Oil & Gas Financial Journal - January 2011

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Bakken production may double Mexico sees production decline Managing oilfield safety reforms Fine line between hedging, speculation OGFJ100P Quarterly Report

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ENERTIA SOFTWARE

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CONTENTS V8/#1

✱

ON THE COVER: Kinder Morgan president Park Shaper talks to OGFJ about the company as an MLP structure, its operations, and ongoing plans.

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COVER STORY: E&P MLPs In 2006, some hydrocarbon producers were looking to the tax advantaged MLP as a way to structure assets – then befell the great economic recession and transactions of all types were stalled. Fast forward to current day, and the idea seems to be in renaissance. OGFJ associate editor Mikaila Adams spoke to various industry experts to get their take on the upstream MLP.

24 2011 outlook

28 Mexico’s predicament

Most petroleum industry forecasters seem a bit uncertain about the nearterm outlook for oil and gas, but the consensus seems to be that demand will strengthen in 2011 but not enough to deplete surpluses and raise prices, particularly with natural gas. OGFJ’s Don Stowers takes a look at some of the predictions.

Oil production in Mexico has declined 25% in six years. Mexico needs the technology, know-how, management capacity, and risk-spreading capability of large international companies, but its tolerance for foreign involvement is still very limited. Jose L. Valera and Andrew J. Stanger of Mayer Brown LLP

discuss Mexico’s predicament and what effect 2008 contract reforms are having on the fundamentals of Mexican oil policy.

transparency and visibility built into the contract management process to ensure compliance regardless of the outcome.

34 Safety reform

38 Tech talk

Oil spill reform debate is ongoing, and many oil and gas operators are taking a “wait and see” approach. Darrin Poole of CLM Matrix points out the importance of having

Karl Schmidt of Enertia Software takes a look at the benefits of a fully-integrated software for upstream energy companies versus the benefits of a “best of breed” solution approach.

42 Bountiful Bakken

48 Private Equity

Government officials in North Dakota believe the state’s oil fields may contain twice the amount of oil previously estimated and that the state’s crude oil production will double within the decade. If correct, North Dakota could jump from No. 4 to No. 2 in terms of largest US oilproducing states.

Private equity investments are crutial to the energy industry. Many independent producers rely in part on equity investment in order to grow. OGFJ has compiled a small but representative sampling of energy-specific firms that invest in the oil and gas industry.

Oil & Gas Financial Journal® (ISSN: 1555-4082) is published 12 times a year, monthly, by PennWell, 1421 S. Sheridan Rd., Tulsa, OK 74112. Periodicals Postage Paid at Tulsa, OK, and additional 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 2011 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 unauthorized 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.

January 2011 Oil & Gas Financial Journal • www.ogfj.com

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DEPARTMENTS [Editor’s Comment]

5 Cheers for China Rising energy consumption in China coupled with limited domestic supply has forced the world’s most populous nation to go outside its borders to aggressively seek oil and gas imports. China has emerged as the world’s second largest consumer of energy. The energy-hungry economy is driving ever-closer to acquiring the No. 1 position from the good ol’ US. And that’s not necessarily a bad thing. [Capital Perspectives]

6 Speculative hedges Hedging is good. Speculating is bad. Sapient Global Markets’ Larry Hickey takes a look at some of the ways the line between hedging and speculating can

become blurred in the energy production and trading businesses. [Upstream News]

12 Big Foot, big spend Chevron has sanctioned development of its $4 billion Big Foot project in the deepwater US Gulf of Mexico and plans to shift more investment spend to the upstream sector in 2011.

50 OGFJ100P Take an updated look at the largest privately held E&P companies ranked by US boe.

OGFJ.com▶ _______________________________________

67 Co./Ad Index [Beyond the Well]

68 Eagles for education

46 Deal Monitor

60 Industry Briefs

62 Energy Players

The Chevron World Challenge recently wrapped up its 12th year of bringing together some of golf’s finest players in a tournament benefitting various education-focused nonprofits. New this year was Chevron’s donation of $530,000 for eagles scored during the four days of play.

FEATURED STORIES Updated daily, OGFJ.com brings you the latest information from the industry. Get details on the recent EOG’s recent sale of Marcellus shale assets to Seneca, Hess Corp.’s $5.6 billion CAPEX for 2011, as well as Apache’s first operated deepwater development in the Gulf of Mexico. Read details on executive moves at Whiting Petroleum, MegaWest Energy, and more.

WHAT’S NEW ON PENNENERGY.COM Including content from all PennWell energy-related brands such as Oil & Gas Journal, Oil & Gas Financial Journal, Offshore, Power Engineering, and Renewable Energy World, PennEnergy.com delivers news, financial market data, in-depth research materials, user-generated content, blogs, and industry job listings in one, easy-to-navigate website.

NEW! FACILITIES AND INFRASTRUCTURE MAPS

ENERGY PHOTO OF THE WEEK ▲ Send us your photos, along with a short description, and your photo could appear online as our Energy Photo of the Week.

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In collaboration with PennWell’s MAPSearch and OGJ, OGFJ is working to bring you new maps detailing facilities and infrastructure in various oil and gas plays. Visit the Unconventional Resource Center page on ____ OGFJ. com for more ___ information.

www.ogfj.com • Oil & Gas Financial Journal January 2011


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OGFJ.com launches new Unconventional Resources Center

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orth American shale plays such as the Eagle Ford, Barnett, Haynesville, Marcellus, Bakken, and Woodford are all noteworthy formations, but unconventional resources is just not about shale. It also includes tight gas, coalbed methane, oil sands, and heavy oil. Get up-to-date information on the most talked about formations in the unconventional resources space –– all in one place.

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PennWell Corporation 1455 West Loop South, Suite 400, Houston, TX 77027 USA Tel: (713) 621-9720 • Fax: (713) 963-6285 www.ogfj.com

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Don Stowers

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Associate Editor Mikaila Adams

Reports from Don Warlick of Warlick International provide insight into the top 5 US shale plays and the 7 factors driving the shale business.

[email protected]

Contributing Editors Dayse Abrantes, Laura Bell, Paula Dittrick, Richard Nemec, Jason Reimbold, Nick Snow, Don Warlick, Peter Howard Wertheim

Presentation Editor Jason T. Blair Shale resource plays, lower 48 states Montana Thrust Belt

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Black Warrior Basin Fayetteville

Chattanooga

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Barnett-Woodford

E&P companies are shifting budgets to high-BTU, liquid-rich plays. Bentek’s Rusty Braziel provides expert analysis.

Pearsall-Eagle Ford

Daniel Bernard

Asia-Pacific +65 9616 8080 [email protected]

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Reprint Sales Where are the high BTU plays?

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Editor’s Comment

China’s energy demands will drive future of global oil and gas industry Don Stowers Editor-OGFJ

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ising energy consumption in China coupled with limited domestic supply has forced the world’s most populous nation to go outside its borders to aggressively seek oil and gas imports. Spurred by rapid industrialization and urbanization, China has emerged as the world’s second largest consumer of energy, just behind you-know-who. As the legendary baseball pitcher Satchel Paige is reported to have said, “Don’t look back. They might be gaining on you.” In this case, that might not be a bad thing. Who wants to be known as the world’s biggest consumer? Personally, I get enough sarcastic comments from my family about my “middle-age spread.” So I don’t feel too bad about my country being overtaken by China in the race for energy consumption superiority. Being No. 2 won’t hurt my feelings. On the other hand, I wouldn’t mind moving up the food chain when it comes to energy exports. China’s oil and gas consumption grew at an annual average growth rate of 6.8% in the decade from 2000 to 2009. Projected AAGR growth of 2.5% is forecast for the next 10 years. As a result, by 2020, 63% of China’s total consumption will be met through imports. So how is China handling this rapid change? The short answer: aggressively. In its effort to secure massive supplies of energy to assure its move towards industrialization and modernization won’t come to a halt, China’s national

oil companies have been acquiring interests in companies and oil and gas assets in Asia, Africa, and North and South America. The People’s Republic even has formed a partnership in South Texas, where China National Offshore Oil Corporation (CNOOC) has forged a deal with Chesapeake Energy in the Eagle Ford shale. CNOOC is paying Chesapeake $1.08 billion for a one-third stake in the Oklahoma company’s Eagle Ford holdings and will also pay $1.08 in drilling costs.

ural gas shortage up to 9 million cubic meters a day during peak demand periods, according to Lin Changhai, a PetroChina executive. In anticipation of this happening, the state-owned company plans to import 610 million cubic meters of LNG to supplement domestic gas output. China’s two gas pipelines to Beijing from the producing region near Shaanxi are currently running at full capacity, and PetroChina is rushing to build a third pipeline to meet the expected increase

The Eagle Ford deal gives CNOOC its first onshore energy asset in the US after its aborted attempt to buy Unocal Corp. in 2005. The Chinese company withdrew its offer amid significant political opposition. To date, there has been no such opposition to its deal with Chesapeake. The deal gives CNOOC its first onshore energy asset in the US after its aborted attempt to buy Unocal Corp. in 2005. The Chinese company withdrew its offer amid significant political opposition. To date, there has been no such opposition to its deal with Chesapeake. CNOOC and China Petroleum Corporation (Sinopec) have been especially active the past two months expanding their asset base in South America. CNOOC and Buenos Aires-based Bridas Corp. took advantage of BP’s fire sale of its assets to pay $30 billion in claims from the Deepwater Horizon disaster. Together, the two companies paid BP over $7 billion for Pan American Energy. In March 2010, CNOOC paid Bridas $3.1 billion for a 40% stake in the company. In December, Sinopec purchased Occidental Petroleum’s Argentine assets for around $2.5 billion. Industry observers expect China to close on additional deals in Latin America this year, as the country changes its focus from Africa to South America. This winter, China could face a nat-

in winter demand. Gas demand in Beijing alone may exceed 60 million cubic meters per day during the coldest days this winter. China is also encouraging large commercial and industrial users to find ways to reduce usage and conserve gas. Some supplies are being diverted from petrochemical and chemical users to residential use to meet peak winter demand. China’s energy-hungry economy is driving the future of global energy. Its growing middle class wants the same conveniences and luxuries that we in the West want, especially gas-guzzling automobiles. However, the Chinese government’s current push for green energy may help curtail the growth in oil demand. If it succeeds, the US could reclaim its place as the world’s No. 1 consumer of hydrocarbons, although that’s not a title I particularly relish. OGFJ Have an opinion about this? Visit www.ogfj.com to comment.


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Capital Perspectives

The bright shining lie between hedging and speculation Larry Hickey, FRM, Sapient Global Markets, London

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edging is good. Speculating is bad. That seems to be the zeitgeist. In the US, the Dodd-Frank financial overhaul goes so far as to bar banks from proprietary trading, speculation by another name. In Europe, speculators are being blamed for the region’s sovereign-debt woes. If the simple act of declaring a transaction to be a hedge means less scrutiny, one might expect a lot of hedges. And so it is. The energy business has lots of hedges, including some mighty speculative ones. Theoretically, hedging is the antithesis of speculation. A hedge 6

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is a transaction designed to reduce exposure to market price movements. Speculation, on the other hand, involves taking on market risk in order to benefit from price movements. One guy is getting smaller. The other is getting bigger. What could be clearer? Well, not so fast. What is so clear theoretically can become murky in reality. As long time energy and risk management consultant and president of Houston-based Mercatus Energy Advisors, Mike Corley, can tell you, “Many hedges look like thinly veiled directional bets.” Let’s look at some of the ways

the line between hedging and speculating can become blurred in the energy production and trading businesses.

The producers You’re an oil producer. You have a certain proven developed production (PDP). You’re long. If oil prices rise, you win. If they fall, you lose. A derivatives marketer has approached you with an interesting idea. With oil prices at $86, he can protect you against a price lower than $70. That sounds good, but the price of the $70 put does not. Always eager to help out, the marketer suggests that



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Capital Perspectives you fund the put by selling the right to any gains beyond $100 by selling the $100 call. The net cost of this hedging structure, called a collar, is zero.

Hedges after all are offset by an underlying position. Yet there is no discussion of any loss on the underlying. The last scenario involved selling the upside to fund insurance against the downside. What about simply “Theoretically, hedging is the antithesis of speculation. A hedge selling the upside? Should that is a transaction designed to reduce exposure to market price count as a hedge? Should a company movements. Speculation, on the other hand, involves taking on protect itself against the “risk” of a market risk in order to benefit from price movements.” large gain? Chesapeake Energy, one of America’s largest gas producers, thinks so. The producer has locked in an Over the past decade Chesapeake “talking your book” in trading outcome between $70 and $100. has recorded more than $5 billion in circles. In reality, the producer has The exposure is hedged within a gains from selling nat gas calls. They hedged his production and specurange. But there is no upfront cash lated on a side bet by selling the $60 are currently betting that prices will flow from the hedging structure. stay below $8 between 2013 and put. Again, the marketer has a solution. 2020. Jeff Mobley, Chesapeake’s If oil prices are range bound If you simply add the sale of a $60 head of investor relations, notes that between $60 and $100, the proput to the structure, there is a posi- ducer will have made a “profit on the company’s hedging program has tive upfront cash flow. So the absobeen highly successful during the hedging.” Listen for that phrase. lute protection at $70 is replaced by It’s a clue that something is amiss. last several years. protection over the range $70 - $60. There is no hedge below $60. But the producer “knows” the price won’t go below $60 anyway. This kind of false knowledge is called

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Capital Perspectives “If anything, the company would like to do more,” said Mobley. This is understandable with NYMEX front-month prices just over $4 and 2020 trading under $7. The sentiment is familiar to any gambler who bet on red when the roulette ball lands on red. Even the timing of a hedge can be speculative. If a producer arbitrarily decides when to put hedges in place based on when he sees “value” in the market, he is in fact speculating. Mike Corley notes that the firm’s risk management policy must be the basis for a sound hedging strategy. The policy sets out what should be hedged and when. But very few producers actually have such a formal framework in place. So, instead of a reasonable policy that might call for 60% of PDP to be hedged on 24-month rolling basis, for instance,

the firm puts a 2011 collar in place and reviews it when the mood hits them. Human nature being what it is, the mood often hits them after a big price move when they tend to make irrational decisions based on little more than their view of the market. Speculative risks can be embedded in hedging transactions. Consider the issue of cash flow timing. Let’s assume production has been hedged with a collar and the call is deeply in the money. If the expiration date of the call coincides with the end of production price risk, the call is payable two or three business days later, but the producer won’t be paid on the actual production for 30 to 90 days after the product is delivered. Imagine the producer who put a six-month hedge on in early 2008 with oil prices at $100. At expira-

tion, oil was almost $150. The call seller would have been on the hook for a large cash payment long before being paid for the production. Mike Corley also notes that “producers also tend to ignore basis risk.” Let’s say gas will be delivered at Mid-Continent. The hedge is done on the NYMEX which is for delivery at Henry Hub, in Louisiana. The producer sells a $5 swap. The future settles at $5.20 and the producer loses $.20 on the hedge. At the same time Mid-Continent trades down to $4.80. So effectively, the producer is selling for $4.60 ($4.80 - $.20) as a result of basis risk. $.40 was lost speculating on basis.

The traders Things don’t get any easier in a trading environment where a hedge

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Capital Perspectives may be distinguished from speculabuy it, is quite beside the point. tion by as little as the intent of the • His portfolio was short oil. Buytrader. The same objective set of ing a call is like going long oil. actions, using the same instruments The degree to which this is true and with the same holding period is called the delta. The positive may either be classified a cautious delta of the call offsets, or hedges, hedge or bold speculation. If you the short oil position. The fact see wide latitude for interpretation that the call introduced new risk here, you are not alone. elements like exposure to volatilLet’s say a trader buys a call on ity, interest rates and time decay is oil. Oil moves up, the value of the incidental. call increases, and he sells it. An • His portfolio was short options. open and shut case of speculation By going long this call, the trader unless: was hedging the portfolio’s expo• The trader expected a customer sure to market volatilities, called to buy the call. He was simply vega. He was also reducing the accumulating inventory for sale to risk of losing money every time a customer. He was hedging his the portfolio is rebalanced, called expected sale. The fact that the negative gamma. In this explacustomer order never materialnation, the delta, probably the ized or that the trader had the call option’s dominant risk element, is offered well above the market, omitted. where no one would reach up to • His portfolio was short another

call, perhaps with a different strike or expiration. So the bought call creates a spread with lower risk characteristics. And the purchase was a hedge. • Finally, his portfolio was long interest rates. As calls are worth less when interest rates rise, the call will tend to offset this exposure, marginally. Interest rates are only a minor risk element for options that expire within a couple of years. Left unsaid are the incremental and speculative exposures to delta, vega and time decay. This hedge justification couldn’t be delivered with a straight face. “The loopholes are big enough to drive a proprietary trading desk through,” quipped Mark O’Toole, a commodities risk expert with OpenLink Financial, an ETRM software

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Capital Perspectives vendor. “The hedge/speculation determination can’t be made looking at a trade in isolation. You have to understand the trade’s incremental contribution to portfolio risk – the true benchmark – and you’ll need a robust risk system to support that analysis.”

The risk manager So how can you reliably differentiate hedging from speculation? Well, given the nebulous differences and wide range of fig leaves available, asking is probably not the way to go. Too many roads lead to “hedge.” VaR is a good proxy over time. Put simply, on days when VaR goes up, you probably speculated. On days when VaR goes down, you probably hedged. VaR, which is typically run daily, will show the reality over time. But

it doesn’t provide a trade-by-trade accounting. If you want to be sure that all trades are hedges in a trading environment, the solution is draconian. Trade flat. Back-to-back everything. Maintain no position. The trader starts with no position. So flat is an option. But that option doesn’t exist for the producer with a natural long position. The producer avoids speculation by trading in strict accordance with a pre-defined hedging policy, so that discretion is removed from the equation.

When you come to the “hedge/speculation” fork in the road, take it! Short of trading flat or perfectly hedging production in accordance with a well-defined risk policy, there is no practical way to verify the classification of transactions as hedges

or speculation on a trade-by-trade basis. There will be some uncertainty. A clear risk policy, a robust risk system, and a strong risk manager can help minimize classification problems. But hedging and speculation are fellow travelers, the Siamese twins of risk. Find one and you won’t have to look too far to find the other. OGFJ About the author Larry Hickey is a director with Sapient Global Markets who has written previously on energy trading and risk management for Oil & Gas Financial Journal. He has spent the past 13 years implementing industry-leading ETRM solutions. The rest is pure speculation.

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Upstream News BHP Billiton reportedly to make cash offer of $44.6 billion for Anadarko

Chevron sanctions GoM Big Foot project

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Company to spend $5.4B on upstream projects in 2011

ncreased speculation has Australian mining giant BHP Billiton preparing a cash offer of $90 a share, or $44.6 billion, for Houston-based Anadarko Petroleum, one of the world’s largest independent oil and gas producers. However, some analysts believe BHP Billiton will have to increase its offer to $110 a share or more in order for the deal to work. As of Dec. 31, Anadarko shares were trading at nearly $77 a share, up nearly $27 a share since speculation of the BHP Billiton buyout first surfaced in early September. Anadarko stock is currently trading at a 52-week high and has been as low as $34.54 this year. Spokesmen for Anadarko and BHP Billiton declined to comment on the acquisition reports, although it appears likely that BHP Billiton is the source of the rumors. Anadarko is famously close-mouthed about its deals. Prior to its 2006 acquisition of Kerr-McGee and Western Gas Resources, executives for the three companies reportedly met in airplane hangars to negotiate in order to avoid being seen together. After BHP Billiton failed in its efforts to acquire Canadian fertilizer giant Potash Corp. and mining giant Rio Tinto this year, company executives have hinted that they would like to add a large petroleum company to their portfolio. Anadarko, as the largest independent producer in the Gulf of Mexico and a major holder of shale assets in the US, would seem to be a good fit for the Australian company. Anadarko also has several major development projects underway in Ghana, Brazil, and Algeria. Anadarko stock fell earlier this year after the fatal explosion aboard the BP-operated Macondo well in the deepwater Gulf of Mexico and the subsequent massive oil spill. Anadarko has a 25% stake in the well, which has raised questions about potential liability for the company. In November, Credit Suisse analysts said that Anadarko, along with Australia’s Woodside Petroleum, were likely acquisition targets for BHP Billiton. Anadarko reportedly has $19 billion in undeveloped oil and gas projects, which could be developed more quickly with a cash injection from BHP Billiton, which is financially very healthy. A recent Credit Suisse report says that Anadarko “holds the deepest and most scalable asset portfolio [among independent petroleum companies]” and is a very attractive acquisition target. If the $90-or-better offer is completed, it would easily surpass the $41 billion merger between XTO Energy and Exxon Mobil Corp., which was completed in 2010 and was the largest deal in the petroleum industry in years.

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hevron Corp. has sanctioned development of its $4 billion Big Foot project in the deepwater US Gulf of Mexico and plans to shift more investment spend to the upstream sector in 2011.

