Tenaz Energy Corp. Announces 2023 Year-End Results – Canadian Energy News, Top Headlines, Commentaries, Features & Events – EnergyNow

The related audited consolidated financial statements, as well as Management’s Discussion and Analysis (“MD&A”) for the year ended December 31, 2023 and Annual Information Form (“AIF”) as of December 31, 2023, are available on SEDAR+ at www.sedarplus.ca and on Tenaz’s website at www.tenazenergy.com.

A webcast presentation to accompany this release is available on Tenaz’s website at www.tenazenergy.com.

HIGHLIGHTS

Fourth Quarter and Year-End 2023 Results

• Production volumes averaged a record level of 3,135 boe/d⁽¹⁾ in Q4 2023. Canadian production of 2,028 boe/d reflected contributions from the new wells brought on-line from the 2023 campaign at Leduc-Woodbend (“LWB”). Production in the Dutch North Sea (“DNS”) of 1,107 boe/d was consistent with the third quarter, despite unplanned facility downtime.
• Production volumes averaged 2,439 boe/d for full year 2023, more than double full year 2022 levels. Production was higher due to the acquisition of Netherlands assets and continued organic growth at LWB in Canada. Production from LWB was 30% higher year-over-year.
• All four wells in the 2023 program at LWB have been successfully put on production. Gross production rates during the fourth quarter averaged 225 boe/d (89% oil) per well.
• Funds flow from operations⁽²⁾ (“FFO”) for the fourth quarter was $13.4 million ($0.50/share⁽³⁾), 178% higher than Q3 2023 and 315% higher than Q4 2022. Higher quarter-over-quarter FFO resulted from higher production in Canada and higher prices for TTF⁽⁴⁾ natural gas.
• FFO for full year 2023 was $28.9 million ($1.05/share), 236% higher than in 2022. Increased annual FFO primarily resulted from contributions from the new Netherlands assets and higher production in Canada, partially offset by higher transaction costs.
• Net income for full year 2023 was $26.5 million ($0.97/share), as compared to $5.2 million ($0.18/share) in 2022. Higher net income resulted primarily from the recognition of a gain on the acquisition of XTO Netherlands Ltd. (“XTO Acquisition”) in Q3 2023, partially offset by increased G&A and transaction costs pertaining both to closed acquisitions and potential future transactions.
• We ended 2023 with positive adjusted working capital⁽²⁾ of $49.3 million, an increase of $4.4 million over the prior quarter and $35.3 million over year-end 2022. The improvement was driven by free cash flow and the XTO Acquisition for the respective periods, partially offset by spending on decommissioning activity and share buybacks. We remain undrawn on our $10 million bank facility.
• During 2023, we deployed $3.9 million for our Normal Course Issuer Bid (“NCIB”) program, repurchasing and retiring 1.3 million shares at an average price of $2.97/share. Since the beginning of the NCIB program in Q3 2022, we have retired 1.8 million common shares (6.1% of basic common shares) at an average cost of $2.63/share.
• We have hedged approximately 40% of our expected European gas production for Q1 2024 through a physical swap at €55.75/MWh (approximately $24.12/Mcf). For Q2 and Q3 2024, we have hedged approximately 20% of our expected European gas production through a physical swap at €34.00/MWh (approximately $14.58/Mcf).
• During 2023, Tenaz delivered a total shareholder return of 83%, ranking TNZ in the top 1.3% of all TSX-listed issues.

