Petrobank Records Second Quarter Net Income of $34.7 Million

CALGARY, ALBERTA--(Marketwire - Aug. 13, 2009) - Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") PBG is pleased to announce our second quarter 2009 financial and operating results, highlighted by production of 41,127 barrels of oil equivalent per day ("boepd"), funds flow from operations of $150.4 million ($1.64 per diluted share), and net income of $34.7 million ($0.40 per diluted share). (All references to $ are Canadian dollars unless otherwise noted.) HIGHLIGHTS (Comparisons are second quarter of 2009 compared to the second quarter of 2008.) - Petrobank's production increased by 72% to 41,127 boepd in the second quarter of 2009. - Canadian Business Unit ("CBU") production increased 19% to 19,579 boepd. - Latin American Business Unit ("LABU") production increased 194% to 21,548 barrels of oil per day ("bopd"). - Our Heavy Oil Business Unit ("HBU") produced 205 bopd in the second quarter and commenced drilling at our Kerrobert Project in July. - Despite a sharp 52% drop in world oil prices, funds flow from operations only decreased by 15% to $150.4 million ($1.64 per diluted share). - Petrobank achieved net income of $34.7 million ($0.40 per diluted share) in the second quarter compared to net income of $57.6 million ($0.64 per diluted share) in the same 2008 period. - CBU production expenses decreased by 27% to $6.52/boe and LABU production expenses decreased by 28% to $7.86/bbl. - CBU operating netbacks averaged $42.72/boe excluding hedging gains of $3.46/boe and LABU operating netbacks averaged $42.88/bbl in the second quarter. - On July 10, 2009, Petrobank issued US$400 million of convertible debentures. - On August 4, 2009, Petrobank and TriStar Oil and Gas Ltd. ("TriStar") entered into an arrangement that will create a new publicly listed company, PetroBakken Energy Ltd. ("PetroBakken"). /T/ FINANCIAL & OPERATING HIGHLIGHTS Three months ended Six months ended June 30, June 30, % ch- % ch- 2009 2008 ange 2009 2008 ange ---------------------------------------------------------------------------- Financial ($000s, except where noted) Oil and natural gas revenue 224,396 247,479 (9) 415,182 426,770 (3) Funds flow from operations (1) 150,350 177,923 (15) 275,506 301,411 (9) Per share - basic ($) 1.78 2.16 (18) 3.28 3.69 (11) - diluted ($) 1.64 1.92 (15) 3.03 3.28 (8) Net income 34,667 57,636 (40) 33,125 93,173 (64) Per share - basic ($) 0.41 0.70 (41) 0.39 1.14 (66) - diluted ($) 0.40 0.64 (38) 0.39 1.04 (63) Capital expenditures 144,422 172,356 (16) 317,416 372,626 (15) CBU 38,901 69,711 (44) 108,925 180,200 (40) LABU 93,203 80,637 16 174,763 149,383 17 HBU 12,318 22,008 (44) 33,728 43,043 (22) Total assets 2,421,171 1,826,464 33 2,421,171 1,826,464 33 Net debt (1) 383,678 176,302 118 383,678 176,302 118 Common shares outstanding, end of period (000s) Basic 92,267 82,668 12 92,267 82,668 12 Diluted (2) 99,270 98,023 1 99,270 98,023 1 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Operations CBU operating netback ($/boe except where noted) (1) (3) Oil and NGL revenue ($/bbl) (4) 62.22 117.64 (47) 54.88 106.19 (48) Natural gas revenue ($/mcf) (4) 3.91 9.83 (60) 4.56 8.73 (48) Oil, NGL and natural gas revenue (4) 56.64 109.43 (48) 51.45 97.61 (47) Royalties 7.40 11.70 (37) 6.30 9.43 (33) Production expenses 6.52 8.88 (27) 6.67 9.10 (27) ---------------------------------------------------------------------------- Operating netback (5) 42.72 88.85 (52) 38.48 79.08 (51) LABU operating netback ($/bbl) (1) Oil revenue (4) 55.76 115.77 (52) 49.01 99.96 (51) Royalties 5.02 11.11 (55) 4.81 9.56 (50) Production expenses 7.86 10.86 (28) 7.63 10.86 (30) ---------------------------------------------------------------------------- Operating netback (5) 42.88 93.80 (54) 36.56 79.54 (54) Average daily production (3) CBU - oil and NGL (bbls) 16,761 14,205 18 18,233 12,778 43 CBU - natural gas (mcf) 16,906 13,871 22 15,550 14,550 7 ---------------------------------------------------------------------------- Total CBU (boe) 19,579 16,517 19 20,825 15,203 37 LABU - oil (bbls) (6) 21,548 7,339 194 21,659 7,987 171 ---------------------------------------------------------------------------- Total Company conventional (boe) 41,127 23,856 72 42,484 23,190 83 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Non-GAAP measure. See "Non-GAAP Measures" herein. (2) Assumes 0.2 million shares will be issued upon conversion of the Company's remaining 3% convertible debentures. (3) Six mcf of natural gas is equivalent to one barrel of oil equivalent ("boe"). HBU bitumen volumes are excluded from average daily production as Whitesands operations are considered to be in the