Tourmaline Oil Corp. Announces Q4 and 2011 Year End Financial Results

CALGARY, March 20, 2012 /CNW/ - Tourmaline Oil Corp. (TSX:TOU) ("Tourmaline" or the "Company") achieved record growth in reserves (78%), production (74%) and funds from operations1 (81%) while delivering strong profitability in a period of difficult natural gas prices.  The Company posted record after-tax earnings of $42.7 million for the 2011 calendar year.

2011 Highlights

  • Record full year 2011 after-tax earnings of $42.7 million ($0.28/diluted share) compared to after-tax earnings of $8.8 million ($0.07/diluted share) for 2010.
  • Record quarterly production in Q4 2011 of 37,912 boepd - a 65% increase over Q4 2010 and a 10% increase over Q3 2011.
  • Record full year 2011 average production of 31,007 boepd - a 74% increase over 2010.
  • Record quarterly funds from operations of $73.3 million or $0.45 per diluted share - an increase of 17% over Q3 2011.
  • Full year 2011 funds from operations of $241.4 million, or $1.58 per diluted share - an increase of 81% over 2010.
  • Total proved reserves growth of 72% (38% per share) and 2P reserves growth of 78% (47% per share) over 2010.
  • Total proved plus probable reserve additions of 123.2 MMBOE in 2011 with reserve value increasing by $1.12 billion (NPV 10% before tax) despite significantly lower forecast natural gas prices employed in the 2011 report.
  • Strong balance sheet with net debt2 of $228.3 million.
  • Record low operating costs of $5.17/boe in Q4 2011 - a 10% decrease from Q3 2011 and full year 2011 operating costs of $5.58/boe were 12% lower than 2010.
  • Record cash G&A3 costs of $0.82 per boe in Q4 2011 and strong 2011 cash G&A unit costs of $1.02 - down 21% from 2010.
  • Strong operating netback4 of $22.35/boe full year 2011 - a 3% increase over 2010.
  • Tourmaline drilled 89 gross wells (72.7 net wells) in 2011 with a 100% success rate.

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1 Funds from operations is defined as cash provided by operations before changes in non-cash operating working capital.  See "Non-IFRS Financial Measures" in the attached Management's Discussion and Analysis.
2 Net debt is defined as long-term bank debt plus working capital (adjusted for the fair value of financial instruments).  See "Non-IFRS Financial Measures" in the attached Management's Discussion and Analysis.
3 Cash G&A is defined as G&A expenses net of administrative and capital recovery and capitalized G&A.
4 Operating netback is defined as revenue (excluding processing income) less royalties, transportation and operating expenses.  See "Non-IFRS Financial Measures" in the attached Management's Discussion and Analysis.

Production Update

As previously disclosed, the Company reached production levels of 50,000 boepd during the first quarter of 2012 and increased full-year 2012 production guidance from 47,000 to 50,000 boepd.  This represents 61% growth over 2011 average production levels.

Current production has now reached 53,000 boepd; the Company has an additional 8 wells to tie-in prior to spring break-up.  Oil and liquids production has recently reached the 7,000 bpd level; the Company expects to reach 10,000 bpd of oil and liquids in the fourth quarter of this year.

Recent EP Highlights

In addition to record well results in all operated areas announced on January 25, 2012 and March 5, 2012, the Company has had additional strong EP successes.  These include:

  • The Kakwa-Falher horizontal flowed at a final test rate of 25.0 mmcfpd at 14.8 MPa with liquids.5
  • The Spirit River 5-4 Charlie Lake horizontal flowed oil at a final test rate of 875 bopd with 1.6 mmcfpd of gas.5
  • The Horse vertical Dunvegan well flowed at a final test rate of 17.6 mmcfpd at 19.6 MPa with approximately 230 bpd of condensate.5
  • The Edson 15-34 Wilrich horizontal flowed gas at a final test rate of 15.5 mmcfpd @ 14.0 MPa with condensate and liquids.5
  • The Company's most recent Sunrise Montney well is producing gas at a rate of 18.0 mmcfpd with approximately 700 bpd of condensate.

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5 Three-day test or longer.  Production tests are not indicative of long-term performance or ultimate recovery.



CORPORATE SUMMARY - DECEMBER 31, 2011                    
  Three Months Ended December 31,   Twelve Months Ended December 31,
    2011     2010 Change     2011     2010 Change
OPERATIONS                          
Production                          
  Natural gas (mcf/d)               200,403                 122,294 64%     165,966     95,605 74%
  Crude oil and NGL (bbls/d)               4,512                 2,571 76%     3,346     1,922 74%
  Oil equivalent (boe/d)               37,912                 22,953 65%     31,007     17,856 74%
                           
Product prices6                          
  Natural gas ($/mcf) $        3.76   $        4.17 (10)%   $        4.17   $        4.52 (8)%
  Crude oil and NGL ($/bbl) $        93.05   $        75.94 23%   $        90.24   $        74.62 21%
                           
Operating expenses ($/boe) $        5.17   $        5.51 (6)%   $        5.58   $        6.34 (12)%
                           
Transportation expenses ($/boe) $        2.24   $        1.80 24%   $        2.07   $        1.74 19%
                           
Operating netback ($/boe) $        21.39   $        22.66 (6)%   $        22.35   $        21.76 3%
                           
Cash general & administrative expenses7 ($/boe) $        0.82   $        1.32 (38)%   $        1.02   $        1.29 (21)%
                           
                           
FINANCIAL ($000, EXCEPT PER SHARE)                          
Revenue               107,944                 64,919 66%     362,992     210,105 73%
Royalties               7,510                 1,634 360%     23,553     15,630 51%
                           
Funds from operations               73,311                 44,940 63%     241,352     133,218 81%
Funds from operations per share $        0.45   $        0.34 32%   $        1.58   $        1.08 46%
                           
Net earnings               16,074                 5,865 174%     42,681     8,813 384%
Net earnings per share $        0.10   $        0.04 150%   $        0.28   $        0.07 300%
                           
Capital expenditures                 828,956     814,334 2%
                           
Weighted average shares outstanding (diluted)                 152,315,296     123,394,559 23%
                           
Net debt                 (228,342)     (49,170) 364%
                           
                           
PROVED + PROBABLE RESERVES8                          
Natural gas (bcf)                             1,417.4                 829.4 71%
Crude oil (mbbls)                 10,935     6,479 69%
Natural gas liquids (mbbls)                 22,899     13,474 70%
Mboe                 270,069     158,181 71%

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6 Product prices include realized gains and losses on financial instrument contracts.
7 Excluding interest and financing charges.
8 Company interest reserves are gross reserves prior to deduction of royalties and includes any royalty interests of the Company

Conference Call Tomorrow at 9:00 a.m. MT (11:00 a.m. ET)

Tourmaline will host a conference call tomorrow, March 21, 2012 starting at 9:00 a.m. MT (11:00 a.m. ET). To participate, please dial (888) 231-8191 (toll-free in North America) or (647) 427-7450 a few minutes prior to the conference call.

The conference call ID number is 54409721

Reader Advisory

See "Forward-Looking Statements", "Boe Conversions" and "Non-IFRS Financial Measures" in the attached Management's Discussion and Analysis.

The estimated values of future net revenue of the Company's reserves disclosed in this news release do not represent fair market value. The reserve data provided in this news release presents only a portion of the disclosure required under National Instrument 51-101. All of the required information will be contained in the Company's Annual Information Form for the year ended December 31, 2011, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 30, 2012. See also the Company's news release dated March 5, 2012

.

MANAGEMENT'S DISCUSSION AND ANALYSIS

For the years ended December 31, 2011 and December 31, 2010

This management's discussion and analysis ("MD&A") should be read in conjunction with Tourmaline's consolidated financial statements and related notes for the years ended 2011 and 2010.  Both the consolidated financial statements and the MD&A can be found at www.sedar.com.  This MD&A is dated March 19, 2012.

The financial information contained herein has been prepared in accordance with International Financial Reporting Standards ("IFRS").  All dollar amounts are expressed in Canadian currency, unless otherwise noted.

Certain financial measures referred to in this MD&A are not prescribed by IFRS.  See "Non-IFRS Financial Measures" for information regarding the following Non-IFRS financial measures used in this MD&A: "funds from operations", "operating netback", "working capital (adjusted for the fair value of financial instruments)" and "net debt".

Additional information relating to Tourmaline can be found at www.sedar.com.

Forward-Looking Statements - Certain information regarding Tourmaline set forth in this document, including management's assessment of the Company's future plans and operations, contains forward-looking statements that involve substantial known and unknown risks and uncertainties. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "should", "believe" and similar expressions are intended to identify forward-looking statements. Such statements represent Tourmaline's internal projections, estimates or beliefs concerning, among other things, an outlook on the estimated amounts and timing of capital investment, anticipated future debt, production, revenues or other expectations, beliefs, plans, objectives, assumptions, intentions or statements about future events or performance. These statements are only predictions and actual events or results may differ materially. Although Tourmaline believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, operational, economic, competitive, political and social uncertainties and contingencies. Many factors could cause Tourmaline's actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, Tourmaline.

In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to: the amount of, and future net revenues from, crude oil, NGL (natural gas liquids) and natural gas reserves; future prospects; the focus, amount and timing of capital expenditures; expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; access to debt and equity markets; projections of market prices and costs; the performance characteristics of the Company's crude oil, NGL and natural gas properties; crude oil, NGL and natural gas production levels and product mix; Tourmaline's future operating and financial results; capital investment programs; supply and demand for crude oil, NGL and natural gas; future royalty rates; drilling, development and completion plans and the results therefrom; future land expiries; dispositions and joint venture arrangements; amount of operating, transportation and general and administrative expenses; treatment under governmental regulatory regimes and tax laws; and estimated tax pool balances.  In addition, statements relating to "reserves" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.

These forward-looking statements are subject to numerous risks and uncertainties, most of which are beyond the Company's control, including the impact of general economic conditions; volatility in market prices for crude oil, NGL and natural gas; industry conditions; currency exchange rate fluctuation; imprecision of reserve estimates; liabilities inherent in crude oil, natural gas and NGL operations; environmental risks; incorrect assessments of the value of acquisitions and exploration and development programs; competition; the lack of availability of qualified personnel or management; the lack of availability of oilfield equipment and services; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; stock market volatility; the performance of existing wells and recently drilled and tested wells; the success obtained in drilling new wells; the sufficiency of budgeted capital expenditures in carrying out planned activities; the ability to access sufficient capital from internal and external sources; the receipt of applicable approvals; and the other risks considered under "Risk Factors" in Tourmaline's most recent annual information form available at www.sedar.com.

With respect to forward-looking statements contained in this MD&A, Tourmaline has made assumptions regarding: future commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment and services; effects of regulation by governmental agencies; and future operating costs.

Management has included the above summary of assumptions and risks related to forward-looking information provided in this MD&A in order to provide readers with a more complete perspective on Tourmaline's future operations and such information may not be appropriate for other purposes.  Tourmaline's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that the Company will derive therefrom.  Readers are cautioned that the foregoing lists of factors are not exhaustive.

These forward-looking statements are made as of the date of this MD&A and the Company disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

Boe Conversions - Per barrel of oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent (6:1). Barrel of oil equivalents (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.  In addition, as the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil 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.

PRODUCTION

  Three Months Ended December 31, Years Ended December 31,
  2011 2010 Change 2011 2010 Change
Natural Gas (mcf) 18,437,079 11,251,067 64% 60,577,481 34,895,923 74%
Crude oil and NGL (bbl) 415,074 236,502 76% 1,221,268 701,355 74%
Oil equivalent (Boe) 3,487,920 2,111,680 65% 11,317,515 6,517,342 74%
Oil equivalent (Boepd) 37,912 22,953 65% 31,007 17,856 74%

Production for the fourth quarter of 2011 averaged 37,912 Boe/d, a 65% increase over the fourth quarter of 2010 average production of 22,953 Boe/d.  Production was 88% natural gas weighted in the fourth quarter of 2011, which is consistent with the fourth quarter of 2010.  For the year ended December 31, 2011, production increased 74% to 31,007 Boe/d from 17,856 Boe/d in 2010.  The Company's significant production growth can be attributed to 80.5 (net) new wells that were brought on-stream in 2011, as well as property and corporate acquisitions during the year.

REVENUE

  Three Months Ended December 31, Years Ended December 31,
(000s)       2011   2010   2011   2010
Revenue from:                        
  Natural Gas $     69,323 $ 46,958 $ 252,781 $ 157,769
  Oil and NGL       38,621   17,961   110,211   52,336
Total revenue from oil, NGL and gas sales $     107,944 $ 64,919 $ 362,992 $ 210,105

For the three months ended December 31, 2011, revenue totalled $107.9 million compared to $64.9 million for the same period in 2010.  Revenue for the year ended December 31, 2011, increased 73% to $363.0 million from $210.1 million in 2010.  Revenue growth for the three months and year ended December 31, 2011, is consistent with the increased production over the same periods.  Revenue includes all petroleum, natural gas and NGL sales and realized gains on financial instruments.

TOURMALINE PRICES:

  Three Months Ended December 31, Years Ended December 31,
        2011   2010 Change   2011   2010 Change
Natural Gas ($/mcf)     $     3.76     $     4.17     (10)%     $ 4.17 $ 4.52 (8)%
Oil and NGL ($/bbl)     $     93.05     $     75.94     23%     $ 90.24 $ 74.62 21%
Oil equivalent ($/Boe)     $     30.95     $     30.74     1%     $ 32.07 $ 32.24 (1)%

The realized average natural gas price for the quarter and year ended December 31, 2011 were 10% and 8%, respectively, lower than the same periods of the prior year. Realized crude oil and NGL prices increased 23% and 21% in the quarter and year ended December 31, 2011, respectively, compared to the same periods of the prior year.

The realized natural gas price for the year ended December 31, 2011 was 15% (December 31, 2010 - 13%) higher than the AECO benchmark due to a combination of higher heat content in the Company's Alberta Deep Basin natural gas production and advantageous commodity contracts.  Realized prices exclude the effect of unrealized gains or losses on commodity contracts. Once these gains and losses are realized they are included in the per unit amounts.

BENCHMARK OIL AND GAS PRICES:

  Three Months Ended December 31, Years Ended December 31,
    2011   2010 Change   2011   2010 Change
Natural Gas                                                            
  NYMEX Henry Hub (US$/mcf)     $     3.48     $     3.98     (13)%     $     4.03     $     4.38     (8)%
  AECO (Cdn$/mcf)     $     3.19     $     3.61     (12)%     $     3.64     $     3.99     (9)%
Oil                                                            
  NYMEX (US$/bbl)     $     94.06     $     85.24     10%     $     95.11     $     79.61     19%
  Edmonton Par (Cdn$/bbl)     $     98.17     $     80.91     21%     $     95.57     $     78.16     22%
                       

RECONCILIATION OF AECO INDEX TO TOURMALINE'S REALIZED GAS PRICES:

  Three Months Ended December 31, Years Ended December 31,
($/mcf)   2011   2010 Change   2011   2010 Change
AECO index     $             3.19     $       3.61      (12)%     $     3.60     $     3.87     (7)%
Heat/quality differential                   0.22             0.18      22%           0.24           0.22     9%
Realized gain                   0.35             0.38      (8)%           0.33           0.43     (23)%
Tourmaline realized natural gas price     $             3.76     $       4.17      (10)%     $     4.17     $     4.52     (8)%
                 

CURRENCY - EXCHANGE RATES:

  Three Months Ended December 31, Years Ended December 31,
    2011   2010 Change   2011   2010 Change
Cdn/US$     $     0.9775     $ 0.9874     (1)%     $     1.0110     $     0.9707     4%
                     

ROYALTIES

Tourmaline's royalties are analyzed as follows:

  Three Months Ended December 31, Years Ended December 31,
(000s)       2011   2010   2011   2010
Natural Gas     $     2,254     $                 (698)     $ 7,134 $ 5,295
Oil and NGL     $     5,256     $                 2,332     $ 16,419 $ 10,335
Total royalties     $     7,510     $                 1,634     $ 23,553 $ 15,630

For the quarter ended December 31, 2011, the average effective royalty rate was 7.0% compared to 2.5% for the same period in 2010.  The royalty rate for the fourth quarter of 2010 was significantly lower due to various drilling incentive program credits received during the quarter. For the year ended December 31, 2011, the average effective royalty rate decreased to 6.5% compared to 7.4% for the same period of 2010. The Company continues to benefit from Provincial Government incentive programs including the Natural Gas Deep Drilling Program and the New Well Royalty Reduction Program in Alberta and the Royalty Relief Program and the Deep Royalty Credit Program in British Columbia.

For 2012, the Company expects its royalty rate to be approximately 10% as some of the wells will no longer qualify for royalty incentive programs due to production maximums being reached and other wells will come off royalty holidays, thereby increasing the Company's overall royalty rate. The royalty rate is sensitive to commodity prices and as such lower prices will offset some of the effects of losing the above noted incentives on certain wells.

OTHER INCOME

For the three months and year ended December 31, 2011, other income was $2.4 million and $5.8 million, respectively, compared to $0.7 million and $1.5 million for the same periods in 2010.  Tourmaline continues to build and acquire interests in facilities which have helped to generate increased third-party processing income.

