Guide Exploration Ltd. Announces 2011 Fourth Quarter Results, 2011 Financial Results and Reserves Information and 2012 Capital and Operations Update

Marketwired

CALGARY, ALBERTA--(Marketwire - March 16, 2012) - Guide Exploration Ltd. (TSX:GO.TO - News) ("Guide" or the "Corporation") announces the financial results for the year ended 2011 and an update on its 2012 capital program.

The audited consolidated financial statements of the Corporation for the years ended December 31, 2011 and 2010 and the related management's discussion and analysis can be accessed on-line on SEDAR at www.sedar.com or on the Corporation's website at www.guidex.ca.

Highlights





--  Revenues (before realized financial derivatives) for the fourth quarter

    of 2011 were $48.0 million with funds flow from operations of $24.8

    million generated from daily average production of 4,458 barrels per day

    of crude oil and natural gas liquids and 43.3 Mmcf/d of natural gas.

    Currently, Guide is producing approximately 5,350 Bbl/d of oil and

    natural gas liquids and 63 Mmcf/d of natural gas. 

--  For the full year 2011, revenue totaled $188.2 million with funds flow

    of $98.6 million ($1.16 per share diluted) on average daily production

    of 4,070 barrels per day of crude oil and NGLs and 47.8 Mmcf/d of

    natural gas (34% Oil/NGLs weighting). 

--  Operating netbacks for the fourth quarter of 2011 averaged $24.15/BOE

    before realized gain on financial derivatives and $28.77/BOE after

    realized gain on financial derivatives. 

--  Operating expenses averaged $11.53/BOE in the fourth quarter of 2011 in

    line with annual operating expenses that averaged $11.59/BOE. 

--  Funds flow from operations in the fourth quarter of 2011 averaged

    $18.50/BOE before realized gain on financial derivatives and $23.12/BOE

    after realized gain on financial derivatives. Per unit funds flow were

    slightly ahead of funds flow from operations for full year 2011 of

    $17.20/BOE before the realized gain from financial derivatives and

    $22.43/BOE including the realized gain from financial derivatives. 

--  The Corporation drilled 54 (49.5 net) wells resulting in 43 (38.9 net)

    oil wells and 11 (10.6 net) natural gas wells, for a success rate of

    100% during the year. 

--  Capital of $150.5 million was invested in exploration and development

    activities. In addition, $7.2 million was spent to acquire properties

    and $15.4 million was received on the sale of properties for a net

    disposition of $8.2 million. 

--  At December 31, 2011 $138.2 million was drawn on available bank credit

    facilities of $250 million and the Corporation had a working capital

    deficiency of $31.6 million. 

--  At December 31, 2011, Guide had outstanding, 92,407,135 Class A Shares,

    8,728,333 share options with an average exercise price of $3.75 and

    2,300,000 warrants. 

--  At year end 2011, Guide had 100 percent of its properties evaluated by

    Sproule Associates Limited ("Sproule"). Sproule has determined that year

    end 2011 proved and probable reserves totaled 38.1 million BOE including

    total proved reserves of 23.4 million BOE. Guide's proved reserves are

    weighted 38.7% to oil and natural gas liquids. Future development

    capital associated with Guide's reserves is $142.4 million

    (undiscounted) for the total proved case and $211.4 million

    (undiscounted) for the total proved plus probable case. 

--  Based on the net present value of future net revenue attributable to

    proved and probable reserves (at a 10% discount rate) as at December 31,

    2011 as evaluated by Sproule and using year end debt and estimated

    undeveloped land value at an average of $95 per acre, the net asset

    value of Guide Exploration at year end 2011 was $520 million or $5.62

    per share. 

--  A loss of $212.8 million ($2.50) per basic share was recorded, which

    included a non-cash impairment of property and equipment of $255.0

    million. This impairment relates to the reduction in the fair value of

    certain cash generating units in Alberta and Saskatchewan, due to

    changes in development plans and forecast lower natural gas prices

    compared with the forecast at December 31, 2010. The impairments are

    described in more detail in Guide's audited consolidated financial

    statements and management discussion and analysis for the year ended

    December 31, 2011. 



Subsequent to December 31, 2011

On January 24, 2012, the Corporation issued 12,000,000 Class A shares at a price of $3.05 per share on a bought deal basis. The gross proceeds of the financing were $36,600,000.

On January 31, 2012, Guide completed the previously announced acquisition of sweet natural gas assets in Northern Alberta for approximately $61.5 million. The properties are currently producing approximately 20 Mmcf/d.

2011 Year in Review

The year ended December 31, 2011 proved to be challenging to the staff and management of Guide as we re-evaluated development plans and engaged a new independent Reserve Evaluator, Sproule, to evaluate our reserves in light of changed development plans.

In setting a course for 2012 and the future, we will narrow our near term development focus to oil, continue to expand our land base for future exploration and development, and maintain a strong focus on cost control and efficiencies.

Guide has focused its near term development efforts on the oil rich Triassic sediment package over its large land position in the Peace River Arch with particular emphasis on its emerging Montney oil resource play at Normandville/Girouxville.

Drilling in the second half of 2011 delineated a broad, oil rich, fairway in the Montney that we believe covers at least 40 sections. In the latter half of 2011, we broadened our window of opportunity for future oil exploration and development by adding land and plays in both conventional reservoirs and in emerging tight rock plays. The $20 million flow-through share offering which was completed in November 2011 is planned to be used in part to target shale resource plays in the Duvernay and Nordegg.

2012 Capital and Operations Update

Guide achieved 2011 exit production volumes of approximately 4,835 barrels per day of crude oil and natural gas liquids and 43 Mmcf/d of natural gas. Including the Northern Alberta property acquisition, average field estimated sales production for February 2012 was 5,350 barrels per day of crude oil and natural gas liquids and 63 Mmcf/d of natural gas.

For 2012, capital and operating guidance remains relatively unchanged. Our oil focused development program of $120 to $130 million will key on the Peace Area oil properties at Normandville and Girouxville. We plan to drill approximately 30 oil wells on these properties in 2012, accounting for two-thirds of our development budget.

Guide's 2012 exploration budget of $20 million is fully funded by our November 2011 flow through share offering. This program targets a wide variety of prospects including resource plays in the Nordegg and Duvernay.

For 2012, we are guiding to production of between 15,500 to 16,300 BOE/d as follows:

Oil: 5,300 - 5,500 Bbl/d

NGLs: 400 - 450 Bbl/d

Gas: 59 - 62 Mmcf/d

Strong growth in oil production (40% year over year) is expected to push overall corporate growth to 8 - 10 percent.

Based on price forecasts of WTI US $95.00/Bbl, $2.50/GJ AECO, and an exchange rate of $0.97 US per dollar Canadian, we expect funds flow from operations of between $120 million and $130 million in 2012 ($1.15 to $1.25 per basic share).

Operational Update

During Q4 2011 and Q1 2012, we drilled 18 horizontal Montney oil wells on our Normandville and Girouxville properties. These 1,000 meter total vertical depth wells are currently being drilled horizontally to a typical measured depth of 2,500 meters to take advantage of a better horizontal oil new well royalty rate. Completion operations have evolved from fracture stimulations of 10 stages to 20 stages of 3 to 5 tonnes per stage, with plans to increase to 24 stages on future new drills. We have also recently commissioned our Q1 2012 Normandville oil battery expansion, effectively doubling the fluid and gas handling capacity.

The fairway for our Normandville/Girouxville Upper Montney oil resource play covers a prospective 40 to 50 net sections of land targeted to be developed with 4 to 8 horizontal wells per section. In 2011, Guide drilled 27 horizontal Montney oil wells on the play. Potential exists to improve the oil recovery factor with a pressure maintenance water and/or gas injection scheme. Timing to implement such a pressure maintenance scheme would be into 2013.

Our 2011 Normandville/Girouxville Montney horizontal 10 stage oil type curve exhibits a 30 day average rate of 95Bbl/d oil and 245 Mcf/d associated gas, 3 month average rate of 85Bbl/d oil and 223 Mcf/d associated gas, and a 12 month average rate of 65 Bbl/d oil and 165 Mcf/d associated gas, with predicted cumulative production of 85 Mbbls oil and 200 Mmcf gas. With an on-stream capital cost of $1.7 million, the half cycle economic indicators are robust. This type curve is based on 18 wells we have drilled and completed in this manner in the area.

