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Copper Tip Energy Services
Hazloc Heaters
WEC - Western Engineered Containment
WEC - Western Engineered Containment
Copper Tip Energy
Hazloc Heaters

Obsidian Energy Announces Increased 2021 Production and Capital Expenditure Guidance with Second Quarter 2021 Results

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These translations are done via Google Translate
  • Successful completion of first half and an early start to the second half 2021 drilling program
  • Continued debt paydown and higher funds flow from operations

Calgary, Alberta–(Newsfile Corp. – July 29, 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 second quarter 2021.

Three Months Ended June 30 Six Months Ended June 30
2021 2020 2021 2020  
      (millions, except per share amounts)
Cash flow from operations 42.2 2.1 70.3 33.5
      Basic per share ($/share) 0.57 0.03 0.95 0.46
      Diluted per share ($/share) 0.55 0.03 0.93 0.46
Funds flow from operations1 42.3 24.7 78.6 61.0
      Basic per share ($/share)1 0.57 0.34 1.06 0.84
      Diluted per share ($/share)1 0.55 0.34 1.04 0.84
Net income (loss) 322.5 (21.1 ) 345.7 (768.7 )
      Basic per share ($/share) 4.33 (0.29 ) 4.67 (10.53 )
      Diluted per share ($/share) 4.23 (0.29 ) 4.57 (10.53 )
Capital expenditures 21.5 0.4 51.0 41.0
Decommissioning expenditures 0.5 0.2 3.8 8.2
Net debt1 435.7 495.7 435.7 495.7
Daily Production        
      Light oil (bbl/d) 10,836 12,800 10,427 12,656
      Heavy oil (bbl/d) 2,660 1,966 2,723 2,805
      NGL (bbl/d) 2,162 2,278 2,108 2,258
      Natural gas (mmcf/d) 54 53 52 53
Total production2 (boe/d) 24,651 25,872 23,942 26,482  
Average sales price3        
      Light oil ($/bbl) 76.97 29.20 72.37 39.78
      Heavy oil ($/bbl) 48.58 5.98 44.46 15.13
      NGL ($/bbl) 39.31 11.65 38.77 17.04
      Natural gas ($/mcf) 3.21 2.14 3.21 2.17
Netback1 ($/boe)        
      Sales price 49.56 20.30 46.98 26.37
      Risk management gain (loss) (0.52 ) 4.75 (1.44 ) 4.61  
      Net sales price 49.04 25.05 45.54 30.98
      Royalties (4.90 ) (0.76 ) (3.83 ) (1.51 )
      Net operating expenses1 (13.71 ) (8.51 ) (13.62 ) (10.32 )
      Transportation (1.95 ) (1.18 ) (1.87 ) (1.95 )
      Netback($/boe) 28.48 14.60 26.22 17.20  


(1) The terms funds flow from operations (“FFO“) and their applicable per share amounts, “net debt”, “netback” and “net operating expenses” 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).

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 six months ended June 30, 2021 on our website at, which will be filed on SEDAR and EDGAR in due course.


The economic environment continued to improve in the second quarter, resulting in higher FFO and further debt reduction. Favourable weather and ground conditions allowed us to accelerate all aspects of our development program including the rig release of three wells from our second half 2021 program.

