Obsidian Energy Announces Fourth Quarter and Full Year 2020 Results and Provides Full Year 2021 Guidance

  • Strong 2020 operational performance drives improved cost metrics and debt reduction
  • Robust well results to date from first half 2021 development program
  • 2021 capital budget set at $127 million with decommissioning budget of $8 million

Calgary, Alberta--(Newsfile Corp. - March 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 fourth quarter and full year 2020.

Three months ended December 31

Year ended December 31


(millions, except per share amounts)
Cash flow from operations



Basic and diluted per share



Funds flow from operations2



Basic and diluted per share 2



Net income (loss)

Basic and diluted ($/share)

Capital expenditures



Decommissioning expenditures



Net debt2










Daily Production



Light oil (bbls/d)



Heavy oil (bbls/d)



NGL (bbls/d)



Natural gas (mmcf/d) 52  52  53  53 
Total production3 (boe/d)  



Average sales price4



Light oil ($/bbl)



Heavy oil ($/bbl)



NGL ($/bbl)



Natural gas ($/mcf)



Netback2 ($/boe)



Sales price



Risk management gain (loss)  (0.14) 0.66  2.25  (0.66)
Net sales price



Net operating expenses2
Transportation  (1.60) (2.56) (1.91) (2.76)
Netback2 ($/boe) 17.64  27.23  17.35  21.65 

(1) Effective June 5, 2019, the Company consolidated its common shares based on seven old common shares outstanding for one new common share. All figures in the table have been updated to reflect the 7:1 consolidation.
(2) 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.
(3) Please refer to the "Oil and Gas Information Advisory" section below for information regarding the term "boe".
(4) Before risk management gains/(losses).

Detailed information can be found in Obsidian Energy's annual audited consolidated financial statements and management's discussion and analysis ("MD&A") as at and for the year ended December 31, 2020 on our website at www.obsidianenergy.com, which will be filed on SEDAR and EDGAR in due course.


In response to the challenges faced in 2020, we took immediate action to manage our underlying asset base, drive continued cost efficiencies, and protect our balance sheet without sacrificing our safety or environmental performance. We implemented a series of decisions to help preserve liquidity including significant cost reduction initiatives, rapidly shut-in volumes deemed temporarily uneconomic, deferred our second half development program and reduced debt levels.

As a result, the Company met all key performance targets in 2020. In conjunction with increased oil prices, capital expenditures were expanded in December to accommodate an early start to our 2021 development program.

Metric 2020 Guidance Range   2020 Results  
Production (boe/d) 1 2 25,300 - 25,500  25,404 
Capital Expenditures ($millions)

Decommissioning Expenditures ($millions)

Net Operating Expense ($/boe)
11.00 - 11.20

General & Administrative ($/boe) 1.45 - 1.55  1.51 

(1) Adjusted for January 2020 Carrot Creek Disposition of 115 boe/d (85% light oil).
(2) Mid-point of Updated 2020 Guidance Range: 11,600 bbl/d light oil, 2,850 bbl/d heavy oil, 2,200 bbl/d NGLs and 52.5 mmcf/d natural gas.

2020 Fourth Quarter and Full Year Financial Highlights

Obsidian Energy highlights the following 2020 key financial results:

  • Debt Reduction - Cash flow from operations exceeded capital expenditures, which contributed to net debt decreasing five percent to $467.8 million at December 31, 2020, compared to $494.2 million from the prior year. This included $395 million drawn on our syndicated credit facility, $60.3 million of senior notes and a $12.5 million working capital deficiency at December 31, 2020.

  • Resilient Funds Flow - FFO was $117.8 million ($1.61 per share) for the year compared to $159.1 million ($2.18 per share) in 2019. Fourth quarter 2020 FFO totaled $26.4 million ($0.36 per share), compared to $54.2 million ($0.74 per share) for the fourth quarter of 2019. The decrease to FFO was a result of lower commodity prices and lower production due to our deferred capital program, which was partially offset by cost reductions.

  • Increased Operating Efficiencies - Net operating costs improved 17 percent to $11.15 per boe in 2020 compared to $13.42 per boe in 2019, as the Company continued to benefit from efficiency improvements despite lower production volumes. For the fourth quarter of 2020, net operating expenses remained consistent on a per boe basis at $12.77 per boe compared to $12.75 per boe in the fourth quarter of 2019.

