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Press release from Marketwire

Petrobank Reports Q2 2010 Net Income of $41.1 Million and Provides Update for Heavy Oil Business Unit

Friday, August 13, 2010

Petrobank Reports Q2 2010 Net Income of $41.1 Million and Provides Update for Heavy Oil Business Unit01:58 EDT Friday, August 13, 2010CALGARY, ALBERTA--(Marketwire - Aug. 13, 2010) - Petrobank Energy and Resources Ltd. ("Petrobank" or the "Company") (TSX:PBG) is pleased to announce second quarter 2010 financial and operating results highlighted by funds flow from operations of $3.12 per diluted share and net income of $0.35 per diluted share. Petrobank's results include the financial and operating results of PetroBakken Energy Ltd. ("PetroBakken") (TSX:PBN), 58% owned by Petrobank and Petrominerales Ltd. ("Petrominerales") (TSX:PMG), 66% owned by Petrobank. PetroBakken announced second quarter financial and operating results on August 10, 2010. Petrominerales announced second quarter financial and operating results on August 5, 2010.All references to $ are Canadian dollars unless otherwise noted. All comparisons are to the prior year period, unless otherwise noted.Q2 2010 HIGHLIGHTS AND SIGNIFICANT TRANSACTIONS -- Petrobank's consolidated production increased 110% to 86,466 barrels of oil equivalent per day ("boepd") in the second quarter of 2010 compared to 41,127 boepd in the second quarter of 2009 due to production increases in PetroBakken and Petrominerales. -- Funds flow from operations increased 123% to $334.6 million in the second quarter of 2010. On a per diluted share basis, funds flow from operations increased 90% to $3.12. -- Net income increased 18% to $41.1 million in the second quarter of 2010. On a per diluted share basis, net income decreased 13% to $0.35. Petrobank's Heavy Oil Business Unit ("HBU") -- Petrobank incurred $10.7 million of capital expenditures in the second quarter related to our Kerrobert heavy oil project and the May River / Conklin oil sands projects. -- We successfully completed pump reconfigurations at Kerrobert and the project is now producing at 250 barrels of oil per day ("bopd") and trending up. -- Kerrobert production is being consistently upgraded insitu by over six degrees API. -- Regulatory approval for the Kerrobert 10 well expansion project was received on August 6th, 54 working days from the initial application submission. -- The May River Project is waiting for final approval from the ERCB, although Alberta Environment contingent approval for the project was received April 12, 2010. PetroBakken -- PetroBakken's production averaged 42,263 boepd in the second quarter of 2010, a 116% increase over the prior year, primarily driven by the acquisition of TriStar Oil & Gas Ltd. ("TriStar") on October 1, 2009 and drilling activities in the Bakken. Production declined 2% compared to the first quarter of 2010 due to a reduction in drilling activity during spring break-up. -- In April 2010, we improved our financial flexibility through a $100 million increase in our revolving credit facility. The borrowing limit was increased from $900 million to $1 billion. -- Our operating netback (excluding hedging gains) of $46.10/boe improved 8% over the prior year primarily due to the increase in oil prices. Compared to the first quarter of 2010, operating netbacks decreased 13% as a result of lower pricing partially offset by lower royalties and production expenses. -- Drilled 37 (27.4 net) wells in the second quarter; including 28 (22.1 net) in the Bakken, and 5 (3.6 net) in conventional plays in southeast Saskatchewan. -- PetroBakken completed the acquisition of Result Energy Inc., the third of our Cardium focused corporate acquisitions, and one non-core property disposition. Petrominerales -- Second quarter crude oil production grew to 44,203 bopd, a 105% gain over the prior year and a 16% gain over the first quarter of 2010. -- Generated a solid operating netback of US$50.93 per barrel in the quarter, a 38% increase. -- Drilled two new oil discoveries on our Central Llanos Basin acreage in Colombia, Yenac-1 and Capybara-1. -- Petrominerales completed the acquisition of PanAndean Resources plc on April 14, 2010. PanAndean assets include four exploration contracts in Peru and one in Colombia totalling 6.7 million gross (2.6 million net) acres. -- On August 10, 2010, Petrominerales announced a US$550 million convertible debenture offering (the "Offering"). The debentures are convertible into common shares of Petrominerales and have an annual coupon rate of 2.625% and a conversion price of US$34.746 (Cdn$36.254) per debenture. The debentures will be issued at 100% of their principal amount and, unless previously redeemed, converted or cancelled, will mature in 2016. The debentures are expected to be issued on or about August 25, 2010. The offering is subject certain approvals, including the approval of the Toronto Stock Exchange. PETROBANK'S LIQUIDITY AND CAPITAL RESOURCES Petrobank, PetroBakken and Petrominerales manage their capital