CALGARY, AB, March 10, 2021 /CNW/ – Tourmaline Oil Corp. (TSX: TOU) (“Tourmaline” or the “Company”) is pleased to release financial and operating results for the full year and fourth quarter of 2020 as well as 2020 reserves.
- Achieved record production in Q4 2020, exiting 2020 producing in excess of 400,000 boepd.
- Achieved a record 2P reserve addition of 826.0 mmboe in 2020 with finding, development and acquisition (“FD&A”) costs of $3.80/boe, including changes in future development capital (“FDC”).
- Fourth quarter 2020 cash flow(1)was $396.9 million ($1.44 per diluted share) and full-year 2020 cash flow was $1,185.7 billion ($4.36 per diluted share). Fourth quarter 2020 free cash flow(2) was $144.8 million.
- In 2021, at current strip pricing(3), the Company expects to generate cash flow of $2.2 billion and free cash flow of $1.1 billion on EP capital spending of $1.075 billion.
- Increased the dividend in 2020 despite a difficult year for Industry – the fourth increase since inception of the dividend in 2018. Given stronger than anticipated cash flow in future years, the Company is increasing its dividend by 14% from $0.14 per share per quarter to $0.16 per share per quarter, commencing in the first quarter of 2021.
- Completed four accretive corporate acquisitions in 2020 that are estimated to have increased the five-year plan free cash flow generation by over 20% or approximately $200 million per annum starting in 2022.
- Delivered full-year 2020 earnings of $618.3 million, underscoring the inherent profitability of the Company’s business model.
- Tourmaline received an ‘A’ rating in the MSCI Global ESG Performance Ranking for its sustainability and environmental initiatives.
- Current production is averaging between 405,000-410,000 boepd, at the higher end of the full-year guidance range of 390,000-410,000 boepd. Despite higher commodity prices, the Company is maintaining previously disclosed production guidance for 2021. The Company expects Q1 2021 average production of between 400,000 and 405,000 boepd.
- Q4 2020 average production was 336,325 boepd, and full-year 2020 average production was 310,598 boepd, both within guidance.
- Natural gas production is forecast to average approximately 1.85-1.9 bcf/day in 2021 and combined oil, condensate, and NGL production is expected to average approximately 85,000-90,000 bpd in 2021. Tourmaline is Canada’s largest natural gas and NGL producer, and the second largest condensate producer.
- All three operated EP complexes have achieved production records during Q1 2021: the Alberta Deep Basin complex is currently producing 252,000 boepd, NEBC is producing 135,000 boepd, and the Peace River High complex is producing 23,000 boepd.
- Full-year 2020 after-tax earnings were $618.3 million ($2.27 per diluted share) as Tourmaline remained profitable despite a challenging year for Industry.
- Fourth quarter 2020 cash flow was $396.9 million ($1.44 per diluted share) and full-year 2020 cash flow was $1,185.7 billion ($4.36 per diluted share).
- Tourmaline generated $273.9 million in free cash flow in 2020.
- Despite a global pandemic and an oil price crash in 2020, Tourmaline increased its dividend from 12 cents per share per quarter to 14 cents which was fully funded from free cash flow generated in 2020.
- Tourmaline continued to effectively manage all-in cash costs in 2020 (operating, transportation, general and administrative, and financing) which totaled $8.60/boe, compared with $8.18/boe in 2019 with a slight increase as a result of the corporate acquisitions which carried higher cash costs. Operating costs on the acquired assets are expected to trend down in 2021-2022.
- Achieved a public investment grade credit rating allowing the Company to issue $250 million of debt at a fixed rate of 2.077% for seven years.
- Topaz Energy Corp. (“Topaz”) successfully completed its initial public offering in 2020 with the market value of Tourmaline’s 51.7% equity ownership of Topaz at December 31, 2020 valued at $790.8 million based on a December 31, 2020 closing price for Topaz common shares of $13.60 per share.
2020/2021 BUDGET AND OUTLOOK
- 2020 Q4 EP capital spending was $243.6 million, full-year 2020 EP spending was $878.8 million.
- Tourmaline accelerated two large frac operations at Spirit River, AB and Doe, NEBC from January 2021 to December 2020 primarily for logistical reasons, avoiding the anticipated post year-end industry frac activity ramp-up. The Company also increased planned Q4 drilling activities on the Jupiter and Modern assets post acquisition as well as at Sundown and Birley-Laprise, B.C. Completing these field activities earlier than originally planned also provided Tourmaline with additional winter 2021 gas volumes, allowing the Company to further benefit from the price spikes that occurred. As a result of these accelerated expenditures into 2020, the 2021 EP capital budget has been reduced by $25 million, from $1.10 billion to $1.075 billion.
- Tourmaline generated cash flow of $396.9 million and free cash flow of $144.8 million in Q4 2020 on EP capital spending of $243.6 million.
- In 2021, at current strip pricing, the Company expects to generate cash flow of $2.2 billion and free cash flow of $1.1 billion on EP capital spending of $1.075 billion. The free cash flow in 2021 will be designated for debt reduction, potential dividend increases, selective acquisitions, capital investment in emission reduction technologies, and potential share buybacks.
