La Cortez Boosts Net Production on Mirto-1

- La Cortez Boosts Net Production on Mirto-1

Monday, September 12, 2011
La Cortez Energy, Inc.

La Cortez Energy, Inc. on Monday provided the following operational update on the work-over activity conducted on the Mirto-1 well.

Maranta Block – Mirto Field

As previously announced, the work-over on the Mirto-1 well was initiated on August 8th, 2011, with the objective to initiate a long-term production test on the Villeta N sand, which is the same zone that is producing in the Mirto-2 well. The work-over operation was completed on August 23rd, and the well was immediately put on production with the following initial results during the period from August 23rd to September 10th: Average gross production before royalties was 334 bopd of 15 degree API oil, with an average Base Sediment and Water (BS&W) of 1.5%. The well is producing by Electro Submersible Pump (ESP), and is stabilizing at 820 psi (flowing pressure at the ESP inlet) which is the expected pressure needed to maintain current production levels. Production on September 10th increased to 343 bopd (gross before royalties) with an average (BS&W) of 0.5%, indicating a continuous reduction in the water cut as expected for this particular reservoir. The well will be placed on long-term production testing with the purpose of monitoring production behavior as well as to gather additional technical data.

The Mirto-2 well continues producing with an average rate of 484 bopd for the year (gross before royalties), and with an average BS&W of 0.7%. The well continues producing from the Villeta N sand with flow pressure stable at 1065 psi, indicating the potential to increase the ESP frequency in order to maintain production levels closer to 500 bopd.

Current production from the Mirto-1 and Mirto-2 wells is 756 bopd gross before royalties, or 151 bopd net (before royalties) to the company, an increase of more than 50% over the year to date average.

Andres Gutierrez, President and CEO of La Cortez, commented on the announcement, "We are very pleased with the initial results obtained from the work-over on the Mirto-1 N sand. The additional production represents a significant increase in net production to the company, and will give us the opportunity to further assess the results of the work-over, and work closely with Emerald Energy Plc. (the operator of the block) to finalize plans for future exploration activity on the block as well as to determine the production potential from the Villeta formation - U sand in the Mirto field."

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Coastal's Bua Ban North A-05 Encounters Net Pay

- Coastal Bua Ban North A-05 Encounters Net Pay

Wednesday, September 07, 2011
Coastal Energy Co.

Coastal Energy announced the successful results of the Bua Ban North A-05 well and provides an operations update.

The Bua Ban North A-05 well was drilled to a total depth of 5,650 feet TVD. The well encountered 81 feet of gross sand and 35 feet of net pay in the Miocene reservoir with 27 percent average porosity. The well tested the Miocene reservoir on the eastern flank of the Bua Ban North A field. The oil water contact in the well was seen at 3,770 feet. The results of the A-05 well add an additional 1,200 acres to the structural closure area. The Company is planning to drill five to six additional evaluation wells at Bua Ban North before moving the rig to G5/50.

The Bua Ban North B-02, B-03 and B-04 wells have all been completed and tied into the production facilities. The aggregate production rate from Bua Ban North B is approximately 8,200 bopd. Average production at Songkhla A is approximately 4,000 bopd, with production currently being constrained due to a temperature issue. The Company is installing additional cooling units to remedy this issue and restore production to 6,500 bopd. The installation is expected to be complete in approximately two weeks.

Aggregate offshore oil production is averaging 13,700 bopd, and total Company production is averaging 15,800 boepd.

Randy Bartley, Chief Executive Officer of Coastal Energy, commented, "We are very pleased with the results of the Bua Ban North A-05 well. This well was drilled as far north as possible to test the presence of hydrocarbons between Bua Ban North A & B. We have several locations identified which are further south and up to 200 feet structurally higher which we plan to test with the upcoming wells.

"Total production from Bua Ban North B has come in above our expectations and the wells continue to perform better than expected. We are working to resolve mechanical production issues at Songkhla and expect to restore production to previous levels in the coming weeks.

