Tenaz Energy Corp. announces 2022 year-end results and reserves

The related audited consolidated financial statements, as well as Management’s Discussion and Analysis (“MD&A”) for the year ended December 31, 2022 and annual information form (“AIF”) as of December 31, 2022, are available on SEDAR at www.sedar.com 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 2022 Results

• Production volumes averaged 1,520 boe/d¹ in Q4, up 43% year-over-year and 24% from Q3. For 2022 as a whole, production averaged 1,218 boe/d, up 20% from full-year 2021 production. The production increase was primarily due to volumes from new wells drilled in the second half of 2022 and occurred despite cold weather induced fluid processing restrictions in Q4.
• Funds flow from operations (“FFO”)² for 2022 was $8.6 million, up 146% from 2021. Higher 2022 funds flow from operations resulted from increases in both commodity prices and production volumes, partially offset by $1.8 million of realized hedging losses and $2.7 million of expensed transaction costs from our M&A activities.
• Net income for Q4 2022 was $0.7 million, as compared to $0.2 million in Q3, as a result of increased operating netback² partially offset by transaction costs. Full year 2022 net income was $5.2 million, which was lower than net income of $8.3 million in 2021, driven by a large impairment reversal recorded in 2021.
• The Company ended 2022 with positive adjusted working capital² of $14 million, up slightly from Q3 2022, despite investing in the drilling, completion and equipping of two (1.75 net) wells in Canada and incurring transaction costs for the Netherlands acquisition in Q4.
• During the fourth quarter, we completed the drilling and fracture stimulation of two (1.75 net) wells and brought both wells on production. The second well has a completed length of 2.16 miles, making it the longest well drilled to-date in the field. Production to-date from these wells exceeds their expected type curves.
• In late December 2022, we purchased a private company holding non-operated interests in the Dutch North Sea (“DNS”). The transaction adds high-value European natural gas production and associated infrastructure to our portfolio in a region of strategic importance to Tenaz. The transaction was completed without the issuance of equity, resulting in significant accretion for our shareholders. As consideration for the Netherlands acquisition, Tenaz posted €40.9 million security related to future decommissioning liabilities. On February 28, 2023, this security requirement was reduced as expected to €11.75 million. As a result of the security reduction, a credit facility which we put in place to facilitate the acquisition has been repaid in full. Tenaz’s original $10 million credit facility with ATB Financial is undrawn and available.
• Our 2023 budget has been updated to reflect the addition of the Netherlands acquisition. Our Exploration and Development (“E&D”) capital guidance is now $20 to $24 million, and annual production guidance is 2,200 to 2,300 boe/d. Based on the current commodity strip, funds flow from operations is expected to exceed our E&D capital investment program during 2023.
• Our Normal Course Issuer Bid (“NCIB”) program retired 454,700 shares (1.6% of basic common shares) at an average cost of $1.66 per share during 2022. We will continue to be active in retiring shares when market prices for our shares are meaningfully below our assessments of fair value. As of the end of February 2023, we have retired 688,700 shares at an average cost of $1.88 per share, utilizing approximately 26% of our approved limit of shares that can be repurchased through this program.

Year-End 2022 Reserves³

• Proved Developed Producing (“PDP”) reserves increased 75%, with a 31% increase through Canadian organic activities alone, reflecting a reserve replacement ratio of 392%. PDP reserves at year-end totaled 3.0 million boe, and after-tax net present value discounted at 10% (“NPV10”) increased 112% to $48.2 million ($1.72 per share).
• Total Proved (“1P”) reserves increased 30%, reflecting a reserve replacement ratio of 548%. 1P reserves at year-end totaled 8.8 million boe, and after-tax NPV10 increased 100% to $86.0 million ($3.06 per share).
• Total Proved + Probable (“2P”) reserves increased 20%, reflecting a reserve replacement ratio of 618%. 2P reserves at year-end totaled 13.6 million boe, and after-tax NPV10 increased 94% to $141.1 million ($5.02 per share).
• After-tax NPV10 for our Canadian assets increased by 50% to $34.1 million at the PDP level, 65% to $71.0 million at the 1P level, and 51% to $110.1 million at the 2P level. After-tax PV10s for our newly-acquired Netherlands natural gas assets were $14.2 million, $15.0 million and $31.0 million at the PDP, 1P and 2P levels, respectively.
• PDP Finding and Developing (“F&D”) costs (including future development capital (“FDC”)) were $17.74/boe, resulting in a 2.4x recycle ratio based on our 2022 operating netback⁴ of $42.31/boe. F&D costs (including FDC) were $16.01 and $14.69 at the 1P and 2P levels, generating recycle ratios of 2.6x and 2.9x, respectively. F&D costs solely reflect the results of our organic investment program in Canada.
• PDP Finding, Developing and Acquisition Costs (“FD&A”), were $10.50/boe (including FDC), resulting in a 4.0x recycle ratio. FD&A costs (including FDC) were $11.40 and $9.53 at the 1P and 2P levels, generating recycle ratios of 3.7x and 4.4x, respectively. The FD&A costs and resulting recycle ratios reflect both organic activities in Canada and the Netherlands acquisition.
• Reserve life indices were 5.4 years, 15.8 years and 24.6 years, respectively, for PDP, 1P and 2P reserves, based on our Q4 2022 production rate.

