Tamarack Valley Energy Announces Year-End 2023 Financial & Reserve Results, Clearwater Resource Evaluation and Provides Operational and Guidance Update Including Executive Appointment

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TSX: TVE

CALGARY, AB, Feb. 28, 2024 /CNW/ – Tamarack Valley Energy Ltd. (“Tamarack” or the “Company”) (TSX:TVE) is pleased to announce its audited financial and operating results for the three months and year ended December 31, 2023 and the results of Tamarack’s year-end independent oil and gas reserves evaluations as of December 31, 2023 (the “Reserve Reports”), prepared by Tamarack’s independent qualified reserves evaluators, McDaniel & Associates Consultants Ltd. (“McDaniel) and GLJ Ltd. (“GLJ”). Selected reserves, financial and operating information is outlined below. Selected financial and operating information should be read with Tamarack’s audited annual consolidated financial statements and related management’s discussion and analysis (“MD&A”) for the three and twelve months ended December 31, 2023, and the Company’s Annual Information Form (“AIF”) for the year ended December 31, 2023, which are available on SEDAR+ at www.sedarplus.ca and on Tamarack’s website at www.tamarackvalley.ca.

2023 Financial and Operational Highlights

Improved Balance Sheet Strength – YoY net debt(1) reduction of $373MM (equal to approximately $0.67 per share) to exit the year with net debt of $984MM.
Improved Operating Costs – Production expense of $8.89/boe in Q4/23 reflected a 16% QoQ improvement demonstrating the benefits of core area production growth, program efficiencies and disposition of assets with higher costs.
Low-Cost Organic Reserves Growth – Increased proved developed producing (“PDP”) reserves by 15% (representing 137% of production) at a finding and development (“F&D”) cost of $16.49/boe and total proved plus probable (“TPP”) reserves by 13% (representing 214% of production) at a F&D cost of $20.86/boe, net of dispositions(2).
Achieved Enhanced Return of Capital Threshold – Delivered on Tamarack’s commitment to achieve the first threshold of our enhanced return of capital framework. As a result, subsequent to year-end, the Company was able to accelerate enhanced returns through the buyback of shares as part of our Normal Course Issuer Bid (“NCIB”).
Increased Oil Production Weighting – Delivered annual production of 67,034 boe/d(3), inline with guidance. Fourth quarter production of 64,881 boe/d(4), reflected ~4,500 boe/d(5) from non-core asset sales and unplanned third party restrictions in the Charlie Lake. Tamarack’s oil and liquids weighting as a percent of total production increased to 85% in Q4 2023 compared to 82% in Q4 2022.
Optimized Capital Spending – Total capital expenditures in 2023 of $516MM included: $21MM of gas conservation projects sanctioned with the Clearwater Infrastructure Limited Partnership (the “CIP”), $20MM accelerated from the 2024 capital budget and $475MM allocated to Tamarack’s development program. Development spending was inline with the upper end of the $425 – $475MM guidance. Accelerated capital of $20MM into 2023 from 2024 represented an opportunity to take advantage of favorable field conditions and services pricing which will result in an equal reduction to 2024 spending.
Free Funds Flow(1) Generation – Delivered $248MM of free funds flow(1) during the year which was directed to dividends and debt repayment.
Strategic Infrastructure Partnership – Entered into a series of agreements with 12 First Nation and Metis communities (the “Indigenous Communities”) to establish the CIP, enhancing the long-term relationships between Tamarack and the Indigenous Communities. As part of this transaction, Tamarack received gross proceeds of $146MM and a 15% working interest in the CIP while retaining operatorship and full access to 100% of Tamarack’s existing mid-stream capacity.

