TOURMALINE CASH FLOWS $203.0 MILLION IN THE SECOND QUARTER

Calgary, Alberta – Tourmaline Oil Corp. (TSX:TOU) (“Tourmaline” or the “Company”) is pleased to announce continued strong financial and operating results for the second quarter of 2015.

 

HIGHLIGHTS

  • Second quarter production of 143,634 boepd, up 31% from second quarter of 2014.
  • Quarterly cash flow(1) of $203.0 million ($0.95/share).
  • Second quarter 2015 operating costs of $4.10/boe, down 13% from Q1 2015.
  • All-in cash costs (operating, transportation, general and administrative(2) and financing) of $7.35/boe, amongst the lowest in the industry.
  • Second quarter pre-tax earnings of $35.6 million.
  • Six additional NEBC lower Montney turbidite wells completed.
  • 24,000 bpd Mulligan oil battery commissioned in July.

 

FINANCIAL RESULTS

Second quarter 2015 cash flow was $203.0 million ($0.95/share) on an average realized natural gas price of
$3.17/mcf and an average oil price of $73.19/boe. Second quarter 2015 pre-tax earnings were $35.6 million,
reflecting the underlying profitability of the Company’s low cost natural gas business, even in a very difficult
commodity price environment. Second quarter after-tax earnings were reduced by $29.5 million due to an
increase in the deferred tax provision related to the recent Alberta Government 20% corporate tax increase.
Tourmaline is expecting full-year 2015 cash flow of $982.1 million ($4.56/share) and is currently forecasting 2016
cash flow of $1,417.4 million ($6.46/share).

COST UPDATE

Second quarter operating costs were $4.10/boe, a 22% decrease over second quarter 2014 operating costs of $5.24/boe and a 13% reduction from first quarter 2015 operating costs of $4.69/boe. Tourmaline is currently forecasting full-year 2015 operating costs of $4.35/boe, and could eclipse this target. Second quarter 2015 general and administrative cash costs were $0.46/boe, a 28% decrease from second quarter 2014 and a 4% decrease from first quarter 2015 costs of $0.48/boe. Second quarter 2015 all-in cash costs were $7.35/boe, down 9% from the first quarter of 2015. Tourmaline’s all-in interest rate on current corporate debt is 2.72%, one of the lowest in the North American energy sector.

 

PRODUCTION UPDATE

Second quarter production averaged 143,634 boepd, a 31% increase over the second quarter of 2014. As previously announced on June 1, 2015, second quarter production was reduced by unplanned firm service restrictions and maintenance outages on both the TCPL and Spectra transportation systems. In June, these outages were extended for longer periods of time than originally announced; in aggregate, Q2 2015 production volumes were reduced by 8,000 boepd. The Spectra outage involved unplanned pipeline maintenance on the T North system which extended for 23 days and resulted in Tourmaline shutting in the 110 mmcfpd Doe gas plant which operates at full capacity. Significantly fewer outages are currently planned by the transportation providers during the second half of 2015. Tourmaline also reduced interruptible gas volumes provided to a third-party Deep Cut facility at Wild River, reducing second quarter 2015 liquid volumes by approximately 2,000 bpd over the previous several quarters.

Second half 2015 production is anticipated to ramp up in all three operated areas, with the 25,000 boepd currently behind pipe systematically brought on-stream as well as the tie-in of approximately 110 new wells. Major new facility start-ups in the second half include the Mulligan oil battery, commissioned in July, and the new Edson gas plant in October.

Average production of 164,500 boepd for full year 2015 is anticipated, with a 2015 exit of approximately 200,000 boepd. The Company expects to reach the 164,500 boepd production target during the second half of August and continue to rapidly accelerate production through to year end. Projected 2016 average production was increased in June to 215,000 boepd (1,051 mmcfpd gas, 40,000 bpd oil, condensate, NGLs).

 

EP CAPITAL PROGRAM AND FINANCIAL UPDATE

Second quarter 2015 EP capital spending was $204.7 million, roughly equivalent to quarterly cash flow. The second quarter capital program also included $89.7 million on land and property acquisitions as the Company consolidated specific assets in all three core-operated complexes during this difficult commodity price environment for industry. This consolidation activity in delineated resource sweet spots has added over 350 sections of land and over 700 highest quality new drilling locations across all three core complexes.

2015 full-year EP capital spending has been increased to $1.4 billion, reflecting the full impact of the increased second half 18 drilling rig program. Tourmaline expects to drill 120 wells during the second half of the year. Drilling and completion costs, in all three complexes, are now consistently 25 – 30% lower than 2H 2014 drilling and completion costs. 2015 facility expenditures are estimated at $310 million down from $790 million in 2014, contributing to continually improving capital efficiencies. The vast majority of the infrastructure build-out in all three core areas is now largely complete; the basic skeleton to service the entire future drilling inventory is now in place. The full year 2015 EP capital program of $1.4 billion remains $200 million lower than the originally planned $1.6 billion 2015 EP budget.

Tourmaline reduced net debt(3) by $108.2 million or 7.7% quarter over quarter. A 2015 exit net debt of $1.4 billion is expected, representing debt to trailing cash flow of 1.4 times. Tourmaline continues to maintain a very strong balance sheet with debt to cash flow remaining at 1.5 times or less throughout the Company’s entire six and a half year history.

Preliminary 2016 EP capital spending of $1.35 billion is expected, less than forecast 2016 cash flow of $1.42 billion. Approximately 80% of the 2016 capital program will be directed towards drilling and completions activity.

