CALGARY, AB–(Marketwired – May 04, 2016) –
Tourmaline Oil Corp. (TSX: TOU) (“Tourmaline” or the “Company”) is pleased to release strong financial and operating results for the first quarter of 2016.
HIGHLIGHTS
- Record daily production of 195,828 boepd, a 36% increase over Q1 2015 and a 9% increase over the previous quarter.
- Q1 2016 operating costs of $3.70 boepd were down 21% year-over-year and 13% quarter-over-quarter.
- Record low all-in Q1 2016 cash costs of $6.68/boe (operating, transportation, general and administration and financing), down 18% year-over-year and 6% over the previous quarter.
- Forecast EP Capital spending in the first half of 2016 is now expected to be approximately $310 million, less than the previous forecast of $350 million.
- Pacesetter wells with record low costs in all three core-operated areas were drilled during the first quarter.
- The Company successfully completed a financing on April 5, 2016 for gross proceeds of $281.6 million.
- Q1 cash flow(1) of $159.4 million, or $0.72 per diluted share, remained strong in a period of weak product prices.
FINANCIAL RESULTS AND CAPITAL BUDGET
First quarter EP capital spending was $243.8 million, allowing the Company to reduce forecast first half 2016 EP spending to $310.0 million, down from $350.0 million disclosed in March 2016. Consequently, the full-year 2016 EP capital has also been reduced from $775.0 million to $725.0 million (including Q1 acquisitions) to remain consistent with forecast cash flow.
As previously announced, the Company closed the acquisition of key Wilrich and Notikewin sweet spot assets in the greater Edson-Ansell-Minehead area during the first quarter of 2016 for $183.0 million, adding approximately 48.0 mmboe of new reserves (Company estimate), 4,000 boepd of production and over 100 incremental sweet spot drilling locations. The Company also disposed of $18.0 million of minor, non-core assets in the quarter.
Given deteriorating 2016 natural gas prices, Tourmaline has reduced anticipated full-year 2016 cash flow to $725.1 million, including first quarter 2016 cash flow of $159.4 million. The Company will continue to execute a cash flow budget in 2016 and 2017. With the infrastructure build-out completed in all three operated complexes, approximately 80% of the 2016 EP capital budget can be directed towards drilling, completion and equipping.
Net debt(2) after the effect of the $269.9 million (net) April 2016 equity financing was $1.5 billion, down from year-end 2015 net debt of $1.6 billion. With Q2 spending considerably less than anticipated cash flow, the balance sheet will be further improved by mid-year. The Company expects 2016 exit net debt of $1.3 billion. Tourmaline currently has $716.5 million of unused credit capacity under existing bank facilities.
CASH COST STRUCTURE
First quarter operating costs were a record low of $3.70/boe, down 21% from first quarter of 2015 and 13% from the previous quarter, and well below forecast 2016 operating cost of $4.25/boe.
First quarter all-in cash costs were $6.68/boe, also a record, and down 18% from the first quarter of 2015.
The Company will continue to seek opportunities to reduce costs in all aspects of its operations.
Drilling and completion costs were reduced by approximately 25% in 2015 vs 2014. The Company is seeking an additional 10% reduction in 2016 vs 2015, and has largely achieved this target in the first quarter of 2016.
EP PROGRAM HIGHLIGHTS
Record first quarter production of 195,828 boepd represents a 36% increase over first quarter 2015 production of 143,725 boepd, and 9% growth over the prior quarter. The Company remains on track for anticipated 2016 average production of 200,000 boepd, even with a significantly-reduced 2016 EP capital budget.
Second quarter 2016 EP activity will be confined to drilling on two pads in the Minehead-Edson area of the Deep Basin and completion of two to three existing drilled pads in the Company’s NEBC Montney gas condensate complex. Tourmaline currently plans to operate seven or eight drilling rigs in the third quarter of 2016 with the $725.0 million 2016 capital program. Tie-ins of new wells are generally being deferred to the second half of the year when higher commodity prices are anticipated.
Tourmaline has established new record low costs on pacesetter wells drilled in all three core operated areas during the first quarter. The Company has now drilled and completed 30 stage NEBC Montney horizontals for $2.9 million, 26 stage Charlie Lake horizontals on the Peace River High for $2.5 million and 25 stage Deep Basin horizontals for $3.9 million. The reduced capital costs realized will allow for an additional eight to ten wells across all three complexes within the revised capital budget in 2016.
Tourmaline has drilled 740 wells since the Company commenced operation in early 2009 and has a well-documented future drilling inventory of 12,352 locations in the Company’s three, large operated complexes, all within reach of Company infrastructure. There are only 1,196 gross future locations of this inventory booked in the 2015 2P reserve report of 1.11 billion boe. In addition, the Company is developing EP plans for several new large projects and future opportunities that are not currently included in the existing future drilling inventory, but are close to existing Tourmaline infrastructure.
First quarter 2016 natural gas production was 1.034 bcf/day and first quarter total liquid production was 23,529 bpd. Tourmaline is the second-largest producer of Canadian natural gas and continues to drill a large proportion of the highest-deliverability gas wells by Industry in its Alberta Deep Basin and NEBC Montney core areas. Although production is weighted approximately 85% towards natural gas, Tourmaline has a number of light oil and condensate growth projects in the existing 2016/2017 capital programs. Condensate production in the NEBC Montney complex for example is forecast to grow by 4,000-5,000 bpd in the first quarter of 2017 with the start-up of the new Doe 2-11 gas plant.
Tourmaline’s expansive Triassic Charlie Lake light oil complex also represents a very large light oil growth opportunity. All the necessary infrastructure is in place to accommodate up to 12,500 bpd of incremental oil production growth within approximately 12 months. The Upper Charlie Lake play is profitable on a full-cycle basis at oil prices of approximately $30.00-35.00/bbl (WTI). Contingent upon oil prices, the Company is evaluating accelerating drilling on the Peace River complex during the second half of 2016. Tourmaline has 1,606 Upper and Lower Charlie Lake locations currently in inventory as well as a sizeable land position on the emerging Lower Montney light oil play in the Progress-Pouce Coupe area, and plans to drill wells in all three horizons in 2H 2016.
(1) “Cash flow” is defined as cash provided by operations before changes in non-cash operating working capital. See “Non-GAAP Financial Measures” below and in the attached Management’s Discussion and Analysis.
(2) “Net debt” is defined as long-term debt plus working capital (adjusted for the fair value of financial instruments). See “Non-GAAP Financial Measures” in the attached Management’s Discussion and Analysis.
| CORPORATE SUMMARY – FIRST QUARTER 2016 | ||||||||||||
| Three Months Ended March 31, | ||||||||||||
| 2016 | 2015 | Change | ||||||||||
| OPERATIONS | ||||||||||||
| Production | ||||||||||||
| Natural gas (mcf/d) | 1,033,792 | 750,542 | 38 | % | ||||||||
| Crude oil and NGL (bbl/d) | 23,529 | 18,635 | 26 | % | ||||||||
| Oil equivalent (boe/d) | 195,828 | 143,725 | 36 | % | ||||||||
| Product prices(1) | ||||||||||||
| Natural gas ($/mcf) | $ | 2.20 | $ | 3.69 | (40 | )% | ||||||
| Crude oil and NGL ($/bbl) | $ | 33.60 | $ | 43.13 | (22 | )% | ||||||
| Operating expenses ($/boe) | $ | 3.70 | $ | 4.69 | (21 | )% | ||||||
| Transportation costs ($/boe) | $ | 1.89 | $ | 2.24 | (16 | )% | ||||||
| Operating netback(3)($/boe) | $ | 9.71 | $ | 16.70 | (42 | )% | ||||||
| Cash general and administrative expenses ($/boe)(2) | $ | 0.42 | $ | 0.48 | (13 | )% | ||||||
|
FINANCIAL ($000, except share and per share) |
||||||||||||
| Revenue | 279,108 | 321,303 | (13 | )% | ||||||||
| Royalties | 6,569 | 15,587 | (58 | )% | ||||||||
| Cash flow(3) | 159,430 | 207,740 | (23 | )% | ||||||||
| Cash flow per share (diluted)(3) | $ | 0.72 | $ | 1.01 | (29 | )% | ||||||
| Net earnings (loss) | (38,390 | ) | 22,159 | (273 | )% | |||||||
| Net earnings (loss) per share (diluted) | $ | (0.17 | ) | $ | 0.11 | (255 | )% | |||||
| Capital expenditures (net of dispositions) | 414,857 | 497,382 | (17 | )% | ||||||||
| Weighted average shares outstanding (diluted) | 221,403,764 | 205,530,914 | 8 | % | ||||||||
| Net debt(3) | (1,802,230 | ) | (1,139,660 | ) | 58 | % | ||||||
| (1) | Product prices include realized gains and losses on financial instrument contracts. | |
| (2) | Excluding interest and financing charges. | |
| (3) | See “Non-GAAP Financial Measures” in the attached Management’s Discussion and Analysis. | |
Conference Call Tomorrow at 9:00
a.m. MDT (11:00 a.m. EDT)
Tourmaline will host a conference call tomorrow, May 5, 2016 starting at 9:00 a.m. MDT (11:00 a.m. EDT). To participate, please dial 1-866-225-0198 (toll-free in North America), or local dial-in 416-695-9701, a few minutes prior to the conference call.
Reader Advisories
CURRENCY
All amounts in this news release are stated in Canadian dollars unless otherwise specified.
FORWARD-LOOKING INFORMATION
This press release contains forward-looking information within the meaning of applicable securities laws. The use of any of the words “forecast”, “expect”, “anticipate”, “continue”, “estimate”, “objective”, “ongoing”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends” and similar expressions are intended to identify forward-looking information. More particularly and without limitation, this press release contains forward-looking information concerning Tourmaline’s plans and other aspects of its anticipated future operations, management focus, objectives, strategies, financial, operating and production results and business opportunities, including anticipated petroleum and natural gas production for various periods, drilling inventory or locations, cash flow and debt to cash flow levels, capital spending, cost reduction initiatives, projected operating and drilling costs, the timing for facility expansions and facility start-up dates, as well as Tourmaline’s future drilling prospects and plans, business strategy, future development and growth opportunities, prospects and asset base. The forward-looking information is based on certain key expectations and assumptions made by Tourmaline, including expectations and assumptions concerning: prevailing commodity prices and currency exchange rates; applicable royalty rates and tax laws; interest rates; future well production rates and reserve volumes; operating costs the timing of receipt of regulatory approvals; the performance of existing wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the successful completion of acquisitions and dispositions; the state of the economy and the exploration and production business; the availability and cost of financing, labour and services; and ability to market crude oil, natural gas and NGL successfully.
Statements relating to “reserves” are also deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.
Although Tourmaline believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Tourmaline can give no assurances that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature it involves inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to reserves, production, revenues, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; marketing and transportation; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; ability to access sufficient capital from internal and external sources; failure to obtain required regulatory and other approvals; and changes in legislation, including but not limited to tax laws, royalties and environmental regulations. Readers are cautioned that the foregoing list of factors is not exhaustive.
Additional information on these and other factors that could affect Tourmaline, or its operations or financial results, are included in the Company’s most recently filed Management’s Discussion and Analysis (See “Forward-Looking Statements” therein) , Annual Information Form (See “Risk Factors” and “Forward-Looking Statements” therein) and other reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or Tourmaline’s website (www.tourmalineoil.com).
The forward-looking information contained in this 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.
RESERVES DATA
The estimated values of future net revenue disclosed in this press release do not represent fair market value. There is no assurance that the forecast prices and cost assumptions used in the reserve evaluations will be attained and variances could be material.
This news release also contains references to estimates of proved plus probable reserves attributed to the Wilrich and Notikewan assets acquired by the Company in the greater Edson-Ansell-Minehead area. Such reserves reflect Company internally estimated “gross” reserves prepared by a qualified reserves evaluator effective December 31, 2015 in accordance with the definitions and provisions contained in the COGE Handbook.
