Tourmaline Oil Corp. Announces Record Year End 2012 Financial Results

CALGARY, ALBERTA–(Marketwire – March 19, 2013) – Tourmaline Oil Corp. (TSX:TOU) (“Tourmaline” or the “Company”) achieved exceptional growth in reserves (69%), production (64%) and cash flow⁽¹⁾ (16%) in 2012 while delivering strong profitability in a year of significantly lower natural gas prices. The Company posted strong after-tax earnings of $15.5 million for the 2012 fiscal year.

Highlights

• 2012 average production of 50,804 boepd represented a 64% increase over the 2011 average production of 31,007 boepd.
• Total proved plus probable (2P) reserve additions of 186.6 mmboe in 2012, representing 69% growth over 2011 total 2P reserves before 2012 production (54% per share). Similarly, proved reserves grew by 80% in 2012 over 2011 (63% per share).
• After-tax earnings of $15.5 million in 2012 despite an average realized natural gas price in 2012 of $2.67/mcf.
• Record annual cash flow of $280.3 million representing 16% growth over 2011 cash flow of $241.4 million.
• 2012 operating expenses of $4.43/boe – a 21% decrease over 2011 operating expenses of $5.58/boe. Fourth quarter 2012 operating expenses were $4.10/boe.
• Completed a $233.2 million equity financing on March 12, 2013.
• Completed the sale of the non-producing Elmworth property on March 12, 2013, for net proceeds of $77.5 million.
• Year-end 2012 2P reserve value of $4.3 billion (10% discount, before tax), representing 61% growth over year-end 2011 2P reserve value, despite a difficult gas price environment during the year and lower overall natural gas prices utilized in the 2012 independent reserve report. (Net Present Value increase in 2012 of $1.65 billion.)
• 2012 2P finding, development and acquisition costs (FD&A) of $10.35/boe including future development capital (FDC) and $5.80/boe excluding FDC – down from $13.34/boe in 2011 (including changes in FDC). 2012 total Proved FD&A costs were $14.06/boe (including FDC), down from $19.71/boe in 2011.
• Total year-end 2012 2P reserves of 438 mmboe after only four full years of operation.
• Drilled 76 gross wells in 2012, with a 100% success rate.

Production Update

Full year 2013 average production guidance was increased from 75,000 boepd to 80,000 boepd, on February 20, 2013. This will represent 57% growth over 2012 average production of 50,804 boepd. The Company expects to reach the 80,000 boepd level in early June when the new Doe gas plant is currently scheduled for start-up.

The new gas processing facility at Doe BC will bring approximately 10,000 – 11,000 boepd of shut-in Triassic Montney production on-stream. The gas handling facility expansion at Spirit River Alberta will bring approximately 2,000 boepd of currently shut-in Charlie Lake light oil and gas production on-stream in June. An additional 2,500-3,000 boepd of shut-in Charlie Lake production will come on-stream in late September through ongoing complementary pipeline/debottlenecking projects.

EP Update

The Company plans to continue operating 11 drilling rigs after break-up, with 2 rigs in NEBC pursuing the Triassic Montney, 2 at Spirit River pursuing the light oil charged Triassic Charlie Lake formation, and 7 in the Alberta Deep Basin pursuing Lower Cretaceous horizontal, liquid rich gas targets.

A total of 70 Deep Basin wells (60 horizontal and 10 vertical), 25 NEBC Montney horizontals and 25 Charlie Lake horizontals are expected for full year 2013.

Major 2013 facility projects include the ongoing Q2 gas facility projects at Doe BC and Spirit River Alberta and two, 50 mmcfpd gas facility expansions in the Alberta Deep Basin during the second half of 2013. Full year 2013 EP capital spending of $740.0 million is anticipated.

Liquids Production, Marketing and Transportation

Tourmaline is targeting the 15,000 bpd total liquid production level in Q4 2013, 70% of which is condensate and light oil.

In March of 2013, Tourmaline entered into certain short-and-long-term contracts to ensure stability of market price and access for the Company’s significant hydrocarbon liquids assets. These agreements include a 130 mmcfpd deep cut gas processing arrangement commencing in 2015, an associated liquids transportation agreement and a 9,000 bopd NGL product fractionation sale agreement.

The Company has a series of additional initiatives in place to manage the capture, transportation, storage, fractionation and the marketing of these liquids, both in the short and long-term.

In addition to participation in a third party deep cut plant, the Company is planning at least one owned-and-operated deep cut facility in the 2015 time frame.

Financial Update

Tourmaline is currently expecting 2013 cash flow of approximately $651.8 million based on production of 80,000 boepd and an AECO natural gas price of $3.66/mcf, representing 133% growth over 2012 cash flow.