 

EP UPDATE

Tourmaline will operate 18 drilling rigs in the second half of 2015 with 11 rigs active in the Alberta Deep Basin, three rigs active in the NEBC Montney complex and four rigs on the Peace River High. The Company is drilling incremental wells during a period of significantly-reduced service costs.

 

ALBERTA DEEP BASIN

The 2H 2015 Deep Basin program will focus on large, multi-well Wilrich and Notikewin pads which will drive continually-improving capital efficiencies. The Company continues to outperform horizontal 30-day IP targets thus far in 2015, with an overall 2015 average of 9.1 mmcfpd vs a base case 30-day IP template of 5 mmcfpd. A total of 60 new Deep Basin horizontal wells will be drilled during the second half, with the vast majority of these wells on-stream early in the fourth quarter. Second half drilling includes step-outs to the three high-rate horizontals in the greater Brazeau area, a highly prospective expanding opportunity at the southeast end of the Deep Basin complex. The 50-55 mmcfpd new gas plant at Edson, the only significant 2015 Deep Basin facility project planned by the Company, is expected to be on-stream early in the fourth quarter, bringing total owned and operated Deep Basin processing capacity to 600 mmcfpd. Second quarter 2015 Deep Basin operating costs were $3.25/boe.

 

NEBC MONTNEY COMPLEX

Current production in the B.C Montney complex ranges between 42,000 – 44,000 boepd with the existing facility network essentially at full capacity. New facility projects at Doe and Sundown will add 100 mmcfpd of new production capacity during 2016; these facilities will also be full upon start-up. An additional six lower Montney turbidite horizontals have been drilled and completed in Q2 with stable condensate rates of 75 – 100 bbl/mmcf, consistent with results from the initial ten 2013/2014 turbidite wells. EP activity pursuing this new, condensaterich, lower Montney horizon has been accelerated as it offers significant production and reserve upside incremental to the existing NEBC five year development plan. The Company estimates that full development of the lower Montney turbidite could add up to 75 – 100 mmcfpd of incremental gas production with 7,500 – 10,000 bpd of additional condensate volumes. The new 2016 Doe plant will include enhanced liquid processing capabilities designed to optimize liquid recoveries from the lower Montney turbidite.

 

PEACE RIVER HIGH CHARLIE LAKE COMPLEX

Tourmaline is currently operating four drilling rigs in the Peace River High Charlie Lake complex, and expects to drill, compete and tie-in an additional 40 wells during the second half. The new Company-operated battery at Mulligan, capable of processing 24,000 bpd of fluid, was commissioned on July 28th. Production from the complex is expected to grow by approximately 7,500 boepd during the second half of 2015. The Company is also testing several incremental large-scope opportunities with the second half drilling program, all of which, if successful, can access the Company’s existing infrastructure. Tourmaline’s 12 megawatt gas-fired electrical generation project at Spirit River will be fully operational and connected to the power grid by December of this year.

 

CORPORATE SUMMARY – SECOND QUARTER 2015

 

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

Tourmaline will host a conference call tomorrow, August 6, 2015 starting at 9:00 a.m. MDT (11:00 a.m. EDT). To participate, please dial 1-866-225-2055 (toll-free in North America), or local dial-in 416-340-8010, a few minutes prior to the conference call.

The conference call ID number is 4220222.

 

Reader Advisories

CURRENCY
All amounts in this news release are stated in Canadian dollars unless otherwise specified.

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

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

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

Also included in this press release are estimates of Tourmaline’s 2015 annual cash flow, capital spending and year-end net debt and net debt to cash flow levels as well as preliminary guidance on 2016 anticipated cash flows, which are based on the various assumptions as to production levels, including estimated average production of 164,500 boepd for 2015 and 215,000 boepd for 2016, capital expenditures, and other assumptions disclosed in this press release and including commodity price assumptions for natural gas (AECO – $3.20/mcf for 2015 and $3.75/mcf for 2016), and crude oil (WTI (US) – $56.17/bbl for 2015 and $68.01/bbl for 2016) and an exchange rate assumption of (US/CAD) $0.80 for 2015 and 2016. To the extent any such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Tourmaline on August 5, 2015 and is included to provide readers with an understanding of Tourmaline’s anticipated cash flows based on the capital expenditure and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.

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

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

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

 

Additional Reader Advisories

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

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

NON-GAAP FINANCIAL MEASURES
This press release includes references to financial measures commonly used in the oil and gas industry, “cash flow”, “operating netback”, “general and administrative cash costs” 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”, “general and administrative cash costs” and “net debt”, for its own performance measures and to provide shareholders and potential investors with a measurement of the Company’s efficiency and its ability to generate the cash necessary to fund a portion of its future growth expenditures or to repay debt. Readers are cautioned that the non-GAAP measures should not be construed as an alternative to net income determined in accordance with GAAP as an indication of the Company’s performance. See “Non-GAAP Financial Measures” in the attached Management’s Discussion and Analysis for the definition and description of these terms.

