Obsidian Energy Ltd 6-K, filed Jan 31, 2023
Obsidian Energy Ltd. (OBE)
About this 6-K
Obsidian Energy Ltd filed this 6-K on January 31, 2023.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 6-K
REPORT OF FOREIGN PRIVATE ISSUER
PURSUANT TO RULE 13a-16 OR 15d-16
OF THE SECURITIES EXCHANGE ACT OF 1934
For the month of January 2023
Commission File Number 1-32895
Obsidian Energy Ltd.
(Translation of registrant’s name into English)
Suite 200, 207 – 9th Avenue SW
Calgary, Alberta T2P 1K3
Canada
(Address of principal executive offices)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.
Form 20-F ☐ Form 40-F ☒
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1) ☐
Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7) ☐
.
DOCUMENTS INCLUDED AS PART OF THIS FORM 6-K
See the Exhibit Index hereto.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on January 31, 2023.
| OBSIDIAN ENERGY LTD. | ||
| By: | /s/ Stephen E. Loukas | |
| Name: | Stephen E. Loukas | |
| Title: | Interim President and CEO | |
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EXHIBIT INDEX
| Exhibit |
Description | |
| 99.1 | News release, dated January 30, 2023 | |
Exhibit 99.1
Obsidian Energy Announces 2023 Guidance and Significant 2022 Reserves Value Increase with Year-End Reserves Report
• 2023 capital expenditures includes development and exploration/appraisal programs with optionality for second half expansion
• 46 well development program across all core areas in 2023 expected to generate seven percent growth in production over 2022 and significant free cash flow at WTI US$80/bbl
• Board approves share buyback program for up to 10 percent of shares outstanding
• Reserve replacement of 144 percent, 214 percent and 393 percent of 2022 production on a proved developed producing, total proved, and total proved plus probable basis, respectively
CALGARY, January 30, 2023 – OBSIDIAN ENERGY LTD. (TSX / NYSE American – OBE) (“Obsidian Energy”, the “Company”, “we”, “us” or “our”) is pleased to announce our 2023 guidance that builds on our successful 2022 drilling results across all three areas, the introduction of a share buyback program, and the results of our independent reserves evaluation for the year ended December 31, 2022 (the “2022 Reserve Report”).
“Our 2022 drilling success positions us to continue to deliver both year-over-year production growth and strong free-cash flow generation in 2023,” said Stephen Loukas, Obsidian Energy’s Interim President and CEO. “Since introducing our 2023 preliminary forecast, we have seen a decline in oil prices, continued service cost inflation, and widening of heavy oil differentials, as well as a decline in our share price such that it trades materially below intrinsic value. Accordingly, our 2023 strategy now focuses on a balance between several components, including capital for development and exploration/appraisal wells, continued debt reduction and return of capital to shareholders via a share buyback, while also preserving acquisition optionality. The majority of our 2023 capital is allocated to core development but includes a component to further delineate our large land base, mainly in the Clearwater formation in the Peace River area. Our program optionality allows us to quickly adjust depending on well results, changes in commodity prices, and acquisition opportunities. We look forward to executing on our plans to create future value for our shareholders and the Company.”
Stephen Loukas continued, “We had an active year in 2022 with a successful capital program that was expanded mid-year and includes the acquisition of additional land in the Peace River area. These results, combined with higher commodity price forecasts, led to a substantial increase in our reserve values and volumes over 2021, replacing reserves across all categories. This represents the sixth year in a row of greater than 100 percent reserve replacement on total proved (“1P”) reserves and total proved plus probable (“2P”) reserves, excluding acquisitions and dispositions, and economic factors. As a result, our proved developed producing (“PDP”) and 1P reserve net present values increased by $438 million to $1.6 billion, and $700 million to $2.1 billion, respectively, at December 31, 2022 (before tax, discounted at 10 percent).”
2023 GUIDANCE
With a strong start to our 2023 development program, Obsidian Energy expects to grow average production to approximately 32,000 to 33,500 boe/d in 2023 – a seven percent increase from 2022 at the mid-point. While still growing production, we are electing to moderate our capital spending and growth profile in this environment of increasing service costs and WTI crude oil prices, which are approximately US$20 per barrel lower from mid-year 2022 levels. At this time, we prefer to redirect capital previously earmarked for development towards the initiation of a normal course issuer bid (“NCIB”).
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We are pleased with our 2022 results, which will be announced in February and are reflected in the increases in our 2022 Reserve Report. Our fourth quarter 2022 capital program remained active despite extreme cold weather in December that hampered operations and production. Fourth quarter capital was approximately $97 million, bringing full year capital slightly below our 2022 guidance at $319 million (including the Peace River gas plant acquisition in September). Production averaged 31,742 boe/d for the fourth quarter, bringing full year 2022 production to 30,682 boe/d, which is slightly below the low end of guidance of 30,800 boe/d due to the impact of the cold weather on operations and facilities. Concerning wells spud in 2022, three wells (2.9 net) were rig released in January 2023 and eight (7.8) net wells are expected to be brought on production in 2023.
During 2023, the Company is planning between $260 and $270 million in capital expenditures for development and exploration/appraisal activities, plus an additional $26 to $28 million in decommissioning expenditures that accelerates our asset retirement obligations (decommissioning expenditures are higher in 2023 than in 2022 as the Alberta Energy Regulator increased industry spend targets for oil and gas companies in Alberta). Capital expenditures are primarily focused on development wells in all areas and incorporate the impact of inflationary pressures on drilling consumables and service costs, which were approximately 30 percent higher at the end of 2022 compared to 2021. Obsidian Energy has contracted rigs and services for the first half 2023 program to minimize the impact of future inflation. Our active first quarter 2023 development program will continue the momentum from the 2022 program, resulting in production growth and expected strong free cash flow. Should commodity prices be favourable, we are well positioned to act on opportunities and adjust the program upward during the second half of the year.
