TOURMALINE OIL CORP. EARNS $80.1 MILLION IN 2015

Calgary, Alberta – Tourmaline Oil Corp. (TSX:TOU) (“Tourmaline” or the “Company”) achieved exceptional growth in reserves (30%) and production (37%) in 2015 while delivering strong profitability.

 

HIGHLIGHTS

  • Q4 earnings after tax of $34.6 million ($0.16/diluted share), re-emphasizing the fundamental profitability of Tourmaline’s EP business even in a very low commodity price environment. Full year 2015 earnings were $80.1 million ($0.37/diluted share).
  • Q4 2015 cash flow(1) of $242.4 million ($1.10/diluted share) a 23.0% increase over Q3 2015 cash flow.
  • All in cash costs (operating, transportation, general and administrative and financing) of $7.56/boe in 2015, a 5.4% reduction from 2014 costs of $7.99/boe. Q4 2015 operating costs were $4.23/boe. 2015 cash G&A costs were $0.45/boe, amongst the lowest in Industry. The Company will continue to pursue cost reductions in all aspects of the EP business.
  • Fourth quarter 2015 production averaged 179,610 boepd, a 37% increase over the fourth quarter of 2014. Full year 2015 average production of 154,403 boepd represented a 37% increase (29% per diluted share) over 2014 average production of 112,929 boepd. Quarter over quarter production growth was a very strong 19.5%.
  • Proved plus probable reserves (“2P”) increased to 1,108.3 mmboe during 2015, a 30% increase over 2014 reserves of 855.8 mmboe and a 36% increase (22% per diluted share) before taking into account annual production of 56.4 mmboe. Total proved (“TP”) reserves increased 48% and proved developed producing (“PDP”) reserves increased by 80% over 2014 before taking into account annual production of 56.4 mmboe.
  • After seven years, Tourmaline has 1.1 billion boe of low cost, economic reserves and currently produces over 1.0 bcf/day of natural gas and 25,000 bpd of oil, condensate and NGLs.
  • In 2015, Tourmaline’s E&P capital program of approximately $1.45 billion generated over 90,000 boe/d of new production resulting in capital efficiency of approximately $15,500 boe/d, an improvement of 26% over 2014 E&P capital efficiency of approximately $20,900 boe/d.
  • 2015 2P finding, development and acquisition (“FD&A”) cost of $5.89/boe including changes in future development capital (“FDC”), 2015 TP FD&A cost of $8.43/boe including FDC and 2015 PDP FD&A cost of$13.42/boe, all are the lowest in the Company’s seven year history.
  • The estimated 2P reserve NAV (PV10 before tax) at year end 2015 was $37.26/per diluted share. The Company has only booked 999 net locations (1,196 gross) in the 2015 reserve report of a well-defined future development drilling inventory of 12,352 gross locations. The infrastructure skeleton, which is now complete in all three core areas, essentially reaches all of the future locations.
  • The 2016 capital program has been reduced to $775 million including acquisitions, a 29.5% drop from the originally planned $1.1 billion program, with no impact on 2016 production estimates. 2016 EP capital spending of $610 million is down 58% from the 2015 EP capital program.

 

2016 EP CAPITAL PROGRAM

Tourmaline is reducing full year 2016 capital spending to $775.0 million, including acquisitions, given current low commodity prices. First half 2016 EP spending of $350.0 million continues as originally planned; the second half EP capital budget has been reduced to $275.0 million. The second half program will be primarily directed to drilling, completions and tie-ins, with minimal facilities projects in this reduced budget outlook. Full year 2016 production guidance remains unchanged at 200,000 boepd as individual well performance and production addition efficiency continue to improve.

The revised full year EP budget of $610 million is at the low end of the estimated ‘maintenance’ capital budget required to keep annual production equivalent to the 2015 exit volume, not including acquisitions made in 2016. Additional new facility expenditures are not required to meet current 2016 and 2017 production plans. The 2016 capital program is a cash flow budget as originally planned; the Company is currently forecasting full year 2016 cash flow of $791.9 million. The Company will continue to observe the commodity price outlook and make adjustments to the full year capital budget accordingly.

Tourmaline commenced the 2016 EP program with 12 operated drilling rigs in January; the rig fleet has been steadily reduced through the first quarter so as to stay on budget. The Company is now down to one operated rig. Tourmaline plans to operate two rigs intermittently through break-up/Q2 and increase to a seven or eight rig program for the third quarter of 2016.

Tourmaline has also disposed of $18.0 million of minor, non-operated assets with production of approximately 425 boepd thus far in 2016, and is pursuing other, non-material, cash generating opportunities.

Exit 2015 net debt(2) was $1.55 billion; the Company is forecasting exit 2016 net debt of approximately $1.52 billion.

 

COST MANAGEMENT STRATEGY

Tourmaline was very successful in reducing both capital and operating costs during 2015. Drill and complete capital costs have been reduced by approximately 25% across all three operated areas year over year. The Company is targeting a further 10% reduction in capital costs in 2016 and has largely achieved that goal with the first quarter drilling and completions activity to date.

All in cash costs in the fourth quarter of 2015 were $7.13/boe, the lowest in the Company’s history. Fourth quarter operating costs were $4.23/boe, slightly lower than guidance and amongst the lowest in Industry. Tourmaline is targeting further cost reductions in 2016.

G&A cash costs were $0.45/boe in 2015, below guidance of $0.60/boe. The Company is anticipating full year 2016 G&A costs of $0.50/boe. Tourmaline only has 183 full time employees in the office and field, and has not had to undertake commodity price related staff reductions

 

EP PROGRAM HIGHLIGHTS

2015 new production of 90,000 boepd was added via an EP capital program of $1.45 billion, yielding production efficiencies of approximately $15,500/boepd, the lowest in company history. The 2015 capital program included $491 million directed towards new facilities and pipelines. Production efficiencies will continue to improve in 2016 in part due to reduced 2016 facility and pipeline expenditures of only $100.0 million.

First quarter 2016 production has been ranging between 190,000 and 205,000 boepd, slightly ahead of forecast. The Company has approximately 12 additional wells to bring on-stream prior to spring break-up.

