Tourmaline Generates Record Free Cash Flow, Grows Production 10%, Increases 2P Reserves to 2.6 Billion Boe in 2019
Tourmaline Oil Corp. (TSX:TOU.TO) ("Tourmaline" or the "Company") is pleased to release financial and operating results for the full year and fourth quarter of 2019 as well as 2019 reserves results. The Company delivered strong returns to shareholders, annual growth and demonstrated continued financial resilience in this very challenging energy cycle.
-- Tourmaline delivered full-year earnings of $319.7 million ($1.18/diluted share), again demonstrating the profitability of its core EP business. -- Annual cash flow((1)) of $1.2 billion ($4.43/diluted share) and Q4 2019 cash flow of $335.9 million ($1.24/diluted share) provide a platform for continued economic growth in 2020. -- Free cash flow((2)) for 2019 of $144.9 million was a 27% increase over 2018. Q4 free cash flow of $67.1 million represents an annualized free cash flow yield of approximately 8%. -- Tourmaline bought back 1,053,000 shares in 2019 at $12.23/share pursuant to its NCIB. Tourmaline will continue to tactically pursue share buybacks funded by free cash flow on hand if distressed valuations continue. -- The Company grew average annual liquids volumes by 16% and total average production volumes by 10% in 2019, while containing capital spending at $1.29 billion (up only 6% from 2018). -- The Company posted record capital efficiency of $8,650/boepd (excluding acquisitions and dispositions) - a 23% improvement over 2018. -- Tourmaline added 250.7 mmboe of proved plus probable reserves ("2P") after adding back annual production of 106.2 mmboe. -- 2P finding, development and acquisition costs (FD&A) in 2019 were $4.26/boe including changes in future development capital ("FDC") ($5.13/boe excluding changes in FDC) based on total capital expenditures of $1.29 billion, total proved ("TP") FD&A in 2019 were $6.15/boe including change in FDC ($6.63/boe excluding change in FDC). 2019 proved, developed producing ("PDP") FD&A were $8.01/boe. -- Subsequent to the quarter, Tourmaline announced an update on its NEBC consolidation activities. Through two corporate transactions, Tourmaline has added 6,000 boepd of current production, 2P reserves of 116.3 mmboe((3)) and 160,000 acres of Montney lands for a combined cash purchase price of $33.4 million.
-- Year-end 2019 PDP reserves of 527.4 mmboe were up 34% over year-end 2018 when including 2019 annual production of 106.2 mmboe((4)), TP reserves of 1.294 billion boe were up 16% over 2018 when including 2019 annual production and 2P of 2.602 billion boe were up 10% when including 2019 annual production. -- Continued improvement in drill-and-complete capital costs resulted in a significant reduction in FDC in the 2019 report. -- 2019 PDP finding and development ("F&D") costs were $7.06/boe, including changes in FDC, a record low, yielding a PDP reserve recycle ratio((5)) of 1.6. Total proved F&D costs in 2019 were $4.94/boe including changes in FDC and 2P F&D was $2.66/boe including changes in FDC. 2P FD&A costs were $4.26/boe including changes in FDC yielding a 2019 2P FD&A recycle ratio of 2.7. -- Tourmaline replaced 236% of 2019's annual production of 106.2 mmboe in 2019 with a 2P addition of 251 mmboe before 2019 production. -- Tourmaline added the 251 mmboe of 2P reserves in 2019 even though 66.8% of the 2019 drilling locations were converting previously-booked locations. In 2019, the Company rig-released 198.9 (net) wells, down 7% from 2018 (213.1 wells) as the Company moderated capital spending due to low commodity prices. -- Tourmaline's 2P reserve value equates to $55.69/share utilizing the lower 2019 engineering price deck. TP reserve value is $32.42/share - PDP reserve value is $16.90/share. -- After 11 years of operation, Tourmaline now has 12.3 TCF of 2P natural gas reserves and 553 million barrels of 2P oil, condensate, and NGL reserves (January 1, 2020). -- For the seventh consecutive year, the Company enjoyed positive 2P technical revisions in its reserve report.
