TOURMALINE DELIVERS RECORD CASH FLOW, FREE CASH FLOW AND EARNINGS IN 2022, INCREASES 2P RESERVES TO 4.5 BILLION BOE AND DECLARES DIVIDEND FOR Q1 2023
CALGARY, AB, Mar. 1, 2023 /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 2022, as well as 2022 reserves.
HIGHLIGHTS
- Full-year 2022 cash flow(1) ("CF") was a record $4.9 billion ($14.26 per diluted share(2)) up 67% over 2021. Fourth quarter 2022 CF was $1.4 billion ($4.08 per diluted share).
- Tourmaline generated a record $3.2 billion of free cash flow(3) ("FCF") in 2022.
- Full-year 2022 after tax net earnings were $4.5 billion ($13.10 per diluted share).
- Tourmaline paid $7.90/share in base and special dividends to shareholders in 2022, a 12% trailing yield(4) based on an average 2022 share price of $66.94.
- Tourmaline's proved plus probable ("2P") reserve value per diluted share(5)(6) before tax is $143 ($109 after tax) using the January 1, 2023 engineering price deck and a 10% discount rate. Total proved ("TP") and proved, developed producing ("PDP") reserve values per diluted share are $97 and $54 before tax, respectively ($75 and $44 after tax, respectively) using the same pricing and discount rates.
- Full-year 2022 average production of 500,832 boepd was up 14% over 2021 average production of 441,115 boepd.
- Current production is ranging between 520,000-530,000 boepd, consistent with the expected first quarter average.
- At current strip pricing(7), the Company expects to generate 2023 cash flow of $3.8 billion ($11.12 per diluted share) and free cash flow of $2.0 billion ($5.72 per diluted share) on unchanged EP capital expenditures(8) of $1.675 billion (as per January 12, 2023 news release). Based on a current share price of $60, Tourmaline is trading at an approximate 10% free cash flow yield(9).
- Exit 2022 net debt(10) was $494 million (0.1 times Q4 2022 annualized cash flow) and well below the Company's long-term net debt target of $1.0-1.2 billion.
- Year-end 2022 PDP reserves of 1.001 billion boe were up 25%, TP reserves of 2.32 billion boe were up 14% and 2P reserves of 4.50 billion boe were up 10% over year-end 2021, after including 2022 annual production of 183 million boe.
- Tourmaline replaced 240% of its 2022 annual production of 183 million boe with 2P additions of 440 million boe including 2022 production, with 88% of the addition from the organic EP program.
- After 14 years of operations, Tourmaline now has 20.7 Tcf of 2P natural gas reserves, the largest in Canada and one of the largest, lowest development cost, lowest emission natural gas reserve bases in North America.
- In January 2023, Tourmaline began delivering gas to the US Gulf Coast, becoming the first Canadian EP company participating in the LNG business with full exposure to JKM (Japan Korea Marker) pricing.
PRODUCTION UPDATE
- Fourth quarter 2022 production averaged 511,590 boepd, up 5% from Q4 2021; full-year 2022 average production of 500,832 boepd was up 14% over 2021 average production of 441,115 boepd.
- Current production is ranging between 520,000-530,000 boepd after a reduction in NGL volumes due to the Pembina Northern pipeline system interruption. Commencing January 17, 2023, a force majeure event on the Pembina Pipeline Corporation Northern line reduced daily Tourmaline NGL production volumes by approximately 8,000 boepd. The pipeline became operational again on February 25, 2023 and is currently flowing at reduced rates. First quarter average production of 520,000-530,000 boepd is still expected; full-year 2023 average production guidance ranging between 520,000 and 540,000 boepd remains unchanged.
- 2022 average liquids production of 112,460 bpd (oil, condensate, NGL) was up 16% over 2021. Tourmaline is the largest NGL producer in Canada at approximately 70,000 bpd and the second largest condensate producer at 32,000 bpd. Condensate and NGL production are expected to grow materially with the Company's Conroy North Montney development project.
- On February 9, 2023, Tourmaline produced its one billionth barrel of oil equivalent of production since inception in 2008.
FINANCIAL HIGHLIGHTS
- Full-year 2022 cash flow was a record $4.9 billion ($14.26 per diluted share), up 67% over 2021 cash flow of $2.9 billion.
- Fourth quarter 2022 cash flow was $1.4 billion ($4.08 per diluted share), up 45% over fourth quarter 2021.
- Tourmaline generated a record $3.2 billion of free cash flow in 2022.
- Full-year 2022 after tax net earnings were $4.5 billion ($13.10 per diluted share) up 121% from 2021 after tax net earnings of $2.0 billion ($6.40 per diluted share). Full year after tax net earnings include $1.5 billion related to the fair value of the embedded derivative associated with the Company's Gulf Coast LNG gas supply agreement.
- The Company increased the quarterly base dividend three times in 2022 to an annualized $1.00/share from an annualized $0.72/share (39% annual increase) and paid four special dividends totaling $7.00/share in 2022. Tourmaline has committed to returning the majority of annual FCF to shareholders and is executing on that plan; the Company plans to return between 50-90% of FCF to shareholders in 2023.
- Tourmaline paid $7.90/share in base and special dividends in 2022, a 12% trailing yield based on an average share price of $66.94 in 2022.
- Tourmaline paid a special dividend of $2.00/share on February 1, 2023 and expects to declare and pay special dividends for the remaining three quarters in 2023, fulfilling the commitment to return 50-90% of free cash flow to investors. Strong base and special dividends are anticipated in 2024 and in subsequent years based on current strip pricing.
- Tourmaline maintains its Investment Grade credit rating of BBB (high) validating the overall financial health of the Company as a stable, low-risk senior North American oil and gas producer.
- Q4 2022 EP capital expenditures were $482.8 million and full-year 2022 EP capital expenditures were $1.6 billion.
- In 2023, at current strip pricing, the Company expects to generate cash flow of $3.8 billion ($11.12 per diluted share) and free cash flow of $2.0 billion ($5.72 per diluted share) on unchanged EP capital expenditures of $1.675 billion (as per January 12, 2023 news release). Based on a current share price of $60, Tourmaline is trading at an approximate 10% free cash flow yield in 2023 while growing production 6% year over year, based on expected 2023 FCF.
- Tourmaline generated cash flow of $1.4 billion and free cash flow of $908.7 million in Q4 2022 on total capital expenditures (before A&D) of $494.0 million.
- Exit 2022 net debt was $494 million (0.1 times Q4 2022 annualized cash flow) and well below the Company's long-term net debt target of $1.0-1.2 billion. Tourmaline is in a surplus position when including the value of its 45.1 million shares in Topaz Energy Corp. ("Topaz") (valued at $954 million using the closing price of the Topaz common shares on December 31, 2022 of $21.13/share).
