TOURMALINE OIL CORP. ANNOUNCES RECORD Q2 2014 FINANCIAL AND OPERATING RESULTS – INCREASES DRILLING PROGRAM AND 2014 EXIT PRODUCTION

Calgary, Alberta – Tourmaline Oil Corp. (TSX:TOU) (“Tourmaline” or the “Company”) is pleased to announce record financial and operating results for the first half of 2014.

 

Highlights

  • Record cash flow(1) of $484.1 million during the first six months of 2014, a 97 % increase over 1H 2013.
  • Record earnings of $156.3 million in the 1H of 2014, a 90% increase over 1H 2013.
  • Q2 2014 production of 109,953 boepd, up 57% over Q2 2013.
  • 2014 exit production volume of 150,000 – 155,000 boepd currently estimated.
  • Average 30-day IP rate of 10.8 mmcfpd vs. internal template 30-day IP rate of 5.0 mmcfpd for the 32 Deep Basin horizontal wells drilled and completed thus far in 2014.
  • Tourmaline has drilled 56 gas wells, 12 oil wells and no dry holes thus far in 2014.

 

Financial Update

  • The Company is forecasting 2014 full-year cash flow of $1.05 billion and cash flow of $1.48 billion in 2015.
  • The Company completed the expansion of its banking credit facility to $1.3 billion during the second quarter.
  • The Company will continue to operate with a debt to cash flow ratio of less than 1.0 times.

 

Production Update

Second quarter 2014 production averaged 109,953 boepd, a 57% increase over second quarter 2013 and a 7% increase over the previous quarter. Second quarter production was reduced by approximately 3,000 boepd due to unscheduled outages related to mainline maintenance on the Alberta TCPL system and compressor issues on the Alliance system in NEBC in June. Additional maintenance on the mainline and the Robb lateral are planned by TCPL in August.

The Company remains on track to meet or exceed the full year average production target of 120,000 boepd. The significant 2H 2014 Company operated facility projects remain on schedule with the new Sundown B.C. facility expected to come on stream on August 15 (50 mmcfpd net addition), the Musreau AB and Doe B.C. plant expansions are set to be completed by October 1 (100 mmcfpd net addition from both expansions), and the new Spirit River AB gas plant is currently scheduled for an October 15 start-up (6,000 boepd net addition). The Company also accelerated the next plant expansion at Wild River, originally scheduled for Q2 2015, to December of 2014 (50 mmcfpd net addition).

During the July 2014 to December 2015 period, the increased operated drilling program of 20 rigs is expected to yield approximately 285 horizontal wells throughout the Company’s three operated EP complexes. This is 25more horizontals than originally forecast by exit 2014 and 75-80 additional horizontals by year end 2015. The additional wells are expected to add incremental production near the end of 2014 and in particular during 2015. Guidance for 2015 will be revisited once 2015 facility project timing is determined.

Tourmaline is currently forecasting a 2014 exit production volume of 150,000 – 155,000 boepd.

 

EP Program Update

Tourmaline is currently operating a total of 20 drilling rigs, with 14 rigs in the Alberta Deep Basin, 3 rigs active in NEBC and 3 rigs active on the Peace River High Charlie Lake horizontal oil play. This expanded drilling program is expected to yield 150 horizontal wells in the Alberta Deep Basin, 75 horizontal wells in the NEBC Montney gas-condensate complex and 60 Charlie Lake horizontals on the Peace River High between July 2014 and year end 2015. Where required, facility expansions to accommodate the anticipated increased production volumes have been accelerated.

 

Alberta Deep Basin

The post break-up Deep Basin drilling program commenced in mid-May, earlier than anticipated, with all 14 rigs
active by mid-July. Twenty new Deep Basin wells have already been drilled and rig released post break-up thus
far.

Production results from the Deep Basin in 2014 continue to exceed the production and economic template utilized by the Company. Of the 32 wells with over 30 days of production to date, the average 30 day IP rate is now 10.8 mmcfpd, well ahead of the forecast 30 day IP rate of 5.0 mmcfpd. Not included is the most recent Wilrich pad to come on-stream, Minehead 7-27, with the 2 wells on the pad averaging 21 mmcfpd and 16 mmcfpd during the first 18 days of production. The Lovett 7-15 well, a horizontal Wilrich well in the Frontal Foothills, has averaged 23 mmcfpd during the first 7 days of production and it is currently flowing 24.8 mmcfpd @ 14.7 MPa.

