Tourmaline Earns $28.5 Million in the Third Quarter
CALGARY, AB--(Marketwired - November 04, 2015) - Tourmaline Oil Corp. (TSX: TOU) ("Tourmaline" or the "Company") is pleased to provide third quarter 2015 financial results and an operational update.
HIGHLIGHTS
- Q3 2015 after tax earnings of $28.5 million underscores the full-cycle profitability of the Company's low cost business, even in a very low commodity price environment.
- Third quarter production of 150,297 boepd, up 39% from the third quarter of 2014 and up 5% from Q2 2015.
- Current production ranging between 179,000 and 182,500 boepd, up 20% over Q3 2015; the Company expects to achieve 2015 exit guidance in the second half of November.
- Nine month operating costs of $4.43/boe, down 15% from 2014 reflecting improved operating efficiencies and strong returns on midstream assets.
Q3 FINANCIAL RESULTS
- Third quarter 2015 cash flow(1) of $197.1 million was down marginally from the previous quarter as the effects of strong production growth were offset by continued weakness in commodity prices.
- All-in cash costs (operating, transportation, general and administrative and financing)(2) during the third quarter were $7.80/boe, amongst the lowest in the industry.
2H 2015/1H 2016 CAPITAL SPENDING
Tourmaline expects full-year 2015 EP capital spending of $1.375 billion, down from the previous estimate. The Company utilized additional funds raised in June ($195.4 million) to drill incremental wells during the third quarter; the rig fleet was increased from 14 to 19 rigs in order to execute the expanded program. A total of 68 wells were drilled during the third quarter. The incremental drilling program was designed to follow up multiple first-half 2015 new EP successes, to provide the necessary production volumes to achieve the target production exit volume of 190,000 - 200,000 boepd and to drill incremental wells during a period of significantly lower per-well capital costs. These objectives have been accomplished and the Company is in the process of ramping the rig fleet back down to 14 rigs. Tourmaline expects to drill a total of 40 wells during the fourth quarter of 2015, and complete 26 wells. Approximately $37.0 million of the $55.0 million Edson gas plant and sales pipeline project was expended during the third quarter, with production scheduled to commence later this month. Total third quarter EP Capital spending was $422.6 million, and total fourth quarter EP Capital spending has been reduced to $250.0 million, less than anticipated Q4 cash flow, as the Company has already generated the well and production inventory necessary to achieve exit targets.
(1) "Cash flow" is defined as cash provided by operations before changes in non-cash operating working capital. See "Non-GAAP Financial Measures" below and in the attached Management's Discussion and Analysis.
(2) See "Non-GAAP Financial Measures" below and in the attached Management's Discussion and Analysis.
Tourmaline currently plans to execute its previously-released 2016 Base Case EP Capital program of $1.1 billion, yielding 2016 full-year average production of 200,000 boepd. A first-half 2016 capital program of approximately $450.0 million is planned with Q1 capital spending of $300.0 million, and Q2 capital spending of $150.0 million. This is less than currently anticipated 1H 2016 cash flow of $565.0 million.
The 2016 Base Case capital program includes only two facility projects -- the Brazeau gas plant in the Deep Basin ($55 million with plant and sales pipeline), scheduled for the first half of 2016, and the Doe B.C. gas plant, scheduled for the second half of the year. Tourmaline expects to drill and complete approximately 70 wells in the first half of 2016, which, coupled with shut-in volumes accumulated through continued outperformance of predictive-type curves, will provide sufficient volumes to meet or exceed Base Case production estimates.
The Company will continue to monitor commodity prices and adjust capital spending accordingly in order to maintain a debt to cash flow ratio of approximately 1.5 times or less. Completion of the infrastructure skeleton in all three core complexes during 2014 and 2015 has resulted in planned infrastructure spending of less than 20% of the total EP capital program in both 2016 and 2017, providing continually-improving capital efficiencies as well as considerable capital flexibility. This infrastructure asset consists of 12 gas processing plants (10 at 100% working interest) with Company-interest processing capacity of 1.05 bcf/day, 14 compressor stations, over 3,500 km of Company-100%-interest pipelines, 48,000 bpd of oil processing capability, 172,000 bbls of oil and condensate storage and six frac water source and recycling facilities. Total Tourmaline exit 2015 processing capacity will be approximately 210,000 - 220,000 boepd, providing considerable flexibility around new facility timing in 2016 and 2017.
COST STRUCTURE AND PERFORMANCE
For the nine months ended September 30, operating costs of $4.43 boe were down 15% from 2014. The Company expects to achieve the full-year operating cost target of $4.35/boe, which is 11% lower than 2014 costs. Third quarter 2015 Peace River High operating costs of approximately $16.00/bbl are not yet at the target level of $11.00/boe. The full impact of the cost savings related to the Mulligan battery start-up during the third quarter will be realized in the fourth quarter and beyond. Third quarter 2015 Deep Basin operating costs were $3.50/boe and NEBC Montney complex operating costs were $3.25/boe. Tourmaline expects to drive overall operating costs down further in 2016 as the benefits of recent facility investments are fully incorporated into our cost structure.
Continued low general and administrative cash costs for the third quarter of $0.56/boe, combined with all-in debt servicing costs of 2.69% and lower third quarter transportation costs, resulted in all-in cash costs of $7.74/boe during the first nine months -- amongst the lowest in Industry. Tourmaline has managed staff growth conservatively since inception seven years ago with only 180 employees currently, and has no need or plans to reduce office or field staff levels.
EP HIGHLIGHTS
- Tourmaline will achieve the low end of exit 2015 production guidance of 190,000 - 200,000 boepd in the second half of November with the start-up of the 55.0 mmcfpd Edson 4-17 gas plant. Production volumes will continue to grow through to year end with additional tie-ins throughout the EP portfolio.
- 2016 average production in the Base Case Budget Scenario is 200,000 boepd, representing approximately 26% growth over 2015 average production levels.
- 2015 exit liquids production estimated at 30,000 bpd, approximately 65% of which is light oil and condensate.
- 17 horizontal wells have now been drilled into the liquid rich Lower Montney turbidite new play horizon in the Sunrise-Dawson B.C complex. For the four most recently completed horizontals, wellhead condensate production rates ranged between 590 and 1,057 bbls/day with accompanying gas rates between 4.9 and 7.7 mmcfpd at Flowing Casing Pressures ("FCP") of between 4.0 and 11.2 MPa on five-day production tests. With 220 future locations in the Lower Montney turbidite, this incremental opportunity, captured during 2014/2015, will provide significant condensate production growth over the next several years.
- Alberta Deep Basin well performance continues to improve with corresponding drilling and completion costs down 20% year over year. Of the 41 wells drilled in the Deep Basin since spring break-up of 2015, the average 30-day initial production ("IP") rate is 11.1 mmcfpd, more than double the rate contemplated on the Company's production performance template. The second Notikewin horizontal in the greater Brazeau play area recently tested at a rate of 30.5 mmcfpd with 370 bbls/day condensate at the wellhead at a FCP of 24.6 MPa on a three-day production test.
- Fourth quarter production levels for the Peace River High Charlie Lake oil and gas complex are already 23% higher than the third quarter average.
| CORPORATE SUMMARY - THIRD QUARTER 2015 |
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
| 2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||||||
| OPERATIONS | |||||||||||||||||||||
| Production | |||||||||||||||||||||
| Natural gas (mcf/d) | 786,910 | 562,739 | 40 | % | 767,587 | 550,685 | 39 | % | |||||||||||||
| Crude oil and NGL (bbl/d) | 19,146 | 14,207 | 35 | % | 17,978 | 15,077 | 19 | % | |||||||||||||
| Oil equivalent (boe/d) | 150,297 | 107,997 | 39 | % | 145,909 | 106,858 | 37 | % | |||||||||||||
| Product prices(1) | |||||||||||||||||||||
| Natural gas ($/mcf) | $ | 3.20 | $ | 4.34 | (26 | )% | $ | 3.35 | $ | 4.79 | (30 | )% | |||||||||
| Crude oil and NGL ($/bbl) | $ | 45.91 | $ | 74.61 | (38 | )% | $ | 47.19 | $ | 73.24 | (36 | )% | |||||||||
| Operating expenses ($/boe) | $ | 4.51 | $ | 5.41 | (17 | )% | $ | 4.43 | $ | 5.20 | (15 | )% | |||||||||
| Transportation costs ($/boe) | $ | 1.98 | $ | 1.84 | 8 | % | $ | 2.07 | $ | 1.88 | 10 | % | |||||||||
| Operating netback(3)($/boe) | $ | 15.06 | $ | 22.19 | (32 | )% | $ | 16.02 | $ | 24.64 | (35 | )% | |||||||||
| Cash general and administrative expenses ($/boe)(2) | $ | 0.56 | $ | 0.65 | (14 | )% | $ | 0.50 | $ | 0.62 | (19 | )% | |||||||||
| FINANCIAL($000, except share and per share) | |||||||||||||||||||||
| Revenue | 312,644 | 321,985 | (3 | )% | 932,643 | 1,021,790 | (9 | )% | |||||||||||||
| Royalties | 14,755 | 29,549 | (50 | )% | 35,286 | 96,587 | (63 | )% | |||||||||||||
| Cash flow(3) | 197,100 | 211,635 | (7 | )% | 607,869 | 695,764 | (13 | )% | |||||||||||||
| Cash flow per share (diluted)(3) | $ | 0.90 | $ | 1.03 | (13 | )% | $ | 2.86 | $ | 3.43 | (17 | )% | |||||||||
| Net earnings (loss) | 28,489 | 67,357 | (58 | )% | 45,451 | 223,662 | (80 | )% | |||||||||||||
| Net earnings (loss) per share (diluted) | $ | 0.13 | $ | 0.33 | (61 | )% | $ | 0.21 | $ | 1.10 | (81 | )% | |||||||||
| Capital expenditures (net of dispositions) | 422,629 | 647,302 | (35 | )% | 1,210,640 | 1,411,431 | (14 | )% | |||||||||||||
| Weighted average shares outstanding (diluted) | 212,561,337 | 202,811,901 | 5 | % | |||||||||||||||||
| Net debt(3) | (1,484,095 | ) | (1,258,913 | ) | 18 | % | |||||||||||||||
| (1) Product prices include realized gains and losses on financial instrument contracts. |
| (2) Excluding interest and financing charges. See "Non-GAAP Financial Measures" below and in the attached Management's Discussion and Analysis. |
| (3) See "Non-GAAP Financial Measures" below and in the attached Management's Discussion and Analysis. |
Conference Call Tomorrow at 9:00 a.m. MT (11:00 a.m. ET)
Tourmaline will host a conference call tomorrow, November 5, 2015 starting at 9:00 a.m. MST (11:00 a.m. EST). To participate, please dial 1-866-225-0198 (toll-free in North America), or local dial-in 416-340-2216, a few minutes prior to the conference call.
Reader Advisories
CURRENCY
All amounts in this news release are stated in Canadian dollars unless otherwise specified.
FORWARD-LOOKING INFORMATION
This press release contains forward-looking information within the meaning of applicable securities laws. The use of any of the words "forecast", "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "could", "believe", "plans", "intends" and similar expressions are intended to identify forward-looking information. More particularly and without limitation, this press release contains forward-looking information concerning Tourmaline's plans and other aspects of its anticipated future operations, management focus, objectives, strategies, financial, operating and production results and business opportunities, including as at and for various future periods, anticipated petroleum and natural gas production, cash flows, capital spending, net debt, net debt to cash flow levels, projected operating and drilling costs, the timing for facility expansions and facility start-up dates, tie-in of production, as well as Tourmaline's future drilling prospects and plans, including the quantity of drilling locations in inventory, business strategy, future development and growth opportunities and prospects and asset base. The forward-looking information is based on certain key expectations and assumptions made by Tourmaline, including expectations and assumptions concerning: prevailing and future commodity prices and currency exchange rates; applicable royalty rates and tax laws; interest rates; future well production rates and reserve volumes; operating costs; the timing of receipt of regulatory approvals; the performance of existing wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the successful completion of acquisitions and dispositions; the availability and cost of labour and services; the state of the economy and the exploration and production business; the availability and cost of financing; and ability to market and transport oil and natural gas successfully.
Statements relating to "reserves" are also deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.
Although Tourmaline believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Tourmaline can give no assurances that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature it involves inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to reserves, production, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; marketing and transportation; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; ability to access sufficient capital from internal and external sources; failure to obtain required regulatory and other approvals; reliance on third parties; and changes in legislation, including but not limited to tax laws, royalties and environmental regulations. Readers are cautioned that the foregoing list of factors is not exhaustive.
Also included in this press release are estimates of Tourmaline's 2015 annual cash flow, capital spending and year-end net debt and net debt to cash flow levels as well as preliminary guidance on 2016 anticipated cash flows, which are based on the various assumptions as to production levels, including estimated average production of 155,000 - 160,000 boepd for 2015 and 200,000 boepd for 2016, capital expenditures, and other assumptions disclosed in this press release and including commodity price assumptions for natural gas (AECO - $2.96/mcf for 2015 and $3.25/mcf for 2016), and crude oil (WTI (US) - $53.26/bbl for 2015 and $62.50/bbl for 2016) and an exchange rate assumption of (US/CAD) $0.79 for 2015 and $0.80 for 2016. To the extent any such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Tourmaline on November 4, 2015 and is included to provide readers with an understanding of Tourmaline's anticipated cash flows based on the capital expenditure and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.
