Caza Spotlights Operational, Financial Results for 2Q11

- Caza Spotlights Operational, Financial Results for 2Q11

Monday, August 15, 2011
Caza O&G Inc.

Caza O&G provided its unaudited financial and operational results for the six months ended June 30, 2011.

Second Quarter Financial Highlights

• Caza's production increased 32% to 18,130 Boe for the three-month period ended June 30, 2011, from 13,712 Boe for the comparative period in 2010. This represents an average daily production rate increase of 48 Boe/d for the three month period ended June 30, 2011, 199 Boe/d as compared to 151 Boe/d for the comparative period. As anticipated, Q2 2011 production was slightly lower than Q1 2011 (which was 23,974 Boe) due to standard production curve declines in certain wells. Recently drilled wells that are in various stages of completion are expected to more than make up for the decline (see "Second Quarter Operational Highlights" below).
• Caza had a cash balance of $24,533,451 as of June 30, 2011, as compared to $9,375,345 at June 30, 2010 and $33,885,900 at December 31, 2010. The increase is attributable to the placing announced on Nov 15 2010. Caza's working capital balance at June 30, 2011, was $20,870,708 as compared to $26,612,514 at March 31, 2011. The decrease in Caza's working capital balance primarily represents the investments made to drill the O.B. Ranch #2 development well in Wharton County, Texas, the Caza Elkins 3401 & 3402 wells in Midland County, Texas, and the Caza 158 #3 in Upton County, Texas.
• Revenues from oil and gas sales increased 112% to $843,836 for the three-month period ended June 30, 2011, up from $398,883 for the comparative period in 2010. The increase in revenues was primarily due to the additional wells brought on since the comparative period. The average combined price received by Caza increased 60% to $46.54 per Boe during the three-month period ended June 30, 2011, from $29.09 per Boe during the comparative period in 2010.
• General and Administrative expenses were $1,435,156 ($1,403,088 net of reimbursements) for the three-month period ended June 30, 2011, as compared to $1,188,962 ($1,078,739 net of reimbursements) for the comparative period in 2010. The change in General and Administrative costs are a result of additional costs incurred and changes in reporting requirements as a result of converting to the International Financial Reporting Standards. During the three month period ended June 30, 2010, the Company received reimbursements that resulted from certain joint venture agreements that provided reductions in overhead costs that expired April 8, 2010.

Second Quarter Operational Highlights

• Drilling commenced on the O.B. Ranch #2 development well in Wharton County, Texas in May 2011. The well reached its target depth of 13,210 feet in June 2011, and electric logs were obtained through the target depth indicating potential pay in the Frio and targeted Cook Mountain formations. The well was fracture stimulated at the end of July 2011, and is currently being flowed back in order to clean up the fracture fluids. The well has been placed on an extended well test, and the market will be updated once stabilized flow rates have been achieved.
• The Caza Elkins 3401 well in Midland County, Texas, reached a total depth of 11,854 feet in June 2011. The rig was immediately moved to the Caza Elkins 3402 location, which reached a total depth of 11,852 feet in July 2011. Log data from both wells indicated multiple potential pay sands for both oil and gas in the Spraberry, Wolfcamp, Strawn, Atoka and Mississippian/Devonian formations. The fracture stimulation program for the Caza Elkins 3401 well began on July 28, 2011. The fracture stimulation program for the Caza Elkins 3402 well began earlier than anticipated on August 12, 2011. Both wells are currently being flowed back in order to clean up the fracture fluids. Caza will update the market once initial flow rates have been established for each well.
• The Caza 158 #3 well on the Windham property reached its target depth of 9,824 feet in June 2011, and Caza elected to participate in the operator's proposal to complete the well. The well has been fracture stimulated across all potentially productive intervals seen on the logs, which include the Spraberry/Wolfcamp, Penn and Strawn formations. The Caza 158 #3 was the fourth well drilled and completed on this property. The Caza 158 #1, 158 #2 and 162 #1 wells are currently at various stages in their respective fracture stimulation programs, but are all producing oil and natural gas.

W. Michael Ford, Chief Executive Officer commented, "I am very pleased with the progress that we have made in 2011, both operationally and from a financial perspective. In the three months to June 30, 2011, Caza has continued to progress a busy work program, which should add further production, reserves and cash flow to the solid platform that we have created through our endeavors to date.

"Revenues have materially risen due to increased oil and gas production levels and a supportive price environment. As we add production through our exploration and development campaign, the Company and the shareholders should continue to benefit.

"I look forward to updating the market on future exploration activities and established flow rates associated with wells that are currently in various stages of completion operations."

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Niko Updates Financial, Operational Results for Year-End

- Niko Updates Financial, Operational Results for Year-End

Wednesday, June 29, 2011
Niko Resources Ltd.