The main emphasis of the 2H 2014/2015 Deep Basin program is horizontal targets in the Cretaceous Wilrich, Notikewin and Falher formations. Within this overall 14 rig program, the Company also plans several horizontals targeting Montney gas-condensate, 10 – 12 horizontals targeting additional Cretaceous horizons and 4 – 5 verticals targeting new exploration play concepts in the Greater Alberta Deep Basin. The Company has cased three Exploration NPW discoveries that tested new play concepts in the Deep Basin thus far in 2014 and will production test these new wells during the third quarter.

Tourmaline expects to reach the 0.5 bcf/day gas production milestone from the Alberta Deep Basin late in 2014. 2014 YTD operating costs in the Deep Basin are approximately $4.45/boe.

 

NEBC Montney Gas Condensate

With the start-up of the Sundown facility in mid-August and completion of the Doe plant expansion in late September, production volumes from Tourmaline’s B.C. Montney gas-condensate complex are anticipated to reach the 45,000 – 47,500 boepd level during the fourth quarter.

Tourmaline has drilled 107 Montney horizontals to date at Dawson-Sunrise-Sundown and has an expanded future drilling inventory now in excess of 1,100 horizontal Montney locations in B.C. The Company is operating three drilling rigs in B.C. and expects to drill 75 – 80 horizontal wells during the next 18 months, including 15 delineation locations in the condensate rich lower turbidite horizon, where condensate rates in the 90 – 100 bbls/mmcf range have been observed from the four initial discovery wells.

The Company continues to add attractive new lands and drilling inventory throughout the B.C. Montney complex, with 5 sections added at greater Dawson in the second quarter.

2014 YTD operating costs in the B.C. Montney complex are approximately $3.67/boe.

 

Peace River High Charlie Lake Oil Complex

Current production from the Peace River High Charlie Lake oil complex is 12,000 boepd with approximately 5,000 boepd of additional volume awaiting facility access. Start-up of the new Spirit River 3-10 gas plant early in Q4 and additional tie-ins are expected to yield a 2014 exit production level of 18,000 – 20,000 boepd from this complex.

Tourmaline has now drilled 82 Charlie Lake horizontal oil wells and no dry holes in the complex to date and with three rigs active expects to add approximately 45 new horizontals per year. Completed and stimulated well costs are averaging $4.0 – 4.5 M with 2P reserves of 350 mstboe per horizontal in the current independent engineering report (December 2013). Seven additional concurrently stimulated well pairs will be drilled and completed prior to year-end 2014, with 10 additional pairs planned in 2015. The Company believes these concurrent pairs may lead to a step change in horizontal well performance.

The Company has a comprehensive Peace River High infrastructure plan in place for 2014 and 2015 that will allow for tie-in of rapidly growing production volumes, improved production on-times and reduced operating costs. The first component of the infrastructure plan is the Tourmaline-operated Spirit River sour gas injection plant which is expected to start-up in mid-October of this year. The second component of the plan is the Mulligan oil battery, of which the first 8,000 bpd phase will be operational by Spring break-up 2015. The Company is also pursuing a complementary series of water disposal, oil blending and direct oil tie-in opportunities to continually improve netbacks. 2014 YTD operating costs for the Spirit River-Mulligan-Earring complex are approximately $14.83/boe; these costs are anticipated to drop to the $10.00/boe level over the next several quarters as the full infrastructure plan is implemented. Overall, long-term corporate operating costs in the $4.25 – $4.50/boe range are anticipated.

 

Conference Call Tomorrow at 9:00 a.m. MT (11:00 a.m. ET)

Tourmaline will host a conference call tomorrow, August 7, 2014 starting at 9:00 a.m. MT (11:00 a.m. ET). To participate, please dial 1-866-226-1793 (toll-free in North America), or local dial-in 416-340-8410, a few minutes prior to the conference call.

The conference call ID number is 4197608.

 

Forward-Looking Information

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

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

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

Also included in this press release are estimates of Tourmaline’s 2014 and 2015 annual cash flow and capital spending which are based on the various assumptions as to production levels, including estimated average production of 120,000 boepd for 2014 and 159,500 boepd for 2015, capital expenditures, and other assumptions disclosed in this press release and including commodity price assumptions for natural gas (AECO – $4.64 /mcf for 2014 and $4.43/mcf for 2015), and crude oil (WTI (US) – $97.40/bbl for 2014 and $93.38/bbl for 2015) and an exchange rate assumption of (US/CAD) $0.92 for 2014 and $0.90 for 2015. To the extent any such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Tourmaline on August 6, 2014 and is included to provide readers with an understanding of Tourmaline’s anticipated cash flows based on the capital expenditure and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.

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

The forward-looking information contained in this press release is made as of the date hereof and Tourmaline undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless expressly required by applicable securities laws.