Additional information on these and other factors that could affect Tourmaline, or its operations or financial results, are included in the Company's most recently filed Management's Discussion and Analysis (See "Forward-Looking Statements" therein) , Annual Information Form (See "Risk Factors" and "Forward-Looking Statements" therein) and other reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or Tourmaline's website (www.tourmalineoil.com).
The forward-looking information contained in this press release is made as of the date hereof and Tourmaline undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless expressly required by applicable securities laws.
See also "Forward-Looking Statements" in the attached Management's Discussion and Analysis.
Additional Reader Advisories
BOE CONVERSIONS
Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an indication of value.
PRODUCTION TESTS
Any references in this release to IP rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue to produce and decline thereafter and are not necessarily indicative of long-term performance or ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Such rates are based on field estimates and may be based on limited data available at this time.
NON-GAAP FINANCIAL MEASURES
This press release includes references to financial measures commonly used in the oil and gas industry, "cash flow", "operating netback", "all-in cash costs", "general and administrative expenses" and "net debt", which do not have standardized meanings prescribed by International Financial Reporting Standards ("GAAP"). Accordingly, the Company's use of these terms may not be comparable to similarly defined measures presented by other companies. Management uses the terms "cash flow", "operating netback", "all-in cash costs", "general and administrative expenses" and "net debt", for its own performance measures and to provide shareholders and potential investors with a measurement of the Company's efficiency and its ability to generate the cash necessary to fund a portion of its future growth expenditures or to repay debt. Readers are cautioned that the non-GAAP measures should not be construed as an alternative to net income determined in accordance with GAAP as an indication of the Company's performance. All-in cash costs is defined as operating, transportation, general and administration, and finance expenses excluding accretion. See "Non-GAAP Financial Measures" in the attached Management's Discussion and Analysis for the definition and description of these terms.
ESTIMATED DRILLING INVENTORY
This press release discloses 220 drilling locations which are unbooked. Unbooked locations are internal estimates based on the Company's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
| CERTAIN DEFINITIONS: | ||
| bbl | barrel | |
| bbls/day | barrels per day | |
| bbl/mmcf | barrels per million cubic feet | |
| bcf | billion cubic feet | |
| bpd or bbl/d | barrels per day | |
| boe | barrel of oil equivalent | |
| boepd or boe/d | barrel of oil equivalent per day | |
| bopd or bbl/d | barrel of oil, condensate or liquids per day | |
| gj | gigajoule | |
| gjs/d | gigajoules per day | |
| mbbls | thousand barrels | |
| mboe | thousand barrels of oil equivalent | |
| mcf | thousand cubic feet | |
| mcfpd or mcf/d | thousand cubic feet per day | |
| mcfe | thousand cubic feet equivalent | |
| mmboe | million barrels of oil equivalent | |
| mmbtu | million British thermal units | |
| mmbtu/d | million British thermal units per day | |
| mmcf | million cubic feet | |
| mmcfpd or mmcf/d | million cubic feet per day | |
| MPa | megapascal | |
| mstboe | thousand stock tank barrels of oil equivalent | |
| NGL | natural gas liquids |
MANAGEMENT'S DISCUSSION AND ANALYSIS
This management's discussion and analysis ("MD&A") should be read in conjunction with Tourmaline's unaudited interim condensed consolidated financial statements and related notes as at and for the three and nine months ended September 30, 2015 and the consolidated financial statements for the year ended December 31, 2014. Both the consolidated financial statements and the MD&A can be found at www.sedar.com. This MD&A is dated November 4, 2015.
The financial information contained herein has been prepared in accordance with International Financial Reporting Standards ("IFRS") and sometimes referred to in this MD&A as Generally Accepted Accounting Principles ("GAAP") as issued by the International Accounting Standards Board. All dollar amounts are expressed in Canadian currency, unless otherwise noted.
Certain financial measures referred to in this MD&A are not prescribed by IFRS. See "Non-GAAP Financial Measures" for information regarding the following non-GAAP financial measures used in this MD&A: "cash flow", "operating netback", "working capital (adjusted for the fair value of financial instruments)", "net debt", "adjusted EBITDA", "senior debt", "total debt", and "total capitalization".
Additional information relating to Tourmaline can be found at www.sedar.com.
Forward-Looking Statements - Certain information regarding Tourmaline set forth in this document, including management's assessment of the Company's future plans and operations, contains forward-looking statements that involve substantial known and unknown risks and uncertainties. The use of any of the words "anticipate", "continue", "estimate", "expect", "may", "will", "project", "should", "believe" and similar expressions are intended to identify forward-looking statements. Such statements represent Tourmaline's internal projections, forecasts, estimates or beliefs concerning, among other things, an outlook on the estimated amounts and timing of capital investment or expenditures, anticipated future debt, expenses, production, cash flow and revenues or other expectations, beliefs, plans, objectives, assumptions, intentions or statements about future events or performance. These statements are only predictions and actual events or results may differ materially. These statements are only predictions and actual events or results may differ materially. Although Tourmaline believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies.
In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to: the size of, and future net revenues and cash flow from, crude oil, NGL (natural gas liquids) and natural gas reserves; future prospects; the focus of and timing of capital expenditures; expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; access to debt and equity markets; projections of market prices and costs; the performance characteristics of the Company's crude oil, NGL and natural gas properties; crude oil, NGL and natural gas production levels and product mix; Tourmaline's future operating and financial results; capital investment programs; supply and demand for crude oil, NGL and natural gas; future royalty rates; drilling, development and completion plans and the results therefrom; future land expiries; dispositions and joint venture arrangements; amount of operating, transportation and general and administrative expenses; treatment under governmental regulatory regimes and tax laws; and estimated tax pool balances. In addition, statements relating to "reserves" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.
These forward-looking statements are subject to numerous risks and uncertainties, most of which are beyond the Company's control, including the impact of general economic conditions; volatility and uncertainty in market prices for crude oil, NGL and natural gas; industry conditions; currency fluctuation; imprecision of reserve estimates; liabilities inherent in crude oil, NGL and natural gas operations; environmental risks; incorrect assessments of the value of acquisitions and exploration and development programs; competition; the lack of availability of qualified personnel or management and skilled labour; changes in income tax laws and incentive programs relating to the oil and gas industry; hazards such as fire, explosion, blowouts, cratering, and spills, any of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; stock market volatility; ability to access sufficient capital from internal and external sources; the receipt of applicable regulatory or third-party approvals; and the other risks considered under "Risk Factors" in Tourmaline's most recent annual information form available at www.sedar.com.
With respect to forward-looking statements contained in this MD&A, Tourmaline has made assumptions regarding: future commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment and services; effects of regulation by governmental agencies; and future operating costs.
Management has included the above summary of assumptions and risks related to forward-looking information provided in this MD&A in order to provide readers with a more complete perspective on Tourmaline's future operations and such information may not be appropriate for other purposes. Tourmaline's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that the Company will derive therefrom. Readers are cautioned that the foregoing lists of factors are not exhaustive.
These forward-looking statements are made as of the date of this MD&A and the Company disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.
Boe Conversions - Per barrel of oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent (6:1). Barrel of oil equivalents (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, as the value ratio between natural gas and crude oil based on current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
| PRODUCTION | ||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||
| 2015 | 2014 | Change | 2015 | 2014 | Change | |||||||||||||
| Natural gas (mcf/d) | 786,910 | 562,739 | 40 | % | 767,587 | 550,685 | 39 | % | ||||||||||
| Oil (bbl/d) | 10,669 | 9,002 | 19 | % | 10,630 | 9,136 | 16 | % | ||||||||||
| NGL (bbl/d) | 8,477 | 5,205 | 63 | % | 7,348 | 5,941 | 24 | % | ||||||||||
| Oil equivalent (boe/d) | 150,297 | 107,997 | 39 | % | 145,909 | 106,858 | 37 | % | ||||||||||
| Natural Gas % | 87 | % | 87 | % | 88 | % | 86 | % | ||||||||||
Production for the three months ended September 30, 2015 averaged 150,297 boe/d, a 39% increase over the average production for the same quarter of 2014 of 107,997 boe/d. For the nine months ended September 30, 2015, production increased 37% to 145,909 boe/d from 106,858 boe/d for the same period in 2014. Wells brought on production from the Company's exploration and production program accounted for approximately 90% of the growth in production volumes in 2015 over 2014, with the remainder of the change being from corporate and property acquisitions (net of dispositions). The slight increase in the natural gas weighting for the first nine months of 2015 is due to the sale of 25% of the Company's oil producing assets in the Peace River High Complex in the fourth quarter of 2014.
Full-year average production guidance for 2015 was revised to 155,000-160,000 boe/d from 164,500 boe/d (as disclosed in the Company's press release dated October 14, 2015). The reduction in full-year guidance is due to ongoing transportation interruptions, on all three transportation systems the Company utilizes, having reduced production by approximately 7,500 boe/d through the first nine months of 2015.
| REVENUE | |||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||
| (000s) | 2015 | 2014 | Change | 2015 | 2014 | Change | |||||||||||||
| Revenue from: | |||||||||||||||||||
| Natural gas | $ | 231,773 | $ | 224,468 | 3 | % | $ | 701,051 | $ | 720,338 | (3 | )% | |||||||
| Oil and NGL | 80,871 | 97,517 | (17 | )% | 231,592 | 301,452 | (23 | )% | |||||||||||
| Total revenue from natural gas, oil and NGL sales | $ | 312,644 | $ | 321,985 | (3 | )% | $ | 932,643 | $ | 1,021,790 | (9 | )% | |||||||
Revenue for the three months ended September 30, 2015 decreased 3% to $312.6 million from $322.0 million for the same quarter of 2014. Revenue for the nine-month period ended September 30, 2015 decreased 9% from $1,021.8 million in 2014 to $932.6 million in 2015. Lower revenue for the period is consistent with the significant decrease in realized commodity prices, partially offset by higher production volumes and realized gains on energy marketing and hedging activities. Revenue includes all petroleum, natural gas and NGL sales and the realized gain (loss) on financial instruments.
| TOURMALINE REALIZED PRICES: | ||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||
| 2015 | 2014 | Change | 2015 | 2014 | Change | |||||||||||||
| Natural gas ($/mcf) | $ | 3.20 | $ | 4.34 | (26 | )% | $ | 3.35 | $ | 4.79 | (30 | )% | ||||||
| Oil ($/bbl) | $ | 74.06 | $ | 94.77 | (22 | )% | $ | 69.57 | $ | 95.84 | (27 | )% | ||||||
| NGL ($/bbl) | $ | 10.48 | $ | 39.74 | (74 | )% | $ | 14.81 | $ | 38.49 | (62 | )% | ||||||
| Oil equivalent ($/boe) | $ | 22.61 | $ | 32.41 | (30 | )% | $ | 23.41 | $ | 35.03 | (33 | )% | ||||||
| BENCHMARK OIL AND GAS PRICES: | ||||||||||
| Three Months Ended September 30, | ||||||||||
| 2015 | 2014 | Change | ||||||||
| Natural gas | ||||||||||
| NYMEX Henry Hub (USD$/mcf) | $ | 2.74 | $ | 3.95 | (31 | )% | ||||
| AECO (CAD$/mcf) | $ | 2.91 | $ | 4.03 | (28 | )% | ||||
| Oil | ||||||||||
| NYMEX (USD$/bbl) | $ | 46.48 | $ | 97.25 | (52 | )% | ||||
| Edmonton Par (CAD$/bbl) | $ | 55.37 | $ | 97.11 | (43 | )% | ||||
| RECONCILIATION OF AECO INDEX TO TOURMALINE'S REALIZED GAS PRICES: | |||||||||||
| Three Months Ended September 30, | |||||||||||
| ($/mcf) | 2015 | 2014 | Change | ||||||||
| AECO index (1) | $ | 2.90 | $ | 4.03 | (28 | )% | |||||
| Heat/quality differential | 0.20 | 0.38 | (47 | )% | |||||||
| Realized gain | 0.31 | 0.03 | 933 | % | |||||||
| Sales point differential (2) | (0.21 | ) | (0.10 | ) | 110 | % | |||||
| Tourmaline realized natural gas price | $ | 3.20 | $ | 4.34 | (26 | )% | |||||
| Premium to AECO pricing due to higher heat content | 7 | % | 9 | % | |||||||
| (1) Weighted based on Tourmaline volumes for the period. |
| (2) Price differential for production sold at other locations (ex. West Coast Station 2 in Northeast B.C.) |
| CURRENCY - EXCHANGE RATES: | |||||||||
| Three Months Ended September 30, | |||||||||
| 2015 | 2014 | Change | |||||||
| CAD$/USD$ (1) | $ | 0.7643 | $ | 0.9186 | (17 | )% | |||
| (1) Average rates for the period. |
The realized average natural gas price for the three and nine months ended September 30, 2015 was $3.20/mcf and $3.35/mcf, which is 26% and 30% lower than the same periods of the prior year. The lower natural gas price reflects a lower AECO index (28%) experienced during the quarter. Included in the realized price is a gain on commodity contracts in the third quarter of 2015 of $22.7 million (nine months ended September 30, 2015 - $107.1 million) compared to a gain of $1.5 million for the same period of the prior year (nine months ended September 30, 2014 - loss of $41.9 million). Realized gains on commodity contracts for the quarter and nine months ended September 30, 2015 have increased compared to the same periods of the prior year as the market price of natural gas has weakened relative to the pricing per the commodity contracts in place. Realized prices exclude the effect of unrealized gains or losses on commodity contracts. Once these gains and losses are realized they are included in the per-unit amounts.
