OIL & GAS nov 2012

November 2012

INSIDE

• Utica shale update

• Corporate governance

• 3Q deals total $50 billion

• OGJ150 quarterly report

• Special Report: ETRM

Building a newMagnum Hunter

Previous Page | Contents | Zoom in | Zoom out | Front Cover | Search Issue | Next Page qqM

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Qmags®THE WORLD’S NEWSSTANDOF


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Visit our Unconventional

Resources Center on OGFJ.com

E&P companies are shifting budgets to

high-BTU, liquid-rich plays. Bentek’s

Rusty Braziel provides expert analysis.

Go to www.ogfj.com <http://www.ogfj.com/> and click Unconventional Resources

C A N A D A

M E X I C O

Avalon, Bone Spring

Bakken

Niobrara

Granite Wash

Eagle Ford

Marcellus SW Penn.

Where are the high BTU plays?

North American shale plays such as

the Eagle Ford, Barnett, Haynesville,

Marcellus, Bakken, and Woodford are

all noteworthy formations, but unconventional

resources include more than shale. They also

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and heavy oil.

Shale resource plays, lower 48 states

Find shale rankings, top producers, the latest

shale news, and YES, we have maps!

Get up-to-date information on the most

talked about formations in the unconven-

tional resources space –– all in one place.

Reports from Don Warlick of Warlick Inter-

national provide insight into the top 5 US

shale plays and the 7 factors driving the

shale business.

Take a photo with

a QRcode app!


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November 2012

INSIDE

• Utica shale update

• Corporate governance

• 3Q deals total $50 billion

• OGJ150 quarterly report

• Special Report: ETRM

Building a newMagnum Hunter

Contents | Zoom in | Zoom out Search Issue | Next PageFor navigation instructions please click here

Contents | Zoom in | Zoom out Search Issue | Next PageFor navigation instructions please click here


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Responsibility is

part of our DNA

Underground shale formations may

reduce the U.S. dependence on imported

oil and gas. But developing these resources

commands respect and responsibility for

the local communities and the environment.

We are committed to keep implementing

technologies that meet the toughest

efficiency and safety standards, today and

in the future. For us, it’s a question of never

being satisfied.

Discover more at neversatisfied.statoil.com

Always improving

Never satisfied


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Oil & Gas Financial Journal® (ISSN: 1555-4082) is published 12 times per year, monthly by PennWell, 1421 S. Sheridan Rd., Tulsa, OK 74112. Periodicals Postage Paid at Tulsa, OK, and addi-tional mailing offices. POSTMASTER: Send address changes to Oil & Gas Financial Journal, 1421 S. Sheridan Rd., Tulsa, OK 74112. Change of address notices should be sent promptly with old as well as new address and with ZIP or postal code. Allow 30 days for change of address. Copyright 2012 by PennWell. (Registered in US Patent & Trademark Office.) All rights reserved. Permission, however, is granted for libraries and others registered with the Copyright Clearance Center Inc. (CCC), 222 Rosewood Drive, Danvers, MA 01923, Phone (508) 750-8400, Fax (508) 750-4744, to photocopy articles for a base fee of $1 per copy of the article, plus 35 cents per page. Payment should be sent directly to the CCC. Federal copyright law prohibits unau-thorized reproduction by any means and imposes fines up to $25,000 for violations. Requests for bulk orders should be sent directly to the Editor. Back issues are available upon request.

November 2012 Oil & Gas Financial Journal • www.ogfj.com 1

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CONTENTS10

COVER STORY: Magnum Hunter Resources talks to

OGFJ about its various shale play posi-

tions, its involvement in the water needs

and transportation side of the business,

as well as possible monetizations.

17 ETRM The use of commodity derivatives

can mitigate or remove oil or gas

price uncertainty as one of the

fundamental industry variables.

26 Oilfield Service CosOil companies expect that

investments made in an in-

house service company will be

lower than the expenditures to

be paid for the services of inde-

pendent contractors. However,

is this assumption correct?

30 Utica vs. Eagle FordThe Utica Shale, nearly equal

to the size of the Eagle Ford,

could become the third-largest

shale play in the US, producing

as much as 250,000 to 500,000

b/d. The play’s potentially

recoverable reserves could

range from 3.75 TCF of gas and

1.31 billion barrels of oil to 15.7

TCF gas and 5.5 billion barrels

of oil. Here, a brief comparison

and update on the play’s

activity.

34 OGJ150Revenue takes 20% dip, income

down 10% in 2Q2012.

ON THE COVER: Magnum Hunter Resources

chairman and CEO Gary Evans.

5 Editor’s Comment

6 Capital Perspectives

8 Upstream News

32 Deal Monitor

42 Industry Briefs

45 Energy Players

48 Beyond The Well ▶

V9/#11


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QUICK RESPONSE CODES ▲You’ll notice we’re featuring more QR codes on our pages. This 2D barcode marries the

printed magazine you rely on with ever-evolving technology – in this case, digital media and

the proliferation of smart phones. Download a reader to your smart phone, snap a picture of

the code, and voila – your browser automatically directs you to our website. There you’ll fi nd

all the energy industry information you’ve come to expect from Oil & Gas Financial Journal.

DEAL MONITOREach month, OGFJ teams up with PLS Inc. to provide a spreadsheet of the latest M&A

transactions in the global energy industry along with incisive analysis about the signifi -

cance of the deals.

GET SOCIAL!In addition to OGFJ.com, fi nd us on Twitter (@OGFJ) and join the Oil & Gas Financial

Journal group on LinkedIn. Follow along with other petroleum industry managers, ana-

lysts, and investors looking for credible, useful information about oil and gas industry

developments and join the discussion today!

BUSINESS OPERATIONS NEWSLETTERFrom tax and accounting to software and government regulations—OGFJ’s Business

Operations newsletter has you covered. Sign up to receive our newest electronic news-

letter today at ogfj.com/subscribe/enewsletter-subscribe.

FEATURED STORIESFind something new on OGFJ.com

every day. Read about the possible

impact of NGL production volumes on

shale development, tax vs. trading in

reducing pollution, the movement of

MLP structures into riskier commodity

price exposure, and more. Plus, get

the latest on management changes at

Zion, Baker Hughes, and more.


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In today’s environment, opportunities are gone as

quickly as they appear. Very few organizations have

the resources to stay current with developing trends

as well as proven reservoirs. Many organizations are

forced to make quick decisions about opportunities

in reservoirs they may not fully understand.

NuTech Energy Alliance works with investors and

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faster decisions resulting in earlier commercial

returns.

NuTech provides the resources and a database of

comparative knowledge to significantly impact our

client’s decision-making process.

NuTech has spent the past 15 years developingthe tools to interpret them.

© 2012 NuTech Energy Alliance Ltd.

www.nutechenergy.com

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Unconventional Reservoirs��


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®

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November 2012 Oil & Gas Financial Journal • www.ogfj.com 5November 2012 Oil & Gas Financial Journal • www.ogfj.com 5

Editor’s Comment

Don StowersEditor-OGFJ

Elections have consequences

This month’s column continues the theme we started in the October issue in which we dis-

cussed political and regulatory risk in the petroleum industry. In the United States, this type of risk often can be minimized or increased, depending on which party is in control of the government.

Generally speaking, the Republi-can Party is seen as pro-business and against excessive government regula-tion, so regulatory risk likely would be reduced in an environment in which the GOP is in power, particularly in the executive branch.

In general, the Democratic Party is viewed as pro-environment and in favor of greater regulation to protect the environment. A president with this mindset is widely seen as someone who would increase regulatory risk, particularly for an industry like coal or oil that exploits our natural resources.

At this writing, the US has not yet held its general election. It’s too late for me to try to persuade anybody how to cast their vote, but I wouldn’t anyway. I prefer to let people make their own informed decisions on politi-cal candidates and keep my nose out of their business. However, I do have some thoughts, which I’ll discuss here.

On Nov. 6, the US elects a president for the next four years. In addition, voters will choose all 435 members of the House of Representa-tives and one-third of the US Senate. The offi cials in these two branches of government determine regulatory

policy for the US energy industry. The Constitution mandates that the legislative branch makes the laws, and the executive branch implements and enforces them. At least that’s how it’s supposed to work. In practice, the executive branch has tremendous power over how the rules are set in place and enforced.

As an example, President Nixon signed a bill in 1970 creating the Envi-ronmental Protection Agency. The EPA was given the responsibility to protect human health and the environ-ment by writing and enforcing regula-tions passed by Congress. Most of us would agree this seemed like a positive development at the time. Few people who were around in 1970, including Nixon, could have imagined what a colossus the EPA has become. Today,the EPA employs more than 17,000 people and hires many more on a con-tractual basis. Its annual budget has grown to nearly $8.7 billion.

For Republicans who want to paredown the size of government, the EPAis an example of a government agency that has gotten too big for its britches and overstepped its charter. For people in the oil and gas industry, the EPAputs up unnecessary roadblocks that prevent them from drilling for and producing the hydrocarbons that keep our country running. This is apparent in the current lack of drilling activity on federally-owned land in the West-ern US and in Alaska. Statistics show that even though drilling activity is up substantially in the US since that time, it has declined around 11% on federal lands.

Many feel that if the regulatoryleash were removed, we could drill our way out of our dependency on foreign oil imports and begin the process of exporting liquefi ed natural gas, or LNG. The US has an abundance of

natural gas reserves, and we recently passed Russia as the world’s top producer of natural gas. But, unlike Russia, we are not yet a major exporter of natural gas. In order to become an LNG exporter, the industry needs to invest billions of dollars in infrastruc-ture, and we need to do it yesterday.Timely government approval of the projects is critical, so we need a gov-ernment that understands this and is prepared to act. There is no time for environmental studies that take years to complete. LNG export facilities must be put on the fast track.

Currently, Republicans hold a 50-vote majority in the House. In the Senate, Democrats have a 53 to 47 edge, and we have a Democratic presi-dent. If Democrats retain control of the White House and the Senate, and the GOP holds the House, it is likely a stalemate will continue with respect to legislation. In other words, we’ll maintain the status quo.

In this situation, the president wields enormous power. Case in point: In the aftermath of the April 2010 Macondo well disaster in the Gulf of Mexico, the president chose to shut down all offshore drilling activity in the Gulf for many months while the causes of the blowout were investi-gated. Many in the industry cried foul, especially those who had a spotless safety record. In response, the admin-istration imposed stricter regulations and more red tape before drilling permits were granted.

During the drilling moratorium, companies and employees sufferedeconomic hardships at a time when the country was still immersed in a recession. More than a few companies were forced to fi le for bankruptcy. So were a few individuals. We have to ask ourselves: Would another administra-tion have handled this differently?


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Capital Perspectives

6 www.ogfj.com • Oil & Gas Financial Journal November 2012

Corporate governance in the news

It is a commonplace of corporate law that offi cers and directors owe fi duciary duties to the business entities they serve. Breaches of these duties are most often

highlighted in the press when they lead to spectacular cor-porate failures on the order of Enron or WorldCom. But fi duciary duties do not exist solely to deter and redress massive instances of fraud; rather, as Justice Cardozo long ago held “[n]ot honesty alone, but the punctilio of an honor the most sensitive, is . . . the standard of behavior.”

Thus, a rule of undivided loyalty has arisen to ensure that the standard of conduct for fi duciaries is kept at a level higher than the morals of the marketplace or mere personal preference and expediency.

Most often, the duty of loyalty is impli-cated when a proposed act or transaction creates a confl ict between the personal inter-ests of an offi cer or director and the interests of the corporation. This might hap-pen when, for instance, a transaction is contemplated directly between the director and the corporation or between a corporation and another entity in which the director has an interest or from which the director will receive a benefi t.

As an example that has been much in the news of late, angry Chesapeake Energy Corp. shareholders have fi led lawsuits against founder Aubrey McClendon and other Chesapeake board members after learning that McClen-don had not only been granted participation rights in the company’s oil and gas wells but that he had also obtained up to $1.1 billion in loans to pay for his stake in those wells.

The lawsuits take aim, in particular, at McClendon’s relationship with and “loans” from EIG Global Energy

Partners, a private equity fi rm that participated in a transaction last year from which it reportedly obtained a $500 million preferred-stock interest in Chesapeake’s operations in Ohio’s Utica shale. One plaintiff alleges that “[s]uch huge loans raise serious confl icts of interest: they can easily cloud the CEO’s judgment on key issues rang-ing from how quickly Chesapeake should generate cash fl ow, to how it operates wells, to how aggressively it can bargain with EIG on fi nancing terms.”

In a case closer to home (and that the authors liti-gated), Dallas-based Longview Energy Corporation

sued its largest (yet a minority) shareholder, two directors placed on its board by that shareholder (a New Jersey-based private equity fund), and a sepa-rate company that those directors and others set up to compete with Longview.

The gist of Longview’s com-plaint was that the two board members directed Longview to pursue an invest-

ment in the South Texas Eagle Ford shale play, offered to fi nance it, and then—after Longview devoted consider-able resources to an analysis of the play—surreptitiously took Longview’s investment playbook to a new company that they formed, controlled, and essentially owned out-right.

Just this month, a Zavala County jury found that the two directors had breached their fi duciary duties to Longview and that the two companies aided-and-abetted that breach. As a consequence, a judgment of $162 mil-lion is expected to be entered, as well as an order transfer-ring tens of thousands of acres of producing and undevel-oped oil and gas leases to Longview.

The teaching point here is a simple one. A direc-

Craig Florence and Randy Gordon, Gardere Wynne Sewell LLP, Dallas


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Capital Perspectives


tor breaches his duty of loyalty if he takes a corporate opportunity for himself or unfairly competes with the corporation to which he owes a duty. And because a busi-ness entity can function effectively only if its offi cers and directors can be counted on to hold the entity’s interests paramount, the remedies for breach of fi duciary duty are uncompromising.

None of this should deter would-be directors from serving on corporate boards because confl icts of the type that gave rise to the Longview case can be easily man-aged. For example, Delaware law (which is the legal home of nearly a million business entities) allows directors to serve more than one master by inserting an appropriate waiver in a company’s certifi cate of incorporation or by making informed, advanced disclosure of a proposed act and receiving advanced board approval for that act. In this way, both the corporation and its directors will know the ground rules before a confl ict can arise.

A director’s job is to maximize the value of the com-pany she serves, and she can’t ordinarily do that well if she serves in another venture operating in the same domain. And she can’t even conceivably do that consis-tent with her duty of loyalty, if she tries the move without

the permission of the company. Were the rules otherwise, we would quickly see a return to 19th century robber-baron “ethics,” in which offi cers and directors skimmed all corporate cream for themselves and left thin water for ordinary investors. OGFJ

Craig Florence, cfl orence@gar-

dere.com, and Randy Gordon,

[email protected], are

partners in the Dallas offi ce of

Gardere Wynne Sewell LLP.

“The teaching point here is a simple one. A

director breaches his duty of loyalty if he takes

a corporate opportunity for himself or unfairly

competes with the corporation to which he

owes a duty. And because a business entity

can function effectively only if its offi cers and

directors can be counted on to hold the entity’s

interests paramount, the remedies for breach of

fi duciary duty are uncompromising.”

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Upstream News

Chevron encounters 220 ft of net gas pay with latest offshore Australia fi nd

An Australian subsidiary of Chevron Corp. has made another natural gas discovery in the GreaterGorgon Area, located in the Carnarvon Basin,

offshore Western Australia.The fi nd follows on the heels of a previous natural gas

discovery in the area in July of this year when the Pon-tus-1 exploration well encountered approximately 97 feet of net gas pay.

In this latest discovery, the Satyr-4 exploration discov-ery well confi rmed approximately 220 feet (67 meters) of net gas pay. The well is located in the WA-374-P1 permit area approximately 75 miles (120 kilometers) northwestof Barrow Island, off the Western Australian coast. The well was drilled in 3,570 feet (1,088 meters) of water to a total depth of 15,023 feet (4,579 meters).

Melody Meyer, president, Chevron Asia Pacifi c Explo-ration and Production Company, said, “Satyr-4 furtherunderscores Chevron’s continuing success in this prolifi cblock and supports our long-term growth plan for the Gorgon Project, and our goal to be a leading LNG sup-plier to the Asia Pacifi c region.”

Chevron Australia is the operator of WA-374-P with a 50% interest while Shell Development (Australia) Pty Ltd and Mobil Australia Resources Company Pty Limited each hold 25%.

Marathon Oil enters Ethiopia

Marathon Oil Corp. subsidiary, Marathon Ethio-pia Limited BV, has entered into a sale and pur-chase agreement with Agriterra Ltd. to acquire

its 20% working interest in the South Omo concession in Ethiopia. The companies expect to close the transaction, subject to completion of the necessary Ethiopian govern-ment approvals, before the end of the year.

Tullow Oil is the operator of the South Omo conces-sion with a 50% working interest, and Africa Oil holds the remaining 30% working interest. The concession has an area of approximately 7.2 million gross acres (29,465 gross square kilometers). An exploration well is antici-pated to spud in South Omo in the fourth quarter of 2012.

In consideration for the assignment of these interests, Marathon Oil will pay Agriterra $40 million, before clos-ing adjustments, with an additional payment of $10 mil-lion due upon Marathon Oil’s participation in a declara-tion of a commercial discovery.

“This acquisition is a strong addition to Marathon Oil’s position in the Tertiary rift trend onshore East Africa and is on trend with the recent Ngamia-1 discovery in

Kenya,” said Annell Bay, Marathon Oil vice president,Global Exploration.