2022 RESERVES
- Year-end 2022 PDP reserves of 1.001 billion boe were up 25% over year-end 2021 including 2022 annual production of 183 million boe. TP reserves of 2.32 billion boe were up 14% including 2022 annual production. 2P reserves of 4.50 billion boe were up 10% including 2022 annual production. The vast majority of the 2022 additions (88%) were from the ongoing organic EP growth program.
- Tourmaline's 2P reserve value (before taxes) equates to $143 per diluted share (after tax reserve value is $109 per diluted share) using the January 1, 2023, engineering price deck and a 10% discount rate. TP reserve value (before tax) is $97 per diluted share and $75 per diluted share (after tax). PDP reserve value is $54 per diluted share (before tax) and $44 per diluted share (after tax) using the same pricing and discount rates.
- Tourmaline's 2022 PDP finding, development and acquisition ("FD&A") costs were $8.74 per boe(11), excluding changes in future development capital ("FDC"), yielding a PDP reserve recycle ratio(12)(13) of 3.06 (3.41 utilizing Q4 2022 cash flow per boe(14) of $29.80).
- TP FD&A costs in 2022 were $10.74 per boe, including changes in FDC, and TP FD&A costs were $6.52 per boe, excluding changes in FDC. The TP FD&A recycle ratio (including FDC) was 2.5 in 2022.
- 2P FD&A costs in 2022 were $10.59 per boe, including changes in FDC, and 2P FD&A costs were $4.70 per boe, excluding changes in FDC. The FDC account was significantly increased in the 2022 year-end reserve report to better reflect current inflationary pressures. The impact of this increase resulted in a significant increase in 2022 2P FD&A costs, as the full change in FDC is absorbed in the current year. The Company does not believe this is representative of the FD&A costs that relate purely to the Company's 2022 EP program. The 2P, three-year average FD&A costs are $5.41/boe, including the higher FDCs in 2022.
- Tourmaline replaced 240% of its 2022 annual production of 183 million boe with 2P additions of 440 million boe, including 2022 production.
- After 14 years of operations, Tourmaline now has 20.7 Tcf of 2P natural gas reserves, the largest in Canada and one of the largest, lowest development cost, lowest emission natural gas reserve bases in North America. The Company also has 1.06 billion boe of 2P crude oil, condensate and NGL (natural gas liquids) reserves (December 31, 2022), one of the largest conventional liquid reserve bases in Canada.
- Tourmaline has only booked 3,359 (gross) locations of a total drilling inventory of 23,077 gross locations (14.6% of the overall inventory) to achieve year-end 2022 2P reserves of 4.50 billion boe.
- The current FDCs associated with 2P reserves represent approximately four years of prospective cash flow at strip pricing. Although the Company has the execution capability to convert the entire 4.5 billion boe of 2P reserves to PDP in that time frame, it does not believe that would be constructive for the current encouraging supply/demand dynamics in the WCSB, or the appropriate capital allocation decision.
MARKETING UPDATE
- Tourmaline continues to diversify its natural gas and liquids marketing portfolio in order to realize the best pricing possible for all of its hydrocarbon streams. That diversification played a major role in enhancing Q4 2022 cash flow as well as full year 2023 expected cash flow.
- In 2021, the Company further diversified its gas marketing portfolio by establishing a US Gulf Coast LNG long-term gas supply agreement with Cheniere Energy. In January 2023, Tourmaline commenced delivery of 140 mmcfpd to the Cheniere Sabine Pass LNG facility and became the first Canadian EP company to participate in the LNG business with exposure to JKM pricing, providing a material increase to anticipated 2023 cash flow (based on the February 15, 2023 JKM strip pricing). The Company receives the JKM price, net of liquification and shipping fees. The 2023 JKM strip is USD $19.24/mcf. Tourmaline currently has an average of 27 mmcfpd hedged at a weighted average fixed JKM price of USD $34.196/mcf in 2023.
- During 2023, the Company will increase natural gas volumes exported to western US markets from 345 mmcfpd to 495 mmcfpd, with an average of 74% of the natural gas accessing the premium priced PG&E California market over the calendar year.
- Average realized natural gas price in Q4 2022 was $6.89/mcf as the Company benefited primarily from strong gas pricing in Western North America. In Q4 2022, the Malin index averaged USD $14.42/mcf, and the PG&E California index averaged USD $15.87/mcf.
- Tourmaline has an average of 791 mmcfpd hedged for 2023 at a weighted average fixed price of CAD $5.93/mcf, an average of 140 mmcfpd hedged at a basis to Nymex of USD $0.42/mcf, and an average of 698 mmcfpd of unhedged volumes exposed to export markets in 2023, including Dawn, Iroquois, Great Lakes, Empress, Chicago, Ventura, Sumas, US Gulf Coast, JKM, Malin, and PG&E.
- Tourmaline is Canada's largest NGL producer with anticipated average production levels of over 70,000 bpd in 2023.
EP UPDATE
- Tourmaline drilled a total of 240 net wells during 2022 for a total of 1,285,407 metres (607,163 HZ metres), the most in the WCSB. In 2022, the Company increased average lateral length by over 12.6%, the number of stages per well by 13% and average sand tonnage by 19% over 2021.
- Tourmaline operated 13 to 14 drilling rigs and four to five frac spreads across the three operated core EP complexes during January and February of 2023, as originally planned.
- The Company expects to drill and complete a total of approximately 300 wells (gross) during 2023.
- There are no material facility projects in the 2023 budget; as such, the Company anticipates 2023 capital efficiencies(15) of approximately $9,000/boepd.
- The Company continues to evolve the Conroy North Montney development project. This minimum 100,000 boepd gas and liquids project is currently planned for the 2025-2027 timeframe, coinciding with the projected startup of LNG Canada and anticipated related strong intra-Basin natural gas pricing. Facility expenditures on this fully sanctioned project will commence in 2024. The agreement between the BRFN and the BC Government announced on January 18, 2023, provides a framework that facilitates the planning, permitting and execution of this major project.
- Tourmaline had over 300 valid drilling permits in NEBC entering 2023 and has received an additional 55 permits during the first quarter of 2023 thus far.
- The Company drilled 11 new pool/new zone discovery and delineation wells in 2022 and has made two additional discoveries in 2023 to date.
- One net rig will continue to drill new pool/new zone exploration wells in 2023. The Company has completed, and tested, a significant extension during the first quarter of 2023 for one of the three material discoveries made to date through the program. Significant incremental reserve increases are anticipated in 2023.
- It is expected that successful discoveries will be able to access existing Tourmaline infrastructure.