Niko reported its financial and operating results, including consolidated financial statements and notes thereto, as well as its managements' discussion and analysis, for the year ended March 31, 2011. The operating results are effective June 28, 2011. All amounts are in U.S. dollars unless otherwise indicated.

FINANCIAL HIGHLIGHTS

• There was a year-over-year increase of 32 percent in funds from operations.
• In October 2010, Niko repaid all of its outstanding long-term debt.
• At March 31, 2011, the Company's unrestricted cash totaled $108 million.
• In January 2009, the Company announced that the Canadian authorities were engaged in a formal investigation into allegations of improper payments in Bangladesh. The Company cooperated in the investigation, which was concluded on June 24, 2011. The Company pleaded guilty to one count of bribery under the Corruption of Foreign Public Officials Act, was fined Cdn$9.5 million and is subject to a 3-year Probation Order. In early 2009, the Company adopted a full anti-corruption compliance program.

EXPLORATION HIGHLIGHTS

• Indonesia: Four new offshore exploration blocks were added and the Company farmed out 45 percent of its working interest in the Seram and East Bula blocks and 40 percent of its working interest in the North Makassar Strait, West Papua IV and Halmahera-Kofiau blocks. Seismic acquisition activity continued during the year and the planning of drilling has commenced.
• Trinidad: The Company increased its exploration acreage in Trinidad with three new offshore blocks, all of which are in proximity to producing gas fields, and entered into an agreement, which closed subsequent to year-end, to acquire a 25 percent working interest in Block 5(c), located 94 kilometres off the east coast of Trinidad.
• Madagascar: Seismic acquisition has been completed and processing is underway.
• Kurdistan: Drilling was completed to a depth of 3,908 meters in May and testing is underway and expected to continue into July 2011.

PRESIDENT'S REPORT

The Company's strategy of accumulating a highly prospective exploration portfolio continued.

In Indonesia, four new blocks were added and farm-outs occurred in five blocks. Farm-outs are a part of the Company's exploration strategy. Partners in Indonesia now include Exxon/Mobil, Marathon, Repsol and Statoil.

In Trinidad & Tobago, four new blocks were added. Partners in this country include Centrica and RWE.

From a drilling perspective, in Trinidad and Tobago, the Company has contracted an offshore rig that is expected to spud the Company's first offshore well in the country in October. In Indonesia, Niko has established an extremely strong drilling organization staffed with seasoned professionals that bring extensive deep-water drilling experience.

During the past year, uncertainty regarding D6 production, reserves and gas price has been a concern. This uncertainty has been largely removed by an independent reserve report that shows that the revision to the Company's worldwide net proved plus probable reserves was approximately 6.8 percent. Operationally, the D6 field's gross gas production averaged approximately 2 billion cubic feet per day over the year with no downtime.

Due to a pre-emptive right, Niko expects to have the opportunity to increase its net interest by 30 percent in each or all of the D6, NEC-25 and D4 blocks in India. Niko expects this opportunity would be financed with debt.

Niko has a strong production base and an extensive portfolio of exploration prospects. Two thousand and twelve could prove to be Niko's most exciting year ever.

Production from the D6 Block has increased year-over-year and is the primary reason for total production increases of 25 percent compared to production in the prior year. The D6 Block is also the primary reason for improved operating netbacks as the D6 Block has higher realized prices and lower profit petroleum than the average of the Company's other properties.

Gas sales volumes from the D6 Block for the year averaged approximately 198 MMcf/d versus a budget of 210 MMcf/d due to well performance. Current gas sales volumes from the block are approximately 167 MMcf/d. Production from the D6 Block is expected to decline until additional wells are drilled and tied-in.

The Company is forecasting total production of 236 MMcfe/d for Fiscal 2012, which assumes that no additional wells will be tied in at D6 during the year and is consistent with the estimated production from total proved reserves in the Company's reserve report.

Operating cashflow increased in Fiscal 2011 primarily as a result of increased oil and gas sales from the D6 Block. Forecast operating cashflow for the coming year is expected to decrease with the decrease in production described above. In addition, maintenance of the onshore terminal and subsea systems for the D6 Block are expected to result in a decreased operating netback.

Exploration expenditures for Fiscal 2011 were for drilling activities on three exploration wells in the D6 Block, seismic acquisition in Indonesia and Madagascar, drilling of the first exploration well in Kurdistan and seismic on Block 2AB in Trinidad and carrying costs of the Trinidad blocks. Forecast expenditures for Fiscal 2012 include drilling on the D6 and D4 Blocks in India; seismic activity and preparation for drilling activities in Indonesia; completion of drilling the well in Kurdistan, and seismic activity in Trinidad on all blocks and commencement of drilling on Block 2AB.

Development expenditures forecast for Fiscal 2012 are primarily for workovers, drilling new wells and acquisition of compression equipment for the D6 block.

