Obsidian Energy Announces Year End 2017 Financial and Operational Results and Proposed Common Share Consolidation

CALGARY, March 7, 2018 /CNW/ - 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 year ended December 31, 2017. All figures are in Canadian dollars unless otherwise stated. Obsidian Energy's Management Discussion and Analysis ("MD&A") dated March 6, 2018 and audited financial statements for year end 2017 can be found on our website at www.obsidianenergy.com. The documents will also be filed on SEDAR and EDGAR in due course.

"We are pleased to report an excellent fourth quarter and full year results," commented David French, President & CEO. "2017 was a breakthrough year for the Company. Notwithstanding a challenging external environment, we consistently delivered on our operational objectives, beat our production guidance, and underpinned the shallow decline cash flows of the business. We grew our A&D adjusted production base in 2017 by approximately 10 percent, kick-starting a disciplined growth story, even while spending less capital and maintaining our focus on balance sheet strength.

We continue to deliver strong results across our field operations, specifically within our Cardium acreage. Off the back of these results, we have found ways to put additional dollars to work in the highly economic Willesden Green fairway. The success of our 2017 program sets us up well for 2018 and beyond. We see many reasons to be excited for the future of Obsidian Energy."

Delivered Year over Year Production Growth of 10 Percent and Full Year 2017 Production above Guidance

Full year 2017 production was 31,723 boe per day, above the high end of our guidance range of 30,500 – 31,500 boe per day. Ongoing waterflood and our shallow base decline, combined with solid execution of our second half development program drove the outperformance.

Fourth quarter 2017 production was 31,447 boe per day, 10 percent higher than the previous year, adjusted for A&D. Relative to the third quarter, we grew total production and liquids production by four percent. This marks another quarter of consistent production delivery and advances our operational momentum into the first quarter of 2018.

Total 2017 Capital Expenditures Beat Guidance, Including Cardium Drilling Acceleration

Full year 2017 capital was $157 million, including decommissioning expenditures, below our guidance of $160 million. Fourth quarter capital was $44 million, including decommissioning expenditures, highlighted by our first foray into the Deep Basin and bringing on seven Cardium producing wells. We also executed a December start-up of five of our 2018 Cardium wells, while delaying some minor Cardium injector capital into 2018.

Operating Expenses were Comfortably Within Guidance Range

Full year and fourth quarter 2017 operating expenses were $13.40 per boe and $12.50 per boe, respectively, net of carried expenses. Growing production volumes offset higher maintenance and turnaround activity, driving a full year number that was comfortably within our guidance range of $13.00 - $13.50 per boe.

As expected, our Peace River operating cost carry was fully utilized in December. The Company is well positioned for continuous operating cost improvement driven by a dedicated push for efficiency and our recent disposition of high cost legacy assets. As a result, we expect our cost basis, excluding any carry impact, to decrease year over year.

Five Percent Higher Funds Flow from Operations versus 2016, Despite 42 Percent Less Production

Full year Funds Flow from Operations was $192 million, up from $182 million in 2016. Despite meaningful disposition activity in 2016 that reduced production by 42 percent, the increase in FFO was supported by higher crude oil prices and more than $100 million less of gross operating expenses.

Fourth quarter Funds Flow from Operations was $52 million, up from $40 million in the third quarter. Higher benchmark commodity prices, robust field realizations and strong production volumes drove the cash flow performance. Our light oil realizations were in line with benchmark expectations, while heavy oil and natural gas realizations were higher than benchmark pricing.

Heavy oil realized pricing increased by 26 percent relative to the third quarter, compared to a 15 percent increase in Canadian Dollar heavy oil benchmark pricing. Our rail transportation and alternative price basis sales points reinforced the strong realized pricing in the quarter.

A portion of our natural gas volumes are sold relative to a US Midwest market at Ventura. In the fourth quarter of 2017, Obsidian Energy had the benefit of selling approximately 30 mmcf per day into this market. The premium we received at Ventura contributed nearly $5 million additional to Funds Flow from Operations and was mainly due to a short term price spike, where our gas realizations averaged approximately $5.00 per mcf above AECO pricing in December. While a portion of our pricing arrangement ended in 2017, we retain 15 mmcf per day of Ventura marketing commitments through the third quarter of 2020.

