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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Hess Boosts Utica Position with $750MM Acquisition

- Hess Boosts Utica Position with $750MM Acquisition

Thursday, September 08, 2011
Hess Corp.

Hess has acquired Marquette Exploration LLC and other leases in Ohio's Utica Shale, boosting its acreage position by 85,000 net acres at a cost of approximately $750 million.

The leases, in which Hess will have a 100 percent working interest, are in Jefferson, Harrison and Belmont counties. Appraisal activities on this acreage are planned to commence in the fourth quarter. Together with the previously announced joint venture with CONSOL Energy, the transactions provide Hess with approximately 185,000 net acres in the Utica Shale play.

"With these transactions, we have built a strategic acreage position in the Utica Shale, allowing us to strengthen our portfolio of unconventional resources in high quality assets, leverage our operating expertise and create significant potential for future growth in reserves and production," said John Hess, Chairman and CEO of Hess Corporation.

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USGS Boosts Marcellus Estimates

- USGS Boosts Marcellus Estimates

Tuesday, August 23, 2011
U.S. Geological Survey

The Marcellus Shale contains about 84 trillion cubic feet of undiscovered, technically recoverable natural gas and 3.4 billion barrels of undiscovered, technically recoverable natural gas liquids according to a new assessment by the U. S. Geological Survey (USGS).

These gas estimates are significantly more than the last USGS assessment of the Marcellus Shale in the Appalachian Basin in 2002, which estimated a mean of about 2 trillion cubic feet of gas (TCF) and 0.01 billion barrels of natural gas liquids.

The increase in undiscovered, technically recoverable resource is due to new geologic information and engineering data, as technological developments in producing unconventional resources have been significant in the last decade. This Marcellus Shale estimate is of unconventional (or continuous-type) gas resources.

Since the 1930's, almost every well drilled through the Marcellus found noticeable quantities of natural gas. However, in late 2004, the Marcellus was recognized as a potential reservoir rock, instead of just a regional source rock, meaning that the gas could be produced from it instead of just being a source for the gas. Technological improvements resulted in commercially viable gas production and the rapid development of a major, new continuous natural gas and natural gas liquids play in the Appalachian Basin, the oldest producing petroleum province in the United States.

This USGS assessment is an estimate of continuous gas and natural gas liquid accumulations in the Middle Devonian Marcellus Shale of the Appalachian Basin. The estimate of undiscovered natural gas ranges from 43.0 to 144.1 TCF (95 percent to 5 percent probability, respectively), and the estimate of natural gas liquids ranges from 1.6 to 6.2 billion barrels (95 percent to 5 percent probability, respectively). There are no conventional petroleum resources assessed in the Marcellus Shale of the Appalachian Basin.

These new estimates are for technically recoverable oil and gas resources, which are those quantities of oil and gas producible using currently available technology and industry practices, regardless of economic or accessibility considerations. As such, these estimates include resources beneath both onshore and offshore areas (such as Lake Erie) and beneath areas where accessibility may be limited by policy and regulations imposed by land managers and regulatory agencies.

The Marcellus Shale assessment covered areas in Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia.

USGS is the only provider of publicly available estimates of undiscovered technically recoverable oil and gas resources of onshore lands and offshore state waters. The USGS worked with the Pennsylvania Geological Survey, the West Virginia Geological and Economic Survey, the Ohio Geological Survey, and representatives from the oil and gas industry and academia to develop an improved geologic understanding of the Marcellus Shale. The USGS Marcellus Shale assessment was undertaken as part of a nationwide project assessing domestic petroleum basins using standardized methodology and protocol.

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Statoil Boosts Estimates at N. Sea Find

- Statoil Boosts Estimates at N. Sea Find

Tuesday, August 16, 2011
Statoil

Communication between the Aldous and Avaldsnes oil discoveries in the North Sea has now been confirmed. In combination these discoveries may represent an oil structure of between 500 million and 1.2 billion barrels of recoverable oil equivalent.

If the upper part of the interval strikes pay dirt, the discovery will be one of the ten largest oil finds ever on the Norwegian continental shelf (NCS). Statoil has a 40% stake both in license PL 265, where Aldous was discovered, and in PL 501, where the Avaldsnes discovery was made.

"Aldous/Avaldsnes is a giant oil discovery, and according to our estimates the combined discovery may make the top 10 list of NCS oil discoveries. Norway has not seen a similar oil discovery since the mid-eighties," said Tim Dodson, Statoil's executive vice president for Exploration.

This is the third "high-impact discovery" for Statoil as an operator in 2011. In April of this year the 250 million barrel Skrugard oil discovery was made in the Barents Sea, and the 150-300 million barrel Peregrino South oil field was discovered offshore Brazil.

"The discoveries are a result of Statoil's exploration strategy of prioritizing high-impact opportunities, while focusing on our established core areas," said Dodson.

As the company announced on August 8, a minimum 65-meter oil column has been confirmed in Aldous Major South well 16/2-8 in the North Sea. The discovery was made in Jurassic sandstone in a very good quality reservoir consisting of coarse-grained, unconsolidated sand.

The well has also established common oil/water contact between the Aldous and Avaldsnes structures, and according to preliminary estimates the combined discovery in the two licenses (PL 265 and PL 501) totals between 500 million and 1.2 billion barrels of recoverable oil equivalent. Between 200 and 400 million barrels of these resources have been discovered in well 16/2-8, with strong indications from well data of another 200 to 400 million barrels of recoverable oil equivalent in the same structure, whereas a resource base of 100 to 400 barrels previously has been estimated in the Avaldsnes structure (PL 501).

The well was drilled by the Transocean Leader drilling rig, which soon will spud Aldous Major North well 16/2-9 (PL265) to clarify the further potential and any communication with Aldous/Avaldsnes. In addition the partners plan further appraisal drilling in license PL 265 next year to clarify the full volume potential for a future development solution.

"As we said at the Capital Market Day event in New York in June, the NCS is a world-class petroleum province. The Aldous/Avaldsnes discoveries are evidence that the NCS is still attractive. Making a discovery of this size in a mature area shows that exploration is all about perseverance, creativity and obtaining new knowledge," said Dodson.

Aldous Major South is located in license 265. Statoil is the operator and has a 40% interest. The other partners are Petoro (30%), Det norske oljeselskap (20%) and Lundin (10%).

Avaldsnes is located in license 501. Lundin is the operator and has a 40% interest, whereas partners Statoil and Mærsk have 40% and 20% interests, respectively.

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Rockhopper Boosts Estimates at Sea Lion Play

- Rockhopper Boosts Estimates at Sea Lion Play

Monday, August 15, 2011
Rockhopper Exploration plc

Rockhopper provided the following update on the interpretation of the fast track seismic data over acreage on licenses PL032 and PL033:

• Initial interpretation of fast track new seismic data in PL032 and PL033 completed
• Seismic shows Sea Lion Main Complex ("SLMC") to extend to the south and new high case area to extend over 90km2
• Two new fan prospects identified within new seismic, Casper and Kermit
• Management interpretation for SLMC potential size: 
  • Low Case: 608 MMbbls STOIIP
  • Mid Case: 1,086 MMbbls STOIIP
  • High Case: 1,279 MMbbls STOIIP

Volumes listed above are within Rockhopper's 100% owned acreage. Not included in the high case listed above, based upon the current interpretation, the Company believes that up to approximately 10% additional volume could be contained within license PL004, in which Rockhopper has a non-operated 7.5% working interest.

During 2011 the Company acquired a total of over 4000km2 of 3D seismic data in conjunction with other operators in the area. Data over the southern portion of licenses PL032 and PL033 has been fast track processed and an initial interpretation has now been completed. This initial interpretation, combined with well data from 14/10-2, 14/10-3, 14/10-4, 14/10-5 and 14/10-6, indicates that the SLMC comprises two fan lobes sourced from the same main feeder channel just to the east of the 14/10-5 and 14/10-2 wells.