Net operating expenses are expected to be slightly lower than 2022 levels as higher production helps offset the impacts of inflationary pressures and planned facility turnaround activity during the year. Free cash flow (“FCF”) generated in 2023 will be directed toward further debt reduction and to shareholders through the NCIB, resulting in a 2023 net debt to funds flow from operations (“FFO”) of approximately 0.5 times (prior to any shares repurchased under an NCIB). Any FCF above expected guidance levels could be allocated towards additional development and exploration/appraisal activities, potential acquisitions and/or additional shareholder return of capital. Our full year 2023 guidance is presented below.
| 2023E Guidance | ||||||
| Production1 |
boe/d | 32,000 – 33,500 | ||||
| % Oil and NGLs |
% | 67 | % | |||
| Capital expenditures2 |
$ millions | 260 – 270 | ||||
| Decommissioning expenditures |
$ millions | 26 – 28 | ||||
| Net operating costs |
$/boe | 13.50 – 14.40 | ||||
| General & administrative |
$/boe | 1.60 – 1.70 | ||||
| Based on midpoint of above guidance |
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| WTI Range |
US$/bbl | 80.00 | ||||
| AECO |
CAD$/GJ | 3.00 | ||||
| FFO3 |
$ millions | 395 | ||||
| FCF (prior to NCIB) |
$ millions | 105 | ||||
| Net debt (prior to NCIB)4 |
$ millions | 215 | ||||
| Net debt to FFO4 |
times | 0.5 | ||||
| (1) | Mid-point of guidance range: 12,330 bbl/d light oil, 6,885 bbl/d heavy oil, 2,565 bbl/d NGLs and 65.8 mmcf/d natural gas. Average production volumes include a minimal amount of forecasted production associated with exploratory capital expenditures. |
| (2) | Capital expenditures include approximately $25 million for exploration/appraisal well activity with minimal impact on forecasted production volumes. |
| (3) | Pricing assumptions outlined are forecasted for the full year of 2023 and include risk management (hedging) adjustments as of January 27, 2023. Guidance FFO and FCF includes approximately $6 million of estimated charges for full year 2023 related to the deferred share units, performance share units and non-treasury incentive plan cash compensation amounts which are based on a share price of $9.00 per share. |
| (4) | Net debt figures estimated as at December 31, 2023, prior to the impact of any share purchased under the NCIB. |
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| Guidance Sensitivity Table | ||||||||
| Variable |
Range | Change in 2023 FFO ($ millions) | ||||||
| WTI (US$/bbl) |
+/- $1.00/bbl | 8.6 | ||||||
| MSW light oil differential (US$/bbl) |
+/- $1.00/bbl | 5.5 | ||||||
| WCS heavy oil differential (US$/bbl) |
+/- $1.00/bbl | 3.1 | ||||||
| Change in AECO ($/GJ) |
+/- $0.25/GJ | 3.2 | ||||||
2023 CAPITAL PROGRAM
Our 2023 program incorporates activity in all three areas, including first quarter 2023 development drilling in Viking following the successful step-out well in 2022 and an expanded Clearwater exploration/appraisal program in Peace River to further assess our extensive land position. With rigs and services contracted, the first half 2023 program is well underway with five rigs in the process of drilling 25 wells (24.8 net) of our 46 well (44.2 net) operated program that includes:
| • | Seven Cardium wells (6.8 net) in Willesden Green and Pembina |
| • | Three Bluesky development wells (3.0 net) and two (2.0 net) exploration/appraisal wells in Peace River |
| • | Two Clearwater exploration/appraisal wells (2.0 net) in Peace River |
| • | 11 wells (11.0 net) in the Viking area |
Obsidian Energy also plans to drill up to four vertical non-productive oil sands exploration wells to collect additional reservoir data in the Peace River area. In addition to the 2023 program wells, three wells (2.9 net) from our 2022 development program were rig-released in 2023, and eight wells (7.8 net) are expected to come on production in early 2023. We expect to further optimize the second half 2023 program as new results from offset wells and first half exploration/appraisal drilling provide additional information.
| Development gross (net) wells |
Exploration/Appraisal gross (net) wells |
Total 2023 |
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| H1 | H2 | Total | H1 | H2 | Total | Program | ||||||||||||||||||||||
| Willesden Green (Cardium) |
5 (5.0 | ) | 6 (6.0 | ) | 11 (11.0 | ) | — | — | — | 11 (11.0 | ) | |||||||||||||||||
| Pembina (Cardium / Devonian) |
2 (1.8 | ) | 6 (4.4 | ) | 8 (6.2 | ) | — | — | — | 8 (6.2 | ) | |||||||||||||||||
| Peace River (Bluesky) |
3 (3.0 | ) | 7 (7.0 | ) | 10 (10.0 | ) | 2 (2.0 | ) | — | 2 (2.0 | ) | 12 (12.0 | ) | |||||||||||||||
| Peace River (Clearwater) |
— | — | — | 2 (2.0 | ) | 2 (2.0 | ) | 4 (4.0 | ) | 4 (4.0 | ) | |||||||||||||||||
| Viking |
11 (11.0 | ) | — | 11 (11.0 | ) | — | — | — | 11 (11.0 | ) | ||||||||||||||||||
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| TOTAL |
21 (20.8 | ) | 19 (17.4 | ) | 40 (38.2 | ) | 4 (4.0 | ) | 2 (2.0 | ) | 6 (6.0 | ) | 46 (44.2 | ) | ||||||||||||||
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| (1) | Three wells (2.9 net) were spud in 2022 and rig-released in 2023; they are included in these totals. |
| (2) | 45 wells (43.0 net) rig-released in 2023 are expected to be brought on production by the end of 2023 with one well expected in early 2024. |
Additional detail regarding our planned 2023 activity is as follows:
| • | Peace River: Continuing on the success of our development of the Bluesky formation, we plan to drill an additional 12 Bluesky wells (12.0 net) in 2023. Two wells (2.0 net) are exploration/appraisal wells planned for the first quarter of 2023 to delineate and further expand our Bluesky play. The first well on the Walrus 16-20 Pad was successfully rig-released in mid-January; it encountered excellent reservoir quality and is being brought on production. A second well is currently being drilled to further delineate the South Walrus area. This provides the opportunity for additional follow up locations in the area, including on land purchased in 2022. |
With approximately 500 sections of prospective Clearwater and Bluesky formation rights, Obsidian Energy plans exploration/appraisal drilling in both formations to further delineate the multizone heavy oil potential in the area. Spud in mid-December 2022, the Dawson Clearwater well (1.0 net) encountered good quality reservoir with oil quality of 12.4o API, providing key information for our 2023 program. The Company currently plans to drill four Clearwater wells (4.0 net) in 2023, following up on the information gained from our 2022 activity.
