"In our opinion, these revised terms for entry into OPL 281 are a very positive development, as they reduce SacOil’s capital exposure and indicate that the work programme will be expedited under a very credible local operator," said analyst Craig Howie.

Turnover jumped by 61 per cent to £2.1 million in the half year to January 31 as volumes from its three producing fields rose by 23 per cent to 187 barrels per day.

Income was also boosted by a 39% rise in oil prices to US$108.9 per barrel.

The company currently has three producing assets all located in the East Midlandsand consisting of a 100% working interest in the West Firsby and Crosby Warren fields and a 65% working interest in the Whisby 4 well.

Higher output reflected the West Firsby WF-9 well coming on stream and reduced downtime after the blizzards had affected the the previous year.

Hugh Mackay, chief executive, added that daily production has been consistently higher than the previous year despite a recent workover programme for the West Firsby 7 well.

“Our UK production continues to generate more than enough cashflow to cover our operating costs and provides a solid foundation from which we can develop our other highly exciting assets.”

“Little or no value is being attached to our highly prospective portfolio of exploration and development assets that include the Berenx gas appraisal project and the Tarbes Val d'Adour re-development project, both of which are located in France.”

Management is committed to realising the inherent value of Europa’s portfolio, he added.

BP (LON:BP.) has increased its dividend as it revealed it was back in profit in 2011.

The oil giant said that replacement profits increased to US$7.6 billion for the fourth quarter (Q4 2010 : US$4.6 billion), which will see the firm posts just shy of US$24 billion in profits for the full year.

It comes after a difficult 2010 in which the Gulf of Mexico oil lead to a near US$5 billion loss. 

Today, BP said that a total of U$1 billion has been committed for the early restoration of natural resources following the Deepwater Horizon accident, while US$7.8 billion has now been paid to meet claims and government payments and a further US$15.1 billion has been paid into the Deepwater Horizon Oil Spill Trust fund.

Meanwhile the company is preparing to go to court in New Orleans on February 27.

"As I have said before, we are prepared to settle if we can do so on fair and reasonable terms, but equally, if this is not possible, we are preparing vigorously for trial," chief executive Bob Dudley said.

BP revealed that it generated around US$22 billion in operating cash flows during the year, which is a 60 per cent increase from last year. And due to high oil prices it expects cash flows will continue to grow.

Cash flows may be as much a 50 per cent higher still by 2014.

Some of the cash will be returned to shareholders. It confirmed today that it will increase the fourth quarter dividend by 14 per cent to 8 cents a share. 

Meanwhile half of the cash will be re-invested, it said. 

In the coming year BP plans to start six major upstream projects. It is also planning to drill twelve exploration wells. 

"2012 will be a year of increasing investment and milestones as we build on the foundations laid last year,” Dudley added. 

“As we move through 2013 and 2014, we expect financial momentum will build as we complete payments into the Gulf of Mexico Trust Fund, restore high-value production and bring new projects on stream."

Leni Gas & Oil (LON:LGO) today told investors that its drilling operations have been slightly delayed at the Eugene Island Field, in the Gulf of Mexico.

The delay relates to a problem with the drilling rig’s previous contractor. And LGO says there are no cost implications for the Eugene Island partners.

The current operator of the Ocean Columbia jack-up rig at Eugene Island-51 has had difficulty withdrawing the rig’s legs from the seafloor.  

Work is currently underway to free the legs so that they can be raised and the rig can be towed to the Eugene Island location, which is about 55 kilometres away.  

At Eugene Island, the drilling programme will start with the A-2ST01 well, a sidetrack of the existing A-2 well, which targets mean recoverable reserves of 0.5 million barrels of oil within the Tex X2 target level.

The slightly deeper Tex-X3 reservoir will also be tested by the well. Both reservoirs are productive in other wells throughout the field.

The partners have budgeted a total 16 days for the drilling and evaluation. The net cost to LGO of drilling, logging and evaluating the A-2 sidetrack is an initial US$280,000.

Any incremental production is expected to be realised quickly with a short payback period on the investment.

Aminex (LON:AEX) and Solo Oil (LON:SOLO) today reported the results of the Ntorya-1 exploration well in Tanzania.

The well has now been drilled to a depth of 2,500 metres. And it did not encounter its targeted sandstone intervals at the prognosed depths of 1,800 to 1,900 metres. However sandstone intervals, containing traces of gas, were encountered at a depth of 2,300 metres.

Further analysis is currently underway using wireline logs and a seismic check-shot survey. This work will help determine whether or not the well will be drilled deeper.

"Ntorya is only the second recent well in the onshore portion of the Ruvuma basin in Tanzania and we are clearly still establishing the accurate correlation between the seismic and well stratigraphy,” said Neil Ritson, Solo Oil’s executive director.

