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Tourmaline Generates Record Free Cash Flow, Grows Production 10%, Increases 2P Reserves to 2.6 Billion Boe in 2019


CALGARY – 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 2019 as well as 2019 reserves results. The Company delivered strong returns to shareholders, annual growth and demonstrated continued financial resilience in this very challenging energy cycle.

HIGHLIGHTS

  • Tourmaline delivered full-year earnings of $319.7 million ($1.18/diluted share), again demonstrating the profitability of its core EP business.

  • Annual cash flow(1) of $1.2 billion ($4.43/diluted share) and Q4 2019 cash flow of $335.9 million ($1.24/diluted share) provide a platform for continued economic growth in 2020.

  • Free cash flow(2) for 2019 of $144.9 million was a 27% increase over 2018. Q4 free cash flow of $67.1 million represents an annualized free cash flow yield of approximately 8%.

  • Tourmaline bought back 1,053,000 shares in 2019 at $12.23/share pursuant to its NCIB. Tourmaline will continue to tactically pursue share buybacks funded by free cash flow on hand if distressed valuations continue.

  • The Company grew average annual liquids volumes by 16% and total average production volumes by 10% in 2019, while containing capital spending at $1.29 billion (up only 6% from 2018).

  • The Company posted record capital efficiency of $8,650/boepd (excluding acquisitions and dispositions) – a 23% improvement over 2018.

  • Tourmaline added 250.7 mmboe of proved plus probable reserves (“2P”) after adding back annual production of 106.2 mmboe.

  • 2P finding, development and acquisition costs (FD&A) in 2019 were $4.26/boe including changes in future development capital (“FDC”) ($5.13/boe excluding changes in FDC) based on total capital expenditures of $1.29 billion, total proved (“TP”) FD&A in 2019 were $6.15/boe including change in FDC ($6.63/boe excluding change in FDC). 2019 proved, developed producing (“PDP”) FD&A were $8.01/boe.

  • Subsequent to the quarter, Tourmaline announced an update on its NEBC consolidation activities. Through two corporate transactions, Tourmaline has added 6,000 boepd of current production, 2P reserves of 116.3 mmboe(3) and 160,000 acres of Montney lands for a combined cash purchase price of $33.4 million.

2019 RESERVES

  • Year-end 2019 PDP reserves of 527.4 mmboe were up 34% over year-end 2018 when including 2019 annual production of 106.2 mmboe(4), TP reserves of 1.294 billion boe were up 16% over 2018 when including 2019 annual production and 2P of 2.602 billion boe were up 10% when including 2019 annual production.

  • Continued improvement in drill-and-complete capital costs resulted in a significant reduction in FDC in the 2019 report.

  • 2019 PDP finding and development (“F&D”) costs were $7.06/boe, including changes in FDC, a record low, yielding a PDP reserve recycle ratio(5) of 1.6. Total proved F&D costs in 2019 were $4.94/boe including changes in FDC and 2P F&D was $2.66/boe including changes in FDC. 2P FD&A costs were $4.26/boe including changes in FDC yielding a 2019 2P FD&A recycle ratio of 2.7.

  • Tourmaline replaced 236% of 2019’s annual production of 106.2 mmboe in 2019 with a 2P addition of 251 mmboe before 2019 production.

  • Tourmaline added the 251 mmboe of 2P reserves in 2019 even though 66.8% of the 2019 drilling locations were converting previously-booked locations. In 2019, the Company rig-released 198.9 (net) wells, down 7% from 2018 (213.1 wells) as the Company moderated capital spending due to low commodity prices.

  • Tourmaline’s 2P reserve value equates to $55.69/share utilizing the lower 2019 engineering price deck. TP reserve value is $32.42/share – PDP reserve value is $16.90/share.

  • After 11 years of operation, Tourmaline now has 12.3 TCF of 2P natural gas reserves and 553 million barrels of 2P oil, condensate, and NGL reserves (January 1, 2020).