Gazprom Neft, TNK-BP report fi rst oil from Messoyakha fi eld

Gazprom Neft and TNK-BP reported that fi rstoil has been produced by the pilot project at the Vostochno-Messoyakhskoe fi eld. The infl ow

received from the fi rst two development wells points to the fi eld’s high potential. The project is being imple-mented by Messoyakhaneftegaz, Gazprom Neft and TNK-BP’s joint venture controlled by the two companies on a parity basis.

A more accurate assessment of reservoirs and well fl owrates will become available in 2014 upon completion of a series of production tests. According to the preliminaryestimate, production from the fi eld’s main reservoir will peak by 2022-2023 at 10 million tons of oil and 5 billion cubic meters of gas.

In 2012, the total investment into development of the Vostochno-Messoyakhskoe fi eld reached about $140 million. The work completed at the fi eld included the drilling of four E&A wells and two clusters of pilot wells. Next year, Gazprom Neft and TNK-BP will boost projectinvestments to $240 million, continue exploration and appraisal activities, drill new wells under the pilot produc-tion program, prepare design documents and construc-tion sites, and begin infrastructure development. In addi-tion to that, Gazprom Neft, the project’s operator, has joined forces with Halliburton to come up with a concep-tual framework for the development of the Messoyakha fi elds group. Full-scale production in these areas will startupon completion of the construction of the Zapolyarye–Purpe trunk oil pipeline.

“By creating a new production cluster in the north of Yamal, Gazprom Neft is consistently implementing its strategic production increase plans. The Messoyakha pilot project will help us get a clearer picture of the reservesand area profi les in preparation for development of one of the country’s largest oil and gas fi elds. I am positive that, with requisite state support, Gazprom Neft and TNK-BP will continue to invest into development of the north-ern territories seeking to begin full-scale production at Messoyakha,” said Vadim Yakovlev, Gazprom Neft First Deputy General Director.

“Commencement of Messoyakha pilot production is a critical stage in long-term development of Yamal as a new petroleum province. The expertise and technologiescontributed to the project by the TNK-BP/GazpromNeft partnership have already yielded the fi rst importantresults. Continued success of the Messoyakha projectdepends on effi cient interaction with the state in creating


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Upstream News

the necessary transportation and production infrastruc-ture and a favorable tax regime to assure considerable increase of hydrocarbon production in this region of strategic importance for the Russian oil and gas industry,”noted Mikhail Slobodin, TNK-BP executive vice presi-dent, Strategy and New Business Development.

CNOOC Ltd. sees production from New Beibu Gulf oil fi elds

CNOOC Ltd. announced October 19 that two new oil fi elds, Weizhou 11-2 and Weizhou 6-9/6-10, successfully commenced production.

Weizhou 11-2 oil fi eld, located in Beibu Gulf in the South China Sea with an average water depth of about 35.4 meters, currently has four producing wells. This oilfi eld was designed to share the existing facilities of Weizhou oil fi elds group in production to achieve the low-cost oil fi eld development and hit its peak productionof approximately 3,960 barrels per day in 2012.

Weizhou 6-9/6-10 oil fi eld is located in Beibu Gulf in the South China Sea with an average water depth of about 32.5 meters. The development and production operations of this oil fi eld primarily rely on the facilities of its surrounding oil fi elds. Currently with nine producingwells, Weizhou 6-9/6-10 is expected to hit its peak pro-duction of approximately 5,870 barrels per day in 2013.

Weizhou 11-2 and Weizhou 6-9/6-10 are both inde-pendent oil fi elds. The company holds 100% interest and acts as the operator of the two oil fi elds.

Confi dence returning to UK offshore sector

Drilling activity is reviving the UK offshore sec-tor, according to the latest North West Europe Review by Deloitte’s Petroleum Services Group.

The number of wells drilled in the UK sector during the fi rst nine months of this year is only 6% below the total for all of 2011.

Additionally, the number of transactions involving UK offshore oil and gas fi elds is already 5% above last year’s count. And the number of fi elds granted development approval in the UK this year has surpassed the total in 2011.

Although there was a decrease in the number of explo-ration and appraisal wells drilled in 3Q 2012 compared to 2Q 2012, the underlying trend is of greater stabil-ity, according to Graham Sadler, managing director of Deloitte’s Petroleum Services Group.

“We’re still not seeing pre-recession levels of activity,but there’s a defi nite feeling of some confi dence coming back to businesses operating in the UK continental shelf,” he said.

New fi eld allowances introduced by the governmentthis year, including the shallow water gas allowance, arestarting to deliver benefi ts, and the government’s plans to create more certainty around decommissioning tax reliefshould stimulate further interest in the sector.

“Along with a sustained high oil price, smaller and technically challenging fi elds continue to be a much moreattractive investment proposition than might have other-wise been the case,” Sadler said.

Seven new UK fi elds are online this year so far, com-pared to fi ve in 2011.

Drilling activity fell by 44% in offshore Norway duringthe third quarter compared to the same period last year,the review found, although activity has largely focused on appraising existing discoveries and exploiting major fi eldsas opposed to new well exploration and appraisal.

No new fi eld development approvals were issuedgranted by the Norwegian government during the thirdquarter, and there were no new production starts in this period.

TAQA, Antrim discover North Sea oil

Antrim Energy Inc. an international oil and gas exploration and production company headquar-tered in Calgary, Canada, has released preliminary

results of drilling operations from well 211/21-N94 (the Contender Well) in UK Northern North Sea Block 211/22a Contender Area (the Contender Block, Antrim interest 8.4%).

The Contender Well has been drilled to a total drilling depth of 16,903 feet (11,550 feet true vertical depth) by operator TAQA Bratani Ltd. (TAQA) from the TAQA-operated North Cormorant production platform. Prelimi-nary estimates indicate a net oil pay in excess of 60 feet was encountered in the Tarbert member of the Jurassic Brent sandstones, with greater than expected porosityand hydrocarbon saturation. The total Brent oil column exceeded 112 feet, with no water bearing sands identifi ed.Further reservoir evaluation is being undertaken. Should the discovery be commercial, the fi eld will be developed under the name ‘Cormorant East’ and production will be processed through the North Cormorant platform.

Under the terms of a farmout agreement (as previouslyannounced on August 25 2011), Antrim retained an 8.4% interest in the Contender Block. Other interests areTAQA 60%, Dana Petroleum (E&P) Ltd. 20%, First Oil Expro Ltd. 7.6% and Bridge Energy Enterprises Ltd. 4%. With the successful drilling of the Contender Well, TAQAalso earned a 35% interest in the adjacent Block 211/22a Kerloch Area, with Antrim retaining a 13.65% interest.


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Two roughnecks trip

pipe in Eagle Ford


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active, but that represents less than 10% of GreenHunter’s current business. Water is such a large issue in these uncon-ventional resource plays, and there are lots of different com-ponents to the business. We see a real need in the industry today and there is an opportunity for consolidation because most of the water business has been historically controlled by the “moms and pops” over the years and it is now a much larger, more sophisticated piece of the oil business today, and a necessary ingredient for shale exploitation success.

OGFJ: Is it still called GreenHunter Energy?

GE: Yes, we have a subsidiary called GreenHunter Water, but the parent company is GreenHunter Energy and it is publicly-traded on the New York Stock Exchange with a market capitalization of just under $100 million.

OGFJ: Where do you operate the water business, in the West or also in Appalachia?

GE: Appalachia is our biggest operating region, but we operate in fi ve states. We’re in West Virginia, Ohio, and Kentucky. We’re in South Texas in the Eagle Ford and the Mississippi Lime play in Oklahoma. We’re in the process of expanding to the Bakken.

OGFJ: Early in your career, weren’t you active in the energy banking industry?

GE: From 1977 to 1985, for about nine years, I was a banker in Dallas. I worked for two banks. One was National Bank of Commerce, which became BankTexas. It was a regional bank, and I went through the credit training program there and became a lending offi cer. Then I started up the energy division for the southwestern region for Mercantile Bank of Canada, out of Toronto, which I ran. We were an energy lender back when the big Texas banks were having all kinds of loan problems and capital issues. We were the new kids on the block with a clean portfolio, so we had a lot of opportunities to do some fairly innovative fi nancings. We were a US corporation, so we could take net profi ts interests, overrides, and other equity kickers at a time when there was virtually no lending. It was a really profi t-able division for our entire bank, both in the United States and Canada.

OIL & GAS FINANCIAL JOURNAL: Gary, in the 1990s you built an oil and natural gas company called Magnum Hunter. You subsequently sold it to Cimarex Energy in 2005 for $2.2 billion. Four years later, here you are building another Magnum Hunter Resources. What prompted your return to the oil patch?

GARY EVANS: When we sold Magnum Hunter back in 2005, I was bound by a two-year non-compete agreement that prevented me from doing anything in the oil patch here in the US until June of 2007. During that time, I got involved in green energy, and I also went to China and became involved in taking a number of Chinese companies public here in the United States on US exchanges through a broker dealer I started with a partner called Global Hunter Securities. So that was my primary focus for a few years. What really led me in getting back into the oil patch was the fi nancial debacle we all experienced in 2008. I was looking for a vehicle to get back into the business, and I found a little company in Houston that I felt could be used as that vehicle, so I took it over in May of 2009 and that’s what led to the new Magnum Hunter Resources Corporation.

OGFJ: Are you still involved in green energy?

GE: Yes and no. I’m still involved with GreenHunter Energy, but we completely changed the business model from an earlier portfolio of renewables. At the time I started that company, the focus was on wind, solar, biomass, biodiesel, and ethanol. We’ve gotten completely out of those busi-ness segments and sold them off one by one. Starting in late 2011, we became involved in the water side of the oil and gas business. The company was completely reconfi gured with a new business model and management team, and is growing quite rapidly. In many respects, it’s a sister company of Magnum Hunter. We handle most of Magnum Hunter’s water needs in the shale plays where Magnum Hunter is

EDITOR’S NOTE: Gary Evans has been racking up the

frequent-flier miles as he travels from one roadshow pre-

sentation to another telling investors and analysts about

his company’s successes and plans for the future. The

chairman and CEO of Magnum Hunter Resources recently

agreed to talk with us and share his company’s story with

our readers.

AN INTERVIEW WITH GARY EVANS, CHAIRMAN AND CEO OF MAGNUM HUNTER RESOURCES

Resource-rich Magnum Hunter

is drilling, building asset base Don Stowers, Editor, OGFJ


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OGFJ: No doubt this background in banking and fi nance proved helpful when you went into the oil and gas business.

GE: Financing is such an integral part of growing any business, but especially the oil and gas industry when all we’re doing is burning through capital, whether we’re drill-ing wells or making acquisitions. I think having a fi nance background gave me a bit of an edge. My fi rst entry into the business back in ’85 was a leveraged buyout of a well service company. So I got my hands dirty for about four years in the fi eld running a well servicing company during a really diffi -cult period in the industry, so that gave me some insight into

the interworkings of fi eld operations that some CEOs may not have today, especially guys with a fi nance back-ground.

OGFJ: You’re on the board of the Maguire Energy Institute at Southern Method-ist University in Dallas. Are you an SMU alum?

GE: I attended school at night here in Dallas at SMU while I was working at the two banks. My fi rst year of college was at California State-Fullerton. I’ve been very involved with SMU for years and did some periodic teaching over there for the MBA program. The Maguire Energy Institute is a group of successful oil and gas executives, and we meet about once a quarter. We do a lot to promote the industry, including energy clubs at SMU, and we often recruit SMU gradu-ates. SMU has some great programs designed for the energy industry. We help put together some of the classes for the fi nance curriculum, and a lot of the executives in the group teach there as well.

OGFJ: Let me ask you about your operations. Magnum Hunter has acquired large amounts of lease acreage in at least fi ve resource plays. Was your company an early entrant into these plays, a fast follower, or a latecomer?

GE: That depends on the play. We were an early entrant into the Eagle Ford and the Marcellus – at least in the areas of those plays where we are operating. The same exits for the Williston Basin. We’re the only US company involved in the Three Forks/Sanish/Bakken plays just north of the border in Saskatchewan. I would say the plays had already hit the radar screens, but the areas where we’re involved had defi nitely not. That’s why our acreage cost is typically quite a bit lower than what our competition have historically paid.

OGFJ: Is there a “sweet spot” in the Canadian Bakken?

GE: Well, Divide County is the county we’re most active in North Dakota, and it goes right up to the Saskatchewan border on the Canadian side. Believe it or not, the shale doesn’t know there’s a border there. We’re active in a fi eld called the Tableland Field, and we’ve been able to make the play very profi table for our company. We really like that area, and it has some unique attributes in that there is royalty relief from the provincial government of Saskatchewan. We only pay a 2.5% royalty on the fi rst 100,000 barrels of oil each well we produce, which means we have a 97.5% net lease. That allows us to generate much higher rates of return than paying a 20% to 25% royalty to landowners down in North Dakota.

OGFJ: Are your Bakken assets living up to your expec-tations so far?

GE: The Williston Basin is one area that we’re continu-ing to build acreage positions and actively drill. We made a large acquisition in May from Baytex Energy -- $311 mil-lion, which was mainly existing wells and acreage in Divide County, North Dakota. Today we have about 132,000 net acres, of which 92,000 is in North Dakota and 40,000 is in the Tableland Field. So we have more than 800 drilling loca-tions in the middle Bakken and Three Forks-Sanish and fi ve to seven drilling rigs running at any given time. That is a lot of future drilling.

OGFJ: Are you having any infrastructure problems with getting your product to market?

GE: In the Tableland Field, we take our crude to a cen-tral battery, and it’s pipelined into Enbridge. The pipeline goes directly across our property, and there is a refi nery up there in Saskatchewan. The North Dakota production is being sold at the wellhead, and it’s trucked to a railroad. We haven’t had any issues on getting our crude out. As you probably know, over the last 60 days, the basis differential for Bakken-Three Forks crude has changed dramatically. We’re now getting about a $2 premium over WTI.

OGFJ: The Eagle Ford is one of the most talked-about oil and liquids plays in North America. Do you view it as one of your core assets?

“We’re very happy with the asset base we’ve

built, but the stock market has been challeng-

ing. We’ve always felt that time would take care

of that if we continue to perform. And that’s

what we’re doing.” — Gary Evans


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GE: I would say that of all the shale plays we’re involved in, the Eagle Ford is the most mature for our company. We have more than 30 wells drilled and producing in the play, and we have a defi ned acreage position there. We have 26,000 net acres, and it’s been very diffi cult adding new acreage because the cost is so high due to the high degree of competitiveness. We have another 200 wells we can drill, but frankly we would consider divesting our holdings in this play for the right price. We’re exploring this possibility right now and have this particular property in a data room with an investment bank, and we’re talking to a number of different parties. It’s not something we have to sell. It’s not something we’re being forced to sell. It’s just that we see our upside as being defi ned. We’ve done about as well as we can do in this play with some of the highest producing wells throughout the entire Eagle Ford Shale. We’ve made signifi -cant improvements in the well completions, it is a “well-oiled machine”, and it might be better suited for someone with a lower cost of capital.

OGFJ: Have you had any issues with bottlenecks with regard to gas pro-cessing in the Eagle Ford since there is so much volume coming onstream right now?

GE: We’re predomi-nately crude oil. We’re 85% oil in the Eagle Ford, so we don’t have any of the issues that gas-weighted compa-nies might have in the play. There’s never been a day since we’ve been involved in this play that we’ve had an issue getting our oil or our casing head gas sold once tied into pipe. We’re currently producing about 3,000 barrels of oil per day in the Eagle Ford. It’s sold at a $10 premium over WTI prices. It’s sold under what is called “Louisiana Light,” and if the WTI price is $90, we get $100 for our oil today due to the basis premium.

OGFJ: Magnum Hunter is also active in the Pearsall play in South Texas. What can you tell us about your operations there?

GE: The Pearsall shale underlies the Eagle Ford and is about 1,500 to 2,000 deeper. It’s still very early on in this evolving resource play. We bought some acreage there and we have just drilled our fi rst Pearsall test well. To a large extent, the jury is still out on the Pearsall. Cabot Oil & Gas has been successful in convincing others that this is a great new play. They recently announced a transaction with a foreign entity on their acreage located near us. So we’re still looking at the

Pearsall as an emerging play but it is getting more interesting by the day.

OGFJ: Is the Pearsall a liquids-rich play?

GE: We believe it’s going to be more gassy with condensate. The negative side of it is that we believe the gas is going to have some H

2S associated with it, so there will have to

be specialized processing facilities. Fortunately we bought a company back in May through our midstream division, TransTex, that is a specialist in this type of processing, so we think we have a competitive advantage in this area.

OGFJ: Magnum Hunter issued a press release recently saying that you are curtailing natural gas production in the Appalachian region. Can you elaborate on this a little?

GE: We have short-term curtailments in Appalachia in two areas. The curtailments in the Marcellus aren’t voluntary.

Those are due to processing restric-tions from Dominion Transmission, which is who we sell our gas to at this time. Those should be alleviated in about a month when our new processing plant that is being completed by Mark-West Energy Partners goes live. So that issue will go away. However, we have voluntary shut-ins of about 400

gas wells that are predominantly producing from the Huron formation over in Kentucky. The reason for those shut-ins has to do with low gas prices, some higher transportation charges, and the fact that the summertime requires us to buy some other chemicals to reduce the ethane to make it pipeline qualifi ed. Since it would cost us more money to produce than we were making, we made the decision to shut in those wells. But as the weather cools, the ethane is much less a problem, and those wells will go back on before the end of the year. Especially since gas prices have dramatically improved.

OGFJ: You have about 60,000 acres in the Utica Shale. Tell us a little about what you’re doing there.

