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Obsidian Energy Announces Second Quarter 2018 Financial and Operational Results

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Obsidian Energy Announces Second Quarter 2018 Financial and Operational Results

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CALGARY, Aug. 2, 2018 /PRNewswire/ - OBSIDIAN ENERGY LTD. (TSX/NYSE – OBE) ("Obsidian Energy", the "Company", "we", "us" or "our") is pleased to announce its financial and operational results for the three and six months ended June 30, 2018. All figures are in Canadian dollars unless otherwise stated.

David French, President and CEO commented, "The second quarter of 2018 was a relatively quiet one for development, as we took advantage of seasonal breakup to prepare for our second half drilling program. Obsidian Energy's team safely completed a major turnaround at our Company's biggest facility in Willesden Green on time and on budget, monitored the non-operated gas processing facility construction in Peace River while advancing our own gathering system in the area, and kicked off lease construction for our summer drilling program.

Our corporate cash flow continues to be constrained by our hedging program in 2018. The combination of wide differentials and a fulsome hedge book hamper our corporate netback right now, but the significant cash generating potential of our field operations remains. That all translates to funds flow from operations in the quarter of $32 million, which is slightly down from the first quarter. Additional maintenance activity was reflected in the opex per boe results of $14.47 per boe, but costs will trend down in second half of the year.

The next several months will be instrumental for the Company. In the second quarter, our Board approved an incremental $50 million of capital earmarked for primary Cardium development. The increased budget sets the stage for growth as we embark on focused Willesden Green development and look to add meaningful light oil volumes into 2019. This production build will position Obsidian Energy to capitalize on strong commodity prices as we roll out of our 2018 hedge book, and see a meaningful uptick in cash flow from organic growth.  

We believe the investment community is beginning to recognize that the stage is set for our underlying business to perform very well. We look forward to previewing our preliminary 2019 plans and long term inventory potential at our fall Investor Day and providing an update on our drilling activities with third quarter results."

Financial and Operating Highlights


Three months ended June 30

Six months ended June 30


2018

2017

% change

2018

2017

% change

Financial (millions, except per share amounts)









Funds flow from operations (1)

$

32

$

43

(26)

$

67

$

100

(33)


Basic per share (1)


0.06


0.09

(33)


0.13


0.20

(35)


Diluted per share (1)


0.06


0.09

(33)


0.13


0.20

(35)

Net income (loss)


(96)


(9)

        >100


(161)


18

>(100)


Basic per share


(0.19)


(0.02)

        >100


(0.32)


(0.04)

>100


Diluted per share


(0.19)


(0.02)

        >100


(0.32)


(0.04)

>100

Capital expenditures (2)

26


24

8


86


50

72

Net Debt (1)

$

408

$

387

5

$

408

$

387

5























Operations











Daily production












Light oil and NGL (bbls/d)


13,379


13,396

-


13,892


14,966

(7)


Heavy oil (bbls/d)


5,172


5,636

(8)


4,963


5,423

(8)


Natural gas (mmcf/d)


61


68

(10)


61


75

(18)

Total production (boe/d) (3)


28,697


30,436

(6)


29,068


32,655

(11)

Average sales price












Light oil and NGL (per bbl)

$

72.32

$

56.12

29

$

68.16

$

55.94

22


Heavy oil (per bbl)


46.81


31.61

48


39.45


32.37

22


Natural gas (per mcf)

$

1.62

$

3.10

(48)

$

2.24

$

3.16

(29)

Netback per boe (3)












Sales price

$

45.59

$

37.51

22

$

44.04

$

38.11

16


Risk management gain (loss)


(7.28)


2.21

>(100)


(5.73)


2.91

>(100)


Net sales price


38.31


39.72

(4)


38.31


41.02

(7)


Royalties


(4.09)


(2.67)

53


(3.40)


(2.68)

27


Operating expenses (4)


(14.47)


(16.44)

(12)


(14.66)


(16.07)

(9)


Transportation


(3.24)


(2.82)

15


(3.20)


(2.55)

25


Netback (1)

$

16.51

$

17.79

(7)

$

17.05

$

19.72

(14)

(1)

The terms "funds flow from operations" and their applicable per share amounts, "Net Debt",  and "netback" are non-GAAP measures. Please refer to the "Non-GAAP Measures" advisory section below for further details.

(2)

Includes the effect of capital carried from its partner under PROP in 2017. The benefit of carried capital expenditures from the Company's partner under the Peace River Oil Partnership ("PROP") was fully utilized in December 2017.

(3)

Please refer to the "Oil and Gas Information Advisory" section below for information regarding the term "boe".

