extraction. More than 65 of API’s existing standards and recommended practices for completion of wells apply to hydraulic fracturing operations. They address topics ranging from planning and design of wells to post-production reclamation. 

a. Hydraulic Fracturing Operations-Well Construction and Integrity Guidelines. 

API HF1 (currently undergoing revision as RP 100-1) addresses casing, pressure 

testing, and cement job evaluation (including cement bond logs on a selective basis). 

Safe and responsible development begins with strong wells, these standards and 

practices include, but are not limited to, pressure testing of cemented casing, cement 

bond logging, and inspections beyond those required by local permitting procedures. 

API HF1 incorporates existing API guidance such as API Specification 5CT (9th 

Edition, July 2011, pertaining to the design, manufacturing, testing, and transportation of casing and tubing) and API Standard 65 Part 2 Isolating Potential Flow 

Zones During Well Construction (2nd Edition, December 2010, covering best practices to isolate potential flow of hydrocarbons and other fluids throughout the hydraulic fracturing process). API HF1 speaks extensively about the variables operators should consider in planning and completing wells. These include local considerations (e.g., regional geology, pressure differentials, and temperature variations that 

affect cement slurry composition), as well as advances in technology. 

It is important to note that constantly evolving data collection, analysis, and monitoring techniques offer operators access to an ever-improving array of real-time information about well activities. API HF1 emphasizes that wholly isolated, solidly 

constructed wells and conscientious monitoring are essential elements to responsible 

development. 

b. Water Management Associated with Hydraulic Fracturing. 

API HF2 (currently under revision as RP 100-2) identifies practices used to minimize the environmental and societal impacts from the acquisition, use, management, treatment, and disposal of water and other fluids used in hydraulic fracturing. This document focuses primarily on issues associated with hydraulic fracturing in deep shale gas development; however, its guidance also extends to many 

other applications of hydraulic fracturing technology, including shale oil development. In an attempt to address the development-related issues stemming from the 

increasingly urban nature of shale gas development and competing uses, API HF2 

recommends that water quality be evaluated on a regional level throughout the 

planning and completion process. It also acknowledges opportunities for creative 

water use strategies (e.g., companies that have used treatment facilities to make 

water from non-potable aquifers appropriate for fracturing) and the continuously 

evolving possibilities for greener fracturing additives (e.g., stimulants like propane 

or ultraviolet antibacterial agents). API HF2 strongly encourages companies to conduct baseline water quality testing, and to continue periodic water quality testing 

throughout the fracturing process. Careful water management in fracturing can 

often help companies reduce costs, while protecting the environment. For example, 

on-site storage facilities and pipelines can help minimize truck traffic, thereby lowering the greenhouse gas footprint of the extraction process. Similarly, treating and 

recycling water for future fracturing projects can help eliminate community concerns about releasing treated produced water for public consumption while also reducing operator costs. Disposal options—whether through underground well injection or treatment at specially accredited facilities—vary according to region; however, the overarching theme of this document is that responsible operators are careful planners who consider the regional, state, and local environmental implications 

of every decision in the water use lifecycle. 

c. Practices for Mitigating Surface Impacts Associated with Hydraulic Fracturing. 

API HF3 (currently under revision as RP 100-2) summarizes the strategies to protect surface water, soil, wildlife, other surface ecosystems, and nearby communities. 

One of the great benefits of hydraulic fracturing is that a multi-well production site 

the size of a two-car garage regularly contains as many as five wells that can 

101 

produce gas for up to 40 years. This is one of the most compact footprints of any 

large-scale energy source. That being said, however, careful planning for on-site 

storage and stormwater management, as well as continuous site inspections of both 

equipment and liners can minimize the risk of any inadvertent surface discharge. 

Baseline water samples and advanced disclosure about the additives used in fracturing fluids can also help increase community comfort with operational activities. 

HF3 draws heavily on API Recommended Practice 51R. 

d. General Environmental Considerations. 

API RP 51R—Environmental Protection for Onshore Oil and Gas Operations and 

Leases, covers diverse operational areas, including the design and construction of 

access roads, the placement of well locations, and practices for restoring sites after 

production has ceased. Notably, Annex A of Recommended Practice 51R focuses on 

‘‘Good Neighbor Guidance’’ and encourages operators to be proactive in protecting 

public safety and the environment, while respecting the property rights of all neighbors (e.g., the landowner, the surface user, and adjoining landowners) and communicating effectively with community stakeholders. These documents are available to 

the pubic online at www.api.org/oil-and-natural-gasoverview/exploration-and-production/hydraulic-fracturing.aspx and focus on some of the most pressing water management issues in hydraulic fracturing (e.g., baseline water quality sampling, and 

regional water planning). Additionally, they are currently being expanded thanks to 

additional input from industry and other stakeholders (including regulators) as they 

progress through API’s open, ANSI-accredited standards review process. 

3. Stakeholder Outreach. 

The task of improving the industry’s ability to respond to public concerns and to 

address issues important to communities and regions where shale gas development 

is occurring continues through efforts at the state, county and local levels. Toward 

that end, API is willing to work with local and regional governments to identify and 

publicize recommended practices for community engagement toward prevention, 

mitigation and remediation of surface impacts and effects upon communities from 

exploration and production activities. API has already engaged in outreach to various county governments to address specific issues brought to the attention of API 

by the county representatives. 

In October 2011, API and its sister trade associations held the first in a series 

of technical workshops specifically devoted to analyzing and promoting industry 

guidance documents on hydraulic fracturing operations. The workshop was held in 

Pittsburgh, Pennsylvania and was open to industry members, community stakeholders, environmentalists, state and federal regulators, and journalists. Registration fees were reduced for nonprofits and community members to encourage participation. More than 250 individuals attended and contributed to active discussions 

throughout the workshop. 

Based on the success of this model, API offered over 15 additional regional oneday workshops throughout 2012. These workshops offered a valuable opportunity to 

understand and address regional concerns, as well as educate regulators and the 

public about the considerable safety measures accompanying hydraulic fracturing 

operations. 

These workshops were only one element of the ongoing dialogue that industry has 

with regulators about continually evolving good practices and effective regulations. 

Discussions occur regularly on a state-specific basis, as well as through organizations like the Interstate Oil and Gas Compact Commission (IOGCC) and the State 

Review of Oil and Natural Gas Environmental Regulations (STRONGER). 

STRONGER is an organization that specializes in recommending improvements to 

state regulatory frameworks. 

At a variety of meetings, industry has shared existing good practices with state 

regulators, and discussed where improvements to state regulations could effectively 

provide additional safeguards for local communities and their water sources. These 

briefings have occurred in Ohio, Pennsylvania, West Virginia, and Michigan and 

will continue in these and other states, as long as regulators want to learn more 

about industry practices. 

Building on momentum from previous recent efforts, API is also planning to continue outreach to both industry and regulators to foster a dialogue of collaboration 

and continuous improvement. Industry and government together must meet the 

challenge of developing our nation’s shale gas endowment in a sustainable way over 

time in ways that protect the environment, respect other uses of lands and waters 

in the vicinity and that are appropriately tailored to the character and context of 

the regions in which shale gas development occurs. 

102 

With conventional well technology, development of shale energy would have been 

prohibitively expensive. However, horizontal drilling and hydraulic fracturing not 

only make harvesting shale resources commercially viable—they allow it to be done 

with remarkably decreased surface impacts. 

The United States Department of Energy has recognized both hydraulic fracturing 

and horizontal drilling as advanced technologies that provide environmental benefits 

in a 1999 report entitled ‘‘Environmental Benefits of Advanced Oil and Gas Production Technology.’’ According to DOE, hydraulic fracturing was first introduced in 

1947 and ‘‘quickly became the most commonly used technique to stimulate oil and 

gas wells. . . . By 1988, fracturing had already been applied nearly a million 

times. Each year, approximately 25,000 gas and oil wells are hydraulically fractured.’’ Since the release of that report, hundreds of thousands of additional wells 

have been hydraulically fractured. The report explains hydraulic fracturing results 

in optimized recovery of oil and gas resources, protection of groundwater resources, 

and less waste requiring disposal, while horizontal drilling results in less impact in 

environmentally sensitive areas, fewer wells needed to achieve desired level of reserve additions, less produced water and less drilling waste. Furthermore, as described above, the industry has actively developed standards and best practices for 

safe and environmentally responsible operations. 

RESPONSES OF JACK N. GERARD TO QUESTIONS FROM SENATOR BARRASSO

On March 14, 2012, the then-Bureau of Land Management (BLM) Director, Bob 

Abbey, testified in the Senate that there has been ‘‘a shift [in oil and natural gas 

production] to private lands in the East and to the South where there are fewer 

amounts of Federal mineral estate.’’ 

Question 1(a). What specific steps should the Federal government take to make 

Federal public lands and Indian lands more competitive with private and state 

lands for the purposes of oil and natural gas production? 

Answer. The federal government should take positive steps to increase the number leases issued on federal lands, to expedite the timeframe for completing environmental analysis, and expedite the timeframe for issuing permits to drill. 

According to a study titled, ‘‘Employment, Government Revenue, and Energy Security Impacts of Current Federal Lands Policy in the Western U.S.’’, prepared for 

API by EIS Solutions of Grand Junction, Colorado, January 2012, which relies upon 

an examination of BLM Oil and Gas Statistics compiled in 2010 and 2011 (the EIS 

Solutions report): 

• The number of new federal oil and gas leases issued by the BLM in Western 

states is down 44% from an average of 1,874 leases in 2007/2008 to 1,053 in 

2009/2010. 

• The number of new permits to drill issued by the BLM is down 39%, from an 

average of 6,444 permits to an average of 3,962. 

• The number of new wells drilled on federal land has declined, 39%, from an average of 4,890 wells to 2,973. 

• The economic downturn starting in 2007 is recognized as a factor contributing 

to these results. However, if market factors were the sole driver of the federal 

lands permitting slowdown, it would be reasonable to assume that non-federal 

drilling permits would generally track the trends occurring with their federal 

counterpart. But this is not the case. 

We have attached the full report from EIS Solutions, which describes in further 

detail the significant decrease in leasing, permitting and the drilling of wells on federal BLM lands. 

When comparing BLM statistics for the entire U.S. related to the years from 2008 

to 2012, the numbers paint a similar portrait. Natural gas production increased on 

nonfederal lands nationwide and in Wyoming when comparing 2008 to 2012, but it 

decreased on federal lands in the same areas over the same timeframe. Nationwide, 

natural gas production increased from 42.1 bcf/day to 56.8 bcf/day on nonfederal 

land, and decreased from 8.4 bcf/day to 8.0 bcf/day on federal land. In Wyoming, 

natural gas production increased from 1.8 bcf/day to 1.9 bcf/day on nonfederal land, 

and decreased from 4.2 bcf/day to 4.0 bcf/day on federal land. In terms of total wells 

drilled, nationally the number of wells drilling on federal lands decreased from 

5,044 in 2008 to 3,022 in 2012, which is a 40 percent drop. In Wyoming, federal 

wells drilled decreased from 2,275 in 2008 to 776 in 2012, which is a 66 percent 

drop. In terms of drilling permits issued, nationally the number of permits decreased from 6,617 in 2008 to 4,256 in 2012, which is a 36 percent drop. In Wyoming, federal permits issued decreased from 3,155 in 2008 to 1,229 in 2012, which 

is a 61 percent drop. This information is provided in a one-page attachment. 

103 

CERTAINTY AND TIMELINESS IN THE LEASING AND PERMITTING PROCESS: 

For years, western producers have been frustrated by the uncertainty that the 

long timelines for operating on federal land create. From leasing through project approval and drilling permits, increasing regulatory requirements and often inefficient 

administrative processes increase time and cost while reducing the certainty producers need to create long term business plans for exploration, production and resource development. Policies and priorities vary widely from administration to administration, creating even more uncertainly and leaving companies unable to determine timelines and costs, raise capital, and to plan development. States and field 

offices operate under widely varying interpretations of regulations, and producers 

are subject to the different approaches among agency field offices that can add ad 

hoc requirements to permits that have no basis in law. Improving and clarifying 

current regulations was needed even before the addition of recently enacted leasing 

policies which added more redundancy to the process. In order to realize the full 

economic and jobs potential that western oil and natural gas offer, companies must 

have certainty in the process along with reasonable time and cost expectations to 

enable them to execute their business plans. 

STREAMLINING THE TIMEFRAME FOR COMPLETION OF ENVIRONMENTAL ANALYSIS

Many large projects are held up in multi-year delays in processing and completing 

environmental analysis under the National Environmental Policy Act. The BLM 

should undertake reform to streamline the process so that smaller projects that may 

include a dozen or so wells do not take months and years to complete the associated 

analysis, and that larger projects that may include thousands of wells do not take 

3 to 10 years to complete the associated analysis. We are including an analysis of 

NEPA delays that was completed by SWCA Environmental Consultants for the 

Western Energy Alliance for your consideration. 

RE-EXAMINING AND RE-ENGINEERING THE PRESENT PERMITTING PROCESS

The government needs a reorientation of the federal onshore oil and natural gas 

program. This should include a comprehensive re-engineering and reform of the entire federal onshore process, including leasing, project NEPA analysis, and permitting, to ensure the timely, efficient, predictable and responsible development of federal energy resources. Comprehensive reform should take advantage of emerging 

technologies and best practices, eliminate redundancies, and explore market mechanisms for achieving environmental protection. Government should refrain from implementation of new regulations without careful examination of the cost and benefit 

of current regulations. 

Question 1(b). Would you please explain how the BLM’s pending regulations on 

hydraulic fracturing would push oil and natural gas production off Federal public 

lands and Indian lands and onto state and private lands? 

Answer. States have demonstrated that they are in the best position to regulate 

oil and gas development and have a proven track record of regulating oil and gas 

activities. Governors Matt Mead (Wyoming), Susana Martinez (New Mexico), Gary 

Herbert (Utah), Jack Dalrymple (North Dakota), Brian Schweitzer (Montana) and 

Robert McDonnell (Virginia), as well as Attorney General Scott Pruitt (Oklahoma) 

have provided written statements that testify to the strong and efficient track 

record of states to regulate oil and natural gas production. States are in the best 

position to understand the unique aspects of their hydrology and geology to inform 

and tailor their regulations. Furthermore, states have demonstrated the ability to 

adapt their regulations to address any changes in oil and gas activities in a prompt 

manner. 

When the BLM rule was originally proposed, we requested that the BLM reconsider the rules and recognize the strong oversight provided by existing state and 

federal regulations because conflicting or duplicative federal requirements would 

delay development of abundant oil and natural gas without providing additional environmental protection. 

We believe that the need for the proposed rule has not been supported by technical or scientific information that demonstrate that present federal and state regulations are inadequate to assure that hydraulic fracturing of oil and natural gas 

wells drilled on federal public lands takes place in a safe an environmentally responsible manner. As we will explain further, API recommends that the proposed 

rule be withdrawn and that prior to promulgating a new rule, the BLM should undertake a careful analysis of the agency’s current regulations, onshore orders and 

other administrative practices concerning the regulation of drilling, well completion 

and production operations in collaboration with state agencies with similar reguVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00107 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
104 

latory mandates, and organizations such as the Ground Water Protection Council 

and STRONGER (State Review of Oil and Natural Gas Environmental Regulations). 

The record shows that there have been no incidents of contamination from hydraulic fracturing in over 1.2 million wells drilled over more than sixty years, and 

no groundwater contamination incidents from hydraulic fracturing operations that 

have occurred on federal public lands. Claims concerning the environmental and 

health impacts of hydraulic fracturing have turned out to be unsubstantiated or 

have resulted from activities or natural occurrences unrelated to hydraulic fracturing—the application of fluids under pressure for the purpose of initiating or propagating fractures in a target geologic formation in order to enhance production of 

oil and/or natural gas. 

We are concerned that the BLM has yet to show that it has carefully examined 

the potential effects of the proposed regulation on the costs of drilling operations 

on federal and tribal lands, and whether such costs might discourage new investment in such drilling operations without significant environmental benefit. More importantly, BLM has not shown that it has carefully examined whether the proposed 

regulations will increase or decrease production of natural gas and oil resources on 

federal lands that belong to the American people and provide revenues to the U.S. 

Treasury. The energy sector represented by API supports 9.2 million jobs and 7.7 

percent of America’s GDP. Even as the overall economy weakened the past several 

years, and millions of jobs were lost, the oil and natural gas industry expanded and 

created more than 86,000 new American jobs since the recession began. The resource basins of the American West are projected to generate 1.3 million barrels of 

domestic oil and condensate production a day by the year 2020, an amount that exceeds the current daily oil imports from Russia, Iraq and Kuwait combined. These 

basins likewise hold the potential to produce 6.2 trillion cubic feet (Tcf) of natural 

gas annually by 2020, an additional one Tcf from 2010 levels. The benefits to the 

nation and the region in terms of capital investment, jobs and energy security from 

development of these resource basins, the majority of which underlie multiple use 

federal public lands, are enormous, especially in this time of economic uncertainty. 

BLM states in the proposed rule’s preamble that it has developed the rule in response to ‘‘public concerns’’ related to hydraulic fracturing activities. The preamble 

states that ‘‘[T]he resulting expansion of oil and gas drilling into new parts of the 

country as a result of the availability of new horizontal drilling technologies has significantly increased public awareness of hydraulic fracturing and the potential impacts that it may have on water quality and water consumption.’’ Nevertheless, the 

agency has not shown that it has carefully examined whether those concerns are 

warranted based on the volume of information publicly available related to well 

stimulation activities that have occurred nationwide for decades. This operating 

record fails to show that actual instances of hydraulic fracturing operations have adversely affected public health or the environment. A rule of this significance should 

be based on facts, science, and engineering, not on unsubstantiated concerns that 

lack empirical demonstration. It has been long established that agencies must provide some factual basis for their policy decisions, and ‘‘that those facts have some 

basis in the record,’’ or they are arbitrary and capricious. 

As API noted in written comments provided to the Office of Management and 

Budget’s Office of Information and Regulatory Affairs June 11, 2012, API believes 

that the estimate of benefits and costs associated with the BLM’s proposed rule as 

described in the May 11, 2012 notice in the Federal Register is flawed and should 

be scrutinized and re-determined. The benefits of the proposed rule are overstated 

by unrealistic assumptions of baseline risks of subsurface contamination in the Low 

Environmental Risk Case and grossly unrealistic in the High Environmental Risk 

Case. The costs of implementing the proposed rule are understated by the assumption that there will be no additional delays in operations even though the proposed 

rule describes a number of additional approvals that will be required throughout operations to bring a well to completion, should the proposed rule be implemented. 

Rules that impose regulatory burdens and delay without net benefit are exactly the 

type of rules that the Administration has sought to prevent. See Executive Order 

13563 (agencies ‘‘must’’ craft regulations ‘‘only upon a reasoned determination that 

[their] benefits justify their costs,’’ that they ‘‘impose the least burden on society,’’ 

and ‘‘maximize net benefits... ’’). 

More recently, in its study ‘‘Future of Natural Gas,’’ MIT examined the potential 

risks of hydraulic fracturing to groundwater aquifers and found that ‘‘no incidents 

of direct invasion of shallow water zones by fracture fluids during the fracturing 

process have been recorded.’’ MIT based its conclusions on the environmental record 

of more than 20,000 shale gas wells drilled over a 10 year period. MIT reviewed 

the results of fracturing operations in the Barnett and Marcellus Shales and found 

105 

that in all cases the highest growth of the fractures remains separated from the 

groundwater aquifers by thousands of feet of formation. 

In addition, former BLM Director Bob Abbey testified before Congress and stated 

that BLM ‘‘has never seen any evidence of impacts to groundwater from the use of 

fracking technology on wells that have been approved by’’ BLM. Director Abbey 

added that BLM believes ‘‘that based upon the track record so far, [hydraulic fracturing] is safe.’’ Director Abbey’s testimony on the safety of hydraulic fracturing is 

in accord with former U.S. Environmental Protection Agency (EPA) Administrator 

Lisa Jackson’s testimony that there is no ‘‘proven case where the fracking process 

itself has affected water.’’ The evidence to date supports the conclusion that hydraulic fracturing poses no risk of subsurface contamination—a conclusion with which 

BLM and EPA apparently agree. 

Moreover, the relationship between hydraulic fracturing and drinking water resources is already the subject of a multi-year multi-million dollar research study 

currently being undertaken by the EPA. This national study includes a review of 

published literature, analysis of existing data, scenario evaluation and modeling, 

laboratory studies, and retrospective and prospective case studies. EPA released a 

2012 progress report and will release the final report at the end of 2014. 

API believes that the case has not been made for a federal, one-size-fits-all approach. Oil and natural gas exploration and production is currently regulated by 

comprehensive state and federal laws. These include laws regulating well design, 

water use, waste management and disposal, air emissions, surface impacts, health, 

safety, location, spacing, and operation. State regulation of oil and natural gas activities pre-dated federal regulation, and is particularly important because it allows 

laws to be tailored to local geology and hydrology. Organizations like STRONGER 

are available to help assess the overall framework of environmental regulations supporting oil and gas operations in a particular state, and could likewise be a resource 

for the BLM. States also exchange information on regulatory experiences and practices through periodic meetings of interstate organizations such as the Interstate Oil 

and Gas Compact Commission (IOGCC) and the Groundwater Protection Council 

(GWPC). 

Question 2(a). Please explain how liquefied natural gas exports would: 

Increase natural gas production and jobs in public land states, such as Wyoming, 

and Indian Reservations; and 

Answer. Exporting LNG will open up new markets which will increase natural 

gas production, including additional production on private, state, tribal and federal 

lands and in Wyoming. LNG exports will create jobs in the oil and natural gas industry, as well as the industries supplying the oil and natural gas sector with materials, equipment, and labor. These jobs would be created by the activities associated 

with the construction and maintenance of liquefaction facilities and increased natural gas production that would be required to support export markets. Recent studies indicate that each bcf per day of production supports between 25,000 and 35,000 

jobs. To put this in perspective, as a result of the current energy renaissance, the 

United States increased its production of natural gas from approximately 60 bcf/day 

in 2010 to approximately 70 bcf/day in late 2012, a significant increase to occur over 

just two short years. 

Virtually all studies concur that natural gas production will increase to support 

export volumes. The NERA study finds that in all three baseline scenarios, natural 

gas production increases. The EIA has estimated that 60 to 70 percent of LNG exports will be from increased production, with about 75 percent of the increased production coming from shale gas. The production of additional unconventional natural 

gas will support the creation of many new jobs as highlighted by the series of studies recently released by IHS. For example, an IHS report estimated that in 2012, 

36 Bcf/d of unconventional natural gas production already supports over 900,000 

jobs. 

A preliminary report by ICF International that modeled the impacts of LNG exports on the macro economy finds that there is a net gain in overall employment 

with LNG exports and that the jobs impact are larger the greater the export volumes. For example, in the mid-export case, where LNG export volumes reach about 

8 Bcf/d by 2035, approximately 309,000 jobs are created in 2035. The preliminary 

report by ICF International shows that even in the manufacturing sector there is 

a net increase in jobs because potential losses are offset by gains related to building 

and supplying LNG and olefin plants with equipment, building and supplying of materials and equipment for oil and gas production and processing, and general economic growth. According to the preliminary ICF International report, in the midexport case, where LNG export volumes reach about 8 bcf/d by 2035, manufacturing 

job growth reaches 31,000 jobs in 2035. 

106 

16 ICF International estimate for year end 2011 figure. 17 ICF International estimate as of Dec. 2012 based on current project list. 18Poten, BG Group, Credit Suisse, Facts Global. 

Other studies that have analyzed the employment impact of increased LNG exports conclude that the gains in jobs are greater than the losses. For example, in 

summarizing the employment of LNG exports, Levi concludes ‘‘The bottom 

line . . . is robust: job gains in directly affected markets are highly likely to be 

greater than job losses in markets hurt by higher natural gas prices.’’ In addition, 

Levi noted that ‘‘Most jobs supported by exports will be in gas production and in 

its supplies—including in energy intensive areas like steel and cement. My study 

estimates that those jobs will be roughly an order of magnitude larger than the jobs 

lost due to higher natural gas prices.’’ 

We are including with our response the preliminary results from the ICF International analysis of the economic impacts of LNG exports, which includes information on the positive employment opportunities. 

Question 2(b). Increase revenues (e.g., through severance taxes or royalties) to 

states, Indian tribes, and the Federal government? 

Answer. Corporate income taxes accrue to both State and Federal governments 

from oil and natural gas development. Any time that production occurs on federal, 

state, or tribal lands, the respective government receives the added benefit of additional revenue that is associated with the bonus bids, rentals, and royalties. From 

a federal standpoint, oil and natural gas production has provided billions of dollars 

to the government, and the potential is there for the government to receive billions 

more if production opportunities are expanded. In fact, the oil and natural gas industry contributes over $86 million a day to the federal government and we have 

the potential to do much more. With LNG exports, the country would see expanded 

production to meet the additional demand. The potential is certainly there for this 

additional production to occur on federal, state and tribal land, and those governments would in turn benefit from the additional revenues accruing. A recent IHS 

report estimates that projected revenue from unconventional development alone 

could reach a cumulative $2.5 trillion by 2035 with roughly half going to the federal 

government and half to state and local governments. 

RESPONSES OF JACK N. GERARD TO QUESTIONS FROM SENATOR ALEXANDER

Question 1. Given the advantage of low domestic natural gas prices that resulted 

from increased production from unconventional natural gas reserves, do we really 

have a problem since we might only export 10 percent of our natural gas? 

Answer. We are hopeful that we do not have a problem given the undeniable benefits that will accrue to the nation as a whole with the export of LNG from the 

United States. However, the U.S. is in a global competition for the development of 

LNG export facilities. According to ICF International, the current world LNG liquefaction capacity is estimated to be approximately 37 Bcf/d.16 A survey of under construction, planned, and proposed facilities around the world indicates approximately 

49.6 Bcf/d of new liquefaction capacity could come online by 2025 outside of the 

U.S.17 Approximately 11.3 bcf/d of capacity is currently under construction in Australia, Indonesia, Algeria and Angola. Add to that the fact that approximately 28.7 

Bcf/d of U.S. liquefaction capacity has been proposed and you get a potential total 

world LNG capacity of 115 Bcf/d. The expected worldwide demand for LNG falls far 

short of that potential supply. Various projections show that expected world demand 

for LNG will be in the range of approximately 50 Bcf/d to 65 Bcf/d by the year 

2025.18 A significant share of the proposed liquefaction capacity may not be built 

(i.e., of the 45 proposed LNG import facilities for construction in the United States, 

only 7 were actually built). 

Each day that we delay affirmative decisions on export applications puts U.S. 

projects at a competitive disadvantage in the global race to construct LNG facilities. 

Therefore, we must ensure that DOE acts expeditiously and moves forward with the 

approval of the pending applications so that we do not lose this critical opportunity. 

Question 2. At what percentage of exports, compared with the overall U.S. production of natural gas, does the U.S. lose its price advantage of natural gas that we 

have today? 

Answer. The expert analysis to date indicates that the U.S. will not lose its price 

advantage of natural gas under any of the scenarios examined. Testimony from representatives of industrial consumers demonstrates that the U.S. petrochemical industry can operate competitively if U.S. natural gas prices remain in the $6-8 range. 

In testimony before the Senate Energy and Natural Resources Committee in October 2009, Dow Chemical Company Director of Energy Risk Management Edward 

107 

19 NERA, ‘‘Macroeconomic Impacts of LNG Exports from the United States,’’ December 10, 

2012, p. 90. 

* All reports have been retained in committee files. 

20The Jan. 2013 Deloitte study, ‘‘Exporting the American Renaissance; Global Impacts of LNG 

Exports from the United States,’’ also analyzes international markets. 21Medlock, K.B. III, ‘‘U.S. LNG Exports: Truth and Consequence,’’ James A. Baker III Institute for Public Policy (Aug. 10, 2012), pp. 32-33. 

Stone stated that ‘‘U.S. petrochemical competitiveness depends on a multitude of 

factors, such as the relative cost of energy (including crude oil, coal, etc.), the relative cost of new facility construction, the strength of the economy in each global 

area, and the extent to which local industry is protected by local government policies. In general, we believe that if crude were in the $75-$100 range, and natural 

gas were available at a consistent $6-$8 dollar per MMBtu range, U.S. petrochemical facilities could be globally competitive.’’ If this is the case, then according 

to Dow Chemical Company’s own recent analysis, LNG exports should not jeopardize recent petrochemical industry expansion plans. As summarized by a May 

2012 Brookings report, the reference natural gas price forecast for all recent major 

studies, projected total natural gas prices even with LNG exports are in a range 

from $5.10 to $7.21 per MMBtu, well within or below the $6-8 range. In the NERA 

study, all of NERA’s reference case core scenarios projected prices below $7.50 per 

Mcf. NERA’s unconstrained LNG export case, which reached an export level of over 

15 Bcf/d, projected a natural gas price as high as $7.50 per Mcf, but only in 2030 

or at the end of the forecast projection. Therefore, recent studies projecting natural 

gas prices, even with very high and unconstrained LNG export levels, do not forecast natural gas prices that jeopardize planned petrochemical industry investment. 

In fact, the additional additive LNG costs of liquefaction and transportation create 

a natural ceiling on exports. For example, the NERA study compiled costs of exporting LNG from the U.S. Gulf Coast to various demand regions around the world. See 

Fig. 62 in the NERA report.19 NERA estimates that the total LNG transport costs 

to Europe, Korea/Japan and China/India can range from $6.30 to $7.14 and $8.39 

per MMBtu in 2015, respectively. If the U.S. Henry Hub natural gas prices are trading at $4, then U.S. LNG exports are economic in these consuming markets since 

the current prevailing LNG prices into Japan of about $16.50 per MMBtu is higher 

than the U.S. sourced LNG price of $11.14. If, however, U.S. Henry Hub prices rise 

to $10, then the price of LNG into Japan becomes greater than $16.50 per MMBtu 

effectively rendering U.S. LNG uneconomic. As Japan adjusts further to the tsunami impact on its nuclear power sector and LNG export projects come on stream 

around the world, the tsunami-impacted price of $16.50 is likely to decrease. If the 

price of LNG delivered to Japan were to drop to, say, $11.00, the incentive to export 

from the U.S. could disappear. 

The NERA study is one of the few studies to date that has incorporated the potential supply response by foreign competing suppliers of LNG that would limit the 

ability of the U.S. to export volumes of LNG.20 According to NERA*, this consideration proved to be quite important since in many of the hypothetical LNG export 

volumes considered in the EIA study*, the world market could not fully absorb the 

export volumes due to strong international competition from foreign LNG and natural gas thereby further limiting the potential for domestic price increases. Medlock 

summarizes this point by stating that ‘‘the analysis herein indicates that international market response will ultimately limit the amount of LNG that the US exports as a matter of commercial rationing.’’21

Brookings’ Study-by-study comparison of the Average Price Impact from 2015- 

2035 of 6 bcf/day of LNG exports (unless otherwise noted): 

Question 3. What are your projections for the amount of natural gas the U.S. will 

be producing in 10 years? 

Answer. As a trade association, API defers to the opinions and projections of the 

experts in the government and in the energy consulting business when it comes to 

future production. An analysis of projections of natural gas production from these 

organizations indicates that the U.S has an abundant natural gas resource base and 

outlook for natural gas production is more than sufficient to accommodate LNG exports as well as growing domestic demand. For example, the U.S. Energy Information Administration (EIA) projects that natural gas production will reach 78 bcf/d 

by 2025 in their latest AEO 2013 ER. In AEO 2012, the EIA was projecting 72 bcf/ 

d of natural gas production by 2025, while in the AEO 2011, the EIA was projecting 

66 bcf/d. (The AEO 2011 is the baseline that the EIA and NERA Consulting used 

in their analysis of the impact of LNG exports.) The upward trend in the outlook 

for natural gas production in the recent AEOs indicates the positive prognosis for 

shale gas and the continued expectation of robust supply growth in the next 10 

108 

22 ICF International, ‘‘ICF Base Case,’’ February 2013. 23 IHS Inc., ‘‘IHS America’s New Energy Future: The Unconventional Oil and Gas Revolution 

and the U.S. Economy,’’ October 2012, p.15. 

years. Commercial forecasters are even more optimistic than the EIA. ICF International and IHS Inc. project 88 bcf/d and 89 bcf/d of natural gas production by 

2025.22 23 Since commercial forecasters are continuously updating their assumptions 

on such parameters as well spacing, estimated ultimate recovery, and other factors 

that affect the outlook for natural gas supply, it is reasonable to conclude that the 

outlook for natural gas may be even rosier. 

Question 4. Under present policies, if you had to make a guess, what would be 

the range of the percentage of U.S. natural gas production that we would be exporting in 10 years? 

Answer. Similarly, API defers to the experts on the question of projected future 

exports. EIA currently projects that the U.S. will be exporting 3.4 bcf/d of natural 

gas by 2025. This of course will be contingent upon a host of complex factors that 

will play out in the global market, including global supply, global demand, and global LNG export capacity. However, API will reiterate its concern that our potential 

to export natural gas from the U.S. becomes less likely with each day that we delay 

the approval of LNG export applications. 

It is important to point out that the U.S. has demonstrated the ability to increase 

production significantly over a short period of time. In early 2006, U.S. marketed 

natural gas production was under 52 billion cubic feet per day (bcf/d). By late 2012, 

U.S. marketed production grew by over 18 bcf/d to 70 bcf/d, which equates to a 36 

percent increase in seven years. The growth rate for U.S. natural gas production 

was even greater in 2010 and 2011. From January 2010 to January 2012, U.S. production grew by over 10 bcf/d or 18 percent in just two years. These production increases are larger than many projections of the volume for LNG exports, and this 

demonstrates that the capacity is clearly there for the U.S. to increase domestic production of natural gas to satisfy the demands of the export market, while at the 

same time providing affordable supplies domestically. 

CONCLUSION

Once again, it was a privilege to have the opportunity to highlight the tremendous 

opportunity that we now have before us given our nation’s emergence as a global 

energy leader. The oil and natural gas industry stands ready to harness this great 

potential and help the country realize the important and significant benefits to be 

gained, which include the creation of thousands of jobs, the generation of government revenues, and enhanced energy security. 

109 

RESPONSE OF JOHN W. HICKENLOOPER TO QUESTION FROM SENATOR WYDEN

Question 1. Last week, I sent a letter to the Secretary of the Interior and to the 

White House encouraging the Administration to issue a strong regulation for hydraulic fracturing on Federal lands. At least four states (Wyoming, Arkansas, Idaho, 

and Montana) have a requirement for disclosure of the anticipated contents of the 

fracking fluid prior to the operation taking place. Colorado decided against that approach. What was the state’s reasoning? 

Answer. We heard from operators that they sometimes alter the contents of the 

fracking fluid at the last minute. It made sense to require the disclosure after the 

operation to avoid the unnecessary cost and confusion resulting from amending reports, especially since it didn’t seem to the Colorado Oil and Gas Conservation Commission (‘‘COGCC’’) that in the end there would be any substantive difference in the 

information that COGCC obtained. 

RESPONSE OF JOHN W. HICKENLOOPER TO QUESTION FROM SENATOR LANDRIEU

Recently, BLM announced that it would be issuing a new version of a proposed 

rule regulating hydraulic fracturing on Federal lands. This would be a revision of 

an earlier proposal that threatened to drastically increase the cost of hydraulic fracturing on Federal lands. I am hopeful that this new rule will represent a more levelheaded approach to regulation, one that leaves the final authority to regulate in the 

hands of states, who have successfully managed hydraulic fracturing for over 60 


gerard1.eps
110 

1 NERA Economic Consulting, Macroeconomic Impacts of LNG Exports from the United 

States, December 2012. 

years, with the help of the production industry, which has created a system of disclosure and self-regulation resulting in increased safety and public awareness. 

Question 1a. Given the successful track record of states and industry regulating 

the process of hydraulic fracturing, do you agree that it makes the most sense to 

retain final authority in the hands of states, recognizing that government would assist in the creation of broad standards, rather than ceding total control to the Federal government? 

Answer. We don’t believe there is no role for the federal government, but, on balance, we believe the states are better positioned to regulate effectively. Given differences in geology, as well as development patterns, locations and drilling intensity, 

a ‘‘one size fits all’’ approach is not as efficient as state-by-state regulations. In January 2012, Colorado passed one of the strongest rules in the country for disclosure 

of hydraulic fracturing fluids and since then many other states have followed Colorado’s lead. If the federal agencies do proceed with rules, we would hope that they 

look to the state rules as models, defer to states that meet certain regulatory control 

thresholds and avoid duplication of the regulatory process in terms of paperwork 

and other aspects of permitting and control. 

Question 1b. Do you believe that increased Federal regulation would result in a 

decline in production activities, negatively affecting the economies of many communities which rely on these industries for economic support? 

Answer. Increased regulation does not necessarily result in a decline in production 

activities. In Colorado, we have undergone three rulemakings: a regulatory overhaul 

in 2008; hydraulic fracturing disclosure in 2012; and this year COGCC adopted 

rules for setbacks and groundwater monitoring which are among the strongest in 

the country. Regulations must constantly evolve to accommodate changing development patterns and technologies and, in Colorado, production has not declined as a 

result of these rules. Nevertheless, for the reasons stated above, we do think the 

states are best suited to establish their regulatory frameworks. In Colorado, we believe that we can best ensure our natural resources and environment are protected, 

while fostering the responsible development of oil and gas resources. 

RESPONSES OF JOHN W. HICKENLOOPER TO QUESTIONS FROM SENATOR ALEXANDER

Question 1. Given the advantage of low domestic natural gas prices that resulted 

from increased production from unconventional natural gas reserves, do we really 

have a [domestic price] problem [if U.S. exports increase] since we might only export 

10% of our natural gas? 

Answer. We understand that there is intense debate over the future of U.S. natural gas exports. Proponents say increased exports would create thousands of jobs, 

reduce the trade deficit and enhance national security. Opponents argue shipping 

large amounts of natural gas abroad could cause price hikes for consumers and 

manufacturers, many of which have benefited from recent low natural gas prices. 

A December 2012 study commissioned by the U.S. Department of Energy and conducted by NERA Economic Consulting found that U.S. natural gas prices will increase when the U.S. exports liquefied natural gas (LNG1). They conclude, however, 

that the global market will limit how high U.S. natural gas prices can rise under 

pressure of LNG exports. This report projects that in spite of limited price fluctuations, even in the most extreme exporting scenario, the U.S. will gain net economic 

benefits from allowing exports. In every one of the market scenarios examined, net 

economic benefits increased as the level of LNG exports increased. 

Question 2. At what percentage of exports, compared with the overall U.S. production of natural gas, does the U.S. lose its price advantage of natural gas that we 

have today? 

Answer. This is a very complex question since there are several factors that influence the future price of LNG exports from the U.S. into world markets, including 

global supply and demand conditions and the future availability of shale gas in the 

U.S. The same study referenced above, conducted by NERA Economic Consulting 

and commissioned by the U.S. DOE, provides an analysis of natural gas prices in 

the U.S. relative to several different export scenarios. The study concludes that natural gas price changes attributable to LNG exports remain in a relatively narrow 

range across the entire suite of export scenarios studied. Natural gas price increases 

at the time LNG exports begin could range from zero to $0.33 in 2010 dollars per 

thousand cubic feet (2010$/Mcf). The largest price increases that would likely be observed after 5 more years of potentially growing exports could range from $0.22 to 

$1.11 (2010$/Mcf). The study employs a complex macroeconomic model to derive 

111 

2 U.S. Energy Information Association, U.S. Department of Energy, Annual Energy Outlook 

2012, http://www.eia.gov/forecasts/aeo/tableslref.cfm. 3 Ibid. 

these estimates and corresponding export percentages are not clearly identified in 

the report. 

Question 3. What are your projections for the amount of natural gas the U.S. will 

be producing in 10 years? 

Answer. We must defer to national experts on projections for the amount of natural gas the country will be producing in the next decade. The U.S. Energy Information Administration (EIA) is the statistical and analytical agency within the U.S. 

DOE and their products are independent of approval by any other officer or employee of the U.S. Government. EIA’s 2012 Annual Energy Outlook projects that 

natural gas production in the U.S. will increase by three trillion cubic feet (Tcf) in 

the next decade, to approximately 26 Tcf in 2023.2

Question 4. Under present policies, if you had to make a guess, what would be 

the range of the percentage of U.S. natural gas production that we would be exporting in 10 years? 