2021 Second Quarter Financial Highlights

  • Strong Funds Flow – FFO was $42.3 million ($0.57 per share) for the second quarter of 2021, an increase from the first quarter of 2021 ($36.3 million; $0.49 per share) and the second quarter of 2020 ($24.7 million; $0.34 per share). Higher commodity prices were partially offset by higher royalty rates and share-based compensation charges of $8.9 million, which was predominately due to the more than doubling of the Company’s share price between March 31, 2021 to June 30, 2021. Adjusting for the share-based compensation charges, FFO would have been $51.2 million ($0.69 per share), representing a 107 percent increase when compared to the second quarter of 2020.
  • Capital Acceleration – Capital expenditures in the second quarter of 2021 totaled $21.5 million (2020: $0.4 million) and were predominately spent on completing the remaining wells in the nine-well first half development program as well as pad construction costs for the second half program. We began our second half 2021 drilling operations earlier than anticipated and accelerated certain optimization projects due to favourable spring ground conditions.
  • Debt Reduction – Continued strong financial results and our focus on debt reduction resulted in a decrease in net debt of 12 percent to $435.7 million at June 30, 2021, compared to $495.7 million at June 30, 2020. This included $370.0 million drawn on our syndicated credit facility (down from $420.0 million at June 30, 2020), $57.3 million of senior notes and $8.4 million of a working capital deficiency.
  • Continued Low G&A Costs – Second quarter 2021 general and administrative (“G&A“) costs were consistent with the first quarter of 2021 at $1.69 per boe compared to $1.36 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.
  • Operating Cost Management – Net operating costs of $13.71 per boe during the second quarter of 2021 were higher than $8.51 per boe in the second quarter of 2020 and $13.52 per boe in the first quarter of 2021. Similar to G&A, operating costs were impacted by the return to normal activity levels in 2021 compared to 2020, where the Company restricted discretionary spending and shut-in production as a result of the low commodity price environment in this period. During the second quarter of 2021, the Company was impacted by high power prices, mostly due to extreme heat in several parts of North America that increased natural gas demand and prices, and completed more 2021 scheduled maintenance activity than originally planned in the quarter.
  • Net Income – Net income of $322.5 million ($4.33 per share) in the second quarter of 2021 benefitted from higher FFO and a $311.5 million impairment reversal within the Company’s Cardium asset due to higher forecasted commodity prices and strong drilling results. This compared to a net loss of $21.1 million ($0.29 per share) in 2020, largely due to the lower commodity price environment at that time.

2021 Second Quarter Operational Highlights

  • Improved Production Levels – Performance from our first half 2021 drilling program and our base resulted in average production of 24,651 boe/d in the second quarter of 2021, a six percent increase over the first quarter of 2021 and ahead of internal estimates. As a result, we have increased our average production guidance for the year to between 24,000 and 24,400 boe/d from 23,300 to 23,800 boe/d.
  • Accelerated Development Program – We completed the first half development program with nine wells on production by mid-June. Careful pad design and facility planning allowed for extended operations into break up, accelerating drilling of the four-well East Crimson 6-21 pad into the first half of 2021.
  • Continued Strong Drilling Performance – We continued to demonstrate drilling efficiencies with estimated first half 2021 per well costs of $3.3 million (inclusive of construction, drilling, completions, equipping and tie-in costs to lease edge), representing a two percent decrease from our 2020 program average while increasing lateral length by 10 percent as compared to our first half 2020 program. Our 2021 drilling results include a new Company pacesetter for wells with intermediate casing and a new Company-best well lateral length.
  • Increased 2021 Development Program – With the continuation of a higher commodity price environment and base production improvements, we added three incremental wells (gross) to our second half 2021 development program and expanded our optimization activities by $2.6 million.
  • Reduction in Decommissioning Liabilities – We abandoned a total of 51 net wells during the second quarter of 2021 through participation in the Area Based Closure (“ABC“) program and the Alberta Site Rehabilitation Program (“ASRP“), where we utilized $1.1 million of net grants. As a result of these efforts, our undiscounted, uninflated decommissioning liability was reduced by an estimated $4 million in the second quarter.
Production Volumes by Product and Producing Region
Three Months Ended June 30, 2021
Area   Production (boe/d)     Light Oil (bbl/d)     Heavy Oil (bbl/d)   NGLs
      Cardium 20,390   10,502   48   2,089   47
      Viking 812   170   108   39   3
      Peace River   2,895       2,429   3   3  
      Key Development Areas 24,097   10,672   2,585   2,131   53
      Legacy Areas   554     164     75     31     1  
      Key Development & Legacy Areas   24,651     10,836     2,660     2,162     54  



In addition to completing our first half 2021 development program, we finished construction of several pad sites in our second half 2021 program in June, allowing for an early start to our program.

Our second half two-rig continuous drilling program is well underway with the rig release of both wells at the East Crimson 1-33 two-well pad in July. Fracture stimulation for these wells is complete, and the wells are expected to be on stream by the end of August. This rig also successfully drilled a third well at the existing 3-29 pad in East Crimson, with completion anticipated in mid-August, and has spud a fourth well at our 3-03 two-well pad in Crimson Lake.

