Southern Pacific Increases its STP-McKay 2P Reserves by 30% and Net Present Value by 55% to $1.7 Billion
CALGARY, ALBERTA -- (Marketwire) -- 01/04/12 -- Southern Pacific Resource Corp. ('Southern Pacific' or the 'Company') (TSX: STP) is pleased to announce that it has increased its proved plus probable (2P) reserves by 30% to 234 million barrels of bitumen and the 2P net present value (discounted at 10%) of these reserves by $0.6 billion to $1.7 billion. The increases are a result of the filing of the STP-McKay Phase 2 expansion application on November 10, 2011. The filing of this application permitted GLJ Petroleum Consultants Ltd., the Company's independent reserves evaluator, to prepare Proven plus Probable production forecasts using the combined Phase 1 and Phase 2 design capacity of 36,000 bbl/d. Phase 1 of Southern Pacific's STP-McKay Thermal Project, a 12,000 bbl/d steam assisted gravity drainage ('SAGD') project located 45 km northwest of Fort McMurray, was approved in October 2010 and is in the final stages of construction.
Prior to filing the Phase 2 application, all reserves were required to be forecast using only the approved Phase 1 capacity of 12,000 bbl/d. The expanded capacity from Phase 2 allowed not only an acceleration of the previously booked reserves, but also made room for an additional 53 MMbbl of previously allocated best estimate contingent resources to be reassigned to the Probable category.
'This report confirms the significant value in our assets at McKay,' said Byron Lutes, President and CEO. 'Our goal is to unlock the potential in order to turn this reserve value into cash flow as quickly as possible. We are excited to be one of the only SAGD projects expected to commence production in 2012.'
In addition to McKay, Southern Pacific had its STP-Senlac project reserves mechanically updated, using the same price forecast and effective date of November 30, 2011. The following table summarizes the entire Company's latest reserves and contingent resource estimates.
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Working
Interest Net Present Value (before tax- WI)
Recoverable (Cdn $ million)
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(MMBOE) 8% 10% 12%
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Reserves
Total Proved (1P) 120.2 $ 1,006 $ 844 $ 723
Proved + Probable Reserves
(2P) 234.0 $ 2,107 $ 1,721 $ 1,416
Proved + Probable + Possible
(3P) 307.4 $ 2,825 $ 2,274 $ 1,852
Contingent Resources
Low Estimate (P90)
Contingent Resource 260.4 $ 670 $ 347 $ 116
Best Estimate (P50)
Contingent Resource 621.8 $ 2,095 $ 1,242 $ 680
High Estimate (P10)
Contingent Resource 1230.1 $ 5,586 $ 3,667 $ 2,373
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(Reserves effective November 30, 2011. Contingent resources at McKay updated effective November 30, 2011. Contingent resources on other lands reflect GLJ's June 30, 2011 report, with the exception of Red Earth, which was completed by Sproule & Associates effective December 31, 2009. Please refer to Southern Pacific's Annual Information Form for further details on contingent resources.)
STP-McKay Phase 1 Operational Update
Work continues on schedule and on budget for the construction of Phase 1 of the STP-McKay Thermal Project. Costs incurred to December 31, 2011 total approximately $366 million of the total forecasted budget of $440 million. Several major milestones have been completed on the project including:
-- Major cogeneration components delivered and installed
-- Major boiler components delivered and installed
-- 95% of piling and foundation work completed
-- Drilling and completion of the initial 12 SAGD well pairs completed
-- 80% of the water treatment and boiler facilities delivered and installed
-- 80% of piperack modules delivered and installed
-- All nine 10,000 bbl tanks erected
-- Completion of the 84 person operations camp and field office
Over the past six months, Southern Pacific has assembled the operations team that will run the project. The total staff complement is expected to be 46 people. The Company is on track with its hiring program, having hired 67% of the operations staff to date. Most of the operations team, including all of the management, have extensive experience in SAGD operations, including involvement in four separate SAGD facility start-ups. At the beginning of January, all of the operations staff relocated from their temporary office in Calgary to the new operations facilities on site. From there, they will continue to develop all necessary start up and operating procedures to ensure a smooth transition from construction to operation.
The Company's target for first steam remains within the second quarter of calendar 2012. The timing will be tightened up as the remaining modules arrive on site. First oil production is expected to occur three to four months from first steam.
