TENAZ ENERGY CORP. ANNOUNCES Q2 2023 RESULTS AND NETHERLANDS RESOURCE ASSESSMENT
CALGARY, AB, August 10, 2023 /CNW/ - Tenaz Energy Corp. ("Tenaz", "We", "Our", "Us" or the "Company") (TSX: TNZ) is pleased to announce its financial and operating results for the three and six months ended June 30, 2023 and provide a resources summary with an effective date of July 1, 2023 of its independent resources report on the resource potential of our Dutch North Sea ("DNS") assets (the "Resources Report"), prepared by McDaniel and Associates Consultants Ltd. ("McDaniel").
The unaudited interim condensed consolidated financial statements and related management's discussion and analysis ("MD&A") are available on SEDAR+ at www.sedarplus.ca and on Tenaz's website at www.tenazenergy.com. Select financial and operating information for the three and six months ended June 30, 2023 appear below and should be read in conjunction with the related financial statements and MD&A.
A webcast presentation to accompany this release is available on Tenaz's website at www.tenazenergy.com.
HIGHLIGHTS
Second Quarter Operating and Financial Results
In June, Tenaz announced the signing of an agreement to purchase XTO Netherlands Ltd ("XTO"), increasing our position in the Dutch North Sea ("DNS"). We closed the XTO acquisition in early July 2023. Accordingly, we will recognize the operating and financial results from the XTO assets beginning with our Q3 2023 report. In June 2023, production from the XTO assets were approximately 475 boe/d(1), with total Netherlands production at approximately 1,250 boe/d.
The XTO acquisition also increased our ownership in the NGT midstream assets to 21.4%, making Tenaz the second-largest shareholder in NGT. We consider the NGT infrastructure as integral for Netherlands energy security and the transition to cleaner energy in Europe.Production volumes averaged 1,903 boe/d in Q2 2023, 19% lower than Q1 2023 and 70% higher than Q2 2022. Production was lower compared to Q1 2023 due to facility turnarounds in both Canada and Netherlands. Production was higher than Q2 2022 due to the acquisition of a private company with Netherlands assets at the end of 2022 and continued organic growth in our Leduc-Woodbend field in Canada. Production acquired from XTO was not included in Q2 2023 results, with closing occurring after the end of the quarter.
Production volumes averaged 2,119 boe/d in first half of 2023, 100% higher than the first six months of 2022. Production was higher due to the acquisition of Netherlands assets at the end of 2022 and development activity in Canada.Funds flow from operations ("FFO")(2) for the second quarter was $3.4 million, 54% lower than Q1 2023 and 60% higher than Q2 2022. Lower quarter-over-quarter FFO resulted from lower production and higher expenses due to facility turnarounds, coupled with lower prices for TTF natural gas(3).
FFO for the six months ended June 30, 2023 was $10.6 million, 244% higher than in the comparable 2022 period. Higher 2023 FFO primarily resulted from contributions from the new Netherlands assets.Free cash flow(2) in the first half of 2023 was $4.0 million, compared to negative free cash flow of $1.1 million in the first six months of 2022, with improved contributions from both our Netherlands and Canadian assets.
Net income for Q2 2023 was a loss of $0.8 million, as compared to profit of $2.9 million in Q1 2023 and profit of $0.8 million in Q2 2022. Lower net income resulted from lower production and higher expenses due to turnarounds in both Canada and Netherlands, as well as transaction costs for closed and prospective M&A activities. First half 2023 net income of $2.1 million was lower than net income of $4.3 million in the first half of 2022, primarily because a $4.2 million impairment reversal was recorded in Q1 2022.
We ended the quarter with positive adjusted working capital (net debt)(2) of $17.1 million, an increase of $3.1 million over year-end 2022 as a result of the free cash flow generated in the first six months of 2023. Subsequent to the end of the quarter, as a part of the XTO acquisition, we acquired positive adjusted working capital of $46.7 million (subject to post-closing adjustments).
