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Tourmaline Oil Corp. Earns $488.9 Million in 2014

March 9, 2015 2:00 PM
Marketwired

CALGARY, AB–(Marketwired – March 09, 2015) – Tourmaline Oil Corp. (TSX: TOU) (“Tourmaline” or the “Company”) achieved exceptional growth in reserves (45%), production (51%) and cash flow(1) (76%) in 2014 while delivering strong profitability. The Company posted record after-tax earnings of $488.9 million for the 2014 fiscal year.

HIGHLIGHTS

  • Record full year after-tax earnings of $488.9 million ($2.41 per diluted share), a 230% increase over 2013, underscoring the fundamental full-cycle profitability of Tourmaline’s natural gas business.
  • Included in the full year 2014 earnings is a one-time pre-tax gain of $266.2 million on the disposition of 25% of the Company’s Peace River High Charlie Lake resource play for gross proceeds of $500.0 million.
  • Industry-leading financial position with year end net debt(2) of $1.1 billion, 1.2 times debt to trailing cash flow or 1.1 times debt to forecast 2015 cash flow.
  • 2014 cash flow of $929.0 million ($4.58 per diluted share), a 76% increase over 2013 (64% per diluted share).
  • 2014 annual production growth of 51% (40% per diluted share), and forecast 2015 production growth of 46% over 2014.
  • Q4 2014 average production of 130,944 boepd, a 52% increase over the fourth quarter of 2013 and a 21% increase over the previous quarter.
  • Current production ranging between 145,000 – 150,000 boepd. The Company presently expects to achieve the 2015 average production target of 164,500 boepd in late April 2015.
  • 2014 average operating netback(3) of $23.35/boe.
  • Continued industry-leading all-in cost structure of $8.07/boe (operating costs, transportation, general and administrative, and financing costs).
  • Q4 2014 operating costs were $4.07/boe, down 25% from Q3 2014. The Company is forecasting 2015 operating costs in the range of $4.25 – $4.35/boe, down from 2014 average operating costs of $4.87.
  • Total 2P reserve additions of 307.0 mmboe in 2014 (179.4 mmboe 2013), representing 52% growth over 2013 total 2P reserves before 2014 production (45% per diluted share).
  • Year end 2014 2P reserve value of $7.7 billion (10% discount, before tax), representing 24% growth over year end 2013 2P reserve value of $6.2 billion, a net present value increase in 2014 of $1.5 billion.
  • 2014 2P finding, development and acquisition costs (“FD&A”) including future development costs (“FDC”) were $10.40/boe, 12% lower than 2013 FD&A including FDC costs ($11.84/boe).
  • 2015 capital program was previously reduced to $1.2 billion from $1.6 billion with no impact on forecast 2015 production or cash flow.
(1) Cash flow is defined as cash provided by operations before changes in non-cash operating working capital. See “Non-GAAP Financial Measures” in the attached Management’s Discussion and Analysis.
(2) Net debt is defined as long-term debt plus working capital (adjusted for the fair value of financial instruments). See “Non-GAAP Financial Measures” in the attached Management’s Discussion and Analysis.
(3) Operating netback is calculated on a per-boe basis and is defined as revenue (excluding processing income) less royalties, transportation costs and operating expenses. See “Non-GAAP Financial Measures” in the attached Management’s Discussion and Analysis.
CORPORATE SUMMARY – DECEMBER 31, 2014
Three Months Ended December 31, Twelve Months Ended December 31,
2014 2013 Change 2014 2013 Change
OPERATIONS
Production
Natural gas (mcf/d) 692,604 446,337 55% 586,456 397,487 48%
Crude oil and NGL (bbl/d) 15,510 11,700 33% 15,186 8,548 78%
Oil equivalent (boe/d) 130,944 86,089 52% 112,929 74,796 51%
Product prices(1)
Natural gas ($/mcf) $ 4.09 $ 3.84 7% $ 4.58 $ 3.65 25%
Crude oil and NGL ($/bbl) $ 55.91 $ 71.83 (22)% $ 68.78 $ 83.25 (17)%
Operating expenses ($/boe) $ 4.07 $ 4.44 (8)% $ 4.87 $ 4.35 12%
Transportation costs ($/boe) $ 1.99 $ 2.25 (12)% $ 1.91 $ 2.07 (8)%
Operating netback(4)($/boe) $ 20.23 $ 21.29 (5)% $ 23.35 $ 20.37 15%
Cash general and administrative expenses ($/boe)(2) $ 0.56 $ 0.68 (18)% $ 0.60 $ 0.74 (19)%
FINANCIAL
($000, except share and per share)
Revenue 340,326 235,113 45% 1,362,116 788,863 73%
Royalties 23,604 13,489 75% 120,191 57,504 109%
Cash flow(4) 233,238 160,732 45% 929,002 526,761 76%
Cash flow per share (diluted)(4) $ 1.14 $ 0.83 37% $ 4.58 $ 2.80 64%
Net earnings 265,210 56,763 367% 488,872 148,114 230%
Net earnings per share (diluted) $ 1.29 $ 0.29 345% $ 2.41 $ 0.79 205%
Capital expenditures (net of dispositions) 152,135 497,941 (69)% 1,563,566 1,315,416 19%
Weighted average shares outstanding (diluted) 202,776,972 188,244,300 8%
Net debt(4) (1,142,509) (832,942) 37%
PROVED + PROBABLE RESERVES(3)
Natural gas (bcf) 4,344.5 3,026.1 44%
Crude oil (mbbls) 37,661 26,960 40%
Natural gas liquids (mbbls) 94,050 58,590 61%
Mboe 855,793 589,904 45%
(1) Product prices include realized gains and losses on financial instrument contracts.
(2) Excluding interest and financing charges.
(3) Reserves are “Company gross reserves”, which are defined as the working interest share of reserves prior to the deduction of interest owned by others (burdens). Royalty interest reserves are not included in Company gross reserves.
(4) See “Non-GAAP Financial Measures” in the attached Management’s Discussion and Analysis.

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

Tourmaline will host a conference call tomorrow, March 10, 2015 starting at 9:00 a.m. MT (11:00 a.m. ET). To participate, please dial 1-800-355-4959 (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 4210791.

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 LLP, each dated effective December 31, 2014, 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 consolidated report includes 100% of the reserves and future net revenue attributable to the properties of Exshaw Oil Corp. (“Exshaw”), a subsidiary of the Company, without reduction to reflect the 9.4% third-party minority interest in Exshaw. The price forecast used in the reserve evaluations is an average of the January 1, 2015 price forecasts for GLJ, Sproule Associates Ltd. and McDaniel & Associates Consultants Ltd., each of which is available on their respective websites, www.gljpc.com, www.sproule.com and www.mcdan.com, and will be contained in the Company’s Annual Information Form for the year ended December 31, 2014, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2015.

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. In general, estimates of economically recoverable crude oil, natural gas and NGL reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For those reasons, estimates of the economically recoverable crude oil, NGL and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. 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 press 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, 2014, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2015.

See also the Company’s news release dated February 18, 2015 for more information with respect to the Company’s reserves data.

INITIAL PRODUCTION (IP) RATES

Any references in this news release to IP rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter and are not necessarily indicative of long-term performance or ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Such rates are based on field estimates and may be based on limited data available at this time.

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 2015 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 2015 average production of 164,500 boepd and commodity price assumptions for natural gas (AECO – $3.50/mcf for 2015), and crude oil (WTI (US) – $57.96/bbl for 2015) and an exchange rate assumption of $0.84 (US/CAD) for 2015. To the extent such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Tourmaline on March 9, 2015 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.

CERTAIN DEFINITIONS:
bbl barrel
bcf billion cubic feet
bpd or bbl/d barrels per day
boe barrel of oil equivalent
boepd or boe/d barrel of oil equivalent per day
bopd or bbl/d barrel of oil, condensate or liquids per day
gj gigajoule
gjs/d gigajoules per day
mbbls thousand barrels
mboe thousand barrels of oil equivalent
mcf thousand cubic feet
mcfpd or mcf/d thousand cubic feet per day
mcfe thousand cubic feet equivalent
mmboe million barrels of oil equivalent
mmbtu million British thermal units
mmbtu/d million British thermal units per day
mmcf million cubic feet
mmcfpd or mmcf/d million cubic feet per day
mstboe thousand stock tank barrels of oil equivalent
NGL natural gas liquids

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the years ended December 31, 2014 and December 31, 2013

This management’s discussion and analysis (“MD&A”) should be read in conjunction with Tourmaline Oil Corp.’s consolidated financial statements and related notes for the years ended December 31, 2014 and 2013. Both the consolidated financial statements and the MD&A can be found at www.sedar.com. This MD&A is dated March 9, 2015.

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)”, “net debt”, “adjusted EBITDA”, “senior debt”, “total debt”, and “total capitalization”.

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 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 and uncertainty 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
Three Months Ended
December 31,		 Years Ended
December 31,
2014 2013 Change 2014 2013 Change
Natural gas (mcf/d) 692,604 446,337 55 % 586,456 397,487 48 %
Crude oil (bbl/d) 10,003 7,859 27 % 9,355 6,203 51 %
NGL (bbl/d) 5,507 3,841 43 % 5,831 2,345 149 %
Oil equivalent (boe/d) 130,944 86,089 52 % 112,929 74,796 51 %

Production for the fourth quarter of 2014 averaged 130,944 boe/d, a 52% increase over the average production for the same quarter of 2013 of 86,089 boe/d. Production was 88% natural gas weighted in the fourth quarter of 2014, compared to 86% for the same quarter of the prior year. For the year ended December 31, 2014, production increased 51% to 112,929 boe/d from 74,796 boe/d in 2013. The Company’s significant production growth when compared to 2013 can be primarily attributed to new wells that have been brought on-stream in 2014, as well as property and corporate acquisitions. The accelerated growth in oil and NGL production is the result of increased drilling in the Spirit River/Peace River High Charlie Lake oil plays, incremental liquids recovered in the Wild River area via deep cut processing, which began in late 2013, and strong condensate recoveries from new wells tied-in in N.E.B.C.

Tourmaline expects 2015 production to average approximately 164,500 boe/d, which is consistent with previous guidance.

REVENUE
Three Months Ended
December 31,		 Years Ended
December 31,
(000s) 2014 2013 Change 2014 2013 Change
Revenue from:
Natural gas $ 260,539 $ 157,800 65 % $ 980,877 $ 529,124 85 %
Oil and NGL 79,787 77,313 3 % 381,239 259,739 47 %
Total revenue from natural gas, oil and NGL sales $ 340,326 $ 235,113 45 % $ 1,362,116 $ 788,863 73 %

Revenue for the three months ended December 31, 2014 increased 45% to $340.3 million from $235.1 million for the same quarter of 2013. Revenue for the year ended December 31, 2014 increased 73% to $1,362.1 million from $788.9 million in 2013. Revenue growth is consistent with the increase in production and increased natural gas prices over the same periods, partially offset by decreases in oil and NGL prices. Revenue includes all natural gas, oil and NGL sales and realized gains and losses on financial instruments.