Our 2012 Normandville/Girouxville Montney horizontal 20 stage oil type curve exhibits a 30 day average rate of 120 Bbl/d and 300 Mcf/d associated gas and a 12 month average rate of 75 Bbl/d and 190 Mcf/d of associated gas, with predicted cumulative production of 110 Mbbls oil and 250 Mmcf gas. On-stream capital costs of $2.0 million provide very attractive half cycle economics. This type curve is based on 10 wells we have drilled and completed in this manner in the area.

One of the advantages of our Normandville/Girouxville Montney horizontal oil play is the moderate on-stream repeatable capital costs associated with the new drills.

Our Northwest Alberta Boyer, low decline, sweet gas asset acquisition closed on January 31, 2012. Boyer is meeting our expectations with current production at the 20 Mmcf/d level and we believe we can maintain production levels with minimal annual maintenance capital until such time that the price of natural gas increases and drives production and reserves expansion.

We hold an extensive acreage position in both the Duvernay and Nordegg. We expect to drill a Duvernay test on our lands in Q3 2012. Experience with drilling through the Duvernay in the targeted area has led us to believe the Duvernay will be 30 to 40% over pressured. The Duvernay in this area is also considered to be in the wet gas window.





Annual Information                                                          

                                                                            

                                                                            

($000s except per share amounts)                        2011           2010 

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Financial                                                                   

                                                                            

Petroleum and natural gas revenue                    188,191        207,831 

                                                                            

Funds flow from operations (1)                        98,585        100,478 

  Per share - basic                                     1.16           1.19 

  Per share - diluted                                   1.16           1.19 

                                                                            

Net income (loss)                                   (212,807)        (1,083)

  Per share - basic                                    (2.50)         (0.01)

  Per share - diluted                                  (2.50)         (0.01)

                                                                            

Capital expenditures                                 150,495        136,330 

Total assets                                         671,057        869,652 

Net dispositions of oil and gas properties             8,258        114,158 

Net debt (1,2)                                       169,894        152,861 

Total non-current financial liabilities               21,797         14,980 

Shareholders' equity                                 394,990        580,006 

                                                                            

Weighted average shares outstanding                                         

  Basic                                           85,192,616     84,770,976 

  Diluted                                         85,192,616     84,770,976 

                                                                            

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(1)See "Non-GAAP Measurements"

(2)Net debt includes bank indebtedness and working capital, but excludes financial derivatives and other liability

Results of Operations





Year ended December 31                2011                    2010          

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                                 4,394,732 BOE           5,401,855 BOE      

($000s)                                       $/BOE                   $/BOE 

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Revenues                        188,191       42.82     207,831       38.47 

Realized gain on financial                                                  

 derivatives                     23,010        5.23      10,552        1.95 

Royalties                       (35,600)      (8.10)    (44,060)      (8.15)

GCA(1)                            6,459        1.47      12,670        2.35 

Transportation costs             (8,325)      (1.89)     (8,806)      (1.63)

Operating costs                 (50,934)     (11.59)    (51,405)      (9.52)

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Net                             122,801       27.94     126,782       23.47 

G&A                             (15,475)      (3.52)    (14,773)      (2.73)

Restructuring costs                   -           -      (1,242)      (0.23)

Interest costs                   (7,575)      (1.72)    (10,086)      (1.87)

Exploration expenses               (916)      (0.21)          -           - 

Capital and other taxes            (250)      (0.06)       (203)      (0.04)

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Funds flow from                                                             

 operations(2)                   98,585       22.43     100,478       18.60 

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(1) GCA means Gas Cost Allowance

(2) See "Non-GAAP Measurements"

Petroleum and Natural Gas Revenue (before royalties)





Year ended December 31                2011                    2010          

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($000s)                                            %                       %

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Light oil                         84,620          45      78,943          38

Heavy oil                         26,782          14      23,481          11

NGLs                               9,554           5       9,379           5

Natural gas                       66,971          36      95,615          46

Royalty income                       264           -         413           -

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Total                            188,191         100     207,831         100

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Revenues for the year ended December 31, 2011 were $188.2 million, compared to $207.8 million during the prior year. Crude oil revenues increased $9.0 million, reflecting higher crude oil prices in 2011. Gas revenues decreased by $28.6 million in 2011 due to decreased production volumes and lower gas prices.

Light oil revenues were 45% of total revenues in 2011, compared to 38% in 2010.

Production





                                         Year ended December 31             

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

                                      2011                    2010          

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

                                                   %                       %

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Light oil (Bbls/d)                 2,674          22       2,913          20

Heavy oil (Bbls/d)                 1,021           9       1,065           7

NGLs (Bbls/d)                        375           3         472           3

Natural gas (Mcf/d)               47,818          66      62,098          70

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BOE/d (6:1)                       12,040         100      14,800         100

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Average production was 12,040 BOE/d during 2011, 19% lower than the average production of 14,800 BOE/d in 2010 impacted by the sale of the Puskwa property in the second quarter of 2010.

In 2011 oil and NGLs accounted for 34% of our average daily production compared with 30% in 2010.

Commodity Pricing and Marketing

Petroleum products are sold to major Canadian marketers at spot reference prices or prices subject to commodity contracts based on US WTI for crude oil and AECO for natural gas. As a means of managing the risk of commodity price volatility and improving netback cash flows, Guide has entered into several natural gas and crude oil financial contracts.

The Corporation has the following financial contracts in place as at December 31, 2011:





Natural Gas:                                                                

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January 1, 2012 - December 31, 2012  22,500 GJ/d                CDN $5.00/GJ

April 1, 2012 - October 31, 2012      5,000 GJ/d                CDN $4.86/GJ

                                                                            

Crude Oil:                                                                  

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Costless Collars:                                                           

January 1, 2012 - December 31, 2012    500 Bbl/d   WTI CDN $85.00-$90.00/Bbl

                                                                            

Other:                                                                      

January 1, 2012 - December 31, 2012    527 Bbl/d       WTI US $85.00/Bbl Put

January 1, 2012 - December 31, 2012  1,000 Bbl/d       WTI US $85.00/Bbl Put

January 1, 2013 - December 31, 2013  1,527 Bbl/d      WTI US $85.00/Bbl Call

January 1, 2013 - December 31, 2013    500 Bbl/d  WTI US $85.00/Bbl Swaption

January 1, 2013 - December 31, 2013     73 Bbl/d     WTI US $100.00/Bbl Call

January 1, 2014 - December 31, 2014    980 Bbl/d  WTI US $85.00/Bbl Swaption

January 1, 2014 - December 31, 2014    500 Bbl/d     WTI US $100.00/Bbl Call

Interest Rate Swap:                                                       

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Notional Amount CAD $50 million      Term: August 5, 2011 - August 5, 2013

  Fixed rate 1.34% - Floating rate is reset against CAD-BA-CDOR on each 3 

                            month anniversary                             



During 2011, Guide recorded realized gains of $23.0 million on financial contracts, compared to gains of $10.6 million in 2010. Spot prices for natural gas continued to be substantially lower than the prices Guide has secured using financial contracts. During the year ended December 31, 2011, oil contracts for 2012 were unwound, for which a cash payment of $3.9 million was received.

Based on the mark to market value at December 31, 2011, an unrealized loss on financial contracts of $0.5 million was recorded in 2011, compared to an unrealized gain of $9.0 million in 2010. If the contracts were unwound at December 31, 2011, the Corporation would owe a net amount of $1.1 million.

Subsequent to December 31, 2011, the Corporation entered into the following commodity financial derivative transactions:





Natural Gas:                                                                

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New contracts                                                               

March 1, 2012 - December 31, 2012     5,000 GJ/d                CDN $4.50/GJ

March 1, 2012 - December 31, 2012     5,000 GJ/d                CDN $4.50/GJ

                                                                            

Crude Oil:                                                                  

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Other:                                                                      

Contracts unwound                                                           

January 1, 2012 - December 31, 2012    527 Bbl/d       WTI US $85.00/Bbl Put

January 1, 2012 - December 31, 2012  1,000 Bbl/d       WTI US $85.00/Bbl Put

                                                                            

Fixed Price:                                                                

New contracts                                                               

February 1, 2012 - February 29,                                             

 2012                                1,000 Bbl/d           WTI US $91.25/Bbl

March 1, 2012 - June 30, 2012        1,000 Bbl/d          WTI CDN $91.25/Bbl

March 1, 2012 - June 30, 2012        1,100 Bbl/d           WTI US $94.00/Bbl

July 1, 2012 - December 31, 2012     1,000 Bbl/d      WTI US $91.25/Bbl Call

July 1, 2012 - December 31, 2012     1,100 Bbl/d      WTI US $94.00/Bbl Call

                                                                            

Costless Collar:                                                            

New contract                                                                

January 1, 2013 - December 31, 2013    500 Bbl/d  WTI CDN $98.00-$102.00/Bbl



The new fixed price oil contracts have initial terms to June 30, 2012, at which time the counterparties may elect to extend the term of these contracts to December 31, 2012.

