Grand Banks Energy Corporation
TSX VENTURE : GBE

Grand Banks Energy Corporation

March 17, 2008 22:37 ET

Grand Banks Announces December 31, 2007 Results

CALGARY, ALBERTA--(Marketwire - March 17, 2008) - Grand Banks Energy Corporation (TSX VENTURE:GBE) (the "Company" or "Grand Banks") is pleased to announce its financial and operating results for the three month period and year ended December 31, 2007. The detailed financial statements and management discussion and analysis for the periods are accessible on the internet at the website www.sedar.com.

Grand Banks has achieved exceptional growth in all aspects of its business in 2007. Moreover, the Company finds itself in the enviable position of having a large inventory of horizontal light oil drilling locations (most of which are eligible to receive substantial royalty holidays), a focused, high quality, operated production base, and a strong balance sheet. Grand Banks' 2007 year-end reserve report shows that its reserves are the highest level in its history. These factors have resulted in record net present value (discounted at 10% P+PA reserve value before tax) of $3.12 per fully diluted share, and $3.64 per fully diluted share, if possible reserves are also included.

While all this bodes well for the shareholders of Grand Banks, its share price has not reflected this value, and the Company believes that its oil properties could be more efficiently developed by a larger company with more resources, a better cost structure and lower cost of capital. An outright sale or business combination with a larger entity has the potential to give Grand Banks' shareholders an opportunity to realize additional value and liquidity. As previously announced, in order to achieve these goals the Company has decided to enter into a competitive process to maximize shareholder value.

2007 Highlights:

- Record quarterly and annual production levels, with exit 2007 production rate of about 1,350 boe/d and current Company production of over 1,500 boe/d

- Record levels of earnings and funds flow from operations on both an absolute and per share basis

- Tower Creek 02-21 Leduc discovery well commenced production and has performed above expectations

- Successful horizontal drilling program on Company's Three Forks/Torquay light oil play

- Proved reserves increased 49% to 2.95 million boe

- Proved plus probable ("P+PA") reserves increased 30% to 4.93 million boe

- Proved plus probable plus possible reserves at year end were 5.79 million boe

- Estimated net asset value ("NAV") per fully diluted share at December 31, 2007:

Discounted at 10% P+PA reserve value before tax increased 70% to $3.12/share

Discounted at 10% P+PA+Possible reserve value before tax is $3.64/share



FINANCIAL SUMMARY TABLE Three Months Ended Years Ended
December 31, December 31,
% %
2007 2006 Change 2007 2006 Change
------------------------------------------------
Average Sales Volumes:
Crude oil & liquids -
bbls/day 638 633 1 613 593 3
Natural gas - mcf/day 4,235 1,363 211 2,421 1,556 56
Sales volumes - boe/day
(6:1) 1,344 860 56 1,016 852 19

Financial Results
(CDN $000s, except per share
amounts)

Gross revenues 7,316 4,315 70 21,764 17,504 24
Net income (loss) 2,631 1,265 108 3,325 627 430
Per share - basic 0.08 0.04 100 0.10 0.02 400
Per share - diluted 0.08 0.04 100 0.10 0.02 400
Funds flow from operations(1) 4,266 2,219 92 11,526 9,706 19
Per share - basic 0.13 0.07 86 0.36 0.32 12
Per share - diluted 0.13 0.07 86 0.35 0.31 13
Capital expenditures 2,552 7,237 (65) 22,980 26,079 (12)
Working capital (deficiency) (12,437) (10,562) 18
Flow-through obligations
(to year end) - 3,855 (100)
Total assets 56,474 52,251 8

(1) Funds flow from operations is a non-GAAP measure that represents net
income plus depletion, depreciation and accretion, stock-based
compensation, future taxes and other non-cash expenses.

Grand Banks 2007 Net Asset Value per Fully Diluted Share Information
(unaudited)

Using Reserve Value, Paddock Lindstrom and Associates at December 31, 2007
- Forecast Pricing and Costs:
----------------------------------------------------------------------------
($000's except share amounts) Proved plus Proved plus probable
probable plus possible
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Reserve Value (10% Dcf before tax NPV,
(includes future capital) 116,073 134,528
Undeveloped property at cost
(land & seismic) 2,745 2,745
Option Proceeds 3,272 3,272
Estimated Net Debt (12,822) (12,822)
----------------------------------------------------------------------------

Estimated Total Net Assets 109,268 127,723
----------------------------------------------------------------------------

Fully Diluted Shares Outstanding (000's) 35,073 35,073
----------------------------------------------------------------------------

Estimated Net Asset Value per Fully Diluted
Share $3.12 $3.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Finance and Budget:

Grand Banks had net debt (including working capital deficiency) of $12.4 million at December 31, 2007. The Company currently has a $19.0 million line of credit with an Alberta financial institution. The 2007 year end independent reserve evaluation has been provided to the Company's lender. This report will be used to determine the potential increase to the Company's lending lines, which is expected to be substantial. This lending line, along with funds flow from operations will be used to fund its 2008 capital spending program.

Outlook:

Grand Banks has completed the drilling of a horizontal step-out well at Sinclair, Manitoba, targeting light oil from the Torquay (Three Forks) formation. The geological data gathered during drilling appears to be very promising, and the well is being prepared for a multi-packer fracture treatment. The rig has been moved to another location about two miles away, to drill another Torquay horizontal oil well. This well will be the last well drilled by Grand Banks before spring break-up.

Grand Banks will now focus on making the arrangements for a multi-well drilling program at Sinclair, Manitoba, consisting of approximately ten wells, to commence immediately after breakup. The Company has identified, using 3D seismic, approximately twenty additional light oil locations on its lands, with the potential for more based upon step-out and infill drilling. Grand Banks also has an inventory of six horizontal Torquay light oil wells that could be fracture stimulated using the new multi-packer technology.

Based upon this inventory, Grand Banks believes that it has the potential, from its land base to increase corporate production to at least 3,000 boe/d by the end of 2008.

Grand Banks is listed on the TSX-Venture Exchange under the Symbol GBE.

FORWARD LOOKING STATEMENTS

This press release contains forward-looking statements including expectations of future production. These statements are based on current expectations that involve a number of risks and uncertainties, which could cause actual results to differ from those anticipated.

BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management's Discussion and Analysis ("MD&A") should be read in conjunction with the audited financial statements of Grand Banks Energy Corporation ("Grand Banks" or the "Company") and accompanying notes for the year ended December 31, 2007.

In this MD&A, production and reserves information are commonly reported in units of barrels of oil equivalent ("boe"). For purposes of computing such units, natural gas is converted to equivalent barrels of oil using a conversion factor of six thousand cubic feet to one barrel of oil. This conversion ratio of 6:1 is based on an energy equivalent wellhead value for the individual products. Such disclosures of boes may be misleading, particularly if used in isolation. Readers should be aware that historical results are not necessarily indicative of future performance.

This MD&A and the annual financial statements and accompanying notes have been prepared by management and approved by the Audit Committee of the Board of Directors of Grand Banks and include information to March 17, 2008.

The quarterly financial statements have not been reviewed or audited on behalf of the shareholders by the Company's independent external auditors.

All financial measures presented in this Annual Report are expressed in Canadian dollars unless otherwise indicated.

Overview

Grand Banks Energy Corporation ("Grand Banks" or the "Company") recorded average sales of natural gas, crude oil and liquids during the three months and year ended December 31, 2007 of 1,344 boe/d and 1,016 boe/d respectively as compared to 860 boe/d and 852 boe/d for the corresponding periods of 2006. The three month and annual sales volumes rose as a result of the new production from the Tower Creek 02-21 natural gas well and from the Company's horizontal development drilling program on its Three Forks/Torquay light oil play along the Saskatchewan/Manitoba border.

With strong production performance from the Tower Creek 02-21 well, the success of the third quarter Three Forks/Torquay drilling program and the royalty changes announced in Alberta the Company's activities and corporate resources in the fourth quarter were focused on advancing its growth opportunities in Saskatchewan and Manitoba.

During the fourth quarter, the 3D seismic data covering 22 square miles of Grand Banks' acreage on the Three Forks/Torquay play was interpreted and integrated with the geological model to identify over 30 follow up horizontal drilling locations on these lands. Using this information, one successful vertical well was drilled and a second well, a horizontal well, was spud prior to year end. Subsequent to year end the horizontal well was successfully completed using the "Packers Plus" multiple fracture technology. In late December, the Company used the "Packers Plus" technology to recomplete one of the horizontal wells drilled in the third quarter. Based on the results of the recompletion and completion of the most recent well the Company anticipates that it can successfully develop all of its Three Forks/Torquay lands using this technology. Additionally, during the fourth quarter the Company made key land acquisitions in its Kingsford area of Saskatchewan setting up three new Midale drilling locations.

Operational and financial results throughout the year mirrored the level and type of activities upon which the Company's resources were focused. During the first half of the year production levels declined as the majority of the Company's resources were committed to the construction of new production facilities for the Tower Creek 02-21 well and the sale of its Stoughton/Viewfield property. In the third quarter both natural gas and oil sales rose along with cash flow and earnings as the 02-21 well was brought on stream and corporate resources were then shifted to the Company's horizontal development drilling program on its Three Forks/Torquay play. The 02-21 well only contributed 2.0 mmcf/d of new natural gas sales in the third quarter due to facility constraints and initial production volumes from the Three Forks/Torquay oil wells averaged 160 bbls/d of light oil.

In the fourth quarter revenues, cash flow and earnings have continued to rise with higher natural gas production and strong oil prices. With normalized operations at the Tower Creek facilities and third party processing facilities, the 02-21 well contributed 3.1 mmcf/d of natural gas sales. The well is currently producing at gross raw rates of nearly 23 mmcf/d, the Company's net share of sales gas being approximately 3.2 mmcf/d or 540 boe/d.

The Company was also active on the acquisition and divesture front during 2007. Firstly, after consolidating its position in its Stoughton/Viewfield property in the first quarter, effective May 1, 2007 the Company disposed of its interest in this property for net proceeds of nearly $8,200,000. Secondly, late in the second quarter, Grand Banks acquired an additional 3.5% working interest in the Tower Creek 02-21 well, facilities and related lands for $3,500,000.

On October 25, 2007, the provincial government of Alberta announced changes to the existing royalty structure. This new oil and gas royalty regime is to take effect on January 1, 2009. The changes are intended to increase the royalties for conventional oil and natural gas, with sliding scale sensitivities to both commodity prices and well productivity rates. The Company requested its independent reserve engineers estimate the impact to its reserves evaluation based upon the currently released information on the new royalty regime. As of December 31, 2007, the Province had not introduced the enabling legislation nor had they provided enough clarity on a number of the issues for our independent reserve engineers to provide a precise calculation of net reserves and the net present value under the proposed new royalty regime. It is possible that the announced changes may be amended before coming into force. Under their forecast price assumptions, our independent reserve engineers have estimated that the change to the net present value, discounted at 10%, of the net revenue from our proved plus probable reserves would be a reduction of 0.9% from $116.1 million to $115.0 million.

