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BREAKING NEWS:
Copper Tip Energy Services
WEC - Western Engineered Containment
Hazloc Heaters
Hazloc Heaters
Copper Tip Energy
WEC - Western Engineered Containment

Obsidian Energy Announces First Quarter 2021 Results and Successful First Half Development Program


  • Successful completion of nine well, first half 2021 drilling program in Cardium
  • Robust initial well results with first five wells on-stream; completion activity commenced on remaining four wells
  • Free cash flow generation results in lower net debt

Calgary, Alberta–(Newsfile Corp. – May 7, 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 first quarter 2021.

Three Months Ended March 31
2021 2020
FINANCIAL
(millions, except per share amounts)
Cash flow from operations 28.1 31.4
Basic per share ($/share) 0.38 0.43
Diluted per share ($/share) 0.37 0.43
Funds flow from operations1 36.3 36.3
Basic per share ($/share)1 0.49 0.50
Diluted per share ($/share)1 0.48 0.50
Net income (loss) 23.2 (747.6 )
Basic per share ($/share) 0.32 (10.24 )
Diluted per share ($/share) 0.31 (10.24 )
Capital expenditures 29.5 40.6
Decommissioning expenditures 3.3 8.0
Net debt1 455.0 517.0
OPERATIONS
Daily Production
Light oil (bbls/d) 10,014 12,512
Heavy oil (bbls/d) 2,788 3,644
NGL (bbls/d) 2,056 2,239
Natural gas (mmcf/d) 50 52
Total production2 (boe/d) 23,225 27,092
Average sales price3
Light oil ($/bbl) 67.34 50.59
Heavy oil ($/bbl) 40.48 20.07
NGL ($/bbl) 38.20 22.52
Natural gas ($/mcf) 3.21 2.20
Netback1 ($/boe)
Sales price 44.21 32.17
Risk management gain (loss) (2.44 ) 4.47
Net sales price 41.77 36.64
Royalties (2.68 ) (2.23 )
Net operating expenses1 (13.52 ) (12.04 )
Transportation (1.79 ) (2.68 )
Netback1 ($/boe) 23.78 19.69
(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 months ended March 31, 2021 on our website at www.obsidianenergy.com, which will be filed on SEDAR and EDGAR in due course.

KEY FIRST QUARTER 2021 RESULTS

Commodity prices continued to improve during the first quarter, generating the highest funds flow from operations over the last four quarters and free cash flow that allowed for the pay down of debt. Net debt is now $62.0 million lower at $455.0 million at March 31, 2021 compared to the same period in 2020. Following suspension of our capital program through the majority of 2020, the Company successfully executed our expanded 2021 first half development program with the drilling of nine Cardium wells (including one well rig released in December 2020). Three of the wells were on production in March and two in April; initial production rates have been at internal expectations while costs came in below our budget. Completion operations have begun on the remaining four wells. We remain committed to restoring COVID-19 related production declines experienced in 2020 through our active development program and continuing to further reduce debt levels through free cash flow generation.

