Matribhumi Samachar English
CALGARY, ALBERTA–(Newsfile Corp. – March 12, 2025) – Tenaz Energy Corp. (“Tenaz”, “We”, “Our”, “Us” or the “Company”) (TSX: TNZ) is pleased to announce financial and operating results for the fourth quarter and year ended December 31, 2024.
The related audited consolidated financial statements, as well as Management’s Discussion and Analysis (“MD&A”) for the year ended December 31, 2024 and Annual Information Form (“AIF”) as of December 31, 2024, are available on SEDAR+ at www.sedarplus.ca and on Tenaz’s website at www.tenazenergy.com.
HIGHLIGHTS
Fourth Quarter and Year-End 2024 Results
Production volumes averaged 2,814 boe/d(1) in Q4 2024, up 11% from Q3 2024, reflecting contributions from two new Ellerslie wells at Leduc-Woodbend (“LWB”). One of the wells was brought on production in mid-September and the second in mid-November. Current gross rate from the two wells is approximately 360 boe/d (83% oil).
Production volumes averaged 2,688 boe/d for full year 2024, a 10% increase from full-year 2023 levels. Production was higher due to continued organic growth at LWB in Canada.
Funds flow from operations(2) (“FFO”) for the fourth quarter was $8.3 million ($0.30/share(2)), 147% higher than Q3 2024 due to higher production and an adjustment to prior-period tax returns, partially offset by higher operating expenses in the Netherlands. FFO for full-year 2024 was $24.5 million ($0.90/share), 15% lower than in 2023 driven by lower natural gas prices, higher operating expenses in the Netherlands, and higher transaction costs.
Net loss for full-year 2024 was $7.7 million ($0.28/share), as compared to net income of $26.5 million ($0.97/share) in 2023. The decrease in net income was primarily driven by increased transaction costs and transition activities for the acquisition of NAM Offshore B.V. (“NOBV”) and a $22.8 million gain on acquisition recorded in 2023.
We ended 2024 with positive adjusted working capital(2) (current assets less current liabilities and long-term debt) of $10.0 million, a decrease from $49.3 million in 2023 due primarily to the payment of a $34.0 million deposit for the acquisition of NOBV. As of year-end 2024, we hold $180.2 million of cash and restricted cash.
During 2024, we deployed $1.2 million for our Normal Course Issuer Bid (“NCIB”) program, repurchasing and retiring 0.3 million shares at an average price of $3.73/share. In February 2025, we renewed our NCIB and obtained approval to purchase up to 2.5 million additional shares. Since the beginning of the NCIB program in Q3 2022, we have retired 2.1 million common shares (7.4% of basic common shares) at an average cost of $2.98/share.
During 2024, Tenaz delivered a total shareholder return of 257%, placing TNZ at the top of the 57 oil and gas companies listed on the TSX and in the top one-third of one percent of TSX-listed issuers in all sectors.
Corporate Updates
On July 18, 2024, we announced the execution of a definitive agreement to purchase NOBV. On August 5, the Netherlands Authority for Consumers and Markets completed its review of the transaction and cleared it to proceed as planned. We are now conducting transition activities with a target of closing and assuming operatorship by mid-2025 or earlier. Free cash flow occurring between the effective date of January 1, 2024 and the closing date will be reflected as a reduction of the purchase price.
On November 14, 2024, we closed a $140 million private placement offering (the “Offering”) of Senior Unsecured Notes due 2029 (the “Notes”). The Notes are non-callable for the first two-and-one-half years, bear interest at 12% per annum, and were priced at par. This long-term debt financing provides significant liquidity to pursue our international M&A strategy, as well as funding the closing of the NOBV acquisition.
Year-End 2024 Reserves(3)
Proved Developed Producing (“PDP”) reserves increased 3.5%, including a 5.3% increase in Canada through organic activities, reflecting a corporate reserve replacement ratio of 113%. PDP reserves at year-end totaled 3.8 million boe.
Total Proved (“1P”) reserves increased 10%, reflecting a reserve replacement ratio of 192%. 1P reserves at year-end totaled 10.1 million boe.
Total Proved plus Probable (“2P”) reserves increased 14%, reflecting a reserve replacement ratio of 306%. 2P reserves at year-end totaled 16.6 million boe.
PDP Finding and Developing (“F&D”)4 costs (including future development capital (“FDC”)) were $14.21/boe, resulting in a 2.0 organic recycle ratio based on our 2024 operating netback(2) of $28.96/boe. F&D costs (including FDC) were $17.74 and $14.49 at the 1P and 2P levels, generating organic recycle ratios of 1.6 and 2.0, respectively.
PDP Finding, Developing and Acquisition (“FD&A”)4 costs, were $14.66/boe (including FDC), resulting in a 2.0 recycle ratio. FD&A costs (including FDC) were $17.61 and $14.15 at the 1P and 2P levels, generating recycle ratios of 1.6 and 2.1, respectively.
Reserve life indices were 3.7 years, 9.9 years, and 16.2 years, respectively, for PDP, 1P and 2P reserves, based on our Q4 2024 production rate.
Year-end 2024 NOBV Reserves(3)
NOBV’s 2P reserves, as at December 31, 2024, increased to 55.7 million boe (99% TTF(5) gas), reflecting 155% replacement during 2024 from the July 2024 report and resulting in a 14% increase in after-tax NPV10(6) to €0.62 billion ($0.97 billion(7)).
Capital Activity and Outlook
Capital expenditures during 2024 were approximately $18.2 million (including costs for Carbon Capture & Storage (“CCS”) evaluation in the Netherlands), 4% below the low end of the guidance range set on November 7, 2024 and 29% below the low end of the original guidance range set on December 21, 2023.
The 2024 Canadian development program included drilling two gross (1.75 net) Ellerslie wells. This capital program reflected a change in the Canadian drilling plans from the initial four gross (3.5 net) well Rex program to the two gross well Ellerslie program. The redirection of the Canadian drilling program was effected to further improve capital efficiencies while still achieving 10% annual corporate production growth. The undrilled Rex wells remain in our project inventory with strong economics at current oil prices.
