CALGARY, ALBERTA — (Marketwire) — 03/19/13 — Tourmaline Oil Corp. (TSX: TOU) (“Tourmaline” or the “Company”) achieved exceptional growth in reserves (69%), production (64%) and cash flow(1) (16%) in 2012 while delivering strong profitability in a year of significantly lower natural gas prices. The Company posted strong after-tax earnings of $15.5 million for the 2012 fiscal year.
Highlights
Production Update
Full year 2013 average production guidance was increased from 75,000 boepd to 80,000 boepd, on February 20, 2013. This will represent 57% growth over 2012 average production of 50,804 boepd. The Company expects to reach the 80,000 boepd level in early June when the new Doe gas plant is currently scheduled for start-up.
The new gas processing facility at Doe BC will bring approximately 10,000 – 11,000 boepd of shut-in Triassic Montney production on-stream. The gas handling facility expansion at Spirit River Alberta will bring approximately 2,000 boepd of currently shut-in Charlie Lake light oil and gas production on-stream in June. An additional 2,500-3,000 boepd of shut-in Charlie Lake production will come on-stream in late September through ongoing complementary pipeline/debottlenecking projects.
EP Update
The Company plans to continue operating 11 drilling rigs after break-up, with 2 rigs in NEBC pursuing the Triassic Montney, 2 at Spirit River pursuing the light oil charged Triassic Charlie Lake formation, and 7 in the Alberta Deep Basin pursuing Lower Cretaceous horizontal, liquid rich gas targets.
A total of 70 Deep Basin wells (60 horizontal and 10 vertical), 25 NEBC Montney horizontals and 25 Charlie Lake horizontals are expected for full year 2013.
Major 2013 facility projects include the ongoing Q2 gas facility projects at Doe BC and Spirit River Alberta and two, 50 mmcfpd gas facility expansions in the Alberta Deep Basin during the second half of 2013. Full year 2013 EP capital spending of $740.0 million is anticipated.
Liquids Production, Marketing and Transportation
Tourmaline is targeting the 15,000 bpd total liquid production level in Q4 2013, 70% of which is condensate and light oil.
In March of 2013, Tourmaline entered into certain short-and-long-term contracts to ensure stability of market price and access for the Company–s significant hydrocarbon liquids assets. These agreements include a 130 mmcfpd deep cut gas processing arrangement commencing in 2015, an associated liquids transportation agreement and a 9,000 bopd NGL product fractionation sale agreement.
The Company has a series of additional initiatives in place to manage the capture, transportation, storage, fractionation and the marketing of these liquids, both in the short and long-term.
In addition to participation in a third party deep cut plant, the Company is planning at least one owned-and-operated deep cut facility in the 2015 time frame.
Financial Update
Tourmaline is currently expecting 2013 cash flow of approximately $651.8 million based on production of 80,000 boepd and an AECO natural gas price of $3.66/mcf, representing 133% growth over 2012 cash flow.
Year-end 2012 net debt(2) was $464.3 million. During the first quarter of 2013 a $233.2 million equity financing closed on March 12, and the planned Elmworth disposition was completed. Net proceeds from the Elmworth disposition were $77.5 million; in addition $155 million of future capital will be removed from the 2P FDC account. Based on the $740.0 million capital program, the net proceeds from the equity financing and property disposition completed in March and the Company–s anticipated 2013 cash flow described above, the Company is forecasting 2013 exit net debt of $309.4 million, as the Company continues to strive to maintain a debt to cash flow ratio of 1.0 times or less.
Tourmaline–s unit cash cost(3) structure continued to improve during 2012 as full-year 2012 royalties fell to $1.63/boe – a 22% improvement; transportation costs fell to $1.87/boe – a 10% improvement; operating expenses were $4.43/boe – a 21% reduction; general and administrative costs dropped by 23% to $0.79/boe; and interest and financing charges increased to $0.70/boe – a change of 27%.
