Oil and Gas News: 08/04/11

Thursday, August 4, 2011

Oil & Gas Post - All News Report for Thursday, August 04, 2011

Thursday, August 04, 2011

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Commodity Corner: Crude Dives to 6-Month Low

- Commodity Corner: Crude Dives to 6-Month Low

Thursday, August 04, 2011
Rigzone Staff
by Saaniya Bangee

Crude oil futures plunged nearly 6 percent Thursday to its lowest settlement since February. Prices pushed lower $5.30, marking the largest one-day drop since May 5, as equity markets sold off.

Light, sweet crude settled at $86.63 a barrel on the New York Mercantile Exchange (NYMEX), down for the fifth consecutive session. Its counterpart settled at $107.25 a barrel amid Europe's sovereign debt crisis. Brent crude traded within a range of $107.05 and $113.60 Thursday.

Largely steered by growing concern that the U.S. economy is experiencing a double-dip recession, equity markets sold-off sharply mid-day Thursday pushing prices further. In addition, the greenback gained against the euro Thursday as the Dollar Index rose by almost 1.5 percent. As the greenback rises, the dollar-denominated commodities becomes expensive for foreign buyers.

Likewise, natural gas futures also tumbled Thursday falling below the $4-mark for the first time since March. Front-month natural gas lost nearly 15 cents to settle at $3.94 per thousand cubic feet. The Energy Information Administration said U.S. natural gas inventory increased by 44 billion cubic feet for the week ended July 29.

Meanwhile, moderate temperature forecasts didn't give the market much support either. Also, the National Hurricane Center reported that Tropical Storm Emily isn't headed toward the Gulf of Mexico.

The intraday range for natural gas was $3.915 to $4.119 per thousand cubic feet.

Gasoline for September delivery dropped 19.41 cents, or 6.6 percent, to end Thursday's trading session at $2.74 a gallon, having traded as low as $2.728 after an earlier intraday peak of $2.94.

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Kodiak Drills Ahead in Williston Basin

- Kodiak Drills Ahead in Williston Basin

Thursday, August 04, 2011
Kodiak O&G Corp.

Kodiak O&G announced its second quarter 2011 financial and operational results. The Company also provided an interim operations update on its Williston Basin drilling and completion activities.

Highlights Include:

2Q 2011 Earnings of $8.2 Million, Before Unrealized Derivatives Gain
Oil & Gas Sales of $22.1 Million, a 261% Increase
Equivalent Sales Volumes 238,000 BOE, a 149% Increase
Adjusted EBITDA of $13.7 Million, 377% Growth
Two New Bakken Well Completions in McKenzie County, N.D.

Second Quarter 2011 Financial Results

The Company reported net income for the second quarter 2011 of $14.0 million, or $0.08 per basic and diluted share, compared with net income of $621,000, or $0.01 per basic and diluted share, for the same period in 2010. Included in the second quarter 2011 net income calculation are unrealized derivative gains of $5.8 million attributed to the non-cash change in the value of derivatives utilized for commodity price risk management. Excluding the effect of unrealized derivative gains, a non-cash credit, Kodiak would have reported adjusted net income (a non-GAAP measure) of $8.2 million for the second quarter 2011, or $0.05 per basic share and $0.04 per diluted share.

For the quarter-ended June 30, 2011, the Company reported oil and gas sales of $22.1 million, as compared to approximately $6.1 million during the same period in 2010, a 261% increase and a Company record. Crude oil revenue accounted for approximately 97% of second quarter 2011 oil and gas sales, and crude oil constituted 94% of sales volumes for the quarter. Kodiak posted a 157% increase in oil sales volumes and a 72% increase in gas sales volumes for an overall 149% increase in quarter-over-quarter equivalent sales volumes of 238,000 barrels of oil equivalent (BOE).

Adjusted EBITDA, a non-GAAP measure, was $13.7 million for the second quarter 2011, as compared to $2.9 million in the same period in 2010, a 377% increase and another Company record. Kodiak defines Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depletion, depreciation, amortization, and accretion (iv) impairment, (v) non-cash expenses relating to share based payments recognized under ASC Topic 718, (vi) pre-tax unrealized gains and losses on foreign currency, and (vii) pre-tax unrealized gain and losses on commodity price risk management activities. A reconciliation of Adjusted EBITDA to net income is included in the financial tables later in this earnings release.

Kodiak reported record net cash provided by operating activities for the second quarter 2011 of $16.3 million, as compared to $7.2 million in the same period in 2010. The Company reported cash used in investing activities of $116.8 million during the second quarter of 2011, of which approximately $30.6 million was invested for the drilling and completion of wells and for infrastructure in its Williston Basin drilling program. The Company also invested $85.8 million during the second quarter 2011 to acquire an additional 25,000 net acres and producing properties in the Williston Basin which closed on June 30, 2011.

Second Quarter 2011 Expense Analysis

For the quarter-ended June 30, 2011, general and administrative (G&A) expense was $4.2 million, as compared to $2.6 million for the same period in 2010. The increase in total G&A is attributed primarily to the hiring of new personnel as the Company continues to expand its operations. The Company had 52 employees at June 30, 2011, as compared to 27 employees at June 30, 2010. Included in the second quarter 2011 G&A expense is a non-cash, stock-based compensation charge of $947,000 million, as compared to $866,000 for the same period in 2010.

Kodiak's lease operating expense (LOE) for the second quarter 2011 was $4.4 million, as compared to $1.5 million during the same period in 2010. The increase in LOE is attributed to additional production expense associated with a growing number of producing wells. Severance taxes were also higher due to increased oil and gas revenues during the 2011 period, as compared to the 2010 period.

Depletion, depreciation, amortization, and accretion (DD&A) expense for the second quarter 2011 was $4.5 million, as compared to $1.5 million for the same period in 2010. The increase is primarily due to the increase in sales volumes and, to a lesser extent, an increase in the per-unit charge.

Williston Basin Operations Update

Kodiak's four operated drilling rigs are presently drilling ahead on multi-well drilling pads. Two rigs are drilling in McKenzie County, and two rigs are drilling in Dunn County. The Company anticipates that the fifth operated drilling rig will be mobilized to McKenzie County when construction of the rig is completed in the fourth quarter of 2011.

As previously announced, the Company's completion activities are progressing according to schedule, and Kodiak expects to complete or commence completion operations on 10 gross and 7.5 net operated wells in the Williston Basin during the third quarter of 2011, including the Koala wells. In addition, the Company expects to participate in the completion of four gross (2.0 net) non-operated wells in the third quarter of 2011.

Management Comment

Commenting on second quarter 2011 results, Kodiak's Chairman and CEO Lynn A. Peterson said, "Kodiak's second quarter results were the strongest in Company history. We reported robust growth in several of the metrics that we monitor to assess our progress and performance. The results from our Koala project area wells are very encouraging and further demonstrate the productive potential in this prolific area of the Williston Basin. The four Koala wells that we have completed to date are all very strong wells with production established from middle Bakken as well as the Three Forks. The wells were drilled in a manner which continues to test the density of well bores and the communication between reservoirs. Well performance will be monitored over the coming quarters.