Year-End 2023 Reserves⁽⁵⁾

• Proved Developed Producing (“PDP”) reserves increased 22%, including a 17% increase in Canada through organic activities, reflecting a corporate reserve replacement ratio of 161%. PDP reserves at year-end totaled 3.7 million boe.
• Total Proved (“1P”) reserves increased 6%, reflecting a reserve replacement ratio of 144%. 1P reserves at year-end totaled 9.3 million boe.
• Total Proved plus Probable (“2P”) reserves increased 7%, reflecting a reserve replacement ratio of 195%. 2P reserves at year-end totaled 14.6 million boe.
• PDP Finding and Developing (“F&D”)⁽⁶⁾ costs (including future development capital (“FDC”)) were $19.53/boe, resulting in a 2.2 organic recycle ratio based on our 2023 operating netback⁽²⁾ of $43.18/boe. F&D costs (including FDC) were $23.44 and $22.10 at the 1P and 2P levels, generating organic recycle ratios of 1.8 and 2.0, respectively.
• PDP Finding, Developing and Acquisition Costs (“FD&A”), were $17.23/boe (including FDC), resulting in a 2.5 recycle ratio. FD&A costs (including FDC) were $19.69 and $17.15 at the 1P and 2P levels, generating recycle ratios of 2.2 and 2.5, respectively. For purposes of the calculation of FD&A costs and their corresponding recycle ratios, we have utilized a nil purchase price for the XTO acquisition. Actual net consideration for the XTO Acquisition was negative $42.8 million, due to acquiring positive working capital while not providing financial consideration to XTO. Had we utilized the negative purchase price for this acquisition, FD&A costs (including FDC) and their corresponding recycle ratios would have been negative values.
• Reserve life indices were 3.2 years, 8.1 years and 12.8 years, respectively, for PDP, 1P and 2P reserves, based on our Q4 2023 production rate.

Capital Activity and Outlook

• Capital expenditures⁽²⁾ during full year 2023 were approximately $24.8 million. This total includes both Drilling and Development capital expenditures (“D&D CAPEX”) and Exploration and Evaluation capital expenditures (“E&E CAPEX”).
• Our 2023 Canadian development program included drilling, completing, equipping and tie-in of four gross (3.35 net) wells. Combining our Canadian investment program with Netherlands workover and facility investment, D&D CAPEX was $23.3 million. Full year D&D CAPEX for 2023 was within our guidance range of $20 to $24 million.
• During 2023, we elected to participate in FEED activities for the potential L10 Carbon Capture and Storage (“CCS”) project in the Netherlands, which is included as E&E CAPEX due to the project’s unsanctioned status. Full year 2023 E&E CAPEX totalled $1.5 million (100% of which related to L10 CCS).
• In 2024, we plan D&D CAPEX of $23 to $25 million. The D&D CAPEX program includes a four (3.5 net) well drilling program in Canada and non-operated workovers, facility maintenance and studies at the F17a oil development project in the Netherlands. In addition, we forecast E&E CAPEX of $3 million for continued evaluation of the potential L10 CCS project.
• Production guidance for 2024 remains unchanged at 2,700 to 2,900 boe/d.

FINANCIAL AND OPERATIONAL SUMMARY

PRESIDENT’S MESSAGE

We are pleased to provide our quarterly and annual report of our financial and operating results, along with our year-end independent reserve report. We had our strongest operating results since the inception of Tenaz, again reporting very strong reserve replacement and capital efficiencies. With respect to acquisitions, we continue to advance our pipeline of potential transactions, particularly in Europe and Latin America. We believe asset market conditions are in our favor with commodity prices at reasonable levels and little evidence that buyer competition has heated up.

Netherlands Operations

At mid-year, we made our second non-operated Netherlands acquisition when we added XTO Netherlands to our DNS portfolio. Our Netherlands production averaged 1,107 boe/d during Q4 2023, up 1% over Q3 2023. For full year 2023, Netherlands contributed 892 boe/d (99% TTF gas) at an average realized price of $16.65/Mcf.

European gas prices appear to have bottomed after this winter’s weather-driven decrease. Despite another warm winter, European gas storage is slightly below last year’s levels, and, as at March 27^th, the prompt price remains at $11.92/Mcf, more than four times North American levels. The TTF forward price curve is largely flat, with an average price of $12.69/Mcf through 2027. We have hedged 40% of our Q1 2024 TTF exposure at $24.12/Mcf and 20% of Q2 and Q3 2024 at $14.58/Mcf.

