Saudi Aramco plans $125 billion spending spree

Saudi Aramco plans $125 billion spending spree

Apr 26, 2011

Sangim Han

SEOUL // Saudi Aramco, the world's largest oil exporter, will spend about $125 billion (Dh459bn) on projects over the next five years as it seeks to increase refining capacity by 50 per cent, Chief Executive Officer Khalid al-Falih said.

The company wants to boost oil-processing capacity to 6 million barrels a day from the current 4m barrels, Mr al-Falih said in a speech in Seoul today. Aramco is building two plants in the kingdom and is considering a further four "grassroots" facilities, he said. That includes one refinery at Jaizan in Saudi Arabia and possible joint-venture projects in China, Vietnam and Indonesia, he said.

"Saudi Aramco isn't just about petroleum production," he said. "We are also one of the world's largest producers of natural gas, a major player in refining, and we are ramping up our petrochemical activities."

Aramco's domestic and international spending plans include oil exploration and production as well as natural gas, refining and petrochemical facilities, he said. Saudi Arabia plans capital expenditure of more than $450bn in the same period, according to Mr al-Falih.

All 12 members of the Organisation of Petroleum Exporting Countries including Saudi Arabia will need to provide a daily average of 29.8m barrels a day this year to satisfy global requirements, or about 600,000 a day more than they pumped in March, the International Energy Agency said April 12.

Aramco built the world's largest natural gas network about 30 years ago, and doubled its processing capacity.

The company plans to expand the network to exceed 14bn standard-cubic-feet per day of capacity in the next five years when the network will encompass seven world-scale gas plants.

For the expansion, the company continues to make natural gas discoveries in places including the Gulf, while beginning exploration in areas such as the Red Sea and the north-west region of the kingdom.

These activities are adding to the company's reserves of 275 trillion cubic feet, the world's fifth-largest proven holdings of gas, in addition to the world's biggest reserves of conventional crude oil, he estimated.

The company is also expanding its petrochemical capabilities in the kingdom, through a petrochemical project in Jubail with Dow Chemical and a planned expansion of Rabigh Refining & Petrochemicals, its joint venture with Sumitomo Chemical.

Mr Al-Falih said South Korea is now among Saudi Arabia's four largest trading partners.

The country accounts for about a fifth of Saudi Arabia's total petroleum exports, and Aramco supplies 30 per cent of South Korea's crude imports.

Aramco is holding its board meeting for the first time in South Korea this week, Mr al-Falih said.

"The Far East is the destination for two out of every three barrels of crude oil" that Aramco exports, he said.

Aramco owns 35 per cent of S-Oil, South Korea's third- largest refiner that's expanding its processing capacity in Ulsan to more than 650,000 barrels a day.

Export Import Bank of Korea and Korea Trade Insurance each signed a memorandum of understanding with Aramco on possible future project financing, according to the website of the oil and gas producer.

Antrim Reports Year-End 2010 Financial, Operating Results

Antrim Reports Year-End 2010 Financial, Operating Results

Wednesday, March 30, 2011

Antrim Energy Inc.

Antrim released its 2010 year-end financial and operating results. The results include a summary and evaluation of reserves that have been independently assessed by McDaniel & Associates Consultants Ltd. in accordance with the standards specified by National Instrument 51-101.

All financial figures are audited and in US dollars except for quarterly figures which are unaudited.

2010 Highlights:

• Conditional sale and farm-out terms agreed for the UK North Sea Causeway and Fyne Development properties
• Multiple exploration targets identified on Antrim's UK North Sea 25th Round licenses
• Two new UK North Sea licenses awarded in the 26th Seaward Licensing Round
• Terms agreed for Antrim's carried interest through the seismic phase on the Pemba-Zanzibar License in Tanzania
• Argentina 2010 drilling program completed - eight wells cased for production
• Average gas price in Argentina increased 20% to $1.84 per mcf over 2009

2011 Highlights:

• Antrim raised $48.5 million in net proceeds from equity financing to drill exploration targets on the UK North Sea 25th Round licenses
• Current cash position of $75 million and no bank debt

Antrim completed 2010 with a healthy cash position of $25.7 million, no bank debt and proved plus probable reserves of 34.9 million barrels of oil equivalent ("boe"), approximately 6.2% lower than in 2009. Production in Argentina decreased slightly to 1,783 barrels of oil equivalent per day ("boepd") from 1,840 boepd in 2009. Production decreased due to the sale of the Puesto Guardian property in February 2010, partially offset by production from new wells drilled in Tierra del Fuego.