Our Normal Course Issuer Bid ("NCIB") retired 716 thousand common shares (2.5% of basic common shares) at an average cost of $2.25 per share during the first six months of 2023. As of the end of July 2023, we have retired 1.22 million common shares (4.3% of basic common shares) at an average cost of $2.07 per share. During Q3 2023, we intend to apply for the renewal of our NCIB program for an additional year.
Budget and Outlook
Capital expenditures(2) during the second quarter totalled approximately $6.0 million, as Canadian drilling was initiated ahead of schedule. First half 2023 capital expenditures totalled $6.7 million. Annual guidance for capital expenditures remains unchanged at $20 to $24 million.
Our planned 2023 Canadian development program is underway with four gross (3.35 net) wells now drilled and completions in progress. The four wells are expected to be tied-in at the end of Q3 2023.Production in the second half of 2023 is expected to increase as both Canada and the Netherlands are off turnarounds, XTO volumes are recognized, and the new Leduc-Woodbend wells are expected to come online at the end of Q3 2023.
Annual production guidance, as updated following the XTO acquisition, is unchanged at 2,300 to 2,500 boe/d.
Netherlands Resources
We engaged McDaniel to independently evaluate and prepare a report on the resource potential of our DNS assets. The Resource Report has an effective date of July 1, 2023 and was prepared in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and uses the resources and reserves definitions, standards and procedures set forth in the Canadian Oil and Gas Evaluation Handbook ("COGEH"). The Resource Report includes contingent and prospective resources attributable to the acquisitions of the Netherlands offshore assets completed on December 20, 2022 and the recent acquisition of XTO completed on July 3, 2023.
The unrisked low, best, and high estimates for Tenaz's share of contingent resources are 2.4, 4.3, and 6.9 million boe ("mmboe") respectively, with a risked mean of 4.5 mmboe. McDaniel conducted an economic analysis of the best estimate case for the contingent resources using the three consultant average forecast prices and costs as of July 1, 2023. The Resource Report indicates after-tax net present values discounted at 10% for the best estimate contingent resources (2C) of $86.0 million (€58.5 million)(4).
The unrisked low, best, and high estimates for Tenaz's share of prospective resources are 8.9, 19.8, and 48.5 mmboe respectively, with a risked mean of 10.2 mmboe after applying chance of discovery on a prospect-by-prospect basis.
(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) | Dutch TTF Gas is a leading European benchmark price as the volumes traded represent more than 14 times the amount of gas used by the Netherlands for domestic purposes. |
(4) | Canadian dollar equivalent calculated using an exchange rate of 1.47 Canadian dollars per euro. |
FINANCIAL AND OPERATIONAL SUMMARY
Three months ended | Six months ended | ||||||||
($000 CAD, except per share and per boe amounts) | Jun 30, 2023 | Mar 31, 2023 | Jun 30, 2022 | Jun 30, | Jun 30, 2022 | ||||
FINANCIAL | |||||||||
Petroleum and natural gas sales | 10,614 | 17,926 | 9,344 | 28,540 | 15,545 | ||||
Cash flow from operating activities | 957 | 5,117 | 1,936 | 6,074 | 3,094 | ||||
Funds flow from operations(1) | 3,361 | 7,274 | 2,104 | 10,635 | 3,096 | ||||
Per share – basic(1)(2) | 0.12 | 0.26 | 0.07 | 0.38 | 0.11 | ||||
Per share – diluted(1) | 0.12 | 0.25 | 0.07 | 0.37 | 0.11 | ||||
Net income (loss) | (757) | 2,882 | 769 | 2,125 | 4,266 | ||||
Per share – basic | (0.03) | 0.10 | 0.03 | 0.08 | 0.15 | ||||
Per share – diluted | (0.03) | 0.10 | 0.03 | 0.07 | 0.15 | ||||
Capital expenditures(1) | 5,967 | 683 | 3,512 | 6,650 | 4,231 | ||||
Adjusted working capital (net debt)(1) | 17,094 | 18,763 | 19,431 | 17,094 | 19,431 | ||||
