TOURMALINE OIL CORP. ACHIEVES RECORD CASH FLOW AND EARNINGS GROWTH IN 2013
Calgary, Alberta – Tourmaline Oil Corp. (TSX:TOU) (“Tourmaline” or the “Company”) achieved exceptional growth in reserves (41%), production (47%) and cash flow1 (88%) in 2013 while delivering strong profitability. The Company posted significant after-tax earnings of $148.1 million for the 2013 fiscal year.
- Record full year after tax earnings of $148.1 million ($0.79 per diluted share), an 854% increase over 2012, and record quarterly after tax earnings of $56.8 million in the fourth quarter, underscoring the fundamental full cycle profitability of Tourmaline’s natural gas business.
- 2013 cash flow of $526.8 million ($2.80 per diluted share), an 88% increase over 2012 (67% per diluted share).
- Record quarterly cash flow of $160.7 million ($0.83 per diluted share) in Q4 2013.
- 2013 annual production growth of 47% (31% per diluted share), and forecast 2014 production growth of 60% over 2013.
- Q4 2013 average production of 86,089 boepd, a 50% increase over the fourth quarter of 2012 and a 16% increase over the previous quarter.
- Total 2P reserve additions of 179.4 mmboe in 2013, representing 41% growth over 2012 total 2P reserves before 2013 production (30% per diluted share).
- Year end 2013 2P reserve value of $6.2 billion (10% discount, before tax), representing 42% growth over year end 2012 2P reserve value of $4.3 billion, a net present value increase in 2013 of $1.9 billion vs. $1.7 billion in 2012.
- Three-year 2P finding, development and acquisitions cost (FD&A) of $11.65/boe (including FDC) and $7.20/boe (excluding FDC).
- 2013 reserve replacement ratio of 6.6 times.
- Continued industry-leading all-in cost structure of $7.72/boe (operating costs, transportation, general and administrative, and financing costs).
- Anticipated full year 2014 average production of 120,000 boepd represents a 60% increase from the 2013 average.
- The Company expects to tie-in approximately 48 wells during the first quarter of 2014, reaching estimated production levels of 115,000-120,000 boepd in late March/early April 2014.
- The Musreau plant expansion, Doe B.C. plant expansion and start-up of the Tourmaline Spirit River gas plant will lead to significant further production growth in the third quarter of 2014.
Alberta Deep Basin
- Tourmaline intends to operate 12 drilling rigs in the Alberta Deep Basin through the balance of 2014; the fleet will be shut down during break-up.
- 17 new Wilrich horizontals have been drilled thus far in 2014; a total of 55 new Wilrich horizontals which will be tied into Tourmaline facilities, are planned for full year 2014.
- The winter program has yielded five new high deliverability Wilrich horizontals in the Smoky-Horse-Berland areas including the Smoky 4-1-59-2W6 well with a 30-day average IP of 22.2 mmcfpd.
- Cretaceous Notikewin results have continued to exceed internal economic template expectations. The 30-day average IP from the Wild River 12-28-56-24W5 horizontal is 20.9 mmcfpd.
- The Company is expanding the Musreau gas plant by 50-55 mmcfpd with a Q3 2014 expected start-up and is also participating in a plant expansion at West Edson. Tourmaline expects to reach the 0.5 bcf/day production milestone in the Deep Basin in either late 2014 or early 2015.
NEBC Montney Gas/Condensate
- Tourmaline is currently operating two rigs in the NEBC Montney gas/condensate complex and will continue with drilling operations through break-up and the remainder of the year. The Company expects to drill 35 Montney horizontal wells in NEBC in 2014.
- The A5-5 and D5-5 condensate-rich Lower Montney discovery wells from late 2013 have 30-day IP rates of 6.3 mmcfpd and 634 bbls/day condensate (100.5 bbls/mmcfpd at wellhead) and 5.6 mmcfpd and 501 bbls/day condensate (89.5 bbls/mmcfpd at wellhead), respectively. One regional follow-up has been drilled and will be completed over the next month. Drilling on an adjacent multi-well follow-up pad to 5-5 has commenced and will continue through break-up. The Company acquired considerable acreage prospective for this new horizon in December 2013.
- The Doe gas plant expansion of 55 mmcfpd is planned for a Q3 2014 start-up. The Company expects to be producing 250 mmcfpd and 5,000-6,000 bbls/day of condensate and NGLs in NEBC by year end 2014.3
Peace River High Charlie Lake Oil
- 14 new Charlie Lake horizontal oil wells have been drilled along the trend thus far in 2014; Tourmaline will continue to operate three drilling rigs during 2014, yielding approximately 45 new wells. The Company has now drilled 72 successful horizontal oil wells into the regional pool with no dry holes to date.
- Two concurrently-completed dual well pairs are currently being stimulated and will be brought on-stream by break-up.
- Current daily production from the complex is averaging 9,000 – 10,000 boepd; an additional 6,000 boepd of production remains shut-in at Spirit River.
- The Tourmaline sour gas injection plant at Spirit River remains on schedule for a Q3 2014 start-up and construction of the Mulligan oil battery will commence during the third quarter as well.
- The Company is targeting a 2014 exit volume of 18,000 – 20,000 boepd from the Peace River High Charlie Lake Complex with these new facilities on-stream.
- The Paleozoic Exploration test at Sunset 11-17 in NEBC was cased to total depth during the first quarter of 2014, with 3 gas pay zones to complete. Completion operations will commence in July as the higher pressure equipment required to safely conduct operations could not be secured in time to finish operations prior to break-up.
- The Company’s first Montney horizontal in the Resthaven-Kakwa gas-condensate play area is currently being completed and stimulated.
- The Smoky 8-15 deep test has been drilled to the Cambrian and cased to total depth; there are multiple deep gas zones to be completed.
- 2014 full year cash flow forecast of $1.0 billion, representing a 92% increase over 2013 cash flow, is driven primarily by the combination of growth in production volumes and stronger natural gas prices.
- 2013 full year operating netbacks2 of $20.37/boe increased 25% over the prior year.
- Maintained low overall cash costs by continuing to drive down unit operating costs to $4.35/boe.
- Year end 2013 net debt3 at $832.9 million, subsequently reduced in February 2014 as a result of 4.6 million common shares issued for gross proceeds of $219.2 million.
- 2013 cash consideration invested in capital expenditures (net of dispositions) was $1.3 billion which included drilling 129 gross wells and investing $43.0 million in land and seismic to acquire 146 sections (net) of undeveloped land. In addition, $386.6 million was spent in part to expand two Deep Basin gas plants and construct a new gas plant in NEBC, bringing total throughput capacity for the Company to approximately 600 mmcfpd. Multiple property acquisitions in Spirit River, NEBC and the Alberta Deep Basin were completed for $226.9 million (515 net sections). During the year, the Company also disposed of non-core assets for cash proceeds of $78.1 million.
Conference Call Tomorrow at 9:00 a.m. MT (11:00 a.m. ET)
Tourmaline will host a conference call tomorrow, March 18, 2014 starting at 9:00 a.m. MT (11:00 a.m. ET). To participate, please dial 1-800-766-6630 (toll-free in North America), or local dial-in 416-340-8527, a few minutes prior to the conference call.
The conference call ID number is 4187197.
All amounts in this news release are stated in Canadian dollars unless otherwise specified.
The reserves data set forth above is based upon the reports of GLJ Petroleum Consultants Ltd. (“GLJ”) and Deloitte LLP, each dated effective December 31, 2013, which have been consolidated into one report by GLJ and adjusted to apply certain of GLJ’s assumptions and methodologies and pricing and cost assumptions. The complete GLJ January 1, 2014 price forecast used in the reserve evaluations is available on its website at www.gljpc.com.
There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. The Company’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. All evaluations and reviews of future net revenue are stated prior to any provisions for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. The after-tax net present value of the Company’s oil and gas properties reflects the tax burden on the properties on a stand-alone basis and utilizes the Company’s tax pools. It does not consider the corporate tax situation, or tax planning. It does not provide an estimate of the after-tax value of the Company, which may be significantly different. The Company’s financial statements and the management’s discussion and analysis should be consulted for information at the level of the Company.
The estimated values of future net revenue disclosed in this news 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.
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 will be contained in the Company’s Annual Information Form for the year ended December 31, 2013, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2014.
Per diluted share reserve information is based on the total common shares outstanding, after accounting for outstanding Company options, at year end 2013 and 2012, respectively.
See also the Company’s news release dated February 19, 2014 for more information with respect to the Company’s reserves data.
Initial Production (IP) Rates
Any references in this news release to IP rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter and are not necessarily indicative of long-term performance or ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Such rates are based on field estimates and may be based on limited data available at this time.
