Tourmaline achieves strong first half growth with a cash flow budget

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Aug 03, 2016, 17:00 ET

CALGARY, Aug. 3, 2016 /CNW/ - Tourmaline Oil Corp. (TSX:TOU) ("Tourmaline" or the "Company") is pleased to release strong financial and operating results for the second quarter of 2016.

Highlights

First half 2016 average production of 190,820 boepd, within the full-year 2016 guidance range of 190,000-195,000 boepd and a 33% increase over 1H 2015.
Record second quarter operating costs of $3.41/boe, down 17% from Q2 2015, and 8% from Q1 2016.
Industry-leading cash financing costs of $0.64/boe, with record low effective interest rates of 2.45%.
All-in cash costs of $6.58/boe (operating, transportation, general and administration and financing) in Q2 2016, down from $6.68/boe in Q1 2016, which was also a record for the Company.
Cash flow⁽¹⁾ for Q2 2016 of $134.3 million remained strong as a result of the Company's continued cost control emphasis, even with weak natural gas prices during the quarter.
Capital spending of $49.0 million was the leading contributor to an improvement in Tourmaline's balance sheet, driving Q2 2016 net debt⁽²⁾ to $1.37 billion, down $158.5 million from Q1 2016 net debt (after taking into account the net proceeds of the April 5, 2016 financing of $269.9 million). Net debt is approaching the 2016 exit net debt target of $1.2 billion.
Tourmaline expects to bring approximately 100 new wells on-stream prior to year-end 2016, allowing the Company to meet or exceed the current production exit target of 210,000-215,000 boepd.
Tourmaline is currently the fifth largest NEBC Montney producer; Tourmaline's Montney production is expected to grow by 50% over the next 18 months.

PRODUCTION

First half 2016 production averaged 190,820 boepd, a 33% increase over first half 2015 and within the full-year 2016 production guidance range of 190,000-195,000 boepd. Tourmaline expects strong second half 2016 production growth with over 100 new wells across all three core complexes coming on-stream prior to year-end.

Second quarter 2016 average production of 185,812 boepd represents a 29% increase over second quarter 2015 production of 143,634 boepd. As previously indicated on June 15, 2016, second quarter production was ultimately reduced by 9,500 boepd due to significant, unplanned, firm service restrictions on the TCPL system in May and June, as well as a lengthy production interruption at the third-party deep cut facility at Wild River-Saturn in the Alberta Deep Basin. The 5,000 bpd of Company-interest NGL production volumes from this facility are anticipated to be restored in early August 2016. As previously disclosed, Tourmaline also elected to defer EP activities and related production from Q2 until 2H 2016 due to poor commodity prices.

The Company remains on track for full-year 2016 average production of between 190,000 and 195,000 boepd, representing 25% year-over-year production growth. Tourmaline is continuing to target 2016 production exit volumes of 210,000-215,000 boepd (1.1 bcf/day of natural gas), essentially at the 2017 average production guidance level. The Company continues to time the start-up of new 2H 2016 production volumes to match an anticipated steadily-improving commodity price environment during the fourth quarter of 2016 and continuing into 2017.

The current 2017 production guidance of 215,000 boepd is based on a 12-rig drilling program and the Company is staffed to efficiently execute a 20-22 rig drilling program. Tourmaline will expand the 2017 drilling program should commodity prices generate incremental cash flow in excess of the current 2017 forecast of $1.2 billion. The impact of significantly reduced capital costs is also not fully factored into current 2017 guidance, which allows for additional wells within the same EP capital program.

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⁽¹⁾ "Cash flow" is defined as cash provided by operations before changes in non-cash operating working capital. See "Non-GAAP Financial Measures" below and in the attached Management's Discussion and Analysis.

⁽²⁾ "Net debt" is defined as long-term debt plus working capital (adjusted for the fair value of financial instruments). See "Non-GAAP Financial Measures" in the attached Management's Discussion and Analysis.

FINANCIAL RESULTS AND CAPITAL BUDGET

First half 2016 EP capital spending was $281.6 million, below the previously-reduced estimate of $310.0 million, and lower than 1H 2016 cash flow of $293.7 million. Second quarter 2016 capital spending was $49.0 million, significantly less than the 2Q 2016 cash flow of $134.3 million ($0.58/share). Second quarter 2016 cash flow remained strong despite extremely low realized natural gas prices of $1.87/mcf for the period. Steadily-improving natural gas prices and the Company's gas marketing activities are expected to potentially yield stronger than anticipated second half 2016 cash flow. Approximately 84% of Tourmaline's 2H 2016 natural gas volumes are either priced at hubs other than the AECO hub, or are financially hedged.

Q2 2016 net debt was $1.37 billion, down from Q1 2016 net debt of $1.5 billion (after taking into account the April 5, 2016 financing), the second consecutive quarter of net debt reduction. Tourmaline is trending towards the exit 2016 net debt level of approximately $1.2 billion. The Company will continue to execute a cash flow budget in 2016 and 2017. The Company has maintained a very strong balance sheet throughout its 7.5 year history. At June 30, 2016, Tourmaline had $759.3 million of unused credit capacity via the recently extended bank facility.

CASH COSTS AND CAPITAL COSTS

Second quarter 2016 operating costs were $3.41/boe, a Company record, down 17% from second quarter 2015 operating costs of $4.10/boe and well ahead of previous 2016 opex guidance of $4.25/boe. As a result, opex guidance for 2016 has been reduced to $3.75/boe. Second quarter 2016 all-in cash costs were $6.58/boe, down from first quarter 2016 cash costs of $6.68/boe. Drill and complete capital costs were reduced by an average of 30% across all three core complexes in Q1 2016 compared to Q1 2015.

The Company is targeting a further 15% reduction in drill and complete capital costs with the recently commenced 2H 2016 EP program. New pacesetter well costs have already been established in the past month in all three core complexes, eclipsing the Q1 2016 pacesetter achievements outlined in the June 15 press release. These continued cash and capital cost reductions serve to drive down the threshold natural gas price required for full cycle gas profitability and related strong earnings.

EP UPDATE

Tourmaline has initiated the 2H 2016 EP program in all three core-operated complexes, with 10 operated drilling rigs now active. The Company plans to focus more on drilling the longer lead time, multi-well pads during the third quarter with a corresponding increase in completion activity scheduled for the fourth quarter. The ongoing EP program coupled with the existing inventory of already-drilled uncompleted wells is expected to yield approximately 100 new producing wells to bring on-stream by year-end, allowing the Company to meet or exceed the current 215,000 boepd production exit target. The Company also expects to reach the 30,000 bpd liquids production (oil, condensate, NGLs) threshold late in 2016 or during the first quarter of 2017. There are no new facility projects planned in the second half of 2016; the next gas plant project is the 60 mmcfpd Doe 2-11 gas plant in NEBC, scheduled for April 1, 2017 start-up.

The second half EP drilling program includes horizontals in multiple new horizons that could significantly expand the longer term production and reserve outlook for all three core complexes. These wells will test the Falher C and Viking, amongst others, in the Alberta Deep Basin, an areal expansion to the condensate-rich Lower Montney Turbidite in NEBC and the Lower Charlie Lake and Lower Montney formations on the Peace River High.

Tourmaline is currently the fifth largest Montney producer in NEBC with daily production of between 50,000 and 55,000 boepd. Facility expansions timed with incremental firm transportation service agreements will rapidly increase production to between 75,000 and 80,000 boepd by Q1 2018, representing growth of over 50%. A further production growth step to the 90,000-95,000 boepd level is planned for Q4 2018. Q2 2016 operating costs in the Company's BC Montney gas/condensate complex were $3.20/boe, amongst the lowest in North America. Tourmaline's drill and complete capital costs for 30-stage Montney horizontal wells are now averaging a record low $2.9 million; the Company will attempt to further reduce these costs in the 2H 2016 program.

CORPORATE SUMMARY – SECOND QUARTER 2016

		Three Months Ended June 30,					Six Months Ended June 30,
		2016		2015		Change	2016		2015		Change
OPERATIONS
Production
	Natural gas (mcf/d)	979,029		764,908		28%	1,006,411		757,765		33%
	Crude oil and NGL (bbl/d)	22,640		16,149		40%	23,085		17,385		33%
	Oil equivalent (boe/d)	185,812		143,634		29%	190,820		143,679		33%
Product prices⁽¹⁾
	Natural gas ($/mcf)	$	1.87	$	3.17	(41)%	$	2.04	$	3.42	(40)%
	Crude oil and NGL ($/bbl)	$	38.94	$	53.34	(27)%	$	36.22	$	47.90	(24)%
Operating expenses ($/boe)		$	3.41	$	4.10	(17)%	$	3.56	$	4.40	(19)%
Transportation costs ($/boe)		$	2.06	$	2.00	3%	$	1.97	$	2.12	(7)%
Operating netback⁽³⁾ ($/boe)		$	8.63	$	16.37	(47)%	$	9.18	$	16.53	(44)%
Cash general and administrative expenses ($/boe)⁽²⁾		$	0.47	$	0.46	2%	$	0.45	$	0.47	(4)%
FINANCIAL ($000, except share and per share)
Revenue		247,123		298,696		(17)%	526,231		619,999		(15)%
Royalties		8,551		4,944		73%	15,120		20,531		(26)%
Cash flow⁽³⁾		134,298		203,029		(34)%	293,728		410,769		(28)%
Cash flow per share (diluted)⁽³⁾		$	0.58	$	0.95	(39)%	$	1.29	$	1.96	(34)%
Net earnings (loss)		(77,940)		(5,197)		1,400%	(116,330)		16,962		(786)%
Net earnings (loss) per share (diluted)		$	(0.34)	$	(0.02)	1,600%	$	(0.51)	$	0.08	(738)%
Capital expenditures (net of dispositions)		49,010		290,629		(83)%	463,867		788,011		(41)%
Weighted average shares outstanding (diluted)							227,064,847		209,560,883		8%
Net debt⁽³⁾							(1,373,849)		(1,283,537)		7%

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

(2) Excluding interest and financing charges.