ESTIMATED DRILLING INVENTORY
This press release discloses drilling locations in four categories: (i) proved undeveloped locations; (ii) probable undeveloped locations; (iii) unbooked locations; and (iv) an aggregate total of (i), (ii) and (iii). Of the 700 undrilled locations disclosed in this press release, 6 are proved undeveloped locations, 0 are probable undeveloped locations and 694 are unbooked. Unbooked locations are internal estimates based on the Company’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company’s multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilledthere is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

CERTAIN DEFINITIONS:

  • bbl – barrel
  • bbl/mmcf – barrels per million cubic feet
  • bcf – billion cubic feet
  • bpd or bbl/d – barrels per day
  • boe – barrel of oil equivalent
  • boepd or boe/d – barrel of oil equivalent per day
  • bopd or bbl/d – barrel of oil, condensate or liquids per day
  • gj – gigajoule
  • gjs/d – gigajoules per day
  • mbbls – thousand barrels
  • mboe – thousand barrels of oil equivalent
  • mcf – thousand cubic feet
  • mcfpd or mcf/d – thousand cubic feet per day
  • mcfe – thousand cubic feet equivalent
  • mmboe – million barrels of oil equivalent
  • mmbtu – million British thermal units
  • mmbtu/d – million British thermal units per day
  • mmcf – million cubic feet
  • mmcfpd or mmcf/d – million cubic feet per day
  • mstboe – thousand stock tank barrels of oil equivalent
  • NGL – natural gas liquids

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

This management’s discussion and analysis (“MD&A“) should be read in conjunction with Tourmaline’s unaudited interim condensed consolidated financial statements and related notes as at and for the three and six months ended June 30, 2015 and the consolidated financial statements for the year ended December 31, 2014. Both the consolidated financial statements and the MD&A can be found at www.sedar.com. This MD&A is dated August 5, 2015.

The financial information contained herein has been prepared in accordance with International Financial Reporting Standards (“IFRS”) and sometimes referred to in this MD&A as Generally Accepted Accounting Principles (“GAAP”) as issued by the International Accounting Standards Board (“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, forecasts, estimates or beliefs concerning, among other things, an outlook on the estimated amounts and timing of capital investment or expenditures, anticipated future debt, expenses, production, cash flow and revenues or other expectations, beliefs, plans, objectives, assumptions, intentions or statements about future events or performance. These statements are only predictions and actual events or results may differ materially. Although Tourmaline believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies. 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 and uncertainty in market prices for crude oil, NGL and natural gas; industry conditions; currency fluctuation; imprecision of reserve estimates; liabilities inherent in crude oil, NGL and natural gas operations; environmental risks; incorrect assessments of the value of acquisitions and exploration and development programs; competition; the lack of availability of qualified personnel or management and skilled labour; changes in income tax laws and incentive programs relating to the oil and gas industry; hazards such as fire, explosion, blowouts, cratering, and spills, any of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; stock market volatility; ability to access sufficient capital from internal and external sources; the receipt of applicable regulatory or third party approvals; and the other risks considered under “Risk Factors” in Tourmaline’s most recent annual information form available at www.sedar.com.

With respect to forward-looking statements contained in this MD&A, Tourmaline has made assumptions regarding: future commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment and services; effects of regulation by governmental agencies; and future operating costs.

Management has included the above summary of assumptions and risks related to forward-looking information provided in this MD&A in order to provide readers with a more complete perspective on Tourmaline’s future operations and such information may not be appropriate for other purposes. Tourmaline’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that the Company will derive therefrom. Readers are cautioned that the foregoing lists of factors are not exhaustive.

These forward-looking statements are made as of the date of this MD&A and the Company disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

Boe Conversions – Per barrel of oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent (6:1). Barrel of oil equivalents (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, as the value ratio between natural gas and crude oil based on current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

 

PRODUCTION

Production for the three months ended June 30, 2015 averaged 143,634 boe/d, a 31% increase over the average production for the same quarter of 2014 of 109,953 boe/d. For the six months ended June 30, 2015, production increased 35% to 143,679 boe/d from 106,278 boe/d for the same period in 2014. Wells brought on stream via the Company’s exploration and production program accounted for approximately 90% of the growth in production volumes in 2015 over 2014, with the remainder of the change being from corporate and property acquisitions (net of dispositions). The slight increase in the natural gas weighting is mostly due to the sale of 25% of the Company’s oil producing assets in the Peace River High Complex in the fourth quarter of 2014 as well as a decrease in NGL production in the second quarter of 2015. Tourmaline processed less natural gas through the third-party deep-cut facility at Wild River during the quarter due to the current economics of propane and ethane.

Full-year average production guidance for 2015 remains unchanged at 164,500 boe/d (as disclosed in the Company’s press release dated March 9, 2015).

 

REVENUE

Revenue for the three months ended June 30, 2015 decreased 15% to $298.7 million from $350.5 million for the same quarter of 2014. Revenue for the six-month period ended June 30, 2015 decreased 11% from $699.8 million in 2014 to $620.0 million in 2015. Lower revenue for the period is consistent with the significant decrease in realized commodity prices, partially offset by higher production volumes and realized gains on energy marketing and hedging activities. Revenue includes all petroleum, natural gas and NGL sales and the realized gain (loss) on financial instruments.

The realized average natural gas price for the three and six months ended June 30, 2015 was $3.17/mcf and $3.42/mcf, which is 33% and 32% lower than the same periods of the prior year. The lower natural gas price reflects a lower AECO index (43%) experienced during the quarter. Included in the realized price is a gain on commodity contracts in the second quarter of 2015 of $26.4 million (six months ended June 30, 2015 – $84.3 million) compared to a loss of $13.9 million for the same period of the prior year (six months ended June 30, 2014 – $42.5 million). Realized gains on commodity contracts for the quarter and six months ended June 30, 2015 have increased compared to the same periods of the prior year as the market price of natural gas has weakened relative to the pricing per the commodity contracts in place. Realized prices exclude the effect of unrealized gains or losses on commodity contracts. Once these gains and losses are realized they are included in the perunit amounts.

