• Increased August average production to ~40,000 boe/d (based on internal field estimates)
• Grew Peace River total average production to ~11,500 boe/d, which included ~3,800 boe/d of Clearwater production (based on internal field estimates)
• Revised 2024 guidance range upwardly to reflect higher production midpoint
Calgary, Alberta--(Newsfile Corp. - September 9, 2024) - OBSIDIAN ENERGY LTD. (TSX: OBE) (NYSE American: OBE) ("Obsidian Energy", the "Company", "we", "us" or "our") is pleased to provide an operational update that includes strong drilling results from our current development program that, in aggregate, exceed our initial expectations, driving an associated increase in the bottom-end and midpoint of our 2024 production guidance. With four rigs currently active (three in the Peace River area), we have rig released 14 (14.0 net) operated wells and placed 10 (10.0 net) operated wells on production since the end of June. Based on internal field estimates, July and August average production increased to over 38,500 and ~40,000 boe/d, respectively, of which our Peace River area comprised over 10,300 boe/d in July and ~11,500 boe/d in August. As a result, we have revised our 2024 production guidance range to 36,400 to 37,000 boe/d (midpoint of 36,700 boe/d) with associated adjustments to our funds flow from operations ("FFO") and free cash flow ("FCF").
"We are highly pleased with our operational and financial performance in 2024, driven by the continued strength in our light oil business and strong growth within our Peace River heavy oil asset base," said Stephen Loukas, Obsidian Energy's President and CEO. "We are excited to continue the further delineation at Peace River over the next two quarters, including the drilling of our initial wells within our recent Peavine and Gift Lake land acquisition. As we approach completion of the first year of our three-year growth plan, we are well on track to meet our stated 50,000 boe/d production target during the spring of 2026. However, given the recent market volatility, broadened macroeconomic concerns, and significant discount between our current share price versus intrinsic value, we are prepared to optimize our 2025 capital plan as needed to maximize shareholder value."
HEAVY OIL ASSETS (PEACE RIVER)
Our Peace River team has been extremely active during the third quarter of 2024 with three rigs currently in operation in our second half capital program and two more expected late in the fourth quarter 2024 or in early 2025. Our Dawson Clearwater development field program is producing at higher rates than expected, and we have successfully tested new drilling and facility designs in our Bluesky Harmon Valley South ("HVS") and Walrus fields. Highlights of our program and second half 2024 drilling are outlined below by targeted formation and field.
Clearwater Formation
Our second half 2024 development and exploration/appraisal programs are well underway at Dawson and West Dawson with four (4.0 net) of the nine (9.0 net) wells spud on production. Development activity will continue throughout the second half at Dawson as well at on our recently acquired Peavine and Gift Lake lands.
Dawson: Our Dawson Clearwater field averaged ~2,400 boe/d (100 percent oil) during the month of August (based on internal field estimates) as new production was brought online. Better than forecasted results at Dawson allowed a faster pace of development than anticipated, which the Company intends to continue into 2025.
One (1.0 net) well at the 13-23 Pad was rig released and produced at average initial production ("IP") 30-day rate of 299 boe/d (100 percent oil).
The two (2.0 net) wells at the 12-33 Pad were rig released by the end of August and placed on production on September 7.
In addition, the three well (3.0 net) 13-13 Pad rig released in our first half development program produced at a gross average IP 30-day rate of 306 boe/d (100 percent oil) per well.
West Dawson - We commenced drilling our two (2.0 net) appraisal wells at the Dawson 9-21 Pad in August. These wells are a step-out to our current producing Dawson development field; results from these wells will provide key information to evaluate the potential western extension of the Clearwater formation trend at Dawson. We are currently drilling the second pad well after rig releasing the first well; the two wells are expected to go on production in late September.
Peavine and Gift Lake - Our Peace River team is preparing to begin drilling our first Clearwater development well in Peavine later in September with further exploration/appraisal drilling locations planned at both Gift Lake and Peavine in late 2024 and early 2025.
Bluesky Formation
We have begun drilling our second half 2024 Bluesky development program in the HVS, Walrus and Cadotte fields.