TOURMALINE PRICES:
Three Months Ended
December 31,		 Years Ended
December 31,
2014 2013 Change 2014 2013 Change
Natural gas ($/mcf) $ 4.09 $ 3.84 7 % $ 4.58 $ 3.65 25 %
Oil ($/bbl) $ 71.11 $ 84.81 (16 )% $ 89.17 $ 92.87 (4 )%
NGL ($/bbl) $ 28.32 $ 45.26 (37 )% $ 36.07 $ 57.80 (38 )%
Oil equivalent ($/boe) $ 28.25 $ 29.69 (5 )% $ 33.05 $ 28.90 14 %
BENCHMARK OIL AND GAS PRICES:
Three Months Ended
December 31,		 Years Ended
December 31,
2014 2013 Change 2014 2013 Change
Natural gas
NYMEX Henry Hub (USD$/mcf) $ 3.83 $ 3.85 (1 )% $ 4.26 $ 3.73 14 %
AECO (CAD$/mcf) $ 3.63 $ 3.52 3 % $ 4.50 $ 3.17 42 %
Oil
NYMEX (USD$/bbl) $ 73.20 $ 97.61 (25 )% $ 92.91 $ 98.05 (5 )%
Edmonton Par (CAD$/bbl) $ 75.22 $ 87.00 (14 )% $ 94.11 $ 93.54 1 %
RECONCILIATION OF AECO INDEX TO TOURMALINE’S REALIZED GAS PRICES:
Three Months Ended
December 31,		 Years Ended
December 31,
($/mcf) 2014 2013 Change 2014 2013 Change
AECO index (1) $ 3.39 $ 3.37 1 % $ 4.18 $ 3.02 38 %
Heat/quality differential 0.36 0.41 (12 )% 0.49 0.45 9 %
Realized gain (loss) 0.34 0.06 467 % (0.09 ) 0.18 (150 )%
Tourmaline realized natural gas price $ 4.09 $ 3.84 7 % $ 4.58 $ 3.65 25 %
(1) Weighted based on Tourmaline volumes for the period.
CURRENCY – EXCHANGE RATES:
Three Months Ended
December 31,		 Years Ended
December 31,
2014 2013 Change 2014 2013 Change
CAD/USD$ (1) $ 0.8800 $ 0.9528 (8 )% $ 0.9053 $ 0.9708 (7 )%
(1) Average rates for the period

The realized average natural gas prices for the quarter and year ended December 31, 2014 were 7% and 25%, respectively, higher than the same periods of the prior year. The higher natural gas price is commensurate with AECO prices over the same periods. Included in the realized price is a gain on commodity contracts in the fourth quarter of 2014 of $21.7 million (year ended December 31, 2014 – loss of $19.1 million) compared to a gain of $2.7 million for the fourth quarter of 2013 (year ended December 31, 2013 – gain of $26.3 million). Realized gains on commodity contracts for the quarter ended December 31, 2014 reflect a weakening of the natural gas price relative to the average pricing on the commodity contracts. Once these gains and losses are realized they are included in the per-unit amounts. The realized natural gas price for the three months ended December 31, 2014 includes an 11% premium to AECO pricing received due to the higher heat content (three months ended December 31, 2013 – 12%).

Realized oil prices have decreased by 16% and 4% for the three months and year ended December 31, 2014 compared to the same periods of the prior year. The decrease in the realized price is consistent with the decrease in the benchmark price of oil during 2014.

For the three months and year ended December 31, 2014, realized NGL prices have decreased by 37% and 38%, respectively, when compared to the same period of the prior year. The proportion of ethane in the NGL mix, which is priced significantly lower than the other products, increased from approximately 10% in 2013 to 41% in 2014 due to deep cut processing in the Wild River area of Alberta, resulting in a corresponding decrease in the realized NGL pricing. The economics of the deep cut processing activities in 2014 were favourable when compared to leaving the ethane in the natural gas stream.

ROYALTIES
Three Months Ended
December 31,		 Years Ended
December 31,
(000s) 2014 2013 2014 2013
Natural gas $ 12,828 $ 3,143 $ 67,540 $ 22,899
Oil and NGL 10,776 10,346 52,651 34,605
Total royalties $ 23,604 $ 13,489 $ 120,191 $ 57,504
Royalties as a percentage of revenue 6.9 % 5.7 % 8.8 % 7.3 %

For the quarter ended December 31, 2014, the average effective royalty rate was 6.9% compared to 5.7% for the same quarter of 2013.

For the year ended December 31, 2014, the average effective royalty rate was 8.8% compared to 7.3% for the same period of 2013. The average effective royalty rate increased in 2014 over 2013 mainly due to increased natural gas prices. In 2014, the Company continued 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 2015 to be approximately 10%. Some wells are expected to reach production maximums and come off royalty holidays, which will be partially offset by new wells coming on stream receiving some royalty relief. The royalty rate is sensitive to commodity prices, and as such, a change in commodity prices will impact the actual rate.

OTHER INCOME
Three Months Ended
December 31,		 Years Ended
December 31,
(000s) except per-unit amounts 2014 2013 Change 2014 2013 Change
Other income $ 5,031 $ 2,292 120 % $ 17,976 $ 6,523 176 %

Other income increased from $2.3 million in the fourth quarter of 2013 to $5.0 million in 2014. For the year ended December 31, 2014, other income increased to $18.0 million compared to $6.5 million for the same period of 2013. The increase in other income is mainly due to fees charged to working interest partners on Tourmaline-operated wells and third party wells where gas is being processed through Company-owned gas plants.

OPERATING EXPENSES
Three Months Ended
December 31,		 Years Ended
December 31,
(000s) except per-unit amounts 2014 2013 Change 2014 2013 Change
Operating expenses $ 48,991 $ 35,177 39 % $ 200,636 $ 118,671 69 %
Per boe $ 4.07 $ 4.44 (8 )% $ 4.87 $ 4.35 12 %

Operating expenses include all periodic lease and field-level expenses and exclude income recoveries from processing third-party volumes. For the year ended December 31, 2014, total operating expenses were $200.6 million, or $4.87/boe, compared to $118.7 million, or $4.35/boe for the same period of 2013. The Company’s operating expenses on a per-boe basis increased primarily due to accelerating the development of the Charlie Lake Peace River High oil complex where growth in oil volumes added to unit production costs. In addition, processing fees related to deep cut natural gas processing at Wild River pressured unit costs as did delays on facilities in the second and third quarters of 2014, resulting in higher processing fees until the facilities were commissioned in the fourth quarter of 2014.

Total third-party processing, gathering and compression fees increased from $33.2 million ($1.22/boe) in 2013 to $51.5 million ($1.25/boe) in 2014. This increase is due to growth in production volumes. On a per-unit basis, increased costs related to the temporary use of third-party processing facilities as well as oil and liquids processing which were partially offset by efficiencies gained through the commissioning of Company owned-and-operated gas plants.

For the fourth quarter of 2014, total operating expenses increased 39% to $49.0 million compared to $35.2 million in the fourth quarter of 2013 due to the growing production base. On a per-boe basis, the costs decreased 8% from $4.44/boe for the fourth quarter of 2013 to $4.07/boe in the fourth quarter of 2014. Although total operating expenses increased with production, the cost per boe decreased 8% reflecting increased operational efficiencies, including the benefit of lower processing fees as more gas is going through Tourmaline owned-and-operated facilities which have come on stream in the last half of 2014.

The Company’s operating expenses in the fourth quarter of 2014 include third-party processing, gathering and compression fees of approximately $10.7 million or $0.89/boe (December 31, 2013 – $8.7 million or $1.10/boe).

The Company’s average operating cost target is approximately $4.35/boe in 2015. Actual costs per boe can change, however, depending on a number of factors, including the Company’s actual production levels.

TRANSPORTATION
Three Months Ended
December 31,		 Years Ended
December 31,
(000s) except per unit amounts 2014 2013 Change 2014 2013 Change
Natural gas transportation $ 16,485 $ 12,220 35 % $ 54,395 $ 38,671 41 %
Oil and NGL transportation 7,463 5,635 32 % 24,419 17,963 36 %
Total transportation $ 23,948 $ 17,855 34 % $ 78,814 $ 56,634 39 %
Per boe $ 1.99 $ 2.25 (12 )% $ 1.91 $ 2.07 (8 )%

Transportation costs for the three months ended December 31, 2014 were $23.9 million or $1.99/boe (three months ended December 31, 2013 – $17.9 million or $2.25/boe). Transportation costs for the year ended December 31, 2014 were $78.8 million or $1.91/boe (year ended December 31, 2013 – $56.6 million or $2.07/boe). The increase in total transportation costs for the three months and year ended December 31, 2014 can be primarily attributed to increased production.

On a per-boe basis, transportation costs for the three and twelve months ended December 31, 2014 are lower due to a reduction in truck and rail transportation, as facilities and facility interconnects were commissioned throughout 2014.

GENERAL & ADMINISTRATIVE EXPENSES (“G&A”)
Three Months Ended
December 31,		 Years Ended
December 31,
(000s) except per-unit amounts 2014 2013 Change 2014 2013 Change
G&A expenses $ 14,351 $ 10,355 39 % $ 48,796 $ 37,582 30 %
Administrative and capital recovery (2,077 ) (985 ) 111 % (4,596 ) (2,317 ) 98 %
Capitalized G&A (5,574 ) (3,951 ) 41 % (19,292 ) (15,023 ) 28 %
Total G&A expenses $ 6,700 $ 5,419 24 % $ 24,908 $ 20,242 23 %
Per boe $ 0.56 $ 0.68 (18 )% $ 0.60 $ 0.74 (19 )%

Total G&A expenses for the fourth quarter of 2014 were $6.7 million compared to $5.4 million for the same quarter of the prior year. G&A costs per boe for the fourth quarter of 2014 decreased 18% down to $0.56/boe, compared to $0.68/boe for the fourth quarter of 2013.

For the year ended December 31, 2014, total G&A expenses were $24.9 million or $0.60/boe compared to $20.2 million or $0.74/boe for the same period of 2013. The higher total G&A expenses in 2014 are directly attributable to managing a larger production, reserve and land base. The Company’s G&A expenses per boe continued to trend downward as Tourmaline’s production base grew faster than its accompanying G&A costs.

G&A costs for 2015 are expected to remain at approximately $0.60/boe. Actual costs per boe can change, however, depending on a number of factors including the Company’s actual production levels.

SHARE-BASED PAYMENTS
Three Months Ended December 31, Years Ended
December 31,
(000s) 2014 2013 2014 2013
Share-based payments $ 15,850 $ 11,588 $ 57,532 $ 38,614
Capitalized share-based payments (7,925 ) (5,794 ) (28,766 ) (19,307 )
Total share-based payments $ 7,925 $ 5,794 $ 28,766 $ 19,307

The Company uses the fair value method for the determination of non-cash related share-based payments expense. During the fourth quarter of 2014, 3,195,500 stock options were granted to employees, officers, directors and key consultants at a weighted-average exercise price of $42.95, and 1,208,833 options were exercised, bringing $18.4 million of cash into treasury. The Company recognized $7.9 million of share-based payment expense in the fourth quarter of 2014 compared to $5.8 million in the fourth quarter of 2013. Capitalized share-based payments for the fourth quarter of 2014 were $7.9 million compared to $5.8 million for the same quarter of the prior year.

For the year ended December 31, 2014, share-based payment expense totalled $28.8 million and a further $28.8 million in share-based payments were capitalized (2013 – $19.3 million and $19.3 million, respectively). The increase in share-based payment expense in 2014 compared to 2013 reflects the increased value attributed to the options and a higher number of options outstanding.