Tourmaline–s total unit cash costs of $9.42/boe dropped by 17% compared to 2011, providing amongst the lowest absolute cost structures in the industry. Similarly, Depletion, Depreciation and Amortization (“DD&A”) charges continued their steady trend downward for the third consecutive fiscal year to $13.04/boe – a 7% improvement over 2011.
Conference Call Tomorrow at 7:00 a.m. MT (9:00 a.m. ET)
Tourmaline will host a conference call tomorrow, March 20, 2013 starting at 7:00 a.m. MT (9:00 a.m. ET). To participate, please dial 1-866-226-1792 (toll-free in North America), or local dial-in 416-340-2216, a few minutes prior to the conference call.
The conference call ID number is 4159296.
Reader Advisories
Currency
All amounts in this news release are stated in Canadian dollars unless otherwise specified.
Reserves Data
The reserves data set forth above is based upon the reports of GLJ Petroleum Consultants Ltd. (“GLJ”) and Deloitte, each dated effective December 31, 2012, 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, 2013 price forecast used in the reserve evaluations is available on its website at .
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, 2012, which will be filed on SEDAR (accessible at ) on or before March 30, 2013.
Per share reserve information is based on the total common shares outstanding, after accounting for outstanding Company options, at year end 2012 and 2011, respectively.
See also the Company–s news release dated February 12, 2013 for more information with respect to the Company–s reserves data.
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.
Financial Outlook
Also included in this news release are estimates of Tourmaline–s 2013 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 2013 average production of 80,000 boepd and commodity price assumptions for natural gas (AECO – $3.66/mcf) (2013), and crude oil (WTI (US) – $95.00/bbl) (2013) and an exchange rate assumption of $1.00 (US/CAD) for 2013. To the extent such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Tourmaline on March 19, 2013 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.
General
See also “Forward-Looking Statements”, “Boe Conversions” and “Non-GAAP Financial Measures” in the attached Management–s Discussion and Analysis.
MANAGEMENT–S DISCUSSION AND ANALYSIS
For the years ended December 31, 2012 and December 31, 2011
This management–s discussion and analysis (“MD&A”) should be read in conjunction with Tourmaline–s consolidated financial statements and related notes for the years ended 2012 and 2011. Both the consolidated financial statements and the MD&A can be found at . This MD&A is dated March 19, 2013.
The financial information contained herein has been prepared in accordance with International Financial Reporting Standards (“IFRS”) and sometimes referred to in this MD&A as Generally Accepted Accounting Principles (“GAAP”) as issued by the International Accounting Standards Board (“IASB”). All dollar amounts are expressed in Canadian currency, unless otherwise noted.
Certain financial measures referred to in this MD&A are not prescribed by IFRS. See “Non-GAAP Financial Measures” for information regarding the following non-GAAP financial measures used in this MD&A: “cash flow”, “operating netback”, “working capital (adjusted for the fair value of financial instruments)” and “net debt”.
Additional information relating to Tourmaline can be found at .
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 .
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 2012 averaged 57,230 Boe/d, a 51% increase over the average production for the same quarter of 2011 of 37,912 Boe/d. Production was 88% natural gas weighted in the fourth quarter of 2012, which is consistent with the fourth quarter of 2011. For the year ended December 31, 2012, production increased 64% to 50,804 Boe/d from 31,007 Boe/d in 2011.
The Company–s significant production growth when compared to 2011 can be primarily attributed to new wells that have been brought on-stream in 2012, as well as property and corporate acquisitions completed during the year.
Production guidance for 2013 is 80,000 Boe/d, an increase from the previous target of 75,000 Boe/d (as disclosed by press release November 8, 2012). The production increase is a direct result of Tourmaline–s continued success in the ongoing exploration and production program, as well as the planned commissioning of facilities in the Doe and Sunrise areas which will allow shut-in production to come on-stream.