Harmon Valley South:
We rig released one of the three (3.0 net) wells planned for the second half at the 13-08 Pad in late July, located in the northern part of HVS. Placed on production in early August, the well produced above our expectations at an average IP 26-day rate of 453 boe/d (100 percent oil).
The one (1.0 net) well at the 13-18 Pad was drilled, rig released and placed on production in late August and is currently cleaning up.
The first (1.0 net) second half well of the four-well 8-28 Pad was rig released in early September, following up on the success of the two first half 2024 wells. We are presently drilling the fourth well on this pad.
Walrus:
Obsidian Energy continues to develop and further appraise our new Walrus field, drilling 14 (14.0 net) wells in total to date (including our first successful 2023 production test well from the presently shut-in winter access well in North Walrus). Two (2.0 net) wells from the second half 2024 program were drilled from new future multi-well pads at the 6-20 and 7-21 locations, have been recently brought online and are currently in the clean-up process.
Our recent activity in South Walrus focused on delineating both the upper and lower zone of the play. High-quality reservoir was encountered in 11 out of the 13 wells drilled with some variability in production performance. As incremental reservoir information is gathered, we continue to refine the technical mapping of our Walrus area through the results of our drilling program, including from recent whipstock exploration/appraisal wells and seismic integration. Follow-up drilling will capitalize on this knowledge, providing the ability to better delineate the thickest pay and more productive areas of the field as we drill multiple follow-up locations from existing and new future pads.
Initial well performance is strongly correlated to the ability to optimize wellbore drawdown to maximize fluid mobility. The total fluid production at Walrus is consistent with established Bluesky reservoirs in the Peace River oil sands region, which exhibit a higher water cut (~50 percent) and shallower decline. Our IP 30-day rates are slightly behind original expectations, but we expect similar or higher final reserve recoveries as the wells are performing better in aggregate over time with a shallower decline.
Of note, our first half 2024 six-well (6.0 net) 15-19 Pad's initial IP rates were impacted by facility capacity constraints due to accelerated construction and spring breakup conditions. However, the pad produced at a consistent rate with a 3-month average of ~590 boe/d (100 percent oil) with little or no decline since June.
To facilitate accelerated initial oil production response times, the two recent 6-20 and 7-21 Pad wells were equipped with additional surface facility tanks to accommodate increased total fluid production. Initial results are highly encouraging with the 6-20 Pad well producing at an IP 21-day rate of 197 boe/d (100 percent oil). After installing the additional tanks, the 6-20 Pad well production began increasing rapidly and has averaged ~400 boe/d (100 percent oil) for the week ending September 6.
As we continue to build our field development at Walrus, we observed that well placement, increased early life fluid handling capacity and the ability to manage ongoing higher water volumes are critical components in developing this field.
In the fourth quarter of 2024, the four-well 15-01 Pad will be equipped with increased fluid handling facilities at the start of production.
Cadotte:
Following up on success in 2023, Obsidian Energy released the first of three (3.0 net) wells targeting the Bluesky formation at the Cadotte 13-15 Pad with production expected onstream in the fourth quarter. The results from these development wells will be used to further delineate and unlock future potential in the Cadotte area.
LIGHT OIL ASSETS
We commenced our second half 2024 light oil capital program with one drilling rig active across Pembina and Willesden Green, and a second rig anticipated to start-up in October 2024. Status of our second half program to date were as follows:
Pembina (Cardium): Our second half 2024 Pembina program is well underway with four (4.0 net) of the seven (6.9 net) wells in the process of drilling and being brought on production in July and August:
The two (2.0 net) wells at the 16-36 Pad were drilled, rig released and brought on production in late August and are in the process of cleaning up. The gross average IP 10-day rates were 420 boe/d (89 percent oil) per well.
The two (2.0 net) wells at the 8-01 Pad were drilled and rig released in late August; they are anticipated to be brought on production in early October.
The remaining three (2.9 net) wells in our second half program are licensed and ready to be drilled later in the year.
Obsidian Energy participated in the 11 (4.9 net) well program, which includes two (0.9 net) injection wells, in the non-operated Pembina Cardium Unit 11 (45 percent working interest). Following up on the strong production additions in 2023 from this area, all 2024 wells have been rig released and are on production. Results to date have been highly encouraging with seven of the nine producing wells achieving a gross IP 30-day rate of 359 boe/d; the remaining two wells have recently been brought online.