Also subsequent to December 31, 2011, the $50 million interest rate swap at 1.34% was unwound and a new contract was entered into with the following terms:





Interest Rate Swap:                                                         

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Notional Amount CAD $75 million    Term: February 6, 2012 - January 5, 2014 

   Fixed rate 1.19% - Floating rate is reset monthly against CAD-BA-CDOR    



Prices (prior to financial derivatives and transportation charges)





                                                  Year ended December 31    

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                                                         2011           2010

Light oil ($/Bbl)                                       86.85          74.50

Heavy oil ($/Bbl)                                       71.81          60.41

NGLs ($/Bbl)                                            69.80          54.44

Natural gas ($/Mcf)                                      3.84           4.23

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Prices realized in 2011 were higher for crude oil and NGLs, and lower for natural gas. Light oil prices increased 17%, heavy oil prices increased 19%, and NGL prices increased by 28%. The average price received for natural gas decreased by 9%.

The average gas price received by Guide during 2011 was $0.24/Mcf higher than the weighted average AECO price during the year, due to the heat content of the gas. The weighted average premium to AECO received in 2010 averaged $0.21/Mcf.

During the year ended December 31, 2011, the average light oil price received by Guide was approximately $8.00/Bbl lower than the posted Edmonton light oil par price, and the average heavy oil price received by the Corporation was approximately $23.00/Bbl lower than the weighted average posted Edmonton light oil par price. During 2010, the average light and heavy oil prices received by the Corporation were approximately $3.00 and $17.00 lower than the weighted average posted Edmonton light oil par price, respectively. The year over year changes reflect Guide's changing crude slate and the changing crude oil differentials seen in Western Canada.

During 2011 Guide realized a higher net commodity price for natural gas, and a lower net commodity price for crude oil, as a result of financial derivative contracts in place. The net price received for natural gas in 2011 was $1.43/Mcf or 37% higher due to financial derivative contracts. The 2011 net price received for crude oil was $1.43/Bbl or 1.7% lower due to financial derivative contracts.

Crude Oil Prices





Year ended December 31                2011                    2010          

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                                  $000s       $/Bbl       $000s       $/Bbl 

Crude oil                       111,536       82.70     102,664       70.71 

Realized financial contracts     (1,920)      (1.43)     (3,811)      (2.63)

Transportation                   (2,945)      (2.18)     (1,831)      (1.26)

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Net crude oil                   106,671       79.09      97,022       66.82 

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Natural Gas Prices





Year ended December 31                2011                    2010          

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                                  $000s       $/Mcf       $000s       $/Mcf 

Natural gas                      67,101        3.84      95,788        4.23 

Realized financial contracts     24,932        1.43      14,646        0.65 

Transportation                   (5,312)      (0.30)     (6,967)      (0.31)

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Net natural gas                  86,721        4.97     103,467        4.57 

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NGL Prices





Year ended December 31                2011                    2010          

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                                  $000s       $/Bbl       $000s       $/Bbl 

NGL                               9,554       69.80       9,379       54.44 

Transportation                      (68)      (0.50)         (8)      (0.05)

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Net NGL                           9,486       69.30       9,371       54.39 

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Performance by Property





Year ended December 31                                                      

                                              2011                          

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

                                                     Operating    Funds flow

                                                     netbacks/          from

                             Production                BOE (1) operations(2)

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                             BOE/d             %             $             %

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Peace                        6,845            57         22.42            60

Smoky                        2,859            24         19.57            22

Cherhill                       973             8         25.85            10

Worsley                        563             5          7.80             2

Other                          800             6         20.88             6

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                            12,040           100         21.24           100

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Year ended December 31                                                      

                                              2010                          

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                                                     Operating    Funds flow

                                                     netbacks/          from

                             Production                 BOE(1) operations(2)

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                             BOE/d             %             $             %

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Peace                        7,672            52         18.59            51

Smoky                        3,483            24         18.95            23

Cherhill                     1,063             7         20.10             8

Worsley                        857             6          7.89             2

Other                        1,725            11         26.66            16

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                            14,800           100         19.11           100

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(1)Operating netbacks/BOE exclude GCA and hedging gains and losses, and are calculated by subtracting royalties, operating costs, and transportation from revenues and dividing the result by the average production for the period

(2)See "Non-GAAP Measurements"

Peace Area

Peace area production averaged 2,257 Bbl/d of oil and NGLs and 27.5 Mmcf/d of natural gas during 2011. During the same period in 2010, production averaged 1,904 Bbl/d of oil and NGLs and 34.6 Mmcf/d of natural gas. The area contributed 60% to total funds flow from operating activities in 2011 based on 57% of production volumes. During 2011, crude oil and liquids production increased by 19% in the Peace area compared to 2010.

During the second half of 2010 Guide confirmed the viability of oil in the Normandville/Girouxville Montney fairway. This oil project was further advanced during 2011 with the drilling of 25 Montney oil wells. Guide plans to continue with this development in 2012 with a similar level of drilling activity, as well as a facility expansion.

A total of 39 (38.5 net) wells were drilled in the Peace area in 2011, of which 13 (12.7 net) wells were drilled in the fourth quarter. Up to a total of 30 (30.0 net) oil wells are planned in 2012.

Smoky Area

The Smoky area production averaged 497 Bbl/d of oil and NGLs and 14.2 Mmcf/d of natural gas during 2011. During the same period in 2010, production averaged 420 Bbl/d of oil and NGLs and 18.4 Mmcf/d of natural gas. In 2011, the Smoky area contributed 22% of funds flow from operations and 24% of production volumes.

The Corporation plans to continue drilling on this project at a measured pace and to closely monitor results. One (1.0 net) well was drilled within the Smoky area during the fourth quarter. In 2012 Smoky area activity will focus on mid-Montney oil at Bezanson and deep natural gas at Smoky Heights as well as the potential of the Duvernay shale in the area.

Cherhill Area

Production in the Cherhill area averaged 619 Bbl/d of oil and NGLs and 2.1 Mmcf/d of natural gas. During the same period in 2010, production averaged 688 Bbl/d of oil and NGLs and 2.2 Mmcf/d of natural gas. In 2011, the Cherhill area contributed 10% of the funds flow from operations and 8% of production volumes.

Assets at Alexis and St. Anne continue to be exploited and optimized. While no drilling occurred here during the fourth quarter, 2 (2.0 net) wells were drilled in 2011, and up to 6 (4.4 net) wells are planned for 2012.

Royalties





Year ended December 31                                  2011           2010 

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

($000s, except as indicated)                                                

Crown                                                 27,316         35,877 

Freehold                                               4,644          4,063 

GORR and other                                         3,640          4,120 

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Gross royalties                                       35,600         44,060 

GCA                                                   (6,459)       (12,670)

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Net royalties                                         29,141         31,390 

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

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

% of revenue                                            18.9           21.2 

% of revenue net of GCA                                 15.5           15.1 



Gross royalties were 18.9% of revenues during 2011, compared to 21.2% for the same period in 2010. By product, gross royalties were 18.4% for light oil, 16.6% for natural gas, 22.9% for heavy oil, and 28.5% for liquids. For the year ended December 31, 2010, gross royalties were 25.0% for light oil, 17.2% for natural gas, 22.6% for heavy oil, and 26.8% for liquids.

The royalty rate for light oil decreased in 2011 compared 2010, reflecting a decrease in the maximum royalty rate effective January 1, 2011.

Total royalties, net of GCA, were 15.5% during 2011, compared to 15.1% during 2010.

Under the Drilling Royalty Credit ("DRC") incentive program, the Alberta Government applied up to $200 per meter for wells spud during the period April 1, 2009 to March 31, 2011 against net crown royalties payable. As at December 31, 2011, the Corporation had received in aggregate drilling credits totaling $23.4 million which were recorded as a reduction of property and equipment.

Operating Costs





Year ended December 31            2011                       2010           

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

                       Production Operating Costs Production Operating Costs

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

                                %     %     $/BOE          %     %     $/BOE

Peace                          57    55     11.27         52    52      9.50

Smoky                          24    15      7.15         24    13      5.15

Cherhill                        8    10     13.96          7    10     13.80

Worsley                         5     6     15.46          6     9     14.33

Other                           6    14     24.59         11    16     13.37

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                              100   100     11.59        100   100      9.52

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Operating costs were $11.59/BOE during 2011, an increase of 22% from $9.52/BOE in 2010. This increase was caused by the drop in daily production volumes, higher utility costs, and increased propane and fuel costs related to new oil wells on production.