Demonstrating Cardium Drilling Consistency; Well Results Command Additional Investment

Following on our recent four well pad in Willesden Green, initial rates from our two 2018 locations are exceeding expectations. The two well pad came on stream February 20 and has averaged approximately 900 boe per day through March 4, implying an average of 450 boe per day per well (88 percent liquids) over that timeframe. These strong initial results demonstrate the regular success we have had optimizing wellbore placement in the bioturbated interval and proven completion design.

We plan to add three wells to our 2018 Willesden Green Cardium program. We expect one of those wells to come on stream in the second quarter, and the next two wells to come on stream early in the fourth quarter. We will fund these wells by reducing our Alberta Viking, Deep Basin and standalone waterflood capital outlays by a total of $9 million.

Second Half Optionality Remains to Increase Returns and Enhance 2019 Outlook

We have the operational flexibility to adjust our capital program as Alberta commodity prices allow. We will continue to be prudent with respect to balance sheet management, and will not call on debt to fund additional development. As next quarter's pricing plays out and we get further certainty on our full year cash flow profile, we will fine tune our capital program for the second half of the year.

Financial and Operating Highlights

		Three months ended December 31					Year ended December 31
		2017		2016		% change	2017		2016		% change
Financial (millions, except per share amounts)
Funds Flow from Operations ^(1)		$	52	$	48	8	$	192	$	182	5
	Basic per share ^(1)		0.10		0.10	-		0.38		0.36	6
	Diluted per share ^(1)		0.10		0.10	-		0.38		0.36	6
Net loss			(58)		(232)	(75)		(84)		(696)	(88)
	Basic per share		(0.12)		(0.46)	(74)		(0.17)		(1.39)	(88)
	Diluted per share		(0.12)		(0.46)	(74)		(0.17)		(1.39)	(88)
Capital expenditures ^(2)			37		50	(26)		141		82	72
Net Debt		$	383	$	502	(24)	$	383	$	502	(24)
Operations
Daily production
	Light oil and NGL (bbls/d)		14,288		15,803	(10)		14,236		26,059	(45)
	Heavy oil (bbls/d)		5,247		5,493	(4)		5,387		8,750	(38)
	Natural gas (mmcf/d)		71		103	(31)		73		121	(40)
Total production (boe/d)^(3)			31,447		38,481	(18)		31,723		54,990	(42)
Average sales price
	Light oil and NGL (per bbl)	$	62.70	$	52.34	20	$	56.84	$	43.74	30
	Heavy oil (per bbl)		38.12		27.09	41		33.27		21.22	57
	Natural gas (per mcf)	$	2.51	$	2.98	(16)	$	2.81	$	2.14	31
Netback per boe ^(3)
	Sales price	$	40.55	$	33.33	22	$	37.58	$	28.83	30
	Risk management gain		-		4.27	(100)		2.02		5.03	(60)
	Net sales price		40.55		37.60	8		39.60		33.86	17
	Royalties		(2.64)		(1.26)	>100		(2.57)		(1.08)	>100
	Operating expenses ^(4)		(12.50)		(14.05)	(11)		(13.40)		(13.18)	2
	Transportation		(2.41)		(1.62)	49		(2.48)		(1.72)	44
	Netback ^(1)	$	23.00	$	20.67	11	$	21.15	$	17.88	18

	(1)	The terms "funds flow from operations" and their applicable per share amounts, "netback", and "net debt" are non-GAAP measures. Please refer to the "Non-GAAP Measures" advisory section below for further details.
	(2)	Includes the benefit of capital carried by partners.
	(3)	Please refer to the "Oil and Gas Information Advisory" section below for information regarding the term "boe".
	(4)	Includes the benefit of carried operating expenses from its partner under the Peace River Oil Partnership of $6 million or $1.89 per boe (2016 – $5 million or $1.30 per boe) for the three months ended and $21 million or $1.78 per boe (2016 – $15 million or $0.75 per boe) for the year ended on a combined basis.

• Funds Flow from Operations for the fourth quarter was $52 million, reflecting stronger realized pricing primarily due to an increase in US$ WTI and Ventura pricing. Full year Funds Flow from Operations was $192 million, a five percent increase relative to 2016.
  
