Tourmaline Achieves Strong Earnings as Well as Record Production and Cash Flow in the First Quarter

CALGARY, May 4, 2017 /CNW/ - Tourmaline Oil Corp. (TSX:TOU) ("Tourmaline" or the "Company") is pleased to release strong financial and operating results for the first quarter of 2017.

HIGHLIGHTS

  • Record Q1 2017 production of 233,278 boepd, a 22% increase over the prior quarter.
  • Strong first quarter 2017 earnings of $99.5 million ($0.37/diluted share) underscoring the fundamental profitability of Tourmaline's asset base.
  • First quarter 2017 cash flow(1) of $292.9 million ($1.09/diluted share), an 84% increase over Q1 2016 cash flow.
  • Current daily production of 240,000 – 245,000 boepd.
  • Q1 2017 liquids production up 45% year-over-year.
  • Continued strong cost management with first quarter operating costs of $3.50/boe and all-in cash costs of $7.31/boe (operating, transportation, general and administration(2) and financing).
  • A significant new oil opportunity in the Lower Charlie Lake formation in the Peace River High complex, with strong production performance from the initial 13 wells and a large future drilling inventory addition.

 

________________________

(1)

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

(2)

"General and administrative cash costs" is defined as general and administrative costs excluding interest and financing charges. See "Non-GAAP Financial Measures" below and in the attached Management's Discussion and Analysis.

 

PRODUCTION UPDATE

Q1 2017 production of 233,278 boepd was a 19% increase over Q1 2016 production of 195,828 boepd and a 22% increase over Q4 2016.  Q1 2017 liquids production of 34,215 bbls/d increased 45% over the comparable period in 2016.  Tourmaline was the second largest producer of Canadian natural gas with average Q1 2017 natural gas production of 1.2 bcf/day.  Current daily production is ranging between 240,000 - 245,000 boepd.  The Company expects to bring approximately 32 new wells on production during the second quarter.

FINANCIAL RESULTS

Q1 2017 cash flow was $292.9 million ($1.09/diluted share), an 84% increase over Q1 2016 cash flow of $159.4 million.  First quarter earnings of $99.5 million ($0.37/diluted share) were up $137.9 million over the first quarter of 2016 or $0.54/share, underscoring the fundamental profitability of Tourmaline's asset base even in a low commodity price environment.

First quarter operating costs of $3.50/boe were 5% lower than first quarter 2016 operating costs of $3.70/boe and first quarter 2017 all-in cash costs were $7.31/boe.

2017 CAPITAL PROGRAM

First quarter 2017 capital expenditures were $399.4 million and the Company is planning to spend approximately $175.0 million during the second quarter, historically a period of lower EP activity.  The first-half 2017 capital budget of $575.0 million will be less than or equal to first-half cash flow as the Company remains on a cash flow budget for the EP program in 2017 as well as subsequent years.  Tourmaline anticipates delivering over 30% production growth in 2017 with the full-year capital budget of $1.3 billion.  Tourmaline continues to maintain a very strong balance sheet with an anticipated 2017 exit net debt(3) to cash flow ratio of approximately 1.1.

In the first quarter of 2017, Tourmaline increased its term loan from $250.0 million to $650.0 million and extended its maturity to February 2022, which included participation from a syndicate of Canadian banks.  The Company now has total credit capacity of $2,500.0 million, of which approximately $1,123.3 million remains unutilized at March 31, 2017. 

_____________________

(3)

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

 

EP UPDATE

Tourmaline operated up to 17 drilling rigs through the first quarter of 2017, drilling a total of 107 wells across all three core-operated complexes.  The Company intends to operate 7 drilling rigs through Q2/break-up and will ramp the program back up late in the second quarter.  The progression to larger multi-well pads in all three complexes has allowed Tourmaline to reduce drilling costs in Q1 by approximately 5% over 2016 costs.  Fracture stimulation costs have increased by between 5 and 10% on a per well basis in Q1 2017 compared to average 2016 costs. 

NEBC MONTNEY GAS CONDENSATE COMPLEX

Tourmaline is currently operating 3 drilling rigs in the NEBC Montney complex and expects to drill a total of 24 new wells during the second quarter.  Two nine-well pads, drilled during Q1 of 2017, will be fracture stimulated and brought on production during Q2.  Completed well costs continue to trend down, due to a combination of steadily improving well design and execution.  The Company recently drilled a 1,381 m lateral at Doe in 5.06 days for $956K (spud to rig release), the current record for the area.  Tourmaline continues to drill and complete the lowest cost Montney wells in Canada, averaging $2.7 million for a completed 30-stage lateral.

The Doe 2-11 gas plant, the Company's third plant in the Sunrise-Dawson complex, came on production as planned during the last week of March.  NEBC Montney production levels are now 315 - 325 mmcfpd of natural gas and 7,000 - 7,500 bpd of condensate and NGLs.  Total condensate and NGL production at the new Doe 2-11 plant is averaging 3,900 bbls/day.  The Company's latest Montney turbidite horizontal at Sunrise-Doe is testing at 11.5 mmcfpd of gas and 755 bpd of condensate over the initial five days of production.

The development plan for Gundy Creek has been initiated.  The Company is operating one rig currently on the property with a second rig planned to commence operations in the third quarter of 2017.  Tourmaline plans to drill 75 wells at Gundy in 2017 and 2018 in advance of Company owned-and-operated gas processing facilities that will be commissioned during the second half of 2018.  Tourmaline conducts essentially all of its NEBC frac operations with recycled, non-potable water, sourced from Company-owned water recycling facilities constructed over the past four years.

The Gundy development, coupled with continued development of Sunrise-Dawson-Sundown is expected to bring total Company NEBC Montney production to approximately 600 mmcfpd and 20,000 bpd of condensate/NGLs by late 2018.

ALBERTA DEEP BASIN COMPLEX

Tourmaline is the largest Alberta Deep Basin operator with current production of 165,000 - 170,000 boepd.  The Company has achieved the production level through drilling only 350 horizontal wells from an inventory of approximately 6,250 horizontal locations all of which are economic at current pricing.  The Company was operating 11 drilling rigs in the complex during the first quarter of 2017 and is currently operating 4 rigs drilling on 6-7 well pads during Q2/break-up.  A 10-12 rig second half 2017 program is currently envisaged as over 90% of the 2017 Deep Basin capital program is dedicated to drilling and completion activity.  Current Company-operated processing capability through the eleven operated gas plants in the Deep Basin is approximately 1.0 bcf/day.

Extremely strong well results continue across the entire complex with average 30-day IP rates of 10.7 mmcfpd and 90-day IP rates of 7.4 mmcfpd plus liquids realized from all Deep Basin wells drilled during the past nine months. 

The Company will dedicate 1-2 drilling rigs in pursuit of higher liquid content horizons in the Deep Basin, following up on recent high condensate production rates realized from horizontals targeting Cretaceous formations other than the Notikewin-Falher-Wilrich package.  Total Company Alberta Deep Basin liquid production is currently in excess of 10,000 bpd.

PEACE RIVER HIGH TRIASSIC OIL COMPLEX

Tourmaline operated 3 drilling rigs during Q1 2017 in pursuit of Triassic Upper Charlie Lake, Lower Charlie Lake and Montney oil targets on the Peace River High.  Approximately 2,250 bpd of light oil was brought on-stream during the first quarter from the complex, with an additional 1,500 bpd brought on-stream thus far in the second quarter.

The Company has now drilled 15 horizontals into the Lower Charlie Lake formation with very strong well performance to date.  The Company believes this is a large new oil resource play that complements the Upper Charlie Lake development and the extensive infrastructure already constructed.  The average 30-day IP rate for the 13 Lower Charlie Lake wells on production is 372 bbls oil per day and 1,056 mcfpd of natural gas (548 boepd).  Average 60-day IP rate for the six Lower Charlie Lake wells with sufficient production duration is 344 bbls oil per day and 1.29 mmcfpd of natural gas (558 boepd).  The Company estimates an undrilled Lower Charlie Lake inventory of 284 gross locations that complements the existing Upper Charlie Lake inventory of 1,579 gross locations.

CORPORATE SUMMARY – FIRST QUARTER 2017






Three Months Ended March 31,



2017


2016

Change

OPERATIONS






Production







Natural gas (mcf/d)                      


1,194,380


1,033,792

16%


Crude oil and NGL (bbl/d)


34,215


23,529

45%


Oil equivalent (boe/d)


233,278


195,828

19%

Product prices(1)







Natural gas ($/mcf)

$

3.15

$

2.20

43%


Crude oil and NGL ($/bbl)

$

41.73

$

33.60

24%

Operating expenses ($/boe)

$

3.50

$

3.70

(5)%

Transportation costs ($/boe)

$

2.81

$

1.89

49%

Operating netback(3) ($/boe)

$

14.59

$

9.71

50%

Cash general and
administrative expenses ($/boe)(2)

$

0.48

$

0.42

14%

FINANCIAL
($000, except share and per share)






Revenue


466,645


279,108

67%

Royalties


27,851


6,569

324%

Cash flow(3)


292,933


159,430

84%

Cash flow per share (diluted)(3)

$

1.09

$

0.72

51%

Net earnings (loss)


99,534


(38,390)

359%

Net earnings (loss) per share (diluted)

$

0.37

$

(0.17)

318%

Capital expenditures
(net of dispositions)


399,385


414,857

(4)%

Weighted average shares outstanding (diluted)

269,394,040

221,403,764

22%

Net debt(3)


(1,695,281)


(1,802,230)

(6)%

(1)

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

(2)

Excluding interest and financing charges.