pre-operating stage and accordingly are capitalized. (4) Net of transportation expenses. (5) Excludes hedging activities. In the second quarter of 2009, the CBU realized gains of $3.46/boe (2008 - realized loss of $2.98/boe) and no gain or loss was recognized by the LABU (2008 - realized loss of $6.38/bbl). In the first six months of 2009, the CBU realized gains of $4.44/boe (2008 - realized loss of $2.19/boe) and no gain or loss was recognized by the LABU (2008 - realized loss of $4.21/bbl). (6) Actual production sold for the three and six months ended June 30, 2009 was 21,390 bopd and 21,399 bopd, respectively (2008 - 7,339 bopd and 7,987 bopd). /T/ OPERATIONAL REVIEW Petrobank reported strong funds flow from operations of $150.4 million, or $1.64 per diluted share, in the second quarter of 2009 as year over year sales volumes increased by 72% to 41,127 boepd. Funds flow from operations decreased by 15% from the prior year, primarily due to a 52% decrease in world oil prices. CBU infrastructure investments in 2008 helped reduce operating expenses to $6.52/boe in the second quarter, preserving strong operating netbacks of $42.72/boe, excluding hedging gains of $3.46/boe. Similarly in Colombia, continued improvements in production operations resulted in operating expenses decreasing to $7.86/bbl, leading to operating netbacks of $42.88/bbl. PETROBAKKEN On August 4, 2009, Petrobank and TriStar agreed to a strategic combination of TriStar and Petrobank's CBU. The combination will create a new publicly listed company, PetroBakken, that will be a premier, Bakken-focused, light oil exploration and production company. Petrobank will capitalize PetroBakken with its CBU assets and $400 million of cash. PetroBakken will then acquire all the outstanding shares of TriStar. In return, Petrobank will receive 109.8 million shares of PetroBakken which will represent approximately 64% of PetroBakken's anticipated shares outstanding. The transaction will be completed by way of plan of arrangement (the "Arrangement") and is subject to TriStar shareholder approval. The information circular for the Arrangement is expected to be mailed to TriStar shareholders on or about August 31, 2009 and it is anticipated that the special meeting of TriStar's shareholders will be held on or about September 30, 2009, with closing of the transaction to occur on or about October 1, 2009. The successful completion of the transaction is also subject to customary regulatory, stock exchange, court and other approvals. PetroBakken will target significant production and reserves growth through an internally-funded capital program underpinned by strong cash flows which will also allow us to provide an attractive dividend yield to our shareholders. Based on the proposed dividend policy, PetroBakken shares are expected to yield approximately 3% based on a $0.96 annualized dividend and anticipated trading levels for PetroBakken. Key Attributes of PetroBakken PetroBakken will combine significant, high growth, long-life Bakken reserves and production with legacy conventional light oil assets, which provide high netbacks and a low production decline profile. PetroBakken will be the premier Bakken player in Canada with a greater proportion of its production coming from the Bakken than any other material producer, and will represent a compelling new investment opportunity for investors. In addition, PetroBakken will have significant future development opportunities in the Horn River and Montney gas resource plays in northeast BC that will add long-term growth to PetroBakken's attractive light oil position. After planned Alberta asset dispositions of approximately 9,500 boepd, PetroBakken will have the following key attributes: - 2009 exit production is expected to be above 37,000 boepd (greater than 95% light oil). - More than 27,000 boepd from the Bakken (greater than 70% of total exit 2009 production). - More than 127 mmboe of high quality, primarily light oil, proved plus probable reserves with significant future reserve growth potential through revisions, additions, improved recoveries and the application of new technology. - Proved plus probable reserve life index of more than 9 years. - Significant land inventory of over 1.0 million net acres with more than 800,000 net acres in southeast Saskatchewan, making PetroBakken the single largest landholder in this region. Of this, over 280,000 net acres (440 net sections) are located in the Bakken play fairway with significant additional exposure to further Bakken exploration activity, including 80,000 net acres in Montana. - Incremental reserve enhancement capabilities on 110 net sections of existing producing Bakken acreage. - More