Monterey Oil Shale Seen as Next Wave of U.S. E&P Efforts

- Monterey Oil Shale Seen as Next Wave of U.S. E&P Efforts

Friday, August 05, 2011
Rigzone Staff
by Karen Boman

California's Monterey shale oil play could become the next wave of U.S. exploration and production as high oil prices, and the sale of non-core assets by major oil and gas operators, has opened the door for smaller oil and gas companies to pursue the play.

Oil has been produced from the Monterey shale since the early 1900s, but the major oil companies who first explored for oil in California initially focused much of their exploration efforts on the state's heavy oil fields. Drilling wells in the state's heavy oil fields was economic; thus, majors did not have the incentive to explore the deeper Monterey shale with inexpensive oil to develop. The fact that exploration acreage has mostly owned or leased by major oil companies or controlled by government entities meant there was little room for smaller oil and gas companies to enter California.

However, the sale of non-core assets has opened the door for smaller operators to enter the market, and the shift by oil and gas companies towards liquids plays from natural gas due to strong oil prices has prompted companies to pursue emerging oil shale plays.

Early last month, the U.S. Energy Information Administration (EIA) estimated in its report, Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays, that the Monterey/Santos play in southern California holds 15.4 billion barrels of shale resources; the Bakken and Eagle Ford are the next largest shale oil plays at approximately 3.6 billion barrels and 3.4 billion barrels of oil respectively. The Monterey shale is the primary source rock for the conventional oil reservoirs found in the Santa Maria and San Joaquin basins in southern California.

Besides oil prices and sale of non-core assets by majors, the state government's interest in creating jobs and revenue within California also is helping to create an environment conducive for Monterey shale oil development, said Global Hunter Securities analyst Phil McPherson, adding that the governor has increased funding for the state's Division of Oil, Gas and Geothermal Resources and increased the number of permits issued.

The need to reverse the two decades of declining oil production within the state is driving the need for new oil production to be brought online. Enhanced oil recovery techniques are being used at historic fields such as Kern River and Midway set to maintain production, but with a mature basin, there is only so much that can be done, McPherson said. California, the third largest U.S. oil producing state, produced 555,000 b/d of crude oil in February of this year, EIA reports.

As a result of these factors, McPherson sees significant potential in the Monterey shale, and while drilling results have been mixed to date, McPherson notes that the Barnett shale took 15 years to figure out and the Bakken oil play four to five years before drilling efforts found success. "Companies pursuing the Monterey shale are still learning the science and the lay of the land," McPherson said.

Venoco Inc., which has 14 years experience drilling and producing from the Monterey horizon offshore California with its Sockeye and South Ellwood fields, began leasing Monterey shale formation properties onshore in 2006. Venoco Chairman and CEO Tim Marquez said the EIA's report on the Monterey shale confirms much of what the company has said about the Monterey shale potential.

A massive amount of data is available on the Monterey, which has sourced six of the largest U.S. oil fields, with over 17,000 wells having penetrated the Monterey in Venoco's target basins and over 11,000 of those wells tested or produced from the Monterey. The company also has acquired over 1,100 digital logs, with shale-petrophysical analysis on more than 50 of these wells.

Venoco currently is operating one rig in its Monterey shale play and is working to identify and secure up to four additional rigs by year-end 2011. The increase in rigs would be in anticipation of much greater activity in 2012, when the company currently expects it may run six to eight rigs in the play and spud between 50 and 75 primarily vertical wells, as warranted by drilling and production results. The company anticipates that it will spend $100 million, half of its capital budget, on its Monterey shale assets.

Drilling activity next year would be focused on delineation and development wells in the company's Sevier discovery, in the area covered by the company's 3-D seismic shoot with Occidental Petroleum in the San Joaquin Valley and, after completion of an anticipated 3-D seismic survey, in the Salinas Valley. "We are shoring up our development plans for the Sevier discovery and have been in contact with the agencies to ensure we have a clear path forward to develop this discovery," said Marquez. "We currently expect to drill 30 to 40 wells there next year."