(3)

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

 

Conference Call Tomorrow at 8:00 a.m. MDT (10:00 a.m. EDT)

Tourmaline will host a conference call tomorrow, May 5, 2017 starting at 8:00 a.m. MDT (10:00 a.m. EDT).  To participate, please dial 1-888-231-8191 (toll-free in North America), or local dial-in 647-427-7450, a few minutes prior to the conference call.

Conference ID is 92124916.

Reader Advisories

CURRENCY

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

FORWARD-LOOKING INFORMATION

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

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

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

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

The forward-looking information contained in this news 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.

FINANCIAL OUTLOOK

Also included in this news release are estimates of Tourmaline's 2017 net debt to cash flow level at year-end as well as 2017 capital spending, which are based on, among other things, the various assumptions as to production levels, capital expenditures, and other assumptions disclosed in this news release and including Tourmaline's estimated 2017 average production of 240,000-260,000 boepd and commodity price assumptions for natural gas (AECO - $3.10/mcf for 2017), and crude oil (WTI (US) - $57.50/bbl for 2017) and an exchange rate assumption of $0.77 (US/CAD) for 2017. To the extent such estimates constitute a financial outlook, they were approved by management and the Board of Directors of Tourmaline on May 4, 2017 and are included to provide readers with an understanding of Tourmaline's anticipated net debt to cash flow based on the capital expenditure, production and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.

INITIAL PRODUCTION (IP) RATES

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

INDUSTRY METRICS

The term cash costs, while commonly used in the oil and gas industry, does not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.

ESTIMATED DRILLING INVENTORY

This news release discloses drilling locations based on four categories: (i) proved undeveloped locations; (ii) probable undeveloped locations; (iii) unbooked locations; and (iv) an aggregate total of (i), (ii) and (iii). Of the Company's 14,980 undrilled locations, which are disclosed herein, 906 are proved undeveloped locations, 20 are proved non-producing locations, 893 are probable undeveloped locations, nil are probable non-producing and 13,161 are unbooked. Proved undeveloped locations, proved non-producing locations, probable undeveloped locations and probable non-producing locations are booked and derived from the Company's most recent independent reserves evaluation as prepared by GLJ Petroleum Consultants Ltd. and Deloitte LLP as of December 31, 2016 and account for drilling locations that have associated proved and/or probable reserves, as applicable.

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

GENERAL

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

CERTAIN DEFINITIONS:




bbl                                               

barrel

bbls/day                                       

barrels per day

bbl/mmcf                                      

barrels per million cubic feet

bcf                                                

billion cubic feet

bpd or bbl/d                                  

barrels per day

boe                                               

barrel of oil equivalent

boepd or boe/d                              

barrel of oil equivalent per day

bopd or bbl/d                                

barrel of oil, condensate or liquids per day

FCP                                               

final circulating pressure

gj                                                   

gigajoule

gjs/d                                              

gigajoules per day

mbbls                                            

thousand barrels

mboe                                             

thousand barrels of oil equivalent

mcf                                                

thousand cubic feet

mcfpd or mcf/d                               

thousand cubic feet per day

mcfe                                              

thousand cubic feet equivalent

mmboe                                          

million barrels of oil equivalent

mmbtu                                           

million British thermal units

mmbtu/d                                        

million British thermal units per day

mmcf                                             

million cubic feet

mmcfpd or mmcf/d                        

million cubic feet per day

MPa                                              

megapascal

mstboe                                          

thousand stock tank barrels of oil equivalent

NGL                                              

natural gas liquids

 

MANAGEMENT'S DISCUSSION AND ANALYSIS

This management's discussion and analysis ("MD&A") should be read in conjunction with Tourmaline's unaudited interim condensed consolidated financial statements and related notes as at and for the three months ended March 31, 2017 and the consolidated financial statements for the year ended December 31, 2016.  The consolidated financial statements and the MD&A can be found at www.sedar.com.  This MD&A is dated May 4, 2017.

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

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

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

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

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

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

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

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

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

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

PRODUCTION














Three Months Ended
March 31,





2017

2016

Change

Natural gas (mcf/d)




1,194,380

1,033,792

16%

Oil (bbl/d)




15,871

13,545

17%

NGL (bbl/d)




18,344

9,984

84%

Oil equivalent (boe/d)




233,278

195,828

19%

Natural gas %




85%

88%


 

Production for the three months ended March 31, 2017 averaged 233,278 boe/d, a 19% increase over the average production for the same quarter of 2016 of 195,828 boe/d.  The increase in production is related to the Company's successful exploration and production program as well as property acquisitions over the past year.  Approximately 80% of the growth in production volumes since the first quarter of 2016 can be attributed to wells brought on stream from the Company's exploration and production program, after taking base decline into consideration. The remainder of the change relates to property acquisitions (net of dispositions) primarily the assets acquired from Shell Canada in the fourth quarter of 2016.  The growth in oil and NGL production is the result of increased drilling in the Spirit River/Peace River High Charlie Lake oil plays, incremental liquids recovered in the Wild River area via deep-cut processing, and strong condensate recoveries from new wells commencing production as the liquids-rich Montney Turbidite is developed in northeast British Columbia. 

Full-year average production guidance for 2017 is between 240,000-260,000 boe/d which is consistent with previous Company guidance released March 7, 2017 in the Company's December 31, 2016 MD&A.

REVENUE








Three Months Ended
March 31,

(000s)


2017


2016

Change

Revenue from:







Natural gas

$

320,755

$

174,251

84%


Oil and NGL


128,317


59,292

116%

Realized gain from:







Natural gas


17,375


32,919

(47)%


Oil and NGL                         


198


12,646

(98)%

Total revenue from natural gas,
oil and NGL sales

$

466,645

$

279,108

67%

 

Revenue for the three months ended March 31, 2017 increased 67% to $466.6 million from $279.1 million for the same quarter of 2016.  Higher revenue for the period is consistent with the significant increase in realized commodity prices and higher production volumes, partially offset by lower realized gains on energy marketing and hedging activities.  Revenue includes all petroleum, natural gas and NGL sales and the realized gain on financial instruments.

Revenue for the first quarter of 2017, included a gain on commodity contracts of $17.6 million compared to a gain of $45.6 million for the same period of the prior year.  Realized gains on commodity contracts for the three months ended March 31, 2017 have decreased compared to the same period of the prior year primarily due to a lower premium received on commodity contracts relative to the benchmark commodity prices in the first quarter of 2017.  Realized prices exclude the effect of unrealized gains or losses on commodity contracts.  Once these gains and losses are realized they are included in the per-unit amounts.

TOURMALINE REALIZED PRICES:










Three Months Ended
March 31,





2017


2016

Change

Natural gas ($/mcf)



$

3.15

$

2.20

43%

Oil ($/bbl)



$

63.37

$

49.70

28%

NGL ($/bbl)



$

23.02

$

11.75

96%

Oil equivalent ($/boe)



$

22.23

$

15.66

42%

 

BENCHMARK OIL AND GAS PRICES:










Three Months Ended
March 31,





2017


2016

Change

Natural gas









NYMEX Henry Hub (USD$/mcf)



$

3.06

$

1.98

55%


AECO (CAD$/mcf)



$

2.69

$

1.83

47%


West Coast Station 2 (CAD$/mcf)



$

2.36

$

1.33

77%


ATP 5A Day Ahead (CAD$/GJ)



$

2.93

$

1.86

58%


PG&E Malin (USD$/mmbtu)



$

2.84

$

1.89

50%


PG&E City Gate (USD$/mmbtu)



$

3.34

$

2.20

52%

Oil









NYMEX (USD$/bbl)



$

51.78

$

33.63

54%


Edmonton Par (CAD$/bbl)



$

64.71

$

41.39

56%

 

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








Three Months Ended
March 31,

($/mcf)



2017


2016

Change

Weighted average index natural gas prices


$

2.77

$

1.72

61%

Heat/quality differential



0.22


0.13

69%

Realized gain



0.16


0.35

(54)%

Tourmaline realized natural gas price


$

3.15

$

2.20

43%

Premium to AECO pricing due to higher heat content



8%


8%


 

CURRENCY – EXCHANGE RATES:










Three Months Ended
March 31,





2017


2016

Change

CAD$/USD$ (1)



$

0.7554

$

0.7288

4%

(1)

Average rates for the period.

