Grand Petroleum Inc.
TSX VENTURE : GPP

Grand Petroleum Inc.

April 19, 2007 19:40 ET

Grand Petroleum Inc. Announces Record 2006 Q4 and Year End Results and Filing of NI 51-101 Report

CALGARY, ALBERTA--(CCNMatthews - April 19, 2007) - Grand Petroleum Inc. (TSX VENTURE:GPP) ("Grand" or the "Corporation") is pleased to announce continued growth in production, cash flow, and earnings for the fourth quarter of 2006. Grand will be filing its audited financial statements for the year ended December 31, 2006, and NI 51-101 report on reserves on www.sedar.com and on the Corporation's web site, www.grandpetroleum.com. Certain selected operational and financial information for the fourth quarters of 2006 and 2005 and the year ended 2006 and 2005 are set out below and should be read in conjunction with Grand's audited financial statements.



Financial and Operating Highlights

Three months
ended Year ended
Dec 31 Dec 31 % Dec 31 Dec 31 %
2006 2005 change 2006 2005 change
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Financial ($000s
except per share
amounts)
Petroleum and natural
gas sales $14,781 $15,699 (6) $56,458 $37,522 50
Funds from operations 5,331 7,876 (32) 25,896 18,624 39
Per share - basic 0.22 0.33 (33) 1.08 0.87 24
- diluted 0.21 0.32 (34) 1.04 0.84 24
Net earnings (loss) (1,897) 505 (476) (767) 2,133 (136)
Per share - basic (0.08) 0.02 (500) (0.03) 0.10 (130)
- diluted (0.08) 0.02 (500) (0.03) 0.10 (130)
Capital expenditures 11,383 11,917 (4) 47,356 47,948 (1)
Net working capital
deficiency (27,548) (16,108) 71 (27,548) (16,108) 71
Total assets 90,541 69,350 31 90,541 69,350 31
Shareholders' equity $45,238 $38,661 17 $45,238 $38,661 17
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Common shares
outstanding (000s)
Weighted average
Basic 24,267 23,694 2 24,014 21,437 12
Diluted 25,126 24,707 2 24,969 22,289 12
End of period
Basic 26,281 23,694 11 26,281 23,694 11
Diluted 28,857 25,669 12 28,857 25,669 12
Operations
Average daily
production
Crude oil & NGLs
(bbls/d) 2,217 1,385 60 1,939 1,088 78
Natural gas (mcf/d) 6,341 8,049 (21) 6,232 4,323 44
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Total (boe/d) 3,274 2,727 20 2,978 1,809 65
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Operating netback
($/boe)
Average realized price 48.23 62.58 (23) 51.69 56.84 (9)
Royalties (10.84) (15.16) (28) (10.63) (10.63) -
Production expense (14.34) (12.03) 19 (12.68) (13.77) (8)
Transportation expense (0.95) (1.06) (10) (0.92) (1.00) (8)
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Operating netback
prior to realized
gain on financial
instruments 22.10 34.33 (36) 27.46 31.44 (13)
Realized gain on
financial instruments 0.84 - - 0.25 - -
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Average operating
netback 22.94 34.33 (33) 27.71 31.44 (12)
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Average sales price
Crude oil ($/bbl) 50.51 52.75 (4) 57.15 53.39 7
Natural gas ($/mcf) 7.41 12.03 (38) 6.94 10.26 (32)
NGLs ($/bbl) 45.11 55.86 (19) 56.37 57.26 (2)
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Combined average
($/boe) 48.23 62.58 (23) 51.69 56.84 (9)
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Drilling Activity (1)
Gross (net) wells
drilled (#)
Crude oil 6 (3.5) 6 (3.5) - 33(21.6) 21(13.8) 57
Natural gas 1 (1.0) - - 3 (2.35) 10 (7.4) (68)
Standing cased 3 (2.5) - - 7 (5.0) - -
Abandoned 1 (0.5) 4 (3.0) (83) 5 (4.0) 8(6.1) (34)
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Total 11 (7.5) 10 (6.5) 15 48(32.95) 39(27.3) 21
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Working interest
reserves - Proved
Crude Oil & NGLs
(mbbl) 2,334 1,801 30
Natural gas (mmcf) 6,353 5,452 17
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Total (mboe) 3,393 2,710 25
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Working interest
reserves proved +
Probable
Crude Oil & NGLs
(mbbl) 4,201 2,964 42
Natural gas (mmcf) 10,999 8,531 29
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Total (mboe) 6,034 4,386 38
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(1) Percent changes are to net wells drilled


Grand achieved record results in increases in production, funds from operations and reserves in 2006, at a time when the crude oil and natural gas industry was battling escalating costs, falling commodity prices and skyrocketing acquisition prices. Production increased by 65 percent from 2005 to 2006, with Q1 2007 estimated to be 3,400 boe per day, up by four percent from Q4 2006. Reserves at the end of 2006 were up by 38 percent over year-end 2005. Finding and development costs were $19.67 per boe on a proven plus probable basis including future development capital. Strong reserve growth continued in Q1 2007 with management estimating additions of 930 mboe of proven plus probable reserves, almost entirely from drilling.

Sylvan Lake - Our Largest Producing Area

Grand now controls 8,789 net acres in the Sylvan Lake area and has drilled a total of fourteen locations in this area of very "tight" and complicated land rights. In the first quarter of 2007 Grand drilled six (5.5 net) wells with a success rate of 100 percent. Our net production has grown to 1,800 boe per day in Q1 2007 (approximately 45 percent natural gas and 55 percent crude oil and natural gas liquids), making Sylvan Lake our largest producing area. Pipeline and facility construction finished at the beginning of Q2 2007 should add an additional 1,000 boe per day of production. Grand intends to drill at least another nine wells in 2007 in this prolific area, which should contribute to additional growth in 2007.

Finding Development and Acquisition Costs

Finding, development and acquisition costs for 2006 were $28.13 per boe proved and $19.67 per boe proved plus probable compared to $24.69 per boe and $19.41 per boe respectively for 2005. Inception to date costs, including future capital, were $23.86 per boe proved and $17.92 per boe proved plus probable.

Strong Balance Sheet and Drilling Inventory

Grand has maintained a strong balance sheet throughout its history. In December 2006 we raised $10.0 million by issuing 1.0 million flow-through shares and 1.3 million common shares. We ended the year with net debt of $27.5 million, or approximately 0.8 times forecast 2007 cash flow. Our bank lines were increased to a total of $44.0 million, supported by our expanding asset base.

Combined with our expected cash flow we have the financial underpinnings for our current 2007 capital expenditure budget (not including acquisitions) of $40 million to $45 million. This budget is focused on exploration, backed by our inventory of more than 100 drilling locations. This year we plan to drill 50 gross (30 to 35 net) wells, primarily in the Sylvan Lake area of Alberta and at Hazelwood, Saskatchewan.

Management's Discussion and Analysis

The following discussion is management's opinion about the operating and financial results of Grand Petroleum Inc. ("Grand" or the "Company") for the three months ended December 31, 2006, the year ended December 31, 2006 and previous periods, and the outlook for Grand based on information available as at April 19, 2007.

The following discussion and analysis should be read in conjunction with the audited financial statements and notes for the year ended December 31, 2006 and with the audited financial statements and Management's Discussion and Analysis (MD&A) for the year ended December 31, 2005.

Presentation

The financial data presented in this MD&A and financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). Per barrel of oil equivalent (boe) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil (6:1).