"As we look at the anticipated ramp-up in our production, combined with the $160 million of cash obtained from the public offering of common stock, the Company is in its strongest financial position ever. We announced the expansion of our borrowing revolver recently and we anticipate that the facility will continue to expand as we bring additional wells on during the remaining months of 2011 and beyond. We expect to selectively add to our Williston Basin acreage position and expect increased drilling and completion activity in the upcoming quarters. We believe we now have ample liquidity through our cash balances, operating cash flow and access to our credit facilities to fund our expanding drilling program."

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Kosmos Names VP of Investor Relations

- Kosmos Names VP of Investor Relations

Thursday, August 04, 2011
Kosmos Energy Ltd.

Kosmos announced that Brad Whitmarsh has joined the Company as Vice President of Investor Relations. Whitmarsh reports to W. Greg Dunlevy, Executive Vice President and Chief Financial Officer.

"We are excited to have Brad join our growing Kosmos team. His knowledge of the oil and gas industry, along with his proven success in establishing key relationships with the investment community, will be extremely beneficial as we build our investor relations program," said Dunlevy.

Prior to joining Kosmos, Whitmarsh was Manager of Investor Relations at Noble Energy, Inc. He also worked in multiple roles in Noble Energy's internal audit department. Whitmarsh earned a bachelor of business administration degree in accounting from Texas A&M University and is a certified public accountant licensed in the state of Texas.

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Vast Exploration Adds Member to BOD

- Vast Exploration Adds Member to BOD

Thursday, August 04, 2011
Vast Exploration Inc.

Vast Exploration announced the appointment of General (Ret'd) Jay Garner as Chairman of the board of directors.

Mr. Stan Bharti, commented, "We are delighted to add General Garner back to the board of directors. Jay has been recently serving as an advisor to the Company, and his guidance has been invaluable over the past several years. We look forward to Jay's leadership and distinguished experience as we move forward to the next phase of the Kurdistan project."

General Garner's military career culminated with his being Assistant Vice Chief of Staff, U.S. Army. In January 2003, General Garner was appointed by the Secretary of Defense to organize and direct the Office of Reconstruction and Humanitarian Assistance (ORHA) for post-war Iraq. In 1991, General Garner was appointed Commanding General, Joint Task Force Bravo for Operation Provide Comfort in northern Iraq. Under his leadership, a coalition of American, British, French and Italian forces provided humanitarian relief assistance to the Iraqi Kurds.

The Company is also pleased to announce that it has appointed Neil Said as the Corporate Secretary of the Company. Mr. Neil Said is a corporate securities lawyer who works as a legal consultant to various TSX and TSX Venture listed companies in the mining and oil & gas industries. Mr. Neil Said previously worked as a securities lawyer at a large Toronto corporate law firm. He obtained his JD degree from the University of Toronto and received a Bachelor of Business Administration from Wilfrid Laurier University. In connection with his appointment, Mr. Said has been granted 200,000 stock options to purchase the same number of common shares of the Company at a price of $0.16 per option exercised. The stock options, and any shares issued on exercise thereof, will be subject to a four month statutory hold period.

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First Solar Misses Q2 Estimates

- First Solar Misses Q2 Estimates

Aug 4, 2011

First Solar (NASDAQ:FSLR) reported adjusted Q2 EPS of $0.70, missing analyst estimates of $0.92. Revenues for the quarter fell 9.4% to $533 million, less than consensus estimates of $583.42 million.

Rob Gillette, CEO of First Solar said, "First Solar continued to execute in the quarter despite a challenging European market, and our 2011 outlook remains solid due to our differentiated and resilient business model. We expect stronger performance in the second half of 2011 as we build projects from our systems pipeline, develop promising new markets, execute our cost reduction roadmaps and continue to improve module efficiencies."

First Solar (NASDAQ:FSLR) has a potential upside of 42.2% based on a current price of $107.94 and an average consensus analyst price target of $153.5.

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Whiting Posts Production Rates for Williston Basin Wells

- Whiting Posts Production Rates for Williston Basin Wells

Thursday, August 04, 201
Whiting Petroleum Corp.

Whiting released information on six western Williston Basin areas within its Lewis & Clark prospect and three nearby prospects. The initial production rates from wells drilled in these nine areas averaged 1,471 barrels of oil equivalent (BOE) per day. Whiting believes that its drilling results at Lewis & Clark and Hidden Bench as well as non-operated drilling results at Missouri Breaks and Starbuck indicate that a large portion of its 1,102,302 gross acres and 680,137 net acres in the Williston Basin has been shown to be productive and have excellent initial production rates.

Eleven Whiting-operated Sanish Sand wells in our Pronghorn area had initial production rates averaging 1,298 BOE per day. This average excludes four delineation wells drilled to determine the southwest boundary of the Sanish Sand reservoir at Pronghorn.

In our Big Stick area, we have completed three wells with initial production rates averaging 1,043 BOE per day. At Demores, where two wells had initial production rates averaging 479 BOE per day, Whiting is changing the direction of its well bores to a north-south orientation to encounter more natural fractures. In its Beaver Creek area, Whiting has completed six wells that averaged 1,119 BOE per day. A recent well in the Beaver Creek area, the Dry Creek 44-20TFH, flowed 2,337 BOE per day from the Three Forks formation on August 2, 2011. The Company has completed one well in its O'Neil Creek area. The Mosser 11-27TFH well was completed in the Three Forks formation with an initial production rate of 193 BOE per day. Severe weather conditions which caused a shut-down of flow back operations post frac is believed to have resulted in the low initial production rate on this well.

At Missouri Breaks and Starbuck, another operator has drilled within the outline of our acreage position. One non-operated well at Missouri Breaks was completed flowing 2,962 BOE per day. Three non-operated wells at Starbuck had initial production rates averaging 1,264 BOE per day. Whiting currently has two operated wells waiting on completion at the Starbuck prospect with results expected within 30 days.

James J. Volker, Whiting's Chairman and CEO, commented, "We are very encouraged with our results at Lewis & Clark and Hidden Bench. We are also encouraged by the initial production rates of area non-operated wells and the shows encountered during drilling operations on our two operated wells at Starbuck. We plan to complete these wells in early September.

"We own 387,351 gross (254,818 net) acres in Lewis & Clark, 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."

Mr. Volker added, "Based on IHS data, with its average of 100,000 BOE, we continue to be on top of the list in terms of cumulative production during the first six months from all Bakken wells drilled in North Dakota since January 2009. For companies with a sample of at least 10 wells, Whiting leads the pack by 15,000 to 70,000 BOE in the first six months. We hold more than 680,000 net acres in the Bakken/Three Forks Hydrocarbon System that we believe will generate increased production and reserve additions."

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Reef Resources to Boost Production at Ausable Field

- Reef Resources to Boost Production at Ausable Field

Thursday, August 04, 2011
Reef Resources Ltd.