"We expect production facilities to be on location at Bua Ban North A in late October."

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AWE Reports Net Loss

- AWE Reports Net Loss

Monday, August 29, 2011
AWE Ltd.

AWE Limited has announced a statutory net loss of $117.6 million for the 12 months to June 2011. After adjustment for significant one-off, the underlying loss was $16.1 million.

The Company's production assets performed strongly with production of 6.1 million BOE. This delivered a 61% increase in after tax net cash flow from operating activities of $140 million, which included exploration expense of $21 million.

Investment in growth activities continued during the year, with $32 million invested in the completion of the Adelphi takeover, $69 million in exploration activities and a further $80 million in project developments (primarily BassGas MLE and Sugarloaf drilling).

The Adelphi Energy takeover, completed during the year, provides AWE with access to an exciting gas and liquids development project in the US, which is delivering strong initial production performance. Reserve reporting to date at Sugarloaf has highlighted the growth potential of the asset, with 2P reserves increasing to 8.5 million BOE at June, 2011.

The Company reported a cash position of $117 million, at June 30, 2011 with an undrawn $150 million loan facility.

Commenting on the result, AWE's Managing Director Bruce Clement said, "The Company's core business continues to perform well as evidenced by the increased operating cashflow of $140 million for the year, reflecting the strength and diversity of AWE's portfolio of production assets.

"The statutory loss of $118 million was impacted by a number of significant one-off factors, primarily asset impairments and the derecognition of previously booked tax losses.

"The second half of 2010/11 has been a period of consolidation for AWE following an extended period of major exploration activity.

"The Company's focus has been on delivering its core production operations, exploiting its existing asset base and establishing its tight gas and shale gas business through the Sugarloaf acquisition and the Perth Basin exploration initiatives. The Company has also completed a comprehensive review of its core assets.

"Looking forward, AWE has a strong balance sheet, robust future cash flow from its 66 million BOE 2P reserve base and significant potential in its Perth Basin gas exploration assets with access to premium domestic markets.

"The Company's near term plans will focus on continuing the strong performance of the base business, exploiting its tight gas and shale gas projects and pursuing selective growth opportunities.

"The Board and Management of AWE are confident about the Company's future. AWE is well positioned to build on its existing assets and to take advantage of opportunities in the current volatile business environment."

Finance

Operating cashflow was strong for the year, rising 61% to $140 million. The reported cashflow included exploration expense of $21 million and significant Tui and Cliff Head workover costs of $29 million.

The year-end financial position of the Company was strong, with cash of $117 million and no debt (and with a $150 million undrawn corporate debt facility available if required).

AWE's sales revenue fell 14% to $305 million for the year, with net field contributions also lower at $172 million. Total oil and gas sales volumes were in line with the prior year, although oil production was down by 36%, offset by increased gas and associated gas liquids sales over the period. Average received oil prices improved to approximately $91 per barrel, as a result in the stronger international prices partially offset by the stronger A$.

In accordance with AWE's successful efforts accounting policy, $63 million of exploration costs were expensed during the year. These costs were largely related to unsuccessful drilling activity in New Zealand, Yemen and Australia.

A net exploration impairment charge of $61 million (post tax) impacted the statutory results. This impairment included the write down of the Yemen and Bass Basin exploration assets acquired as part of the ARC Energy merger in 2008. In addition, a post-tax net oil and gas asset impairment of $15 million was also recorded (largely related to the Cliff Head project).

Subsequent to the end of the year, AWE sold its shareholding in Buru Energy Limited for a cash consideration of $17 million. These funds were received after year end and are not included in the reported results.

Exploration

Exploration expenditure for the year was primarily incurred on the conventional oil and gas exploration opportunities in Australia, New Zealand and Yemen.

In the latter part of year, AWE accelerated activities in tight gas and shale gas exploration in the onshore Perth Basin, where drilling of the Arrowsmith-2 well has been completed and hydraulic stimulations are being planned. Timing of the hydraulic stimulation activity is subject to the receipt of all regulatory approvals.