  • Reduced G&A Costs - Cost saving initiatives improved G&A costs significantly in 2020, decreasing 26 percent to $1.51 per boe in 2020 compared to $2.03 per boe in 2019. In the fourth quarter, G&A decreased three percent to $1.63 per boe in 2020 compared to $1.68 per boe in 2019.

  • Capital Discipline - Capital expenditures in 2020 totaled $57.2 million (a decrease of 45 percent over 2019) and decommissioning expenditures totaled $11.1 million. Fourth quarter capital expenditures were $11.6 million (a decrease of 66 percent from the fourth quarter of 2019) and decommissioning expenditures were $2.3 million in the fourth quarter of 2020 compared to $6.4 million in the same period in 2019.

    • The majority of 2020 capital expenditures were spent in the first half with the drilling of 10 net wells. Fourth quarter 2020 capital expenditures were primarily in December and relate to the start of our 2021 development program.

  • Net Income/Loss - The significantly lower oil price environment resulted in the Company recording non-cash asset impairments in the first quarter of 2020, which predominately contributed to the net loss of $771.7 million ($10.53 per share) in 2020. For the fourth quarter of 2020, the Company recorded net income of $0.2 million ($0.01 per share).

2020 Fourth Quarter and Full Year Operational Highlights

The Company highlights the following 2020 key operational results:

  • Strong Asset Performance - We achieved strong 2020 reserves replacement, increases in reserve life indices and additional future drilling locations despite challenges of global commodity prices.

    • Total proved ("1P") and total proved plus probable ("2P") reserves increased 113 percent and 125 percent, respectively in 2020 over 2019 levels. Our 2020 development program replaced 96% of production on a proved developed producing ("PDP") basis prior to economic impacts from the lower commodity price forecast. Including economic factors, we replaced 64 percent of production on a PDP basis.

    • Finding and development costs are reflective of our strong results with operated development costs for our capital activity in 2020 of $9.44 per boe on a 2P basis.

    • Consistent positive technical revisions combined with drilling results and new future drilling locations increased our reserve life indices to approximately 8.5, 11.4 and 14.3 years for PDP, 1P and 2P reserves respectively.

  • Outstanding Development Well Results - We achieved considerable success in replacing production and added 37.3 net Cardium locations to our 2P reserves, net of our 2020 drilling program. Our 10 net well drilling program resulted in some of the best wells in the history of our Cardium area, delivering strong initial production ("IP") and ongoing rates.

  • Extended Reach Drilling at Lower Well Capital Costs - We successfully reduced our costs per well to $3.2 million for the year with an increased average horizontal length of 2,797 meters. These costs are inclusive of all construction, drilling, completions, equipping and gathering system expenditures, and represent a six percent reduction from 2019 costs despite an increase in the average horizontal length by five percent.

  • Continued Reduction in Decommissioning Liabilities - On a full year basis, we successfully abandoned a combined total of 247 net wells and 338 net kilometres of pipeline in 2020 through participation in the Alberta Site Rehabilitation Program ("ASRP") and the Area Based Closure ("ABC") programs. Our undiscounted decommissioning liability at year-end 2020 decreased by four percent to $596.6 million from $621.2 million. ABC eligible spending of $10 million as conducted prior to the suspension of ABC spend targets in 2020 is fully creditable against our 2021 ABC spend requirements.

Production Volumes by Product and Producing Region
Three Months Ended December 31, 2020
Area Production
  Light Oil
  Heavy Oil








Peace River 3,175  -  2,702  4  3 
Key Development Areas




Legacy Areas 383  71  42  30  1 
Key Development & Legacy Areas 23,644  10,055  2,895  2,087  52 



We began drilling our first half 2021 program in our high economic return Willesden Green Cardium area in December 2020. With continued strong commodity prices in 2021, Obsidian Energy expanded our planned first half drilling program from seven to nine wells. To date, seven wells have been successfully rig-released, and the remaining wells are expected to be rig-released prior to the third week of April, subject to ground conditions. We have also successfully completed five of the new Willesden Green wells. The remaining four wells are progressing on schedule and will be completed as soon as ground conditions allow, giving the Company a head start on our second half capital program. All activity to date has been completed on schedule and within budget estimates.