On February 27, 2008 the Company announced it had formed a special committee to investigate strategic alternatives to maximize shareholder value. The Company believes that its oil properties could be more efficiently developed by a larger company with more resources, a better cost structure and lower cost of capital. An outright sale or business combination with a larger entity has the potential to give Grand Banks' shareholders an opportunity to realize additional value and liquidity.



The following table summarizes the results for the three months and years
ended December 31, 2007 and 2006:

----------------------------------------------------------------------------
Three Months Ended Years Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
(000s, except per share
amounts) ($) ($) (%) ($) ($) (%)
Financial Results
Gross revenues 7,316 4,315 70 21,764 17,504 24
Income (loss) before income
taxes 1,535 (41) 3844 2,229 (679) 428
Net income (loss) 2,631 1,265 108 3,325 627 430
Per share - basic 0.08 0.04 100 0.10 0.02 400
Per share - diluted 0.08 0.04 100 0.10 0.02 400
Funds flow from
operations (1) 4,266 2,219 92 11,526 9,706 19
Per share - basic 0.13 0.07 86 0.36 0.32 12
Per share - diluted 0.13 0.07 86 0.35 0.31 13
Additions to property and
equipment 2,552 7,237 (65) 22,980 26,079 (12)
Proceeds on disposal of
property and equipment - - - 8,255 123 6611
Total assets 56,474 52,251 8
Working capital
(deficiency) (12,437) (10,562) 18
Asset retirement obligation
(including current portion) 1,260 1,223 3
Flow-through share
obligations - 3,855 (100)
----------------------------------------------------------------------------
(000s) (#) (#) (%) (#) (#) (%)
Share Data
Equity outstanding
Common shares 32,556 31,915 2
Stock options 2,517 2,854 (12)
----------------------------------------------------------------------------
Fully diluted 35,073 34,769 1
----------------------------------------------------------------------------
Sales Volumes (average)
Crude oil and liquids
(bbls/d) 638 633 1 613 593 3
Natural gas (mcf/d) 4,235 1,363 211 2,421 1,556 56
Average boe/d (6:1) 1,344 860 56 1,016 852 19
----------------------------------------------------------------------------
Product Prices (average)
Crude oil and liquids
($/bbl) 81.86 59.21 38 72.12 63.07 14
Natural gas ($/mcf) 6.43 6.88 (7) 6.36 6.70 (5)
----------------------------------------------------------------------------
($/boe) ($/boe) (%) ($/boe) ($/boe) (%)
Netback Analysis
Oil and gas revenue (6:1) 59.14 54.48 9 58.64 56.11 5
Royalty expense 6.27 9.31 (33) 8.39 10.71 (22)
Operating costs 10.54 9.21 14 10.85 8.89 22
----------------------------------------------------------------------------
Netback 42.33 35.96 18 39.40 36.51 8
----------------------------------------------------------------------------
(1) Funds flow from operations is a non-GAAP measure that represents net
income plus depletion, depreciation and accretion, stock-based
compensation, future taxes and other non-cash expenses. See further
discussion under Non-GAAP Measures in the Management's Discussion and
Analysis.

Sales Volumes
----------------------------------------------------------------------------
Three Months Ended Years Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------

Sales Volumes (average) (%) (%)
Crude oil and liquids
(bbls/d) 638 633 1 613 593 3
Natural gas (mcf/d) 4,235 1,363 211 2,421 1,556 56
Average boe/d (6:1) 1,344 860 56 1,016 852 19
----------------------------------------------------------------------------


In the fourth quarter, average sales volumes on a boe basis increased by 56% due to the addition of new natural gas production at Tower Creek along with the new oil production from Saskatchewan and Manitoba. Natural gas sales volumes increased 211% due to the 3.1 mmcf/d of new natural gas sales at Tower Creek offset by natural production declines at the Company's other gas producing properties. Production from Tower Creek in the fourth quarter held steady as start up and third party maintenance issues were dealt with in the third quarter. Currently gross production from the 02-21 well is nearly 23 mmcf/d of raw gas; the Company's net share of sales gas is 3.2 mmcf/d or 540 boe/d. Oil and liquid sales in the fourth quarter increased 1% on the strength of 208 bbls/d of new production in the quarter from the new wells drilled in Saskatchewan and Manitoba. These production increases were offset by the sale of the Stoughton, Saskatchewan properties effective May 1, 2007 along with natural declines in production from existing wells at Kingsford and Frys East, Saskatchewan. The six new wells were drilled from mid-June through to the end of August, with production commencing in mid-July from the first two wells drilled with the remaining wells being tied in by mid-September. All the wells are now on production and are currently producing over 200 bbls/d of light oil.

Sales volumes for 2007 reflect the impact of the second quarter natural gas and third quarter oil production additions offset by natural production declines, the sale of the Stoughton property and the lack of drilling activity in the first half of the year and reduced drilling activity in the fourth quarter. All of the Company's sales volumes consisted of natural gas and light to medium gravity crude oil, with no heavy oil.



Gross Revenues
----------------------------------------------------------------------------
Three Months Ended Years Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
(000s) ($) ($) (%) ($) ($) (%)
Crude oil and liquids 4,808 3,450 39 16,127 13,644 18
Natural gas 2,506 863 190 5,623 3,807 48
Other income 2 2 - 14 53 (74)
----------------------------------------------------------------------------
7,316 4,315 70 21,764 17,504 24
----------------------------------------------------------------------------


The 70% increase in revenues for the fourth quarter of 2007 was due to the 56% higher sales volumes as noted above and the 38% increase in prices realized for crude oil and liquids offset by the 7% drop in natural gas prices. The 24% increase in total revenues for the year ended December 31, 2007 was due to 56% higher natural gas sales volumes partially offset by 5% lower natural gas prices and 3% higher oil volumes with stronger oil prices. The improvement in average oil prices was due to the combination of higher world oil prices, offset by a stronger Canadian dollar but then partially corrected by an improvement in the overall quality of crude oil produced by the Company. For example on average in 2007 the Company received $81 per barrel of crude produced from its Three Forks/Torquay properties at Frys East and Sinclair as compared to the $66 per barrel received for its Midale production from Kingsford. The Company has not hedged any of its production.



Royalty Expenses
----------------------------------------------------------------------------
Three Months Ended Years Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
(000s) ($) ($) (%) ($) ($) (%)
Royalty expenses 776 737 5 3,111 3,331 (7)
----------------------------------------------------------------------------
$/boe 6.27 9.31 (33) 8.39 10.71 (22)
----------------------------------------------------------------------------
Royalty rate 10.6% 17.1% (38) 14.3% 19.1% (25)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The decrease in royalty expenses in the fourth quarter on a boe basis was due to the production from the Tower Creek 02-21 well and four of the six new oil wells being on "royalty holiday". Royalty expense for the quarter showed a small increase due to higher sales values and mineral and production taxes on the new production in Saskatchewan. For the year ended December 31, 2007, royalty expenses were lower due to the royalty holidays noted above and the Alberta Crown annual capital cost and custom processing fee adjustments that were recorded in the second quarter of 2007. These reductions were partially offset by higher crown royalty rates in Saskatchewan as wells at Kingsford came off royalty holiday starting in June, 2006. Due to the high level of productivity of the Tower Creek well, it is expected to come off royalty holiday in the first quarter of 2008. Royalty expense in 2006 was presented net of funds receivable under the Alberta Royalty Tax Credit ("ARTC") program. The ARTC program was discontinued effective January 1, 2007, the 2006 royalty expense had been reduced by $339,000 of ARTC.



Production Expenses
----------------------------------------------------------------------------
Three Months Ended Years Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
(000s) ($) ($) (%) ($) ($) (%)
Production Expenses 1,304 729 79 4,023 2,766 45
----------------------------------------------------------------------------
$/boe 10.54 9.21 14 10.85 8.89 22
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Production expenses in the fourth quarter of 2007 increased by 79% over 2006 as the result of the 56% increase in production levels and higher per unit operating costs at Tower Creek. For the year ended December 31, 2007 production expenses increased for the reasons noted above in addition to workover costs at Kingsford and a one time adjustment to processing fees at Kakwa.



Depletion, Depreciation and Accretion
----------------------------------------------------------------------------
Three Months Ended Years Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
(000s) ($) ($) (%) ($) ($) (%)
Depletion and depreciation 2,623 2,125 23 8,680 9,493 (9)
Accretion of Asset Retirement
Obligations 22 24 (8) 72 85 (15)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2,645 2,149 23 8,752 9,578 (9)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$/boe 21.39 27.15 (21) 23.60 30.79 (23)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The increase in depletion and depreciation expense in the fourth quarter was due to higher production volumes offset by the lower depletion and depreciation rate per boe. The decrease in the depletion and depreciation expense for the year was due to the improved depletion and depreciation rate which more than offset the increase in production volumes. The lower depletion rate was due to the addition of new proven oil reserves in Saskatchewan and Manitoba in 2006 and 2007, the discovery at Tower Creek in 2006, plus the subsequent upward revision of reserves and the significant conversion of probable reserves to proved reserves in 2007, and finally, the positive impact of the sale of the Stoughton/Viewfield property.



Interest
----------------------------------------------------------------------------
Three Months Ended Years Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
(000s) ($) ($) (%) ($) ($) (%)
Interest Expenses 179 40 348 554 177 213
----------------------------------------------------------------------------
$/boe 1.45 0.51 184 1.49 0.57 161
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The increase in interest costs was the result of the increase in interest on bank indebtedness. For much of 2006, the Company had cash on hand from its flow-through equity financings and accordingly had not drawn any funds on its bank lines until late in the third quarter. Throughout 2007, the Company has drawn on both its revolving bank line and its term facility to fund its capital program which had shifted emphasis from exploration to development.



