Tourmaline Delivers Net Earnings Of $2 Billion In 2021, Adds 1,090 Mmboe Of 2P Reserves And Declares Dividend For Q1 2022

March 2, 2022 3:00 PM

CALGARY, AB, March 2, 2022 /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 2021 as well as 2021 reserves.

HIGHLIGHTS

Full-year average 2021 production of 441,115 boepd was up 42% over 2020 average production of 310,598 boepd.
Current production is ranging between 500,000-510,000 boepd, with a Q1 2022 exit of 510,000-515,000 boepd anticipated.
Full-year 2021 after tax net earnings were $2.03 billion ($6.40 per diluted share).
Full-year 2021 cash flow⁽¹⁾ was a record $2.93 billion ($9.25 per diluted share⁽²⁾) up 147% over 2020.
Tourmaline generated a record $1.49 billion of free cash flow⁽³⁾ (“FCF”) in 2021.
Exit 2021 net debt⁽⁴⁾ was $973 million (0.25 times 2021 net debt to Q4 annualized cash flow) and below the Company’s long-term net debt target of $1.0-1.2 billion.
Year-end 2021 proved, developed producing (“PDP”) reserves of 947.3 million boe were up 50%, total proved (“TP”) reserves of 2.19 billion boe were up 39% and proved plus probable (“2P”) reserves of 4.24 billion boe were up 33% over year-end 2020, including 2021 annual production of 161.0 million boe.
Tourmaline replaced 677% of its 2021 annual production of 161.0 million boe with 2P additions of 1.090 billion boe including 2021 production.
Tourmaline’s 2P reserve value⁽⁵⁾ equates to $97.54 per diluted share⁽⁶⁾ using the January 1, 2022 engineering price deck and a 10% discount rate. TP and PDP reserve value is $62.70 and $33.77 per diluted share⁽⁷⁾, respectively, using the same pricing and discount rates.
After 13 years of operations, Tourmaline now has 19.5 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 2021, the Company further diversified the gas marketing portfolio by establishing a US Gulf Coast LNG pathway and entered into a long-term arrangement with Cheniere Energy Inc. In 2023, Tourmaline will become the first Canadian EP company participating in the LNG business with full exposure to JKM (Japan Korea Marker) pricing.
The Company’s exploration program has successfully tested six new horizons spread across the three operated complexes thus far.
Tourmaline achieved its net 25% methane reduction target in 2021, three years earlier than targeted.

PRODUCTION UPDATE

Fourth quarter 2021 production averaged 485,078 boepd, up 44% from Q4 2020; full-year 2021 production of 441,115 boepd was up 42% over 2020 average production of 310,598 boepd.
2021 average liquids production of 97,206 bpd (oil, condensate, NGL) was up 50.7% over 2020.
Current production is ranging between 500,000-510,000 boepd. The Company expects to exit Q1 at 510,000-515,000 boepd. Full-year 2022 average production guidance of 500,000 boepd remains unchanged.
All three Company-operated EP complexes are currently producing at or above full-year 2022 guidance levels. The Alberta Deep Basin is currently producing 250,000 boepd, the BC Montney gas condensate complex is producing 230,000 boepd and the Peace River High complex is producing 25,000 boepd.

FINANCIAL HIGHLIGHTS

Full-year 2021 after tax net earnings were $2.03 billion ($6.40 per diluted share).
Fourth quarter 2021 cash flow was $968.2 million ($2.88 per diluted share), and full-year 2021 cash flow was a record $2.93 billion ($9.25 per diluted share). Annual cash flow is up 147% on total revenue⁽⁸⁾ of $4.67 billion for 2021, up 115% over 2020.
Tourmaline generated a record $1.49 billion of free cash flow in 2021.
The Company increased the base dividend three times in 2021 to $0.72/share (29% annual increase) and paid a special dividend of $0.75/share in October 2021. Tourmaline has committed to returning the majority of annual FCF to shareholders and is executing on that plan.
Subsequent to year-end 2021, Tourmaline increased the annual base dividend to $0.80/share and paid a second special dividend of $1.25/share in February 2022.
Tourmaline’s Investment Grade credit rating improved from BBB to BBB (high) during 2021 in conjunction with its issuance of a fixed term note and the acquisition of Black Swan. The public investment grade rating upgrade validated the overall financial health of Tourmaline as a stable, low-risk senior North American oil and gas producer.

