Tourmaline Oil Corp.
TSX : TOU

Tourmaline Oil Corp.

November 13, 2013 17:00 ET

Tourmaline Oil Corp. Announces Q3 2013 Financial Results-Increases 2013 Exit Production Guidance to 110,000-115,000 boepd

CALGARY, ALBERTA--(Marketwired - Nov. 13, 2013) - Tourmaline Oil Corp. (TSX:TOU) ("Tourmaline" or the "Company") is pleased to announce results for the three and nine months ended September 30, 2013 and provide an update on its 2013 EP program.

Q3 2013 Highlights

  • Record daily production of 92,000 boepd achieved in November 2013.
  • 2013 exit guidance increased by 15% to 110,000-115,000 boepd.
  • Record average production for the third quarter of 74,096 boepd, a 6% increase over the second quarter of 2013.
  • Third quarter cash flow(1) of $120.6 million, up 90% over the same period in 2012.
  • Record nine month earnings of $91.4 million.
  • Continued top-tier cost control performance with third quarter operating expenses at $4.36/boe and cash G&A of $0.68/boe.
  • Increased bank facility from $750 million to $900 million in November 2013.
  • Continued industry-leading Wilrich well results in the Alberta Deep Basin including the two-well pad at Kakwa that commenced production at 54.6 mmcfpd in November 2013.
  • The initial 3 well Montney pad at Sundown, utilizing the completion technique evolved at Sunrise-Dawson, tested at 37.1 mmcfpd.
  • The first concurrently-stimulated horizontal well pair at Spirit River, Alberta tested at a final oil rate of 2,435 bpd with 0.5 mmcfpd of gas.
  • Multiple, successful, regional Charlie Lake horizontal oil wells.

Production Update

Current production has reached an estimated 92,000 boepd including 14,500 bpd of oil and liquids. In addition, the Company has approximately 12,500 boepd of tied-in production currently shut-in awaiting expanded facility capacity, as well as a further 18,000 boepd of tested production currently being tied-in. An additional 26 wells, either drilling or being completed, will also be tied-in during the next 2.5 months.

Tourmaline is increasing its 2013 exit production guidance to between 110,000 and 115,000 boepd. Forecast 2014 average production of 118,000 boepd is currently expected to be achieved in late January or early February 2014. This represents 54% growth in average production for full year 2014 over 2013. This will also be the sixth year in a row that year-over-year production has grown by over 50%.

Third quarter production averaged 74,096 boepd, a 54% increase over the third quarter of 2012 and a 6% increase over the second quarter of 2013. Third quarter production was reduced by approximately 4,500 boepd at Spirit River due to the inability of the third party plant, currently being utilized to process associated gas volumes for the pool, to accept the full available gas volumes from Tourmaline. Both parties continue to address the matter and production levels have been steadily increasing over the past month.

Tie-in approvals from the new Alberta Energy Regulator since July 1 have been approximately 2-3 months slower than approvals during the first half of the year. This has resulted in several tie-ins being delayed until November 2013 from the originally scheduled August/September time frame which also negatively impacted third quarter volumes.

Full year 2013, average production of 76,500 boepd is now anticipated - between original 2013 guidance of 75,000 boepd and the increased guidance announced in Q2 2013 of 80,000 boepd. This represents 51% growth over 2012 average production volumes of 50,804 boepd. Tourmaline's current liquids production of 14,500 boepd has already exceeded the estimated 2013 liquids exit volume target of 13,000 boepd.

2013/2014 Financial Update

Third quarter 2013 cash flow(1) was $120.6 million, a 90% increase over third quarter 2012. Full year 2013 cash flow(1) of $540 million is now anticipated, a 93% increase over full year 2012.

Third quarter earnings were $9.2 million compared to a $4.8 million loss in the third quarter of 2012. The nine months earnings were a record $91.4 million.

Third quarter EP Capital spending was $355.0 million and the Company spent $108.8 million on a series of previously announced acquisitions during the quarter. The third quarter expenditures included $62 million on the plant expansions at Banshee and Wild River, related gathering systems and enhanced liquids extraction equipment, all scheduled to support increased Q4 2013 production levels.

Full year 2013, capital spending of $1,050 million is now anticipated. Third quarter net debt(1) pro-forma the October 8, 2013 equity financing was $503.8 million with 2013 exit net debt(1) now expected at $560 million. This represents 0.80 times annualized anticipated Q4 cash flow(1) of $175 million. A 2014 EP Capital program of $900.0 million has been approved, full year 2014 cash flow(1) is projected at $1,002 million, assuming an AECO natural gas price of $3.86/mcf and a WTI oil price of US $97.00/bbl.

The Company expanded its bank facility with its existing banking syndicate to $900.0 million in early November.

Deep Basin Update

Tourmaline currently has 10 drilling rigs operating in the Deep Basin of Alberta. Six of the rigs are drilling Cretaceous Wilrich horizontal targets at Edson, Minehead, Banshee, Smoky-Horse and Kakwa. Two rigs are pursuing Notikewin, Bluesky and Cardium horizontal targets throughout the Deep Basin complex. One rig is pursuing horizontal Wilrich in structure targets in the Lovett-Basing area and the tenth rig is pursuing 3D seismic defined multi-objective vertical opportunities along the Western margin of the asset base.

The Company continues to deliver industry leading horizontal Wilrich results with several high-deliverability wells drilled and tested during the third quarter. The most recent two-well pad at Kakwa (13-15/4-10) tested at a final combined rate of 54.6 mmcfpd with 360 bbl/day of free condensate. The most recent Edson Wilrich horizontal at 14-19, joint with Perpetual Energy Inc., tested at a final rate of 40 mmcfpd and commenced production at a restricted rate of 20 mmcfpd in October. The Minehead 8-35 horizontal tested at a final rate of 19.8 mmcfpd @ 4.3 MPa and will be on-stream through the expanded Banshee plant by year end. The Company has 14 new Wilrich horizontals to bring on production during the balance of November and December. As the Company expands the use of pad drilling in its Wilrich development, drill-and-complete costs are expected to continue to drop.

Results from the Cretaceous Notikewin horizontal development continue to exceed expectations, the most recent horizontal at Marsh 16-26, tested at a final rate of 14.7 mmcfpd @ 6.0 MPa. The Company has four additional Notikewin horizontals that are drilled and will be completed and tied-in prior to year end.

The most recent 3D seismic defined multi-objective vertical at Banshee 9-30 tested at a final comingled test rate of 13.9 mmcfpd @ 2.1 MPa.

The ongoing plant expansions at Banshee/Minehead and Wild River are both proceeding on schedule and are anticipated to start up during the first half of December. Each expansion will add 50 mmcfpd of gas processing capacity.

NEBC Montney Update

Current production from the NEBC Montney complex is 33,000 boepd, with a further 5,000 boepd of additional tied-in production shut-in due to capacity constraints. The Company plans a further 50 mmcfpd processing capacity expansion for the complex, with an estimated third quarter 2014 start up. Tourmaline plans to operate two drilling rigs in BC pursuing Montney horizontal targets throughout 2014. Current operating costs at Sunrise-Dawson are below $3.00/boe.

During the third quarter, the Company has utilized the highly successful Montney completion technique, developed at Sunrise-Dawson, on the Montney section at Sundown, with very strong results. The initial 3-well Montney horizontal pad at Sundown tested at a final combined stabilized gas rate of 37.1 mmcfpd. Tourmaline has in excess of 250 horizontal Montney follow-up locations on the current Company Montney landholdings at Sundown. The Company is planning to build a new 25 mmcfpd gas facility at Sundown in the first quarter of 2014 to handle the increased production volumes. This property is now expected to become a significant NEBC producing entity for Tourmaline over the next two-three years.

The Company also participated in two successful Montney wells at Septimus, with average final test rates of 8.5 mmcfpd and 325 bbls/day of condensate.

Peace River High Charlie Lake Oil Complex

Tourmaline is currently operating three drilling rigs delineating the regional Charlie Lake oil pool currently covering approximately 16 townships. The Company has drilled 20 additional successful horizontal wells since July 1, 2013, including four successful pool delineation wells at Earring and Mulligan, 35-40 miles north of the original Spirit River Complex.

These delineation wells include the Earring 15-16 well, which has a 20-day IP of 735 boepd (350 bopd oil, 2.3 mmcfpd gas), and the Mulligan 1-14-81-8W6M which production tested at a rate of 560 boepd (360 bpd, 1.2 mmcfpd gas). Pingel 1- 30-81-7W6M is currently flowing 375 bopd with 0.30 mmcfpd of gas and Mulligan 13-36-81-8W6 has been drilled and completed and will commence flow testing this week. In addition to an oil-charged primary objective, these four delineation wells have also encountered an additional nine separate hydrocarbon bearing zones above and/or below the main Charlie Lake horizon.

In the original Spirit River pool, the Company completed its first concurrently-stimulated horizontal well pair with final production test rates of 2,436 bpd of 40° API oil and 0.5 mmcfpd of gas. The wells are approximately 400 metres apart and were drilled into a lower productivity portion of the pool. Tourmaline plans several more of these concurrently-stimulated well pairs along the 65 mile long regional pool and believes this stimulation technique has the potential for a step change improvement in well performance.