OPERATING EXPENSES

  Three Months Ended December 31, Years Ended December 31,
($000s, except per unit amounts)       2011   2010   2011   2010
Operating Expenses     $     18,028     $                 11,633     $ 63,129 $ 41,352
Per Boe     $     5.17     $                 5.51     $ 5.58 $ 6.34

Operating expenses include all periodic lease and field level expenses and exclude income recoveries from processing third-party volumes. Operating expenses for the fourth quarter of 2011 were $18.0 million or 55% higher than the same quarter of 2010 operating expenses of $11.6 million due to increased variable costs relating to new production.  On a per-Boe basis, fourth quarter operating expenses decreased 6% compared to the same quarter of the prior year, due to increased production, and the impact of redirecting natural gas from third-party facilities to Tourmaline-owned infrastructure.

For the year ended December 31, 2011, operating expenses were $63.1 million or $5.58/Boe compared to $41.4 million or $6.34/Boe for the same period of 2010.  Although the total operating expenses increased commensurate with production, the costs per Boe decreased 12%, reflecting increased operational efficiencies.  In 2011, Tourmaline's operating expenses included third-party processing, gathering and compression fees of approximately $19.1 million or $1.68 per Boe (2010- $15.7 million or $2.40 per Boe).  The Company continues to increase capacity at its plants in order to reduce third-party processing charges.  In December 2011, the Company completed its plant expansion at Sunrise in N.E. British Columbia and commissioned a new gas plant at Musreau in the Alberta Deep Basin.  These projects allow for additional volumes to flow through Company owned-and-operated plants thereby reducing third-party processing charges on a go-forward basis.

The Company's operating cost target is $5.25 per Boe in 2012.  Actual costs per Boe can change, however, depending on a number of factors including the Company's actual production levels.

TRANSPORTATION

Transportation costs for the three months ended December 31, 2011 were $7.8 million or $2.24 per Boe (2010 - $3.8 million or $1.80 per Boe, respectively).  Transportation costs for the year ended December 31, 2011, were $23.4 million compared to $11.4 million in 2010 due to increased production in 2011.  On a per-Boe basis, transportation costs for 2011 were 19% higher at $2.07 per Boe compared to $1.74 per Boe in 2010.  This increase can primarily be attributed to higher relative production in British Columbia which carries higher transportation costs.

GENERAL & ADMINISTRATIVE EXPENSES ("G&A")

  Three Months Ended December 31, Years Ended December 31,
($000s, except per unit amounts)       2011       2010   2011   2010
G&A expenses     $     7,256     $     6,503     $ 23,943 $ 19,907
Administrative and capital recovery           (786)       (1,856)       (2,413)   (5,156)
Capitalized G&A           (3,600)           (1,868)       (10,036)   (6,359)
Total G&A expenses     $     2,870     $     2,779     $ 11,494 $ 8,392
Per Boe           0.82           1.32       1.02       1.29

G&A expenses for the fourth quarter of 2011 were $2.9 million compared to $2.8 million for the same quarter of the prior year.  During the fourth quarter of 2011, the Company capitalized $4.4 million in direct G&A costs compared to $3.7 million for the same period of 2010.  Cash G&A expenses were $0.82 per Boe for the fourth quarter of 2011, compared to $1.32 per Boe for the same quarter in 2010, resulting in a decrease of 38% primarily due to the higher production levels in 2011.

For the year ended December 31, 2011, G&A expenses totalled $11.5 million compared to $8.4 million for the prior year.  During the same period, direct G&A costs of $12.4 million were capitalized (December 31, 2010 - $11.5 million).  The increase in G&A expenses in 2011 compared to 2010 is primarily due to office staff additions and higher rent expense as the Company increased its head office space. The higher total G&A expenses result from the need to manage the larger production, reserve and land base.  Notwithstanding this, the Company's G&A expenses per Boe continue to trend downward as Tourmaline's production base continues to grow faster than its accompanying G&A costs.  G&A costs decreased 21% for the year ended December 31, 2011 to $1.02 per Boe, compared to $1.29 per Boe for 2010.  This decrease in per Boe G&A costs is consistent with a growing production base.

G&A costs for 2012 are not expected to exceed $1.00 per Boe, due to higher forecasted production volumes expected in 2012.  Actual costs per Boe can change, however, depending on a number of factors including the Company's actual production levels.

SHARE-BASED COMPENSATION

  Three Months Ended December 31, Years Ended December 31,
($000s, except per unit amounts)       2011       2010   2011   2010
Share-based payments     $     6,266     $     7,029     $ 23,370 $ 20,776
Capitalized share-based payments           (3,133)           (3,515)       (11,685)   (10,388)
Total share-based payments     $     3,133     $     3,514     $ 11,685 $ 10,388

Tourmaline uses the fair value method for the determination of all non-cash related share-based payments. During the fourth quarter of 2011, 2,038,024 share options were granted to employees, officers, directors and key consultants at an exercise price of $28.35, and 410,000 options were exercised, bringing $3.1 million cash into treasury.  For the fourth quarter of 2011, share-based payments and capitalized share-based payments were $3.1 million and $3.1 million, compared to $3.5 million and $3.5 million, respectively, for the same quarter of the prior year.

For the year ended December 31, 2011, share-based payments totalled $11.7 million and a further $11.7 million in share-based payments were capitalized (December 31, 2010 - $10.4 million and $10.4 million, respectively).  The increase in share-based payments reflects the increased number of employees due to increased activity.  During the year, 1,356,502 share options were exercised bringing $12.5 million cash into treasury.

DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A")

  Three Months Ended December 31, Years Ended December 31,
($000s, except per unit amounts)       2011       2010   2011       2010
Depletion, Depreciation and Amortization     $     41,240     $     29,265     $ 158,168 $     96,660
Per Boe     $     11.82     $     13.86     $ 13.98 $     14.83

DD&A expense was $41.2 million for the fourth quarter of 2011 compared to $29.3 million for the same period in 2010 due to higher production volumes, as well as, a larger capital asset base being depleted.  The per-unit DD&A rate for the fourth quarter of 2011 was $11.82 per Boe compared to $13.86 per Boe for the fourth quarter of 2010.  The lower rate reflects the positive reserve additions in the fourth quarter of 2011.

For the year ended December 31, 2011, DD&A expense was $158.2 million (December 31, 2010 - $96.7 million) with an effective rate of $13.98/Boe (2010 - $14.83/Boe).  The lower DD&A rate in 2011 reflects strong reserve additions derived from Tourmaline's exploration and production program.

FINANCE EXPENSES

Finance expenses for the fourth quarter of 2011 totalled $1.1 million and are comprised of interest expense, accretion of provisions, as well as transaction costs incurred on the corporate acquisition of Cinch Energy Corp.  Finance expenses for the fourth quarter of 2010 were $1.2 million.

For the year ended December 31, 2011, finance expenses were $6.2 million compared to $2.8 million for the same period of 2010.  The increased finance expenses are largely due to a $2.8 million increase in interest expense resulting from a higher average balance drawn on the credit facility during 2011.

CASH FLOW FROM OPERATIONS, FUNDS FROM OPERATIONS AND NET EARNINGS

  Three Months Ended December 31, Years Ended December 31,
    2011   2010 Change   2011   2010 Change
Cash flow from operations per share (1)     $     0.38     $     0.35     9%     $ 1.50 $ 1.16 29%
Funds from operations per share (1) (2)     $     0.45     $     0.34     32%     $ 1.58 $ 1.08 46%
Earnings per share (1)     $     0.10     $     0.04     150%     $ 0.28 $ 0.07 300%
Operating netback per Boe (2)     $     21.39     $     22.66     (6)%     $ 22.35 $ 21.76 3%
(1) Fully diluted
(2) See "Non-IFRS Financial Measures"
                               

Funds from operations for the three months and year ended December 31, 2011 were $73.3 million and $241.4 million, respectively, or $0.45 and $1.58, respectively, on a per-diluted-share basis.  The Company had after-tax earnings of $16.1 million ($0.10 per diluted share) for the three months ended December 31, 2011, compared to after-tax earnings of $5.9 million ($0.04 per diluted share) in the previous year.  For the year ended December 31, 2011, Tourmaline had after-tax earnings of $42.7 million ($0.28 per diluted share) compared to $8.8 million ($0.07 per diluted share) in 2010. The increase in funds from operations and after-tax earnings in 2011 can be attributed to the larger production base, higher revenues and continued cost containment for the year compared to 2010.

CAPITAL EXPENDITURES

  Three Months Ended December 31, Years Ended December 31,
(000s)   2011   2010   2011   2010
Land and seismic     $ 17,227     $ 6,477     $ 51,995 $ 35,842
Drilling and completions       146,586       115,616       431,977   322,928
Facilities       58,638       42,625       227,052   128,577
Property acquisitions       6,590       53,834       115,231   343,234
Corporate acquisitions       -       -       -   3,156
Property dispositions       (617)       (2,813)       (7,983)   (24,647)
Other       3,743       1,325       10,684   5,244
Total cash capital expenditures     $ 232,167     $ 217,064     $ 828,956 $ 814,334

During the fourth quarter of 2011, the Company invested $232.2 million of cash consideration, net of dispositions, compared to $217.1 million for the same period in 2010.  Expenditures on exploration and production were $222.5 million compared to $164.7 million in the same quarter of 2010, which is consistent with the Company's growth strategy.

The following table summarizes the drill, complete and tie-in activities for the periods:

  Three Months Ended December 31, 2011, Years Ended December 31, 2011,
    Gross   Net   Gross   Net
Drilled       34.0       27.7       89.0   72.7
Completed       34.0       26.9       83.0   69.6
Tied-in       20.0       16.4       76.0   65.9

Corporate Acquisition

On July 12, 2011, the Company acquired all of the issued and outstanding shares of Cinch Energy Corp. in exchange for Tourmaline common shares. The acquisition resulted in an increase to Property, Plant and Equipment ("PP&E") of approximately $182.8 million and an increase to Exploration and Evaluation ("E&E") assets of $87.1 million.  The acquisition of Cinch provides for an increase in lands and production in two of Tourmaline's key highly profitable core and designated growth areas of Dawson in NEBC and Musreau-Kakwa in the Alberta Deep Basin.

The Company's 2012 capital program is budgeted at $375 million and will be focused on liquids-rich gas and oil opportunities that are the most economic in the current depressed natural gas price environment.

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2011, Tourmaline had negative working capital of $146.6 million, after adjusting for the fair value of financial instruments (the unadjusted working capital deficiency was $146.3 million).  Management believes the Company has sufficient liquidity and capital resources to fund its 2012 exploration and development program through expected cash flow from operations and its unutilized bank credit facilities.

On March 8, 2011, Tourmaline issued 1.58 million common shares on a flow-through basis at a price of $30 per share for gross proceeds of approximately $47.4 million and net proceeds of 45.6 million.  On May 17, 2011, Tourmaline issued 6.8 million common shares at $25.50 per share for gross proceeds of approximately $174.0 million, with net proceeds of approximately $166.5 million.  In October 2011, the Company issued 4.9 million common shares at $33 per share for gross proceeds of $161.7 million, with net proceeds of $155.3 million. In December 2011, the Company also issued 1.4 million common shares on a flow-through basis for gross proceeds of $55.8 million. The proceeds of the above noted financings were used to temporarily reduce bank debt and to fund the Company's 2011 exploration and development program.

On September 8, 2011, the Company increased its credit facility for an extendible revolving term loan to $350 million from $275 million with three Canadian chartered banks, in addition to its existing $25 million operating line.  The facility bears interest on a variable grid currently 250 basis points over the prevailing banker's acceptance rate.  Security for the facility includes a general security agreement and a $500 million demand loan debenture secured by a first floating charge over all assets.  On July 31, 2012, at the Company's discretion, the facility is available on a non-revolving basis for a period of 365 days, at which time the facility would be due and payable.  Alternatively, the facility may be extended for a further 364-day period at the request of the Company and subject to approval by the banks.

A subsidiary of the Company also has a financing arrangement with a Canadian chartered bank for an extendible revolving term loan in the amount of $5 million in addition to a $5 million operating line.  The interest rate charged varies based on the amount outstanding.  Security for the facility includes a general security agreement and a demand loan debenture secured by a first floating charge over all of the subsidiary's assets.  The revolving term credit facility has a 364-day extendible period plus a one-year maturity.

The Company is required to meet certain financial-based covenants to maintain the facilities.  The financial covenants include a requirement to ensure the total amount drawn on the facility does not exceed the total borrowing base as defined in each facility's agreement, and that the ratio of earnings adjusted for interest, taxes and other non-cash items to interest expense does not exceed a predetermined amount, as determined by each facility's agreement.  As at December 31, 2011, the Company was in compliance with these covenants.

As at December 31, 2011, the Company had $81.7 million drawn on existing facilities (December 31, 2010 - nil), and net debt of $228.3 million (December 31, 2010 - $49.2 million).

SHARES OUTSTANDING

As at March 19, 2012, the Company has 158,632,586 common shares outstanding and 14,208,523 share options granted and outstanding.

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

In the normal course of business, Tourmaline is obligated to make future payments.  These obligations represent contracts and other commitments that are known and non-cancellable.

Payments Due by Year
(000s)
 
2012
 
2013
 
2014
 
2015
  2016 and
thereafter
 
Total
Operating leases $ 2,587 $ 2,266 $ 2,121 $ 526 $ - $ 7,500
Flow-through obligations       54,777       -       -       -       -   54,777
Firm transportation agreements       26,415       25,394       16,880       8,067       375   77,131
Bank debt(1)       84,389       -       -       -       -   84,389
  $ 168,168 $ 27,660 $ 19,001 $ 8,593 $ 375 $ 223,797

(1) Includes interest expense at 3.23% being the rate applicable at December 31, 2011.

FINANCIAL RISK MANAGEMENT

The Board of Directors has overall responsibility for the establishment and oversight of the Company's risk management framework.  The Board has implemented and monitors compliance with risk management policies.

The Company's risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company's activities. The Company's financial risks are discussed in detail in note 5 of the Company's audited consolidated financial statements for the year ended December 31, 2011.

(a) Credit risk:

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Company's receivables from joint venture partners and petroleum and natural gas marketers.  The Company monitors the age of and investigates issues relating to its receivables that have been past due for over 90 days.  At December 31, 2011, the Company had $0.6 million (December 31, 2010 - $1.0 million) over 90 days.  The Company is satisfied that these amounts are substantially collectible.

(b) Liquidity risk:

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they come due.  Liquidity is required to fund capital requirements as well as satisfy financial obligations as they become due.  The Company's approach to managing liquidity is to ensure that it will have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions without incurring unacceptable losses or risking harm to the Company's reputation.  The Company relies on operating cash flows and available undrawn balances on the bank credit facilities.

The Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary.  Further, the Company utilizes authorizations for expenditures on both operated and non-operated projects to further manage capital expenditures.  The Company also attempts to match its payment cycle with the collection of petroleum and natural gas revenues on the 25th of each month.

(c) Market risk:

Market risk is the risk that changes in market conditions, such as commodity prices, interest rates or foreign exchange rates will affect the Company's net income or value of financial instruments.  The objective of market risk management is to manage and curtail market risk exposure within acceptable limits, while maximizing the Company's returns.

The Company utilizes both financial derivatives and physical delivery sales contracts to manage market risks.  All such transactions are conducted in accordance with the risk management policy that has been approved by the Board of Directors.

Currency risk has minimal impact on the value of the financial assets and liabilities on the statement of financial position at December 31, 2011.  Changes in the US to Canadian exchange rate, however, could influence future petroleum and natural gas prices which could impact the value of certain derivative contracts.  This influence cannot be accurately quantified.

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates.  The Company is exposed to interest rate risk to the extent that changes in market interest rates will impact the Company's bank debt which is subject to a floating interest rate. As at December 31, 2011, the Company had entered into one interest rate swap.

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices.  As at December 31, 2011, the Company has entered into certain financial derivative and physical delivery sales contracts in order to manage commodity risk.  These instruments are not used for trading or speculative purposes.  The Company has not designated its financial derivative contracts as effective accounting hedges, even though the Company considers all commodity contracts to be effective economic hedges.  As a result, all such financially-settled commodity contracts are recorded on the consolidated statement of financial position at fair value, with changes in the fair value being recognized as an unrealized gain or loss on the consolidated statement of income and comprehensive income.

The following table provides a summary of the unrealized gains and losses on financial instruments for the year ended December 31, 2011:

  Three Months Ended December 31, Years Ended December 31,
(000s)   2011       2010   2011   2010
Unrealized gain/(loss) on financial instruments     $ (4,566)     $     (879)     $ 944 $ (863)
Unrealized gain/(loss) on investments held for trading       40           187       (111)   260
Total     $ (4,526)     $     (692)     $ 833 $ (603)

In addition to the financial commodity contracts discussed above, the Company has entered into physical contracts to manage commodity risk.  These contracts are considered normal sales contracts and are not recorded at fair value in the consolidated financial statements.  These contracts have been disclosed in note 5 of the Company's consolidated financial statements for the years ended December 31, 2011 and December 31, 2010.

(d) Capital management:

The Company's policy is to maintain a strong capital base to maintain investor, creditor and market confidence and to sustain the future development of the business.  The Company considers its capital structure to include shareholders' equity, bank debt and working capital.  In order to maintain or adjust the capital structure, the Company may from time to time issue shares and adjust its capital spending to manage current and projected debt levels.  The annual and updated budgets are approved by the Board of Directors.