NEBC Montney production reached a record 55,000 boepd in the first quarter of 2016; the Company has three multi-well pads to frac during the second quarter that will keep the Tourmaline operated facility network in BC full. The complex is expected to grow by an additional 10,000 boepd in 2017 through the new Doe plant, now scheduled to be constructed in the first quarter of 2017. The incremental 100 mmcfpd Sundown development drilling and facility project is scheduled for 2018, providing additional, significant long term growth for Tourmaline’s BC Montney complex.

The Alberta Deep Basin Wilrich and Notikewin sweet spot development strategy continues to deliver well performance significantly above the economic base case template. The average 30 day IP for Deep Basin horizontals has been 10.1 mmcfpd over the past four months (46 horizontal wells).

As previously announced, the Company closed the acquisition of key Wilrich and Notikewin sweet spot assets in the greater Edson-Ansell-Minehead area during the first quarter, adding approximately 48.0 million boe of new reserves on a 2P basis (Company estimate), 4,000 boepd of production, and over 100 incremental sweet spot drilling locations. The Company has subsequently completed redirection of the acquired production into the Tourmaline facility network, significantly reducing operating costs for the new production stream. The first step-out to the Q4 2015 high rate Minehead Notikewin 2-27 well tested at 47 mmcfpd at a FCP of 32.5 MPa on a three-day test in early March.

The Smoky 12-30 Wilrich horizontal tested at 39.0 mmcfpd at a FCP of 13.1 MPa during the first three days of inline testing in March. The well is located within an extensive Wilrich ‘sweet-spot’ in the Smoky-Horse-Leland area that Tourmaline has been delineating over the past two years.

Ongoing delineation drilling, discoveries in new horizons (Lower Charlie Lake in Alberta, Montney Turbidite in NEBC), and the sweet spot asset consolidation program in 2015 have led to a material increase in the future drilling inventory in all three core areas to a total of 12,352 locations, up from 10,591 locations. Only 1,196 gross locations, or 9.7%, of this inventory are booked in the year-end 2015 reserve report.

 

CORPORATE SUMMARY – DECEMBER 31, 2015

 

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

Tourmaline will host a conference call tomorrow, March 8, 2016 starting at 9:00 a.m. MT (11:00 a.m. ET). To participate, please dial 1-866-225-0198 (toll-free in North America), or local dial-in 416-340-2216, a few minutes prior to the conference call.

 

Reader Advisories

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

FORWARD-LOOKING INFORMATION
This press release contains forward-looking information within the meaning of applicable securities laws. The use of any of the words “forecast”, “expect”, “anticipate”, “continue”, “estimate”, “objective”, “ongoing”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends” and similar expressions are intended to identify forward-looking information. More particularly and without limitation, this press release contains forward-looking information concerning Tourmaline’s plans and other aspects of its anticipated future operations, management focus, objectives, strategies, financial, operating and production results and business opportunities, including anticipated petroleum and natural gas production for various periods, drilling inventory or locations, cash flow and debt to cash flow levels, capital spending, cost reduction initiatives, projected operating and drilling costs, the timing for facility expansions and facility start-up dates, as well as Tourmaline’s future drilling prospects and plans, business strategy, future development and growth opportunities, prospects and asset base. The forward-looking information is based on certain key expectations and assumptions made by Tourmaline, including expectations and assumptions concerning: prevailing commodity prices and currency exchange rates; applicable royalty rates and tax laws; interest rates; future well production rates and reserve volumes; operating costs the timing of receipt of regulatory approvals; the performance of existing wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the successful completion of acquisitions and dispositions; the state of the economy and the exploration and production business; the availability and cost of financing, labour and services; and ability to market crude oil, natural gas and NGL successfully.

Statements relating to “reserves” are also deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

Although Tourmaline believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Tourmaline can give no assurances that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature it involves inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to reserves, production, revenues, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; marketing and transportation; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; ability to access sufficient capital from internal and external sources; failure to obtain required regulatory and other approvals; and changes in legislation, including but not limited to tax laws, royalties and environmental regulations. Readers are cautioned that the foregoing list of factors is not exhaustive.

Additional information on these and other factors that could affect Tourmaline, or its operations or financial results, are included in the Company’s most recently filed Management’s Discussion and Analysis (See “Forward-Looking Statements” therein) , Annual Information Form (See “Risk Factors” and “Forward-Looking Statements” therein) and other reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or Tourmaline’s website (www.tourmalineoil.com). The forward-looking information contained in this press release is made as of the date hereof and Tourmaline undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless expressly required by applicable securities laws.

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, 2015, 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, 2016 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, 2015, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 30, 2016.

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.

This news release also contains references to estimates of proved plus probable reserves attributed to the Wilrich and Notikewan assets acquired by the Company in the greater Edson-Ansell-Minehead area. Such reserves reflect Company internally estimated “gross” reserves prepared by a qualified reserves evaluator effective December 31, 2015 in accordance with the definitions and provisions contained in the COGE Handbook.

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 30, 2016.

See also the Company’s news release dated February 22, 2016 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.

FD&A COSTS
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 2016 cash flow and net debt, which are 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 2016 average production of 200,000 boepd and commodity price assumptions for natural gas (AECO – $2.55/mcf for 2016), and crude oil (WTI (US) – $41.91/bbl for 2016) and an exchange rate assumption of $0.73 (US/CAD) for 2016. To the extent such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Tourmaline on March 7, 2016 and is included to provide readers with an understanding of Tourmaline’s anticipated cash flow and net debt 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.

INDUSTRY METRICS
The terms FD&A, cash costs, operating netbacks and capital efficiency, while commonly used in the oil and gas industry, do not have standardized meanings and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.

ESTIMATED DRILLING INVENTORY
This press release discloses drilling locations in four categories: (i) proved undeveloped locations; (ii) probable undeveloped locations; (iii) unbooked locations; and (iv) an aggregate total of (i), (ii) and (iii). Of the 12,352 undrilled locations disclosed in this presentation, 711 are proved undeveloped locations, 15 are proved non-producing locations, 468 are probable undeveloped locations, 2 are probable non-producing and 11,156 are unbooked. Proved undeveloped locations, proved non-producing locations, probable undeveloped locations and probable non-producing locations are booked and derived from the Company’s most recent independent reserves evaluation as prepared by GLJ Petroleum Consultants Ltd. and Deloitte LLP as of December 31, 2015 and account for drilling locations that have associated proved and/or probable reserves, as applicable.