Answer. Many factors within the global natural gas market will affect U.S. exports, including international supply and demand for natural gas. Again, we must 

defer to national experts on projections of U.S. natural gas exports in the next decade. The EIA’s 2012 Annual Energy Outlook projects that natural gas exports will 

be approximately 3.32 Tcf in 2023, which would be just under 13% of U.S. production.3

RESPONSES OF ANDREW N. LIVERIS TO QUESTION FROM SENATOR MURKOWSKI

Question 1. Dow stated previously before this committee (2009) that U.S. petrochemical facilities could be globally competitive if U.S. domestic prices fell within 

the $6-$8 per MMBtu range. Has your position changed today and if so, can you 

explain why? 

Answer. Dow’s statement relates to competitiveness, which is a function of several 

interdependent variables. There is no absolute price range that can guarantee competitiveness. When making investment decisions, we look at the following parameters with respect to feedstock and energy costs: the expected absolute cost, the cost 

relative to competing geographies/the world price of oil, and volatility. The expected 

absolute cost must be lower than our other geographic alternatives. The same is 

true for volatility. Price and volatility are generally a function of supply/demand balance but can be subject to market shocks and distortions. 

Question 2. You indicated in testimony before this committee that you support the 

requirement for a public interest determination to obtain a license to export LNG 

to non-FTA countries, particularly because natural gas is utilized by certain industries as a feedstock. Do you support a similar public interest determination for exports of products that other industries in the U.S. may use for value-added products? If not, why not? Why should LNG exports be regulated differently than other 

exports? 

Answer. Over 70 years ago, Congress determined that natural gas exports should 

be measured against the public interest and enacted into law an export licensing 

regime to require that natural gas exports not be inconsistent with the public interest. The rationale for this action in the Natural Gas Act was that natural gas is 

a strategic commodity that has a critical impact on the well-being of consumers, the 

health of the economy, the security of the nation and other public interests. States 

and the federal government have enacted policies that virtually compel consumers 

to purchase natural gas, whether through environmental regulations or mandated 

fuel switching. The same cannot be said for other commodities, making natural gas 

fundamentally unique. 

Dow, as just one of many affected constituencies, has submitted comments to the 

DOE dated January 24, 2013 and February 25 2013 urging DOE to take the steps 

necessary to ensure that, the licensing of natural gas exports fully meets the public 

interest. 

RESPONSE OF ANDREW N. LIVERIS TO QUESTION FROM SENATOR LANDRIEU

Dow is one of several companies which have greatly benefitted from increased 

natural gas production, with this new, affordable source of gas allowing your company to invest billion in my state and others, reopening one facility and planning 

more. You have expressed a desire to see that natural gas exports are managed in 

a responsible manner, so as not to place undue burden on American manufacturing. 

112 

One of your key points has been the number of proposed export facilities, which, 

if all were approved and operating at full capacity, would represent 19 bcf per day 

of export, almost 1/3 our current demand. However, many believe that this figure 

is not achievable and will be limited by the capital available to finance construction. 

Indeed, in a New York Times article published January 5, Charif Souki, CEO of 

Cheniere, one of the companies proposing an export terminal predicted that by 2018, 

the country would manage to export only one billion to two billion cubic feet of gas 

a day, or roughly 2 percent of current domestic consumption. In 10 years, after two 

to four projects have received permits and have been built, he said he expected exports to grow to three billion to five billion cubic feet a day. 

Question 1. Do you believe that a market-determined level of export, reflecting the 

realities of financing and market entry, could be maintained without placing undue 

pressure on manufacturers like yourself who are poised to invest billions in new and 

existing facilities? 

Answer. It is critical to remember that although natural gas is a newly abundant 

resource, natural gas exports should not be viewed in isolation from the overall dynamics of the aggregate natural gas market. In fact, it is important to note that 

there are currently 29.4 bcf/d of LNG export projects that have applied to the DOE. 

Before acting on export applications, DOE should establish criteria and metrics for 

natural gas export public interest determinations required by the Natural Gas Act 

through an open process that elicits input from the broad spectrum of affected U.S. 

stakeholders. Established criteria and metrics will enable DOE to consider, based 

on appropriate data, projections and analysis, anticipated demand and the supply 

needed to maintain market balance (among other factors). An approach that rushes 

toward exports without a full understanding of the implications builds higher risk 

into the system and will change how investors plan for the future. 

Further, we do not believe that financing will be a limiting factor as many have 

suggested. As evidence, financing for LNG projects in Australia has not been a factor despite having relatively higher natural gas prices. In fact, the Ichthys LNG 

projects recently announced the biggest projected financing ever arranged in international financial market at roughly US$20 billion. The role of export credit agencies in financing projects cannot be discounted. Financing was not an issue in overbuilding LNG import facilities in the U.S. not so long ago. 

We believe the normal dynamics of a market for domestic natural gas can co-exist 

with preserving the public interest so long as abrupt shocks, such as severe speculative price volatility, and major artificial distortions, such as cartel pricing, can be 

ameliorated. This is the challenge facing DOE: how to balance natural gas exports 

with all of the other aspects of the public interest in the short, medium and the 

long term. 

RESPONSES OF ANDREW N. LIVERIS TO QUESTIONS FROM SENATOR BARRASSO

Question 1. In your testimony, you express concern about environmental regulations. You state ‘‘overly restrictive environmental regulations.on hydraulic fracturing could greatly reduce future supplies of natural gas.’’ You also ‘‘urge caution 

in considering policies that encourage fuel switching between natural gas and coal.’’ 

To what extent is DOW concerned about: (a) Federal hydraulic fracturing regulations; (b) EPA rulemakings that encourage fuel switching between natural gas and 

coal; (c) a tax on carbon emissions; and (d) proposals to establish a clean energy 

standard? 

Answer. We are concerned about governmental actions that would restrict supply 

and/or accelerate demand because of the potential impact on domestic natural gas 

prices. We believe it is critical that DOE, in making its public interest determination under the Natural Gas Act, consider the impact of all policies that could affect 

either supply or demand. 

We are also concerned about policies that would rapidly and excessively drive coal 

and other energy sources out of power generation. We firmly believe that the nation’s interest is best served by maintaining robust diversity in power generation 

sources. Dow has and will continue to evaluate any climate change policies in the 

context of its effects on U.S. competitiveness in general and energy sources such as 

natural gas. We would be very concerned about any policies that call on a single 

fuel source to carry a disproportionate share of the nation’s energy burden. History 

shows us that whenever we have done so, we have been disappointed. 

RESPONSE OF ANDREW N. LIVERIS TO QUESTIONS FROM SENATOR ALEXANDER

Question 1. Given the advantage of low domestic natural gas prices that resulted 

from increased production from unconventional natural gas reserves, do we really 

have a problem since we might only export 10 percent of our natural gas? 

113 

Answer. There is a significant level of uncertainty regarding exports and the 

broader natural gas market, and the stakes are quite high. Some parties claim that 

exports will not exceed 10 percent of natural gas production; we believe that it is 

quite likely that higher levels of exports would occur. DOE has already approved 

natural gas exports accounting for well over 50 percent of annual production. If even 

a significant portion of that already-approved volume is exported, then exports could 

easily exceed 10 percent of production. Approval of pending LNG export applications 

would permit LNG exports to flow to non-FTA countries that have markedly more 

demand for U.S. natural gas, making it far more likely that a higher percentage of 

production would be exported, with potentially severe consequences for domestic 

users of natural gas. 

Given the threat of exports at that level, broad issuance of natural gas export permits could lead to natural gas price spikes. Speculation in natural gas trading has 

in the past driven the price up beyond what the purely physical market would indicate. This is what drove prices up in the last decade. Therefore, the price movement 

would likely occur well before the actual exports occur, due to expectations in the 

market. 

In these circumstances, we believe DOE should take a cautious and measured approach to assuring an appropriate balance between natural gas exports and the public interest based on criteria and metrics established through a public comment 

process. 

Question 2. At what percentage of exports, compared with the overall U.S. production of natural gas, does the U.S. lose its price advantage of natural gas that we 

have today? 

Answer. We believe that the domestic demand for natural gas is going to increase 

significantly over the next 10 to 15 years and we are skeptical that supply will be 

able to keep pace. Accordingly, we see prices increasing from their current levels 

regardless of the level of exports. Exports will constitute additional demand and will 

serve to move prices even higher than they would otherwise be. Today we might 

be able to export 10 percent of our production without a significant impact on price. 

In out years, that may not be the case. Our analysis shows the potential for significant demand spikes in the 2017-2020 timeframe, and that an unprecedented level 

of production will be needed to balance the market. In a supply-constrained market, 

or even a balanced market, exports will have a far greater price impact than they 

would in a market with ample supply such as now. Australia currently exports 

roughly half of its natural gas production and in doing so it has imported much 

higher natural gas prices, placing its energy-intensive industries in a difficult competitive position and subjecting its population to much higher energy costs. 

We believe that exports of natural gas should not be viewed in isolation from the 

overall supply/demand dynamics of the aggregate natural gas market. Indeed, current law requires exactly just such an evaluation prior to approval of natural gas 

export applications. Congress and the administration should work to define what is 

in the public interest to determine a prudent and rational approach that balances 

the interests of the American consumer and domestic needs with exports. Rather 

than a particular level of exports, Dow advocates movement beyond a single report 

by one economic consultancy to an open process to enable the full profile of U.S. 

stakeholders to provide economic and non-economic input to DOE to inform establishment of criteria to make public interest determinations. We are in year 4 or 5 

of a 100 year energy advantage. There are still many unknowns, so we should exercise prudence as we move ahead. 

Question 3. What are your projections for the amount of natural gas the U.S. will 

be producing in 10 years? 

Answer. Dow is not a natural gas producer, but rather we are one of the world’s 

largest consumers. For that reason, our focus is on understanding demand first and 

then the supply that would be required to maintain balance. Our analysis shows the 

potential for significant disconnect of demand from supply in the 2017-2020 timeframe in a high export case, and that an unprecedented level of production will be 

needed to balance the market without harming manufacturers and raising prices 

significantly for consumers. With regard to increasing supply/production, it is currently unclear how quickly this can happen and at what cost. 

Question 4. Under present policies, if you had to make a guess, what would be 

the range of the percentage of U.S. natural gas production that we would be exporting in 10 years? 

Answer. Natural gas is a vital and finite natural resource that plays a significant 

role in the overall health of the U.S. economy. Under present policy, the DOE is 

required by law to determine whether export applications are in the public interest 

and the level of exports in 10 years will in large part be based on that determination. We believe DOE needs more information in order to accurately assess the pubVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00117 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
114 

1 U.S. Environmental Protection Agency, Clean Energy - Air Emissions, available at http:// 

www.epa.gov/cleanenergy/energy-and-you/affect/air-emissions.html. 2Deutsche Bank Group-DB Climate Change Advisors, Comparing Life-Cycle Greenhouse Gas 

Emissions from Natural Gas and Coal (2011), available at http://www.worldwatch.org/system/ 

files/pdf/NaturallGaslLCAlUpdatel082511.pdf. 3 Alvarez, R. et al., Greater focus needed on methane leakage from natural gas infrastructure, 

published in Proceedings of the National Academy of Sciences (2012), available at http:// 

www.pnas.org/content/early/2012/04/02/1202407109.abstract. 4 U.S. Energy Information Administration, Natural Gas Gross Withdrawals and Production, 

2010 data. available at http://www.eia.gov/dnav/ng/nglprodlsumldculNUSla.htm; U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks (1990- 

2009) (Apr. 15, 2012). Net emissions of methane were just over 600 bcf (billions of standard 

cubic feet), while gross withdrawals were approximately 26,800 bcf; this implies a net leakage 

of approximately 2.3 percent 5 Howarth, R. et al., Methane Emissions from Natural Gas Systems, Background Paper Prepared for the National Climate Assessment (reference number 2011-0003) (Feb. 25, 2012), available at http://www.eeb.cornell.edu/howarth/Howarth%20et%20al.%20-- 

%20National%20Climate%20Assessment.pdf. 

lic interest and determine an appropriate balance with the public interest. Dow is 

asking DOE to solicit additional comments regarding the impact of natural gas exports on jobs, consumer energy prices, trade levels, environmental issues, and U.S. 

energy independence and to establish public interest criteria against which to measure exports. 

However, as noted above, our analysis shows the potential for significant demand 

spikes in the 2017-2020 timeframe, and that an unprecedented level of production 

will be needed to balance the market without harming manufacturers and raising 

prices significantly for consumers. It is for the reason that we are urging a cautious 

approach. 

RESPONSE OF FRANCES BEINECKE TO QUESTION FROM SENATOR WYDEN

Question 1. Ms. Beinecke, you note in your testimony that one of the benefits of 

natural gas, of course, is that when you burn it, it releases fewer greenhouse gas 

emissions than resources like coal. This benefit, though, can be offset if more natural gas leaks in to the atmosphere. There are conflicting reports about the level 

of methane leakage from natural gas production and transport, ranging from as little as 0 percent leaked to as much as 9 percent in some reports for some basins. 

How can we get our arms around this question of how much methane is being 

leaked, and what are your thoughts for how we can make sure that leakage is minimized? 

Answer. Natural gas contains less carbon per unit of energy than coal and thus 

produces fewer greenhouse gas emissions per unit of useful electric or thermal output when combusted.1 But that is not the whole picture—natural gas operations 

also emit significant amounts of methane, a powerful greenhouse gas, during the extraction, production, processing, transmission, and distribution steps. 

According to most comparative lifecycle assessments of greenhouse gas emissions 

during electricity production from natural gas and coal, natural gas would produce 

approximately 50 to 60 percent fewer emissions than coal, if there were no methane 

emissions at all from the natural gas industry.2

However, when the impact of methane emissions from the natural gas industry 

is included in the analysis, it can be estimated that natural gas provides a clear 

advantage over coal only when methane emissions as a fraction of total production 

are below 3 percent. When emissions are between 3 percent and around 7-8 percent, 

natural gas does not have an advantage over coal in the near-term, from a greenhouse gas perspective; this is because methane leakage has more deleterious effects 

in the nearer term. When emissions exceed 7-8 percent, natural gas has no advantage over coal at any time, from a greenhouse gas perspective.3 The numbers above 

are for electricity generation from natural gas or coal; when using these fuels directly for useful thermal output, natural gas squanders its advantage over coal from 

a greenhouse gas perspective at even lower methane leakage levels. 

In its latest comprehensive inventory, the EPA estimated methane emissions from 

the oil and gas industry to be about 2.5 percent as a fraction of total production.4

Recent studies have suggested that emissions could be much higher, in the range 

of 7 percent or higher in certain basins.5 The oil and gas industry claims that industry-wide emissions may be even lower than EPA’s current estimate. Also, EPA recently released the first set of greenhouse gas emissions reporting data from the oil 

115 

6 U.S. Environmental Protection Agency, Greenhouse Gas Reporting Program, 2011 Data, 

available at http://epa.gov/ghgreporting/ghgdata/reported/index.html. 7 Environmental Defense Fund, New Study To Provide Important, Direct Measurement Data 

On Methane Emissions From Natural Gas Production (2012), available at http://blogs.edf.org/ 

energyexchange/2012/10/10/new-study-to-provide-important-new-direct-measurement-data-onmethane-emissions-from-natural-gas-production/. 8 NRDC, Leaking Profits: The U.S. Oil and Gas Industry Can Reduce Pollution, Conserve Resources, and Make Money by Preventing Methane Waste (Mar. 2012), available at http:// 

www.nrdc.org/energy/leaking-profits.asp 9 U.S. Environmental Protection Agency, Federal Register Vol. 77, No. 159, Oil and Natural 

Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews (Aug. 16, 2012), available at https://www.federalregister.gov/articles/2012/08/16/2012-16806/oil-and-natural-gas-sector-new-source-performance-standards-and-national-emission-standards-for. 

and gas sector, required by Congress in 20086. The reporting rule data confirms that 

methane leakage is significant and provides additional insight into sources of leakage. However, the reporting requirements omit a number of methane sources within 

the industry, and so the data does not provide a complete picture of total methane 

emissions from the sector. As such, much more accurate and verified data is needed 

to ascertain the true extent of methane emissions from the oil and gas sector. NRDC 

is encouraged that more studies are beginning to be conducted to address this important issue.7

Regardless of exactly how much methane is being leaked, it is imperative to reduce methane emissions to the greatest extent possible, to a sector leakage rate of 

well below 1 percent. Fortunately, according to our report last year,8 NRDC found 

that 10 tried and tested, cost-effective technologies exist today that could control up 

to about 80 percent of these emissions. Some of these are: a) technologies to control 

emissions soon after a well is fracked, as well as while the well is operating; b) better seals for compressors; c) gas flow controllers with reduced leakage; and d) better 

leak detection and repair programs. (Importantly, these same technologies would 

help control toxic air pollutants that are known to cause serious health issues.) 

The technologies described in NRDC’s report are cost-effective. Most require a 

modest upfront investment. But in most cases these investments would pay for 

themselves in less than two years, while some investments could take a little longer. 

This is because these technologies reduce the leakage of methane, which after being 

retained or captured can be sold as fuel or used onsite. However, these technologies 

are not currently being used widely enough by industry. 

A number of these controls are required for some sources under EPA’s recently 

updated new source performance standards to control volatile organic compounds, 

or VOCs, which are co-emitted with methane.9 But due to their incomplete coverage, 

the standards fail to reach the vast majority of methane emissions from the sector. 

Thus, more can and needs to be done. Methane pollution should be addressed directly, instead of as a co-benefit of other pollution standards, which will more effectively control methane leakage by reaching methane sources not covered by the 

VOC standards. More importantly, existing sources of methane leakage should be 

addressed, as they contribute to the bulk of methane leakage from the industry. The 

Clean Air Act confers EPA with the authority and obligation to undertake these activities. 

Accordingly, we need stronger standards from the EPA to ensure that methane 

emissions from the oil and gas industry are significantly reduced, using technologies 

that are viable and cost-effective. This can be done by EPA at the national level, 

and the agency has legal tools available to address region-specific circumstances in 

conjunction with the states. 

RESPONSE OF FRANCES BEINECKE TO QUESTIONS FROM SENATOR ALEXANDER

Question 1. Given the advantage of low domestic natural gas prices that resulted 

from increased production from unconventional natural gas reserves, do we really 

have a problem since we might only export 10 percent of our natural gas? 

Question 2. At what percentage of exports, compared with the overall U.S. production of natural gas, does the U.S. lose its price advantage of natural gas that we 

have today? 

Question 3. What are your projections for the amount of natural gas the U.S. will 

be producing in 10 years? 

Question 4. Under present policies, if you had to make a guess, what would be 

the range of the percentage of U.S. natural gas production that we would be exporting in 10 years? 

Answer. NRDC does not have a position on LNG exports and has not yet engaged 

in analysis on these issues. 

116 

* All figures have been retained in committee files. 

Right now, NRDC’s shale oil and gas work is focused on the environmental, 

health and community impacts of the fracking production process. However and 

wherever shale has is used, protecting against the environmental and health impacts of production is critically important. 

Specifically, we’ve been working aggressively to advance stringent and protective 

safeguards at the local, state and national level. And in addition to our regulatory 

efforts, we recently launched NRDC’s Community Defense Project, a major new initiative to help local communities protect and defend themselves against the risks 

presented by fracking through the courts and the halls of state capitols. 

Additionally, we are devoted to advancing policies to promote the development of 

real clean energy sources, like energy efficiency and renewable power sources, like 

wind and solar, as quickly as possible. 

NRDC did submit comments to DOE on the specific issue of a study that DOE 

commissioned on the price and economic impacts in the United States of LNG exports. We pointed out some flaws in the study that tended to underestimate the 

price impact of LNG exports and also critiqued the study for failing to take into account the economic impacts (social costs) of carbon pollution. Finally, we urged DOE 

to look at the potential economic and environmental impacts of LNG exports in 

other countries, including China and India, which are heavily dependent on coal. 

RESPONSES OF KENNETH B. MEDLOCK TO QUESTIONS FROM SENATOR MURKOWSKI

Question 1. Dow has expressed concern about the ability of the natural gas supply 

in the U.S. to meet potential increases in domestic demand, particularly from the 

manufacturing, power and transportation sectors. Do you have a response to this 

concern? 

Answer. The concern seems to be actually one of how price will respond to demand growth from many sectors. First, the price impact of demand growth in multiple sectors is ultimately dependent upon the elasticity of supply. If supply can expand significantly as price rises (meaning it is very elastic—such as in Case 1 in 

Figure SM.1*), then the capabilities of the upstream sector are more than adequate 

to meet demands from multiple sectors. Figure SM.1 indicates the effect of different 

supply capabilities in response to a particular demand increase due to exports. Research done at the Baker Institute indicates that domestic supply is highly elastic, 

which would suggest that price will not rise substantially as demand grows. 

Second, the opportunity for demand growth in each of the aforementioned sectors 

is a function of the domestic price of gas. If the price of gas begins to rise, then 

the opportunities for demand growth are mitigated, although not at the same pace 

in each sector. For example, as gas prices rise, the opportunity for natural gas into 

transportation is likely reduced first. Then, certain sectors in manufacturing will be 

affected, followed by power generation. Importantly, the rank order is not independent from policy. For example, as EPA actions aimed at reducing certain pollutants become binding, coal-fired power generation will be displaced in favor of natural gas, largely due to the already large installed natural gas generation capacity 

in the US. So, gas demand in power is likely to be the most responsive margin along 

which demand growth occurs in the US. 

Industrial sector opportunities will persist as long as the price of natural gas in 

the US is lower relative to price in other regions. This is a very important point 

because low price in the US is but one necessary condition—it is not sufficient. In 

fact, in the late 1990s domestic gas price scarcely increases and was averaging in 

the mid $2/mcf range, but domestic industrial gas demand was declining due to efficiency improvement and certain activities moving offshore to cheaper supplies 

(places such as Trinidad). So, the price abroad is also an important factor when determining industrial demand opportunities domestically. Indeed, if domestic demand 

rises to the point that domestic price also rises, then some of the presupposed industrial demand may not actually materialize because the opportunities for expansion 

will be deemed greater elsewhere. 

Policy makers must ultimately grapple with (i) whether or not intervention is 

warranted and (ii) if so, what can (and perhaps even should) be done to limit the 

increases in demand for US-produced natural gas. For example, if there is a policy 

orientation to seeing the industrial sector expand, then the EPA rule-makings that 

stand to promote the expansion of gas demand in power generation must ultimately 

be challenged. More generally, if the concerns are that expanded demand will compromise the opportunity for industrial activity, then one could argue government 

should take steps to limit demand growth on multiple fronts—power generation deVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00120 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
117 

mands, transportation demand, and exports. This seems ill-advised when prices are 

allowed to serve a rationing function that will ensure the greatest overall economic 

benefit—for example, when price discovery occurs in a transparent marketplace 

driven by supply-demand fundamentals. 

However, if domestic supply is indeed highly elastic, as Baker Institute research 

indicates, then the concerns are inconsequential. In effect, there is room for growth 

from multiple sectors because supply is adequate. 

Question 2. The debate about LNG exports has included arguments for action by 

the government to limit the volume of LNG exports to ensure the domestic price 

of natural gas remains low. When the U.S. has imposed price controls in the past, 

this has resulted in gas shortages. What would be the impacts to the natural gas 

industry and U.S. economy from efforts by the government today to restrict the level 

of exports? 

Answer. Restrictions on export volumes, or any restrictions for that matter, create 

market distortions. Constraining the margins of demand response can have undesirable consequences because it effectively subsidizes certain sectors at the expense of 

others. More specifically, rents accrue to the consumers who are not constrained, 

largely because revenue earning opportunities are diverted from other sectors. This 

is distortionary by definition. Accordingly, the overall welfare effect of such a policy 

is generally negative. 

Importantly, it is not likely that shortages such as those in the 1970s would 

emerge, because the proposed policy is not one of direct price control. It is indirect 

via quantity controls. The domestic price, under a policy of export restrictions, 

would still equilibrate supply and demand, so the central tendency should still reflect long run marginal cost. The quantity control would result in lower domestic 

production, but the result would be driven by lower demand. 

Question 3. During the hearing before this committee, there was testimony that 

natural gas prices index to oil prices worldwide and concern expressed that this will 

lead to higher gas prices in the U.S. if LNG exports to non-FTA countries are approved. Do you have a response to this concern? 

Answer. This is simply not true. To begin, oil indexation of natural gas occurs in 

a contract-specific manner. So, an individual buyer might be willing to contract a 

certain proportion of their supply using oil-indexed terms. This only occurs if the 

buyer has concerns about the ability to procure supply, which is indicative of a lack 

of liquidity. Historically, this has been true in Asian and European markets due to 

high fixed costs of entry. However, the oil-indexed paradigm has already been significantly altered in Europe following the opening of several hubs on the continent 

and expansion of various supply options. In Asia, the market is changing much 

more sluggishly, but buyers in the Asian market are already arguing for gas-indexed purchase agreements, a development triggered by supply growth not only in 

the US, but also Australia, East Africa, the Middle East, and Russia. 

In fact, in the last 10 years the spot (or short term) market in both Asia and Europe has grown substantially. In Europe, spot and short term sales have jumped 

from less than 10 percent of total LNG sales in 2000 to almost 25 percent of total 

LNG sales in 2011, and the pipeline market is witnessing a similar evolution. In 

Asia, the trend is similar, with spot and short term sales increasing from around 

2 percent of total LNG sales in 2000 to just over 20 percent of total LNG sales in 

2011 (see *Figures SM.2 and SM.3). In addition, the contracts in place to consumers 

in each market are not dictating flow. In fact, Figures SM.2 and SM.3 together indicate significant diversion from the Atlantic to Pacific basin as total trade in the Atlantic basin falls well short of contracted volume in 2011 but the opposite is true 

in the Pacific basin. 

Importantly, the spot price in Europe is below the typical oil-indexed price, as was 

the spot price in Asia until the disaster at Fukushima, which led to an unexpected 

demand shock that drove a classic basis blowout in the Asian price (see *Figure 

SM.4—Asian price is JKM, European price is NBP, and US price is Henry Hub). 

As nuclear capacity comes back online in Japan, the spot price in Asia will decline 

back to its ‘‘normal’’ relationship with NBP. Growth in spot market trade is expected to continue, so the price in any exporting region will at most be the spot price 

in the importing region minus the cost of liquefaction and transportation. Thus, if 

the long run price of gas in Asia is $10/mcf, then the price in the US should be approximately $4.50-$5/mcf, which is still significantly lower than oil-parity. This simply means is that a basis differential should persist due to transport costs. This is 

even true across the pipeline network in the most liquid natural gas market in the 

world—North America. 

118 

RESPONSE OF KENNETH B. MEDLOCK TO QUESTION FROM SENATOR BARRASSO

Question 1. In your opening statement, you mentioned that the three countries 

‘‘most heavily impacted’’ by the increase in natural gas production in North America 

would be Russia, Iran, and Venezuela. 

a. Would you please explain how liquefied natural gas (LNG) exports from the 

United States would impact each of these nations (and their state-owned enterprises), respectively? 

b. Would you please explain how LNG exports from the United States would promote U.S. national security interests and the energy security of key U.S. allies such 

as NATO member nations and Japan? 

Answer. To begin, the statement was made in reference to a study we performed 

for the Department of Energy Office of International Policy and Affairs. In that 

study (attached as an addendum), we simulated a world with known shale resources 

and compared it to a world without any shale. The second case was meant to capture the outcome that most anticipated would occur in the early 2000s, when large 

investments were being made to import natural gas to the US. A key result of that 

work was that Russia, Iran and Venezuela were the three countries most disadvantaged by the emergence of shale in the United States. So, the dramatic change in 

North American gas market has already had a significant ripple effect throughout 

the global gas market. Importantly, this result is one very important reason why 

this question has to be considered in an international trade context, as pointed out 

in ‘‘US LNG Exports: Truth and Consequence’’ (also attached as an addendum). 

LNG exports from the US—were they to occur—would likely extend those impacts. This follows from the fact that US LNG exports would be directed at markets 

in Asia, and potentially Europe. Asian demands, should they continue to grow, will 

naturally pull on resources in Russia and the Middle East, as well as Southeast 

Asia, Africa and Australia. In fact, Russia is a natural partner for pipeline trade 

with Asia—barring of course any geopolitical constraints—and the Middle East is 

a natural waterborne trade partner with Asian consumers—as witnessed by trade 

in multiple commodities. To the extent that US supplies are sold to Asian consumers, then, all else equal, this would displace supplies from other locations. This 

would reduce dependence of Asian consumers, and the world for that matter, on 

supplies from Russia and the Middle East. Since Iranian reserves are among the 

world’s largest, Iran is impacted directly. Importantly, much of this is an impact 

that is most likely immaterial in the near term, but longer term could be substantial. However, expectations about future market conditions are very much governed 

by actions today, and, in turn, those expectations drive future investment decisions 

and hence are influential to future outcomes. 

LNG exports will not likely have any real impact in the short to medium term 

on Venezuela. It is not currently a significant player in global natural gas markets, 

and the political and economic fate of the nation—and the resultant impacts on 

PDVSA for that matter—are highly uncertain in the wake of the passing of Hugo 

Chavez. The only thing that can be said is that global demands for Venezuelan natural gas are generally abated with US LNG exports. But there could emerge regional trading partners—such as Chile, Argentina, Brazil, and Colombia—that enjoy 

a distinct transportation cost advantage to the US due their proximity to Venezuela. 

But, even that is an uncertain stipulation as gas resources exist in many of those 

countries as well, although political pressures hinder development. 

The effects on NOCs such as Gazprom and INOC are different and to an extent 

uncertain largely due to the response pathways available to each. In the case of 

Gazprom, domestic prices are highly subsidized in Russia, and domestic sales account for almost 70 percent of Russian volumes. So, export revenues have historically been a critical source of revenue for the government and for field development. 

To the extent export revenues are compromised, one option available is to phase out 

domestic subsidies. This has, in fact, been discussed for different classes of consumers—i.e.-industrial, commercial, residential, power generators. It is not a politically palatable solution, as industrial users in Russia argue decreased competitiveness, and residential and commercial users argue a right to Russia’s national 

wealth. Nevertheless, a decrease in the subsidy levels would compensate for lost 

revenues if exports are lower. Of course, if Russia cannot accomplish a reduction 

in subsidies and it loses export markets, it runs the risk of beginning to look like 

Mexico—a nation with resource wealth that it cannot tap and, as a result, years of 

slowly declining production. 

In the case of INOC, a significant portion of current gas production is used for 

enhanced oil recovery and the rest is sold domestically at prices well below international market parity. This has led to domestic gas shortages that have pushed 

119 

* All SA figures have been retained in committee files. 

up imports from Turkmenistan, an almost inconceivable outcome given Iran’s resource wealth. But, this is an oft repeated unintended consequence of artificial price 

setting. If Iran could export, it would likely do so via pipeline to Pakistan and India 

and LNG to other Asian buyers. This would provide valuable revenue uplift associated with gas production that could be used to enhance Iran’s position in global gas 

markets through further development and bolster the government’s budget. So, by 

delaying the need for Iranian resources, the only real market for Iranian natural 

gas is domestic, and unwinding subsidies is a tenable and highly unlikely proposition, meaning Iranian natural gas is effectively a stranded resource in terms of 

its global impacts. It also denies Iran a potentially important revenue stream. 

Any US national security interests and energy security benefits bestowed to US 

allies follow directly from the above. By reducing dependence on trading partners 

in volatile regions of the world and/or trading partners who have demonstrated a 

willingness to manipulate supply to gain a political advantage, any concerns about 

security of supply are mitigated. Thus, it follows that more direct trade with a stable trading partner where market forces are instrumental in determining supplydemand balance will enhance security of supply. This is, in fact, among the reasons 

that some Asian buyers are seeking to add US LNG supplies to their portfolios. 

Another important reasons Asian buyers seek trade with the US is the desirability of a gas price indexed purchase rather than a price indexed to oil for contracted flows. In fact, as the US enters the global LNG market, liquidity will be enhanced. This is a very important point that ties directly back to the impacts of US 

LNG exports on NOCs and the gas market more generally. Oil indexation of gas 

sales is still prevalent, particularly in Asia, as it provides a means of ensuring delivery of supplies where there is no ability to buy at a hub or on an exchange, and 

it follows from a lack of market liquidity. As liquidity grows, the desirability of this 

paradigm wanes. In fact, short term and spot sales of LNG have increased from 

around 5 percent of the global LNG market in 2000 to over 20 percent in 2011. This 

is indicative of the ongoing paradigm shift. Adding US LNG to the supply portfolio 

enhances liquidity by adding a supply option as well as a direct link to a liquid gas 

market, which will further erode the traditional LNG contract paradigm. This will 

have direct implications for revenues for all gas exporters, even those with existing 

contracts as LNG contracts typically have re-openers (or price renegotiation clauses) 

that can be triggered when markets shift in particular ways. So, the liquidity effects 

of US LNG exports could indeed be significant and transformative of the way LNG 

is traded globally. Note this could happen even if export capacity is added but very 

little gas is actually exported. 

RESPONSES OF KENNETH B. MEDLOCK TO QUESTIONS FROM SENATOR ALEXANDER

Question 1. Given the advantage of low domestic natural gas prices that resulted 

from increased production from unconventional natural gas reserves, do we really 

have a problem since we might only export 10 percent of our natural gas? 

Answer. The answer depends entirely on how responsive domestic supply is to 

price. The price impact of LNG exports, or any increase in demand for that matter, 

is ultimately dependent upon the elasticity of supply. Consider *Figure SA.1, which 

indicates the effect of different supply capabilities in response to a particular demand increase due to exports. If supply can expand significantly as price rises 

(meaning it is very elastic—such as in Case 1 in Figure SA.1), then domestic supply 

capabilities are more than adequate to meet such demand growth. However, if one 

takes the view that supply is relatively unresponsive to price, as in Case 2 in Figure 

SA.1, then the price impacts could be significant for even small volumes of LNG exports. This would have adverse effects on all sources of demand and would ultimately serve to limit demand growth in all sectors as well as limit LNG exports. 

Research done at the Baker Institute indicates that domestic supply is highly 

elastic, as in Case 1, which would suggest that price will not rise substantially as 

demand grows. So, this indicates that LNG exports will not have a significant price 

impact domestically. 

It is important to also note that an assumption about volume must be made in 

the context of a fully responsive international trade paradigm. In other words, export volumes are not simply given volumes. They are arrived at through the equilibration of demand and supply around price. Trade affects price in both exporting 

and importing markets. This point is highlighted in ‘‘US LNG Exports: Truth and 

Consequence’’ which is attached for your reference. 

120 

Question 2. At what percentage of exports, compared with the overall U.S. production of natural gas, does the U.S. lose its price advantage of natural gas that we 

have today? 

Answer. There is no such volume. If the price advantage is completely eroded 

than exports will fall until a price differential exists that supports the cost of the 

trade. In fact, the price in an exporting region will always be lower than the price 

in the importing region. If it is not, then trade will cease. See *Figure SA.2 for an 

illustration of equilibrium in an international trade context. 

Importantly, this is not simply an academic exercise. It is proven time and again 

in multiple markets where trade between regions exists. Only when the cost of the 

trade (t in Figure SA.2) is diminishingly small do we see price convergence in an 

absolute sense between trading partners. For natural gas, the full cost of the estimated trade from the US Gulf Coast to Japan is about $5/mcf, meaning the price 

differential between the two markets should gravitate toward that value. Even if 

one removes the fixed cost of infrastructure from the calculation, the differential 

still persists at over $2/mcf. So, if trade is occurring, a differential will exist, and 

as long as the US is the exporting country, the price in the US will be lower. 

During the testimony, it was claimed that the price to a consumer in Australia 

is at parity with the price of LNG delivered to Japan. Apparently, this was done 

to support the notion that the domestic price for the exporter will rise to parity with 

the price paid by the importer. This comparison is not apples-to-apples. The LNG 

price is an ex-ship price, whereas the price to a consumer in Australia reflects the 

cost of local distribution, taxes, fees and other costs. Even in the US in 2012, when 

the price at Henry Hub averaged $2.76/mcf, the national average price of gas delivered to the city gate, where the local distribution company (LDC) takes possession 

of the gas, was $4.73. Then, the LDC must account for its fees and costs thus resulting in a national average price delivered to residential users of $10.68/mcf and commercial users of $8.13/mcf. To make matters more complicated, the fees and costs 

vary widely by LDC, so some US consumers pay much more than indicated by the 

national average, such as in Massachusetts where the average price to a residential 

consumer in 2012 was $13.42/mcf. Even industrial and power generation users of 

gas who are not LDC customers pay more than Henry Hub as they must pay to 

ship gas along the interstate pipelines. In 2012, the spot price of delivered LNG was $15.09/mcf in Japan and $9.48/mcf 

in the UK. But, comparing these wholesale spot prices to delivered end-user prices 

is completely inappropriate when evaluating the effects of trade. Moreover, the East 

Australian (or Sydney) market is not connected to West Australia, which is where 

Australia’s LNG exports originate. Prices in East Australia are set entirely by East 

Australian supply-demand factors having nothing to do with exports from the Australian Northwest shelf to Japan. Moreover, the wholesale price of gas in West Australia is well below the current price of LNG delivered to Japan. 

As one final point, it is important to note that US competitive advantage can be 

compromised if other countries, who may also export but need not, heavily subsidize 

prices to industrial users. This tilts the scale, but also creates an unsustainable situation, as has been witnessed many times over—Indonesia, Argentina, Iran, etc. 

Notably, the advantage is not about absolute price, it is about relative price. Even 

if the price in the US averages $2.50/mcf, industrial users will offshore if the price 

abroad is lower. This, in fact, happened in the late 1990s in the US. 

Question 3. What are your projections for the amount of natural gas the U.S. will 

be producing in 10 years? 

Answer. The work done at the Baker Institute under the Center for Energy Studies indicates the US marketed production volumes will be about 8 percent higher 

than currently. Importantly, this volume is projected to primarily be used to meet 

domestic demands, as the prediction for export volume by then is just under 2 bcf/ 

d, which is less than 3 percent of current marketed production. The above referenced paper ‘‘US LNG Exports: Truth and Consequence’’ highlights the primary 

drivers of this result. Namely, international market responses to current high prices 

will serve to ultimately lower them—i.e.-the best cure for high prices is high prices. 

Question 4. Under present policies, if you had to make a guess, what would be 

the range of the percentage of U.S. natural gas production that we would be exporting in 10 years? 

Answer. We have done various scenarios to assess the market potential for US 

LNG exports. We consistently see a range of between 0.5 bcf/d and 3.5 bcf/d, which 

equates to a range of between less than one percent to about five percent. In order 

to drive export volumes to the high end, we must make very strong assumptions 

about the long term supply responsiveness of Russia, China (due to shale resources), 

and Qatar. 

(121) 

APPENDIX II 

Additional Material Submitted for the Record 

STATEMENT OF THE AMERICAN PUBLIC GAS ASSOCIATION

On behalf of the American Public Gas Association (APGA), thank you for the opportunity to submit testimony on the Senate Committee on Energy and Natural Resources hearing titled, ‘‘Opportunities and Challenges for Natural Gas.’’ APGA believes that the Committee should consider two issues critical for U.S. consumers of 

natural gas, which are reform of Section 5 of the Natural Gas Act (NGA) and the 

export of domestically produced natural gas in the form of liquefied natural gas 

(LNG). We sincerely appreciate the opportunity to present our views and stand 

ready to work with the Committee on these and any other natural gas issues that 

may be considered. 

APGA is the national association for publicly-owned natural gas distribution systems. There are approximately 1,000 public gas systems located in 36 states. Publicly-owned gas systems are not-for-profit, retail distribution entities owned by, and 

accountable to, the citizens they serve. They include municipal gas distribution systems, public utility districts, county districts, and other public agencies that have 

natural gas distribution facilities. 

ISSUE 1—REFORM OF SECTION 5 OF THE NATURAL GAS ACT

Background 

In 1938, Congress gave the Federal Power Commission (now the Federal Energy 

Regulatory Commission (FERC)) authority under the NGA to regulate transportation rates charged by interstate natural gas transmission pipelines. The NGA 

mandates that customers of interstate pipelines are to be charged ‘‘just and reasonable’’ rates, mirroring the core rate sections of the Federal Power Act (FPA), which 

mandate just and reasonable rates for electric utilities. 