Realized oil prices decreased by 22% and 27% for the three and nine months ended September 30, 2015, which is consistent with the decrease in the benchmark price for crude oil during the quarter partially offset by a gain on commodity contracts in the third quarter of 2015 of $22.7 million (nine months ended September 30, 2015 - $43.6 million). NGL prices decreased 74% from $39.74/bbl to $10.48/bbl, when compared to the same quarter of 2014. The decrease in NGL prices is consistent with the decrease in crude oil and natural gas prices over the period as well as oversupply in the propane market in 2015 leading to significantly reduced prices for that commodity.
| ROYALTIES | ||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| (000s) | 2015 | 2014 | 2015 | 2014 | ||||||||||||
| Natural gas | $ | 7,687 | $ | 14,240 | $ | 16,253 | $ | 54,712 | ||||||||
| Oil and NGL | 7,068 | 15,309 | 19,033 | 41,875 | ||||||||||||
| Total royalties | $ | 14,755 | $ | 29,549 | $ | 35,286 | $ | 96,587 | ||||||||
| Royalties as a percentage of revenue | 5.5 | % | 9.2 | % | 4.5 | % | 9.1 | % | ||||||||
For the quarter ended September 30, 2015, the average effective royalty rate was 5.5% compared to the rate of 9.2% for the same quarter of 2014. For the nine-month period ended September 30, 2015, the average effective royalty rate decreased from 9.1% in 2014 to 4.5% in 2015. The decrease in the average effective royalty rate for 2015 can be attributed to significantly lower commodity prices received during the period. Royalty rates are impacted by changes in commodity prices whereby the actual royalty rate decreases when prices decrease.
The Company also continues to benefit from the New Well Royalty Reduction Program and the Natural Gas Deep Drilling Program in Alberta, as well as the Deep Royalty Credit Program in British Columbia.
The Company is forecasting the royalty rate for 2015 to be approximately 5%, revised down from 8% as disclosed in the Company's MD&A dated August 5, 2015. The royalty rate is, however, sensitive to commodity prices and product mixes, and as such, a change in commodity prices or product mix will impact the actual rate.
| OTHER INCOME | ||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||
| (000s) | 2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||
| Other income | $ | 7,164 | $ | 3,544 | 102 | % | $ | 20,270 | $ | 12,945 | 57 | % | ||||||
Other income increased from $3.5 million in the third quarter of 2014 to $7.2 million for the same quarter of 2015. For the nine-month period ended September 30, 2015, other income increased from $12.9 million in 2014 to $20.3 million in 2015. The increase in other income is mainly due to the increase in processing capacity of Company-owned gas plants, where fees are charged to working interest partners on Tourmaline-operated wells.
| OPERATING EXPENSES | ||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||
| (000s) except per unit amounts | 2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||
| Operating expenses | $ | 62,299 | $ | 53,758 | 16 | % | $ | 176,637 | $ | 151,645 | 16 | % | ||||||
| Per boe | $ | 4.51 | $ | 5.41 | (17 | )% | $ | 4.43 | $ | 5.20 | (15 | )% | ||||||
Operating expenses include all periodic lease and field-level expenses and exclude income recoveries from processing third-party volumes. For the third quarter of 2015, total operating expenses were $62.3 million compared to $53.8 million in 2014. Operating costs for the nine months ended September 30, 2015 were $176.6 million, compared to $151.6 million for the same period in 2014, reflecting increased costs relating to the growing production base.
On a per-boe basis, the costs decreased from $5.41/boe for the third quarter of 2014 to $4.51/boe in the third quarter of 2015. For the nine months ended September 30, 2015, operating costs were $4.43/boe, down from $5.20/boe in the prior year. The Company's investments in processing facilities in 2014 have reduced the volume of gas flowing to third-party facilities, leading to the reduction in operating expenses on a per-boe basis, as well as increased operational efficiencies along with fixed costs being distributed over a significantly higher production base.
The Company expects its full-year 2015 operating costs to average approximately $4.35/boe (as disclosed in the Company's MD&A dated March 9, 2015). Actual costs per boe can change depending on a number of factors including the Company's actual production levels.
| TRANSPORTATION | ||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||
| (000s) except per unit amounts | 2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||
| Natural gas transportation | $ | 19,947 | $ | 13,285 | 50 | % | $ | 59,231 | $ | 37,910 | 56 | % | ||||||
| Oil and NGL transportation | 7,437 | 4,950 | 50 | % | 23,279 | 16,956 | 37 | % | ||||||||||
| Total transportation | $ | 27,384 | $ | 18,235 | 50 | % | $ | 82,510 | $ | 54,866 | 50 | % | ||||||
| Per boe | $ | 1.98 | $ | 1.84 | 8 | % | $ | 2.07 | $ | 1.88 | 10 | % | ||||||
For the third quarter of 2015, total transportation expenses were $27.4 million compared to $18.2 million in 2014. Transportation costs for the nine months ended September 30, 2015 were $82.5 million, compared to $54.9 million for the same period in 2014, reflecting increased costs related to higher production volumes.
On a per-boe basis, the costs increased from $1.84/boe for the third quarter of 2014 to $1.98/boe in the third quarter of 2015. For the nine months ended September 30, 2015, transportation costs were $2.07/boe, up from $1.88/boe for the same period of 2014. The per-unit increase in costs in 2015 is primarily due to a new pipeline fee charged to mainline shippers increasing natural gas transportation expense.
| GENERAL & ADMINISTRATIVE EXPENSES ("G&A") | ||||||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||
| (000s) except per unit amounts | 2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||||||
| G&A expenses | $ | 15,934 | $ | 11,548 | 38 | % | $ | 44,261 | $ | 34,445 | 28 | % | ||||||||||
| Administrative and capital recovery | (2,511 | ) | (336 | ) | 647 | % | (7,286 | ) | (2,519 | ) | 189 | % | ||||||||||
| Capitalized G&A | (5,741 | ) | (4,753 | ) | 21 | % | (17,062 | ) | (13,718 | ) | 24 | % | ||||||||||
| Total G&A expenses | $ | 7,682 | $ | 6,459 | 19 | % | $ | 19,913 | $ | 18,208 | 9 | % | ||||||||||
| Per boe | $ | 0.56 | $ | 0.65 | (14 | )% | $ | 0.50 | $ | 0.62 | (19 | )% | ||||||||||
The increase in gross G&A expenses in 2015 compared to 2014 is primarily due to staff additions needed to manage the larger production, reserve and land base. G&A expenses for the third quarter of 2015 were $7.7 million compared to $6.5 million for the same quarter of the prior year. G&A expenses for the nine-month period ended September 30, 2015 were $19.9 million compared to $18.2 million for the same period in 2014. The increase in administrative and capital recoveries in the third quarter of 2015 compared to 2014 is due to the Company having a higher percentage of wells which it operates on behalf of its partners and, as such, is able to recover more of its G&A expenses.
On a per-boe basis, G&A expenses decreased from $0.65/boe for the third quarter of 2014 to $0.56/boe in the third quarter of 2015. For the nine months ended September 30, 2015, G&A expenses were $0.50/boe, down from $0.62/boe in the prior year. The decrease per boe reflects Tourmaline's growing production base which continues to increase at a faster rate than G&A costs.
G&A costs for 2015 are forecast to average approximately $0.55/boe, down from the previous guidance of $0.60/boe as disclosed in the Company's MD&A dated August 5, 2015. Actual costs per boe can change, however, depending on a number of factors including the Company's actual production levels.
| SHARE-BASED PAYMENTS | ||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| (000s) except per unit amounts | 2015 | 2014 | 2015 | 2014 | ||||||||||||
| Share-based payments | $ | 15,170 | $ | 14,668 | $ | 48,018 | $ | 41,682 | ||||||||
| Capitalized share-based payments | (7,585 | ) | (7,334 | ) | (24,009 | ) | (20,841 | ) | ||||||||
| Total share-based payments | $ | 7,585 | $ | 7,334 | $ | 24,009 | $ | 20,841 | ||||||||
| Per boe | $ | 0.55 | $ | 0.74 | $ | 0.60 | $ | 0.71 | ||||||||
The Company uses the fair value method for the determination of non-cash related share-based payments expense. During the third quarter of 2015, 481,000 stock options were granted to employees, officers, directors and key consultants at a weighted-average exercise price of $34.08 and 991,950 options were exercised, resulting in $18.2 million of cash proceeds.
The Company recognized $7.6 million of share-based payments expense in the third quarter of 2015 compared to $7.3 million in the third quarter of 2014. Capitalized share-based payments for the third quarter of 2015 were $7.6 million compared to $7.3 million for the same period of the prior year.
For the nine months ended September 30, 2015, share-based payment expense totalled $24.0 million and a further $24.0 million in share-based payments were capitalized (nine months ended September 30, 2014 - $20.8 million and $20.8 million, respectively). Share-based payments are higher in 2015 compared to the same periods in 2014, which reflects a higher number of options outstanding.
| DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A") | ||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| (000s) except per unit amounts | 2015 | 2014 | 2015 | 2014 | ||||||||||||
| Total depletion, depreciation and amortization | $ | 174,772 | $ | 123,919 | $ | 520,105 | $ | 366,556 | ||||||||
| Less mineral lease expiries | (12,960 | ) | (1,106 | ) | (49,394 | ) | (14,415 | ) | ||||||||
| Depletion, depreciation and amortization | $ | 161,812 | $ | 122,813 | $ | 470,711 | $ | 352,141 | ||||||||
| Per boe | $ | 11.70 | $ | 12.36 | $ | 11.82 | $ | 12.07 | ||||||||
DD&A expense, excluding mineral lease expiries, was $161.8 million for the third quarter of 2015 compared to $122.8 million for the same period of 2014. For the nine-month period ended September 30, 2015, DD&A expense (excluding mineral lease expiries) was $470.7 million compared to $352.1 million in the same period of 2014. The increase in DD&A expense in 2015 over 2014 is due to higher production volumes, as well as a larger capital asset base being depleted.
The per-unit DD&A rate (excluding the impact of mineral lease expiries) was $11.70/boe for the third quarter of 2015 compared to the rate of $12.36/boe for the same quarter in 2014. The per-unit DD&A rate (excluding the impact of mineral lease expiries) was $11.82/boe for the nine-month period ended September 30, 2015 compared to the rate of $12.07/boe in the same period of the prior year. The reduction in the rate for both the three and nine month periods reflects reserves added at a faster rate than the increase to the depletable base.
Mineral lease expiries for the three months ended September 30, 2015 were $13.0 million, compared to expiries in the same quarter of the prior year of $1.1 million. For the nine months ended September 30, 2015, expiries were $49.4 million compared with $14.4 million for the same period in 2014. The Company prioritizes drilling on what it believes to be the most cost-efficient and productive acreage, and with such a large land base, the Company has chosen not to continue some of the expiring sections of land.
| FINANCE EXPENSES | ||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||
| (000s) | 2015 | 2014 | Change | 2015 | 2014 | Change | ||||||||||||
| Interest expense | $ | 9,498 | $ | 5,793 | 64 | % | $ | 27,482 | $ | 16,112 | 71 | % | ||||||
| Accretion expense | 788 | 594 | 33 | % | 2,038 | 1,755 | 16 | % | ||||||||||
| Transaction costs on corporate and property acquisitions | 923 | - | 100 | % | 1,948 | 1,496 | 30 | % | ||||||||||
| Total finance expenses | $ | 11,209 | $ | 6,387 | 75 | % | $ | 31,468 | $ | 19,363 | 63 | % | ||||||
Finance expenses are comprised of interest expense, accretion of provisions and transaction costs associated with corporate and property acquisitions. Finance expenses for the three and nine months ended September 30, 2015 totaled $11.2 million and $31.5 million, respectively, compared to $6.4 million and $19.4 million for the same periods of 2014. The increase in finance expenses in 2015 over 2014 is mainly due to the higher average bank debt outstanding, partially offset by a lower average effective interest rate. The average bank debt outstanding for the nine months ended September 30, 2015 was $1,203.6 million (nine months ended September 30, 2014 - $639.2 million), with an average effective interest rate of 2.69% (2014 - 2.99%).
DEFERRED INCOME TAXES
For the three months ended September 30, 2015, the provision for deferred income tax expense was $14.0 million compared to $29.3 million for the same period in 2014. The decrease is primarily due to the lower pre-tax earnings recorded in the third quarter of 2015 compared to the respective period in 2014.
For the nine months ended September 30, 2015, the provision for deferred income tax expense was $65.2 million compared to $87.4 million for the same period in 2014. The decrease is due to lower pre-tax earnings recorded for the nine months ended September 30, 2015 compared to the respective period in 2014, which was partially offset by the increase in Alberta's corporate tax rate.
| CASH FLOW FROM OPERATING ACTIVITIES, CASH FLOW AND NET EARNINGS | |||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||
| (000s) except per unit amounts | 2015 | 2014 | Change | 2015 | 2014 | Change | |||||||
| Cash flow from operating activities | $ 261,398 | $ 233,047 | 12% | $ 606,796 | $ 714,193 | (15)% | |||||||
| Per share (1) | $ 1.19 | $ 1.13 | 5% | $ 2.85 | $ 3.52 | (19)% | |||||||
| Cash flow (2) | $ 197,100 | $ 211,635 | (7)% | $ 607,869 | $ 695,764 | (13)% | |||||||
| Per share (1)(2) | $ 0.90 | $ 1.03 | (13)% | $ 2.86 | $ 3.43 | (17)% | |||||||
| Net earnings | $ 28,489 | $ 67,357 | (58)% | $ 45,451 | $ 223,662 | (80)% | |||||||
| Per share (1) | $ 0.13 | $ 0.33 | (61)% | $ 0.21 | $ 1.10 | (81)% | |||||||
| Operating netback per boe (2) | $ 15.06 | $ 22.19 | (32)% | $ 16.02 | $ 24.64 | (35)% | |||||||
| (1) Fully diluted |
| (2) See "Non-GAAP Financial Measures" |
Cash flow for the three months ended September 30, 2015 was $197.1 million or $0.90 per share compared to $211.6 million or $1.03 per diluted share for the same period of 2014. Cash flow for the nine months ended September 30, 2015 was $607.9 million or $2.86 per share compared to $695.8 million or $3.43 per diluted share for the same period of 2014.