Capital investment in the Netherlands upstream assets in 2023 totaled $4.4 million for well workover and facilities projects, managing to maintain flat production over the second half of 2023. We would expect to have roughly similar activity for 2024, yielding production levels slightly below those in the second half of 2023.

With the XTO Acquisition, we also increased our shareholding in the NGT midstream system by 10.1%, bringing our ownership in this high-reliability and valuable offshore gas gathering business to 21.4%. NGT is accounted for as an equity investment, whereby our interest in the net income of NGT is included in our results as income from associate. Tenaz estimates that full year 2023 NGT net income was approximately $27 million ($6 million to Tenaz’s equity interest). Dividend payments from NGT have traditionally occurred in the first half of the subsequent year. Payout of earnings in the form of dividends from NGT can vary from year to year, but typically closely matches the underlying earnings from the prior financial year. Tenaz received an interim dividend of €2.2 million ($3.1 million) at the end of Q4 2023.

In addition to its desirable attributes as a natural gas gathering and processing business, NGT also represents critical infrastructure that may also have a key long-term role in the energy transition in Europe. The NGT system is a hard-to-replicate pipeline network that is certified to transport hydrogen and may provide a cost-effective and environmentally-benign way to connect future offshore hydrogen production with onshore users.

Tenaz also has an 11.35% participation right in the L10 CCS project, which is intended to provide a permanent storage solution for CO₂ sourced from industrial emitters. This project has entered the Front-End Engineering Design (“FEED”) phase, which is scheduled to continue until the end of Q2 2025. The FEED phase is required for comprehensive project planning before making the Final Investment Decision (“FID”), with FID currently slated for Q2/Q3 2025. In the event of a positive FID, project start up is estimated to occur in 2028, with injection of up to five million tonnes per annum of CO₂. The L10 gas field, located approximately 50 km offshore in the DNS, has a potential storage capacity of 96 MT. The combined storage capacity of the L10 and other pools potentially amenable to CCS in the Tenaz license areas is approximately 150 MT.

Canadian Operations

Production from the Leduc-Woodbend (“LWB”) field averaged 2,028 boe/d in Q4 2023, an increase of 59% compared to Q3 2023, driven by strong contributions from our four well (3.35 net) drilling program which was fully on production in the fourth quarter. For 2023 as a whole, production averaged 1,547 boe/d as compared to 1,193 boe/d in 2022, an increase of 30%.

The four wells drilled in 2023 are the longest to-date in the LWB field, with total measured depths ranging from 5,000 to 5,700 meters. These wells also have the longest completed horizontal sections at LWB, with completion intervals ranging from 3,600 to 4,200 meters. Despite longer laterals and an increased number of fracs, these wells were drilled entirely within the targeted Rex member of the Mannville group and were completed with 97% of frac stages successfully placed. The new wells have generated impressive rates, with a Q4 2023 average rate of 225 boe/d per well and a very high oil percentage of 89% in their product mix. This strong average well rate was achieved even though one of the wells only has 40% of its lateral open to production due to a fish stuck in the lateral. We view the improving technical indicators and production levels on the Rex wells as evidence of the effectiveness of Tenaz’s engineering and geoscience approach, which we will also seek to apply on future international acquisitions that we operate.

Capital expenditures for Canada in 2023 totaled approximately $19 million, more than 80% of which was for the four-well DCET (drill, complete, equip and tie-in) program, with the remainder primarily for facility modifications and land acquisition. As a result of the success of the drilling program and ongoing efforts to reduce well failures and other sources of downtime, unit operating expense in Canada decreased to $12.47/boe in Q4 2023, a 31% reduction from Q3 2023. For 2023 as a whole, unit operating expense decreased to $16.55/boe, 6% lower than in 2022.