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| • | Willesden Green: We plan to drill 11 wells (11.0 net) targeting the Cardium formation in Willesden Green to follow up on the success of our 2022 program, which exceeded expectations and achieved notable top Alberta production rates at our 3-03 Pad and 4-17 Pad. Willesden Green continues to provide strong high quality economic results for the Company. |
In 2023, we will also focus on managing facility capacity from new production additions across our Cardium areas (Willesden Green and Pembina). At the same time, we will be utilizing existing pads to lower capital and help mitigate the impact of inflation and higher service costs.
| • | Pembina: In late December 2022, we brought on a strong three-well pad at Lodgepole in the Pembina area. We will continue our successful development in this area with eight wells (6.2 net) planned for 2023, including two low-cost Devonian vertical wells in the second half of the year on new land acquired in 2022. |
| • | Viking: Continuing the success of our re-entry into Viking in 2022, we plan to drill 11 wells (11.0 net) in the first half of 2023 prior to spring break-up. These wells will follow-up the 2022 step-out well that tested the western extent of the play and displayed strong production rates with a shallower decline, resulting in faster payouts and strong economic returns. The 2023 program will extend our Viking footprint to the west, offsetting the step-out well with a full development program and associated infrastructure. Future producing locations in the western portion of the field will be refined and developed as we incorporate the results of our early 2023 drilling program, which is expected to be brought on production towards the end of the first quarter. |
RETURN OF CAPITAL
Obsidian Energy is committed to returning capital to our shareholders. Execution of our corporate plans over the last several years and our 2023 guidance is expected to generate FCF and liquidity to allow us to achieve this goal. Based on our guidance, net debt to FFO is expected to be well below 1.0 times in 2023, and the strength of our 2022 Reserves Report and operations provides us the opportunity to further enhance our liquidity position.
Our Board of Directors have authorized a NCIB of up to 10 percent of our public float, which we are applying to the Toronto Stock Exchange (“TSX”) for approval. To enhance our liquidity, we are pursuing increasing our debt capacity, which will facilitate execution under a NCIB. Any NCIB purchases will be subject to the Company maintaining at least $65.0 million of liquidity and complying with the terms and positions of our current credit facilities. In addition, our July 2027 Senior Unsecured Notes (the “Notes”) have a provision whereby we are required to make an offer to noteholders to repurchase their Notes, subject to a cap of $63.8 million, based on the amount of excess FCF (calculated on a semi-annual basis) and the amount of liquidity available to the Company. Based off current strip pricing and our projected first half 2023 results, we expect that we would be able to make such an offer in addition to continuing to execute our NCIB. Further details regarding the NCIB will be provided when it has been approved by the TSX.
Considering the Company’s current production profile, our net debt target is $225 million, which we expect to achieve in the second half of 2023 based on our guidance (and subject to shares purchased under an NCIB). As we approach this debt level while maintaining our liquidity threshold, we will evaluate additional return of capital plans. The NCIB is initially being implemented as we believe the intrinsic value of our shares far exceeds our current trading price as evidenced, in part, by the net present value, before-tax, discounted at 10 percent (“NPV10”) of our 2022 PDP reserves less net debt (at September 30, 2022), which exceeds $15 per share.
2022 RESERVES REPORT
We are pleased to announce our independent reserves evaluation for the year ended December 31, 2022, prepared by GLJ Ltd. (“GLJ”).
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“The strength of the Company’s high-quality assets and successful 2022 capital program combined with improved pricing are shown in the results of our 2022 Reserves Report,” said Stephen Loukas. “The future price deck increased roughly 30 percent from year-end 2021, helping to mitigate the impact of inflation and rising expenses on finding and development costs. We also aligned our future development capital in our reserve book to reflect our expected future capital activity, increasing our five-year program to approximately $250 million per year. With the addition of over 80 new locations (primarily in the Cardium and Viking areas), we are well positioned to further enhance our reserve book through development and exploration/appraisal activities in 2023 as we further develop our strong land base.”