Revenue for the three months ended December 31, 2012 increased 33% to $143.1 million from $107.9 million for the same quarter of 2011. Revenue for the year ended December 31, 2012 increased 24% to $449.8 million from $363.0 million in 2011. Revenue growth is consistent with the increase in production over the same periods, partially offset by lower realized commodity 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, 2012 were 13% and 36%, respectively, lower than the same periods of the prior year. Realized crude oil and NGL prices decreased 10% and 7% for the quarter and year ended December 31, 2012, respectively, compared to the same periods of the prior year.
The realized natural gas price for the quarter ended December 31, 2012 was $3.29/mcf, which is 3% (three months ended December 31, 2011 – 18%) higher than the AECO index price. The Company receives a premium to the AECO index on its Alberta Deep Basin natural gas production to reflect a higher heat content, which has remained consistent year-over-year (December 31, 2012 – 8% and December 31, 2011 – 7%). In 2012, this premium was partially offset by losses on commodity contracts.
The realized natural gas price for the year ended December 31, 2012 was 10% (December 31, 2011 – 16%) 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, 2012, the average effective royalty rate was 7.5% compared to 7.0% for the same quarter of 2011. For the year ended December 31, 2012, the average effective royalty rate was 6.7% compared to 6.5% for the same period of 2011. The Company continues to benefit from the New Well Royalty Reduction Program and the Natural Gas Deep Drilling Program in Alberta as well as the Deep Royalty Credit Program in British Columbia.
The Company expects its royalty rate for 2013 to be approximately 10% as some of the wells will no longer qualify for royalty incentive programs due to production maximums being reached and other wells coming off royalty holidays, thereby increasing the Company–s overall royalty rate. The royalty rate is sensitive to commodity prices, however, and as such, a change in commodity prices will impact the actual rate.
OTHER INCOME
For the quarter ended December 31, 2012, other income totaled $1.4 million, all of which pertained to processing income, compared to $2.4 million of other income for the same quarter of 2011, of which $2.3 million related to processing income. Processing income has been decreasing as a smaller amount of third-party production has been processed in Tourmaline owned-and-operated facilities as the Company grows the amount of its own production, thus reducing capacity for third-party volumes. For the year ended December 31, 2012, other income was $5.0 million compared to $5.8 million for the prior year.
Operating expenses include all periodic lease and field-level expenses and exclude income recoveries from processing third-party volumes. For the fourth quarter of 2012, total operating expenses increased 20% from $18.0 million in the fourth quarter of 2011 to $21.6 million in 2012 due to the increased variable costs relating to new production. On a per-Boe basis, the costs decreased 21% from $5.17/Boe for the fourth quarter of 2011 to $4.10/Boe in the fourth quarter of 2012 due to increased production, increased operational efficiencies and the impact of redirecting natural gas from third-party facilities to Tourmaline-owned infrastructure. Tourmaline–s operating expenses in the fourth quarter of 2012 include third-party processing, gathering and compression fees of approximately $5.7 million or $1.09/Boe (December 31, 2011- $5.9 million or $1.68/Boe).
For the year ended December 31, 2012, total operating expenses were $82.3 million, or $4.43/Boe, compared to $63.1 million, or $5.58/Boe for the same period of 2011. Although total operating expenses increased with production, the costs per Boe decreased 21% reflecting increased operational efficiencies. Third-party processing, gathering and compression fees for the year ended December 31, 2012 have increased year-over-year with production ($21.7 million in 2012 versus $19.1 million in 2011); however, the cost per Boe has decreased to $1.17/Boe in 2012 versus $1.68/Boe in 2011.
In September 2012, the Company completed its plant expansion at Musreau in the Alberta Deep Basin. During 2012, the Company also began work on a gas plant at Doe in NEBC and a new liquids handling facility at Spirit River. These projects allow for additional volumes to flow through Company owned-and-operated plants thereby reducing third-party processing charges on a go-forward basis.