Looking forward to 2024, we expect to again conduct a four well (3.5 net) drilling program in LWB at roughly comparable CAPEX levels to last year. We believe that this program will continue to generate strong Canadian production growth, with average production in 2024 expected to increase on the order of 20% from 2023 levels.

With respect to commodities hedging, we have hedged approximately 25% of our winter 2024/25 gas production at an AECO marker price of $3.28/Mcf. Our crude oil produced at LWB sells for approximately the WCS marker price and does not require diluent. We are currently unhedged for both WCS differentials and the underlying WTI index. Though we may hedge as opportunities arise, we have a constructive view of both world oil fundamentals and the Canadian transport situation as start-up of the Trans Mountain pipeline approaches. Moreover, our unlevered financial position allows us the flexibility to maintain a greater degree of operating leverage through unhedged commodity exposure.

Reserves

We commissioned McDaniel and Associates Consultants Ltd. (“McDaniel”) to provide an independent year-end 2023 reserves evaluation report (the “McDaniel Report”), dated March 12, 2024 with an effective date of December 31, 2023. Total Proved plus Probable (“2P”) reserves increased 7%, reflecting a reserve replacement ratio of 195%. The increase in reserves was driven by the XTO Acquisition and our development activities at LWB, partially offset by production during 2023. At year-end 2023, 2P reserves totaled 14.6 million boe, with a reserve life index of 12.8 years calculated using our record level of production in Q4 2023.

Organic F&D costs (including FDC) were $22.10/boe at the 2P level, generating a recycle ratio of 2.0. When calculating FD&A costs, we have elected a conservative presentation by setting consideration for the XTO Acquisition at a zero cost. With this assumption, FD&A costs (including FDC) were $17.14/boe, generating a recycle ratio of 2.5. Had we utilized the actual negative purchase price for XTO, FD&A costs (including FDC) and recycle ratio would have had negative values.

The McDaniel Report is discussed in more detail later in this press release.

Corporate Discussion

Our corporate guidance levels for 2024 remain unchanged at 2,700 to 2,900 boe/d of production and $23 to $25 million of D&D CAPEX.

With respect to corporate liquidity, positive adjusted working capital was $49.3 million at the end of 2023, an increase of $4.4 million over the prior quarter and $35.3 million over year-end 2022. The improvement was driven by free cash flow and the XTO Acquisition for the respective periods, partially offset by spending on decommissioning activity and share buybacks. We remain undrawn on our $10 million bank facility.

During 2023, we expended $3.9 million under our Normal Course Issuer Bid (“NCIB”) program, buying back 1.3 million shares at an average price of $2.97/share. Since inception, the NCIB program has retired 1.9 million shares at an average price of $2.70/share.

It has now been more than two years since we executed our recapitalization of Altura Energy in Q4 2021. During that time, we have increased our production rate more than three-fold, doubling Canadian production through organic activity and introducing overseas production through our first two Netherlands transactions. Funds flow from operations (“FFO”) for 2023 was $28.9 million, an approximately eight-fold increase from before the recapitalization, driven both by higher production and higher margins. Regarding our balance sheet, we have moved from a net debt position of $3.5 million prior to the recapitalization to $49.3 million in positive adjusted working capital at year-end 2023, and have an undrawn bank facility.

In terms of market performance, Tenaz shares now trade at twice the level then at the time of the recapitalization of Altura. During 2023, Tenaz delivered a total shareholder return of 83%, ranking TNZ in the top 1.3% of all TSX issuers, and among the very best returns for companies in the oil and gas industry.