HIGHLIGHTS
With the largest development program undertaken in several years, Obsidian Energy drilled wells in all three core areas in 2022. Focused on delineating our substantial land position and expanding our opportunity base, we renewed activity in Viking and Peace River and increased our reserve base through extensions, step-out wells, and new exploration/appraisal drilling. We also increased our Peace River land position during the year, providing additional potential Bluesky locations to our portfolio. These activities, combined with significantly improved commodity price forecasts compared to 2021, had a significant impact on our reserve evaluation.
| • | Reserves NPV10 increased over 2021 levels as follows: |
| • | PDP: 38 percent increase to $1.6 billion. |
| • | 1P: 49 percent increase to $2.1 billion. |
| • | 2P: 54 percent increase to $2.8 billion. |
| • | We replaced 144 percent of 2022 production on a PDP basis, 214 percent on a 1P basis and 393 percent on a 2P basis. |
| • | Our drilling program combined with technical revisions generated reserves replacement of 2022 production of 113 percent for PDP, 177 percent for 1P and 347 percent for 2P, excluding the effects of acquisition and disposition activity and commodity price changes from year-end 2021. |
| • | Our optimization capital program continued to deliver strong results for the fourth year in a row, successfully adding 2.3 mmboe of PDP reserves through capital expenditures of $13.3 million, providing a compelling PDP reserve addition cost of $5.74 per boe. |
| • | Future development capital (“FDC”) was added to appropriately adjust the undeveloped reserves and generate a five-year program of approximately $250 million per year. |
| • | Finding and development (“F&D”) costs including changes in FDC were $20.48/boe for PDP, $26.88/boe for 1P and $19.21/boe for 2P. |
| • | Development and acquisition (“FD&A”) costs including changes in FDC were $20.53/boe (PDP), $26.63/boe (1P) and $19.06/boe (2P). |
| • | The strength and profitability of our assets was demonstrated through 2022 recycle ratios of 2.4x for PDP, 1.9x for 1P and 2.6x for 2P, based on our expected 2022 operating netback of $49.82/boe and F&D costs (including changes in FDC). |
| • | Our total undeveloped proved plus probable reserve locations increased by over 80 new net locations to 311 total net locations booked (including 236 net locations in the Cardium, 22 net locations in the Bluesky, 2 net locations in the Clearwater, 49 in the Viking, one Devonian and one Mannville). |
| • | These locations are booked with a highly achievable total FDC of $1,255 million (approximately $250 million per year). |
| • | Obsidian Energy maintains a strong reserve life index (“RLI”) of approximately 6.8, 9.9 and 13.3 years on a PDP, 1P, and 2P basis, respectively. |
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SUMMARY OF 2022 RESERVES
GLJ conducted an independent reserves evaluation of 100 percent of our reserves effective December 31, 2022, using a four-consultant average (“IC4”) of forecast commodity prices and assumptions at December 31, 2022. This evaluation was prepared in accordance with definitions, standards, and procedures set out in the Canadian Oil and gas Evaluation Handbook and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Reserves included below are company share gross reserves which are the Company’s total working interest reserves before the deduction of any royalties and excluding any royalty interests payable to the Company. The numbers in the tables below may not add due to rounding.
Summary of Reserves1
As at December 31, 2022
| Reserve Category |
Light & Medium Oil (mmbbl) |
Heavy Oil & Bitumen (mmbbl) |
Natural Gas Liquids (mmbbl) |
Conventional Natural Gas (bcf) |
Barrel of Oil Equivalent (mmboe) |
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| Proved |
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| Developed producing |
31.2 | 8.5 | 7.3 | 175.3 | 76.2 | |||||||||||||||
| Developed non-producing |
0.3 | — | 0.1 | 2.3 | 0.8 | |||||||||||||||
| Undeveloped |
25.1 | 1.8 | 4.7 | 107.4 | 49.5 | |||||||||||||||
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| Total Proved |
56.6 | 10.3 | 12.1 | 285.0 | 126.5 | |||||||||||||||
| Total Probable |
23.3 | 5.1 | 5.0 | 123.6 | 54.1 | |||||||||||||||
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| Total Proved plus Probable |
79.9 | 15.5 | 17.1 | 408.6 | 180.6 | |||||||||||||||
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| (1) | Reserves are shown on a gross working interest basis. |
Reserves Reconciliation – Total Proved
| Reconciliation Category |
Light & Medium Oil (mmbbl) |
Heavy Oil & Bitumen (mmbbl) |
Natural Gas Liquids (mmbbl) |
Conventional Natural Gas (bcf) |
Barrel of Oil Equivalent (mmboe) |
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| Total Proved |
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| December 31, 2021 |
55.4 | 11.3 | 9.6 | 224.4 | 113.7 | |||||||||||||||
| Discoveries |
— | — | — | — | — | |||||||||||||||
| Extensions |
7.3 | 1.0 | 1.8 | 47.4 | 18.0 | |||||||||||||||
| Infill Drilling |
0.5 | 0.3 | — | 1.2 | 1.1 | |||||||||||||||
| Improved Recovery |
0.2 | 0.1 | — | 0.2 | 0.3 | |||||||||||||||
| Technical Revisions |
(4.0 | ) | (0.8 | ) | 1.1 | 25.1 | 0.5 | |||||||||||||
| Acquisitions |
— | — | 0.1 | 2.0 | 0.4 | |||||||||||||||
| Dispositions |
(0.1 | ) | — | — | (0.4 | ) | (0.2 | ) | ||||||||||||
| Economic Factors |
1.5 | 0.7 | 0.3 | 8.4 | 4.0 | |||||||||||||||
| Production |
(4.3 | ) | (2.2 | ) | (0.9 | ) | (23.3 | ) | (11.2 | ) | ||||||||||
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| December 31, 2022 |
56.6 | 10.3 | 12.1 | 285.0 | 126.5 | |||||||||||||||