DEPLETION, DEPRECIATION AND AMORTIZATION (“DD&A”)
Three Months Ended December 31, Years Ended
December 31,
(000s) except per unit amounts 2014 2013 2014 2013
Total depletion, depreciation and amortization $ 149,435 $ 96,249 $ 515,991 $ 356,239
Less mineral lease expiries (9,126 ) (2,282 ) (23,541 ) (33,127 )
Depletion, depreciation and amortization $ 140,309 $ 93,967 $ 492,450 $ 323,112
Per boe $ 11.65 $ 11.86 $ 11.95 $ 11.84

DD&A expense was $140.3 million for the fourth quarter of 2014 compared to $94.0 million for the same period of 2013 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 2014 was $11.65/boe compared to $11.86/boe for the same quarter of 2013.

For the year ended December 31, 2014, DD&A expense was $492.5 million (December 31, 2013 – $323.1 million) with a DD&A rate of $11.95/boe (December 31, 2013 – $11.84/boe). The increase in DD&A expense in 2014 over the same periods of 2013 is due to higher production volumes, as well as a larger capital asset base being depleted.

Mineral lease expiries for the three months and year ended December 31, 2014 were $9.1 million and $23.5 million, respectively (December 31, 2013 – $2.3 million and $33.1 million, respectively). The Company prioritizes drilling on what it believes to be the most cost-efficient and productive acreage, and with such a large land base, the Company has chosen to not continue some of the expiring sections of land. Tourmaline expects to continue to see mineral lease expiries of a similar magnitude on a go-forward basis.

FINANCE EXPENSES
Three Months Ended
December 31,		 Years Ended
December 31,
(000s) 2014 2013 Change 2014 2013 Change
Interest expense $ 8,520 $ 3,551 140 % $ 24,632 $ 12,220 102 %
Accretion expense 596 626 (5 )% 2,351 2,038 15 %
Transaction costs on corporate and property acquisitions – 9 (100 )% 1,496 1,100 36 %
Total finance expenses $ 9,116 $ 4,186 118 % $ 28,479 $ 15,358 85 %

Finance expenses totalled $9.1 million and $28.5 million for the quarter and year ended December 31, 2014, respectively, and are comprised of interest expense, transaction costs on corporate and property acquisitions and accretion of decommissioning obligations (December 31, 2013 – $4.2 million and $15.4 million, respectively). The increased finance expenses in 2014 are largely due to a higher interest expense resulting from a higher balance drawn on the credit facility. The average bank debt outstanding and the average effective interest rate on the debt during 2014 were $744.0 million and 2.9%, respectively (2013 – $337.0 million and 3.0%, respectively).

CASH FLOW FROM OPERATING ACTIVITIES, CASH FLOW AND NET EARNINGS
Three Months Ended
December 31,		 Years Ended
December 31,
(000s) except per unit amounts 2014 2013 Change 2014 2013 Change
Cash flow from operating activities $ 201,188 $ 128,852 56 % $ 915,381 $ 479,239 91 %
Per share (1) $ 0.98 $ 0.66 48 % $ 4.51 $ 2.55 77 %
Cash flow (2) $ 233,238 $ 160,732 45 % $ 929,002 $ 526,761 76 %
Per share (1)(2) $ 1.14 $ 0.83 37 % $ 4.58 $ 2.80 64 %
Net earnings $ 265,210 $ 56,763 367 % $ 488,872 $ 148,114 230 %
Per share (1) $ 1.29 $ 0.29 345 % $ 2.41 $ 0.79 205 %
Operating netback per boe (2) $ 20.23 $ 21.29 (5 )% $ 23.35 $ 20.37 15 %
(1) Fully diluted
(2) See “Non-GAAP Financial Measures”

Cash flow for the three months ended December 31, 2014 was $233.2 million or $1.14 per diluted share compared to $160.7 million or $0.83 per diluted share for the same period of 2013. For the year ended December 31, 2014, cash flow was $929.0 million or $4.58 per diluted share, compared to December 31, 2013 cash flow of $526.8 million or $2.80 per diluted share. The increase in cash flow in 2014 reflects increased production, as well as higher natural gas prices.

The Company had after-tax earnings for the three months and year ended December 31, 2014 of $265.2 million ($1.29 per diluted share) and $488.9 million ($2.41 per diluted share), respectively, compared to earnings of $56.8 million ($0.29 per diluted share) and $148.1 million ($0.79 per diluted share), respectively, for the same periods of 2013. The earnings increase is attributable to a significant increase in revenues, as well as gains on divestitures of $268.2 million most of which were realized in December 2014 (December 31, 2013 – $77.0 million).

CAPITAL EXPENDITURES
Three Months Ended December 31, Years Ended
December 31,
(000s) 2014 2013 2014 2013
Land and seismic $ 12,234 $ 8,660 $ 61,357 $ 43,008
Drilling and completions 386,950 280,326 1,159,700 721,653
Facilities 217,010 122,801 789,379 386,601
Property acquisitions 28,250 82,180 33,027 226,926
Property dispositions (498,114 ) (24 ) (500,639 ) (78,069 )
Other 5,805 3,998 20,742 15,297
Total cash capital expenditures $ 152,135 $ 497,941 $ 1,563,566 $ 1,315,416

During the fourth quarter of 2014, the Company invested $152.1 million of cash consideration, net of $498.1 million in proceeds on dispositions, compared to $497.9 million for the same period of 2013. Expenditures on exploration and production were $616.2 million compared to $411.8 million for the same quarter of 2013, which is consistent with the Company’s aggressive growth strategy including the increase to a 20-rig drilling program up from the average program of 15 rigs for the fourth quarter of 2013.

The growth in facilities expenditures includes work on the completion of the 50 mmcfpd facility expansions at each of Doe and Musreau as well as a new 50 mmcfpd facility at Sundown commissioned in September 2014. Significant expenditures were also made at the new sour gas processing plant in Spirit River (30 mmcfpd) commissioned in November and the 50 mmcfpd expansion at Wild River, which were placed on production in December 2014. It also includes several large pipeline lateral projects, which are intended to optimize transportation of natural gas to Tourmaline-operated processing facilities.

During 2014, the Company invested $1,563.6 million of cash consideration, net of proceeds on dispositions, compared to $1,315.4 million in 2013. Expenditures on exploration and production were $2,010.4 million compared to $1,151.3 million for 2013.

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

Year Ended
December 31, 2014		 Year Ended
December 31, 2013
Gross Net Gross Net
Drilled 206 176.75 129 115.14
Completed 198 169.83 123 111.33
Tied-in 83 73.50 54 46.85

Acquisitions and Dispositions

On April 24, 2014, the Company acquired all of the issued and outstanding shares of Santonia Energy Inc. (“Santonia”). As consideration, the Company issued 3,228,234 common shares at a price of $54.94 per share. Total transaction costs incurred by the Company of $1.5 million associated with this acquisition were expensed in the consolidated statement of income and comprehensive income. The acquisition resulted in an increase in Property, Plant and Equipment (“PP&E”) of approximately $167.5 million and an increase to Exploration and Evaluation (“E&E”) assets of $19.1 million. The acquisition of Santonia resulted in an increase in lands and production in a highly profitable core area of the Alberta Deep Basin.

On December 23, 2014, the Company completed the sale of a 25% working interest in its Peace River High complex for cash consideration of $500.0 million before customary adjustments to Canadian Non-Operated Resources Corp. (“CNOR”). The Company will continue to be the operator of all jointly-owned assets. Under the terms of the arrangement, Tourmaline has committed to spend $400 million gross ($300 million net) per year over the next 5 years. The committed capital expenditure can be deferred to future periods in the event of an economic downturn, and as agreed upon by both parties. As part of the capital commitment, the Company also agreed to carry CNOR for the first $87.1 million spent (CNOR share) on specified capital projects. At December 31, 2014, approximately $44.5 million remained to be spent on these specified capital projects.

Capital expenditures in 2015 are now forecast to be $1.2 billion, which was revised downward from $1.4 billion on the February 18, 2015 press release. The Company has revised its capital budget in light of the depressed commodity prices.

LIQUIDITY AND CAPITAL RESOURCES

On February 12, 2014, the Company issued 4.615 million common shares at a price of $47.50 per share for total gross proceeds of $219.2 million. The proceeds were used to temporarily reduce bank debt and to fund the Company’s 2014 exploration and development program.

On April 24, 2014, the Company completed the acquisition of Santonia with the issuance of 3.228 million Tourmaline shares at a closing price on that date of $54.94 per Tourmaline share, for consideration of $177.4 million. The Company also assumed Santonia’s net debt of $40.6 million, which included $8.9 million in transaction costs.

During 2014, the Company issued 1.43 million flow-through common shares at an average price of $65.97 per share, for total gross proceeds of $94.3 million. The proceeds were used to temporarily reduce bank debt and to fund the Company’s 2014 exploration and development program.

On December 23, 2014, the Company closed the disposition of a 25% working interest in the Spirit River complex for cash proceeds of $500.0 million before customary adjustments.

The Company has a covenant-based unsecured, bank credit facility in place with a syndicate of bankers, the details of which are described in note 9 of the Company’s consolidated financial statements for the year ended December 31, 2014. This facility is a three-year extendible revolving facility in the amount of $1,550.0 million plus a $50.0 million operating revolver with an initial maturity date of June 2017. 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 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 1.50 to 3.15 percent over bankers’ acceptance rates depending on the Company’s senior debt to adjusted EBITDA ratio.

On November 3, 2014, the Company entered into a five-year term loan agreement with a Canadian Chartered Bank for $250.0 million, bearing an interest rate of 240 basis points over the applicable bankers’ acceptance rate. The covenants for the term loan are the same as those under the Company’s syndicated credit facility and the term loan will rank equally with the obligations under the Company’s syndicated credit facility. Proceeds from the term loan were used to repay a portion of the current outstanding bank debt.

The Company’s aggregate borrowing capacity is now $1.85 billion. The increase in borrowing capacity will provide the Company with greater flexibility when executing its capital program.

At December 31, 2014, Tourmaline had negative working capital of $223.7 million, after adjusting for the fair value of financial instruments (the unadjusted working capital deficiency was $189.9 million) (December 31, 2013 – $242.6 million and $245.3 million, respectively). Management believes the Company has sufficient liquidity and capital resources to fund the 2015 exploration and development program through expected cash flow from operations and, its unutilized bank credit facility. As at December 31, 2014, the Company had $248.6 million in long term debt outstanding and $670.3 million drawn against the revolving credit facility for total bank debt of $918.9 million (net of prepaid interest and debt issue costs) (December 31, 2013 – $590.3 million). Net debt at December 31, 2014 was $1,142.5 million (December 31, 2013 – $832.9 million).

SHARES AND STOCK OPTIONS OUTSTANDING

As at March 9, 2015, the Company has 203,525,644 common shares outstanding and 16,682,968 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.