Realized oil prices decreased by 26% and 30% for the three and six months ended June 30, 2015, which is consistent with the decrease in the benchmark price for crude oil during the quarter partially offset by a gain on commodity contracts in the second quarter of 2015 of $8.3 million (six months ended June 30, 2015 – $20.9 million). NGL prices decreased 55% from $38.57/bbl to $17.26/bbl, when compared to the same quarter of 2014. The decrease in NGL prices is consistent with the decrease in crude oil and natural gas prices over the period as well as oversupply in the propane market during the second quarter of 2015 leading to significantly reduced prices for that commodity.

 

ROYALTIES

For the quarter ended June 30, 2015, the average effective royalty rate was 1.9% compared to the rate of 10.0% for the same quarter of 2014. For the six-month period ended June 30, 2015, the average effective royalty rate decreased from 9.0% in 2014 to 4.0% in 2015. The decrease in the average effective royalty rate for 2015 can mostly be attributed to significantly lower commodity prices as well as natural gas deep drilling program credits received during the quarter. Royalty rates are impacted by changes in commodity prices whereby the actual royalty rate decreases when prices decrease. Additionally, during the second quarter of 2015, the Company received credits related to gas cost allowance, capital cost allowance and custom processing fees on natural gas production due to a true up of the royalty calculation by the Alberta Government. After removing the impact of these royalty credits, royalties for the three months ended June 30, 2015 would be $11.3 million with a royalty rate of 4.3% and for the six months ended June 30, 2015 royalties would be $26.9 million with a royalty rate of 5.2%.

The Company also continues to benefit from the New Well Royalty Reduction Program and the Natural Gas Deep Drilling Program in Alberta, as well as the Deep Royalty Credit Program in British Columbia.

The Company is forecasting the royalty rate for 2015 to be approximately 8%. The higher royalty rate reflects a higher forecast natural gas price as well as higher forecast oil price for the second half of 2015. The royalty rate is, however, sensitive to commodity prices and product mixes, and as such, a change in commodity prices or product mix will impact the actual rate.

 

OTHER INCOME

Other income increased from $4.5 million in the second quarter of 2014 to $5.6 million in 2015. For the six-month
period ended June 30, 2015, other income increased from $9.4 million in 2014 to $13.1 million in 2015. The
increase in other income is mainly due to the increase in processing capacity of Company-owned gas plants,
where fees are charged to working interest partners on Tourmaline-operated wells.

 

OPERATING EXPENSES

Operating expenses include all periodic lease and field-level expenses and exclude income recoveries from processing third-party volumes. For the second quarter of 2015, total operating expenses were $53.6 million compared to $52.4 million in 2014. Operating costs for the six months ended June 30, 2015 were $114.3 million, compared to $97.9 million for the same period in 2014, reflecting increased costs relating to the growing production base. These increases were offset by lower processing, gathering and compression fees which decreased from $15.1 million in the second quarter of 2014 to $10.2 million in the second quarter of 2015 and from $27.5 million to $23.7 million for the six months ended June 30, 2014 and 2015, respectively.

On a per-boe basis, the costs decreased from $5.24/boe for the second quarter of 2014 to $4.10/boe in the second quarter of 2015. For the six months ended June 30, 2015, operating costs were $4.40/boe, down from $5.09/boe in the prior year. The lower per-unit operating expense is mainly due to the decrease in third-party processing, gathering and compression fees, which were approximately $0.78/boe or 19% of total operating costs in the second quarter of 2015 compared to $1.51/boe or 29% of total operating costs in the same period of 2014. The Company’s significant investments in processing facilities in 2014 have reduced the volume of gas flowing to third-party facilities, leading to the reduction in operating expenses on a per-boe basis.

The Company expects its full year 2015 operating costs to average approximately $4.35/boe (as disclosed in the Company’s MD&A dated March 9, 2015). Actual costs per boe can change depending on a number of factors including the Company’s actual production levels.

 

TRANSPORTATION

For the second quarter of 2015, total transportation expenses were $26.1 million compared to $21.3 million in 2014. Transportation costs for the six months ended June 30, 2015 were $55.1 million, compared to $36.6 million for the same period in 2014, reflecting increased costs related to higher production volumes.

On a per-boe basis, the costs decreased from $2.13/boe for the second quarter of 2014 to $2.00/boe in the second quarter of 2015, reflecting a decrease in the proportion of oil and NGLs produced, which are generally more expensive to transport. For the six months ended June 30, 2015, transportation costs were $2.12/boe, up from $1.90/boe for the same period of 2014. This increase in year-to-date per-unit transportation costs is primarily due to NGL pipeline restrictions that were in place in the first quarter of 2015, which necessitated the use of more expensive truck transportation during that period. These NGL pipeline restrictions were not in place during the second quarter of 2015.

 

GENERAL & ADMINISTRATIVE EXPENSES (“G&A”)

The increase in gross G&A expenses in 2015 compared to 2014 is primarily due to staff additions needed to manage the larger production, reserve and land base. The Company increased its staff count by approximately 15% from June 2014 to June 2015. G&A expenses for the second quarter of 2015 were $6.0 million compared to $6.4 million for the same quarter of the prior year. G&A expenses for the six-month period ended June 30, 2015 were $12.2 million compared to $11.7 million for the same period in 2014. The lower total G&A expenses in the second quarter of 2015 compared to 2014 is due to higher administrative and capital recoveries billed to the Company’s joint-interest partners as the Company has a higher percentage of wells which it operates on behalf of its partners and, as such, is able to recover more of its G&A expenses.