(3) See "Non-GAAP Financial Measures" in the attached Management's Discussion and Analysis.

Conference Call Tomorrow at 7:30 a.m. MDT (9:30 a.m. EDT)

Tourmaline will host a conference call tomorrow, August 4, 2016 starting at 7:30 a.m. MDT (9:30 a.m. EDT). To participate, please dial 1-888-231-8191 (toll-free in North America), or local dial-in 647-427-7450, a few minutes prior to the conference call.

Reader Advisories

CURRENCY

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

FORWARD-LOOKING INFORMATION

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

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

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

Additional information on these and other factors that could affect Tourmaline, or its operations or financial results, are included in the Company's most recently filed Management's Discussion and Analysis (See "Forward-Looking Statements" therein) , Annual Information Form (See "Risk Factors" and "Forward-Looking Statements" therein) and other reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or Tourmaline's website (www.tourmalineoil.com).

The forward-looking information contained in this press release is made as of the date hereof and Tourmaline undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless expressly required by applicable securities laws.

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.

FINANCIAL OUTLOOK

Also included in this news release are estimates of Tourmaline's 2016 and 2017 cash flows as well as 2016 net debt, which are based on, among other things, the various assumptions as to production levels, capital expenditures, and other assumptions disclosed in this news release and including Tourmaline's estimated 2016 average production of 190,000-195,000 boepd and estimated average production of 215,000 boepd in 2017 and commodity price assumptions for natural gas (AECO - $2.19/mcf for 2016 and $3.35 for 2017), and crude oil (WTI (US) - $47.18/bbl for 2016 and $60.00/bbl for 2017) and an exchange rate assumption of $0.77 (US/CAD) for 2016 and $0.80 (US/CAD) for 2017. To the extent that such estimates constitute financial outlooks, they were approved by management and the Board of Directors of Tourmaline on August 3, 2016 and are included to provide readers with an understanding of Tourmaline's anticipated cash flow and net debt based on the capital expenditure, production and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.

NON-GAAP FINANCIAL MEASURES

This press release includes references to financial measures commonly used in the oil and gas industry, "cash flow", "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", "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.

GENERAL

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

CERTAIN DEFINITIONS

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

MANAGEMENT'S DISCUSSION AND ANALYSIS

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 six months ended June 30, 2016 and the consolidated financial statements for the year ended December 31, 2015. The consolidated financial statements and the MD&A can be found at www.sedar.com. This MD&A is dated August 3, 2016.

The financial information contained herein has been prepared in accordance with International Financial Reporting Standards ("IFRS") and sometimes referred to in this MD&A as Generally Accepted Accounting Principles ("GAAP") as issued by the International Accounting Standards Board. All dollar amounts are expressed in Canadian currency, unless otherwise noted.

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

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

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

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 and regulatory 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 June 30,			Six Months Ended June 30,
	2016	2015	Change	2016	2015	Change
Natural gas (mcf/d)	979,029	764,908	28%	1,006,411	757,765	33%
Oil (bbl/d)	12,564	10,418	21%	13,055	10,610	23%
NGL (bbl/d)	10,076	5,731	76%	10,030	6,775	48%
Oil equivalent (boe/d)	185,812	143,634	29%	190,820	143,679	33%
Natural gas %	88%	89%		88%	88%

Production for the three months ended June 30, 2016 averaged 185,812 boe/d compared to 143,634 boe/d for the same quarter of 2015. The second quarter production, was impacted by firm service restrictions, an expanded maintenance program on the Spectra system in B.C. as well as a fire at the Pembina Saturn 2 facility and was still 29% higher than the prior year. For the six months ended June 30, 2016, production increased 33% to 190,820 boe/d from 143,679 boe/d for the same period of 2015. The increase in natural gas production is related to the Company's successful exploration and production program as well as corporate and property acquisitions over the past year. The growth in oil and NGL production is the result of increased drilling in the Spirit River/Peace River High Charlie Lake oil plays, incremental liquids recovered in the Wild River area via deep-cut processing, and strong condensate recoveries from new wells commencing production as the liquids-rich Montney Turbidite is developed in northeast British Columbia. Approximately 95% of the growth in production volumes since the second quarter of 2015 can be attributed to wells brought on stream from the Company's exploration and production program, with the remainder of the change being from corporate and property acquisitions (net of dispositions).

Full-year average production guidance for 2016 is approximately 190,000-195,000 boe/d which was revised downward from 200,000 boe/d in the Company's press release dated June 15, 2016.

REVENUE

		Three Months Ended					Six Months Ended
						June 30,					June 30,
(000s)		2016		2015		Change	2016		2015		Change
Revenue from:
	Natural gas	$	166,901	$	220,315	(24)%	$	374,071	$	469,278	(20)%
	Oil and NGL	80,222		78,381		2%	152,160		150,721		1%
Total revenue from natural gas, oil and NGL sales		$	247,123	$	298,696	(17)%	$	526,231	$	619,999	(15)%

Revenue for the three months ended June 30, 2016 decreased 17% to $247.1 million from $298.7 million for the same quarter of 2015. Revenue for the six-month period ended June 30, 2016 decreased 15% from $620.0 million in 2015 to $526.2 million in 2016. Lower revenue for the period is consistent with the significant decrease in realized commodity prices and lower realized gains on energy marketing and hedging activities, partially offset by higher production volumes. Revenue includes all petroleum, natural gas and NGL sales and the realized gain on financial instruments.

TOURMALINE REALIZED PRICES:

	Three Months Ended							Six Months Ended
					June 30,					June 30,
	2016		2015		Change	2016		2015		Change
Natural gas ($/mcf)	$	1.87	$	3.17	(41)%	$	2.04	$	3.42	(40)%
Oil ($/bbl)	$	59.51	$	73.19	(19)%	$	54.42	$	67.27	(19)%
NGL ($/bbl)	$	13.29	$	17.26	(23)%	$	12.52	$	17.56	(29)%
Oil equivalent ($/boe)	$	14.61	$	22.85	(36)%	$	15.15	$	23.84	(36)%

BENCHMARK OIL AND GAS PRICES:

		Three Months Ended
				June 30,
		2016		2015		Change
Natural gas
	NYMEX Henry Hub (USD$/mcf)	$	2.25	$	2.74	(18)%
	AECO (CAD$/mcf)	$	1.40	$	2.68	(48)%
Oil
	NYMEX (USD$/bbl)	$	45.64	$	57.95	(21)%
	Edmonton Par (CAD$/bbl)	$	55.10	$	69.40	(21)%

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

	Three Months Ended
	June 30,
($/mcf)	2016		2015		Change
AECO index ⁽¹⁾	$	1.39	$	2.65	(48)%
Heat/quality differential	0.10		0.24		(58)%
Realized gain	0.38		0.38		−%
Sales point differential ⁽²⁾	−		(0.10)		100%
Tourmaline realized natural gas price	$	1.87	$	3.17	(41)%
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
					June 30,
	2016		2015		Change
CAD$/USD$ ⁽¹⁾	$	0.7761	$	0.8134	(5)%

(1) Average rates for the period.

The realized average natural gas price for the three and six months ended June 30, 2016 was $1.87/mcf and $2.04/mcf, respectively, which is 41% and 40% lower than the same periods of the prior year. The lower natural gas price reflects lower index prices experienced during the quarter which was partially offset by realized gains on commodity contracts. The realized price for the second quarter of 2016, included a gain on commodity contracts of $34.1 million (six months ended June 30, 2016 - $67.0 million) compared to a gain of $26.4 million for the same period of the prior year (six months ended June 30, 2015 - $84.3 million). Realized gains on commodity contracts for the quarter ended June 30, 2016 have increased compared to the same period of the prior year reflecting the significant decrease in the AECO benchmark price during the quarter compared to the commodity contract prices. Realized gains on commodity contracts for the six months ended June 30, 2016 have decreased compared to the same period of the prior year primarily due to a lower proportion of hedged volumes in the first quarter of 2016. 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 19% for the three and six months ended June 30, 2016, which is consistent with the decrease in the benchmark price for crude oil during the quarter partially offset by a $7.0 million gain on commodity contracts in the second quarter of 2016 (six months ended June 30, 2016 - $19.7 million). NGL prices decreased 23% from $17.26/bbl to $13.29/bbl, when compared to the same quarter of 2015. The decrease in NGL prices is consistent with the decrease in crude oil and natural gas prices over the same period.