PAYMENTS DUE BY YEAR
(000s) 1 Year 2-3 Years 4-5 Years >5 Years Total
Operating leases $ 4,371 $ 10,507 $ 10,692 $ 1,325 $ 26,895
Firm transportation and processing agreements 104,575 288,052 269,429 622,076 1,284,132
Capital commitments (1) 350,552 620,629 600,000 – 1,571,181
Flow through share commitments 13,434 – – – 13,434
Revolving credit facility (2) – 722,449 – – 722,449
Term debt (3) 11,129 22,257 270,569 – 303,955
$ 484,061 $ 1,663,894 $ 1,150,690 $ 623,401 $ 3,922,046
(1) Includes drilling commitments, and capital spending commitments under the joint arrangement in the Spirit River complex of $344.5 million in year 1 and $300.0 million per year thereafter until 2019. The capital spending commitment can be deferred to future periods in the event of an economic downturn, and as agreed upon by both parties.
(2) Includes interest expense at an annual rate of 2.82% being the rate applicable to outstanding debt on the credit facility at December 31, 2014.
(3) Includes interest expense at an annual rate of 4.47% being the fixed rate on the term debt (including the interest rate swap) at December 31, 2014.

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, 2014.

As at December 31, 2014, the Company has entered into certain financial derivative 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 entered into in 2014 are summarized in note 5 of the Company’s consolidated financial statements for the year ended December 31, 2014.

The following table provides a summary of the unrealized gains and losses on financial instruments for the year ended December 31, 2014:

Three Months Ended December 31, Years Ended
December 31,
(000s) 2014 2013 2014 2013
Unrealized gain (loss) on financial instruments $ 30,186 $ (4,847 ) $ 34,615 $ (10,046 )

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. Physical contracts in place at December 31, 2014 have been summarized in note 5 of the Company’s consolidated financial statements for the year ended December 31, 2014.

Financial derivative and physical delivery contracts entered into subsequent to December 31, 2014 are detailed in note 5 of the Company’s consolidated financial statements for the year ended December 31, 2014.

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, 2014.

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.

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, 2014, the Company’s DC&P and ICFR are effective. There were no changes in the Company’s DC&P or ICFR during the period beginning on October 1, 2014 and ending December 31, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s DC&P or 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.

In May, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) issued an updated Internal Control-Integrated Framework (“2013 Framework”) replacing the Internal Control – Integrated Framework (1992). Tourmaline adopted the 2013 Framework for the year ended December 31, 2014.

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

The oil and gas industry is currently subject to regulation pursuant to a variety of provincial and federal environmental legislation, all of which is subject to governmental review and revision from time to time. Such legislation provides for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. In addition, such legislation sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability and the imposition of material fines and penalties.

The use of fracture stimulations has been ongoing safely in an environmentally responsible manner in western Canada for decades. With the increase in the use of fracture stimulations in horizontal wells there is increased communication between the oil and natural gas industry and a wider variety of stakeholders regarding the responsible use of this technology. This increased attention to fracture stimulations may result in increased regulation or changes of law which may make the conduct of the Company’s business more expensive or prevent the Company from conducting its business as currently conducted. Tourmaline focuses on conducting transparent, safe and responsible operations in the communities in which its people live and work.

CHANGES IN ACCOUNTING POLICIES

The following new accounting standards and amendments to existing standards, as issued by the International Accounting Standards Board (“IASB”), have been adopted by the Company effective January 1, 2014.

IFRIC 21 – Levies clarifies that a levy is not recognized until the obligating event in the legislation occurs, even if there is no realistic opportunity to avoid the obligation.

IAS 36 – Impairment of Assets expands the disclosure of recoverable amounts when they are based on fair value less cost to sell and an impairment is recognized.

STANDARDS ISSUED BUT NOT YET ADOPTED

The following pronouncements from the IASB will become effective for financial reporting periods beginning on or after January 1, 2015 and have not yet been adopted by the Company. These new or revised standards permit early adoption with transitional arrangements depending upon the date of initial application.

IFRS 9 – Financial Instruments replaces the existing guidance in IAS 39 Financial Instruments: Recognition and Measurement. The new standard includes revised guidance on the classification and measurement of financial instruments, including a new expected credit loss model for calculating impairment on financial assets, and the new general hedge accounting requirements. It also carries forward the guidance on recognition and derecognition of financial instruments from IAS 39. IFRS 9 is effective for annual reporting periods beginning on or after January 1, 2018 with early adoption permitted.

IFRS 11 – Joint Arrangements was amended to add new guidance on the accounting for the acquisition of an interest in a joint operation that constitutes a business. The amendments to IFRS 11 are effective for annual reporting periods beginning on or after January 1, 2016 with early adoption permitted.

IFRS 15 – Revenue from Contracts with Customers establishes a comprehensive framework for determining whether, how much and when revenue is recognized. It replaces existing revenue recognition guidance, including IAS 18 Revenue, IAS 11 Construction Contracts and IFRIC 13 Customer Loyalty Programmes. IFRS 15 is effective for annual reporting periods beginning on or after January 1, 2017 with early adoption permitted.

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

NON-GAAP FINANCIAL MEASURES

This MD&A or documents referred to in this MD&A make reference to the terms “cash flow”, “operating netback”, “working capital (adjusted for the fair value of financial instruments)”, “net debt”, “adjusted EBITDA”, “senior debt”, “total debt”, and “total capitalization” which are not recognized measures under GAAP, and do not have a standardized meaning prescribed by GAAP. Accordingly, the Company’s use of these terms may not be comparable to similarly defined measures presented by other companies. Management uses the terms “cash flow”, “operating netback”, “working capital (adjusted for the fair value of financial instruments)” and “net debt”, for its own performance measures and to provide shareholders and potential investors with a measurement of the Company’s efficiency and its ability to generate the cash necessary to fund a portion of its future growth expenditures or to repay debt. Investors are cautioned that the non-GAAP measures should not be construed as an alternative to net income determined in accordance with GAAP as an indication of the Company’s performance. The terms “adjusted EBITDA”, “senior debt”, “total debt”, and “total capitalization” are not used by management in measuring performance but are used in the financial covenants under the Company’s credit facility. Under the Company’s credit facility “adjusted EBITDA” means generally net income or loss, excluding extraordinary items, plus interest expense and income taxes and adjusted for non-cash items and gains or losses on dispositions, “senior debt” means generally the indebtedness, liabilities and obligations of the Company to the lenders under the credit facility and certain other secured indebtedness, liabilities and obligations of the Company (“bank debt”), “total debt” means generally bank debt plus any other indebtedness of the Company, and “total capitalization” means generally the sum of the Company’s shareholders’ equity and all other indebtedness of the Company including bank debt, all determined on a consolidated basis in accordance with GAAP.

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:

Three Months Ended December 31, Years Ended
December 31,
(000s) 2014 2013 2014 2013
Cash flow from operating activities (per GAAP) $ 201,188 $ 128,852 $ 915,381 $ 479,239
Change in non-cash working capital 32,050 31,880 13,621 47,522
Cash flow $ 233,238 $ 160,732 $ 929,002 $ 526,761

Operating Netback

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

Three Months Ended December 31, Years Ended
December 31,
($/boe) 2014 2013 2014 2013
Revenue, excluding processing income $ 28.25 $ 29.69 $ 33.05 $ 28.90
Royalties (1.96 ) (1.70 ) (2.92 ) (2.11 )
Transportation costs (1.99 ) (2.25 ) (1.91 ) (2.07 )
Operating expenses (4.07 ) (4.44 ) (4.87 ) (4.35 )
Operating netback (1) $ 20.23 $ 21.29 $ 23.35 $ 20.37
(1) May not add due to rounding.

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:

As at December 31,
(000s) 2014 2013
Working capital (deficit) $ (189,928 ) $ (245,314 )
Fair value of financial instruments — short-term (asset) liability (33,727 ) 2,691
Working capital (deficit) (adjusted for the fair value of financial instruments) $ (223,655 ) $ (242,623 )

Net Debt

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

As at December 31,
(000s) 2014 2013
Bank debt $ (918,854 ) $ (590,319 )
Working capital (deficit) (189,928 ) (245,314 )
Fair value of financial instruments — short-term (asset) liability (33,727 ) 2,691
Net debt $ (1,142,509 ) $ (832,942 )

SELECTED QUARTERLY INFORMATION

2014 2013
($000s, unless otherwise noted) Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
PRODUCTION
Natural gas (mcf) 63,719,524 51,771,964 51,225,036 47,339,926 41,062,993 36,486,443 34,477,391 33,055,857
Oil and NGL(bbls) 1,426,951 1,307,089 1,468,198 1,340,699 1,076,395 735,727 640,001 667,907
Oil equivalent (boe) 12,046,872 9,935,749 10,005,704 9,230,686 7,920,228 6,816,800 6,386,233 6,177,216
Natural gas (mcf/d) 692,604 562,739 562,912 525,999 446,337 396,592 378,872 367,287
Oil and NGL (bbls/d) 15,510 14,207 16,134 14,897 11,700 7,997 7,033 7,421
Oil equivalent (boe/d) 130,944 107,997 109,953 102,563 86,089 74,096 70,178 68,636
FINANCIAL
Revenue, net of royalties 351,939 311,586 313,655 317,336 219,069 167,138 180,505 161,124
Cash flow from operating activities 201,188 233,047 231,756 249,390 128,852 128,192 128,432 93,763
Cash flow (1) 233,238 211,635 231,542 252,587 160,732 120,560 128,870 116,599
Per diluted share 1.14 1.03 1.13 1.28 0.83 0.64 0.68 0.64
Net earnings (loss) 265,210 67,357 66,437 89,868 56,763 9,163 30,004 52,184
Per basic share 1.31 0.33 0.33 0.47 0.30 0.05 0.16 0.29
Per diluted share 1.29 0.33 0.32 0.45 0.29 0.05 0.16 0.29
Total assets 6,622,303 5,978,645 5,446,094 5,082,535 4,696,471 4,210,171 3,811,192 3,735,641
Working capital (deficit) (189,928 ) (493,160 ) (131,672 ) (255,240 ) (245,314 ) (206,250 ) (50,851 ) (165,385 )
Working capital (deficit)(adjusted for the fair value of financial instruments) (1) (223,655 ) (495,222 ) (123,166 ) (248,094 ) (242,623 ) (204,507 ) (53,676 ) (166,049 )
Cash capital expenditures (net) 152,135 647,302 297,733 466,396 497,941 468,261 158,751 190,463
Basic outstanding shares (000s) 203,162 201,673 201,431 195,567 189,805 184,621 184,175 183,408
PER UNIT
Natural gas ($/mcf) 4.09 4.34 4.71 5.38 3.84 3.30 3.92 3.50
Oil and NGL ($/bbl) 55.91 74.61 74.53 70.49 71.83 91.65 87.06 88.75
Revenue ($/boe) 28.25 32.41 35.03 37.84 29.69 27.58 29.88 28.33
Operating netback ($/boe)(1) 20.23 22.19 24.02 27.94 21.29 18.59 21.28 20.20
(1) See Non-GAAP Financial Measures.

The oil and gas exploration and production industry is cyclical in nature. The Company’s financial position, results of operations and cash flows are principally impacted by production levels and commodity prices, particularly natural gas prices.

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 2014 was due to unscheduled third-party maintenance, equipment issues and downtime at Musreau, the Saturn Deep Cut facility as well as downtime on the TCPL mainline pipeline. The Company’s average annual production has increased from 50,804 boe per day in 2012 to 74,796 boe per day in 2013 to 112,929 boe per day in 2014. The production growth can be attributed primarily to the Company’s exploration and development activities, as well as from acquisitions of producing properties. The Company’s cash flows from operating activities were $273.5 million in 2012, $479.2 million in 2013 and $915.4 million in 2014. Cash flows have increased with higher production and strengthening natural gas prices.