Non-GAAP Measures

This MD&A contains the terms "funds from operations" and "operating netbacks". Funds from operations is calculated by taking cash flow from operating activities as per the Statement of Cash Flows before the change in non-cash working capital related to operating activities. Operating netbacks are calculated by subtracting royalties, production expenses and transportation expenses per boe from the average sales price per boe before hedging gains or losses. Management uses funds from operations and operating netbacks to analyze operating performance and leverage and to provide shareholders and potential investors with additional information regarding the Company's liquidity and its ability to generate funds to finance operating activities and capital expenditures. Funds from operations, operating netbacks and working capital are not standards under GAAP and, therefore, may not be comparable to similar benchmarks presented by issuers outside the oil and natural gas industry. Investors are cautioned that the non-GAAP Measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with GAAP.



Calculation of Funds from Operations
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Three months ended Dec 31 Year ended Dec 31
($000s except per unit amounts) 2006 2005 2006 2005
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Cash flow from operating
activities $ 6,515 $ 8,530 $ 26,411 $ 16,418
Increase (decrease) in non-cash
working capital (1,184) (654) (515) 2,206
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Funds from operations 5,331 7,876 25,896 18,624
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Basic per share 0.22 0.33 1.08 0.87
Diluted per share $ 0.21 $ 0.32 $ 1.04 $ 0.84
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Forward-Looking Statements

This discussion contains forward-looking statements. Forward-looking statements address future events and conditions, and are based on current expectations. Management's assessment of future plans and operations, capital expenditures and the nature of capital expenditures and the method of financing thereof, wells to be drilled, timing of drilling, completion and tie-in of wells and the resulting production, production estimates, expected royalty rates, transportation costs and operating costs, and the taxability of the Company, may constitute forward-looking statements under applicable securities laws. These necessarily involve risks including, without limitation: risks associated with oil and natural gas exploration, development, production, marketing and transportation; loss of markets; volatility of commodity prices; currency fluctuations; imprecision of reserve estimates and estimates of recoverable quantities of oil and natural gas reserves; environmental claims and liabilities; compliance with environmental laws and regulations; changes in tax laws; political instability; fluctuations in foreign currency and exchange rates; competition from other producers; inability to retain drilling rigs and other services; the timing and length of plant turnarounds and the impact of such turnarounds; delays resulting from or inability to obtain required regulatory approvals; and the ability to access external sources of debt and equity capital. Because of the nature of forward-looking statements, they involve inherent risks and uncertainties and, therefore, actual results could differ materially from those currently anticipated. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the Company's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) and at the Company's website (www.grandpetroleum.com). Furthermore, the forward-looking statements contained in this MD&A are made as of the date hereof and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

Results of Operations

Revenue and funds from operations increased by 50 percent and 39 percent, respectively, year-over-year as a result of a 65 percent increase in production partially offset by a nine percent decrease in commodity prices. Grand's average 2006 operating netback of $27.46 per boe represented a 13 percent decrease from the $31.44 per boe average operating netback in 2005. This is largely attributable to 32 percent lower realized natural gas prices. Production expenses and transportation costs both decreased year-over-year on a per unit of production basis, while royalties remained the same. Royalties per unit of production decreased due to lower commodity prices, however this reduction was offset due to new wells with higher royalty burdens. Production expenses and transportation costs decreased per unit of production due to increased production, and increased efficiencies within Grand's field operations. Lower average realized sales price of $5.15 per boe or nine percent was the largest contributing factor to cause net earnings to drop from $3.23 per boe in 2005 to a loss of $0.71 per boe in 2006. Although Grand experienced a reduction in non-cash items and operating costs of $0.83 per boe and $1.17 per boe respectively year-over-year this was not enough to offset the lower sales price, which, combined with increased production, produced a loss in 2006 of $0.8 million compared with net earnings of $2.1 million in 2005.

Grand also continued to show strong operational growth, drilling 48 (32.95 net) wells in 2006 compared to 39 (27.3 net) in 2005. Fourth-quarter and full-year 2006 drilling results are outlined in the tables below.



Drilling Results For The Three Months Ended December 31, 2006
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Natural
gas Oil D&A Standing Total Net % Success(1)
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West Central Alberta 1 - - 2 3 3 100
East Central Alberta - 1 - - 1 1 100
Southeast Saskatchewan - 5 1 1 7 3.5 86
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Total 1 6 1 3 11 7.5 93
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(1) For net wells drilled.


Drilling Results For The Year Ended December 31, 2006
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Natural
gas Oil D&A Standing Total Net % Success(1)
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West Central Alberta 3 4 1 5 13 10.95 91
East Central Alberta - 7 2 - 9 9 78
Southeast Saskatchewan - 22 2 2 26 13 92
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Total 3 33 5 7 48 32.95 88
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(1) For net wells drilled.


Grand drilled just under 33 net wells in 2006, achieving an overall success rate of 88 percent and bringing on approximately 1,600 boe per day of new production. Grand's producing areas provide year-round access, so the Company's drilling program is not particularly weighted towards the winter season.

In West Central Alberta Grand drilled a total of 13 (10.95 net) wells in 2006, of which eight (7.6 net) were in the Sylvan Lake area. Drilling in Sylvan Lake continued into the first quarter of 2007, when Grand drilled an additional six (5.5 net) wells, and brought three (3.0 net) wells drilled in 2006 on-production. Production in West Central Alberta averaged approximately 1,800 boe per day in the first quarter of 2007.

In East Central Alberta Grand drilled nine (9.0 net) wells in 2006, including three successful horizontal wells in the Schneider area. Grand was able not only to offset declines in this area, but to increase production year-over-year. In 2007 Grand plans to conduct some development drilling in this area to offset declines.

Grand and its partner were active in Southeast Saskatchewan throughout 2006, drilling 26 gross (13.0 net) wells with a 92 percent success rate. The program continues in 2007, with six (3.0 net) wells being drilled in the first quarter. A total of 16 (8.0 net) wells commenced production in 2006, with six starting in the fourth quarter. An additional nine wells began producing in the first quarter of 2007, increasing average production in this area to approximately 450 per bbls per day in March 2007. As drilling continues in this area, Grand expects to continue experiencing a high success rate and incremental production from continued exploration and development.



DETAILED FINANCIAL ANALYSIS

Production
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Three months ended Dec 31 Year ended Dec 31
2006 2005 % Change 2006 2005 % Change
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Crude oil (bbls/d) 2,017 1,156 74 1,774 1,000 77
Natural gas (mcf/d) 6,341 8,049 (21) 6,232 4,323 44
NGL (bbls/d) 200 229 (13) 165 88 88
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Total (boe/d) 3,274 2,727 20 2,978 1,809 65
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Grand's production increased to an average of 2,978 boe per day in 2006 from 1,809 boe per day in 2005. The increase of 65 percent resulted from the Company's successful drilling program. Grand's production mix remained relatively unchanged from 2005 to 2006. In 2006, 60 percent of the total production came from crude oil sales, 35 percent from natural gas sales and five percent from natural gas liquids (NGL) sales. Production in the fourth quarter also showed growth, increasing by 20 percent from the fourth quarter of 2005 due to continued successful drilling and tie-ins of new wells. The production mix leaned more towards crude oil in the fourth quarter of 2006, with 62 percent of Grand's production coming from crude oil sales, 32 percent from natural gas sales and six percent from NGL sales, compared to 42 percent, 49 percent and eight percent respectively in the fourth quarter of 2005. In 2007 Grand expects the production mix to be approximately 65 percent crude oil and NGL and 35 percent natural gas.