GE: Most of our Utica assets have come as a result of acqui-sitions. We tend to buy a lot of production in the shallow formations, and with that comes a lot of Marcellus and Utica leases. That’s good from the standpoint that almost all of our acreage positions are held by production and cost very


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little on a per-acre basis. We’ve been watching and learning from others that are drilling around us. As we monitor the activity, it turns out that it appears we are in a pretty good sweet spot. We’re excited about our holdings, and we’re planning to drill our fi rst Utica test well early in the fi rst quarter of 2013. We may drill up to 10 Utica wells next year.

OGFJ: Where in the Utica are your assets?

GE: We’re in three counties in Ohio – Washington, Noble, and Monroe – and in Tyler County, West Virginia.

OGFJ: Eureka Pipeline, Magnum Hunter’s midstream subsidiary, has proven valuable to you given your early entrance into a number of plays lacking infrastructure. How does your midstream business complement your E&P segment? What are your long-term plans for the midstream segment?

GE: When we bought Triad Energy out of bankruptcy back in February 2010, we also ended up with lots of right-of-way and some midstream assets, which we have since rebranded Eureka Hunter. We have now built over 60 miles of new 20-inch pipe, predomi-nantly in West Virginia to gather Triad Hunter’s new Marcellus wells. We’re moving about 70 mil-lion cubic feet per day. We’re now laying that pipe under the Ohio River to go from West Virginia to Ohio, which should be completed in the next 30 days. It will allow us to begin gathering gas in the state of Ohio. So we’re pretty excited about what we’ve been able to accomplish with Eureka Hunter Midstream, and our goal is to spin this out to the public sometime in 2013, probably about mid-year. We have brought in a private equity fund, ArcLight Capital Partners out of Boston, and they’ve invested about $130 million. They own over 30% of Eureka Hunter. While it’s early in our life cycle, we are building the system out and signifi cantly increasing volumes will occur as the new MarkWest facility that I mentioned earlier comes on stream in late November.

OGFJ: Do you operate midstream assets elsewhere or just in the Appalachian region?

GE: In May of this year, we bought a group of 60 small amine and gas treating plants through a company called TransTex. That gives us diversity as well as signifi cant plant capacity and knowledgeable manpower in gas processing throughout the state of Texas. As we introduce Trans-

Tex Hunter to the Appalachian region, they’re looking at deploying new assets up there.

OGFJ: Magnum Hunter is obviously a resource-rich company, and yet your stock is currently trading at a discount to others in your peer group. What are inves-tors missing?

GE: The market today rewards those companies that use less leverage. We aren’t shy about borrowing, and with my fi nance background I am comfortable and always looking at our existing and future cash fl ows. If we were to mon-etize some of our assets, such as the properties we own in the Eagle Ford, that will likely get some attention from the marketplace and could be a real catalyst for us. We recog-nize that we need to do some things to harvest a lot of the potential that we have built over the past few years. If we do,

maybe the market will take note. We’re very happy with the asset base we’ve built, but we’re not so happy with the share price. We’ve always felt that time would take care of that issue as long as we continue to perform as we have done in the past. And that’s the path we are continuing down.

OGFJ: Which of your assets looks the most promising right now, and where do you plan to concentrate your capital spending in 2013?

GE: The Marcellus will get a big chunk of our budget next year. We’ve got the pipeline in place and running. We’ve got the processing plant almost operational. We have already delin-eated our acreage position. We’re in the process of taking delivery of a new drilling rig for this region. We’ve got

everything in place, and gas has moved back from $2.00 to around $3.50. This is encouraging. Of all the shale plays we’re in, the Marcellus decline curve has outperformed even what our petroleum engineers estimated. This means that even though we’ve held back drilling in this region in 2012, there has been an amazing resilience of existing production holding up. If we had stopped that drilling in other regions, we would have seen a dramatic decline in production. We haven’t seen that in the Marcellus. This tells me that we’re probably underestimating our recoveries per well and fi eld-wide. For the next 12 months, I believe we’ll be in a $3.50 to $5.00 gas regime, and with that price environment, we can make an incredible rate of return up in the Marcellus. I don’t think any other gas fi eld in the United States can profi tably compete with this scenario.

OGFJ: We appreciate your time. Thank you.

ND Pump Jack


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A Supplement to

ENERGY TRADING

RISK MANAGEMENT

November 2012


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continued on pg.22

www.ogfj.com ◆ November 2012 ◆ Energy Trading & Risk Management 19

Commodity price volatility has always been with us and is

the single biggest variable in forecasting EBIT for non-

integrated independent exploration and production com-

panies. The recent volatility in oil prices and the collapse of the North

American gas price suggest strongly this is not going to change.

Hedging using derivatives can dampen the impact of price

movement on earnings and is a staple tool in the oil or gas com-

pany treasury arsenal, particularly for North American CFOs.

The use of commodity derivatives can mitigate or remove oil

or gas price uncertainty as one of the fundamental industry vari-

ables, a variable which in turn directly impacts liquidity, (the poor

management of which is the biggest predictor of a small cap’s

impending mortality).

Like many useful tools, derivatives are a double-edged blade

and their use either by CFOs or by bankers must be done cau-

tiously with due respect to the risks both hidden and obvious. To

quote Julius Caesar, “It is always the unseen dangers that are the

most terrifying.” There are many unseen dangers in the interac-

tion between derivatives, the underlying reservoir, and the fi scal

and commercial risks in upstream oil and gas endeavours.

If used incorrectly, without a clear understanding of and regard

for the interaction between the derivative product and its specifi c

characteristics and the underlying reserve, production, timing and

fi scal risks, derivatives can multiply losses in the case of reservoir-

related production, under-performance.

The North American model Hedging as a tool to manage price risk is long established in North

America and often used by CFOs to manage price exposure. For

bankers, it allows them to safely increase leverage to smaller oil

and gas companies. Hedging tools can also be useful to underpin

leverage or protect returns on equity in leveraged acquisition sce-

narios in volatile commodity price environments.

Historically hedging was and still often is limited, both in lend-

ing policies of some banks and in oil company board-approved

risk mitigation strategies to proved, developed, and producing

(PDP) reserves over a time horizon of perhaps three to fi ve years.

On a diversifi ed conventional reserve base of multiple wells,

several producing horizons and fi elds with signifi cant production

history, predicting the future production performance over this

sort of time horizon using type and decline curves is generally

quite accurate. Companies with this sort of conventional reserve

base can enter into contingent liability derivatives like swaps on

a high percentage of their PDP production with a high degree of

confi dence that the physical production to back any hedge liabili-

ties will be there regardless of availability of future resources like

capital and rigs to drill and complete future wells.

VPPsOne feature of the US market not seen anywhere else is the volu-

metric production payment, or VPP.

Unlike a conventional loan, in a VPP the holder of the instru-

ment provides the producer with an upfront cash payment in

return for receiving specifi c volumes of oil or gas (not a specifi c

amount of cash) from specifi cally designated fi elds over a speci-

fi ed period of time. In most cases an agreement transferring the

specifi ed reserves to the VPP holder is executed as part of the

transaction. In order to mitigate the price risk that has been trans-

ferred to the holder of the VPP, the VPP will often have a hedge

in the form of swaps associated with the production volumes inte-

grated into the commercial structure of the agreement.

This structure is unique to the US because VPPs transfer own-

ership of a specifi c volume of oil or gas to the buyer in return for

capital. The transfer of oil and gas ownership of reserves when

“still in the ground” is not something that can be done in many

places outside of the US as reserve ownership tends to be in the

hands of the state with oil and gas companies receiving the right

through a license or contract to extract and sell the oil (ownership

of the oil or gas itself transferring at the wellhead).

Where a hedge is integrated into the deal, the PDP production

stream is sold forward on a locked-in price to result in a stable

predictable revenue line that is used to repay the capital (and

any embedded interest/profi t) over the life of the VPP. Because all

of the sales revenue is taken for repayment, the unhedged non-

transferred volumes from the underlying parent oil or gas fi eld or

fi elds must be suffi cient to cover all of the global fi eld-level opex

and any other liabilities or obligations of the fi eld, including the

operating costs of the VPP volumes.

Hedging is an effectiverisk management tool

for upstream companiesThe use of commodity derivatives can mitigate or remove oil or gas

price uncertainty as one of the fundamental industry variables.

Kevin Price, Societe Generale, London


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20 Energy Trading & Risk Management ◆ November 2012 ◆ www.ogfj.com

Triple Point Technology’s Chief Marketing Offi cer,

Michael Schwartz, comments on price volatility,

mobile ETRM applications, Dodd-Frank, and more.

What can energy companies do to cope with today’s volatile price

movements?

It starts with complete visibility into all risk drivers combined with

real-time analytics - this turns data into actionable information. A

complete understanding of the potential impact of adverse risk

events is vital to minimizing the negative effects of price volatility on

the bottom line.

Triple Point’s Commodity XL™ is the only solution providing

enterprise-wide transparency and control over all areas of exposure

on a real-time, integrated platform. The solution

minimizes physical and fi nancial risks across the

entire supply chain. Real-time straight-through

processing (STP) coupled with advanced busi-

ness intelligence tools address market risk,

operational risk, counterparty credit risk, and

regulatory risk.

According to Apple, iPhones and iPads are

already being deployed or tested at over 90%

of Fortune 500 companies. How do you see

the trend towards a wireless workplace chang-

ing the way companies manage ETRM?

A more mobile workforce means that in order

to ensure maximum productivity and effi ciency,

business applications need to be accessible from

wherever employees are at any point in time.

Mobility will transform ETRM by empowering employees to perform

key functions on-the-go, before competitors can react. You can’t just

take an entire application and put it on a mobile platform. You have

to think about which functions make sense in a mobile environment,

and then create applications that enable them to be performed

effectively on a mobile device.

Triple Point is the only ETRM software company currently offering

mobile applications. We have already released fi ve applications:

• Mobile Commodity Trader supplies traders with all the tools nec-

essary for doing business on the road.

• Mobile Voyage Estimator wins more business for shippers and

charterers by providing accurate quotes.

• Mobile Inventory Navigator allows schedulers to assess bulk com-

modity inventory and capacity levels in real-time.

• Mobile Management Dashboard provides pinpoint analysis of

key performance indicators for improved decision making and

bottom-line results.

• Mobile System Console enables administrators to monitor

deployments of Triple Point’s Commodity Management solution.

What should ETRM companies do to ensure Dodd-Frank compliance?

Dodd-Frank regulations related to reporting and swap clearing require

rigorous scrutiny of IT systems to ensure they facilitate compliance.

Energy companies that have not already developed a compliance plan

must act immediately to avoid being caught unprepared.

Adaptive reporting engines will be needed to ensure that transac-

tion data, including swap life cycle events and valuations, can be con-

veyed to swap data repositories (SDRs) in near real-time. All systems will

need to maintain a detailed, accessible history of transaction data. Fur-

thermore, companies can’t rely on credit rating agencies alone. Systems

must provide internal scoring methods, collateral

management, and liquidity analysis. Companies

must also ensure that systems provide strong

documentation of trading and hedging strate-

gies, particularly if they want to obtain end-user

exemptions.

Triple Point is committed to providing the

most comprehensive ETRM solution for meeting

Dodd-Frank requirements. Our platform offers

real-time reporting and STP, automatically trans-

mits data to SDRs, provides comprehensive audit

trails, and enables companies to produce the

necessary documentation to support an end-user

exemption election. As the specifi cs of Dodd-

Frank continue to evolve, energy companies can

count on Triple Point to deliver what’s needed to

ensure compliance.

I heard recently that CNOOC, Petrobras, SK Energy, Valero, and

other major oil companies have moved to Triple Point’s ETRM

platform. To what do you attribute your success?

Oil is a very physical business, involving production, inventory man-

agement, pipeline scheduling, and numerous other logistical opera-

tions. In order for an oil company to manage its business as profi tably

as possible, it needs an ETRM system that manages the physical side

of the business along with the fi nancial side. Commodity XL has been

the solution of choice among energy companies because it provides

real-time tools for managing exposure across the entire portfolio.

Analysts have validated this assertion, with Gartner naming Triple

Point a Leader in its Magic Quadrant for ETRM Platforms for four

consecutive years. Gartner has commended us for our extensive

range of functional coverage for all aspects of ETRM, and for having

the most comprehensive credit risk management, hedge accounting,

and compliance solutions.

Energy Industry Challenges & Trends: Q&A with Triple Point Technology


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Achieving Dodd-Frank Compliance with Triple Pointby Mike Zadoroznyj, VP, Solutions Director, Treasury & Regulatory Compliance, Triple Point Technology

It goes without saying that starting in the very near future, the Dodd-Frank Act will have a significant impact on the way energy companies do business. Stringent regulations related to reporting, swap clearing, and other areas require rigorous scrutiny of trading and supporting IT systems to ensure they will facilitate compliance. Energy companies that have not already commenced execution of a compliance plan must take action immediately to avoid the potentially disastrous ramifications of being caught unprepared as the regulations take effect.

Triple Point Technology is committed to providing the most comprehensive ETRM solution available for meeting Dodd-Frank requirements. Our flagship ETRM platform, Commodity XL™, delivers functionality for energy companies to achieve compliance with Dodd Frank regulations related to:

�� Transaction Reporting – Dodd-Frank requires companies to submit all swap-related trade data, including reportable life cycle events and valuations, to swap data repositories (SDRs) in near real-time. The SDRs will then transmit the data to the CFTC for review. Commodity XL facilitates this process by enabling companies to automatically transmit their data to SDRs such as the ICE Trade Vault.

�� Position Monitoring & Reporting – A portion of Dodd-Frank known as the Position Limits Requirement was recently repealed in Federal Court. However, there is the chance US regulators will appeal the Court’s decision. If the appeal is successful, market participants will be restricted to holding no more than a specified number of contracts within certain commodity classes. And if a market participant exceeds a position limit, it will be required to report the incident to the CFTC. To maintain compliance, companies will have to continuously monitor their positions, and aggregate commodity positions in future equivalent contracts. Commodity XL actively monitors aggregate positions in real-time, and provides trading and hedging alerts to prevent limit breaches.

�� End User Exemption Elections – Dodd-Frank requires market participants to centrally clear over-the-counter (OTC) derivative trades designated as “clearable” by the CFTC and SEC. Companies that trade derivatives to protect against price volatility are exempt from clearing, but must apply for an End User Exemption on a hedge-by-hedge basis.

To qualify for an End User Exemption, it must be proved that the derivative is being used to hedge or mitigate commercial risk. Other requirements for exemption include ensuring that at least one party to the swap is not a “financial entity,” and providing a notice specifying how the organization meets its financial obligations associated with entering into a non-cleared swap.

Commodity XL ensures that organizations’ bona fide hedging programs are exempt from central clearing and margin requirements by providing a complete audit trail of hedging activity, along with effectiveness testing and automated documentation and disclosure management. The solution provides enterprise-wide access to all information, ensuring that it can be located rapidly in the event of an audit.

�� Collateral & Margining – Under Dodd-Frank, both cleared and uncleared swaps are subject to higher collateral and margining requirements. This puts a strain on market participants by reducing the amount of available working capital. To ensure an accurate view of liquidity and exposure, participants must have systems such as Commodity XL that provide comprehensive collateral and margining management. Commodity XL improves cash flow and mitigates risk by enabling companies to understand their true position. The solution automatically calculates liquidity, and enables users to view information at the enterprise level or the deal level. Extensive analytical tools are also available for assessing the impact of higher collateral and margining requirements on the bottom line.

As the specifics of Dodd-Frank continue to evolve and the regulations begin to take effect, energy companies can count on Triple Point to help maintain compliance. Our regulatory experts continually monitor Dodd-Frank legislation to ensure that we provide the functionality required to support our customers’ compliance efforts today and in the future.

For more information, email [email protected], or call +1.203.291.7979.


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Put vol.

Reserve report PD (PDP+PDNP)

Current production

Vo

lum

e (M

Mb

ls)

40,000

35,000

30,000

25,000

20,000

15,000

10,000

5,000

0

Year

2012 2013 2014 2015 2016 2017

$100.19

$99.50

$100.75

$98.00

$98.35

$93.00

$95.00

$95.00

$95.00

$96.75

$95.00

$91.25

Swap vol.

Reserve report PDP

Reserve report total proved (PD+PUD)

Current Prod + new acq

Crude oil hedge positions

continued from pg.19


Depending on the economics of the underlying asset, including

the nature of the lease operating expenses of the properties (fi xed

vs variable etc.) and the precise shape of the commodity forward

curves, a VPP structure may or may not result in higher leverage

than a traditional loan with hedging. Other considerations when

using this structure include accounting and tax issues and the fact

that a VPP may result in an actual transfer of reserves (whereas

a reserve-based loan repayable in dollars does not) impacting

reserve replacement ratios and other performance indicator statis-

tics of the parent company.

Resource plays, acquisitions, and predictable dividendsIn recent years the combination of the development of large

resource plays in the US and the emergence of business models

designed to ensure consistent dividend payouts to investors has

led to the development of more aggressive hedging policies in

companies and less restrictive covenants in bank loans. Typically

such companies will hedge out a high percentage of their total

proved reserves, including the proved undeveloped component

but cap the volume of contingent liability derivatives at current

actual production levels. Bank facilities may in turn have covenants

that require that contingent derivatives volumes can at no time

surpass “actual” production, and if the production drops may have

clauses that require unwinding of the “open” hedge position to a

level no more than the prevailing production rate.

Resource plays in particular lend themselves to this sort of

approach as the geological risk associated with proved undevel-

oped component of reserves is greatly reduced and spread over

a scale of operations consisting of hundreds of wells a year. This

means the geological risk of reservoir underperformance can

largely be ignored. The key risk then becomes the ability of the

company to continue to source suffi cient capital and rig resources

to convert undeveloped reserves quickly enough to at least main-

tain the existing production levels, avoiding any decline.