ROYALTIES

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(000s)	2016		2015		2016		2015
Natural gas	$	1,567	$	(1,661)	$	2,980	$	8,566
Oil and NGL	6,984		6,605		12,140		11,965
Total royalties	$	8,551	$	4,944	$	15,120	$	20,531
Royalties as a percentage of revenue	4.2%		1.9%		3.4%		4.0%

For the quarter ended June 30, 2016, the average effective royalty rate was 4.2% compared to the rate of 1.9% for the same quarter of 2015. The second quarter 2015 rate reflects a large natural gas royalty credit received in June 2015 related to gas cost allowance which resulted in significantly lower natural gas royalties in that quarter.

For the six-month period ended June 30, 2016, the average effective royalty rate decreased from 4.0% in 2015 to 3.4% in 2016. The decrease can be attributed to significantly lower commodity prices received during the period. Royalty rates are impacted by changes in commodity prices whereby the actual royalty rate decreases when prices decrease. The Company also receives gas cost allowance from the Crown, which further reduces royalties to account for expenses incurred to process and transport the Crown's portion of natural gas production.

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.

On January 29, 2016, the Alberta Government (the "Government") released a new Royalty Regime effective January 1, 2017. The new regime will apply to wells drilled after the effective date, whereby all other wells will follow the old framework for a further 10 years. On April 21, 2016, the Government provided further details and calibration on the Modernized Royalty Framework ("MRF"). On July 11, 2016, the Government further announced two new royalty programs; the Enhanced Hydrocarbon Recovery Program ("EHRP") and the Emerging Resources Program ("ERP"). The EHRP will begin January 1, 2017 and will replace the existing Enhanced Oil Recovery Program. It will help to promote incremental production through enhanced recovery methods. The ERP is also effective January 1, 2017, and will encourage industry to access new oil and gas resources in higher-risk and higher-cost areas that have large resource potential. Detailed program and application guidelines are expected in the next few months. On July 12, 2016, the Government announced that new wells spud before January 1, 2017 may elect to opt-in early to the MRF, if they meet certain criteria. Per the announcement, wells spud before July 13, 2016 will continue to operate under the previous royalty framework until December 31, 2026. Wells spud during the early election period (July 13, 2016 to December 31, 2016) that did not elect to opt-in early to the MRF or did not meet the criteria will continue to operate under the previous royalty framework until December 31, 2026. At this time, the Company does not anticipate opting-in early to the MRF. Based on the details provided thus far, we believe that the MRF is generally consistent with the initial goal of incentivising the use of technology to improve productivity and rewards producers deploying the most competitive operating practices. As additional information is provided, the Company will continue to monitor the expected overall impact starting in 2017.

The Company expects its royalty rate for 2016 to be approximately 5%, consistent with the previous Company guidance released May 4, 2016 in the Company's March 31, 2016 MD&A. The royalty rate is sensitive to commodity prices, and as such, an increase in commodity prices later in 2016, will increase the actual rate.

OTHER INCOME

	Three Months Ended June 30,					Six Months Ended June 30,
(000s)	2016		2015		Change	2016		2015		Change
Other income	$	7,169	$	6,230	15%	$	13,650	$	14,381	(5)%

Other income increased from $6.2 million in the second quarter of 2015 to $7.2 million for the same quarter of 2016. The increase in processing income is related to additional processing capacity acquired from Mapan in August 2015. For the six-month period ended June 30, 2016, other income decreased from $14.4 million in 2015 to $13.7 million in 2016. In 2016, the Company is now processing less third party volumes at its owned and operated gas processing facilities. As the Company's production increases, third party volumes processed at those facilities is reduced. Conversely, if the Company's production is temporarily reduced in a certain area, processing income from third parties could increase for a short period of time.

OPERATING EXPENSES

			Three Months Ended June 30,					Six Months Ended June 30,
(000s) except per unit amounts	2016		2015		Change	2016		2015		Change
Operating expenses	$	57,630	$	53,647	7%	$	123,520	$	114,338	8%
Per boe	$	3.41	$	4.10	(17)%	$	3.56	$	4.40	(19)%

Operating expenses include all periodic lease and field-level expenses and exclude income recoveries from processing third-party volumes. For the second quarter of 2016, total operating expenses were $57.6 million compared to $53.6 million in 2015, an increase of 7% over a production base increase of 29% for the same period. Operating costs for the six months ended June 30, 2016 were $123.5 million, compared to $114.3 million for the same period of 2015, reflecting an 8% increase in total costs over a 33% increase in production.

On a per-boe basis, the costs decreased from $4.10/boe for the second quarter of 2015 to $3.41/boe in the second quarter of 2016. For the six months ended June 30, 2016, operating costs were $3.56/boe, down from $4.40/boe in the prior year. The Company's investments in processing facilities in 2014 and 2015 have reduced the volume of gas flowing to third-party facilities, contributing to the reduction in operating expenses on a per-boe basis. Additionally, along with a commitment to continue to drive down the overall cost structure, the Company is realizing increased operational efficiencies in all three core areas along with fixed costs being distributed over a significantly higher production base.

The Company's average operating cost target is now being reduced to $3.75/boe, which is a $0.50/boe decrease from the previous guidance of $4.25/boe initially released on March 7, 2016. Although, additional deep cut processing was curtailed in the second quarter due to a fire at the Pembina Saturn 2 facility, the Company does expect an increase in operating expenses per boe during the second half of 2016 due to additional volumes, bearing higher operating expenses, flowing through the facility. Actual costs per boe can change, however, depending on a number of factors, including the Company's actual production levels.

TRANSPORTATION

			Three Months Ended June 30,					Six Months Ended June 30,
(000s) except per unit amounts	2016		2015		Change	2016		2015		Change
Natural gas transportation	$	25,946	$	19,506	33%	$	51,529	$	39,284	31%
Oil and NGL transportation	8,840		6,594		34%	16,882		15,842		7%
Total transportation	$	34,786	$	26,100	33%	$	68,411	$	55,126	24%
Per boe	$	2.06	$	2.00	3%	$	1.97	$	2.12	(7)%

For the second quarter of 2016, total transportation expenses were $34.8 million compared to $26.1 million in 2015. Transportation costs for the six months ended June 30, 2016 were $68.4 million, compared to $55.1 million for the same period in 2015, reflecting increased costs related to higher production volumes.

On a per-boe basis, the costs increased slightly from $2.00/boe for the second quarter of 2015 to $2.06/boe in the second quarter of 2016 as pipeline tolls for the transportation of natural gas have increased. For the six months ended June 30, 2016, transportation costs were $1.97/boe, down from $2.12/boe for the same period of 2015. The per-unit decrease in costs in 2016 is primarily due to lower unutilized transportation fees on take-or-pay agreements for NGL production and a reduction in oil and NGL trucking costs as a result of better trucking rates, transporting shorter distances and fewer pipeline disruptions in the period.

GENERAL & ADMINISTRATIVE EXPENSES ("G&A")

			Three Months Ended June 30,					Six Months Ended June 30,
(000s) except per unit amounts	2016		2015		Change	2016		2015		Change
G&A expenses	$	14,858	$	14,264	4%	$	29,663	$	28,327	5%
Administrative and capital recovery	(819)		(2,244)		(64)%	(1,962)		(4,775)		(59)%
Capitalized G&A	(6,034)		(6,007)		−%	(12,155)		(11,321)		7%
Total G&A expenses	$	8,005	$	6,013	33%	$	15,546	$	12,231	27%
Per boe	$	0.47	$	0.46	2%	$	0.45	$	0.47	(4)%

The slight increase in gross G&A expenses in the second quarter of 2016 compared to the same period of 2015 is primarily due to staff additions needed to manage the larger production, reserve and land base. G&A expenses for the second quarter of 2016 were $8.0 million compared to $6.0 million for the same quarter of the prior year. G&A expenses for the six-month period ended June 30, 2016 were $15.5 million compared to $12.2 million for the same period in 2015. The decrease in administrative and capital recoveries in 2016 compared to 2015 can be attributed to lower recoveries received from partners due to a reduction in the Company's capital exploration and production activities.

On a per-boe basis, G&A expenses for the second quarter of 2016 were consistent with the prior year. For the six months ended June 30, 2016, G&A expenses were $0.45/boe, down from $0.47/boe in the prior year. The decrease per boe reflects Tourmaline's growing production base which continues to increase at a faster rate than total G&A costs.

G&A costs for 2016 are expected to average approximately $0.50/boe which is unchanged from the initial guidance released March 7, 2016. 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 June 30,				Six Months Ended June 30,
(000s) except per unit amounts	2016		2015		2016		2015
Share-based payments	$	12,196	$	16,240	$	24,614	$	32,848
Capitalized share-based payments	(6,098)		(8,120)		(12,307)		(16,424)
Total share-based payments	$	6,098	$	8,120	$	12,307	$	16,424
Per boe	$	0.36	$	0.62	$	0.35	$	0.63

The Company uses the fair value method for the determination of non-cash related share-based payments expense. During the second quarter of 2016, 80,300 stock options were granted to employees, officers, directors and key consultants at a weighted-average exercise price of $29.59 and 968,999 options were exercised, resulting in $28.2 million of cash proceeds. There were also 58,334 stock options forfeited.