The Company–s operating cost target is $4.25/Boe in 2013. This is lower than the previous year–s guidance due to a combination of increased production, continued operational efficiencies and redirecting third-party gas into Company owned-and-operated facilities. 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, 2012 were $9.8 million or $1.86/Boe (three months ended December 31, 2011 – $7.8 million or $2.24/Boe). Transportation costs for the year ended December 31, 2012 were $34.7 million or $1.87/Boe (year ended December, 2011 – $23.4 million or $2.06/Boe). The increase in total transportation costs for the three months and the year ended December 31, 2012 can be primarily attributed to increased production. Oil and liquids transportation costs have increased due to pipeline and infrastructure constraints resulting in a higher use of more expensive truck transportation.
On a per-Boe basis, transportation costs for the three months and year ended December 31, 2012 are lower primarily due to the expansion of the Company–s owned-and-operated Sunrise and Musreau plants which allows increased volumes to be processed at these facilities which are closer to the Company–s producing assets than the previous third-party facilities.
G&A expenses for the fourth quarter of 2012 were $4.1 million compared to $2.9 million for the same quarter of the prior year. G&A costs per Boe for the fourth quarter of 2012 decreased 6% down to $0.77/Boe, compared to $0.82/Boe for the fourth quarter of 2011.
For the year ended December 31, 2012, G&A expenses were $14.6 million or $0.79/Boe compared to $11.5 million or $1.02/Boe for the same period of 2011. The higher total G&A expenses from 2011 to 2012 result from the need to manage the larger production, reserve and land base. Additionally, the administrative and capital recoveries from joint venture partners have decreased as the Company–s overall working interest has increased. Notwithstanding this, the Company–s G&A expenses per Boe continue to trend downward as Tourmaline–s production base continues to grow faster than its accompanying G&A costs.
G&A costs for 2013 are expected to be similar to 2012 on a dollar-per-Boe basis. Actual costs per Boe can change, however, depending on a number of factors including the Company–s actual production levels.
Tourmaline uses the fair value method for the determination of non-cash related share-based payments expense. During the fourth quarter of 2012, 1,927,000 stock options were granted to employees, officers, directors and key consultants at a weighted-average exercise price of $32.00, and 683,799 options were exercised, bringing $6.8 million of cash into treasury. The Company recognized $3.9 million of share-based payment expense in the fourth quarter of 2012 compared to $3.1 million in the fourth quarter of 2011. Capitalized share-based payments expense for the fourth quarter of 2012 was $3.9 million compared to $3.1 million for the same quarter of the prior year.
For the year ended December 31, 2012, share-based payment expense totalled $14.9 million and a further $14.9 million in share-based payments were capitalized (2011 – $11.7 million and $11.7 million, respectively). The increase in share-based payment expense in 2012 compared to 2011 reflects the increased number of options outstanding.
DD&A expense was $66.0 million for the fourth quarter of 2012 compared to $41.2 million for the same period of 2011 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 2012 was $12.53/Boe compared to $11.82/Boe for the fourth quarter of 2011.
For the year ended December 31, 2012, DD&A expense was $242.5 million (December 31, 2011 – $158.2 million) with an effective rate of $13.04/Boe (December 31, 2011 – $13.98/Boe). The lower DD&A rate in 2012 reflects strong reserve additions derived from Tourmaline–s exploration and production program, coupled with lower finding and development costs in 2012 versus those incurred in 2011.
Finance expenses totalled $4.4 million and $13.0 million for the quarter and year ended December 31, 2012, respectively (December 31, 2011 – $1.1 million and $6.2 million, respectively) and are comprised of interest expense, transaction costs on corporate and property acquisitions and accretion of decommissioning obligations. The increased finance expenses are largely due to higher interest expense resulting from a higher balance drawn on the credit facility in 2012. The average bank debt outstanding and the average effective interest rate on that debt during 2012 were $245.4 million and 3.34%, respectively (2011 – $54.7 million and 3.3% respectively).