In the main Spirit River pool, current Charlie Lake production capacity has reached 16,000 boepd. The third party Gordondale East plant has not been able to accept the originally-planned associated sour gas volumes of 37 mmcfpd from Tourmaline; pool production has however been steadily increased from approximately 6,000 boepd in September to over 8,000 boepd in November. Both Tourmaline and the plant operator are continuing to work on opportunities to bring additional shut-in volumes of approximately 8,000 boepd on-stream.

The Company is continuing with plans to build a 100% owned-and-operated sour gas injection plant at Spirit River, providing a significant addition to sour gas processing capacity in the area. A new oil battery, with initial capacity of 2,000 bopd to handle the increasing production volumes in the Mulligan-Pingel area, is planned for the first quarter of 2014.

Tourmaline has now drilled 60 successful Charlie Lake horizontals, both at Spirit River and into the regional oil pool, and zero dry holes to date. Completed, stimulated well costs are now averaging between $3.5 and $4.0 million, with 2P reserves of 348 mstboe per horizontal well currently recognized by third-party engineering at Spirit River. Tourmaline controls 485 sections along the regional oil pool, approximately 80% of the total pool as currently mapped, and now has over 1,200 management-identified future Charlie Lake horizontal locations in inventory. The Company is staging drilling and facility construction to achieve the 30,000 boepd production level from the Charlie Lake complex in 2015.

Exploration Program Update

The first Paleozoic exploration well at Sunset 11-17 is currently drilling in the upper Paleozoic, approximately three weeks away from the primary objective in the Devonian. Hydrocarbon shows have been encountered from several horizons thus far, including gas-to-surface, while drilling, from an Upper Mississippian horizon.

The Company's first horizontal Montney test on its extensive land holdings at Musreau-Resthaven will spud in January 2014 and the first deep exploration well testing Devonian targets beneath the Deep Basin Cretaceous complex will spud in February 2014.

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

CORPORATE SUMMARY - THIRD QUARTER 2013
Three Months Ended September 30, Nine Months Ended September 30,
2013 2012 Change 2013 2012 Change
OPERATIONS
Production
Natural gas (mcf/d) 396,592 255,451 55 % 381,025 256,235 49 %
Crude oil and NGL (bbls/d) 7,997 5,600 43 % 7,486 5,940 26 %
Oil equivalent (boe/d) 74,096 48,175 54 % 70,990 48,646 46 %
Product prices(1)
Natural gas ($/mcf) $ 3.30 $ 2.52 31 % $ 3.57 $ 2.42 48 %
Crude oil and NGL ($/bbl) $ 91.65 $ 83.34 10 % $ 89.27 $ 83.87 6 %
Operating expenses ($/boe) $ 4.36 $ 3.66 19 % $ 4.31 $ 4.56 (5 )%
Transportation expenses ($/boe) $ 2.01 $ 1.97 2 % $ 2.00 $ 1.87 7 %
Operating netback ($/boe)(3) $ 18.59 $ 15.68 19 % $ 19.99 $ 15.12 32 %
Cash general & administrative expenses ($/boe)(2) $ 0.68 $ 0.79 (14 )% $ 0.76 $ 0.79 (4 )%
FINANCIAL ($000, EXCEPT PER SHARE)
Revenue 187,974 102,127 84 % 553,750 306,726 81 %
Royalties 17,798 7,641 133 % 44,015 19,511 126 %
Cash flow(3) 120,560 63,515 90 % 366,029 186,472 96 %
Cash flow per share(3) $ 0.64 $ 0.38 68 % $ 1.96 $ 1.13 73 %
Net earnings (loss) 9,163 (4,770 ) 292 % 91,351 (782 ) - %
Net earnings (loss) per share $ 0.05 $ (0.03 ) 267 % $ 0.49 $ (0.00 ) - %
Capital expenditures 468,261 175,277 167 % 817,475 445,532 83 %
Weighted average shares outstanding (diluted) 186,676,207 164,854,721 13 %
Net debt(3) (689,355 ) (311,847 ) 121 %
(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.

Forward-Looking Information

This press release contains forward-looking information within the meaning of applicable securities laws. The use of any of the words "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, natural gas and natural gas liquids production volumes, cash flows, net debt levels, capital efficiency and capital spending, projected operating costs, disposition initiatives, the timing for facility expansions, as well as Tourmaline's future and completion prospects and plans, including the number and type of wells to be drilled in core areas, 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 which include tie-in approvals; the performance of existing wells; the success obtained in drilling new wells; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour and services; the state of the economy and the exploration and production business; the availability and cost of financing; and ability to market oil and natural gas successfully.

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

Undue reliance should not be placed on the forward-looking information because Tourmaline can give no assurances that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature it involves inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to reserves, production, costs and expenses; health, safety and environmental risks; commodity price and currency exchange rate fluctuations; marketing and transportation; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to realize the anticipated benefits of acquisitions; 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.

Also included in this press release are estimates of Tourmaline's 2013 and 2014 cash flow and Tourmaline's 2013 exit net debt, which are based on the various assumptions as to production levels, capital expenditures, and other assumptions disclosed in this press release and including commodity price assumptions for natural gas (AECO - $3.21/mcf and $3.86/mcf, respectively) and crude oil (WTI - US $98.62/bbl and US $97.00/bbl, respectively) and an exchange rate assumption of $0.98 and $0.97, respectively (US/CDN). To the extent such estimates constitute a financial outlook, they were approved by management of Tourmaline on November 13, 2013 and are included to provide readers with an understanding of Tourmaline's anticipated cash flow based on the capital expenditure and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.

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 Management's Discussion and Analysis forming part of this press release (See "Forward-Looking Statements" therein) and reports on file with applicable securities regulatory authorities including Tourmaline's most recent Annual Information Form, which 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.

Additional Reader Advisories

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

"Cash flow", "operating netback" and "net debt" as used in this press release are financial measures commonly used in the oil and gas industry, which do not have any standardized meaning prescribed by International Financial Reporting Standards ("IFRS"). See "Non-GAAP Financial Measures" in the attached Management's Discussion and Analysis for the definition and description of these terms.

Production tests are not necessarily indicative of long-term performance or ultimate recovery. All production tests are 3 – 5 days duration.

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

Conference Call Tomorrow at 10:00 a.m. MT (12:00 p.m. ET)

Tourmaline will host a conference call tomorrow, November 14, 2013 starting at 10:00 a.m. MT (12:00 p.m. ET). To participate, please dial (800) 565-0813 (toll-free in North America) or (416) 340-8527 a few minutes prior to the conference call.

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 for the nine months ended September 30, 2013 and the consolidated financial statements for the year ended December 31, 2012. Both the consolidated financial statements and the MD&A can be found at www.sedar.com. This MD&A is dated November 13, 2013.

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

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

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

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

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

These forward-looking statements are subject to numerous risks and uncertainties, most of which are beyond the Company's control, including the impact of general economic conditions; volatility in market prices for crude oil, NGL and natural gas; industry conditions; currency fluctuation; imprecision of reserve estimates; liabilities inherent in crude oil and natural gas operations; environmental risks; incorrect assessments of the value of acquisitions and exploration and development programs; competition; the lack of availability of qualified personnel or management; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; stock market volatility; ability to access sufficient capital from internal and external sources; the receipt of applicable approvals; and the other risks considered under "Risk Factors" in Tourmaline's most recent annual information form available at www.sedar.com.

With respect to forward-looking statements contained in this MD&A, Tourmaline has made assumptions regarding: future commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment and services; effects of regulation by governmental agencies; and future operating costs.

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

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

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

PRODUCTION
Three Months Ended
September 30,
Nine Months Ended
September 30,
2013 2012 Change 2013 2012 Change
Natural gas (mcf/d) 396,592 255,451 55 % 381,025 256,235 49 %
Oil and NGL (bbl/d) 7,997 5,600 43 % 7,486 5,940 26 %
Oil equivalent (boe/d) 74,096 48,175 54 % 70,990 48,646 46 %

Production for the three months ended September 30, 2013 averaged 74,096 boe/d, a 54% increase over the average production for the same quarter of 2012 of 48,175 boe/d. Production was 89% natural gas weighted in the third quarter of 2013. For the nine months ended September 30, 2013, production increased 46% to 70,990 boe/d from 48,646 boe/d for the same period of 2012. The Company's significant production growth, when compared to 2012, can be attributed to new wells that have been brought on-stream since September 30, 2012, as well as property and corporate acquisitions.

The Company expects 2013 production to average approximately 76,500 boe/d. The slight reduction in volumes can mostly be attributed to unscheduled downtime which occurred during the third quarter, shut-ins due to plant capacity issues at Spirit River, plant start-up issues at the Doe plant in NEBC, as well as gas processing issues at a third party facility at Spirit River, all of which resulted in lower than anticipated production during the third quarter.

REVENUE
Three Months Ended
September 30,
Nine Months Ended
September 30,
(000s) 2013 2012 Change 2013 2012 Change
Revenue from:
Natural gas $ 120,547 $ 59,195 104 % $ 371,324 $ 170,225 118 %
Oil and NGL 67,427 42,932 57 % 182,426 136,501 34 %
Total revenue from natural gas, oil and NGL sales $ 187,974 $ 102,127 84 % $ 553,750 $ 306,726 81 %

Revenue for the three months ended September 30, 2013 increased 84% to $188.0 million from $102.1 million for the same quarter of 2012. For the nine months ended September 30, 2013, revenue was $553.8 million, an 81% increase over revenue of $306.7 million for the same period of 2012. Revenue growth is consistent with the increase in production and increased commodity prices over the same periods. Revenue includes all petroleum, natural gas and NGL sales and realized gains on financial instruments.