In the United Kingdom, total proved plus probable reserves were 27.7 million boe (net to Antrim) as at December 31, 2010, the same as in 2009. Fyne and Dandy total proved plus probable reserves at December 31, 2010 remained at 17.5 million boe, unchanged from 2009. Two exploration wells are planned for the latter part of 2011 in licences adjacent to Fyne (the "Greater Fyne Area"). The Fyne and Dandy fields represent 50.2% of the Company's total proved plus probable reserves as at December 31, 2010. Causeway total proved plus probable reserves remained at 10.2 million boe (net to Antrim).

In October 2010, Antrim signed an Earn In Agreement ("EIA") with Premier Oil UK Limited ("Premier") to jointly explore development options for Fyne and the Greater Fyne Area located in the UK Central North Sea. Under the terms of the EIA, Premier paid initial consideration of $2 million to Antrim for an option to acquire a 39.9% interest in the UK Continental Shelf ("UKCS") License P077 Block 21/28a (the "Fyne License).

In return, Antrim will receive up to $50 million, less the initial consideration, towards its remaining working interest share of development costs of the Fyne Field. The option to farm-in has not yet been exercised. The UK reserves previously described do not reflect the impact of this transaction as it has not yet closed.

In March 2010, Antrim signed a Conditional Letter Agreement ("CLA") with Valiant Petroleum plc ("Valiant") to sell a 30% interest in UKCS Licenses P201 Block 211/22a South East Area and P1383 Block 211/23d (the "Causeway Licenses"). In return, Antrim will receive up to $21.75 million towards their remaining working interest share of development costs of the Causeway Field. The UK reserves previously described do not reflect the impact of this sale as the transaction has not yet closed.

In Argentina, total proved plus probable reserves in Tierra del Fuego decreased by 22.6% to 7.1 million boe as at December 31, 2010 compared to 9.24 million boe in 2009 (net to Antrim). This reduction was due to 2010 production and the impact of remapping of undeveloped drilling locations in the Los Flamencos gas field following the 2010 drilling campaign.

In Tierra del Fuego, a ten well (net 2.5) development drilling program designed to increase gas and NGL production from the Los Flamencos gas field, commenced in late February 2010 and was completed in December 2010. Eight of the ten wells have been cased as producers and three have been tied in as of December 31, 2010. The remaining five cased wells are expected to be completed and placed on production by the end of the second quarter of 2011.

In December 2010, Antrim signed an agreement with Ras Al Khaimah Gas Tanzania Limited ("RAK Gas") and NOR Energy AS whereby Antrim replaced its previous right to be carried for 30% through the pre-drilling exploration phase of the Pemba-Zanzibar Production Sharing agreement ("P-Z PSA") with a 20% carried interest through the pre-drilling phase and an additional 10% right to participate in the P-Z PSA to be exercised up to 180 days following receipt of the initial drilling results. The carried interests (up to 30%) are to be repaid from future production.

On March 17, 2011, Antrim issued 48,191,700 common shares at a price of Cdn $1.07 per common share for gross proceeds of Cdn $51.6 million (net proceeds Cdn $48.5 million) which included 6,191,700 common shares issued to the underwriters pursuant to the 98.3% exercise of the over-allotment option.

Net proceeds from the equity financing will be used for exploration of the Greater Fyne Area including the "West Teal" Fulmar Prospect at 11,500 feet drilling depth, which contains a discovery well drilled by a previous operator in 1991 that was subsequently abandoned after encountering mechanical problems, and the "Carra" Tay Prospect at 5,000 feet drilling depth.
On March 28, 2011, Antrim announced that it had signed a Letter of Award ("LOA") with AGR Peak Management Limited to drill two wells (the West Teal and Carra Prospects) commencing in the third quarter of 2011. The LOA is for a minimum duration of 50 days.