F&D and FD&A Costs
In addition to F&D, the Company uses FD&A as a measure of the efficiency of its overall capital program including the effect of acquisitions and dispositions. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
Also included in this news release are estimates of Tourmaline’s 2014 cash flow, which is 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 2014 average production of 120,000 boepd and commodity price assumptions for natural gas (AECO – $3.86/mcf) (2014), and crude oil (WTI (US) – $97.00/bbl) (2014) and an exchange rate assumption of $0.97 (US/CAD) for 2014. To the extent such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Tourmaline on March 17, 2014 and is included to provide readers with an understanding of Tourmaline’s anticipated cash flow based on the capital expenditure, production and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.
See also “Forward-Looking Statements”, “Boe Conversions” and “Non-GAAP Financial Measures” in the attached Management’s Discussion and Analysis.
- bbl – barrel
- bcf – billion cubic feet
- bpd – barrels per day
- boe – barrel of oil equivalent
- boepd or boe/d – barrel of oil equivalent per day
- bopd or bbl/d – barrel of oil, condensate or liquids per day
- gj – gigajoule
- gjs/d – gigajoules per day
- mbbls – thousand barrels
- mboe – thousand barrels of oil equivalent
- mcf – thousand cubic feet
- mcfe – thousand cubic feet equivalent
- mmboe – million barrels of oil equivalent
- mmbtu – million British thermal units
- mmbtu/d – million British thermal units per day
- mmcf – million cubic feet
- mmcfpd or mmcf/d – million cubic feet per day
- mstboe – thousand stock tank barrels of oil equivalent
- NGL – natural gas liquids
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the years ended December 31, 2013 and December 31, 2012
This management’s discussion and analysis (“MD&A“) should be read in conjunction with Tourmaline Oil Corp.’s consolidated financial statements and related notes for the years ended December 31, 2013 and 2012. Both the consolidated financial statements and the MD&A can be found at www.sedar.com. This MD&A is dated March 17, 2014.
The financial information contained herein has been prepared in accordance with International Financial Reporting Standards (“IFRS”) and sometimes referred to in this MD&A as Generally Accepted Accounting Principles (“GAAP”) as issued by the International Accounting Standards Board (“IASB”). All dollar amounts are expressed in Canadian currency, unless otherwise noted.
Certain financial measures referred to in this MD&A are not prescribed by IFRS. See “Non-GAAP Financial Measures” for information regarding the following non-GAAP financial measures used in this MD&A: “cash flow”, “operating netback”, “working capital (adjusted for the fair value of financial instruments)”, “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, estimates or beliefs concerning, among other things, an outlook on the estimated amounts and timing of capital investment, anticipated future debt, expenses, production, cash flow and revenues or other expectations, beliefs, plans, objectives, assumptions, intentions or statements about future events or performance. These statements are only predictions and actual events or results may differ materially. Although Tourmaline believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies. Many factors could cause Tourmaline’s actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, Tourmaline.
In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to: the size of, and future net revenues and cash flow from, crude oil, NGL (natural gas liquids) and natural gas reserves; future prospects; the focus of and timing of capital expenditures; expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; access to debt and equity markets; projections of market prices and costs; the performance characteristics of the Company’s crude oil, NGL and natural gas properties; crude oil, NGL and natural gas production levels and product mix; Tourmaline’s future operating and financial results; capital investment programs; supply and demand for crude oil, NGL and natural gas; future royalty rates; drilling, development and completion plans and the results therefrom; future land expiries; dispositions and joint venture arrangements; amount of operating, transportation and general and administrative expenses; treatment under governmental regulatory regimes and tax laws; and estimated tax pool balances. In addition, statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.
These forward-looking statements are subject to numerous risks and uncertainties, most of which are beyond the Company’s control, including the impact of general economic conditions; volatility in market prices for crude oil, NGL and natural gas; industry conditions; currency fluctuation; imprecision of reserve estimates; liabilities inherent in crude oil and natural gas operations; environmental risks; incorrect assessments of the value of acquisitions and exploration and development programs; competition; the lack of availability of qualified personnel or management; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; stock market volatility; ability to access sufficient capital from internal and external sources; the receipt of applicable approvals; and the other risks considered under “Risk Factors” in Tourmaline’s most recent annual information form available at www.sedar.com.
With respect to forward-looking statements contained in this MD&A, Tourmaline has made assumptions regarding: future commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment and services; effects of regulation by governmental agencies; and future operating costs.
Management has included the above summary of assumptions and risks related to forward-looking information provided in this MD&A in order to provide shareholders with a more complete perspective on Tourmaline’s future operations and such information may not be appropriate for other purposes. Tourmaline’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that the Company will derive therefrom. Readers are cautioned that the foregoing lists of factors are not exhaustive.
These forward-looking statements are made as of the date of this MD&A and the Company disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.
Boe Conversions – Per barrel of oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent (6:1). Barrel of oil equivalents (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, as the value ratio between natural gas and crude oil based on the 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 for the fourth quarter of 2013 averaged 86,089 boe/d, a 50% increase over the average production for the same quarter of 2012 of 57,230 boe/d. Production was 86% natural gas weighted in the fourth quarter of 2013, compared to 88% for the same quarter of the prior year. For the year ended December 31, 2013, production increased 47% to 74,796 boe/d from 50,804 boe/d in 2012. The Company’s significant production growth when compared to 2012 can be primarily attributed to new wells that have been brought on-stream in 2013, as well as property acquisitions. The significant increase in liquids production can be attributed to growth in oil production in Spirit River and stronger NGL recoveries in both the Alberta Deep Basin and NEBC.
Tourmaline increased its 2014 production guidance from 118,000 boe/d to 120,000 boe/d in its February 19, 2014 press release. The production increase is a direct result of Tourmaline’s continued success in the ongoing exploration and production program, as well as, continued investments in facilities and infrastructure.
Revenue for the three months ended December 31, 2013 increased 64% to $235.1 million from $143.1 million for
the same quarter of 2012. Revenue for the year ended December 31, 2013 increased 75% to $788.9 million
from $449.8 million in 2012. Revenue growth is consistent with the increase in production and increased natural
gas prices over the same periods, offset by a small decrease in liquids prices. Revenue includes all natural gas,
petroleum and NGL sales and realized gains on financial instruments.
The realized average natural gas prices for the quarter and year ended December 31, 2013 were 17% and 37%, respectively, higher than the same periods of the prior year.
Realized crude oil and NGL prices decreased 14% for the quarter ended December 31, 2013, compared to the same quarter in 2012 as a result of widening Canadian differentials for sour crude and liquids relative to Edmonton Par. Realized crude oil and NGL prices decreased 1% for the year ended December 31, 2013, compared 2012.
The realized natural gas price for the quarter ended December 31, 2013 was $3.84/mcf, which is $0.32/mcf higher than the AECO index price (three months ended December 31, 2012 – $3.29/mcf and $0.10/mcf higher than AECO). The higher realized price is primarily due to higher heat content ($0.26/mcf and $0.29/mcf for the fourth quarters of 2013 and 2012, respectively). The remainder of the premium in the fourth quarter of 2013 relates to positive hedging positions, where in the fourth quarter of 2012 hedging losses offset the premium received by $0.19/mcf.
The realized natural gas price for the year ended December 31, 2013 was 15% (December 31, 2012 – 10%) higher than the AECO index as Tourmaline realized a gain on commodity contracts in combination with the higher heat content noted above. Realized prices exclude the effect of unrealized gains or losses. Once these gains and losses are realized they are included in the per-unit amounts.
For the quarter ended December 31, 2013, the average effective royalty rate was 5.7% compared to 7.5% for the same quarter of 2012. The reduced royalty rate reflects additional drilling credits earned and recorded in the fourth quarter of 2013. In 2013 the Company continued 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.
For the year ended December 31, 2013, the average effective royalty rate was 7.3% compared to 6.7% for the same period of 2012. The average effective royalty rate increased in 2013 over 2012 mainly due to increased natural gas prices, and the impact of some wells reaching production maximums or coming off royalty holidays.
The Company expects an increase in its royalty rate for 2014 to approximately 10% as some wells will continue to reach production maximums and come off royalty holidays partially offset by new wells coming on stream receiving some royalty relief. The royalty rate is sensitive to commodity prices, and as such, a change in commodity prices will impact the actual rate.
The increase in other income in 2013 compared to 2012 can be attributed to higher processing income due to temporary excess capacity at the new Doe gas plant and a processing facility acquired in NEBC in late 2012, which was partially utilized in 2013 by a third party.
Operating expenses include all periodic lease and field-level expenses and exclude income recoveries from processing third-party volumes. For the fourth quarter of 2013, total operating expenses increased 63% from $21.6 million in the fourth quarter of 2012 to $35.2 million in 2013 due to the increased total costs relating to the growing production base. On a per-boe basis, the costs increased 8% from $4.10/boe for the fourth quarter of2012 to $4.44/boe in the fourth quarter of 2013. The higher costs per boe can be attributed to additional turnarounds which were incurred in the fourth quarter of 2013. Tourmaline’s operating expenses in the fourth quarter of 2013 include third-party processing, gathering and compression fees of approximately $8.7 million or $1.10/boe (December 31, 2012 – $5.7 million or $1.09/boe).