  • For the seventh consecutive year, the Company enjoyed positive 2P technical revisions in its reserve report.

PRODUCTION UPDATE

  • 2019 production averaged 290,865 boepd, Q4 2019 averaged 299,844 boepd. As announced on December 17, 2019, lengthy outages at the third-party Saturn deep-cut facility in the Alberta Deep Basin and on the NEBC Enbridge system reduced both quarterly liquid volumes and total production levels.

  • Current average production is 310,500 boepd excluding the production impact of Polar Star Canadian Oil and Gas Inc. which closed in February 2020. Tourmaline has deferred a minimum of $25.0 million of first quarter capital expenditures from the planned EP program into 2H 2020 due to lower commodity prices, reducing 1H average production by approximately 2,500 boepd. The Company is on track to meet full-year 2020 guidance of 315,000 – 320,000 boepd inclusive of this capital deferral and the effects of weather-related freeze-offs in January. Closing of the recently-announced acquisitions will be accretive to production volumes, primarily in the second quarter.

  • 2019 average liquids production was 55,338 bpd (oil, condensate, NGL), a 16% increase over 2018. Current 2020 liquids production is 64,300 bpd. The Company is targeting full-year 2020 liquids production of approximately 68,000 bpd (a 22% year-over-year increase).

FINANCIAL HIGHLIGHTS

  • Full-year 2019 after-tax earnings were $319.7 million ($1.18/diluted share) as Tourmaline remained profitable despite a challenging year for natural gas prices. The Company has built one of the most stable, low-cost businesses in the North American energy sector.

  • Fourth quarter 2019 cash flow was $335.9 million ($1.24/diluted share) and full-year 2019 cash flow was $1,205.5 million ($4.43/diluted share).

  • Tourmaline generated $67.1 million of free cash flow in Q4 2019. The first quarter 2020 dividend of $0.12/share will be paid on March 31, 2020.

  • The five-year EP development plan, released in mid-December, remains unchanged. It is expected to generate approximately $1.75 billion of free cash flow over the five years at strip pricing(6). This cash is expected to be deployed into dividend increases, debt reduction, and share buybacks. The Company acquired 1,053,000 shares in 2019 through the NCIB at an average price of $12.23.

  • Tourmaline continued to effectively manage all-in cash costs in 2019 (operating, transportation, general and administrative and financing) which totalled $8.18/boe compared to $7.87/boe in 2018.

MARKETING HIGHLIGHTS

  • For 2019, the Company posted a realized gas price across the portfolio of $2.59/mcf, a 46% premium over the average AECO 5A price for the year.

  • For calendar year 2020, Tourmaline has an average of 252 mmcf/d hedged at a weighted-average fixed price of CAD $2.44/mcf, an average of 202 mmcf/d hedged at a basis to NYMEX of $(0.31) USD/mcf, an average of 410 mmcf/d incremental volume exposed to export markets, including Dawn, Chicago, Ventura, Sumas, Malin and PGE.

  • In the first quarter of 2020, as part of the Company’s gas marketing diversification strategy, the Company signed a long-haul transportation agreement for 25 mmcfpd delivering to the US Gulf Coast which will commence on November 1, 2022.

  • For 2H 2019, Tourmaline had in excess of 4,000 bbls/d of propane exposed to Argus Far East Index (AFEI) and realized wellhead prices in excess of CAD $23/bbl above Edmonton prices.

  • For 2020, Tourmaline expects to have in excess of 5,000 bbls/d of propane exposed to AFEI.

2019/2020 CAPITAL PROGRAMS

  • Full-year EP capital spending in 2019 was $1,033.1 million. The Company reduced its originally-planned program by approximately $270.0 million during the course of the year. Continued per-well capital cost improvements allowed the Company to largely achieve original EP targets on the reduced spending.

