Tullow Touts Record Results in 1H11

- Tullow Touts Record Results in 1H11

Wednesday, August 24, 2011
Tullow Oil plc

Tullow announced its half-yearly results for the six months ended 30 June 2011.

2011 Half-yearly results summary

• Record first half revenue and profit
• Interim dividend doubled
• Exploration success continues and developments being progressed

Tullow had a very strong first half. Record results were driven by increased production from the Jubilee field in Ghana and higher commodity prices. Exploration and appraisal success continued and the Group strengthened its portfolio with farm-ins in East Africa and two strategic acquisitions. Further progress was made in Uganda and Tullow now expects completion of its farm-down to CNOOC and Total in September. In July the Group listed Tullow Oil plc shares on the Ghana Stock Exchange.

Key highlights

• Record sales revenue of over $1 billion driven by Jubilee Production; interim dividend doubled.
• 71% exploration and appraisal success year-to-date (17/24); Akasa-1 discovery announced today.
• Completion of farm-in to six blocks in Kenya and Ethiopia; first well to spud in Kenya in Q4 2011.
• Group production expected to average 82-84,000 bopd for 2011 and exceed 100,000 bopd by year-end.
• Jubilee production in Ghana is expected to increase to 105,000 bopd in October; plateau production of 120,000 bopd is now expected before year-end.
• MoU signed with the Government of Uganda; $2.9 billion Sale and Purchase Agreements signed for the farm-down to CNOOC and Total; completion now expected in September.
• Nuon E&P and EO Group acquisitions completed in June and July respectively.
• Secondary listing on the Ghana Stock Exchange completed in July following successful $72.3 million offer.

Commenting, Aidan Heavey, Chief Executive, said, "We have delivered a strong performance and achieved record results in the first half allowing us to double the dividend. We continue to make good progress with production plans in both Ghana and Uganda and while delays to the farm-down to CNOOC and Total have been frustrating, we now expect completion in September. With a strong balance sheet, growing production and a potentially transformational drilling campaign to come, we move into the second half of the year with real confidence."

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Petrofac Touts $2.71B in Revenue, Up 25%

- Petrofac Touts $2.71B in Revenue, Up 25%

Monday, August 22, 2011
Petrofac Ltd.

Petrofac announced its interim results for the six months ended June 30, 2011.

FINANCIAL HIGHLIGHTS

• Revenue up 25.2% to US $2,711.1 million (2010 restated: US $2,165.8 million)
• Net profit up 6.6% to US $246.3 million (2010 restated: US $231.0 million)
• Earnings per share (diluted) up 6.7% to 71.84 cents (2010 restated: 67.31 cents)
• Interim dividend up 26.1% to 17.40 cents (10.54 pence) per share (2010: 13.80 cents)
• Backlog US $11.4 billion at 30 June 2011 (December 31, 2010: US $11.7 billion; 30 June 2010: US $6.9 billion)
• Gross cash balances at 30 June 2011 of US $1.8 billion (December 31, 2010: US $1.1 billion)

Ayman Asfari, Petrofac's group chief executive commented on the interim results:

"We have had a successful year to date, with good operational performance across our portfolio of projects and encouraging progress against our recently announced Integrated Energy Services strategy. We are well on course to deliver like-for-like net profit growth in 2011 of at least 15% and in-line with current market expectations.

"With a strong financial position, a differentiated and competitive offering and a proven track record in project execution, we remain confident of achieving our medium-term growth target of more than doubling our recurring 2010 earnings by 2015."

OPERATIONAL HIGHLIGHTS

Engineering & Construction

• Order intake in the year to date of US $1.6 billion with new awards in Algeria, Iraq and Malaysia
• Good progress on South Yoloten development, in Turkmenistan: substantially completed construction of temporary facilities and placed the majority of orders for procurement items
• Completed the Jihar gas plant in Syria and the In Salah Gas compression facilities and power generation in Algeria Offshore Engineering & Operations
• Secured a number of new contracts and extensions, including a contract to provide maintenance services on the Rumaila oilfield in Iraq for BP
• Record activity, including on the SEPAT development and upgrade of the FPSO Berantai (formerly the East Fortune) in Malaysia (both being undertaken jointly with E&C)