In addition to exploration and development expenditures, the Company's acquisition of Block 5(c), located 94 kilometres off the east coast of Trinidad closed in June 2011 for a purchase price of $78.1 million.

Funds from operations improvements resulted from improved volumes and operating netbacks partially offset by higher current income taxes, higher interest expense related to the Company's convertible debentures, a Cdn$9.5 million (US$9.7 million) fine described previously herein and lower other income as the prior year periods benefited from a favorable arbitration ruling related to a pipeline dispute.

Net income increased year-over-year as a result of the increase in funds from operations. The benefit from improved funds from operations was offset by higher non-cash charges related primarily to depletion and a loss on short-term investments.

Exploration Acreage

Niko has increased its exploration acreage with the addition of three blocks in Trinidad and four blocks in Indonesia. In addition, Niko farmed out 45 percent of its working interest in two blocks in Indonesia to Repsol and 40 percent of its working interest in three blocks in Indonesia to Statoil.

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Africa Oil Reports Operational, Financial Ops for 1Q11

- Africa Oil Reports Operational, Financial Ops for 1Q11

Friday, May 27, 2011
Africa Oil Corp.

Africa Oil announced its financial and operating results for the three months ended March 31, 2011.

Highlights and accomplishments during the first quarter of 2011 included:

• The Company completed the acquisition of Centric Energy Corp. ("Centric"), a publicly traded oil and gas company listed on the TSX Venture Exchange. Total consideration paid was valued at $60.2 million and included the issuance of 30,155,524 AOC common shares. Centric's primary asset is Block 10BA in Kenya which is strategically located within the highly prospective East African Tertiary Rift System between AOC's Block 10BB and its South Omo Block. Centric and Tullow Oil plc ("Tullow") are joint venture partners on the Block 10BA. In addition, Centric also has a carried 25% interest in Block 7 and Block 11, both located in the Republic of Mali and operated by Heritage Oil Corporation.
• Africa Oil entered into amending agreements with the Government of Puntland in the quarter, represented by the Puntland Petroleum and Mineral Agency, in respect of the production sharing agreements ("PSAs") for the Dharoor Valley Exploration Area and the Nugaal Valley Exploration Area. Under the PSAs, as amended, the First Exploration Agreement has been extended for a further 12 months, from January 17, 2011 to January 17, 2012. Under the amended PSAs, AOC is obligated to spud a minimum of one exploratory well in the Dharoor Valley Exploration Area by July 27, 2011. A second exploratory well is required to be spudded in the Nugaal Valley Exploration Area or, at the option of AOC, in the Dharoor Valley Exploration Area, by September 27, 2011. In conjunction with this amendment, the Company completed its farmout agreement with Red Emperor Resources NL ("Red Emperor"). Under the terms of the farmout agreement and an election made by Red Emperor to increase their interests, Red Emperor will earn a 20% interest in both the Dharoor and Nugaal Valley Blocks and is committed to paying a disproportionate share of costs related to the one well drilling commitment included in the first exploration period of both the Dharoor and Nugaal Valley Production Sharing Agreements.
• The Company signed a definitive agreement with Lion Energy Corp. ("Lion"), a publicly traded oil and gas company listed on the TSX Venture Exchange, to acquire all of the issued and outstanding common shares of Lion. Pursuant to the agreement with Lion, AOC will acquire, by way of a plan of arrangement, all of the issued and outstanding shares of Lion in consideration for 0.20 common shares of AOC for each common share of Lion. It is anticipated that 17,233,636 AOC shares will be issued as consideration to acquire Lion. Lion is a joint venture partner of AOC in Kenya and Puntland (Somalia), and currently holds the following working interests; 33.3% in Block 9 (Kenya), 10% in Block 10BB (Kenya), and 15% in each of Dharoor Valley and Nugaal Valley (Puntland). In addition to the above properties, Lion estimated that it had cash, accounts receivable and investments in marketable securities with an approximate aggregate value of CAD$30 million at the date of signing the definitive agreement. A meeting of Lion shareholders, to approve the transaction, is scheduled to be held on June 8, 2011 and, assuming shareholder approval, the transaction is expected to close shortly thereafter.
• Subsequent to the end of the first quarter, Africa Oil entered into a letter of intent for the creation of a new Puntland focused oil exploration company. The new company will be created as a result of the transfer of AOC's interest in its oil and gas properties in Puntland (Somalia) to Denovo Capital Corp. ("Denovo") (the "Transaction"). Denovo is a capital pool company and intends for the Transaction to constitute the "Qualifying Transaction" of Denovo, as that term is defined in the policies of the TSX Venture Exchange. Under the terms of the letter of intent:
  • Africa Oil and Denovo will negotiate and enter into a definitive agreement pursuant to which Africa Oil will transfer to Denovo all of the issued and outstanding shares of its subsidiary holding companies (the "Puntland Subsidiaries") which hold participating interests in the Dharoor Valley and Nugaal Valley Production Sharing Agreements in Puntland (Somalia) (the "Puntland PSAs"). Africa Oil will receive, in consideration of the transfer, 27,777,778 common shares of Denovo. As a result of the Transaction, the Puntland Subsidiaries will become wholly owned subsidiaries of Denovo.