General and Administrative Costs
----------------------------------------------------------------------------
Three Months Ended Years Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
(000s) ($) ($) (%) ($) ($) (%)
Gross General and
Administrative costs 852 736 16 2,929 2,082 41
Overhead recovered (72) (172) (58) (490) (587) (17)
Overhead capitalized - - - - - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
780 564 38 2,439 1,495 63
----------------------------------------------------------------------------
----------------------------------------------------------------------------
$/boe 6.31 7.12 (11) 6.58 4.81 37
----------------------------------------------------------------------------
----------------------------------------------------------------------------


General and administrative costs, net of overhead recovered, for the three months and year ended December 31, 2007 increased by 38% and 63% respectively over the comparative periods of 2006. This increase was due to the cost of expanded operations and management changes resulting in higher salaries, consulting fees and associated personnel costs. Additionally, office rent in the fourth quarter increased, and in the second quarter bonuses were paid related to the successful sale of the Stoughton/Viewfield property. The decrease in the cost per boe in the fourth quarter related to the 56% increase in production volumes while the increase in the cost per boe for the year was attributable to the 19% increase in production volumes compared to the 41% increase in general and administrative costs.



Stock-Based Compensation
----------------------------------------------------------------------------
Three Months Ended Years Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
(000s) ($) ($) (%) ($) ($) (%)
Stock-Based Compensation 97 137 (29) 656 836 (22)
----------------------------------------------------------------------------
$/boe 0.78 1.73 (55) 1.77 2.69 (34)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Stock-based compensation costs for the year decreased $180,000 due to the decrease in the value assigned to each option. During 2007, the Company granted 1,364,000 stock options compared to 709,000 granted in 2006. The increase in the number of stock options granted related to the management changes in the first half of the year. Stock-based compensation costs are amortized over the vesting period, which is two years from the date of grant.

Net Income

Grand Banks recorded net income of $2,631,000 ($0.08 per share) and $3,325,000 ($0.10 per share) for the three months and year ended December 31, 2007 compared with net income of $1,265,000 ($0.04 per share) and $627,000 ($0.02 per share) for the corresponding periods in 2006.

The improvement in net earnings was due primarily to higher net sales revenues from Tower Creek, higher net oil revenues due to higher oil prices and to the reduction in depletion and depreciation rates which have improved due to lower finding and development costs, the conversion of probable reserves to proved reserves in 2007 and the sale of the Stoughton/Viewfield property.

Liquidity and Capital Resources

At December 31, 2007, the Company had a working capital deficiency of $12,437,000 (including $11,213,000 drawn on its revolving bank loan) and $855,000 drawn on its non-revolving reducing term facility compared to a working capital deficiency of $10,562,000 (including $6,328,000 drawn on its revolving bank loan) at December 31, 2006. At December 31, 2007, the Company had a $19,000,000 ($10,500,000 - December 31, 2006) revolving line of credit agreement with a Canadian financial institution. The line of credit bears interest at prime rate plus 0.25% per annum and the non-revolving term facility bears interest at 7.5% and is repayable in 25 blended monthly payments of principal and interest of $37,000. For the year ended December 31, 2007, the Company had funds flow from operations of $11,526,000. (See "Non-GAAP Measures.") The Company has not declared any dividends.

On May 1, 2007 the Company closed the sale of its Stoughton/Viewfield property resulting in net proceeds of nearly $8,200,000.

Based on our December 31, 2007 reserve evaluation, the Company believes its lines of credit could be expanded and these expanded lines of credit and funds flow from operations are expected to exceed the Company's working capital commitments for the forthcoming year.

The Company had a $3,855,000 flow-through spending obligation at December 31, 2006, which was completely satisfied in August, 2007.

Financing and Investing Activities

In February 2007 the Company borrowed $1,200,000 in the form of a fixed term loan to help finance the facilities for the tie-in of the Tower Creek well. To December 31, 2007, $345,000 in principal had been repaid. In May 2007, the Company was granted an increase in its revolving line of credit from $10,500,000 to $19,000,000.



----------------------------------------------------------------------------
Three Months Ended Years Ended
December 31, December 31,
2007 2006 Change 2007 2006 Change
----------------------------------------------------------------------------
(000s) ($) ($) (%) ($) ($) (%)
Land & property acquisitions 557 33 1588 4,599 1,478 211
Geological and geophysical 23 - - 1,421 312 355
Drilling and completion 1,757 6,351 (72) 12,780 20,505 (38)
Equipment and gathering 196 853 (77) 4,128 3,760 10
G&A capitalized - - - - - -
Office equipment 19 - - 52 24 117
----------------------------------------------------------------------------
2,552 7,237 (65) 22,980 26,079 (12)
Proceeds of disposition - - - (8,255) (123) (6611)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Additions to property and
equipment, net of proceeds 2,552 7,237 (65) 14,725 25,956 (43)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Land and property acquisition costs were higher due to the $3,500,000 acquisition of an additional 3.5% working interest in the Tower Creek 02-21 well and associated facilities.

Geological and geophysical costs were higher due to the two 3D seismic programs shot on the Company's Three Forks/Torquay play during the third quarter. Drilling and completion costs were lower due to fewer wells drilled. The Company participated in the drilling of 17 wells (9.5 net) in 2007 as compared to 28 wells (15.6 net) in 2006. The increases in the equipping and gathering costs were related to the Tower Creek facilities.

Financial Instruments

Grand Banks has not entered into any commodity or financial instrument hedges; however, it does carry various forms of financial instruments, all of which are recognized in the Company's financial statements. Unless otherwise indicated in the financial statements, it is management's opinion that the Company is not exposed to excessive interest, currency or credit risks arising from these financial instruments. The fair values of these financial instruments approximate their carrying values, unless otherwise indicated. The Company has no unrecognized gains or losses on its financial instruments.



Obligations
----------------------------------------------------------------------------
As of December 31, 2007 Payments Due By Period
---------------------------------------------
Less Than 1 1 - 3 4 - 5 After 5
Total Year Years Years Years
----------------------------------------------------------------------------
(000s) ($) ($) ($) ($) ($)
Office lease 1,255 320 641 294 -
Natural gas transportation 910 490 420 - -
Flow-through shares - - - - -
Lease rentals land 702 141 245 215 101
Asset retirement obligations 3,790 73 335 144 3,238
----------------------------------------------------------------------------
Total contractual obligations 6,657 1,024 1,641 653 3,339
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Transactions with Related Parties

All related party transactions are in the normal course of operations and have been measured at the agreed to exchange amounts, which is the amount of consideration established and agreed to by the related parties and which is similar to those negotiated with third parties.

(a) The Company conducts oil and gas exploration and development activities and related transactions with organizations managed or controlled by directors. These transactions are negotiated and conducted using standard industry agreements and terms. The amounts associated with these transactions are insignificant to the operations of the Company.

(b) Included in general and administrative expenses are consulting fees of $380,000 (2006 - $328,000) incurred with companies controlled by officers of the Company for the year ended December 31, 2007.

(c) Included in general and administrative expenses are legal fees of $20,000 (2006 - $55,000) incurred with a firm in which one of the Company's officers was a partner for the year ended December 31, 2007.

(d) Included in general and administrative expenses is $78,000 (2006 - $53,000) paid for directors' fees to independent directors for the year ended December 31, 2007.


Summary of Quarterly Results

Eight-Quarter Comparison

The quarterly results are prepared without audit or review by the Company's independent auditors. The following table summarizes the Company's financial and operating highlights for the past eight quarters. Sales volumes are the average for the periods shown, net to the Company, before the deduction of royalties.



----------------------------------------------------------------------------
Three Months Ended Mar.31, Jun.30, Sep.30, Dec.31,
2006 2006 2006 2006
----------------------------------------------------------------------------
Sales Volumes
Crude oil and liquids (bbls/d) 643 527 569 633
Natural gas (mcf/d) 1,844 1,561 1,464 1,363
Average boe/d (6:1) 951 787 813 860
----------------------------------------------------------------------------
($) ($) ($) ($)
Product Prices
Crude oil and liquids ($/bbl) 57.21 67.10 70.17 59.21
Natural gas ($/mcf) 7.80 6.02 5.89 6.88
Oil equivalent ($/boe) 53.84 56.86 59.68 54.48
----------------------------------------------------------------------------
(000s, except per share amounts) ($) ($) ($) ($)

Financial Results
Gross revenues 4,632 4,088 4,469 4,315
Net income (loss) (425) (439) 226 1,265
Per share - basic (0.01) (0.01) (0.01) 0.04
Per share - diluted (0.01) (0.01) (0.01) 0.04
Funds flow from operations 2,803 2,209 2,475 2,219
Additions to property and equipment,
net of proceeds 7,196 5,426 6,097 7,237
Total assets 43,511 42,371 44,526 52,251
Working capital (deficiency) (2,576) (6,011) (9,571) (10,562)
Flow-through share obligation 3,500 1,800 740 3,855
Asset retirement obligation 964 753 837 1,223
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Three Months Ended Mar.31, Jun.30, Sep.30, Dec.31,
2007 2007 2007 2007
----------------------------------------------------------------------------
Sales Volumes
Crude oil and liquids (bbls/d) 616 554 642 638
Natural gas (mcf/d) 1,056 1,026 3,324 4,235
Average boe/d (6:1) 792 725 1,196 1,344
----------------------------------------------------------------------------
($) ($) ($) ($)
Product Prices
Crude oil and liquids ($/bbl) 61.51 67.42 76.39 81.86
Natural gas ($/mcf) 7.51 7.98 5.42 6.43
Oil equivalent ($/boe) 57.86 62.81 56.07 59.14
----------------------------------------------------------------------------
(000s, except per share amounts) ($) ($) ($) ($)

Financial Results
Gross revenues 4,124 4,152 6,172 7,316
Net income (loss) (320) 328 686 2,631
Per share - basic (0.01) 0.01 0.02 0.08
Per share - diluted (0.01) 0.01 0.02 0.08
Funds flow from operations 1,885 2,086 3,289 4,266
Additions to property and equipment,
net of proceeds 2,939 314 8,990 2,552
Total assets 50,618 53,479 56,024 56,474
Working capital (deficiency) (10,382) (8,721) (14,280) (12,437)
Flow-through share obligation 2,864 1,475 - -
Asset retirement obligation 1,253 1,214 1,248 1,260
----------------------------------------------------------------------------


Sales Volumes

Early in 2006, total sales volumes dropped modestly as natural gas volume declines at Virginia Hills exceeded new oil sales volumes from new wells at Kingsford, Saskatchewan and Sinclair, Manitoba. For the balance of 2006, natural gas volumes continued to decline as a few new gas wells tempered the effect of the Virginia Hills well. Oil production peaked in the first quarter of 2006 and then held relatively steady as new wells replaced the declining production from older wells.

Overall natural gas and oil volumes had declined in the first half of 2007 as the Company had concentrated on the tie-in of wells drilled in 2006, particularly the Tower Creek gas discovery. The third quarter of 2007 reflected the initial effects of the Tower Creek natural gas discovery well drilled in mid-2006, that commenced production during the last week of June, 2007. Natural gas production in the fourth quarter increased due to normalized operations at Tower Creek.

