Obsidian Energy Releases 2018 Reserves Results, Announces Company Update and Revises 2019 Guidance

CALGARY, Feb. 11, 2019 /CNW/ - OBSIDIAN ENERGY LTD. (TSX – OBE, NYSE – OBE.BC) ("Obsidian Energy", the "Company", "we", "us" or "our") is pleased to release its year-end 2018 independent reserves evaluation and provide Company updates on our recent drilling results, marketing and hedging portfolio, 2019 development and guidance revisions.

2018 Year-End Reserves Summary

The Company is pleased to present the results of its year-end 2018 independent reserves evaluation, prepared by Sproule Associates Limited ("Sproule").

2018 marks the second year in a row that Obsidian Energy has achieved greater than 100 percent reserve replacement on proved plus probable ("2P") and total proved reserves ("1P"). This increase is a direct result and recognition of the performance of our 2018 Cardium drilling program with a 1P and 2P reserve replacement in the Cardium of approximately 150 and 140 percent respectively. Our Cardium assets in Willesden Green continue to perform with 16 additional undeveloped locations added to our book's primary Cardium count. The Company also continues to see benefits from its optimization and decline mitigation projects with an average three year proved developed producing ("PDP") decline of 15.8 percent. We are excited about the future development opportunities, particularly in our Cardium assets, which will allow us to create long term value for our shareholders.

Reserve Highlights:

• Replaced 102 percent of 2018 production on a 2P reserves basis, 109 percent on a 1P reserves basis and 66 percent on a PDP reserves basis. Excluding legacy shut-ins and economic factors, the Company replaced 94 percent of total 2018 production on a PDP reserves basis.
  
  
• Reserve replacement was driven by strong well performance of the 2018 drilling program in both the Cardium and Peace River areas. 1P reserve replacement in the Cardium is approximately 150 percent and 2P reserve replacement in both the Cardium and Peace River areas is approximately 140 percent.
  
  
• Obsidian Energy's average three-year PDP decline is 15.8 percent resulting in a reserve life index ("RLI") of approximately 8, 10 and 13 years on a PDP,1P and 2P basis respectively.
  
  
• Through the disposition of natural gas weighted production and shutting in high cost gas weighted legacy production in 2018, our 2P liquids weighting increased by two percent, to 69 percent total liquids and our PDP liquids weighting increased by three percent, to 67 percent total liquids.
  
  
• Obsidian Energy added 16 net undeveloped locations to its primary Cardium count. Our total undeveloped reserve book remains conservative and highly achievable, with 175 total net locations booked, including 126 net locations in the Cardium.
  
  
• 2P finding and development ("F&D") costs for our operated development activity in 2018 were $13.40 per boe. 2P F&D costs, including changes in future development capital, were $21.16 per boe.
  
  
• Despite $75 million of negative pricing impacts, before-tax net present value discounted at 10 percent ("NPV10") for 2P reserves, is $1.7 billion at year-end 2018, based on Sproule's commodity price forecast at December 31, 2018.
  
  
• NPV10 per share, adjusted for Net Debt, equates to approximately $2.40, $1.60 & $1.25 per share for 2P, 1P and PDP, respectively.

Cardium Drilling Program Update

All 14 wells of the second half 2018 Cardium program have been drilled and completed with 12 currently on production. Well performance on average is exceeding the updated type-curves presented at our Investor Day on November 15, 2018. The Company's focus on cost reduction has resulted in an average well cost of $3.6 million on the first 14 wells, significantly below forecasted cost estimates. The final two wells off the 5-18 pad have been fractured, with one well setting a record for the Company's longest Cardium well drilled to date at 5,290 meters of measured depth with 38 fracture stages. These two wells will be on production by mid-February.

Early rate performance of the wells is shown below. Aggregate production from the program has averaged approximately 3,620 barrels of oil per day and 4,693 boe per day in the last 30 days.