The reserve data provided in this news release presents only a portion of the disclosure required under National Instrument 51-101. All of the required information is contained in the Company’s Annual Information Form for the year ended December 31, 2015, which is filed on SEDAR (accessible at www.sedar.com).
See also the Company’s news release dated February 22, 2016 for more information with respect to the Company’s reserves data.
FINANCIAL OUTLOOK
Also included in this news release are estimates of Tourmaline’s 2016 cash flow and net debt, which are based on, among other things, the various assumptions as to production levels, capital expenditures, and other assumptions disclosed in this news release and including Tourmaline’s estimated 2016 average production of 200,000 boepd and commodity price assumptions for natural gas (AECO – $2.23/mcf for 2016), and crude oil (WTI (US) – $43.54/bbl for 2016) and an exchange rate assumption of $0.73 (US/CAD) for 2016. To the extent such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Tourmaline on May 4, 2016 and is included to provide readers with an understanding of Tourmaline’s anticipated cash flow and net debt based on the capital expenditure, production and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.
INDUSTRY METRICS
The terms cash costs and operating netbacks, while commonly used in the oil and gas industry, do not have standardized meanings and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.
ESTIMATED DRILLING INVENTORY
This press release discloses drilling locations in four categories: (i) proved undeveloped locations; (ii) probable undeveloped locations; (iii) unbooked locations; and (iv) an aggregate total of (i), (ii) and (iii). Of the 12,352 undrilled locations disclosed in this presentation, 711 are proved undeveloped locations, 15 are proved non-producing locations, 468 are probable undeveloped locations, 2 are probable non-producing and 11,156 are unbooked. Proved undeveloped locations, proved non-producing locations, probable undeveloped locations and probable non-producing locations are booked and derived from the Company’s most recent independent reserves evaluation as prepared by GLJ Petroleum Consultants Ltd. and Deloitte LLP as of December 31, 2015 and account for drilling locations that have associated proved and/or probable reserves, as applicable.
Unbooked locations are internal estimates based on the Company’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company’s multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and 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.
GENERAL
See also “Forward-Looking Statements”, “Boe Conversions” and “Non-GAAP Financial Measures” in the attached Management’s Discussion and Analysis.
| CERTAIN DEFINITIONS: | ||
| bbl | barrel | |
| bbls/day | barrels per day | |
| bbl/mmcf | barrels per million cubic feet | |
| bcf | billion cubic feet | |
| bpd or bbl/d | barrels per day | |
| boe | barrel of oil equivalent | |
| boepd or boe/d | barrel of oil equivalent per day | |
| bopd or bbl/d | barrel of oil, condensate or liquids per day | |
| FCP | final circulating pressure | |
| gj | gigajoule | |
| gjs/d | gigajoules per day | |
| mbbls | thousand barrels | |
| mboe | thousand barrels of oil equivalent | |
| mcf | thousand cubic feet | |
| mcfpd or mcf/d | thousand cubic feet per day | |
| mcfe | thousand cubic feet equivalent | |
| mmboe | million barrels of oil equivalent | |
| mmbtu | million British thermal units | |
| mmbtu/d | million British thermal units per day | |
| mmcf | million cubic feet | |
| mmcfpd or mmcf/d | million cubic feet per day | |
| MPa | megapascal | |
| mstboe | thousand stock tank barrels of oil equivalent | |
| NGL | natural gas liquids | |
MANAGEMENT’S DISCUSSION AND ANALYSIS
This management’s discussion and analysis (“MD&A”) should be read in conjunction with Tourmaline’s unaudited interim condensed consolidated financial statements and related notes as at and for the three months ended March 31, 2016 and the consolidated financial statements for the year ended December 31, 2015. The consolidated financial statements and the MD&A can be found at www.sedar.com. This MD&A is dated May 4, 2016.
The financial information contained herein has been prepared in accordance with International Financial Reporting Standards (“IFRS”) and sometimes referred to in this MD&A as Generally Accepted Accounting Principles (“GAAP”) as issued by the International Accounting Standards Board. All dollar amounts are expressed in Canadian currency, unless otherwise noted.
Certain financial measures referred to in this MD&A are not prescribed by IFRS. See “Non-GAAP Financial Measures” for information regarding the following non-GAAP financial measures used in this MD&A: “cash flow”, “operating netback”, “working capital (adjusted for the fair value of financial instruments)”, “net debt”, “adjusted EBITDA”, “senior debt”, “total debt”, and “total capitalization”.
Additional information relating to Tourmaline can be found at www.sedar.com.
Forward-Looking Statements – Certain information regarding Tourmaline set forth in this document, including management’s assessment of the Company’s future plans and operations, contains forward-looking statements that involve substantial known and unknown risks and uncertainties. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements. Such statements represent Tourmaline’s internal projections, forecasts, estimates or beliefs concerning, among other things, an outlook on the estimated amounts and timing of capital investment or expenditures, anticipated future debt, expenses, production, cash flow and revenues or other expectations, beliefs, plans, objectives, assumptions, intentions or statements about future events or performance. These statements are only predictions and actual events or results may differ materially. Although Tourmaline believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies.
In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to: the size of, and future net revenues and cash flow from, crude oil, NGL (natural gas liquids) and natural gas reserves; future prospects; the focus of and timing of capital expenditures; expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; access to debt and equity markets; projections of market prices and costs; the performance characteristics of the Company’s crude oil, NGL and natural gas properties; crude oil, NGL and natural gas production levels and product mix; Tourmaline’s future operating and financial results; capital investment programs; supply and demand for crude oil, NGL and natural gas; future royalty rates; drilling, development and completion plans and the results therefrom; future land expiries; dispositions and joint venture arrangements; amount of operating, transportation and general and administrative expenses; treatment under governmental regulatory regimes and tax laws; and estimated tax pool balances. In addition, statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.
These forward-looking statements are subject to numerous risks and uncertainties, most of which are beyond the Company’s control, including the impact of general economic conditions; volatility and uncertainty in market prices for crude oil, NGL and natural gas; industry conditions; currency fluctuation; imprecision of reserve estimates; liabilities inherent in crude oil, NGL and natural gas operations; environmental risks; incorrect assessments of the value of acquisitions and exploration and development programs; competition; the lack of availability of qualified personnel or management and skilled labour; changes in income tax laws and incentive programs relating to the oil and gas industry; hazards such as fire, explosion, blowouts, cratering, and spills, any of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; stock market volatility; ability to access sufficient capital from internal and external sources; the receipt of applicable regulatory or third-party approvals; and the other risks considered under “Risk Factors” in Tourmaline’s most recent annual information form available at www.sedar.com.
With respect to forward-looking statements contained in this MD&A, Tourmaline has made assumptions regarding: future commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment and services; effects of regulation by governmental 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 March 31, |
|||||||||
| 2016 | 2015 | Change | |||||||
| Natural gas (mcf/d) | 1,033,792 | 750,542 | 38 | % | |||||
| Oil (bbl/d) | 13,545 | 10,805 | 25 | % | |||||
| NGL (bbl/d) | 9,984 | 7,830 | 28 | % | |||||
| Oil equivalent (boe/d) | 195,828 | 143,725 | 36 | % | |||||
| Natural gas % | 88 | % | 87 | % | |||||
Production for the three months ended March 31, 2016 averaged 195,828 boe/d, a 36% increase over the average production for the same quarter of 2015 of 143,725 boe/d. The increase in natural gas production is related to the Company’s successful exploration and production program as well as corporate and property acquisitions over the past year. The growth in oil and NGL production is the result of increased drilling in the Spirit River/Peace River High Charlie Lake oil plays, incremental liquids recovered in the Wild River area via deep-cut processing, and strong condensate recoveries from new wells commencing production as the liquids-rich Montney Turbidite is developed in northeast British Columbia. Approximately 92% of the growth in production volumes since the first quarter of 2015 can be attributed to wells brought on stream from the Company’s exploration and production program, with the remainder of the change being from corporate and property acquisitions (net of dispositions).
Full-year average production guidance for 2016 is approximately 200,000 boe/d which is consistent with previous Company guidance released March 7, 2016 in the Company’s December 31, 2015 MD&A.
| REVENUE | ||||||||||
|
Three Months Ended March 31, |
||||||||||
| (000s) | 2016 | 2015 | Change | |||||||
| Revenue from: | ||||||||||
| Natural gas | $ | 207,170 | $ | 248,963 | (17 | )% | ||||
| Oil and NGL | 71,938 | 72,340 | (1 | )% | ||||||
| Total revenue from natural gas, oil and NGL sales | $ | 279,108 | $ | 321,303 | (13 | )% | ||||
Revenue for the three months ended March 31, 2016 decreased 13% to $279.1 million from $321.3 million for the same quarter of 2015. Lower revenue for the period is consistent with the significant decrease in realized commodity prices and lower realized gains on energy marketing and hedging activities, partially offset by higher production volumes. Revenue includes all petroleum, natural gas and NGL sales and the realized gain (loss) on financial instruments.
| Tourmaline Realized Prices: | |||||||||
|
Three Months Ended March 31, |
|||||||||
| 2016 | 2015 | Change | |||||||
| Natural gas ($/mcf) | $ | 2.20 | $ | 3.69 | (40 | )% | |||
| Oil ($/bbl) | $ | 49.70 | $ | 61.50 | (19 | )% | |||
| NGL ($/bbl) | $ | 11.75 | $ | 17.79 | (34 | )% | |||
| Oil equivalent ($/boe) | $ | 15.66 | $ | 24.84 | (37 | )% | |||
| Benchmark Oil and Gas Prices: | ||||||||||
|
Three Months Ended March 31, |
||||||||||
| 2016 | 2015 | Change | ||||||||
| Natural gas | ||||||||||
| NYMEX Henry Hub (USD$/mcf) | $ | 1.98 | $ | 2.81 | (30 | )% | ||||
| AECO (CAD$/mcf) | $ | 1.83 | $ | 2.75 | (33 | )% | ||||
| Oil | ||||||||||
| NYMEX (USD$/bbl) | $ | 33.63 | $ | 48.57 | (31 | )% | ||||
| Edmonton Par (CAD$/bbl) | $ | 41.39 | $ | 52.75 | (22 | )% | ||||
| Reconciliation of AECO Index to Tourmaline’s Realized Gas Prices: | |||||||||||
|
Three Months Ended March 31, |
|||||||||||
| ($/mcf) | 2016 | 2015 | Change | ||||||||
| AECO index (1) | $ | 1.81 | $ | 2.75 | (34 | )% | |||||
| Heat/quality differential | 0.13 | 0.23 | (43 | )% | |||||||
| Realized gain | 0.35 | 0.86 | (59 | )% | |||||||
| Sales point differential (2) | (0.09 | ) | (0.15 | ) | (40 | )% | |||||
| Tourmaline realized natural gas price | $ | 2.20 | $ | 3.69 | (40 | )% | |||||
| Premium to AECO pricing due to higher heat content | 7 | % | 8 | % | |||||||
| (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 March 31, |
|||||||||
| 2016 | 2015 | Change | |||||||
| CAD$/USD$ (1) | $ | 0.7288 | $ | 0.8063 | (10 | )% | |||
| (1) | Average rates for the period. | |
The realized average natural gas price for the three months ended March 31, 2016 was $2.20/mcf, which is 40% lower than the same period of the prior year. The lower natural gas price reflects lower index prices experienced during the quarter and lower realized gains on commodity contracts. Included in the realized price is a gain on commodity contracts in the first quarter of 2016 of $32.9 million (three months ended March 31, 2015 – $57.9 million). Realized gains on commodity contracts for the quarter ended March 31, 2016 have decreased compared to the same period of the prior year reflecting a lower proportion of hedged volumes in 2016. Realized prices exclude the effect of unrealized gains or losses on commodity contracts. Once these gains and losses are realized they are included in the per-unit amounts.