Oil production in the first half of 2007 declined due to the lack of development drilling activity prior to the third quarter of 2007. Oil production increased during the second half of 2007 as horizontal development wells at Frys, Saskatchewan and Sinclair, Manitoba were drilled and came on production throughout the third quarter.

Gross Revenues

The decrease in gross sales revenues from the first quarter of 2006 to the third quarter of 2006 was a result of a decrease in natural gas prices, along with the decrease in sales volumes. The subsequent decline in gross revenues during 2006 to the second quarter of 2007 relate to the decreases in sales volumes which were slightly offset by the steady increase in product prices until the third quarter of 2007. Revenues rose in the third quarter of 2007 due to new sales volumes from Tower Creek and the Three Forks/Torquay oil wells along the Saskatchewan/Manitoba border. Revenues continued to rise in the fourth quarter due to increase gas volumes from Tower Creek and higher commodity prices. All of the Company's natural gas, crude oil and liquids were sold at spot prices, which are subject to world and North America supply and demand fundamentals.

Net Income (Loss)

The Company incurred a modest loss in the first and second quarters of 2006. In the third quarter of 2006, the Company recorded net income of $226,000 as the increased proved reserves from the Tower Creek well reduced the depletion rate. The fourth quarter of 2006 also showed net income of $1,265,000 as a result of a lower depletion rate combined with a future tax recovery of $1,306,000, related to the issue of flow-through shares.

The Company recorded a net loss of $320,000 in the first quarter of 2007 as lower sales revenues, higher general and administrative expenses and interest costs more than offset the improvements in depletion and depreciation expense. The net income of $328,000 recorded in the second quarter of 2007 is primarily due to the lower depletion and depreciation expense. In the third quarter of 2007 the Company recorded net income of $686,000 on the strength of higher sales and improved depletion and depreciation rates. This trend continue in the fourth quarter of 2007 as higher gas sales and commodity prices resulted in the largest earnings the Company has ever recorded.

Additions to Property and Equipment

Grand Banks' capital program, focused on drilling development oil wells in Saskatchewan mixed with exploratory natural gas wells in Alberta, has ranged between $5,000,000 and $7,000,000 per quarter, until in the first quarter of 2007 when the Company deferred some of its drilling plans to focus its capital resources on the tie-in of wells drilled in 2006. During the second quarter of 2007, the Company completed the facilities required to place the Tower Creek 02-21 well on production. The Company also drilled one horizontal oil well in the Frys area of Saskatchewan and started drilling a second one, both of which came on production in July of 2007. Additionally, the Company was active on the acquisition and divesture front in the second quarter of 2007. Firstly, after consolidating its position in its Stoughton/Viewfield property, the Company disposed of its interest in this property for net proceeds of nearly $8,200,000. Secondly, Grand Banks acquired an additional 3.5% working interest in the Tower Creek 02-21 well, facilities and related lands for $3,500,000. During the third quarter of 2007, the Company drilled four more wells and shot two 3D seismic programs on its Three Forks/Torquay play. The Company also abandoned the second well it was drilling in the Tower Creek area after encountering serious hole problems during drilling. Capital expenditures in the fourth quarter were limited as the Company only drilled one new well and recompleted another as it focused its resources on advancing its growth opportunities in Saskatchewan and Manitoba by consolidating land positions and completing its technical work on the Three Forks/Tourquay play.

Working Capital (Deficiency)

Throughout 2006 and 2007, the Company has been working with a net working capital deficit (including revolving bank loans as a current liability) as it has raised less flow through capital and focused more and more of its operations on development activities. Exploration drilling success as well as development drilling success has allowed the Company to prudently leverage its balance sheet while capital spending has exceeded funds flow from operations. The working capital deficiency at December 31, 2007 stood at $12,437,000 which represents less than one year's funds flow from operations based on an annualized fourth quarter funds flow from operations of $4,266,000.

Flow-Through Obligations

In 2006, the Company issued $4,200,000 of flow-through shares. The remaining flow-through obligations at December 31, 2006 totaled $3,855,000, which were all satisfied during the third quarter of 2007.

Asset Retirement Obligations

The asset retirement obligations grew from $964,000 in the first quarter of 2006 to $1,260,000 in the fourth quarter of 2007 as the Company continued to drill wells that are required to be abandoned and reclaimed at some point in the future. The asset retirement obligation represents the present value of future abandonment and reclamation cost for the Company's interest in the wells. These amounts include the current portion of asset retirement obligations, which are included in working capital.



Other Items

Outstanding Shares, Options and Warrants
The following table is a summary of the Company's share capital structure:

----------------------------------------------------------------------------
As at December 31, March 17,
2007 2008
----------------------------------------------------------------------------
(000s) (#) (#)
Common shares outstanding 32,556 32,559
Options outstanding 2,517 2,514
----------------------------------------------------------------------------
Fully diluted 35,073 35,073
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Weighted
Average Weighted
Exercise Average
Shares Price Term
----------------------------------------------------------------------------
(#000s) ($) (Years)
Options outstanding at December 31, 2006 2,854 1.24 4.1
----------------------------------------------------------------------------
Options outstanding at December 31, 2007 2,517 1.30 4.0
----------------------------------------------------------------------------
Options vested at December 31, 2007 1,718 1.24 3.2
----------------------------------------------------------------------------


Accounting Policy Changes

On January 1, 2007, the Company adopted the new Canadian accounting standards for financial instruments - recognition and measurement, financial instruments - presentations and disclosures, hedging and comprehensive income. Prior periods have not been restated. Additional disclosure requirements for financial instruments and accounting changes have been approved by the Canadian Institute of Chartered Accountants and will be required disclosure beginning January 1, 2008. These new standards have no material impact on the Company's financial statements.

(a) Financial Instruments - Recognition and Measurement

This new standard requires all financial instruments within its scope, including all derivatives, to be recognized on the balance sheet initially at fair value. Subsequent measurement of all financial assets and liabilities except those held-for-trading and available for sale are measured at amortized cost determined using the effective interest rate method. Held-for-trading financial assets are measured at fair value with changes in fair value recognized in earnings. Available-for-sale financial assets are measured at fair value with changes in fair value recognized in other comprehensive income and reclassified to earnings when derecognized or impaired. There were no changes to the measurement of existing financial assets and liabilities at the date of adoption.

Cash and cash equivalents are designated as "held-for-trading" and are measured at carrying value, which approximates fair value due to the short-term nature of these instruments. Accounts receivable are designated as "loans and receivables" and accounts payable and accrued liabilities and bank loans are designated as "other liabilities", all of which are measured at carrying value, which approximates fair value due to the short-term nature of these instruments.

Risk management assets and liabilities are derivative financial instruments classified as "held-for-trading" unless designated for hedge accounting. The Company has no commodity contracts or fixed-price physical contracts in place at this time.

(b) Derivatives

The Company may use various types of derivative financial instruments to manage risks associated with crude oil and natural gas fluctuations. These instruments are not used for trading or speculative purposes. Proceeds and costs realized from holding the related contracts are recognized in petroleum and natural gas revenues at the time that each transaction under a contract is settled. For the unrealized portion of such contracts, the Company utilized the fair value method of accounting. The fair value is based on an estimate of the amounts that would have been paid to or received from counterparts to settle these instruments given quoted future market prices and other relevant factors. The method requires the fair value of the derivative financial instruments to be recorded at each balance sheet date with unrealized gains or losses on these contracts recorded through net earnings. The Company had no derivatives in 2007.

(c) Embedded Derivatives

On adoption, the Company elected to recognize, as separate assets and liabilities, only for those embedded derivatives in hybrid instruments issued, acquired or substantively modified after January 1, 2003. The Company did not identify any material embedded derivatives which require separate recognition and measurement.

(d) Other Comprehensive Income

The new standards establish a new statement of comprehensive income, which is comprised of net earnings and other comprehensive income. The Company currently has no other comprehensive income items.

Beginning January 1, 2007 the Company adopted Section 1506 "Accounting Changes" the only impact of which is to provide disclosure of when an entity has not applied a new source of GAAP that has been issued but is not yet effective. This is the case with Section 3862 "Financial Instruments - Disclosures" and Section 3863 "Financial Instruments - Presentation" which are required to be adopted for fiscal years beginning on or after October 1, 2007. The Company will adopt these standards on January 1, 2008 and it is expected the only effect on the Company will be incremental disclosures regarding the significance of financial instruments for the entity's financial position and performance and the nature, extent and management of risks arising from financial instruments to which the entity is exposed.

As of January 1, 2008, the Company will be required to adopt CICA Handbook Section 1535 "Capital Disclosures", which requires entities to disclose their objectives, policies and processes for managing capital, and in addition, whether the entity has complied with any externally imposed capital requirements. The Company is assessing the impact of this new standard on its financial statements and anticipates that the main impact will be in terms of additional disclosures required.

As of January 1, 2008, the Company will be required to adopt CICA Handbook Section 3031, "Inventories". This new standard will have no impact on the Company's financial statements.

In February 2008, the CICA issued Section 3064, "Goodwill and Intangible Assets", replacing Section 3062, "Goodwill and Other Intangible Assets" and Section 3450, "Research and Development Costs". Various changes have been made to other sections of the CICA Handbook for consistency purposes. The new Sections will be applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. Accordingly, the Company will adopt the new standards for its fiscal year beginning January 1, 2009. It establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The Company is currently evaluating the impact of the adoption of this new Section on its financial statements.

In January 2006, the CICA Accounting Standards Board ("AcSB") adopted a strategic plan for the direction of accounting standards in Canada. As part of that plan, accounting standards in Canada for public companies are expected to converge with International Financial Reporting Standards ("IFRS") by the start of 2011. The Company continues to monitor and assess the impact of convergence of Canadian GAAP and IFRS.

Critical Accounting Estimates

Management is required to make judgments, assumptions and estimates in the application of generally accepted accounting principles that have a significant impact on the financial results of the Company.

Reserve estimates have a significant impact on income or loss, as they are a key component in the calculation of depletion and depreciation and site restoration costs. A change in the reserve quantity estimates will result in a corresponding change in depletion, depreciation and site restoration costs. In addition, if capitalized costs are determined to be in excess of the calculated ceiling, which is based on reserve quantities and values, the excess must be written off as an expense. The reserves and estimated future net cash flow from the assets of Grand Banks have been independently evaluated.

Future site restoration costs are estimated and amortized over the life of reserves. These costs were estimated by management using industry standard guidelines. A change in estimated future site restoration costs will change the amortization of site restoration costs included in depletion and depreciation expense.