Reef Resources announced that significant progress is being made on determining the Ausable #5 future flow rate. The presence of very light oil, blended with natural gas condensates, creates foamy oil conditions and consequently the current mechanical bottom hole pumping configuration is operating at very low efficiency causing erratic flow rate and high fluid levels in the wellbore. The Ausable field has now been shut in for a period of time to provide fluid level and pressure build up data that is necessary to determine the Ausable #5 likely flow rate using industry accepted inflow analysis technique and will be reported as soon as all data is processed.

When the likely ultimate flow rate has been estimated Reef will be able to design and execute a plan for long term lifting of the well fluids using revised pumping techniques that will allow the full potential of the well to be realised.

The removal of the frac tools from Ausable # 2 is also progressing. The first stage of tubing cuts have been successfully executed and will now concentrate on extracting the frac tools over the course of the next few days. Once the frac tools are removed the Company will report on the status of Ausable #2.

Arnie Hansen stated, "While still at a preliminary state, Ausable # 5 is looking very positive and the Company's engineering team is working on a solution to increase pumping efficiencies therefore increasing production. This is the first stage of optimization with next goal to acquire and inject natural gas to re-pressure the reef that will significantly increase production and demonstrate the true value of the Ausable pool."

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Delta Ends Strong in 2Q11

- Delta Ends Strong in 2Q11

Thursday, August 04, 2011
Delta Petroleum Corp.

Delta announced its financial and operating results for the second quarter 2011.

Carl Lakey, Delta's CEO and President stated, "We are pleased to provide our shareholders with another solid operating quarter coupled with the accomplishment of some very important strategic steps. We sold our remaining non-core assets, which reduced our leverage and provided sufficient liquidity to continue our deep shale evaluation and development in the Vega Area. While the strategic alternatives process, the 2C well results, and the Netherland Sewell report were all announced subsequent to the end of the quarter, much of the efforts that went into those steps occurred in the second quarter. The 2B and 2C well results and Netherland Sewell's report are very important contributions that support Delta's intrinsic value and aid our strategic alternatives process."

VEGA AREA SHALE EVALUATION UPDATE

As previously announced, the Delta 2C well began producing hydrocarbons on Wednesday, July 20, at a rate of 5.4 million cubic feet of gas per day (MMcf/d), which was choke-restricted with a 7/64 of an inch choke and 8,360 psi of flowing tubing pressure. Gas sales from the well began on Thursday, July 21 from the Niobrara and Frontier formations only. The well is currently producing between 2.5 – 3.5 MMcf/d with 6,100 psi of flowing tubing pressure. The well choke is currently set at 9/64 of an inch. The Mancos shale, Corcoran and Williams Fork formations remain uncompleted.

The Delta 2B well in the Vega Area of the Piceance Basin drilled through a portion of the Mancos formation and reached total depth of 10,700 feet. Below the Williams Fork the well was completed in 1,200 feet of shale in the Corcoran and the upper portion of the Mancos formation. Gas production began on April 24 and sales commenced on April 29. As announced on May 10, the 2B well experienced sustained production of 3.3 MMcf/d from only the Mancos and Corcoran formations. The well is currently producing 0.6 MMcf/d. The information available indicates that the natural fractures in the 2B well may have prematurely closed by the high flow rate (6 MMcf/d) during initial flowback activities, which has subsequently hindered production. The Company is currently evaluating refracturing the well in the Mancos and Corcoran formations to reestablish higher production levels in the well.

The Company is currently drilling the 12B well. The current depth is approximately 8,500 feet with a target depth of 13,000 feet. It is expected that the target depth will reach the Frontier formation. Total depth is expected to be reached during September. Once completed, this well will hold the acreage of the federal Sheep Creek Unit and bring the Company's Vega leasehold up to 95% held by production.

STRATEGIC ALTERNATIVES UPDATE

On July 6, 2011, Delta announced that it had engaged Macquarie Capital (USA) Inc. and Evercore Group, L.L.C. to act as advisors to the Company in conducting a strategic alternatives process aimed at maximizing shareholder value and dealing with the Company's 2012 debt maturities. Through this process, the Board of Directors is evaluating all opportunities available, including a potential sale of the Company. The process is in its early stages and the Company does not expect to make further public comment regarding the process until the Board of Directors has approved a specific transaction or otherwise determines that disclosure of significant developments, if any, is appropriate.

OPERATIONS UPDATE

Current production of the Company approximates 28 million cubic feet equivalent per day (MMcfe/d) net.

2011 CAPITAL EXPENDITURES AND PRODUCTION GUIDANCE

Delta will focus its current available capital for the remainder of 2011 on drilling and completing the 12B well and completing the remaining two previously drilled Williams Fork wells. The completions of the remaining two previously drilled wells have been postponed to the fourth quarter of 2011; however, these plans could be altered depending on shale well results, with capital potentially being reallocated to additional shale activity. Developments related to the strategic alternatives process may also affect current capital spending plans.

Production for the third quarter 2011 is expected to be between 2.6 Bcfe and 2.7 Bcfe.

RESULTS FOR THE SECOND QUARTER 2011

For the quarter ended June 30, 2011, the Company reported total production of 3.2 Bcfe. Production from continuing operations was 2.8 Bcfe, remaining flat when comparing second quarter 2011 to the prior year period. Revenue from oil and gas sales was $16.9 million, an increase of 14% when compared to the prior year period of $14.8 million. The average natural gas price received during the quarter ended June 30, 2011 increased to $5.31 per thousand cubic feet (Mcf) compared to $4.92 per Mcf for the prior year period. The average oil price received during the quarter ended June 30, 2011 increased to $86.87 per barrel compared to $58.29 per barrel for the prior year period.

The Company reported a second quarter net loss attributable to Delta common stockholders of ($963,000), or ($0.03) per diluted share, compared to a net loss attributable to Delta common stockholders of ($149.8 million), or ($5.43) per diluted share, in the second quarter of 2010. The decrease in net loss is primarily due to a decrease in dry hole costs and impairments and a decrease in operating expenses, as well as discontinued operations.

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La Cortez Updates Ops at Putumayo Block

- La Cortez Updates Ops at Putumayo Block

Thursday, August 04, 2011
La Cortez Energy Inc.

La Cortez provided the following operational update on the Company's Putumayo-4 block located in the Putumayo Basin in southwestern Colombia:

Putumayo-4 Block

Social Activity

As previously disclosed, at the end of November 2010, the local community consultation process was suspended pending appoint of a new contractor to act on behalf of the Ministry of Interior. During July 2011, consultations were reinitiated, and significant progress has been made in the northern part of the block with two communities consulted to date. One agreement is ready for signature by the community and Petroleos del Norte S.A. (PetroNorte), operator of the Block; a second agreement is under discussion, with final approval currently expected within a month. Community consultations in the southern part of the block are proceeding more slowly, and while the negotiations continue in earnest, it has been agreed to focus all initial seismic activity in the northern area of the block in order to fulfill the commitments to the ANH (Agencia Nacional de Hidrocarburos).