Common shares outstanding (000) | |||||||||
End of period – basic | 27,378 | 27,733 | 28,548 | 27,378 | 28,548 | ||||
Weighted average for the period – basic | 27,555 | 27,917 | 28,481 | 27,735 | 28,469 | ||||
Weighted average for the period – diluted | 28,308 | 28,545 | 29,241 | 28,427 | 28,914 | ||||
OPERATING | |||||||||
Average daily production | |||||||||
Heavy crude oil (bbls/d) | 711 | 937 | 636 | 824 | 576 | ||||
Natural gas liquids (bbls/d) | 57 | 63 | 61 | 60 | 61 | ||||
Natural gas (mcf/d) | 6,802 | 8,022 | 2,524 | 7,409 | 2,551 | ||||
Total (boe/d)(2) | 1,903 | 2,337 | 1,117 | 2,119 | 1,062 | ||||
($/boe)(2) | |||||||||
Petroleum and natural gas sales | 61.31 | 85.23 | 91.90 | 74.43 | 80.84 | ||||
Royalties | (4.80) | (6.28) | (17.11) | (5.61) | (13.93) | ||||
Transportation expenses | (3.66) | (3.41) | (3.12) | (3.52) | (2.39) | ||||
Operating expenses | (28.25) | (24.69) | (14.47) | (26.30) | (17.56) | ||||
Midstream income(1) | 5.21 | 4.36 | - | 4.74 | - | ||||
Operating netback(1) | 29.81 | 55.21 | 57.20 | 43.74 | 46.96 | ||||
BENCHMARK COMMODITY PRICES | |||||||||
WTI crude oil (US$/bbl) | 73.77 | 76.11 | 108.41 | 74.94 | 101.35 | ||||
WCS (CAD$/bbl) | 78.93 | 74.52 | 122.08 | 74.06 | 111.56 | ||||
AECO daily spot (CAD$/mcf) | 2.43 | 3.24 | 6.88 | 2.84 | 5.70 | ||||
TTF (CAD$/mcf) | 15.24 | 22.78 | 40.26 | 18.99 | 40.96 | ||||
(1) | 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. |
(2) | 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. |
PRESIDENT'S MESSAGE
We are pleased to provide this update along with our results for the second quarter of 2023. During Q2 2023, we advanced our overseas acquisition strategy, conducted turnarounds on our facilities in both Canada and Netherlands, and initiated our 2023 development program in Canada. We also commissioned an independent assessment by McDaniel of the resource potential in our Netherlands assets.
As announced prior to the end of Q2 2023, we acquired additional Netherlands assets from XTO with an effective date of January 1, 2023, closing this acquisition in early July 2023. As of our last data in June 2023, these assets are producing at the mid-point of their expected range of 475 boe/d(1). In combination with our earlier acquisition of a private company in December 2022, our total production rate in Netherlands as of June was approximately 1,250 boe/d. In the XTO purchase, we also increased our shareholding in the NGT midstream system by 10.1%, bringing our ownership in this high-reliability gathering business to 21.4%.
Production averaged 1,903 boe/d in Q2 2023, down 19% from our Q1 2023 levels. The main driver of the quarter-over-quarter decrease was facility turnaround work conducted in both Canada and Netherlands, during which time production was idled. The operator of our Dutch North Sea assets completed its annual maintenance and integrity management campaign, resulting in 26 days of downtime during April and May. Following the shut-down, production has been delivering on the prior expectations for these predictable reservoirs. The shutdown was timed to coincide with seasonally low demand for European natural gas. In Canada, we also conducted turnarounds at our two processing facilities, including an expansion of gas compression capacity at one facility to accommodate future production increases.
Despite the turnarounds, Q2 2023 production was still 70% higher than in Q2 2022, due to successful drilling in Canada in the second half of 2022 and the first Netherlands acquisition. First half 2023 production was 2,119 boe/d, up 100% from the first half of 2022, including an organic increase of 36% in Canada.
We generated FFO(2) of $3.4 million in Q2 2023, 54% below Q1 2023, primarily due to lower production as a result of the turnarounds. FFO for Q2 2023 was 60% higher than in Q2 2022, driven by higher production, including the impact of the first Netherlands acquisition.