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ENVIRONMENTAL PERFORMANCE IMPROVEMENT
- Tourmaline has had an engineering team in place for four years developing and implementing new proprietary emission reduction technologies, executing expanded water management initiatives, managing third party environmental related research, evolving a methane testing centre, and managing an emerging carbon offset business. Tourmaline intends to invest $30-50 million per year on environmental performance improvement initiatives.
- The Company is displacing diesel with natural gas on all the drilling rigs in the operated fleet, and currently has one rig running directly on high line power. Since embarking on this initiative over five years ago, the Company has displaced approximately 91.3 million litres of diesel, yielding an emission reduction of 57,888 tonnes and net cost savings of approximately Cdn$86.0 million.
- In working with Trican Well Services Ltd., the first Canadian Tier 4 fleet was deployed in October 2021 with continued successful deployment of Tier 4 fleets operating for the Company during 2022 in Alberta and NEBC.
- Tourmaline is recognized as having the lowest freshwater intensity for 2021 in Alberta at an intensity of 0.11bbl/boe, 12 months after fracturing. The Company continues to make significant investments to expand water management/water recycling capability in all three operated complexes.
- Also in 2022, Tourmaline expanded operations at the Company-operated Emission Testing Center ("ETC"), the first of its kind in the world, at the West Wolf gas plant. To date, 18 new clean technologies have been tested at the ETC. The ETC is critical in evolving new technology and methodologies in order to continue materially reducing methane and other emissions over the entire EP business.
DIVIDEND
- The Company is pleased to announce that its Board of Directors has declared a quarterly cash dividend on its common shares of $0.25 per common share. The dividend will be payable on March 31, 2023 to shareholders of record at the close of business on March 15, 2023. This quarterly cash dividend is designated as an "eligible dividend" for Canadian income tax purposes.
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(1) |
This news release contains certain specified financial measures consisting of non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures. See "Non-GAAP and Other Financial Measures" in this news release for information regarding the following non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures used in this news release: "cash flow", "capital expenditures", "free cash flow", "operating netback", "operating netback per boe", "cash flow per boe", "cash flow per diluted share", "free cash flow per diluted share", "adjusted working capital" and "net debt". Since these specified financial measures do not have standardized meanings under International Financial Reporting Standards ("GAAP"), securities regulations require that, among other things, they be identified, defined, qualified and, where required, reconciled with their nearest GAAP measure and compared to the prior period. See "Non-GAAP and Other Financial Measures" in this news release and in the Company's Management's Discussion and Analysis for the year ended December 31, 2022 (the "Annual MD&A"), which information is incorporated by reference into this news release, for further information on the composition of and, where required, reconciliation of these measures. |
(2) |
"Cash flow per diluted share" is a non-GAAP financial ratio. Cash flow, a non-GAAP financial measure, is used as a component of the non-GAAP financial ratio. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(3) |
"Free cash flow" is a non-GAAP financial measure defined as cash flow less capital expenditures, excluding acquisitions and dispositions. Free cash flow is prior to dividend payments. See "Non-GAAP and Other Financial Measures" in this news release. |
(4) |
Calculated as the dividend per common share for the year divided by the average common share price for the year. |
(5) |
2P, TP and PDP reserve value per diluted share is calculated as the net present value of the reserves (before or after tax, as the case may be) as at December 31, 2022 discounted at 10%, divided by the number of diluted weighted average common shares outstanding for the year ended December 31, 2022. |
(6) |
Supplementary financial measure. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(7) |
Based on oil and gas commodity strip pricing at February 15, 2023. |
(8) |
"Capital Expenditures" is a non-GAAP financial measure defined as cash flow from investing activities adjusted for the change in non-cash working capital (deficit), and corporate acquisitions. See "Non-GAAP Financial Measures" in this news release and in the Annual MD&A. |
(9) |
Calculated as forecast 2023 FCF per diluted share (based on estimated diluted Common Shares of 345 million) divided by the stated share price per Common Share. |
(10) |
"Net debt" is a capital management measure. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(11) |
Non-GAAP financial ratio. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(12) |
Non-GAAP financial ratio. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. 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. |
(13) |
Non-GAAP financial ratio. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(14) |
Non-GAAP financial ratio. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(15) |
Capital efficiencies are calculated as capital expenditures divided by estimated production added over the period. |
CORPORATE SUMMARY – DECEMBER 31, 2022
Three Months Ended December 31, |
Year Ended December 31, |
|||||||||
2022 |
2021 |
Change |
2022 |
2021 |
Change |
|||||
OPERATIONS |
||||||||||
Production |
||||||||||
Natural gas (mcf/d) |
2,376,463 |
2,269,290 |
5 % |
2,330,234 |
2,063,455 |
13 % |
||||
Crude oil, condensate and NGL |
115,513 |
106,863 |
8 % |
112,460 |
97,206 |
16 % |
||||
Oil equivalent (boe/d) |
511,590 |
485,078 |
5 % |
500,832 |
441,115 |
14 % |
||||
Product prices(1) |
||||||||||
Natural gas ($/mcf) |
$ |
6.89 |
$ |
4.66 |
48 % |
$ |
5.87 |
$ |
3.94 |
49 % |
Crude oil, condensate and NGL |
$ |
63.01 |
$ |
56.66 |
11 % |
$ |
66.97 |
$ |
47.89 |
40 % |
Operating expenses ($/boe) (2) |
$ |
4.38 |
$ |
3.95 |
11 % |
$ |
4.30 |
$ |
3.77 |
14 % |
Transportation costs ($/boe) (3) |
$ |
5.08 |
$ |
4.45 |
14 % |
$ |
4.92 |
$ |
4.25 |
16 % |
Operating netback ($/boe) (4) |
$ |
30.56 |
$ |
22.10 |
38 % |
$ |
27.04 |
$ |
18.57 |
46 % |
Cash general and |
$ |
0.56 |
$ |
0.49 |
14 % |
$ |
0.57 |
$ |
0.54 |
6 % |
FINANCIAL |
||||||||||
Total revenue from commodity sales |
2,176,463 |
1,529,345 |
42 % |
7,742,837 |
4,669,263 |
66 % |
||||
Royalties |
292,784 |
168,168 |
74 % |
1,115,549 |
387,914 |
188 % |
||||
Cash flow |
1,402,647 |
968,236 |
45 % |
4,883,949 |
2,929,126 |
67 % |
||||
Cash flow per share (diluted) |
$ |
4.08 |
$ |
2.88 |
42 % |
$ |
14.26 |
$ |
9.25 |
54 % |
Net earnings |
(30,366) |
996,248 |
(103) % |
4,487,049 |
2,025,991 |
121 % |
||||
Net earnings per share (diluted) |
$ |
(0.09) |
$ |
2.96 |
(103) % |
$ |
13.10 |
$ |
6.40 |
105 % |
Capital expenditures (net of |
505,982 |
447,461 |
13 % |
1,879,347 |
1,590,371 |
18 % |
||||
Weighted average shares outstanding |
342,533,099 |
316,788,967 |
8 % |
|||||||
Net debt |
(494,442) |
(972,979) |
(49) % |
|||||||
PROVED + |
||||||||||
Natural gas (bcf) |
20,663.8 |
19,487.1 |
6 % |
|||||||
Crude oil (mbbls) |
114,367 |
98,345 |
16 % |
|||||||
Natural gas liquids (mbbls) |
941,936 |
896,793 |
5 % |
|||||||
Mboe |
4,500,272 |
4,242,981 |
6 % |
|||||||
Notes: |
|
(1) |
Product prices include realized gains and losses on risk management activities and financial instrument contracts. |
(2) |
Supplementary financial measure. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(3) |
Supplementary financial measure. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(4) |
Excluding interest and financing charges. Non-GAAP financial measure and non-GAAP ratio. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(5) |
Non-GAAP financial measure and non-GAAP ratio. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(6) |
Non-GAAP financial measure. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. |
(7) |
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. |
2022 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.