The two lobes, represented as sand packages within the wells, are identified as the SL20 and SL10 units, and, from the formation pressure data acquired in the wells, are shown to be in pressure communication. The two packages together comprise the SLMC and are interpreted to comprise of mass flow turbidite sand sequences prograding from the sand input point to the east and extending beyond the southern boundary of license PL032 into license PL004, where Rockhopper has a non-operated 7.5% working interest.

The Company believes that recovery rates of 30% to 40% could be achievable using industry standard production techniques including water injection, artificial lift, deviated or horizontal wells and /or other enhanced oil recovery techniques.

Should a recovery factor of 30% be achieved, based upon the Company's mid case area, the SLMC would contain approximately 325mmbbls recoverable oil. Should a recovery factor of 40% be achieved, the mid case number would increase to 434mmbbls recoverable oil.

The fast track seismic interpretation has enabled the identification of two new feeders into the basin and the mapping of two new prospects, Casper and Kermit. Both of these comprise similar fan systems fed from eastern basin margin feeder channels and exhibit similar seismic character to the SLMC. Casper is stratigraphically shallower than the SLMC while Kermit is stratigraphically deeper than the SLMC.

Following well 14/10-6 the Company believes that the B15 sand, which forms part of the lower fan complex, has the potential to contain up to 161 mmbbls STOIIP on a high case basis. Formation pressure testing indicates that B15 is also in communication with the SLMC.

Fan prospects currently mapped on the Company's acreage are now SLMC, Lower Fan (B sands), Chatham, Casper and Kermit.

In addition to the SLMC, management interpretation of potential in place resources across the other fan prospects within the licence is set out below (All mmbbls STOIIP):

	Low	Mid	High
Lower Fan (B15)	100	130	161
Casper	135	163	194
Kermit	39	47	55
Chatham	28	93	318

The balance of the newly acquired 3D seismic data is still being processed and the Company expects it will be available for interpretation before the end of 2011.

Future Drilling Plans

Following completion of drilling operations on well 14/10-6, the Company is currently committed to drill three further wells using the Ocean Guardian drilling unit. The Company is discussing the possibility of drilling additional wells under an assignment agreement.

The Company intends to drill the next well 3.3km north west of the 14/10-2 discovery well. The second well in the sequence is currently planned to be located approximately 4.1 km to the south south east of the 14/10-2 discovery well. The third well in the sequence is currently planned to be located approximately 5.5km south west of the 14/10-2 discovery well. The second and third locations are subject to change depending upon drilling results and technical work and are subject to gaining the relevant regulatory consents. The Company currently intends to wait for the result of well 14/10-7 before deciding whether to take any additional drilling slots. Estimates of in place and prospective resource information are based upon wells drilled to date and could alter with future well results. Once the Company completes its current drilling campaign, all estimated potential in place resource estimates will be further refined.

Operations continue at the 14/10-6 location and a further announcement will be made once 14/10-7 has been spudded.

Sam Moody, Chief Executive, commented, "We are highly encouraged by the interpretation of new seismic data which identifies both significant reservoir extension and the existence of two additional fan prospects above and beneath the Sea Lion Main Complex. We look forward to continuing our drilling program as we seek to further refine our understanding of Sea Lion and the other prospects on our licenses."

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GTI Boosts Marcellus Presence with Pittsburgh Office

- GTI Boosts Marcellus Presence with Pittsburgh Office

Tuesday, August 09, 2011
Gas Technology Institute

Gas Technology Institute (GTI) on Wednesday announced the opening of the organization's newest office in Pittsburgh, PA. Headquartered in the Chicago suburb of Des Plaines, IL, GTI has field offices across the country, and the new office in Pittsburgh represents GTI's local commitment to the natural gas industry in the Marcellus Shale fairway and the surrounding region.

GTI's continued growth in this region will be achieved by generating effective technology development and services based on customer needs, and through partnering to develop technology, create collaborative opportunities and achieve strategic business results. The efforts led by the Pittsburgh Office will advance the development of innovative solutions to the region's most pressing challenges.

"We're excited about establishing a stronger presence in this important region," says David Carroll, President and CEO of GTI. "We are committed to the future of natural gas and see tremendous opportunity for growth in the shale market where GTI has performed analysis since the 1980s. Our new office location will help us provide the continued high-level customer service and technology developments that will help meet today's complex energy and environmental challenges."

The Director of the Pittsburgh office is Patrick Findle, who has worked for GTI earlier in his career and has returned to help establish a strategic beachhead for business growth. He brings many years of technology business development in the natural gas industry that will help GTI build industry relationships and facilitate new business.

Notes Findle, "Along with growing global demand for natural gas, there is a correlating demand for new technologies to enable and ensure its responsible production, distribution, and use. The opening of the Pittsburgh Office is evidence of GTI's commitment to become a valued resource and partner to the natural gas industry as it transforms this region."

The GTI PA office can be found at 800 Old Pond Road, Suite 706 B, Bridgeville, PA 15017; 412-319-7249.

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EOG CEO: Boosts Asset Sale Target to $1.6B, from $1B

- EOG CEO: Boosts Asset Sale Target to $1.6B, from $1B

Friday, August 05, 2011
Dow Jones Newswires
HOUSTON
by Ryan Dezember

EOG Resources Chief Executive Mark Pappa said Friday the oil and gas explorer is increasing the amount of cash it hopes to raise by selling assets this year in order to offset rising oilfield service costs.

The assets being sold "are primarily mature long-lived domestic gas properties and other acreage," Pappa told investors during a conference call to discuss EOG's second-quarter results. Those properties are scattered in east Texas, the mid-continent and in the Gulf of Mexico.

Houston-based EOG posted a profit of $295.6 million, or $1.10 a share, up from $59.9 million, or 24 cents a share, a year earlier. Excluding hedging impacts, write-downs and other impacts, per-share earnings rose to $1.11 from 18 cents.

Revenue jumped 89% to $2.57 billion on a 13% increase in output and oil prices that climbed 37%.

Analysts polled by Thomson Reuters expected a per-share profit of 79 cents and revenue of $2.01 billion. Shares rose 6.22% to $97.86 in early Friday trading.

While EOG's oil and natural-gas liquids production rose in the second-quarter, natural-gas output was about 1% lower to an average of 1,615 million cubic feet per day. EOG has stressed its shift to oil production in recent quarters due to an oversupply-induced natural-gas price slump.

"We're not interested in growing North American gas volumes at current prices unlike most other companies," Pappa said, adding that EOG will drill in natural-gas basins only where necessary to preserve leases.

By mid-year, EOG had completed $944 million worth of gas-asset sales and has another $271 million in deals pending, Pappa said. The divesture target should be reached by the end of the year.

About $400 million of the extra $600 million being raised will be spent on rising oilfield-service costs, Pappa said.

Beyond raising money to cope with oil-patch inflation, Pappa said EOG plans to open a Wisconsin sand mine in the fourth quarter, which will supply sand proppant for "most of our North American resource plays."

Proppant is a crucial component in hydraulic fracturing, a process in which water, sand and chemicals are forced deep underground to crack open energy-bearing rocks, including shales, so that oil and natural gas can seep out. The sand, or proppant, wedges into the resulting fissures to hold them open. Proppant, which comes in grades ranging from raw sand to manufactured ceramic spheres, is in tight supply worldwide.

Supplying much of its own proppant should save EOG some $400 million a year and help reduce the cost of drilling a well in its prolific Eagle Ford wells in south Texas by about $1 million, executives said.

EOG has also signed an agreement for a 70,000-barrel-a-day rail off-loading facility in St. James, La., that will allow it to transport most of its crude oil from the Eagle Ford and North Dakota's Bakken Shale around Cushing, Okla., where congestion has depressed oil prices this year, to the Gulf Coast, where crude oil fetches a premium.

The Louisiana off-loading facility should be able to start taking shipments in the first quarter of 2012 and will enable EOG to take advantage of the difference in regional oil prices, Pappa said.

Pappa, who turns 65 next month, also said Friday that he will remain as CEO for the next 18 months "and, when I do retire, my successor will be a long-tenured EOG employee."