- The $1.075 billion 2021 capital budget consists of approximately $900 million of maintenance capital, required to keep production flat at 400,000 boepd, and $175 million directed towards realizing the unchanged 3-5% annual growth outlined in the five-year development plan. The Gundy, B.C. Phase 2 deep cut expansion remains the only significant new project in the five-year plan. $100 million of the $175 million in available incremental capital for 2021 is directed to the Phase 2 deep cut facility construction. The new facility will commence production in Q2 2022 (200 mmcfpd, 15,000 bpd condensate and liquids) and is strategically tied to an increase in gas transportation capacity to California commencing in 2022 and 2023.
- In the updated five-year plan, Tourmaline expects to generate $4.1 billion of free cash flow at strip pricing over the five years.
- Strong natural gas prices, coupled with the Company’s long evolving market diversification strategy, will result in materially stronger Q1 2021 cash flows than originally anticipated.
- Current full-year 2021 net debt(4)to cash flow is now expected to be 0.4 times. Tourmaline expects to reduce debt to its target total debt amount of $1.3 billion in 2H 2021, after which free cash flow allocation will shift to potential dividend increases, accretive acquisitions, capital investment in emission reduction technologies and potential share buybacks.
- Tourmaline increased 2P reserves to 3.31 billion boe in 2020 at historically low FD&A costs.
- Year-end 2020 proved, developed producing (“PDP”) reserves of 736.4 million boe were up 61.2 per cent over year-end 2019 when including 2020 annual production of 113.7 million boe. Total proved (“TP”) reserves of 1.7 billion boe were up 39.4 per cent when including 2020 annual production. 2P reserves of 3.31 billion boe were up 31.7 per cent including 2020 annual production.
- Tourmaline’s 2020 PDP FD&A costs were $5.46 per boe including changes in FDC, a record low, yielding a PDP reserve recycle ratio(5)of 1.91. Total proved FD&A costs in 2020 were $4.86 per boe including changes in FDC, and 2P FD&A was $3.80 per boe including changes in FDC. The 2P FD&A recycle ratio was 2.7 in 2020.
- Tourmaline replaced 727% of its 2020 annual production of 113.7 million boe in 2020 with 2P additions of 826.0 million boe before 2020 production.
- Tourmaline’s 2P reserve value(6)equates to $57.95 per diluted share using the January 1, 2021 engineering price deck and a 10% discount rate. TP reserve value is $35.03 per diluted share and PDP reserve value is $20.17 per diluted share using the same pricing and discount rates.
- After 12 years of operation, Tourmaline now has 15.5 trillion cubic feet of 2P natural gas reserves, one of the largest, lowest-development cost, lowest-emission natural gas reserve bases in North America as well as 738 million barrels of 2P crude oil, condensate, and NGL (natural gas liquids) reserves (January 1, 2021).
- Tourmaline has only booked 2,579 (gross) locations of a total drilling inventory of 20,014 gross locations (13% per cent of the overall inventory) to achieve year-end 2020 2P reserves of 3.31 billion boe.
- For the eighth consecutive year, the Company enjoyed positive 2P technical revisions in its reserve report.
- Tourmaline has an average of 567 mmcfpd hedged for 2021 at a weighted-average fixed price of CAD $2.64/mcf; an average of 129 mmcfpd hedged at a basis to NYMEX of $(0.01) USD/mcf; and an average of 502 mmcfpd incremental volume exposed to export markets, including Dawn, Iroquois, Empress, Chicago, Ventura, Sumas, Malin and PG&E.
- Natural gas fundamentals for 2021 and 2022 are steadily improving. Approximately 61% of Tourmaline’s natural gas volumes are exposed to spot prices in markets on the Western half of the continent (PG&E, Malin, Sumas, Station 2, AECO) where 2021 fundamentals continue to be most supportive.
- At PG&E, 95% of the total deliveries remain unhedged for 2021 at a market where forward prices continue to be strong.
- Tourmaline has sales diversification to the US and other hubs of 584 mmcfpd for exit 2021, 705 mmcfpd for exit 2022 and 755 mmcfpd for exit 2023. The Company’s diversified transportation portfolio, with associated direct sale opportunities, allowed for considerable realized price and cash flow benefits during the February 2021 cold snap.
- The Company will continue to hedge volumes related to 2021 and 2022 over the next several months.
- Tourmaline had 4 bcf of natural gas in storage facilities at Dawn, Ontario and PG&E, San Francisco which was fully withdrawn as the Company took advantage of the higher natural gas prices.
- Tourmaline operated 12 drilling rigs and three to four frac spreads across the three operated core EP complexes in January and February – activity is now tapering into spring breakup.
- The Company expects to drill and complete a total of approximately 225 (gross) wells during 2021.
- During 2020, the Company systematically drilled longer horizontals in all three complexes. Average horizontal well laterals were 16% longer, however, average drilling costs for these longer wells in 2020 were down on average 6% across all three complexes. Total completion costs for the longer horizontal wells were down 14% over 2019 levels, on a completed lateral meter basis.
- Tourmaline accelerated the completion and stimulation of the Spirit River 6-10-78-8 W6 pad from January 2021 to December 2020. The seven well Montney and Lower Charlie Lake pad has significantly exceeded performance curve expectations and is producing at a combined rate of 3,365 bpd of light crude oil and 31.4 mmcfpd of natural gas after 68 days of production. Five of the seven wells on the pad rank as the top five oil wells in Alberta for January 2021, based on calendar-day production rates and were brought on-stream during a period of increasing oil and natural gas prices.