On a per-boe basis, G&A expenses decreased from $0.64/boe for the second quarter of 2014 to $0.46/boe in the second quarter of 2015. For the six months ended June 30, 2015, G&A expenses were $0.47/boe, down from $0.61/boe in the prior year. The decrease per boe reflects Tourmaline’s growing production base which continues to increase at a faster rate than G&A costs.

G&A costs for 2015 are forecast to average approximately $0.60/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 2015, 760,000 stock options were granted to employees, officers, directors and key consultants at a weighted-average exercise price of $39.48 and 396,466 options were exercised, resulting in $8.4 million of cash proceeds.

The Company recognized $8.1 million of share-based payments expense in the second quarter of 2015 compared to $6.8 million in the second quarter of 2014. Capitalized share-based payments for the second quarter of 2015 were $8.1 million compared to $6.8 million for the same period of the prior year. Share-based payments are higher in 2015 compared to the same period in 2014 due to a higher number of options outstanding.

For the six months ended June 30, 2015, share-based payment expense totalled $16.4 million and a further $16.4 million in share-based payments were capitalized (six months ended June 30, 2014 – $13.5 million and $13.5 million, respectively). Share-based payments are higher in 2015 compared to the same periods in 2014, which reflects a higher number of options outstanding.

 

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

DD&A expense, excluding mineral lease expiries, was $155.8 million for the second quarter of 2015 compared to $121.4 million for the same period of 2014. For the six-month period ended June 30, 2015, DD&A expense (excluding mineral lease expiries) was $308.9 million compared to $229.3 million in the same period of 2014. The increase in DD&A expense in 2015 over 2014 is due to higher production volumes, as well as a larger capital asset base being depleted.

The per-unit DD&A rate (excluding the impact of mineral lease expiries) was $11.92/boe for the second quarter of 2015 compared to the rate of $12.13/boe for the same quarter in 2014. The per-unit DD&A rate (excluding the impact of mineral lease expiries) was $11.88/boe for the six-month period ended June 30, 2015 compared to the rate of $11.92/boe in the same period of the prior year.

Mineral lease expiries for the three months ended June 30, 2015 were $21.9 million, compared to expiries in the same quarter of the prior year of $5.7 million. For the six months ended June 30, 2015, expiries were $36.4 million compared with $13.3 million for the same period in 2014. The Company prioritizes drilling on what it believes to be the most cost-efficient and productive acreage, and with such a large land base, the Company has chosen not to continue some of the expiring sections of land.

 

FINANCE EXPENSES

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, 2015 totaled $11.0 million and $20.3 million respectively, compared to $7.5 million and $13.0 million for the same periods of 2014. The increase in finance expenses in 2015 over 2014 is mainly due to the higher average bank debt outstanding, partially offset by a lower average effective interest rate. The average bank debt outstanding for the six months ended June 30, 2015 was $1,173.3 million (June 30, 2014 – $602.5 million), with an average effective interest rate of 2.72% (2014 – 3.02%).

 

DEFERRED INCOME TAXES

For the three months ended June 30, 2015, the provision for deferred income tax expense was $40.9 million compared to $25.2 million for the same period in 2014. The increase is primarily due to the increase in the Alberta corporate tax rate legislated by Alberta’s new NDP government from 10% to 12% during the quarter, which was partially offset by lower pre-tax earnings recorded in the second quarter of 2015 compared to the respective period in 2014.

For the six months ended June 30, 2015, the provision for deferred income tax expense was $51.3 million compared to $58.1 million for the same period in 2014. The decrease is due to lower pre-tax earnings recorded for the six months ended June 30, 2015 compared to the respective period in 2014, which was partially offset by the increase in Alberta’s corporate tax rate.

 

CASH FLOW FROM OPERATING ACTIVITIES, CASH FLOW AND NET EARNINGS (LOSS)

Cash flow for the three months ended June 30, 2015 was $203.0 million or $0.95 per share compared to $231.5 million or $1.13 per diluted share for the same period of 2014. Cash flow for the six months ended June 30, 2015 was $410.8 million or $1.96 per share compared to $484.1 million or $2.41 per diluted share for the same period of 2014.

The Company had an after-tax loss for the three months ended June 30, 2015 of $5.2 million or $0.02 per share compared to net earnings of $66.4 million or $0.32 per diluted share for the same period of 2014. For the six-month period ended June 30, 2015, net earnings were $17.0 million or $0.08 per share compared to net earnings of $156.3 million or $0.78 per diluted share for the first half of 2014. The decrease in both cash flow and after-tax earnings in 2015 reflects significantly lower realized oil, natural gas and NGL prices, partially offset by an increase in production over 2014.

 

CAPITAL EXPENDITURES

During the second quarter of 2015, the Company invested $290.6 million of cash consideration, net of dispositions, compared to $297.7 million for the same period of 2014. Expenditures on exploration and production were $197.9 million compared to $288.4 million for the same quarter of 2014. During the six-month period ended June 30, 2015, the Company invested $788.0 million of cash consideration, net of dispositions, compared to $764.1 million for the same period in 2014. The drilling and completion costs of $386.3 million in 2015 include 6.25 more net wells drilled and completed over 2014 at a lower cost per well reflecting continuous improvement of capital efficiencies. Facilities expenditures include work on the new Mulligan oil battery, preliminary expenditures on the Spirit River Sour Gas Plant expansion and the new Edson Gas Plant, all scheduled to be commissioned in the second half of 2015 or early 2016.

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

 

LIQUIDITY AND CAPITAL RESOURCES

On March 12, 2015, the Company issued 640,000 flow-through common shares at a price of $50.00 per share, for total gross proceeds of $32.0 million. The proceeds were used to temporarily reduce bank debt and then to fund the Company’s 2015 exploration and development program.