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

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Lundin Reports Strong 2Q Results, Boosts Output Forecast

- Lundin Reports Strong 2Q Results, Boosts Output Forecast

Wednesday, August 03, 2011
Lundin Petroleum AB

Lundin reported for the six month period ended June 30, 2011

Six months ended June 30, 2011

• Production of 32,300 boepd up 13% from the first six months 2010
• Profit after tax of MUSD 130.3 up 526% from the first six months 2010
• EBITDA of MUSD 505.3 up 96% from the first six months 2010
• Operating cash flow of MUSD 390.3 up 52% from the first six months 2010
• Net debt down to below MUSD 120 from MUSD 410 at year end
• Five exploration discoveries, four in Norway and one in Malaysia
• Ten Norwegian licenses awarded in the 2010 Norwegian licensing round, six as operator
• Operated license awarded in Barents Sea in the 21st Norwegian licensing round
• Operated Gurita block awarded in the Natuna Sea, offshore Indonesia

Second Quarter ended June 30, 2011

• Production of 31,100 boepd
• Profit after tax of MUSD 76.9
• EBITDA of MUSD 266.9
• Operating cash flow of MUSD 196.7
• Three exploration discoveries – Skalle and Earb South discoveries in Norway and Tarap discovery in Malaysia
• Appraisal well confirmed extension of the Avaldsnes discovery
• New operated block PM307 awarded in Malaysia
• Brynhild field plan of development (formerly called Nemo) submitted

Comments from C. Ashley Heppenstall, President and CEO

Lundin Petroleum achieved excellent results in the second quarter of 2011 with increased profitability and cash flow. What is extremely pleasing however, is the continued exploration success. I have always highlighted that the major valuation creation for our company will be achieved through increasing our oil and gas resources, and the best way to do that is through exploration.

Lundin Petroleum produced a net result for the first six months of MUSD 130.3. The strong production coupled with oil prices achieved of well over USD 100 per barrel resulted in operating cash flow of MUSD 390.3 and EBITDA of MUSD 505.3. Despite our significant exploration and development investment program net debt during the first half of the year has reduced from MUSD 410 to below MUSD 120.

The positive exploration news has continued during the second quarter with further discoveries at Skalle in PL438 in the Barents Sea, Earb South in PL505 in the northern Norwegian north Sea and Tarap in Block SB303 offshore East Malaysia. In addition the results of the first Avaldsnes appraisal well were extremely encouraging confirming the extension of the Avaldsnes field to the south east. We have now achieved five discoveries from our first five exploration wells this year following the Tellus and Caterpillar discoveries during the first quarter.

Our business is continuing to grow and I am confident we will continue to increase shareholder value. We are generating strong cash flow and profitability from our existing production which is outperforming, our development projects are proceeding well and our exploration success continues.

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Origin Boosts Total 2P Reserves by 13%

- Origin Boosts Total 2P Reserves by 13%

Friday, July 29, 2011
Origin Energy Ltd.

Origin announced record annual production and sales revenues for its Exploration and Production business, released in the company's Production Report for the quarter to June 30, 2011.

This follows the release yesterday of Origin's 2011 Annual Reserves Report, in which the company announced a 13 percent annual increase in total Proved plus Probable (2P) reserves.

Origin Executive Director, Finance and Strategy, Ms. Karen Moses, said, "The Exploration and Production business has delivered record annual production of 135 Petajoules equivalent (PJe), up 30 percent on the prior year. Sales revenues also increased to a record $835 million, an increase of 32 percent on the prior year.

"The strong performance was driven by a 36 percent increase in production from Australia Pacific LNG as gas was supplied into major new contracts, higher production from Origin's increased share of Otway, a full year's contribution from Kupe and higher production from BassGas after an extended shutdown in 2009/2010.

"Notably, the record increases were achieved amid a challenging operating environment with extreme weather conditions impacting a number of our assets.

"Origin also reported a 13 percent annual increase in 2P reserves to 7,041 PJe, driven by increases in our CSG reserves held through Australia Pacific LNG and in the Ironbark area," Ms. Moses said.

During the year, Australia Pacific LNG made significant progress on its CSG to LNG project, culminating with a Final Investment Decision announced on July 28, 2011. The decision initiates development of the first LNG train and infrastructure to support a second train, and is underpinned by a sale and purchase agreement with Sinopec for the supply of 4.3 million tonnes per annum of LNG. Sinopec has also subscribed for a 15% equity interest in Australia Pacific LNG1.

"The Final Investment Decision on the first phase of the Australia Pacific LNG project marks the commencement of one of Australia’s largest LNG export projects," Ms. Moses said.

"Australia Pacific LNG holds Australia's largest 2P CSG reserves, including extensive acreage within the premier production fairways providing high quality gas resources with high deliverability," Ms. Moses said.

Production for the quarter to 30 June 2011 was 37 PJe, or 23 percent, higher than the June Quarter in 2010, with all asset areas either increasing production or maintaining production at comparable levels. Most notably, Otway increased production by 49 percent. Total sales volumes and revenues increased by 8 percent and 11 percent respectively.

Compared with the March Quarter 2011, production was 28 percent higher, as Otway returned to higher production levels and CSG and Cooper Basin production increased after the floods experienced earlier in the year. Sales volumes and revenues were 19 percent and 14 percent higher respectively, reflecting the increased production.

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Whiting Boosts 2Q Production in 2011, Ups Capex to $1.6B

- Whiting Boosts 2Q Production in 2011, Ups Capex to $1.6B

Thursday, July 28, 2011
Whiting Petroleum Corp.

Whiting's production in the second quarter of 2011 totaled 5.84 million barrels of oil equivalent (MMBOE), of which 4.79 million barrels were crude oil/natural gas liquids (82%) and 1.05 MMBOE was natural gas (18%). This second quarter 2011 production total equates to a daily average production rate of 64,120 barrels of oil equivalent (BOE), which compared to the 64,600 BOE average daily rate in the second quarter of 2010.

After three weeks of mostly dry weather, we are making good progress fracing new wells and returning wells to production. In the Williston Basin, we reached a new production record of 58,105 BOE per day gross (31,161 net) on July 19, 2011. Our Sanish field is also coming back strong after first half 2011 inclement weather, reaching 44,102 BOE per day gross (22,817 net) on July 19, 2011.

We currently have two full-time dedicated frac crews and one half-time frac crew working in the Williston Basin and believe they are capable of fracing approximately 18 to 20 wells per month between now and year-end 2011. Therefore, we expect to reduce our current 44-well inventory of operated wells waiting on completion to below 25 by November 30, 2011. Based on our current drilling rig count of 17 rigs working in the Williston Basin, 20 to 25 wells being prepared for completion represents a typical inventory.

We have 11 service units running in the Sanish field and are making good progress in placing back into production wells that were shut-in during the inclement weather due to muddy roads. As of July 15, 2011, we had 27 wells waiting for a service unit. We expect this inventory to be eliminated by September 30, 2011

We reported in our news release of June 8, 2011, that our Seep Ridge Gas Pipeline in Uintah County, Utah was shut-in for repairs on April 16, 2011. The pipeline was back on stream June 14, 2011 and is currently at full capacity. We are transporting 21.9 million cubic feet (MMcf) of gas per day net to Whiting's interests from the Flat Rock and Chimney Rock fields.

In addition on June 8, 2011, we reported that we were experiencing under-deliveries of CO2 contract quantities from our North Ward Estes field CO2 supplier. The shortfall was approximately 25 MMcf per day below our contracted delivery volume of 134 MMcf per day. Currently, we are receiving 122 MMcf per day and expect to resume delivery of full contract quantities by September 30, 2011. Further, we have recently signed two new CO2 supply contracts for additional quantities of CO2 that we expect to be sufficient to fully execute our development plans at North Ward Estes for several years. More details are included later in this news release.

Second Quarter 2011 Financial Results

Discretionary cash flow in the second quarter of 2011 totaled a record $313.3 million, representing an increase of 37% over the $228.2 million reported for the same period in 2010. The increase in discretionary cash flow in the second quarter of 2011 versus the comparable 2010 period was primarily the result of a 29% increase in the Company's realized oil price (net of hedging), including the price of natural gas liquids (NGLs). A reconciliation of discretionary cash flow to net cash provided by operating activities is included later in this news release.