For the year ended December 31, 2013, total operating expenses were $118.7 million, or $4.35/boe, compared to $82.3 million, or $4.43/boe for the same period of 2012. Although total operating expenses increased with production, the cost per boe decreased 2% reflecting increased operational efficiencies. The Company’s operating expenses were $0.10 higher than expected on a per-boe basis due to slightly lower production than originally forecasted.
Third-party processing, gathering and compression fees for the year ended December 31, 2013, have increased year-over-year with production ($33.2 million in 2013 versus $21.7 million in 2012); the cost per boe has increased to $1.22/boe in 2013 versus $1.17/boe in 2012 due to the temporary use of higher cost third-party processing on certain volumes, as well as, increased oil and liquids production which is subject to higher processing fees.
During 2013, the Company commissioned a gas plant at Doe in NEBC, completed an expansion of the Spirit River battery in Alberta and two gas plant expansions at Wild River and Banshee in the Deep Basin. These projects allow for additional volumes to flow through Company owned-and-operated plants thereby reducing third-party charges on a go-forward basis.
The Company’s operating cost target is $4.15/boe in 2014. Actual costs per boe can change, however, depending on a number of factors, including the Company’s actual production levels.
Transportation costs for the three months ended December 31, 2013 were $17.9 million or $2.25/boe (three months ended December 31, 2012 – $9.8 million or $1.86/boe). Transportation costs for the year ended December 31, 2013 were $56.6 million or $2.07/boe (year ended December 31, 2012 – $34.7 million or $1.87/boe). The increase in total transportation costs for the three months and year ended December 31, 2013 can be primarily attributed to increased production.
On a per-boe basis, transportation costs for the three and twelve months ended December 31, 2013 are higher as a result of the increased use of more expensive transportation due to pipeline and infrastructure constraints.
GENERAL & ADMINISTRATIVE EXPENSES (“G&A”)
Total G&A expenses for the fourth quarter of 2013 were $5.4 million compared to $4.1 million for the same quarter of the prior year. G&A costs per boe for the fourth quarter of 2013 decreased 12% down to $0.68/boe, compared to $0.77/boe for the fourth quarter of 2012.
For the year ended December 31, 2013, total G&A expenses were $20.2 million or $0.74/boe compared to $14.6 million or $0.79/boe for the same period of 2012. The higher total G&A expenses in 2013 are directly attributable to managing a larger production, reserve and land base. The Company’s G&A expenses per boe continue to trend downward as Tourmaline’s production base continues to grow faster than its accompanying G&A costs.
G&A costs for 2014 are expected to be approximately $0.60/boe. The Company expects G&A costs per boe to continue to decrease as the production base grows. Actual costs per boe can change, however, depending on a number of factors including the Company’s actual production levels.
The Company uses the fair value method for the determination of non-cash related share-based payments expense. During the fourth quarter of 2013, 2,398,000 stock options were granted to employees, officers, directors and key consultants at a weighted-average exercise price of $40.77, and 763,694 options were exercised, bringing $8.7 million of cash into treasury. The Company recognized $5.8 million of share-based payment expense in the fourth quarter of 2013 compared to $3.9 million in the fourth quarter of 2012. Capitalized share-based payments for the fourth quarter of 2013 were $5.8 million compared to $3.9 million for the same quarter of the prior year.
For the year ended December 31, 2013, share-based payment expense totalled $19.3 million and a further $19.3 million in share-based payments were capitalized (2012 – $14.9 million and $14.9 million, respectively). The increase in share-based payment expense in 2013 compared to 2012 reflects the increased value attributed to the options and a higher number of options outstanding.
DEPLETION, DEPRECIATION AND AMORTIZATION (“DD&A”)
DD&A expense was $94.0 million for the fourth quarter of 2013 compared to $66.0 million for the same period of 2012 due to higher production volumes, as well as a larger capital asset base being depleted. The per-unit DD&A rate for the fourth quarter of 2013 was $11.86/boe compared to $12.53/boe for the same quarter of 2012.
For the year ended December 31, 2013, DD&A expense was $323.1 million (December 31, 2012 – $242.5 million) with a DD&A rate of $11.84/boe (December 31, 2012 – $13.04/boe). The lower DD&A rate for the quarter and year ended December 31, 2013 reflects strong reserve additions derived from Tourmaline’s exploration and production program.
Mineral lease expiries for the three months and year ended December 31, 2013 were $2.3 million and $33.1 million, respectively (December 31, 2012 – nil and nil, respectively). The increase in expiries is a result of mineral leases acquired via property and corporate acquisitions which were partially through their term at the date they were purchased, and have now begun to expire. The Company prioritizes drilling on what it believes to be the most cost-efficient and productive acreage, and with such a large land base, the Company has chosen to not continue some of the expiring sections of land. Tourmaline expects to continue to see mineral lease expiries
of a similar magnitude on a go-forward basis.
Finance expenses totalled $4.2 million and $15.4 million for the quarter and year ended December 31, 2013, respectively, and are comprised of interest expense, transaction costs on corporate and property acquisitions and accretion of decommissioning obligations (December 31, 2012 – $4.4 million and $13.0 million, respectively). The increased finance expenses in 2013 are largely due to higher interest expense resulting from a higher balance drawn on the credit facility. The average bank debt outstanding and the average effective interest rate on the debt during 2013 were $337.0 million and 3.0%, respectively (2012 – $245.4 million and 3.34%, respectively). In the fourth quarter of 2013, this increase in interest expense was offset by a decrease in transaction costs on corporate acquisitions, with the fourth quarter of 2012 having costs related to a corporate acquisition.
CASH FLOW FROM OPERATING ACTIVITIES, CASH FLOW AND NET EARNINGS
Cash flow for the three months ended December 31, 2013 was $160.7 million or $0.83 per diluted share compared to $93.8 million or $0.54 per diluted share for the same period of 2012. For the year ended December 31, 2013, cash flow was $526.8 million or $2.80 per diluted share, which is higher than the December 31, 2012 cash flow of $280.3 million or $1.68 per diluted share. The increase in cash flow in 2013 reflects increased production and higher natural gas prices.
The Company had after-tax earnings for the three months and year ended December 31, 2013 of $56.8 million ($0.29 per diluted share) and $148.1 million ($0.79 per diluted share), respectively, compared to earnings of $16.3 million ($0.09 per diluted share) and $15.5 million ($0.09 per diluted share), respectively, for the same periods of 2012. The significant increase is attributable to increased natural gas prices and production, as well as the $77.0 million in gains realized on the sale of certain non-core assets in Alberta and NEBC (December 31, 2012 – $7.6 million).
During the fourth quarter of 2013, the Company invested $497.9 million of cash consideration, net of dispositions, compared to $296.1 million for the same period of 2012. Expenditures on exploration and production were $411.8 million compared to $211.1 million for the same quarter of 2012, which is consistent with the Company’s aggressive growth strategy. The growth in facilities expenditures includes costs related to the expansion of the Wild River and Banshee gas facilities both of which were completed in late 2013. The Company also continued to add to its overall asset base through strategic property acquisitions during the third and fourth quarters of 2013.
During 2013 the Company invested $1,315.4 million of cash consideration, net of dispositions, compared to $741.6 million in 2012. Expenditures on exploration and production were $1,151.3 million compared to $654.2 million for 2012.
The following table summarizes the drill, complete and tie-in activities for the period:
Capital expenditures in 2014 are forecast to be $1.0 billion, which was revised upward from $900 million in the February 19, 2014 press release. Major planned 2014 facility projects include expansions at Musreau in Alberta and Doe in NEBC, and a new gas plant in Spirit River, Alberta (in late 2014).
LIQUIDITY AND CAPITAL RESOURCES
On March 12, 2013, the Company issued 5.78 million common shares at a price of $34.25 per share and 0.835 million flow-through common shares at a price of $42.15 per share, for total gross proceeds of $233.2 million. The proceeds were used to temporarily reduce bank debt and to fund the Company’s 2013 exploration and development program.
On October 8, 2013, the Company issued 3.495 million common shares at a price of $41.75 per share and 0.925 million flow-through common shares at a price of $51.60 per share, for total gross proceeds of $193.6 million. The proceeds were used to temporarily reduce bank debt and to fund the Company’s remaining 2013 and its upcoming 2014 exploration and development programs.
On February 12, 2014 the Company issued 4.615 million common shares at a price of $47.50 per share for total gross proceeds of $219.2 million. The proceeds will be used to temporarily reduce bank debt and to fund the Company’s upcoming 2014 exploration and development programs.