 

The realized average natural gas price for the three months ended March 31, 2017 was $3.15/mcf, which is 43% higher than the same period of the prior year.  The increase reflects higher natural gas benchmark prices in the quarter which were partially offset by lower realized gains on commodity contracts.

Realized oil prices increased by 28% for the three months ended March 31, 2017 compared to the same period of the prior year.  The increase in price reflects the higher benchmark price for oil, partially offset by the lower gains on commodity contracts.

NGL prices for the first quarter of 2017 increased 96% from $11.75/bbl to $23.02/bbl, when compared to the same quarter of 2016.  The increase in NGL prices is consistent with the increase in benchmark commodity prices over the same periods.   Additionally, in the first quarter of 2016, the price of propane was significantly discounted due to oversupply in the market, which has since recovered.

ROYALTIES














Three Months Ended
March 31,

(000s)



2017


2016

Natural gas


$

13,212

$

1,413

Oil and NGL



14,639


5,156

Total royalties


$

27,851

$

6,569

Royalties as a percentage of revenue



6.2%


2.8%

 

For the quarter ended March 31, 2017, the average effective royalty rate was 6.2% compared to the rate of 2.8% for the same quarter of 2016.  The increase in the average effective royalty rate for 2017 can primarily be attributed to significantly higher commodity prices received during the period as well as the adoption of the Modernized Royalty Framework ("MRF").

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 Company also receives gas cost allowance from the Crown, which further reduces royalties to account for expenses incurred to process and transport the Crown's portion of natural gas production.

On January 1, 2017, the Company adopted the MRF introduced by the Alberta Government in 2016.  This new royalty regime is applicable to all new wells drilled beginning January 1, 2017, and all other wells drilled prior to January 1, 2017 will follow the old framework for a further 10 years.  The Company believes that the MRF is generally consistent with the initial goal of incentivizing the use of technology to improve productivity and rewards producers deploying the most competitive operating practices.  Under the new framework, the Company anticipates an increase in the corporate royalty rate but based on the Company's current development plans and operational practices, the increase is not expected to be significant.

The Company expects its royalty rate for 2017 to be approximately 8%, consistent with the previous Company guidance contained in the Company's December 31, 2016 MD&A.  The royalty rate is sensitive to commodity prices, and as such, a change in commodity prices, will impact the actual rate.

OTHER INCOME























Three Months Ended
March 31,

(000s)





2017


2016

Change

Other income




$

7,179

$

6,481

11%

 

Other income increased from $6.5 million in the first quarter of 2016 to $7.2 million for the same quarter of 2017.  The increase in other income is due to additional processing capacity acquired from the Shell Canada asset acquisition in the fourth quarter of 2016, some of which processes additional third-party production.

OPERATING EXPENSES

















Three Months Ended
March 31,

(000s) except per unit amounts



2017


2016

Change

Operating expenses


$

73,433

$

65,890

11%

Per boe


$

3.50

$

3.70

(5)%

 

Operating expenses include all periodic lease and field-level expenses and exclude income recoveries from processing third-party volumes.  For the first quarter of 2017, total operating expenses were $73.4 million compared to $65.9 million in 2016, an increase of 11% over a production base increase of 19% for the same period.

On a per-boe basis, the costs decreased from $3.70/boe for the first quarter of 2016 to $3.50/boe in the first quarter of 2017.  Along with a commitment to continue to drive down the overall cost structure, the Company continues to realize increased operational efficiencies in all three core areas along with fixed costs being distributed over a significantly higher production base.

The Company expects full year 2017 operating expenses per boe to increase slightly over the first quarter rate due to higher expenses related to managing a larger base as well as additional volumes flowing through deep cut processing, which bears higher operating expenses.  The Company's average operating cost target is approximately $3.60/boe in 2017 which is unchanged from the previous guidance released March 7, 2017.  Actual operating costs per boe can change, however, depending on a number of factors, including the Company's actual production levels.

TRANSPORTATION




















Three Months Ended
March 31,

(000s) except per unit amounts




2017


2016

Change

Natural gas transportation



$

45,978

$

25,583

80%

Oil and NGL transportation




13,121


8,042

63%

Total transportation



$

59,099

$

33,625

76%

Per boe



$

2.81

$

1.89

49%

 

For the first quarter of 2017, total transportation expenses were $59.1 million compared to $33.6 million in 2016, reflecting increased costs related to higher production volumes. 

On a per-boe basis, the costs increased from $1.89/boe for the first quarter of 2016 to $2.81/boe in the first quarter of 2017.  The per-unit costs in the first quarter of 2017 reflect additional costs of transporting natural gas to Malin, Oregon and City Gate, California which commenced in the second half of 2016, where the Company received a higher price for its natural gas.  The increased distance resulted in higher per-boe fuel and transportation costs.  Additionally, pipeline tolls for natural gas transportation have also increased in 2017 compared to 2016.

GENERAL & ADMINISTRATIVE EXPENSES ("G&A")













Three Months Ended
March 31,

(000s) except per unit amounts




2017


2016

Change

G&A expenses



$

16,875

$

14,805

14%

Administrative and capital recovery




(1,568)


(1,143)

37%

Capitalized G&A




(5,243)


(6,121)

(14)%

Total G&A expenses



$

10,064

$

7,541

33%

Per boe



$

0.48

$

0.42

14%

 

Total G&A expenses in the first quarter of 2017 were $10.1 million compared to $7.5 million for the same quarter of 2016.  The increase is primarily due to staff and office space additions needed to manage the larger production, reserve and land base, as well as higher professional and industry fees and third party service provider fees.  The increase in administrative and capital recoveries in the first quarter of 2017 compared to 2016 can be attributed to higher recoveries received from partners related to the increase in capital exploration and production activities in the first quarter of 2017 compared to the first quarter of 2016.

On a per-boe basis, G&A expenses increased from $0.42/boe for the first quarter of 2016 to $0.48/boe in the first quarter of 2017.  The per-boe increase reflects a lower percentage of capitalized G&A in the first quarter of 2017 due to more support staff required to manage a larger production base.

As production continues to increase in 2017, the G&A costs per boe are expected to decrease and average approximately $0.45/boe which is unchanged from the previous guidance released March 7, 2017.  Actual G&A 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
March 31,

(000s) except per unit amounts




2017


2016

Share-based payments



$

10,274

$

12,418

Capitalized share-based payments




(5,137)


(6,209)

Total share-based payments



$

5,137

$

6,209

Per boe



$

0.24

$

0.35

 

The Company uses the fair value method for the determination of non-cash related share-based payments expense.  During the first quarter of 2017, 439,500 stock options were granted to employees, officers, directors and key consultants at a weighted-average exercise price of $30.47 and 98,133 options were exercised, resulting in $2.2 million of cash proceeds.

The Company recognized $5.1 million of share-based payments expense in the first quarter of 2017 compared to $6.2 million in the first quarter of 2016.  Capitalized share-based payments for the first quarter of 2017 were $5.1 million compared to $6.2 million for the same period of the prior year.

Share-based payments are lower in 2017 compared to the same period of 2016, which reflects options with a lower fair value being expensed in 2017 compared to 2016.

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









Three Months Ended
March 31,

(000s) except per unit amounts



2017


2016

Total depletion, depreciation and amortization


$

188,674

$

180,939

Less mineral lease expiries



(6,501)


(5,921)

Depletion, depreciation and amortization


$

182,173

$

175,018

Per boe


$

8.68

$

9.82

 

DD&A expense, excluding mineral lease expiries, was $182.2 million for the first quarter of 2017 compared to $175.0 million for the same period of 2016.  The increase in DD&A expense in 2017 over 2016 is due to higher production volumes.

The per-unit DD&A rate (excluding the impact of mineral lease expiries) was $8.68/boe for the first quarter of 2017 compared to the rate of $9.82/boe for the same quarter of 2016.  The decrease in per-boe depletion in 2017 compared to 2016 can be attributed to lower future development costs as drilling and completion costs have decreased over the past year thereby adding a higher proportion of reserves with lower associated future development costs, resulting in a lower depletion rate.

Mineral lease expiries for the three months ended March 31, 2017 were $6.5 million, compared to expiries in the same quarter of the prior year of $5.9 million.  The Company prioritizes drilling on what it believes to be the most cost-efficient and productive acreage, and with such a large land base, the Company has chosen not to continue some of the expiring sections of land.   The Company explores all alternatives (including swaps, farm-outs and dispositions) to realize the value from these sections before they expire.

FINANCE EXPENSES














Three Months Ended
March 31,

(000s)



2017


2016

Change

Interest expense


$

10,075

$

10,859

(7)%

Accretion expense



1,198


790

52%

Foreign exchange (gain) on U.S. denominated debt



(506)


(72,759)

99%

Realized loss on cross-currency swaps



506


72,759

(99)%

Realized loss on interest rate swaps



750


900

(17)%

Transaction costs on corporate and property acquisitions



52


178

(71)%

Total finance expenses


$

12,075

$

12,727

(5)%

 

Finance expenses for the three months ended March 31, 2017 totaled $12.1 million compared to $12.7 million for the same period of 2016.  The decrease in finance expenses in 2017 over 2016 is mainly due to the lower average bank debt outstanding.  The average bank debt outstanding and the average effective interest rate on the debt for the three months ended March 31, 2017 was $1,466.8 million and 2.44%, respectively (three months ended March 31, 2016$1,571.8 million and 2.45% respectively).