Production by Area
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Three months ended Dec 31
2006 2005
Natural Oil Natural
Oil & NGL gas Total & NGL gas Total
(bbls/d) (mcf/d) (boe/d) (bbls/d) (mcf/d) (boe/d)
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West Central Alberta 674 5,652 1,616 252 6,443 1,326
East Central Alberta 1,255 689 1,370 917 1,604 1,184
Southeast Saskatchewan 288 - 288 217 - 217
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Total 2,217 6,341 3,274 1,386 8,047 2,727
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Year ended Dec 31
2006 2005
Natural Oil Natural
Oil & NGL gas Total & NGL gas Total
(bbls/d) (mcf/d) (boe/d) (bbls/d) (mcf/d) (boe/d)
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West Central Alberta 428 5,280 1,308 102 2,994 601
East Central Alberta 1,246 952 1,405 861 1,329 1,083
Southeast Saskatchewan 265 - 265 125 - 125
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Total 1,939 6,232 2,978 1,088 4,323 1,809
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Grand's production increased by 118 percent year-over-year in West Central Alberta, and in 2006 44 percent of the Company's total production came from West Central Alberta wells, compared to 33 percent in 2005. East Central Alberta's production increased by 30 percent and Southeast Saskatchewan's by 112 percent year-over-year. Production also increased in each operating area in the fourth quarter of 2006 over the fourth quarter of 2005.

In 2007 Grand plans to continue its drilling program and aims to achieve similar levels of success as in previous years. Approximately 50 percent of budgeted wells are to be drilled in West Central Alberta, primarily in the Sylvan Lake area, approximately 10 percent will be drilled in East Central Alberta to offset production declines, and the remainder will be drilled in Southeast Saskatchewan. The number of wells drilled in each of the core areas may vary depending on the success achieved.



Petroleum and Natural Gas Sales
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Three months ended Dec 31 Year ended Dec 31
2006 2005 % Change 2006 2005 % Change
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Revenue ($000s)
Crude oil $ 9,373 $ 5,610 67 $37,006 $ 19,488 90
Natural gas 4,324 8,912 (51) 15,784 16,195 (3)
NGL 830 1,177 (29) 3,395 1,839 85
Realized gain on
financial
instruments 254 - - 273 - -
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Total $14,781 $ 15,699 (6) $56,458 $ 37,522 50
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Average sales price (1)
Crude oil ($/bbl) $ 50.51 $ 52.75 (4) $ 57.15 $ 53.39 7
Natural gas ($/mcf) 7.41 12.03 (38) 6.94 10.26 (32)
NGL ($/bbl) 45.11 55.86 (19) 56.37 57.26 (2)
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Combined average
($/boe) $ 48.23 $ 62.58 (23) $ 51.69 $ 56.84 (9)
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(1) The average selling prices reported are before realized gains from
financial instrument and transportation charges.


Revenue from petroleum and natural gas sales, before royalties, transportation costs and after financial instrument gains, totalled $56.5 million in the year ended December 31, 2006, compared to $37.5 million in 2005. The increase in revenue is a result of the 65 percent growth in production volumes from the prior year. The impact of increased production was offset by a decrease in Grand's realized average sales price that was consistent with the changes in benchmark oil and natural gas prices. In 2006 the AECO-C spot natural gas reference price averaged $6.53 per mcf, 26 percent lower than the 2005 average price of $8.81 per mcf, while the crude oil reference price increased by nine percent from an average of $57.36 per bbl in 2005 to an average of $62.35 per bbl in 2006.

Grand's production averaged 60 percent crude oil in 2006, up from 55 percent in 2005, reducing the impact of lower natural gas prices. However, overall revenue declined on an absolute basis in the fourth quarter of 2006 from the fourth quarter of 2005. This is attributable to the steep decline of natural gas prices and the lesser decline of crude oil prices that set in during the latter months of 2006. Growing production in the fourth quarter did not fully offset the effects of these price declines, resulting in an overall revenue decline in the fourth quarter of $0.9 million or six percent.

In the year ended December 31, 2006, Grand's realized crude oil prices averaged $57.15 per bbl, natural gas prices averaged $6.94 per mcf and NGL prices averaged $56.37 per bbl. This compares to $53.39 per bbl, $10.26 per mcf and $57.26 per bbl, respectively, in the year ended December 31, 2005. When weighted to production, this resulted in a decline of approximately nine percent in Grand's overall realized average price for 2006 from 2005.

For the fourth quarter, the overall price decline was considerably sharper at 23 percent to an average of $48.23 per boe in 2006 from $62.58 per boe iin 2005. This decline reflected both the sharp drop in natural gas prices from their year-end 2005 peak and the easing of crude oil prices later in 2006.

The Company sells the majority of its oil and natural gas on the spot market and, therefore, both the historical prices received and future prices expected fluctuate with the prevailing market prices of crude oil and natural gas. In April 2006 the Company entered into a costless collar contract for the period of July 1, 2006 to December 31, 2006 for 500 bbls per day with a floor price of US$65.00 per bbl WTI and a ceiling price of US$85.00 per bbl WTI. The realized gain from the hedge for the period of July 1, 2006 to December 31, 2006 was $0.3 million.



Royalties
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Three months ended Dec 31 Year ended Dec 31
2006 2005 % Change 2006 2005 % Change
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Royalties ($000s)
Crown $ 2,014 $ 2,207 (9) $ 6,489 $ 3,202 103
Freehold 833 877 (5) 3,263 2,487 31
GORR 419 719 (42) 1,798 1,329 35
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Total $ 3,266 $ 3,803 (14) $11,550 $ 7,018 65
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Average percentage of total revenue before gain on financial instruments
Crown 13.9% 14.1% (1) 11.6% 8.5% 36
Freehold 5.7% 5.6% 2 5.8% 6.6% (12)
GORR 2.9% 4.6% (37) 3.2% 3.5% (9)
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Total 22.5% 24.2% (7) 20.6% 18.7% 10
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Royalties for the year ended December 31, 2006 totalled $11.6 million net of Alberta Royalty Tax Credit, compared to $7.0 million in 2005. The higher royalties reflect year-over-year production increases, as well as higher royalty obligations on new wells in West Central Alberta and Southeast Saskatchewan.

Royalties as a percentage of sales increased to 20.6 percent in the year ended December 31, 2006 from 18.7 percent in the year ended December 31, 2005. Crown royalties increased due to new wells drilled or acquired on Crown lands, while freehold royalties as a percentage of revenue decreased primarily due to increased production from royalty-free wells and Crown wells. By Company operating area, West Central Alberta's royalties as a percentage of sales were 29.1 percent, East Central Alberta's 16.6 percent and Southeast Saskatchewan's 23.1 percent in 2006. The West Central Alberta properties produced an average of 44 percent of the Company's production 2006, East Central Alberta produced 47 percent and Southeast Saskatchewan produced nine percent. Approximately 50 percent of the net wells drilled in 2007 are to be in West Central Alberta, which, when they come on production, are expected to increase royalties as a percentage of sales during 2007. As well, due to new legislation, the Alberta Royalty Tax Credit of $0.5 million that was received by Grand in previous years will no longer be available beginning 2007.

On a quarterly basis, royalties declined to $3.3 million in the fourth quarter of 2006 from $3.8 million in the fourth quarter of 2005 due to lower sales prices as most royalties are calculated as a percentage of revenue. Royalties as a percentage of sales decreased quarter-over-quarter as a result of the increase in royalty-free oil production in the East Central Alberta area from the successful horizontal wells drilled in Schneider Lake.



Production and Transportation Expenses
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Three months ended Dec 31 Year ended Dec 31
($000s) 2006 2005 % Change 2006 2005 % Change
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Production expenses $ 4,378 $ 3,081 42 $14,027 $ 9,334 50
Overhead recoveries
- operating (55) (53) 4 (222) (210) 6
Water disposal income (5) (10) (50) (22) (30) (27)
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Total before
transportation 4,318 3,018 43 13,783 9,094 52
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Transportation expenses 287 266 8 1,003 659 52
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Total $ 4,605 $ 3,284 40 $14,786 $ 9,753 52
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Production and transportation expense totalled $14.8 million for the year ended December 31, 2006 compared to $9.8 million for the year ended December 31, 2005. The increase of 52 percent was due mainly to the 65 percent increase in production. Production expense increased in the fourth quarter of 2006 over the fourth quarter of 2005, also largely due to increases in production but due in part to higher unit costs. Costs per unit of production, including transportation, decreased in 2006 to $13.60 per boe from $14.77 per boe in 2005. Production expenses (not including transportation) averaged $8.29 per boe in West Central Alberta, $17.42 per boe in East Central Alberta and $9.23 per boe in Southeast Saskatchewan.