-- 2019 production averaged 290,865 boepd, Q4 2019 averaged 299,844 boepd. As announced on December 17, 2019, lengthy outages at the third-party Saturn deep-cut facility in the Alberta Deep Basin and on the NEBC Enbridge system reduced both quarterly liquid volumes and total production levels. -- Current average production is 310,500 boepd excluding the production impact of Polar Star Canadian Oil and Gas Inc. which closed in February 2020. Tourmaline has deferred a minimum of $25.0 million of first quarter capital expenditures from the planned EP program into 2H 2020 due to lower commodity prices, reducing 1H average production by approximately 2,500 boepd. The Company is on track to meet full-year 2020 guidance of 315,000 - 320,000 boepd inclusive of this capital deferral and the effects of weather-related freeze-offs in January. Closing of the recently-announced acquisitions will be accretive to production volumes, primarily in the second quarter. -- 2019 average liquids production was 55,338 bpd (oil, condensate, NGL), a 16% increase over 2018. Current 2020 liquids production is 64,300 bpd. The Company is targeting full-year 2020 liquids production of approximately 68,000 bpd (a 22% year-over-year increase).
-- Full-year 2019 after-tax earnings were $319.7 million ($1.18/diluted share) as Tourmaline remained profitable despite a challenging year for natural gas prices. The Company has built one of the most stable, low-cost businesses in the North American energy sector. -- Fourth quarter 2019 cash flow was $335.9 million ($1.24/diluted share) and full-year 2019 cash flow was $1,205.5 million ($4.43/diluted share). -- Tourmaline generated $67.1 million of free cash flow in Q4 2019. The first quarter 2020 dividend of $0.12/share will be paid on March 31, 2020. -- The five-year EP development plan, released in mid-December, remains unchanged. It is expected to generate approximately $1.75 billion of free cash flow over the five years at strip pricing((6)). This cash is expected to be deployed into dividend increases, debt reduction, and share buybacks. The Company acquired 1,053,000 shares in 2019 through the NCIB at an average price of $12.23. -- Tourmaline continued to effectively manage all-in cash costs in 2019 (operating, transportation, general and administrative and financing) which totalled $8.18/boe compared to $7.87/boe in 2018.
-- For 2019, the Company posted a realized gas price across the portfolio of $2.59/mcf, a 46% premium over the average AECO 5A price for the year. -- For calendar year 2020, Tourmaline has an average of 252 mmcf/d hedged at a weighted-average fixed price of CAD $2.44/mcf, an average of 202 mmcf/d hedged at a basis to NYMEX of $(0.31) USD/mcf, an average of 410 mmcf/d incremental volume exposed to export markets, including Dawn, Chicago, Ventura, Sumas, Malin and PGE. -- In the first quarter of 2020, as part of the Company's gas marketing diversification strategy, the Company signed a long-haul transportation agreement for 25 mmcfpd delivering to the US Gulf Coast which will commence on November 1, 2022. -- For 2H 2019, Tourmaline had in excess of 4,000 bbls/d of propane exposed to Argus Far East Index (AFEI) and realized wellhead prices in excess of CAD $23/bbl above Edmonton prices. -- For 2020, Tourmaline expects to have in excess of 5,000 bbls/d of propane exposed to AFEI.
2019/2020 CAPITAL PROGRAMS
-- Full-year EP capital spending in 2019 was $1,033.1 million. The Company reduced its originally-planned program by approximately $270.0 million during the course of the year. Continued per-well capital cost improvements allowed the Company to largely achieve original EP targets on the reduced spending. -- The 2020 EP capital program remains at $925.0 million. Additionally, Tourmaline has the flexibility to reduce activity to a maintenance capital budget which is $100 million lower than the current plan. Tourmaline will monitor commodity prices and the natural gas supply/demand balance over the next few months; the full-year program may be revised in conjunction with the Q1 2020 results release in May 2020. The Company has already elected to defer a minimum of $25.0 million of originally-planned Q1 2020 EP expenditures into 2H 2020. -- Less than 15% of 2020 capital expenditures are directed towards facility expenditures, which will drive anticipated 2020 capital efficiencies of $6,500 - $7,000/boepd. -- Tourmaline continues to target a net debt((7)())-to-cash flow range of 1.0 - 1.5 times. At December 31, 2019, net debt-to-cash flow was at 1.5 times (net debt to annualized Q4 2019 cash flow was at 1.3 times). Current targeted exit 2020 net debt-to-cash flow is 1.2 times.