Venoco plans to drill three to four additional delineation wells in its Sevier discovery during the second half of 2011. The company also continues to expand its onshore Monterey acreage position, which includes approximately 304,000 gross and 214,000 net acres across the Santa Maria, Salinas Valley and San Joaquin basins, the latter of which includes the Sevier discovery. Venoco has a number of people searching for acquisition and leasing opportunities to acquire additional acreage interest.

Marquez said Venoco has completed and started testing one zone in its Sevier 1-29 sidetrack well during the second quarter. "Because this is a redrill, we have smaller casing in the well which limits our production volumes and presents a challenge to reducing fluid levels. With this constraint, we are encouraged by the peak 24-hour rate of 61 BOE/d from that initial zone. We have two other zones in this well to test once we're finished testing the initial zone."

Venoco has had to revise some of the initial concepts from its Monterey shale production offshore from the Sockeye field, which has two different zones of Monterey that are shallower and less naturally fractured. The company has concluded that drilling vertical wells is a more economic way to tap the Monterey shale and that comes in contact with more gross intervals of oil, said Mike Edwards, vice president of corporate and investor relations at Venoco. Venoco's wells likely will be produced through acidization, in which acid is sent to recover mud from the natural fractures, rather than hydraulic fracturing.

Venoco's current focus is on its Sevier discovery, but the company also sees potential for horizontal wells in its Santa Maria prospect area. The company has drilled vertical wells with initial production rates of 1,000 b/d, and believes that particular zones of the prospect area hold potential for horizontal wells.

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Report: E&P Capital Spending to Rise 12% in 2011

- Report: E&P Capital Spending to Rise 12% in 2011

Tuesday, August 02, 2011
Rigzone Staff
by Karen Boman

Capital spending on exploration and production (E&P) by 139 publicly traded oil and gas companies is expected to rise by 12 percent to $406 billion in 2011. Spending growth this year is largely fueled by strong oil prices and builds on gains of 19 percent in 2010, according to a new report by IHS.

While the increase is less than the 19 percent increase seen last year, oil and gas companies, which spent considerably less during the economic downturn of two years ago, are continuing to increase their upstream portfolio investments, particularly for oil-weighted projects, said Aliza Fan Dutt, senior analyst at IHS and author of the IHS Herold Global E&P CAPEX Review.

"Despite recent volatility and a wobbly economy recovery, oil prices remain relatively strong, which supports higher capital spending. In addition, investments in oil and unconventionals continue at a rapid clip, which conventional gas outlays remain relatively depressed."

The shift to drilling on oil and liquids-rich properties that began in 2010 accelerated through the year and continues today, according to the report. According to Fan Dutt, "those companies that shifted their portfolios earlier will benefit more than those that moved more slowly." Fan Dutt cited EOG Resources as an example of such a company. EOG, a natural gas producer, shifted to the oil side much earlier than most of its peers. AS a result, oil now contributes 60 percent of the company's revenues; EOG is posting strong earnings growth."

"Cost inflation will continue to be a key issue, with more companies competing for oil services and equipment during a time of elevated oil prices," said Fan Dutt. "Cost containment will be particularly important for natural gas-weighted producers as they struggle to achieve strong margins amid weak natural gas prices."

Mid-size U.S. E&P companies should increase spending by 25 percent, while U.S. integrated oil companies are expected to reduce their spending rate to 14 percent this year. However, as a group, integrated oils are planning to continue their massive investments in oil and gas projects worldwide.

Marathon Oil Corp., the most aggressive of the integrated U.S. companies, is ramping up spending by 37 percent as it drills on expanded U.S. acreage in the Anadarko Woodford play, the Niobrara play in the Denver-Julesberg Basin in Colorado and Wyoming and in its Bakken shale position.