The change in our capital program from the originally-planned Rex wells to Ellerslie wells on newly-acquired lands delayed the start of our drilling program. As a result, production in 2024 was 0.4% below the bottom end of our 2,700 to 2,900 boe/d guidance range. We did not reduce our production guidance range when we reduced our capital investment guidance.
In 2025, we plan drilling and development capital expenditures of $30.0 to $34.0 million, consisting of a three gross (2.3 net) well drilling program in the Glauconitic and Ellerslie formations at LWB in Canada, using unstimulated horizontal wells. In our non-operated Netherlands assets, capital investment will be directed toward minor production-adding activities on existing wells, facility maintenance, and a development well in the L10/L11a license. In addition, Tenaz plans to invest $1.7 million in exploration and evaluation expenditures relating to continuing Front End Engineering Design (FEED) activities for the potential L10 Carbon Capture and Storage (“CCS”) project in the Netherlands.
Excluding NOBV, our annual consolidated production guidance for 2025 is 2,900 to 3,100 boe/d(1), approximately 12% higher than 2024. Tenaz will update its 2025 guidance reflecting additional investment and production from NOBV after closing, which is projected to occur at mid-year 2025 or earlier.
(1) The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. Per boe amounts have been calculated by using the conversion ratio of six thousand cubic feet (6 Mcf) of natural gas to one barrel (1 bbl) of crude oil. Refer to “Barrels of Oil Equivalent” section included in the “Advisories” section of this press release.
(2) This is a non-GAAP and other financial measure. Refer to “Non-GAAP and Other Financial Measures” included in the “Advisories” section of this press release.
(3) Reserves evaluated by McDaniel & Associates Consultants Ltd. in a report effective December 31, 2024 dated March 12, 2025 (“McDaniel Report”). Refer to “Reserves”.
(4) “FD&A Cost”, “F&D Cost”, “Reserves Replacement Ratio” and “Recycle Ratio” do not have standardized meanings and therefore may not be comparable with the calculation of similar measures for other entities. See “Information Regarding Disclosure on Oil and Gas Reserves and Operational Information” in this press release.
(5) TTF is the price for natural gas in the Netherlands.
(6) NPV10 is the net present value discounted at 10 percent.
(7) Translated from Euro to Canadian dollars at a 1.5645 exchange rate.
FINANCIAL AND OPERATIONAL SUMMARY
Three months ended
Year Ended
Dec 31
Sept 30
Dec 31
Dec 31
Dec 31
($000 CAD, except per share and per boe amounts)
2024
2024
2023
2024
2023
FINANCIAL
Petroleum and natural gas sales
16,285
14,822
21,261
63,000
64,852
Cash flow from operating activities
23
11,923
8,927
6,244
15,176
Funds flow from operations(1)
8,299
3,360
13,401
24,524
28,862
Per share – basic(2)
0.30
0.12
0.50
0.90
1.05
Per share – diluted(2)
0.26
0.11
0.45
0.79
0.99
Net income (loss)
(6,037)
(2,454)
3,515
(7,713)
26,547
Per share – basic
(0.22)
(0.09)
0.13
(0.28)
0.97
Per share – diluted(2)
(0.22)
(0.09)
0.12
(0.28)
0.91
Capital expenditures(1)
4,962
6,946
2,967
18,225
24,855
Adjusted working capital (net debt)(1)
9,953
8,999
49,338
9,953
49,338
Common shares outstanding (000)
End of period – basic
27,610
27,426
26,793
27,610
26,793
Weighted average for the period – basic
27,542
27,360
26,963
27,105
27,429
Weighted average for the period – diluted
32,279
31,368
29,970
31,067
29,053
OPERATING
Average daily production
Heavy crude oil (bbls/d)
1,097
794
1,342
988
917
Natural gas liquids (bbls/d)
78
54
75
68
64
Natural gas (Mcf/d)
9,836
10,119
10,310
9,792
8,749
Total (boe/d)
2,814
2,535
3,135
2,688
2,439
Netbacks ($/boe)
Petroleum and natural gas sales
62.90
63.57
73.71
64.04
72.85
Royalties
(5.00)
(4.45)
(5.89)
(5.36)
(5.46)Transportation expenses
(2.99)
(1.97)
(3.50)
(2.84)
(3.56)Operating expenses
(33.38)
(33.89)
(19.36)
(32.26)
(25.23)Midstream income(1)
4.24
7.13
4.86
5.38
4.90
Operating netback(1)
25.77
30.39
49.82
28.96
43.50
BENCHMARK COMMODITY PRICES
WTI crude oil (US$/bbl)(3)
70.28
75.20
78.33
75.73
77.62
WCS (CAD$/bbl)
81.32
85.02
76.86
83.91
80.90
AECO daily spot (CAD$/Mcf) (4)
1.48
0.71
2.30
1.39
2.64
TTF (CAD$/Mcf) (5)
19.00
15.66
18.52
15.06
17.72
(1) This is a non-GAAP and other financial measure. Refer to “Non-GAAP and Other Financial Measures” in the section “Advisories”.
(2) Per share metrics calculated using the weighted average common shares for the applicable period.
(3) WTI represents posting price of West Texas Intermediate (“WTI”) crude oil.
(4) AECO is the natural gas price index for Alberta.
(5) TTF is the price for natural gas in the Netherlands.
PRESIDENT’S MESSAGE
We achieved several important milestones over the last year and continue to execute our corporate strategy at Tenaz. One of the most important steps was the signing of a definitive agreement to acquire NOBV from Nederlandse Aardolie Maatschappij B.V. (“NAM”).
Since the announcement of the NOBV acquisition, we have been engaged in transition activities prior to assuming operatorship. We continue to target a mid-year or earlier closing date. The transition activities include partial replacement of the IT environment, onboarding over 200 new colleagues, and integrating new and existing supplier and contractor relationships. We are very much looking forward to working with our new team. The NOBV staff is highly engaged in a successful transition that includes setting up an optimal go-forward organization prepared for future growth. We are focused on the planning for stepped-up workover and facility projects, and in the longer term, drilling the development and exploration locations identified on the NOBV assets. The Dutch offshore offers many opportunities to deliver safe, secure and low-emission energy for Europe in this time of supply uncertainty.