Cash flow for the three months ended December 31, 2012 was $93.8 million or $0.54 per diluted share compared to $73.3 million or $0.45 per diluted share for the same period of 2011. For the year ended December 31, 2012, cash flow was $280.3 million or $1.68 per diluted share, which is higher than the December 31, 2011 cash flow of $241.4 million or $1.58 per diluted share. Cash flow in 2012 reflects increased production over 2011 offset by lower natural gas prices.
The Company had after-tax earnings for both the three months and year ended December 31, 2012 of $16.3 million ($0.09 per diluted share) and $15.5 million ($0.09 per diluted share), respectively, compared to earnings of $16.1 million ($0.10 per diluted share) and $42.7 million ($0.28 per diluted share), respectively, for the same periods of 2011. The decreased after-tax earnings for the 2012 year, compared to 2011, reflect lower natural gas prices.
During the fourth quarter of 2012, the Company invested $296.1 million of cash consideration, net of dispositions, compared to $232.2 million for the same period of 2011. Expenditures on exploration and production were $211.1 million compared to $222.5 million for the same quarter of 2011.
The following table summarizes the drill, complete and tie-in activities for the period:
Capital expenditures in 2013 are forecast to be $740 million, which has been revised upward from $650 million (as previously disclosed by press release November 8, 2012). A total of 70 Deep Basin wells, 25 NEBC Montney horizontal wells and 25 Charlie Lake horizontal wells are expected to be drilled in 2013. Major 2013 facility projects include the completion of the gas facilities at Doe in NEBC and Spirit River, Alberta (planned to be completed in the second quarter) and two gas facility expansions in the Alberta Deep Basin during the second half of 2013.
Corporate Acquisition
On November 30, 2012, the Company acquired all of the issued and outstanding shares of Huron Energy Corporation (“Huron”) in exchange for Tourmaline common shares. The acquisition resulted in an increase to Property, Plant and Equipment (“PP&E”) of approximately $251.5 million and an increase to Exploration and Evaluation (“E&E”) assets of $59.1 million. The acquisition of Huron provides for an increase in lands and production in Tourmaline–s key highly profitable core and designated growth area of Sunrise in NEBC.
LIQUIDITY AND CAPITAL RESOURCES
On April 4, 2012, the Company issued 1.4 million flow-through common shares at a price of $28.80 per share for total gross proceeds of $40.4 million. On August 30, 2012, the Company issued 4.039 million common shares at a price of $29.00 per share for total gross proceeds of $117.1 million. Subsequently, on September 19, 2012, the underwriters exercised their over-allotment option and purchased a further 0.6 million shares at a price of $29.00 per share for total gross proceeds of $17.4 million. On November 1, 2012, the Company issued 1.05 million flow-through common shares at a price of $36.90 per share for total gross proceeds of $38.7 million. The proceeds of the above-noted financings were used to temporarily reduce bank debt and to fund the Company–s capital exploration program.
In June 2012, the Company amended and restated its bank credit facility to be a covenant-based facility rather than a borrowing base facility. This facility is a 3-year extendible revolving facility in the amount of $550 million plus a $25 million operating revolver from a syndicate of six lenders with an initial maturity date of June, 2015. 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. The facility will provide the Company with greater flexibility by providing access to an additional $200 million over the previous facility.
Under the terms of the bank credit facility, Tourmaline has provided its covenant that, on a rolling four quarter basis: (i) the ratio of EBITDA to interest expense shall equal or exceed 3.5:1, (ii) the ratio of senior debt to EBITDA shall not exceed 3:1, (iii) the ratio of total debt to EBITDA shall not exceed 4:1, and (iv) the ratio of senior debt to total capitalization shall not exceed 0.5:1. As at December 31, 2012, the Company is in compliance with all debt covenants.