Realized oil prices decreased by 19% for the three months ended March 31, 2016, which is consistent with the decrease in the benchmark price for crude oil during the quarter partially offset by a gain on commodity contracts of $12.7 million (three months ended March 31, 2015 – $12.6 million). NGL prices decreased 34% from $17.79/bbl to $11.75/bbl, when compared to the same quarter of 2015. The decrease in NGL prices is consistent with the decrease in crude oil and natural gas prices over the same period.
| ROYALTIES | ||||||||
|
Three Months Ended March 31, |
||||||||
| (000s) | 2016 | 2015 | ||||||
| Natural gas | $ | 1,413 | $ | 10,227 | ||||
| Oil and NGL | 5,156 | 5,360 | ||||||
| Total royalties | $ | 6,569 | $ | 15,587 | ||||
| Royalties as a percentage of revenue | 2.8 | % | 6.2 | % | ||||
For the quarter ended March 31, 2016, the average effective royalty rate was 2.8% compared to the rate of 6.2% for the same quarter of 2015. The decrease in the average effective royalty rate for 2016 can be attributed to significantly lower commodity prices received during the period. Royalty rates are impacted by changes in commodity prices whereby the actual royalty rate decreases when prices decrease. The Company also receives gas cost allowance from the Crown, which further reduces royalties to account for expenses incurred to process and transport the Crown’s portion of natural gas production.
The Company also continues to benefit from the New Well Royalty Reduction Program and the Natural Gas Deep Drilling Program in Alberta, as well as the Deep Royalty Credit Program in British Columbia.
On January 29, 2016, the Alberta Government released a new Royalty Regime effective January 1, 2017. The new regime will apply to wells drilled after the effective date, whereby all other wells will follow the old framework for a further 10 years. On April 21, 2016, the Alberta Government provided further details and calibration on the Modernized Royalty Framework (“MRF”). These details were seen as the second step of a five-step process with plans to provide further information in May/June 2016. Based on the details provided thus far, we believe that the MRF is generally consistent with the initial goal of incentivising the use of technology to improve productivity and rewards producers deploying the most competitive operating practices. As additional information continues to be provided, the Company will continue to monitor the overall impact on the Company starting in 2017.
The Company expects its royalty rate for 2016 to be approximately 5%, the slight decrease from the previous guidance of 6% reflects the lower than forecast royalty rate experienced during the first quarter of 2016. The royalty rate is sensitive to commodity prices, and as such, an increase in commodity prices later in 2016, will increase the actual rate.
| OTHER INCOME | |||||||||
|
Three Months Ended March 31, |
|||||||||
| (000s) | 2016 | 2015 | Change | ||||||
| Other income | $ | 6,481 | $ | 8,151 | (20 | )% | |||
Other income decreased from $8.2 million in the first quarter of 2015 to $6.5 million for the same quarter of 2016. In 2016, the Company is now processing less third party volumes at its owned and operated gas processing facilities. As the Company’s production increases, third party volumes processed at those facilities is reduced.
| OPERATING EXPENSES | |||||||||
|
Three Months Ended March 31, |
|||||||||
| (000s) except per unit amounts | 2016 | 2015 | Change | ||||||
| Operating expenses | $ | 65,890 | $ | 60,691 | 9 | % | |||
| Per boe | $ | 3.70 | $ | 4.69 | (21 | )% | |||
Operating expenses include all periodic lease and field-level expenses and exclude income recoveries from processing third-party volumes. For the first quarter of 2016, total operating expenses were $65.9 million compared to $60.7 million in 2015, an increase of 9% over a production base increase of 36% for the same period.
On a per-boe basis, the costs decreased from $4.69/boe for the first quarter of 2015 to $3.70/boe in the first quarter of 2016. The Company’s investments in processing facilities in 2014 and 2015 have reduced the volume of gas flowing to third-party facilities, contributing to the reduction in operating expenses on a per-boe basis. Additionally, the Company is realizing increased operational efficiencies in all three core areas along with fixed costs being distributed over a significantly higher production base. Operating expenses per-boe in the first quarter of 2015 also reflected additional start-up costs related to several facilities which were commissioned late in 2014.
The Company’s average operating cost target is approximately $4.25/boe in 2016 which is unchanged from the previous guidance released March 7, 2016. The Company does expect an increase in operating expenses per boe over the first quarter rate due to additional volumes flowing through deep cut processing, which bears higher operating expenses. Actual costs per boe can change, however, depending on a number of factors, including the Company’s actual production levels.
| TRANSPORTATION | |||||||||
|
Three Months Ended March 31, |
|||||||||
| (000s) except per unit amounts | 2016 | 2015 | Change | ||||||
| Natural gas transportation | $ | 25,583 | $ | 19,778 | 29 | % | |||
| Oil and NGL transportation | 8,042 | 9,248 | (13 | )% | |||||
| Total transportation | $ | 33,625 | $ | 29,026 | 16 | % | |||
| Per boe | $ | 1.89 | $ | 2.24 | (16 | )% | |||
For the first quarter of 2016, total transportation expenses were $33.6 million compared to $29.0 million in 2015, reflecting increased costs related to higher production volumes. On a per-boe basis, the costs decreased from $2.24/boe for the first quarter of 2015 to $1.89/boe in the first quarter of 2016. The per-unit decrease in costs in 2016 is primarily due to lower unutilized transportation fees on take-or-pay agreements for NGL production and a reduction in oil and NGL trucking costs as a result of better trucking rates, transporting shorter distances and fewer pipeline disruptions in the period.
| GENERAL & ADMINISTRATIVE EXPENSES (“G&A”) | |||||||||||
|
Three Months Ended March 31, |
|||||||||||
| (000s) except per unit amounts | 2016 | 2015 | Change | ||||||||
| G&A expenses | $ | 14,805 | $ | 14,063 | 5 | % | |||||
| Administrative and capital recovery | (1,143 | ) | (2,531 | ) | (55 | )% | |||||
| Capitalized G&A | (6,121 | ) | (5,314 | ) | 15 | % | |||||
| Total G&A expenses | $ | 7,541 | $ | 6,218 | 21 | % | |||||
| Per boe | $ | 0.42 | $ | 0.48 | (13 | )% | |||||
The slight increase in gross G&A expenses in the first quarter of 2016 compared to the same period 2015 is primarily due to staff additions needed to manage the larger production, reserve and land base. G&A expenses for the first quarter of 2016 were $7.5 million compared to $6.2 million for the same quarter of the prior year. The decrease in administrative and capital recoveries in the first quarter of 2016 compared to 2015 can be attributed to lower recoveries received from partners due to a reduction in the Company’s capital exploration and production activities.
On a per-boe basis, G&A expenses decreased from $0.48/boe for the first quarter of 2015 to $0.42/boe in the first quarter of 2016. The decrease per boe reflects Tourmaline’s growing production base which continues to increase at a faster rate than total G&A costs.
G&A costs for 2016 are expected to average approximately $0.50/boe which is unchanged from the previous guidance released March 7, 2016. Actual costs per boe can change, however, depending on a number of factors including the Company’s actual production levels.
| SHARE-BASED PAYMENTS | ||||||||
|
Three Months Ended March 31, |
||||||||
| (000s) except per unit amounts | 2016 | 2015 | ||||||
| Share-based payments | $ | 12,418 | $ | 16,608 | ||||
| Capitalized share-based payments | (6,209 | ) | (8,304 | ) | ||||
| Total share-based payments | $ | 6,209 | $ | 8,304 | ||||
| Per boe | $ | 0.35 | $ | 0.64 | ||||
The Company uses the fair value method for the determination of non-cash related share-based payments expense. During the first quarter of 2016, 125,000 stock options were granted to employees, officers, directors and key consultants at a weighted-average exercise price of $28.18 and 148,334 options were exercised, resulting in $3.7 million of cash proceeds. There were also 103,334 stock options forfeited.
The Company recognized $6.2 million of share-based payments expense in the first quarter of 2016 compared to $8.3 million in the first quarter of 2015. Capitalized share-based payments for the first quarter of 2016 were $6.2 million compared to $8.3 million for the same period of the prior year.
Share-based payments are lower in 2016 compared to the same period of 2015, which reflects a decreased value attributed to the options which corresponds with the decrease in the share price over the past two years.
| DEPLETION, DEPRECIATION AND AMORTIZATION (“DD&A”) | ||||||||
|
Three Months Ended March 31, |
||||||||
| (000s) except per unit amounts | 2016 | 2015 | ||||||
| Total depletion, depreciation and amortization | $ | 180,939 | $ | 167,688 | ||||
| Less mineral lease expiries | (5,921 | ) | (14,579 | ) | ||||
| Depletion, depreciation and amortization | $ | 175,018 | $ | 153,109 | ||||
| Per boe | $ | 9.82 | $ | 11.84 | ||||
DD&A expense, excluding mineral lease expiries, was $175.0 million for the first quarter of 2016 compared to $153.1 million for the same period of 2015. The increase in DD&A expense in 2016 over 2015 is due to higher production volumes, as well as a larger capital asset base being depleted.
The per-unit DD&A rate (excluding the impact of mineral lease expiries) was $9.82/boe for the first quarter of 2016 compared to the rate of $11.84/boe for the same quarter of 2015. The decrease in per-boe depletion in 2016 can be attributed to lower future development costs as drilling and completion costs have decreased over the past year thereby adding a higher proportion of reserves with lower associated future development costs, resulting in a lower depletion rate.
Mineral lease expiries for the three months ended March 31, 2016 were $5.9 million, compared to expiries in the same quarter of the prior year of $14.6 million. The Company prioritizes drilling on what it believes to be the most cost-efficient and productive acreage, and with such a large land base, the Company has chosen not to continue some of the expiring sections of land. The Company explores all alternatives (including swaps, farm-outs and dispositions) to realize the value from these sections before they expire.
| FINANCE EXPENSES | ||||||||||
|
Three Months Ended March 31, |
||||||||||
| (000s) | 2016 | 2015 | Change | |||||||
| Interest expense | $ | 10,859 | $ | 8,207 | 32 | % | ||||
| Accretion expense | 790 | 551 | 43 | % | ||||||
| Foreign exchange loss on U.S. denominated debt | 72,759 | − | 100 | % | ||||||
| Realized (gain) on cross-currency swaps | (72,759 | ) | − | 100 | % | |||||
| Realized loss on interest rate swaps | 900 | 606 | 49 | % | ||||||
| Transaction costs on corporate and property acquisitions | 178 | 525 | (66 | )% | ||||||
| Total finance expenses | $ | 12,727 | $ | 9,889 | 29 | % | ||||
Finance expenses for the three months ended March 31, 2016 totaled $12.7 million compared to $9.9 million for the same period of 2015. The increase in finance expenses in 2016 over 2015 is mainly due to the higher average bank debt outstanding, partially offset by a lower average effective interest rate. The average bank debt outstanding and the average effective interest rate on the debt for the three months ended March 31, 2016 was $1,571.8 million and 2.45%, respectively (three months ended March 31, 2015 – $1,038.3 million and 2.78% respectively).
In the first quarter of 2016, the Company drew from the credit facility in U.S. dollars, as permitted under the credit facility, which when repaid created a foreign exchange loss. Concurrent with the draw of U.S. dollar denominated borrowings, the Company entered into cross-currency swaps to manage the foreign currency risk resulting from holding U.S. dollar denominated borrowings. The Company fixed the Canadian dollar amount for purposes of principal and interest repayment resulting in a gain on cross-currency swaps equivalent to the realized foreign exchange loss. This transaction allows the Company to take advantage of the interest rate spread between CDOR and LIBOR without taking on foreign exchange risk.