Reserves Summary

Oil and gas revenue of $12.5 million for the year ended December 31, 2010 decreased from $13.0 million in 2009. Revenue decreased as a result of lower oil production partially offset by higher gas production and by higher oil and gas prices received. Antrim generated cash flow from operations of $1.5 million in 2010 compared to a cash flow from operations deficiency of $1.1 million in 2009. Cash flow increased due to lower operating and general and administrative costs and higher interest and other income offset by lower revenue.

Net production to Antrim in 2010 was 1,783 boepd compared to 1,840 boepd for 2009. For the three month periods ended December 31, 2010 and 2009, net production was 1,757 and 1,990 boepd respectively. Production decreased due to the sale of the Puesto Guardian property in February 2010 partially offset by production from new wells drilled in Tierra del Fuego. All of Antrim's production is based in Argentina.

Expenditures on petroleum and natural gas properties in 2010 were $6.7 million compared to $4.8 million in 2009. The 2010 capital expenditures are net of $2 million received from Premier for the Fyne option. Capital expenditures in 2010 related to the drilling program in Argentina and ongoing development costs on the UK properties.

2011 Outlook

Antrim expects to have a Field Development Plan for Causeway submitted and approved in 2011 for an anticipated production startup in the middle of 2012. Production startup from the Fyne Field is anticipated in the middle of 2013.

In 2011, Antrim will use its strong financial position to take a leading role in the exploration of the Greater Fyne Area. The drilling program is scheduled to begin in the third quarter with a well drilled and tested on the West Teal Prospect (Antrim 100%). The well is expected to take 55 days to drill and test and cost approximately $30 million.

An additional exploration well in the Greater Fyne Area is expected to be drilled on the Carra Prospect. The well is expected to take 19 days to drill, at an estimated cost of $12 million.
An East Fyne appraisal well is scheduled to be drilled on the Fyne Field. This well is intended to de-risk the eastern extent of the Fyne Field and extend the submission deadline of the FDP for Fyne to June 25, 2012.

In Argentina, Antrim's focus will be on the recently acquired Cerro de Los Leones License (Antrim 50.1% and operator) in the Neuquen Basin. A 3-D seismic program is planned to be shot to support the drilling of at least one exploration well on the license in 2011. Cash flow from Antrim's expected 1,800 boepd from Tierra del Fuego will be used to support this exploration program and any new in-country opportunities.

In East Africa, Antrim holds an option to participate up to 30% working interest in an exploration program on the Tanzanian Pemba-Zanzibar License. This region has recently experienced a significant increase in exploration activity, with several major discoveries announced by consortiums led by Anadarko and British Gas. The Pemba-Zanzibar License has been in an effective force majeure for several years. Antrim expects this impasse could be resolved with the recently announced agreement signed with RAK Gas LLC, a UAE-based exploration and production company with interests elsewhere in Tanzania.

Antrim also considers other global exploration opportunities and views its bilateral strategy of balancing longer term and capital-intensive investments in the UK North Sea with shorter investment cycle on-shore exploration and production opportunities as central to its corporate development.

Musings: Are The Shale Resource Estimates Realistic Or Fantasy?

Musings: Are The Shale Resource Estimates Realistic Or Fantasy?

Tuesday, March 29, 2011
Parks Paton Hoepfl & Brown

by  G. Allen Brooks

 

Maybe you've seen the advertisements from various financial newsletters touting the investment potential of companies involved in developing the Bakken oil shale formation that spreads across North Dakota and Montana and into the neighboring Canadian provinces of Saskatchewan and Manitoba. The claims, which several years ago appeared outrageous, of the Bakken containing eight times the amount of oil as in Saudi Arabia or 21-times the reserves held by Kuwait seem less than fantasy today.

These newsletters began trumpeting the financial impact of the Bakken for various oil exploration companies active in the formation following the 2008 U.S. Geological Service (USGS) revised estimate for the basin's reserve potential suggesting it might contain between 3.0-4.3 billion barrels, a 25-fold increase over the organization's prior estimate made in 1995, which said the field might contain 151 million barrels.