Big Foot “Sanctioning Big Foot underscores our commitment to the Gulf of Mexico and will contribute to future US energy supply,” said George Kirkland, vice chairman, Chevron Corp. Big Foot will be Chevron’s sixth operated facility in the deepwater Gulf of Mexico and located approximately 225 miles south of New Orleans, Louisiana, in water depths of 5,200 feet. The development will utilize a dry tree Extended Tension Leg Platform with an on-board drilling rig and have production capacity of 75,000 barrels of oil and 25 million cubic feet of natural gas per day. First oil is anticipated in 2014. Discovered in 2006, the Big Foot field lies in the Walker Ridge Area and is estimated to contain total recoverable resources in excess of 200 million oil-equivalent barrels. Primary pay sands are Middle to Upper Miocene ranging from 19,000 to 24,000 feet and lie below a salt canopy ranging from 8,000 to 15,000 feet thick. Three exploration and appraisal wells with multiple sidetracks have been drilled in the field to define the Big Foot structure. Chevron, through its subsidiary Chevron USA Inc., has a 60% working interest in the Big Foot project. Partners are Statoil (27.5%) and Marubeni (12.5%). 2011 budget On December 9, Chevron announced its $26 billion capital and exploratory budget for 2011 in which it detailed a shift to a greater proportion of investment spend to the upstream sector. In 2008, upstream spend represented 75% of the overall

Chevron expects to spend $5.4B on upstream projects in 2011 including those in the Gulf of Mexico. Map courtesy of Chevron



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Upstream News program. In 2009, the figure was 80%. In 2011 it will be 85%. According to a company spokesperson, the company is “more heavily weighted in upstream because the returns in the sector are stronger over time.” In the US, the company plans to spend $5.4 billion on upstream projects, which represents 20% of its overall capital program for 2011. Upstream spending expected in 2011 includes projects in the US Gulf of Mexico such as deepwater exploration and development, including Jack/St. Malo, Tahiti-2, Big Foot, Perdido and Buckskin appraisal.

Apache’s appraisal offshore Western Australia tests 58 MMcf/d

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pache Corp. has reported the Spar-2 appraisal well in Permit WA-4-R offshore Western Australia tested 58 million cubic feet (MMcf) of natural gas and 950 barrels of condensate per day. Apache’s Australia subsidiary plans to bring gas from the Spar Field and nearby Halyard Field to Western Australia’s domestic gas market via an existing Apache-operated pipeline 10 miles southeast of Spar-2 and through the Varanus Island processing and transportation hub.

First production from Halyard of approximately 50 MMcf per day (gross) is expected in the second half of 2011 with Spar following in late-2012 as additional capacity becomes available at Varanus Island. Apache owns a 55% interest in both WA-4-R and adjacent Permit WA-13-L, where Halyard is located. Santos owns the remaining interests. Spar-2 was completed over a perforated interval of 131 feet (40 meters) within 163 feet (50 m) of high-quality gas pay in a single zone at the top of the Barrow Group formation. The appraisal is located about one mile (1.6 kilometers) to the southwest of the Halyard-1 discovery and approximately 18 miles (29 km) southwest of Apache’s John Brookes platform. Thomas M. Maher, vice president and managing director of Apache’s Australia Region, said, “The proximity to Apache’s existing infrastructure will reduce the time and expense required to develop the project and deliver needed gas supplies to the growing Western Australia market.” The Halyard-1 discovery, drilled in 2008, test-flowed at a peak rate of 68 MMcf of gas and 936 barrels of condensate per day from 91 feet (28 m) of net pay in the Cretaceous Halyard sandstone.

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Upstream News Rapidly growing CNOOC makes deepwater gas find in Qiongdongnan Basin

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NOOC Ltd. has made a deepwater gas discovery on Block 64/11 offshore China after the Lingshui 22-1-1 exploration well drilled by its partner, BG Group (BG) , encountered gas-bearing sands. This recent discovery comes from an exploration well located in Qiongdongnan Basin in the South China Sea approximately 130 kilometres offshore in a water depth of 1,338 metres. BG will conduct further analysis of the well results to evaluate the hydrocarbon potential in the Block. Zhu Weilin, executive vice president of the company commented, “This is the first deepwater well in Qiongdongnan Basin. We are excited about the well results. It has further strengthened our confidence in deepwater exploration in this area.” The company signed the production sharing contract (PSC) with BG for deepwater block 64/11 on 7th June 2006. The Chinese oil company has been very active and is growing rapidly. The recent discovery comes on the heels of a partnership with Oklahoma City-based natural gas producer Chesapeake Energy in the Eagle Ford shale in Texas. It is reported that CNOOC is looking to sign additional joint ventures with US and Canadian companies in other North American shale plays. The company recently also signed a major deal to buy Venezuelan crude.

Anadarko makes third gas discovery offshore Mozambique

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nadarko Petroleum Corp. has made its third major natural gas discovery this year in the Offshore Area 1 of Mozambique’s Rovuma Basin at the Lagosta prospect. The discovery well encountered a total of more than 550 net feet of natural gas pay in multiple high-quality Oligocene and Eocene sands. The Lagosta discovery, located approximately 16 miles to the south of its Barquentine discovery and 14 miles to the southeast of the Windjammer discovery, significantly expands this emerging world-class natural gas province, Anadarko senior vice president, Worldwide Exploration Bob Daniels said. While additional appraisal drilling will be required, the company believes the three discoveries to date exceed the resource size threshold necessary to support an LNG (liquefied natural gas) development. The company has assigned an integrated project team to begin advancing commercialization options, added Daniels. The Lagosta exploration well has been drilled to a current depth of approximately 13,850 feet in water depths of approximately 5,080 feet. The partnership plans to drill 14

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to a total depth of approximately 15,900 feet to evaluate a deeper zone. Once operations are complete at Lagosta, the partnership expects to mobilize the rig 17.5 miles to the southwest to drill the Tubarão exploration well, which also is located in the 2.6-million-acre Offshore Area 1. Anadarko is the operator of Offshore Area 1 with a 36.5% working interest. Co-owners in the area are Mitsui E&P Mozambique Area 1 Ltd. (20%), BPRL Ventures Mozambique BV (10%), Videocon Mozambique Rovuma 1 Ltd. (10%) and Cove Energy Mozambique Rovuma Offshore Ltd. (8.5%). Empresa Nacional de Hidrocarbonetos ep’s 15% interest is carried through the exploration phase.

Talisman, Sasol to partner in Canada’s Montney Shale

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algary-based Talisman Energy signed an agreement with South Africa’s Sasol Ltd. on Dec. 20 to create a strategic partnership to develop the Farrell Creek assets in Talisman’s Montney Shale play in northeastern British Columbia. Talisman will sell a 50% working interest in its Farrell Creek assets to Sasol for a total consideration of Can$1.05 billion (about US$1.03 billion). The deal allows Talisman to develop the Farrell Creek area and unlock some of the value of the estimated 44 tcfe of net contingent resource held across its Montney Shale play. Farrell Creek represents about 22% (9.6 tcfe) of Talisman’s resource potential in the play and about 275 (51,000 net acres) of the company’s 190,000 net Tier 1 acres of land in the Montney. Sasol will pay 25% of the consideration (about Can$260 million – US$256 million) in cash at closing and carry 75% of Talisman’s future capital commitments in the Farrell Creek area to a total of about Can$790 million (US$778 million). The play has been largely de-risked and production at Farrell Creek is expected to exit this year at between 40 and 60 MMcfe per day, said a Talisman spokesman. Talisman’s processing facilities at Farrell Creek have been expanded to 120 MMcf per day, and the company has secured more than 500 MMcf per day of egress capacity from the region. As part of the deal, the partners have agreed to conduct a feasibility study around the economic viability of a facility in western Canada to convert natural gas to liquid fuels, using Sasol’s commercial gas-to-liquids (GTL) technology. This could prove a strategic alternative to traditional North American pipeline or LNG marketing. The outlook for GTL could be very positive if North American natural gas prices continue to decouple from oil prices. The GTL process produces premium, clean liquid fuels. Sasol will acquire a 50% working interest in all Talisman lands, existing wells, and processing facilities in the Farrell



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Upstream News Creek region. Talisman and Sasol will each own 50% of the Farrell Creek assets, with Talisman as operator of the partnership. The companies have also agreed to collaborate on certain other western Canadian natural gas opportunities. Closing is expected in the first half of 2011. Sasol is looking at expanding its proprietary GTL technology in new markets. Sasol is listed on the Johannesburg and NYSE, and has a market capitalization of about US$30 billion. Goldman, Sachs & Co. and Jefferies & Co. acted as advisors to Talisman on this transaction.

Noble makes gas discovery offshore Israel

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oble Energy Inc. has made a significant natural gas discovery at the Leviathan exploration prospect offshore Israel. Drilled in the Rachel license, the well encountered a minimum of 220 feet of net natural gas pay in several subsalt Miocene intervals. Noble said that apparent reservoir quality is very good, and the intervals discovered are geologically similar to those intersected at Tamar. Leviathan-1, located in approximately 5,400 feet of water, is about 80 miles offshore of Haifa and 29 miles

southwest of the Tamar discovery. The results from the well confirm the pre-drill estimated resource range, with a gross mean for Leviathan of 16 trillion cubic feet. The Leviathan field is estimated to cover approximately 125 square miles and, as a result of its size, will require two or more appraisal wells to further define total gas resources. Charles D. Davidson, Noble’s chairman and CEO, said, “Leviathan is the latest major discovery for Noble Energy and is easily the largest exploration discovery in our history. In the past two years, we and our partners have made three significant natural gas discoveries in the Levantine basin. Total gross mean resources discovered are estimated to be approximately 25 trillion cubic feet, with nearly 8.5 trillion cubic feet net to Noble Energy’s interest.” Drilling at Leviathan-1 will continue to a planned total depth of 23,600 feet to evaluate two additional intervals. Current well depth is 16,960 feet. The company’s second contracted rig will arrive in early 2011 to spud an appraisal well located 8 miles northeast of the discovery well. Noble operates Leviathan with a 39.66% working interest. Delek Drilling and Avner Oil Exploration both hold a 22.67% interest, and Ratio Oil Exploration holds the remaining 15%. OGFJ

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Kinder Morgan, the largest independent transporter of petroleum products in the US, transported approximately 1.9 MMb/d in 2009. All photos courtesy of Kinder Morgan.

Beyond the pipeline Are hydrocarbon producers the new MLPs? Mikaila Adams, OGFJ Associate Editor

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eyond the financial crisis: it’s the direction we’re all looking. Beyond the pipeline: it’s the direction many hydrocarbon producers were looking before the financial crisis reared its ugly head. During the years 2006 and 2007, many in the upstream sector began to take a second look at the master limited partnership structure for assets. Then befell the great economic crisis, and transactions of all types, both inside the energy industry and out, all but came to a halt. Fast forward to current day, and the idea seems to be in renaissance. MLPs are limited partnerships whose interests (limited partner units) are traded on public exchanges like corporate stock. The traditional MLP approach is a limited partnership (LP) with a GP that is a wholly-owned subsidiary of the sponsor. Another option is the limited liability structure (LLC) where there is no GP. Because of the partnership structure, MLPs are flow-through vehicles 16

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that generally do not pay income taxes. Thus, unlike corporate investors, MLP investors are not subject to double taxation on dividends. As of Dec. 31, there were 70 energy MLPs with a total market capitalization of $212 billion, according to FactSet and the National Association of Publicly Traded Partnerships. This number has grown from 18 MLPs with a market cap of $15 billion in 2000. In truth, the majority of these are midstream MLPs. Midstream businesses are the first energy MLPs to come to mind, as they typically make the most sense to operate under the MLP structure. Midstream MLPs, for example, natural gas pipeline MLPs, typically operate stable cash flow businesses. These type of MLPs “operate fee-based pipeline assets backed by long-term contracts,” noted Tudor, Pickering, Holt & Co. Securities Inc. analyst George O’Leary.



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“Commodity prices don’t tend to dictate the performance of these MLPs, certainly not to the same degree as they do for E&P stocks,” he continued. Barbara Spudis de Marigny of Gardere Wynne Sewell LLP reiterated these traditional challenges: “The industries using MLP form continue to be dictated by the reliability of revenue and its inelasticity relative to the price of oil and gas. E&P MLPs, by their nature, cannot be as confident of steady revenues as infrastructure or pipeline MLPs.”

million. Then chairman and CEO Bob R. Simpson stated that, “In today’s marketplace, we believe an opportunity exists with the MLP structure to further enhance the captured value of a portion of XTO’s exceptional property base.” Shortly thereafter, the bottom fell out, the marketplace changed, and the MLP was not to be. XTO did, however, find its ‘opportunity’ years later in December 2009. Its $40.4 billion buyout by ExxonMobil topped the list of North American energy deals in 2009. In June 2007, Petrohawk announced its intent to The evolution throw its hat into the ring. The MLP, to be named HK The MLP vehicle began with tax changes in the ‘80s. Energy Partners LP, would be set up to acquire certain of The sector began with Apache Petroleum Co. in 1981. Petrohawk’s oil and natural gas properties located in West APC, with Apache Corp. as its general partner, was born Texas, New Mexico, and Oklahoma. A Form S-1 was filed through a consolidation of interests in 33 of Apache’s with the Securities and Exchange Commission (SEC) on oil and gas programs. This MLP has evolved over time Oct. 30, 2007, but then, on Jan. 25, 2008, citing market and is now Cimarex in a different form. Tax changes in conditions, the company announced it would delay the the late ‘80s essentially prevented the disincorporation proposed MLP public offering. Other companies, namely Pioneer Natural Resources of corporate America. In short, problems with structure Co. and Encore Acquisition Co., were looking at the surfaced (distribution levels too high given the depleting structure as well. The results were different. nature of the business, over-leveraged companies, and Dallas-based Pioneer had approved a plan to form two general partner (GP) interests too often promoted at the new publicly-traded MLPs, one related to its long-lived expense of limited partner (LP) interests) and depleted proved developed reserves in the Spraberry field in West assets without reinvestment caused the partnerships to self-liquidate. Investors and management teams alike were Texas, and the second related to its gas reserves in the Raton Basin field in southern Colorado. left burned by the entities. Pioneer Southwest Energy (PSE) was offered up in Enter the pioneers. The beginning of the growth MLP really started to grab hold in the early ‘90s with Rich April 2008 and now owns producing oil and gas properKinder of Kinder Morgan and the late Dan Duncan of ties in the Spraberry field in the Permian Basin and looks Enterprise Products Partners. to acquire producing oil and gas properties onshore Texas Despite its heavy association with pipelines, Kinder and New Mexico. Morgan is, fundamentally, the largest upstream MLP. The At the time, Encore Acquisition Co. (EAC) was also company holds the title of second-largest oil producer in working on its MLP spin-off. Encore Energy Partners Texas, producing over 55,000 barrels of oil per day at the (ENP) was formed to own and operate oil and gas propSACROC Unit and the Yates Field in the Permian Basin. erties in the Big Horn Basin, the Permian Basin, the WilToday, however, it is LINN Energy that is known as liston Basin, and the Arkoma Basin. It IPOed in Septemthe catalyst that started the transformation of how mature ber 2007 by selling 9 million units at $21 each. producing oil and gas properties are owned and capitalAfter the wave-turned-ripple of upstream MLP IPOs ized in the US, similar to how Kinder Morgan led a shift from 2006-2008, the market for them went quiet. Was in the way pipeline assets are owned inside MLPs. When it the drastic change in the markets stopping the flow, or LINN Energy’s MLP, led by the energy investment bank- something more fundamental? ing experience of Kolja Rockov (now LINN’s executive “Some companies that had considered an MLP as a vice president and CFO), went public in January 2006, way to “arbitrage” perceived valuation differences versus the upstream MLP as we know it today was born. corporate form pulled back as they realized that you have to have an ongoing commitment and strategy to grow the Flashback to 2007: MLP and that the IPO is just the first step in the proThe “next wave” that wasn’t cess,” said John Walker, chairman and CEO of EVEP and In the August 2007 issue of Oil & Gas Financial Journal, president and CEO of EnerVest. before the effects of the economic turmoil took hold, So who’s in? some folks in the industry saw exploration and production (E&P) companies as the “next wave” of MLPs, and a Today’s players select group announced intentions to ride the wave. Currently, the upstream MLP sector is made up of LINN Energy LLC (LINE), Legacy Reserves LP (LGCY), EV At the time, XTO Energy was reviewing its entire portfolio of producing properties for selective inclusion in Energy Partners LP (EVEP), Encore Energy Partners an MLP with an initial capitalization of greater than $500 (ENP), BreitBurn Energy Partners LP (BBEP), Pioneer January 2011 Oil & Gas Financial Journal • www.ogfj.com

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Current upstream MLPs

Basin, Mid-Continent, and Rocky Mountains regions. Houston-based EVEP went public in September 2006. Market Enterprise Company The company “has enjoyed significant growth over the cap value past four years, expanding its proved reserves base from 8,020 5,550 LINE Linn Energy 51 bcfe to approximately 800 bcfe and its enterprise 1,448 1,163 LGCY Legacy Reserves LP value from $150 million to more than $1.7 billion,” said 1,499 1,210 EVEP EV Energy Partners LP Walker. 1,531 1,078 BBEP BreitBurn Energy Partners LP On Oct. 31, 2009, Denbury Natural Resources (DNR) 1,080 1,006 Pioneer Southwest Energy Partners LP PSE acquired Encore Acquisition Co., which held the general 1,227 1,001 ENP Encore Energy Partners LP partner of Encore Energy Partners (ENP). Because the 1,507 1,353 VNR Vanguard Natural Resources LLC ENP strategy did not fit with DNR’s strategy, the GP 229 68 CEP Constellation Energy Partners LP and the units held by EAC were considered to be on the market beginning in April 2010. Market Cap On Nov. 16, 2010, Vanguard Natural Resources LLC CEP 0% (VNR) announced its intent to buy the general partner VNR 11% and 20,924,055 common units of ENP from Denbury. LINE 45% Scott W. Smith, president, CEO, and director of VanENP 8% guard commented, “It was our thought that Denbury, as a leading CO2 development company, would have little interest in maintaining a public MLP in addition to managing a successful C-Corp. As the assets in ENP were PSE 8% already in an MLP structure, we were very comfortable with the production profile. The geographic diversity and oil weighted focus made this opportunity even more appealing.” BBEP 9% He added that the company will run the two MLPs separately under one management team, but with two independent boards of directors. EVEP 10% California-based BreitBurn Energy Partners LP’s assets LGCY 9% consist primarily of producing and non-producing crude Enterprise Value oil and natural gas reserves in the Los Angeles Basin in CEP 1% California, the Wind River and Big Horn Basins in central VNR 9% Wyoming, the Sunniland Trend in Florida, the Antrim Shale in Michigan, and the New Albany Shale in Indiana LINE 49% ENP 7% and Kentucky. The company was distressed to a degree and had litigation issues with Quicksilver Resources, but the companies have settled and BreitBurn reinstated disPSE 7% tributions beginning with the first quarter of 2010. As mentioned previously, Pioneer Southwest Energy (PSE) was offered up in April 2008 and now owns BBEP 9% producing properties in the Permian Basin and looks to acquire properties onshore Texas and New Mexico. Constellation Energy Partners is another associated with the upstream MLP group, although its tangled EVEP 9% weave of utility-minded management and natural gas production from high cost coalbed methane has left the LGCY 9% company with the smallest market cap and enterprise Source: FactSet Fundamentals data, Bloomberg data, Robert W. Baird & Co. estimates value. The company lists proved reserves located in the Black Warrior Basin in Alabama, the Cherokee Basin in Southwest Energy Partners LP (PSE), Vanguard Natural Oklahoma and Kansas, and the Woodford Shale in the Resources LLC (VNR), and Constellation Energy PartArkoma Basin in Oklahoma. ners LP (CEP). The newest out of the gate is QR Energy. The As previously mentioned, LINN Energy LLC IPOed in Houston-based limited partnership – currently operatJanuary 2006. ing onshore, mature fields in the Mid Continent region, Midland, Tex.-based Legacy Reserves LP is focused Northern Louisiana, the Permian Basin in Texas, and on oil and natural gas properties primarily in the Permian cont’d on p. 65 18

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A conversation with Kinder Morgan’s Park Shaper Mikaila Adams, OGFJ Associate Editor

EDITOR’S NOTE: C. Park Shaper is president of Kinder Morgan, one of the largest pipeline transportation and energy storage companies in North America. The company is also the second largest oil producer in Texas, producing over 55,000 b/d at the SACROC Unit and the Yates Field in the Permian Basin. The Kinder Morgan companies include Kinder Morgan Energy Partners LP, Kinder Morgan Management LLC, and Kinder Morgan Inc., a private entity. Shaper recently took time from his schedule to speak with OGFJ’s Mikaila Adams.

OGFJ: Kinder Morgan is one of the original companies with hydrocarbon producing assets to utilize the MLP structure. How did the company come to be a pioneer on that front? PARK SHAPER: I wouldn’t characterize us as one of the original companies to put producing assets in the MLP structure. In truth, in the 1980s there were a number of MLPs that owned production assets that didn’t fare well because the exposure to commodity prices led to volatility in distributable cashflow, resulting in volatility in distributions – which investors found unappetizing. When Kinder Morgan became Kinder Morgan in February 1987 (the MLP had been in existence prior to that, but that’s when Rich Kinder and Bill Morgan purchased the general partner and renamed it Kinder Morgan), we took a bit of a different approach. We believed the MLP structure could be used very effectively as a growth vehicle. We focused on assets with stable cash flows, which really were, and primarily are, midstream assets – assets where we don’t actually own the commodity that’s moving on them, but rather we own the asset and get paid a fee for transporting that commodity. That gave us stable cash flows. We were able to expand those assets and grow the cashflows through increased utilization and by investing additional capital in them. We were able to acquire additional assets that fit that profile, which allowed us to grow the cashflows and grow the distribution. That was really something that hadn’t been done in MLPs prior to that. I think in that way, Kinder Morgan started taking a unique approach to the MLP structure and it was very effective. And, there are a number of people who are doing it very well today. That being said, we do own some production assets. We got into that business through our CO2 transporta20

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tion business. All of the production assets that we own are related to CO2 floods. We were able to take our CO2 expertise and apply it to a production field and have a significant impact on the production coming out of that field, thereby attaining very attractive rates of return. In general, we would avoid that kind of asset within an MLP because of the commodity price sensitivity. We pay out the vast majority of our cashflows to our investors and we don’t want that payout to be reduced quarter to quarter or year to year. Exposure to commodity prices is not something that we seek out; it is something we try to avoid, but the opportunity that we found to apply our CO2 expertise to these fields was so significant that we took on that exposure and hedged away as much as we could. We have relatively limited exposure in the nearterm and we will layer hedges on throughout the years to limit our exposure to commodity price movements.