Reserves and Future Net Revenue Data (Forecast Prices and Costs)
Summary of Crude Oil, Natural Gas and Natural Gas Liquids Reserves and |
||||||||||||||||||||
Light & Medium Crude |
Conventional Natural |
Shale Natural Gas(2) |
Natural Gas Liquids |
Total Oil Equivalent |
||||||||||||||||
Reserves Category |
Company |
Company |
Company |
Company |
Company |
Company |
Company |
Company |
Company Gross (Mboe) |
Company Net (Mboe) |
||||||||||
Proved Producing |
15,761 |
12,385 |
2,283,478 |
2,009,384 |
2,406,984 |
1,854,524 |
203,670 |
166,320 |
1,001,175 |
822,689 |
||||||||||
Proved Developed Non- |
1,320 |
967 |
95,709 |
82,882 |
216,512 |
174,341 |
14,484 |
12,101 |
67,841 |
55,939 |
||||||||||
Proved Undeveloped |
43,645 |
33,359 |
2,403,189 |
2,099,405 |
3,400,823 |
2,712,735 |
241,962 |
200,937 |
1,252,943 |
1,036,320 |
||||||||||
Total Proved |
60,726 |
46,711 |
4,782,376 |
4,191,671 |
6,024,319 |
4,741,600 |
460,116 |
379,358 |
2,321,959 |
1,914,948 |
||||||||||
Total Probable |
53,640 |
41,417 |
3,183,615 |
2,711,649 |
6,673,506 |
5,108,451 |
481,819 |
390,154 |
2,178,313 |
1,734,921 |
||||||||||
Total Proved Plus Probable |
114,367 |
88,129 |
7,965,991 |
6,903,320 |
12,697,825 |
9,850,051 |
941,936 |
769,512 |
4,500,272 |
3,649,869 |
||||||||||
Reserves Category |
Net Present Values of Future Net Revenue ($000s) |
||||||||||||||||||||||||||||
Before Income Taxes Discounted at (2) |
After Income Taxes Discounted at (2) (3) |
Unit Value |
|||||||||||||||||||||||||||
0 |
5 |
8 |
10 |
15 |
20 |
0 |
5 |
8 |
10 |
15 |
20 |
($/Boe) |
($/Mcfe) |
||||||||||||||||
Proved Producing |
27,256,608 |
22,048,650 |
19,815,550 |
18,594,008 |
16,202,116 |
14,452,939 |
21,685,281 |
17,643,107 |
15,880,983 |
14,913,475 |
13,014,064 |
11,621,938 |
22.60 |
3.77 |
|||||||||||||||
Proved Developed Non- |
1,547,216 |
1,185,761 |
1,045,007 |
970,579 |
829,370 |
729,452 |
1,151,010 |
881,261 |
775,795 |
719,940 |
613,796 |
538,537 |
17.35 |
2.89 |
|||||||||||||||
Proved Undeveloped |
31,743,036 |
20,066,138 |
15,818,145 |
13,668,368 |
9,832,017 |
7,367,494 |
23,731,897 |
14,875,960 |
11,646,742 |
10,012,402 |
7,098,117 |
5,230,277 |
13.19 |
2.20 |
|||||||||||||||
Total Proved |
60,546,860 |
43,300,549 |
36,678,702 |
33,232,955 |
26,863,503 |
22,549,885 |
46,568,188 |
33,400,328 |
28,303,520 |
25,645,816 |
20,725,977 |
17,390,752 |
17.35 |
2.89 |
|||||||||||||||
Total Probable |
54,739,447 |
26,882,473 |
19,218,845 |
15,791,766 |
10,376,611 |
7,344,119 |
40,697,268 |
19,870,844 |
14,132,259 |
11,567,762 |
7,523,462 |
5,268,589 |
9.10 |
1.52 |
|||||||||||||||
Total Proved Plus |
115,286,307 |
70,183,022 |
55,897,547 |
49,024,720 |
37,240,114 |
29,894,004 |
87,265,456 |
53,271,172 |
42,435,779 |
37,213,578 |
28,249,439 |
22,659,340 |
13.43 |
2.24 |
|||||||||||||||
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) |
||||||||||||||||
Reserves Category |
Revenue |
Royalties |
Operating |
Capital |
Abandonment |
Future Net |
Income |
Future Net |
||||||||
Proved Producing |
42,824,434 |
5,775,434 |
8,703,218 |
1,125 |
1,088,049 |
27,256,608 |
5,571,327 |
21,685,281 |
||||||||
Proved Developed Non- |
2,434,472 |
301,383 |
467,582 |
94,982 |
23,309 |
1,547,216 |
396,207 |
1,151,010 |
||||||||
Proved |
54,968,413 |
7,322,603 |
8,482,475 |
7,037,299 |
382,999 |
31,743,036 |
8,011,139 |
23,731,897 |
||||||||
Total |
100,227,318 |
13,399,419 |
17,653,275 |
7,133,407 |
1,494,357 |
60,546,860 |
13,978,672 |
46,568,188 |
||||||||
Total |
93,842,747 |
14,329,453 |
17,685,183 |
6,488,314 |
600,351 |
54,739,447 |
14,042,179 |
40,697,268 |
||||||||
Total Proved Plus |
194,070,065 |
27,728,872 |
35,338,459 |
13,621,720 |
2,094,708 |
115,286,307 |
28,020,851 |
87,265,456 |
||||||||
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 |
||||||||||||||||||
Crude Oil and Natural Gas Liquids Pricing |
||||||||||||||||||
Year |
Inflation(2) % |
|||||||||||||||||
CAD/USD |
NYMEX WTI Near |
MSW, Light |
Alberta Natural Gas Liquids |
|||||||||||||||
Constant |
Then |
Spec |
Edmonton |
Edmonton |