Non-GAAP Measures

Funds flow from operations is not a recognized measure under Canadian generally accepted accounting principles ("GAAP"). Management believes that funds flow from operations is a useful measure of financial performance. For the purposes of funds flow from operations calculations, the following table reconciles the non-GAAP financial measures "funds flow from operations" to "net income," the most comparable measure calculated in accordance with GAAP:



----------------------------------------------------------------------------
Three Months Ended Years Ended
December 31, December 31,
2007 2006 2007 2006
----------------------------------------------------------------------------
(000s) ($) ($) ($) ($)
Net income 2,631 1,265 3,325 627
Adjustments for:
Depletion, depreciation
and accretion 2,645 2,149 8,752 9,578
Stock-based compensation 97 137 656 836
Future income tax recovery (1,096) (1,306) (1,096) (1,306)
Asset retirement costs incurred (11) (26) (111) (29)
----------------------------------------------------------------------------
Funds flow from operations 4,266 2,219 11,526 9,706
----------------------------------------------------------------------------


Netback is the average per unit of volume for oil and gas revenues less royalties and production costs incurred. Netback is expressed in terms of dollars per boe and is calculated in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.

Forward-Looking Statements

This Annual Report contains forward-looking or outlook information with respect to Grand Banks. The use of any of the words "anticipate," "continue," "estimate," "expect," "may," "will," "project," "should," "believe," "outlook," and similar expressions are intended to identify forward-looking statements. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in the Company's forward-looking statements. Consequently, all of the forward-looking statements made in this Annual Report are qualified by these cautionary statements and there can be no assurance that actual results or developments anticipated by the Company will be realized, or that they will have the expected consequences or effects on the Company or its business or operations. The Company assumes no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events or otherwise.

The Company's actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this MD&A.

- Volatility in market prices for oil and natural gas.

- Risks inherent in the Company's operations.

- Geological, technical, drilling and processing problems.

- General economic conditions.

- Industry conditions, including fluctuation in the price of oil and natural gas.

- Governmental regulations.

- Fluctuation in foreign exchange and interest rates.

- Unanticipated events that can reduce production or cause production to be shut-in or delayed.

- Failure to obtain industry partners and other third party consents and approvals, when required.

- The need to obtain required approvals from regulatory authorities.

- The other factors discussed in the "Operational and Other Business Risks" section of this MD&A.

Operational and Other Business Risks

Need to Replace and Grow Reserves

The future oil and natural gas production of Grand Banks, and therefore future cash flows, are highly dependent upon ongoing success in exploring its current and future undeveloped land base, exploiting the current producing properties and acquiring or discovering additional reserves. Without reserve additions through exploration, acquisition or development activities, reserves and production will decline over time as reserves are depleted.

The business of discovering, developing or acquiring reserves is capital intensive. To the extent cash flows from operations are insufficient and external sources of capital become limited or unavailable, the ability of Grand Banks to make the necessary capital investments to maintain and expand its oil and natural gas reserves may be impaired.

There can be no assurance that the Company will be able to find and develop or acquire additional reserves to replace and grow production at acceptable costs.

Exploration, Development and Production Risks

Oil and natural gas exploration involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that expenditures made on future exploration by Grand Banks will result in new discoveries of oil and natural gas in commercial quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions such as over pressured zones, tools lost in the hole and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.

The long-term commercial success of Grand Banks depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. No assurance can be given that the Company will be able to continue to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participation are identified, Grand Banks may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic.

Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rate over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.

Exploration, Development and Production Risks (continued)

In addition, oil and gas operations are subject to the risks of exploration, development and production of oil and natural gas properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blowouts, sour gas releases, fires and spills. Losses resulting from the occurrence of any of these risks could have a materially adverse effect on future results of operations, liquidity and financial condition.

Reserve Estimates

The production forecast and recoverable estimates contained in the Company's engineering report are only estimates and the actual production and ultimate recoverable reserves from the properties may be greater or less than the reserve estimates of Paddock Lindstrom & Associates Ltd. ("Paddock Lindstrom").

There are numerous uncertainties inherent in estimating quantities of reserves and cash flows to be derived from, including many factors that are beyond the control of Grand Banks. The reserve and cash flow information set forth herein represent estimates only. The reserves and estimated future net cash flow from the assets of Grand Banks have been independently evaluated by Paddock Lindstrom at December 31, 2007. These evaluations include a number of assumptions relating to factors such as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditure, marketability of production, future prices of oil and natural gas, operating costs and royalties and other government levies that may be imposed over the producing life of the reserves.

These assumptions were based on price forecasts in use at the date the relevant evaluations were prepared and many of these assumptions are subject to change and are beyond the control of the Company. Actual production and cash flows derived therefrom will vary from these evaluations, and such variations could be material. The foregoing evaluations are based in part on the assumed success of exploitation activities intended to be undertaken in future years. The reserves and estimated cash flows to be derived therefrom contained in such evaluations will be reduced to the extent that such exploitation activities do not achieve the level of success assumed in the evaluations.

Volatility of Oil and Natural Gas Prices

The operational results and financial condition of Grand Banks will be dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated widely during recent years and are determined by supply and demand factors, including weather and general economic conditions as well as conditions in other oil and natural gas regions. Any decline in oil and natural gas prices could have an adverse effect of the operations, proved reserves and financial conditions of Grand Banks and could result in a reduction of the net production revenue of the Company causing a reduction in its oil and gas acquisition and development activities. In addition, bank borrowings that might be made available to the Company are typically determined in part by the borrowing base of the reserves of Grand Banks. A sustained material decline in prices from historical average prices could reduce the borrowing base of the Company, therefore reducing the bank credit available to Grand Banks and possibly requiring that a portion of such bank debt be repaid.

Grand Banks uses the full cost method of accounting for oil and natural gas properties. Under this accounting method, capitalized costs are reviewed on a quarterly basis for impairment to ensure that the carrying amount of these costs is recoverable based on expected future cash flows.

Operational Hazards and Other Uncertainties

Oil and natural gas exploration operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts and oil spills, each of which could result in substantial damage to oil and natural gas wells, production faculties, other property and the environment or in personal injury.

In accordance with industry practice, Grand Banks is not fully insured against all of these risks, nor are all such risks insurable. Although Grand Banks maintains liability insurance, where available, in an amount that it considers adequate and consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event Grand Banks could incur significant costs that could have a material adverse affect upon its financial condition. Business interruption insurance may also be purchased for selected facilities, to the extent that such insurance is available. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including premature decline of reservoirs and the invasion of water into producing formations.

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment in the particular areas where such activities will be conducted. Demand for such equipment or access restrictions may affect the availability and/or cost of such equipment to Grand Banks and may delay exploration and development activities. To the extent Grand Banks is not the operator of its oil and gas properties, the Company will be dependent on other operators for timing of activities related to non-operating properties and will be largely unable to direct or control the activities of the operators.

Although property title reviews are completed according to industry standards prior to the purchase of most oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat the claim of Grand Banks, which could result in the reduction of the revenue received by the Company.

Competition

There is strong competition relating to all aspects of the oil and natural gas industry. Grand Banks actively competes for capital, skilled personnel, undeveloped land, reserve acquisitions, access to drilling rigs, service rigs and other equipment, access to processing facilities and pipeline and refining capacity, and in all other aspects of its operations with a substantial number of other organizations, many of which may have greater technical and financial resources than Grand Banks.

Key Personnel

The success of Grand Banks depends in large measure on certain key personnel. The loss of the services of such key personnel could have a material adverse affect on the Company. Grand Banks does not have key person insurance in effect for management. The contributions of these individuals to the immediate operations of Grand Banks are likely to be of central importance. In addition, the competition for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that the Company will be able to continue to attract and retain all personnel necessary for the development and operation of its business.

Environmental Risks

The oil and natural gas industry is subject to environmental regulations pursuant to a variety of international conventions and Canadian federal, provincial and municipal laws, regulations and guidelines. A breach of such regulations may result in the imposition of fines or issuances of clean-up orders in respect of Grand Banks or its assets. Such regulations may be changed to impose higher standards and potentially more costly obligations on the Company. There can be no assurance that future environmental costs will not have a material adverse affect on Grand Banks.

Other Information

Additional information regarding Grand Banks Energy Corporation's reserves and other data is available on the Company's website at www.grandbanksenergy.com and on the Canadian Securities Administrators' System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com.

MANAGEMENT'S RESPONSIBILITY STATEMENT

To the Shareholders of Grand Banks Energy Corporation

The accompanying financial statements and all information contained in the Annual Report are the responsibility of management. The financial statements of the Company have been prepared by management in accordance with the accounting policies set out in the accompanying notes to the financial statements. In the opinion of management, the financial statements have been prepared with acceptable limits of materiality and are in accordance with
Canadian generally accepted accounting principles ("GAAP") appropriate in the circumstances.

Management maintains systems of control appropriate for the Company's size and operations. Policies and procedures are designed to give reasonable assurance those transactions are properly authorized, assets are safeguarded and financial records properly maintained to provide reliable and timely financial information for the preparation of financial statements.

The Audit Committee of the Company's Board of Directors, comprised of non-management Directors, recommends the nomination of the independent auditors and meets with management and the independent auditors to satisfy themselves that management fulfills its responsibilities for financial reporting and control. The Committee reviews the financial statements with the external auditors, considers auditors' independence and approves the auditors' fees.

The financial statements have been audited by Deloitte & Touche LLP, independent auditors, and have been approved by the Board of Directors on the recommendation of the Audit Committee.

EDWARD C. McFEELY, President & Chief Executive Officer

JOHN KALMAN, C.A., Vice President Finance & Chief Financial Officer

Calgary, Alberta

March 17, 2008


AUDITORS' REPORT

To the Shareholders of Grand Banks Energy Corporation

We have audited the balance sheets of Grand Banks Energy Corporation as at December 31, 2007 and 2006 and the statements of operations, comprehensive income and retained earnings and cash flows for the years then ended. These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these financial statements present fairly, in all material respects, the financial position of Grand Banks Energy Corporation as at December 31, 2007 and 2006 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

Deloitte & Touche LLP, Chartered Accountants

Calgary, Alberta

March 7, 2008




GRAND BANKS ENERGY CORPORATION
2007 Annual Report


BALANCE SHEETS

----------------------------------------------------------------------------
As of December 31 2007 2006
----------------------------------------------------------------------------
(000s) ($) ($)
ASSETS
Current
Cash and cash equivalents - -
Accounts receivable 4,225 6,044
Prepaid expenses and advances 291 160
----------------------------------------------------------------------------
4,516 6,204
Property and equipment (Note 4) 50,862 44,741
Future tax asset (Note 10) 1,096 1,306
----------------------------------------------------------------------------
56,474 52,251
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS'EQUITY
Current
Revolving bank loan (Note 5) 11,213 6,328
Current portion of long-term bank loan (Note 5) 397 -
Accounts payable and accrued liabilities 5,270 10,176
Current portion of asset retirement obligation
(Note 6) 73 262
----------------------------------------------------------------------------
16,953 16,766
Long-term bank loan (Note 5) 458 -
Asset retirement obligation (Note 6) 1,187 961
----------------------------------------------------------------------------
18,598 17,727
----------------------------------------------------------------------------
Shareholders'Equity
Share capital (Note 7) 30,365 30,489
Share purchase loans (Note 9) (48) (48)
Contributed surplus (Note 8) 2,599 2,448
Retained earnings 4,960 1,635
----------------------------------------------------------------------------
37,876 34,524
----------------------------------------------------------------------------
Subsequent Event (Note 16) 56,474 52,251
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the financial statements.