Periodically, Congress has updated both the FPA and the NGA as the electric and 

natural gas industries have evolved. Significantly for these purposes, Congress 

amended the FPA in 1988 and again in 2005 allowing FERC to provide refunds to 

the extent customers were charged unjust and unreasonable rates as found by 

FERC; with such refunds to be effective as of the refund-effective date, which may 

be set by FERC as early as the date that a complaint is filed under FPA Section 

206. Unfortunately, no such amendments were made to the NGA. 

Until 1992, interstate pipeline companies were required to have their rates evaluated every three years by the FERC to ensure that they were just and reasonable, 

so the need for such reform was not as pressing. 

However, in 1992, FERC issued Order 636 as part of the transition to unbundled 

open access transportation and ended the three-year rate review process. The practical result of this has been that pipelines with increasing costs file for and receive 

rate increases under NGA Section 4; while pipelines with decreasing costs, ,whose 

rates have long since ceased to be just and reasonable, simply continue charging 

consumers excessive rates, often for very extended periods of time, sometimes 10 or 

more years. 

Even if customers or the FERC initiates an NGA Section 5 complaint case against 

an interstate pipeline company, and the FERC agrees that the just and reasonable 

standard was violated, the FERC can only change the company’s rates prospectively 

from and after the date of the FERC final order, with no refunds to affected consumers during the often lengthy period required to process such a complaint case. 

It goes almost without saying that unless pipelines can settle such cases on terms 

very favorable to themselves, as is usually the case, they have every incentive and 

the resources to drag out the litigation of the complaint case for years since there 

are no refund repercussions at the end of the proceeding. This lack of parity between the complaint sections of the NGA and FPA leaves natural gas customers 

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1The annual report of the Natural Gas Supply Association, ‘‘Pipeline Cost Recovery Report: 

32 Major Pipelines 2006–2010,’’ shows that the twelve companies called on the carpet are but 

a small fraction of the total number of over-earners (see Report at pp. 4–5). 2 Natural Gas Pipeline Co. of America, RP10-147, comments of PGC et al at 1-3, comments 

of Missouri Public Service Commission at 3-6; comments of APGA at 1-3; comments of Pennsylvania Public Utility Commission at 1; and in Northern Natural Gas Co., RP10-148, comments 

of Northern Municipal Distributors Group et al at 2-3, 5-6; comments of Michigan Public Service 

Commission at 1-2; response of APGA at 1-4. 3 Comm’r LaFleur concurring statement (p. 2) in Northern Natural Gas Co., RP10-148, Oct. 

29, 2010 4 Chairman Wellinghoff dissenting statement (p. 4) in Northern Natural Gas Co., RP10-148, 

Nov. 2 , 2010 

ranging from homeowners to industrial enterprises exposed to overcharges for extended periods in violation of the NGA’s just and reasonable standard. This lack of 

protection has resulted in millions of customers paying excessive, unjust and unreasonable rates for natural gas transportation, affecting families’ bottom lines and 

businesses’ ability to compete and create jobs. 

Recent Developments 

Since November 2009, FERC has initiated approximately three Section 5 cases 

each year. Whether or not Section 5 cases are initiated at all is at the discretion 

of the Commissioners—there is no statutory requirement that FERC do so. APGA 

believes that the recent FERC Section 5 actions are important for a number of reasons. First, the Commission to its credit is taking the initiative to review pipeline 

Form 2 filings (annual filings containing pipeline financial data) and calling out the 

most egregious over-earners, most of which have not been before the Commission 

in many years for a rate review. The Form 2 data shows that these entities are 

often earning returns in excess of 20 percent, which, all seem to concede, is exorbitant for a regulated monopoly.1

The second point that these cases illustrate is the futility of bringing such complaint cases if the goal is to achieve just and reasonable rates under the NGA. The 

pipelines are able to use delay tactics and threats of time-consuming NGA Section 

4 filings to bully both the customers into settling the cases on terms very favorable 

to the pipelines and the commission into approving these unbalanced settlements. 

These points have been made by the various parties to these cases2 and fully recognized by the commissioners themselves. For example, in one of the first complaint 

cases initiated by the commission, involving Northern Natural Gas Company, Docket No. RP10-148, Commissioner LaFleur observed as follows in a concurring statement: 

I Irecognize the concerns raised by the Industrials on rehearing regarding the unfair advantage pipelines may have in a section 5 proceeding vis- ́a-vis their customers. The Commission can only act, however, within the existing statutory 

scheme. I believe that this proceeding clearly demonstrates the need for reform of 

section 5 of the NGA to prevent the asymmetry of leverage between applicants 

under section 4 and complainants or the Commission under section 5. As happened 

here, without Commission authority to set a refund effective date upon institution 

of a complaint or investigation under section 5, a pipeline can threaten to file a general section 4 rate case and move those rates into effect prior to the date by which 

a Commission order in the section 5 proceeding could lower those rates. This situation places the parties supporting the section 5 proceeding in a difficult situation 

in that they may be forced to pay even higher rates without refund relief for some 

period of time. It also hampers the Commission’s efforts to ensure just and reasonable rates. I therefore support legislative action to amend the NGA to provide the 

Commission with refund authority in section 5, similar to that provided under section 206 of the Federal Power Act.3 ’’ 

Similarly, in a dissenting statement in that same case Chairman Wellinghoff stated: 

‘‘As a general matter, the lack of refund authority under section 5 of the NGA 

allows the regulated community to defeat the purpose of section 5 at least in some 

circumstances. This is not the case under the Federal Power Act (FPA). The Commission must establish a refund effective date for a section 206 proceeding and has 

the authority to order refunds for the period ending 15 months after the refund effective date. Thus, the incentive for game-playing is removed and the Commission 

can determine on the merits that a public utility’s rates are just and reasonable. 

For this reason, I support legislative changes providing for NGA refund authority 

paralleling that provided to the Commission in the FPA.4 ’’ 

In fact, all of the sitting commissioners including (newly appointed Commissioner 

Clark has expressed his support for Section 5 reform in a meeting with APGA), 

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5 Natural Gas Supply Association, ‘‘Pipeline Cost Recovery Report: 32 Pipelines 2006-2010’’ 

pgs 4-5. 6Of course, in today’s financial markets, the assumed 12% ROE is several hundred basis 

points above what could be justified. 7 Natural Gas Supply Association, ‘‘Pipeline Cost Recovery Report: 32 Pipelines 2006-2010’’, 

p. 5 8 Energy Information Administration ‘‘Annual Energy Outlook 2012 Early Release,’’ pgs: 1 and 

5. 

being fully familiar with the outcomes in these Section 5 proceedings, have stated 

their support for amendment of NGA Section 5 to provide refund authority comparable to that available under FPA Section 206. 

The prospect of continuing to pay excessive rates for natural gas transportation 

has brought together a diverse group of stakeholders that is growing. Groups that 

have supported reform include: the Industrial Energy Consumers of America; American Iron and Steel Institute; American Forest and Paper Association; American 

Public Power Association; National Farmers Union; Public Citizen; and, most recently, the National League of Cities, which represents 19,000 cities, villages, and 

towns. This growing coalition of organizations recognizes that the only way to protect individual consumers as well as the competitiveness of major industrial users 

of natural gas is to reform Section 5 of the NGA. As significant as the number and 

type of entities supporting reform is the absence of entities opposing reform. To 

date, only pipelines and their trade association have opposed the efforts to amend 

NGA Section 5 to afford consumers meaningful protection against rate overcharges. 

The arguments for reform are straight-forward and persuasive. First and foremost 

is the NGA mandate that pipelines charge just and reasonable rates and that customers be protected from paying unjust and unreasonable rates for natural gas 

transportation. The fact that overcharges are an ongoing problem is illustrated both 

by the pipeline’s own (Form 2) data cited in the Section 5 complaints initiated by 

the commission and by the data released each year by the Natural Gas Supply Association (NGSA). In 2012, NGSA released a study of the 32 largest interstate pipelines (representing 80 percent of the transmission market), which found that these 

companies overcharged customers by $4.2 billion from 2006-2010 (this is an increase 

of $100 million compared to the 2011 report).5 The study also used Form 2 data submitted by interstate pipeline companies and assumed an average return on equity 

(ROE) of 12 percent to be acceptable.6 Over the five year period, several companies 

averaged an ROE above 20 percent and one above 42 percent.7

Overcharging for natural gas transportation does not simply mean fewer dollars 

available for businesses and consumers, but also means fewer jobs in an economy 

where job growth is more critical than ever. Major industrial enterprises spend millions of dollars on natural gas, which constitutes a major input cost. The fact that 

many of these enterprises are paying excessive rates for natural gas transportation 

limits their ability to create new jobs in the midst of strong competition from companies around the world. The money spent on excessive natural gas rates could be better spent by creating new jobs here in the U.S. and taking advantage of our nation’s 

vast, newly accessible shale gas reserves.8

Addressing Pipeline Arguments Against Reform 

The benefits to businesses and consumers of reforming Section 5 of the NGA to 

limit pipelines to rates that are just and reasonable are clear and compelling: lower 

costs and greater domestic job creation. However, to date, interstate pipelines continue to resist reform since it affects their bottom line, so it is important to address 

each of their arguments to determine their merit or lack thereof. 

Interstate pipeline companies’ arguments against reform may be summarized as 

follows: FERC-established rates remain just and reasonable until changed; ordering 

refunds would constitute ‘‘retroactive ratemaking’’; providing for refunds would undermine infrastructure development; and reform is unnecessary because transportation rates themselves are a relatively small component of the total bundled cost 

of natural gas to consumers. Each of those points will be addressed below. 

The pipelines argue that since the rates being charged by a pipeline at any given 

point in time were previously approved by the FERC, they must still be just and 

reasonable, and thus refunds should be denied. This contention is self-evidently inaccurate since a rate that is just and reasonable at any given point in time may 

become unjust and unreasonable at a subsequent point in time if costs materially 

increase or decrease. Pipelines are not bashful about filing to increase their rates 

when costs are rising, and such rate increases go into effect virtually immediately 

subject to refund after a nominal suspension period under NGA Section 4. The suggestion that pipelines should be allowed to supersede previous rates determined to 

be just and reasonable after a nominal suspension period but that consumers should 

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9 El Paso Natural Gas Company website: http://investor.eppipelinepartners.com/phoenix.zhtml?c=215819&p=irol-newsArticle&ID=1532478&highlight= 10 Natural Gas Supply Association, ‘‘Pipeline Cost Recovery Report: 32 Pipelines 2005-2009,’’ 

pg. 5. 

have to wait potentially years before getting relief from unjust and unreasonable 

rates is absurd on its face. This argument was obviously found wanting in 1988 

when Congress amended FPA Section 206 to provide for refunds where rates were 

ultimately determined to be excessive. 

Interstate pipelines also argue that reform of Section 5 to provide refund protection for consumers is tantamount to ‘‘retroactive ratemaking.’’ This statement is legally inaccurate and is designed to conjure fears amongst policymakers of overzealous regulators intrusively altering pipeline rates, creating uncertainty and 

harming pipelines’ business. In reality, if a customer files a complaint under a reformed Section 5, the Commission, if it believes that the complainant has shown 

good cause to set the matter down for hearing, will set a refund-effective date, which 

date may not precede the date the complaint is filed. Hence, all refunds are prospective from the refund-effective date, and there will be no refunds unless the Commission at the end of the proceeding determines that the pipelines’ rates are excessive 

under the ‘‘just and reasonable’’ standard. In short, unless FERC determines that 

interstate pipelines are violating the NGA, no refunds will be required. The identical provision under the FPA has been upheld against charges of retroactive ratemaking. 

The interstate pipeline companies also argue that reforming Section 5 will harm 

their ability to build infrastructure. This argument is a red-herring and is misleading in at least five different ways: 

First, new infrastructure projects are certificated to earn healthy equity returns, 

usually in the 12 percent range. NGA Section 5 reform does not affect by one iota 

the ability of these projects to earn such returns; rather, NGA Section 5 reform is 

only applicable to those egregious over-earners whose customers are underwriting 

returns far in excess of the allowed returns. 

Second, almost all significant new infrastructure projects are undertaken on the 

basis of ‘‘negotiated’’ contracts between the transporter and the shippers. Negotiated 

contracts are not subject to rate changes by the transporter under NGA Section 4 

or rate challenges by shippers under NGA Section 5; the rate is fixed for the term 

through bilateral negotiations. These negotiated contracts form the basis for the 

project developer to go to the marketplace and provide the developer with known 

returns for the contract terms. Thus, the argument that NGA Section 5 reform 

would deter new infrastructure development is false and misleading. 

Third, the FERC is required by law in setting rates to provide for a rate of return 

that permits the affected pipeline to recover all debt costs plus raise capital in the 

marketplace at reasonable rates. FERC has done just that, and the financial markets understand this, so NGA Section 5 reform will not affect at all the ability of 

interstate pipelines to raise capital in the marketplace. 

Fourth, the FERC itself, which is pro-business and pro-infrastructure, understands that the argument that Section 5 reform would be bad for infrastructure development and thus bad for job development is rash, for all of the reasons noted 

above, which explains why all sitting commissioners, including the Chairman and 

prior two Chairmen, support NGA Section 5 reform. Commissioner Clark has also 

expressed his support in a private meeting with APGA. 

Fifth, many of the leading builders of infrastructure are not the more egregious 

over-earners, and they have successfully gone to the marketplace for billions of dollars for new infrastructure construction. For example, El Paso Natural Gas Company touts on their website that in 2010 they invested $318 million in new infrastructure projects.9 According to the NGSA study, El Paso had an ROE of 8.3 percent for 2010 and a five year average ROE of 10.7 percent.10 In other words, there 

is no correlation between over-earning pipelines and infrastructure construction. 

In brief, this ‘‘infrastructure’’ argument is nothing but a strawman raised by the 

pipelines because they have no defense on the merits against Section 5 reform—they 

are overcharging customers because the rates of many of them are no longer just 

and reasonable. Absent NGA Section 5 reform, FERC, which is supposed to ensure 

that pipelines charge and consumers pay just and reasonable rates, is basically 

helpless to prevent allowing pipelines to defeat the purpose of the NGA. 

Finally, the interstate pipelines also argue that transportation rates for natural 

gas are a small part of the overall cost to consumers, so policymakers should ignore 

it. First, this contention tries to obscure the fact that excessive rates for transporVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00128 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
125 

11 Natural Gas Supply Association, ‘‘Pipeline Cost Recovery Report: 32 Major Pipelines 2006- 

2010,’’ pgs 4-5. 12 Effect of Increased Natural Gas Exports on Domestic Energy Markets, U.S. Energy Information Administration (Jan. 2012) (‘‘EIA Export Report’’). As requested by the DOE/FE, the EIA 

Export Report considered four scenarios: (1) 6 Bcf/d phased in at a rate of 1 Bcf/d per year (low/ 

slow scenario); (2) 6 Bcf/d phased in at a rate of 3 Bcf/d per year (low/rapid scenario); (3) 12 

Bcf/d phased in at a rate of 1 Bcf/d per year (high/slow scenario); and (4) 12 Bcf/d phased in 

at a rate of 3 Bcf/d per year (high/rapid scenario). 13Macroeconomic Impacts of LNG Exports from the United States, NERA Economic Consulting (Dec. 2012) (‘‘NERA Study’’). APGA understands (and applauds the fact) that the merits 

and demerits of the NERA Study will be assessed independently by DOE/FE in a separate proceeding (77 Fed. Reg. 73627); and hence APGA’s comments here on the NERA Study are only 

preliminary and not intended to represent its complete assessment of the NERA Study. 

tation cost consumers and businesses some $4.2 billion over a five-year period11— money that should remain in the communities of the customers that are being overcharged. The fact of the matter is that the price of gas at the wellhead, which is 

the major component of the blended gas cost paid by consumers, is deregulated and 

thus that component is not at issue here. What is at issue is the FERC-regulated 

component: pipeline rates to move the gas from the field to local distribution companies and industrial loads and the issue that there is no basis for a regulated entity 

under the Natural Gas Act to over-recover its allowed return by hundreds of millions of dollars, as is the case today, simply because the production component of 

the ultimate charge paid by consumers is unregulated. 

Conclusion 

APGA believes that it is critical that businesses and individual consumers pay a 

fair price for natural gas and for its transportation. FERC is charged with ensuring 

this result, but in contrast to the situation under the FPA, it is handcuffed from 

carrying out its mandate by the same flaw in the NGA that handicapped the Commission under the FPA until Congress acted in 1988. As FERC Chairman 

Wellinghoff (and his predecessors) and all sitting FERC commissioners have observed publically and/or privately, no credible public policy reason exists to treat 

electric and natural gas customers differently in regard to ensuring that rates of jurisdictional companies are just and reasonable. 

APGA thanks the Committee for its interest in this important issue and respectfully requests a hearing at the Senate Committee on Energy and Natural Resources 

so these issues can be debated in an open, on-the-record forum. 

ISSUE 2—LNG EXPORT

The Department of Energy Office of Fossil Energy (‘‘DOE/FE’’) commissioned two 

studies regarding the effects of LNG exports. The first, conducted by the U.S. Energy Information Administration (‘‘EIA’’), studied the impact of LNG exports on domestic prices and concluded that the exports will increase prices, with higher volumes causing more drastic increases.12 The second, conducted by NERA Economic 

Consulting, focused on the macroeconomic effects of LNG exports, which it found 

would be a net positive while at the same time confirming that LNG exports would 

raise domestic natural gas prices, which would burden the U.S. consumers who can 

least afford the increase and disadvantage domestic manufacturing.13 Policymakers 

must consider both of these studies and the many non-governmental studies, but 

also go beyond them to consider the profound tradeoffs entailed by exporting away 

an increasingly valuable U.S. fuel rather than supporting its use domestically. 

Increased production of natural gas in the U.S. provides the nation with an unprecedented opportunity to pursue energy independence and sustained economic 

growth through a manufacturing renaissance grounded in plentiful, low cost natural 

gas. Price increases will also jeopardize the viability of natural gas as a ‘‘bridge-fuel’’ 

in the transition away from carbon-intensive and otherwise environmentally problematic coal-fired electric generation and inhibit efforts to foster natural gas as a 

major transportation fuel, which is important to wean the U.S. from its historic and 

high-risk dependence on foreign oil. 

Background 

To date, 22 applications have been submitted to DOE to export domestic LNG 

from the contiguous United States to Free Trade Agreement (FTA) or non-FTA nations based on the promise of huge unconventional domestic gas reserves. Many of 

those 22 applicants own or are affiliated with companies that own existing or previously planned LNG import terminals. Also to date, the total export capacity applied for is 29.41Bcf/d and 24.8 Bcf/d to FTA and non-FTA nations, respectively. 

Total marketed natural gas production was approximately 66 Bcf/d in the U.S. in 

126 

14 15 U.S.C. § 717b(a). 15Sabine Pass Liquefaction, LLC, Opinion and Order Denying Request for Review Under Section 3(c) of the Natural Gas Act, October 21, 2010, FE Docket No. 10-111-LNG. 16 Id. at 6. As requested by the DOE/FE, the EIA Export Report considered four scenarios: 

(1) 6 Bcf/d phased in at a rate of 1 Bcf/d per year (low/slow scenario); (2) 6 Bcf/d phased in at 

a rate of 3 Bcf/d per year (low/rapid scenario); (3) 12 Bcf/d phased in at a rate of 1 Bcf/d per 

year (high/slow scenario); and (4) 12 Bcf/d phased in at a rate of 3 Bcf/d per year (high/rapid 

scenario). 17 Id. 18 Id. at 8. 19 Id. 20 Id. at 9. 21 AEO2013 Early Release Overview at 2. 22See Steven Mufson, The New Boom: Shale Gas Fueling an American Industrial Revival, 

Washington Post (Nov. 14 (2012) (reporting that manufacturers have plans to invest as much 

as $80 billion in U.S. chemical, fertilizer, steel, aluminum, tire and plastics plants); Letter from 

Edward J. Markey, Ranking Member, House of Representatives Committee on Natural Resources, to Steven Chu, Secretary of Energy (Dec. 14, 2012)(‘‘Markey Letter’’) (stating that 

AEO2013 domestic demand projections ‘‘fail to capture many of the more than 100 newly announced natural gas-intensive manufacturing projects that have been announced over the past 

18 months. Those projects represent of $90 billion in investment and billions of cubic feet of 

additional future daily natural gas use.’’). 

201l; therefore, based on current marketed production data, the total applied-for export capacity would have the effect of increasing the demand for natural gas by 

nearly 48 percent. 

Policymakers in Congress and at DOE have a duty to ensure that any application 

before it for export authority is not inconsistent with the public interest pursuant 

to NGA section 3(a).14 The ‘‘public interest analysis of export applications’’ should 

be ‘‘focused on domestic need for natural gas,’’ threats to domestic supply, and 

‘‘other factors to the extent they are shown to be relevant.’’15

LNG Exports Will Increase Domestic Natural Gas Prices 

According to the EIA Export Report, ‘‘[l]arger export levels lead to larger domestic 

price increases.’’16 EIA also concluded that ‘‘rapid increases in export levels lead to 

large initial price increases,’’ but that slower increases in export levels will ‘‘eventually produce higher average prices during the decade between 2025 and 2035.’’17

Even under the ‘‘low/slow’’ baseline scenario in the EIA Export Report, price impacts will peak at about 14 percent.18 Under the low/rapid baseline scenario, EIA 

projects that wellhead prices will be approximately 18 percent higher in 2016 than 

they otherwise would be19. In fact, under all of the ‘‘low’’ scenarios accounting for 

different economic and shale reserve conditions, EIA predicts price impacts well 

above 10 percent that then moderate.20 Under the ‘‘high/rapid scenario,’’ EIA 

projects that prices will increase by 36 percent to 54 percent by 2018 depending on 

natural gas supplies and economic growth. 

The NERA study also concluded that the higher the volume of LNG exports, the 

more domestic natural gas prices will rise. Both studies underestimate potential 

price increases because they are based on outdated projections of domestic demand 

for natural gas and the questionable assumption that the demand for natural gas 

is sufficiently elastic to prevent significant price spikes. 

Domestic Demand Underestimated 

On December 5, 2012, the EIA issued the Early Release of its Annual Energy Outlook for 2013 (‘‘AEO2013’’). The AEO2013 projects greater increases in domestic demand for natural gas than projected in prior Annual Energy Outlooks. In particular, 

the AEO2013 projects greater increases in demand for natural gas from domestic 

industry, particularly from the bulk chemicals and primary metals industries and 

as a result of ‘‘higher output in the manufacturing sector.’’21 However, even 

AEO2013 appears to underestimate the coming growth in natural gas use for manufacturing, if domestic prices remain low.22

AEO2013 also projects greater increases in future reliance on natural gas for electric generation than projected by the EIA in previous Annual Energy Outlooks. The 

increased reliance on natural gas for electric generation is partially based on low 

natural gas prices, but also on implementation of the Environmental Protection 

Agency’s (EPA) pending Mercury Air Toxic Standards (‘‘MATS’’), which will force the 

retirement of a number of coal-fired generators. 

Both studies commissioned by DOE/FE rely on projected natural gas demand from 

AEO2011. These outdated projections fail to account for current EIA expectations 

regarding future demand and tend to overestimate demand elasticity, or the ability 

of natural gas consumers to curtail their purchases in response to higher prices in 

the electric generation sector. Once a coal plant is retired due to MATS, or for any 

127 

23 ‘‘Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units’’ 77 C.F.R. 22392 (Apr. 13, 2012). 24See Energy Information Administration, Fuel Competition in Power Generation and Elasticities of Substitution (June 2012) (general description of fuel switching and price elasticity among 

fuels in the power generation sector) available at http://www.eia.gov/analysis/studies/ 

fuelelasticities/pdf/eia-fuelelasticities.pdf. 25See Markey Letter (casting doubt on the assumption that benefits to the natural gas sector 

will be widely enjoyed by ordinary American via retirement investments). 26 NERA Study at 8. 27 NERA Study at 53. 28 NERA Study at 64 29 NERA Study at 13. 

other reason, the operator of the retired plant cannot switch it back on in response 

to higher natural gas costs. Meanwhile, the EPA’s new greenhouse gas standards 

for new electric generators virtually ensure that new coal plants will not be constructed to replace those that are retired.23 Soon, electric generation companies will 

not only demand more gas but also rely on it more heavily for base load production, 

altering expectations about demand elasticity that prognosticators have relied on 

when assuming that natural gas prices will not raise sharply due to LNG exports.24

This same trend would also exacerbate the increases in the price of electricity 

caused by LNG exports that are projected by the EIA and NERA. 

While demand elasticity will shrink in the electric sector, leading to sharper increases in natural gas and electricity prices than previously forecasted, manufacturers will continue to be ‘‘responsive’’ to increases in the price of natural gas—meaning that manufacturers will curtail consumption and hence production due to higher 

prices. Congress and the DOE need to examine what this means for the economy 

and the broader public interest of the nation in its consideration of this and other 

LNG export applications. 

Effects of Higher Prices 

Increases in the price of natural gas will impact the U.S. consumers who can least 

afford the price increase, inhibit the expansion of domestic manufacturing, and forestall the further use of natural gas as a bridge fuel away from the carbon-intensive 

coal and foreign sourced oil for transportation. The NERA study specifically describes the effects of LNG exports and the attendant price increases in terms of a 

‘‘wealth transfer.’’ The DOE/FE must examine what this wealth transfer would entail for the public interest when evaluating LNG export applications. 

Hurts Economically Vulnerable Households 

Proposed LNG exports would raise domestic natural gas prices, which will increase costs to households that rely on natural gas for heating and cooking. NERA 

projects that these higher costs will be offset by increases in the value of natural 

gas resources and related companies, which NERA assumes many Americans own 

through retirement savings and other investments.25 NERA admits, however, that 

‘‘[h]ouseholds with income solely from wages or government transfers,’’ will not 

share in the benefits of increased profits from natural gas.25 Therefore, the increase 

in natural gas prices due to exports will impact most those consumers without investments or retirement savings, those living paycheck-to-paycheck or relying on 

government assistance—in other words, the most needy in our society. 

Suppresses Other Domestic Industries 

The NERA study indicates that as the price of natural gas increases, the economy 

demands or produces fewer goods and services. This results in lower wages and capital income for consumers; under such economic conditions, consumers save less of 

their income for investment. 

As a result, industries that rely on natural gas will experience ‘‘a reduction in 

overall output,’’ mitigated by a ‘‘switch to fuels that are relatively cheaper.’’27 The 

latter argument assumes that alternatives to natural gas are affordable and available, which is an invalid assumption for fertilizer manufacturers and other industries. 

Moreover, the NERA study identified chemical manufacturing as one of the natural gas and energy intensive industries that will be among the most severely disadvantaged due to natural gas price increases caused by LNG exports.28 According 

to NERA ‘‘[d]omestic industries for which natural gas is a significant component of 

their cost structure will experience increases in their cost of production, which will 

adversely impact their competitive position in a global market and harm U.S. consumers who purchase their goods.’’29 Leaders in the chemical sector have voiced conVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00131 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
128 

30Press Release, Dow Chemical, DOE Report on LNG Exports Short Changes Manufacturing 

and U.S. Competitiveness (Dec. 6, 2012) available at http://www.dow.com/news/press-releases/article/?id=6138 31 Clifford Kraus, South African Company to Build U.S. Plant to Convert Gas to Liquids, New 

York Times (Dec. 3, 2012) available at: http://www.nytimes.com/2012/12/04/business/energy-environment/sasol-plans-first-gas-to-liquids-plant-in-us.html?lr=0 32President Barack Obama, State of the Union Address (Jan. 24, 2011), transcript available 

at: http://www.whitehouse.gov/state-of-the-union-2012. 33 U.S. House Committee on Natural Resources Democrats, Drill Here, Sell There, Pay More: 

The Painful Price of Exporting Natural Gas (March 2012) available at http://democrats.naturalresources.house.gov/reports/drill-here-sell-there-pay-more. 34 NERA claims that harm resulting from exports will ‘‘likely be confined to very narrow segments of industry,’’ namely low value-added, energy intensive manufacturing. NERA Study at 

67-69. NERA, however, ignores the benefits of producing materials in the U.S. that can then 

be used by other U.S. manufactures that are less energy intensive and higher up the value 

chain. For instance, if plastics are produced at competitive prices in the U.S., toy manufacturers 

may find it economical to ‘‘re-shore’’ toy manufacturing plants. Steven Mufson, The New Boom: 

Shale Gas Fueling an American Industrial Revival, Washington Post (Nov. 14, 2012). 35 EIA Export Report at 17. 

cern regarding LNG exports and adverse impacts on the industry caused by inflated 

natural gas prices.30

When evaluating whether export applications are consistent with the public interest, policymakers must ask not only ‘‘what will we gain from LNG exports,’’ but also 

‘‘what will we give up.’’ A U.S. manufacturing renaissance that promises greater 

economic growth and job creation with positive effects rippling throughout the economy hangs in the balance. Right now, industry is poised to invest billions of dollars 

in new natural gas intensive facilities in the U.S. premised on the promise of low 

domestic natural gas prices. For example, Sasol North America, Inc. is currently 

considering investing in the first gas to liquids plant in the U.S., an innovative technology for producing diesel and other liquid fuels without oil, and U.S. natural gas 

prices are a primary consideration regarding whether the investment will go forward.31

Last year, in his State of the Union address, President Obama spoke of ‘‘an America that attracts a new generation of high-tech manufacturing and high-paying 

jobs—a future where we’re in control of our own energy, and our security and prosperity aren’t so tied to unstable parts of the world,’’ and ‘‘an economy built on American manufacturing, American energy.’’32 Low natural gas prices in the U.S. provide 

the path forward. Higher natural gas prices due to LNG exports threaten this nascent return to American manufacturing, and prior economic data demonstrate that 

when domestic energy prices increase, the country loses manufacturing jobs, particularly in the fertilizer, plastics, chemicals, and steel industries.33

Rather than trading a few existing manufacturing jobs for a few natural gas and 

construction jobs, the DOE/FE should pursue policies that create new manufacturing jobs and broader economic growth in the U.S. Using natural gas for manufacturing provides a value-added benefit to the economy because industry multiplies 

the value of every dollar it expends on natural gas for energy or as a raw material. 

Rather than investing in natural gas exports, which squeeze out investments from 

other sectors of the economy, the U.S. should pursue policies that allow industry to 

invest in natural gas dependent manufacturing. Energy and natural gas intensive 

manufacturing produces chemicals, metals, cement and other materials that may be 

low-value adding but create positive ripple effects up the value-chain and throughout the economy.34 Rather than exporting natural gas as a raw natural resource, 

the U.S. could export processed materials, such as steel, or higher value-added 

goods at more competitive prices, with greater benefits to the U.S. job market and 

GDP. 

Threaten Transition from Coal 

Current low natural gas prices provide an opportunity to wean the U.S. off of carbon-intensive coal. Inflated natural gas prices due to LNG exports will decrease the 

viability of natural gas as a bridge-fuel to a lower carbon future. Current low prices 

make natural gas-fired electricity generation an economically sound alternative to 

coal-fired generation. Sustained low prices may encourage this transition by private 

initiative regardless of increased environmental regulations as investors find natural gas competitive with coal. If exports inflate natural gas prices, the economics 

turn against cleaner burning natural gas.35

In addition, as discussed above, new environmental regulations will soon force 

coal retirements. Future greenhouse gas regulation could cause additional retirements in the future. If natural gas prices remain low, the U.S. may be able to transition away from carbon intensive coal without causing electricity prices to increase 

129 

36 Cheniere and other exporters claim that their proposed exports will benefit the U.S. balance 

of trade, but it does not consider the benefits to the trade balance of cutting oil imports and 

exporting value-added goods manufactured in the U.S. with affordable natural gas. 37Officials are planning a series of compressed natural gas (‘‘CNG’’) filling pumps at existing 

filling stations across the Pennsylvania US Route 6, stretching 400 miles from New York State 

near Milford, Pike County, Pa. in the east and through Crawford County, Pa. to the Ohio state 

line on the west, known as ‘‘PA Route 6 CNG Corridor;’’ at the same time, Chesapeake Energy 

is converting its vehicles in northeastern Pennsylvania to CNG and working with a local convenience-store chain and transit authority to foster further CNG integration. Eric Hrin, Pennsylvania Looks to CNG, The Daily Review Online (May 26, 2011) available at http:// 

thedailyreview.com/news/pennsylvania-looks-to-cng-1.1135267; see also, Texas S.B. 20 (On July 

15, 2011, the governor of Texas signed S.B. 20, supporting a network of natural gas-refueling 

stations along the Texas Triangle between Dallas/Ft. Worth, San Antonio, and Houston. The 

new legislation will lay a foundation for wider-scale deployment of heavy-duty, mid- and lightduty natural gas vehicles (‘‘NGVs’’) in the Texas market). 38 Rodney White, Firm on Track to Build LNG-Fueled Locomotive, Platts Gas Daily (Nov. 28, 

2012). 39MIT Energy Initiative, The Future of Natural Gas, at 14 (2011). 40 Id. 

significantly. If natural gas prices are high, however, electricity prices will spike as 

relatively cheap coal-fired generators are forced to retire for regulatory reasons. 

Spiking electricity rates will have rippling effects on the U.S. economy, especially 

energy intensive, cost-sensitive manufacturing. 

Keeps the U.S. Dependent on Foreign Oil 

Currently, the U.S. imports billions of dollars worth of oil from around the globe, 

a great deal of which is used as gasoline to fuel vehicles. The replacement of current 

gasoline-powered fleets with natural gas vehicles would significantly reduce U.S. dependence on foreign oil, and thereby enhance U.S. security and strategic interests 

and reduce our trade deficit.36 State governments and businesses are expending 

substantial resources today to put the needed infrastructure in place.37

Automobiles are not the only modes of transportation that businesses are interested in transitioning to natural gas; a company in Canada is investing in commercial locomotives powered by LNG and teaming up with Caterpillar to employ similar 

technology in heavy duty equipment that currently runs on diesel.38 If Congress and 

the DOE allow export applications to go through, the resulting increase in natural 

gas prices would undermine recent investments to expand natural gas as a transportation fuel. 

Policymakers should not pursue an export policy that undermines the efficient, 

domestic use of a domestic fuel stock and America’s first and best opportunity to 

move toward energy independence by decreasing reliance on foreign oil. 

U.S. and Foreign Natural Gas Prices Will Converge 

Currently, there are significant disparities between domestic natural gas commodity prices and prices in some nations that rely on LNG imports. These disparities provide would-be exporters with appealing arbitrage opportunities in the shortterm, but they will not last. Gas rich shale deposits are a global phenomenon, just 

now beginning to be tapped. Also, despite relatively low domestic natural gas prices, 

certain countries, such as Qatar, can produce massive quantities of natural gas at 

even lower prices. As other nations develop their resources and export capacity and 

as U.S. natural gas prices increase due to export, international and domestic prices 

will converge, leaving the U.S. with higher domestic prices that thwart energy independence and that undermine the competitiveness of the manufacturing sector that 

relies heavily on natural gas as a process fuel. 

The U.S. is at the forefront of technology in the development of shale gas reserves. 

A recent study by MIT concludes that the U.S. should export its technology and expertise.39 According to MIT, the development of international non-conventional natural gas reserves will create a more liquid market with less disparity between prices 

around the globe40

The U.S. should follow this strategy, instead of spending billions of dollars to 

build facilities in order to export a commodity that will possibly be abundant worldwide before the LNG export facilities can even be completed. 

The U.S. has an opportunity not even imagined two or three years ago to significantly expand its manufacturing sector, transition away from our reliance on coalfired electricity generation (without risking price shocks), and finally make real 

progress towards energy independence. All of this, however, depends on relatively 

low and stable natural gas prices (which sharply contrasts with the history of natural gas price volatility). Congress and the DOE should not turn a blind eye and 

allow the same businesses that gambled and lost on projections of the need for fuVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00133 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
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1SECRETARY OF ENERGY ADVISORY BOARDD, SHALE GAS PRODUCTION SUBCOMMITTEE 90-DAY REPORT 6 (Aug. 18, 2011), available at http://www.shalegas.energy.gov/ 

resources/081811l90ldaylreportlfinal.pdf. 2 U.S. Energy Information Administration, Annual Energy Outlook Early Release 2012, http:// 

www.eia.gov/forecasts/aeo/er/executivelsummary.cfm 

ture natural gas imports to now potentially squander our nation’s future on what 

may well turn out to be another failed venture as natural gas production and export 

capacity develop throughout the world. 

APGA respectfully requests that the Committee hold at least one hearing dedicated to examining the domestic impacts of LNG export on consumers and businesses. Conclusion 

APGA appreciates the opportunity to submit testimony to the Senate Committee 

on Energy and Natural Resources on these two critical natural gas issues. We stand 

ready to work with the Committee on these and all other natural gas issues. 

STATEMENT OF FRED KRUPP, PRESIDENT, ENVIRONMENTAL DEFENSE FUND

The United States is in the midst of a natural gas boom. Shale gas accounted for 

only two percent of total U.S. natural gas production in 2001.1 With the development of horizontal drilling, hydraulic fracturing, and advanced seismography, that 

number has grown extensively to 34 percent in 2011. The U.S. Energy Information 

Administration projects shale gas will account for 50 percent of domestic natural gas 

production by 2040, spanning the nation from New York and Pennsylvania to Ohio, 

Texas, Colorado, and California.2

New supplies of domestic natural gas have caused a drop in price that has benefited the economy and the environment alike. Low-cost natural gas is one reason 

why proposals for new coal-fired power plants have been withdrawn across the country and why old, inefficient, highly polluting coal plants are finally retiring. Environmental Defense Fund recognizes the potentially important benefits this shift 

from coal to natural gas can achieve, particularly for air quality and the climate. 

However, new natural gas development presents serious risks to public health, 

the environment, and the climate. EDF believes that no community should be forced 

to sacrifice health or a quality environment for the sake of cheap energy production, 

nor should the potential greenhouse gas benefits of switching from coal or oil to natural gas be squandered through wasteful production and distribution practices. The 

opportunity for natural gas to be a net ‘‘win’’ for America depends upon whether 

we take serious steps to minimize these risks. 

Fortunately, there are steps that can be taken now to significantly reduce the risk 

to public health and the environment from unconventional natural gas operations 

and to maximize the greenhouse gas benefits that natural gas can provide in comparison with coal or oil. As the committee goes about the important work of assessing the future of natural gas in the United States, I respectfully urge you to consider the following three points. 

1. Strong regulation and enforcement is critical to safe production of unconventional natural gas.—Oil and gas production is governed by a web of federal, 

state, and local regulation. The challenge is to strengthen those strands that 

are weakest and to add new strands as necessary to ensure that the web is complete. The federal government can start by reviewing how oil and gas development is conducted on land that it owns. The Department of Interior is currently 

in the process of re-proposing a set of environmental standards for natural gas 

development on public land, and it is important that these rules be comprehensive and rigorous. I would also recommend that the committee review how 

states are carrying out their responsibilities and what the federal government 

can do to support them in their necessary and important work, both individually, and collectively through organizations such as the Groundwater Protection Council. 

2. Measuring and reducing fugitive methane emissions is an urgent task.— 

The primary constituent in natural gas is methane—a powerful greenhouse gas 

many times more potent than carbon dioxide itself over 20 years. Even small 

leaks of natural gas at the wellhead or along the infrastructure used to process 

and transport the gas to our power plants, home, and businesses can work to 

undo much, if not all, of the greenhouse gas benefits we think we are getting 

when we substitute natural gas for coal or oil. 

A paper published in the Proceedings of the National Academy of Sciences (PNAS) 

last April concluded that for natural gas to have a net climate benefit, methane 

131 

leakage needs to be reduced to one percent or less. This finding was based on the 

best available science, which indicated that natural gas offered a climate advantage, 

when substituting natural gas for other fuels used in electric generation or transportation. Current EPA data estimates methane leakage at approximately 2.5 percent, 

and even the American Petroleum Institute believes that the leakage rate is greater 

than 1 percent. 

Reducing methane from the oil and gas sector can achieve significant benefits, 

and while efforts are underway to replace leakage estimates with hard data, we 

know enough and have the technology to get started now. Enormous climate benefits could be realized if a 1 percent methane emissions target is achieved—comparable to the impact that increasing the fuel economy by about 10 miles per gallon 

across the entire U.S. light-duty vehicle fleet could yield by 2035. 

EPA’s recently finalized national emissions standards for the oil and gas sector 

helped to create a strong foundation on which to build. Those standards, however, 

did not explicitly address methane, and as a result, left too many emissions 

unaddressed. Right now there are three steps that EPA can take to reduce methane 

emissions from the oil and gas sector: 

• Include all significant methane emissions sources in the national emissions 

standards.—The NSPS included green completion requirements, but limited 

those requirements to gas wells. Market fundamentals, however, have driven 

producers to target oil-rich deposits that produce significant amounts of gas. 