TOURMALINE PRICES:
Three Months Ended
September 30,
Nine Months Ended
September 30,
2013 2012 Change 2013 2012 Change
Natural gas ($/mcf) $ 3.30 $ 2.52 31 % $ 3.57 $ 2.42 48 %
Oil and NGL ($/bbl) $ 91.65 $ 83.34 10 % $ 89.27 $ 83.87 6 %
Oil equivalent ($/boe) $ 27.58 $ 23.04 20 % $ 28.57 $ 23.01 24 %

The realized average natural gas price for the three and nine months ended September 30, 2013 was 31% and 48%, respectively, higher than the same periods of the prior year. Realized crude oil and NGL prices increased 10% and 6%, respectively, for the three and nine months ended September 30, 2013, compared to the same periods of 2012.

The realized natural gas price for the quarter ended September 30, 2013 was 35% (September 30, 2012 - 10%) higher than the AECO index price of which approximately 12% (September 30, 2012 - 8%) relates to a premium received due to higher heat content. The higher heat content is due to an increase in the relative contribution of NEBC natural gas which has a higher ethane content. The remainder of the premium received relates to positive hedging positions. The realized gain on commodity contracts for the third quarter of 2013 ($20.1 million) has increased from the same period in the prior year ($2.3 million), as the market price of natural gas decreased relative to the prices per the commodity contracts settled in the period. Realized prices exclude the effect of unrealized gains or losses. Once these gains and losses are realized they are included in the per unit amounts.

BENCHMARK GAS AND OIL PRICES:
Three Months Ended
September 30,
2013 2012 Change
Natural gas
NYMEX Henry Hub (USD$/mcf) $ 3.56 $ 2.89 23 %
AECO (CAD$/mcf) $ 2.45 $ 2.30 7 %
Oil
NYMEX (USD$/bbl) $ 105.81 $ 92.20 15 %
Edmonton Par (CAD$/bbl) $ 105.36 $ 84.87 24 %
RECONCILIATION OF AECO INDEX TO TOURMALINE'S REALIZED GAS PRICES:
Three Months Ended
September 30,
($/mcf) 2013 2012 Change
AECO index $ 2.45 $ 2.30 7 %
Heat/quality differential 0.30 0.18 67 %
Realized gain 0.55 0.04 1,275 %
Tourmaline realized natural gas price $ 3.30 $ 2.52 31 %
CURRENCY - EXCHANGE RATES:
Three Months Ended
September 30,
2013 2012 Change
CAD$/USD$ $ 0.9627 $ 1.0043 (4 )%
ROYALTIES
Three Months Ended
September 30,
Nine Months Ended
September 30,
(000s) 2013 2012 2013 2012
Natural gas $ 7,709 $ 592 $ 19,756 $ (1,509 )
Oil and NGL 10,089 7,049 24,259 21,020
Total royalties $ 17,798 $ 7,641 $ 44,015 $ 19,511
Royalties as a percentage of revenue 9.5 % 7.5 % 7.9 % 6.4 %

For the quarter ended September 30, 2013, the average effective royalty rate increased to 9.5% compared to 7.5% for the same quarter of 2012. For the nine months ended September 30, 2013, the average effective royalty rate was 7.9% compared to 6.4% for the same period of 2012.

The Company continues to benefit from the New Well Royalty Reduction Program and the Natural Gas Deep Drilling Program in Alberta as well as the Deep Royalty Credit Program in British Columbia. The average effective royalty rate increased in 2013 over 2012 due to increased commodity prices and, in addition, the maximum allowable benefit has been reached on some higher producing wells resulting in increased royalties. Also during 2012, there were additional royalty incentives received on some of the Company's producing wells which significantly reduced the royalty rate for that period.

The Company expects its royalty rate for 2013 to be approximately 10% as additional wells will no longer qualify for royalty incentive programs due to production maximums being reached and other wells coming off royalty holidays, thereby increasing the Company's overall royalty rate. The royalty rate is also sensitive to commodity prices, however, and as such, a change in commodity prices will impact the actual rate.

OTHER INCOME

For the quarter ended September 30, 2013, other income was $1.7 million (three months ended September 30, 2012 - $0.9 million), the majority of which relates to processing income.

For the nine months ended September 30, 2013, other income was $4.2 million (nine months ended September 30, 2012 - $3.7 million), which includes $4.2 million in processing income (nine months ended September 30, 2012 - $2.8 million). In late 2012, Tourmaline acquired, and now operates, a gas processing facility in NEBC, which has allowed the Company to process additional volumes. Temporary excess capacity at this plant was utilized by a third party resulting in increased processing income for the Company. Notwithstanding this, the Company expects processing income to decrease as the Company's production grows, thus reducing capacity for third-party volumes in Tourmaline owned-and-operated facilities.

OPERATING EXPENSES
Three Months Ended
September 30,
Nine Months Ended
September 30,
(000s) except per unit amounts 2013 2012 Change 2013 2012 Change
Operating expenses $ 29,718 $ 16,236 83 % $ 83,494 $ 60,736 37 %
Per boe $ 4.36 $ 3.66 19 % $ 4.31 $ 4.56 (5 )%

Operating expenses include all periodic lease and field-level expenses and exclude income recoveries from processing third-party volumes. For the third quarter of 2013, total operating expenses increased 83% from $16.2 million in the third quarter of 2012 to $29.7 million in 2013 due to the increased variable costs relating to new production, as well as increased property taxes in 2013. The third quarter of 2012 included some 13th month adjustments resulting in lower operating expenses recorded during that period. On a per-boe basis, the costs increased 19% from $3.66/boe for the third quarter of 2012 to $4.36/boe in the third quarter of 2013.

The Company's operating expenses in the third quarter of 2013 include third-party processing, gathering, and compression fees of approximately $8.7 million or 29% of total operating costs (September 30, 2012 - $4.3 million or 27% of total operating costs).

For the nine months ended September 30, 2013, total operating expenses were $83.5 million, or $4.31/boe, compared to $60.7 million, or $4.56/boe, for the same period of 2012. Although total operating expenses increased along with production, the costs per boe decreased 5% reflecting increased operational efficiencies.

The Company expects its full year 2013 operating costs to average approximately $4.25/boe, which is consistent with previous guidance. Actual costs per boe can change, however, depending on a number of factors including the Company's actual production levels.

TRANSPORTATION
Three Months Ended
September 30,
Nine Months Ended
September 30,
(000s) except per unit amounts 2013 2012 Change 2013 2012 Change
Natural gas transportation $ 9,404 $ 6,279 50 % $ 26,451 $ 18,362 44 %
Oil and NGL transportation 4,298 2,458 75 % 12,328 6,534 89 %
Total transportation $ 13,702 $ 8,737 57 % $ 38,779 $ 24,896 56 %
Per boe $ 2.01 $ 1.97 2 % $ 2.00 $ 1.87 7 %

Transportation costs for the three months ended September 30, 2013 were $13.7 million or $2.01/boe (three months ended September 30, 2012 - $8.7 million or $1.97/boe, respectively). Transportation costs for the nine months ended September 30, 2013 were $38.8 million or $2.00/boe (nine months ended September 30, 2012 - $24.9 million or $1.87/boe, respectively). The increase in total transportation costs for the three and nine months ended September 30, 2013 can be attributed to increased production as well as increased oil and NGL transportation costs. Pipeline and infrastructure constraints have resulted in a greater use of more expensive truck transportation.

GENERAL & ADMINISTRATIVE EXPENSES ("G&A")
Three Months Ended
September 30,
Nine Months Ended
September 30,
(000s) except per unit amounts 2013 2012 Change 2013 2012 Change
G&A expenses $ 9,791 $ 6,667 47 % $ 27,227 $ 19,550 39 %
Administrative and capital recovery (606 ) (484 ) 25 % (1,332 ) (822 ) 62 %
Capitalized G&A (4,519 ) (2,685 ) 68 % (11,072 ) (8,184 ) 35 %
Total G&A expenses $ 4,666 $ 3,498 33 % $ 14,823 $ 10,544 41 %
Per boe $ 0.68 $ 0.79 (14 )% $ 0.76 $ 0.79 (4 )%

G&A expenses for the third quarter of 2013 were $4.7 million ($0.68/boe) compared to $3.5 million ($0.79/boe) for the same quarter of the prior year. For the nine months ended September 30, 2013, G&A expenses were $14.8 million ($0.76/boe) compared to $10.5 million ($0.79/boe) for the same period of 2012. The increase in G&A expenses in 2013 compared to 2012 is primarily due to staff additions needed to manage the larger production, reserve and land base. Overall, the Company's G&A expenses per boe continue to trend downward as Tourmaline's production base continues to grow faster than its accompanying G&A costs.

G&A costs for 2013 are expected to be similar to 2012 on a dollar-per-boe basis. Actual costs per boe can change, however, depending on a number of factors including the Company's actual production levels.