AWE continues to pursue further conventional and unconventional exploration opportunities, applying an added degree of financial and technical discipline.

Development

The Adelphi takeover was completed during the year, and development drilling activity in its USA operations has accelerated since the acquisition was finalised. An independent reserve statement was released in March 2011, which reported a 37% improvement (to 8.6 million BOE net to AWE) in existing 2P reserves in the Sugarloaf AMI. Further drilling activity is expected to see added conversion of possible reserves into the 2P reserves category during 2011/12.

The $346 million gross budget for first phase of the Yolla MLE project was approved during the year and significant progress has been made with the onshore fabrication of gas compression and accommodation modules and preparations for offshore installation at the end of 2011. An extended production shutdown is planned during the offshore installation activities (December to April).

The second phase of the development will incorporate the drilling of at least two additional development wells on the Yolla field and remains on schedule for late 2012/early 2013. Engineering planning, including the evaluation of additional upside potential in the field, is continuing with budget commitment expected by end 2011. Total expenditure to June 30, 2011 on the MLE project was $107 million.

Production well workovers were successfully completed on the Pateke and Cliff Head projects, with the Cliff Head-12 well workover increasing production from the Cliff Head field by over 1,500 bopd after coming on stream in August 2011.

2011-2012 guidance

Production guidance for the current financial year has been set at 5.0 to 5.5 million BOE, substantially impacted by the planned extended shutdown of the Yolla field for the offshore installation activities associated with the MLE project. Based on a A$100 per
barrel Brent oil price for the year, AWE expects oil and gas sales revenue to reach a range of $270 to $300 million. Planned exploration expenditure for the year is estimated at $50 million, with development expenditure planned to reach $150 million, the majority of which will be incurred on the BassGas MLE project.

With a net cash position of $117 million AWE is well positioned to further exploit those assets within the Company's existing portfolio and take advantage of opportunities to add to its asset base.

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Hess' Second-Quarter Net Surges 62% On High Oil Prices

- Hess' Second-Quarter Net Surges 62% On High Oil Prices

Wednesday, July 27, 2011
Dow Jones Newswires
by Tess Stynes & Ryan Dezember

Hess' second-quarter earnings soared 62% thanks to sharply higher oil prices and despite a wider loss for its marketing and refining operations.

Hess' performance in recent quarters has been boosted by high oil prices, as well as improved demand for gasoline and diesel products. However, its marketing and refining business has continued to lag.

Hess reported a profit of $607 million, or $1.78 a share, up from $375 million, or $1.15 a share, a year earlier. Revenue climbed 27% to $9.81 billion.

Analysts polled by Thomson Reuters most recently forecast earnings of $1.94 a share on revenue of $10.08 billion.

Pearce Hammond, an analyst with Houston investment bank Simmons & Co., said that Hess' trading losses as well as those from its refining joint venture with Venezuela's state oil company were "major disappointments." Overall, the results "will likely weigh on the stock today," Hammond wrote in a note to clients.

Shares recently traded 3.13% lower at $70.80.

Earnings at the exploration-and-production segment, which accounts for most of Hess' profit, surged 53% despite lower production. Average prices, excluding hedging impacts, jumped 46% for oil and 6.5% for natural gas.

In the marketing and refining business, losses widened in the refining-and-trading segments, while marketing income strengthened by 65%.

Copyright (c) 2011 Dow Jones & Company, Inc.

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BG Doubles Santos Basin Net Potential

- BG Doubles Santos Basin Net Potential

Thursday, June 30, 2011
BG Group

BG Group on Thursday issued a material upgrade for its interests in the pre-salt Santos Basin, offshore Brazil.

Mean Total Reserves and Resources* are now estimated to amount to some 6 billion barrels of oil equivalent (boe) net to BG Group, with an upside potential of 8 billion boe net. Existing discoveries account for 96% of the mean Total Reserves and Resources.