See also “Forward-Looking Statements” in the attached Management’s Discussion and Analysis.

 

Additional Reader Advisories

Boe Conversions
Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an indication of value.

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

Non-GAAP Financial Measures
This press release includes references to financial measures commonly used in the oil and gas industry, “cash flow”, “operating netback” and “net debt”, which do not have standardized meanings prescribed by International Financial Reporting Standards (“GAAP”). Accordingly, the Company’s use of these terms may not be comparable to similarly defined measures presented by other companies. Management uses the terms “cash flow”, “operating netback”, 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. See “Non-GAAP Financial Measures” in the attached Management’s Discussion and Analysis for the definition and description of these terms.

CERTAIN DEFINITIONS:

  • bbls – barrels
  • boe – barrel of oil equivalent
  • boepd – barrel of oil equivalent per day
  • bopd – barrel of oil, condensate or liquids per day
  • gjsd – gigajoules per day
  • mmboe – millions of barrels of oil equivalent
  • mbbls – thousand barrels
  • mmcf – million cubic feet
  • mcf – thousand cubic feet
  • mmcfpd – million cubic feet per day
  • mmcfpde – million cubic feet per day equivalent
  • mcfe – thousand cubic feet equivalent
  • mmbtu – million British thermal units
  • mstboe – thousand stock tank barrels of oil equivalent

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

This management’s discussion and analysis (“MD&A“) should be read in conjunction with Tourmaline’s unaudited interim condensed consolidated financial statements and related notes as at and for the three and six months ended June 30, 2014 and the consolidated financial statements for the year ended December 31, 2013. Both the consolidated financial statements and the MD&A can be found at www.sedar.com. This MD&A is dated August 6, 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 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

Production for the three months ended June 30, 2014 averaged 109,953 boe/d, a 57% increase over the average production for the same quarter of 2013 of 70,178 boe/d. For the six months ended June 30, 2014, production increased 53% to 106,278 boe/d from 69,411 boe/d for the same period in 2013. The Company’s significant production growth, when compared to 2013, can be primarily attributed to new wells that have been brought on-stream since June 30, 2013, as well as property and corporate acquisitions. Production was 85% natural gas weighted in the second quarter of 2014 compared to 90% in the second quarter of 2013. The accelerated growth in oil and NGL production is the result of increased drilling in the Spirit River/Peace River High Charlie Lake oil plays, incremental liquids recovered in the Wild River area via deep cut processing, which began in late 2013, and strong condensate recoveries from new wells tied-in in N.E.B.C.

Full-year average production guidance for 2014 remains unchanged at 120,000 boe/d (as disclosed in the Company’s MD&A dated March 17, 2014).

 

REVENUE

Revenue for the three months ended June 30, 2014 increased 84% to $350.5 million from $190.8 million for the same quarter of 2013. Revenue for the six-month period ended June 30, 2014 grew 91% from $365.8 million in 2013 to $699.8 million in 2014. Revenue growth is consistent with the increase in production and the rise in natural gas prices for the same periods, partially offset by weaker NGL prices. Revenue includes all petroleum, natural gas and NGL sales and realized gain (loss) on financial instruments.

The realized average natural gas price for the three and six months ended June 30, 2014 was 20% and 36%, respectively, higher than the same periods of the prior year. The higher natural gas price reflects the higher AECO prices experienced during the periods. Included in the realized price is a loss on commodity contracts in the second quarter of 2014 of $13.9 million (six months ended June 30, 2014 – $42.5 million) compared to a gain of $2.5 million for the same period of the prior year (six months ended June 30, 2013 – $3.6 million). The increased focus on hedging activities allows for more predictable cash flows to support the larger capital budget.

As a result, a larger volume of natural gas has been subject to pricing per the commodity contracts in place, creating realized losses when the price of natural gas increases. Realized prices exclude the effect of unrealized gains or losses on commodity contracts. Once these gains and losses are realized they are included in the per-unit amounts. Partially offsetting the loss on commodity contracts was a 6% premium to AECO pricing received due to the higher heat content (three months ended June 30, 2013 – 8%).

Realized oil prices were relatively unchanged for the three and six months ended June 30, 2014. For the three-month period ending June 30, 2014, NGL prices decreased 39% from $63.08/bbl to $38.57/bbl, when compared to the same period in 2013. NGL prices decreased 42% for the six-month period ended June 30, 2014, when compared to the same period of the prior year. The proportion of ethane in the NGL mix, which is priced significantly lower than the other products, increased from approximately 9% in 2013 to 39% in the second quarter of 2014 due to deep cut processing in the Wild River area of Alberta, resulting in a corresponding decrease in the realized NGL pricing. The economics of the deep cut processing activities are favourable when compared to leaving the ethane in the natural gas stream.