Unbooked locations are internal estimates based on the Company’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company’s multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

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
  • bbls/day – barrels per day
  • bbl/mmcf – barrels per million cubic feet
  • 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
  • FCP – final circulating pressure
  • 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
  • MPa – megapascal
  • mstboe – thousand stock tank barrels of oil equivalent
  • NGL – natural gas liquids

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

For the years ended December 31, 2015 and December 31, 2014

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, 2015 and 2014. Both the consolidated financial statements and the MD&A can be found at www.sedar.com. This MD&A is dated March 7, 2016.

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, forecasts, estimates or beliefs concerning, among other things, an outlook on the estimated amounts and timing of capital investment or expenditures, 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; future decommissioning obligations; 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, any 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 regulatory or third-party 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; future operating costs; and decommissioning obligations.

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 an understanding of 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

Production for the fourth quarter of 2015 averaged 179,610 boe/d, a 37% increase over the average production for the same quarter of 2014 of 130,944 boe/d. For the year ended December 31, 2015, production increased 37% to 154,403 boe/d from 112,929 boe/d in 2014. The increase in natural gas production is related to the Company’s successful exploration and production program during the year as well as the commissioning of the Doe, Musreau, Sunrise, Spirit River and Wild River gas processing facilities in the fourth quarter of 2014 allowing for significantly higher production capacity in 2015. 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, and strong condensate recoveries from new wells commencing production as the liquids-rich Montney Turbidite is developed in northeast British Columbia. Wells brought on production from the Company’s exploration and production program accounted for approximately 93% of the growth in production in 2015 over 2014, with the remainder of the change being from corporate and property acquisitions (net of dispositions).

Tourmaline expects 2016 production to average approximately 200,000 boe/d, which is consistent with previous Company guidance in the October 14, 2015 press release.

 

REVENUE

Revenue for the three months ended December 31, 2015 increased 7% to $364.8 million from $340.3 million for the same quarter of 2014. Revenue for the year ended December 31, 2015 decreased 5% to $1,297.5 million from $1,362.1 million in 2014. Revenue for the three months and year ended December 31, 2015 was significantly impacted by the decrease in realized commodity prices, even after taking into account production volumes which were 37% higher than the prior year. Total revenue also includes $72.8 million and $223.5 million in realized gains on energy marketing and hedging activities for the three and twelve months ended December 31, 2015, respectively. Revenue includes all natural gas, oil and NGL sales and realized gains and losses on financial instruments.

The realized average natural gas prices for the quarter and year ended December 31, 2015 were 27% and 29%, respectively, lower than the same periods of the prior year. The lower natural gas price reflects a lower AECO index experienced during the year. Included in the realized price is a gain on natural gas commodity contracts in the fourth quarter of 2015 of $41.6 million (year ended December 31, 2015 – gain of $148.7 million) compared to a gain of $21.7 million for the fourth quarter of 2014 (year ended December 31, 2014 – loss of $19.1 million). Realized gains on commodity contracts for the quarter ended December 31, 2015 reflect a weakening of the natural gas price relative to the average pricing on the commodity contracts. Once these unrealized gains and losses are realized they are included in the per-unit amounts.

Realized oil prices have increased by 3% for the three months ended December 31, 2015. Included in the realized price is a gain on commodity contracts of $31.2 million compared to a gain of $2.9 million in the fourth quarter of 2014. In the fourth quarter of 2015, the Company unwound its oil hedges related to the second half of 2016 resulting in a realized gain of $14.0 million, included in the above-noted gain for the quarter. For the year ended December 31, 2015, realized oil prices decreased by 21% compared to the prior year. The significant decrease in the realized price is consistent with the decrease in the benchmark price of oil during 2015 offset by gains on commodity contracts of $74.8 million compared to $1.9 million for the year ended December 31, 2014.

For the three months and year ended December 31, 2015, realized NGL prices have decreased by 51% and 60%, respectively, when compared to the same periods of the prior year. The decrease in NGL prices is consistent with the decrease in crude oil and natural gas prices over the period further impacted by an oversupply in the propane market in 2015 leading to significantly reduced prices for that commodity.

 

ROYALTIES

For the quarter ended December 31, 2015, the average effective royalty rate was 3.9% compared to 7.5% for the same quarter of 2014.

For the year ended December 31, 2015, the average effective royalty rate was 4.3% compared to 8.7% for the same period of 2014. The decrease in the average effective royalty rate for 2015 can be attributed to significantly lower commodity prices received during the period. Royalty rates are impacted by changes in commodity prices whereby the actual royalty rate decreases when prices decrease. The Company also receives gas cost allowance from the Crown, which further reduces royalties to account for the portion of expenses incurred to process and transport the Crown’s portion of natural gas.

In 2015, 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. On January 29, 2016, the Alberta Government released a new Royalty Regime effective January 1, 2017. The new regime will apply to wells drilled after the effective date, whereby all other wells will follow the old framework for a further 10 years. Although some guidance was provided as it relates to the new calculation, there is still uncertainty around some of the details. Further details are to be released by March 31, 2016. After that time, the Company will be able to further assess the expected impact of the royalty rate changes on a go-forward basis.

The Company expects its royalty rate for 2016 to be approximately 6%. The royalty rate is sensitive to commodity prices, and as such, a change in commodity prices will impact the actual rate.

 

OTHER INCOME

Other income increased from $5.3 million in the fourth quarter of 2014 to $6.9 million in the fourth quarter of 2015. For the year ended December 31, 2015, other income increased to $29.2 million compared to $18.5 million for the same period of 2014. The increase in other income is mainly due to the increase in processing capacity of Company-owned gas plants, where fees are charged to working interest partners on Tourmaline-operated wells.

 

OPERATING EXPENSES

Operating expenses include all periodic lease and field-level expenses and exclude income recoveries from processing third-party volumes. For the fourth quarter of 2015, total operating expenses were $69.8 million compared to $49.0 million in 2014. Operating costs for the year ended December 31, 2015 were $246.5 million, compared to $200.6 million for the same period of 2014, reflecting increased costs relating to the growing production base.