The key measures that the Company utilizes in evaluating its capital structure are net debt, which is defined as long-term bank debt plus working capital (adjusted for the fair value of financial instruments), to annualized funds from operations, defined as cash flow from operating activities before changes in non-cash working capital, and the current credit available from its creditors in relation to the Company's budgeted capital program.  Net debt to annualized funds from operations represents a measure of the time it is expected to take to pay off the debt if no further capital expenditures were incurred and if funds from operations in the next year were equal to the amount in the most recent quarter annualized.

The Company monitors this ratio and endeavors to maintain it at or below 2.0 to 1.0 in a normalized commodity price environment. This ratio may increase at certain times as a result of acquisitions or low commodity prices. As shown below, as at December 31, 2011, the Company's ratio of net debt to annualized funds from operations was 0.78 to 1.0.

(000s) As at
December 31, 2011
As at
December 31, 2010
Net debt:                
  Bank debt     $ (81,749)     $ -
  Working capital/(deficit)       (146,317)       (49,642)
  Fair value of financial instruments - short-term (asset)/liability       (276)       472
Net debt     $ (228,342)     $ (49,170)
Annualized funds from operations                
  Cash flow from operating activities for Q4     $ 61,801     $ 46,109
  Change in non-cash working capital       11,510       (1,169)
  Funds from operations for Q4     $ 73,311     $ 44,940
Annualized funds from operations (based on most recent quarter annualized):     $ 293,244     $ 179,760
Net debt to annualized funds from operations       0.78       0.27

The Company has not paid or declared any dividends since the date of incorporation, nor are any contemplated in the foreseeable future.  There were no changes in the Company's approach to capital management since December 31, 2010.

APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Management reviews its estimates on a regular basis. The emergence of new information and changed circumstances may result in actual results or changes to estimates that differ materially from current estimates.  The Company's use of estimates and judgments in preparing the consolidated financial statements is discussed in note 2 of the consolidated financial statements for the years ended December 31, 2011 and December 31, 2010.

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING

The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures ("DC&P") to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's Chief Executive Officer and Chief Financial Officer by others, particularly during the periods in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. All control systems by their nature have inherent limitations and, therefore, the Company's DC&P are believed to provide reasonable, but not absolute, assurance that the objectives of the control systems are met.

The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal controls over financial reporting ("ICFR") to provide reasonable assurance regarding the reliability of the Company's financial reporting and the preparation of financial statements for external purposes in accordance with IFRS.

The Company's Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company's DC&P and ICFR as defined by National Instrument 52-109 - Certification of Disclosure in Issuers' Annual and Interim Filings. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as at December 31, 2011, the Company's DC&P and ICFR are effective. There were no changes in the Company's ICFR during the period beginning on October 1, 2011 and ended December 31, 2011 that have materially affected, or are reasonably likely to materially affect, the Company's ICFR. It should be noted that a control system, including the Company's disclosure and internal controls and procedures, no matter how well conceived can provide only reasonable, but not absolute assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

BUSINESS RISKS AND UNCERTAINTIES

Tourmaline monitors and complies with current government regulations that affect its activities, although operations may be adversely affected by changes in government policy, regulations or taxation. In addition, Tourmaline maintains a level of liability, property and business interruption insurance which is believed to be adequate for Tourmaline's size and activities, but is unable to obtain insurance to cover all risks within the business or in amounts to cover all possible claims.

See "Forward-Looking Statements" in this MD&A and "Risk Factors" in Tourmaline's most recent annual information form for additional information regarding the risks to which Tourmaline and its business and operations are subject.

IMPACT OF NEW ENVIRONMENTAL REGULATIONS

Environmental legislation, including the Kyoto Accord, the federal government's "EcoACTION" plan and Alberta's Bill 3 - Climate Change and Emissions Management Amendment Act, is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. Given the evolving nature of the debate related to climate change and the resulting requirements, it is not possible to determine the operational or financial impact of those requirements on Tourmaline.

INTERNATIONAL FINANCIAL REPORTING STANDARDS ("IFRS")

The Company's IFRS accounting policies are provided in note 2 of the December 31, 2011 consolidated financial statements.  In addition, note 24 to the December 31, 2011 consolidated financial statements presents reconciliations between the Company's 2010 results reported under previous Canadian generally accepted accounting principles ("GAAP") and its 2010 results reported under IFRS.  The reconciliations in the December 31, 2011 consolidated financial statements include the consolidated statement of financial position as at January 1, 2010 and December 31, 2010, and consolidated statements of income and comprehensive income for the year ended December 31, 2010.

The following provides summary reconciliations of Tourmaline's 2010 previous GAAP and IFRS results, along with a discussion of the significant IFRS accounting policy changes.

SUMMARY STATEMENT OF FINANCIAL POSITION RECONCILIATIONS

As at January 1, 2010

($000s)
Previous
GAAP

E&E
Decommissioning
Obligations
Share-Based
Payments

Other (1)

IFRS
Current assets             248,452             -             -             -             (204)             248,248
Investments             632             -             -             -             -             632
Exploration and evaluation assets             -             250,972             -             -             -             250,972
Property, plant and equipment             754,798             (250,972)             -             -             -             503,826
Deferred taxes             -             -             -             -             138             138
Total assets             1,003,882             -             -             -             (66)             1,003,816
                          
Current liabilities             86,938             -             -             -             -             86,938
Decommissioning obligations             7,208             -             11,945             -             -             19,153
Deferred premium on flow-through shares             -             -             -             -             3,833             3,833
Deferred taxes             780             -             -             -             (780)             -
Share capital             895,095             -             -             -             (4,143)             890,952
Non-controlling interest             13,526             -             -             -             -             13,526
Contributed surplus             2,018             -             -             6,529             -             8,547
Retained earnings/(deficit)             (1,683)             -             (11,945)             (6,529)             1,024             (19,133)
Total liabilities and shareholders' equity             1,003,882             -             -             -             (66)             1,003,816
(1) Other includes adjustments for share issue costs, the deferred premium on flow-through shares, the impact of the fact that Tourmaline's forward gas sales contracts no longer meet the definition of a derivative and the deferred tax impact related thereto.
   

As at December 31, 2010
($000s) Previous
GAAP

E&E
Depletion Decommissioning
Obligations
Share-Based
Payments

Other (1)

IFRS
Current assets 143,356 - - - - (14,413) 128,943
Investments 3,932 - - - - - 3,932
Fair value of financial instruments 1,601 - - - - (1,601) -
Exploration and evaluation assets - 479,067 - - - - 479,067
Property, plant and equipment 1,637,960 (479,067) 29,184 9,844 6,531 (351) 1,204,101
Total assets 1,786,849 - 29,184 9,844 6,531 (16,365) 1,816,043
               
Current liabilities 180,945 - - - - (2,360) 178,585
Decommissioning obligations 13,628 - - 21,776 - (125) 35,279
Long-term obligation 14,589 - - - - - 14,589
Fair value of financial instruments - - - - - 270 270
Deferred premium on flow-through shares - - - - - 348 348
Deferred taxes 25,457 - - - (964) 21,576 46,069
Share capital 1,517,675 - - - (128) (9,495) 1,508,052
Non-controlling interest 13,767 - - - - 142 13,909
Contributed surplus 7,919 - - - 21,343 - 29,262
Retained earnings/(deficit) 12,869 - 29,184 (11,932) (13,720) (26,721) (10,320)
Total liabilities and shareholders' equity 1,786,849 - 29,184 9,844 6,531 (16,365) 1,816,043
(1) Other includes adjustments for share issue costs, the deferred premium on flow-through shares, the impact of the fact that Tourmaline's forward gas sales contracts no longer meet the definition of a derivative, gains and losses on divestitures and the deferred tax impact related thereto.
   

SUMMARY NET EARNINGS RECONCILIATION

2010                    
($000s)   Annual   Q4   Q3   Q2   Q1
Net earnings/(loss) - previous GAAP   14,552   (2,593)   4,463   (672)   13,354
After-tax addition/(deduction):                    
  Unrealized gain/(loss) on financial instruments   (16,553)   4,995   (7,410)   3,676   (17,814)
  General and administrative   (1,561)   (749)   (478)   (90)   (244)
  Share-based payments   (7,191)   (2,324)   (1,855)   (1,702)   (1,310)
  Depletion and depreciation   29,184   12,108   4,791   6,262   6,023
  Decommissioning obligation accretion   13   10   13   (8)   (2)
  Gain/(loss) on divestitures   2,082   1,606   3,534   (3,058)   -
  Deferred taxes   (11,010)   (7,135)   (2,662)   (2,620)   1,407
  Transaction costs on corporate acquisition   (561)   -   -   -   (561)
  Non-controlling interest   (142)   (53)   32   (88)   (33)
Net earnings - IFRS   8,813   5,865   428   1,700   820

Accounting Policy Changes and the Impact of Transition to IFRS

  • Exploration and Evaluation ("E&E") assets - On transition to IFRS Tourmaline reclassified $251.0 million of PP&E assets to E&E assets on the consolidated statement of financial position.  This consisted of the book value of undeveloped land that relates to exploration properties, geological and geophysical costs and drilling and completion costs of wells in progress.  E&E assets are not depleted and must be assessed for impairment at the transition date and when indicators of impairment exist.  There was no transitional impairment of the E&E assets.  The cost of any impairment recognized during a period, is charged as additional depletion and depreciation expense.

  • Property, plant and equipment ("PP&E") - This includes oil and gas assets in the development and production phases. The Company has allocated the amount recognized under the previous GAAP as at January 1, 2010 to cash-generating units ("CGU") using reserve values.

  • Divestitures - Under previous GAAP, proceeds from divestitures were deducted from the full cost pool without recognition of a gain or loss unless the deduction resulted in a change in the depletion rate of 20 percent or greater, in which case a gain or loss was recorded.  Under IFRS, gains and losses are recorded on divestitures and are calculated as the difference between the proceeds and the net book value of the asset disposed. For the year ended December 31, 2010, Tourmaline recognized a $2.1 million net gain on divestitures under IFRS compared to nil under the previous GAAP.

  • Impairment of PP&E assets - Under IFRS, impairment tests of PP&E must be performed at the CGU level as opposed to the entire PP&E balance which was required under the previous GAAP through the full cost ceiling test.  An impairment is recognized if the carrying value exceeds the recoverable amount for a CGU. The recoverable amount is determined using fair value less costs to sell based on discounted future cash flow of proved plus probable reserves using forecast prices and costs.  PP&E impairments can be reversed in the future if the recoverable amount increases.

    Tourmaline performed and passed its impairment tests on its PP&E assets on transition to IFRS at January 1, 2010 as well as for the year ended December 31, 2010.

  • Decommissioning Obligations - Under the previous GAAP, a credit adjusted risk free rate was used to measure the obligation.  Under IFRS, Tourmaline has used a risk free rate given the expected cash flow is risked.  The result of using a lower discount rate was an increase to the obligation on transition of $11.9 million with an offsetting charge to the opening deficit, net of the deferred income tax effect of $3.0 million.

  • Depletion and depreciation expense - Under IFRS, Tourmaline has chosen to base the depletion calculation using proved-plus-probable reserves.  This resulted in a decrease to depletion and depreciation expense in 2010 as compared to the previous GAAP.

  • Share-based compensation - The major differences from the previous GAAP are the treatment of graded vesting awards as multiple separate awards with different lives, an adjustment to the measure of volatility used in the calculation to value those options that were issued while the Company was private and estimating forfeiture rates in advance as opposed to recognizing the impact when the forfeiture occurs.

RECENT PRONOUNCEMENTS ISSUED

The following pronouncements from the International Accounting Standards Board ("IASB") will become effective for financial reporting periods beginning on or after January 1, 2013 and have not yet been adopted by the Company. All of these new or revised standards permit early adoption with transitional arrangements depending upon the date of initial application.

IFRS 9 - Financial Instruments addresses the classification and measurement of financial assets.

IFRS 10 - Consolidated Financial Statements builds on existing principles and standards and identifies the concept of control as the determining factor in whether an entity should be included within the consolidated financial statements of the parent company.

IFRS 11 - Joint Arrangements establishes the principles for financial reporting by entities when they have an interest in arrangements that are jointly controlled.

IFRS 12 - Disclosure of Interest in Other Entities provides the disclosure requirements for interests held in other entities including joint arrangements, associates, special purpose entities and other off balance sheet entities.

IFRS 13 - Fair Value Measurement defines fair value, requires disclosure about fair value measurements and provides a framework for measuring fair value when it is required or permitted within the IFRS standards.

IAS 19 - Employee Benefits revises the existing standard to eliminate options to defer the recognition of gains and losses in defined benefit plans, requires re-measurements of a defined benefit plan's assets and liabilities to be presented in other comprehensive income and increases disclosure.

IAS 27 - Separate Financial Statements revised the existing standard which addresses the presentation of parent company financial statements that are not consolidated financial statements.

IAS 28 - Investments in Associate and Joint Ventures revised the existing standard and prescribes the accounting for investments and sets out the requirements for the application of the equity method when accounting for investments in associates and joint ventures.

The IASB also issued Presentation of Items of Other Comprehensive Income, an amendment to IAS 1 Financial Statement Presentation. The amendment addresses the presentation of other comprehensive income and requires the grouping of items within other comprehensive income that might eventually be reclassified to the profit and loss section of the income statement. The change becomes effective for financial years after July 1, 2012 with earlier adoption permitted.

The Company has not completed its evaluation of the effect of adopting these standards on its financial statements.

NON-IFRS FINANCIAL MEASURES

This MD&A includes references to financial measures commonly used in the oil and gas industry such as "funds from operations", "operating netback", "working capital (adjusted for the fair value of financial instruments)" and "net debt", which do not have any standardized meaning prescribed by IFRS.  Management believes that in addition to net income and cash flow from operating activities; funds from operations, operating netback, net debt and working capital (adjusted for the fair value of financial instruments) are useful supplemental measures in assessing Tourmaline's ability to generate the cash necessary to repay debt or fund future growth through capital investment.  Readers are cautioned, however, that these measures should not be construed as an alternative to net income or cash flow from operating activities determined in accordance with IFRS as an indication of Tourmaline's performance.  Tourmaline's method of calculating these measures may differ from other companies and accordingly, they may not be comparable to measures used by other companies.  For these purposes, Tourmaline defines funds from operations as cash provided by operations before changes in non-cash operating working capital, defines operating netback as revenue (excluding processing income) less royalties, transportation costs and operating expenses and defines working capital (adjusted for the fair value of financial instruments) as working capital adjusted for the fair value of financial instruments.  Net debt is defined as long-term bank debt plus working capital (adjusted for the fair value of financial instruments).

Funds from Operations

A summary of the reconciliation of funds from operations to cash flow from operating activities is set forth below:

  Three Months Ended December 31, Years Ended December 31,
(000s)   2011       2010   2011   2010
Cash flow from operating activities (per IFRS)     $ 61,801     $     46,109     $ 228,421     $ 143,296
Change in non-cash working capital       11,510           (1,169)       12,931       (10,078)
Funds from operations     $ 73,311     $     44,940     $ 241,352     $ 133,218

Operating Netback

Operating netback is calculated on a per-Boe basis and is defined as revenue (excluding processing income) less royalties, transportation costs and operating expenses, as shown below:

  Three Months Ended December 31, Years Ended December 31,
($/Boe)   2011   2010   2011   2010
Revenue, excluding processing fee income $ 30.95 $ 30.74 $ 32.07 $ 32.24
Royalties   (2.15)   (0.77)   (2.08)   (2.40)
Transportation costs   (2.24)   (1.80)   (2.06)   (1.74)
Operating expenses   (5.17)   (5.51)   (5.58)   (6.34)
Operating netback $ 21.39 $ 22.66 $ 22.35 $ 21.76

Working Capital (Adjusted for the Fair Value of Financial Instruments)

A summary of the reconciliation of working capital to working capital (adjusted for the fair value of financial instruments) is set forth below:

(000s)   As at
December 31, 2011
  As at
December 31, 2010
Working capital/(deficit)     $ (146,317)     $ (49,642)
Fair value of financial instruments - short-term (asset)/liability       (276)       472
Working capital/(deficit) (adjusted for the fair value of financial instruments)     $ (146,593)     $ (49,170)

Net Debt

A summary of the reconciliation of net debt is set forth below:

(000s)   As at
December 31, 2011
  As at
December 31, 2010
Bank debt     $ (81,749)     $ -
Working capital/(deficit)       (146,317)       (49,642)
Fair value of financial instruments - short-term (asset)/liability       (276)       472
Net debt     $ (228,342)     $ (49,170)
         

SELECTED QUARTERLY INFORMATION

  2011   2010
($000s, unless otherwise noted) Q4 Q3 Q2 Q1   Q4 Q3 Q2 Q1
PRODUCTION                  
Crude oil and NGL(bbls)             415,074             316,890             272,184             217,121               236,502             147,997             178,787             138,068
Gas (mcf)             18,437,079             17,058,132             13,798,653             11,283,617         11,251,067             9,502,337             8,693,492             5,449,027
Oil equivalent (Boe)             3,487,920             3,159,912             2,571,959             2,097,724               2,111,680             1,731,720             1,627,702             1,046,239
Crude oil and NGL (bbls/d)             4,512             3,444             2,991             2,412               2,571             1,609             1,965             1,534
Gas (mcf/d)             200,403             185,414             151,634             125,374               122,294             103,286             95,533             60,545
Oil equivalent (Boe/d)             37,912             34,347             28,263             23,308               22,953             18,823             17,887             11,625
FINANCIAL                  
Gross revenue, net of royalties             98,309             98,225             87,551             62,019               63,340             46,822             50,310             34,935
Cash flow from operating activities             61,801             77,622             42,112             46,886               46,109             40,685             34,623             21,879
Funds from operations (1)             73,311             62,686             60,415             44,940               44,940             31,250             33,925             23,103
Per diluted share             0.45             0.40             0.41             0.32               0.34             0.25 0.27             0.21
Net earnings/(loss)             16,074             8,688             15,192             2,727               5,865             428             1,700             820
Per diluted share             0.10             0.06             0.10             0.02               0.04             0.00 0.01             0.01
Total assets             2,711,024             2,517,607             2,030,285             1,936,836               1,816,043             1,546,820 1,412,776             1,366,481
Working capital             (146,317)             (120,080)             (31,963)             (139,138)               (49,642)             (78,205) (21,672) 234,339
Working capital (adjusted for the fair
value of financial instruments) (1)
            (146,593)             (123,858)             (31,592)             (136,933)               (49,170)             (78,314) (22,075)             234,362
Capital expenditures             232,167             249,162             130,075             217,553               217,064             151,944             286,808 158,518
Basic outstanding shares (000s)             158,578             151,906             145,215             138,124               136,191             123,841             122,691             120,191
PER UNIT                  
Gas ($/mcf)             3.76             4.25             4.38             4.48               4.17             4.36 4.61             5.41
Crude oil and NGL ($/bbl)             93.05             87.01             95.54             83.00               75.94             70.49 72.49             78.29
Revenue ($/Boe)             30.95             31.67             33.61             32.68               30.74             29.94 32.58             38.53
Operating netback ($/Boe)             21.39             21.21             24.52             22.99               22.66             19.12 21.82             24.16
(1) See Non-IFRS Financial Measures                  
               

The oil and gas exploration and production industry is cyclical in nature. The Company's financial position, results of operations and cash flows are principally impacted by production levels, and commodity prices, particularly natural gas prices. The Company has had continued growth over the last eight quarters summarized in the table above.  The Company's average production has increased from 17,856 Boe per day in 2010 to 31,007 Boe per day in 2011, with cash flows from operating activities increasing from $143.3 million in 2010 to $228.4 million in 2011.  The production growth can be attributed to both the Company's exploration and development activities, as well as, from acquisitions of producing properties.  Over the same period, natural gas prices have declined.  Commodity price changes can indirectly impact expected production by changing the amount of funds available to reinvest in exploration, development and acquisition activities in the future.  Decreases in commodity prices not only reduce revenues and cash flows available for exploration, they may also challenge the economics of potential capital projects by reducing the quantities of reserves that are commercially recoverable.