(4)

Operating costs per boe is presented excluding the impact of carried operating expenses. The benefit of carried operating expenses from the Company's partner under PROP was fully utilized in December 2017

 

  • Funds Flow from Operations ("FFO") for the second quarter of 2018 was $32 million, a decrease of nine percent from the first quarter of 2018. FFO gains from higher oil prices were offset by realized risk management losses, volatile crude oil differentials and lower production. Realized risk management losses for the quarter totaled $7.28 per boe compared to $4.20 per boe in the first quarter of 2018.

  • Second quarter production averaged 28,697 boe per day, a decrease of three percent relative to first quarter 2018. We planned major turnarounds in the quarter at our Crimson Lake and Lodgepole facilities, which were executed on time and on budget. Production was slightly behind overall estimates due to lower rates from our first quarter Mannville and PCU#9 programs.

  • Average liquids sales prices in the second quarter were $65.21 per boe, excluding the impact of hedging activities. Realized heavy oil pricing in the quarter was $46.81 per bbl, a $15.47 per bbl increase relative to the first quarter while benchmark WCS pricing increased by $14.36 per bbl. This reflects our flexible marketing strategy in the Peace River area whereby we sell into 10 different sales points with various benchmark prices independent of WCS. We also signed a rail agreement for 1,000 bbl per day for the second half of 2018 which maintains our flexibility in the area going forward.

  • Average natural gas sales prices were $1.62 per mcf, excluding the impact of hedging activities. Realized gas pricing exceeded AECO benchmark pricing as the Company continued to benefit from its Ventura marketing arrangement.

  • Second quarter operating costs totaled $14.47 per boe, a 12 percent decrease from the $16.44 per boe in the comparable period of 2017. Current period operating costs were increased by higher power prices and planned turnaround and maintenance activities in the Cardium, offset by decreases in trucking costs and workovers. We expect operating costs to trend lower in the second half of 2018.

  • Invested $26 million of development capital expenditures, which focused on bringing wells on production from our first quarter development program, spending on our gas gathering infrastructure to satisfy the requirements under Alberta Energy Regulator ("AER") Directive 84 in Peace River and lease construction for our second half development program. Remaining 2018 development capital is split approximately evenly between the third and fourth quarter.

  • Net Debt of $408 million at June 30, 2018 is relatively unchanged from $407 million at March 31, 2018. Net debt includes $326 million drawn on our revolving credit facility and $79 million of senior notes. The Company paid US$24 million of Senior Note Maturities in the quarter, utilizing the revolving credit facility.

  • Executed several dispositions of existing third-party royalty interests totaling approximately $9 million in proceeds. Subsequent to the quarter, we disposed of additional existing third-party royalty interests totaling approximately $5 million in proceeds. There is a negligible production impact associated with the dispositions.

  • Subsequent to the quarter, the Company received over $12 million of insurance recoveries related to previously paid legal defense expenditures.

  • Subsequent to June 30, 2018, the Company entered into an agreement in principle regarding a recent legal claim related to a covenant provided on a predecessor company's long-term office lease, which was assumed by a third party that subsequently filed for creditor protection. The lease related to space outside of Penn West Plaza. Under the terms of the settlement, the Company will pay $13 million over three years as follows: 2018 - $4 million, July 2019 - $5 million and July 2020 - $4 million. The settlement was recorded within "Restructuring" on the Consolidated Statement of Income (Loss), and will settle the outstanding claim.

  • Subsequent to the quarter, one of the Company's major gas shippers discontinued the requirement to post a $4 million Letter of Credit ("LC") due to the improved financial position and outlook for the Company. This is an approximate 30 percent reduction in total outstanding LC's which improves go forward liquidity.

  • We continue to have ongoing dialogue with China Investment Corporation ("CIC") regarding a potential sale of the Company's Peace River assets towards the end of the year. We remain committed to reducing debt, accelerating growth and buying back shares with any meaningful asset sale proceeds.

The table below outlines select metrics in our key development and legacy areas for the three months ended June 30, 2018 and excludes the impact of hedging:



Area

Select Metrics – Three Months Ended June 30, 2018

Production

Liquids
Weighting

Operating
Cost

Netback

Cardium(1)

18,400 boe/d

66%

$17/boe

$27/boe

Deep Basin

 1,541 boe/d

24%

$1/boe

$18/boe

Alberta Viking

 1,782 boe/d

51%

$10/boe

$25/boe

Peace River

 4,834 boe/d

99%

 $11/boe

$24/boe

Key Development Areas

26,557 boe/d

68%

$14/boe

$26/boe

Legacy Areas

2,140 boe/d

20%

$17/boe

$(4)/boe

Key Development & Legacy Areas

28,697 boe/d

65%

$14/boe

$24/boe


(1)

Includes the impact of turnaround activities in the second quarter

 

The table below provides a summary of our operated activity in the second quarter.