We were able to get an earlier start than expected on our four gross (3.35 net) well drilling program at Leduc-Woodbend in Canada, taking advantage of availability of suitable drilling services and dry weather at the beginning of June. As a result, capital expenditures(2) ("CAPEX") in Canada was $4.2 million in Q2 2023, reflecting drilling of the first two wells. Because of wet weather in early July, our rig move to the next pad was delayed, and the program is back on its original schedule to deliver production at the end of Q3 2023. Netherlands CAPEX was $1.7 million in Q2 2023, roughly evenly split between Exploration & Development ("E&D") investment for facilities and technical work by the operator on the potential for Carbon Capture & Storage ("CCS").
Free cash flow(2) in the first half of 2023 was $4.0 million, compared to negative free cash flow of $1.1 million in the first six months of 2022, with improved contributions from both our Netherlands and Canadian assets.
Looking forward, our production guidance for full-year 2023 for both assets remains as previously announced, with Canada at 1,450 to 1,550 boe/d and Netherlands at 850 to 950 boe/d, for a corporate total of 2,300 to 2,500 boe/d. Capital guidance of $20 to $24 million also remains unchanged.
With respect to liquidity, positive adjusted working capital (net debt)(2) was $17.1 million as at June 30, 2023. This working capital balance was prior to the addition of approximately $46.7 million through the XTO acquisition. In addition, we remain undrawn on our $10 million bank facility.
Our Normal Course Issuer Bid ("NCIB") program retired 716 thousand common shares (2.5% of basic common shares) at an average cost of $2.25 per share during the first six months of 2023. As of the end of July 2023, we have retired 1.22 million common shares (4.3% of basic common shares) at an average cost of $2.07 per share. During Q3 2023, we plan to apply for the renewal of our NCIB program for an additional year.
Due to warm weather last winter and increased storage levels this summer, pricing for European natural gas (as referenced by the TTF index) was lower in Q2 2023. Despite higher storage levels, there is uncertainty about the ability to meet demand for a typical winter in 2023-2024, which is likely to support prices and maintain elevated volatility in the coming months. One of the main sources of supply for Europe is now imported LNG, and the competitive global landscape for LNG supply creates risks in the near-to-medium term. In addition, there is significant uncertainty regarding long-term supply replacement for historical imports of Russian gas, and risk of interruption of the remaining Russian deliveries into Europe. Consequently, forward TTF prices are at a meaningful premium to the prompt price of $16.24 per mcf. The forward price for Q4 2023 is $20.21 per mcf, with calendar 2024 at $22.50(3). Our view is that the presence of European natural gas in our product mix is differentiating and advantageous to Tenaz.
Our other major product is Canadian oil, for which WTI is currently priced at US$83 per bbl with WCS differentials contracting to approximately US$16 per bbl. Our crude typically sells at the WCS price without the addition of diluent. While Canadian natural gas is a less significant product in our mix, a meaningful portion of our AECO gas exposure is fixed for summer 2023 at prices above current market levels.
We view our recently-closed acquisitions as examples of our approach to finding real value in the overseas M&A market for producing properties. These transactions reflect our philosophy of issuing as little equity as possible, while still improving our balance sheet and liquidity. Our team of technical and finance professionals is dedicated to securing additional value-adding acquisitions and is fully aligned with the rest of our 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 additional assets into the portfolio in the future. When we do so, we are confident that our acquisition investment will be consistent with our stated financial and strategic goals. We appreciate the support of our shareholders as we pursue realization of the Tenaz vision.
/s/ Anthony Marino
President and Chief Executive Officer
August 10, 2023
(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) | As of close of markets on August 10, 2023. |
NETHERLANDS RESOURCE REPORT
Further to the integration of assets we have acquired in the DNS, we engaged McDaniel to independently assess the resource potential of the assets beyond the reserve volumes that we currently recognize. The Resource Report showed the potential on our licenses with undeveloped oil and gas discoveries that qualify as contingent resources and exploration upside in the form of prospective resources.