  • Africa Oil currently holds a 45% participating interest in the Puntland PSAs. Upon completion of the transaction for the acquisition of Lion Energy Corp, AOC's participating interest in the Puntland PSAs will be increased, directly or indirectly, to 60%. It is anticipated that the entire 60% participating interest will be transferred to Denovo.
  • The definitive agreement will provide for conditions precedent that are standard for a transaction of this nature, including receipt, by both AOC and Denovo, as required, of all regulatory, partner and third party approvals including TSX Venture Exchange approval. Denovo will also seek Denovo shareholder approval for a proposed 0.65 (new) for 1.00 (old) consolidation of its common shares and a change of name of the company, both of which are conditions precedent to completion of the transaction. It will be a condition precedent of the transaction that Africa Oil will have completed its proposed acquisition of Lion Energy Corp. and that Denovo will have completed a private placement of CAD$35 million comprised of 38,888,889 subscription receipts of Denovo sold at a post-consolidation price of CAD$0.90 per subscription receipt. Each subscription receipt will be exercised, upon completion of the transaction, into a unit of Denovo, comprised of one common share and one share purchase warrant (a "Denovo Warrant"). Each Denovo Warrant will entitle the holder to acquire an additional Denovo share for $1.50 for two years, subject to accelerated exercise provisions if the Denovo shares trade at greater than $2.00 for 10 consecutive trading days. It is anticipated that the definitive agreement will be entered into during the second quarter of 2011.
  • Africa Oil will acquire 11,111,111 subscription receipts in the private placement financing, for proceeds of CAD$10 million. At the conclusion of the Transaction and the private placement financing described above, AOC is anticipated hold approximately 55% (non-diluted) of the issued and outstanding common shares of Denovo. Upon completion of the Transaction it is expected that Denovo will meet the listing requirements of the Exchange for a Tier II Oil and Gas Issuer.
• Africa Oil ended the quarter in a strong financial position with cash of $77.8 million and working capital of $57.2 million as compared to cash of $76.1 million and working capital of $70.6 million at December 31, 2010. The Company's liquidity and capital resource position improved since year end primarily as the result of payments received upon the completion of farmout transactions. Working capital improved $24.4 million subsequent to the end of the quarter as the current portion of the warrant and convertible debenture obligations were settled in shares.
• Africa Oil currently has more than sufficient funds to meet its portion of the $163 million expenditure obligations ($43 million net) as per the active work programs approved by the Company's Board of Directors for 2011. During the first quarter, the Company spent $5.0 million of the 2011 Board of Directors approved $43 million in capital expenditures.
• As of the end of the first quarter, the Company has completed all previously announced farmout transactions with Tullow. Tullow has acquired a 50% interest in, and operatorship of, five of AOC's east African exploration blocks, comprised of four exploration blocks in Kenya and one exploration block in Ethiopia.
• The Company completed the amendment to their farmout agreement with Lion. The amendment reduced Lion's interest in Block 10BB to 10% (originally 20%) and eliminated its interest in Block 10A (originally 25%).
• The Company, together with its joint venture partner Lion, entered into the First Additional Exploration Phase under the Block 9 PSC in Kenya. As a result of the withdrawal of its two other joint venture partners, AOC will now hold a 66.7% working interest in the PSC and has been approved by the government as Operator of Block 9. Lion will hold the remaining 33.3%. The First Additional Exploration Phase commenced on December 31, 2010 and will expire on December 31, 2013 with a one well work commitment (minimum depth 1,500 meters).
• The Company continued to actively explore in East Africa:
  • In Block 10BB, the Company, together with its partners, is currently in the process of undertaking Full Tensor Gravity ("FTG") surveys and finalizing the prospect and lead inventory on Block 10BB. Drilling is scheduled to commence in the third quarter of 2011.
  • In Block 10A, the Company, together with its partners, has completed recording approximately 800km (gross) of 2D seismic. Seismic data acquired is currently being processed. The Company expects to drill a well on this block in the fourth quarter of 2011.
  • In Puntland, the Company has recently signed a letter of intent with a drilling contractor and plans to spud the first well in the Dharoor Block during the third quarter of 2011. A second well in the Dharoor Block is planned to commence following completion of the first exploration well.
  • In Block 9, the Company, together with its partners, has recently commenced 750km (gross) 2D seismic survey focused on the oil prone Kaisut sub-basin. The seismic crew has recently commenced recording and is anticipated to be completed during the third quarter of 2011.
  • The Company completed its seismic acquisition program in the Company's Ogaden area of Ethiopia, acquiring 500 km 2D seismic. The new data has been integrated with existing seismic to generate a series of new prospect maps. The Company continues to focus efforts on the large El Kuran prospect.