Operating expenses by product were as follows:





Year ended December 31                     2011                 2010        

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

                                     ($000's)     $/BOE   ($000's)     $/BOE

Light oil                             12,755      13.07    12,006      11.29

Heavy oil                              6,913      18.54     6,016      15.47

NGLs                                   1,527      11.14     1,599       9.28

Natural gas                           29,739      10.20    31,784       8.40

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BOE                                   50,934      11.59    51,405       9.52

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General and Administration Expenses





Year ended December 31                    2011                 2010         

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

($000s)                                          $/BOE                $/BOE 

Gross                                 21,034      4.78     20,016      3.71 

Capitalized overhead                  (3,881)    (0.88)    (3,411)    (0.64)

Overhead recoveries                   (1,678)    (0.38)    (1,832)    (0.34)

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Net                                   15,475      3.52     14,773      2.73 

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



Gross general and administrative ("G&A") expenses in 2011 included $2.3 million of costs related to restructuring and associated retiring allowances.

Capital and Deferred Taxes

The 2011 and 2010 current tax provisions of $250,000 and $203,000, respectively, relate to Saskatchewan capital and resource tax, and were based upon revenues earned in Saskatchewan. It is not expected that Guide will pay income taxes in 2012.

The 2011 deferred income tax recovery was $43.1 million on a loss before tax of $255.7 million. A deferred income tax asset of $20.7 million was not recognized at December 31, 2011. A deferred income tax recovery of $10.9 million on a loss before tax of $11.7 million was recorded in 2010. The 2010 income tax recovery included an $11.8 million benefit relating to the disposal of properties.

Capital Expenditures





Exploration and evaluation assets, property and equipment            ($000s)

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

Balance at December 31, 2010                                        816,647 

Additions                                                           150,495 

Disposals                                                           (10,676)

Acquisitions                                                          7,150 

Net decommissioning liability additions (disposals)                   6,003 

Capitalized share-based compensation                                  1,005 

Derecognition expense                                                (7,538)

Non-monetary transactions                                               123 

Depletion and depreciation                                          (90,666)

Impairment of property and equipment                               (255,000)

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Balance at December 31, 2011                                        617,543 

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

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



Capital expenditures during 2011 were $150.5 million. Drilling and completions expenditures comprised 68% of capital activity. The Corporation drilled 54 (49.5 net) wells, resulting in 43 (38.9 net) oil wells and 11 (10.6 net) natural gas wells, for a success rate of 100% during the year.

On August 4, 2011, the Corporation purchased interests in certain natural gas properties in the Smoky area for cash consideration of approximately $6.9 million including closing adjustments.

On August 31, 2011, properties in the Western Montney area of British Columbia were sold for net proceeds of $12.7 million, resulting in a gain on disposition of $2.9 million.





Year ended December                        2011                 2010        

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

($000s)                                               %                    %

Land                                   13,180         9     6,807          5

Geological and geophysical              4,488         3     2,354          2

Drilling and completion               101,652        68   104,663         77

Plant and facilities                   29,169        19    22,634         16

Inventory                               1,267         1      (240)         -

Other assets                              739         -       112          -

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

Capital expenditures                  150,495       100   136,330        100

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

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



Liquidity and Capital Resources





                                                                            

As at December 31                                        2011           2010

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

($000s)                                                                     

Bank debt                                             138,248        135,682

Working capital deficiency (1)                         31,646         17,179

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

Total net debt (2)                                    169,894        152,861

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

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



(1)Excludes fair value of financial derivatives and other liability

(2) See "Non-GAAP Measurements"

Funding of Capital Program





                                                                            

Year ended December 31                                  2011           2010 

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

($000s)                                                                     

Issuance of Class A shares, net of costs              30,104            337 

Repurchase of Class A shares                          (2,417)        (4,154)

Funds flow from operations (1)                        98,585        100,478 

Change in bank debt                                    2,566        (81,561)

Change in financing lease                                  -         (1,545)

Acquisition of properties                             (7,150)       (17,791)

Disposals of properties                               15,408        131,949 

Change in working capital and other                   13,399          8,617 

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

                                                     150,495        136,330 

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

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



(1) See "Non-GAAP Measurements"

On September 16, 2011, the Corporation issued 2,300,000 units ("Units") for gross proceeds of $6.5 million under a private placement to the new management group of the Corporation and their designates. Each Unit consisted of one Class A share of the Corporation and one share purchase warrant ("Warrant"). Each Warrant entitles the holder to acquire one Class A share of the Corporation at an exercise price of $3.10 for a period of three years. The Warrants are not exercisable until the twenty day volume weighted average trading price of the Class A shares exceeds $5.00 per share.

On November 16, 2011 the Corporation issued 1,515,152 flow-through Class A shares at $3.30 per share by way of a private placement for gross proceeds of $5.0 million. The Corporation was required to incur qualifying development expenses of $5.0 million prior to December 31, 2011. As of December 31, 2011, all of the required qualifying expenditures had been incurred.

On November 24, 2011 the Corporation issued 5,634,000 flow-through Class A shares at $3.55 per share for gross proceeds of $20.0 million. The Corporation is required to incur qualifying exploration expenses of $20.0 million prior to December 31, 2012. As of December 31, 2011, $2.0 million of the required qualifying expenditures had been incurred.

During the year ended December 31, 2011, under the Normal Course Issuer Bid, the Corporation purchased 1,022,100 Class A shares for $2,417,000, of which all shares were cancelled at December 31, 2011.

Subsequent to December 31, 2011, the Corporation entered into an agreement with a syndicate of underwriters to issue, on a bought deal basis, 12,000,000 Class A shares at a price of $3.05 per share for aggregate proceeds, before share issue costs, of $36.6 million. Closing of the offering occurred on January 24, 2012.

On January 31, 2012, the Corporation purchased interests in certain natural gas properties in the Boyer area of Alberta for cash consideration of $61.5 million. At December 31, 2011, a deposit of $6.1 million had been paid towards the transaction.

On February 15, 2012, the Corporation purchased interests in certain petroleum and natural gas properties in the Peace area of Alberta for cash consideration of $6.0 million.

Subsequent to December 31, 2011, the Corporation entered into an agreement to dispose of properties in the Senex area of Alberta for cash consideration of $11.0 million before closing adjustments, a 3% royalty interest, and reimbursement for a recently completed horizontal well. The transaction is expected to close on March 30, 2012.

The Corporation has $250 million in credit facilities available, consisting of a $225 million extendible 364 day revolving term facility and a $25 million non-revolving facility. The $25 million facility is available subject to mutual approval of the banking syndicate and the Corporation, including repayment terms. Collateral for the facilities consists of a demand debenture for $500 million collateralized by a first floating charge over all of the property and equipment of the Corporation. At December 31, 2011, an amount of $138.2 million was drawn against the revolving credit facility (December 31, 2010 - $135.7 million).

The facilities bear interest at the bank's prime or banker's acceptance rates plus a rate margin. The margins range from 1.25% per annum to 5.25% per annum, based upon the Corporation's debt to cash flow ratio. For the year ended December 31, 2011, the effective interest rate was 5.1% (December 31, 2010 - 5.8%).

An annual review is scheduled to occur on or before May 28, 2012. The level of the borrowing base will be determined by the bank syndicate based upon their review of, among other things, the Corporation's reserves and the value thereof, utilizing commodity prices determined by the bank syndicate which will be different than that utilized by the Corporation's independent reserve evaluator.

Impairment of Property and Equipment

At December 31, 2011 the Corporation recorded an impairment expense of $255.0 million related to property and equipment (December 31, 2010 - $Nil). The recoverable amounts of the Corporation's CGUs were estimated at fair value less costs to sell, based on the value of the after-tax cash flows from oil and gas reserves discounted at 10%, using reserves estimated by independent reserve evaluators, and the fair value of undeveloped land determined internally.

Impairments were recorded at each of the Corporation's CGUs with the exception of Peace, resulting from a reduction in the estimated volumes of oil and gas reserves, as well as a weakening of the forward price curve for natural gas as at December 31, 2011 as compared to December 31, 2010.

Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in forward price estimates, production costs or recovery rates may change the economic status of reserves. Future price estimates are used in impairment testing. Commodity prices have fluctuated widely in recent years due to global and regional factors, including supply and demand fundamentals, inventory levels, exchange rates, weather, economic and geopolitical factors. Changes in the economic environment could result in significant changes to the discount rate used to calculate net present values.

A one percent increase in the assumed after tax discount rate would result in an additional impairment of approximately $5.0 million as at December 31, 2011, while a 10% decrease in the forward commodity price estimates would result in an additional impairment of approximately $102.0 million.

Sensitivity Analysis

The following table shows sensitivities to 2012 budgeted funds flow from operations as a result of fluctuations in product prices, production volumes and other market factors. The table is based on budgeted 2012 production volumes, adjusted for the January 31, 2012 acquisition of properties.





Change to annual funds flow from operations       Change    $000s $/share(2)

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

Price per barrel of oil (US$ WTI)(1)         $      1.00      700       0.01

Price per mcf of natural gas (C$ AECO)(1)    $      0.10      800       0.01

Oil production volumes                         100 Bbl/d    2,200       0.02

Gas production volumes                          1 Mmcf/d      300       0.00

Exchange rate (US/Canadian)                  $      0.01    1,300       0.01

Interest rate on debt                                  1%   1,100       0.01

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



(1)After adjustment for estimated royalties

(2)Based on basic shares outstanding at December 31, 2011, adjusted for the January 24, 2012 share issuance.

Contractual Obligations





$                           Total    2012  2013  2014  2015  2016 Thereafter

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

Bank loan                 138,248 138,248     -     -     -     -          -

Operating leases           10,065   1,830 1,830 1,830 1,830 1,830        915

Firm transportation                                                         

 agreements                 6,135   2,810 2,027 1,028   270     -          -

Flow-through share                                                          

 expenditures              18,000  18,000     -     -     -     -          -

Capital commitments         1,500   1,500     -     -     -     -          -

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

Total                     173,948 162,388 3,857 2,858 2,100 1,830        915

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

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



At December 31, 2011 the Corporation is committed to future minimum lease payments of $10.1 million under an operating lease for office space, and $6.1 million in firm contracts relating to the transportation of natural gas.

On November 24, 2011 the Corporation issued 5,634,000 flow-through Class A shares at $3.55 per share for gross proceeds of $20.0 million. The Corporation is required to incur qualifying exploration expenses of $20.0 million prior to December 31, 2012. As of December 31, 2011, $2.0 million of the required qualifying expenditures had been incurred.

At December 31, 2011, the Corporation has entered into contracts for drilling rig services under which the Corporation is committed to using services totaling $1.5 million during the four months ending April 30, 2012.

Litigation

The Corporation is involved in various claims and legal actions arising in the normal course of business. The Corporation does not expect that the outcome of these proceedings will have a material adverse effect on the Corporation as a whole.

Fourth Quarter Results

Q4 2011 compared to Q3 2011





                                       December 31         September 30     

Three months ended                        2011                 2011         

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

                                         1,074,473 BOE        1,076,198 BOE 

($000s)                                    $     $/BOE          $     $/BOE 

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

Revenues                              48,037     44.71     44,026     40.91 

Realized gain on financial                                                  

 derivatives                           4,970      4.62      9,795      9.10 

Royalties                             (8,625)    (8.03)    (8,290)    (7.70)

GCA(1)                                   943      0.88      2,612      2.43 

Transportation costs                  (2,021)    (1.88)    (2,041)    (1.90)

Operating costs                      (12,386)   (11.53)   (12,689)   (11.79)

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

                                      30,918     28.77     33,413     31.05 

General and administration            (3,726)    (3.47)    (4,665)    (4.34)

Interest costs                        (1,798)    (1.67)    (1,874)    (1.74)

Exploration expenses                    (477)    (0.44)       (23)    (0.02)

Capital and other taxes                  (78)    (0.07)       (62)    (0.06)

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

Funds flow from operations(2)         24,839     23.12     26,789     24.89 

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

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



(1)GCA means Gas Cost Allowance

(2)See "Non-GAAP Measurements"

Funds flow from operations decreased by $2.0 million or 7% during Q4 2011 compared to Q3 2011. Higher crude oil production volumes and prices were more than offset by a loss on oil financial derivative contracts in Q4 2011 compared to a gain in Q3 2011, as well as lower natural gas production volumes and prices during Q4 2011.

During the three months ended December 31, 2011, crude oil production and NGL averaged 4,458 Bbls/d in Q4 2011, a 13% increase from 3,962 Bbls/d in Q3 2011. Natural gas production was 43.3 Mmcf/d in the fourth quarter of 2011, a 7% decrease from 46.4 Mmcf/d in the third quarter of 2011.

Natural gas prices, before financial derivative contracts and transportation, averaged $3.37/Mcf in Q4 2011, 13% lower than the $3.87/Mcf received in Q3 2011. Excluding transportation and financial derivative contracts, crude oil prices averaged $85.82/Bbl in Q4 2011, 12% higher than the $76.32/Bbl realized in Q3 2011.

The $4.8 million decrease in realized gains on financial derivative contracts in Q4 2011 reflects primarily a loss on oil derivative contracts in Q4 2011, compared to a gain on these contracts in Q3 2011. The $6.9 million gain on natural gas derivative contracts during the quarter resulted in a $1.73/Mcf increase in the realized gas price. The $1.9 million loss on oil derivative contracts during Q4 2011 resulted in a $5.15/Bbl decrease in the realized price for crude oil.

Operating costs were $12.4 million during the fourth quarter of 2011 and $12.7 million during Q3 2011. On a per unit basis, operating costs were $11.53/BOE in the fourth quarter of 2011, a 2% decrease from $11.79/BOE during the three months ended September 30, 2011.

Net G&A expenses of $3.7 million in Q4 2011 were 20% lower than the expenses of $4.7 million in Q3 2011, due primarily to corporate restructuring costs incurred during the third quarter.





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

Quarterly Highlights                                                        

(unaudited)                                           2011                  

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

Production                                 Q4        Q3        Q2        Q1 

Light oil (Bbl/d)                       3,018     2,343     2,503     2,832 

Heavy oil (Bbl/d)                       1,028     1,245       863       948 

Natural Gas (Mcf/d)                    43,325    46,416    48,257    53,398 

Liquids (Bbl/d)                           412       374       346       368 

BOE/d                                  11,679    11,698    11,755    13,048 

Total BOE produced                  1,074,473 1,076,198 1,069,717 1,174,344 

Daily BOE of production per million                                         

 Class A shares - basic                   132       139       140       155 

                                                                            

Prices (prior to financial                                                  

 derivatives and transportation                                             

 charges)                                                                   

Light oil ($/Bbl)                       88.40     80.14     95.58     83.14 

Heavy oil ($/Bbl)                       78.23     69.16     75.80     64.08 

Crude oil ($/Bbl)                       85.82     76.32     90.51     78.41 

Natural Gas ($/Mcf)                      3.37      3.87      4.10      3.98 

NGLs ($/Bbl)                            70.26     66.79     74.44     67.84 

                                                                            

Per BOE ($)                                                                 

Revenues                                44.71     40.91     44.95     40.91 

Royalties, net of GCA                   (7.15)    (5.27)    (9.01)    (5.23)

Transportation costs                    (1.88)    (1.90)    (1.93)    (1.87)

Operating costs                        (11.53)   (11.79)   (12.64)   (10.51)

Net                                     24.15     21.95     21.37     23.30 

G&A                                     (3.47)    (4.34)    (3.67)    (2.69)

Restructuring costs                         -         -         -         - 

Interest expense                        (1.67)    (1.74)    (1.91)    (1.58)

Exploration expenses                    (0.44)    (0.02)    (0.19)    (0.18)

Capital and other taxes                 (0.07)    (0.06)    (0.05)    (0.05)

Realized gain (loss) on financial                                           

 derivatives                             4.62      9.10      3.25      4.06 

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Funds flow from operations (1)          23.12     24.89     18.80     22.86 

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

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



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

Quarterly Highlights                                                        

(unaudited)                                           2010                  

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

Production                                 Q4        Q3        Q2        Q1 

Light oil (Bbl/d)                       2,600     2,517     3,295     3,249 

Heavy oil (Bbl/d)                         985     1,009     1,108     1,161 

Natural Gas (Mcf/d)                    57,459    59,186    67,689    64,165 

Liquids (Bbl/d)                           394       433       537       527 

BOE/d                                  13,556    13,823    16,222    15,631 

Total BOE produced                  1,247,108 1,271,739 1,476,256 1,406,752 

Daily BOE of production per million                                         

 Class A shares - basic                   161       163       191       184 

                                                                            