- Tourmaline elected to complete the Phase 1 expansion of the Sundown, B.C. Montney project during the second half of 2020. During the past five years, the Company has been steadily expanding the land position at Sundown, steadily dropping drill/complete capital costs and dropping operating expenses to less than $2.00/boe. The Company expanded the existing gas processing facility at Sundown and drilled one five-well pad during Q4 2020, bringing on an incremental 40 mmcfpd at a capital efficiency of $4,500/boepd, including facility costs. The Sundown facility is now producing at 120 mmcfpd; the next expansion phase will grow production to 250 mmcfpd at similar capital efficiencies. This second expansion is not currently in the five-year development plan. Current Sundown 2P reserves are 1.0 TCF of natural gas, with 90 locations included in the Company’s reserve report and an estimated 857 locations remaining in inventory.
- The Company continues to realize the anticipated 30-40% capital cost reduction for drilling and completion activities on the acquired Jupiter and Modern assets in the Alberta Deep Basin complex.
SUSTAINABILITY AND ENVIRONMENTAL PERFORMANCE IMPROVEMENT
- Tourmaline won independent awards in 2020 for ongoing successful efforts to reduce emissions through diesel displacement and for water management activities that ultimately eliminate freshwater usage in frac operations. The Company achieved an Industry ‘A’ rating in the most recent MSCI Global ESG Performance ranking.
- Tourmaline has had an engineering team in place for over 18 months developing and implementing new proprietary emission reduction technologies, executing expanded water management initiatives, managing third-party environmental related research, and more recently managing an emerging carbon offset business.
- Tourmaline is operating a methane testing and research facility, the only one in Canada, at one of the Company’s Ansell-Edson gas processing facilities. This site will evolve technology that more accurately measures fugitive, flare and storage emissions as well as drives towards zero methane emission well sites.
- Tourmaline has invested $8.0 million to date building proprietary units for the Company’s broad diesel displacement initiatives. The long-term goal is to transition all drilling and frac operations to much lower emission emitting natural gas, or where possible, highline power/electricity. The Company’s rig in the Peace River High area is fully electric, operating solely off highline power. The cost savings realized from reduced diesel in drilling operations this January alone were $1.8 million. To date, the Company has displaced 34.6 million litres of diesel with a net savings of $28.0 million including the cost of the replacement natural gas. On an energy equivalent basis, natural gas emits 30% less CO2, 90% less carbon monoxide, 95% less nitrogen dioxide, 90% less particulate matter, and 99% less sulfur dioxide than diesel. The go-forward, longer-term costs savings, are expected to be well over $75 million from this initiative which also provides a major contribution towards the corporate goal of reducing CO2 emission intensity by over 25% in the next five years.
- Tourmaline was the most active operator in the WCSB in 2020 during the pandemic, employing as many people as possible in the service sector and in the rural communities of Alberta and British Columbia while continuing to safely, effectively and efficiently manage operations.
- During the global pandemic in 2020, Tourmaline made multiple foodbank, United Way, and youth development charitable donations totaling over $1 million assisting people in need in Calgary, Edson, Hinton, Grande Prairie, Spirit River, and Fort St. John.
- Tourmaline was one of the few senior Canadian producers that did not reduce its dividend, recognizing the broad shareholder base and many individuals who rely on the dividend for necessary income, accentuated during the COVID-19 crisis.
- The Company is pleased to announce that its Board of Directors has declared a quarterly cash dividend on its common shares of C$0.16 per common share. The dividend will be payable March 31, 2021 to shareholders of record at the close of business on March 18, 2021. This quarterly cash dividend is designated as an “eligible dividend” for Canadian income tax purposes.
|(1)||“Cash flow” is defined as cash provided by operations before changes in non-cash operating working capital. See “Non-GAAP Financial Measures” in this news release and in the Company’s 2020 Management’s Discussion and Analysis.|
|(2)||“Free cash flow” is defined as cash flow less total net capital expenditures. Total net capital expenditures is defined as total capital spending before acquisitions, net of non-core dispositions. Free cash flow is prior to dividend payments. See “Non-GAAP Financial Measures” in this news release and the Company’s 2020 Management’s Discussion and Analysis.|
|(3)||Based on oil and gas commodity strip pricing at March 1, 2021.|
|(4)||See “Non-GAAP Financial Measures” in this news release and in the Company’s Management’s Discussion and Analysis for the year ended December 31, 2020.|
|(5)||The recycle ratio is calculated by dividing the cash flow per boe by the appropriate F&D or FD&A costs related to the reserve additions for that year.|
|(6)||2P reserve value per share is calculated as the before tax net present value of the reserves at December 31, 2020 discounted at 10% divided by total diluted shares outstanding at December 31, 2020.|
