Obsidian Energy Announces Third Quarter Results with Continued Increasing Funds Flow from Operations

  • Successful drilling results to date in the second half 2021 drilling program
  • Continued debt pay down and higher funds flow from operations
  • Acquisition of remaining Peace River Oil Partnership ownership subsequent to the quarter

Calgary, Alberta–(Newsfile Corp. – November 8, 2021) – OBSIDIAN ENERGY LTD. (TSX: OBE) (OTCQX: OBELF) (“Obsidian Energy“, the “Company“, “we“, “us” or “our“) is pleased to report strong operating and financial results for the third quarter 2021.

    Three Months Ended
September 30
    Nine Months Ended
September 30
    2021     2020     2021     2020  
(millions, except per share amounts)
Cash flow from operations   65.5     34.8     135.8     68.3  
Basic per share ($/share)   0.88     0.47     1.83     0.93  
Diluted per share ($/share)   0.85     0.47     1.78     0.93  
Funds flow from operations1   59.3     30.4     137.9     91.4  
Basic per share ($/share)1   0.79     0.41     1.86     1.25  
Diluted per share ($/share)1   0.77     0.41     1.81     1.25  
Net income (loss)   46.6     (3.2 )   392.3     (771.9 )
Basic per share ($/share)   0.62     (0.04 )   5.28     (10.55 )
Diluted per share ($/share)   0.60     (0.04 )   5.14     (10.55 )
Capital expenditures   45.1     4.6     96.1     45.6  
Decommissioning expenditures   1.6     0.6     5.4     8.8  
Net debt1   428.1     478.9     428.1     478.9  
Daily Production                        
Light oil (bbl/d)   10,314     10,952     10,389     12,084  
Heavy oil (bbl/d)   2,688     2,823     2,712     2,811  
NGL (bbl/d)   2,213     2,244     2,144     2,254  
Natural gas (mmcf/d)   54     54     53     53  
Total production2 (boe/d)   24,164     25,031     24,017     25,995  
Average sales price3                        
Light oil ($/bbl)   84.27     50.84     76.35     43.14  
Heavy oil ($/bbl)   60.87     29.54     49.94     19.99  
NGL ($/bbl)   52.79     22.11     43.64     18.73  
Natural gas ($/mcf)   3.89     2.40     3.44     2.25  
Netback1 ($/boe)                        
Sales price   56.21     32.74     50.11     28.43  
Risk management gain (loss)   (0.93 )   (0.42 )   (1.27 )   2.98  
Net sales price   55.28     32.32     48.84     31.41  
Royalties   (5.99 )   (1.42 )   (4.56 )   (1.48 )
Net operating expenses1   (13.28 )   (11.36 )   (13.50 )   (10.65 )
Transportation   (2.41 )   (2.13 )   (2.05 )   (2.01 )
Netback1($/boe)   33.60     17.41     28.73     17.27  


(1) The terms funds flow from operations (“FFO“) and their applicable per share amounts, “net debt”, “netback” and “net operating costs” are non-GAAP measures. Please refer to the “Non-GAAP Measures” advisory section below for further details.
(2) Please refer to the “Oil and Gas Information Advisory” section below for information regarding the term “boe”.
(3) Before risk management gains/(losses).

OBE Announces Q3 2021 Results

Detailed information can be found in Obsidian Energy’s unaudited interim consolidated financial statements and management’s discussion and analysis (“MD&A“) as at and for the three and nine months ended September 30, 2021 on our website at www.obsidianenergy.com, which will be filed on SEDAR and EDGAR in due course.


We benefitted from favourable commodity prices in the third quarter, resulting in FFO, free cash flow generation and further debt reduction. Production levels continued to be strong, supported by a combination of our 2021 development program results and continued outperformance of our base production. Our development program was extremely active with 11 operated wells (10.2 net) rig released during the period, the majority of which were brought on production in October.

2021 Third Quarter Financial Highlights

  • Strong Funds Flow – FFO was $59.3 million ($0.79 per share) for the third quarter of 2021, an increase from the second quarter of 2021 ($42.3 million; $0.57 per share) and the third quarter of 2020 ($30.4 million; $0.41 per share). Higher commodity prices and continued strong production performance drove the increase.