  • The 2020 EP capital program remains at $925.0 million. Additionally, Tourmaline has the flexibility to reduce activity to a maintenance capital budget which is $100 million lower than the current plan. Tourmaline will monitor commodity prices and the natural gas supply/demand balance over the next few months; the full-year program may be revised in conjunction with the Q1 2020 results release in May 2020. The Company has already elected to defer a minimum of $25.0 million of originally-planned Q1 2020 EP expenditures into 2H 2020.

  • Less than 15% of 2020 capital expenditures are directed towards facility expenditures, which will drive anticipated 2020 capital efficiencies of $6,500 – $7,000/boepd.

  • Tourmaline continues to target a net debt(7)-to-cash flow range of 1.0 – 1.5 times. At December 31, 2019, net debt-to-cash flow was at 1.5 times (net debt to annualized Q4 2019 cash flow was at 1.3 times). Current targeted exit 2020 net debt-to-cash flow is 1.2 times.

EP HIGHLIGHTS

  • 2019 capital efficiency was approximately $8,650/boepd (excluding acquisitions and dispositions) – a record low for Tourmaline as the Company continued to reduce capital costs and deliver strong well results. The Company is forecasting a further improvement in capital efficiency in 2020.

  • Q4 2019 operating costs were $3.06/boe, significantly less than originally forecast. NEBC full-year 2019 operating costs were a record low of $2.40/boe.

  • Tourmaline rig-released 198.9 net wells in 2019, down 7% from 2018 and still achieved full-year production growth of 10% in 2019.

  • Tourmaline operated up to 11 drilling rigs during Q1 2020, with 10 rigs now operating. The Company currently plans to operate three rigs through break-up in Q2 2020.

  • Capital cost reduction/improvements continue to be achieved through monobore trials in the Alberta Deep Basin, application of rotary steerable technology and novel pad equipping approaches, amongst other technology-driven opportunities. NEBC Montney horizontal completed well costs are now averaging $2.9 million (drill, 35 stage-completions, equip.).

ENVIRONMENTAL IMPROVEMENT INITIATIVES

As outlined in the Company’s Sustainability Report, published in February 2020, Tourmaline has made major strides in reducing emissions and continually improving overall environmental performance.

Major Environmental Performance Achievements

  • 46% reduction in CO2 emissions intensity since 2013.

  • Near elimination of all fresh water, in well stimulation operations, in British Columbia.

  • Initiation of methane-reduction retrofit compliance plan resulting in over 3,400 high-bleed devices being replaced in 2019.

  • An approximate 50% reduction in the surface area per producing well in the Company’s operating areas due to multi-pad well development.

  • Broad replacement of diesel in Tourmaline’s drilling and completion operations with natural gas. Tourmaline now operates 15 natural gas fuel substitution units allowing for the displacement of 9.8 million litres of diesel per year.

Environmental Performance Targets

  • Continued emphasis on reducing corporate emissions intensity by maintaining the Company’s top-decile performance relative to the Company’s peer group while targeting a 25% reduction in total methane emissions from 2018 levels by 2023.

  • Reduce corporate emissions intensity by 25% by 2027 (scope 1) using 2018 as a baseline, by continuing to focus on overall efficiencies with the application of new, innovative technologies including the electrification of assets, when feasible.

  • Continually improve the Company’s peer-leading performance on water usage in completion activities by reducing and eventually eliminating the usage of fresh water throughout its core gas operations.

The environmental performance improvements achieved thus far, and the myriad of future-planned initiatives, require significant capital investment. The vast majority of these initiatives, however, ultimately reduce Tourmaline’s capital and operating cost structure. Shareholders receive a double win – a cleaner environment via Tourmaline’s net-cleanest hydrocarbon molecule and enhanced returns via the Company’s improved efficiencies.

Our strong results and intense focus on sustainability is why the world needs Canadian natural gas now and in the future.

DIVIDEND

The Company is pleased to announce that its Board of Directors has declared a quarterly cash dividend on its common shares of C$0.12 per common share. The dividend will be payable March 31, 2020 to shareholders of record at the close of business on March 16, 2020. This quarterly cash dividend is designated as an “eligible dividend” for Canadian income tax purposes.