Engineering, Training Services and Production Solutions

• Opened a third Indian office, in Delhi, to support growth in activity levels across the group
• Entered into an MOU for a technical training partnership with PETRONAS to develop competency-based training for operations and maintenance personnel in Malaysia
• Good progress on Ticleni in Romania, improving production through optimising pump settings, working over wells and bringing back on-stream the first five of many shut-in wells
• Agreed to invest up to a further US $75 million in Seven Energy taking our interest up to 24.5%
• Selected bidder on Magallanes and Santuario Production Enhancement Contracts in Mexico

Energy Developments

• Secured first Risk Service Contract (RSC) in Malaysia, for development of the Berantai field
• Acquired FPF3 (formerly the Jasmine Venture), deployed on the Jasmine field in the Gulf of Thailand and leased to Pearl Energy, a subsidiary of Mubadala, and now operated by Offshore Engineering & Operations
• Pre-invested in field infrastructure in readiness for future developments, including the acquisition of FPF4 (formerly the Cossack Pioneer)
• Cendor phase 2 in Block PM304, offshore Malaysia, progressing to schedule and entered into an MOU with PETRONAS to accelerate the third phase of Block PM304, West Desaru

OUTLOOK

We are confident that we can continue the good progress that we have achieved in Engineering & Construction in the year to date. With high levels of backlog, we have outstanding revenue visibility which should ensure that we report strong growth in our full year revenues and we expect full year net margins to be in line with our medium-term guidance at around 11%.

While Offshore Engineering & Operations activity levels and revenues are expected to continue at record levels, net profit is expected to be lower in the second half of the year, as the first half benefited from significant progress on the SEPAT development and a provision release following completion of a long-term maintenance services contract. Net margins for the full year are expected to be substantially higher than in the prior year.

The second half performance of the Engineering, Training Services and Production Solutions reporting segment is expected to be broadly in line with the first half of the year, albeit with a greater contribution from Production Solutions, as we expect a general improvement in our consultancy and technology businesses and a positive contribution from the Ticleni Production Enhancement Contract.

In Energy Developments, our operational assets are expected to continue to perform broadly in line with the first half, with the exception of the Ohanet RSC, which ends, as expected, in October. On the Berantai field development, we expect the FPSO Berantai to mobilize to the field in early 2012, with first gas from the field expected shortly thereafter.

With a strong financial position, a differentiated and competitive offering and a proven track record in project execution, we are confident that we will continue to deliver superior value for our customers and sector-leading returns for our shareholders.

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Rosneft Touts $2.83B in 2Q Earnings

- Rosneft Touts $2.83B in 2Q Earnings

Friday, July 29, 2011
Rosneft

Rosneft has published its consolidated financial results under US GAAP for 2Q and 1H 2011.

In 1H 2011, Rosneft's average crude oil output (including production by subsidiaries and share in production by affiliates) increased by 2.7% year-on-year, to 2,362 th. barrels per day. The increase reflects higher production at Vankor and Verkhnechonsk fields in Eastern Siberia and crude output growth at Sakhalin-1 project. The Company's average daily crude oil production reached 2,368 th. barrels in Q2 2011 and rose to a record of 2,400 th. barrels in July, which was made possible due to on-schedule capacity expansion of oil treatment unit at the Vankor field.

Petroleum product output by Rosneft was 13.4 mln tonnes in 2Q 2011, which is 20% higher year-on-year. The growth reflects acquisition of a 50% stake in Ruhl Oel GmbH, which owns stakes in four German refineries.

In 2Q 2011, Rosneft's revenues grew by more than 1.5 times year-on-year to USD 23.274B. The increase was primarily attributable to higher crude oil prices and growth of production and refinery throughput. In 1H 2011, revenues reached USD 43.397B, which is 44% higher compared with 1H 2010.

Rosneft's EBITDA amounted to USD 5.333B in 2Q 2011, which is an increase of 12% year-on-year. Tax burden rise, particularly due to abolition of a reduced duty for Vankor crude and introduction of increased export duty for naphta, put downward pressure on the figure. The increase was also tempered by real strengthening of the rouble against the USD, and higher transportation and electricity tariffs year-on-year. The above-mentioned negative impact was partially offset by tight cost control. Unit lifting costs increased by 4.4% quarter-on-quarter (to USD 3.1 per barrel) and unit refinery costs rose by 5.7% while real rouble appreciation was 6.2%. In 1H 2011, EBITDA grew by 30% year-on-year, to USD 11.986B.

In 2Q 2011, free cash flow amounted to USD 1.73B, up 8% year-on-year. As a result, in 1H 2011 the Company's free cash flow increased by 66% year-on-year, to USD 4.911B.