Prices (prior to financial                                                  

 derivatives and transportation                                             

 charges)                                                                   

Light oil ($/Bbl)                       76.44     71.26     72.53     77.47 

Heavy oil ($/Bbl)                       60.32     58.13     57.76     64.91 

Crude oil ($/Bbl)                       72.01     67.50     68.82     74.17 

Natural Gas ($/Mcf)                      3.81      3.75      4.07      5.22 

NGLs ($/Bbl)                            58.06     49.48     53.41     56.80 

                                                                            

Per BOE ($)                                                                 

Revenues                                36.88     34.82     37.44     44.28 

Royalties, net of GCA                   (4.42)    (4.16)    (6.71)    (7.59)

Transportation costs                    (1.67)    (1.66)    (1.64)    (1.56)

Operating costs                        (10.11)   (10.20)    (9.03)    (8.88)

Net                                     20.68     18.80     20.06     26.25 

G&A                                     (3.38)    (3.09)    (2.07)    (2.54)

Restructuring costs                         -     (0.05)    (0.81)        - 

Interest expense                        (1.32)    (1.45)    (2.42)    (2.14)

Exploration expenses                        -         -         -         - 

Capital and other taxes                 (0.06)    (0.05)     0.02     (0.07)

Realized gain (loss) on financial                                           

 derivatives                             1.10      1.90      3.61      1.02 

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

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

Funds flow from operations (1)          17.02     16.06     18.39     22.52 

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

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



(1)See "Non-GAAP Measurements"





Quarterly Highlights                                                        

(unaudited)                                         2011                    

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

                                                                            

                                        Q4         Q3         Q2         Q1 

Financial ($000s)                                                           

Petroleum and natural gas                                                   

 revenue, before royalties          48,037     44,026     48,086     48,042 

Operating costs                    (12,386)   (12,689)   (13,517)   (12,342)

General & administrative                                                    

 expenses                           (3,726)    (4,665)    (3,928)    (3,156)

Restructuring costs                      -          -          -          - 

Interest expense                    (1,798)    (1,874)    (2,046)    (1,857)

Impairment of property and                                                  

 equipment                        (255,000)         -          -          - 

Impairment of goodwill                   -          -          -          - 

Funds flow from operations (1)      24,839     26,789     20,115     26,842 

 Per share, basic (1)                 0.28       0.32       0.24       0.32 

 Per share, diluted (1)               0.28       0.32       0.24       0.32 

Earnings (loss)                   (227,147)    17,132     10,505    (13,297)

 Per share, basic                    (2.57)      0.20       0.13      (0.16)

 Per share, diluted                  (2.57)      0.20       0.13      (0.16)

Total assets                       671,057    898,110    880,379    885,286 

Weighted average outstanding                                                

 Class A shares-basic           88,406,663 84,364,096 83,980,083 83,980,083 

Weighted average outstanding                                                

 Class A shares-diluted         88,406,663 84,364,096 83,980,083 83,980,083 

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

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



(1) See "Non-GAAP Measurements"





Quarterly Highlights                                                        

(unaudited)                                         2010                    

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

                                                                            

                                        Q4         Q3         Q2         Q1 

Financial ($000s)                                                           

Petroleum and natural gas                                                   

 revenue, before royalties          45,995     44,279     55,273     62,284 

Operating costs                    (12,612)   (12,978)   (13,328)   (12,487)

General & administrative                                                    

 expenses                           (4,212)    (3,930)    (3,063)    (3,568)

Restructuring costs                      -        (59)    (1,183)         - 

Interest expense                    (1,645)    (1,849)    (3,578)    (3,014)

Impairment of property and                                                  

 equipment                               -          -          -          - 

Impairment of goodwill             (25,333)         -          -          - 

Funds flow from operations (1)      21,227     20,425     27,146     31,680 

 Per share, basic (1)                 0.25       0.24       0.32       0.37 

 Per share, diluted (1)               0.25       0.24       0.32       0.37 

Earnings                           (35,055)       577     14,587     18,808 

 Per share, basic                    (0.41)      0.01       0.17       0.22 

 Per share, diluted                  (0.41)      0.01       0.17       0.22 

Total assets                       869,652    886,847    861,436  1,010,720 

Weighted average outstanding                                                

 Class A shares-basic           83,983,158 84,869,236 85,143,751 85,098,939 

Weighted average outstanding                                                

 Class A shares-diluted         83,983,158 84,869,236 85,143,751 85,098,939 

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

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



(1) See "Non-GAAP Measurements"

Significant factors and trends that have impacted the Corporation's results during the above periods include:

Production in 2011 averaged 12,040 BOE/d compared to 14,800 BOE/d in 2010. The 19% reduction relates primarily to a decline in natural gas production, reflecting the Corporation's capital program being weighted towards oil projects. In addition, the Puskwa light oil properties were sold in the second quarter of 2010.

Recent market events and conditions, including disruptions in the international credit markets and other financial systems and the American and European sovereign debt levels have caused significant volatility in commodity prices.

Operating costs were $11.59/BOE during 2011, an increase of 22% from $9.52/BOE in 2010. This increase was caused by the drop in daily production volumes, higher utility costs, and increased propane and fuel costs related to new oil wells on production.

Petroleum products are sold to major Canadian marketers at spot reference prices or prices subject to commodity contracts based on US WTI for crude oil and AECO for natural gas. As a means of managing the risk of commodity price volatility and improving netback cash flows, Guide has entered into several natural gas and crude oil financial contracts. The $24.9 million gain realized on natural gas derivative contracts in 2011, which increased $10.3 million from 2010, raised the effective gas price received during the year by $1.43/Mcf to $5.27/Mcf, before transportation.

At December 31, 2011 the Corporation recorded an impairment expense of $255.0 million related to property and equipment (December 31, 2010 - $Nil). The recoverable amounts of the Corporation's CGUs were estimated at fair value less costs to sell, based on the value of the after-tax cash flows from oil and gas reserves discounted at 10%, using reserves estimated by independent reserve evaluators, and the fair value of undeveloped land determined internally.

Reserves

The reserves information is based upon an independent reserve evaluation prepared by Sproule effective December 31, 2011 ("Sproule Report"). The following presentation summarizes the Corporation's crude oil, natural gas and natural gas liquids reserves and net present values of future net revenues for the Corporation's reserves using forecast prices and costs based on the Sproule Report. The Sproule Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101.

Further detailed information in respect of Guide's reserves will be included in Guide's Annual Information Form for the year ended December 31, 2011, which is expected to be filed on SEDAR on or before March 30, 2012.

Gross reserves are the total of the Corporation's working interest share before deduction of royalties owned by others and without including any of the Corporation's royalty interests. Net reserves are the total of the Corporation's working interest reserves after deducting amounts attributable to royalties owned by others, plus the Corporation's royalty interest reserves.





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

Summary of Reserves                                                         

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

                      Oil and NGLs                                          

                        (Mbbls)        Natural Gas (Mmcf)     Total (MBOE)  

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

                     Gross      Net     Gross       Net      Gross     Net  

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

Proved developed                                                            

 producing           4,407.4  3,540.5  44,064.7   37,617.5 11,751.5  9,810.1

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

Proved developed                                                            

 non-producing         391.8    306.6  10,823.4    9,359.4  2,195.8  1,866.5

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

Proved undeveloped   4,261.1  3,638.6  31,282.1   27,867.0  9,474.8  8,283.1

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

Total proved         9,060.3  7,485.7  86,170.2   74,844.0 23,422.0 19,959.8

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

Probable             6,692.2  5,336.8  47,972.4   40,920.1 14,687.6 12,156.8

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

Total proved plus                                                           

 probable           15,752.6 12,822.5 134,142.6  115,764.1 38,109.6 32,116.6

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



Note: totals may not add due to rounding





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

                                  Net Present Value of Future Revenue Before

                                  Income Taxes as of December 31, 2011 ($MM)

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

                                             Discounted at:                 

Reserves category                     Undisc         5%        10%       15%

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

Proved developed producing             358.7      300.6      266.4     242.1

Proved developed non-producing          47.0       33.2       25.7      21.1

Proved undeveloped                     197.1      151.5      117.8      92.7

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

Total proved                           602.9      485.2      409.9     355.8

Probable                               430.4      303.2      232.5     186.6

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

Total proved plus probable           1,033.2      788.5      642.4     542.5

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

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



Note: Net present value of future revenues does not represent fair market value. Totals may not add due to rounding. The after tax net present value of Guide's reserves reflects a tax burden on the properties on a stand-alone basis utilizing the Corporation's tax pools. It does not consider the business-entity-level tax situation or tax planning and the estimated value at the level of the business entity may be significantly different. Guide's consolidated financial statements and Management's Discussion & Analysis should be consulted for information at the level of the business entity.