The Company had after-tax net earnings for the three months ended September 30, 2015 of $28.5 million or $0.13 per share compared to $67.4 million or $0.33 per diluted share for the same period of 2014. For the nine-month period ended September 30, 2015, after-tax net earnings were $45.5 million or $0.21 per share compared to $223.7 million or $1.10 per diluted share for the corresponding period of 2014. The decrease in both cash flow and after-tax net earnings in 2015 reflects significantly lower realized oil, natural gas and NGL prices, partially offset by an increase in production over 2014.
| CAPITAL EXPENDITURES | ||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| (000s) | 2015 | 2014 | 2015 | 2014 | ||||||||||||
| Land and seismic | $ | 8,477 | $ | 11,973 | $ | 37,376 | $ | 49,123 | ||||||||
| Drilling and completions | 290,153 | 354,715 | 676,420 | 772,750 | ||||||||||||
| Facilities | 122,866 | 277,771 | 392,528 | 572,369 | ||||||||||||
| Property acquisitions | 955 | - | 91,341 | 4,777 | ||||||||||||
| Property dispositions | (6,144 | ) | (2,425 | ) | (6,663 | ) | (2,525 | ) | ||||||||
| Other | 6,322 | 5,268 | 19,638 | 14,937 | ||||||||||||
| Total cash capital expenditures | $ | 422,629 | $ | 647,302 | $ | 1,210,640 | $ | 1,411,431 | ||||||||
During the third quarter of 2015, the Company invested $422.6 million of cash consideration, net of dispositions, compared to $647.3 million for the same period of 2014. Expenditures on exploration and production were $421.5 million compared to $644.5 million for the same quarter of 2014. During the nine-month period ended September 30, 2015, the Company invested $1,210.6 million of cash consideration, net of dispositions, compared to $1,411.4 million for the same period in 2014. The drilling and completion costs of $676.4 million in 2015 include 18.58 more net wells drilled and completed over 2014 at a lower cost per well reflecting continuous improvement of capital efficiencies. Facilities expenditures include work on the new Mulligan oil battery commissioned in the third quarter of 2015 and preliminary expenditures on the Spirit River Sour Gas Plant expansion and the new Edson Gas Plant, scheduled to be commissioned in the fourth quarter of 2015 or early 2016.
The following table summarizes the drill, complete and tie-in activities for the periods:
| Nine Months Ended September 30, 2015 | Nine Months Ended September 30, 2014 | |||||||
| Gross | Net | Gross | Net | |||||
| Drilled | 159 | 133.68 | 140 | 121.49 | ||||
| Completed | 138 | 118.47 | 127 | 112.08 | ||||
| Tied-in | 61 | 49.54 | 57 | 50.81 | ||||
Corporate Acquisitions
On July 20, 2015, the Company acquired all of the issued and outstanding shares of Bergen Resources Inc. ("Bergen"). As consideration, the Company issued 725,000 common shares at a price of $33.90 per share. Total transaction costs incurred by the Company of $0.2 million associated with this acquisition were expensed in the interim consolidated statement of income and comprehensive income. The acquisition resulted in an increase in Property, Plant and Equipment ("PP&E") of approximately $26.8 million and Exploration and Evaluation ("E&E") assets of $2.1 million along with net debt of $8.4 million.
On August 14, 2015, the Company acquired all of the issued and outstanding shares of Mapan Energy Ltd. ("Mapan"). As consideration, the Company issued 2,718,026 common shares at a price of $32.98 per share. Total transaction costs incurred by the Company of $1.1 million associated with this acquisition were expensed in the interim consolidated statement of income and comprehensive income. The acquisition resulted in an increase in PP&E of approximately $58.5 million along with working capital of $15.0 million. The acquisition of Mapan provides for an increase in lands and production in the Alberta Deep Basin, one of the Company's core areas.
LIQUIDITY AND CAPITAL RESOURCES
On March 12, 2015, the Company issued 640,000 flow-through common shares at a price of $50.00 per share, for total gross proceeds of $32.0 million. The proceeds were used to temporarily reduce bank debt and then to fund the Company's 2015 exploration and development program.
On April 1, 2015, the Company purchased Perpetual Energy Inc.'s interests in the West Edson area of the Alberta Deep Basin with the issuance 6,750,000 shares at a closing price on that date of $38.32 per share, for total consideration of $258.7 million.
On June 23, 2015, the Company issued 4,947,500 common shares at a price of $39.50 per share for total gross proceeds of $195.4 million. The proceeds were used to temporarily reduce bank debt and to fund the Company's 2015 exploration and development program.
On July 20, 2015, the Company closed the acquisition of Bergen with the issuance of 725,000 common shares at a price of $33.90 per Tourmaline share for consideration of $24.6 million. The Company also assumed Bergen's net debt of $8.4 million.
On August 14, 2015, the Company closed the acquisition of Mapan with the issuance of 2,718,026 common shares at a price of $32.98 per Tourmaline share for consideration of $89.6 million. The Company also assumed Mapan's working capital of $15.0 million.
The Company has a covenant-based, unsecured, bank credit facility in place with a syndicate of bankers. In June 2015, the Company increased the facility amount from $1,550.0 to $1,800.0 million. The term was also increased from three to four years, resulting in an initial maturity of June 2019. The maturity date may, at the request of the Company and with consent of the lenders, be extended on an annual basis. The credit facility also includes an expansion feature ("accordion") which allows the Company, upon approval from the lenders, to increase the facility amount by up to $500.0 million by adding a new financial institution or by increasing the commitment of its existing lenders. With the exception of the increase in the facility amount, length of term and the addition of the accordion feature, the debt was renewed under the same terms and conditions as those outlined in note 9 of the Company's consolidated financial statements for the year ended December 31, 2014. The Company also has a $50.0 million operating revolver, resulting in total bank credit facility capacity of $1,850.0 million. The facility can be drawn in either Canadian or U.S. funds and bears interest at the bank's prime lending rate, banker's acceptance rates or LIBOR (for U.S. borrowings), plus applicable margins, which range from 0.50% to 3.15% depending on the type of borrowing and the Company's senior debt to adjusted EBITDA ratio.
The Company also has a $250.0 million five-year term loan with a Canadian Chartered Bank. In September 2015, the Company extended the maturity of the term loan from November 30, 2019 to November 30, 2020 and the annual interest rate was reduced to 220 basis points from 240 basis points over the applicable bankers' acceptance rate. The covenants for the term loan are similar to those under the Company's current credit facility and the term loan will rank equally with the obligation under the Company's credit facility.
As at September 30, 2015, the Company had negative working capital of $339.2 million, after adjusting for the fair value of financial instruments (the unadjusted working capital deficiency was $297.7 million) (December 31, 2014 - $223.7 million and $189.9 million, respectively). As at September 30, 2015, the Company had $248.6 million in long-term debt outstanding and $896.3 million drawn against the revolving credit facility for total bank debt of $1,144.9 million (net of prepaid interest and debt issue costs) (December 31, 2014 - $918.9 million). Net debt at September 30, 2015 was $1,484.1 million (December 31, 2014 - $1,142.5 million). Management believes the Company has sufficient liquidity and capital resources to fund the remainder of its 2015 and 2016 exploration and development programs through expected cash flow from operations and its unutilized borrowing capacity. As at September 30, 2015, the Company is in compliance with all debt covenant calculations.
SHARES AND STOCK OPTIONS OUTSTANDING
As at November 4, 2015, the Company has 220,812,892 common shares outstanding and 16,626,413 stock options granted and outstanding.
COMMITMENTS AND CONTRACTUAL OBLIGATIONS
In the normal course of business, the Company is obligated to make future payments. These obligations represent contracts and other commitments that are known and non-cancellable.
| PAYMENTS DUE BY YEAR | |||||||||||||||
| (000s) | 1 Year | 2-3 Years | 4-5 Years | > 5 Years | Total | ||||||||||
| Operating leases | $ | 5,078 | $ | 11,053 | $ | 8,073 | $ | - | $ | 24,204 | |||||
| Firm transportation and processing agreements | 144,911 | 404,016 | 272,675 | 547,360 | 1,368,962 | ||||||||||
| Capital commitments (1) | 313,244 | 908,283 | 75,000 | - | 1,296,527 | ||||||||||
| Flow-through share commitments | 24,435 | - | - | - | 24,435 | ||||||||||
| Credit facility (2) | - | - | 988,552 | - | 988,552 | ||||||||||
| Term debt (3) | 11,131 | 22,263 | 22,263 | 251,157 | 306,814 | ||||||||||
| $ | 498,799 | $ | 1,345,615 | $ | 1,366,563 | $ | 798,517 | $ | 4,009,494 | ||||||
| (1) Includes drilling commitments, and capital spending commitments under the joint arrangement in the Spirit River complex of $300.0 million per year until 2019. The capital spending commitment under the joint arrangement can be deferred to future periods in the event of an economic downturn, and as agreed upon by both parties. |
| (2) Includes interest expense at an annual rate of 2.52% being the rate applicable to outstanding debt on the credit facility at September 30, 2015. |
| (3) Includes interest expense at an annual rate of 4.47% being the fixed rate on the term debt (including the interest rate swap) at September 30, 2015. |
OFF BALANCE SHEET ARRANGEMENTS
The Company has certain lease arrangements, all of which are reflected in the commitments and contractual obligations table, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or general and administrative expenses depending on the nature of the lease.
FINANCIAL RISK MANAGEMENT
The Board of Directors has overall responsibility for the establishment and oversight of the Company's risk management framework. The Board has implemented and monitors compliance with risk management policies.
The Company's risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company's activities. The Company's financial risks are discussed in note 5 of the Company's audited consolidated financial statements for the year ended December 31, 2014.
As at September 30, 2015, the Company has entered into certain financial derivative contracts in order to manage commodity price and interest rate risk. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, even though the Company considers all commodity contracts to be effective economic hedges. Such financial derivative contracts are recorded on the consolidated statement of financial position at fair value, with changes in the fair value being recognized as an unrealized gain or loss on the consolidated statement of income and comprehensive income. The contracts that the Company has in place at September 30, 2015 are summarized and disclosed in note 3 of the Company's unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2015 and 2014.
The Company has entered into physical delivery sales contracts to manage commodity risk. These contracts are considered normal sales contracts and are not recorded at fair value in the consolidated financial statements. Physical contracts in place at September 30, 2015 have been summarized and disclosed in note 3 of the Company's unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2015 and 2014.
Financial derivative and physical delivery contracts entered into subsequent to September 30, 2015 are detailed in note 3 of the Company's unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2015 and 2014.
APPLICATION OF CRITICAL ACCOUNTING ESTIMATES
Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Management reviews its estimates on a regular basis. The emergence of new information and changed circumstances may result in actual results or changes to estimates that differ materially from current estimates. The Company's use of estimates and judgments in preparing the interim condensed consolidated financial statements is discussed in note 1 of the consolidated financial statements for the year ended December 31, 2014.
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING
The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures ("DC&P"), as defined by National Instrument 52-109. The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal controls over financial reporting ("ICFR"), as defined by National Instrument 52-109, to provide reasonable assurance regarding the reliability of the Company's financial reporting and the preparation of financial statements for external purposes in accordance with IFRS.
There were no changes in the Company's DC&P or ICFR during the period beginning on July 1, 2015 and ending on September 30, 2015 that have materially affected, or are reasonably likely to materially affect, the Company's ICFR. It should be noted that a control system, including the Company's disclosure and internal controls and procedures, no matter how well conceived can provide only reasonable, but not absolute assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.
In May 2013, the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") issued an updated Internal Control-Integrated Framework ("2013 Framework") replacing the Internal Control-Integrated Framework (1992). Tourmaline adopted the 2013 Framework for the year ended December 31, 2014.
BUSINESS RISKS AND UNCERTAINTIES
Tourmaline monitors and complies with current government regulations that affect its activities, although operations may be adversely affected by changes in government policy, regulations or taxation. In addition, Tourmaline maintains a level of liability, property and business interruption insurance which is believed to be adequate for Tourmaline's size and activities, but is unable to obtain insurance to cover all risks within the business or in amounts to cover all possible claims.
See "Forward-Looking Statements" in this MD&A and "Risk Factors" in Tourmaline's most recent annual information form for additional information regarding the risks to which Tourmaline and its business and operations are subject.
IMPACT OF ENVIRONMENTAL REGULATIONS
The oil and gas industry is currently subject to regulation pursuant to a variety of provincial and federal environmental legislation, all of which is subject to governmental review and revision from time to time. Such legislation provides for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. In addition, such legislation sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability and the imposition of material fines and penalties.