____________________________________

(1)

“Cash flow” is defined as cash provided by operations before changes in non-cash operating working capital. See “Non-GAAP Financial Measures” in this news release and in the Company’s 2019 Management’s Discussion and Analysis.

(2)

“Free cash flow” is defined as cash flow less total net capital expenditures. Total net capital expenditures is defined as total capital spending before acquisitions, net of non-core dispositions. Free cash flow is prior to dividend payments. See “Non-GAAP Financial Measures” in this news release and the Company’s 2019 Management’s Discussion and Analysis.

(3)

Reserves have been evaluated by independent reserve evaluators as at December 31, 2018 as follows: Polar Star 2P reserves of 80.7 mmboe by Sproule and Chinook 2P reserves of 35.6 mmboe by McDaniel for a combined 2P reserves total of 116.3 mmboe. Reserves are working interest gross reserves before deduction of royalties payable to others and without including any royalty interests.

(4)

See “Supplemental Information Regarding Product Types” in this news release.

(5)

The recycle ratio is calculated by dividing the cash flow per boe by the appropriate F&D or FD&A costs related to the reserve additions for that year.

(6)

Based on oil and gas commodity strip pricing at December 11, 2019.

(7)

See “Non-GAAP Financial Measures in this new release and in the Company’s 2019 Management’s Discussion and Analysis.

CORPORATE SUMMARY – DECEMBER 31, 2019

Three Months Ended December 31,

Twelve Months Ended December 31,

2019

2018

Change

2019

2018

Change

OPERATIONS

Production

Natural gas (mcf/d)

1,439,746

1,347,778

7%

1,413,160

1,305,025

8%

Crude oil, condensate and NGL

(bbl/d)

59,886

51,938

15%

55,338

47,540

16%

Oil equivalent (boe/d)

299,844

276,568

8%

290,865

265,044

10%

Product prices(1)

Natural gas ($/mcf)

$

2.77

$

3.13

(12)%

$

2.59

$

2.73

(5)%

Crude oil, condensate and NGL

($/bbl)

$

38.59

$

43.40

(11)%

$

39.29

$

46.47

(15)%

Operating expenses ($/boe)

$

3.06

$

3.35

(9)%

$

3.28

$

3.33

(2)%

Transportation costs ($/boe)

$

4.13

$

3.63

14%

$

3.86

$

3.52

10%

Operating netback(3) ($/boe)

$

13.00

$

15.82

(18)%

$

12.12

$

14.12

(14)%

Cash general and
administrative expenses ($/boe)(2)

$

0.52

$

0.42

24%

$

0.49

$

0.49

-%

FINANCIAL

($000, except share and per share)

Total revenue from commodity sales
and realized gains

579,588

595,487

(3)%

2,127,337

2,106,209

1%

Royalties

22,559

15,380

47%

83,030

77,369

7%

Cash flow(4)

335,856

391,532

(14)%

1,205,540

1,303,462

(8)%

Cash flow per share (diluted)(4)

$

1.24

$

1.44

(14)%

$

4.43

$

4.80

(8)%

Net earnings

61,340

190,895

(68)%

319,740

401,418

(20)%

Net earnings per share (diluted)

$

0.23

$

0.70

(67)%

$

1.18

$

1.48

(20)%

Capital expenditures (net of
dispositions)

320,389

395,194

(19)%

1,287,259

1,214,437

6%

Weighted average shares outstanding
(diluted)

271,878,824

271,702,910

-%

Net debt(4)

(1,755,684)

(1,720,009)

2%

PROVED +

PROBABLE RESERVES(3)

Natural gas (bcf)

12,294.6

11,712.7

5%

Crude oil (mbbls)

96,984

82,046

18%

Natural gas liquids (mbbls)

455,851

423,198

8%

Mboe

2,601,928

2,457,358

6%

(1)

Product prices include realized gains and losses on risk management activities and financial instrument contracts.

