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Press release from CNW Group

Sterling Resources announces 2012 year-end NI 51-101 reserves and resources information

Tuesday, March 26, 2013

Sterling Resources announces 2012 year-end NI 51-101 reserves and resources information17:00 EDT Tuesday, March 26, 2013CALGARY, March 26, 2013 /CNW/ - Sterling Resources Ltd. (TSXV: SLG) ("Sterling" or the "Company"), an international oil and gas company with exploration and development assets in the United Kingdom, Romania, France and the Netherlands, is pleased to announce the filing of its annual reserves disclosure pursuant to National Instrument 51-101 ("NI 51-101") and an update of the Company's Contingent and Prospective Resources, both as at December 31, 2012.The Company has increased its Proved and Proved plus Probable Reserves by 1.7 and 2.7 million barrels of oil equivalent ("MMboe") respectively, an increase of approximately 8 percent over year-end 2011.  This increase can largely be ascribed to the reclassification of Contingent Resources to Reserves for the Cladhan field, offsetting reductions in Reserves attributable to the Sheryl and Kirkleatham fields.The Company has increased P50 Contingent Resources by 3.6 MMboe, an increase of 4 percent from year-end 2011.  This increase is attributable to new properties added to the Company's portfolio in the UK and Romania and exploration success with the Eugenia-1 well offshore Romania, offsetting the reduction attributed to reclassification of the Cladhan field Contingent Resources to Reserves.The Company has increased Best Estimate Prospective Resources by 103.3 MMboe equivalent, an increase of 22 percent over year-end 2011.  This increase is due to new properties added to the Company's portfolio in the UK, the Netherlands and Romania and new prospectivity identified within the Company's previously held properties."Sterling has continued to successfully build its portfolio of assets during 2012," stated Mike Azancot, Sterling's CEO.  "We have progressed the Cladhan Resources to Reserves and added significant acreage to our holdings in the UK, Netherlands and Romania.  Year-on-year our Proved plus Probable Reserves have increased from 32.6 to 35.3 MMboe, P50 Contingent Resources have increased from 93.9 to 97.5 MMboe, and Best Estimate Prospective Resources have increased from 460.3 to 563.7 MMboe," added Mr. Azancot.Reserves and Resources Summary (Based on Forecast Prices and Costs)(1)  Company Share Gross and Net Reservesas at December 31, 2012(MMboe)(2)Net Present Value Before Tax(5)as at December 31, 2012(Millions of Canadian $) TotalProvedProvedplusProbableProved plusProbable plusPossibleTotalProvedProvedplusProbableProved plusProbable plusPossibleBreagh (3)22.630.939.96208261,001Cladhan (4) Total (6,11)25.335.345.86779581,187  Unrisked Contingent Resources (7)(9)as at December 31, 2012Company ShareUnrisked Prospective Resources (8)(10)as at December 31, 2012 Company Share  1C2C3CLowEstimateBestEstimateHighEstimate  P(90) (10)P(50) (10)P(10) (10)P(90) (10)P(50) (10)P(10) (10)GasBcf3354295222,0312,8304,004OilMMbbls2126334792193  Unrisked Unconventional ContingentResources as at December 31, 2012Company ShareUnrisked Unconventional ProspectiveResources as at December 31, 2012Company Share (12)  1C2C3CLowEstimateBestEstimateHighEstimate  P(90) (10)P(50) (10)P(10) (10)P(90) (10)P(50) (10)P(10) (10)GasBcf---3001,4497,000OilMMbbls------Notes:(1)Estimates of Reserves and Future Net Revenue have been made assuming the development of each property in respect of which the estimate is made will occur, without regard to the likely availability to the Company of funding required for that development.   (2)Gross before royalties.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.  There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. In this instance the gross values are the same as the net values because the royalty is zero.  (3)MMboes may be misleading, particularly if used in isolation.  A BOE conversion ration of 6Mcf : 1bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.   (4)Oil.    (5)Discounted at 10 percent per annum.  (6)Company Reserves totals are arithmetic aggregations of multiple estimates, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give particular attention to the estimates of individual classes of Reserves and appreciate the differing probabilities of recovery associated with each class. For Proved (1P) Reserves these totals have a higher than 90 percent probability of occurring on an unrisked basis. For Proved plus Probable plus Possible (3P) Reserves, these totals have a lower than 10 percent probability of occurring on an unrisked basis.  (7)Contingent Resources are those quantities of petroleum estimated as of a given date to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. The Resources volumes shown represent probabilistic totals of several entities within each licence or block area. There is no certainty that it will be commercially viable to produce any portion of the Contingent Resources.  (8)Prospective Resources are those quantities of petroleum estimated as of a given date to be potentially recoverable from undiscovered accumulations by application of future development projects. There is no certainty that any portion of the Prospective Resources will be discovered or, if discovered, that it will be commercially viable to produce any portion of the Resources. These Prospective Resources are in areas of the field or geological horizons, in which the presence of hydrocarbons require confirmation by drilling.  (9)Company Resources totals shown by Resource category are statistical aggregates of unrisked Resources at a company level. For Contingent Resources the statistical aggregates assume no dependencies between discoveries and for Prospective Resources these statistical totals assume no dependencies between prospects.  (10)The P(50) or 2C is considered to be the best estimate of the quantity that will actually be recovered. If probabilistic methods are used there is at least a 50 percent probability P(50) that the quantities actually recovered will equal or exceed the estimate. Similarly, the 1C or P(90) and 3C or P(10) represent the low and high estimates respectively.  (11)The estimates of Reserves and Resources for individual properties may not reflect the same confidence level as estimates of Reserves and Resources for all properties, due to the effects of aggregation.  (12)Unconventional Prospective Resources are based on the RPS assessment of Silurian Wenlockian shale gas potential in the Sud Craiova licence in Romania.  RPS calculates the potential based on mapping of the extent of the Wenlockian shale, geochemical analysis of outcrop shale samples, a well test on licence that produced gas from the shale and comparison with the analogous Haynesville Shale gas reservoirs in the U.S.A. The volumes cited here are unrisked.  RPS assigns a geological probability of success of 5 percent to the prospect.Operational ReviewReserves The following details those events which have impacted the determination of the Company's 2012 year-end Reserves:BreaghIn the United Kingdom Sterling continued to advance the Breagh development in the North Sea. On May 14, 2012 the Company announced that development drilling operations commenced at Breagh in the UK Southern North Sea. The Ensco 70 rig was deployed to start the Breagh development drilling program. During 2012, three wells A01 (redrill of the suspended 42/13-3), A02 (redrill of the 42/13-5Z), and A03 wells were drilled.On December 12, 2012 the Company announced the results of production testing from these initial three wells completed as part of the on-going Breagh development.  In summary, all well results fall within the range of expected outcomes from the reservoir simulation model. Once normalized to reflect the expected sales level of wellhead pressure, the current three well capacity is estimated at 88 million standard cubic feet per day ("MMscfd") which is in line with the general assumption contained in the Field Development Program (FDP ). The A03 well is the largest producer to date with an initial rate capacity expected to be approximately 58 MMscfd; and the A01 and A02 wells are expected to produce initially at approximately 14 and 18 MMscfd respectively, at platform export pressures of 1150 psig. Well flow test results are not necessarily indicative of long-term performance or ultimate recovery.  More extensive flow performance will be conducted on each well once full production begins.Subsequently, the fourth development well (A04) has been drilled and completed and drilling of the fifth development well (A05) has commenced.  Production testing of both of these wells is anticipated to occur at the beginning of May, after drilling and completing the A05 well.The Breagh Alpha platform was installed in October 2011 and is fully commissioned. The offshore pipeline was fully installed during 2012 and the onshore pipeline has been completed.  Commissioning of the pipeline is expected to be performed during April 2013 by pressure testing, de-watering and "gassing-up" the offshore and onshore elements of the pipeline. Modifications to the Teesside Gas Processing Plant are ongoing.  All pipework has been fully installed and work continues on cold/hot loop testing and commissioning continues on the plant.CladhanOn April 20, 2012, the Company announced the divestment of an interest in the Cladhan field.  The Company signed a sale and purchase agreement with TAQA Bratani Limited ("TAQA") for the sale of a 13.5 percent interest in the North Cladhan area (Blocks 210/29a and 210/30a) for an initial consideration of US$47 million including an allocation to tax allowances. The Company's equity position following the transaction was 26.4 percent.The initial consideration was satisfied in three instalments: US$22.3 million was paid at completion, US$4.3 million was paid early in 2013 following the achievement of certain milestones and the balance as a carry of part of Sterling's development expenditure in respect of Cladhan up to a maximum carry amount, adjusted for tax, of US$53.6 Million. Subsequently the Company has agreed with TAQA to apply the US$53.6 million carry element additionally against pre-sanction long lead items of the development (subsea tie-in and linepipe) and front-end engineering and design for the pipeline and host platform modifications.The Company announced on March 5, 2013 that the FDP for the field had been submitted to the Department of Energy and Climate Change ("DECC") by the Operator, and the partnership now expects to gain approval for the FDP by the end of the April 2013. With the submission of the FDP for a three well development of the field and significant progress of a transportation, processing and operating services agreement and construction tie-in agreement to develop the accumulation as a subsea tie-back to the Tern platform, RPS Energy has reclassified 2011 year-end Contingent Resources to Proved, Probable and Possible reserves.Kirkleatham and SherylIn April of 2011, development of the Kirkleatham field in northeast England, in which Sterling holds a 47 percent interest, was completed.  First gas production was achieved on April 19, 2011.  Since then the well has produced increasing amounts of water and has subsequently been shut-in.  Previously considered Reserves in the field have been reclassified as Contingent Resources. In November 2012, the P1220 licence containing the Sheryl Oil discovery was relinquished and Proved and Probable and Proved, Probable and Possible Reserves have been removed from the Company's asset base.Resources The following details those events which have impacted the determination of the Company's 2012 year-end Resources:On January 12, 2012 the Company announced that it had been successful in the final portion of the UK 26th Offshore Licensing Round awards, and was being awarded five additional blocks covered by three licences:The first licence (Sterling 100 percent - Operator) contains portions of Blocks 43/15a and 43/20a and the main exploration play is an Intra-Carboniferous structure which is partially covered by 3D seismic. The prospect lies just to the northeast of the Cavendish gas field and the Keplar gas discovery. Target formations are the Carboniferous Westphalian and Namurian formations which are present at Cavendish.The second licence (Sterling 100 percent - Operator) contains portions of Blocks 49/18b and 49/19b which holds an undeveloped gas discovery and an additional prospect and further leads with the target horizon being the Rotliegend Leman sandstone. The discovery lies to the north of the Indefatigable field and the other prospect and leads are to the north of the Brigantine complex. The Leman sandstone is of high quality and the old discovery well (drilled in 1995) tested in excess of 40 MMscfd.Sterling had also been successful in its application for a licence in the Central North Sea, covering Block 16/3d which contains part of the Cairngorm discovery. This application was originally made by Stratic Energy Corporation (now Enquest PLC) and Sterling on a 50 / 50 basis.  Subsequently (May 2012), Sterling's 50 percent interest in the licence was swapped for Enquest's 10 percent  interest in the F and L Quad blocks in the NetherlandsOn February 7, 2012 the Company announced completion and preliminary results of the F17-09 well in Block F17a of the Dutch North Sea. After reaching a depth of 2,200 metres, the well encountered a 10 metre gross oil interval (6 metre net oil interval), through interbedded sands with porosities averaging 24 percent.On March 5, 2012 the Company announced that its wholly-owned subsidiary in the Netherlands had been awarded a 30 percent interest in the exploration licences E03 and F01 in the Dutch North Sea jointly with Wintershall, who is operator with 30 percent and EBN holding the remaining 40 percent.On March 22, 2012 the Company announced that its wholly owned subsidiary in Romania had obtained approval from the National Agency for Mineral Resources ("NAMR") for a 40 percent interest in the 1,000 square kilometre Romanian Black Sea concession Block 27 (Muridava). The shallow water block, adjacent to Sterling's Pelican Block, contains multiple exploration plays, has existing 2D seismic coverage and contains an existing hydrocarbon discovery, Olimpiyskaya, which was drilled in 2001. This well has limited historical data. The Concession Agreement has an initial three-year exploration period.  Block 27 was one of a number of 10th Round offshore concessions awarded in June 2010 and was ratified by the government in October 2011.On July 13, 2012 the Company announced that its wholly-owned subsidiary in Romania had obtained approval from NAMR for an interest in the 1,000 square kilometre Romanian Black Sea concession Block 25 (Luceafarul).  The Company's subsidiary in Romania will obtain a 50 percent interest and will be operator.  The current concession holder Petro Ventures Europe BV will then hold the remaining 50 percent interest. This shallow water block west of and adjacent to Sterling's Midia Block, contains an existing gas discovery and multiple exploration plays, has existing 2D seismic coverage and has been assessed by independent reserves evaluator RPS Energy at the time of acquisition. The Concession Agreement has an initial three-year exploration period. Seismic work is currently progressing through the permitting process. Block 25 was one of a number of 10th Round offshore concessions awarded in June 2010 and subsequently ratified by the government in October 2011.On October 19, 2012 the Company announced that it had signed a sale and purchase agreement with ExxonMobil Exploration and Production Romania ("EMEPR") and OMV Petrom for the sale of its 65 percent interest in a portion of the Block 15 Midia in the Romanian Black Sea (the "Sale Portion").The Sale Portion is on the southeastern margin of the block, in deeper waters and covers 125,000 gross acres, or 11 percent of the total area of the Midia and Pelican Concession.  