The USGS stated that the Bakken formation is estimated to be larger than all other current USGS oil field assessments in the Lower 48. The agency called it the largest "continuous" oil accumulation ever assessed. This means the oil is spread rather evenly across the basin as opposed to being located in discrete deposits. The next largest continuous oil deposit is the Austin Chalk trend stretching from Louisiana to central Texas that is estimated to contain 1.0 billion barrels.

Jeff Hume, president and chief operating officer of Continental Resources was quoted in an article not long ago suggesting that there could be as much as 24 billion barrels of reserves in the Bakken formation.

Exhibit 1.  Bakken Is U.S. Largest Continuous Oil Field

Source:  EIA

The success the domestic exploration and production companies have had in the Bakken has been partially responsible for U.S. oil production growing over the past two years to the highest level in over a decade.

Exhibit 2.  Domestic Oil Production Up Last Two Years

Source:  EIA

North Dakota's oil production reached a peak last November at 356,697 barrels per day from 5,099 producing wells. Over the past three years, monthly oil production in North Dakota has grown by more than 2.5 times. Production is off slightly in January to 342,088 barrels per day from 5,061 wells. While we can't be certain, we suspect the traditionally harsh winter in that region of the country impacts oil production efforts, especially since the infrastructure to produce much of this additional oil has not kept pace with the rising production.

There have been media stories about the dramatic increase in the number of railroad tanker cars hauling Bakken production to refineries. We are also aware of some of the oil making its way by truck across the US-Canadian border to shipping facilities there. All of that will change as new pipelines are constructed.

Exhibit 3.  North Dakota's Oil Production Soaring

Source:  North Dakota Natural Resource Department

More important is the growth in drilling, which will be critical for boosting the state's oil and gas production in the future. The most recent Baker Hughes rig count showed 153 working rigs in North Dakota, more than double the count merely 14 months earlier.

According to Mark Williams, senior vice president of exploration and development for Whiting Petroleum, "All current and planned projects could take us up to 1.1 million barrels a day."

The most important factor in the growth of Bakken oil production has been the application of drilling and well completion techniques learned from drilling the gas shales – horizontal wells with longer lateral sections and a greater number of hydraulic fracturing treatments.  Estimates are that by applying these technologies, Bakken wells that were drilled only a few years ago might produce 100,000-200,000 barrels over their lifetime but are now getting 400,000-700,000 barrels out of the deposits.  Even though the cost to drill and complete these newer wells is greater than for the older wells, the economics of greater production, especially at today's $100 per barrel oil price, are extremely attractive.

Government Tries to Clarify Offshore Drilling Rules

Government Tries to Clarify Offshore Drilling Rules

Tuesday, March 29, 2011
Houston Chronicle

by  Jennifer A. Dlouhy

 

The federal government on Monday issued a five-page memo meant to clarify rules for offshore drilling, in response to oil and gas industry complaints that new mandates imposed since last year's Gulf spill are muddled.

The federal Bureau of Ocean Energy Management, Regulation and Enforcement also said it would reopen a public comment period to help guide the agency's possible rewrite of a drilling safety rule put in place last October.

"Our goal remains the same as it has been from day one: to ensure that offshore operations are conducted as safely as possible," said Michael Bromwich, the bureau's director. "This guidance document gives deep-water drilling operators additional information to help address some of the recurring issues that have been raised in our ongoing discussions with industry."

The document covers several areas but focuses on a major source of industry complaints: confusion about the wording of the October offshore drilling safety rule. That measure adopted two sets of recommended practices for emergency equipment and well design that had been developed by the American Petroleum Institute.

The problem was that instead of rewriting those mandates in their own words, government regulators simply referenced API documents and specified that any time the API recommended practices said "should" it now meant "must" under the interim drilling safety rule.

Industry representatives complained that the changes affected more than 14,000 discretionary provisions in 80 different standards, and in some cases, those new requirements were conflicting.

For instance, API's recommended well construction practices sometimes offer operators an array of options that might make sense, but the language of the rule seemed to make all of those options mandatory.