Commenting on the results, Rosneft's President Eduard Khudainatov said, "We posted good results for the second quarter, including record operating figures. We closed the deal on acquisition of a stake in German refineries, which resulted in insignificant net debt rise. EBITDA reduction quarter-on-quarter was anticipated following abolition of export duty for Vankor crude. Ongoing performance improvement, investment program implementation and higher shareholder returns are our priorities for the near future."

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Talisman Touts 2Q11 Results

- Talisman Touts 2Q11 Results

Thursday, July 28, 2011
Talisman Energy Inc.

Talisman reported its operating and financial results for the second quarter of 2011. The company is reporting under International Financial Reporting Standards (IFRS) and all values in this release are in US$ unless otherwise stated.

• Cash flow was $897 million for the quarter, up 14% compared to $790 million a year ago and $811 million in the first quarter.
• Net income was $698 million versus $572 million in 2010 and a net loss of $326 million in the previous quarter.
• Earnings from operations were $168 million, up 14% from the same period last year and up from $157 million in the prior quarter.
• Production for the quarter averaged 420,000 boe/d, compared to 411,000 boe/d in 2010. Production from ongoing operations was up 13%, compared to 372,000 boe/d a year ago.
• Net debt at June 30, 2011 was $3 billion versus $2.5 billion at March 31, 2011.
• The company closed a second transaction with Sasol, selling a 50% interest in its Cypress A Montney shale properties for C$1.05 billion, including certain future development costs.
• Talisman acquired additional acreage in the Alberta Duvernay shale play, bringing its land position to 360,000 net acres.
• The company continues to deliver strong natural gas volumes in Southeast Asia, with price realizations of $9.78/mcf.
• Talisman plans to drill a number of important exploration wells in the second half of this year.

"Talisman achieved a strong financial performance this quarter" said John A. Manzoni, President & CEO. "We continue to grow and strengthen our shale portfolio in North America, and are looking forward to results from a number of significant exploration wells in the second half of the year.

"Total volumes in the quarter were 2% above the comparable number for 2010, although down from the first quarter, largely due to annual maintenance turnarounds. Excluding volumes from assets which have been sold, underlying growth in production is 13% year over year.

"We continue to see strong growth in North American shale volumes, which averaged approximately 470 mmcfe per day in the quarter, an increase of 178% over the same period last year and up 4% over the previous quarter. Our success in the Marcellus is continuing, with production averaging over 400 mmcf per day during the quarter.

"In the liquids-rich Eagle Ford shale play, we now have six rigs running and are planning to build to 10 by year-end. In the Montney shale, we are operating 10 rigs and closed the second transaction with Sasol during the quarter, for approximately C$1 billion, including certain future development costs.

"We are continuing to build our North American shale portfolio, with a sizeable land acquisition during the quarter, in what we hope will emerge as another successful liquids-rich play. Talisman now holds approximately 360,000 net acres in the Alberta Duvernay shale play, acquired at an average cost of about $2,000 per acre. We will begin drilling into the play in the second half of the year, with two rigs.

"In Southeast Asia, volumes continue to be strong, although down from a year ago, reflecting a one-time upward adjustment in the second quarter of last year and annual maintenance turnarounds. Natural gas prices in the region averaged about $9.80 per mcf during the quarter, reflecting strong regional demand and linkage to oil prices.

"North Sea volumes were down relative to both the previous year and the prior quarter, with annual maintenance turnarounds and natural production declines. Ongoing planned turnarounds will result in slightly lower North Sea production in the third quarter, with a return to higher volumes in the fourth quarter when work is completed. Work on future development projects continues and we have seen encouraging early test results at the Grosbeak discovery in Norway.

"The Yme project in Norway took a significant step forward with offshore installation completed at the end of the quarter; however there is still a significant amount of remaining work to commission the topsides. The amount of rework which is required on the platform has turned out to be substantial, and I believe we are now close to defining the full scope. In light of what we have found we are now moving our expectation for first production to the second quarter of 2012.

"In addition, we have seen a slight delay in the final stages of commissioning the non-operated Kitan project, and our Eagle Ford ramp-up was delayed by about three months.

"This combination of factors has led us to revise our current view of production for this year, including Colombia, to between 430,000 and 440,000 boe per day. Excluding Colombia, this represents only slight absolute growth over last year, although it represents between 7 - 10% organic growth from ongoing operations in 2010. It is, nonetheless, below our minimum expectation of 5% absolute growth for the year and I am very disappointed to miss our own target for the first time since I joined the company.