On a per-boe basis, the costs increased from $4.07/boe for the fourth quarter of 2014 to $4.23/boe in the fourth quarter of 2015. The slight increase is primarily related to a third party equalization payment made during the quarter and an increase in turnaround costs in the fourth quarter of 2015. For the year ended December 31, 2015, operating costs were $4.37, down from $4.87 in the prior year. The Company’s investments in processing facilities in 2014 and 2015 have reduced the volume of gas flowing to third-party facilities, leading to the reduction in operating expenses on a per-boe basis, as well as increased operational efficiencies along with fixed costs being distributed over a significantly higher production base.

The Company’s average operating cost target is approximately $4.25/boe in 2016. Actual costs per boe can change, however, depending on a number of factors, including the Company’s actual production levels.

 

TRANSPORTATION

Transportation costs for the three months ended December 31, 2015 were $32.1 million, compared to $23.9 million in the same period of 2014. Transportation costs for the year ended December 31, 2015 were $114.6 million, compared to $78.8 million for the same period of 2014, reflecting increased costs related to higher production volumes.

On a per-boe basis, transportation costs decreased from $1.99/boe in the fourth quarter of 2014 to $1.94/boe in the fourth quarter of 2015. The decrease is related to lower per-unit trucking costs on oil and NGLs in the fourth quarter of 2015 compared to the same period in the prior year.

For the twelve months ended December 31, 2015, transportation costs were $2.03/boe, up from $1.91/boe for the same period of 2014. The per-unit increase in costs in 2015 is primarily due to a new pipeline fee charged to mainline shippers and an increase in tolls leading to higher natural gas transportation expense.

 

GENERAL & ADMINISTRATIVE EXPENSES (“G&A”)

Total G&A expenses for the fourth quarter of 2015 were $5.4 million compared to $6.7 million for the same quarter of the prior year. G&A costs per boe for the fourth quarter of 2015 decreased 41% down to $0.33/boe, compared to $0.56/boe for the fourth quarter of 2014. The lower fourth quarter G&A expenses reflect an office rent incentive received as well as a reduction in compensation expense related to annual bonuses.

For the year ended December 31, 2015, total G&A expenses were $25.3 million or $0.45/boe compared to $24.9 million or $0.60/boe for the same period of 2014. Although total G&A expenditures were relatively consistent with the prior year, 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 2016 are expected to average approximately $0.50/boe. Actual costs per boe can change, however, depending on a number of factors including the Company’s actual production levels.

 

SHARE-BASED PAYMENTS

The Company uses the fair value method for the determination of non-cash related share-based payments expense. During the fourth quarter of 2015, 3,326,000 stock options were granted to employees, officers, directors and key consultants at a weighted-average exercise price of $26.73, and 40,334 options were exercised, bringing $0.9 million of cash into treasury. The Company recognized $6.8 million of share-based payment expense in the fourth quarter of 2015 compared to $7.9 million in the fourth quarter of 2014. Capitalized share-based payments for the fourth quarter of 2015 were $6.8 million compared to $7.9 million for the same quarter of the prior year. The decrease in share-based payment expense in the fourth quarter 2015 compared to 2014 reflects the decreased value attributed to the options, consistent with the drop in the Company’s share price.

For the year ended December 31, 2015, share-based payment expense totalled $30.8 million and a further $30.8 million in share-based payments were capitalized (2014 – $28.8 million and $28.8 million, respectively). The increase in share-based payment expense in 2015 compared to 2014 reflects a higher number of options outstanding offset by the decreased value attributed to the options.

 

DEPLETION, DEPRECIATION AND AMORTIZATION (“DD&A”)

DD&A expense was $166.1 million for the fourth quarter of 2015 compared to $140.3 million for the same period of 2014. The per-unit DD&A rate for the fourth quarter of 2015 was $10.05/boe compared to $11.65/boe for the same quarter of 2014.

For the year ended December 31, 2015, DD&A expense was $636.8 million (year ended December 31, 2014 – $492.5 million) with a DD&A rate of $11.30/boe (year ended December 31, 2014 – $11.95/boe). The increase in DD&A expense in 2015 over the same periods of 2014 is due to higher production volumes, as well as a larger capital asset base being depleted.

The decrease in per boe depletion in 2015 over the same periods of 2014 can be attributed to lower future development costs as drilling and completion costs have decreased over the past year thereby adding a higher proportion of reserves with lower associated future development costs, resulting in a lower depletion rate.

Mineral lease expiries for the three months and year ended December 31, 2015 were $4.7 million and $54.1 million, respectively (December 31, 2014 – $9.1 million and $23.5 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 but attempts to mitigate all expiries through land swaps, asset dispositions or drilling to maintain the lease.

 

FINANCE EXPENSES

Finance expenses totalled $11.1 million and $44.6 million for the quarter and year ended December 31, 2015, compared to $9.3 million and $29.0 million for the quarter and year ended December 31, 2014, respectively. The increased finance expenses in 2015 are largely due to higher interest expense resulting from a higher balance drawn on the credit facility, as well as a $3.1 million loss on a long-term interest rate swap. The average bank debt outstanding and the average effective interest rate on the debt during 2015 were $1,225.4 million and 2.6%, respectively (2014 – $744.0 million and 2.9%, respectively).

During the fourth quarter of 2015, the Company began drawing from the credit facility in U.S. dollars, as permitted under the credit facility, which when repaid created a foreign exchange loss. Concurrent with the draw of U.S. dollar denominated borrowings, the Company entered into cross-currency swaps to manage the foreign currency risk resulting from holding U.S. dollar denominated borrowings. The Company fixed the Canadian dollar amount for purposes of principal and interest repayment resulting in a gain on cross-currency swaps equivalent to the realized foreign exchange loss.

 

DEFERRED INCOME TAXES

For the three months ended December 31, 2015, the provision for deferred income tax expense was $18.2 million compared to $96.7 million for the same period in 2014. The decrease is primarily due to lower pre-tax earnings recorded in the fourth quarter of 2015 compared to the respective period in 2014 offset by the increase in the Alberta corporate tax rate legislated by Alberta’s new NDP government from 10% to 12% effective July 1, 2015.

For the year ended December 31, 2015, the provision for deferred income tax expense was $83.4 million compared to $184.2 million for the same period in 2014. The decrease is due to lower pre-tax earnings recorded for the year ended December 31, 2015 compared to the respective period in 2014, which was partially offset by the increase in Alberta’s corporate tax rate. The change in tax rate increased deferred income taxes for the year by $30.6 million.