Although lower than in 2005, production expenses per unit of production were higher than expected in 2006, due to a number of factors. Electrical power charges in East Central Alberta increased by 23 percent year over year, labour and supplies and materials costs increased, and additional funds were spent to continually improve the Company's safety and environmental practices. Operating costs per unit of production were also impacted by repairs and maintenance charges on older wells, and on facilities in the Galahad area. In the fourth quarter of 2006 Grand had charges for a prior year by a battery operator, and higher than usual charges for power, safety, dewaxing and hot oiling, and repairs and maintenance. These late-year expenses accounted for the increase in production expense per unit of production from $12.03 per boe in the fourth quarter of 2005 to $14.34 per boe in the fourth quarter of 2006.

In West Central Alberta and Southeast Saskatchewan production costs remained consistent with previous quarters. Increased production in these areas should result in lower production costs per unit of production going forward.



Operating Netbacks
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Three months ended Dec 31 Year ended Dec 31
($/boe) 2006 2005 % Change 2006 2005 % Change
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Average realized sales
price $ 48.23 $ 62.58 (23) $ 51.69 $ 56.84 (9)
Royalties (10.84) (15.16) (28) (10.63) (10.63) -
Production expense (14.34) (12.03) 19 (12.68) (13.77) (8)
Transportation expense (0.95) (1.06) (10) (0.92) (1.00) (8)
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Operating netback prior
to realized gain on
financial instruments $ 22.10 $ 34.33 (36) $ 27.46 $ 31.44 (13)
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Realized gain on
financial instruments 0.84 - - 0.25 - -
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Average operating
netback $ 22.94 $ 34.33 (33) $ 27.71 $ 31.44 (12)
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Grand's average operating netback, prior to the gain on financial instruments, was $27.46 per boe in the year ended December 31, 2006, compared to $31.44 per boe in the year ended December 31, 2005. The lower netback was due primarily to lower commodity prices, partially offset by lower production expenses per boe. Production expenses per boe, including transportation, decreased to $13.60 in 2006 from $14.77 in 2005, primarily as a result of increased production. Royalties remained the same at $10.63 per boe. In the fourth quarter of 2006 the operating netback, prior to the gain on financial instruments, averaged $22.10 per boe. The 36 percent decrease from the fourth quarter of 2005 was greater than the year-over-year drop due to pricing dynamics in each quarter: in 2005 commodity prices were particularly high in the fourth quarter, whereas in the fourth quarter of 2006 commodity prices were lower than the average for that year, exaggerating the drop in the netback for the quarter versus the full year.



General and Administrative Expense
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($000s except per Three months ended Dec 31 Year ended Dec 31
unit of production) 2006 2005 % Change 2006 2005 % Change
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General and
administrative
expense $ 1,371 $ 734 87 $ 3,864 $ 2,568 50
Overhead recoveries
- capital (93) (179) (48) (585) (691) (15)
Capitalized general
and administrative
expense (188) (81) 132 (533) (374) 43
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Net general and
administrative
expense $ 1,090 474 130 $ 2,746 $ 1,503 83
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Per unit of
production ($/boe) $ 3.62 $ 1.89 92 $ 2.53 $ 2.28 11
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Net general and administrative expense for the year ended December 31, 2006 totalled $2.7 million compared to $1.5 million for the year ended December 31, 2005. On a unit of production basis, this expense increased to $2.53 per boe from $2.28 per boe year-over-year. The increase stems from an increase in salaries year-over-year due to the addition of technical staff, as well as associated costs such as software rental and the cost of employee benefits. In addition, capitalized overhead decreased by 15 percent year-over-year due to a greater proportion of non-operated capital expenditures. The annual increases were particularly felt in the fourth quarter of 2006 due to the loading of expenses such as bonuses and audit and reserve evaluation fees, with net general and administrative expense increasing by 130 percent period-over-period, and by 92 percent on a unit of production basis. Effective May 1, 2007, Grand has signed a new lease for office space which will see office rent increase by approximately $0.1 million or 49 percent in 2007 from 2006. Other G&A expenses are expected to remain fairly constant on a dollar basis, and total G&A expense may decrease on a unit-of production basis, as production increases in 2007.



Stock-based Compensation
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Three months ended Dec 31 Year ended Dec 31
2006 2005 % Change 2006 2005 % Change
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Total ($000s) $ 417 $ 359 16 $ 1,187 $ 788 51
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Per unit of
production ($/boe) $ 1.38 $ 1.43 (3) $ 1.09 $ 1.19 (8)
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Stock-based compensation expense is the amortization over the vesting period of the fair value of stock options granted to employees and directors of the Company. The fair value of all options granted is estimated at the date of grant using the Black-Scholes option pricing model. The non-cash compensation expense for the year ended December 31, 2006 increased 51 percent due to options being granted to both recruit new staff and retain current staff in today's competitive environment. During the fourth quarter of 2006, the Company issued 597,500 stock options to employees. The options vest over two years and are exercisable into common shares at an average price of $3.83. Pursuant to Grand's option plan, one third of the options granted vest immediately resulting in higher initial compensation expense. Total outstanding stock options at December 31, 2006 were 2,575,833.

During the three months and the year ended December 31, 2006 Grand capitalized $0.2 million ($0.1 related to tax effect) of stock-based compensation associated with exploration and development activities.



Interest Expense
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Dec 31 Year ended Dec 31
2006 2005 % Change 2006 2005 % Change
----------------------------------------------------------------------------
Total ($000s) $ 442 $ 92 380 $ 1,220 $ 197 519
----------------------------------------------------------------------------
Per unit of
production ($/boe) $ 1.47 $ 0.37 297 $ 1.12 $ 0.30 273
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Interest expense on a per unit of production basis for the three months and the year ended December 31, 2006 increased by 297 percent and 273 percent, respectively, over the comparable periods in 2005 due to higher bank debt. In May and June 2005 Grand raised $16.0 million (net of issue costs) through two share issues, thereby decreasing debt. In 2006 Grand carried higher bank debt throughout the year to facilitate its capital expenditure program.



Depletion, Depreciation and Accretion (DD&A)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($000s except per Three months ended Dec 31 Year ended Dec 31
unit of production) 2006 2005 % Change 2006 2005 % Change
----------------------------------------------------------------------------
Depletion and
depreciation $ 7,473 $ 6,385 17 $26,004 $ 14,634 78
Accretion 96 77 25 346 300 15
----------------------------------------------------------------------------
Total DD&A $ 7,569 6,462 17 $26,350 $ 14,934 76
----------------------------------------------------------------------------
Per unit of production
($/boe) $ 25.13 $ 25.76 (2) $ 24.24 $ 22.62 7
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the year ended December 31, 2006, depletion and depreciation expense totalled $26.0 million or $23.92 per boe of production, compared to $14.6 million or $22.16 per boe in the year ended December 31, 2005. The increase of 78 percent is attributable mainly to higher production volumes in 2006, and to a much lesser extent to gradually increasing finding and development costs. Total costs subject to depletion and depreciation in the year ended December 31, 2006 include approximately $9.8 million relating to future development costs estimated to complete crude oil and natural gas wells for which proved reserves have been assigned. Undeveloped land with a value of approximately $4.4 million and salvage value of $3.2 million were excluded from the costs subject to depletion. Undeveloped land is included in the depletion and depreciation calculation once it is considered to be developed or impaired. Accretion expense for both 2006 and 2005 was $0.3 million or $0.32 per boe in 2006 compared to $0.45 per boe in 2005.