The Rockies Express Pipelines is one of the largest ever constructed in the US. The 1,679-mile line runs from Colorado to eastern Ohio and boasts capacity of 1.8 bcf/d.



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OGFJ: Thirteen years in that capacity is a long time. How has the company continued to be successful using the MLP structure? SHAPER: Our approach has been consistent and will be going forward. We look for stable assets, largely based on fee income from our customers, that are integral to the energy infrastructure of the US – typically longer-line, bigger assets that the economy really depends upon. We get growth and cashflow by increasing utilization. We get growth by operating them efficiently. We get growth by expanding those assets. We hope to sign up customers for new storage contracts – incremental storage and incremental transportation. We also get growth in cashflows by acquiring similar assets and operating them efficiently. OGFJ: Should we expect to see a wave of E&P companies looking to get in on the structure?

OGFJ: Kinder Morgan CO2 Co. LP ranked No. 25 in Oil & Gas Journal’s recent ranking of US producers by total assets in 2Q10. This coupled with the company’s large midstream operation is impressive. Is there room for growth, and what is the future of Kinder Morgan?

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SHAPER: On the production side, clearly our goal is to produce incremental volumes so we’re very happy with our performance. We’ll work hard to maintain that level of production or grow it. Our other major business segments are: products pipelines where we’re transporting gasoline, diesel fuel, and jet fuel; natural gas pipelines where we’re transporting natural gas and storing natural gas; terminals where we store a lot of refined products and chemicals; and Kinder Morgan Canada where we own essentially two crude oil pipelines coming out of Alberta. One is the only pipeline currently that goes to the West Coast; it runs to the refineries in Washington State and also to the Vancouver area. The second is a line that runs down into the Rocky Mountains and east to Wood River, Illinois. Our growth in each one of those is driven by the same philosophy. We see opportunities across all of those business segments. OGFJ: Does any infrastructure tie in to shale?

SHAPER: For producers considering this, I think there are some advantages and disadvantages. The advantage is that it’s a very tax efficient structure in that you eliminate a layer of taxation at the entity level. All of the tax attributes are taxed to the partners, so the tax does get paid, but it eliminates double taxation. The disadvantage is, if you have a commodity sensitive business, investors in MLPs are generally buying in for the distribution, and if they don’t have confidence that your distribution, at a minimum, will stay flat (but hopefully grow), you may not get a very attractive valuation. That’s the balance that producers have to strike when considering the MLP structure.

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SHAPER: What’s happening in the natural gas world right now is some shift in supply sources, namely the shale fields. We have a presence in the Haynesville, Eagle Ford, and Marcellus. We see opportunities in each one, but especially the Eagle Ford as it’s on top of existing assets that we currently own that move natural gas out of South Texas. It’s very attractively located for us. It also seems to be attractive for producers. They’re getting more oil out of the field, which helps their economics when oil and gas prices are where they are. We also have some long lines that access Haynesville gas. We entered a joint venture with Petrohawk in May called KinderHawk. It gathers natural gas volumes within the Haynesville. Clearly there is a lot of activity around the shale. There will be need for incremental infrastructure development around it and we think our existing asset base leaves us very well positioned to participate in that. OGFJ: Thank you very much for your time. OGFJ



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We are pleased to announce the closing of EnerVest Energy Institutional Fund XII with equity commitments of

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$2,400,000,000 for the acquisition and development of oil and natural gas properties and strategic corporate acquisitions in North America

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Acquisition Contact

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Senior VP, Business Development

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713-659-3500

[email protected]

[email protected]

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INDUSTRY OUTLOOK An Eagle Ford shale well at dawn. Photo courtesy of Swift Energy.

Oil price surge to continue in 2011, while natural gas prices remain flat Industry increasingly optimistic about the economy and most expect upstream capital spending to rise steadily

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ost petroleum industry forecasters seem a bit uncertain about the near-term outlook for oil and gas, but the consensus seems to be that demand will strengthen in 2011 but not enough to deplete surpluses and raise prices, particularly with natural gas. Crude oil prices have been increasing steadily over the past year. However, natural gas prices remain in a deep rut due to plentiful supplies created by increased production from North American shale plays. In its annual Forecast and Review issue dated Jan. 3, Oil & Gas Journal’s editors predict that US and global energy demand growth rates will slow somewhat in 2011 due in part to persistently high unemployment. Obviously, if the economy strengthens and more workers find jobs, energy demand would increase accordingly. Energy demand is expected to increase only 1% in 2011 compared with preliminary data that indicates a 3% increase in energy consumption last year, according to OGJ’s Marilyn Radler, senior editor-economics, and Laura Bell, statistics editor. 24

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They say that demand for oil, nuclear energy, hydroelectric power, and other renewable forms of energy will be up in the coming year, while demand for natural gas will inch up slowly and coal demand remains flat. Even if the economy were to stage a remarkable recovery in 2011, it is likely that strong prices will keep oil demand down. The primary use for refined oil is as transportation fuels, and vehicle owners tend to drive less when they see abrupt price spikes. Some analysts are predicting $4.00 gasoline prices at the pump if oil again approaches or exceeds the $100/bbl mark. John Hofmeister, the former president of Shell who currently heads a grassroots organization, Citizens for Affordable Energy, says Americans could be paying $5.00 a gallon for gasoline by 2012. Other industry experts say $5.00 gasoline is likely in the next decade, but probably not in the next year or two. $5.00 retail gasoline would mean oil prices in the neighborhood of $150 to $180 a barrel, which most industry analysts



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don’t predict until at least 2015, but it is interesting to note that these predictions are not coming from peak oil forecasters. They are coming from mainstream experts who see demand tightening markedly with respect to supplies in the next few years.

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than the 2010 average. The agency says it expects the natural gas market to begin to tighten in 2012, with the Henry Hub spot price increasing to an average of $4.50 per MMbtu.

Wood Mackenzie upstream insight

Scotland-based Wood Mackenzie estimates that upstream spending in 2010 amounted to about $380 billion. This The story is a little different for natural gas. On Jan. 3, is about $19 billion higher than 2009, but still about 105 Raymond James & Associates cut its US natural gas price below the historical peak in 2008. forecast, citing persistent supply growth and limited access to Investment plans have recovered “spectacularly” in the capital for producers. US, says the firm, due mainly to the boom in unconvenThe bank lowered its 2011 estimate to $3.75 per thoutional gas and liquids-rich plays. Overseas, giant capital sand cubic feet from $4.25 previously, and cut its estimate projects in other major producing provinces, such as Angola for 2012 to $4.25 from $4.75. and Australia, are also pursuing aggressive schedules. “Unfortunately for energy companies, this supply probWood Mackenzie’s experts believe the recovery will conlem may be around for a while,” Houston-based Raymond tinue through the next three years. Upstream spending in James analysts J. Marshall Adkins, John Freeman, and Darthe US is expected to climb from a low point of $63 billion ren Horowitz said in a note to clients. “We expect that the in 2009, to around $95 billion in 2013. Still more spectacuUS will remain structurally oversupplied with gas until we lar growth is planned in Australia (up 190%) and Iraq (up see a step-change upward in demand.” 1,700%). Even more mature provinces such as the UK are Gas prices tumbled 21% in 2010 as output from shale for- anticipating a resurgence in investment, potentially to higher mations climbed. US marketed gas production rose to 1.945 levels than before the economic crisis. However, the recovery is not evenly reflected across the trillion cubic feet in October, the highest level since 1973, according to the US Department of Energy. globe. Capital spending in Canada fell by 30% in 2009 and Roughly 15% to 20% of US natural gas drilling will be may not return to the peak levels of 2008 within the next five, driven by funding from joint-venture partners, Raymond or even ten, years, says the consulting firm. Upstream investment in Russia remains almost 20% below the 2008 total. James said. India’s Reliance Industries, for example, agreed More than half of future upstream investment will be last June to acquire a $1.3 billion stake in a shale-gas venture led by Pioneer Natural Resources Company. provided by the multi-national majors and a group of About 40% of gas drilling in 2011 will be in areas rich in prominent national oil companies. PetroChina has by far natural-gas liquids, such as ethane and propane, Raymond the largest upstream commitment among the NOCs, and James said. This enables producers in some shale plays, such its spending plans rank with the largest of the majors. It has as the Eagle Ford in Texas and the Marcellus in the northpursued an international expansion strategy over the past eastern US, to earn more than they would from natural gas 10 years, but still spends only 5% of its upstream budget on sales, so long as gas prices remain below $4 per thousand overseas projects. cubic feet. Two other Chinese oil companies, CNOOC and Sinopec, Demand for natural gas from power generators and have recently acquired large stakes in South American oil and industrial consumers will continue to rise in 2011, but not gas assets. In March 2010, CNOOC paid $3.1 billion to enough to offset higher supplies, said the Raymond James acquire half of Bridas Energy Holdings, an Argentine comanalysts. pany. In November, CNOOC and Bridas acquired Pan American Energy, a private company with assets in South America, EIA forecast for just over $7 billion. China Petroleum Corporation (SinoThe Energy Information Administration expects the price pec) acquired Occidental Petroleum’s Argentine assets for of West Texas Intermediate crude oil to average about $93 around $2.5 billion on Dec. 10. All this seems to indicate a per barrel in 2011, $14 higher than the average price last shift in China’s emphasis from Africa to Latin America. year. For 2012, the EIA says WTI prices will rise to $99 per barrel by the fourth quarter. This is based on the assumption Conclusion that US real gross domestic product grows 2.2% in 2011 An informal poll by Oil & Gas Financial Journal recently and 2.9% in 2012, while world real GDP (weighted by oil asked what will happen to upstream capital spending in consumption) grows by 3.3% in 2011 and 3.7% in 2012. 2011. Most responders, just over 50%, said spending will be Natural gas working inventories ended 2010 at 3.1 trillion robust for the next several years, possibly approaching the cubic feet, about 1% below 2009’s record-setting Dec. 31 peak levels of early 2008. Another 21% said capex spending level. Inventories are expected to remain at or near record would increase by at least 5% but would not reach 2008 levhighs through most of 2011, keeping prices depressed. els. This is another sign that industry people are increasingly The EIA says the projected Henry Hub natural gas spot optimistic about the economy and the petroleum sector in price will average $4.02 per MMbtu for 2011, $0.37 lower particular. OGFJ

Natural gas forecast

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Major Mexico oil and gas fields

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New oil contracts not likely to help Mexico’s declining oil production Jose L. Valera and Andrew J. Stanger, Mayer Brown LLP, Houston

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n November 24th Pemex released in model form the first contract with private sector E&P companies implementing Mexico’s 2008 legislative oil reforms. This contract is intended to increase production from existing, mature onshore oilfields. Faced with rapidly declining crude oil production, Mexico is beginning to look for outside help. Averaging 3.3 million barrels per day (b/d) in 2005, Mexican crude production is now predicted to fall as low as 2.5 million b/d for 2010. Although such a production rate is still impressive and would be enviable for many countries, the rapidity of the decline—25% in six years—has sounded alarms in Mexico. This is 28

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because oil income is the lifeblood of the Mexican government (oil represents over 30% of federal revenues and more than 15% of Mexico’s export revenues). Petroleos Mexicanos (Pemex), the state-owned oil monopoly that controls all segments of the Mexican oil industry, initially hoped that crude oil declines could be offset by enhanced production from existing fields. Now it appears that the decline is evidence of a chronic condition requiring not only enhanced recovery efforts but leaps in new exploratory activity. However, it is widely acknowledged that Pemex lacks the funding, technology, and know-how to succeed in



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Creating Energy for Today. Ensuring it for Tomorrow.

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these efforts, at least in the near term. President Felipe Calderon believes that the current situation requires greater cooperation with foreign companies. In 2008, he proposed to the Congress a series of substantive reforms relating to the oil industry, which included a measure allowing Pemex to enter into joint ventures with outside companies and to share in cash the value of production. The proposals were significantly diluted by the political opposition, and the allowed contracts, though broadening the scope of items for which a company may be compensated, do not constitute a radical departure from the previous Pemex contract regime of multiple service contracts. The new law still does not allow private E&P companies to receive compensation in kind or tied to the value of production; rather they continue to be limited to receiving only fixed compensation paid in cash. The limited upside potential offered by such an arrangement is a significant disincentive for the undertaking of exploration risk by private companies, which is what Mexico needs the most. Even these modest reforms have drawn street

newly formed Pemex. For Mexico, this was a defining moment and continues to be a source of national pride, particularly on each March 18th when the country celebrates Expropriation Day. If President Cardenas’s decision to expel foreign interests from Mexico was controversial at the time, it proved to be an extremely fortunate choice decades later: in 1971 a fisherman noticed petroleum bubbling up from the Gulf of Campeche, and thereby stumbled across one of the world’s largest oil finds—the supergiant Cantarell field. This and other discoveries made Mexico a leading oil exporter and launched Pemex to the ranks of giant oil companies. But now that the prodigious discoveries of the 1970s appear to be in rapid decline, Pemex is beginning to look for the next generation of oil fields. Mexico still has significant oil reserves: according to 2009 Pemex estimates, the country has proven crude oil reserves of 10.4 billion barrels and possible crude oil reserves (3P) of 30.9 billion barrels. But with Mexican consumption increasing and production declining, in the absence of significant new discoveries the US Energy Information Administration estimates that Mexico will become an oil-importing nation by 2015 and will require net imports of 1.3 “With Mexican consumption increasing and million b/d by 2035. production declining, in the absence of signifiThe recent decrease in crude oil production is cant new discoveries, the US EIA estimates that largely due to the decline of the flagship CantarMexico will become an oil-importing nation by ell field, which produced on average 2.125 million 2015 and will require net imports of 1.3 million b/d in 2004 but now, even with nitrogen injection b/d by 2035.” recovery efforts, averages less than a quarter of that amount. Other fields appear to be taking up some of the protests and incurred intense political opposition. slack, but not nearly enough. The Ku-Maloob-Zaap Members of the center-left political parties staunchly field (KMZ), also located in the Gulf of Campeche, oppose any increased participation by foreign oil has more than doubled its production over the same companies, fearing that such an approach would period from 304,000 b/d in 2004 to 847,000 b/d as divert funds from the Mexican people. of October 2010, thanks to nitrogen injection recovThe urgent need to develop new sources of proery. However, many experts predict that production duction will likely increase the pressure on Mexico at KMZ is near its peak. to assess the fundamentals of its oil policy and decide The Chicontepec oil field, which is Pemex’s largest whether keeping foreign companies at a distance will onshore project, has not produced expected volumes remain a tenable strategy. due in part to its complex reservoir geology. Faced with severe criticism over project costs from the A declining national patrimony National Hydrocarbons Commission (CNH), a govThe barriers to private sector participation derive ernment observer of Pemex, the company announced from a long-standing distrust of foreign oil compain September that it will reduce drilling on the projnies and the belief that oil revenues are the true foun- ect by 60% next year. Since Chicontepec’s reserves dation for national economic development. Although comprise about 40% of Mexico’s possible crude oil foreign oil companies were heavily involved in the reserves, this is an enormous setback. Mexican oil industry in its early years (by 1920 over The problem of production is compounded 90% of investment came from abroad), they soon because Pemex is only beginning efforts to find and came to be seen as exploitative. develop new fields. According to CNH, 95% of curAfter a series of disputes, President Lazaro Carderent production comes from fields that are peaking or nas decreed in 1938 the expropriation of foreign oil have already peaked, and enhanced recovery efforts assets, which were immediately put into the hands of have been made in only 16 of those fields. Rates 30

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of decline for Mexican oil fields are unusually high compared to international averages; large Mexican oil fields decline at a rate of 16.1% per year while the international average is 10.4%. Cantarell has declined at a rate of 16.3% per year, while other super-giant fields decline on average at a rate of 3.4% per year. Despite significant efforts, Mexico’s overall rate of reserve replacement has only climbed to 78% in 2010. Reserve replacement based on new fields is only 28%. Pemex hopes to return to producing 3.3 million barrels a day by 2025, but as CNH explains in its 2010 annual report, this will require an “unprecedented effort in exploratory activity.” By CNH estimates, Pemex will need to drill over 165 exploratory wells per year over the next fifteen years. That is a significant leap in activity given that Pemex has averaged only 68 exploratory wells per year over the last eleven years. Moreover, Pemex must triple the number of shallow water fields (from the current 112 fields to 365) and increase its deep water fields tenfold (from the current 4 to 41). Deep water production is still entirely new to Pemex, which has drilled about 15

“The new contracts will also be subject to a high degree of political risk. Although many members of the center-left PRI have supported the idea of incentive-based contracts, others in the same party, along with other opposition parties, are fighting against them.” deep water exploratory wells since 2004 but has yet to develop any new fields.

New contracts The Mexican constitution provides that oil and other hydrocarbons are the property of the state and prohibits private companies from holding concessions. In addition to this constitutional limitation, current Mexican law severely restricts the consideration payable by Pemex under contracts for the exploration and production of hydrocarbons, prohibiting payments in kind or otherwise sharing in production, and prohibiting any form of sharing or allocation of sales proceeds or profits. Thus, a private company may not own production, share in the proceeds from the sale thereof, or share in the profits from the project. The intent of the law continues to be that only Pemex may be in the “business” and only Pemex may realize the upside. For much of its history, Pemex has operated under cash, fee-based arrangements with traditional service companies. The multiple service contracts introduced in 2003 were the first attempt to engage with E&P companies, but Pemex could not legally deviate from 32

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the service framework and could only offer compensation on the basis of units of work. Such arrangements did not adequately compensate for risk and were widely considered to be unsuccessful. The contracts resulting from the 2008 statutory reforms are not expected to go much further. The contracts to increase production from existing, mature onshore oilfields following the model form released on November 24th are anticipated to be awarded by mid-2011 pursuant to a competitive bidding process. Compensation under this first contract may be determined based on several different variables, which are all tied to cost recovery and fixed, per-barrel cash compensation (which is adjustable for inflation). The total compensation payable to the contractor in any one year may not exceed Pemex’s cash flow from the same project during such year. Uncompensated amounts may be carried forward to following years, but are lost if they remain unpaid at the end of the contract term. Pemex may terminate the contract for convenience should it no longer fit within the economic goals for the project. Regulations issued under the new law would allow Pemex to also enter into contracts agreeing to pay incentive compensation if the contractor (1) reduces budgeted costs, (2) increases reserves, or (3) otherwise increases profits for Pemex. In addition, Pemex may include clauses in multi-year works contracts providing for compensation adjustment if the contractor contributes new technology or experiences changes in the cost of materials. All such compensation must be “reasonable” and paid in cash pursuant to a threshold-based formula or by reference to indicators specified in the contract. Contracts cannot grant any preferential rights to acquire petroleum at an export point or allow the contractor to influence sales to third parties. Pemex has not yet issued model form contracts utilizing this incentive compensation approach. A constitutional challenge by members of the lower house of Congress to the incentive compensation regime outlined in the regulations was declared without merit last December by the Mexican courts. This compensation scheme may not be adequate for exploration projects—particularly in deep waters— where contractors would expect market-based upside potential to compensate for increased costs and downside risks. Not only is the compensation limited, but the downside potential is enhanced: the contracts must include penalty provisions to be triggered should the contractor’s operations have a “negative impact” on “environmental sustainability” or if the contractor breaches the contract “in terms of opportunity, time, and quality indicators.” These terms are not defined in the statute and will likely be clarified through litigation or regulations that are yet to be enacted. Similarly, the requirement that all



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compensation be “reasonable” (at the risk of the contract being void) will require contractors to walk a fine line between being profitable but not too profitable. The new contracts will also be subject to a high degree of political risk. Although many members of the center-left PRI have supported the idea of incentivebased contracts, others in the same party, along with other opposition parties, are fighting against them. These legislators take the position that incentive compensation paid to private companies takes profits away from Mexico. They would prefer reduced taxes to allow Pemex to keep a greater portion of its revenues to invest in exploration and production, rather than allow private companies to become more involved in Mexican oil. Some legislators, including Cuauhtémoc Cardenas (the son of President Cardenas, who decreed the expropriation of foreign oil assets in 1938), demand that any contracts between Pemex and private companies be made public to ensure their legality. As parties position themselves ahead of the 2012 presidential elections, the degree of foreign involvement in Mexican oil is likely to remain a wedge issue.

Outlook The rapid decline of oil production has left Mexico

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with no easy choices. On one hand, Mexico needs the technology, know-how, management capacity, and riskspreading capability that large international oil companies could offer, and on the other hand, its legal and political tolerance for foreign involvement is still very limited (as the struggle over the 2008 reforms continues to demonstrate). Ultimately, the 2008 contract reforms are little more than a tentative step toward greater engagement with private companies and have not changed the fundamentals of Mexican oil policy. While many support a more flexible oil policy, it remains to be seen whether Mexico, even in the face of declining production, will be able to adopt such an approach. OGFJ About the authors Jose L. Valera is a partner in the Houston office of Mayer Brown LLP. His practice focuses on the development of energy projects in Latin America. Andrew J. Stanger is an associate in the Houston office of Mayer Brown LLP. His practice focuses on international energy transactions.