At December 31, 2012, Tourmaline had negative working capital of $103.7 million, after adjusting for the fair value of financial instruments (the unadjusted working capital deficiency was $98.9 million) (December 31, 2011 – $146.6 million and $146.3 million, respectively). Management believes the Company has sufficient liquidity and capital resources to fund the 2013 exploration and development program through expected cash flow from operations, its unutilized bank credit facility and the financing described in the subsequent events section of this MD&A. As at December 31, 2012, the Company–s bank debt balance was $360.6 million (December 31, 2011 – $81.7 million), and net debt was $464.3 million (December 31, 2011 – $228.3 million).
SHARES AND STOCK OPTIONS OUTSTANDING
As at March 19, 2013, the Company has 182,230,907 common shares outstanding and 14,617,384 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.
Subsequent to December 31, 2012, the Company entered into a 130 mmcf/d deep cut gas processing agreement and a firm service transportation agreement for the associated liquids. Both agreements have ten-year terms and begin in 2015. The Company also entered into a ten-year 9,000 bbl/d natural gas liquids product fractionation marketing agreement beginning in 2016.
OFF BALANCE SHEET ARRANGEMENTS
The Company has certain lease arrangements, all of which are reflected in the commitments and contractual obligations table, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or general and administrative expenses depending on the nature of the lease.
FINANCIAL RISK MANAGEMENT
The Board of Directors has overall responsibility for the establishment and oversight of the Company–s risk management framework. The Board has implemented and monitors compliance with risk management policies.
The Company–s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company–s activities. The Company–s financial risks are discussed in note 5 of the Company–s consolidated financial statements for the year ended December 31, 2012.
As at December 31, 2012, the Company has entered into certain financial derivative and physical delivery sales contracts in order to manage commodity risk. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, even though the Company considers all commodity contracts to be effective economic hedges. Such financial derivative commodity contracts are recorded on the consolidated statement of financial position at fair value, with changes in the fair value being recognized as an unrealized gain or loss on the consolidated statement of income and comprehensive income. The contracts that the Company has entered into in the 2012 year are detailed in note 5 of the Company–s consolidated financial statements for the year ended December 31, 2012.
The following table provides a summary of the unrealized gains and losses on financial instruments for the year ended December 31, 2012:
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. These contracts have been disclosed in note 5 of the Company–s consolidated financial statements for the year ended December 31, 2012.
The Company has entered into several financial derivative and physical delivery sales contracts subsequent to December 31, 2012. These contracts are detailed in note 5 of the Company–s consolidated financial statements for the year ended December 31, 2012.
SUBSEQUENT EVENTS
On March 12, 2013, the Company closed on the disposition of a non-producing property for proceeds of $77.5 million, subject to closing adjustments and transaction costs. The asset has been reclassified to current as an asset held for sale as at December 31, 2012.
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.
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, 2012.
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING
The Company–s Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures (“DC&P”), as defined by National Instrument 52-109 – Certification 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, 2012, the Company–s DC&P and ICFR are effective. There were no changes in the Company–s ICFR during the period beginning on October 1, 2012 and ending December 31, 2012 that have materially affected, or are reasonably likely to materially affect, the Company–s ICFR. It should be noted that a control system, including the Company–s disclosure and internal controls and procedures, no matter how well conceived can provide only reasonable, but not absolute assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.
BUSINESS RISKS AND UNCERTAINTIES
Tourmaline monitors and complies with current government regulations that affect its activities, although operations may be adversely affected by changes in government policy, regulations or taxation. In addition, Tourmaline maintains a level of liability, property and business interruption insurance which is believed to be adequate for Tourmaline–s size and activities, but is unable to obtain insurance to cover all risks within the business or in amounts to cover all possible claims.
See “Forward-Looking Statements” in this MD&A and “Risk Factors” in Tourmaline–s most recent annual information form for additional information regarding the risks to which Tourmaline and its business and operations are subject.
IMPACT OF NEW ENVIRONMENTAL REGULATIONS
Environmental legislation, including the Kyoto Accord, the federal government–s “EcoACTION” plan and Alberta–s Bill 3 – Climate Change and Emissions Management Amendment Act, is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. Given the evolving nature of the debate related to climate change and the resulting requirements, it is not possible to determine the operational or financial impact of those requirements on Tourmaline.