On a quarterly basis, depletion and depreciation totalled $7.5 million in the fourth quarter of 2006 compared to $6.4 million in the fourth quarter of 2005. The increase of 17 percent is attributable to higher production, however on a unit of production base costs decreased to $24.81 from $25.45 period over period due do the increase in reserves booked at December 31, 2006. Quarterly accretion remained consistent at $0.1 million year over year, with costs of $0.32 per boe in the fourth quarter of 2006 and $0.31 per boe in the fourth quarter of 2005.

Income Taxes

In May and June 2005, Grand completed two flow-through share issues and renounced a total of $11.8 million of Canadian exploration expense to shareholders in the first quarter of 2006. In December of 2006, Grand issued shares through a flow-through issue for gross proceeds of $5.0 million, which were renounced to shareholders in the first quarter of 2007. All of the total qualifying expenditures of $5.0 million are expected to be expended by December 31, 2007. During 2006 and 2005, Grand recorded minimal income taxes. The estimated tax pools at December 31, 2006 are included in the table below:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
($ millions)
----------------------------------------------------------------------------

Canadian exploration expense $ 8.3
Canadian development expense 16.2
Canadian oil and gas property expense 14.3
Undepreciated capital cost 25.6
Share issue costs 1.5
----------------------------------------------------------------------------
Balance December 31, 2006 $ 65.9
----------------------------------------------------------------------------
----------------------------------------------------------------------------


All tax filings are subject to subsequent government audit and potential reassessments. Accordingly the final determined tax liability and tax pool balances may differ materially from amounts estimated and recorded.

Net Earnings and Funds from Operations

For the year ended December 31, 2006, funds from operations increased to $25.9 million or $1.04 per diluted share from $18.6 million or $0.84 per diluted share in the year ended December 31, 2005. Grand recorded a net loss of $0.8 million or $0.03 per diluted share in the year ended December 31, 2006, compared with net earnings of $2.1 million or $0.10 per diluted share in the year ended December 31, 2005. The decrease in average sales price of $5.15 per boe from 2005 to 2006 had the greatest impact on net income in 2006. Operating netbacks remained strong in 2006 despite lower commodity prices, and combined with a 65 percent increase in production this created a 39 percent increase in funds from operatons over 2005.

For the quarter ended December 31, 2006 Grand recorded a net loss of $1.9 million or $0.08 per diluted share compared to earnings of $0.5 million or $0.02 per diluted share in the quarter ended December 31, 2005. The quarterly loss, which was higher than the loss for the full year, is attributable to a combination of higher depletion costs per unit of production, lower than yearly average commodity prices and year-end reserves evaluation, audit charges and bonuses booked in the fourth quarter. Funds from operations totalled $5.3 million in the fourth quarter of 2006, a decrease of 32 percent from $7.9 million in the fourth quarter of 2005. The decline is attributable to lower revenue caused by reduced commodity prices and higher expenses, particularly higher operating costs and higher general and administrative costs.



Capital Expenditures
----------------------------------------------------------------------------
----------------------------------------------------------------------------
West East
2006 Capital Central Central Southeast
Expenditures ($000s) Alberta Alberta Saskatchewan Total
----------------------------------------------------------------------------

Land, acquisitions
and dispositions $ 2,281 $ 290 $ 9 $ 2,580
Geological and geophysical 2,163 823 66 3,052
Drilling and completions 13,467 8,608 6,984 29,059
Well equipment/tie-ins 6,104 3,642 2,189 11,935
Administrative capital - - - 46
Equipment inventory - - - 684
----------------------------------------------------------------------------
Total $ 24,015 $ 13,363 $ 9,248 $ 47,356
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Grand expended $47.4 million in capital in 2006 compared to $47.9 million in 2005. With $29.1 million spent on drilling and completions, the budget was weighted considerably to drilling of Grand's extensive inventory to achieve production and reserves growth. Spending of $7.0 million in Saskatchewan continued the exploratory drilling program and set up the area to add new reserves in 2007 by capitalizing on development locations established by successful 2006 exploratory drilling. Grand also invested considerable capital in infrastructure. By area, West Central Alberta received $24.0 million or 51 percent of capital expenditures, in keeping with Grand's focus on this area. Fourth quarter 2006 capital spending totalled $11.4 million compared to $11.9 million in the fourth quarter of 2005. Capital spending in the fourth quarter included close to $1.0 spent on land sales in West Central Alberta plus the drilling of 7.5 net wells of which three (3.0 net) were in Sylvan Lake, seven (3.5 net) in Southeast Saskatchewan and one (1.0 net) in the Galahad area of East Central Alberta. An additional $2.8 million was spent on well equipment and tie ins during the fourth quarter of 2006. Total capital expenditures include $0.2 million of non-cash items related to capitalized stock-based compensation.

Liquidity and Capital Resources

For the year ended December 31, 2006, Grand's capital expenditures of $47.4 million were funded by funds from operations and the Company's bank line. At year-end Grand had access to a $35.5 million revolving loan facility and a $7.5 million acquisition and development loan, for a total of $43.0 million, of which $24.1 million was drawn at December 31, 2006. Effective January 31, 2007, the revolving loan facility was raised to $40.0 million, and the acquisitions and development loan was reduced to $4.0 million for a total of $44.0 million. At December 31, 2006, Grand had a working capital deficit of $27.5 million which is 0.82 times estimated 2007 funds from operations.

In December 2006, Grand issued 1.0 million flow-through common shares at a price of $5.00 per share for gross proceeds of $5.0 million, and 1.3 million common shares at a price of $3.80 per share for gross proceeds of just over $5.0 million. The proceeds were used to pay down bank debt in preparation for the Company's 2007 capital expenditure program.

Commodity prices and production volumes are the factors with the largest impact on Grand's ability to generate adequate cash flow to meet its obligations. A prolonged decrease in commodity prices would negatively affect cash flow from operations and would also likely result in a reduction in the size of available bank loans. Normal production declines, without additional production through drilling or acquisitions, would negatively impact funds flow even in times of high commodity prices. This could also result in a reduction of bank lines available as well as access to capital markets.

At present Grand has budgeted to spend approximately $40 million to $45 million on capital expenditures in 2007. The Company believes that internally-generated funds from operations and incremental bank debt should be sufficient to finance current operations and planned capital spending in 2007. Other sources of financing, including equity offerings, may be considered. The Company is committed to payments under an operating lease for office space through April 3, 2012 for a total of $1.9 million.

Share Capital

Grand is authorized to issue an unlimited number of common shares as well as first preferred shares and second preferred shares, all without nominal or par value. To date, no preferred shares have been issued. The Company's share capital at December 31, 2006 is outlined below:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of Shares Amount
(000s) ($000s)
----------------------------------------------------------------------------
Common shares
Balance December 31, 2005 23,693 $ 32,474
Tax effect of 2005 flow-through share
offerings - (4,004)
Issued on exercise of options 272 426
Transfer from contributed surplus on exercise
of options - 176
Flow-through shares issued December 2006 1,000 5,000
Common shares issued December 2006 1,316 5,001
Share issue costs (net of tax effect of $198) - (390)
----------------------------------------------------------------------------
Balance December 31, 2006 26,281 $ 38,683
----------------------------------------------------------------------------
----------------------------------------------------------------------------


During the fourth quarter of 2006, the Company issued 1.0 million flow-through common shares at a price of $5.00 per share for gross proceeds of $5.0 million and 1.3 million common shares at a price of $3.80 per share for gross proceeds of approximately $5.0 million. As well, during the fourth quarter of 2006, the Company issued 0.6 million stock options to employees. The options vest over two years and are exercisable into common shares at an average price of $3.83. Total outstanding stock options at December 31, 2006 were 2.6 million

At April 19, 2007 there were 26,289,523 outstanding shares.



