CALGARY, ALBERTA--(CCNMatthews - Aug. 15, 2005) - Petrobank Energy and Resources Ltd. (TSX:PBG)(TSX:PBG.NT.A)(Petrobank) is pleased to provide this operational update of our Canadian, Latin American and Heavy Oil Business Units, and our second quarter financial results.
FINANCIAL HIGHLIGHTS
The second quarter results reflect the going concern performance of the Company's production assets in Canada and Colombia. The Canadian comparative numbers for prior periods include the results from a number of properties that were sold by the Company during 2004.
- Canadian production increased 37 percent year-over-year, excluding production from properties sold during 2004.
- Despite disposing of 63 percent of second quarter 2004 Canadian production, cash flow from operations only decreased 26 percent to $4.6 million during the current quarter.
- Colombian oil sales averaged 1,024 bopd in the second quarter of 2005, compared to 1,072 bopd in the first quarter of 2005.
- Net debt was reduced by 72 percent from $121.8 million at the end of the second quarter of 2004 to $33.4 million at the end of the current period.
- Operating netbacks improved 42 percent and 14 percent in Canada and Colombia, respectively.
- The Company recorded second quarter net income of $4.7 million compared to a loss a year earlier of $1.8 million.
- Increased available borrowing base under credit facilities from $10 million to $35 million.
- Financing was secured to fund the WHITESANDS - THAI(TM) pilot project.
OPERATIONAL UPDATE
Canadian Business Unit Update
During the first half of the year Petrobank was able to increase production slightly despite the very limited scope of our field activity. Our efforts in the field were plagued with delays due to extended regulatory approval processes, availability of equipment, and the long period of unseasonably wet weather in southern Alberta. The Company did not commence any Canadian drilling operations until June of this year. Production averaged 2,147 boepd during the second quarter compared to 1,927 boepd in the first quarter.
Since the beginning of July, activity has accelerated dramatically. Compared to only nine wells drilled in the first half of 2005, a total of 31 wells have been drilled to-date in the third quarter along with the completion of our gas facility expansion at Jumpbush. We are very encouraged by our recent results at Jumpbush, Red Willow, Macklin and Princeton, and we are well on our way to meeting our 2005 goal to double Canadian production.
Jumpbush
Petrobank has a 70 percent working interest in the 61,000 acre (42,700 net) Jumpbush property, primarily focused on the Siksika First Nation lands east of Calgary. In partnership with Siksika Energy and Resources Corporation (SERC), we are implementing year one of an aggressive five-year development plan that projects at least 50 wells being drilled each year.
Our 2005 plan at Jumpbush is to drill a total of 58 wells (40.6 net) and to upgrade our existing infrastructure of pipelines, compression, and facilities to handle up to 25 mmcf/day gross (17.5 mmcf/day net). The Jumpbush property is predominantly gas, and during the first and second quarters produced an average of 9.0 mmcf/day (6.3 mmcf/day net) and 11.2 mmcf/day (7.9 mmcf/day net), respectively.
Petrobank promotes and maintains a strong positive working relationship with the Siksika First Nation, which ultimately governs the pace and scope of our operations on their lands. Regulations and approvals on First Nation lands are more complex than similar operations on Crown land, and this complex process can cause delays in reaching final approval for operations. Due to minor delays in the approval process, unseasonably wet weather and the limited availability of equipment for our drilling program, operations at Siksika did not ramp-up as quickly as expected.
During June 2005, nine gas wells (6.3 net) were drilled and a further 22 gas wells (15.4 net) have been drilled to-date in the third quarter. Line-looping of a pipeline that brings the majority of the gas into the plant from the eastern portion of the field was also completed. The Jumpbush gas plant expansion was recently completed and is now being brought on-stream. The priority pipelining for key, high productivity wells and additional line-looping is underway and should be complete by the end of August, allowing Petrobank to operate the new facility at or near its full capacity. The balance of drilling and pipelining will continue during the second half of this year and is expected to be completed by the end of October.
Red Willow
The majority of operations at Red Willow during the first half of 2005 were workovers, pumpjack installations on oil wells, and preparations for drilling. No wells were drilled in the first half of the year, but we have now drilled six wells since the beginning of July. This drilling resulted in two oil wells and one gas well from the Lower Mannville and Devonian sections. One development oil well is already producing at initial rates in excess of 200 bopd and 500 mcfpd with further tie-ins planned. The program for the balance of the year is to shoot a 3-D seismic survey and drill an additional eight wells - four of which are currently identified and being licensed.
Macklin
Macklin is an exploration land block (4,336 gross acres - 100% working interest) in Saskatchewan along the Alberta border with potential for Colony gas and Sparky and Cummings oil accumulations. In 2004 Petrobank acquired a 3-D seismic program over most of the lands, and identified several exploratory locations. Since the beginning of July two wells have been drilled, cased, and completed. The first well encountered a new Sparky oil accumulation and the second proved up the horizontal production capability of a Cummings oil accumulation. Each of the two wells demonstrated potential in both the Sparky and Cummings. The horizontal well in the Cummings recently came on-stream at an initial rate of 232 bopd with a current water-cut of less than 5%. The vertical well in the Sparky will be brought on production later in the third quarter, and based on these preliminary results a development program is planned for later in the year that includes 5 horizontal wells in the Cummings and one additional vertical well for Sparky production.
Exploration
Petrobank continued to build its exploration and development position in Southern Alberta close to existing core areas through farm-ins and crown land sales. Petrobank drilled one farm-in well in July and plans to drill up to an additional eight earning wells this year. This activity is continuing to expand our undeveloped land base of 335,000 net acres and our inventory of drilling prospects, and forms the basis for new potential core area additions similar to Macklin and Red Willow.
Princeton
Late in 2004 Petrobank drilled an exploratory coal bed methane ("CBM") well in the Princeton Basin of British Colombia. Petrobank, as operator, holds a 60% working interest in this unique land position. Petrobank and our partners own the Petroleum and Natural Gas rights (including CBM) as well as the coal rights over the entire basin totaling 38,000 acres, excluding the Princeton townsite. The exploratory well confirmed our previous geological interpretation and encountered thick coals containing high gas saturations. In conjunction with our partners and independent experts, considerable effort has been made to evaluate and apply the most effective stimulation technique for this initial well. After completion and fracture treatment, the well flowed free methane with only minor amounts of fresh water, indicating that the coal was fully gas saturated and would probably not require an extended de-watering period. Our near term efforts will be focused on refining the techniques for drilling and completion that will improve gas production rates as we move this project closer to commerciality. Petrobank is extremely encouraged by the results of this first well into a new CBM basin, and we believe we are well advanced on the timeline from exploration concept to commercial project.