2021/2022 BUDGET AND OUTLOOK

Q4 2021 EP capital expenditures were $410.9 million; full-year 2021 EP capital expenditures were $1.39 billion.
Tourmaline, as previously disclosed, accelerated the construction of the Gundy Phase 2 deep cut and the Aitken 46-C expansions into Q4 2021. Both projects were completed on budget and are currently on-stream at full capacity. The Company also accelerated the drilling of one BC pad at Gundy, and the fracing of two additional BC pads from Q1 2022 into Q4 2021, primarily for operational continuity and logistics reasons. These incremental EP operations added approximately $80.0 million to the Q4 2021 EP capital program.
In 2022 at current strip⁽⁹⁾ pricing, the Company expects to generate cash flow of $4.05 billion ($11.97 per diluted share) and free cash flow of $2.85 billion ($8.43 per diluted share) on unchanged EP capital expenditures of $1.125 billion.
Tourmaline builds 2.5% inflation per annum on both capital and operating costs into the Company’s five-year EP capital plan. The $80.0 million of BC drilling/completion capital accelerated into Q4 2021 will also remain in the 2022 budget to provide for anticipated 2022 inflation. The Company’s continuing material reductions of drill times in all three EP complexes also provides a further offset to inflationary pressures.
Tourmaline generated cash flow of $968.2 million and free cash flow of $545.9 million in Q4 2021 on EP capital expenditures of $410.9 million.
Exit 2021 net debt was $973 million (0.25 times 2021 net debt to Q4 annualized cash flow) and below the Company’s long-term net debt target of $1.0-1.2 billion. The majority of Tourmaline’s net debt is substantially offset by its investment in Topaz, using a closing price of Topaz common shares at December 31, 2021 of $17.85 per share.

2021 RESERVES

Year-end 2021 PDP reserves of 947.3 million boe were up 50% over year-end 2020 including 2021 annual production of 161.0 million boe. TP reserves of 2.19 billion boe were up 39.0% including 2021 annual production. 2P reserves of 4.24 billion boe were up 33% including 2021 annual production.
Tourmaline’s 2021 PDP finding, development and acquisition (“FD&A”) costs were $7.27 per boe⁽¹⁰⁾ including changes in future development capital (“FDC”) yielding a PDP reserve recycle ratio^(11)(12) of 2.5 (3.0 utilizing Q4 2021 cash flow per boe⁽¹³⁾of $21.70 instead of full-year 2021 cash flow per boe of $18.19). TP FD&A costs in 2021 were $5.94 per boe including changes in FDC and 2P FD&A was $4.54 per boe including changes in FDC. The 2P FD&A recycle ratio was 4.0 in 2021.
Tourmaline replaced 677% of its 2021 annual production of 161.0 million boe with 2P additions of 1.090 billion boe including 2021 production.
Tourmaline’s 2P reserve value (before taxes) equates to $97.54 per diluted share using the January 1, 2022 engineering price deck and a 10% discount rate. TP reserve value is $62.70 per diluted share and PDP reserve value is $33.77 per diluted share using the same pricing and discount rates.
After 13 years of operations, Tourmaline now has 19.5 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 995.1 million boe of 2P crude oil, condensate and NGL (natural gas liquids) reserves (December 31, 2021) – one of the largest conventional liquid reserve bases in Canada.
Tourmaline has only booked 3,168 (gross) locations of a total drilling inventory of 22,715 gross locations (14% of the overall inventory) to achieve year-end 2021 2P reserves of 4.24 billion boe.
The current FDCs associated with 2P reserves represent approximately three years of prospective cash flow at strip pricing. Although the Company has the execution capability to convert the entire 4.24 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 continued to diversify its natural gas and liquids marketing portfolio in order to realize the best pricing possible for all of its hydrocarbon streams.
In 2021, the Company further diversified the gas marketing portfolio by establishing a US Gulf Coast LNG long-term netback supply agreement with Cheniere Energy. In 2023, Tourmaline will become the first Canadian EP company participating in the LNG business with full exposure to JKM pricing, providing a material increase to anticipated 2023 cash flow based on the February 15, 2022 JKM strip pricing.
In November 2022, the Company will increase gas volumes exported to western US markets from 345 to 445 mmcfpd, with approximately 67% of the gas accessing the premium priced PG&E California market. In November 2023, western US market exposure will increase by an incremental 50 mmcfpd.
Average realized natural gas price in Q4 2021 was $4.66/mcf as the Company benefited from rising commodity prices.
Tourmaline has an average of 845 mmcfpd hedged for 2022 at a weighted average fixed price of CAD $3.44/mcf, an average of 151 mmcfpd hedged at a basis to Nymex of USD $(0.05)/mcf, and an average of 609 mmcfpd of unhedged volumes exposed to export markets in 2022, including Dawn, Iroquois, Empress/McNeil, Chicago, Ventura, Sumas, US Gulf Coast, Malin, and PG&E.
The 2022 volumes include approximately 145 mmcfpd of lower-priced deals inherited in the Black Swan and Modern corporate transactions, the majority of which will expire during 2022.
NGL price realizations in Q4 2021 were up 24% over Q3 2021. Tourmaline is Canada’s largest NGL producer with anticipated average production levels of over 70,000 bpd in 2022.