Senlac Operational Update
Phase J, consisting of three SAGD well pairs, has been drilled, completed and tied-in at the STP-Senlac Thermal Project. Circulation steam on the first well pair commenced in mid December, and first oil arrived in late December. It is expected that only two well pairs will be required to fill the plant back to its design capacity of 5,000 bbl/d. The third will be brought on at a later date, when required. The Company is expecting a strong first quarter of calendar 2012 based on a production ramp up from Phase J and a favourable pricing environment.
Red Earth Update
Southern Pacific continues to explore the potential of its STP-Red Earth Thermal Project in the Peace River oil sands. Testing on the 1,000 bbl/d pilot project occurred over the last half of 2011 on three existing wellbores drilled prior to Southern Pacific taking ownership. Southern Pacific used these existing wellbores to test three different configurations of Cyclic Steam Stimulation (CSS). The purpose of the tests was to gain relatively low-cost knowledge on the reservoir performance under different CSS scenarios. One cycle of steam was injected into all three wellbores and each of the wells was then placed on production. The results were mixed. After running integrity and inspection tests on the wells, Southern Pacific determined that all three wells suffered from poor cement bonds on the intermediate casing strings. It was further determined that the wells were not drilled using industry standard thermal drilling practices. This meant isolation and placement of steam, followed by recovery of production from only the zone of interest (the Bluesky), will be difficult, if not impossible from these wells.
This was the first test on the pilot project since Southern Pacific acquired the asset in late 2010 for $14 million. The above ground facilities ran well. The well that had the best cement integrity generated a cumulative steam oil ratio of 4.4 on its first steam cycle. This is encouraging for a CSS project, especially given the identified cement bond issues. In total, Southern Pacific produced approximately 3,800 bbl of oil from the three wellbores over the 4.5 month period (not all wells were producing over this entire period) which indicates that the bitumen within this project mobilizes readily with steam. Based on the information gathered to date, the Company continues to believe the reservoir has the potential to deliver commercial production rates. Southern Pacific's technical team is reviewing the results and will be making recommendations to further test the Red Earth project in 2012. This will most likely involve plans to drill new CSS wells utilizing improved thermal drilling practices and continue to use the existing facilities to generate steam and process oil. Independent estimates of 2.1 billion barrels of discovered bitumen resources on the Company's Red Earth acreage make this a project well worth pursuing.
About Southern Pacific
Southern Pacific Resource Corp. is engaged in the exploration, development and production of in-situ thermal heavy oil and bitumen production in the Athabasca oil sands of Alberta and in Senlac, Saskatchewan. Southern Pacific trades on the TSX under the symbol 'STP.'
Advisory
This news release contains certain 'forward-looking information' within the meaning of such statements under applicable securities law including estimates as to: future production, operations, operating costs, commodity prices, administrative costs, commodity price risk management activity, acquisitions and dispositions, capital spending, access to credit facilities, income and oil taxes, regulatory changes, and other components of cash flow and earnings anticipated discovery of commercial volumes of bitumen, the timeline for the achievement of anticipated exploration, anticipated results from the current drilling program and, subject to regulatory approval and commercial factors, the commencement or approval of any SAGD project. Specific risk factors related to STP-McKay Phase 2 include, but are not limited to, the timeline for completion of the DBM, approval of the application, the expected increase in the P+P reserves and net present value, development plans and the anticipated geological characteristics. Risk factors related to STP-McKay Phase 1 include the expected date of first steam.
Forward-looking information is frequently characterized by words such as 'plan', 'expect', 'project', 'intend', 'believe', 'anticipate', 'estimate', 'may', 'will', 'potential', 'proposed' and other similar words, or statements that certain events or conditions 'may' or 'will' occur. These statements are only predictions. Forward-looking information is based on the opinions and estimates of management at the date the statements are made, and are subject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially from those projected in the forward-looking statements. These factors include, but are not limited to the inherent risks involved in the exploration and development of conventional oil and gas properties and of oil sands properties, difficulties or delays in start-up operations, the uncertainties involved in interpreting drilling results and other geological data, fluctuating oil prices, the possibility of unanticipated costs and expenses, uncertainties relating to the availability and costs of financing needed in the future and other factors including unforeseen delays. As an oil sands enterprise in the development stage, with some conventional production Southern Pacific faces risks including those associated with exploration, development, start-up, approvals and the continuing ability to access sufficient capital from external sources if required. Actual timelines associated may vary from those anticipated in this news release and such variations may be material. Industry related risks could include, but are not limited to, operational risks in exploration, development and production, delays or changes in plans, risks associated to the uncertainty of reserve estimates, health and safety risks and the uncertainty of estimates and projections of production, costs and expenses. For a description of the risks and uncertainties facing Southern Pacific and its business and affairs, readers should refer to Southern Pacific's most recent Annual Information Form. Southern Pacific undertakes no obligation to update forward-looking statements if circumstances or management's estimates or opinions should change, unless required by law.
The reader is cautioned not to place undue reliance on this forward-looking information.
Definitions
'Contingent Resources' means 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. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage.
'High (P10)' means an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high estimate.
'Best (P50)' means the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
'Low (P90)' means a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
'Probable reserves' means those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved plus Probable reserves.
'Possible reserves' means those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated Proved plus Probable plus Possible reserves.
'Proved reserves' means those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated Proved reserves.
'Discovered Bitumen Initially-In-Place' (equivalent to Discovered Bitumen Resources) is that quantity of bitumen that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of Discovered Bitumen Initially-In-Place includes production, reserves, and contingent resources; the remainder is unrecoverable.
'Barrel of Oil Equivalent' Where amounts are expressed on a barrel of oil equivalent ('BOE') basis, natural gas volumes have been converted to BOE at a ratio of 6,000 cubic feet of natural gas to one barrel of oil equivalent. This conversion ratio is based upon an energy equivalent conversion method primarily applicable at the burner tip and does not represent value equivalence at the wellhead. BOE figures may be misleading, particularly if used in isolation.
Safe Harbour
Contingent Resources
This press release contains estimates of contingent resources. There are numerous uncertainties inherent in estimating quantities of Contingent Resources and future net revenues to be derived therefrom, including factors beyond the Company's control. The reserves, resources and estimated future net cash flow from the Company's properties have been independently evaluated by GLJ except as otherwise noted. These evaluations include a number of assumptions relating to factors such as initial production rates, production decline rates, ultimate recovery of reserves and resources, timing and amount of capital expenditures, marketability of production, future prices of blended bitumen, crude oil and natural gas, operating costs, well abandonment and salvage values, royalties and other government levies that may be imposed over the producing life of the reserves and resources. These assumptions were based on prices in use at the date the relevant evaluations were prepared, and many of these assumptions are subject to change and are beyond the Company's control. Actual production and cash flow derived therefrom will vary from these evaluations, and such variations could be material. Estimates with respect to reserves and resources that may be developed and produced in the future are often based upon volumetric calculations, probabilistic methods and upon analogy to similar types of reserves and resources, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be material, in the estimated reserves or resources.
Reserve and resource estimates may require revision based on actual production experience. Such figures have been determined based upon assumed commodity prices and operating costs. Market price fluctuations of crude oil and natural gas prices may render uneconomic the recovery of certain grades of bitumen. The present value of estimated future net revenue referred to herein should not be construed as the fair market value of estimated bitumen, crude oil and natural gas reserves and bitumen resources attributable to the Company's properties. The estimated discounted future revenue from reserves are based upon price and cost estimates which may vary from actual prices and costs and such variance could be material. Actual future net revenue will also be affected by factors such as the amount and timing of actual production, supply and demand for bitumen, crude oil and natural gas, curtailments or increases in consumption by purchasers and changes in governmental regulations or taxation.
References to Contingent Resources do not constitute, and should be distinguished from, references to reserves. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. 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. Not all technically feasible development plans will be commercial. The commercial viability of a development project is dependent on the forecast of fiscal conditions over the life of the project. For Contingent Resources the risk component relating to the likelihood that an accumulation will be commercially developed is referred to as the 'chance of development.' Not all exploration projects will result in discoveries. The chance that an exploration project will result in the discovery of petroleum is referred to as the 'chance of discovery.' Thus, for an undiscovered accumulation the chance of commerciality is the product of two risk components - the chance of discovery and the chance of development.
Contacts:
Southern Pacific Resource Corp.
Byron Lutes
President & CEO
403-269-1529
blutes@shpacific.com
Southern Pacific Resource Corp.
Howard Bolinger
CFO
403-269-2640
hbolinger@shpacific.com
www.shpacific.com