The Company recognized $6.1 million of share-based payments expense in the second quarter of 2016 compared to $8.1 million in the second quarter of 2015. Capitalized share-based payments for the second quarter of 2016 were $6.1 million compared to $8.1 million for the same period of the prior year.

For the six months ended June 30, 2016, share-based payment expense totalled $12.3 million and a further $12.3 million in share-based payments were capitalized (six months ended June 30, 2015 - $16.4 million and $16.4 million, respectively).

Share-based payments are lower in 2016 compared to the same period of 2015, reflecting a lower option value which corresponds to the decrease in share price over the past two years.

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

	Three Months Ended June 30,				Six Months Ended June 30,
(000s) except per unit amounts	2016		2015		2016		2015
Total depletion, depreciation and amortization	$	168,386	$	177,645	$	349,325	$	345,333
Less mineral lease expiries	(959)		(21,855)		(6,880)		(36,434)
Depletion, depreciation and amortization	$	167,427	$	155,790	$	342,445	$	308,899
Per boe	$	9.90	$	11.92	$	9.86	$	11.88

DD&A expense, excluding mineral lease expiries, was $167.4 million for the second quarter of 2016 compared to $155.8 million for the same period of 2015. For the six-month period ended June 30, 2016, DD&A expense (excluding mineral lease expiries) was $342.4 compared to $308.9 million in the same period of 2015. The increase in DD&A expense in 2016 over 2015 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 $9.90/boe for the second quarter of 2016 compared to the rate of $11.92/boe for the same quarter of 2015. The per-unit DD&A rate (excluding the impact of mineral lease expiries) was $9.86/boe for the six-month period ended June 30, 2016 compared to the rate of $11.88/boe in the same period of the prior year.

The decrease in per-boe depletion in 2016 can be attributed to lower future development costs as drilling and completion costs have decreased over the past year thereby adding a higher proportion of reserves with lower associated future development costs, resulting in a lower depletion rate.

Mineral lease expiries for the three months ended June 30, 2016 were $1.0 million, compared to expiries in the same quarter of the prior year of $21.9 million. For the six months ended June 30, 2016, expiries were $6.9 million compared with $36.4 million for the same period in 2015. 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. The Company explores all alternatives (including swaps, farm-outs and dispositions) to realize the value from these sections before they expire.

FINANCE EXPENSES

	Three Months Ended June 30,							Six Months Ended June 30,
(000s)	2016		2015		Change	2016		2015		Change
Interest expense	$	9,890	$	9,777	1%	$	20,749	$	17,984	15%
Accretion expense	713		699		2%	1,503		1,250		20%
Foreign exchange loss on U.S. denominated debt	10,483		−		100%	83,242		−		100%
Realized (gain) on cross-currency swaps	(10,483)		−		(100)%	(83,242)		−		(100)%
Realized loss on interest rate swaps	843		669		26%	1,743		1,275		37%
Transaction costs on corporate and property acquisitions	36		500		(93)%	214		1,025		(79)%
Total finance expenses	$	11,482	$	11,645	(1)%	$	24,209	$	21,534	12%

Finance expenses for the three and six months ended June 30, 2016 totaled $11.5 million and $24.2 million compared to $11.6 million and $21.5 million, respectively, for the same periods of 2015. The finance expenses in the first six months of 2016 compared 2015 include increased interest expense attributed to a higher average bank debt outstanding, partially offset by a lower average effective interest rate. The average bank debt outstanding and the average effective interest rate on the debt for the six months ended June 30, 2016 was $1,493.0 million and 2.45%, respectively (six months ended June 30, 2015 – $1,173.3 million and 2.72% respectively).

For the six months ended June 30, 2016, the Company drew from the credit facility in U.S. dollars, as permitted under the credit facility, which when repaid created a foreign exchange loss. Concurrent with the draw of U.S. dollar denominated borrowings, the Company entered into cross-currency swaps to manage the foreign currency risk resulting from holding U.S. dollar denominated borrowings. The Company fixed the Canadian dollar amount for purposes of principal and interest repayment resulting in a gain on cross-currency swaps equivalent to the realized foreign exchange loss. This transaction allows the Company to take advantage of the interest rate spread between CDOR and LIBOR (for U.S. borrowings) without taking on foreign exchange risk.

DEFERRED INCOME TAXES (RECOVERY)

For the three months ended June 30, 2016, the provision for deferred income tax recovery was $23.8 million compared to a deferred income tax expense of $40.9 million for the same period of 2015. The recovery is primarily due to the second quarter of 2016 pre-tax loss of $102.1 million. The deferred income tax expense in the second quarter of 2015 reflects an increase in the Alberta corporate tax rate from 10% to 12% which was introduced by the Government in June 2015.

For the six months ended June 30, 2016, the provision for deferred income tax recovery was $36.8 million compared to deferred income tax expense of $51.3 million for the same period in 2015. The recovery is primarily due to the pre-tax loss recorded for the six months ended June 30, 2016 compared to pre-tax income in 2015.

CASH FLOW FROM OPERATING ACTIVITIES, CASH FLOW AND NET EARNINGS (LOSS)

		Three Months Ended June 30,					Six Months Ended June 30,
(000s) except per unit amounts		2016		2015		Change	2016		2015		Change
Cash flow from operating activities		$	143,392	$	151,028	(5)%	$	319,700	$	345,398	(7)%
	Per share ⁽¹⁾	$	0.62	$	0.71	(13)%	$	1.41	$	1.65	(15)%
Cash flow ⁽²⁾		$	134,298	$	203,029	(34)%	$	293,728	$	410,769	(28)%
	Per share ⁽¹⁾⁽²⁾	$	0.58	$	0.95	(39)%	$	1.29	$	1.96	(34)%
Net earnings (loss)		$	(77,940)	$	(5,197)	1,400%	$	(116,330)	$	16,962	(786)%
	Per share ⁽¹⁾	$	(0.34)	$	(0.02)	1,600%	$	(0.51)	$	0.08	(738)%
Operating netback per boe ⁽²⁾		$	8.63	$	16.37	(47)%	$	9.18	$	16.53	(44)%

(1)

Per share amounts have been calculated using the weighted average number of diluted common shares except the net earnings (loss) per share amounts in periods which Tourmaline has reported a net loss. In these periods, the weighted average number of basic common shares has been used as there is an anti-dilutive impact on per-share calculations. For the three and six months ended June 30, 2016, the weighted average number of common shares – diluted would be 232,709,594 and 227,064,847 excluding the anti-dilutive impact (213,708,478 – for the three months ended June 30, 2015).

(2)

See "Non-GAAP Financial Measures".

Cash flow for the three months ended June 30, 2016 was $134.3 million or $0.58 per diluted share compared to $203.0 million or $0.95 per diluted share for the same period of 2015. Cash flow for the six months ended June 30, 2016 was $293.7 million or $1.29 per share compared to $410.8 million or $1.96 per diluted share for the same period of 2015.

The Company had an after-tax net loss for the three months ended June 30, 2016 of $77.9 million or $0.34 per share compared to an after-tax net loss of $5.2 million or $0.02 per share for the same period of 2015. For the six-month period ended June 30, 2016, the after-tax net loss was $116.3 million or $0.51 per share compared to net earnings of $17.0 million or $0.08 per diluted share for the first half of 2015. The decrease in both cash flow and after-tax net earnings (loss) in 2016 reflects significantly lower realized oil, natural gas and NGL prices, partially offset by an increase in production over 2015. Net earnings (loss) for the three and six months ended June 30, 2016 have also been significantly impacted by unrealized losses on financial instruments of $64.1 million and $92.7 million, respectively, compared to losses of $16.3 million and $16.7 million, respectively, from the same periods of the prior year. These unrealized losses are primarily related to future calls on oil and natural gas that are currently above strip pricing. By entering into these future calls the Company has been able to realize a higher premium on physical commodity contracts in the current year.

CAPITAL EXPENDITURES

	Three Months Ended June 30,				Six Months Ended June 30,
(000s)	2016		2015		2016		2015
Land and seismic	$	5,904	$	3,845	$	8,256	$	28,899
Drilling and completions	13,802		108,985		164,445		386,267
Facilities	18,017		85,034		108,856		269,662
Property acquisitions	5,107		85,871		187,815		90,386
Property dispositions	−		−		(18,000)		(519)
Other	6,180		6,894		12,495		13,316
Total cash capital expenditures	$	49,010	$	290,629	$	463,867	$	788,011

During the second quarter of 2016, the Company invested $49.0 million of cash consideration, net of dispositions, compared to $290.6 million for the same period of 2015. Expenditures on exploration and production were $37.7 million compared to $197.9 million for the same quarter of 2015. During the six-month period ended June 30, 2016, the Company invested $463.9 million of cash consideration, net of dispositions, compared to $788.0 million for the same period in 2015.

The drilling and completion costs of $164.4 million in 2016 include 79.11 net wells drilled and completed compared to $386.3 million spent on 120.96 net wells drilling and completed in 2015. The lower costs per well reflect the Company's continuously improving operating practices, combined with reduced drilling and completion service costs.

Facilities expenditures include work on the new Brazeau Gas Plant commissioned in the first quarter of 2016, and progress payments on the new Doe Gas Plant and the Mulligan marketing terminal, both of which are to be commissioned in late 2016 or early 2017.