CORPORATE SUMMARY – DECEMBER 31, 2020
|Three Months Ended December 31,||Twelve Months Ended December 31,|
|Natural gas (mcf/d)||1,592,010||1,439,746||11%||1,476,613||1,413,160||4%|
|Crude oil, condensate and NGL (bbl/d)||70,990||59,886||19%||64,496||55,338||17%|
|Oil equivalent (boe/d)||336,325||299,844||12%||310,598||290,865||7%|
|Natural gas ($/mcf)||$||3.19||$||2.77||15%||$||2.68||$||2.59||3%|
|Crude oil, condensate and NGL ($/bbl)||$||33.85||$||38.59||(12)%||$||30.87||$||39.29||(21)%|
|Operating expenses ($/boe)||$||3.25||$||3.06||6%||$||3.14||$||3.28||(4)%|
|Transportation costs ($/boe)||$||4.42||$||4.13||7%||$||4.48||$||3.86||16%|
|Operating netback(3) ($/boe)||$||13.65||$||13.00||5%||$||10.93||$||12.12||(10)%|
|Cash general and
administrative expenses ($/boe)(2)
($000, except share and per share)
|Total revenue from commodity sales and realized gains||688,374||579,588||19%||2,174,903||2,127,337||2%|
|Cash flow per share (diluted)(4)||$||1.44||$||1.24||16%||$||4.36||$||4.43||(2)%|
|Net earnings per share (diluted)||$||2.28||$||0.23||891%||$||2.27||$||1.18||92%|
|Capital expenditures (net of dispositions)||271,284||320,389||(15)%||1,083,625||1,287,259||(16)%|
|Weighted average shares outstanding (diluted)||272,079,590||271,878,824||-%|
|Natural gas (bcf)||15,459.2||12,294.6||26%|
|Crude oil (mbbls)||102,843||96,984||6%|
|Natural gas liquids (mbbls)||634,890||455,851||39%|
|(1)||Product prices include realized gains and losses on risk management activities and financial instrument contracts.|
|(2)||Excluding interest and financing charges.|
|(3)||Reserves are “Company gross reserves”, which are defined as the working interest share of reserves prior to the deduction of interest owned by others (burdens). Royalty interest reserves are not included in Company gross reserves.|
|(4)||See “Non-GAAP Financial Measures” in this news release and in the Company’s Management’s Discussion and Analysis for the year ended December 31, 2020.|
2020 RESERVE SUMMARY
The following tables summarize the Company’s gross reserves defined as the working interest share of reserves prior to the deduction of interest owned by others (burdens). Royalty interest reserves are not included in Company gross reserves. Company net reserves are defined as the working net carried and royalty interest reserves after deduction of all applicable burdens.
Tourmaline’s Reserves and Net Present Values of Future Net Revenue disclosed in this news release include the full impact of the sale of certain assets to Topaz Energy Corp. (“Topaz”) notwithstanding Tourmaline’s 51.7% ownership interest in Topaz. The Net Present Values of Future Net Revenue on a Total Proved Plus Probable basis (discounted at a rate of 10%) would increase by approximately 6.5% had the Topaz transaction not occurred. On a Proved Producing and Total Proved basis, the Net Present Values of Future Net Revenue (discounted at a rate of 10%) would increase by approximately 8.5% and 7.6%, respectively. Refer to the General Development of the Business section in the Company’s recently filed Annual Information Form for further details.
Reserves and Future Net Revenue Data (Forecast Prices and Costs)
|Summary of Crude Oil, Natural Gas and Natural Gas Liquids Reserves and
Net Present Values of Future Net Revenue
as of December 31, 2020
Forecast Prices and Costs(1)
|Light & Medium Crude
|Shale Natural Gas(2)||Natural Gas Liquids||Total Oil Equivalent|
|Reserves Category||Company Gross
|Proved Developed Non-Producing||1,791||1,430||86,881||79,270||174,689||154,455||10,365||9,203||55,750||49,587|
|Total Proved Plus Probable||102,843||87,296||7,783,684||7,123,950||7,675,505||6,644,073||634,890||556,731||3,314,264||2,938,698|
|Net Present Values of Future Net Revenue ($000s)|
|Before Income Taxes Discounted at (2)
|After Income Taxes Discounted at (2) (3)
|Unit Value Before Income Tax Discounted at 10%/year|
|Proved Developed Non-Producing||763,691||592,722||523,565||486,385||414,782||363,460||606,060||512,097||468,528||443,379||390,975||349,840||9.81||1.63|
|Total Proved Plus Probable||40,124,699||24,789,010||19,704,403||17,223,156||12,925,150||10,225,520||32,997,511||20,755,796||16,654,183||14,642,731||11,138,617||8,920,267||5.86||0.98|
|(1)||Numbers may not add due to rounding.|
|(2)||Shale Natural Gas is required to be presented separately from Conventional Natural Gas as its own product type pursuant to National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). While the Tourmaline Montney reserves do not strictly fit the definition of “shale gas” as defined in NI 51-101 because the natural gas is not “primarily adsorbed” as stated within the definition, the Montney reserves have been included as shale gas for purposes of this disclosure.|
|(3)||The after-tax net present value of the Company’s oil and gas properties reflects the tax burden on the properties on a stand-alone basis. It does not consider the Company’s tax situation, or tax planning. It does not provide an estimate of the value at the Company level which may be significantly different. The Company’s financial statements and management’s discussion and analysis should be consulted for information at the Company level.|
|Total Future Net Revenue ($000s)
as of December 31, 2020
Forecast Prices and Costs(1)
|Proved Developed Non-Producing||1,194,349||109,414||261,539||41,756||17,948||763,691||157,632||606,060|
|Total Proved Plus Probable||76,528,876||7,008,379||19,195,653||8,787,572||1,412,573||40,124,699||7,127,188||32,997,511|