Given reserve risk in resource plays is greatly reduced compared

to conventional reservoirs. The risk being taken by investors and

bankers with this kind of approach is more in line with the usual

risk of continuation of a going concern, namely, can the company

source suffi cient resources to continue to maintain its operations

at least at current levels.

Finally, in some limited cases, the North American market has

accepted a further level of uncertainty that relates to acquisitions

where companies may hedge the price of production of “to be

acquired” properties. This is done to ensure that the acquisition

economics are protected in a situation in which the acquisition is

being completed in a potentially falling commodity price market.

Such hedging is only done when certain acquisition milestones are

passed, and acquisition debt facilities may have specifi c require-

ments relating to the need to unwind the hedge if certain mile-

stones are not reached or certain price thresholds breached.

Ultimately, at high prices, the value of the company’s resource

base acreage (both existing and to be acquired) the reserve life

and production half-life statistics (indicating the ability to restruc-

ture hedges over a longer period of time) and fi nally the ability to

sell the acreage to raise capital (so called “right way risk”) is the

fi nal backstop to the potential future liabilities of the hedge pro-

gram in these situations.

Given the recent drop in gas price and to a lesser extent of

WTI in the US in particular, this approach to hedging has proved


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Chris Croom, PresidentZach Lee, CEO281.655.3200www.asset-risk.com

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Each member of ARM’s senior management team has more than 20 years

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to be benefi cial to companies that have managed to protect the

economics of the business over a long term without unduly expos-

ing themselves to physical delivery risk if the market price were to

move above the strike of the swap.

The graphic on page (20) is a conceptual example of a resource-

based company hedge program (in this case oil) for a company in

the middle of closing an acquisition.

International markets The level of hedging risk acceptable outside of North America

varies depending on the context but is normally far less than can

be comfortably tolerated in the American context for a number

of reasons.

Undeveloped conventional reserves and contingent deriva-

tives are a dangerous mix. Firstly, reserve risk is different, typically

the reserve base is almost always conventional, and therefore the

undeveloped components of reserves have far more geological-

specifi c risk associated with them than in a resource play. In addi-

tion, reserves are often offshore, meaning additional drilling to

make up any production shortfall is logistically far more expensive

and time constrained in terms of resources to mobilize rigs. (Trying

to drill your way out of trouble is never a very convincing strategy,

but offshore cost and time considerations make it impossible.)

Generally, the use of swaps in upstream project fi nance for

conventional reservoirs against non-producing reserves is inad-

visable. In the cases of an underperforming reservoir or even a

delayed start up of production, “out of the money” swaps can

quickly amplify the loss in the event of default. Puts, or differed

variations of them, are generally used avoiding any potential con-

tingent liability (apart from the option premium) unless and until

reserves are producing. The only (rare) exception to this is per-

haps where an asymmetrical collar structure can be used to offset

the time uncertainty of fi rst oil or gas in a new fi eld development

(fl oor now but with a high level call strike perhaps a year after

predicted fi rst oil or gas to allow room for unexpected delays).

This strategy, while providing some mitigation to start-up

delays, still does nothing to mitigate reserve risk itself, which

is always higher on undeveloped “volumetrically” calculated

reserves, so the banker providing the derivative and the oil

company CFO must question if the costs saved in premiums for

options is worth the potentially huge risk if the fi eld signifi cantly

underperforms on fi rst production at a time when the call is out

of the money.

It might be argued that such an approach is betting not just

the loan, the careers of board members (and their bankers), but

indeed the company itself on variables that are beyond the con-

trol of management in order to save some upfront costs.

Tax – corporate or wellhead ? – it mattersFiscal regimes are far more variable and complex for companies

operating outside North America and can have unintended con-

sequences that amplify liabilities in the event of prices above the


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“One feature of the US market not seen any-

where else is the volumetric production pay-

ment. In a VPP, the holder of the instrument

gives the producer an upfront cash payment in

return for receiving specifi c volumes of oil or

gas (rather than cash) from certain designated

fi elds over a specifi ed period of time. To miti-

gate price risk, the VPP will often have a hedge

in the form of swaps associated with produc-

tion volumes integrated into the agreement.”

www.ogfj.com ◆ November 2012 ◆ Energy Trading & Risk Management 25

strike price of the derivative instrument being used.

In high tax regimes like Norway (and indeed the situation was

similar under Petroleum Revenue Tax [PRT] paying fi elds in the UK

in the past), the tax, or a large component of it, is calculated at the

“fi eld” level on the wellhead price received for the oil or gas rather

than as a corporate tax based on the fi nancial profi t or loss (includ-

ing hedging gains and losses) of the parent company. This can lead

easily to over hedging through unintended operational gearing.

To give an example, say a tax rate is 80% on wellhead prices,

and the company hedges 50% of its production at $50 a barrel.

If the oil price goes to $100, the company will owe a tax liability

of $80 to the host government and $50 to the hedge provider a

total of $130 on every barrel of “hedged” oil produced. At the

same time for the un-hedged barrel, they have just $20 post tax

revenues to cover the $30 loss on the hedged barrels. As can be

gleaned from this simple example, over-hedging via fi scal induced

operational over gearing is a potentially rapid route to bankruptcy.

Production sharing contracts (PSCs) seen in many emerging

countries represent an even more complex minefi eld for the inex-

pert use of commodity derivatives, as the combination of the

quantum of cost oil recovery and profi t oil horizon uncertainties

combined with the additional complexity of fl ows of cash from a

hedging program can lead to unpredictable effects on future cash

fl ow, leading to high cash fl ow volatility with cashfl ow in surplus

in some periods being followed by unexpected defi cits in others.

Basis risk On top of all the risks outlined above, another risk occurs wherever

the hedging instrument is not an exact match for the underlying

physical crude. An example would be production from an oil res-

ervoir being hedged by the purchase of Brent Crude swaps. While

correlations can give some comfort that the spread between the

price of different crudes, they cannot predict exactly how such a

spread will move over time. The gap between the swapped price

and the underlying market price of the physical crude being pro-

duced is the basis risk.

Various strategies can be employed to manage this risk,

including in some markets “basis” and synthetic swaps that are

designed to cover the gap. However, basis risk remains an addi-

tional uncertainty in simple crude hedge swap strategies unless

the underlying crude is a direct benchmark to the swap. Basis risk

can come in various guises, for example on gas VPPs the calorifi c

value of the gas can be a hidden source of this risk if the VPP is

denominated in production volume rather than calorifi c content.

GSA escalator hedgingIn some markets, long-term gas contracts are sold on prices linked

to crude products like Gasoil or heavy fuel oil. Details will vary

with the specifi c contract, but the price escalators typically have

delays built in so the price movement on the gas price happens

some months after a movement in price on the benchmark esca-

lator. Hedge strategies attempting to synthetically tie in the gas

price have to address two kinds of basis risk, time variant and

product specifi c.

Sentiment of the capital markets While North American investors seem to welcome a certain amount

of hedging as a sign of good risk management, many stock market

investors in other parts of the world are less keen. Putting aside the

technical considerations above which are perhaps beyond the con-

cern of all but the most sophisticated investors, oil stocks are often

bought not just to have exposure to exploration upside but also to

the oil price itself. Many international CFOs may feel little incentive

to hedge downside signifi cantly because they may receive criticism

from shareholders for reducing high price upsides.

Conclusion: One size (in this case price) does not fi t allWhen it comes to the use of commodity derivatives, what consti-

tutes a sensible risk management program depends on context.

The nature of underlying reserves, the size, scale, maturity, and

sophistication of the company’s operations, the petroleum eco-

nomics of the underlying asset(s), and the fi scal context of the

country of operations. Correctly utilized, hedging tools represent

a useful way of underpinning value, maintaining liquidity, and man-

aging credit risk. Incorrectly used they can amplify risk signifi cantly.

About the author

Kevin Price is the managing director and glob-

al head of reserve-based fi nance at Societe

Generale. He is responsible for all of the bank’s re-

serve-based fi nancing activities both internation-

ally and throughout North America. Price has over

25 years’ experience in the upstream oil and gas

and fi nance industries, having started his career as

a petroleum geologist, he spent 12 years working in the oil indus-

try before moving into reserve-based lending and oil fi eld devel-

opment fi nance in 1997. Since 1997 he has held various positions

in British and European Banks with specialist upstream fi nancing

teams, initially as a technical advisor and latterly as a senior banker

responsible for arranging and structuring a number of innovative

international borrowing bases and oilfi eld development fi nancings

both in the North Sea and in emerging markets. Price joined So-

ciete Generale in 2006 as head of the international reserve-based

fi nance business, becoming the global head in 2009.


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Drilling and completions, well workovers, seismic data acquisition and processing, well and pro-duction logging are the typical services to the

upstream industry. Normally these services are provided by service companies on a market basis.

In the “normal” business model the contractors and the clients are separate legal and business entities and the parties are negotiating and concluding contracts by the

rules of a competitive business environment. In con-trast with that market-oriented logic, we can fi nd many examples of vertical integrations when oil companies own service companies – most of all in Central and Eastern Europe, in North Africa and the Middle East, as well as in the countries of the FSU and in China. The study that follows attempts to analyze the business rationales and the risks of these venture solutions.

Oil company-owned service companies

can be a risky choice for most operators

Imre Szilágyi, Exploration Geologist and Petroleum Economist, Budapest, Hungary

Oil companies expect that investments made in an in-house service

company will be lower than the expenditures to be paid for the services

of independent contractors. However, is this assumption correct?


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Determination is in our nature

The days of easy oil exploration are over. Today, we go to great lengths (and unfathomable depths) to provide

much needed energy to the world. As one of the major leaseholders in the deep water Gulf of Mexico, we

keep raising the bar by applying new technologies, so we can recover more oil while keeping the people and

the environment safe. It’s what we call never being satisfied.

Explore more at neversatisfied.statoil.com

Always exploring

Never satisfied


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Business rationalesThe oil companies’ fi nancial performance is largely depen-dent on the availability of cost-effi cient services. It is vital for the operators to have access to the given service at the lowest price – of course quality requirements should be met.

Soaring service prices are nightmares for the oil com-panies’ exploration and asset managers as they jeopardize the profi tability of their projects. Therefore, from time to time it becomes the topic of strategic discussions that setting up an in-house service company instead of taking the risk of market price fl uctuations might be a reasonable option. The oil companies choosing this option expect that the investments made in an in-house service com-pany will be lower than the expenditures to be paid for the services of independent contractors.

For some recently privatized independent oil compa-nies, in-house service companies are the heritage of their national oil company past. Among these ventures we can fi nd the Central and Eastern European companies which – in parallel with their gradual privatization – tend to become global players, while drilling, logging, and seismic service companies still remain part of their portfolio.

The strategic question for them is whether the running forward or the sell-out of their service assets is the better choice. The question usually becomes hot when the man-agement of the service company calls for some capex to replace the amortized equipment. At this point the busi-ness rationale behind the capital expenditure is much the same as it is in the case of the above-mentioned example: the hope is that the expenditures will be recovered as the market prices rise and the in-house company operation costs decline.

Risks and concernsWhen the oil companies are spending capex either to establish service companies or to develop their service companies’ infrastructure, in fact, they are taking a long forward position. They agree to buy an asset (the service company) in the hope that the investments (expendi-tures of the service company setup/development) will be cheaper than the asset price (the market priced cost of the service) at a specifi ed time (when the need for the given service arises).

The problem with the deal is that, unlike brokers of

the capital markets, the oil companies are unable to cover their deals by taking opposite positions at the same time.

Similarly, in every market the upstream service prices are driven primarily by the demand-supply balance in the given market segment. Once the former exceeds the latter, prices go up. And, vice versa, prices go down if the demand lags behind the supply.

The oilfi eld services market is subject to the same fl uc-tuations that other markets have. If prices for services are rising, the long forward proves to be benefi cial. Invest-ments made into the development of the in-house asset are recovered because the extra profi t is left in the owner’s pocket.

On the other hand, if the development of a demand-driven market proves to be wrong or if the market turns out to be supply-driven, the long forward deal may fail. Once this happens, the service companies may suffer seri-ous losses due to the fact that their incomes are not cover-ing their costs and their shareholders’ profi t expectations.

When the shareholder of the service company is the oil company itself, it can decide if it wants to suffer the loss as a shareholder of a losing enterprise or as a client by paying more for a service than it would be reasonable on a market price basis. Needless to say, the latter choice is unrealistic for companies in a concession partnership with other oil companies and/or operating in a recoverable cost-based PSA environment. Both the concession part-ners and the host country government authorities insist on competitive prices, and they will not accept the opera-tor’s argument that they should pay higher-than-the-going rate to the operator’s in-house service company.

Even if the in-house service company happens to prove competitive, the strategy may fail for the simple reason that the owner itself may cancel or postpone exploration programs due to the limitations of the in-house service company. In this case, the outcome is the same as it would be if the service company is not competitive. The in-house service capacities become redundant for their owner.

The obvious optional solution – the theoretical hedge of “the long forward” – could be if the service company tries to sell its capacities to third parties. I call this attempt “theoretical” because in the long run it cannot be suc-cessful due to the fact that the owner of a service is an oil company. At least we can align three serious arguments jeopardizing the success of the “hedge.”

First, the potential clients of the in-house service com-pany are the peers of the owner oil company. They may be concerned that sensitive information about the opera-tions will be passed on to a competitor or possible com-petitor by the contractor. Another concern of the client might be that its peer might bias the operation by directly instructing the service company on the grounds of owner-ship rights. As a consequence, the service company might have to reduce the offer prices to compensate the clients’ concerns – if the concerns can be compensated at all.

“For some recently privatized independent oil

companies, in-house service companies are

the heritage of their national oil company past.

Even as they become global players, the drill-

ing, logging, and seismic service companies

often remain part of their portfolio.”


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STATEMENT OF OWNERSHIP, MANAGEMENT AND CIRCULATION

1. Publication Title: Oil & Gas Financial Journal. 2. Publication Number: 023-057. 3. Filing Date: October 1, 2012. 4. Issue frequency: Monthly. 5. Number of Issues Published Annually: 12. 6. Annual Subscrip-tion Price : $149.00. 7. Complete Mailing Address of Known Office of Publication:PennWell Corporation, 1421 South Sheridan Road, Tulsa OK 74112, Tulsa County. 7a. Con-tact Person: Traci Huntsman. 7b. Telephone:918-831-9435. 8. Complete Mailing Address of Headquarters or General Business Office of Publisher: PennWell Corporation, 1455 West Loop South, Houston TX 77027. 9. Full Names and Complete Mailing Addresses of Publisher, Editor and Managing Editor: Pub-lisher: Nicole Durham, 1455 West Loop South, Houston, TX 77027. Editor: Don Stowers, 1455 West Loop South, Houston, TX 77027. Man-aging Editor: Don Stowers, 1455 West Loop South, Houston, TX 77027. 10. Owner: Pen-nWell Corporation, 1421 South Sheridan Road, Tulsa OK 74112, Tulsa County; Successors to the estate of Helen B. Lauinger, 1421 South Sheridan Road, Tulsa OK 74112, Tulsa County. 11. Known Bondholders, Mortgagees, and other Security Holders Owning or Holding 1% or more of total amount of bonds, mort-gages, or Other Securities: None. 12. N/A. 13. Publication Title: Oil & Gas Financial Journal. 14. Issue Date for Circulation Data: September 2012.

15. Extent and Nature of Circulation:Average No. No. Copies of Copies Each Single IssueIssue During PublishedPreceding Nearest to12 Months: Filing Date:

a. Total # of copies 6,929 7,701

b. Legitimate paid and/or requested distribution

1. Outside county paid/ 5,099 5,244requested mail sub-scriptions stated on PSform 3541

2. In-county paid/requested 0 0mail subscriptions statedon PS form 3541

3. Sales through dealers 174 180and carriers, streetvendors, counter sales,and other paid or requesteddistribution outside USPS®

4. Requested copies distri- 0 0buted by other mail classesthrough the USPS

c. Total paid and/or 5,273 5,424requested circulation

d. Nonrequested copies distribution

1. Outside county non-re- 920 975quested copies stated onPS form 3541

2. In-county nonrequested 0 0stated on PS form 3541

3. Nonrequested copies dis- 0 0tributed through the USPSby other classes of mail

4. Nonrequested copies 335 625distributed outside the mail

e. Total nonrequested dis- 1,255 1,600 tribution

f. Total Distribution 6,528 7,024

g. Copies not Distributed 401 677

h. Total 6,929 7,701

i. Percent paid and/or 80.78% 77.22%requested circulation

16. Publication of Statement of Ownership:Will be printed in the November 2012 issue of this publication. 17. Signature and Title of Edi-tor, Publisher, Business Manager, or Owner: Traci Huntsman, Manager Corporate Assets and Postal Compliance. Date: 10/01/2012.I certify that all information furnished on this form is true and complete. I understand that anyone who furnishes false or misleading infor-mation on this form or who omits material or information requested on the form may be sub-ject to criminal sanctions (including fines and imprisonment) and/or civil sanctions (including civil penalties).

Note: 11,475 copies of Oil & Gas Financial Journal were distributed in electronic format and not accounted for in the USPS Statement of Ownership.

Second, the in-house service company may be viewed internally in the owner oil company as a non-core business within the company. The relevant market risk (the beta) is higher in the oilfi eld services business than it is in the oil and gas exploration and production industry. It means that – due to the higher cost of capital – an investment made into a service companies will have a lower performance index (PI) than the E&P projects. As a consequence, when the capex allocation decisions are made, the in-house service company may easily fi nd itself below the bottom line. Besides, there are no strategic or stakeholder interests found in the favor of investing in a service company instead of spending the scanty capex for drilling a well or for a seismic survey.