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Reserves Reconciliation – Total Proved Plus Probable
| Reconciliation Category |
Light & Medium Oil (mmbbl) |
Heavy Oil & Bitumen (mmbbl) |
Natural Gas Liquids (mmbbl) |
Conventional Natural Gas (bcf) |
Barrel of Oil Equivalent (mmboe) |
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| Total Proved Plus Probable |
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| December 31, 2021 |
69.5 | 15.8 | 12.8 | 297.5 | 147.8 | |||||||||||||||
| Discoveries |
— | — | — | — | — | |||||||||||||||
| Extensions |
14.1 | 2.1 | 2.5 | 70.4 | 30.4 | |||||||||||||||
| Infill Drilling |
2.4 | 0.4 | 0.2 | 5.4 | 3.9 | |||||||||||||||
| Improved Recovery |
0.3 | 0.1 | — | — | 0.3 | |||||||||||||||
| Technical Revisions |
(4.0 | ) | (1.4 | ) | 2.0 | 45.4 | 4.2 | |||||||||||||
| Acquisitions |
— | — | 0.1 | 2.8 | 0.6 | |||||||||||||||
| Dispositions |
(0.1 | ) | — | — | (0.5 | ) | (0.2 | ) | ||||||||||||
| Economic Factors |
1.9 | 0.6 | 0.4 | 10.8 | 4.8 | |||||||||||||||
| Production |
(4.3 | ) | (2.2 | ) | (0.9 | ) | (23.3 | ) | (11.2 | ) | ||||||||||
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| December 31, 2022 |
79.9 | 15.5 | 17.1 | 408.6 | 180.6 | |||||||||||||||
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Summary of Before Tax Net Present Values
As at December 31, 2022(1)
| Net Present Values | Discount Rate | |||||||||||||||||||
| $ millions |
Undiscounted | 5 Percent | 10 Percent | 15 Percent | 20 Percent | |||||||||||||||
| Proved |
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| Developed producing |
1,994 | 1,881 | 1,579 | 1,354 | 1,193 | |||||||||||||||
| Developed non-producing |
22 | 17 | 14 | 11 | 10 | |||||||||||||||
| Undeveloped |
1,321 | 828 | 549 | 379 | 267 | |||||||||||||||
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| Total Proved |
3,338 | 2,726 | 2,142 | 1,745 | 1,470 | |||||||||||||||
| Total Probable |
1,991 | 1,046 | 653 | 451 | 333 | |||||||||||||||
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| Total Proved plus Probable |
5,328 | 3,772 | 2,794 | 2,196 | 1,803 | |||||||||||||||
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| (1) | The December 31, 2022, reserve net present values include only active Obsidian Energy existing well, facility, and pipeline decommissioning liability estimates, which totals $28 million NPV10 (2021 - $22 million). |
Future Development Capital
As at December 31, 2022
| $ millions |
Total Proved | Total Proved Plus Probable |
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| 2023 |
173 | 202 | ||||||
| 2024 |
197 | 256 | ||||||
| 2025 |
245 | 261 | ||||||
| 2026 |
183 | 267 | ||||||
| 2027 |
173 | 260 | ||||||
| 2028 and subsequent |
9 | 9 | ||||||
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| Total, Undiscounted |
980 | 1,255 | ||||||
| Total, Discounted @ 10% |
769 | 979 | ||||||
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F&D and FD&A Costs
As at December 31, 2022
| ($ millions, except as noted) |
Proved Developed Producing |
Total Proved | Total Proved Plus Probable |
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| Exploration and development capital expenditures |
314.8 | 314.8 | 314.8 | |||||||||
| Total change in FDC |
11.3 | 324.1 | 523.5 | |||||||||
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| F&D capital, including total change in FDC |
326.1 | 639.0 | 838.3 | |||||||||
| Reserve additions, including revisions (mmboe) |
15.9 | 23.8 | 43.6 | |||||||||
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| F&D per boe |
20.48 | 26.88 | 19.21 | |||||||||
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| ($ millions, except as noted) |
Proved Developed Producing |
Total Proved | Total Proved Plus Probable |
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| F&D capital, including total change in FDC |
326.1 | 639.0 | 838.3 | |||||||||
| Acquisitions, net of dispositions |
4.6 | 4.6 | 4.6 | |||||||||
| Acquisitions, FDC |
— | — | — | |||||||||
| Dispositions, FDC |
— | (4.3 | ) | (4.3 | ) | |||||||
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| FD&A capital, including total change in FDC |
330.7 | 639.2 | 838.6 | |||||||||
| Reserve additions, including revisions and acquisitions (mmboe) |
16.1 | 24.0 | 44.0 | |||||||||
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| FD&A per boe |
20.53 | 26.63 | 19.06 | |||||||||
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| (1) | Capital expenditures are unaudited. |
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F&D Costs by Year
| ($/boe) |
2022 | 2021 | 2020 | 3-Year Average | ||||||||||||
| F&D costs, including total change in FDC1 |
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| Proved developed producing |
20.48 | 9.57 | 9.41 | 13.74 | ||||||||||||
| Total proved |
26.88 | 13.68 | 3.32 | 17.29 | ||||||||||||
| Total proved plus probable |
19.21 | 10.27 | 11.19 | 15.51 | ||||||||||||
| FD&A costs, including total change in FDC2 |
||||||||||||||||
| Proved developed producing |
20.53 | 9.07 | 9.77 | 13.70 | ||||||||||||
| Total proved |
26.63 | 12.87 | 3.39 | 16.63 | ||||||||||||
| Total proved plus probable |
19.06 | 9.62 | 11.50 | 14.84 | ||||||||||||
| (1) | The calculation of F&D includes the change in FDC and excludes the effects of acquisitions and depositions. |
| (2) | The calculation of FD&A includes the change in FDC and includes the effects of acquisitions and dispositions. |
Summary of Pricing and Inflation Rate Assumptions
As at December 31, 2022(1)
| IC4 Forecast(2) | WTI Cushing, Oklahoma ($US/bbl) |
Canadian Light Sweet Crude 40° API ($Cdn/bbl) |
Natural Gas AECO-C Spot ($Cdn/mmbtu) |
Exchange Rate ($US/$Cdn) |
||||||||||||||||||||||||||||
| Year |
2022 | 2021 | 2022 | 2021 | 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||||||