FINANCIAL AND OPERATIONAL SUMMARY

PRESIDENT’S MESSAGE

We view 2022 as a year in which the newly-created Tenaz Energy made significant advancements in three critical areas: development of our asset base in Canada, closing our first international acquisition and strengthening our organizational capability. These three areas are important to both the near- and long-term performance of Tenaz.

Our Canadian asset base consists of a single, high-quality oil project at Leduc-Woodbend. In this field, we made technical advancements in a number of key geologic, engineering and operational inputs to our development program. A substantially improved geologic description and frac design changes made it possible to increase the length of our development wells and simultaneously improve frac geometry and placement success. We reached lateral lengths in excess of two miles in our 2022 program while achieving frac placement efficiency of nearly 100%. The ability to drill longer laterals and confidently place more frac stages substantially increased our capital efficiency as evidenced by a very strong 2P F&D cost (including FDC) of $14.69 per boe, with a corresponding recycle ratio of 2.9. We have prepared the Leduc-Woodbend field for enhanced long-term growth through new land acquisition and by building production scale, with related reductions in unit cost expected in 2023 and beyond.

Our Netherlands acquisition is directly in line with our strategy of making high-return acquisitions primarily targeting the European and Middle East North Africa (“MENA”) regions. In this case, we acquired a private company with upstream and midstream offshore assets by posting decommissioning security as the primary form of consideration. With no share issuance, this acquisition enhances our per share metrics for production, reserves, FFO and NPV10. The transaction diversifies our production base, giving us an approximately one-third weighting to high-value European natural gas, which currently has a calendar-year 2023 strip of €47 per mwh ($20.37 per mmbtu). In addition, we acquired 11.3% ownership in Noordgastransport B.V. (“NGT”), which holds one of the largest gas-gathering and processing networks in the DNS, and exposure to a large potential Carbon Capture and Storage (“CCS”) project.

We will seek to expand our asset base in our regions of strategic interest by pursuing additional value-adding transactions. We believe the asset market is more conducive to this objective than at any time in our company’s eighteen-month history. Commodity prices have receded from the highs of early 2022, introducing greater realism into sellers’ expectations. As a result, we have been able to substantially expand and improve the quality of potential acquisitions in our transaction pipeline.

Organizational capability is the essential requirement for success in both our organic and acquisition activities. We started Tenaz in autumn 2021 with a strong officer corps of aligned and technically capable oil and gas professionals. During 2022 and early 2023, we made several key additions to our production engineering and acquisition evaluation technical ranks. Our new production engineering personnel are among the key drivers of our capital efficiency improvements in Leduc-Woodbend. In the acquisition side of our business, other new engineering colleagues give us the ability to evaluate more transactions as we scour our target regions for the highest return projects. Our goal is to take the controllable risk out of the M&A process to the largest extent possible, and our enhanced organization furthers that objective. We believe Tenaz is positioned for success in both elements of our business plan, international M&A and domestic organic development.

Operations Update

We continue to enhance our Leduc-Woodbend project returns by improving our knowledge of the Rex reservoir and depositional environment, extending horizontal well lengths, and continuously improving our frac stimulation design and execution. Better geologic and reservoir description allows optimal placement of well trajectories to remain in the pay column for the entirety of the horizontal length. Drilling longer wells reduces the surface footprint required for field development and improves capital efficiency by increasing ultimate recovery without a commensurate increase in well cost. Improved stimulation design reduces completion and well clean-up costs, and increases proppant concentrations and resulting pack conductivity, thereby generating improved production performance.

In our third quarter release, we announced an increase to our 2022 capital program and commenced an additional two wells (1.75 net) in the Leduc-Woodbend field. During the fourth quarter, we completed the drilling and fracture stimulation of those wells and brought them on production. The shorter of the two wells had a horizontal length of 1.25 miles and was completed with 71 frac stages (with 100% placement). The second well in this program had a horizontal length of 2.16 miles, making it the longest well drilled to date in the field. This well was completed with 124 stages (again with 100% placement).

Production volumes from Leduc-Woodbend averaged 1,425 boe/d in Q4 2022, an increase of 17% compared to Q3 2022 and 34% over Q4 2021. For full-year 2022, Leduc-Woodbend volumes were up 18% over 2021. The production increase was driven primarily by continued strong performance from the two (1.75 net) summer-program wells which were drilled in Q3 and strong initial rates during clean-up from the additional two (1.75 net) wells finished in Q4. The Q4 wells began producing hydrocarbons late in November 2022, with the longer of the two wells (2.16 mile length) recording a post-cleanup IP90 of 280 boe/d (83% liquids). The shorter well (1.25 mile length) achieved first oil quickly but has taken longer to recover all of its load fluid. The February 2023 production rate for this well averaged 260 boe/d (83% liquids) and is still cleaning up.

