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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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From the best map data to software that maximizes the value of your spend and keeps you in compliance, P2 Energy Solutions has the right package to fit your company, large or small.
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March 2011
®
Will Michael Bromwich
reopen the GOM to deepwater drilling?
INSIDE • • • •
Contents
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Assessing CapEx risks Shale gas: a global game changer Commercializing new technology Insurance lessons from deepwater
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___________________________________________
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CONTENTS V8/#3
FEATURES
✱
ON THE COVER: Michael Bromwich, director of the Bureau of Ocean Energy Management, Regulation and Enforcement. ©2011 Michael Stravato. Provided courtesy of the James A. Baker III Institute for Public Policy, Rice University.
12
COVER STORY: Gulf of Mexico While the debate continues over safety and risk mitigation issues in the Gulf of Mexico, some participants have grown weary of the uncertainty and are preparing to exit the Gulf for friendlier waters in other parts of the globe. OGFJ editor Don Stowers gathers details and insight from various industry participants, including BOEMRE director Michael Bromwich.
20 Shale impact Shale gas use has grown from near zero to roughly 20% of the US gas stream. Many changes are likely to result from its development. Mayer Brown’s Dallas Parker outlines changes that reflect the economic impact of shale gas on global politics and energy policies.
24 Insurance lessons The Deepwater Horizon incident
and the drilling moratorium put the spotlight on many things, including insurance as a critical resource. Insurance issues should be considered early and often, as policyholders have arguments to overcome popular insurer efforts to avoid coverage. Linda Kornfeld and Selena Linde of Dickstein Shapiro say to consider the damage at issue,
and review policy terms to determine which coverage issues may arise and which arguments will be the most effective.
that considers both CapEx and Operations Risks and their impact on NPV.
can’t afford to relearn the same lessons.
28 Assessing risk
32 Avoid losing $ on ETRM An ETRM implementation is an expensive deployment of missioncritical software with countless challenges. Sapient’s Larry Hickey discusses some key lessons learned from implementations. In this environment, you
The sun provides more energy to the earth’s surface in one hour than mankind uses in a year. But much work remains to be done to turn solar power into liquid transportation fuels. Joseph Gallehugh talks to Dr. Jim Trainham of the Research Triangle Solar
Energy sector opportunities abound, but many are capital intensive and carry significant CapEx risks. Richard Westney of Westney Consulting Group discusses ways to assess NPV
36 Solar fuel’s impact
Fuels Institute for an idea of how this new energy direction could impact the oil and gas industry.
39 Utica Shale Lying below the Marcellus Shale in some areas, the lesser-known Utica Shale may contain more than 20 tcf of natural gas. The mineralogy differs from the Marcellus, but with challenges come opportunities.
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.
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DEPARTMENTS [Editor’s Comment]
5 Middle East unrest Conflicts in the Middle East are a contributing factor in the run-up in crude oil prices. Libya alone may not cause much instability, but if protests continue to spread, prices could spike. Prodemocracy movements in some countries may inadvertently cause people to suffer in others. OGFJ editor Don Stowers runs down the list of some of the players and countries who could be caught in the middle. [Capital Perspectives]
6 Commercializing energy tech Technology will play an ever increasing role in meeting technical challenges and complex economic conditions in the oil industry. Jessica Rouse of OTM
Consulting details the participation of Oiltech at the Energy Technology Capital Conf. and its thoughts on how to commercialize new technology. [Upstream News]
10 Enlarging Ensco Two of the industry’s most well-known offshore drilling companies, Ensco plc and Pride Int’l, have agreed to merge. The combined company holds an estimated enterprise value of $16B and a revenue backlog near $10B.
47 Co./Ad Index
40 Deal Monitor
[Beyond the Well]
48 Teach For America
42 Industry Briefs 44 Energy Players
ExxonMobil has donated $500,000 to Teach For America programs to help recruit, train, and support science and math educators.
OGFJ.com▶ ___________________________________
FACILITIES AND INFRASTRUCTURE MAPS In collaboration with PennWell’s MAPSeach 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.
LEGALLY SPEAKING Energy attorney Aaron Ball continues as a guest blogger for OGFJ.com. Read recent posts on the risky and profitable business of investing in spin-off companies, the likelihood of tax hikes on the industry, as well as details about Iraqi oil production shortfalls as land mines and other issues hinder development. Join the discussion and post your comments today!
FEATURED STORIES Updated daily, OGFJ.com brings you the latest information from the industry. Get details on the recent addition of Marcellus Shale acreage by the Gastar Exploration/Antrim joint venture, the recent study showing $3B in revenue generation by the Eagle Ford Shale in 2010, and the $2.85B merger transaction between Holly and Frontier creating one of the largest US refiners. Find information on recent executive moves at Apache, Babst Calland, Northern Offshore, and more. 2
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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.
www.ogfj.com • Oil & Gas Financial Journal March 2011
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When it comes to treasury management, our expertise runs deep.
With all of the elements involved in the oil and gas industry, it’s important to have an experienced financial partner that knows the terrain. For over twenty years, Union Bank® has put its vast reserves of lending and banking expertise to work for some of the major players in the energy industry. By tapping into our award-winning treasury management services, we can help you streamline reporting for accurate response times. And our electronic settlement service lets you process payments and invoices remotely, helping you meet your monthly settlement deadlines. That’s one powerful combination working on your behalf.
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Energy Capital Services: Andrew Koch Vice President 214-922-4233
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©2011 Union Bank, N.A. Union Bank is a proud member of the Mitsubishi UFJ Financial Group (MUFG), one of the world’s largest financial organizations. Financing subject to credit and collateral approval. Other restrictions may apply. Terms and conditions subject to change. ________ unionbank.com
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Visit our Unconventional Resources Center on OGFJ.com
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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 include more than shale. They also include 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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Editor’s Comment
Middle East unrest causing instability in world oil markets Don Stowers Editor-OGFJ
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s we watch crude oil prices climb past the $100 mark and prices at the pump creep well past $3.00 a gallon, some of us are wondering what effect this will have on the economic recovery in the US and elsewhere and what it portends for the oil and gas industry as well. The consensus among those who earn a living making economic forecasts is that sustained high oil prices will have a negative impact on economic growth, and slow growth would not be good for the energy industry either. Of course higher prices generally mean bigger profits for oil companies, but continual high prices for months and months means that on the retail level consumers will start to adjust their habits, drive less, car-pool with neighbors, and think twice about that cross-country road trip. If the economy slows down again, demand will decline and oil prices will have to adjust to this new paradigm. In a nutshell, it means that, ideally, prices should be high enough for industry participants to make a nice profit, but should not be too high for too long. Excessively high prices are counterproductive. What is driving the current run-up in crude oil prices? The uncertainty caused by the conflicts in the Middle East is a significant factor. Prices seemed to rise almost overnight when Libya, the fourth-largest oil exporting nation in Africa, was forced to cut off an estimated 75% of its 1.7 million barrels per
day of production, 1.5 million barrels of which are exported, mostly to Europe. Think what might happen to oil prices if this were Saudi Arabia, the world’s largest oil exporter. The protests against the governments in Tunisia, Egypt, Bahrain, Jordan, Oman, Iran, and Libya and the ensuing violence in many of those countries not only has Middle East leaders worried, it has European and other countries concerned as well. The Europeans, Chinese, Japanese, and others who rely on oil imports from Middle Eastern countries are worried that oil supplies will be dramatically reduced or cut off entirely from countries that may be embroiled in a civil war. Quite a few international petroleum companies could be affected by the strife in Libya and potentially in other countries as well. There are currently 35 foreign oil and gas companies active in Libya, including leading NOCs and IOCs from every continent except Antarctica, according to UK-based Evaluate Energy, an energy research firm. Some of the most important foreign producers in Libya are ENI, OMV, RepsolYPF, ConocoPhillips, Hess, Marathon, Occidental, and Suncor. In addition, there is a second tier of companies that are producing, but on a smaller scale. These include Statoil, GDF Suez, Total, Wintershall, and Gazprom. Shell, RWE-DEA, and Australia’s Woodside Petroleum also have a presence. “Although there may be short-term mayhem, Libyan oil and gas prospects may improve in the medium term as a result of structural changes that take place now,” said Evaluate Energy’s Dan Krijgsman. He added, “Libya may not be as strategically important to its trading partners as many other Arab oil and gas producers, but it is definitely now well connected to many countries and
companies worldwide, which makes the current disruptions a truly international, not local, issue.” Saudi Arabia seems to be immune from the unrest at the moment, but no one knows if that situation will change. On Feb. 23, the Saudi monarch promised $37 billion in benefits to low- and middle-income citizens, including funds to alleviate the country’s chronic housing shortage. He obviously hopes that taking this step will head off unrest and insulate the country from the current wave of uprisings. To address the decline in oil exports from Libya and elsewhere in the region, Saudi Arabia says it will increase its own production accordingly, although some industry observers doubt whether Riyadh has the excess capacity needed to ramp up production to this level. If the Saudis are unsuccessful in alleviating the oil export shortage, expect prices to continue to climb. Libya alone probably won’t cause too much instability in oil markets. However, if the protests continue to spread, possibly even outside the region, industry analysts are concerned that prices could spike to $125, $150, even $200 a barrel, depending on which countries may be affected by the strife. In Europe and the US, sustained high oil prices are likely to slow the pace of growth, and the already-high unemployment rates in some countries will rise. In emerging nations in Africa and Asia, including China and India, the impact of higher prices will be worse because it means food prices may climb beyond affordable levels. In short, the pro-democracy movements in some countries may inadvertently cause people to suffer in others. OGFJ Have an opinion about this? Visit www.ogfj.com to comment.
March 2011 Oil & Gas Financial Journal • www.ogfj.com
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Capital Perspectives
How to commercialize new technology Jessica Rouse, OTM Consulting, London
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f you’ve ever had an idea for a great new invention for the oil industry but wondered how to get the financial backing you need to produce and market it, you should have been in Houston on Feb. 9. If you had attended the Energy Technology Capital Conference (ETCC), you might have gotten answers to some of your questions about commercializing new energy technology. One group of influential investors representing the Oiltech Investment Network (Oiltech) participated in a panel discussion in which they presented the results of a technology commercialization study conducted among operators, oilfield service companies, investors, and innovators. Oiltech is a consortium of 10 global investors in upstream oil and gas technologies who joined together in 2010 to form the network. The key objective of Oiltech is to encourage entrepreneurship and maximize the quality of technology investment opportunities within the oil and gas sector. Members of Oiltech collectively have invested over $950 million in more than 70 oil and gas technology companies over the last five years. Oiltech members include Altira Group, Chevron Technology Ventures, Energy Capital Management, Energy Ventures, Epi-V, Investinor, Lime Rock Partners, SEP, Shoaibi Group, and Viking Venture. They are based in North America, Europe, and the Middle East. The network collaborated with the Houston Technology Center (HTC) to launch the first of many Oiltech events planned in the US. The ETCC was organized by HTC 6
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and attracted more than 250 delegates this year, including entrepreneurs seeking investment funding for more than 40 emerging technologies. Oiltech facilitated one-onone meetings between its investor members and companies seeking funding, providing an opportunity for companies to showcase their technologies and business plans, discuss their investment needs, and explore potential routes to market. One of the objectives of the network is to drive innovation by providing a platform to connect operator oil companies to innovative technology providers, and entrepreneurs to energy-focused investors. The network also ran an entrepreneurs’ advisory workshop in Aberdeen [Scotland] in October 2010 that connected 29 upstream oil and gas technology companies to Oiltech members. The event pro-
vided a platform for entrepreneurial companies to meet with investors to discuss their technology offering in the hope of securing funding. The network hoped to replicate the opportunity by collaborating with HTC at the Energy Technology Capital Conference in the US. OTM Consulting, an independent technology management consultancy in the upstream oil and gas sector, manages the Oiltech Investment Network. OTM recently completed the aforementioned technology commercialization study. The study analyzed case histories for more than 40 technologies, and participants were asked to assess key success factors that result in effective uptake of new technologies. The commercialization study findings were a springboard for discussions at the ETCC Oiltech lunchtime panel, which included
Oiltech Investment Network members at Energy Technology Capital Conference in Houston on Feb. 9. (L to R) Chris Dudgeon, Trevor Burgess, Leif Andre Skare, Dirk McDermott, David Malone, and John Hanten. Photo courtesy of Oiltech.
www.ogfj.com • Oil & Gas Financial Journal March 2011
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New Worlds. Source market intelligence and insight through the PLS M&A Database.*
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Aggressive buyers & sellers need information to guide their business decisions.
PLS’ M&A Database is cross-linked with various PLS reports and other data sets. The database includes not only corporate and asset deals, but also joint ventures, VPPs and acreage acquisitions.
At PLS, our firm offers a number of products and tools—including a comprehensive Mergers & Acquisitions Database to help clients steer a straight course.
The U.S. and Canada Database allows searching by conventional and unconventional transactions, while the Global Database has a unique calendar presentation. All three databases include a one button click-through to a relational database of “Deals in Play”— a unique extension of the PLS multiple listing service. This allows clients to gain a good sense of the current inventory of assets for sale.
The M&A Database provides buyers and sellers current market values and price comparables on oil and gas transactions on a reserve or production basis. PLS’ M&A Database offers a number of unique features including: source documents for every deal (press releases, investor presentations, PLS research and SEC filings), various quick looks, analyst comments, oil/gas equivalent ratio toggling ([6-1] up to [15-1]) and two-click downloads to Excel.
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Capital Perspectives five Oiltech members. The five ‘top scoring’ commercialization success factors identified in the study, were discussed by panel members. These success factors are: 1. Business need 2. Value articulation 3. Developer skills 4. Operator engagement – the developer of the technology engages with and understands the real needs of end-users 5. Operator involvement – the end-users of the technology are involved throughout the development and testing of the technology, and understand from an early stage the features and benefits of the new technology Chris Dudgeon, managing director of OTM Consulting, served as panel moderator. He commented, “The study was a great opportunity to understand the key drivers in the uptake of technology within the sector. Technology products associated with oil and gas often take a long time to be implemented, and we wanted to identify why this was and how we could accelerate this process.” The study indicated that new technologies should be seen as a solution to a clearly defined business need. Leif Andre Skare, partner at Energy Ventures in Houston, added, “We closely track customers to ensure we understand their drivers and needs. We also look closely at timing – to confirm that a product can realistically be launched by the time a customer needs it.” The value of the product to the end-user must be clearly articulated and measured, said Trevor Burgess of Lime Rock Partners. He explained, “No one will buy your product if you can’t explain the value it will bring. A major success factor for companies is to show how the product will save endusers money, increase production rates or reduce operational risks. 8
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Technology developers need to be specific – how does their product do this? They should define the market areas where their technology adds value, and quantify that value. They should also explain the potential risks, and how these can be mitigated.” Another key success factor is the need for sufficient skills to be available to develop the product or technology within the developer’s organization. “You can’t push a technology onto an organization; it needs to be pulled from within. The functionality of the product needs to justify the cost of introducing or replacing the existing technology,” said John Hanten, venture executive for Chevron Technology Ventures. A common pitfall for technology developers is misunderstanding the real needs of the end-user. Developers need to work closely with operators to offer solutions that really provide an answer to a problem that cannot be solved in any other way. David Malone, chief technology officer for Shoaibi Group commented, “A key factor to success is to develop a sponsor within an enduser who believes in your idea. This will help you to develop your technology so that it becomes a valued product. You can’t sell a technology, but you can sell a product.” The final point raised during the discussion was that end-users of the technology need to be involved throughout the development and testing stages. Operators (E&P companies) need to understand from the outset the features and benefits that the new technology will offer. Dirk McDermott, founder and managing partner of Altira Group, highlighted the importance of domain expertise and knowledge transfer between technology developers and investors.
“Over the past 12 years I have learned the value of expert people within a portfolio company. They can make or break an organization. We invest in people who are experienced in their profession, and this has added value over and over again. Private equity funding can bring many benefits – money, experience, access to advisors, and additional investors. However, it is important to ask the question, ‘Who do I want to partner with over the next 5 to 10 years?’ Great business plans don’t always proceed in the way we would hope, and so it is important to have the right investor partner engaged to guide you through the tough times and also celebrate your successes.” Technology will play an ever more significant role in meeting increasingly demanding technical challenges and complex economic conditions. Entrepreneurs and innovators are the key to these developments, and the growing levels of investment and commercialization expertise provided by members of the Oiltech Investment Network will be a key factor in realizing the potential of new technologies. Entrepreneurs wanting to connect with energy-focused investors, and end-users searching for innovative technology solutions should visit www.oiltechinvest.com to learn more. OGFJ About the author Jessica Rouse works for OTM Consulting and is manager of the Oiltech Investment Network. She has done extensive market analysis on emerging technologies for unconventional gas applications. She holds a bachelor’s degree in chemistry from Cardiff University and a PhD in materials science from the University of Southampton.
www.ogfj.com • Oil & Gas Financial Journal March 2011
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Upstream News BP looks to grow production offshore India with Reliance agreement
Chevron builds on drilling successes offshore Western Australia with new gas hit
I
ith its Orthrus-2 well, Chevron Corp. has hit gas in the Carnarvon Basin offshore Western Australia. The Orthrus-2 well is located in the WA-24-R permit area approximately 60 miles northwest of Barrow Island. The well was drilled to a total depth of 14,098 feet. Combining both appraisal and exploration objectives, the well encountered 243 feet of net gas pay, of which 102 feet of net gas pay was encountered in a deeper, previously unexplored target interval in the Orthrus field. George Kirkland, vice chairman, Chevron, said, “The find at Orthrus-2 represents our tenth offshore discovery in Australia within the past 18 months.” Chevron’s Australian subsidiary is the operator of WA-24-R and holds a 50% interest, while Mobil Australia Resources Co. Pty Ltd. holds 25%. Shell Development (Australia) Pty Ltd. and BP Exploration Alpha Ltd. each hold a 12.5% interest.
n its second major deal since the Gulf of Mexico oil spill, BP has agreed to acquire upstream assets offshore India from privately-held Reliance Industries Ltd. for US$7.2 billion. Completion of the transaction, subject to Indian regulatory approvals and other conditions, would result in BP taking a 30% stake in 23 oil and gas production sharing contracts covering 270,000 square kilometers that Reliance operates in India, including the producing KG D6 block. This block contains the D-1 and D-3 gas fields, which contain over 13tcf of proved and probable reserves. According to a Feb. 21 report by Jefferies & Co. Inc., these particular fields have been producing at a combined rate of 1.8 bcf/d in recent months, although production rates have fallen as reservoir complexity has restricted well deliverability. The fields were originally planned to peak at 2.8 bcf/d, and Jefferies speculates that restoring field output may be one reason Reliance agreed to partner with BP. A 50/50 joint venture would also be created to source and market gas in India as well as to accelerate the creation of infrastructure to handle the gas. BP will pay Reliance an aggregate consideration of US$7.2 billion, and completion adjustments, for the interests in the production sharing contracts. Jefferies & Co. translates the unit price for the proved and probable reserves near US$9.3/boe. The company is expected to pay the US$7.2 billion sequentially over 2011 out of cash reserves. Payments of up to US$1.8 billion could be shelled out by BP depending on further exploration success. Reliance will continue to serve as operator of the 23 oil and gas blocks that currently produce nearly 1.8 bcf of gas per day, over 30% of India’s total consumption, and over 40% of India’s total production. “India is one of the fastest growing economies in the world. By allying ourselves with Reliance, we will access the most prolific gas basin in India and secure a place in the fast growing Indian gas markets, creating a genuinely distinctive BP position,” said Robert Dudley, BP Group chief executive. In an effort to rebuild after the Deepwater Horizon disaster last year, the company is looking to markets where it can grow. Last month the company was involved in an $8 billion share swap deal with Russia’s Rosneft to explore the Russian Arctic region. – Mikaila Adams
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Ensco, Pride merger to create second largest offshore driller
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wo of the industry’s most well-known offshore drilling companies, Ensco plc and Pride International Inc., have agreed to merge into a combined company with an estimated enterprise value of $16 billion and a revenue backlog estimated to be near $10 billion. Ensco will combine with Pride in a cash and stock transaction valued at $41.60 per share based on Ensco’s closing share price on Feb. 4. The implied offer price represents a premium of 21% to Pride’s closing share price as of the same date and a premium of 25% to the one month volume weighted average closing price of Pride. “Although Ensco is paying a healthy premium, we believe the transaction makes great strategic sense,” noted Jefferies & Co. Inc. in a Feb. 7 report. “Ensco is paying a 21% premium, which we estimate is 8.4x our 2012 TEV/ EBITDA, 153% of NAV and 114% of replacement value. In comparison, we estimate the deal is a 20-30% premium to the other diversified offshore drillers trading at 7.0x our 2012 TEV/EBITDA and 120% of NAV.” Under the terms of the merger agreement, Pride stockholders will receive 0.4778 newly-issued shares of Ensco plus $15.60 in cash for each share of Pride common stock. Upon closing, Pride stockholders collectively will own approximately 38% of Ensco’s outstanding shares. Total cash paid to Pride shareholders will be approximately $2.8 billion. Ensco has received commitments from Deutsche Bank Securities Inc. and Citibank NA to finance the incremental debt required for the transaction.
www.ogfj.com • Oil & Gas Financial Journal March 2011
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Upstream News Ensco expects the combined company to realize annual pre-tax expense synergies of at least $50 million for full year 2012 and beyond. Jefferies & Co. Inc. believes the number could be “significantly higher” as Pride’s cost infrastructure was geared towards building a larger company. A Feb. 10 report by Jefferies puts the cost saving in the $150 million to $200 million range. Ensco plc’s chairman, president, and CEO, Dan Rabun, stated, “Pride has gained valuable expertise building and operating ultra-deepwater semisubmersibles and drillships and has strong relationships with leading customers in Brazil and West Africa, two of the fastestgrowing deepwater markets in the world. Ensco is a leading provider of premium jackups and ultra-deepwater semisubmersible rigs with a major presence in the North Sea, Southeast Asia, North America and the Middle East. Together, we will form an even stronger company that is ideally positioned to capitalize on growth opportunities within our industry.” Pride International’s president and CEO Louis Raspino added, “I have always been an advocate of scale, believing that a company with critical mass is afforded numerous benefits, including operational efficiencies, marketing advantages and the ability to attract and retain talented individuals that will help to secure a strong future for our company.”
ment will be named at a later date. Ensco’s eight board members will continue to serve as directors and two Pride directors will be appointed to an expanded board effective at closing. Ensco’s lead financial advisor and strategic advisor for the transaction is Deutsche Bank AG Cayman Islands Branch and Citi also served as financial advisor, and its legal advisor is Baker & McKenzie LLP. The financial advisor for Pride is Goldman, Sachs & Co. and its legal advisors are Baker Botts LLP and Wachtell, Lipton, Rosen & Katz. The companies anticipate that the transaction could close as soon as 2Q11. – Mikaila Adams
Statoil finds gas near Gullfaks in North Sea
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tatoil has found gas and condensate around two kilometers west of the Gullfaks South field in the middle sector of the North Sea. The size of the discovery is estimated at between 19 and 75 million barrels of recoverable oil equivalent. Plans call for tie-back of the discovery to existing infrastructure in the Gullfaks South area. “The discovery by Gullfaks confirms once again that infrastructure-led exploration is important and leads to finds with high profitability that can quickly come on Combined company stream,” said Gro Gunleiksrud Haatvedt, senior vice The transaction will create the second largest offshore president for exploration on the Norwegian continental driller with operations and drilling contracts in more than shelf (NCS). 25 countries on six continents in both deep and shallow The discovery was made in the Rimfaks valley where water basins utilizing 74 rigs including 21 ultra-deepwater drilling of well 34/10-53 S confirmed a column of around 300 meters in good-quality reservoir rocks. Gas and deepwater rigs. was found in the Brent group while no hydrocarbons Within the fleet of 27 floating rigs (semisubmersibles were discovered in the Statfjord group. and drillships) are 21 deepwater drilling rigs, including The well was drilled to a vertical depth of 3,847 meters seven rigs delivered since 2008 and another five ultra below sea level, and was concluded in the Lower Jurassic deepwater rigs expected to be delivered between now and 2013. Thirteen of the rigs are rated for operations in rocks of the Statfjord group. Water depth in the area is 136 meters. water depths of 7,500 feet and greater. “Even if the volumes are modest compared to the large The combined company’s jackup rig fleet, composed discoveries previously made on the NCS, discoveries of of 47 rigs, all with independent leg design, includes 27 this type are important in order to maximize the potential units with water depth ratings of 300 feet and greater, on the NCS,” said Haatvedt. with nine units delivered since 2000. Mid-water rigs will While not formation tested, further data acquisition represent 8% of the combined fleet. Noting the combined company’s “premium fleet,” Jeffer- and sampling are being made to determine the hydrocarbon system and estimate contacts. ies says the company is “poised to generate significant EPS The well was drilled by the Deepsea Atlantic drilling growth” and estimates 75% of the combined company’s rig. After completion, the rig is to drill a sidetrack well to EBITDA will be derived from premium assets by 2013. Opal, which is a prospect in the Middle Jurassic reservoir The combined company, to retain the name Ensco rocks (Brent group) located west of the Rimfaks valley in plc, will remain domiciled in the UK, as will most of production license 050B. the senior executives. Dan Rabun will remain chairman, The licensees of PL050 and PL050B are Statoil (operapresident, and CEO and James W. Swent will continue as tor, 70%) and Petoro (30%). OGFJ senior vice president and CFO. The remaining manageMarch 2011 Oil & Gas Financial Journal • www.ogfj.com
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Twilight or dawn in the Gulf of Mexico? While the debate continues over safety and risk mitigation issues in the Gulf of Mexico, some participants have grown weary of the uncertainty and are preparing to exit the Gulf for friendlier waters in other parts of the globe. Don Stowers, Editor – OGFJ
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www.ogfj.com • Oil & Gas Financial Journal March 2011
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The Chevron-operated Hercules 173 in Gulf of Mexico shallow waters. Photo courtesy of Hercules Offshore
I am very confident we are getting close to the point where we can issue deepwater permits. – BOEMRE’s Michael Bromwich, Feb. 25
y the time this issue of Oil & Gas Financial Journal goes to press, the US Department of the Interior will probably have issued the first new deepwater drilling permits in the Gulf of Mexico since the Deepwater Horizon well blowout last April 20. However, the offshore industry needs to know: Is this a token action or will the number of permits issued return to previous levels? Oil and gas companies have sharply criticized the Obama administration for creating a de facto drilling ban in the Gulf long after the official drilling moratorium put into effect after the BP oil spill was lifted. Offshore operators with excellent safety records believe they are all being punished unjustly for an accident that happened to one operator, BP. March 2011 Oil & Gas Financial Journal • www.ogfj.com
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“The perception was that we were a permitting mill…It would be irresponsible to approve new drilling before we have answered the simple, yet compelling question, ‘How do you deal with it.’” – Michael Bromwich, BOEMRE
©2011 Michael Stravato. Provided courtesy of the James A. Baker III Institute for Public Policy, Rice University
As of late February, not a single new deepwater permit had been granted except for two water injection wells. Only 31 drilling permits for the shelf were issued during this period. This compares with an average of about 20 shallowwater permits per month prior to April 20, creating a deficit of about 130 wells that weren’t drilled on the shelf during the past 10 months. On Feb. 11, the Baker Institute for Public Policy at Rice University in Houston held a conference aimed at examining the policy implications of the deadly explosion in the Gulf and the subsequent oil spill as well as the economic and political impact of the shutdown in new drilling activity. Addressing conference attendees, Michael Bromwich, director of the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), said the domestic offshore industry should not expect his agency to begin issuing new permits until fundamental questions concerning disaster prevention and spill containment plans have been answered. “It would be irresponsible to approve new drilling before we have answered the simple, yet compelling question, ‘How do you deal with it,’” said Bromwich. BOEMRE, a division of the Interior Department, regulates offshore exploration and production and was formed after the previous regulator, the Minerals Management Service (MMS), was dissolved after facing criticism it was a “rubber stamp” for the petroleum industry. 14
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Speaking before a gathering of about 200 or so energy executives, academics, and reporters, Bromwich emphasized his agency’s commitment to aggressive regulation and enforcement, adding that it isn’t likely permitting will ever return to the levels prior to the Deepwater Horizon disaster. “The perception was that we were a permitting mill,” he said, adding that the drilling permit process will now take longer due to tougher safety and environmental standards put in place following the incident. Although Bromwich said he didn’t anticipate any further rulemaking, the offshore industry is concerned about delays caused by extensive reports, analyses, meetings, and what one policy wonk called “bureaucratic foot-dragging.” BOEMRE plans to prepare an Environmental Impact Statement (EIS) for proposed oil and gas lease sales in the Western and Central Planning Areas of the Gulf of Mexico, off the coasts of Texas, Louisiana, Mississippi, and Alabama, for the five-year oil and gas leasing program from 2012 to 2017. “This important step in the offshore resource evaluation and development process will help ensure that all interests and concerns regarding oil and gas leasing, exploration, development, and production from proposed sales are appropriately considered,” said Bromwich. “Every comment will be analyzed and considered as we continue to prepare for the next five-year program.” Noble Corp. is among the drillers that have grown tired www.ogfj.com • Oil & Gas Financial Journal March 2011
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Previous Page Contents Zoom In Zoom Out Front Cover Search Issue Next Page Interior Secretary Ken Salazar and Marine Well Containment Company CEO Marty Massey view the company’s interim system capping stack with industry and government officials. Photo courtesy of Business Wire
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of waiting for Washington to act. The company recently said it will move its Clyde Boudreaux rig to Brazil because the current leaseholder in the Gulf of Mexico declined to extend its contract with Noble due the lack of permits being issued by BOEMRE. Roger Hunt, Noble’s senior vice president for marketing and new contracts, told analysts in a recent conference call that the company has endured the moratorium but finally has decided it cannot wait any longer. The company said there was too much uncertainty, and this situation had contributed to a serious decline in fourth-quarter profits. Another speaker at the Baker Institute forum expressed concern about the “new regulatory environment” in Washington. Karen Harbert, president and CEO of the Institute for 21st Century Energy for the US Chamber of Commerce, said she is afraid this will “put the government in the boardroom.” She added, “We don’t need more regulation – we need better regulation. The government has an obligation not to change the rules of the game every two years.” Harbert added, “You may not realize this, but there is more opportunity than there is capital,” adding that Gulf of Mexico operators could move their rigs elsewhere if regulations and the cost of drilling in the Gulf become too onerous. J. Robinson West, chairman and CEO of PFC Energy, an energy advisory firm, concurred, “The industry is going to invest in the deepwater. The money will be spent, but it will go elsewhere if drilling doesn’t resume soon.” He added, “Whatever oil isn’t produced in the Gulf will have to be imported.” According to a July 2010 report by IHS Global Insight, the Gulf of Mexico oil and gas industry generated almost $70 billion of economic value and 400,000 jobs in 2009. The Greater Houston Partnership noted, “A restriction on offshore drilling results in significant job losses, lose government revenues, and decreased national security.”