Year-end 2012 net debt(2) was $464.3 million. During the first quarter of 2013 a $233.2 million equity financing closed on March 12, and the planned Elmworth disposition was completed. Net proceeds from the Elmworth disposition were $77.5 million; in addition $155 million of future capital will be removed from the 2P FDC account. Based on the $740.0 million capital program, the net proceeds from the equity financing and property disposition completed in March and the Company’s anticipated 2013 cash flow described above, the Company is forecasting 2013 exit net debt of $309.4 million, as the Company continues to strive to maintain a debt to cash flow ratio of 1.0 times or less.

Tourmaline’s unit cash cost(3) structure continued to improve during 2012 as full-year 2012 royalties fell to $1.63/boe – a 22% improvement; transportation costs fell to $1.87/boe – a 10% improvement; operating expenses were $4.43/boe – a 21% reduction; general and administrative costs dropped by 23% to $0.79/boe; and interest and financing charges increased to $0.70/boe – a change of 27%.

Tourmaline’s total unit cash costs of $9.42/boe dropped by 17% compared to 2011, providing amongst the lowest absolute cost structures in the industry. Similarly, Depletion, Depreciation and Amortization (“DD&A”) charges continued their steady trend downward for the third consecutive fiscal year to $13.04/boe – a 7% improvement over 2011.

Conference Call Tomorrow at 7:00 a.m. MT (9:00 a.m. ET)

Tourmaline will host a conference call tomorrow, March 20, 2013 starting at 7:00 a.m. MT (9:00 a.m. ET). To participate, please dial 1-866-226-1792 (toll-free in North America), or local dial-in 416-340-2216, a few minutes prior to the conference call.

The conference call ID number is 4159296.

Reader Advisories

Currency

All amounts in this news release are stated in Canadian dollars unless otherwise specified.

Reserves Data

The reserves data set forth above is based upon the reports of GLJ Petroleum Consultants Ltd. (“GLJ”) and Deloitte, each dated effective December 31, 2012, which have been consolidated into one report by GLJ and adjusted to apply certain of GLJ’s assumptions and methodologies and pricing and cost assumptions. The complete GLJ January 1, 2013 price forecast used in the reserve evaluations is available on its website at www.gljpc.com.

There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. The Company’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.

All evaluations and reviews of future net revenue are stated prior to any provisions for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. The after-tax net present value of the Company’s oil and gas properties reflects the tax burden on the properties on a stand-alone basis and utilizes the Company’s tax pools. It does not consider the corporate tax situation, or tax planning. It does not provide an estimate of the after-tax value of the Company, which may be significantly different. The Company’s financial statements and the management’s discussion and analysis should be consulted for information at the level of the Company.

The estimated values of future net revenue disclosed in this news release do not represent fair market value. There is no assurance that the forecast prices and cost assumptions used in the reserve evaluations will be attained and variances could be material.

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, 2012, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 30, 2013.

Per share reserve information is based on the total common shares outstanding, after accounting for outstanding Company options, at year end 2012 and 2011, respectively.

See also the Company’s news release dated February 12, 2013 for more information with respect to the Company’s reserves data.

F&D and FD&A Costs

In addition to F&D, the Company uses FD&A as a measure of the efficiency of its overall capital program including the effect of acquisitions and dispositions. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

Financial Outlook

Also included in this news release are estimates of Tourmaline’s 2013 cash flow, which is based on, among other things, the various assumptions as to production levels, capital expenditures, and other assumptions disclosed in this news release and including Tourmaline’s estimated 2013 average production of 80,000 boepd and commodity price assumptions for natural gas (AECO – $3.66/mcf) (2013), and crude oil (WTI (US) – $95.00/bbl) (2013) and an exchange rate assumption of $1.00 (US/CAD) for 2013. To the extent such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Tourmaline on March 19, 2013 and is included to provide readers with an understanding of Tourmaline’s anticipated cash flow based on the capital expenditure, production and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.

General

See also “Forward-Looking Statements”, “Boe Conversions” and “Non-GAAP Financial Measures” in the attached Management’s Discussion and Analysis.

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the years ended December 31, 2012 and December 31, 2011

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 2012 and 2011. Both the consolidated financial statements and the MD&A can be found at www.sedar.com. This MD&A is dated March 19, 2013.

The financial information contained herein has been prepared in accordance with International Financial Reporting Standards (“IFRS”) and sometimes referred to in this MD&A as Generally Accepted Accounting Principles (“GAAP”) as issued by the International Accounting Standards Board (“IASB”). 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-GAAP Financial Measures” for information regarding the following non-GAAP financial measures used in this MD&A: “cash flow”, “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, expenses, production, cash flow and 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, 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 size of, and future net revenues and cash flow from, crude oil, NGL (natural gas liquids) and natural gas reserves; future prospects; the focus of 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 fluctuation; imprecision of reserve estimates; liabilities inherent in crude oil and natural gas 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; 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; 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 shareholders 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 for the fourth quarter of 2012 averaged 57,230 Boe/d, a 51% increase over the average production for the same quarter of 2011 of 37,912 Boe/d. Production was 88% natural gas weighted in the fourth quarter of 2012, which is consistent with the fourth quarter of 2011. For the year ended December 31, 2012, production increased 64% to 50,804 Boe/d from 31,007 Boe/d in 2011.

