AWE Reports Net Loss

- AWE Reports Net Loss

Monday, August 29, 2011
AWE Ltd.

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

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

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

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

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

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

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

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

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

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

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

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

Finance

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

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

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

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

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

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

Exploration

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

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

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

Development

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

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

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

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

2011-2012 guidance

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

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

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Report: UK O&G Production Declines Continue

- Report: UK O&G Production Declines Continue

Monday, August 01, 2011
Rigzone Staff
by Karen Boman

UK oil and natural gas production declined in 2010, mirroring the larger trend seen over the past decade, the UK Department of Energy and Climate Change (DECC) reports.

In the Digest of United Kingdom Energy Statistics (DUKES) 2011 report, DECC reports that primary energy production in 2010 totaled 158.1 million tones of oil equivalent, down 5.3 percent from 2009. Production has fallen each year since 1999, and is down 46.9 percent on 1999 levels, an average rate of decline of 5.6 percent.

Crude oil production, which includes natural gas liquids (NGLs), in 2010 was 63 million tones, 7.7 percent lower than in 2009, and now accounts for 44 percent of primary energy production.

DECC notes that net imports of crude oil and NGLs rose to meet demand with oil exports decreasing by six percent. Net imports grew to just under 9 million tones or around 13 percent of the UK's demand.

The decrease in oil production over the past 10 years shows a sharp rate of decline between 2002 and 2006, with a shallower profile in later years. The main factor behind this flattening effect was the Buzzard field development, which compensated for the sharper falls seen in existing fields. On average, crude oil production has been decreasing by around seven percent a year.

Gross UK gas production has been decreasing since 2000, and in 2010 was down 4.3 percent from 2009. Gross gas production has fallen by 47.3 percent since its peak in 2000. Gas imports in 2010 were almost a third higher than in 2009, mainly because of lower production and higher demand.

Liquefied natural gas (LNG) is increasingly important as a source of imports to supplement existing ones. In September 2010, imports from shipped LNG surpassed the gas imported via pipeline from Norway for the first time; in 2010, LNG imports accounted for 35 percent of the UK's total commercial imports.

UK primary energy consumption in 2010 grew by 3.2 percent, largely driven by the colder weather in 2010. Total oil consumption in the UK fell marginally in 2010; the majority of final consumption of oil, around 75 percent, was consumed in the transport sector. Energy use for transport fell by one percent in 2010 compared to 2009, largely due to falls in aviation fuel resulting from disruptions due to snow and volcanoes.

Overall gas demand grew by 8.4 percent in 2010, with gas demand for electricity generation growing by 3.5 percent; gas's share of the UK's supply of electricity was 47 percent.

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Chesapeake CEO: Utica Shale Acres Worth $15B-$20B

- Chesapeake CEO: Utica Shale Acres Worth $15B-$20B

Monday, August 01, 2011
Dow Jones Newswires
HOUSTON
by Ryan Dezember

Chesapeake Chief Executive Aubrey McClendon said Friday that the company believes its acreage above the Utica Shale formation in eastern Ohio, 1.25 million acres the company has quietly pieced together over the last year and a half, is worth $15 billion to $20 billion.

"That's a big number to share but we believe we understand the hydrocarbon potential under our acreage and we also know a fair amount about how to create and extract value from a play such as this," McClendon told investors during a conference call to discuss the company's second-quarter earnings. "The Utica should emerge as a key driver in the future growth of U.S. energy supplies, especially in natural gas liquids."

Oklahoma City-based Chesapeake reported earnings of $510 million, or 68 cents a share, compared with a prior-year profit of $255 million, or 37 cents a share. Excluding mark-to-market and other impacts, adjusted earnings rose to 76 cents from 75 cents. Revenue jumped 65% to $3.32 billion on higher production and rising oil and gas prices.

Analysts surveyed by Thomson Reuters expected a per-share profit of 72 cents on revenue of $2.77 billion.

In order to contend with rising oilfield service costs and ramp up drilling in Ohio, Chesapeake said it will boost spending by $1 billion over the next two years to between $6 billion and $6.5 billion annually.