In the second quarter of 2011, Whiting reported net income available to common shareholders of $202.9 million, or $1.73 per basic share and $1.71 per diluted share, on total revenues of $481.2 million. This compared to net income available to common shareholders of $119.9 million, or $1.18 per basic share and $1.06 per diluted share, on total revenues of $377.6 million in the second quarter of 2010.

The Company's second quarter 2011 results include after-tax unrealized derivative gains of $84.5 million, or $0.71 per diluted share. Excluding this gain and certain other items, Whiting reported second quarter 2011 adjusted net income available to common shareholders of $120.3 million, or $1.02 per basic and diluted share. This compared to second quarter 2010 adjusted net income available to common shareholders of $72.2 million, or $0.71 per basic share and $0.66 per diluted share. A reconciliation of adjusted net income available to common shareholders versus net income available to common shareholders is included later in this news release.

First Six Months 2011 Financial Results

Discretionary cash flow in the first six months of 2011 totaled $597.4 million, representing an increase of 35% over the $442.7 million reported for the same period in 2010. The increase in discretionary cash flow in the first half of 2011 versus the comparable 2010 period was primarily the result of a 23% increase in the Company's realized oil price (net of hedging), including the price of NGLs. A reconciliation of discretionary cash flow to net cash provided by operating activities is included later in this news release.

In the first six months of 2011, Whiting reported net income available to common shareholders of $222.0 million, or $1.89 per basic share and $1.87 per diluted share, on total revenues of $913.4 million. This compared to net income available to common shareholders of $201.1 million, or $1.97 per basic share and $1.79 per diluted share, on total revenues of $728.9 million in the first six months of 2010.

Excluding after-tax unrealized derivative gains and losses and certain other items, Whiting reported first half 2011 adjusted net income available to common shareholders of $221.2 million, or $1.89 per basic share and $1.87 per diluted share. This compared to first half 2010 adjusted net income available to common shareholders of $134.7 million, or $1.32 per basic share and $1.23 per diluted share. A reconciliation of adjusted net income available to common shareholders versus net income available to common shareholders is included later in this news release.

James J. Volker, Whiting's Chairman and CEO, commented, "Our two recent discoveries at Redtail and Hidden Bench, our new wells at Sanish and Lewis & Clark and our encouraging results at Big Tex demonstrate our strategy and ability to develop new oil play areas for future multi-rig development while successfully executing on our existing large scale resource plays. This course of action resulted in our decision to increase our capital budget to $1.60 billion from $1.35 billion."

Mr. Volker continued, "We hold more than 680,000 net acres in the Bakken/Three Forks Hydrocarbon System that we believe will provide increased production and reserve additions. We added 76,000 net acres in the Williston Basin during the second quarter. With our planned development in these new areas and our existing core properties, we expect a strong second half in 2011."

2011 Capital Budget Increased to $1.6 Billion from $1.3 Billion

Whiting has increased its 2011 capital budget to $1,600.0 million from $1,350.0 million. Of this $250.0 million increase, we expect to invest approximately $90.0 million in additional land acquisitions. We have increased our acreage acquisition budget to $200.0 million from $110.0 million. We expect to invest the remaining $160.0 million in drilling. New plays receiving a portion of this funding in 2011 include the Hidden Bench prospect in McKenzie County, North Dakota (18 additional wells), the Cassandra prospect in Williams County, North Dakota (6 additional wells), the Starbuck prospect in Richland County, Montana (5 additional wells), and our Redtail Niobrara prospect in Weld County, Colorado (4 additional wells). The increased budget is expected to be funded through internal cash flow and bank borrowings from our line of credit.

Hidden Bench Prospect. Whiting completed the Arnegard 21-26H discovery well at its Hidden Bench prospect flowing 2,423 barrels of oil and 4,012 thousand cubic feet (Mcf) of gas or 3,092 BOE per day from an 8,913-foot lateral in the Bakken formation on June 23, 2011. The flow rate was gauged on a 48/64-inch choke with a flowing casing pressure of 900 psi. The well, which was drilled to a vertical depth of approximately 11,490 feet, was fracture stimulated in a total of 30 stages, all using sliding sleeves. Whiting owns 59,170 gross (30,905 net) acres in the Hidden Bench prospect, located in McKenzie County, North Dakota. The Company plans to drill a total of 11 operated wells in the prospect in 2011.

Also at Hidden Bench, Whiting completed the Rovelstad 21-13H flowing 1,880 barrels of oil and 3,419 Mcf of gas (2,450 BOE) per day on June 15, 2011. The well was tested on a 48/64-inch choke with a flowing casing pressure of 700 psi and was fracture stimulated in a total of 30 stages, all using sliding sleeves. The Rovelstad well is located approximately two miles northeast of the Arnegard well.

Redtail Prospect. Whiting completed the Wild Horse 16-13H discovery well at its Redtail prospect flowing 1,061 barrels of oil and 1,561 Mcf of gas (1,321 BOE) per day from the Niobrara formation at a vertical depth of 6,762 feet. The flow rate, which was taken on June 16, 2011, was gauged on a one-inch choke with a flowing casing pressure of 270 psi. The Wild Horse 16-13H was fracture stimulated in 21 stages, all using sliding sleeve technology. The well's lateral length was 4,113 feet. The Wild Horse 16-13H produced at an average rate of 454 BOE per day during its first 30 days of production. Based on the results of this well, Whiting added four wells to its 2011 drilling program at Redtail. As of July 15, 2011, Whiting had acquired 103,880 gross (75,701 net) acres in the Redtail prospect in the Denver Julesburg Basin. Our average acreage cost to date is $462 per net acre, and we have an average working interest of 73% and an average net revenue interest of 61%.

Our first three horizontal wells at Redtail, the Pawnee 16-13H, the Terrace 36-11H and the Chalk Bluffs 36-13H, were completed with initial flow rates of 141 BOE per day, 105 BOE per day and 99 BOE per day. We believe that the higher production rates exhibited at the Wild Horse well were primarily the result of changing the well orientation to a northeast azimuth from an east to west orientation and modifying our frac design, including our frac fluid. We expect our next well at Redtail, the Two Mile Creek 22-13H, to be completed by the end of July 2011.

Big Tex Prospect. Whiting fraced its first horizontal well at the Big Tex prospect the first week of July 2011. The Bissett 9701, located in the Delaware Basin in Pecos County, Texas, produced 788 BOE per day (92% oil) from the Wolfbone on July 25, 2011. The well is still cleaning up after frac. The well's 3,610-foot lateral was fracture stimulated in a total of 16 stages, all using sliding sleeves.

As of July 15, 2011, Whiting had accumulated 116,494 gross (88,062 net) acres in our Big Tex prospect area in Pecos, Reeves and Ward Counties, Texas in the Delaware Basin. Our average acreage cost to date is $540 per net acre, and we have an average working interest of 76% and an average net revenue interest of 57%.

Big Island Prospect. At our Big Island prospect in Golden Valley County, North Dakota, we completed the Maus 23-22 pumping 282 barrels of oil per day from the Red River formation at a depth of approximately 12,450 feet. This is a conventional vertical well that we believe sets up four more tests of adjacent Red River prospects. We estimate EURs in this area at 400,000 BOE for a completed well cost of only approximately $3.8 million.

Operations Update - Core Development Areas

Bakken and Three Forks Development

Lewis & Clark Prospect. Whiting completed the Clemens 34-9TFH in the Three Forks formation flowing 1,919 barrels of oil and 1,137 Mcf of gas (2,108 BOE) per day on June 29, 2011. The well was tested on a 48/64-inch choke with a flowing casing pressure of 544 psi. The Clemens well, which was drilled on the north-central portion of the Lewis & Clark prospect in Billings County, North Dakota, was fracture stimulated in a total of 30 stages. The new producer was drilled approximately five miles east of the Federal 32-4TFH discovery well, which was completed in the Three Forks formation flowing 1,970 BOE per day on November 25, 2009.

