Tourmaline Earns $28.5 Million in the Third Quarter

CALGARY, AB–(Marketwired – November 04, 2015) – Tourmaline Oil Corp. (TSX: TOU) (“Tourmaline” or the “Company”) is pleased to provide third quarter 2015 financial results and an operational update.

HIGHLIGHTS

• Q3 2015 after tax earnings of $28.5 million underscores the full-cycle profitability of the Company’s low cost business, even in a very low commodity price environment.
• Third quarter production of 150,297 boepd, up 39% from the third quarter of 2014 and up 5% from Q2 2015.
• Current production ranging between 179,000 and 182,500 boepd, up 20% over Q3 2015; the Company expects to achieve 2015 exit guidance in the second half of November.
• Nine month operating costs of $4.43/boe, down 15% from 2014 reflecting improved operating efficiencies and strong returns on midstream assets.

Q3 FINANCIAL RESULTS

• Third quarter 2015 cash flow⁽¹⁾ of $197.1 million was down marginally from the previous quarter as the effects of strong production growth were offset by continued weakness in commodity prices.
• All-in cash costs (operating, transportation, general and administrative and financing)⁽²⁾ during the third quarter were $7.80/boe, amongst the lowest in the industry.

2H 2015/1H 2016 CAPITAL SPENDING

Tourmaline expects full-year 2015 EP capital spending of $1.375 billion, down from the previous estimate. The Company utilized additional funds raised in June ($195.4 million) to drill incremental wells during the third quarter; the rig fleet was increased from 14 to 19 rigs in order to execute the expanded program. A total of 68 wells were drilled during the third quarter. The incremental drilling program was designed to follow up multiple first-half 2015 new EP successes, to provide the necessary production volumes to achieve the target production exit volume of 190,000 – 200,000 boepd and to drill incremental wells during a period of significantly lower per-well capital costs. These objectives have been accomplished and the Company is in the process of ramping the rig fleet back down to 14 rigs. Tourmaline expects to drill a total of 40 wells during the fourth quarter of 2015, and complete 26 wells. Approximately $37.0 million of the $55.0 million Edson gas plant and sales pipeline project was expended during the third quarter, with production scheduled to commence later this month. Total third quarter EP Capital spending was $422.6 million, and total fourth quarter EP Capital spending has been reduced to $250.0 million, less than anticipated Q4 cash flow, as the Company has already generated the well and production inventory necessary to achieve exit targets.

⁽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⁾ See “Non-GAAP Financial Measures” below and in the attached Management’s Discussion and Analysis.

Tourmaline currently plans to execute its previously-released 2016 Base Case EP Capital program of $1.1 billion, yielding 2016 full-year average production of 200,000 boepd. A first-half 2016 capital program of approximately $450.0 million is planned with Q1 capital spending of $300.0 million, and Q2 capital spending of $150.0 million. This is less than currently anticipated 1H 2016 cash flow of $565.0 million.

The 2016 Base Case capital program includes only two facility projects — the Brazeau gas plant in the Deep Basin ($55 million with plant and sales pipeline), scheduled for the first half of 2016, and the Doe B.C. gas plant, scheduled for the second half of the year. Tourmaline expects to drill and complete approximately 70 wells in the first half of 2016, which, coupled with shut-in volumes accumulated through continued outperformance of predictive-type curves, will provide sufficient volumes to meet or exceed Base Case production estimates.

The Company will continue to monitor commodity prices and adjust capital spending accordingly in order to maintain a debt to cash flow ratio of approximately 1.5 times or less. Completion of the infrastructure skeleton in all three core complexes during 2014 and 2015 has resulted in planned infrastructure spending of less than 20% of the total EP capital program in both 2016 and 2017, providing continually-improving capital efficiencies as well as considerable capital flexibility. This infrastructure asset consists of 12 gas processing plants (10 at 100% working interest) with Company-interest processing capacity of 1.05 bcf/day, 14 compressor stations, over 3,500 km of Company-100%-interest pipelines, 48,000 bpd of oil processing capability, 172,000 bbls of oil and condensate storage and six frac water source and recycling facilities. Total Tourmaline exit 2015 processing capacity will be approximately 210,000 – 220,000 boepd, providing considerable flexibility around new facility timing in 2016 and 2017.

COST STRUCTURE AND PERFORMANCE

For the nine months ended September 30, operating costs of $4.43 boe were down 15% from 2014. The Company expects to achieve the full-year operating cost target of $4.35/boe, which is 11% lower than 2014 costs. Third quarter 2015 Peace River High operating costs of approximately $16.00/bbl are not yet at the target level of $11.00/boe. The full impact of the cost savings related to the Mulligan battery start-up during the third quarter will be realized in the fourth quarter and beyond. Third quarter 2015 Deep Basin operating costs were $3.50/boe and NEBC Montney complex operating costs were $3.25/boe. Tourmaline expects to drive overall operating costs down further in 2016 as the benefits of recent facility investments are fully incorporated into our cost structure.

Continued low general and administrative cash costs for the third quarter of $0.56/boe, combined with all-in debt servicing costs of 2.69% and lower third quarter transportation costs, resulted in all-in cash costs of $7.74/boe during the first nine months — amongst the lowest in Industry. Tourmaline has managed staff growth conservatively since inception seven years ago with only 180 employees currently, and has no need or plans to reduce office or field staff levels.

EP HIGHLIGHTS

• Tourmaline will achieve the low end of exit 2015 production guidance of 190,000 – 200,000 boepd in the second half of November with the start-up of the 55.0 mmcfpd Edson 4-17 gas plant. Production volumes will continue to grow through to year end with additional tie-ins throughout the EP portfolio.
• 2016 average production in the Base Case Budget Scenario is 200,000 boepd, representing approximately 26% growth over 2015 average production levels.
• 2015 exit liquids production estimated at 30,000 bpd, approximately 65% of which is light oil and condensate.
• 17 horizontal wells have now been drilled into the liquid rich Lower Montney turbidite new play horizon in the Sunrise-Dawson B.C complex. For the four most recently completed horizontals, wellhead condensate production rates ranged between 590 and 1,057 bbls/day with accompanying gas rates between 4.9 and 7.7 mmcfpd at Flowing Casing Pressures (“FCP”) of between 4.0 and 11.2 MPa on five-day production tests. With 220 future locations in the Lower Montney turbidite, this incremental opportunity, captured during 2014/2015, will provide significant condensate production growth over the next several years.
• Alberta Deep Basin well performance continues to improve with corresponding drilling and completion costs down 20% year over year. Of the 41 wells drilled in the Deep Basin since spring break-up of 2015, the average 30-day initial production (“IP”) rate is 11.1 mmcfpd, more than double the rate contemplated on the Company’s production performance template. The second Notikewin horizontal in the greater Brazeau play area recently tested at a rate of 30.5 mmcfpd with 370 bbls/day condensate at the wellhead at a FCP of 24.6 MPa on a three-day production test.
• Fourth quarter production levels for the Peace River High Charlie Lake oil and gas complex are already 23% higher than the third quarter average.

CORPORATE SUMMARY – THIRD QUARTER 2015

			Three Months Ended September 30,									Nine Months Ended September 30,
			2015			2014			Change			2015				2014				Change
OPERATIONS
Production
	Natural gas (mcf/d)			786,910			562,739		40	%			767,587				550,685			39	%
	Crude oil and NGL (bbl/d)			19,146			14,207		35	%			17,978				15,077			19	%
	Oil equivalent (boe/d)			150,297			107,997		39	%			145,909				106,858			37	%
Product prices(1)
	Natural gas ($/mcf)		$	3.20		$	4.34		(26	)%		$	3.35			$	4.79			(30	)%
	Crude oil and NGL ($/bbl)		$	45.91		$	74.61		(38	)%		$	47.19			$	73.24			(36	)%
Operating expenses ($/boe)			$	4.51		$	5.41		(17	)%		$	4.43			$	5.20			(15	)%
Transportation costs ($/boe)			$	1.98		$	1.84		8	%		$	2.07			$	1.88			10	%
Operating netback(3)($/boe)			$	15.06		$	22.19		(32	)%		$	16.02			$	24.64			(35	)%
Cash general and administrative expenses ($/boe)(2)			$	0.56		$	0.65		(14	)%		$	0.50			$	0.62			(19	)%
FINANCIAL($000, except share and per share)
Revenue				312,644			321,985		(3	)%			932,643				1,021,790			(9	)%
Royalties				14,755			29,549		(50	)%			35,286				96,587			(63	)%
Cash flow(3)				197,100			211,635		(7	)%			607,869				695,764			(13	)%
Cash flow per share (diluted)(3)			$	0.90		$	1.03		(13	)%		$	2.86			$	3.43			(17	)%
Net earnings (loss)				28,489			67,357		(58	)%			45,451				223,662			(80	)%
Net earnings (loss) per share (diluted)			$	0.13		$	0.33		(61	)%		$	0.21			$	1.10			(81	)%
Capital expenditures (net of dispositions)				422,629			647,302		(35	)%			1,210,640				1,411,431			(14	)%
Weighted average shares outstanding (diluted)													212,561,337				202,811,901			5	%
Net debt(3)													(1,484,095	)			(1,258,913	)		18	%

(1) Product prices include realized gains and losses on financial instrument contracts.