"There are areas where it says you should do this or you should do that," said Al Reese Jr., the chief operating officer of Houston-based ATP Oil & Gas. "But I can't turn left and turn right at the same time."

His company navigated the process and received a permit to resume a deep-water pro-ject in the Gulf of Mexico.

A positive step

The new guidance document clarifies that operators are allowed to select "any of the appropriate options," without getting special permission from the bureau.

It also suggests that oil and gas companies maintain documentation demonstrating they evaluated the recommended practices, even when the government's rule doesn't make them mandatory.

Erik Milito, the upstream director at the American Petroleum Institute, called the announcement a positive step.

"Ensuring a clear, consistent and efficient process for offshore regulatory requirements and for approvals of permits is a crucial component to steadily increasing offshore production," he said.

'Departure documents'

With Monday's memo, the ocean energy bureau also formalized a process it has used in approving six deep-water drilling projects in the Gulf of Mexico -- "departure documents" that specify how individual operators are not strictly following the API recommended practices incorporated in the drilling safety rule.

The ocean energy bureau said that whenever oil companies intend to deviate from the recommended practices incorporated in the rule, they must get approval to use alternate procedures or equipment.

The bureau said that it is evaluating potential revisions to the drilling safety rule "in light of comments received from the public and other considerations."

The government said that it will reopen the public comment period, probably within a month, giving people another chance to tell the bureau what works and what doesn't.

Any rewrite of the rule would take months, or longer.

Iraq, Shell Resolve Last Obstacle to $12B Gas Deal -Official

Iraq, Shell Resolve Last Obstacle to $12B Gas Deal -Official

Tuesday, March 29, 2011
Dow Jones Newswires

by  Hassan Hafidh

 

The Iraqi Oil Ministry and Shell have removed the last obstacle preventing them from signing a long-awaited $12 billion joint-venture deal, a senior Iraqi oil official said Tuesday.

The main dispute was over the rights of export. Shell, along with its partner Japan's Mitsubishi, wanted to handle exports, while under current Iraqi hydrocarbon laws the Iraqi State Oil Marketing Organization should do so.

"The issue is nearly resolved," Ali H. Khudhier, head of the state-run South Gas Company told Dow Jones Newswires in an interview in his office in Zubair, south of Basra.

"Shell wanted to handle exports, but now it is agreed that SOMO would handle export," he said. Shell, however, has asked for further discussions as it needs to install an export mechanism, he said.

Last week, the energy committee at the Iraqi council of ministers asked the Oil Ministry to review the Shell draft deal which aims to capture and exploit millions of cubic feet a day of gas flared from four super-giant oil fields near Basra.

The gas project is crucial to Baghdad's ambitious oil expansion that will also boost much-needed power generation in Iraq.

"Once the energy committee approves the recent changes, we need to sit with Shell to adjust these changes in the draft contract," Khudhier said. He preferred not to give a specific date for signing the deal, but he said it could happen in a matter of weeks.

The joint venture--Basrah Gas Co, or BGC--will process associated gas produced from three supergiant Iraqi fields--Rumaila, West Qurna 1 and Zubair--all located in Basra. The three fields are being developed by international oil companies.

"We are expecting these three fields to produce up to 3 billion cubic feet a day in the coming six to seven years," Khudhier said.

In total, the three fields are currently producing some 1.05 billion cubic feet a day, but only 450 million cubic feet a day are utilized while the rest is flared, he said.

The project is vital to Shell's strategy of positioning itself as a leading gas supplier and producer in the Middle East. After domestic needs are met, an LNG terminal will be built in the Gulf to handle the export of 600 million cubic feet a day.

"The extra gas will be exported to East Asia and Gulf states including Kuwait and the United Arab Emirates," Khudhier said.
He also said Iraq could revive a disused pipeline to export gas to Kuwait. "If the Kuwaitis want to import gas from us, we are ready to supply them," he said. Iraq used to export an average of 200 million cubic feet a day gas to neighboring Kuwait, but sales were suspended when Iraq invaded its neighbor in 1990.