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Managing compliance and safety reform in an ever-changing regulatory environment Darrin Poole, CLM Matrix, Houston

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Partisan politics aside, it is anticipated that some form of offshore drilling safety regulations bill will pass the Senate due to mounting pressure from both the President and the public. However, until then much of the offshore drilling industry remains caught in legislative limbo. While many oil and gas operators are taking a “wait and see” attitude towards increased governmental oversight in the Gulf of Mexico and elsewhere, the oil spill reform debate clearly illustrates one thing – in an everchanging regulatory environment, it is imperative to have transparency and visibility built into your contract management process. When laws change, a company must be able to quickly access all its contracts and have a process in place for consistently updating contract language to ensure compliance. There are tremendous regulatory and compliance demands placing pressure on the contracting process in the oil and gas industry. The multitude of players in both upstream and downstream operations require energy

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n a sweeping response to BP’s Deepwater Horizon massive oil spill in the Gulf of Mexico, the US House of Representatives passed a bill in July toughening offshore drilling safety standards. Known as the Consolidated Land, Energy, and Aquatic Resources (CLEAR) Act, the House version removed the $75 million economic liability cap from oil spills, imposed new safety standards, increased the number of independent inspections and equipment certifications required, and increased penalties for safety violations. The oil spill response bill narrowly cleared the House and then promptly stalled in the Senate in early August when Democrats rejected taking up the bill due to disagreements over who would foot the costs of future spill cleanups. Compounding the problem, Senate Republicans created their own version of the bill. Currently the 400-page bill is tabled, but it or another version may be taken up by the new Congressional session that began in January.

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companies to have full visibility into the governing terms and conditions that manage the entire operational value chain and the associated rights and obligations afforded to each participant in the process. To bring this into focus, consider one of the provisions in the pending oil spill reform bill (SEC 626) - the Certificate of Inspection Requirements. Under this provision, floating rigs would be required to adhere to much more stringent safety requirements. Specifically, all rigs must be able to prove that they regulate the safety of blowout preventers – a direct response to the blowout preventer problems with BP’s Deepwater Horizon. At a minimum, proving blowout safety compliance would necessitate inserting specific language into a variety of agreements including: a) Construction contracts, b) Sub-contractor contracts, c) Vendor contracts, d) Contract trade agreements, and e) Equipment purchase and/or lease contracts. “The oil spill reform debate clearly illustrates one thing – in an ever-changing regulatory environment, it is imperative to have transparency and visibility built into your contract management process. When laws change, a company must be able to quickly access all its contracts and have a process in place for consistently updating contract language to ensure compliance.” If your contract management process is template driven, then changes like these are a considerable burden. Effective and efficient contract lifecycle management processes accommodate dynamic document creation based upon approved legal clauses that ensure regulatory compliance. It used to be that the IT departments drove the contract management processes within organizations. Today, that responsibility is shifting to legal, compliance, procurement and even sales organizations. The contract process is so critical and cuts across so many organizational areas, companies are focused on finding tools that have the brainpower, flexibility, and capacity to help them be proactive in all areas. Specifically: • Legal wants functionality such as legal libraries, notification alerts, and workflow approvals; • Compliance wants standardization, governance, and reporting against regulations — both internal and external; • Procurement wants visibility into vendor obligations and reminder notifications for expiring agreements; • Sales wants insight, historical information, timely approvals, more time with their clients than the legal department, more efficiencies in the proposal-to-quoteto-contract process; and 36

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• Executives want business intelligence, safeguards, and peace of mind. Every stakeholder wants visibility and to have their part of the workflow identified and accounted for throughout the life of the contract. Contract lifecycle management systems are attractive investments for energy companies because they offer a single, searchable, enterprise-wide tool that serves all functional needs. The field of contract lifecycle management vendors is wide and their offerings are diverse, making it challenging to determine which solution is the best fit for your needs. At a minimum, a content lifecycle management solution should: • Be a fully-scalable enterprise class solution that provides complete lifecycle capabilities including rules-based contract initiation and authoring, front and back-end system integration, repository and full document management capabilities. • Standardize contract creation using a library of contract clauses that include most favorable terms as defined by the company. • Offer rule-based document creation and be fully configurable to specific process and document types without code (wizard driven). • Provide policy-based approval workflow. • Easily integrate with legacy enterprise software to avoid duplication of functionality. • Offer tools such as contract compliance tracking and automated reminders and alerts. • Enhance collaboration through online negotiation and exchange of documents. • Offer global contracts visibility to support best practice information and instruction from legal, operations and finance. • Have a robust search feature and real-time user defined reporting capabilities for obligation traceability. • Provide a rules-based contract initiation and authoring procedure to guarantee that all contracts issued contain the most current language so that there are no gaps or loopholes to cause legal liability. • Be easy to use to ensure a high level of adoption and quick time-to-value. No one knows what the final outcome will be in Washington, but having a defined and automated process for initiating, creating, negotiating, executing, and monitoring all types of contracts is key to a lot less red tape and a lot more profit. OGFJ About the author Darrin Poole is a vice president at CLM Matrix, which provides Contract Lifecycle Management (CLM) software solutions on Microsoft Office and SharePoint technology platforms.



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The method versus the madness The value of integrated software in the upstream energy company Karl Schmidt, Enertia Software, Midland, Texas

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f you take a look at the benefits of a fully integrated ERP application solution and compare those benefits to the “best of breed” solution approach, you will find some facts that are usually overlooked or not well considered.

Small piece, big differences Let’s examine a very small piece of the process to shine a little bright light on some real differences. Fully integrated solutions support workflow technology available for supply chain management activities such as having purchase orders, receipts, and payables linked directly into inventory management and joint interest processing. That same workflow and approval logic is leveraged for ownership changes and AFE 38

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approvals, among other functions. It is a single solution applied in a similar methodology across different parts of a whole system the same way. Best of Breed solutions have one or another primary system and rely on another vendor’s application for accounts payable processing, another for JIB transactions (which is usually not part of that accounts payable process), and a completely different application for AFE management. Inventory management may fall victim to the process, or it may be another module manually maintained. In some worlds that might “work,” but let’s consider that scenario a little bit further. The fully integrated solution takes one program and database environment to run your live data and a test



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environment for user acceptance testing of new versions, features, and fixes. A fully integrated solution is secured and tested for user acceptance on a defined release schedule for the entire application. It is secured one way, one time, using the same setup for all users. It is audited for everyone, once, as an application. It is supported by a single vendor. It is enhanced by that single vendor who has the benefit of working with customer partners to build a rich and robust integrated solution, where each customer can determine the best way to apply the system to their business processes and reporting needs. In the Best of Breed approach, the environment is a lot different. In our limited example for workflow, procurement, accounts payable, and AFE processing, we find the “many vendors” solution. Some of the parts might be online, but some will be in-house. Some activities may be automated, but many will be manual. Each has to be set up where they can be used live and

“A fully integrated solution is secured and tested for user acceptance on a defined release schedule for the entire application. It is secured one way, one time, using the same setup for all users. It is audited for everyone, once, as an application. It is supported by a single vendor... who has the benefit of working with customer partners to build a rich and robust integrated solution, where each customer can determine the best way to apply the system...”

tested either way, creating lots of moving parts. Each vendor interfaces with the other in a mostly limited, if not completely custom method, for each installation. Sometimes you can use what someone else built, but the interfaces become customized to a particular customer quickly. Data resides as cross references in at least three of these systems and each must be maintained, checked, and validated. The user acceptance testing now adds the complexity of scheduling with four vendors on ambiguous release schedules. All four interfaces get tested each time you dare to upgrade any of the applications and so do all the programs – ouch! Security is set up and managed four ways, four times, with four audits. The vendors are not out for each other’s common good. They exist to profit individually, as they should, so don’t expect a lot of change for the customer’s common good. It “works,” so it’s not worth the cost of change. Really? Are you truly considering the cost and lost value all this extra effort is costing your company? 40

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The Help Desk Consider the cost of the Help Desk staff required to install the applications and maintain them. Integrated solutions are published as Live and Test environments. Development and testing database copies are available for the user with their own IT developer groups who want to build and interface with other economics, reserves, and G&G solutions. A data warehouse may or may not be in the picture, but if it is, the ability to extract data is the only real concern. Since there is a single source of data, the complexity is lowered and the accuracy is assured. Not having to check and balance multiple solution interfaces all the time makes this a much simpler process. With confidence in the data, you can make better decisions faster. Consider your internal help desk providers, whoever they may be. Some companies have non-technical staff members, usually paid well, providing support and help to other department users or new employees. Other companies rely on technical IT savvy employees who may or may not have much business process experience. A single integrated application is set up, accessed by users, secured, and used for each department’s functions in a similar, seamless program interface. Once the methodology of a common integrated solution is learned, the business processes interact with different data and transactions, but the use of the system from navigation to inquiry to reporting and data extraction is common. This results in reduced administrative burden by requiring less time, collectively, in performing these duties. Less time and effort delivered by a common internal group for your Help Desk functions results in less cost and higher productivity. The Best of Breed approach requires the Help Desk resources to either learn all the systems and interfaces or to have different employees supporting different issues. The loss of a common group of resources for this function is a burden to productivity and a higher cost. Administration of interfaces and cross references eat into the resources’ time and take away from their ability to help the business user unless these resources are expanded, thereby also raising costs.

Accuracy, reliability of data Consider the accuracy and reliability of the data and how comfortable you are with it. Fully integrated solutions store data in a common database in common tables. That means aggregating or filtering data for all or a group of companies is as easy as selecting the list. You’ll see only what you have security to see, but you’ll get it all back the way you ask for it. If you are in a truly integrated solution, a financial inquiry leads to drill-down to transaction details,



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images related directly to the transactions, and all the purchase order and accounts payable coding and approval, inventory data and the billing information related to all the approved transactions. You can see it all balanced without the need for additional reconciliations or “check and balance” reporting for the various systems. The Best of Breed approach might give you drilldown reporting, but where is the coding and approvals, images, and inventory? You might find yourself looking online in a different system for that data, taking time and losing productivity all the while. You also might have to consider the coding from the interfaced solution versus the internal ERP cross references. Were there errors? If there are errors, are they reconciled and fixed in both places or just in-house? Here is where the madness really starts to shine. If you don’t fix each system, and users keep finding the errors in the system that was not fixed, is it eventually deemed unreliable, or do the users start building their own spreadsheet solutions to track what they consider important?

Your company Fully integrated solutions are not meant to do everything for everybody. However, the range of function-

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ality needs to be compared to your business needs by your own business process experts. Don’t just take the word of the doubters or the best of breed guys – look for yourself. If you can determine the scope of your business that can be served by these integrated applications, you can consider the costs of resources and application support better for your organization. Once you factor that reality into your ROI, you may well find tremendous value hidden in the details. Technology has advanced tremendously and continues to do so at breakneck speed. The benefits are amazing if you can find a single solution that can meet the needs of many and eliminate waste, enhance reliability, and regain lost productivity. OGFJ About the author Karl Schmidt is vice president of Midland, Texas-based Enertia Software. He has been actively involved with upstream energy technology solutions at Enertia for more than 18 years. During his time in the industry, Schmidt has worked with more than 200 companies in the private and public sectors to define and implement their software integration and business process objectives.

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Call 800.823.6277 Email [email protected] Visit www.MAPSearch.com


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Bakken may double production in 10 years Formation has largest oil deposits in North America outside the oil fields of Alaska

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overnment officials in North Dakota said Jan. 2 that state’s oil fields may contain twice the amount of oil previously estimated and that the state’s crude oil production will double within the decade. If the estimate is correct, North Dakota, currently the fourth-largest oil-producing state in the US, will jump to second place behind Texas. Lynn Helms, director of the North Dakota Department of Mineral Resources, says the state is currently producing about 350,000 barrels of oil per day and should produce about 110 million barrels in 2010, up from 79.7 million in 2009 and more than double the amount produced three years ago. Record rig activity, pushed by strong crude oil prices coupled with advances in drilling technology, has enabled the state to see the two-fold increase in production. The drilling and completion technology alone has cut the time required to complete a well from 65 days in 2008 to 25 days in 2010.

Bakken in 1951, and it was initially described by geologist J. W. Nordquist in 1953. However, development lagged because exploration and production companies did not have the technology to extract the oil economically until recent years. Low oil prices and the high cost of recovery made the Bakken oil uneconomical for decades. All this changed when the price of oil rose to over $50 a barrel in the past decade and peaked at around $140/ bbl in 2008. Although prices fell during the economic collapse of late 2008 and 2009, they have rebounded quickly with prices currently flirting with $90/bbl and up. This makes exploration and production of Bakken crude a no-brainer. There has been a land rush in the Bakken by American, Canadian, and international oil companies that has made some land-holding farmers overnight millionaires as they leased their land to oil developers. On April 10, 2008, the US Geological Service issued a report estimating the amount of technically recoverable oil within the Bakken formation at 3.0 to 4.3 billion barrels, with a mean of 3.65 billion. The state of North Dakota also released a report that month which estimated “North Dakota, which has about 5,300 producthat there are 2.1 billion barrels of technically recovering wells, now accounts for about 6% of total able oil in the Bakken. This would make the Bakken shale US crude oil production. Roughly 2,000 of those the largest oil find in US history outside the oil fields of wells have been drilled in the last three years, Alaska. mainly in the Bakken Shale and Three Forks The USGS also estimates approximately 1.85 tcf associplays. About 95% of the wells drilled target ated/dissolved natural gas and 148 million barrels of those formations.” natural gas liquids in the Bakken formation. The drilling and completion technology to recover “We are now looking at 700,000 barrels a day, and Bakken Formation oil involves vertical drilling followed we see that coming in the next four to seven years,” said by horizontal drilling, formation fracturing, and the use Helms. of proppants. At that rate, North Dakota would surpass California In recent years, oil companies drilling in the Willisand Alaska based on current production levels in those ton Basin have discovered the Sanish-Three Forks play, states. North Dakota, which has about 5,300 producwhich lies just under the Middle Bakken Zone. Some of ing wells, now accounts for about 6% of total US crude the Bakken operators are targeting this formation, and oil production. Roughly 2,000 of those wells have been the wells so far have been strong producers. Brigham drilled in the last three years, mainly in the Bakken Shale Exploration Company, based in Austin, Texas, was one and Three Forks plays. About 95% of the wells drilled of the first companies to drill into the Sanish-Three Forks target those formations. formation. Since then, several other operators have folThe Bakken Shale is in the Williston Basin in North lowed suit. Dakota. However, it is found in the adjacent state of A number of publicly traded oil and gas companies curMontana and also the Canadian provinces of Saskatcherently have drilling rigs in the Bakken region, with varywan and Manitoba. Although oil has been found in other ing asset prices, risks, and potentials. These include EOG shale formations – notably the Niobrara in Colorado, Resources Inc., Continental Resources Inc., Whiting Oil Nebraska, and Wyoming; the Eagle Ford in South Texas; & Gas Inc., Marathon Oil Corporation, Brigham Exploand California’s Monterey Shale – all are compared to the ration, Hess Corporation, and Samson Oil and Gas Ltd. Bakken when resource potential is discussed. A niche fund, the Williston Basin/Mid-North America We have known that the Bakken Shale had abundant Stock Fund (ICPAX) invests in the publicly traded comoil reserves since the 1950s. Oil was first discovered in the panies that are profiting from this massive oil find. OGFJ 42

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Bakken Shale News Hess capex includes Tioga plant expansion

nearly 25% of the company’s E&P revenue streams are expected to be New York-based Hess Corporation generated by oil production, up from announced its 2011 capital and explor7% in 2010. atory budget of $5.6 billion on Jan. In the recent transaction, Williams 7, nearly all of which is targeted for has agreed to purchase roughly 85,800 exploration and production: $3.1 billion net acres from private owners for $925 for production, $1.6 billion for develop- million. The acreage is located entirely ments, and $900 million for exploration. on the Fort Berthold Indian ReservaGreg Hill, president of worldwide tion, located in the Williston Basin of exploration and production, said, “More North Dakota. than 35% of our capital and exploratory The company estimates that these expenditures in 2011 are devoted to properties represent approximately 185 unconventional oil projects. We have a MMboe in total net reserves potential balanced program that will underpin our in the Middle Bakken and the Upper long-term target of growing reserves Three Forks formations. The deal was and production by at least 3% per year.” expected to close by year end 2010. Assets in the proposed transaction Production expenditures of approximately $3.1 billion includes the Bakken include 3,300 barrels per day of net oil oil shale in North Dakota, where Hess production from 24 existing wells. plans to operate 15 rigs and expand In addition to the purchase price, production facilities. Field development Williams expects to invest additional funds for drilling and development costs expenditures of $1.6 billion include expansion of the Tioga natural gas plant totaling approximately $60 million in and construction of a crude oil rail load- 2010 and $200 million to $300 million ing and storage facility to support the in 2011. development of the Bakken oil shale in Currently, there are three rigs operatNorth Dakota. ing on these properties. Williams expects The $325 million Tioga plant expan- to double the current level of drilling sion in northwestern North Dakota will activity to six rigs by 2012 and expects increase capacity at the plant from 100 the new leases to be producing more MMcf of natural gas daily to 250 MMcf than 20,000 barrels per day by the end per day. of 2012. The plant was built in 1954. Hess plans to start construction on the expan- Continental Resources sion project in March and complete it in increases Bakken spending Continental Resources Inc. expects late 2012. In November, Hess announced plans to produce 20.6 million barrels of oil equivalent in 2011, an increase of 30% to acquire an additional 167,000 net over expected production for 2010. acres in the Bakken from privately-held The company’s 2010 total production TRZ Energy LLC for $1.05 billion in cash. The properties being acquired are was about 15.8 MMboe. “Our 2011 capital expenditures budlocated near Hess’s existing acreage and get of $1.36 billion will support accelerhave current net production of roughly ated growth,” said Harold Hamm, 4,400 boe/d. chairman and CEO. “We’ve committed Williams diversifies with 91% of 2011 capex, or $1.2 billion, to Bakken acquisition drilling, workovers, and facilities, which Tulsa-based Williams Companies is directly support production growth. diversifying its E&P interests with a “Of this drilling-related capex, 92% recent acreage acquisition in North will be invested in the Bakken Shale play Dakota’s Bakken Shale formation. in North Dakota and Montana and in According to the company, by 2013, the Woodford Shale play in Oklahoma,” 44

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he said. “These two plays will be critical to driving our growth for the next five years.” Continental continued to add to its acreage positions in strategic, liquidsrich plays in 2010. The company now has 864,559 net acres leased in the Bakken Shale play, an increase of 47,707 net acres in the third quarter. In the Niobrara Shale play of Colorado and Wyoming, the company now has leased 73,000 net acres, an increase of 13,929 net acres in the third quarter of 2010.

Brigham announces 5 highrate Bakken completions Brigham Exploration Co. has completed 5 high-rate Bakken shale wells at an average early 24-hour peak flow back rate of 3,085 barrels of oil equivalent. As of late December, Brigham had completed 45 consecutive high frac stage, long lateral Bakken and Three Forks wells in North Dakota at an average early 24-hour peak flow back rate of 2,810 barrels of oil equivalent. Brigham’s accelerated development of its acreage in North Dakota and Montana is proceeding with 3 operated rigs drilling in Rough Rider, 3 operated rigs drilling in Ross, and 1 operated rig drilling in Richland County, Montana. Brigham’s eighth operated rig is currently expected to arrive in May 2011. Brigham currently has 2 wells flowing back, 2 wells fracing, and 8 wells waiting on completion. Brigham anticipates fracing the Swindle 16-9 #1H located in Roosevelt County, Montana early in the first quarter 2011. Shortly thereafter, Brigham will frac the Johnson 30-19 #1H, located in Richland County, Montana. In the first quarter 2011, Brigham expects to add additional fracture stimulation capacity thereby providing access to two fully dedicated frac crews focused on completing Brigham operated horizontal wells in the basin. At that time, Brigham estimates that about 8 wells per month will be fracture stimulated and brought on line to production.



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Deal Monitor

$7.1B BP-Bridas Corp. deal is month’s largest

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he major deal of the past month is BP’s sale of its 60% interest in Pan American Energy LLC to Bridas Corp., the oil company owned by Argentina’s billionaire Bulgheroni family and China’s CNOOC Ltd. for US$7.06 billion. Pan American’s asset base is in South America, and Bridas and CNOOC already own the other 40% stake in the company. Under terms of the deal, Bridas and Beijing-based CNOOC will each pay $2.47 billion to finance the acquisition, with the remaining US$2.12 billion to come from

third-party loans or additional funds from the two companies, according to a statement issued by CNOOC on Nov. 28. The deal will be completed in the first half of 2011. In March 2010, CNOOC paid US$3.1 billion to acquire half of Bridas Energy Holdings. Pan American, headquartered in Buenos Aires, produces about 240,000 barrels of oil equivalent per day and has proven reserves of 1.54 billion barrels. Since 2001, Pan American has invested US$6.7 billion in exploration and production, enabling it to boost output by about 70%.

Rodman & Renshaw - Deal Monitor – Select transactions

11/16/10 - 12/15/10

US Transactions Date Announced

Buyer

Seller

13-Dec-10

Duramax

High Plains Gas

Asset Location Rocky Mountains

10-Dec-10

Occidental

Undisclosed

Rocky Mountains

10-Dec-10

Energen

SandRidge

Mid Continent

10-Dec-10

Occidental

Shell

Gulf Coast Onshore

7-Dec-10

BP

Shell

Gulf of Mexico

3-Dec-10

Stealth Enery

Antelope

Rocky Mountains

1-Dec-10

Antero Resources

Bluestone Energy

Appalachia

29-Nov-10

Oasis

Undisclosed

Rocky Mountains

29-Nov-10

Chesapeake

Antares Energy

Gulf Coast Onshore

29-Nov-10

Marathon

Denali Oil & Gas

Gulf Coast Onshore

22-Nov-10

Hess

Tracker Resource Development

Rocky Mountains

21-Nov-10

Energy XXI

Exxon Mobil

Gulf of Mexico

17-Nov-10

Vanguard Natural Resources

Denbury; Encore

Multi State

Date Announced

Buyer

Seller

Asset Location

29-Nov-10

Bridas Corp

BP

South America

10-Dec-10

China Petrochemical Corporation

Occidental

South America

29-Nov-10

Husky Energy

Exxon Mobil

Canada

14-Dec-10

Harvest; KNOC

Hunt Oil

Canada

International Transactions

1-Dec-10

Undisclosed

Daylight Energy

Canada

19-Nov-10

Undisclosed

Perpetual Energy

Canada

1-Dec-10

Whitecap Resources

Undisclosed

Canada

1-Dec-10

Strategic Oil & Gas

Undisclosed

Canada

14-Dec-10

United Energy Group

BP

South Asia

6-Dec-10

East West Petroleum

Undisclosed

North Africa

Source: Rodman Energy Group, public filings, and company press releases. Information represents best data available at time of publishing. Metrics include adjustment for non-reserve value and/or non-proved reserve value if applicable. Prepared by Jason Reimbold, Vice President, Rodman Energy Group. For more information, email to [email protected]. Rodman & Renshaw LLC (Member FINRA, SIPC) is a fullservice investment bank with offices in New York and Houston.

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Deal Monitor BP’s move was part of a continuing global effort to raise cash to meet compensation claims after the April 2010 Deepwater Horizon disaster in the Gulf of Mexico. BP has been scrambling to raise cash and reportedly needs to raise about US$30 billion by mid-2011 to help pay the cleanup costs and some of the compensation claims. The second-largest deal of the month is the acquisition by China Petroleum Corporation (Sinopec) of Occidental Petroleum’s Argentine assets for around US$2.5 billion. The transaction was made public on Dec. 10 and is expected to be completed by the end of the first quarter. Occidental is using the proceeds of the sale to acquire US

assets in South Texas and North Dakota, to increase its stake in Plains All-American, to acquire a 505 JV interest in the Elk Hills Power Plant, and to increase its common dividend rate by 21%. The two largest US deals belonged to Occidental Petroleum. In one deal, Oxy purchased US Gulf Coast assets from Shell for an estimated US$1.8 billion. The assets, which currently produce roughly 200 million cubic feet per day of gas equivalent, will be 100% operated by Oxy. Secondly, Oxy purchased 180,000 net contiguous acres in North Dakota which produce from the Bakken and are prospective in the Three Forks formation from an undisclosed private seller for US$1.4 billion. OGFJ

Price ($MM)

Non Proved Reserve Value ($MM)

Reserves (MMBoe)

Production (Boe/D)

Reserves ($/Boe)

Production ($/Boe/d)

Reserves ($/Mcfe)

Production ($/Mcfe/d) NA

5.3

—

NA

NA

NA

NA

NA

1,400.0

—

NA

NA

NA

NA

NA

NA

—

110.0

NA

NA

NA

NA

NA

NA

1,800.0

—

NA

33,333

NA

54,000

NA

9,000

257.0

—

5.4

5,100

48.04

50,392

8.01

8,399

—

2.5

NA

NA

NA

NA

NA

NA

—

118.0

NA

NA

NA

NA

NA

NA

30.0

—

NA

NA

NA

NA

NA

NA

—

200.0

NA

NA

NA

NA

NA

NA

—

10.0

NA

NA

NA

NA

NA

NA

1,050.0

—

NA

NA

NA

NA

NA

NA

1,001.0

—

66.0

20,000

15.17

50,050

2.53

8,342

380.0

—

20.0

4,030

Median Mean

Number of Transactions 13

19.00

94,288

3.17

15,715

$19.00 $27.40

$52.196 $62.183

$3.17 $4.57

$8,699 $10,364

Price ($MM)

Non Proved Reserve Value ($MM)

Reserves (MMBoe)

Production (Boe/D)

Reserves ($/Boe)

Production ($/Boe/d)

Reserves ($/Mcfe)

Production ($/Mcfe/d)

7,060.0

—

924.0

144,000

7.64

49,028

1.27

8,171

2,450.0

—

393.0

51,000

6.23

48,039

1.04

8,007

841.0

—

NA

33,000

NA

25,485

NA

4,247

525.0

—

53.0

11,720

9.91

44,795

1.65

7,466

70.0

—

NA

1,500

NA

46,667

NA

7,778

40.0

—

NA

NA

NA

NA

NA

NA

25.0

—

0.9

300

27.78

83,333

4.63

13,889 4,667

14.0

—

NA

500

NA

28,000

NA

775.0

—

NA

35,000

NA

22,143

NA

3,690

17.5

—

NA

100

NA

175,000

NA

29,167

$8.77 $12.89

$46,667 $58,054

$1.46 $2.15

$7,778 $9,676

Number of Transactions 10

Median Mean


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Private equity providers to oil and gas industry Leading private equity providers to oil & gas industry (alpha order) Avista Capital Partners When founded 2005 Locations London, New York, Houston Primary focus Strategy is to make controlling or influential minority investments in growth-oriented energy, healthcare, media, industrial, and consumer businesses. Individual investment range Varies Aggregate capital commitment Estimated at $5 billion Management Avista’s Co-Managing Partners are Thompson Dean, former Managing Partner of DLJMB, and Steven Webster, former Chairman of DLJMB Global Energy Partners. In addition, Newton Aguiar, David Burgstahler, Robert Cabes, David Durkin, OhSang Kwon, Brendan Scollans, Sriram Venkataraman, and Arthur Zuckerman are also Partners. Portfolio companies ACP II Marcellus; Appalachian Midstream Partners; Basic Energy Services Inc.; Celtique Energie Holdings Ltd.; Enduring Resources; GeoKinetics; Hansa Hydrocarbons; Laramie Energy II; Laredo Energy IV; Manti Exploration; Peregrine Oil & Gas II; Royal Offshore; Spartan Offshore Drilling

Cadent Energy Partners When founded 2004 Locations Rye Brook, NY, and Houston Primary focus Small- to mid-sized energy companies in North America Individual investment range $25 million to $50 million Aggregate capital commitment Approx. $1 billion Management Managing Partners: Paul G. McDermott, Bruce M. Rothstein; Partners: Darin R. Booth, David Coppe; Executive Advisors: Michael McGovern, David H. Kennedy Portfolio companies Probe Holdings Inc., WestFire Energy Ltd., Torqued-Up Energy Services, Ardent Services LLC, Vermillion Resources Inc., Array Holdings, Logan Holdings Inc., Sherwood Energy LLC

Energy Capital Solutions LP When founded 2001 Locations

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Dallas Primary focus E&P and oil service firms, private equity and PIPEs transactions, buy-side and sell-side advisory Individual investment range Varies Aggregate capital commitment $2.7 billion in private capital raised since inception (80 transactions) Management Managing Director and Founder: J. Russell Weinberg; Director: Scott S. Trulock; Associate: David M. Malkowski Portfolio companies N/A

$6.5 billion Management Partners: David B. Miller, Gary R. Petersen, D. Martin Phillips, Robert L. Zorich. Managing Directors: E. Murphy Markham IV, R. Jason McMahon, Jason M. DeLorenzo, Hallie M. Kim, M. Sean Smith, Wynne M. Snoots, Douglas E. Swanson Jr. Portfolio companies Caiman Energy LLC, Common Resources, Crimson Energy Partners III, Destiny Oil & Gas, Empresa Energy, EV Energy Partners, Laredo Energy IV, Legado Resources, Marquette Exploration, Oasis Petroleum, Peregrine Oil & Gas II, Plains All American Pipeline LP, Tracker Resources Development II, Unconventional Resources

EnerVest

First Reserve Corporation

When founded 1992 Location Houston Primary Focus EnerVest Energy Institutional Fund XII recently closed with equity commitments of $1.5 billion and total purchasing power of $2.4 billion for the acquisition and development of oil and natural gas properties and strategic corporate acquisitions in North America. Individual investment range Transactions having a value between $50 million and $250 million. Aggregate capital commitment $2.4 billion (Fund XII) EnerVest Management Jon Rex Jones, chairman; John B. Walker, president and CEO; Mark A. Houser, executive vice president and COO; James M. Vanderhider, executive vice president and CFO. Vanderhider is responsible for the firm’s private equity efforts. Portfolio companies N/A

When founded 1983 Locations Greenwich, Conn.; London; Houston Primary focus Private equity and infrastructure investments Individual investment range Varies Aggregate capital commitment $12.5 billion since inception Management Chairman and CEO: William E. Macaulay; Vice Chairman: John A. Hill; Managing Directors: Timothy H. Day, Joseph R. Edwards, Cathleen M. Ellsworth, Will Honeybourne, Alex T. Krueger, Jeffrey S. MacDonald, Mark A. McComiskey, Kenneth W. Moore, J. Hardy Murchison, Jeffrey K. Quake, Alan G. Schwartz, Thomas J. Sikorski, Jennifer C. Zarrilli Portfolio companies Diversified across the energy sector. More than 100 platform acquisitions and about 300 add-on transactions. Includes Acteon Ltd., Aspect Abundant Shale LP, Beryl Resources LP, Dresser Inc., Remora Energy International, Saxon Energy Services, Stone Mountain Resources

EnCap Investments LP When founded 1988 Locations Houston and Dallas Primary focus To partner with seasoned management teams with demonstrated track record of value creation Individual investment range Not disclosed Aggregate capital commitment, capital under management

GasRock Capital LLC When founded 2005 Locations Houston Primary focus Mezzanine debt and project equity Individual investment range $5 million - $100 million Aggregate capital commitment



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Not disclosed Management Co-Founders: Frank M. Weisser, Scott W. Johnson, David R. Taylor, Marshall Lynn Bass Portfolio companies Miller Energy LLC, Westside Energy Corp., Saddle Rim LLC, Endevco Eureka LLC, Z2 Oil & Gas LLC, HNNG Development LLC, Two Oaks E&P Company, BPI Energy Inc., Chroma E&P Inc., Admiral Bay Resources Inc., Rancher Energy Corp.

Kayne Anderson Capital Advisors When founded 1991 (PE energy investing) Locations Houston, Los Angeles Primary focus Privately-issued private and preferred securities of both private and public companies in the USA and Canada Individual investment range $20 million - $100 million and up Aggregate capital commitment $2.5 billion Management President, Chief Investment Officer, and Co-Managing Partner: Robert Sinnott; Co-Managing Partner: Daniel Weingeist Portfolio companies Augustus Energy Partners, Caddo Resources, Compass Resources Corp. II, Crestwood Midstream, Exaro Energy, Grenadier Energy Partners, Greystone Exploration & Production, Highland Oil & Gas, HRM Resources, Laricina Energy, Matris Exploration, Millbrae Energy, OBENCO II, Pedernales Production, Sagebrush Resources, Trail Ridge Energy, Zone Energy

Lime Rock Partners When founded 1998 Locations Westport, Conn.; Houston; Aberdeen (UK); Dubai (UAE) Primary focus Global energy companies Individual investment range $25 million to $150 million Aggregate capital commitment, capital under management $3.9 billion Management Managing Directors: Jonathan Farber, John Reynolds, Saad Bargach, Thomas Bates, Trevor Burgess, Will Franklin, Mark McCall, J McLane, Simon Munro, Townes Pressler, Lawrence Ross; Directors: Jeffrey Scofield, Rob Willings Portfolio companies

Allis-Chalmers Energy, Arena Exploration, Braden Exploration, Bridge Energy, Global Energy Services, Hercules Offshore, ITS Group, Laricina Energy, PDC Mountaineer, Tiway Oil, Vantage Energy

Natural Gas Partners When founded 1988 Locations Irving, Tex.; Stamford, Conn.; Santa Fe, NM; Houston; London Primary focus Oil and natural gas asset portfolios, oilfield service, and other energy opportunities Individual investment range Not disclosed Aggregate capital commitment, capital under management $7.3 billion Management Managing Partners: Kenneth A. Hersh, William J. Quinn, David R. Albin. Principal: Thomas J. N. Verhagen. Managing Directors: Richard L. Covington, John S. Foster, Scott A. Gieselman, David W. Hayes, Christopher D. Ray, Colin F. Raymond, Tony R. Weber, John A. Weinzierl Portfolio companies Nine private equity funds invested in numerous energy companies

Quantum Energy Partners When founded 1998 Locations Houston Primary focus Mainly upstream, midstream, and power sectors Individual investment range $100 million to $400 million Aggregate capital commitment, capital under management $5.7 billion Management Co-founder, President, and CEO: Wil VanLoh; Co-founder and Managing Partner: Toby Neugebauer. COO: Cedric Burgher. Managing Directors: Alan Smith, David Bole, Scott Soler, John Campbell, James Baird (also General Counsel). Portfolio companies Action Energy, Aspect Holdings, Ceritas Energy II, Chalker Energy Partners III, Denali Oil & Gas Partners II, EnergyQuest II, Icon NGS, Quantum NGS Holdings, RMP Energy, Sequoia Resources, Tecton Energy, Tri-C Resources, Ute Energy, Vantage Energy, Wapiti Energy

Rhone Capital When founded 1997 Locations

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New York, London, Paris Primary focus Rhone specializes in middle market leveraged buyouts, recapitalizations, and partnership financings. The firm seeks to invest in energy, materials, industrials, retailing, consumer staples, healthcare, and financial sectors. It focuses on investments in European and trans-Atlantic companies. Individual investment range The firm seeks to invest between $50 million and $200 million in companies with enterprise values between $200 million and $1.3 billion. It prefers to invest in companies having a sales value between $100 million and $750 million and EBITDA between $25 million and $100 million. Aggregate capital commitment, capital under management Current fund size is about $1 billion. Management Managing Directors: Ferdinand Groos, Steven Langman, Sheldon Gordon, Andrew Sweet, and Robert Agostinelli Portfolio companies A diversified portfolio of companies, including in the energy space, UTEX Industries, which designs and manufactures products used in gas and oil completion and deepwater drilling and production activities.

Warburg Pincus When founded 1971 (first institutional fund), but traces its roots back to 1939 Locations New York, Sao Paolo, Beijing, Frankfurt, Hong Kong, London, Mumbai, San Francisco, Shanghai, Amsterdam, Luxembourg, Port Louis Primary focus Wide range, including energy, health care, financial services, technology, media, telecommunications, consumer, and industrial Individual investment range Varies, but average investment period is 5 to 7 years. Aggregate capital commitment, capital under management Over past 40 years, Warburg Pincus has raised more than 12 private equity funds and invested more than $35 billion in 600 companies in 30 countries. Management Co-Presidents: Charles R. Kaye and Joseph P. Landy. Portfolio companies More than 110. Dallas-based Kosmos Energy is one of the major energy sector companies. Others include Antero Resources, Broad Oak Energy, Canbriam Energy, Fairfield Energy, Gulf Coast Energy Resources; Laredo Petroleum; Omega Energia; Osum Oil Sands Corp.; Spectraseis; and Targa Resources.


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OGFJ100P company update

I

ndependent research firm IHS Herold Inc. has provided OGFJ with updated production data for our periodic ranking of US-based private E&P companies. The rankings provided by IHS are based on operated production only within the US. There were minor changes at the top of the list of producers from our last installment in October. In the top five spots, Samson Lone Star dipped from No. 2 to No. 3, Yates Petroleum fell two spots to No. 5 from No. 3, Merit Energy gained two spots to No. 2 from No. 4, and Hilcorp Energy moved up one spot from No. 5 to No. 4. Inching into the top ten in this installment is Citation Oil & Gas. The company switched the No. 11 for the No. 10 spot with Mewbourne Oil. As for the rest of the private sector, activity continued; the focus of which: monetizing shale assets.

Mergers & acquisitions In October, No. 61 Enduring Resources LLC sold its Eagle Ford acreage to a joint venture formed by Canada’s Talisman and Norway’s Statoil. The deal, comprising about 97,000 acres in a $1.325 billion transaction, equates to roughly US$10,900 per acre after allocating $8,100 per flowing mcfe to existing production of 5,500 boe/d. The acreage is located in McMullen, Karnes, Bee, and Live Oak counties with the majority of it

Top 10 private gas producers

in the condensate window. In another Eagle Ford shale deal announced in October, Plains Exploration & Production Co. (NYSE: PXP) agreed to acquire interest in approximately 60,000 acres, primarily in oil-rich Karnes County, from No. 60 Dan A. Hughes Co. and Houston American Energy Corp., for roughly $578 million in cash. About a third of the acreage is part of a joint operating area with EOG Resources. In another divestiture, privately held Anschutz Exploration announced its plan to sell its Appalachian properties to a thenunnamed buyer for an undisclosed price. Chesapeake Energy’s (NYSE: CHK) third quarter 2010 financial and operational results report dated November 3 later identified the company as the buyer. The Oklahoma City-based natural gas producer is looking to purchase the Denver-based company’s 500,000 net Appalachian acres, along with some production in Pennsylvania, Ohio, and NY for roughly $850 million. Public data shows Anschutz with just one drilling permit in McKean County, PA, in the neighborhood of SM Energy. Approximately 25% of the assets acquired are expected to be resold after closing, not yet reported as of press time, while the remainder of the assets will be combined with Chesapeake leasehold in a play in which the company expects to execute a new industry joint venture in the first half of 2011. A Novem-

Top 10 private liquids producers

100P Rank

Company

Gas (Mcf)

Rank

1

3

Samson Lone Star LP

117,334,761

1

2

2

Merit Energy Co.

98,019,007

2

3

5

Yates Petroleum Corp.

92,369,542

3

4

6

Samson Resources Co.

71,089,964

4

5

4

Hilcorp Energy Co.

67,766,460

5

6

8

EnerVest Operating LLC

56,806,545

7

14

J-W Operating Co.

8

11

Mewbourne Oil Co.

9

7

Walter Oil & Gas Corp.

10

12

LLOG Exploration Co.

Rank

Source: IHS Herold

E ! AP 2430 N 11 oth 20 at Bo Us See

100P Rank

Company

Liquid (bbl)

1

Aera Energy LLC

40,969,525

4

Hilcorp Energy Co.

8,755,591

10

Citation Oil & Gas Corp.

7,784,665

2

Merit Energy Co.

7,741,444

9

Endeavor Energy Resources LP

6,087,826

6

7


4,357,563

47,518,570

7

24

Slawson Exploration Co. Inc.

3,816,189

43,909,593

8

3

Samson Lone Star LP

3,175,026

43,670,400

9

25

Texas Petroleum Investment Co.

3,135,489

35,360,950

10

12


3,080,040

Source: IHS Herold

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OGFJ100P ber 4 research report from Jefferies & Co. noted the targeting of the Utica shale as a motive for the acquisition. As the demand for shale assets remains high, some privately held companies–with operations limited by their size–are looking to sell to larger companies. Such may be the case for privately held Talon Oil & Gas and Chief Oil & Gas, according to a Jefferies & Co. Inc. report dated October 6. Talon Oil &Gas, a Dallas-based company backed by privateequity firm EnCap Investments LP, holds Barnett, East Texas,

and Panhandle reserves, and according to the Wall Street Journal, could command a price of $1 billion to $1.5 billion. Chief Oil & Gas, active in the Appalachian Basin, northern Texas, and Central Utah, could also be looking to capitalize on its shale assets. The company holding 600,000 acres in the Pennsylvania Marcellus, “looks to be in the most prolific areas in the Northeast and established areas in the Southwest,” noted Jefferies in the October 6 report. The Wall Street Journal, citing people familiar with the matter, noted Chief Oil & Gas could fetch up to $3 billion.

2010 Year-to-date production ranked by BOE Rank

Company

BOE

Total wells

Largest field Belridge South

1

Aera Energy LLC

43,474,529

12,395

2

Merit Energy Co.

24,077,945

5,455

Lost Soldier

3

Samson Lone Star LP

22,730,820

1,991

Gulf Terrace

4

Hilcorp Energy Co.

20,050,001

1,630

Calliou Island

5


16,884,347

3,704

Powder River Basin Coal Bed

6


13,040,506

2,301

Ignacio-Blanco

7


11,635,963

83

Ship Shoal Block 0189

8


11,311,521

3,329

Giddings

9


10,170,136

4,822

Sprayberry

10


9,644,432

2,365

Sho-Vel-Tum

11

Mewbourne Oil Co.

9,342,793

1,138

Mendota Northwest

12


8,973,532

38

High Island Block 0170

13

Bass Companies

8,292,920

1,047

Keystone

14

J-W Operating Co.

8,070,851

889

Elm Grove

15

Hunt Oil Co.

8,070,029

519

Fairway

16

Ballard Exploration Co. Inc.

6,345,519

68

Gulf Terrace

17

Quantum Resources Management LLC

5,337,904

1,215

Jay

18

Red Willow Production Co.

5,184,913

358

Ignacio-Blanco

19

Lewis Energy Group

5,116,619

1,148

Owen

20

Marbob Energy Corp.

4,883,304

1,143

Grayburg Jackson

21

Valence Operating Co.

4,718,061

503

Farrar

22

Sheridan Production Co. LLC

4,581,516

1,255

Javelina

23

RAAM Global Energy Co.

4,469,875

47

West Cameron Block 0368

24


4,447,509

206

Big Bend

25


4,236,546

1,325

Luling-Branyon

26

Milagro Exploration LLC

3,953,656

492

Magnet Withers

Land Management

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OGFJ100P Rank

Company

BOE

Total wells

Largest field

27

Kaiser-Francis Oil Co.

3,817,126

1,302

Elk City

28

Fasken Oil and Ranch Ltd.

3,807,899

770

Sprayberry

29

Petro-Hunt Group

3,738,289

336

Charlson

30

Talon Oil & Gas LLC

3,721,075

249

Newark East

31

J.M. Huber Corp.

3,317,614

1,694

Powder River Basin Coal Bed

32

Stephens Production Co.

3,088,258

843

Gragg

33

BASA Resources Inc.

2,999,741

2,346

East Texas

34

Helis Oil & Gas Co. LLC

2,895,461

14

Eugene Island Block 0351

35

Dynamic Offshore Resources LLC

2,875,844

36

Green Canyon Block 0065

36

DCOR LLC

2,797,915

247

Dos Cuadras

37

Davis Petroleum Corp.

2,697,450

90

Lac Blanc

38

Killam Oil Co. Ltd.

2,641,625

406

Cuba Libre

39

Laredo Petroleum Inc.

2,590,733

335

Begert Dist 10

40

Wagner Oil Co.

2,545,699

241

La Sal Vieja Dist 4

41

Jetta Operating Co. Inc.

2,294,712

949

Thompson

42

Murex Petroleum Corp.

2,085,785

139

Sanish

43

Tidelands Oil Production Co.

2,039,039

431

Wilmington

44

Wolverine Gas and Oil Corp.

2,037,124

22

Covenant

45

Tellus Operating Group LLC

2,036,525

428

Baxterville

46

Texland Petroleum LP

1,988,355

598

Fullerton

47

J. Cleo Thompson & James Cleo Thompson, Jr.

1,866,453

885

Sprayberry

48

WildHorse Resources LLC

1,824,624

215

Terryville

49

Broad Oak Energy Inc.

1,811,871

247

Sprayberry

50

Burnett Oil Co. Inc.

1,762,718

270

Newark East

51

Stephens & Johnson Operating Co.

1,723,042

737

Oklahoma City

52

Gary, Samuel Jr & Associates Inc.

1,698,984

108

Marceaux Island

53

New Dominion LLC

1,698,404

243

Oklahoma City

54

Vernon E. Faulconer Inc.

1,694,180

623

Porters Creek

55

Manti Resources Inc.

1,670,211

35

Bancker

56

Tana Exploration Co.

1,666,540

13

Matagorda Island Block 0633

57

Patara Oil & Gas LLC

1,661,326

190

Andys Mesa

58

MacPherson Oil Co.

1,628,208

269

Round Mountain

59

Sanguine Gas Exploration LLC

1,618,683

138

Mills Ranch

60

Dan A. Hughes Co.

1,581,420

132

Berry R Cox

61

Enduring Resources LLC

1,576,447

118

Speary

62

Jones Energy Ltd.

1,566,388

279

Mammoth Creek North

63

Finley Resources Inc.

1,560,354

500

Newark East

64

Vess Oil Corp.

1,546,626

1,364

Kurten

65

Zenergy Inc.

1,528,123

220

Belle Isle Southwest

Financial Accounting 52

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OGFJ100P Rank

Company

BOE

Total wells

Largest field

66

Berexco Inc.

1,469,969

1,268

Terry

67

Ergon Exploration Inc.

1,429,428

37

Brookeland

68

Square Mile Energy

1,429,052

28

Coconut

69

Wagner & Brown Ltd.

1,418,341

104

Overton

70

Nadel & Gussman

1,350,393

599

Greenwood Gas Area

71

Rosewood Resources Inc.

1,345,361

1,070

Waverly

72

Phoenix Exploration Co.

1,339,793

30

Belle Isle

73

JM Cox Resources LP

1,336,404

842

Sprayberry

74

Sanchez Oil & Gas Corp.

1,255,257

51

Etta

75

Anglo-Suisse Offshore Partners LLC

1,247,152

54

West Delta Block 0030

76

Union Gas Operating Co.

1,215,453

50

Vickers

77

Castex Energy Inc.

1,213,536

36

Joe McHugh

78

E&B Natural Resources Management Corp.

1,212,219

1,037

Poso Creek

79

Black Elk Energy LLC

1,207,080

47

South Pass Block 0089

80


1,191,651

37

Little Knife

81

Muskegon Development Co.

1,190,013

1,274

Antrim

82

Great Western Drilling Co.

1,180,982

316

Suntura

83

West Bay Exploration Co.

1,164,464

64

Napoleon

84

McGowan Working Partners

1,154,799

294

Shuler

85

Cobra Oil & Gas Corp.

1,137,892

120

Sprayberry

86

Famcor Oil Co. Inc.

1,137,028

75

Cold Springs

87

Cypress E&P Corp.

1,122,057

21

Cypress Eagle

88

Sundown Energy Inc.

1,115,593

247

Wagon Wheel

89

Smith Production Inc.

1,094,817

144

Samano

90

Royal Production Co. Inc.

1,094,708

40

Brazos Block 0501

91

GeoSouthern Energy Corp.

1,094,154

102

De Witt

92

Mull Drilling Co. Inc.

1,087,097

295

Arapahoe

93

Dugan Production Corp.

1,086,981

902

Basin

94

Energy Production Corp.

1,062,203

77

Neuhoff

95

KEBO Oil & Gas Inc.

1,060,277

98

Houdman

96

Midroc Operating Co.

1,054,089

95

Little Cedar Creek

97

Murfin Drilling Co.

1,053,528

874

Humperdinck

98

JAMEX Inc.

1,048,993

93

Rexville

99

Denali Oil & Gas

1,043,819

31

Haynes Dist 4

100

Mack Energy Corp.

1,027,571

254

Little Ducky Lake

101

Verado Energy Inc.

1,026,175

173

Oak Hill

102

Ellora Energy Inc.

1,021,395

92

Huxley

103

Laramie Energy II LLC

1,007,790

84

Rulison

104

Dewbre Petroleum Corp.

1,006,578

145

McAllen Ranch

Production Revenue Accounting



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OGFJ100P Rank

BOE

Total wells

Largest field

105

Company Border To Border Exploration LLC

1,004,696

17

Magnolia Springs

106

Augustus Energy Partners

993,040

672

Buffalo Grass

107

Elm Ridge Resources Inc.

964,695

103

Ignacio-Blanco

108

Chinn Exploration Co.

948,751

249

Oak Hill

109

Antero Resources Corp.

926,379

117

Reams Southeast

110

Winn Exploration Co. Inc.

909,382

23

Warmsley South

111

Southern California Gas Co.

907,514

183

Honor Rancho

112

Petro-Chem Operating Co. Inc.

888,245

79

Grayson

113

McElvain Oil & Gas Properties Inc.

885,823

228

Ignacio-Blanco

114

Canaan Resources LLC

875,313

253

Pittsburgh County CBM Gas Area Garden Banks Block 0339

115

Deep Gulf Energy LP

874,717

1

116

Strat Land Exploration Co.

864,314

311

Hansford

117

Aruba Petroleum Inc.

862,880

66

Newark East

118

CrownQuest Operating LLC

853,859

510

Iatan East Howard

119

Neumin Production Co.

845,573

72

Lavaca Bay

120

Petrogulf Corp.

845,418

51

Ignacio-Blanco

121

Woolsey Petroleum Corp.

842,793

464

Roundup South

122

American Warrior Inc.

840,145

811

Dewald North

123

Luff Exploration Co.

837,330

72

Harding Springs East

124

Sabco Oil & Gas Corp.

828,427

92

Mustang Island Block 0889

125

Lario Oil & Gas Co.

817,883

295

Sand Hills

126

Mack Energy Co

814,157

191

Sho-Vel-Tum

127

Trend Exploration I LLC

811,853

32

Unnamed

128

Eagle Oil & Gas Co.

811,817

85

Converse

Source: IHS Herold; For more information about IHS Herold’s Private Company Database, visit herold.com/research.herold.contact_us

2010 Year-to-date production – alphabetical listing Rank 1

Company Aera Energy LLC

BOE

City

State

43,474,529

Bakersfield

CA

Kate Shae, CFO; Gaurdie Banister, pres, CEO

Top executive officials

122

American Warrior Inc.

840,145

Garden City

KS

Dan Dalke, controller; Cecil O'Brate, pres, owner

75

Anglo-Suisse Offshore Partners LLC

1,247,152

Houston

TX

John Sherwood, CEO; Thomas Fiorito, exec VP, COO; JE Ward, VP ops, prod; Brian Romere, CFO

109

Antero Resources Corp.

926,379

Greensburg

PA

Paul Rady, chair, CEO; Glen Warren, pres, CFO

117

Aruba Petroleum Inc.

862,880

Plano

TX

James Poston, CEO; Jim Lovett, CFO; John Goforth, VP; Michael McAlister, VP landl Linda Cavender, VP

106

Augustus Energy Partners

993,040

Billings

MT

Steve Durrett, pres

16

Ballard Exploration Co. Inc.

6,345,519

Houston

TX

A. Ballard, pres, CEO, owner

Cost Accounting Joint Interest Billing 54

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Company

BOE

City

State


33

BASA Resources Inc.

2,999,741

Dallas

TX

Sandra Wallace, CFO; Michael Foster, pres, co-founder; Lary Knowlton, co-founder, exec VP

13

Bass Companies

8,292,920

Fort Worth

TX

Stewart Henry, pres, COO; W. Cottham, VP, sec, controller; W. McCreight, VP land

66

Berexco Inc.

1,469,969

Wichita

KS

Charles Spradlin, exec VP, exp mgr; Robert Beren, chair, CEO, owner; Adam Beren, pres

79

Black Elk Energy LLC

1,207,080

New Orleans

LA

John Hoffman, pres, CEO; James Hagemeier, CFO; Douglas Fehr, COO

105

Border To Border Exploration LLC

1,004,696

Coldspring

TX

John Gaines, CFO; Matthew Telfer, CEO, geologist

49

Broad Oak Energy Inc.

1,811,871

Dallas

TX

Jim Sherrill, CFO; John Coss, pres; David Braddock, CEO; Robert Skinner, VP ops

50

Burnett Oil Co. Inc.

1,762,718

Fort Worth

TX

Philip Boschetti, VP, CFO; Anne Marion, chair, owner; William Pollaru, pres

114

Canaan Resources LLC

875,313

Oklahoma City

OK

Leo Woodard, chair, CEO; John Penton, pres; S. Mark Cain, Michael Mewbourn, VP finance, CFO

77

Castex Energy Inc.

1,213,536

Houston

TX

John Stoika, pres

108

Chinn Exploration Co.

948,751

Longview

TX

Thomas Chinn, pres, owner

10


9,644,432

Houston

TX

Curtis Harrell, pres, CEO; Christopher Phelps, CFO, VP finance, strategic planning; Wayne Wiesen, sr. VP, gen counsel, sec; Forrest Harrell Sr., chair; Steven Pearson, sr. VP ops; Robert Kennedy, sr. VP bus dev, land; Steve Anna, sr. VP engineering

85

Cobra Oil & Gas Corp.

1,137,892

Wichita Falls

TX

Jeff Dillard, pres; Robert Osborne, VP, co-owner; Richard Haskin, CFO

118

CrownQuest Operating LLC

853,859

Midland

TX

Robert Floyd, pres; Timothy Dunn, principal, CEO

87

Cypress E&P Corp.

1,122,057

Austin

TX

Robert Beardsley, pres; Larry Cochran, VP, principal; William Jackson, VP ops

60

Dan A. Hughes Co.

1,581,420

Beeville

TX

Dan Hughes, president, partner

37

Davis Petroleum Corp.

2,697,450

Houston

TX

Daniel Hawk, exec VP, CFO; Michael Reddin, pres, CEO

36

DCOR LLC

2,797,915

Ventura

CA

William Templeton, pres; managing member, principal

115

Deep Gulf Energy LP

874,717

Houston

TX

Dave Huber, co-founder; Tom Young, VP, bus dev

99

Denali Oil & Gas

1,043,819

Houston

TX

Rick Louden, pres, CEO; John Elzner, sr VP bus dev; Paul Hunt, VP exp; Jeff Waybright, VP, CFO; Allen May, VP bus dev

104

Dewbre Petroleum Corp.

1,006,578

Corpus Christi

TX

Claudia Grivich, CFO; David Kinard, VP prod/mgmt; Jack Day, VP, ops mgr; Jerry Dewbre, pres, CEO, owner

93

Dugan Production Corp.

1,086,981

Farmington

NM

Thomas Dugan, pres, CEO; Thomas Blair, VP prod; John Alexander, VP ops

35

Dynamic Offshore Resources LLC

2,875,844

Houston

TX

Michel Moreno, co-founder, dir; John Jo, sr VP acq eng; Howard Tate, sr VP, CFO; Matt McCarroll, pres, CEO

78

E&B Natural Resources Management Corp.

1,212,219

Bakersfield

CA

Francesco Galesi, chair; Frank Ronkese, CFO, treas; Stephen Layton, pres

128

Eagle Oil & Gas Co.

811,817

Dallas

TX

Warren Ayres, exec VP, CFO, dir; Pat Bolin, pres, CEO, chair; Bill Fairhurst, VP exp

102

Ellora Energy Inc.

1,021,395

Boulder

CO

Steven Enger, pres, COO; Lon McCain, exec VP, CFO; T. Scott Martin, chair, CEO

107

Elm Ridge Resources Inc.

964,695

Dallas

TX

James Clark, pres, CEO, owner

9


10,170,136

Midland

TX

Autry Stephens, CEO, founder, partner

61


1,576,447

Vernal

UT

Barth Whitham, pres, CEO

94

Energy Production Corp.

1,062,203

Dallas

TX

Kelly Wade, VP, production mgr; Joe Vaughan, pres, CEO, owner; Greg Fusselman, VP, treas

8


11,311,521

Houston

TX

Mark Houser, pres

67

Ergon Exploration Inc.

1,429,428

Monroe

LA

Leslie Lampton, chair, pres

Gas Marketing

www.qbsol.com

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OGFJ100P Rank

Company

BOE

City

State

1,137,028

Houston

TX


86

Famcor Oil Co. Inc.

James Ray, pres

28

Fasken Oil and Ranch Ltd.

3,807,899

Midland

TX

Norbert Dickman, VP, gen mgr

63

Finley Resources Inc.

1,560,354

Fort Worth

TX

James Finley, founder, CEO; Brent Talbot, pres; Stephen Clark, CFO

52

Gary, Samuel Jr & Associates Inc.

1,698,984

Denver

CO

Samuel Gary, pres; treas, founder; Craig Ambler, COO, partner; Lonnie Brock, CFO

91

GeoSouthern Energy Corp.

1,094,154

The Woodlands

TX

John Perrella, CFO, controller; George Bishop, pres, owner

82

Great Western Drilling Co.

1,180,982

Midland

TX

Bruce Brady, pres; Kenneth Davis, chair

34

Helis Oil & Gas Co. LLC

2,895,461

New Orleans

LA

David Kerstein, pres; Michael Schott, VP, CFO

4

Hilcorp Energy Co.

20,050,001

Houston

TX

Jeffery Hildebrand, pres, CEO, founder; George Newton, exec VP A&D; Greg Lalicker, exec VP

15

Hunt Oil Co.

8,070,029

Dallas

TX

Ernest Easley, sr VP, US E&D; Donald Robillard, sr VP, CFO; Ray Hunt, CEO; Stephen Hurley, pres; James Jennings, chair; Craig Glick, sr VP

47

J. Cleo Thompson & James Cleo Thompson, Jr.

1,866,453

Dallas

TX

Cliff Milford, CFO; Linda Gordon, partner; James Thompson, pres; CEO, managing partner

31

J.M. Huber Corp.

3,317,614

Houston

TX

Jeffrey Ellena, CFO; Ralph Schofield, pres; James Frew, VP strategy, bus dev

98

JAMEX Inc.

1,048,993

Lewisville

TX

Douglas Quebe, VP; Michael Yarussi, pres, CEO

41

Jetta Operating Co. Inc.

2,294,712

Fort Worth

TX

David Patterson, VP drilling, ops; Jeanette Clark, VP controller, treas; Richard Cornelius, VP land, acquisitions; John Jarrett, CFO; Gregory Bird, pres, owner; William Monroe, VP geology

73

JM Cox Resources LP

1,336,404

Midland

TX

John Cox, pres, CEO

62

Jones Energy Ltd.

1,566,388

Austin

TX

Hal Hawthorne, VP exp; Mike McConnell, pres; Jonny Jones, CEO; Jon Jones, chair; Craig Fleming, sr VP, CFO; Jody Crook, VP land

14

J-W Operating Co.

8,070,851

Addison

TX

Howard Westerman, CEO, chair; G. Gene Gradick, pres; CD McDaniels, exec VP, vice chair; Paul Westerman, COO; Lindon Leners, VP finance

27

Kaiser-Francis Oil Co.

3,817,126

Tulsa

OK

Henry Kleemeier, exec VP, COO; James Willis, exec VP; Don Millican, CFO, VP; George Kaiser, pres, CEO

95

KEBO Oil & Gas Inc.

1,060,277

Portland

TX

Ken Boester, pres, owner

38

Killam Oil Co. Ltd.

2,641,625

Laredo

TX

Radcliffe Killam, CEO; David Killam, partner, mgr

103

Laramie Energy II LLC

1,007,790

Denver

CO

Robert Boswell, chair, CEO; Bruce Payne, pres, CFO

39

Laredo Petroleum Inc.

2,590,733

Tulsa

OK

Jerry Schuyler, pres, COO; Patrick Curth, sr VP exp, land; Randy Foutch, chair, CEO; Mark Womble, sr VP, CFO

125

Lario Oil & Gas Co.

817,883

Denver

CO

Patrick O'Shaughnessy, chair; David Loger, CFO, exec VP; Michael O'Shaughnessy, pres, CEO; Paul Gagnon, pres Lario Canada

19

Lewis Energy Group

5,116,619

San Antonio

TX

Mark Stavinoha, CAO; Al Holcomb, VP special projects; R. Stan Jumper, VP E&D; Rodney Lewis, pres, CEO

12


8,973,532

Houston

TX

Gerald Boelte, chair, owner; Scott Gutterman, pres, CEO; Kevin Guilbeau, exec VP, COO; Kemberlia Ducote, CFO, controller

123

Luff Exploration Co.

837,330

Denver

CO

Kenneth Luff, pres; Kathleen Schell, CFO

126

Mack Energy Co

814,157

Duncan

OK

Noble Means, CFO, controller; Randy Smith, VP prod; Chris Fowler, VP E&E; Tom McCasland, pres, chair

100

Mack Energy Corp.

1,027,571

Ft. Worth

TX

Mack Chase, pres; Robert Chase, VP; Brad Bartek, VP, treas; Richard Chase, VP

58

MacPherson Oil Co.

1,628,208

Santa Monica

CA

Donald MacPherson, pres, CEO; Scott MacPherson, sr VP. COO; Bradford Williams, CFO

Business Intelligence 56

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BOE

City

State

55

Manti Resources Inc.

Company

1,670,211

Corpus Christi

TX

Lee Barberito, pres; Robert Helm, CFO


20

Marbob Energy Corp.

4,883,304

Artesia

NM

John Gray, pres; Douglas Chandler, VP

113

McElvain Oil & Gas Properties Inc.

885,823

Denver

CO

Steve Shefte, VP, COO; Guy McElvain, pres, CEO; David Sykes, CFO, treas

84

McGowan Working Partners

1,154,799

Jackson

MS

Joseph McGowan, VP; David McGowan, partner; James Phyler, VP; David Russell, pres, CEO; John McGowan, managing GP

2

Merit Energy Co.

24,077,945

Dallas

TX

T. Porter Trimble, sr VP, bus dev; Jake Plunk, VP bud dev; Gayden Carr, VP finance; Robert Matejek, pres; William Gayden, chair, founder

11

Mewbourne Oil Co.

9,342,793

Tyler

TX

Kenneth Waits, COO, exec VP; J. Roe Buckley, CFO, exec VP; Curtis Mewbourne, pres, CEO, owner

96

Midroc Operating Co.

1,054,089

Dallas

TX

James Harris, VP; Donald Clark, pres

26

Milagro Exploration LLC

3,953,656

Houston

TX

Gary Mabie, COO; James Ivey, exec VP, CFO; Marshall Munsell, sr VP bus dev Lewis Mull, chair, CEO; Mark Shreve, pres, COO; Steven Anderson, sr VP; Jennifer Mull, exec VP

92

Mull Drilling Co. Inc.

1,087,097

Wichita

KS

42

Murex Petroleum Corp.

2,085,785

Houston

TX

Waldo Ackerman, pres; Donald Kessel, VP

97

Murfin Drilling Co.

1,053,528

Wichita

KS

Robert Young, CFO, sec, treas; David Doyel, VP exp; William Murfin, chair; David Murfin, pres

81

Muskegon Development Co.

1,190,013

Mount Pleasant

MI

William Myler, pres, CEO; Thomas Myler, VP

70

Nadel & Gussman

1,350,393

Tulsa

OK

Stephen Heyman, partner, LLC mgr; Wayne Hamilton, CFO; James Adelson, pres, partner, LLC mgr

119

Neumin Production Co.