|(1)||Numbers may not add due to rounding.|
|(2)||Abandonment and Reclamation Costs includes all active and inactive assets, with or without associated reserves, inclusive of all wells (existing and undrilled), facilities and pipelines.|
|(3)||The after-tax net present value of the Company’s oil and gas properties reflects the tax burden on the properties on a stand-alone basis. It does not consider the Company’s tax situation, or tax planning. It does not provide an estimate of the value at the Company level, which may be significantly different. The Company’s financial statements and management’s discussion and analysis should be consulted for information at the Company level.|
|Summary of Pricing and Inflation Rate Assumptions
Forecast Prices and Costs (1)
|Crude Oil and Natural Gas Liquids Pricing|
|NYMEX WTI Near
Month Futures Contract
Crude Oil at Cushing,
|Alberta Natural Gas Liquids
(Then Current Dollars)
|Natural Gas and Sulphur Pricing|
|Alberta Plant Gate||British Columbia|
|NYMEX Henry Hub
Near Month Contract
@ Ontario Then
|(1)||Crude oil and natural gas benchmark reference pricing, inflation and exchange rates utilized by GLJ in the GLJ Reserve Report and Deloitte in the Deloitte Reserve Report, were an average of forecast prices and costs published by Sproule Associates Ltd. as at December 31, 2020 and GLJ and McDaniel & Associates Consultants Ltd. as at January 1, 2021 (each of which is available on their respective websites at www.sproule.com, www.gljpc.com, and www.mcdan.com). GLJ assigns a value to the Company’s existing physical diversification contracts for natural gas for consuming markets at Dawn, Chicago, Ventura, Malin, PG&E, Iroquois, and Kingsgate based on forecasted differentials to NYMEX Henry Hub as per the aforementioned consultant average price forecast, contracted volumes and transportation costs. No incremental value is assigned to potential future contracts which were not in place as of December 31, 2020.|
|(2)||Inflation rates used for forecasting prices and costs.|
|(3)||Exchange rates used to generate the benchmark reference prices in this table.|
Reserves Performance Ratios
The following tables highlight Tourmaline’s reserves, F&D and FD&A costs as well as the associated recycle ratios.
Reserves, Capital Expenditures and Cash Flow(1)
|As at December 31,||2020||2019||2018|
|Proved Plus Probable||3,314,264||2,601,928||2,457,358|
|Capital Expenditures ($ millions)|
|Exploration and Development(2)||912||1,069||1,261|
|Net Property Acquisitions (Dispositions)||172||219||(47)|
|Net Corporate Acquisitions (Dispositions)(3)||794||–||–|
|Less: Topaz Property Acquisitions(4)||(119)||–||–|
|Cash Flow ($/boe)|
|Cash Flow – Three Year Average||11.67||12.75||12.80|
|(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 Company’s most recently filed Management’s Discussion and Analysis for further discussion.|
|(2)||Includes capitalized G&A of $31 million, $33 million and $30 million for 2020, 2019 and 2018 respectively.|
|(3)||Includes purchase price (cash and/or common shares) plus net debt.|
|(4)||Includes property acquisitions incurred by Topaz from non-related parties.|
|(5)||Represents the capital expenditures used for purposes of F&D and FD&A calculations.|
Finding and Development Costs
|Finding and Development Costs, Excluding FDC||2020||2019||2018||3-Year Avg.|
|Reserve Additions (MMboe)||185.4||160.7||241.0|
|F&D Costs ($/boe)||4.92||6.65||5.24||5.52|
|F&D Recycle Ratio(1)||2.1||1.7||2.6||2.1|
|Total Proved Plus Probable|
|Reserve Additions (MMboe)||210.5||180.4||326.6|
|F&D Costs ($/boe)||4.33||5.92||3.86||4.52|
|F&D Recycle Ratio(1)||2.4||1.9||3.5||2.6|
|Finding and Development Costs, Including FDC||2020||2019||2018||3-Year Avg.|
|Change in FDC ($ millions)||(286.0)||(275.2)||441.7|
|Reserve Additions (MMboe)||185.4||160.7||241.0|
|F&D Costs ($/boe)||3.38||4.94||7.07||5.32|
|F&D Recycle Ratio(1)||3.1||2.3||1.9||2.2|
|Total Proved Plus Probable|
|Change in FDC ($ millions)||(566.3)||(589.4)||486.3|
|Reserve Additions (MMboe)||210.5||180.4||326.6|
|F&D Costs ($/boe)||1.64||2.66||5.35||3.59|
|F&D Recycle Ratio(1)||6.4||4.3||2.5||3.3|
Finding, Development and Acquisition Costs
|Finding, Development and Acquisition Costs, Excluding FDC||2020||2019||2018||3-Year Avg.|
|Reserve Additions (MMboe)||510.3||194.2||247.4|
|FD&A Costs ($/boe)||3.45||6.63||4.91||4.48|
|FD&A Recycle Ratio(1)||3.0||1.7||2.7||2.6|
|Total Proved Plus Probable|
|Reserve Additions (MMboe)||826.0||250.7||337.9|
|FD&A Costs ($/boe)||2.13||5.13||3.59||3.01|
|FD&A Recycle Ratio(1)||4.9||2.2||3.7||3.9|
|Finding, Development and Acquisition Costs, Including FDC||2020||2019||2018||3-Year Avg.|
|Change in FDC ($ millions)||723.3||(93.4)||465.3|
|Reserve Additions (MMboe)||510.3||194.2||247.4|
|FD&A Costs ($/boe)||4.86||6.15||6.79||5.63|
|FD&A Recycle Ratio(1)||2.1||1.8||2.0||2.1|
|Total Proved Plus Probable|
|Change in FDC ($ millions)||1,383.5||(218.0)||526.8|
|Reserve Additions (MMboe)||826.0||250.7||337.9|
|FD&A Costs ($/boe)||3.80||4.26||5.15||4.21|
|FD&A Recycle Ratio(1)||2.7||2.7||2.6||2.8|
|(1)||The recycle ratio is calculated by dividing the cash flow per boe by the appropriate F&D or FD&A costs related to the reserve additions for that year.|
Conference Call Tomorrow at 9:00 a.m. MT (11:00 a.m. ET)
Tourmaline will host a conference call tomorrow, March 11, 2021 starting at 9:00 a.m. MT (11:00 a.m. ET). To participate, please dial 1-888-231-8191 (toll-free in North America), or international dial-in 647-427-7450, a few minutes prior to the conference call.