Operational Activity

Assuming completion of the community consultation process under the timeline indicated above, the near-term operational objective is to shoot 104.8 km of 2D seismic over the block during October 2011. The seismic acquisition is a contractual obligation of the parties under the terms of our agreement with the ANH. The results of the seismic acquisition program will allow PetroNorte and us to finalize the selection of the drilling location for the first exploration well to be drilled on the Putumayo-4 block.

Bid specification for the seismic acquisition is expected to be complete by the end of August 2011, awarded in September, and initiated in October 2011. We anticipate that we will have the seismic volume interpretation from the acquired seismic by early 2012. In addition, once the community consultations are finalized, we will commence work on the Environmental Impact Study, which is required to secure the environmental license. Subject to completion of permitting and civil works at the drill-site, we and PetroNorte anticipate spudding the exploratory well (which is a commitment obligation under the contract with the ANH) during the second quarter of 2012.

Andres Gutierrez, President and CEO of La Cortez, commented on the announcement, "We are very pleased to announce the community consultation process is underway once again, and eagerly anticipate the increased level of activity over the coming months. We remain very optimistic about the exploration potential of the Putumayo-4 block and are encouraged that our views are shared by others who have recently approached us regarding their potential interest in partnering with us on future exploration and development activity."

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TGS 2Q Revenue Up 21%

- TGS 2Q Revenue Up 21%

Thursday, August 04, 2011
TGS-NOPEC Geophysical Co. ASA

TGS reported net revenues of USD 136 million in 2Q 2011, compared to USD 112 million in 2Q 2010. Investments and the corresponding pre-funding revenues were significantly lower in 2Q 2011 than in 2Q 2010 due to the expected back end loaded investment plan, as previously communicated to the market. Despite lower investments, TGS is pleased to report late sales of USD 98.0 million which is up 52% from 2Q 2010.

2nd QUARTER HIGHLIGHTS
- Consolidated net revenues were USD 136.1 million, an increase of 21% compared to 2Q 2010.
- Net late sales totaled USD 98.0 million, up 52% from 2Q 2010.
- Net pre-funding revenues were USD 26.7 million, down 38% from 2Q 2010, funding 43% of the Company's operational multi-client investments during 2Q (investments of USD 61.7 million, down 36% from 2Q 2010).
- Proprietary revenues were USD 11.4 million, up 142% from 2Q 2010.
- Operating profit (EBIT) was USD 57.7 million (42% of net revenues), compared to USD 33.4 million (30% of net revenues) in 2Q 2010.
- Cash flow from operations was USD 93.3 million, up from USD 74.1 million in 2Q 2010.
- Earnings per share (fully diluted) were USD 0.41, compared to 0.18 in 2Q 2010.
6 MONTHS FINANCIAL HIGHLIGHTS
- Consolidated net revenues were USD 268.1 million, an increase of 3% compared to H1 2010.
- Net late sales from the multi-client library totaled USD 182.8 million, up 33% from USD 138.0 million in 2010.
- Net pre-funding revenues were USD 63.4 million, down 44% from 2010, funding 60% of the Company's operational multi-client investments during H1 (investments of USD 105.2 million, down 46% from 2010).
- Proprietary revenues were USD 21.9 million, up 118% from 2010.
- Operating profit (EBIT) was USD 116.7 million (44% of net revenues), compared to USD 92.3 million (35% of net revenues) in 2010.
- Cash flow from operations was USD 231.6 million, an increase of 28% from USD 180.4 million in 2010.
- Earnings per share (fully diluted) were USD 0.81 compared to USD 0.58 for the same period in 2010.

"Another strong quarter with revenue growth of 21% from last year," TGS' CEO Robert Hobbs stated. "We continue to see great demand for our existing library data and all business areas experienced growth in late sales compared to one year ago. We maintain our guidance for 2011."

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Virginia Pushing for Offshore Oil and Gas

- Virginia Pushing for Offshore Oil and Gas

Thursday, August 04, 2011
Rigzone Staff
by Barbara Saunders

While most states battle to keep offshore oil and gas development away from their coastlines, the State of Virginia pushes – with some success so far – to allow it.

The U. S. House of Representatives already approved legislation that would open Virginia's waters, beyond 50 miles of the coastline, to hydrocarbon exploration and production. However, a corresponding Senate measure got bogged down recently before that chamber's Energy and Natural Resources Committee.

The committee hit an impasse over the proposed revenue-sharing provisions. This would provide states with 37.5 percent of revenues from offshore leasing development.

The Obama Administration postponed South Atlantic lease sale 220

The Obama Administration postponed South Atlantic lease sale 220 and other lease sales after the 2010 Macondo well disaster in the Gulf of Mexico

Now, the fate of the legislation is up in the air. The legislation – introduced by Virginia Democratic Sens. Mark Warner and Jim Webb – was incorporated into other legislation up for the committee's consideration.

Sen. Lisa Murkowski, a Republican who represents Alaska, expressed optimism that the committee would soon reach agreement on the proposal.

"We must recognize the importance of putting safety and the nation's need for greater energy production together," Murkowski said. "Our shared goal is to have safe production."

Sens. Murkowski and Mary Landrieu, a Louisiana Democrat, offered a revenue sharing amendment to the Outer Continental Shelf Reform Act (S. 917). Although several members on the committee spoke in favor of the concept of revenue sharing, the committee lost its quorum and the proposal was not voted on.

"Today's markup demonstrated bipartisan support for equitable revenue sharing for coastal energy-producing states," Murkowski said. "We'll keep working to fine-tune the language and reach agreement on a plan that's acceptable to our members."

Murkowski added that she would work with members of the committee from both parties on refining revenue sharing language to include funding for renewable energy projects at the state level. Once that was accomplished, Murkowski said she would hope the markup of the bill could be rescheduled as soon as possible so the Outer Continental Shelf Reform Act and revenue sharing could be voted on by the full committee.

"Those who understand the importance of inviting coastal states to be partners in our efforts to increase the nation's energy security are not going to let this issue go away," Murkowski said. "It is in our best interest to have American workers producing American energy, and revenue sharing will help us reach that goal."

The Landrieu-Murkowski revenue sharing amendment would allow coastal states to retain a portion of the revenues generated by energy production in federal waters, beginning in 2019. It would apply to all forms of energy production, from oil and gas to wind and hydrokinetic. Murkowski's new language would create a coastal state clean energy fund with 12.5 percent of the overall federal revenue from offshore production.

According to a Wood Mackenzie study, development of oil and natural gas resources off the Atlantic coast could produce $428 billion in revenues for federal, state and local governments.

The Obama Administration postponed until after 2017 lease sales in the South Atlantic in the wake of the 2010 Macondo well disaster. Since that time, Virginia's governor, senators and congressional delegation have come out strong in favor of lifting the moratorium and allowing lease sales to proceed.