The largest North American E&Ps will increase capital outlays by only three percent, which will be buttressed by spending on unconventional resources in shale basins, according to the report. "For example, Pioneer is increasing its spending by 53 percent, with its expansive holdings in the Spraberry field and Eagle Ford shale play, where it was an early entrant."

Global integrated oil companies will continue to make massive investments in oil and gas projects worldwide with a "muted" nine percent spending increase, down slightly from last year. Canadian integrated oil companies are slightly more eager to spend with a planned increase of 13 percent. Husky Energy leads this group with a 44 percent increase on operations mainly in Western Canada and offshore Canada's east coast.

Spending by integrated oil companies outside North America is expected to rise by 13 percent in 2011, the same growth rate seen last year. IHS attributed the increase to strong spending in Latin America and Russia. Colombia's state-owned oil company Colombia will spend 56 percent more this year on top of a 34 percent increase last year. Brazil's state energy company Petrobras also continues to invest heavily on its upstream portfolio with an estimated 24 percent increase. Additionally, Russia's Lukoil is expected to spend 55 percent more this year.

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CAMAC Appoints New CFO, Senior VP of E&P

- CAMAC Appoints New CFO, Senior VP of E&P

Monday, June 06, 2011
CAMAC Energy Inc.

CAMAC announced the appointment of Edward G. Caminos as Senior Vice President and Chief Financial Officer of the Company, effective as of July 1, 2011, and the appointment of Alan W. Halsey as Senior Vice President, Exploration and Production, of the Company, effective as of June 6, 2011.

Mr. Caminos, 48, has been Chief Financial Officer of BPZ Resources since May 2007. From October 2006 until May 2007, Mr. Caminos served as BPZ's Vice President - Finance and Chief Accounting Officer. Mr. Caminos served as BPZ's interim Chief Financial Officer from June 2006 until October 2006 and as Corporate Controller of BPZ from January 2005 until October 2006. During the 15 years prior to joining BPZ, Mr. Caminos gained valuable experience in the energy sector through various managerial level roles including, Director—Financial Reporting for the Americas Division at Duke Energy, Financial Reporting Manager and, prior to its sale, as interim Controller for Reliant Energy Europe Divisions, and Regional Controller – Latin America for the seismic division of Schlumberger. Mr. Caminos began his career with the international accounting firm KPMG Peat Marwick Main.

Mr. Caminos is a Certified Public Accountant and graduated from Bloomsburg University of Pennsylvania, with a Bachelor's degree in Business Administration — Accounting, in 1984.

Mr. Halsey, 61, joined the Company as its Senior Vice President, Exploration & Production, on June 6, 2011. Prior to joining the Company, he managed his private investment interests after leaving Transmeridian Exploration in 2008, where he had served as Vice President and Chief Operating Officer for this company that had producing assets in Kazakhstan and other exploration interests in the former Soviet Union. He joined Transmeridian in 2006 following a short hiatus after taking early retirement from Texaco Inc. in 2002, where he had served for almost 21 years in positions of increasing responsibility that included Chief Petroleum Engineer for Texaco's Latin America/West Africa group in Miami and, most recently, Chairman and Managing Director of the Texaco Upstream Companies in Nigeria. Prior to that time he served as President of Texaco's affiliate in Colombia, South America and as General Manager of Texaco's Angola oil and gas operations. Mr. Halsey graduated from Imperial College of Science and Technology, University of London with a degree in Oil Technology in 1971 and subsequently worked in Latin America, USA and the North Sea before joining Texaco in 1981.

Dr. Kase Lukman Lawal, Chief Executive Officer, Chairman and Director of CAMAC, commented, "We are extremely pleased to welcome both Ed and Alan to their new roles with CAMAC. Their many years of collective experience and leadership in the oil and gas industry will be of great benefit to the new vision for growth of CAMAC."