The mean Total Reserves and Resources represents a doubling of BG Group's previous best estimate of 3 billion boe prevailing at the time of the Group's February 2010 Strategy Presentation.

The aggregate range of Total Reserves and Resources net to BG Group is from 4 billion boe (P90) to 8 billion boe (P10)**.

These new estimates result from BG Group's internal analysis based on probabilistic modelling of its Santos Basin interests. The analysis used a wealth of drilling, appraisal and other data that BG Group has gained or developed in relation to those interests, including:

• a total of 29 wells drilled in our existing discoveries; two wells drilled on Lula since November 2010 proving particularly important in delineating the flanks of the field. Other wells have demonstrated excellent connectivity in the reservoir;
• a total of 19 drill stem tests on current discoveries;
• the shooting and analysis of over 14,400 square kilometers of 3D seismic;
• full analysis of a completed extended well test (EWT) on Lula Sul and early results from the Guara EWT indicating the very large hydrocarbon volumes connected to each of these wells;
• production from the first permanent floating production, storage and offloading vessel on Lula which commenced in October 2010;
• development plans that include enhanced recovery processes to improve ultimate recovery factors for these giant fields; and
• cost optimization, potential debottlenecking of facilities and greater well productivity enhancing the economic viability of later phases of development.

BG Group Chief Executive Sir Frank Chapman said: "The doubling of our estimated Santos Basin mean reserves and resources is clearly significant and demonstrates the continued rapid evolution of our understanding of these enormous discoveries. Robust economics and solid progress with the fast-track development program will see gross installed production capacity rising steadily to reach more than 2.3 million boe per day by 2017. I believe this - alongside progress with major ventures in Australia, the US and across our global portfolio - will transform the scope, scale and value of BG Group."

* Total Reserves and Resources are defined by BG Group as the aggregate of proved and probable reserves plus discovered resources and risked exploration.

** The Total Reserves and Resources upgrade announced today is based upon probabilistic modelling by BG Group of its interests in the Santos Basin, in accordance with Society of Petroleum Engineers (SPE) guidelines. The data has been analyzed, interpreted and verified by BG Group and not by the Operator or other Consortium partners.

BG Group has interests in five blocks in the Santos Basin, offshore Brazil

• BM-S-9 (30%) containing the Guara, Carioca, Abare and Iguacu discoveries and prospects.
• BM-S- 10 (25%) containing the Parati and Macunaima discoveries and prospects.
• BM-S-11 (25%) containing the Lula, Cernambi and Iara discoveries and prospects.
• BM-S-50 (20%) containing prospects including Sagittario.
• BM-S-52 (40%) containing the Corcovado discovery.

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Coastal Confirms Net Pay at Buan Ban North B Field

- Coastal Confirms Net Pay at Buan Ban North B Field

Tuesday, June 28, 2011
Coastal Energy Co.

Coastal Energy announced the results of two wells drilled at the Bua Ban North B field, offshore Thailand.

The Bua Ban North B-08 well was drilled to a total depth of 5,900 feet TVD and encountered 92 feet of net pay with 28 percent porosity and 25 percent water saturation in the Miocene interval. The B-08 well was drilled on the easternmost fault block of the field and successfully appraised the discovery made by the B-03 well. As a result of the B-08 drilling, the lowest known oil was moved 140 feet lower in this fault block.

The B-07 well was drilled as a water injection well and to establish the oil water contact in the field. The B-07 encountered the oil water contact at 3,824 feet, which was in line with the prognosis based upon previous drilling results. Pressure and log data from the B-08 well indicate that the oil water contact may be deeper on the eastern side of the field.

Randy Bartley, Chief Executive Officer of Coastal Energy, commented, "The results of the B-07 and B-08 wells serve as further confirmation of the Miocene trend in the Songkhla basin. Updated mapping based on drilling results indicates that the structural closure at Bua Ban North B is approximately 2,800 acres in size. The positive appraisal of the eastern fault block has major implications for the extension of this field as it has significantly increased the prospectivity along the major eastern Miocene fault which extends over three kilometers between Bua Ban North A & B.