structure independently; they generate their own cash flows, and have the ability to fund their operations through the issuance of secured and unsecured debt as well as equity financing. Petrobank's capital resources are focused on funding corporate and HBU expenditures. At June 30, 2010, independent of PetroBakken and Petrominerales, Petrobank on a standalone basis had no bank debt outstanding and positive working capital of $22.4 million. A $30 million credit facility is also available. Based on Petrobank's current ownership in PetroBakken, Petrobank expects to receive $105 million of dividends annually paid monthly. With the recent commencement of a dividend policy at Petrominerales, Petrobank also expects to receive $33 million annually from Petrominerales, paid on a quarterly basis. Petrobank also has an option to raise funds by issuing equity, selling a portion of its ownership in PetroBakken and Petrominerales or by issuing additional debt secured by these interests.We currently intend to fund our HBU capital expenditure program with cash on hand, available credit, cash from operations and dividends received from PetroBakken and Petrominerales.SUMMARY OF FINANCIAL AND OPERATING RESULTS Three months ended June 30, Six months ended June 30, % % 2010 2009 Change 2010 2009 Change --------------------------------------------------------------------------- Financial ($000s, except where noted) Oil and natural gas revenue 573,040 224,396 155 1,106,173 415,182 166 Funds flow from operations (1) 334,592 150,350 123 668,546 275,506 143 Per share - basic ($) 3.18 1.78 79 6.51 3.28 98 - diluted ($) 3.12 1.64 90 6.26 3.03 107 Net income 41,050 34,667 18 123,549 33,125 273 Per share - basic ($) 0.39 0.41 (5) 1.20 0.39 208 - diluted ($) 0.35 0.40 (13) 1.11 0.39 185 Capital expenditures PetroBakken 122,688 38,901 215 307,804 108,925 183 Petrominerales 115,055 93,203 23 231,264 174,763 32 Heavy Oil Business Unit 10,653 12,318 (14) 34,587 33,728 3 --------------------------------------------------------------------------- Total Company 248,396 144,422 72 573,655 317,416 81 Total assets 7,160,685 2,421,171 196 7,160,685 2,421,171 196 Common shares, end of period (000s) Basic 105,993 92,267 15 105,993 92,267 15 Diluted (2) 110,167 99,270 11 110,167 99,270 11 --------------------------------------------------------------------------- Operations PetroBakken operating netback ($/boe except where noted) (1) (3) Oil and NGL revenue ($/bbl) (4) 70.98 62.22 14 73.61 54.88 34 Natural gas revenue ($/mcf) (4) 4.11 3.91 5 4.57 4.56 - Oil and natural gas revenue (4) 62.86 56.64 11 66.65 51.45 30 Royalties 9.17 7.40 24 9.43 6.30 50 Production expenses 7.59 6.52 16 7.69 6.67 15 --------------------------------------------------------------------------- Operating netback (5) 46.10 42.72 8 49.53 38.48 29 Petrominerales operating netback ($/bbl) (1) Oil revenue (4) 65.15 55.76 17 65.87 49.01 34 Royalties 6.51 5.02 30 7.02 4.81 46 Production expenses 6.61 7.86 (16) 5.60 7.63 (27) --------------------------------------------------------------------------- Operating netback 52.03 42.88 21 53.25 36.56 46 Average daily production PetroBakken - oil and NGL (bbls) 34,852 16,761 108 36,245 18,233 99 PetroBakken - natural gas (mcf) 44,469 16,906 163 38,598 15,550 148 --------------------------------------------------------------------------- Total PetroBakken (boe) (3) 42,263 19,579 116 42,678 20,825 105 Petrominerales - oil (bbls) (6) 44,203 21,548 105 41,218 21,659 90 --------------------------------------------------------------------------- Total Company conventional (boe) (7) 86,466 41,127 110 83,896 42,484 97 --------------------------------------------------------------------------- (1) Non-GAAP measure. See "Non-GAAP Measures" section within this press release. (2) Consists of common shares, stock options, deferred common shares, incentive shares and convertible debentures as at the period end date. (3) Six Mcf of natural gas is equivalent to one boe. (4) Net of transportation expenses and excludes revenue from purchased oil. (5) Excludes hedging activities. (6) Actual production sold for the three and six months ended June 30, 2010 was 49,466 boe and 43,995 bopd, respectively (2009 - 21,390 bopd and 21,399 bopd). After adjusting for oil purchased from third parties and marketed on their behalf, Petrominerales actual production sold and used in per barrel calculations was 44,560 bopd and 40,880 bopd, respectively. (7) HBU bitumen volumes are excluded from average daily production as Conklin and Kerrobert operations are considered to be in the pre-operating stage and accordingly are capitalized. HEAVY OIL BUSINESS UNIT OPERATIONAL UPDATE Kerrobert Project Early in the second quarter we installed and commissioned progressive cavity pumps, modified wellhead configurations and added bottomhole pressure monitoring appropriate for the new pumps. As a result, the wells were offline for the first half of the second quarter. We also experienced downtime late in second quarter and early in the third quarter due to