than 1,300 future Bakken drilling locations using predominantly long-reach, bilateral horizontal wells. - Significant upside gas potential in the Horn River and Montney plays in northeast BC, with more than 63,000 net undeveloped acres and over 400 potential drilling locations, providing an additional long-term growth platform. - Industry leading operating netbacks estimated to be above $57.00/boe based on US$75.00 WTI. - Expected operating costs of approximately $8.00/boe. - Approximately $1.9 billion of tax pools. - Run-rate cash flow of more than $700 million based on US$75 WTI oil price and 2009 exit production. - 2010 capital budget of approximately $550 million based on a US$75 WTI oil price. - Initial dividend of $0.96 per share per annum, payable monthly, representing a payout ratio of 23% based on run rate cash flow. - Excellent financial flexibility with a pro forma debt to cash flow ratio of less than one times. - 172 million PetroBakken shares outstanding. - Industry leading technical team. Strategic Rationale The combination of the Petrobank and TriStar assets is highly complementary as it creates a pure play investment opportunity for exposure to high-netback light oil and the continuing technical enhancements of the Bakken resource play. In the Bakken alone, the combined asset base creates a dominant, operationally complementary land position providing significant long-term development growth through the future drilling of 1,300+ identified locations. The combined entity is expected to have an improved cost of capital as a result of the focused nature of the high netback light oil assets in southeast Saskatchewan. Additionally, the strategic merger results in the combination of premier technical teams focused on unlocking the value embedded in this large resource base. Independently, TriStar and Petrobank have been industry leaders in applying new, leading-edge technologies to unlock the true potential of the Bakken resource play. Bringing these two teams together creates the preeminent Bakken development team, utilizing best practices to continually enhance and ultimately maximize recovery factors. It is expected that PetroBakken's increased scale will provide superior operating efficiencies through complementary gathering systems, oil processing facilities, marketing arrangements and gas plant synergies. PETROBANK FOLLOWING THE COMPLETION OF THE PETROBAKKEN TRANSACTION Petrobank will capitalize PetroBakken with $400 million, contribute all the Company's CBU assets and transfer all bank debt and working capital associated with the CBU. Net Canadian bank debt at June 30, 2009 totalled $364 million and is expected to increase to approximately $400 million by September 30, 2009 due to increasing third quarter activity levels and land acquisitions. After closing the PetroBakken transaction, Petrobank will have estimated cash, net of working capital balances, of approximately $40 million, an undrawn operating line of credit estimated to initially be $20 million and Petrobank will be receiving over $105 million of dividends per year from PetroBakken, which together will be used to fund ongoing Heavy Oil Business Unit expenditures and obligations outstanding under Petrobank convertible bonds (principal amount US$405.1 million). Following the arrangement, an investment in one share of Petrobank (basic) will effectively represent 1.19 shares of PetroBakken, 0.71 shares of Petrominerales, and 100% of the Heavy Oil Business Unit assets, including our proprietary THAI(TM) and CAPRI(TM) technologies. CANADIAN BUSINESS UNIT ("CBU") OPERATIONAL UPDATE (all comparisons are to the second quarter of 2008) - CBU production increased 18.5% to 19,579 boepd. - CBU production expenses decreased by 27% to $6.52/boe. - CBU operating netbacks were $42.72/boe, excluding hedging gains of $3.46/boe. - We completed the first 20 stage fracture stimulation in Canada, using Packers Plus technology. - Our new drilling and completion strategy for the Bakken play now focuses on dual leg horizontal wells with high intensity fracture stimulation, creating the most cost effective approach to increase Bakken production and reserves. - On August 4th, 2009, Petrobank entered into a definitive agreement with TriStar to create PetroBakken. Our aggressive drilling program through 2008 was followed by a dramatic slowdown in activity during the first half of 2009 in response to significantly lower commodity prices and field activity was further reduced during the second quarter due to spring break up. Our 2009 drilling program resulted in only 11 (7.3 net) wells being drilled in the second quarter and 32 (24.4 net) wells drilled in total during the