The use of fracture stimulations has been ongoing safely in an environmentally responsible manner in western Canada for decades. With the increase in the use of fracture stimulations in horizontal wells there is increased communication between the oil and natural gas industry and a wider variety of stakeholders regarding the responsible use of this technology. This increased attention to fracture stimulations may result in increased regulation or changes of law which may make the conduct of the Company's business more expensive or prevent the Company from conducting its business as currently conducted. Tourmaline focuses on conducting transparent, safe and responsible operations in the communities in which its people live and work.
NON-GAAP FINANCIAL MEASURES
This MD&A or documents referred to in this MD&A make reference to the terms "cash flow", "operating netback", "working capital (adjusted for the fair value of financial instruments)", "net debt", "adjusted EBITDA", "senior debt", "total debt", and "total capitalization" which are not recognized measures under GAAP, and do not have a standardized meaning prescribed by GAAP. Accordingly, the Company's use of these terms may not be comparable to similarly defined measures presented by other companies. Management uses the terms "cash flow", "operating netback", "working capital (adjusted for the fair value of financial instruments)" and "net debt", for its own performance measures and to provide shareholders and potential investors with a measurement of the Company's efficiency and its ability to generate the cash necessary to fund a portion of its future growth expenditures or to repay debt. Investors are cautioned that the non-GAAP measures should not be construed as an alternative to net income determined in accordance with GAAP as an indication of the Company's performance. The terms "adjusted EBITDA", "senior debt", "total debt", and "total capitalization" are not used by management in measuring performance but are used in the financial covenants under the Company's credit facility. Under the Company's credit facility "adjusted EBITDA" means generally net income or loss, excluding extraordinary items, plus interest expense and income taxes and adjusted for non-cash items and gains or losses on dispositions, "senior debt" means the sum of drawn amounts on the credit facility, the term loan and outstanding letters of credit less cash and cash equivalents and excluding debt issue costs ("bank debt"), "total debt" means generally the sum of "senior debt" plus subordinated debt, Tourmaline currently does not have any subordinated debt, and "total capitalization" means generally the sum of the Company's shareholders' equity and all other indebtedness of the Company including bank debt, all determined on a consolidated basis in accordance with GAAP.
Cash Flow
A summary of the reconciliation of cash flow from operating activities (per the statements of cash flow), to cash flow, is set forth below:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| (000s) | 2015 | 2014 | 2015 | 2014 | |||||||||||
| Cash flow from operating activities (per GAAP) | $ | 261,398 | $ | 233,047 | $ | 606,796 | $ | 714,193 | |||||||
| Change in non-cash working capital | (64,298 | ) | (21,412 | ) | 1,073 | (18,429 | ) | ||||||||
| Cash flow | $ | 197,100 | $ | 211,635 | $ | 607,869 | $ | 695,764 | |||||||
Operating Netback
Operating netback is calculated on a per-boe basis and is defined as revenue (excluding processing income) less royalties, transportation costs and operating expenses, as shown below:
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| ($/boe) | 2015 | 2014 | 2015 | 2014 | ||||||||||||
| Revenue, excluding processing income | $ | 22.61 | $ | 32.41 | $ | 23.41 | $ | 35.03 | ||||||||
| Royalties | (1.07 | ) | (2.97 | ) | (0.89 | ) | (3.31 | ) | ||||||||
| Transportation costs | (1.98 | ) | (1.84 | ) | (2.07 | ) | (1.88 | ) | ||||||||
| Operating expenses | (4.51 | ) | (5.41 | ) | (4.43 | ) | (5.20 | ) | ||||||||
| Operating netback (1) | $ | 15.06 | $ | 22.19 | $ | 16.02 | $ | 24.64 | ||||||||
| (1) May not add due to rounding. |
Working Capital (Adjusted for the Fair Value of Financial Instruments)
A summary of the reconciliation of working capital to working capital (adjusted for the fair value of financial instruments) is set forth below:
| (000s) | As at September 30, 2015 | As at December 31, 2014 | ||||||
| Working capital (deficit) | $ | (297,698 | ) | $ | (189,928 | ) | ||
| Fair value of financial instruments - short-term (net) | (41,479 | ) | (33,727 | ) | ||||
| Working capital (deficit) (adjusted for the fair value of financial instruments) | $ | (339,177 | ) | $ | (223,655 | ) | ||
Net Debt
A summary of the reconciliation of net debt is set forth below:
| (000s) | As at September 30, 2015 | As at December 31, 2014 | ||||||
| Bank debt | $ | (1,144,918 | ) | $ | (918,854 | ) | ||
| Working capital (deficit) | (297,698 | ) | (189,928 | ) | ||||
| Fair value of financial instruments - short-term (net) | (41,479 | ) | (33,727 | ) | ||||
| Net debt | $ | (1,484,095 | ) | $ | (1,142,509 | ) | ||
| SELECTED QUARTERLY INFORMATION |
| 2015 | 2014 | 2013 | |||||||||||||||||||||||
| ($000s, unless otherwise noted) | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | |||||||||||||||||
| PRODUCTION | |||||||||||||||||||||||||
| Natural gas (mcf) | 72,395,759 | 69,606,629 | 67,548,751 | 63,719,524 | 51,771,964 | 51,225,036 | 47,339,926 | 41,062,993 | |||||||||||||||||
| Oil and NGL(bbls) | 1,761,403 | 1,469,591 | 1,677,123 | 1,426,951 | 1,307,089 | 1,468,198 | 1,340,699 | 1,076,395 | |||||||||||||||||
| Oil equivalent (boe) | 13,827,363 | 13,070,696 | 12,935,248 | 12,046,872 | 9,935,749 | 10,005,704 | 9,230,686 | 7,920,228 | |||||||||||||||||
| Natural gas (mcf/d) | 786,910 | 764,908 | 750,542 | 692,604 | 562,739 | 562,912 | 525,999 | 446,337 | |||||||||||||||||
| Oil and NGL (bbls/d) | 19,146 | 16,149 | 18,635 | 15,510 | 14,207 | 16,134 | 14,897 | 11,700 | |||||||||||||||||
| Oil equivalent (boe/d) | 150,297 | 143,634 | 143,725 | 130,944 | 107,997 | 109,953 | 102,563 | 86,089 | |||||||||||||||||
| FINANCIAL | |||||||||||||||||||||||||
| Revenue, net of royalties | 332,927 | 283,062 | 312,834 | 351,939 | 311,586 | 313,655 | 317,336 | 219,069 | |||||||||||||||||
| Cash flow from operating activities | 261,398 | 151,028 | 194,370 | 201,188 | 233,047 | 231,756 | 249,390 | 128,852 | |||||||||||||||||
| Cash flow (1) | 197,100 | 203,029 | 207,740 | 233,238 | 211,635 | 231,542 | 252,587 | 160,732 | |||||||||||||||||
| Per diluted share | 0.90 | 0.95 | 1.01 | 1.14 | 1.03 | 1.13 | 1.28 | 0.83 | |||||||||||||||||
| Net earnings (loss) | 28,489 | (5,197 | ) | 22,159 | 265,210 | 67,357 | 66,437 | 89,868 | 56,763 | ||||||||||||||||
| Per basic share | 0.13 | (0.02 | ) | 0.11 | 1.31 | 0.33 | 0.33 | 0.47 | 0.30 | ||||||||||||||||
| Per diluted share | 0.13 | (0.02 | ) | 0.11 | 1.29 | 0.33 | 0.32 | 0.45 | 0.29 | ||||||||||||||||
| Total assets | 7,471,042 | 7,071,801 | 6,801,583 | 6,622,303 | 5,978,645 | 5,446,094 | 5,082,535 | 4,696,471 | |||||||||||||||||
| Working capital (deficit) | (297,698 | ) | (70,156 | ) | (195,907 | ) | (189,928 | ) | (493,160 | ) | (131,672 | ) | (255,240 | ) | (245,314 | ) | |||||||||
| Working capital (deficit) (adjusted for the fair value of financial instruments) (1) | (339,177 | ) | (86,090 | ) | (232,572 | ) | (223,655 | ) | (495,222 | ) | (123,166 | ) | (248,094 | ) | (242,623 | ) | |||||||||
| Cash capital expenditures | 422,629 | 290,629 | 497,382 | 152,135 | 647,302 | 297,733 | 466,396 | 497,941 | |||||||||||||||||
| Total outstanding shares (000s) | 220,813 | 216,378 | 204,284 | 203,162 | 201,673 | 201,431 | 195,567 | 189,805 | |||||||||||||||||
| PER UNIT | |||||||||||||||||||||||||
| Natural gas ($/mcf) | 3.20 | 3.17 | 3.69 | 4.09 | 4.34 | 4.71 | 5.38 | 3.84 | |||||||||||||||||
| Oil and NGL ($/bbl) | 45.91 | 53.34 | 43.13 | 55.91 | 74.61 | 74.53 | 70.49 | 71.83 | |||||||||||||||||
| Revenue ($/boe) | 22.61 | 22.85 | 24.84 | 28.25 | 32.41 | 35.03 | 37.84 | 29.69 | |||||||||||||||||
| Operating netback ($/boe)(1) | 15.06 | 16.37 | 16.70 | 20.23 | 22.19 | 24.02 | 27.94 | 21.29 | |||||||||||||||||
| (1) See Non-GAAP Financial Measures. |
The oil and gas exploration and production industry is cyclical. The Company's financial position, results of operations and cash flows are principally impacted by production levels and commodity prices, particularly natural gas prices.
Overall, the Company has had continued annual growth over the last two years summarized in the table above. The Company's average annual production has increased from 74,796 boe per day in 2013 to 112,929 boe per day in 2014 and 145,909 boe per day in the first nine months of 2015. The production growth can be attributed primarily to the Company's exploration and development activities, and from acquisitions of producing properties.
The Company's cash flow was $526.8 million in 2013, $929.0 million in 2014, and 2015 forecast cash flow is $886.8 million, reflecting the strong production growth year over year. 2015 cash flow to date has been significantly impacted by the drop in commodity prices. Commodity price fluctuations can indirectly impact expected production by changing the amount of funds available to reinvest in exploration, development and acquisition activities in the future. Changes in commodity prices impact revenue and cash flow available for exploration, and also the economics of potential capital projects as low commodity prices can potentially reduce the quantities of reserves that are commercially recoverable. The Company's capital program is dependent on cash flow generated from operations and access to capital markets.