Keith Hill, President and CEO, commented, "Africa Oil continued to add highly prospective exploration acreage to its portfolio during the first quarter of 2011. Exploration activities continued throughout the quarter with FTG, 2D seismic and drilling preparations continuing on multiple blocks. The Company is very well financed, has a well diversified exploration portfolio and reputable joint venture partners. We are looking forward to the commencement of continuous drilling in 2011."

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Antrim Reports Financial, Operational Results for 1Q11

- Antrim Reports Financial, Operational Results for 1Q11

Wednesday, May 25, 2011
Antrim Energy Inc.

Antrim reported its financial and operational results for the three month period ended March 31, 2011.

All financial figures are unaudited and in US dollars unless otherwise noted

HIGHLIGHTS:

• Antrim to drill three wells in the UK North Sea
• Joint venture with Premier Oil on the Fyne Field proceeding
• Heads of Terms export agreement signed for Causeway oil production
• Average gas price in Argentina increased 12% to $2.08 per mcf
• Antrim raised Cdn $48.5 million from equity financing
• Current cash position of $76 million and no bank debt

In the first quarter 2011, average production in Argentina was 1,640 barrels of oil equivalent per day ("boepd") compared to 1,835 boepd in the first quarter 2010. The decline in production is attributable to the sale of the Puesto Guardian property in February 2010, as well as scheduled gas plant maintenance and service rig repairs in Tierra del Fuego.

Oil and gas revenue, net of royalties, was $2.4 million for the three months ended March 31, 2011 compared to $2.7 million for the same period in 2010. Net revenue decreased as a result of lower oil and gas sales partially offset by higher oil and gas prices received. Antrim generated cash flow from operations of $0.6 million for the three months ended March 31, 2011 compared to a cash flow deficiency of $0.2 million for the same period in 2010.

Antrim's average gas price for the first quarter of 2011 was $2.08 per mcf compared to $1.85 per mcf for the same period in 2010, a 12% increase. For the first quarter, oil prices averaged $55.00 per barrel compared to $46.54 per barrel for the same period in 2010, an 18% increase.

On April 5, 2011, Antrim announced that a Heads of Terms agreement had been signed for the export of Causeway crude oil to the Cormorant North production platform. The Cormorant North platform is operated by TAQA Bratani Limited and is located approximately 15 km west of the Causeway Field.

On April 4, 2011, Antrim announced that Premier Oil UK Limited ("Premier") had elected to drill the East Fyne well under the Earn-In Agreement ("EIA") previously announced on October 6, 2010. The well is an appraisal well designed to de-risk the eastern extent of the Fyne Field and is expected to be drilled before the end of 2011. Under the terms of the EIA, Antrim will be carried for all development expenses, including the East Fyne drilling costs, up to $50 million.

On March 28, 2011, Antrim announced that it had signed a Letter of Award ("LOA") to provide well project management and drilling services for two wells commencing in the third quarter of 2011.

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 Prospect and either the Carra or Erne Prospects.

OVERVIEW OF OPERATIONS

United Kingdom

Fyne Field

On April 4, 2011, Antrim announced that Premier had elected to drill the East Fyne well in the Fyne Field in P077 Block 21/28a (the "Fyne License") under the

OGX Reports Operational Reports for 2010

OGX Reports Operational Reports for 2010 

Monday, March 28, 2011
OGX S.A.

OGX announced its 2010 results. The following financial and operating information is presented on a consolidated basis, in accordance with the International Financial Reporting Standards (IFRS) issued by the International Accounting Standards Board - IASB, in reais (R$), unless stated otherwise.

"2010 was a year of tremendous achievements for OGX. Our drilling success and identification of extraordinary accumulations in the Campos, Santos and Parnaiba basins validated the geological models developed by our team, revealed the significant potential of our portfolio located mostly in shallow waters, and encouraged the mapping of additional prospects. With 9 drilling rigs now at our disposal, we are also prepared to enter another exploratory cycle in under-explored basins, such as the Espirito Santo and Para-Maranhão, as well as commence seismic studies in five recently-acquired blocks in Colombia," commented Mr. Paulo Mendonça, OGX's General Executive Officer.