BALANCE SHEETS
As at December 31 December 31
($000s) 2006 2005
----------------------------------------------------------------------------

Assets
Current assets
Accounts receivable 9,108 9,877
Prepaids and deposits 330 627
----------------------------------------------------------------------------
9,438 10,504

Future income tax asset - 193
Property, plant and equipment (note 3) 81,103 58,653
----------------------------------------------------------------------------
90,541 69,350
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and accrued liabilities 12,897 15,705
Bank debt (note 5) 24,089 10,907
----------------------------------------------------------------------------
36,986 26,612

Asset retirement obligation (note 4) 5,245 4,077
Future income tax liability (note 8b) 3,072 -

Shareholders' equity
Share capital (note 6b) 38,683 32,474
Contributed surplus (note 7) 2,203 1,068
Retained earnings 4,352 5,119
----------------------------------------------------------------------------
45,238 38,661
----------------------------------------------------------------------------

Commitments (note 11)

----------------------------------------------------------------------------
90,541 69,350
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the financial statements.



STATEMENTS OF OPERATIONS AND RETAINED EARNINGS

For the years ended December 31, December 31,
($000s, except per share amounts) 2006 2005
----------------------------------------------------------------------------

Revenue
Petroleum and natural gas sales 56,458 37,522
Royalty expenses, net of Alberta
Royalty Tax Credit (11,550) (7,018)
Interest income 20 2
----------------------------------------------------------------------------
44,928 30,506
----------------------------------------------------------------------------

Expenses
Production 13,783 9,094
Transportation 1,003 659
General and administrative 2,746 1,503
Interest 1,220 197
Stock-based compensation (note 6e) 1,187 788
Depletion and depreciation 26,004 14,634
Accretion 346 300
----------------------------------------------------------------------------
46,289 27,175
----------------------------------------------------------------------------
Net earnings (loss) before taxes (1,361) 3,331

Current tax (note 8c) (4) (8)
Future income tax recovery (expense) (note 8a) 598 (1,190)
----------------------------------------------------------------------------

Net earnings (loss) (767) 2,133
Retained earnings, beginning of year 5,119 2,986
----------------------------------------------------------------------------
Retained earnings, end of year 4,352 5,119
----------------------------------------------------------------------------
Earnings (loss) per share (note 6f)
Basic (0.03) 0.10
Diluted (0.03) 0.10
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the financial statements.



STATEMENTS OF CASH FLOWS

For the years ended December 31, December 31,
($000s) 2006 2005
----------------------------------------------------------------------------
Cash provided by (used in):
Operations
Net earnings (loss) (767) 2,133
Add items not affecting cash:
Future income tax expense (recovery) (598) 1,190
Stock-based compensation 1,187 788
Depletion and depreciation 26,004 14,634
Accretion 346 300
Abandonment expenditures (276) (421)
Change in non-cash working capital (note 10) 515 (2,206)
----------------------------------------------------------------------------
26,411 16,418
----------------------------------------------------------------------------

Investing
Expenditures on property, plant and equipment (47,285) (40,011)
Dispositions (acquisitions) of property, plant
and equipment 110 (7,938)
Change in non-cash working capital (note 10) (2,257) 2,946
----------------------------------------------------------------------------
(49,432) (45,003)
----------------------------------------------------------------------------

Financing
Issue of capital stock for cash 10,427 16,894
Share issue costs (note 6b) (588) (1,061)
Bank indebtedness 13,182 10,907
----------------------------------------------------------------------------
23,021 26,740
----------------------------------------------------------------------------
Increase (decrease) in cash - (1,845)
Cash, beginning of year - 1,845
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash, end of year - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the financial statements.


Notes to the Financial Statements

Years ended December 31, 2006 and December 31, 2005.

(All tabular amounts are in thousands except per share/option figures, commodity prices and certain other exceptions as noted.)

1. NATURE OF OPERATIONS

Grand Petroleum Inc. ("Grand" or "The Company") is a public company engaged in the exploration, development and production of crude oil and natural gas in Alberta and Saskatchewan. Grand began trading on the TSX Venture Exchange on January 15, 2004 under the symbol GPP.

2. SIGNIFICANT ACCOUNTING POLICIES

These financial statements have been prepared by management in accordance with accounting principles generally accepted in Canada within the framework of accounting policies summarized below.

a) Revenue Recognition

Revenues associated with sales of petroleum and natural gas and all other items are recorded when the risks and rewards of ownership are transferred to the buyer.

b) Property, Plant & Equipment

Capitalized Costs

The Company follows the full cost method of accounting for exploration and development expenditures whereby all costs relating to the acquisition of, exploration for and development of petroleum and natural gas reserves, whether productive or unproductive are capitalized. Such costs include lease acquisition, geological and geophysical, lease rentals on undeveloped properties, drilling, both productive and non-productive wells, production equipment and overhead charges directly related to acquisition, exploration and development activities. Proceeds received from disposals of petroleum and natural gas properties and production equipment are credited against capitalized costs unless the disposal would alter the rate of depletion and depreciation by more than 20 percent, in which case a gain or loss on disposal is recorded.

Depletion and depreciation

All costs of acquisition, exploration and development of oil and natural gas reserves, associated tangible plant and equipment costs (net of salvage value) and estimated costs of future development of proved reserves are depleted and depreciated by the unit-of-production method based on estimated gross proved reserves as determined by independent engineers. Oil and natural gas reserves are converted to equivalent units using their estimated relative energy content of six thousand cubic feet of natural gas to one barrel of oil. The cost of unproved properties is excluded from the depletion calculation and is assessed for impairment at least annually.

Depreciation of furniture, fixtures and office equipment is provided using the declining balance method at rates between 20 percent and 50 percent.

Ceiling Test

The Corporation annually applies a "ceiling test" to assess whether the carrying amount of the petroleum and natural gas properties is recoverable. The recoverable amount for this test is the estimate of undiscounted cash flows expected from the production of proved reserves, based on assumptions and price forecasts used in the independent engineers' reserve report, plus the lower of cost and market of unproved properties.

When the carrying amount is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying amount exceeds the sum of discounted cash flows expected from the production of proved and probable reserves and the lower of cost and market of unproved properties. The cash flows are estimated using expected future product prices and costs and are discounted using a risk free interest rate.

c) Interest in Joint Operations

A portion of the Company's petroleum and natural gas exploration and development activities is conducted jointly with others, and accordingly, the financial statements reflect only the Company's proportionate interest in such activities.

d) Measurement Uncertainty

The preparation of the financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events at the balance sheet date. Actual results could differ from those estimated. Specifically, the ceiling test and the amounts recorded for depletion, depreciation, accretion and asset retirement obligations are based on estimates of proved reserves, future oil and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be significant.

e) Cash and Cash Equivalents

The Company considers deposits in banks, certificates of deposit and short-term investments with original maturities of three months or less as cash and cash equivalents.

f) Flow-through Shares

The resource expenditure deductions for income tax purposes related to exploratory activities funded by flow-through share arrangements are renounced to investors in accordance with tax legislation. Future tax liabilities and share capital are adjusted by the estimated cost of the tax deductions when the expenditures are renounced.

g) Per Share Amounts

Basic per share amounts are computed by dividing the net earnings by the weighted average number of common shares outstanding for the year. Diluted per share amounts reflect the potential dilution that would occur if securities or other contracts to issue common shares were exercised or converted to common shares. Diluted per share information is calculated using the treasury stock method that assumes any proceeds received by the Company upon the exercise of in-the-money stock options, plus the unamortized stock based compensation cost, would be used to buy back common shares at the average market price for the period. Anti-dilutive options or instruments are not included in the calculation and all options and instruments are considered anti-dilutive when the Company is in a loss position.