Number of Wells Q2 2018



Drilled

Completed

On-stream



Gross

Net

Gross

Net

Gross

Net

Cardium









Producer


0

0.0

2

1.4

3

1.9


Injector


0

0.0

3

3.0

6

6.0

Deep Basin


0

0.0

0

0.0

0

0.0

Alberta Viking


0

0.0

0

0.0

0

0.0

Peace River


1

0.6

1

0.6

1

0.6

Total


1

0.6

6

5.0

10

8.4

 

Operational Update

Our Willesden Green well brought on-stream in April is currently producing approximately 300 boe per day, with rates of 780 boe per day for the first 30 days of production and 580 boe per day for the first 60 days of production (60 percent liquids). The first three wells in our second half 2018 program are directly offsetting this well, and drilling commenced on July 30.

In Pembina, two wells in PCU#11 came on-stream in April. With rates of 200 boe per day per well (gross) for the first 30 days of production, these wells are meeting expectations. Our four well pad in PCU#9 came on production with expected total fluid rates but with higher water cuts. Pad production for July is behind expectations at approximately 375 boe per day, and infrastructure optimization work is ongoing to debottleneck the area. We are confident in the significant running room throughout our Pembina acreage and look forward to presenting the long term inventory potential of the assets.

While wet weather slowed the post breakup start in Willesden Green by a few days, we are currently running one rig in the area. We drilled our sole Mannville well on route south to our Cardium program, which was rig released on July 28 and will be fracked in early-August. We also participated in a non-operated Mannville well which is expected to come online in the third quarter.

Our second half 2018 Willesden Green program is comprised of 15 horizontal drills off six multi-well pads. The average lateral length is approximately 1.5 miles per well, and all are within close proximity of our successful first half program. The first rig will drill a three well pad on the west side of the North Saskatchewan River in early August, moving to the eastern flank of the play later in the year. A second rig will begin drilling on the east side of the river in mid-September, and we plan to run both rigs until the 2019 break-up season. We plan to have 5 wells on production by the end of December, with the remaining wells coming on production early 2019. We have also kicked off surface acquisition and licensing process for a material 2019 program and are well positioned for a consistent pace of development throughout the year and beyond. We will provide additional detail on our drilling plans, inventory and expected growth wedge with our fall Investor Day.

In Peace River, our first half program continues to exceed expectations. The four wells had average peak rates above 500 bbl per day, and production over the first 90 days has averaged 400 bbl per day per well (gross). As a result of this performance and the economics of future wells in the current commodity price environment, we have elected to re-allocate capital from our scheduled Alberta Viking program to four additional Peace River wells. The wells will be drilled for approximately the same capital cost net to Obsidian Energy and are expected to come on production in the fourth quarter.

The Peace River joint industry gas gathering system and gas plant is proceeding on schedule, and we expect to have the system on-stream well in advance of the September 30, 2018 AER Directive-84 regulatory deadline. Commissioning of the non-operated plant started in late July and all Peace River solution gas will be online and delivering to the plant by mid-September. Spending increased by approximately $5 million, due to construction cost overruns as plans were finalized for the gathering system and plant.

Current Hedging Position

No hedges were added recently as we are already at approved levels for the next 12 months. With the business freeing up from one-time costs in 2018 and potential dispositions impacting both debt and production levels next year, we do not expect to add incremental 2019 hedges at this time. Currently, the Company has the following crude oil hedges in place:


Q3 2018

Q4 2018

Q1 2019

Q2 2019

Q3 2019

WTI $USD

$50.05

$49.78

$50.02

$56.53

$57.00


bbl/day

8,000

8,000

3,000

2,000

1,000

WTI $CAD

$71.04

$71.04

$67.88

$68.58

-


bbl/day

4,000

4,000

6,000

4,000

-

Total







bbl/day

12,000

12,000

9,000

6,000

1,000

 

 Additionally, the Company has the following foreign exchange contracts in place:

  • 2018 foreign exchange revenue swaps at an average of 1.268 on notional US$9 million per month;
  • 2018 foreign exchange revenue collars at an average of 1.210 – 1.272 on notional US$2 million per month;
  • Q1 2019 foreign exchange revenue swaps at an average of 1.300 on notional US$2 million per month;

Currently, the Company has the following natural gas hedges in place:


Q3 2018

Q4 2018

AECO $CAD

$2.67

$2.67


mcf/day

17,100

15,200

Ventura $USD (1)

$2.79

$2.79


mcf/day

7,500

7,500

Total




mcf/day

24,600

22,700

(1)

Through the third quarter of 2020, the Company has an agreement in place to sell 15 mmcf per day of natural gas at the Ventura index price less the cost of transportation from AECO. Recent transportation deductions for the Company to bring product to the Ventura market have been approximately $0.55 per mcf.