| Forecast |
||||||||||||||||||||||||||||||||
| 2023 |
80.25 | 67.91 | 103.16 | 79.36 | 4.44 | 3.22 | 0.74 | 0.80 | ||||||||||||||||||||||||
| 2024 |
78.19 | 65.42 | 97.34 | 76.07 | 4.54 | 3.07 | 0.76 | 0.80 | ||||||||||||||||||||||||
| 2025 |
76.10 | 66.72 | 94.21 | 77.59 | 4.37 | 3.14 | 0.76 | 0.80 | ||||||||||||||||||||||||
| 2026 |
76.96 | 68.05 | 94.90 | 79.13 | 4.44 | 3.20 | 0.77 | 0.80 | ||||||||||||||||||||||||
| 2027 |
78.50 | 69.42 | 96.48 | 80.73 | 4.52 | 3.26 | 0.77 | 0.80 | ||||||||||||||||||||||||
| 2028 |
80.07 | 70.81 | 98.41 | 82.33 | 4.61 | 3.34 | 0.77 | 0.80 | ||||||||||||||||||||||||
| 2029 |
81.67 | 72.22 | 100.38 | 83.98 | 4.70 | 3.40 | 0.77 | 0.80 | ||||||||||||||||||||||||
| 2030 |
83.31 | 73.67 | 102.38 | 85.66 | 4.79 | 3.46 | 0.77 | 0.80 | ||||||||||||||||||||||||
| 2031 |
84.97 | 75.14 | 104.43 | 87.37 | 4.88 | 3.54 | 0.77 | 0.80 | ||||||||||||||||||||||||
| 2032 |
86.68 | 76.64 | 106.16 | 89.12 | 4.98 | 3.60 | 0.77 | 0.80 | ||||||||||||||||||||||||
| 2033 |
88.40 | 108.28 | 5.08 | 0.77 | ||||||||||||||||||||||||||||
| (1) | Prices escalate at two percent after 2033, with the exception of foreign exchange which stays flat. |
| (2) | Pricing forecasts utilized IC4 pricing (GLJ, Sproule & Associates Ltd., McDaniel & Associates Consultants and Deloitte Resource Evaluation & Advisory). |
The financial and operating information in this news release is based on estimates and is unaudited. Some of the terms below do not have standardized meanings. Further detail can be found in the “Oil and Gas Advisory” section contained in this release. Additional reserve information as required under NI 51-101 will be included in our Annual Information Form as at December 31, 2022 which will be filed on SEDAR, EDGAR, and posted to our website once we file our year-end 2022 financial documents.
HEDGING UPDATE
The Company continues to focus our hedging program on near term WTI positions to protect cashflow given our first half capital program. As at January 27, 2023, the following financial oil and gas contracts are in place on a weighted average basis:
WTI Oil Contracts
| Type |
Remaining Term | Volume (bbl/d) |
Bought Put Price (C$/bbl) |
Sold Call Price (C$/bbl) |
Swap Price (C$/bbl) |
|||||||||||||||
| WTI Collar |
October 2022 | 10,000 | 109.75 | 130.07 | — | |||||||||||||||
| WTI Swap |
November 2022 | 1,950 | 123.97 | |||||||||||||||||
| WTI Collar |
November 2022 | 7,000 | 106.07 | 126.77 | — | |||||||||||||||
| WTI Collar |
December 2022 | 2,000 | 105.00 | 130.20 | — | |||||||||||||||
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AECO Natural Gas Contracts
| Type |
Remaining Term | Volume (mcf/d) |
Swap Price (C$/mmf) |
|||||||||
| AECO Swap |
October 2022 | 26,065 | 4.74 | |||||||||
| AECO Swap |
December 2022 – March 2023 | 14,976 | 6.18 | |||||||||
| AECO Swap |
April 2023 – October 2023 | 44,073 | 3.63 | |||||||||
2023 GUIDANCE RELEASE WEBCAST & UPDATED PRESENTATION
In association with this release, our Interim President and CEO, Mr. Stephen Loukas and other members of management will host a webcast presentation online on Tuesday, January 31, 2023, at 9:30 a.m. Mountain Standard Time (11:30 a.m. Eastern Standard Time) (the “Presentation”).
The Presentation will be broadcast live on the Internet and may be accessed either through our website or directly at the webcast portal. Those who wish to listen to the Presentation via phone should connect five to 10 minutes prior to the scheduled start time through the following numbers:
| Canada / USA: | 1-800-319-4610 (toll-free) | |
| Toronto: | 1-416-915-3239 | |
| Calgary: | 1-403-351-0324 | |
A question-and-answer session will be held following the Presentation. If you wish to submit a question to the Company, participants can do so ahead of time after registering on the webcast portal on the Intranet or by emailing questions to investor.relations@obsidianenergy.com. The updated Presentation will be available for replay following the webcast on our website, www.obsidianenergy.com.
FOURTH QUARTER AND FULL YEAR 2022 RESULTS RELEASE
We intend to release our fourth quarter and full year 2022 financial and operational results before North American markets open on February 23, 2023. In addition, the 2022 management’s discussion and analysis and the audited 2022 consolidated financial statements will be available on our website at www.obsidianenergy.com, on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov on or about the same date.
ADDITIONAL READER ADVISORIES
OIL AND GAS INFORMATION ADVISORY
This news release contains a number of oil and gas metrics, including “F&D costs”, “FD&A costs”, “Operating netback”, “Recycle Ratio” and “RLI” which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics are commonly used in the oil and gas industry and have been included herein to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods.
F&D costs are the sum of capital expenditures incurred in the period, plus the change in estimated future development capital for the reserves category, all divided by the change in reserves during the period for the reserve category. F&D costs exclude the impact of acquisitions and divestitures.
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FD&A costs are the sum of capital expenditures incurred in the period for the reserves category and including the impact of acquisition and disposition activity, all divided by the change in reserves during the period for the reserve category.
Operating netback is the per unit of production amount of revenue less royalties, net operating expenses and transportation expenses.
Recycle Ratio is calculated by dividing the operating netback by the F&D costs for the year. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves.