The Company has a covenant-based bank credit facility in place with a syndicate of bankers, the details of which are described in note 9 of the Company’s consolidated financial statements for the year ended December 31, 2013. In October 2013, the facility was increased to $900 million from $750 million, under the same terms and covenants, with an initial maturity of June 2016.
At December 31, 2013, Tourmaline had negative working capital of $242.6 million, after adjusting for the fair value of financial instruments (the unadjusted working capital deficiency was $245.3 million) (December 31, 2012 – $103.7 million and $98.9 million, respectively). Management believes the Company has sufficient liquidity and capital resources to fund the 2014 exploration and development program through expected cash flow from operations, its unutilized bank credit facility and the financings described above. As at December 31, 2013, the Company’s bank debt balance was $590.3 million (December 31, 2012 – $360.6 million), and net debt was $832.9 million (December 31, 2012 – $464.3 million).
SHARES AND STOCK OPTIONS OUTSTANDING
As at March 17, 2014, the Company has 195,138,903 common shares outstanding and 15,654,810 stock options granted and outstanding.
COMMITMENTS AND CONTRACTUAL OBLIGATIONS
In the normal course of business, Tourmaline is obligated to make future payments. These obligations represent contracts and other commitments that are known and non-cancellable.
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 consolidated financial statements for the year ended December 31, 2013.
As at December 31, 2013, the Company has entered into certain financial derivative contracts in order to manage commodity risk. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, even though the Company considers all commodity contracts to be effective economic hedges. Such financial derivative commodity contracts are recorded on the consolidated statement of financial position at fair value, with changes in the fair value being recognized as an unrealized gain or loss on the consolidated statement of income and comprehensive income. The contracts that the Company entered into in 2013 are detailed in note 5 of the Company’s consolidated financial statements for the year ended December 31, 2013.
The following table provides a summary of the unrealized gains and losses on financial instruments for the year ended December 31, 2013:
The Company has entered into physical contracts to manage commodity risk. These contracts are considered normal sales contracts and are not recorded at fair value in the consolidated financial statements. Physical contracts in place at December 31, 2013 have been disclosed in note 5 of the Company’s consolidated financial statements for the year ended December 31, 2013.
Financial derivative and physical delivery contracts entered into subsequent to December 31, 2013 are detailed in note 5 of the Company’s consolidated financial statements for the year ended December 31, 2013.
APPLICATION OF CRITICAL ACCOUNTING ESTIMATES
Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Management reviews its estimates on a regular basis. The emergence of new information and changed circumstances may result in actual results or changes to estimates that differ materially from current estimates. The Company’s use of estimates and judgments in preparing the consolidated financial statements is discussed in note 1 of the consolidated financial statements for the year ended December 31, 2013.
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING
The Company’s Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures (“DC&P”), as defined by National Instrument 52-109 – Certification of Disclosure in Issuers’ Annual and Interim Filings (“NI 52-109”), to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company’s Chief Executive Officer and Chief Financial Officer by others, particularly during the periods in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. All control systems by their nature have inherent limitations and, therefore, the Company’s DC&P are believed to provide reasonable, but not absolute, assurance that the objectives of the control systems are met.
The Company’s Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal controls over financial reporting (“ICFR”), as defined by NI 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 GAAP.
The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company’s DC&P and ICFR. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as at December 31, 2013, the Company’s DC&P and ICFR are effective. There were no changes in the Company’s DC&P or ICFR during the period beginning on October 1, 2013 and ending December 31, 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s DC&P or 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 design and assessment of the Company’s DC&P and ICFR were based on the framework in ‘Internal Control – Integrated Framework (1992)’ issued by the Committee of Sponsoring Organizations of the Treadway Commission.
BUSINESS RISKS AND UNCERTAINTIES
Tourmaline monitors and complies with current government regulations that affect its activities, although operations may be adversely affected by changes in government policy, regulations or taxation. In addition, Tourmaline maintains a level of liability, property and business interruption insurance which is believed to be adequate for Tourmaline’s size and activities, but is unable to obtain insurance to cover all risks within the business or in amounts to cover all possible claims.
See “Forward-Looking Statements” in this MD&A and “Risk Factors” in Tourmaline’s most recent annual information form for additional information regarding the risks to which Tourmaline and its business and operations are subject.
IMPACT OF NEW ENVIRONMENTAL REGULATIONS
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.
CHANGES IN ACCOUNTING POLICIES
The following new accounting standards and amendments to existing standards, as issued by the International Accounting Standards Board (“IASB”), have been adopted by the Company effective January 1, 2013.
IFRS 9 – Financial instruments addresses the classification and measurement of financial assets.
IFRS 10 – Consolidated Financial Statements builds on existing principles and standards and identifies the concept of control as the determining factor in whether and entity should be included within the consolidated financial statements of the parent company.
IFRS 11 – Joint Arrangements establishes the principles for financial reporting by entities when they have an interest in arrangements that are jointly controlled.
IFRS 12 – Disclosure of Interest in Other Entities provides the disclosure requirements for interests held in other entities including joint arrangements, associates, special purpose entities and other off balance sheet entities.
IFRS 13 – Fair Value Measurement defines fair value, requires disclosure about fair value measurements and provides a framework for measuring fair value when it is required or permitted within the IFRS standards.
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 generally the indebtedness, liabilities and obligations of the Company to thelenders under the credit facility and certain other secured indebtedness, liabilities and obligations of the Company (“bank debt”), “total debt” means generally bank debt plus any other indebtedness of the Company, and “total capitalization” means generally the sum of the Company’s shareholders’ equity and all other indebtedness of the Company including bank debt, all determined on a consolidated basis in accordance with GAAP.
A summary of the reconciliation of cash flow from operating activities (per the statement of cash flow), to cash flow, is set forth below:
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:
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:
A summary of the reconciliation of net debt is set forth below:
SELECTED QUARTERLY INFORMATION
The oil and gas exploration and production industry is cyclical in nature. The Company’s financial position, results of operations and cash flows are principally impacted by production levels and commodity prices, particularly natural gas prices.
Overall, the Company has had continued annual growth over the last two years summarized in the table above. The small decrease in production from the second quarter to the third quarter of 2012 was due to weather-related tie-in delays, as well as production disruptions related to sour gas handling issues at Spirit River and a one-time equipment issue at Sunrise. The Company’s average annual production has increased from 50,804 boe per day in 2012 to 74,796 boe per day in 2013. The production growth can be attributed primarily to the Company’s exploration and development activities, as well as from acquisitions of producing properties.
The Company’s cash flows from operating activities were $273.5 million in 2012 and $479.2 million in 2013. Cash flows have increased with higher production and strengthening natural gas prices in 2013 over 2012. Commodity price changes can indirectly impact expected production by changing the amount of funds available to reinvest in exploration, development and acquisition activities in the future. Decreases in commodity prices not only reduce revenues and cash flows available for exploration, they may also challenge the economics of potential capital projects by reducing the quantities of reserves that are commercially recoverable. The Company’s capital program is dependent on cash flows generated from operations and access to capital markets.
SELECTED ANNUAL INFORMATION
The changes to the financial information summarized above are due primarily to the continuing growth in the Company’s crude oil, natural gas and NGL production over the periods, from the Company’s exploration and development activities and from the acquisition of producing properties.
To the Shareholders of Tourmaline Oil Corp.:
The accompanying consolidated financial statements of Tourmaline Oil Corp. and all the information in the
Annual Report are the responsibility of management and have been approved by the Board of Directors. The
financial statements have been prepared by management in accordance with International Financial Reporting
Standards as issued by the International Accounting Standards Board. When alternative accounting methods
exist, management has chosen those it deems most appropriate in the circumstances. Financial statements are
not precise since they include certain amounts based on estimates and judgments. Management has determined
such amounts on a reasonable basis in order to ensure that the financial statements are presented fairly, in all
material respects. The financial information contained elsewhere in this report has been reviewed to ensure
consistency with the financial statements.
Management has established systems of internal controls, which are designed to provide reasonable assurance
that assets are safeguarded from loss or unauthorized use and to produce reliable accounting records for the
preparation of financial information. The Board of Directors is responsible for ensuring that management fulfills
its responsibilities for financial reporting and internal control. It exercises its responsibilities primarily through the
Audit Committee, with some assistance from the Reserves Committee regarding the annual evaluation of the
Company’s petroleum and natural gas reserves. The Audit Committee has reviewed the financial statements with
management and the auditors, and has reported to the Board of Directors. The external auditors have access to
the Audit Committee without the presence of management.
The financial statements have been audited on behalf of the shareholders by KPMG LLP, the external auditors.
Their examination included such tests and procedures, as they considered necessary, to provide reasonable
assurance that the consolidated financial statements are presented fairly in accordance with International
Financial Reporting Standards. The Board of Directors has approved the financial statements.