(2) Excluding interest and financing charges. See “Non-GAAP Financial Measures” below and in the attached Management’s Discussion and Analysis.

(3) See “Non-GAAP Financial Measures” below and in the attached Management’s Discussion and Analysis.

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

Tourmaline will host a conference call tomorrow, November 5, 2015 starting at 9:00 a.m. MST (11:00 a.m. EST). 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”, “could”, “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 as at and for various future periods, anticipated petroleum and natural gas production, cash flows, capital spending, net debt, net debt to cash flow levels, projected operating and drilling costs, the timing for facility expansions and facility start-up dates, tie-in of production, as well as Tourmaline’s future drilling prospects and plans, including the quantity of drilling locations in inventory, business strategy, future development and growth opportunities and 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 and future 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 availability and cost of labour and services; the state of the economy and the exploration and production business; the availability and cost of financing; and ability to market and transport oil and natural gas 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, 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; reliance on third parties; 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.

Also included in this press release are estimates of Tourmaline’s 2015 annual cash flow, capital spending and year-end net debt and net debt to cash flow levels as well as preliminary guidance on 2016 anticipated cash flows, which are based on the various assumptions as to production levels, including estimated average production of 155,000 – 160,000 boepd for 2015 and 200,000 boepd for 2016, capital expenditures, and other assumptions disclosed in this press release and including commodity price assumptions for natural gas (AECO – $2.96/mcf for 2015 and $3.25/mcf for 2016), and crude oil (WTI (US) – $53.26/bbl for 2015 and $62.50/bbl for 2016) and an exchange rate assumption of (US/CAD) $0.79 for 2015 and $0.80 for 2016. To the extent any such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Tourmaline on November 4, 2015 and is included to provide readers with an understanding of Tourmaline’s anticipated cash flows based on the capital expenditure and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.

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.

See also “Forward-Looking Statements” in the attached Management’s Discussion and Analysis.

Additional Reader Advisories

BOE CONVERSIONS

Boes 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. 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 6:1 conversion basis may be misleading as an indication of value.

PRODUCTION TESTS

Any references in this 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 to produce 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.

NON-GAAP FINANCIAL MEASURES

This press release includes references to financial measures commonly used in the oil and gas industry, “cash flow”, “operating netback”, “all-in cash costs”, “general and administrative expenses” and “net debt”, which do not have standardized meanings prescribed by International Financial Reporting Standards (“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”, “all-in cash costs”, “general and administrative expenses” 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. Readers 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. All-in cash costs is defined as operating, transportation, general and administration, and finance expenses excluding accretion. See “Non-GAAP Financial Measures” in the attached Management’s Discussion and Analysis for the definition and description of these terms.

ESTIMATED DRILLING INVENTORY

This press release discloses 220 drilling locations which are unbooked. 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.

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
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

This management’s discussion and analysis (“MD&A”) should be read in conjunction with Tourmaline’s unaudited interim condensed consolidated financial statements and related notes as at and for the three and nine months ended September 30, 2015 and the consolidated financial statements for the year ended December 31, 2014. Both the consolidated financial statements and the MD&A can be found at www.sedar.com. This MD&A is dated November 4, 2015.

The financial information contained herein has been prepared in accordance with International Financial Reporting Standards (“IFRS”) and sometimes referred to in this MD&A as Generally Accepted Accounting Principles (“GAAP”) as issued by the International Accounting Standards Board. 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. 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.

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

These forward-looking statements are subject to numerous risks and uncertainties, most of which are beyond the Company’s control, including the impact of general economic conditions; volatility 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, NGL 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 and skilled labour; changes in income 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; and future operating costs.

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

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

Boe Conversions – Per barrel of oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent (6:1). Barrel of oil equivalents (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, as the value ratio between natural gas and crude oil based on current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

PRODUCTION
		Three Months Ended September 30,									Nine Months Ended September 30,
		2015			2014			Change			2015			2014			Change
Natural gas (mcf/d)		786,910			562,739			40	%		767,587			550,685			39	%
Oil (bbl/d)		10,669			9,002			19	%		10,630			9,136			16	%
NGL (bbl/d)		8,477			5,205			63	%		7,348			5,941			24	%
Oil equivalent (boe/d)		150,297			107,997			39	%		145,909			106,858			37	%
Natural Gas %		87	%		87	%					88	%		86	%

Production for the three months ended September 30, 2015 averaged 150,297 boe/d, a 39% increase over the average production for the same quarter of 2014 of 107,997 boe/d. For the nine months ended September 30, 2015, production increased 37% to 145,909 boe/d from 106,858 boe/d for the same period in 2014. Wells brought on production from the Company’s exploration and production program accounted for approximately 90% of the growth in production volumes in 2015 over 2014, with the remainder of the change being from corporate and property acquisitions (net of dispositions). The slight increase in the natural gas weighting for the first nine months of 2015 is due to the sale of 25% of the Company’s oil producing assets in the Peace River High Complex in the fourth quarter of 2014.

Full-year average production guidance for 2015 was revised to 155,000-160,000 boe/d from 164,500 boe/d (as disclosed in the Company’s press release dated October 14, 2015). The reduction in full-year guidance is due to ongoing transportation interruptions, on all three transportation systems the Company utilizes, having reduced production by approximately 7,500 boe/d through the first nine months of 2015.

REVENUE
			Three Months Ended September 30,									Nine Months Ended September 30,
(000s)			2015			2014			Change			2015			2014			Change
Revenue from:
	Natural gas		$	231,773		$	224,468		3	%		$	701,051		$	720,338		(3	)%
	Oil and NGL			80,871			97,517		(17	)%			231,592			301,452		(23	)%
Total revenue from natural gas, oil and NGL sales			$	312,644		$	321,985		(3	)%		$	932,643		$	1,021,790		(9	)%

Revenue for the three months ended September 30, 2015 decreased 3% to $312.6 million from $322.0 million for the same quarter of 2014. Revenue for the nine-month period ended September 30, 2015 decreased 9% from $1,021.8 million in 2014 to $932.6 million in 2015. Lower revenue for the period is consistent with the significant decrease in realized commodity prices, partially offset by higher production volumes and realized gains on energy marketing and hedging activities. Revenue includes all petroleum, natural gas and NGL sales and the realized gain (loss) on financial instruments.

TOURMALINE REALIZED PRICES:
		Three Months Ended September 30,									Nine Months Ended September 30,
		2015			2014			Change			2015			2014			Change
Natural gas ($/mcf)		$	3.20		$	4.34		(26	)%		$	3.35		$	4.79		(30	)%
Oil ($/bbl)		$	74.06		$	94.77		(22	)%		$	69.57		$	95.84		(27	)%
NGL ($/bbl)		$	10.48		$	39.74		(74	)%		$	14.81		$	38.49		(62	)%
Oil equivalent ($/boe)		$	22.61		$	32.41		(30	)%		$	23.41		$	35.03		(33	)%

BENCHMARK OIL AND GAS PRICES:
			Three Months Ended September 30,
			2015			2014			Change
Natural gas
	NYMEX Henry Hub (USD$/mcf)		$	2.74		$	3.95		(31	)%
	AECO (CAD$/mcf)		$	2.91		$	4.03		(28	)%
Oil
	NYMEX (USD$/bbl)		$	46.48		$	97.25		(52	)%
	Edmonton Par (CAD$/bbl)		$	55.37		$	97.11		(43	)%

RECONCILIATION OF AECO INDEX TO TOURMALINE’S REALIZED GAS PRICES:
		Three Months Ended September 30,
($/mcf)		2015				2014				Change
AECO index (1)		$	2.90			$	4.03			(28	)%
Heat/quality differential			0.20				0.38			(47	)%
Realized gain			0.31				0.03			933	%
Sales point differential (2)			(0.21	)			(0.10	)		110	%
Tourmaline realized natural gas price		$	3.20			$	4.34			(26	)%
Premium to AECO pricing due to higher heat content			7	%			9	%

(1) Weighted based on Tourmaline volumes for the period.

(2) Price differential for production sold at other locations (ex. West Coast Station 2 in Northeast B.C.)

CURRENCY – EXCHANGE RATES:
		Three Months Ended September 30,
		2015			2014			Change
CAD$/USD$ (1)		$	0.7643		$	0.9186		(17	)%

(1) Average rates for the period.

The realized average natural gas price for the three and nine months ended September 30, 2015 was $3.20/mcf and $3.35/mcf, which is 26% and 30% lower than the same periods of the prior year. The lower natural gas price reflects a lower AECO index (28%) experienced during the quarter. Included in the realized price is a gain on commodity contracts in the third quarter of 2015 of $22.7 million (nine months ended September 30, 2015 – $107.1 million) compared to a gain of $1.5 million for the same period of the prior year (nine months ended September 30, 2014 – loss of $41.9 million). Realized gains on commodity contracts for the quarter and nine months ended September 30, 2015 have increased compared to the same periods of the prior year as the market price of natural gas has weakened relative to the pricing per the commodity contracts in place. Realized prices exclude the effect of unrealized gains or losses on commodity contracts. Once these gains and losses are realized they are included in the per-unit amounts.