The three wells on the 4-35 pad are the first wells to be brought on production in our 2021 development program. The 4-35 pad sits adjacent to the 12-26 and 1-27 pads that delivered strong results from our first half 2020 program; IP10 rates for two of the new wells averaged 801 boe/d (89 percent oil). We are also very pleased with our 2021 drilling performance thus far. The first well reached a measured depth of 5,576 metres (3,503 metres horizontal length), which is the longest well drilled for the Company since 2018. Additionally, a second well in the program became a new Company pacesetter for wells with intermediate casing, drilling to a measured depth of 5,349 metres in 11.1 days (spud to rig release) - saving over $0.2 million and finishing 1.5 days quicker than our internal estimate.

102/12-33-043-08W5910 boe/d (87% oil)-
100/03-25-043-08W5692 boe/d (91% oil)Last eleven days average 1,021 boe/d (78% oil)



The COVID-19 pandemic created a very challenging environment in 2020. We acted quickly with the support of our employees, board and stakeholders, and are positioned to take advantage of the improving economic environment in 2021. With a strong start to our 2021 development program, we expect to generate higher fourth quarter and exit production rates than achieved in 2020, while still meaningfully reducing debt levels. With a continued constructive pricing environment, our program further positions us for additional production growth that generates even greater free cash flow in 2022.

The Company is replacing our previous guidance for first half 2021 to full year 2021 as our longer-term bank and senior note extensions, coupled with improved commodity prices provide added stability. A total budget of $127 million in capital expenditures plus an additional $8 million in decommissioning expenditures is planned for our development and environmental programs in 2021. We intend to utilize a two-rig continuous drilling program in the second half of 2021 with plans to drill 23 wells (19.3 net), predominantly in our Willesden Green and Pembina Cardium assets. Combined with the nine net wells drilled in the first half of the year, we expect to bring 25 wells (22.8 net) on production in 2021, with the remaining seven wells (6.8 net) expected on production early in the first quarter of 2022. In addition, our successful optimization program continues with $8 million allocated for 2021 (included in the capital expenditure figures above) to capture further highly attractive capital efficiencies. The Company has significant capability to scale our development drilling in response to changes in commodity prices.

Net operating expenses per boe are expected to be higher than 2020 levels largely due to reduced production volumes, higher staff costs due to the full reinstatement of salaries, minimal benefit from the Canadian Wage Subsidy program and a forecasted increase to well repairs and maintenance given the recent improvement in commodity prices. Increases in both cash flow and funds flow from operations are expected due to the continued strong performance of our high netback Willesden Green focused development program and the higher pricing environment.

We are continuing our participation in the ASRP and ABC programs, focusing on fields in Northern Alberta in the first quarter of 2021 where we've abandoned 106 net wells and 154 net kilometres of pipelines year to date. Decommissioning activity will be expanded over the next two years with an anticipated 485 net wells and 647 net kilometres of pipelines abandoned prior to the end of 2022 with the support of nearly $30 million of ASRP grants.

Our 2021 budget and 2022 forecast are designed to steadily restore average production to approximately 25,400 to 26,400 boe/d in 2022, while also paying down debt. We expect to generate approximately $45 million of free cash flow in 2021 (net of non-recurring transaction expenses associated with our bank facility and senior note extensions, using the midpoint of our guidance and WTI US$60 per barrel), which will be directed toward debt reduction. This is expected to result in an annualized fourth quarter 2021 net debt to EBITDA ratio of 2:1. We anticipate 2022 free cash of approximately $100 million (at WTI US$60 per barrel and the mid-point of the 2021 production forecast) driven by higher production and the absence of transaction expenses. Our full year 2021 guidance is presented below.

2021 Guidance
Production 1boe/d23,300 - 23,800
Net Operating Expense$/boe$12.70 - $13.10
General & Administrative$/boe$1.65 - $1.85
Capital Expenditures
Decommissioning Expenditures 2
$ millions
$ millions
$125 - $130
Based on midpoint of above guidance

Funds Flow from Operations $ millions$160 - $195
Funds Flow from Operations per share$2.18 - $2.65
Free Cash Flow$ millions$25 - $60

Pricing assumptions

WTI RangeUS$/bbl$55.00 - $65.00
Foreign ExchangeCAD/USD$1.27

(1) Mid-point of guidance range: 10,600 bbl/d light oil, 2,800 bbl/d heavy oil, 1,950 bbl/d NGLs and 49.2 mmcf/d natural gas
(2) Decommissioning expenditures do not include grants and allocations to be utilized by the Company under the Alberta Site Rehabilitation program.