Michael L. Rose Brian G. Robinson
President and Vice-President, Finance and
Chief Executive Officer Chief Financial Officer
Calgary, Alberta Calgary, Alberta
March 17, 2014
To the Shareholders of Tourmaline Oil Corp.:
We have audited the accompanying consolidated financial statements of Tourmaline Oil Corp., which comprise the consolidated statements of financial position as at December 31, 2013 and December 31, 2012 and the consolidated statements of income and comprehensive income, changes in equity and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.
In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Tourmaline Oil Corp. as at December 31, 2013 and December 31, 2012 and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards.
March 17, 2014
CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
CONSOLIDATED STATEMENTS OF CASH FLOW
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2013 and 2012
(tabular amounts in thousands of dollars, unless otherwise noted)
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 and conducts many of its activities jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities.
The Company’s registered office is located at Suite 2400, 525 – 8th Avenue S.W., Calgary, Alberta, Canada T2P 1G1.
1. BASIS OF PREPARATION
(a) Statement of compliance:
These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).
Certain prior year amounts have been reclassified for consistency with the current period presentation. These reclassifications had no effect on the reported results of operations.
The consolidated financial statements were authorized for issue by the Board of Directors on March 17, 2014.
(b) Basis of measurement:
The consolidated financial statements have been prepared on the historical-cost basis except for the following:
(i) derivative financial instruments are measured at fair value; and
(ii) held for trading financial assets are measured at fair value with changes in fair value recorded in earnings.
The methods used to measure fair values are discussed in note 4.
Operating expenses in the consolidated statements of income and comprehensive income are presented as a combination of function and nature in conformity with industry practice. Depletion, depreciation and amortization are presented in separate lines by their nature, while operating expenses and net administrative expenses are presented on a functional basis. Significant expenses such as salaries and benefits are presented by their nature in the notes to the financial statements.
(c) Functional and presentation currency:
These consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency
(d) Use of estimates and judgments:
The timely preparation of the financial statements requires management to make judgments, estimates and
assumptions that affect the application of accounting policies and reported amounts of assets and liabilities and
income and expenses. Accordingly, actual results may differ from these estimates. Estimates and underlying
assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period
in which the estimates are revised and in any future periods affected. Significant estimates and judgments made
by management in the preparation of these financial statements are outlined below.
Critical judgments in applying accounting policies:
The following are the critical judgments, apart from those involving estimations (see below), that management
has made in the process of applying the Company’s accounting policies and that have the most significant effect
on the amounts recognized in these consolidated financial statements:
(i) Identification of cash-generating units:
The Company’s assets are aggregated into cash-generating units (“CGU”) for the purpose of calculating
impairment. A CGU is comprised of assets that are grouped together into the smallest group of assets that
generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or
groups of assets. By their nature, these estimates and assumptions are subject to measurement uncertainty and
may impact the carrying value of the Company’s assets in future periods.
(ii) Impairment of petroleum and natural gas assets:
Judgements are required to assess when impairment indicators exist and impairment testing is required. For the
purposes of determining whether impairment of petroleum and natural gas assets has occurred, and the extent of
any impairment or its reversal, the key assumptions the Company uses in estimating future cash flows are
forecasted petroleum and natural gas prices, expected production volumes and anticipated recoverable
quantities of proved and probable reserves. These assumptions are subject to change as new information
becomes available. Changes in economic conditions can also affect the rate used to discount future cash flow
estimates. Changes in the aforementioned assumptions could affect the carrying amounts of assets. Impairment
charges and reversals are recognized in profit or loss.
(iii) Deferred taxes:
Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be
recoverable. This involves an assessment of when those deferred tax assets are likely to reverse and a judgment
as to whether or not there will be sufficient taxable profits available to offset the tax assets when they do reverse.
This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent
assumptions regarding future profitability change, there can be an increase or decrease in the amounts
recognized in respect of deferred tax assets as well as the amounts recognized in profit or loss in the period in
which the change occurs.
Key sources of estimation uncertainty:
The following are the key assumptions concerning the sources of estimation uncertainty at the end of the
reporting period, that have a significant risk of causing adjustments to the carrying amounts of assets and
Estimation of reported recoverable quantities of proved and probable reserves include judgmental assumptions
regarding production profile, commodity prices, exchange rates, remediation costs, timing and amount of future
development costs, and production, transportation and marketing costs for future cash flows. It also requires
interpretation of geological and geophysical models in anticipated recoveries. The economical, geological and
technical factors used to estimate reserves may change from period to period. Changes in reported reserves can
impact the carrying values of the Company’s petroleum and natural gas properties and equipment, the
calculation of depletion and depreciation, the provision for decommissioning obligations, and the recognition of
deferred tax assets due to changes in expected future cash flows. The recoverable quantities of reserves and
estimated cash flows from the Company’s petroleum and natural gas interests are independently evaluated by
reserve engineers at least annually.
The Company’s petroleum and natural gas reserves represent the estimated quantities of petroleum, natural gas
and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree
of certainty to be economically recoverable in future years from known reservoirs and which are considered
commercially producible. Such reserves may be considered commercially producible if management has the
intention of developing and producing them and such intention is based upon (i) a reasonable assessment of the
future economics of such production; (ii) a reasonable expectation that there is a market for all or substantially all
of the expected petroleum and natural gas production; and (iii) evidence that the necessary production,
transmission and transportation facilities are available or can be made available. Reserves may only be
considered proven and probable if producibility is supported by either production or conclusive formation tests.
The Company’s petroleum and gas reserves are determined pursuant to National Instrument 51-101, Standard of
Disclosures for Oil and Gas Activities.
(ii) Share-based payments:
All equity-settled, share-based awards issued by the Company are recorded at fair value using the Black-Scholes
option-pricing model. In assessing the fair value of equity-based compensation, estimates have to be made
regarding the expected volatility in share price, option life, dividend yield, risk-free rate and estimated forfeitures
at the initial grant date.
(iii) Decommissioning obligations:
The Company estimates future remediation costs of production facilities, wells and pipelines at different stages of
development and construction of assets or facilities. In most instances, removal of assets occurs many years into
the future. This requires judgment regarding abandonment date, future environmental and regulatory legislation,
the extent of reclamation activities, the engineering methodology for estimating cost, future removal technologies
in determining the removal cost and liability-specific discount rates to determine the present value of these cash
(iv) Deferred taxes:
Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts
recognized in profit or loss both in the period of change, which would include any impact on cumulative
provisions, and in future periods.
2. SIGNIFICANT ACCOUNTING POLICIES
The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements, and have been applied consistently by the Company and its subsidiaries.
The consolidated financial statements include the accounts of Tourmaline Oil Corp. and Exshaw Oil Corp., of which the Company owns 90.6% (note 10).
Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. In assessing control, substantive potential voting rights that currently are exercisable are taken into account. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases.
(ii) Transactions eliminated on consolidation:
Intercompany balances and transactions, and any unrealized income and expenses arising from inter-company transactions, are eliminated in preparing the consolidated financial statements.
(iii) Jointly-controlled operations and jointly-controlled assets:
Substantially all of the Company’s oil and natural gas activities involve jointly-controlled assets. The consolidated financial statements include the Company’s share of these jointly-controlled assets and a proportionate share of the relevant revenue and related costs.
(b) Business Combinations:
The purchase method of accounting is used to account for acquisitions of subsidiaries and assets that meet the definition of a business under IFRS. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. If the cost of acquisition is less than the fair value of the net assets of the subsidiary acquired, the difference is recognized immediately in the income statement. Acquisition costs incurred are expensed.
(c) Financial instruments:
(i) Non-derivative financial instruments:
Non-derivative financial instruments comprise accounts receivable, cash and cash equivalents, investments, bank overdrafts, bank debt, and accounts payable and accrued liabilities. Non-derivative financial instruments are recognized initially at fair value plus, for instruments not at fair value through profit or loss, any directly attributable transaction costs. Subsequent to initial recognition, non-derivative financial instruments are measured as described below:
Cash and cash equivalents:
Cash and cash equivalents comprise cash on hand, term deposits held with banks, other short-term highly-liquid investments with original maturities of three months or less, and are measured similar to other nonderivative financial instruments.
An instrument is classified at fair value through profit or loss if it is held for trading or is designated as such upon initial recognition. Tourmaline’s investments in public companies are designated as held for trading. Financial instruments are designated at fair value through profit or loss if the Company manages such investments and makes purchase and sale decisions based on their fair value in accordance with the Company’s risk management or investment strategy. Upon initial recognition, attributable transaction costs are recognized in profit or loss when incurred. Financial instruments at fair value through profit or loss are measured at fair value, and changes therein are recognized in profit or loss.
Other non-derivative financial instruments, such as accounts receivable, bank debt, and accounts payable and accrued liabilities, are measured at amortized cost using the effective interest method, less any impairment losses. The bank debt has a floating rate of interest and therefore the carrying value approximates the fair value.