845,573

Point Comfort

TX

Stan Ueng, VP; Tony Chen, pres

53

New Dominion LLC

1,698,404

Tulsa

OK

David Chernicky, pres, CEO; Tim Cargile, COO, CFO; Janet McGehee, exec VP, engineering, prod

57

Patara Oil & Gas LLC

1,661,326

Houston

TX

Bill Berilgen, CEO

112

Petro-Chem Operating Co. Inc.

888,245

Shreveport

LA

Laurence Hock, pres, CEO

120

Petrogulf Corp.

845,418

Houston

TX

Brian Dolan, VP ops; Ron Thompson, VP land, legal; Betty Pennington, exec VP, sec; Douglas McCleod, pres, CEO, owner

29

Petro-Hunt Group

3,738,289

Denver

CO

Tom Nelson, CFO; Douglas Hunt, director acquisitions; Charles Rigdon, VP eng; Bruce Hunt, pres

72

Phoenix Exploration Co.

1,339,793

Houston

TX

John Parker, sr VP exp; Stephen Heitzman, pres, CEO; Timothy Duncan, sr VP bus dev; John Harrison, CFO; Keith Westmoreland, sr VP ops

17

Quantum Resources Management LLC

5,337,904

Houston

TX

Alan Smith, pres, CEO; John Campbell, interim COO; Donald Wolf, chair; Matthew Assiff, CFO

23

RAAM Global Energy Co.

4,469,875

Lexington

KY

Jeff Craycraft, CFO; Howard Settle, CEO

18

Red Willow Production Co.

5,184,913

Ignacio

CO

Barbara Wickman, pres, COO; Leonard Burch, tribal chair, CEO

71

Rosewood Resources Inc.

1,345,361

Dallas

TX

Linda Tucker, VP admin, finance; Gary Conrad, pres; Ovidio Alfaro, VP; Geoff Ice, VP exp; Mark Malinowsky, VP eng

90

Royal Production Co. Inc.

1,094,708

Corpus Christi

TX

Donald Kersting, VP prod; William Gregorcyk, pres; Scott Smith, VP land

124

Sabco Oil & Gas Corp.

828,427

Houston

TX

Bob Howell, VP, ops; A. Behrooz Ramesh, exec VP; Ali Saberioon, pres, CEO; David Lucke, CFO; Paul Dunning, sr VP, land

3

Samson Lone Star LP

22,730,820

Tulsa

OK

Scott Rowland, VP bus dev

6


13,040,506

Tulsa

OK

C. Tholen, exec VP; David Adams, COO; Dudley Viles, exec VP; David Bradford, sr VP, bus dev; Stacy Schusterman, Co-CEO, chair; Jack Canon, sr VP, gen counsel

Software and consulting services for the oil and gas industry 713.430.8601

[email protected]



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Company

BOE

City

State


74

Sanchez Oil & Gas Corp.

1,255,257

Houston

TX

Frank Guerra, CFO, COO; Roberto Alaniz, exec VP exp; Antonio Sanchez, CEO, chair, owner; Tony Sanchez, pres

59

Sanguine Gas Exploration LLC

1,618,683

Tulsa

OK

Randolph Nelson, pres; Thomas Fuller, VP finance, treas

22

Sheridan Production Co. LLC

4,581,516

Houston

TX

Jim Bass, exec VP, COO; Tim Blaine, CFO; Lisa Stewart, CEO

24


4,447,509

Wichita

KS

Donald Slawson, pres, CEO

89

Smith Production Inc.

1,094,817

Spring

TX

Charlie Moore, VP eng; Kelly Mahoney, VP bus dev; Glenn Smith, pres, CEO

111

Southern California Gas Co.

907,514

Los Angeles

CA

Michael Niggli, COO; Debra Reed, pres, CEO; Dennis Arriola, sr VP, CFO

68

Square Mile Energy

1,429,052

Houston

TX

Al Bettis, VP land; Gary Loveless, chair, CEO

51

Stephens & Johnson Operating Co.

1,723,042

Wichita Falls

TX

Fred Stephens, pres; Joe Johnson, VP

32

Stephens Production Co.

3,088,258

Fort Smith

AR

Jack Stephens, chair; William Walker, pres, CEO; Jon Jacoby, exec VP, CFO

116

Strat Land Exploration Co.

864,314

Tulsa

OK

Larry Darden, pres, CEO, owner

88

Sundown Energy Inc.

1,115,593

Dallas

TX

Tim Allen, pres; Allen Farris, CFO, corp principal; Gregg Allen, VP

30

Talon Oil & Gas LLC

3,721,075

Dallas

TX

Grant Henderson, pres

1,666,540

Houston

TX

Madison Woodward, VP exp, new ventures; Kevin Talley, pres; Daniel Markey, VP, exp, tech; Randy Judd, VP eng; Carl Comstock, VP, land, bus dev

Tellus Operating Group LLC

2,036,525

Ridgeland

MS

Charles M. May Jr., COO; Tom Wofford, CFO; Richard Mills pres, mgr


4,236,546

Houston

TX

Wiliam Crawford, co-owner, principal; H Sallee, pres, co-founder

46

Texland Petroleum LP

1,988,355

Fort Worth

TX

Jerry Namy, pres, CEO, co-owner; James Wilkes, pres, COO, co-owner; Frank Kyle, co-owner, CFO; R.J. Schumacher, chair

43

Tidelands Oil Production Co.

2,039,039

Long Beach

CA

Michael Domanski, pres, CEO, gen mgr; Mark Kapelke, VP ops, eng

80


1,191,651

Denver

CO

Jeffrey Vaughan, pres; Shawn McCarter, COO; James Wason, VP land; Paul Wiesner, CFO

127

Trend Exploration I LLC

811,853

Midland

TX

David Holland, chair; Terrence Holland, pres, CEO, geologist; R. Kent Gaultney, exec VP

76

Union Gas Operating Co.

1,215,453

Houston

TX

Russell Chabaud, pres, CEO; Randall Lowry, VP, sec, treas

21

Valence Operating Co.

4,718,061

Kingwood

TX

Steve Manning, pres; Douglas Scherr, CFO, sec; Walter Scherr, CEO

101

Verado Energy Inc.

1,026,175

Dallas

TX

Michael Slater, pres, sec; Herman Fichtner, VP finance Tom Markel, VP acct, CFO; David Enright, pres; Jean Crawley, VP land, admin; Vernon Faulconer, CEO

56

Tana Exploration Co.

45 25

54

Vernon E. Faulconer Inc.

1,694,180

Tyler

TX

64

Vess Oil Corp.

1,546,626

Wichita

KS

J. Vess, pres

69

Wagner & Brown Ltd.

1,418,341

Midland

TX

Ted Meade, VP land; Paul Morris, pres, CEO; Cyril Wagner, principal; Jack Brown, principal

40

Wagner Oil Co.

2,545,699

Fort Worth

TX

HE Patterson, sr VP, COO; Bryan Wagner, pres, owner; William Lesikar, VP, CFO

7


11,635,963

Houston

TX

Joseph Walter, pres; chair, CEO; Cecil Looke, VP ops

83

West Bay Exploration Co.

1,164,464

Traverse City

MI

Harry Graham, VP exp; Robert Tucker, pres, owner; Gary Gottschalk, VP land, legal; David Rataj, VP finance, treas

48

WildHorse Resources LLC

1,824,624

Houston

TX

Jay Graham, pres; Anthony Bahr, CEO

110

Winn Exploration Co. Inc.

909,382

Corpus Christi

TX

Michael Calley, VP, sec, treas, GM; Charles Winn, pres, founder, owner

44

Wolverine Gas and Oil Corp.

2,037,124

Grand Rapids

MI

Gary Bleeker, VP; Sidney Jansma, pres, CEO

121

Woolsey Petroleum Corp.

842,793

Wichita

KS

I. Woolsey, pres; Kay Woolsey, VP, sec; Scott Frazier, VP, treas, financial mgr

5


16,884,347

Artesia

NM

John Yates, chair; John Yates Jr., pres; Scott Yates, VP; James Brown, COO; John Perini, CFO; Jorge Mendoza, chief admin officer

65

Zenergy Inc.

1,528,123

Tulsa

OK

Wayne Taylor, VP geo, ops; Tom Harrold, VP geo, exp; Robert Zinke, pres, chair; Michele Knotts, VP land

Source: IHS Herold; For more information about IHS Herold’s Private Company Database, visit herold.com/research.herold.contact_us

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Industry Briefs Energen buys SandRidge Permian acreage for $110M

Energy in September. GHS acted as left joint book runner on both transEnergen Corp.’s oil and gas exploraactions. On Nov. 18, Global Hunter tion and production company, Eneracted as a co-manager on offerings of gen Resources Corp., has purchased convertible senior notes and com40,000 acres in the Permian Basin mon stock for PDC Energy. The from SandRidge Energy Inc. for $110 convertible senior notes offering of million. Based on 320-acre spacing, $115 million priced at 3.25% and will the company has identified 62 net mature in 2016. The common stock potential drilling locations in the 3rd offering was increased in size from Bone Spring play on 21,300 net acres the originally announced 3,000,000 in Loving, Reeves, Ward, and Winshares of common stock to 4,140,000 kler counties. Unproved Bone Spring shares and priced at $32 per share, for reserves (net unrisked) are estimated total gross proceeds of $132.48 milto exceed 21 MMboe (78% oil, 22% lion. These energy transactions were natural gas). The company expects followed by a $13.5 million common stock offering for a China-based firm, to invest $465 million to develop Shengkai Innovations Inc. GHS acted the acreage. A horizontal drilling play targeting the 3rd Bone Spring as left joint book runner in this transSands at a vertical depth of 10,500action, which consisted of 2,456,800 11,500 feet, the typical Bone Spring shares priced at $5.50 on November 19. Prior to that transaction, GHS well has estimated ultimate recovery acted as lead placement agent on a of 400,000-500,000 boe; Energen Resources estimates that drilling and $7.9 million private placement for completion costs are nearly $7.5 mil- Zoom Technologies of China. Zoom lion per well. This acquisition brings sold 2,113,664 units at a price of Energen’s total acreage position in $3.75 per unit. Each unit is comthe 3rd Bone Spring play to more prised of one share of common stock than 33,000 net undeveloped acres. of Zoom and warrants to purchase Together with existing acreage, this three-quarters of one common stock. acquisition brings the company’s total Avalon potential to more than 60,000 Apache selects net undeveloped acres and more than OGN Group for North Sea 180 drilling locations. platform construction Apache Corp. has selected OGN Global Hunter closes five Group, a UK-based oil and gas endeals exceeding $418M gineering and fabrication contractor, Global Hunter Securities said Dec. 13 to build a new satellite oil production it has closed five separate transactions platform for the UK Forties field. The for four different clients at the end of new platform will be bridge-linked to November, totaling $418.8 million. the existing Forties Alpha installation The deals represent a cross section in the Apache-operated field, located of GHS’ portfolio of expertise, with on the UK continental shelf. The both debt and equity offerings for contract is worth in excess of $240 public and private companies in GHS’ million. Onshore construction is core-focus sectors of global energy expected to be complete by mid-year and China. The largest of the deals 2012. Apache holds an approximate was a $150 million senior secured 97% working interest in the Forties notes offering for Black Elk Energy. field. This was GHS’ second deal of this size for a private GoM E&P company Hess acquires Bakken within the last two months, the first acreage for $1.05 billion having been closed for RAAM Global New York-based Hess Corp. has 60

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agreed to acquire 167,000 net acres in the Bakken oil shale play in North Dakota from TRZ Energy LLC for $1.05 billion in cash. The properties being acquired are located near Hess’ existing acreage and have current net production of roughly 4,400 boe/d.

Chevron sets $26B capital, exploratory budget for 2011 Chevron Corp. announced a $26 billion capital and exploratory spending program for 2011. Included in the 2011 program are $2 billion of expenditures by affiliates, which do not require cash outlays by Chevron. Acquisition costs associated with the recently announced purchase of Atlas Energy Inc. are not included. Roughly 85% ($22.6 billion) of the spending program is for upstream oil and gas exploration and production projects worldwide. Another 10% is associated with the company’s downstream businesses. Major capital investments include development of the vast natural gas resources in Western Australia and development opportunities in the deepwater US Gulf of Mexico, Western Africa, and the Gulf of Thailand. Capital spending will also be directed towards existing assets throughout the world to improve oil and gas recovery, and reduce natural field decline.

Marathon buys into Eagle Ford Shale Marathon Oil Corp. has completed an agreement with Denali Oil & Gas for entry into the Eagle Ford Shale formation in Wilson and Atascosa counties, Texas. Marathon will pay Denali $10 million as well as drill and complete four wells to earn approximately 17,000 net acres with the option to purchase Denali’s remaining 58,000 net acres in the play in the two counties. If executed, the full 75,000 net acres, including the initial payment, carried well interest and lease extensions, will cost approximately $2,800 per acre or roughly



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Industry Briefs $209 million. If Marathon does not exercise its purchase option, Denali has the option to sell the remaining 58,000 acres to Marathon. Total cost under this option, including the initial payment, carried well interest and lease extensions, would be $92 million or approximately $1,225 per acre. This agreement covers all of Denali’s acreage in Wilson and Atascosa counties but excludes Denali’s 25,000 acres in Gonzales and Fayette counties.

for production through December 2013 at a NYMEX-equivalent price of $7.21 per MMbtu. Closing consideration included $93 million of cash and the assumption of $25 million of subordinated debt due 2013. Antero also issued roughly 3.8 million units in the transaction.

contemplates 22 operated drilling rigs running in the Haynesville Shale play, split between north Louisiana (15 rigs) and the Shelby Trough area (7 rigs) in east Texas, 4 rigs drilling in the company’s Appalachian JV, and 2 rigs drilling in the Permian. The Haynesville drilling program is expected to satisfy the company’s lease GlobaLogix opens obligations during 2011. No detailed Barnett operations center production guidance is given but GlobaLogix, a Houston-based oilfield the company cites a 40% production control and automation company, growth target. has opened a new operations center ATP enters second round of in Aledo, Texas to support oil and Calfrac sets 2011 capex Titan-related financing gas producers operating within the Calfrac Well Services Ltd. has set its ATP Oil & Gas has entered the Barnett shale play. The new location 2011 capital budget at $280 million. second round of financing related to will enable GlobaLogix to provide The capital program will focus on the ATP Titan in the amount of $100 SCADA, network design, system further bolstering Calfrac’s fracturing, million. As noted in a research report engineering, PLC integration and coiled tubing and cementing capacity, by Global Hunter Securities LLC programming, equipment installation infrastructure and logistical capabilidated December 7, 2010, the comand support services to various shale ties as it continues to expand its prespany has now borrowed $250 million projects in the area. GlobaLogix has ence in the emerging North American of the $350 million term loan facility. satellite offices in Pinedale, Wyoming; unconventional oil and gas markets. The first installment of $150 million Denver, Colorado; Canonsburg, was made in September. The facility Pennsylvania; and Fairfield, McCook Dune signs credit facility is secured by the company’s floating and Carthage, Texas. Dune Energy Inc. has replaced its production facility at the Telemark $40 million revolving credit facilHub, the ATP Titan. Funding is American Standard adds ity with Wells Fargo Capital Finance provided by Beal Bank Nevada, an Bakken, Three Forks acreage LLC with a new $40 million term affiliate of CLG Energy Finance. American Standard Energy Corp. loan facility from Wayzata Opportunihas executed a Purchase Agreement ties Fund II LP. The new facility will Antero acquires Bluestone, to acquire additional Bakken and mature on March 15, 2012. Major adds Marcellus acreage Three Forks acreage including partial terms of the new facility are that Antero Resources has acquired priinterest in 26 additional gross wells, Wells Fargo Capital Finance LLC will vately held Bluestone Energy Partof which 15 are currently producing, remain agent for the facility, the $8.5 ners. The Bluestone assets include 10 completing and one drilling. The million of standby Letters of Credit producing properties with 19 MMcfd additional 367 plus net mineral acres for P&A bonds will now be cash of gross operated production (13 acquired in the transaction are located collateralized through the bonding MMcfd net including non-operated within the Williston Basin of North agent, the June 2011 bond interest production) from 93 operated vertiDakota. The newly acquired wells payment of $15.75 million will be cal and 3 operated horizontal wells, have a current production sum of held in escrow until due. The primary gathering and compression assets and nearly 2,900 boe/d. The completed negative covenant of the term loan is approximately 40,000 net acres in the acquisition brings American Stanthat the total present value of future Marcellus Shale play in West Virdard’s Bakken footprint to over 6,000 net revenues discounted at 10%, or ginia and Pennsylvania. Roughly 96% net acres. PV-10%, of the proved developed of the leasehold is located in West reserves must be greater than two (2) EXCO sets $976 million Virginia and 54% is held by productimes the value of the face amount of tion. Antero expects to add nearly 20 budget for 2011 the term loan. The mid-year, June 30, EXCO Resources plans to spend bcfe of proved developed producing 2010 unaudited internally prepared reserves by year-end 2010 as a result. $768.9 million on drilling and reserve report PV-10 using SEC price The assets also include 11 bcf net of completions in 2011 as part of a assumptions was $149.9 million or index fixed price natural gas hedges $976.2 million total budget. The plan 3.7 times the value of the revolver. January 2011 Oil & Gas Financial Journal • www.ogfj.com

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Energy Players GTI mourns passing of Bernie Lee Dr. Bernard S. “Bernie” Lee, former president and CEO of the Institute of Gas Technology (IGT), now referred to as Gas Technology Institite (GTI), passed away on November 7, 2010. He joined IGT in 1965 and was responsible for the development of various synthetic fuels programs involving coal, oil shale, and liquid hydrocarbons. A recognized authority on energy, in particular fossil fuel conversion technologies, Dr. Lee became president of IGT in 1978. In 1984, he was the recipient of the American Gas Association (AGA) Gas Industry Research Award, and in 1998 he was honored with AGA’s Distinguished Service Award. Dr. Lee was a strong leader in the international liquefied natural gas community and played an active role in organizing the International Conference & Exhibition on Liquefied Natural Gas series as a member of the steering committees and as chairman. In addition, he provided frequent testimony to Congress on energy issues. He retired in 1999 after serving as IGT’s president and CEO for 21 years, but continued to be involved, serving as an energy advisor in Malaysia and China. During the past four years, Dr. Lee had been actively promoting the development of massive electricity storage (MES) to the renewable energy industries (solar and wind) and the scientific research community. Together with David Gushee, he published several papers on the subject and coined the phrase “MES”. He served on IGT’s Board of Trustees and Executive Committee and on several other industry boards. He received his bachelor’s degree and doctorate in chemical engineering from the Polytechnic Institute of Brooklyn.

Lindsay named executive VP, International Drilling Co. Lindsay COO of Helmerich & Payne earned a bachelor’s degree from the Helmerich & Payne Inc. has named John Lindsay executive vice president and chief operating officer. Lindsay joined the company in 1987 as a drilling engineer. He Lindsay has since served in various positions including operations manager for the company’s MidContinent region and vice president, US Land Operations, for Helmerich & Payne International Drilling Co. In 2006, he was appointed executive vice president, US and International Operations for Helmerich & Payne 62

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University of Tulsa.

Questar CFO Craven to retire; Hadlock named executive VP, CFO Martin Craven, vice president and CFO of Questar Corp. has elected to retire, effective March 1, 2011, after 20 years with the company. Kevin W. Hadlock has been named executive vice president and succeed Craven as CFO, effective January 1, 2011. Craven began his career at Questar in 1990 in the treasury department, after 12 years with other energy companies. Hadlock comes to Questar after six years with Baltimore

Gas & Electric (BGE) and its parent company, Constellation Energy. He was named senior vice president and CFO of BGE after serving as Constellation Energy’s vice president of investor relations and financial planning and analysis. Hadlock earned a bachelor’s degree from Brigham Young University and an MBA from Northwestern University’s Kellogg School of Management.

Apache makes corporate leadership changes Apache Corp. has made changes in the leadership of its corporate and financial teams. Thomas P. Chambers, vice president of Planning and Investor Relations, has Chambers been promoted to executive vice president and CFO. Matthew W. Dundrea, vice president and treasurer, has been promoted to senior vice president, Treasury and Admin- Dundrea istration. Robert J. Dye, vice president – Corporate Services, has been promoted to senior vice president – Global Communications and Corporate Affairs. Rebecca A. Dye Hoyt, vice president and controller, has been promoted to vice president, chief accounting officer, and controller with added responsibility for the Corporate Land Administration group in addition to Apache’s worldwide accounting organization. Rod Gryder, director of Internal Audit, has been promoted to vice president – Audit. Alfonso Leon, director of strategic planning, has been promoted to vice president –Planning, Strategy and Investor Relations. Chambers joined Apache in 1995 as director of Corporate



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Energy Players Planning and was named vice president – Corporate Planning in 2001. He earned his bachelor’s degree from the University of Notre Dame.

Continental Resources appoints Eissenstat senior VP, chief legal officer Continental Resources Inc. has appointed Eric S. Eissenstat to head the company’s legal team. Eissenstat, a former director of the Fellers Snider law firm in Oklahoma Eissenstat City, will serve as senior vice president and chief legal officer. Eissenstat joins Continental with 27 years of experience in complex business and commercial matters involving oil and gas, antitrust, business torts, computer law, shareholder suits, class actions, insurance, trade regulation, contract, corporate disputes, employment-related disputes, intellectual property and commercial arbitration. He earned his bachelor’s degree with honors from Oklahoma State University and his JD with honors and Order of the Coif from the University of Oklahoma.