Also at Lewis & Clark, Whiting completed the Richard 21-15TFH in the Sanish Sand flowing 865 barrels of oil and 977 Mcf of gas (1,028 BOE) per day on May 22, 2011. The well was tested on a 20/64-inch choke with a flowing casing pressure of 483 psi. The Richard well, which was drilled on the southeast side of the prospect in Stark County, North Dakota, was fracture stimulated in a total of 30 stages.

We own 387,351 gross (254,818 net) acres in the Lewis & Clark prospect, which is more than three and a half times larger than our Sanish field. At Lewis & Clark, Whiting has a controlling interest in 164 1,280-acre spacing units with an average working interest of 64%. Based on production to date at Lewis & Clark, it appears that these wells have a relatively shallow decline rate. Therefore, we continue to believe that our wells at Lewis & Clark will have Estimated Ultimate Recoveries (EURs) in the 300,000 to 500,000 BOE range.

Whiting's net production from the Lewis & Clark prospect averaged 2,640 BOE per day in the second quarter of 2011, up 93% from the 1,370 BOE per day average in the first quarter of 2011. From April 15 through July 15, 2011, Whiting completed 10 new wells at Lewis & Clark, bringing the total number of producing operated wells to 26. The average initial production rate for the 10 new wells came to 647 BOE per day. As of July 15, 2011, there were nine wells being completed or awaiting completion and six wells were being drilled. We currently have six drilling rigs operating in this project, and we expect to average eight rigs working from September through December. Based on well results to date, we plan to step up activity in the Stark County and Billings County portions of the prospect in the second half of 2011.

New Pronghorn Gas Plant. In early April 2011, Whiting broke ground on the construction of a gas processing plant at Lewis & Clark. The Pronghorn Gas Plant, formally named the Belfield Gas Plant, is located near Belfield, North Dakota. The Pronghorn Gas Plant will have an initial inlet capacity of 30 MMcf of gas per day and is expected to be completed by November 2011.

Whiting's net production from the Middle Bakken and Three Forks formations in the Sanish and Parshall fields of Mountrail County, North Dakota averaged 24,350 BOE per day in the second quarter of 2011 in the face of extreme weather, a decrease of 6% from the 26,010 BOE average daily rate in the first quarter of 2011.

In the Sanish field, we completed the Nesheim 11-24XH flowing 3,502 barrels of oil and 1,500 Mcf of gas (3,752 BOE) per day on July 14, 2011. The cross-unit well flowed on a 48/64-inch choke with a flowing casing pressure of 720 psi. The well was fracture stimulated in a total of 30 stages, all using sliding sleeve technology. The new producer was drilled on the east-central side of the Sanish field.

Also in the Sanish field, Whiting completed the Brookbank State 41-16XH flowing 2,503 barrels of oil and 1,990 Mcf of gas (2,835 BOE) per day on June 10, 2011. This cross-unit well flowed on a 52/64-inch choke with a flowing casing pressure of 700 psi. The well was fracture stimulated in a total of 21 stages, all using the plug & perf method.

Whiting recently completed its second wing well in the Sanish field. The Oppeboen 14-5WH was completed flowing 2,198 barrels of oil and 581 Mcf of gas (2,294 BOE) per day on July 15, 2011. The well's flow rate was gauged on a 20/64-inch choke with a flowing casing pressure of 1,233 psi. The well's 6,176-foot lateral was fracture stimulated in a total of 22 stages, all using sliding sleeves. Whiting has a total of up to 81 potential wing well locations in Sanish field. A wing well is normally a well drilled within a typical east-west trending 1,280-acre unit near the north or south lease line with an approximate 7,000-foot lateral.

Whiting also saw strong results from a Three Forks well in the Sanish field. The Vangen 11-3TFH was tested flowing 1,200 barrels of oil and 830 Mcf of gas (1,338 BOE) from the Three Forks formation on June 25, 2011. The flow rate was gauged on a 40/64-inch choke with a flowing casing pressure of 409 psi. The well was drilled on the south-central side of the Sanish field.

Whiting owns 106,898 gross (65,056 net) acres in the Sanish field, located in Mountrail County, North Dakota. Whiting's net production from the Sanish field in the second quarter of 2011 averaged 20,515 BOE per day, a decrease of 5% from the first quarter 2011 average rate of 21,685 BOE per day. The decrease was due to well completion delays and downtime resulting from inclement weather in North Dakota. Compared to the second quarter 2010 average rate of 20,045 BOE per day, production in the second quarter of 2011 was up 2%.

From April 15 through July 15, 2011, Whiting completed five operated Bakken wells and three operated Three Forks wells in the Sanish field. The average initial production rate for the five Bakken wells came to 2,614 BOE per day, while the initial production rates for the three Three Forks wells averaged 811 BOE per day. The eight new completions bring to 171 the number of Whiting-operated wells in the Sanish field as of July 15, 2011. Including non-operated wells, there were 243 producing wells in the Sanish field as of July 15, 2011. The Company plans to continue with its current nine operated drilling rig count in the Sanish field through 2013. In 2011, Whiting intends to drill 95 operated wells (52.7 net wells) in the field, of which 70 are planned Three Forks wells, 15 are cross-unit Bakken wells, seven are Bakken infill wells and three are wing wells. Whiting has contracted two full-time dedicated frac crews and a half-time crew that started the last week of June 2011 working in the Williston Basin that we believe are capable of fracture stimulating 18 to 20 wells per month. As of July 15, 2011, 29 operated wells and six non-operated wells were being completed or awaiting completion and eight operated wells and two non-operated wells were being drilled in the Sanish field.

The 17-mile oil line connecting the Sanish field to the Enbridge pipeline in Stanley, North Dakota is currently transporting approximately 33,000 barrels per day, which represents approximately 85% of Whiting's gross operated Sanish production. This 8-inch diameter line has a capacity of approximately 65,000 barrels of oil per day. The Company is currently saving between $1.00 and $2.00 per barrel in transportation costs for each barrel that is transported through the pipeline rather than being transported by truck.

Robinson Lake Gas Plant. During the second quarter of 2011, a fractionation facility and a second NGL train were brought online at the Robinson Lake Gas Plant. As of July 8, 2011 the plant is processing 39.6 MMcf of gas per day (gross). The plant has a processing capacity of 90 MMcf of gas per day. Currently, there is inlet compression in place to process 70 MMcf per day, and compression will be added as the processing demand increases. Whiting owns a 50% interest in the plant. The plant receives 25% of the net proceeds from natural gas and NGLs processed at the plant. As of July 8, 2011, sales from the plant were 30.9 MMcf of gas and 4,372 barrels of NGLs per day, from which Whiting was netting 3.9 MMcf of gas and 546 barrels of NGLs per day due to its 50% plant ownership.

Williston Basin Land Position. Whiting increased its acreage position in the Bakken / Three Forks Hydrocarbon System of the Williston Basin to 1,102,302 gross acres from 999,972 gross acres and to 680,137 net acres from 603,702 net acres. This includes 62,180 gross (41,332 net) acres in Richland County, Montana acreage, referred to as the Missouri Breaks prospect, which is prospective in both the Bakken and Three Forks formations. The Company expects to drill at least one well at Missouri Breaks in the second half of 2011. Whiting's average cost for its entire Williston Basin acreage is currently $419 per net acre.

In-House Core Analysis. In April 2011, Whiting installed two scanning electron microscope workstations in its Denver office. These machines enable us to perform core analyses in weeks rather than months. We believe that we are one of the few companies in the US to have this in-house capability.

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Husky Boosts Production, Profit in 2Q11

- Husky Boosts Production, Profit in 2Q11

Wednesday, July 27, 2011
Husky Energy Inc.

Husky continued to execute against its strategic plan in the second quarter of 2011, recording strong growth in earnings, cash flow and production compared to the same period a year earlier. Net earnings grew 274 percent compared to the second quarter of 2010, cash flow increased 104 percent, and production grew 10 percent.