DEFERRED INCOME TAXES (RECOVERY)
For the three months ended March 31, 2016, the provision for deferred income tax recovery was $12.9 million compared to deferred income tax expense of $10.3 million for the same period in 2015. The recovery is primarily due to the pre-tax loss recorded in the first quarter of 2016 compared to pre-tax income in the same period of 2015.
| CASH FLOW FROM OPERATING ACTIVITIES, CASH FLOW AND NET EARNINGS (LOSS) | |||||||||||
|
Three Months Ended March 31, |
|||||||||||
| (000s) except per unit amounts | 2016 | 2015 | Change | ||||||||
| Cash flow from operating activities | $ | 176,308 | $ | 194,370 | (9 | )% | |||||
| Per share (1) | $ | 0.80 | $ | 0.95 | (16 | )% | |||||
| Cash flow (2) | $ | 159,430 | $ | 207,740 | (23 | )% | |||||
| Per share (1)(2) | $ | 0.72 | $ | 1.01 | (29 | )% | |||||
| Net earnings (loss) | $ | (38,390 | ) | $ | 22,159 | (273 | )% | ||||
| Per share (1) | $ | (0.17 | ) | $ | 0.11 | (255 | )% | ||||
| Operating netback per boe (2) | $ | 9.71 | $ | 16.70 | (42 | )% | |||||
| (1) | Fully diluted. | |
| (2) | See “Non-GAAP Financial Measures”. | |
Cash flow for the three months ended March 31, 2016 was $159.4 million or $0.72 per diluted share compared to $207.7 million or $1.01 per diluted share for the same period of 2015.
The Company had an after-tax net loss for the three months ended March 31, 2016 of $38.4 million or $0.17 per diluted share compared to earnings of $22.2 million or $0.11 per diluted share for the same period of 2015. The decrease in both cash flow and after-tax net earnings (loss) in 2016 reflects significantly lower realized oil, natural gas and NGL prices, partially offset by an increase in production over 2015.
| CAPITAL EXPENDITURES | ||||||||
|
Three Months Ended March 31, |
||||||||
| (000s) | 2016 | 2015 | ||||||
| Land and seismic | $ | 2,352 | $ | 25,054 | ||||
| Drilling and completions | 150,643 | 277,282 | ||||||
| Facilities | 90,839 | 184,628 | ||||||
| Property acquisitions | 182,708 | 4,515 | ||||||
| Property dispositions | (18,000 | ) | (519 | ) | ||||
| Other | 6,315 | 6,422 | ||||||
| Total cash capital expenditures | $ | 414,857 | $ | 497,382 | ||||
During the first quarter of 2016, the Company invested $414.9 million of cash consideration, net of dispositions, compared to $497.4 million for the same period of 2015. Expenditures on exploration and production were $243.8 million compared to $487.0 million for the same quarter of 2015. The drilling and completion costs of $150.6 million in 2016 include 70.11 net wells drilled and completed compared to $277.3 million spent on 92.71 net wells drilling and completed in 2015. The lower costs per well reflect the Company’s continuously improving operating practices, combined with reduced drilling and completion service costs. Facilities expenditures include work on the new Brazeau Gas Plant commissioned in the first quarter of 2016, and progress payments on the new Doe Gas Plant and the Mulligan marketing terminal, both of which are to be commissioned in late 2016 or early 2017.
The following table summarizes the drill, complete and tie-in activities for the periods:
|
Three Months Ended March 31, 2016 |
Three Months Ended March 31, 2015 |
|||||||
| Gross | Net | Gross | Net | |||||
| Drilled | 27 | 25.28 | 42 | 35.74 | ||||
| Completed (1) | 49 | 44.83 | 65 | 56.97 | ||||
| Tied-in (1) | 5 | 4.10 | 27 | 23.14 | ||||
| (1) | A multi-well pad is included as a single completion and tie-in. | |
Acquisitions and Dispositions
2016
On January 29, 2016, the Company acquired assets in the Minehead-Edson-Ansell area of the Alberta Deep Basin for cash consideration of $183.0 million, before customary adjustments. The acquisition resulted in an increase in Property, Plant and Equipment (“PP&E”) of approximately $179.2 million, an increase in Exploration and Evaluation (“E&E”) assets of $4.8 million, and the assumption of $1.0 million in decommissioning liabilities. The assets acquired included land interests, production, reserves and facilities in the area.
On March 1, 2016, the Company sold non-core assets for cash consideration of $18.0 million, before customary adjustments.
2015
On April 1, 2015, the Company acquired Perpetual Energy Inc.’s (“Perpetual”) interests in the West Edson area of the Alberta Deep Basin with the issuance of 6,750,000 Tourmaline shares at a price of $38.32 per share for total consideration of $258.7 million. The acquisition resulted in an increase in Property, Plant and Equipment (“PP&E”) of approximately $226.9 million and an increase in Exploration and Evaluation (“E&E”) assets of $34.2 million. The interests included Perpetual’s land interests, production, reserves and facilities that were jointly-owned with Tourmaline.
On July 20, 2015, the Company acquired all of the issued and outstanding shares of Bergen Resources Inc. (“Bergen”). As consideration, the Company issued 725,000 common shares at a price of $33.90 per share for total consideration of $24.6 million. Total transaction costs incurred by the Company of $0.2 million associated with this acquisition were expensed in the consolidated statement of income and comprehensive income. The acquisition resulted in an increase in PP&E of approximately $26.8 million and E&E assets of $2.1 million. The acquisition of Bergen consolidated the Company’s working interest in a core area of the Peace River High.
On August 14, 2015, the Company acquired all of the issued and outstanding shares of Mapan Energy Ltd. (“Mapan”). As consideration, the Company issued 2,718,026 common shares at a price of $32.98 per share for total consideration of $89.6 million. The acquisition resulted in an increase in PP&E of approximately $58.5 million. Total transaction costs incurred by the Company of $1.1 million associated with this acquisition were expensed in the consolidated statement of income and comprehensive income. The acquisition of Mapan provides for an increase in lands and production in the Alberta Deep Basin, one of the Company’s core areas.
Exploration and production capital expenditures in 2016 are now forecast to be $725.0 million (including acquisition and divestiture activity in the first quarter of 2016) which is reduced from the previous guidance of $775.0 million released on March 7, 2016. The Company expects drilling and completions costs of approximately $375.0 million, facilities expenditures (including equipment, pipelines and tie-ins) of $179.0 million as well as land and seismic expenditures of $6.0 million. The capital budget is closely monitored and will be adjusted as required depending on cash flow available.
LIQUIDITY AND CAPITAL RESOURCES
The Company has a covenant-based, unsecured, bank credit facility in place with a syndicate of bankers, the details of which are described in note 9 of the Company’s consolidated financial statements for the year ended December 31, 2015 and in note 7 of the Company’s unaudited interim condensed consolidated financial statements for the three months ended March 31, 2016. The facility is a four-year extendible revolving facility in the amount of $1,800.0 million with an initial maturity date 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 includes an expansion feature (“accordion”) which allows the Company, upon approval from the lenders, to increase the facility amount by up to $500.0 million by adding a new financial institution or by increasing the commitment of its existing lenders. The Company also has a $50.0 million operating revolver, resulting in total bank credit facility capacity of $1,850.0 million. The facility can be drawn in either Canadian or U.S. funds and bears interest at the bank’s prime lending rate, banker’s acceptance rates or LIBOR (for U.S. borrowings), plus applicable margins, which range from 0.50% to 3.15% 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 bearing an annual interest rate of 220 basis points over the applicable bankers’ acceptance rates with an initial maturity of November 2020. The maturity date may, at the request of the Company and with consent of the lender, be extended on an annual basis. The covenants for the term loan are the same as those under the Company’s current credit facility and the term loan will rank equally with the obligation under the Company’s credit facility.
The Company’s aggregate borrowing capacity is now $2.1 billion.
As at March 31, 2016, the Company had negative working capital of $227.1 million, after adjusting for the fair value of financial instruments (the unadjusted working capital deficiency was $201.6 million) (December 31, 2015 – $283.8 million and $247.4 million, respectively). As at March 31, 2016, the Company had $248.7 million in long-term debt outstanding and $1,326.4 million drawn against the revolving credit facility for total bank debt of $1,575.1 million (net of prepaid interest and debt issue costs) (December 31, 2015 – $1,266.6 million). Net debt at March 31, 2016 was $1,802.2 million (December 31, 2015 – $1,550.4 million). On April 5, 2016, the Company closed a financing for net proceeds of approximately $269.9 million, which subsequently reduced net debt to approximately $1,532.3 million. As at March 31, 2016, the Company is in compliance with all debt covenant calculations.
For 2016, Management intends on matching the capital budget to expected cash flow and as such Management believes the Company has sufficient resources to fund its 2016 exploration and development programs. As at March 31, 2016, the Company had $509.5 million in unutilized borrowing capacity. The unutilized borrowing capacity was further increased on April 5, 2016 with the financing disclosed above resulting in unutilized capacity of $779.4 million, excluding the working capital deficiency. The 2016 exploration and development program will be continuously and diligently monitored throughout the year and will be adjusted as necessary depending on commodity price outlooks in order to remain consistent with cash flow. Management is dedicated to keeping a strong balance sheet which is especially important in times of significantly depressed commodity prices.
SHARES AND STOCK OPTIONS OUTSTANDING
As at May 4, 2016, the Company has 231,956,759 common shares outstanding and 19,550,046 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 | $ | 5,309 | $ | 11,028 | $ | 5,389 | $ | – | $ | 21,726 | |||||
| Firm transportation and processing agreements | 179,582 | 411,386 | 368,146 | 917,708 | 1,876,822 | ||||||||||
| Capital commitments (1) | 311,111 | 603,261 | 295,500 | – | 1,209,872 | ||||||||||
| Flow-through share commitments | 22,906 | – | – | – | 22,906 | ||||||||||
| Credit facility (2) | – | – | 1,446,963 | – | 1,446,963 | ||||||||||
| Term debt (3) | 7,776 | 15,552 | 262,792 | – | 286,120 | ||||||||||
| Interest rate swaps | 3,145 | 6,315 | 1,981 | – | 11,441 | ||||||||||
| $ | 529,829 | $ | 1,047,542 | $ | 2,380,771 | $ | 917,708 | $ | 4,875,850 | ||||||
| (1) | Includes drilling commitments, and capital spending commitments under the joint arrangement in the Spirit River complex of $300.0 million per year until 2019. The capital spending commitment under the joint arrangement can be deferred to future periods in the event of an economic downturn, and as agreed upon by both parties. Since December 31, 2015, an economic downturn event, as defined in the joint arrangement in the Spirit River complex has existed and as such capital spending for 2016 may be reduced and extended to future years. | |
| (2) | Includes interest expense at an annual rate of 2.63% being the rate applicable to outstanding debt on the credit facility at March 31, 2016. | |
| (3) | Includes interest expense at an annual rate of 3.11% being the fixed rate on the term debt at March 31, 2016. | |
OFF BALANCE SHEET ARRANGEMENTS
The Company has certain lease arrangements, all of which are reflected in the commitments and contractual obligations table, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or general and administrative expenses depending on the nature of the lease.
FINANCIAL RISK MANAGEMENT
The Board of Directors has overall responsibility for the establishment and oversight of the Company’s risk management framework. The Board has implemented and monitors compliance with risk management policies.
The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities. The Company’s financial risks are discussed in note 5 of the Company’s audited consolidated financial statements for the year ended December 31, 2015.
As at March 31, 2016, the Company has entered into certain financial derivative contracts in order to manage commodity price and interest rate risk. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, even though the Company considers all commodity contracts to be effective economic hedges. Such financial derivative contracts are recorded on the consolidated statement of financial position at fair value, with changes in the fair value being recognized as an unrealized gain or loss on the consolidated statement of income and comprehensive income. The contracts that the Company has in place at March 31, 2016 are summarized and disclosed in note 3 of the Company’s unaudited interim condensed consolidated financial statements for the three months ended March 31, 2016 and 2015.
The Company has entered into physical delivery sales contracts to manage commodity risk. These contracts are considered normal sales contracts and are not recorded at fair value in the consolidated financial statements. Physical contracts in place at March 31, 2016 have been summarized and disclosed in note 3 of the Company’s unaudited interim condensed consolidated financial statements for the three months ended March 31, 2016 and 2015.
Financial derivative and physical delivery contracts entered into subsequent to March 31, 2016 are detailed in note 3 of the Company’s unaudited interim condensed consolidated financial statements for the three months ended March 31, 2016 and 2015.
APPLICATION OF CRITICAL ACCOUNTING ESTIMATES
Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Management reviews its estimates on a regular basis. The emergence of new information and changed circumstances may result in actual results or changes to estimates that differ materially from current estimates. The Company’s use of estimates and judgments in preparing the interim condensed consolidated financial statements is discussed in note 1 of the consolidated financial statements for the year ended December 31, 2015.
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING
The Company’s Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures (“DC&P”), as defined by National Instrument 52-109. The Company’s Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal controls over financial reporting (“ICFR”), as defined by National Instrument 52-109, to provide reasonable assurance regarding the reliability of the Company’s financial reporting and the preparation of financial statements for external purposes in accordance with IFRS.
There were no changes in the Company’s DC&P or ICFR during the period beginning on January 1, 2016 and ending on March 31, 2016 that have materially affected, or are reasonably likely to materially affect, the Company’s ICFR. It should be noted that a control system, including the Company’s disclosure and internal controls and procedures, no matter how well conceived can provide only reasonable, but not absolute assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.
The Company uses the guidelines as set in the Committee of Sponsoring Organizations of the Treadway Commission 2013 Internal Control-Integrated Framework.
BUSINESS RISKS AND UNCERTAINTIES
Tourmaline monitors and complies with current government regulations that affect its activities, although operations may be adversely affected by changes in government policy, regulations or taxation. In addition, Tourmaline maintains a level of liability, property and business interruption insurance which is believed to be adequate for Tourmaline’s size and activities, but is unable to obtain insurance to cover all risks within the business or in amounts to cover all possible claims.
See “Forward-Looking Statements” in this MD&A and “Risk Factors” in Tourmaline’s most recent annual information form for additional information regarding the risks to which Tourmaline and its business and operations are subject.
IMPACT OF ENVIRONMENTAL REGULATIONS
The oil and gas industry is currently subject to regulation pursuant to a variety of provincial and federal environmental legislation, all of which is subject to governmental review and revision from time to time. Such legislation provides for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. In addition, such legislation sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability and the imposition of material fines and penalties.
The use of fracture stimulations has been ongoing safely in an environmentally responsible manner in western Canada for decades. With the increase in the use of fracture stimulations in horizontal wells there is increased communication between the oil and natural gas industry and a wider variety of stakeholders regarding the responsible use of this technology. This increased attention to fracture stimulations may result in increased regulation or changes of law which may make the conduct of the Company’s business more expensive or prevent the Company from conducting its business as currently conducted. Tourmaline focuses on conducting transparent, safe and responsible operations in the communities in which its people live and work.
NON-GAAP FINANCIAL MEASURES
This MD&A or documents referred to in this MD&A make reference to the terms “cash flow”, “operating netback”, “working capital (adjusted for the fair value of financial instruments)”, “net debt”, “adjusted EBITDA”, “senior debt”, “total debt”, and “total capitalization” which are not recognized measures under GAAP, and do not have a standardized meaning prescribed by GAAP. Accordingly, the Company’s use of these terms may not be comparable to similarly defined measures presented by other companies. Management uses the terms “cash flow”, “operating netback”, “working capital (adjusted for the fair value of financial instruments)” and “net debt”, for its own performance measures and to provide shareholders and potential investors with a measurement of the Company’s efficiency and its ability to generate the cash necessary to fund a portion of its future growth expenditures or to repay debt. Investors are cautioned that the non-GAAP measures should not be construed as an alternative to net income determined in accordance with GAAP as an indication of the Company’s performance. The terms “adjusted EBITDA”, “senior debt”, “total debt”, and “total capitalization” are not used by management in measuring performance but are used in the financial covenants under the Company’s credit facility. Under the Company’s credit facility “adjusted EBITDA” means generally net income or loss, excluding extraordinary items, plus interest expense and income taxes and adjusted for non-cash items and gains or losses on dispositions, “senior debt” means the sum of drawn amounts on the credit facility, the term loan and outstanding letters of credit less cash and cash equivalents and excluding debt issue costs (“bank debt”), “total debt” means generally the sum of “senior debt” plus subordinated debt, Tourmaline currently does not have any subordinated debt, and “total capitalization” means generally the sum of the Company’s shareholders’ equity and all other indebtedness of the Company including bank debt, all determined on a consolidated basis in accordance with GAAP.
Cash Flow
A summary of the reconciliation of cash flow from operating activities (per the statements of cash flow), to cash flow, is set forth below:
|
Three Months Ended March 31, |
|||||||
| (000s) | 2016 | 2015 | |||||
| Cash flow from operating activities (per GAAP) | $ | 176,308 | $ | 194,370 | |||
| Change in non-cash working capital | (16,878 | ) | 13,370 | ||||
| Cash flow | $ | 159,430 | $ | 207,740 | |||
Operating Netback
Operating netback is calculated on a per-boe basis and is defined as revenue (excluding processing income) less royalties, transportation costs and operating expenses, as shown below:
|
Three Months Ended March 31, |
||||||
| ($/boe) | 2016 | 2015 | ||||
| Revenue, excluding processing income | $ | 15.66 | $ | 24.84 | ||
| Royalties | (0.37) | (1.21) | ||||
| Transportation costs | (1.89) | (2.24) | ||||
| Operating expenses | (3.70) | (4.69) | ||||
| Operating netback (1) | $ | 9.71 | $ | 16.70 | ||
| (1) | May not add due to rounding. | |
Working Capital (Adjusted for the Fair Value of Financial Instruments)
A summary of the reconciliation of working capital to working capital (adjusted for the fair value of financial instruments) is set forth below:
| (000s) |
As at March 31, 2016 |
As at December 31, 2015 |
|||
| Working capital (deficit) | $ | (201,588) | $ | (247,391) | |
| Fair value of financial instruments – short-term (net) | (25,545) | (36,392) | |||
| Working capital (deficit) (adjusted for the fair value of financial instruments) | $ | (227,133) | $ | (283,783) | |
Net Debt
A summary of the reconciliation of net debt is set forth below:
| (000s) |
As at March 31, 2016 |
As at December 31, 2015 |
||||
| Bank debt | $ | (1,575,097) | $ | (1,266,604) | ||
| Working capital (deficit) | (201,588) | (247,391) | ||||
| Fair value of financial instruments – short-term (net) | (25,545) | (36,392) | ||||
| Net debt | $ | (1,802,230) | $ | (1,550,387) | ||
| SELECTED QUARTERLY INFORMATION | ||||||||||||||
| 2016 | 2015 | 2014 | ||||||||||||
| ($000s, unless otherwise noted) | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | ||||||
| PRODUCTION | ||||||||||||||
| Natural gas (mcf) | 94,075,078 | 85,328,135 | 72,395,759 | 69,606,629 | 67,548,751 | 63,719,524 | 51,771,964 | 51,225,036 | ||||||
| Oil and NGL(bbls) | 2,141,099 | 2,302,708 | 1,761,403 | 1,469,591 | 1,677,123 | 1,426,951 | 1,307,089 | 1,468,198 | ||||||
| Oil equivalent (boe) | 17,820,279 | 16,524,064 | 13,827,363 | 13,070,696 | 12,935,248 | 12,046,872 | 9,935,749 | 10,005,704 | ||||||
| Natural gas (mcf/d) | 1,033,792 | 927,480 | 786,910 | 764,908 | 750,542 | 692,604 | 562,739 | 562,912 | ||||||
| Oil and NGL (bbls/d) | 23,529 | 25,030 | 19,146 | 16,149 | 18,635 | 15,510 | 14,207 | 16,134 | ||||||
| Oil equivalent (boe/d) | 195,828 | 179,610 | 150,297 | 143,634 | 143,725 | 130,944 | 107,997 | 109,953 | ||||||
| FINANCIAL | ||||||||||||||
| Revenue, net of royalties | 250,377 | 350,629 | 332,927 | 283,062 | 313,440 | 351,939 | 311,586 | 313,655 | ||||||
| Cash flow from operating activities | 176,308 | 228,959 | 261,398 | 151,028 | 194,370 | 201,188 | 233,047 | 231,756 | ||||||
| Cash flow (1) | 159,430 | 242,351 | 197,100 | 203,029 | 207,740 | 233,238 | 211,635 | 231,542 | ||||||
| Per diluted share | 0.72 | 1.10 | 0.90 | 0.95 | 1.01 | 1.14 | 1.03 | 1.13 | ||||||
| Net earnings (loss) | (38,390) | 34,636 | 28,489 | (5,197) | 22,159 | 265,210 | 67,357 | 66,437 | ||||||
| Per basic share | (0.17) | 0.16 | 0.13 | (0.02) | 0.11 | 1.31 | 0.33 | 0.33 | ||||||
| Per diluted share | (0.17) | 0.16 | 0.13 | (0.02) | 0.11 | 1.29 | 0.33 | 0.32 | ||||||
| Total assets | 7,844,728 | 7,640,671 | 7,471,042 | 7,071,801 | 6,801,583 | 6,622,303 | 5,978,645 | 5,446,094 | ||||||
| Working capital (deficit) | (201,588) | (247,391) | (297,698) | (70,156) | (195,907) | (189,928) | (493,160) | (131,672) | ||||||
| Working capital (deficit)(adjusted for the fair value of financial instruments) (1) | (227,133) | (283,783) | (339,177) | (86,090) | (232,572) | (223,655) | (495,222) | (123,166) | ||||||
| Cash capital expenditures | 414,857 | 325,499 | 422,629 | 290,629 | 497,382 | 152,135 | 647,302 | 297,733 | ||||||
| Total outstanding shares (000s) | 221,484 | 221,336 | 220,813 | 216,378 | 204,284 | 203,162 | 201,673 | 201,431 | ||||||
| PER UNIT | ||||||||||||||
| Natural gas ($/mcf) | 2.20 | 2.99 | 3.20 | 3.17 | 3.69 | 4.09 | 4.34 | 4.71 | ||||||
| Oil and NGL ($/bbl) | 33.60 | 47.65 | 45.91 | 53.34 | 43.13 | 55.91 | 74.61 | 74.53 | ||||||
| Revenue ($/boe) | 15.66 | 22.08 | 22.61 | 22.85 | 24.84 | 28.25 | 32.41 | 35.03 | ||||||
| Operating netback ($/boe)(1) | 9.71 | 15.22 | 15.06 | 16.37 | 16.70 | 20.23 | 22.19 | 24.02 | ||||||
| (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 112,929 boe per day in 2014 to 154,403 boe per day in 2015 and 195,828 boe per day in the first three months of 2016. The production growth can be attributed primarily to the Company’s exploration and development activities, and from acquisitions of producing properties.