Latin American Business Unit
In Colombia, production averaged 1,024 barrels of oil per day (bopd) from our Orito and Neiva blocks in the second quarter a slight decrease from the first quarter average of 1,072 bopd. Production during the quarter was impacted as a result of the Orito-90 well, which produces approximately 285 bopd (gross), being off-line for 45 days due to operational problems encountered during an electrical submersible pump (ESP) replacement by the well operator, Ecopetrol. Our Orito-116 well, targeting a large southwest extension to the main producing region of the Orito field, tested both the Lower A unit sands, and the Upper B, C, & D sands. Initial production tests in the lower A sand units showed positive hydrocarbon potential with water cuts fluctuating between 80 and 90 percent at very low drawdown and inflow potential of greater than 5,000 barrels per day of total fluid. The upper B, C, and D sands tested at unstimulated rates of 200 bopd with water cuts of less than 10 percent. The well was tested from these upper sands over an extended period to determine overall fluid rates, and the decision was made to proceed with a completion that included under-reaming the B, C, and D sands and the upper portion of the A sands followed by the installation of a large volume ESP. Long lead times and logistical and operational difficulties have delayed the installation of the ESP, but the well is expected to be on production in September. The next well at Orito (Orito-117) will be drilled directionally from the same surface location, and is expected to spud in late September.
We have now signed contracts on three exploration blocks and one technical evaluation area (TEA) covering a total of 672,638 acres in the Llanos Basin where we have identified a series of geological trends offering multi-pool/multi-zone prospects that can be effectively identified through the application of 3-D seismic and North American exploration techniques. We are still awaiting final approval of our new exploration block contiguous with our Orito block in the Putumayo Basin (33,755 acres), which is currently held up in a review process between Ecopetrol and the National Hydrocarbons Agency. Recently we have also entered into negotiations for one additional exploration block and three additional TEA's in the Llanos Basin covering an additional 1,855,253 acres. In total these blocks cover 2,561,646 acres (4,000 square miles) of highly prospective land in two of Colombia's most prolific Basins, and would make Petrobank one of the largest exploration landholders in the country. All new exploration blocks are governed by Colombia's new fiscal terms where we earn 100 percent of production subject only to an eight percent initial royalty rate.
The first prospect on these new exploration lands is expected to be drilled on the Joropo Block in the first quarter of 2006. The location for this well has been selected based on 3-D seismic and is interpreted as an up-dip extension to an original well drilled off 2-D seismic in 1985. The discovery well encountered a thin oil zone over water and was abandoned at the time. A follow up 3-D seismic program shot in 2000, indicated that the original well was drilled down structure. Seismic programs are being developed for the other two new exploration contracts, and are being scheduled for the first quarter of 2006.
Our planned initial public offering (IPO) of the Company's subsidiary, Petrominerales Colombia Ltd. is now being considered for the fall of 2005 along with a number of other financing initiatives that will facilitate an acceleration of our exploration and development activities in Colombia.
Heavy Oil Business Unit
Petrobank, through its 84 percent owned subsidiary WHITESANDS INSITU Ltd., is constructing the WHITESANDS pilot project to field-demonstrate our patented THAI(TM) heavy oil recovery process. THAI(TM) is a revolutionary combustion technology for the in-situ recovery of bitumen and heavy oil that combines a vertical air injection well with a horizontal production well. THAI(TM) integrates existing proven technologies and provides the opportunity to create a step change in the development of heavy oil resources globally. During the process a high temperature combustion front is created where part of the oil in the reservoir is burned, generating heat, which reduces the viscosity of the remaining oil allowing it to flow by gravity to the horizontal production well. The combustion front sweeps the oil from the toe to the heel of the horizontal producing well, recovering up to an estimated 80 percent of the original oil-in place while partially upgrading the crude oil in-situ. Petrobank controls all intellectual property rights to the THAI(TM) process and related enhancements, including the patented CAPRI(TM) technology, which offers the potential for further in-situ upgrading through the use of a well-bore integrated catalyst.
THAI(TM) has many potential benefits over other in-situ recovery methods, such as SAGD (Steam Assisted Gravity Drainage). These benefits include higher resource recovery, 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.
On April 12, 2005 Petrobank and WHITESANDS closed a $23.75 million financing with the Richardson Financial Group (RFG). Through this investment RFG acquired a 16 percent interest in WHITESANDS Insitu Ltd. for $14 million and also acquired 3 million common shares of Petrobank for $9.75 million. Effective March 31, 2005, the WHITESANDS project also received an additional $9 million non-dilutionary financing commitment from Technology Partnerships Canada (TPC) bringing the total third party funding of the project to $32.75 million. In addition, Petrobank has filed an application for further funding under the Innovative Energy Technologies Program of the Government of Alberta for up to $10 million.
Project activities at our WHITESANDS - THAI(TM) project continued during the second quarter. Drilling of the three horizontal production wells, three vertical air injection wells and 17 additional observation wells are expected to be completed by the end of September. All major equipment has been ordered within budget and delivery is on schedule. Fabrication and construction contracts are in place and the plant is being constructed using modular design methods where key elements of the project are manufactured offsite with final assembly at the project site. Rain delays slowed civil work progress on the access road and plant site, which has impacted the overall schedule by approximately one month. Construction activities are targeted to begin by September with completion forecasted by year-end. Capital costs continue to be in line with earlier estimates and startup is anticipated in early 2006.
Internationally, we continue to work with various state oil companies to jointly evaluate the THAI(TM) technology and potential resource accumulations. The ultimate goal is to capture a global portfolio of heavy oil resources where the application of our new technology can lead to greatly improved recovery rates and significant long-term value growth for the Company.
OUTLOOK
As we move into the third quarter of 2005, our activity level in all three business units is accelerating. In Canada, after a slightly delayed start, we are well on track to achieve our target of doubling our production by year-end. Our development activities at Jumpbush and Red Willow are being complimented by new exploration successes at Macklin and elsewhere, along with some very encouraging results from our Princeton CBM project. In Colombia, we anticipate having our Orito-116 well on-stream in September and our next well Orito-117 spudding in the same month. Our Colombian exploration program is in high gear with our first drilling location in the Llanos Basin programmed for early 2006, and a number of new exploration projects commencing on our growing land base. In our Heavy Oil Business Unit, the WHITESANDS pilot project is under construction and on target to deliver initial results in early 2006. We continue to refine our existing technology base surrounding the THAI(TM) and CAPRI(TM) technologies, develop new patents, and pursue new resource capture opportunities both domestically and internationally.
As we continue to convert "vision to value", we remain convinced that Petrobank offers our shareholders an extraordinary opportunity to participate in the upside inherent in each of our three Business Units.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following Management's Discussion and Analysis (MD&A) is dated August 12, 2005 and should be read in conjunction with the unaudited consolidated financial statements of the Company for the three and six month periods ended June 30, 2005, MD&A for the year ended December 31, 2004, and the audited consolidated financial statements for the year ended December 31, 2004. Additional information for the Company can be found at www.sedar.com. In addition to historical information, the MD&A contains forward-looking statements that reflect management's objectives and expectations as at the date of this report, which involve risks and uncertainties. The Company's actual results may differ materially from those anticipated in these forward-looking statements.