"In particular, I would like to highlight our accomplishments in the Campos Basin, where we achieved a success rate of 100% and registered excellent discoveries, most of them located in an extensive carbonate platform, which had its production potential proved through one of the best horizontal well drill-stem tests ever performed in Brazil," added Mr. Mendonça.
"With all necessary equipment already procured from renowned suppliers, the drilling of the first production well and related drill-stem test both completed, we are on track and poised to reach a very important milestone for OGX with the initiation of production in the third quarter of 2011. The successful horizontal well drill-stem test recently performed in Waimea, where we will begin our production, surpassed our expectations. We look forward to conducting the upcoming extended well test, which signals the beginning of production and, ultimately, commercialization of our resources," noted Reinaldo Belotti, Production Officer of OGX. 

2010 Highlights and Subsequent Events

• Drilling of 26 wells during the year of 2010 and 11 in the subsequent months in the Campos, Santos and Parnaíba Basins;
• Confirmed the existence of important oil-bearing regions in the Campos basin: an extensive carbonate platform in the Albian section, as well as important sandstone reservoirs in the Tertiary of the BM-C-41, BM-C-42 and BM-C-43 blocks in the south of the Campos Basin, and another one in BM-C-39 and BM-C-40 blocks, more to the north, with large discoveries in the Santonian, Albian and Albian-Cenomanian sections;
• Performed several drill-stem tests, proving high levels of productivity in several discovered accumulations;
• Concluded the drilling of the first horizontal well (OGX-26HP) of the Waimea accumulation, which tested and confirmed the productive potential of 40,000 barrels per day and productivity index of 100m³/day/kgf/cm² in carbonate reservoirs in the Campos Basin. OGX's production phase will commence at this well through an extended well test (EWT);
• Three discoveries in the Santos Basin, with the identification of liquid hydrocarbons and associated gas;
• Revealed the great hydrocarbon-bearing potential in the Parnaíba Basin with the results obtained in the drilling of the wells OGX-16 and OGX-22, allowing for a volume estimate of potential resources of approximately 15 trillion cubic feet (Tcf) of natural gas in the region;
• Acquired five high-potential exploratory blocks in three onshore basins in Colombia: Cesar-Ranchería, Lower Magdalena Valley and Middle Magdalena Valley Basins;
• Procured all of the essential equipment for beginning production in the Waimea accumulation in the Campos Basin. 

Exploratory Campaign

2010 was a year of extraordinary accomplishments and major achievements for OGX, notable for significant discoveries and the confirmation of the high productivity potential of our main hydrocarbon accumulations. We intensified our exploratory campaign and conducted important drill-stem tests that confirmed the Company's geological model and the potential of the discoveries we have made. These tests yielded fundamental information that provided for a better understanding of the reservoirs that had been discovered in the Campos Basin, allowing us to further enhance the calibration of the production model to be put into place.

At the moment we are drilling the 39th well of OGX, which added to the four other wells drilled by Maersk Oil, bring the total number of wells drilled in the Campos, Santos and Parnaíba Basins to 43 in approximately 18 months since the beginning of our exploratory campaign. Of the 43 total wells, 26 were drilled in 2010, demonstrating the intensification of our activities, and resulting in important discoveries, some of them in areas that until now had been under-explored, including the Parnaíba onshore basin in the interior of the state of Maranhão. These results were made possible due to both a more robust operating structure and the superior geological knowledge that has been acquired about the region. We expanded the number of available drilling rigs from four to nine and now have nearly 5,000 people working on our behalf including outsourced personnel. 

Campos Basin

We ended 2010 with 18 wells drilled in the Campos Basin, all of which identified hydrocarbons, confirming a success rate of 100% in this basin. Of this total, 11 were drilled in the BM-C-41, BM-C-42 and BM-C-43 blocks and allowed for the identification of several accumulations in different geological ages, confirming the presence of a vast oil-bearing province in these blocks. Through the wells OGX-2A, OGX-3, OGX-5, OGX-6, OGX-7A, OGX-8, OGX-10, OGX-15, OGX-20, OGX-21D, OGX-26HP, OGX-28, as well as the MRK-3/4 wells, we have also confirmed the existence of an extensive carbonate platform in the Albian section with great permo-porosity conditions and good quality oil. Moreover, we recorded important discoveries in the Tertiary age and in the Aptian section, reaffirming the enormous potential of the region.

We also began our drilling activities in the blocks BM-C-39 and BM-C-40, located between the Peregrino and Polvo fields, and have obtained excellent results, especially with the OGX-14 (Peró), OGX-18 (Ingá) and OGX-25 (Waikiki) wells. For OGX-14 and OGX-18, drill-stem tests were performed which identified production potential of 3,000 barrels/day using a vertical well for the Peró accumulation that could reach 15,000 barrels/day using a horizontal well, and 8,000 to 12,000 barrels/day through a vertical well at the Ingá accumulation that could reach 25,000-35,000 barrels/day through a horizontal well. The tests also enabled us to measure the quality of the oil at approximately 27° API in each accumulation. Well OGX-25, also known as Waikiki, was an exceptional discovery with the largest detected net pay of approximately 145 meters in the Albian-Cenomanian section.