  • Capital Development Program Growth – We entered the third quarter with momentum with our capital expenditures totalling $45.1 million (2020: $4.6 million) over the quarter. Our development activities were predominately focused on the Cardium formation in the Willesden Green and Pembina areas with 11 wells (10.2 net) rig released and three wells (3.0 net) on production during the quarter.

  • Continued Debt Reduction – Continued strong free cash flow generation resulted in a decrease in net debt to $428.1 million as at September 30, 2021, compared to $478.9 million at September 30, 2020. This included $340.0 million drawn on our syndicated credit facility (down from $395.0 million as at September 30, 2020), $58.9 million of senior notes and $29.2 million of a working capital deficiency.

  • Solid G&A Costs – Third quarter 2021 general and administrative (“G&A“) costs were $1.82 per boe compared to $1.40 per boe in 2020. Lower production volumes in 2021 combined with several temporary measures taken in 2020 in response to the low commodity price environment reduced costs in the comparable period in 2020.

  • Maintained Operating Costs – Net operating costs of $13.28 per boe were lower than the second quarter of 2021 ($13.71 per boe) but higher than the third quarter of 2020 ($11.36 per boe). Similar to G&A, operating costs reflect the return to normal activity levels in 2021 compared to 2020, where the Company restricted discretionary spending and shut-in production due to the low commodity price environment.

  • Higher Net Income – Net income of $46.6 million ($0.62 per share) in the third quarter of 2021 benefitted from higher FFO and a net impairment reversal of $22.3 million. This compared to a net loss of $3.2 million ($0.04 per share) in 2020, largely due to the lower commodity price environment at that time.

2021 Third Quarter Operational Highlights

  • Increased Production Guidance – Continued strong performance from our base volumes and new well additions over 2021 resulted in average production of 24,164 boe/d in the third quarter of 2021. With two drilling rigs active in our Cardium assets, we brought three new wells on production in September, and expect to bring an additional 14 (13.0 net) wells on production in the fourth quarter and 13 (12.6 net) wells in the first quarter of 2022. Based on these results, we recently increased our full-year 2021 production guidance to between 24,300 and 24,500 boe/d, prior to the Peace River Oil Partnership (“PROP“) acquisition.

  • Return to Peace River Area – The Company resumed development drilling in our Peace River asset in conjunction with our recent proposed acquisition (see “Highlights Subsequent to the Quarter”) combined with the strong commodity price environment. Four infill development wells are planned for the fourth quarter, which are expected to be on stream by the end of January 2022.

  • Accelerated 2022 Development Program – The early start to our second half 2021 development program in June allowed the Company to accelerate our 2022 development program with the planned acceleration of three Cardium (2.8 net) wells into December 2021. Our 2022 program will benefit by maintaining access to the drilling rigs, minimizing mobilization costs and continuing drilling into 2022.

  • Reduction in Decommissioning Liabilities – A total of 80 net wells and 27 net kilometres of pipeline was abandoned during the third quarter of 2021 through participation in the Area Based Closure (“ABC“) program and the Alberta Site Rehabilitation Program (“ASRP“). We spent $1.6 million and utilized $2.9 million of net grants in the third quarter.

Production Volumes by Product and Producing Region
Three Months Ended September 30, 2021
Area   Production
    Light Oil
    Heavy Oil
Cardium   19,807     9,988     60     2,127     46  
Viking   822     177     122     49     3  
Peace River   2,974         2,449     2     3  
Key Development Areas   23,603     10,165     2,631     2,178     52  
Legacy Areas   561     149     57     35     2  
Key Development & Legacy Areas   24,164     10,314     2,688     2,213     54  


Highlights Subsequent to the Quarter

  • Acquired Remaining Interest in Peace River – Subsequent to the quarter, we entered into a purchase and sale agreement (the “Agreement“) to acquire the remaining 45 percent partnership interest in the Peace River Oil Partnership (“PROP“) asset from our joint venture partner (the “Vendor“), through a wholly-owned subsidiary (the “Acquisition“). Based on the purchase price of $43.5 million, consideration at closing is expected to be approximately $36 million. The Acquisition has an effective date of July 1, 2021 with closing expected during the week of November 15, 2021.