-- 2019 capital efficiency was approximately $8,650/boepd (excluding acquisitions and dispositions) - a record low for Tourmaline as the Company continued to reduce capital costs and deliver strong well results. The Company is forecasting a further improvement in capital efficiency in 2020. -- Q4 2019 operating costs were $3.06/boe, significantly less than originally forecast. NEBC full-year 2019 operating costs were a record low of $2.40/boe. -- Tourmaline rig-released 198.9 net wells in 2019, down 7% from 2018 and still achieved full-year production growth of 10% in 2019. -- Tourmaline operated up to 11 drilling rigs during Q1 2020, with 10 rigs now operating. The Company currently plans to operate three rigs through break-up in Q2 2020. -- Capital cost reduction/improvements continue to be achieved through monobore trials in the Alberta Deep Basin, application of rotary steerable technology and novel pad equipping approaches, amongst other technology-driven opportunities. NEBC Montney horizontal completed well costs are now averaging $2.9 million (drill, 35 stage-completions, equip.).
ENVIRONMENTAL IMPROVEMENT INITIATIVES
As outlined in the Company's Sustainability Report, published in February 2020, Tourmaline has made major strides in reducing emissions and continually improving overall environmental performance.
Major Environmental Performance Achievements
-- 46% reduction in CO((2)) emissions intensity since 2013. -- Near elimination of all fresh water, in well stimulation operations, in British Columbia. -- Initiation of methane-reduction retrofit compliance plan resulting in over 3,400 high-bleed devices being replaced in 2019. -- An approximate 50% reduction in the surface area per producing well in the Company's operating areas due to multi-pad well development. -- Broad replacement of diesel in Tourmaline's drilling and completion operations with natural gas. Tourmaline now operates 15 natural gas fuel substitution units allowing for the displacement of 9.8 million litres of diesel per year.
Environmental Performance Targets
-- Continued emphasis on reducing corporate emissions intensity by maintaining the Company's top-decile performance relative to the Company's peer group while targeting a 25% reduction in total methane emissions from 2018 levels by 2023. -- Reduce corporate emissions intensity by 25% by 2027 (scope 1) using 2018 as a baseline, by continuing to focus on overall efficiencies with the application of new, innovative technologies including the electrification of assets, when feasible. -- Continually improve the Company's peer-leading performance on water usage in completion activities by reducing and eventually eliminating the usage of fresh water throughout its core gas operations.
The environmental performance improvements achieved thus far, and the myriad of future-planned initiatives, require significant capital investment. The vast majority of these initiatives, however, ultimately reduce Tourmaline's capital and operating cost structure. Shareholders receive a double win - a cleaner environment via Tourmaline's net-cleanest hydrocarbon molecule and enhanced returns via the Company's improved efficiencies.
Our strong results and intense focus on sustainability is why the world needs Canadian natural gas now and in the future.
The Company is pleased to announce that its Board of Directors has declared a quarterly cash dividend on its common shares of C$0.12 per common share. The dividend will be payable March 31, 2020 to shareholders of record at the close of business on March 16, 2020. 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 2019 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 2019 Management's Discussion and Analysis. (3) Reserves have been evaluated by independent reserve evaluators as at December 31, 2018 as follows: Polar Star 2P reserves of 80.7 mmboe by Sproule and Chinook 2P reserves of 35.6 mmboe by McDaniel for a combined 2P reserves total of 116.3 mmboe. Reserves are working interest gross reserves before deduction of royalties payable to others and without including any royalty interests. (4) See "Supplemental Information Regarding Product Types" in this news release. (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) Based on oil and gas commodity strip pricing at December 11, 2019. (7) See "Non-GAAP Financial Measures in this new release and in the Company's 2019 Management's Discussion and Analysis.