| CONSOLIDATED FINANCIAL STATEMENTS | |||||||
| CONSOLIDATED STATEMENTS OF FINANCIAL POSITION | |||||||
September 30, | December 31, | ||||||
| (000s) (unaudited) | 2015 | 2014 | |||||
| Assets | |||||||
| Current assets: | |||||||
| Cash and cash equivalents | $ | - | $ | 263,052 | |||
| Accounts receivable | 164,761 | 203,212 | |||||
| Prepaid expenses and deposits | 22,339 | 11,417 | |||||
| Fair value of financial instruments (note 3) | 45,003 | 35,571 | |||||
| Total current assets | 232,103 | 513,252 | |||||
| Fair value of financial instruments (note 3) | 8,283 | - | |||||
| Long-term asset | 6,852 | 7,145 | |||||
| Exploration and evaluation assets (notes 4 and 5) | 666,696 | 635,633 | |||||
| Property, plant and equipment (note 5) | 6,557,108 | 5,466,273 | |||||
| Total Assets | $ | 7,471,042 | $ | 6,622,303 | |||
| Liabilities and Shareholders' Equity | |||||||
| Current liabilities: | |||||||
| Accounts payable and accrued liabilities | $ | 526,277 | $ | 701,336 | |||
| Fair value of financial instruments (note 3) | 3,524 | 1,844 | |||||
| Total current liabilities | 529,801 | 703,180 | |||||
| Bank debt (note 7) | 1,144,918 | 918,854 | |||||
| Fair value of financial instruments (note 3) | 11,317 | 6,356 | |||||
| Deferred premium on flow-through shares (note 9) | 4,825 | 3,210 | |||||
| Decommissioning obligations (note 6) | 144,454 | 114,038 | |||||
| Deferred taxes | 465,278 | 422,090 | |||||
| Shareholders' equity: | |||||||
| Share capital (note 9) | 4,252,770 | 3,615,378 | |||||
| Non-controlling interest (note 8) | 28,736 | 30,006 | |||||
| Contributed surplus | 158,626 | 124,325 | |||||
| Retained earnings | 730,317 | 684,866 | |||||
| Total shareholders' equity | 5,170,449 | 4,454,575 | |||||
| Total Liabilities and Shareholders' Equity | $ | 7,471,042 | $ | 6,622,303 | |||
| Commitments (note 12) |
| Subsequent events (note 3) |
| See accompanying notes to the interim condensed consolidated financial statements. |
| CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||
| (000s) except per-share amounts (unaudited) | 2015 | 2014 | 2015 | 2014 | |||||||||||||
| Revenue: | |||||||||||||||||
| Oil and natural gas sales | $ | 267,210 | $ | 320,476 | $ | 781,990 | $ | 1,063,713 | |||||||||
| Royalties | (14,755 | ) | (29,549 | ) | (35,286 | ) | (96,587 | ) | |||||||||
| Net revenue from oil and natural gas sales | 252,455 | 290,927 | 746,704 | 967,126 | |||||||||||||
| Realized gain (loss) on financial instruments | 45,434 | 1,509 | 150,653 | (41,923 | ) | ||||||||||||
| Unrealized gain on financial instruments (note 3) | 27,874 | 15,606 | 11,196 | 4,429 | |||||||||||||
| Other income | 7,164 | 3,544 | 20,270 | 12,945 | |||||||||||||
| Total net revenue | 332,927 | 311,586 | 928,823 | 942,577 | |||||||||||||
| Expenses: | |||||||||||||||||
| Operating | 62,299 | 53,758 | 176,637 | 151,645 | |||||||||||||
| Transportation | 27,384 | 18,235 | 82,510 | 54,866 | |||||||||||||
| General and administration | 7,682 | 6,459 | 19,913 | 18,208 | |||||||||||||
| Share-based payments (note 11) | 7,585 | 7,334 | 24,009 | 20,841 | |||||||||||||
| (Gain) on divestitures | - | (1,808 | ) | (35,232 | ) | (2,009 | ) | ||||||||||
| Depletion, depreciation and amortization | 174,772 | 123,919 | 520,105 | 366,556 | |||||||||||||
| Total expenses | 279,722 | 207,897 | 787,942 | 610,107 | |||||||||||||
| Income from operations | 53,205 | 103,689 | 140,881 | 332,470 | |||||||||||||
| Finance expenses | 11,209 | 6,387 | 31,468 | 19,363 | |||||||||||||
| Income before taxes | 41,996 | 97,302 | 109,413 | 313,107 | |||||||||||||
| Deferred taxes | 13,969 | 29,303 | 65,232 | 87,433 | |||||||||||||
| Net income and comprehensive income before non-controlling interest | 28,027 | 67,999 | 44,181 | 225,674 | |||||||||||||
| Net income (loss) and comprehensive income (loss) attributable to: | |||||||||||||||||
| Shareholders of the Company | 28,489 | 67,357 | 45,451 | 223,662 | |||||||||||||
| Non-controlling interest (note 8) | (462 | ) | 642 | (1,270 | ) | 2,012 | |||||||||||
| $ | 28,027 | $ | 67,999 | $ | 44,181 | $ | 225,674 | ||||||||||
| Net income per share attributable to common shareholders (note 10) | |||||||||||||||||
| Basic | $ | 0.13 | $ | 0.33 | $ | 0.22 | $ | 1.13 | |||||||||
| Diluted | $ | 0.13 | $ | 0.33 | $ | 0.21 | $ | 1.10 | |||||||||
| See accompanying notes to the interim condensed consolidated financial statements. |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY | |||||||||||||||||||
| (000s) (unaudited) | Share Capital | Contributed Surplus | Retained Earnings | Non-Controlling Interest | Total Equity | ||||||||||||||
| Balance at December 31, 2014 | $ | 3,615,378 | $ | 124,325 | $ | 684,866 | $ | 30,006 | $ | 4,454,575 | |||||||||
| Issue of common shares (note 9) | 221,108 | - | - | - | 221,108 | ||||||||||||||
| Issue of common shares on acquisitions (note 9) | 372,878 | - | - | - | 372,878 | ||||||||||||||
| Share issue costs, net of tax | (6,562 | ) | - | - | - | (6,562 | ) | ||||||||||||
| Share-based payments | - | 24,009 | - | - | 24,009 | ||||||||||||||
| Capitalized share-based payments | - | 24,009 | - | - | 24,009 | ||||||||||||||
| Options exercised (notes 9 and 11) | 49,968 | (13,717 | ) | - | - | 36,251 | |||||||||||||
| Income attributable to common shareholders | - | - | 45,451 | - | 45,451 | ||||||||||||||
| Loss attributable to non-controlling interest | - | - | - | (1,270 | ) | (1,270 | ) | ||||||||||||
| Balance at September 30, 2015 | $ | 4,252,770 | $ | 158,626 | $ | 730,317 | $ | 28,736 | $ | 5,170,449 | |||||||||
| (000s) (unaudited) | Share Capital | Contributed Surplus | Retained Earnings | Non-Controlling Interest | Total Equity | |||||
| Balance at December 31, 2013 | $ 3,062,432 | $ 91,718 | $ 195,994 | $ 17,877 | $ 3,368,021 | |||||
| Issue of common shares | 282,012 | - | - | - | 282,012 | |||||
| Issue of common shares on acquisitions | 177,359 | - | - | - | 177,359 | |||||
| Share issue costs, net of tax | (9,524) | - | - | - | (9,524) | |||||
| Share-based payments | - | 20,841 | - | - | 20,841 | |||||
| Capitalized share-based payments | - | 20,841 | - | - | 20,841 | |||||
| Options exercised | 65,852 | (17,824) | - | - | 48,028 | |||||
| Income attributable to common shareholders | - | - | 223,662 | - | 223,662 | |||||
| Income attributable to non-controlling interest | - | - | - | 2,012 | 2,012 | |||||
| Balance at September 30, 2014 | $ 3,578,131 | $ 115,576 | $ 419,656 | $ 19,889 | $ 4,133,252 | |||||
See accompanying notes to the interim condensed consolidated financial statements.
| CONSOLIDATED STATEMENTS OF CASH FLOW | ||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||
| (000s) (unaudited) | 2015 | 2014 | 2015 | 2014 | ||||||||||||||
| Cash provided by (used in): | ||||||||||||||||||
| Operations: | ||||||||||||||||||
| Net income | $ | 28,489 | $ | 67,357 | $ | 45,451 | $ | 223,662 | ||||||||||
| Items not involving cash: | ||||||||||||||||||
| Depletion, depreciation and amortization | 174,772 | 123,919 | 520,105 | 366,556 | ||||||||||||||
| Accretion | 788 | 594 | 2,038 | 1,755 | ||||||||||||||
| Share-based payments | 7,585 | 7,334 | 24,009 | 20,841 | ||||||||||||||
| Deferred taxes | 13,969 | 29,303 | 65,232 | 87,433 | ||||||||||||||
| Unrealized (gain) on financial instruments | (27,874 | ) | (15,606 | ) | (11,196 | ) | (4,429 | ) | ||||||||||
| (Gain) on divestitures | - | (1,808 | ) | (35,232 | ) | (2,009 | ) | |||||||||||
| Non-controlling interest | (462 | ) | 642 | (1,270 | ) | 2,012 | ||||||||||||
| Decommissioning expenditures | (167 | ) | (100 | ) | (1,268 | ) | (57 | ) | ||||||||||
| Changes in non-cash operating working capital | 64,298 | 21,412 | (1,073 | ) | 18,429 | |||||||||||||
| Total cash flow from operating activities | 261,398 | 233,047 | 606,796 | 714,193 | ||||||||||||||
| Financing: | ||||||||||||||||||
| Issue of common shares | 18,210 | 4,952 | 263,676 | 345,622 | ||||||||||||||
| Share issue costs | (3 | ) | (87 | ) | (9,386 | ) | (12,732 | ) | ||||||||||
| Increase (decrease) in bank debt | (38,785 | ) | 59,611 | 239,808 | 143,738 | |||||||||||||
| Total cash flow from financing activities | (20,578 | ) | 64,476 | 494,098 | 476,628 | |||||||||||||
| Investing: | ||||||||||||||||||
| Exploration and evaluation | (38,785 | ) | (52,098 | ) | (106,834 | ) | (142,590 | ) | ||||||||||
| Property, plant and equipment | (389,033 | ) | (597,629 | ) | (1,019,128 | ) | (1,266,589 | ) | ||||||||||
| Property acquisitions | (955 | ) | - | (91,341 | ) | (4,777 | ) | |||||||||||
| Proceeds from divestitures | 6,144 | 2,425 | 6,663 | 2,525 | ||||||||||||||
| Net repayment of long-term obligation | (671 | ) | (996 | ) | (2,402 | ) | (2,595 | ) | ||||||||||
| Changes in non-cash investing working capital | 182,480 | 350,775 | (150,904 | ) | 223,205 | |||||||||||||
| Total cash flow used in investing activities | (240,820 | ) | (297,523 | ) | (1,363,946 | ) | (1,190,821 | ) | ||||||||||
| Changes in cash | - | - | (263,052 | ) | - | |||||||||||||
| Cash, beginning of period | - | - | 263,052 | - | ||||||||||||||
| Cash, end of period | $ | - | $ | - | $ | - | $ | - | ||||||||||
| Cash is defined as cash and cash equivalents. |
| See accompanying notes to the interim condensed consolidated financial statements. |
NOTES TO THE INTERIM CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS
AS AT SEPTEMBER 30, 2015 AND FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2015 AND 2014
(tabular amounts in thousands of dollars, unless otherwise noted) (unaudited)
Corporate Information:
Tourmaline Oil Corp. (the "Company") was incorporated under the laws of the Province of Alberta on July 21, 2008. The Company is engaged in the acquisition, exploration, development and production of petroleum and natural gas properties. These unaudited interim condensed consolidated financial statements reflect only the Company's proportionate interest in such activities.
The Company's registered office is located at Suite 2400, 525 - 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, 2014.
The accounting policies and significant accounting judgments, estimates, and assumptions used in these unaudited interim condensed consolidated financial statements are consistent with those described in Notes 1 and 2 of the Company's consolidated financial statements for the year ended December 31, 2014.
The unaudited interim condensed consolidated financial statements were authorized for issue by the Board of Directors on November 4, 2015.
2. DETERMINATION OF FAIR VALUE
A number of the Company's accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.
Tourmaline classifies the fair value of transactions according to the following hierarchy based on the amount of observable inputs used to value the instrument.
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1. Prices are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.
Level 3 - Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.
The fair value of cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities approximate their carrying amounts due to their short term nature. Bank debt bears interest at a floating market rate with applicable variable margins, and accordingly the fair market value approximates the carrying amount. The Company's financial instruments have been assessed on the fair value hierarchy described above and classified as Level 2.
3. FINANCIAL RISK MANAGEMENT
The Board of Directors has overall responsibility for the establishment and oversight of the Company's risk management framework. The Board has implemented and monitors compliance with risk management policies.
The Company's risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company's activities. The Company's financial risks are consistent with those discussed in note 5 of the Company's consolidated financial statements for the year ended December 31, 2014.
As at September 30, 2015, the Company has entered into certain financial derivative contracts in order to manage commodity price and interest rate risk. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, even though the Company considers all commodity and interest rate contracts to be effective economic hedges. As a result, all such contracts are recorded on the interim consolidated statement of financial position at fair value, with changes in the fair value being recognized as an unrealized gain or loss on the interim consolidated statement of income and comprehensive income.
The Company has the following financial derivative contracts in place as at September 30, 2015 (1):
| (000s) | 2015 | 2016 | 2017 | 2018 | 2019 | Fair Value | ||||||||||||||
| Gas | ||||||||||||||||||||
| Financial swaps | mmbtu/d | 61,630 | 65,000 | - | - | - | $ | 12,223 | ||||||||||||
| USD$/mmbtu | $ | 3.15 | $ | 3.08 | ||||||||||||||||
| Nymex call options (writer) | mmbtu/d | - | - | 20,000 | 20,000 | - | $ | (1,073 | ) | |||||||||||
| USD$/mmbtu | $ | 5.00 | $ | 5.00 | ||||||||||||||||
| Oil | ||||||||||||||||||||
| Financial swaps | bbls/d | 2,200 | 2,500 | - | - | - | $ | 33,973 | ||||||||||||
| USD$/bbl | $ | 76.73 | $ | 69.13 | ||||||||||||||||
| Costless collars | bbls/d | 1,300 | - | - | - | - | $ | 7,052 | ||||||||||||
| USD$/bbl | $ | 81.15 - $94.29 | ||||||||||||||||||
| Financial call swaptions (2) | bbls/d | - | 1,400 | 2,500 | - | - | $ | (2,840 | ) | |||||||||||
| USD$/bbl | $ | 82.25 | $ | 69.13 | ||||||||||||||||
| Total Fair Value | $ | 49,335 | ||||||||||||||||||
| (1) The volumes and prices reported are the weighted-average volumes and prices for the period. |
| (2) This is a European swaption whereby the Company provides the option to extend an oil swap into the period subsequent to the call date. |
The Company has entered into the following financial derivative contracts subsequent to September 30, 2015:
| Type of Contract | Quantity | Time Period | Contract Price | |||
| Oil Financial Swap | 500 bbls/d | January 2016 - December 2016 | USD $56.50/bbl | |||
| Oil Financial Call Swaptions(1) | 500 bbls/d | January 2017 - December 2017 | USD $56.50/bbl | |||
| (1) One time option to call on December 31, 2016. |
The Company has the following interest rate swap arrangements:
| (000s) | ||||||||||||||
| Term | Type (Floating to Fixed) | Amount | Company Fixed Interest Rate | Counter Party Floating Rate Index | Fair Value | |||||||||
| Nov 28, 2014 - Nov 28, 2019 | Swap | $ | 250,000 | 2.065 | % | Floating Rate | $ | (10,889 | ) | |||||
The following table provides a summary of the unrealized gains (losses) on financial instruments for the three and nine months ended September 30, 2015 and 2014:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||
| (000s) | 2015 | 2014 | 2015 | 2014 | |||||||||||
| Unrealized gain on financial instruments - commodity contracts | $ | 29,063 | $ | 15,548 | $ | 17,922 | $ | 4,776 | |||||||
| Unrealized gain (loss) on financial instruments - interest rate swaps | (1,189 | ) | 58 | (6,726 | ) | (347 | ) | ||||||||
| Total unrealized gain on financial instruments | $ | 27,874 | $ | 15,606 | $ | 11,196 | $ | 4,429 | |||||||
In addition to the financial commodity contracts discussed above, the Company has entered into physical delivery sales contracts to manage commodity risk. These contracts are considered normal sales contracts and are not recorded at fair value in the consolidated financial statements.