The Resource Report has an effective date of July 1, 2023 and was prepared in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and uses the resources and reserves definitions, standards and procedures set forth in the Canadian Oil and Gas Evaluation Handbook ("COGEH"). The Resource Report includes contingent and prospective resources attributable to the acquisitions of the Netherlands offshore assets completed on December 20, 2022 and on July 3, 2023.
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. The unrisked low, best, and high estimates for Tenaz's share of contingent resources are 2.4, 4.3, and 6.9 mmboe respectively, with a risked mean of 4.5 mmboe. McDaniel conducted an economic analysis of the best estimate case for the contingent resources using the 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 July 1, 2023. The Resource Report indicates after-tax net present values discounted at 10% for the best estimate contingent resources (2C) of $86.0 million (€58.5 million). Contingent volumes and economic estimates do not reflect any scaling factor for chance of development.
Prospective resources reflect 21 exploration prospects on our licenses that are operated by Wintershall and Neptune. The unrisked low, best, and high estimates for Tenaz's share of prospective resources are 8.9, 19.8, and 48.5 mmboe respectively, with a risked mean of 10.2 mmboe after applying chance of discovery on a prospect-by-prospect basis. Prospective volumes do not reflect any scaling factor for chance of development.
In our current position as non-operator, we are unable to guarantee that any of these resource projects will be pursued. Nonetheless, the Resource Report illustrates that there is the potential for investment activity on these blocks beyond the project slate included in our reserve report as of December 31, 2022.
The tables below summarize the volumes and economic values in the Resource Report.
Netherlands Summary of Prospective Resources Estimates as at July 1, 2023
Company Gross Values(1)(2) Prospective Resources - Unrisked(3)(7) | Risked (mboe) | ||||||||
Prospect | Type | Working Interest | Low (mboe) | P50(10) (mboe) | Mean(10) (mboe) | High (P10)(10) (mboe) | |||
F10 Block | Crude Oil(9) | 5.00 % | 1,425 | 4,963 | 8,027 | 18,028 | 1,814 | ||
F10 Block | Natural Gas | 5.00 % | 1,138 | 3,033 | 4,229 | 8,723 | 579 | ||
F17a Block | Natural Gas | 5.00 % | 373 | 675 | 752 | 1,232 | 379 | ||
L10 Block | Natural Gas | 21.43 % | 2,809 | 5,428 | 6,168 | 10,461 | 4,158 | ||
L11a Block | Natural Gas | 21.43 % | 1,309 | 2,334 | 2,563 | 4,120 | 1,845 | ||
N7b Block | Natural Gas | 17.86 % | 1,849 | 3,335 | 3,680 | 5,903 | 1,456 | ||
Total(5)(6)(7)(8) | 8,902 | 19,770 | 25,418 | 48,467 | 10,230 | ||||
(1) | Gross values are Company working interest resources. |
(2) | Based on the July 1, 2023 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) | These are partially risked prospective resources that take into account the chance of discovery but not the chance 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 percent for crude oil and 75 percent for natural gas. |
F10 Block (Crude Oil)(9) CK1 West (29%), CK2 (20%), CK3 (20%) | |
F10 Block (Natural Gas) MB1 (15%), MB2 (15%), MB3 (11%) | |
F17a Block (Natural Gas) CK2 (50%) | |
L10 Block (Natural Gas) Limonite (72%), Topaz (64%), Malachite (63%), 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 Summary of Contingent Resources Estimates as at July 1, 2023