CORPORATE SUMMARY - DECEMBER 31, 2019
Three Months Ended December 31, Twelve Months Ended December 31, 2019 2018 Change 2019 2018 Change OPERATIONS Production Natural gas (mcf/d) 1,439,746 1,347,778 7% 1,413,160 1,305,025 8% Crude oil, condensate and NGL (bbl/d) 59,886 51,938 15% 55,338 47,540 16% Oil equivalent (boe/d) 299,844 276,568 8% 290,865 265,044 10% Product prices(1) Natural gas ($/mcf) $ 2.77 $ 3.13 (12)% $ 2.59 $ 2.73 (5)% Crude oil, condensate and NGL ($/bbl) $ 38.59 $ 43.40 (11)% $ 39.29 $ 46.47 (15)% Operating expenses ($/boe) $ 3.06 $ 3.35 (9)% $ 3.28 $ 3.33 (2)% Transportation costs ($/boe) $ 4.13 $ 3.63 14% $ 3.86 $ 3.52 10% Operating netback(3) ($/boe) $ 13.00 $ 15.82 (18)% $ 12.12 $ 14.12 (14)% Cash general and $ 0.52 $ 0.42 24% $ 0.49 $ 0.49 -% administrative expenses ($/boe)(2) FINANCIAL ($000, except share and per share) Total revenue from commodity sales 579,588 595,487 (3)% 2,127,337 2,106,209 1% and realized gains Royalties 22,559 15,380 47% 83,030 77,369 7% Cash flow(4) 335,856 391,532 (14)% 1,205,540 1,303,462 (8)% Cash flow per share (diluted)(4) $ 1.24 $ 1.44 (14)% $ 4.43 $ 4.80 (8)% Net earnings 61,340 190,895 (68)% 319,740 401,418 (20)% Net earnings per share (diluted) $ 0.23 $ 0.70 (67)% $ 1.18 $ 1.48 (20)% Capital expenditures (net of 320,389 395,194 (19)% 1,287,259 1,214,437 6% dispositions) Weighted average shares outstanding 271,878,824 271,702,910 -% (diluted) Net debt(4) (1,755,684) (1,720,009) 2% PROVED + PROBABLE RESERVES(3) Natural gas (bcf) 12,294.6 11,712.7 5% Crude oil (mbbls) 96,984 82,046 18% Natural gas liquids (mbbls) 455,851 423,198 8% Mboe 2,601,928 2,457,358 6% ---
(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, 2019.
2019 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 74% 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 7% 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 9% and 8%, 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 Oil and Gas Reserves and Net Present Values of Future Net Revenue as of December 31, 2019 Forecast Prices and Costs(1) Light & Medium Crude Conventional Natural Shale Natural Gas(2) Natural Gas Liquids Total Oil Equivalent Oil Gas Company Company Company Company Company Company Company Company Company Company Gross Net Gross Net Gross Net Gross Net Gross Net Reserves Category (Mbbls) (Mbbls) (MMcf) (MMcf) (MMcf) (MMcf) (Mbbls) (Mbbls) (Mboe) (Mboe) --- Proved Producing 13,948 11,422 1,676,894 1,505,877 910,873 844,148 82,118 68,535 527,361 471,628 Proved Developed Non-Producing 1,935 1,504 95,010 85,260 208,272 196,007 12,432 10,958 64,914 59,340 Proved Undeveloped 32,189 26,203 1,929,133 1,751,774 1,408,310 1,308,908 113,735 102,419 702,164 638,736 Total Proved 48,072 39,130 3,701,036 3,342,911 2,527,455 2,349,063 208,285 181,912 1,294,439 1,169,704 Total Probable 48,912 39,478 2,412,245 2,173,075 3,653,824 3,279,086 247,566 210,547 1,307,490 1,158,719 Total Proved Plus Probable 96,984 78,608 6,113,281 5,515,987 6,181,279 5,628,148 455,851 392,458 2,601,928 2,328,422