The Company has the following physical contracts in place at September 30, 2015 (1)(6):
| 2015 | 2016 | 2017 | 2018 | 2019 | ||||||||||||||||||
| Gas | ||||||||||||||||||||||
| Fixed price - AECO | mcf/d | 174,131 | 32,760 | - | - | - | ||||||||||||||||
| CAD$/mcf | $ | 3.71 | $ | 3.32 | - | - | - | |||||||||||||||
| Fixed price - AECO (USD) | mmbtu/d | 21,739 | 3,730 | - | - | - | ||||||||||||||||
| USD$/mmbtu | $ | 2.56 | $ | 2.72 | - | - | - | |||||||||||||||
| Fixed price - Stn 2 | mcf/d | 22,159 | - | - | - | - | ||||||||||||||||
| CAD$/mcf | $ | 3.45 | - | - | - | - | ||||||||||||||||
| Basis differentials (2)(3) | mmbtu/d | 18,261 | 63,770 | 22,500 | 22,500 | 22,500 | ||||||||||||||||
| USD$/mmbtu | $ | (0.38 | ) | $ | (0.52 | ) | $ | (0.46 | ) | $ | (0.46 | ) | $ | (0.46 | ) | |||||||
| Basis differentials - Stn 2 (4) | mcf/d | - | 52,152 | 37,929 | 37,929 | 9,482 | ||||||||||||||||
| CAD$/mcf | - | $ | (0.33 | ) | $ | (0.29 | ) | $ | (0.29 | ) | $ | (0.26 | ) | |||||||||
| AECO Monthly Calls / Call Swaptions (5) | mcf/d | 89,524 | 134,475 | 75,857 | 42,670 | - | ||||||||||||||||
| CAD$/mcf | $ | 4.08 | $ | 4.34 | $ | 4.60 | $ | 4.80 | - | |||||||||||||
| Oil | ||||||||||||||||||||||
| Fixed Price | bbls/d | 1,026 | - | - | - | - | ||||||||||||||||
| USD$/bbl | $ | 55.38 | - | - | - | - | ||||||||||||||||
| (1) The volumes and prices reported are the weighted-average volumes and prices for the period. |
| (2) Tourmaline also has 22.5 mmcf/d of Nymex-AECO basis differentials at $(0.46) from 2020-2022. |
| (3) Tourmaline also has 10,000 mmbtu/d SoCal - AECO basis differential at $(0.73) from November 2013 to October 2016. |
| (4) Station 2 - AECO basis differential. Tourmaline also has 9,482 mcf/d of Stn 2. basis differentials at $(0.26) for 2020-2021. |
| (5) These are European swaptions whereby the Company provides the option to extend a gas swap into the period subsequent to the call date or increase the volumes under contract. |
| (6) Tourmaline also has entered into deals to sell 50,000 mmbtu/d at Chicago GDD pricing less transportation costs from April 2015 to October 2020 and 20,000 mmbtu/d at Ventura GDD pricing less transportation costs from April 2015 to October 2020. |
The Company has entered into the following physical contracts subsequent to September 30, 2015(1):
| Type of Contract | Quantity | Time Period | Contract Price | |||
| Basis Differentials | 10,000 MMbtu/d | January 2016 - December 2016 | USD $(0.66)/MMbtu | |||
| (1) Transactions with common terms have been aggregated and presented at the weighted average price. |
4. EXPLORATION AND EVALUATION ASSETS
| (000s) | |||||
| As at December 31, 2014 | $ | 635,633 | |||
| Capital expenditures | 106,834 | ||||
| Transfers to property, plant and equipment (note 5) | (69,610 | ) | |||
| Acquisitions | 67,938 | ||||
| Divestitures | (24,705 | ) | |||
| Expired mineral leases | (49,394 | ) | |||
| As at September 30, 2015 | $ | 666,696 | |||
Exploration and evaluation ("E&E") assets consist of the Company's exploration projects which are pending the determination of proven and probable reserves, as well as undeveloped land. Additions represent the Company's share of costs on E&E assets during the period.
Impairment Assessment
In accordance with IFRS, an impairment test is performed if the Company identifies an indicator of impairment. At September 30, 2015 and December 31, 2014, the Company determined that no indicators of impairment existed on its E&E assets; therefore, an impairment test was not performed.
5. PROPERTY, PLANT AND EQUIPMENT
Cost
| (000s) | |||||
| As at December 31, 2014 | $ | 6,733,617 | |||
| Capital expenditures | 1,043,137 | ||||
| Transfers from exploration and evaluation (note 4) | 69,610 | ||||
| Change in decommissioning liabilities (note 6) | 21,268 | ||||
| Acquisitions | 444,122 | ||||
| Divestitures | (18,520 | ) | |||
| As at September 30, 2015 | $ | 8,293,234 | |||
Accumulated Depletion, Depreciation and Amortization
| (000s) | |||||
| As at December 31, 2014 | $ | 1,267,344 | |||
| Depletion, depreciation and amortization | 470,711 | ||||
| Divestitures | (1,929 | ) | |||
| As at September 30, 2015 | $ | 1,736,126 | |||
Net Book Value
| (000s) | |||
| As at December 31, 2014 | $ | 5,466,273 | |
| As at September 30, 2015 | $ | 6,557,108 | |
Future development costs of $5,124.9 million were included in the depletion calculation at September 30, 2015 (December 31, 2014 - $4,610.0 million).
Capitalization of G&A and Share-Based Payments
A total of $17.1 million in G&A expenditures have been capitalized and included in E&E and PP&E assets at September 30, 2015 (December 31, 2014 - $19.3 million). Also included in E&E and PP&E are non-cash share-based payments of $24.0 million (December 31, 2014 - $28.8 million).
Impairment Assessment
In accordance with IFRS, an impairment test is performed on a CGU if the Company identifies an indicator of impairment. At September 30, 2015, the Company determined that indicators of impairment existed on two of its CGUs due to the decline in the current and forward commodity prices.
An impairment is recognized if the carrying value of a CGU exceeds the recoverable amount for that CGU. The Company determines the recoverable amount by using fair value less costs to sell, based on discounted future cash flows of proved plus probable reserves using forecast prices and costs.
An impairment test was performed at September 30, 2015 on two of the Company's CGU's using a pre-tax discount rate of 10% and the following forward commodity price estimates:
| Year | WTI Oil (US$/bbl)(1) | Foreign Exchange Rate(1) | Edmonton Light Crude Oil (Cdn$/bbl)(1) | AECO Gas (Cdn$/mmbtu)(1) | ||||
| 2015 | 47.00 | 0.7567 | 57.49 | 2.93 | ||||
| 2016 | 53.33 | 0.7633 | 64.53 | 3.29 | ||||
| 2017 | 62.07 | 0.8017 | 71.23 | 3.53 | ||||
| 2018 | 66.67 | 0.8100 | 76.89 | 3.83 | ||||
| 2019 | 71.33 | 0.8250 | 81.01 | 4.10 | ||||
| 2020 | 74.77 | 0.8333 | 84.73 | 4.31 | ||||
| 2021 | 78.24 | 0.8333 | 88.84 | 4.47 | ||||
| 2022 | 81.75 | 0.8333 | 93.04 | 4.65 | ||||
| 2023 | 85.37 | 0.8333 | 97.34 | 4.85 | ||||
| 2024 | 87.90 | 0.8333 | 99.92 | 5.00 | ||||
| Thereafter | +1.8%/yr | 0.8333 | +1.8%/yr | +1.8%/yr | ||||
| (1) Source: Average of, GLJ Petroleum Consultants, McDaniel & Associates Consultants, and Sproule Associates price forecasts, effective October 1, 2015 |
The external reserve evaluators also assess many financial assumptions regarding royalty rates, operating costs and future development capital, along with several other non-financial assumptions with a direct bearing on reserve volumes. Management has reviewed these variables in performing its impairment assessment, but given they are estimates there remains uncertainty.
The Company has determined that there was no impairment to PP&E at September 30, 2015.
For the year ended December 31, 2014, the Company identified indicators of impairment on two of its CGUs based on the decline in commodity prices and performed impairment tests accordingly. The Company determined that there was no impairment to PP&E at December 31, 2014.
Business Combination
On April 1, 2015, the Company acquired Perpetual Energy Inc.'s ("Perpetual") interests in the West Edson area of the Alberta Deep Basin with the issuance of 6,750,000 Tourmaline shares at a price of $38.32 per share for total consideration of $258.7 million. The interests included Perpetual's land interests, production, reserves and facilities that were jointly-owned with Tourmaline.
Results from operations are included in the Company's unaudited interim consolidated financial statements from the closing date of the transaction. The acquisition has been accounted for using the purchase method based on fair values as follows:
| (000s) | Perpetual Energy Inc. | ||||
| Fair value of net assets acquired: | |||||
| Property, plant and equipment | $ | 226,943 | |||
| Exploration and evaluation | 34,160 | ||||
| Decommissioning obligations | (2,443 | ) | |||
| Total | $ | 258,660 | |||
| Consideration: | |||||
| Common shares issued | $ | 258,660 | |||
Corporate Acquisitions
Bergen Resources Inc.
On July 20, 2015, the Company acquired all of the issued and outstanding shares of Bergen Resources Inc. ("Bergen"). As consideration, the Company issued of 725,000 Tourmaline shares at a price of $33.90 per share for total consideration of $24.6 million. Total transaction costs incurred by the Company of $0.2 million associated with this acquisition were expensed in the interim consolidated statement of income and comprehensive income. The acquisition resulted in an increase in Property, Plant and Equipment ("PP&E") of approximately $26.8 million and Exploration and Evaluation ("E&E") assets of $2.1 million along with net debt of $8.4 million. Results from operations for Bergen are included in the Company's unaudited interim consolidated financial statements from the closing date of the transaction.
Mapan Energy Ltd.
On August 14, 2015, the Company acquired all of the issued and outstanding shares of Mapan Energy Ltd. ("Mapan"). As consideration, the Company issued of 2,718,026 Tourmaline shares at a price of $32.98 per share for total consideration of $89.6 million. Total transaction costs incurred by the Company of $1.1 million associated with this acquisition were expensed in the interim consolidated statement of income and comprehensive income.
Results from operations for Mapan are included in the Company's unaudited interim consolidated financial statements from the closing date of the transaction. The acquisition has been accounted for using the purchase method based on fair values as follows:
| (000s) | Mapan Energy Ltd. | ||||
| Fair value of net assets acquired: | |||||
| Cash | $ | 11,011 | |||
| Working capital | 4,000 | ||||
| Property, plant and equipment | 58,471 | ||||
| Fair Value of Financial Instruments | (122 | ) | |||
| Decommissioning obligations | (3,157 | ) | |||
| Deferred income tax asset | 19,437 | ||||
| Total | $ | 89,640 | |||
| Consideration: | |||||
| Common shares issued | $ | 89,640 | |||
Santonia Energy Inc.
On April 24, 2014, the Company acquired all of the issued and outstanding shares of Santonia Energy Inc. ("Santonia"). As consideration, the Company issued 3,228,234 common shares at a price of $54.94 per share. Total transaction costs incurred by the Company of $1.5 million associated with this acquisition were expensed in the interim consolidated statement of income and comprehensive income.
Results from operations for Santonia are included in the Company's unaudited interim consolidated financial statements from the closing date of the transaction. The acquisition has been accounted for using the purchase method based on fair values as follows:
| (000s) | Santonia Energy Inc. | ||||
| Fair value of net assets acquired: | |||||
| Cash | $ | 2,445 | |||
| Working capital deficiency | (10,965 | ) | |||
| Property, plant and equipment | 167,473 | ||||
| Exploration and evaluation | 19,058 | ||||
| Bank debt | (32,079 | ) | |||
| Decommissioning obligations | (8,487 | ) | |||
| Deferred income tax asset | 39,914 | ||||
| Total | $ | 177,359 | |||
| Consideration: | |||||
| Common shares issued | $ | 177,359 | |||
Acquisition of Oil and Natural Gas Properties
For the nine months ended September 30, 2015, the Company completed property acquisitions including swaps for total cash consideration of $91.3 million (December 31, 2014 - $33.0 million) and in addition to the Perpetual acquisition, a further $69.6 million in non-cash consideration (December 31, 2014 - $2.2 million). The Company also assumed $6.2 million in decommissioning liabilities in addition to the Perpetual acquisition (December 31, 2014 - $4.9 million).
Disposition of Oil and Natural Gas Properties
On December 23, 2014, the Company completed the sale of a 25% working interest in its Peace River High complex for cash consideration of $500.0 million (before customary adjustments) to Canadian Non-Operated Resources Corp. ("CNOR"). The net book value of oil and natural gas properties disposed was $236.5 million and the gain on disposition was $266.2 million. The Company will continue to be the operator of all jointly-owned assets. Under the terms of the arrangement, the Company has committed to spend $400.0 million gross ($300.0 million net) per year over the next five years. The committed capital expenditures can be deferred to future periods in the event of an economic downturn, and as agreed upon by both parties. As part of the capital commitment, the Company also agreed to carry CNOR for the first $87.1 million spent (CNOR share) on specified capital projects. At September 30, 2015, the full-committed amount had been spent on these specified projects.