Natural gas volumes have been converted to barrels of oil equivalent (boe) so that six thousand cubic feet (mcf) of natural gas equals one barrel based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. Boes may be misleading, particularly if used in isolation. This report contains financial terms that are considered non-GAAP measures such as cash flow from operations, cash flow per share, net debt, and operating netback. These measures are commonly utilized in the oil and gas industry and are considered informative for our shareholders. Specifically, cash flow from operations and cash flow per share reflect cash generated from operating activities before changes in non-cash working capital. We consider these measures important as they demonstrate our ability to generate sufficient cash to fund future growth opportunities and repay debt. All amounts are in Canadian dollars, unless otherwise stated.
Production
Oil and NGL production in Canada during the second quarter averaged 273 barrels per day (bpd), a decrease from the 317 bpd produced in the first quarter and the 1,850 bpd produced in the second quarter of 2004. The decrease from the prior year period is due to a series of dispositions during 2004 including the $96.1 million sale in December 2004. Production from properties sold during 2004 accounted for 2,716 boepd (51 percent natural gas) in the second quarter of 2004 and eliminated all of the Company's heavy oil production. Second quarter natural gas production decreased from the prior year period, also as a result of these dispositions. The Company averaged 11.2 million cubic feet per day (mmcfpd) in the second quarter compared to 9.7 mmcfpd in the first quarter and 14.6 mmcfpd a year earlier. Total Canadian production for the second quarter was 2,147 boepd, an 11 percent increase from the first quarter and a 50 percent decrease from the same period last year. Excluding production from properties sold during 2004, Canadian production increased 37 percent from the second quarter of 2004.
Colombian oil sales averaged 1,024 bpd in the second quarter, a slight decrease from the first quarter average of 1,072 bpd and lower than the 1,354 bpd averaged in the second quarter of 2004. Second quarter production was impacted as a result of the Orito-90 well, which produces approximately 285 bopd (gross), being off-line for 45 days due to operational problems encountered during an electrical submersible pump (ESP) replacement by the well operator, Ecopetrol. Production is expected to increase with planned well interventions and upon finalization of the completion of the Orito-116 well.
Average Benchmark Prices and US$ Exchange Rate
For the three months ended June 30, March 31, June 30,
2005 2005 2004
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WTI crude oil (US$/bbl) 53.17 49.84 38.32
WTI crude oil (Cdn$/bbl) 66.14 61.15 52.11
Bow River heavy oil differential
(US$/bbl) 20.28 18.55 11.02
NYMEX natural gas (US$/mmbtu) (1) 6.73 6.27 5.97
AECO (daily) natural gas (Cdn$/mcf) 7.38 6.90 6.99
US$/Cdn$ exchange rate 0.80 0.82 0.74
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(1) Prices quoted are near-month contract prices for settlement during
the next month.
Realized Prices
The average Canadian oil and NGL price received in the second quarter was $63.60 per barrel, a 34 percent increase from the $47.59 per barrel received in the first quarter and a 133 percent increase from the $27.35 per barrel received in the second quarter of 2004. The average price received increased significantly from 2004 periods due to higher commodity prices, hedges that expired on December 31, 2004, and the disposition of heavy oil production in the fourth quarter of 2004.
The average natural gas price received in the second quarter was $6.60 per mcf, a 9 percent increase from $6.08 per mcf received in the first quarter and a 10 percent increase from the $5.99 per mcf received in the second quarter of 2004. In 2004, the natural gas price was impacted by a natural gas price collar on 10,000 mcfpd with a ceiling AECO price of $6.27 per mcf. This contract expired on December 31, 2004. Natural gas prices continue to reflect the impact of the Company's long-term physical natural gas sales and transportation contracts.
Oil sales prices in Colombia averaged US$42.06 per barrel in the second quarter, representing a US$11.11 per barrel (21% of WTI) differential to WTI compared to a differential of US$9.80 per barrel (20% of WTI) in the first quarter and US$4.76 per barrel (12% of WTI) in the second quarter of 2004. The lower differential in 2004 was a result of a fixed differential at WTI prices above $30.00 per barrel pursuant to the original marketing agreement for Orito production that was amended in December 2004.
Royalties
Royalties decreased from $3.1 million in the second quarter of 2004 to $2.2 million in the current period. Canadian royalties as a percentage of revenue increased slightly from 21.0 percent in the second quarter of 2004 to 21.9 percent in the current period. Canadian royalty rates are expected to average approximately 24 percent throughout the remainder of 2005. Colombian royalties remained constant at a rate of 8 percent.
Production Expenses
Consolidated production expenses increased to $2.3 million from $2.0 million in the first quarter and decreased from $3.7 million in the second quarter of 2004. Production expenses per unit of production in Canada were $7.12 per boe, increases of 5 percent from $6.76 per boe in the first quarter and $6.77 per boe in the second quarter of 2004. Production expenses in Colombia averaged $10.09 per barrel during the quarter, a 19 percent increase from the first quarter average of $8.46 per barrel and an 18 percent increase from the second quarter 2004 average of $8.53 per barrel. The increase in Colombian per unit operating costs is primarily a result of the fixed nature of certain costs combined with lower production volumes.
General and Administrative Expenses
General and administrative expenses were $2.2 million in the second quarter of 2005 compared to $2.1 million in both the first quarter and the comparative 2004 period.
Interest on Bank Debt
The Company's credit facility was undrawn throughout the second quarter of 2005 compared to $24.8 million drawn at the end of the same period a year earlier. As a result, interest on bank debt decreased from $0.3 million in the second quarter of 2004 to nil in 2005.
Interest on Subordinated Notes
Interest on subordinated notes totaled $2.1 million during the second quarter, compared to $2.8 million during the same period last year. The decrease relates to the repurchase of $31.5 million of notes in the first half of 2005.
Depletion, Depreciation and Accretion
Depletion, depreciation and accretion expense increased to $3.8 million in the second quarter ($13.13 per boe) from $3.6 million in the first quarter ($13.33 per boe) and decreased from $8.4 million ($16.32 per boe) in the second quarter of 2004. On a unit-of-production basis in Canada, the rate fell to $10.85 per boe compared to $14.62 in the second quarter of 2004. The rate decreased primarily as a result of reserve additions from fourth quarter 2004 drilling at Jumpbush. In Colombia, the rate was $17.91 per barrel in the second quarter of 2005, compared to $21.68 per barrel a year earlier. The decrease is a result of reserve additions recorded in the fourth quarter of 2004.
Gain
On April 12, 2005 the Company sold a 16 percent interest in its previously wholly owned subsidiary, WHITESANDS Insitu Ltd. (WHITESANDS) for proceeds net of issuance costs totaling $12.7 million. The reduction in the Company's interest in WHITESANDS resulted in a pre-tax gain to the Company of $4.7 million.
Loss on Repurchase of Subordinated Notes
On April 22, 2005 the Company repurchased an additional $17.2 million face value of subordinated notes, reducing the outstanding face value to $68.9 million. The Company recorded a pre-tax loss of $0.7 million on the transaction. Through the first half of 2005 the outstanding face value of subordinated notes has been reduced by a total of 31 percent or $31.5 million, which results in annualized cash interest savings of $2.8 million until maturity on July 31, 2006.