Mike Ward, executive director of the Virginia Petroleum Council, told Rigzone that leasing is needed so the industry can assess the hydrocarbon resources off the state's coastline. "Some of the seismic technologies used are 30 years old now," Ward pointed out. "The question looms as to what might be out there."

The proposed Lease Sale 220 area begins 50 miles off the coast of Virginia and points eastward in a triangle shape about 183 miles, covering approximately 3 million acres. The federal government estimates that the area contains 130 million barrels of oil and 1,140 billion cubic feet of gas. At current national rates of consumption, this would supply six days of oil and 18 days of natural gas, according to the Southern Environmental Law Center.

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Oil Demand to Increase; Supply Less Certain -Study

- Oil Demand to Increase; Supply Less Certain -Study

Thursday, August 04, 2011
Ernst & Young LLP

Oil demand and prices should continue to rise in the third quarter of 2011 according to indicators, even with ongoing uncertainty with respect to the economic recovery, deficit reduction initiatives in the US and the debt crisis in Europe.

In the first quarter of this year, with expectations for continued economic improvement and as a result of the supply disruptions from the Middle East, oil prices rose to over $100/barrel. But after peaking in the second quarter, crude prices fell back slightly, in spite of the announced stock release by the International Energy Agency (IEA), as the economic recovery lost some steam.

Oil

The bright spot in the oil outlook is the increasing activity in the Gulf of Mexico since the oil spill last year, with the first new production out of the Gulf coming in the second quarter. While overall production remains below pre-2010 levels, the application and permitting process is substantially improved, and increasing production will create jobs and increase domestic energy supplies at a time of expected strong demand growth. Oil production elsewhere in the Americas continued to increase as well, notably from the Bakken formation in the Upper Midwest, as well as from the Canadian oil sands and Brazil.

The big unknowns for oil producers are the short-term effects of the IEA's release of 60 million barrels from emergency supplies and OPEC members' disagreement over supply increases. The IEA's release announcement brought prices down temporarily and is expected to fill the void of Libyan supplies. However, as the market moves into the high-demand season, the IEA release will not meet that increased demand, and the market will need more supply from OPEC at a time when its spare capacity is at its lowest level in more than 20 years. Beyond the short-term, over the next three to five years, pressures on OPEC to increase capacity and production are expected to increase substantially.

"Oil prices are dictated by supply and demand, and all signs point to modest oil demand growth and uncertain supply," said Marcela Donadio, Americas Oil and Gas Leader, Ernst & Young LLP. "Barring a strong economic shock, continued strong oil prices seem to be in order over the next three to five years."

Gas

US natural gas production continues to grow, with the latest production figures reaching the highest point in almost 40 years. Shale gas is driving the growth and is now approaching about 30% of US total gas production, even as gas-directed drilling has slowed and issues surrounding the economic feasibility and potential environmental impacts of the resource are raised.

"We maintain that natural gas is a sound solution to the nation's need for domestic, cleaner-burning fuel," said Donadio. "We have the resource in abundance and we know how to produce it safely. We need to put any questions around that to rest and focus on creating more opportunities to increase natural gas demand."

Oilfield services

Oilfield service activity is dictated by upstream spending. Spending is expected to continue to grow by about 15 to 20% in 2011, returning close to the peak 2008 levels. Service capacity is being strained by the unconventionals boom. Cost increases and staffing shortages are appearing. This resurgence of the oilfield service segment is being driven by fit-for-purposes technology such as rotary steerable rigs and directional/horizontal drilling; strong oil prices; and the efficient application of shale gas technologies including multi-stage fracking and horizontal drilling.

Transactions

The second quarter was another fairly strong quarter for oil and gas transaction activity, marking seven consecutive quarters of deal growth. Deal activity in Americas continues to dominate the global transactions landscape.

Looking into the second half of year, transaction activity should stay fairly strong, boosted by the expected continued high oil prices and the ever-high geopolitical risk, tempered only by the still reasonably high levels of economic uncertainty, particularly in the US and Europe.

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Rodinia Preps Drilling Ops at Mulyawara 1 Well

- Rodinia Preps Drilling Ops at Mulyawara 1 Well

Thursday, August 04, 2011
Rodinia Oil Corp.

Rodinia Oil is preparing to run the second intermediate casing string prior to drilling ahead into prospective formations at Mulyawara 1, in the Officer Basin of South Australia.

Rodinia began drilling Mulyawara 1 on the morning of Thursday June 9, 2011 (Australian Central Standard Time) and reached the first intermediate casing point of 1,525 meters on August 1, 2011. The casing shoe is being set above the projected depth of the first series of evaporite (salt) seals.

To date drilling has been slower than anticipated due to mechanical issues on the rig, drilling in harder rock than predicted and extremely high rate water inflows from upper zones, which forced drilling operations to switch from the faster air hammer drilling to the slower underbalanced water rotary drilling.

Mulyawara 1 has confirmed the existence of excellent reservoir quality rocks in the Neoproterozoic with the Eidacaran Age Murnaroo Formation having an average log porosity of 18% (commonly up to 23%) and flowing water at rates between 600 and 900 Bbl per hour during air drilling operations. The well has also encountered small gas peaks and traces of hydrocarbon fluorescence exhibiting blooming cut over discrete intervals within the undifferentiated Upper Cryogenian.

Although these findings are encouraging and reduce the risks associated with source, migration and reservoir, this exploration well is still a high-risk venture and yet to be proven. The primary objectives of the well are yet to be intersected and lie below the prospective regional salt seals.

Rodinia has an 80% working interest in this well and prospect and is the operator.

Mulyawara 1 is located in the northwest corner of PEL 253 in the Officer Basin, South Australia on a structure of approximately 36.3 square kilometers (per horizon) in size as identified on seven separate 2-D seismic lines.

As Mulyawara-1 is entering the prospective target formations, management of Rodinia will continue to impose an operational trading blackout on all officers, employees, directors and consultants until the results of the exploration well are made public.

Rodinia expects to issue the next drilling update report once Mulyawara-1 has reached total depth, unless a material event occurs in the interim.

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Kulczyk Oil Spuds Ukraine Olgovskoye Well

- Kulczyk Oil Spuds Ukraine Olgovskoye Well

Thursday, August 04, 2011
Kulczyk Oil Ventures Inc.

Kulczyk Oil Ventures announced that the O-12 well on the Olgovskoye License in Ukraine commenced drilling on August 3, 2011.

O-12 Exploration Well

The O-12 well is located approximately 1.4 kilometers to the northwest of the recently tested O-9 well. The O-12 well will be drilled to a depth of 2,650 meters and is designed to test gas-bearing reservoirs in the Muscovian and Bashkirian sections and to further develop the gas production capability of the Olgovskoye Field. The drilling of the O-12 well is expected to take approximately 40 days.

The well, identified after interpretation of 2D seismic data by the KOV/KUB-Gas technical team, is on trend with the main Olgovskoye producing area and is intended to extend the known boundaries of the Olgovskoye Field. A successful well will increase gas production and lead to additional drilling locations along this trend.

Olgovskoye License

The O-12 well is the fourth new well drilled in the Olgovskoye Field since the Company acquired its interest in KUB-Gas in June 2010. It is part of a larger development program on the KUB-Gas assets through 2011 and 2012 which has involved the drilling of new wells at O-8, O-9 and O-14. The Olgovskoye Field currently produces from 4 wells (O-3, O-4, O-5 and O-7) with each well producing from a separate horizon.

The first of new wells was drilled at the Olgovskoye-8 location and reached a total depth ("TD") of 2,780 meters in early January. Production testing of the O-8 well will begin in August.

The second of the new wells drilled on the Olgovskoye license, the O-9 well, finished drilling at a depth of 2,638 meters in mid-April and was cased to TD as a potential multi-zone gas well. The O-9 was production tested in June and July of this year and the well is expected to begin commercial production at a gross rate of approximately 1.5 million cubic feet per day ("MMcf/d") prior to the end of the third quarter as disclosed in the news release of KOV dated August 1, 2011.

The third of the new wells, Olgovskoye-14 ("O-14"), was drilled to a TD of 2,800 meters and cased to TD after encountering up to eight potential gas-bearing zones in the Middle and Lower Bashkirian sections of the well as disclosed in the news release of KOV dated 18 July 2011. A service rig will be moved to the O-14 location to production test the well after the production testing of the O-8 well is finished.

KUB-Gas LLC ("KUB-Gas") owns a 100% interest in the Olgovskoye license and in four other licenses in the Lugansk area of Ukraine. KOV owns an effective 70% interest in KUB-Gas.

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EDITORIAL: World's Watching

- EDITORIAL: World's Watching

Thursday, August 04, 2011
Houston Chronicle

The excitement across Texas about possibilities for new natural gas and oil plays is palpable, particularly across South Texas, site of the rich Eagle Ford Shale formation.

Like most Texans, we're supporters of responsible, environmentally sensitive development of these resources that can help bring well-paying jobs to Texas, greatly increased revenues to the state and greater energy and economic security to the country as well.

For those and other reasons we're pleased to see the Texas Railroad Commission take a pro-active position in overseeing safe and responsible development of the area's resources.

Commissioner David Porter has created an Eagle Ford Task Force to head off the kind of public backlash that has troubled the Barnett Shale area in North Texas.

Porter is on target with his diagnosis of what went wrong in North Texas: too little information about the development process, which has been near populated areas, and a perception that the energy companies doing the work were calling the shots while the Railroad Commission was largely AWOL or doing the minimum to direct the process to ensure that public and environmental interests were protected.

To his credit, Porter is trying to avoid a repeat of that situation in South Texas and the public backlash that could hinder development of the region's immense resources. He has assembled a group of 22 stakeholders that includes representatives of drilling, pipeline and trucking companies, green energy experts and environmentalists, county and economic development officials, landowners and those who represent landowners, according a report by Vicki Vaughan of the San Antonio Express-News that ran in last Thursday's Chronicle ("Eagle Ford advisers ready to tackle goals," Page D3, July 28).

The significance of this work was probably best summed up by an Eagle Ford landowner and member of the Sierra Club: "We're on a world stage," said Teresa Carrillo. While noting the "fantastic" economic opportunity presented by the drilling, Carrillo also focused on the challenge to do it right.

Others have emphasized the opportunity that Eagle Ford offers the industry to "do it right and establish best practices" that can be used in other areas going forward.

This attitude is imperative, we would argue, and appears to be gaining traction across the industry, judging by the remarks of visitors from the industry meeting with the Chronicle's editorial board recently.

We detect a consensus that when it comes to caring for the environment, the entire industry must be cleaner than clean -- more rigorous than the regulators.

We hope that mind-set prevails and believe the Railroad Commission is setting the proper tone in its approach toward development in the Eagle Ford Shale area.

Copyright (c) 2011, Houston Chronicle

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Progress Energy Reported Mixed Q2 Results, Top Line Down 5%

- Progress Energy Reported Mixed Q2 Results, Top Line Down 5%

Aug 4, 2011

Progress Energy (NYSE:PGN) reported Q2 EPS of $0.71, ahead of consensus estimates of $0.64 per share. Revenues for the quarter fell 4.9% year-over-year to $2.26 billion, missing consensus estimates of $2.29 billion.

The company sees 2011 EPS of $3.00 to $3.12, vs. consensus estimates of $3.13 per share.

Bill Johnson, Progress Energy chairman, president and CEO said, "Favorable weather in the second quarter, coupled with continued financial discipline within the company, helped us successfully deliver on our earnings per share goal for the first half of the year. "We continue to feel the effects of a challenging economy in our service area, but we remain focused on managing the business effectively and making wise investments to meet our customers' needs today and in the future, as we prepare for our pending merger with Duke Energy."

Progress Energy has a potential upside of 1.2% based on a current price of $46.53 and an average consensus analyst price target of $47.11.

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El Paso Pipeline Partners Missed Q2 Estimates, Top Line Up 9%

- El Paso Pipeline Partners Missed Q2 Estimates, Top Line Up 9%

Aug 4, 2011

El Paso Pipeline Partners (NYSE:EPB) reported Q2 EPS of $0.50, missing consensus estimates of $0.54 per share. Revenues for the quarter rose 9.1% year-over-year to $358.0 million, missing consensus estimates of $360.8 million.

Jim Yardley, president and chief executive officer of El Paso Pipeline Partners said, "We continue to deliver superior results for our unitholders with another quarter of higher earnings and cash flow. Our portfolio of high-quality assets continues to grow through acquisitions and expansions. During the quarter, we completed the acquisition of additional interests in CIG and SNG, and now own 100 percent of SNG. We also placed into service additional expansion projects which brings our total to fourteen in less than three years. Our successful acquisitions and expansions have enabled us to deliver consistent distribution growth, as we have increased quarterly distributions every quarter since our IPO in 2007."

El Paso Pipeline Partners has a potential upside of 19.4% based on a current price of $35.29 and an average consensus analyst price target of $42.15.

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El Paso Topped Q2 EPS Estimates By $0.10 Per Share

- El Paso Topped Q2 EPS Estimates By $0.10 Per Share

Aug 4, 2011

El Paso (NYSE:EP) reported Q2 EPS of $0.34, ahead of consensus estimates of $0.24 per share.

Doug Foshee, chairman, president, and chief executive officer of El Paso Corporation said, "We are very pleased with our financial and operational performance. With the completion of our Ruby Pipeline, we have placed three major projects into service this year and will complete two more by year end. And with natural gas likely to be the cornerstone for growth in electric power development, we continue to see exciting growth opportunities on the horizon. Execution in our E&P business is outstanding, with oil programs ramping up with results that are equal to or better than expectations. We are very encouraged by the completion of our first 7,000 foot plus lateral in the Wolfcamp Shale, and we see this program delivering many years of very profitable development across our large acreage position. On the financial front, we continue to make excellent progress, improving our balance sheet primarily through drop downs to El Paso Pipeline Partners. This progress has put us in position to separate into two outstanding companies by year end. We believe this is a great time to be a shareholder of El Paso."