6. DECOMMISSIONING OBLIGATIONS
The Company's decommissioning obligations result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted amount of cash flow required to settle its decommissioning obligations is approximately $198.0 million (December 31, 2014 - $157.5 million), with some abandonments expected to commence in 2021. A risk-free rate of 2.31% (December 31, 2014 - 2.36%) and an inflation rate of 1.8% (December 31, 2014 - 2.0%) were used to calculate the decommissioning obligations.
| (000s) | As at September 30, 2015 | As at December 31, 2014 | |||||||
| Balance, beginning of period | $ | 114,038 | $ | 76,037 | |||||
| Obligation incurred | 12,255 | 14,257 | |||||||
| Obligation incurred on corporate acquisitions | 3,516 | 8,487 | |||||||
| Obligation incurred on property acquisitions | 5,132 | 4,881 | |||||||
| Obligation divested | (270 | ) | (5,676 | ) | |||||
| Obligation settled | (1,268 | ) | (413 | ) | |||||
| Accretion expense | 2,038 | 2,351 | |||||||
| Change in future estimated cash outlays | 9,013 | 14,114 | |||||||
| Balance, end of period | $ | 144,454 | $ | 114,038 | |||||
7. BANK DEBT
The Company has a covenant-based, unsecured, bank credit facility in place with a syndicate of bankers. In June 2015, the Company increased the facility amount from $1,550.0 to $1,800.0 million. The term was also increased from three to four years, resulting in an initial maturity of June 2019. The maturity date may, at the request of the Company and with consent of the lenders, be extended on an annual basis. The credit facility also includes an expansion feature ("accordion") which allows the Company, upon approval from the lenders, to increase the facility amount by up to $500.0 million by adding a new financial institution or by increasing the commitment of its existing lenders. With the exception of the increase in the facility amount, length of term and the addition of the accordion feature, the debt was renewed under the same terms and conditions as those outlined in note 9 of the Company's consolidated financial statements for the year ended December 31, 2014. The Company also has a $50.0 million operating revolver, resulting in total bank credit facility capacity of $1,850.0 million. The facility can be drawn in either Canadian or U.S. funds and bears interest at the bank's prime lending rate, banker's acceptance rates or LIBOR (for U.S. borrowings), plus applicable margins, which range from 0.50% to 3.15% depending on the type of borrowing and the Company's senior debt to adjusted EBITDA ratio.
The Company also has a $250.0 million five-year term loan with a Canadian Chartered Bank. In September 2015, the Company extended the maturity of the term loan from November 30, 2019 to November 30, 2020 and the annual interest rate was reduced to 220 basis points from 240 basis points over the applicable bankers' acceptance rate. The covenants for the term loan are similar to those under the Company's current credit facility and the term loan will rank equally with the obligation under the Company's credit facility.
As at September 30, 2015, the Company had $248.6 million in long-term debt outstanding and $896.3 million drawn against the bank credit facility for total bank debt of $1,144.9 million (net of prepaid interest and debt issue costs) (December 31, 2014 - $918.9 million). In addition, Tourmaline has outstanding letters of credit of $6.3 million (December 31, 2014 - $2.4 million), which reduce the credit available on the facility. The effective interest rate for the nine months ended September 30, 2015 was 2.69% (nine months ended September 30, 2014 - 2.99%). As at September 30, 2015, the Company is in compliance with all debt covenants.
8. NON-CONTROLLING INTEREST
The Company owns 90.6 percent of Exshaw Oil Corp., a private company engaged in oil and gas exploration in Canada. A reconciliation of the non-controlling interest is provided below:
| (000s) | As at September 30, 2015 | As at December 31, 2014 | ||||||
| Balance, beginning of period | $ | 30,006 | $ | 17,877 | ||||
| Share of subsidiary's net income (loss) for the period | (1,270 | ) | 12,129 | |||||
| Balance, end of period | $ | 28,736 | $ | 30,006 | ||||
9. SHARE CAPITAL
(a) Authorized
Unlimited number of Common Shares without par value.
Unlimited number of non-voting Preferred Shares, issuable in series.
(b) Common Shares Issued
| As at September 30, 2015 | As at December 31, 2014 | |||||||||||
| (000s) except share amounts | Number of Shares | Amount | Number of Shares | Amount | ||||||||
| Balance, beginning of period | 203,162,112 | $ | 3,615,378 | 189,804,864 | $ | 3,062,432 | ||||||
| For cash on public offering of common shares (1)(5) | 4,947,500 | 195,425 | 4,615,198 | 219,222 | ||||||||
| For cash on public offering of flow-through common shares (2)(3)(4) | 640,000 | 25,683 | 1,430,053 | 74,939 | ||||||||
| Issued on corporate and property acquisitions (note 5) | 10,193,026 | 372,878 | 3,228,234 | 177,359 | ||||||||
| For cash on exercise of stock options | 1,870,253 | 36,251 | 4,083,763 | 66,473 | ||||||||
| Contributed surplus on exercise of stock options | - | 13,717 | - | 24,925 | ||||||||
| Share issue costs | - | (9,386 | ) | - | (13,332 | ) | ||||||
| Tax effect of share issue costs | - | 2,824 | - | 3,360 | ||||||||
| Balance, end of period | 220,812,891 | $ | 4,252,770 | 203,162,112 | $ | 3,615,378 | ||||||
| (1) On February 12, 2014, the Company issued 4.615 million common shares at a price of $47.50 per share for total gross proceeds of $219.2 million. A total of 15,198 common shares were purchased by insiders. |
| (2) On June 2, 2014, the Company issued 1.15 million flow-through shares at a price of $68.15 per share for total gross proceeds of $78.4 million. The implied premium on flow-through common shares was determined to be $15.6 million or $13.55 per share. A total of 122,000 flow-through common shares were purchased by insiders. As at December 31, 2014, the Company had spent the full-committed amount. The expenditures were renounced to investors in February 2015 with an effective renunciation date of December 31, 2014. |
| (3) On November 28, 2014, the Company issued 0.28 million flow-through shares at a price of $57.00 per share for total gross proceeds of $16.0 million. The implied premium on flow-through common shares was determined to be $3.8 million or $13.62 per share. As at September 30, 2015, the Company had spent the full-committed amount. The expenditures were renounced to investors in February 2015 with an effective renunciation date of December 31, 2014. |
| (4) On March 12, 2015, the Company issued 0.64 million flow-through shares at a price of $50.00 per share for total gross proceeds of $32.0 million. The implied premium on flow-through common shares was determined to be $6.3 million or $9.87 per share. As at September 30, 2015, the Company is committed to spend the remaining $24.4 million on qualified exploration expenditures by December 31, 2016. The expenditures will be renounced to investors with an effective renunciation date of December 31, 2015. |
| (5) On June 23, 2015, the Company issued 4.948 million common shares at a price of $39.50 for total gross proceeds of $195.4 million. A total of 60,000 common shares were purchased by insiders. |
10. EARNINGS PER SHARE
Basic earnings-per-share attributed to common shareholders was calculated as follows:
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||
| Net earnings for the period (000s) | $ | 28,489 | $ | 67,357 | $ | 45,451 | $ | 223,662 | ||||
| Weighted average number of common shares - basic | 218,745,913 | 201,497,624 | 211,389,015 | 197,906,925 | ||||||||
| Earnings per share - basic | $ | 0.13 | $ | 0.33 | $ | 0.22 | $ | 1.13 | ||||
Diluted earnings-per-share attributed to common shareholders was calculated as follows:
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||
| Net earnings for the period (000s) | $ | 28,489 | $ | 67,357 | $ | 45,451 | $ | 223,662 | ||||
| Weighted average number of common shares - diluted | 219,376,160 | 206,469,220 | 212,561,337 | 202,811,901 | ||||||||
| Earnings per share - fully diluted | $ | 0.13 | $ | 0.33 | $ | 0.21 | $ | 1.10 | ||||
There were 11,098,666 and 11,083,666 options excluded from the weighted-average share calculations for the three and nine month periods ended September 30, 2015, respectively, because they were anti-dilutive (three and nine months ended September 30, 2014 - 2,035,000 options, respectively).
11. SHARE-BASED PAYMENTS
The Company has a rolling stock option plan. Under the employee stock option plan, the Company may grant options to its employees up to 22,081,289 shares of common stock, which represents 10% of the current outstanding common shares. The exercise price of each option equals the volume-weighted average market price for the five days preceding the issue date of the Company's stock on the date of grant and the option's maximum term is five years. Options are granted throughout the year and vest 1/3 on each of the first, second and third anniversaries from the date of grant.
| Nine Months Ended September 30, | |||||||||||||
| 2015 | 2014 | ||||||||||||
| Number of Options | Weighted Average Exercise Price | Number of Options | Weighted Average Exercise Price | ||||||||||
| Stock options outstanding, beginning of period | 17,046,500 | $ | 36.44 | 16,028,651 | $ | 27.95 | |||||||
| Granted | 1,359,500 | 37.40 | 2,151,000 | 52.80 | |||||||||
| Exercised | (1,870,253 | ) | 19.38 | (2,874,930 | ) | 16.71 | |||||||
| Forfeited | (33,333 | ) | 39.17 | (164,889 | ) | 50.81 | |||||||
| Stock options outstanding, end of period | 16,502,414 | $ | 38.45 | 15,139,832 | $ | 33.36 | |||||||
The weighted average trading price of the Company's common shares was $36.94 during the nine months ended September 30, 2015 (nine months ended September 30, 2014 - $52.13).
The following table summarizes stock options outstanding and exercisable at September 30, 2015:
| Range of Exercise Price | Number Outstanding at Period End | Weighted Average Remaining Contractual Life | Weighted Average Exercise Price | Number Exercisable at Period End | Weighted Average Exercise Price | |||||
| $20.68 - $29.93 | 3,187,750 | 1.18 | 26.97 | 3,187,750 | 26.97 | |||||
| $30.76 - $39.57 | 4,128,164 | 2.95 | 34.43 | 1,822,442 | 32.63 | |||||
| $40.18 - $48.99 | 7,526,500 | 3.45 | 42.12 | 2,049,000 | 41.28 | |||||
| $51.47 - $56.76 | 1,660,000 | 3.77 | 53.85 | 553,333 | 53.85 | |||||
| 16,502,414 | 2.92 | 38.45 | 7,612,525 | 34.13 | ||||||
The fair value of options granted during the nine-month period ended September 30, 2015 was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions and resulting values:
| September 30, | ||||||||
| 2015 | 2014 | |||||||
| Fair value of options granted (weighted average) | $ | 10.93 | $ | 18.50 | ||||
| Risk-free interest rate | 2.29 | % | 2.83 | % | ||||
| Estimated hold period prior to exercise | 4 years | 4 years | ||||||
| Expected volatility | 33 | % | 40 | % | ||||
| Forfeiture rate | 2 | % | 2 | % | ||||
| Dividend per share | $ | 0.00 | $ | 0.00 | ||||
12. COMMITMENTS
In the normal course of business, the Company is obligated to make future payments. These obligations represent contracts and other commitments that are known and non-cancellable.
PAYMENTS DUE BY YEAR
| (000s) | 1 Year | 2-3 Years | 4-5 Years | > 5 Years | Total | ||||||||||
| Operating leases | $ | 5,078 | $ | 11,053 | $ | 8,073 | $ | - | $ | 24,204 | |||||
| Firm transportation and processing agreements | 144,911 | 404,016 | 272,675 | 547,360 | 1,368,962 | ||||||||||
| Capital commitments (1) | 313,244 | 908,283 | 75,000 | - | 1,296,527 | ||||||||||
| Flow-through share commitments | 24,435 | - | - | - | 24,435 | ||||||||||
| Credit facility (2) | - | - | 988,552 | - | 988,552 | ||||||||||
| Term debt (3) | 11,131 | 22,263 | 22,263 | 251,157 | 306,814 | ||||||||||
| $ | 498,799 | $ | 1,345,615 | $ | 1,366,563 | $ | 798,517 | $ | 4,009,494 | ||||||
| (1) Includes drilling commitments, and capital spending commitments under the joint arrangement in the Spirit River complex of $300 million per year until 2019. The capital spending commitment under the joint arrangement can be deferred to future periods in the event of an economic downturn, and as agreed upon by both parties. |
| (2) Includes interest expense at an annual rate of 2.52% being the rate applicable to outstanding debt on the credit facility at September 30, 2015. |
| (3) Includes interest expense at an annual rate of 4.47% being the fixed rate on the term debt (including the interest rate swap) at September 30, 2015. |
ABOUT TOURMALINE OIL CORP.
Tourmaline is a Canadian intermediate crude oil and natural gas exploration and production company focused on long-term growth through an aggressive exploration, development, production and acquisition program in the Western Canadian Sedimentary Basin.
Contact
FOR FURTHER INFORMATION, PLEASE CONTACT:
Tourmaline Oil Corp.
Michael Rose
Chairman, President and Chief Executive Officer
(403) 266-5992
OR
Tourmaline Oil Corp.
Brian Robinson
Vice President, Finance and Chief Financial Officer
(403) 767-3587
robinson@tourmalineoil.com
OR
Tourmaline Oil Corp.
Scott Kirker
Secretary and General Counsel
(403) 767-3593
kirker@tourmalineoil.com
OR
Tourmaline Oil Corp.
Suite 3700, 250 - 6th Avenue S.W.
Calgary, Alberta T2P 3H7
Phone: (403) 266-5992
Facsimile: (403) 266-5952
Website: www.tourmalineoil.com
E-mail: info@tourmalineoil.com