www.ogfj.com • Oil & Gas Financial Journal March 2011
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However, Shirley Neff, a senior analyst with the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, said their research shows that stricter regulation is needed. “We have a higher fatality rate in the Gulf of Mexico than elsewhere [in the world],” said Neff. She pointed to Norway, Canada, Australia, Brazil, and the United Kingdom as examples of countries with better safety records than the US. She also pointed out that the US government currently regulates operators, but not other companies operating in the deepwater arena, and this is an area that needs to be addressed. The drilling moratorium that went into effect after the deadly April 20 blowout just 40 miles off the Louisiana coast was lifted in October by Interior Secretary Ken Salazar. Although, to date, it has not led to the issuance of any new deepwater drilling permits, there are signs that is about to change. Salazar, in lifting the moratorium, said that information gathered in recent months shows “significant progress in reforms to “What happened in the Gulf of Mexico, obviously, was tragic. It never should have happened. But I continue to believe it’s an anomaly. I simply do not accept the notion that there is a systemic issue with safety and operating capability across the industry. That defies logic.” – John Hofmeister, former president of Shell Oil Co.
drilling and workplace safety regulations and standards, and increased availability of oil spill response resources since the Macondo well was contained on July 15 and killed on September 19, and improved blowout containment capabilities.” He added, “The oil and gas industry will be operating under tighter rules, stronger oversight, and in a regulatory environment that will remain dynamic as we continue to build on the reforms we have already implemented.” Salazar has acknowledged that the new, more stringent rules would add to the cost of deepwater projects, but he said he didn’t know to what extent. Two projects have helped a great deal in moving forward the drilling permit process: 1. The creation of new oil spill response task forces by NOIA, IPAA, and API to respond to oil spills in the Gulf of Mexico, and 2. a new interim containment system launched by Marine Well Containment Company, a not-for-profit, independent organization formed by several oil majors and open to all oil and gas operators in the US Gulf of Mexico. 18
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The task forces will review spill response actions that occurred in the Macondo well spill and make recommendations as to how to improve future response and containment efforts. “A recurring theme…is that the technology exists to drill successfully in deeper and deeper water, but the technology to respond to release of oil in these environments appears not to have kept pace,” said NOIA president Randall Luthi. On Feb. 25, Salazar and Bromwich visited Houston to view a new capping stack built by Marine Well Containment Company (MWCC). The system will provide rapid containment response capabilities in the event of a potential future underwater well control incident in the deepwater Gulf. “The interim well containment system is complete and available for use,” said Marty Massey, MWCC’s CEO. “Over the past six months, we have worked closely with BOEMRE, the Coast Guard, and other authorities to help ensure that the design meets the regulatory requirements. BOEMRE has reviewed the functional specifications of the interim response system and its input has been included in the final specification.” He added, “Our objective is to ensure that the well containment response system is in a state of continuous operational readiness to facilitate rapid deployment and response in the event that it is required.” The capability of the interim containment system will continue to build as components of the expanded system are completed and delivered to MWCC. Massey says the expanded system is on track to be completed in 2012. A second well containment system being developed by Helix Corporation is expected to be ready by the end of March. John Hofmeister, former president of Houston-based Shell Oil Co. who now heads Citizens for Affordable Energy, a public policy organization aimed at educating the public about energy, recently told the Houston Business Journal, “What happened in the Gulf of Mexico, obviously, was tragic. It never should have happened. But I continue to believe it’s an anomaly. I simply do not accept the notion that there is a systemic issue with safety and operating capability across the industry. That defies logic.” OGFJ
www.ogfj.com • Oil & Gas Financial Journal March 2011
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Shale gas: a global game changer Dallas Parker, Mayer Brown , Houston
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en years ago, few crystal balls foresaw the lightning impact and development of shale gas on the world’s energy scene. In the last 10 years – during which shale gas became commercial in the US – its use has grown from near zero to about 20% of the already enormous US gas stream. Booked shale gas reserves, at present rates of production, may still be onstream 100 years into the future, a figure that will increase if gas begins to approach oil on a price parity basis. Many likely changes will result from shale gas development. But the most important ones reflect the economic impact of shale gas on global politics and today’s energy producers.
Economic model implications Let’s start with one of the more subtle changes: that of the economic models used around the world. Although shale deposits are distributed globally and have been so 20
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for millions of years, it was US research and development with its entrepreneurial risk-takers that put recoverable shale gas on the mineral inventories of many nations. Hopefully, spreading of the entrepreneurial model will be one of the more lasting effects of the shale gas story. Traditionally, US capital and know-how migrated in search of raw materials. In the case of shale gas, other countries are inverting that approach and bringing capital here, investing billions in the expertise and reserves of US shale gas companies: Norway’s Statoil, CNOOC of China, Mitsui of Japan, Reliance of India, and France’s Total, to name a few. It’s hard to imagine they will value the technology that enables the production of this tight gas – yet ignore the competitive economic system that produced the technology. Interestingly, we are even seeing some of this result already in China, where the major state-owned energy companies find themselves in tough competition with each other for limited global resources.
www.ogfj.com • Oil & Gas Financial Journal March 2011
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A farm and a Marcellus shale well coexist. Photo courtesy of Range Resources
The shale gas impact won’t stop in abstract economics. Developing reserves will help stop the wealth drain and spread prosperity. For example, in the US, as we drill wells and hook up gathering systems, we’ll see investment in exploration, pipelines, storage facilities, conversions of electricity generation to gas, cheaper and cleaner electricity, more competitive US manufacturing, good jobs, royalties to property owners, and a better US balance of payments. These activities will generate concrete real economic growth in the US – and can produce similar results worldwide.
environmental issues. They have no tradition of American-style entrepreneurship. What they do have is reliance on Russia’s Gazprom in a power-constrained economy. They want to accelerate the development of their shale gas reserves. This story is repeated many places.
Cartel pricing versus market pricing
Politics aside, shale gas pricing could thwart the once likely coalescing of a Russian-Persian Gulf gas cartel. Gas prices will likely reflect real costs rather than cartel-engineered prices that spike with every political flare-up. With competitive, market-priced shale gas onstream, Worldwide political impact of shale gas the massive international wealth transfers of the last 40 The distribution of shale gas is so widespread that locally years could retrench. But other developments will affect produced shale gas may become the standard fuel in many gas exporters’ global strategy. For example, five years ago places. Traditional gas imports (by pipeline or as LNG) the US was building LNG import facilities and signing may become incremental sources. up long-term cartel suppliers. Today, we are seeing a very The potential of shale gas implies a loss of political leverage for some sellers. For example, Russia has used threats of interruptions – and actual interruptions – like “Politics aside, shale gas pricing could thwart old-time gunboats, notably with Ukraine, but with other the once likely coalescing of a Russian-PersianEuropean countries, too. Gulf gas cartel. Gas prices will likely reflect real I recently attended a conference on shale gas in Poland costs rather than cartel-engineered prices that on behalf of Mayer Brown. The Poles share with other spike with every political flare-up.” Europeans concerns about fracking, water recycling, and March 2011 Oil & Gas Financial Journal • www.ogfj.com
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likely prospect of US gas exports. This unexpected development hits global LNG prices three ways: One, US demand no longer supports extreme gas prices. Two, we may compete for LNG customers – or help other nations establish their own production. Three, the economics of gas-to-liquid projects have seemingly been immutably changed. Gas exporting countries will still be suppliers but likely not as they anticipated.
ments to wind and solar capability. In any case, subsidized, vested interests will no doubt fight to hold their favored positions – even at the risk of losing a job-producing, indigenous energy supply and a more prosperous national economy. But we can also focus on a more positive future, one in which shale gas accomplishes two things: A) it removes a huge area of international economic uncertainty, one in which – for decades – a supply conDevelopment of renewables centration in volatile regions of the globe held many of and nuclear power the cards in basic energy; and Because shale gas can be distributed through existing B) because low-emission gas power plants are cheaper gas facilities, it can decrease the to build and operate than coal urgency with which some counplants, shale gas may permit tries pursue solar and wind projgreater progress in reducing ects. But these renewables have greenhouse gases. been supported by global warmIn such a world, the results ing concerns and benefited from would be nations economically deliberately high subsidies. So grounded on safe, reliable, and a commitment to renewables is often domestically produced likely to remain even if gas availenergy supplies, the fostering ability is explored and ultimately of new jobs and opportunities, adopted. growing freedom from monopoBut don’t count the market listic energy pricing, and a cleaner out: Many countries will have environment. shale gas potential but no counI think the trend is in favor of try will soon have a functional, the more positive world marunsubsidized renewables indusket economy. But even if the try. In today’s global economy, more positive view of the future competitively priced gas can make starts off slowly, few consuming its own case. countries will want to extend the Where nuclear power is used, it forty-year economic drain many has already passed three big tests: have experienced, the depenA) reduced emissions, B) competdence on long sea-lanes, and itive economics, and C) exaggerpowerlessness in the face of high ated fears of catastrophic results. prices and pressure politics. Where it isn’t being used, the There are no guarantees, but A Barnett Shale well near Decatur, TX. value of those tests has been disin a world with widely distributed Photo courtesy of Devon Energy counted. I don’t see big changes shale gas reserves, this potential in today’s nuclear position. future is much closer than it was 10 years ago. OGFJ
Two potential futures
Looking at a present day oil and gas importing area like Europe, we could focus on a potentially negative outcome: a world divided into many smaller, densely populated countries with state ownership of minerals and no deep-seated entrepreneurial tradition. Such countries may resist the disruptions associated with exploration, production, hydrofracking, building an industrial infra-structure, and so on – just as US coastal state residents often resist offshore oil production – and offshore windmills, for that matter. Citizens in countries with green politics and economics are already accustomed to choosing favorites and then subsidizing them significantly. Shale gas may open economic options yet still be rejected in favor of commit22
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About the author Dallas Parker is a partner in Mayer Brown’s Houston office. He represents clients in corporate and securities law matters, with extensive experience in the areas of mergers, acquisitions, takeovers, proxy contests, public and private offerings of equity and debt securities, corporate governance, independent committees, and related matters. Parker represents US-based clients wishing to do business around the globe, as well as international clients wishing to conduct business in the US. He earned his JD, cum laude, from the University of Texas School of Law and his bachelor’s degree from Vanderbilt University. www.ogfj.com • Oil & Gas Financial Journal March 2011
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Response crews battle the blazing remnants of the Deepwater Horizon April 21, 2010. Photo courtesy of the US Coast Guard.