In the first quarter of 2017, the Company drew from the credit facility in U.S. dollars, as permitted under the credit facility, which when repaid created a foreign exchange gain.  Concurrent with the draw of U.S. dollar denominated borrowings, the Company entered into cross-currency swaps to manage the foreign currency risk resulting from holding U.S. dollar denominated borrowings.  The Company fixed the Canadian dollar amount for purposes of principal and interest repayment resulting in a gain on cross-currency swaps equivalent to the realized foreign exchange gain.  This transaction allows the Company to take advantage of the interest rate spread between CDOR and LIBOR without taking on foreign exchange risk.

DEFERRED INCOME TAXES (RECOVERY)

For the three months ended March 31, 2017, the provision for deferred income tax expense was $41.4 million compared to deferred income tax recovery of $12.9 million for the same period in 2016.  The deferred income tax expense is primarily due to the pre-tax income of $141.1 million recorded in the first quarter of 2017 compared to a pre-tax loss of $52.1 million in the same period of 2016.

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













Three Months Ended
March 31,

(000s) except per unit amounts




2017


2016

Change

Cash flow from operating activities



$

338,005

$

176,308

92%


Per share (1)                     



$

1.25


$0.80

56%

Cash flow (2)



$

292,933

$

159,430

84%


Per share (1)(2)



$

1.09

$

0.72

51%

Net earnings (loss)



$

99,534

$

(38,390)

359%


Per share (1)



$

0.37

$

(0.17)

318%

Operating netback per boe (2)



$

14.59

$

9.71

50%

(1)

Per share amounts have been calculated using the weighted average number of diluted common shares except the net earnings (loss) per share amounts in periods which Tourmaline has reported a net loss.  In these periods, the weighted average number of basic common shares has been used as there is an anti-dilutive impact on per-share calculations.  For the three months ended March 31, 2017, the weighted average number of common shares – diluted is 269,394,040 (March 31, 2016 - 221,493,414 common shares excluding the anti-dilutive impact).

(2)

See "Non-GAAP Financial Measures".

 

Cash flow for the three months ended March 31, 2017 was $292.9 million or $1.09 per diluted share compared to $159.4 million or $0.72 per diluted share for the same period of 2016.

The Company had after-tax net income for the three months ended March 31, 2017 of $99.5 million or $0.37 per diluted share compared to an after-tax net loss of $38.4 million or $0.17 per share for the same period of 2016.  The increase in both cash flow and after-tax net earnings in 2017 reflects significantly higher realized oil, natural gas and NGL prices and an increase in production over 2016.

CAPITAL EXPENDITURES





















Three Months Ended
March 31,

(000s)





2017


2016

Land and seismic




$

16,873

$

2,352

Drilling and completions





241,290


150,643

Facilities





134,799


90,839

Property acquisitions





795


182,708

Property dispositions






(18,000)

Other





5,628


6,315

Total cash capital expenditures




$

399,385

$

414,857

 

During the first quarter of 2017, the Company invested $399.4 million of cash consideration, net of dispositions, compared to $414.9 million for the same period of 2016.  Expenditures on exploration and production were $393.0 million compared to $243.8 million for the same quarter of 2016.  The drilling and completion costs of $241.3 million in 2017 include 143.02 net wells drilled and completed compared to $150.6 million spent on 70.11 net wells drilled and completed in the first quarter of 2016.  The lower costs per well reflect the Company's continuously improving operating practices, combined with reduced drilling and completion service costs.  

Facilities expenditures in the quarter include costs associated with the new Doe Gas Plant, which was commissioned in the first quarter of 2017, the Wildhay compressor expansion as well as the Mulligan marketing terminal which are both expected to be commissioned in 2017.

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





Three Months Ended
March 31, 2017


Three Months Ended
March 31, 2016





Gross

Net


Gross

Net

Drilled




107

91.71


27

25.28

Completed (1)




62

51.31


49

44.83

Tied-in




74

66.86


50

45.70

(1)

A multi-well pad is included as a single completion.   

 

Acquisitions and Dispositions

2016

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

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

On November 30, 2016, the Company acquired assets from Shell Canada located in the Alberta Deep Basin and the North East B.C. Gundy area for total consideration of $1,367.8 million, including cash consideration of $1,000.1 million and 10,017,938 Tourmaline common shares at a deemed price of $36.70, before customary adjustments.  The acquisition resulted in an increase in PP&E of approximately $1,333.4 million, an increase in E&E assets of $38.5 million, and the assumption of $4.1 million in decommissioning liabilities.  Total transaction costs incurred by the Company of $1.6 million were associated with this acquisition and expensed in the consolidated statement of income (loss) and comprehensive income (loss).  The assets acquired include land interests, production, reserves and facilities.

On December 23, 2016, the Company sold 50% of its interest in the planned Mulligan marketing terminal in the Gordondale area of Alberta for $30.0 million, before customary adjustments.

LIQUIDITY AND CAPITAL RESOURCES

The Company has a covenant-based, unsecured, bank credit facility in place with a syndicate of banks, the details of which are described in note 9 of the Company's consolidated financial statements for the year ended December 31, 2016 and in note 7 of the Company's unaudited interim condensed financial statements for the three months ended March 31, 2017.  This is an extendible revolving facility in the amount of $1,800.0 million with an initial maturity date of June 2020.  The maturity date may, at the request of the Company and with consent of the lenders, be extended on an annual basis.  The credit facility includes an expansion feature ("accordion") which allows the Company, upon approval from the lenders, to increase the facility amount by up to $500.0 million by adding a new financial institution or by increasing the commitment of its existing lenders.  The Company also has a $50.0 million operating revolver, resulting in total bank credit facility capacity of $1,850.0 million.  The facility can be drawn in either Canadian or U.S. funds and bears interest at the bank's prime lending rate, banker's acceptance rates or LIBOR (for U.S. borrowings), plus applicable margins, which range from 0.50% to 3.90% depending on the type of borrowing and the Company's senior debt to adjusted EBITDA ratio.

The Company also has a term loan with a syndicate of banks.  On February 3, 2017, the Company increased the term loan from $250.0 million to $650.0 million and extended its maturity date to February 2022.  The term loan can be drawn in either Canadian or U.S. funds and bears interest at the bank's prime lending rate, banker's acceptance rates or LIBOR (for U.S. borrowings), plus 200 basis points.  With the exception of the increase in amount and maturity date extension the term debt was renewed under the same terms and conditions as those outlined in note 9 of the Company's consolidated financial statements for the year ended December 31, 2016.  The maturity date may, at the request of the Company and with consent of the lender, be extended on an annual basis.  The covenants for the term loan are the same as those under the Company's current credit facility and the term loan will rank equally with the obligation under the Company's credit facility.

The Company's aggregate borrowing capacity is now $2,500.0 million.

As at March 31, 2017, the Company had negative working capital of $337.2 million, after adjusting for the fair value of financial instruments (the unadjusted working capital deficiency was $355.1 million) (December 31, 2016$184.3 million and $223.8 million, respectively).  As at March 31, 2017, the Company had $647.8 million in long-term debt outstanding and $710.3 million drawn against the revolving credit facility for total bank debt of $1,358.1 million (net of prepaid interest and debt issue costs) (December 31, 2016 - $1,406.6 million).  Net debt at March 31, 2017 was $1,695.3 million (December 31, 2016 - $1,590.9 million).

For 2017, management intends to continue matching the capital budget to the expected annual cash flow and as such management believes the Company has sufficient resources to fund its 2017 exploration and development program.  As at March 31, 2017, the Company also has $1,123.3 million in unutilized borrowing capacity.  The 2017 exploration and development program will continue to be diligently monitored and adjusted as necessary depending on commodity prices in order to remain consistent with cash flow.  Management is dedicated to keeping a strong balance sheet, which has proven to be very important, especially in the current commodity price environment.

SHARES AND STOCK OPTIONS OUTSTANDING

As at May 4, 2017, the Company has 269,168,945 common shares and 20,493,864 stock options outstanding.

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

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

PAYMENTS DUE BY YEAR






















(000s)


1 Year


2-3 Years


4-5 Years


>5 Years


Total

Operating leases

$

5,736

$

10,875

$

-

$

-

$

16,611

Firm transportation and processing agreements


244,514


550,526


568,801


1,487,242


2,851,083

Capital commitments (1)


316,329


609,852


158,010


34,221


1,118,412

Flow-through share commitments


62,731


-


-


-


62,731

Credit facility (2)


-


-


777,112


-


777,112

Term debt (3)


19,091


38,182


684,671


-


741,944


$

648,401

$

1,209,435

$

2,188,594

$

1,521,463

$

5,567,893

(1)

Includes drilling commitments, and capital spending commitments under the joint arrangement in the Spirit River complex of $300.0 million per year from 2015 to 2019.  The capital spending commitment can be deferred to future periods in the event of an economic downturn, and as agreed upon by both parties.  In 2016, an economic downturn event resulted in $216.0 million of capital spending being deferred into future periods.