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

	Six Months Ended June 30, 2016		Six Months Ended June 30, 2015
	Gross	Net	Gross	Net
Drilled	34	32.28	66	55.74
Completed ⁽¹⁾	51	46.83	75	65.22
Tied-in ⁽¹⁾	12	9.85	36	29.54

(1) A multi-well pad is included as a single completion and tie-in.

Exploration and production capital expenditures in 2016 are now forecast to be $775.0 million (including the acquisition and divestiture activity in the first quarter of 2016) which is $50.0 million higher than the previous guidance of $725.0 million disclosed in the Company's MD&A dated May 7, 2016. The Company expects drilling and completions costs of approximately $425.0 million, facilities expenditures (including equipment, pipelines and tie-ins) of $175.0 million as well as land and seismic expenditures of $10.0 million. The capital budget is closely monitored and will continue to be adjusted as required depending on cash flow available.

Acquisitions and Dispositions

2016

On January 29, 2016, the Company acquired assets in the Minehead-Edson-Ansell area of the Alberta Deep Basin for cash consideration of $183.0 million, before customary adjustments. The acquisition resulted in an increase in Property, Plant and Equipment ("PP&E") of approximately $179.2 million, an increase in Exploration and Evaluation ("E&E") assets of $4.8 million, and the assumption of $1.0 million in decommissioning liabilities. The assets acquired included land interests, production, reserves and facilities in the area.

On March 1, 2016, the Company sold non-core assets for cash consideration of $18.0 million, before customary adjustments.

2015

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

On April 5, 2016, the Company issued 10,387,500 common shares at a price of $27.11 per share for total gross proceeds of $281.6 million (net proceeds - $269.9 million). The proceeds were used to temporarily reduce bank debt which then will be redrawn, to fund the Company's 2016 exploration and development program and future potential acquisition opportunities.

On May 17, 2016, the Company issued 1,320,000 flow-through common shares at a price of $35.50 per share, for total consideration of $46.9 million. The proceeds were used to temporarily reduce bank debt and then to fund the Company's 2016 exploration and development program.

The Company has a covenant-based, unsecured, bank credit facility in place with a syndicate of bankers in the amount of $1,800.0 million. In June 2016, the Company extended the term of the facility from three to four years resulting in a maturity of June 2020. In addition, the maximum ratio of senior debt to adjusted EBITDA was increased from 3.0 to 3.75 times and the maximum ratio of senior debt to total capitalization has increased from 0.5 to 0.55 times, respectively. The maturity date may, at the request of the Company and with consent of the lenders, be extended on an annual basis. The credit facility includes an expansion feature ("accordion") which allows the Company, upon approval from the lenders, to increase the facility amount by up to $500.0 million by adding a new financial institution or by increasing the commitment of its existing lenders. With the exception of the increase in length of term and the changes to the financial covenants, 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, 2015. 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 3.90% depending on the type of borrowing and the Company's senior debt to adjusted EBITDA ratio.

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

The Company's aggregate borrowing base capacity is $2.1 billion.

As at June 30, 2016, the Company had negative working capital of $43.8 million, after adjusting for the fair value of financial instruments (the unadjusted working capital deficiency was $60.6 million) (December 31, 2015 – $283.8 million and $247.4 million, respectively). As at June 30, 2016, the Company had $248.7 million in long-term debt outstanding and $1,081.4 million drawn against the revolving credit facility for total bank debt of $1,330.1 million (net of prepaid interest and debt issue costs) (December 31, 2015 - $1,266.6 million). Net debt at June 30, 2016 was $1,373.8 million compared to $1,550.4 million at December 31, 2015. The significant reduction in net debt can primarily be attributed to the April and May financings partially offset by property acquisitions during the first half of 2016. As at June 30, 2016, the Company is in compliance with all debt covenant calculations.

For 2016, Management intends on matching the capital budget to expected cash flow and as such Management believes the Company has sufficient resources to fund its 2016 exploration and development programs. For the first half of 2016, E&P spending, along with capitalized G&A, was $294.1 million consistent with cash flow for the same period of $293.7 million. As at June 30, 2016, the Company had $759.3 million in unutilized borrowing capacity. The 2016 exploration and development program will be continuously and diligently monitored throughout the year and will be adjusted as necessary depending on commodity price outlooks in order to remain consistent with cash flow. Management is dedicated to keeping a strong balance sheet, which has proven to be very important, especially in times of significantly depressed commodity prices.

SHARES AND STOCK OPTIONS OUTSTANDING

As at August 3, 2016, the Company has 234,380,292 common shares outstanding and 18,498,179 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	$	5,553	$	11,033	$	4,048	$	-	$	20,634
Firm transportation and processing agreements	188,461		416,266		372,289		962,627		1,939,643
Capital commitments ⁽¹⁾	310,044		600,750		290,000		-		1,200,794
Flow-through share commitments	8,476		46,860		-		-		55,336
Credit facility ⁽²⁾	-		-		1,221,154		-		1,221,154
Term debt ⁽³⁾	7,711		15,422		260,756		-		283,889
Interest rate swaps	3,235		6,235		1,500		-		10,970
	$	523,480	$	1,096,566	$	2,149,747	$	962,627	$	4,732,420


(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. Since December 31, 2015, an economic downturn event, as defined in the joint arrangement in the Spirit River complex has existed and as such capital spending for 2016 may be reduced and extended to future years.
(2)	Includes interest expense at an annual rate of 2.96% being the rate applicable to outstanding debt on the credit facility at June 30, 2016.
(3)	Includes interest expense at an annual rate of 3.09% being the fixed rate on the term debt at June 30, 2016.

OFF BALANCE SHEET ARRANGEMENTS

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

FINANCIAL RISK MANAGEMENT

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

The Company's risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company's activities. The Company's financial risks are discussed in note 5 of the Company's audited consolidated financial statements for the year ended December 31, 2015.

As at June 30, 2016, 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 June 30, 2016 are summarized and disclosed in note 3 of the Company's unaudited interim condensed consolidated financial statements for the three and six months ended June 30, 2016 and 2015.

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 June 30, 2016 have been summarized and disclosed in note 3 of the Company's unaudited interim condensed consolidated financial statements for the three and six months ended June 30, 2016 and 2015.

Financial derivative and physical delivery contracts entered into subsequent to June 30, 2016 are detailed in note 3 of the Company's unaudited interim condensed consolidated financial statements for the three and six months ended June 30, 2016 and 2015.

APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Management reviews its estimates on a regular basis. The emergence of new information and changed circumstances may result in actual results or changes to estimates that differ materially from current estimates. The Company's use of estimates and judgments in preparing the interim condensed consolidated financial statements is discussed in note 1 of the consolidated financial statements for the year ended December 31, 2015.

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING

The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures ("DC&P"), as defined by National Instrument 52-109. 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 April 1, 2016 and ending on June 30, 2016 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.

The Company uses the guidelines as set in the Committee of Sponsoring Organizations of the Treadway Commission 2013 Internal Control-Integrated Framework.

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 June 30,				Six Months Ended June 30,
(000s)	2016		2015		2016		2015
Cash flow from operating activities (per GAAP)	$	143,392	$	151,028	$	319,700	$	345,398
Change in non-cash working capital	(9,094)		52,001		(25,972)		65,371
Cash flow	$	134,298	$	203,029	$	293,728	$	410,769

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 June 30,				Six Months Ended June 30,
($/boe)	2016		2015		2016		2015
Revenue, excluding processing income	$	14.61	$	22.85	$	15.15	$	23.84
Royalties	(0.51)		(0.38)		(0.44)		(0.79)
Transportation costs	(2.06)		(2.00)		(1.97)		(2.12)
Operating expenses	(3.41)		(4.10)		(3.56)		(4.40)
Operating netback ⁽¹⁾	$	8.63	$	16.37	$	9.18	$	16.53
(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 June 30, 2016		As at December 31, 2015
Working capital (deficit)	$	(60,567)	$	(247,391)
Fair value of financial instruments – short-term (net)	16,812		(36,392)
Working capital (deficit) (adjusted for the fair value of financial instruments)	$	(43,755)	$	(283,783)

Net Debt

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

(000s)	As at June 30, 2016		As at December 31, 2015
Bank debt	$	(1,330,094)	$	(1,266,604)
Working capital (deficit)	(60,567)		(247,391)
Fair value of financial instruments – short-term (net)	16,812		(36,392)
Net debt	$	(1,373,849)	$	(1,550,387)