Capital investment for the fourth quarter was $5.0 million, bringing total investment in 2022 to $17.1 million. Capital investment was at the high end of our guidance range of $15 to $17 million, due to the impact of inflation in materials and services, particularly tubulars and construction.

We continue to high-grade and expand our Leduc-Woodbend land base through swaps, private mineral leasing, and Crown land sales. Although the absolute size of our Leduc-Woodbend land position remained relatively constant in 2022, we leased 1,920 gross (1,680 net) hectares of acreage that upgraded the quality of our land base by filling in holes in our core area and adding new prospective lands at the currently-identified field limits.

In Netherlands, our newly acquired asset made small contributions to Q4 2022 and 2022 annual production of 95 boe/d and 24 boe/d, respectively, owing to closing the transaction late in December. Our Netherlands asset continues to perform as expected with an average production rate of approximately 4.8 mmcf/d for the first two months of 2023.

ESG performance remains our highest priority. In our operated asset at Leduc-Woodbend, we completed 2022 with no injuries, reportable incidents or vehicle accidents. We have established a practical and forward-looking safety program placing emphasis on personal responsibility, hazard identification, investigation of “near misses” as learning opportunities, and regulatory compliance. In the environmental realm, we proactively modified a number of natural gas-operated devices to reduce their methane emissions by approximately 90%. Finally, we note that our share of the potential CCS project in the Dutch North Sea could offset carbon emissions for a Tenaz production level of 50,000 boe/d or more, compensating for a significant amount of our targeted long-term growth.

Outlook for 2023

Our expanded production scale at Leduc-Woodbend bodes well for improvement in unit costs. With the strong performance of recent wells and improved reservoir understanding, we are confident in conducting a planned four-well (3.35 net) drilling program for 2023. We expect our Canadian unit to produce 1,450 to 1,550 boe/d this year, an increase of 25% over 2022.

Our Netherlands assets are expected to produce approximately 4.5 mmcf/d (750 boe/d) and to contribute meaningful free cash flow for 2023. Our Netherlands capital budget includes minor workover and production enhancement activities. Though not currently budgeted, there is also the potential for drilling activity in Netherlands late in 2023.

In combination with Canada, our consolidated production guidance for 2023 is 2,200 to 2,300 boe/d with capital guidance of $20 to $24 million. Under the current strip, this capital program is more than fully funded by internal cash flow generation.

International M&A will continue to be our top priority. While there can be no certainty about the consummation or timing of any of the acquisitions in our current transaction pipeline, we believe the M&A market has moved in favor of our disciplined approach to evaluation and bidding. We maintain our playbook for new asset integration, which we think will be particularly effective on future acquisitions that we operate. We believe that we approach the M&A market from a position of strength with positive free cash flow from our growing organic asset base, negative net debt and a supportive shareholder base.

Prior to the recapitalization in October 2021, our predecessor company had outstanding indebtedness and was required by its lenders to have a certain percentage of its sales hedged. Tenaz is not currently required to hedge as we are now undrawn on our credit facility. Nonetheless, during Q4 2022 and Q1 2023, we executed some hedging transactions to mitigate a portion of our commodity price exposure. For AECO natural gas, we have price protection at levels exceeding the current strip for 3,000 GJ/d for Q1 2023 and 2,000 GJ/d for Summer 2023. We also have firm transport contracted for the large majority of our expected AECO natural gas production in 2023.

For WTI oil, we swapped 200 bbls/d at $75 per bbl for the first two months of 2023. In addition, we have fixed the differential exposure for 200 bbls/d of heavy oil (WCS marker) for the last nine months of 2023 at US$16.50 per bbl versus WTI.

We currently have hedges in place on all or part of the price exposure on 22% of our projected oil-equivalent production for 2023. Although we are not compelled to hedge, we will monitor the commodity markets for further opportunities to mitigate cash flow risks. Details of our hedging positions can be found in our annual report, available on our website and SEDAR.

We took important steps for the future of Tenaz in 2022. We are confident in our strategy and our ability to execute it. All of our management and directors are Tenaz shareholders, and every one of our employees is incentivized to deliver for our shareholder base. On behalf of our Board of Directors, we thank our shareholders and full stakeholder group for their ongoing support of Tenaz. We look forward to reporting our results to you during 2023.

/s/ Anthony Marino

President and Chief Executive Officer
March 21, 2023

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, 2022 available on SEDAR at www.sedar.com 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, effective December 31, 2022, in its report dated March 15, 2023. As a reporting issuer in Canada, Tenaz is required to report its reserves and net present value estimates using forecast pricing and costs, as stipulated under NI 51-101. 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, 2023 (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 2021 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, 2022

Reconciliation of Reserves for 2022

Summary of Net Present Values of Future Net Revenue as at December 31, 2022

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 NPVs are based on the Consultant Average Price Forecast at January 1, 2023. 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 FD&A⁽⁵⁾ and F&D⁽⁵⁾ costs including FDC: