Southern Pacific Provides May Operational Update: Successful High Pressure Steam Stimulation Test at STP-McKay

CALGARY, ALBERTA–(Marketwired – June 13, 2013) – Southern Pacific Resource Corp. (“Southern Pacific” or the “Company”) (TSX:STP) today provided an operational update for the month of May, 2013 with respect to the Company’s STP-McKay and STP-Senlac Thermal Projects.

STP-McKay Thermal Project – High Pressure Steam Stimulation (“HPSS”)

During the month of May, the Company focused its operations on the successful implementation and completion of a High Pressure Steam Stimulation (“HPSS”) test on one of the existing 12 steam-assisted gravity drainage (“SAGD”) well pairs at STP-McKay.

As previously stated, production ramp up at STP-McKay has been slower than anticipated, largely a result of delays establishing sufficient horizontal communication between injector and producer on some of the well pairs. After analyzing the production data over the past seven months, the Company believes that the conformance delay is occurring due to several factors including sand grain sorting, higher bitumen saturation levels, lower operating pressures and wider well pair configuration (Pad 1 was drilled with a wider average separation between the injector and producer in order to capture underlying oil which would otherwise have been stranded). The Company’s reservoir modeling identified the HPSS as a low cost procedure that would accelerate horizontal communication between the two wellbores by geo-mechanically expanding and re-aligning the sand matrix to promote improved communication pathways, thus reducing the time required to enhance the well pair’s horizontal conformance.

The Company submitted an application to the Energy Resources Conservation Board (“ERCB”) in March, 2013 to conduct a HPSS test and it received approval to proceed in late April. The approval of the test allowed Southern Pacific to inject a finite volume of steam at a pressure that exceeds the current maximum operating pressure of the project. A few weeks of test preparation in the field were required, which included shutting in the test well pair and the offset well pair to stabilize and monitor pressures, and calibrate the surrounding observation wells. The test commenced on May 21^st and was completed on May 29^th. The HPSS was performed on the well pair 1P1, the furthest to the east of the existing 12 well pairs. This well pair was chosen as it has been one of the well pairs which to date had not demonstrated significant communication between the injector and producer well bores. In addition, this well is located underneath an existing horizontal observation well drilled into the upper Wabiskaw zone, which was used to monitor and verify pressure impacts to the overlying caprock. Following the HPSS, the well pair was allowed to de-pressure and cool, and subsequently placed on SAGD production on June 4^th. While the results of the test are still being evaluated, initial results are very encouraging, as evidenced by the following:

• The well pair has been operating in steady SAGD mode since June 4th; this well pair had never operated in steady SAGD mode prior to the stimulation. The rate has been steadily improving to a current fluid rate of approximately 750 barrels per day (“bbl/d”) with a 25% oil cut. The oil cut continues to improve as the stimulation fluid (steam condensed to water) is recovered;
• A significant improvement in horizontal communication along the length of the injector and producer wellbores was established during the HPSS;
• There were no pressure or temperature disturbances measured above the well pair from the overlying horizontal Wabiskaw well, nor laterally from the offset vertical observation wells; and
• The test planning, protocol, execution and monitoring were conducted in a manner that was safe, protected the wellbore integrity and provided the information necessary to repeat this process on other well pairs at negligible cost.

Now that SAGD operation has been established, the well pair’s steam chamber should continue to develop, with an expected increase to continue in oil productivity as the chamber grows both horizontally and vertically. As a result of 1P1’s proximity to the overlying Wabiskaw horizontal well, the successful testing of this well pair has allowed the Company to obtain valuable data demonstrating no noticeable pressure increases in the overlying caprock. A meeting with the ERCB discussing the test process and preliminary results has recently occurred and a follow-up application has been filed with the ERCB to perform similar HPSS’s on the remaining five wells on Pad 101. The Company expects to conduct these over the summer. The Company is also currently evaluating the potential to perform HPSS’s on some of the well pairs on Pad 102.

STP-McKay Thermal Project – Production

Production remained relatively steady for the month of May, averaging 1,024 bbl/d despite two of the well pairs being shut-in during most of the month in order to prepare for the HPSS. Over 87% of May’s production came from five of the SAGD well pairs. These five well pairs have settled into steady state operations with optimal subcool and operating pressures having been achieved in late April. The farthest well pair to the west, 2P6, was also converted to SAGD production on May 27^th and has been running steadily since. This well pair had previously been in circulation and had never operated successfully in SAGD mode prior to this attempt. The Company now has all 12 of its well pairs capable of SAGD, although two of the well pairs are periodically returned to circulation as a measure to improve conformance.

STP-Senlac Thermal Project

Senlac production averaged 3,127 bbl/d for the month of May. This represents a 10% increase over the average rate in April. Two new SAGD well pairs from Phase K continue to ramp up and the third well pair continues to circulate steam and prepare for SAGD mode, which should occur in late June.

Total Corporate Production

Total Company production including the capitalized production from STP-McKay phase 1 and STP-Senlac averaged 4,151 bbl/d for the month ended May, 2013, which is an 7% increase from the previous month. As production continues to ramp-up, the Company will continue to provide monthly operational updates to its shareholders.

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.” An updated corporate presentation is now available on Southern Pacific’s website at www.shpacific.com.

Visit our website at: www.shpacific.com.

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 and lending costs, 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.

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 oil and gas properties and of oil sands properties, delays in ramp-up operations, the uncertainties involved in interpreting drilling results and other geological data, fluctuating oil prices and discounts, 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, Southern Pacific faces risks including those associated with exploration, development, ramp-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

“Barrels of oil equivalent” (boe) maybe misleading, particularly if used in isolation. A boe conversion of 6 mcf to 1 barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.