"The factors which have led to this reduction are specific and identifiable, and we remain confident in the underlying quality of the portfolio. Our growth target of 5 - 10% annually in the medium term remains firmly in place.

"There are continuing signs of success in the early testing phase of our international exploration portfolio, which has been largely focused on Colombia and Papua New Guinea to date. In the second half of the year, we plan to drill significant wells in Indonesia, Peru, Poland and the Kurdistan region of northern Iraq.

"Cash flow was $897 million during the quarter, up 14% year over year, reflecting higher oil prices. Similarly, earnings from operations, which adjust for non-operational impacts, were also up 14% to $168 million.

"Net income was $698 million compared to $572 million a year earlier and a loss of $326 million in the first quarter. This reflects the impact of changing commodity prices on the mark-to-market value of held-for-trading financial instruments and changes in the non-cash value of share based payments.

"We continue to expect that our cash exploration and development capital spending will be between $4 to $4.5 billion. In addition, we have spent $510 million on land purchases in the quarter.

"I am confident in the structure of our portfolio to deliver long-term, profitable growth of 5 - 10%. The project set-backs we have experienced are localized, but nevertheless, reinforce the need to continue the improvements we have begun across our business to address project execution and delivery. We can look forward to getting these issues behind us, and to drilling a number of important exploration wells through the second half. The underlying financial performance was strong this quarter, and we will continue to focus on effectively delivering against our strategy, with our strong portfolio of assets."

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TNK-BP Touts Financial Results for 1H 2011

- TNK-BP Touts Financial Results for 1H 2011

Tuesday, July 26, 2011
TNK-BP

TNK-BP reported its results for the first half of 2011.

Commenting on the results, Mikhail Fridman, Executive Chairman of TNK-BP Ltd., said, "This was an exceptional first half performance for TNK-BP. Thanks to management's continuous efforts to enhance operational efficiency and further develop our key business streams, the Company was able to deliver robust results. We have increased production, significantly expanded our resource base and nearly doubled net profit for the period. Growing our international business is a key priority for TNK-BP and we've made great progress thus far in 2011 by closing the deal to acquire BP's upstream assets in Venezuela and identifying several additional acquisition targets abroad."

1H11 OPERATIONAL HIGHLIGHTS

• In 1H11, oil and gas production (excluding JVs) continued to grow and reached 1,765 mboe/d, up 1.2% on 1H10. This growth was primarily driven by further production increases at our producing greenfields, Uvat and Verkhnechonskoye, and also by continued success in developing our Orenburg fields as well as increasing gas production at Rospan. We have developed and started implementation of a long-term West Siberia efficiency improvement program targeting a decrease in the annual production decline rate from the current 7% to approximately 2-3% per year.
• We have made good progress in our exploration and appraisal program aimed at growing the company’s resource base. Over 200 million boe of resources were added in 1H11 through exploration and appraisal. We have also demonstrated our ability to obtain new acreage by successfully acquiring 3 licenses through the federal auctions in the Orenburg region with estimated resources of 149 million boe.
• On the international front, we have closed the acquisition of upstream assets from BP in Venezuela in June, while the Vietnam deal close is expected in 3Q pending approval by the Vietnamese Ministry of Industry and Trade. We will now focus on the integration of these assets into our portfolio and ensuring their operational and financial efficiency. We have also just announced the signing of a Farm-out Agreement with Brazilian Petra Energia for the acquisition of a 45% stake in 21 blocks in the Brazilian Solimoes Basin. We hope to have the necessary agreements finalized before the end of August.
• Refining throughput was at 761 mb/d, increasing 11% y-o-y as a result of continuing debottlenecking efforts.
• We have progressed with expansion of our retail chain by opening the first two new-format highway service stations under the BP brand in Tver region within the framework of our long-term retail business development strategy. Opening these new service stations is the first step in implementing a strategy to develop highway retail sites in the European part of Russia. The operations of the sites have been very successful with initial fuel sale volumes exceeding the plan by 2-3 times.
• We also continued to reinforce our position in B2B by signing a long-term formula-based jet fuel supply agreement signed with Transaero Airlines, in line with the company’s strategy to strengthen its presence in Russia’s jet fuel market and increase transparency of fuel sales.
• Finally on the corporate side, we have embarked on an important initiative of improving the organizational structure of our business, led by Deputy Chairman of the Management Board, Maxim Barskiy. This involves switching from an asset-based management system, where local management has both wide functional and operational responsibility, to a functional governance model (or matrix model), with clear segregation of functions and more streamlined decision making. The first practical steps of this transition were the integration of Technology and Supply Chain Management streams into Upstream, as well as development and enactment of the new Delegation of Authority Matrix. The new organizational structure will improve decision-making, focus local management on its area of expertise, and improve our competitive advantage, as we continue our transformation into a global oil and gas player.