More importantly than these statistical improvements, we believe that we have demonstrated, at least to a modest degree, both elements of our overseas acquisition-oriented business model. First, we believe there is a great value opportunity in overseas acquisitions. In the Netherlands, we have executed two small but highly-accretive transactions in a high-value commodity market. We hope that these transactions will prove to be forerunners of larger future acquisitions from our transaction pipeline. Second, we believe that we will be able to significantly improve production profiles and cost levels when we operate assets acquired in the overseas market. We have demonstrated such capability at the LWB field, where our geologic description, drilling methods and frac designs have significantly improved production results and capital efficiencies. We find it encouraging that such technical improvement could be achieved when taking over from a quality operator like Altura, which discovered this substantial and previously-overlooked oil development project. Our assessment is that the North American oil and gas industry is in general much more efficient than the overseas industry, especially with respect to the more mature producing assets that we are targeting. The combination of these two factors – better value at acquisition and more opportunities for operational improvement – is what we believe creates such outsized opportunities for high returns in the overseas market.

We appreciate the hard and effective work of our team members in pursuing this strategy. In many ways, it is not an easy business model, requiring detailed technical, commercial and financial work to evaluate and structure transactions. Because of their complexity and the inherent slowness of the overseas asset market, these acquisitions typically take a long time to bring to fruition with many twists and turns along the way. These challenges, in fact, increase the opportunity to achieve high returns on capital. Our team of technical and finance professionals recognizes this and seeks to take advantage of the complexities to strike more favorable terms and structures for Tenaz.

Our team is invested in Tenaz and fully aligned with our broader shareholder group in pursuit of our shared success. As we have previously stated, we can make no guarantees regarding the certainty or timing of the next transaction, but we are optimistic about bringing quality assets into our portfolio. When we do so, we are confident that our investments will be consistent with our stated financial and strategic goals. We appreciate the continued support of our shareholders as we pursue our vision for Tenaz.

/s/ Anthony Marino

President and Chief Executive Officer
March 28, 2024

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, 2023 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, 2024 (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. Consistent with 2022 year-end reserves, and in accordance with guidance in the COGE Handbook, the McDaniel Report includes all abandonment, decommissioning and reclamation obligations (“ADR”), including all ADR associated with both active and inactive wells regardless of whether such wells had any attributed reserves.

Summary of Gross Reserves as at December 31, 2023

Reconciliation of Reserves for 2023

Summary of Net Present Values of Future Net Revenue as at December 31, 2023

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, 2024. 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.

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. For purposes of the calculation of FD&A costs and their corresponding recycle ratios, we have utilized a nil purchase price for the XTO acquisition. Actual net consideration for the XTO Acquisition was negative $42.8 million, due to acquiring positive working capital while not providing financial consideration to XTO. Had we utilized the negative purchase price for this acquisition, FD&A costs (including FDC) and their corresponding recycle ratios would have had negative values.

CONTINGENT RESOURCES AND PROSPECTIVE RESOURCES

An independent resources report on the resource potential of the Company’s DNS assets (the “Resources Report”) was prepared by McDaniel, the Company’s independent qualified reserves evaluator, in accordance with the standards contained in the COGE Handbook and the definitions contained in NI 51-101 and the COGE Handbook. The Resources Report has an effective date of December 31, 2023 and a preparation date of March 12, 2024.

Contingent and prospective resources evaluated in the Resources Report are located offshore in the Dutch North Sea in the country of the Netherlands. Contingent resources reflect the undeveloped Rembrandt and Vermeer oil discoveries operated by Wintershall Noordzee B.V. (“Wintershall“) and two undeveloped natural gas discoveries on the Neptune Energy Netherlands B.V. (“Neptune“) operated licenses. Prospective resources reflect 15 exploration prospects on licenses that are operated by Wintershall and Neptune. 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)

Netherlands Contingent Resources

Summary of Contingent Resources Estimates – Company Gross Values
(Forecast Prices and Costs)

Netherlands Summary of Company Share of Net Present Values as at December 31, 2023

About Tenaz Energy Corp.

Tenaz is an energy company focused on the acquisition and sustainable development of international oil and natural gas assets capable of returning free cash flow to shareholders. In addition, Tenaz conducts development of a semi-conventional oil project in the Rex member of the Upper Mannville group at Leduc-Woodbend in central Alberta and has non-operated natural gas production assets offshore Netherlands.