EP UPDATE

Tourmaline drilled a total of 280 net wells during 2021 for a total of 1.289 million metres. The Company has systematically increased lateral length by over 30% since 2018 while reducing actual drill/complete costs per lateral foot by an additional 30% in that time period.
Tourmaline operated 13 drilling rigs and four to five frac spreads across the three operated core EP complexes during January and February of 2022 as originally planned.
The Company expects to drill and complete a total of approximately 265 (gross) wells during 2022.
The Company continues to operate five drilling rigs in NEBC with new multiple high-performance pads at Sundown, Gundy, Aitken, and Laprise.
Facility expansions at Gundy and Aitken were accelerated into 2H 2021 and completed on budget. The Aitken 46-C expansion/deep cut was executed in 120 days for $96.5 million; the previous owner had estimated 270 days for $116 million. There are no material facility projects in the 2022 budget; as such, the Company anticipates record 2022 capital efficiencies⁽¹⁴⁾ in the $6,000/boepd range.
The Company continues to evolve the Conroy/N. Montney development project. This minimum 100,000 boepd gas and liquids project is currently planned in the 2025-26 timeframe, coinciding with the projected startup of LNG Canada and anticipated related strong intra-Basin natural gas pricing. The production, cash flow, and capital for this project are not reflected in the current corporate five-year EP plan. Once sanctioned, the Company believes it can execute this project in approximately 18 months.
The three-well 1-15 Upper Charlie Lake pad has averaged at a combined rate of 2,500 bopd and 2.8 mmcfpd over the first two weeks of production. The Company has two additional pads to bring on-stream in the complex, prior to spring break-up.
The 4-23 two well Wilrich pad at Smoky tested at combined rate of 65 mmcfpd over three days of testing in February 2022. The pad has since been turned over to production.

EXPLORATION PROGRAM

The Company embarked upon a modest exploration program over two years ago as a subset of the annual EP program. The Company has successfully tested six new horizons spread across the three operated complexes to date. The December 31, 2021 reserve report includes 845.1 bcfe of 2P reserves from these discoveries thus far. Further delineation drilling is planned in all three complexes over the next 12 months; the Company will disclose further details in upcoming quarters as appropriate.
Successful discoveries to date are accessing existing Tourmaline infrastructure.
This ‘Back to the Future’ initiative provides shareholders with an additional, unique, long-term growth and value accretion opportunity.

ACQUISITION UPDATE

Tourmaline completed a highly successful consolidation strategy in the 2020 and 1H 2021 time period. In July 2021, the Company indicated that the larger acquisition program was being paused. The Company made the decision to focus on integration of the assets acquired in the completed deals and realization of the identified capital and operating synergies.
The Company has indicated that $200-300 million of annual FCF could be allocated to further smaller, complementary asset acquisitions within existing complexes.
During Q4 2021 and thus far in Q1 2022, the Company has completed a number of these small acquisitions that in aggregate are meaningful. To that end, Tourmaline has acquired 2,400 boepd of production, an estimated 43 mmboe of reserves (based on internal estimates), 295 gross sections of land (including land sales), and 238 gross drilling locations for total cash proceeds of $63.8 million over the two quarters.

SUSTAINABILITY AND ENVIRONMENTAL PERFORMANCE IMPROVEMENT

Tourmaline has had an engineering team in place for three 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 $20-40 million per year on environmental performance improvement initiatives.
The Company now has displaced diesel with natural gas on all the drilling rigs in the operated fleet, and currently has one rig running directly on high line power.
In 2021, the Company entered into a joint venture with Trican to utilize the first Tier 4 natural gas frac unit in Canada, displacing the majority of the diesel consumed during frac operations with Company-sourced natural gas. This unit is currently being utilized on a full-time basis in the Gundy BC complex.
During 2021, Tourmaline continued its Basin leading initiative to reduce freshwater usage in EP well stimulation operations. The Company now has seven water management/water recycling complexes across all three operated complexes.
Tourmaline achieved its net 25% methane reduction target in 2021, three years earlier than targeted.
In 2021, the Company’s Emission Testing Center (“ETC”), the first of its kind in the world, at the West Wolf gas plant, became fully operational. The ETC is critical in evolving new technology and methodologies 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 $0.20 per common share. The dividend will be payable on March 31, 2022 to shareholders of record at the close of business on March 15, 2022. This quarterly cash dividend is designated as an “eligible dividend” for Canadian income tax purposes.

___________
⁽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”, “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, 2021 (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⁾	“Net debt” is a capital management measure. See “Non-GAAP and Other Financial Measures” in this news release and in the Annual MD&A.
⁽⁵⁾	2P, TP and PDP reserve value per share is calculated as the before tax net present value of the reserves at December 31, 2021 discounted at 10% divided by total diluted shares outstanding at December 31, 2021.
⁽⁶⁾	Supplementary financial measure. See “Non-GAAP and Other Financial Measures” in this news release and in the Annual MD&A.
⁽⁷⁾	Supplementary financial measure. See “Non-GAAP and Other Financial Measures” in this news release and in the Annual MD&A.
⁽⁸⁾	Total revenue from commodity sales and premium (loss) on risk management activities and realized gain (loss) on financial instruments.
⁽⁹⁾	Based on oil and gas commodity strip pricing at February 15, 2022.
⁽¹⁰⁾	Non-GAAP financial ratio. 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. 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.
⁽¹²⁾	Non-GAAP financial ratio. See “Non-GAAP and Other Financial Measures” in this news release and in the Annual MD&A.
⁽¹³⁾	Non-GAAP financial ratio. See “Non-GAAP and Other Financial Measures” in this news release and in the Annual MD&A.
⁽¹⁴⁾	Capital efficiencies are calculated as capital expenditures divided by estimated production added over the period.