h) Asset Retirement Obligations

The Company recognizes the estimated liability associated with an asset retirement obligation (ARO) in the financial statements at the time the asset is acquired and the liability is incurred. The estimated fair value of the ARO liability is recorded as a long term liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on a unit of production basis over the life of the proved reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. The ARO is also adjusted for changes in the estimates of timing of cash flows or changes in the original estimated undiscounted cost. Actual costs incurred upon settlement of the ARO are charged against the ARO to the extent of the liability recorded.

i) Income Taxes

The Company follows the asset and liability method of accounting for income taxes. Under this method, the Company records future income taxes for the effect of any differences between the accounting and the income tax basis of an asset or liability using income tax rates substantially enacted on the balance sheet date. The effect of a change in income tax rates on the future income tax assets and liabilities is recognized in income in the period of the change. Future income tax assets are limited to the amount that is more likely than not to be realized.

j) Stock-based Compensation

Compensation costs attributable to all stock options granted to employees and directors are measured at fair value at the date of grant using the Black-Scholes option pricing model. The Company records a compensation cost for all stock options granted to employees or directors over the vesting period of the options based on the calculated fair value of the options. The compensation cost is a charge to earnings or is capitalized as a cost of exploration and development activities with an offsetting increase to contributed surplus on the balance sheet. Consideration paid by employees or directors upon exercise of the stock options and the amount previously recognized in contributed surplus are recorded as share capital. The Company has not incorporated an estimated forfeiture rate for stock options that will not vest; rather, the Company accounts for actual forfeitures as they occur.

k) Hedging

The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking various hedge transactions in accordance with the Canadian Institute of Chartered Accountants (CICA) accounting guideline for hedging relationships. This guideline requires that the hedge transaction be formally assessed at inception and on an ongoing basis to determine whether it is highly effective in offsetting changes in anticipated cash flows. If the transaction does not meet the requirements for hedge accounting, the gain or loss is recognized in income. If a bona fide hedging transaction is settled early, the gain or loss on settlement is deferred and recognized in the same period as the underlying hedged item is recognized.



3. PROPERTY, PLANT AND EQUIPMENT

Accumulated
depletion and Net book
Cost depreciation value
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Petroleum and natural gas properties $ 89,905 $ (33,842) $ 56,063
Production Equipment 31,517 (9,183) 22,334
Asset retirement costs 5,040 (2,431) 2,609
Furniture, fixtures and office
equipment 167 (70) 97
----------------------------------------------------------------------------
Balance, December 31, 2006 $ 126,629 $ (45,526) $ 81,103
----------------------------------------------------------------------------

Accumulated
depletion and Net book
Cost depreciation value
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Petroleum and natural gas properties $ 57,137 $ (14,582) $ 42,555
Production Equipment 16,975 (3,281) 13,694
Asset retirement costs 3,942 (1,615) 2,327
Furniture, fixtures and office
equipment 121 (44) 77
----------------------------------------------------------------------------
Balance, December 31, 2005 $ 78,175 $ (19,522) $ 58,653
----------------------------------------------------------------------------


In calculating the Company's depletion at December 31, 2006, approximately $4.4 million (December 31, 2005 - $3.0 million) of unproved properties and $3.2 million (December 31, 2005 - $2.3 million) of salvage were excluded from the depletion calculation. At December 31, 2006 future development costs of approximately $9.8 million (December 31, 2005 - $7.3 million) are required to complete wells for which proved reserves have been assigned and were added to the Company's net book value for the purposes of the depletion calculation.

For the year ended December 31, 2006 the Company capitalized $0.5 million (December, 2005 - $0.4 million) of general and administrative costs directly related to exploration activities.

The Company's ceiling test calculation, performed at December 31, 2006, resulted in no impairment loss. The future prices used by the Company in estimating cash flows were based on forecasts by an independent reserves evaluator, adjusted for the Company's quality and transportation differentials. The following table summarizes the benchmark prices used in the calculation.




Edmonton Light Cromer Medium Foreign
WTI Oil Crude Oil Crude Oil AECO Gas exchange
(US$/bbl) (Cdn$/bbl) (Cdn$/bbl) (Cdn$/mmbtu) (US$/Cdn$)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007 62.00 70.25 61.25 7.20 0.87
2008 60.00 68.00 59.25 7.45 0.87
2009 58.00 65.75 57.25 7.75 0.87
2010 57.00 64.50 56.00 7.80 0.87
2011 57.00 64.50 56.00 7.85 0.87
2012 57.50 65.00 56.50 8.15 0.87
2013 58.50 66.25 57.75 8.30 0.87
2014 59.75 67.75 59.00 8.50 0.87
2015 61.00 69.00 60.00 8.70 0.87
2016 62.25 70.50 61.25 8.90 0.87
2017 63.50 71.75 62.50 9.10 0.87
Thereafter(1) 0.87
----------------------------------------------------------------------------
(1) An increase of 2.00% represents the change in future prices each year
after 2017 to the end of the reserve life.


4. ASSET RETIREMENT OBLIGATIONS

The Company's ARO results from working interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. As at December 31, 2006 the Company estimates the total undiscounted amount of cash flows required to settle its asset retirement obligation, over the next thirty years, to be approximately $8.5 million (2005 - $8.3 million). The amount has been discounted using a credit-adjusted risk-free interest rate of 8 percent and an inflation rate of 1.5 percent. A reconciliation of the ARO is provided below:



Year ended Year Ended
December 31, December 31,
2006 2005
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Beginning of year $ 4,077 $ 3,580
Liabilities incurred 643 407
Liabilities acquired - 148
Liabilities disposed (31) -
Liabilities settled (194) (468)
Revisions in estimate of cash flows 404 110
Accretion Expense 346 300
----------------------------------------------------------------------------
End of year $ 5,245 $ 4,077
----------------------------------------------------------------------------


Revisions are a result of updated reserve life as calculated by the independent reserves evaluator and updated future cost assumptions.

5. BANK LOAN

At December 31, 2006 the Company had a revolving demand credit facility with a Canadian chartered bank in the amount of $35.5 million. The facility bears interest at a rate ranging from the bank's prime rate plus 0.125 percent to 1.250 percent. The rate is adjusted quarterly based upon the Company's debt to cash flow ratio calculated using unaudited preceding quarterly financial statements in accordance with the credit facility agreement. As at December 31, 2006 the rate was prime plus 0.375 percent (December 31, 2005 - prime plus 0.500 percent).

The facility is secured by a $15.0 million debenture with a floating charge over all assets of the Company, a $50.0 million supplemental debenture and a general security agreement. The Company also had available a $7.5 million non-revolving acquisition development demand loan. This facility bears interest at bank prime rate plus 0.75 percent per annum, with a drawdown rate of 0.25 percent.

On January 31, 2007, the amount available under the Company's revolving demand credit facility was increased from $35.5 million to $40. million. The Company's non-revolving acquisition and development demand loan was decreased from $7.5 million to $4.0 million.

The facilities are subject to a semi-annual review. This review includes a borrowing base re-determination, including any completed acquisitions, and a full assessment of the Company's financial position and operations. The next review is to take place in May 2007.