(2)

Excluding interest and financing charges.

(3)

Reserves are “Company gross reserves”, which are defined as the working interest share of reserves prior to the deduction of interest owned by others (burdens). Royalty interest reserves are not included in Company gross reserves.

(4)

See “Non-GAAP Financial Measures” in this news release and in the Company’s Management’s Discussion and Analysis for the year ended December 31, 2019.

2019 RESERVE SUMMARY

The following tables summarize the Company’s gross reserves defined as the working interest share of reserves prior to the deduction of interest owned by others (burdens). Royalty interest reserves are not included in Company gross reserves. Company net reserves are defined as the working net carried and royalty interest reserves after deduction of all applicable burdens.

Tourmaline’s Reserves and Net Present Values of Future Net Revenue disclosed in this news release include the full impact of the sale of certain assets to Topaz Energy Corp. (“Topaz”) notwithstanding Tourmaline’s 74% ownership interest in Topaz. The Net Present Values of Future Net Revenue on a Total Proved Plus Probable basis (discounted at a rate of 10%) would increase by approximately 7% had the Topaz transaction not occurred. On a Proved Producing and Total Proved basis, the Net Present Values of Future Net Revenue (discounted at a rate of 10%) would increase by approximately 9% and 8%, respectively. Refer to the General Development of the Business section in the Company’s recently filed Annual Information Form for further details.

Reserves and Future Net Revenue Data (Forecast Prices and Costs)

Summary of Oil and Gas Reserves and

Net Present Values of Future Net Revenue

as of December 31, 2019

Forecast Prices and Costs(1)

Light & Medium Crude
Oil

Conventional Natural
Gas

Shale Natural Gas(2)

Natural Gas Liquids

Total Oil Equivalent

Company

Company

Company

Company

Company

Company

Company

Company

Company

Company

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Reserves Category

(Mbbls)

(Mbbls)

(MMcf)

(MMcf)

(MMcf)

(MMcf)

(Mbbls)

(Mbbls)

(Mboe)

(Mboe)

Proved Producing

13,948

11,422

1,676,894

1,505,877

910,873

844,148

82,118

68,535

527,361

471,628

Proved Developed Non-Producing

1,935

1,504

95,010

85,260

208,272

196,007

12,432

10,958

64,914

59,340

Proved Undeveloped

32,189

26,203

1,929,133

1,751,774

1,408,310

1,308,908

113,735

102,419

702,164

638,736

Total Proved

48,072

39,130

3,701,036

3,342,911

2,527,455

2,349,063

208,285

181,912

1,294,439

1,169,704

Total Probable

48,912

39,478

2,412,245

2,173,075

3,653,824

3,279,086

247,566

210,547

1,307,490

1,158,719

Total Proved Plus Probable

96,984

78,608

6,113,281

5,515,987

6,181,279

5,628,148

455,851

392,458

2,601,928

2,328,422

Net Present Values of Future Net Revenue ($000s)

Before Income Taxes Discounted at
(%/year)

After Income Taxes Discounted at(3)
(%/year)

Unit Value
Before Income
Tax Discounted
at 10%/year

Reserves Category

0

5

10

15

20

0

5

10

15

20

($/Boe)

($/Mcfe)

Proved Producing

6,776,073

5,475,633

4,579,234

3,953,261

3,496,236

6,513,916

5,329,729

4,494,030

3,901,446

3,463,622

9.71

1.62

Proved Developed Non-Producing

951,690

723,446

581,989

487,603

420,666

703,333

555,992

464,566

402,764

357,903

9.81

1.63

Proved Undeveloped

8,114,346

5,258,108

3,623,511

2,611,296

1,943,173

5,988,919

3,824,651

2,584,398

1,819,464

1,317,883

5.67

0.95

Total Proved

15,842,109

11,457,187

8,784,733

7,052,160

5,860,075

13,206,167

9,710,371

7,542,994

6,123,674

5,139,408

7.51

1.25

Total Probable

20,521,808

10,555,460

6,308,597

4,165,195

2,945,016

15,169,537

7,746,820

4,579,558

2,987,161

2,086,554

5.44

0.91

Total Proved Plus Probable

36,363,916

22,012,647

15,093,330

11,217,355

8,805,091

28,375,704

17,457,191

12,122,552

9,110,834

7,225,961

6.48

1.08

Notes:

(1)

Numbers may not add due to rounding.