CORPORATE SUMMARY – DECEMBER 31, 2021

	Three Months Ended December 31,					Twelve Months Ended December 31,
	2021		2020		Change	2021		2020		Change
OPERATIONS
Production
Natural gas (mcf/d)	2,269,290		1,592,010		43%	2,063,455		1,476,613		40%
Crude oil, condensate and NGL (bbl/d)	106,863		70,990		51%	97,206		64,496		51%
Oil equivalent (boe/d)	485,078		336,325		44%	441,115		310,598		42%
Product prices⁽¹⁾
Natural gas ($/mcf)	$	4.66	$	3.19	46%	$	3.94	$	2.68	47%
Crude oil, condensate and NGL ($/bbl)	$	56.66	$	33.85	67%	$	47.89	$	30.87	55%
Operating expenses ($/boe)⁽²⁾	$	3.95	$	3.25	22%	$	3.77	$	3.14	20%
Transportation costs ($/boe)⁽³⁾	$	4.45	$	4.42	1%	$	4.25	$	4.48	(5)%
Operating netback ($/boe)⁽⁴⁾	$	22.10	$	13.65	62%	$	18.57	$	10.93	70%
Cash general and administrative expenses ($/boe)⁽⁵⁾	$	0.49	$	0.50	(2)%	$	0.54	$	0.56	(4)%
FINANCIAL ($000, except share and per share)
Total revenue from commodity sales and realized gains	1,529,345		688,374		122%	4,669,263		2,174,903		115%
Royalties	168,168		28,623		488%	387,914		65,523		492%
Cash flow	968,236		396,869		144%	2,929,126		1,185,687		147%
Cash flow per share (diluted)	$	2.88	$	1.44	100%	$	9.25	$	4.36	112%
Net earnings	996,248		629,191		58%	2,025,991		618,311		228%
Net earnings per share (diluted)	$	2.96	$	2.28	30%	$	6.40	$	2.27	182%
Capital expenditures (net of dispositions)⁽⁶⁾	447,461		271,284		65%	1,590,371		1,083,625		47%
Weighted average shares outstanding (diluted)						316,788,967		272,079,590		16%
Net debt						(972,979)		(1,784,920)		(45)%
PROVED + PROBABLE RESERVES⁽⁷⁾
Natural gas (bcf)						19,487.1		15,459.2		26%
Crude oil (mbbls)						98,345		102,843		(4)%
Natural gas liquids (mbbls)						896,793		634,890		41%
Mboe						4,242,981		3,314,264		28%


(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.

2021 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
Net Present Values of Future Net Revenue
as of December 31, 2021
Forecast Prices and Costs⁽¹⁾

	Light & Medium Crude Oil		Conventional Natural Gas		Shale Natural Gas⁽²⁾		Natural Gas Liquids		Total Oil Equivalent
Reserves Category	Company Gross (Mbbls)	Company Net (Mbbls)	Company Gross (MMcf)	Company Net (MMcf)	Company Gross (MMcf)	Company Net (MMcf)	Company Gross (Mbbls)	Company Net (Mbbls)	Company Gross (Mboe)	Company Net (Mboe)
Proved Producing	13,666	11,294	2,316,261	2,081,062	2,151,299	1,759,736	189,034	156,708	947,293	808,135
Proved Developed Non-Producing	1,695	1,263	56,830	51,128	291,228	243,333	17,399	14,473	77,104	64,812
Proved Undeveloped	35,322	28,459	2,290,336	2,071,498	3,089,713	2,554,843	231,476	196,134	1,163,473	995,650
Total Proved	50,682	41,016	4,663,427	4,203,689	5,532,239	4,557,912	437,910	367,315	2,187,870	1,868,597
Total Probable	47,662	38,626	3,098,317	2,773,983	6,193,076	5,006,345	458,883	373,721	2,055,111	1,709,069
Total Proved Plus Probable	98,345	79,642	7,761,744	6,977,672	11,725,316	9,564,257	896,793	741,036	4,242,981	3,577,666