  
• Average liquids sales prices in the fourth quarter were $56.10 per boe and average natural gas sales prices were $2.51 per mcf. Strong realized pricing in the quarter is a result of our value adding marketing activities, specifically on heavy oil and natural gas.
  
  
• Fourth quarter operating costs were $12.50 per boe, net of carried expenses. As expected, operating costs were consistent with the third quarter and around $2 per boe below first half 2017, which had higher maintenance and turnaround activity.
  
  
• Invested $37 million of development capital expenditures across our key development areas and $7 million of decommission expenditures in the fourth quarter. Full year development capital and decommission expenditures were $141 million and $16 million, respectively.
  
  
• Total Net Debt was $383 million at December 31, 2017, $119 million lower than the prior year. Net debt includes $253 million drawn on our revolving credit facility and $106 million of Senior Notes.

The table below outlines select metrics in our key development and legacy areas for the three months ended December 31, 2017 and excludes the impact of hedging:

Area		Select Metrics – Three Months Ended December 31, 2017
		Production	Liquids Weighting	Operating Cost	Netback
Cardium		18,190 boe/d	64%	$13/boe	$28/boe
Deep Basin		1,356 boe/d	31%	$1/boe	$28/boe
Alberta Viking		2,508 boe/d	54%	$11/boe	$23/boe
Peace River^(1)		4,963 boe/d	99%	$3/boe	$30/boe
Key Development Areas		27,018 boe/d	68%	$12/boe	$28/boe
Legacy Areas^(2)		4,429 boe/d	25%	$28/boe	$(6)/boe
Key Development & Legacy Areas		31,447 boe/d	62%	$13/boe	$23/boe

(1)	Net of carried operating costs.
(2)	A portion of Legacy Areas are classified as Assets Held for Sale. Refer to January 31, 2018 press release for more details

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

			Number of Wells Q4 2017
			Drilled		Completed		On stream
			Gross	Net	Gross	Net	Gross	Net
Cardium
	Producer		6	5.8	4	4.0	7	6.7
	Injector		0	0.0	5	4.5	5	4.5
Deep Basin			0	0.0	0	0.0	2	1.7
Alberta Viking			0	0.0	0	0.0	4	4.0
Peace River			4	2.2	5	2.8	5	2.8
Total			10	8.0	14	11.3	23	19.7

In the Cardium, we brought on production three PCU #9 wells and five associated injectors. In Willesden Green, we brought on our four well pad late in December but due to extreme cold weather and third party pipeline curtailment, all four wells were not running at the same time until January 3, 2018.

We brought on the final two wells of our three well Mannville program, our first foray into the Deep Basin.  These three wells contributed approximately 1,300 boe per day to the quarter (net to OBE) with strong liquids yields averaging 55 bbl/mmcf (135 bbl/d per well).

The second half 2017 Peace River program is currently producing approximately 2,100 boe per day gross production (1,200 boe per day net working interest). All 12 wells were on production by mid-December 2017. Per well results are consistent with expectations and reconfirm the upside we see within the heart of our acreage.

Our second half 2017 Alberta Viking program is fully optimized and all 10 wells were on production early in the fourth quarter. The wells displayed initial rates above expectations, and the total program reached a peak rate of approximately 1,900 boe per day in the quarter. The wells averaged approximately 1,200 boe per day over the quarter.

Operational Update

Our four well pad in Willesden Green Cardium was on-stream as of January 3, 2018. IP30 for the wells averaged nearly 650 boe per day (87 percent liquids). The pad is currently producing approximately 1,200 boe per day. We expect injection support to mitigate decline rates and meaningfully enhance the ultimate recovery from the wells. Our two well pad in Willesden Green, approximately 20 kilometers east, was on stream February 20, 2018. The pad has averaged approximately 900 boe per day since the wells came on production, implying an average of 450 boe per day per well over that timeframe. We have elected to add three additional Willesden Green Cardium wells to our 2018 development plans, within close proximity to our recent program. The wells will be funded from other areas of our development program.

We have drilled six and completed four wells in Pembina, which are accompanied by six low cost injector conversions for waterflood support. We expect these wells to be on production early in the second quarter.

We recently finished drilling a two-mile Mannville (Falher) well which is expected to be on stream at the end of March. Initial pressure metrics and production tests look encouraging, and we expect the well to be highly economic due to our owned infrastructure processing advantage and high liquids content. We plan to drill another Deep Basin opportunity in the second half of 2018.

Total 2018 capital expectations for Peace River are down slightly, and we shifted to a four well program from five wells. We believe four wells with varying lateral legs and lengths can deliver the same production wedge as originally anticipated. We are currently on the third of four wells and preliminary drilling and production test results are consistent with expectations.

Our second half Alberta Viking program is highly economic, targeting structural lows to maximize light oil productivity. The program will be drilled in the third quarter.

Updated Hedging Position

We continued our active hedging program and extended our hedge book into 2019. Currently, the Company has the following crude oil hedges in place:

		Q1 2018	Q2 2018	Q3 2018	Q4 2018	Q1 2019	Q2 2019	Q3 2019
WTI $USD		$50.82	$50.00	$50.05	$49.78	$50.02	$56.53	$57.00
	bbl/day	7,000	7,000	8,000	8,000	3,000	2,000	1,000
WTI $CAD		$71.03	$71.03	$71.04	$71.04	$67.88	$68.58	-
	bbl/day	5,000	5,000	4,000	4,000	6,000	4,000	-
Total
	bbl/day	12,000	12,000	12,000	12,000	9,000	6,000	1,000

Additionally, the Company has the following foreign exchange contracts in place for 2018:

• Foreign exchange swaps on revenues at an average of 1.268 on notional US$9 million per month
• Foreign exchange collar on revenues at an average of 1.210 – 1.272 on notional US$2 million per month
• Foreign exchange swaps on May 2018 debt maturities at an average of 1.233 on US$15 million

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

			Q1 2018	Q2 2018	Q3 2018	Q4 2018
AECO $CAD			$2.83	$2.72	$2.67	$2.67
	mcf/day		28,400	22,700	17,100	15,200
	Ventura $USD ^(1)		$2.79	$2.79	$2.79	$2.79
	mcf/day		7,500	7,500	7,500	7,500
	Total
	mcf/day		35,900	30,200	24,600	22,700

(1)

Until the third quarter of 2020, the Company has an agreement in place to sell 15 mmcf per day at the Ventura index price less the cost of transportation from AECO. Ventura pricing in the fourth quarter averaged approximately $4.00 per mcf.  Recent transportation deductions for the Company to bring product to the Ventura market have been approximately $0.55 per mcf.

2018 Guidance Summary

Our total 2018 guidance remains 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

Our Total Capital Expenditure Guidance remains the same, but accounts for the reallocation as noted below:

Capital Category	# of Operated Wells	Net Capital
Cardium	11 Producers	$51 million
Deep Basin	2 Producers	$7 million
Peace River	4 Producers	$8 million
Alberta Viking	4 Producers	$6 million
Existing Wellbore Optimization	>50 Projects	$14 million
Total Development	21 Producers	$86 million
Regulatory Directive 84 Requirements		$14 million
Infrastructure & Corporate Capital		$25 million
Total E&D Capital Expenditures		$125 million
Decommissioning Expenditures		$10 million
Total Capital Expenditures		$135 million

Proposed Share Consolidation

Obsidian Energy will propose a consolidation of the Company's outstanding common shares at the upcoming Annual and General Meeting. Obsidian believes that a share consolidation will reduce its outstanding equity float to a level more suitable to the current size of the Company, appeal to a broader universe of investors and reinforce compliance with the New York Stock Exchange's minimum share price listing requirement. The proposed 3:1 ratio balances improved marketability for the shares, reduced transaction costs for lot trading and sufficient liquidity going forward.

Shareholders will be asked to pass a special resolution that will authorize the Board of Directors to direct the Company to amend our articles, in order to consolidate (or reverse split) the Company's issued common shares into a lesser number of issued common shares on the basis of three (3) old common shares for one (1) new common share. The Board of Directors will retain the discretion to revoke the share consolidation resolution and elect not to proceed with the filing of the articles of amendment and the implementation of the share consolidation.