(ii) Derivative financial instruments:
The Company has entered into certain financial derivative contracts in order to manage the exposure to market risks from fluctuations in commodity prices and interest rates. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, and thus not applied hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, all financial derivative contracts are classified as fair value through profit or loss and are recorded on the statement of financial position at fair value. Transaction costs are recognized in profit or loss when incurred.
The Company has accounted for its forward physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the statement of financial position. Settlements on these physical sales contracts are recognized in oil and natural gas revenue.
Embedded derivatives are separated from the host contract and accounted for separately if the economic characteristics and risks of the host contract and the embedded derivative are not closely related, a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative, and the combined instrument is not measured at fair value through earnings. Changes in the fair value of separable embedded derivatives are recognized immediately in earnings.
(iii) Share capital:
Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares and share options are recognized as a deduction from equity, net of any tax effects.
(d) Property, plant and equipment and intangible exploration assets:
(i) Recognition and measurement:
Exploration and evaluation expenditures:
Pre-license costs are recognized in the statement of operations as incurred.
Exploration and evaluation costs, including the costs of acquiring licenses and directly attributable general and administrative costs, initially are capitalized as either tangible or intangible exploration and evaluation assets according to the nature of the assets acquired. The costs are accumulated in cost centers by well, field or exploration area pending determination of technical feasibility and commercial viability.
Exploration and evaluation assets are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial viability, and (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For purposes of impairment testing, exploration and evaluation assets are allocated to cash-generating units.
The technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable when proven and/or probable reserves are determined to exist. A review of each exploration licence or field is carried out, at least annually, to ascertain whether proven or probable reserves have been discovered. Upon determination of proven and/or probable reserves, intangible exploration and evaluation assets attributable to those reserves are first tested for impairment and then reclassified from exploration and evaluation assets to a separate category within tangible assets referred to as oil and natural gas interests. The cost of undeveloped land that expires or any impairment recognized during a period is charged as additional depletion and depreciation expense.
Development and production costs:
Items of property, plant and equipment, which include oil and gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses. Development and production assets are grouped into CGUs for impairment testing. The Company allocated its property, plant and equipment to the following CGUs: ‘Deep Basin’, ‘Spirit River’ and ‘BC Montney’. When significant parts of an item of property, plant and equipment, including oil and natural gas interests, have different useful lives, they are accounted for as separate items (major components).
Gains and losses on disposal of an item of property, plant and equipment, including oil and natural gas interests, are measured as the difference between the fair value of the proceeds received or given up and the carrying value of the assets disposed, and are recognized in profit or loss.
(ii) Subsequent costs:
Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property, plant and equipment are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized oil and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred.
(iii) Depletion and depreciation:
The net carrying value of development or production assets is depleted using the unit-of-production method by reference to the ratio of production in the year to the related proved-plus-probable reserves, taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually.
Proved-plus-probable reserves are estimated annually by independent qualified reserve evaluators and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. For interim consolidated financial statements, internal estimates of changes in reserves and future development costs are used for determining depletion for the period.
For other assets, depreciation is recognized in profit or loss on a straight-line basis over the estimated useful lives of each part of an item of property, plant and equipment. Leased assets are depreciated over the shorter of the lease term and their useful lives unless it is reasonably certain that the Company will obtain ownership by the end of the lease term. Land is not depreciated.
The estimated useful lives for depreciable assets are as follows:
Depreciation methods, useful lives and residual values are reviewed at each reporting date.
(i) Financial assets:
A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.
An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate.
Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.
All impairment losses are recognized in profit or loss.
An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost, the reversal is recognized in profit or loss.
(ii) Non-financial assets:
The carrying amounts of the Company’s non-financial assets, other than E&E assets and deferred tax assets, are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset’s recoverable amount is estimated. For goodwill and other intangible assets that have indefinite lives, or that are not yet available for use, an impairment test is completed each year. E&E assets are assessed for impairment when they are reclassified to property, plant and equipment, as oil and natural gas interests, and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For the purpose of impairment testing, assets are grouped into CGUs. The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell.
In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value in use is generally computed by reference to the present value of the future cash flows expected to be derived from production of proven-plus-probable reserves. Fair value less costs to sell is determined as the amount that would be obtained from the sale of an asset in an arm’s length transaction between knowledgeable and willing parties.
The goodwill acquired in an acquisition, for the purpose of impairment testing, is allocated to the CGUs that are expected to benefit from the synergies of the combination. E&E assets are allocated to the related CGUs when they are assessed for impairment, both at the time of triggering facts and circumstances as well as upon their eventual reclassification to property, plant and equipment.
An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the assets in the unit (group of units) on a pro-rata basis. Impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized.
A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax “riskfree” rate that reflects current market assessments of the time value of money. Provisions are not recognized for future operating losses.
(i) Decommissioning obligations:
The Company recognizes the decommissioning obligations for the future costs associated with removal, site restoration and decommissioning costs. The fair value of the liability for the Company’s decommissioning obligation is recorded in the period in which it is incurred, discounted to its present value using the risk-free interest rate and the corresponding amount recognized by increasing the carrying amount of petroleum and natural gas assets. The asset recorded is depleted on a unit-of-production basis over the life of the reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost could also result in an increase or decrease to the obligation. Actual costs incurred upon settlement of the decommissioning obligation are charged against the obligation to the extent of the liability recorded.
(ii) Onerous contracts:
A provision for onerous contracts is recognized when the expected benefits to be derived by the Company from a contract are lower than the unavoidable cost of meeting its obligations under the contract. The provision is measured at the present value of the lower of the expected cost of terminating the contract and the expected net cost of continuing with the contract. Before a provision is established, the Company recognizes any impairment loss on associated assets.
(g) Revenue recognition:
Revenue from the sale of oil and natural gas is recorded when the significant risks and rewards of ownership of the product is transferred to the buyer, which is usually when legal title passes to the external party. This is generally at the time product enters the pipeline. Revenue is measured net of discounts, customs duties and royalties. With respect to the latter, the entity is acting as a collection agent on behalf of others. Tariffs and tolls charged to other entities for use of pipelines and facilities owned by the Company are recognized as revenue as they accrue in accordance with the terms of the service or tariff and tolling agreements. Royalty income is recognized as it accrues in accordance with the terms of the overriding royalty agreements.
(h) Finance income and expenses:
Finance expense comprises interest expense on borrowings, accretion of the discount on provisions, transaction costs on business combinations and impairment losses recognized on financial assets.
Interest income is recognized as it accrues in profit or loss, using the effective-interest method.
(i) Deferred taxes:
Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.
Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.
Deferred tax is recognized on the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred-tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.
A deferred-tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred-tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.
(j) Flow-through common shares:
Periodically, the Company finances a portion of its exploration and development activities through the issuance of flow-through shares. The resource expenditure deductions for income tax purposes related to exploratory development activities are renounced to investors in accordance with tax legislation. Flow-through shares issued are recorded in share capital at the fair value of common shares on the date of issue. The premium received on issuing flow-through shares is initially recorded as a deferred liability. As qualifying expenditures are incurred, the premium is reversed and a deferred income tax liability is recorded. The net amount is then recognized as deferred income tax expense.
(k) Share-based payments:
The Company applies the fair-value method for valuing share option grants. Under this method, compensation cost attributable to all share options granted are measured at fair value at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options or units that vest. Upon the exercise of the share options, consideration received, together with the amount previously recognized in contributed surplus, is recorded as an increase to share capital.
(l) Per-share information:
Basic per-share information is computed by dividing income by the weighted average number of common shares outstanding for the period. The treasury-stock method is used to determine the diluted per share amounts, whereby any proceeds from the share options, warrants or other dilutive instruments are assumed to be used to purchase common shares at the average market price during the period. The weighted average number of shares outstanding is then adjusted by the net change.
(m) Leased assets:
Leases where the Company assumes substantially all the risks and rewards of ownership are classified as finance leases. Upon initial recognition, the leased asset is measured at an amount equal to the lower of its fair value and the present value of the minimum lease payments. Subsequent to initial recognition, the asset is accounted for in accordance with the accounting policy applicable to that asset.
Minimum lease payments made under finance leases are apportioned between the finance expenses and the reduction of the outstanding liability. The finance expenses are allocated to each year during the lease term so as to produce a constant periodic rate of interest on the remaining balance of the liability.
Other leases are operating leases, which are not recognized on the Company’s statement of financial position.
3. ACCOUNTING CHANGES
(a) Changes in Accounting Policies:
The following new accounting standards and amendments to existing standards, as issued by the International
Accounting Standards Board (“IASB”), have been adopted by the Company effective January 1, 2013:
IFRS 9 – Financial Instruments addresses the classification and measurement of financial assets.
IFRS 10 – Consolidated Financial Statements builds on existing principles and standards and identifies the concept of control as the determining factor in whether an entity should be included within the consolidated financial statements of the parent company.
IFRS 11 – Joint Arrangements establishes the principles for financial reporting by entities when they have an interest in arrangements that are jointly controlled.