McClendon said Chesapeake, which is drilling into the Utica with five rigs, plans to add three more rigs by the end of the year and eventually have as many as 40 drilling in eastern Ohio by the end of 2014.

Chesapeake has spent between $1.5 billion and $2 billion on leasing property in eastern Ohio and continues to add parcels, McClendon said. The acreage will exceed the $15 billion to $20 billion range once more of it is developed into producing oil fields, but that is its value now as Chesapeake shops it to potential joint venture partners.

Chesapeake plans to sell a stake in the property during the fourth quarter.

The Utica, a deeply buried rock formation, lies below parts of eight states, from Tennessee to New York, as well as parts of Canada. Oil companies, however, have concentrated their leasing and exploration efforts in eastern Ohio, which they believe will yield more valuable oil and natural gas liquids.

While McClendon decline to detail the results from the 15 Utica wells it's drilled so far, he said the activity that will come there should lift an Ohio work force that has suffered for years as manufacturers flee the Rust Belt. Abundant water, needed to hydraulically fracture shale formations, easy transport by rail, highway and river, and a large base of industrial workers make the Utica more attractive and potentially more profitable than many other recent shale discoveries, McClendon said.

"We think that our activity can help rejuvenate this area and we're quite pleased with the size of the work force and the quality of the work force," he said. "This is pretty much the most ideal place in America for a new play."


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

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Range Boosts Production in 1Q 2011

Range Boosts Production in 1Q 2011

Tuesday, April 19, 2011
Range Resources Corp.

Range provided an operations update. First quarter production volumes averaged 545.5 Mmcfe net per day, a 17% increase over the prior-year period and 1% higher than fourth quarter 2010. The record production marked the Company's 33rd consecutive quarter of sequential production growth. Production was 79% natural gas, 16% natural gas liquids (NGLs) and 5% crude oil. Targeted drilling to the liquids-rich portion of the Marcellus Shale play in Pennsylvania and the Midcontinent regions drove the production growth. First quarter 2011 production was 16% NGLs versus 12% for first quarter of 2010.

The Company also announced that its preliminary first quarter 2011 commodity price realizations (including the impact of cash-settled hedges and derivative settlements which would correspond to analysts' estimates) averaged $5.46 per mcfe. This represents a 2% decrease from the prior-year period, but a 2% increase as compared to the fourth quarter 2010. Preliminary first quarter production and realized prices by each commodity are: natural gas – 429.9 Mmcfe per day ($4.40), natural gas liquids – 14,338 barrels per day ($47.96) and crude oil – 4,924 barrels per day ($81.35).

Commenting on the announcement, John Pinkerton, Range's Chairman and CEO, said, "Despite the unusually cold weather conditions we incurred in the first quarter, we were able to reach the mid-point of our production guidance. Adjusting for the weather related downtime, we would have exceeded the high end of our guidance. Our operating teams did an outstanding job battling some of the most brutal weather conditions we have experienced in many years. Looking ahead, due to the terrific drilling results so far this year, combined with the progress of the infrastructure projects, we are well on track to reach our production growth target for the year. In addition, the Barnett sale is on schedule to close at the end of the month."

Marcellus Shale Division

We exited the first quarter at approximately 260 Mmcfe per day net from the Marcellus Shale, up from approximately 200 Mmcfe per day at year-end 2010. During the first quarter, the Marcellus Division brought online 26 horizontal wells in southwest Pennsylvania, 15 of which were located in the liquids-rich area of the play. The initial production rates of the 15 new wells averaged 7.4 (6.3 net) Mmcf per day of natural gas and 452 (384 net) barrels of NGLs and condensate per day or 10.1 (8.6 net) Mmcfe per day. An additional 16 wells were completed in southwest Pennsylvania during the first quarter that are awaiting connection to the gathering system. In northeast Pennsylvania, Range brought on its first five wells in Lycoming County at a combined initial production rate of 45 (39 net) Mmcf per day in mid-February.