SHARE-BASED PAYMENTS
Three Months Ended
September 30,
Nine Months Ended
September 30,
(000s) except per unit amounts 2013 2012 2013 2012
Share-based payments $ 10,882 $ 7,150 $ 27,026 $ 22,182
Capitalized share-based payments (5,441 ) (3,575 ) (13,513 ) (11,091 )
Total share-based payments $ 5,441 $ 3,575 $ 13,513 $ 11,091
Per boe $ 0.80 $ 0.81 $ 0.70 $ 0.83

The Company uses the fair value method for the determination of non-cash related share-based payments expense. During the third quarter of 2013, 340,000 stock options were granted to employees, officers, directors and key consultants at a weighted-average exercise price of $40.18, and 446,367 options were exercised, bringing $4.9 million of cash into treasury. The Company recognized $5.4 million of share-based payment expense in the third quarter of 2013 compared to $3.6 million in the third quarter of 2012.

For the nine months ended September 30, 2013, share-based payment expense totalled $13.5 million and capitalized share-based payments were $13.5 million (2012 - $11.1 million and $11.1 million, respectively). Share-based payments in 2013 are higher compared to 2012 due to the additional number of employees required to manage increased activity, along with an overall increase in the fair value of options granted.

DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A")
Three Months Ended
September 30,
Nine Months Ended
September 30,
(000s) except per unit amounts 2013 2012 2013 2012
Total depletion, depreciation and amortization $ 96,250 $ 58,733 $ 259,990 $ 176,530
Less mineral lease expiries (15,819 ) - (30,845 ) -
Depletion, depreciation and amortization $ 80,431 $ 58,733 $ 229,145 $ 176,530
Per boe $ 11.80 $ 13.25 $ 11.82 $ 13.24

DD&A expense, net of mineral lease expiries expense, was $80.4 million for the third quarter of 2013 compared to $58.7 million for the same period of 2012 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) for the third quarter of 2013 was $11.80/boe compared to $13.25/boe for the third quarter of 2012.

For the nine months ended September 30, 2013, DD&A expense was $229.1 million (nine months ended September 30, 2012 - $176.5 million) with an effective rate of $11.82/boe (nine months ended September 30, 2012 - $13.24/boe). The lower DD&A rate, for the three and nine months ended September 30, 2013, compared to the same periods of 2012, reflects strong reserve additions derived from Tourmaline's exploration and production program.

Mineral lease expiries for the three and nine months ended September 30, 2013 were $15.8 million and $30.8 million, respectively (September 30, 2012 - nil). The increase in expiries is a result of mineral leases acquired via property and corporate acquisitions which were partially through their term at the date they were purchased, and have now begun to expire. The Company prioritizes drilling on what it believes to be the most cost-efficient and productive acreage, and with such a large land base, the Company has chosen to not continue some of the expiring sections of land. Tourmaline expects to continue to see mineral lease expiries of a similar magnitude on a go-forward basis.

FINANCE EXPENSES
Three Months Ended
September 30,
Nine Months Ended
September 30,
(000s) 2013 2012 Change 2013 2012 Change
Interest expense $ 2,445 $ 3,035 (19 )% $ 8,025 $ 6,788 18 %
Accretion expense 533 325 64 % 1,412 940 50 %
Transaction costs on corporate and property acquisitions 421 - - % 1,091 172 534 %
Other 247 236 5 % 644 632 2 %
Total finance expenses $ 3,646 $ 3,596 1 % $ 11,172 $ 8,532 31 %

Finance expenses are comprised of interest expense, accretion of provisions and transaction costs associated with corporate and property acquisitions. Finance expenses for the three months ended September 30, 2013 totalled $3.6 million, which are consistent with 2012 third quarter finance expenses. Finance expenses for the nine months ended September 30, 2013 increased from $8.5 million in 2012 to $11.1 million in 2013, due to transaction costs associated with acquisitions ($0.9 million increase in 2013), and a $1.2 million increase in interest expense resulting from a higher balance drawn on the credit facility during 2013. The average bank debt outstanding in 2013 was $311.2 million (2012 - $236.3 million), with an average effective interest rate of 3.06% (2012 - 3.27%).

DEFERRED INCOME TAXES

For the three and nine months ended September 30, 2013, the provision for deferred income tax expense was $8.8 million and $42.7 million, respectively, compared to an expense of $2.4 million and $7.3 million, respectively, for the same periods in 2012. The increase was due to higher pre-tax earnings in 2013 and an increase in the Company's effective tax rate during the third quarter of 2013 due to the Province of British Columbia increasing its provincial tax rate from 10% to 11%.

CASH FLOW FROM OPERATING ACTIVITIES, CASH FLOW AND NET EARNINGS
Three Months Ended
September 30,
Nine Months Ended
September 30,
(000s) except per unit amounts 2013 2012 Change 2013 2012 Change
Cash flow from operating activities $ 128,192 $ 66,713 92 % $ 350,387 $ 168,806 108 %
Per share (1) $ 0.68 $ 0.40 68 % $ 1.88 $ 1.02 84 %
Cash flow (2) $ 120,560 $ 63,515 90 % $ 366,029 $ 186,472 96 %
Per share (1) (2) $ 0.64 $ 0.38 68 % $ 1.96 $ 1.13 73 %
Net earnings (loss) $ 9,163 $ (4,770 ) 292 % $ 91,351 $ (782 ) - %
Per share (1) $ 0.05 $ (0.03 ) 267 % $ 0.49 $ (0.00 ) - %
Operating netback per boe (2) $ 18.59 $ 15.68 19 % $ 19.99 $ 15.12 32 %
(1)Fully diluted
(2)See "Non-GAAP Financial Measures"

Cash flow for the three months ended September 30, 2013 was $120.6 million or $0.64 per diluted share compared to $63.5 million or $0.38 per diluted share for the same period of 2012. Cash flow for the nine months ended September 30, 2013 increased to $366.0 million or $1.96 per diluted share compared to September 30, 2012 cash flow of $186.5 million or $1.13 per diluted share. The increase in cash flow in 2013 reflects higher commodity prices over 2012, as well as increased production.

After-tax earnings for the three months ended September 30, 2013 are higher at $9.2 million ($0.05 per diluted share) compared to a loss of $4.8 million ($0.03 per diluted share) for the same period of 2012, due mainly to higher commodity prices and increased production. After-tax earnings for the nine month period ending September 30, 2013 were $91.4 million ($0.49 per diluted share) compared to a loss of $0.8 million ($0.00 per diluted share) in 2012. The significant increase is attributable to increased commodity prices and production as well as the gain realized on the sale of a non-core asset in Elmworth, Alberta, and the gain realized on financial instruments.

CAPITAL EXPENDITURES
Three Months Ended
September 30,
Nine Months Ended
September 30,
(000s) 2013 2012 2013 2012
Land and seismic $ 17,566 $ 6,719 $ 34,348 $ 22,018
Drilling and completions 205,324 116,721 441,327 289,506
Facilities 132,097 43,333 263,800 131,489
Property acquisitions 108,763 5,867 144,746 6,841
Property dispositions (100 ) (65 ) (78,045 ) (12,633 )
Other 4,611 2,702 11,299 8,311
Total cash capital expenditures $ 468,261 $ 175,277 $ 817,475 $ 445,532

During the third quarter of 2013 the Company invested $468.3 million of cash consideration compared to $175.3 million for the same period of 2012. Expenditures on exploration and production were $355.0 million compared to $166.8 million for the same quarter of 2012, which is consistent with the Company's aggressive growth strategy. During the nine-month period ended September 30, 2013, the Company invested $817.5 million cash consideration compared to $445.5 million for the same period of 2012. The growth in facilities expenditures includes Phase 1 of the Spirit River gas facility expansion (completed in June 2013), the NEBC gas facility (completed in July 2013), as well as costs related to the expansion of the Wild River and Banshee gas facilities, both scheduled to be completed in late 2013. The Company also continued to add to its overall asset base through strategic property acquisitions during the third quarter of 2013.

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

Three Months Ended
September 30, 2013
Gross Net
Drilled 44 38.51
Completed 31 28.98
Tied-in 9 8.17

LIQUIDITY AND CAPITAL RESOURCES

On March 12, 2013, the Company issued 5.78 million common shares at a price of $34.25 per share and 0.835 million flow-through common shares at a price of $42.15 per share, for total gross proceeds of $233.2 million. The proceeds were used to temporarily reduce bank debt and to fund the Company's 2013 exploration and development program.

On October 8, 2013, the Company issued 3.495 million common shares at a price of $41.75 per share and 0.925 million flow-through common shares at a price of $51.60 per share, for total gross proceeds of $193.6 million. The proceeds were used to temporarily reduce bank debt and will be used to fund the Company's remaining 2013 and 2014 exploration and development programs.

The Company has a covenant-based bank credit facility in place with a syndicate of bankers, the details of which are described in note 9 of the Company's consolidated financial statements for the year ended December 31, 2012. In October 2013, the facility was increased to $900 million from $750 million, under the same terms and covenants, with an initial maturity of June 2016.