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White Marlin E&P Adds Executives to Management Team

- White Marlin E&P Adds Executives to Management Team

Friday, June 03, 2011
White Marlin E&P LLC

White Marlin E&P announced the addition of two seasoned oil and gas executives to their management team. Robert (Don) Gray joins the company as Vice President of Land and Louis Romero as Vice President of Exploration. Each executive has over 30 years experience in their respective fields.

Mr. Gray joined White Marlin from Houston based Radiant Oil & Gas where he served as Vice President of Land and Land Manager. Prior to Radiant, Mr. Gray was Land Manager for Americo Energy Resources and Petro-Guard Operating Company. He has also been an Assistant Vice President for Bank One (now JP Morgan Chase), and Manager of the Oil & Gas Division at Capital Financial Group. Additionally, Mr. Gray was president and one of the founders of Sandstone Exploration, Inc., and he has acted as a land management consultant to numerous oil and gas exploration and production companies. He began his career as a Staff Landman with Hunt Oil Company in 1980 after attending the University of Texas in Austin where he majored in Government, accompanied by a minor in Petroleum Land Management. Mr. Gray is a member of the American Association of Professional Landmen and the Houston Association of Landmen.

Mr. Romero is a highly qualified professional geologist with over 30 years of domestic and international oil and gas experience. His background includes prospect generation, screening, and company operations and management for hydrocarbon exploration in many of the basins of North America and internationally in the Far East, South America and Africa. Some of his career accomplishments include significant oil and gas discoveries in the US Gulf Coast as an independent and company affiliated geologist. Louis has led the development of reserve additions totaling over 55 million barrels of oil resulting in $2.7 billion of economic impact. Louis has previously worked with Devon Energy, Ocean Energy (formerly Flores and Rucks), Sandefer Oil and Gas, Crown Central Petroleum, Transco Exploration, and as an independent producer. Louis is a member of AAPG, Houston Geological Society, and the Lafayette Geological Society.

Terry Clark, President and CEO of White Marlin E&P, offered that, "We are proud to have these consummate professionals join our executive leadership. Don Gray and Louis Romero both bring extensive knowledge and experience that will further strengthen our ability to acquire, develop, and operate new properties. Their respective management skills compliment our already strong team, and I am confident that their contributions will accelerate the growth of our business."

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El Paso Sees Great Value in Spinning Off E&P Unit

- El Paso Sees Great Value in Spinning Off E&P Unit

Wednesday, May 25, 2011
Houston Chronicle
by Tom Fowler

Natural gas pipeline giant El Paso Corp. will spin off its growing exploration and production business into a stand-alone public company, a move that has long been anticipated by analysts and investors.

The new company would be a midsize E&P company with significant acreage in a number of shale plays, including the Haynesville gas shales in Louisiana, the Eagle Ford and Wolfcamp oil shales in Texas and Utah's Altamont oil shales.

Following the spinoff, El Paso Corp. will be a natural gas pipeline business with more than 43,000 miles of pipe, midstream processing business and general and limited partner interests in El Paso Pipeline Partners, a public master limited partnership that owns some of the pipeline assets.

The as-yet-unnamed company will be Houston-based with about $4.7 billion in assets. The current head of El Paso Exploration and Production, Brent Smolik, will be CEO. The tax-free spinoff is expected to be completed by year's end.

"We believe that the creation of these two stand-alone public companies will result in significant and sustainable value creation," said Doug Foshee, chairman and chief executive officer of El Paso.

Also on Tuesday, El Paso raised its full-year earnings outlook from the 90-cent to $1.05-per-share range to a range of $1 to $1.10 per share, based largely on its improving E&P business. The 2011 exploration and production budget has also been increased by $300 million to $1.6 billion in order to step up activity on the oil-rich Eagle Ford shale in South Texas.

El Paso was one of several companies that tried its hand at the merchant energy business model in the 1990s -- owning and operating a wide range of assets from pipelines to power plants to energy trading businesses. With the collapse of the biggest of the energy merchants in late 2001, Enron Corp., many of the other companies fell on hard times and had to sell off assets and exit businesses.