In fact, it is a vicious circle. The more reluctant the shareholder is to fi nance the development of its service company infrastructure (or the replace-ment of the amortized tools), the less profi t is realized as the operational costs of the service company grow because of the use of technologically outdated and amortized equipment. Time is growing short as the decline of the actual profi ts triggers negative sentiments about capex allocation.

Third, the in-house service company will not accommodate the corporate management systems (HR, IT, Procurement, etc.) and policies of the oil com-pany. Service companies and oil companies follow very different management logics. This could lead to serious operational diffi culties if the management of the oil company forces its own governance system on the service company.

The end result of the realization of these assumptions is the irreversible decline of the in-house service company’s effi ciency: costs are constantly growing while the market share is getting less and less. At the end of the day, the liquidation of the in-house service company remains the only solution.

ConclusionsInvestments made by oil companies to build in-house oilfi eld service capaci-ties are very similar to long forwards. In our case, however, the investor most likely is unable to hedge the deal. Despite some of the apparent lures of developing an in-house services operation, I would not advise an oil company to do so.

Oil companies already operating are advised to sell or outsource their service companies as soon as conditions are favorable. (Favorable conditions include that the NPV-expectations are still positive and a there is a buyer that is willing to pay more.) If no such conditions prevail, the liquidation of the service company is the only realistic choice. The earlier it is done, the less painful it will be.

Finally, I have to note that the assumptions and considerations of the above study are limited to a real market environment and are valid if the companies are viewed as profi t-making investments. If a regional market is monopolistic or the given oilfi eld service is not available in that market, an in-house service company might be a reasonable option. Similarly, if the oil company is driven by other than the profi t motive (for example, a national oil company), it may fi nance in-house services without any concern. OGFJ

About the authorImre Szilágyi is an independent exploration geologist and petroleum

economist based in Budapest, Hungary. He previously served as

CEO of GES Geophysical Services, which was owned by MOL Hun-

garian Oil and Gas Plc. Szilágyi recently completed a study analyz-

ing the risks involved in operator-owned oilfi eld service companies.

He holds an MS degree in geology from Eötvös Loránd University of

Budapest and an MBA from Budapest University of Technology and

Economics. He can be reached at [email protected].


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Analysts say that the Utica Shale, which is nearly equal to the size of the Eagle Ford play in Texas, could become the third-largest shale play in the

United States, producing as much as 250,000 to 500,000 barrels of oil a day. The Ohio Department of Natural Resources estimates that the Utica’s potentially recover-able reserves could range from 3.75 TCF of gas and 1.31 billion barrels of oil to 15.7 TCF gas and 5.5 billion bar-rels of oil.

In comparing the Utica to the Eagle Ford, the fol-lowing: True vertical depth (TVD) in the Utica can be as shallow as 4,500 feet versus ~ 6,000 feet in the Eagle Ford, recovery factor can be 5% versus 4%, formation thickness 140 feet versus an average of 100 feet and porosity of 8% versus 5-8% in the Eagle Ford.

With regard to activity and players here is what’s happening so far:• Chesapeake holds more than

1 million net acres in the Utica and is by far the most active driller with a total of 87 wells with plans to fi nish 2012 with 15 operated rigs. The company has signifi cant funds to support development through the end of 2014 thanks to the remaining drilling carry from the January 2012 joint venture with Total.

• After Chesapeake released data for fi ve wells drilled in Carroll and Harrison Counties in the Utica/Point Pleasant play earlier in the year, everyone took notice. The Buell well IP was 9.5 MMCFED of gas, 150 BD of condensate, and 1,275 BD of NGLs for a total of 1,040 BOED.

• Then came Gulfport Energy’s Wagner 1-28H well in Harrison County producing 14 MMCFED of dry natural gas and 1,881 BD of natural gas liquids (after processing) along with 432 barrels of oil, signifi cantly higher than the IP rate of Chesapeake’s Buell well. Gulfport plans to drill 200 wells in the area in the next four years.

• There are other big players here also: BP has invested, then there’s Hess and CONSOL who entered into a 50/50 joint venture a year ago valued at almost $600 million to fund drilling and development across 200,000 acres.

And there is more activity when it comes to deals tak-ing place in the Utica involving acquisitions and infra-structure as indicated by the following examples:• EnerVest Ltd. amassed a huge collection of Utica

drilling rights beginning in 2003 with plans to harvest their investment. Accordingly, they plan to sell drilling rights to about 70% of the acreage and retain slightly more than 200,000 net acres whose potential will be determined in the future. It’s estimated this sale could generate more than $6 billion.

• In September, Spectra Energy, EnBridge and DTE Energy formed a Utica pipe-line joint venture with plans to commence operations by late 2015 depending upon demand at that time. Total investment for this new pipeline system is estimated at $1.2 billion to $1.5 billion.• Also in September, NiSource and Hilcorp Energy announced a joint venture to construct the Pennant Mid-stream gathering pipeline infra-structure with NGL processing in Northeast Ohio/Western Pennsylvania. Reportedly it will cost around $300 million.

SummaryThere are more announced (and unannounced) deals and plans that will be adding to Utica momentum, support-ing a transition from early-stage to a bigger development opportunity that will probably rank with the big shale plays in the future. It will depend, of course, on continu-ing investment by larger players like Chesapeake, Hess, BP, CONSOL and others plus the near-term economics of crude oil and liquids to affi rm a logical path forward in Utica development. OGFJ

About the authorDon Warlick is president of WarlickEnergy

(www.warlickenergy.com), a Houston-based

energy intelligence fi rm. The company pub-

lishes a series of special reports on each of the

leading US unconventional shales and also

provides market research services addressing

North American and International oil &

gas markets.

Utica vs. Eagle Ford

Don Warlick, WarlickEnergy

Early-stage Utica deals, characteristics and how the plays stack up

Utica Shale

Mich.

LakeHuron

Lake Erie

Lake Ontario

Ohio

Ky.

N. C.Tenn.

Va.

Pa.

Uticashale

N. Y.

Vt.CANADA

N. H.

Mass.

R. I.

Conn.

N. J.

Del.

Md.

*Approximate

W. Va.


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Deal Monitor


PLS Inc. reports that oil and gas upstream M&A deal value in Q3 2012 increased around the world to $49.8 billion in 154 transactions (with values

disclosed). This includes CNOOC’s $17.9 billion bid for Nexen announced July 23rd. Compared to Q2, deal value is up 79% from $27.8 billion while deal count is down 25% from 193. Regionally, the markets are getting bigger deals done while smaller deals are slowing down. The Q3 mar-ket as measured by deal count is the lowest in two years.

In Q3, 11 deals hit the >$1 billion mark led by CNOOC’s $17.9 billion offer for Calgary-based Nexen. Rounding out the other top 5 deals are Plains E&P’s buy of select BP Gulf of Mexico assets ($5.6 billion), Shell, Chevron and Enervest’s purchase of Chesapeake’s Permian basin assets ($3.3 billion), Shell’s purchase of an Australian

LNG project from Chevron ($2.4 billion) and ExxonMo-bil’s buy of Denbury’s Bakken assets ($2.0 billion).

In the US, deal value surged to $19.4 billion in 56 transactions, up from Q2 total of $11.0 billion in 69 trans-actions. In Canada, deal value rose to $19.7 billion (31 deals), up from $7.7 billion in Q2 (37 deals). Internation-ally (outside of North America), deal value totaled $10.7 billion (67 deals), up from $9.1 billion (87 deals).

Regarding activity this month (as shown in the table below), the US continues to see signifi cant activity in con-ventional Gulf Coast and Gulf of Mexico regions. W&T Offshore paid $216 million for the last tranche of Gulf of Mexico assets from Newfi eld Exploration – a company that created tremendous value as a Gulf of Mexico exploitation fi rm. EPL Oil & Gas bought all of Hilcorp’s Gulf of Mex-

Third quarter 2012 deal value

is $50 billion globally Ronyld Wise, PLS Inc., Houston

PLS Inc., Monthly Deal Monitor – Select transactions 09/17/12 - 10/16/12

US Transactions

Date Announced Buyer Seller Asset Location

16-Oct-12 Northstar Offshore Group Undisclosed Gulf of Mexico (Shallow)

11-Oct-12 Texas Petroleum Investment Forest Oil GC Onshore

3-Oct-12 Argent Energy Trust EnergyQuest II Multiple

25-Sep-12 Summit Energy GMX Resources Mid-Continent

20-Sep-12 ExxonMobil Denbury Resources Bakken Shale

20-Sep-12 Denbury Resources ExxonMobil Multiple

18-Sep-12 W&T Offshore Newfi eld Exploration Gulf of Mexico (Deep)

17-Sep-12 EPL Oil & Gas Hilcorp Energy Gulf of Mexico (Shallow)

Total Transaction value

Number of Transactions

International Transactions

Date Announced Buyer Seller Asset Location

16-Oct-12 OMV RWE Norway

15-Oct-12 Canacol Energy Shona Energy International Colombia

15-Oct-12 Bayfi eld Energy Trinity Exploration & Production Trinidad and Tobago

9-Oct-12 Ithaca Energy Noble Energy United Kingdom

1-Oct-12 Undisclosed Equal Energy Canada

25-Sep-12 Undisclosed Lone Pine Resources Canada Canada

Total Transaction value

Number of Transactions

PLS Inc. Validity of data is not guaranteed and is based on information available at time of publication.

Prepared by PLS Inc. For more information, email [email protected].

+ =


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Deal Monitor


ico shelf assets for $550 million. Moving onshore, Forest Oil sold its conventional south Louisiana assets for $220 million to privately-held Texas Petroleum. On the uncon-ventional side, ExxonMobil bought out all of Denbury’s North Dakota Bakken assets for $2.0 billion. PLS analysts estimate the acreage part of this deal to be $834 million - 74,000 acres in the core at $10,000 per acre plus 99,000 acres non-core at $1,000 per acre. In return, Denbury received cash plus two signifi cant Exxon owned C02 fi elds – one in the Rockies and one on the Gulf Coast. PLS estimates the value of these two fi elds to be $400 million.

Activity in Canada slowed signifi cantly this month as producers are hesitant to sell during a low cycle in gas prices.

Internationally, activity also slowed. The largest deal is OMV’s $321 million purchase of a 20% WI in the Edvard Grieg oilfi eld development project (formerly known as Luno) in the Norwegian North Sea.

At press time (late October), several signifi cant develop-ments are also impacting the M&A markets. Once the US elections conclude on November 6, the markets should gain some clarity on future US policies. In Canada, on October 19, the government moved to block Petronas’ June 28 $5.8 billion bid for Progress Energy citing insuffi -cient “net benefi t” to Canada. Petronas and Progress have thirty days to work with government offi cials to address

and clarify the ruling. The vagaries around “net benefi t” will be a primary focus in Canada for the foreseeable future. Others foreign entities are interested in Progress. The issue has analysts factoring additional risk into govern-ment approval of CNOOC’s $17.9 billion bid for Nexen announced July 23.

Also, in Canada ExxonMobil offered $3.1 billion on October 17 to buy Celtic Exploration marking Exxon’s largest unconventional Canadian deal to date in the coun-try. And, on October 22, Rosneft surprised the markets with an offer to buy 100% of TNK-BP for a total of $60 billion. AAR (controlled by Russian billionaires) agreed to sell 50% of TNK-BP for $30.8 billion in cash plus net debt assumed while BP agreed to sell the other 50% of TNK-BP for $28.2 billion in cash, net debt assumed and stock of Rosneft. If completed, this deal would rank as the second largest oil deal ever – behind the $82 billion Exxon’s $82 billion takeover of Mobil in 1998.

Looking forward, as of mid-October, PLS estimates that there is $107 billion of deals on the market globally (excluding TNK-BP). This is up slightly from the $105 billion tally PLS prepared in mid-July 2012. Leading the list of sellers are Total (selling an estimated $10 billion upstream), Shell (selling $8 billion in Australia), BP (sell-ing an estimated $7 billion in Argentina) and Petrobras (selling up to $7 billion in the Gulf of Mexico). OGFJ

Note: Canada transactions assume 20% royalty, unless disclosed.

Proved Reserve Value ($MM)

Non Proved Reserve Value

($MM)Reserves(MMBoe)

Production(Boe/D)

Reserves($/Boe)

Production($/Boe/d)

Reserves($/Mcfe)

Production($/Mcfe/d)

$160.0 7.4 7,400 $21.62 $76,190 $3.60 $12,698

$220.0 7.5 7,500 $29.33 $66,007 $4.89 $11,001

$132.5 3.2 3,198 $41.43 $181,507 $6.91 $30,251

$69.0 11.5 11,495 $6.00 $35,994 $1.00 $5,999

$1,166.0 $834.0 107.0 107,000 $10.90 $75,714 $1.82 $12,619

$215.0 $185.0 10.0 10,000 $21.50 $59,722 $3.58 $9,954

$216.0 $12.0 7.7 7,700 $28.05 $25,868 $4.68 $4,311

$550.0 36.3 36,300 $15.15 $55,000 $2.53 $9,167

$2728.5

8

$1031.0 Median

Mean

$21.56

$21.75

$62,864

$72,000

$3.59

$3.62

$10,477

$12,000

2P Reserve Value ($MM)

Non 2P Reserve Value ($MM)

2P Reserves(MMBoe)

Production(Boe/D)

2P Reserves($/Boe)

Production($/Boe/d)

2P Reserves($/Mcfe)

Production($/Mcfe/d)

$320.8 38.0 NA $8.44 - $1.41 -

$146.2 $12.0 14.6 2,147 $10.03 $68,072 $1.67 $11,345

$85.3 NA 2,370 - $35,979 - $5,996

$38.5 3.4 1,100 $11.32 $35,000 $1.89 $5,833

$17.7 35.0 596 NA $29,698 - -

$19.0 NA 454 NA $41,887 - -

$627.4

6

$12.0 Median

Mean

$10.03

$9.93

$35,979

$42,187

$1.67

$1.66

$5,996

$7,725


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OGJ150 Quarterly


Revenue takes a 20% dip,

income down 10% in 2Q

The top 20 fastest growing companies1

2nd quarterrank by

total assets Company

— Stockholders’ equity — ——– Net income ——– –––– Long-term debt ––––

Most recent quarter

Preceding quarter2

Change, %

Most recent quarter

Preceding quarter2

Change, %

Most recent quarter

Preceding quarter2

–––––– $1,000 –––––– –––––– $1,000 –––––– –––––– $1,000 ––––––

39 Berry Petroleum Co. 958,806 878,537 9.1 81,016 33,898 139.0 -- --

82 Callon Petroleum Co. 207,222 198,751 4.3 3,799 488 678.5 -- --

58 Carrizo Oil & Gas Inc. 557,300 523,086 6.5 28,504 9,423 202.5 816,478 870,331

56 Chaparral Energy Inc. 463,079 426,803 8.5 40,463 9,782 313.6 1,143,401 1,071,955

2 Chevron Corp. 131,289,000 126,326,000 3.9 7,232,000 6,499,000 11.3 9,765,000 8,765,000

59 Clayton Williams Energy Inc. 384,102 351,280 9.3 32,822 7,779 321.9 699,560 624,547

21 Concho Resources Inc. 3,355,565 3,025,723 10.9 319,297 31,117 926.1 2,523,366 2,281,752

24 Continental Resources Inc. 2,791,497 2,379,369 17.3 405,684 69,094 487.1 2,252,918 1,891,651

16 Denbury Resources Inc. 5,153,197 4,928,442 4.6 211,865 113,467 86.7 2,942,070 2,727,700

29 Energen Corp. 2,692,544 2,473,824 8.8 131,287 57,406 128.7 1,153,599 1,153,686

65 Energy Partners Ltd. 522,034 489,744 6.6 35,401 1,503 2,255.4 204,750 204,568

73 GeoResources Inc. 408,787 379,139 7.8 20,704 11,420 81.3 80,000 60,000

49 Laredo Petroleum Holdings Inc. 822,058 788,495 4.3 30,975 26,235 18.1 1,051,863 781,913

62 Legacy Reserves LP 526,962 469,703 12.2 82,942 7,389 1,022.5 439,000 333,000

63 Northern Oil and Gas Inc. 558,240 510,047 9.4 43,626 8,806 395.4 -- --

88 PrimeEnergy Corp. 42,124 36,855 14.3 7,423 1,661 346.9 97,750 845,000

61 Rosetta Resources Inc. 732,022 655,309 11.7 76,969 22,297 245.2 290,000 230,000

112 Spindletop Oil & Gas Co. 17,128 16,110 6.3 1,018 742 37.2 -- --

55 W&T Offshore Inc. 595,167 544,416 9.3 53,567 3,218 1,564.6 680,000 684,000

26 Whiting Petroleum Corp. 3,279,821 3,125,182 4.9 150,851 98,446 53.2 1,420,000 1,240,000

1Based on 2nd quarter ending June 30, 2012, unless otherwise noted. Companies were selected on the basis of growth in stockholders’ equity from previous quarter. Only companies with positive net income for both

quarters were considered. Companies were not considered if they had a decline in net income, were subsidiaries of another company, or became public within the last year. 2Based on previously reported data.

Don Stowers, Editor, OGFJ

Laura Bell, Statistics Editor, Oil & Gas Journal

Revenues in the second quarter of 2012 dropped sharply from the same quarter in 2011 –

down $62.5 billion, or 20%, for the

group of publicly-traded US-based companies track by Oil & Gas Journal and Oil & Gas Financial Journal. Revenues also fell from the fi rst quar-

ter of 2012 – down $38.5 billion, or 13%. The year-over-year numbers represent the largest decline since the onset of the 2008-2009 recession,

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OGJ150 Quarterly


which had a signifi cant impact on drilling activity and earnings.