"This marks a second consecutive quarter of strong results across key performance metrics," said Husky CEO Asim Ghosh. "Over the past 12 months we have made significant progress in implementing our strategic plan and executing a financing strategy to carry out our growth initiatives. The momentum we have built in growing production combined with a strong performance from our Midstream and Downstream segments, has enabled us to deliver solid improvements in results."

Production for the quarter averaged 311,600 barrels of oil equivalent per day (boe/day), compared to 283,900 boe/day in the second quarter of 2010. Production gains were achieved despite forest fire and pipeline disruptions in northern Alberta as the Company realizes the benefits from recent acquisitions of oil and gas properties in Western Canada and increased investment in organic growth opportunities.

"In addition, we continue to achieve key milestones in advancing our growth pillars," said Ghosh. "This quarter Husky and its partner in the Liwan Gas Project reached agreements on natural gas prices and have jointly approved the Overall Development Plan (ODP) for the first phase of the development. The submission of the ODP to Chinese government authorities will now take place. This will be a cornerstone development for Husky as we look to build a substantial oil and gas business in the region."

Highlights from the second quarter included the following:

• Net earnings of $669 million, or $0.71 per share (diluted). This compares to net earnings of $179 million or $0.19 per share in the second quarter of 2010.
• Cash flow from operations of $1,511 million, or $1.67 per share (diluted), compared to cash flow of $739 million or $0.87 per share in the second quarter of 2010.
• Drilling was completed on an additional producing well at the North Amethyst field in the Atlantic Region. North Amethyst achieved average gross production of 33,000 bbls/day (23,000 net to Husky) in the quarter.
• Executed an agreement for the sale of gas from the first phase of the Liwan Gas Project The gas price mechanism is in line with the anticipated Guangdong "city gate" market price and provides for an attractive rate of return on the project.
• Phase 1 of the Sunrise Energy Project continued to achieve its milestones, with the first 12 steam-assisted gravity drainage (SAGD) horizontal well pairs completed on schedule.
• Closed a $1.2 billion common share offering, providing the Company with enhanced financial flexibility to accelerate its growth strategy.

Production volumes in the second quarter were in line with annual guidance of 290,000 to 315,000 boe/day. Volumes were impacted by difficult operating conditions in the Slave Lake region where forest fires caused production interruptions, and by the outage of the Rainbow pipeline. The northern portion of the Rainbow pipeline was out of operation through May and June and impacted production by approximately 13,600 boe/day. The northern portion of the pipeline remains shut down, however, Husky has been able to reduce the impact of the outage to approximately 11,000 boe/day through a number of mitigating activities.

"Our thoughts and support are with the people of the Slave Lake region as they look to recover from this devastating event and begin the long process of rebuilding their homes and lives," said COO Rob Peabody. "We are grateful none of our workers were injured and our team in the region deserves a great deal of credit for the work they are doing to mitigate the effects of the disruptions."

Reduced volumes from the Slave Lake region were offset by recent acquisitions and strong performance from the North Amethyst field, which began producing in May 2010. A turnaround of the SeaRose Floating Production, Storage and Offloading (FPSO) vessel, originally scheduled for 16 days, was completed in two days in early July.

Second quarter earnings and cash flow growth were driven by higher production, higher realized crude oil and natural gas prices and strong throughput rates and margins within the Downstream segment. This was partially offset by a stronger Canadian dollar.

Average realized crude oil pricing in the quarter was $86.90 per barrel, compared to $64.75 in the same period of 2010. U.S. refining market crack spreads increased in the quarter, with the average Chicago 3:2:1 crack spread at U.S. $28.90 per barrel, compared to U.S. $11.33 in the same period of 2010.

KEY AREA SUMMARY AND GROWTH UPDATE: THE FOUNDATION BUSINESS

Western Canada - Unconventional and Conventional

The Company continues to maintain production levels in Western Canada and has accelerated development of its emerging oil and gas resource portfolio.

Oil Resource Plays

Husky has an extensive Western Canadian oil resource land base of approximately 500,000 acres and is advancing exploration and development of its highest-potential prospects.

In the second quarter, the Company acquired 11,500 acres in the Bakken formation in south central Saskatchewan, adjacent to its Oungre oil resource lands. Husky now holds 18,700 net acres in this light oil play. Current production from four producing wells is approximately 600 bbls/day and two additional wells have been drilled and will be completed once wet conditions recede. Given the positive results from the first Oungre Bakken wells, Husky has committed additional funds to accelerate the drilling and completion of 10 additional wells in the second half of 2011.

The Company continues to develop its opportunities in the Lower Shaunavon zone in southern Saskatchewan, the Viking zone in southwest Saskatchewan and central Alberta, and in the northern Cardium resource trend at Wapiti and Kakwa in west central Alberta. Spring break-up and extended wet conditions delayed drilling and completion plans in the second quarter, however, the Company expects to accelerate its activities in the second half of the year. The Company drilled two wells at its central Alberta Viking oil resource project in the second quarter, following a six well drilling program in the first quarter. A total of 11 Viking wells have been placed on production from this area along with another three from the southwestern Saskatchewan Viking oil resource project.

Gas Resource Plays

Husky continues to build its gas resource portfolio in Alberta and British Columbia, with approximately 16,000 acres of new land acquired in the quarter, adding to the Company's existing base of approximately 800,000 acres.

A key focus of activity has been the liquids-rich Cardium formation at Ansell in west central Alberta. In the first two quarters, Husky drilled 21 Cardium formation wells at Ansell and a further 12 Cardium and nine deeper multi-zone wells are planned in the second half. The Company is currently constructing additional offload capacity, which will increase total production capacity at Ansell to 56 mmcf/day and over 2,000 bbls/day liquids.

The Company took steps in the quarter to seek a joint venture partner to accelerate development of the Ansell assets. A preliminary development plan has been created which could potentially see up to 2,600 Cardium and deeper Manville formation wells drilled on the play, most of which would be horizontal.

Heavy Oil

To maintain current heavy oil production levels, the Company is accelerating thermal developments. The goal is to achieve an increasingly higher proportion of heavy oil production through thermal at finding and development (F&D) and operating costs comparable to current levels.

Construction of the 8,000 bbls/day South Pikes Peak thermal project was approximately 67 percent complete at the end of the second quarter, and is progressing on schedule and within original cost estimates. First production is expected in mid-2012.

The 3,000 bbls/day Paradise Hill thermal development is progressing on schedule and is approximately 28 percent complete. Paradise Hill will use existing Bolney infrastructure and is planned to become operational in the third quarter of 2012.

Exploration

Husky successfully acquired the exploration rights to two parcels of land in the Northwest Territories in a Call for Bids in the Central Mackenzie Valley. Each block contains approximately 215,000 acres with a five-year primary term and a term extension to nine years when a well is drilled. The lands complement the existing portfolio of resource plays and are close to existing pipeline infrastructure. Development of the properties will be considered in the context of Husky's full suite of opportunities.

The Company is presently evaluating the timing of preliminary work on the new concessions, including conducting 3D seismic and well drilling.

GROWTH PILLARS

Oil Sands

Phase 1 of the Sunrise Energy Project continues to progress on schedule towards planned first production in 2014. In the second quarter, drilling was completed on the first 12 SAGD horizontal well pairs, as part of 49 planned initial well pairs. SAGD drilling costs are trending on budget and on schedule, with the full drilling program forecast to be completed in the third quarter of 2012.

Engineering contractors achieved detailed engineering milestones during the quarter and purchases of major equipment and preparation for surface facility construction remain on schedule for the third quarter.

Conceptual development engineering for subsequent phases of the Sunrise Energy Project has been initiated and a full field development plan is expected to be completed by the end of 2011.

Progress continues at the Tucker Oil Sands Project as the Company enhances its understanding of how to develop the reservoir. Production averaged 6,400 bbls/day during the quarter and Tucker exited the quarter in excess of 7,000 bbls/day.

Atlantic Region

The North Amethyst satellite development continued to perform well through the second quarter, with average gross production of 33,000 bbls/day (23,000 bbls/day net to Husky). Drilling was completed on an additional producing well and a supporting water injection well is scheduled to be completed in the third quarter. The production well came on stream June 23 at a rate of 6,200 bbls/day.