Other Income (Expense)
Due primarily to interest income earned on the Company's significant cash balance throughout the second quarter of 2005, other income totaled $0.3 million in the current period compared to other expenses of $22,000 a year earlier.
Capital Taxes
The Company's second quarter capital taxes totaled $0.5 million (2004 - $0.3 million) including Large Corporations Tax in Canada and presumptive income taxes in Colombia.
Future Income Tax Recovery
The Company's second quarter future income tax recovery totaled $0.6 million compared to a $1.0 million recovery in the second quarter of 2004. A future income tax recovery was recorded despite recognizing net income in the current period primarily due to the gain reflected on the WHITESANDS financing being non-taxable.
Capital Expenditures Three months ended June 30, 2005 2004 ------------------------------------------------------------------------ Business Unit Canada $ 8,722 $ 7,120 Heavy Oil 2,661 457 Latin America (Colombia) 5,459 2,418 ------------------------------------------------------------------------ Total $ 16,842 $ 9,995 ------------------------------------------------------------------------ ------------------------------------------------------------------------ ------------------------------------------------------------------------ Six months ended June 30, 2005 2004 ------------------------------------------------------------------------ Business Unit Canada $ 12,191 $ 15,536 Heavy Oil 5,071 937 Latin America (Colombia) 10,360 8,235 ------------------------------------------------------------------------ Total $ 27,622 $ 24,708 ------------------------------------------------------------------------ ------------------------------------------------------------------------
Canadian Business Unit expenditures during the second quarter related primarily the Jumpbush property, including drilling, completions and compression for the plant expansion. Heavy Oil expenditures related to the WHITESANDS Insitu Ltd. - THAI(TM) pilot project including drilling observation wells and engineering design for the pilot. Latin American expenditures related primarily to well interventions at Neiva and drilling and completing the Orito-116 well in Colombia.
Liquidity and Capital Resources
Effective March 31, 2005 Technology Partnerships Canada (TPC) announced their commitment to invest up to $9 million towards the development and field demonstration of the Company's THAI(TM) technology at the WHITESANDS pilot project. TPC's investments will be made quarterly based on 20.134 percent of eligible expenditures. The fist claim is scheduled for September 2005 and will be made retroactive to include expenditures incurred since August 26, 2004.
On April 12, 2005 the Company closed a $23.75 million financing involving an investment in Petrobank and its wholly owned subsidiary, WHITESANDS. The investor acquired a 16 percent interest in WHITESANDS for a $14 million equity commitment and 3 million common shares of Petrobank at a price of $3.25 per share for aggregate gross proceeds of $23.75 million.
At June 30, 2005 net debt totaled $34.4 million, including the book value of outstanding subordinated notes ($66.7 million). The subordinated notes are not callable and mature in July 2006. Working capital at June 30, 2005 totaled $32.3 million.
In August, Petrobank obtained a new senior secured credit facility increasing the maximum borrowing base available to $20 million from its previous level of $10 million. In addition, a further $15 million credit facility was obtained to fund the acquisition and/or development of producing or proved non-producing petroleum and natural gas reserves in Canada. This development facility was secured primarily to provide funding flexibility for the Company's Jumpbush development program.
Subsequent to June 30, 2005, warrant holders exercised 399,000 warrants in return for 399,000 common shares at an exercise price of $4.00 per share, resulting in cash proceeds of $1.6 million. The total number of warrants outstanding has been reduced to 1,021,300, which upon exercise would result in additional proceeds of $4.1 million.
Changes in Accounting Policies
Financial Instruments
Effective January 1, 2005 the Company retroactively adopted the revised recommendations of the Canadian Institute of Chartered Accountants (CICA) section 3861, "Financial Instruments - Disclosure and Presentation", on the classification of obligations that must or could be settled with an entity's own equity instruments. The new recommendation requires securities such as Petrobank's subordinated notes to be reclassified from equity to liabilities on the balance sheet. There is no impact on earnings per share but interest expense on the subordinated notes and the related future income tax recovery are deducted when calculating net income rather than net income attributable to common shareholders as previously reported. Note 2 discloses the impact of the adoption of the revised recommendations of CICA section 3861 on the consolidated financial statements.
Summary of Quarterly Results
2005
Q2 Q1
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Financial ($000s except where noted)
Oil and natural gas revenue 13,206 11,382
Cash flow from operations (1) 4,575 3,396
Per share - basic and diluted ($) 0.08 0.06
Net income (loss) 4,702 (248)
Per share - basic and diluted ($) 0.08 -
Capital expenditures 16,842 10,780
Operations
Canadian operating netbacks by product (2)
Light/medium oil and NGL sales price ($/bbl) 63.60 47.59
Royalties 13.94 9.76
Production expenses 10.82 9.99
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Operating netback 38.84 27.84
Heavy oil sales price ($/bbl) - -
Royalties - -
Production expenses - -
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Operating netback - -
Natural gas sales price ($/mcf) 6.60 6.08
Royalties 1.45 1.19
Production expenses 1.10 1.02
Transportation expenses 0.21 0.29
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Operating netback 3.84 3.58
Oil equivalent sales price ($/boe) 42.63 38.30
Royalties 9.35 7.59
Production expenses 7.12 6.76
Transportation expenses 1.13 1.43
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Operating netback 25.03 22.52
Colombian operating netback ($/bbl)
Oil sales price 52.34 49.13
Royalties 4.19 3.93
Production expenses 10.09 8.46
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Operating netback 38.06 36.74
Average daily production
Canada - light/medium oil and NGL (bbls) 273 317
Canada - heavy oil (bbls) - -
Canada - natural gas (mcf) 11,245 9,662
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Total Canada (boe) 2,147 1,927
Colombia - oil (bbls) 1,024 1,072
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Total Company (boe) 3,171 2,999
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Summary of Quarterly Results
2004
Q4 Q3 Q2 Q1
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Financial ($000s except where noted)
Oil and natural gas revenue 17,028 18,700 18,175 19,474