The only bright spot is net income, which dipped $3.4 billion, or 10%, for the collective companies from 2Q11 to 2Q12, but rose $5.5 billion, or 21%, from the previous quarter despite the reduced revenues.

The number of reporting compa-nies rose slightly, from 123 to 136, in the second quarter of 2012. For these companies, total revenue was $303.1 billion, down $1.5 billion from the same quarter in 2011 but up $2 billion over the prior quarter. So the 1% change either way means

that revenue growth has been essen-tially fl at for several quarters.

Year-to-date capital spending stood at nearly $97.2 billion for the second quarter of 2012 compared to $81.6 billion for the second quar-ter of 2011. This represents a 20% increase.

Total asset value for the combined OGJ150 group of companies grew to nearly $1.298 trillion from $1.276 trillion year over year, represent-ing about a 2% increase. However, compared to the previous quarter, asset value fell by almost $54 billion, a 4% drop.

Stockholder equity for the entire group rose by $19.7 billion to $640.5 billion (about a 2% increase) from the 2Q2011 to the 2Q2012. However, the fi gure declined by nearly $7.0 bil-lion from $647.5 billion (down about 1%) from the fi rst quarter.

Largest in net incomeThe 20 largest companies ranked according to net income had $35.1 billion in collective net income for the second quarter of 2012. This compares with $27.3 billion the pre-vious quarter and $33.3 billion for the second quarter of 2011.

Once again, the $35.1 billion in net income for the top 20 companies is greater than the $32.7 billion in collective net income for the entire OGJ150 group of 136 companies. In other words, the largest 20 compa-nies in net income represented 108% of the profi ts of the entire group.

Of the 136 companies in the group, 50 showed a net loss in the income column. This represents 37% of the entire group. Among the

The top 20 in net income and stockholders’ equity*

Rank CompanyNet income,

$1,000 Rank CompanyStockholders’equity, $1,000

1 ExxonMobil Corp. 17,654,000 1 ExxonMobil Corp. 167,985,000

2 Chevron Corp. 7,232,000 2 Chevron Corp. 131,289,000

3 ConocoPhillips 2,289,000 3 ConocoPhillips 46,443,000

4 Occidental Petroleum Corp. 1,328,000 4 Occidental Petroleum Corp. 39,550,000

5 Chesapeake Energy Corp. 1,037,000 5 Apache Corp. 30,673,000

6 Sandridge Energy Inc. 921,867 6 Devon Energy Corp. 22,225,000

7 Hess Corp. 535,000 7 Anadarko Petroleum Corp. 21,278,000

8 Devon Energy Corp. 477,000 8 Hess Corp. 19,959,000

9 Continental Resources Inc. 405,684 9 Chesapeake Energy Corp. 19,788,000

10 EOG Resources Inc. 395,778 10 Marathon Oil Corp. 17,785,000

11 Marathon Oil Corp. 393,000 11 EOG Resources Inc. 13,355,141

12 Apache Corp. 356,000 12 Murphy Oil Corp. 9,304,628

13 Kinder Morgan CO2 Co. LP 327,000 13 Noble Energy Inc. 7,805,000

14 Concho Resources Inc. 319,297 14 Pioneer Natural Resources Co. 5,756,976

15 Murphy Oil Corp. 295,437 15 WPX Energy Inc. 5,631,000

16 Noble Energy Inc. 292,000 16 Denbury Resources Inc. 5,153,197

17 Linn Energy LLC 237,086 17 Sandridge Energy Inc. 4,422,078

18 Plains Exploration & Production Co. 232,275 18 Newfield Exploration Co. 4,191,000

19 Denbury Resources Inc. 211,865 19 Linn Energy LLC 4,131,663

20 Whiting Petroleum Corp. 150,851 20 Plains Exploration & Production Co. 3,763,510

Total 35,090,140 Total 580,489,193

*Based on 2nd quarter ended June 30, 2012

Some key changes from previous quarter

How company appeared on last quarter’s list Why change?

How company appears on this quarter’s list

El Paso Corp. Acquired by Kinder Morgan Inc.

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OGJ150 Quarterly


larger companies reporting losses: No. 6 Anadarko Petroleum ($70 million); No. 14 Pioneer Natural Resources ($39.5 million); No. 19 WPX Energy ($6 million); and No. 23 Southwestern Energy ($488.1 million).

In many cases, low natural gas prices were instrumental in the income loss. Since prices have rebounded a little since the second quarter and are trending upward, it is likely many of these companies will show better results when third-quarter fi nancials are reported.

The 10 largest companies in net income were (in order): Exxon-Mobil ($17.7 billion); Chevron ($7.2 billion); ConocoPhillips ($2.3 billion); Occidental ($1.3 billion); Chesapeake ($1.0 billion); Sandridge Energy ($922 million); Hess Corp. ($535 million); Devon Energy ($477 million); Continental Resources ($406 million); and EOG Resources ($396 million).

ExxonMobil’s net income of $17.7 billion amounted to approxi-mately 54% of the total net income for the entire group of 136 compa-

nies. The top fi ve companies in net income had about 91% of the total net income for the entire group.

Largest in total revenueThe top 20 companies in total rev-enue had $253.5 billion in revenue compared to $264.5 billion for the entire OGJ150 group of 136 compa-nies, or roughly 96% of the total.

The 10 largest companies in total revenue were (in order): ExxonMobil ($127.4 billion); Chevron ($62.6 billion); ConocoPhillips ($15.2 bil-lion); Hess ($9.3 billion); Murphy

The top 20 in spending*

Rank Company

Capital, exploratory

spending, $1,000

1 ExxonMobil Corp. 16,560,000

2 Chevron Corp. 12,962,000

3 ConocoPhillips 7,858,000

4 Occidental Petroleum Corp. 5,125,000

5 Chesapeake Energy Corp. 5,120,000

6 Devon Energy Corp. 4,267,000

7 Hess Corp. 3,856,000

8 Apache Corp. 3,756,000

9 EOG Resources Inc. 3,748,278

10 Anadarko Petroleum Corp. 3,553,000

11 Marathon Oil Corp. 2,181,000

12 Noble Energy Inc. 1,900,000

13 Continental Resources Inc. 1,778,808

14 Pioneer Natural Resources Co. 1,424,807

15 Murphy Oil Corp. 1,337,019

16 Southwestern Energy Co. 1,140,661

17 Sandridge Energy Inc. 1,123,040

18 Whiting Petroleum Corp. 979,522

19 Concho Resources Inc. 949,059

20 Newfield Exploration Co. 875,000

Total 80,494,194

*Based on year-to-date June 30, 2012.

The top 20 in total revenue*

Rank Company

Totalrevenue,

$1,000




4 Hess Corp. 9,309,000









13 Continental Resources Inc. 1,004,719

14 Noble Energy Inc. 966,000

15 Pioneer Natural Resources Co. 924,732

16 Linn Energy LLC 800,597

17 WPX Energy Inc. 775,000

18 Newfield Exploration Co. 628,000

19 Denbury Resources Inc. 601,781

20 Southwestern Energy Co. 599,728

Total 253,564,215

*Based on 2nd quarter ended June 30, 2012

The top 20 in assets — market capitalization*

Rank Company

Market capitalization,

$1,000









9 Hess Corp. 14,838,716



12 Noble Energy Inc. 15,182,780


14 Pioneer Natural Resources Co. 10,852,982

15 Linn Energy LLC 7,603,128

16 Denbury Resources Inc. 5,908,676

17 Plains Exploration & Production Co. 4,534,702

18 Newfield Exploration Co. 3,956,152

19 WPX Energy Inc. 3,219,820

20 Sandridge Energy Inc. 3,272,688

Total 1,058,245,671

*As of June 30, 2012

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OGJ150 Quarterly


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Oil ($7.2 billion); Occidental ($5.8 billion); Apache ($4.0 billion); Mara-thon Oil ($3.8 billion); Chesapeake ($3.4 billion); and Anadarko ($3.2 billion).

Clearly, among US-based compa-nies in total revenue and net income, ExxonMobil Corp. is in a class by itself.

Top spendersSpending by the top 20 companies in the second quarter continued to surge. It more than doubled from the fi rst quarter of 2012 to the second – a 103% increase to $80.5 billion. The top 10 spenders were, in order: ExxonMobil ($16.6 billion); Chevron ($13 billion); ConocoPhil-lips ($7.9 billion); Occidental ($5.1 billion); Chesapeake ($5.1 billion); Devon ($4.3 billion); Hess ($3.9 billion); Apache ($3.8 billion); EOG Resources ($3.7 billion); and Anadarko ($3.6 billion).

Fastest-growing companiesThe fi ve fastest-growing companies, ranked by stockholders’ equity, wereContinental Resources (up 17.3%); PrimeEnergy Corp. (up 14.3%); Legacy Reserves LP (up 12.2%); Rosetta Resources (up 11.7%); and Concho Resources (up 10.9%).

Continental Resources recently unveiled its newest oil fi eld in an area of southern Oklahoma that has produced some of the state’s richest discoveries. The South Central Okla-homa Oil Province, known at Conti-nental as SCOOP, covers much of four counties in south central Oklahoma. The rock is an oil-rich portion of the Woodford Shale that lies beneath pre-viously developed oil fi elds.