While the full scope of emissions from these sources is not precisely known, we 

know they can produce a lot of emissions and they’re growing fast. In addition 

to emissions resulting from oil and gas co-producing wells, other important 

sources to address are liquids unloading activities and leaky equipment at wellsites. By building out these protections, we can ensure new sources are deploying state-of-the-art pollution control technologies to reduce methane emissions. 

• Existing sources.—New sources are only part of the problem. We need rigorous 

protections for existing sources in the oil and gas sector under the NSPS. EPA 

can also help to lay the groundwork by encouraging states with ozone non-attainment concerns to deploy oil and gas controls as cost-effective solutions. EPA 

can do this by providing clear pollution control guidelines, documenting emissions reductions states can achieve, and by underscoring the obvious cost advantages of emission reductions from the oil and gas sector. 

Accountability.—Finally, it is important for EPA’s greenhouse gas reporting program for oil and gas sources to be comprehensive by expanding coverage to sources that don’t currently have to report (like co-producing wells 

and gathering and boosting infrastructure). Additionally, EPA should move 

away from emissions factors and non-standardized measurement methodologies and toward reliance on direct, continuous emissions measurement. 

3. Natural gas is only a piece of our energy future.—We cannot allow the recent abundance and market conditions of natural gas to distract us from pursuing the policies that continue our nation’s progress in developing the energy 

technologies and services necessary to accelerate our transition to a modern, 

clean, low-carbon energy economy. Numerous studies demonstrate that natural 

gas is not a panacea. Investments in energy efficiency and renewables, along 

with a transmission and distribution grid capable of supporting them, are critical to our nation’s energy future. There is much that the federal government 

can and should do to accelerate the development and deployment of efficiency 

and renewables, and I would be pleased to share these ideas with the committee 

at the appropriate time. 

Natural gas has indeed transformed our nation’s energy mix. And the economic 

and environmental benefits of natural gas are clear. But the jury is still out on 

whether gas production can and will be done safely and responsibly—and whether 

it will help or hurt our efforts to solve climate change. Getting strong, effective rules 

in place is the key. Irrespective of whether the U.S. becomes an LNG exporter, or 

whether the nation expands the use of natural gas vehicles, natural gas needs to 

be produced responsibly. If we fail, the positive role it can play in helping to accelerate our transition to a clean, low-carbon energy future will be lost. 

STATEMENT OF PAUL KOUROUPAS, VICE PRESIDENT OF PUBLIC POLICY, VNG.CO, 

BALA CYNWD, PA 

My name is Paul Kouroupas. I am the Vice President of Public Policy of VNG.CO 

(VNG), a start-up compressed natural gas refueling infrastructure company based 

132 

1 Energy Information Administration. ‘‘Annual Energy Outlook.’’ 5 Dec 2012 http:// 

www.eia.gov/forecasts/aeo/er/index.cfm 

in Bala Cynwd, Pennsylvania. VNG offers a nationwide retail CNG fueling program 

to support the widespread use of light-duty natural gas vehicles (NGVs). VNG will 

install, operate and maintain CNG fueling equipment, co-located within existing retail gasoline stations. VNG will initially deploy its compressed natural gas pumps 

to support fleets with CNG fueling services in the retail market and ultimately expand its deployment to support the mass-market consumer segment. 

SUMMARY

The purpose of the present hearing is to ‘‘explore opportunities and challenges associated with America’s natural gas resources.’’ By and large, the current discussion 

has focused on the benefits of low-cost natural gas for chemical and manufacturing 

companies, as well as the benefits (and potential costs) of allowing gas producers 

to export this resource overseas. While these opportunities are considerable and certainly merit discussion, this focus misses the greatest opportunity for natural gas 

to improve our economy, environment, and national security while also benefitting 

American consumers directly: the potential of natural gas to fuel light-duty vehicles 

on a mass-market basis, which could be our most potent weapon in the fight to 

eliminate U.S. dependence on foreign oil. 

On behalf of VNG, I am pleased to share with the members of the Committee our 

company’s perspective on the unique benefits of using natural gas to fuel light-duty 

NGVs, as well several minor regulatory changes that can unleash these benefits for 

the American economy. 

• NGVs provide direct benefits to consumers—Development of the light-duty NGV 

market allows Americans to directly benefit from the shale revolution, instead 

of limiting direct benefits to manufacturers, trucking fleets, or exporters. With 

natural gas priced 40% below gasoline for a gallon equivalent, the average U.S. 

household that currently spends $3,000 per year on gasoline could save $1,200 

per year on fuel costs with natural gas. 

• The greatest mass-market potential of any alternative fuel—With over 15 million light-duty NGVs on the road worldwide, NGVs are an established technology, and the shale gas revolution gives America unprecedented potential to 

commercialize them on a mass-market basis. The National Petroleum Council 

of the U.S. Department of Energy last year released a comprehensive report 

analyzing alternative fuels and concluded that NGVs have the potential to 

achieve 17% of new light-duty vehicle sales by 2020—far higher than other alternatives, which face significant technological obstacles and higher costs. 

• International clean energy technology leadership—Development of the domestic 

market for light-duty NGVs can help U.S. automakers lead in the burgeoning 

international NGV market, which is already growing rapidly in countries like 

Germany, Italy, Brazil, and Argentina. NGVs can also serve as a platform for 

innovation and development of renewable natural gas (RNG) and hydrogen fuel 

cell technologies, gaseous fuels which can dramatically reduce transportation 

GHG emissions. 

Despite this unique potential, light-duty NGVs have received relatively little attention from policymakers, and this technology still suffers from an uneven playing 

field compared to other transportation alternatives like electric vehicles (EVs) and 

biofuels. As the Committee considers the various opportunities and challenges associated with America’s natural gas abundance, the light-duty NGV market ought to 

be included in the discussion as perhaps the greatest opportunity of all, and lawmakers should seek to provide NGVs with a level playing field compared to other 

alternative fuels. There is substantial private investment in compressed natural gas 

(CNG) fueling infrastructure and automakers are beginning to offer a growing 

breadth of vehicles that run on CNG. By leveling the playing field for NGVs, Congress will encourage additional private investment. 

THE LIGHT-DUTY NGV OPPORTUNITY

The ability of natural gas to serve as a fuel for heavy-duty fleets has been well 

known to policymakers for many years, but these vehicles consume just a quarter 

of the total on-road fuels in the U.S.1 Thanks to the vast new low-cost gas supplies 

unlocked by the shale drilling revolution, it is now possible to consider the potential 

to bring the benefits of natural gas fuel to the light-duty cars, vans, SUVs and 

133 

2 Bi-fuel natural gas vehicles are capable of running the same internal combustion engine on 

either gasoline or natural gas. Retaining a gasoline tank while the natural gas refueling infrastructure is being developed eliminates drivers’ ‘‘range anxiety.’’ 3 U.S. Energy Information Administration. ‘‘U.S. household expenditures for gasoline account 

for nearly 4% of pretax income.’’ 4 Feb 2013. http://www.eia.gov/todayinenergy/detail.cfm?id=9831 4 Eisenstein, Paul. ‘‘Are battery-powered cars losing their charge?’’ Autoblog. 6 Dec 2012. 

http://www.autoblog.com/2012/12/06/are-battery-powered-cars-losing-their-charge/ 5 Rascoe, Ayesha and Deepa Seetharaman. ‘‘U.S. backs off goal of one million electric cars by 

2015.’’ Reuters. 31 Jan 2013. http://www.reuters.com/article/2013/01/31/us-autos-greencars-chuidUSBRE90U1B020130131 6 Borenstein, Seth. ‘‘What holds energy tech back? The infernal battery.’’ Associated Press. 22 

pickups that are driven by U.S. business and government fleets as well as families 

that consume 75% of U.S. on-road fuels. 

Despite a relative lack of policy support, U.S. automakers and natural gas refueling infrastructure providers like VNG have already recognized the enormous opportunity represented by the light-duty NGV market. GM and Chrysler have both introduced new bi-fueled2 NGV versions of popular pickup truck models for fleet customers, and VNG is working to develop the kind of retail-oriented fueling infrastructure for these fleets that will also seed the market for future mass-market consumers. Furthermore, natural gas producers like Chesapeake and Encana are making their own efforts to promote widespread adoption of natural gas in recognition 

of the fact that this market could be vital to the long-term profitability of the U.S. 

gas drillers. 

While progress is already being made by the private sector in developing the 

light-duty NGV market, greater policymaker understanding of NGVs and support 

for a level playing field for them will help this market achieve its full potential sooner. 

Light-Duty Vehicles Are Chief Driver of Oil Dependence 

Transportation accounts for 70% of U.S. oil consumption and 30% of greenhouse 

gas emissions, making it a critical sector to address in the pursuit of U.S. energy 

independence and climate change goals. And, while other sectors of the economy (including power, manufacturing, and home heating) have moved away from oil use 

over the past three decades, the transportation sector is still almost completely dependent on gasoline and diesel, leaving U.S. businesses, government, and households at the mercy of volatile global markets. Increasing domestic production of unconventional oil is a welcome development, but it does not affect our vulnerability 

to global price swings, nor is it sufficient to significantly reduce global prices. 

Light-duty vehicles (including cars, SUVs, vans, and pickups) are the main source 

of this dependency, accounting for 75% of on-road transportation fuel use in the U.S. 

According to new data from the EIA, the average American household spent nearly 

$3,000 on gasoline to fill these light-duty vehicles last year—nearly 4% of household 

pretax income, the highest level in three decades.3 Addressing the near-total dependence of light-duty vehicles on oil must remain a central priority of U.S. energy 

policy, for the sake of the economy, our national security, and the environment. 

Other Alternatives Are Falling Short of Expectations 

While policymakers have touted various preferred alternative fuel technologies in 

recent years, these technologies have failed to make an impact thus far and may 

not for the foreseeable future. 

• Electric Vehicles—Sales of the Chevy Volt and Nissan Leaf in 2012 were less 

than half of automaker projections, combining for less than 35,000 sold nationwide.4 The Administration, a staunch backer of EV technology in the 2009 stimulus bill, recently acknowledged the struggles of the industry and backed off its 

2011 goal of having one million plug-in electric vehicles on U.S. roads by 2015.5

In fact, some industry observers believe that EVs will not be able to overcome 

the cost and recharging issues that limit their appeal to consumers until there 

is a new breakthrough in battery technology—which could be decades away.6

• Cellulosic Biofuels—Both the current and previous Administrations have hailed 

the potential of cellulosic biofuels made from non-food feedstocks to provide a 

sustainable source of renewable transportation fuel. However, this technology 

faces fundamental challenges in cellulosic feedstock production and distribution 

as well as the high cost of processing these feedstocks into fuels, which have 

prevented any significant commercial volume of these fuels from being produced 

despite government mandates for millions of gallons per year under the RenewVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00137 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
134 

7 Congressional Research Service. ‘‘Renewable Fuel Standard (RFS): Overview and Issues.’’ 23 

Jan 2012. http://www.fas.org/sgp/crs/misc/R40155.pdf 8Green Car Congress. ‘‘DC Circuit court vacates 2012 cellulosic RFS standard, affirms 2012 

advanced biofuel standard.’’ 27 Jan 2013. http://www.greencarcongress.com/2013/01/api20130127.html 9Gas Vehicles Report. http://www.ngvjournal.com/en/magazines/the-gvr/download/3523/11378/ 

26 

* All reports have been retained in committee files. 

10 National Petroleum Council. ‘‘Future Transportation Fuels Study.’’ Aug 2012. http:// 

www.npc.org/FTF-80112.html 11 Ebhardt, Tommaso and Craig Trudell. ‘‘Gasoline Sticker Shock Fuels Fiat Natural Gas Auto 

Sales.’’ Bloomberg. 17 Sept 2012. http://www.bloomberg.com/news/2012-09-17/gasoline-stickershock-fuels-fiat-natural-gas-auto-sales.html 

able Fuels Standard.7 Indeed, a district court recently vacated EPA’s 2012 requirement for cellulosic biofuels due to a lack of availability.8

While both EV and advanced biofuels technologies may hold merit in the long 

term, the fact is that both face substantial near-term technological barriers to their 

success. The seriousness and urgency of our near-total transportation dependence 

on oil requires a focus on solutions that are ready to make a difference today—not 

technology gambles that may or may not become a viable solution five or ten years 

down the road. 

‘‘Larger, Faster, Earlier’’ Impacts for Light-Duty NGVs 

In contrast to EVs and biofuels, NGVs are the only alternative fuel solution to 

offer a ready technology at an affordable price—today. Natural gas can save drivers 

up to 40% on fuel costs (or $1,200 per year based on average household gasoline 

expenses of $3,000), and our vast shale reserves guarantee stable, low-cost domestic 

supplies for decades. Light-duty NGVs are also a proven technology with no ‘learning curve’ similar to electric vehicles (EVs)—indeed, there are over 15 million lightduty NGVs on the road worldwide in countries in Europe, Asia, and South America.9 Since the engine and performance is the same, natural gas can power any sort 

of vehicle that currently uses gasoline, and fleets and consumers can continue to 

buy the vehicles they like and need. 

These advantages were recognized in a landmark new comprehensive study of alternative fuel technologies by the National Petroleum Council of the U.S. Department of Energy. According to this ‘‘Future Transportation Fuels’’ report*, NGVs 

have potential for ‘‘larger, earlier, and faster’’ impacts on U.S. oil dependence compared to other alternatives due to a lack of technological barriers combined with the 

economic rationale presented by fuel savings. In the composite ‘‘best case’’ scenario 

developed by the NPC, light-duty NGVs were able to achieve a 17% share of new 

light-duty vehicle sales by 2020—double the share of plug-in hybrid electrics 

(PHEVs) and pure EVs combined.10

A key finding of the NPC report* is the potential for rapid cost reductions in the 

incremental costs of NGVs compared to gasoline vehicles through simple manufacturing economies of scale. While today’s NGV incremental costs in the U.S. may be 

$10,000 or more, this is due to the inefficiencies of low-volume conversions, and not 

due to the use of expensive components (as is the case with EVs, whose even greater 

incremental costs are due to costs of lithium-ion batteries, which are already mass 

produced). The NPC projects that incremental costs could be reduced by 2/3rds in 

the near term with a move to high-volume, assembly-line production of 100,000 vehicles/year. 

The European experience clearly shows that rapid cost reductions of this magnitude are possible. Indeed, in Italy, Fiat already sells some bi-fuel models at an 

incremental cost of less than $3,000, and Opel (the European arm of GM) is offering 

rebates that can completely eliminate incremental costs.11 This ability to achieve incremental cost reductions in the near term without need for any technological advances is key to understanding the vastly greater potential of NGVs compared to 

other alternatives, as it gives NGVs a realistic path towards mass-market viability—without the need for long-term subsidies. EVs and advanced biofuels simply 

cannot claim a similar path, as both depend on subsidies and technological breakthroughs which may or may not materialize even in the long term. 

An Opportunity for U.S. Companies to Lead in Key Clean Energy Technologies 

NGVs may be an established technology compared to EVs and biofuels, but the 

global market for these vehicles is just beginning to realize its potential. U.S.-developed shale gas drilling technology is being exported to countries all over the world, 

helping to usher in what the International Energy Agency has called a ‘‘Golden Age 

135 

12 International Energy Agency. ‘‘Are we entering a golden age of gas?’’ World Energy Outlook 

2011. http://www.worldenergyoutlook.org/goldenageofgas/ 13 National Petroleum Council. ‘‘Renewable Natural Gas for Transportation.’’ 1 Aug 2012. 

http://www.npc.org/FTFlTopiclpapers/22-RNG.pdf 14 Energy Vision. ‘‘Renewable Natural Gas: The Solution to a Major Transportation Challenge.’’ 2012. http://energy-vision.org/wordpress/wp-content/uploads/2012/05/EV-RNG-Facts-andCase-Studies.pdf 15 Cannon, James S. ‘‘Natural Gas: An Essential Bridge to Hydrogen Fuel Cell Vehicles.’’ January 2012. http://vng.co/wp-content/uploads/2012/05/Natural-Gas-An-Essential-Bridge-To-Hydrogen-Fuel-Cell-Vehicles.pdf 16 VNG.CO. ‘‘Comments of VNG.CO.’’ 6 Feb 2012. http://vng.co/wp-content/uploads/2012/05/ 

Natural-Gas-As-Essential-Bridge-To-Hydrogen-Fuel-Cell-Vehicles-With-Comments.pdf 17Federal Register. ‘‘2017 and Later Model Year Light-Duty Vehicle Greenhouse Gas and Corporate Average Fuel Economy Standards; Final Rule.’’ 15 Oct 2012. P. 62814. http:// 

www.gpo.gov/fdsys/pkg/FR-2012-10-15/pdf/2012-21972.pdf 18Medlock, Dr. Kenneth. ‘‘U.S. LNG Exports: Truth and Consequences.’’ August 2012. http:// 

bakerinstitute.org/publications/US%20LNG%20Exports%20- 

%20Truth%20and%20Consequence%20Final—Aug12-1.pdf 

of Gas.’’12 By establishing America as the center of development for NGVs in the 

years ahead, U.S. automakers will be positioned to take advantage of new opportunities in overseas markets in Asia, Europe, and South America that are just beginning to develop their shale gas resources. 

NGVs are also a platform for the development of even cleaner, ultra-low-carbon 

transportation fuels and technologies that will be needed to combat climate change. 

NGVs can fuel on biogas (or renewable natural gas, or ‘‘RNG’’) captured from landfills, wastewater plants, and other sources, resulting in ultra-low lifecycle GHGs of 

90% below gasoline or less.13 Moreover, unlike cellulosic biofuels mandated in the 

RFS, biogas is a renewable fuel derived from non-food feedstocks that is being produced and used in commercial applications today.14

In the longer term, natural gas will also facilitate the development of hydrogen 

fuel cell vehicles (FCVs) due to numerous fuel storage and refueling infrastructure 

synergies between these gaseous fuels.15 FCVs are a crucial technology for meeting 

long-term climate change goals, combining the zero-emission performance of EVs 

with the gasoline-like range and refueling characteristics of NGVs. 

In comments on the 2017-2025 light-duty vehicle regulations,16 VNG argued that 

the development of the light-duty NGV market would reduce several specific ‘‘nearterm market barriers to FCV adoption’’ identified by EPA and NHTSA, including: 

• Refueling Infrastructure—NGV refueling stations use most of the same hardware used to dispense hydrogen fuel, enabling them to be adapted to supply hydrogen or even hydrogen-natural gas blends in the future; 

• Fuel Cost—Hydrogen produced through the steam reforming of natural gas is 

the lowest-cost method of distributed hydrogen production available today; 

• Vehicle Cost—Natural gas and hydrogen also share gaseous storage technologies, and innovations and cost improvements for advanced on-board storage 

and fuel management technologies for NGVs will benefit FCVs as well. 

The EPA acknowledged these linkages in its rationale for giving NGVs additional 

‘‘advanced technology’’ multiplier incentives in the new 2017-2025 light-duty vehicle 

regulations, and cited VNG’s comments as well as those of Natural Gas Vehicles for 

America in support of this decision.17

MAXIMIZING DOMESTIC BENEFITS OF THE U.S. GAS BOOM

Despite concerns expressed by some parties over potential increases in natural 

gas demand from NGVs or LNG exports, the reality is that the shale gas revolution 

has unlocked an enormous amount of natural gas supply capacity that can be 

tapped at relatively low costs. 

• A recent study by (hearing witness) Dr. Kenneth Medlock III of the James 

Baker III Institute for Public Policy18 finds that shale gas supplies have effectively increased the elasticity of domestic gas supplies fivefold. Thus, the long 

term price of gas will remain between $4-$6 per MMCF for ‘‘decades’’ even with 

substantial increases in demand. 

• Chesapeake Energy has similarly noted that, based on the production economics 

of current domestic gas plays, the U.S. could add gas production sufficient to 

meet the fuel needs of 2/3rds of the entire domestic light-and heavy-duty transportation fleet while maintaining long-term natural gas prices of less than $7 

per MMCF—still low by historic standards. 

136 

19The White House. ‘‘Fact Sheet: All-of-the-Above Approach to American Energy.’’ 7 March 

2012. http://www.whitehouse.gov/the-press-office/2012/03/07/fact-sheet-all-above-approach-american-energy 

When considering the ‘‘opportunities and challenges’’ for natural gas, light duty 

NGVs offer the opportunity to save consumers an average of $1,200 per year on 

their fuel costs, reduce greenhouse gas emissions by 24% (and up to 90% with renewable natural gas), and achieve energy independence by replacing oil use in the 

vehicles consuming 75% of on-road transportation fuels. And if the domestic NGV 

market develops robustly, natural gas producers will have strong domestic demand 

for their product, reducing the incentive to export natural gas—and its economic, 

environmental, and energy security benefits—overseas. 

POLICY CHANGES TO LEVEL THE PLAYING FIELD FOR NGVS

Policymakers can realize this vision for light-duty NGVs simply by providing them 

with a level playing field to compete with other alternative fuel technologies, potentially including the following steps: 

• Remove Regulatory Barriers—While the new 2017-2025 light-duty vehicle regulations promulgated by EPA and NHTSA take important steps towards creating 

a level playing field for NGVs, they still face arbitrary and unfair obstacles 

under the CAFE program due to outdated legislative restrictions intended to 

limit credits for E85 flex-fuel vehicles. Legislation is necessary to harmonize 

treatment for NGVs, granting them the fair, no-cost regulatory incentives that 

EPA and NHTSA have already said they deserve. 

• Tax Credit Parity for NGVs—EVs currently benefit from tax credits of up to 

$7,500 per vehicle included in the 2009 stimulus bill, while light-duty NGVs receive no tax credits. As detailed in the NPC report, although NGVs do not face 

the same long-term cost obstacles as EVs (which are unique to EV dependence 

on expensive lithium-ion battery packs), incremental NGV costs are high today 

simply due to low production volumes. The current Administration has previously advocated for identical tax credits for both EVs and NGVs,19 and such 

a level playing field would help increase NGV demand and bring down prices 

in the near term. 

• Federal Vehicle Fleets—Federal vehicle fleets should be leaders in adopting 

light-duty NGVs, which would save taxpayer money through lower fuel costs, 

help reduce vehicle costs for consumers and businesses through increasing production economies of scale, and support the private sector development of retailoriented CNG refueling networks for public use. However, current federal fleet 

procurement of alternative fuel vehicles is focused almost entirely on flex-fuel 

E85 vehicles due to their low incremental costs—despite the fact that these vehicles may end up costing more over their lifetime due to E85 costs that are 

higher than gasoline on a per-BTU basis. E85 also yields fewer environmental 

and energy security benefits than natural gas. Federal fleets should be required 

to evaluate the lifecycle costs and benefits of all fleet purchases, which would 

reward the superior cost savings and environmental performance of NGVs. 

• Alternative Fuel Standard—The current RFS, which as noted calls for unattainable volumes of cellulosic biofuels that do not yet exist, is broken and unfairly 

focuses only on biofuels. Expanding this program to an ‘‘Alternative Fuel Standard’’ would allow refiners to meet requirements with credits generated by any 

alternative fuel that reduces GHG emissions by 20% or more—including CNG 

and electricity as well as biofuels. This type of ‘‘fuel neutral’’ policy would encourage much more rapid progress towards energy independence goals than the 

current biofuel-only RFS. 

VNG played an active role in facilitating recent progress on the regulatory treatment of NGVs by EPA, and is recommending Congress take additional action to address these issues that cannot be addressed simply through administrative action. 

VNG appreciates the opportunity to submit this testimony and looks forward to 

working with the Committee and other policymakers to support the light-duty NGV 

market, which will reduce the cost of driving for American households and businesses, reduce climate change impacts for transportation, and help this country 

achieve energy independence. If you have any questions or would like additional information, please contact me at pkouroupas@vng.co (973-886-7675). 

137 

STATEMENT OF AMERICAN CHEMISTRY COUNCIL

February 12, 2013 The American Chemistry Council* is pleased to submit for the 

hearing record our Executive Committee’s unanimously approved position related to 

energy and competitiveness (see attached). The policy re-emphasizes our strong support for a comprehensive ‘‘all of the above’’ energy strategy to support U.S. economic 

growth and the growth of the chemical industry. 

The policy also restates ACC’s support for free market policies that promote the 

export of American-made goods, including liquefied natural gas. The Executive Committee unanimously expressed its opposition to any new export bans or restrictions 

on liquefied natural gas, such as a moratorium on export terminals or the prohibition on the export of natural gas produced on public lands. 

While there is broad agreement among ACC members on these key principles, 

there is not a clear consensus on the issue of whether the Natural Gas Act’s public 

interest requirement should be further defined in export permitting to non-FTA 

countries. 

ACC will continue to discuss this issue. ACC members will also continue to work 

together to vigorously advocate for sound energy and related regulatory policies that 

will ensure the availability of abundant, diverse energy supplies and stable reliable 

energy markets. 

*The American Chemistry Council (ACC) represents the leading companies engaged in the business of chemistry. ACC members apply the science of chemistry 

to make innovative products and services that make people’s lives better, healthier 

and safer. ACC is committed to improved environmental, health and safety performance through Responsible Care®, common sense advocacy designed to address major 

public policy issues, and health and environmental research and product testing. 

The business of chemistry is a $760 billion enterprise and a key element of the nation’s economy. It is one of the nation’s largest exporters, accounting for ten cents 

out of every dollar in U.S. exports. Chemistry companies are among the largest investors in research and development. Safety and security have always been primary 

concerns of ACC members, and they have intensified their efforts, working closely 

with government agencies to improve security and to defend against any threat to 

the nation’s critical infrastructure. 

ACC POLICY ON ENERGY AND COMPETITIVENESS

ACC supports public policies that promote the availability of competitively priced 

natural gas and feedstock to support the continued growth of the chemical industry 

in the United States. To that end, ACC supports free trade principles in the context 

of U.S. energy policy. Natural gas has enormous potential to renew and grow the 

American chemistry industry, the entire domestic manufacturing sector, and the 

U.S. economy at large, creating jobs and more exports of manufactured goods. America needs to couple rules-based free trade principles with an ‘‘all of the above’’ energy strategy to ensure we are fully developing our domestic energy resources, including natural gas, and taking full advantage of each energy source to promote sustained economic growth. 

ELEMENTS OF ACC POLICY ON ENERGY AND COMPETITIVENESS

• ACC supports a market-based ‘‘all of the above’’ national energy policy anchored 

in maximizing access to competitively priced domestic energy supplies, using energy efficiently and developing a diverse set of energy sources. 

• An abundant, competitively priced and reliable supply of natural gas and natural gas liquids (NGLs) has created a manufacturing renaissance in the United 

States. ACC supports policies that promote our industry’s competitive advantage, such as public policies and positions that encourage the responsible production of natural gas and NGLs. 

• As America’s largest export industry, we support exports of American-made 

products, including liquefied natural gas (LNG). 

• ACC supports the application of existing trade rules (including WTO commitments and bilateral Free Trade Agreements) to all exports, including LNG. 

• Consistent with U.S. trade laws, we oppose imposition of any new LNG export 

bans or restrictions, such as those that would impose a moratorium on export 

terminals or prohibit exports of gas produced on public land. We support full 

compliance with the Natural Gas Act in the issuance of LNG export permits, 

including the presumption that exports to Free Trade Agreement countries are 

in the public interest. 

• There is a lack of clear consensus among our members concerning whether the 

Natural Gas Act’s ‘‘public interest’’ requirement should be further defined in exVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00141 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
138 

port permitting for non-FTA countries. ACC therefore will further study this 

issue and ways to achieve consensus. 

• ACC will also continue to monitor the U.S. energy situation, including natural 

gas supply/demand scenarios, and their implications for global competitiveness 

of the industry. 

STATEMENT OF BILL COOPER, PRESIDENT, CENTER FOR LIQUEFIED NATURAL GAS

As President of the Center for Liquefied Natural Gas, I would like to thank Chairman Ron Wyden and Ranking Member Lisa Murkowski of the Senate Energy and 

Natural Resources Committee for accepting the following testimony, to be entered 

into the public record. 

I will be focusing on the topic of liquefied natural gas (LNG) exports, specifically 

by identifying common myths and then providing a summary of the facts. As you 

will see from this testimony, the United States has abundant supplies of natural 

gas, more than enough to allow for exports while also meeting growing domestic demand. 

The ability to export LNG represents a window of opportunity to create more jobs, 

generate more public revenues and reduce our trade deficit. A multitude of industries and communities will benefit from this opportunity to export some of America’s 

abundant natural gas resources in global markets. 

By resuming its approval process for LNG export applications, the U.S. Department of Energy can allow the United States to begin reaping those benefits, without 

hurting U.S. consumers. 

MYTH 1—We should use natural gas here in the United States instead of exporting it. 

Data compiled by the U.S. government and independent experts show clearly that 

the United States has an abundant supply of natural gas, more than enough to 

meet growing domestic demand and allow for exports. 

For example, the U.S. Energy Information Administration’s 2013 Annual Energy 

Outlook shows that U.S. natural gas production is projected to grow by roughly 40 

percent from 2012 to 2040. Over the same period, U.S. consumption of natural gas 

is expected to grow by less than 20 percent. Because production of U.S. natural gas 

is projected to rise faster than consumption by 2040, the U.S. has a natural gas surplus available for export. 

Meanwhile, a recent report from Deloitte observed the following: 

Producers can develop more reserves in anticipation of demand growth, 

such as LNG exports. Indeed, LNG export projects will likely be backed by 

long-term supply contracts, as well as long-term contracts with buyers. 

There will be ample notice and time in advance of the exports to make supplies available. 

Furthermore, reports from the Brookings Institution, the Congressional Research 

Service and the Baker Institute at Rice University—among many others—have 

stressed the enormous size of America’s natural gas resource base, which in turn 

underscores the large surplus, a portion of which the United States can leverage for 

exports to create additional jobs, new tax revenues and a reduction in our trade deficit. 

In addition to fundamental economic realities about the benefits of free trade, this 

large natural gas surplus is a key reason why a recent macroeconomic report from 

the U.S. Department of Energy concluded that ‘‘LNG export has net benefits to the 

U.S. economy.’’ The DOE report also observed that exports would specifically benefit 

consumers by stating that the net result of allowing LNG exports ‘‘is an increase 

in U.S. households’ real income and welfare.’’ The report added that ‘‘consumers, in 

aggregate, are better off as a result of opening up LNG exports.’’ 

MYTH 2—Natural gas exports would harm U.S. manufacturing. 

Many of the largest U.S. manufacturers have voiced support for LNG exports. 

Companies like General Electric and Caterpillar, for example, have both written to 

the U.S. Department of Energy urging approval for LNG export applications, stressing the economic benefits that exports would yield, as well as the potential economic 

harm from retaliatory trade restrictions that other countries could impose upon the 

United States. 

In a blog post entitled ‘‘Banning LNG Exports Will Hurt Jobs and Economy,’’ the 

National Association of Manufacturers observed the following: 

Proposals that seek to limit LNG or coal or any other product would have 

far-reaching negative effects on the United States and should be rejected. 

139 

Such restrictions limit economic opportunities and stifle job growth rather 

than provide a source of increased economic growth. 

Export growth has created and saved manufacturing jobs over the past 

few years, which were tough economically for the United States. Export 

growth is vital not just for businesses across-the-board that directly export, 

but also for the many manufacturers in the supply chain. 

In its Initial Comments to DOE on the NERA LNG Export Study, the National 

Association of Manufacturers also noted: 

With 95 percent of the world’s consumers outside the United States, export bans on any product, including LNG, can be expected to have farreaching negative effects, including on domestic economic opportunities, employment and ultimately economic growth. 

The United States’ ability to challenge other countries’ existing exports 

restraints on agricultural, forestry, mineral and ferrous scrap products— 

just to name a few—will be virtually non-existent if the United States itself 

begins imposing its own export restrictions. Even worse, as the world’s largest economy and largest trading country, U.S. actions are often replicated 

by our trading partners to our own dismay. If the U.S. were to go down 

the path of export restrictions, even more countries would quickly follow 

suit and could easily limit U.S. access to other key natural resources or inputs that are not readily available in the United States. 

As added proof, major chemical manufacturers that also support LNG exports are 

moving forward with plans to invest billions of dollars to expand their existing petrochemical operations. Put simply, companies would not be investing heavily in operations that rely on affordable and abundant supplies of natural gas and natural 

gas liquids (NGLs) if LNG exports truly posed a credible threat to that business. 

MYTH 3—Unfettered exports could undermine our economic competitiveness. 

In addition to the points outlined above, which detail how LNG exports would actually grow the U.S. economy, it’s important to note that arguing against ‘‘unfettered’’ or ‘‘uncontrolled’’ exports is a straw man. There is no such thing as unfettered or uncontrolled LNG exports. 

The U.S. government—through the Department of Energy (DOE) and the Federal 

Energy Regulatory Commission (FERC)—has a robust regulatory review process in 

place for LNG exports. Absent affirmative evidence from opponents that the proposed project is not in the ‘‘public interest,’’ DOE is required to approve the applications, thereby assuring a level playing field for all participants. Further studies are 

not warranted; the NERA study was robust with 63 scenarios including high and 

low side supply/demand cases. Every export scenario yielded positive net benefits for 

the U.S. economy. The DOE has also been studying LNG exports for more than one 

year already. DOE needs to actively resume the review process for all projects in 

the permitting queue and it needs to move expeditiously on those applications. 

The opportunity to export liquefied natural gas (LNG) will not remain on the 

table on the same scale, with the same benefits, indefinitely. The U.S. is not the 

only nation with abundant shale gas reserves. And while some debate the value of 

free trade in a global economy, other nations are trying to duplicate the success of 

America’s shale industry. 

Worldwide demand for LNG between 2020 and 2025 is projected to be around 60 

billion cubic feet per day (bcf/d), up from approximately 37 bcf/d today. The sizeable 

gap between future demand and current capacity, 23 bcf/d, makes the global LNG 

market an attractive opportunity. However, the United States is not the only nation 

capable of seizing this opportunity. 

The capacity of non-U.S. projects that are either planned, proposed or under construction is approximately 50 bcf/d. In fact, proposed foreign LNG capacity is more 

than double the expected global market opportunity in 2025. If you add on proposed 

U.S. LNG capacity, the global marketplace has a proposed supply of 80 bcf/d competing to fill only 23 bcf/d of demand. The longer the U.S. delays, the more likely 

other nations will satisfy that demand. 

MYTH 4—Exports will lead to significant price increases for natural gas in the 

United States. 

Numerous assessments of potential LNG exports have found that any impact on 

domestic prices would be minimal. 

For example, the Brookings Institution observed that producers of natural gas 

‘‘will likely anticipate future demand from LNG exports and will increase production 

accordingly, limiting price spikes.’’ Brookings also noted that any price impact would 

be ‘‘modest.’’ Kenneth Medlock with the Baker Institute has said: ‘‘The impact on 

U.S. domestic prices will not be large if [LNG] exports are allowed.’’ 

140 

In a report commissioned for the U.S. Department of Energy, NERA Economic 

Consulting found that ‘‘price changes attributable to LNG exports remain in a relatively narrow range across the entire range of scenarios,’’ adding that any such 

price changes ‘‘do not offset the positive impacts’’ from exports. 

What many opponents of exports cite in reference to prices is the EIA’s price impact study from 2012, which analyzed four different export scenarios. In the most 

dramatic (and most unlikely) scenario, the model suggested an extreme upper limit 

price impact of 54 percent. But the scenario that many experts agree is the most 

likely is that natural gas price impacts would peak at less than 10 percent. At least 

one analysis, from Deloitte, pegged the price impact at only two percent. 

To provide a real-world example of how the price issue differs in rhetoric from 

reality, Methanex is relocating one of its methanol plants from Chile to Louisiana 

to take advantage of abundant and low-cost natural gas supplies. Addressing the 

export concern head on, Methanex CEO John Floren said it signed long-term supply 

contracts to hedge against any potential price impacts, reflecting a fundamental 

market reality of chemical manufacturing in the United States that undermines the 

suggestion that future price volatility would prevent the future growth of this industry. 

Interestingly, at least one of the chemical companies that has voiced opposition 

to LNG exports on the basis of price impacts has stated that if ‘‘natural gas were 

available at a consistent $6-$8 dollar per MMBtu range, U.S. petrochemical facilities could be globally competitive.’’ Current Henry Hub natural gas prices are less 

than $3.50 per MMBtu, meaning even in the worst-case and most unrealistic scenario modeled by EIA (where LNG exports increase domestic prices by 54 percent), 

the cost of natural gas would be $5.39 per MMBtu—below the price range that at 

least one major chemical manufacturer has said publicly would keep the industry 

competitive. 

A common criticism by opponents of LNG exports is that natural gas production 

will lag demand, causing price spikes if there are LNG exports. Since 2008, we’ve 

seen production increase by 10 bcf/d and natural gas prices fall by more than $8 

per thousand cubic feet (mcf). Clearly, natural gas production was running faster 

than demand or there wouldn’t have been such a dramatic decline in natural gas 

prices. Given the new shale gas realities, producers should be able to ramp up production in anticipation of demand growth. 

MYTH 5—The ‘‘value-add’’ for exports is low. 

According to the U.S. International Trade Administration (ITA), each $1 billion 

of exports could result in more than 5,000 new jobs, many of which would be permanent manufacturing jobs. Thus, $13 billion to $25 billion worth of LNG exports— 

the current range of investment possibilities—could mean the creation of between 

70,000 and 140,000 new American jobs. ITA has also observed that the value per 

export-supported job is almost $165,000. 

Construction and operation of new LNG projects will create as many as 50,000 

new jobs in design, engineering and construction, which translate into hundreds of 

millions of dollars in new wages for U.S. workers during the construction of the facility. 

LNG exports will also lead to additional domestic natural gas production, which 

will in turn create hundreds of thousands of new jobs in the United States. 

The enormous potential for new jobs is a major reason why labor unions have also 

voiced support for LNG exports. Brad Karbowsky with the United Association of 

Plumbers, Fitters and HVAC Techs said the following about potential jobs created 

as a result of LNG exports: 

The billions of dollars in wages generated by these well-paying jobs will 

be multiplied throughout communities across the country in the form of investment and taxes, which will in turn be used to support schools, fire stations and other essential public services. This new source of shared prosperity will provide a foundation for future growth. 

Harry Melander, President of the Minnesota State Building and Construction 

Trade Council, has also observed: 

Exporting America’s abundant natural gas to global markets is yet another excellent opportunity to increase job production and investment as a 

result of the burgeoning U.S. domestic energy production. 

Nor are the benefits all directly related to the LNG industry. As natural gas production has expanded in recent years due to the responsible development of shale, 

local businesses like hotels and restaurants in production areas have benefitted 

from a growth in demand for their products and services. Adam Diaz, a small business owner in Susquehanna County, Pa., recently observed: 

141 

In the last three years since the natural gas industry came to Susquehanna County, Pennsylvania, my company has been able to grow from 30 

employees to 250, while our revenue has increased from less than $2 million annually to almost $50 million today. This growth has led to an increased tax contribution of almost $3.5 million in federal, state and local 

taxes. Recently though, drilling rig counts have been falling in my area. 

LNG exports will increase demand, bring back the rigs and allow businesses like mine to grow and add much needed jobs to local economies to 

keep them strong. 

With LNG exports, U.S. natural gas production will grow even more. That production will create U.S. jobs in support sectors that manufacture steel pipe, equipment, 

control panels, heavy duty trucks, and cement, in addition to well-paying jobs for 

welders, pipefitters, cement masons, plumbers, machinery mechanics, pump operators and engineers. 

MYTH 6—Exports could lead to competitive disadvantages of U.S. manufacturers 

in global trade 

The price of natural gas in the U.S. will be priced below what competitors will 

face in Asia, for example, even with U.S. exports. There is a substantial cost to liquefying natural gas and transporting it specialized tankers to distant markets 

(ranges from $8 billion to $20 billion per project of 2 bcf/d), and that fact means 

the U.S. domestic price for natural gas will be several dollars per thousand cubic 

feet lower than the price of natural gas in countries which import our LNG. 

Rice University professor Ken Medlock notes in his 2012 LNG Export study that 

these costs will average $2.92/mcf for liquefaction and $2.15/mcf for transportation 

to Asia ($5.07/mcf total). Other studies show the cost range to be higher, including 

the NERA study that has a cost range between $6.30/mcf to $8.39/mcf. 