Cash flow from operations (1) 4,388 6,166 6,215 6,628
Per share - basic and diluted ($) 0.08 0.11 0.11 0.12
Net income (loss) 6,630 (1,727) (1,822) (2,248)
Per share - basic and diluted ($) 0.12 (0.03) (0.03) (0.04)
Capital expenditures 14,272 8,921 9,995 14,713
Operations
Canadian operating netbacks by product (2)
Light/medium oil and NGL
sales price ($/bbl) 21.05 27.03 29.54 27.50
Royalties 10.18 9.79 8.93 8.97
Production expenses 9.11 6.78 7.14 6.81
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Operating netback 1.76 10.46 13.47 11.72
Heavy oil sales price ($/bbl) 15.96 26.95 22.36 24.46
Royalties 4.36 5.31 3.29 3.45
Production expenses 9.89 9.08 10.69 8.52
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Operating netback 1.71 12.56 8.38 12.49
Natural gas sales price ($/mcf) 5.80 6.13 5.99 6.09
Royalties 1.18 1.10 1.08 1.20
Production expenses 1.18 1.08 0.94 1.06
Transportation expenses 0.23 0.23 0.30 0.28
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Operating netback 3.21 3.72 3.67 3.55
Oil equivalent sales price ($/boe) 29.90 33.09 32.22 32.18
Royalties 7.53 7.20 6.79 7.15
Production expenses 7.81 6.90 6.77 6.82
Transportation expenses 0.93 0.85 1.02 0.97
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Operating netback 13.63 18.14 17.64 17.24
Colombian operating netback ($/bbl)
Oil sales price 46.45 48.69 45.62 36.63
Royalties 3.71 3.96 3.62 2.93
Production expenses 7.08 7.10 8.53 7.89
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Operating netback 35.66 37.63 33.47 25.81
Average daily production
Canada - light/medium oil
and NGL (bbls) 993 1,065 1,288 1,332
Canada - heavy oil (bbls) 424 564 562 703
Canada - natural gas (mcf) 17,880 16,231 14,592 16,069
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Total Canada (boe) 4,397 4,334 4,282 4,713
Colombia - oil (bbls) 1,155 1,229 1,354 1,702
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Total Company (boe) 5,552 5,563 5,636 6,415
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Summary of Quarterly Results
2003
Q4 Q3
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Financial ($000s except where noted)
Oil and natural gas revenue 20,540 13,962
Cash flow from operations (1) 6,424 3,562
Per share - basic and diluted ($) 0.12 0.08
Net income (loss) (20,248) (3,398)
Per share - basic and diluted ($) (0.38) (0.07)
Capital expenditures 27,338 28,065
Operations
Canadian operating netbacks by product (2)
Light/medium oil and NGL sales price ($/bbl) 26.81 28.09
Royalties 5.89 6.01
Production expenses 6.22 5.24
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Operating netback 14.70 16.84
Heavy oil sales price ($/bbl) 22.95 24.86
Royalties 2.36 4.22
Production expenses 11.18 6.83
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Operating netback 9.41 13.81
Natural gas sales price ($/mcf) 5.89 5.49
Royalties 0.88 0.82
Production expenses 1.26 1.79
Transportation expenses 0.28 0.51
------------------------------------------------------------------------
Operating netback 3.47 2.37
Oil equivalent sales price ($/boe) 30.57 28.76
Royalties 5.12 5.35
Production expenses 7.55 7.06
Transportation expenses 0.85 0.83
------------------------------------------------------------------------
Operating netback 17.05 15.52
Colombian operating netback ($/bbl)
Oil sales price 31.66 31.37
Royalties 2.53 2.44
Production expenses 15.62 9.24
------------------------------------------------------------------------
Operating netback 13.51 19.69
Average daily production
Canada - light/medium oil and NGL (bbls) 2,147 2,097
Canada - heavy oil (bbls) 784 812
Canada - natural gas (mcf) 17,702 6,581
------------------------------------------------------------------------
Total Canada (boe) 5,881 4,005
Colombia - oil (bbls) 1,374 1,166
------------------------------------------------------------------------
Total Company (boe) 7,255 5,171
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) 2003 and 2004 periods restated for change in accounting policy.
(2) Sales prices are shown after hedging costs. The hedging costs
relating to oil sales were net against the Canadian light/medium
oil and NGL price, except for the Company's 300 bopd fixed price
crude oil contract (WTI - US$27.74) that was net against the heavy
oil sales price in 2004. The majority of these hedges expired on
December 31, 2004.
Highlights
Three months ended Six months ended
June 30, % June 30, %
2005 2004 change 2005 2004 change
------------------------------------------------------------------------
Financial
($000s, except where noted)
Oil and natural
gas revenue 13,206 18,175 (27) 24,588 37,649 (35)
Cash flow from
operations (1) 4,575 6,215 (26) 7,971 12,843 (38)
Per share - basic
and diluted ($) (2) 0.08 0.11 (27) 0.14 0.23 (39)
Net income (loss) 4,702 (1,822) 4,454 (4,070)
Per share - basic
and diluted ($) 0.08 (0.03) 0.08 (0.07)
Capital expenditures 16,842 9,995 69 27,622 24,708 12
Total assets 190,366 220,113 (14) 190,366 220,113 (14)
Net debt (3) 34,388 121,803 (72) 34,388 121,803 (72)
Common shares outstanding,
end of period (000s)
Basic 58,392 54,732 7 58,392 54,732 7
Diluted 63,828 59,582 7 63,828 59,582 7
Operations (4)
Canadian operating netback
($/boe except where noted)
Oil and NGL revenue
($/bbl) (5) 63.60 27.35 133 55.04 26.89 105
Natural gas revenue
($/mcf) (5) 6.60 5.99 10 6.36 6.04 5
Oil and natural gas
revenue (5) 42.63 32.22 32 40.59 32.19 26
Royalties 9.35 6.79 38 8.52 6.98 22
Production expenses 7.12 6.77 5 6.95 6.80 2
Transportation
expenses 1.13 1.02 11 1.27 0.99 28
------------------------------------------------------------------------
Operating netback 25.03 17.64 42 23.85 17.42 37
Colombian operating
netback ($/bbl)
Oil revenue 52.34 45.62 15 50.70 40.61 25
Royalties 4.19 3.62 16 4.05 3.24 25
Production expenses 10.09 8.53 18 9.26 8.13 14
------------------------------------------------------------------------
Operating netback 38.06 33.47 14 37.39 29.24 28
Average daily production
Canada - oil and
NGL (bbls) 273 1,850 (85) 295 1,942 (85)
Canada - natural
gas (mcf) 11,245 14,592 (23) 10,459 15,331 (32)
------------------------------------------------------------------------
Total Canada (boe) 2,147 4,282 (50) 2,038 4,497 (55)
Colombia -
oil (bbls) 1,024 1,354 (24) 1,048 1,528 (31)
------------------------------------------------------------------------
Total Company (boe) 3,171 5,636 (44) 3,086 6,025 (49)
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) Cash flow from operations before changes in other non-cash items and
asset retirement obligations settled. 2004 amount has been restated
for change in accounting policy.
(2) Calculated based on cash flow from operations before changes in
other non-cash items and asset retirement obligations settled.
(3) Includes working capital (deficiency) and subordinated notes.
(4) 6 mcf of natural gas is equivalent to 1 barrel of oil equivalent
(boe).
(5) Canadian sales prices are shown after hedging costs. The majority
of these hedges expired on December 31, 2004.