In 2003, El Paso went from being involved in around 20 different industries to just two: pipelines and E&P, Foshee said.

"We got down to our core and thought we could be good and competent managers of those two businesses," he said.

Rebuilding came first

The E&P business was tough shape, however, he said, the company as a whole was saddled with a lot of debt and the pipeline business was about to embark on nearly $8 billion in expansion projects.

The idea of a spinoff of the E&P business has been considered for quite some time, but the unit needed to first rebuild itself and the corporation to strengthen its balance sheet, Foshee said in an interview.

The turnaround for E&P between 2007 and the end of 2010 has been strong. From about 3.7 trillion cubic feet equivalent of reserves in 2007, El Paso now has about 8 tcf equivalent, due largely to the unconventional shale plays. Reserve replacement costs have declined from $3.55 per mcf equivalent in 2007 to $1.40 at the end of 2010.

In 2007, 38 percent of the company's reserves were considered oil, but by the end of 2010 it was 48 percent. More than two-thirds of future growth prospects are in the oil area, the company said.

El Paso's exploration business has operations in Brazil and Egypt and some shallow-water Gulf of Mexico holdings, but the bulk of its efforts are focused on onshore unconventional oil and gas.

The company became active in the Haynesville in 2007 when it acquired leases through the acquisition of People's Energy. The company perfected its drilling and production techniques in the Haynesville, driving down costs significantly.

El Paso acquired 138,000 acres in the Wolfcamp play in West Texas and has seven years to assess and develop the field. In the Eagle Ford, El Paso has 170,000 net acres, with about 60 percent of them in areas considered rich with more valuable oil and natural gas liquids.

In Utah's Altamont field, El Paso has about 193,000 net acres. It plans to use enhanced oil recovery techniques, like CO2 injection and infill drilling, to boost production in the coming years.

Shares in El Paso closed up Tuesday $1.24, or almost 7 percent, at $20.22.

Analysts not unanimous

Analysts are not of one mind on an El Paso split. In a research note this week, Tudor Pickering Holt & Co. said it believed the company would be better off focusing on creating cash flow to continue to reduce debt for the next few years before doing a spinoff that would generate relatively little cash.

But Pearce Hammond, director for E&P research for Simmons & Co., said it's a sensible move that will appeal to shareholders.

"I would think they would pick up a number of investors who didn't want a piece of the pipeline business," Hammond said.

El Paso's focus on oil production growth makes sense given how much more oil is getting on the market compared to natural gas, Hammond said.

"But gas will have its day in the sun again," he said. "There seems to be a lot more demand for natural gas in the U.S. in the next decade than for oil."

Copyright (c) 2011, Houston Chronicle

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Tullow Strengthens North Sea Portfolio with Nuon E&P Acquisition

- Tullow Strengthens North Sea Portfolio with Nuon E&P Acquisition

Tuesday, May 24, 2011
Tullow Oil plc

Tullow has entered into an agreement to acquire Nuon Exploration and Production (Nuon E&P) for a cash consideration of €300 million ($421.5 million) from the Vattenfall Group.

The acquisition of Nuon E&P will significantly enhance Tullow's North Sea business adding a portfolio of 25 licenses that include over 30 producing fields, numerous development and exploration opportunities and ownership of key infrastructure. This portfolio will increase the Group's North Sea gas production by 9,000 boepd to approximately 23,000 boepd and add reserves and resources of 28 mmboe.

The Nuon E&P assets are very complementary to the Group's existing Dutch assets and will provide a stronger platform for growth in an area that the Group considers has significant potential. The portfolio includes a number of near term development and exploration opportunities with the potential to sustain and grow production in the short term. The ownership and access to key infrastructure is an excellent strategic fit with Tullow's existing exploration acreage in the area.

The Nuon E&P transaction has an effective date of 1 January 2011 and is expected to complete by July 2011.

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