Conference ID is 1689407.
All amounts in this news release are stated in Canadian dollars unless otherwise specified.
This news release contains forward-looking information and statements (collectively, “forward-looking information”) within the meaning of applicable securities laws. The use of any of the words “forecast”, “expect”, “anticipate”, “continue”, “estimate”, “objective”, “ongoing”, “on track”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends” and similar expressions are intended to identify forward-looking information. More particularly and without limitation, this news 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 the following: anticipated petroleum and natural gas production and production growth for various periods including estimated production levels for 2021 and beyond; expected free cash flow and cash flow levels for 2021 and beyond; potential for share buybacks; targeted 2021 exit net debt to cash flow ratio; the future declaration and payment of dividends and the timing and amount thereof including any future increase; cash flow and free cash flow levels; production levels supported by certain of the Company’s reserves and drilling inventory; capital spending over various periods; cost reduction initiatives; improvements in capital efficiency; projected operating and drilling costs; the timing for facility expansions and facility start-up dates; sustainability and environmental improvement initiatives; anticipated future commodity prices including the expectation for future increases above current levels; the ability to generate, and the amount of, anticipated cash flow and free cash flow including in 2021 and over the five year development plan; 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 the following: prevailing and future commodity prices and currency exchange rates; 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 and the benefits to be derived therefrom; the state of the economy and the exploration and production business; the availability and cost of financing, labour and services; and ability to market crude oil, natural gas and NGL successfully. Without limitation of the foregoing, future dividend payments, if any, and the level thereof is uncertain, as the Company’s dividend policy and the funds available for the payment of dividends from time to time is dependent upon, among other things, free cash flow, financial requirements for the Company’s operations and the execution of its growth strategy, fluctuations in working capital and the timing and amount of capital expenditures, debt service requirements and other factors beyond the Company’s control. Further, the ability of Tourmaline to pay dividends will be subject to applicable laws (including the satisfaction of the solvency test contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness, including its credit facility.
Statements relating to “reserves” are also deemed to be forward looking information, 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 it 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 natural gas industry in general such as operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to reserves, production, revenues, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; marketing and transportation; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; ability to access sufficient capital from internal and external sources; failure to obtain required regulatory and other approvals; and changes in legislation, including but not limited to tax laws, royalties and environmental regulations.
In addition, pandemics, epidemics or outbreaks of an infectious disease in Canada or worldwide, including COVID-19or other illnesses could have an adverse impact on the Company’s results, business, financial condition or liquidity. If the pandemic is further prolonged, including through subsequent waves, or if additional variants of COVID-19 emerge which are more transmissible or cause more severe disease, or if other diseases emerge with similar effects, the adverse impact on the economy could worsen. It remains uncertain how the macroeconomic environment, and societal and business norms will be impacted following this COVID-19 pandemic. Unexpected developments in financial markets, regulatory environments, or consumer behaviour may also have adverse impacts on the Company’s results, business, financial condition or liquidity, for a substantial period of time. The Company’s business, financial condition, results of operations, cash flows, reputation, access to capital, cost of borrowing, access to liquidity, and/or business plans may, in particular, and without limitation, be adversely impacted as a result of the pandemic and/or decline in commodity prices as a result of: the shut-down of facilities or the delay or suspension of work on major capital projects due to workforce disruption or labour shortages caused by workers becoming infected with COVID-19, or government or health authority mandated restrictions on travel by workers or closure of facilities or worksites; suppliers and third-party vendors experiencing similar workforce disruption or being ordered to cease operations; reduced cash flows resulting in less funds from operations being available to fund capital expenditure budgets; reduced commodity prices resulting in a reduction in the volumes and value of reserves; crude oil storage constraints resulting in the curtailment or shutting in of production; counterparties being unable to fulfill their contractual obligations on a timely basis or at all; the inability to deliver products to customers or otherwise get products to market caused by border restrictions, road or port closures or pipeline shut-ins, including as a result of pipeline companies suffering workforce disruptions or otherwise being unable to continue to operate; and the ability to obtain additional capital including, but not limited to, debt and equity financing being adversely impacted as a result of unpredictable financial markets, commodity prices and/or a change in market fundamentals. The COVID-19 pandemic has also created additional operational risks for the Company, including the need to provide enhanced safety measures for its employees and customers; comply with rapidly changing regulatory guidance; address the risk of, attempted fraudulent activity and cybersecurity threat behaviour; and protect the integrity and functionality of the Company’s systems, networks, and data as a larger number of employees work remotely. The Company is also exposed to human capital risks due to issues related to health and safety matters, and other environmental stressors as a result of measures implemented in response to the COVID-19 pandemic, as well as the potential for a significant proportion of the Company’s employees, including key executives, to be unable to work effectively, because of illness, quarantines, sheltering-in-place arrangements, government actions or other restrictions in connection with the pandemic. The extent to which the COVID-19 pandemic continues to impact the Company’s results, business, financial condition or liquidity will depend on future developments in Canada, the U.S. and globally, including the development and widespread availability of efficient and accurate testing options, and effective treatment options or vaccines. Despite the approval of certain vaccines by the regulatory bodies in Canada and the U.S., the ongoing evolution of the development and distribution of an effective vaccine also continues to raise uncertainty.