We have included an updated NOBV acquisition reserve report along with this annual announcement of results. As is customary for a year-end report, the updated NOBV report rolls forward the start date of the reserve assessment to December 31, 2024, one year after the effective date of the NOBV acquisition. The updated report recognized two projects not included in the report released at the time we announced the NOBV acquisition: a tie-in of a discovered but unproduced field using an existing idle well and one new development drilling location. These additions and other factors resulted in an increase in 2P reserves from 53.6 (as at January 1, 2024) to 55.7 million boe (as at December 31, 2024). Both reserve volumes are comprised of 99% TTF gas, with the remainder being condensate. After tax NPV10 increased from $803 million to $967 million compared to the July 1, 2024 report.
Overall, the projects outlined in the reserve report are both technically and economically more attractive than initially anticipated at the time of the NOBV acquisition announcement. A significant number of potential development projects are not included in the updated reserve report, and may be recognized in future reserve and resource reports. Following the full integration of the NOBV technical team post-closing, we are confident that additional projects across all reserve categories will be matured over time. Notably, we will leverage the significantly under-utilized infrastructure in the NOBV asset base, allowing for production growth without requiring substantial infrastructure investment.
With respect to commodity price conditions, the market for TTF gas continues to be volatile as it balances the availability of supply and seasonal demand requirements. Gas storage in Europe has experienced significant withdrawals this winter. Despite average winter temperatures trending at slightly warmer than normal, a series of cold spells caused demand spikes, and storage is expected to end the season at multi-year lows.
The primary source of supply into Europe has switched from pipeline imports to LNG, with the United States being the dominate supplier into the continent. Refilling storage this summer will require Europe to remain competitive in the LNG market, and gas prices will need to remain above coal-to-gas switching levels or else additional natural gas will need to be imported. European buyers hold less long-term supply contracts compared to Asian market participants, which makes Europe more reliant on spot market purchases of cargos. When global demand in all LNG markets is strong, spot market purchases require higher-priced competitive bids to secure supply. Looking forward, more supply is being built with European destinations in mind, so the price of European gas may normalize over time as certainty of sufficient supply becomes more visible.
Aside from NOBV, our current asset portfolio continues to provide investment opportunity and value to shareholders. In Canada, we acquired the Watelet Gas Plant and associated leasehold in Q2 2024 from a private seller. Although the primary purpose of the acquisition was to own and operate the gas plant, the acquired leasehold contained a number of open hole multi-lateral drilling opportunities that our team identified and was able to quickly work up into drillable locations. Our initial capital investment plan for 2024 emphasized our traditional Rex drilling at LWB, but the new lands offered the chance to switch to a lower capital intensity program using the unstimulated multi-lateral wells in the Ellerslie formation. The switch delayed the start of the drilling program and resulted in moderately lower 2024 production than we originally planned, while improving capital efficiency.
During the second half of 2024, we drilled two unstimulated multi-lateral horizontal wells in the Ellerslie formation of the Mannville group on the newly-acquired leasehold. The first well was completed in September 2024, with technical specifications and initial production results reported in our Q3 update. This well produces at a stable 35% water cut, and averaged gross production of 344 boe/d (92% oil) in Q4 2024. The second well was drilled with four horizontal laterals at a true vertical depth of 1,479 meters, a total measured depth of 5,246 meters, and an open hole length in the Ellerslie reservoir of 2,677 meters. This well was on production for 52 days in Q4 2024 at an average gross rate of 106 boe/d (69% oil) with a stable water cut of approximately 80%. Current rate from the two wells is approximately 360 boe/d (83% oil). Oil gravity is 26 °API. Tenaz has an 87.5% working interest in these two Ellerslie A pool wells.
We will continue development of the Ellerslie A Pool in 2025 with another multilateral well to be drilled to the east of the first well that we drilled in late 2024. Our other planned drilling for 2025 includes two unstimulated horizontal wells targeting the Glauconitic Sand. The first well is a three-leg multi-lateral within the Glauconite D Pool and the second is a single lateral well in the Glauconite A Pool. Our 2025 Canadian drilling program is designed to preserve optionality for further investment, while delivering continued organic production growth at high capital efficiency. Our multi-year inventory of Rex horizontal locations continues to have strong prospective economics. Our year-end 2024 reserve report reflects our robust Canadian operations, with a 2P reserve replacement ratio of 306% and a 2P organic recycle ratio of 2.0.
In our non-operated Netherlands asset, Eni Energy Netherlands B.V. has planned a development well in the L10/L11a license area (“L10 Malachite”) targeting a stranded discovered natural gas pool between two existing fields. The Malachite well is targeted to be drilled in the second half of 2025.
During Q4 2024, we enhanced Tenaz’ financial capabilities with a $140 million Offering of Senior Unsecured Notes due 2029, placed with institutional investors. The Notes replaced a $90 million delayed draw term loan entered into in July 2024 with National Bank of Canada to support the acquisition of NOBV.
We are honoured that Tenaz shares returned 257% in 2024. This total shareholder return placed Tenaz at the top of the 57 oil and gas companies listed on the TSX and in the top percentile of TSX-listed issues in all sectors. Looking forward, we see significant value in Tenaz’ assets. Accordingly, on February 11, 2025, we announced the renewal of our NCIB which will re-purchase a modest number of shares in the near term, and provide flexibility to increase the level of purchases in the future.
Finally, we continue to pursue acquisition projects within what we believe to be a robust transaction pipeline. Our goal is to maintain the same high standards in expanding our asset base as we have in our transactions to date. Our Board of Directors and employees remain aligned with shareholders, and we will continue our efforts to deliver value in 2025 and subsequent years.
/s/ Anthony Marino
President and Chief Executive Officer
March 12, 2025
RESERVES
The McDaniel Report was prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserves information as required under NI 51-101 is included in Tenaz’s Annual Information Form for the year ended December 31, 2024 (“AIF”) available on SEDAR+ at www.sedarplus.ca and on Tenaz’s website at www.tenazenergy.com.