It contains the newly-determined Anca and Maria prospects and is adjacent to EMEPR's and OMV Petrom's deep water Neptun block containing the Domino-1 gas discovery well some 35 kilometres to the southeast.On November 7, 2012 the Company announced the results of the exploration well on the Ioana prospect in Block 15 Midia in the Romanian Black Sea.  The well was drilled to a total depth of 1,950 metres measured depth ("MD"), 1,513 metres true vertical depth subsea ("TVDSS").  Gas shows from drilling mud gas measurements were experienced from a depth of 500 MD down to total depth of 1,950 metres MD.On December 14, 2012 the Company announced a gas discovery following the drilling of the Eugenia-1 well drilled in the Black Sea offshore Romania. The well reached a total depth of 2,276 metres (2,248 metres subsea). The preliminary log analysis indicates a total of 22 metres of gas-bearing Late Cretaceous sandstones, mainly within two intervals.  Average porosity ranges from 10 to 20 percent and average gas saturations range from 55 to 62 percent.  The sandstone units are located within the interval 1,938 to 2,038 metres MD. Formation pressure data and recovered gas samples from open-hole logging tools confirm moveable gas. Further detailed analysis of logs, pressure data and samples is ongoing. In addition to these Late Cretaceous sandstones, a further 20 metre zone of interest is evident within an Eocene limestone section from 1,900 to 1,938 metres. The interval was drilled with gas shows but attempts to collect pressure data were unsuccessful although this is not an uncommon occurrence in carbonates where matrix porosity is limited. Log analysis will be undertaken to determine if the Eocene limestone could be gas bearing and producible as was the case in the adjacent Olimpiyskaya well. The well also encountered 100 metres of good quality sandstones in a shallower objective in the Oligocene formation. Although drilled at a downdip location to enable drilling of the deeper Eocene and Late Cretaceous main objectives, the interval remains an interesting prospect updip of the current well.The Company's hydrocarbon reserves and resources were independently evaluated by RPS Energy effective December 31, 2012 in accordance with the Canadian Oil and Gas Evaluation Handbook ("COGEH") reserves definitions and evaluation practices and procedures, as specified by NI 51-101. There is no certainty that it will be commercially viable to produce any portion of the Reserves.  The evaluation uses the RPS Energy forecast prices and costs as at December 31, 2012.  Complete details regarding Sterling's reserves and resources for the year ended December 31, 2012 and in a format specified by NI 51-101 can be found on SEDAR at or on the Company's website www.sterling-resources.comNeither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.Filer Profile No. 00002072Forward-Looking StatementsAll statements included in this press release that address activities, events or developments that Sterling expects, believes or anticipates will or may occur in the future are forward-looking statements. In addition, statements relating to reserves or resources are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves and resources described can be profitably produced in the future.These forward-looking statements involve numerous assumptions made by Sterling based on its experience, perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate in the circumstances.  In addition, these statements involve substantial known and unknown risks and uncertainties that contribute to the possibility that the predictions, forecasts, projections and other-forward looking statements will prove inaccurate, certain of which are beyond Sterling's control, including: the impact of general economic conditions in the areas in which Sterling operates, civil unrest, industry conditions, changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced, increased competition, the lack of availability of qualified personnel or management, fluctuations in commodity prices, foreign exchange or interest rates, stock market volatility and obtaining required approvals of regulatory authorities. In addition there are risks and uncertainties associated with oil and gas operations.  Readers should also carefully consider the matters discussed under the heading "Risk Factors" in the Company's Annual Information Form.Undue reliance should not be placed on these forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur.  Sterling's actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking statements.  These statements speak only as of the date of the press release. Sterling does not intend and does not assume any obligation to update these forward-looking statements except as required by law.Financial outlook information contained in this press release about prospective results of operations, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management's assessment of the relevant information currently available.  Readers are cautioned that such financial outlook information contained in this press release should not be used for purpose other than for which it is disclosed herein.SOURCE: Sterling Resources Ltd.For further information: For further information: visit or contact: Mike Azancot, President and Chief Executive Officer, Phone: 44-20-3008-8488, Mobile: 44-7740-432883, David Blewden, Chief Financial Officer, Phone: 44-20-3008-8488, Mobile: 44-7771-740804, George Kesteven, Manager, Corporate and Investor Relations, Phone: (403) 215-9265, Mobile: (403) 519-3912,