The Company's capital program is dependent on cash flows generated from operations and access to capital markets.

SELECTED ANNUAL INFORMATION

      Previous GAAP(2)
($000s unless otherwise noted) 2011 2010 2009
PRODUCTION      
Crude oil and NGL (bbls) 1,221,268 701,355 119,347
Gas (mcf) 60,577,481 34,895,923 6,850,937
Oil equivalent (Boe) 11,317,515 6,517,342 1,261,170
Crude oil and NGL (bbls/d) 3,346 1,922 327
Gas (mcf/d) 165,966 95,605 18,770
Oil equivalent (Boe/d) 31,007 17,856 3,455
FINANCIAL      
Gross revenue, net of royalties 346,104 195,407 35,127
Cash flow from operating activities 228,421 143,296 (514)
Funds from operations (1) 241,352 133,218 21,722
Per diluted share 1.58 1.08 0.31
Net earnings/(loss) 42,681 8,813 (2,121)
Per diluted share 0.28 0.07             (0.03)
Total assets 2,711,024 1,816,043 1,003,882
Working capital (146,317) (49,642) 161,514
Working capital (adjusted for the fair value of financial instruments) (1) (146,593) (49,170) 161,190
Capital expenditures 828,956 814,334 499,258
Basic outstanding shares (000s) 158,578 136,191 101,809
PER UNIT      
Gas ($/mcf) 4.17 4.52 4.24
Crude oil and NGL ($/bbl) 90.24 74.62 66.10
Revenue ($/Boe) 32.07 32.24 29.28
Operating netback ($/Boe) 22.35 21.76 17.58
(1)See Non-IFRS Financial Measures.
(2)As Tourmaline's IFRS transition date was January 1, 2010, the 2009 comparative information has not been restated.
 

The changes to the financial information summarized above are due primarily to the continuing growth in the Company's crude oil, natural gas and NGL production over the periods, from the acquisition of producing properties and from the Company's exploration and development activities.

CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(000s) December 31, 2011 December 31, 2010 January 1, 2010
Assets       (Note 24)   (Note 24)
Current assets:            
  Cash and cash equivalents $             - $             65,160 $             199,789
  Accounts receivable                   60,799                   58,669               45,129
  Prepaid expenses and deposits                   5,313                   5,114               3,210
  Fair value of financial instruments (note 4)                   276                   -               120
                    66,388                   128,943               248,248
Investments (note 10)                   233                   3,932               632
Exploration and evaluation assets (note 6)                   620,515                   479,067               250,972
Property, plant and equipment (note 7)                   2,023,888                   1,204,101               503,826
Deferred taxes (note 14)                   -                   -               138
  $             2,711,024 $             1,816,043 $             1,003,816
Liabilities and Shareholders' Equity                                 
Current liabilities:                                 
  Accounts payable and accrued liabilities $             212,705 $             178,113 $             86,938
  Fair value of financial instruments (note 4)               -               472               -
                    212,705                   178,585               86,938
Bank debt (note 9)                   81,749                   -               -
Decommissioning obligations (note 8)                   50,463                   35,279               19,153
Long-term obligation (note 11)                   10,864                   14,589               -
Fair value of financial instruments (note 4)                   74                   270               -
Deferred premium on flow-through shares (note 13)                   11,316                   348               3,833
Deferred taxes (note 14)                   107,977                   46,069               -
Shareholders' equity:                                 
  Share capital (note 13)                   2,140,660                   1,508,052               890,952
  Non-controlling interest (note 12)                   15,079                   13,909               13,526
  Contributed surplus                   47,776                   29,262               8,547
  Retained earnings/(deficit)                   32,361                   (10,320)               (19,133)
                    2,235,876                   1,540,903               893,892
  $             2,711,024 $             1,816,043 $             1,003,816
Commitments (note 21)
Subsequent events (notes 5 and 23)
See accompanying notes to the consolidated financial statements. 
 

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

  Years Ended December 31,
(000s) except per-share amounts 2011 2010
Revenue:       (Note 24)
  Oil and natural gas sales $             342,820 $             194,928
  Royalties                   (23,553)                   (15,630)
                    319,267                   179,298
  Realized gain on financial instruments                   20,172                   15,177
  Unrealized gain/(loss) on financial instruments (note 5)                   833                   (603)
  Other income (note 17)                   5,832                   1,535
                    346,104                   195,407
Expenses:                
  Operating               63,129                   41,352
  Transportation                   23,384                   11,357
  General and administration                   11,494                   8,392
  Share-based payments               11,685                   10,388
  (Gain)/loss on divestitures               3,630                   (2,082)
  Depletion, depreciation and amortization                   158,168                   96,660
                    271,490                   166,067
Results from Operating Activities                   74,614                   29,340
Finance expenses (note 18)                   6,180                   2,774
Income before taxes                   68,434                   26,566
  Deferred taxes (note 14)                   24,583                   17,370
Net income and comprehensive income for the year
before non-controlling interest
                  43,851                   9,196
Net income and comprehensive income attributable to:                
  Shareholders of the Company                   42,681                   8,813
  Non-controlling interest (note 12)                   1,170                   383
  $             43,851 $             9,196
         
Income per share attributable to common shareholders (note 15)                
  Basic $                 0.29 $             0.07
  Diluted $                 0.28 $             0.07
See accompanying notes to the consolidated financial statements.  
   

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(000s) except per-share amounts                
    Share
Capital
  Contributed
Surplus
  Retained
Earnings/(Deficit)
  Non-Controlling
Interest
 
Total Equity
Balance at January 1, 2010 $             890,952 $             8,547 $             (19,133) $ 13,526 $             893,892
Issue of common shares (note 13)                   636,727                   -               -               -               636,727
Share issue costs, net of tax                   (19,848)                   -               -               -               (19,848)
Share-based payments                   -                   10,388               -               -               10,388
Capitalized share-based payments                   -                   10,388               -               -               10,388
Options exercised (note 13)                   221                   (61)               -               -               160
Income attributable to common shareholders                   -                   -               8,813         -               8,813
Income attributable to non-controlling interest                   -                   -               -   383         383
Balance at December 31, 2010                   1,508,052                   29,262               (10,320)   13,909         1,540,903
Issue of common shares (note 13)               629,809                   -               -               -               629,809
Share issue costs, net of tax               (14,589)                   -               -               -               (14,589)
Share-based payments               -                   11,685               -               -               11,685
Capitalized share-based payments       -                   11,685   -               -               11,685
Options exercised (note 13)     -             17,388                   (4,856)               -               -               12,532
Income attributable to common shareholders                   -                   -               42,681               -               42,681
Income attributable to non-controlling interest                   -                   -               -               1,170               1,170
Balance at December 31, 2011 $             2,140,660 $             47,776 $             32,361 $             15,079 $             2,235,876
See accompanying notes to the consolidated financial statements.              
             

CONSOLIDATED STATEMENTS OF CASH FLOW

  Years Ended December 31,
(000s) 2011 2010
Cash provided by (used in):        
Operations:        
  Net income $             42,681 $             8,813
  Items not involving cash:                    
    Depletion, depreciation and amortization                       158,168                   96,660
    Accretion                       1,315                   1,128
    Share-based payments                       11,685                   10,388
    Deferred taxes                       24,583                   17,370
    Unrealized (gain)/loss on financial instruments
(note 4)
                      (833)                   603
    (Gain)/Loss on divestitures                       3,630                   (2,082)
    Non-controlling interest                       1,170                   383
  Realized (gain)/loss on sale of investments                   -                   (45)
  Decommissioning expenditures                   (1,047)                   -
  Changes in non-cash operating working capital (note 20)                   (12,931)                   10,078
                    228,421                   143,296
Financing:                
  Issue of common shares               451,491                   508,730
  Share issue costs                   (19,329)                   (26,502)
  Increase/(decrease) in bank debt                   62,053                   (6,550)
                    494,215                   475,678
Investing:                
  Exploration and evaluation                   (213,414)                   (198,816)
  Property, plant and equipment                   (508,294)                   (293,775)
  Property acquisitions                   (115,231)                   (343,234)
  Proceeds from divestitures                   7,983                   24,647
  Corporate acquisitions                   -                   (3,156)
  Proceeds from sale of investments                   3,588                   255
  Repayment of long-term obligation                   (3,725)                   (1,552)
  Change in non-cash investing working capital (note 20)                   41,297                   62,028
                    (787,796)                   (753,603)
Changes in cash                   (65,160)                   (134,629)
Cash, beginning of year               65,160               199,789
Cash, end of year $             - $             65,160
Cash is defined as cash and cash equivalents.
See accompanying notes to the consolidated financial statements.
 
   

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2011 and 2010
(tabular amounts in thousands of dollars, unless otherwise noted)
______________________________________________________________________________________________________

Corporate Information:

Tourmaline Oil Corp. (the "Company") was incorporated under the laws of the Province of Alberta on July 21, 2008.  The Company is engaged in the acquisition, exploration, development and production of petroleum and natural gas properties.  The Company is engaged in the exploration for, and development and production of, oil and natural gas and conducts many of its activities jointly with others. These consolidated financial statements reflect only the Company's proportionate interest in such activities.

The Company's registered office is located at 3700, 250 - 6th Avenue S.W., Calgary, Alberta, Canada T2P 3H7.

1. BASIS OF PREPARATION

(a) Statement of compliance:

These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB").  In preparing these consolidated financial statements, IFRS 1 - "First-time Adoption of International Financial Reporting Standards" has been applied.

Tourmaline's significant accounting policies under IFRS are presented in note 2.  These policies have been retrospectively and consistently applied except where specific exemptions permitted an alternative treatment upon transition to IFRS in accordance with IFRS 1.  The impact of the new standards, including reconciliations presenting the change from previous GAAP to IFRS as at January 1, 2010, as at and for the year ended December 31, 2010, is presented in note 24.

The consolidated financial statements were authorized for issue by the Board of Directors on March 19, 2012.

(b) Basis of measurement:

The consolidated financial statements have been prepared on the historical-cost basis except for the following:

(i) derivative financial instruments are measured at fair value; and

(ii) held for trading financial assets are measured at fair value with changes in fair value recorded in earnings.

The methods used to measure fair values are discussed in note 4.

Operating expenses in the consolidated statements of income and comprehensive income are presented as a combination of function and nature in conformity with industry practice.  Depletion, depreciation and amortization are presented in separate lines by their nature, while operating expenses and net administrative expenses are presented on a functional basis.  Significant expenses such as salaries and benefits are presented by their nature in the notes to the financial statements.

(c) Functional and presentation currency:

These consolidated financial statements are presented in Canadian dollars, which is the Company's functional currency.

(d) Use of estimates and judgments:

The timely preparation of the financial statements requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the preparation of these financial statements are outlined below.

Critical judgments in applying accounting policies:

The following are the critical judgments, apart from those involving estimations (see below), that management has made in the process of applying the Company's accounting policies and that have the most significant effect on the amounts recognized in these consolidated financial statements:

(i) Reserves:

Estimation of reported recoverable quantities of proved and probable reserves include judgmental assumptions regarding production profile, commodity prices, exchange rates, remediation costs, timing and amount of future development costs, and production, transportation and marketing costs for future cash flows. It also requires interpretation of geological and geophysical models in anticipated recoveries. The economical, geological and technical factors used to estimate reserves may change from period to period. Changes in reported reserves can impact the carrying values of the Company's petroleum and natural gas properties and equipment, the calculation of depletion and depreciation, the provision for decommissioning obligations, and the recognition of deferred tax assets due to changes in expected future cash flows. The recoverable quantities of reserves and estimated cash flows from the Company's petroleum and natural gas interests are independently evaluated by reserve engineers at least annually.

The Company's petroleum and natural gas reserves represent the estimated quantities of petroleum, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be economically recoverable in future years from known reservoirs and which are considered commercially producible. Such reserves may be considered commercially producible if management has the intention of developing and producing them and such intention is based upon (i) a reasonable assessment of the future economics of such production; (ii) a reasonable expectation that there is a market for all or substantially all the expected petroleum and natural gas production; and (iii) evidence that the necessary production, transmission and transportation facilities are available or can be made available. Reserves may only be considered proven and probable if producibility is supported by either production or conclusive formation tests. The Company's petroleum and gas reserves are determined pursuant to National Instrument 51-101, Standard of Disclosures for Oil and Gas Activities.

(ii) Identification of cash-generating units:

The Company's assets are aggregated into cash-generating units ("CGU") for the purpose of calculating impairment.  A CGU is comprised of assets that are grouped together into the smallest group of assets that generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets. By their nature, these estimates and assumptions are subject to measurement uncertainty and may impact the carrying value of the Company's assets in future periods.

(iii) Share-based payments:

All equity-settled, share-based awards issued by the Company are recorded at fair value using the Black-Scholes option-pricing model. In assessing the fair value of equity-based compensation, estimates have to be made regarding the expected volatility in share price, option life, dividend yield, risk-free rate and estimated forfeitures at the initial grant date.

Key sources of estimation uncertainty:

The following are the key assumptions concerning the sources of estimation uncertainty at the end of the reporting period, that have a significant risk of causing adjustments to the carrying amounts of assets and liabilities.

(i) Decommissioning obligations:

The Company estimates future remediation costs of production facilities, wells and pipelines at different stages of development and construction of assets or facilities. In most instances, removal of assets occurs many years into the future. This requires judgment regarding abandonment date, future environmental and regulatory legislation, the extent of reclamation activities, the engineering methodology for estimating cost, future removal technologies in determining the removal cost and liability-specific discount rates to determine the present value of these cash flows.

(ii) Impairment of petroleum and natural gas assets:

For the purposes of determining whether impairment of petroleum and natural gas assets has occurred, and the extent of any impairment or its reversal, the key assumptions the Company uses in estimating future cash flows are forecast petroleum and natural gas prices, expected production volumes and anticipated recoverable quantities of proved and probable reserves. These assumptions are subject to change as new information becomes available. Changes in economic conditions can also affect the rate used to discount future cash flow estimates. Changes in the aforementioned assumptions could affect the carrying amounts of assets.  Impairment charges and reversals are recognized in profit or loss.

(iii) Income taxes:

Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts recognized in profit or loss both in the period of change, which would include any impact on cumulative provisions, and in future periods. Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse and a judgment as to whether or not there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets as well as the amounts recognized in profit or loss in the period in which the change occurs.

2. SIGNIFICANT ACCOUNTING POLICIES

The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements, and have been applied consistently by the Company and its subsidiaries.

Certain comparative amounts have been reclassified to conform with the current year's presentation per note 24.

(a) Consolidation:

The consolidated financial statements include the accounts of Tourmaline Oil Corp., Exshaw Oil Corp., of which the Company owns 90.6% (note 12), and Cinch Energy Corp., which is a wholly-owned subsidiary.

(i) Subsidiaries:

Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. In assessing control, potential voting rights that currently are exercisable are taken into account. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases.