Readers are cautioned that the foregoing list of factors is not exhaustive.
Additional information on these and other factors that could affect Tourmaline, or its operations or financial results, are included in the Company’s most recently filed Management’s Discussion and Analysis (See “Forward-Looking Statements” therein), Annual Information Form (See “Risk Factors” and “Forward-Looking Statements” therein) and other reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or Tourmaline’s website (www.tourmalineoil.com).
The forward-looking information contained in this news 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.
The reserves data set forth above is based upon the reports of GLJ Ltd. (“GLJ”) and Deloitte LLP, each dated effective December 31, 2020, which have been consolidated into one report by GLJ and adjusted to apply certain of GLJ’s assumptions and methodologies and pricing and cost assumptions. The price forecast used in the reserve evaluations is an average of the January 1, 2021 price forecasts for GLJ, Sproule Associates Ltd. and McDaniel & Associates Consultants Ltd., each of which is available on their respective websites, www.gljpc.com, www.sproule.com and www.mcdan.com, and will be contained in the Company’s Annual Information Form for the year ended December 31, 2020, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2021.
There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil, natural gas and NGL reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For those reasons, estimates of the economically recoverable crude oil, NGL and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.
All evaluations and reviews of future net revenue are stated prior to any provisions for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. The after-tax net present value of the Company’s oil and gas properties reflects the tax burden on the properties on a stand-alone basis and utilizes the Company’s tax pools. It does not consider the corporate tax situation, or tax planning. It does not provide an estimate of the after-tax value of the Company, which may be significantly different. The Company’s financial statements and the management’s discussion and analysis should be consulted for information at the level of the Company.
The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to effects of aggregations. The estimated values of future net revenue disclosed in this news release do not represent fair market value. There is no assurance that the forecast prices and cost assumptions used in the reserve evaluations will be attained and variances could be material.
The reserve data provided in this news release presents only a portion of the disclosure required under National Instrument 51-101. All of the required information will be contained in the Company’s Annual Information Form for the year ended December 31, 2020, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2021.
In this news release, production and reserves information may be presented on a “barrel of oil equivalent” or “BOE” basis. 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. In addition, as the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
This news release contains metrics commonly used in the oil and natural gas industry. Each of these metrics is determined by the Company as set out below or elsewhere in this news release. These metrics are “reserve replacement”, “F&D” costs, “FD&A” costs, “recycle ratio”, “F&D recycle ratio”, “FD&A recycle ratio” and “NPV per share”. These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies. As such, they should not be used to make comparisons.
Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company’s performance over time, however, such measures are not reliable indicators of the Company’s future performance and future performance may not compare to the performance in previous periods.
“F&D” costs are calculated by dividing the sum of the total capital expenditures for the year (in dollars) by the change in reserves within the applicable reserves category (in boe). F&D costs, including FDC, includes all capital expenditures in the year as well as the change in FDC required to bring the reserves within the specified reserves category on production.
“FD&A” costs are calculated by dividing the sum of the total capital expenditures for the year inclusive of the net acquisition costs and disposition proceeds (in dollars) by the change in reserves within the applicable reserves category inclusive of changes due to acquisitions and dispositions (in boe). FD&A costs, including FDC, includes all capital expenditures in the year inclusive of the net acquisition costs and disposition proceeds as well as the change in FDC required to bring the reserves within the specified reserves category on production.
The Company uses F&D and FD&A as a measure of the efficiency of its overall capital program including the effect of acquisitions and dispositions. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
Also included in this news release are estimates of Tourmaline’s 2021 exit net debt-to-cash flow ratio as well as 2021 – 2025 cash flow and free cash flow, which are based on, among other things, the various assumptions as to production levels, capital expenditures, annual cash flows and other assumptions disclosed in this news release and including Tourmaline’s estimated average production of 390,000 – 410,000 boepd for 2021 and 426,000, 448,000, 465,000 and 482,000 boepd for 2022 – 2025, respectively. Commodity price assumptions for natural gas (NYMEX (US) – $2.85/mcf, $2.65/mcf, $2.51/mcf, $2.52/mcf and $2.54/mcf for 2021 – 2025, respectively; AECO – $2.96/mcf, $2.51/mcf, $2.29/mcf, $2.30/mcf and $2.40/mcf for 2021 – 2025, respectively), and crude oil (WTI (US) – $58.52/bbl, $54.44/bbl, $51.80/bbl, $50.35/bbl and $49.68/bbl for 2021 – 2025, respectively) and an exchange rate assumption of $0.79 (US/CAD) for 2021 – 2023 and $0.78 for 2024 – 2025. Further, in the case of years subsequent to 2021, readers are cautioned that such estimates are provided for illustration only and are based on budgets and forecasts that have not been finalized and are subject to a variety of additional factors and contingencies including prior years’ results. To the extent such estimates constitute financial outlooks, they were approved by management and the Board of Directors of Tourmaline on March 10, 2021 and are included to provide readers with an understanding of Tourmaline’s anticipated cash flow and free cash flow based on the capital expenditure, production and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.