Company Gross Values(1)(2) Contingent Resources - Unrisked(3)(4)(6) | Chance of | Risked Pre-COD(5) (mbbl) | |||||
Crude Oil(8) Property | Working Interest | 1C(10) (mbbl) | 2C(10) (mbbl) | 3C(10) (mbbl) | |||
Vermeer | 5.00 % | 323 | 982 | 1,902 | 100 % | 1,060 | |
Rembrandt | 5.00 % | 1,026 | 1,482 | 1,986 | 100 % | 1,496 | |
L11-07 | 21.43 % | - | - | - | 100 % | - | |
L10-19 | 21.43 % | - | - | - | 100 % | - | |
Total Crude Oil(9) | 1,349 | 2,464 | 3,888 | 2,557 | |||
Company Gross Values(1)(2) Contingent Resources - Unrisked(3)(4)(6) | Chance of | Risked Pre-COD(5) (mmcf) | |||||
Natural Gas Property | Working Interest | 1C(10) (mmcf) | 2C(10) (mmcf) | 3C(10) (mmcf) | |||
Vermeer | 5.00 % | - | - | - | 100 % | - | |
Rembrandt | 5.00 % | - | - | - | 100 % | - | |
L11-07 | 21.43 % | 3,433 | 4,905 | 6,635 | 100 % | 4,982 | |
L10-19 | 21.43 % | 3,070 | 6,239 | 11,635 | 100 % | 6,907 | |
Total Natural Gas(9) | 6,502 | 11,144 | 18,270 | 11,889 | |||
Company Gross Values(1)(2) Contingent Resources - Unrisked(3)(4)(6) | Chance of | Risked Pre-COD(5) (mboe) | |||||
Total Oil | Working Interest | 1C(10) (mboe) | 2C(10) (mboe) | 3C(10) (mboe) | |||
Vermeer | 5.00 % | 323 | 982 | 1,902 | 100 % | 1,060 | |
Rembrandt | 5.00 % | 1,026 | 1,482 | 1,986 | 100 % | 1,496 | |
L11-07 | 21.43 % | 572 | 817 | 1,106 | 100 % | 830 | |
L10-19 | 21.43 % | 512 | 1,040 | 1,939 | 100 % | 1,151 | |
Total Oil Equivalent(9) | 2,432 | 4,322 | 6,933 | 4,538 | |||
(1) | Gross values are Company working interest resources. |
(2) | Based on the July 1, 2023 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 unrisked contingent resources that do not take into account the chance of development (COD), 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 percent for crude oil and 75 percent for natural gas. |
(6) | These are economic contingent resources and are sub-classified in terms of maturity as development on hold. |
(7) | 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. |
(8) | Vermeer crude oil is 30o API and Rembrandt crude oil is 23o API. |
(9) | Numbers may not add up due to rounding. |
(10) | Denotes Contingent - Low estimate ("1C"), Contingent - Best estimate ("2C") and Contingent – High estimate ("3C"). Also refer to "Information Regarding Disclosure on Crude Oil and Natural Gas Resources" section included in the "Advisories" section of this press release. |
Netherlands Summary of Net Present Values as at July 1, 2023
Unrisked Net Present Value Discounted at(1)(2) | |||||
Best Estimate Contingent (2C) Resources Total(3)(4) | 0% (€000) | 5% (€000) | 8% (€000) | 10% (€000) | 15% (€000) |
Before Tax Net Present Values | |||||
L11-07 & L10-19 natural gas | 75,992 | 56,028 | 46,982 | 41,882 | 31,660 |
Vermeer & Rembrandt crude oil(5) | 115,784 | 62,925 | 44,177 | 34,884 | 18,829 |
Best Estimate Contingent Resources Total | 191,776 | 118,954 | 91,159 | 76,765 | 50,489 |
After Tax Net Present Values | |||||
Best Estimate Contingent Resources Total | 148,328 | 91,315 | 69,696 | 58,505 | 38,022 |
(1) | Based on the July 1, 2023 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) | 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 percent for crude oil and 75 percent for natural gas. |
(5) | Vermeer crude oil is 30o API and Rembrandt crude oil is 23o API. |
About Tenaz Energy Corp.
Tenaz is an energy company focused on the acquisition and sustainable development of international oil and gas assets capable of returning free cash flow to shareholders. Tenaz has domestic operations in Canada along with offshore natural gas assets in the Netherlands. The domestic operations consist of a semi-conventional oil project in the Rex member of the Upper 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. Further information on NGT can be found at https://noordgastransport.nl. 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", "adjusted working capital (net debt)", "free cash flow", "midstream income" 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 International Financial Reporting Standards ("IFRS") 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 ("FFO")
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 income from associate 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 IFRS. A summary of the reconciliation of cash flow from operating activities to funds flow from operations, is set forth below:
($000) | Q2 2023 | Q1 2023 | Q2 2022 | YTD 2023 | YTD 2022 | ||||||
Cash flow from operating activities | 957 | 5,117 | 1,936 | 6,074 | 3,094 | ||||||
Change in non-cash operating working capital | 1,294 | 907 | 168 | 2,201 | 2 | ||||||
Decommissioning liabilities settled | 209 | 333 | - | 542 | - | ||||||
Income from associate | 901 | 917 | - | 1,818 | - | ||||||
Funds flow from operations | 3,361 | 7,274 | 2,104 | 10,635 | 3,096 | ||||||
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) from the consolidated statements of cash flows that is most directly comparable to cash flows used in investing activities. The reconciliation to primary financial statement measures is set forth below:
($000) | Q2 2023 | Q1 2023 | Q2 2022 | YTD 2023 | YTD 2022 |
Exploration and evaluation | 880 | 36 | - | 916 | - |
Property, plant and equipment | 5,087 | 647 | 3,512 | 5,734 | 4,231 |
Capital expenditures | 5,967 | 683 | 3,512 | 6,650 | 4,231 |
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 most directly comparable to cash flows used in investing activities and is comprised of funds flow from operations less capital expenditures. A summary of the reconciliation of the measure, is set forth below:
($000) | Q2 2023 | Q1 2023 | Q2 2022 | YTD 2023 | YTD 2022 |
Funds flow from operations | 3,361 | 7,274 | 2,104 | 10,635 | 3,096 |
Less: Capital expenditures | (5,967) | (683) | (3,512) | (6,650) | (4,231) |
Free cash flow | (2,606) | 6,591 | (1,408) | 3,985 | (1,135) |
Midstream Income
Tenaz considers midstream income an integral part of determining operating netback. Operating netbacks assists management and investors with evaluating operating performance. Tenaz's midstream income consists of the income from its associate, Noordtgastransport B.V. Under IFRS, 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 and comprehensive income. Also see "Operating Netback" section below.
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 June 30, 2023 and December 31, 2022 is summarized as follows:
($000) | June 30 2023 | December 31 2022 |
Current assets | 46,967 | 72,317 |
Current liabilities | (30,162) | (58,749) |
Net current assets | 16,805 | 13,568 |
Exclude fair value of derivative instruments | 289 | 476 |
Adjusted working capital (net debt)(1) | 17,094 | 14,044 |
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. 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. Tenaz's operating netback is disclosed in the "Financial and Operational Summary" section of this press release.
Information Regarding Disclosure on Crude Oil and Natural Gas Resources
The resources estimates in this press release are derived from a resource report of Tenaz's Dutch North Sea assets with an effective date of July 1, 2023 prepared by McDaniel and Associates Consultants Ltd., an independent qualified reserves evaluator, in accordance with the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. The following provides the definitions of the various resource categories used in this press release as set out in COGEH.
"Contingent resource" and "prospective resource" are not, and should not be confused with, petroleum and natural gas reserves. Contingent resource is defined in the COGEH 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 COGEH as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from unknown accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development (COD).
Prospective resources are 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 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 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 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 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 July 1, 2023. 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, activities and budget for 2023, and our anticipated operational and financial performance; expected well performance; expected economies of scale; forecasted average production volumes and capital expenditures for 2023; the ability to grow our assets domestically and internationally; statements relating to a potential CCS project; and the Company's strategy.
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 the Company's oil and gas properties in a manner consistent with its 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; certain commodity price, interest rate, 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 or other regulatory matters; changes in development plans of the Company or by third party operators of the Company's properties, increased debt levels or debt service requirements; inaccurate estimation of the Company's oil and gas reserve volumes; 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.
SOURCE Tenaz Energy Corp.
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