El Paso has a potential upside of 27.7% based on a current price of $19.49 and an average consensus analyst price target of $24.89.

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Report: Bakken Oil Creates Boon, Challenges for North Dakota

- Report: Bakken Oil Creates Boon, Challenges for North Dakota

Thursday, August 04, 2011
Rigzone Staff
by Karen Boman

The Bakken oil boom has bolstered North Dakota's employment rate and tax revenues, but also has created a number of challenges for state and local government as well as producers operating in the Bakken, according to a report by the Energy Policy Research Foundation.

North Dakota has been an oil producing state for 60 years, but only during the past three years has the Bakken boom made North Dakota the fourth largest oil producing state in the U.S. and one of the largest onshore plays in the country. The success of the Bakken, which the U.S. Geological Survey estimated in 2008 to hold 4.3 billion barrels of technically recoverable reserves, has been largely attributed to advances in oil field technology such as hydraulic fracturing and horizontal drilling. High oil prices, low natural gas prices and ready access to privately held prospects also have contributed to the Bakken's success.

With an unemployment rate of 3.2 percent, the state received $749.5 million in state revenues from crude oil taxes on production and extraction in 2010, and more than $10.1 million in extraction taxes for natural gas last year. The oil and gas industry also spent $1.49 billion in taxable sales and purchases.

However, the influx of drilling activity to the state means that state and local governments face a range of new requirements to support the surge in oil production, especially road repair and construction, the report noted. And while North Dakota enjoys the lowest unemployment rate in the nation, the high wages offered by the oil and gas industry is beginning to make it difficult for local stores, shops and restaurants to keep workers given the opportunities in the petroleum sector.

The rate of services required to support the oil boom also are in short supply, with hotels in petroleum producing regions booked two to three years out and every apartment rented. Many oil companies operate their own "man camps" where employees eat and sleep while they are working. "A challenge for the state is to address the requirements for expanded infrastructure and related services while at the same time address the financial risks of an economic downturn should the rising production prove unsustainable," the report noted.

Limited access to traditional transports on infrastructure such as pipelines means that Bakken production is expensive to deliver to major refining centers and is discounted heavily at the wellhead. Bakken crude sells at a discount to Light Louisiana sweet and even West Texas Intermediate crude, despite its high quality, as transportation costs remain high for shipment to refining centers and major consuming markets. However, new infrastructure developments may soon support higher wellhead values.

Well drilling costs also have increased significantly in the past few years, and are expected to grow further, as rising oil prices have triggered drilling activity in multiple shale plays throughout the U.S. While the cost can vary from company to company depending on a host of factors such as the length of the horizontal lateral, the number of frac stages, and the choice of proppant (sand or ceramic), the cost of drilling and completing an oil well in North Dakota in 2009 was $5.6 million, according to the North Dakota Petroleum Council.

Today, several companies have reported drilling and completing costs of over $10 million per well. The increase is largely due to longer horizontal laterals and more frac stages, but also higher input costs from increased demand in rigs and completion services throughout the country and region.

Constraints on well completion services mean that many companies face a backlog of wells that are awaiting completion. The delay can come from weather related constraints as well as constraints in available frac crews. Projects are currently underway to secure the water supplies needed for hydraulic fracturing activity, but the issue of water supply for both local communities and the oil field will continually be dealt with and debated as drilling increases in the region.

Producers also must overcome severe weather constraints, such as heavy snowfall and temperatures as cold as -40 degrees Fahrenheit in the winter, which can result in well shut-ins. The past few winters have been some of the worst in North Dakota history and are proving to be very challenging for the industry. Additionally, severe spring rains have caused towns to be evacuated due to flooding.

While uncertainties exist about the future of shale oil, "North Dakota is embracing oil development and has thus far provided a regulatory environment that addresses genuine environmental concerns but also embraces the economic benefits of rising oil production," the report said.

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Venezuela to Compensate American Oil Companies for Nationalization?

- Venezuela to Compensate American Oil Companies for Nationalization?

Thursday, August 04, 2011
OilPrice.com
by John Daly

If Cuba's Fidel Castro is America's favorite Latin American bête noire, then Venezuela's Hugo Chavez qualifies as Washington's reigning Prince of Darkness.

In 1960, Fidel Castro nationalized US business interests without compensation, bringing down on impoverished benighted country 51 years of sanctions that continue to the present day.

Similarly, four years ago Chavez completed the nationalization of foreign oil interests, transferring their shares to the state-owned petroleum company Petróleos de Venezuela, S.A., more commonly referred to by its acronym PDVSA.

The screaming was heard echoing through the boardrooms and canyons of Wall Street.

Now the picture appears to be shifting, as Venezuelan Energy Minister Rafael Ramirez told reporters this week, "We've never said we wouldn't pay" the two U.S. multinational corporations Exxon-Mobil and Conoco-Phillips, "the only two that didn't accept our laws and didn't accept (the terms of a compensation deal for confiscated assets) and took the dispute to the World Bank's International Center for the Settlement of Investment Disputes, or ICSID."

As Ramirez is also the president of PDVSA, his comments should not be taken lightly. Ramirez added that the arbitration processes "are moving forward and we have to defend ourselves because those mechanisms are so perverse that if you don't show up they execute you."

Venezuela's oil industry had been under private control until 1974, when Venezuela nationalized it, setting up PDVSA. Venezuela's oil production is centered in the Orinoco Oil Belt, which analysts believe contains the world's largest reserves of extra-heavy oil, with an estimated 300 billion recoverable barrels.

In the 1990s PDVSA began a so-called "oil opening," where it allowed more and more foreign private companies to extract oil, via majority shares in joint ventures and the operating agreements.

In February 2007 Chavez announced a new law-decree to nationalize the last remaining oil production sites that are under foreign company control, to take effect on 1 May, allowing the foreign companies to negotiate the nationalization terms. Under the new regulations, the earlier joint ventures, involving ExxonMobil, ChevronTexaco, Statoil, ConocoPhillips, and BP, were transformed give PDVSA a minimum 60 percent stake. The process completed a government initiative begun in 2005, when the Chavez administration transformed earlier "operating agreements" in Venezuela's older oil fields into joint ventures with a wide variety of foreign companies. Thirty out of 32 such operating agreements were transformed by the end of 2005 - only two challenged the transition in court, and no guesses as to who the companies were. Most foreign companies accepted the new arrangements, including Chevron, Statoil, Total and BP, but ExxonMobil and ConocoPhillips refused

Ramirez had not referred to the compensation issue since expressing confidence last November when he averred that Venezuela would emerge victorious in the arbitration proceedings, saying then that the multinational companies' aspirations were "unreasonable."

If not "unreasonable," then certainly "greedy," as according to media reports, Exxon-Mobil alone is demanding compensation ranging from between $7 and 12 billion.

Ramirez said that said Venezuela scored a victory at the Washington-based ICSID in June 2010, when the World Bank tribunal unanimously ruled that it did not have jurisdiction over any dispute that dated back prior to 2006.