RLI is calculated as total Company gross reserves divided by GLJ’s forecasted 2023 production for the associated reserve category.
Under NI 51-101, proved reserves estimates are defined as having a high degree of certainty to be recoverable with a targeted 90 percent probability in aggregate that actual reserves recovered over time will equal or exceed proved reserve estimates. For proved plus probable reserves under NI 51-101, the targeted probability is an equal (50 percent) likelihood that the actual reserves to be recovered will be greater or less than the proved plus probable reserve estimate. The reserve estimates set forth above are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.
Barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil 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 equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value.
TEST RESULTS AND INITIAL PRODUCTION RATES
Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery. Readers are cautioned that short term rates should not be relied upon as indicators of future performance of these wells and therefore should not be relied upon for investment or other purposes. A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered preliminary until such analysis or interpretation has been completed.
ABBREVIATIONS
| Oil | Natural Gas | |||||
| API | American Petroleum Institute | AECO | Alberta benchmark price for natural gas | |||
| bbl | barrel or barrels | mcf | thousand cubic feet | |||
| bbl/d | barrels per day | mmcf | million cubic feet | |||
| boe | barrel of oil equivalent | bcf | billion cubic feet | |||
| boe/d | barrels of oil equivalent per day | mmcf/d | million cubic feet per day | |||
| MSW | Mixed Sweet Blend | NGL | natural gas liquids | |||
| mmbbls | million barrels | |||||
| mmboe | million barrels of oil equivalent | |||||
| WCS | Western Canada Select | |||||
| WTI | West Texas Intermediate | |||||
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NON-GAAP AND OTHER FINANCIAL MEASURES
Throughout this news release and in other materials disclosed by the Company, we employ certain measures to analyze financial performance, financial position, and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore may not be comparable to similar measures provided by other issuers. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income (loss) and cash flow from operating activities as indicators of our performance.
Non-GAAP Financial Measures
The following measures are non-GAAP financial measures: FFO; net debt; net operating costs; and FCF. These non-GAAP financial measures are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section “Non-GAAP and Other Financial Measures” in our MD&A for the three and nine months ended September 30, 2022, for an explanation of the composition of these measures, how these measures provide useful information to an investor, and the additional purposes, if any, for which management uses these measures.
Non-GAAP Ratios
The following measures are non-GAAP ratios: net debt to funds flow from operations, which uses net debt and funds flow from operations as a component; and net operating costs ($/boe), which uses net operating costs as a component. These non-GAAP ratios are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. See the disclosure under the section “Non-GAAP and Other Financial Measures” in our MD&A for the three and nine months ended September 30, 2022, for an explanation of the composition of these non-GAAP ratios, how these non-GAAP ratios provide useful information to an investor, and the additional purposes, if any, for which management uses these non-GAAP ratios.
Supplementary Financial Measures
The following measure is a supplementary financial measures: general and administrative costs ($/boe). See the disclosure under the section “Non-GAAP and Other Financial Measures” in our MD&A for the three and nine months ended September 30, 2022, for an explanation of the composition of this measure.
FUTURE-ORIENTED FINANCIAL INFORMATION
This release contains future-oriented financial information (“FOFI”) and financial outlook information relating to the Company’s prospective results of operations, operating costs, expenditures, production, FFO, adjusted FFO, FCF, net operating costs, and net debt, which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth below under “Forward-Looking Statements”. The Company’s actual results, performance or achievement could differ materially from those expressed in, or implied by, such FOFI, or if any of them do so, what benefits the Company will derive therefrom. The Company has included this FOFI to provide readers with a more complete perspective on the Company’s business as of the date hereof and such information may not be appropriate for other purposes.
FORWARD-LOOKING STATEMENTS
Certain statements contained in this document constitute forward-looking statements or information (collectively “forward-looking statements”) within the meaning of the “safe harbour” provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as “anticipate”, “continue”, “estimate”, “expect”, “forecast”, “budget”, “may”, “will”, “project”, “could”, “plan”, “intend”, “should”, “believe”, “outlook”, “objective”, “aim”, “potential”, “target” and similar words suggesting future events or future performance. In addition, statements relating to “reserves” or “resources” are deemed to be forward-looking statements as they involve the implied assessment, based on certain
11
estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this document contains forward-looking statements pertaining to, without limitation, the following: our 2023 capital plan and associated guidance including production and associated weighting, net operating costs, general & administrative costs, FFO, FCF (prior to NCIB), net debt (prior to NCIB) and net debt to FFO; our intentions regarding a NCIB and the belief that our shares our undervalued; our ability to deliver on production growth and FCF; our 2023 strategy in regard to development and exploration/appraisal capital, continued debt reduction and return of capital to shareholders while also preserving acquisition optionality; our expectations for drilling, locations and on production dates; our ability to optimize our program based on various results achieved; how we plan to lower capital and help mitigate the impact of inflation and higher service costs; our pursuit to increase our debt capacity and the impact that has on the NCIB, our belief in our ability to complete the NCIB and make an offer on the Notes if necessary, per the terms and conditions, based on certain underlying assumptions; our expected timing on certain debt targets; that we are well positioned to further develop our reserve book through development and exploration/appraisal activities in 2023; the hosting of the Presentation and subsequent posting on our website; that additional reserve information, as required under NI 51-101, will be included in our Annual Information Form which will be filed on SEDAR, EDGAR and our website on or about February 23, 2023; our expected RLIs; and our hedging program.