Due to the outstanding performance of its existing wells combined with the initial performance of the newly connected wells, Range's Marcellus production has temporarily outgrown the existing infrastructure. In southwestern Pennsylvania, the third expansion of the gas processing facilities has been completed and is in the testing phase. This 200 Mmcf per day of additional processing capacity is expected to commence operation in May. With this expansion, Range's total processing capacity will expand to 350 Mmcf per day. Later in the third quarter, Range's processing capacity is scheduled to increase again to 390 Mmcf per day. In northeast Pennsylvania, the next expansion of the Lycoming County gathering system is scheduled to be completed late in the third quarter which will tie in an additional 20 wells.

Range has entered into two memorandums of understanding exploring options to sell ethane from the liquids-rich area in southwest Pennsylvania. Range plans to complete firm ethane sales agreements in the next 12 months covering a significant portion of its projected ethane production.

Midcontinent Division

First quarter activity for the Midcontinent Division focused on drilling operations in several key areas. One rig remains active in the Texas Panhandle, where two Granite Wash wells and one vertical St. Louis exploratory well are undergoing completion. Range's original horizontal St. Louis Lime well continues to perform above expectations. After 12 weeks of production, the well has produced more than 1.0 Bcfe with current rates still at 13.0 Mmcf of natural gas and over 900 barrels of liquids per day or 18.4 (5.6 net) Mmcfe per day. Activity in the Ardmore Basin Woodford play continues with four wells in various stages of completion. Production from these liquids-rich completions is expected to reach sales by the end of the second quarter. One operated rig is currently running in the play, along with additional non-operated activity. Drilling also continues in the Mississippian Lime play of northern Oklahoma with one operated rig and one non-operated rig in the Woodford "Cana" Shale play of the Anadarko Basin.

Appalachian Division

During the first quarter of 2011, the Appalachian Division continued to focus on tight gas sand and coal bed methane (CBM) drilling projects on its 350,000 (235,000 net) acres in Virginia. All of this acreage is either owned or held by production allowing for discretionary drilling with no lease expiration issues. In 2011, Range plans 50 tight gas sand wells, 15 CBM wells and 15 horizontal wells targeting the Huron Shale, Berea and Big Lime formations in Virginia. For the first quarter, the division drilled 5 (4.5 net) vertical tight gas sand wells and one CBM well in the Nora field. Also in the quarter, Range performed 8 recompletions of behind-pipe pays to continue to maximize production on existing wells.

Southwest Division

In the first quarter the Southwest Division drilled its first Penn Shale well in the Conger Field of West Texas where Range has approximately 91,000 net acres. The well has a lateral length of 4,000 feet and will be completed with a multi-stage fracture treatment later in the second quarter.

Reef Resources to Test Flows at Ausable Well

Reef Resources to Test Flows at Ausable Well

Tuesday, April 19, 2011
Reef Resources Ltd.

Reef Resources has agreed to complete and flow test the Ausable #5 well in SW Ontario, Canada.

A decision has been made to mechanically complete the well and to conduct flow tests on the basis of the existing data. Further analysis of electric logs and cores from the wells will continue.

Following production testing; the well will be connected to the existing central production facility and placed on production as an oil and natural gas liquids (NGL) producer. The Company's objective is to have the well on production within the next four to six weeks.

Due to the presence of extensive oil and natural gas liquids pay zones in the Ausable #5 well, the Company will now begin detailed scheduling for the drilling of the Ausable #6, #7, #8 and #9 wells and the expansion of the Ausable production facility. Currently it is hoped to complete this additional work by the end of 2011.

The Company will issue additional status reports during the testing and completion of Ausable #5 and as plans for the full Enhanced Oil Recovery and Natural Gas Liquids Program (EOR) are finalized. The Ausable reef is currently on production and is generating revenue from the initial EOR program which commenced in 4th quarter 2010 through the Ausable #1 and #4 wells.

Company President, Arnie Hansen, commented, "We see this as a turning point in the development of the Ausable Reef as the results of the well fully support our geological model and demonstrate the viability of the EOR scheme. We look forward to a busy period over the remainder of the year as we plan and execute the necessary well program."