Edmonton |
|||||||||||||
2023 |
0.0 |
0.7450 |
80.33 |
80.33 |
103.77 |
13.75 |
39.80 |
53.88 |
106.22 |
|||||||||
2024 |
2.3 |
0.7650 |
76.71 |
78.50 |
97.74 |
14.33 |
39.13 |
52.67 |
101.35 |
|||||||||
2025 |
2.0 |
0.7683 |
73.72 |
76.95 |
95.27 |
13.77 |
39.74 |
51.42 |
98.94 |
|||||||||
2026 |
2.0 |
0.7717 |
72.89 |
77.61 |
95.58 |
13.98 |
39.86 |
51.61 |
100.19 |
|||||||||
2027 |
2.0 |
0.7750 |
72.89 |
79.16 |
97.07 |
14.20 |
40.47 |
52.39 |
101.74 |
|||||||||
2028 |
2.0 |
0.7750 |
72.90 |
80.75 |
99.01 |
14.49 |
41.28 |
53.44 |
103.78 |
|||||||||
2029 |
2.0 |
0.7750 |
72.90 |
82.36 |
100.99 |
14.79 |
42.11 |
54.51 |
105.85 |
|||||||||
2030 |
2.0 |
0.7750 |
72.89 |
84.01 |
103.01 |
15.09 |
42.95 |
55.60 |
107.97 |
|||||||||
2031 |
2.0 |
0.7750 |
72.89 |
85.69 |
105.07 |
15.39 |
43.81 |
56.71 |
110.13 |
|||||||||
2032 |
2.0 |
0.7750 |
72.90 |
87.40 |
106.69 |
15.71 |
44.47 |
57.56 |
112.33 |
|||||||||
2033 |
2.0 |
0.7750 |
72.89 |
89.15 |
108.83 |
16.02 |
45.35 |
58.71 |
114.58 |
|||||||||
2034 |
2.0 |
0.7750 |
72.90 |
90.93 |
111.00 |
16.34 |
46.26 |
59.88 |
116.87 |
|||||||||
2035 |
2.0 |
0.7750 |
72.89 |
92.75 |
113.22 |
16.67 |
47.19 |
61.08 |
119.21 |
|||||||||
2036 |
2.0 |
0.7750 |
72.89 |
94.60 |
115.49 |
17.00 |
48.13 |
62.30 |
121.59 |
|||||||||
2037 |
2.0 |
0.7750 |
72.89 |
96.50 |
117.80 |
17.34 |
49.09 |
63.55 |
124.03 |
|||||||||
2038 |
2.0 |
0.7750 |
72.89 |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
|||||||||
Year |
Natural Gas and Sulphur Pricing |
|||||||||||||||||||||||
NYMEX Henry Hub |
Midwest |
AECO/NIT Then Current |
Alberta Plant Gate |
Sumas Spot |
British Columbia |
JKM |
||||||||||||||||||
Spot |
ARP $Cdn/ |
Westcoast |
Spot Plant |
|||||||||||||||||||||
Constant |
Then Current |
Dawn Price @ Ontario Then |
Constant |
Then Current |
||||||||||||||||||||
2023 |
4.74 |
4.74 |
4.50 |
4.23 |
4.67 |
3.92 |
3.92 |
3.92 |
5.03 |
4.08 |
3.73 |
29.83 |
||||||||||||
2024 |
4.40 |
4.50 |
4.29 |
4.40 |
4.43 |
3.99 |
4.09 |
4.09 |
4.61 |
4.28 |
3.92 |
26.38 |
||||||||||||
2025 |
4.13 |
4.31 |
4.10 |
4.21 |
4.24 |
3.73 |
3.90 |
3.90 |
4.43 |
4.10 |
3.75 |
20.50 |
||||||||||||
2026 |
4.13 |
4.40 |
4.19 |
4.27 |
4.32 |
3.72 |
3.96 |
3.96 |
4.52 |
4.16 |
3.81 |
17.80 |
||||||||||||
2027 |
4.13 |
4.49 |
4.26 |
4.34 |
4.41 |
3.70 |
4.02 |
4.02 |
4.61 |
4.23 |
3.87 |
17.62 |
||||||||||||
2028 |
4.13 |
4.58 |
4.35 |
4.43 |
4.50 |
3.71 |
4.11 |
4.11 |
4.70 |
4.32 |
3.95 |
17.95 |
||||||||||||
2029 |
4.13 |
4.67 |
4.44 |
4.51 |
4.59 |
3.71 |
4.20 |
4.20 |
4.80 |
4.40 |
4.03 |
18.30 |
||||||||||||
2030 |
4.13 |
4.76 |
4.54 |
4.60 |
4.68 |
3.72 |
4.29 |
4.29 |
4.90 |
4.49 |
4.13 |
18.65 |
||||||||||||
2031 |
4.13 |
4.86 |
4.61 |
4.69 |
4.77 |
3.72 |
4.37 |
4.37 |
4.99 |
4.58 |
4.21 |
19.02 |
||||||||||||
2032 |
4.13 |
4.95 |
4.71 |
4.79 |
4.87 |
3.72 |
4.46 |
4.46 |
5.10 |
4.67 |
4.30 |
19.40 |
||||||||||||
2033 |
4.13 |
5.05 |
4.81 |
4.89 |
4.97 |
3.72 |
4.55 |
4.55 |
5.20 |
4.76 |
4.39 |
19.76 |
||||||||||||
2034 |
4.13 |
5.15 |
4.91 |
4.98 |
5.07 |
3.72 |
4.64 |
4.64 |
5.30 |
4.86 |
4.47 |
20.13 |
||||||||||||
2035 |
4.13 |
5.26 |
5.01 |
5.08 |
5.17 |
3.73 |
4.74 |
4.74 |
5.41 |
4.96 |
4.57 |
20.51 |
||||||||||||
2036 |
4.13 |
5.36 |
5.11 |
5.18 |
5.28 |
3.73 |
4.84 |
4.84 |
5.52 |
5.06 |
4.65 |
20.90 |
||||||||||||
2037 |
4.13 |
5.47 |
5.21 |
5.29 |
5.38 |
3.73 |
4.93 |
4.93 |
5.63 |
5.16 |
4.75 |
21.31 |
||||||||||||
2038 |
4.13 |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
+2.0%/yr |
3.73 |
+2.0%/yr |
+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, 2022 and GLJ and McDaniel & Associates Consultants Ltd. as at January 1, 2023 (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, Kingsgate and US Gulf Coast 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, 2022. |
(2) |
Inflation rates used for forecasting prices and costs, with the exception of capital expenditures, which have been forecasted to have nil inflation until 2026, at which time the inflation profile is as published in these tables. |