IFRS 12 – Disclosure of Interest in Other Entities provides the disclosure requirements for interests held in other entities including joint arrangements, associates, special purpose entities and other off balance sheet entities.
IFRS 13 – Fair Value Measurement defines fair value, requires disclosure about fair value measurements and provides a framework for measuring fair value when it is required or permitted within the IFRS standards.
4. 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.
(i) Property, plant and equipment and intangible exploration assets:
The fair value of property, plant and equipment recognized in a business combination, is based on market values. The market value of property, plant and equipment is the estimated amount for which property, plant and equipment could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm’s-length transaction after proper marketing wherein the parties had each acted knowledgeably, prudently and without compulsion. The market value of oil and natural gas interests (included in property, plant and equipment) and intangible exploration assets is estimated with reference to the discounted cash flow expected to be derived from oil and natural gas production based on externally prepared reserve reports. The risk-adjusted discount rate is specific to the asset with reference to general market conditions.
The market value of other items of property, plant and equipment is based on the quoted market prices for similar items.
(ii) Cash and cash equivalents, accounts receivable, bank debt and accounts payable and accrued liabilities:
The fair value of cash and cash equivalents, accounts receivable, bank debt and accounts payable and accrued liabilities is estimated as the present value of future cash flow, discounted at the market rate of interest at the reporting date. At December 31, 2013 and December 31, 2012, the fair value of these balances approximated their carrying value due to their short term to maturity. The bank debt has a floating rate of interest and therefore the carrying value approximates the fair value.
The fair value of commodity price risk management contracts is determined by discounting the difference between the contracted prices and published forward price curves as at the statement of financial position date, using the remaining contracted oil and natural gas volumes and a risk-free interest rate (based on published government rates). The fair value of options and costless collars is based on option models that use published information with respect to volatility, prices and interest rates.
(iv) Share options:
The fair value of employee share options is measured using a Black-Scholes option-pricing model. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility (based on weighted average historic volatility adjusted for changes expected due to publicly available information), weighted average expected life of the instruments (based on historical experience and general option holder behaviour), expected dividends, and the risk-free interest rate (based on government bonds).
Tourmaline classifies the fair value of these 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 following tables provide fair value measurement information for financial assets and liabilities as of December 31, 2013 and December 31, 2012. The carrying value of cash and cash equivalents, trade and other receivables and trade and other payables included in the consolidated statement of financial position approximate fair value due to the short-term nature of those instruments. These assets and liabilities are not included in the following tables.
5. 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.
(a) Credit risk:
Credit risk is the risk of financial loss to the Company if a customer or counter-party to a financial instrument fails to meet its contractual obligations, and arises principally from the Company’s receivables from joint venture partners and petroleum and natural gas marketers. As at December 31, 2013, Tourmaline’s receivables consisted of $19.5 million (December 31, 2012 – $22.7 million) from joint venture partners, $99.9 million (December 31, 2012 – $52.8 million) from petroleum and natural gas marketers and $16.6 million (December 31, 2012 – $8.4 million) from provincial governments.
Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the month following production. The Company sells a significant portion of its oil and gas to a limited number of counter-parties. In 2013, Tourmaline had three counter-parties that individually accounted for more than ten percent of annual revenues. The Company’s policy to mitigate credit risk associated with these balances is to establish marketing relationships with creditworthy purchasers. Tourmaline historically has not experienced any collection issues with its petroleum and natural gas marketers. Joint venture receivables are typically collected within one to three months of the joint venture bill being issued to the partner. The Company attempts to mitigate the risk from joint venture receivables by obtaining partner approval of significant capital expenditures prior to expenditure. The receivables, however, are from participants in the petroleum and natural gas sector, and collection of the outstanding balances are dependent on industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessful drilling. In addition, further risk exists with joint venture partners as disagreements occasionally arise that increase the potential for non-collection. The Company does not typically obtain collateral from petroleum and natural gas marketers or joint venture partners; however, the Company does have the ability to withhold production from joint venture partners in the event of non-payment.
The Company monitors the age of, and investigates issues behind, its receivables that have been past due for over 90 days. At December 31, 2013, the Company had $0.8 million (December 31, 2012 – $1.1 million) over 90 days. The Company is satisfied that these amounts are substantially collectible.
The carrying amount of accounts receivable, cash and cash equivalents and commodity price risk management contracts represents the maximum credit exposure. The Company does not have an allowance for doubtful accounts as at December 31, 2013 (December 31, 2012 – nil) and did not provide for any doubtful accounts nor was it required to write-off any receivables during the year ended December 31, 2013 (December 31, 2012 – nil).
(b) Liquidity risk:
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they come due. The Company’s approach to managing liquidity is to ensure that it will have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions without incurring unacceptable losses or risking harm to the Company’s reputation. Liquidity risk is mitigated by cash on hand, when available, and access to credit facilities.
The Company’s accounts payable and accrued liabilities balance at December 31, 2013 is approximately $385.6 million (December 31, 2012 – $225.9 million). It is the Company’s policy to pay suppliers within 45-75 days. These terms are consistent with industry practice. As at December 31, 2013, substantially all of the account balances were less than 90 days.
The Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. Further, the Company utilizes authorizations for expenditures on both operated and non-operated projects to further manage capital expenditures. The Company also attempts to match its payment cycle with collection of petroleum and natural gas revenues on the 25th of each month.
The following are the contractual maturities of financial liabilities, including estimated interest payments, at December 31, 2013:
(c) Market risk:
Market risk is the risk that changes in market conditions, such as commodity prices, interest rates and foreign exchange rates will affect the Company’s net income or value of financial instruments. The objective of market risk management is to manage and curtail market risk exposure within acceptable limits, while maximizing the Company’s returns.
The Company utilizes both financial derivatives and physical delivery sales contracts to manage market risks. All such transactions are conducted in accordance with the risk management policy that has been approved by the Board of Directors.
Currency risk has minimal impact on the value of the financial assets and liabilities on the consolidated statement of financial position at December 31, 2013. Changes in the US to Canadian exchange rate, however, could influence future petroleum and natural gas prices which could impact the value of certain derivative contracts. This influence cannot be accurately quantified.
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company is exposed to interest rate risk to the extent that changes in market interest rates will impact the Company’s bank debt which is subject to a floating interest rate. Assuming all other variables remain constant, an increase or decrease of 1% in market interest rates for the year ended December 31, 2013 would have decreased or increased shareholders’ equity and net income by $2.5 million (December 31, 2012 – $1.8 million). The unrealized loss on the interest rate swap has been included on the consolidated statement of financial position with changes in the fair value included in the unrealized gain or loss on financial instruments on the consolidated statement of income and comprehensive income.
Commodity price risk is the risk that the fair value or future cash flow will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted by not only the relationship between the Canadian and United States dollar, but also world economic events that dictate the levels of supply and demand. As at December 31, 2013, the Company has entered into certain financial derivative and physical delivery sales contracts in order to manage commodity risk. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, even though the Company considers all commodity contracts to be effective economic hedges. As a result, all such commodity contracts are recorded on the 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 Company has not offset any financial assets and liabilities, in the consolidated statements of financial position.
The Company has the following financial derivative contracts in place as at December 31, 2013 (1):
The Company has entered into four interest rate swap arrangements:
The following table provides a summary of the unrealized gains and losses on financial instruments for the years ended December 31, 2013 and 2012:
As at December 31, 2013, if the future strip prices for oil were $1.00 per bbl higher and prices for natural gas were $0.10 per mcf higher, with all other variables held constant, after-tax earnings would have been $3.8 million (December 31, 2012 – $1.3 million) lower. An equal and opposite impact would have occurred to after-tax earnings if oil prices were $1.00 per bbl lower and gas prices were $0.10 per mcf lower. In addition to the financial commodity contracts discussed above, the Company has entered into physical contracts to manage commodity risk. These contracts are considered normal sales contracts and are not recorded at fair value in the consolidated financial statements.
The Company has the following physical contracts in place at December 31, 2013(1):
(d) Capital management:
The Company’s policy is to maintain a strong capital base to maintain investor, creditor and market confidence and to sustain the future development of the business. The Company considers its capital structure to include shareholders’ equity, bank debt and working capital. In order to maintain or adjust the capital structure, the Company may from time to time issue shares and adjust its capital spending to manage current and projected debt levels. The annual and updated budgets are approved by the Board of Directors.
The key measure that the Company utilizes in evaluating its capital structure is net debt to annualized cash flow, which is defined as long-term bank debt plus working capital (adjusted for the fair value of financial instruments), to annualized cash flow (based on the most recent quarter), defined as cash flow from operating activities before changes in non-cash working capital. Net debt to annualized cash flow represents a measure of the time it is expected to take to pay off the debt if no further capital expenditures were incurred and if cash flow in the next year were equal to the amount in the most recent quarter annualized.