NON-GAAP FINANCIAL MEASURES
This news release includes references to “free cash flow”, “cash flow”, and “net debt” which are financial measures commonly used in the oil and gas industry and do not have a standardized meaning 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 term “free cash flow”, “cash flow”, 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, to pay dividends or to repay debt. Investors are cautioned that these non-GAAP measures should not be construed as an alternative to net income or cash from operating activities determined in accordance with GAAP as an indication of the Company’s performance. Free cash flow is calculated as cash flow less total net capital expenditures and is prior to dividend payments. Net capital expenditures is defined as the sum of E&P capital program and other corporate expenditures, net of non-core dispositions. See “Non-GAAP Financial Measures” in the December 31, 2019 Management’s Discussion and Analysis for the definition and description of these terms.
OIL AND GAS METRICS
This news release contains certain oil and gas metrics which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included in this document to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the Company’s future performance and future performance may not compare to the Company’s performance in previous periods and therefore such metrics should not be unduly relied upon.
ESTIMATES OF DRILLING LOCATIONS
Unbooked drilling locations are the internal estimates of Tourmaline based on Tourmaline’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 Tourmaline’s management as an estimation of Tourmaline’s multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Tourmaline will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and natural gas reserves, resources or production. The drilling locations on which Tourmaline 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 a certain number of the unbooked drilling locations have been de-risked by Tourmaline 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 of Tourmaline has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
SUPPLEMENTAL INFORMATION REGARDING PRODUCT TYPES
This news release includes references to 2020 annual production, 2020 average daily production, Q4 2020 average daily production, current average daily production, Q1 2021 average daily production and 2021 average daily production. The following table is intended to provide supplemental information about the product type composition for each of the production figures that are provided in this news release:
|Light and Medium
|Shale Natural Gas||Natural Gas
|2020 Annual Production||10,266,666||339,302,682||201,137,676||13,338,870||113,678,929|
|2020 Average Daily Production||28,051||927,057||549,556||36,445||310,598|
|Q4 2020 Average Daily Production||29,113||993,899||598,111||41,877||336,325|
|Current Average Daily Production||32,957||1,267,517||643,263||56,079||407,500|
|Q1 2021 Average Daily Production||32,553||1,251,965||635,371||55,391||402,500|
|2021 Average Daily Production||33,060||1,198,601||667,955||55,848||400,000|
|(1)||For the purposes of this disclosure, condensate has been combined with Light and Medium Crude Oil as the associated revenues and certain costs of condensate are similar to Light and Medium Crude Oil. Accordingly, NGLs in this disclosure exclude condensate.|
See also “Forward-Looking Statements”, and “Non-GAAP Financial Measures” in the most recently filed Management’s Discussion and Analysis.
|bbls/day||barrels per day|
|bbl/mmcf||barrels per million cubic feet|
|bcf||billion cubic feet|
|bcfe||billion cubic feet equivalent|
|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|
|DUC||drilled but uncompleted wells|
|gjs/d||gigajoules per day|
|mboe||thousand barrels of oil equivalent|
|mboepd||thousand barrels of oil equivalent per day|
|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|
|mstb||thousand stock tank barrels|
|natural gas||conventional natural gas and shale gas|
|NCIB||normal course issuer bid|
|NGL or NGLs||natural gas liquids|
|tcf||trillion cubic feet|
MANAGEMENT’S DISCUSSION AND ANALYSIS AND CONSOLIDATED FINANCIAL STATEMENTS
To view Tourmaline’s Management’s Discussion and Analysis and Consolidated Financial Statements for the years ended December 31, 2020 and 2019, please refer to SEDAR (www.sedar.com) or Tourmaline’s website at www.tourmalineoil.com.
About Tourmaline Oil Corp.
Tourmaline is an investment grade Canadian senior crude oil and natural gas exploration and production company focused on providing strong and predictable long-term growth and a steady return to shareholders through an aggressive exploration, development, production and acquisition program in the Western Canadian Sedimentary Basin by building its extensive asset base in its three core exploration and production areas and exploiting and developing these areas to increase reserves, production and cash flows at an attractive return on invested capital.
SOURCE Tourmaline Oil Corp.
For further information: Tourmaline Oil Corp., Michael Rose, Chairman, President and Chief Executive Officer, (403) 266-5992; OR Tourmaline Oil Corp., Brian Robinson, Vice President, Finance and Chief Financial Officer, (403) 767-3587; email@example.com; OR Tourmaline Oil Corp., Scott Kirker, Secretary and General Counsel, (403) 767-3593; firstname.lastname@example.org; OR Tourmaline Oil Corp., Jamie Heard, Senior Capital Markets Analyst, (403) 767-5942; email@example.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: firstname.lastname@example.org, Website: www.tourmalineoil.com