 

CASH FLOW FROM OPERATING ACTIVITIES, CASH FLOW AND NET EARNINGS

Cash flow for the three months ended December 31, 2015 was $242.4 million or $1.10 per diluted share compared to $233.2 million or $1.14 per diluted share for the same period of 2014. For the year ended December 31, 2015, cash flow was $850.2 million or $3.96 per diluted share, compared to $929.0 million or $4.58 per diluted share in the prior year.

The Company had after-tax earnings for the three months and year ended December 31, 2015 of $34.6 million ($0.16 per diluted share) and $80.1 million ($0.37 per diluted share), respectively, compared to earnings of $265.2 million ($1.29 per diluted share) and $488.9 million ($2.41 per diluted share), respectively, for the same periods of 2014. The decrease in both cash flow and after-tax net earnings in 2015 reflects lower realized revenues generated in 2015 due to the low commodity price environment. The comparative periods in 2014 also benefited from the sale of a 25% working interest in the Peace River High complex for cash consideration of $500.0 million and resulted in the Company recording a gain of $266.2 million in the consolidated statement of income and comprehensive income.

 

CAPITAL EXPENDITURES

During the fourth quarter of 2015, the Company invested $325.5 million of cash consideration, net of $0.3 million in proceeds on dispositions, compared to $152.1 million for the same period of 2014, which was reduced by property dispositions of $498.1 million. Expenditures on exploration and production in 2015 were substantially reduced to $319.1 million compared to $616.2 million for the same quarter of 2014.

During 2015, the Company invested $1,536.1 million of cash consideration, net of $7.0 million in proceeds on dispositions, compared to $1,563.6 million in 2014, net of $500.6 million in proceeds on dispositions. Expenditures on exploration and production were $1,425.4 million in 2015 compared to $2,010.4 million for 2014, a decrease of $585.0 million primarily related to lower facility expenditures and significantly lower drilling and completion costs per well in 2015. Facilities expenditures in 2015 include work on the Mulligan oil battery commissioned in the third quarter of 2015, preliminary costs on the Spirit River Sour Gas Plant expansion, the Edson Gas Plant which was commissioned in the fourth quarter of 2015 and also costs on the new Brazeau Gas Plant which will be commissioned in the first half of 2016.

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

Acquisitions and Dispositions
On April 1, 2015, the Company acquired Perpetual Energy Inc.’s (“Perpetual”) interests in the West Edson area of the Alberta Deep Basin with the issuance of 6,750,000 Tourmaline shares at a price of $38.32 per share for total consideration of $258.7 million. The acquisition resulted in an increase in Property, Plant and Equipment (“PP&E”) of approximately $226.9 million and an increase in Exploration and Evaluation (“E&E”) assets of $34.2 million. The interests included Perpetual’s land interests, production, reserves and facilities that were jointly-owned with Tourmaline.

On July 20, 2015, the Company acquired all of the issued and outstanding shares of Bergen Resources Inc.
(“Bergen”). As consideration, the Company issued 725,000 common shares at a price of $33.90 per share for
total consideration of $24.6 million. Total transaction costs incurred by the Company of $0.2 million associated
with this acquisition were expensed in the consolidated statement of income and comprehensive income. The
acquisition resulted in an increase in PP&E of approximately $26.8 million and E&E assets of $2.1 million. The
acquisition of Bergen consolidated the Company’s working interest in a core area of the Peace River High.

On August 14, 2015, the Company acquired all of the issued and outstanding shares of Mapan Energy Ltd.
(“Mapan”). As consideration, the Company issued 2,718,026 common shares at a price of $32.98 per share for
total consideration of $89.6 million. The acquisition resulted in an increase in PP&E of approximately $58.5
million. Total transaction costs incurred by the Company of $1.1 million associated with this acquisition were
expensed in the consolidated statement of income and comprehensive income. The acquisition of Mapan
provides for an increase in lands and production in the Alberta Deep Basin, one of the Company’s core areas.

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 for
total consideration of $177.4 million. 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. 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.

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 $400.0 million gross ($300.0 million net) per year
over a five year period. 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, 2015, the full-committed carried amount had been spent on these specified projects.

Exploration and production capital expenditures in 2016 are now forecast to be $775.0 million inclusive of the
acquisition of assets in the Minehead-Edson-Ansell area of the Alberta Deep Basin ($165.0 million – net of
disposition). The forecast was revised downward from $1.1 billion to $925.0 million in the February 2, 2016 press
release and has been further reduced to $775.0 million given the current economic environment.

 

LIQUIDITY AND CAPITAL RESOURCES

On March 12, 2015, the Company issued 640,000 flow-through common shares at a price of $50.00 per share, for total gross proceeds of $32.0 million. The proceeds were used to temporarily reduce bank debt and then to fund the Company’s 2015 exploration and development program.

On April 1, 2015, the Company purchased Perpetual Energy Inc.’s interests in the West Edson area of the Alberta Deep Basin with the issuance 6,750,000 shares at a closing price on that date of $38.32 per share, for total consideration of $258.7 million.

On June 23, 2015, the Company issued 4,947,500 common shares at a price of $39.50 per share for total gross proceeds of $195.4 million. The proceeds were used to temporarily reduce bank debt and to fund the Company’s 2015 exploration and development program.

On July 20, 2015, the Company closed the acquisition of Bergen with the issuance of 725,000 common shares at a price of $33.90 per Tourmaline share for consideration of $24.6 million. The Company also assumed Bergen’s net debt of $8.4 million.

On August 14, 2015, the Company closed the acquisition of Mapan with the issuance of 2,718,026 common shares at a price of $32.98 per Tourmaline share for consideration of $89.6 million. The Company also assumed Mapan’s working capital of $15.0 million.

On November 25, 2015, the Company issued 482,700 flow-through common shares at a price of $34.10 per share, for total gross proceeds of $16.5 million. The proceeds were used to temporarily reduce bank debt and then to fund the Company’s 2015 exploration and development program.