Iraq is home to 126 trillion cubic feet of gas, but produces only around 1.5 billion cubic feet a day--of which 700 million cubic feet a day are burned for lack of infrastructure.

Keppel Delivers Rig Four Months Ahead of Schedule

Keppel Delivers Rig Four Months Ahead of Schedule

Tuesday, March 29, 2011
Keppel Corp. Ltd.

Keppel FELS has delivered Alpha Star, the second of two DSSTM 38 semisubmersible rigs, to Brazil's Queiroz Galvão Óleo e Gás (QGOG) four months ahead of schedule and with zero lost time incidents.

This continues Keppel FELS track record of delivering its rigs on time or ahead of schedule. It is the third early delivery this year, following the early delivery of the semisubmersible drilling tender, West Jaya, to Seadrill and of the KFELS N Class rig, Rowan Stavanger, for Rowan Companies.

Mr. Tong Chong Heong, CEO of Keppel Offshore & Marine, said, "This is our second safe and early delivery to QGOG and a sterling record for our company. This outstanding achievement is a demonstration of the great teamwork and synergy we have built with QGOG. It brings to fore the excellence of our efficient processes, project management, innovative methods and the Can-Do spirit which we apply on all our projects.

"We are glad to be able to send Alpha Star off early to contribute to Brazil's exploration and production efforts, enabling QGOG to anticipate its service from Petrobras. Our philosophy is to provide maximum value to our customers and we look forward to supporting QGOG as they expand their foothold in the deepwater drilling segment."

The rig has been chartered by Petrobras for six years to support exploration and production activities offshore Brazil.

Mr. Leduvy Gouvea, Chef Executive Officer of Queiroz Galvão Óleo e Gás said, "With this early delivery, we are able to start work earlier for Petrobras, and reinforce our status as the premier drilling operator in Brazil. We are confident that Alpha Star will be just as successful as its sister rig, the DSSTM 38 Gold Star, which is performing successfully for Petrobras in Brazil.

"Through the various projects we have been working on, they have proven to be an exceptional partner, delivering projects which exceed expectations and enabling us to efficiently serve the fast-growing oil and gas exploration industry. They share our commitment to provide technologically advanced and high quality products to our customers in a reliable and safe manner."

Jointly developed and owned by Keppel's Deepwater Technology Group and Marine Structure Consultants, the DSSTM 38 design is in the league of some of the world's most advanced drilling semisubmersibles.

Designed to maximize uptime with reduced emissions and discharges, a DSSTM 38 rig is well-suited to handle the operational requirements in the deepwater "Golden Triangle" region, which comprises Brazil, Africa and the Gulf of Mexico.

Gauging the Gulf: Anticipated Production Declines

Gauging the Gulf: Anticipated Production Declines

Monday, March 28, 2011
Rigzone Staf
by  Trey Cowan

As of the most recent data provided by the EIA (October 2010), crude oil production coming from the Gulf of Mexico makes up approximately 29% of total U.S. daily production. We would note that this is a drop from the month of May when the Gulf contributed to 31% of all crude production.

In the U.S. Energy Information Administration's July Short-term Energy Outlook, the EIA projected that the moratorium would result in lost production of approximately 82,000 bbl/d on average during 2011 or a cumulative 30 million barrels.

Given how early in the game it was when the government made these projections, we doubt they fully considered how slowly the permitting process would resume once they rescinded the moratorium. Using average decline rates, taking the slow resumption into account, we believe the average lost production in 2011 will approximate 95,700 bbl/d or 35 million barrels in total.

The chart above illustrates that after the hurricanes of 2004 & 2005, it took several years to regain production crippled by the storms. The years 2009 and 2010 benefit from projects started in the previous six years that resulted in Gulf of Mexico production exceeding the prior peak set early in the decade.

The impact from suppressed drilling in the Gulf of Mexico over the next two years will be mitigated by operators exploiting horizontal drilling for oil in regions like the Bakken and Eagle Ford shale. This boost in the lower 48, along with the anticipated declines in production from the gulf, suggests the percentage of production from offshore sources will drop. We are anticipating that the Gulf of Mexico's annual contribution will drop from 30% to approximately 26% in U.S. supplies over the next two years.