In July, we started drilling in our Central Pembina region, and are currently drilling the first well on the 7-17 Pembina Cardium Unit #9 three-well pad. With the remaining wells on this pad to be drilled in August, we expect completion of all wells by mid-September.

With an improved economic environment and higher FFO, we have modestly increased our 2021 capital plan with the addition of three gross wells to our second half program and expanded optimization activities by $2.6 million. We plan to drill 25 wells (22.0 net), up from 23 wells (20.3 net) in our second half 2021 program, predominantly in our Willesden Green and Pembina Cardium assets. Combined with the nine wells brought on production in the first half of the year (one of which was rig released in 2020), we expect to bring 28 wells (25.0 net), up from 25 wells (22.8 net), on production in 2021. Consistent with previous guidance, the remaining seven wells (7.0 net) are expected on production early in the first quarter of 2022. Our successful optimization program continued with $3.9 million invested in the second quarter (first quarter 2021: $2.9 million) out of a total of $10.6 million now allocated to capture highly attractive capital efficiencies in 2021.

During the first half of 2021, we successfully abandoned a combined total of 158 net wells and 155 net kilometres of pipeline through participation in the ASRP, where we utilized $5.9 million of grants, and the ABC program. Our second-half decommissioning program is fully underway with four service rigs working on decommissioning well activity. With the support of approximately $28 million (gross) of ASRP grants and allocations from the program, we anticipate 589 net wells and 702 net kilometres of pipelines will be abandoned in 2021 and 2022.


With solid results from our base production and our 2021 development program to date, we are revising our 2021 production guidance and increasing our capital expenditures for the remainder of the year, adding three incremental gross wells to our second half program and expanding our optimization activities. A minor change in 2021 guidance for net operating expenses was also made due to higher than expected power prices. Our revised 2021 guidance includes $8.9 million of share-based compensation recorded in the second quarter (not included in our original 2021 guidance), which is reflected in the FFO and FCF metrics. We continue to meaningfully reduce debt levels, which is expected to result in an improved annualized fourth quarter 2021 net debt to EBITDA ratio of 1.8:1 (assuming mid-point of operational guidance and WTI of US$65/bbl).

(Revised Guidance)
Production 1 boe/d 23,300 – 23,800 24,000 – 24,400
Net Operating Expense $/boe $12.70 – $13.10 $12.80 – $13.20
General & Administrative $/boe $1.65 – $1.85 $1.65 – $1.85
Capital Expenditures $ millions $125 – $130 $133 – $138
 Decommissioning Expenditures 2 $ millions $8 $8
Based on midpoint of above guidance
      Funds Flow from Operations3 $ millions $160 – $1954 $180 – $2005
      Funds Flow from Operations3 per share $2.18 – $2.654 $2.37 – $2.675
      Free Cash Flow3 $ millions $25 – $604 $35 – $555
Pricing assumptions
      WTI Range US$/bbl $55.00 – $65.00 $60.00 – $70.00
      AECO C/mcf $2.79 $3.19
      Foreign Exchange CAD/USD $1.27 $1.25


(1) Mid-point of guidance range: 10,600 bbl/d light oil, 2,650 bbl/d heavy oil, 2,150 bbl/d NGLs and 52.6 mmcf/d natural gas.
(2) Decommissioning expenditures do not include grants and allocations to be utilized by the Company under the ASRP.
(3) Includes the $11.3 million charge related to the DSU, PSU and NTIP cash compensation plans, which increased largely due to the Company’s significant increase in our share price which closed at $4.24 per share at June 30, 2021 compared to $0.87 at December 31, 2020.
(4) Includes actual WTI and natural gas prices for the first quarter of 2021 Risk management (hedging) adjustments incorporated into 2021 guidance as at May 6, 2021.
(5) Includes actual WTI and natural gas prices for the first half of 2021. Risk management (hedging) adjustments incorporated into 2021 guidance as at July 28, 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
      April 2021 5,525 bbl/d $ 77.90/bbl
      May 2021 5,956 bbl/d $ 79.67/bbl
      June 2021 6,350 bbl/d $ 81.27/bbl
      July 2021 6,419 bbl/d $ 88.07/bbl
      August 2021 3,000 bbl/d $ 90.33/bbl  