Net Present Values of Future Net Revenue ($000s) Before Income Taxes Discounted at After Income Taxes Discounted at(3) Unit Value (%/year) (%/year) Before Income Tax Discounted at 10%/year Reserves Category 0 5 10 15 20 0 5 10 15 20 ($/Boe) ($/Mcfe) --- Proved Producing 6,776,073 5,475,633 4,579,234 3,953,261 3,496,236 6,513,916 5,329,729 4,494,030 3,901,446 3,463,622 9.71 1.62 Proved Developed Non-Producing 951,690 723,446 581,989 487,603 420,666 703,333 555,992 464,566 402,764 357,903 9.81 1.63 Proved Undeveloped 8,114,346 5,258,108 3,623,511 2,611,296 1,943,173 5,988,919 3,824,651 2,584,398 1,819,464 1,317,883 5.67 0.95 Total Proved 15,842,109 11,457,187 8,784,733 7,052,160 5,860,075 13,206,167 9,710,371 7,542,994 6,123,674 5,139,408 7.51 1.25 Total Probable 20,521,808 10,555,460 6,308,597 4,165,195 2,945,016 15,169,537 7,746,820 4,579,558 2,987,161 2,086,554 5.44 0.91 Total Proved Plus Probable 36,363,916 22,012,647 15,093,330 11,217,355 8,805,091 28,375,704 17,457,191 12,122,552 9,110,834 7,225,961 6.48 1.08
Notes: (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) (Undiscounted) as of December 31, 2019 Forecast Prices and Costs(1) Reserves Category Revenue Royalties Operating Capital Abandonment Future Net Income Future Net Costs Development and Revenue Tax Revenue Costs Reclamation Before After Costs(2) Income Tax Income Tax(3) Proved Producing 12,077,042 1,248,887 3,611,456 50 440,576 6,776,073 262,157 6,513,916 Proved Developed Non- 1,573,143 164,268 368,213 66,242 22,730 951,690 248,357 703,333 Producing Proved 17,308,773 1,640,354 3,550,448 3,805,349 198,275 8,114,346 2,125,427 5,988,919 Undeveloped Total 30,958,957 3,053,509 7,530,117 3,871,642 661,581 15,842,109 2,635,941 13,206,167 Proved Total 37,823,111 4,827,222 8,615,423 3,532,409 326,248 20,521,808 5,352,271 15,169,537 Probable Total Proved Plus 68,782,068 7,880,731 16,145,540 7,404,051 987,829 36,363,916 7,988,212 28,375,704 Probable
Notes: (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 Alberta Natural Gas Liquids Month Futures Contract (Then Current Dollars) Crude Oil at Cushing, Oklahoma Year Inflation(2) CAD/USD Constant Then MSW, Light Spec Edmonton Edmonton Edmonton % Exchange 2020 Current Crude Oil Ethane Propane Butane C5+ Rate $ $US/ (40 API, $Cdn/Bbl $Cdn/Bbl $Cdn/Bbl Stream $US/$Cdn(3) $US/Bbl Bbl 0.3%S) at Quality Edmonton $Cdn/Bbl Then Current $Cdn/Bbl === 2020 0.0 0.7600 61.00 61.00 72.64 6.42 26.36 42.09 76.83 2021 1.7 0.7700 62.70 63.75 76.06 7.41 29.80 47.03 79.82 2022 2.0 0.7850 63.82 66.18 78.35 8.33 32.94 50.66 82.30 2023 2.0 0.7850 64.20 67.91 80.71 8.65 34.00 52.21 84.72 2024 2.0 0.7850 64.40 69.48 82.64 8.98 34.89 53.48 86.71 2025 2.0 0.7850 64.58 71.07 84.60 9.24 35.78 54.77 88.73 2026 2.0 0.7850 64.75 72.68 86.57 9.46 36.69 56.07 90.77 2027 2.0 0.7850 64.84 74.24 88.49 9.67 37.57 57.32 92.76 2028 2.0 0.7850 64.84 75.73 90.31 9.89 38.41 58.50 94.65 2029 2.0 0.7850 64.85 77.24 92.17 10.12 39.26 59.71 96.57 2030 2.0 0.7850 64.85 78.79 94.01 10.35 40.11 60.90 98.53 2031 2.0 0.7850 64.85 80.36 95.89 10.56 40.91 62.12 100.50 2032 2.0 0.7850 64.84 81.97 97.81 10.77 41.73 63.36 102.51 2033 2.0 0.7850 64.84 83.61 99.76 10.98 42.56 64.63 104.56 2034 2.0 0.7850 64.85 85.28 101.76 11.20 43.42 65.92 106.65 2035 2.0 0.7850 64.85 +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr
Natural Gas and Sulphur Pricing Alberta Plant Gate British Columbia NYMEX Henry Hub Spot Near Month Contract Year Constant Then Current Midwest AECO/NIT Dawn Price Constant Then Current ARP $Cdn/ Sumas Spot Westcoast Spot Plant 2020 $ $US/MMbtu Price @ Spot @ Ontario Then 2020 $ $Cdn/ MMbtu $US/ Station 2 Gate $US/ Chicago Then Current Current $Cdn/ MMbtu MMbtu $Cdn/ $Cdn/ MMbtu Then Current $Cdn/ $US/MMbtu MMbtu MMbtu MMbtu $US/ MMbtu MMbtu --- 2020 2.62 2.62 2.53 2.04 2.58 1.82 1.82 1.83 2.16 1.66 1.41 2021 2.82 2.87 2.78 2.32 2.82 2.07 2.10 2.11 2.44 1.99 1.74 2022 2.95 3.06 2.96 2.62 3.01 2.30 2.39 2.40 2.72 2.31 2.07 2023 2.99 3.17 3.07 2.71 3.12 2.35 2.48 2.50 2.83 2.46 2.21 2024 3.01 3.24 