  • Commenced Equity Offering – The Acquisition will be partially funded through a “best efforts” marketed equity offering of subscription receipts for gross proceeds of up to $22.5 million at $4.40 per subscription receipt. The remainder of the cash funding will be from a limited recourse debt financing against the acquired interest.

  • Amended Senior Credit Facility and Senior Note Repayment – In connection with the Acquisition, we have agreed to reduce our aggregate syndicated credit facility commitment amount by $25 million to $415 million at closing of the transaction. At the same time, the Company will repay approximately $3.3 million of its senior notes, which will leave approximately US$43.7 million outstanding with a maturity date of November 30, 2022.

  • Extended Employment Contract – The Company extended Stephen Loukas’s employment contract as Interim President and CEO to December 31, 2022, subject to the option to terminate, if mutually agreeable to both parties, on July 1, 2022.

We refer you to our recent release dated November 2, 2021 for more details about the PROP Acquisition and its associated transactions.


Our second half development program advanced substantially with the drilling of 11 wells (10.2 net) and three gross/net wells brought on production in the quarter. Subsequent to the quarter, development activity has been significant with an additional five wells (4.8 net) rig-released and eight wells (7.2 net) brought on stream. On October 27, we announced the acceleration of three wells from our 2022 program to ensure uninterrupted drilling into 2022, allowing us to secure access to the drilling rigs and to minimize mobilization costs.

  • Willesden Green: Subsequent to our October 27 update, we rig released our ninth Cardium well in our second half program – the final of four wells (4.0 net) on the 6-22 Faraway pad. The wells are expected to undergo fracturing operations during the second week of November and be on production in mid-December. Drilling is underway on the first of two wells on our 4-17 Faraway pad site prior to finishing the year with one well at our existing 1-25 Crimson pad and an accelerated 2022 well at our 8-3 Faraway pad. These final four wells (4.0 net) are anticipated to be on production in early February of 2022.

    Results for our earlier second-half 2021 wells are as follows:

    • 3-3 pad – IP30 rates for the two wells averaged 494 boe/d (70 percent light oil)
    • 3-29 pad – IP30 rate for the well was 201 boe/d (84 percent light oil)
    • 1-33 pad – IP30 rate on the first well was 218 boe/d (71 percent light oil); following a pump repair, the second well averaged 372 boe/d (66 percent light oil) over the past 22 days
  • Pembina: We rig-released an additional Cardium well (0.9 net) since our last update, bringing the total to five Cardium wells (4.5 net) as part of our second half program. The first well at the 7-17 pad has produced at an average rate of 310 boe/d (69 percent light oil) for the 15 days post-cleanup. The remaining two wells have minor interventions underway with continuous production expected to begin in mid-November. The three remaining Pembina Cardium wells (2.8 net) from the 2021 program will be drilled in November and early December and are expected to be completed and brought on production in January 2022. In December 2021, we anticipate rig releasing the first of two additional, accelerated wells (1.8 net), with the second well finishing drilling in early January.

    The two vertical non-Cardium wells (1.5 net) rig-released in October continue to produce at strong rates. The first well averaged 331 boe/d (97 percent light oil) over its first twenty-five days. The second well produced at an average of 222 boe/d (95 percent light oil) over its 10 days of production post-cleanup.

  • PROP: As part our 2021 development program, the Company is returning to drilling in our Peace River asset in the fourth quarter of 2021 with a four-well program (at 100 percent working interest post Acquisition). These wells target the Bluesky formation from our existing pads: three wells at the 6-31 pad and one at the 14-25 pad. Production from the four wells is expected to be on stream by the end of January 2022.

A summary of this year’s completed and planned activity in our development program is as follows, with assumptions that the Acquisition is closed and our interest now at 100 percent:

  Operated Wells
Rig Released
Gross (net)
Operated Wells
On Production
Gross (net)
Q1 2021 6 (6.0) 3 (3.0)1
Q2 2021 3 (3.0) 6 (6.0)
Q3 2021 11 (10.2) 3 (3.0)
Q4 2021E 16 (15.5) 14 (13.0)
TOTAL 36 (34.7) 26 (25.0)2


(1) On-stream count includes 1 well rig-released in 2020.
(2) 2 wells (1.9 net) spud in 2021 are expected to be rig released in 2022.
Including these 2 wells, 13 wells (12.6 net) from the 2021 program will start production in the first quarter of 2022.