The following tables are a summary of Tenaz’s crude oil, natural gas liquids (“NGLs”) and natural gas reserves, as evaluated by McDaniel in the McDaniel Report. Under NI 51-101 Tenaz is required to report its reserves and net present value estimates using forecast pricing and costs. The forecast prices reflected in the net present values are based on an average of the price decks of three independent engineering firms, GLJ Ltd., Sproule Associates Limited and McDaniel & Associates Consultants Ltd. (the “Consultant Average Price Forecast”) at January 1, 2025 (see the Company’s AIF). It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of our crude oil, NGLs and natural gas reserves provided herein are estimates only and there is no assurance the estimated reserves will be recovered. It is important to note that the recovery and reserves estimates provided herein are estimates only. Actual reserves may be greater or less than the estimates. Reserves information may not add up due to rounding. The McDaniel Report includes abandonment, decommissioning and reclamation obligations (“ADR”) for properties and associated wells, pipelines, facilities, and surface leases with attributed reserves, as provided for under NI 51-101. All ADR is included in decommissioning liability described in management’s discussion and analysis.
Summary of Gross Reserves as at December 31, 2024
Company Gross Reserves(1)(2)
Light Crude Oil & Medium Crude Oil
Heavy
Crude Oil
Conventional Natural Gas
Natural Gas Liquids
Oil Equivalent
Reserve Category
(Mbbl)
(Mbbl)
(MMcf)
(Mbbl)
(Mboe)(4)
Proved
Proved Developed Producing
310
917
14,615
153
3,815
Proved Developed Non-Producing
10
–
5
–
11
Proved Undeveloped
252
2,909
17,903
192
6,337
Total Proved
572
3,826
32,523
345
10,163
Total Probable
478
2,686
18,765
195
6,486
Total Proved plus Probable(3)
1,050
6,512
51,288
540
16,649
(1) Gross reserves are Company working interest reserves before royalty deductions.
(2) Based on the January 1, 2025 Consultant Average Price Forecast.
(3) Numbers may not add due to rounding.
(4) Barrels of oil equivalent 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. See “Information Regarding Disclosure on Oil and Gas Reserves and Operational Information” in this press release.
Reconciliation of Reserves for 2024
Company Gross Reserves(1)(2)
Light Crude Oil & Medium Crude Oil
Heavy
Crude Oil
Conventional Natural Gas
Natural Gas Liquids
Oil Equivalent
(Mbbl)
(Mbbl)
(MMcf)
(Mbbl)
(Mboe)(7)
Total Proved
December 31, 2023
105
4,056
28,570
331
9,253
Economic Factors
5
(9)
(508)
(4)
(93)Extensions and improved recovery(3)
414
–
310
7
473
Technical Revisions(4)
(48)
140
3,678
8
712
Acquisitions
96
–
265
29
169
Discoveries(5)
–
–
3,792
–
632
Production
–
(361)
(3,584)
(25)
(984)December 31, 2024(6)
572
3,826
32,523
345
10,163
Total Proved plus Probable
December 31, 2023
126
6,626
44,100
518
14,621
Economic Factors
1
(16)
(244)
(3)
(59)Extensions and improved recovery(3)
846
–
618
14
963
Technical Revisions(4)
(42)
217
3,286
(3)
720
Acquisitions
119
47
342
38
260
Discoveries(5)
–
–
6,770
–
1,128
Production
–
(361)
(3,584)
(25)
(984)December 31, 2024(6)
1,050
6,512
51,288
540
16,649
(1) Gross reserves are Company working interest reserves before royalty deductions.
(2) Based on the January 1, 2025 Consultant Average Price Forecast.
(3) Extensions and Improved Recovery includes all new Ellerslie wells booked during the year at Leduc-Woodbend
(4) Technical revisions were realized in all reserve categories. The revisions were driven by performance deviations from earlier estimates.
(5) Discoveries are related to the additional Malachite well in Netherlands, which moved from Contingent Resources to 2P Reserves.
(6) Numbers may not add due to rounding.
(7) Barrels of oil equivalent 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. See “Information Regarding Disclosure on Oil and Gas Reserves and Operational Information” in this press release.
Summary of Net Present Values of Future Net Revenue as at December 31, 2024
Benchmark crude oil and NGL prices used are adjusted for quality of crude oil or NGL produced, and for transportation costs. The calculated after-tax net present values (“NPVs”) are based on the Consultant Average Price Forecast at January 1, 2025. The NPVs include ADR but do not include a provision for interest, debt service charges and general and administrative expenses. It should not be assumed that the NPV estimate represents the fair market value of the reserves.
After Tax Net Present Value Discounted at(1)(2)
0%
5%
10%
15%
20%
Reserve Category
($M)
($M)
($M)
($M)
($M)
Proved
Proved Developed Producing
5,826
34,081
44,606
48,113
48,576
Proved Developed Non-Producing
153
144
135
125
116
Proved Undeveloped
121,019
92,865
72,571
57,809
46,844
Total Proved
126,997
127,090
117,311
106,048
95,537
Total Probable
162,104
117,108
88,346
69,223
55,940
Total Proved plus Probable(3)
289,101
244,198
205,657
175,270
151,477
(1) Based on the January 1, 2025 Consultant Average Price Forecast.
(2) Includes abandonment and reclamation costs as defined in NI 51-101.
(3) Numbers may not add due to rounding.
Finding and Development Costs and Recycle Ratios
FDC reflects the future capital costs, as provided by the Company and included in the McDaniel Report, to bring Tenaz’s proved and probable developed and undeveloped reserves on production. Changes in forecasted FDC occur annually as a result of development activities, acquisition and disposition activities, changes in capital cost estimates based on improvements in well design and performance, and changes in service costs.
Tenaz has incurred the following F&D(5) and FD&A(5) costs including FDC.