The Company’s significant production growth when compared to 2011 can be primarily attributed to new wells that have been brought on-stream in 2012, as well as property and corporate acquisitions completed during the year.

Production guidance for 2013 is 80,000 Boe/d, an increase from the previous target of 75,000 Boe/d (as disclosed by press release November 8, 2012). The production increase is a direct result of Tourmaline’s continued success in the ongoing exploration and production program, as well as the planned commissioning of facilities in the Doe and Sunrise areas which will allow shut-in production to come on-stream.

Revenue for the three months ended December 31, 2012 increased 33% to $143.1 million from $107.9 million for the same quarter of 2011. Revenue for the year ended December 31, 2012 increased 24% to $449.8 million from $363.0 million in 2011. Revenue growth is consistent with the increase in production over the same periods, partially offset by lower realized commodity prices. Revenue includes all natural gas, petroleum and NGL sales and realized gains on financial instruments.

The realized average natural gas prices for the quarter and year ended December 31, 2012 were 13% and 36%, respectively, lower than the same periods of the prior year. Realized crude oil and NGL prices decreased 10% and 7% for the quarter and year ended December 31, 2012, respectively, compared to the same periods of the prior year.

The realized natural gas price for the quarter ended December 31, 2012 was $3.29/mcf, which is 3% (three months ended December 31, 2011 – 18%) higher than the AECO index price. The Company receives a premium to the AECO index on its Alberta Deep Basin natural gas production to reflect a higher heat content, which has remained consistent year-over-year (December 31, 2012 – 8% and December 31, 2011 – 7%). In 2012, this premium was partially offset by losses on commodity contracts.

The realized natural gas price for the year ended December 31, 2012 was 10% (December 31, 2011 – 16%) higher than the AECO index as Tourmaline realized a gain on commodity contracts in combination with the higher heat content noted above. Realized prices exclude the effect of unrealized gains or losses. Once these gains and losses are realized they are included in the per unit amounts.

For the quarter ended December 31, 2012, the average effective royalty rate was 7.5% compared to 7.0% for the same quarter of 2011. For the year ended December 31, 2012, the average effective royalty rate was 6.7% compared to 6.5% for the same period of 2011. The Company continues to benefit from the New Well Royalty Reduction Program and the Natural Gas Deep Drilling Program in Alberta as well as the Deep Royalty Credit Program in British Columbia.

The Company expects its royalty rate for 2013 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 coming off royalty holidays, thereby increasing the Company’s overall royalty rate. The royalty rate is sensitive to commodity prices, however, and as such, a change in commodity prices will impact the actual rate.

OTHER INCOME

For the quarter ended December 31, 2012, other income totaled $1.4 million, all of which pertained to processing income, compared to $2.4 million of other income for the same quarter of 2011, of which $2.3 million related to processing income. Processing income has been decreasing as a smaller amount of third-party production has been processed in Tourmaline owned-and-operated facilities as the Company grows the amount of its own production, thus reducing capacity for third-party volumes. For the year ended December 31, 2012, other income was $5.0 million compared to $5.8 million for the prior year.

Operating expenses include all periodic lease and field-level expenses and exclude income recoveries from processing third-party volumes. For the fourth quarter of 2012, total operating expenses increased 20% from $18.0 million in the fourth quarter of 2011 to $21.6 million in 2012 due to the increased variable costs relating to new production. On a per-Boe basis, the costs decreased 21% from $5.17/Boe for the fourth quarter of 2011 to $4.10/Boe in the fourth quarter of 2012 due to increased production, increased operational efficiencies and the impact of redirecting natural gas from third-party facilities to Tourmaline-owned infrastructure. Tourmaline’s operating expenses in the fourth quarter of 2012 include third-party processing, gathering and compression fees of approximately $5.7 million or $1.09/Boe (December 31, 2011- $5.9 million or $1.68/Boe).

For the year ended December 31, 2012, total operating expenses were $82.3 million, or $4.43/Boe, compared to $63.1 million, or $5.58/Boe for the same period of 2011. Although total operating expenses increased with production, the costs per Boe decreased 21% reflecting increased operational efficiencies. Third-party processing, gathering and compression fees for the year ended December 31, 2012 have increased year-over-year with production ($21.7 million in 2012 versus $19.1 million in 2011); however, the cost per Boe has decreased to $1.17/Boe in 2012 versus $1.68/Boe in 2011.