Realized oil prices decreased by 22% and 27% for the three and nine months ended September 30, 2015, which is consistent with the decrease in the benchmark price for crude oil during the quarter partially offset by a gain on commodity contracts in the third quarter of 2015 of $22.7 million (nine months ended September 30, 2015 – $43.6 million). NGL prices decreased 74% from $39.74/bbl to $10.48/bbl, when compared to the same quarter of 2014. The decrease in NGL prices is consistent with the decrease in crude oil and natural gas prices over the period as well as oversupply in the propane market in 2015 leading to significantly reduced prices for that commodity.

ROYALTIES
		Three Months Ended September 30,								Nine Months Ended September 30,
(000s)		2015				2014				2015				2014
Natural gas		$	7,687			$	14,240			$	16,253			$	54,712
Oil and NGL			7,068				15,309				19,033				41,875
Total royalties		$	14,755			$	29,549			$	35,286			$	96,587
Royalties as a percentage of revenue			5.5	%			9.2	%			4.5	%			9.1	%

For the quarter ended September 30, 2015, the average effective royalty rate was 5.5% compared to the rate of 9.2% for the same quarter of 2014. For the nine-month period ended September 30, 2015, the average effective royalty rate decreased from 9.1% in 2014 to 4.5% in 2015. 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 continues to benefit from the New Well Royalty Reduction Program and the Natural Gas Deep Drilling Program in Alberta, as well as the Deep Royalty Credit Program in British Columbia.

The Company is forecasting the royalty rate for 2015 to be approximately 5%, revised down from 8% as disclosed in the Company’s MD&A dated August 5, 2015. The royalty rate is, however, sensitive to commodity prices and product mixes, and as such, a change in commodity prices or product mix will impact the actual rate.

OTHER INCOME
		Three Months Ended September 30,									Nine Months Ended September 30,
(000s)		2015			2014			Change			2015			2014			Change
Other income		$	7,164		$	3,544		102	%		$	20,270		$	12,945		57	%

Other income increased from $3.5 million in the third quarter of 2014 to $7.2 million for the same quarter of 2015. For the nine-month period ended September 30, 2015, other income increased from $12.9 million in 2014 to $20.3 million in 2015. 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
		Three Months Ended September 30,									Nine Months Ended September 30,
(000s) except per unit amounts		2015			2014			Change			2015			2014			Change
Operating expenses		$	62,299		$	53,758		16	%		$	176,637		$	151,645		16	%
Per boe		$	4.51		$	5.41		(17	)%		$	4.43		$	5.20		(15	)%

Operating expenses include all periodic lease and field-level expenses and exclude income recoveries from processing third-party volumes. For the third quarter of 2015, total operating expenses were $62.3 million compared to $53.8 million in 2014. Operating costs for the nine months ended September 30, 2015 were $176.6 million, compared to $151.6 million for the same period in 2014, reflecting increased costs relating to the growing production base.

On a per-boe basis, the costs decreased from $5.41/boe for the third quarter of 2014 to $4.51/boe in the third quarter of 2015. For the nine months ended September 30, 2015, operating costs were $4.43/boe, down from $5.20/boe in the prior year. The Company’s investments in processing facilities in 2014 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 expects its full-year 2015 operating costs to average approximately $4.35/boe (as disclosed in the Company’s MD&A dated March 9, 2015). Actual costs per boe can change depending on a number of factors including the Company’s actual production levels.

TRANSPORTATION
		Three Months Ended September 30,									Nine Months Ended September 30,
(000s) except per unit amounts		2015			2014			Change			2015			2014			Change
Natural gas transportation		$	19,947		$	13,285		50	%		$	59,231		$	37,910		56	%
Oil and NGL transportation			7,437			4,950		50	%			23,279			16,956		37	%
Total transportation		$	27,384		$	18,235		50	%		$	82,510		$	54,866		50	%
Per boe		$	1.98		$	1.84		8	%		$	2.07		$	1.88		10	%

For the third quarter of 2015, total transportation expenses were $27.4 million compared to $18.2 million in 2014. Transportation costs for the nine months ended September 30, 2015 were $82.5 million, compared to $54.9 million for the same period in 2014, reflecting increased costs related to higher production volumes.

On a per-boe basis, the costs increased from $1.84/boe for the third quarter of 2014 to $1.98/boe in the third quarter of 2015. For the nine months ended September 30, 2015, transportation costs were $2.07/boe, up from $1.88/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 increasing natural gas transportation expense.

GENERAL & ADMINISTRATIVE EXPENSES (“G&A”)
		Three Months Ended September 30,											Nine Months Ended September 30,
(000s) except per unit amounts		2015				2014				Change			2015				2014				Change
G&A expenses		$	15,934			$	11,548			38	%		$	44,261			$	34,445			28	%
Administrative and capital recovery			(2,511	)			(336	)		647	%			(7,286	)			(2,519	)		189	%
Capitalized G&A			(5,741	)			(4,753	)		21	%			(17,062	)			(13,718	)		24	%
Total G&A expenses		$	7,682			$	6,459			19	%		$	19,913			$	18,208			9	%
Per boe		$	0.56			$	0.65			(14	)%		$	0.50			$	0.62			(19	)%

The increase in gross G&A expenses in 2015 compared to 2014 is primarily due to staff additions needed to manage the larger production, reserve and land base. G&A expenses for the third quarter of 2015 were $7.7 million compared to $6.5 million for the same quarter of the prior year. G&A expenses for the nine-month period ended September 30, 2015 were $19.9 million compared to $18.2 million for the same period in 2014. The increase in administrative and capital recoveries in the third quarter of 2015 compared to 2014 is due to the Company having a higher percentage of wells which it operates on behalf of its partners and, as such, is able to recover more of its G&A expenses.

On a per-boe basis, G&A expenses decreased from $0.65/boe for the third quarter of 2014 to $0.56/boe in the third quarter of 2015. For the nine months ended September 30, 2015, G&A expenses were $0.50/boe, down from $0.62/boe in the prior year. The decrease per boe reflects Tourmaline’s growing production base which continues to increase at a faster rate than G&A costs.

G&A costs for 2015 are forecast to average approximately $0.55/boe, down from the previous guidance of $0.60/boe as disclosed in the Company’s MD&A dated August 5, 2015. Actual costs per boe can change, however, depending on a number of factors including the Company’s actual production levels.

SHARE-BASED PAYMENTS
		Three Months Ended September 30,								Nine Months Ended September 30,
(000s) except per unit amounts		2015				2014				2015				2014
Share-based payments		$	15,170			$	14,668			$	48,018			$	41,682
Capitalized share-based payments			(7,585	)			(7,334	)			(24,009	)			(20,841	)
Total share-based payments		$	7,585			$	7,334			$	24,009			$	20,841
Per boe		$	0.55			$	0.74			$	0.60			$	0.71

The Company uses the fair value method for the determination of non-cash related share-based payments expense. During the third quarter of 2015, 481,000 stock options were granted to employees, officers, directors and key consultants at a weighted-average exercise price of $34.08 and 991,950 options were exercised, resulting in $18.2 million of cash proceeds.

The Company recognized $7.6 million of share-based payments expense in the third quarter of 2015 compared to $7.3 million in the third quarter of 2014. Capitalized share-based payments for the third quarter of 2015 were $7.6 million compared to $7.3 million for the same period of the prior year.

For the nine months ended September 30, 2015, share-based payment expense totalled $24.0 million and a further $24.0 million in share-based payments were capitalized (nine months ended September 30, 2014 – $20.8 million and $20.8 million, respectively). Share-based payments are higher in 2015 compared to the same periods in 2014, which reflects a higher number of options outstanding.

DEPLETION, DEPRECIATION AND AMORTIZATION (“DD&A”)
		Three Months Ended September 30,								Nine Months Ended September 30,
(000s) except per unit amounts		2015				2014				2015				2014
Total depletion, depreciation and amortization		$	174,772			$	123,919			$	520,105			$	366,556
Less mineral lease expiries			(12,960	)			(1,106	)			(49,394	)			(14,415	)
Depletion, depreciation and amortization		$	161,812			$	122,813			$	470,711			$	352,141
Per boe		$	11.70			$	12.36			$	11.82			$	12.07

DD&A expense, excluding mineral lease expiries, was $161.8 million for the third quarter of 2015 compared to $122.8 million for the same period of 2014. For the nine-month period ended September 30, 2015, DD&A expense (excluding mineral lease expiries) was $470.7 million compared to $352.1 million in the same period of 2014. The increase in DD&A expense in 2015 over 2014 is due to higher production volumes, as well as a larger capital asset base being depleted.

The per-unit DD&A rate (excluding the impact of mineral lease expiries) was $11.70/boe for the third quarter of 2015 compared to the rate of $12.36/boe for the same quarter in 2014. The per-unit DD&A rate (excluding the impact of mineral lease expiries) was $11.82/boe for the nine-month period ended September 30, 2015 compared to the rate of $12.07/boe in the same period of the prior year. The reduction in the rate for both the three and nine month periods reflects reserves added at a faster rate than the increase to the depletable base.

Mineral lease expiries for the three months ended September 30, 2015 were $13.0 million, compared to expiries in the same quarter of the prior year of $1.1 million. For the nine months ended September 30, 2015, expiries were $49.4 million compared with $14.4 million for the same period in 2014. 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 not to continue some of the expiring sections of land.