The purchase method of accounting is used to account for acquisitions of subsidiaries and assets that meet the definition of a business under IFRS. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date.  If the cost of acquisition is less than the fair value of the net assets of the subsidiary acquired, the difference is recognized immediately in the income statement.

(ii) Jointly-controlled operations and jointly-controlled assets:

Substantially all of the Company's oil and natural gas activities involve jointly-controlled assets. The consolidated financial statements include the Company's share of these jointly-controlled assets and a proportionate share of the relevant revenue and related costs.

(iii) Transactions eliminated on consolidation:

Intercompany balances and transactions, and any unrealized income and expenses arising from intercompany transactions, are eliminated in preparing the consolidated financial statements.

(b) Financial instruments:

(i) Non-derivative financial instruments:

Non-derivative financial instruments comprise trade and other receivables, cash and cash equivalents, investments, bank overdrafts, loans and borrowings, and trade and other payables. Non-derivative financial instruments are recognized initially at fair value plus, for instruments not at fair value through profit or loss, any directly attributable transaction costs. Subsequent to initial recognition, non-derivative financial instruments are measured as described below:

Cash and cash equivalents:

Cash and cash equivalents comprise cash on hand, term deposits held with banks, other short-term highly-liquid investments with original maturities of three months or less.

Investments:

An instrument is classified at fair value through profit or loss if it is held for trading or is designated as such upon initial recognition.  Tourmaline's investments in public companies are designated as held for trading.  Financial instruments are designated at fair value through profit or loss if the Company manages such investments and makes purchase and sale decisions based on their fair value in accordance with the Company's risk management or investment strategy. Upon initial recognition, attributable transaction costs are recognized in profit or loss when incurred. Financial instruments at fair value through profit or loss are measured at fair value, and changes therein are recognized in profit or loss.

Other:

Other non-derivative financial instruments, such as trade and other receivables, loans and borrowings, and trade and other payables, are measured at amortized cost using the effective interest method, less any impairment losses.

(ii) Derivative financial instruments:

The Company has entered into certain financial derivative contracts in order to manage the exposure to market risks from fluctuations in commodity prices and interest rates. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, and thus not applied hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, all financial derivative contracts are classified as fair value through profit or loss and are recorded on the statement of financial position at fair value. Transaction costs are recognized in profit or loss when incurred.

The Company has accounted for its forward physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the statement of financial position. Settlements on these physical sales contracts are recognized in oil and natural gas revenue.

Embedded derivatives are separated from the host contract and accounted for separately if the economic characteristics and risks of the host contract and the embedded derivative are not closely related, a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative, and the combined instrument is not measured at fair value through earnings.  Changes in the fair value of separable embedded derivatives are recognized immediately in earnings.

(iii) Share capital:

Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares and share options are recognized as a deduction from equity, net of any tax effects.

(c) Property, plant and equipment and intangible exploration assets:

(i) Recognition and measurement:

Exploration and evaluation expenditures:

Pre-license costs are recognized in the statement of operations as incurred.

Exploration and evaluation costs, including the costs of acquiring licenses and directly attributable general and administrative costs, initially are capitalized as either tangible or intangible exploration and evaluation assets according to the nature of the assets acquired.  The costs are accumulated in cost centers by well, field or exploration area pending determination of technical feasibility and commercial viability.

Exploration and evaluation assets are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial viability, and (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount.  For purposes of impairment testing, exploration and evaluation assets are allocated to cash-generating units.

The technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable when proven and/or probable reserves are determined to exist.  A review of each exploration licence or field is carried out, at least annually, to ascertain whether proven or probable reserves have been discovered.  Upon determination of proven and/or probable reserves, intangible exploration and evaluation assets attributable to those reserves are first tested for impairment and then reclassified from exploration and evaluation assets to a separate category within tangible assets referred to as oil and natural gas interests.  The cost of undeveloped land that expires or any impairment recognized during a period is charged as additional depletion and depreciation expense.

Development and production costs:

Items of property, plant and equipment, which include oil and gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses. Development and production assets are grouped into CGUs for impairment testing.  The Company allocated its historical property, plant and equipment cost at January 1, 2010, the date of IFRS transition, to the following CGUs:  'Deep Basin', 'Spirit River' and 'Montney', based on a pro ration using December 31, 2009 externally-determined reserve values underlying each of its CGUs.  When significant parts of an item of property, plant and equipment, including oil and natural gas interests, have different useful lives, they are accounted for as separate items (major components).

Gains and losses on disposal of an item of property, plant and equipment, including oil and natural gas interests, are measured as the difference between the fair value of the proceeds received or given up and the carrying value of the assets disposed, and are recognized in profit or loss.

(ii) Subsequent costs:

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property, plant and equipment are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred.  Such capitalized oil and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred.

(iii) Depletion and depreciation:

The net carrying value of development or production assets is depleted using the unit-of-production method by reference to the ratio of production in the year to the related proved-plus-probable reserves, taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually.

Proved-plus-probable reserves are estimated annually by independent qualified reserve evaluators and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible.  For interim consolidated financial statements, internal estimates of changes in reserves and future development costs are used for determining depletion for the period.

For other assets, depreciation is recognized in profit or loss on a straight-line basis over the estimated useful lives of each part of an item of property, plant and equipment. Leased assets are depreciated over the shorter of the lease term and their useful lives unless it is reasonably certain that the Company will obtain ownership by the end of the lease term. Land is not depreciated.

The estimated useful lives for depreciable assets are as follows:

         
Plants and facilities       30 years
Office equipment       25% declining balance
Furniture and fixtures       25% declining balance

Depreciation methods, useful lives and residual values are reviewed at each reporting date.

(d) Impairment:

(i) Financial assets:

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.

An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate.

Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.

All impairment losses are recognized in profit or loss.

An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost, the reversal is recognized in profit or loss.

(ii) Non-financial assets:

The carrying amounts of the Company's non-financial assets, other than E&E assets and deferred tax assets, are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset's recoverable amount is estimated. For goodwill and other intangible assets that have indefinite lives, or that are not yet available for use, an impairment test is completed each year. E&E assets are assessed for impairment when they are reclassified to property, plant and equipment, as oil and natural gas interests, and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount.

For the purpose of impairment testing, assets are grouped into CGUs.  The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell.

In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset.  Value in use is generally computed by reference to the present value of the future cash flows expected to be derived from production of proven-plus-probable reserves.

The goodwill acquired in an acquisition, for the purpose of impairment testing, is allocated to the CGUs that are expected to benefit from the synergies of the combination.  E&E assets are allocated to the related CGUs when they are assessed for impairment, both at the time of triggering facts and circumstances as well as upon their eventual reclassification to property, plant and equipment.

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the other assets in the unit (group of units) on a pro-rata basis.  Impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized.

(e) Provisions:

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax "risk-free" rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses.

(i) Decommissioning obligations:

The Company recognizes the decommissioning obligations for the future costs associated with removal, site restoration and decommissioning costs.  The fair value of the liability for the Company's decommissioning obligation is recorded in the period in which it is incurred, discounted to its present value using the risk-free interest rate and the corresponding amount recognized by increasing the carrying amount of petroleum and natural gas assets.  The asset recorded is depleted on a unit-of-production basis over the life of the reserves.  The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period.  Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost could also result in an increase or decrease to the obligation.  Actual costs incurred upon settlement of the decommissioning obligation are charged against the obligation to the extent of the liability recorded.

(ii) Onerous contracts:

A provision for onerous contracts is recognized when the expected benefits to be derived by the Company from a contract are lower than the unavoidable cost of meeting its obligations under the contract. The provision is measured at the present value of the lower of the expected cost of terminating the contract and the expected net cost of continuing with the contract. Before a provision is established, the Company recognizes any impairment loss on associated assets.

(f) Revenue recognition:

Revenue from the sale of oil and natural gas is recorded when the significant risks and rewards of ownership of the product is transferred to the buyer, which is usually when legal title passes to the external party. This is generally at the time product enters the pipeline. Revenue is measured net of discounts, customs duties and royalties. With respect to the latter, the entity is acting as a collection agent on behalf of others.

Tariffs and tolls charged to other entities for use of pipelines and facilities owned by the Company are recognized as revenue as they accrue in accordance with the terms of the service or tariff and tolling agreements.

Royalty income is recognized as it accrues in accordance with the terms of the overriding royalty agreements.

(g) Finance income and expenses:

Finance expense comprises interest expense on borrowings, accretion of the discount on provisions, transaction costs on business combinations and impairment losses recognized on financial assets.

Interest income is recognized as it accrues in profit or loss, using the effective-interest method.

(h) Income taxes:

Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred tax is recognized on the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred-tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.

A deferred-tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred-tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

(i) Flow-through common shares:

Periodically, the Company finances a portion of its exploration and development activities through the issuance of flow-through shares.  The resource expenditure deductions for income tax purposes related to exploratory development activities are renounced to investors in accordance with tax legislation.  Flow-through shares issued are recorded in share capital at the fair value of common shares on the date of issue.  The premium received on issuing flow-through shares is initially recorded as a deferred credit.  As qualifying expenditures are incurred, the premium is reversed and a deferred income tax liability is recorded.  The net amount is then recognized as deferred income tax expense.

(j) Share-based payments:

The Company applies the fair-value method for valuing share option grants.  Under this method, compensation cost attributable to all share options granted are measured at fair value at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus.  A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options or units that vest.  Upon the exercise of the share options, consideration received, together with the amount previously recognized in contributed surplus, is recorded as an increase to share capital.

(k) Per-share information:

Basic per-share information is computed by dividing income by the weighted average number of common shares outstanding for the period.  The treasury-stock method is used to determine the diluted per share amounts, whereby any proceeds from the share options, warrants or other dilutive instruments are assumed to be used to purchase common shares at the average market price during the period.  The weighted average number of shares outstanding is then adjusted by the net change.

(l) Leased assets:

Leases where the Company assumes substantially all the risks and rewards of ownership are classified as finance leases.  Upon initial recognition, the leased asset is measured at an amount equal to the lower of its fair value and the present value of the minimum lease payments.  Subsequent to initial recognition, the asset is accounted for in accordance with the accounting policy applicable to that asset.

Minimum lease payments made under finance leases are apportioned between the finance expenses and the reduction of the outstanding liability.  The finance expenses are allocated to each year during the lease term so as to produce a constant periodic rate of interest on the remaining balance of the liability.

Other leases are operating leases, which are not recognized on the Company's statement of financial position.

(m) Comparative amounts:

Certain comparative amounts may have been reclassified to conform with presentation adopted in the current year.

3. FUTURE ACCOUNTING CHANGES

The following pronouncements from the IASB will become effective for financial reporting periods beginning on or after January 1, 2013 and have not yet been adopted by the Company. All of these new or revised standards permit early adoption with transitional arrangements depending upon the date of initial application.

IFRS 9 - Financial Instruments addresses the classification and measurement of financial assets.

IFRS 10 - Consolidated Financial Statements builds on existing principles and standards and identifies the concept of control as the determining factor in whether an entity should be included within the consolidated financial statements of the parent company.

IFRS 11 - Joint Arrangements establishes the principles for financial reporting by entities when they have an interest in arrangements that are jointly controlled.

IFRS 12 - Disclosure of Interest in Other Entities provides the disclosure requirements for interests held in other entities including joint arrangements, associates, special purpose entities and other off balance sheet entities.

IFRS 13 - Fair Value Measurement defines fair value, requires disclosure about fair value measurements and provides a framework for measuring fair value when it is required or permitted within the IFRS standards.

IAS 19 - Employee Benefits revises the existing standard to eliminate options to defer the recognition of gains and losses in defined benefit plans, requires re-measurements of a defined benefit plan's assets and liabilities to be presented in other comprehensive income and increases disclosure.

IAS 27 - Separate Financial Statements revised the existing standard which addresses the presentation of parent company financial statements that are not consolidated financial statements.

IAS 28 - Investments in Associate and Joint Ventures revised the existing standard and prescribes the accounting for investments and sets out the requirements for the application of the equity method when accounting for investments in associates and joint ventures.

The IASB also issued Presentation of Items of Other Comprehensive Income, an amendment to IAS 1 Financial Statement Presentation. The amendment addresses the presentation of other comprehensive income and requires the grouping of items within other comprehensive income that might eventually be reclassified to the profit and loss section of the income statement. The change becomes effective for financial years after July 1, 2012 with earlier adoption permitted.

The Company has not completed its evaluation of the effect of adopting these standards on its consolidated financial statements.

4. DETERMINATION OF FAIR VALUE

A number of the Company's accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.

(i) Property, plant and equipment and intangible exploration assets:

The fair value of property, plant and equipment recognized in a business combination, is based on market values. The market value of property, plant and equipment is the estimated amount for which property, plant and equipment could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm's-length transaction after proper marketing wherein the parties had each acted knowledgeably, prudently and without compulsion. The market value of oil and natural gas interests (included in property, plant and equipment) and intangible exploration assets is estimated with reference to the discounted cash flow expected to be derived from oil and natural gas production based on externally prepared reserve reports. The risk-adjusted discount rate is specific to the asset with reference to general market conditions.

The market value of other items of property, plant and equipment is based on the quoted market prices for similar items.

(ii) Cash and cash equivalents, trade and other receivables, bank debt and trade and other payables:

The fair value of cash and cash equivalents, trade and other receivables, bank debt and trade and other payables is estimated as the present value of future cash flow, discounted at the market rate of interest at the reporting date. At December 31, 2011 and December 31, 2010, the fair value of these balances approximated their carrying value due to their short term to maturity.  The bank debt has a floating rate of interest and therefore the carrying value approximates the fair value.

(iii) Derivatives:

The fair value of commodity price risk management contracts is determined by discounting the difference between the contracted prices and published forward price curves as at the statement of financial position date, using the remaining contracted oil and natural gas volumes and a risk-free interest rate (based on published government rates). The fair value of options and costless collars is based on option models that use published information with respect to volatility, prices and interest rates.

(iv) Share options:

The fair value of employee share options is measured using a Black Scholes option pricing model. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility (based on weighted average historic volatility adjusted for changes expected due to publicly available information), weighted average expected life of the instruments (based on historical experience and general option holder behaviour), expected dividends, and the risk-free interest rate (based on government bonds).

(v) Measurement:

Tourmaline classifies the fair value of these transactions according to the following hierarchy based on the amount of observable inputs used to value the instrument.

  • Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

  • Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1. Prices are either directly or indirectly observable as of the reporting date.  Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

  • Level 3 - Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

The following tables provide fair value measurement information for financial assets and liabilities as of December 31, 2011 and December 31, 2010.  The carrying value of cash and cash equivalents, trade and other receivables and trade and other payables included in the consolidated statement of financial position approximate fair value due to the short-term nature of those instruments.  These assets and liabilities are not included in the following tables.


December 31, 2011
  Carrying
Amount
 
Fair Value
 
Level 1
 
Level 2
 
Level 3
Financial Assets:                            
  Investments     $ 233 $ 233     $ 233 $ - $ -
  Commodity price risk contracts       276   276       -   276   -
Financial liabilities:                            
  Bank debt       81,749   81,749       81,749   -   -
  Commodity price risk contracts       74   74       -   74   -


December 31, 2010
  Carrying
Amount
 
Fair Value
 
Level 1
 
Level 2
 
Level 3
Financial Assets:                            
  Investments     $ 3,932 $ 3,932     $ 3,932 $ - $ -
Financial liabilities:                            
  Commodity price risk contracts       742   742       -   742   -

5. FINANCIAL RISK MANAGEMENT

The Board of Directors has overall responsibility for the establishment and oversight of the Company's risk management framework.  The Board has implemented and monitors compliance with risk management policies.

The Company's risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company's activities.

(a) Credit risk:

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Company's receivables from joint venture partners and petroleum and natural gas marketers.  As at December 31, 2011, Tourmaline's receivables consisted of $9.7 million (December 31, 2010 - $21.1 million) from joint venture partners, $40.1 million (December 31, 2010 - $23.6 million) from petroleum and natural gas marketers and $11.0 million (December 31, 2010 - $13.9 million) from provincial governments.

Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the month following production.  The Company sells a significant portion of its oil and gas to a limited number of counterparties.  In 2011, Tourmaline had three counterparties that individually accounted for more than ten percent of annual revenues.  The Company's policy to mitigate credit risk associated with these balances is to establish marketing relationships with creditworthy purchasers.  Tourmaline historically has not experienced any collection issues with its petroleum and natural gas marketers.  Joint venture receivables are typically collected within one to three months of the joint venture bill being issued to the partner.  The Company attempts to mitigate the risk from joint venture receivables by obtaining partner approval of significant capital expenditures prior to expenditure.  The receivables, however, are from participants in the petroleum and natural gas sector, and collection of the outstanding balances are dependent on industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessful drilling.  In addition, further risk exists with joint venture partners as disagreements occasionally arise that increase the potential for non-collection.  The Company does not typically obtain collateral from petroleum and natural gas marketers or joint venture partners; however, the Company does have the ability to withhold production from joint venture partners in the event of non-payment.

The Company monitors the age of, and investigates issues behind, its receivables that have been past due for over 90 days.  At December 31, 2011, the Company had $0.6 million (December 31, 2010 - $1.0 million) over 90 days.  The Company is satisfied that these amounts are substantially collectible.