Therefore, according to these studies, U.S. manufacturers would still enjoy a $5/ 

mcf to $8/mcf cost advantage over Asian competitors, even if Asian prices and U.S. 

LNG delivered prices in Japan equalize. That provides a huge competitive advantage to U.S. manufacturers even with LNG exports from the United States. 

MYTH 7—LNG exports will back out the same amount of gas used by manufacturers. 

Critics assume a zero-sum game in natural gas markets, where 1 bcf of LNG exports takes exactly 1 bcf in supply away from the manufacturing sector. Those critics assert that supply doesn’t increase; there is merely a reallocation of given volume of U.S. gas production. History shows that markets don’t work that way. They 

adjust to increasing demands and gas supply can be expected to increase in response to any increase in demand. Of course, producers will respond to demand 

growth and changes in gas prices; they will develop more projects and produce more 

gas. 

Critics never mention that there will be more gas production to feed LNG exports 

and to feed increased gas use by manufacturing. A more realistic view of the world 

actually takes into account that producers will respond to demand changes—i.e., 

that the supply curve is very elastic and not completely inelastic as in the zero sum 

mischaracterization of the critics. As producers increase gas production in response 

to growing demand, manufacturing use of gas can still increase. 

An economically realistic depiction of what the shale gas revolution is all about 

would yield benefits of exports plus the value of the additional U.S. gas production 

and growth in manufacturing use. In fact, the discussions about the benefits of manufacturing asserted by critics are misleading because they try to make it appear 

that the choice is stark between either manufacturing or exports, when the real 

choice involves whether the U.S. wants to reap the benefits from exports plus more 

natural gas production plus more manufacturing use of gas. 

This is not a zero sum game. The shale gas revolution requires a change in this 

zero-sum mind-set in which natural gas supplies are fixed or diminishing over time, 

and in which the policy issue is one of deciding which sector gets what share of an 

ever-diminishing natural gas resource. As Dr. Daniel Yergin, Vice Chairman of IHS 

and founder of IHS CERA, explained in his testimony before the House Energy and 

Commerce Committee’s Subcommittee on Energy and Power on February 5, 2013: 

[O]wing to the very large resource base, the market in the U.S. is demand-constrained, rather than supply-constrained. Larger markets—whether they be in electric power, industrial consumption, transportation, or exports—are required to maintain the investment flow into the development 

of the resources. 

It is worth repeating: the natural gas market is not supply constrained as the zero 

sum mind set argues; it is demand constrained. If additional demand comes, addiVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00145 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
142 

tional natural gas supply will come along as well. The new shale gas reality is that 

there is an increasing gas supply available for LNG exports in addition to increasing 

domestic demand, including power generation, manufacturing and other gas consumers. 

MYTH 8—Natural gas deserves special restraints that apply to no other product. 

Critics argue that it is better for the economy to export finished products made 

using natural gas rather than exporting natural gas. Taken to its logical conclusion, 

that prescription would mean that it is not beneficial to export chemicals or aluminum or any intermediate product that is used by another manufacturer. American automobile makers use considerable materials made from chemicals, plastics 

and aluminum, so according to the critics’ logic, exports of chemicals, plastics and 

aluminum should be restricted to ensure low U.S. prices of these products for the 

benefit of automakers or other consumers. The long history of support for free trade 

by Democrat and Republican administrations would be thrown out with this logic. 

There is no sound economic rationale for claiming natural gas is a special case requiring laborious study before exports are allowed; nor are chemicals, plastics, lumber, wheat, aluminum, and countless other manufacturing and agricultural products 

special cases calling out for extensive review and study before their exports are allowed. The U.S. economy would be a net beneficiary from unrestricted LNG exports, 

just as the U.S. is a net beneficiary of unrestricted exports of chemicals, plastics, 

and aluminum and countless other products. 

Additionally, restraints on LNG exports run afoul of the United States’ obligations 

under WTO and GATT, as well as the long-standing policy of the United States to 

support exports. As stated in the comments filed with DOE by the Peterson Institute for International Economics: 

If the United States nevertheless does impose restraints [on LNG exports], U.S. actions will certainly be cited in the future by other countries 

that decide to flout international trade rules and restrict their own exports 

of natural resources as a means of subsidizing downstream industrial users. 

What’s more, it is likely that countries that are not FTA partners will either retaliate with their own natural resource restrictions or challenge U.S. 

policies at the WTO. 

As General Electric stated in its comments filed with the DOE: 

[D]eclining to approve exports of natural gas would be squarely at odds 

with the United States’ longstanding policy and international trade norms 

disfavoring export restraints (see GATT Article XI). Indeed the United 

States has been the vanguard of those challenging such restraints globally. 

(See US/EU/Mexico Challenge to China’s Export Restraints on Raw Materials—WTO DS 394, 395, 398, successfully challenging China’s export restraints on certain raw materials).For the United States to now adopt such 

restrictions itself would fundamentally undermine its own international 

trade policy, which has served to preserve critical access to raw materials 

globally. 

MYTH 9—No clearly established criteria exist for DOE to apply the public interest standard in permitting applications for LNG exports. 

The DOE has provided regulatory clarity as to what constitutes the public interest, establishing a clear standard for future decisions. 

For example, in the Kenai LNG case, the DOE concluded: ‘‘DOE considers domestic need for the gas and any other issue determined to be appropriate, including 

whether the arrangement is consistent with DOE’s policy of promoting competition 

in the marketplace . . . ’’ Since then, DOE has added several considerations to the 

‘‘domestic need,’’ but most appear to flow from the concept that the primary concern 

is to have enough natural gas to meet the domestic needs of U.S. consumers. 

For instance, DOE has added the following considerations, quoting from the Federal Register notice in the Golden Pass Products LLC filing: 

To the extent determined to be relevant or appropriate, these issues [considerations] will include the impact of LNG exports associated with this Application, and the cumulative impact of any other application(s) previously 

approved, on domestic need for the gas proposed for export, adequacy of domestic natural gas supply, U.S. energy security, and any other issues, including the impact on the U.S. economy (GDP), consumers, and industry, 

job creation, U.S. balance of trade, international considerations, and whether the arrangement is consistent with DOE’s policy of promoting competition in the marketplace by allowing commercial parties to freely negotiate 

their own trade arrangements. 

143 

The record for the various proceedings at DOE overwhelmingly contains evidence 

that the U.S. has an abundance of natural gas, more than enough to meet growing 

domestic needs for years to come and allow LNG exports. That evidence is in the 

form of the factual studies filed in support of the various applications now pending 

before the DOE. 

For further clarification, DOE issued its 1984 Policy Guidelines, which were later 

amended to include exports, stating: 

[t]he market, not government, should determine the price and other contract terms of imported [or exported] natural gas. The federal government’s 

primary responsibility in authorizing imports [or exports] will be to evaluate the need for the gas and whether the import [or export] arrangement 

will provide the gas on a competitively priced basis for the duration of the 

contract while minimizing regulatory impediments to a freely operating 

market.’’ DOE’s three stated responsibilities are: One, ‘‘to evaluate the need 

for the gas′′; two, assure that the ‘‘arrangement will provide the gas on a 

competitively priced basis for the duration of the contract′′; and three, to 

‘‘minimiz[e] regulatory impediments to a freely operating market. 

As to the need for the gas, borrowing from the Sabine Pass order, there has been 

‘‘substantial evidence showing an existing and a projected future supply of domestic 

natural gas sufficient to simultaneously support export and domestic natural gas demand both currently’’ and over the terms of the projects proposed. 

Concerning competitive pricing, there is a very liquid, competitive domestic market for natural gas with a multitude of producers, marketers, sellers, and buyers, 

thus assuring that the natural gas is competitively priced in the U.S. market. 

The third stated responsibility of DOE is to ‘‘minimize regulatory impediments to 

a freely operating market.’’ Such a responsibility certainly cannot mean that any 

one market determinant, such as price or export volumes, could be used to impede 

the development of the free market. What it surely means is that applicants that 

meet the statutory and regulatory requirements should be granted the authorizations to export LNG from the United States without regulatory limitation as to export volumes. The ‘‘freely operating market’’ will then allocate scarce and finite economic resources such as financing and end-use contracts to determine which 

projects will be built and become operational. For as some projects will likely be 

built, others may not. 

The role of the regulator is to assure a level playing field for all participants and 

to monitor developments for continued consistency with the public interest, not to 

be a predictor of future events. DOE’s policy to allow a ‘‘freely operating market’’ 

to function with minimal regulatory impediments directly acknowledges the plain 

reading of the Natural Gas Act, which gives DOE the tools to respond to market 

conditions that adversely affect the public interest, not to predict future events during the authorization proceeding for projects with lifespans in excess of 20 years 

each. Those market conditions are not short-term phenomena such as temporary 

price increases. 

Far from being vague in its regulatory framework, DOE has a clearly defined set 

of criteria for making its LNG export determinations, with that framework focusing 

on the domestic need for the natural gas proposed to be exported in order to protect 

the U.S. consumer. 

MYTH 10—DOE’s process lacks opportunity for all affected stakeholders and the 

general public to comment on what constitutes the ‘‘public interest.’’ 

Once DOE determines that an application is complete, it publishes a notice in the 

Federal Register informing the public of the opportunity to submit motions to intervene, protest, and/or to comment on the proceedings. The opponents complaining 

about the lack of opportunity to get involved have been publicly outspoken on the 

issue of LNG exports since prior to the closing of those public comment periods and 

have sufficient resources to monitor events and take such action as necessary to protect their interests. They simply chose not to do so. 

CONCLUSION

LNG exports would provide the United States with enormous economic benefits— 

new jobs, new tax revenue, new economic growth and a reduced trade deficit. Better 

yet, these benefits will not come at the expense of domestic consumers of natural 

gas, whether they are industrial users or individual households. 

Those opposed to LNG exports have employed a series of inaccurate characterizations about LNG and the impacts that would result from allowing exports. As such, 

I thank the Committee for providing me the opportunity to explain why such claims 

are myths, and that the overwhelming evidence shows that allowing LNG exports 

144 

1 Natural gas prices set to jump with exports - Pittsburgh Tribune-Review http:// 

www.pittsburghlive.com/x/pittsburghtrib/sl741745.html#ixzz1QOd1TrPm 

2http://gulfnews.com/business/markets/china-s-natural-gas-push-will-affect-energy-prices1.829199 

will be a net benefit to the United States. I respectfully request that the Committee 

urge DOE to commence issuing export approvals so the U.S. can reap all of the benefits of our natural gas resources. 

STATEMENT OF PAUL SANSONE, SANSONE & ASSOCIATES

The ‘Shale Gale’, a huge expansion of available domestically produced natural gas, 

is the subject of the hearing. I am writing to provide documentation that the legal 

and regulatory oversight of the industry was manipulated by apparent fraud to secure exception from environmental regulation (Clean Air Act, and Clean Water Act 

exemptions), fast track approval for LNG ‘‘import’’ terminals ( FERC review not 

State review), and the right of eminent domain for natural gas pipelines connected 

to these terminals. Substantial evidence exists that the use of false and misleading 

information and industry wide racketeering was utilized to allow industry to 

produce the current oversupply of natural gas and create a political and economic 

conditions necessary to convert the ‘‘stranded assets’’ of import terminals and pipelines for the export of natural gas. The goal of the apparent fraud and racketeering 

appears to be a covert effort to convert limited regional natural gas markets into 

an internationally traded commodity which could be used for speculative investment. The scope and impact of this apparent fraud obligates an immediate investigation, the cessation of any natural gas export permits until the full facts are 

made public, and the criminal prosecution of those responsible for misleading Congress and the American people. 

Please find attached an Issue summary prepared in March of 2011, before the industry was openly calling for the conversion of LNG ‘‘import’’ terminals to ‘‘export’’ 

facilities. Developers seeking permits for a LNG ‘‘import’’ facility in Oregon (Oregon 

LNG, Leucadia Corp.) publicly solicited investors for the project promoting ‘‘import’’ 

permits as a short-cut to more profitable ‘‘export’’ facilities. 

Industry projections of domestic natural gas resource size and estimated costs of 

production have been consistently unreliable. A newly released analysis of the domestic natural gas resource entitled ‘‘Drill, Baby, Drill—Can unconventional fuels 

usher in a new era of energy abundance’’ by J. David (http://www.postcarbon.org/ 

reports/DBD-report-FINAL.pdf) calls into question the actual size of the domestic 

natural gas resource. 

SUMMARY OF LNG

LNG export fraud—legal and policy options 

We’re truly going to go down as the dumbest generation.. It’s bad public 

policy to export natural gas—a cleaner, cheaper domestic resource—and import more expensive, dirtier OPEC oil.1

T. Boone Pickens in response to U.S. Dept. of Energy’s approval of the first U.S. LNG 

export terminal 

1. Summary—Booming U.S. natural gas production from shale gas and the 

resulting low prices have triggered a wave of now public proposals to export 

U.S. gas as LNG. The proposed LNG export terminals were all either recently 

constructed or expanded for the stated purpose of LNG import. While the companies built their core facility infrastructure, such as docks, pipelines and storage tanks, claiming they would increase U.S. gas supplies, these same companies are now moving to use this infrastructure to sell U.S. gas into the highpriced Pacific Rim and European markets. With China’s recent announcement 

that it will increase is natural gas use by over 300 percent in the next five 

years,2 China is positioning itself as the most likely purchaser of U.S. LNG 

pending development of its own shale gas resources. Opening the door to U.S. 

LNG export would cause a major increase in the price of natural gas for consumers and unprecedented profits for gas producers. 

Despite the lack of any rational economic basis for LNG import and Oregon’s 

unique location for LNG export, investors behind two LNG terminals planned for 

Oregon continue to claim to state and federal regulators, their investors and the 

public that the Oregon terminals are intended to import LNG. While the Jordan 

Cove terminal in Coos Bay recently acknowledged it was considering export, its forVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00148 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
145 

3ORS 162.085(1), ‘‘(1) A person commits the crime of unsworn falsification if the person knowingly makes any false written statement to a public servant in connection with an application 

for any benefit.’’ The term ‘‘benefit’’ is broadly defined to mean ‘‘gain or advantage to the beneficiary or to a third person pursuant to the desire or consent of the beneficiary.’’ ORS 162.055(1). 

See Oregon Federation of Teachers v. Oregon Taxpayers United, 345 Ore. 1; 189 P.3d 

9(2008)(broadly defining what constitutes a ‘‘benefit’’ under ORS 162.085(1)) 4 U.S. Energy Information Administration (2005 averge wellhead price of $7.33/thousand cubic feet compared to 2009 and 2010 average wellhead prices of $3.67 and $4.16.) 5 Henry Hub price of June 15, 2011 of $4.52/mmbtu. http://www.neo.ne.gov/statshtml/124.htm; Japanese pre-earthquake LNG prices from January 2011 were $11.96/mmbtu and as of June 

2011 had risen to nearly $ 14 mmbtu. Japan’s December LNG Import Bill Rises 3.9% on Crude, 

Bloomberg News By Dinakar Sethuraman - Jan 30, 2011 http://www.bloomberg.com/news/2010- 

12-29/japan-s-november-lng-import-bill-increases-6-after-crude-oil-prices-gain.html; http:// 

www.asahi.com/english/TKY201106220170.html. 6http://www.lngworldnews.com/usa-cove-point-lng-requests-ferc-approval-to-order-lng-imports 

7http://www.excelerateenergy.com/2011/04/04-13-2011.html 

8http://www.bloomberg.com/news/2011-05-20/cheniere-surges-45-after-u-s-expands-its-lng-export-approval.html 9http://www.pennenergy.com/index/blogs/all-energyall-the-time/blogs/Pennenergy/all-energyall-the-time/post987l6847736399226820909.html 

mal regulatory filings continue to assert the terminals would be used for LNG import. There is a strong basis, however, to believe that the claims that the Oregon 

terminals are intended for LNG import are fraudulent and that the planned terminals have long been intended to export expanding Rockies shale gas production to 

the Asian market. 

A review of the five existing U.S. LNG terminals now proposing to export LNG 

supports that the Oregon projects are following a pattern of intentional deception 

that involves some of the largest U.S. natural gas producers and pipeline companies 

when they allege that their terminals are for LNG import. 

If true, falsely claiming intended export projects are import projects to investors 

and government regulators would violate a host of state and federal laws. These 

range from the federal Securities and Exchange Act and criminal prohibitions 

against making false statements to federal agencies to violations of Oregon’s criminal prohibition against ‘‘unsworn falsification’’ which prohibits providing false information to a state agency in an effort to obtain a ‘‘benefit’’ such as a wetland fill 

permit or state land lease.3 Furthermore, providing false information to a state 

agency under ORS 162.085(1) is a predicate offense under Oregon’s Racketeer Influenced and Corrupt Organization Act (ORICO). Oregon Federation of Teachers v. Oregon Taxpayers United, 345 Ore. 1; 189 P.3d 9(2008) (specifically affirming that violations of ORS 162.085(1) qualified as ORICO predicate offenses. 

Because of the price impacts on consumers in states near proposed LNG export 

terminals and the very similar pattern of expansion or development for import followed quickly by a switch to export that has occurred at each of the LNG terminals 

now proposing export there may be grounds for a coordinated investigation with 

other states such as New York and Maryland. 

In addition to any potential criminal or civil enforcements, there are strong public 

policy reasons for pressuring the investors pushing LNG terminals in Oregon to stop 

their false claims that the planned terminals are still intended for LNG import. 

2. The national rush to export LNG 

The largest gas producers and pipeline companies in the United States are moving to convert at least five of the 11 existing U.S. LNG import terminals into LNG 

export terminals that would export low-priced U.S. natural gas to the Asian (primarily Chinese) and European markets. The plans come as new drilling technology 

has opened up a surge in natural gas production that has sent average gas prices 

in 2009 and 2010 to half of their 2005 levels.4 Asian LNG prices, however, remain 

more than 300 percent above U.S. prices5 and LNG prices in Europe are on the 

order of 200 percent above U.S. prices. 

The price equation has brought U.S. LNG imports to almost a standstill and the 

Cove Point Maryland LNG terminal in June 2011 even asked FERC to order LNG 

tankers to deliver LNG to its facility against their will to maintain safety systems 

that depend on LNG for cooling.6 In April 2011, Excelerate Energy announced it 

was completely abandoning the offshore LNG import facility it built in 2005 in the 

Gulf because of abundant U.S. gas supplies.7

In May, 2011, the U.S. Dept. of Energy (DOE) approved Cheniere Energy’s plan 

to export U.S. produced gas as LNG from its Sabine Pass, LA LNG terminal which 

was permitted and constructed as an LNG import terminal.8 Cheniere already has 

a contract to export the U.S. produced LNG to China.9 The terminal is the world’s 

largest and the project is now pending FERC approval. DOE approved the project 

despite Cheniere’s own study showing that allowing just this one export terminal 

146 

10 U.S. DOE Order approving LNG export from Sabine Pass LNG terminal at p. 11, citing 

Navigant Consulting’s Market Analysis for Sabine Pass LNG Export Project (NCI Report) at p. 

14. See also Natural gas prices set to jump with exports - Pittsburgh Tribune-Review http:// 

www.pittsburghlive.com/x/pittsburghtrib/sl741745.html#ixzz1QOd1TrPm 11 Estimate is based on a U.S. EIA 2010 reported marketed NG price of 4.16/ thousand cubic 

feet and total marketed production of 22,568,863 million cubic feet. http://www.eia.gov/dnav/ng/ 

nglprodlwhvldculnusla.htm 12 Natural gas prices set to jump with exports - Pittsburgh Tribune-Review http:// 

www.pittsburghlive.com/x/pittsburghtrib/sl741745.html#ixzz1QOd1TrPm 13 1 cubic meter of LNG = 20,631 cubic feet x 266,000 cubic meter LNG (for a QMAX tanker)= 

5487846000 cubic feet of natural gas per tanker. 5,487,846,000 cubic feet per tanker/total average daily of 2010 U.S. marketed natural gas production of 61,832,501,370 = 0.08875 = 8.8 % 

of average daily US marketed natural gas production. 14 Natural gas prices set to jump with exports - Pittsburgh Tribune-Review http:// 

www.pittsburghlive.com/x/pittsburghtrib/sl741745.html#ixzz1QOd1TrPm 15 Natural gas prices set to jump with exports - Pittsburgh Tribune-Review http:// 

www.pittsburghlive.com/x/pittsburghtrib/sl741745.html#ixzz1QOd1TrPm 16 Natural gas prices set to jump with exports - Pittsburgh Tribune-Review http:// 

www.pittsburghlive.com/x/pittsburghtrib/sl741745.html#ixzz1QOd1TrPm 17http://www.adn.com/2008/11/09/583470/utility-petitions-to-block-gas.html 18http://www.adn.com/2010/07/08/1359592/give-southcentral-priority-on.html; http:// 

www.adn.com/2010/08/14/1410315/parnell-backs-liquefied-natural.html 19http://www.adn.com/2011/02/09/1692895/ap-newsbreak-alaska-lng-plant.html 20http://www.lngworldnews.com/indonesia-may-import-4-5-mtpa-of-lng-from-2013/ 

could result in up to an 11.6 percent increase in the price of U.S. natural gas.10 This 

price increase alone would generate more than $10 billion a year in increased revenues for U.S. gas producers based on 2010 gas revenues and would come directly 

from consumers’ pockets.11 But the potential 11 percent price increase from just one 

LNG terminal highlights just how much producers would benefit from opening the 

door to broader LNG export and what is at stake for U.S. consumers. 

In a recent Pittsburgh Times article on the potential for LNG export to increase 

gas prices, the Times reported that if the five already proposed export terminals 

were approved they could collectively export 13.9 percent of total U.S. gas production12 and fundamentally change the U.S gas market. But even this is a gross underestimate. If the two proposed Oregon LNG terminals are included, as well as 

other terminals that will likely soon move to export, the potential export percentage 

number jumps significantly higher. 

The ease at which the United States could feel the pain of LNG exports is highlighted by the fact that a modern large scale QMAX LNG tanker (266,000 cubic meters), which has already docked at the Sabine Pass LNG terminal, can export more 

than 8.8 percent of total U.S. daily gas production in a single shipment.13

Major energy consumers are finally waking up to the reality of how LNG exports 

would drive a major increase in U.S. gas prices. The Industrial Energy Consumers 

of America, which represents American manufacturers with annual sales of $800 

billion and 750,000 employees, is now fighting Cheniere’s Sabine Pass LNG export 

plans with its saying that the impact on gas prices would be ‘‘absolutely frightening.’’14 T. Boone Pickens opposed the Cheniere LNG export saying that if the 

United States approved LNG export we ‘‘we’re truly going to go down as the dumbest generation.. It’s bad public policy to export natural gas—a cleaner, cheaper domestic resource—and import more expensive, dirtier OPEC oil.’’15 The American 

Public Gas Association, which represents 700 public gas companies in 36 states is 

also opposing LNG export because of the threat to increased prices.16

The potential for LNG exports to drain seemingly abundant supplies is not merely 

hypothetical. Alaskan industrial gas users, consumers and some elected leaders 

strongly opposed Conoco’s plans to extend its FERC permit at its LNG export terminal in Kenai Alaska, which at the time was the only U.S. export terminal. Alaska’s largest electric utility even filed suit to challenge the exports saying that the 

terminal, which exported a third of all locally produced gas, drove up prices and left 

it without adequate supply to meet local needs.17 18 But with the facility nearing the 

end of its FERC license, Conoco announced in February 2011 it was closing the export facility because it could not obtain sufficient gas supplies to export and meet 

local needs.19 Ironically, Conoco (which is now proposing LNG export from its Freeport Texas LNG terminal) also said it was considering converting the Kenai facility 

into an LNG import terminal. 

In a similar example, Indonesia, for which for years was a major LNG exporter, 

has recently found itself planning its first LNG import terminal as it now faces gas 

shortages caused by LNG export.20

3. Change to U.S. natural gas market 

147 

21http://www.bloomberg.com/apps/news?pid=newsarchive&sid=aH0jhcEHz07s 22http://www.indexmundi.com/energy.aspx?product=gas&graph=consumption 23 U.S. EIA, 2010. 24 ‘‘Palomar gas partners pull the plug on controversial pipeline proposal,’’ Oregonian, March 

23, 2011. http://www.oregonlive.com/business/index.ssf/2011/03/palomarlgaslpartnerslpulllthe.html 25http://www.oregonlive.com/business/index.ssf/2011/07/oregonllnglterminallplanslreve.htm 

26http://www.williams.com/midstream/msloperations.aspx 27http://www.pacificconnectorgp.com/overview.php 28 Ruby Pipeline, Final EIS at p. 1-2. 29http://www.investorvillage.com/mbthread.asp?mb=2234&tid=8498013&showall=1 30http://www.pacificconnectorgp.com/partners.php; http://www.williams.com/midstream/ms— 

operations.aspx 

Allowing LNG exports would change the fundamental mechanics of the U.S. natural gas market, which is currently defined by massive new gas discoveries in shale 

formations, production increases, and low prices. The United States recently outpaced Russia as the World’s largest natural gas producer21 and is by far the largest 

natural gas consumer using 47 percent more natural gas than Russia, which is the 

second largest consumer.22 Globally, the U.S. has the fourth largest proven gas reserves with well over a hundred years of supply and only Russia, Iran and Qatar 

have larger reserves.23 Exporting LNG, however, would drive both increased prices 

and major increases in U.S. gas production that could meaningfully reduce U.S. gas 

supplies. 

4. Investors claim Oregon projects still for LNG import 

Despite the fundamentals of the U.S. gas market and agreement from federal, 

state and private sector experts that there is no justification for new LNG import 

terminals,24 the investors pushing the two Oregon LNG terminals continue to tell 

federal and regulators, investors and the public that their projects are for LNG import. While the proposed Jordan Cove terminal in Coos Bay has recently acknowledged that it is considering LNG export, it continues to formally claim to FERC and 

the State of Oregon that its terminal is for LNG import. Both companies are relying 

on the benefits of LNG imports to support that the project is in the ‘‘public interest’’ 

and entitles them to the powers of eminent domain. 

There is a strong basis for believing that such representations are fraudulent and 

that there is no genuine intent to import LNG. As even the Oregonian recently reported, ‘‘Experts say export economics from Oregon are a slam dunk, potentially 

doubling the price that Canadian and U.S. producers net for their gas domestically.’’25

A number of factors strongly support that the Oregon LNG projects are intended 

for export. These factors include: 

1. The absence of any market rationale for importing LNG given the abundance and low price of U.S. gas and the comparatively high price of global LNG; 

2. The high profit margin from exporting low-cost U.S. gas to the nearby Pacific Rim market and the increased revenues that would result from the higher 

gas prices generally; 

3. The new FERC-permitted pipeline infrastructure to the Jordan Cove terminal would create a direct connection from William’s Opal Wyoming gas hub 

to the Coos Bay LNG terminal with at least one company (PG&E Strategic Capital) owning gas capacity on the new Ruby Pipeline (Opal Wyoming to Malin, 

Oregon) and owning a 1/3rd interest in the Pacific Connector (Malin, OR to 

Coos Bay); 

4. Gas producers have a strong incentive to export abundant Rockies’ gas supplies which are driving low Rockies’ prices. Williams, which is Wyoming’s largest gas producer as well as a major pipeline owner, for example, is the co-owner 

and lead player in developing the 234-mile Pacific Connector pipeline that 

would connect the Jordan Cove terminal to the western terminus of the new 

Ruby Pipeline from Wyoming at Malin, Oregon.26 27 The 680-mile nearly completed Ruby Pipeline, in fact, originates at the Opal Hub, which Williams operates and is considered the gas epicenter of the Rockies.28 Williams is well aware 

of the need for new export capacity from the Rockies and decreased its Wyoming production by 15 percent in 2009 due to low prices.29 30

While Ruby’s owner, El Paso Energy, (which is also large U.S. gas producer (22nd 

largest in 2009) will clearly benefit from the large California gas market, El Paso 

is no stranger to LNG and actually owns the Elba Island LNG terminal in Georgia. 

The terminal is operated by BG Group, which has already proposed LNG exports 

148 

31 Huge natural gas field ’discovered’ in Texas, World Net Daily News; November 30, 2005 

http://www.wnd.com/?pageId=33642 32 Richard M. Pollastro, U.S. Geological Survey, Denver, Colorado, Geologic and Production 

Characteristics Utilized in Assessing the Barnett Shale Continuous (Unconventional) Gas Accumulation, Barnett-Paleozoic Total Petroleum System, Fort Worth Basin, Texas; presented at 

Barnett Shale Symposium Ellison Miles Geotechnology Institute Brookhaven College, Farmers 

Branch, Dallas, Texas 2003. On file 33 Cheniere applied to US DOE in September 2010 and the application was approved in May 

2010. 34http://www.firstenercastfinancial.com/forums/showthread.php?t=10&page=7 35http://www.firstenercastfinancial.com/forums/showthread.php?t=10&page=7 36http://uk.reuters.com/article/2011/02/01/lng-dominion-export-idUKN0122810220110201 

from its Lake Charles terminal and there is every reason to expect that LNG export 

will soon be proposed from El Paso’s Elba Island, GA terminal. 

4. Oregon terminals are following a familiar path 

The Oregon terminals appear to be following a similar path of intentional misrepresentation which has become more obvious as U.S gas supplies have remained 

high and prices low. A review of each of the five LNG terminals now proposing LNG 

export shows that these facilities were either constructed or significantly expanded 

in the last two to three years with the project backers claiming that they would help 

import low cost LNG into the U.S. market. Completion of construction was soon following by announcement of plans to export. 

The bonanza of new shale gas has been well known to gas industry insiders since 

well before 2003,31 when even USGS described the Barnett Shale formation in 

Texas, which was the first mega shale find, as a ‘‘giant gas accumulation’’ and ‘‘one 

of the most significant domestic onshore gas plays.’’32 Just as these shale gas formations were spiking production and similarly massive gas reserves were being discovered in the Haynesville shale in east Texas and Louisiana, a group of companies 

all heavily involved in gas production (Exxon-Mobil, Cheniere, Conoco-Phillips) 

launched plans for LNG ‘‘import’’ terminals on the Gulf Coast in pipeline-close proximity to the Barnett Shale. Four new terminals in the Gulf were completed between 

2008 and 2010, as were major terminal expansions at three existing LNG terminals 

on the East Coast. 

Each project cost on the order of a billion dollars and was built at a time when 

the then-existing LNG terminals were not even operating at half capacity. Once the 

projects were completed, these same companies effectively declared their LNG import projects obsolete given the high price of LNG and low cost of U.S. gas and 

quickly re-positioned to obtain export approval. While an LNG terminal needs to install expensive liquefaction equipment to be converted to LNG export, the roughly 

$3 billion costs are minimal given the potential price differential between U.S. gas 

and Pacific Rim LNG prices. Although permit modifications from FERC and U.S. 

DOE are needed, DOE approved Cheniere’s export application within nine months 

and FERC is moving quickly on the application.33

These companies now frame their unique ability to quickly modify their terminals 

to switch to lucrative LNG export as something they stumbled into as a chance to 

salvage their expensive investments in LNG import. As Cheniere Energy, which was 

exclusively a gas producer before proposing the Sabine Pass and Freeport LNG terminals, explained in announcing that the Sabine Pass import terminal would switch 

to LNG export, ‘‘[t]he 853-acre Sabine Pass site is strategically situated to provide 

export services given its large acreage position, proximity to unconventional gas 

plays in Louisiana and Texas, and its interconnections with multiple interstate and 

intrastate pipeline systems.’’34 Cheniere further explained that, ‘‘the Sabine Pass 

terminal already has many of the needed facilities for an export terminal. Cheniere 

would use its existing infrastructure, including five storage tanks and two berths 

at the Sabine Pass terminal, as well as Cheniere Energy Inc.’s 94-mile Creole Trail 

Pipeline . . . ’’35

When Dominion Resources, which owns the recently expanded Cove Point Maryland LNG terminal and is a Marcellus shale gas producer, announced it was considering LNG export its Chief Executive made nearly the same comment stating, ‘‘If 

you think about Cove Point, where it sits there in the Mid-Atlantic, a couple hundred miles from the Marcellus region, it has got all the facilities it needs other than 

the liquefaction itself.’’36

The idea, however, that the world’s largest and most sophisticated gas industry 

players, such as Conoco-Phillips, Sempra, Dominion and Exxon-Mobil, all collectively responded to news of massive new U.S. shale gas discoveries by making catastrophically poor decisions to invest in costly LNG import projects that can now coincidentally be used as the springboard for far more lucrative LNG export projects 

is strained. While there clearly were assessments supporting the need for new LNG 

149 

37 Additional research is needed to better detail the timing of LNG terminal development and 

shale gas acquisition generally described below which should be considered preliminary. 38http://www.reuters.com/article/2010/03/02/lng-elba-expansion-idUSN0215533320100302 39http://www.ft.com/cms/s/0/d0443c62-7b26-11e0-9b06-00144feabdc0.html#axzz1SsEVzme7 40http://www.nytimes.com/2010/03/25/business/global/25energy.html 41http://www.thestreet.com/story/10447133/1/chesapeake-statoil-form-gas-venture.html;http:// 

www.reuters.com/article/2011/02/01/lng-dominion-export-idUSN0122810220110201 42http://www.chron.com/disp/story.mpl/headline/biz/5956709.html 43http://panews.com/local/x847473509/Golden-Pass-LNG-receives-first-shipment 44http://thetimes-tribune.com/news/gas-drilling/marcellus-gas-has-transco-pipeline-almost-atcapacity-1.1118270#axzz1RLZJJwgV 45http://www.advfn.com/newsllExxon-CEO-No-Thought-Of-Exporting-LNG-FromUSl40756658.html 46http://www.bloomberg.com/news/2011-06-01/exxon-mobil-targets-first-papua-new-guinea-lngcargoes-in-2014.html 47http://www.marketwatch.com/story/exxon-mobil-to-buy-xto-energy-in-41-billion-deal-2009-12- 

14 48http://www.denverpost.com/business/ci—16462625 

terminals, there is no question that gas producers were well aware of the unprecedented U.S. shale reserves when they proposed LNG import projects. 

From a geographical perspective alone, it is worth noting that the biggest new 

LNG ‘‘import’’ projects in Freeport, TX (Conoco), Golden Pass, LA(Exxon-Mobil), 

Sabine Pass, LA(Cheniere Energy),, and Cameron, TX(Sempra) all constructed in 

the last two to three years, were all built at the close proximity to Texas’ Barnett 

Shale which was the first mega-shale reserves to be ‘‘discovered’’ and commercially 

produced with Halliburton’s fracking technology in the 1990s and early 2000s. 

5. Companies acquire shale gas interests while expanding LNG ‘‘import’’ terminals 

It is also telling that many of the companies building new LNG ‘‘import’’ terminals or expanding existing terminals were acquiring major interests in U.S. shale 

gas reserves at the same time they were developing and expanding their nearby 

LNG terminal infrastructure for the purported purpose of LNG import.37 For example: 

Lake Charles and Elba Island LNG terminals—BG Group(formerly British Gas), 

spent over $900 million expanding the Elba Island and Lake Charles LNG terminals 

and constructing new gas pipelines while at the same time acquiring gas production 

rights for almost a million acres in the Marcellus and Haynesville shale formations.38 BG Group, which controls almost 50 percent of the total LNG terminal capacity on the East Coast, is now seeking permission to export LNG its Lake Charles 

terminal.39 BG Group recently signed a 20-year $70 billion deal in March 2010 to 

export LNG to the China National Offshore Oil Corp (CNOOC) from Australia and 

the Chinese are potential purchasers for the Lake Charles LNG as well.40

Cove Point Maryland—Statoil (Europe’s second largest gas importer) doubled the 

storage and output capacity of the Cove Point Maryland LNG terminal in 2009, 

shortly after buying a 32 percent interest in 1.8 million acres of the nearby 

Marcellus shale in 2008.41 At the same time Dominion Resources, which owns the 

Cove Point terminal and is also a Marcellus shale gas producer, expanded the pipeline infrastructure to the terminal. 

Cove Point Statoil’s deal was with Chesapeake Energy(2nd largest U.S. gas producer) who is a partner in the Cheniere LNG export project and has likely been the 

most active industry proponent of LNG exports. 

Freeport LNG terminal—Conoco-Phillips, the 3rd largest U.S. gas producer and 

the 50 percent owner and operator of the Freeport LNG terminal, received its first 

LNG shipment at its new billion dollar LNG import terminal in April 2008, but less 

than four months later it sought permission to re-export the LNG it had imported.42

Golden Pass LNG terminal—Exxon-Mobil, the largest U.S. gas producer, and coowner of the newly built Golden Pass LNG terminal (which it co-owns with Conoco 

and Qatar Gas) in Texas received its first LNG shipment in October 2010 with commenters noting that there was no domestic market for the gas.43 As a part of that 

project Exxon built a new 69-mile pipeline that connects the facility with Williams’ 

Transco Pipeline system which is near capacity with a flood of new shale gas production.44 While Exxon-Mobil has thus far denied any interest in exporting, or interesting even re-exporting LNG45, it globally has significant experience in LNG and 

is currently building a $15 billion LNG export terminal in Papua New Guinea.46

Exxon-Mobile has also been aggressively acquiring shale gas producers in the 

Haynesville Shale (LA/TX) and Marcellus Shale (NY, PA) including its 2009 $41 billion purchase of XTO Energy47 (3rd largest owner of U.S. gas reserves), Haynesville 

shale producer Ellora Energy for $695 million in 201048, and $1.6 billion for two 

150 

49http://www.haynesvilleplay.com/2011/06/exxon-still-buying-gas.html 50 U.S. EIA, 2009. 51http://www.reuters.com/article/2011/06/07/lng-export-sempra-idUSN079630320110607 52http://www.lngpedia.com/2009/06/24/sempra-cameron-lng-terminal-louisiana-gets-its-firstlng-shipment/ 53http://www.lngworldnews.com/usa-ferc-approves-sempra-to-re-export-lng-from-cameronterminal/ 54 a100.gov.bc.ca/.../1137189645610—5f08234ed4754316b54f925e36601e44.pdf 55 a100.gov.bc.ca/.../1226700475492—8e248a8d30d89bba23feaf7f461ca741d9738f8be453.pdf 56http://www.nrcan.gc.ca/eneene/sources/natnat/kitimat-eng.php 57 Richard M. Pollastro, U.S. Geological Survey, Denver, Colorado, Geologic and Production 

Characteristics Utilized in Assessing the Barnett Shale Continuous (Unconventional) Gas Accumulation, Barnett-Paleozoic Total Petroleum System, Fort Worth Basin, Texas; presented at 

Barnett Shale Symposium Ellison Miles Geotechnology Institute Brookhaven College, Farmers 

Branch, Dallas, Texas 2003 58http://www.nytimes.com/gwire/2011/05/20/20greenwire-frack-studys-safety-findings-exaggerated-bush-65374.html 59http://www.kbr.com/Newsroom/Articles/Features/Did-You-Know/Leading-With-ExperienceKBRs-LNG-Firsts/ 60http://www.lngworldnews.com/canada-apache-eog-award-kitimat-lng-feed-contract-to-kbr/ 61 15 U.S.C. § 717(b)(e)(3)(b)(ii). 

Marcellus Shale producers in 2011.49 These major acquisitions have made ExxonMobil by far the largest holder of U.S. gas reserves.50 Its current silence on LNG 

exports may reflect an effort to minimize attention while the first LNG export terminals from lower visibility companies are being approved. 

Cameron LNG terminal and Costa Azul (Baja)—Sempra, which is the largest gas 

company in the U.S. in terms of coverage area and population, served has said it 

is considering LNG export from its Cameron LNG terminal in Louisiana and potentially its Costa Azul terminal in Baja.51 The Cameron terminal was opened in June 

200952 as an LNG import terminal but within just a year and a half after opening 

it had received full FERC permission to export LNG.53

Kitimat, B.C.—When the Kitimat import terminal was approved in 2006 it’s investors claimed, ‘‘The Kitimat LNG terminal is designed to meet a supply shortage 

of natural gas in the North American market.’’54 But by November of 2008 Kitimat 

sought state and federal permission to change the plant from an import to export 

facility citing the abundant gas supplies in the ‘‘worldclass unconventional gas developments in northeastern BC (Horn River and Monterey fields).’’55 Less than two 

months later, Kitimat had won a permit amendment that authorized the export terminal and announced a deal to sell LNG to Mitsubishi.56 Kitimat is now co-owned 

by major shale gas producers Encana (7th largest gas producer), EOG Resources 

(9th largest U.S. gas producer) and Apache. 