	Net Present Values of Future Net Revenue ($000s)
	Before Income Taxes Discounted at ⁽²⁾(%/year)						After Income Taxes Discounted at^{(2) (3)} (%/year)						Unit Value Before Income Tax Discounted at 10%/year
Reserves Category	0	5	8	10	15	20	0	5	8	10	15	20	($/Boe)	($/Mcfe)
Proved Producing	15,895,760	13,323,539	12,106,290	11,411,616	9,996,380	8,984,527	13,793,015	11,724,576	10,726,715	10,153,628	8,978,499	8,079,741	14.12	2.35
Proved Developed Non-Producing	1,862,980	1,352,921	1,156,872	1,054,529	864,456	735,753	1,435,838	1,027,731	874,366	795,234	650,130	552,567	16.27	2.71
Proved Undeveloped	20,460,819	12,839,140	10,095,313	8,717,048	6,278,640	4,863,857	15,379,706	9,540,902	7,435,008	6,377,707	4,510,673	3,327,238	8.76	1.46
Total Proved	38,219,559	27,515,600	23,358,475	21,183,193	17,139,476	14,584,136	30,608,559	22,293,210	19,036,089	17,326,568	14,139,302	11,959,545	11.34	1.89
Total Probable	39,372,998	19,788,766	14,264,392	11,773,086	7,807,442	5,744,160	29,287,702	14,637,854	10,499,401	8,634,477	5,671,909	4,005,961	6.89	1.15
Total Proved Plus Probable	77,592,557	47,304,365	37,622,867	32,956,279	24,946,918	20,328,297	59,896,260	36,931,063	29,535,490	25,961,045	19,811,211	15,965,506	9.21	1.54

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, 2021
Forecast Prices and Costs⁽¹⁾

Reserves Category	Revenue	Royalties	Operating Costs	Capital Development Costs	Abandonment and Reclamation Costs⁽²⁾	Future Net Revenue Before Income Tax	Income Tax	Future Net Revenue After Income Tax⁽³⁾
Proved Producing	25,765,001	2,433,456	6,626,387	970	808,427	15,895,760	2,102,746	13,793,015
Proved Developed Non-Producing	2,643,209	210,932	438,012	104,091	27,195	1,862,980	427,141	1,435,838
Proved Undeveloped	35,978,182	3,195,226	6,318,605	5,691,019	312,513	20,460,819	5,081,114	15,379,706
Total Proved	64,386,393	5,839,614	13,383,004	5,796,080	1,148,135	38,219,559	7,611,001	30,608,559
Total Probable	66,737,385	7,554,755	14,085,762	5,232,675	491,196	39,372,998	10,085,296	29,287,702
Total Proved Plus Probable	131,123,778	13,394,369	27,468,766	11,028,755	1,639,331	77,592,557	17,696,296	59,896,260