Insurance lessons from the deepwater Linda Kornfeld, Dickstein Shapiro LLP, Los Angeles Selena Linde, Dickstein Shapiro LLP, Washington, DC
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he unprecedented gush of oil into the Gulf of Mexico waters after the Deepwater Horizon explosion in April 2010 caused worldwide businesses to contemplate the implications of the likely and massive litigation and potential serious economic losses that they might suffer because of the spill. Fortunately, for many businesses, the anticipated losses did not occur. However, the event led to concern about future events and their potential impact. Part of the dialogue last year in considering how businesses may address financial hardship because of the Gulf oil spill centered on the availability of insurance. In fact, policyholders and insurers alike expected massive coverage litigation and in doing so considered the relevant coverage issues that would be addressed and resolved in that litigation. Should the oil and gas industry suffer another event similar in manner or degree, insurance will be a critical resource. Insurance issues should be considered early and often whether as a result of a significant environmental
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event that causes businesses to become defendants in litigation due to an environmental event or as a result of economic losses incurred during a government-imposed drilling moratorium (as happened after the Deepwater Horizon explosion) or due to other events that interfere with normal business operations. Commercial general liability (CGL) and business interruption insurance may offer a critical first line of assistance in responding to litigation or other business losses. In the context of similar types of large-scale losses, insurers have often responded with a host of arguments to avoid paying policyholders’ claims. Whether policyholders can defeat these arguments will depend on the particular facts involved and the applicable policy language. Regardless, policyholders never should accept an insurer’s denial of coverage as having merit, but instead should always consult with outside coverage counsel to determine independently the merits of the claim. Here we focus on certain notable insurer arguments.
www.ogfj.com • Oil & Gas Financial Journal March 2011
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Economic losses
Pollution exclusion
Plaintiffs in a number of lawsuits filed in connection with the Gulf oil spill alleged that the spill resulted in “catastrophic environmental destruction,” which has caused the plaintiffs to suffer “economic loss.” Policyholders can expect some insurers to argue against coverage for such allegations by claiming that economic losses do not constitute direct “bodily injuries” or “property damage” under CGL policies. Policyholders should reject this argument. CGL policies typically cover “those sums that the insured becomes legally obligated to pay as damages because of ‘bodily injury’ or ‘property damage’ to which this insurance applies . . .” and generally do not expressly exclude “economic losses.” Courts addressing the economic loss question have focused on the “because of” policy language and found coverage when the damages sought are “because of” bodily injury or property damage. According to those courts, as long as the claimed economic losses naturally flow from property damage or bodily injury, coverage should apply. In the context of litigation similar to that filed in response to the Deepwater Horizon disaster, coverage should not be impacted simply because some plaintiffs do not claim damage to their own property, but, instead, claim economic loss resulting from damage to other property, such as wetlands. A causal connection between damaged property and lost profits may overcome insurer economic loss defenses.
Many insurers may cite pollution exclusions in both CGL and first-party policies to defend against coverage for oil spill losses and litigation or similar catastrophic environmental events. “Policyholders can expect some insurers to [claim that] economic losses do not constitute direct ‘bodily injuries’ or ‘property damage’ under CGL policies. Policyholders should reject this argument.”
However, these exclusions do not bar coverage for all pollution-related claims. For example, although pollution exclusions often include broad definitions of “pollutant,” many courts have narrowed the applicability of the exclusion to “traditional” environmental contaminants. Thus, in connection with the Gulf oil spill, policyholders could have sought to avoid application of pollution exclusions by arguing that it does not apply to losses resulting from for example the release of “unrefined” oil or the use of chemical dispersants in the clean-up effort. The exclusion also often does not apply to product liability claims. Some Gulf oil spill plaintiffs have alleged injury
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because of the use of chemical dispersants. Companies that manufactured or sold these dispersants could argue in favor of coverage by alleging that the claims against them are for product liability claims that fall outside the pollution exclusion. The “cause” of the catastrophic event also may provide an avenue to avoid this exclusion. For example, with respect to the Gulf oil spill, the cause of the loss at issue may not have been the release of a pollutant, but rather the fire and explosion at the Deepwater Horizon. Fire and explosion are covered causes of loss under many CGL and first-party policies. Thus, policyholders could argue that the loss resulted from a covered cause of loss as opposed to one that is excluded. The success of this argument will depend on the state causation law that ultimately may apply and the specific wording of the insurance policy provisions.
Many of the suits that arose from the Deepwater Horizon oil spill included “nuisance” claims. There are two types of nuisance claims, private and public, both of which were employed in the Gulf oil spill litigation. The typical remedy sought for a nuisance claim is not compensatory damages, but the “abatement” of the nuisance. In the past, some insurers have argued that suits seeking abatement are not covered by their policies. These insurers rely on CGL policy language requiring the insurers to pay “those sums that the insured becomes legally obligated to pay as damages . . .” According to the insurers, the term “damages” is limited to “legal” monetary damages, and because abatement is an equitable remedy, the nuisance claims are not covered. In the context of oil spill-related suits insurers may raise a similar argument. However, in the environmental context courts generally have rejected attempts by insurers to draw a distinction between legal and equitable relief. These courts recognize that regardless whether the relief is styled as damages, abatement, or other injunctive relief, it still requires the policyholder to pay money because of harm caused to third-parties. 26
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Moratoriums on drilling
“Many business interruption policies pay for lost profits when a business cannot perform its normal business activities because of an order of ‘civil authority.’ Drilling ‘moratoriums’ generally should fall within this ‘civil authority’ coverage.”
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After the Deepwater Horizon explosion, President Obama issued a temporary moratorium on drilling in the Gulf waters. Any event that interferes with the ability of a business to conduct its normal business activities can result in substantial lost profits. Many companies in the oil and gas industry contain some form of “business interruption” insurance in their insurance portfolio. The policy language in these policies can vary, sometimes widely, with respect to the type of event that is necessary to trigger coverage to pay for lost profits. Frequently these policies require actual damage to the policyholder’s property that results in an “interruption” of business. However, most companies that suffered loss because of the drilling moratorium did not themselves suffer any actual damage to their property because of the Deepwater Horizon explosion. Given the language in many policy forms that fact should not matter. Indeed, many business interruption policies pay for lost profits when a business cannot perform its normal business activities because of an order of “civil authority.” Drilling “moratoriums” generally should fall within this “civil authority” coverage. Thus, policyholders should review their policies to determine the extent to particular policy language will provide adequate protection. In sum, policyholders have arguments to overcome popular insurer efforts to avoid coverage. It is important to consider the particular damage at issue, and to review the specific terms of the individual policy to determine which coverage issues may arise and which arguments will be the most effective. OGFJ About the authors Linda Kornfeld is the managing partner of Dickstein Shapiro LLP’s Los Angeles office and a partner in the insurance coverage practice. She represents corporate policyholders in complex litigation matters and provides insurance risk management advice with respect to policy procurement and renewals. Selena Linde is deputy practice leader of Dickstein Shapiro’s insurance coverage practice and is based in Washington, DC. She specializes in policyholder insurance coverage and complex civil litigation.
www.ogfj.com • Oil & Gas Financial Journal March 2011
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CONFERENCE & EXHIBITION
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Assessing the risk in capital-intensive opportunities Energy sector opportunities abound, but many are capital intensive and carry significant CapEx Risks. These risks are often underestimated, with cost overruns and schedule delays common. Richard Westney, Westney Consulting Group, Houston
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he increasing number and complexity of energy sector opportunities has made it more important than ever that investment decisions reflect a complete understanding of all the risks to economic value. Energy is a capital-intensive business, and the success of many opportunities is tied to the owner/operator’s ability to create a new capital asset. For example, the opportunity may be to participate in a newly-formed project company which intends to define, engineer, and construct a pro-
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duction facility and depends on project finance and other investors to fund the project. Or, it may be to invest in an established company with a portfolio of opportunities that require the development of capital assets. Evaluating the attractiveness of these capital-intensive opportunities requires careful answers to questions such as: • How much is the production facility likely to cost? • What is the maximum cash impairment we are likely to experience before positive cash-flow?
www.ogfj.com • Oil & Gas Financial Journal March 2011
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Operations Risks Some form of risk analysis is usually applied to develop answers to these and similar questions. In many cases, the focus is on Operations Risks. These risks create uncertainties around the base case assumptions as to the revenues and costs of the operating facility (see Fig. 1). The risk analysis will typically address potential variations from the base case assumptions for such variables as product price, production capacity, and utilities cost, in order to determine the level of risk to the Net Present Value (NPV) or similar metrics of economic value.
CapEx Risks
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Fig. 1: Cash flow during operations Revenue - based on: Production capacity Utilization rate Product price
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Cash flow
• What is the likely time required to complete construction, commissioning and startup? • How long is it likely to take to achieve full production? • What is the likelihood we will have sufficient operating margin to service the project’s debt obligations? And above all: • How likely are we to achieve our required return?
Time
Operations costs, e.g: Utilities Raw materials
– Fig. 2: Combining CapEx and operations cash flows Revenue - based on: Production capacity Utilization rate Product price
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Capital-intensive opportunities also have significant CapEx Risks. These are the risks associated with the developer/operator’s ability to define the project, achieve financial close, complete the engineering and construction within budget and on schedule, and start-up the facility. These CapEx risks are important. Large engineering and construction projects have had a long history of cost overruns and schedule delays, often resulting in major impacts on economic value as well as investor confidence. The base case for a project is typically developed by internal and/or external engineering teams who define the scope, schedule, execution plan, and cost estimate. There is considerable experience to suggest the base case often grossly understates the cost and time required and reflects an overconfident assessment of risks. Risks to the project’s cost, time, and performance
Time to full Production Production profile
CapEx costs Engineering Procurement Construction Startup
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Operations costs, e.g: Utilities Raw materials
objectives are apt to be significant, and it can be difficult to fully transfer all these risks to contractors and suppliers. The evaluation of capital-intensive investment opportunities therefore requires the ability to assess the full range of CapEx risks and to integrate them with operations risks in order to have a complete understanding of the total economic risk exposure. Figure 2 illustrates the combined CapEx and Operations cash-flows that drive economic value. Most of the variables associated with cost and revenue have a range of uncertainty as a result of CapEx
March 2011 Oil & Gas Financial Journal • www.ogfj.com
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and Operations Risks. Since the timing of costs and revenues is also uncertain, it is usually not selfevident how these uncertainties combine into the overall level of risk. The only place where the uncertainties in all the project variables come together is in profitability, which, for this purpose, is most easily measured by NPV. The solution, then, for a capital-intensive opportunity, is to develop a probabilistic assessment of NPV which considers the combined impact of all risks. The decision-maker can use the results, together with consideration of risk appetite and other investment criteria, to evaluate the overall attractiveness of the opportunity. A probabilistic assessment of NPV is a four-step process illustrated by Fig. 3.
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which they are uncertain, and how they vary with time must be understood. A choice must be made for each variable: whether to treat it as certain or uncertain. For example, if a firm fixed-price agreement is in place for the first five years of power supply, the model would treat the cost of power as fixed. If the product is a fungible commodity to be sold on the open market, it is likely that the model would be constructed to treat product price as uncertain. In most cases timing is treated as uncertain. Although this adds complexity to the model, it is an important part in ensuring the analysis yields meaningful results.
Step 2: Assess the risks and uncertainties
For those variables that are uncertain, the risks that drive uncertainty must be identified in order to determine that variable’s range of uncertainty. For Of course, every opportunity is different. The example: specific variables that are important, the extent to • Risks to Revenue may include lower-than expected product price, reduced production capacity, or increased downtime. Fig. 3: Steps in developing a probabilistic • Risks to CapEx Costs may assessment of NPV include cost overruns from scope changes, lower-than-expected conStep 2: Step 1: Step 3: Step 4: tractor or supplier performance, or Assess the Identify the Construct the Apply the unexpected logistical difficulties. risks & variables that probabilistic analysis results • Risks to OpEx Costs may uncertainties are uncertain NPV model to decisionmaking include production inefficiencies, higher cost of feedstock, and increases in utilities costs. • Risks to Timing may include Fig. 4: Probabilistic view of NPV considering all various causes of delays to the CapEx and operations risks engineering, procurement, construction and startup of the proj100% ect. For each variable, the model will require a range of possible values, 20% of the time the NPV will be <0 as well as the selection of a prob75% ability distribution that reflects the way that variable is likely to respond to the risks that affect it. Cumulative probability
Step 1: Identifying the variables that are uncertain
50% of the time the NPV will be at least $100MM
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25% of the time the NPV will be at least $200MM
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Step 3: Construct the probabilistic NPV Model The probabilistic NPV Model will use Monte Carlo simulation to develop a probability distribution of all possible NPV outcomes. It must reflect both the uncertainties in the key NPV variables as well as the interdependencies among these variables. For example, the model may consider: • The potential threats from
www.ogfj.com • Oil & Gas Financial Journal March 2011
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strategic risks such as global market conditions. • The correlation between commercial, financial, technical and execution risks. • The cause and effect relationship between risks; for example, the risk of insufficient funding of front-end engineering can increase the risk of startup changes and operating issues. • The “snowball effect” in which project risks over time combine and cascade in a way that drives a project to a tipping point beyond which failure is inevitable. For example a project that is poorly defined yet contracted with LSTK will inevitably experience cost overruns, delays, and even litigation. • The importance of mapping all variables, and their risks/uncertainties, against time, which is itself an uncertain variable.
Step 4: Apply the analysis results to decision-making The results of the analysis usually provide insights into economic risk that are not readily apparent. Fig. 4 illustrates a typical presentation of the results. It shows a given opportunity’s cumulative probability vs. NPV.
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In this example, the decision-maker used these results to compare the opportunity’s strategic fit with the portfolio, as well as its risk/reward profile with that of other alternative opportunities.
Summary While energy sector opportunities abound, many are capital intensive and carry significant CapEx Risks. These risks, associated with the engineering, procurement, construction, and startup of a production facility, are often underestimated, with cost overruns and schedule delays common. Investment decisions for capital intensive opportunities benefit from a comprehensive, probabilistic assessment of NPV that considers both CapEx and Operations Risks and their impact on NPV. OGFJ About the author Richard Westney is founder and chairman of Westney Consulting Group, a Houston-based firm that advises the energy industry on the risks and strategies for major development projects.