As at September 30, 2013, the Company had negative working capital of $204.5 million, after adjusting for the fair value of financial instruments (the unadjusted working capital deficiency was $206.3 million) (December 31, 2012 - $103.7 million and $98.9 million, respectively). Management believes the Company has sufficient liquidity and capital resources to fund the remainder of its 2013 and its 2014 exploration and development programs through expected cash flow from operations and its unutilized bank credit facility. As at September 30, 2013, the Company's bank debt balance was $484.8 million (December 31, 2012 - $360.6 million), and net debt was $689.4 million (December 31, 2012 - $464.3 million). On October 8, 2013, the net proceeds of the financing were received effectively reducing net debt by $185.6 million.

SHARES OUTSTANDING

As at November 13, 2013, the Company has 189,571,687 common shares outstanding and 14,003,828 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 $ 2,365 $ 8,572 $ 10,164 $ 7,402 $ 28,503
Flow-through obligations - 7,862 - - 7,862
Firm transportation and processing agreements 47,411 104,376 91,184 240,033 483,004
Bank debt(1) - 526,618 - - 526,618
$ 49,776 $ 647,428 $ 101,348 $ 247,435 $ 1,045,987
(1) Includes interest expense at an annual rate of 2.87% being the rate applicable to outstanding bank debt at September 30, 2013.

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, 2012.

As at September 30, 2013, the Company has entered into certain financial derivative and physical delivery sales contracts in order to manage commodity risk. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, even though the Company considers all commodity contracts to be effective economic hedges. Such financial derivative commodity contracts are recorded on the consolidated statement of financial position at fair value, with changes in the fair value being recognized as an unrealized gain or loss on the consolidated statement of income and comprehensive income. The contracts that the Company has entered into in the first nine months of 2013 are detailed in note 3 of the Company's interim condensed consolidated financial statements for the three and nine months ended September 30, 2013.

The following table provides a summary of the unrealized gains and losses on financial instruments for the three and nine months ended September 30, 2013 and 2012:

Three Months Ended
September 30,
Nine Months Ended
September 30,
(000s) 2013 2012 2013 2012
Unrealized gain (loss) on financial instruments $ (4,701 ) $ (3,551 ) $ (5,199 ) $ 1,426
Unrealized (loss) on investments held for trading - - - (103 )
Total $ (4,701 ) $ (3,551 ) $ (5,199 ) $ 1,323

The Company has entered into physical contracts to manage commodity risk. These contracts are considered normal sales contracts and are not recorded at fair value in the consolidated financial statements. Physical contracts entered into since December 31, 2012 to September 30, 2013 have been disclosed in note 3 of the Company's interim condensed consolidated financial statements for the three and nine months ended September 30, 2013.

Financial derivative and physical delivery contracts entered into subsequent to September 30, 2013 are detailed in note 3 of the Company's interim condensed consolidated financial statements for the three and nine months ended September 30, 2013.

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, 2012.

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING

The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures ("DC&P"), as defined by National Instrument 52-109 Certification, to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's Chief Executive Officer and Chief Financial Officer by others, particularly during the periods in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. All control systems by their nature have inherent limitations and, therefore, the Company's DC&P are believed to provide reasonable, but not absolute, assurance that the objectives of the control systems are met.

The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal controls over financial reporting ("ICFR"), as defined by 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 ICFR during the period beginning on July 1, 2013 and ending on September 30, 2013 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.

ADOPTION OF NEW ACCOUNTING STANDARDS

On January 1, 2013, the Company adopted new standards with respect to consolidations (IFRS 10), joint arrangements (IFRS 11), disclosure of interests in other entities (IFRS 12), fair value measurements (IFRS 13) and amendments to financial instrument disclosures (IFRS 7). The adoption of these standards had no impact on the amounts recorded in the interim condensed consolidated financial statements or on the comparative periods.

BUSINESS RISKS AND UNCERTAINTIES

Tourmaline monitors and complies with current government regulations that affect its activities, although operations may be adversely affected by changes in government policy, regulations or taxation. In addition, Tourmaline maintains a level of liability, property and business interruption insurance which is believed to be adequate for Tourmaline's size and activities, but is unable to obtain insurance to cover all risks within the business or in amounts to cover all possible claims.

See "Forward-Looking Statements" in this MD&A and "Risk Factors" in Tourmaline's most recent annual information form for additional information regarding the risks to which Tourmaline and its business and operations are subject.

IMPACT OF NEW ENVIRONMENTAL REGULATIONS

Environmental legislation, including the Kyoto Accord, the federal government's "EcoACTION" plan and Alberta's Bill 3 - Climate Change and Emissions Management Amendment Act, is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. Given the evolving nature of the debate related to climate change and the resulting requirements, it is not possible to determine the operational or financial impact of those requirements on Tourmaline.

NON-GAAP FINANCIAL MEASURES

This MD&A or documents referred to in this MD&A make reference to the terms "funds from operations", "net debt", "operating netback", "working capital (adjusted for the fair value of financial instruments and future taxes)", "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 "funds from operations", "net debt", "operating netback", and "working capital (adjusted for the fair value of financial instruments)", 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 "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 "EBITDA" means generally net income or loss, excluding extraordinary items, plus interest expense and income taxes and adjusted for non-cash items and gains or losses on dispositions, "senior debt" means generally the indebtedness, liabilities and obligations of the Company to the lenders under the credit facility and certain other secured indebtedness, liabilities and obligations of the Company ("bank debt"), "total debt" means generally bank debt plus any other indebtedness of the Company, and "total capitalization" means generally the sum of the Company's shareholders' equity and all other indebtedness of the Company including bank debt, all determined on a consolidated basis in accordance with GAAP.

Cash Flow

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

Three Months Ended
September 30,
Nine Months Ended
September 30,
(000s) 2013 2012 2013 2012
Cash flow from operating activities (per GAAP) $ 128,192 $ 66,713 $ 350,387 $ 168,806
Change in non-cash operating working capital (7,632 ) (3,198 ) 15,642 17,666
Cash flow $ 120,560 $ 63,515 $ 366,029 $ 186,472

Operating Netback

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

Three Months Ended
September 30,
Nine Months Ended
September 30,
($/boe) 2013 2012 2013 2012
Revenue, excluding processing income $ 27.58 $ 23.04 $ 28.57 $ 23.01
Royalties (2.61 ) (1.72 ) (2.27 ) (1.46 )
Transportation costs (2.01 ) (1.97 ) (2.00 ) (1.87 )
Operating expenses (4.36 ) (3.66 ) (4.31 ) (4.56 )
Operating netback(1) $ 18.59 $ 15.68 $ 19.99 $ 15.12
(1) May not add due to rounding.

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

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

(000s) As at
September 30,
2013
As at
December 31,
2012
Working capital (deficit) $ (206,250 ) $ (98,913 )
Fair value of financial instruments - short-term (asset) liability 1,743 (4,814 )
Working capital (deficit) (adjusted for the fair value of financial instruments) $ (204,507 ) $ (103,727 )

Net Debt

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

(000s) As at
September 30,
2013
As at
December 31,
2012
Bank debt $ (484,848) $ (360,573)
Working capital (deficit) (206,250) (98,913)
Fair value of financial instruments - short-term (asset) liability 1,743 (4,814)
Net debt $ (689,355) $ (464,300)
SELECTED QUARTERLY INFORMATION
2013 2012 2011
($000s, unless otherwise noted) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
PRODUCTION
Natural gas (mcf) 36,486,443 34,477,391 33,055,857 27,879,639 23,501,484 24,276,149 22,430,621 18,437,079
Oil and NGL(bbls) 735,727 640,001 667,907 618,483 515,157 596,992 515,408 415,074
Oil equivalent (boe) 6,816,800 6,386,233 6,177,216 5,265,090 4,432,071 4,643,016 4,253,845 3,487,920
Natural gas (mcf/d) 396,592 378,872 367,287 303,040 255,451 266,771 246,490 200,403
Oil and NGL (bbls/d) 7,997 7,033 7,421 6,723 5,600 6,560 5,664 4,512
Oil equivalent (boe/d) 74,096 70,178 68,636 57,230 48,175 51,022 46,746 37,912
FINANCIAL
Revenue, net of royalties 167,138 180,505 161,124 134,864 91,863 105,567 94,781 98,309
Cash flow from operating activities 128,192 128,432 93,763 104,671 66,713 42,566 59,527 61,801
Cash flow (1) 120,560 128,870 116,599 93,807 63,515 61,121 61,836 73,311
Per diluted share 0.64 0.68 0.64 0.54 0.38 0.37 0.38 0.45
Net earnings (loss) 9,163 30,004 52,184 16,301 (4,770 ) 1,012 2,976 16,074
Per basic share 0.05 0.16 0.29 0.10 (0.03 ) 0.01 0.02 0.10
Per diluted share 0.05 0.16 0.29 0.09 (0.03 ) 0.01 0.02 0.10
Total assets 4,210,171 3,811,192 3,735,641 3,580,253 2,992,552 2,862,502 2,878,261 2,711,024
Working capital (206,250 ) (50,851 ) (165,385 ) (98,913 ) (98,184 ) (15,311 ) (176,029 ) (146,317 )
Working capital (adjusted for the fair value of financial instruments) (1) (204,507 ) (53,676 ) (166,049 ) (103,727 ) (101,577 ) (19,809 ) (175,696 ) (146,593 )
Capital expenditures 468,261 158,751 190,463 296,108 175,277 53,831 216,424 232,167
Total outstanding shares (000s) 184,621 184,175 183,408 174,813 165,678 160,459 158,807 158,578
PER UNIT
Natural gas ($/mcf) 3.30 3.92 3.50 3.29 2.52 2.23 2.54 3.76
Oil and NGL ($/bbl) 91.65 87.06 88.75 83.28 83.34 77.75 91.48 93.05
Revenue ($/boe) 27.58 29.88 28.33 27.18 23.04 21.64 24.48 30.95
Operating netback ($/boe) (1) 18.59 21.28 20.20 19.17 15.68 14.22 15.52 21.39
(1) See Non-GAAP Financial Measures.