Husky will participate in a partner-operated exploration well at Mizzen in the third quarter. The well will aid in evaluating the 2009 oil discovery on the prospect, located in the Flemish pass. Husky holds a 35 percent working interest in the field. An exploration well is also planned for the fourth quarter to test the partner-operated Fiddlehead prospect, located south of the Terra Nova field. Husky holds a 50 percent working interest in the well.

South East Asia

Development of the Liwan Gas Project offshore southeast China achieved a significant milestone, with the approval of the ODP for the Liwan 3-1 field by Husky and its joint partner, China National Offshore Oil Corporation (CNOOC). Submission of the ODP to Chinese government authorities will now take place.

The companies continue to advance the development towards planned first gas in late 2013 or early 2014.

In support of the ODP submission, a gas sale agreement has been executed with CNOOC Gas and Power Group, Guangdong Trade Branch, for the sale of gas from the Liwan 3-1 field. The gas will supply the Guangdong Province natural gas grid from an onshore gas plant on Gaolan Island, Zhuhai. The gas price mechanism is in line with the anticipated Guangdong "city gate" market price, establishing an attractive rate of return for the project.

The Liwan Gas Project is comprised of three significant gas discoveries the Company has made on Block 29/26: Liwan 3- 1, Liuhua 34-2 and Liuhua 29-1. A gas contract agreement and ODP filing for the Liuhua 34-2 field is expected later this year and similar milestones are anticipated for the Liuhua 29-1 field in 2012.

Production from the Liwan 3-1 field and the Liuhua 34-2 field is expected to ramp up through 2014 towards a rate above 300 mmcf/day (gross). In 2015, the Liuhua 29-1 field is expected to be placed on stream, increasing gross production to approximately 500 mmcf/day. Husky has a 49 percent ownership interest in production.

The Company's share of the estimated total overall integrated project cost of U.S.$6.5 billion will be approximately U.S.$3 billion.

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Tie-In Boosts Kulczyk Oil's Ukraine Gas Production

- Tie-In Boosts Kulczyk Oil's Ukraine Gas Production

Tuesday, July 26, 2011
Kulczyk Oil Ventures Inc.

Kulczyk Oil announced that total gas production on its properties in Ukraine has increased by 70% to more than 10 million cubic feet per day ("MMcf/d") (more than 7 MMcf/d net to KOV), as a result of the tie-in of the M-19 discovery well in the Makeevskoye Field.

Highlights

• M-19 well initial average gas production rate in excess of 5.5 MMcf/d (3.85 MMcf/d net to KOV) since tie-in;
• Projected production rate for the remainder of 2011 from the M-19 well is a minimum of 4 MMcf/d (2.8 MMcf/d net to KOV);
• The tie-in of the M-19 well has increased the gas production by almost 70% from an average of approximately 6 MMcf/d (4.2 MMcf/d net to KOV) for the first six months of 2011 to the current rate of more than 10 MMcf/d (more than 7 MMcf/d net to KOV).

Timothy M. Elliott, the President and Chief Executive Officer of KOV, stated that "we have substantially increased production from our Ukraine assets since closing the acquisition in June 2010 and are very pleased that KUB-Gas is already producing more than 10 MMcf/d before the end of July. We are confident that we will meet or exceed our target of exiting 2011 with a production rate for KUB-Gas of 12 MMcf/d (8.4 MMcf/d net to KOV). KOV will continue with its active development program in the Ukraine during the coming year and we expect to have a number of new locations defined once the 3D seismic surveys recently completed at Makeevskoye and Olgovskoye are processed and interpreted. The successful start-up of gas production from the newly discovered zone in the M-19 well has confirmed the effectiveness of modern seismic interpretation techniques in the identification of new exploration targets".

The M-19 well

The M-19 exploration well was drilled in the second half of 2010 to a total depth of 2,060 metres and tested gas at a rate of approximately 5 MMcf/d in January 2011 before being suspended pending completion of a pipeline to tie the well to the production facilities of KUB-Gas LLC ("KUB-Gas"). The pipeline was completed and all regulatory approvals required for the commercial production of the well were obtained prior to the start of production on July 11, 2011.

Average gas production from the M-19 well was 5.52 MMcf/d (3.86 MMcf/d net to KOV) since the first full day of production on July 11, 2011. It is presently anticipated that production rates from the well will stabilize at a lower rate and average about 4.0 MMcf/d for the remainder of 2011. The successful tie-in of the M-19 well to production facilities has increased total KUB-Gas production from its four producing gas licenses in Ukraine to an average of 10.73 MMcf/d (7.51 MMcf/d net KOV) during the 10 producing days ended July 24th.

The estimated selling price per thousand cubic feet ("Mcf") in the second quarter of 2011 was approximately US $9.00 per Mcf with as estimated netback of US $5.80. The netback during the first quarter of 2011 was US $4.77 per Mcf. The final financial information with respect to the second quarter will be released in mid-August.

The M-19 well was the first well operated by KUB-Gas logged with western logging tools. By comparing the Ukrainian and western logging data over the same formations, the Company is developing a methodology to better understand and analyze existing Ukrainian log data with a view to more effectively evaluating the potential of the area.

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Bow Boosts 2P Certified Reserves by 60%

- Bow Boosts 2P Certified Reserves by 60%

Tuesday, July 19, 2011
Bow Energy Ltd.

Bow has obtained further 2P certified reserves in the Blackwater CSG Field (ATP 1025P) increasing Bow's total certified reserves to 238 PJ of 2P and 2,752 PJ of 3P reserves.

As previously announced Bow has reached an agreement to share exploration and production data with a number of CSG companies operating in the Bowen Basin. This has allowed data on adjacent Exploration Permits and Petroleum Leases to be extrapolated across permit and or lease boundaries. Based on the data from pilot production wells adjacent to Bow's Blackwater CSG field, along with Bow's previous core hole data, MHA Petroleum Consultants, Inc (MHA) have certified within the Rangal coal measures of Bow's Blackwater field (ATP 1025P) a further 89 PJ of 2P and 13 PJ of 3P. Several pilot production programs are in progress at Blackwater with 10 wells in various stages of dewatering. The aim of these programs is to test different well design and completion techniques to determine the optimal commercial production methods.

CEO, John De Stefani commented, "the new gas reserves at Blackwater follow on from our previous announcement regarding the recognition of the initial reserves at Norwich Park and are a further step towards achieving our goal from the current funded work programs of 1,250PJ 2P and 6,200PJ 3P reserves. Pilot programs are continuing on the Blackwater CSG Field with a series of pilot wells aimed at obtaining further reserve upgrades."

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Novatek Boosts Production in 2Q11

- Novatek Boosts Production in 2Q11

Friday, July 08, 2011
OAO Novatek

Novatek reported preliminary production data for the second quarter and first half 2011.

Gross production for the second quarter totaled 12.13 billion cubic meters of natural gas and 1.04 million tons of liquids (gas condensate and crude oil). Gross natural gas production increased by 3.72 billion cubic meters, or by 44.2%, and gross liquids production increased by 157 thousand tons, or by 17.8%, as compared with the corresponding gross production in the second quarter 2010.

In the first half 2011, gross production for Novatek totaled 25.56 billion cubic meters of natural gas and 2.06 million tons of liquids. Natural gas production increased by 7.17 billion cubic meters, or by 39.0%, whereas gross liquids production increased by 316 thousand tons, or by 18.1% as compared with the corresponding gross production in the first half 2010.

In the second quarter and first half 2011, Novatek processed 982 and 1,956 thousand tons, respectively, of unstable gas condensate at the Purovsky Gas Condensate Processing Plant.

The Company's preliminary stable gas condensate export volumes amounted to 753 thousand tons for the second quarter 2011 as compared to 536 thousand tons in the corresponding period of 2010. At 30 June 2011, we had approximately 206 million cubic meters of natural gas and 274 thousand tons of stable gas condensate in transit or storage and recognized as inventory.