The carrying amount of accounts receivable, cash and cash equivalents and commodity price risk management contracts represents the maximum credit exposure.  The Company does not have an allowance for doubtful accounts as at December 31, 2011 (December 31, 2010 - nil) and did not provide for any doubtful accounts nor was it required to write-off any receivables during the year ended December 31, 2011 (December 31, 2010 - nil).

(b) Liquidity risk:

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they come due.  The Company's approach to managing liquidity is to ensure that it will have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions without incurring unacceptable losses or risking harm to the Company's reputation.  Liquidity risk is mitigated by cash on hand, when available, and access to credit facilities.

The Company's accounts payable and accrued liabilities balance at December 31, 2011 is approximately $212.7 million (December 31, 2010 - $178.1 million).  It is the Company's policy to pay suppliers within 45-75 days.  These terms are consistent with industry practice.  As at December 31, 2011, substantially all of the account balances were less than 90 days.

The Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary.  Further, the Company utilizes authorizations for expenditures on both operated and non-operated projects to further manage capital expenditures.  The Company also attempts to match its payment cycle with collection of petroleum and natural gas revenues on the 25th of each month.

The following are the contractual maturities of financial liabilities, including estimated interest payments, at December 31, 2011:

    Carrying
Amount
  Contractual
Cash Flow
  Less Than
One  Year
One - Two
Years
Two - Five
Years
  More Than
Five Years
Non-derivative financial liabilities:                                
  Trade and other payables     $ 208,980     $ 208,980     $ 208,980     $ -     $ -     $ -
  Bank debt (1)       81,749       84,389       84,389       -       -       -
  Transportation liability       14,589       14,589       3,725       3,725       7,139       -
Derivative financial liabilities:                                                
  Financial commodity contracts       74       74       74       -       -       -
      $ 305,392     $ 308,032     $ 297,168     $ 3,725     $ 7,139     $ -
(1) Includes interest expense at 3.23% being the rate applicable at December 31, 2011.
 

(c) Market risk:

Market risk is the risk that changes in market conditions, such as commodity prices, interest rates and foreign exchange rates will affect the Company's net income or value of financial instruments.  The objective of market risk management is to manage and curtail market risk exposure within acceptable limits, while maximizing the Company's returns.

The Company utilizes both financial derivatives and physical delivery sales contracts to manage market risks.  All such transactions are conducted in accordance with the risk management policy that has been approved by the Board of Directors.

Currency risk has minimal impact on the value of the financial assets and liabilities on the consolidated statement of financial position at December 31, 2011.  Changes in the US to Canadian exchange rate, however, could influence future petroleum and natural gas prices which could impact the value of certain derivative contracts.  This influence cannot be accurately quantified.

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates.  The Company is exposed to interest rate risk to the extent that changes in market interest rates will impact the Company's bank debt which is subject to a floating interest rate.  Assuming all other variables remain constant, an increase or decrease of 1% in market interest rates in the year ended December 31, 2011 would have decreased or increased shareholders' equity and net income by $0.4 million, and nil for 2010 as there was no debt outstanding at year end.

The following table outlines the realized and unrealized gains on interest rate contracts for the three months and year ended December 31, 2011:


(000s)
          Year Ended
December 31, 2011



Term

Type
(Floating
to Fixed)



Amount
Company
Fixed
Interest
Rate (%)
Counter
Party
Floating
Rate Index
 

Realized
Gain/(Loss)


Unrealized
Gain/ (Loss)
September 29,
2011- September
29, 2013


Swap


$150,000


1.15%

Floating
Rate
              

$ 49
      

$ (33)

The unrealized loss on the interest rate swap has been included on the consolidated statement of financial position with changes in the fair value included in the unrealized gain/(loss) on financial instruments on the consolidated statement of income and comprehensive income.  There were no interest rate contracts in place at December 31, 2010.

Commodity price risk is the risk that the fair value or future cash flow will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted by not only the relationship between the Canadian and United States dollar, but also world economic events that dictate the levels of supply and demand.  As at December 31, 2011, the Company has entered into certain financial derivative and physical delivery sales contracts in order to manage commodity risk.  These instruments are not used for trading or speculative purposes.  The Company has not designated its financial derivative contracts as effective accounting hedges, even though the Company considers all commodity contracts to be effective economic hedges.  As a result, all such commodity contracts are recorded on the consolidated statement of financial position at fair value, with changes in the fair value being recognized as an unrealized gain or loss on the consolidated statement of income and comprehensive income.

The Company has entered into the following derivative contracts as at December 31, 2011:

Type of Contract   Quantity   Time Period   Contract Price   Fair Value
Financial Swap   100 bbls/d   July 2011 - December 2012   US$90.00/bbl $ (327)
Financial Swap   100 bbls/d   July 2011 - June 2012   US$101.40/bbl   40
Financial Swap   100 bbls/d   September 2011 - December 2012   US$101.00/bbl   81
Financial Swap   100 bbls/d   January 2012 - December 2012   US$104.00/bbl   193
Financial Swap   100 bbls/d   January 2012 - December 2012   US$108.00/bbl   341
Costless Collar   100 bbls/d   September 2010 - August 2012   US$75/bbl floor -
US$96/bbl ceiling
 
(193)
Costless Collar   100 bbls/d   July 2012 - June 2013   US$85/bbl floor -
US$109.65/bbl ceiling
 
11
Financial Swap   100 bbls/d   January 2012 - June 2013   US$99.70/bbl   89
Total fair value             $ 235

The following contracts were entered into subsequent to December 31, 2011 and are therefore not reflected in the consolidated statements of income and comprehensive income:

Type of Contract     Quantity     Time Period     Contract Price
Financial Swap     100 bbls/d     July 2012 - June 2013     US$100.10/bbl
Financial Swap     100 bbls/d     August 2012 - July 2013     US$101.10/bbl
Financial Swap     100 bbls/d     August 2012 - December 2013     US$100.60/bbl
Financial Swap     100 bbls/d     January 2013 - December 2013     US$101.05/bbl
Financial Swap     100 bbls/d     July 2012 - March 2013     US$103.30/bbl
Financial Swap     100 bbls/d     January 2013 - December 2013     US$101.45/bbl
Financial Swap     100 bbls/d     January 2013 - December 2013     US$103.40/bbl

The following table provides a summary of the unrealized gains and losses on financial instruments for the year ended December 31, 2011:

  Years Ended December 31,
(000s)   2011   2010
Unrealized gain/(loss) on financial instruments     $             944  $             (863)
Unrealized gain/(loss) on investments held for trading                   (111)               260
Total     $             833 $             (603)

The unrealized gain/(loss) on derivative contracts has been included on the consolidated statement of financial position with changes in the fair value included in the unrealized gain/(loss) on financial instruments on the consolidated statement of income and comprehensive income.

As at December 31, 2011, if the future strip prices for oil were $1.00 per bbl higher, with all other variables held constant, before-tax earnings for the period would have been $0.3 million (2010 - $0.2 million) lower.  An equal and opposite impact would have occurred to before-tax earnings and the fair value of the derivative contracts liability oil prices $1.00 per bbl lower.

In addition to the financial commodity contracts discussed above, the Company has entered into physical contracts to manage commodity risk.  These contracts are considered normal sales contracts and are not recorded at fair value in the consolidated financial statements.

The Company has entered into the following physical contracts as at December 31, 2011:

                   
Type of Contract     Quantity     Time Period     Contract Price
AECO Fixed Price     2,000 gjs/d     March 2010 - March 2012     Cdn$5.72/gj
AECO Call Option     3,000 gjs/d     January 2011 - December 2012     Cdn$6.00/gj strike price
AECO Fixed Price     3,000 gjs/d     January 2011 - December 2012     Cdn$5.53/gj
AECO Fixed Price     3,000 gjs/d     February 2011 - April 2012     Cdn$4.00/gj
AECO/Nymex Differential Swap     5,000 MMbtu/d     November 2011 - October 2012     Nymex less USD$0.62/MMbtu
AECO/Nymex Differential Swap     3,000 MMbtu/d     November 2011 - October 2012     Nymex less USD$0.535/MMbtu
AECO/Nymex Differential Swap     5,000 MMbtu/d     January 2012 - December 2012     Nymex less USD$0.4325/MMbtu
AECO/Nymex Differential Swap     2,000 MMbtu/d     January 2012 - December 2012     Nymex less USD$0.42/MMbtu
AECO/Nymex Differential Swap     3,000 MMbtu/d     December 2011 - March 2012     Nymex less USD$0.30/MMbtu
AECO Fixed Price     3,000 gjs/d     January 2012 - December 2014     Cdn$4.45/gj
AECO Call Option     3,000 gjs/d     January 2012 - December 2014     Cdn$4.50/gj strike price
AECO Call Option     3,000 gjs/d     January 2015 - December 2016     Cdn$6.00/gj strike price

The following contracts were entered into subsequent to December 31, 2011:

               
Type of Contract     Quantity Time Period     Contract Price
AECO/Nymex Differential Swap     6,000 MMbtu/d (1) February 2012 - December 2012     Nymex less USD$0.42/MMbtu
AECO/Nymex Differential Swap     5,000 MMbtu/d February 2012 - December 2012     Nymex less USD$0.325/MMbtu
AECO/Nymex Differential Swap     7,000 MMbtu/d February 2012 - December 2012     Nymex less USD$0.44/MMbtu
(1) This is a restructuring of a previously held contract whereby the volumes, contract price and time period of the contract were amended subsequent to December 31, 2011.

(d) Capital management:

The Company's policy is to maintain a strong capital base to maintain investor, creditor and market confidence and to sustain the future development of the business.  The Company considers its capital structure to include shareholders' equity, bank debt and working capital.  In order to maintain or adjust the capital structure, the Company may from time to time issue shares and adjust its capital spending to manage current and projected debt levels.  The annual and updated budgets are approved by the Board of Directors.

The key measure that the Company utilizes in evaluating its capital structure is net debt, which is defined as long-term bank debt plus working capital (adjusted for the fair value of financial instruments), to annualized funds from operations, defined as cash flow from operating activities before changes in non-cash working capital.  Net debt to annualized funds from operations represents a measure of the time it is expected to take to pay off the debt if no further capital expenditures were incurred and if funds from operations in the next year were equal to the amount in the most recent quarter annualized.

The Company monitors this ratio and endeavours to maintain it at, or below, 2.0 to 1.0 in a normalized commodity price environment. This ratio may increase at certain times as a result of acquisitions or low commodity prices. As shown below, as at December 31, 2011, the Company's ratio of net debt to annualized funds from operations was 0.78 to 1.0.


(000s)
  As at
December 31, 2011
  As at
December 31, 2010
Net debt:                
  Bank debt     $             (81,749)     $             -
  Working capital/(deficit)                   (146,317)                   (49,642)
  Fair value of financial instruments - short-term (asset)/liability                   (276)                   472
Net debt     $             (228,342)     $             (49,170)
Annualized funds from operations:                
  Cash flow from operating activities for Q4     $             61,801     $             46,109
  Change in non-cash working capital                   11,510                   (1,169)
  Funds from operations for Q4     $             73,311     $             44,940
Annualized funds from operations (based on most recent quarter annualized)     $             293,244     $             179,760
Net debt to annualized funds from operations                   0.78                   0.27

The Company has not paid or declared any dividends since the date of incorporation, nor are any contemplated in the foreseeable future.  There were no changes in the Company's approach to capital management since December 31, 2010.

6. EXPLORATION AND EVALUATION ASSETS

(000s)  
As at January 1, 2010     $             250,972
  Capital expenditures                   200,816
  Capitalized share-based payments                   10,388
  Transfers to property, plant and equipment (note 7)                   (178,012)
  Acquisitions                   206,876
  Divestitures                   (11,973)
As at December 31, 2010     $             479,067
  Capital expenditures                   213,414
  Capitalized share-based payments                   9,374
  Transfers to property, plant and equipment (note 7)                   (212,303)
  Acquisitions                   135,766
  Divestitures                   (4,803)
As at December 31, 2011     $             620,515

General and administrative expenditures for the year ended December 31, 2011 of $8.2 million (December 31, 2010 — $5.9 million) have been capitalized and included as exploration and evaluation assets.  Non-cash share-based payments in the amount of $9.4 million (December 31, 2010 - $10.4 million) were also capitalized and included in exploration and evaluation assets.

7. PROPERTY, PLANT AND EQUIPMENT ("PP&E")

Cost

(000s)  
As at January 1, 2010 $             503,826
Capital expenditures               617,764
Transfers from exploration and evaluation (note 6)               178,012
Change in decommissioning liabilities (note 8)               15,963
Divestitures               (15,983)
As at December 31, 2010 $             1,299,582
Capital expenditures               508,294
Capitalized share-based payments               2,312
Transfers from exploration and evaluation (note 6)               212,303
Change in decommissioning liabilities (note 8)               15,397
Acquisitions               246,940
Divestitures               (8,525)
As at December 31, 2011 $             2,276,303

Accumulated Depletion, Depreciation and Amortization

(000s)                        
As at January 1, 2010                       $             -
Depletion, depreciation and amortization                                     96,660
Divestitures                                     (1,179)
As at December 31, 2010                       $             95,481
Depletion, depreciation and amortization                                     158,168
Divestitures                                     (1,234)
As at December 31, 2011                       $             252,415

Net Book Value

(000s)          
As at January 1, 2010         $           503,826
As at December 31, 2010                     1,204,101
As at December 31, 2011         $           2,023,888

General and administrative expenditures for the year ended December 31, 2011 of $1.8 million (December 31, 2010 - $0.5 million) have been capitalized and included as costs of oil and natural gas properties.  Also included in oil and natural gas properties are non-cash related share-based payments of $2.3 million (December 31, 2010 - nil).

Future development costs for the year ended December 31, 2011 of $1,539 million (December 31, 2010 - $1,008 million) were included in the depletion calculation.

Impairment Testing

In accordance with IFRS, an impairment is recognized if the carrying value exceeds the recoverable amount for each CGU.  The Company determines the recoverable amount by using fair value less cost to sell, based on discounted future cash flows of proved plus probable reserves using forecast prices and costs.

An impairment test was performed at December 31, 2011 on the Company's PP&E assets using a pre-tax discount rate of 10%, an inflation rate of 2% and the following forward commodity price estimates:



Year

WTI Oil
(US$/bbl)(1)
Foreign
Exchange Rate
(US$/Cdn$)(1)
Edmonton Light
Crude Oil
(Cdn$/bbl)(1)

AECO Gas
(Cdn$/mmbtu)(1)
2012 97.00 0.980 97.96 3.49
2013 100.00 0.980 101.02 4.13
2014 100.00 0.980 101.02 4.59
2015 100.00 0.980 101.02 5.05
2016 100.00 0.980 101.02 5.51
2017 100.00 0.980 101.02 5.97
2018 101.35 0.980 102.40 6.21
2019 103.38 0.980 104.47 6.33
2020 105.45 0.980 106.58 6.46
2021 107.56 0.980 108.73 6.58
Thereafter +2.0%/yr 0.980 +2.0%/yr +2.0%/yr
(1) Source: GLJ Petroleum Consultants price forecast, effective January 1, 2012

There was no impairment to PP&E at December 31, 2011 (December 31, 2010 - nil).

Corporate Acquisitions

Cinch Energy Corp.

On July 12, 2011, the Company acquired all of the issued and outstanding shares of Cinch Energy Corp. ("Cinch").  As consideration, the Company issued 6,363,523 common shares at a price of $33.02 per share. Total transaction costs incurred by the Company of $1 million associated with this acquisition were expensed in the consolidated statement of income and comprehensive income.

The acquisition of Cinch provided for an increase in lands and production in two of Tourmaline's core and designated growth areas of Dawson, NEBC and Musreau-Kakwa in Alberta.

Results from operations for Cinch are included in the Company's consolidated financial statements from the closing date of the transaction.  The value attributed to the property, plant and equipment acquired was supported by an engineering report prepared at December 31, 2010 by independent reserve engineers using proved plus probable reserves discounted at a rate of 10%.  The report was internally rolled forward to June 30, 2011 using updated pricing.  Additional value was also attributed based on internal reserve estimates relating to successful drilling results in 2011.  The allocation of net assets acquired is based on the best available information at the time and could be subject to further change.  The acquisition has been accounted for using the purchase method based on estimated fair values as follows:

(000s)             Cinch Energy Corp.
Fair value of net assets acquired:                
  Property, plant and equipment             $ 182,770
  Exploration and evaluation               87,136
  Working capital deficiency               (3,897)
  Bank debt               (19,696)
  Decommissioning obligations               (2,430)
  Deferred income tax liabilities               (33,759)
Total             $ 210,124
Consideration:                
  Common shares issued             $ 210,124

Included in the consolidated statements of income and comprehensive income for the year ended December 31, 2011 are the following amounts relating to Cinch Energy Corp. since July 12, 2011:

(000s)        
Oil and natural gas sales     $             17,923
Net income and comprehensive income                  $             3,605

If Tourmaline had acquired Cinch on January 1, 2011, the pro-forma results of the oil and gas sales and net income for the year ended December 31, 2011 would have been as follows:




(000s)
 


As Stated
 


Cinch
  Pro Forma
Year Ended
December 31,
2011
Oil and natural gas sales $ 342,820 $             38,033 $             380,853
Net income and comprehensive income $ 43,851 $             6,276 $             50,127

Altia Energy Ltd.