Additional details regarding the status of our 2021 development program can be found in our recent operations update release.


As per our PROP Acquisition news release of November 2, 2021, we updated our pro-forma guidance for 2021 after giving effect to the Acquisition, assuming the Acquisition closes during the week of November 15, 2021, and incorporating our third quarter and nine-month 2021 results. Using the mid-point of our post-acquisition guidance, we expect fourth quarter 2021 production to average approximately 26,730 boe/d, generating funds flow from operations of approximately $88 million.

Production1 boe/d 24,600 – 24,800
% Oil and NGLs % 64%
Capital Expenditures2 $ millions 141 – 143
Decommissioning Expenditures3 $ millions 8
Net Operating Costs $/boe 12.95 – 13.15
General & Administrative $/boe 1.70 – 1.80
Based on midpoint of above guidance  
WTI Range US$/bbl 75.00 – 80.00
Funds Flow from Operations4, 5, 6 $ millions 223 – 228
Free Cash Flow2, 4, 5, 6 $ millions 72 – 77
Net Debt $ millions 404 – 409


(1) Mid-point of guidance range:10,660 bbl/d light oil, 2,900 bbl/d heavy oil, 2,205 bbl/d NGLs and 53.6 mmcf/d natural gas.
(2) Includes capital cost updates for PROP Q4 drilling at 100% OBE and otherwise excludes acquisitions
(3) Decommissioning expenditures do not include grants and allocations to be utilized by the Company under the ASRP.
(4) Includes approximately $15 million of estimated charges for full year 2021 related to the deferred share units, preferred share units and non-treasury incentive plan cash compensation amounts which are based on the Company’s closing share price on September 30, 2021 of $4.51 per share. The charge is primarily due to the Company’s increased share price in 2021 compared to the closing price on December 31, 2020 of $0.87 per share.
(5) Includes actual WTI and natural gas prices for the first nine months of 2021. Pricing assumptions outlined are forecasted for the fourth quarter of 2021. Risk management (hedging) adjustments incorporated into 2021 guidance as at October 26, 2021.
(6) Includes actual AECO prices for the first nine months of 2021 and AECO forward strip pricing as of October 26, 2021.


The Company has the following financial oil and gas contracts in place on a weighted average basis:

Term   Notional Volume     Pricing (CAD)  
Oil – WTI            
October 2021   7,750 bbl/d   $ 92.59/bbl  
November 2021   6,500 bbl/d   $ 100.39/bbl  
December 2021   500 bbl/d   $ 100.00/bbl  


Natural Gas – AECO            
October 2021   23,695 mcf/d   $ 2.70/mcf  
November 2021 – March 2022   25,591 mcf/d   $ 4.63/mcf  


Additionally, the Company has the following physical contracts in place:

  Notional Volume Term   Pricing (CAD)  
Heavy Oil Differential1 – USD        
  550 bbl/d Oct – Dec 2021   US$26.00/bbl  


(1) Hedged on a USD basis and inclusive of WCS differential, quality, and transportation charges.



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 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 to be preliminary until such analysis or interpretation has been completed.


Certain financial measures including FFO, FFO per share-basic, FFO per share-diluted, free cash flow, netback, net operating costs and net debt, included in this release do not have a standardized meaning prescribed by IFRS and therefore are considered non-GAAP measures; accordingly, they may not be comparable to similar measures provided by other issuers. FFO is cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures, office lease settlements, the effects of financing related transactions from foreign exchange contracts and debt repayments and certain other expenses and is representative of cash related to continuing operations. FFO is used to assess the Company’s ability to fund its planned capital programs. See “Calculation of Funds Flow from Operations” below for a reconciliation of FFO to cash flow from operating activities, being its nearest measure prescribed by IFRS. Free cash flow is funds flow from operations less capital and decommissioning expenditures. Netback is the per unit of production amount of revenue less royalties, net operating costs, transportation expenses and realized risk management gains and losses, and is used in capital allocation decisions and to economically rank projects. Net operating costs are calculated by deducting processing income and road use recoveries and is used to assess the Company’s cost position. Processing fees are primarily generated by processing third party volumes at the Company’s facilities. In situations where the Company has excess capacity at a facility, it may agree with third parties to process their volumes as a means to reduce the cost of operating/owning the facility. Road use recoveries are a cost recovery for the Company as we operate and maintain roads that are also used by third parties. Net debt is the total of long-term debt and working capital deficiency and is used by the Company to assess its liquidity. These non-GAAP measures are further described and defined in the MD&A. See the MD&A for reconciliations of netback, net operating costs and net debt to the nearest GAAP measures, as applicable.