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

                                  Net Present Value of Future Revenue After 

                                  Income Taxes as of December 31, 2011 ($MM)

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

                                             Discounted  at:                

Reserves category                     Undisc         5%        10%       15%

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

Proved developed producing             358.7      300.6      266.4     242.1

Proved developed non-producing          47.0       33.2       25.7      21.1

Proved undeveloped                     197.1      151.5      117.8      92.7

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

Total proved                           602.9      485.2      409.9     355.8

Probable                               327.8      231.5      177.8     143.2

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

Total proved plus probable             930.7      716.7      587.7     499.0

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

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



Note: Net present value of future revenues does not represent fair market value. Totals may not add due to rounding.

The forecast prices and inflation factors used in the Sproule Report were an average of the forecast prices and inflation factors as published by Sproule Associates Ltd., GLJ Consultants Ltd., McDaniel & Associates Consultants Ltd. and AJM-Deloitte as at December 31, 2011 (the "Consultants' Average Forecast Prices"). The following is a summary of the price forecast for the first five years as provided in the Consultants' Average Forecast Prices.





                                          Henry Hub                         

                                 WTI @  (Louisiana) Alberta Spot            

                               Cushing  Natural gas  Natural gas     USD/CAD

Pricing assumptions          ($US/Bbl)    ($US/Mcf)    ($Cdn/GJ)    Exchange

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

2012                             98.14         3.72         3.23        0.99

2013                             98.60         4.42         3.84        0.99

2014                             99.01         4.90         4.30        0.99

2015                            101.08         5.60         4.94        0.99

2016                            102.33         5.98         5.27        0.99

5 year average                   99.83         4.92         4.32        0.99



Reconciliation of Company gross reserves by principal product type - forecast prices and costs





                       LIGHT AND MEDIUM OIL              HEAVY OIL          

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

                                         Gross                        Gross 

                                        Proved                       Proved 

                       Gross    Gross     Plus     Gross    Gross      Plus 

                      Proved Probable Probable    Proved Probable  Probable 

FACTORS               (Mbbl)   (Mbbl)   (Mbbl)    (Mbbl)   (Mbbl)    (Mbbl) 

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

                                                                            

December 31, 2010      5,242    8,386   13,628     7,032    5,873    12,905 

                                                                            

 Extensions              169       74      243       185      513       698 

 Improved Recovery        88       37      125       166       30       196 

 Technical Revisions   2,328   (3,152)    (824)   (5,305)  (5,254)  (10,559)

 Discoveries               0        0        0         0        0         0 

 Acquisitions              0        0        0         0        0         0 

 Dispositions           (121)    (150)    (271)        0        0         0 

 Economic Factors        (65)     (20)     (85)        2      (20)      (18)

 Production             (974)       0     (974)     (373)       0      (373)

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

                                                                            

December 31, 2011      6,668    5,175   11,842     1,708    1,142     2,850 

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

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

                                                                            

                        NATURAL GAS LIQUIDS             NATURAL GAS         

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

                                         Gross                        Gross 

                                        Proved                       Proved 

                       Gross    Gross     Plus     Gross    Gross      Plus 

                      Proved Probable Probable    Proved Probable  Probable 

FACTORS               (Mbbl)   (Mbbl)   (Mbbl)    (MMcf)   (MMcf)    (MMcf) 

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

                                                                            

December 31, 2010        891      731    1,622   135,967   79,731   215,698 

                                                                            

 Extensions                0        0        0         0        0         0 

 Improved Recovery        14        4       18     1,313      438     1,751 

 Technical Revisions     (66)    (350)    (416)  (31,314) (28,606)  (59,919)

 Discoveries               2        0        3       475       42       517 

 Acquisitions             15        3       17     2,648      498     3,145 

 Dispositions            (18)     (12)     (30)   (1,910)  (2,658)   (4,568)

 Economic Factors        (16)      (1)     (17)   (3,624)  (1,473)   (5,097)

 Production             (137)       0     (137)  (17,385)       0   (17,385)

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

                                                                            

December 31, 2011        685      376    1,061    86,170   47,972   134,143 

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

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



At December 31, 2011, future development capital was $142.4 million for gross proved reserves and $211.4 million for gross proved plus probable reserves. Components of the future capital for gross proved plus probable reserves include 2012 - $60.8 million (including 34.8 net wells), 2013 - $81.0 million (including 56.9 net wells), 2014 - $49.1 million (including 38.6 net wells), 2015 - $18.2 million (including 12 net wells) and thereafter $2.3 million (with no further drilling).

Net Asset Value





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

                                       December 31, 2011  December 31, 2011 

                                         forecast prices    forecast prices 

                                        5% discount rate  10% discount rate 

                                                   ($MM)              ($MM) 

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

Net present value of future revenues of                                     

 reserves, discounted, before tax (1)            788.469            642.436 

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

Undeveloped land (2)                              47.236             47.236 

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

Bank debt                                       (138.248)          (138.248)

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

Working capital deficiency                       (31.646)           (31.646)

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

Net asset value                                  665.811            519.778 

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

Basic common shares outstanding (000's)           92.407             92.407 

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

Net asset value per share ($/share)                 7.21               5.62 

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



(1) Derived from the Sproule Report.

(2) Internally valued by Guide (Undeveloped land at an average of $95/Acre or $235/Ha)

At December 31, 2011, the net asset value of the Corporation is estimated at $5.62 per basic share outstanding. This estimate is based on the net present value of future revenues of gross proven and probable reserves, discounted at 10%, before tax of $642.4 million, undeveloped land value of $47.2 million, net debt of $169.9 million and outstanding basic shares of 92.4 million. This net asset value does not include any value for the asset acquisition which was completed on January 31, 2012.

Bank Credit Facilities

The Corporation has $250 million in credit facilities available, consisting of a $225 million extendible 364 day revolving term facility and a $25 million non-revolving facility. At December 31, 2011, an amount of $138.2 million was drawn against the revolving credit facility.

The level of the borrowing base will be determined by the bank syndicate based upon their review of, among other things, the Corporation's reserves and the value thereof, utilizing commodity prices determined by the bank syndicate which will be different than that utilized by the Corporation's independent reserve evaluator. An annual review is in progress. The Corporation does not anticipate a significant change in the amount of these credit facilities.





GUIDE EXPLORATION LTD.                                                      

Consolidated Statements of                                                  

 Financial Position                                                         

                                    December 31,  December 31,   January 1, 

($000's)                                    2011          2010         2010 

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

                                                                            

                                                                            

ASSETS                                                                      

                                                                            

CURRENT                                                                     

  Accounts receivable                     21,259        28,829       41,270 

  Deposits and prepaid expenses            9,258         3,361        6,190 

  Fair value of financial                                                   

   derivatives                            22,997        20,815        4,241 

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

                                          53,514        53,005       51,701 

                                                                            

Exploration and evaluation assets         10,145             -            - 

Property and equipment                   607,398       816,647      881,937 

Goodwill                                       -             -       25,333 

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

                                         671,057       869,652      958,971 

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

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

                                                                            

LIABILITIES                                                                 

                                                                            

CURRENT                                                                     

  Accounts payable and accrued                                              

   liabilities                            62,163        49,369       55,531 

  Financing lease                              -             -        1,545 

  Bank loan                              138,248       135,682      217,243 

  Other liability                          3,554             -        3,775 

  Fair value of financial                                                   

   derivatives                             2,250         6,411       13,789 

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

                                         206,215       191,462      291,883 

                                                                            

Decommissioning liabilities               48,055        39,947       38,228 

Fair value of financial derivatives       21,797        14,980            - 

Deferred income taxes                          -        43,257       49,245 

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

                                         276,067       289,646      379,356 

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

                                                                            

                                                                            

SHAREHOLDERS' EQUITY                                                        

                                                                            

Share capital                            606,256       586,626      595,559 

Contributed surplus                       48,742        40,581       30,174 

Retained earnings (deficit)             (260,008)      (47,201)     (46,118)

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

                                         394,990       580,006      579,615 

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

                                         671,057       869,652      958,971 

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

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

                                                                            

                                                                            

GUIDE EXPLORATION LTD.                                                      

Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss)  

                                                                            

                                                     Year ended December 31 

($000s, except per share amounts)                         2011         2010 

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

                                                                            