 

ROYALTIES

For the quarter ended June 30, 2014, the average effective royalty rate increased to 10.4% compared to 7.8% for the same quarter of 2013. For the six-month period ended June 30, 2014, the average effective royalty rate increased from 7.2% in 2013 to 9.6% in 2014. The increase in the average effective royalty rate for 2014 can be attributed to higher oil and NGL production which have higher royalty rates, as well as an increase in natural gas prices. Royalties are paid based on a monthly reference price and do not take into account the lower price received on hedged volumes in an environment of natural gas price appreciation, effectively resulting in a higher royalty rate.

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 2014 to remain at approximately 10%. The royalty rate is however sensitive to commodity prices and product mixes, and as such, a change in commodity prices or product mix will impact the actual rate.

 

OTHER INCOME

Other income increased from $1.2 million in the second quarter of 2013 to $4.5 million in 2014. For the six-month period ended June 30, 2014, other income increased from $2.6 million in 2013 to $9.4 million in 2014. The increase in processing income is mainly due to fees charged to working interest partners on Tourmaline operated wells where gas is being processed through the Company-owned Banshee gas processing plant. Tourmaline has experienced a rapid growth in production volumes from wells in that area.

 

OPERATING EXPENSES

Operating expenses include all periodic lease and field-level expenses and exclude income recoveries from processing third-party volumes. For the second quarter of 2014, total operating expenses were $52.4 million compared to $27.4 million in 2013. Operating costs for the six months ended June 30, 2014 were $97.9 million, compared to $53.8 million for the same period in 2013, reflecting increased costs relating to the growing production base.

On a per-boe basis, the costs increased from $4.29/boe for the second quarter of 2013 to $5.24/boe in the second quarter of 2014. For the six months ended June 30, 2014, operating costs increased from $4.28/boe in the prior year to $5.09/boe. The production of oil and NGLs incurs higher per-unit operating costs compared to natural gas. As the Company’s production profile becomes more heavily weighted to oil and NGLs, we anticipate an increase in per-unit operating expenses. The per-unit operating costs in the Wild River area have also increased as approximately 70 mmcfpd of natural gas is being processed through third-party fractionation facilities in an effort to recover more valuable natural gas liquids. The Company’s operating expenses also increased with the addition of volumes from the Santonia acquisition, which were subject to higher per-unit costs. It is expected that as this new production is processed through Tourmaline facilities and is subject to the same efficiencies, the costs associated with these incremental volumes will fall more in line with the corporate average.

The Company’s operating expenses in the second quarter of 2014 include third-party processing, gathering, and compression fees of approximately $15.1 million or 29% of total operating costs (three months ended June 30, 2013 – $7.5 million or 27% of total operating costs). For the six-month period ended June 30, 2014, the Company’s operating expenses included $27.5 million related to third-party processing, gathering and compression fees (28% of total operating costs) compared to $15.8 million (29% of total operating costs) for the same period in the prior year.

The Company expects its full year 2014 operating costs to average approximately $4.90/boe, which has increased from previous guidance of $4.40/boe (as disclosed in the Company’s MD&A dated May 7, 2014). Forecast operating costs have been increased to reflect the growth in oil and NGL production as well as additional costs for processing and fractionation of liquids extracted through deep cut facilities. The Company continues to invest capital in Company owned-and-operated plants in an effort to increase processing capacity and maintain its low operating cost structure. Actual costs per boe can change depending on a number of factors including the Company’s actual production levels.

 

TRANSPORTATION

Transportation costs for the three months ended June 30, 2014 were $21.3 million or $2.13/boe compared to $12.6 million or $1.97/boe for the same period of the prior year. Total transportation costs for the three and six months ended June 30, 2014 increased as a result of higher production volumes. The increase in per-unit transportation costs for the second quarter of 2014 over the same period of 2013 is due to the use of more expensive truck transportation, necessitated by strong growth in oil and NGL production. These increased costs will be mitigated by facility interconnects scheduled to come on stream in 2014 and 2015.

For the six months ended June 30, 2014, transportation costs were $36.6 million or $1.90/boe compared to $25.1 million or $2.00/boe for the first six months of 2013. The first half of 2014 saw unutilized transportation costs decrease when compared to the same period of 2013 as production increased. This reduction in unutilized transportation is reflected in the lower per-unit cost for the six-month period ended 2014, compared to 2013.