(2)

Shale Natural Gas is required to be presented separately from Conventional Natural Gas as its own product type pursuant to National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). While the Tourmaline Montney reserves do not strictly fit the definition of “shale gas” as defined in NI 51-101 because the natural gas is not “primarily adsorbed” as stated within the definition, the Montney reserves have been included as shale gas for purposes of this disclosure.

(3)

The after-tax net present value of the Company’s oil and gas properties reflects the tax burden on the properties on a stand-alone basis. It does not consider the Company’s tax situation, or tax planning. It does not provide an estimate of the value at the Company level which may be significantly different. The Company’s financial statements and management’s discussion and analysis should be consulted for information at the Company level.

Total Future Net Revenue ($000s)

(Undiscounted)

as of December 31, 2019

Forecast Prices and Costs(1)

Reserves Category

Revenue

Royalties

Operating
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

12,077,042

1,248,887

3,611,456

50

440,576

6,776,073

262,157

6,513,916

Proved Developed Non-
Producing

1,573,143

164,268

368,213

66,242

22,730

951,690

248,357

703,333

Proved
Undeveloped

17,308,773

1,640,354

3,550,448

3,805,349

198,275

8,114,346

2,125,427

5,988,919

Total
Proved

30,958,957

3,053,509

7,530,117

3,871,642

661,581

15,842,109

2,635,941

13,206,167

Total
Probable

37,823,111

4,827,222

8,615,423

3,532,409

326,248

20,521,808

5,352,271

15,169,537

Total Proved Plus
Probable

68,782,068

7,880,731

16,145,540

7,404,051

987,829

36,363,916

7,988,212

28,375,704

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

Alberta Natural Gas Liquids
(Then Current Dollars)

Year

Inflation(2)
%

CAD/USD
Exchange
Rate
$US/$Cdn(3)

Constant
2020
$
$US/Bbl

Then
Current
$US/
Bbl

MSW, Light
Crude Oil
(40 API,
0.3%S) at
Edmonton
Then
Current
$Cdn/Bbl

Spec
Ethane
$Cdn/Bbl

Edmonton
Propane
$Cdn/Bbl

Edmonton
Butane
$Cdn/Bbl

Edmonton
C5+
Stream
Quality
$Cdn/Bbl

2020

0.0

0.7600

61.00

61.00

72.64

6.42

26.36

42.09

76.83

2021

1.7

0.7700

62.70

63.75

76.06

7.41

29.80

47.03

79.82

2022

2.0

0.7850

63.82

66.18

78.35

8.33

32.94

50.66

82.30

2023

2.0

0.7850

64.20

67.91

80.71

8.65

34.00

52.21

84.72

2024

2.0

0.7850

64.40

69.48

82.64

8.98

34.89

53.48

86.71

2025

2.0

0.7850

64.58

71.07

84.60

9.24

35.78

54.77

88.73

2026

2.0

0.7850

64.75

72.68

86.57

9.46

36.69

56.07

90.77

2027

2.0

0.7850

64.84

74.24

88.49

9.67

37.57

57.32

92.76

2028

2.0

0.7850

64.84

75.73

90.31

9.89

38.41

58.50

94.65

2029

2.0

0.7850

64.85

77.24

92.17

10.12

39.26

59.71

96.57

2030

2.0

0.7850

64.85

78.79

94.01

10.35

40.11

60.90

98.53

2031

2.0

0.7850

64.85

80.36

95.89

10.56

40.91

62.12

100.50

2032

2.0

0.7850

64.84

81.97

97.81

10.77

41.73

63.36

102.51

2033

2.0

0.7850

64.84

83.61

99.76

10.98

42.56

64.63

104.56

2034

2.0

0.7850

64.85

85.28

101.76

11.20

43.42

65.92

106.65

2035

2.0

0.7850

64.85

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

Natural Gas and Sulphur Pricing

Alberta Plant Gate

British Columbia

NYMEX Henry Hub
Near Month Contract

Spot

Year

Constant
2020 $
$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
2020 $
$Cdn/
MMbtu