“Additional evaluation of these well results will I am sure be key in helping to unlock the potential for the Tertiary and Cretaceous hydrocarbon plays within the PSA."

Aminex is the operator of the Ntorya well. It has a 56.25 per cent stake in the well. While Solo Oil has an 18.75 per cent stake, alongside fellow JV partner Tullow Oil (LON:TLW) which owns 25 per cent.

Ntorya 1 was drilled in an onshore location in eastern Tanzania. It was drilled to test an area within the Rovuma basin, which is also host to several large gas discoveries offshore in deep waters.

The Ruvuma Basin has become extremely active for the oil and gas industry in recent years. 

Anadarko (NYSE:APC) of the US with partner Cove Energy (LON:COV) have drilled several successful deep water gas wells offshore in the Mozambique sector of the basin. BG (LON:BG) and partner Ophir Energy (LON:OPHR) also made an offshore gas discovery in the Tanzanian sector last year.

Premier Oil told investors it would plug and abandon an appraisal well in the north sea after results came in at the low end of the group’s expectations.

The East Fyne appraisal well was drilled to a total depth of 5,020 feet. It encountered 11 feet of gas bearing sands and 8 feet of oil bearing sands.

The group had expected to find a larger oil reservoir at this location.

Premier says the findings will be incorporated into its information on the Greater Fyne Area and it will decide whether a commercial development is viable by the end of the second quarter of this year.

The Fyne area is being explored through a joint venture. Premier is the operator with a 39.9 per cent stake, while Antrim Energy (LON:AEY) owns 35.1 per cent and First Oil Expro has a 25 per cent.

Premier will next spud a well on the Bluebell prospect, in the Central North Sea, in March 2012.

The company also reported on the Anoa development well this morning. The well, on the Natuna Sea Block A, was deepened to 11,012 feet to investigate the Lama Formation. 

It encountered 300 feet of tight, but fractured, Lama Formation sandstone. However Premier says it is not possible to determine the fractures contain moveable gas. The Lama interval will be tested later this month.

Premier’s next exploration well on the Natuna block will test the Biawak Besar prospect. The well will spud in March 2012.

Wentworth Resources (LON:WRL) today announced the spudding of the onshore Ziwani-1 exploration well on the Mnazi Bay licence onshore Tanzania, in the Rovuma basin.

The well is being drilled near the coast within the Rovuma basin. Mnazi bay is already known to host hydrocarbons, and two gas fields have already been established in the area. The last well in Mnazi Bay was drilled in 2007.

In recent years a number of majors have made very large gas discoveries in the Rovuma basin, offshore in deep waters.

Ziwani-1, the fifth well to be drilled in Mnazi Bay, is located 13 kilometres from the Mnazi Bay and Msimbati gas fields. It will be drilled to a depth of 1,800-2,500 meters. And it is targeting Miocene and Oligocene sandstones, which are similar to the reservoirs of the nearby gas fields.

"We are excited to start the year with a high impact work programme that has the potential to deliver significant asset growth and shareholder value in 2012,” managing director Geoff Bury said.

The spudding follows last week’s news of Wentworth’s asset swap deal with Cove Energy, which gave the firm and increased stake in Mnazi Bay.

The deal, valued at US$38.8 million, saw Wentworth trade in a royalty it held over Cove’s future production (from the offshore Rovuma concession) in return for Cove’s 16.38 per cent stake in the Mnazi bay. It will also issue shares and make a future cash payment to Cove.

Wentworth and the operator Maurel et Prom will now take the Mnazi bay assets forward, alongside the Tanzania Petroleum Development Corporation. 

Maurel et Prom own 38.22 per cent stake in Mnazi Bay and the TPDC owns a 20 per cent stake.

Under the Mnazi Bay joint venture agreement Wentworth’s exploration costs are partially carried.

It will pay 30 per cent of the costs of the Ziwani-1 well and holds a 52.225 per cent participating interest in this exploration well.

"The carried interest we enjoy in the Mnazi Bay concession provides full participation with reduced financial exposure,” Bury said.

“We look forward to updating further on the Ziwani-1 well as well as our entire work programme as we commence what is a seminal year in the company's development."

The Ziwani-1 drilling is the start of the 2012 Mnazi Bay work programme.

In addition to Ziwani-1 the programme will include work-overs on three existing wells and the drilling of one further well – which will be either appraisal or exploration.

“This well and the 2012 work programme are designed to explore for additional hydrocarbon resources and to further prove up existing natural gas reserves,” Wentworth said.

“Proving up additional gas resources will enable the concession partners to commit to and deliver agreed quantities of natural gas to the proposed Dar es Salaam to Mnazi Bay pipeline.”