In September 2012, the Company completed its plant expansion at Musreau in the Alberta Deep Basin. During 2012, the Company also began work on a gas plant at Doe in NEBC and a new liquids handling facility at Spirit River. 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 $4.25/Boe in 2013. This is lower than the previous year’s guidance due to a combination of increased production, continued operational efficiencies and redirecting third-party gas into Company owned-and-operated facilities. Actual costs per Boe can change, however, depending on a number of factors, including the Company’s actual production levels.

Transportation costs for the three months ended December 31, 2012 were $9.8 million or $1.86/Boe (three months ended December 31, 2011 – $7.8 million or $2.24/Boe). Transportation costs for the year ended December 31, 2012 were $34.7 million or $1.87/Boe (year ended December, 2011 – $23.4 million or $2.06/Boe). The increase in total transportation costs for the three months and the year ended December 31, 2012 can be primarily attributed to increased production. Oil and liquids transportation costs have increased due to pipeline and infrastructure constraints resulting in a higher use of more expensive truck transportation.

On a per-Boe basis, transportation costs for the three months and year ended December 31, 2012 are lower primarily due to the expansion of the Company’s owned-and-operated Sunrise and Musreau plants which allows increased volumes to be processed at these facilities which are closer to the Company’s producing assets than the previous third-party facilities.

G&A expenses for the fourth quarter of 2012 were $4.1 million compared to $2.9 million for the same quarter of the prior year. G&A costs per Boe for the fourth quarter of 2012 decreased 6% down to $0.77/Boe, compared to $0.82/Boe for the fourth quarter of 2011.

For the year ended December 31, 2012, G&A expenses were $14.6 million or $0.79/Boe compared to $11.5 million or $1.02/Boe for the same period of 2011. The higher total G&A expenses from 2011 to 2012 result from the need to manage the larger production, reserve and land base. Additionally, the administrative and capital recoveries from joint venture partners have decreased as the Company’s overall working interest has increased. 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 for 2013 are expected to be similar to 2012 on a dollar-per-Boe basis. Actual costs per Boe can change, however, depending on a number of factors including the Company’s actual production levels.

Tourmaline uses the fair value method for the determination of non-cash related share-based payments expense. During the fourth quarter of 2012, 1,927,000 stock options were granted to employees, officers, directors and key consultants at a weighted-average exercise price of $32.00, and 683,799 options were exercised, bringing $6.8 million of cash into treasury. The Company recognized $3.9 million of share-based payment expense in the fourth quarter of 2012 compared to $3.1 million in the fourth quarter of 2011. Capitalized share-based payments expense for the fourth quarter of 2012 was $3.9 million compared to $3.1 million for the same quarter of the prior year.

For the year ended December 31, 2012, share-based payment expense totalled $14.9 million and a further $14.9 million in share-based payments were capitalized (2011 – $11.7 million and $11.7 million, respectively). The increase in share-based payment expense in 2012 compared to 2011 reflects the increased number of options outstanding.

DD&A expense was $66.0 million for the fourth quarter of 2012 compared to $41.2 million for the same period of 2011 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 2012 was $12.53/Boe compared to $11.82/Boe for the fourth quarter of 2011.

For the year ended December 31, 2012, DD&A expense was $242.5 million (December 31, 2011 – $158.2 million) with an effective rate of $13.04/Boe (December 31, 2011 – $13.98/Boe). The lower DD&A rate in 2012 reflects strong reserve additions derived from Tourmaline’s exploration and production program, coupled with lower finding and development costs in 2012 versus those incurred in 2011.

Finance expenses totalled $4.4 million and $13.0 million for the quarter and year ended December 31, 2012, respectively (December 31, 2011 – $1.1 million and $6.2 million, respectively) and are comprised of interest expense, transaction costs on corporate and property acquisitions and accretion of decommissioning obligations. The increased finance expenses are largely due to higher interest expense resulting from a higher balance drawn on the credit facility in 2012. The average bank debt outstanding and the average effective interest rate on that debt during 2012 were $245.4 million and 3.34%, respectively (2011 – $54.7 million and 3.3% respectively).

Cash flow for the three months ended December 31, 2012 was $93.8 million or $0.54 per diluted share compared to $73.3 million or $0.45 per diluted share for the same period of 2011. For the year ended December 31, 2012, cash flow was $280.3 million or $1.68 per diluted share, which is higher than the December 31, 2011 cash flow of $241.4 million or $1.58 per diluted share. Cash flow in 2012 reflects increased production over 2011 offset by lower natural gas prices.

The Company had after-tax earnings for both the three months and year ended December 31, 2012 of $16.3 million ($0.09 per diluted share) and $15.5 million ($0.09 per diluted share), respectively, compared to earnings of $16.1 million ($0.10 per diluted share) and $42.7 million ($0.28 per diluted share), respectively, for the same periods of 2011. The decreased after-tax earnings for the 2012 year, compared to 2011, reflect lower natural gas prices.

During the fourth quarter of 2012, the Company invested $296.1 million of cash consideration, net of dispositions, compared to $232.2 million for the same period of 2011. Expenditures on exploration and production were $211.1 million compared to $222.5 million for the same quarter of 2011.

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

Capital expenditures in 2013 are forecast to be $740 million, which has been revised upward from $650 million (as previously disclosed by press release November 8, 2012). A total of 70 Deep Basin wells, 25 NEBC Montney horizontal wells and 25 Charlie Lake horizontal wells are expected to be drilled in 2013. Major 2013 facility projects include the completion of the gas facilities at Doe in NEBC and Spirit River, Alberta (planned to be completed in the second quarter) and two gas facility expansions in the Alberta Deep Basin during the second half of 2013.

Corporate Acquisition

On November 30, 2012, the Company acquired all of the issued and outstanding shares of Huron Energy Corporation (“Huron”) in exchange for Tourmaline common shares. The acquisition resulted in an increase to Property, Plant and Equipment (“PP&E”) of approximately $251.5 million and an increase to Exploration and Evaluation (“E&E”) assets of $59.1 million. The acquisition of Huron provides for an increase in lands and production in Tourmaline’s key highly profitable core and designated growth area of Sunrise in NEBC.

LIQUIDITY AND CAPITAL RESOURCES

On April 4, 2012, the Company issued 1.4 million flow-through common shares at a price of $28.80 per share for total gross proceeds of $40.4 million. On August 30, 2012, the Company issued 4.039 million common shares at a price of $29.00 per share for total gross proceeds of $117.1 million. Subsequently, on September 19, 2012, the underwriters exercised their over-allotment option and purchased a further 0.6 million shares at a price of $29.00 per share for total gross proceeds of $17.4 million. On November 1, 2012, the Company issued 1.05 million flow-through common shares at a price of $36.90 per share for total gross proceeds of $38.7 million. The proceeds of the above-noted financings were used to temporarily reduce bank debt and to fund the Company’s capital exploration program.

In June 2012, the Company amended and restated its bank credit facility to be a covenant-based facility rather than a borrowing base facility. This facility is a 3-year extendible revolving facility in the amount of $550 million plus a $25 million operating revolver from a syndicate of six lenders with an initial maturity date of June, 2015. The maturity date may, at the request of the Company and with the consent of the lenders, be extended on an annual basis. The facility is secured by a first ranking floating charge over all assets of the Company and its material subsidiaries. The facility can be drawn in either Canadian or U.S. funds and bears interest at the bank’s prime lending rate, bankers’ acceptance rates or LIBOR (for U.S. borrowings), plus applicable margins. The facility will provide the Company with greater flexibility by providing access to an additional $200 million over the previous facility.

Under the terms of the bank credit facility, Tourmaline has provided its covenant that, on a rolling four quarter basis: (i) the ratio of EBITDA to interest expense shall equal or exceed 3.5:1, (ii) the ratio of senior debt to EBITDA shall not exceed 3:1, (iii) the ratio of total debt to EBITDA shall not exceed 4:1, and (iv) the ratio of senior debt to total capitalization shall not exceed 0.5:1. As at December 31, 2012, the Company is in compliance with all debt covenants.

At December 31, 2012, Tourmaline had negative working capital of $103.7 million, after adjusting for the fair value of financial instruments (the unadjusted working capital deficiency was $98.9 million) (December 31, 2011 – $146.6 million and $146.3 million, respectively). Management believes the Company has sufficient liquidity and capital resources to fund the 2013 exploration and development program through expected cash flow from operations, its unutilized bank credit facility and the financing described in the subsequent events section of this MD&A. As at December 31, 2012, the Company’s bank debt balance was $360.6 million (December 31, 2011 – $81.7 million), and net debt was $464.3 million (December 31, 2011 – $228.3 million).

SHARES AND STOCK OPTIONS OUTSTANDING

As at March 19, 2013, the Company has 182,230,907 common shares outstanding and 14,617,384 stock 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.

Subsequent to December 31, 2012, the Company entered into a 130 mmcf/d deep cut gas processing agreement and a firm service transportation agreement for the associated liquids. Both agreements have ten-year terms and begin in 2015. The Company also entered into a ten-year 9,000 bbl/d natural gas liquids product fractionation marketing agreement beginning in 2016.

OFF BALANCE SHEET ARRANGEMENTS

The Company has certain lease arrangements, all of which are reflected in the commitments and contractual obligations table, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or general and administrative expenses depending on the nature of the lease.

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 note 5 of the Company’s consolidated financial statements for the year ended December 31, 2012.

As at December 31, 2012, 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. Such financial derivative 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 contracts that the Company has entered into in the 2012 year are detailed in note 5 of the Company’s consolidated financial statements for the year ended December 31, 2012.