Then Current
$Cdn/
MMbtu

ARP $Cdn/
MMbtu

Sumas Spot
$US/
MMbtu

Westcoast
Station 2
$Cdn/
MMbtu

Spot Plant
Gate
$Cdn/
MMbtu

2020

2.62

2.62

2.53

2.04

2.58

1.82

1.82

1.83

2.16

1.66

1.41

2021

2.82

2.87

2.78

2.32

2.82

2.07

2.10

2.11

2.44

1.99

1.74

2022

2.95

3.06

2.96

2.62

3.01

2.30

2.39

2.40

2.72

2.31

2.07

2023

2.99

3.17

3.07

2.71

3.12

2.35

2.48

2.50

2.83

2.46

2.21

2024

3.01

3.24

3.15

2.81

3.20

2.39

2.58

2.59

2.90

2.56

2.31

2025

3.02

3.32

3.23

2.89

3.27

2.41

2.66

2.67

2.98

2.66

2.42

2026

3.02

3.39

3.30

2.96

3.34

2.42

2.72

2.74

3.05

2.73

2.48

2027

3.02

3.46

3.36

3.03

3.41

2.43

2.78

2.80

3.12

2.80

2.54

2028

3.02

3.52

3.43

3.10

3.48

2.44

2.85

2.87

3.18

2.87

2.61

2029

3.02

3.60

3.50

3.17

3.55

2.45

2.92

2.94

3.26

2.93

2.68

2030

3.02

3.67

3.58

3.24

3.62

2.46

2.99

3.00

3.33

3.00

2.74

2031

3.02

3.74

3.65

3.30

3.69

2.46

3.05

3.07

3.39

3.06

2.80

2032

3.02

3.81

3.72

3.37

3.77

2.46

3.11

3.13

3.46

3.12

2.85

2033

3.02

3.89

3.80

3.43

3.84

2.46

3.17

3.19

3.54

3.19

2.91

2034

3.02

3.97

3.87

3.50

3.92

2.46

3.23

3.25

3.61

3.25

2.97

2035

3.02

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

2.46

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

Notes:

(1)

Crude oil and natural gas benchmark reference pricing, inflation and exchange rates utilized by GLJ in the GLJ Reserve Report and Deloitte in the Deloitte Reserve Report, were an average of forecast prices and costs published by Sproule Associates Ltd. as at December 31, 2019 and GLJ and McDaniel & Associates Consultants Ltd. as at January 1, 2020 (each of which is available on their respective websites at www.sproule.comwww.gljpc.com, and www.mcdan.com). GLJ assigns a value to the Company’s existing physical diversification contracts for natural gas for consuming markets at Dawn, Chicago, Ventura, Malin and PG&E based on forecasted differentials to NYMEX Henry Hub as per the aforementioned consultant average price forecast, contracted volumes and transportation costs. No incremental value is assigned to potential future contracts which were not in place as of December 31, 2019.

(2)

Inflation rates used for forecasting prices and costs.

(3)

Exchange rates used to generate the benchmark reference prices in this table.

RESERVES PERFORMANCE RATIOS

The following tables highlight Tourmaline’s reserves, F&D and FD&A costs as well as the associated recycle ratios.