incinerator repairs, well clean up procedures, and the replacement of a metal-on-metal pump on one of the wells to an elastomeric design.The reconfigured wells were brought online and stabilized during mid-May. The new wellheads and downhole instrumentation will provide us with the ability to control and optimize well performance. Production rates have ranged from 60 to 150 bopd per well as we lined out the pumps. We established new well operating parameters, and cleaned up the wells as they continue the transition from primary heavy oil to THAI(TM) oil production. We are now producing upgraded oil consistently in the 14 to 18 degree API range. We are seeing minimal solids production, all of which has been less than the Facsrite(TM) mesh size. Our Kerrobert project is currently averaging 250 bopd and rising.Additional compression was installed and became operational at the end of April and we have ramped up air injection to over 2/3 of designed capacity. Wellbore temperatures at the toes of the wells have stabilized above 200 degrees Celsius and we have operated at temperatures of up to 650 degrees Celsius. Temperatures are rising along both wellbores with heel temperatures up to 90 degrees Celsius versus an ambient reservoir temperature of 27 degrees Celsius. Our ten well expansion plans for Kerrobert are progressing and we have received both our environmental and enhanced oil recovery approvals as of August 6, 2010 which was just 54 working days from the application date and only 14 working days from receipt of our final freehold consents. We expect drilling to commence during the third quarter of 2010. Startup operations for the pre-ignition heating cycle with steam injection are planned for early November 2010 and air injection is expected to commence in Q1 of 2011. Conklin Project During the second quarter the majority of production at Conklin came from our P3B well with production rates averaging 100 bopd and maximum rates exceeding 535 bopd. Production was adversely impacted by downtime related to surface equipment issues and while we established full communication between P1B and P2B and the combustion front. During the quarter we continued evaluating reconfiguration and pumping options for the Conklin wells, building on our Kerrobert experience. We also continued to operate the P3B well at higher bottomhole pressures in April. The testing was completed late in the month and production rates were measured at up to 480 bopd. The testing has demonstrated that operating at a higher backpressure improves well control and production. We expect to make minor modifications to our current surface facilities to enable sustained operations at higher backpressures in conjunction with the reconfiguration to include pumps. In the last week of April, the P3B well was shut-in to enable the replacement of a packer in the A3 injection well. The work was completed and the well was restarted during mid-May. Upon the restart we encountered a surface casing vent flow ("SCVF") which, pursuant to ERCB regulations, required the well to be shut in. After evaluating the potential causes of the SCVF over a 30 day period in cooperation with the ERCB, it was determined that the SCVF was not material. The well was brought back on in mid July. During this extended downtime we took the opportunity to complete preventive maintenance on the P3B well train.On the P1B well and the P2B well, we progressed towards establishing full communication with the combustion zone. We now understand that these wells were drilled further away from the combustion zone than originally projected, resulting in a longer restart time. We have recorded temperatures in the offsetting observation wells of between 300 - 500 degrees Celsius indicating the combustion zone is now in proximity of the wells. Production rates have ranged from 100 to 150 bopd of partially upgraded oil. Production on all wells was interrupted by operating problems encountered with our new high efficiency incinerator design which constrained the produced gas and liquid production from the wells. Design issues have now been addressed, and the unit has performed above design specifications as of mid-July. We also scheduled a five-day maintenance turnaround for the middle of July.With the facilities fully operational and the maintenance issues addressed, we have increased air injection rates on the P1B and the P2B wells to up to 100,000 m3/day as we aggressively establish full communication with the combustion zone. By the end of the third quarter we will have installed a gas lift string and bottom hole pressure monitor and will have conducted another high bottomhole pressure run on P3B. We will also maintain high air injection rates on the P1B and P2B wells to facilitate rapid communication. In March of 2010 we acquired our fourth seismic survey over the Conklin pilot area. The new survey has been processed and we are interpreting the results. The time lapse seismic has proven to provide sensitive analysis of the movement of the combustion front. May River