A A P L’ S 57 T H A N N U A L M E E T I N G J U N E 8 - 11 , 2011
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www.landman.org • 817-847-7700 March 2011 Oil & Gas Financial Journal • www.ogfj.com
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How to avoid losing millions on an ETRM implementation Larry Hickey, FRM, Sapient, London
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he wily sage peered over the top of his wire-rimmed glasses and eyed the project manager up and down. Wearily, he intoned, “So you want to lose millions on an ETRM implementation? You want to stumble in the footsteps of legends: managers like Richard ‘Build It Here’ Christy, Robin ‘Big Bang’ Quivers, JD ‘De-Supported’ Harnmeyer, and Sal ‘Scope Creep’ Governale? Well, it’s not going to be easy. But with the right combination of project mismanagement skills, it can be done.” OK. So that conversation probably never occurred. But you could be forgiven for thinking it did. An ETRM implementation is an expensive deployment of mission-critical software. There are countless challenges to be overcome and more than a few have failed to navigate the shoal waters. A 2008 UtiliPoint study of 35 ETRM implementation 32
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projects found that, while only one was a complete failure, a quarter of respondents indicated that their systems were not implemented properly. With the average implementation project taking nine months to a year to complete, the median licensing fee north of a half million dollars, and implementation service costs between 1.5 to 2.5 times the license fee, failure can be costly. That follows are some of the key lessons learned from scores of implementations involving a wide range of vendors and applications, including some of the most popular and enduring in the space. There are truisms that relate to any project. Communicate, plan, know where you are and where you want to be, document everything, etc. They also apply to ETRM implementations. But in the interests of time and space, I’ve dispensed with general bromides to focus on the hard-won www.ogfj.com • Oil & Gas Financial Journal March 2011
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truths that apply specifically to ETRM implementations. Okay, here’s one bromide: The cheapest lessons are learned through the experiences of others.
Expectations An ETRM implementation should be a rewarding experience, both personally and professionally. You will work with a dedicated team, meet a range of people from different disciplines, gain valuable project management experience, and develop a detailed understanding of a complex system at the heart of your company’s operations. But it’s no walk in the park. The application is necessarily complex. It must support the requirements of a wide range of customers on a common code base. Complexity is the flip side of the required flexibility and scalability. So ETRM software is fundamentally different from an off-the-shelf application. It is not ‘plug ‘n play.’ One size does not fit all. Significant configuration will be required to tap the full potential of the application and this configuration will require input from the customer. This has to be understood at every level of the organization and championed from the very top. After suffering through years with an inadequate system or a gaggle of spreadsheets, there is a natural tendency to make up a laundry list of requirements based on limitations of the legacy system. The new system will be the panacea that ‘solves all problems,’ so we might as well pile them on. The salesman may have even encouraged this view. Of course, the initial implementation will not solve every problem – and here’s the important part – nor should it attempt to. A good rule of thumb is to try to capture 80% of requirements in the initial effort and either address the other 20% in a separate implementation phase or outside the core system. If you have a flexible, enterprise solution maybe that number is 95% with the rest in a subsequent phase. If you have a point solution, maybe it’s 60% with the balance managed outside the core system. But it’s not 100% in the initial implementation. The outsized effort necessary to put rare or complex structures into the project scope can put the entire implementation at risk. Identify and deliver core functionality in the first phase. Add bells and whistles later.
An implementation methodology The vendor should have a proven implementation methodology to bridge the gap between the ETRM system and the implemented business solution companies actually need. It must be a well-defined, tried and tested process that details client and vendor specific activities to be conducted and the order in which they should be done. Ideally, the vendor should come armed with a list of clients willing to provide references. You may want to do a Google search for historic new client signing press releases by the vendor. Compare it to the list of references, paying particular attention to the names that don’t appear on the reference list.
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Vendors with a strong delivery capacity are proud of it. Expect them to note that their implementations are delivered in accordance with a recognized standard such as Prince2 in the UK or the Project Management Institute’s methodology in the US. Look for evidence that lessons learned are being codified.
Scope Every phase of the project needs firm documented requirements that have been reviewed and accepted by both the client and the vendor. Each phase must have its own budget, timeline, and goal. This defines the initial scope. Acceptance test criteria or “test cases” must be defined as part of this initial scope. Deliverables that are too broadly defined or not fully understood contain the seeds of failure. Reports are an area of particular interest. They must be clearly defined as part of the initial scope or hypothetically the following could happen. A one-page specification could be received for a report. Based on this specification, development begins. Meanwhile an outside consultant has been hired to interview end-users and develop a specification of the same process. After a month the specification could balloon to 12 pages. When it is eventually signed off six months later, it could be 75 pages long.
The best laid plans of mice and men Things change. There must be a formal, documented process in place to make controlled scope changes. The estimated costs and benefits of the additional scope must be spelled out and approved. Over the course of the project, many decisions will be made relating to the configuration of the system. As choices are made, document the reasoning behind decisions. This is so, after the system is live, others can understand what the thinking was at the time and be able to independently evaluate if the conditions or assumptions have changed. Q: How do you eat an elephant? A: One bite at a time. Is your plan realistic? Are you planning to boil the ocean with your team of four? Is milestone two dependent on the development of a perpetual motion machine? Build a project plan that breaks down any large deliverable into manageable chunks delivered in phases. Avoid a ‘Big Bang’ plan that has everything arrive at once. Critically, map tasks to resources where skills are not fungible and include vacations, holidays and a buffer to include sick days and other unforeseen events. Note any dependencies so the critical path is clear. By the way, high-end skills are not fungible. In the 10% to 15% of ETRM implementations that users deemed to be excellent, having the right expert and knowledgeable resources on the project were identified as key success factors. Head Office: We want a baby. How much effort do you estimate? PM: About 9 woman-months.
March 2011 Oil & Gas Financial Journal • www.ogfj.com
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Head Office: Hmmm...We’re sending over 3 women. Can we pick up the baby in 3 months? Some tasks can’t be compressed due to their very nature. QA testing is one such example. Let’s say the plan is for a 20 person-day effort, one person over four weeks. The same results will not be achieved by putting four people on the job for one week.
Sponsorship and buy-in The client must take ownership of the implementation. The way to own is to help create. The implementation team should be a mix of vendor resources and representatives from each of the front, middle, and back offices. Key stakeholders should be included from the inception. A particular risk occurs when the project has IT but no business sponsorship. Failure to identify all interested or affected parties could prove problematic. Suppose a key person from the risk department is away when a critical decision about risk reporting is made. Even though all present might agree with the proposed solution, a workaround in this case, the “An ETRM implementation should be a rewarding experience, both personally and professionally…but it’s no walk in the park.”
key player may disagree and become a roadblock thereafter. Executive sponsorship is the best way to signal the organization’s commitment to change. This support should be clear, visible, and vocal. Ways to demonstrate this commitment include holding steering committee meetings and having senior management attend weekly status meetings. Without executive sponsorship, the end-users could choose to resist an implementation, buffered in the knowledge that senior management never established it as a priority. If the project was on a time and materials basis this could go on for some time, generating revenue for the vendor but no deliverables for the client. Training is a tempting target when looking to reduce scope. But effective training is critical if end-users are to accept or ‘buy in’ to the application. Where possible use the client team members as trainers and schedule multiple sessions to ensure the information is taken on board. It’s not reasonable to assume that knowledge of a new and complex system will be retained after a single pass.
A special caveat It is likely that the implementation means the replacement of a system that one or more people in the organization have worked long and hard to sustain. It is critically important to identify these individuals and keep them even closer by including them in the implementation effort. Otherwise, there is the risk of active resistance or passive-aggressive behavior. Having code that you wrote be replaced by a 34
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commercial system can feel threatening. Winning these folks over is a key objective.
Pricing model risks Certain risks are introduced by the implementation pricing model itself. If the implementation is being done on a time and materials basis, the client bears all the risk of scope creep or inefficient delivery. If the implementation is being done on a fixed price basis, the vendor bears all the risk and the client has no real incentive to assist or control scope. Each model has weaknesses. The good faith of the parties involved is the main bulwark against a breakdown.
A third way A more flexible approach may do a better job of aligning interests. Where scope is clearly defined and responsibilities can be allocated, the fixed fee model makes sense. This relieves the client of pricing uncertainty while presenting an acceptable level of risk to the vendor. Where the scope cannot be determined with any precision, perhaps a new development initiative, for example, the time and materials model may be more appropriate. This provides maximum flexibility for the client without unacceptable risk to the vendor. For cases that fall between these extremes, a fees-atrisk model may do the best job aligning interests. Here the client is billed on a time and materials basis but a quarter of fees are “at risk.” The client decides how much of the “at-risk” fees will be paid based on pre-agreed criteria laid out on a balanced scorecard. The vendor has some skin in the game. Whew! We’re implemented. Nothing can go wrong now. Not so fast. Even if the implementation goes to plan, there are still risks that the value of the work that has been done can be seriously degraded. These risks are associated with your choice of vendor. Most obviously, the vendor might go belly up, as Vedaris did in 2004, leaving clients stranded. This is less of a risk with industry-leading vendors. Or the vendor might be bought out, ceding control of their future direction to the acquiring entity. Or the vendor may simply stop supporting your application. Here’s a fairy tale to illustrate one of the more creative ways that might happen:
A fairy tale with no prince Once upon a time in a land near, near away, there lived a company. This company liked to buy other little companies to gain market share, hoping that one day they could sell to Mr. Bubble and live happily ever after. But while they were buying companies, Mr. Bubble burst. The company was very sad because they now had an assortment of products that each required support and a management team with limited operations experience. The company looked at its product line: ‘WideButShallow’, ‘Intermediate,’ and ‘DeepButNarrow.’ Customers had bought each system to meet different requirements. The company
www.ogfj.com • Oil & Gas Financial Journal March 2011
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decided to give ‘WideButShallow’ a makeover and rename it ‘Ain’tItGreat?,’ a one-size-fits-all solution for everyone. They then stopped development of ‘Intermediate’ and ‘DeepButNarrow.’ All maintenance revenue was used to develop ‘Ain’tItGreat?’ But because each solution was fundamentally different, ‘Intermediate’ and ‘DeepButNarrow’ customers couldn’t upgrade to ‘Ain’tItGreat?’ They had to re-implement. They were still paying maintenance but their system was no longer supported. These customers and their orphan systems did not live happily ever after. If the vendor does manage to stay in business and continues to support the system, you’re still not out of woods yet. The point solution you were sold may not support the full range of processes required by your business. Enter the spreadsheets and still more point solutions.
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solution. Most ETRM implementations are delivered successfully. But achieving that outcome is neither certain nor simple. The lessons discussed here flow from smart, hard-working people. It’s frustratingly easy to go off the rails. I’m reminded of a conversation between two parents of teenagers. “Have you seen the price of college?” remarked one. “Have you seen the price of ignorance?,” responded the other. In this high-stakes environment, you can’t afford to relearn the same old lessons. Finally, you might have recognized some of the names at the beginning of this piece. But not because you worked with them. They are all members of the Howard Stern Show staff and the nicknames are classic ETRM implementation errors. OGFJ
Interfaces
About the author This brings us to one of the great implementation bugaLarry Hickey is a director with Sapient Global boos – interfaces. Rather than recount specific horror Markets. He has been rattling around the stories, let’s look at the recurring themes. ETRM space for the past 12 years. Functionality from each system is lost across the interface. The interface is not supported by either vendor. The interface requires upgrading at twice the frequency of each system, due to changes at either end. The interface dramatically increases your total cost of ownership. Avoiding interfaces is one of the key selling points of a fully integrated
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March 2011 Oil & Gas Financial Journal • www.ogfj.com
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An infinite source of liquid fuel The sun provides more energy to the earth’s surface in one hour than mankind uses in a year. But much work remains to be done to turn solar power into liquid transportation fuels. Joseph Gallehugh, Energy Industry Writer, Greensboro, NC
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iquid fuel from the sun? For years that tantalizing process has been the holy grail of clean, renewable energy. Scientists have actually produced a carbon dioxide and hydrogen precursor to gasoline, called syngas, on a pilot scale but have yet to practically produce gasoline from the sun’s energy. So the commercial viability for the concept seems possible, yet distant. Recent developments, however, have the concept gaining steam. One is a five-year, $17.5 million Department of Energy grant to establish an Energy Frontier Research Center at the University of North Carolina at Chapel Hill. Dr. Thomas Meyer, a world-renowned scientist who is the former associate director for strategic research at the Los Alamos National Laboratory, directs the center. In September a closely related energy innovation collab36