On behalf of the Board of Directors:

W.J. McNAUGHTON, Chairman of the Audit Committee

KENNETH H. HAYES, Director


STATEMENTS OF OPERATIONS, COMPREHENSIVE INCOME AND RETAINED EARNINGS

----------------------------------------------------------------------------
For the Years Ended December 31 2007 2006
----------------------------------------------------------------------------
(000s, except per share amounts) ($) ($)
Revenue
Crude oil and liquids 16,127 13,644
Natural gas 5,623 3,807
Other income 14 53
----------------------------------------------------------------------------
21,764 17,504
Less: royalties (3,111) (3,331)
----------------------------------------------------------------------------
18,653 14,173
----------------------------------------------------------------------------
Expenses
Production 4,023 2,766
General and administrative 2,439 1,495
Interest 554 177
Stock-based compensation (Note 11) 656 836
Depletion, depreciation and accretion 8,752 9,578
----------------------------------------------------------------------------
16,424 14,852
----------------------------------------------------------------------------
Income (loss) before taxes 2,229 (679)
Future income tax recovery (Note 10) 1,096 1,306
----------------------------------------------------------------------------
Net income and comprehensive income for the year 3,325 627
Retained earnings, beginning of year 1,635 1,008
----------------------------------------------------------------------------
Retained earnings, end of year 4,960 1,635
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Income per share (Note 7(c))
Basic 0.10 0.02
Diluted 0.10 0.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the financial statements.


STATEMENTS OF CASH FLOWS

----------------------------------------------------------------------------
Years Ended December 31,
2007 2006
----------------------------------------------------------------------------
(000s) ($) ($)
Cash flows from operating activities

Net income 3,325 627
Adjustments for:
Depletion, depreciation and accretion 8,752 9,578
Stock-based compensation 656 836
Future income tax recovery (1,096) (1,306)
Asset retirement obligations settled (Note 6) (111) (29)
----------------------------------------------------------------------------
11,526 9,706
Changes in non-cash operating working capital
balances (Note 15) 293 (320)
----------------------------------------------------------------------------
11,819 9,386
----------------------------------------------------------------------------
Cash flows from financing activities

Issue of shares, net 677 4,173
Increase in long-term debt 1,200 -
Repayment of long-term debt (345) -
Increase in revolving bank loan 4,885 6,328
Changes in non-cash operating working capital
balances (Note 15) - -
----------------------------------------------------------------------------
6,417 10,501
----------------------------------------------------------------------------
Cash flows from investing activities

Proceeds on disposal of property and equipment 8,255 123
Additions to property and equipment (22,980) (26,079)
Change in non-cash investing working capital
(Note 15) (3,511) 626
----------------------------------------------------------------------------
(18,236) (25,330)
----------------------------------------------------------------------------
Decrease in cash and cash equivalents - (5,443)
Cash and cash equivalents, beginning of year - 5,443
----------------------------------------------------------------------------
Cash and cash equivalents, end of year - -
----------------------------------------------------------------------------

See accompanying notes to the financial statements.


NOTES TO FINANCIAL STATEMENTS

December 31, 2007 and 2006


1. Nature of Operations

Grand Banks Energy Corporation's ("Grand Banks" or "the Company") principal business is the exploration, development and production of crude oil and natural gas properties. The Company was originally incorporated on June 25, 1969 under the British Columbia Companies Act and changed its name from Pacific Amber Resources Ltd. to Grand Banks Energy Corporation in 2003. The Company has been continued under the Alberta Business Corporations Act. The Company's common voting shares are listed on the TSX Venture Exchange.

2. Summary of Significant Accounting Policies

The financial statements of the Company have been prepared by management in accordance with Canadian generally accepted accounting principles. The preparation of financial statements in accordance with Canadian generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. The financial statements have, in management's opinion, been properly prepared using careful judgment within reasonable limits of materiality and within the framework of the significant accounting policies summarized below.

(a) Property and Equipment

The Company accounts for crude oil and natural gas properties using the full cost method of accounting. Under this method, all costs associated with the acquisition of, exploration for and the development of natural gas and crude oil reserves, including asset retirement costs, are capitalized.

Costs accumulated within each cost centre are depleted and amortized using the unit-of-production method based on estimated gross (before deduction of royalties) proved reserves. For purposes of this calculation, gas is converted to oil on an energy equivalent basis (six thousand cubic feet of natural gas to one barrel of oil). Capitalized costs subject to depletion are net of equipment salvage values and include estimated future costs to be incurred in developing proved reserves. Proceeds from the disposal of properties are normally deducted from the full cost pool without recognition of gain or loss unless that deduction would result in a change to the rate of depreciation, depletion and amortization of 20% or greater, in which case a gain or loss is recorded.

Costs of acquiring and evaluating unproved properties are initially excluded from depletion. These unevaluated properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion.

The Company applies an impairment test ("ceiling test") to determine if capitalized costs are not recoverable and exceed their fair value. The carrying amount of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from proved reserves. If the sum of cash flows is less than the carrying amount, the impairment loss is limited to the amount by which the carrying amount exceeds the sum of the fair value of proved and probable reserves and the costs of unproved properties that have been subject to a separate impairment test and contain no probable reserves.

Expenditures that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are charged against income.

Office equipment is recorded at cost. Amortization is provided on a declining balance basis at rates ranging from 20% to 30% over the estimated useful life of the equipment.

(b) Joint Venture Operations

Substantially all of the Company's petroleum and natural gas exploration activities are conducted jointly with others. These financial statements reflect only the Company's proportionate interest in such activities.

(c) Asset Retirement Obligations

The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred and records a corresponding increase in the carrying value of the related long-lived asset. The fair value is determined through a review of engineering studies, industry guidelines and management's estimates on a site-by-site basis. The liability is subsequently adjusted for the passage of time and is recognized as an accretion expense in the statement of operations. The liability is also adjusted due to revisions in either the timing or the amount of the original estimated cash flows associated with the liability. The increase in the carrying value of the asset is amortized using the unit-of-production method based on estimated gross proved reserves as determined by independent engineers. Actual expenditures incurred are charged against the accumulated obligation. Any difference between the actual costs incurred upon settlement of the asset retirement obligation and the recorded liability is recognized as a gain or loss in the period in which settlement occurs.

(d) Flow-Through Shares

Expenditure deductions for income tax purposes related to exploratory and development activities funded by flow-through share arrangements are to be renounced to investors in accordance with income tax legislation. Share capital is reduced by the estimated cost of the renounced tax deductions for expenditures when renounced.

(e) Future Income Taxes

The Company uses the liability method of tax allocation in accounting for income taxes. Under this method, future tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities and measured using substantively enacted tax rates and laws that will be in effect when the differences are expected to reverse.

(f) Measurement Uncertainty

The amounts recorded for depletion and amortization of petroleum and natural gas properties and equipment, the provision for asset retirement obligation and stock-based compensation are based on estimates. A number of the Company's financial statement calculations are based on estimates of proved and probable reserves, production rates, oil and 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 estimates in future periods could be significant.

The Black-Scholes option valuation method was developed for use in estimating the fair value of traded options that were fully tradable with no vesting restrictions. This option valuation model requires the input of highly subjective assumptions including the expected stock price volatility. Because the Company's stock options and performance incentive warrants have characteristics significantly different from those of traded options and because changes in the subjective input assumptions can materially affect the calculated fair value, such value is subject to measurement uncertainty. Once recorded, no adjustments are made to the fair value recorded for these options.

The financial statements include accruals based on the terms of existing joint venture agreements. Due to varying interpretations of the definition of terms in these agreements, the accruals made by management in this regard may be significantly different from those determined by the Company's joint venture partners. The effect on the financial statements resulting from such adjustments, if any, will be reflected prospectively.

The Company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to contractual agreements and management decisions, result in the accrual of estimated asset retirement obligation costs. Any changes in these estimates will affect future earnings.

Costs attributable to commitments and contingencies are expected to be incurred over an extended period of time and are to be funded primarily from the Company's cash provided by operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, it could be material for any one quarter or year.

(g) Cash and Cash Equivalents

Cash and cash equivalents consists of cash on hand, bank balances (including temporary bank overdrafts), term deposits and short-term investments with maturities of three months or less when purchased.

(h) Stock-Based Benefit Plan

The Company records compensation expense in the financial statements for stock options granted to employees, directors and consultants using the fair value method. Fair values are determined using the Black-Scholes option pricing model. Compensation costs are recognized over the vesting period.

(i) Per Share Amounts

Basic earnings per common share are computed by dividing earnings by the weighted average number of common shares outstanding for the period. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments.

(j) Revenue Recognition

Revenues associated with the sale of crude oil and natural gas are recorded when the title passes to the customer. Revenues from crude oil and natural gas production from properties in which the Company has an interest with other producers are recognized on the basis of the Company's net working interest. Alberta Royalty Tax Credits are netted against oil and gas royalties.

3. Changes in Accounting Policies

On January 1, 2007, the Company adopted the new Canadian accounting standards for financial instruments - recognition and measurement, financial instruments - disclosure and presentation, hedging and comprehensive income. Prior periods have not been restated. Additional disclosure requirements for financial instruments and accounting changes have been approved by the Canadian Institute of Chartered Accountants ("CICA") and will be required disclosure beginning January 1, 2008. These new standards have no material impact on the Company's financial statements.

(a) Financial Instruments - Recognition and Measurement

This new standard requires all financial instruments within its scope, including all derivatives, to be recognized on the balance sheet initially at fair value. Subsequent measurement of all financial assets and liabilities except those held-for-trading and available for sale are measured at amortized cost determined using the effective interest rate method. Held-for-trading financial assets are measured at fair value with changes in fair value recognized in earnings. Available-for-sale financial assets are measured at fair value with changes in fair value recognized in other comprehensive income and reclassified to earnings when derecognized or impaired. There were no changes to the measurement of existing financial assets and liabilities at the date of adoption.