2024
PDP
1P
2P
F&D and FD&A Costs per boe(1)(2)(3)(5)
F&D Costs per boe (including FDC)$14.21
$17.74
$14.49
FD&A Costs per boe (including FDC)$14.66
$17.61
$14.15
Recycle Ratio (x)(2)(4)(5)
F&D (including FDC)
2.0
1.6
2.0
FD&A (including FDC)
2.0
1.6
2.0
(1) Barrels of oil equivalent 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. See “Information Regarding Disclosure on Oil and Gas Reserves and Operational Information” in this press release.
(2) 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 capital generally will not reflect total finding and development costs related to reserve additions for that year.
(3) The calculation of F&D and FD&A costs includes the change in FDC required to bring proved and probable undeveloped and developed reserves into production. The F&D or FD&A number is calculated by dividing the identified capital expenditures by applicable reserve additions including extensions, infills, revisions, acquisitions and disposals, and economic factors, after changes in FDC costs.
(4) Recycle Ratio is calculated by dividing operating netback (a non-GAAP measure) by the cost of adding reserves (“F&D Cost”).
(5) “FD&A Cost”, “F&D Cost”, and “Recycle Ratio” do not have standardized meanings and therefore may not be comparable with the calculation of similar measures for other entities. See “Information Regarding Disclosure on Oil and Gas Reserves and Operational Information” in this press release.
NOBV Reserves Volumes and Net Present Value
McDaniel has completed an independent evaluation of the reserves associated with the NOBV assets and have assigned 55.7 million boe (99% natural gas) of Total Proved + Probable (“2P”) reserves with an effective date of December 31, 2024 (report dated March 12, 2025). McDaniel’s Total Proved (“1P”) and 2P reserves evaluation respectively include 2.1 and 4.6 net development wells with risked production profiles, and no exploration wells. McDaniel’s evaluation projects that the existing upstream assets will have a remaining economic production life of 28 years.
McDaniel’s evaluation of 2P reserves and after-tax net present value discounted at 10 percent (“NPV10”) of the 2P reserves using January 1, 2025 Consultant Average Price Forecast(1), after taking into account estimated decommissioning costs, are shown in the table below. The after-tax NPV10 includes decommissioning costs associated with the acquired assets, which are estimated to have a NPV10 of approximately €142 million ($222 million(2)).
Reserve CategoryVolume
(MMboe)Future Development Costs
(€MM)After-Tax NPV10
(€MM)PDP28.4€ 3.9€ 294.11P37.3€ 102.4€ 414.92P55.7€ 214.6€ 618.1
(1) Consultant Average Pricing effective January 1, 2025 assumed TTF gas pricing of €41.50/MWh for 2025, €35.99/MWh for 2026, and €35.24/MWh for 2027.
(2) Translated from Euro to CAD at a 1.5645 exchange rate.
CONTINGENT RESOURCES AND PROSPECTIVE RESOURCES
The Resources Report was prepared by McDaniel, the Company’s independent qualified reserves evaluator, in accordance with the COGE Handbook and NI 51 101. The Resources Report has an effective date of December 31, 2024 and a preparation date of March 12, 2025 Tenaz has commissioned our independent reserve evaluator to conduct an assessment of the resources for NOBV and expects to provide details of this report later in 2025.
Contingent and prospective resources evaluated in the Resource Report are located offshore in the Dutch North Sea in the Netherlands. Contingent resources reflect the undeveloped Rembrandt and Vermeer oil discoveries on the non-operated license F17a Deep Block and three undeveloped natural gas discoveries on the non-operated licenses, L10/L11a Block and K12 Block. Prospective resources reflect 21 exploration prospects on the non-operated licenses. Prospective volumes do not reflect any scaling factor for chance of development. As a non-operator interest holder the Company is unable to guarantee that any resource projects will be pursued.
The Resources Report summarizes estimates of crude oil and natural gas contingent resources and prospective resources of the Company and the net present values of best estimate contingent (2C) resources using forecast prices and costs.
An estimate of risked net present value of future net revenue of contingent resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the Company proceeding with the required investment. It includes contingent resources that are considered too uncertain with respect to the chance of development and chance of discovery to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized.
Information relating to resources contains forward-looking statements. See “Note Regarding Forward-Looking Statements”.
The tables below summarize the volumes and economic values in the Resources Report.
Netherlands Prospective Resources
Summary of Prospective Resources Estimates – Company Gross Values
(Forecast Prices and Costs)
Company Gross Values(1)(2)
Prospective Resources – Unrisked(3)(7)
Prospect
Type
Working Interest
Low (P90)(10)
(Mboe)
P50(10)
(Mboe)
Mean(10)
(Mboe)
High (P10)(10)
(Mboe)
Risked Mean
Resources (4)
(Mboe)
F17a Block(9)
Crude Oil
5.00 %
373
675
752
1,232
227
L10 Block
Natural Gas
21.43 %
2,405
4,724
5,401
9,248
2,756
L11a Block
Natural Gas
21.43 %
1,309
2,334
2,563
4,120
1,384
N7b Block
Natural Gas
17.86 %
1,849
3,335
3,680
5,903
1,092
Total(5)(6)(7)(8)
5,936
11,069
12,395
20,504
5,459
(1) Gross values are Company working interest resources.
(2) Based on the January 1, 2025 Consultant Average Price Forecast.
(3) There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be economically viable or technically feasible to produce any portion of the resources.
(4) Quantifying the chance of development requires consideration of both economic contingencies and other contingencies such as legal, regulatory, market access, political, social license, internal and external approvals and commitment to project finance and development timing. As many of these factors are extremely difficult to quantify, the chance of development is uncertain and must be used with caution. The chance of development was estimated to be 60% for crude oil and 75% for natural gas.
Chance of Discovery for the prospects in each block is as follows:
F17a Block (Natural Gas) CK2 (50%)
L10 Block (Natural Gas) Limonite (72%), Topaz (64%), Sapphire (64%), L10-21 (72%)
L11a Block (Natural Gas) Fresnel (72%), Obsidian (72%), L11-2 (2%)
N7b Block (Natural Gas) Snapper (65%), Sole (57%), Crab East (49%), Crab West (49%), Crab East Upper Sloch (29%), Crab West Upper Sloch (29%)
(5) Total based on the arithmetic aggregation of the prospects. Numbers may not add due to rounding.