Commodity price changes can indirectly impact expected production by changing the amount of funds available to reinvest in exploration, development and acquisition activities in the future. Decreases in commodity prices not only reduce revenues and cash flows available for exploration, they may also challenge the economics of potential capital projects by reducing the quantities of reserves that are commercially recoverable. The Company’s capital program is dependent on cash flows generated from operations and access to capital markets.

SELECTED ANNUAL INFORMATION
($000s unless otherwise noted) 2014 2013 2012
PRODUCTION
Natural gas (mcf) 214,056,451 145,082,684 98,087,893
Oil and NGL (bbls) 5,542,937 3,120,030 2,246,040
Oil equivalent (boe) 41,219,012 27,300,477 18,594,022
Natural gas (mcf/d) 586,456 397,487 268,000
Oil and NGL (bbls/d) 15,186 8,548 6,137
Oil equivalent (boe/d) 112,929 74,796 50,804
FINANCIAL
Revenue, net of royalties 1,294,516 727,836 427,075
Cash flow from operating activities 915,381 479,239 273,477
Cash flow (1) 929,002 526,761 280,279
Per diluted share 4.58 2.80 1.68
Net earnings 488,872 148,114 15,519
Per basic share 2.46 0.81 0.10
Per diluted share 2.41 0.79 0.09
Total assets 6,622,303 4,696,471 3,580,253
Working capital (deficit) (189,928 ) (245,314 ) (98,913 )
Working capital (deficit) (adjusted for the fair value of financial instruments) (1) (223,655 ) (242,623 ) (103,727 )
Cash capital expenditures (net) 1,563,566 1,315,416 741,640
Basic outstanding shares (000s) 203,162 189,805 174,813
PERUNIT
Natural gas ($/mcf) 4.58 3.65 2.67
Oil and NGL ($/bbl) 68.78 83.25 83.71
Revenue ($/boe) 33.05 28.90 24.19
Operating netback ($/boe) 23.35 20.37 16.27
(1) See Non-GAAP Financial Measures.

MANAGEMENT’S REPORT

To the Shareholders of Tourmaline Oil Corp.:

The accompanying consolidated financial statements of Tourmaline Oil Corp. and all the information in the Annual Report are the responsibility of management and have been approved by the Board of Directors. The financial statements have been prepared by management in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. Financial statements are not precise since they include certain amounts based on estimates and judgments. Management has determined such amounts on a reasonable basis in order to ensure that the financial statements are presented fairly, in all material respects. The financial information contained elsewhere in this report has been reviewed to ensure consistency with the financial statements.

Management has established systems of internal controls, which are designed to provide reasonable assurance that assets are safeguarded from loss or unauthorized use and to produce reliable accounting records for the preparation of financial information. The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control. It exercises its responsibilities primarily through the Audit Committee, with some assistance from the Reserves Committee regarding the annual evaluation of the Company’s petroleum and natural gas reserves. The Audit Committee has reviewed the financial statements with management and the auditors, and has reported to the Board of Directors. The external auditors have access to the Audit Committee without the presence of management.

The financial statements have been audited on behalf of the shareholders by KPMG LLP, the external auditors. Their examination included such tests and procedures, as they considered necessary, to provide reasonable assurance that the consolidated financial statements are presented fairly in accordance with International Financial Reporting Standards. The Board of Directors has approved the financial statements.

(signed) (signed)
Michael L. Rose Brian G. Robinson
President and Vice-President, Finance and
Chief Executive Officer Chief Financial Officer
Calgary, Alberta Calgary, Alberta
March 9, 2015

INDEPENDENT AUDITORS’ REPORT

To the Shareholders of Tourmaline Oil Corp.:
We have audited the accompanying consolidated financial statements of Tourmaline Oil Corp., which comprise the consolidated statements of financial position as at December 31, 2014 and December 31, 2013 and the consolidated statements of income and comprehensive income, changes in equity and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Tourmaline Oil Corp. as at December 31, 2014 and December 31, 2013 and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards.

(Signed) “KPMG LLP”
Chartered Accountants
March 9, 2015
Calgary, Canada

CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
As at
December 31,
(000s) 2014 2013
Assets
Current assets:
Cash and cash equivalents $ 263,052 $ –
Accounts receivable 203,212 136,041
Prepaid expenses and deposits 11,417 6,918
Fair value of financial instruments (notes 4 and 5) 35,571 166
Total current assets 513,252 143,125
Fair value of financial instruments (notes 4 and 5) – 663
Long-term asset 7,145 2,373
Exploration and evaluation assets (note 6) 635,633 700,525
Property, plant and equipment (note 7) 5,466,273 3,849,785
Total Assets $ 6,622,303 $ 4,696,471
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities $ 701,336 $ 385,582
Fair value of financial instruments (notes 4 and 5) 1,844 2,857
Total current liabilities 703,180 388,439
Bank debt (note 9) 918,854 590,319
Long-term obligation – 3,414
Fair value of financial instruments (notes 4 and 5) 6,356 5,216
Deferred premium on flow-through shares 3,210 –
Decommissioning obligations (note 8) 114,038 76,037
Deferred taxes (note 12) 422,090 265,025
Shareholders’ equity:
Share capital (note 11) 3,615,378 3,062,432
Non-controlling interest (note 10) 30,006 17,877
Contributed surplus 124,325 91,718
Retained earnings 684,866 195,994
Total shareholders’ equity 4,454,575 3,368,021
Total Liabilities and Shareholders’ Equity $ 6,622,303 $ 4,696,471
Commitments (note 19)
Subsequent events (note 5)
See accompanying notes to the consolidated financial statements.

Approved on behalf of the Board of Directors of Tourmaline Oil. Corp.:

(signed) (signed)
Robert W. Blakely, Director Phillip A. Lamoreaux, Director
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
Years Ended
December 31,
(000s) except per-share amounts 2014 2013
Revenue:
Oil and natural gas sales $ 1,379,393 $ 759,153
Royalties (120,191 ) (57,504 )
Net revenue from oil and natural gas sales 1,259,202 701,649
Realized gain (loss) on financial instruments (17,277 ) 29,710
Unrealized gain (loss) on financial instruments (note 5) 34,615 (10,046 )
Other income (note 15) 17,976 6,523
Total net revenue 1,294,516 727,836
Expenses:
Operating 200,636 118,671
Transportation 78,814 56,634
General and administration 24,908 20,242
Share-based payments 28,766 19,307
(Gain) on divestitures (268,231 ) (76,990 )
Depletion, depreciation and amortization 515,991 356,239
Total expenses 580,884 494,103
Income from operations 713,632 233,733
Finance expenses (note 16) 28,479 15,358
Income before taxes 685,153 218,375
Deferred taxes (note 12) 184,152 68,682
Net income and comprehensive income before non-controlling interest 501,001 149,693
Net income and comprehensive income attributable to:
Shareholders of the Company 488,872 148,114
Non-controlling interest (note 10) 12,129 1,579
$ 501,001 $ 149,693
Net income per share attributable to common shareholders(note 13)
Basic $ 2.46 $ 0.81
Diluted $ 2.41 $ 0.79
See accompanying notes to the consolidated financial statements.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(000s) Share Capital Contributed Surplus Retained Earnings Non-Controlling Interest Total Equity
Balance at December 31, 2013 $ 3,062,432 $ 91,718 $ 195,994 $ 17,877 $ 3,368,021
Issue of common shares (note 11) 294,161 – – – 294,161
Issue of common shares on corporate acquisition (notes 7 and 11) 177,359 – – – 177,359
Share issue costs, net of tax (note 11) (9,972 ) – – – (9,972 )
Share-based payments – 28,766 – – 28,766
Capitalized share-based payments – 28,766 – – 28,766
Options exercised (note 11) 91,398 (24,925 ) – – 66,473
Income attributable to common shareholders – – 488,872 – 488,872
Income attributable to non-controlling interest – – – 12,129 12,129
Balance at December 31, 2014 $ 3,615,378 $ 124,325 $ 684,866 $ 30,006 $ 4,454,575
(000s) Share Capital Contributed Surplus Retained Earnings Non-Controlling Interest Total Equity
Balance at December 31, 2012 $ 2,599,614 $ 70,923 $ 47,880 $ 16,298 $ 2,734,715
Issue of common shares (note 11) 411,099 – – – 411,099
Share issue costs, net of tax (note 11) (13,123 ) – – – (13,123 )
Share-based payments – 19,307 – – 19,307
Capitalized share-based payments – 19,307 – – 19,307
Options exercised (note 11) 64,842 (17,819 ) – – 47,023
Income attributable to common shareholders – – 148,114 – 148,114
Income attributable to non-controlling interest – – – 1,579 1,579
Balance at December 31, 2013 $ 3,062,432 $ 91,718 $ 195,994 $ 17,877 $ 3,368,021
See accompanying notes to the consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOW
Years Ended
December 31,
(000s) 2014 2013
Cash provided by (used in):
Operations:
Net income $ 488,872 $ 148,114
Items not involving cash:
Depletion, depreciation and amortization 515,991 356,239
Accretion on decommissioning obligations 2,351 2,038
Share-based payments 28,766 19,307
Deferred taxes 184,152 68,682
Unrealized (gain) loss on financial instruments (note 5) (34,615 ) 10,046
(Gain) on divestitures (268,231 ) (76,990 )
Non-controlling interest 12,129 1,579
Decommissioning expenditures (413 ) (2,254 )
Changes in non-cash operating working capital (note 18) (13,621 ) (47,522 )
Total cash flow from operating activities 915,381 479,239
Financing:
Issue of common shares 380,031 473,830
Share issue costs (13,332 ) (17,633 )
Increase in bank debt 298,901 229,746
Total cash flow from financing activities 665,600 685,943
Investing:
Exploration and evaluation (186,093 ) (154,431 )
Property, plant and equipment (1,845,085 ) (1,012,128 )
Property acquisitions (33,027 ) (226,926 )
Proceeds from divestitures 500,639 78,069
Net repayment of long-term obligation (3,460 ) (3,462 )
Changes in non-cash investing working capital (note 18) 249,097 153,696
Total cash flow from investing activities (1,317,929 ) (1,165,182 )
Changes in cash 263,052 –
Cash, beginning of year – –
Cash, end of year $ 263,052 $ –
Cash is defined as cash and cash equivalents.
See accompanying notes to the consolidated financial statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2014 AND 2013

(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. 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, Canada 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 9, 2015.

(b) Basis of measurement:

The consolidated financial statements have been prepared on the historical-cost basis except for derivative financial instruments which are measured at fair value. 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 judgments and estimates:

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 depletion and 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 forecasted 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) Exploration and evaluation assets:

The application of the Company’s accounting policy for exploration and evaluation assets requires management to make certain judgements as to future events and circumstances as to whether economic quantities of reserves have been found in assessing economic and technical feasibility.

(iv) 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 of 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., Santonia Energy Inc. and Exshaw Oil Corp., of which the Company owns 90.6% (note 10).

(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, substantive 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.

(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-owned assets:

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

(b) Business Combinations:

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. If the cost of acquisition is greater than the fair value of the net assets of the subsidiary acquired, the difference is recognized as goodwill on the statement of financial position. Acquisition costs incurred are expensed.