 

Management Changes

The Company is pleased to announce that Mr. Aaron Smith has joined the Company as Vice President, Development.

Mr. Smith has over 20 years of engineering expertise across a broad range of technical and leadership roles. Most recently, Mr. Smith held the position of Vice President, Production at a diversified oil and natural gas company based in Calgary. Prior to that, Mr. Smith held various management positions overseeing major development campaigns in Western Canada, successfully executing horizontal drilling programs targeting liquids rich formations such as the Cardium. Mr. Smith's technical expertise and leadership capabilities will prove critical as the Company fast tracks Cardium development with a repeatable, low cost approach.

The Company also announces two additional management changes. Mr. Mark Hodgson has transitioned to the role of Vice President, Operations and E&P Services, and Mr. Andrew Sweerts has assumed the role of Vice President, Business Development and Commercial.

Full Year 2018 Guidance

Our Total Capital Expenditure Guidance reflects the Peace River and Alberta Viking drilling and regulatory spend updates noted above:




Capital Category

# of Operated Wells

Net Capital

Cardium

24 Producers

$101 million

Deep Basin

2 Producers

$7 million

Peace River

8 Producers

$14 million

Alberta Viking

0 Producers

$0 million

Existing Wellbore Optimization

>50 Projects

$14 million

Total Development

34 Producers

$136 million

Regulatory Directive 84 Requirements


$19 million

Infrastructure & Corporate Capital


$25 million

Total E&D Capital Expenditures


$180 million

Decommissioning Expenditures


$10 million

Total Capital Expenditures


$190 million

 

2018 production and operating cost guidance is unchanged:


2018 Annual Guidance

Production

29,000 to 30,000 boe per day

Production Growth Rate (1)

5%

Operating Costs

$13.00 - $13.50 per boe

General & Administrative

$2.00 - $2.50 per boe



(1)

Relative to full year 2017 production, adjusted for all 2017 & 2018 A&D, of 28,000 boe per day

 

Fall 2018 Investor Day

The Company will be webcasting an Investor Day presentation later this fall. The presentation will offer the investment community a technical asset overview and preliminary corporate guidance for 2019. Webcast details will be disseminated at a later date.

Second Quarter 2018 Financial Results Conference Call Details

A conference call will be held to discuss the results at 6:30 a.m. MST (8:30 a.m. EST) on August 2, 2018.

To listen to the conference call, please call 647-427-7450 or 1-888-231-8191 (toll-free). This call will be broadcast live on the Internet and may be accessed directly at the following URL:

https://event.on24.com/wcc/r/1791004/DC2D21D21A48076B2901BDEE400E9328

A digital recording will be available for replay two hours after the call's completion, and will remain available until August 16, 2018, 21:59 Mountain Time (23:59 Eastern Time). To listen to the replay, please dial 416-849-0833 or 1-855-859-2056 (toll-free) and enter Conference ID 6083229, followed by the pound (#) key.

An updated corporate presentation has been added to Obsidian Energy's website at www.obsidianenergy.com.

Confirms Filing of Year-End Disclosure Documents

On March 7, 2018, Obsidian Energy filed its audited Consolidated Financial Statements for the year ended December 31, 2017 and related Management's Discussion and Analysis with Canadian securities regulatory authorities. Obsidian Energy has also filed its Annual Information Form for the year ended December 31, 2017, which includes the disclosure and reports relating to reserves data and other oil and gas information required pursuant to National Instrument 51-101 on that date. Obsidian Energy's Annual Report on Form 40-F for the year ended December 31, 2017 was filed on March 8, 2018, with the U.S. Securities and Exchange Commission pursuant to its rules and regulations at that time.

Copies of these documents may be obtained electronically via www.sedar.com and www.sec.gov/edgar.shtml (for the Form 40-F) or through Obsidian Energy's website at www.obsidianenergy.com. Hard copies of Obsidian Energy's audited Consolidated Financial Statements and related MD&A are also available upon request, free of charge, by contacting our Investor Relations group or by requesting them through our website.