SELECTED QUARTERLY INFORMATION

			2016				2015		2014
($000s, unless otherwise noted)		Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
PRODUCTION
Natural gas (mcf)		89,091,644	94,075,078	85,328,135	72,395,759	69,606,629	67,548,751	63,719,524	51,771,964
Oil and NGL(bbls)		2,060,260	2,141,099	2,302,708	1,761,403	1,469,591	1,677,123	1,426,951	1,307,089
Oil equivalent (boe)		16,908,867	17,820,279	16,524,064	13,827,363	13,070,696	12,935,248	12,046,872	9,935,749
Natural gas (mcf/d)		979,029	1,033,792	927,480	786,910	764,908	750,542	692,604	562,739
Oil and NGL (bbls/d)		22,640	23,529	25,030	19,146	16,149	18,635	15,510	14,207
Oil equivalent (boe/d)		185,812	195,828	179,610	150,297	143,634	143,725	130,944	107,997
FINANCIAL
Revenue, net of royalties		181,671	250,377	350,629	333,704	283,731	313,440	351,939	311,586
Cash flow from operating activities		143,392	176,308	228,959	261,398	151,028	194,370	201,188	233,047
Cash flow ⁽¹⁾		134,298	159,430	242,351	197,100	203,029	207,740	233,238	211,635
	Per diluted share	0.58	0.72	1.10	0.90	0.95	1.01	1.14	1.03
Net earnings (loss)		(77,940)	(38,390)	34,636	28,489	(5,197)	22,159	265,210	67,357
	Per basic share	(0.34)	(0.17)	0.16	0.13	(0.02)	0.11	1.31	0.33
	Per diluted share	(0.34)	(0.17)	0.16	0.13	(0.02)	0.11	1.29	0.33
Total assets		7,694,141	7,844,728	7,640,671	7,471,042	7,071,801	6,801,583	6,622,303	5,978,645
Working capital (deficit)		(60,567)	(201,588)	(247,391)	(297,698)	(70,156)	(195,907)	(189,928)	(493,160)
Working capital (deficit) (adjusted for the fair value of financial instruments) ⁽¹⁾		(43,755)	(227,133)	(283,783)	(339,177)	(86,090)	(232,572)	(223,655)	(495,222)
Cash capital expenditures		49,010	414,857	325,499	422,629	290,629	497,382	152,135	647,302
Total outstanding shares (000s)		234,161	221,484	221,336	220,813	216,378	204,284	203,162	201,673
PER UNIT
Natural gas ($/mcf)		1.87	2.20	2.99	3.20	3.17	3.69	4.09	4.34
Oil and NGL ($/bbl)		38.94	33.60	47.65	45.91	53.34	43.13	55.91	74.61
Revenue ($/boe)		14.61	15.66	22.08	22.61	22.85	24.84	28.25	32.41
Operating netback ($/boe) ⁽¹⁾		8.63	9.71	15.22	15.06	16.37	16.70	20.23	22.19

(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 production growth over the last two years summarized in the table above. The Company's average annual production has increased from 112,929 boe per day in 2014 to 154,403 boe per day in 2015 and 190,820 boe per day in the first six months of 2016. 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 $929.0 million in 2014, $850.2 million in 2015, and 2016 forecast cash flow is $762.1 million. The decrease in cash flow year-over-year continues to reflect the significant declines in commodity prices over the same periods. 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

		June 30,		December 31,
(000s) (unaudited)		2016		2015
Assets
Current assets:
	Accounts receivable	$	113,066	$	175,624
	Prepaid expenses and deposits	16,811		14,769
	Fair value of financial instruments (note 3)	1,559		39,677
Total current assets		131,436		230,070
Long-term asset		6,362		6,688
Exploration and evaluation assets (note 4)		626,890		620,142
Property, plant and equipment (note 5)		6,929,453		6,783,771
Total Assets		$	7,694,141	$	7,640,671
Liabilities and Shareholders' Equity
Current liabilities:
	Accounts payable and accrued liabilities	$	173,632	$	474,176
	Fair value of financial instruments (note 3)	18,371		3,285
Total current liabilities		192,003		477,461
Bank debt (note 7)		1,330,094		1,266,604
Fair value of financial instruments (note 3)		49,210		9,701
Deferred premium on flow-through shares (note 9)		10,967		5,982
Decommissioning obligations (note 6)		182,293		163,459
Deferred taxes		449,528		485,888
Shareholders' equity:
	Share capital (note 9)	4,619,339		4,266,234
	Non-controlling interest (note 8)	27,349		28,431
	Contributed surplus	184,735		171,958
	Retained earnings	648,623		764,953
Total shareholders' equity		5,480,046		5,231,576
Total Liabilities and Shareholders' Equity		$	7,694,141	$	7,640,671

Commitments (note 12).

Subsequent events (note 3).

See accompanying notes to the interim condensed consolidated financial statements.

CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

		Three Months Ended June 30,				Six Months Ended June 30,
(000s) except per-share amounts (unaudited)		2016		2015		2016			2015
Revenue:
	Oil and natural gas sales	$	205,994	$	263,974	$	439,538		$	514,780
	Royalties	(8,551)		(4,944)		(15,120)			(20,531)
	Net revenue from oil and natural gas sales	197,443		259,030		424,418			494,249
	Realized gain on financial instruments	41,129		34,722		86,693			105,219
	Unrealized (loss) on financial instruments (note 3)	(64,070)		(16,251)		(92,713)			(16,678)
	Other income	7,169		6,230		13,650			14,381
Total net revenue		181,671		283,731		432,048			597,171
Expenses:
	Operating	57,630		53,647		123,520			114,338
	Transportation	34,786		26,100		68,411			55,126
	General and administration	8,005		6,013		15,546			12,231
	Share-based payments (note 11)	6,098		8,120		12,307			16,424
	(Gain) on divestitures	(2,621)		(35,053)		(7,074)			(35,232)
	Depletion, depreciation and amortization	168,386		177,645		349,325			345,333
Total expenses		272,284		236,472		562,035			508,220
Income (loss) from operations		(90,613)		47,259		(129,987)			88,951
Finance expenses		11,482		11,645		24,209			21,534
Income (loss) before taxes		(102,095)		35,614		(154,196)			67,417
Deferred taxes (recovery)		(23,841)		40,927		(36,784)			51,263
Net income (loss) and comprehensive income (loss) before non-controlling interest		(78,254)		(5,313)		(117,412)			16,154
Net income (loss) and comprehensive income (loss) attributable to:
	Shareholders of the Company	(77,940)		(5,197)		(116,330)			16,962
	Non-controlling interest (note 8)	(314)		(116)		(1,082)			(808)
		$	(78,254)	$	(5,313)	$		(117,412)	$	16,154
Net income (loss) per share attributable to common shareholders (note 10)
	Basic	$	(0.34)	$	(0.02)	$		(0.51)	$	0.08
	Diluted	$	(0.34)	$	(0.02)	$		(0.51)	$	0.08
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, 2015	$	4,266,234	$	171,958	$	764,953	$	28,431	$	5,231,576
Issue of common shares (note 9)	319,423		-		-		-		319,423
Share issue costs, net of tax (note 9)	(10,009)		-		-		-		(10,009)
Share-based payments	-		12,307		-		-		12,307
Capitalized share-based payments	-		12,307		-		-		12,307
Options exercised (note 9)	43,691		(11,837)		-		-		31,854
Loss attributable to common shareholders	-		-		(116,330)		-		(116,330)
Loss attributable to non-controlling interest	-		-		-		(1,082)		(1,082)
Balance at June 30, 2016	$	4,619,339	$	184,735	$	648,623	$	27,349	$	5,480,046

(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)	258,660		-		-		-		258,660
Share issue costs, net of tax	(6,559)		-		-				(6,559)
Share-based payments	-		16,424		-		-		16,424
Capitalized share-based payments	-		16,424		-		-		16,424
Options exercised (note 9)	24,790		(6,750)		-		-		18,040
Income attributable to common shareholders	-		-		16,962		-		16,962
Loss attributable to non-controlling interest	-		-		-		(808)		(808)
Balance at June 30, 2015	$	4,113,377	$	150,423	$	701,828	$	29,198	$	4,994,826
See accompanying notes to the interim condensed consolidated financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOW

			Three Months Ended June 30,				Six Months Ended June 30,
(000s) (unaudited)			2016		2015		2016		2015
Cash provided by (used in):
Operations:
Net income (loss)			$	(77,940)	$	(5,197)	$	(116,330)	$	16,962
Items not involving cash:
		Depletion, depreciation and amortization	168,386		177,645		349,325		345,333
		Accretion	713		699		1,503		1,250
		Share-based payments	6,098		8,120		12,307		16,424
		Deferred taxes (recovery)	(23,841)		40,927		(36,784)		51,263
		Unrealized loss on financial instruments	64,070		16,251		92,713		16,678
		(Gain) on divestitures	(2,621)		(35,053)		(7,074)		(35,232)
		Amortization on long-term asset	163		-		326		-
		Non-controlling interest	(314)		(116)		(1,082)		(808)
	Decommissioning expenditures		(416)		(247)		(1,176)		(1,101)
	Changes in non-cash operating working capital		9,094		(52,001)		25,972		(65,371)
Total cash flow from operating activities			143,392		151,028		319,700		345,398
Financing:
	Issue of common shares		356,626		203,840		360,319		245,466
	Share issue costs		(13,533)		(8,182)		(13,642)		(9,383)
	Increase/(Decrease) in bank debt		(245,003)		38,359		63,490		278,593
Total cash flow from financing activities			98,090		234,017		410,167		514,676
Investing:
	Exploration and evaluation		(9,370)		(24,974)		(14,004)		(68,049)
	Property, plant and equipment		(34,533)		(179,784)		(280,048)		(630,095)
	Property acquisitions		(5,107)		(85,871)		(187,815)		(90,386)
	Proceeds from divestitures		-		-		18,000		519
	Net repayment of long-term obligation		-		(866)		-		(1,731)
	Changes in non-cash investing working capital		(192,472)		(201,171)		(266,000)		(333,384)
Total cash flow used in investing activities			(241,482)		(492,666)		(729,867)		(1,123,126)
Changes in cash			-		(107,621)		-		(263,052)
Cash, beginning of period			-		107,621		-		(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 JUNE 30, 2016 AND FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2016 AND 2015

(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, 2015.