On April 1, 2015, the Company purchased Perpetual Energy Inc.’s interests in the West Edson area of the Alberta Deep Basin with the issuance 6,750,000 shares at a closing price on that date of $38.32 per share, for total consideration of $258.7 million.

On June 23, 2015, the Company issued 4,947,500 common shares at a price of $39.50 per share for total gross proceeds of $195.4 million. The proceeds were used to temporarily reduce bank debt and to fund the Company’s 2015 exploration and development program.

The Company has a covenant-based, unsecured, bank credit facility in place with a syndicate of bankers. In June 2015, the Company increased the facility amount from $1,550.0 to $1,800.0 million. The term was also increased from three to four years, resulting in an initial maturity of June 2019. The credit facility also includes an expansion feature (“accordion”) which allows the Company, upon approval from the lenders, to increase the facility amount by up to $500.0 million by adding a new financial institution or by increasing the commitment of its existing lenders. With the exception of the increase in the facility amount, length of term and the addition of the accordion feature, the debt was renewed under the same terms and conditions as those outlined in note 9 of the Company’s consolidated financial statements for the year ended December 31, 2014. The Company also has a $50.0 million operating revolver, resulting in total bank credit facility capacity of $1,850.0 million. The maturity date may, at the request of the Company and with consent of the lenders, be extended on an annual basis. The facility can be drawn in either Canadian or U.S. funds and bears interest at the bank’s prime lending rate, banker’s acceptance rates or LIBOR (for U.S. borrowings), plus applicable margins, which range from 0.50% to 3.15% depending on the type of borrowing and the Company’s senior debt to adjusted EBITDA ratio.

The Company also has a five-year term loan agreement with a Canadian Chartered Bank for $250.0 million, bearing an interest rate of 240 basis points over the applicable bankers’ acceptance rate. The covenants for the term loan are similar to those under the Company’s current credit facility and the term loan will rank equally with the obligations under the Company’s credit facility.

As at June 30, 2015, the Company had negative working capital of $86.1 million, after adjusting for the fair value of financial instruments (the unadjusted working capital deficiency was $70.2 million) (December 31, 2014 – $223.7 million and $189.9 million, respectively). As at June 30, 2015, the Company had $248.7 million in long-term debt outstanding and $948.7 million drawn against the revolving credit facility for total bank debt of $1,197.4 million (net of prepaid interest and debt issue costs) (December 31, 2014 – $918.9 million). Net debt was $1,283.5 million (December 31, 2014 – $1,142.5 million). Management believes the Company has sufficient liquidity and capital resources to fund the remainder of its 2015 exploration and development programs through expected cash flow from operations and its unutilized borrowing capacity.

 

SHARES AND STOCK OPTIONS OUTSTANDING

As at August 5, 2015, the Company has 216,461,865 common shares outstanding and 17,179,414 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, 2014.

As at June 30, 2015, the Company has entered into certain financial derivative contracts in order to manage commodity price 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 (loss) and comprehensive income (loss). The contracts that the Company has in place at June 30, 2015 are summarized and disclosed in note 3 of the Company’s unaudited interim condensed consolidated financial statements for the three and six months ended June 30, 2015 and 2014.

The Company has entered into physical delivery sales contracts to manage commodity risk. These contracts are considered normal sales contracts and are not recorded at fair value in the consolidated financial statements. Physical contracts in place at June 30, 2015 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, 2015 and 2014.

Physical delivery contracts entered into subsequent to June 30, 2015 are detailed in note 3 of the Company’s unaudited interim condensed consolidated financial statements for the three and six months ended June 30, 2015 and 2014.

There were no financial derivative contracts entered into subsequent to June 30, 2015.

 

APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Management reviews its estimates on a regular basis. The emergence of new information and changed circumstances may result in actual results or changes to estimates that differ materially from current estimates. The Company’s use of estimates and judgments in preparing the interim condensed consolidated financial statements is discussed in note 1 of the consolidated financial statements for the year ended December 31, 2014.

 

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING

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

There were no changes in the Company’s DC&P or ICFR during the period beginning on April 1, 2015 and ending on June 30, 2015 that have materially affected, or are reasonably likely to materially affect, the Company’s ICFR. It should be noted that a control system, including the Company’s disclosure and internal controls and procedures, no matter how well conceived can provide only reasonable, but not absolute assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

In May 2013, the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) issued an updated Internal Control-Integrated Framework (“2013 Framework”) replacing the Internal Control-Integrated Framework (1992). Tourmaline adopted the 2013 Framework for the year ended December 31, 2014.

 

BUSINESS RISKS AND UNCERTAINTIES

Tourmaline monitors and complies with current government regulations that affect its activities, although operations may be adversely affected by changes in government policy, regulations or taxation. In addition, Tourmaline maintains a level of liability, property and business interruption insurance which is believed to be adequate for Tourmaline’s size and activities, but is unable to obtain insurance to cover all risks within the business or in amounts to cover all possible claims.

See “Forward-Looking Statements” in this MD&A and “Risk Factors” in Tourmaline’s most recent annual information form for additional information regarding the risks to which Tourmaline and its business and operations are subject.

 

IMPACT OF 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 the sum of drawn amounts on the credit facility, the term loan and outstanding letters of credit less cash and cash equivalents and excluding debt issue costs (“bank debt”), “total debt” means generally the sum of “senior debt” plus subordinated debt, Tourmaline currently does not have any subordinated debt, and “total capitalization” means generally the sum of the Company’s shareholders’ equity and all other indebtedness of the Company including bank debt, all determined on a consolidated basis in accordance with GAAP.