2023 Financial & Operating Results

Three months ended
December 31

Year ended
December 31,

2023

2022

  %
change

2023

2022

  %
change

($ thousands, except per share amounts)

Oil and natural gas sales

$    418,864

$   422,313

(1)

$1,702,930

$ 1,455,448

17

Cash flow from operating activities

215,981

227,889

(5)

631,626

805,377

(22)

    Per share – basic

0.39

0.42

(7)

1.13

1.75

(35)

    Per share – diluted

0.39

0.42

(7)

1.13

1.73

(35)

Adjusted funds flow (1)

194,771

196,746

(1)

764,494

727,061

5

    Per share – basic (1)

0.35

0.36

(3)

1.37

1.58

(13)

    Per share – diluted (1)

0.35

0.36

(3)

1.37

1.57

(13)

Free funds flow (1)

67,067

71,470

(6)

248,038

268,484

(8)

    Per share – basic (1)

0.12

0.13

(8)

0.45

0.58

(24)

    Per share – diluted (1)

0.12

0.13

(8)

0.44

0.58

(23)

Net income

57,322

50,441

14

94,196

345,198

(73)

    Per share – basic

0.10

0.09

11

0.17

0.75

(77)

    Per share – diluted

0.10

0.09

11

0.17

0.74

(77)

Net debt (1)

(983,585)

(1,356,570)

(27)

(983,585)

(1,356,570)

(27)

Investments in oil and natural gas assets

127,704

125,276

2

516,456

458,577

13

Weighted average shares outstanding

   Basic

556,699

545,118

2

556,527

460,345

21

   Diluted

560,008

549,062

2

560,032

464,276

21

Average daily production

   Light oil (bbls/d)

14,928

17,382

(14)

16,326

17,423

(6)

   Heavy oil (bbls/d)

37,447

31,328

20

35,788

15,768

127

   NGL (bbls/d)

2,769

4,241

(35)

3,536

3,888

(9)

   Natural gas (mcf/d)

58,419

68,355

(15)

68,302

67,221

2

   Total (boe/d)

64,881

64,344

1

67,034

48,283

39

Average sale prices

   Light oil ($/bbl)

$         99.79

$     103.37

(3)

$        98.64

$       115.47

(15)

   Heavy oil, net of blending expense(1) ($/bbl)

74.09

71.36

4

75.61

85.40

(11)

   NGL ($/bbl)

42.31

50.53

(16)

41.67

54.66

(24)

   Natural gas ($/mcf)

2.82

4.89

(42)

2.84

6.15

(54)

   Total ($/boe)

70.07

71.19

(2)

69.48

82.54

(16)

Benchmark pricing

   West Texas Intermediate (US$/bbl)

78.32

82.65

(5)

77.62

94.23

(18)

   Edm Par differential (US$/bbl)

5.19

1.66

213

3.25

1.79

82

   WCS differential (US$/bbl)

21.89

25.89

(15)

18.70

18.27

2

   Edmonton Par (Cdn$/bbl)

99.69

109.97

(9)

100.39

120.05

(16)

 Hardisty Heavy (Cdn$/bbl)

76.96

77.09

79.53

98.43

(19)

Foreign exchange (USD to CAD)

1.36

1.36

1.35

1.30

4

Operating netback ($/Boe)

   Average realized sales, net of blending expense (1)

70.07

71.19

(2)

69.48

82.54

(16)

   Royalty expenses

(13.81)

(15.07)

(8)

(12.97)

(16.01)

(19)

   Net production expenses (1)

(8.89)

(10.54)

(16)

(9.49)

(10.38)

(9)

   Transportation expenses

(3.56)

(3.64)

(2)

(3.90)

(2.88)

35

   Carbon tax

(2.53)

(0.01)

nm

(0.65)

0.03

nm

Operating field netback ($/Boe) (1)

41.28

41.93

(2)

42.47

53.30

(20)

   Realized commodity hedging gain (loss)

0.80

0.31

158

(1.23)

(3.52)

(65)

Operating netback ($/Boe) (1)

$         42.08

$       42.24

$        41.24

$         49.78

(17)

Adjusted funds flow ($/Boe) (1)

$         32.63

$       33.24

(2)

$        31.25

$         41.26

(24)

Brian Schmidt, President and CEO of Tamarack stated

“Tamarack completed its strategic transformation in 2023, integrating the three corporate Clearwater acquisitions that closed in 2022 and divesting our non-core west central Alberta Cardium assets, affording our team the ability to focus on our core Clearwater, Charlie Lake and EOR assets. Most importantly, we delivered on a key commitment to our shareholders to reduce our net debt(1) and achieved the first threshold of our enhanced return of capital framework with share buybacks commencing in January 2024.