2021 First Quarter Financial Highlights

  • Strong Funds Flow – FFO was $36.3 million ($0.49 per share) for the first quarter of 2021, in line with the first quarter of 2020. Higher oil prices in 2021 offset realized hedging gains and higher production volumes in 2020.
  • Capital Discipline – Capital expenditures in the first quarter of 2021 totaled $29.5 million (2020: $40.6 million). First quarter 2021 capital expenditures were predominately spent on drilling six wells with three wells completed and on stream (2020: 10 wells drilled; three wells completed and on stream). Decommissioning expenditures totaled $3.3 million compared to $8.0 million in the same period in 2020.
  • Debt Reduction – Our continued focus on debt reduction resulted in a decrease in net debt of 12 percent to $455.0 million at March 31, 2021, compared to $517.0 million at March 31, 2020. This included $386.0 million drawn on our syndicated credit facility (down from $407.0 million at March 31, 2020), $58.2 million of senior notes and $10.8 million of a working capital deficiency.
  • Continued Low G&A Costs – G&A costs remained relatively consistent at $1.69 per boe in the first quarter of 2021 compared to $1.63 per boe in 2020, despite lower production volumes in 2021. On an absolute basis, G&A costs were $0.5 million lower at $3.5 million in the first quarter of 2021 compared to the same period in 2020.
  • Operating Cost Management – Net operating costs of $13.52 per boe were under budget during the first quarter of 2021 but higher than $12.04 per boe in the first quarter of 2020. Lower production volumes and increased power costs, in part due to cold weather in February, impacted per boe results during the first quarter of 2021. In addition, the reduction of discretionary repair and maintenance activities, beginning in March 2020, due to decreasing oil prices as a result of the COVID-19 pandemic contributed to lower operating costs in 2020.
  • Net Income – Net income of $23.2 million ($0.32 per share) in the first quarter of 2021 benefitted from higher oil prices and the Company’s overall lower cost structure. This compared to a net loss of $747.6 million ($10.24 per share) in 2020, largely due to the recording of non-cash impairments from the significantly lower forecasted oil price environment at the time.

2021 First Quarter Operational Highlights

  • Solid Asset Performance – During 2020, the Company postponed virtually all development activity from late March to early December in response to the COVID-19 pandemic and the low commodity price environment. As a result, production declines led to lower production levels throughout 2020 and into 2021, realizing 23,225 boe/d in average production in the first quarter of 2021 compared to 27,092 boe/d in the first quarter of 2020. We expect to increase production throughout 2021 and into 2022 with an active development program focused on restoring production to pre-COVID-19 levels.
  • Robust Development Well Results – Our first half drilling program delivered strong initial production (“IP“) with our three wells on the 4-35 pad achieving top quartile rates compared to our wells drilled in the area since 2017.
  • Extended Reach Drilling at Lower Well Capital Costs – We continued to improve drilling and completion efficiency on capital, design and execution over the quarter. The first half development program drilling costs were approximately six percent less with an increase in average drilled horizontal length of eight percent and completed lateral length of 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.
  • Continued Reduction in Decommissioning Liabilities – We successfully abandoned a combined total of 107 net wells and 155 net kilometres of pipeline during the first quarter of 2021 through participation in the Area Based Closure (“ABC“) program and the Alberta Site Rehabilitation Program (“ASRP“), where we have utilized $4.8 million of net grants. As a result of these efforts, our undiscounted, uninflated decommissioning liability was reduced $12 million in the first quarter.
Production Volumes by Product and Producing Region
Three Months Ended March 31, 2021
Area Production
(boe/d)
Light Oil
(bbls/d)
Heavy Oil
(bbls/d)
NGLs
(bbls/d)
Gas
(mmcf/d)
Cardium 19,056 9,803 47 1,985 43.3
Viking 794 157 123 40 2.8
Peace River 3,012 2,567 3 2.6
Key Development Areas 22,862 9,960 2,737 2,028 48.8
Legacy Areas 363 53 51 28 1.4
Key Development & Legacy Areas 23,225 10,014 2,788 2,056 50.2

 

2021 DEVELOPMENT PROGRAM UPDATE

We are pleased with our nine-well first half 2021 program in our high economic return Willesden Green Cardium area. All nine wells have been rig-released with five of the new Willesden Green wells commissioned with well IP rates as outlined below. All activity to date has been completed on schedule or early compared to our plan, and our program has been delivered below our capital budget estimates.

We achieved new levels of drilling accomplishments in our first half program with a new Company pacesetter Cardium well with intermediate casing (11.1 days and 5,349 metres depth from spud to rig release), saving over $0.2 million and finishing 1.5 days quicker than estimated. We also set a new Company record length in the Cardium with a measured depth of 5,576 metres (3,503 metres horizontal length), which is the longest Cardium well drilled for the Company.