Cash and cash equivalents are designated as "held-for-trading" and are measured at carrying value, which approximates fair value due to the short-term nature of these instruments. Accounts receivable are designated as "loans and receivables" and accounts payable and accrued liabilities and bank loans are designated as "other liabilities", all of which are measured at carrying value, which approximates fair value due to the short-term nature of these instruments.

Risk management assets and liabilities are derivative financial instruments classified as "held-for-trading" unless designated for hedge accounting. The Company has no commodity contracts or fixed-price physical contracts in place at this time.

(b) Derivatives

The Company may use various types of derivative financial instruments to manage risks associated with crude oil and natural gas fluctuations. These instruments are not used for trading or speculative purposes. Proceeds and costs realized from holding the related contracts are recognized in petroleum and natural gas revenues at the time that each transaction under a contract is settled. For the unrealized portion of such contracts, the Company utilized the fair value method of accounting. The fair value is based on an estimate of the amounts that would have been paid to or received from counterparts to settle these instruments given quoted future market prices and other relevant factors. The method requires the fair value of the derivative financial instruments to be recorded at each balance sheet date with unrealized gains or losses on these contracts recorded through net earnings. The Company had no derivatives in 2007.

(c) Embedded Derivatives

On adoption, the Company elected to recognize, as separate assets and liabilities, only for those embedded derivatives in hybrid instruments issued, acquired or substantively modified after January 1, 2003. The Company did not identify any material embedded derivatives which require separate recognition and measurement.

(d) Other Comprehensive Income

The new standards establish a new statement of comprehensive income, which is comprised of net earnings and other comprehensive income. The Company currently has no other comprehensive income items.

Beginning January 1, 2007 the Company adopted Section 1506 "Accounting Changes" the only impact of which is to provide disclosure of when an entity has not applied a new source of GAAP that has been issued but is not yet effective. This is the case with Section 3862 "Financial Instruments - Disclosures" and Section 3863 "Financial Instruments - Presentation" which are required to be adopted for fiscal years beginning on or after October 1, 2007. The Company will adopt these standards on January 1, 2008 and it is expected the only effect on the Company will be incremental disclosures regarding the significance of financial instruments for the entity's financial position and performance and the nature, extent and management of risks arising from financial instruments to which the entity is exposed.

As of January 1, 2008, the Company will be required to adopt CICA Handbook Section 1535 "Capital Disclosures", which requires entities to disclose their objectives, policies and processes for managing capital, and in addition, whether the entity has complied with any externally imposed capital requirements. The Company is assessing the impact of this new standard on its financial statements and anticipates that the main impact will be in terms of additional disclosures required.

As of January 1, 2008, the Company will be required to adopt CICA Handbook Section 3031, "Inventories". This new standard will have no impact on the Company's financial statements.

In February 2008, the CICA issued Section 3064, "Goodwill and Intangible Assets", replacing Section 3062, "Goodwill and Other Intangible Assets" and Section 3450, "Research and Development Costs". Various changes have been made to other sections of the CICA Handbook for consistency purposes. The new Sections will be applicable to financial statements relating to fiscal years beginning on or after October 1, 2008. Accordingly, the Company will adopt the new standards for its fiscal year beginning January 1, 2009. It establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The Company is currently evaluating the impact of the adoption of this new Section on its financial statements.

In January 2006, the CICA Accounting Standards Board ("AcSB") adopted a strategic plan for the direction of accounting standards in Canada. As part of that plan, accounting standards in Canada for public companies are expected to converge with International Financial Reporting Standards ("IFRS") by the start of 2011. The Company continues to monitor and assess the impact of convergence of Canadian GAAP and IFRS.



4. Property and Equipment
----------------------------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Amortization Value
----------------------------------------------------------------------------
(000s) ($) ($) ($)
December 31, 2007
Petroleum and natural gas properties 81,776 31,004 50,772
Furniture and equipment 172 82 90
----------------------------------------------------------------------------
81,948 31,086 50,862
----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, 2006
Petroleum and natural gas properties 67,027 22,346 44,681
Furniture and equipment 120 60 60
----------------------------------------------------------------------------
67,147 22,406 44,741
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Future development costs relating to proved reserves of $15,752,000 (December 31, 2006 - $10,568,000) have been included in the depletion calculation. The Company did not capitalize any general and administrative costs during the years ended December 31, 2007 or 2006. The Company excluded $2,745,000 (December 31, 2006 - $1,785,000) of undeveloped properties from the depletion calculation as follows:



----------------------------------------------------------------------------

----------------------------------------------------------------------------
December 31, 2007 2006
----------------------------------------------------------------------------
(000s) ($) ($)
Unproven costs
Land 1,599 1,056
Geological and geophysical 1,146 278
Drilling and completion - 451
----------------------------------------------------------------------------
2,745 1,785
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company performed a ceiling test calculation at December 31, 2007 and 2006 to assess the recoverable value of its oil and gas properties. The undiscounted value of future net revenues from the Company's proved reserves exceeded the carrying value of the oil and gas properties at December 31, 2007 and 2006. The oil and gas future prices are based on the commodity price forecast of the Company's independent reserve evaluators. These prices have been adjusted for heating content, quality and transportation parameters specific to the Company. The following table summarizes the benchmark prices used in the ceiling test calculation at December 31, 2007:



----------------------------------------------------------------------------
Natural Gas
CDN/US Alberta
Year WTI Oil Exchange Rate Spot Prices
----------------------------------------------------------------------------
($US/bbl) ($) ($CDN/mmbtu)
2008 90.00 1.00 6.62
2009 88.00 1.00 7.10
2010 84.00 1.00 7.24
2011 82.00 1.00 7.38
2012 80.00 1.00 7.53
2013 81.60 1.00 7.68
----------------------------------------------------------------------------
Escalate thereafter 2.0% per year.


5. Bank Indebtedness

(a) Revolving Bank Loan

At December 31, 2007, the Company had a $19,000,000 (December 31, 2006 - $10,500,000) revolving line of credit agreement with a Canadian financial institution. The line of credit bears interest at prime plus 0.25% per annum, is secured by the assets of the Company, and is due on demand. At December 31, 2007 the effective rate under the revolving line of credit was 6.25% (December 31, 2006 - 6.25%). At December 31, 2007, the Company was in compliance with all covenants related to this credit facility.

(b) Long-Term Bank Loan

At December 31, 2007 the Company had drawn $855,000 (December 31, 2006 - $Nil) on its long-term credit facility with the same Canadian financial institution. This credit facility bears interest at 7.5%. This credit facility is fully drawn and the outstanding balance is repayable through blended monthly payments of interest and principal of $37,000. The balance is repayable over the next 25 months, the final installment being due January 31, 2010. This credit facility is secured by the assets of the Company, including a specific charge on the Tower Creek property.

6. Asset Retirement Obligation

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of oil and gas properties:



----------------------------------------------------------------------------
December 31, 2007 2006
----------------------------------------------------------------------------
(000s) ($) ($)
Balance, beginning of year 1,223 894
Liabilities incurred in year 151 273
Asset retirement obligations settled (111) (29)
Liabilities disposed of in year (75) -
Accretion expense 72 85
----------------------------------------------------------------------------
1,260 1,223
Less current portion 73 262
----------------------------------------------------------------------------
Balance, end of year 1,187 961
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The undiscounted amount of cash flows, required over the estimated reserve life of the underlying assets, to settle the obligation, adjusted for inflation is estimated at $3,790,000 (2006 - $3,063,000). The obligation was calculated using a credit-adjusted risk free discount rate of 8% and an inflation rate of 2%. It is expected that this obligation will be funded from the Company's general resources at the time the costs are incurred with the majority of costs expected to occur between 2009 and 2036. No funds have been set aside to settle this obligation.

7. Share Capital

(a) Authorized

The authorized share capital consists of an unlimited number of common shares without nominal or par value.

(b) Issued and Outstanding



(b) Issued and Outstanding
----------------------------------------------------------------------------
Shares Amount
----------------------------------------------------------------------------
(000s) (#) ($)
----------------------------------------------------------------------------
Balance, December 31, 2005 29,750 29,228
Issued on exercise of options (Note 7(e)) 165 170
Transfer from contributed surplus - 178
Flow-through shares issued 2,000 4,200
Tax effect of flow-through shares - (3,090)
Share issue costs - (197)
----------------------------------------------------------------------------
Balance, December 31, 2006 31,915 30,489
Issued on exercise of options (Note 7(e)) 641 677
Transfer from contributed surplus - 505
Tax effect of flow-through shares (1) - (1,306)
----------------------------------------------------------------------------
Balance at December 31, 2007 32,556 30,365
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Calculated at an effective rate of 31.10% on renounced expenditures.


(c) Per Share Amounts

The following table summarizes the calculation of basic net loss and diluted
net loss per share for the years ended December 31, 2007 and 2006:

----------------------------------------------------------------------------
December 31, 2007 2006
----------------------------------------------------------------------------
(000s, except per share amounts) ($) ($)
Net Income available to common shareholders 3,325 627
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted average number of common shares
Outstanding - basic 32,378 30,173
Dilutive effect of stock options 425 806
----------------------------------------------------------------------------
Weighted average number of common shares
Outstanding - diluted 32,803 30,979
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Income per share
Basic 0.10 0.02
Diluted 0.10 0.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(d) Flow-Through Share Information

----------------------------------------------------------------------------
Years Ended December 31, 2007 2006
----------------------------------------------------------------------------
(000s) ($) ($)
Remaining obligation, beginning of period 3,855 6,740
Amount of flow-through shares issued - 4,200
Expenditures incurred (3,855) (7,085)
----------------------------------------------------------------------------
Remaining obligation, end of period - 3,855
----------------------------------------------------------------------------
----------------------------------------------------------------------------

During October and November 2006, the Corporation issued 2,000,000 flow-
through shares at $2.10 per share for gross proceeds of $4,200,000.


(e) Stock Options

The Option Plan allows directors, employees and consultants to be granted incentive based compensation under the Option Plan while allowing a rolling maximum of 10% of the number of issued and outstanding shares from time-to-time to be granted under the Option Plan. Options may be granted under the Option Plan at an exercise price and vesting provisions as set by the Board of Directors of the Company from time-to-time, subject to the limitations of any stock exchange on which the common shares are listed.