Natural Gas – AECO  
      April 2021 26,065 mcf/d $ 2.83/mcf
      May 2021 21,326 mcf/d $ 2.68/mcf
      June 2021 21,326 mcf/d $ 2.67/mcf
      July 2021 21,326 mcf/d $ 2.57/mcf
      August – October 2021 23,695 mcf/d $ 2.70/mcf
      November 2021 – March 2022 4,739 mcf/d $ 4.18/mcf  


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

Notional Volume Term Pricing (CAD)  
Physical Oil Contracts1
      WTI 571 bbl/d Apr – Jun 2021 $ 59.04/bbl  
Light Oil Differential2 3    
1,245 bbl/d Apr – Jun 2021 $ 5.51/bbl
1,230 bbl/d Jul – Sep 2021 $ 5.82/bbl
Light Oil Differential – USD2    
1,556 bbl/d Apr – Jun 2021 US$4.00/bbl
1,539 bbl/d Jul – Sep 2021 US$4.42/bbl  
Heavy Oil Differential4    
564 bbl/d Jul – Sep 2021 $ 14.85/bbl
Heavy Oil Differential– USD    
550 bbl/d Jul – Dec 2021 US$26.00/bbl  


(1) WTI, differentials and foreign exchange hedged to lock-in positive net operating income on certain heavy oil properties.
(2) Differentials completed on a WTI – MSW basis.
(3) USD transactions completed on a US$ WTI – US$ MSW basis and converted to Canadian dollars using a fixed foreign exchange ratio of CAD/USD $1.281 in the second quarter of 2021 and $1.279 in the third quarter of 2021.
(4) Differentials completed on a WTI – WCS basis.
(5) Hedged on a USD basis and inclusive of WCS differential, quality and transportation charges.


For further information on these and other matters, Obsidian Energy will post an updated quarterly corporate presentation today on our website,



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.


Certain financial measures including FFO, FFO per share-basic, FFO per share-diluted, free cash flow, netback, net operating costs, net debt and EBITDA, 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 expenses, 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. EBITDA is cash flow from operations excluding the impact of changes in non-cash working capital, decommissioning expenditures and financing expenses.


  Three months ended
June 30
  Six months ended
June 30
(millions, except per share amounts) 2021   2020   2021   2020  
Cash flow from operating activities $ 42.2 $ 2.1 $ 70.3 $ 33.5
Change in non-cash working capital (2.3 ) 15.2 8.0 10.1
Decommissioning expenditures 0.5 0.2 3.8 8.2
Onerous office lease settlements 2.4 6.2 4.7 5.0
Deferred financing costs (1.7 ) (2.7 )
Financing fees paid 0.3 4.4
Realized foreign exchange loss – debt maturities   0.3
Restructuring charges1 0.1 (1.9 ) 0.3
Transaction costs 0.1
Other expenses   0.8     1.0     (8.4 )   3.9  
Funds flow from operations $ 42.3   $ 24.7 $ 78.6 $ 61.0  
Per share        
      Basic per share $ 0.57 $ 0.34 $ 1.06 $ 0.84
      Diluted per share $ 0.55 $ 0.34 $ 1.04 $ 0.84  


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


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



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; our increase to our average production guidance and our first half results supporting the goal of returning production to pre-COVID levels by the end of 2021; our expected 2021 second half development and optimization program; our expected timing for development activity and ability to respond to changes in commodity prices; our expected timing for rig release, completion and on production for certain wells; our expectation for annualized fourth quarter 2021 net debt to EBITDA ratio; our full year guidance including production, net operating expenses, G&A expenses, capital and decommissioning expenditures, FFO and FFO/share and free cash flow; our expectation for the ASRP and ABC programs in 2021 and 2022 and our commitment to further reducing or decommissioning liability; our hedges; and when we will post our updated corporate presentation.

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 (including our guidance set out under “Outlook”) 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 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 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 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 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 (, EDGAR website ( 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. 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 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

Investor Relations:
Toll Free: 1-888-770-2633


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