In addition, our successful optimization program continues with $3.9 million invested in the first quarter out of a total of $8 million allocated for 2021 to capture highly attractive capital efficiencies.

Production rates for the new 2021 wells on-stream were as follows:

Well IP10 IP30
4-35: Three Well Pad
102/12-33-043-08W5 910 boe/d (87% oil) 748 boe/d (74% oil)
102/04-33-043-08W5 849 boe/d (80% oil) 662 boe/d (65% oil)
100/03-25-043-08W5 690 boe/d (91% oil) 714 boe/d (73% oil)
13-19: Two Well Pad
102/02-32-043-08W5 57 boe/d (91% oil)* 158 boe/d (76% oil)*
102/16-29-043-08W5 460 boe/d (75% oil) 311 boe/d (66% oil)
 * Early rates depressed by extended frac fluid recovery, recent production rate of 220 boe/d (76% oil).

 

Given the current favourable ground conditions, completions activity began in early May on the remaining four wells in the first half program, giving the Company a head start on our second half activity plan. In addition, construction of several pad sites in our second half program has been completed; drilling activity will commence in July dependent upon weather conditions.

We expect to drill 23 wells (19.3 net) in our two-rig continuous drilling program in the second half of 2021, predominantly in our Willesden Green and Pembina Cardium assets. Combined with the nine (9.0 net) wells drilled in our first half 2021 program, 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. The Company has significant capability to scale our development drilling in response to changes in commodity prices.

Our proactive management has led to a reduction of our decommissioning liabilities by over 30 percent since December 31, 2018, on an uninflated and undiscounted basis. We remain committed to further reducing this obligation. Decommissioning activity will continue throughout the remainder of 2021 both under the ASRP and ABC programs. With the support of nearly $30 million of ASRP grants, we anticipate 511 net wells and 409 net kilometres of pipelines will be abandoned prior to the end of 2022, which is equivalent to approximately a 90 percent decrease in our Legacy inactive well inventory at year-end 2020.

2021 OUTLOOK AND GUIDANCE; 2022 FORECAST

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. 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. This is expected to result in an annualized fourth quarter 2021 net debt to EBITDA ratio of 2:1 (assuming mid-point of operational guidance and WTI of US$60/bbl). With first quarter 2021 results at or ahead of our budget, we remain on track to meet our 2021 guidance.

2021E
(Guidance)
2022E
(Forecast 4)
Production 1 boe/d 23,300 – 23,800 25,400 – 26,400
Net Operating Expense $/boe $12.70 – $13.10 n/a
General & Administrative $/boe $1.65 – $1.85 n/a
Capital Expenditures $ millions $125 – $130 $102 – $117
Decommissioning Expenditures 2 $ millions $8 $13
Based on midpoint of above guidance
Funds Flow from Operations $ millions $160 – $1953 $195 – $255
Funds Flow from Operations per share $2.18 – $2.653 n/a
Free Cash Flow $ millions $25 – $603 $60 – $130
Pricing assumptions
WTI Range US$/bbl $55.00 – $65.00 $55.00 – $65.00
AECO C/mcf $2.79 $2.79
Foreign Exchange CAD/USD $1.27 $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.
(3) Includes actual WTI and natural gas prices for the first quarter of 2021. WTI = US$57.84/bbl; AECO natural gas prices = CAD$3.15/mcf. Risk management (hedging) adjustments incorporated into 2021 guidance as at May 6, 2021.
(4) Forecast 2022 free cash flow and production profiles based on ~$110MM capital program, $13MM decommissioning expenditures and includes a 34 well drilling program. Opex modelled at $12.75/boe and G&A modelled at $1.70/boe.

 

CLOSURE OF STRATEGIC REVIEW PROCESS

The Company has formally closed our previously announced strategic alternatives process, considering the successful completion of our syndicated credit facility and senior notes maturity extension to November 2022 and our stronger operational and improved financial position. However, we continue to pursue consolidation and merger/acquisition/disposition opportunities as part of our normal course of business to create incremental value for our stakeholders.