In addition to the exploratory wells, the first appraisal well for the Waimea accumulation, OGX‐21D (BM-C-41 block) was drilled. It was converted into a horizontal well, OGX-26HP, which extended 1,000 meters within the carbonate reservoirs of the Albian section of the Waimea accumulation, originally discovered by well OGX‐3. The well OGX-26HP, which will be OGX's first production well, was tested and registered a productivity index (PI) of 100m³/day/kgf/cm², one of the highest seen to date in Brazil, as well as a production potential of 40,000 barrels/day and oil gravity of approximately 20° API. This well is currently equipped for an extended well test (EWT) that could record flows of up to 20,000 barrels/day and reach even higher flow levels in a definitive project scenario. The results to date have exceeded initial expectations regarding the Waimea accumulation and offer an even more solid foundation for the initiation of OGX's production phase.

Besides this, two other appraisal wells in the Pipeline (OGX-36D) and Waikiki (OGX-35D) accumulations confirmed their extensions, advancing significantly the delineation of these accumulations, which are respectively located in the southern and northern blocks of the Campos Basin. These directional wells, which were drilled at respective distances of 2.6km and 2.0 km from the wildcat wells, were the pilots for the horizontal wells in these accumulations. Therefore, OGX initiated the drilling of the first horizontal well in the Pipeline accumulation (OGX-39HP) which will be used in the future for production in this area. 

Santos Basin

With respect to the Santos Basin, of particular note was the drilling in the Natal prospect (OGX-11D) in the BM-S-59 block adjacent to the Mexilhão field, which identified liquid hydrocarbons and associated gas in the Santonian section with net pay of around 75 meters. The liquid hydrocarbons proved to be of excellent quality, rated at about 41° API, indicating a higher level of attractiveness of the project. Two other wells registered important discoveries: Belém (OGX-17, with net pay of 43 meters in the Albian section), located in the BM-S-56 block; and Aracajú (OGX-19, with net pay of 40 meters in the Santonian section), located in the BM-S-58 block.

Drilling of the OGX-12 (Niterói), OGX-23 (Ilhéus) and OGX-24 (Itagi) wells has been concluded and resulted in shows of non-commercial hydrocarbons. However, the information acquired through these wells has been of great importance in the calibration of a new geological model for the region. In addition, with the transfer of exploratory rights of the BM-S-29 block from Maersk to OGX, the Company now owns 100% of this block, which is in the evaluation phase. To date, the company's success rate in the Santos Basin has been approximately 60%. 

Parnaíba Basin

In the Parnaíba Basin, the Company's subsidiary OGX Maranhão, drilled two wells in the PN-T-68 block, reaffirming the great oil-bearing potential of this new frontier which had not been explored since the 1980s. In the first well, OGX-16 (Califórnia), an important gas discovery was made in the Devonian section with a drill-stem test that encountered 1,900-psi pressure and generated a flame 15 meters long. In addition, evidence of gas was also encountered in the Pimenteiras and Itaim formations, also in the Devonian section. The data obtained through this drilling campaign, coupled with the seismic information recently acquired in the area as well as technical analysis, have made it possible to identify approximately 20 prospects similar to the one drilled by OGX-16 and to estimate a volume of resources of approximately 15 trillion cubic feet (Tcf) of natural gas for our portfolio in this region. In the second well, OGX-22 (Fazenda São José), two accumulations were found with net pay of 49 and 47 meters in the Poti and Cabeças formations, respectively. The top of the Poti formation was tested with exceptional results which indicated a production potential of up to 3.4 million m³ per day in Absolute Open Flow (AOF).

These estimates point to a production potential for the region of approximately 15 million cubic meters per day of natural gas. Based on this relevant new data, OGX decided to review the scope of its exploratory campaign for the region and boosted the forecast for the number of wells to be drilled from 7 to 15. 

Drilling Activity in Progress operated by OGX

• 1-OGX-30-RJS, also known as Salvador prospect, is being drilled by the rig Ocean Quest in the BM-S-58 block in the Santos basin. Drilling was initiated on January 11th;
• 1-OGX-33-RJS, also known as Chimborazo prospect, is being drilled by the rig Pride Venezuela in the BM-C-41 block in the Campos basin. Drilling was initiated on February 3rd;
• 1-OGX-34-MA, also known as Bom Jesus prospect, is being drilled by the rig QG-1 in the PN-T-68 block in the Parnaíba basin. Drilling was initiated on February 13th;
• 1-OGX-37-RJS, also known as Potosi prospect, is being drilled by the rig Ocean Ambassador in the BM-C-43 block in the Campos basin. Drilling was initiated on March 6th;
• 3-OGX-38-MA, the first appraisal well of the Fazenda São José accumulation, is being drilled by the rig BCH-05 in the PN-T-68 block in the Parnaíba basin. Drilling was initiated on March 25th;
• 9-OGX-39HP-RJS, first horizontal well of the Pipeline accumulation, is being drilled by the rig Ocean Star in the BM-C-41 block in the Campos basin. Drilling was initiated on March 25th. This well will be used in the future for production in the area.