As at December 31, 2007, the Company had the following stock options outstanding:



----------------------------------------------------------------------------
Option Weighted
Price Average
Share Per Share Exercise
Options Range Price
----------------------------------------------------------------------------
(#000s) ($) ($)
----------------------------------------------------------------------------
Outstanding at December 31, 2005 2,310 1.00 - 1.25 1.10
Granted 709 1.65 - 1.80 1.65
Exercised (165) 1.00 - 1.05 1.04
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Outstanding, December 31, 2006 2,854 1.00 - 1.80 1.24
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Granted 1,364 1.30 - 1.40 1.39
Exercised (641) 1.00 - 1.25 1.06
Expired (1,060) 1.05 - 1.80 1.41
----------------------------------------------------------------------------
Outstanding, December 31, 2007 2,517 1.00 - 1.68 1.30
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The following table summarizes information about the stock options
outstanding at December 31, 2007 and 2006:

----------------------------------------------------------------------------
Options Outstanding Options Currently Exercisable
----------------------------------------------------------------------------
Weighted Weighted
Average Weighted Average Weighted
Remaining Average Remaining Average
Share Contractual Exercise Share Contractual Exercise
Option Price Options Life Price Options Life Price
----------------------------------------------------------------------------
($) (#000s) (Years) ($) (#000s) (Years) ($)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2007
1.00 10 3.4 1.00 10 3.4 1.00
1.05 790 2.5 1.05 790 2.5 1.05
1.25 307 3.6 1.25 307 3.6 1.25
1.30 140 5.6 1.30 47 4.6 1.30
1.40 914 5.3 1.40 305 4.3 1.40
1.65 352 4.0 1.65 257 3.6 1.65
1.68 4 4.7 1.68 3 4.2 1.68
----------------------------------------------------------------------------
2,517 4.0 1.30 1,719 3.2 1.24
----------------------------------------------------------------------------
----------------------------------------------------------------------------
2006
1.00 130 2.4 1.00 130 2.4 1.00
1.05 1,285 3.5 1.05 1,285 3.5 1.05
1.15 150 3.8 1.15 100 3.3 1.15
1.25 580 4.6 1.25 387 4.1 1.25
1.65 695 5.1 1.65 232 4.1 1.65
1.80 10 5.4 1.80 3 4.4 1.80
1.68 4 5.7 1.68 1 4.7 1.68
----------------------------------------------------------------------------
2,854 4.1 1.24 2,138 3.6 1.15
----------------------------------------------------------------------------
----------------------------------------------------------------------------


8. Contributed Surplus

----------------------------------------------------------------------------
December 31, 2007 2006
----------------------------------------------------------------------------
(000s) ($) ($)
Balance, beginning of year 2,448 1,790
Stock compensation costs 656 836
Transfer to share capital upon exercise of options (505) (178)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance, end of year 2,599 2,448
----------------------------------------------------------------------------
----------------------------------------------------------------------------


9. Share Purchase Loans

At December 31, 2007, the Company had $48,000 (2006 - $48,000) in share purchase loans recorded as a reduction of shareholders' equity.

10. Income Taxes

(a) The effective tax rate of income tax varies from the statutory rate as follows:



----------------------------------------------------------------------------
2007 2006
----------------------------------------------------------------------------
(000s) ($) ($)
Combined federal and provincial tax rates 33.24% 36.15%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Expected income tax recovery at statutory rate 741 (245)
Alberta Royalty Tax Credit 2 (80)
Crown charges - 242
Tax rate changes 156 (276)
Resource allowance - (373)
Stock-based compensation 218 302
Other (340) 354
Change valuation allowance (1,873) (1,230)
----------------------------------------------------------------------------
Actual income tax recovery (1,096) (1,306)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(b) At December 31, 2007, subject to confirmation by income tax authorities,
the Company had the following tax pools available to reduce future taxable
income:

----------------------------------------------------------------------------
December 31, 2007 2006
----------------------------------------------------------------------------
(000s) ($) ($)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cumulative Canadian development expenses 15,566 14,224
Cumulative Canadian exploration expenses 13,442 11,543
Cumulative Canadian oil and gas property expense - 2,781
Foreign exploration and development expenses 7,248 8,053
Undepreciated capital cost 9,324 8,318
Non-capital losses carried forward for tax
purposes expiring between 2008 and 2014 6,855 7,980
Undeducted share issue costs carried forward 388 746
----------------------------------------------------------------------------
52,823 53,645
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(c) The tax benefit of these tax pools in excess of carrying values in 2007 has been recognized as a future tax asset as the realization of the benefit meets the test of more likely than not. In 2006, the tax benefit recognized only related to the future tax to be renounced for the flow-through shares issued during the year.

At December 31, 2007, the Company had approximately $1,497,000 (2006 - $1,497,000) of capital losses available that have no expiry date and can be used to reduce future capital gains. The tax benefit of these losses has not been recognized as a future asset as the ultimate realization of the asset value is uncertain.

(d) Future income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts for income tax purposes. The components of the Company's future income tax assets and liabilities are as follows:



----------------------------------------------------------------------------
December 31, 2007 2006
----------------------------------------------------------------------------
(000s) ($) ($)
----------------------------------------------------------------------------
Nature of temporary differences
Property and equipment (1,080) 562
Unused non-capital tax losses carried forward 2,060 2,494
Share issue costs 116 231
Unused capital losses carried forward 225 117
----------------------------------------------------------------------------
1,321 3,404
Valuation allowance (225) (2,098)
----------------------------------------------------------------------------
Future income tax asset 1,096 1,306
----------------------------------------------------------------------------
----------------------------------------------------------------------------


11. Stock Compensation

The Company records stock-based compensation expense for all common share options granted to employees, consultants, officers and directors. The total fair value of share options granted during the year was estimated at $656,000 (2006 - $795,000) using the Black-Scholes option pricing model with the following assumptions:



----------------------------------------------------------------------------
December 31, 2007 2006
----------------------------------------------------------------------------
Dividend yield Nil Nil
Expected volatility (%) 45 - 52 41 - 74
Risk free rate of return (%) 4.5 4.5
Weighted average life (years) 6 5
----------------------------------------------------------------------------
----------------------------------------------------------------------------


12. Financial Instruments

The Company carries a number of financial instruments as detailed on the balance sheet. It is management's opinion that the Company is not exposed to significant commodity, interest, currency or credit risks arising from these financial instruments. The fair values of these financial instruments approximate their carrying values, unless otherwise noted.

The Company holds various forms of financial instruments. The nature of these instruments and the Company's operations expose the Company to fair value, interest rate and industry credit risks. The Company manages its exposure to these risks by operating in a manner that minimizes its exposure to the extent practical.

The Company will be subject to commodity and currency price risk for the delivery of natural gas and crude oil.

The floating rate debt appropriately reflects rates currently available for debt with similar terms and maturities. Accordingly, the fair value of the revolving bank loan is not materially different from the recorded value (Note 5 (a)). The fixed rate long-term bank loan, which has a carrying value of $855,000 at December 31, 2007, has a fair value of $875,000 (Note 5 (b)).

A significant portion of the Company's bank loan is currently held with the same financial institution and, as such, the Company is exposed to concentration of credit risk. Substantially all 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.

13. Related Party Transactions

All related party transactions are in the normal course of operations and have been measured at the agreed to exchange amounts, which is the amount of consideration established and agreed to by the related parties and which is similar to those negotiated with third parties. The Company had the following related party transactions:

(a) The Company conducts oil and gas exploration and development activities and related transactions with organizations managed or controlled by directors. These transactions are negotiated and conducted using standard industry agreements and terms. The amounts associated with these transactions are insignificant to the operations of the Company.

(b) Included in general and administrative expenses are consulting fees of $380,000 (2006 - $328,000) incurred with companies controlled by officers of the Company for the year ended December 31, 2007.

(c) Included in general and administrative expenses are legal fees of $20,000 (2006 - $55,000) incurred with a firm in which one of the Company's officers was a partner for the year ended December 31, 2007.

(d) Included in general and administrative expenses is $78,000 (2006 - $53,000) paid for directors' fees to independent directors for the year ended December 31, 2007.

14. Commitments

(a) The Company has a commitment for an office lease that expires in November 2011 as follows:



----------------------------------------------------------------------------
($)
2008 320,000
2009 320,000
2010 321,000
2011 294,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(b) The Company has entered into employment agreements with its executive officers. In addition to defining the terms of employment, the agreements entitle these executives to compensation on a change of management or control, or for termination without cause. The Company has agreed to indemnify certain individuals, who have acted at the Company's request to be officers or directors of the Company. Payment, if any, as a result of these indemnifications will be recorded in the period that the related payment is determinable.

(c) The Company has an obligation related to the construction of the Tower Creek Pipeline, that was built and paid for by a third party, to allow the Tower Creek 02-21 well to be connected to the third party's existing sour gas gathering and processing facilities. The agreement to build the pipeline had a provision referred to as the "Backstop Commitment" that required the partners in the well to make a payment at the end of the first three years of operation of the pipeline in the event that a set volume of raw gas was not delivered into the pipeline over this period. Initially, the Company's share of the "Backstop Commitment" was $1,109,000 with the requirement to deliver approximately 3.7 billion cubic feet of raw gas. As at December 31, 2007, the Company's share of the commitment had been reduced to $910,000. Based on the Company's December 31, 2007 reserve evaluation this commitment will be reduced by a further $490,000 in 2008, $410,000 in 2009 and the final $10,000 early in 2010, well in advance of the end of the three year period.

15. Statement of Cash Flows

(a) Changes in non-cash working capital balances are comprised of the following:



----------------------------------------------------------------------------
December 31, 2007 2006
----------------------------------------------------------------------------
(000s) ($) ($)
Accounts receivable 1,819 (346)
Prepaid expenses and advances (131) (60)
Accounts payable and accrued liabilities (4,906) 712
----------------------------------------------------------------------------
(3,218) 306
----------------------------------------------------------------------------
Less amounts related to investing activities (3,511) 626
Less amounts related to financing activities - -
----------------------------------------------------------------------------
Amounts related to operating activities 293 (320)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(b) In the year ended December 31, 2007, the cash interest paid was $553,000 (2006 - $139,000).

16. Subsequent Event

Subsequent to December 31, 2007, the Company formed a special committee to investigate strategic alternatives to maximize shareholder value.

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

Contact Information

  • Grand Banks Energy Corporation
    E.C. (Ted) McFeely
    Chairman, President & CEO
    (403) 262-8666
    (403) 262-8796 (FAX)
    or
    Grand Banks Energy Corporation
    John Kalman
    Vice President, Finance & CFO
    (403) 262-8666
    (403) 262-8796 (FAX)
    or
    Grand Banks Energy Corporation
    1600, 444 - 5th Avenue S.W.
    Calgary, Alberta T2P 2T8