Commenting on the financial results, Jonathan Muir, Chief Financial Officer of TNK-BP Ltd., said, "In the first half 2011, TNK-BP continued to demonstrate strong financial results, supported by a favorable market environment, sustainable production growth and refinery throughput improvement. EBITDA increased by 59% y-o-y to USD 7.4 bn, underpinned by a 42% rise in the oil price, partially offset by cost increases due to higher excise rates, rising electricity and transportation tariffs, and continuing rouble appreciation. Our net income increased by 87% y-o-y to USD 4.5 bn on the back of EBITDA growth. Healthy cash flows from operations allowed us to raise organic capital expenditure by 33% y-o-y to USD 2.2 bn with particular focus on our key growth assets: Uvat, Verkhnechonskoye and Orenburg. Our financial discipline remained strong with good cash flow and successful debt portfolio management giving us the flexibility to pursue strategic inorganic opportunities."

1H11 FINANCIAL HIGHLIGHTS

• Revenues for 1H11 increased by 41% relative to 1H10 reflecting a 42% higher Urals price and 21 mboe/d (1.2%) production growth partly offset by a decrease of export sales in favor of the domestic market to avail of higher netbacks.
• Export duties and taxes other than income tax increased by 38% for 1H11 relative to 1H10 as a result of the impact of higher Urals prices on export duty and mineral extraction tax rates as well as the growth in excise rates in Russia partly offset by a significant duty lag benefit.
• Underlying materials, service and payroll inflation on cash costs amounted to only 4% year-on-year. However, electricity and transport tariff growth inflated cash costs by 8%. Rouble appreciation added 4% year-on-year. In addition, a one-off increase on an environmental provision in 2Q11 related to reassessment of some legacy issues increased costs by 3%.
• EBITDA for 1H11 amounted to USD 7.4 bn which is 59% higher compared to 1H10 largely due to the higher prices and duty lag benefit supported on the operations side by higher production and sales volumes. These positive factors were partly offset by a negative exchange rate impact as well as tariff and excise rates growth.
• 1H11 Net income amounted to USD 4.5 bn which is 87% up on the same period of 2010. This increase outpaced the EBITDA growth primarily due to relatively flat DD&A.
• Operating cash flow for 1H11 totaled USD 5.9 bn, up 51% compared to 1H10. This is a reflection of the higher EBITDA (adjusted for non-cash provisions), partly offset by a USD 0.5 bn increase in working capital primarily due to a price-driven growth in inventory and accounts receivable balances.
• Net debt increased by USD 0.6 bn compared to year end 2010 resulting in gearing growing to 22%.
• Organic capital investment in 1H11 amounted to USD 2.2 bn, 33% above 1H10, largely associated with increased investments in our growth greenfields (VCNG, Uvat) and Orenburg.

2Q11 RESULTS

• Revenues for 2Q11 increased by 11% relative to 1Q, reflecting primarily the increase in Urals price.
• Export duties and other taxes increased 20% q-o-q driven by a 12% increase from the price effect on export duties and MET and a decrease in duty lag benefit in 2Q, partly offset by the effect of lower export sales volumes.
• Cash costs (operating expenses, transportation and SG&A) increased by 15% largely due to rouble appreciation, increase in wellwork, contracting and other activities compared to a seasonally slower 1Q as well as increased environmental provisions.
• EBITDA for 2Q11 was 12% lower compared to 1Q. The most significant reason is the decrease of duty lag benefit further exacerbated by price-driven growth in duties, taxes and costs of purchases that effectively eliminated all q-o-q benefit of higher prices on revenues. Other factors include a comparative negative impact of one-offs - disposal gains in 1Q and higher provisions in 2Q, as well as rouble appreciation and increased spending on well-work together with annual wages and salary indexation and Moscow offices relocation cost.
• 2Q11 Net Income decreased by 14%, generally following the EBITDA trend.
• Operating cash flow in 2Q increased by 55% compared to 1Q attributed primarily to lower working capital. This is mainly due to a comparative USD 1.3 bn reduction in accounts receivable balances driven by a general decrease of trade accounts receivable due to lower crude export sales in June as well as shorter receivables collection terms.
• Organic capital investments were $0.4bn higher than in 1Q11, representing primarily a seasonally higher activity level.
• Compared to the 2Q 2010 results, 2Q 2011 EBITDA and net income increased by 45% and 81%, respectively. This reflects a stronger external environment with the Urals price increasing by 48% and a higher duty lag benefit supported by an increase in trading volumes and an improvement in trading mix, including in particular a 6% higher share of refined products. These positive factors were partly offset by the effect of a stronger rouble and inflationary pressure on costs and a USD 0.1 bn comparative net loss related to one-off impacts.