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, 2015, except as noted below.

On January 1, 2016, the Company adopted the amendments made to IFRS 11 – Joint Arrangements, which provided new guidance on the accounting for the acquisition of an interest in a joint operation that constitutes a business. There was no impact on the Company as a result of adopting the amended standard.

The unaudited interim condensed consolidated financial statements were authorized for issue by the Board of Directors on August 3, 2016.

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 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, 2015.

As at June 30, 2016, the Company has entered into certain financial derivative contracts in order to manage commodity price, foreign exchange 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 (loss) and comprehensive income (loss).

The Company has the following financial derivative contracts in place as at June 30, 2016⁽¹⁾:

(000s)		2016		2017		2018		2019		2020		Fair Value
Gas
Financial swaps	mmbtu/d	125,217		–		–		–		–		$	(2,033)
	USD$/mmbtu	$	2.90
NYMEX call options (writer)⁽²⁾	mmbtu/d	–		110,000		110,000		90,000		20,000		$	(33,433)
	USD$/mmbtu			$	3.77	$	3.77	$	3.94	$	3.75
Oil
Financial swaps	bbls/d	3,500		3,000		–		–		–		$	(4,471)
	USD$/bbl	$	49.28	$	49.63
Financial call swaptions ⁽³⁾	bbls/d	400		4,000		2,125		–		–		$	(15,103)
	USD$/bbl	$	80.10	$	62.45	$	52.18
Total Fair Value												$	(55,040)

(1)	The volumes and prices reported are the weighted-average volumes and prices for the period.
(2)	These are European calls whereby the counterparty can exercise the option monthly on a particular day to purchase NYMEX at a specified price.
(3)	These are European and Asian swaptions whereby the Company provides the option to extend an oil swap into the period subsequent to the call date, or retroactively fix the price on the volumes under the contract.

No financial derivative contracts were entered into subsequent to June 30, 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
Apr 5, 2016 – Apr 5, 2019	Swap	$	50,000	0.867%	Floating Rate	$	(29)
Nov 28, 2014 – Nov 28, 2019	Swap	$	250,000	2.065%	Floating Rate	$	(10,282)
June 6, 2016 – June 6, 2020	Swap	$	50,000	1.025%	Floating Rate	$	(311)
Apr 5, 2016 – Apr 5, 2021	Swap	$	50,000	0.988%	Floating Rate	$	(294)
June 13, 2016 – June 13, 2021	Swap	$	25,000	0.973%	Floating Rate	$	(66)
Total Fair Value						$	(10,982)

The following table provides a summary of the unrealized gains (losses) on financial instruments recorded in the consolidated statements of income (loss) and comprehensive income (loss) for the three and six months ended June 30, 2016 and 2015:

	Three Months Ended June 30,				Six Months Ended June 30,
(000s)	2016		2015		2016		2015
Unrealized (loss) on financial instruments – commodity contracts	$	(64,346)	$	(17,685)	$	(92,109)	$	(11,141)
Unrealized gain/(loss) on financial instruments – interest rate swaps	276		1,434		(604)		(5,537)
Total unrealized (loss) on financial instruments	$	(64,070)	$	(16,251)	$	(92,713)	$	(16,678)

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 June 30, 2016⁽¹⁾⁽⁷⁾:

		2016		2017		2018		2019		2020
Gas
Fixed price – AECO	mcf/d	295,595		55,776		–		–		–
	CAD$/mcf	$	2.33	$	2.44	–		–		–
Basis differentials ⁽²⁾⁽³⁾	mmbtu/d	194,293		72,500		32,500		32,500		32,500
	USD$/mmbtu	$	(0.52)	$	(0.60)	$	(0.54)	$	(0.54)	$	(0.54)
Basis differentials – Stn 2 ⁽⁴⁾	mcf/d	52,151		37,928		37,928		9,482		9,482
	CAD$/mcf	$	(0.33)	$	(0.29)	$	(0.29)	$	(0.26)	$	(0.26)
AECO monthly calls / call swaptions ⁽⁵⁾	mcf/d	10,430		75,857		71,116		–		–
	CAD$/mcf	$	5.56	$	4.60	$	4.25		–	–
Oil
Fixed differential ⁽⁶⁾	bbls/d	2,328		962		–		–		–
	USD$/bbl	$	(6.78)	$	(6.84)	–		–		–

(1)	The volumes and prices reported are the weighted-average volumes and prices for the period.
(2)	Tourmaline also has 21.1 mmcf/d of NYMEX-AECO basis differentials at $(0.53) from 2021-2023.
(3)	Tourmaline also has 10,000 mmbtu/d SoCal – AECO basis differential at $(0.73) until October 2016.
(4)	Tourmaline also has 9,482 mcf/d of Stn 2. basis differentials at $(0.26) for 2021.
(5)	These are monthly calls for 2016 and in 2017-2018 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 sells physical crude at a fixed differential to NYMEX.
(7)	Tourmaline also has entered into deals to sell 30,000 mmbtu/d at Chicago GDD pricing less transportation costs from April 2015 to October 2020; 20,000 mmbtu/d at Chicago GDD pricing less transportation costs from April 2015 to March 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 June 30, 2016:

Type of Contract	Quantity	Time Period	Contract Price
Gas Fixed price – AECO	10,000 GJs/d	November 2016 – March 2017	CAD$3.00/GJ

4. EXPLORATION AND EVALUATION ASSETS

(000s)
As at December 31, 2015		$	620,142
	Capital expenditures	14,004
	Transfers to property, plant and equipment (note 5)	(7,632)
	Acquisitions	7,691
	Divestitures	(435)
	Expired mineral leases	(6,880)
As at June 30, 2016		$	626,890

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 June 30, 2016 and December 31, 2015, 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, 2015		$	8,685,985
	Capital expenditures	292,355
	Transfers from exploration and evaluation (note 4)	7,632
	Change in decommissioning liabilities (note 6)	18,327
	Acquisitions	189,445
	Divestitures	(19,918)
As at June 30, 2016		$	9,173,826

Accumulated Depletion, Depreciation and Amortization

(000s)
As at December 31, 2015		$	1,902,214
	Depletion, depreciation and amortization	342,445
	Divestitures	(286)
As at June 30, 2016		$	2,244,373

Net Book Value

(000s)
As at December 31, 2015	$	6,783,771
As at June 30, 2016	$	6,929,453

Future development costs of $4,816.4 million were included in the depletion calculation at June 30, 2016 (December 31, 2015 – $4,523.1 million).

Capitalization of G&A and Share-Based Payments

A total of $12.2 million in G&A expenditures have been capitalized and included in E&E and PP&E assets at June 30, 2016 (December 31, 2015 – $22.9 million). Also included in E&E and PP&E are non-cash share-based payments of $12.3 million (December 31, 2015 - $30.8 million).

Impairment Assessment

In accordance with IFRS, an impairment test is performed on a Cash Generating Unit ("CGU") if the Company identifies an indicator of impairment. At June 30, 2016, the Company determined that there were no indicators of impairment on any of the Company's CGUs; therefore an impairment test was not performed.

For the year ended December 31, 2015, the Company identified indicators of impairment on all of its CGUs due to the decline in current and forward commodity prices for oil and natural gas and performed impairment tests accordingly. The Company determined that there was no impairment to PP&E at December 31, 2015.

Business Combinations

Minehead-Edson-Ansell

On January 29, 2016, the Company acquired assets in the Minehead-Edson-Ansell area of the Alberta Deep Basin for cash consideration of $183.0 million before customary adjustments. The acquisition resulted in an increase in lands, production, reserves and facilities in a core area of the Alberta Deep Basin.

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)		Minehead-Edson-Ansell
Fair value of net assets acquired:
	Property, plant and equipment		$	179,230
	Exploration and evaluation		4,753
	Decommissioning obligations		(983)
Total			$	183,000
Consideration:
	Cash		$	183,000

Perpetual Energy Inc.

On April 1, 2015, the Company acquired Perpetual Energy Inc.'s ("Perpetual") interests in the West Edson area of the Alberta Deep Basin with the issuance of 6,750,000 Tourmaline shares at a price of $38.32 per share for total consideration of $258.7 million. The acquisition resulted in an increase in land, production, reserves and processing capacity along with allowing the Company to leverage operational synergies created from having full ownership of the assets.

(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 (loss) and comprehensive income (loss). 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. The acquisition of Bergen consolidated the Company's working interest in a core area of the Peace River High.

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

Results from operations for Mapan are included in the Company's 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

Acquisitions and Dispositions of Oil and Natural Gas Properties

For the six months ended June 30, 2016, the Company completed property cash acquisitions for total cash consideration of $5.1 million excluding the Minehead-Edson-Ansell acquisition (December 31, 2015 - $92.0 million). There were also $7.7 million in acquisitions involving non-cash consideration (December 31, 2015 - $73.4 million). The Company also assumed $1.6 million in decommissioning liabilities in addition to the Minehead-Edson-Ansell acquisition (December 31, 2015 - $3.0 million).