FINANCE EXPENSES
		Three Months Ended September 30,									Nine Months Ended September 30,
(000s)		2015			2014			Change			2015			2014			Change
Interest expense		$	9,498		$	5,793		64	%		$	27,482		$	16,112		71	%
Accretion expense			788			594		33	%			2,038			1,755		16	%
Transaction costs on corporate and property acquisitions			923			–		100	%			1,948			1,496		30	%
Total finance expenses		$	11,209		$	6,387		75	%		$	31,468		$	19,363		63	%

Finance expenses are comprised of interest expense, accretion of provisions and transaction costs associated with corporate and property acquisitions. Finance expenses for the three and nine months ended September 30, 2015 totaled $11.2 million and $31.5 million, respectively, compared to $6.4 million and $19.4 million for the same periods of 2014. The increase in finance expenses in 2015 over 2014 is mainly due to the higher average bank debt outstanding, partially offset by a lower average effective interest rate. The average bank debt outstanding for the nine months ended September 30, 2015 was $1,203.6 million (nine months ended September 30, 2014 – $639.2 million), with an average effective interest rate of 2.69% (2014 – 2.99%).

DEFERRED INCOME TAXES

For the three months ended September 30, 2015, the provision for deferred income tax expense was $14.0 million compared to $29.3 million for the same period in 2014. The decrease is primarily due to the lower pre-tax earnings recorded in the third quarter of 2015 compared to the respective period in 2014.

For the nine months ended September 30, 2015, the provision for deferred income tax expense was $65.2 million compared to $87.4 million for the same period in 2014. The decrease is due to lower pre-tax earnings recorded for the nine months ended September 30, 2015 compared to the respective period in 2014, which was partially offset by the increase in Alberta’s corporate tax rate.

CASH FLOW FROM OPERATING ACTIVITIES, CASH FLOW AND NET EARNINGS
			Three Months Ended September 30,						Nine Months Ended September 30,
(000s) except per unit amounts			2015		2014		Change		2015		2014		Change
Cash flow from operating activities			$ 261,398		$ 233,047		12%		$ 606,796		$ 714,193		(15)%
	Per share (1)		$ 1.19		$ 1.13		5%		$ 2.85		$ 3.52		(19)%
Cash flow (2)			$ 197,100		$ 211,635		(7)%		$ 607,869		$ 695,764		(13)%
	Per share (1)(2)		$ 0.90		$ 1.03		(13)%		$ 2.86		$ 3.43		(17)%
Net earnings			$ 28,489		$ 67,357		(58)%		$ 45,451		$ 223,662		(80)%
	Per share (1)		$ 0.13		$ 0.33		(61)%		$ 0.21		$ 1.10		(81)%
Operating netback per boe (2)			$ 15.06		$ 22.19		(32)%		$ 16.02		$ 24.64		(35)%

(1) Fully diluted

(2) See “Non-GAAP Financial Measures”

Cash flow for the three months ended September 30, 2015 was $197.1 million or $0.90 per share compared to $211.6 million or $1.03 per diluted share for the same period of 2014. Cash flow for the nine months ended September 30, 2015 was $607.9 million or $2.86 per share compared to $695.8 million or $3.43 per diluted share for the same period of 2014.

The Company had after-tax net earnings for the three months ended September 30, 2015 of $28.5 million or $0.13 per share compared to $67.4 million or $0.33 per diluted share for the same period of 2014. For the nine-month period ended September 30, 2015, after-tax net earnings were $45.5 million or $0.21 per share compared to $223.7 million or $1.10 per diluted share for the corresponding period of 2014. The decrease in both cash flow and after-tax net earnings in 2015 reflects significantly lower realized oil, natural gas and NGL prices, partially offset by an increase in production over 2014.

CAPITAL EXPENDITURES
		Three Months Ended September 30,								Nine Months Ended September 30,
(000s)		2015				2014				2015				2014
Land and seismic		$	8,477			$	11,973			$	37,376			$	49,123
Drilling and completions			290,153				354,715				676,420				772,750
Facilities			122,866				277,771				392,528				572,369
Property acquisitions			955				–				91,341				4,777
Property dispositions			(6,144	)			(2,425	)			(6,663	)			(2,525	)
Other			6,322				5,268				19,638				14,937
Total cash capital expenditures		$	422,629			$	647,302			$	1,210,640			$	1,411,431

During the third quarter of 2015, the Company invested $422.6 million of cash consideration, net of dispositions, compared to $647.3 million for the same period of 2014. Expenditures on exploration and production were $421.5 million compared to $644.5 million for the same quarter of 2014. During the nine-month period ended September 30, 2015, the Company invested $1,210.6 million of cash consideration, net of dispositions, compared to $1,411.4 million for the same period in 2014. The drilling and completion costs of $676.4 million in 2015 include 18.58 more net wells drilled and completed over 2014 at a lower cost per well reflecting continuous improvement of capital efficiencies. Facilities expenditures include work on the new Mulligan oil battery commissioned in the third quarter of 2015 and preliminary expenditures on the Spirit River Sour Gas Plant expansion and the new Edson Gas Plant, scheduled to be commissioned in the fourth quarter of 2015 or early 2016.

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

		Nine Months Ended September 30, 2015				Nine Months Ended September 30, 2014
		Gross		Net		Gross		Net
Drilled		159		133.68		140		121.49
Completed		138		118.47		127		112.08
Tied-in		61		49.54		57		50.81

Corporate Acquisitions

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. Total transaction costs incurred by the Company of $0.2 million associated with this acquisition were expensed in the interim consolidated statement of income and comprehensive income. The acquisition resulted in an increase in Property, Plant and Equipment (“PP&E”) of approximately $26.8 million and Exploration and Evaluation (“E&E”) assets of $2.1 million along with net debt of $8.4 million.

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. Total transaction costs incurred by the Company of $1.1 million associated with this acquisition were expensed in the interim consolidated statement of income and comprehensive income. The acquisition resulted in an increase in PP&E of approximately $58.5 million along with working capital of $15.0 million. The acquisition of Mapan provides for an increase in lands and production in the Alberta Deep Basin, one of the Company’s core areas.

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.

The Company has a covenant-based, unsecured, bank credit facility in place with a syndicate of bankers. In June 2015, the Company increased the facility amount from $1,550.0 to $1,800.0 million. The term was also increased from three to four years, resulting in an initial maturity 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 also 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. With the exception of the increase in the facility amount, length of term and the addition of the accordion feature, the debt was renewed under the same terms and conditions as those outlined in note 9 of the Company’s consolidated financial statements for the year ended December 31, 2014. 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. In September 2015, the Company extended the maturity of the term loan from November 30, 2019 to November 30, 2020 and the annual interest rate was reduced to 220 basis points from 240 basis points over the applicable bankers’ acceptance rate. The covenants for the term loan are similar to those under the Company’s current credit facility and the term loan will rank equally with the obligation under the Company’s credit facility.

As at September 30, 2015, the Company had negative working capital of $339.2 million, after adjusting for the fair value of financial instruments (the unadjusted working capital deficiency was $297.7 million) (December 31, 2014 – $223.7 million and $189.9 million, respectively). As at September 30, 2015, the Company had $248.6 million in long-term debt outstanding and $896.3 million drawn against the revolving credit facility for total bank debt of $1,144.9 million (net of prepaid interest and debt issue costs) (December 31, 2014 – $918.9 million). Net debt at September 30, 2015 was $1,484.1 million (December 31, 2014 – $1,142.5 million). Management believes the Company has sufficient liquidity and capital resources to fund the remainder of its 2015 and 2016 exploration and development programs through expected cash flow from operations and its unutilized borrowing capacity. As at September 30, 2015, the Company is in compliance with all debt covenant calculations.

SHARES AND STOCK OPTIONS OUTSTANDING

As at November 4, 2015, the Company has 220,812,892 common shares outstanding and 16,626,413 stock options granted and outstanding.

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

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

PAYMENTS DUE BY YEAR
(000s)		1 Year			2-3 Years			4-5 Years			> 5 Years			Total
Operating leases		$	5,078		$	11,053		$	8,073		$	–		$	24,204
Firm transportation and processing agreements			144,911			404,016			272,675			547,360			1,368,962
Capital commitments (1)			313,244			908,283			75,000			–			1,296,527
Flow-through share commitments			24,435			–			–			–			24,435
Credit facility (2)			–			–			988,552			–			988,552
Term debt (3)			11,131			22,263			22,263			251,157			306,814
		$	498,799		$	1,345,615		$	1,366,563		$	798,517		$	4,009,494

(1) Includes drilling commitments, and capital spending commitments under the joint arrangement in the Spirit River complex of $300.0 million per year until 2019. The capital spending commitment under the joint arrangement can be deferred to future periods in the event of an economic downturn, and as agreed upon by both parties.

(2) Includes interest expense at an annual rate of 2.52% being the rate applicable to outstanding debt on the credit facility at September 30, 2015.

(3) Includes interest expense at an annual rate of 4.47% being the fixed rate on the term debt (including the interest rate swap) at September 30, 2015.

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 audited consolidated financial statements for the year ended December 31, 2014.