Project Engineering, procurement, and construction management on the project has been awarded for the wellsites, pipelines, and central processing facility. Petrobank has initiated ordering long lead materials and equipment, and with timely regulatory approval, steam start-up could occur in mid-2012. An additional 12 OSE stratigraphic wells and 3D seismic over the project area have been completed, allowing us to further delineate the reservoir and to optimize well placements for the 18 well pairs planned for Phase 1 of the project. The regulatory application for May River's first phase was filed with the ERCB and Alberta Environment in December 2008. The first round of SIR's from Alberta Environment and the ERCB were responded to in mid-December 2009. We have received and responded to the second round of SIR's from Alberta Environment and they have given the project contingent approval (subject to ERCB approval) on April 12, 2010. We received the second round of SIR's from the ERCB on May 13, 2010 and responses were submitted on June 1, 2010. The final hurdle to approval will be the resolution of two Statements of Concern ("SOC"). The SOCs were recently filed and are general in nature. Pursuant to Section 26 of the Energy Resources Conservation Act (ERCA), the SOC holders must demonstrate how their rights are directly and adversely impacted by the project. To date, they have not provided such information, and the ERCB is soliciting both parties to determine if they have legitimate concerns and standing before they will issue the final approval for the project. The May River design is CO2 capture ready, incorporates power generation utilizing low energy produced gas, sulphur recovery, and will be a net water producer rather than a water user, making our May River project a leading environmentally sustainable benchmark for oil sands and heavy oil development. The project utilizes a modular approach that is designed to be installed and operated on heavy oil projects world-wide.Dawson Project The second round of SIR's were received from the ERCB in June and responses were submitted in July. There are no Statements of Concern filed related to this project. Engineering has been completed and equipment procurement will commence as soon as final approvals have been received. Dawson is a joint venture project located near Peace River, Alberta with a significant heavy oil resource in the Bluesky formation.Archon Technologies / Business Development Archon Technologies Ltd. is a wholly-owned subsidiary of Petrobank. Archon maintains a state of the art laboratory with highly qualified staff, all of whom are committed to developing, evaluating and patenting new technologies supporting and protecting the THAI(TM) and CAPRI(TM)technologies. Archon has eight additional global patents or patents pending related to the THAI(TM) process. In addition, successful bench scale testing of several new ground breaking technologies at the lab has encouraged Archon to undertake design of small scale field pilots at Conklin, Alberta. The technologies tested include the use of a variation of enriched air injection schemes and conversion of H2S to elemental sulphur through direct oxidation. This will also enhance the Crystasulf(TM) technology. These technologies are expected to significantly improve the economic benefits of THAI(TM) by increasing early stage oil production rate and simplifying surface handling of H2S. The small scale field pilots to confirm the merits of these new technologies are planned for the winter of 2010/11. Additionally, Archon is currently constructing new bench scale tests to evaluate the effectiveness of alternative sand control systems to be used for future THAI(TM) projects. The field and lab tests will help further improve the overall operational robustness and economics of THAI(TM) process.Economic and environmental benefits of our innovative technology has continued to generate strong world-wide interest in licensing initiatives. Our joint venture strategy is to demonstrate and commercialize THAI(TM) and CAPRI(TM) in a wide range of large global heavy oil resource opportunities. THAI(TM) has many potential benefits over SAGD, including expected higher resource recovery (70%-80% versus 30%-50% for SAGD), lower production and capital costs, minimal usage of natural gas and fresh water, a partially upgraded crude oil product, reduced diluent requirements for transportation, and lower greenhouse gas emissions. The THAI(TM) process also has the potential to operate in lower pressure, lower quality, thinner and deeper reservoirs than current steam-based recovery processes. The continued field demonstration of THAI(TM) will have an enormous impact on resource recovery and estimates of reserve volumes. As we have previously reported, we are in final negotiations with a large international energy company and progressing towards potential agreements with others to license THAI(TM) and develop it in their heavy oil fields. These negotiations are complex and require the integration of many business, legal and financial aspects within our business model which leads to long negotiation cycles.EXECUTIVE APPOINTMENT Petrobank is pleased to announce the appointment of Peter Cheung, CA as Vice President, Finance and Chief Financial Officer effective August 14, 2010, replacing Corey Ruttan who will continue to provide Petrobank with his guidance and leadership as a member of the Board of Directors and as President and Chief Executive Officer of Petrominerales.Peter brings an extensive range of accounting, capital markets, financial analysis and treasury experience to Petrobank. Most recently, Peter was Treasurer at Compton Petroleum Corporation, after having founded an investment management company. Previously, Peter was Vice President and Treasurer at Pengrowth Energy Trust and Vice President at RBC Capital Markets Energy Investment Banking. Peter's wide range of experiences will add to Petrobank's innovative culture as we deliver results for our shareholders.INVESTOR CONFERENCE CALL Management of Petrobank will be holding a conference call for investors, financial analysts, media and any interested persons on Friday, August 13, 2010 at 8:00 a.m. Mountain Time (10:00 a.m. Eastern Time) to discuss Petrobank's second quarter financial and operating results. The investor conference call details are as follows:Live call dial-in numbers: 416-340-8527 / 877-240-9772Replay dial-in numbers: 416-695-5800 / 800-408-3053Replay pass code: 1637151The live audio webcast link is: and is also available on our website at: PRESENTATIONS The Petrobank, PetroBakken and Petrominerales corporate presentations have been updated and can be found at,, and 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, operated by Petrobank's 58% owned TSX-listed subsidiary, PetroBakken Energy Ltd. (TSX:PBN), is a premier light oil production company combining, high growth, long-life Bakken reserves and production with legacy conventional light oil assets, delivering industry leading operating netbacks, strong cash flows and production growth. PetroBakken is applying leading edge technology to a multi-year inventory of Bakken and Cardium light oil development locations, along with a significant inventory of opportunities in the Horn River and Montney gas resource plays in northeast BC. PetroBakken's strategy is to deliver accretive production and reserves growth, along with an attractive dividend yield. The Latin American Business Unit, operated by Petrobank's 66% owned TSX listed subsidiary, Petrominerales Ltd. (TSX:PMG), is a Latin America-based exploration and production company producing oil in Colombia with 17 exploration blocks covering a total of 2.1 million acres in the Llanos and Putumayo Basins and five exploration blocks in Peru covering a total of 9.4 million gross (5.2 million net) acres in the Ucayali and Titicaca Basins. 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. 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 and operating netback. These measures are commonly utilized in the oil and gas industry and are considered informative for management and shareholders. Management considers operating netback important as it is a measure of profitability per barrel of production. Operating netbacks may not be comparable to those reported by other companies nor should they be viewed as an alternative to 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: Three months ended June Six months ended June 30, 30, 2010 2009 2010 2009 --------------------------------------------------------------------------- Funds flow from operations: Non-GAAP $ 334,592 $ 150,350 $ 668,546 $ 275,506 Changes in non-cash working capital 45,221 (29,216) (71,065) (43,108) --------------------------------------------------------------------------- Cash flow from operating activities: GAAP $ 379,813 $ 121,134 $ 597,481 $ 232,398 --------------------------------------------------------------------------- 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 from operations and the timing of certain 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; the results of exploration and development drilling, recompletions and related activities; timing and rig availability, outcome of exploration contract negotiations; 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. Barrels of Oil Equivalent: Disclosure provided in this press release in respect of barrels of oil equivalent ("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.FOR FURTHER INFORMATION PLEASE CONTACT: Petrobank Energy and Resources Ltd. John D. Wright President and Chief Executive Officer and Director (403) 750-4400 or Petrobank Energy and Resources Ltd. Chris J. Bloomer Senior Vice President and Chief Operating Officer, Heavy Oil and Director (403) 750-4400 or Petrobank Energy and Resources Ltd. Corey C. Ruttan Senior Vice President and Chief Financial Officer and Director (403) 750-4400 or Petrobank Energy and Resources Ltd. Peter Cheung Vice President, Finance and Chief Financial Officer (effective August 14, 2010) (403) 750-4400 /