first half of 2009. Production averaged 19,579 boepd, a 19% increase from the 16,517 boepd produced in the second quarter of 2008. Due to lower activity levels and field restrictions due to spring break-up, production was down 11% from the first quarter of 2009. We anticipate a return to strong production growth through the balance of the year as we dramatically increase our drilling activity in the Bakken. Through most of the first half of the year we operated with a maximum of only two rigs on the Bakken play. We now have five rigs operating and a sixth rig will be starting shortly. Outside of the Bakken, our activities are targeted toward building on our expertise and drilling inventory in other large resource accumulations, including the Montney and Horn River Basin. The reduced drilling pace in early 2009 provided the opportunity to re-evaluate our Bakken drilling and completion strategies and to pioneer new techniques to maximize returns on our Bakken program. Our new strategy of drilling long-reach, bilateral horizontal wells provides improved production and reserves per-well by implementing the most cost effective approach for increasing the intensity of fracture stimulations along the length of the horizontal well bore while reducing the inter-well distance of the horizontal well bores, sub-surface. Furthermore, this new approach has immediate applications in our large inventory of existing producing wells, as we can re-enter these wells and add a second parallel horizontal leg with high intensity fracture stimulations ("re-entries"). TriStar's complementary inventory of undeveloped lands, and existing producers, further increases the growth potential of PetroBakken. Through the last half of 2009, our primary focus will be to increase Bakken drilling activity and continue to demonstrate our ability to maintain our low-cost advantage in developing this large resource base. We are positioned for continued long-term reserve and production growth as we increase our pace of development through the rest of the year. With current commodity prices we would expect to drill a further 70 wells in addition to another 20 re-entries through the balance of 2009, before taking into account the PetroBakken transaction. The Bakken Resource Petrobank pioneered the horizontal fracture stimulation techniques that opened up the true potential of this substantial resource, and we continue to find new ways to improve well performance and expected ultimate recoveries from the Bakken. This zone is a marginal reservoir that has been tested and analyzed for more than 50 years, yet only recently have advances in technology created the opportunity to produce significant oil from the Bakken. Recent, repeated testing has allowed us to conclude that every time we increase the number of fracture stimulations in a given section of land, we increase productivity and expected ultimate recoveries from the zone. Our efforts through early 2009 to further improve Bakken production have focused on increasing the intensity of fracture stimulation completions (fracs) by 38% in our long (1,400 metre) horizontals, by 200% in our short (700 metre) horizontals, and then by 400% in our short bilateral (two 700 metre horizontal legs from a single vertical well bore) horizontal wells. Recently, Petrobank also completed the first 20-stage fracture stimulation in Canada using Packers Plus technology. Our first two 20-stage frac wells have materially improved production performance compared to offset competitor wells and were initially free-flowing at rates in excess of 400 bopd. These results further demonstrate the potential of our strategy to cost-effectively increase fracture stimulation intensity and ultimate recoveries from the Bakken. We continue to build on our innovative approach to maximizing value from the Bakken resource. We are now implementing our new drilling and completion strategy which is to drill long bilateral horizontal wells (two 1,400 metre horizontal legs from a single vertical well bore) with a total of 30 fracture stimulations (15 fracture stimulations in each horizontal leg). These are the first wells to be drilled this way, and Petrobank has successfully executed all the unique elements of this approach in other wells. By combining our two most highly effective solutions for maximizing productivity and expected ultimate recoveries, we have developed the most capital efficient oil recovery method for the Bakken, to-date. We are also applying this approach to our large inventory of existing well bores. We have started to re-enter these horizontal wells and drill second parallel horizontal legs from the same vertical well, and complete them