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orative made up of UNC-CH, Duke University, North Carolina State University, and RTI International, announced the formation of the Research Triangle Solar Fuels Institute based in Research Triangle Park, NC. A number of influential funding recommendations have lined up to support such alternative fuel development. Two separate entities: The American Energy Innovation Council, a group of top business executives that includes General Electric Chairman Jeffrey Immelt and former Microsoft Chairman Bill Gates; and The President’s Council of Advisors on Science and Technology (PCAST), have called on the government to boost total funding for energy research, development, demonstration, and deployment to about $16 billion a year. The American Enterprise Institute, the Brookings Insti-
www.ogfj.com • Oil & Gas Financial Journal March 2011
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tution, and the Breakthrough Institute, released a report in October that suggests federal funding for clean energy technology should increase to $25 billion annually. Researchers point out that the sun provides more energy to the earth’s surface in one hour than mankind uses in a year. As intriguing as that sounds, much work must be done to make “sunthetic” fuel, solar-driven transportation liquids such as gasoline, diesel, and jet fuel, a reality. With the right combination of funding, new advancements in nanotechnology, and burgeoning knowledge in chemical and materials engineering, experts say it is possible that in as little as a decade scientists may be able to do what nature has done for millions of years through photosynthesis – create and store energy from the sun. While Dr. Jim Trainham, executive director of the Research Triangle Solar Fuels Institute, hasn’t projected a definitive cost for commercializing the process, he notes that, “Financing sunthetic research is not for the faint of heart. I expect only the oil and gas industry knows how to manage capital projects as big as these will be.” With that caveat, how would this new energy direction impact the oil and gas industry? That question evokes a plethora of other questions, and an endless stream of answers that have both positive and negative implications. On the positive side, commercialization of solar fuels technology would create a monumental opportunity for the
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oil and gas industry. Commercialized sunthetics would ensure that the oil and gas industry continues to flourish, providing an endless supply of product to consumers. Producing liquid fuel from the sun could gradually reduce America’s dependence on foreign oil. This would temper “Financing sunthetic research is not for the faint of heart. I expect only the oil and gas industry knows how to manage capital projects as big as these will be.” – Dr. Jim Trainham global geo-political hotspots, reducing them from a boil to a simmer, because less oil would need to be imported by the US. One compelling reason for the oil and gas industry to participate in the development of solar fuels is the minimal investment required to build new processing and distribution infrastructure such as refineries, pipelines, truck fleets, and tank farms. With the exception of minor retooling, the
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March 2011 Oil & Gas Financial Journal • www.ogfj.com
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How scientists make liquid fuel from the sun
to replace gasoline with solar fuel is a good deal.” Fig. 1: RTSFI’s way: artificial photosynthesis As for exploration and production, ExxonMobil, Shell, BP America, ConoCO2 capture from coPhillips, and Chevron together spent industrial processes $33.8 billion to find new oil and gas CO2 in during the past three years, according to testimony provided to the House Sunlight in Refinement Energy & Commerce subcommittee by industry executives in 2010. TrainSunlight capture ham believes a fraction of that amount panel H20 in H2 out Intermediate Storage would induce a tipping point toward Final fuel Catalysis fuel production Gasoline making solar fuels a commercial reality. Methanol Diesel/ ExxonMobil alone is investing $600 DME O2 out Industrial sales Kerosene million in research and development to Syngas Jet fuel produce energy from algae. Producing gasoline, diesel, jet fuel, and sunthetic chemical feedstocks from the sun’s Still, a fraction of $33.8 billion is energy is as basic as photosynthesis. The sunthetics process starts by splitting water a lot of money. How high would the with the sun’s energy. When the hydrogen and oxygen are separated the oxygen is sold price of a gallon of gasoline have to be as an industrial gas while the hydrogen is stored for the next step in the process. In the next stage a catalytic reaction combines the hydrogen with carbon dioxide to yield for solar fuels to be competitive with intermediate fuels such as methanol and dimethylether (DME). In the last refinement petroleum? Proponents don’t know for stage, the final fuel is produced in the form of gasoline. Other fuels such as diesel, jet sure but when hidden cost subsidies fuel, and kerosene will be produced via Fischer-Tropes synthesis. are added, presumably the cost would current downstream system would remain intact, unafapproach $8 to $10 a gallon. Trainham estimates a good fected by this redirected recipe for gasoline. That’s because goal for research is $5 per gallon of gasoline equivalent. sunthetic solar fuels are the same chemically as the gasoline, Beyond that, it’s anybody’s guess. diesel, and jet fuel that are transported today and because Proponents stress that solar fuels science today is where they would require some level of refinement before going solar electricity science was 30 years ago – in its infancy. At to the retail market. that time one of the landmarks of solar electricity advanceOver time, commercialized sunthetics would transform ment was that ARCO Solar produced more than one megathe image of the oil and gas industry from an environwatt of photovoltaic modules in one year. In 2008 the US mental villain to an ecological hero. The process used to produced 8,775 megawatts solar-generated electricity. produce clean, renewable gasoline from the sun, requires As with solar electricity 30 years ago, there remains much CO2 for a catalytic reaction with hydrogen. As a result, to be refined, and much potential to be realized, from proponents estimate production of solar fuels will signifi- sunthetics development. Ultimately, while oil versus solar cantly reduce net lifecycle carbon intensity compared to fuel futures may be modeled within the next five years, petroleum-based fuel. the development of solar fuels is subject to considerable This technology isn’t cheap to develop. Beyond research research and development. and development costs, will solar fuels require government Proponents of solar fuels believe that when the cost of subsidies to be economical? oil security and the cost of lost wealth related to imported “Capitol Hill ignores the hidden costs of oil and gasooil are factored into prices, the crude versus solar fuels cost line,” Trainham says.“That $3 we pay on average per gallon debate becomes moot. Trainham projects that when this today at the pump is misleading. The true cost is $8 to new liquid fuel reaches commercialization it will not just $10.” compete, but will become a major source of all liquid transThe $5 to $7 in hidden costs is derived from taxpayers’ portation fuels in the future. cost to obtain the 53% of oil that the US imports, includFor more information, go to www.solarfuels.org. OGFJ ing the military cost of protecting the Persian Gulf. That number also includes public health and environmental costs About the author as well as the loss of US jobs and the accompanying federal Joe Gallehugh, an energy, chemical, and technology writer, is owner of the marketing and state tax revenues lost due to imports. and public relations practice Gallehugh Group “With gradual replacement of petroleum-based gasoline with solar fuels, as a substitute for imported oil,” Trainham Inc. In addition to the Research Triangle Solar Fuels Institute, he works with Electric Power maintains, “Our country would experience a gradual, but Research Institute, P2 Energy Solutions, and significant, reduction in hidden costs. Any early governThe FMC Corp. A graduate of North Carolina ment support for research and development, while finite, State University, he lives in Greensboro, NC. could be recouped. Considering oil’s hidden costs, paying 38
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Utica offers challenges, opportunities Lying below the Marcellus in some areas, the Utica Shale has a very different mineralogy.
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here are at least two potential gas shale plays in the northeastern US states, with one of them extending into Canada. Most people are familiar with the Devonian Marcellus Shale play, but the lesser-known play is the Ordovician Utica, which takes its name from the city of Utica, in upstate New York, where it outcrops. The Utica Shale occurs in outcrops in New York and in the subsurface in the provinces of Quebec and Ontario in Canada. It is also found in the states of Pennsylvania, West Virginia, and Ohio. The shale reaches a thickness of up to 1,000 feet and is as thin as 70 feet on the margins. Estimates are that the Utica Shale may contain more than 20 trillion cubic feet of natural gas – not as much as the Marcellus Shale, but still an impressive amount. Since most of Canada’s natural gas traditionally comes from the province of Alberta and other western provinces, the Utica has the potential of redrawing that country’s energy map. One Canadian oil and gas executive said this about the Utica Shale: “The Utica best compares to the highly successful Barnett Shale in Texas. Initial estimates show the total recoverable potential of the Utica Shale in Quebec could be as high as 25 tcf, with an estimated 93 bcf of original gas in place per square mile. A recovery factor of 15% would yield 14 bcf recoverable gas per square mile.” There have been numerous vertical wells drilled into the Utica Shale over the years, stretching as far back as the 1800s, although none were very productive. Several energy companies hope to change that as they deploy new technology utilizing multi-stage hydraulic fracturing and horizontal drilling techniques.
Challenges in the Utica Shale The Utica Shale has a much higher carbonate content than the Marcellus Shale and a lower clay mineral content. This difference in mineralogy produces a very different response to hydraulic fracturing treatments. The methods used in the Marcellus do not produce as much fracturing in the Utica. However, fracturing rates might be improved with new techniques as more information is gathered. Two major challenges for developing the Utica Shale are its significant depth and a lack of information. In areas where the Marcellus Shale is present, the Utica Shale is probably going to be a resource for the distant future. The Marcellus is less expensive to develop, and companies will focus on it before setting their sights on a deeper target with an uncertain payout. However,
in areas where the Marcellus has been developed, the Utica will have an infrastructure advantage. Drilling pads, roadways, pipelines, gathering systems, surveying work, permit preparation data, and landowner relationships may still be useful for developing the Utica.
New activity Questerre Energy, a Calgary-based company, reports that it has produced 12 MMcfd from one well less than 50 miles southwest of Quebec City. Other players currently operating in the Utica Shale include Gastem, Canbriam Energy, Forest Oil, Talisman Energy, and Quantum. Of these, Gastem has announced plans to drill into the Utica across the border in New York. Talisman and Questerre have begun horizontal drilling in the St. Lawrence Lowlands in Quebec. Forest Oil has been doing extensive drilling and testing, mostly in the St. Lawrence Lowlands and the Gaspe Peninsula in Quebec. Oklahoma City-based Chesapeake Energy is rumored to be acquiring acreage in the Utica Shale, according to Jefferies & Co. Another company operating in the Utica Shale is Consol Energy, which recently drilled into the Utica Shale near St. Clairsville. Consol, better known as a coal mining company, has more than 70,000 acres planned for natural gas development in and around Belmont County. Last year, Consol acquired the assets of Dominion Resources Inc., including their positions in the Marcellus and Utica Shale plays, for $3.5 billion. “While most of our delineation efforts are focused on the Marcellus Shale, our vast acreage holdings include other zones that warrant testing, including the Utica Shale,” said Consol Energy chairman and CEO J. Brett Harvey. “As a result of this discovery, we will shift some of our exploration capital to this shale in 2011.” With all the attention being given to the Marcellus Shale, the Utica Shale play has been hovering under the radar. This subsurface formation generally lies under the Marcellus and overlapping it at some points. More recently, Consol announced it would reduce its shale gas drilling in 2011 due to sustained low prices. The company said it would reduce its planned build-up of its horizontal rig fleet in the Marcellus from an average of five rigs to an average of “just under four rigs.” A Consol spokesman said, “Our major objective in 2011 continues to be the delineation of our Marcellus acreage in central Pennsylvania and northern West Virginia. We also plan to drill a modest number of exploration wells in the Utica Shale.” OGFJ
March 2011 Oil & Gas Financial Journal • www.ogfj.com
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Deal Monitor
Chinese companies on shopping spree
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he two largest deals in the last 30 days (Jan. 16-Feb. 15) involve Chinese companies buying into shale assets in North America. With the aggressiveness China has shown on acquiring oil and gas resources to supply fuel for their burgeoning economy, this won’t be the last we’ll hear from the Asian economic powerhouse. On Feb. 9, Canada’s EnCana Corporation signed a C$5.4 billion (US$5.5 billion) cooperation agreement with PetroChina International Investment Company Limited, a subsidiary of PetroChina Company Ltd., to acquire a 50% interest in EnCana’s Cutbank Ridge business assets in British Columbia and Alberta. Under terms of the agreement, the two companies would establish a 50/50 joint venture that would ambitiously grow natural gas production from the Cutbank Ridge lands for years ahead. The joint venture deal is China’s largest Canadian upstream transaction ever recorded and demonstrates that the Chinese are willing to pay a premium to secure North Ameri-
can resources necessary to feed the growing Asian economy. Commenting on the deal, IHS Herold’s Christopher Sheehan said that securing energy supply, rather than price, is the key driver for PetroChina and the Chinese government. The deal will give PetroChina access to Canada’s shale gas resources, while EnCana will obtain additional capital to fund its gas development plans. China has also shown an interest in the development of the Kitimat LNG terminal, which will be situated on the west coast of British Columbia. The terminal is currently in the early stages of the approval process by the Canadian government. The other major deal involving a Chinese company is between CNOOC Limited and Oklahoma City-based Chesapeake Energy Corporation. The two companies entered into a partnership agreement in the Niobrara Shale-focused Denver-Julesburg (DJ) Basin in northeast Colorado and the Power River Basin in southeast Wyoming. This is the second
Rodman & Renshaw - Deal Monitor – Select transactions
1/16/11 - 2/15/11
US Transactions Date Announced
Buyer
Seller
9-Feb-11
BG Group plc
EXCO Resources
Asset Location Appalachia
3-Feb-11
TX Holdings Inc
Partners
Mid Continent Rocky Mountains
31-Jan-11
CNOOC
Chesapeake
24-Jan-11
Undisclosed
Synergy Resources
Rocky Mountains
18-Jan-11
Gulf Coast Energy Resources
Undisclosed
Gulf Coast Onshore
18-Jan-11
Strategic American Oil Corp.
Galveston Bay Energy
Gulf of Mexico
17-Jan-11
Nostra Terra
New Century
Gulf Coast Onshore
16-Jan-11
Undisclosed
Strike Energy
Gulf Coast Onshore
International Transactions Date Announced
Buyer
Seller
Asset Location
10-Feb-11
Valeura Energy
TransAtlantic Petroleum
Middle East
9-Feb-11
PetroChina
EnCana
Canada
31-Jan-11
Maersk
Devon Energy
West Africa
27-Jan-11
Jomar Capital
Online Energy
Canada
19-Jan-11
Magnum Hunter
NuLoch Resources
North America
17-Jan-11
Undisclosed
Stetson Oil & Gas
Canada
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 full-service investment bank with offices in New York and Houston.