On January 14, 2010, Tourmaline acquired all of the issued and outstanding shares of Altia Energy Ltd. ("Altia").  As consideration, Tourmaline paid cash of $2.7 million before transaction costs of $0.6 million and issued 6,411,670 shares at a price of $15.00 per share.  The transaction costs incurred by the Company were expensed in the consolidated statement of income and comprehensive income.  The operations of Altia have been included with the results of the Company commencing January 14, 2010.

This acquisition, along with previous acquisitions in 2009, allowed Tourmaline to establish a strong Montney position in the Sunrise-Dawson area of NEBC.  This was an area where Tourmaline's management and technical staff had extensive technical experience, as well as historical success.

The acquisition was accounted for using the purchase method based on estimated fair values as follows:

    Altia Energy Ltd.
Net assets acquired:    
  Property, plant and equipment $ 73,555
  Exploration and evaluation   52,665
  Cash   (492)
  Working capital   100
  Long-term investment   -
  Long-term bank debt   (6,550)
  Decommissioning obligation   (1,452)
  Deferred taxes   (18,987)
Total $ 98,839
Consideration:    
  Cash $ 2,664
  Shares issued   96,175
Total $ 98,839

Included in the consolidated statements of income and comprehensive income for the year ended December 31, 2010 are the following amounts relating to Altia Energy Ltd. since January 14, 2010:

(000s)        
Oil and natural gas sales     $             14,188
Net income and comprehensive income                  $             1,309

If Tourmaline had acquired Altia on January 1, 2010, the pro-forma results of the oil and gas sales and net income for the year ended December 31, 2010 would have been as follows:



(000s)
 

As Stated
 

Altia
  Pro Forma
Year Ended
December 31, 2010
Oil and natural gas sales $ 194,928 $    14,950 $             209,878
Net income and comprehensive income $ 9,196 $     1,467 $             10,663

Acquisition of Oil and Natural Gas Properties

For the year ended December 31, 2011, the Company completed property acquisitions for total cash consideration of $115.2 million.  The Company also assumed $1.8 million in decommissioning liabilities.  The acquisitions were not deemed business combinations as the Company acquired additional working interests in wells in which it already had an ownership interest and therefore no additional processes were acquired and as such did not constitute a business combination.

For the year ended December 31, 2010, the Company acquired oil and natural gas properties in Alberta for total consideration of $367 million (before adjustments). The assets acquired are located in Tourmaline's core areas and include land, oil and gas wells, facilities, pipelines and seismic data.  In accordance with IFRS, these property acquisitions were determined to be business combinations.

From the period of when the assets were acquired in 2010 to December 31, 2010, the acquisitions generated revenues of $22.9 million and net earnings of $0.3 million, which are included in the 2010 comparative consolidated statements of income and comprehensive income.

If the acquisitions had occurred on January 1, 2010, management estimates revenues generated from the acquisitions for the year ended December 31, 2010 would have been $44.2 million with an estimated net income of nil.

8. DECOMMISSIONING OBLIGATIONS

The Company's decommissioning obligations result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities.  The Company estimates the total undiscounted amount of cash flow required to settle its decommissioning obligations is approximately $72.5 million (2010 - $40.0 million), which will be incurred between 2023 and 2028.  A risk-free rate of 2.49% (2010 - 3.5%) and an inflation rate of 2% (2010 - 3%) were used to calculate the fair value of the decommissioning obligations.  The decommissioning obligations at December 31, 2011, have been adjusted by approximately $5.1 million due to changes in estimates during the year.


(000s)
Year Ended
December 31, 2011
Year Ended
December 31, 2010
Balance, beginning of year     $             35,279 $             19,153
  Obligation incurred                   6,048               4,411
  Obligation incurred on corporate acquisitions (note 7)                   2,430               1,452
  Obligation incurred on property acquisitions                   1,845               7,936
  Obligation divested                   (481)               (965)
  Obligation settled                   (1,047)               -
  Accretion expense                   1,315               1,128
  Change in future estimated cash outlays                   5,074               2,164
Balance, end of year     $             50,463 $             35,279

9. BANK DEBT

On September 8, 2011, the Company increased its credit facility for an extendible revolving term loan to $350 million from $275 million with three Canadian chartered banks, in addition to its already existing $25 million operating line.  The facility bears interest on a variable grid currently 250 basis points over the prevailing banker's acceptance rate.  Security for the facility includes a general security agreement and a $500 million demand loan debenture secured by a first floating charge over all assets.  On July 31, 2012, at the Company's discretion, the facility is available on a non-revolving basis for a period of 365 days, at which time the facility would be due and payable.  Alternatively, the facility may be extended for a further 364-day period at the request of the Company and subject to approval by the banks.

A subsidiary of the Company also has a financing arrangement with a Canadian chartered bank for an extendible revolving term loan in the amount of $5 million in addition to a $5 million operating line.  The interest rate charged varies based on the amount outstanding.  Security for the facility includes a general security agreement and a demand loan debenture secured by a first floating charge over all of the subsidiary's assets.  The revolving term credit facility has a 364-day extendible period plus a one-year maturity.

The Company is required to meet certain financial-based covenants to maintain the facilities.  The financial covenants include a requirement to ensure the total amount drawn on the facility does not exceed the total borrowing base as defined in each facility's agreement, and that the ratio of earnings adjusted for interest, taxes and other non-cash items to interest expense does not exceed a predetermined amount, as determined by each facility's agreement.  As at December 31, 2011, the Company was in compliance with these covenants.

Tourmaline has drawn down on existing facilities in the amount of $81.7 million.  The effective interest rate for the year ended December 31, 2011 was 3.3% (December 31, 2010- 3.5%).  In addition, Tourmaline has outstanding letters of credit of $3.6 million, which reduce the credit available on the facility.

10. INVESTMENTS

In November 2011, Tourmaline sold its interest in a private junior oil and gas company for proceeds of $3.3 million. There was no gain or loss recorded on the sale.  Tourmaline continues to own common shares in a public junior oil and gas company which have been fair valued at $0.2 million based on the quoted market price at December 31, 2011.

A reconciliation of the Company's investment is provided below:


(000s)
Year Ended
December 31, 2011
Year Ended
December 31, 2010
Balance, beginning of year $             3,932 $             632
  Proceeds on disposition of shares (net of realized gain of
$45,000 in 2010)
              (3,588)               (210)
  Acquired on asset disposition               -               3,250
  Unrealized gain/(loss) on investments               (111)               260
Balance, end of year $             233 $             3,932

11. LONG TERM OBLIGATION

As part of an acquisition of petroleum and natural gas properties in June 2010, the Company acquired a firm transportation agreement.  A liability of $19.9 million was recorded to account for the fair value of the agreement at the time of the acquisition. This amount was accounted for as part of the acquisition cost and will be charged as a reduction to transportation expenses over the life of the agreement as the obligation is met.  The reduction to transportation expense for the year ended December 31, 2011 was $3.7 million.  The outstanding balance is $14.6 million of which $3.7 million has been included in accounts payable and accrued liabilities.

12. NON-CONTROLLING INTEREST

Tourmaline owns 90.6 percent of Exshaw Oil Corp., a private company engaged in oil and gas exploration in Canada.

A reconciliation of the non-controlling interest is provided below:


(000s)
  Year Ended
December 31, 2011
  Year Ended
December 31, 2010
Balance, beginning of year $ 13,909 $ 13,526
Share of subsidiary's net income for the year   1,170   383
Balance, end of year $ 15,079 $ 13,909

13. SHARE CAPITAL

(a) Authorized

Unlimited number of Common Shares without par value.

Unlimited number of non-voting Preferred Shares, issuable in series.

(b) Common Shares Issued

  Year Ended
December 31, 2011
  Year Ended
December 31, 2010

($000s)
Number of
Shares
 
Amount
  Number of
Shares
 
Amount
Balance, beginning of year 136,191,061 $             1,508,052   101,809,391 $             890,952
For cash on Initial Public Offering (includes
over-allotment option)
-               -   11,500,000               241,500
For cash on public offering of common shares 11,725,000               335,737   -               -
For cash on public offering of flow-through
common shares(1)
1,361,500   44,290   -   -
For cash on private placement of common shares -               -   10,350,000               188,850
For cash on private placement of flow-through
common shares(2)(3)
1,580,000               39,658   3,600,000               65,202
Issued for the acquisition of properties -               -   2,500,000               45,000
Issued on corporate acquisitions 6,363,523               210,124   6,411,670               96,175
For cash on exercise of share options 1,356,502               12,532   20,000               160
Contributed surplus on exercise of share options -               4,856   -               61
Share issue costs -               (19,329)   -               (26,502)
Tax effect of share issue costs -               4,740   -               6,654
Balance, end of year 158,577,586 $             2,140,660   136,191,061 $ 1,508,052
(1)  On December 1, 2011, the Company issued 1.36 million flow-through shares at $41.00 per share for total gross proceeds of $55.8 million.  The implied premium on the flow-through shares was determined to be $11.5 million or $8.47 per share.  A total of 0.16 million shares were purchased by insiders.  As at December 31, 2011, the Company is committed to spending an additional $54.8 million on qualified exploration and development expenditures by December 31, 2012. The expenditures were renounced to investors in February 2012, with an effective date of renunciation of December 31, 2011. 
(2) On March 8, 2011, the Company issued 1.58 million flow-through shares at $30.00 per share for total gross proceeds of $47.4 million.  The implied premium on the flow-through shares was determined to be $7.7 million or $4.90 per share.  A total of 0.38 million shares were purchased by insiders.  As at December 31, 2011, the Company had spent the full committed amount.  The expenditures were renounced to investors in February 2012, with an effective date of renunciation of December 31, 2011. 
(3)  On March 19, 2010, the Company issued 2.45 million flow-through shares at $21.60 per share for total gross proceeds of $52.9 million.  The implied premium on the flow-through shares was $8.8 million or $3.60 per share.  On August 12, 2010, the Company issued 1.15 million flow-through shares at $22.00 per share for total gross proceeds of $25.3 million.  The implied premium on the flow-through shares was $4.2 million or $3.65 per share. The Company has spent the full committed amounts on the above noted issuances.

14. INCOME TAXES

The provision for income taxes in the consolidated statements of income and comprehensive income reflect an effective tax rate which differs from the expected statutory tax rate.  Differences were accounted for as follows:

(000s) December 31, 2011 December 31, 2010
Income before taxes $             68,434 $             26,566
Canadian statutory rate(1)               26.5%               28.0%
Expected income taxes at statutory rates               18,135               7,438
Effect on income tax of:        
       Share-based payments               3,097               2,909
       Flow-through shares               4,330               8,277
       Effect of change in corporate tax rate and other               (979)               (1,254)
Deferred income tax $             24,583 $             17,370
(1) The statutory rate consists of the combined statutory tax rate for the Company and its subsidiaries for the year ended December 31, 2011.  The general combined Federal/Provincial tax rate was reduced from 28% to 26.5% due to the Federal tax rate dropping from 18% in 2010 to 16.5% in 2011.

The movement in deferred tax balances during the years ended December 31, 2011 and 2010 are as follows:

(000s)

2011
Balance
January 1,
2011
Recognized in
Net Earnings/
(Loss)

Recognized
in Liabilities

Recognized
in Equity
Acquired in
Business
Combination
Balance
December 31,
2011
Deferred tax liabilities:                        
    Exploration and evaluation and property, plant and
equipment
$             91,995 $             27,429 $             8,306 $             - $             37,441 $             165,171
       Risk management contracts               (136)               212               -               -               -               76
Deferred tax assets:                                                                                                    
       Decommissioning obligations                       (8,806)                       (3,204)                       -                   -               (606)               (12,616)
       Long-term obligations                       (4,634)                   987                       -                   -               -               (3,647)
       Non-capital losses                       (23,308)                   (4,804)                       -                   -               (2,438)               (30,550)
       Share issue costs                       (9,042)                   3,963                       -                   (4,740)               (638)               (10,457)
Deferred tax liability/(asset) $                 46,069 $             24,583 $             8,306 $             (4,740) $             33,759 $             107,977

(000s)

2010
Balance
January 1,
2010
Recognized in
Net Earnings/
(Loss)

Recognized
in Liabilities

Recognized
in Equity
Acquired in
Business
Combination
Balance
December 31,
2010
Deferred tax liabilities:                        
    Exploration and evaluation and property, plant and
equipment
$             19,815 $             35,135 $             16,504 $             - $             20,541 $             91,995
       Risk management contracts               34               (170)               -               -               -               (136)
Deferred tax assets:                                                                                                    
       Decommissioning obligations                       (4,788)                   (3,656)                       -                   -               (362)               (8,806)
       Long-term obligations                       (232)                   (4,402)                       -                   -               -               (4,634)
       Non-capital losses                       (9,531)                   (12,585)                       -                   -               (1,192)               (23,308)
       Share issue costs                       (5,436)                   3,048                       -                   (6,654)               -               (9,042)
Deferred tax liability/(asset) $                 (138) $             17,370 $             16,504 $             (6,654) $             18,987 $             46,069

As at December 31, 2011, the Company has estimated federal tax pools of $2.1 billion (2010 - $1.2 billion) available for deduction against future taxable income.

15. EARNINGS PER SHARE

Basic earnings-per-share was calculated as follows:

  Years Ended December 31,
    2011   2010
Net earnings for the year (000s)     $ 42,681 $ 8,813
Weighted average number of common shares - basic       146,647,848   120,786,535
Earnings per share - basic     $ 0.29 $ 0.07

Diluted earnings-per-share was calculated as follows:

  Years Ended December 31,
    2011   2010
Net earnings for the year (000s)     $ 42,681 $ 8,813
Weighted average number of common shares - diluted       152,315,296   123,394,559
Earnings per share - fully diluted     $ 0.28 $ 0.07

There were 3,568,024 options excluded from the weighted-average share calculation for the year ended December 31, 2011 because they were anti-dilutive (December 31, 2010 - 2,322,000).

16. SHARE-BASED PAYMENTS

The Company has a rolling share option plan.  Under the employee share option plan, the Company may grant options to its employees up to 15,857,759 shares of common stock.  The exercise price of each option equals the volume-weighted average market price for the five days preceding the issue date of the Company's stock on the date of grant and the option's maximum term is five years.  Options are granted throughout the year and vest 1/3 on each of the first, second and third anniversaries from the date of grant.

 
Number of Options
Weighted Average
Exercise Price
Share options outstanding, January 1, 2010             8,610,000 $ 9.99
  Granted             3,407,000   17.88
  Exercised             (20,000)   8.00
Share options outstanding, December 31, 2010             11,997,000 $ 12.24
  Granted             3,768,024   28.53
  Exercised             (1,356,502)   9.24
  Forfeited             (194,999)   13.99
Share options outstanding, December 31, 2011             14,213,523 $ 16.82

The following table summarizes share options outstanding and exercisable at December 31, 2011:



Range of Exercise
Price

Number
Outstanding at
Year End
Weighted
Average
Remaining
Contractual Life
 
Weighted
Average
Exercise Price

Number
Exercisable at
Year End
  Weighted
Average
Exercise
Price
$7.00 - $8.00 3,006,167 1.90 $ 7.09 2,884,500 $ 7.05
$10.00 - $15.00 4,708,499 2.70   12.79 2,861,277   12.67
$16.68 - $32.78 6,498,857 4.25   24.24 849,500   18.33
  14,213,523 3.24 $ 16.82 6,595,277 $ 10.94

The fair value of options granted were estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions and resulting values:

    December 31, 2011   December 31, 2010
Fair value of options granted (weighted average) $ 10.05 $ 6.89
Risk-free interest rate   1.67%   2.43%
Estimated hold period prior to exercise   4 years   5 years
Expected volatility   40%   40%
Forfeiture rate   2%   2%
Dividend per share $ 0.00 $ 0.00

17. OTHER INCOME

  Years Ended December 31,
(000s)   2011   2010
Processing income     $             5,152 $             892
Interest income                   304               111
Other                   376               532
Total other income     $             5,832 $             1,535

18. FINANCE EXPENSES

  Years Ended December 31,
(000s)   2011   2010
Finance expenses:            
  Interest on loans and borrowings     $             3,874 $            1,085
  Transaction costs on corporate acquisitions                   991   561
  Accretion of provisions                   1,315   1,128
Total finance expenses     $             6,180 $ 2,774

19. SUPPLEMENTAL DISCLOSURES

Tourmaline's consolidated statement of income and comprehensive income is prepared primarily by nature of the expenses, with the exception of salaries and wages which are included in both the operating and general and administrative expense line items as follows:

  Years Ended December 31,
(000s)   2011   2010
Operating     $ 10,139 $ 5,906
General and Administrative                   6,497   5,201
Total employee compensation costs     $             16,636 $            11,107

20. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital is comprised of:

  Years Ended December 31,
(000s)   2011   2010
Source/(use) of cash:                
  Trade and other receivables     $             (2,130)     $             (13,540)
  Deposit and prepaid expenses                   (199)                   (1,904)
  Trade and other payables                   34,592                   87,450
                    32,263                   72,006
  Working capital (deficiency)/surplus acquired                   (3,897)                   100
      $             28,366     $             72,106
Related to operating activities     $             (12,931)     $             10,078
Related to investing activities     $             41,297     $             62,028

Cash interest paid was $1.9 million for the year ended December 31, 2011 (December 31, 2010 - nil).

21. COMMITMENTS

On March 8, 2011, the Company issued 1.58 million common shares on a flow-through basis at a price of $30.00 per share for total gross proceeds of $47.4 million.  As at December 31, 2011, the Company had spent the full committed amount.