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

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 74,796 boe per day in 2013 to 112,929 boe per day in 2014 and 143,679 boe per day in the first six months of 2015. The production growth can be attributed primarily to the Company’s exploration and development activities, and from acquisitions of producing properties. The slight decrease in production in the second quarter of 2015, from the first quarter of 2015, is due to unplanned third party maintenance by TCPL on the Edson, Alberta lateral and by Spectra on the T North B.C. system. Similar-type unplanned downtime was experienced in the same period of 2014 where there was unscheduled third-party maintenance, equipment issues and downtime at Musreau, the Saturn deep-cut facility, as well as downtime on the TCPL mainline pipeline.

The Company’s cash flow was $526.8 million in 2013, $929.0 million in 2014, and 2015 forecast cash flow is $982.1 million, reflecting the strong production growth year over year. 2015 cash flow to date has been significantly impacted by the drop in commodity prices. Commodity price fluctuations can indirectly impact expected production by changing the amount of funds available to reinvest in exploration, development and acquisition activities in the future. Changes in commodity prices impact revenue and cash flow available for exploration, and also the economics of potential capital projects as low commodity prices can potentially reduce the quantities of reserves that are commercially recoverable. The Company’s capital program is dependent on cash flow generated from operations and access to capital markets.

 

CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

 

CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

 

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

 

CONSOLIDATED STATEMENTS OF CASH FLOW

 

NOTES TO THE INTERIM CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS

AS AT JUNE 30, 2015 AND FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2015 AND 2014
(tabular amounts in thousands of dollars, unless otherwise noted) (unaudited)


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

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

 

1. BASIS OF PREPARATION

These unaudited interim condensed consolidated financial statements have been prepared in accordance with International Accounting Standard (“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, 2014.

The accounting policies and significant accounting judgments, estimates, and assumptions used in these unaudited interim condensed consolidated financial statements are consistent with those described in Notes 1 and 2 of the Company’s consolidated financial statements for the year ended December 31, 2014. The unaudited interim condensed consolidated financial statements were authorized for issue by the Board of Directors on August 5, 2015.

 

2. DETERMINATION OF FAIR VALUE

A number of the Company’s accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability Tourmaline classifies the fair value of transactions according to the following hierarchy based on the amount of observable inputs used to value the instrument.

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

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

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

The fair value of cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities approximate their carrying amounts due to their short term nature. Bank debt bears interest at a floating market rate with applicable variable margins, and accordingly the fair market value approximates the carrying amount. The Company’s financial instruments have been assessed on the fair value hierarchy described above and classified as Level 2.

 

3. FINANCIAL RISK MANAGEMENT

The Board of Directors has overall responsibility for the establishment and oversight of the Company’s risk management framework. The Board has implemented and monitors compliance with risk management policies. The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities. The Company’s financial risks are consistent with those discussed in note 5 of the Company’s consolidated financial statements for the year ended December 31, 2014.

As at June 30, 2015, the Company has entered into certain financial derivative contracts in order to manage commodity price 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 (loss) and comprehensive income (loss).

The Company has the following financial derivative contracts in place as at June 30, 2015 (1):

In addition to the financial commodity contracts discussed above, the Company has entered into physical delivery sales contracts to manage commodity risk. These contracts are considered normal sales contracts and are not recorded at fair value in the consolidated financial statements.

The Company has the following physical contracts in place at June 30, 2015 (1)(6):

 

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.

Impairment Assessment
In accordance with IFRS, an impairment test is performed if the Company identifies an indicator of impairment. At June 30, 2015 and December 31, 2014, the Company determined that no indicators of impairment existed on its E&E assets; therefore, an impairment test was not performed.

 

5. PROPERTY, PLANT AND EQUIPMENT

Cost

Future development costs of $4,948.2 million were included in the depletion calculation at June 30, 2015 (December 31, 2014 – $4,610.0 million).

Capitalization of G&A and Share-Based Payments
A total of $11.3 million in G&A expenditures have been capitalized and included in E&E and PP&E assets at June 30, 2015 (December 31, 2014 – $19.3 million). Also included in E&E and PP&E are non-cash share-based payments of $16.4 million (December 31, 2014 – $28.8 million).

Impairment Assessment
In accordance with IFRS, an impairment test is performed on a CGU if the Company identifies an indicator of impairment. At June 30, 2015, the Company determined that no indicators of impairment existed on any of the Company’s CGUs; therefore an impairment test was not performed.

For the year ended December 31, 2014, the Company identified indicators of impairment on two of its CGUs based on the decline in commodity prices and performed impairment tests accordingly. The Company determined that there was no impairment to PP&E at December 31, 2014.

Business Combination
On April 1, 2015, the Company acquired Perpetual Energy Inc.’s (“Perpetual”) interests in the West Edson area of the Alberta Deep Basin with the issuance of 6,750,000 Tourmaline shares at a price of $38.32 per share for total consideration of $258.7 million. The interests include Perpetual’s land interests, production, reserves and facilities that were jointly-owned with Tourmaline.

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

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 (loss) and comprehensive income (loss).

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:

Acquisition of Oil and Natural Gas Properties
For the six months ended June 30, 2015, the Company completed property acquisitions including swaps for total cash consideration of $90.4 million (December 31, 2014 – $33.0 million) and an additional $325.0 million in non-cash consideration (December 31, 2014 – $2.2 million) of which $258.7 million related to the Perpetual transaction. The Company also assumed $4.9 million in decommissioning liabilities (December 31, 2014 – $4.9 million).