with higher intensity multi-stage fracs. Initial re-entry results have resulted in production increases of 80 to 150 bopd from previous well production rates prior to the re-entries. Another part of our strategy is to operate centralized facilities that capture additional value from the gas and natural gas liquids associated with our Bakken light oil, and to ensure field efficiencies that maintain low operating costs. To strengthen our infrastructure, three new facilities at Viewfield, Creelman, and Freestone were connected to our main Midale plant through 100 kilometres of new pipelines through 2008. The future growth of our infrastructure will be timed to match our need with future drilling. PetroBakken's combined infrastructure will provide additional oil handling capabilities for Petrobank's current and future locations north of our Freestone facility as well as gas processing capabilities for TriStar wells and facilities. Ongoing field efficiencies have resulted in a reduction of our Bakken production costs to $5.75/boe. This brings the average second quarter production costs for all of our CBU operations down to $6.52/boe, a 4% decrease from the $6.81/boe recorded in the first quarter of 2009 and a remarkable 27% reduction from the second quarter of 2008. Including the TriStar assets, PetroBakken will have 330 net undeveloped Bakken sections with a drilling inventory of over 1,300 bilateral wells, only 407 of which have been assigned 2P reserves. This substantial drilling inventory combined with our innovative approach to drilling and completing Bakken wells are expected to contribute to a multi-year growth profile for PetroBakken. Beyond Bakken Additional long-term growth will come from Petrobank's large land position in the Montney and Horn River natural gas resource plays located in northeast British Columbia. The company has 17 sections of land (100% working interest) in the Monias area with Montney potential and a further 97 (84 net) sections north of Fort Nelson in the Horn River basin. Petrobank has, to-date, successfully operated over 270 horizontal wells with multi-stage fracture stimulations, more than any other operator in Canada. This experience positions Petrobank to be a leader in the development of these massive unconventional resource plays. At Monias, our first Montney horizontal well was drilled in the fourth quarter of 2008 adjacent to our 5.0 mmcfpd gas plant. Based on that successful result, a second well is currently drilling. This well is a multi-leg horizontal with high density fracture stimulation designed to further increase production rates and expected ultimate gas recoveries. Our first horizontal well gas well in the Horn River Basin was drilled in the first quarter of 2009 in an area that offers multi-season access due to our proximity to the Alaska Highway. Based on that successful result, a second well is planned for later this year, building on what we learned from the first well as well as testing additional geological concepts. Our immediate operational goal for both of these prolific resource plays is to identify optimal technology applications that lower our internal hurdle for a gas price necessary to provide a competitive rate of return that will ultimately allow us to initiate a major full-scale development. HEAVY OIL BUSINESS UNIT ("HBU") OPERATIONAL UPDATE - Production averaged 205 bopd of partially upgraded oil. - P1B was drilled as a THAI(TM) well, replacing P1. - P2B was drilled as the second THAI(TM)/CAPRI(TM) well, replacing P2. - We have confirmed the CAPRI(TM) in-situ catalytic upgrading effect. - The Kerrobert project was approved on July 9, 2009, and drilling has commenced. Whitesands Project During the second quarter production averaged 205 bopd, down 43 barrels per day compared to the previous quarter as operations were ramped down and stabilized in preparation for drilling the P1B and P2B wells. As previously reported, P1 was shut-in on March 31, 2009 and P2 was subsequently shut-in on July 24, 2009 to facilitate the drilling of the replacement wells for P1 and P2. Concurrent with the preparation for drilling the new wells, P3B air injection was reduced and production was stabilized at 100 bopd per day prior to and during the drilling and completion operations. We commenced drilling P1B on July 5, 2009 and we completed drilling on July 16, 2009. This well is completed as a THAI(TM) well with a FacsRite(TM) liner utilizing cartridge screens designed for superior downhole sand control, liner integrity and increased flow area. The FacsRite(TM) liner is manufactured by Absolute Completion Technologies in Alberta and internationally distributed by Schlumberger. This liner