The Company has a covenant-based, unsecured, bank credit facility in place with a syndicate of bankers. This is a four-year extendible revolving facility in the amount of $1,800.0 million with an initial maturity date of June 2019. The maturity date may, at the request of the Company and with consent of the lenders, be extended on an annual basis. The credit facility includes an expansion feature (“accordion”) which allows the Company, upon approval from the lenders, to increase the facility amount by up to $500.0 million by adding a new financial institution or by increasing the commitment of its existing lenders. The Company also has a $50.0 million operating revolver, resulting in total bank credit facility capacity of $1,850.0 million. The facility can be drawn in either Canadian or U.S. funds and bears interest at the bank’s prime lending rate, banker’s acceptance rates or LIBOR (for U.S. borrowings), plus applicable margins, which range from 0.50% to 3.15% depending on the type of borrowing and the Company’s senior debt to adjusted EBITDA ratio.

The Company also has a $250.0 million five-year term loan with a Canadian Chartered Bank bearing an annual interest rate of 220 basis points over the applicable bankers’ acceptance rates with an initial maturity of November 2020. The maturity date may, at the request of the Company and with consent of the lender, be extended on an annual basis. The covenants for the term loan are the same as those under the Company’s current credit facility and the term loan will rank equally with the obligation under the Company’s credit facility.

The Company’s aggregate borrowing capacity is now $2.1 billion.

Under the terms of the revolving 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, 2015, adjusted EBITDA for the purposes of the above noted covenant calculations was $886.4 million (December 31, 2014 – $952.5 million), on a rolling four-quarter basis. As at December 31, 2015, the Company is in compliance with all debt covenant calculations.

As at December 31, 2015, the Company had negative working capital of $283.8 million, after adjusting for the fair value of financial instruments (the unadjusted working capital deficiency was $247.4 million) (December 31, 2014 – $223.7 million and $189.9 million, respectively). As at December 31, 2015, the Company had $248.6 million in long-term debt outstanding and $1,018.0 million drawn against the revolving credit facility for total bank debt of $1,266.6 million (net of prepaid interest and debt issue costs) (December 31, 2014 – $918.9 million). Net debt at December 31, 2015 was $1,550.4 million (December 31, 2014 – $1,142.5 million).

For 2016, Management intends on matching the capital budget to the expected cash flow and as such Management believes the Company has sufficient resources to fund its 2016 exploration and development programs. As at December 31, 2015, the Company also has $535.7 million in unutilized borrowing capacity. The 2016 exploration and development program will be continuously and diligently monitored throughout the year and will be adjusted as necessary depending on commodity price outlooks in order to remain consistent with cash flow. Management is dedicated to keeping a strong balance sheet which is especially important in times of significantly depressed commodity prices.

 

SHARES AND STOCK OPTIONS OUTSTANDING

As at March 7, 2016, the Company has 221,400,925 common shares outstanding and 19,701,414 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.

 

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, 2015.

As at December 31, 2015, 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 2015 are summarized in note 5 of the Company’s consolidated financial statements for the year ended December 31, 2015.

The following table provides a summary of the unrealized gains and losses on financial instruments for the year ended December 31, 2015:

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, 2015 have been summarized in note 5 of the Company’s consolidated financial statements for the year ended December 31, 2015.

Financial derivative and physical delivery contracts entered into subsequent to December 31, 2015 are detailed in note 5 of the Company’s consolidated financial statements for the year ended December 31, 2015.

 

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, 2015.

 

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, 2015, 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, 2015 and ending December 31, 2015 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.

 

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, 2016 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.

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, 2018 with early adoption permitted.

IFRS 16 – Leases sets out the principles for the recognition, measurement, presentation and disclosure of leases for both parties to a contract, i.e. the customer (‘lessee’) and the supplier (‘lessor’) and replaces the previous leases standard, IAS 17. IFRS 16 is effective for annual reporting periods beginning on or after January 1, 2019.

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 the sum of drawn amounts on the credit facility, the term loan and outstanding letters of credit less cash and cash equivalents and excluding debt issue costs (“bank debt”), “total debt” means generally the sum of “senior debt” plus subordinated debt, Tourmaline currently does not have any subordinated debt, 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:

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

Working Capital (Adjusted for the Fair Value of Financial Instruments)
A summary of the reconciliation of working capital to working capital (adjusted for the fair value of financial
instruments) is set forth below:

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:

 

SELECTED QUARTERLY INFORMATION

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 Company’s average annual production has more than doubled in two years increasing from 74,796 boe per day in 2013 to 154,403 boe per day in 2015. 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 flow was $526.8 million in 2013, $929.0 million in 2014, and $850.2 million in 2015. Although 2015 was a year of record production, cash flow was significantly impacted by the drop in commodity prices. Commodity price fluctuations 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.

 

SELECTED ANNUAL INFORMATION

 

CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

 

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

 

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014
(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 7, 2016.

(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 BlackScholes 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.

Certain comparative amounts have been reclassified to conform with the current year’s presentation.

(a) Consolidation:
The consolidated financial statements include the accounts of Tourmaline Oil Corp., Tourmaline Oil Marketing Corp., Mapan Energy Ltd., Bergen Resources 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 fromintercompany 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 businesses 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 consideration of acquisition given up is less than the fair value of the net assets received, the difference is recognized immediately in the income statement. If the consideration of acquisition is greater than the fair value of the net assets received, 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 highlyliquid investments with original maturities of three months or less, and are measured similar to other nonderivative 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. 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, aremeasured 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:

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 or 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 pretax 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 “riskfree” 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 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, foreign exchange loss on U.S. denominated debt, realized gain on cross-currency swaps, realized loss on interest rate swaps and 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 fairvalue 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

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, 2016 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.

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, 2018 with early adoption permitted.

IFRS 16 – Leases sets out the principles for the recognition, measurement, presentation and disclosure of leases for both parties to a contract, i.e. the customer (‘lessee’) and the supplier (‘lessor’) and replaces the previous leases standard, IAS 17 Leases. IFRS 16 is effective for annual reporting periods beginning on or after January 1, 2019.

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, 2015 and December 31, 2014, 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, 2015 and December 31, 2014. 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.

 

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 counter-party 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, 2015, Tourmaline’s receivables consisted of $120.1 million (December 31, 2014 – $115.7 million) from petroleum and natural gas marketers, $35.3 million (December 31, 2014 – $48.1 million) from partners in jointly-owned assets, and $20.2 million (December 31, 2014 – $39.4 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 counter-parties. In 2015, Tourmaline had three counter-parties 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 from partners 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 the 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. To further mitigate collection risk, the Company has the ability to obtain the partners’ share of capital expenditures in advance of a project.