The Company’s cash flow was $929.0 million in 2014, $850.2 million in 2015, and 2016 forecast cash flow is $725.1 million. The decrease in cash flow year-over-year continues to reflect the significant declines in commodity prices over the same periods. Commodity price fluctuations can indirectly impact expected production by changing the amount of funds available to reinvest in exploration, development and acquisition activities in the future. Changes in commodity prices impact revenue and cash flow available for exploration, and also the economics of potential capital projects as low commodity prices can potentially reduce the quantities of reserves that are commercially recoverable. The Company’s capital program is dependent on cash flow generated from operations and access to capital markets.
| CONSOLIDATED FINANCIAL STATEMENTS | |||||||
| CONSOLIDATED STATEMENTS OF FINANCIAL POSITION | |||||||
|
March 31, |
December 31, | ||||||
| (000s) (unaudited) | 2016 | 2015 | |||||
| Assets | |||||||
| Current assets: | |||||||
| Accounts receivable | $ | 132,662 | $ | 175,624 | |||
| Prepaid expenses and deposits | 14,333 | 14,769 | |||||
| Fair value of financial instruments (note 3) | 31,197 | 39,677 | |||||
| Total current assets | 178,192 | 230,070 | |||||
| Fair value of financial instruments (note 3) | 2,769 | – | |||||
| Long-term asset | 6,525 | 6,688 | |||||
| Exploration and evaluation assets (note 4) | 616,528 | 620,142 | |||||
| Property, plant and equipment (note 5) | 7,040,714 | 6,783,771 | |||||
| Total Assets | $ | 7,844,728 | $ | 7,640,671 | |||
| Liabilities and Shareholders’ Equity | |||||||
| Current liabilities: | |||||||
| Accounts payable and accrued liabilities | $ | 374,128 | $ | 474,176 | |||
| Fair value of financial instruments (note 3) | 5,652 | 3,285 | |||||
| Total current liabilities | 379,780 | 477,461 | |||||
| Bank debt (note 7) | 1,575,097 | 1,266,604 | |||||
| Fair value of financial instruments (note 3) | 30,266 | 9,701 | |||||
| Deferred premium on flow-through shares (note 9) | 5,012 | 5,982 | |||||
| Decommissioning obligations (note 6) | 172,238 | 163,459 | |||||
| Deferred taxes | 473,886 | 485,888 | |||||
| Shareholders’ equity: | |||||||
| Share capital (note 9) | 4,271,284 | 4,266,234 | |||||
| Non-controlling interest (note 8) | 27,663 | 28,431 | |||||
| Contributed surplus | 182,939 | 171,958 | |||||
| Retained earnings | 726,563 | 764,953 | |||||
| Total shareholders’ equity | 5,208,449 | 5,231,576 | |||||
| Total Liabilities and Shareholders’ Equity | $ | 7,844,728 | $ | 7,640,671 | |||
| Commitments (note 12). |
| Subsequent events (notes 3 and 13). |
| See accompanying notes to the interim condensed consolidated financial statements. |
CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
|
Three Months Ended March 31, |
|||||||
| (000s) except per-share amounts (unaudited) | 2016 | 2015 | |||||
| Revenue: | |||||||
| Oil and natural gas sales | $ | 233,544 | $ | 250,806 | |||
| Royalties | (6,569) | (15,587) | |||||
| Net revenue from oil and natural gas sales | 226,975 | 235,219 | |||||
| Realized gain on financial instruments | 45,564 | 70,497 | |||||
| Unrealized (loss) on financial instruments (note 3) | (28,643) | (427) | |||||
| Other income | 6,481 | 8,151 | |||||
| Total net revenue | 250,377 | 313,440 | |||||
| Expenses: | |||||||
| Operating | 65,890 | 60,691 | |||||
| Transportation | 33,625 | 29,026 | |||||
| General and administration | 7,541 | 6,218 | |||||
| Share-based payments (note 11) | 6,209 | 8,304 | |||||
| (Gain) on divestitures | (4,453) | (179) | |||||
| Depletion, depreciation and amortization | 180,939 | 167,688 | |||||
| Total expenses | 289,751 | 271,748 | |||||
| Income (loss) from operations | (39,374) | 41,692 | |||||
| Finance expenses | (12,727) | 9,889 | |||||
| Income (loss) before taxes | (52,101) | 31,803 | |||||
| Deferred taxes (recovery) | (12,943) | 10,336 | |||||
| Net income (loss) and comprehensive income (loss) before non-controlling interest | (39,158) | 21,467 | |||||
| Net income (loss) and comprehensive income (loss) attributable to: | |||||||
| Shareholders of the Company | (38,390) | 22,159 | |||||
| Non-controlling interest (note 8) | (768) | (692) | |||||
| $ | (39,158) | $ | 21,467 | ||||
|
Net income (loss) per share attributable to common shareholders (note 10) |
|||||||
| Basic | $ | (0.17) | $ | 0.11 | |||
| Diluted | $ | (0.17) | $ | 0.11 | |||
| See accompanying notes to the interim condensed consolidated financial statements. |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY | ||||||||||||||||||||
| (000s) (unaudited) | Share Capital | Contributed Surplus | Retained Earnings | Non-Controlling Interest | Total Equity | |||||||||||||||
| Balance at December 31, 2015 | $ | 4,266,234 | $ | 171,958 | $ | 764,953 | $ | 28,431 | $ | 5,231,576 | ||||||||||
| Issue of common shares (note 9) | – | – | – | – | – | |||||||||||||||
| Issue of common shares on acquisitions (note 9) | – | – | – | – | – | |||||||||||||||
| Share issue costs, net of tax | (80 | ) | – | – | – | (80 | ) | |||||||||||||
| Share-based payments | – | 6,209 | – | – | 6,209 | |||||||||||||||
| Capitalized share-based payments | – | 6,209 | – | – | 6,209 | |||||||||||||||
| Options exercised (notes 9 and 11) | 5,130 | (1,437 | ) | – | – | 3,693 | ||||||||||||||
| Loss attributable to common shareholders | – | – | (38,390 | ) | – | (38,390 | ) | |||||||||||||
| Loss attributable to non-controlling interest | – | – | – | (768 | ) | (768 | ) | |||||||||||||
| Balance at March 31, 2016 | $ | 4,271,284 | $ | 182,939 | $ | 726,563 | $ | 27,663 | $ | 5,208,449 | ||||||||||
| (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) | 25,683 | – | – | – | 25,683 | ||||||||||||||
| Share issue costs, net of tax (note 9) | (898 | ) | – | – | – | (898 | ) | ||||||||||||
| Share-based payments | – | 8,304 | – | – | 8,304 | ||||||||||||||
| Capitalized share-based payments | – | 8,304 | – | – | 8,304 | ||||||||||||||
| Options exercised (notes 9 and 11) | 13,231 | (3,605 | ) | – | – | 9,626 | |||||||||||||
| Income attributable to common shareholders | – | – | 22,159 | – | 22,159 | ||||||||||||||
| Loss attributable to non-controlling interest | – | – | – | (692 | ) | (692 | ) | ||||||||||||
| Balance at March 31, 2015 | $ | 3,653,394 | $ | 137,328 | $ | 707,025 | $ | 29,314 | $ | 4,527,061 | |||||||||
| See accompanying notes to the interim condensed consolidated financial statements. |
CONSOLIDATED STATEMENTS OF CASH FLOW
|
Three Months Ended March 31, |
||||||||
| (000s) (unaudited) | 2016 | 2015 | ||||||
| Cash provided by (used in): | ||||||||
| Operations: | ||||||||
| Net income (loss) | $ | (38,390) | $ | 22,159 | ||||
| Items not involving cash: | ||||||||
| Depletion, depreciation and amortization | 180,939 | 167,688 | ||||||
| Accretion | 790 | 551 | ||||||
| Share-based payments | 6,209 | 8,304 | ||||||
| Deferred taxes (recovery) | (12,943) | 10,336 | ||||||
| Unrealized loss on financial instruments | 28,643 | 427 | ||||||
| (Gain) on divestitures | (4,453) | (179) | ||||||
| Amortization on long-term asset | 163 | – | ||||||
| Non-controlling interest | (768) | (692) | ||||||
| Decommissioning expenditures | (760) | (854) | ||||||
| Changes in non-cash operating working capital | 16,878 | (13,370) | ||||||
| Total cash flow from operating activities | 176,308 | 194,370 | ||||||
| Financing: | ||||||||
| Issue of common shares | 3,693 | 41,626 | ||||||
| Share issue costs | (109) | (1,201) | ||||||
| Increase in bank debt | 308,493 | 240,234 | ||||||
| Total cash flow from financing activities | 312,077 | 280,659 | ||||||
| Investing: | ||||||||
| Exploration and evaluation | (4,634) | (43,075) | ||||||
| Property, plant and equipment | (245,515) | (450,311) | ||||||
| Property acquisitions | (182,708) | (4,515) | ||||||
| Proceeds from divestitures | 18,000 | 519 | ||||||
| Net repayment of long-term obligation | – | (865) | ||||||
| Changes in non-cash investing working capital | (73,528) | (132,213) | ||||||
| Total cash flow used in investing activities | (488,385) | (630,460) | ||||||
| Changes in cash | – | (155,431) | ||||||
| Cash, beginning of period | – | 263,052 | ||||||
| Cash, end of period | $ | – | $ | 107,621 | ||||
| Cash is defined as cash and cash equivalents. |
| See accompanying notes to the interim condensed consolidated financial statements. |
NOTES TO THE INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
AS AT MARCH 31, 2016 AND FOR THE THREE MONTHS ENDED MARCH 31, 2016 AND 2015
(tabular amounts in thousands of dollars, unless otherwise noted) (unaudited)
Corporate Information:
Tourmaline Oil Corp. (the “Company”) was incorporated under the laws of the Province of Alberta on July 21, 2008. The Company is engaged in the acquisition, exploration, development and production of petroleum and natural gas properties. These unaudited interim condensed consolidated financial statements reflect only the Company’s proportionate interest in such activities.
The Company’s registered office is located at Suite 2400, 525 – 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, 2015.
The accounting policies and significant accounting judgments, estimates, and assumptions used in these unaudited interim condensed consolidated financial statements are consistent with those described in Notes 1 and 2 of the Company’s consolidated financial statements for the year ended December 31, 2015, except as noted below.
On January 1, 2016, the Company adopted the amendments made to IFRS 11 – Joint Arrangements, which provided new guidance on the accounting for the acquisition of an interest in a joint operation that constitutes a business. There was no impact the Company as a result of adopting the amended standard.
The unaudited interim condensed consolidated financial statements were authorized for issue by the Board of Directors on May 4, 2016.
2. DETERMINATION OF FAIR VALUE
A number of the Company’s accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.
Tourmaline classifies the fair value of transactions according to the following hierarchy based on the amount of observable inputs used to value the instrument.
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.
Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.
The fair value of cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities approximate their carrying amounts due to their short term nature. Bank debt bears interest at a floating market rate with applicable variable margins, and accordingly the fair market value approximates the carrying amount. The Company’s financial instruments have been assessed on the fair value hierarchy described above and classified as Level 2.
3. FINANCIAL RISK MANAGEMENT
The 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, 2015.
As at March 31, 2016, the Company has entered into certain financial derivative contracts in order to manage commodity price, foreign exchange and interest rate risk. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, even though the Company considers all commodity and interest rate contracts to be effective economic hedges. As a result, all such contracts are recorded on the interim consolidated statement of financial position at fair value, with changes in the fair value being recognized as an unrealized gain or loss on the interim consolidated statement of income (loss) and comprehensive income (loss).