configuration has been used in projects worldwide but P1B is the first well in North America to be completed with the FacsRite(TM) design. P2B is our second THAI(TM)/CAPRI(TM) well and drilling was completed on August 7, 2009. P2B has the same liner design as our successful P3B well. Both wells are expected to be completed, tied in and operational by the end of August, with production expected near the end of the third quarter. P3B wellbore temperatures have been operating between 400 and 500 degrees Celsius, well within the CAPRI(TM) catalyst range. Produced light hydrocarbons from the P3B secondary separator averaged 36 degrees API and the combined P3B THAI(TM)/CAPRI(TM) production from the primary and secondary separators ranged from 12 to 15 degrees API, compared to a reservoir quality of 8 degrees API. The CAPRI(TM) upgrading effect has been measured at as much as 3 degrees API higher than THAI(TM) production, confirming a direct in-situ upgrading effect of the catalyst. In the second quarter, we commenced a routine regulatory inspection of the surface facilities starting with the P1 production train. During the current drilling and completion operations, we will be able to complete the majority of the inspections prior to resuming full operations on all three wells. To-date, the facilities inspections have shown no evidence of any corrosion in the vessels and associated equipment. Whitesands is now configured as a modified three well THAI(TM)/CAPRI(TM) demonstration site, which will allow us to continue to test new technology enhancements, such as oxygen enrichment, CO2 co-injection, and partial surface upgrading. Kerrobert Project Regulatory applications for the Kerrobert Project were filed on April 22, 2009 and approval was received on July 9, 2009. In our environmental application we completed additional work to enable expansion of the project which resulted in a slightly longer initial regulatory process but will facilitate a shorter time frame for expansion projects. Drilling operations began on July 18, 2009 and the first production well KP1 completed drilling on August 5, 2009. KP2 commenced drilling on August 7, 2009 and drilling is expected to be completed next week. Both of these wells will utilize FacsRite(TM) liners. The air injection wells are planned to be completed by the end of August, and the pre-ignition heating cycle (PIHC) will be initiated simultaneously. Air injection is planned to begin in early October and first production is expected to occur at about the same time. This two well project applies the THAI(TM) technology in a conventional heavy oil reservoir at Kerrobert and is a 50/50 joint venture with Baytex Energy Trust, who purchased True Energy Trust's Saskatchewan assets. With the approval of the Kerrobert project, Petrobank earned a 50% percent interest in an initial four sections of land. This joint project will highlight the applicability of the THAI(TM) technology in Saskatchewan's conventional heavy oil resource base. We consider that a significant portion of the estimated 20 billion of barrels of unrecovered conventional heavy oil resources in Saskatchewan can be commercialized using THAI(TM). In addition, Saskatchewan is actively encouraging oil and gas development and the application of advanced technologies through government royalty incentive programs. May River Project The May River Project is our first large-scale commercial THAI(TM) application on Petrobank's oil sands leases west of Conklin, Alberta. The May River design builds on the experience gained from Whitesands. The project will be built in phases, with initial production capacity of 10,000 barrels of THAI(TM) oil per day, and an ultimate capacity of up to 100,000 bopd. The regulatory application for May River's first phase was filed with the Energy Resources Conservation Board and Alberta Environment in December 2008. The application has been deemed complete by the regulatory authorities and is now moving through the regulatory process. We expect to receive approval for the project near the end of the year. Front end engineering and design for the project began in the fourth quarter of 2008, and we expect to have completed this phase of engineering in the fourth quarter of 2009. The design incorporates self-sufficient power generation utilizing low-BTU produced gas, produced gas sweetening, simplified CO2 capture add-on capability, and the project will be a net water producer rather than a water user. These design elements contribute to making the May River Project a leading environmentally sustainable process for oil sands and heavy oil development. The project is also designed to utilize a modular approach with