Hassen to chair global oil, gas banking at Macquarie Capital Macquarie Group has named Thomas E. Hassen chairman of Global Oil and Gas Banking for Macquarie Capital. Hassen has over 30 years of expeHassen rience in investment banking, specializing in the energy sector. Previously, Hassen was vice chairman of the Global Industries Group and also a senior managing director in the Global Energy Group at Bear Stearns. From 1998 to 2005 he was co-chairman and co-head of the Global Energy Group at Credit Suisse and, prior to 64

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that, spent 20 years at Morgan Stanley, where he was managing director and co-head of their Global Energy Group. Most recently he was vice chairman of Irving Place Capital, a New York-based private equity firm. Hassen joins the firm’s New York office.

He was promoted to Global Supply Chain & Manufacturing leader in December 2008. Way holds a master’s in engineering from the University of Wales College in the United Kingdom.

Peak Well Services names Avern chief executive

Kelly D. Kerr, vice president finance and CFO of MegaWest Energy Corp., resigned from the company November 26, 2010.

Specialist downhole tool provider, Peak Well Services, has appointed Nigel Avern as chief executive. Avern joins Peak after a 17-year career with Expro where he man- Avern aged various divisions of the global business, notably as region director for Asia and president of South America. Latterly he was an executive officer responsible for product lines and managing director for the company’s Connectors & Measurements business. He will initially be based between the company’s two main offices, in the UK (Aberdeen) and Australia (Perth). He will also sit on the company’s board of directors.

GE Oil & Gas names Way VP, services Andrew Way has been appointed vice president of services for GE Oil & Gas, a business within GE Energy. In this role, Way is responsible for leading continued growth of the business’ equipment repair, maintenance, upgrade and remote monitoring, and diagnostics capabilities across all segments of the oil and gas industry. Way started his GE career in 1996. He held roles of increasing responsibility in Aircraft Engines and Engine Services, before moving to Equipment Services in 2001 where he was promoted to CEO of GE Equipment Services UK. In October 2007, Way joined the GE Oil & Gas business as the Global Services operations leader.

Kerr resigns from MegaWest CFO post

Dril-Quip co-chairman to step down as co-CEO Larry E. Reimert, co-chairman and co-CEO of Dril-Quip Inc., stepped down from his duties as co-CEO effective January 1, 2011, in order to concentrate on his cancer-related health issues. Reimert will retain his duties as co-chairman and will act as technical and strategic advisor for the company on a part time basis. J. Mike Walker, co-chairman and co-CEO, will assume Reimert’s CEO responsibilities and the company’s various departmental vice presidents will assume Reimert’s other day to day responsibilities.

Venoco hires McLaughlin as VP Edward McLaughlin will join Venoco Inc. as vice president of corporate development. McLaughlin served as president of Petro-Canada Resources (USA) from 2007 until the sale of the company’s assets in 2010. He originally joined the company in 2003 as VP - Land & Business Development. Prior to that, he was VP - Land & Business Development for Ensign Oil & Gas Inc., was director of business development for Encana Oil & Gas (USA) and VP - Land for Ocean Energy Resources (formerly UMC Petroleum Corp. & General Atlantic Resources). He holds a BBA from the University of Denver and an MBA from the University of Colorado, Denver.



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cont’d from p.18

along the Gulf Coast – was formed in September by Quantum Resources Funds. The partnership raised $300 million in its December 16 IPO, offering 15 million shares at a price of $20 per share with the underwriting help of Wells Fargo, JP Morgan Chase, and Raymond James Financial.

Investor consideration One attractive piece of the puzzle is the opportunity to make up for the hit many investors took during the recession. Many are looking for vehicles to help recoup losses. Treasuries are sitting near 3%, utilities are hovering around 4%, midstream MLPs are averaging a yield of 5% to 6%, while upstream MLPs are coming in closer to 7% to 9%. From a macroeconomic standpoint, those yield numbers, coupled with concerns regarding the direction of the US dollar and speculation of a coming inflationary phase, are enticing. Encore’s current yield is 9.4% versus the group mean of 7.9% (not including Constellation which suspended its distribution on June 26, 2009 and has yet to reinstate). ENP’s premium yield to the group can be attributed to its variable distribution policy. The policy produces a more volatile cash flow stream, which investors discount at a higher rate. “EVEP has generated production and proved reserves growth for its unitholders on a per unit basis, resulting in quarterly per unit cash distribution growth of 90% and, for those who have held units since the IPO, a compound annual rate of return of 27% based on quarterly cash distributions plus unit price appreciation,” noted EVEP’s Walker. But there is a flipside. “The riskier nature of the E&P business is reflected in E&P MLP yields, an indication of the risk associated with an MLP. The riskier the business, the higher the yield demanded by its unitholders, typically,” noted Tudor Pickering analyst O’Leary. Take for example, O’Leary said, E&P MLPs currently trading at ~8% average yield versus natural gas pipeline MLPs at ~6%. In late 2008/early 2009 (the stock market had tanked and capital markets had closed up), the yield spread between natural gas pipeline MLP (least risky) and E&P MLP yields expanded significantly with the pipeline guys reaching average yield of approximately 10% while the E&P MLPs had an average yield above 30% during the same time period – an indication of which type of business is riskier under the MLP structure.”

Company consideration The elimination of double taxation effectively lowers the partnership’s cost of capital, thus enhancing the partnership’s competitive position when in pursuit of expansion projects and acquisitions. Like any project, risks must be

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considered carefully. The most obvious risk is commodity price volatility. “E&P companies don’t really fit the typical MLP mold because their operations/cash flows are very commodity sensitive – you can only hedge your production so far out into the future. Fluctuations in oil and/or gas price can significantly affect distributable cash flow. An MLP not being to cover its distribution is no good,” warned O’Leary. Alan Smith, CEO of QR Energy said: “For an upstream MLP to be successful, it must have long-lived, lower decline assets and be able to provide stable cash flows through an ongoing, long term hedging program,” noting that QR Energy’s assets are “well-suited for an MLP and include low-risk development opportunities.” That strategy is echoed by EVEP’s Walker. “Today’s upstream MLP’s hold primarily mature, long-lived producing assets with low production decline rates. They also have commodity price hedges for a significant amount of their production for three to five years into the future, which helps to reduce commodity price risk and volatility in expected future distributable cash flow.” Other factors to consider, as noted by Vanguard’s Smith, are the company’s ability to grow and access capital markets. “In a market where property transactions are plentiful and the capital markets are accessible, growth can be achieved quickly,” he said. Growth For Vanguard, growth has been steady. According to Smith, over the last 18 months, the company has acquired over $200 million in assets and conducted three successful equity offerings. Companies can grow through the drillbit or through acquisitions. The M&A market is heating up, opening up opportunities for growth – even shale comes into play. LINN Energy has grown through the drillbit. In early December, the company announced a $480 million capex budget for 2011 consisting of two components: high rate-of-return liquids-focused drilling in the Granite Wash and Permian Basin Wolfberry trend and low-risk, low-cost projects. The capital program calls for drilling 45 horizontal Granite Wash wells (35 operated) and more than 130 Wolfberry wells in the Permian Basin. The company expects to drill more than 220 wells and complete more than 380 workover, recompletion, and optimization projects during the year. “LINN’s exceptional performance in 2010 enabled us to increase our distribution by 5% and deliver a year-todate return to unitholders of more than 40%,” said Mark E. Ellis, LINN’s president and CEO in a company press release. “We estimate production to grow more than 35% in 2011.” In early September, LINN Energy signed three agreements to acquire properties in the Wolfberry trend of the


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Permian Basin for a combined price of $352.2 million. Legacy Reserves LP also snapped up additional Permian Basin assets in 2010. On December 22, the limited partnership closed on its $103.3 million acquisition of Permian properties from Concho Resources Inc. The properties produce an estimated 1,419 boe/d, of which 47% is oil. Proved reserves are estimated to be 5.8 MMboe, 88% of which are considered proved developed producing. The Concho acquisition was on the heels of another Permian Basin addition that also closed December 22 for $1.4 million in cash. The Lea County, NM oil well produces roughly 17 boe/d, 86% of which is oil. Proved developed producing reserves are estimated to be 54,000 boe. Prior to that, in November, Legacy closed a $6.6 million acquisition of Powder River Basin oil assets with net production of 82 b/d with proved developed producing reserves of 300,000 barrels of oil. The acquisition was funded with its existing credit facility. In a company press release, Steven H. Pruett, Legacy president and CFO, noted that the company continues to be active in the acquisition arena, allowing the company to increase production volumes and cash flow, all the while drilling its Wolfberry locations near Midland. Drilling in an MLP, said EVEP’s Walker, should be used primarily to maintain or slightly increase production. The majority of growth in such vehicles comes from accretive acquisitions of MLP-appropriate producing oil and gas assets. EVEP and EnerVest Ltd., the controlling entity of EVEP’s general partner, have large teams devoted to acquisitions. “The experience of these teams, and EnerVest’s 18-year track record of success in the acquisition market, are key in having an aggressive but disciplined effort in acquiring oil and gas assets at attractive rates of return,” noted Walker. In late September, the company closed on the acquisition of properties in the Mid-Continent region from Petrohawk Energy Corp. for $119.9 million. In August, EVEP completed a public offering of 3.45 million common units, raising net proceeds of $114 million in anticipation of closing the acquisition. Just before year-end 2010, the company closed on the acquisition of Barnett Shale assets from Talon Oil & Gas LLC. EVEP acquired a 31.02% interest in the assets for $295.9 million. EVEP’s outstanding debt after funding the acquisition stood at roughly $619 million on a revised borrowing base of $700 million. As these transactions show, there appears to be no shortage of assets up for grabs. A December 21 research note from Robert W. Baird & Co. put M&A opportunities at roughly $250 billion. MLPs stand to benefit as traditional independents shed conventional proved reserves – unsexy from a growth standpoint to the traditional independents – to finance 66

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shale growth. MLPs, as owners of low-decline, proved assets, are natural buyers of those conventional assets. “There are a lot of factors to consider, but I think that rising oil prices and independents needing money to finance shale growth set you up for more M&A possibilities for the MLPs, and for the potential creation of more MLPs on an outright basis,” noted Robert W. Baird analyst Ethan Bellamy. And, over time, as shale plays begin to mature, another realm of M&A opportunities come into play. In as little as five years after a well is drilled, shale assets may be deemed MLP-suitable. The earliest Barnett wells may already be MLP-suitable from a year-over-year decline standpoint. With the amount of money being poured into creating shale assets now, the potential for expansion of MLP-suitable assets looms large in the coming years. So, while acquisitions are key to the growth of upstream MLPs, one must exercise caution. Overextending financial resources by growing too aggressively can leave companies with liquidity problems or difficulty obtaining additional financing. Capital markets MLPs are reliant on access to capital markets because the companies essentially pay out all cash flow after expenses. To grow, the upstream MLPs need continual access to the capital markets. “If the capital markets aren’t available and MLPsuitable assets aren’t available at reasonable valuations, it could cause long term cash flow issues if production can’t be maintained,” warned Vanguard’s Smith. As it stands now, conditions seem favorable. When asked about the feasibility of getting upstream MLPs financed in the current climate, Kyle Hranicky, head of the Wells Fargo Energy Group, commented: “The debt markets, including both bank and public high yield, for upstream MLPs have rebounded nicely over the last year.” Hranicky cited examples of recent financings including: • BreitBurn Energy Partners, which closed an amended and extended $735 million borrowing base bank credit facility in May 2010 as well as issued $305 million in senior notes (as a first time issuer) in October 2010, and • LINN Energy, which closed an amended and extended $1.375 billion borrowing base bank credit facility in April 2010 as well as issued $1.3 billion in senior notes in April 2010.

Conclusion Are we poised to see the next phase of upstream MLP activity – activity that was stalled with the onslaught of the economic crisis, or will upstream companies find reliability of revenue and commodity price volatility issues too big a burden to bear? Time will tell. OGFJ



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Companies 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

Company/Advertiser Index PAGE

COMPANY

PAGE

Amegy Bank

63

Empresa Nacional de Hidrocarbonetos

14

Logical Information Machines

American Gas Association

62

Encana Oil & Gas

64

Macquarie Group Ltd.

American Standard Energy Corp.

61

EnCap Investments LP

Anadarko Petroleum Corp.

12

Encore Acquisition Corp.

17

Marubeni

Anschutz Exploration

50

Encore Energy Partners LP

17

Mayer Brown LLP

Antero Resources

61


50

MegaWest Energy

EnerCom Inc.

25

Mercatus Energy Advisors

Apache Corp.

13,17,60,62

F

48,51

7 43,64

Marathon Oil Corp.

42,60

COMPANY

PAGE

RAAM Global Energy

60

Ralph E. Davis & Associates Inc. 10 Ratio Oil Exploration

15

12

Raymond James & Associates

26

28

Raymond James Financial

65

64

Reliance Industries

26

Rhone Capital

49

6

Asset Risk Management

35

Energen Corp.

60

Merit Energy Co.

50

Rio Tinto

12

Atlas Energy Inc.

60

Energen Resources Corp.

60

Mewbourne Oil Co.

50

Robert W. Baird & Co.

18

ATP Oil & Gas

61

Energy Capital Solutions LP

48

Mitsui E&P Mozambique

14

Rodman & Renshaw

46

Avista Capital Partners

48

Energy Information Administration

Morgan Stanley

64

Rodman Energy Group

3

Avner Oil Exploration

15

Energy XXI

NAPE Expo LP

45

Baltimore Gas & Electric

62

Enertia Software

Beal Bank Nevada

61

EnerVest Ltd.

Bear Sterns

64

EnerVest Management Partners Ltd.

BHP Billiton

12

Black Elk Energy

60

Bloomberg

18

EOG Resources Inc.

BlueRock Energy Capital

27

EV Energy Partners LP

17

North Dakota Department of Mineral Resources

61

EXCO Resources

61

NuTech Energy Alliance

Expro

64

NYMEX

Bluestone Energy Partners BP

5,12,34,46

26,30 29 IFC,38 17,48

Samson Lone Star LP

50

National Association of Publicly Traded Partnerships 16

Samson Oil and Gas Ltd.

42

National Hydrocarbons Commission

SandRidge Energy Inc.

60

Sapient Global Markets

6

Natural Gas Partners

Ensign Oil & Gas Inc.

64

NGP Capital Resources

37

Sasol Ltd.

Enterprise Products Partners

17

Noble Energy Inc.

15

Securities and Exchange Commission

17,61

Shell

24,47

42,50

14

ExxonMobil

BreitBurn Energy Partners LP

17

FactSet Research Systems Inc.

16

Occidental Petroleum

5,26,46

12,17

49,BC

Noble Royalties Inc.

BPRL Ventures Mozambique Bridas Corp.

30

23

NYSE

IBC 42

Shengkai Innovations Inc.

59

Sinopec

9,61 15 5,26,47

14

60 5,26,47

SM Energy

50

Statoil

12,50

Talisman Energy

14,50 51,66

Fellers Snider

64

Ocean Energy Resources

64

Talon Oil & Gas LLC

Brigham Exploration Co.

42

First Reserve Corp.

48

OGN Group

60

Teach For America

68

Cadent Energy Partners

48

Gardere Wynne Sewell LLP

17

OpenLink Financial

10

TELACU Education Foundation

68

Calfrac Well Services Ltd.

61

Gas Technology Institute

62

P2 Energy Solutions

31

Tiger Woods Foundation

68

CanaccordAdams

GasRock Capital LLC

48

Pan American Energy

Chesapeake Energy

5,8,14,50

8

GE Oil & Gas

64

PDC Energy

60

Tudor, Pickering, Holt & Co. Securities Inc.

16

Chevron Corp.

12,60,68

Global Hunter Securities

60

Peak Well Services

64

Union Bank

21

61

Pemex

28

Unocal Corp.

Chief Oil & Gas

51

GlobaLogix

Cimarex

17

Goldman, Sachs & Co.

15

PennWell Corp.


50

Halliburton Energy Services

19

MAPSearch

Citizens for Affordable Energy

24

Harwood Capital Inc.

33

Petro-Canada Resources

CLG Energy Finance

61

Helmerich & Payne Inc.

62

PetroChina

CLM Matrix

34

Hess Corp.

CNOOC Ltd.

4,14,26,46

Concho Resources Inc.

66

42,60

Petrohawk Energy Corp.

Hilcorp Energy Co.

50

Pioneer Natural Resources Co.

Houston American Energy Corp.

50

Pioneer Southwest Energy Partners LP

50

Plains All-American Plains Exploration & Production Co.

Constellation Energy Partners LP

18,62

IHS Herold Inc.

Continental Resources Inc.

42,64

Irving Place Capital

64

14

Jefferies & Co. Inc.

15,51

PLS Inc.

Cove Energy Mozambique Rovuma Offshore Ltd. Credit Suisse

12,64

5,26,46

TRZ Energy LLC

44,60

5

US Department of Energy

26

41

US Geological Service

42

64

Vanguard Natural Resources LLC

18

Venoco Inc.

64

Videocon Mozambique Rovuma

14

5,26 17 17,26

Warburg Pincus

49

17

Wayzata Opportunities Fund II LP

61

47

Wells Fargo

50

Western Gas Resources

12

Western National Bank

39

9,11,13,15

61,65

JP Morgan Chase

65

Potash Corp.

12

Whiting Oil & Gas Inc.

42

Dan A. Hughes Co.

50

Kayne Anderson Capital Advisors

49

Project Lead the Way

68

Williams Companies

44

Delek Drilling

15

Kerr-McGee

12

QR Energy

18

Williston Basin/Mid-North America Stock Fund

42

Denali Oil & Gas

60

Kinder Morgan

16

Quantum Energy Partners

49

Wood Mackenzie

26

Denbury Natural Resources

18

KinderHawk

22

Quantum Resources Funds

65

Woodside Petroleum

DonorsChoose.org

68

Legacy Reserves LP

17

Questar Corp.

62

XTO Energy

Dril-Quip

64

Lime Rock Partners

49

Quicksilver Resources

18


50

Dune Energy Inc.

61

LINN Energy

17

Quorum Business Solutions Inc. 50-57

Zoom Technologies

60

12 12,17


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Beyond the Well

Chevron donates $530K for eagles scored at Chevron World Challenge tion partners for every eagle scored. single solution to improving eduThe donation amount increased cation in California, the Chevron each day. Eagles earned $15,000 on World Challenge nonprofit partnerMikaila Adams ships reflect a variety of educational Associate Editor – OGFJ Thursday, December 2, jumped to $25,000 on Friday, December 3, approaches: doubled to $50,000 on Saturday, DonorsChoose.org uses the power December 4, and doubled again to of the Internet to direct millions of il giant Chevron Corp., in $100,000 for the final day of the dollars in contributions from individits third year as title sponsor, tournament on Sunday, December 5. uals to fund classroom projects across recently saw The Chevron A total of 13 eagles and one the country. Project Lead the Way World Challenge wrap up its 12th double eagle were scored during the engages students in science, technolyear of bringing together some of tournament for a total Eagles For ogy, engineering, and mathematics golf’s finest players in a tournament Education donation of $530,000. (STEM) fields through its rigorous, benefitting various educationhands-on curriculum that fosfocused nonprofits. ters in students a love of learnThe offseason tournament, ing and a passion for solving a PGA TOUR co-sponsored our world’s challenges. Teach event and part of the Official For America is the national World Golf Ranking, is hosted corps of top college graduates by Tiger Woods at the Jack and professionals who commit Nicklaus-designed Sherwood to teach for two years in urban Country Club gold course in and rural public school and Thousand Oaks, California. become lifelong leaders in the The 72-hole, regulation-play effort to expand educational event features an elite field of opportunity. TELACU Edu18 PGA Tour players competcation Foundation prepares Eagles for Education scoreboard – Day one of the Cheving for a $5 million purse. Latino students for academic ron World Challenge. Photo courtesy of Chevron Corp. This year, US Open champion success in underserved comGraeme McDowell, who came in secNotable results include overall eagle munities throughout Los Angeles ond in the Chevron World Challenge leader Paul Casey with three eagles, County. Tiger Woods Foundation is a behind Jim Furyk last year, managed a and Bubba Watson with the tournaglobal organization focused on reachfour-shot comeback including two long ment’s lone double eagle on the 16th ing young people through innovative birdie putts on No. 18 to defeat Tiger hole on Friday. Anthony Kim and education facilities, original curricula, Woods, a four time tournament winner. Sean O’Hair eagled twice. McDowell, grants and college scholarships. For his win, McDowell claimed $1.2 the tournament’s winner, shot one “The Chevron World Challenge million and moved up to No. 7 in the eagle as did tournament runner-up brings together some of the world’s Official World Golf Ranking. Woods. Others to eagle were Dustin best golfers while supporting innovaIn addition to bringing together Johnson, Rory McIlroy, Ian Poulter, tive education programs in Califorsome of the world’s best golfers, the and Nick Watney. nia,” said Rhonda I. Zygocki, vice tournament brings together educaNonprofit partners participating in president of Policy, Government and tion-focused nonprofit partners. The 2010 Chevron World Challenge Public Affairs for Chevron Corp. New to the tournament this year included DonorsChoose.org, Project “Eagles for Education has provided was Chevron’s Eagles For Education. Lead the Way, Teach For America, an exciting platform for Chevron to Throughout the four days of tourna- TELACU Education Foundation increase its support for our nonprofit ment play, Chevron donated $15,000 and the Tiger Woods Foundation. partners throughout the tournato the tournament’s nonprofit educa- Supporting the belief that there is no ment.” OGFJ

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No one values the energy of America like we do.

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INVESTI NGPARTNER B U I L D I NGPARTNER PLANNI NGPARTNER A DV I S I NGPARTNER FINANCI NGPARTNER

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