The Company has the following financial derivative contracts in place as at March 31, 2016 (1):
| (000s) | 2016 | 2017 | 2018 | 2019 | 2020 | Fair Value | |||||||||||||||
| Gas | |||||||||||||||||||||
| Financial swaps | mmbtu/d | 65,000 | – | – | – | – | $ | 18,759 | |||||||||||||
| USD$/mmbtu | $ | 3.08 | |||||||||||||||||||
| NYMEX call options (writer) | mmbtu/d | – | 110,000 | 110,000 | 20,000 | 20,000 | $ | (18,349 | ) | ||||||||||||
| USD$/mmbtu | $ | 3.77 | $ | 3.77 | $ | 3.75 | $ | 3.75 | |||||||||||||
| Oil | |||||||||||||||||||||
| Financial swaps | bbls/d | 2,327 | 1,000 | – | – | – | $ | 15,207 | |||||||||||||
| USD$/bbl | $ | 56.89 | $ | 50.00 | |||||||||||||||||
| Financial call | bbls/d | 400 | 4,000 | 1,125 | – | – | $ | (6,311 | ) | ||||||||||||
| swaptions (2) | USD$/bbl | $ | 80.10 | $ | 62.45 | $ | 50.00 | ||||||||||||||
| Total Fair Value | $ | 9,306 | |||||||||||||||||||
| (1) | The volumes and prices reported are the weighted-average volumes and prices for the period. | |
| (2) | These are European and Asian swaptions whereby the Company provides the option to extend an oil swap into the period subsequent to the call date, or retroactively fix the price on the volumes under the contract. | |
The Company has entered into the following financial derivative contracts subsequent to March 31, 2016(1):
| Type of Contract | Quantity | Time Period | Contract Price | ||||
| Gas call writer (2) | 20,000 mmbtu/d | January 1, 2019 – December 31, 2019 | $ | 4.00 USD$/mmbtu | |||
| Oil financial swaps | 1,000 bbls/d | July 1, 2016 – December 31, 2017 | $ | 50.00 USD$/bbl | |||
| Oil financial swaps | 500 bbls/d | January 1, 2017 – December 31, 2017 | $ | 47.30 USD$/bbl | |||
| Oil financial call swaptions (3) | 1,000 bbls/d | January 1, 2018 – December 31, 2018 | $ | 54.60 USD$/bbl | |||
| (1) | Transactions with common terms have been aggregated and presented at the weighted average price. | |
| (2) | This option can be called monthly on the last day of each month. | |
| (3) | These are Asian (monthly) call options. | |
The Company has the following interest rate swap arrangements:
| (000s) | ||||||||||||||
| Term |
Type (Floating to Fixed) |
Amount |
Company Fixed Interest Rate |
Counter Party Floating Rate Index |
Fair Value | |||||||||
| Apr 5, 2016 – Apr 5, 2019 | Swap | $ | 50,000 | 0.867 | % | Floating Rate | $ | (38 | ) | |||||
| Nov 28, 2014 – Nov 28, 2019 | Swap | $ | 250,000 | 2.065 | % | Floating Rate | $ | (11,000 | ) | |||||
| Apr 5, 2016 – Apr 5, 2021 | Swap | $ | 50,000 | 0.988 | % | Floating Rate | $ | (220 | ) | |||||
| Total Fair Value | $ | (11,258 | ) | |||||||||||
The following table provides a summary of the unrealized gains (losses) on financial instruments recorded in the consolidated statements of income (loss) and comprehensive income (loss) for the three months ended March 31, 2016 and 2015:
|
Three Months Ended March 31, |
||||||||
| (000s) | 2016 | 2015 | ||||||
| Unrealized gain/(loss) on financial instruments – commodity contracts | $ | (27,763 | ) | $ | 6,544 | |||
| Unrealized (loss) on financial instruments – interest rate swaps | (880 | ) | (6,971 | ) | ||||
| Total unrealized (loss) on financial instruments | $ | (28,643 | ) | $ | (427 | ) | ||
In addition to the financial commodity contracts discussed above, the Company has entered into physical delivery sales contracts to manage commodity risk. These contracts are considered normal sales contracts and are not recorded at fair value in the consolidated financial statements.
The Company has the following physical contracts in place at March 31, 2016 (1)(7):
| 2016 | 2017 | 2018 | 2019 | 2020 | ||||||||||||||||||
| Gas | ||||||||||||||||||||||
| Fixed price – AECO | mcf/d | 198,297 | 21,043 | – | – | – | ||||||||||||||||
| CAD$/mcf | $ | 2.30 | $ | 2.04 | – | – | – | |||||||||||||||
| Basis differentials (2)(3) | mmbtu/d | 199,755 | 42,500 | 22,500 | 22,500 | 22,500 | ||||||||||||||||
| USD$/mmbtu | $ | (0.52 | ) | $ | (0.55 | ) | $ | (0.46 | ) | $ | (0.46 | ) | $ | (0.46 | ) | |||||||
| Basis differentials – Stn 2 (4) | mcf/d | 52,152 | 37,929 | 37,929 | 9,482 | 9,482 | ||||||||||||||||
| CAD$/mcf | $ | (0.33 | ) | $ | (0.29 | ) | $ | (0.29 | ) | $ | (0.26 | ) | $ | (0.26 | ) | |||||||
| AECO monthly calls / call swaptions (5) | mcf/d | 10,430 | 75,857 | 71,116 | – | |||||||||||||||||
| CAD$/mcf | $ | 5.56 | $ | 4.60 | $ | 4.25 | – | – | ||||||||||||||
| Oil | ||||||||||||||||||||||
| Fixed differential (6) | bbls/d | 387 | – | – | – | – | ||||||||||||||||
| USD$/bbl | $ | 6.50 | – | – | – | – | ||||||||||||||||
| (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 2021-2022. | |
| (3) | Tourmaline also has 10,000 mmbtu/d SoCal – AECO basis differential at $(0.73) from November 2013 to October 2016. | |
| (4) | Tourmaline also has 9,482 mcf/d of Stn 2. basis differentials at $(0.26) for 2021. | |
| (5) | These are monthly calls for 2016 and in 2017-2018 are European Swaptions, whereby the Company provides the option to extend a gas swap into the period subsequent to the call date or increase the volumes under contract. | |
| (6) | Tourmaline sells physical crude at a fixed differential to NYMEX. | |
| (7) | Tourmaline also has entered into deals to sell 30,000 mmbtu/d at Chicago GDD pricing less transportation costs from April 2015 to October 2020, 20,000 mmbtu/d at Chicago GDD pricing less transportation costs from April 2015 to March 2020, and 20,000 mmbtu/d at Ventura GDD pricing less transportation costs from April 2015 to October 2020. | |
The Company has entered into the following physical contracts subsequent to March 31, 2016:
| Type of Contract | Quantity | Time Period | Contract Price | |||
| Basis differentials | 20,000 mmbtu/d | January 1, 2017 – December 31, 2017 | USD$(0.65)/mmbtu | |||
4. EXPLORATION AND EVALUATION ASSETS
| (000s) | |||||
| As at December 31, 2015 | $ | 620,142 | |||
| Capital expenditures | 4,634 | ||||
| Transfers to property, plant and equipment (note 5) | (6,667 | ) | |||
| Acquisitions | 4,753 | ||||
| Divestitures | (413 | ) | |||
| Expired mineral leases | (5,921 | ) | |||
| As at March 31, 2016 | $ | 616,528 | |||
Exploration and evaluation (“E&E”) assets consist of the Company’s exploration projects which are pending the determination of proven and probable reserves, as well as undeveloped land. Additions represent the Company’s share of costs on E&E assets during the period.
Impairment Assessment
In accordance with IFRS, an impairment test is performed if the Company identifies an indicator of impairment. At March 31, 2016 and December 31, 2015, the Company determined that no indicators of impairment existed on its E&E assets; therefore, an impairment test was not performed.
5. PROPERTY, PLANT AND EQUIPMENT
| Cost | |||||
| (000s) | |||||
| As at December 31, 2015 | $ | 8,685,985 | |||
| Capital expenditures | 251,724 | ||||
| Transfers from exploration and evaluation (note 4) | 6,667 | ||||
| Change in decommissioning liabilities (note 6) | 9,132 | ||||
| Acquisitions | 183,528 | ||||
| Divestitures | (19,090 | ) | |||
| As at March 31, 2016 | $ | 9,117,946 | |||
| Accumulated Depletion, Depreciation and Amortization | ||||
| (000s) | ||||
| As at December 31, 2015 | $ | 1,902,214 | ||
| Depletion, depreciation and amortization | 175,018 | |||
| As at March 31, 2016 | $ | 2,077,232 | ||
| Net Book Value | |||
| (000s) | |||
| As at December 31, 2015 | $ | 6,783,771 | |
| As at March 31, 2016 | $ | 7,040,714 | |
Future development costs of $4,820.8 million were included in the depletion calculation at March 31, 2016 (December 31, 2015 – $4,523.1 million).
Capitalization of G&A and Share-Based Payments
A total of $6.1 million in G&A expenditures have been capitalized and included in E&E and PP&E assets at March 31, 2016 (December 31, 2015 – $22.9 million). Also included in E&E and PP&E are non-cash share-based payments of $6.2 million (December 31, 2015 – $30.8 million).
Impairment Assessment
In accordance with IFRS, an impairment test is performed on a CGU if the Company identifies an indicator of impairment. At March 31, 2016, the Company determined that there were no indicators of impairment on any of the Company’s CGUs; therefore an impairment test was not performed.
For the year ended December 31, 2015, the Company identified indicators of impairment on all of its CGUs due to the decline in current and forward commodity prices for oil and natural gas and performed impairment tests accordingly. The Company determined that there was no impairment to PP&E at December 31, 2015.
Business Combinations
Minehead-Edson-Ansell
On January 29, 2016, the Company acquired assets in the Minehead-Edson-Ansell area of the Alberta Deep Basin for cash consideration of $183.0 million before customary adjustments. The acquisition resulted in an increase in lands, production, reserves and facilities in a core area of the Alberta Deep Basin.
Results from operations are included in the Company’s unaudited interim consolidated financial statements from the closing date of the transaction. The acquisition has been accounted for using the purchase method based on fair values as follows:
| (000s) | Minehead-Edson-Ansell | ||||
| Fair value of net assets acquired: | |||||
| Property, plant and equipment | $ | 179,230 | |||
| Exploration and evaluation | 4,753 | ||||
| Decommissioning obligations | (983 | ) | |||
| Total | $ | 183,000 | |||
| Consideration: | |||||
| Cash | $ | 183,000 | |||
Perpetual Energy Inc.
On April 1, 2015, the Company acquired Perpetual Energy Inc.’s (“Perpetual”) interests in the West Edson area of the Alberta Deep Basin with the issuance of 6,750,000 Tourmaline shares at a price of $38.32 per share for total consideration of $258.7 million. The acquisition resulted in an increase in land, production, reserves and processing capacity along with allowing the Company to leverage operational synergies created from having full ownership of the assets.
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 (loss) and comprehensive income (loss). The acquisition resulted in an increase in Property, Plant and Equipment (“PP&E”) of approximately $26.8 million and Exploration and Evaluation (“E&E”) assets of $2.1 million along with net debt of $8.4 million. Results from operations for Bergen are included in the Company’s unaudited interim consolidated financial statements from the closing date of the transaction. The acquisition of Bergen consolidated the Company’s working interest in a core area of the Peace River High.
Mapan Energy Ltd.
On August 14, 2015, the Company acquired all of the issued and outstanding shares of Mapan Energy Ltd. (“Mapan”). As consideration, the Company issued of 2,718,026 Tourmaline shares at a price of $32.98 per share for total consideration of $89.6 million. Total transaction costs incurred by the Company of $1.1 million associated with this acquisition were expensed in the interim consolidated statement of income and comprehensive income. The acquisition of Mapan resulted in an increase in lands and production in a core area of the Alberta Deep Basin.
Results from operations for Mapan are included in the Company’s unaudited interim consolidated financial statements from the closing date of the transaction. The acquisition has been accounted for using the purchase method based on fair values as follows:
| (000s) | Mapan Energy Ltd. | |||
| Fair value of net assets acquired: | ||||
| Cash | $ 11,011 | |||
| Working capital | 4,000 | |||
| Property, plant and equipment | 58,471 | |||
| Fair Value of Financial Instruments | (122 | ) | ||
| Decommissioning obligations | (3,157 | ) | ||
| Deferred income tax asset | 19,437 | |||
| Total | $ 89,640 | |||
| Consideration: | ||||
| Common shares issued | $ 89,640 | |||
Acquisitions and Dispositions of Oil and Natural Gas Properties
For the three months ended March 31, 2016, the Company did not complete any property cash acquisitions other than the Minehead-Edson-Ansell acquisition (December 31, 2015 – $92.0 million); however, there were $4.6 million in acquisitions involving non-cash consideration (December 31, 2015 – $73.4 million). The Company also assumed $1.0 million in decommissioning liabilities in addition to the Minehead-Edson-Ansell acquisition (December 31, 2015 – $3.0 million).