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 Month Futures Contract Crude Oil at Cushing, Oklahoma		MSW, Light Crude Oil (40 API, 0.3%S) at Edmonton Then Current $Cdn/Bbl	Alberta Natural Gas Liquids (Then Current Dollars)
Year	Inflation⁽²⁾ ^%	CAD/USD Exchange Rate $US/$Cdn⁽³⁾	Constant 2022 $US/Bbl	Then Current $US/ Bbl			Spec Ethane $Cdn/Bbl	Edmonton Propane $Cdn/Bbl	Edmonton Butane $Cdn/Bbl	Edmonton C5+ Stream Quality $Cdn/Bbl
2022	0.0	0.7967	72.83	72.83	86.82		11.48	43.39	57.49	91.85
2023	2.3	0.7967	67.21	68.78	80.73		10.33	35.92	50.17	85.53
2024	2.0	0.7967	63.96	66.76	78.01		9.81	34.62	48.53	82.98
2025	2.0	0.7967	63.95	68.09	79.57		10.01	35.31	49.50	84.63
2026	2.0	0.7967	63.96	69.45	81.16		10.22	36.02	50.49	86.33
2027	2.0	0.7967	63.95	70.84	82.78		10.42	36.74	51.50	88.05
2028	2.0	0.7967	63.96	72.26	84.44		10.64	37.47	52.53	89.82
2029	2.0	0.7967	63.95	73.70	86.13		10.86	38.22	53.58	91.61
2030	2.0	0.7967	63.95	75.18	87.85		11.08	38.99	54.65	93.44
2031	2.0	0.7967	63.95	76.68	89.60		11.31	39.77	55.74	95.32
2032	2.0	0.7967	63.95	78.21	91.40		11.53	40.56	56.86	97.22
2033	2.0	0.7967	63.96	79.78	93.23		11.77	41.37	58.00	99.17
2034	2.0	0.7967	63.96	81.38	95.09		12.00	42.20	59.15	101.15
2035	2.0	0.7967	63.96	83.00	96.99		12.24	43.04	60.34	103.17
2036	2.0	0.7967	63.96	84.66	98.93		12.49	43.91	61.54	105.24
2037	2.0	0.7967	63.96	+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 Near Month Contract			Midwest Price @ Chicago Then Current $US/ MMbtu	AECO/NIT Spot Then Current $Cdn/ MMbtu	Dawn Price @ Ontario Then Current $US/MMbtu	Spot
Year		Constant 2022 $US/ MMbtu	Then Current $US/MMbtu	Midwest Price @ Chicago Then Current $US/ MMbtu	AECO/NIT Spot Then Current $Cdn/ MMbtu	Dawn Price @ Ontario Then Current $US/MMbtu	Constant 2021 $Cdn/ MMbtu	Then Current $Cdn/ MMbtu	ARP $Cdn/ MMbtu	Sumas Spot $US/ MMbtu	Westcoast Station 2 $Cdn/ MMbtu	Spot Plant Gate $Cdn/ MMbtu
2022		3.85	3.85	3.71	3.56	3.78	3.31	3.31	3.29	3.66	3.48	3.23
2023		3.36	3.44	3.30	3.20	3.37	2.89	2.96	2.93	3.28	3.14	2.89
2024		3.04	3.17	3.03	3.05	3.10	2.68	2.80	2.77	3.01	2.98	2.73
2025		3.04	3.24	3.09	3.10	3.16	2.68	2.86	2.83	3.07	3.04	2.79
2026		3.04	3.30	3.16	3.17	3.23	2.69	2.92	2.89	3.14	3.10	2.85
2027		3.04	3.37	3.22	3.23	3.29	2.69	2.98	2.95	3.20	3.16	2.91
2028		3.04	3.44	3.29	3.30	3.36	2.69	3.04	3.01	3.26	3.22	2.97
2029		3.04	3.51	3.36	3.36	3.43	2.70	3.11	3.08	3.33	3.29	3.04
2030		3.04	3.57	3.43	3.43	3.49	2.69	3.17	3.14	3.40	3.35	3.10
2031		3.04	3.65	3.50	3.50	3.57	2.70	3.24	3.21	3.47	3.42	3.17
2032		3.04	3.72	3.57	3.57	3.64	2.70	3.30	3.28	3.54	3.49	3.23
2033		3.04	3.79	3.64	3.64	3.71	2.70	3.37	3.34	3.61	3.56	3.29
2034		3.04	3.87	3.71	3.71	3.78	2.70	3.44	3.41	3.68	3.63	3.36
2035		3.04	3.95	3.79	3.79	3.86	2.70	3.51	3.48	3.76	3.70	3.43
2036		3.04	4.03	3.87	3.86	3.94	2.70	3.58	3.55	3.83	3.78	3.49
2037		3.04	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	2.70	+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, 2021 and GLJ and McDaniel & Associates Consultants Ltd. as at January 1, 2022 (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, US Gulf Coast and JKM 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, 2021.
⁽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,	2021	2020	2019
*Reserves (Mboe)*
Proved Producing	947,293	736,448	527,361
Total Proved	2,187,870	1,691,056	1,294,439
Proved Plus Probable	4,242,981	3,314,264	2,601,928
*Capital Expenditures* ($ millions)
Exploration and Development⁽²⁾	1,437	912	1,069
Net Property Acquisitions (Dispositions)⁽³⁾	196	172	219
Net Corporate Acquisitions (Dispositions)⁽³⁾	1,232	794	–
Less: Topaz Property Acquisitions⁽⁴⁾	(161)	(119)	–
Total⁽⁵⁾	2,704	1,759	1,287
*Cash Flow* ($/boe)
Cash Flow	18.19	10.43	11.36
Cash Flow – Three Year Average	13.97	11.67	12.75

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 $38 million, $32 million and $30 million for 2021, 2020 and 2019 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	2021	2020	2019	3-Year Avg.
*Total Proved*
Reserve Additions (MMboe)	257.6	185.4	160.7
F&D Costs ($/boe)	5.58	4.92	6.65	5.66
F&D Recycle Ratio⁽¹⁾	3.3	2.1	1.7	2.5
*Total Proved Plus Probable*
Reserve Additions (MMboe)	232.2	210.5	180.4
F&D Costs ($/boe)	6.19	4.33	5.92	5.48
F&D Recycle Ratio⁽¹⁾	2.9	2.4	1.9	2.5

Finding and Development Costs, Including FDC	2021	2020	2019	3-Year Avg.
*Total Proved*
Change in FDC ($ millions)	197.2	(286.0)	(275.2)
Reserve Additions (MMboe)	257.6	185.4	160.7
F&D Costs ($/boe)	6.34	3.38	4.94	5.06
F&D Recycle Ratio⁽¹⁾	2.9	3.1	2.3	2.8
*Total Proved Plus Probable*
Change in FDC ($ millions)	41.6	(566.3)	(589.4)
Reserve Additions (MMboe)	232.2	210.5	180.4
F&D Costs ($/boe)	6.37	1.64	2.66	3.70
F&D Recycle Ratio⁽¹⁾	2.9	6.4	4.3	3.8