Willesden Green (Cardium):
The Crimson 8-09 Pad (1.0 net) well produced at an IP 30-day rate of 110 boe/d (84 percent light oil); rates continue to increase as the well cleans up with an IP 60-day rate of 140 boe/d (77 percent light oil).
The first well in our second half Willesden Green four-well program is expected to be spud in October after the rig completes its activities in the Pembina area.
- Viking: Optimization work at our Viking field partially offset production declines over 2024, maintaining current production levels over 2,300 boe/d.
REVISED 2024 GUIDANCE
We have revised our 2024 guidance with annual production expected to range from 36,400 to 37,000 with a midpoint of 36,700 boe/d - a 14 percent increase from 32,275 boe/d in 2023. Our FFO is increased by $10 million to $415 million, resulting in a 2024 net debt to FFO of approximately 1.0 times, with a related increase to FCF by approximately $5 million to $52 million, while maintaining our WTI forecast of US$75/bbl for 2024. Our revised 2024 guidance incorporates our second quarter results and key assumptions used by the Company, is as follows:
| 2024 Guidance | Revised 2024 Guidance | |||
| Production1 | boe/d | 35,650 - 37,150 | 36,400 - 37,000 | |
| % Oil and NGLs | % | 69% | 69% | |
| Capital expenditures2 | $ millions | 330 - 340 | 335 - 345 | |
| Acquisition3 Decommissioning expenditures | $ millions $ millions | 79 23 - 24 | 85 23 - 24 | |
| Net operating costs | $/boe | 13.75 - 14.25 | 13.75 - 14.25 | |
| General & administrative | $/boe | 1.60 - 1.70 | 1.55 - 1.65 | |
| Based on midpoint of above guidance | ||||
| WTI4 | US$/bbl | 75.00 | 75.00 | |
| MSW Differential4 | US$/bbl | 3.00 | 3.50 | |
| WCS Differential4 AECO4 | US$/bbl CAD$/GJ | 15.00 2.25 | 15.00 1.50 | |
| FFO2, 5 | $ millions | 405 | 415 | |
| FFO/share6 | $/share | 5.29 | 5.44 | |
| FCF | $ millions | 47 | 52 | |
| FCF/share6 | $/share | 0.61 | 0.68 | |
| Net debt (prior to NCIB)7 | $ millions | 395 | 400 | |
| Net debt (prior to NCIB) to FFO7 | times | 1.0 | 1.0 | |
Approximate mid-point of 2024 Guidance range: 13,200 bbl/d light oil, 9,000 bbl/d heavy oil, 2,800 bbl/d NGLs and 68.4 mmcf/d natural gas with a minimal amount of forecasted production associated with exploration/appraisal capital expenditures.
Approximate mid-point of Revised 2024 Guidance range: 13,400 bbl/d light oil, 8,700 bbl/d heavy oil, 3,000 bbl/d NGLs and 69.6 mmcf/d natural gas with a minimal amount of forecasted production associated with exploration/appraisal capital expenditures. Revised production guidance reflects the impact of accelerated drilling at both our Peace River Bluesky and Clearwater development fields during the second quarter and higher than anticipated IP rates from new wells.Capital expenditures include approximately $21 million for exploration/appraisal activity with minimal impact on forecasted production volumes.
Acquisition expenditures include $80.5 million for the Peace River Clearwater acquisition and $4 million for other minor acquisitions completed to date in 2024.
WTI and AECO pricing assumptions of 2024 Guidance were forecasted for June to December 31, 2024, while MSW and WCS differentials were forecasted for July to December 2024. Revised pricing assumptions included risk management (hedging) adjustments as of May 27, 2024. Full year pricing assumptions, including actuals realized thus far, resulted in WTI of US$76.53/bbl, MSW differentials of US$4.57/bbl, WCS differentials of US$15.75/bbl, AECO of $2.20/mcf, and FX of 1.35x CAD/USD.