Wentworth also told investors that talks are underway with TPDC with a view to agreeing a long-term gas supply agreement.

Isarene hosts the world class Ain Tsila gas field. 

The deal was first struck in April last year. Petroceltic says it is now owed over US$100 million from the deal and payment is due in the next 30 days.

"We are delighted to announce the completion of the Enel farmout and formally welcome our new partner to the Isarene Licence,” said chief executive Brian O'Cathain.

“Since announcement of the deal in April 2011 we have forged a valuable and co-operative working relationship with Enel and Sonatrach, culminating in the completion of the highly successful appraisal campaign. 

“We look forward to a long and successful relationship in this outstanding asset."

Under the terms of the deal, ENEL agreed to pay to US$36.75 million to Petroceltic. This gives the firm more than 24 per cent of all back costs incurred from 2005 until the end of the exploration period in April 2010. 

Additionally ENEL had to commit to funding 49 per cent of the costs associated with the recently completed six well appraisal drilling programme. These costs are capped to a maximum of US$145 million.

Furthermore, there is a further potential payment which is contingent up the outcome of future appraisal as well as future reserve volumes and production volumes. This could be worth as much as US$75 million for the company.

The company now retains a 56.625 per cent interest in the licence while Algeria’s national oil company Sonatrach owns 25 per cent and ENEL owns 18.375 per cent.

Earlier this week broker Daniel Stewart came out with a bullish assessment of Petroceltic. It says the firm has a well diversified asset base that has ‘game changing’ potential.

The bullish view is reflected in the broker’s punchy price target, set at 13.7p, which implies nearly 70 per cent upside from the current price of 8.2p a share.

Gulf Keystone Petroleum (LON:GKP) has received permission to transfer its interest in the Hassi Ba Hamou permit in Algeria to BG Group and Sonatrach at no cost. 

The receipt of formal government approvals ends a process that began back in 2010.

It is part of a strategic exit from the country which will allow the company to concentrate on its world class oil assets in Kurdistan, the semi-autonomous region of Iraq.

Todd Kozel, company’s chief executive, said:  "We are pleased that with the HBH transfer we have made good progress towards achieving our goal of a gradual strategic exit from Algeria. 

“We are firmly focused on our operations spanning four exploration blocks in the Kurdistan Region of Iraq, including the Shaikan world-class discovery, where the 2012 and 2013 high impact drilling campaign is currently underway following excellent results achieved in 2011.”

The flagship Shaikan block is estimated to contain 8 billion barrels of crude calculated on a P90 basis – meaning the oil has a 90 per cent certainty of being produced.  The P10 value is 13.4 billion barrels, giving a mean figure of 10.5 billion barrels.

The last update was possibly one of the most encouraging so far as the company’s chief operating officer, John Gerstenlauer, said the Shaikan-4 may be the best well it has logged to date.

It achieved a flow rate of 4,970 barrels and 7 million standard cubic feet of gas a day from a thin zone at the bottom of the lower-lying Kurre Chine B formation.

The oil was a 39 degree API light crude, while the gas flowed at a wellhead pressure 1,101 PSI. 

In the Kurre Chine C, Shaikan-4 achieved a flow rate of 563 barrels a day and flowed 3.65 million cubic feet of gas. These were two of seven planned well tests.    

Chief executive W Michael Ford said that it intends to “target these oil and liquids-rich opportunities within our inventory”.

Caza has a 40% working interest and a 32% net revenue interest in the Mud Slide Slim well in New Mexico, which has been producing gas since 2008.

This prospect includes the Bone Spring horizontal play where a host of other producers have been drilling wells in the past 18 months.

Caza said it recently conducted its own extensive stimulation and production tests on each of the Bone Spring zones in the Mud Slide Slim well. 

The tests showed each zone of interest, the Avalon Shale and 1st and 3rd Bone Spring Sands, to be commercially productive and therefore viable horizontal targets. 

Caza has now comingled these zones with the well producing at a peak daily rate of 159 barrels of oil per day and is currently producing 73 barrels of oil per day using a pumping unit.

W Michael Ford added: “The recent re-completion of the Mud Slide Slim well in the Bone Spring Formation has further improved our production profile at a relatively low cost to the company.”

“More importantly, we are very excited about the Bone Spring Formation and the potential for further horizontal drilling within our lease blocks.  We are currently evaluating the production potential of the Bone Spring horizontal play and how it might impact our current New Mexico acreage position. This may also impact our 2012 drill plan when evaluated against the rest of our prospect/property inventory.”  

Caza added that fourth quarter production overall increased to 277 barrels of oil equivalent per day, up 19% on the third quarter’s 233 barrels of oil equivalent per day. 

Shares rose by 7% to 10.85p.