Reserves, Capital Expenditures and Cash Flow(1)

As at December 31,

2019

2018

2017

Reserves (Mboe)

Proved Producing

527,361

473,269

436,208

Total Proved

1,294,439

1,206,381

1,055,702

Proved Plus Probable

2,601,928

2,457,358

2,216,206

Capital Expenditures ($ millions)

Exploration and Development(2)

1,069

1,261

1,364

Net Acquisitions (Dispositions)

219

(47)

58

Total Capital Expenditures

1,287

1,214

1,422

Cash Flow ($/boe)

Cash Flow

11.36

13.47

13.63

Cash Flow – Three Year Average

12.75

12.80

13.11

Notes:

(1)

Cash flow is defined as cash provided by operations before changes in non-cash operating working capital. See “Non-GAAP Financial Measures” below and in the Company’s most recently filed Management’s Discussion and Analysis for further discussion.

(2)

Includes capitalized G&A of $33 million, $30 million and $27 million for 2019, 2018 and 2017 respectively.

Finding and Development Costs

Finding and Development Costs, Excluding FDC

2019

2018

2017

3-Year Avg.

Total Proved

Reserve Additions (MMboe)

160.7

241.0

272.8

F&D Costs ($/boe)

6.65

5.24

5.00

5.48

F&D Recycle Ratio(1)

1.7

2.6

2.7

2.3

Total Proved Plus Probable

Reserve Additions (MMboe)

180.4

326.6

537.5

F&D Costs ($/boe)

5.92

3.86

2.54

3.54

F&D Recycle Ratio(1)

1.9

3.5

5.4

3.6

Finding and Development Costs, Including FDC

2019

2018

2017

3-Year Avg.

Total Proved

Change in FDC ($ millions)

(275.2)

441.7

481.1

Reserve Additions (MMboe)

160.7

241.0

272.8

F&D Costs ($/boe)

4.94

7.07

6.76

6.44

F&D Recycle Ratio(1)

2.3

1.9

2.0

2.0

Total Proved Plus Probable

Change in FDC ($ millions)

(589.4)

486.3

612.1

Reserve Additions (MMboe)

180.4

326.6

537.5

F&D Costs ($/boe)

2.66

5.35

3.68

4.02

F&D Recycle Ratio(1)

4.3

2.5

3.7

3.2

Finding, Development and Acquisition Costs

Finding, Development and Acquisition Costs,
Excluding FDC

2019

2018

2017

3-Year Avg.

Total Proved

Reserve Additions (MMboe)

194.2

247.4

285.2

FD&A Costs ($/boe)

6.63

4.91

4.98

5.40

FD&A Recycle Ratio(1)

1.7

2.7

2.7

2.4

Total Proved Plus Probable

Reserve Additions (MMboe)

250.7

337.9

557.8

FD&A Costs ($/boe)

5.13

3.59

2.55

3.42

FD&A Recycle Ratio(1)

2.2

3.7

5.3

3.7

Finding, Development and Acquisition Costs,
Including FDC

2019

2018

2017

3-Year Avg.

Total Proved

Change in FDC ($ millions)

(93.4)

465.3

515.7

Reserve Additions (MMboe)

194.2

247.4

285.2

FD&A Costs ($/boe)

6.15

6.79

6.79

6.62

FD&A Recycle Ratio(1)

1.8

2.0

2.0

1.9

Total Proved Plus Probable

Change in FDC ($ millions)

(218.0)

526.8

678.3

Reserve Additions (MMboe)

250.7

337.9

557.8

FD&A Costs ($/boe)

4.26

5.15

3.76

4.28

FD&A Recycle Ratio(1)

2.7

2.6

3.6

3.0

Note:

(1)

The recycle ratio is calculated by dividing the cash flow per boe by the appropriate F&D or FD&A costs related to the reserve additions for that year.

Conference Call Tomorrow at 9:00 a.m. MT (11:00 a.m. ET)

Tourmaline will host a conference call tomorrow, March 4, 2020 starting at 9:00 a.m. MT (11:00 a.m. ET). To participate, please dial 1-888-231-8191 (toll-free in North America), or international dial-in 647-427-7450, a few minutes prior to the conference call.

Conference ID is 3587405.



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