WTI and AECO pricing assumptions of Revised 2024 Guidance are forecasted for September to December 31, 2024, while MSW and WCS differentials are forecasted for October to December 2024. Pricing assumptions include risk management (hedging) adjustments as of September 4, 2024. Full year pricing assumptions, including actuals realized from January 1, 2024, to August 28, 2024, result in WTI of US$77.36/bbl, MSW differentials of US$4.77/bbl, WCS differentials of US$15.36/bbl, AECO of $1.45/GJ, and FX of 1.36x CAD/USD.2024 Guidance FFO and FCF included approximately $9.6 million of estimated charges for full year 2024 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 $10.82 per share.
Revised 2024 Guidance FFO and FCF includes approximately $4.9 million of estimated charges for full year 2024 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 $9.27 per share.Per share calculations are based on an estimated 77.6 million and 76.3 million shares outstanding for the 12-months ended December 31, 2024, for 2024 Guidance and Revised 2024 Guidance, respectively.
Net debt figures estimated as at December 31, 2024. Revised 2024 Guidance includes the impact of approximately $26.2 million of share purchases to September 6, 2024, under the Company's normal course issuer bid ("NCIB") program in connection repurchasing shares.
| Guidance Sensitivity Table | ||
| Variable (September/October1 to December) | Range | Change in 2024 FFO ($ millions) |
| WTI (US$/bbl) | +/- $1.00/bbl | 3.8 |
| MSW light oil differential (US$/bbl) | +/- $1.00/bbl | 2.4 |
| WCS heavy oil differential (US$/bbl) | +/- $1.00/bbl | 1.4 |
| Change in AECO ($/GJ) | +/- $0.25/GJ | 0.8 |
- WTI and AECO pricing assumptions of Revised 2024 Guidance are forecasted for September to December 31, 2024, while MSW and WCS differentials are forecasted for October to December 2024.
HEDGING UPDATE
The following contracts were in place in August or are currently in place on a weighted average basis:
Oil Contracts
| Type | Remaining Term | Volume (bbl/d) | Swap Price ($/bbl) |
| WCS Differential | January - December 2025 | 2,500 | ($20.15) |
AECO Natural Gas Contracts
| Type | Remaining Term | Volume (mcf/d) | Percentage Hedged1 | Swap Price ($/mcf) |
| AECO Swap | September - October 2024 | 43,365 | 62% | $2.52 |
| AECO Swap | November 2024 - March 2025 | 14,929 | 22% | $3.74 |
| AECO Collars | November 2024 - March 2025 | 4,976 | 7% | $3.43 - $4.11 |
- Based on 2024E natural gas production of 69.6 mmcf/d.
Electricity Contracts
| Type | Remaining Term | Volume (MWh/d) | Swap Price ($/MWh) |
| Power Swaps | September - December 2024 | 144 MWh/d | $92.83 |
UPDATED CORPORATE PRESENTATION
In association with this release, Obsidian Energy will post an updated corporate presentation in due course on our website.
PETERS & CO. LIMITED CONFERENCE AND UPDATED CORPORATE PRESENTATION
Obsidian Energy will be participating in the 28th Annual Peters & Co. Limited Annual Energy Conference (the "Conference") from Tuesday, September 10 to Thursday, September 12, 2024 in Toronto, Ontario at the Ritz-Carlton Hotel. Stephen Loukas, President and CEO will discuss the Company in a presentation at 9:00 a.m. ET (7:00 a.m. MT) on Tuesday, September 10, 2024. Mr. Loukas along with Peter Scott, Senior Vice President and Chief Financial Officer, will also be hosting one-on-one meetings at the Conference.
ADDITIONAL READER ADVISORIES
OIL AND GAS INFORMATION ADVISORY
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.
DRILLING LOCATIONS
This news release discloses drilling locations or inventory. Unbooked drilling locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources.
Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that we will drill all unbooked locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves or production.