3.15 2.81 3.20 2.39 2.58 2.59 2.90 2.56 2.31 2025 3.02 3.32 3.23 2.89 3.27 2.41 2.66 2.67 2.98 2.66 2.42 2026 3.02 3.39 3.30 2.96 3.34 2.42 2.72 2.74 3.05 2.73 2.48 2027 3.02 3.46 3.36 3.03 3.41 2.43 2.78 2.80 3.12 2.80 2.54 2028 3.02 3.52 3.43 3.10 3.48 2.44 2.85 2.87 3.18 2.87 2.61 2029 3.02 3.60 3.50 3.17 3.55 2.45 2.92 2.94 3.26 2.93 2.68 2030 3.02 3.67 3.58 3.24 3.62 2.46 2.99 3.00 3.33 3.00 2.74 2031 3.02 3.74 3.65 3.30 3.69 2.46 3.05 3.07 3.39 3.06 2.80 2032 3.02 3.81 3.72 3.37 3.77 2.46 3.11 3.13 3.46 3.12 2.85 2033 3.02 3.89 3.80 3.43 3.84 2.46 3.17 3.19 3.54 3.19 2.91 2034 3.02 3.97 3.87 3.50 3.92 2.46 3.23 3.25 3.61 3.25 2.97 2035 3.02 +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr 2.46 +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr
Notes: (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, 2019 and GLJ and McDaniel & Associates Consultants Ltd. as at January 1, 2020 (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 and PG&E 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, 2019. (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, 2019 2018 2017 --- Reserves (Mboe) Proved Producing 527,361 473,269 436,208 Total Proved 1,294,439 1,206,381 1,055,702 Proved Plus Probable 2,601,928 2,457,358 2,216,206 Capital Expenditures ($ millions) Exploration and Development(2) 1,069 1,261 1,364 Net Acquisitions (Dispositions) 219 (47) 58 Total Capital Expenditures 1,287 1,214 1,422 Cash Flow ($/boe) Cash Flow 11.36 13.47 13.63 Cash Flow - Three Year Average 12.75 12.80 13.11 ---
Notes: (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 $33 million, $30 million and $27 million for 2019, 2018 and 2017 respectively.
Finding and Development Costs
Finding and Development Costs, Excluding FDC 2019 2018 2017 3-Year Avg. --- Total Proved Reserve Additions (MMboe) 160.7 241.0 272.8 F&D Costs ($/boe) 6.65 5.24 5.00 5.48 F&D Recycle Ratio(1) 1.7 2.6 2.7 2.3 Total Proved Plus Probable Reserve Additions (MMboe) 180.4 326.6 537.5 F&D Costs ($/boe) 5.92 3.86 2.54 3.54 F&D Recycle Ratio(1) 1.9 3.5 5.4 3.6 --- Finding and Development Costs, Including FDC 2019 2018 2017 3-Year Avg. --- Total Proved Change in FDC ($ millions) (275.2) 441.7 481.1 Reserve Additions (MMboe) 160.7 241.0 272.8 F&D Costs ($/boe) 4.94 7.07 6.76 6.44 F&D Recycle Ratio(1) 2.3 1.9 2.0 2.0 Total Proved Plus Probable Change in FDC ($ millions) (589.4) 486.3 612.1 Reserve Additions (MMboe) 180.4 326.6 537.5 F&D Costs ($/boe) 2.66 5.35 3.68 4.02 F&D Recycle Ratio(1) 4.3 2.5 3.7 3.2 ---
Finding, Development and Acquisition Costs
Finding, Development and Acquisition Costs, 2019 2018 2017 3-Year Avg. Excluding FDC --- Total Proved Reserve Additions (MMboe) 194.2 247.4 285.2 FD&A Costs ($/boe) 6.63 4.91 4.98 5.40 FD&A Recycle Ratio(1) 1.7 2.7 2.7 2.4 Total Proved Plus Probable Reserve Additions (MMboe) 250.7 337.9 557.8 FD&A Costs ($/boe) 5.13 3.59 2.55 3.42 FD&A Recycle Ratio(1) 2.2 3.7 5.3 3.7 --- Finding, Development and Acquisition Costs, 2019 2018 2017 3-Year Avg. Including FDC --- Total Proved Change in FDC ($ millions) (93.4) 465.3 515.7 Reserve Additions (MMboe) 194.2 247.4 285.2 FD&A Costs ($/boe) 6.15 6.79 6.79 6.62 FD&A Recycle Ratio(1) 1.8 2.0 2.0 1.9 Total Proved Plus Probable Change in FDC ($ millions) (218.0) 526.8 678.3 Reserve Additions (MMboe) 250.7 337.9 557.8 FD&A Costs ($/boe) 4.26 5.15 3.76 4.28 FD&A Recycle Ratio(1) 2.7 2.6 3.6 3.0 ---
Note: (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 4, 2020 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 3587405.