                                                                            

INCOME                                                                      

Petroleum and natural gas revenue                      188,191      207,831 

Royalties, net of gas cost allowance                   (29,141)     (31,390)

Realized gain on financial derivatives                  23,010       10,552 

Unrealized gain (loss) on financial derivatives           (474)       8,972 

Gain on disposal of assets                               4,732            - 

Other income                                               123          334 

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

                                                       186,441      196,299 

                                                                            

EXPENSES                                                                    

Operating                                               50,934       51,405 

Transportation                                           8,325        8,806 

General and administration                              15,475       14,773 

Restructuring costs                                          -        1,242 

Share-based compensation                                 2,509        4,447 

Interest                                                 7,575       10,086 

Exploration expenses                                       916            - 

Accretion                                                3,173        2,984 

Derecognition expenses                                   7,538        9,069 

Depletion and depreciation                              90,666       79,886 

Impairment of property and equipment                   255,000            - 

Impairment of goodwill                                       -       25,333 

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

                                                       442,111      208,031 

                                                                            

Loss before taxes                                     (255,670)     (11,732)

                                                                            

Income taxes                                                                

                                                                            

Capital and other taxes                                    250          203 

Deferred income tax recovery                           (43,113)     (10,852)

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

                                                       (42,863)     (10,649)

NET LOSS AND COMPREHENSIVE LOSS                                             

                                                                            

                                                      (212,807)      (1,083)

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

                                                                            

                                                                            

                                                                            

NET LOSS AND COMPREHENSIVELOSS PER SHARE                                    

                                                                            

Basic                                                    (2.50)       (0.01)

Diluted                                                  (2.50)       (0.01)

Weighted average Class A shares - basic             85,192,616   84,770,976 

                                - diluted           85,192,616   84,770,976 



GUIDE EXPLORATION LTD.

Consolidated Statement of Changes in Equity





                                                                            

                                                       Retained             

                                   Share  Contributed   Earnings            

($000s)                          Capital      Surplus  (Deficit)      Total 

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

                                                                            

Balance, January 1, 2010         595,559       30,174    (46,118)   579,615 

                                                                            

Share-based compensation               -        6,380          -      6,380 

Options exercised                    460         (123)         -        337 

Shares purchased and cancelled    (8,304)       4,150          -     (4,154)

Tax deduction of share issue                                                

 costs                            (1,089)           -          -     (1,089)

Comprehensive loss                     -            -     (1,083)    (1,083)

                                                                            

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

Balance, December 31, 2010       586,626       40,581    (47,201)   580,006 

                                                                            

Share-based compensation               -        3,514          -      3,514 

Tax deduction of share issue                                                

 costs                              (197)           -          -       (197)

Issue of common shares            26,891            -          -     26,891 

Shares purchased and cancelled    (7,064)       4,647          -     (2,417)

Comprehensive loss                     -            -   (212,807)  (212,807)

                                                                            

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

Balance, December 31, 2011       606,256       48,742   (260,008)   394,990 

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

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

                                                                            

                                                                            

                                                                            

GUIDE EXPLORATION LTD.                                                      

Consolidated Statements of Cash Flows                                       

                                                     Year ended December 31 

($000s)                                                    2011        2010 

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

                                                                            

                                                                            

Cash provided by (used in):                                                 

                                                                            

OPERATING ACTIVITIES                                                        

Net loss                                               (212,807)     (1,083)

Items not requiring cash:                                                   

  Deferred income tax recovery                          (43,113)    (10,852)

  Impairment of goodwill                                      -      25,333 

  Impairment of property and equipment                  255,000           - 

  Depletion and depreciation                             90,666      79,886 

  Derecognition expenses                                  7,538       9,069 

  Accretion                                               3,173       2,984 

  Share-based compensation                                2,509       4,447 

  Other income                                             (123)       (334)

  Gain on disposal of assets                             (4,732)          - 

  Unrealized gain (loss) on financial derivatives           474      (8,972)

Abandonment costs                                        (1,068)       (491)

Change in non-cash working capital                        6,036       3,378 

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                                                        103,553     103,365 

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FINANCING ACTIVITIES                                                        

  Issue of common shares, net of costs                   30,104         337 

  Repurchase of common shares                            (2,417)     (4,154)

  Financing lease payments                                    -      (1,545)

  Bank loan (repayment)                                   2,566     (81,561)

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                                                         30,253     (86,923)

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INVESTING ACTIVITIES                                                        

  Exploration and evaluation expenditures               (10,145)          - 

  Additions to property and equipment                  (140,350)   (136,330)

  Acquisitions of oil and gas properties                 (7,150)    (17,791)

  Disposals of oil and gas properties                    15,408     131,949 

  Change in non-cash working capital                      8,431       5,730 

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                                                       (133,806)    (16,442)

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CHANGE IN CASH                                                -           - 

CASH, BEGINNING AND END OF PERIOD                             -           - 

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SUPPLEMENTAL INFORMATION                                                    

                                                                            

  Cash interest paid                                      7,665       9,599 

  Cash taxes paid                                           187         371 



Guide has approximately 104.4 million Class A shares issued and outstanding which trade on the Toronto Stock Exchange under the symbol "GO".

ADVISORIES

Forward Looking Statements:

Certain information regarding Guide Exploration Ltd. in this news release including management's assessment of future plans and operations, drilling plans, production estimates and commodity mix, ability to maintain decline at Boyer with minimal capital, type curves for Guide's horizontal Montney wells, Guide's tax status, use of proceeds from financing, drilling and completion costs of certain wells, timing of implementation of pressure maintenance scheme, capital expenditures and the allocation thereof, 2012 funds flow from operations and 2012 funds flow from operations per share and the assumptions relating thereto. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, capital expenditure costs, including drilling, completion and facilities costs, unexpected decline rates in wells, wells not performing as expected, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements.

Included herein is an estimate of Guide's 2012 funds flow from operations and 2012 funds flow from operations per share and is based on the various assumptions as to production levels, commodity prices and other assumptions stated herein. To the extent such estimate constitutes future oriented financial information or a financial outlook, they were approved by management of Guide on January 26, 2012, and such future oriented financial information or financial outlook is included herein to provide readers with an understanding of Guide's anticipated funds flow from operations based on the assumptions described herein estimated and information on funds anticipated to be available to fund Guide's operations, and exploration and development program and readers are cautioned that the information may not be appropriate for other purposes.

Forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although the Corporation believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Corporation can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this document, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Corporation operates; the timely receipt of any required regulatory approvals; the ability of the Corporation to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration results; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Corporation to secure adequate product transportation; future oil and natural gas prices; currency, exchange and interst rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Corporation operates; and the ability of the Corporation to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list of factors and assumptions is not exhaustive. Additional information on these and other factors that could affect Guide's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), at Guide's website (www.guidex.ca). Furthermore, the forward looking statements contained in this news release are made as at the date of this news release and Guide does not undertake any obligation to update publicly or to revise any of the included forward looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

Non-GAAP Measurements:

This news release contains terms commonly used in the oil and gas industry, such as funds flow from operations, funds flow from operations per share, and operating netback. These terms are not defined by Generally Accepted Accounting Principles ("GAAP") and should not be considered an alternative to, or more meaningful than, cash provided by operating activities or net earnings as determined in accordance with GAAP as an indicator of Guide's performance. Management believes that in addition to net earnings, funds flow from operations is a useful financial measurement which assists in demonstrating the Corporation's ability to fund capital expenditures necessary for future growth or to repay debt. Guide's determination of funds flow from operations may not be comparable to that reported by other companies. All references to funds flow from operations throughout this news release are based on cash flow from operating activities before changes in non-cash working capital and abandonment expenditures. The Corporation calculates funds flow from operations per share by dividing funds flow from operations by the weighted average number of Class A shares outstanding. Guide uses the term net debt. This measure does not have any standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures presented by other companies.

Type Curves:

Information on type curves for wells in certain areas, as included herein, are illustrative of the Corporation's expectations for the results for the average well of that type. Actual results for wells drilled may vary from the results predicted from the type curves for such wells and such variations may be material.

BOES:

Disclosure provided herein in respect of barrels of oil equivalent (boe) 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. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1; utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

Contact:
William E. Andrew
Guide Exploration Ltd.
Chair, Chief Executive Officer
(403) 261-6012

Dale A. Miller
Guide Exploration Ltd.
President
(403) 261-6012

Jennifer Livingston
Guide Exploration Ltd.
Manager, Investor Relations
(403) 261-6012
www.guidex.ca

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