The following table provides a summary of the unrealized gains and losses on financial instruments for the year ended December 31, 2012:

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 year ended December 31, 2012.

The Company has entered into several financial derivative and physical delivery sales contracts subsequent to December 31, 2012. These contracts are detailed in note 5 of the Company’s consolidated financial statements for the year ended December 31, 2012.

SUBSEQUENT EVENTS

On March 12, 2013, the Company closed on the disposition of a non-producing property for proceeds of $77.5 million, subject to closing adjustments and transaction costs. The asset has been reclassified to current as an asset held for sale as at December 31, 2012.

On March 12, 2013, the Company issued 5.78 million common shares, at a price of $34.25 per share, and 0.835 million flow-through common shares, at a price of $42.15 per share, for total gross proceeds of $233.2 million.

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 1 of the consolidated financial statements for the year ended December 31, 2012.

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”), as defined by National Instrument 52-109 – Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”), 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”), as defined by NI 52-109, 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 GAAP.

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company’s DC&P and ICFR. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as at December 31, 2012, 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, 2012 and ending December 31, 2012 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.

RECENT PRONOUNCEMENTS ISSUED

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

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 became effective on July 1, 2012.

NON-GAAP FINANCIAL MEASURES

This MD&A includes references to financial measures commonly used in the oil and gas industry such as “cash flow”, “operating netback”, “working capital (adjusted for the fair value of financial instruments)” and “net debt”, which do not have any standardized meaning prescribed by GAAP. Management believes that in addition to net income and cash flow from operating activities, the aforementioned non-GAAP financial measures 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 GAAP 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 cash flow as cash flow from operating activities 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).

Cash Flow

A summary of the reconciliation of cash flow from operating activities (per the statement of cash flow), to cash flow, is set forth below:

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:

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:

Net Debt

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

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.

Overall, the Company has had continued annual growth over the last two years summarized in the table above. The small decrease in production from the second quarter to the third quarter of 2012 was due to weather-related tie-in delays, as well as production disruptions related to sour gas handling issues at Spirit River and a one-time equipment issue at Sunrise. The Company’s average annual production has increased from 31,007 Boe per day in 2011 to 50,804 Boe per day in 2012. The production growth can be attributed primarily to the Company’s exploration and development activities, as well as from acquisitions of producing properties. Over the same period, natural gas prices have declined, with the largest declines occurring in 2012.

The Company’s cash flows from operating activities were $228.4 million in 2011 and $273.5 million in 2012. 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.

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 Company’s exploration and development activities and from the acquisition of producing properties.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2012 and 2011

(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 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 Suite 2400, 525 – 8th Avenue S.W., Calgary, Alberta T2P 1G1.

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”).
The consolidated financial statements were authorized for issue by the Board of Directors on March 19, 2013.

(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) 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.

(ii) Impairment of petroleum and natural gas assets:

Judgements are required to assess when impairment indicators exist and impairment testing is required. 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) Deferred taxes:

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.

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) 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) 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.

(iii) 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.

(iv) Deferred 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.

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.

(a) Consolidation:

The consolidated financial statements include the accounts of Tourmaline Oil Corp., Exshaw Oil Corp., of which the Company owns 90.6% (note 10), and Huron Energy Corporation, 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) 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.

(iii) 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.

(b) Financial instruments:

(i) Non-derivative financial instruments:

Non-derivative financial instruments comprise accounts receivable, cash and cash equivalents, investments, bank overdrafts, bank debt, and accounts payable and accrued liabilities. 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, and are measured similar to other non-derivative financial instruments.

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 accounts receivable, bank debt, and accounts payable and accrued liabilities, are measured at amortized cost using the effective interest method, less any impairment losses. The bank debt has a floating rate of interest and therefore the carrying value approximates the fair value.

(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 property, plant and equipment to the following CGUs: ‘Deep Basin’, ‘Spirit River’ and ‘BC Montney’. 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:

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. Fair value less costs to sell is determined as the amount that would be obtained from the sale of an asset in an arm’s length transaction between knowledgeable and willing parties.

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 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. 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) Deferred 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 liability. 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.

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 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, accounts receivable, bank debt and accounts payable and accrued liabilities:

The fair value of cash and cash equivalents, accounts receivable, bank debt and accounts payable and accrued liabilities is estimated as the present value of future cash flow, discounted at the market rate of interest at the reporting date. At December 31, 2012 and December 31, 2011, 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, 2012 and December 31, 2011. 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.