As at September 30, 2015, the Company has entered into certain financial derivative contracts in order to manage commodity price and interest rate 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 contracts are recorded on the consolidated statement of financial position at fair value, with changes in the fair value being recognized as an unrealized gain or loss on the consolidated statement of income and comprehensive income. The contracts that the Company has in place at September 30, 2015 are summarized and disclosed in note 3 of the Company’s unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2015 and 2014.

The Company has entered into physical delivery sales 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 September 30, 2015 have been summarized and disclosed in note 3 of the Company’s unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2015 and 2014.

Financial derivative and physical delivery contracts entered into subsequent to September 30, 2015 are detailed in note 3 of the Company’s unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2015 and 2014.

APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Management reviews its estimates on a regular basis. The emergence of new information and changed circumstances may result in actual results or changes to estimates that differ materially from current estimates. The Company’s use of estimates and judgments in preparing the interim condensed consolidated financial statements is discussed in note 1 of the consolidated financial statements for the year ended December 31, 2014.

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING

The Company’s Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures (“DC&P”), as defined by National Instrument 52-109. 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 National Instrument 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 IFRS.

There were no changes in the Company’s DC&P or ICFR during the period beginning on July 1, 2015 and ending on September 30, 2015 that have materially affected, or are reasonably likely to materially affect, the Company’s ICFR. It should be noted that a control system, including the Company’s disclosure and internal controls and procedures, no matter how well conceived can provide only reasonable, but not absolute assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

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 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.

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 statements of cash flow), to cash flow, is set forth below:

		Three Months Ended September 30,								Nine Months Ended September 30,
(000s)		2015				2014				2015			2014
Cash flow from operating activities (per GAAP)		$	261,398			$	233,047			$	606,796		$	714,193
Change in non-cash working capital			(64,298	)			(21,412	)			1,073			(18,429	)
Cash flow		$	197,100			$	211,635			$	607,869		$	695,764

Operating Netback

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

		Three Months Ended September 30,								Nine Months Ended September 30,
($/boe)		2015				2014				2015				2014
Revenue, excluding processing income		$	22.61			$	32.41			$	23.41			$	35.03
Royalties			(1.07	)			(2.97	)			(0.89	)			(3.31	)
Transportation costs			(1.98	)			(1.84	)			(2.07	)			(1.88	)
Operating expenses			(4.51	)			(5.41	)			(4.43	)			(5.20	)
Operating netback (1)		$	15.06			$	22.19			$	16.02			$	24.64

(1) May not add due to rounding.

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

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

(000s)		As at September 30, 2015				As at December 31, 2014
Working capital (deficit)		$	(297,698	)		$	(189,928	)
Fair value of financial instruments – short-term (net)			(41,479	)			(33,727	)
Working capital (deficit) (adjusted for the fair value of financial instruments)		$	(339,177	)		$	(223,655	)

Net Debt

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

(000s)		As at September 30, 2015				As at December 31, 2014
Bank debt		$	(1,144,918	)		$	(918,854	)
Working capital (deficit)			(297,698	)			(189,928	)
Fair value of financial instruments – short-term (net)			(41,479	)			(33,727	)
Net debt		$	(1,484,095	)		$	(1,142,509	)

SELECTED QUARTERLY INFORMATION

									2015												2014			2013
($000s, unless otherwise noted)			Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4
PRODUCTION
Natural gas (mcf)			72,395,759			69,606,629			67,548,751			63,719,524			51,771,964			51,225,036			47,339,926			41,062,993
Oil and NGL(bbls)			1,761,403			1,469,591			1,677,123			1,426,951			1,307,089			1,468,198			1,340,699			1,076,395
Oil equivalent (boe)			13,827,363			13,070,696			12,935,248			12,046,872			9,935,749			10,005,704			9,230,686			7,920,228
Natural gas (mcf/d)			786,910			764,908			750,542			692,604			562,739			562,912			525,999			446,337
Oil and NGL (bbls/d)			19,146			16,149			18,635			15,510			14,207			16,134			14,897			11,700
Oil equivalent (boe/d)			150,297			143,634			143,725			130,944			107,997			109,953			102,563			86,089
FINANCIAL
Revenue, net of royalties			332,927			283,062			312,834			351,939			311,586			313,655			317,336			219,069
Cash flow from operating activities			261,398			151,028			194,370			201,188			233,047			231,756			249,390			128,852
Cash flow (1)			197,100			203,029			207,740			233,238			211,635			231,542			252,587			160,732
	Per diluted share		0.90			0.95			1.01			1.14			1.03			1.13			1.28			0.83
Net earnings (loss)			28,489			(5,197	)		22,159			265,210			67,357			66,437			89,868			56,763
	Per basic share		0.13			(0.02	)		0.11			1.31			0.33			0.33			0.47			0.30
	Per diluted share		0.13			(0.02	)		0.11			1.29			0.33			0.32			0.45			0.29
Total assets			7,471,042			7,071,801			6,801,583			6,622,303			5,978,645			5,446,094			5,082,535			4,696,471
Working capital (deficit)			(297,698	)		(70,156	)		(195,907	)		(189,928	)		(493,160	)		(131,672	)		(255,240	)		(245,314	)
Working capital (deficit) (adjusted for the fair value of financial instruments) (1)			(339,177	)		(86,090	)		(232,572	)		(223,655	)		(495,222	)		(123,166	)		(248,094	)		(242,623	)
Cash capital expenditures			422,629			290,629			497,382			152,135			647,302			297,733			466,396			497,941
Total outstanding shares (000s)			220,813			216,378			204,284			203,162			201,673			201,431			195,567			189,805
PER UNIT
Natural gas ($/mcf)			3.20			3.17			3.69			4.09			4.34			4.71			5.38			3.84
Oil and NGL ($/bbl)			45.91			53.34			43.13			55.91			74.61			74.53			70.49			71.83
Revenue ($/boe)			22.61			22.85			24.84			28.25			32.41			35.03			37.84			29.69
Operating netback ($/boe)(1)			15.06			16.37			16.70			20.23			22.19			24.02			27.94			21.29

(1) See Non-GAAP Financial Measures.

The oil and gas exploration and production industry is cyclical. 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 increased from 74,796 boe per day in 2013 to 112,929 boe per day in 2014 and 145,909 boe per day in the first nine months of 2015. The production growth can be attributed primarily to the Company’s exploration and development activities, and from acquisitions of producing properties.

The Company’s cash flow was $526.8 million in 2013, $929.0 million in 2014, and 2015 forecast cash flow is $886.8 million, reflecting the strong production growth year over year. 2015 cash flow to date has been 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. Changes in commodity prices impact revenue and cash flow available for exploration, and also the economics of potential capital projects as low commodity prices can potentially reduce the quantities of reserves that are commercially recoverable. The Company’s capital program is dependent on cash flow generated from operations and access to capital markets.

CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
			September 30,			December 31,
(000s) (unaudited)			2015			2014
Assets
Current assets:
	Cash and cash equivalents		$	–		$	263,052
	Accounts receivable			164,761			203,212
	Prepaid expenses and deposits			22,339			11,417
	Fair value of financial instruments (note 3)			45,003			35,571
Total current assets				232,103			513,252
Fair value of financial instruments (note 3)				8,283			–
Long-term asset				6,852			7,145
Exploration and evaluation assets (notes 4 and 5)				666,696			635,633
Property, plant and equipment (note 5)				6,557,108			5,466,273
Total Assets			$	7,471,042		$	6,622,303
Liabilities and Shareholders’ Equity
Current liabilities:
	Accounts payable and accrued liabilities		$	526,277		$	701,336
	Fair value of financial instruments (note 3)			3,524			1,844
Total current liabilities				529,801			703,180
Bank debt (note 7)				1,144,918			918,854
Fair value of financial instruments (note 3)				11,317			6,356
Deferred premium on flow-through shares (note 9)				4,825			3,210
Decommissioning obligations (note 6)				144,454			114,038
Deferred taxes				465,278			422,090
Shareholders’ equity:
	Share capital (note 9)			4,252,770			3,615,378
	Non-controlling interest (note 8)			28,736			30,006
	Contributed surplus			158,626			124,325
	Retained earnings			730,317			684,866
Total shareholders’ equity				5,170,449			4,454,575
Total Liabilities and Shareholders’ Equity			$	7,471,042		$	6,622,303

Commitments (note 12)

Subsequent events (note 3)

See accompanying notes to the interim condensed consolidated financial statements.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
			Three Months Ended September 30,								Nine Months Ended September 30,
(000s) except per-share amounts (unaudited)			2015				2014				2015				2014
Revenue:
	Oil and natural gas sales		$	267,210			$	320,476			$	781,990			$	1,063,713
	Royalties			(14,755	)			(29,549	)			(35,286	)			(96,587	)
	Net revenue from oil and natural gas sales			252,455				290,927				746,704				967,126
	Realized gain (loss) on financial instruments			45,434				1,509				150,653				(41,923	)
	Unrealized gain on financial instruments (note 3)			27,874				15,606				11,196				4,429
	Other income			7,164				3,544				20,270				12,945
Total net revenue				332,927				311,586				928,823				942,577
Expenses:
	Operating			62,299				53,758				176,637				151,645
	Transportation			27,384				18,235				82,510				54,866
	General and administration			7,682				6,459				19,913				18,208
	Share-based payments (note 11)			7,585				7,334				24,009				20,841
	(Gain) on divestitures			–				(1,808	)			(35,232	)			(2,009	)
	Depletion, depreciation and amortization			174,772				123,919				520,105				366,556
Total expenses				279,722				207,897				787,942				610,107
Income from operations				53,205				103,689				140,881				332,470
Finance expenses				11,209				6,387				31,468				19,363
Income before taxes				41,996				97,302				109,413				313,107
Deferred taxes				13,969				29,303				65,232				87,433
Net income and comprehensive income before non-controlling interest				28,027				67,999				44,181				225,674
Net income (loss) and comprehensive income (loss) attributable to:
	Shareholders of the Company			28,489				67,357				45,451				223,662
	Non-controlling interest (note 8)			(462	)			642				(1,270	)			2,012
			$	28,027			$	67,999			$	44,181			$	225,674
Net income per share attributable to common shareholders (note 10)
	Basic		$	0.13			$	0.33			$	0.22			$	1.13
	Diluted		$	0.13			$	0.33			$	0.21			$	1.10

See accompanying notes to the interim condensed consolidated financial statements.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(000s) (unaudited)		Share Capital				Contributed Surplus				Retained Earnings			Non-Controlling Interest				Total Equity
Balance at December 31, 2014		$	3,615,378			$	124,325			$	684,866		$	30,006			$	4,454,575
Issue of common shares (note 9)			221,108				–				–			–				221,108
Issue of common shares on acquisitions (note 9)			372,878				–				–			–				372,878
Share issue costs, net of tax			(6,562	)			–				–			–				(6,562	)
Share-based payments			–				24,009				–			–				24,009
Capitalized share-based payments			–				24,009				–			–				24,009
Options exercised (notes 9 and 11)			49,968				(13,717	)			–			–				36,251
Income attributable to common shareholders			–				–				45,451			–				45,451
Loss attributable to non-controlling interest			–				–				–			(1,270	)			(1,270	)
Balance at September 30, 2015		$	4,252,770			$	158,626			$	730,317		$	28,736			$	5,170,449

(000s) (unaudited)		Share Capital		Contributed Surplus		Retained Earnings		Non-Controlling Interest		Total Equity
Balance at December 31, 2013		$ 3,062,432		$ 91,718		$ 195,994		$ 17,877		$ 3,368,021
Issue of common shares		282,012		–		–		–		282,012
Issue of common shares on acquisitions		177,359		–		–		–		177,359
Share issue costs, net of tax		(9,524)		–		–		–		(9,524)
Share-based payments		–		20,841		–		–		20,841
Capitalized share-based payments		–		20,841		–		–		20,841
Options exercised		65,852		(17,824)		–		–		48,028
Income attributable to common shareholders		–		–		223,662		–		223,662
Income attributable to non-controlling interest		–		–		–		2,012		2,012
Balance at September 30, 2014		$ 3,578,131		$ 115,576		$ 419,656		$ 19,889		$ 4,133,252

See accompanying notes to the interim condensed consolidated financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOW
				Three Months Ended September 30,								Nine Months Ended September 30,
(000s) (unaudited)				2015				2014				2015				2014
Cash provided by (used in):
Operations:
Net income				$	28,489			$	67,357			$	45,451			$	223,662
Items not involving cash:
		Depletion, depreciation and amortization			174,772				123,919				520,105				366,556
		Accretion			788				594				2,038				1,755
		Share-based payments			7,585				7,334				24,009				20,841
		Deferred taxes			13,969				29,303				65,232				87,433
		Unrealized (gain) on financial instruments			(27,874	)			(15,606	)			(11,196	)			(4,429	)
		(Gain) on divestitures			–				(1,808	)			(35,232	)			(2,009	)
		Non-controlling interest			(462	)			642				(1,270	)			2,012
	Decommissioning expenditures				(167	)			(100	)			(1,268	)			(57	)
	Changes in non-cash operating working capital				64,298				21,412				(1,073	)			18,429
Total cash flow from operating activities					261,398				233,047				606,796				714,193
Financing:
	Issue of common shares				18,210				4,952				263,676				345,622
	Share issue costs				(3	)			(87	)			(9,386	)			(12,732	)
	Increase (decrease) in bank debt				(38,785	)			59,611				239,808				143,738
Total cash flow from financing activities					(20,578	)			64,476				494,098				476,628
Investing:
	Exploration and evaluation				(38,785	)			(52,098	)			(106,834	)			(142,590	)
	Property, plant and equipment				(389,033	)			(597,629	)			(1,019,128	)			(1,266,589	)
	Property acquisitions				(955	)			–				(91,341	)			(4,777	)
	Proceeds from divestitures				6,144				2,425				6,663				2,525
	Net repayment of long-term obligation				(671	)			(996	)			(2,402	)			(2,595	)
	Changes in non-cash investing working capital				182,480				350,775				(150,904	)			223,205
Total cash flow used in investing activities					(240,820	)			(297,523	)			(1,363,946	)			(1,190,821	)
Changes in cash					–				–				(263,052	)			–
Cash, beginning of period					–				–				263,052				–
Cash, end of period				$	–			$	–			$	–			$	–

Cash is defined as cash and cash equivalents.

See accompanying notes to the interim condensed consolidated financial statements.

NOTES TO THE INTERIM CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS

AS AT SEPTEMBER 30, 2015 AND FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2015 AND 2014

(tabular amounts in thousands of dollars, unless otherwise noted) (unaudited)

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 unaudited interim condensed consolidated financial statements reflect only the Company’s proportionate interest in such activities.

The Company’s registered office is located at Suite 2400, 525 – 8^th Avenue S.W., Calgary, Alberta, Canada T2P 1G1.

1. BASIS OF PREPARATION

These unaudited interim condensed consolidated financial statements have been prepared in accordance with International Accounting Standard 34, “Interim Financial Reporting”. These unaudited interim condensed consolidated financial statements do not include all of the information and disclosure required in the annual financial statements and should be read in conjunction with the Company’s consolidated financial statements for the year ended December 31, 2014.

The accounting policies and significant accounting judgments, estimates, and assumptions used in these unaudited interim condensed consolidated financial statements are consistent with those described in Notes 1 and 2 of the Company’s consolidated financial statements for the year ended December 31, 2014.

The unaudited interim condensed consolidated financial statements were authorized for issue by the Board of Directors on November 4, 2015.

2. 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.

Tourmaline classifies the fair value of 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 fair value of cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities approximate their carrying amounts due to their short term nature. Bank debt bears interest at a floating market rate with applicable variable margins, and accordingly the fair market value approximates the carrying amount. The Company’s financial instruments have been assessed on the fair value hierarchy described above and classified as Level 2.

3. 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 consistent with those discussed in note 5 of the Company’s consolidated financial statements for the year ended December 31, 2014.

As at September 30, 2015, the Company has entered into certain financial derivative contracts in order to manage commodity price and interest rate 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 and interest rate contracts to be effective economic hedges. As a result, all such contracts are recorded on the interim consolidated statement of financial position at fair value, with changes in the fair value being recognized as an unrealized gain or loss on the interim consolidated statement of income and comprehensive income.

The Company has the following financial derivative contracts in place as at September 30, 2015 ⁽¹⁾:

(000s)				2015			2016			2017			2018			2019		Fair Value
Gas
Financial swaps		mmbtu/d			61,630			65,000			–			–		–		$	12,223
		USD$/mmbtu		$	3.15		$	3.08
Nymex call options (writer)		mmbtu/d			–			–			20,000			20,000		–		$	(1,073	)
		USD$/mmbtu								$	5.00		$	5.00
Oil
Financial swaps		bbls/d			2,200			2,500			–			–		–		$	33,973
		USD$/bbl		$	76.73		$	69.13
Costless collars		bbls/d			1,300			–			–			–		–		$	7,052
		USD$/bbl		$	81.15 – $94.29
Financial call swaptions (2)		bbls/d			–			1,400			2,500			–		–		$	(2,840	)
		USD$/bbl					$	82.25		$	69.13
Total Fair Value																		$	49,335

(1) The volumes and prices reported are the weighted-average volumes and prices for the period.

(2) This is a European swaption whereby the Company provides the option to extend an oil swap into the period subsequent to the call date.

The Company has entered into the following financial derivative contracts subsequent to September 30, 2015:

Type of Contract		Quantity		Time Period		Contract Price
Oil Financial Swap		500 bbls/d		January 2016 – December 2016		USD $56.50/bbl
Oil Financial Call Swaptions(1)		500 bbls/d		January 2017 – December 2017		USD $56.50/bbl

(1) One time option to call on December 31, 2016.