(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, and for the Year ended December 31, |
2022 |
2021 |
2020 |
Reserves (Mboe) |
|||
Proved Producing |
1,001,175 |
947,293 |
736,448 |
Total Proved |
2,321,959 |
2,187,870 |
1,691,056 |
Proved Plus Probable |
4,500,272 |
4,242,981 |
3,314,264 |
Capital Expenditures ($ millions) |
|||
Exploration and Development(2) |
1,677 |
1,437 |
912 |
Net Property Acquisitions (Dispositions)(3) |
202 |
196 |
172 |
Net Corporate Acquisitions (Dispositions)(3) |
188 |
1,232 |
794 |
Less: Topaz Property Acquisitions(4) |
– |
(161) |
(119) |
Total(5) |
2,067 |
2,704 |
1,759 |
Cash Flow ($/boe) |
|||
Cash Flow |
26.72 |
18.19 |
10.43 |
Cash Flow - Three Year Average |
19.67 |
13.97 |
11.67 |
Notes: |
|
(1) |
Cash flow is defined as cash provided by operations before changes in non-cash operating working capital. See "Non-GAAP and Other Financial Measures" below and in the Annual MD&A for further discussion. |
(2) |
Includes capitalized G&A of $47 million, $38 million and $32 million for 2022, 2021, and 2020 respectively. |
(3) |
Includes purchase price (cash and/or common shares) plus net debt, if applicable. |
(4) |
Includes property acquisitions incurred by Topaz from non-related parties, prior to June 8, 2021, when it was a controlled subsidiary of Tourmaline. |
(5) |
Represents the capital expenditures used for purposes of F&D and FD&A calculations. |
Finding and Development Costs
Finding and Development Costs, Excluding FDC |
2022 |
2021 |
2020 |
3-Year Avg. |
Total Proved |
||||
Reserve Additions (MMboe) |
284.6 |
257.6 |
185.4 |
|
F&D Costs ($/boe) |
5.89 |
5.58 |
4.92 |
5.53 |
F&D Recycle Ratio(1) |
4.5 |
3.3 |
2.1 |
3.6 |
Total Proved Plus Probable |
||||
Reserve Additions (MMboe) |
387 |
232.2 |
210.5 |
|
F&D Costs ($/boe) |
4.33 |
6.19 |
4.33 |
4.85 |
F&D Recycle Ratio(1) |
6.2 |
2.9 |
2.4 |
4.1 |
Finding and Development Costs, Including FDC |
2022 |
2021 |
2020 |
3-Year Avg. |
Total Proved |
||||
Change in FDC ($ millions) |
1,202 |
197.2 |
(286.0) |
|
Reserve Additions (MMboe) |
284.6 |
257.6 |
185.4 |
|
F&D Costs ($/boe) |
10.12 |
6.34 |
3.38 |
7.06 |
F&D Recycle Ratio(1) |
2.6 |
2.9 |
3.1 |
2.8 |
Total Proved Plus Probable |
||||
Change in FDC ($ millions) |
2,380.7 |
41.6 |
(566.3) |
|
Reserve Additions (MMboe) |
387 |
232.2 |
210.5 |
|
F&D Costs ($/boe) |
10.49 |
6.37 |
1.64 |
7.09 |
F&D Recycle Ratio(1) |
2.5 |
2.9 |
6.4 |
2.8 |
Finding, Development and Acquisition Costs
Finding, Development and Acquisition Costs, |
2022 |
2021 |
2020 |
3-Year Avg. |
Total Proved |
||||
Reserve Additions (MMboe) |
316.9 |
657.8 |
510.3 |
|
FD&A Costs ($/boe) |
6.52 |
4.11 |
3.45 |
4.40 |
FD&A Recycle Ratio(1) |
4.1 |
4.4 |
3.0 |
4.5 |
Total Proved Plus Probable |
||||
Reserve Additions (MMboe) |
440.1 |
1,089.7 |
826.0 |
|
FD&A Costs ($/boe) |
4.70 |
2.48 |
2.13 |
2.77 |
FD&A Recycle Ratio(1) |
5.7 |
7.3 |
4.9 |
7.1 |
Finding, Development and Acquisition Costs, |
2022 |
2021 |
2020 |
3-Year Avg. |
Total Proved |
||||
Change in FDC ($ millions) |
1,337.3 |
1,201.1 |
723.3 |
|
Reserve Additions (MMboe) |
316.9 |
657.8 |
510.3 |
|
FD&A Costs ($/boe) |
10.74 |
5.94 |
4.86 |
6.59 |
FD&A Recycle Ratio(1) |
2.5 |
3.1 |
2.1 |
3.0 |
Total Proved Plus Probable |
||||
Change in FDC ($ millions) |
2,593.0 |
2,241.2 |
1,383.5 |
|
Reserve Additions (MMboe) |
440.1 |
1,089.7 |
826.0 |
|
FD&A Costs ($/boe) |
10.59 |
4.54 |
3.80 |
5.41 |
FD&A Recycle Ratio(1) |
2.5 |
4.0 |
2.7 |
3.6 |
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 2, 2023 starting at 9:00 a.m. MT (11:00 a.m. ET).
To participate without operator assistance, you may register and enter your phone number at https://bit.ly/3ROiPpp to receive an instant automated call back.
To participate using an operator, please dial 1-888-664-6383 (toll-free in North America), or 1-416-764-8650 (international dial-in), a few minutes prior to the conference call.
Conference ID is 03091736.
Reader Advisories
CURRENCY
All amounts in this news release are stated in Canadian dollars unless otherwise specified.