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OGJ150 Quarterly


Rankby totalassets 2Q12

——————––––––––– 2nd Quarter ending June 30, 2012 –––––––––————YTD

Capital & expl. ––– spending –––

Totalassets$1,000

Stockholders’ —— equity ——

Total—— revenue ——

Net—— income ——

Company Rank $1,000 Rank $1,000 Rank $1,000 Rank $1,000

1 ExxonMobil Corp. 329,645,000 1 167,985,000 1 127,363,000 1 17,654,000 1 16,560,000

2 Chevron Corp. 219,379,000 2 131,289,000 2 62,608,000 2 7,232,000 2 12,962,000

3 ConocoPhillips 114,008,000 3 46,443,000 3 15,166,000 3 2,289,000 3 7,858,000

4 Occidental Petroleum Corp. 64,283,000 4 39,550,000 6 5,792,000 4 1,328,000 4 5,125,000

5 Apache Corp. 57,217,000 5 30,673,000 7 3,972,000 12 356,000 8 3,756,000

6 Anadarko Petroleum Corp. 53,332,000 7 21,278,000 10 3,222,000 129 (70,000) 10 3,553,000

7 Chesapeake Energy Corp. 47,526,000 9 19,788,000 9 3,389,000 5 1,037,000 5 5,120,000

8 Devon Energy Corp. 43,470,000 6 22,225,000 12 2,559,000 8 477,000 6 4,267,000

9 Hess Corp. 40,614,000 8 19,959,000 4 9,309,000 7 535,000 7 3,856,000

10 Marathon Oil Corp. 32,250,000 10 17,785,000 8 3,784,000 11 393,000 11 2,181,000

11 EOG Resources Inc. 25,998,577 11 13,355,141 11 12,909,319 10 395,778 9 3,748,278

12 Noble Energy Inc. 16,981,000 13 7,805,000 14 966,000 16 292,000 12 1,900,000

13 Murphy Oil Corp. 15,000,768 12 9,304,628 5 7,190,339 15 295,437 15 1,337,019

14 Pioneer Natural Resources Co. 12,569,734 14 5,756,976 15 924,732 125 (39,537) 14 1,424,807

15 Linn Energy LLC 11,180,102 19 4,131,663 16 800,597 17 237,086 29 481,140

16 Denbury Resources Inc. 10,935,416 16 5,153,197 19 601,781 19 211,865 28 574,008

17 Plains Exploration & Production Co. 10,231,435 20 3,763,510 21 566,724 18 232,275 22 824,280

18 Newfield Exploration Co. 9,844,000 18 4,191,000 18 628,000 21 135,000 20 875,000

19 WPX Energy Inc. 9,842,000 15 5,631,000 17 775,000 113 (6,000) 21 828,000

20 Sandridge Energy Inc. 9,178,535 17 4,422,078 24 478,434 6 921,867 17 1,123,040

21 Concho Resources Inc. 7,758,309 23 3,355,565 27 2432,796 14 319,297 19 949,059

22 QEP Resources Inc. 7,637,600 22 3,416,200 23 500,200 84 200 26 681,500

23 Southwestern Energy Co. 7,503,963 21 3,515,877 20 2599,728 132 (488,100) 16 1,140,661

24 Continental Resources Inc. 7,254,312 26 2,791,497 13 1,004,719 9 405,684 13 1,778,808

25 Range Resources Corp. 6,543,894 28 2,416,721 26 442,440 30 55,676 23 781,574

26 Whiting Petroleum Corp. 6,510,584 25 3,279,821 22 502,174 20 150,851 18 979,522

27 Cimarex Energy Co. 6,031,304 24 3,291,974 29 353,122 28 64,302 24 752,390

28 Consol Energy Inc.3 5,970,939 — — 45 4158,643 70 51,144 59 143,206

29 Energen Corp. 5,779,540 27 2,692,544 25 2470,355 22 131,287 27 574,360

30 EQT Production6 5,469,398 — — 44 158,649 48 17,704 34 448,611

31 Cabot Oil & Gas Corp. 4,410,192 29 2,131,330 35 265,657 36 35,937 35 411,327

32 Kinder Morgan CO2 Co. LP7 4,169,000 — — 28 413,000 13 8327,000 — —

33 SM Energy Inc. 3,999,571 33 1,527,696 32 304,425 44 24,889 25 705,366

34 Helix Energy Solutions Group Inc. 3,688,805 32 1,579,988 30 9347,394 33 44,561 56 150,107

35 Unit Corp. 3,353,437 30 2,000,378 31 329,892 121 (19,302) 39 371,703

36 Quicksilver Resources Inc. 3,244,524 53 578,793 42 165,562 135 (672,541) 44 307,169

37 Ultra Petroleum 3,232,822 58 488,574 41 170,270 136 (1,186,982) 31 469,290

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OGJ150 Quarterly





Totalassets$1,000





38 Forest Oil Corp. 3,117,330 48 696,125 49 135,731 134 (511,173) 37 395,781

39 Berry Petroleum Co. 3,016,054 41 958,806 36 229,703 26 81,016 41 328,968

40 Bill Barrett Corp. 2,955,446 35 1,235,382 43 160,465 65 3,298 33 460,059

41 Exco Resources Inc. 2,942,267 46 773,101 54 117,978 133 (496,433) 45 305,969

42 McMoran Exploration Co. 2,786,669 31 1,654,085 59 90,295 128 (65,158) 43 312,272

43 High Mount Exploration & Production LLC 2,709,000 — — 65 69,000 131 (139,000) — —

44 Comstock Resources Inc. 2,661,312 37 1,041,293 52 125,028 117 (10,304) 40 348,337

45 Stone Energy Corp. 2,583,230 43 832,492 37 226,640 40 30,547 48 275,813

46 BreitBurn Energy Partners LP 2,431,490 34 101,485,766 39 4203,176 24 92,523 75 37,382

47 Swift Energy Co. 2,236,021 38 1,013,687 50 134,757 68 3,028 38 374,753

48 Vanguard Natural Resources LLC 2,157,797 40 969,673 46 151,915 23 103,447 79 23,646

49 Laredo Petroleum Holdings Inc. 2,115,938 45 822,058 47 140,624 39 30,975 30 480,877

50 Eagle Rock Energy Partners LP 2,098,531 39 10998,616 34 282,404 29 61,789 57 150,023

51 EV Energy Partners LP 2,062,015 36 101,178,774 68 63,552 50 14,956 68 62,566

52 Penn Virginia Corp. 1,977,072 44 826,588 64 76,845 112 (5,638) 51 188,236

53 PDC Energy 1,917,828 42 858,844 55 106,045 53 12,271 54 165,157

54 Seneca Resources Corp.11, 12 131,885,014 — — 48 138,549 45 21,915 — —

55 W&T Offshore Inc. 1,872,818 52 595,167 38 215,513 31 53,567 52 187,284

56 Chaparral Energy Inc. 1,868,148 61 463,079 51 127,334 35 40,463 49 237,144

57 Magnum Hunter Resources Corp. 1,805,536 50 681,427 69 60,360 116 (7,457) 50 224,925

58 Carrizo Oil & Gas Inc. 1,704,642 55 557,300 60 83,818 41 28,504 36 409,027

59 Clayton Williams Energy Inc. 1,490,185 66 384,102 57 104,610 38 32,822 42 313,170

60 Fidelity Exploration & Production Co.14 151,481,556 — — 56 105,943 47 17,957 — —

61 Rosetta Resources Inc. 1,217,386 47 732,022 40 197,983 27 76,969 47 277,961

62 Legacy Reserves LP 1,162,095 56 10526,962 62 79,166 25 82,942 61 134,342

63 Northern Oil and Gas Inc. 1,073,598 54 558,240 53 119,208 34 43,626 46 283,869

64 Halcon Resources Corp. 994,786 51 680,889 80 223,281 59 7,659 32 468,197

65 Energy Partners Ltd. 989,260 57 522,034 58 99,320 37 35,401 64 85,133

66 Venoco Inc. 937,813 81 64,339 61 82,499 51 14,546 62 132,039

67 Goodrich Petroleum Corp. 892,858 75 123,433 71 41,347 108 (3,202) 63 131,777

68 Gulfport Energy Corp. 871,800 49 692,714 67 66,329 43 25,117 55 150,653

69 Layne Christensen Co.16 831,667 62 429,831 33 289,560 124 (23,866) 74 41,699

70 Wexpro 15768,200 — — 63 77,700 42 25,800 — —

71 Approach Resources Inc. 734,338 59 480,333 78 29,927 58 7,862 58 147,869

72 Rex Energy Corp. 655,126 63 415,296 76 230,257 32 53,143 66 74,118

73 GeoResources Inc. 653,311 64 408,787 66 68,309 46 20,704 53 168,517

74 Contango Oil & Gas Co.17 624,654 60 464,339 72 39,823 56 9,337 80 20,847

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OGJ150 Quarterly





Totalassets$1,000





75 Miller Energy Resources Inc.18 546,516 67 299,357 98 8,265 85 189 93 4,714

76 Matador Resources Co. 537,689 65 407,777 70 55,935 114 (6,676) 60 137,946

77 Crimson Exploration Inc. 467,246 71 170,048 75 30,524 62 3,911 69 60,288

78 PetroQuest Energy Inc. 457,031 72 151,709 74 33,413 126 (53,232) 65 75,825

79 Black Hills Corp.3 416,617 — — 81 20,621 122 (19,621) — —

80 GMX Resources Inc. 394,792 124 (67,673) 82 16,318 130 (103,312) 71 52,974

81 Triangle Petroleum Corp.16 384,671 68 208,253 94 10,343 102 (1,209) 70 55,952

82 Callon Petroleum Co. 378,612 69 207,222 79 225,360 64 3,799 67 72,538

83 Warren Resources Inc. 333,959 70 184,057 77 30,198 61 5,259 73 43,920

84 DTE Gas Resources19 15319,000 — — 91 212,000 105 (2,000) — —

85 PostRock Energy Services Corp. 267,663 114 1,451 87 13,938 120 (18,508) 89 8,998

86 Abraxas Petroleum Corp. 253,295 79 75,374 84 15,939 118 (10,926) 76 35,116

87 Dune Energy Inc. 246,600 76 123,313 89 13,109 77 878 81 17,721

88 PrimeEnergy Corp. 212,299 86 42,124 73 37,464 60 7,423 72 51,714

89 Double Eagle Petroleum Co. 159,252 84 51,449 102 5,243 110 (4,020) 86 12,739

90 US Energy Corp. 147,283 74 125,659 97 8,522 99 (990) 78 30,530

91 GeoMet Inc. 144,478 123 (61,255) 99 7,771 127 (53,904) 105 509

92 Dorchester Minerals LP 127,772 73 10126,708 85 215,242 57 8,680 — —

93 VOC Energy Trust 127,684 — — 92 11,883 54 11,730 — —

94 Voyager Oil & Gas Inc. 126,764 80 73,048 95 9,015 115 (6,961) 83 15,776

95 Panhandle Oil and Gas Inc.20 126,626 78 83,729 88 13,650 66 3,100 82 16,026

96 Synergy Resources Corp.21 117,160 77 99,015 100 7,538 69 2,431 77 34,026

97 FX Energy Inc. 108,595 82 61,604 96 8,665 119 (12,115) 88 9,407

98 Credo Petroleum Corp.22 90,046 83 52,938 101 6,362 76 928 84 15,745

99 Lucas Energy Inc.23 65,454 87 33,088 115 11,718 104 (1,907) 99 2,379

100 Gasco Energy Inc. 64,022 89 29,591 118 1,604 111 (5,152) 96 3,812

101 Evolution Petroleum Corp.17 58,955 85 46,623 104 4,536 72 1,095 97 3,353

102 American Eagle Energy Corp. 56,792 91 25,561 116 1,692 88 (147) 87 12,063

103 Tengasco Inc. 50,405 88 32,112 103 5,230 74 1,087 92 6,792

104 Cross Borders Resources Corp. 37,468 94 19,121 105 4,148 79 475 90 7,906

105 Adams Resources & Energy Inc.3 37,148 — — 107 23,624 96 (557) 91 7,125

106 Reserve Petroleum Co. 35,030 90 28,720 108 23,065 71 1,112 98 3,284

107 EnerJex Resources Inc. 34,061 92 25,310 112 2,049 67 3,062 94 4,551

108 Pegasi Energy Resources Corp. 31,691 98 14,223 130 183 106 (3,039) 95 4,390

109 Cubic Energy Inc.17 30,539 122 (8,169) 120 947 109 (3,651) 113 87

110 Earthstone Energy Inc.23 26,482 96 18,676 110 2,349 82 270 100 2,122

111 GeoPetro Resources Co. 24,761 93 19,330 136 — 98 (897) 111 127

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OGJ150 Quarterly





Totalassets$1,000





112 Spindletop Oil & Gas Co. 24,506 97 17,128 109 2,940 75 1,018 103 858

113 Duma Energy Corp.24 23,934 103 12,399 113 1,879 86 74 107 437

114 Houston American Energy Corp. 22,931 95 18,914 134 36 123 (22,022) 85 14,867

115 FieldPoint Petroleum Corp. 21,379 105 10,410 111 2,158 78 719 102 972

116 Royale Energy Inc. 20,173 108 6,909 122 877 101 (1,075) 109 380

117 Mexco Energy Corp.23 16,204 100 12,955 123 627 87 (63) 106 471

118 San Juan Basin Royalty Trust 15,924 102 2512,475 93 10,793 55 2610,379 — —

119 Cross Timbers Royalty Trust 14,251 99 2512,975 106 3,962 63 263,823 — —

120 Texas Vanguard Oil Co. 14,075 101 12,607 114 1,772 83 206 108 424

121 Sun River Energy Inc.18 12,718 119 (1,521) 135 21 107 (3,059) 117 18

122 Pyramid Oil Co. 12,325 104 10,541 119 1,350 80 289 104 778

123 Daleco Resources Corp.27 11,952 112 3,061 131 166 91 (303) — —

124 Apache Offshore Investment Partnership 11,668 106 9,407 121 914 81 275 116 37

125 Blacksands Petroleum Inc.22 9,876 111 3,756 124 251 97 (676) 101 1,774

126 Alamo Energy Corp.16 8,470 110 4,975 133 66 94 (400) 118 4

127 Pioneer Oil & Gas20 8,048 107 7,526 127 211 89 (174) — —

128 Sabine Royalty Trust 6,507 109 5,868 86 15,110 52 14,300 — —

129 Blue Dolphin Energy Co.3 5,451 — — 125 250 92 7(311) — —

130 Permian Basin Royalty Trust 4,912 116 25851 83 16,142 49 2615,657 — —

131 Daybreak Oil & Gas Inc.28 3,133 120 (1,539) 128 203 90 (295) 112 114

132 TN-K Energy Group Inc. 2,756 118 (1,242) 117 1,649 73 1,093 114 69

133 Petron Energy II Inc. 2,562 113 1,625 132 105 95 (473) 110 148

134 Treaty Energy Corp. 2,184 117 (902) 90 13,087 100 (997) — —

135 United American Petroleum Corp. 2,146 115 1,420 129 189 103 (1,580) — —

136 Baron Energy Inc.29 661 121 (3,578) 126 225 93 (390) 115 62

— ATP Oil & Gas Corp.30 NA — NA — NA — NA — NA

— Black Raven Energy Inc.30 NA — NA — NA — NA — NA

— Glen Rose Petroleum Corp.30 NA — NA — NA — NA — NA

— John D. Oil and Gas Co.30 NA — NA — NA — NA — NA

— Oakridge Energy Inc.30 NA — NA — NA — NA — NA

— Savoy Energy Corp.30 NA — NA — NA — NA — NA

— Tri-Valley Corp.30 NA — NA — NA — NA — NA

TOTAL 1,297,649,756 640,538,848 264,542,392 32,650,951 97,228,503

NA = Not Available. *Annual data reported in OGJ150, Oct. 3, 2011, p. 50. 1Net operating. 2Operating. 3Oil and gas operations only. 4Sales. 5Before income taxes. 6Subsidiary of EQT Resources Inc. 7Subsidiary of Kinder Morgan Inc. 8Before depreciation, depletion and amortization. 9Net. 10Partner’s equity. 11Subsidiary of National Fuel Gas Co. 123rd quarter. 13Total assets are Sept. 30, 2011. 14Sub-

sidiary of MDU Resources Group. 15Total assets are Dec. 31, 2011. 162nd quarter July 31. 174th quarter. 181st quarter July 31. 19Subsidiary of DTE Energy Inc. 203rd quarter. 213rd quarter Mar. 31. 223rd

quarter May 31. 231st quarter. 243rd quarter Apr. 30. 25Trust corpus. 26Distributable income. 27Earnings before interest and taxes. 281st quarter May 31. 294th quarter July 31. 30Not filed at press time.

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Industry Briefs


Emerald Oil completes Williston Basin acquisitionDenver, CO-based Voyager Oil & Gas Inc. (dba Emerald Oil Inc.) has closed the previously announced acquisition of operated acreage in McKenzie County, North Dakota. Emerald acquired 4,453 net acres in McKenzie County, North Dakota for $3,200 per acre. The purchase included operating permits for four wells and a recently constructed well pad and tank battery at an additional cost of $1.18 million, for a total cash purchase price of $15.4 million. Emerald is focused primarily on the development of its approximately 48,100 net acres in the Williston Basin in North Dakota and Montana, prospective for oil in the Bakken and Three Forks formations. The next step in the conversion is to execute, noted Global Hunter Securities Octo-ber 8. The prospectivity supports the acreage value, and while the conver-sion to operator is daunting, the com-pany’s steps are well documented, noted the analyst, who estimate 2012 CF of $10.5 million to scale to $27.5 million in 2013.

Halcon to offer $700M in senior unsecured notesHalcon Resources Corp. intends to offer $700 million in aggregate principal amount of senior unsecured notes due 2021. Halcon intends to use the net proceeds from the offering to fund the cash consider-ation payable in connection with its pending acquisition of producing and undeveloped oil and gas assets in the Williston Basin. The offering is ex-pected to close into escrow, subject to release upon closing of the Williston Basin Assets acquisition.

Investment group launches OFS Capital A group of international oil and gas industry executives and investment bankers has launched OFS Capital (OFS), a boutique energy investment

and merchant bank. OFS provides services to the energy industry with a focus on the exploration and produc-tion, oilfi eld services, power, distri-bution, and renewables sectors. The group will advise both corporate and institutional clients and will be active throughout North and South Amer-ica. OFS Capital is co-headquartered in Houston and Rio de Janeiro, with offi ces in Washington, DC, Bogota, Mexico City, New York, and London.

Wynnchurch Capital sinks private equity into oil, gas drilling equipment companyOn October 1, private equity fi rm Wynnchurch Capital Ltd. made an equity investment in onshore and offshore oil and gas drilling equip-ment provider Loadmaster Derrick & Equipment Inc. Tommy Welsh and Tommy Hebert, the owners of Load-master, co-invested in the transaction and will continue to lead the Brous-sard, Louisiana-based company.

Chesapeake sells Glass Mountain Pipeline shareTulsa, Oklahoma-based SemGroup Corp. and Gavilon LLC said Octo-ber 10 that each has completed the acquisition of a 25% share of Glass Mountain Pipeline LLC previously owned by an affi liate of Chesapeake Energy. SemGroup now owns 50% of Glass Mountain Pipeline. The remaining 50% is now owned by Gavilon. Chesapeake will maintain its long-term transportation agree-ment with Glass Mountain Pipeline, providing the economic incentive for its construction. The Glass Mountain Pipeline will have an initial capac-ity of approximately 140,000 b/d and 440,000 barrels of intermediate storage. One lateral will originate in Woods County, OK. The second lateral will originate in Ellis County, OK. The pipeline will increase in diameter where the laterals inter-sect near in Major County, OK and continue east to Cushing, OK. The

pipeline will terminate at Gavilon’s Cushing facility, where the JV will own one million barrels of crude oil storage. Following pipeline construc-tion, Rose Rock Midstream LP, Sem-Group’s master limited partnership, will serve as the pipeline operator.

United Central Industrial merges with GHX IndustrialHouston-based GHX Industrial LLC and United Central Industrial Supply of Bristol, Tenn., have merged, form-ing a large, energy-focused indus-trial distribution and service-related company. Both entities will continue to operate independently, but will utilize a combination of shared administrative, strategic and manage-ment services. Since its inception in 1974, United Central has focused on serving mining industries in the US and Canada. GHX has a 70-year history of providing fl uid transfer (hoses), fl uid sealing (gaskets), and other products to a variety of oil and gas upstream companies, refi neries, power generation, petrochemical, mining, agriculture, and marine en-terprises. Coming out of the merger, The United Distribution Group Inc. has been formed to manage United Central and its subsidiaries, Good-ing Rubber Co. and National Mine Service and GHX and its subsidiaries McCarty Equipment Company and McCarty Equipment of Canada.

New railroad launched by Port San Antonio, Watco to meet Eagle Ford demandPort San Antonio and Watco Com-panies inaugurated a rail service that clears the way for growth at the Port’s East Kelly Railport. The San Antonio Central Railroad (SACRR) now operates within the 350-acre site. San Antonio Central also trans-fers railcars from nearby Union Pacifi c and BNSF Railway trains and delivers the cargo to the front door of the growing number of logistics, manu-facturing and warehousing businesses


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Industry Briefs


at the Port. In addition to operat-ing the region’s newest rail service, Watco Companies has completed the fi rst phase of track expansions at East Kelly Railport. Over the summer, the fi rm doubled track at the Railport from four to almost eight miles. Port San Antonio began operations at the Railport in 2007, and has added customers from various sectors. Re-cently, in particular, strong demand from oil and gas drilling projects on the Eagle Ford Shale have driven growth at the Railport. Between fi scal 2010 and 2011, rail volume grew over 75%—from 2,594 railcars served in FY2010 to 4,556 in FY2011. In FY2012, which concluded September 30, a new record was set with 5,167 railcars processed at the Railport. The new activity has been largely driven by demand for transloading services for drilling equipment and supplies headed to Eagle Ford Shale well sites. The track expansion now allows busi-nesses at the Railport to serve up to 20,000 railcars per year.

W&T Offshore to issue $250M private placement to fund GOM acquisition W&T Offshore Inc. is in the process of issuing $250 million of 8.5% senior notes due 2019 via a private place-ment to repay debt and partially fund a recent Gulf of Mexico asset acquisi-tion. The notes are proposed to be offered as additional notes under an indenture pursuant to which W&T Offshore initially issued $600 million principal amount of its 8.5% senior notes due 2019 on June 10, 2011. The company intends to apply the net proceeds of this private offering to repay a portion of the outstanding indebtedness recently incurred under its revolving credit facility to partially fund its recently completed acquisi-tion of exploration and production properties in the Gulf of Mexico from Newfi eld Exploration. On October 5, W&T Offshore closed on the $208 million purchase of 7.7 MM-

boe of proved reserves, 8,350 boepd of production (37% crude oil), and 78 GoM lease blocks from Newfi eld Exploration. According to Global Hunter Securities, as of October 4, W&T Offshore had a cash balance of $46 million with $120 million drawn down on its revolver which holds a $650 million borrowing base. On a debt maturity basis, the current revolver matures in 2015 while the outstanding $600 million of 8.5% notes mature in 2019.

AusTex equity raise to fund Miss Lime developmentAusTex Oil Ltd. has plans to raise up to A$12.5 million in an equity capital raise which will fund the appraisal and development of the company’s acreage in the light oil portion of the Mississippi Lime Play. The offer com-prises a placement of approximately 83.3 million new fully paid ordinary shares to investors at a price of $0.12 per share which raised $10 million; and, a Share Purchase Plan of up to $15,000 per eligible shareholder at the Issue Price to raise up to $2.5 million. GMP Securities is Sole Lead Manager and Bookrunner. The fi rst tranche of 29.3 million shares was ex-pected to settle on October 24, 2012, and the second tranche of approxi-mately 54 million shares is subject to shareholder approval at a meeting to be held on or around November 21, 2012. Net proceeds from the offer will be used to fund appraisal and development of AusTex’s acreage in the light oil window of the Mississippi Lime, including: participating in ad-ditional horizontal wells with Range Resources, including an offsetting well to the Balder #1-30N (1st 30-day average rate 899 boepd, 70% oil); continuation of the two vertical well per month program at the company’s 100% owned Snake River Project in Northern OK; drilling activity at AusTex’s properties in Kansas; and pursuing land acquisitions and joint ventures.

Copano makes public offering Copano Energy LLC has started a public offering of 6,000,000 of its common units representing limited liability company interests in the company. Copano also intends to grant the underwriters a 30-day option to purchase up to 900,000 additional common units if the un-derwriters sell more than 6,000,000 common units in the offering. Co-pano intends to use the net proceeds from the offering, including the proceeds from any exercise of the underwriters’ option to purchase additional common units, to repay a portion of the outstanding indebted-ness under its revolving credit facility and expects to use the increased bor-rowing capacity as needed for capital projects, acquisitions, hedging, working capital and general corpo-rate purposes. Barclays, BofA Merrill Lynch, Morgan Stanley, Wells Fargo Securities, Goldman, Sachs & Co. and RBC Capital Markets are acting as joint book-running managers for the offering.

CLNG ramps up effort to highlight LNG benefi ts The Center for Liquefi ed Natural Gas (CLNG) has launched a new initiative and dedicated website (http://lnginitiative.org/) focused on America’s opportunity to sell liquefi ed natural gas (LNG). The CLNG exports website will provide the public with information and analyses on the benefi ts of selling natural gas outside the US. “A revolution in American energy has unlocked a vast supply of natural gas, more than enough to meet the needs of our country for generations to come,” said CLNG president Bill Cooper. “We can continue to harness this important resource for our domestic needs while also selling some to our trading partners. This will grow our economy, revitalize our manufacturing sector, and create tens of thousands of American jobs.”