Circle Oil Briefs Operations at Al Amir Lease

Circle Oil Briefs Operations at Al Amir Lease

Monday, April 11, 2011

Circle Oil plc

Circle Oil announced an update regarding the Al Amir SE-7X water injector well located to the west of the Al Amir SE-4X well in the Al Amir Development Lease. Al Amir SE-7X, which started drilling on 27 November 2010, has been successfully sidetracked and has now reached target depth ("TD") at 15,600 ft measured depth ("MD") in the Lower Rudeis.

The main objectives for this well were to provide water injection support into the Kareem sands and to delineate the Kareem oil-water contact, which is required for technical reasons including resource estimation. The Kareem sands were encountered between 10,664 and 10,852 ft MD and these have been successfully cased off.

The Main Shagar Sands, encountered between 10,738 and 10,770 ft MD, were water bearing and of excellent reservoir quality. As a result Al Amir SE-7X should provide a good initial water injection well. The overlying sand stringers from 10,664 to 10,718 ft MD have indicated oil saturations on logs.

This places the deepest oil in Al Amir SE for the Kareem at approximately 10,200 ft Sub Surface, which positively corresponds with the latest estimates for the oil-water contact calculated using formation pressure data. Additional work is to be undertaken to refine this elevation. The well has been plugged back to 11,180 ft MD and is being completed as a water injector in the Kareem sands to support the updip oil producers. A further development well and water injection wells form the immediate drilling program for the Al Amir SE field.

The secondary objective of the well was to evaluate the Lower Rudeis thin sand stringers with indicated hydrocarbon saturations between 15,553 and 15,567 ft MD, which were previously encountered in the Al Amir SE-6X well. Log analysis by the operator identified 6 ft of pay with an average 10% porosity and a hydrocarbon saturation of 68%.

The decision was taken not to test this interval due to mechanical problems, but to conduct further drilling to properly evaluate the productivity of the Lower Rudeis sands.

In the drilling of the up-hole section of Al Amir SE-7X, sand stringers with potential hydrocarbon saturations containing 6 ft of potential pay were encountered in the South Gharib (5,634 to 5,645 ft MD) and a further 4 ft of potential pay in the Belayim (8,400 to 8,404 ft MD). These zones will be the subject of further evaluation in future drilling which will be undertaken to properly evaluate these positive occurrences for additional hydrocarbons in the NW Gemsa block.

During 2010 four successful wells were drilled and completed:

• Geyad-2X ST completed as a producer in February;
• Al Amir SE-5X completed as a producer in March;
• Al Amir SE-6X completed as a producer in July; and
• Al Ola-1X completed as a producer in December.

Further intensive exploration, appraisal and development drilling is planned over the next eighteen months. This will include drilling water injection wells to support the oil production in both the Al Amir SE and Geyad fields as required.

In addition, construction is now underway to construct facilities together with an 8-inch gas pipeline to the nearby facilities for gas export and the sale of gas and associated liquids. These facilities are expected to be completed by year end, with an associated increase in gas and liquids production.

The current production rate from the NW Gemsa fields of Geyad and Al Amir SE is approximately 7,500 bopd gross as fluid off-take from the fields is controlled in line with best reservoir management practice as the water flood is initiated, becomes operational and is proven to be effective in maximizing recovery rates. By mid 2012 the production rate is expected to rise to approximately 12,000 bopd gross as water flood operations become effective.

Gross production from start up in February 2009 through to the end of February 2011 was 4.6 MMBO. Work is currently underway on an independent third party report on ultimate recoverable resources for NW Gemsa. The results are expected during the second quarter of 2011 and will be incorporated within the Annual Report for 2010. The NW Gemsa permit, in which Circle Oil holds a 40% interest, has been a very successful venture for the Company.

The NW Gemsa concession, containing the Al-Amir and Geyad Development Leases, covering an area of over 260 square kilometers, lies about 300 kilometers southeast of Cairo in a partially unexplored area of the Gulf of Suez Basin. The concession agreement includes the right of conversion to a production license of 20 years, plus extensions, in the event of commercial discoveries.

The North West Gemsa Concession partners include: Vegas Oil and Gas (50% interest and operator); Circle Oil Plc (40% interest); and Sea Dragon Energy (10% interest).