Finding, Development and Acquisition Costs

Finding, Development and Acquisition Costs, Excluding FDC	2021	2020	2019	3-Year Avg.
*Total Proved*
Reserve Additions (MMboe)	657.8	510.3	194.2
FD&A Costs ($/boe)	4.11	3.45	6.63	4.22
FD&A Recycle Ratio⁽¹⁾	4.4	3.0	1.7	3.3
*Total Proved Plus Probable*
Reserve Additions (MMboe)	1,089.7	826.0	250.7
FD&A Costs ($/boe)	2.48	2.13	5.13	2.65
FD&A Recycle Ratio⁽¹⁾	7.3	4.9	2.2	5.3

Finding, Development and Acquisition Costs, Including FDC	2021	2020	2019	3-Year Avg.
*Total Proved*
Change in FDC ($ millions)	1,201.1	723.3	(93.4)
Reserve Additions (MMboe)	657.8	510.3	194.2
FD&A Costs ($/boe)	5.94	4.86	6.15	5.57
FD&A Recycle Ratio⁽¹⁾	3.1	2.1	1.8	2.5
*Total Proved Plus Probable*
Change in FDC ($ millions)	2,241.2	1,383.5	(218.0)
Reserve Additions (MMboe)	1,089.7	826.0	250.7
FD&A Costs ($/boe)	4.54	3.80	4.26	4.23
FD&A Recycle Ratio⁽¹⁾	4.0	2.7	2.7	3.3

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 3, 2022 starting at 9:00 a.m. MT (11:00 a.m. ET). To participate, please dial 1-888-664-6383 (toll-free in North America), or international dial-in 1-416-764-8650, a few minutes prior to the conference call.

Conference ID is 68524395.

[expand title=”Advisories & Contact”]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 and business opportunities, including the following: anticipated petroleum and natural gas production and production growth for various periods including estimated production levels for 2022 and beyond; expected free cash flow and cash flow levels for 2022 and beyond; targeted 2022 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 expenditures over various periods; cost reduction initiatives; improvements in capital efficiency; projected operating and drilling costs; the timing for facility expansions and facility start-up dates; sustainability and environmental improvement initiatives; anticipated future commodity prices including the expectation for future increases above current levels; the ability to generate, and the amount of, anticipated cash flow and free cash flow including in 2022 and over the five year development plan; expectations that in 2023 Tourmaline will become the first Canadian EP company participating in the LNG business with full exposure to JKM pricing; 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 and interest rates; applicable royalty rates and tax laws; 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; ability to maintain its investment grade credit rating; 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; climate change risks; inflation; supply chain risks and changes in legislation, including but not limited to tax laws, royalties and environmental regulations.

In addition, wars (including Russia’s military actions in Ukraine), hostilities, civil insurrections, pandemics, epidemics or outbreaks of an infectious disease in Canada or worldwide, including COVID-19 or other illnesses could have an adverse impact on the Company’s results, business, financial condition or liquidity. Ongoing military actions between Russia and Ukraine have the potential to threaten the supply of oil and gas from the region. The long-term impacts of the actions between these nations remains uncertain. If the pandemic is further prolonged, including through subsequent waves, or if additional variants of COVID-19 emerge which are more transmissible or cause more severe disease, or if other diseases emerge with similar effects, the adverse impact on the economy could worsen. It remains uncertain how the macroeconomic environment, and societal and business norms will be impacted following the COVID-19 pandemic.

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.

RESERVES DATA

The reserves data set forth above is based upon the reports of GLJ Ltd. (“GLJ”) and Deloitte LLP, each dated effective December 31, 2021, 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, 2022 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, 2021, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2022.

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, 2021, which will be filed on SEDAR (accessible at www.sedar.com) on or before March 31, 2022.

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 2022 cash flow and free cash flow, which are based on, among other things, the various assumptions as to production levels, capital expenditures, annual cash flows and other assumptions disclosed in this news release and including Tourmaline’s estimated average 2022 production of 500,000 boepd, 2022 commodity price assumptions for natural gas (NYMEX (US) – $4.49/mcf; AECO – $4.20/mcf) crude oil (WTI (US) – $83.95/bbl) and an exchange rate assumption of $0.79 (US/CAD). To the extent such estimates constitute financial outlooks, they were approved by management and the Board of Directors of Tourmaline on March 2, 2022 and are included to provide readers with an understanding of Tourmaline’s anticipated cash flow and free cash flow based on the capital expenditure, production and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.

NON-GAAP 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 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 a standardized meaning prescribed by GAAP. In addition, this news release contains the terms adjusted working capital and net debt, which are considered “capital management measures” and do not have standardized meanings prescribed by GAAP. This news release also contains the terms reserve value per diluted share, operating expenses ($/boe), and transportation costs ($/boe), which are considered “supplementary financial measures” and 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 net income determined in accordance with GAAP and these measures should not be considered to be more meaningful than GAAP measures in evaluating the Company’s performance.