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

Overall, the Company has had continued annual growth over the last two years summarized in the table above. The Company's average annual production has increased from 31,007 boe per day in 2011 to 50,804 boe per day in 2012 and 70,990 boe per day in the first nine months of 2013. 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 flows were $241.4 million in 2011, $280.3 million in 2012 and 2013 estimated cash flows (based on the first nine months annualized) are $488.0 million, due mainly to strong growth in production levels and strengthening commodity prices. Commodity price changes can indirectly impact expected production by changing the amount of funds available to reinvest in exploration, development and acquisition activities in the future. Changes in commodity prices impact revenues and cash flows 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 flows generated from operations and access to capital markets.

CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(000s) (unaudited) September 30,
2013
December 31,
2012
Assets
Current assets:
Accounts receivable $ 86,298 $ 83,868
Assets held for sale - 33,007
Prepaid expenses and deposits 8,523 5,309
Fair value of financial instruments (notes 2 and 3) - 4,814
Total current assets 94,821 126,998
Long-term asset 2,439 2,580
Exploration and evaluation assets (note 4) 699,744 639,933
Property, plant and equipment (note 5) 3,413,167 2,810,742
Total Assets $ 4,210,171 $ 3,580,253
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable and accrued liabilities $ 299,328 $ 225,911
Fair value of financial instruments (notes 2 and 3) 1,743 -
Total current liabilities 301,071 225,911
Bank debt (note 7) 484,848 360,573
Decommissioning obligations (note 6) 75,514 64,757
Long-term obligation 4,346 7,139
Fair value of financial instruments (notes 2 and 3) 654 2,012
Deferred premium on flow-through shares 1,474 8,755
Deferred taxes 230,421 176,391
Shareholders' equity:
Share capital (note 9) 2,871,793 2,599,614
Non-controlling interest (note 8) 17,396 16,298
Contributed surplus 83,423 70,923
Retained earnings 139,231 47,880
Total shareholders' equity 3,111,843 2,734,715
Total Liabilities and Shareholders' Equity $ 4,210,171 $ 3,580,253
Commitments (note 12)
Subsequent events (notes 3 and 13)
See accompanying notes to the interim condensed consolidated financial statements.
CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
Three Months Ended
September 30,
Nine Months Ended
September 30,
(000s) except per-share amounts (unaudited) 2013 2012 2013 2012
Revenue:
Oil and natural gas sales $ 167,899 $ 99,817 $ 527,211 $ 294,914
Royalties (17,798 ) (7,641 ) (44,015 ) (19,511 )
Net revenue from oil and natural gas sales 150,101 92,176 483,196 275,403
Realized gain on financial instruments 20,075 2,310 26,539 11,812
Unrealized gain (loss) on financial instruments (note 3) (4,701 ) (3,551 ) (5,199 ) 1,323
Other income 1,663 928 4,231 3,673
Total net revenue 167,138 91,863 508,767 292,211
Expenses:
Operating 29,718 16,236 83,494 60,736
Transportation 13,702 8,737 38,779 24,896
General and administration 4,666 3,498 14,823 10,544
Share-based payments 5,441 3,575 13,513 11,091
(Gain) on divestitures (4,736 ) (324 ) (48,146 ) (7,596 )
Depletion, depreciation and amortization 96,250 58,733 259,990 176,530
Total expenses 145,041 90,455 362,453 276,201
Income from operations 22,097 1,408 146,314 16,010
Finance expenses 3,646 3,596 11,172 8,532
Income (loss) before taxes 18,451 (2,188 ) 135,142 7,478
Deferred taxes 8,835 2,363 42,693 7,318
Net income (loss) and comprehensive income (loss) for the period before non-controlling interest 9,616 (4,551 ) 92,449 160
Net income (loss) and comprehensive income (loss) attributable to:
Shareholders of the Company 9,163 (4,770 ) 91,351 (782 )
Non-controlling interest (note 8) 453 219 1,098 942
$ 9,616 $ (4,551 ) $ 92,449 $ 160
Net income (loss) per share attributable to common shareholders (note 10)
Basic $ 0.05 $ (0.03 ) $ 0.50 $ (0.00 )
Diluted $ 0.05 $ (0.03 ) $ 0.49 $ (0.00 )

See accompanying notes to the interim condensed consolidated financial statements.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(000s) (unaudited)
Share
Capital
Contrib-
uted
Surplus
Retained
Earnings
Non-
Controlling
Interest
Total
Equity
Balance at December 31, 2012 $ 2,599,614 $ 70,923 $ 47,880 $ 16,298 $ 2,734,715
Issue of common shares (note 9) 226,564 - - - 226,564
Share issue costs, net of tax (7,275 ) - - - (7,275 )
Share-based payments - 13,513 - - 13,513
Capitalized share-based payments - 13,513 - - 13,513
Options exercised (note 9) 52,890 (14,526 ) - - 38,364
Income attributable to common shareholders - - 91,351 - 91,351
Income attributable to non-controlling interest - - - 1,098 1,098
Balance at September 30, 2013 $ 2,871,793 $ 83,423 $ 139,231 $ 17,396 $ 3,111,843
(000s) (unaudited)
Share
Capital
Contrib-
uted
Surplus
Retained
Earnings
Non-
Controlling
Interest
Total
Equity
Balance at December 31, 2011 $ 2,140,660 $ 47,776 $ 32,361 $ 15,079 $ 2,235,876
Issue of common shares 166,398 - - - 166,398
Share issue costs, net of tax (5,701 ) - - - (5,701 )
Share-based payments - 11,091 - - 11,091
Capitalized share-based payments - 11,091 - - 11,091
Options exercised 15,079 (4,203 ) - - 10,876
Loss attributable to common shareholders - - (782 ) - (782 )
Income attributable to non-controlling interest - - - 942 942
Balance at September 30, 2012 $ 2,316,436 $ 65,755 $ 31,579 $ 16,021 $ 2,429,791

See accompanying notes to the interim condensed consolidated financial statements.

CONSOLIDATED STATEMENTS OF CASH FLOW
Three Months Ended
September 30,
Nine Months Ended
September 30,
(000s) (unaudited) 2013 2012 2013 2012
Cash provided by (used in):
Operations:
Net income (loss) $ 9,163 $ (4,770 ) $ 91,351 $ (782 )
Items not involving cash:
Depletion, depreciation and amortization 96,250 58,733 259,990 176,530
Accretion 533 325 1,412 940
Share-based payments 5,441 3,575 13,513 11,091
Deferred taxes 8,835 2,363 42,693 7,318
Unrealized (gain) loss on financial instruments (note 3) 4,701 3,551 5,199 (1,323 )
Realized (gain) loss on sale of investments - - - (38 )
(Gain) on divestitures (4,736 ) (324 ) (48,146 ) (7,596 )
Non-controlling interest 453 219 1,098 942
Decommissioning expenditures (80 ) (157 ) (1,081 ) (610 )
Changes in non-cash operating working capital 7,632 3,198 (15,642 ) (17,666 )
Total cash flow from operating activities 128,192 66,713 350,387 168,806
Financing:
Issue of common shares 4,853 141,170 271,524 185,783
Share issue costs (249 ) (5,457 ) (9,815 ) (7,602 )
Increase (decrease) in bank debt 192,999 (104,788 ) 124,275 128,521
Total cash flow from financing activities 197,603 30,925 385,984 306,702
Investing:
Exploration and evaluation (51,061 ) (25,890 ) (107,871 ) (59,921 )
Property, plant and equipment (308,537 ) (143,585 ) (642,903 ) (391,403 )
Property acquisitions (108,763 ) (5,867 ) (144,746 ) (6,841 )
Proceeds from divestitures 100 65 78,045 12,633
Proceeds from sale of investments - - - 168
Net repayment of long-term obligation (733 ) (931 ) (2,596 ) (2,794 )
Changes in non-cash investing working capital 143,199 78,570 83,700 (27,350 )
Total cash flow from investing activities (325,795 ) (97,638 ) (736,371 ) (475,508 )
Changes in cash - - - -
Cash, beginning of period - - - -
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 consolidated financial statements

As at September 30, 2013 and for the three and nine months ended September 30, 2013 and 2012

(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 consolidated financial statements reflect only the Company's proportionate interest in such activities.

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

1. BASIS OF PREPARATION

These unaudited interim condensed consolidated financial statements have been prepared in accordance with International Accounting Standard ("IAS") 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, 2012.

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, 2012, except as detailed below.

On January 1, 2013, the Company adopted new standards with respect to consolidations (IFRS 10), joint arrangements (IFRS 11), disclosure of interests in other entities (IFRS 12), fair value measurements (IFRS 13) and amendments to financial instrument disclosures (IFRS 7). The adoption of these standards had no impact on the amounts recorded in the interim condensed consolidated financial statements or on the comparative periods.