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Maverick Boosts Reserves at Blue Ridge Dome

- Maverick Boosts Reserves at Blue Ridge Dome

Wednesday, June 29, 2011
Maverick Drilling & Exploration Ltd.

Maverick Drilling & Exploration announced a significant upgrade to Maverick's 2P reserves on its flagship asset, Blue Ridge Dome, by approximately 26.8 million net oil barrels for Maverick's share of its leases. The reserves reflect no barrels equivalent in natural gas and are all true liquid oil barrels.

The reserve upgrade is a result of a combination of new lease acquisitions on Blue Ridge Dome and further analysis of results of Maverick's ongoing drilling program. A comparison to previously disclosed reserves is set out below:

Net Maverick Reserves

	Proved 1P (million bbls)	Proved + Probable 2P (million bbls)
ISO prospectus	7.8	25.6
Today	12.4	52.4
9 month increase (%)	59%	104%

Approximately 7.6 million net 2P barrels of the increase are the result of the company's improvements on those Blue Ridge Dome leases held at the time of listing (in September 2010). The remaining 19.2 million 2P barrels relate to acquisitions and expansion of holdings in the field.

Commenting on the upgrade, Maverick's executive chairman, Mr. Don Henrich said, "This is a superb outcome in Maverick's first nine months as a listed company. The substantial upgrade highlights the vale of Blue Ridge Dome, and the inherent potential of Boiling Dome, a piercement type salt dome with similar characteristics. The reserve upgrade underpins our aggressive acquisitions and in-field drilling and completion program which is achieving record production month over month for the past several months."

As previously announced, the company holds considerably larger net acreage on Boiling Dome than on Blue Ridge Dome. The Directors expect to announce maiden reserves for Boiling Dome later this calendar year, after commencement of the pilot drilling program.

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Aroway Boosts Production at Peace River Arch Prospect

- Aroway Boosts Production at Peace River Arch Prospect

Monday, June 27, 2011
Aroway Energy Inc.

Aroway reported that the Company's first well of the 2011 drilling program has been on a stable production for 20 days and is producing oil, natural gas liquids and gas from the targeted Leduc formation. The well, which is located in Peace River Arch oil and gas exploration prospects, was placed on restricted flow rate in late May, and in early June the well began to produce oil. Based on the present well pressures and the operators' conservative production practises, the well is expected to stabilize at a rate of 400 boe/day, 200 boe/day net to Aroway. The oil produced from the well is produced and pipelined to a facility owned by the Company's Joint Venture Partner and well operator. Aroway is paying 50% of all costs associated with this well to earn a 50% interest in the well.

The Company also reports that total depth has been reached on the third well of the 2011 drilling program. The well encountered numerous potential hydrocarbon bearing zones in the Triassic deposits and based on the drilling logs, the well will be evaluated in each of the prospective zones. A 100 meter pipeline tie-in has begun and will be complete in the next week, and the well will be production tested directly into the pipeline. Aroway is paying 50% of all costs associated with this well to earn a 50% interest in the well.

Testing on the Company's second well of the 2011 drill program will commence as soon as the roads dry out as heavy rains have hit the area over the past week. We are confident the service rig will be on the location and testing will begin within the next 10 days.

Chris Cooper, President of Aroway commented, "We were quite confident that our first well of 2011 would end up as an oil well as soon as the gas cap was produced. We will have concrete Company production numbers in coming weeks which will bring us much closer to our year-end target of 600 boe/day."

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Iraq Boosts Oil Supplies to Jordan

- Iraq Boosts Oil Supplies to Jordan

Wednesday, June 22, 2011
Knight Ridder/Tribune Business News
by Taylor Luck, Jordan Times, Amman

Jordan has started receiving additional oil supplies from Iraq as officials in Amman continue to explore alternatives to address the Kingdom's energy woes.

According to Minister of Energy and Mineral Resources Khaled Toukan, Jordan has started to receive 15,000 barrels of Iraqi oil daily as part of an agreement struck between Baghdad and Amman earlier this month.

Also under the deal, signed during a visit of Prime Minister Marouf Bakhit to Baghdad, the Kingdom receives 30,000 tonnes of heavy fuel oil per day from Iraq at an $88 per tonne discount.

The boost in Iraqi oil comes amidst a drop in Egyptian gas supplies, which Jordan relies on for 80 percent of its electricity needs. Iraqi heavy fuel oil accounts for the remaining 20 percent.

Jordan currently receives 100 million cubic feet of natural gas from Egypt daily, well below the 250 million cubic feet stipulated in an amended agreement between the two sides, Toukan said.

Officials expect increased amounts of Egyptian gas by July, but remain sceptical of the reliability of supply -- particularly after attacks on the Arab Gas Pipeline earlier this year led to two separate six-week disruptions forcing the country's power plants onto their costly diesel reserves.

Facing popular pressure at home, Cairo made amending a 12-year agreement between the two sides a condition to resuming gas supplies, which the Kingdom previously received at preferential prices of less than half of the international rate.

Meanwhile, the government is set to float a tender in November for the construction of an offshore gas terminal to receive and transport liquid gas to Amman.

According to Toukan, Jordan has received interest from several international firms in the terminal, to be built off the Port of Aqaba within the next two years.

The government has received expressions of interest from British Petroleum, Royal Dutch Shell, GDF Suez, Qatar Gas Cooperation and Lemont/General Electric, among others.

Jordan's drive for liquid gas comes as part of officials' efforts to cover a five- to six-year "gap period" ahead of the development of domestic energy sources including wind, solar and nuclear power.

Copyright (c) 2011, Jordan Times, Amman

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Statoil: Subsea Compression Boosts Gas

- Statoil: Subsea Compression Boosts Gas

Friday, June 17, 2011
Statoil

Statoil and its partners want to compress gas on the seabed to boost recovery. Subsea compression was recently selected as the preferred concept for Gullfaks.

"Gas compression on the seabed represents an important advance in technology, and once again, Statoil is leading the way for development of new technology. This is one of our most important measures for improving recovery from existing fields," said Siri Espedal Kindem, Statoil's vice president of technology.

Since 2008, Statoil and its partners have worked with Framo Engineering to develop technology for compressing wet gas on the seabed. Statoil has now decided to take the concept a step further on the Gullfaks South subsea field.

"This could increase production from the field by three billion cubic metres of gas, which means a six percent increase in recovery," said Ivar Aasheim, head of Field Development on the Norwegian shelf.

The current field recovery rate is already 62 percent. The combination of subsea compression and conventional low pressure production in the later phases could lift the recovery rate to 74 percent, thus also increasing the Gullfaks C lifetime.

Why compression?

Natural pressure declines as a field ages. This means that compression is necessary in order to extract more gas, and to get the gas to the platform.

The standard solution is compression on a platform or from land; however, the closer the compression is placed in relation to the well, the more gas can be extracted. That is why Statoil wants to place the compressor near the wells, on the seabed.

Not just Gullfaks

Statoil is currently working on three subsea compression projects in early stages. On the Åsgard field, the selected concept involves a subsea solution that will help increase pressure from the Mikkel and Midgard reservoirs. This could enhance recovery by 28 billion cubic metres of gas and 14 million barrels of condensate.

Together with operating company Shell, we are also working on a similar seabed solution on Ormen Lange.

"And this is just the beginning. Subsea compression can increase recovery on several small and medium-sized fields in the time ahead. Statoil has already identified more candidates," said Siri Espedal Kindem.

Seabed factories

Today, almost 50 percent of Statoil's production comes from a total of 488 subsea wells.

Statoil's expertise in subsea operations is the key to more efficient production and improved recovery.

"In many cases, subsea facilities make it possible to produce oil and gas that would not otherwise have been profitable to recover. This is how we take responsibility for increasing production from the Norwegian shelf," said Aasheim.

Subsea gas compression is another step in the direction of seabed factories, where operations that currently take place on platforms are moved down to the seabed.

"Processing on the seabed, particularly gas compression, is also very important in developing fields in deep water and vulnerable areas. This is an important technological breakthrough," Kindem concludes.

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