6. Laying the foundation to export LNG from shale gas 

The gas industry was well aware of the massive potential for new shale gas before 

2003.57 Those interests, in fact, were very visible in the 2005 Energy Policy Act, 

which was crafted with strong influence from U.S. gas producers working under the 

Cheney Energy Task Force. The 2005 Act gave major tax breaks for shale gas development and the so-called ‘‘Halliburton Loophole,’’ exempted shale gas extraction 

from the Safe Drinking Water Act.58 Halliburton is considered the pioneer of the 

‘‘fracking’’ technologies needed for shale gas development and by the mid-1990s was 

highly active in Texas’ Barnett Shale. 

But the same people promoting special treatment for shale gas were intimately 

familiar with LNG export. Halliburton subsidiary KBR, for example, has built 40 

percent of the world’s LNG export terminals59 and recently won the design contract 

for the Kitimat LNG export terminal (originally permitted for LNG import) in British Columbia.60

There are even signs that those crafting the 2005 Energy Act actively planned to 

facilitate LNG export. For example, the Act included a condition that for the first 

time allowed LNG terminal operators obtaining permits before 2015 to use their terminal (import or export) exclusively for natural gas owned by the terminal’s operators and with the assurance that FERC was prohibited from, ‘‘any regulation of the 

rates, charges, terms, or conditions of service of the LNG terminal.’’61 This opened 

the door for gas producers to own an LNG terminal to export the gas they owned 

(or independently contracted for) free from the type of ‘‘open access’’ requirements 

that FERC had required for LNG terminals (and still does require for gas pipelines) 

and operate the terminal for maximum profitability. While this would benefit any 

LNG terminal operator, this special treatment provides a unique incentive for 

vertically integrated gas producers who are interested in export. 

7. Potential criminal and civil violations for misrepresenting export terminals 

as import terminals 

151 

If LNG terminal developers, pipeline companies and gas producers are misrepresenting efforts to develop LNG export infrastructure by falsely claiming to investors, 

federal and state regulators and the public that they are seeking to develop LNG 

‘‘import’’ projects they may be violating a host of state and federal laws. Cooperation 

with U.S. DOJ would be needed for the investigation of any federal violations and 

coordination with other states, such as Maryland and New York, could make sense 

given the particular impacts on these states from nearby export terminals. Because 

LNG export would likely trigger a major increase in hydraulic fracturing of shale 

gas in New York City’s drinking watershed, where controversy over fracing is already high, New York may be a particularly interested in investigating LNG exportrelated fraud. 

While a more detailed review of potential legal violations would be useful, at least 

several areas for further consideration and review include: 

A. False statements to state regulators 

The planned Oregon LNG terminal applicants have applied for a range of state 

permits, such as wetland fill permits and water right permits. In doing so the applicants have consistently claimed that the ‘‘purpose and need’’ for their projects was 

LNG import and that the facilities would in fact import LNG. While not sworn 

statements, Oregon law prohibits false unsworn statements related to obtaining a 

‘‘benefit’’ from the state. ORS 162.085(1) states: ‘‘(1) A person commits the crime of 

unsworn falsification if the person knowingly makes any false written statement to 

a public servant in connection with an application for any benefit.’’ 

The term ‘‘benefit’’ is broadly defined to mean ‘‘gain or advantage to the beneficiary or to a third person pursuant to the desire or consent of the beneficiary’’ and 

would definitely appear to include a water right, wetland fill permit or state land 

lease. ORS 162.055(1). Oregon’s Supreme Court has interpreted the term ‘‘benefit’’ 

very broadly finding that even annual non-profit charity financial reporting submitted to the Attorney General’s office was in effect an application for a ‘‘benefit’’ 

since the information in the form could lead to withdrawl of an entity’s charitable 

status. Oregon Federation of Teachers v. Oregon Taxpayers United, 345 Ore. 1; 189 

P.3d 9(2008). The Court further held that ORS 162.085(1) extended not only to a 

permit application itself, but any false statements made ‘‘in connection’’ to that application. Id. at 15. Violation of ORS 162.085(1) is a Class B misdemeanor. 

Investigation of such a crime would obviously open the door to the subpoena of 

internal documents related to potential LNG export under ORS 180.073. 

B. Oregon’s Racketeer Influenced and Corrupt Organization Act 

Violating ORS 162.085(1)’s restriction against unsworn falsification is a predicate 

crime under Oregon’s Racketeer Influenced and Corrupt Organization Act (ORICO). 

ORS 166.715(6)(a)(B). This has been specifically affirmed by the Oregon Supreme 

Court. Oregon Federation of Teachers v. Oregon Taxpayers United, 345 Ore. 1, 12; 

189 P.3d 9(2008). While additional research regarding a potential ORICO action is 

needed, ORICO’s powerful remedial provisions could even allow a court to order a 

defendant to abandon a permit obtained under fraudulent pretenses. ORS 

166.725(1). Furthermore, ORICO’s attorney fee recovery provisions under ORS 

166.725(14) have obvious practical benefits. 

C. False filings with federal regulators 

Federal law makes it a crime for any person to ‘‘knowingly and willingly’’ make 

‘‘any materially false, fictitious or fraudulent statement or misrepresentation’’ or 

‘‘falsifies, conceals, or covers up by any trick, scheme, or device a material fact’’ or 

‘‘makes or uses any false writing or document knowing the same to contain any materially false, fictitious, or fraudulent statement or entry’’ to any Agency or department of the United States regarding a matter within its jurisdiction. 18 U.S.C. § 

1001(a). Violations are punishable by up to five years in prison. Id. The companies 

seeking LNG terminals in Oregon have filed a broad spectrum of documents with 

federal agencies, such Federal Energy Regulatory Commission (FERC) and the U.S. 

Coast Guard, representing that their LNG terminals are planned and intended for 

LNG import. The LNG terminal investors now seeking LNG export from the Gulf 

and East Coast filed similar documents while seeking permits for construction and 

expansion approvals. To the extent that projects ultimately intended to be LNG export terminals were fraudulently misrepresented to federal regulators as ‘‘import’’ 

terminals violations of 18 U.S.C. §1001(a) may have occurred. Unlike Oregon law, 

such false statements are not a federal RICO predicate act. 

D. Federal and state securities fraud. 

Numerous companies associated with the five LNG terminals now proposing LNG 

export reported to investors and the Securities and Exchange Commission (SEC) for 

years that they were pursuing LNG import projects. Leucadia National, which has 

proposed the Oregon LNG terminal, and Veresen (formerly Fort Chicago), which is 

152 

62 Veresen May 12, 2011 Media release. http://veresen.mediaroom.com/ 

index.php?s=5043&item=38956 

co-owner of the Jordan Cove project, continues to assert that such projects are for 

LNG import. Verseen, however, in May 2011 first acknowledged in a letter to shareholders it was considering LNG export.62 To the extent the actual purpose of 

planned LNG terminals was to facility LNG export, contrary statements to investors 

and the SEC may have violated the federal Securities and Exchange Act and related 

statutes. 15 USC § 77(q); 77(w). Securities and Exchange Act violations carry criminal penalties of up to five years and $10,000. 15 USC § 77(x). Potential violations 

of Oregon’s securities statutes should also be considered if applicable. ORS Chapter 

59. 

E. Violations of the Natural Gas Act’s prohibition against market manipulation 

Misrepresenting plans for LNG export projects as import projects may violate the 

Natural Gas Act’s prohibition against market manipulation given the potential for 

export projects to significantly increase domestic natural gas prices. 15 USC § 

717(c)1; 18 C.F.R. § (1)(c)(1). This anti-manipulation provision was first passed in 

the 2005 Energy Policy Act and carries a maximum criminal penalty of five years 

and $1,000,000 and additional penalties of up to $50,000 a day. 15 USC § 717(t)(1), 

(2). Civil penalties can be up to $ 1 million a day. 15 USC § 717t-1. To prevail it 

would presumably be necessary to show a specific intent to use export as a tool to 

increase natural gas prices. 

CONCLUSION

The potential impacts of LNG export are very real and threaten to squander a 

resource that is both a unique U.S. competitive advantage and offers a chance to 

reduce U.S. dependency on foreign oil and greenhouse gas emissions. There are opportunities, however, for using the unprecedented price increases and potential supply shortages that would result from export to motivate energy consumers to fight 

a concerted effort by gas producers to open large scale U.S. gas exports. This effort 

would be greatly strengthened by the exposure of fraudulent efforts by some of the 

largest U.S. gas players to build the infrastructure for LNG export terminals under 

the guise that they would be used for ‘‘import.’’ 

STATEMENT OF LEE FULLER, VICE PRESIDENT OF GOVERNMENT RELATIONS, INDEPENDENT PETROLEUM ASSOCIATION OF AMERICA

This testimony is submitted to the record for the Senate Energy and Natural Resources Committee hearing examining the role of natural gas in United States’ energy policy on behalf of the Independent Petroleum Association of America (IPAA). 

IPAA represents thousands of independent oil and natural gas explorers and producers, as well as the service and supply industries that support their efforts, which 

will be significantly affected by federal action. Independent producers develop 95 

percent of American oil and natural gas wells, produce 54 percent of American oil 

and produce 85 percent of American natural gas. The average independent has been 

in business for 26 years and employs 12 full-time and three part-time employees. 

In total, America’s onshore independent oil and natural gas producers supported 2.1 

million direct jobs in the United States in 2010. 

American natural gas presents an opportunity for the United States to utilize a 

clean burning, secure and affordable fuel. Projections suggest that identified resources could provide enough natural gas to meet America’s needs based on current 

demand for as much as 100 years. This abundance allows the opportunity for the 

American economy to utilize natural gas in new ways—an expansion of US chemical 

production, greater use of natural gas for electricity generation, natural gas vehicle 

development and exports of liquefied natural gas. The federal government can enhance or impede the development of American natural gas. Two areas that can have 

substantial impact are the regulatory framework for new production and tax policies 

that affect the capital essential to meeting future American natural gas demand. 

This testimony will address these issues. 

Regulation of Hydraulic Fracturing 

The notion that oil and natural gas production generally, and hydraulic fracturing 

in particular, are unregulated flies in the face of reality. The allegation that oil and 

natural gas production is unregulated ignores the long, successful history of statebased regulation of natural gas production. Drilling permitting is grounded in state 

regulatory systems because it involves state land use authority; the federal governVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00156 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
153 

ment has never—nor should it ever—determine the use of lands properly governed 

by state jurisdictions. 

Hydraulic fracturing has been used as a well stimulation technology since the late 

1940s for oil, natural gas, geothermal and water wells that is regulated as a part 

of the drilling permits issued by state regulators. Over the past decade, the combination of horizontal drilling and hydraulic fracturing has allowed industry to 

produce oil and natural gas from shale and tight sands that, previously, was uneconomic to produce. 

Hydraulic fracturing refers to one, temporal step in the oil and natural gas production process. The term hydraulic fracturing has been misconstrued to mean anything related to oil and natural gas development. To be clear, when industry references ‘‘hydraulic fracturing,’’ the industry is referencing the step in the oil and 

natural gas development process that uses water, sand and additives to break apart 

the hydrocarbon bearing formation (i.e. shale) to create permeability and release oil 

and natural gas. 

Regulation of oil and natural gas production depends, largely, on where the oil 

and natural gas production is taking place. The federal government has permitting 

and regulatory authority over production in the Outer Continental Shelf (OCS) and 

on federally managed lands. These regulations are frequently updated. The Bureau 

of Land Management, for example, is currently in the process of promulgating new 

regulations entitled, ‘‘Oil and Gas; Well Stimulation, Including Hydraulic Fracturing, on Federal and Indian Lands.’’ 

Natural gas and oil production on state and private lands are, generally, regulated by state regulatory authorities. The proximity state oil and gas regulators to 

the operations occurring in their respective states, combined with the regulators’ understanding of the unique circumstances in their states, creates the most efficient 

system create for environmentally responsible oil and natural gas development. Additionally, state regulators generally have the technical expertise, resources and capabilities to manage the permitting process. 

State oil and gas regulators, for example, have successfully regulated the process 

of hydraulic fracturing for decades. Fracturing regulations were developed and have 

been implemented by state oil and natural gas regulatory agencies through well construction and completion requirements. These regulations have effectively managed 

the limited environmental risks of the fracturing process. Over the 60 plus years 

since the earliest use of hydraulic fracturing, there have been no incidents related 

to the fracturing process that suggests the existence of a systemic environmental 

management problem. 

Responsible, common-sense regulations on development are a foundation of the oil 

and natural gas industry’s operations—and rightly so. Protecting the environment 

and developing our resources must go hand-in-hand. Today, the oil and natural gas 

industry is regulated by both state and federal environmental agencies. However, 

uniform federal standards that usurp longstanding, state regulatory authority are 

not the answer. In fact, most federal environmental laws create a broad, overarching 

federal framework that delegates to the states the responsibility of creating the specific regulations—regulations that reflect the realities that circumstances differ in 

each state are require different approaches. 

These federal environmental laws apply regardless of whether natural gas and oil 

production are occurring on federal, state or private lands. Moreover, because most 

federal environmental laws are drafted using a manufacturing facility as a model 

for the regulatory framework, these laws have provisions that reflect industries that 

do not fit that model including forestry, agriculture, mining and oil and natural gas 

production. Uniformity is simply a flawed concept for regulation. Examples of environmental laws adopting a broad framework but delegating implementation to state 

regulatory agencies, including the Clean Air Act, Clean Water Act, Safe Drinking 

Water Act and others. IPAA has enclosed legal analysis of applicable federal environmental laws to the upstream oil and natural gas industry. 

Despite the numerous federal and state regulations applicable to the oil and natural gas production process, fossil fuel opponents frequently posit the need to create 

federal, baseline regulations for hydraulic fracturing without any evidence that the 

current regulatory approach is inadequate. 

To the contrary, federal officials, state regulators, and independent experts have 

publicly stated that shale development—including hydraulic fracturing—does not 

pose ‘‘substantial’’ risks. 

• Interior Secretary Ken Salazar: Responding to what he deemed ‘‘hysteria’’ about 

hydraulic fracturing, Salazar said the process ‘‘can be done safely and has been 

done safely hundreds of thousands of times.’’ (Feb. 2012) 

154 

• EPA Administrator Lisa Jackson: ‘‘In no case have we made a definitive determination that the [fracturing] process has caused chemicals to enter groundwater.’’ (April 2012) Jackson also has said: ‘‘I’m not aware of any proven case 

where [hydraulic fracturing] itself has affected water.’’ (May 2011) • U.S. EPA: ‘‘EPA did not find confirmed evidence that drinking water wells have 

been contaminated by hydraulic fracturing fluid injection . . . ’’ (2004) • Former EPA Administrator Carol Browner: ‘‘There is no evidence that the hydraulic fracturing at issue has resulted in any contamination or endangerment 

of underground sources of drinking water.’’ (May 1995) • U.S. Dept. of Energy and Ground Water Protection Council: ‘‘[B]ased on over 

sixty years of practical application and a lack of evidence to the contrary, there 

is nothing to indicate that when coupled with appropriate well construction; the 

practice of hydraulic fracturing in deep formations endangers ground water. 

There is also a lack of demonstrated evidence that hydraulic fracturing conducted in many shallower formations presents a substantial risk of 

endangerment to ground water.’’ (May 2009) • CardnoEntrix (Inglewood Oil Field Study): ‘‘Before-and-after monitoring of 

groundwater quality in monitor wells did not show impacts from high-volume 

hydraulic fracturing and high-rate gravel packing.’’ (October 2012) • Center for Rural Pennsylvania: ‘‘[S]tatistical analyses of post-drilling versus 

pre-drilling water chemistry did not suggest major influences from gas well 

drilling or hydrofracturing (fracking) on nearby water wells . . . ’’ (Oct. 2011) • John Hanger, Former Pa. DEP Secretary: ‘‘We’ve never had one case of fracking 

fluid going down the gas well and coming back up and contaminating someone’s 

water well.’’ (2012) • Dr. Stephen Holditch, Department of Petroleum Engineering, Texas A&M University; member of Natural Gas Subcommittee of the Secretary of Energy Advisory Board: ‘‘I have been working in hydraulic fracturing for 40+ years and 

there is absolutely no evidence hydraulic fractures can grow from miles below 

the surface to the fresh water aquifers.’’ (October 2011) • Dr. Mark Zoback, Professor of Geophysics, Stanford University: ‘‘Fracturing 

fluids have not contaminated any water supply and with that much distance to 

an aquifer, it is very unlikely they could.’’ (August 2011) 

Despite this consistent experience showing effective regulation, the Obama Administration has sought to encroach upon the progress of even state and private 

land development through instructions to virtually every agency to find opportunities to federalize the regulation of oil and natural gas production, particularly hydraulic fracturing—the very technology that has unlocked the oil and natural gas 

reserves from shale. In the spring of 2012, there were no less than 11 federal agencies trying to find ways to regulation hydraulic fracturing. Since there has been no 

evidence of hydraulic fracturing contaminating groundwater or suggestions that systemic regulatory failure exists in the current regulatory framework, IPAA would encourage Members of the Committee to oppose any new federal regulations on the 

oil and natural gas industry to allow America’s oil and natural gas producers to create jobs and the energy to power the American economy. 

Tax Policy 

Federal tax policy has historically played a substantial role in developing America’s natural gas and petroleum. Early on, after the creation of the federal income 

tax, the treatment of costs associated with the exploration and development of this 

critical national resource helped attract capital and retain it in this inherently capital intensive and risky business. Allowing the expensing of intangible drilling and 

development costs and percentage depletion rates of 27.5 percent are examples of 

such policy decisions that resulted in the United States extensive development of 

its petroleum. 

But, the converse is equally true. By 1969, the depletion rate was reduced and 

later eliminated for all producers except independents. However, even for independents, the rate was dropped to 15 percent and allowed for only the first 1000 barrels 

per day of petroleum produced. A higher rate is allowed for marginal wells which 

increases as the petroleum price drops, but even this is constrained—in the underlying code—by net income limitations and net taxable income limits. In the Windfall 

Profits Tax, federal tax policy extracted some $44 billion from the industry that 

could have otherwise been invested in more production. Then, in 1986 as the industry was trying to recover from the last long petroleum price drop before the 1998- 

99 crisis, federal tax policy was changed to create the Alternative Minimum Tax 

that sucked millions more dollars from the exploration and production of petroleum 

and natural gas. These changes have discouraged capital from flowing toward this 

industry. 

155 

Independent producers historically reinvest over 100 percent of American oil and 

natural gas cash flow back into new American production. 

The Obama Administration’s budget request—and recurring advocacy statements 

on an almost daily basis—would strip essential capital from new American natural 

gas and oil investment by radically raising taxes on American production. American 

natural gas and oil production would be reduced. It runs counter to the Administration’s clean energy and energy security objectives. The following is a review of some 

of the Obama Administration proposed changes to natural gas and oil taxation. 

Intangible Drilling and Development Costs (IDC)—Expensing IDC has been part 

of the tax code since 1913. IDC generally include any cost incurred that has no salvage value and is necessary for the drilling of wells or the preparation of wells for 

the production of natural gas or oil. Only independent producers can fully expense 

IDC on American production. Loss of IDC for independent producers will have significant effects on their capital development budgets. A Raymond James analysis in 

2009 reported that the loss of IDC would result in capital drilling budgets being reduced by 25 to 30 percent. This compares with information provided to IPAA by its 

members indicating that drilling budgets would be cut by 25 to 40 percent. Regardless of the exactness of the assessments, clearly, the consequences would be significant. And, the consequences would soon be evident. Roughly half of America’s current natural gas production is provided by wells developed during the past four 

years. 

Percentage Depletion—All natural resources minerals are eligible for a percentage 

depletion income tax deduction. Percentage depletion for natural gas and oil has 

been in the tax code since 1926 after Congress determined that relying solely on 

cost depletion was leading to the loss of important American mineral resources. Unlike percentage depletion for all other resources, natural gas and oil percentage depletion is highly limited. It is available only for American production, only available 

to independent producers and for royalty owners, only available for the first 1000 

barrels per day (6000 mcfd of natural gas) of production, limited to the net income 

of a property and limited to 65 percent of the producer’s net income. Percentage depletion provides capital primarily for smaller independents and is particularly important for marginal well operators. These wells—that account for 20 percent of 

American oil and 12-13 percent of American natural gas—are the most vulnerable 

economically. Input to IPAA from its operators who take percentage depletion indicates that the combined effect of the Obama Administration proposals on IDC and 

percentage depletion would reduce drilling budgets in half. At this lower rate, new 

production will not offset the natural decline in production from existing wells. For 

example, one producer now drills ten wells per year; without IDC and percentage 

depletion, this producer could only drill five wells per year. A five well program will 

not replace declining production in existing wells and the small business company 

will have to shutdown. Congress’ choice is straightforward: reduce American oil production by 20 percent and its natural gas production by 12 percent or retain the 

current historic tax policies that have encouraged American production. 

Passive Loss Exception for Working Interests in Oil and Gas Properties—The Tax 

Reform Act of 1986 divided investment income/expense into two baskets—active and 

passive. The Tax Reform Act exempted working interests in natural gas and oil 

from being part of the passive income basket and, if a loss resulted (from expenditures for drilling wells), it was deemed to be an active loss that could be used to 

offset active income as long as the investor’s liabilities were not limited. Natural gas 

and oil development require large sums of capital and producers frequently join together to diversify risk. Additionally, natural gas and oil operators have sought individual investors to contribute capital and share the risk of drilling wells. Most 

American wells today are drilled by small and independent companies, many of 

which depend on individual investors. There is no sound reason for Congress to 

enact tax rules that would discourage individual investors from continuing to participate in this system. Moreover, Congress applied the passive loss rules only to 

individuals and not to corporations. The repeal of the working interest rule, therefore, would senselessly drive natural gas and oil investments away from individuals 

and toward corporations. There is no apparent reason why Congress would or 

should favor corporate ownership over individual ownership of working interests. 

Furthermore, since AMT restrictions apply to IDC of individual working interest investors, the application of the passive loss rules to those investors is unnecessary 

and excessive. In sum, to qualify for the exception, the taxpayer must have liability 

exposure and definitely be at risk for any losses. If income/loss, arising from natural 

gas and oil working interests, is treated as passive income/loss, the primary income 

tax incentive for taxpayers to risk an investment in natural gas and oil development 

would be significantly diminished. In today’s banking climate, smaller producers 

find banks uninterested or incapable of providing capital; taking private investors 

156 

away will further exacerbate the challenge of raising capital to sustain American 

marginal well production. 

Geological and Geophysical (G&G) Amortization—G&G costs are associated with 

developing new American natural gas and oil resources. For decades, they were expensed until a tax court case concluded that they should be amortized over the life 

of the well. After years of consideration and constrained by budget impacts, in 2005, 

Congress set the amortization period at two years. It also simplified G&G amortization by applying the two year amortization to failed as well as successful wells; previously, failed wells could be expensed. Later, Congress extended the amortization 

period to five years for large major integrated oil companies and then extended the 

period to seven years. Early recovery of G&G costs allows for more investment in 

finding new resources. Congress recognized that America benefitted if capital used 

to explore for new natural gas and oil could be quickly reinvested in more exploration or production of American resources, it was in the national interest. Nothing 

has changed to alter that conclusion. If anything, current capital and credit limitations enhance the rationale to get these funds back into new investment. 

Marginal Well Tax Credit—This countercyclical tax credit was recommended by 

the National Petroleum Council in 1994 to create a safety net for marginal wells 

during periods of low prices. These wells as stated above account for 20 percent of 

American oil and 12 percent of American natural gas. They are the most vulnerable 

to shutting down forever when prices fall to low levels. Congress enacted in this 

countercyclical tax credit in 2004 after ten years of consideration. It concluded that 

the nation benefitted if these marginal operations were supported during times of 

low prices, that the production from these wells were—in effect—a national resource 

reserve that would be lost forever if the wells had to be shutdown and plugged during difficult economic times. No different conclusion is now warranted. A year ago, 

as America faced high energy prices, the clear risk of foreign energy dependency 

was all too evident; America’s marginal wells are a first defense against more foreign imports. Fortunately, to date, the marginal well tax credit has not been needed, 

but it remains a key element of support for American production—and American energy security. 

Enhanced Oil Recovery (EOR) Tax Credit—The EOR credit is designed to encourage oil production using costly technologies that are required after a well passes 

through its initial phase of production. Conventional oil well production declines 

regularly after it begins production. However, millions of barrels of oil remain in formations when the initial production phase is over. The 2001 National Energy Report 

indicated that ‘‘anywhere from 30 to 70 percent of oil, and 10 to 20 percent of natural gas, is not recovered in field development. It is estimated that enhanced oil recovery projects, including development of new recovery techniques, could add about 

60 billion barrels of oil nationwide through increased use of existing fields.’’ For example, one of the technologies is the use of carbon dioxide as an injectant. In 2006, 

the Department of Energy studied the potential for using carbon dioxide enhanced 

oil recovery (CO2-EOR) and concluded that: ‘‘Ten basin-oriented assessments- four 

new, three updated and three previously released- estimate that 89 billion barrels 

of additional oil from currently ‘stranded’ oil resources in ten U.S. regions could be 

technically recoverable by applying state-of-the-art CO2-EOR technologies.’’ Given 

the increased interest in carbon capture and sequestration, CO2-EOR offers the potential to sequester the carbon dioxide while increasing American oil production. 

Currently, the oil price threshold for the EOR tax credit has been exceeded and the 

oil value is considered adequate to justify the EOR efforts. However, at lower prices 

EOR becomes uneconomic and these costly wells would be shutdown. The EOR tax 

credit was enacted in 1990 and provides the potential to maintain important US oil 

production by supporting the development of these wells in low price periods. 

The Administration justifies its proposals based on two flawed rationales. First, 

the provision ‘‘... like other oil and gas preferences the Administration proposes 

to repeal, distorts markets by encouraging more investment in the oil and gas industry than would occur under a neutral system.’’ Second, to the extent that the 

provision ‘‘... encourages overproduction of oil, it is detrimental to long-term energy security and is also inconsistent with the Administration’s policy of reducing 

carbon emissions and encouraging the use of renewable energy sources through a 

cap-and-trade program.’’ 

157 

The Administration’s second rationale is similarly irrational. Production of American oil and natural gas serves the nation’s goal of improving its energy security. 

Production of American oil and natural gas has been regulated to assure that wells 

are limited to volumes that conserve the long term production of its reservoir. These 

limitations have been entrenched since the mid-1930s. Current production reflects 

the need for American production to be maximized and nothing suggests that it 

should not be. Similarly, the Administration’s climate goals of reducing carbon emissions and encouraging the use of renewable energy sources are enhanced by American natural gas and oil production. Natural gas is a clean, abundant, affordable 

and American resource that must be a part of any climate initiative. Oil will continue to be a key component of America’s energy supply for the foreseeable future 

and any policies should rely first on American oil rather than foreign sources. 

Conclusion 

As the Committee considers policies related to America’s natural gas resources, 

it must recognize that federal actions can dramatically affect the future of the nation’s energy security and the nation’s ability to meet the potential for its economic 

growth. IPAA urges the Committee to support those actions that enhance that fuVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00161 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132

fuller.eps
158 

1 42 U.S.C. §§ 11001-11050. 

2 H. R. Rep. No. 99-962 at 281 (1986), reprinted in 1986 U.S.C.C.A.N. 3276, 3374. 

3See, e.g., 132 Cong. Rec. H9595 (Oct. 8, 1986) (statement of Rep. Edgar) (‘‘my concerns rest 

with the families that live in the shadow of these chemical and manufacturing plants’’). 4 42 U.S.C. § 11023. 

ture and reject the ill-advised calls for adverse restrictions to capital and unnecessary federal regulation of production. 

ENCLOSURES—TOXIC RELEASE INVENTORY 

The federal Emergency Planning and Community Right-to-Know Act (EPCRA)1

was enacted by Congress as Title III to the Superfund Amendments and Reauthorization Act of 1986. Adopted in response to several highly-visible chemical incidents, 

EPCRA primarily addresses two key issues: (1) support for emergency planning to 

respond to chemical accidents, and (2) ‘‘provid[ing] the public with important information on hazardous chemicals in their communities.’’2 In order to achieve its first 

goal, EPCRA sets up a broad, comprehensive framework for emergency planning at 

the state and local levels. For example, EPCRA requires that owners or operators 

of facilities at which hazardous chemicals are present to provide information contained in the Material Safety Data Sheets (MSDSs) for these chemicals to various 

state and local authorities. These MSDSs provide a variety of information concerning chemical products, including information on product composition, the physical and chemical properties of the product, potential health hazards and toxicity information, and first aid information and other steps to take in the event of a spill 

of the product. Addressing its second goal, EPCRA specifically focuses on major 

chemical and other industrial facilities—those categorized as falling within Standard Industrial Classification (SIC) Codes 20 to 39 (covering only manufacturing operations such as chemical manufacturing, automobile manufacturing, etc.)—and requires these facilities to report annually to the U.S. Environmental Protection Agency (EPA) regarding various releases of specified hazardous chemicals, a form of reporting that is commonly referred to as ‘‘Toxic Release Inventory’’ or ‘‘TRI’’ reporting. 

EPCRA was specifically enacted in response to the tragic incident in Bhopal, India 

and to domestic chemical release incidents such as one that had occurred in Institute, West Virginia. These incidents resulted from the atmospheric release of chemicals from large chemical manufacturing plants into the surrounding community, 

raising concerns about the risks posed by these releases from large industrial facilities.3 Based on these incidents, in enacting the TRI provisions in Section 313 of 

EPCRA4 Congress specifically focused on the types of facilities that created these 

risks—large chemical production plants and other types of concentrated industrial 

operations using significant volumes of hazardous chemicals, particularly where the 

facilities are located in urban environments or other population centers. Given this 

approach, Congress limited the EPCRA Section 313 reporting requirements only to 

those facilities that have the equivalent of at least 10 full-time employees, are classified as being in an industry that has an SIC Code of 20 to 39 (i.e., most manufacturing facilities), and have manufactured, imported or processed more than 25,000 

pounds of any covered toxic chemical or ‘‘otherwise used’’ more than 10,000 pounds 

of any such chemical. 

CONGRESS DID NOT INTEND TO REGULATE OIL AND NATURAL GAS EXPLORATION AND

PRODUCTION UNDER THE TRI PROGRAM

Congress made a conscious decision in enacting the TRI provisions of EPCRA in 

1986 to focus on the types of large manufacturing facilities that were believed to 

be creating risks to individuals who live in the neighborhoods in the vicinity of such 

facilities. In adopting this approach, Congress chose not to impose TRI reporting requirements on a wide range of other types of commercial and industrial operations, 

including but certainly not limited to facilities involved in the exploration and production of oil and natural gas. For example, residential and commercial construction, transportation services, and agricultural operations as well as other types of 

decentralized operations were also specifically excluded from the scope of the TRI 

reporting requirements as a result of the congressional deliberations. 

Oil and natural gas exploration and production operations in particular differ in 

key respects from the types of manufacturing operations on which Congress chose 

to impose TRI reporting obligations. The industrial operations covered by SIC Codes 

20-39 which were made subject to TRI reporting—including not only chemical manufacturers themselves but also manufacturing operations that use chemicals, such 

as motor vehicle, ship, railroad car and aircraft manufacturers, manufacturers of 

159 

5See 62 Fed. Reg. 23834 (May 1, 1997). 

6 61 Fed. Reg. 33588, 33592 (June 27, 1996). 

electronics and other types of consumer products and industrial equipment, manufacturers of materials such as steel, plastics and cement and even manufacturers 

of clothing—typically involve manufacturing processes in large, centralized facilities. 

These facilities often use or produce significant quantities of chemicals on a consistent, long-term basis and consequently store substantial quantities of chemicals 

as a routine matter. At the same time, these manufacturing facilities are often located in urbanized environments with many residences surrounding or in close proximity to the manufacturing plant. It was these specific types of circumstances, for 

example, that resulted in thousands of nearby residents being exposed to the chemicals accidentally released from the chemical manufacturing facility in Bhopal. 

In contrast to these concentrated manufacturing operations, oil and natural gas 

exploration and production facilities are generally widely scattered. Well pads are 

spread out through many areas of the country, with hundreds or thousands of feet 

separating individual well pads even in those areas with substantial exploration and 

production activity. In addition, these facilities are generally found in rural environments, with few if any individuals residing in the vicinity of a well pad itself. In 

fact, many well pads are located in isolated areas far from any residential areas. 

At the same time, the operations at an individual well pad typically use very limited 

amounts of chemicals and many uses of chemicals—such as for hydraulic fracturing 

and other stimulation operations—are indeed very short-term. As a result operations at individual well pads do not at all create the types of significant risks associated with the use of chemicals that are specifically posed by large manufacturing 

operations. Consequently, there is no indication that Congress ever intended that 

highly decentralized operations such as oil and natural gas exploration and production facilities were to be subject to TRI reporting requirements. 

Moreover, when it first enacted EPCRA Congress gave EPA the authority to revisit the scope of the TRI reporting when necessary and to add to the categories 

of facilities that must file TRI reports if the Agency deemed it appropriate. Nevertheless, even when EPA subsequently decided to expand the scope of the types of 

facilities that must comply with TRI reporting obligations, the Agency again decided 

not to include oil and natural gas exploration and production facilities within the 

scope of this program. In exercising its authority, EPA added categories of facilities 

only when it found that these plants engaged in types of activities which are similar 

to or related to the activities conducted at the facilities within the manufacturing 

sector. 

Consistent with this congressionally-directed approach, EPA has only added 

through the years such categories as petroleum bulk terminals, wholesaling of 

chemicals and related products, metal mining, facilities engaged in the processing 

(but not the extraction) of coal, solvent recovery services and hazardous waste treatment facilities to the industry sectors required to submit TRI reports;5 however, 

EPA has specifically rejected adding oil and natural gas exploration and production 

facilities to the list of industry sectors required to comply with TRI reporting requirements. In justifying this action, EPA stated that ‘‘[t]his industry group is 

unique in that it may have related activities located over significantly large geographic areas.’’6 EPA even noted that for individual well sites, operations probably 

would not have exceeded the thresholds established in the Act with respect to the 

minimum number of employees a particular facility must have and the amounts of 

chemicals it must use in order to be subject to the TRI requirements in the first 

place. Thus, EPA found no compelling need to require oil and natural gas exploration and production facilities to submit TRI reports, and in fact identified significant concerns that might have arisen if it had decided otherwise. 

TRI REPORTING WOULD BE BURDENSOME FOR OIL AND NATURAL GAS EXPLORATION AND

PRODUCTION FACILITIES AND WOULD NOT YIELD SIGNIFICANT BENEFITS

If oil and natural gas exploration and production facilities were to be subject to 

TRI reporting, such requirements would be unnecessarily burdensome, the usefulness of the data generated by such reporting would not justify the costs and those 

costs, taken together with other regulatory burdens, would severely affect the production of American oil and natural gas. 

According to its recent analysis of reporting burdens associated with TRI reporting, the Agency has estimated that facilities that are subject to TRI reporting will 

spend an average of 48 man hours and over $2400 for each ‘‘Form R’’ report that 

160 

7 EPA, Toxic Release Inventory, TRI Form R Toxic Chemical Release Reporting, Information 

Collection Request Supporting Statement, EPA ICR No. 1363.15 at 24 (Dec. 10, 2007 8 ICR Supporting Statement at 41. 

1 33 U.S.C. §§ 1251–1387. 

must be submitted to EPA.7 Imposing these types of reporting burdens on operations at individual well sites could result in substantial cumulative burdens for 

well operators, many of whom would have to prepare dozens or even hundreds of 

such reports (if they were eventually subjected to these reporting obligations) because of the number of individual wells they operate and the highly decentralized 

nature of the operations. These burdens would in turn substantially impede the 

ability of oil and natural gas operators to produce adequate supplies of American 

energy at affordable prices. Moreover, these reports would only provide minimal 

benefit in light of the fact the fact that few if any residents would ever be exposed 

to any releases of chemicals from many well sites. 

At the same time, the imposition of such reporting requirements on oil and natural gas exploration and production facilities could also place substantial administrative burdens on EPA itself and on the TRI program generally. EPA currently estimates that approximately 30,000 facilities throughout the country are subject to 

TRI reporting requirements and will file a total of about 77,000 reporting forms.8

In contrast, there are over 933,000 operating well sites across the country—if any 

significant portion of these well sites were to become subject to TRI reporting, it 

would obviously result in a dramatic increase in the number of reports submitted 

to the Agency and could potentially overwhelm the system with information about 

facilities that pose little risk of the type that EPCRA was designed to address in 

the first place, thereby undermining EPA’s ability to focus its attention and resources on the types of facilities that Congress actually intended to cover—those 

that pose a potential risk to significant populations. 

CONCLUSION

In short, Congress intended EPCRA to meet two principal objectives—namely, 

first to provide chemical information for emergency planning and response to key 

state and local governmental agencies, and second to focus on large centralized 

manufacturing operations and facilities to obtain information on releases to the environment. Oil and natural gas exploration and production activities differ from 

those types of manufacturing operations that are subject to TRI reporting obligations in several key respects. First, in contrast to these manufacturing facilities, oil 

and natural gas exploration operations are widely scattered and relatively small in 

scale. Moreover, these operations are generally not undertaken near large, urban 

centers in the U.S. Thus, the decision of Congress not to include oil and natural gas 

exploration and production activities within the universe of facilities subject to TRI 

requirements was wholly consistent with congressional intent. Indeed, many other 

commercial and industrial sectors were likewise excluded from TRI coverage. In addition, EPA has chosen not to add oil and natural gas exploration and production 

activities to the universe of facilities required to comply with TRI reporting obligations because there is no compelling reason to impose new reporting burdens that 

would provide no significant benefit and that would only serve to drive up the cost 

of oil and natural gas production. 

ENCLOSURE—CLEAN WATER ACT 

Congress passed the Federal Water Pollution Control Act Amendments of 1972 to 

address pollution of the nation’s rivers, lakes, streams and ocean waters, with the 

ultimate goal of eliminating all discharges of pollutants into those waters.1 Commonly referred to as the federal Clean Water Act (CWA), this federal water pollution law is aimed at achieving the national goal of making our nation’s waters safe 

for swimming and fishing. To achieve these objectives, the CWA regulates the discharges of pollutants into the ‘‘waters of the United States’’ from municipal, industrial and other sources (e.g., persons filling wetlands or concentrated animal feeding 

operations such as feedlots). The Act also includes provisions that are designed to 

prevent spills of oil and hazardous substances from entering and contaminating national waterways and that assign liability for cleaning up spills that do occur. 

As a key part of this overall framework, the CWA authorized the implementation 

of the National Pollutant Discharge Elimination System (NPDES) program, which 

established a system for the issuance of permits to control discharges of pollutants 

into the navigable waters and their tributaries from wastewater treatment plants, 

industrial facilities and other ‘‘point sources.’’ These permits establish limits on the 

amounts of pollutants that a facility may have in the wastewater it discharges to 

161 

2 33 U.S.C. § 1342(l)(2). 

3 H.R. Rep. No. 99-189, at 37 (1985). 

a stream, river, lake or other regulated surface water and set forth permit conditions that require monitoring of discharges and reporting to the appropriate permitting authority. The authority to issue these NPDES permits has largely been delegated to the states, most of which have developed their own wastewater discharge 

permitting programs. 

At the same time, the CWA established a system for addressing spills of oil and 

hazardous substances that is largely implemented by the federal government 

through the U.S. Environmental Protection Agency (EPA) and other agencies such 

as the U.S. Coast Guard. The CWA prohibits the discharge of harmful quantities 

of oil or hazardous substances into or on U.S. surface waters or adjoining shorelines 

and imposes liability for any spill that contaminates these surface waters on the 

owner and operator of the vessel or on-shore facility that was the source of the spill. 

The Act also requires that the owners and operators of vessels and facilities from 

which oil or hazardous substances could be spilled in harmful quantities prepare 

plans—known as Spill Prevention, Control and Countermeasure (SPCC) Plans—for 

preventing these types of spills and outlining measures that are to be taken if a 

spill does occur. 

Oil and natural gas exploration and production operations are subject to regulation under the Clean Water Act in various ways. Among other things, any discharges of wastewaters such as produced waters from well sites to navigable waters 

or their tributaries are fully subject to the NPDES permit requirements under the 

CWA. In addition, stormwater runoff from a well site that contains pollutants is 

subject to the same permitting requirements that are imposed on stormwater discharges from various industrial facilities under the CWA. Moreover, oil and natural 

gas exploration and production facilities are fully subject to the spill requirements 

of the CWA, including the need to prepare SPCC plans to minimize any potential 

for spills that could harm nearby waters. 