FORWARD-LOOKING INFORMATION
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, business opportunities and shareholder return plan, including the following: the future declaration and payment of base and special dividends and the timing and amount thereof which assumes, among other things, the availability of free cash flow to fund such dividends; the Company's plan to return between 50-90% of free cash flow to shareholders; anticipated 2023 cash flow and free cash flow and long-term net debt targets; anticipated petroleum and natural gas production and production growth for various periods including estimated production levels for the first quarter of 2023 and full-year 2023 and condensate and NGL production growth anticipated from the Company's Conroy North Montney development project; expected full-year 2023 EP capital spending levels and anticipated capital efficiencies; the number of wells expected to be drilled in 2023; the anticipated restart of the Pembina Pipeline Corporation Northern pipeline system; anticipated natural gas prices; anticipated increase in natural gas volumes to western US markets; anticipated inflationary contingencies; anticipated strong intra-Basin natural gas pricing from the startup of LNG Canada; anticipated reserve increases resulting from exploration activities, and the anticipated ability of successful exploration discoveries to access existing Tourmaline infrastructure; the timing for facility expansions and facility start-up dates; sustainability and environmental improvement initiatives; the anticipated amount to be invested per year on environmental performance improvement initiatives; 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; the degree to which Tourmaline's operations and production may be disrupted or by circumstances attributable to supply chain disruptions; applicable royalty rates and tax laws; interest rates; inflation rates; future well production rates and reserve volumes; operating costs, receipt of regulatory approvals and the timing thereof; 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 benefits to be derived from acquisitions; 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 natural gas liquids 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 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; supply chain disruptions; 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; changes in rates of inflation; 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; uncertainties associated with counterparty credit risk; failure to obtain required regulatory and other approvals including drilling permits and the impact of not receiving such approvals on the Company's long-term planning; 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 which 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, 2022, 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 forecast prices published by Sproule Associates Ltd. as at December 31, 2022 and GLJ and McDaniel & Associates Consultants Ltd. as at January 1, 2023 (each of which is available on their respective websites at www.sproule.com, www.gljpc.com, and www.mcdan.com), and will be contained in the Company's Annual Information Form for the year ended December 31, 2022, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2023.
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, 2022, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2023.
BOE EQUIVALENCY
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.
INDUSTRY METRICS
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", and "FD&A recycle ratio". These metrics are considered "non-GAAP ratios" and 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. See "Non-GAAP and Other Financial Measures" in this news release and in the Annual MD&A. The non-GAAP financial measures used as a component of these non-GAAP ratios are capital expenditures and cash flow.
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 "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.
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.
FINANCIAL OUTLOOKS
Also included in this news release are estimates of Tourmaline's 2023 cash flow and free cash flow, which are based on, among other things, the various assumptions as to production levels, capital expenditures and other assumptions disclosed in this news release and including Tourmaline's estimated 2023 average production of 530,000 boepd, 2023 commodity price assumptions for natural gas ($3.20/mcf NYMEX US, $2.80/mcf AECO, $18.12/mcf JKM US), crude oil ($77.85/bbl WTI US) and an exchange rate assumption of $0.75 (US/CAD). To the extent such estimates constitute a financial outlook, it was approved by management and the Board of Directors of Tourmaline on March 1, 2023 and is included to provide readers with an understanding of Tourmaline's anticipated cash flow and free cash flow based on the capital expenditure, production, pricing, exchange rate and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.
NON-GAAP AND OTHER FINANCIAL MEASURES
This news release contains the terms "cash flow", "capital expenditures", "free cash flow" and "operating netback", which are considered "non-GAAP financial measures" and the terms "cash flow per diluted share", "free cash flow per diluted share", "operating netback per boe", "cash flow per boe", "finding and development costs", "finding, development and acquisition costs" and "recycle ratio", which are considered "non-GAAP ratios". These terms do not have standardized meanings prescribed by GAAP. In addition, this news release contains the terms "adjusted working capital" and "net debt", which are considered "capital management measures" and also do not have standardized meanings prescribed by GAAP. Accordingly, the Company's use of these terms may not be comparable to similarly defined measures presented by other companies. Investors are cautioned that these measures should not be construed as an alternative to or more meaningful than the most directly comparable GAAP measures in evaluating the Company's performance. See "Non-GAAP and Other Financial Measures" in the most recent Management's Discussion and Analysis for more information on the definition and description of these terms.
Non-GAAP Financial Measures
Management uses the term "cash flow" for its own performance measure 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 its future growth expenditures, to repay debt or to pay dividends. The most directly comparable GAAP measure for cash flow is cash flow from operating activities. A summary of the reconciliation of cash flow from operating activities to cash flow, is set forth below:
Three Months Ended |
Years Ended |
||||
(000s) |
2022 |
2021 |
2022 |
2021 |
|
Cash flow from operating activities (per GAAP) |
$ 1,115,399 |
$ |
1,058,460 |
$ 4,692,731 |
$ 2,847,117 |
Current Income Taxes |
(7,599) |
- |
(11,934) |
- |
|
Change in non-cash working capital (deficit) |
294,847 |
(90,224) |
203,152 |
82,009 |
|
Cash flow |
$ 1,402,647 |
$ |
968,236 |
$ 4,883,949 |
$ 2,929,126 |
Management uses the term "capital expenditures" as a measure of capital investment in exploration and production activity, as well as property acquisitions and divestitures, and such spending is compared to the Company's annual budgeted capital expenditures. The most directly comparable GAAP measure for capital expenditures is cash flow used in investing activities. A summary of the reconciliation of cash flow used in investing activities to capital expenditures, is set forth below:
Three Months Ended |
Years Ended |
|||
(000s) |
2022 |
2021 |
2022 |
2021 |
Cash flow used in investing activities (per GAAP) |
$ 548,471 |
$ 468,384 |
$ 1,971,129 |
$ 1,380,111 |
Corporate acquisitions |
- |
- |
(67,770) |
- |
Proceeds from sale of investments |
- |
- |
- |
103,824 |
Change in non-cash working capital (deficit) |
(42,489) |
(20,923) |
(24,012) |
106,436 |
Capital expenditures |
$ 505,982 |
$ 447,461 |
$ 1,879,347 |
$ 1,590,371 |
Management uses the term "free cash flow" for its own performance measure 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 its future growth expenditures, to repay debt and provide shareholder returns. Free cash flow is defined as cash flow less capital expenditures, excluding acquisitions and dispositions. Free cash flow is prior to dividend payment. The most directly comparable GAAP measure for cash flow is cash flow from operating activities. See "Non-GAAP Financial Measures – Cash Flow" and " Non-GAAP Financial Measures – Capital Expenditures" above.