Consolidated Balance Sheets
(Unaudited, thousands of Canadian dollars)
As at June 30, 2005 December 31, 2004
------------------------------------------------------------------------
(Restated
- Note 2)
Assets
Current assets
Cash and cash equivalents $ 35,461 $ 75,509
Accounts receivable and other
current assets 17,814 13,063
------------------------------------------------------------------------
53,275 88,572
Capital assets 137,091 116,820
------------------------------------------------------------------------
$ 190,366 $ 205,392
------------------------------------------------------------------------
------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and
accrued liabilities $ 20,959 $ 27,893
Obligations under gas sale and
transportation contracts 6,067 6,477
Asset retirement obligations (Note 5) 2,870 2,870
Future income tax liability 13,485 15,492
Subordinated notes (Note 6) 66,704 95,862
------------------------------------------------------------------------
110,085 148,594
Non-controlling interest (Note 3) 8,406 -
Shareholders' equity
Common shares (Note 4) 83,391 73,157
Contributed surplus (Note 4) 914 525
Deficit (12,430) (16,884)
------------------------------------------------------------------------
71,875 56,798
------------------------------------------------------------------------
$ 190,366 $ 205,392
------------------------------------------------------------------------
------------------------------------------------------------------------
See accompanying notes to these consolidated financial statements.
Consolidated Statements of Operations and Retained Earnings
(Unaudited, thousands of Canadian dollars, except per share amounts)
Three months ended Six months ended
June 30, June 30,
2005 2004 2005 2004
------------------------------------------------------------------------
(Restated (Restated
- Note 2) - Note 2)
Revenues
Oil and natural gas $ 13,206 $ 18,175 $ 24,588 $ 37,649
Royalties (2,216) (3,093) (3,911) (6,612)
------------------------------------------------------------------------
10,990 15,082 20,677 31,037
------------------------------------------------------------------------
Expenses
Production 2,332 3,676 4,321 7,824
Transportation 220 395 468 811
General and administrative 2,223 2,087 4,371 3,786
Interest on bank debt - 251 - 729
Interest on subordinated
notes (Note 2) 2,125 2,844 4,673 5,668
Depletion, depreciation
and accretion 3,788 8,368 7,388 17,401
------------------------------------------------------------------------
10,688 17,621 21,221 36,219
------------------------------------------------------------------------
Income (loss) before other
items and taxes 302 (2,539) (544) (5,182)
Gain (Note 3) 4,744 - 4,744 -
Loss on repurchase of
subordinated notes (Note 6) (676) - (542) -
Other income (expense) 304 (22) 571 (553)
------------------------------------------------------------------------
Net income (loss) before taxes 4,674 (2,561) 4,229 (5,735)
Capital taxes (539) (274) (945) (537)
Future income tax recovery 567 1,013 1,170 2,202
------------------------------------------------------------------------
Net income (loss) 4,702 (1,822) 4,454 (4,070)
Deficit, beginning of period (17,132) (19,965) (16,884) (17,717)
------------------------------------------------------------------------
Deficit, end of period $ (12,430) $ (21,787) $ (12,430) $ (21,787)
------------------------------------------------------------------------
------------------------------------------------------------------------
Basic and diluted earnings
(loss) per share (Note 4) $ 0.08 $ (0.03) $ 0.08 $ (0.07)
------------------------------------------------------------------------
------------------------------------------------------------------------
See accompanying notes to these consolidated financial statements.
Consolidated Statements of Cash Flow
(Unaudited, thousands of Canadian dollars)
Three months ended Six months ended
June 30, June 30,
2005 2004 2005 2004
------------------------------------------------------------------------
(Restated (Restated
- Note 2) - Note 2)
Operating Activities
Net income (loss) $ 4,702 $ (1,822) $ 4,454 $ (4,070)
Depletion, depreciation
and accretion 3,788 8,368 7,388 17,401
Non-cash stock based
compensation 230 84 434 166
Future income tax recovery (567) (1,013) (1,170) (2,202)
Amortization of discount on
subordinated notes (Note 6) 490 598 1,067 1,173
Gain (4,744) - (4,744) -
Loss on repurchase of
subordinated notes 676 - 542 -
Loss recorded on disposition
of sales contract - - - 375
------------------------------------------------------------------------
Cash flow from operations 4,575 6,215 7,971 12,843
Asset retirement
obligations settled (37) (127) (37) (127)
Changes in other non-cash
working capital (1,194) (1,005) (4,952) (4,992)
------------------------------------------------------------------------
3,344 5,083 2,982 7,724
------------------------------------------------------------------------
Financing Activities
Repurchase / redemption of
subordinated notes (Note 6) (17,230) - (30,767) -
Issuance of shares by
subsidiary (Note 3) 12,651 - 12,651 -
Issuance of common
shares (Note 4) 9,433 125 9,851 410
Repayment of bank debt - 2,215 - (5,259)
Repayment of debenture - - - (14,014)
Amortization of obligations
under gas hedging contracts (206) (202) (410) (404)
Changes in other non-cash
working capital (3,800) - (3,800) -
------------------------------------------------------------------------
848 2,138 (12,475) (19,267)
------------------------------------------------------------------------
Investing Activities
Expenditures on capital
assets (16,842) (9,995) (27,622) (24,708)
Proceeds on disposition of
capital assets - 4,174 - 42,311
Changes in other non-cash
working capital 708 (1,400) (2,933) (6,060)
------------------------------------------------------------------------
(16,134) (7,221) (30,555) 11,543
------------------------------------------------------------------------
Net change in cash position (11,942) - (40,048) -
Cash and cash equivalents,
beginning of period 47,403 - 75,509 -
------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ 35,461 $ - $ 35,461 $ -
------------------------------------------------------------------------
------------------------------------------------------------------------
See accompanying notes to these consolidated financial statements.
Notes to the Consolidated Financial Statements
As at and for the three and six month periods ended June 30, 2005 (All tabular amounts are expressed in thousands of Canadian dollars, except share amounts)
Note 1 - Significant Accounting Policies
The interim consolidated financial statements as at and for the three and six month periods ended June 30, 2005 should be read in conjunction with the audited consolidated financial statements as at and for the year ended December 31, 2004. The notes to these interim consolidated financial statements do not conform in all respects to the note disclosure requirements of generally accepted accounting policies for annual financial statements. These interim consolidated financial statements are prepared using the same accounting policies and methods of computation as disclosed in the audited consolidated financial statements as at and for the year ended December 31, 2004 except as described in Note 2. Certain prior period amounts have been reclassified to conform with current presentation.
Note 2 - Changes in Accounting Policies
Financial Instruments
Effective January 1, 2005 the Company retroactively adopted the new recommendations of the Canadian Institute of Chartered Accountants (CICA) section 3861, "Financial Instruments - Disclosure and Presentation", on the classification of obligations that must or could be settled with an entity's own equity instruments. The new recommendation requires securities such as Petrobank's subordinated notes to be reclassified from equity to liabilities on the balance sheet. For the three and six month periods ended June 30, 2004 there is no impact on earnings per share but interest expense on the subordinated notes (3 months - $2.8 million; 6 months - $5.7 million) and the related future income tax recovery (3 months - $0.9 million; 6 months - $1.9 million) are deducted when calculating net income rather than the net income attributable to common shareholders as previously reported.