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Anadarko Touts 2Q11 Results

- Anadarko Touts 2Q11 Results

Monday, July 25, 2011
Anadarko Petroleum Corp.

Anadarko announced second-quarter 2011 net income attributable to common stockholders of $544 million, or $1.08 per share (diluted). These results include certain items typically excluded by the investment community in published estimates. In total, these items decreased net income by approximately $28 million, or $0.06 per share (diluted) on an after-tax basis. Cash flow from operating activities in the second quarter of 2011 was $1.837 billion, and discretionary cash flow totaled $1.838 billion.

Second-Quarter 2011 Highlights

• Achieved record liquids sales volumes of 297,000 barrels per day
• Finalized Lucius unitization agreement
• Successfully tested three wells at the Caesar/Tonga mega project
• Closed the acquisition of the Wattenberg Processing Plant

"We achieved record liquids sales volumes during the quarter, enhancing margins and generating excellent cash flows," said Anadarko Chairman and CEO Jim Hackett. "Nearly all of the year-over-year volume growth was attributable to a 34,000 barrel-per-day increase in liquids volumes. These results contributed to strong discretionary cash flows of more than $1.8 billion -- approximately $117 million above our capital expenditures, which included a one-time cash investment of $518 million associated with the acquisition of the Wattenberg plant."

During the second quarter of 2011, sales volumes totaled 62 million barrels of oil equivalent (BOE), or 685,000 BOE per day, averaging approximately 2.3 billion cubic feet of natural gas per day, 225,000 barrels of oil per day (BOPD), and 72,000 barrels of natural gas liquids per day.

Operations Summary

The company achieved sales-volumes records during the second quarter of 2011 in Wattenberg, Greater Natural Buttes, Wamsutter (operated), Bone Spring and the Marcellus Shale. In the Eagleford Shale, Anadarko closed its $1.6 billion joint-venture agreement with a subsidiary of Korea National Oil Corporation and exited the quarter with record gross sales volumes of approximately 45,000 BOE per day in the play, an increase of approximately 25 percent from the end of the prior quarter. In Ghana, current gross production from Jubilee is approximately 80,000 BOPD, and production continues to ramp up with further well completions and gas injection.

In the deepwater Gulf of Mexico, Anadarko continued to advance two major projects during the second quarter. The company finalized the Lucius unitization agreement and recently announced plans to develop the field with a truss spar designed for a capacity of 80,000 BOPD and 450 million cubic feet of natural gas per day. Sanctioning is expected to occur later this year, with first production expected in 2014. At the Caesar/Tonga project, Anadarko completed flow and reservoir tests on three wells. Each of the wells tested at flow rates of approximately 15,000 BOPD with high-quality (27º API gravity) oil.

Exploration Summary

Anadarko has mobilized the Discoverer Spirit drillship to begin the company's 2011 exploration program in West Africa, following the drillship's completion of the final test at Caesar/Tonga. This program includes the Montserrado exploration well in Liberia, as well as the Jupiter exploration well and Mercury appraisal well in Sierra Leone. In other deepwater exploration areas, Anadarko continued to delineate its large natural gas discoveries in Mozambique, and to advance appraisal activities in the Tweneboa/Enyenra area offshore Ghana. The company also recently began appraisal drilling in the Campos Basin offshore Brazil.

As previously announced by Diamond Offshore, Anadarko signed long-term contracts in the second quarter for two new-build drillships. The Ocean BlackHawk is expected to be delivered in late 2013, and the Ocean BlackHornet is expected to be delivered in early 2014. These new state-of-the-art rigs are designed to work in up to 12,000 feet of water, and each has been contracted for a term of five years. These new rigs will feature enhanced drilling capabilities and safety equipment designed to meet the highest specifications in the industry.