 

GENERAL & ADMINISTRATIVE EXPENSES (“G&A”)

G&A expenses for the second quarter of 2014 were $6.4 million ($0.64/boe) compared to $5.2 million ($0.82/boe) for the same quarter of the prior year. G&A expenses for the six-month period ended June 30, 2014 were $11.7 million ($0.61/boe) compared to $10.2 million ($0.81/boe) for the same period in 2013. The increase in G&A expenses in 2014 compared to 2013 is primarily due to staff additions needed to manage the larger production, reserve and land base, as well as the higher drilling rig count. The Company increased its staff count by approximately 25% from June 2013 to June 2014. The decrease in G&A expenses per boe reflects Tourmaline’s growing production base which continues to increase at a faster rate than the accompanying G&A costs.

G&A costs for 2014 are expected to be approximately $0.60/boe. Actual costs per boe can change, however, depending on a number of factors including the Company’s actual production levels.

 

SHARE-BASED PAYMENTS

The Company uses the fair value method for the determination of non-cash related share-based payments expense. During the second quarter of 2014, 991,000 stock options were granted to employees, officers, directors and key consultants at a weighted-average exercise price of $55.15 and 1,486,353 options were exercised, bringing $24.0 million of cash into treasury.

The Company recognized $6.8 million of share-based payments expense in the second quarter of 2014 compared to $4.5 million in the second quarter of 2013. Capitalized share-based payments for the second quarter of 2014 were $6.8 million compared to $4.5 million for the same quarter of the prior year.

For the six months ended June 30, 2014, share-based payment expense totalled $13.5 million and a further $13.5 million in share-based payments were capitalized (six months ended June 30, 2013 – $8.1 million and $8.1 million, respectively). Share-based payments are higher in 2014 compared to the same periods in 2013, which reflects the increased value attributed to the options and a higher number of options outstanding.

 

DEPLETION, DEPRECIATION AND AMORTIZATION (“DD&A”)

DD&A expense, excluding mineral lease expiries, was $121.4 million for the second quarter of 2014 compared to $74.9 million for the same period of 2013. For the six-month period ended June 30, 2014, DD&A expense (excluding mineral lease expires) was $229.3 million compared to $148.7 million in the same period of 2013. The increase in DD&A expense in 2014 over the same period in 2013 is due to higher production volumes, as well as a larger capital asset base being depleted.

The per-unit DD&A rate (excluding the impact of mineral lease expiries) was $12.13/boe for the second quarter of 2014 compared to the rate of $11.72/boe for the same quarter in 2013. The per-unit DD&A rate (excluding the impact of mineral lease expiries) was $11.92/boe for the six-month period ended June 30, 2014 compared to the rate of $11.84/boe in the same period of the prior year.

Mineral lease expiries for the three months ended June 30, 2014 were $5.7 million, compared to expiries in the same quarter of the prior year of $7.4 million. For the six months ended June 30, 2014 expiries were $13.3 million compared with $15.0 million for the same period in 2013. Tourmaline expects to continue to see mineral lease expiries of a similar magnitude on a go-forward basis.

 

FINANCE EXPENSES

Finance expenses are comprised of interest expense, accretion of provisions and transaction costs associated with corporate and property acquisitions. Finance expenses for the three and six months ended June 30, 2014 totalled $7.5 million and $13.0 million, respectively (three and six months ended June 30, 2013 – $3.0 million and $7.5 million, respectively). The increase in finance expenses in 2014 over 2013 is due to the recognition of transaction costs associated with a corporate acquisition in the period as well as a higher average bank debt outstanding, partially offset by a lower average effective interest rate. The average bank debt outstanding for the six months ended 2014 was $602.5 million (2013 – $301.7 million), with an average effective interest rate of 3.02% (2013 – 3.28%).

 

DEFERRED INCOME TAXES

For the three months ended June 30, 2014, the provision for deferred income tax expense was $25.2 million compared to $14.3 million for the same period in 2013. For the six-month period ended June 30, 2014, the provision for deferred income tax expense was $58.1 million compared to $33.9 million for the same period in 2013. The increase is consistent with the higher pre-tax earnings recorded in the second quarter and first half of 2014 compared to the respective periods in 2013.

 

CASH FLOW FROM OPERATING ACTIVITIES, CASH FLOW AND NET EARNINGS

Cash flow for the three months ended June 30, 2014 was $231.5 million or $1.13 per diluted share compared to $128.9 million or $0.68 per diluted share for the same period of 2013. Cash flow for the six months ended June 30, 2014 was $484.1 million or $2.41 per share compared to $245.5 million or $1.32 per share for the same period of 2013.