HEDGING UPDATE

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

Term Notional Volume Pricing (CAD)
April 2021 5,525 bbl/d $77.90/bbl
May 2021 4,625 bbl/d $79.64/bbl
June 2021 1,000 bbl/d $79.78/bbl

 

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
1,280 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 $14.85/bbl
(1) WTI, differentials and foreign exchange hedged to lock-in positive net operating income on certain heavy oil properties.
(2) Differentials completed on a WTI – MSW basis.
(3) USD transactions completed on a US$ 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:

Term Notional Volume Pricing (CAD)
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 2021 21,326 mcf/d $2.57/mcf
September 2021 21,326 mcf/d $2.57/mcf
October 2021 21,326 mcf/d $2.57/mcf

 

ANNUAL GENERAL MEETING

The Company is pleased to announce that its Annual General Meeting (“AGM“) will be scheduled for Wednesday, June 16, 2021 at 9:00 am (Mountain Time). It is our intention to hold our AGM in person at the offices of Obsidian Energy depending on the Alberta Health guidelines in place on public gatherings at that time. Further announcements and information regarding the AGM will be made in due course.

UPDATED CORPORATE PRESENTATION

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

ADDITIONAL READER ADVISORIES

OIL AND GAS INFORMATION ADVISORY

Barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value. Boe/d means barrels of oil equivalent per day.

NON-GAAP MEASURES

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.

CALCULATION OF FUNDS FLOW FROM OPERATIONS

Three months ended
March 31
(millions, except per share amounts) 2021 2020
Cash flow from operating activities $ 28.1 $ 31.4
Change in non-cash working capital 10.3 (5.1 )
Decommissioning expenditures 3.3 8.0
Onerous office lease settlements 2.3 (1.2 )
Deferred financing costs (1.0 )
Financing fees paid 4.1
Realized foreign exchange loss – debt maturities 0.3
Restructuring charges1 (2.0 ) 0.3
Transaction costs 0.1
Other expenses (9.2 ) 2.9
Funds flow from operations $ 36.3 $ 36.3
Per share
Basic per share $ 0.49 $ 0.50
Diluted per share $ 0.48 $ 0.50
(1) Excludes the non-cash portion of restructuring.

 

ABBREVIATIONS

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

 

FORWARD-LOOKING STATEMENTS

Certain statements contained in this document constitute forward-looking statements or information (collectively “forward-looking statements”) within the meaning of the “safe harbour” provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as “anticipate”, “continue”, “estimate”, “expect”, “forecast”, “budget”, “may”, “will”, “project”, “could”, “plan”, “intend”, “should”, “believe”, “outlook”, “objective”, “aim”, “potential”, “target” and similar words suggesting future events or future performance. In addition, statements relating to “reserves” or “resources” are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. 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 we will file the unaudited interim consolidated financial statements and MD&A on SEDAR and EDGAR in due course; that we expect to increase production throughout 2021 and into 2022 with an active development program focused on restoring production to pre-COVID 19 levels; our expected 2021 optimization program; our expected timing for development activity and ability to respond to changes in commodity prices; our expected timing for rig-release, and completion for certain wells; our expectation for the ASRP and ABC programs in 2021 and 2022 and our commitment to further reducing or decommissioning liability; how are 2021 budget and 2022 are designed and expectations for production and debt reduction; our expectation for annualize 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; that we will continue to pursue consolidation and merger/acquisition/disposition opportunities as part of our normal course of business to create incremental value for our stakeholders; our hedges; the date, time and location of the AGM; 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 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, 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.

CONTACT

OBSIDIAN ENERGY
Suite 200, 207 – 9th Avenue SW, Calgary, Alberta T2P 1K3
Phone: 403-777-2500
Toll Free: 1-866-693-2707
Website: www.obsidianenergy.com;

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



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