"We expect the next six to nine months to be the most active period of deepwater exploration and appraisal drilling in our company's history," said Hackett. "Our exploration program is designed to deliver upon our goal of discovering more than 500 million BOE of net risked resources this year. We are continuing to advance our deep inventory of high-impact prospects, and the new rig agreements reinforce our long-term commitment to the safety and success of our global exploration program."

Financial Summary

Anadarko reported total product revenues of approximately $3.5 billion during the second quarter of 2011, a 46-percent increase relative to the second quarter of 2010. The company ended the second quarter of 2011 with approximately $3.4 billion of cash on hand in addition to its five-year, $5 billion undrawn credit facility. As provided in the supplemental information to this release, Anadarko protected an additional 450,000 MMBtu per day of 2013 natural gas production, with three-way collars that have a middle floor of $5.00 per MMBtu and a ceiling of $6.57 per MMBtu.

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ExxonMobil Touts Three Deepwater GOM Discoveries

- ExxonMobil Touts Three Deepwater GOM Discoveries

Wednesday, June 08, 2011
ExxonMobil Corp.

ExxonMobil announced two major oil discoveries and a gas discovery in the deepwater Gulf of Mexico after drilling the company's first post-moratorium deepwater exploration well.

The KC919-3 wildcat well confirmed the presence of a second oil accumulation in Keathley Canyon block 919. The well encountered more than 475 feet of net oil pay and a minor amount of gas in predominantly Pliocene high-quality sandstone reservoirs. The well, which is continuing to drill deeper, is located 250 miles southwest of New Orleans in approximately 7,000 feet of water.

Drilling in early 2010 encountered oil and natural gas at Hadrian North in KC919 and extending into KC918, with over 550 feet of net oil pay and a minor amount of gas in high-quality Pliocene and Upper Miocene sandstone reservoirs.

ExxonMobil encountered 200 feet of natural gas pay in Pliocene sandstone reservoirs at its Hadrian South prospect in Keathley Canyon block 964 during drilling in 2009.

"We estimate a recoverable resource of more than 700 million barrels of oil equivalent combined in our Keathley Canyon blocks," said Steve Greenlee, president of ExxonMobil Exploration Company. "This is one of the largest discoveries in the Gulf of Mexico in the last decade. More than 85 percent of the resource is oil with additional upside potential."

"We plan to work with our joint venture partners and other lessees in the area to determine the best way to safely develop these resources as rapidly as possible," Greenlee said.

ExxonMobil is the operator of KC918, KC919, KC963 and KC964 with 50 percent working interest. Eni Petroleum US LLC and Petrobras America Inc. each hold a 25 percent working interest in KC919, KC963 and KC964. Petrobras America Inc. holds a 50 percent working interest in KC918.

Over the past decade, ExxonMobil has drilled 36 deepwater wells in the Gulf of Mexico in water ranging from 4,000 feet to 8,700 feet.

"As one of the largest lease holders in the Gulf of Mexico with interests in over 370 leases, we are committed to the continued safe exploration and development of this important national resource," Greenlee said.

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Coastal Touts Success at Bua Ban North Appraisal

- Coastal Touts Success at Bua Ban North Appraisal

Monday, June 06, 2011
Coastal Energy Co.

Coastal Energy announced the successful results of the Bua Ban North B-04 appraisal well.

The Bua Ban North B-04 well was drilled to 6,000 feet TVD and encountered 64 feet of net pay in the Miocene objective with average porosity of 27%. The B-04 confirms the discovery made by the B-02 well, which encountered 62 feet of net pay in the Miocene with 26% porosity. The B-04 well is currently being cased and will then be suspended pending the arrival of production equipment. The Company plans to drill a water disposal well before mobilizing the rig to its next planned location.

Randy Bartley, Chief Executive Officer of Coastal Energy, commented, "We are pleased with the continued success in the Miocene trend at Bua Ban North B. Drilling is expected to be complete by mid-June and the Mobile Offshore Production Unit is scheduled to arrive in late June. A hydraulic unit will be used for completion operations and production testing is anticipated to begin in mid-July.

"The B-04 well further confirmed the Miocene trend at Bua Ban North B and the potential of the Miocene play across the Songkhla basin. Following Bua Ban North B, the rig will be mobilized to the Songkhla H prospect, which is in the middle of the basin between Songkhla A and Bua Ban. An exploration well will be drilled to test the Miocene and deeper zones at this location."