(6) The unrisked total is not representative of the portfolio unrisked total and is provided to give an indication of the resources range assuming all the prospects are successful.
(7) Volumes listed are full life volumes, prior to any cutoffs due to economics.
(8) Based on a Mcf to boe conversion of 6 to 1. A boe conversion of 6 to 1 is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(9) Crude oil prospects with expected quality consistent with prior discoveries.
(10) Refer to “Information Regarding Disclosure on Crude Oil and Natural Gas Resources” section included in the “Advisories” section of this press release.
Netherlands Contingent Resources
Summary of Contingent Resources Estimates – Company Gross Values
(Forecast Prices and Costs)
Company Gross Values(1)(2)
Contingent Resources – Unrisked(3)(4)(6)
Risked
Resources
Crude Oil
Working
1C(10)
2C(10)
3C(10)
Chance of
2C
Property
Interest
(Mbbl)
(Mbbl)
(Mbbl)
Development
(Mbbl)
Vermeer(6)
5.00 %
323
982
1,902
60 %
589
Rembrandt(6)
5.00 %
1,026
1,482
1,986
60 %
889
L11-07
21.43 %
–
–
–
– %
–
L10-19
21.43 %
–
–
–
– %
–
K12-G
12.32 %
–
–
–
– %
–
Total Crude Oil(7)
1,349
2,464
3,888
1,478
Company Gross Values(1)(2)
Contingent Resources – Unrisked(3)(4)(5)
Risked
Resources
Natural Gas
Working
1C(9)
2C(9)
3C(9)
Chance of
2C
Property
Interest
(MMcf)
(MMcf)
(MMcf)
Development
(MMcf)
Vermeer
5.00 %
–
–
–
– %
–
Rembrandt
5.00 %
–
–
–
– %
–
L11-07
21.43 %
3,433
4,905
6,635
75 %
3,679
L10-19
21.43 %
3,070
6,239
11,635
75 %
4,680
K12-G
12.32 %
1,232
2,464
3,696
75 %
1,848
Total Natural Gas(7)
7,734
13,608
21,966
10,206
Company Gross Values(1)(2)
Contingent Resources – Unrisked(3)(4)()
Risked
Resources
Working
1C(9)
2C(9)
3C(9)
Chance of
2C
Total Oil Equivalent(8)
Interest
(Mboe)
(Mboe)
(Mboe)
Development
(Mboe)
Vermeer
5.00 %
323
982
1,902
60 %
589
Rembrandt
5.00 %
1,026
1,482
1,986
60 %
889
L11-07
21.43 %
572
817
1,106
75 %
613
L10-19
21.43 %
512
1,040
1,939
75 %
780
K12-G
12.32 %
205
411
616
75 %
308
Total Oil Equivalent(7)
2,638
4,732
7,549
3,180
(1) Gross values are Company working interest resources.
(2) Based on the January 1, 2025 Consultant Average Price Forecast.
(3) There is no certainty that it will be commercially viable to produce any portion of the resources.
(4) Company gross contingent resources are based on the working interest share of the property gross resources.
(5) These are economic contingent resources and are sub-classified in terms of maturity as development on hold.
(6) Vermeer crude oil is 30o API and Rembrandt crude oil is 23o API.
(7) Numbers may not add due to rounding.
(8) Based on a Mcf to boe conversion of 6 to 1. A BOE conversion of 6 to 1 is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(9) Denotes Contingent – Low estimate (“1C”), Contingent – Best estimate (“2C”) and Contingent – High estimate (“3C”).
(10) Refer to “Information Regarding Disclosure of Crude Oil and Natural Gas Resources” included in the section “Advisories”.
Netherlands Summary of Company Share of Net Present Values as at December 31, 2024
Unrisked Net Present Value Discounted at(1)(2)
0%
5%
8%
10%
15%
Best Estimate Contingent (2C) Resources Total(3)(4)
($000)
($000)
($000)
($000)
($000)
Before Tax Net Present Values
L11-07 & L10-19 natural gas
84,069
61,118
50,504
44,457
32,197
Vermeer & Rembrandt crude oil(5)
194,441
110,198
79,769
64,493
37,609
Best Estimate Contingent Resources Total
278,510
171,315
130,273
108,950
69,806
After Tax Net Present Values
Best Estimate Contingent Resources Total
182,273
105,477
76,256
61,128
33,493
(1) Based on the January 1, 2025 Consultant Average Price Forecast.
(2) Numbers may not add due to rounding.
(3) There is no certainty that it will be commercially viable to produce any portion of the resources.
(4) Vermeer crude oil is 30o API and Rembrandt crude oil is 23o API.
(5) These are unrisked values that do not take into account the chance of development, which is defined as the probability of a project being commercially viable. Quantifying the chance of development requires consideration of both economic contingencies and other contingencies such as legal, regulatory, market access, political, social license, internal and external approvals and commitment to project finance and development timing. As many of these factors are extremely difficult to quantify, the chance of development is uncertain and must be used with caution. The chance of development was estimated to be 60% for crude oil and 75% for natural gas.
Risked Net Present Value Discounted at
0%
5%
8%
10%
15%
Best Estimate Contingent (2C) Resources Total
($000)
($000)
($000)
($000)
($000)
Before Tax Net Present Values
L11-07 & L10-19 natural gas
63,052
45,839
37,878
33,343
24,148
Vermeer & Rembrandt crude oil
116,665
66,119
47,861
38,696
22,565
Best Estimate Contingent Resources Total
179,716
111,957
85,739
72,039
46,713
After Tax Net Present Values
Best Estimate Contingent Resources Total
119,290
64,941
44,637
34,297
16,070
About Tenaz Energy Corp.