The Company had after-tax earnings for the three months ended June 30, 2014 of $66.4 million or $0.32 per diluted share compared to $30.0 million or $0.16 per diluted share for the same period of 2013. For the six-month period ended June 30, 2014, after-tax earnings were $156.3 million or $0.78 per diluted share compared to $82.2 million or $0.44 per diluted share for the first half of 2013. The increase in both cash flow and after-tax earnings in 2014 reflects higher natural gas prices, as well as a significant increase in production over 2013.

 

CAPITAL EXPENDITURES

During the second quarter of 2014, the Company invested $297.7 million of cash consideration, net of dispositions, compared to $158.8 million for the same period of 2013. Expenditures on exploration and production were $288.4 million compared to $121.8 million for the same quarter of 2013, which is consistent with the Company’s aggressive growth strategy. During the six-month period ended June 30, 2014, the Company
invested $764.1 million of cash consideration, net of dispositions, compared to $349.2 million for the same period in 2013. Expenditures on exploration and production were $749.8 million compared with $384.5 million for the same period in 2013.

The growth in facilities expenditures includes work on the expansion of the facilities at Doe, Musreau and Wild River; a new sour gas processing facility in Spirit River; an oil battery at Mulligan in the Spirit River area; a compressor station at Sundown; and several large pipeline lateral projects intended to optimize transportation of, and related logistics for getting, natural gas to Tourmaline operated processing facilities.

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

Corporate Acquisition
On April 24, 2014, the Company acquired all of the issued and outstanding shares of Santonia Energy Inc. (“Santonia”). As consideration, the Company issued 3,228,234 common shares at a price of $54.94 per share. Total transaction costs incurred by the Company of $1.5 million associated with this acquisition were expensed in the interim consolidated statement of income and comprehensive income. The acquisition resulted in an increase in Property, Plant and Equipment (“PP&E”) of approximately $167.5 million and an increase to Exploration and Evaluation (“E&E”) assets of $19.1 million. The acquisition of Santonia provides for an increase in lands and production in a highly profitable core area of the Alberta Deep Basin.

 

LIQUIDITY AND CAPITAL RESOURCES

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 were used to temporarily reduce bank debt and were used to fund the Company’s 2014 exploration and development program.

On April 24, 2014, the Company closed the acquisition of Santonia Energy Inc. (“Santonia”) with the issuance of 3.228 million Tourmaline shares at a closing price on that date of $54.94 per Tourmaline share, for consideration of $177.4 million. The Company also assumed Santonia’s net debt of $40.6 million, which included $8.9 million in transaction costs.

On June 2, 2014, the Company issued 1.15 million flow-through common shares at a price of $68.15 per share, for total gross proceeds of $78.4 million. The proceeds were used to temporarily reduce bank debt and to fund the Company’s remaining 2014 and its upcoming 2015 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 May 2014, the facility was increased to $1.3 billion from $900 million, with an initial maturity of June 2017. The revisions to the credit facility included the removal of the EBITDA to interest expense covenant as well as a revision to the definition of senior debt to mean generally the indebtedness, liabilities and obligations of the Company to the lenders under the credit facility. The increase in the facility will provide the Company with greater flexibility when executing its capital program.

As at June 30, 2014, the Company had negative working capital of $123.2 million, after adjusting for the fair value of financial instruments (the unadjusted working capital deficiency was $131.7 million) (December 31, 2013 – $242.6 million and $245.3 million, respectively). As at June 30, 2014, the Company had $704.1 million drawn on its credit facility (December 31, 2013 – $590.3 million), and net debt was $827.2 million (December 31, 2013 – $832.9 million). Management believes the Company has sufficient liquidity and capital resources to fund the remainder of its 2014 exploration and development programs through expected cash flow from operations and its unutilized bank credit facility.

 

SHARES AND STOCK OPTIONS OUTSTANDING

As at August 6, 2014, the Company has 201,438,624 common shares outstanding and 14,940,434 stock options granted and outstanding.

 

COMMITMENTS AND CONTRACTUAL OBLIGATIONS

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

 

OFF BALANCE SHEET ARRANGEMENTS

The Company has certain lease arrangements, all of which are reflected in the commitments and contractual obligations table, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or general and administrative expenses depending on the nature of the lease.

 

FINANCIAL RISK MANAGEMENT

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

The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities. The Company’s financial risks are discussed in note 5 of the Company’s audited consolidated financial statements for the year ended December 31, 2013.

As at June 30, 2014, 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 in place at June 30, 2014 are summarized and disclosed in note 3 of the Company’s interim condensed consolidated financial statements for the three and six months ended June 30, 2014 and 2013.

The following table provides a summary of the unrealized gains (losses) on financial instruments for the three and six months ended June 30, 2014 and 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 June 30, 2014 have been summarized and disclosed in note 3 of the Company’s interim condensed consolidated financial statements for the three and six months ended June 30, 2014 and 2013.