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Deal Monitor partnership between the two companies in the past several months. The first project cooperation agreement in the Eagle Ford Shale in South Texas was announced on Nov. 15. Under the agreement, CNOOC will purchase 33.3% undivided interest in Chesapeake’s 800,000 net oil and natural gas leasehold acres in the DJ and Powder River basins. The consideration for the transaction will be $570 million in cash at closing. In addition, CNOOC has agreed to fund 66.7% of Chesapeake’s share of drilling and completion costs until an additional $697 million has been paid, which Chesapeake expects to occur by year-end 2014. The transaction is expected to close in the first quarter of 2011. As the operator of the project, Chesapeake will conduct all leasing, drilling, completion, operations, and marketing activities for the project. Chesapeake is currently operating 16 producing wells in the DJ and Powder River basins that have reached initial production rates of up to 1,000 barrels of oil and 3.0 million cubic feet of natural gas per day. Over the next several decades, the companies plan to develop net unrisked unproved resource potential up to 5.0
billion barrels of oil equivalent (after deducting an assumed average royalty burden of 20%). Chesapeake is currently utilizing five operated rigs to develop its DJ and Powder River basins leasehold and with the additional capital investment from CNOOC, anticipates increasing its drilling activities to approximately 10 rigs by year-end 2011 and 20 rigs by yearend 2012. CNOOC will have the option to acquire a 33.3% share of any additional acreage acquired by Chesapeake in the area and the option to participate with Chesapeake for a 33.3% interest in midstream infrastructure related to production generated from the assets. Chesapeake’s advisor on the transaction was Jefferies & Company Inc., and CNOOC Limited’s advisor was Tudor, Pickering, Holt & Co. Securities Inc. In another deal involving shale assets, the UK’s BG Group paid Dallas-based EXCO Resources $230 million for a 50% stake in oil and natural gas assets in the Marcellus shale development that EXCO recently purchased from Chief Oil & Gas LLC and other parties. OGFJ
Proved Reserve Value ($MM)
Non Proved Reserve Value ($MM)
Reserves (MMBoe)
Production (Boe/D)
Reserves ($/Boe)
Production ($/Boe/d)
Reserves ($/Mcfe)
Production ($/Mcfe/d)
—
230.0
NA
NA
NA
NA
NA
NA
10.0
—
NA
90
NA
111,111
NA
18,519
—
1,267.0
NA
NA
NA
NA
NA
NA
—
5.7
NA
NA
NA
NA
NA
NA
95.0
—
NA
1,837
NA
51,724
NA
8,621
9.9
—
3.6
378
2.75
26,190
0.46
4,365
—
0.1
NA
NA
NA
NA
NA
NA
21.7
—
1.4
NA
15.78
NA
2.63
NA
$9.27 $9.27
$51,724 $63,009
$1.54 $1.54
$8,621 $10,501
Reserves ($/Boe)
Production ($/Boe/d)
Reserves ($/Mcfe)
Production ($/Mcfe/d)
Median Mean
Number of Transactions 8
Proved Reserve Value ($MM)
Non Proved Reserve Value ($MM)
Reserves (MMBoe)
Production (Boe/D)
61.5
—
NA
NA
NA
NA
NA
NA
4,300.0
1,100.0
166.7
42,500
25.80
101,176
4.30
16,863
70.0
—
NA
NA
NA
NA
NA
NA
5.9
—
NA
NA
NA
NA
NA
NA
271.0
56.0
NA
NA
NA
NA
NA
NA
5.0
—
NA
NA
NA
NA
NA
NA
$25.80 $25.80
$101,176 $101,176
$4.30 $4.30
$16,863 $16,863
Number of Transactions 6
Median Mean
March 2011 Oil & Gas Financial Journal • www.ogfj.com
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Industry Briefs ConocoPhillips to focus 2011 spending on upstream ConocoPhillips has approved a 2011 capital program of $13.5 billion. Almost 90% of the capital program will be in support of exploration and production, while the refining and marketing segment represents about 9%. The 2011 capital program for E&P is approximately $12 billion, including capitalized interest of $0.4 billion and $0.7 billion for the company’s contributions to the FCCL business venture and loans to other affiliates. This program also includes about $1.7 billion for worldwide exploration. In North America, the capital program is expected to total approximately $6 billion. Spending in North America is increased, compared with prior years, with emphasis on liquids-rich resource plays and highest-return investments. In the US Lower 48, funding will be focused on the Eagle Ford and other liquidsrich plays in the Permian, Bakken and Barnett Fields. Spending in Canada will focus on existing SAGD oil sands projects and selective programs in the Western Canada gas basins, primarily on high-graded resource plays and on maintaining a substantial position for future development. Spending in Alaska is expected to be directed toward development of the existing Prudhoe Bay and Kuparuk Fields, as well as the Western North Slope. In Europe, Asia Pacific and Africa, the E&P capital program is expected to total about $6 billion.
EnCap raises $3.5B fund for upstream sector EnCap Investments LP has closed EnCap Energy Capital Fund VIII LP with $3.5 billion of limited partner capital commitments. Fund VIII provides growth capital to proven management teams focused primarily on the upstream sector of the oil and gas industry in North America. EnCap is led by the firm’s four managing partners, David B. Miller, Gary 42
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R. Petersen, D. Martin Phillips and Robert L. Zorich. Since its inception in 1988, EnCap has managed approximately $11 billion of capital commitments. To date, EnCap has committed approximately $700 million to six portfolio companies in Fund VIII, including Common Resources II, Lone Star II, Caiman Energy, Talon Oil & Gas II, Eclipse Resources and Venado Oil & Gas.
Wood Group to sell Well Support Division for $2.8B International energy services company Wood Group has entered into a conditional agreement to sell its Well Support Division to GE for cash consideration of $2.8 billion. Following the sale, the board intends that Wood Group will return cash of not less than $1.7 billion to shareholders. For the year ended December 31, the Well Support Division had revenues of $947.1 million, EBITDA of $165.9 million and EBITA of $128.1 million. At December 31 it had gross assets of $604.7 million. The sale, coupled with the December 2010 acquisition of PSN Ltd. for an enterprise value of US$95 million, is part of Wood Group’s strategy to focus on its core engineering and operations and maintenance activities in its Engineering & Production Facilities and Gas Turbine Services divisions. The transaction is expected to close by the end of Q211.
Encana establishes $5.4B JV with PetroChina Calgary-based Encana Corp. has signed a cooperation agreement with PetroChina International Investment Co. Ltd. that would see PetroChina pay C$5.4 billion to acquire a 50% interest in Encana’s Cutbank Ridge business assets in British Columbia and Alberta. Under the agreement, the two companies would establish a 50/50 joint venture that would ambitiously grow natural gas production from assets for years ahead. The
50% interest represents current daily production of about 255 MMcfe/d, proved reserves of about 1 tcfe, and about 635,000 net acres of land. The planned JV infrastructure, on a 100% basis, includes about 700 MMcfe/d of processing capacity, about 3,400 kilometres (about 2113 miles) of pipelines and the Hythe natural gas storage facility. Under the JV, each company would contribute 50/50 to future development capital requirements. Encana will initially operate the joint venture’s assets and market the production. Following the completion of the transaction, the JV would operate under the direction of a joint management committee. The transaction is subject to regulatory approval by Canadian and Chinese authorities, due diligence, and the negotiation and execution of various transaction agreements. RBC Capital Markets and Jefferies & Co. Inc. are acting as financial advisors to Encana. Burnet, Duckworth & Palmer LLP is acting as legal advisor to Encana.
Transzap awarded sixth SAS 70 Type II certification Transzap Inc., the parent company of Oildex, an energy industry provider of eRevenue, ePayables and eBudgeting, software-as-a-service (SaaS) solutions, has achieved SAS 70 Type II certification for the sixth consecutive year, for its design and execution of operational controls. Completing the SAS 70 Type II audit provides customers and auditors with the assurance that necessary controls and procedures are in place to manage and safeguard data.
Marathon sets $5.267 budget for 2011 Marathon Oil Corp. has set its 2011 capital, investment, and exploration budget at $5.267 billion for 2011, consistent with prior guidance and a 9% increase from 2010 capital spending. The company will focus on “more scalable and lower-risk
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Industry Briefs activities, largely aimed at liquids rich opportunities such as the Bakken, Anadarko Woodford, Eagle Ford and Niobrara resource plays in the US,” said Clarence P. Cazalot, Jr., Marathon president and CEO. Oil projects are expected to make up more than 80% of the upstream budget. Total planned capital spending in the upstream segments is roughly $3.7 billion or 71% of total spending for 2011. This upstream program includes spending of $1.3 billion on base assets ($1 billion on E&P base and $300 million on Oil Sands Mining and Integrated Gas), $1.9 billion on growth assets such as liquids resource plays in the US, and $465 million specifically for impact exploration. Marathon’s 2011 worldwide E&P budget of approximately $3.4 billion reflects an increase of 29% over 2010 capital spending.
Voyager Oil & Gas prices $50M private placement Billings, Montana-based Voyager Oil & Gas Inc. has priced a private placement pursuant to which certain accredited investors have agreed to purchase 12,500,000 units at a price of $4.00 per unit for gross proceeds of roughly $50 million. Each unit will consist of one common share and one-half warrant to purchase one common share. The warrants, which represent the right to acquire up to an aggregate of 6,250,000 common shares, will be exercisable within the 5-year anniversary of the closing date of the private placement. The warrant exercise price of $7.10 per share is 150% of the average closing price of the company’s common shares for the five days ended January 31. Canaccord Genuity Inc. acted as the lead placement agent. Rodman & Renshaw LLC, Dougherty & Co. LLC, CK Cooper & Co. Inc., Wunderlich Securities Inc., Global Hunter Securities LLC, and Feltl and Co. acted as co-placement agents.
Eagle Ford Gathering enters agreement Anadarko Eagle Ford Gathering LLC, a joint venture between Kinder Morgan Energy Partners LP and Copano Energy LLC, have executed a definitive long-term agreement to provide natural gas gathering, transportation, processing and fractionation services to Anadarko E&P Co. LP in the Eagle Ford Shale. In December, OGFJ spoke with Kinder Morgan’s president, Park Shaper. Shaper noted the company’s involvement in various shale plays. “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.” Eagle Ford Gathering’s previously announced 30-inch pipeline in the western Eagle Ford Shale play is under construction and is expected to begin service in the 3Q11. After fully subscribing its initial capacity of 375,000 MMbtu per day, the JV recently announced plans to construct 74 miles of additional pipelines that will enable it to deliver natural gas to Formosa Hydrocarbons Co. for processing. The additional pipelines, which are expected to be completed by year end, will enable the joint venture to more fully utilize the 600 MMcf per day capacity of its 30-inch pipeline.
Chesapeake to sell Fayetteville assets Oklahoma City-based Chesapeake Energy Corp. said Feb. 7 that it will sell all of its Fayetteville Shale assets, as well as its equity investments in Frac Tech Holdings LLC and Chaparral Energy Inc. If completed, Chesapeake anticipates that the combined pre-tax proceeds could exceed $5 billion. In the Fayetteville, the company is the second-largest producer of natural gas with current net
production of roughly 415 million cubic feet of natural gas equivalent production per day. The company owns about 487,000 net acres of leasehold. Chesapeake owns 25.8% of Frac Tech and 20% of Chaparral. In light of Chesapeake’s plan to reduce its long-term debt by 25% in 201112, the company plans to use the net proceeds from these sales and its previously announced Niobrara joint venture to retire nearly $2 billion to $3 billion of its shorter-dated senior notes and to also reduce borrowings under its revolving bank credit facility.
Hercules to buy 20 Seahawk rigs, assets Hercules Offshore has agreed to purchase 20 rigs and related assets from Seahawk Drilling and its affiliates for roughly 22.3 million shares of Hercules common stock and cash consideration of $25 million, which will be used primarily to pay off Seahawk’s Debtor-in-Possession loan, which it secured in connection with its bankruptcy filing to support the business and provide liquidity prior to the closing of the transaction. The amount of Hercules shares issued will be proportionally reduced at closing, based on a fixed price of $3.36 per share, if the outstanding amount of the DIP loan exceeds $25 million, with the total cash consideration not to exceed $45 million. The assets to be acquired will consist of 20 jackup rigs located in the US Gulf of Mexico and related equipment, accounts receivable, cash and contractual rights. Assumed liabilities will be limited to specific items, such as accounts payable, with all other liabilities retained by Seahawk. Closing is subject to bankruptcy court approval, Hercules Offshore lender approval, as well as regulatory approvals and other conditions. Jefferies & Co. provided a fairness opinion to Hercules, and Andrews Kurth LLP and Thompson & Knight LLP acted as legal advisers to Hercules for this transaction.
March 2011 Oil & Gas Financial Journal • www.ogfj.com
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Energy Players Newport succeeds Atencio as Mainland Resources CEO Houston-based Mainland Resources Inc. has promoted Michael J. Newport to the position of CEO and director of the company. Nick Atencio has tendered his resignation Newport as CEO and as a director of the board, but will continue to serve the company as a technical consultant. Newport has served Mainland since 2007 as president. He started his career with Amoco in 1979. He joined Greenhill Petroleum in 1989 as land manager for Permian Basin Region operations. Newport also spent 13 years managing brokers for West Texas, South Texas, East Texas, Oklahoma, Mississippi, Alabama and North Louisiana, as well as performing all land management activities for various operators actively drilling and completing wells in these areas. He received a bachelor’s degree, an MBA, and completed hours for a Petroleum Land Management degree, all from the University of Oklahoma.
consulting, Wright served in management roles for Exxon at its UK refinery at Fawley during a 15-year career. Wright is a chartered engineer and holds a bachelor’s degree from Imperial College London. Anness joined Solomon Associates in 1990. Prior to Solomon Associates, he spent nearly two decades with Amoco Corp.
United Vision Logistics promotes Hoffmann to CEO Transportation and logistics services provider United Vision Logistics has promoted Howard Hoffmann to CEO. Since Jan. 1, Hoffmann has served Hoffmann as the company’s interim CEO. Prior to 2011, he served as the company’s chief integration officer, overseeing the integration and rebranding of four legacy companies into one entity, United Vision Logistics. Hoffman brings more than 30 years of financial, operational and general management experience in a wide range of industries. He previously served as CEO of MedQuist Inc. and interim CEO of Global Knowledge Network Inc.
Wright promoted to VP, Europe and Middle East ops for Solomon Associates Apache elects Joung, Josey Stephen Wright has to board of directors been named vice president of Europe and Middle East Operations for Solomon Associates, effective April 1. He replaces Lawrence Anness, Wright who will retire after a 20 year career with the global energy consulting company. Wright joined Solomon Associates in January 2010 as senior consultant in the company’s UK office. Before Solomon Associates, Wright served as vice president of process consulting in Europe, the Middle East and Africa for KBC Process Technology Ltd. Prior to 44
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Apache Corp. has elected Chansoo Joung, a senior advisor at Warburg Pincus LLC, and Scott Josey, former chairman and CEO of Mariner Energy, to its board Josey of directors. Joung, who joined Warburg Pincus in 2005, provides advice on new and existing investments in the energy sector for the firm. Previously, he was an investment banker at Goldman Sachs for nearly 18 years. Josey served as the chairman of the board and CEO of Mariner Energy from August
2001 until November 2010, when it merged with Apache. Previously, he served as vice president of Enron North America and co-managed its Energy Capital Resources group. He was also a co-founder of Sagestone Capital Partners, and was a director with Enron Capital & Trade Resources Corp. in its energy investment group. Before that, he worked at Texas Oil and Gas Corp.
MicroSeismic makes executive changes Geophysical service company MicroSeismic Inc. (MSI), has promoted Michael Thornton to chief technology officer. Thornton previThorton ously served as vice president of analysis. Chief geophysicist, Michael Mueller, will succeed him becoming vice president, analysis, leading delivery of all comMueller mercial geophysical services as well as IT infrastructure worldwide. Thornton obtained his PhD from the University of Houston and his master’s degree and bachelor’s degree from Texas A&M University. He has 17 years of experience in the oil and gas industry, having spent six years in management at Veritas DGC as imaging director. Prior, he spent 11 years at ExxonMobil. Mueller’s experience in geoscience technology research and development, with a focus on multicomponent seismic and seismic anisotropy spans almost 30 years. He delivered the first application of the ocean bottom seismic method at Azeri field in the South Caspian Sea and co-invented the dipole sonic shear anisotropy logging application. He led a McKinsey and Co. study on technology, strategy and governance helping to develop and execute the strategic
www.ogfj.com • Oil & Gas Financial Journal March 2011
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Energy Players plan for unconventional gas resource progression and reserves production in North America for BP. He earned a bachelor’s degree from Binghamton University and a master’s degree ifrom the University of Houston.