The Company monitors this ratio and endeavours to maintain it at, or below, 2.0 to 1.0 in a normalized commodity price environment. This ratio may increase at certain times as a result of acquisitions or low commodity prices. As shown below, as at December 31, 2013, the Company’s ratio of net debt to annualized cash flow was 1.3 to 1.0 (December 31, 2012 – 1.24 to 1.0).
6. EXPLORATION AND EVALUATION ASSETS
Exploration and evaluation (“E&E”) assets consist of the Company’s exploration projects which are pending the determination of proven and/or probable reserves. Additions represent the Company’s share of costs on E&E assets during the year.
General and administrative expenditures for the year ended December 31, 2013 of $3.9 million (December 31, 2012 – $5.2 million) have been capitalized and included as exploration and evaluation assets. Non-cash share-based payment expense in the amount of $3.8 million (December 31, 2012, $5.8 million) were also capitalized and included in exploration and evaluation assets. Expired mineral lease expenses have been included in the “Depletion, depreciation and amortization” line item on the consolidated statements of income and comprehensive income.
7. PROPERTY, PLANT AND EQUIPMENT
General and administrative expenditures for the year ended December 31, 2013 of $11.1 million (December 31, 2012 – $6.1 million) have been capitalized and included as costs of oil and natural gas properties. Also included in oil and natural gas properties is non-cash share-based payment expense of $15.5 million (December 31, 2012 – $9.1 million).
Future development costs for the year ended December 31, 2013 of $3,197 million (December 31, 2012 – $2,233 million) were included in the depletion calculation.
The Company has performed an impairment assessment of its property, plant, and equipment on a CGU basis
and has determined that there are no indicators of impairment at December 31, 2013; therefore an impairment
test was not performed. For the year ended December 31, 2012 the Company identified impairment triggers due
to weak natural gas prices. The Company tested for and did not identify any impairment.
Huron Energy Corporation
On November 30, 2012, the Company acquired all of the issued and outstanding shares of Huron Energy Corporation (“Huron”). As consideration, the Company issued 7,401,682 common shares at a price of $33.02 per share. Total transaction costs incurred by the Company of $1.0 million associated with this acquisition were expensed in the consolidated statement of income and comprehensive income.
The acquisition of Huron provided for an increase in lands and production in Tourmaline’s core and designated growth area of Sunrise, NEBC.
Results from operations for Huron are included in the Company’s consolidated financial statements from the closing date of the transaction. The value attributed to the property, plant and equipment acquired was supported by an engineering report prepared as at August 31, 2012 by independent reserve engineers using proved plus probable reserves discounted at a rate of 10% and updated internally to the date of the corporate acquisition of November 30, 2012. The allocation of net assets acquired is based on the best available information at the time and could be subject to further change. The acquisition has been accounted for using the purchase method based on estimated fair values as follows:
Included in the consolidated statements of income and comprehensive income for the year ended December 31, 2012 are the following amounts relating to Huron Energy Corporation since November 30, 2012:
Acquisition of Oil and Natural Gas Properties
For the year ended December 31, 2013, the Company completed property acquisitions for total cash consideration of $226.9 million (December 31, 2012 – $88.6 million) and an additional $88.6 million in non-cash consideration (December 31, 2012 – $5.3 million). The Company also assumed $7.3 million in decommissioning liabilities (December 31, 2012 – $4.2 million).
8. 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 $118.9 million (December 31, 2012 – $92.7 million), with some abandonments expected to commence in 2021. A risk-free rate of 3.24% (December 31, 2012 – 2.49%) and an inflation rate of 2.0% (December 31, 2012 – 2.0%) were used to calculate the fair value of the decommissioning obligations. The decommissioning obligations at December 31, 2013 have been adjusted by approximately $5.1 million due to changes in estimates during the year (December 31, 2012 – nil).
9. BANK DEBT
The Company has a covenant-based bank credit facility in place with a syndicate of bankers. This facility is a three-year extendible revolving facility in the amount of $875 million plus a $25 million operating revolver with an initial maturity date of June 2016. The maturity date may, at the request of the Company and with the consent of the lenders, be extended on an annual basis. The facility is secured by a first ranking floating charge over all assets of the Company and its material subsidiaries. The facility can be drawn in either Canadian or U.S. funds and bears interest at the bank’s prime lending rate, bankers’ acceptance rates or LIBOR (for U.S. borrowings), plus applicable margins, which range from 2.00 to 4.00 percent over bankers’ acceptance rates depending on the Company’s senior debt to adjusted EBITDA ratio.
Under the terms of the bank credit facility, Tourmaline has provided its covenant that, on a rolling four quarter basis: (i) the ratio of adjusted EBITDA to interest expense shall equal or exceed 3.5:1, (ii) the ratio of senior debt to adjusted EBITDA shall not exceed 3:1, (iii) the ratio of total debt to adjusted EBITDA shall not exceed 4:1, and (iv) the ratio of senior debt to total capitalization shall not exceed 0.5:1. At December 31, 2013, adjusted EBITDA for the purposes of the above noted covenant calculations was $540.4 million (December 31, 2012 – $289.8 million), on a rolling four quarter basis. As at, and for the periods ending December 31, 2013 and December 31, 2012 the Company is in compliance with all debt covenants.
As at December 31, 2013, Tourmaline’s bank debt balance was $590.3 million (December 31, 2012 – $360.6 million). In addition, Tourmaline has outstanding letters of credit of $2.2 million (December 31, 2012 – $4.4 million), which reduce the credit available on the facility. The effective interest rate on the Company’s borrowings under the bank facility for the year ended December 31, 2013 was 3.06% (December 31, 2012 – 3.31%).
Tourmaline 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:
Unlimited number of Common Shares without par value.
Unlimited number of non-voting Preferred Shares, issuable in series.
(b) Common Shares Issued
The provision for deferred taxes in the consolidated statements of income and comprehensive income reflect an effective tax rate which differs from the expected statutory tax rate. Differences were accounted for as follows:
As at December 31, 2013, the Company has estimated federal tax pools of $3.4 billion (2012 – $2.7 billion) available for deduction against future taxable income. The Company has $505 million of unused tax losses expiring between 2023 and 2033.
13.EARNINGS PER SHARE
Basic earnings-per-share was calculated as follows:
The Company has a rolling stock option plan. Under the employee stock option plan, the Company may grant options to its employees up to 18,980,486 shares of common stock. The exercise price of each option equals the volume-weighted average market price for the five days preceding the issue date of the Company’s stock on the date of grant and the option’s maximum term is five years. Options are granted throughout the year and vest 1/3 on each of the first, second and third anniversaries from the date of grant.
The fair value of options, granted during the year, was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions and resulting values:
Tourmaline’s consolidated statement of income and comprehensive income is prepared primarily by nature of the expenses, with the exception of salaries and wages which are included in both the operating and general and administrative expense line items as follows:
18.SUPPLEMENTAL CASH FLOW INFORMATION
Changes in non-cash working capital is comprised of:
Cash interest paid was $8.9 million for the year ended December 31, 2013 (December 31, 2012 – $11.8 million).
In the normal course of business, Tourmaline is obligated to make future payments. These obligations represent
contracts and other commitments that are known and non-cancellable:
20.KEY MANAGEMENT PERSONNEL COMPENSATION
Key management personnel are persons who have the authority and responsibility for planning, directing and controlling the activities of the Company, directly or indirectly. Key management includes all directors and executives of the Company. The table below summarizes all key management personnel compensation paid during the years ended December 31, 2013 and 2012. Non-executive directors do not receive short-term compensation.
Compensation of Key Management
On February 12, 2014 the Company issued 4.615 million common shares at a price of $47.50 per share for total gross proceeds of $219.2 million. A total of 15,198 common shares were purchased by insiders.
On March 4, 2014, Tourmaline entered into an agreement with Santonia Energy Inc. (“Santonia”), pursuant to which Tourmaline will acquire all of the issued and outstanding shares of Santonia. The transaction is expected to close on or prior to April 30, 2014. The deal is subject to approval by the regulators and shareholders of Santonia.
ABOUT TOURMALINE OIL CORP.
Tourmaline is a Canadian senior crude oil and natural gas exploration and production company focused on longterm growth through an aggressive exploration, development, production and acquisition program in the Western Canadian Sedimentary Basin.
FOR FURTHER INFORMATION, PLEASE CONTACT:
Tourmaline Oil Corp.
Chairman, President and Chief Executive Officer
Tourmaline Oil Corp.
Vice President, Finance and Chief Financial Officer
(403) 767-3587; email@example.com
Tourmaline Oil Corp.
Secretary and General Counsel
(403) 767-3593; firstname.lastname@example.org
Tourmaline Oil Corp.
Suite 3700, 250 – 6th Avenue S.W.
Calgary, Alberta T2P 3H7
Phone: (403) 266-5992
Facsimile: (403) 266-5952