There were no financial derivative or physical delivery contracts entered into subsequent to June 30, 2014.

 

APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Management reviews its estimates on a regular basis. The emergence of new information and changed circumstances may result in actual results or changes to estimates that differ materially from current estimates. The Company’s use of estimates and judgments in preparing the interim condensed consolidated financial statements is discussed in note 1 of the consolidated financial statements for the year ended December 31, 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, 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.

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

There were no changes in the Company’s DC&P or ICFR during the period beginning on April 1, 2014 and ending on June 30, 2014 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

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

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

 

NON-GAAP FINANCIAL MEASURES

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

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

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:

 

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 Company’s average annual production has increased from 50,804 boe per day in 2012 to 74,796 boe per day in 2013 and 106,278 boe per day in the first six months of 2014. The production growth can be attributed primarily to the Company’s exploration and development activities, and from acquisitions of producing properties.

The Company’s cash flows from operating activities were $273.5 million in 2012 and $479.2 million in 2013. Estimated 2014 cash flows from operating activities (based on the first six months annualized) are $962.3 million, due mainly to strong growth in production levels and strengthening commodity prices. 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. Changes in commodity prices impact revenues and cash flows available for exploration, and also the economics of potential capital projects as low commodity prices can potentially reduce the quantities of reserves that are commercially recoverable. The Company’s capital program is dependent on cash flows generated from operations and access to capital markets.

 

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 INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As at June 30, 2014 and for the three and six months ended June 30, 2014 and 2013
(tabular amounts in thousands of dollars, unless otherwise noted) (unaudited)


Corporate Information:
Tourmaline Oil Corp. (the “Company”) was incorporated under the laws of the Province of Alberta on July 21, 2008. The Company is engaged in the acquisition, exploration, development and production of petroleum and natural gas properties. These interim condensed consolidated financial statements reflect only the Company’s proportionate interest in such activities.

The Company’s registered office is located at Suite 2400, 525 – 8th Avenue S.W., Calgary, Alberta, Canada  T2P 1G1.

 

1. BASIS OF PREPARATION

These unaudited interim condensed consolidated financial statements have been prepared in accordance with International Accounting Standard (“IAS”) 34, “Interim Financial Reporting”. These unaudited interim condensed consolidated financial statements do not include all of the information and disclosure required in the annual financial statements and should be read in conjunction with the Company’s consolidated financial statements for the year ended December 31, 2013.

The accounting policies and significant accounting judgments, estimates, and assumptions used in these unaudited interim condensed consolidated financial statements are consistent with those described in Notes 1 and 2 of the Company’s consolidated financial statements for the year ended December 31, 2013, except as detailed below.

On January 1, 2014, the Company adopted IFRIC 21, which addresses payments to government bodies. There was no impact on the Company as a result of adopting the new standard.

The unaudited interim condensed consolidated financial statements were authorized for issue by the Board of Directors on August 6, 2014.

 

2. DETERMINATION OF FAIR VALUE

A number of the Company’s accounting policies and disclosures require the determination of fair value for both financial and non-financial assets and liabilities. Fair values have been determined for measurement 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.
Measurement:

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

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

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

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

 

3. FINANCIAL RISK MANAGEMENT

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

The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities. The Company’s financial risks are consistent with those discussed in note 5 of the Company’s audited consolidated financial statements for the year ended December 31, 2013.

As at June 30, 2014, 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 interim consolidated statement of financial position at fair value, with changes in the fair value being recognized as an unrealized gain or loss on the interim consolidated statement of income and comprehensive income.

The Company has the following financial derivative contracts in place as at June 30, 2014 (1):

The following table provides a summary of the unrealized losses on financial instruments for the three and six months ended June 30, 2014 and 2013:

As at June 30, 2014, if the future strip prices for oil were $1.00/bbl higher and prices for natural gas were $0.10/mcf higher, with all other variables held constant, the after-tax loss on financial instruments would have been $3.4 million (June 30, 2013 – $2.2 million) lower. An equal and opposite impact would have occurred to unrealized gain (loss) and the fair value of the derivative contracts liability if oil prices were $1.00/bbl lower and gas prices were $0.10/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 June 30, 2014 (1):

No physical contracts were entered into subsequent to June 30, 2014

 

4. 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 probable reserves, as well as undeveloped land. Additions represent the Company’s share of costs on E&E assets during the period.

 

5. PROPERTY, PLANT AND EQUIPMENT (“PP&E”)

Future development costs of $3,763 million were included in the depletion calculation at June 30, 2014 (December 31, 2013 – $3,197 million).