On March 1, 2016, the Company sold non-core assets for cash consideration of $18.0 million, before customary adjustments. The net book value of the oil and natural gas properties disposed was equal to the cash consideration received.

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 $231.8 million (December 31, 2015 – $224.5 million), with some abandonments expected to commence in 2021. A risk-free rate of 1.72% (December 31, 2015 – 2.15%) and an inflation rate of 1.8% (December 31, 2015 – 1.8%) were used to calculate the decommissioning obligations. The downward adjustment in the risk-free rate used to calculate decommissioning obligations resulted in the majority of the change in future estimated cash outlays.

(000s)		As at June 30, 2016		As at December 31, 2015
Balance, beginning of period		$	163,459	$	114,038
	Obligation incurred	3,325		16,780
	Obligation incurred on corporate acquisitions	−		3,516
	Obligation incurred on property acquisitions	1,585		5,484
	Obligation divested	(1,405)		(270)
	Obligation settled	(1,176)		(1,613)
	Accretion expense	1,503		2,854
	Change in estimate (cash outlays and risk-free rate)	15,002		22,670
Balance, end of period		$	182,293	$	163,459

7. BANK DEBT

The Company has a covenant-based, unsecured, revolving credit facility in place with a syndicate of banks in the amount of $1,800.0 million. In addition, the Company has a $50.0 million operating revolver, resulting in total bank credit facility capacity of $1,850.0 million. In June 2016, the Company extended the term of the facility from three to four years resulting in a maturity of June 2020. In addition, the maximum ratio of senior debt to adjusted EBITDA was increased from 3.0 to 3.75 times and the maximum ratio of senior debt to total capitalization has increased from 0.5 to 0.55 times, respectively. With the exception of the increase in length of term and the changes to the financial covenants, 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, 2015.

The credit 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 3.90% 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, the details of which are described in note 9 of the Company's consolidated financial statements for the year ended December 31, 2015. The covenants for the term loan are the same as those under the Company's current credit facility and the term loan will rank equally with the obligations under the Company's credit facility.

As at June 30, 2016, the Company had $248.7 million in long-term debt outstanding and $1,081.4 million drawn against the bank credit facility for total bank debt of $1,330.1 million (net of prepaid interest and debt issue costs) (December 31, 2015 - $1,266.6 million). In addition, Tourmaline has outstanding letters of credit of $10.6 million (December 31, 2015 - $13.4 million), which reduce the credit available on the facility. The effective interest rate for the six months ended June 30, 2016 was 2.45%. As at June 30, 2016, 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 June 30, 2016		As at December 31, 2015
Balance, beginning of period		$	28,431	$	30,006
	Share of subsidiary's net (loss) for the period	(1,082)		(1,575)
Balance, end of period		$	27,349	$	28,431

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 June 30, 2016			As at December 31, 2015
(000s) except share amounts	Number of Shares	Amount		Number of Shares	Amount
Balance, beginning of period	221,335,925	$	4,266,234	203,162,112	$	3,615,378
For cash on public offering of common shares ⁽¹⁾⁽⁴⁾	10,387,500	281,605		4,947,500	195,425
For cash on public offering of flow-through common shares ^(2)(3)(5)	1,320,000	37,818		1,122,700	38,403
Issued on corporate and property acquisitions (note 5)	-	-		10,193,026	372,878
For cash on exercise of stock options	1,117,333	31,854		1,910,587	37,159
Contributed surplus on exercise of stock options	-	11,837		-	14,051
Share issue costs	-	(13,642)		-	(10,066)
Tax effect of share issue costs	-	3,633		-	3,006
Balance, end of period	234,160,758	$	4,619,339	221,335,925	$	4,266,234

(1)	On April 5, 2016, the Company issued 10.388 million common shares at a price of 27.11 for total gross proceeds of 281.6 million. A total of 37,500 common shares were purchased by insiders.
(2)	On May 17, 2016, the Company issued 1.320 million flow-through shares at a price of $35.50 per share for total gross proceeds of $46.9 million. The implied premium on the flow-through common shares was determined to be $9.0 million or $6.85 per share. As at June 30, 2016, the Company is committed to spend the full amount on qualified exploration expenditures by December 31, 2017. The expenditures will be renounced to investors with an effective date of December 31, 2016.
(3)	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 June 30, 2016, the Company had spent the full committed amount. The expenditures were renounced to investors with an effective renunciation date of December 31, 2015.
(4)	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 54,000 common shares were purchased by insiders.
(5)	On November 25, 2015, the Company issued 0.48 million flow-through shares at a price of $34.10 per share for total gross proceeds of $16.5 million. The implied premium on flow-through common shares was determined to be $3.7 million or $7.75 per share. As at June 30, 2016, the Company is committed to spend $8.5 million on qualified exploration expenditures by December 31, 2016. The expenditures were renounced to investors with an effective renunciation date of December 31, 2015.

10. EARNINGS PER SHARE

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Net earnings (loss) for the period (000s)	$	(77,940)	$	(5,197)	$	(116,330)	$	16,962
Weighted average number of common shares – basic	232,460,854		211,693,769		226,932,309		207,649,597
Earnings (loss) per share – basic	$	(0.34)	$	(0.02)	$	(0.51)	$	0.08

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
Net earnings (loss) for the period (000s)	$	(77,940)	$	(5,197)	$	(116,330)	$	16,962
Weighted average number of common shares – diluted	232,460,854		211,693,769		226,932,309		209,560,883
Earnings (loss) per share – fully diluted	$	(0.34)	$	(0.02)	$	(0.51)	$	0.08

There were 18,672,713 options excluded from the weighted-average share calculations for the three and six month periods ended June 30, 2016 because they were anti-dilutive (three and six months ended June 30, 2015 – 17,013,364 and 10,602,666 options).

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 23,416,076 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 second, second and second anniversaries from the date of grant.

		Six Months Ended June 30,
		2016			2015
		Number of Options	Weighted Average Exercise Price		Number of Options	Weighted Average Exercise Price
Stock options outstanding, beginning of period		19,746,414	$	36.50	17,046,500	$	36.44
	Granted	205,300	28.73		878,500	39.22
	Exercised	(1,117,333)	28.51		(878,303)	20.54
	Forfeited	(161,668)	38.94		(33,333)	39.17
Stock options outstanding, end of period		18,672,713	$	36.87	17,013,364	$	37.40

The weighted average trading price of the Company's common shares was $28.02 during the six months ended June 30, 2016 (six months ended June 30, 2015 – $39.05).

The following table summarizes stock options outstanding and exercisable at June 30, 2016:

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	5,421,715	2.94	26.43	2,099,415	26.38
$30.76 - $39.57	4,171,998	2.35	34.40	2,856,331	33.53
$40.18 - $48.99	7,429,000	2.70	42.11	4,422,667	41.77
$51.47 - $56.76	1,650,000	3.02	53.85	838,333	54.23
	18,672,713	2.72	36.87	10,216,746	37.33

The fair value of options granted during the six-month period ended June 30, 2016 was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions and resulting values:

	June 30,
	2016		2015
Fair value of options granted (weighted average)	$	8.43	$	11.49
Risk-free interest rate	2.02%		2.31%
Estimated hold period prior to exercise	4 years		4 years
Expected volatility	34%		33%
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	$	5,553	$	11,033	$	4,048	$	-	$	20,634
Firm transportation and processing agreements	188,461		416,266		372,289		962,627		1,939,643
Capital commitments ⁽¹⁾	310,044		600,750		290,000		-		1,200,794
Flow-through share commitments	8,476		46,860		-		-		55,336
Credit facility ⁽²⁾	-		-		1,221,154		-		1,221,154
Term debt ⁽³⁾	7,711		15,422		260,756		-		283,889
Interest rate swaps	3,235		6,235		1,500		-		10,970
	$	523,480	$	1,096,566	$	2,149,747	$	962,627	$	4,732,420

(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. Since December 31, 2015, an economic downturn event, as defined in the joint arrangement in the Spirit River complex has existed and as such capital spending for 2016 may be reduced and extended to future years.
(2)	Includes interest expense at an annual rate of 2.96% being the rate applicable to outstanding debt on the credit facility at June 30, 2016.
(3)	Includes interest expense at an annual rate of 3.09% being the fixed rate on the term debt at June 30, 2016.

ABOUT TOURMALINE OIL CORP.

Tourmaline is a Canadian senior 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.

SOURCE Tourmaline Oil Corp.

Tourmaline Oil Corp., Michael Rose, Chairman, President and Chief Executive Officer, (403) 266-5992; Tourmaline Oil Corp., Brian Robinson, Vice President, Finance and Chief Financial Officer, (403) 767-3587, [email protected]; Tourmaline Oil Corp., Scott Kirker, Secretary and General Counsel, (403) 767-3593, [email protected]; Tourmaline Oil Corp., Suite 3700, 250 - 6th Avenue S.W., Calgary, Alberta T2P 3H7, Phone: (403) 266-5992, Facsimile: (403) 266-5952, E-mail: [email protected], Website: www.tourmalineoil.com

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