Tenaz is an energy company focused on the acquisition and sustainable development of international oil and gas assets. Tenaz has domestic operations in Canada along with offshore natural gas and midstream assets in the Netherlands. Tenaz produces crude oil and natural gas from a number of formations within the Mannville Group at Leduc-Woodbend in central Alberta. The Netherlands natural gas assets are located in the Dutch sector of the North Sea. Additional information regarding Tenaz is available on SEDAR+ and its website at www.tenazenergy.com. Tenaz’s Common Shares are listed for trading on the Toronto Stock Exchange under the symbol “TNZ”.
ADVISORIES
Non‐GAAP and Other Financial Measures
This press release contains references to measures used in the oil and natural gas industry such as “funds flow from operations”, “funds flow from operations per share”, “funds flow from operations per boe”, “capital expenditures”, “free cash flow”, “midstream income”, “adjusted working capital (net debt)”, and “operating netback”. The data presented in this press release is intended to provide additional information and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with IFRS Accounting Standards as issued by the International Accounting Standards Board and sometimes referred to in this press release as Generally Accepted Accounting Principles (“GAAP”). These reported non-GAAP measures and their underlying calculations are not necessarily comparable or calculated in an identical manner to a similarly titled measure of other companies where similar terminology is used. Where these measures are used, they should be given careful consideration by the reader.
Funds flow from operations
Tenaz considers funds flow from operations to be a key measure of performance as it demonstrates the Company’s ability to generate the necessary funds for sustaining capital, future growth through capital investment, and settling liabilities. Funds flow from operations is calculated as cash flow from operating activities plus midstream income and before changes in non-cash operating working capital and decommissioning liabilities settled. Funds flow from operations is not intended to represent cash flows from operating activities calculated in accordance with GAAP. A summary of the reconciliation of cash flow from operating activities to funds flow from operations, is set forth below:
($000)
Q4 2024
Q3 2024
Q4 2023
2024
2023
Cash flow from operating activities
23
11,923
8,927
6,244
15,176
Change in non-cash operating working capital
6,114
(10,469)
(3,113)
7,641
274
Decommissioning liabilities settled
1,065
243
6,187
5,350
9,048
Midstream income
1,097
1,663
1,400
5,289
4,364
Funds flow from operations
8,299
3,360
13,401
24,524
28,862
Funds flow from operations per share is calculated using basic and diluted weighted average number of shares outstanding in the period.
Funds flow from operations per boe is calculated as funds flow from operations divided by total production sold in the period.
Capital Expenditures
Tenaz considers capital expenditures to be a useful measure of the Company’s investment in its existing asset base calculated as the sum of drilling and development costs and exploration and evaluation costs. Exploration and evaluation asset additions (being exploration and evaluation costs) and property, plant and equipment additions (being drilling and development costs) are taken from the consolidated statements of cash flows that is most directly comparable to cash flows used in investing activities. The reconciliation to financial statement measures is set forth below.
($000)
Q4 2024
Q3 2024
Q4 2023
2024
2023
Exploration and evaluation expenditures
501
462
357
1,948
1,519
Property, plant and equipment expenditures
4,461
6,484
2,610
16,277
23,336
Capital expenditures
4,962
6,946
2,967
18,225
24,855
Free Cash Flow (“FCF”)
Tenaz considers free cash flow to be a key measure of performance as it demonstrates the Company’s excess funds generated after capital expenditures for potential shareholder returns, acquisitions, or growth in available liquidity. FCF is a non-GAAP financial measure and is comprised of funds flow from operations less capital expenditures. A summary of the reconciliation of the measure, is set forth below:
($000)
Q4 2024
Q3 2024
Q4 2023
2024
2023
Funds flow from operations
8,299
3,360
13,401
24,524
28,862
Less: Capital expenditures
(4,962)
(6,946)
(2,967)
(18,225)
(24,855)Free cash flow
3,337
(3,586)
10,434
6,299
4,007
Midstream Income
Tenaz considers midstream income an integral part of determining operating netback. Operating netback assists management and investors with evaluating operating performance. Tenaz’s midstream income consists of the equity-accounted income from its associate, Noordgastransport B.V.(“NGT”) prior to the amortization of the fair value increment recognized on NGT at the time of the acquisition. Under GAAP, investments in associates are accounted for using the equity method of accounting. Income from associate is Tenaz’s share of the investee’s net income.
($000)
Q4 2024
Q3 2024
Q4 2023
2024
2023
Income from associate
917
1,418
543
4,383
3,507
Plus: Amortization of fair value increment of NGT
180
245
857
906
857
Midstream income
1,097
1,663
1,400
5,289
4,364
Adjusted working capital (net debt)
Management views adjusted working capital (net debt) as a key industry benchmark and measure to assess the Company’s financial position and liquidity. Adjusted working capital (net debt) is calculated as current assets less current liabilities, excluding the fair value of derivative instruments. Tenaz’s adjusted working capital (net debt) as at December 31, 2024 and 2023 is summarized as follows:
($000)
December 31, 2024
December 31, 2023
Current assets
188,537
92,488
Current liabilities
(40,304)
(43,988)Net current assets
148,233
48,500
Fair value of derivative instruments
(5)
838
Long-term debt
(138,275)
–
Adjusted working capital (net debt)
9,953
49,338
Operating Netback
Tenaz calculates operating netback on a dollar and per boe basis, as petroleum and natural gas sales less royalties, operating costs and transportation costs, plus midstream income (as described above). Operating netback is a key industry benchmark and a measure of performance for Tenaz that provides investors with information that is commonly used by other crude oil and natural gas producers. The measurement on a per boe basis assists management and investors with evaluating operating performance on a comparable basis with other issuers.
Information Regarding Disclosure of Oil and Gas Reserves and Operational Information
All amounts in this press release are stated in Canadian dollars unless otherwise specified. Tenaz’s crude oil, natural gas liquids, and natural gas reserves statement for the year ended December 31, 2024, is contained within the Company’s AIF. The AIF is available on SEDAR+ at www.sedarplus.ca and on the Company’s website at www.tenazenergy.com. The recovery and reserve estimates are estimates only and there is no guarantee that the estimated reserves will be recovered.