(2)

Includes interest expense at an annual rate of 2.64% being the rate applicable to outstanding debt on the credit facility at March 31, 2017.

(3)

Includes interest expense at an annual rate of 2.94% being the fixed rate on the term debt at March 31, 2017.

 

OFF BALANCE SHEET ARRANGEMENTS

The Company has certain lease arrangements, all of which are reflected in the commitments and contractual obligations table above, 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, 2016.

As at March 31, 2017, the Company has entered into certain financial derivative contracts in order to manage commodity price and interest rate risk.  These instruments are not used for trading or speculative purposes.  The Company has not designated its financial derivative contracts as effective accounting hedges, even though the Company considers all commodity contracts to be effective economic hedges.  Such financial derivative contracts are recorded on the consolidated statement of financial position at fair value, with changes in the fair value being recognized as an unrealized gain (loss) on the consolidated statement of income (loss) and comprehensive income (loss).  The contracts that the Company has in place at March 31, 2017 are summarized and disclosed in note 3 of the Company's unaudited interim condensed consolidated financial statements for the three months ended March 31, 2017 and 2016.

The Company has entered into physical delivery sales contracts to manage commodity risk.  These contracts are considered normal sales contracts and are not recorded at fair value in the consolidated financial statements.  Physical contracts in place at March 31, 2017 have been summarized and disclosed in note 3 of the Company's unaudited interim condensed consolidated financial statements for the three months ended March 31, 2017 and 2016.

Financial derivative and physical delivery contracts entered into subsequent to March 31, 2017 are detailed in note 3 of the Company's unaudited interim condensed consolidated financial statements for the three months ended March 31, 2017 and 2016.

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, 2016.

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING

The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures ("DC&P"), as defined by National Instrument 52-109. The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal controls over financial reporting ("ICFR"), as defined by National Instrument 52-109, to provide reasonable assurance regarding the reliability of the Company's financial reporting and the preparation of financial statements for external purposes in accordance with IFRS.

There were no changes in the Company's DC&P or ICFR during the period beginning on January 1, 2017 and ending on March 31, 2017 that have materially affected, or are reasonably likely to materially affect, the Company's ICFR.  It should be noted that a control system, including the Company's disclosure and internal controls and procedures, no matter how well conceived can provide only reasonable, but not absolute assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

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

BUSINESS RISKS AND UNCERTAINTIES

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

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

IMPACT OF ENVIRONMENTAL REGULATIONS

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

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

NON-GAAP FINANCIAL MEASURES

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

Cash Flow

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




Three Months Ended
March 31,

(000s)



2017


2016

Cash flow from operating activities (per GAAP)


$

338,005

$

176,308

Change in non-cash working capital



(45,072)


(16,878)

Cash flow


$

292,933

$

159,430

 

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
March 31,

($/boe)





2017


2016

Revenue, excluding processing income




$

22.23

$

15.66

Royalties





(1.33)


(0.37)

Transportation costs





(2.81)


(1.89)

Operating expenses





(3.50)


(3.70)

Operating netback (1)




$

14.59

$

9.71

(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
March 31,
2017


As at
December 31,
2016

Working capital (deficit)


$

(355,097)

$

(223,781)

Fair value of financial instruments – short-term (net)



17,906


39,517

Working capital (deficit) (adjusted for the fair value
of financial instruments)


$

(337,191)

$

(184,264)

 

Net Debt

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

(000s)



As at
March 31,
2017


As at
December 31,
2016

Bank debt


$

(1,358,090)

$

(1,406,586)

Working capital (deficit)



(355,097)


(223,781)

Fair value of financial instruments – short-term (net)



17,906


39,517

Net debt


$

(1,695,281)

$

(1,590,850)


 

SELECTED QUARTERLY INFORMATION















2017





2016




2015

($000s, unless otherwise noted)


Q1


Q4

Q3

Q2

Q1


Q4

Q3

Q2

PRODUCTION












Natural gas (mcf)


107,494,272


90,409,566

82,363,542

89,091,644

94,075,078


85,328,135

72,395,759

69,606,629

Oil and NGL(bbls)


3,079,321


2,578,571

1,852,618

2,060,260

2,141,099


2,302,708

1,761,403

1,469,591

Oil equivalent (boe)


20,995,033


17,646,832

15,579,875

16,908,867

17,820,279


16,524,064

13,827,363

13,070,696

Natural gas (mcf/d)


1,194,380


982,713

895,256

979,029

1,033,792


927,480

786,910

764,908

Oil and NGL (bbls/d)


34,215


28,028

20,138

22,640

23,529


25,030

19,146

16,149

Oil equivalent (boe/d)


233,278


191,814

169,347

185,812

195,828


179,610

150,297

143,634

FINANCIAL












Total revenue from natural gas,
oil and NGL sales, net of royalties


438,794


366,697

292,495

238,572

272,539


353,478

297,889

293,752

Cash flow from operating activities


338,005


192,134

185,067

143,392

176,308


228,959

261,398

151,028

Cash flow (1)


292,933


252,542

185,531

134,298

159,430


242,351

197,100

203,029


Per diluted share


1.09


1.02

0.79

0.58

0.72


1.10

0.90

0.95

Net earnings (loss)


99,534


59,621

24,738

(77,940)

(38,390)


34,636

28,489

(5,197)


Per basic share


0.37


0.24

0.11

(0.34)

(0.17)


0.16

0.13

(0.02)


Per diluted share


0.37


0.24

0.10

(0.34)

(0.17)


0.16

0.13

(0.02)

Total assets


9,612,395


9,357,523

7,790,816

7,694,141

7,844,728


7,640,671

7,471,042

7,071,801

Working capital (deficit)


(355,097)


(223,781)

(162,280)

(60,567)

(201,588)


(247,391)

(297,698)

(70,156)

Working capital (deficit)
(adjusted for the fair value of
financial instruments) (1)


(337,191)


(184,264)

(148,431)

(43,755)

(227,133)


(283,783)

(339,177)

(86,090)

Cash capital expenditures


399,385


1,244,974

224,448

49,010

414,857


325,499

422,629

290,629

Total outstanding
shares (000s)


269,169


268,596

234,966

234,161

221,484


221,336

 

220,813

216,378

PER UNIT












Natural gas ($/mcf)


3.15


3.20

2.80

1.87

2.20


2.99

3.20

3.17

Oil and NGL ($/bbl)


41.73


38.42

39.98

38.94

33.60


47.65

45.91

53.34

Revenue ($/boe)


22.23


22.01

19.54

14.61

15.66


22.08

22.61

22.85

Operating netback ($/boe) (1)


14.59


15.00

12.69

8.63

9.71


15.22

15.06

16.37

(1)

See Non-GAAP Financial Measures.

 

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

On an annual basis, the Company has had continued production growth over the last two years.  The Company's average annual production has increased from 154,403 boe per day in 2015 to 185,672 boe per day in 2016 and 233,278 boe per day in the first three months of 2017.  The production growth can be attributed primarily to the Company's exploration and development activities, and from acquisitions of producing properties.

The Company's cash flow was $850.2 million in 2015, $731.8 million in 2016 and forecast 2017 forecast cash flow is $1,411.4 million.  The increase in forecast cash flow in 2017 reflects the increase in commodity prices for 2017 compared to 2016 as well as the significant increase in production.  Commodity price fluctuations can indirectly impact expected production by changing the amount of funds available to reinvest in exploration, development and acquisition activities in the future.  Changes in commodity prices impact revenue and cash flow available for exploration, and also the economics of potential capital projects as low commodity prices can potentially reduce the quantities of reserves that are commercially recoverable.  The Company's capital program is dependent on cash flow generated from operations and access to capital markets.

INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION








March 31,


December 31,

(000s) (unaudited)


2017


2016

Assets





Current assets:






Accounts receivable

$

208,576

$

201,288


Prepaid expenses and deposits


9,428


10,575


Fair value of financial instruments (note 3)


4,885


895

Total current assets


222,889


212,758

Long-term asset


5,871


6,034

Fair value of financial instruments (note 3)


4,232


2,990

Exploration and evaluation assets (note 4)


688,928


678,531

Property, plant and equipment (note 5)


8,690,475


8,457,210

Total Assets

$

9,612,395

$

9,357,523

Liabilities and Shareholders' Equity





Current liabilities:






Accounts payable and accrued liabilities

$

555,195

$

396,127


Fair value of financial instruments (note 3)


22,791


40,412

Total current liabilities


577,986


436,539

Bank debt (note 7)


1,358,090


1,406,586

Fair value of financial instruments (note 3)


23,276


40,266

Deferred premium on flow-through shares (note 9)


12,141


16,167

Decommissioning obligations (note 6)


223,188


212,669

Deferred taxes


522,427


477,015

Shareholders' equity:






Share capital (note 9)


5,836,662


5,818,867


Non-controlling interest (note 8)


27,704


27,549


Contributed surplus


198,405


188,883


Retained earnings


832,516


732,982

Total shareholders' equity


6,895,287


6,768,281

Total Liabilities and Shareholders' Equity

$

9,612,395

$

9,357,523

Commitments (note 12).