The Company monitors the age of, and investigates issues behind, its receivables that have been past due for over 90 days. At December 31, 2015, the Company has $4.8 million (December 31, 2014 – $3.4 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, 2015 (December 31, 2014 – nil) and did not provide for any doubtful accounts nor was it required to write-off any receivables during the year ended December 31, 2015 (December 31, 2014 – 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, 2015 is $474.2 million (December 31, 2014 – $701.3 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, 2015, substantially all of the account payable 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, 2015:

(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, 2015. 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, 2015 would have decreased or increased shareholders’ equity and net income by $9.1 million (December 31, 2014 – $5.6 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. The realized loss on the interest rate swap has been included in finance expenses 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, 2015, 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, 2015 (1):

The Company has entered in to the following financial derivative contracts subsequent to December 31, 2015:

The following table provides a summary of the unrealized gains and losses on financial instruments for the years ended December 31, 2015 and 2014:

For the financial instruments in place at December 31, 2015, 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 $5.5 million lower (December 31, 2014 – $3.7 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, 2015 (1)(7):

The Company has entered into the following physical contracts subsequent to December 31, 2015:

(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, 2015, the Company’s ratio of net debt to annualized cash flow was 1.60 to 1.0 (December 31, 2014 – 1.22 to 1.0).

The Company has not paid or declared any dividends since the date of incorporation, nor are any contemplated in the foreseeable future. There have been no changes in the Company’s approach to capital management since December 31, 2014.

 

6. EXPLORATION AND EVALUATION ASSETS

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, 2015 and 2014, 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

 

Accumulated Depletion, Depreciation and Amortization

Future development costs for the year ended December 31, 2015 of $4,523.1 million (December 31, 2014 – $4,610.0 million) were included in the depletion calculation.

Capitalization of G&A and Share-Based Payments
A total of $22.9 million in G&A expenditures have been capitalized and included in E&E and PP&E assets at
December 31, 2015 (December 31, 2014 – $19.3 million). Also included in E&E and PP&E are non-cash sharebased
payments of $30.8 million at December 31, 2015 (December 31, 2014 – $28.8 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, 2015, the Company determined that indicators of impairment exist for all of its CGUs due to the continued decline in the current and forward commodity prices for oil and natural gas since December 31, 2014.

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 the greater of fair value less cost to sell and the value-in-use. Value in use is generally the future cash flows expected to be derived from production of proven and probable reserves estimated by the Company’s third party reserve evaluators and the internally estimated future cash flows of facility infrastructure, when required. During 2015, the Company used pre-tax discount rates of approximately 10%. In prior years, Tourmaline used fair value less costs to sell, discounted at a pre-tax discount rate of 10% to calculate impairment, however in the current period, value in use has been determined to be a better measure due to the lack of comparable market metrics.

The following forward commodity price estimates were used in determining whether an impairment to the carrying value of the CGUs existed at December 31, 2015:

The Company has determined that there was no impairment to PP&E at December 31, 2015 (December 31, 2014 – nil).

Business Combination
On April 1, 2015, the Company acquired Perpetual Energy Inc.’s (“Perpetual”) interests in the West Edson area of the Alberta Deep Basin with the issuance of 6,750,000 Tourmaline shares at a price of $38.32 per share for total consideration of $258.7 million. The interests included Perpetual’s land interests, production, reserves and facilities that were jointly-owned with Tourmaline. The value attributed to the property, plant and equipment acquired was supported by an engineering report prepared at December 31, 2014 by independent reserve engineers and internally rolled-forward to the acquisitions date using proved plus probable reserves discounted at a rate based on what a market participant would pay as well as market metrics in the prevailing area.

The acquisition resulted in an increase in production and processing capacity along with allowing the Company to leverage operational synergies created from having full ownership of the assets.

Results from operations are included in the Company’s consolidated financial statements from the closing date of the transaction. The acquisition has been accounted for using the purchase method based on fair values as follows:

Included in the consolidated statements of income and comprehensive income for the year ended December 31, 2015 are the following amounts relating to Perpetual since April 1, 2015:

If the Company had completed the business combination on January 1, 2015, the pro-forma results of the oil and gas sales and net income and comprehensive income for the year ended December 31, 2015 would have been as follows:

 

Corporate Acquisitions

Bergen Resources Inc.
On July 20, 2015, the Company acquired all of the issued and outstanding shares of Bergen Resources Inc. (“Bergen”). As consideration, the Company issued of 725,000 Tourmaline shares at a price of $33.90 per share for total consideration of $24.6 million. Total transaction costs incurred by the Company of $0.2 million associated with this acquisition were expensed in the consolidated statement of income and comprehensive income. The acquisition resulted in an increase in PP&E of approximately $26.8 million and E&E assets of $2.1 million along with net debt of $8.4 million.

Results from operations for Bergen 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, 2014 by independent reserve engineers using proved plus probable reserves discounted at a rate based on what a market participant would pay as well as market metrics in the prevailing area. The acquisition of Bergen consolidated the Company’s working interest in a core area of the Peace River High.

Included in the consolidated statements of income and comprehensive income for the year ended December 31, 2015 are the following amounts relating to Bergen since July 20, 2015:

If the Company had acquired Bergen on January 1, 2015, the pro-forma results of the oil and gas sales and net income and comprehensive income for the year ended December 31, 2015 would have been as follows:

Mapan Energy Ltd.
On August 14, 2015, the Company acquired all of the issued and outstanding shares of Mapan Energy Ltd. (“Mapan”). As consideration, the Company issued of 2,718,026 Tourmaline shares at a price of $32.98 per share for total consideration of $89.6 million. Total transaction costs incurred by the Company of $1.1 million associated with this acquisition were expensed in the consolidated statement of income and comprehensive income. The acquisition of Mapan resulted in an increase in lands and production in a core area of the Alberta Deep Basin.