"The drilling rig is going to mobilize to the Songkhla H prospect next, which is a commitment well outside of the two established production areas on G5/43. We will proceed with the installation of the mobile offshore production unit to begin production at Bua Ban North B once the rig is off location."

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Toyota Motor Estimates 31% Drop Full Year Net Profit

- Toyota Motor Estimates 31% Drop Full Year Net Profit



Jun 10, 2011

Toyota Motor (NYSE:TM) said today it expects its net profit to fall by almost a third this year, as production continues to be disrupted 3 months after the massive earthquake and tsunami that struck Japan on March 11th.

The company predicted its profit for the full year ending in March 2012 would decline 31% to $3.5 billion.

Analysts had been expecting a profit of $5.28 billion, and the company reported $5.1 billion in profit for the year ending March 2011.

The company expects full year sales to decline 2%, and said global production wouldn't recover completely until November.

Toyota Motor has a potential upside of 14.3% based on a current price of $80.84 and an average consensus analyst price target of $92.4.

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Petrobras Touts $6.5B in 1Q Net Earnings

- Petrobras Touts $6.5B in 1Q Net Earnings

Thursday, May 26, 2011
Petrobras

Petrobras announces its consolidated results of the first quarter 2011 (1Q11), in accordance with generally accepted accounting practices in United States (US GAAP).

The consolidated net income reached US $6.5 billion in the 1Q11, (US $1.00 per ADS), compared to US $4.3 billion in the 1Q10 (US $ 0.98 per ADS). The increase of 51% was primarily due to higher production volumes, higher prices and higher domestic sales volumes. The increase was also due to higher foreign exchange gains on net debt denominated in U.S. dollars.

Adjusted EBITDA was US $9.5 billion in 1Q11, compared to US $8.4 billion in the 1Q10.

Capital expenditures amounted to US $9.9 billion in the 1Q11, most of which allocated to the expansion of future oil and gas production capacity.

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Rosneft Net Profit Up 58% at $3.94B, Beats Expectations

Rosneft Net Profit Up 58% at $3.94B, Beats Expectations

Friday, April 29, 2011
Dow Jones Newswires
by Jacob Gronholt-Pedersen

Rosneft said first-quarter net profit rose 58% from last year on higher oil prices and crude output as well as tax breaks on its Vankor field.

London-listed Rosneft said net profit under U.S. Generally Accepted Accounting Principles rose to $3.94 billion from $2.49 billion in the first quarter of 2010, above a forecast of $3.72 billion in a Dow Jones Newswires survey of eight analysts.

Revenue increased 36% to $20.12 billion from $14.76 billion a year earlier, boosted by a surge in global crude prices as well as higher output, helped by a ramp-up of production at the huge East Siberian Vankor field. Analysts had expected revenue of $20.3 billion.

Earnings before interest, taxes, depreciation and amortization, or Ebitda, rose 50% to $6.65 billion from $4.44 billion and were above analysts' expectation of $6.42 billion.

Rosneft said it produced 2.564 million barrels of oil equivalent per day during the quarter, and lowered net debt by 19% in the three months to $11.1 billion.

Coastal Energy Hits Net Pay at Bua Ban North

Coastal Energy Hits Net Pay at Bua Ban North

Friday, April 29, 2011
Coastal Energy Co.

Coastal Energy announced the successful results of the Bua Ban North B-01 exploration well.

The Bua Ban North B-01 well was drilled to 7,960 feet TVD and encountered 28 feet of net pay in the Upper Oligocene with 23% average porosity and 29 feet of net pay in the Lower Oligocene with 16% average porosity. Net pay estimates are based on log analysis, shows and MDT analysis; the well has not been flow tested. The Company estimates that this fault block contains a total of 13 million barrels of oil in place across these two intervals.