Three Months Ended |
Years Ended |
||||
(000s) |
2022 |
2021 |
2022 |
2021 |
|
Cash flow |
$ |
1,402,647 |
$ 968,236 |
$ 4,883,949 |
$ 2,929,126 |
Capital expenditures |
(505,982) |
(447,461) |
(1,879,347) |
(1,590,371) |
|
Property acquisitions |
12,126 |
26,721 |
273,843 |
545,861 |
|
Proceeds from divestitures |
(109) |
(1,560) |
(71,489) |
(392,556) |
|
Free Cash Flow |
$ |
908,682 |
$ 545,936 |
$ 3,206,956 |
$ 1,492,060 |
Management uses the term "operating netback" as a key performance indicator and one that is commonly presented by other oil and natural gas producers. Operating netback is defined as the sum of commodity sales from production, premium (loss) on risk management activities and realized gains (loss) on financial instruments less the sum of royalties, transportation costs and operating expenses. A summary of the reconciliation of operating netback to commodity sales from production, which is a GAAP measure, is set forth below:
Three Months Ended |
Years Ended |
||||
(000s) |
2022 |
2021 |
2022 |
2021 |
|
Commodity sales from production |
$ 1,932,515 |
$ |
1,709,063 |
$ 8,110,837 |
$ 5,053,611 |
Premium on risk management activities |
409,241 |
21,579 |
517,109 |
13,943 |
|
Realized loss on financial instruments |
(165,293) |
(201,297) |
(885,109) |
(398,291) |
|
Royalties |
(292,784) |
(168,168) |
(1,115,549) |
(387,914) |
|
Transportation costs |
(238,937) |
(198,537) |
(898,871) |
(683,737) |
|
Operating expenses |
(206,344) |
(176,360) |
(785,611) |
(607,292) |
|
Operating netback |
$ 1,438,398 |
$ |
986,280 |
$ 4,942,806 |
$ 2,990,320 |
Non-GAAP Financial Ratios
Management calculates "operating netback per-boe" as operating netback divided by total production for the period. Netback per-boe is a key performance indicator and measure of operational efficiency and one that is commonly presented by other oil and natural gas producers. A summary of the calculation of operating netback per boe, is set forth below:
Three Months Ended |
Years Ended |
|||
($/boe) |
2022 |
2021 |
2022 |
2021 |
Revenue, excluding processing income |
$ 46.24 |
$ 34.27 |
$ 42.36 |
$ 29.00 |
Royalties |
(6.22) |
(3.77) |
(6.10) |
(2.41) |
Transportation costs |
(5.08) |
(4.45) |
(4.92) |
(4.25) |
Operating expenses |
(4.38) |
(3.95) |
(4.30) |
(3.77) |
Operating netback |
$ 30.56 |
$ 22.10 |
$ 27.04 |
$ 18.57 |
Management uses cash flow per boe to highlight how much cash flow is generated by each boe produced. The ratio is calculated by dividing cash flow by total production for the period. See "Non-GAAP Financial Measures – Cash Flow". See "Reserves Performance Ratios" section for information on annual cash flow per boe and comparative period data used.
See "Reserves Performance Ratios" and "Industry Metrics" for information on the composition of the non-GAAP financial measures used as a component of and comparative period data for finding and development costs, finding, development and acquisition costs and recycle ratio.
Capital Management Measures
Management uses the term "adjusted working capital" for its own performance measures and to provide shareholders and potential investors with a measurement of the Company's liquidity. A summary of the composition of adjusted working capital (deficit), is set forth below:
As at December 31, |
||
(000s) |
2022 |
2021 |
Working capital (deficit) |
$ 809,449 |
$ (361,034) |
Fair value of financial instruments – short-term (asset) liability |
(709,286) |
240,970 |
Lease liabilities – short-term |
3,109 |
2,997 |
Decommissioning obligations – short-term |
30,000 |
20,103 |
Unrealized foreign exchange in working capital – (asset) |
(8,605) |
(6,441) |
Adjusted working capital (deficit) |
$ 124,667 |
$ (103,405) |
Management uses the term "net debt", as a key measure for evaluating its capital structure and to provide shareholders and potential investors with a measurement of the Company's total indebtedness. A summary of the composition of net debt, is set forth below:
As at December 31, |
||
(000s) |
2022 |
2021 |
Bank debt |
$ (170,767) |
$ (421,539) |
Senior unsecured notes |
(448,342) |
(448,035) |
Adjusted working capital (deficit) |
124,667 |
(103,405) |
Net debt |
$ (494,442) |
$ (972,979) |
Supplementary Financial Measures
The following measures are supplementary financial measures: cash flow per diluted share, reserve value per diluted share, operating expenses ($/boe), cash general and administrative expenses ($/boe) and transportation costs ($/boe). These measures are calculated by dividing the numerator by a diluted share count or by total production for the period, depending on the financial measure discussed.
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 current production, full-year 2022 production, Q4 2022 production and full-year 2023 expected 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 |
||||||
Company Gross |
Company Gross |
Company Gross |
Company Gross |
Company Gross |
||||||
Current Production |
45,000 |
1,335,000 |
1,125,000 |
70,000 |
525,000 |
|||||
2022 Production |
42,923 |
1,284,879 |
1,045,355 |
69,537 |
500,832 |
|||||
Q4 2022 Production |
43,549 |
1,310,520 |
1,065,943 |
71,964 |
511,590 |
|||||
2023 Expected Average |
48,300 |
1,336,100 |
1,118,500 |
72,600 |
530,000 |
|||||
(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. |
CREDIT RATINGS
Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities. Credit ratings are not recommendations to purchase, hold or sell securities and do not address the market price or suitability of a specific security for a particular investor. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant.
GENERAL
See also "Forward-Looking Statements", and "Non-GAAP and Other Financial Measures" in the most recently filed Management's Discussion and Analysis.
CERTAIN DEFINITIONS:
1H |
first half |
2H |
second half |
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 |
EP |
exploration and production |
gj |
gigajoule |
gjs/d |
gigajoules per day |
JKM |
Japan Korea Marker |
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 |
natural gas |
conventional natural gas and shale gas |
NCIB |
normal course issuer bid |
NGL or NGLs |
natural gas liquids |
Tcf |
trillion cubic feet |
ABOUT TOURMALINE OIL CORP.
Tourmaline is Canada's largest and most active natural gas producer dedicated to producing the lowest-emission and lowest-cost natural gas in North America. We are an investment grade exploration and production company providing strong and predictable operating and financial performance through the development of our three core areas in the Western Canadian Sedimentary Basin. With our existing large reserve base, decades-long drilling inventory, relentless focus on execution and cost management, and industry-leading environmental performance, we are excited to provide shareholders an excellent return on capital, and an attractive source of income through our base dividend and surplus free cash flow distribution strategies.
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; [email protected] OR Tourmaline Oil Corp., Scott Kirker, Chief Legal Officer, (403) 767-3593; [email protected] OR Tourmaline Oil Corp., Jamie Heard, Manager, Capital Markets, (403) 767-5942; [email protected] OR Tourmaline Oil Corp., Suite 2900, 250 - 6th Avenue S.W., Calgary, Alberta T2P 3H7, Phone: (403) 266-5992; Facsimile: (403) 266-5952, E-mail: [email protected], Website: www.tourmalineoil.com
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