Capitalization of G&A and Share-Based Payments
A total of $9.0 million in G&A expenditures have been capitalized and included in E&E and PP&E assets at June 30, 2014 (December 31, 2013 – $15.0 million). Also included in E&E and PP&E are non-cash share-based payments of $13.5 million (December 31, 2013 – $19.3 million).

Impairment Assessment
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 June 30, 2014; therefore an impairment test was not performed. Similarly, for the year ended December 31, 2013, the Company did not identify any impairment indicators and as a result did not conduct an impairment test.

Corporate Acquisition
On April 24, 2014, the Company acquired all of the issued and outstanding shares of Santonia Energy Inc. (“Santonia”). As consideration, the Company issued 3,228,234 common shares at a price of $54.94 per share. Total transaction costs incurred by the Company of $1.5 million associated with this acquisition were expensed in the interim consolidated statement of income and comprehensive income.

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

The above noted amounts are estimates based on information available to the Company at the time of preparation of the June 30, 2014 unaudited interim consolidated financial statements. Accordingly, the estimates used to derive the fair values in the purchase price include accruals and deferred tax assets. A future change in estimates could have an impact on the above-noted purchase equation.

Acquisition of Oil and Natural Gas Properties
For the six months ended June 30, 2014, the Company completed property acquisitions for total cash consideration of $4.8 million (December 31, 2013 – $226.9 million) and an additional $0.5 million in non-cash consideration (December 31, 2013 – $88.6 million). The Company also assumed $0.4 million in decommissioning liabilities (December 31, 2013 – $7.3 million).

 

6. DECOMMISSIONING OBLIGATIONS

The Company’s decommissioning obligations result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted amount of cash flow required to settle its decommissioning obligations is approximately $141.6 million (December 31, 2013 – $118.9 million), with some abandonments expected to commence in 2021. A risk-free rate of 2.96% (December 31, 2013 – 3.24%) and an inflation rate of 2.0% (December 31, 2013 – 2.0%) were used to calculate the fair value of the decommissioning obligations.

 

7. BANK DEBT

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 May 2014, the Company increased its facility to $1.3 billion, with an initial maturity of June 2017. The revisions to the credit facility included the removal of the EBITDA to interest expense covenant as well as a revision to the definition of senior debt to mean generally the indebtedness, liabilities and obligations of the Company to the lenders under the credit facility.

As at June 30, 2014, the Company’s bank debt balance was $704.1 million (December 31, 2013 – $590.3 million). In addition, the Company has outstanding letters of credit of $3.1 million (December 31, 2013 – $2.2 million), which reduce the credit available on the facility. The average effective interest rate for the six months ended June 30, 2014 was 3.02% (six months ended June 30, 2013 – 3.28%). As at June 30, 2014, the Company is in compliance with all debt covenants.

 

8. NON-CONTROLLING INTEREST

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

 

9. SHARE CAPITAL

(a) Authorized
Unlimited number of Common Shares without par value.

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

(b) Common Shares Issued

 

10. EARNINGS PER SHARE

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

There were 1,366,000 options excluded from the weighted-average share calculation for the three and six months ended June 30, 2014 because they were anti-dilutive (three and six months ended June 30, 2013 – 2,005,000 and 4,032,000, respectively).

 

11. SHARE-BASED PAYMENTS

The Company has a rolling stock option plan. Under the employee stock option plan, the Company may grant options to its employees up to 20,143,112 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 weighted average trading price of the Company’s common shares was $51.92 during the six months ended June 30, 2014 (six months ended June 30, 2013 – $37.38).

The following table summarizes stock options outstanding and exercisable at June 30, 2014:

The fair value of options granted during the six-month period ended June 30, 2014 was estimated on the date of
grant using the Black-Scholes option-pricing model with the following weighted average assumptions and
resulting values:

 

12. COMMITMENTS

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

 

 

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.
Michael Rose
Chairman, President and Chief Executive Officer
(403) 266-5992

OR

Tourmaline Oil Corp.
Brian Robinson
Vice President, Finance and Chief Financial Officer
(403) 767-3587; robinson@tourmalineoil.com

OR

Tourmaline Oil Corp.
Scott Kirker
Secretary and General Counsel
(403) 767-3593; kirker@tourmalineoil.com

OR

Tourmaline Oil Corp.
Suite 3700, 250 – 6th Avenue S.W.
Calgary, Alberta T2P 3H7
Phone: (403) 266-5992
Facsimile: (403) 266-5952
E-mail: info@tourmalineoil.com
Website: www.tourmalineoil.com

 


 

(1) See “Non-GAAP Financial Measures” in the attached Management’s Discussion and Analysis.