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Visit our Unconventional

Resources Center on OGFJ.com

E&P companies are shifting budgets to

high-BTU, liquid-rich plays. Bentek’s

Rusty Braziel provides expert analysis.

Go to www.ogfj.com <http://www.ogfj.com/> and click Unconventional Resources

C A N A D A

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Bakken

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Marcellus SW Penn.

Where are the high BTU plays?

North American shale plays such as

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Marcellus, Bakken, and Woodford are

all noteworthy formations, but unconventional

resources include more than shale. They also

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Shale resource plays, lower 48 states

Find shale rankings, top producers, the latest

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Get up-to-date information on the most

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tional resources space –– all in one place.

Reports from Don Warlick of Warlick Inter-

national provide insight into the top 5 US

shale plays and the 7 factors driving the

shale business.

Take a photo with

a QRcode app!


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Energy Players


Rich named CEO of Parker Drilling Parker Drilling has selected Gary Rich as president and CEO. Rich will also serve as a member of Parker Drill-ing’s board of directors. Most recently, Rich served as vice president of global sales for Baker Hughes, and prior to this role, he served as president of that company’s European operations. Previously, Rich was president of Hughes Christensen Company (HCC). He assumes the president and CEO role from Robert L. Parker Jr., who will remain execu-tive chairman of Parker Drilling. Rich holds a BS from Brigham Young Uni-versity and an MS from the Univer-sity of Texas. He holds a certifi cation in management from the University of Utah and attended the California Institute of Technology’s Strategic Marketing of Technology Products program.

Allen Parks joins GHS as managing directorAllen Parks, founder of Parks Paton Hoepfl & Brown (PPHB), has joined Global Hunter Securities as Manag-ing Director, Investment Banking. Parks has over three decades of expe-rience in drilling, M&A advisory, and investment banking. Prior to joining GHS, Parks founded PPHB and was a partner for nearly a decade provid-ing fi nancial advisory expertise to the oilfi eld services sector. He spear-headed the licensing process and was the fi rm’s chief compliance offi cer in reporting to FINRA. Parks has held executive positions with CIBC World Markets and Dain Rauscher Wessels Inc. While at Dual Drilling Company, he spent two decades working as a senior fi nancial operations executive. Parks holds a bachelor of science in chemical engineering from the Uni-versity of Texas, a master of business administration from the University of

Texas, and completed the advanced management program at the Harvard Business School.

Pinsonnault joins Deloitte Corporate Restructuring GroupDeloitte Financial Ad-visory Services LLP has expanded its Corporate Restructuring Group (Deloitte CRG) with the addition of Scott Pinsonnault as a direc-tor specializing in oil and gas companies and the broader energy sector. Pinson-nault has 17 years of experience working on corporate bankruptcies and restructurings in oil, gas, energy and related industries. He has been the chief restructuring offi cer of two oil and gas companies and an adviser to a third. He has represented various banks as a fi nancial advisor for their interests in exploration and produc-tion and oil fi eld service companies. Prior to joining Deloitte CRG, Pinsonnault worked for a boutique restructuring fi rm. Pinsonnault earned his bachelor’s degree from St. Lawrence University, his master’s degree from Texas A&M University, and an MBA from Tulane University.

Chesapeake names Webb senior VP Chesapeake Energy Corp. has appointed James R. Webb as senior vice president – legal and general counsel. Webb joins Chesapeake on a full-time basis after serv-ing on a contract basis as chief legal counsel. For the past 17 years, Webb has practiced law at McAfee & Taft, Oklahoma’s largest law fi rm, and has served as a partner for the past 12 years. Prior to that, he worked at the law fi rm of Gorsuch Kirgis in Denver. Webb graduated with a bachelor’s

degree from Austin College in Sher-man, Texas and a Juris Doctorate degree from Washington University in St. Louis. Henry J. Hood, Chesa-peake’s senior vice president – land and legal since 1997, will transfer his responsibilities for Chesapeake’s legal department to Webb while retaining responsibility for the management of the company’s land and regulatory departments.

Ballard Spahr’s Stark to co-chair ABA Energy CommitteeRoger D. Stark, a Washington-based partner at Ballard Spahr with more than 20 years of experience advising on the struc-turing and fi nancing of energy projects, has been named a co-chair of the American Bar Association’s Committee on Renewable, Alterna-tive and Distributed Energy Re-sources (RADER). Stark will promote the Committee’s mission to facilitate dialogue among thought leaders in the legal, regulatory, and policy communities on issues affecting non- conventional energy resources. RADER is part of the ABA’s Section of Environment, Energy, and Re-sources. Stark’s one-year term began in October.

EIC appoints Mitchell chairmanThe Energy Industries Council (EIC), a trade association for UK companies that supply goods and services to the energy industries worldwide, has ap-pointed Paul Mitchell as chairman of its board. Mitchell is a Chartered Civil Engineer with nearly 40 years’ experience in the design and construction of large scale schemes, with specifi c expertise in major energy projects. Mitchell has served on

Webb

Stark

Pinsonnault

Rich

Mitchell


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Energy Players


the EIC’s Board for two years and will take over the role of chairman with immediate effect following the retirement of Mike Rolls, director of business development, sustainability and government affairs at Siemens UK Energy Sector. Rolls has served as chairman of the EIC since May 2009. The chairman provides a formal point of contact between the EIC’s CEO, Ian Stokes, and the 20-strong board of directors, and plays a vital role in the strategic direction of the EIC. Mitchell currently works as an execu-tive with Rotary Building Services, part of the Lorne Stewart Group.

Transocean makes management changes Effective October 1, 2012, Ihab Toma has been named executive vice president, chief of staff of Transocean Ltd. In addition to continuing to oversee the company’s worldwide marketing effort, Toma will assume responsibility for Human Resources, Global Supply Chain, and Informa-tion Technology. John Stobart has been named executive vice president and COO. Before joining the com-pany, Stobart served as worldwide drilling manager for BHP Billiton Pe-troleum since 1994 in Australia, the UK, and, most recently, in Houston. Stobart received his bachelor’s degree from the University of Calgary and has also completed the London Busi-ness School Accelerated Development Program.

Organizational changes at NGP Capital Resources NGP Capital Resources Co. senior vice president R. Kelly Plato is leaving the company to pursue other business opportunities. Hans Hubbard and Chris Ryals have each been promoted to the position of managing director. Stephen K Gardner, president and CEO commented, “Kelly has played a vital role in the growth and develop-ment of NGPC over the years. He was instrumental in helping us work

our way through the challenges of the fi nancial crisis and in rebuilding our investment portfolio over the last eighteen months.” Gardner contin-ued, “Hans and Chris have been key members of our investment team since our inception and their exten-sive backgrounds in energy-based lending have signifi cantly benefi ted the company over the years.”

Akin Gump elects Kim Koopersmith as fi rm chairperson Akin Gump Strauss Hauer & Feld LLP has elected Kim Koop-ersmith to serve as chairperson of the fi rm, effective April 1, 2013. Upon assuming the role, Koopersmith will become the fi rst woman at Akin Gump—and one of very few women at a major, global law fi rm—to hold the position of fi rm chairperson. She succeeds Bruce McLean, who will step down from the role following a 20-year tenure, remaining with the fi rm as senior executive partner.

3Legs Resources names new CEO, focuses attention on Poland shale gas3Legs Resources plc, an indepen-dent oil and gas group focusing on the exploration and development of unconventional oil and gas resources, has named Kamlesh Parmar as CEO. Parmar has been with 3Legs since its inception in 2007 and has previously held the position of Group Com-mercial Director and Poland Country Manager. Parmar is one of the four members of the Management Board of OPPPW, the Polish upstream oil and gas industry association. He is currently a director of the 3Legs group of companies, as well as Darley Energy Poland Sp. z o.o., Darley En-ergy Plc, Tapar Ltd. and Tapar (PF) Ltd. Peter Clutterbuck has resigned his positions as CEO and director to

pursue other business interests.

Energy executives Davis, Vann join CCMP Capital CCMP Capital Advisors LLC has added Houston-based energy execu-tives Kyle Vann and Waters Davis to the fi rm as executive advisors. Vann and Davis will work with CCMP on energy investments in the E&P, mid-stream, power and services sectors. Vann spent 25 years in various senior leadership positions at Koch Indus-tries including leading the creation of Entergy-Koch LP, an energy trad-ing and transportation joint venture between Entergy Corp. and Koch In-dustries operating in North America and Europe, and served as its CEO. He currently serves on the board of directors of Texon LP, Crosstex Energy and Legacy Reserves and provides energy consulting services to Entergy Corp. He earned his BS from the University of Kansas. Davis’s past roles have included president of Reli-ant Energy Retail Services and execu-tive vice president of Spark Energy, as well as energy practice leader at McK-insey & Company. He has also served as a senior executive at a number of private companies. He has a BS from the University of Texas and an MBA from Harvard Business School.

Donald McGuire named NewOak COO NewOak has appointed Donald McGuire as COO and Head of Investment Banking. McGuire joins NewOak with over 27 years of experi-ence in fi nance and operations at major investment banking, pharma-ceutical, and technology companies around the globe. Most recently, Mc-Guire was managing partner of KDM Advisors in Greenwich CT, working with founders, shareholders, Boards, and management teams to develop or restructure their companies. He earned a bachelor’s degree from John Carroll University and an MBA from Pace University.

Koopersmith


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Company/Advertiser IndexCompanies mentioned in this issue of Oil & Gas Financial Journal are listed in

alphabetical order with advertisers in boldface type. The index is provided as a service. The publisher does not assume any liability for errors or omission.

COMPANY PAGE COMPANY PAGE COMPANY PAGE COMPANY PAGE


3Legs Resources plc 46

AAR 33

Africa Oil 8

Agriterra Ltd. 8

Akin Gump Strauss Hauer & Feld LLP 46

AkzoNobel Surface Chemistry 48

American Bar Association 45

Anadarko Petroleum 36

Antrim Energy Inc. 9

Apache Corp. 37,48

Asset Risk Management 23

ArcLight Capital Partners 15

AusTex Oil Ltd. 43

BHP Billiton Petroleum 46

BP 30,32

Baker Hughes 45

Ballard Spahr 45

BankTexas 11

Barclays 43

Basic Energy Services 16

Baytex Energy 12

BofA Merrill Lynch 43

Bridge Energy Enterprises Ltd. 9

CCMP Capital Advisors LLC 46

CIBC World Markets 45

CLNG 43

CNOOC Ltd. 9,32

CONSOL 30

Cabot Oil & Gas 14

Celtic Exploration 33

Cheniere Energy 48

Chesapeake Energy Crop. 6,30,32,36,42,45

Chevron Corp. 8,32,36

Cimarex Energy 11

Concho Resources 37

ConocoPhillips 36

Continental Resources 36

Copano Energy LLC 43

Crosstex Energy 46

DTE Energy 30

Dain Rauscher Wessels Inc. 45

Dana Petroleum 9

Darley Energy Poland 46

Deloitte 9,45

Denbury 32

Devon Energy 36

DrillingInfo Energy Services Group 31

Dominion 14

Dual Drilling Co. 45

EIC 45

EIG Global Energy Partners 6

EOG Resources 36

EPA 5

EPL Oil & Gas 32

EnBridge 30

Enbridge 12

EnerVest Ltd. 30,32

Enertia Software IFC

Enron 6

Eureka Hunter Midstream 15

Eureka Pipeline 15

ExxonMobil 32,36

First Oil Expro Ltd. 9

Forest Oil 33

GES Geophysical Services 29

GHX Industrial LLC 42

GMP Securities 43

Gardere Wynne Sewell LLP 6

Gavilon LLC 42

Gazprom Neft 8

Glass Mountain Pipeline LLC 42

Global Hunter Securities 42,45

Goldman, Sachs & Co. 43

Gorsuch Kirgis 45

Graves & Co. 2

GreenHunter Energy 11

Gulfport Energy 30

Halcon Resources Corp. 42

Halliburton 48

Hess Corp. 30,36

Hilcorp Energy 30,32

Hughes Christensen 45

KDM Advisors 46

Koch Industries 46

Legacy Reserves LP 37,46

Loadmaster Derrick & Equipment Inc. 42

Longview Energy Corp. 6

Magnum Hunter Resources 11

Marathon Oil 37

MarkWest Energy Partners 14

McAfee & Taft 45

McKinsey & Co. 46

Mercantile Bank of Canada 11

Mobil Australia Resources Co. Pty Ltd. 8

Morgan Stanley 43

Murphy Oil 36

NGP Capital Resources Co. 46

National Bank of Commerce 11

Netherland Sewell & Associates BC

Newfi eld Exploration 32,43

NewOak 46

Nexen 32

NiSource 30

Noble Royalties Inc. IBC

NuTech Energy Alliance 3

OFS Capital 42

OMV 33

OPPPW 46

Occidental Petroleum 36

Ohio Department of Natural Resources 30

PLS Inc. 32

Parker Drilling 45

Parks Paton Hoepfl & Brown 45

Petronas 33

Pioneer Natural Resources 36

Plains Exploration & Production Co. 32

Port San Antonio 42

PrimeEnergy Corp. 37

Progress Energy 33

Quorum Business Solutions 34-41

RBC Capital Markets 43

Range Resources 43

Regions Financial Corp. 13

Reliant Energy Retail Services 46

Rose Rock Midstream LP 42

Rosetta Resources 37

Rosneft 33

SMU 12

Sandridge Energy 36

SemGroup Corp. 42

Shell 8,48

Siemens 45

Societe Generale 19

Southwestern Energy 36

Spark Energy 46

Spectra Energy 30

Statoil Cover,27

TAQA 9

TNK-BP 8,33

Tapar Ltd. 46

Texas General Land Offi ce 48

Texas Petroleum 33

Texon LP 46

Total 30

Transocean Ltd. 46

TransTex 15

Triad Energy 15

Triple Point Technologies 20-21

Tullow Oil 8

United Central Industrial Supply 42

US Department of Interior. 48

Voyager Oil & Gas Inc. 42

W&T Offshore Inc. 32,43

WarlickEnergy 30

Watco Companies 42

Weaver 7

Wells Fargo Securities 43

WorldCom 6

WPX Energy 36

Wynnchurch Capital Ltd. 42


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Beyond the Well


As every Texan knows, there are miles and miles of Texas. The same is true for Texas beaches.

And while everybody loves the beach, not everyone respects the beach. Every year, beachgoers leave tons of trash on Texas beaches and even more washes up from the Gulf of Mexico, or from streams and rivers. Every year, the Texas General Land Offi ce leads the charge to keep the beaches clean.

This year, the 26th Annual Texas General Land Offi ce Adopt-A-Beach Fall Cleanup saw more than 9,316 vol-unteers pitch in and remove 153 tons of trash from 29 sites along 186 miles of Texas coast.

Galveston County, a popular spot for beachgoers, saw the most volun-teers and the most trash. Some 3,432 volunteers picked up 114,250 pounds of trash from 58 miles of Bolivar Pen-insula, Galveston Island, and the John M. O’ Quinn 1-45 Estuarial Corridor (Bay).

The all-volunteer program began in the fall of 1986, when 2,800 volun-teers picked up 124 tons of trash. In 26 years, 430,000 Adopt-A-Beach volunteers have picked up more than 8,300 tons of trash from the Texas Gulf Coast, some of it originating from as far away as Asia. Volunteers record the data to learn more about the causes of marine debris and to help mitigate pol-lution along the coastline.

So successful is the program, that it has helped pass an international treaty and has won awards.

Data collected from previous cleanups played an integral role in the passage of MARPOL Annex V, an international treaty that prohibits the dumping of plastics in the world’s oceans. In 1991, the International Maritime Organization designated the Gulf of Mexico and the Wider Carib-bean as a “special area” where the dumping of trash, with few exceptions, is prohibited.

According to the US Department of Interior, the Adopt-A-Beach program does more than any other volunteer program in the nation to take care of public lands and, on October 11, was, for the third time, awarded the Take Pride in America Award for top

corporate-sponsored event in Washing-ton, DC.

“Adopt-A-Beach volunteers work hard and really make a difference, from cleaning up trash that’s deadly to fi sh and birds to improving Texas tourism,” said Renee Tuggle, Adopt-A-Beach coordinator. “I can’t think of any other effort that even comes close to the real world change this program and its volunteers bring about.”

Coastal cleanups are held three times each year and require the hard work and dedication of many. Among the thousands of volunteers are local coor-dinators who work many unpaid hours publicizing the cleanups in coastal com-munities. Additionally, corporate and local media sponsors provide necessary resources to help underwrite the costs associated with the events. Shell Oil Co. was one of the lead statewide spon-sors of this year’s fall cleanup. Other statewide sponsors included: Apache Corp., AkzoNobel Surface Chemistry, Cheniere Energy, Halliburton, and the Ocean Conservancy.

The next coastwide cleanup will be the Spring Adopt-A-Beach effort scheduled for Saturday, April 20, 2013. Find out more at www.TexasAdoptA-Beach.org. OGFJ

Industry supports annual

Adopt-A-Beach fall cleanup

Mikaila Adams

Senior Associate Editor –

OGFJ

Shell Oil played a large part in the 26th Annual Texas

General Land Office Adopt-A-Beach Fall Cleanup.

Photo courtesy of Texas General Land Office.


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It’s time to plan!��

�� !��!��

As good partners, Noble Royalties has enabled landowners to make an Immediate financial impact on their families and in their communities.

By selling just a portion of their royalty, families control the resultsnow while adding financial certainty and control to their estates.

J.D. (DOUG) BRADLEYSr. V.P., Land Acquisitions & Divestitures

[email protected]


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Documents

OIL & GAS nov 2012