On March 1, 2016, the Company sold non-core assets for cash consideration of $18.0 million, before customary adjustments. The net book value of the oil and natural gas properties disposed was equal to the cash consideration received.
6. DECOMMISSIONING OBLIGATIONS
The Company’s decommissioning obligations result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted amount of cash flow required to settle its decommissioning obligations is approximately $230.7 million (December 31, 2015 – $224.5 million), with some abandonments expected to commence in 2021. A risk-free rate of 2.00% (December 31, 2015 – 2.15%) and an inflation rate of 1.8% (December 31, 2015 – 1.8%) were used to calculate the decommissioning obligations.
| (000s) |
As at March 31, 2016 |
As at December 31, 2015 |
|||||
| Balance, beginning of period | $ | 163,459 | $ | 114,038 | |||
| Obligation incurred | 2,671 | 16,780 | |||||
| Obligation incurred on corporate acquisitions | – | 3,516 | |||||
| Obligation incurred on property acquisitions | 983 | 5,484 | |||||
| Obligation divested | (1,366) | (270) | |||||
| Obligation settled | (760) | (1,613) | |||||
| Accretion expense | 790 | 2,854 | |||||
| Change in future estimated cash outlays | 6,461 | 22,670 | |||||
| Balance, end of period | $ | 172,238 | $ | 163,459 | |||
7. BANK DEBT
The Company has a covenant-based, unsecured, revolving credit facility in place with a syndicate of bankers, the details of which are described in note 9 of the Company’s consolidated financial statements for the years ended December 31, 2015 and December 31, 2014. The facility has a credit limit of $1,800.0 million plus a $50.0 million operating line, and has an initial maturity date of June 2019.
The Company also has a $250.0 million five-year term loan with a Canadian Chartered Bank, the details of which are described in note 9 of the Company’s consolidated financial statements for the years ended December 31, 2015 and 2014.
As at March 31, 2016, the Company had $248.7 million in long-term debt outstanding and $1,326.4 million drawn against the bank credit facility for total bank debt of $1,575.1 million (net of prepaid interest and debt issue costs) (December 31, 2015 – $1,266.6 million). In addition, Tourmaline has outstanding letters of credit of $15.4 million (December 31, 2015 – $13.4 million), which reduce the credit available on the facility. The effective interest rate for the three months ended March 31, 2016 was 2.45%. As at March 31, 2016, the Company is in compliance with all debt covenants.
8. NON-CONTROLLING INTEREST
The Company owns 90.6 percent of Exshaw Oil Corp., a private company engaged in oil and gas exploration in Canada. A reconciliation of the non-controlling interest is provided below:
| (000s) |
As at March 31, 2016 |
As at December 31, 2015 |
|||||||
| Balance, beginning of period | $ | 28,431 | $ | 30,006 | |||||
| Share of subsidiary’s net (loss) for the period | (768 | ) | (1,575 | ) | |||||
| Balance, end of period | $ | 27,663 | $ | 28,431 | |||||
9. SHARE CAPITAL
(a) Authorized
Unlimited number of Common Shares without par value.
Unlimited number of non-voting Preferred Shares, issuable in series.
(b) Common Shares Issued
|
As at March 31, 2016 |
As at December 31, 2015 |
|||||||||||
| (000s) except share amounts | Number of Shares | Amount | Number of Shares | Amount | ||||||||
| Balance, beginning of period | 221,335,925 | $ | 4,266,234 | 203,162,112 | $ | 3,615,378 | ||||||
| For cash on public offering of common shares (2) | – | – | 4,947,500 | 195,425 | ||||||||
| For cash on public offering of flow-through common shares (1)(3) | – | – | 1,122,700 | 38,403 | ||||||||
| Issued on corporate and property acquisitions (note 5) | – | – | 10,193,026 | 372,878 | ||||||||
| For cash on exercise of stock options | 148,334 | 3,693 | 1,910,587 | 37,159 | ||||||||
| Contributed surplus on exercise of stock options | – | 1,437 | – | 14,051 | ||||||||
| Share issue costs | – | (109 | ) | – | (10,066 | ) | ||||||
| Tax effect of share issue costs | – | 29 | – | 3,006 | ||||||||
| Balance, end of period | 221,484,259 | $ | 4,271,284 | 221,335,925 | $ | 4,266,234 | ||||||
| (1) | 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 March 31, 2016, the Company is committed to spend the remaining $6.4 million on qualified exploration expenditures by December 31, 2016. The expenditures were renounced to investors with an effective renunciation date of December 31, 2015. | |
| (2) | On June 23, 2015, the Company issued 4.948 million common shares at a price of $39.50 for total gross proceeds of $195.4 million. A total of 54,000 common shares were purchased by insiders. | |
| (3) | On November 25, 2015, the Company issued 0.48 million flow-through shares at a price of $34.10 per share for total gross proceeds of $16.5 million. The implied premium on flow-through common shares was determined to be $3.7 million or $7.75 per share. As at March 31, 2016, the Company is committed to spend $16.5 million on qualified exploration expenditures by December 31, 2016. The expenditures were renounced to investors with an effective renunciation date of December 31, 2015. | |
10. EARNINGS PER SHARE
Basic earnings-per-share attributed to common shareholders was calculated as follows:
|
Three Months Ended March 31, |
||||||
| 2016 | 2015 | |||||
| Net earnings (loss) for the period (000s) | $ | (38,390) | $ | 22,159 | ||
| Weighted average number of common shares – basic | 221,403,764 | 203,560,489 | ||||
| Earnings (loss) per share – basic | $ | (0.17) | $ | 0.11 | ||
Diluted earnings-per-share attributed to common shareholders was calculated as follows:
|
Three Months Ended March 31, |
||||||
| 2016 | 2015 | |||||
| Net earnings (loss) for the period (000s) | $ | (38,390) | $ | 22,159 | ||
| Weighted average number of common shares – diluted | 221,403,764 | 205,530,914 | ||||
| Earnings (loss) per share – fully diluted | $ | (0.17) | $ | 0.11 | ||
There were 19,619,746 options excluded from the weighted-average share calculations for the three-month period ended March 31, 2016 because they were anti-dilutive (three months ended March 31, 2015 – 9,867,666 options).
11. SHARE-BASED PAYMENTS
The Company has a rolling stock option plan. Under the employee stock option plan, the Company may grant options to its employees up to 22,148,426 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 first anniversaries from the date of grant.
| Three Months Ended March 31, | |||||||||||
| 2016 | 2015 | ||||||||||
| Number of Options | Weighted Average Exercise Price | Number of Options | Weighted Average Exercise Price | ||||||||
| Stock options outstanding, beginning of period | 19,746,414 | $ | 36.50 | 17,046,500 | $ | 36.44 | |||||
| Granted | 125,000 | 28.18 | 118,500 | 37.53 | |||||||
| Exercised | (148,334) | 24.90 | (481,837) | 19.98 | |||||||
| Forfeited | (103,334) | 40.53 | – | – | |||||||
| Stock options outstanding, end of period | 19,619,746 | $ | 36.51 | 16,683,163 | $ | 36.93 | |||||
The weighted average trading price of the Company’s common shares was $26.09 during the three months ended March 31, 2016 (three months ended March 31, 2015 – $38.22).
The following table summarizes stock options outstanding and exercisable at March 31, 2016:
| Range of Exercise Price |
Number Outstanding at Period End |
Weighted Average Remaining Contractual Life | Weighted Average Exercise Price |
Number Exercisable at Period End |
Weighted Average Exercise Price | |||||
| $20.68 – $29.93 | 6,306,082 | 2.78 | 26.78 | 2,999,082 | 27.13 | |||||
| $30.76 – $39.57 | 4,204,664 | 2.51 | 34.39 | 2,625,664 | 32.70 | |||||
| $40.18 – $48.99 | 7,459,000 | 2.95 | 42.11 | 3,917,667 | 41.86 | |||||
| $51.47 – $56.76 | 1,650,000 | 3.27 | 53.85 | 550,000 | 53.85 | |||||
| 19,619,746 | 2.77 | 36.51 | 10,092,413 | 35.75 | ||||||
The fair value of options granted during the three-month period ended March 31, 2016 was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions and resulting values:
| March 31, | ||||||||
| 2016 | 2015 | |||||||
| Fair value of options granted (weighted average) | $ | 8.30 | $ | 10.66 | ||||
| Risk-free interest rate | 2.06 | % | 2.08 | % | ||||
| Estimated hold period prior to exercise | 4 years | 4 years | ||||||
| Expected volatility | 34 | % | 32 | % | ||||
| 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 | $ | 5,309 | $ | 11,028 | $ | 5,389 | $ | – | $ | 21,726 | |||||
| Firm transportation and processing agreements | 179,582 | 411,386 | 368,146 | 917,708 | 1,876,822 | ||||||||||
| Capital commitments (1) | 311,111 | 603,261 | 295,500 | – | 1,209,872 | ||||||||||
| Flow-through share commitments | 22,906 | – | – | – | 22,906 | ||||||||||
| Credit facility (2) | – | – | 1,446,963 | – | 1,446,963 | ||||||||||
| Term debt (3) | 7,776 | 15,552 | 262,792 | – | 286,120 | ||||||||||
| Interest rate swaps | 3,145 | 6,315 | 1,981 | – | 11,441 | ||||||||||
| $ | 529,829 | $ | 1,047,542 | $ | 2,380,771 | $ | 917,708 | $ | 4,875,850 | ||||||
| (1) | Includes drilling commitments, and capital spending commitments under the joint arrangement in the Spirit River complex of $300.0 million per year until 2019. The capital spending commitment under the joint arrangement can be deferred to future periods in the event of an economic downturn, and as agreed upon by both parties. Since December 31, 2015, an economic downturn event, as defined in the joint arrangement in the Spirit River complex has existed and as such capital spending for 2016 may be reduced and extended to future years. | |
| (2) | Includes interest expense at an annual rate of 2.63% being the rate applicable to outstanding debt on the credit facility at March 31, 2016. | |
| (3) | Includes interest expense at an annual rate of 3.11% being the fixed rate on the term debt at March 31, 2016. | |
13. SUBSEQUENT EVENTS
On April 5, 2016, the Company issued 10,387,500 common shares at a price of $27.11 per share for total gross proceeds of $281.6 million (net proceeds – $269.9 million). The proceeds will be used to temporarily reduce bank debt, to fund the Company’s 2016 exploration and development program and future potential acquisition opportunities.
ABOUT TOURMALINE OIL CORP.
Tourmaline is a Canadian intermediate crude oil and natural gas exploration and production company focused on long-term growth through an aggressive exploration, development, production and acquisition program in the Western Canadian Sedimentary Basin.
FOR FURTHER INFORMATION, PLEASE CONTACT:
Tourmaline Oil Corp.
Michael Rose
Chairman, President and Chief Executive Officer
(403) 266-5992
OR
Tourmaline Oil Corp.
Brian Robinson
Vice President, Finance and Chief Financial Officer
(403) 767-3587; [email protected]
OR
Tourmaline Oil Corp.
Scott Kirker
Secretary and General Counsel
(403) 767-3593; [email protected]
OR
Tourmaline Oil Corp.
Suite 3700, 250 – 6th Avenue S.W.
Calgary, Alberta T2P 3H7
Phone: (403) 266-5992
Facsimile: (403) 266-5952
E-mail: [email protected]
Website: www.tourmalineoil.com