With respect to forward-looking statements contained in this document, the Company has made assumptions regarding, among other things: that the Company does not dispose of or acquire material producing properties or royalties or other interests therein other than stated herein (provided that, except where otherwise stated, the forward-looking statements contained herein do not assume the completion of any transaction); the impact of regional and/or global health related events, including the ongoing COVID-19 pandemic, on energy demand and commodity prices; that the Company’s operations and production will not be disrupted by circumstances attributable to the COVID-19 pandemic and the responses of governments and the public to the pandemic; global energy policies going forward, including the ability of members of OPEC, and other nations to agree on and adhere to production quotas from time to time; our ability to qualify for (or continue to qualify for) new or existing government programs created as a result of the COVID-19 pandemic (including the Alberta Site Rehabilitation Program) or otherwise, and obtain financial assistance therefrom, and the impact of those programs on our financial condition; our ability to execute our plans as described herein and in our other disclosure documents and the impact that the successful execution of such plans will have on our Company and our stakeholders; future capital expenditure and decommissioning expenditure levels; future operating costs and general & administrative costs; future crude oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil and natural gas prices; future hedging activities; future crude oil, natural gas liquids and natural gas production levels; future exchange rates, inflation rates and interest rates; future debt levels; our ability to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including extreme weather events, such as wild fires and flooding, infrastructure access and delays in obtaining regulatory approvals and third party consents; our ability to obtain equipment in a timely manner to carry out development activities and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; our ability to obtain financing on acceptable terms, including our ability (if necessary) to continue to extend the revolving period and term out period of our credit facility, our ability to maintain the existing borrowing base under our credit facility, our ability (if necessary) to replace our syndicated bank facility and our ability (if necessary) to finance the repayment of our Notes on maturity; and our ability to add production and reserves through our development and exploration/appraisal activities.
Although the Company believes that the expectations reflected in the forward-looking statements contained in this document, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the forward-looking statements contained herein will not be correct, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: the possibility that we change our 2023 capital plans in response to internal and external factors, including
12
those described herein; the possibility that the Company will not be able to continue to successfully execute our business plans and strategies in part or in full, and the possibility that some or all of the benefits that the Company anticipates will accrue to our Company and our stakeholders as a result of the successful execution of such plans and strategies do not materialize; the possibility that the Company is unable to complete one or more of the potential transactions being pursued, on favorable terms or at all; the possibility that the Company ceases to qualify for, or does not qualify for, one or more existing or new government assistance programs implemented in connection with the COVID-19 pandemic and other regional and/or global health related events or otherwise, that the impact of such programs falls below our expectations, that the benefits under one or more of such programs is decreased, or that one or more of such programs is discontinued; the impact on energy demand and commodity prices of regional and/or global health related events, including the ongoing COVID-19 pandemic, and the responses of governments and the public to the pandemic, including the risk that the amount of energy demand destruction and/or the length of the decreased demand exceeds our expectations; the risk that there is another significant decrease in the valuation of oil and natural gas companies and their securities and in confidence in the oil and natural gas industry generally, whether caused by a resurgence of the COVID-19 pandemic, the worldwide transition towards less reliance on fossil fuels and/or other factors; the risk that the COVID-19 and/or other pandemics adversely affects the financial capacity of the Company’s contractual counterparties and potentially their ability to perform their contractual obligations; the possibility that the revolving period and/or term out period of our credit facility and the maturity date of our Notes is not further extended (if necessary), that the borrowing base under our credit facility is reduced, that the Company is unable to renew or refinance our credit facilities on acceptable terms or at all and/or finance the repayment of our Notes when they mature on acceptable terms or at all and/or obtain debt and/or equity financing to replace one or all of our credit facilities and Notes; the possibility that we breach one or more of the financial covenants pursuant to our agreements with our lenders and the holders of our Notes; the possibility that we are forced to shut-in production, whether due to commodity prices decreasing, extreme weather events or other factors; the risk that OPEC and other nations fail to agree on and/or adhere to production quotas from time to time that are sufficient to balance supply and demand fundamentals for crude oil; general economic and political conditions in Canada, the U.S. and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; industry conditions, including fluctuations in the price of crude oil, natural gas liquids and natural gas, price differentials for crude oil and natural gas produced in Canada as compared to other markets, and transportation restrictions, including pipeline and railway capacity constraints; fluctuations in foreign exchange or interest rates; the risk that our costs increase significantly due to inflation, supply chain disruptions and/or other factors, adversely affecting our profitability; unanticipated operating events or environmental events that can reduce production or cause production to be shut-in or delayed (including extreme cold during winter months, wild fires and flooding); the risk that wars and other armed conflicts adversely affect world economies and the demand for oil and natural gas, including the ongoing war between Russia and Ukraine; the possibility that fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to hydrocarbons and technological advances in fuel economy and renewable energy generation systems could permanently reduce the demand for oil and natural gas and/or permanently impair the Company’s ability to obtain financing on acceptable terms or at all, and the possibility that some or all of these risks are heightened as a result of the response of governments and consumers to the ongoing COVID-19 pandemic and/or public opinion and/or special interest groups. Additional information on these and other factors that could affect Obsidian Energy, or its operations or financial results, are included in the Company’s Annual Information Form (See “Risk Factors” and “Forward-Looking Statements” therein) which may be accessed through the SEDAR website (www.sedar.com), EDGAR website (www.sec.gov) or Obsidian Energy’s website. Readers are cautioned that this list of risk factors should not be construed as exhaustive.
Unless otherwise specified, the forward-looking statements contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update or revise any forward-looking statements. The forward-looking statements contained in this document are expressly qualified by this cautionary statement.
Obsidian Energy shares are listed on both the Toronto Stock Exchange in Canada and the NYSE American in the United States under the symbol “OBE”.
All figures are in Canadian dollars unless otherwise stated.
13
CONTACT
OBSIDIAN ENERGY
Suite 200, 207 - 9th Avenue SW, Calgary, Alberta T2P 1K3
Phone: 403-777-2500
Toll Free: 1-866-693-2707
Website: www.obsidianenergy.com;
Investor Relations:
Toll Free: 1-888-770-2633
E-mail: investor.relations@obsidianenergy.com
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