Note 3 - Gain
On April 12, 2005 the Company sold a 16 percent interest in its previously wholly owned subsidiary, WHITESANDS Insitu Ltd. (WHITESANDS) for proceeds of $14 million ($12.7 million net of issuance costs). The reduction in the Company's interest in WHITESANDS resulted in a pre-tax gain of $4.7 million. The cash investment in WHITESANDS totaled $8.9 million to June 30, 2005, with the remaining $3.8 million to be invested in up to two additional tranches ending no later than April 15, 2006.
Under the financing agreement, on an annual basis, the investor may request a third-party valuation of WHITESANDS and may require the Company to repurchase the investor's interest in WHITESANDS at fair market value. The Company has the option to fund this repurchase with cash or through the exchange of Petrobank common shares, valued at 95 percent of the 10-day weighted average trading price prior to the date of exchange.
Note 4 - Share Capital
As at June 30, 2005 the Company had outstanding 58,392,246 common shares, 3,895,901 stock options, 1,420,300 share purchases warrants, and 120,000 deferred share units.
Common Share Continuity Number Amount
------------------------------------------------------------------------
Balance at December 31, 2004 54,956,396 $ 73,157
Exercise of stock options 435,850 1,014
Issued through private placement 3,000,000 9,750
Share issue costs - (913)
Tax effect of share issue costs - 338
Transfer from contributed surplus
related to stock options exercised - 45
------------------------------------------------------------------------
Balance at June 30, 2005 58,392,246 $ 83,391
------------------------------------------------------------------------
------------------------------------------------------------------------
Weighted -
Average
Stock Option Continuity Number Exercise Price
------------------------------------------------------------------------
Balance at December 31, 2004 3,381,751 $ 2.47
Granted 1,182,500 4.01
Exercised (435,850) (2.33)
Expired/cancelled (232,500) (2.61)
------------------------------------------------------------------------
Balance at June 30, 2005 3,895,901 $ 2.94
------------------------------------------------------------------------
------------------------------------------------------------------------
Share Purchase Warrants
The 1,420,300 outstanding share purchase warrants allow holders to purchase an equivalent number of common shares at $4.00 per share on or before May 6, 2006. Subsequent to June 30, 2005 warrant holders exercised 399,000 warrants for cash proceeds of $1.6 million, reducing the total number of warrants outstanding to 1,021,300.
Deferred Share Units
In March 2005, the Company granted 120,000 deferred share units under the Company's deferred share compensation plan that allows holders to receive one common share per unit upon payment of $0.05 per share. The units vest after three years and expire after ten years. The plan allows the Company to grant up to 500,000 units.
Earnings Per Share
Basic and diluted earnings (loss) per share have been calculated based on net income (loss) divided by the weighted average number of common shares outstanding for the three month period ended June 30, 2005 of 57,852,276 (2004 - 54,683,858) and for the six month period ended June 30, 2005 of 56,456,953 (2004 - 54,623,228). The diluted calculations include 268,930 (2004 - nil) additional shares for the three month period and 534,904 (2004 - nil) additional shares for the six month period ended June 30, 2005 for the potential impact of stock options, share purchase warrants, and deferred share units.
Stock Based Compensation
The fair value of stock options and deferred share units granted have been estimated on their respective grant dates using the Black Scholes option-pricing model using the following assumptions:
Three months ended June 30, 2005 2004 ------------------------------------------------------------------------ Risk free interest rate 4.25% 4.5% Dividend rate 0% 0% Expected life (years) 4 4 Expected volatility 50% 30% ------------------------------------------------------------------------ ------------------------------------------------------------------------
The average value per option and deferred share unit granted during the three and six month periods ended June 30, 2005 were $1.43 and $1.29 respectively, as at the date of grant.
Note 5 - Asset Retirement Obligations
Changes to asset retirement obligations were as follows:
Three months ended Six months ended
June 30, June 30,
2005 2004 2005 2004
------------------------------------------------------------------------
Asset retirement obligations,
beginning of period $ 2,705 $ 8,270 $ 2,870 $ 9,602
Obligations incurred 150 100 219 403
Obligations settled (37) (127) (37) (127)
Obligations disposed - (125) - (1,166)
Accretion expense 61 186 120 402
Changes in estimated future
cash flows and other (9) (395) (302) (1,205)
------------------------------------------------------------------------
Asset retirement obligations,
end of period $ 2,870 $ 7,909 $ 2,870 $ 7,909
------------------------------------------------------------------------
------------------------------------------------------------------------
The total undiscounted amount of estimated cash flows required to settle the obligations is $15.4 million (2004 - $24.5 million) using an inflation factor of 1.5 percent. The obligations have been recorded at their present value using a credit-adjusted risk free rate of 9 percent. Most of these obligations are not expected to be paid for several years extending up to 36 years in the future, and are expected to be funded from general Company resources at the time of settlement.
Note 6 - Subordinated Notes
Petrobank's subordinated notes are unsecured and subordinate to the Company's existing credit facility and any other senior debt that may be outstanding from time to time. Interest on the notes is payable quarterly at a rate of 9 percent per annum and the notes mature on July 31, 2006. The notes may be repaid at their face value prior to their maturity date and the Company has the option of issuing common shares, at market price, to settle quarterly interest payments as well as the principal amount. The notes were recorded at fair value on issuance and the discount to face value is being amortized to interest on subordinated notes over the term of the notes.
On January 13, 2005, the Company repurchased $14.3 million face value of outstanding subordinated notes through a substantial issuer bid at a price including accrued interest of $95 per $100 face value at a cost of $13.6 million. The Company recorded a pre-tax gain of $0.1 million on this transaction.
On April 22, 2005 the Company repurchased an additional $17.2 million face value of notes at par resulting in a pre-tax loss of $0.7 million. Through the first half of 2005 the outstanding face value has been reduced by 31 percent to $68.9 million.
Carrying Value Face Value
------------------------------------------------------------------------
Balance at December 31, 2004 $ 95,862 $ 100,438
Amortization of discount 1,067 -
Repurchased - January 13, 2005 (13,671) (14,302)
Repurchased - April 22, 2005 (16,554) (17,227)
------------------------------------------------------------------------
Balance at June 30, 2005 $ 66,704 $ 68,909
------------------------------------------------------------------------
------------------------------------------------------------------------
Note 7 - Commitments and Contingencies
The Company has signed contracts for three new exploration blocks and one technical evaluation area (TEA) in the Llanos Basin of Colombia with the National Hydrocarbon Agency (ANH). The first-phase commitments (12 to 24 months) include reprocessing 2-D and 3-D seismic, shooting additional 2-D seismic, and drilling one well on the Joropo Block in the Llanos Basin. Total first-phase commitments are estimated to be approximately US$8.4 million. Upon completion of the first-phase the Company has the option to proceed with second-phase commitments, including the drilling of prospective wells identified during the first-phase, or it can elect not to proceed with any further expenditures and return the block or TEA to the ANH.