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, 2012, Tourmaline’s receivables consisted of $22.7 million (December 31, 2011 – $9.7 million) from joint venture partners, $52.8 million (December 31, 2011 – $40.1 million) from petroleum and natural gas marketers and $8.4 million (December 31, 2011 – $11.0 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 2012, Tourmaline had two 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, 2012, the Company had $1.1 million (December 31, 2011 – $0.6 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, 2012 (December 31, 2011 – nil) and did not provide for any doubtful accounts nor was it required to write-off any receivables during the year ended December 31, 2012 (December 31, 2011 – 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, 2012 is approximately $225.9 million (December 31, 2011 – $212.7 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, 2012, 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, 2012:

(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, 2012. 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, 2012 would have decreased or increased shareholders’ equity and net income by $1.8 million, and $0.4 for 2011. 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.

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, 2012, 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, 2012:

As at December 31, 2012, if the future strip prices for oil were $1.00 per bbl higher and prices for natural gas were $0.10 per mcf higher, with all other variables held constant, before-tax earnings would have been $1.3 million (December 31, 2011 – $0.3 million) lower. An equal and opposite impact would have occurred to before-tax earnings and the fair value of the derivative contracts liability if oil prices were $1.00 per bbl lower and gas prices were $0.10 per mcf 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.

On May 29, 2012, the Company entered into an interest rate swap. The following table outlines the realized and unrealized losses on the interest rate contract recorded on the consolidated statement of income and comprehensive income for the year ended December 31, 2012:

The following table provides a summary of the unrealized gains (losses) on financial instruments for the years ended December 31, 2012 and 2011:

The following contracts were entered into subsequent to December 31, 2012 and are therefore not reflected in the consolidated statements of income and comprehensive income:

The Company has entered into the following physical contracts as at December 31, 2012:

The Company has entered into the following physical contracts subsequent to December 31, 2012:

(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 to cash annualized flow, which is defined as long-term bank debt plus working capital (adjusted for the fair value of financial instruments), to annualized cash flow, defined as cash flow from operating activities before changes in non-cash working capital. Net debt to annualized cash flow 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 cash flow 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, 2012, the Company’s ratio of net debt to annualized cash flow was 1.24 to 1.0.

The Company has not paid or declared any dividends since the date of incorporation, nor are any contemplated in the foreseeable future. There have been no changes in the Company’s approach to capital management since December 31, 2011.

6. EXPLORATION AND EVALUATION ASSETS

General and administrative expenditures for the year ended December 31, 2012 of $5.2 million (December 31, 2011 – $8.2 million) have been capitalized and included as exploration and evaluation assets. Non-cash share-based payment expense in the amount of $5.8 million (December 31, 2011 – $9.4 million) were also capitalized and included in exploration and evaluation assets.

7. PROPERTY, PLANT AND EQUIPMENT

Cost

Accumulated Depletion, Depreciation and Amortization

Net Book Value

General and administrative expenditures for the year ended December 31, 2012 of $6.1 million (December 31, 2011 – $1.8 million) have been capitalized and included as costs of oil and natural gas properties. Also included in oil and natural gas properties is non-cash share-based payment expense of $9.1 million (December 31, 2011 – $2.3 million).

Future development costs for the year ended December 31, 2012 of $2,233 million (December 31, 2011 – $1,539 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 costs 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, 2012 on the Company’s PP&E assets using a pre-tax discount rate of 10% and the following forward commodity price estimates:

There was no impairment to PP&E at December 31, 2012 (December 31, 2011 – nil).

Corporate Acquisitions

Huron Energy Corporation

On November 30, 2012, the Company acquired all of the issued and outstanding shares of Huron Energy Corporation. (“Huron”). As consideration, the Company issued 7,401,682 common shares at a price of $33.02 per share. Total transaction costs incurred by the Company of $1.0 million associated with this acquisition were expensed in the consolidated statement of income and comprehensive income.

The acquisition of Huron provided for an increase in lands and production in Tourmaline’s core and designated growth area of Sunrise, NEBC.

Results from operations for Huron 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 August 31, 2012 by independent reserve engineers using proved plus probable reserves discounted at a rate of 10% and updated internally to the date of the corporate acquisition of November 30, 2012. 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:

Included in the consolidated statements of income and comprehensive income for the year ended December 31, 2012 are the following amounts relating to Huron Energy Corporation since November 30, 2012:

If Tourmaline had acquired Huron on January 1, 2012, the pro-forma results of the oil and gas sales and net income for the year ended December 31, 2012 would have been as follows:

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:

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:

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:

Acquisition of Oil and Natural Gas Properties

For the year ended December 31, 2012, the Company completed property acquisitions for total cash consideration of $88.6 million (before adjustments) (December 31, 2011 – $115.2 million) and an additional $5.3 million in non-cash consideration (December 31, 2011 – $0.9 million). The Company also assumed $4.2 million in decommissioning liabilities (December 31, 2011 – $1.8 million).

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 $92.7 million (December 31, 2011 – $72.5 million), with some abandonments expected to commence in 2021. A risk-free rate of 2.49% (December 31, 2011 – 2.49%) and an inflation rate of 2.0% (December 31, 2011 – 2.0%) were used to calculate the fair value of the decommissioning obligations.