A share consolidation will be subject to approval of the Toronto Stock Exchange and the New York Stock Exchange. Further information regarding the potential share consolidation and timing of the Annual and General Meeting will be included in the Company's Management Information Circular to be disseminated later this spring.

Year-End 2017 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 March 7, 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:

http://event.on24.com/wcc/r/1602755-1/F3B454234B7BA6D9E327EEC65E28F03E

A digital recording will be available for replay two hours after the call's completion, and will remain available until March 21, 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 1898936, followed by the pound (#) key.

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.

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

		Year ended December 31
(millions, except per share amounts)		2017		2016
Cash flow from operating activities		$	125	$	(137)
Change in non-cash working capital			(5)		97
Decommissioning expenditures			16		11
Office lease settlements			16		4
Monetization of foreign exchange contracts			-		(32)
Settlements of normal course foreign exchange contracts			(8)		(3)
Monetization of transportation commitment			-		(20)
Realized foreign exchange loss – debt prepayments			-		191
Realized foreign exchange loss – debt maturities			6		37
Carried operating expenses ^(1)			21		15
Restructuring charges			10		19
Other expenses^(2)			11		-
Funds flow from operations		$	192	$	182
Per share – funds flow from operations
	Basic per share	$	0.38	$	0.36
	Diluted per share	$	0.38	$	0.36

(1)	The effect of carried operating expenses from the Company's partner under the Peace River Oil Partnership which came to an end in December 2017.
(2)	The Company settled the outstanding lawsuit it had with the United States Securities and Exchange Commission ("SEC") for US$8.5 million (CAD$11 million) during the fourth quarter of 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: that the MD&A and audited financial statements will be filed on our website, SEDAR and EDGAR in due course; that the success of our entire 2017 program sets us up well for 2018 and beyond and we see many reasons to be excited for  the future of Obsidian Energy; that our consistent production delivery and advances our operational momentum into the first quarter of 2018; that the Company is well positioned for continuous operating cost improvement driven by a dedicated push for efficiency and our recent disposition of high cost legacy assets in the Peace River area and as a result, we expect our cost basis, excluding any carry impact to  decrease year over year; that certain of our natural gas volumes will be sold into Ventura through a commitments through the fourth quarter of 2020; the changes to be made in our drilling program for 2018, expectations for when they will come on stream, possible economics, liquids weighting and how they will be funded; that we have the operational flexibility to adjust our capital program as Alberta commodity prices allow; that we will continue to be prudent with respect to balance sheet management, and will not call on debt to fund additional development; that as next quarter's pricing plays out and we get further certainty on our full year cash flow profile, we will revisit our capital program for the second half of the year; that we expect injection support to mitigate decline rates and meaningfully enhance the ultimate recovery from the wells; our hedging position for both production and foreign exchange contracts; our updated capital spending plans in 2018; expected full year production; our expected production growth rate; and expected ranges for 2018 operating costs and general and administrative costs; that the Company will propose a consolidation of the Company's outstanding common shares at the upcoming Annual and General Meeting; the Company's belief that a share consolidation will reduce its outstanding equity float to a level more suitable to the current size of the Company, appeal to a broader universe of investors and reinforce  compliance with the New York Stock Exchange's minimum share price listing requirement; that the proposed 3:1 ratio balances improved marketability for the shares, reduces transaction costs for lot trading and provide sufficient liquidity going forward; that shareholders will be asked to pass a special resolution at the Annual General Meeting in connection with the share consolidation; that the Board of Directors will retain the discretion to revoke the share consolidation resolution and elect not to proceed with the filing of the articles of amendment and the implementation of the share consolidation; and that the Company will disseminate its Management Information Circular later this Spring.

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; 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.

SOURCE Obsidian Energy Ltd.

OBSIDIAN ENERGY: Suite 200, 207 - 9th Avenue SW, Calgary, Alberta T2P 1K3, Phone: [phone], Fax: [phone], Toll Free: 1-866-693-2707, Website: www.obsidianenergy.com; Investor Relations: Toll Free: 1-888-770-2633, E-mail: [email protected]

Related Links

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