The Company is also negotiating two additional exploration blocks and three additional TEA's in Colombia. One exploration block is in the Putumayo Basin with the remainder located in the Llanos Basin. First-phase commitments (12 months) would include reprocessing 2-D seismic, shooting additional 2-D and 3-D seismic, and performing feasibility studies for Petrobank's patented THAI(TM) heavy oil recovery process. Total first-phase commitments are estimated to be approximately US$3 million.
Petrobank is committed to payments under operating leases for office space, net of sub-lease arrangements, as follows:
Remainder of 2005 $ 275
2006 661
2007 301
------------------------------------------------------------------------
$ 1,237
------------------------------------------------------------------------
------------------------------------------------------------------------
Note 8 - Government Assistance
Effective March 31, 2005, Technology Partnerships Canada (TPC) announced their commitment to invest up to $9 million towards the development and field demonstration of the Company's THAI(TM) technology at the WHITESANDS pilot project. Under the TPC funding commitment, TPC has agreed to contribute 20.134 percent of eligible expenditures for the WHITESANDS project to a maximum of $9 million. Upon commercialization of the THAI(TM) technology TPC would be entitled to receive a royalty, based on gross business revenue, of up to three percent until December 31, 2017. This period is to be extended until no later than December 31, 2022 if cumulative royalty payments made under the agreement are less than $26.2 million. As of June 30, 2005 no amounts of assistance have been reflected in the financial statements. The first claim scheduled for September 2005 will be made retroactive and include eligible expenses incurred since August 26, 2004.
Note 9 - Subsequent Events
In August 2005, Petrobank obtained a new senior secured credit facility consisting of a revolving operating demand loan with a $20 million borrowing base plus a $15 million acquisition/development loan. Under the operating loan interest is charged on drawn amounts at bank prime plus 0.25 percent or Bankers' Acceptance fee rates of 1.25 percent.
The $15 million acquisition/development loan was obtained to fund acquisitions and/or development of producing or proved non-producing petroleum and natural gas reserves in Canada. Interest is charged on drawn amounts at a rate of bank prime plus 0.5 percent.
Advances under the facilities are secured by a $75 million debenture with a floating charge over all Canadian assets of the Company as well as a general assignment of the Company's accounts receivable, a negative pledge to provide fixed charges on major producing petroleum properties in Canada and an assignment of material contracts.
Note 10 - Segmented Information
Three months ended June 30,
2005 2004 (1)
------------------------------------------------------------------------
Canada Canada
and and
Other Colombia Total Other Colombia Total
------------------------------------------------------------------------
Revenues
Oil and
natural gas $ 8,329 $ 4,877 $ 13,206 $ 12,554 $ 5,621 $ 18,175
Royalties (1,826) (390) (2,216) (2,647) (446) (3,093)
------------------------------------------------------------------------
6,503 4,487 10,990 9,907 5,175 15,082
Expenses
Production 1,392 940 2,332 2,625 1,051 3,676
Transportation 220 - 220 395 - 395
General and
administrative 1,298 925 2,223 1,330 757 2,087
Depletion,
depreciation and
accretion 2,119 1,669 3,788 5,697 2,671 8,368
------------------------------------------------------------------------
Segmented income $ 1,474 $ 953 $ 2,427 $ (140) $ 696 $ 556
Non-segmented
expenses
Interest on
bank debt - (251)
Interest on
subordinated notes (2,125) (2,844)
Gain 4,744 -
Loss on repurchase of
subordinated notes (676) -
Other income (expense) 304 (22)
Capital taxes (539) (274)
Future income tax recovery 567 1,013
------------------------------------------------------------------------
Net income (loss) $ 4,702 $ (1,822)
------------------------------------------------------------------------
------------------------------------------------------------------------
Identifiable
assets (2) $109,752 $ 80,614 $190,366 $146,652 $ 73,461 $220,113
Capital
expenditures (2) $ 11,383 $ 5,459 $ 16,842 $ 7,577 $ 2,418 $ 9,995
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) Restated - Note 2.
(2) Canada includes Heavy Oil Business Unit expenditures of $2.7
million in 2005 (2004 - $0.5 million), identifiable assets at
June 30, 2005 of $30.7 million (2004 - $6.6 million), and no
revenue and expenses.
Six months ended June 30,
2005 2004 (1)
------------------------------------------------------------------------
Canada Canada
and and
Other Colombia Total Other Colombia Total
------------------------------------------------------------------------
Revenues
Oil and
natural gas $ 14,971 $ 9,617 $ 24,588 $ 26,355 $ 11,294 $ 37,649
Royalties (3,142) (769) (3,911) (5,712) (900) (6,612)
------------------------------------------------------------------------
11,829 8,848 20,677 20,643 10,394 31,037
Expenses
Production 2,565 1,756 4,321 5,551 2,273 7,824
Transportation 468 - 468 811 - 811
General and
administrative 2,576 1,795 4,371 2,352 1,434 3,786
Depletion,
depreciation and
accretion 4,053 3,335 7,388 11,454 5,947 17,401
------------------------------------------------------------------------
Segmented income $ 2,167 $ 1,962 $ 4,129 $ 475 $ 740 $ 1,215
Non-segmented expenses
Interest on
bank debt - (729)
Interest on
subordinated notes (4,673) (5,668)
Gain 4,744 -
Loss on repurchase of
subordinated notes (542) -
Other income (expense) 571 (553)
Capital taxes (945) (537)
Future income tax recovery 1,170 2,202
------------------------------------------------------------------------
Net income (loss) $ 4,454 $ (4,070)
------------------------------------------------------------------------
------------------------------------------------------------------------
Identifiable
assets (2) $109,752 $ 80,614 $190,366 $146,652 $ 73,461 $220,113
Capital
expenditures (2) $ 17,262 $ 10,360 $ 27,622 $ 16,473 $ 8,235 $ 24,708
------------------------------------------------------------------------
------------------------------------------------------------------------
(1) Restated - Note 2.
(2) Canada includes Heavy Oil Business Unit expenditures of $5.1
million in 2005 (2004 - $0.9 million), identifiable assets at
June 30, 2005 of $30.7 million (2004 - $6.6 million), and no
revenue and expenses.
Certain statements in this report are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995. Specifically, this press release contains forward-looking statements relating to, prospects for technologies which remain unproven and the expected amount and timing of capital 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. Such factors include, but are not limited to: the ability to economically test, develop and utilize the technologies described herein, the feasibility of the technologies, general economic, market and business conditions; fluctuations in oil and gas prices; the results of exploration and development of drilling and related activities; 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.
FOR FURTHER INFORMATION PLEASE CONTACT:
Petrobank Energy and Resources Ltd.
John D. Wright
President and CEO
(403) 750-4400
Petrobank Energy and Resources Ltd.
Chris J. Bloomer
Vice-President Heavy Oil and CFO
(403) 750-4400
Petrobank Energy and Resources Ltd.
Corey C. Ruttan
Director Corporate Finance and Investor Relations
(403) 750-4400
(403) 266-5794 (FAX)
Email: ir@petrobank.com
Website: www.petrobank.com