direct and immediate applicability to heavy oil projects world-wide. Dawson Project The Dawson Project is a joint project involving our first Alberta-based, third party THAI(TM) license. Our partner is now Shell Canada Limited, who acquired Duvernay Oil Corp. in August 2008. The project is located near Peace River, Alberta and will be developed in the Bluesky formation. In August 2008, a stratigraphic well was drilled on the project site, which will be used as a thermal observation well during the project's operating phase. The regulatory application for the project was filed on April 2, 2009 and we expect to receive approval by the end of 2009. This project will be virtually the same as the Kerrobert Project and will demonstrate the THAI(TM) technology in a more mobile oil sands reservoir. Business Development Our wholly-owned subsidiary, Archon Technologies Ltd., continues to evaluate a number of innovative engineering, environmental, and other value-added technology options to improve operational efficiency, increase production efficiencies, and reduce the overall environmental impact of bitumen and heavy oil recovery. The utilization of the FacsRite(TM) liner is another example of our ability to evaluate new technologies and rapidly deploy them in the field. Additional technologies being assessed include; elemental sulphur recovery, enriched oxygen injection, carbon dioxide co-injection, power generation using produced lean gas, enhanced produced water quality, and incremental surface upgrading. We have been in active discussions and negotiations on potential licensing arrangements opportunities and there is a great deal of interest in our technologies because of their superior economic and environmental benefits. Our business strategy is to license and apply THAI(TM) and related technologies in a wide range of large global resource opportunities. LATIN AMERICAN BUSINESS UNIT ("LABU") OPERATIONAL UPDATE A full operational update of our 67% owned Latin American Business Unit, Petrominerales Ltd. PMG, was published on August 5, 2009 and can be found at www.petrominerales.com and www.sedar.com. Highlights of that release included: - Crude oil production increased 194% to 21,548 bopd due to drilling successes in Corcel, Mapache and Neiva. - July production averaged 21,922 bopd. - Funds flow from operations increased by 20% to US$64.1 million (US$0.63 per share diluted) despite significantly lower world oil prices. - Petrominerales recorded net income of US$15.3 million (US$0.15 per share diluted). - Phase I of Monterrey offloading facility was operational at first-phase capacity of 11,000 bopd and crude oil deliveries commenced on July 9, 2009. Petrobank Energy and Resources Ltd. is a Calgary-based oil and natural gas exploration and production company with operations in western Canada and Latin America. The Company operates high-impact projects through three business units and a technology subsidiary. The Canadian Business Unit is focused on developing a solid production platform from the Bakken light oil play in southeast Saskatchewan, and exploiting a large undeveloped land base through the application of new technology to large oil and gas resource opportunities. The Latin American Business Unit, operated by Petrobank's 67% owned TSX-listed subsidiary, Petrominerales Ltd. PMG, is a Latin American-based exploration and production company producing oil in Colombia with 16 exploration blocks covering a total of 1.9 million acres in the Llanos and Putumayo Basins of Colombia and 2.6 million acres in the Ucayali Basin of Peru. Whitesands Insitu Partnership, a partnership between Petrobank and its wholly-owned subsidiary Whitesands Insitu Inc., owns 75 net sections of oil sands leases in Alberta, 36 sections of oil sands licenses in Saskatchewan and operates the Whitesands project which is field-demonstrating Petrobank's patented THAI(TM) heavy oil recovery process. THAI(TM) is an evolutionary in-situ combustion technology for the recovery of bitumen and heavy oil that integrates existing proven technologies and provides the opportunity to create a step change in the development of heavy oil resources globally. THAI(TM) and CAPRI(TM) are registered trademarks of Archon Technologies Ltd., a wholly-owned subsidiary of Petrobank. Forward-Looking Statements. Certain information provided in this press release constitutes forward-looking statements. The words "anticipate", "expect", "project", "estimate", "forecast" and similar expressions are intended to identify such forward-looking statements. Specifically, this press release contains forward-looking statements relating to financial results, results of operations, the timing for obtaining necessary approvals and otherwise satisfying conditions related to the completion of the PetroBakken transaction and the timing of other projects. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. You can find a discussion of those risks and uncertainties in our Canadian securities filings. Such factors include, but are not limited to: general economic, market and business conditions; fluctuations in oil prices; uncertainties that TriStar and Petrobank may not obtain regulatory and security holder approvals with respect to the PetroBakken transaction or that other conditions to the completion of the PetroBakken transaction are not satisfied within expected timeframes or at all, the results of exploration and development drilling, recompletions and related activities; timing and rig availability, fluctuation in foreign currency exchange rates; the uncertainty of reserve estimates; changes in environmental and other regulations; risks associated with oil and gas operations; and other factors, many of which are beyond the control of the Company. There is no representation by Petrobank that actual results achieved during the forecast period will be the same in whole or in part as those forecast. Except as may be required by applicable securities laws, Petrobank assumes no obligation to publicly update or revise any forward-looking statements made herein or otherwise, whether as a result of new information, future events or otherwise. Non-GAAP Measures. This press release contains financial terms that are not considered measures under Canadian generally accepted accounting principles ("GAAP"), such as funds flow from operations, funds flow per share, net debt and operating netback. These measures are commonly utilized in the oil and gas industry and are considered informative for management and shareholders. Specifically, funds flow from operations and funds flow per share reflect cash generated from operating activities before changes in non-cash working capital. Management considers funds flow from operations and funds flow per share important as they help evaluate performance and demonstrate the Company's ability to generate sufficient cash to fund future growth opportunities and repay debt. Net debt includes bank debt plus accounts payable and accrued liabilities less current assets (excluding future income tax asset) and is used to evaluate the Company's financial leverage. Profitability relative to commodity prices per unit of production is demonstrated by an operating netback. Funds flow from operations, funds flow per share, net debt and operating netbacks may not be comparable to those reported by other companies nor should they be viewed as an alternative to cash flow from operations, net income or other measures of financial performance calculated in accordance with GAAP. The following table shows the reconciliation of funds flow from operations to cash flow from operating activities for the periods noted: /T/ Three months ended June 30, Six months ended June 30, 2009 2008 Change 2009 2008 Change ---------------------------------------------------------------------------- Funds flow from operations: Non-GAAP 150,350 177,923 (15%) 275,506 301,411 (9%) Changes in non-cash working capital (29,216) (22,615) 29% (43,108) (76,406) (44%) ---------------------------------------------------------------------------- Cash flow from operating activities: GAAP 121,134 155,308 (22%) 232,398 225,005 3% ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- /T/ Resources and Contingent Resources. In this press release, Petrobank has disclosed estimated volumes of "contingent resources" or "resource" estimates. "Resources" are oil and gas volumes that are estimated to have originally existed in the earth's crust as naturally occurring accumulations but are not capable of being classified as "reserves". The following are excerpts from the definition of "contingent resources" as contained in Section 5 of the COGE Handbook, which is referenced by the Canadian Securities Administrators in "National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities". "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. 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. "Contingent resources" are further classified in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status. "Resources" and "contingent resources" do not constitute, and should not be confused with, reserves. Barrels of Oil Equivalent ("boe"). Disclosure provided in this press release in respect of boe units may be misleading, particularly if used in isolation. A boe conversion relationship of 6 mcf to 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head.