When Chavez's government was sued before the ICSID for its 2007 nationalization policies ExxonMobil and ConocoPhillips not only demanded compensation for seized assets, but also refunds for higher taxes and royalties paid prior to 2006.

Sure gonna be interesting to watch.

(John Daly is an energy and geopolitical specialist with OilPrice.com. The full article is available here.)

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Kuwaiti Firm Eyes Sudan Oil Exploration

- Kuwaiti Firm Eyes Sudan Oil Exploration

Thursday, August 04, 2011
Knight Ridder/Tribune Business News

A company based in the Arab Gulf state of Kuwait has expressed interest in conducting oil-wells drilling and exploration activities in Sudan, state media reported on Tuesday.

Sudan's daily oil output currently stands at 110,000 barrels, according to official figures, after the country lost nearly 75 percent of the previous 500,000 barrels per day figure it was splitting evenly since 2005 with South Sudan which seceded on 9 July.

Officials say they expect the current oil figure to rise to 170,000 barrel per day by 2012.

Exploration and production scene of Sudan's oil sector is dominated by Asian and Arab companies, with Chinese-led companies as the main operators.

A delegation of Gulf Petroleum Investment Company (GPI), a Kuwaiti shareholding company, arrived in the country and held a meeting on Tuesday with the country's acting minister of oil Ali Ahmad Osman at his office in Khartoum.

The minister instructed the competent departments at his ministry to provide GPI with necessary support and facilitate its venture to join Sudan's market of oil wells drilling and exploration.

Meanwhile, the company's delegation apprised the minister of its activities in oil-exploration fields, including its operations in Egypt, UAE and Syria.

It is not clear where will the Kuwaiti company's exploration activities take place but new explorations are underway in a number of areas.

In October last year, Sudan announced that oil exploration activities would be initiated in three areas in South Darfur State, one of the three states that make up the country's war-battered western region.

In 2006, Sudan awarded a license to a consortium of Arab and Sudanese companies for block 12A which covers part of North Darfur and stretches up to the border with Libya.

Analysts opine that oil exploration activities in Sudan are subject to a number of uncertainties, including political instability and armed conflicts.

Copyright (c) 2011, Sudan Tribune

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Petro Matad Begins Drilling at Davsan Tolgoi-9 Well

- Petro Matad Begins Drilling at Davsan Tolgoi-9 Well

Thursday, August 04, 2011
Petro Matad Ltd.

Petro Matad announced that the Davsan Tolgoi-9 ("DT-9") exploration well was spudded at 8.50 p.m. Mongolian time (1.50 p.m. BST) on August 3, 2011.

The DT-9 well is being drilled vertically to an estimated target depth of 1,750 meters. The well is being drilled by the Company's contractor, DQE International.

DT-9 targets the Lower Tsagaantsav reservoir at a location 2.5 km south of and 220 meters high to the Company's DT-4 well, which recovered oil-saturated core from the Lower Tsagaantsav.

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Horn Petroleum to Commence Drilling Program in Puntland

- Horn Petroleum to Commence Drilling Program in Puntland

Thursday, August 04, 2011
Range Resources Ltd.

Range announced that its Puntland Joint Venture partner and operator, Africa Oil, through its newly created company Horn Petroleum is currently in final preparations to commence the historic and highly prospective two well drilling campaign in the Dharoor Valley Block in Puntland, with the first well scheduled to spud early in the fourth quarter of 2011.

The drilling locations have been selected over two robust prospects and each well is targeting gross best estimate prospective resources of 300 million barrels and 375 million barrels recoverable for the two prospects (with net attributable prospective resources to Range of 60 million barrels and 75 million barrels respectively). Contracts for the drilling rig and third party services are in advanced stages of negotiation and are expected to be executed in early August.

The Puntland Government and Dharoor Valley communities are fully supportive of the drilling project and have ensured they will do all necessary to allow the project to move forward safely and expeditiously. Specific milestone target dates have been adjusted by the Puntland Government allowing the Company and partners to move the drilling start-up to the fourth quarter of 2011. In addition, partial relinquishments in both the Dharoor Valley and Nugaal Valley agreements have been finalized and approved.

Range Resources Executive Director, Peter Landau commented, "We are delighted that JV partner and Puntland operator, Africa Oil Corp., along with the Puntland Government have settled on mutually agreeable terms that will finally see a well(s) drilled in Puntland, Somalia this year. We look forward to advising the market in the coming week(s) as critical service contracts are entered into and mobilization begins."

"Range is certainly entering into an exciting stage for the Company, with the drilling of the first exploration well in Georgia progressing well, the first well in the 21 well initial Trinidad work program having spudded and scheduled to be completed and on-line mid next week before moving on to the next well in this program. Also with a contractor appointed for the third well on the North Chapman Ranch Project, the Company will have its four operations all active in September and October of this year. "

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Leni Reinstates Production at Hontomin Well

- Leni Reinstates Production at Hontomin Well

Thursday, August 04, 2011
Leni Gas & Oil plc

Leni Gas announced the reinstatement of production at the Hontomin-2 well in Northern Spain, and its immediate plans for further production enhancement at the Ayoluengo Field.

During the last few weeks, operations at Hontomin have focused on cleaning the well and the perforating of an additional reservoir zone shallower than the previously producing interval. These operations were successfully concluded and the well was returned to production on the evening of the July 29, 2011.

A total of 13.5 meters of perforations were opened between 1349.5 and 1365 meters including 7.5 meters in new reservoir zones which were identified on wireline logs run earlier in July. The well continues to clean-up with water cut reducing and oil production increasing. The well is producing approximately 180 bfpd and the water cut has been falling over the last 4 days. During the last 24 hour period the well produced 15 barrels of oil and production is expected to continue to rise significantly as the static fluid level in the well is reduced and the new perforations contribute to oil flow. In October 2010, Hontomin-2 reached a production rate of over 85 bopd which was achieved without the 7.5 meters of newly opened perforations.

The Company-owned Cardwell rig has now been returned from Hontomin to the main Ayoluengo field 30 kilometres away where several wells from the recent well intervention program will be returned to production. Wells Ayo-22 and Ayo-32 are expected to be brought back on production within the next few weeks. Further routine maintenance work to other producing wells, including Ayo-18 and Ayo-40, also requiring the use of the Company's Cardwell service rig, will be undertaken and this is expected to lead to further improvements in overall production rates which have been performing as expected.

Design work for chemical stimulation in order to treat the scale and wax found in wells during the recent work-overs and further enhance production is progressing and field trials are planned for the autumn.

Neil Ritson, LGO's Chief Executive, commented, "Hontomin-2 is an important well and we firmly expect further improvements in production as it cleans up. The return of the rig to Ayoluengo will allow us to consolidate the gains made during the recent interventions and therefore production from Spain is expected to exceed 400 bopd in the next few months. We are happy with the recent progress made in Spain and intend to update shareholders on further developments as soon as possible."

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