Non-GAAP Financial Measures

Cash Flow

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 December 31,				Years Ended December 31,
(000s)	2021		2020		2021		2020
Cash flow from operating activities (per GAAP)	$	1,058,460	$	326,526	$	2,847,117	$	1,125,136
Change in non-cash working capital (deficit)	(90,224)		70,343		82,009		60,551
Cash flow	$	968,236	$	396,869	$	2,929,126	$	1,185,687

Capital Expenditures

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 December 31,				Years Ended December 31,
(000s)	2021		2020		2021		2020
Cash flow used in investing activities (per GAAP)	$	468,384	$	326,526	$	1,380,111	$	1,162,271
Corporate acquisitions	–		(73,750)		–		(100,822)
Proceeds from sale of investments	–		–		103,824		–
Change in non-cash working capital (deficit)	(20,923)		794		106,436		22,176
Capital expenditures	$	447,461	$	271,284	$	1,590,371	$	1,083,625

Free Cash Flow

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.

Operating Netback

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 from commodity sales from production, which is a GAAP measure, is set forth below:

	Three Months Ended December 31,				Years Ended December 31,
($/boe)	2021		2020		2021		2020
Commodity sales from production	$	1,709,063	$	688,269	$	5,053,611	$	2,200,911
Premium (loss) on risk management activities	21,579		(10,913)		13,943		(106,001)
Realized gain (loss) on financial instruments	(201,297)		11,018		(398,291)		79,993
Royalties	(168,168)		(28,623)		(387,914)		(65,523)
Transportation costs	(198,537)		(136,875)		(683,737)		(509,520)
Operating expenses	(176,360)		(100,590)		(607,292)		(356,674)
Operating netback	$	986,280	$	422,286	$	2,990,320	$	1,243,186

Non-GAAP Financial Ratios

Operating Netback per-boe

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 December 31,				Years Ended December 31,
($/boe)	2021		2020		2021		2020
Revenue, excluding processing income	$	34.27	$	22.25	$	29.00	$	19.13
Royalties	(3.77)		(0.93)		(2.41)		(0.58)
Transportation costs	(4.45)		(4.42)		(4.25)		(4.48)
Operating expenses	(3.95)		(3.25)		(3.77)		(3.14)
Operating netback	$	22.10	$	13.65	$	18.57	$	10.93

Cash Flow per-boe

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 “Reserve Performance Ratios” section for information on annual cash flow per boe and comparative period data used.

Capital Management Measures

Adjusted Working Capital

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)	2021		2020
Working capital (deficit)	$	(361,034)	$	111,744
Fair value of financial instruments – short-term liability	240,970		36,115
Lease liabilities – short-term	2,997		3,412
Decommissioning obligations – short-term	20,103		4,618
Unrealized foreign exchange in working capital – (asset) liability	(6,441)		1,450
Adjusted working capital (deficit)	$	(103,405)	$	157,339

Net Debt

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)	2021		2020
Bank debt	$	(421,539)	$	(1,942,259)
Senior unsecured notes	(448,035)		–
Adjusted working capital (deficit)	(103,405)		157,339
Net debt	$	(972,979)	$	(1,784,920)

Supplementary Financial Measures

The following measures are supplementary financial measures: reserve value per diluted share, operating 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.

Finding and Development Costs, Finding, Development and Acquisition Costs and Recycle Ratio

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.

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 2021 average daily production, Q4 2021 average daily production, current average daily production, Q1 2022 average daily production and 2022 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 Crude Oil⁽¹⁾	Conventional Natural Gas	Shale Natural Gas	Natural Gas Liquids⁽¹⁾	Oil Equivalent Total
	Company Gross (Bbls)	Company Gross (Mcf)	Company Gross (Mcf)	Company Gross (Bbls)	Company Gross (Boe)
2021 Annual Production	13,725,460	462,324,351	290,836,724	21,754,730	161,007,036
2021 Average Daily Production	37,604	1,266,642	796,813	59,602	441,115
Q4 2021 Average Daily Production	40,880	1,299,980	969,310	65,983	485,078
Current Average Daily Production	42,000	1,280,000	1,060,000	73,000	505,000
2022 Average Daily Production	42,600	1,225,000	1,084,000	72,600	500,000

(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.

INITIAL PRODUCTION RATES

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

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
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

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, 2021 and 2020, please refer to SEDAR (www.sedar.com) or Tourmaline’s website at www.tourmalineoil.com.

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.

For further information: Tourmaline Oil Corp., Michael Rose, Chairman, President and Chief Executive Officer, (403) 266-5992 OR Tourmaline Oil Corp., Brian Robinson, Vice President, Finance and Chief Financial Officer, (403) 767-3587; brian.robinson@tourmalineoil.com OR Tourmaline Oil Corp., Scott Kirker, General Counsel, (403) 767-3593; scott.kirker@tourmalineoil.com OR Tourmaline Oil Corp., Jamie Heard, Manager, Capital Markets, (403) 767-5942; jamie.heard@tourmalineoil.com 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: info@tourmalineoil.com, Website: www.tourmalineoil.com

[/expand]

Tourmaline Delivers Net Earnings Of $2 Billion In 2021, Adds 1,090 Mmboe Of 2P Reserves And Declares Dividend For Q1 2022

Latest Headlines