Disposition of Oil and Natural Gas Properties
On December 23, 2014, the Company completed the sale of a 25% working interest in its Peace River High complex for cash consideration of $500.0 million (before customary adjustments) to Canadian Non-Operated Resources Corp. (“CNOR”). The net book value of oil and natural gas properties disposed was $236.5 million and the gain on disposition was $266.2 million. The Company will continue to be the operator of all jointly-owned assets. Under the terms of the arrangement, the Company has committed to spend $400.0 million gross ($300.0 million net) per year over the next five years. The committed capital expenditures can be deferred to future periods in the event of an economic downturn, and as agreed upon by both parties. As part of the capital commitment, the Company also agreed to carry CNOR for the first $87.1 million spent (CNOR share) on specified capital projects. At June 30, 2015, approximately $1.5 million remained to be spent on these specified projects.

 

6. DECOMMISSIONING OBLIGATIONS

The Company’s decommissioning obligations result from net ownership interests in petroleum and natural gas assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted amount of cash flow required to settle its decommissioning obligations is approximately $168.7 million (December 31, 2014 – $157.5 million), with some abandonments expected to commence in 2021. A risk-free rate of 2.31% (December 31, 2014 – 2.36%) and an inflation rate of 1.8% (December 31, 2014 – 2.0%) were used to calculate the decommissioning obligations.

 

7. BANK DEBT

The Company has a covenant-based, unsecured, bank credit facility in place with a syndicate of bankers. In June 2015, the Company increased the facility amount from $1,550.0 to $1,800.0 million. The term was also increased from three to four years, resulting in an initial maturity of June 2019. The credit facility also includes an expansion feature (“accordion”) which allows the Company, upon approval from the lenders, to increase the facility amount by up to $500.0 million by adding a new financial institution or by increasing the commitment of its existing lenders. With the exception of the increase in the facility amount, length of term and the addition of the accordion feature, the debt was renewed under the same terms and conditions as those outlined in note 9 of the Company’s consolidated financial statements for the year ended December 31, 2014. The Company also has a $50.0 million operating revolver, resulting in total bank credit facility capacity of $1,850.0 million. The maturity date may, at the request of the Company and with consent of the lenders, be extended on an annual basis. The facility can be drawn in either Canadian or U.S. funds and bears interest at the bank’s prime lending rate, banker’s acceptance rates or LIBOR (for U.S. borrowings), plus applicable margins, which range from 0.50% to 3.15% depending on the type of borrowing and the Company’s senior debt to adjusted EBITDA ratio.

The Company also has a $250.0 million five-year term loan with a Canadian Chartered Bank, the details of which are described in note 9 of the Company’s consolidated financial statements for the year ended December 31, 2014.

As at June 30, 2015, the Company had $248.7 million in long-term debt outstanding and $948.7 million drawn against the bank credit facility for total bank debt of $1,197.4 million (net of prepaid interest and debt issue costs) (December 31, 2014 – $918.9 million). In addition, Tourmaline has outstanding letters of credit of $6.6 million (December 31, 2014 – $2.4 million), which reduce the credit available on the facility. The effective interest rate for the six months ended June 30, 2015 was 2.72% (six months ended June 30, 2014 – 3.02%). As at June 30, 2015, the Company is in compliance with all debt covenants.

 

8. NON-CONTROLLING INTEREST

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

 

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 17,013,364 and 10,602,666 options excluded from the weighted-average share calculations for the three and six month periods ended June 30, 2015 because they were anti-dilutive (three and six months ended June 30, 2014 – 1,366,000 options, respectively).

 

11.SHARE-BASED PAYMENTS

The Company has a rolling stock option plan. Under the employee stock option plan, the Company may grant options to its employees up to 21,637,792 shares of common stock, which represents 10% of the current outstanding common shares. The exercise price of each option equals the volume-weighted average market price for the five days preceding the issue date of the Company’s stock on the date of grant and the option’s maximum term is five years. Options are granted throughout the year and vest 1/3 on each of the first, second and third anniversaries from the date of grant.

 

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.

 

13. DEFERRED INCOME TAX

Effective July 1, 2015, the Alberta provincial corporate tax rate increased from 10% to 12%. As a result, deferred income tax expense and deferred income tax liability increased by $29.5 million for the three and six month periods ended June 30, 2015.

 

14.SUBSEQUENT EVENTS

On June 29, 2015, the Company entered into an agreement to acquire 100% of the common shares of Mapan Energy Ltd. (“Mapan”) with the issuance of 2.73 million Tourmaline common shares at a price of $38.82 per Tourmaline share based on the five-day volume-weighted average price ending June 26, 2015, for consideration of approximately $106.0 million. The completion of the arrangement, which is anticipated to occur in August 2015, is subject to, among other things, the approval of at least two-thirds of the votes cast by Mapan shareholders voting at an annual and special meeting to be held in August 2015.

 

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) “Cash flow” is defined as cash provided by operations before changes in non-cash operating working capital. See “Non-GAAP Financial Measures” below and in the attached Management’s Discussion and Analysis.
(2) “General and administrative cash costs” is defined as general and administrative costs excluding interest and financing charges. See “Non-GAAP Financial Measures” below and in the attached Management’s Discussion and Analysis.
(3) “Net debt” is defined as long-term debt plus working capital (adjusted for the fair value of financial instruments). See “Non-GAAP Financial Measures” below and in the attached Management’s Discussion and Analysis.