(c) Financial instruments:

(i) Non-derivative financial instruments:

Non-derivative financial instruments comprise cash and cash equivalents, accounts receivable, investments, 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.

(d) 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.

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. Undeveloped land is not depreciated.

The estimated useful lives for depreciable assets are as follows:

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

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

(e) 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.

(f) 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.

(g) 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.

(h) 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.

(i) 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.

(j) 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.

(k) 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.

(l) 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.

(m) 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. ACCOUNTING CHANGES

(a) Changes in Accounting Policies:

The following new accounting standards and amendments to existing standards, as issued by the International Accounting Standards Board (“IASB”), have been adopted by the Company effective January 1, 2014:

IFRIC 21 – Levies clarifies that a levy is not recognized until the obligating event in the legislation occurs, even if there is no realistic opportunity to avoid the obligation.

IAS 36 – Impairment of Assets expands the disclosure of recoverable amounts when they are based on fair value less cost to sell and an impairment is recognized.

(b) Future Accounting Changes

The following pronouncements from the IASB will become effective or were amended for financial reporting periods beginning on or after January 1, 2015 and have not yet been adopted by the Company. These new or revised standards permit early adoption with transitional arrangements depending upon the date of initial application.

IFRS 9 – Financial Instruments replaces the existing guidance in IAS 39 Financial Instruments: Recognition and Measurement. The new standard includes revised guidance on the classification and measurement of financial instruments, including a new expected credit loss model for calculating impairment on financial assets, and the new general hedge accounting requirements. It also carries forward the guidance on recognition and derecognition of financial instruments from IAS 39. IFRS 9 is effective for annual reporting periods beginning on or after January 1, 2018 with early adoption permitted.

IFRS 11 – Joint Arrangements was amended to add new guidance on the accounting for the acquisition of an interest in a joint operation that constitutes a business. The amendments to IFRS 11 are effective for annual reporting periods beginning on or after January 1, 2016 with early adoption permitted.

IFRS 15 – Revenue from Contracts with Customers establishes a comprehensive framework for determining whether, how much and when revenue is recognized. It replaces existing revenue recognition guidance, including IAS 18 Revenue, IAS 11 Construction Contracts and IFRIC 13 Customer Loyalty Programmes. IFRS 15 is effective for annual reporting periods beginning on or after January 1, 2017 with early adoption permitted.

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

4. DETERMINATION OF FAIR VALUE

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

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

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

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

(ii) Cash and cash equivalents, accounts receivable, bank debt, accounts payable and accrued liabilities:

The fair value of cash and cash equivalents, accounts receivable, bank debt, 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, 2014 and December 31, 2013, 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, 2014 and December 31, 2013. The carrying value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities 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.

As at December 31, 2014
(000s) Carrying Amount Fair Value
Financial Assets:
Commodity price risk contracts (1) $ 35,571 $ 35,571
Financial Liabilities:
Bank debt 918,854 918,854
Commodity price risk contracts (1) 8,200 8,200
As at December 31, 2013
(000s) Carrying Amount Fair Value
Financial assets:
Commodity price risk contracts (1) $ 829 $ 829
Financial liabilities:
Bank debt 590,319 590,319
Commodity price risk contracts (1) 8,073 8,073
(1) Commodity price contracts are fair valued using Level 2 information.

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 jointly owned assets and petroleum and natural gas marketers. As at December 31, 2014, Tourmaline’s receivables consisted of $115.7 million (December 31, 2013 – $99.9 million) from petroleum and natural gas marketers, $48.1 million (December 31, 2013 – $19.5 million) from partners in jointly owned assets, and $39.4 million (December 31, 2013 – $16.6 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 2014, Tourmaline had four 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. Receivables are typically collected within one to three months of the bill being issued to the partner. The Company attempts to mitigate the risk from receivables with partners 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 asset 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 asset partners; however, the Company does have the ability to withhold production from 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, 2014, the Company has $3.4 million (December 31, 2013 – $0.8 million) over 90 days. The Company is satisfied that these amounts are substantially collectible.

The carrying amount of cash and cash equivalents, accounts receivable 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, 2014 (December 31, 2013 – nil) and did not provide for any doubtful accounts nor was it required to write-off any receivables during the year ended December 31, 2014 (December 31, 2013 – 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, 2014 is approximately $701.3 million (December 31, 2013 – $385.6 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, 2014, 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, 2014:

(000s) Carrying Amount Contractual Cash Flow Less Than One Year One – Two Years Two – Five Years More Than Five Years
Non-derivative financial liabilities:
Trade and other payables $ 701,336 $ 701,336 $ 701,336 $ – $ – $ –
Revolving credit facility (1) 670,291 722,449 – – 722,449 –
Term debt (2) 248,563 303,955 11,129 11,129 281,697 –
Derivative financial liabilities:
Financial commodity contracts 8,200 8,200 1,844 6,356 – –
$ 1,628,390 $ 1,735,940 $ 714,309 $ 17,485 $ 1,004,146 $ –
(1) Includes interest expense at 2.82% being the rate applicable to outstanding debt on the credit facility at December 31, 2014.
(2) Includes interest expense at an annual rate of 4.47% being the fixed rate on the term debt (including the interest rate swap) at December 31, 2014.

(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, 2014. 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 for the year ended December 31, 2014 would have decreased or increased shareholders’ equity and net income by $5.6 million (December 31, 2013 – $2.5 million). 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 or 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, 2014, 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 not offset any financial assets and liabilities, in the consolidated statements of financial position.

The Company has the following financial derivative contracts in place as at December 31, 2014(1):

2015 2016 2017 2018 2019 Fair Value
Gas
Fixed Price mmbtu/d 5,000 – – – – $2,287
USD$/
mmbtu		 $4.21
Nymex Call Options (Writer) mmbtu/d – – 20,000 20,000 – $(2,789)
USD$/
mmbtu		 $5.00 $5.00
Oil
Financial Swaps bbls/d 1,474 400 – – – $18,761
USD$/bbl $88.40 $80.10
Costless Collars bbls/d 1,300 – – – – $13,709
USD$/bbl $81.15 – $94.29
Financial Call Swaptions (2) bbls/d – 1,200 – – – $(434)
USD$/bbl $- $86.13
Total Fair Value (000s) $31,534
(1) The volumes and prices reported are the weighted average volumes and prices for the period.
(2) These are European swaptions whereby the Company provides the option to extend an oil swap into the period subsequent to the call date, or retroactively fix the price on the volumes under the contract.

The Company has entered in to the following financial derivative contracts subsequent to December 31, 2014:

Type of Contract Quantity Time Period Contract Price
Oil Financial Swap 2,000 Bbls/d April 2015 – June 2015 USD $59.30/bbl average
Oil Financial Call Swaptions (1) 500 Bbls/d April 2015 – June 2015 USD $57.47/bbl
Gas Financial Swap 5,000 MMbtu/d April 2015 – October 2015 USD $3.05/MMbtu
Oil Financial Swap 1,000 Bbls/d July 2015 – September 2015 USD $62.97/bbl average
Oil Financial Call Swaptions (2) 1,500 Bbls/d July 2015 – September 2015 USD $59.91/bbl average
Oil Financial Call Swaptions (3) 1,000 Bbls/d October 2015 – December 2015 USD $62.97/bbl average
(1) This option can be called monthly on the last day of each month that has just passed to double the volumes under contract.
(2) One time option to call on June 30, 2015.
(3) One time option to call on September 30, 2015.

The Company has entered into one interest rate swap arrangement:

(000s)
Term Type
(Floating to Fixed)		 Amount Company Fixed
Interest Rate(1)		 Counter Party
Floating Rate Index		 Fair Value
Nov 28, 2014 – Nov 28, 2019 Swap $ 250,000 2.065% Floating Rate $ (4,163)
(1) Canadian Dealer offer rate, excluding stamping and stand-by fees.

The following table provides a summary of the unrealized gains and losses on financial instruments for the years ended December 31, 2014 and 2013:

Years Ended
December 31,
(000s) 2014 2013
Unrealized gain (loss) on financial instruments — commodity contracts $ 38,098 $ (9,543 )
Unrealized gain (loss) on financial instruments — interest rate swaps (3,483 ) (503 )
Total unrealized gain (loss) on financial instruments $ 34,615 $ (10,046 )

As at December 31, 2014, 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, after-tax earnings would have been $3.7 million lower (December 31, 2013 – $3.8 million lower). An equal and opposite impact would have occurred to after-tax earnings 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.

The Company has the following physical contracts in place at December 31, 2014(1):

2015 2016 2017 2018 2019
Gas
Fixed Price – AECO mcf/d 163,566 3,527 – – –
CAD$/mcf $ 4.26 $ 4.20
Basis Differentials (2) mmbtu/d 42,603 50,838 22,500 22,500 22,500
USD$/mmbtu $ (0.51 ) $ (0.47 ) $ (0.46 ) $ (0.46 ) $ (0.46 )
AECO Call Options (Writers)/Call Swaptions (3) mcf/d 36,136 134,511 66,375 42,669 –
CAD$/mcf $ 4.23 $ 4.34 $ 4.76 $ 4.80
(1) Transactions with common terms have been aggregated and presented at the weighted average price.
(2) Tourmaline also has 22.5 mmcf/d of Nymex-AECO basis differentials at $0.46 from 2020-2022.
(3) These are European swaptions whereby the Company provides the option to extend a gas swap into the period subsequent to the call date or increase the volumes under contract.

The Company has entered into the following physical contracts subsequent to December 31, 2014:

Type of Contract Quantity Time Period Contract Price
Gas Fixed Price – AECO 35,000 GJs/d April 2015 – October 2015 CAD$2.86/GJ average
Gas Call Writer (1) 20,000 GJs/d April 2015 – October 2015 CAD$2.93/GJ average
Gas Fixed Price – AECO 50,000 GJs/d April 2015 – December 2015 CAD$2.83/GJ average
Gas Fixed Price – Stn 2. 10,000 GJs/d April 2015 – December 2015 CAD$2.65/GJ average
Gas Fixed Price – AECO 10,000 GJs/d November 2015 – March 2016 CAD$3.21/GJ average
Gas Fixed Price – AECO 10,000 GJs/d January 2016 – December 2016 CAD$3.05/GJ average
Basis Differential 20,000 MMbtu/d April 2015 – March 2020 Chicago GDD less USD$0.68/MMbtu
(1) This option can be called monthly on the last day of each month.

(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 annualized cash flow, which is defined as long-term bank debt plus working capital (adjusted for the fair value of financial instruments), to annualized cash flow (based on the most recent quarter), 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, 2014, the Company’s ratio of net debt to annualized cash flow was 1.22 to 1.0 (December 31, 2013 – 1.30 to 1.0).

As at December 31,
(000s) 2014 2013
Net debt:
Bank debt $ (918,854 ) $ (590,319 )
Working capital (deficit) (189,928 ) (245,314 )
Fair value of financial instruments – short-term (asset) liability (33,727 ) 2,691
Net debt $ (1,142,509 ) $ (832,942 )
Annualized cash flow:
Cash flow from operating activities for Q4 $ 201,188 $ 128,852
Change in non-cash working capital 32,050 31,880
Cash flow for Q4 $ 233,238 $ 160,732
Annualized cash flow (based on most recent quarter annualized) $ 932,952 $ 642,928
Net debt to annualized cash flow 1.22 1.30

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, 2013.