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

TermNotional VolumePricing (CAD)
January 2021
6,150 bbl/d
February 2021
6,250 bbl/d
March 2021
6,800 bbl/d
April 2021
4,750 bbl/d
May 2021
1,125 bbl/d


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

Notional VolumeTerm  Pricing (CAD) 
Physical Oil Contracts 1

WTI 542 bbl/dJan - Mar 2021  $55.54/bbl
WTI571 bbl/dApr - Jun 2021 
Light Oil Differential 2 3

1,245 bbl/dApr - Jun 2021  $5.51/bbl

1,230 bbl/dJul - Sep 2021 
Light Oil Differential - USD 2

1,556 bbl/dApr - Jun 2021  

1,539 bbl/dJul - Sep 2021 
Heavy Oil Differential 4

564 bbl/dJul - Sep 2021 

(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.

The Company has the following natural gas hedges in place on a weighted average basis:

TermNotional Volume Pricing (CAD) 
January 202123,700 mcf/d $2.94/mcf
February 202123,700 mcf/d $2.94/mcf
March 202126,100 mcf/d $2.96/mcf
April 202126,100 mcf/d $2.83/mcf
May 202121,300 mcf/d $2.68/mcf
June 202121,300 mcf/d $2.67/mcf
July 20214,700 mcf/d $2.28/mcf
August 20214,700 mcf/d $2.28/mcf
September 20214,700 mcf/d $2.28/mcf
October 20214,700 mcf/d $2.28/mcf 



For further information on these and other matters, Obsidian Energy will post an updated corporate presentation on Tuesday March 30, 2021 on our website, www.obsidianenergy.com.



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. Boe/d means barrels of oil equivalent per day.


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
December 31
Year ended
December 31
(millions, except per share amounts)2020 
Cash flow from operating activities$11.1
Change in non-cash working capital


Decommissioning expenditures



Onerous office lease settlements



Deferred financing costs

Financing fees paid



Realized foreign exchange loss - debt maturities



Restructuring charges 1



Transaction costs



Other expenses 2 
Funds flow from operations $26.4
$54.2 $117.8 $159.1 




Per share



Basic and diluted per share$0.36 $0.74 $1.61 $2.18 

(1) In 2019 and 2020, excludes the non-cash portion of restructuring.
(2) In 2019, mainly includes legal fees related to claims against former Penn West Petroleum Ltd. employees related to the Company's 2014 restatement of certain financial results.


Oil Natural Gas
bblbarrel or barrelsmmcf million cubic feet
bbl/dBarrels per daymmcf/d million cubic feet per day
boebarrel of oil equivalentAECOAlberta benchmark price for natural gas
boe/dbarrels of oil equivalent per dayNGLnatural gas liquids
MSWMixed Sweet Blend

WTIWest 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. Please note that initial production and/or peak rates are not necessarily indicative of long-term performance or ultimate recovery. In particular, this document contains forward-looking statements pertaining to, without limitation, the following: that certain of our 2020 ABC spending will be creditable against our 2021 spend requirements; our expected timing for rig-release, and completion for certain wells; that we are well positioned to take advantage of the improving economic environment in 2021; our expectation to generate higher fourth quarter and exit production rates than achieved in 2020, while still meaningfully reducing debt levels; with the continued constructive pricing environment, that our program further positions us for additional production growth that generates even greater free cash flow in 2022; our proposed drilling program, on production dates, optimization program and expense; our expectations for net operating expenses; where we plan to focus our ASRP and ABC programs and expectations for the next two years; our expectations for production and debt in the next two years and the corresponding annualize fourth quarter 2021 net debt to EBITDA ratio; our anticipated 2022 free cash; our full year guidance including production, net operating expenses, G&A expenses, capital and decommissioning expenditures, FFO and FFO/share and FCF; 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, including Bonterra Energy Corp.); 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 additional production due to the continuation of low commodity prices or the further deterioration of commodity prices and our expectations regarding when commodity prices will improve such that any remaining shut-in properties can be returned to production; 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 (including the proposed acquisition of Bonterra Energy Corp.), 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 additional production or continue existing production shut-ins longer than anticipated, 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 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
Website: www.obsidianenergy.com;

Investor Relations:
Toll Free: 1-888-770-2633
E-mail: investor.relations@obsidianenergy.com

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