Subsequent events (note 3).

See accompanying notes to the interim condensed consolidated financial statements.

 

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










Three Months Ended
March 31
,

(000s) except per-share amounts (unaudited)



2017


2016

Revenue:







Oil and natural gas sales


$

449,072

$

233,544


Royalties



(27,851)


(6,569)


Net revenue from oil and natural gas sales



421,221


226,975


Realized gain on financial instruments



17,573


45,564


Unrealized gain (loss) on financial instruments (note 3)



39,843


(28,643)


Other income



7,179


6,481

Total net revenue



485,816


250,377

Expenses:







Operating



73,433


65,890


Transportation



59,099


33,625


General and administration



10,064


7,541


Share-based payments (note 11)



5,137


6,209


Depletion, depreciation and amortization



188,674


180,939


Realized foreign exchange (gain)



(677)



Unrealized foreign exchange loss



159



(Gain) on divestitures



(3,233)


(4,453)

Total expenses



332,656


289,751

Income (loss) from operations



153,160


(39,374)

Finance expenses



12,075


12,727

Income (loss) before taxes



141,085


(52,101)

Deferred taxes (recovery)



41,396


(12,943)

Net income (loss) and comprehensive income (loss)
before non-controlling interest



99,689


(39,158)

Net income (loss) and comprehensive income (loss) attributable to:







Shareholders of the Company



99,534


(38,390)


Non-controlling interest (note 8)



155


(768)



$

99,689

$

(39,158)

Net income (loss) per share attributable
to common shareholders
(note 10)







Basic


$

0.37

$

(0.17)


Diluted


$

0.37

$

(0.17)

See accompanying notes to the interim condensed consolidated financial statements.

 

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY







(000s) (unaudited)

Share Capital

Contributed
Surplus

Retained
Earnings

Non-
Controlling
Interest

Total Equity

Balance at December 31, 2016

$

5,818,867

$

188,883

$

732,982

$

27,549

$

6,768,281

Issue of common shares on acquisitions (note 9)


14,853


-


-


-


14,853

Share issue costs, net of tax


(27)


-


-


-


(27)

Share-based payments


-


5,137


-


-


5,137

Capitalized share-based payments


-


5,137


-


-


5,137

Options exercised (notes 9 and 11)


2,969


(752)


-


-


2,217

Income attributable to common shareholders


-


-


99,534


-


99,534

Income attributable to non-controlling interest


-


-


-


155


155

Balance at March 31, 2017

$

5,836,662

$

198,405

$

832,516

$

27,704

$

6,895,287























(000s) (unaudited)

Share Capital

Contributed
Surplus

Retained
Earnings

Non-
Controlling
Interest

Total Equity

Balance at December 31, 2015

$

4,266,234

$

171,958

$

764,953

$

28,431

$

5,231,576

Share issue costs, net of tax


(80)


-


-


-


(80)

Share-based payments


-


6,209


-


-


6,209

Capitalized share-based payments


-


6,209


-


-


6,209

Options exercised (notes 9 and 11)


5,130


(1,437)


-


-


3,693

Loss attributable to common shareholders


-


-


(38,390)


-


(38,390)

Loss attributable to non-controlling interest


-


-


-


(768)


(768)

Balance at March 31, 2016

$

4,271,284

$

182,939

$

726,563

$

27,663

$

5,208,449

See accompanying notes to the interim condensed consolidated financial statements.

 

CONSOLIDATED STATEMENTS OF CASH FLOW


















Three Months Ended
March 31,

(000s) (unaudited)




2017


2016

Cash provided by (used in):







Operations:







Net income (loss)



$

99,534

$

(38,390)

Items not involving cash:









Depletion, depreciation and amortization




188,674


180,939



Accretion




1,198


790



Share-based payments




5,137


6,209



Deferred taxes (recovery)




41,396


(12,943)



Unrealized (gain) loss on financial instruments




(39,843)


28,643



(Gain) on divestitures




(3,233)


(4,453)



Amortization on long-term asset




163


163



Non-controlling interest




155


(768)


Unrealized foreign exchange loss




159



Decommissioning expenditures




(407)


(760)


Changes in non-cash operating working capital




45,072


16,878

Total cash flow from operating activities




338,005


176,308

Financing:








Issue of common shares




2,217


3,693


Share issue costs




(37)


(109)


Increase (decrease) in bank debt




(48,496)


308,493

Total cash flow from (used in) financing activities




(46,316)


312,077

Investing:








Exploration and evaluation




(31,780)


(4,634)


Property, plant and equipment




(366,810)


(245,515)


Property acquisitions




(795)


(182,708)


Proceeds from divestitures




-


18,000


Changes in non-cash investing working capital




107,696


(73,528)

Total cash flow used in investing activities




(291,689)


(488,385)

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 INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As at March 31, 2017 and for the three months ended March 31, 2017 and 2016

(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. 

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 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, 2016.

These unaudited interim condensed consolidated financial statements are presented in Canadian dollars and include the accounts of Tourmaline Oil Corp., and its 90.6% owned subsidiary Exshaw Oil Corp. (note 8), which both have a functional currency in Canadian dollars.  Tourmaline Oil Corp. also includes its 100% owned subsidiary Tourmaline Oil Marketing Corp., which has a functional currency in US dollars.

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, 2016, except as noted below.

On January 1, 2017, the Company adopted the amendments made to IAS 7 – Statement of Cash Flows, which require disclosures that enable users of the financial statements to evaluate changes in liabilities arising from financing activities, including both changes arising from cash flow and non-cash changes.  There was no impact to the Company as a result of adopting the amended standard.

These unaudited interim condensed consolidated financial statements reflect only the Company's proportionate interest in such activities.  The unaudited interim condensed consolidated financial statements were authorized for issue by the Board of Directors on May 4, 2017.

2.  DETERMINATION OF FAIR VALUE

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

Tourmaline classifies the fair value of transactions according to the following hierarchy based on the amount of observable inputs used to value the instrument.

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices are either directly or indirectly observable as of the reporting date.  Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

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

3.  FINANCIAL RISK MANAGEMENT

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

The Company's risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company's activities.  The Company's financial risks are consistent with those discussed in note 5 of the Company's consolidated financial statements for the year ended December 31, 2016.

As at March 31, 2017, the Company has entered into certain financial derivative contracts in order to manage commodity price, foreign exchange and interest rate risk.  These instruments are not used for trading or speculative purposes.  The Company has not designated its financial derivative contracts as effective accounting hedges, even though the Company considers all commodity and interest rate contracts to be effective economic hedges.  As a result, all such contracts are recorded on the interim consolidated statement of financial position at fair value, with changes in the fair value being recognized as an unrealized gain or loss on the interim consolidated statement of income (loss) and comprehensive income (loss).

The Company has the following financial derivative contracts in place as at March 31, 2017 (1):




2017


2018


2019


2020

Fair Value
(000s)

Gas












AECO  swaps

mmbtu/d


18,956




$

1,708


CAD$/mmbtu

$

3.15









NYMEX swaps

mmbtu/d


85,564


4,932



$

(6,677)


USD$/mmbtu

$

3.11

$

3.11







NYMEX call options (writer) (2)

mmbtu/d


110,000


110,000


90,000


20,000

$

(23,564)


USD$/mmbtu

$

3.52

$

3.68

$

3.94

$

3.75



Oil












Financial swaps

bbls/d


4,500


1,000



$

1,637


USD$/bbl

$

51.56

$

55.65







Financial call swaptions (3)

bbls/d


2,000


3,125



$

(6,962)


USD$/bbl

$

69.45

$

54.30







Total fair value









$

(33,858)

(1)

The volumes and prices reported are the weighted average volumes and prices for the period.

(2)

These are European calls whereby the counterparty can exercise the option monthly on a particular day to purchase NYMEX at a specified price.  

(3)

These are European and Asian swaptions whereby the Company provides the option to extend an oil swap into the period subsequent to the call date, or retroactively fix the price on the volumes under the contract.