6. EXPLORATION AND EVALUATION ASSETS

(000s)
As at January 1, 2013 $ 639,933
Capital expenditures 158,264
Transfers to property, plant and equipment (note 7) (96,594 )
Acquisitions 35,405
Divestitures (3,356 )
Expired mineral leases (33,127 )
As at December 31, 2013 $ 700,525
Capital expenditures 186,093
Transfers to property, plant and equipment (note 7) (227,664 )
Acquisitions 30,037
Divestitures (29,817 )
Expired mineral leases (23,541 )
As at December 31, 2014 $ 635,633

Exploration and evaluation (“E&E”) assets consist of the Company’s exploration projects which are pending the determination of proven and/or probable reserves. Additions represent the Company’s share of costs on E&E assets during the year. Expired mineral lease expenses have been included in the “Depletion, depreciation and amortization” line item on the consolidated statements of income and comprehensive income.

Impairment Assessment

In accordance with IFRS, an impairment test is performed if the Company identifies an indicator of impairment. At December 31, 2014 and 2013, the Company determined that no indicators of impairment existed on its E&E assets; therefore an impairment test was not performed.

7. PROPERTY, PLANT AND EQUIPMENT

Cost

(000s)
As at January 1, 2013 $ 3,305,685
Capital expenditures 1,027,602
Transfers from exploration and evaluation (note 6) 96,594
Change in decommissioning liabilities (note 8) 5,109
Acquisitions 287,512
Divestitures (57,702 )
As at December 31, 2013 $ 4,664,800
Capital expenditures 1,873,851
Transfers from exploration and evaluation (note 6) 227,664
Change in decommissioning liabilities (note 8) 28,371
Acquisitions 194,525
Divestitures (255,594 )
As at December 31, 2014 $ 6,733,617

Accumulated Depletion, Depreciation and Amortization

(000s)
As at January 1, 2013 $ 494,943
Depletion, depreciation and amortization 323,112
Divestitures (3,040 )
As at December 31, 2013 $ 815,015
Depletion, depreciation and amortization 492,450
Divestitures (40,121 )
As at December 31, 2014 $ 1,267,344

Net Book Value

(000s)
As at December 31, 2013 $ 3,849,785
As at December 31, 2014 $ 5,466,273

Future development costs for the year ended December 31, 2014 of $4,610.0 million (December 31, 2013 – $3,197.0 million) were included in the depletion calculation.

Capitalization of G&A and Share Based Payments

A total of $19.3 million in G&A expenditures have been capitalized and included in E&E and PP&E assets at December 31, 2014 (December 31, 2013 – $15.0 million). Also included in E&E and PP&E are non-cash share-based payments of $28.8 million (December 31, 2013 – $19.3 million).

Impairment Assessment and Testing

In accordance with IFRS, an impairment test is performed if the Company identifies an indicator of impairment. At December 31, 2014, the Company determined that indicators of impairment exist for two of its CGUs due to the recent decline in the current and forward commodity prices for oil and natural gas.

An impairment is recognized if the carrying value of a CGU exceeds the recoverable amount for that 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, 2014 on the Company’s PP&E assets using a pre-tax discount rate of 10% and the following forward commodity price estimates:

Year WTI Oil (US$/bbl)(1) Foreign Exchange Rate(1) Edmonton Light Crude Oil (Cdn$/bbl)(1) AECO Gas (Cdn$/mmbtu)(1)
2015 64.17 0.8533 67.89 3.38
2016 76.67 0.8683 83.52 3.83
2017 83.33 0.8683 90.96 4.06
2018 87.08 0.8683 95.26 4.41
2019 90.67 0.8683 99.33 4.76
2020 94.30 0.8683 103.80 4.97
2021 96.59 0.8683 106.16 5.18
2022 98.36 0.8683 108.10 5.36
2023 100.18 0.8683 110.09 5.54
2024 102.02 0.8683 112.13 5.70
Thereafter 103.88 0.8683 114.17 5.80
(1) Source: 3 Consultants’ average, GLJ Petroleum Consultants, McDaniel & Associates Consultants, and Sproule Associates price forecasts, effective January 1, 2015

The Company has determined that there was no impairment to PP&E at December 31, 2014 (December 31, 2013 – nil).

Corporate Acquisition

On April 24, 2014, the Company acquired all of the issued and outstanding shares of Santonia Energy Inc. (“Santonia”). As consideration, the Company issued 3,228,234 common shares at a price of $54.94 per share. Total transaction costs incurred by the Company of $1.5 million associated with this acquisition were expensed in the consolidated statement of income and comprehensive income.

The acquisition of Santonia resulted in an increase in lands and production in a core area of the Alberta Deep Basin.

Results from operations for Santonia 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, 2013 by independent reserve engineers using proved plus probable reserves discounted at a rate of 12% and updated internally to the date of the corporate acquisition of April 24, 2014. The allocation of net assets acquired is based on the best available information at the time and could be subject to further change. The acquisition has been accounted for using the purchase method based on estimated fair values as follows:

(000s) Santonia Energy Inc.
Fair value of net assets acquired:
Cash $ 2,445
Working capital deficiency (10,965 )
Property, plant and equipment 167,473
Exploration and evaluation 19,058
Bank debt (32,079 )
Decommissioning obligations (8,487 )
Deferred income tax asset 39,914
Total $ 177,359
Consideration:
Common shares issued $ 177,359

Included in the consolidated statements of income and comprehensive income for the year ended December 31, 2014 are the following amounts relating to Santonia Energy Inc. since April 24, 2014:

(000s)
Oil and natural gas sales $ 28,871
Net income and comprehensive income $ 6,890

If the Company had acquired Santonia on January 1, 2014, the pro-forma results of the oil and gas sales and net income and comprehensive income for the year ended December 31, 2014 would have been as follows:

(000s) As Stated Santonia Pro Forma
Year Ended
December 31, 2014
Oil and natural gas sales $ 1,379,393 $ 17,482 $ 1,396,875
Net income and comprehensive income $ 488,872 $ 3,090 $ 491,962

Acquisition of Oil and Natural Gas Properties

For the year ended December 31, 2014, the Company completed property acquisitions for total cash consideration of $33.0 million (December 31, 2013 – $226.9 million) and an additional $2.2 million in non-cash consideration (December 31, 2013 – $88.6 million). The Company also assumed $4.9 million in decommissioning liabilities (December 31, 2013 – $7.3 million).

Disposition of Oil and Natural Gas Properties

On December 23, 2014, the Company completed the sale of a 25% working interest in its Peace River High complex for cash consideration of $500.0 million (before customary adjustments) to Canadian Non-Operated Resources Corp. (“CNOR”). The net book value of oil and natural gas properties disposed was $236.5 million and the gain on disposition was $266.2 million. The Company will continue to be the operator of all jointly-owned assets. Under the terms of the arrangement, the Company has committed to spend $400.0 million gross ($300.0 million net) per year over the next 5 years. The committed capital expenditure can be deferred to future periods in the event of an economic downturn, and as agreed upon by both parties. As part of the capital commitment, the Company also agreed to carry CNOR for the first $87.1 million spent (CNOR share) on specified capital projects. At December 31, 2014, approximately $44.5 million remained to be spent on these specified capital projects.

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 $157.5 million (December 31, 2013 – $118.9 million), with some abandonments expected to commence in 2021. A risk-free rate of 2.36% (December 31, 2013 – 3.24%) and an inflation rate of 2.0% (December 31, 2013 – 2.0%) were used to calculate the fair value of the decommissioning obligations. The decommissioning obligations at December 31, 2014 have been adjusted by approximately $14.1 million primarily due to changes in the estimates of the risk free rate during the year (December 31, 2013 – $5.1 million).

(000s) Years Ended
December 31,
2014 2013
Balance, beginning of year $ 76,037 $ 64,757
Obligation incurred 14,257 10,193
Obligation incurred on corporate acquisitions 8,487 –
Obligation incurred on property acquisitions 4,881 7,347
Obligation divested (5,676 ) (960 )
Obligation settled (413 ) (2,254 )
Accretion expense 2,351 2,038
Change in future estimated cash outlays 14,114 (5,084 )
Balance, end of year $ 114,038 $ 76,037

9. BANK DEBT

(000s) Years Ended
December 31,
2014 2013
Revolving Credit Facility(1) $ 673,437 $ 592,322
Term Debt(1) 249,239 –
Debt Issue Costs (3,822 ) (2,003 )
Bank Debt $ 918,854 $ 590,319
(1) Amounts shown net of prepaid interest.

The Company has a covenant-based, unsecured, bank credit facility in place with a syndicate of bankers. This facility is a three-year extendible revolving facility in the amount of $1,550.0 million plus a $50.0 million operating revolver with an initial maturity date of June 2017. 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 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 1.50 to 3.15 percent over bankers’ acceptance rates depending on the Company’s senior debt to adjusted 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 senior debt (which means, generally the indebtedness, liabilities and obligations of the Company to the lenders under the facility) to adjusted EBITDA shall not exceed 3:1, (ii) the ratio of total debt to adjusted EBITDA shall not exceed 4:1, and (iii) the ratio of senior debt to total capitalization shall not exceed 0.5:1. At December 31, 2014, adjusted EBITDA for the purposes of the above noted covenant calculations was $952.5 million (December 31, 2013 – $540.4 million), on a rolling four quarter basis. As at, and for the periods ending December 31, 2014 and December 31, 2013 the Company is in compliance with all debt covenants.

On November 3, 2014, the Company entered into a five-year term loan agreement with a Canadian Chartered Bank for $250.0 million, bearing an annual interest rate of 240 basis points over the applicable bankers’ acceptance rate. The covenants for the term loan are the same as the Company’s syndicated credit facility and will rank equally with the obligations under the syndicated facility.

The Company’s aggregate borrowing capacity is now $1.85 billion.

As at December 31, 2014, the Company had $248.6 million in long term debt outstanding and $670.3 million drawn against the revolving credit facility for total bank debt of $918.9 million (net of prepaid interest and debt issue costs) (December 31, 2013 – $590.3 million). In addition, Tourmaline has outstanding letters of credit of $2.4 million (December 31, 2013 – $2.2 million), which reduce the credit available on the facility. The effective interest rate on the Company’s borrowings under the bank facility for the year ended December 31, 2014 was 2.93% (December 31, 2013 – 3.06%).