6. SHARE CAPITAL

a) Authorized

Unlimited number of common shares without par value.
Unlimited number of first preferred shares, of which none have been issued.
Unlimited number of second preferred shares, of which none have been issued.

b) Issued and Outstanding
Number of
Shares Amount
(000s) ($000s)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Common shares
Balance at December 31, 2005 23,693 32,474
Tax effect of 2005 flow-through share offerings - (4,004)
Issued on exercise of options 272 426
Transfer from contributed surplus on exercise of
options - 176
Flow-through shares issued December 2006 1,000 5,000
Common shares issued December 2006 1,316 5,001
Share issue costs (net of tax effect of $198) - (390)
----------------------------------------------------------------------------
Balance, December 31, 2006 26,281 38,683
----------------------------------------------------------------------------


c) Stock Options

The Company has adopted a stock option plan (the "Plan") for directors, senior officers and employees of the Company. Options granted pursuant to the Plan will not exceed a term of five years, and are granted at an option price and on other terms that the directors determine are necessary to achieve the goal of the Plan and in accordance with regulatory policies. Options vest one-third immediately, one-third one year later, and one-third two years from grant date. As at December 31, 2006, there were 2.6 million stock options outstanding with an exercise price between $1.00 and $5.00.



The following table sets forth a reconciliation of the Plan activity to
December 31, 2006:
Weighted
Number of average
options exercise
outstanding price
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance December 31, 2005 1,975 $ 1.89
Granted 878 4.14
Cancelled (5) 2.32
Exercised (272) 1.57
----------------------------------------------------------------------------
Balance December 31, 2006 2,576 $ 2.69
----------------------------------------------------------------------------

Outstanding options Exercisable options
Weighted Weighted
Average average Average
Exercise Number of remaining exercise Number of exercise
Price ($) Options life (years) price Options price
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1.00 - 1.50 760 2.03 $ 1.02 760 $ 1.02
1.51 - 2.00 140 2.16 1.86 140 1.86
2.01 - 3.00 658 2.95 2.40 625 2.37
3.01 - 4.00 598 4.97 3.83 199 3.83
4.01 - 5.00 420 4.16 4.82 187 4.83
----------------------------------------------------------------------------
1.00 - 5.00 2,576 3.30 $ 2.69 1,911 $ 2.19
----------------------------------------------------------------------------


d) Flow-through Shares

Pursuant to the May and June 2005 flow-through share offerings, the Company renounced $11.8 million of qualifying expenditures to shareholders effective December 31, 2005. All of the qualifying expenditures totalling $11.8 million had been spent at December 31, 2005.

The Company has an obligation to incur qualifying exploration expenditures of $5.0 million by December 31, 2008 to satisfy the terms of the flow-through common shares issued in December 2006. At December 31, 2006 the Company had not incurred any of the qualifying exploration expenditures.

e) Stock-based Compensation

The Company has calculated its stock-based compensation expense using the Black-Scholes option pricing model to estimate the fair value of stock options issued at the date of the grant. The assumptions used to determine stock-based compensation expense in the years ended December 31, 2006 and 2005 are as follows:



For the years ended December 31 2006 2005
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Weighted average fair value per option $ 1.99 $ 2.27
Risk-free interest rate (%) 4.30 5.00
Average Volatility (%) 49 60
Expected life (years) 5 5
----------------------------------------------------------------------------


The Company has recorded compensation expense during the year ended December 31, 2006 of $1.2 million (2005 - $0.8 million) and capitalized $0.1 million (December 31, 2005 - nil) of stock based compensation directly related to exploration activities.

f) Earnings per Share

The following table summarizes the weighted average shares outstanding:




For the years ended December 31 2006 2005
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Basic 24,014 21,437
Diluted 24,969 22,289
----------------------------------------------------------------------------

The reconciling item between the basic and diluted weighted average common
shares outstanding is stock options.

7. CONTRIBUTED SURPLUS

2006 2005
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, beginning of year $ 1,068 $ 280
Stock-based compensation expense 1,187 788
Stock-based compensation capitalized 124 -
Transfer to share capital on exercise of options (176) -
----------------------------------------------------------------------------
Balance, end of year $ 2,203 $ 1,068
----------------------------------------------------------------------------


8. INCOME TAXES

a) Future Income Tax Recovery (Expense)

The provision for income tax reflects an effective tax rate which differs from federal and provincial statutory tax rates. The main difference is as follows:




For the years ended December 31 2006 2005
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Earnings (loss) before tax $ (1,361) $ 3,331
Enacted tax rate 34.78% 37.84%
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Computed income taxes at the enacted rate (473) 1,260

Increase (decrease) in taxes resulting from:
Non-deductible Crown payments 917 802
Resource allowance (955) (1,249)
Impact of change in effective rate (160) 118
Stock-based compensation 413 298
Other (340) (39)
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Provision for (recovery of) income taxes $ (598) $ 1,190
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b) Components of the Net Future Income Tax Asset
(Liability):

As at December 31 2006 2005
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Non-capital losses $ - $ 107
Attributed Canadian Royalty Income 72 -
Asset retirement obligation 1,546 1,369
Property, plant and equipment (5,152) (1,756)
Share issue costs 462 473
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Future income tax asset (liability) $ (3,072) $ 193
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c) Current Tax

For the years ended December 31, 2006 and 2005 the current tax expense represents Saskatchewan capital tax.

9. FINANCIAL INSTRUMENTS

(a) Fair Value of Financial Instruments:

The Company's financial instruments recognized in the balance sheet consist of accounts receivable, accounts payable and accrued liabilities and bank debt. The fair values of financial assets and liabilities that are included in the balance sheet approximate their carrying amounts.

(b) Credit Risk:

Substantially all of the Company's accounts receivable are with customers and joint venture partners in the oil and gas industry and are subject to normal industry credit risks.

(c) Foreign Currency Exchange Risk:

The Company is exposed to foreign currency fluctuations as crude oil and natural gas prices are referenced to U.S. dollar denominated prices.

(d) Interest Rate Risk:

The Company is exposed to interest rate risk to the extent that bank debt is at a floating rate of interest.

(e) Commodity Price Risk Management:

In the second quarter of 2006, the Company entered into a costless collar contract for the period of July 1, 2006 to December 31, 2006 for 500 bbls per day with a floor price of US$65.00 per bbl WTI and a ceiling price of US$85.00 per bbl WTI. The realized gain recorded during 2006 was $0.3 million.




10. SUPPLEMENTAL CASH FLOW INFORMATION

For the years ended December 31 2006 2005
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Accounts receivable $ 769 $ (6,394)
Prepaid and deposits 297 (376)
Accounts payable and accrued liabilities (2,808) 7,510
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Change in non-cash working capital (1,742) 740
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Operating activities 515 (2,206)
Investing activities $ (2,257) $ 2,946
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The following cash payments have been included in the determination of
earnings:

For the years ended December 31 2006 2005
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Interest paid $ 1,220 $ 197
Taxes paid - -
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11. COMMITMENT

The Company is committed to payments under an operating lease for office space through April 30, 2012 as follows:



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2007 $ 309
2008 360
2009 360
2010 360
2011 360
2012 $ 118
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The Company is committed to a contract through August 1, 2008 for the utilization of pipeline capacity on a oil pipeline system in eastern Alberta to deliver sufficient volumes of crude oil that will result in $0.3 million of total pipeline fees prior to the expiration of the contract. The Company expects to provide the volumes through normal operations.

The Company has an obligation to incur qualifying exploration expenditures of $5.0 million by December 31, 2008 to satisfy the terms of the flow-through common shares issued in December 2006. At December 31, 2006 the Company had not incurred any of the qualifying exploration expenditures.

Certain information set forth in this press release contains forward-looking statements. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, reliance should not be placed on forward-looking statements. Grand's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Grand will derive therefrom. Grand disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

The TSX Venture Exchange does not accept responsibility for the adequacy or accuracy of this release.

Contact Information

  • Grand Petroleum Inc.
    Andrew Hogg
    President and CEO
    (403) 231-8403
    or
    Grand Petroleum Inc.
    Brenda Galonski
    Vice President, Finance and CFO
    (403) 231-8402
    Website: www.grandpetroleum.com