RECENT PRONOUNCEMENTS ISSUED
The following pronouncements from the IASB will become effective for financial reporting periods beginning on or after January 1, 2013 and have not yet been adopted by the Company. All of these new or revised standards permit early adoption with transitional arrangements depending upon the date of initial application.
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.
IAS 19 – Employee Benefits revises the existing standard to eliminate options to defer the recognition of gains and losses in defined benefit plans, requires re-measurements of a defined benefit plan–s assets and liabilities to be presented in other comprehensive income and increases disclosure.
IAS 27 – Separate Financial Statements revised the existing standard which addresses the presentation of parent company financial statements that are not consolidated financial statements.
IAS 28 – Investments in Associate and Joint Ventures revised the existing standard and prescribes the accounting for investments and sets out the requirements for the application of the equity method when accounting for investments in associates and joint ventures.
The Company has not completed its evaluation of the effect of adopting these standards on its financial statements.
The IASB also issued Presentation of Items of Other Comprehensive Income, an amendment to IAS 1 Financial Statement Presentation. The amendment addresses the presentation of other comprehensive income and requires the grouping of items within other comprehensive income that might eventually be reclassified to the profit and loss section of the income statement. The change became effective on July 1, 2012.
NON-GAAP FINANCIAL MEASURES
This MD&A includes references to financial measures commonly used in the oil and gas industry such as “cash flow”, “operating netback”, “working capital (adjusted for the fair value of financial instruments)” and “net debt”, which do not have any standardized meaning prescribed by GAAP. Management believes that in addition to net income and cash flow from operating activities, the aforementioned non-GAAP financial measures are useful supplemental measures in assessing Tourmaline–s ability to generate the cash necessary to repay debt or fund future growth through capital investment. Readers are cautioned, however, that these measures should not be construed as an alternative to net income or cash flow from operating activities determined in accordance with GAAP as an indication of Tourmaline–s performance. Tourmaline–s method of calculating these measures may differ from other companies and accordingly, they may not be comparable to measures used by other companies. For these purposes, Tourmaline defines cash flow as cash flow from operating activities before changes in non-cash operating working capital, defines operating netback as revenue (excluding processing income) less royalties, transportation costs and operating expenses and defines working capital (adjusted for the fair value of financial instruments) as working capital adjusted for the fair value of financial instruments. Net debt is defined as long-term bank debt plus working capital (adjusted for the fair value of financial instruments).
Cash Flow
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
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:
Net Debt
A summary of the reconciliation of net debt is set forth below:
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 31,007 Boe per day in 2011 to 50,804 Boe per day in 2012. The production growth can be attributed primarily to the Company–s exploration and development activities, as well as from acquisitions of producing properties. Over the same period, natural gas prices have declined, with the largest declines occurring in 2012.
The Company–s cash flows from operating activities were $228.4 million in 2011 and $273.5 million in 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.
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.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2012 and 2011
(tabular amounts in thousands of dollars, unless otherwise noted)
Corporate Information:
Tourmaline Oil Corp. (the “Company”) was incorporated under the laws of the Province of Alberta on July 21, 2008. The Company is engaged in the acquisition, exploration, development and production of petroleum and natural gas properties 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 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”).
The consolidated financial statements were authorized for issue by the Board of Directors on March 19, 2013.
(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 forecast 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 liabilities.
(i) Reserves:
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 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 flows.
(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.
(a) Consolidation:
The consolidated financial statements include the accounts of Tourmaline Oil Corp., Exshaw Oil Corp., of which the Company owns 90.6% (note 10), and Huron Energy Corporation, which is a wholly-owned subsidiary.
(i) Subsidiaries:
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, 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.
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.
(ii) Transactions eliminated on consolidation:
Intercompany balances and transactions, and any unrealized income and expenses arising from intercompany 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) 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 non-derivative financial instruments.
Investments:
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:
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.
(c) 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 accor