 

The Company has entered into the following financial derivative contracts subsequent to March 31, 2017:

Type of Contract


Quantity


Time Period


Contract Price

Gas Financial swaps


20,000 mmbtu/d


January 2018 – December 2018


USD$3.07/mmbtu

 

The Company has entered into multiple interest rate swaps over the next 7 years at an annual average interest rate as detailed below:



2017


2018


2019


2020


2021


2022


2023


Fair Value

Effective interest rate(1)


1.53%


1.53%


1.56%


1.28%


1.37%


1.42%


1.71%



Notional amount
hedged (000s)

$

602,192

$

625,000

$

589,726

$

393,630

$

309,452

$

117,603

$

8,288

$

(3,092)

(1)

Canadian Dealer offer rate, excluding stamping and stand-by fees.

 

The following table provides a summary of the unrealized gains (losses) on financial instruments recorded in the consolidated statements of income (loss) and comprehensive income (loss) for the three months ended March 31, 2017 and 2016:




Three Months Ended
March 31,

(000s)



2017


2016

Unrealized gain (loss) on financial instruments – commodity contracts


$

40,605

$

(27,763)

Unrealized (loss) on financial instruments – interest rate swaps



(762)


(880)

Total unrealized gain (loss) on financial instruments


$

39,843

$

(28,643)

 

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

The Company has the following physical contracts in place at March 31, 2017 (1)(5):




2017


2018


2019


2020


2021

Gas












Fixed price – AECO

mcf/d


214,920


42,067





CAD$/mcf

$

3.11

$

3.19







Basis differentials - AECO (2)(3)

mmbtu/d


100,264


147,500


147,500


147,500


76,664


USD$/mmbtu

$

(0.65)

$

(0.72)

$

(0.72)

$

(0.72)

$

(0.64)

Basis differentials - Dawn

mmbtu/d



18,836


25,000


25,000


6,164


USD$/mmbtu



$

(0.15)

$

(0.15)

$

(0.15)

$

(0.15)

Basis differentials – Stn 2

mcf/d


56,357


47,913


19,478


17,807


9,478


CAD$/mcf

$

(0.26)

$

(0.20)

$

(0.05)

$

(0.07)

$

(0.26)

AECO Monthly Calls /
Call Swaptions (3)

mcf/d


7,376


71,086




CAD$/mcf

$

2.85

$

4.26







Oil












Fixed differential (4)

bbls/d


1,333


1,552





USD$/bbl

$

(6.79)

$

(6.95)







(1)

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

(2)

Tourmaline also has an average of 53.5 mmcf/d of NYMEX-AECO basis differentials at $(0.68) from 2022-2024. A portion of these basis deals have a cap on NYMEX, 13.6 mmcf/d at USD$4.28/mcf for 2017, 92.5 mmcf/d at USD$4.18/mcf from 2018-2020 and 40.0 mmcf/d at USD$4.57/mcf from 2021-2024.

(3)

These are monthly calls for 2017 that are European Swaptions, whereby the Company provides the option to extend a gas swap into the period subsequent to the call date or increase the volumes under contract. In 2018, there is a combination of monthly calls and European Swaptions.

(4)

Tourmaline sells physical crude at a fixed differential to NYMEX.

(5)

Tourmaline also has entered into deals to sell 30,000 mmbtu/d at Chicago GDD pricing less transportation costs from April 2015 to October 2020; 20,000 mmbtu/d at Chicago GDD pricing less transportation costs from April 2015 to March 2020; 5,000 mmbtu/d at Chicago GDD pricing less transportation costs from November 2017 to March 2023; 25,000 mmbtu/d at Emerson GDD pricing less transportation costs from November 2016 to October 2017; and 20,000 mmbtu/d at Ventura GDD pricing less transportation costs from April 2015 to October 2020.

 

The Company has entered into the following physical contracts subsequent to March 31, 2017:

Type of Contract


Quantity


Time Period


Contract Price

Gas Fixed Price – AECO


20,000 GJs/d


November 2017 – March 2018


CAD$3.05/GJ

Gas Fixed Price – AECO


30,000 GJs/d


January 2018 – March 2018


CAD$3.16/GJ

Gas Fixed Price – AECO


40,000 GJs/d


January 2018 – December 2018


CAD$2.55/GJ

Gas Fixed Price – AECO


20,000 GJs/d


April 2018 – December 2018


CAD$2.53/GJ

Gas Call Swaptions - AECO (1)


20,000 GJs/d


January 2019 – December 2019


CAD$2.60/GJ

(1)

Counterparty has a one-time option to call on December 31, 2018.

 

4.  EXPLORATION AND EVALUATION ASSETS

(000s)






As at December 31, 2016




$

678,531


Capital expenditures





31,780


Transfers to property, plant and equipment (note 5)





(13,983)


Acquisitions





322


Divestitures





(1,221)


Expired mineral leases





(6,501)

As at March 31, 2017




$

688,928

 

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

Impairment Assessment

In accordance with IFRS, an impairment test is performed if the Company identifies an indicator of impairment.  At March 31, 2017 and December 31, 2016, the Company determined that no indicators of impairment existed on its E&E assets; therefore, an impairment test was not performed.

5.  PROPERTY, PLANT AND EQUIPMENT

Cost










(000s)





As at December 31, 2016



$

11,008,617


Capital expenditures




371,947


Transfers from exploration and evaluation (note 4)




13,983


Change in decommissioning liabilities (note 6)




9,563


Acquisitions




19,945

As at March 31, 2017



$

11,424,055

 

Accumulated Depletion, Depreciation and Amortization









(000s)








As at December 31, 2016






$

2,551,407


Depletion, depreciation and amortization







182,173

As at March 31, 2017






$

2,733,580

 

Net Book Value
















(000s)








As at December 31, 2016






$

8,457,210

As at March 31, 2017






$

8,690,475

 

Future development costs of $6,430.7 million were included in the depletion calculation at March 31, 2017 (December 31, 2016$6,417.4 million).

Capitalization of G&A and Share-Based Payments

A total of $5.2 million in G&A expenditures have been capitalized and included in PP&E assets at March 31, 2017 (December 31, 2016 – $23.7 million).  Also included in PP&E are non-cash share-based payments of $5.1 million (December 31, 2016 - $22.8 million).

Impairment Assessment

In accordance with IFRS, an impairment test is performed on a CGU if the Company identifies an indicator of impairment.  At March 31, 2017 and December 31, 2016, the Company determined that there were no indicators of impairment on any of the Company's CGUs; therefore impairment tests were not performed.

Business Combinations

Minehead-Edson-Ansell

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

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

(000s)



Minehead-Edson-Ansell

Fair value of net assets acquired:








Property, plant and equipment





$

179,230


Exploration and evaluation






4,753


Decommissioning obligations






(983)

Total





$

183,000

Consideration:








Cash





$

183,000

 

Shell Canada

On November 30, 2016, the Company acquired assets in the Alberta Deep Basin and the Northeast B.C. Gundy area ("Gundy assets") for total consideration of $1,367.8 million, including cash consideration of $1,000.1 million before customary adjustments and 10,017,938 Tourmaline common shares at a deemed price of $36.70 per share.  Total transaction costs incurred by the Company of $1.6 million associated with this acquisition were expensed in the consolidated statement of income (loss) and comprehensive income (loss).  The Deep Basin assets acquired resulted in significant increases in lands, production, reserves and facilities in a core development area of the Company.  The Gundy assets acquired include land, production and reserves and now provide the Company with sufficient size and scope in the Northeast Montney play to drive strategic Company-operated infrastructure development.

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

(000s)




Shell Canada

Fair value of net assets acquired:







Property, plant and equipment




$

1,333,367


Exploration and evaluation





38,493


Decommissioning obligations





(4,106)

Total




$

1,367,754

Consideration:







Cash




$

1,000,096


Common Shares





367,658

Total




$

1,367,754

 

Acquisitions and Dispositions of Oil and Natural Gas Properties

For the three months ended March 31, 2017, the Company completed property acquisitions for cash of $0.8 million (December 31, 2016 - $42.5 million) and, a further $19.3 million in acquisitions involving non-cash consideration (December 31, 2016 - $8.0 million). Of the $19.3 million, $14.9 million relates to assets acquired by issuing 475,000 Tourmaline common shares at a price $31.27 per share.  The Company also assumed $0.2 million in decommissioning liabilities as a result of these acquisitions (December 31, 2016 - $1.4 million).

The Company did not complete any cash property dispositions for the quarter ended March 31, 2017.  For the year ended December 31, 2016, the Company completed property dispositions for total cash consideration of $48.0 million.

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 $410.5 million (December 31, 2016$392.0 million), with some abandonments expected to commence in 2034.  A risk-free rate of 2.31% (December 31, 2016 – 2.31%) and an inflation rate of 2.0% (December 31, 2016 – 2.0%) were used to calculate the decommissioning obligations.