The drilling rig Sea Explorer, which drilled well 9-OGX-26HP, an appraisal well of the Waimea accumulation in which the extended well test (EWT) will be performed, will drill the third appraisal well of the Pipeline accumulation.
The drilling rig Ocean Lexington has just drilled well 3-OGX-35D, the first appraisal well of the Waikiki accumulation, which will be used as a pilot for a horizontal well.
The jack up rig, Ocean Scepter, will start operating soon and will be dedicated to the Pará-Maranhão Basin. 

Beginning of Production

The beginning of OGX's production is expected for the third quarter of 2011. This will be an important milestone in the Company's history and will contribute to its ongoing growth trajectory in the coming years. The production will be in the Waimea accumulation, in block BM-C-41 in the Campos Basin, through an extended well test (EWT), which could record flows of up to 20,000 barrels/day.

The technology that will be employed for this first project has been widely applied within the oil industry and calls for using wet christmas trees and flexible lines that will be directly connected to the FPSO OSX-1. The well was prepared for production using the subsea centrifugal pumping method.

All of the key equipment for this phase of production has already been contracted from globally renowned suppliers and some pieces have already been delivered. Suppliers of equipment and services include: Schlumberger (Integrated Project Management and equipment and services for well completion), GE Oil & Gas (subsea X-trees), Wellstream (flexible lines and a vessel for launching the lines), Oceaneering (control umbilical), Baker Hughes (electrical subsea pumping) and OSX, which will supply the FPSO OSX-1. This FPSO (Floating Production Storage & Offloading system) is currently in Singapore, undergoing modifications to its processing plant in order to conform to the characteristics of the Waimea oil and is expected to arrive in Brazil by mid 2011.

Shell and Showa Shell Sekiyu supporting relief efforts in Japan

Shell and Showa Shell Sekiyu supporting relief efforts in Japan

Tuesday, 22 March 2011 16:30 Ordons.com

Tokyo. Showa Shell Sekiyu K.K. and Shell said today they would make a combined donation of US $2 million to the Japanese Red Cross Society to provide disaster relief assistance in response to the catastrophic earthquake and tsunami in Japan. The Shell Group, in addition to this, has implemented a worldwide employee donation program to further support Japan's disaster relief efforts.

Shell's Country Chairman for Japan, Chris Gunner, said "Our hearts are heavy as we reflect on the thousands of lives lost and the enormous damage due to the earthquakes and the tsunami. Shell has been part of the Japanese community for more than 100 years. Financial support will not dull the pain of this tragedy, but it is important in helping to rebuild lives."

"Given the scale of this catastrophe and resulting human suffering, we want to do our part to assist with the relief and reconstruction efforts," said Shigeya Kato, Chairman of Showa Shell Sekiyu K.K.
All Showa Shell Sekiyu and Shell employees in Japan are safely accounted for and Showa Shell's refineries, marketing and distribution businesses are operational, apart from numerous retail service stations and a small number depots which were impacted in the Tohoku area. However, as a result of the earthquake and tsunami, and the nuclear power plant issues, Japan has suffered significant power generation loss, and refinery and depot shutdowns.

The shutdown of power plants in Japan and rolling power blackouts in the northern half of the main island, including around Tokyo, has seen an increase demand for imports of Liquefied Natural Gas (LNG) and other fuels. Shell and its LNG joint ventures are working with their Japanese customers to help ensure continuing and additional supplies of LNG into the country to meet these critical requirements. Since the time of the earthquake, six shipments of LNG from Brunei, two from Sakhalin and one diverted cargo from Nigeria have unloaded in Tokyo Bay, as well as cargoes to other locations in Japan, providing much needed gas supply. Further cargoes are expected to follow in the coming days.

In addition to the financial donation, Showa Shell Sekiyu has an emergency task force working with the Japanese government in prioritizing supply of petroleum products to the affected areas and maintaining the energy supply 'lifeline'. Its actions include:

In addition to the financial donation, Showa Shell Sekiyu has an emergency task force working with the Japanese government in prioritizing supply of petroleum products to the affected areas and maintaining the energy supply 'lifeline'. Its actions include:

* Terminating the export of refined petroleum products, including gasoline and diesel, this month to strengthen supply to the domestic market;

* Working around the clock to supply petroleum products to its service stations, and supplying other petroleum companies and government agencies in response to their requests;

* Expanding its distribution capabilities in Tokyo by strengthening the deployment of lorries;

* Providing food relief to the disaster area.

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