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 2020 and beyond; expected free cash flow and cash flow levels; potential for share buybacks; targeted 2020 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; 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 free cash flow including in 2020 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. 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 Petroleum Consultants Ltd. ("GLJ") and Deloitte LLP, each dated effective December 31, 2019, 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, 2020 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, 2019, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 30, 2020.
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, 2019, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 30, 2020.
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 2020 exit net debt-to-cash flow ratio as well as 2020 - 2024 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 315,000 - 320,000 boepd for 2020 and 333,000, 353,000, 372,000 and 391,000 boepd for 2021 - 2024, respectively. Commodity price assumptions for natural gas (NYMEX (US) - $2.29/mcf, $2.46/mcf, $2.46/mcf, $2.49/mcf and $2.54/mcf for 2020 - 2024, respectively; AECO - $1.92/mcf, $2.08/mcf, $2.10/mcf, $2.13/mcf and $2.27/mcf for 2020 - 2024, respectively), and crude oil (WTI (US) - $57.30/bbl, $53.51/bbl, $51.81/bbl, $51.20/bbl and $51.19/bbl for 2020 - 2024, respectively) and an exchange rate assumption of $0.76 (US/CAD) for 2020 and 2021 and $0.75 for 2022 - 2024. Further, in the case of years subsequent to 2020, 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 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 3, 2020 and are included to provide readers with an understanding of Tourmaline's anticipated 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. In particular, readers are cautioned that estimates for 2021 and beyond are provided for illustration only as budgets and forecasts beyond 2021 have not been finalized and are subject to a variety of factors including prior year's results.
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 2019 annual production, 2019 average daily production, Q4 average daily production, current average daily production and 2020 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 Conventional Shale Natural Gas Natural Gas Oil Equivalent Crude Oil(1) Natural Gas Liquids(1) Total Company Gross Company Gross Company Gross Company Gross Company Gross (Bbls) (Mcf) (Mcf) (Bbls) (Boe) 2019 Annual Production 9,102,058 348,019,492 167,783,775 11,096,311 106,165,580 2019 Average Daily 24,937 953,478 459,682 30,401 290,865 Production Q4 2019 Average Daily 27,832 925,580 514,166 32,054 299,844 Production Current Average Daily 27,571 960,312 516,337 36,821 310,500 Production 2020 Average Daily 31,179 896,058 600,466 36,900 317,500 Production
(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.
bbl barrel 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 gj gigajoule gjs/d gigajoules per day mbbls thousand barrels mmbbls million barrels 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 MPa megapascal mstb thousand stock tank barrels 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, 2019 and 2018, please refer to SEDAR (www.sedar.com) or Tourmaline's website at www.tourmalineoil.com.
ABOUT TOURMALINE OIL CORP.
Tourmaline is a Canadian senior crude oil and natural gas exploration and production company focused on long-term growth through an aggressive exploration, development, production and acquisition program in the Western Canadian Sedimentary Basin.
SOURCE Tourmaline Oil Corp.
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SOURCE: Tourmaline Oil Corp.
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; firstname.lastname@example.org OR Tourmaline Oil Corp., Scott Kirker, Secretary and General Counsel, (403) 767-3593; 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