The Company has the following interest rate swap arrangements:

(000s)
Term		Type (Floating to Fixed)		Amount			Company Fixed Interest Rate			Counter Party Floating Rate Index		Fair Value
Nov 28, 2014 – Nov 28, 2019		Swap		$	250,000		2.065	%		Floating Rate		$	(10,889	)

The following table provides a summary of the unrealized gains (losses) on financial instruments for the three and nine months ended September 30, 2015 and 2014:

		Three Months Ended September 30,							Nine Months Ended September 30,
(000s)		2015				2014			2015				2014
Unrealized gain on financial instruments – commodity contracts		$	29,063			$	15,548		$	17,922			$	4,776
Unrealized gain (loss) on financial instruments – interest rate swaps			(1,189	)			58			(6,726	)			(347	)
Total unrealized gain on financial instruments		$	27,874			$	15,606		$	11,196			$	4,429

In addition to the financial commodity contracts discussed above, the Company has entered into physical delivery sales 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 September 30, 2015 ⁽¹⁾⁽⁶⁾:

				2015				2016				2017				2018				2019
Gas
Fixed price – AECO		mcf/d			174,131				32,760				–				–				–
		CAD$/mcf		$	3.71			$	3.32				–				–				–
Fixed price – AECO (USD)		mmbtu/d			21,739				3,730				–				–				–
		USD$/mmbtu		$	2.56			$	2.72				–				–				–
Fixed price – Stn 2		mcf/d			22,159				–				–				–				–
		CAD$/mcf		$	3.45				–				–				–				–
Basis differentials (2)(3)		mmbtu/d			18,261				63,770				22,500				22,500				22,500
		USD$/mmbtu		$	(0.38	)		$	(0.52	)		$	(0.46	)		$	(0.46	)		$	(0.46	)
Basis differentials – Stn 2 (4)		mcf/d			–				52,152				37,929				37,929				9,482
		CAD$/mcf			–			$	(0.33	)		$	(0.29	)		$	(0.29	)		$	(0.26	)
AECO Monthly Calls / Call Swaptions (5)		mcf/d			89,524				134,475				75,857				42,670				–
		CAD$/mcf		$	4.08			$	4.34			$	4.60			$	4.80				–
Oil
Fixed Price		bbls/d			1,026				–				–				–				–
		USD$/bbl		$	55.38				–				–				–				–

(1) The volumes and prices reported are the weighted-average volumes and prices for the period.

(2) Tourmaline also has 22.5 mmcf/d of Nymex-AECO basis differentials at $(0.46) from 2020-2022.

(3) Tourmaline also has 10,000 mmbtu/d SoCal – AECO basis differential at $(0.73) from November 2013 to October 2016.

(4) Station 2 – AECO basis differential. Tourmaline also has 9,482 mcf/d of Stn 2. basis differentials at $(0.26) for 2020-2021.

(5) These are European swaptions whereby the Company provides the option to extend a gas swap into the period subsequent to the call date or increase the volumes under contract.

(6) Tourmaline also has entered into deals to sell 50,000 mmbtu/d at Chicago GDD pricing less transportation costs from April 2015 to October 2020 and 20,000 mmbtu/d at Ventura GDD pricing less transportation costs from April 2015 to October 2020.

The Company has entered into the following physical contracts subsequent to September 30, 2015⁽¹⁾:

Type of Contract		Quantity		Time Period		Contract Price
Basis Differentials		10,000 MMbtu/d		January 2016 – December 2016		USD $(0.66)/MMbtu

(1) Transactions with common terms have been aggregated and presented at the weighted average price.

4. EXPLORATION AND EVALUATION ASSETS

(000s)
As at December 31, 2014			$	635,633
	Capital expenditures			106,834
	Transfers to property, plant and equipment (note 5)			(69,610	)
	Acquisitions			67,938
	Divestitures			(24,705	)
	Expired mineral leases			(49,394	)
As at September 30, 2015			$	666,696

Exploration and evaluation (“E&E”) assets consist of the Company’s exploration projects which are pending the determination of proven and probable reserves, as well as undeveloped land. Additions represent the Company’s share of costs on E&E assets during the period.

Impairment Assessment

In accordance with IFRS, an impairment test is performed if the Company identifies an indicator of impairment. At September 30, 2015 and December 31, 2014, the Company determined that no indicators of impairment existed on its E&E assets; therefore, an impairment test was not performed.

5. PROPERTY, PLANT AND EQUIPMENT

Cost

(000s)
As at December 31, 2014			$	6,733,617
	Capital expenditures			1,043,137
	Transfers from exploration and evaluation (note 4)			69,610
	Change in decommissioning liabilities (note 6)			21,268
	Acquisitions			444,122
	Divestitures			(18,520	)
As at September 30, 2015			$	8,293,234

Accumulated Depletion, Depreciation and Amortization

(000s)
As at December 31, 2014			$	1,267,344
	Depletion, depreciation and amortization			470,711
	Divestitures			(1,929	)
As at September 30, 2015			$	1,736,126

Net Book Value

(000s)
As at December 31, 2014		$	5,466,273
As at September 30, 2015		$	6,557,108

Future development costs of $5,124.9 million were included in the depletion calculation at September 30, 2015 (December 31, 2014 – $4,610.0 million).

Capitalization of G&A and Share-Based Payments

A total of $17.1 million in G&A expenditures have been capitalized and included in E&E and PP&E assets at September 30, 2015 (December 31, 2014 – $19.3 million). Also included in E&E and PP&E are non-cash share-based payments of $24.0 million (December 31, 2014 – $28.8 million).

Impairment Assessment

In accordance with IFRS, an impairment test is performed on a CGU if the Company identifies an indicator of impairment. At September 30, 2015, the Company determined that indicators of impairment existed on two of its CGUs due to the decline in the current and forward commodity prices.

An impairment is recognized if the carrying value of a CGU exceeds the recoverable amount for that CGU. The Company determines the recoverable amount by using fair value less costs to sell, based on discounted future cash flows of proved plus probable reserves using forecast prices and costs.

An impairment test was performed at September 30, 2015 on two of the Company’s CGU’s using a pre-tax discount rate of 10% and the following forward commodity price estimates:

Year		WTI Oil (US$/bbl)(1)		Foreign Exchange Rate(1)		Edmonton Light Crude Oil (Cdn$/bbl)(1)		AECO Gas (Cdn$/mmbtu)(1)
2015		47.00		0.7567		57.49		2.93
2016		53.33		0.7633		64.53		3.29
2017		62.07		0.8017		71.23		3.53
2018		66.67		0.8100		76.89		3.83
2019		71.33		0.8250		81.01		4.10
2020		74.77		0.8333		84.73		4.31
2021		78.24		0.8333		88.84		4.47
2022		81.75		0.8333		93.04		4.65
2023		85.37		0.8333		97.34		4.85
2024		87.90		0.8333		99.92		5.00
Thereafter		+1.8%/yr		0.8333		+1.8%/yr		+1.8%/yr

(1) Source: Average of, GLJ Petroleum Consultants, McDaniel & Associates Consultants, and Sproule Associates price forecasts, effective October 1, 2015

The external reserve evaluators also assess many financial assumptions regarding royalty rates, operating costs and future development capital, along with several other non-financial assumptions with a direct bearing on reserve volumes. Management has reviewed these variables in performing its impairment assessment, but given they are estimates there remains uncertainty.

The Company has determined that there was no impairment to PP&E at September 30, 2015.

For the year ended December 31, 2014, the Company identified indicators of impairment on two of its CGUs based on the decline in commodity prices and performed impairment tests accordingly. The Company determined that there was no impairment to PP&E at December 31, 2014.

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.

Results from operations are included in the Company’s unaudited interim 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:

(000s)			Perpetual Energy Inc.
Fair value of net assets acquired:
	Property, plant and equipment		$	226,943
	Exploration and evaluation			34,160
	Decommissioning obligations			(2,443	)
Total			$	258,660
Consideration:
	Common shares issued		$	258,660

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 interim consolidated statement of income and comprehensive income. The acquisition resulted in an increase in Property, Plant and Equipment (“PP&E”) of approximately $26.8 million and Exploration and Evaluation (“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 unaudited interim consolidated financial statements from the closing date of the transaction.

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 interim consolidated statement of income and comprehensive income.

Results from operations for Mapan are included in the Company’s unaudited interim 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:

(000s)			Mapan Energy Ltd.
Fair value of net assets acquired:
	Cash		$	11,011
	Working capital			4,000
	Property, plant and equipment			58,471
	Fair Value of Financial Instruments			(122	)
	Decommissioning obligations			(3,157	)
	Deferred income tax asset			19,437
Total			$	89,640
Consideration:
	Common shares issued		$	89,640

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 interim consolidated statement of income and comprehensive income.

Results from operations for Santonia are included in the Company’s unaudited interim 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:

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

Acquisition of Oil and Natural Gas Properties

For the nine months ended September 30, 2015, the Company completed property acquisitions including swaps for total cash consideration of $91.3 million (December 31, 2014 – $33.0 million) and in addition to the Perpetual acquisition, a further $69.6 million in non-cash consideration (December 31, 2014 – $2.2 million). The Company also assumed $6.2 million in decommissioning liabilities in addition to the Perpetual acquisition (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 the next five years. The committed capital expenditures 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 September 30, 2015, the full-committed amount had been spent on these specified projects.

6. 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 $198.0 million (December 31, 2014 – $157.5 million), with some abandonments expected to commence in 2021. A risk-free rate of 2.31% (December 31, 2014 – 2.36%) and an inflation rate of 1.8% (December 31, 2014 – 2.0%) were used to calculate the decommissioning obligations.