THE EXEMPTION FROM STORMWATER PERMITTING REQUIREMENTS FOR OIL AND

NATURAL GAS EXPLORATION IS QUITE LIMITED

In adopting the CWA, Congress has at various times considered how the provisions of the Act should apply to oil and natural gas exploration and production activities in light of the unique circumstances of well sites so as not to unnecessarily 

impede vital energy production. For example, in fashioning the scope of the 

stormwater permit program included in the CWA in 1987, Congress specifically considered how these new permitting requirements should specifically apply to 

stormwater runoff from oil and natural gas exploration and production facilities.2

Following its review Congress determined that it was appropriate to provide a limited exemption from stormwater permitting requirements for oil and natural gas exploration and production sites because of their unique nature. This exemption applies only in those specific situations where the stormwater runoff is not contaminated by and does not come into contact with raw materials, intermediate or finished products, byproducts or waste products in the first place. Thus, if the 

stormwater runoff from an oil or natural gas well site is contaminated with materials such as oil, grease or hazardous substances, the operator of the well site is not 

exempt from the regulations under the CWA and must still obtain permit coverage 

from EPA or from the appropriate state permitting authority under the NPDES program. 

In enacting this limited permitting exemption, Congress recognized that oil and 

natural gas operators were already taking the proper steps to control stormwater 

runoff from well sites and other facilities. Congress also recognized that if such runoff was uncontaminated there was little more to be gained by requiring operators 

to incur the costs and potential delays of obtaining a new burdensome permit. 

Therefore, the congressional committee responsible for fashioning the stormwater 

permit program concluded that: 

to avoid penalizing operators for using good management practices designed to prevent or minimize pollution and for making expenditures to prevent stormwater run-off contamination, uncontaminated stormwater diversion devices should not be regulated under the permit scheme of the Act.3

162 

4 133 Cong. Rec. H171 (daily ed. Jan. 8, 1987) (statement of Rep. Hammerschmidt). 

5 71 Fed. Reg. at 33633. 

Consequently, ‘‘[w]ith this limitation on the permitting requirements for such 

stormwater runoff, important oil [and] gas... operations will be able to continue 

without unnecessary paperwork restrictions . . . .’’4

At the same time, decided in 1987 to extend these stormwater permitting requirements in general to construction projects. EPA initially determined that these 

stormwater permitting requirements should apply to construction projects that disturb more than five acres. Moreover, EPA also determined that oil and natural gas 

well sites being prepared for drilling should be treated as construction sites and not 

as oil and natural gas sites subject to the limited exemption from stormwater permitting requirements. Even after EPA eventually lowered the threshold for the applicability of the stormwater permitting requirements to construction activities from 

five acres to one acre in response to litigation, the Agency believed that relatively 

few oil and natural gas sites that were being developed would fall under the NPDES 

stormwater permitting requirements. However, it eventually became clear that this 

fundamental assumption was entirely wrong—in fact, members of the oil and natural gas industry subsequently made EPA aware that close to 30,000 oil and natural 

gas sites annually could be subject to stormwater permitting under EPA’s interpretation. Given this key information, EPA decided to reassess whether thousands of 

oil and natural gas sites that were just being prepared for drilling should indeed 

be subject to the burdens of the NPDES stormwater permitting program. 

This issue was eventually resolved by Congress in the Energy Policy Act of 2005 

(‘‘EPAct’’). In light of the significant implications of any permitting requirements for 

energy production, Congress clarified in the EPAct that the limited exemption from 

stormwater permitting requirements for oil and natural gas exploration and production operations originally included in the 1987 amendments to the CWA should indeed extend to construction-related activities at oil and natural gas sites, including 

activities that are necessary to prepare a site for drilling for oil or natural gas. 

In taking this action, Congress rejected the notion that there should be different 

standards applied for oil and natural gas construction sites and simply subjected the 

process of preparing oil and natural gas sites for drilling to the same standards for 

stormwater permitting that already apply once drilling and production commence. 

In doing so, Congress continued to provide an exemption from permitting requirements that is limited in scope, i.e., again if stormwater runoff from sites being prepared for drilling is contaminated with pollutants such as oil or hazardous substances, the permitting exemption does not apply and the operator is still required 

to obtain permit coverage for such discharges. It is only when the stormwater runoff 

from oil and natural gas sites—including runoff associated with construction activities at these sites—is uncontaminated that operators are exempt from permitting 

requirements. Under these circumstances, a requirement that an operator obtain 

permit coverage would serve little purpose other than imposing unnecessary and unjustified regulatory burdens—and the associated costs—on oil and natural gas exploration and production and would only serve to unreasonably impede the development of American energy supplies. 

Even with this limited exemption, there are still many layers of other effective 

controls currently in place which act to ensure that stormwater flows off of oil and 

natural gas sites do not adversely affect human health and the environment. One 

layer of control is the standard management practices already adopted by the oil 

and natural gas industry itself to control stormwater runoff. In fact, EPA has readily acknowledged that the oil and natural gas industry has already implemented effective practices to prevent soil erosion and runoff associated with the preparation 

of sites for drilling and other construction activities. The Agency has stated that 

these industry practices ‘‘result in practical, cost-effective approaches that are flexible enough to address the variety of situations and water quality concerns that 

might be encountered in the field.’’5

At the same time, states still retain their inherent governmental powers to exercise regulatory controls should they become concerned about the impact of sediment 

or other discharges from oil and natural gas site operations. In fact, many states 

with active oil and natural gas exploration and production activity already have requirements in place independent of their NPDES programs to effectively address 

sediment and erosion control at oil and natural gas sites. For example, the State 

of West Virginia requires the use of BMPs at sites being prepared for drilling activity consistent with the erosion and sediment control field manual issued by the Office of Oil and Gas of the West Virginia Department of Environmental Protection. 

These requirements have proven to be very effective and efficient in ensuring that 

any concerns about sediment deposition are properly addressed. These state proVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00166 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
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1 42 U.S.C. §§ 4321–4347. 

grams are consistent with the national policy set forth in the CWA of preserving 

the primary responsibilities and rights of the states to prevent, reduce and eliminate pollution and to plan the development and use of land and serve to supplement 

the federal permitting programs already in place. 

SPCC REGULATION

EPA has likewise considered how to apply various other provisions of the CWA 

to oil and natural gas exploration and production activities. For example, in promulgating regulations for the SPCC program, EPA has only taken very limited actions 

to accommodate the unique circumstances of well sites. As noted above, oil and natural gas production facilities are subject to the oil spill provisions of the CWA and 

operators of well sites must therefore prepare SPCC plans for their well sites if they 

meet the same criteria that apply to all facilities, i.e., more than a specified amount 

of oil can be stored on the site and if spilled the oil could enter a surface water in 

harmful quantities. The SPCC plan must specify operating procedures that the facility uses to prevent oil spills as well as control measures to prevent any oil spill from 

reaching nearby waters and measures to contain and clean up any spill that does 

reach nearby waters or their shorelines. Like the owners and operators of other 

types of facilities that are subject to these oil spill requirements, operators of well 

sites must report spills of oil to the proper authorities and are responsible for cleaning up and restoring the affected area in the event of a spill. 

However, when EPA amended its SPCC regulations in 2002, it imposed requirements on oil and natural gas exploration and production facilities that were subsequently found to be unduly restrictive and burdensome. Accordingly, as part of its 

revisions to the SPCC regulations in 2008, EPA modified certain requirements applicable to well sites to provide the operators of these sites with greater flexibility 

in meeting the regulatory requirements while continuing to balance the need to ensure that that the potential for any spills of oil or hazardous substances from well 

sites that may reach navigable waters is appropriately minimized against the unnecessary burdens imposed by new regulations on the production of American oil 

and natural gas resources. These amendments remain subject to public comment 

and may be further revised before they are finalized. 

CONCLUSION

As can be seen, oil and natural gas exploration and production activities are subject to key regulatory requirements imposed by the CWA. However, both Congress 

and EPA have taken reasonable steps to minimize unnecessary burdens on oil and 

natural gas production without compromising substantive environmental protection. 

The congressional action in the EPAct extending the limited NPDES stormwater 

permitting exemption to cover drilling and construction-related activities was not an 

attempt to provide special treatment for oil and natural gas sites; rather, it was an 

effort to clear up the unnecessary confusion and make sure that these activities 

were subject to the same standards that already apply to oil and natural gas operations themselves. This congressional action did not expand any permitting exemptions for these operations and the NPDES permitting exemption continues to remain limited in scope and apply only where stormwater runoff is not contaminated, 

just as was the case before the passage of the EPAct. Likewise, well sites remain 

subject to the oil spill provisions of the SPCC and recent EPA amendments to the 

SPCC regulations simply represent an effort to minimize the impacts of these regulations on oil and natural gas production without limiting critical environmental 

protections for the nation’s waters. 

ENCLOSURE—NATIONAL ENVIRONMENTAL POLICY ACT 

The National Environmental Policy Act (NEPA)1 was enacted on January 1, 1970 

in order to establish a national environmental policy to be implemented by all federal agencies across the government. Viewed as a landmark piece of legislation, 

NEPA was enacted in order to: (1) formally declare a national policy which will encourage productive and enjoyable harmony between man and his environment; (2) 

to promote efforts which will prevent or eliminate damage to the environment and 

biosphere and stimulate the health and welfare of man; and (3) to enrich the understanding of the ecological systems and natural resources important to the nation. 

NEPA imposes a number of key requirements on federal governmental agencies 

in order to achieve these goals. For example, as a general matter, the federal government is required to use all practicable means to preserve and maintain condiVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00167 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
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tions under which human beings can coexist with the natural world in productive 

harmony. In addition, federal agencies are specifically required to lend appropriate 

support to initiatives and programs meant to prevent the degradation of the environment, as well as to directly incorporate environmental considerations in their decision making, using a systematic, interdisciplinary approach. 

Perhaps the most significant element of NEPA is the requirement that federal 

agencies prepare an environmental impact statement (EIS) for those actions which 

are classified as ‘‘major federal actions that will significantly affect the quality of 

the human environment.’’ An EIS is an in-depth analysis, often several hundred 

pages in length, of the potential environmental impacts associated with a federal 

action. The EIS also examines alternatives to the proposed action and the environmental impacts of those alternatives. This requirement concerning the preparation 

of an EIS addresses the federal decision-making process by creating methods for 

stakeholders to present information and concerns regarding the environmental aspects of various federal actions. However, NEPA’s EIS requirements are procedural 

in nature; specific environmental standards are addressed under federal or state 

regulatory laws such as the Clean Water Act or the Clean Air Act. 

As directed under NEPA, the federal Council on Environmental Quality (CEQ) 

has promulgated the necessary regulations to implement the requirement to prepare 

these EISs in those cases where major Federal actions are proposed. Under these 

regulations CEQ has specified that the federal actions that are potentially subject 

to these EIS requirements are defined broadly to include such actions as federal 

construction projects, the issuance of federal permits and leases, and federal funding 

of state, local or private actions, among various other types of federal projects. However, while federal actions are generally subject to NEPA, not every federal action 

requires an EIS; rather, only federal actions significantly affecting the quality of the 

human environment must have an EIS. 

In fact, in many cases various federal actions may be exempted from the EIS requirement through one of two mechanisms. First, the CEQ regulations authorize 

federal agencies to specifically identify various categories of actions that by their nature do not have a significant impact on the environment in the first place; these 

categories of activities are generally referred to as ‘‘categorical exclusions.’’ Most federal agencies have developed their own ‘‘categorical exclusions’’ that cover a wide 

variety of routine federal actions, including such actions as maintenance activities 

on federal properties, oversight of state environmental programs, and inspections 

and enforcement activities. Any federal actions which fall under a categorical exclusion do not require any specific environmental analysis and are not subject to EIS 

requirements. 

Second, for those actions that are not covered by a categorical exclusion, CEQ regulations authorize agencies to prepare a limited analysis, commonly known as an 

Environmental Assessment (EA), which generally amounts to a very preliminary review of the possible impacts of a proposed federal action on human health and the 

environment. The purpose of an EA is to determine whether a federal action will 

have a significant impact on the environment, which would trigger the need for an 

EIS. If the conclusion of the EA is that an action would not significantly affect the 

human environment, the federal agency may then issue a Finding of No Significant 

Impact (FONSI), which concludes the agency’s NEPA obligations for that action and 

in these cases the federal agency is not required to continue to prepare an EIS in 

order to satisfy NEPA. 

CONGRESS HAS NOT PROVIDED AN UNWARRANTED NEPA EXEMPTION FOR OIL AND

NATURAL GAS PROJECTS

In an effort to facilitate the prudent development of our nation’s energy supplies 

and to move toward energy independence, Congress sought to reach a careful balance in the Energy Policy Act of 2005 (EPAct) between encouraging oil and natural 

gas development and assuring the protection of human health and the environment. 

As part of this approach, Congress established under Section 390 of EPAct a rebuttable presumption that activities related to oil and natural gas development on federal land or pursuant to leases of federal interests in oil and natural gas reservoirs 

should be subject to a categorical exclusion under NEPA; in these cases the cognizant federal agency would not be required to prepare an EIS or an EA. Under 

EPAct, this rebuttable presumption applies where: 

• the surface disturbance associated with the activity is less than five acres so 

long as the total disturbance on a lease area is less than 150 acres and a sitespecific analysis under NEPA (i.e., an EA or an EIS) has previously been prepared; 

165 

• an oil or natural gas well is being drilled at a location where drilling has previously occurred within the last five years; • an oil or natural gas well is being drilled within a developed field where the 

drilling activity has been analyzed within the last five years in an approved 

land use plan or an EA or EIS prepared under NEPA; • a pipeline is being placed in an approved corridor; or • the activity consists of maintenance. 

As can be seen, this EPAct requirement cannot be viewed as a substantial ‘‘carveout’’ from NEPA—rather it provides a well-reasoned, limited categorical exclusion 

that avoids unnecessary, duplicative, and costly EIS requirements for those oil and 

natural gas projects that would be deemed to have minimal impacts in the first 

place or have already been adequately studied in other prior NEPA reviews. For certain oil and natural gas projects EPAct Section 390 creates a rebuttable presumption that a NEPA review is not required in connection with an Application for Permit to Drill at a specific well site where an EA or EIS has already previously examined the potential impacts of drilling in the area in which the proposed drilling site 

is located. In other cases this section would simply clarify that no site-specific environmental review is necessarily required in two situations where environmental impacts would be minimal in any event, i.e., where the drilling will be conducted on 

a site that is already disturbed or where the only activity being undertaken is maintenance. 

In essence, this provision attempts to strike a balance and is indeed quite narrow 

in scope—it does not at all represent a complete exclusion from NEPA requirements 

for these types of oil and natural gas activities. Instead, in enacting Section 390 

Congress has established only a limited categorical exclusion from the EIS requirements for a set of oil and natural gas activities that have already been subject to 

environmental review or are the types of activities that normally have minimal environmental impacts. In fact, in any given case the federal agency overseeing the 

activity could nevertheless still decide to prepare an analysis of the potential environmental impacts of drilling at a well site in the form of an EA or EIS because 

of particular concerns about that impacts at that location. 

In any event, because it only applies to the activities or actions of federal agencies 

or activities on federal lands, NEPA would still by its own terms have no application 

to many oil and natural gas drilling operations in the first place even in the absence 

of the congressional action taken in EPAct. For example, NEPA would not apply to 

most drilling activities in the Marcellus Shale in the Northeast, the Barnett Shale 

in Texas, or the Fayetteville Shale in Arkansas, where the federal government owns 

relatively little land and few rights to subsurface oil and natural gas. Likewise, it 

would have no applicability to drilling in the coalbeds of the Black Warrior Basin 

in Alabama since drilling activity there is undertaken solely on private lands. 

FEDERAL AGENCIES WILL CONTINUE TO PROTECT THE ENVIRONMENT

While Congress has acted to reasonably streamline the NEPA approval process 

for oil and natural gas drilling activities, this action does not at all suggest that the 

federal government is actually attempting under EPAct to abdicate its responsibilities to ensure that these activities are undertaken in a manner protective of human 

health and the environment—rather, just the contrary is true. In fact, the two principal federal land management agencies—the U.S. Bureau of Land Management 

(BLM) and the U.S. Forest Service (USFS—part of the U.S. Department of Agriculture (USDA))—with responsibilities over federal lands where oil and natural gas 

operations are undertaken have at the same time also adopted specific policies 

under NEPA and other applicable federal land management statutes to ensure that 

ongoing operations are conducted in a manner fully protective of human health and 

the environment and in accordance with federal environmental policies. For example, BLM has formally stated as part of its agency policy that it will: 

• conduct on-site inspections of all proposed drilling locations even where a categorical exclusion under NEPA applies; 

• review an Application for Permit to Drill in the same fashion as would have 

been done in the absence of a categorical exclusion; 

• continue to consult, where appropriate, with the U.S. Fish and Wildlife Service, 

state historic preservation offices and other officials regarding the potential impacts of drilling activities; and 

• apply mitigation measures identified in previously prepared EAs or EISs in 

order to minimize the environmental impacts of drilling. 

Similar to BLM, USDA (which includes the USFS) also has emphasized in its 

operational agency policies that the Department will continue to ensure that oil and 

166 

1 42 U.S.C. §§ 6901–6992K. 

natural gas drilling activities use best management practices in order to minimize 

the effects of these activities on surface resources and prevent unnecessary or unreasonable surface resource disturbances, stating that: 

It is critical to note that use of Section 390 in no way limits or diminishes 

the Forest Service’s substantive authority or responsibility regarding review 

and approval of a [Surface Use Plan of Operations] . . . . The Authorized 

Forest Officer will continue to assure that operations on leaseholds on National Forest System lands will minimize effects on surface resources and 

prevent unnecessary or unreasonable surface resource disturbance, including effects to cultural and historical resources and fisheries, wildlife and 

plant habitat. Best management practices are to be applied as necessary to 

reduce impacts of any actions approved under these categorical exclusions. 

CONCLUSION

In sum, the EPAct was not intended to be integrated as a new government policy 

to excuse oil and natural gas projects from key environmental reviews; rather, Congress enacted Section 390 of the EPAct merely to eliminate unnecessary, redundant 

and costly environmental reviews for certain types of oil and natural gas drilling 

projects in an effort to streamline the approval process for the construction and operation of energy projects that will move our nation toward energy independence. 

In fact, while Congress authorized the adoption of a process to exempt certain oil 

and natural gas projects from further NEPA scrutiny in certain cases, this exemption was quite narrowly drawn and therefore only applies to a limited number of 

energy projects. It was based on a close review of the estimated impacts of these 

proposed projects in light of actual experience and represents a careful balance with 

respect to encouraging necessary energy development while protecting human 

health and the environment. In any event, even in those cases where these categorical exclusions from NEPA may apply, the relevant federal land management agencies have emphasized that they still continue to take steps to ensure that the use 

of the categorical exclusions will not result in any lessening of substantive environmental protections—that is, the permits will continue to have specific provisions to 

manage the environmental risks of oil and natural gas development. As a result 

Section 390 of EPAct does not sacrifice environmental protections but simply expedites the production of vital American supplies of oil and natural gas that is needed 

for our country. 

ENCLOSURE—RESOURCE CONSERVATION AND RECOVERY ACT 

Enacted in 1976, the Resource Conservation and Recovery Act (RCRA)1 was 

passed to achieve three key goals: namely, to (1) conserve energy and natural resources, (2) reduce or eliminate the generation of hazardous waste as expeditiously 

as possible, and (3) protect human health and the environment. Congress subsequently amended RCRA in 1980 to address a number of key new issues raised in 

implementing this law, and then again in 1984 when it adopted the Hazardous and 

Solid Waste Amendments (HSWA) Act; HSWA established further waste cleanup 

and corrective action requirements, restrictions that prohibit the disposal of certain 

wastes in or on the land unless the wastes comply with specified treatment standards and/or waste constituent levels, and various other technical requirements for 

the management and disposal of solid and hazardous wastes. 

One of the key portions of RCRA—Subtitle C—is intended to effectively control 

the management and disposal of hazardous waste from ‘‘cradle to grave.’’ The waste 

management framework established by Subtitle C is designed principally to address 

‘‘low volume,’’ ‘‘high toxicity’’ wastes generated at one site and transported to another for disposal. Consistent with this framework, RCRA bans the disposal of ‘‘hazardous wastes’’—which are broadly defined under the statute—at facilities without 

valid permits. In order to obtain a permit, any new treatment, storage or disposal 

facility must meet stringent specifications for handling RCRA Subtitle C or hazardous wastes. Permitted facilities are subject to a wide range of management 

standards mandating ground-water protection, facility closure, and post-closure care 

requirements. Other specific management standards apply to targeted waste management units such as containers, tanks, surface impoundments, waste piles, land 

treatment units, landfills and incinerators. 

RCRA also establishes a comprehensive system designed to closely track the generation, storage, transport and disposal of Subtitle C wastes. Any company which 

generates these wastes above certain threshold amounts must register with EPA 

167 

2S. Rep. No. 96-172 at 6 (1980), reprinted in 1980 U.S.C.C.A.N. 5019, 5024-25. 

and/or an authorized state agency and comply with their requirements. These generators also must satisfy applicable recordkeeping and waste marking, labeling and 

placarding requirements in preparing wastes prior to shipment for off-site disposal. 

The Act provides that EPA may delegate to the states the authority to administer 

and enforce these various regulatory requirements and in the case of most states, 

the Agency has done so. 

Taken together, the Subtitle C requirements impose costly and rigorous limitations—constraints that were made more demanding by the 1984 HSWA Act. However, RCRA’s broad definition of hazardous waste had the effect of expanding 

RCRA’s scope well beyond the ‘‘low volume,’’ ‘‘high toxicity’’ wastes it was originally 

designed to cover. 

CONGRESS DID NOT INTEND TO REGULATE OIL AND NATURAL GAS EXPLORATION AND

PRODUCTION WASTES UNDER RCRA

As a result of regulations proposed by EPA in 1978 to implement the 1976 Act, 

Congress recognized that certain types of wastes presented unique issues and were 

most likely not well suited to regulation under EPA’s highly prescriptive Subtitle 

C regulatory scheme. These concerns particularly applied to those wastes that were 

produced in substantial volumes but also had relatively low toxicity. In fact, these 

wastes posed management issues that were far different than the issues posed by 

Subtitle C wastes generated by manufacturing and other industrial operations 

under routine circumstances. 

One particular category of these ‘‘high-volume, ‘‘low-toxicity’’ wastes consisted of 

drilling fluids, produced waters and other wastes associated with the exploration 

and production of oil and natural gas. In the course of early deliberations concerning 

potential amendments to RCRA, Congress specifically considered regulations for 

these categories of wastes that had previously been proposed by EPA. However, 

after careful deliberation Congress found that the extensive regulatory program proposed by EPA to regulate drilling fluids, produced waters and related wastes, i.e., 

wastes generated from oil and natural gas exploration and production operations, 

could have a significant economic impact on American oil and natural gas production.2 Moreover, Congress also recognized that the large volumes of these wastes 

really could not be handled by existing waste management units. Based on these 

concerns, Congress concluded that these wastes should be subject to a different regulatory scheme than other more ‘‘mainstream’’ Subtitle C wastes. 

EPA HAS CONCLUDED THAT REGULATION OF OIL AND NATURAL GAS EXPLORATION AND

PRODUCTION WASTES UNDER THE SUBTITLE C WASTE MANAGEMENT PROGRAM IS NOT

APPROPRIATE

Congress specifically considered the proper way to handle these ‘‘high-volume,’’ 

‘‘low-toxicity’’ wastes in addressing changes to RCRA in 1980. After considering a 

wealth of information, Congress decided that instead of specifically including these 

wastes under the general Subtitle C waste management program, EPA should instead set up a specialized way to address the need for any regulatory controls for 

these wastes. As part of this specified process, Congress first required EPA to study 

how these wastes were being managed by the states at that time and whether such 

existing management practices were adequate in light of the nature of these wastes. 

As part of this process, EPA was specifically required to look at the sources and volume of drilling fluids, produced water and other ‘‘high-volume,’’ ‘‘low-toxicity’’ wastes 

associated with oil and natural gas exploration and production; potential risks to 

human health and the environment from surface runoff or leaching from these 

wastes; existing disposal practices, alternatives to such practices and the costs of 

these alternatives; and the impact of any alternatives on oil and natural gas exploration and production. 

Once this study was completed, EPA was required to submit it to Congress for 

its review. EPA was further required under this specialized process to make a determination within six months from the time the report was given to Congress regarding whether the imposition of any additional regulatory controls on ‘‘high-volume,’’ 

‘‘low-toxicity’’ wastes was warranted. In the event that the Agency subsequently determined that drilling fluids, produced waters and related categories of wastes 

should be regulated under the standard RCRA Subtitle C waste management controls, Congress directed that any regulations implementing such a decision would 

not become effective unless specifically approved by Congress. In amending RCRA 

in 1980 Congress applied a similar process to other similar types of ‘‘high-volume,’’ 

‘‘low-toxicity’’ waste such as fly ash waste and slag wastes, noting that such amendVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00171 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
168 

3S. Rep. No. 96-172 at 2, reprinted in 1980 U.S.C.C.A.N. at 5020. 

4 53 Fed. Reg. 25446 (July 6, 1988). 

ments were necessary to ‘‘bring the implementation of the Act closer to the original 

intent of Congress.’’3

As a result of this mandated study, EPA subsequently determined that ‘‘high-volume,’’ ‘‘low-toxicity’’ wastes associated with oil and natural gas production should 

not be regulated under the RCRA Subtitle C waste management program. In reaching this conclusion, the Agency first confirmed that the wastes produced in connection with oil and natural gas exploration and production were being produced in 

substantial quantities. For example, EPA found that 361 million barrels of drilling 

waste were generated in 1985 as the result of drilling activities at about 70,000 well 

sites and that over 800,000 active well sites generated 20.9 billion barrels of produced water. Perhaps even more important, EPA also found in this study that a 

wide range of practices for the management of such waste had already been effectively adopted under various state regulatory programs as a result of widely varying 

geological, ecological, topographic, economic, geographic and other differences among 

well sites. 

Based on these findings EPA’s study came to the conclusion that imposing any 

form of RCRA Subtitle C waste management controls on these types of oil and natural gas exploration and production wastes was not effective and would not only result in substantial economic hardships for the oil and natural gas industry, but 

would also place severe and undue administrative burdens on regulated oil and natural gas companies and regulatory authorities themselves. For example, EPA’s 1988 

study found that: 

• imposing strict Subtitle C waste management controls on the handling and 

management of ‘‘high-volume,’’ ‘‘low-toxicity’’ wastes could impose costs on the 

oil and natural gas industry exceeding $6.7 billion; • imposing these controls could also lead to declines in oil and natural gas production of up to 12 percent and costs to consumers of approximately $4.5 billion; • the current RCRA program did not provide adequate flexibility for addressing 

this specialized class of wastes; • regulating oil and natural gas exploration and production wastes under the 

strict Subtitle C waste management controls could lead to severe permitting 

delays that would disrupt production of vital American energy supplies and 

could severely strain the existing capacity of facilities authorized to treat and 

dispose of hazardous wastes; • existing state and federal regulatory programs were generally adequate to manage oil and natural gas wastes and any gaps in these regulatory programs could 

be effectively addressed by regulation under RCRA programs for non-hazardous 

waste (Subtitle D) and by working with the states on their regulatory programs; • the state regulatory programs were specifically tailored to the unique circumstances of the oil and natural gas industry and it would be impractical and 

inefficient to impose the relatively inflexible RCRA Subtitle C waste regulations 

on oil and natural gas exploration and production wastes because of the potential for disrupting these state regulatory programs; and • substantial burdens would be imposed on EPA and state regulatory authorities 

if even a small percentage of the hundreds of thousands of oil and natural gas 

exploration and production facilities were required to obtain permits to treat, 

store or dispose of waste under the RCRA Subtitle C waste management program. 4

In light of this independent review, EPA’s decision not to regulate these ‘‘highvolume,’’ ‘‘low-toxicity’’ wastes from oil and natural gas exploration and development 

was a careful decision based on sound science and technical support. In the years 

since it made its original determination, EPA has still not found it necessary to revisit its determination or change its conclusions regarding the inappropriateness of 

regulating these oil and natural gas wastes under the RCRA Subtitle C waste management system. 

At the same time, consistent with its prior determination EPA has continued to 

work with state regulatory officials to ensure that state regulatory programs remain 

adequate to address any issues with respect to the control and disposition of these 

wastes. For example, in 1988 the Agency initiated a program in cooperation with 

state regulators to review state programs for the regulation of oil and natural gas 

exploration and production waste on a periodic basis. This process has now been formalized through the State Review of Oil & Natural Gas Environmental Regulations 

(STRONGER), which involves representatives of state and federal regulatory agencies, industry and environmental advocacy organizations. As part of this review 

169 

1 H.R. Rep. No. 93-1185 (1974), reprinted in 1974 U.S.C.C.A.N. 6454, 6481. 

2 H. R. Rep. No. 93-1185 (1974), reprinted in 1974 U.S.C.C.A.N. 6454, 6459. 

3 H.R. Rep. No. 93-1185 (1974), reprinted in 1974 U.S.C.C.A.N. 6454, 6481. 

4 Natural Resources Defense Council v. U.S. Environmental Protection Agency, 824 F.2d 1258, 

1268 (1st Cir. 1987). 

process, state regulatory programs are compared to a set of national guidelines 

which is regularly updated in order to identify areas for improvement in existing 

state programs. More than 30 reviews of state programs responsible for the regulation of over 85 percent of American onshore oil and natural gas production have 

been conducted under this process. 

CONCLUSION

In enacting RCRA and overseeing its implementation, Congress recognized that 

certain types of ‘‘high-volume,’’ ‘‘low-toxicity’’ waste such as the drilling fluids, produced waters and other wastes produced in connection with the exploration and production of oil and natural gas are different in key respects from the types of wastes 

typically managed under the RCRA Subtitle C regulatory program and that it may 

not be appropriate to subject such wastes to the strict requirements of that program. 

After careful study EPA has again subsequently confirmed that it would be impractical, costly and disruptive to manage these oil and natural gas wastes under the 

RCRA Subtitle C waste regulations. The decision not to regulate oil and natural gas 

exploration and production wastes as Subtitle C wastes under RCRA reflects the nature of those wastes and the reality that the RCRA Subtitle C regulatory program 

is not designed to and was never intended to address these wastes in the first place. 

ENCLOSURE—SAFE DRINKING WATER ACT 

Congress enacted the federal Safe Drinking Water Act (SDWA)1 in 1974 to ensure 

that water supply systems serving the public meet appropriate standards to protect 

the public health. As part of SDWA, the U.S. Environmental Protection Agency 

(EPA) is required to establish (1) national drinking water regulations to address 

contaminants that might adversely affect human health, and (2) an Underground 

Injection Control (UIC) program to protect underground sources of drinking water 

from contamination. To address these requirements, EPA has implemented a program for the treatment and disinfection of water supplies that must be met by public water supply systems across the country and also has established standards for 

maximum levels of various contaminants that may be found in drinking water provided to the public (these are known as maximum contaminant levels or MCLs). 

SDWA also specifies that EPA may delegate to the states the authority to enforce 

drinking water regulations and to issue UIC permits if the state has a program in 

place that meets certain minimum requirements established by Congress, and in 

fact these federal programs are now largely administered by the states. 

Similar to other landmark federal laws passed at that time, SDWA was specifically intended to cover the disposal of wastes that might threaten underground 

sources of drinking water (USDWs) and not production-related operations themselves. Congress initially passed SDWA based on its recognition that various industrial and agricultural practices had resulted in increased concentrations of potentially harmful chemicals that were entering the nation’s drinking water sources.2

For example, in the key congressional report from the U.S. House of Representatives 

Committee on Interstate and Foreign Commerce accompanying the 1974 law, this 

congressional committee recognized the concerns of the U.S. Geological Survey and 

the Bureau of Mines regarding the ‘‘indiscriminate ‘sweeping of our wastes underground’’’ and noted that these wastes were coming from many sources, such as municipalities that ‘‘increasingly engag[e] in underground injection of sewage, sludge 

and other wastes. Industries are injecting chemicals, byproducts and wastes. . . . Even government agencies, including the military, are getting rid of difficult to 

manage waste problems by underground disposal methods.’’3 Consistent with this 

view, the intended focus of the UIC program when it was originally enacted as part 

of SDWA in 1974 was on managing the discharge of wastes into geologic formations. 

In order to ensure that this issue was effectively addressed, SDWA was specifically 

designed to establish a federal-state partnership to ‘‘protect drinking water from 

contamination by the underground injection of waste.’’4

CONGRESS DID NOT INTEND TO REGULATE HYDRAULIC FRACTURING UNDER THE UIC

PROGRAM

At the same time, Congress did not intend that the UIC program would be extended to regulate wells that are themselves used for the production of oil or natVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00173 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
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5While such formations may contain groundwater that would technically meet the definition 

of an ‘‘underground source of drinking water’’ under SDWA because the water contains less than 

10,000 milligrams per liter of total dissolved solids, such groundwater would not in practice be 

used as drinking water-and would certainly not be tapped by a private drinking water well - 

because it is of low quality, would require significant treatment in order to be potable and would 

be quite expensive to access. 6Palmer, I.D., et al., Comparison between gel-fracture and water-fracture stimulations in the 

Black Warrior basin; Proceedings 1991 Coalbed Methane Symposium, Univ. of Alabama (Tuscaloosa), pp. 233-242 7 40 C.F.R. § 146.23(b)(2). 

ural gas. In considering SDWA, Congress recognized that many states already had 

vigorous regulatory programs in place to govern petroleum operations and that 

these programs had been more than adequate through the years to ensure that 

these operations would not harm underground sources of drinking water, particularly in many of the energy-producing states in the South and Western portions of 

the country. To ensure that SDWA was properly targeted, Congress intended to 

limit the scope of SDWA to avoid imposing unnecessary regulations that would be 

a constraint on energy production, divert funds from energy development and represent an inflationary factor in energy costs. In accordance with this approach, 

Congress focused the UIC program on waste disposal activities that threatened 

the quality of underground drinking water sources and never sought to regulate 

wells that were themselves being used for oil and natural gas production. 

Given the focus of the UIC program on the underground disposal of waste, EPA 

also had never thought to regulate energy production operations such as hydraulic 

fracturing—a critical oil and natural gas production technique that will be essential 

to the aggressive development of the nation’s energy resources—under SDWA. In 

fact, EPA’s regulations for the UIC program address a variety of wells, including 

wells used for the disposal of hazardous waste (Class I wells), wells used for the 

disposal of wastes from oil and natural gas production activities and wells used to 

enhance oil and natural gas production from existing production wells (Class II 

wells), and other types of disposal wells such as cesspools (Class III-V wells). However, those regulations do not purport to regulate hydraulic fracturing. 

Hydraulic fracturing is a well stimulation technology that has been used for 60 

years in millions of energy production operations. As Congress has already recognized, hydraulic fracturing has been effectively regulated for decades by the states 

and is essential for the future development of America’s oil and natural gas supplies. State regulations require the use of various techniques to protect drinking 

water aquifers, including the use of steel casing and cement to seal off shallow formations containing drinking water sources from materials being pumped into and 

out of an oil or natural gas well. These regulations effectively protect against any 

risks to drinking water aquifers; consequently, there would be no additional environmental benefits to further federal regulation of hydraulic fracturing under 

SDWA. 

In fact, hydraulic fracturing differs in many key respects from what have traditionally been viewed as waste disposal activities intended for regulation under 

EPA’s UIC program. As part of these waste disposal operations, wastes are specifically injected into subsurface formations for purposes of disposal and are intended 

to be left in the subsurface. In contrast, hydraulic fracturing is an activity that 

takes place in the production well itself and is a part of the process of completing 

the well and preparing it for the production of oil and natural gas. The fluids used 

in the hydraulic fracturing process—consisting mostly of water—are pumped into an 

oil- or natural gas-bearing formation that is generally thousands of feet below any 

aquifers being used for drinking water.5 Moreover, the fluids that are pumped into 

the subsurface as part of the hydraulic fracturing process are intended to be removed from the formations into which they are pumped. Indeed, studies of coalbed 

methane wells in Alabama have shown that 80 percent or more of the fluids pumped 

into a well during the hydraulic fracturing process are eventually recovered from 

the well during the production process.6

In light of these fundamental differences between hydraulic fracturing and subsurface waste injection, many of the regulations developed by EPA to implement the 

UIC program simply have no application to hydraulic fracturing activities whatsoever. For example, EPA’s regulations require that certain parameters such as injection pressure, flow rate and cumulative volume of fluids injected be monitored weekly or monthly and in some cases on a daily basis.7 These requirements for ongoing 

monitoring would simply not apply or be practical for an activity such as hydraulic 

fracturing that takes only a few hours to complete. 

SDWA was never meant to create special treatment for these kinds of energy-producing operations—instead, SDWA recognized that there was a need to regulate 

171 

8 118 F.3d 1467 (11th Cir. 1997). 

9See Evaluation of Impacts to Underground Sources of Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs, EPA Office of Water (June 2004). 

waste disposal operations and not to impose undue regulatory burdens on production operations if they were not necessary. When Congress amended SDWA in 1980, 

it relied on the fact that the states already had existing programs in place to regulate oil and natural gas exploration and production activities, including activities 

that could be considered as ‘‘underground injection’’ subject to regulation under 

SDWA. In order to take advantage of the experience of state regulators and to avoid 

disrupting existing state programs, Congress specifically provided in Section 1425 

of the Act that states could assume primary authority over Class II injection wells— 

those associated with oil and natural gas production activities—by demonstrating 

that their programs meet the same basic standards as those established by Congress for programs administered by EPA. 

While many parties have sought to reexamine this law, even EPA itself has specifically emphasized that SDWA was never intended to regulate wells that are 

themselves used for the production of oil or natural gas. For example, in addressing 

the scope of SDWA in Legal Environmental Assistance Foundation v. U.S. Environmental Protection Agency,8 the Agency expressly argued that Congress never intended to regulate hydraulic fracturing as ‘‘underground injection’’ under SDWA. 

While the U.S. Court of Appeals subsequently decided that hydraulic fracturing fit 

the definition of ‘‘underground injection’’ and so had to be regulated under the Act, 

the court’s decision ignored the intent of Congress and did not consider whether hydraulic fracturing actually posed any risk to drinking water supplies in the first 

place. In fact since this ruling the court’s decision has been severely criticized for 

its failure to follow the will of Congress and ignoring EPA’s long-standing interpretation of the specific scope of SDWA. 

Because of the regulatory uncertainty created by this court decision, Congress 

amended SDWA in the Energy Policy Act of 2005 to specifically clarify that hydraulic fracturing is not regulated as a form of underground injection under SDWA except that EPA does have the authority to regulate the use of diesel in the fluids 

employed in the fracturing operations. This exemption simply confirmed the wellrecognized proposition that the UIC provisions of SDWA were primarily intended 

to regulate the subsurface disposal of waste and that Congress never intended to 

regulate an activity such as hydraulic fracturing under SDWA. Moreover, Congress’s 

decision to clarify SDWA to exempt hydraulic fracturing from unnecessary regulation is consistent with the longstanding congressional mandate under this law to 

avoid impeding oil and natural gas production unless restrictions are absolutely necessary to protect underground sources of drinking water. 

FEDERAL REGULATION OF HYDRAULIC FRACTURING IS NOT NECESSARY

Contrary to unsupported claims, Congress’s position that hydraulic fracturing 

should be excluded from additional federal controls under SDWA is based on sound 

science. For example, in 2004 EPA completed a study of the potential impacts of 

hydraulic fracturing of coalbed methane (CBM) wells on drinking water supplies; 

the Agency has, in fact, characterized this study as the most extensive review of the 

potential impacts of hydraulic fracturing on public health ever undertaken.9 As part 

of this study, EPA reviewed information about alleged incidents of drinking water 

well contamination believed by the affected parties to be associated with hydraulic 

fracturing or other CBM development activities. A draft of the study report was subject to extensive public comment and was thoroughly reviewed by numerous EPA 

offices, other federal agencies and a peer review panel of experts. 