The unaudited interim condensed consolidated financial statements were authorized for issue by the Board of Directors on November 13, 2013.

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 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.

Measurement:

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.

3. FINANCIAL RISK MANAGEMENT

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

The Company's risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company's activities. The Company's financial risks are consistent with those discussed in note 5 of the Company's audited consolidated financial statements for the year ended December 31, 2012.

As at September 30, 2013, the Company has entered into certain financial derivative and physical delivery sales contracts in order to manage commodity risk. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, even though the Company considers all commodity contracts to be effective economic hedges. As a result, all such commodity contracts are recorded on the 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 entered into the following financial derivative contracts from January 1, 2013 to September 30, 2013:

(000s)
Type of Contract Quantity Time Period(1) Contract Price Fair
Value
Financial Swap 200 bbls/d April 2013 - March 2014 USD$97.87/bbl average (139)
Financial Swap 200 bbls/d July 2013 - June 2014 USD$98.00/bbl (100)
Financial Swap 400 bbls/d January 2014 - December 2014 USD$94.825/bbl (76)
Financial Swap 200 bbls/d January 2014 - December 2014 USD$94.75/bbl (44)
Financial Swap 400 bbls/d October 2013 - December 2013 USD$97.55/bbl (152)
Financial Swap 5,000 mmbtu/d April 2013 - March 2014 USD$4.12/mmbtu 384
Financial Costless Collar 1,100 bbls/d January 2014 - December 2014 USD$80.91/bbl floor - USD$97.57/bbl ceiling average (1,239)
Financial Call Swaption 200 bbls/d April 2014 - March 2015 USD$100.00/bbl average strike
(March 31, 2013 call date)
(116)
Financial Call Swaption 600 bbls/d January 2015 - December 2015 USD$104.98/bbl average strike
(December 31, 2014 call date)
(307)
(1)Transactions with common terms have been aggregated and presented as the weighted average price.

There were no financial derivative contracts entered into subsequent to September 30, 2013.

The Company has entered into two interest rate swap arrangements. The following table outlines the realized and unrealized gains/(losses) on these interest rate contracts recorded on the consolidated statement of income (loss) and comprehensive income (loss) for the nine months ended September 30, 2013:

(000s)
Term Type
(Floating
to
Fixed)
Amount Company
Fixed
Interest
Rate
(%)
Counter
Party
Floating
Rate
Index
Nine Months Ended
September 30, 2013
Realized
(Loss)
Unrealized
Gain
(Loss)
May 29, 2012-
May 29, 2014
Swap $150,000 1.35 % Floating Rate (145 ) 51
May 29, 2014-
May 29, 2015
Swap $150,000 1.72 % Floating Rate - (281 )

The following table provides a summary of the unrealized gains and losses on financial instruments for the three and nine months ended September 30, 2013 and 2012:

Three Months Ended
September 30,
Nine Months Ended
September 30,
(000s) 2013 2012 2013 2012
Unrealized gain (loss) on financial instruments $ (4,701) $ (3,551) $ (5,199) $ 1,426
Unrealized (loss) on investments held for trading - - - (103)
Total $ (4,701) $ (3,551) $ (5,199) $ 1,323

As at September 30, 2013, if the future strip prices for oil were $1.00/bbl higher and prices for natural gas were $0.10/mcf higher, with all other variables held constant, an adjustment would have been recorded to unrealized gain (loss) on financial instruments resulting in a reduction to before-tax earnings of $2.9 million (September 30, 2012 - $1.5 million). An equal and opposite impact would have occurred to unrealized gain (loss) and the fair value of the derivative contracts liability if oil prices were $1.00/bbl lower and gas prices were $0.10/mcf lower.

Financial assets and liabilities are only offset if the Company has the current legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. The Company offsets derivative contracts assets and liabilities when the counterparty, commodity, currency and timing of settlement are the same. The following table provides a summary of the Company's offsetting derivative contracts positions.

September 30, 2013 December 31, 2012
Derivative Contracts Derivative Contracts
(000s) Asset Liability Net Asset Liability Net
Gross amount $ 4,592 $ (6,989 ) $ (2,397 ) $ 7,623 $ (4,821 ) $ 2,802
Amount offset (4,592 ) 4,592 - (2,809 ) 2,809 -
Net amount $ $ (2,397 ) $ (2,397 ) $ 4,814 $ (2,012 ) $ 2,802

In addition to the financial commodity contracts discussed above, the Company has entered into physical contracts to manage commodity risk. These contracts are considered normal sales contracts and are not recorded at fair value in the consolidated financial statements.

The Company has entered into the following physical contracts from January 1, 2013 to September 30, 2013:

Type of Contract Quantity Time Period(1) Contract Price
AECO Fixed Price 20,000 gjs/d April 2013 - March 2014 CAD$3.305/gj average
AECO Fixed Price 35,000 gjs/d April 2013 - October 2013 CAD$3.617/gj average
AECO Fixed Price 20,000 gjs/d August 2013 - October 2013 CAD$3.100/gj
AECO Fixed Price 25,000 gjs/d November 2013 - March 2014 CAD$3.839/gj average
AECO Fixed Price 25,000 gjs/d January 2014 - December 2014 CAD$3.792/gj average
AECO Fixed Price 25,000 gjs/d April 2014 - October 2014 CAD$3.466/gj average
AECO Fixed Price 5,000 gjs/d January 2015 - December 2015 CAD$4.00/gj
(Buyer) AECO/Nymex
Differential Swap
30,000 mmbtu/d April 2013 - October 2013 Nymex less USD$0.42/mmbtu average
AECO/Nymex
Differential Swap
10,000 mmbtu/d November 2013 - October 2016 SoCal GDD less USD$0.725/mmbtu
AECO/Nymex
Differential Swap
20,000 mmbtu/d November 2013 - March 2014 Nymex less USD$0.426/mmbtu average
AECO/Nymex
Differential Swap
40,000 mmbtu/d January 2014 - December 2014 Nymex less USD$0.493/mmbtu average
AECO/Nymex
Differential Swap
20,000 mmbtu/d January 2014 - December 2016 Nymex less USD$0.375/mmbtu average
AECO/Nymex
Differential Swap
20,000 mmbtu/d January 2015 - December 2022 Nymex less USD$0.486/mmbtu average
AECO Call Option
(writer)
20,000 gjs/d November 2013 - October 2014 CAD $4.000/gj strike price
AECO Call Option
(writer)
5,000 gjs/d January 2015 - December 2015 CAD$4.360/gj strike price
AECO Call Option
(writer)
8,000 gjs/d January 2016 - December 2016 CAD$5.000/gj strike price
NYMEX Call Option
(writer)
20,000 mmbtu/d January 2017 - December 2018 USD$5.000/mmbtu strike price
AECO Call Swaption
(writer)
25,000 gjs/d November 2013 - October 2014 CAD$4.000/gj strike average
(call date October 31, 2013)
AECO Call Swaption
(writer)
10,000 gjs/d January 2014 - December 2014 CAD$3.751/gj strike average
(call date December 31, 2013)
AECO Call Swaption
(writer)
15,000 gjs/d April 2014 - March 2015 CAD$3.717/gj strike average
(call date March 31, 2014)
AECO Call Swaption
(writer)
5,000 gjs/d April 2014 - March 2016 CAD$3.850/gj strike average
(call date March 31, 2014)
AECO Call Swaption
(writer)
25,000 gjs/d November 2014 - October 2015 CAD$4.000/gj strike average
(call date October 31, 2014)
(1) Transactions with common terms have been aggregated and presented as the weighted average price.

The Company has entered into the following physical contracts subsequent to September 30, 2013:

Type of Contract Quantity Time Period Contract Price
AECO Call
Swaption (writer)(1)
15,000 gjs/d January 2017 - December 2017 CAD$4.650/gj strike
(call date December 31, 2016)
(1) This transaction replaces an AECO Call Swaption (writer) previously in place for 15,000 gjs with a term of January 2014 - December 2014.

4. EXPLORATION AND EVALUATION ASSETS

(000s)
As at December 31, 2012 $ 639,933
Capital expenditures 111,709
Transfers to property, plant and equipment (note 5) (44,130 )
Acquisitions 25,383
Divestitures (2,306 )
Expired mineral leases (30,845 )
As at September 30, 2013 $ 699,744

General and administrative expenditures for the nine months ended September 30, 2013 of $3.9 million (December 31, 2012 - $5.2 million) have been capitalized and included as exploration and evaluation assets. Non-cash share-based payment expenses in the amount of $3.8 million (December 31, 2012 - $5.8 million) were also capitalized and included in exploration and evaluation assets. Expired mineral lease expenses have been included in the "Depletion, depreciation and amortization" line item on the consolidated statements of income (loss) and comprehensive income (loss).