(000s)




As at
March 31,
2017


As at
December 31,
2016

Balance, beginning of period



$

212,669

$

163,459


Obligation incurred




8,439


14,798


Obligation incurred on property acquisitions




165


6,520


Obligation divested





(1,406)


Obligation settled




(407)


(1,367)


Accretion expense




1,198


3,607


Change in future estimated cash outlays




1,124


27,058

Balance, end of period



$

223,188

$

212,669


 

7.  BANK DEBT

The Company has a covenant-based, unsecured, bank credit facility in place with a syndicate of banks, the details of which are described in note 9 of the Company's consolidated financial statements for the year ended December 31, 2016.  This is an extendible revolving facility in the amount of $1,800.0 million with an initial maturity date of June 2020.  The maturity date may, at the request of the Company and with consent of the lenders, be extended on an annual basis.  The credit facility includes an expansion feature ("accordion") which allows the Company, upon approval from the lenders, to increase the facility amount by up to $500.0 million by adding a new financial institution or by increasing the commitment of its existing lenders.  The Company also has a $50.0 million operating revolver, resulting in total bank credit facility capacity of $1,850.0 million.  The facility can be drawn in either Canadian or U.S. funds and bears interest at the bank's prime lending rate, banker's acceptance rates or LIBOR (for U.S. borrowings), plus applicable margins, which range from 0.50% to 3.90% depending on the type of borrowing and the Company's senior debt to adjusted EBITDA ratio.

The Company also has a term loan with a syndicate of banks.  On February 3, 2017, the Company increased the term loan from $250.0 million to $650.0 million and extended its maturity date to February 2022.  The term loan can be drawn in either Canadian or U.S. funds and bears interest at the bank's prime lending rate, banker's acceptance rates or LIBOR (for U.S. borrowings), plus 200 basis points.  With the exception of the increase in amount and maturity date extension the term debt was renewed under the same terms and conditions as those outlined in note 9 of the Company's consolidated financial statements for the year ended December 31, 2016.  The maturity date may, at the request of the Company and with consent of the lender, be extended on an annual basis.  The covenants for the term loan are the same as those under the Company's current credit facility and the term loan will rank equally with the obligation under the Company's credit facility.

The Company's aggregate borrowing capacity is now $2,500.0 million.

As at March 31, 2017, the Company had $647.8 million in long-term debt outstanding and $710.3 million drawn against the bank credit facility for total bank debt of $1,358.1 million (net of prepaid interest and debt issue costs) (December 31, 2016 - $1,406.6 million).  In addition, Tourmaline has outstanding letters of credit of $18.6 million (December 31, 2016 - $18.6 million), which reduce the credit available on the facility.  The effective interest rate for the three months ended March 31, 2017 was 2.44% (three months ended March 31, 2016 – 2.45%).  As at March 31, 2017, the Company is in compliance with all debt covenants.

8.  NON-CONTROLLING INTEREST

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

(000s)




As at
March 31,
2017


As at
December 31,
2016

Balance, beginning of period



$

27,549

$

28,431


Share of subsidiary's net income (loss) for the period




155


(882)

Balance, end of period



$

27,704

$

27,549


 

9.  SHARE CAPITAL

(a) Authorized

Unlimited number of Common Shares without par value.

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

(b) Common Shares Issued


As at
March 31,
2017

As at
December 31,
2016

(000s) except share amounts

Number of
Shares


Amount

Number of
Shares


Amount

Balance, beginning of period

268,595,812

$

5,818,867

221,335,925

$

4,266,234

For cash on public offering of common shares (1)(4)

-


-

32,146,200


1,037,722

For cash on public offering of flow-through common shares (2)(3)

-


-

2,210,500


69,760

Issued on corporate and property acquisitions (note 5)

475,000


14,853

10,017,938


367,658

For cash on exercise of stock options

98,133


2,217

2,885,249


82,217

Contributed surplus on exercise of stock options

-


752

-


28,717

Share issue costs

-


(37)

-


(45,684)

Tax effect of share issue costs

-


10

-


12,243

Balance, end of period

269,168,945

$

5,836,662

268,595,812

$

5,818,867

(1)

On April 5, 2016, the Company issued 10.388 million common shares at a price of $27.11 per share for total gross proceeds of $281.6 million. A total of 37,500 common shares were purchased by insiders.

(2)

On May 17, 2016, the Company issued 1.320 million flow-through shares at a price of $35.50 per share for total gross proceeds of $46.9 million.  The implied premium on the flow-through common shares was determined to be $9.0 million or $6.85 per share.  As at March 31, 2017, the Company is committed to spend $23.1 million on qualified exploration expenditures by December 31, 2017.  The expenditures were renounced to investors in January 2017 with an effective renunciation date of December 31, 2016.

(3)

On October 20, 2016, the Company issued 0.891 million flow-through shares at a price of $44.50 per share for total gross proceeds of $39.6 million.  The implied premium on the flow-through common shares was determined to be $7.7 million or $8.63 per share.  As at March 31, 2017, the Company is committed to spend the full amount on qualified exploration expenditures by December 31, 2017.  The expenditures were renounced to investors in January 2017 with an effective renunciation date of December 31, 2016.

(4)

On November 30, 2016, the Company issued 21.759 million common shares at a price of $34.75 per share for total gross proceeds of $756.1 million.  A total of 175,000 common shares were purchased by insiders.

 

10. EARNINGS (LOSS) PER SHARE

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




Three Months Ended
March 31,




2017


2016

Net earnings (loss) for the period (000s)


$

99,534

$

(38,390)

Weighted average number of common shares – basic



269,055,152


221,403,764

Earnings (loss) per share – basic


$

0.37

$

(0.17)

 

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




Three Months Ended
March 31,




2017


2016

Net earnings (loss) for the period (000s)


$

99,534

$

(38,390)

Weighted average number of common shares – diluted



269,394,040


221,403,764

Earnings (loss) per share – fully diluted


$

0.37

$

(0.17)

 

There were 16,583,365 options excluded from the weighted-average share calculations for the three-month period ended March 31, 2017 because they were anti-dilutive (three months ended March 31, 2016 – 19,619,746 options were anti-dilutive).

11. SHARE-BASED PAYMENTS

The Company has a rolling stock option plan.  Under the employee stock option plan, the Company may grant options to its employees up to 22,879,360 shares of common stock, which represents 8.5% of the current outstanding common shares.  The exercise price of each option equals the volume-weighted average market price for the five days preceding the issue date of the Company's stock on the date of grant and the option's maximum term is seven 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.



Three Months Ended

March 31,



2017

2016



Number of
Options


Weighted
Average
Exercise
Price

Number of
Options


Weighted
Average
Exercise
Price

Stock options outstanding, beginning of period


20,037,497

$

37.26

19,746,414

$

36.50


Granted


439,500


30.47

125,000


28.18


Exercised


(98,133)


22.59

(148,334)


24.90


Forfeited                                      



(103,334)


40.53

Stock options outstanding, end of period


20,378,864

$

37.18

19,619,746

$

36.51

 

The weighted average trading price of the Company's common shares was $30.46 during the three months ended March 31, 2017 (three months ended March 31, 2016$26.09).

The following table summarizes stock options outstanding and exercisable at March 31, 2017:

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

$22.49 - $29.26


4,093,499

3.22

26.17

1,683,866

25.43

$30.06 - $39.57


7,261,365

3.91

34.60

2,790,165

34.05

$40.18 - $48.99


7,379,000

1.95

42.11

6,346,333

41.95

$51.47 - $56.76


1,645,000

2.27

53.85

1,096,667

53.85



20,378,864

2.93

37.18

11,917,031

38.86


 

The fair value of options granted during the three-month period ended March 31, 2017 was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions and resulting values:




March 31,




2017


2016

Fair value of options granted (weighted average)


$

9.53

$

8.30

Risk-free interest rate



1.16%


2.06%

Estimated hold period prior to exercise



5 years


4 years

Expected volatility



33%


34%

Forfeiture rate



2%


2%

Dividend per share


$

0.00

$

0.00

 

12. COMMITMENTS

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

PAYMENTS DUE BY YEAR
























(000s)



1 Year


2-3 Years


4-5 Years


>5 Years


Total

Operating leases


$

5,736

$

10,875

$

-

$

-

$

16,611

Firm transportation and processing
agreements



244,514


550,526


568,801


1,487,242


2,851,083

Capital commitments (1)



316,329


609,852


158,010


34,221


1,118,412

Flow-through share commitments



62,731


-


-


-


62,731

Credit facility (2)



-


-


777,112


-


777,112

Term debt (3)



19,091


38,182


684,671


-


741,944



$

648,401

$

1,209,435

$

2,188,594

$

1,521,463

$

5,567,893

(1)

Includes drilling commitments, and capital spending commitments under the joint arrangement in the Spirit River complex of $300.0 million per year from 2015 to 2019.  The capital spending commitment can be deferred to future periods in the event of an economic downturn, and as agreed upon by both parties.  In 2016, an economic downturn event resulted in $216.0 million of capital spending being deferred into future periods.

(2)

Includes interest expense at an annual rate of 2.64% being the rate applicable to outstanding debt on the credit facility at March 31, 2017.

(3)

Includes interest expense at an annual rate of 2.94% being the fixed rate on the term debt at March 31, 2017.

 

ABOUT TOURMALINE OIL CORP.

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

SOURCE Tourmaline Oil Corp.

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


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