This press release contains metrics commonly used in the oil and natural gas industry, such as “reserve life indices”, “recycle ratio”, “finding and development (F&D) costs”, “finding, development and acquisition (FD&A) costs”, and “operating netback”. Each of these metrics is determined by Tenaz as set forth in this press release. These terms do not have standardized meanings or standardized methods of calculation and therefore may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Such metrics have been included to provide readers with additional information to evaluate the Company’s performance, however such metrics should not be unduly relied upon for investment or other purposes. Management uses these metrics for its own performance measurements and to provide readers with measures to compare Tenaz’s performance over time. Such measures are not reliable indicators of the Company’s future performance and future performance may not compare to the performance in previous periods. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes.
Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis. The aggregate of the costs incurred in the financial year and changes during that year in estimated FDC may not reflect total F&D costs related to reserves additions for that year.
Information Regarding Disclosure of Crude Oil and Natural Gas Resources
The resources estimates in this press release are derived from the Resources Report. The following provides the definitions of the various resource categories used in this press release as set out in the COGE Handbook. “Contingent resource” and “prospective resource” are not, and should not be confused with, petroleum and natural gas reserves.
Contingent resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies.
The primary contingencies which currently prevent the classification of the contingent resource as reserves include but are not limited to: preparation of firm development plans, including determination of the specific scope and timing of the project; project sanction; access to capital markets; stakeholder and regulatory approvals; access to required services and field development infrastructure; crude oil and natural gas prices internationally in jurisdictions in which Tenaz operates; demonstration of economic viability; future drilling program and testing results; further reservoir delineation and studies; facility design work; corporate commitment; limitations to development based on adverse topography or other surface restrictions; and the uncertainty regarding marketing and transportation of petroleum from development areas.
Prospective resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have two risk components, the chance of discovery and the chance of development. There is no certainty that the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources. Application of any geological and economic chance factor does not equate prospective resources to contingent resources or reserves.
Low estimate prospective resource is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
Best estimate prospective resource is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
High estimate prospective resource is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.
Mean estimate prospective resource is the arithmetic average from the probabilistic assessment.
Although the Company has identified prospective resources, there are numerous uncertainties inherent in estimating oil and gas resources, including many factors beyond the Company’s control and no assurance can be given that the indicated level of resources or recovery of hydrocarbons will be realized. In general, estimates of recoverable resources are based upon a number of factors and assumptions made as of the date on which the resource estimates were determined, such as geological and engineering estimates which have inherent uncertainties and the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results. There are several significant negative factors relating to the prospective resource estimate which include (i) structural events that are well defined seismically and are low risk, however, reservoir quality, seal, hydrocarbon migration and associated hydrocarbon column estimates are more at risk than the former, (ii) well costs are very high due to the exploratory nature of the initial group of wells, (iii) due to limited infrastructure proximate to the prospects, gas discoveries may be stranded for some time until infrastructure is in place, which may take some time due to the remoteness of the prospects and costs associated with same, and (iv) other factors which are not within the control of the Company.
There is no certainty that any portion of the prospective resources will be discovered. There is no certainty that it will be commercially viable to produce any portion of the contingent resources or prospective resources or that Tenaz will produce any portion of the volumes currently classified as contingent resources or prospective resources. All contingent resources and prospective resources evaluated by McDaniel were deemed economic at the effective date of December 31, 2024. The estimates of contingent resources and prospective resources involve implied assessment, based on certain estimates and assumptions, that the resources described exist in the quantities predicted or estimated and that the resources can be profitably produced in the future.
The risked net present value of the future net revenue from the contingent resources and prospective resources does not represent the fair market value. Actual contingent resources and prospective resources (and any volumes that may be reclassified as reserves) and future production therefrom may be greater than or less than the estimates provided herein.
The resource estimates are estimates only and there is no guarantee that the estimated resources will be recovered.
Barrels of Oil Equivalent
The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. Per boe amounts have been calculated by using the conversion ratio of six thousand cubic feet (6 Mcf) of natural gas to one barrel (1 bbl) of crude oil. The boe conversion ratio of 6 Mcf to 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. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
Forward‐looking Information and Statements
This press release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “budget”, “forecast”, “guidance”, “continue”, “estimate”, “objective”, “ongoing”, “may”, “will”, “project”, “should”, “could”, “believe”, “plans”, “potential”, “intends”, “strategy” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this press release contains forward-looking information and statements pertaining to: Tenaz’s capital plans and budget; matters relating to NOBV including expectations for our base business and our financial position before and after closing of the NOBV acquisition ; our anticipated operational and financial performance; uses of the Offering proceeds; location inventory; commodity price conditions; forecasted annual average production volumes; capital expenditures; our NCIB; the ability to grow our assets domestically and internationally; statements relating to a potential CCS project; estimates of reserves and resources, and net present values; and our corporate strategy (including available opportunities).
The forward-looking information and statements contained in this press release reflect several material factors and expectations and assumptions of the Company including, without limitation: the continued performance of oil and gas properties in a manner consistent with past experiences; that the Company will continue to conduct its operations in a manner consistent with past operations; expectations regarding future development; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; expectations regarding future acquisition opportunities; the accuracy of the estimates of the Company’s reserves volumes, or contingent resources or prospective resources; certain commodity price, interest rate, tariffs, inflation and other cost assumptions; the continued availability of oilfield services; and the continued availability of adequate debt and equity financing and cash flow from operations to fund its planned expenditures. The Company believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable, but no assurance can be given that these factors, expectations, and assumptions will prove to be correct.
The forward-looking information and statements included in this press release are not guarantees of future performance and should not be unduly relied upon. Such information and statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or supply of the Company’s products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates, tariffs, or other regulatory matters; changes in development plans of the Company or by third party operators of the Company’s interests, increased debt levels or debt service requirements; inaccurate estimation of the Company’s oil and gas reserve volumes, or contingent resources or prospective resources; limited, unfavorable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and certain other risks detailed from time to time in the Company’s public documents.
The forward-looking information and statements contained in this press release speak only as of the date of this press release, and the Company does not assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.
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