ABBREVIATIONS
| Oil | Natural Gas | |||
| bbl | barrel or barrels | AECO | Alberta benchmark price for natural gas | |
| bbl/d | barrels per day | GJ | gigajoule | |
| boe | barrel of oil equivalent | mcf | thousand cubic feet | |
| boe/d | barrels of oil equivalent per day | mcf/d | thousand cubic feet per day | |
| MSW | Mixed Sweet Blend | mmcf/d | million cubic feet per day | |
| WTI | West Texas Intermediate | |||
| WCS | Western Canadian Select | Electricity | ||
| MWh | Megawatt hour | |||
| MWh/d | Megawatt hour per day | |||
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 and cash flow from operating activities as indicators of our performance. The Company's unaudited consolidated financial statements and MD&A as at and for the three and six months ended June 30, 2024 are available on the Company's website at www.obsidianenergy.com and under our SEDAR+ profile at www.sedarplus.ca and EDGAR profile at www.sec.gov. The disclosure under the section "Non-GAAP and Other Financial Measures" in the MD&A is incorporated by reference into this news release.
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 six months ended June 30, 2024, 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: FFO (basic per share ($/share)), which use FFO as a component; FCF (basic per share ($/share)), which use FCF as a component; net operating costs ($/boe), which uses net operating costs as a component; and net debt to funds flow from operations, which uses net debt and funds flow from operations 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 six months ended June 30, 2024, 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 measure: 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 six months ended June 30, 2024, for an explanation of the composition of this measure.
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 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: how we are prepared to optimize our 2025 capital plan to maximize shareholder value; our Revised guidance for 2024 production (including mixture and growth), debt levels, capital and decommissioning expenditures, acquisition expenses, net operating costs, general & administrative costs, FFO and FFO/share, FCF and FCF/share, Net debt and Net debt to FFO (prior to NCIB); our expected sensitivities to changes in WTI, MSW, AECO and WCS; that we are continuing to define new areas for future development; our anticipating timing for and number of drill rigs and the expectations those have on our plans and development for 2025; when we expect to announce our 2025 guidance and update our multi-year corporate plan; our development program for the rest of 2024 and early 2025 and the expected associated locations; our expectations for certain step-out wells and capitalizing on follow-up drilling; expected drilling, rig-release, spud and on-production dates; our expectations for reserve recoveries; how we can better optimize well production and anticipate estimate well volume recoveries; how we can use development wells to further delineate and unlock future potential results in certain areas; our hedges; our expectations for an updated corporate presentation; and our attendance at the Conference.
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); that regional and/or global health related events (such as the COVID-19 pandemic) will not have any adverse impact on energy demand and commodity prices in the future; global energy policies going forward, including the continued ability of members of OPEC, Russia 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 or otherwise, and obtain financial assistance therefrom, and the impact of those programs on our financial condition; Obsidian Energy's views with respect to its financial condition and prospects, the stability of general economic and market conditions, currency exchange rates and interest rates, and our ability to comply with applicable terms and conditions under the Company's debt agreements, the existence of alternative uses for Obsidian Energy's cash resources and compliance with applicable laws; our ability to execute our plans as described herein and in our other disclosure documents, including our three-year growth plan, 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 net operating costs and G&A 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, including that we will not be required to shut-in production due to low commodity prices or the further deterioration of commodity prices or inability to access our properties due to blockades or other activism; future exchange 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, wild fires, 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 senior unsecured notes on maturity or pursuant to the terms of the underlying agreement; and our ability to add production and reserves through our development and exploitation 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: Obsidian Energy's future capital requirements; general economic and market conditions; demand for Obsidian Energy's products; and unforeseen legal or regulatory developments and other risk factors detailed from time to time in Obsidian Energy reports filed with the Canadian securities regulatory authorities and the United States Securities and Exchange Commission; the possibility that we change our budget in response to internal and external factors, including 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 (including our three-year growth plan), 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 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, and the responses of governments and the public to any 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 the decrease 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 financial capacity of the Company's contractual counterparties is adversely affected 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 senior unsecured 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 senior unsecured notes when they mature on acceptable terms or at all and/or obtain new debt and/or equity financing to replace one or all of our credit facilities and senior unsecured 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 senior unsecured notes; the possibility that we are unable to complete the Offer with our noteholders; the possibility that we are forced to shut-in production, whether due to commodity prices failing to rise 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; 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 Russian and Ukraine and/or hostilities in the Middle East; 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; 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 and hot during the spring and summer months, wild fires and flooding); 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 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.sedarplus.ca), 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.
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
To view the source version of this press release, please visit https://www.newsfilecorp.com/release/222631
SOURCE: Obsidian Energy Ltd.