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.

Abbreviations

Oil

Natural Gas

bbl

barrel or barrels

Mcf

thousand cubic feet

bbl/d

barrels per day

MMcf

million cubic feet

Mbbl

thousand barrels

Bcf

billion cubic feet

MMbbl

million barrels

Mcf/d

thousand cubic feet per day

boe/d

barrels of oil equivalent per day

MMcf/d

million cubic feet per day

 

Non-GAAP Measures

Certain financial measures including Funds Flow from Operations, Funds Flow from Operations per share-basic, Funds Flow from Operations per share-diluted, netback and net debt included in this press 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. Funds flow from Operations is cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures and office lease settlements which also excludes the effects of financing related transactions from foreign exchange contracts and debt repayments/ pre-payments and is representative of cash related to continuing operations. Funds Flow from Operations 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 Funds Flow from Operations to its nearest measure prescribed by IFRS. Netback is the per unit of production amount of revenue less royalties, operating expenses, transportation and realized risk management gains and losses, and is used in capital allocation decisions and to economically rank projects. See "Financial and Operational Highlights" above for a calculation of the Company's netbacks. Net debt includes long-term debt and includes the effects of working capital and all cash held on hand.

Calculation of Funds Flow from Operations

(millions, except per share amounts)

Three months ended

June 30

Six months ended

June 30

2018

2017

2018

2017

Cash flow from operating activities

$

(20)

$

19

$

37

$

57

Change in non-cash working capital


26


14


(6)


16

Decommissioning expenditures


1


3


3


7

Office lease settlements


4


4


9


8

Settlements of normal course foreign exchange contracts

-


(8)


-


(8)

Realized foreign exchange loss – debt maturities

8


1


8


4

Carried operating expenses (1)

-


6


-


10

Restructuring charges – cash portion

7


4


8


6

Other expenses

6


-


8


-

Funds flow from operations

$

32

$

43

$

67

$

100










Per share










Basic per share

$

0.06

$

0.09

$

0.13

$

0.20


Diluted per share                                              

$

0.06

$

0.09

$

0.13

$

0.20

(1)  The benefit of carried operating expenses from the Company's partner under PROP was fully utilized in December 2017.

 

Forward-Looking Statements

Certain statements contained in this document constitute forward-looking statements or information (collectively "forward-looking statements"). 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: the opex costs will trend down in the second half of the year; that the increased budget will lead to development and meaningful light oil volumes into 2019, and the production growth will position the Company to capitalize on strong commodity prices as we roll out of our 2018 hedge book, and see a meaningful uptick in cash flow from organic growth; that we will conduct an investor day in the fall and provide an update on activities at that time and that it will be webcasted; that the Company will settle the long-term office lease claim with the payments and timing set forth and that it will settle the outstanding claim; that we continue to have discussions with CIC regarding a sale of the Peace River asset towards the end of the year; that we remain committed to reducing debt, accelerating growth and buying back shares with any meaningful asset sale proceeds; that the investment community is beginning to recognize that the stage is set for our underlying business to perform very well; that the rail contracts maintains our marketing flexibility in the area going forward; our fracking expectations for the future in the Mannville; that there is significant running room throughout Pembina; our drilling schedule and location expectations;  our expectations for drilling costs and production timing for certain wells;  that we expect to have the joint industry gas gathering system on-stream well in advance of the AER Directive-84 regulatory deadline; that we do not expect to add incremental 2019 hedges at this time.

With respect to forward-looking statements contained in this document, we have made assumptions regarding, among other things that we do not dispose of any material producing properties other than stated herein; our ability to execute our long-term plan as described herein and in our other disclosure documents and the impact that the successful execution of such plan will have on our Company and our shareholders; that the current commodity price and foreign exchange environment will continue or improve; future capital expenditure levels; 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 crude oil, natural gas liquids and natural gas production levels; 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 weather, 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 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 we believe 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 we will not be able to continue to successfully execute our long-term plan in part or in full, and the possibility that some or all of the benefits that we anticipate will accrue to our Company and our securityholders as a result of the successful execution of such plans do not materialize; the possibility that we are unable to execute some or all of our ongoing asset disposition program on favourable terms or at all; 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); and the other factors described under "Risk Factors" in our Annual Information Form and described in our public filings, available in Canada at www.sedar.com and in the United States at www.sec.gov. Readers are cautioned that this list of risk factors should not be construed as exhaustive.

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 any forward-looking statements. The forward-looking statements contained in this document are expressly qualified by this cautionary statement.

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SOURCE Obsidian Energy Ltd.

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