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Tag Touts Flow Test Results at Cheal-B4ST Well

- Tag Touts Flow Test Results at Cheal-B4ST Well

Tuesday, May 31, 2011
TAG Oil Ltd.

TAG Oil announced that completion and flow testing operations on the Cheal-B4ST discovery well located in PML 38156, Taranaki Basin, New Zealand, have been completed, and the well has now been placed on permanent production into TAG's 100%-owned Cheal Production Facility.

The Cheal-B4ST vertical exploration well was drilled to a total depth of 1821m (5973 feet), encountering net pay in both the Urenui and Mt. Messenger Formations. Flow rates averaged 400 barrels of oil equivalent (BOE) per day (360 barrels of oil + 240 thousand cubic feet gas) after the first week of production.

The Cheal-B4ST well encountered 17 meters (56 feet) of net pay within the Urenui (~1400m) and Mt. Messenger (~1700m) zones. These Miocene-aged zones were isolated and tested separately, confirming oil and gas flow rates from both zones. The final completion co-mingles the two zones.

TAG Oil CEO Garth Johnson commented, "The Cheal-B4ST well represents a significant milestone for the Cheal oil and gas field and opens the door for substantial reserve growth. Prior to this year, all our Cheal reserves were assigned solely to the Mt. Messenger Formation, but with Cheal-B4ST, we now have three wells producing oil from the Urenui Formation as well. Given these excellent results, further development of the widespread Urenui Formation will be a top priority."

TAG also reports that the Company is expanding the capabilities of the artificial lift systems at the Cheal Production Facility to accommodate the new wells drilled in the last nine months. At present, the Plant is producing approximately 1000 barrels of oil equivalent per day with approximately 350 barrels of oil equivalent per day that is shutin, awaiting completion of the expansion. The expansion work is scheduled to be complete by September 2011 at a nominal cost.

The Cheal oil and gas field is located in Petroleum Mining Permit 38156 in the Taranaki Basin New Zealand.

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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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OXY Touts $1.1B in 1Q 2011

OXY Touts $1.1B in 1Q 2011

Thursday, April 28, 2011
Occidental Petroleum Corp.

Occidental Petroleum Corporation (OXY) announced core income of $1.6 billion ($1.96 per diluted share) for the first quarter of 2011, compared with $1.1 billion ($1.35 per diluted share) for the first quarter of 2010. Net income for the first quarter of 2011 was $1.5 billion ($1.90 per diluted share), compared with $1.1 billion ($1.31 per diluted share) for the first quarter of 2010.

In announcing the results, Dr. Ray R. Irani, Chairman and Chief Executive Officer, said, "The first quarter of 2011 core income of $1.6 billion was 45-percent higher than the first quarter of 2010. Our oil and gas production for the first quarter of 2011 increased over 4 percent, as compared to the first quarter of 2010, to 730,000 BOE per day."

QUARTERLY RESULTS

Oil and Gas

Oil and gas segment earnings were $2.5 billion for the first quarter of 2011, compared with $1.9 billion for the same period in 2010. The increase in the first quarter of 2011 results was due to higher crude oil prices and higher sales volumes in the Middle East, partially offset by higher operating costs and DD&A rates.

For the first quarter of 2011, daily oil and gas production volumes averaged 730,000 barrels of oil equivalent (BOE), compared with 701,000 BOE in the first quarter of 2010. Volumes increased over 4 percent, primarily in domestic gas and NGL production and Middle East/North Africa crude oil volumes. The domestic gas increase was from the new acquisition in South Texas, which closed in the first quarter of 2011. The Middle East/North Africa increase included new production from Iraq and higher volumes from the Mukhaizna field in Oman.

As a result of higher year-over-year average oil prices affecting production sharing and similar contracts, production was negatively impacted in the Middle East/North Africa, Long Beach and Colombia by 12,000 BOE per day. Dolphin and Elk Hills volumes were also lower from planned maintenance and production shut-downs in the first quarter of 2011.

Daily sales volumes increased over 6 percent from 685,000 BOE per day in the first quarter of 2010 to 728,000 BOE per day in the first quarter of 2011.

Oxy's realized price for worldwide crude oil was $92.14 per barrel for the first quarter of 2011, compared with $74.09 per barrel for the first quarter of 2010. Worldwide realized NGL prices rose from $47.48 per barrel in the first quarter of 2010 to $52.64 per barrel in the first quarter of 2011. Domestic realized gas prices dropped from $5.62 per Mcf in the first quarter of 2010 to $4.21 per Mcf for the first quarter of 2011.