(000s)			As at September 30, 2015				As at December 31, 2014
Balance, beginning of period			$	114,038			$	76,037
	Obligation incurred			12,255				14,257
	Obligation incurred on corporate acquisitions			3,516				8,487
	Obligation incurred on property acquisitions			5,132				4,881
	Obligation divested			(270	)			(5,676	)
	Obligation settled			(1,268	)			(413	)
	Accretion expense			2,038				2,351
	Change in future estimated cash outlays			9,013				14,114
Balance, end of period			$	144,454			$	114,038

7. BANK DEBT

The Company has a covenant-based, unsecured, bank credit facility in place with a syndicate of bankers. In June 2015, the Company increased the facility amount from $1,550.0 to $1,800.0 million. The term was also increased from three to four years, resulting in an initial maturity 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 also 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. With the exception of the increase in the facility amount, length of term and the addition of the accordion feature, the debt was renewed under the same terms and conditions as those outlined in note 9 of the Company’s consolidated financial statements for the year ended December 31, 2014. 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. In September 2015, the Company extended the maturity of the term loan from November 30, 2019 to November 30, 2020 and the annual interest rate was reduced to 220 basis points from 240 basis points over the applicable bankers’ acceptance rate. The covenants for the term loan are similar to those under the Company’s current credit facility and the term loan will rank equally with the obligation under the Company’s credit facility.

As at September 30, 2015, the Company had $248.6 million in long-term debt outstanding and $896.3 million drawn against the bank credit facility for total bank debt of $1,144.9 million (net of prepaid interest and debt issue costs) (December 31, 2014 – $918.9 million). In addition, Tourmaline has outstanding letters of credit of $6.3 million (December 31, 2014 – $2.4 million), which reduce the credit available on the facility. The effective interest rate for the nine months ended September 30, 2015 was 2.69% (nine months ended September 30, 2014 – 2.99%). As at September 30, 2015, the Company is in compliance with all debt covenants.

8. NON-CONTROLLING INTEREST

The Company owns 90.6 percent of Exshaw Oil Corp., a private company engaged in oil and gas exploration in Canada. A reconciliation of the non-controlling interest is provided below:

(000s)			As at September 30, 2015				As at December 31, 2014
Balance, beginning of period			$	30,006			$	17,877
	Share of subsidiary’s net income (loss) for the period			(1,270	)			12,129
Balance, end of period			$	28,736			$	30,006

9. 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

		As at September 30, 2015						As at December 31, 2014
(000s) except share amounts		Number of Shares		Amount				Number of Shares		Amount
Balance, beginning of period		203,162,112		$	3,615,378			189,804,864		$	3,062,432
For cash on public offering of common shares (1)(5)		4,947,500			195,425			4,615,198			219,222
For cash on public offering of flow-through common shares (2)(3)(4)		640,000			25,683			1,430,053			74,939
Issued on corporate and property acquisitions (note 5)		10,193,026			372,878			3,228,234			177,359
For cash on exercise of stock options		1,870,253			36,251			4,083,763			66,473
Contributed surplus on exercise of stock options		–			13,717			–			24,925
Share issue costs		–			(9,386	)		–			(13,332	)
Tax effect of share issue costs		–			2,824			–			3,360
Balance, end of period		220,812,891		$	4,252,770			203,162,112		$	3,615,378

(1) On February 12, 2014, the Company issued 4.615 million common shares at a price of $47.50 per share for total gross proceeds of $219.2 million. A total of 15,198 common shares were purchased by insiders.

(2) On June 2, 2014, the Company issued 1.15 million flow-through shares at a price of $68.15 per share for total gross proceeds of $78.4 million. The implied premium on flow-through common shares was determined to be $15.6 million or $13.55 per share. A total of 122,000 flow-through common shares were purchased by insiders. As at December 31, 2014, the Company had spent the full-committed amount. The expenditures were renounced to investors in February 2015 with an effective renunciation date of December 31, 2014.

(3) On November 28, 2014, the Company issued 0.28 million flow-through shares at a price of $57.00 per share for total gross proceeds of $16.0 million. The implied premium on flow-through common shares was determined to be $3.8 million or $13.62 per share. As at September 30, 2015, the Company had spent the full-committed amount. The expenditures were renounced to investors in February 2015 with an effective renunciation date of December 31, 2014.

(4) On March 12, 2015, the Company issued 0.64 million flow-through shares at a price of $50.00 per share for total gross proceeds of $32.0 million. The implied premium on flow-through common shares was determined to be $6.3 million or $9.87 per share. As at September 30, 2015, the Company is committed to spend the remaining $24.4 million on qualified exploration expenditures by December 31, 2016. The expenditures will be renounced to investors with an effective renunciation date of December 31, 2015.

(5) On June 23, 2015, the Company issued 4.948 million common shares at a price of $39.50 for total gross proceeds of $195.4 million. A total of 60,000 common shares were purchased by insiders.

10. EARNINGS PER SHARE

Basic earnings-per-share attributed to common shareholders was calculated as follows:

		Three Months Ended September 30,						Nine Months Ended September 30,
		2015			2014			2015			2014
Net earnings for the period (000s)		$	28,489		$	67,357		$	45,451		$	223,662
Weighted average number of common shares – basic			218,745,913			201,497,624			211,389,015			197,906,925
Earnings per share – basic		$	0.13		$	0.33		$	0.22		$	1.13

Diluted earnings-per-share attributed to common shareholders was calculated as follows:

		Three Months Ended September 30,						Nine Months Ended September 30,
		2015			2014			2015			2014
Net earnings for the period (000s)		$	28,489		$	67,357		$	45,451		$	223,662
Weighted average number of common shares – diluted			219,376,160			206,469,220			212,561,337			202,811,901
Earnings per share – fully diluted		$	0.13		$	0.33		$	0.21		$	1.10

There were 11,098,666 and 11,083,666 options excluded from the weighted-average share calculations for the three and nine month periods ended September 30, 2015, respectively, because they were anti-dilutive (three and nine months ended September 30, 2014 – 2,035,000 options, respectively).

11. 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 22,081,289 shares of common stock, which represents 10% of the current outstanding common shares. 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.

			Nine Months Ended September 30,
			2015						2014
			Number of Options			Weighted Average Exercise Price			Number of Options			Weighted Average Exercise Price
Stock options outstanding, beginning of period			17,046,500			$	36.44		16,028,651			$	27.95
	Granted		1,359,500				37.40		2,151,000				52.80
	Exercised		(1,870,253	)			19.38		(2,874,930	)			16.71
	Forfeited		(33,333	)			39.17		(164,889	)			50.81
Stock options outstanding, end of period			16,502,414			$	38.45		15,139,832			$	33.36

The weighted average trading price of the Company’s common shares was $36.94 during the nine months ended September 30, 2015 (nine months ended September 30, 2014 – $52.13).

The following table summarizes stock options outstanding and exercisable at September 30, 2015:

Range of Exercise Price		Number Outstanding at Period End		Weighted Average Remaining Contractual Life		Weighted Average Exercise Price		Number Exercisable at Period End		Weighted Average Exercise Price
$20.68 – $29.93		3,187,750		1.18		26.97		3,187,750		26.97
$30.76 – $39.57		4,128,164		2.95		34.43		1,822,442		32.63
$40.18 – $48.99		7,526,500		3.45		42.12		2,049,000		41.28
$51.47 – $56.76		1,660,000		3.77		53.85		553,333		53.85
		16,502,414		2.92		38.45		7,612,525		34.13

The fair value of options granted during the nine-month period ended September 30, 2015 was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions and resulting values:

		September 30,
		2015				2014
Fair value of options granted (weighted average)		$	10.93			$	18.50
Risk-free interest rate			2.29	%			2.83	%
Estimated hold period prior to exercise			4 years				4 years
Expected volatility			33	%			40	%
Forfeiture rate			2	%			2	%
Dividend per share		$	0.00			$	0.00

12. COMMITMENTS

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

PAYMENTS DUE BY YEAR

(000s)		1 Year			2-3 Years			4-5 Years			> 5 Years			Total
Operating leases		$	5,078		$	11,053		$	8,073		$	–		$	24,204
Firm transportation and processing agreements			144,911			404,016			272,675			547,360			1,368,962
Capital commitments (1)			313,244			908,283			75,000			–			1,296,527
Flow-through share commitments			24,435			–			–			–			24,435
Credit facility (2)			–			–			988,552			–			988,552
Term debt (3)			11,131			22,263			22,263			251,157			306,814
		$	498,799		$	1,345,615		$	1,366,563		$	798,517		$	4,009,494

(1) Includes drilling commitments, and capital spending commitments under the joint arrangement in the Spirit River complex of $300 million per year until 2019. The capital spending commitment under the joint arrangement can be deferred to future periods in the event of an economic downturn, and as agreed upon by both parties.

(2) Includes interest expense at an annual rate of 2.52% being the rate applicable to outstanding debt on the credit facility at September 30, 2015.

(3) Includes interest expense at an annual rate of 4.47% being the fixed rate on the term debt (including the interest rate swap) at September 30, 2015.

ABOUT TOURMALINE OIL CORP.

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

FOR FURTHER INFORMATION, PLEASE CONTACT:

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

OR

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

OR

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

OR

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