Transocean names Deeming senior VP, general counsel
president of Geographix (a Landmark/Halliburton company), CEO of Photometrics Ltd., and GM/VP at IHS, where he was responsible for creating a new Global Energy Product Group. Stevenson holds an MBA and a bachelor’s degree from Dartmouth College.
with a bachelor’s degree in economics. He also served as a Lieutenant in the United States Army, First Calvary Division.
Hunton & Williams adds Simpson in London
Law firm Hunton & Williams has added Jonathan G. Simpson as a Transocean Ltd. has appointed Nick Guerrerio named VP, partner in its London office. Simpson Deeming as senior vice president, CFO of Merichem is the eighth partner within the past general counsel and assistant corMerichem Co. has appointed Richard year to join the firm’s energy and inporate secretary. Eric B. Brown, J. Guerrerio vice president and CFO. frastructure practice. Simpson comes currently in that role, will transition Guerrerio replaces Bruce Upshaw, to the firm from Paul, Hastings, to the company’s Houston office, senior vice president and CFO, who Janofsky & Walker LLP, where he was primarily leading the company’s will retire effective March 31. Guerhead of its European projects group. Macondo litigation efforts. Deeming rerio has over 38 years of experiSimpson has significant experience most recently served as group general ence in the mining, manufacturing, advising governments, leading multicounsel and company secretary of engineering support, chemical and national sponsors and leading finanChristie’s. Prior, Deeming served as petrochemical industries. Prior to cial institutions with project developthe chief legal officer of Linde Group joining Merichem, Guerrerio held ment and project finance transactions AG. similar positions with several compain Europe, the Americas, the Middle nies, including Vopak North America, East, Africa and Asia in several sectors including infrastructure (including ANGA appoints Banaszak Mettler-Toledo and SGS. He began VP, chief economist his career as a staff auditor with Coo- PPP), power and renewables, oil, gas, petrochemicals, mining and minerals. America’s Natural Gas Alliance pers and Lybrand. Guerrerio holds Most recently, he has advised on the (ANGA) has named Sara Banaszak as a bachelor’s degree from Fordham University and MBA studies at Iona $15 billion Southstream Gas Pipeline vice president and chief economist. Project; he advised the Republic of Banaszak joins ANGA after spending College. Merichem licenses patented Srpska on its €3.5 billion concession process technologies and supplies six years at the American Petroleum Institute as senior economist. Prior to proprietary equipment to provide hy- motorway program; he advised on the restructuring of the Croatian gas drocarbon treating solutions and byAPI, Banaszak worked for PFC Enmarket; and he advised on one of the ergy; the US Department of Energy’s product management services to the largest-ever sovereign debt deals in Office of Fossil Energy; and at the US upstream and downstream sectors. Albania. Energy Information Administration. She graduated cum laude from the Madison Williams names University of Pennsylvania, holds a Coppola managing director Morris joins Capstone Investment banking firm Madison master’s degree from the University Advisory Group of Hawaii, and is pursuing her PhD at Williams and Co. has hired Paul Cop- Brian Morris has joined the Chicago pola as managing director and senior office of Capstone Advisory Group George Washington University. energy specialist, institutional equity LLC as a managing director. Prior to TerraSpark Geosciences sales and trading. He will be based in joining Capstone, Morris spent more names Stevenson COO the Houston office. Prior to jointhan 10 years with KPMG, most Software solutions and consulting ser- ing Madison Williams, Coppola was recently as a managing director in vices provider TerraSpark Geosciences a portfolio manager at Arrowhawk the Economic and Valuation Services LLC has appointed Robert Stevenson Capital Partners and Satellite Asset Group. Before KPMG, he spent sevas COO. Stevenson joins TerraSpark Management, covering integrated eral years employed in the corporate with over 30 years of management oils, refiners, oil service, and explora- finance and strategic planning group and engineering experience in several tion and production companies. He of a start-up telecommunications industries including energy, software spent 12 years at Morgan Stanley & company. He holds an MBA from and imaging systems, and manageCo., most recently as executive direc- the University of Chicago Graduate ment consulting. Previously he served tor, global energy specialist. Coppola School of Business and a bachelor’s as CEO of Translation Technologies, graduated from Fordham University degree from DePaul University. March 2011 Oil & Gas Financial Journal • www.ogfj.com
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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
AAPL
31
EnCana Corp.
API
18
EnCap Investments LP
Altira Group
6
F
Company/Advertiser Index PAGE 40,42
COMPANY
PAGE
COMPANY
PAGE
Marine Well Containment Co.
16
SGS
45
42
Mariner Energy
44
Sagestone Capital Partners
44
Energy Capital Management
6
Mayer Brown
20
Sapient
32
America’s Natural Gas Alliance
45
Energy Ventures
6
McKinsey and Co.
44
Satellite Asset Management
45
American Petroleum Institute
45
Enertia Software
IFC
MedQuist Inc.
44
Seahawk Drilling
Amoco Corp.
44
Enron
44
Merichem Co.
45
Shell
Anadarko E&P Co. LP
43
Ensco plc
10
Mettler-Toledo
45
Shoaibi Group
Andrews Kurth LLP
43
Epi-V
MicroSeismic Inc.
44
Solomon Associates
Apache Corp.
44
EXCO Resources
Microsoft
36
Statoil
Arrowhawk Capital Partners
45
Evaluate Energy
Minerals Management Service
14
Suncor
Baker & McKenzie LLP
11
ExxonMobil
38,44,48
Mitsui
20
Talisman Energy
39
Baker Botts LLP
11
Feltl and Co.
43
Mobil Australia Resources Co. Pty Ltd.
10
Talon Oil & Gas II
42
Baker Institute for Public Policy
14
Forest Oil
39
Morgan Stanley & Co.
45
Teach for America
48
BG Group
41
Formosa Hydrocarbons Co.
43
NOIA
18
TerraSpark Geosciences LLC
45
BOEMRE
13
Frac Tech Holdings LLC
43
Natural Gas Partners
Texas Oil and Gas Corp.
44
The American Energy Innovation Council
36
The American Enterprise Institute
36
BP
10,13,38,45
GDF Suez
6 41 5
5
Noble Corp.
Breakthrough Institute
36
GE
42
Noble Royalties Inc.
Brookings Institution
36
Gastem
39
NuTech Energy Alliance
Burnet, Duckworth & Palmer LLP
42
Gazprom
5,21
Business Wire
16
General Electric
43
CK Cooper & Co. Inc. CNOOC Ltd.
20,40
BC 14 IBC 23
43 5,10,18,38 6 44 5,11,20 5
The President’s Council of Advisors on Science and
OMV
5
Technology
36
36
OTM Consulting
6
Thompson & Knight LLP
43
Geographix
45
Occidental Petroleum
5
Total
Global Hunter Securities LLC
43
Oildex
44
Oiltech Investment Network
37,42 6
5,20
Translation Technologies
45
Transocean Ltd.
45
Caiman Energy
42
Global Knowledge Network Inc.
Canaccord Genuity Inc.
43
Goldman, Sachs & Co.
Transzap Inc.
42
Canbriam Energy
39
Greater Houston Partnership
16
PLS Inc.
7
Tudor, Pickering, Holt & Co. Securities Inc.
41
Capstone Advisory Group LLC
45
Greenhill Petroleum
44
Paul, Hastings, Janofsky & Walker LLP
45
Union Bank
Chaparral Energy Inc.
43
HESS
Chesapeake Energy Corp. Chevron Corp.
39,40,43 6,10,13,38
Helix Corp. Hercules Offshore
10,44
5
P2 Energy Solutions
PennWell Corp.
18 13,43
Chief Oil & Gas LLC
41
Houston Business Journal
18
Citibank NA
10
Houston Technology Center
6
Citizens for Affordable Energy
18
Hunton & Williams
42
IHS
45
15
3
United Vision Logistics
44
MAPSearch
35
US Coast Guard
18,24
Oil Sands and Heavy Oil Technologies
27
US Department of Energy
36,45
PennEnergy
46
US Department of the Interior
14
11
US Energy Information Administration
45 9
Petoro PetroChina Co. Ltd.
40,42
Varel International
PFC Energy
16,45
Venado Oil & Gas
42
IPAA
18
Photometrics Ltd.
45
Veritas DGC
44
39
Institute for 21st Century Energy
16
Pride International Inc.
10
Viking Venture
43
Investinor
Quantum
39
Vopak North America
45
Crédit Agricole
19
Jefferies & Co. Inc.
Questerre Energy
39
Voyager Oil & Gas Inc.
43
Deutsche Bank Securities Inc.
10
KBC Process Technology Ltd.
44
RBC Capital Markets
42
Wachtell, Lipton, Rosen & Katz
11
Devon Energy
22
KPMG
45
RWE-DEA
Warburg Pincus LLC
44
Dickstein Shapiro LLP
24
Kinder Morgan Energy Partners LP
43
Range Resources
Westney Consulting Group
28
Dominion Resources Inc.
39
Lime Rock Partners
Dougherty & Co. LLC
43
Linde Group AG
45
Repsol-YPF
DrillingInfo Energy Services Group
17
Lone Star II
42
Research Triangle Solar Fuels Institute
36
Woodside Petroleum
Common Resources II ConocoPhillips
5,38,42
Consol Energy Copano Energy LLC
ENI
16,40,45
6 10,39,41
6
Reliance Industries Ltd.
5 21
6
10,20
Wintershall
5
5
Wood Group
42 5
5
Madison Williams and Co.
45
Rodman & Renshaw LLC
43
Wunderlich Securities Inc.
43
Eagle Ford Gathering LLC
43
Mainland Resources Inc.
44
Rosneft
10
YPE
25
Eclipse Resources
42
Marathon Oil Corp.
5,42
SEP
6
March 2011 Oil & Gas Financial Journal • www.ogfj.com
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Beyond the Well
ExxonMobil grant helpsrecruit math, science teachers to Houston Teach For America-Houston details what the grant means to the program. “ExxonMobil’s grant will help recruit Mikaila Adams Associate Editor – OGFJ and train talented math and science teachers to Houston’s low-income middle schools. From professional development to one-on-one mentoreach For America, a program that ing and more, the training for our brings together recent high-rankteachers will be invaluable to support ing college graduates with lowthem in the classroom.” performing schools in an effort to break As happens too often around the the cycle of educational inequity, is in country, a child’s zip code or family jeopardy due to anticipated state budget cuts in Texas. The ExxonMobil Foundation, as part of its ongoing quest to help advance science and math education, has donated $500,000 to the Teach For America program in four regions across the country to help recruit, train, and support science and math educators. Exxon’s $125,000 grant to Teach For America-Houston was awarded Feb. 8 at Teach For America works to break the HISD’s Dowling Middle School where cycle of educational inequality in a group of 6th grade students received classrooms around the country. a hands-on math lesson from math Photo courtesy of Jean-Christian Bourcart teacher Imani Gooden, herself a Teach For America teacher, and the president of income determines his or her educational ExxonMobil Exploration Co., Stephen outcome. M. Greenlee, a geoscientist. According to the National AssessGooden is among a record 300 new ment of Educational Progress, there is a Teach For America teachers welcomed 27-point gap in math skills between lowinto Houston schools recently. Today, income students and their higher income there are over 500 Teach For America peers in the eighth grade. teachers in Houston classrooms impactFounded by Texas native Wendy Kopp ing more than 38,000 students, includin 1990, Teach For America aims to close ing nearly 14,000 secondary math and that gap. science students in Houston’s highestIndependent research has repeatedly need schools. shown that Teach For America teachers “Innovative and highly skilled math have a positive impact on their students’ and science teachers are vital to the next achievement, particularly in math and generation’s success. Teach For America science. teachers step up to go into schools in In its latest principal survey in Housmost need and help students prepare to ton, 97% of principals report that Teach meet and exceed the challenges of college For America teachers’ training was as and careers that await them,” said Exxon- good or better than other teachers in Mobil’s Greenlee. their school and 96% reported the Teach Terry Bruner, executive director at For America teachers made a positive
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impact in the school environment. In the program, recent college graduates commit to teach for two years in urban and rural public schools and become lifelong leaders in expanding educational opportunity. For their efforts, they are eligible to receive loan forbearance and interest payment on qualified student loans, as well as an education award of $4,725 at the end of each year of service through AmeriCorps, the national service network. Across the country, nearly 8,200 members are teaching in 39 regions while 20,000 Teach For America alumni continue working from inside and outside the field of education for the fundamental changes necessary to ensure educational excellence and equity. In Texas alone, over 1,000 members are teaching some 76,000 students. The ExxonMobil Foundation realizes the wide reaching impact of the program and has offered grants of $1250,000 each to the programs in Dallas, Washington DC, and South Louisiana. “Our corporate, foundation and individual funding partners are particularly important in these difficult economic times and we’re grateful for their continued support,” said Teach for America’s Kaitlin Gastrock. To ensure the program can continue its impact and reach an even greater number of children in Texas, state funding must be maintained at its current level of $8 million over two years. “During these challenging economic times, it’s even more important for states to invest in high-impact programs like Teach For America to ensure that public dollars are going further to create educational opportunity for students,” said Gastrock. And support from corporations, like these from ExxonMobil, is critical. If you’d like to help, or for more information, visit www.teachforamerica.org. OGFJ
www.ogfj.com • Oil & Gas Financial Journal March 2011
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No one values the energy of America like we do.
America is a special place. We consider it a privilege to do business here. Over the last 12 years, Noble has become one of the country’s largest independent oil & gas royalty purchasers. We’re interested in acquiring more. Find out what your royalties are worth. Talk to us.
Cash for current and future cash flow Discreet, Simple, timely closings
Contact Doug Bradley – Senior Vice President, Land & Acquisitions 15601 N. Dallas Parkway, Suite 900, Addison, TX 75001 972.788.5839 |
[email protected] © 2010 Noble Royalties, Inc.
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5VISL9V`HS[PLZ0UJ Committed to being America’s #1 independent royalty purchaser.
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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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