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:

(000s) Years Ended
December 31,
2014 2013
Balance, beginning of year $ 17,877 $ 16,298
Share of subsidiary’s net income for the year 12,129 1,579
Balance, end of year $ 30,006 $ 17,877

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

Year Ended
December 31, 2014		 Year Ended
December 31, 2013
(000s) except share amounts Number of Shares Amount Number of Shares Amount
Balance, beginning of year 189,804,864 $ 3,062,432 174,813,059 $ 2,599,614
For cash on public offering of common shares (1)(2)(3) 4,615,198 219,222 9,275,000 343,881
For cash on public offering of flow-through common shares (1)(2)(4)(5) 1,430,053 74,939 1,760,000 67,218
Issued on corporate acquisitions 3,228,234 177,359 – –
For cash on exercise of stock options 4,083,763 66,473 3,956,805 47,023
Contributed surplus on exercise of stock options – 24,925 – 17,819
Share issue costs – (13,332 ) – (17,633 )
Tax effect of share issue costs – 3,360 – 4,510
Balance, end of year 203,162,112 $ 3,615,378 189,804,864 $ 3,062,432
(1) 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. The implied premium on the flow-through common shares was determined to be $6.6 million or $7.90 per share. A total of 30,000 common shares and 85,000 flow-through common shares were purchased by insiders. As at December 31, 2013, the Company had spent the full committed amount. The expenditures were renounced to investors in February 2014 with an effective renunciation date of December 31, 2013.
(2) On October 8, 2013, the Company issued 3.495 million common shares at a price of $41.75 per share and 0.925 million flow-through common shares at a price of $51.60 per share, for total gross proceeds of $193.6 million. The implied premium on the flow-through common shares was determined to be $9.1 million or $9.85 per share. A total of 45,000 common shares and 75,000 flow-through common shares were purchased by insiders. As at December 31, 2013, the Company had spent the full committed amount. The expenditures were renounced to investors in February 2014 with an effective renunciation date of December 31, 2013.
(3) On February 12, 2014, the Company issued 4.615 million common shares at a price of $47.50 per share for total gross proceeds of $219.2 million. A total of 15,198 common shares were purchased by insiders.
(4) On June 2, 2014, the Company issued 1.15 million flow-through shares at a price of $68.15 per share for total gross proceeds of $78.4 million. The implied premium on flow-through common shares was determined to be $15.6 million or $13.55 per share. A total of 122,000 flow-through common shares were purchased by insiders. As at December 31, 2014, the Company had spent the full committed amount. The expenditures were renounced to investors in February 2015 with an effective renunciation date of December 31, 2014.
(5) On November 28, 2014, the Company issued 0.28 million flow-through shares at a price of $57.00 per share for total gross proceeds of $16.0 million. The implied premium on flow-through common shares was determined to be $3.8 million or $13.62 per share. As at December 31, 2014, the Company had spent $2.5 million on eligible expenditures and is committed to spend the remainder of $13.5 million on qualified exploration and expenditures by December 31, 2015. The expenditures will be renounced to investors with an effective renunciation date of December 31, 2014.

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:

(000s) Years Ended
December 31,
2014 2013
Income before taxes $ 685,153 $ 218,375
Canadian statutory rate (1)(2) 25.13 % 25.14 %
Expected income taxes at statutory rates (3) 172,160 54,906
Effect on income tax of:
Share-based payments 7,249 4,865
Flow-through shares 4,200 7,161
Effect of change in corporate tax rate and other 543 1,750
Deferred income tax $ 184,152 $ 68,682
(1) The statutory rate consists of the combined statutory tax rate for the Company and its subsidiary for the year ended December 31, 2014.
(2) The allocation of taxable income between the provinces resulted in a 0.01% change in the statutory tax rate.
(3) May not calculate due to rounding.

The movement in deferred tax balances during the years ended December 31, 2014 and 2013 are as follows:

(000s) Balance January 1, 2014 Recognized in Net Earnings Recognized
in Liabilities		 Recognized
in Equity		 Acquired in Business Combination Balance
December 31, 2014
Deferred tax liabilities:
Exploration and evaluation and property, plant and equipment $ 422,717 $ 184,167 $ 16,187 $ – $ (23,833 ) $ 599,238
Risk management contracts (1,825 ) 8,855 – – (132 ) 6,898
Long-term asset 598 1,202 – – – 1,800
Deferred tax assets:
Decommissioning obligations (19,158 ) (7,433 ) – – (2,122 ) (28,713 )
Long-term obligations (1,799 ) 939 – – – (860 )
Non-capital losses (127,052 ) (8,108 ) – – (13,827 ) (148,987 )
Share issue costs (8,456 ) 4,530 – (3,360 ) – (7,286 )
Deferred tax liability (asset) $ 265,025 $ 184,152 $ 16,187 $ (3,360 ) $ (39,914 ) $ 422,090
(000s) Balance January 1, 2013 Recognized in Net Earnings Recognized
in Liabilities		 Recognized in Equity Acquired in Business Combination Balance December 31, 2013
Deferred tax liabilities:
Exploration and evaluation and property, plant and equipment $ 269,606 $ 128,649 $ 24,462 $ – $ – $ 422,717
Assets held for sale 8,181 (8,181 ) – – – –
Long-term asset 645 (47 ) – – – 598
Deferred tax assets:
Decommissioning obligations (16,189 ) (2,969 ) – – – (19,158 )
Short-term obligation (37 ) 37 – – – –
Risk management contracts 700 (2,525 ) – – – (1,825 )
Long-term obligations (2,716 ) 917 – – – (1,799 )
Non-capital losses (75,056 ) (51,996 ) – – – (127,052 )
Share issue costs (8,743 ) 4,797 – (4,510 ) – (8,456 )
Deferred tax liability (asset) $ 176,391 $ 68,682 $ 24,462 $ (4,510 ) $ – $ 265,025

As at December 31, 2014, the Company has estimated federal tax pools of $4.3 billion (2013 – $3.4 billion) available for deduction against future taxable income. The Company has $592.0 million of unused tax losses expiring between 2023 and 2033.

13. EARNINGS PER SHARE

Basic earnings-per-share was calculated as follows:

Years Ended
December 31,
2014 2013
Net earnings for the year (000s) $ 488,872 $ 148,114
Weighted average number of common shares – basic 199,010,771 183,710,423
Earnings per share – basic $ 2.46 $ 0.81

Diluted earnings-per-share was calculated as follows:

Years Ended
December 31,
2014 2013
Net earnings for the year (000s) $ 488,872 $ 148,114
Weighted average number of common shares – diluted 202,776,972 188,244,300
Earnings per share – fully diluted $ 2.41 $ 0.79

There were 5,110,500 options excluded from the weighted-average share calculation for the year ended December 31, 2014 because they were anti-dilutive (December 31, 2013 – 4,703,000). At December 31, 2014 there were 203,162,112 basic common shares outstanding (December 31, 2013 – 189,804,864).

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 20,316,211 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.

Years Ended
December 31,
2014 2013
Number of Options Weighted Average Exercise Price Number of Options Weighted Average Exercise Price
Stock options outstanding, beginning of year 16,028,651 $ 27.95 15,325,232 $ 19.87
Granted 5,346,500 46.92 4,843,000 40.47
Exercised (4,083,763 ) 16.28 (3,956,805 ) 11.88
Forfeited (244,888 ) 45.22 (182,776 ) 28.69
Stock options outstanding, end of year 17,046,500 $ 36.44 16,028,651 $ 27.95

The weighted average trading price of the Company’s common shares was $49.47 during the year ended December 31, 2014 (December 31, 2013 – $39.28).

The following table summarizes stock options outstanding and exercisable at December 31, 2014:

Range of Exercise Price Number Outstanding at
Period End		 Weighted Average Remaining Contractual Life Weighted Average Exercise Price Number Exercisable at
Period End		 Weighted Average Exercise Price
$10.00 – $18.35 1,639,699 0.64 $ 18.26 1,639,699 $ 18.26
$20.68 – $29.93 3,351,305 1.91 26.91 3,037,972 27.25
$30.76 – $39.57 2,893,996 2.86 33.06 1,716,663 32.09
$40.18 – $48.99 7,501,500 4.19 42.13 1,319,000 40.89
$51.47 – $56.76 1,660,000 4.52 53.85 – –
17,046,500 3.21 $ 36.44 7,713,334 $ 28.75

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:

Years Ended
December 31,
2014 2013
Fair value of options granted (weighted average) $ 14.85 $ 14.22
Risk-free interest rate 2.67 % 2.88 %
Estimated hold period prior to exercise 4 years 4 years
Expected volatility 35 % 40 %
Forfeiture rate 2 % 2 %
Dividend per share $ 0.00 $ 0.00

15. OTHER INCOME

Years Ended
December 31,
(000s) 2014 2013
Processing income $ 17,669 $ 6,400
Interest income 243 193
Other 64 (70 )
Total other income $ 17,976 $ 6,523

16. FINANCE EXPENSES

Years Ended
December 31,
(000s) 2014 2013
Finance expenses:
Interest on loans and borrowings $ 24,632 $ 12,220
Transaction costs on corporate and property acquisitions 1,496 1,100
Accretion of decommissioning obligations 2,351 2,038
Total finance expenses $ 28,479 $ 15,358

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:

Years Ended
December 31,
(000s) 2014 2013
Operating $ 20,083 $ 16,275
General and administration 13,520 11,640
Total employee compensation costs $ 33,603 $ 27,915

18. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital is comprised of:

Years Ended
December 31,
(000s) 2014 2013
Source/(use) of cash:
Trade and other receivables $ (67,171 ) $ (52,173 )
Deposit and prepaid expenses (4,499 ) (1,609 )
Trade and other payables 318,111 159,956
246,441 106,174
Working capital (deficiency)/surplus acquired (10,965 ) –
$ 235,476 $ 106,174
Related to operating activities $ (13,621 ) $ (47,522 )
Related to investing activities $ 249,097 $ 153,696

Cash interest paid was $20.5 million for the year ended December 31, 2014 (December 31, 2013 – $8.9 million).

19. COMMITMENTS

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

PAYMENTS DUE BY YEAR

(000s) 1 Year 2-3 Years 4-5 Years >5 Years Total
Operating leases $ 4,371 $ 10,507 $ 10,692 $ 1,325 $ 26,895
Firm transportation and processing agreements 104,575 288,052 269,429 622,076 1,284,132
Capital commitments (1) 350,552 620,629 600,000 – 1,571,181
Flow through share commitments 13,434 – – – 13,434
Revolving credit facility (2) – 722,449 – – 722,449
Term debt (3) 11,129 22,257 270,569 – 303,955
$ 484,061 $ 1,663,894 $ 1,150,690 $ 623,401 $ 3,922,046
(1) Includes drilling commitments, and capital spending commitments under the joint arrangement in the Spirit River complex of $344.5 million in year 1 and $300.0 million per year thereafter until 2019. The capital spending commitment can be deferred to future periods in the event of an economic downturn, and as agreed upon by both parties.
(2) Includes interest expense at an annual rate of 2.82% being the rate applicable to outstanding debt on the credit facility at December 31, 2014.
(3) Includes interest expense at an annual rate of 4.47% being the applicable rate on the term debt net of the interest rate swap at December 31, 2014.

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, 2014 and 2013. Non-executive directors do not receive short-term compensation.

Compensation of Key Management

Years Ended
December 31,
(000s) 2014 2013
Short-term compensation (1) $ 4,208 $ 3,463
Share-based payments (2) 7,704 6,968
Total compensation paid to key management $ 11,912 $ 10,431
(1) Short-term compensation includes employee benefits provided to key management personnel.
(2) Based on the grant date fair value of the applicable awards. The fair value of options granted is estimated at the date of grant using a Black-Scholes Option-Pricing Model. The total share-based payment of options issued in 2014 is based on a weighted average fair value estimated to be $18.88 per option (2013- $14.45 per option).

ABOUT TOURMALINE OIL CORP.

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

FOR FURTHER INFORMATION, PLEASE CONTACT:

Tourmaline Oil Corp.
Michael Rose
Chairman, President and Chief Executive Officer
(403) 266-5992; info@tourmalineoil.com

OR

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

OR

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

OR

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

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