TOURMALINE DELIVERS NET EARNINGS OF $2 BILLION IN 2021, ADDS 1,090 MMBOE OF 2P RESERVES AND DECLARES DIVIDEND FOR Q1 2022

TOURMALINE DELIVERS NET EARNINGS OF $2 BILLION IN 2021, ADDS 1,090 MMBOE OF 2P RESERVES AND DECLARES DIVIDEND FOR Q1 2022

Canada NewsWire

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





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.

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.

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