In addition, we continued to realize significant value generation from the assets acquired pursuant to the acquisition of Deltastream Energy Corp. Since close of the acquisition in October 2022, Tamarack has grown production on the Deltastream assets by 29%. Reflecting the highly economic nature of the Clearwater, the assets delivered ~230MM of free NOI(6) in 2023. Incremental to that, the 2023 year-end BTAX TPP NPV10(7) of the assets increased to over $1.8 billion. Overall this transaction continues to exceed our expectations while providing long term development visibility.”

2023 Reserves Report Highlights

Tamarack’s drilling program combined with continued development of Clearwater waterflood contributed significantly to the 2023 reserves, further enhancing the long-term resiliency and sustainability of free funds flow for the Company moving forward. Key highlights of the Company’s PDP, total proved (“TP”) and TPP reserves from the Reserves Report are highlighted below: 

Strong Development Program Results – Excluding reserves and production associated with the dispositions(2), Tamarack’s capital program delivered strong results in 2023:

PDP reserves increased by 15% to 64 MMboe(8) and replaced 137% of production
TP reserves increased by 18% to 128 MMboe(9) and replaced 189% of production
TPP reserves increased by 13% to 224 MMboe(10) and replaced 214% of production

Attractive Finding and Development (“F&D”) Costs – Focused execution in the Charlie Lake and Clearwater achieved the following F&D costs, including changes in Future Development Capital (“FDC”):

PDP reserves: $16.49/boe
TP reserves: $20.90/boe
TPP reserves: $20.86/boe

Strong Recycle Ratios – Tamarack’s highly economic oil plays delivered an annual operating netback(1) of $42.47/boe. Coupled with low-cost reserve additions the Company delivered the following recycle ratios(1):

PDP: 2.6x
TP: 2.0x
TPP: 2.0x

Increased Oil Weighting – Overall liquids-weighting increased YoY by 7%, with 2023 TPP reserves comprised of 85% oil and NGLs and 15% natural gas.

Significant Intrinsic Value – Realized before-tax net present value of booked reserves(7)

PDP NPV10: $1.6 billion
TP NPV10: $2.6 billion
TPP NPV10: $4.5 billion

Charlie Lake Pool Extensions – The Company’s Charlie Lake assets continued to add material pool extensions in 2023, contributing to reserves growth in the play of 4% and 147% production replacement on a TPP basis. Through ongoing optimization and additions to the Company’s land position the percentage of booked TPP locations exceeding 2.5 miles of lateral length increased from 35% to 46% YoY.

Clearwater Assets & Waterflood Value Contribution – The Company’s Clearwater assets realized significant reserves growth in 2023, delivering increased bookings of 43% and 28% for TP and TPP reserves respectively. The TPP increase replaced 279% of 2023 Clearwater production. At year-end 2023, 12% of total Clearwater TPP reserves were associated with waterflood (3% at 2022 year-end), indicating the continued opportunity for reserves growth as waterflood development continues. In support of converting our resource to booked reserves and realized funds flow Tamarack has allocated capital within the 2024 budget to materially increase water injection rates from ~4,000 bbl/d at year-end 2023 to over 15,000 bbl/d by the end of 2024. 

Contingent and Prospective Resource Evaluation – With the integration of the three Clearwater consolidating transactions complete, Tamarack retained McDaniel to evaluate and prepare a report (the “Resource Report”) on the heavy oil contingent and prospective resources of the Company’s Clearwater assets as at December 31, 2023.

The Resource Report indicates Tamarack’s Clearwater heavy oil assets have a “best estimate” of Company gross Contingent Resources (unrisked) of 89.5 MMbbl(12) and Company gross Prospective Resources (unrisked) of 118.4 MMbbl(13).
Inventory attributed to the Company’s Clearwater assets within the Report totals 592 net Contingent and 1,182 net Prospective drilling locations. When combined with the Company’s 381 net TPP locations included in the year-end evaluation, the identified Clearwater inventory exceeds 2,100 locations.
With Clearwater assets producing approximately 13 MMbbl of heavy oil in 2023, TPP reserves represent eight years …

Full story available on Benzinga.com


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