5. PROPERTY, PLANT AND EQUIPMENT

Cost
(000s)
As at December 31, 2012 $ 3,305,685
Capital expenditures 652,578
Transfers from exploration and evaluation (note 4) 44,130
Change in decommissioning liabilities (note 6) 10,521
Acquisitions 127,065
Divestitures (3,696 )
As at September 30, 2013 $ 4,136,283
Accumulated Depletion, Depreciation and Amortization
(000s)
As at December 31, 2012 $ 494,943
Depletion, depreciation and amortization expense (net of mineral lease expiries) 229,145
Divestitures (972 )
As at September 30, 2013 $ 723,116
Net Book Value
(000s)
As at December 31, 2012 $ 2,810,742
As at September 30, 2013 $ 3,413,167

General and administrative expenditures for the nine months ended September 30, 2013 of $7.2 million (December 31, 2012 - $6.1 million) have been capitalized and included as costs of oil and natural gas properties. Also included in oil and natural gas properties is non-cash share-based payment expense of $9.7 million (December 31, 2012 - $9.1 million).

Future development costs for the nine months ended September 30, 2013 of $2,429 million (December 31, 2012 - $2,233 million) were included in the depletion calculation.

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 $113.3 million (December 31, 2012 - $92.7 million), with some abandonments expected to commence in 2021. A risk-free rate of 2.89% (December 31, 2012 - 2.49%) and an inflation rate of 2.0% (December 31, 2012 - 2.0%) were used to calculate the fair value of the decommissioning obligations.

(000s) Nine Months Ended
September 30,
2013
Year Ended
December 31,
2012
Balance, beginning of period $ 64,757 $ 50,463
Obligation incurred 7,003 5,685
Obligation incurred on corporate acquisitions - 4,643
Obligation incurred on property acquisitions 6,140 4,235
Obligation divested (95 ) (319 )
Obligation settled (1,081 ) (993 )
Reclassification of obligation associated with assets held for sale - (285 )
Accretion expense 1,412 1,328
Change in future estimated cash outlays (2,622 ) -
Balance, end of period $ 75,514 $ 64,757

7. BANK DEBT

The Company has a covenant-based bank credit facility in place with a syndicate of bankers, the details of which are described in note 9 of the Company's consolidated financial statements for the year ended December 31, 2012. In October 2013, the facility was increased, under the same terms and covenants, to $900 million with an initial maturity of June 2016.

As at September 30, 2013, the Company's bank debt balance was $484.8 million (December 31, 2012 - $360.6 million). In addition, the Company has outstanding letters of credit of $2.1 million (December 31, 2012 - $4.4 million), which reduce the credit available on the facility. The average effective interest rate for the nine months ended September 30, 2013 was 3.06% (nine months ended September 30, 2012 - 3.27%). As at September 30, 2013, 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) Nine Months Ended
September 30,
2013
Year Ended
December 31,
2012
Balance, beginning of period $ 16,298 $ 15,079
Share of subsidiary's net income for the period 1,098 1,219
Balance, end of period $ 17,396 $ 16,298

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
Nine Months Ended
September 30, 2013
Year Ended
December 31, 2012
(000s except per-share amounts) Number of
Shares
Amount Number of
Shares
Amount
Balance, beginning of period 174,813,059 $ 2,599,614 158,577,586 $ 2,140,660
For cash on public offering of common shares(2)(4) 5,780,000 197,965 4,639,000 134,531
For cash on public offering of flow-through common shares(1) (3)(4) 835,000 28,599 2,452,000 62,685
Issued on corporate acquisitions - - 7,401,682 244,404
For cash on exercise of stock options 3,193,111 38,364 1,742,791 17,712
Contributed surplus on exercise of stock options - 14,526 - 6,745
Share issue costs - (9,815 ) - (9,497 )
Tax effect of share issue costs - 2,540 - 2,374
Balance, end of period 184,621,170 $ 2,871,793 174,813,059 $ 2,599,614
(1) On April 4, 2012, the Company issued 1.4 million flow-through common shares at $28.80 per share for total gross proceeds of $40.4 million. The implied premium on the flow-through common shares was determined to be $8.5 million or $6.07 per share. A total of 0.15 million shares were purchased by insiders. As at September 30, 2013, the Company had spent the full committed amount. The expenditures were renounced to investors in February 2013 with an effective renunciation date of December 31, 2012.
(2)On August 30, 2012, the Company issued 4.039 million common shares at a price of $29.00 per share for total gross proceeds of $117.1 million. A total of 39,000 shares were purchased by insiders. Subsequently, on September 19, 2012, the Underwriters exercised their over-allotment Option and purchased a further 0.6 million shares at a price of $29.00 per share for total gross proceeds of $17.4 million.
(3) On November 1, 2012, the Company issued 1.05 million flow-through common shares at $36.90 per share for total gross proceeds of $38.7 million. The implied premium on the flow-through common shares was determined to be $7.9 million or $7.55 per share. A total of 0.05 million shares were purchased by insiders. As at September 30, 2013, the Company had spent the full committed amount. The expenditures were renounced to investors in February 2013, with an effective renunciation date of December 31, 2012.
(4) On March 12, 2013, the Company issued 5.78 million common shares at a price of $34.25 per share and 0.835 million flow-through common shares at a price of $42.15 per share, for total gross proceeds of $233.2 million. The implied premium on the flow-through common shares was determined to be $6.6 million or $7.90 per share. A total of 30,000 common and 85,000 flow-through common shares were purchased by insiders. As at September 30, 2013, the Company had spent $27.3 million on eligible expenditures and is committed to spend the remainder of $7.9 million on qualified exploration and development expenditures by December 31, 2014. The expenditures will be renounced to investors with an effective renunciation date of December 31, 2013.

10. EARNINGS PER SHARE

Basic earnings-per-share was calculated as follows:

Three Months Ended
September 30,
Nine Months Ended
September 30,
2013 2012 2013 2012
Net earnings (loss) for the period (000s) $ 9,163 $ (4,770 ) $ 91,351 $ (782 )
Weighted average number of common shares - basic 184,480,948 162,032,270 181,828,804 160,301,308
Earnings (loss) per share - basic $ 0.05 $ (0.03 ) $ 0.50 $ (0.00 )

Diluted earnings-per-share was calculated as follows:

Three Months Ended
September 30,
Nine Months Ended
September 30,
2013 2012 2013 2012
Net earnings (loss)for the period (000s) $ 9,163 $ (4,770 ) $ 91,351 $ (782 )
Weighted average number of common shares - diluted 189,764,708 162,032,270 186,676,207 160,301,308
Earnings (loss) per share - fully diluted $ 0.05 $ (0.03 ) $ 0.49 $ (0.00 )

There were 2,345,000 options excluded from the weighted-average share calculation for the nine months ended September 30, 2013 because they were anti-dilutive (September 30, 2012 - 14,134,531).

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 18,462,117 shares of common stock. The exercise price of each option equals the volume-weighted average market price for the five days preceding the issue date of the Company's stock on the date of grant and the option's maximum term is five years. Options are granted throughout the year and vest 1/3 on each of the first, second and third anniversaries from the date of grant.

Nine Months Ended September 30,
2013 2012
Number of
Options
Weighted
Average
Exercise
Price
Number of
Options
Weighted
Average
Exercise
Price
Stock options outstanding, beginning of period 15,325,232 $ 19.87 14,213,523 $ 16.82
Granted 2,445,000 40.19 980,000 23.57
Exercised (3,193,111 ) 12.01 (1,058,992 ) 10.27
Forfeited (109,443 ) 24.59 - -
Stock options outstanding, end of period 14,467,678 $ 24.98 14,134,531 $ 17.78

The following table summarizes stock options outstanding and exercisable at September 30, 2013:

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
$7.00 - $10.00 1,732,182 0.52 $ 9.17 1,732,182 $ 9.17
$12.00 - $18.35 3,969,124 1.53 16.56 3,969,124 16.56
$20.68 - $29.93 3,860,706 3.14 26.85 1,514,654 27.11
$30.76 - $41.89 4,905,666 4.25 35.91 309,000 30.83
14,467,678 2.76 $ 24.98 7,524,960 $ 17.57

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

September 30,
2013
September 30,
2012
Fair value of options granted (weighted average) $ 13.98 $ 8.11
Risk-free interest rate 2.65 % 2.38 %
Estimated hold period prior to exercise 4 years 4 years
Expected volatility 40 % 40 %
Forfeiture rate 2 % 2 %
Dividend per share $ 0.00 $ 0.00

12. COMMITMENTS

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

Payments Due by Year (000s) 1 Year 2-3 Years 4-5 Years >5 Years Total
Operating leases $ 2,365 $ 8,572 $ 10,164 $ 7,402 $ 28,503
Flow-through obligations - 7,862 - - 7,862
Firm transportation and processing agreements 47,411 104,376 91,184 240,033 483,004
Bank debt(1) - 526,618 - - 526,618
$ 49,776 $ 647,428 $ 101,348 $ 247,435 $ 1,045,987
(1) Includes interest expense at an annual rate of 2.87% being the rate applicable to outstanding bank debt at September 30, 2013.

13. SUBSEQUENT EVENTS

On October 8, 2013, the Company issued 3.495 million common shares at a price of $41.75 per share and 0.925 million flow-through common shares at a price of $51.60 per share, for total gross proceeds of $193.6 million. The Company is committed to spend $47.73 million on qualified exploration expenditures by December 31, 2014. Flow-through common shares will be renounced to investors with an effective renunciation date of December 31, 2013.

About Tourmaline Oil Corp.

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

Contact Information

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

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

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

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