  Three months ended
September 30
  Nine months ended
September 30
(millions, except per share amounts) 2021   2020   2021   2020  
Cash flow from operating activities $ 65.5   $ 34.8   $ 135.8   $ 68.3  
Change in non-cash working capital   (9.1 )   (11.1 )   (1.1 )   (1.0 )
Decommissioning expenditures   1.6     0.6     5.4     8.8  
Onerous office lease settlements   2.3     2.4     7.0     7.4  
Deferred financing costs   (1.7 )       (4.4 )    
Financing fees paid           4.4      
Realized foreign exchange loss – debt maturities         0.3      
Restructuring charges1   0.1         (1.8 )   0.3  
Transaction costs       2.9         2.9  
Other expenses1   0.6     0.8     (7.7 )   4.7  
Funds flow from operations $ 59.3   $ 30.4   $ 137.9   $ 91.4  
Per share                        
Basic per share $ 0.79   $ 0.41   $ 1.86   $ 1.25  
Diluted per share $ 0.77   $ 0.41   $ 1.81   $ 1.25  


(1) Excludes the non-cash portion of restructuring and other expenses.


Oil   Natural Gas
bbl barrel or barrels mcf thousand cubic feet
bbl/d barrels per day mmcf million cubic feet
boe barrel of oil equivalent mmcf/d million cubic feet per day
boe/d barrels of oil equivalent per day AECO Alberta benchmark price for natural gas
MSW Mixed Sweet Blend NGL natural gas liquids
WTI West Texas Intermediate    



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, Funds Flow from Operations, Free Cash Flow, 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 in order 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.


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: that we will file the unaudited interim consolidated financial statements and MD&A on SEDAR and EDGAR in due course; the anticipated closing date of the Acquisition; our expected fourth quarter of 2021 and first quarter of 2022 drilling program and anticipated results thereof, including, but not limited to, the locations and number of wells and the impact of the drilling program impact on mobilization costs and continued drilling; our increase to our full-year 2021 production guidance; the anticipated timing of certain fracturing operations; the timing of certain wells coming onto production; and the Corporation’s pro-forma guidance for 2021 and anticipated results for the fourth quarter of 2021.

With respect to forward-looking statements and FOFI 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 and FORI contained herein (including our guidance set out under “2021 Updated Guidance”) do not assume the completion of any transaction other than the Acquisition); 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 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 (including the CEWS and ASRP) 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 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; 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 to renew or replace our syndicated bank facility and our ability to finance the repayment of our senior notes on maturity; 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 and FOFI contained in this document, and the assumptions on which such forward-looking statements and FOFI 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 and FOFI 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 and FOFI involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the forward-looking statements and FOFI 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 and FOFI. These risks and uncertainties include, among other things: 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 , including but not limited to the Acquisition and the financings being undertaken in connection therewith; 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 the 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 that has been caused by the COVID-19 pandemic persists or worsens; the risk that the COVID-19 pandemic 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 senior notes is not further extended (if necessary), that the borrowing base under our credit facility is reduced, that the Company is unable to renew our credit facilities on acceptable terms or at all and/or finance the repayment of our senior notes when they mature on acceptable terms or at all and/or obtain debt and/or equity financing to replace one or both of our credit facilities and senior 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 notes; the possibility that we are forced to shut-in production, whether due to commodity prices failing to rise or decreasing further or changes to existing government curtailment programs or the imposition of new programs; the risk that OPEC, Russia 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; 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 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. 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 and FOFI 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. The forward-looking statements and FOFI 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 OTCQX Market in the United States under the symbol “OBE” and “OBELF” respectively.

All figures are in Canadian dollars unless otherwise stated.


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/102407