After much scrutiny and careful review, the Agency found in this key 2004 study 

that, although thousands of CBM wells are fractured annually, there were ‘‘no confirmed cases [of contamination of drinking water wells] that are linked to fracturing 

fluid injection into CBM wells or subsequent underground movement of fracturing 

fluids.’’ EPA also identified a number of key factors that minimize the risk posed 

by hydraulic fracturing to underground sources of drinking water (USDWs), even 

though that term is very broadly defined in SDWA and may include aquifers that 

are not in fact used as sources of drinking water and would be quite unlikely to 

serve as sources of drinking water. These factors include the removal of much of 

the fracturing fluid from the subsurface once fracturing operations are completed 

and the dilution, dispersion and adsorption as well as the potential biodegradation 

of any fluids that remain in the subsurface. Consequently, EPA concluded that hydraulic fracturing of CBM wells poses little or no threat to USDWs. This EPA study 

172 

10See Ground Water Protection Council, Survey Results On Inventory and Extent of Hydraulic Fracturing In Coalbed Methane Wells In the Producing States (Dec. 15, 1998); Interstate Oil 

and Gas Compact Comm’n, States Experience With Hydraulic Fracturing (July 2002 11Letter from Thomas P. Richmond, GWPC President, to The Hon. James Inhofe and The 

Hon. James Jeffords (June 8, 2005). 1 42 U.S.C. §§ 9601-9675. 

confirmed the results of prior studies by state regulators which essentially reached 

the same conclusion.10

In addition, Congress recognized that there was little need for federal regulation 

of hydraulic fracturing because the states had been quite satisfactorily regulating 

the practice for many years. For example, the Ground Water Protection Council 

(GWPC), a highly-regarded national organization representing state officials 

charged with protection of groundwater, had studied the impacts of hydraulic fracturing and came to the conclusion that there are no technical threats posed by these 

oil and natural gas operations to human health and the environment. In reaching 

this conclusion, GWPC noted that: 

As the front line regulators of the state oil and natural gas UIC program, we have 

not seen credible evidence that the hydraulic fracturing of coal bed methane reservoirs, or any other deeper formations, causes any documented threat to underground sources of drinking water. The states have maintained oversight of hydraulic 

fracturing as a part of the oil and natural gas production process. This makes good 

regulatory sense and has stood the test of time for over 50 years. Any requirement 

to regulate this process as underground injection would not result in any additional 

environmental protection of under ground sources of drinking water (USDW) and, 

it would strain already depleted state UIC resources. The result would be that 

money that could be used to solve severe contaminant source problems, such as 

urban storm water or large capacity cesspools, would be diverted to a practice that 

is already regulated under another program and is not a threat to USDWs.11

CONCLUSION

In short, trying to regulate hydraulic fracturing under the UIC program would be 

like trying to fit a square peg into a round hole. Given the lack of harm to drinking 

water aquifers and the need to focus limited regulatory resources on actual threats 

to drinking water, Congress’s decision in 2005 to clarify the scope of regulation 

under SDWA to exclude hydraulic fracturing was entirely reasonable and reflected 

the active support of state regulators in charge of groundwater protection. 

ENCLOSURE—SUPERFUND 

In 1980 Congress responded to the problems posed by contaminated waste sites 

such as those at Love Canal (near Niagara Falls, New York) and Times Beach, Missouri by passing the Comprehensive Environmental Response, Compensation and 

Liability Act (CERCLA).1 Commonly referred to as the federal ‘‘Superfund’’ law, 

CERCLA was intended to encourage the prompt and expeditious cleanup of numerous abandoned hazardous waste disposal sites and other contaminated properties 

scattered across the country. In enacting CERCLA, Congress had recognized that 

there was a ‘‘gap’’ in addressing the need to remediate hazardous waste sites—the 

federal Resource Conservation and Recovery Act (RCRA) was already in place to 

govern the handling and disposal of hazardous wastes from active facilities, but 

there was still a need to address the environmental problems posed by the plethora 

of old, non-operating hazardous waste sites in the country. 

To help achieve the statute’s goals, CERCLA established a very onerous liability 

scheme under which parties could be held strictly, jointly, severally and retroactively liable for the cleanup of hazardous waste landfills and other contaminated 

sites. Under CERCLA four categories of parties can be held liable for the cleanup 

of these sites, including current and former owners and operators of the sites as well 

as entities that generated hazardous substances which were disposed of at a contaminated site and any entity that transported these hazardous substances to these 

sites. In addition, CERCLA provides broad powers to federal and state governments 

to recover the costs that these governments incurred in remediating these sites to 

required cleanup levels. 

As part of the funding mechanisms for the law, CERCLA further established a 

very substantial trust fund referred to as the Hazardous Substance Superfund (the 

‘‘Trust Fund’’) that was intended to be used to help fund these cleanup activities. 

This fund, financed by an excise tax on crude oil, petroleum products and other 

specified chemicals, was specifically intended to help support the U.S. Environmental Protection Agency (EPA) in carrying out the Agency’s responsibilities under 

173 

2 126 Cong. Rec. H 9248 (Sept. 18, 1980) (statement of Rep. Harsha). 

the law, essentially amounted to a feedstock tax that was imposed on the oil and 

natural gas industry in a manner to reflect the industry’s responsibilities for these 

hazardous waste problems. Additional monies were provided to this Trust Fund in 

the amendments to CERCLA adopted as part of the Superfund Amendments and 

Reauthorization Act of 1986 (SARA) to further support cleanup activities. 

In enacting CERCLA, Congress attempted to strike a careful balance among a 

number of critical factors shaping the overall cleanup program. First, there already 

were a number of federal laws on the books that were intertwined with the scope 

of CERCLA. For example, the federal Clean Water Act (CWA) had previously been 

adopted to regulate the cleanup of oil spills and related remediation activities; 

RCRA also had been passed in order to address cleanup issues at active industrial 

sites. At the same time, there were also a number of other pending federal legislative proposals that would have addressed other facets of cleanup responsibilities 

such as the cleanup of oil pollution in the nation’s navigable waters. Against this 

background, two key elements of CERCLA were included in order to strike a reasonable accommodation with these other environmental activities: (1) the ‘‘petroleum 

exclusion’’ and (2) the treatment of ‘‘federally-permitted releases.’’ 

THE ‘‘PETROLEUM EXCLUSION’’ 

The ‘‘petroleum exclusion’’ reflected the numerous reasonable steps taken by Congress to fashion a responsible cleanup program in the face of many competing pressures. First, Congress recognized that the principal focus of the cleanup program 

should be on releases of hazardous chemicals, which was the most serious threat 

to human health and the environment posed by the abandoned waste sites. Indeed, 

in commenting on the need for the Superfund program at that time, then-EPA Administrator Douglas Costle noted that ‘‘[t]he problem of hazardous spills is acute 

and more threatening than oil.’’2 As a result CERCLA was passed to provide EPA 

with the necessary tools to address the widespread and serious contamination at old 

chemical waste sites like the Love Canal site in New York or the ‘‘Valley of the 

Drums’’ site in Kentucky—these sites included large landfills covering many acres 

and a wide variety of manufacturing and waste processing facilities that had handled large volumes of chemicals for many years and that had very high levels of 

hazardous chemical contaminants in the soils and extensive plumes of contaminated 

groundwater that threatened drinking water supplies. 

Second, although the cleanup of chemical waste sites was given a high priority 

by Congress in enacting CERCLA, Congress had never intended to ignore the need 

to clean up petroleum contamination, but instead decided to address these issues 

much more effectively through other programs. For example, recognizing the need 

to address oil spills, Congress had already passed key provisions in the CWA as 

noted above to address spills of petroleum into the surface waters, thus negating 

the need to address it again during the deliberations on CERCLA. Congress subsequently expanded the regulation of oil spills by passing the Oil Pollution Act of 1990 

(OPA), which imposes liability on any party responsible for a vessel or onshore facility from which oil is discharged to the waters of the United States (which includes 

most surface waters and adjacent wetlands) or adjoining shorelines for the cost of 

cleaning up those discharges and for the damages that may result from the incident. 

OPA was adopted to directly respond to the concerns raised in the congressional debates on Superfund regarding the need to hold parties responsible for a wide range 

of surface spills of petroleum. For underground storage tanks (USTs) containing petroleum, Congress also eventually added provisions to RCRA in 1984 to address any 

leaking USTs. This program specifically imposes requirements to prevent leaks from 

USTs containing petroleum as well as to ensure the proper monitoring of these 

tanks and corrective actions if these tanks leak. 

In any event, the adoption of the so-called ‘‘petroleum exclusion’’ is consistent with 

the general principles that the courts themselves have adopted in interpreting the 

scope of CERCLA responsibilities. In addressing the question of CERCLA liability, 

an overwhelming number of courts have consistently ruled that companies which 

sell useful products such as petroleum and/or crude-oil products themselves should 

not be subject to CERCLA in the first place. According to this universally-standard 

rule, CERCLA was intended to cover only the disposal of contaminated products, not 

the use of uncontaminated petroleum and crude oil supplies. 

Consistent with this view, EPA also has interpreted the ‘‘petroleum exclusion’’ 

rule only to cover hauling and transport of crude oil and refined petroleum products 

themselves, including those substances that are normally found in crude oil or are 

normally added to crude oil as part of the standard refining process. However, to 

174 

3S. Rep. No. 96-848 at 46 (1980). 

4 126 Cong. Rec. S 14965 (Nov. 24, 1980) (Statement of Sen. Randolph). 

the extent that petroleum or petroleum products eventually become contaminated 

with hazardous substances as a result of use or otherwise, then these supplies 

would no longer be covered under the ‘‘petroleum exclusion’’ rule and they would 

then become subject to CERCLA liability just like any other contaminated waste 

materials. As a result, companies which have generated waste motor oils or hydraulic oils, or other types of used petroleum products, would be required to clean up 

sites that have become contaminated from the disposal of these waste products just 

as with any other hazardous wastes. 

FEDERALLY-PERMITTED RELEASES

CERCLA also contains a provision excluding ‘‘federally-permitted releases’’ from 

CERCLA liability. This exclusion covers releases of hazardous substances to the environment that have been authorized pursuant to a variety of federal permits, such 

as a National Pollutant Discharge Elimination System (NPDES) permit or a dredge 

or fill permit issued under the CWA, or an air permit issued under various provisions of the Clean Air Act. In addition, Congress included within the exclusion for 

federally-permitted releases any injection of fluids or other materials authorized 

under state law (i) for the purpose of stimulating or treating wells for the production 

of crude oil, natural gas or water, (ii) for the purpose of secondary, tertiary or other 

enhanced recovery of crude oil or natural gas, or (iii) which are brought to the surface in conjunction with the production of crude oil or natural gas and are subsequently reinjected into the subsurface. 

These ‘‘federally-permitted releases’’ exemptions have been quite misinterpreted 

in many cases. This CERCLA exemption was not included as a means to avoid imposing any liability on responsible parties, but rather to ensure that permitting 

issues were instead properly addressed under the respective federal regulatory programs in which they were administered in the first place. Indeed, in enacting this 

particular exclusion, Congress specifically recognized that ‘‘in view of the large sums 

of money spent to comply with specific regulatory programs,’’ any liability for releases of hazardous substances in accordance with duly issued permits ‘‘should be 

determined based on the facts of each individual case.’’3 Accordingly, Congress provided that liability for these types of releases should not arise under CERCLA, but 

should more properly be determined under the law pursuant to which the release 

was authorized or under common law so as to ‘‘give regulated entities clarity in 

their legal duties and responsibilities.’’4 A similar provision is included in the Oil 

Pollution Act of 1990. 

CONCLUSION

CERCLA was enacted in order to address the environmental problems posed by 

abandoned, inactive contaminated waste sites and hazardous substance spills. This 

law casts a broad web of liability on responsible parties for the cleanup of these 

sites and resulted in a dramatic shift in the nature of liability for these problems— 

imposing a new federal standard involving strict, joint and several liability that 

could be imposed retroactively and without regard to fault for conduct occurring 

years earlier. 

In adopting this approach, Congress had to grapple with the impacts of imposing 

this far-reaching new liability regime on other pre-existing federal environmental 

regulatory requirements and to try to ensure that these other federal laws were still 

properly implemented. To achieve this goal, Congress chose to codify two particularly key provisions: the ‘‘petroleum exclusion’’ and the exclusion for federally-permitted releases. Neither of these exemptions was adopted in order to afford special 

treatment to the oil and natural gas industry or any specific industry. Rather, they 

were included either for sound practical reasons or because it was clear that the 

scope of CERCLA should have never covered these situations in the first place. 

There has been no intent to ignore any environmental problems caused by the spillage of crude oil or petroleum. In fact, as Congress intended, any environmental 

problems caused by contaminated petroleum or crude oil supplies are amply addressed under CERCLA or under a plethora of other federal environmental regulatory authorities. 

175 

1http://investor.shareholder.com/bhi/riglcounts/rclindex.cfm 2Data as of 2010 (most recent available). United States Energy Information Agency http:// 

www.eia.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid=3&pid=26&aid=1# 3 United States Energy Information Agency. http://www.eia.gov/cfapps/ipdbproject/ 

IEDIndex3.cfm?tid=5&pid=53&aid=1 4 United States Energy Information Agency. http://www.eia.doe.gov/emeu/mer/pdf/pages/ 

sec5l4.pdf 5 As of December 1, 2008, there were 88,357 oil and gas wells on BLM lands. Government 

Accountability Office. http://www.gao.gov/new.items/d10245.pdf 6 Bureau of Land Management, http://www.blm.gov/wo/st/en/prog/energy/oillandlgas/statistics.html 7 BOEMRE, Gulf of Mexico Region Blocks and Active Leases by planning Area, January 3, 

2011; EIA, Overview of U.S. Legislation and Regulations Affecting Offshore Oil and Natural Gas 

Activity, p. 2, September, 2005. 8 United States Energy Information Agency, http://www.eia.gov/dnav/pet/ 

petlmovelwklyldcllNUS-Z00lmbblpdll.htm 9 Correspondence from Celia Boddington, BLM, to David Alberswerth, TWS, February12, 

2012. 

STATEMENT OF THE WILDERNESS SOCIETY

The oil and gas industry and their allies continue to insist that the only way to 

address our country’s energy challenges is to open more public lands and waters to 

oil and natural gas drilling, and reduce environmental and safety standards. In 

truth, oil and gas drilling in America is already occurring at an astonishing pace 

and in a bewildering number of places. Yet, in the Rocky Mountain West vast expanses of public lands open to drilling and under lease by the industry are not being 

used, and thousands of drilling permits issued to companies by the Bureau of Land 

Management (BLM) are sitting idle. 

More oil and gas drilling occurs in America every year than anywhere else in the 

world. 

As of January 13, there were 1,764 rotary drilling rigs operating on U.S. lands 

and waters.1

America ranks #2 in world natural gas production, and #3 in oil production. 

The U.S. is the second largest natural gas producer in the world2 and the thirdlargest producer of oil.3

Tens of thousands of wells are drilled every year in the U.S. 

At the beginning of the last decade 27,000 oil and gas wells were drilled in the 

U.S. in one year. But in 2010 over 40,000 new wells were drilled on American lands 

and waters.4

The West’s public lands are already extensively drilled, leased, and available for 

leasing. There are tens of thousands of oil and natural gas wells on public lands, 

with thousands more currently approved for drilling and tens of thousands more 

planned for the future.5 Tens of millions of acres of federal public lands are available for leasing under current BLM Resource Management Plans. 

Tens of millions of acres of onshore and offshore federal lands are already under 

lease to oil and gas companies—the vast majority of it unused. 

According to BLM data, as of the end of FY 2012, 37,792,212 acres of federal public lands are leased for oil and gas development, an area larger than the State of 

Florida.6 However, only one third of these leases— 12,512,974 acres— are in production. In addition, over 34 million acres of offshore federal lands are under lease in 

the Gulf of Mexico alone, where roughly 4,000 platforms produce oil and/or gas.7

The United States has become a net exporter of refined petroleum products. 

In 2011, the United States exported more petroleum products, such as gasoline 

and diesel fuel, than it imported for the first time in decades. The trend has continued into 2012 as the U.S. was exporting about 1,000 Mbbl/d in May 2012, according 

to the United States Energy Information Agency.8

The oil and gas industry is sitting on nearly 7,000 approved but idle federal drilling permits. 

Though the industry and their political allies persistently complain about ‘‘restrictive’’ government policies that allegedly are thwarting U.S. oil and gas development, 

the BLM reported in February, 2013, that 6,990 approved onshore federal drilling 

permits were sitting idle, unused by oil and gas operators who have obtained them9. 

The industry has ‘‘shut in’’ thousands of gas wells on western public lands during 

the past four years, but continues to complain about their alleged ‘‘lack of access’’ 

to federal lands for drilling. 

For example, according to the Wyoming Oil & Gas Conservation Commission, as 

of 2009, there were over 12,500 shut-in coal bed methane wells in the Powder River 

176 

10http://www.uwyo.edu/eori/lfiles/co2conference10/tom%20doll%20eoril30june2010l2009- 

2010.pdf 11http://phx.corporate-ir.net/phoenix.zhtml?c=62256&p=irol-irhome 

Basin of Wyoming alone!10 Thousands more natural gas wells have been shut-in 

elsewhere in Wyoming and the West, primarily due to low natural gas prices. 

Low natural gas prices—not government policies or regulations—are causing 

many companies to reduce spending on natural gas projects on federal lands, a 

strategy intended to drive up prices. 

For example, the CEO of Ultra Petroleum, a large independent producer with 

major investments in gas wells on federal lands in Wyoming, recently told his investors of the company’s strategy to curtail exploration activities because, ‘‘We don’t believe in cash flow growth or production growth without economic returns.’’11 Moreover, ‘‘Industry-wide, you’re just beginning to see natural gas production roll over. 

Once it begins, it will accelerate, and I think we are looking at a two-year window 

of monthly reductions in domestic natural gas supply. So it’s taken us and the industry some time to react to the market signals, but we have and we won’t be quick 

to over-invest in the coming years. We’ve seen natural gas prices respond positively, 

but they are a long, long way away from levels that will attract capital.’’ In other 

words, natural gas producers will increasingly be curtailing their drilling activities, 

in a strategy designed to raise consumer prices. 

THE WILDERNESS SOCIETY, 

Washington, DC, February 19, 2013. 

Hon. RON WYDEN, 

Chairman, Committee on Energy and Natural Resources, U.S. Senate, Washington, 

DC. 

Hon. LISA MURKOWSKI, 

Ranking Member, Committee on Energy and Natural Resources, U.S. Senate, Washington, DC. 

DEAR CHAIRMAN WYDEN AND RANKING MEMBER MURKOWSKI: 

We respectfully request that this letter and the accompanying information be included in the Committee on Energy and Natural Resources February 12, 2013, hearing record regarding ‘‘Opportunities and Challenges for Natural Gas’’. Accompanying this letter are two fact sheets: ‘‘Oil and Gas Drilling on Federal Lands— 

Some Key Facts′′; and ‘‘Most BLM Lands in the Five Rocky Mountain States are 

Open to Oil & Gas Leasing.’’ These fact sheets document a number of often overlooked but relevant facts regarding the availability of federal onshore lands for oil 

and gas development. 

At least one witness during the February 12 hearing implied that federal land 

management polices are somehow inhibiting the oil and gas industry’s ability to 

gain access to federal onshore lands for oil and gas development. The relevant facts, 

however, portray a completely different reality with regard to this question: tens of 

millions of acres of onshore federal lands are currently available for oil and gas development; tens of millions of acres of federal lands are under lease to oil and gas 

companies; nearly 7,000 federal drilling permits have been issued to companies but 

are not being utilized by them; and over ninety-two thousand oil and gas wells are 

operating on federal onshore lands, with thousands of new wells permitted by the 

Bureau of Land Management every year. 

In conclusion and as the accompanying documents demonstrate, the oil and gas 

industry has available to it tens of millions of acres of onshore federal lands. The 

real issue that Congress should contemplate is not whether federal policies are unnecessarily inhibiting the extraction of oil and gas resources from our federal lands, 

but instead whether there are sufficient safeguards in place to assure that (1) the 

most environmentally sensitive public lands are protected from the adverse impacts 

of oil and gas development, and (2) that oil and gas extraction and development activities on federal lands are done in an environmentally safe manner. 

Sincerely, 

DAVID ALBERSWERTH, 

Senior Policy Advisor. 

177 


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wild2.eps
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THEODORE ROOSEVELT CONSERVATION PARTNERSHIP, 

Washington, DC, February 18, 2013. 

Hon. RON WYDEN, 

Chairman, Senate Energy and Natural Resources Committee. 

Hon. LISA MURKOWSKI, 

Ranking Member, Senate Energy and Natural Resources Committee. 

DEAR CHAIRMAN WYDEN, RANKING MEMBER MURKOWSKI AND MEMBERS OF THE

COMMITTEE: 

Thank you for the opportunity to provide testimony and comment on the hearing 

entitled, ‘‘Opportunities and Challenges for Natural Gas.’’ The Theodore Roosevelt 

Conservation Partnership (TRCP) agrees that a balance must be achieved among 

the range of natural resource values to ensure the proper development of natural 

gas on federal public lands. There must be an even balance between the development of natural gas resources and the conservation of our natural resources to ensure sustainability of the biological and economic values of these natural resources. 

TRCP supports responsible energy development and has worked over the past decade to promote principles and recommendations that will help our country achieve 

the balance needed to continue producing energy while conserving the environment. 

TRCP and our conservation partners, a coalition of 22 conservation and sportsmen 

organizations that make up the Fish, Wildlife, and Energy Working Group, have developed the, ‘‘FACTS for Fish and Wildlife’’ a set of recommendations that, when 

implemented, resolve conflict that has been evident in the past. FACTS, an acronym 

which stands for Funding, Accountability, Coordination, Transparency, and Science, 

represent the key actions needed to resolve on-going conflicts between energy and 

renewable natural resources. 

While the focus of the hearing was on how to manage the increase in natural gas 

extraction and potential exports, it must be recognized that there are significant impacts to the landscape during energy exploration and production. New technology 

has allowed previously un-developable gas resources to be tapped—many in sensitive fish and wildlife habitats. This is evident in the serious decline of mule deer 

habitats and populations in portions of Wyoming and Colorado, and also has broad 

implications for development in sage grouse habitats in 11 western states. On federal public lands the priority for energy development has overridden the multipleuse mandate in some sensitive locations. 

To successfully achieve balance between energy extraction and natural resource 

conservation, we recommend implementation of the FACTS principles and taking 

the following actions: 

• Identify habitats that are too valuable or special to have natural gas development at this time and require that any development be done off-site. This includes areas of world class recreational opportunities and irreplaceable habitats 

or landscapes; 

• Provide clear direction on what constitutes ‘‘multiple-use’’ and what is considered ‘‘undue and unnecessary degradation’’ of the environment under Federal 

Land Planning and Management Act (FLPMA). 

• Broadly and consistently implement the 2010 Department of the Interior oil and 

gas leasing reforms. 


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180 

• Evaluate the economic and employment loss in local communities due to the impacts of industrialized energy development on outdoor recreation economies and 

communities. 

• Provide new guidance on mitigation at the landscape level and what constitutes 

adequate compensation where impacts cannot be mitigated effectively. 

We must be aware that many landscapes and communities, particularly those 

with abundant public lands and where natural gas extraction is proposed, rely on 

the significant jobs and economic benefits associated with outdoor recreation on public lands. In many cases the identity and culture of locales have been built around 

these opportunities. For example, a recent study by Southwick Associates for Sportsmen for Responsible Energy Development showed that counties with a higher percentage of public lands managed for conservation and recreation reported higher 

levels of job and population growth than those with higher percentages of lands 

managed for commodity production. In Cody, Wyoming, hunters, anglers and wildlife watchers contributed over $30 million to Cody’s economy in 2010-2011. Let’s not 

forgo a sustainable source of jobs and income based on a recreation economy for one 

that is not sustainable—the key is to find the proper balance in both. 

We are pleased that you chose to hold this hearing so early in the 113th Congress 

and look forward to finding the ‘‘sweet spot’’ where energy development and natural 

resource conservation can coexist. The sportsmen-conservation community has extensive experience in this area and we believe TRCP and its partners can help Congress navigate this new opportunity and chart the course for a strong domestic energy supply that is balanced with the needs of fish, wildlife, and sportsmen. 

We look forward to working with Congress and the Obama Administration on this 

endeavor. 

Sincerely, 

WHIT FOSBURGH, 

President and CEO. 

FACTS FOR FISH AND WILDLIFE

ENERGY DEVELOPMENT RECOMMENDATIONS FROM THE THEODORE ROOSEVELT

CONSERVATION PARTNERSHIP

Energy and our ability to access affordable, reliable fuel and electricity are fundamental to the American way of life. All forms of energy, oil, natural gas, coal, wind, 

solar, geo-thermal and nuclear energy must be transported via pipelines or transmission lines. These two realities pose challenges for energy development and natural resource management. Energy production and transmission have been controversial for a long time in America, and in 2013 we still have no comprehensive 

policy that drives energy production and transmission. As a result, both have followed a scattershot approach, often based around variables such as markets, investment, permitting and access instead of a national strategy. One consequence of this 

approach is a great underestimation of how energy production and transmission affects fish, wildlife and outdoor recreation, often to the detriment or exclusion of 

these values and resources. Sixty-seven percent of U.S. lands are privately owned. 

In the West, the division of private and public lands is about 50/50 with some states 

like Nevada (81%) and Utah (63%) being mostly publicly owned. Because wildlife 

does not understand or respect artificial boundaries like state or property lines, it 

is imperative that lands be managed across boundaries. 

Traditionally, conservation and sportsmen organizations with a stake in energy 

issues have focused on public lands, and rightfully so, as those lands are held in 

trust for all Americans and are mandated to provide multiple-use, sustained yield 

for many values, including fish and wildlife. But as our need for expanded energy 

resources (particularly renewable energy) and transmission capacity increases, the 

impetus for managing fish and wildlife throughout all lands—regardless of ownership—is increasing as well. Good stewardship and conservation benefit both public 

and private lands, and management recommendations for fish and wildlife on public 

lands can easily be adopted on private lands. 

As part of our Passport for Responsible Development, the TRCP has created the 

‘‘FACTS for Fish and Wildlife,’’ specific recommendations for balancing fish and 

wildlife needs with the development of energy resources. First released in 2006, this 

revision updates those recommendations, expands their applicability to broader geographic regions and private lands, and addresses forms of energy development beyond traditional oil and gas. The ‘‘Passport for Responsible Energy Development’’ 

will allow for better fish and wildlife stewardship through better policy and management during energy development. 

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The FACTS recommendations are applicable, with a few exceptions, to land and 

water, traditional or renewable energy, public or private lands, and infrastructure 

associated with development. They can increase our ability to responsibly manage 

fish and wildlife during energy development, balance competing values, become conservation stewards and ensure a future for our fish and wildlife populations. These 

practices-driven by the FACTS—will sustain and uphold our nation’s shared natural 

resources and unique outdoor legacy. 

The TRCP supports and promotes responsible energy development that balances 

land and resource values that sustain fish and wildlife populations and maintain 

opportunities for hunting and fishing. Our work is guided by the TRCP Fish, Wildlife and Energy Working Group (FWEWG), a team comprised of representatives of 

our conservation partner organizations, and a staff of experienced wildlife and policy 

experts. By combining the science-based expertise of the FWEWG with an active 

network of sportsmen, the TRCP Center for Responsible Energy Development is 

working with hunters and anglers throughout the country to conserve our outdoor 

traditions by supporting a balanced approach to energy development and the management of fish and wildlife resources. 

Too often, sportsmen’s voices are not heard when energy policies are being decided 

or when development is implemented. The Theodore Roosevelt Conservation Partnership believes that if the principles contained in this ‘‘Passport for Responsible 

Development’’ are followed, the management of fish and wildlife habitats will be improved and American sportsman will be given a voice, thereby resulting in the conservation of millions of acres of wild spaces that fish and wildlife need and that 

hunters and anglers cherish. 

Join Hunters and Anglers for Responsible Development, a free grassroots movement that will add your voice to those of other sportsmen and -women nationwide. 

Speak up to ensure your values are integrated into energy development on your 

public lands. For more information about how join the TRCP go to our website, 

www.trcp.org, or call 202-639-TRCP. 

(F) Funding 

Successful fish and wildlife management requires adequate funding. Traditionally, 

fish and wildlife programs are underfunded or rely on funding sources other than 

federal monies. While funding alone will not solve the problem, it plays a critical 

role in our ability to balance energy development with the needs of fish and wildlife. 

Funding must be secure, substantial and properly allocated to make a difference. 

F.1 Determine adequate funding for sustainable fish/wildlife management, including monitoring, in areas proposed for energy development. 

F.2 Prior to development, identify and secure appropriate funds for fish/wildlife monitoring and mitigation, including compensation if necessary or required. 

F.3 Establish a long-term, dedicated ‘‘mitigation trust’’ to benefit fish/wildlife 

that is funded by royalties, rents, fines or voluntary payments. 

F.4 Ensure that funds designated and intended for fish/wildlife management 

are not redirected to other causes. 

F.5 Work cooperatively with various funding sources to leverage additional 

federal or state grants. 

(A) ACCOUNTABILITY 

Doing what you said or promised defines accountability. It also entails accepting 

responsibility for actions that you may or may not have taken. On public lands, 

promises are made through various decision strategies and should be considered 

‘‘contracts with the people’’ that mandate proper stewardship of the nation’s lands 

and minerals. On private lands, accountability increases trust, enabling projects to 

transcend conflicts that can delay or stop development. 

A.1 Proactively address fish/wildlife management and needs with a specific 

‘‘Conservation Strategy’’ for each energy field or project. Finalize strategies before development starts, specify recommendations and actions to minimize impacts and establish plans for mitigation, detailed monitoring and adaptive management. 

A.2 Establish and update regularly a system of tracking commitments, in 

plans or agreements, along with any actions contrary to those commitments. 

A.3 Ensure that laws, regulations and policies intended to conserve and protect fish/wildlife during energy development are not abdicated or abridged. 

A.4 Utilize lease development plans or master lease planning to evaluate and 

address potential impacts prior to development. 

A.5 Notify the public and allow comment on development projects involving 

public lands or resources. Provide the public with information on modifications 

to current development plans. 

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(C) Coordination 

Energy development and natural resource management do not occur in a vacuum. 

Coordination is essential in ensuring that fish and wildlife are properly managed 

between boundaries. All stakeholders must be involved, and experts that manage 

fish and wildlife at the local, state or national levels must be included in energy 

project planning and implementation. Coordination enables us to address unanticipated actions that arise. A key stakeholder in public lands and fish and wildlife resources, the public must be included to build trust and brainstorm tactics. 

C.1 Foster broad-based coordination between fish/wildlife managers, landowners and affected stakeholders to ensure fish/wildlife sustainability. 

C.2 Establish expanded coordination across geopolitical boundaries between 

property owners (public and private). Ensure that managers consider the movement corridors of fish/wildlife. 

C.3 Coordinate among all affected stakeholders during planning and implementation of public-lands energy projects. 

C.4 Include state fish/wildlife agencies in energy development planning and 

monitoring of fish/wildlife during/after development. C.5 Establish a process for 

annual review and adjustments of actions that affect fish/wildlife. An adaptive 

management strategy is appropriate if based on established adaptive management guidelines and science. 

(T) Transparency 

‘‘There is no disinfectant like sunshine.’’ That statement was used to describe how 

transparency can avert undesirable activities, particularly in the public interest. 

Transparency is essential to building trust among stakeholders. Transparency can 

prevent unnecessary delays, stoppages or bad press. Openness during energy development enables fish and wildlife management that benefits all stakeholders, not 

just project proponents. 

T.1 Identify ‘‘Special Places’’ with exceptional resource concerns or values 

where energy development should not be allowed. Map these places and incorporate these values into management plans. 

T.2 Provide up-to-date information through a range of media and informational outlets to the public and fish/wildlife managers for energy development 

projects. 

T.3 Guide leasing/development by complete and up-to-date baseline information on fish/wildlife resources and by coordinated plans for energy development 

and fish/wildlife management. 

T.4 Provide the public with information about all proposed public lands energy leases and development; allow sufficient time for public comment. 

1T.5 Make all meetings related to public-lands use and energy development 

part of the public record. 

(S) Science 

Science is the foundation of good land and resource management. It is essential 

to understanding how fish and wildlife react to energy development and maintaining sustainable populations during and after development. Utilizing known science 

enables a balanced approach that sustains energy AND fish/wildlife instead of energy OR fish and wildlife. 

S.1 Utilize science in all fish/wildlife decisions, particularly when specific research has been conducted on the impacts of energy development. Assure that 

mitigation and monitoring based on new scientific information is implemented 

in the energy development process. 

S.2 Incorporate science-based mitigation, using tested and proven methods of 

adaptive management, when making decisions about fish/wildlife management 

and energy development. Identify and address ‘‘gaps’’ in science prior to development and implement coordinated research to address these gaps. 

S.3 If necessary, utilize a third-party review of development and mitigation 

proposals. 

S.4 Establish a credible and qualified ‘‘science review team’’ and engage 

science-based organizations for fish/wildlife management and development decisions. 

S.5 Establish a process to incorporate new information/science into planning/ 

implementation of existing and new energy projects. 

A new Strategy for Managing Fish and Wildlife 

Managing for impacts before they occur could help conserve some of the species 

at risk from the current energy boom. The TRCP Fish, Wildlife and Energy Working 

Group recommends that a ‘‘Conservation Strategy’’ for resources be required before 

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development begins. This would identify/direct management in coordination to provide a balanced approach. It also would allow stakeholders more involvement, incorporate the latest science and future information, provide for sustainable fish/wildlife, and help produce domestic energy with less conflict. 

The basic elements of a Conservation Strategy are: 

1. Identification and protection of special places where development should 

not occur, or be significantly restricted. 

2. Establishment of baselines for resources and values for which all future development and mitigation will be compared. 

3. Creation of specific plans showing how fish, wildlife, water and sporting 

recreation will be maintained during all phases of development, including minimum value levels and impact thresholds. 

4. Coordination of development with the management of fish, wildlife, water 

and sporting recreation using adaptive management. 

5. Establishment of monitoring protocols before development begins, coordination of monitoring with state fish and game agencies, and commitment of adequate funding for completion of monitoring. 

6. Creation of mitigation plans for affected resources and values, implementation plans for mitigation actions based on adaptive management plans, and the 

creation of a mitigation trust to ensure adequate funding for mitigation activities. 

7. Establishment of research protocols to address unknown resource impacts 

and to provide input to adaptive management programs. 

8. Confirm a schedule of annual meetings to plan development scenarios, address impacts and incorporate adaptive management. 

9. Commitment to protective stipulations and other restrictions for protecting 

and sustaining fish, wildlife, water and sporting values. 

10. Development of a process to share information/data including publishing 

science, stakeholder involvement, and integrating new science and information 

into future plans, actions and management. 

Species Spotlight—Sage Grouse 

Sage-grouse are synonymous with the expanses of sagebrush prairies in the West 

and have been a favored game bird for Western hunters for generations. Human alteration of sage habitats for more than 100 years has reduced grouse populations, 

and there are now less than half the number encountered by early western settlers. 

Sage-grouse behavior is negatively affected by the increased level of development 

from drilling and energy production. This fact is confirmed by a growing body of research on the impacts to sage-grouse, which have experienced an approximately 80% 

decline in the Powder River Basin of Wyoming. Breeding activity is reduced because 

sage-grouse males are likely to abandon key display grounds within four miles of 

active drilling. Young birds do not return to sites with heavy development activity, 

suggesting that populations will not sustain themselves near active well fields. 

Sage-grouse populations are affected by other factors like drought and human disturbance, but managers cannot ignore or discount the impact we create by developing energy resources. To complicate matters further, wind power is now proposed 

on many of the remaining core sage-grouse habitats, and it is unknown how sagegrouse will react to this new threat. 

In 2010, the U.S. Fish and Wildlife Service determined that the sagegrouse deserved protection under the Endangered Species Act (ESA) but was found to be ‘‘precluded from listing’’ by higher priority species. This move effectively makes the bird 

a ‘‘candidate’’ species and efforts are now under way from the western states and 

federal resource agencies to address the deficiencies that will prevent the bird from 

being listed under the ESA. There is also a push by some advocates to stop hunting 

sagegrouse in states that still have healthy and viable populations in a misguided 

attempt to address the declines even though the biggest threats are to habitat and 

the ability of the BLM to manage energy operations in occupied sage-grouse habitat. 

Research in the Powder River Basin and the Upper Green River Basin has shown 

that large blocks of undisturbed sage habitat are necessary to sustain sage-grouse 

populations. Scientists predict that sage-grouse will disappear from developed areas 

unless some key habitats are protected. If we lose the ability to hunt sage-grouse 

or have the species listed under the ESA, the bird will lose one of the biggest advocates they have -American sportsmen. 

Species Spotlight: Mule Deer 

Mule deer, icons of western big game hunting, are declining in many parts of their 

range due to changes in land use, drought, predation, disease and periodic severe 

winters. Accelerated energy development that is reducing irreplaceable, critical winVerDate Nov 24 2008 16:28 Apr 01, 2013 Jkt 000000 PO 00000 Frm 00187 Fmt 6601 Sfmt 6621 G:\DOCS\80132.TXT 80132
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ter range could spell disaster for existing populations. The most significant effects 

are not seen on the land at drilling sites (which can be reclaimed), but are caused 

by the trucks, personnel, equipment, roads and facilities that displace wintering 

mule deer. This is evident on the Pinedale Anticline natural gas field called the 

‘‘Mesa’’ outside of Pinedale, WY where mule deer populations have declined approximately 60% in the decade since intensive development began. The threats to mule 

deer range from heavy gas drilling and industrialization of the southwestern portion 

of Wyoming to the more dispersed, but pervasive, coal bed methane development in 

the Powder River Basin of Montana and Wyoming. New development from southcentral Wyoming to Colorado and Utah affects deer from the Red Desert, Sierra 

Madre, Piceance Basin and Book Cliffs. 

These impacts are most often felt in prime hunting destinations—public lands 

where multiple-use mandates are supposed to guarantee sportsmen that their wildlife will be sustained. Recent analysis conducted by the TRCP shows a dismal level 

of coordination between federal land management and state wildlife agencies, making the tough job of managing habitats to meet population objectives much harder. 

Combined with severe winters (like 2010-2011), other pressures on habitats, the increased risk of poaching and inadvertent road killing, mule deer populations are in 

significant risk. Energy development could further reduce already declining populations unless federal agencies and industry make changes to current energy development processes. When mule deer lose crucial habitats, sportsmen are at risk of 

losing access, opportunities and their hunting traditions. 

Identification of Special Places 

All landscapes and habitats are not created equal, nor do fish and wildlife utilize 

habitats in the same way. The same can be said of sportsmen. There are places that 

provide such unique, important, sensitive or extraordinary values that energy development should be restricted or significantly limited. The TRCP calls these areas 

‘‘Special Places’’ and recommends that during responsible and balanced energy development these areas be identified and protected. The following criteria are recommended for identification and inclusion into special places, but each part of the 

country will be different and affected stakeholders (including state wildlife agencies, 

NGO’s, sportsmen, and landowners) should work together to identify areas before 

the commitment to development begins. 

CATEGORIES 

1. Areas where no development takes place because of extremely important 

resources or values, where energy development would irreparably harm those 

resources, and where no mitigation or compensation could replace their loss or 

degradation. 

2. Areas where development would be restricted to avoid or minimize impacts 

to important resources and where impacts could be mitigated or compensated 

for so that no net loss is achievable. 

CRITERIA 

1. Area of concern provides significant recreational opportunity (hunting/fishing) and is a major component of a local economy. The term ‘‘World Class’’ may 

be used to describe this resource. The ‘‘World Class’’ designation would indicate 

that quality of the hunting or fishing experience could not be matched anywhere 

else in the world. 

2. Area of concern is a designated wilderness, a wilderness study area, currently a roadless area, or provides significant wildlife habitat that is not impacted by motor vehicle access. 

3. Area provides irreplaceable and substantial habitat for one or more game 

animals or fish at least during one season of the year and is considered a limiting factor in species population management. 

As a nation, we have come to expect energy awareness and conservation from corporations but sometimes forget that individuals also play a big role. Sportsmen and 

-women are leaders in fish and wildlife conservation and it’s no surprise that they 

are stepping up as leaders in energy conservation as well. Here are five simple steps 

every sportsman can take to reduce their demand for energy, save money, improve 

their experiences and ensure they have less impact on our fish, wildlife and water 

resources as they pursue their passions in the great outdoors. 

Æ