9. BANK DEBT

In June 2012, the Company amended and restated its bank credit facility to a covenant-based facility rather than a borrowing base facility. This facility is a three-year extendible revolving facility in the amount of $550 million plus a $25 million operating revolver from a syndicate of lenders with an initial maturity date of June 2015. The maturity date may, at the request of the Company and with the consent of the lenders, be extended on an annual basis. The facility is secured by a first ranking floating charge over all assets of the Company and its material subsidiaries. The facility can be drawn in either Canadian or U.S. funds and bears interest at the bank’s prime lending rate, bankers’ acceptance rates or LIBOR (for U.S. borrowings), plus applicable margins, which range from 2.00 to 3.25 percent over bankers’ acceptance rates depending on the Company’s senior debt to EBITDA ratio.

Under the terms of the bank credit facility, Tourmaline has provided its covenant that, on a rolling four quarter basis: (i) the ratio of EBITDA to interest expense shall equal or exceed 3.5:1, (ii) the ratio of senior debt to EBITDA shall not exceed 3:1, (iii) the ratio of total debt to EBITDA shall not exceed 4:1, and (iv) the ratio of senior debt to total capitalization shall not exceed 0.5:1. As at December 31, 2012, the Company is in compliance with all debt covenants.

As at December 31, 2012, Tourmaline’s bank debt balance was $360.6 million (December 31, 2011 – $81.7 million). In addition, Tourmaline has outstanding letters of credit of $4.4 million (December 31, 2011 – $3.6 million), which reduce the credit available on the facility.

10. 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:

11. 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

12. DEFERRED TAXES

The provision for deferred 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:

The movement in deferred tax balances during the years ended December 31, 2012 and 2011 is as follows:

As at December 31, 2012, the Company has estimated federal tax pools of $2.7 billion (2011 – $2.1 billion) available for deduction against future taxable income.

13. EARNINGS PER SHARE

Basic earnings per share was calculated as follows:

Diluted earnings per share was calculated as follows:

There were 6,147,524 options excluded from the weighted-average share calculation for the year ended December 31, 2012 because they were anti-dilutive (December 31, 2011 – 3,568,024).

14. SHARE-BASED PAYMENTS

The Company has a rolling stock option plan. Under the employee stock option plan, the Company may grant options to its employees up to 17,481,306 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.

The following table summarizes stock options outstanding and exercisable at December 31, 2012:

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

15. OTHER INCOME

16. FINANCE EXPENSES

17. 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:

18. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital is comprised of:

Cash interest paid was $11.8 million for the year ended December 31, 2012 (December 31, 2011 – $1.9 million).

19. COMMITMENTS

On April 4, 2012, the Company issued 1.4 million common shares on a flow-through basis at a price of $28.80 per share for gross proceeds of $40.4 million. As of December 31, 2012, the Company has spent $36.5 million on eligible expenditures and is committed to spend the remaining $3.9 million before December 31, 2013.

On November 1, 2012, the Company issued 1.05 million common shares on a flow-through basis at a price of $36.90 per share for gross proceeds of $38.7 million. The Company has not incurred any eligible expenditures pertaining to this issuance as at December 31, 2012 and is committed to spend the entire $38.7 million before December 31, 2013.

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:

Subsequent to December 31, 2012, the Company entered into a 130 mmcf/d deep cut gas processing agreement and a firm service transportation agreement for the associated liquids. Both agreements have ten-year terms and begin in 2015. The Company also entered into a ten-year 9,000 bbl/d natural gas liquids product fractionation marketing agreement beginning in 2016.

20. 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, 2012 and 2011. Non-executive directors do not receive short-term compensation.

Compensation of Key Management

21. SUBSEQUENT EVENTS

On March 12, 2013, the Company closed on the disposition of a non-producing property for proceeds of $77.5 million, subject to closing adjustments and transaction costs. The asset has been reclassified to current as an asset held for sale as at December 31, 2012.

On March 12, 2013, the Company issued 5.78 million common shares, at a price of $34.25 per share, and 0.835 million flow-through common shares, at a price of $42.15 per share, for total gross proceeds of $233.2 million.

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.

Contact Information

Tourmaline Oil Corp.
Michael Rose
Chairman, President and Chief Executive Officer
(403) 266-5992

Tourmaline Oil Corp.
Brian Robinson
Vice President, Finance and Chief Financial Officer
(403) 767-3587
robinson@tourmalineoil.com

Tourmaline Oil Corp.
Scott Kirker
Secretary and General Counsel
(403) 767-3593
kirker@tourmalineoil.com

Tourmaline Oil Corp.
Suite 3700, 250 – 6th Avenue S.W.
Calgary, Alberta T2P 3H7
(403) 266-5992
(403) 266-5952 (FAX)
www.tourmalineoil.com