Results from operations for Mapan 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, 2014 by independent reserve engineers using proved plus probable reserves discounted at a rate based on what a market participant would pay as well as market metrics in the prevailing area. The acquisition has been accounted for using the purchase method based on fair values as follows:

Included in the consolidated statements of income and comprehensive income for the year ended December 31, 2015 are the following amounts relating to Mapan since August 14, 2015:

If the Company had acquired Mapan on January 1, 2015, the pro-forma results of the oil and gas sales and net income and comprehensive income for the year ended December 31, 2015 would have been as follows:

Santonia Energy Inc.
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 based on what a market participant would pay and market metrics in the prevailing area. The acquisition has been accounted for using the purchase method based on estimated fair values as follows:

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

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:

Acquisition of Oil and Natural Gas Properties
In addition to the above noted acquisitions, for the year ended December 31, 2015, the Company completed property acquisitions for total cash consideration of $92.0 million (December 31, 2014 – $33.0 million) and, a further $73.4 million in non-cash consideration (December 31, 2014 – $2.2 million). The Company also assumed $3.0 million in decommissioning liabilities (December 31, 2014 – $4.9 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 a five year period. 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, 2015, the full-committed carried amount had been spent on these specified 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 $224.5 million (December 31, 2014 – $157.5 million), with some abandonments expected to commence in 2021. A risk-free rate of 2.15% (December 31, 2014 – 2.36%) and an inflation rate of 1.8% (December 31, 2014 – 2.0%) were used to calculate the fair value of the decommissioning obligations. The decommissioning obligations at December 31, 2015 have been adjusted by approximately $22.7 million (December 31, 2014 – $14.1 million) which includes changes in cost estimates of facility abandonment as well as $10.4 million relating to the revaluation of acquired decommissioning liabilities.

 

9. BANK DEBT

The Company has a covenant-based, unsecured, revolving credit facility in place with a syndicate of bankers. This is a four-year extendible revolving facility in the amount of $1,800.0 million with an initial maturity date of June 2019. The maturity date may, at the request of the Company and with consent of the lenders, be extended on an annual basis. The credit facility includes an expansion feature (“accordion”) which allows the Company, upon approval from the lenders, to increase the facility amount by up to $500.0 million by adding a new financial institution or by increasing the commitment of its existing lenders. The Company also has a $50.0 million operating revolver, resulting in total bank credit facility capacity of $1,850.0 million. The facility can be drawn in either Canadian or U.S. funds and bears interest at the bank’s prime lending rate, banker’s acceptance rates or LIBOR (for U.S. borrowings), plus applicable margins, which range from 0.50% to 3.15% depending on the type of borrowing and the Company’s senior debt to adjusted EBITDA ratio.

Under the terms of the revolving 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, 2015, adjusted EBITDA for the purposes of the above noted covenant calculations was $886.4 million (December 31, 2014 – $952.5 million), on a rolling four-quarter basis. As at, and for the periods ending December 31, 2015 and December 31, 2014 the Company is in compliance with all debt covenants.

The Company also has a $250.0 million five-year term loan with a Canadian Chartered Bank bearing an annual interest rate of 220 basis points over the applicable bankers’ acceptance rates. The maturity date may, at the request of the Company and with consent of the lender, be extended on an annual basis with a maturity of November 2020. The covenants for the term loan are the same as those under the Company’s current credit facility and the term loan will rank equally with the obligation under the Company’s credit facility. The Company’s aggregate borrowing capacity is now $2.1 billion.

As at December 31, 2015, the Company had $248.6 million in long term debt outstanding and $1,018.0 million drawn against the revolving credit facility for total bank debt of $1,266.6 million (net of prepaid interest and debt issue costs) (December 31, 2014 – $918.9 million). In addition, Tourmaline has outstanding letters of credit of $13.4 million (December 31, 2014 – $2.4 million), which reduce the credit available on the facility. The effective interest rate on the Company’s bank debt for the year ended December 31, 2015 was 2.68% (December 31, 2014 – 2.93%).

 

10. NON-CONTROLLING INTEREST

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

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

 

11. SHARE CAPITAL

(a) Authorized
Unlimited number of Common Shares without par value.

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

(b) Common Shares Issued

 

12. DEFERRED TAXES

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

The movement in deferred tax balances during the years ended December 31, 2015 and 2014 are as follows:

As at December 31, 2015, the Company has estimated federal tax pools of $5.4 billion (2014 – $4.3 billion) available for deduction against future taxable income. The Company has $619.6 million of unused tax losses expiring between 2023 and 2035.

 

13. EARNINGS PER SHARE

Basic earnings-per-share was calculated as follows:

Diluted earnings-per-share was calculated as follows:

There were 11,176,000 options excluded from the weighted-average share calculation for the year ended December 31, 2015 because they were anti-dilutive (December 31, 2014 – 5,110,500). At December 31, 2015, there were 221,335,925 basic common shares outstanding (December 31, 2014 – 203,162,112).

 

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 22,133,592 shares of common stock. The exercise price of each option equals the volume-weighted average market price for the five days preceding the issue date of the Company’s stock on the date of grant and the option’s maximum term is five years. Options are granted throughout the year and vest 1/3 on each of the first, second and third anniversaries from the date of grant.

The weighted average trading price of the Company’s common shares was $34.38 during the year ended December 31, 2015 (December 31, 2014 – $49.47).

The following table summarizes stock options outstanding and exercisable at December 31, 2015:

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

 

15. OTHER INCOME

 

16. FINANCE EXPENSES

 

17. SUPPLEMENTAL DISCLOSURES

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

 

18. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital is comprised of:

 

Cash interest paid was $30.2 million for the year ended December 31, 2015 (December 31, 2014 – $20.5 million).

Cash interest paid was $30.2 million for the year ended December 31, 2015 (December 31, 2014 – $20.5 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.

 

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, 2015 and 2014.

Compensation of Key Management

 

21. SUBSEQUENT EVENTS

On January 29, 2016, the Company purchased assets in the Minehead-Edson-Ansell area of the Alberta Deep Basin for cash consideration of approximately $182.9 million. The assets include land interests, production, reserves and facilities and are immediately adjacent to one of the Company’s largest-producing complexes.

 

ABOUT TOURMALINE OIL CORP.

Tourmaline is a Canadian senior crude oil and natural gas exploration and production company focused on longterm 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

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
E-mail: info@tourmalineoil.com
Website: www.tourmalineoil.com

 


 

(1) “Cash flow” is defined as cash provided by operations before changes in non-cash operating working capital. See “Non-GAAP Financial Measures” below and 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.