The B-01 well also encountered good oil shows in three zones in the Miocene; however, this interval was not targeted in this well and the Miocene was not encountered in an optimal structural position. There was also an oil show in the Eocene interval.

The Company has spudded the Bua Ban North B-02 well, which will test two Miocene intervals in an optimal structural position. The B-02 well will also test Oligocene and Eocene targets. Although high gas readings were encountered throughout the Eocene and an oil show was observed, the top of the Eocene reservoir was penetrated at 7170 feet, below our interpreted threshold for development of reservoir quality sands.

Randy Bartley, Chief Executive Officer of Coastal Energy, commented, "The B-01 well delivered positive results for the Bua Ban North B prospect. We saw good oil shows throughout all of our targeted intervals which support further drilling to test the Miocene and Eocene intervals at this location. The shallow shows continue to support the potential for shallower Miocene and Upper Oligocene targets along the entire western margin of the Songkhla basin. The Eocene interval is predicted to be of reservoir quality at 6,500 feet and shallower; it was encountered in this well at 7,170 feet. We plan to test Eocene targets further up the terrace at shallower depths.

"The drilling results from Bua Ban North continue to be positive. We also remain on target to begin production testing of the multiple discoveries at Bua Ban North A in mid-May."

Randy Bartley, President and Chief Executive Officer of the Company and a member of the Society of Petroleum Engineering and Jerry Moon, Vice President, Technical & Business Development, a member of the American Association of Petroleum Geologists, a Licensed Professional Geoscientist and a Certified Petroleum Geologist in the state of Texas, have reviewed the contents of this announcement.

Far East Reports Net Present Value of Shouyang Block Resources

Far East Reports Net Present Value of Shouyang Block Resources

Wednesday, April 06, 2011
Far East Energy Corp.

Far East announced the results of an independent report by Netherland, Sewell & Associates (NSAI) evaluating, as of December 31, 2010, the contingent gas resources and Net Present Value at 10% Discount ("NPV10") of the net contingent cash flow for the three target coal seams in Far East Energy's 485,000 acre (1960 square kilometers) Shouyang Block, situated in Shanxi Province, China.

The report gives a Best Estimate of NPV10 of $738.3 million, and a High Estimate of $1.46 billion, net to Far East.

"Obviously, this is a very strong report, and one with which we are well pleased," said Michael R. McElwrath, CEO and President of Far East. "These estimates highlight the robust economic potential of the Block. And, it is important to note that we hope and believe that these numbers are just the beginning, as meaningful improvements in well-by-well gas rates and sustainability – which we certainly expect as we further develop, dewater, and optimize production – should have the impact of increasing these estimates, as well as reclassifying some of these resources as reserves."

McElwrath continued, "This report includes only our interest in the Contingent Resources and, of course, does not constitute a reserves report. While, under the terms of our gas sales agreement, we received payment for gas at year-end 2010, we did not flow gas through the system until mid-January, and even then that was frequently interrupted as we worked out the bugs in the gathering system during the testing and commissioning process. That lack of gas flow at year-end and our anticipation of frequent interruptions as testing and commissioning occurred, led us to decide that under the applicable rules we did not have a sufficiently completed gas sales system functioning as of year-end to recognize proven gas reserves in our December 31, 2010 financials. We will recognize proved gas reserves as appropriate in 2011, and will also provide a report indicating the probable and possible gas reserves at that time."

McElwrath continued, "With our current cash balance of $34 million, we will again accelerate the pace of our drilling program, and drilling should be funded until approximately the end of 2011. Additionally, we are also targeting a total of 200 to 250 wells in 2012, and 300 to 400 in 2013. Of course, the costs of these accelerated outyear drilling programs will be partially offset by growing revenues from gas sales, and discussions are underway with several international banks and other institutions for debt financing. Shouyang's potential becomes more apparent with each successive independent analysis that we receive, and we will proceed apace to realize the value of the underlying resource."