On December 1, 2011, the Company issued 1.36 million common shares on a flow-through basis at a price of $41 per share for total gross proceeds of $55.8 million.  As of December 31, 2011, the Company has spent $1.0 million on eligible expenditures and is committed to spend the remainder of $54.8 million before December 31, 2012.

In the normal course of business, Tourmaline is obligated to make future payments.  These obligations represent contracts and other commitments that are known and non-cancellable:

Payments Due by Year
(000s)
 
2012
 
2013
 
2014
 
2015
  2016 and
thereafter
 
Total
Operating leases $ 2,587 $ 2,266 $ 2,121 $ 526 $ - $ 7,500
Flow-through obligations       54,777       -       -       -       -   54,777
Firm transportation agreements       26,415       25,394       16,880       8,067       375   77,131
Bank debt(1)       84,389       -       -       -       -   84,389
  $ 168,168 $ 27,660 $ 19,001 $ 8,593 $ 375 $ 223,797
(1) Includes interest expense at 3.23% being the rate applicable at December 31, 2011.

22. KEY MANAGEMENT PERSONNEL COMPENSATION

Key management personnel are persons who have the authority and responsibility for planning, directing and controlling the activities of the Company, directly or indirectly. Key management includes all directors and executives of the Company.  The table below summarizes all key management personnel compensation paid during the years ended December 31, 2011 and 2010. Non-executive directors do not receive short-term compensation.

Compensation of Key Management

  Years ended December 31,
(000s)   2011   2010
Short-term compensation(1)     $             1,561     $             1,467
Share-based payments(2)                   6,507                   5,875
Total compensation paid to key management     $             8,068     $             7,342
(1) Short-term compensation includes employee benefits provided to key management personnel.
(2)  Based on the grant date fair value of the applicable awards. The fair value of options granted are estimated at the date of grant using a Black-Scholes Option Pricing Model. The total share-based payment of options issued in 2011 is based on a weighted average fair value estimated to be $11.14 per option (2010- $7.02 per option).

23. SUBSEQUENT EVENT

On March 14, 2012, the Company announced that it entered into a private placement flow-through common share financing agreement.  The Company intends to issue 1,250,000 flow-through common shares at a price of $28.80 per share for gross proceeds of $36.0 million.  In addition, officers, directors and employees of Tourmaline will have the opportunity to purchase up to 140,000 flow-through common shares at a price of $28.80.  The proceeds will be used to fund the Company's 2012 capital exploration program.

24. RECONCILIATION OF THE FINANCIAL STATEMENTS FROM CANADIAN GAAP TO IFRS

Tourmaline's accounting policies under IFRS differ from those followed under previous GAAP.  These accounting policies have been applied for the year ended December 31, 2011, as well as, to the opening statement of financial position on the transition date January 1, 2010, and the comparative information for the year ended December 31, 2010.

The adjustments arising from the application of IFRS to amounts on the statement of financial position on the transition date and on transactions prior to that date, were recognized as an adjustment to the Company's opening deficit category on the statement of financial position when appropriate.

On transition to IFRS on January 1, 2010, Tourmaline used certain exemptions allowed under IFRS 1 "First Time Adoption of International Reporting Standards". The exemptions used were:

Full Cost Accounting - IFRS 1 allows an entity that used full cost accounting under its previous GAAP to elect, at the time of adoption to IFRS, to measure oil and gas assets in the development and production phases by allocating the amount determined under the entity's previous GAAP for those assets to the underlying assets pro rata using reserve volumes or reserve values as of that date. Tourmaline has used reserve values as at January 1, 2010 to allocate the cost of development and production assets to CGUs.

Business Combinations - IFRS 1 allows an entity to use the IFRS rules for business combinations on a prospective basis rather than re-stating all business combinations Tourmaline has elected to use this exemption.

Share-Based Compensation - IFRS1 allows an entity an exemption on IFRS 2, "Share-Based Payments" to equity instruments which vested before Tourmaline's transition date to IFRS.

Decommissioning Obligations - As Tourmaline elected to use the oil and gas exemption, a decommissioning obligation exemption was also used that allows for the re-measurement of decommissioning obligations on IFRS transition to be offset to retained earnings/(deficit).

In preparing its comparative information for the year ended December 31, 2010, the Company has adjusted amounts previously reported in its financial statements prepared in accordance with former Canadian GAAP. An explanation of how the transition from former Canadian GAAP to IFRS has affected the Company's financial position, financial performance and cash flows is set out in the following tables and the notes that accompany the tables.

Reconciliation of consolidated statement of financial position at the date of IFRS transition - January 1, 2010:


(000s)

Canadian GAAP
Effect of
Transition to IFRS

Note
 
IFRS
Assets              
Current assets:              
  Cash and cash equivalents $             199,789 $             -   $             199,789
  Accounts receivable                   45,129                   -                         45,129
  Prepaid expenses and deposits                   3,210                   -                         3,210
  Fair value of financial instruments                   324                   (204)     (j)                   120
                    248,452                   (204)                         248,248
Investments                   632                   -                         632
Exploration and evaluation assets                   -                   250,972     (a)                   250,972
Property, plant and equipment                   754,798                   (250,972)     (a)                   503,826
Deferred taxes                   -                   138                         138
  $             1,003,882 $             (66)   $             1,003,816
Liabilities and Shareholders' Equity                              
Current liabilities:                              
  Accounts payable and accrued liabilities $             86,938 $             -   $             86,938
Decommissioning obligations                   7,208                   11,945     (c)                   19,153
Deferred premium on flow-through shares                   -                   3,833     (k)                   3,833
Deferred taxes                   780                   (780)     (h)                   -
Shareholders' equity:                              
  Share capital                   895,095                   (4,143)     (d,k)                   890,952
  Non-controlling interest                   13,526                   -                         13,526
  Contributed surplus                   2,018                   6,529     (d)                   8,547
  Deficit                   (1,683)                   (17,450)     (c,d,k)                   (19,133)
                    908,956                   (15,064)                         893,892
  $             1,003,882 $             (66)   $             1,003,816

Reconciliation of consolidated statement of financial position as at December 31, 2010:


(000s)

Canadian GAAP
Effect of
Transition to IFRS

Note
 
IFRS
Assets          
Current assets:              
  Cash and cash equivalents $             65,160 $             -   $             65,160
  Accounts receivable               58,669               -                 58,669
  Prepaid expenses and deposits                   5,114                   -                     5,114
  Fair value of financial instruments                   14,413                   (14,413) (j)                   -
                    143,356                   (14,413)                     128,943
Investments                   3,932                   -                     3,932
Fair value of financial instruments                   1,601                   (1,601) (j)                   -
Exploration and evaluation assets                   -                   479,067 (a)                   479,067
Property, plant and equipment                   1,637,960                   (433,859) (a,c,e,f,g)                   1,204,101
  $             1,786,849 $             29,194   $             1,816,043
Liabilities and Shareholders' Equity                          
Current liabilities:                          
  Accounts payable and accrued liabilities $             178,113 $             -   $             178,113
  Fair value of financial instruments               -               472                 472
  Deferred taxes                   2,832                   (2,832) (h)                   -
                    180,945                   (2,360)                     178,585
Decommissioning obligations                   13,628                   21,651 (c,f)                   35,279
Long-term obligation                   14,589                   -                     14,589
Fair value of financial instruments                   -                   270                     270
Deferred premium on flow-through shares                   -                   348 (k)                   348
Deferred taxes                   25,457                   20,612 (h)                   46,069
Shareholders' equity:                          
  Share capital                   1,517,675                   (9,623) (d,k)                   1,508,052
  Non-controlling interest                   13,767                   142                     13,909
  Contributed surplus                   7,919                   21,343 (d)                   29,262
  Retained earnings/ (deficit)                   12,869                   (23,189) (c,d,e,f,g,h,k,l)                   (10,320)
                    1,552,230                   (11,327)                     1,540,903
  $             1,786,849 $             29,194   $             1,816,043

Reconciliation of consolidated statement of income for the year ended December 31, 2010:


(000s)

Canadian GAAP
Effect of
Transition to IFRS

Note
 
IFRS
Revenue:          
  Oil and natural gas sales $             194,928 $             -   $             194,928
  Royalties                   (15,630)                   -                 (15,630)
                    179,298                   -                 179,298
  Realized gain on financial instruments                   15,177                   -                 15,177
  Unrealized gain/ (loss) on financial instruments                   15,950                   (16,553) (j)               (603)
  Other income                   1,535                   -                 1,535
                    211,960                   (16,553)                 195,407
Expenses:                      
  Operating               41,352                   -                 41,352
  Transportation                   11,357                   -                 11,357
  General and administration                   6,831                   1,561 (l)               8,392
  Share-based payments               3,197                   7,191 (d)               10,388
  (Gain)/loss on divestiture                                    (2,082) (g)               (2,082)
  Depletion, depreciation and amortization                   126,985                   (30,325) (e)               96,660
Results from operating activities                   22,238                   7,102                 29,340
Finance expenses                   1,085                   1,689 (f,i)               2,774
Income before taxes                   21,153                   5,413                 26,566
  Deferred taxes                   6,360                   11,010 (h,k)               17,370
Net income/(loss) and net comprehensive
income/(loss) before non-controlling interest
                  14,793                   (5,597)                 9,196
Net income/(loss) and comprehensive
income/(loss) attributable to:
                     
  Shareholders of the Company                   14,552                   (5,739)                 8,813
  Non-controlling interest                   241                   142                 383
      $             14,793 $             (5,597)   $             9,196

NOTES TO THE RECONCILIATIONS

(a) IFRS 1 election for full cost oil and gas entities:

The Company elected to use an IFRS 1 exemption whereby the previous GAAP full cost pool was used to measure exploration and evaluation assets and development and production assets on transition to IFRS as follows:

(i) exploration and evaluation assets were reclassified from the full cost pool to intangible exploration assets at the amount that was recorded under previous GAAP; and

(ii) the remaining full cost pool was allocated to the producing/development assets and components pro rata using reserve values.

This resulted in a transfer of $251.0 million to exploration and evaluation assets and a corresponding decrease in property, plant and equipment on transition. As at December 31, 2010, the transfer was $479.1 million, which included undeveloped land acquired in 2010, geological and geophysical costs and costs related to wells in progress.

(b) Impairment of property, plant and equipment ("PP&E"):

In accordance with IFRS, impairment tests of PP&E must be performed at the CGU level as opposed to the entire PP&E balance which was required under the previous GAAP through the full cost ceiling test.  An impairment is recognized if the carrying value exceeds the recoverable amount for a CGU.  For Tourmaline, the recoverable amount is determined using fair value less cost to sell based on discounted future cash flow of proved plus probable reserves using forecast prices and costs. There was no impairment to PP&E on transition on January 1, 2010 or for the year ended December 31, 2010.

(c) Decommissioning obligations:

Under the previous GAAP, decommissioning obligations were discounted at a credit-adjusted risk-free rate of ten percent. Under IFRS, the estimated cash flow to abandon and remediate the wells and facilities has been risk adjusted therefore the provision is discounted at the risk-free rate in effect at the end of each reporting period. The change in the decommissioning obligations each period as a result of changes in the discount rate will result in an offsetting charge to PP&E. Upon transition to IFRS, the impact of this change was an $11.9 million increase in the decommissioning obligations with a corresponding increase to the deficit on the statement of financial position. As at December 31, 2010, the decommissioning obligations were $21.7 million higher than under the previous GAAP due to the change in discount rate and its impact on the liabilities incurred or acquired during 2010.  In addition, under the previous GAAP, accretion of the discount was included in depletion and depreciation expense. Under IFRS it is included in finance expenses.

(d) Share-based compensation:

Under the previous GAAP, the Company recognized an expense related to share-based compensation on a straight-line basis through the date of full vesting and did not incorporate a forfeiture rate at the grant date.

Under IFRS, the Company is required to calculate a volatility factor, recognize the expense over the individual vesting periods for the graded vesting awards and estimate a forfeiture rate at the date of grant and update it throughout the vesting period.

(e) Depletion policy:

Upon transition to IFRS, the Company adopted a policy of depleting oil and natural gas interests on a unit-of-production basis over proved-plus-probable reserves. The depletion policy under the previous GAAP was based on units of production over proved reserves. In addition, depletion was done on the Canadian cost centre under the previous GAAP.  IFRS requires depletion and depreciation to be calculated based on individual components.

There was no impact of this difference on adoption of IFRS at January 1, 2010 as a result of the IFRS 1 election as discussed in note (a) above.

Depleting the oil and natural gas interests over proved-plus-probable reserves resulted in a decrease to depletion and depreciation for the year ended December 31, 2010 of $30.3 million.

(f) Business combinations:

In accordance with IFRS, internal transaction costs incurred on a business combination are expensed. Under the previous GAAP, these costs were capitalized as part of the acquisition. As a result, $0.6 million was charged to other expenses for transaction costs incurred on the corporate acquisition for the year ended December 31, 2010.  In addition, the decommissioning obligations were re-measured under IFRS requirements.

(g) Gains and losses on divestitures:

Under previous GAAP, proceeds from divestitures were deducted from the full cost pool without recognition of a gain or loss unless the deduction resulted in a change in the depletion rate of 20 percent or greater, in which case a gain or loss was recorded. Under IFRS, gains and losses are recorded on divestitures and are calculated as the difference between the proceeds and the net book value of the asset disposed. For the year ended December 31, 2010, Tourmaline recognized a $2.1 million net gain on divestitures under IFRS compared to nil under the previous GAAP.

(h) Deferred income taxes:

The adjustment to deferred income taxes on transition relates to the opening adjustment to the decommissioning obligations, the adjustment to the unrealized gain or loss on financial instruments and the treatment of flow-through shares.  Adjustments to deferred income taxes have been made in regards to the adjustments resulting in a change to the temporary difference between tax and accounting values.  The deferred income tax impact of the opening adjustments was a deferred income tax asset of $0.9 million.

Under IFRS there is no requirement to separate the portion of deferred income taxes related to current assets or liabilities. The amounts previously classified as current have be reclassified to long-term.

(i) Finance expenses:

Under IFRS, a separate line item is required in the statement of income and comprehensive income for finance expenses. The items under the previous GAAP that were reclassified to finance expenses were interest, transaction costs on business combinations and financing expense, which included the accretion on the decommissioning obligations.

(j) Fair value of financial instruments:

Under previous GAAP, Tourmaline recognized the fair value of its futures contracts for physical delivery.  Those contracts do not meet the definition of a financial instrument under IFRS, resulting in the removal of the asset, liability and related charges to the income statement.

(k) Flow-through shares:

Under IFRS, proceeds from the issuance of flow-through shares are allocated between the sale of the shares, which are recorded in share capital, and the sale of the tax benefits, which are initially recorded as an accrued liability. The allocation is made based on the difference between the issue price of flow-through shares and the market price of the common shares on the date the offering is priced. The liability related to the sale of the tax benefits is reversed as qualifying expenditures intended for renunciation to subscribers are incurred, and a deferred tax liability is recorded. The difference between the deferred tax liability recorded and the liability related to the sale of tax benefits is recognized as deferred tax expense. Under previous GAAP, when flow-through shares were issued, they were recorded in share capital based on proceeds received. Upon filing the renunciation documents with the tax authorities, a future tax liability was recognized and share capital was reduced for the tax effect of expenditures renounced to subscribers.

The IFRS adjustment on transition date associated with flow-through shares was to decrease share capital by $4.0 million, decrease retained earnings by $1.9 million with $3.8 million going to the liability account "Deferred premium on flow-through shares" and to increase the deferred tax liability by $2.1 million.   For the year ended December 31, 2010 IFRS adjustments were made to decrease share capital by $5.1 million, reduce retained earnings by $8.3 million as a result of the increase to deferred income tax expense, decrease the liability account "Deferred premium on flow-through shares" by $3.5 million, and increase the deferred tax liability balance by $16.9 million.

(l) Capitalized general and administrative costs:

Under IFRS, the criteria for which general and administrative expenses ("G&A") can be capitalized are different than previous GAAP and as a result a greater portion of G&A costs have been expensed.  This resulted in an additional $1.6 million of G&A expenses for the year ended December 31, 2010.

(m)  Cash flow statement:

The transition from former Canadian GAAP to IFRS has had no material effect upon the reported cash flows generated by the Company.  For the year ended December 31, 2010, transaction costs of $0.6 million and general and administrative costs of $1.5 million were included in net income rather than capitalized and as such are now included in cash provided from operating activities.  These reconciling items between former Canadian GAAP presentation and the IFRS presentation have no net impact on the cash flow generated.

 

 About Tourmaline Oil Corp.

Tourmaline is a Canadian intermediate crude oil and natural gas exploration and production company focused on long-term growth through an aggressive exploration, development, production and acquisition program in the Western Canadian Sedimentary Basin.

 

 

 

 

 

 

For further information:

Tourmaline Oil Corp.

Michael Rose

Chairman, President and Chief Executive Officer

(403) 266-5992

OR

Tourmaline Oil Corp.

Brian Robinson

Vice-President, Finance and Chief Financial Officer

(403) 767-3587; robinson@tourmalineoil.com

OR

Tourmaline Oil Corp.

Scott Kirker

Secretary and General Counsel

(403) 767-3593; kirker@tourmalineoil.com

OR

Tourmaline Oil Corp.

Suite 3700, 250 - 6th Avenue S.W.

Calgary, Alberta T2P 3H7

Phone: (403) 266-5992

Facsimile: (403) 266-5952

Website: www.tourmalineoil.com