Pad	Status	Deliverability
8-9 (3 wells)	On production	Average IP30 per well: 621 boepd (76% oil); IP60 per well: 477 boepd (71% oil)
14-1 (2 wells)	On production	Average IP30 per well: 433 boepd (85% oil); IP60 per well: 338 boepd (84% oil)
4-6 (3 wells)	On production	Average IP30 per well: 527 boepd (91% oil); IP60 per well: 563 boepd (84% oil)
1-36 (2 wells)	On production	Average IP30 per well: 672 boepd (90% oil)
9-2 (2 wells)	On production	Average IP10 per well: 502 boepd (90% oil)
5-18 (2 wells)	Fracturing complete	Production expected mid-February

Marketing and Hedging Portfolio Update

In late December, the Company monetized the physical delivery contract for 15,000 mmcf per day to Northern Border Ventura for US$10.5 million or CAD$14 million. The decision to monetize the contract was due to an expansion in the forward curve spread between AECO and Northern Border Ventura gas pricing.

The recent downward swing in oil prices also allowed the Company to restructure part of its existing hedge book by removing a 1,000 barrel a day WTI swap in the third quarter of 2019 for cash to Obsidian Energy of approximately $500,000.

2019 Development and Revised Guidance

In early December, the Alberta Government announced a mandatory curtailment program ("Curtailment") to relieve excess supply of crude oil and bitumen in Western Canada. Since the announcement, there has been a meaningful contraction of Canadian differentials improving the outlook for Western Canadian producers. Obsidian Energy is supportive of these actions and views them as a near-term positive step for the energy industry in Western Canada.

In light of the Curtailment, Obsidian Energy has elected to defer a four-well pad with two Cardium wells and two Deep Basin wells to the second half of 2019. The deferral will reduce first half 2019 capital expenditures by approximately $20 million to $45 million. Our first half 2019 drilling program now consists of five Willesden Green Cardium wells which is underway with production expected near the end of March.

Based on preliminary estimates, the Company expects first quarter 2019 light and heavy oil production to be approximately 15,750 – 16,250 barrels per day net to Obsidian Energy, which reflects the curtailment requirements for the quarter. Total production for the first quarter of 2019, including natural gas liquids and natural gas is expected to be approximately 27,000 – 27,500 boe per day net to Obsidian Energy. Currently, the Company has approximately 2,200 boe per day behind pipe and if the Curtailment requirements were to be lifted or reduced, we would bring those volumes on production.

The full year 2019 optimization budget has been reduced by $3 million in favour of adding one Willesden Green Cardium well to the second half 2019 drilling program for a total of 16 Willesden Green Cardium wells and two Deep Basin wells with no changes to our full year capital estimate. The Company continues to evaluate its capital allocation decisions on an ongoing basis. At this time, we view the servicing of our credit facility and the Cardium development in Willesden Green as the most prudent use of investment dollars in our portfolio.   

Due to mandated Curtailments and the decision to shift capital into the second half of 2019, Obsidian Energy is revising its guidance for full year production and growth rates. With reduced volumes, there will be follow-on affects to operating and general & administrative cost per boe. Obsidian Energy's guidance assumes the Curtailment will remain throughout 2019 but continues to ease over the course of the year.

Production and Cost Guidance:

Metric	Previous 2019 Guidance Range	Updated 2019 Guidance Range
Production	28,000 to 29,000 boe per day	26,750 to 27,750 boe per day
Capital Expenditures including Decommissioning Expenditures	$120 MM	No change
Production Growth Rate ^(1)	3%-6%	Flat
Operating Costs	$13.00 - $13.50 per boe	$14.00 - $14.50 per boe
General & Administrative	$1.75 - $2.25 per boe	$2.00 - $2.50 per boe
(1) Relative to projected full year 2018 production (using midpoint of guidance), adjusted for shut in volumes, of 27,250 boe per day

Capital Program Details:

Capital Category	# of Wells	Net Capital
Cardium	16 Producers	$74 million
Deep Basin	2 Producers	$7 million
Non-Operated Primary Drilling	2.5 net Producers	$6 million
Existing Wellbore Optimization	>25 Projects	$5 million
Maintenance & Corporate		$16 million
Capital Expenditures		$108 million
Decommissioning Expenditures		$12 million
Total		$120 million

2018 Year-End Reserves Tables

In 2018, we engaged Sproule, an independent, qualified engineering firm, to evaluate 100 percent of our 1P and 2P reserves. Sproule conducted an independent reserves evaluation of Obsidian Energy's reserves effective December 31, 2018. This evaluation was prepared in accordance with definitions, standards, and procedures set out in Canadian Oil and Gas Evaluation Handbook ("COGEH") and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). The Sproule reserves evaluation was based on Sproule's December 31, 2018 forecast prices and costs. Reserves included below are Company gross reserves which are the Company's total working interest reserves before the deduction of any royalties and excluding any royalty interests payable to the Company. The numbers in the tables below may not add due to rounding.

Summary of Reserves

As at December 31, 2018
Reserve	Light & Medium Crude Oil	Heavy Crude Oil & Bitumen	Natural Gas Liquids	Conventional Natural Gas	Barrel of Oil Equivalent
Estimates Category	(mmbbl)	(mmbbl)	(mmbbl)	(bcf)	(mmboe)
Proved
Developed producing	33	6	6	131	66
Developed non-producing	1	0	0	3	2
Undeveloped	14	1	2	41	24
Total Proved	47	7	8	176	92
Total Probable	17	4	3	57	33
Total Proved plus Probable	64	11	11	233	125

 Reserves Reconciliation – Proved

	Light & Medium Crude Oil	Heavy Crude Oil & Bitumen	Natural Gas Liquids	Conventional Natural Gas	Barrel of Oil Equivalent
Reconciliation Category	(mmbbl)	(mmbbl)	(mmbbl)	(bcf)	(mmboe)
Total Proved
December 31, 2017	47	8	8	194	96
Extensions	2	0	1	13	5
Infill Drilling	1	0	0	3	2
Improved Recovery	0	0	0	0	0
Technical Revisions	2	0	1	19	6
Discoveries	0	0	0	0	0
Acquisitions	0	0	0	0	0
Dispositions	(1)	0	(0)	(23)	(5)
Economic Factors	0	0	(0)	(7)	(1)
Production	(4)	(2)	(1)	(22)	(11)
December 31, 2018	47	7	8	176	92

Reserves Reconciliation – Proved Plus Probable

	Light & Medium Crude Oil	Heavy Crude Oil & Bitumen	Natural Gas Liquids	Conventional Natural Gas	Barrel of Oil Equivalent
Reconciliation Category	(mmbbl)	(mmbbl)	(mmbbl)	(bcf)	(mmboe)
Total Proved Plus Probable
December 31, 2017	66	12	10	258	131
Extensions	4	0	1	18	8
Infill Drilling	1	0	0	3	2
Improved Recovery	0	0	0	0	0
Technical Revisions	(1)	0	1	14	2
Discoveries	0	0	0	0	0
Acquisitions	0	0	0	0	0
Dispositions	(1)	0	(0)	(31)	(7)
Economic Factors	0	0	(0)	(8)	(1)
Production	(4)	(2)	(1)	(22)	(11)
December 31, 2018	64	11	11	233	125

Summary of Before Tax Net Present Values

As at December 31, 2018
Net Present Value	Discount Rate
$ millions	Undiscounted	5 Percent	10 Percent	15 Percent	20 Percent
Proved
Developed producing	2,140	1,474	1,128	921	784
Developed non-producing	43	33	26	22	19
Undeveloped	592	285	140	63	17
Total Proved	2,774	1,792	1,294	1,006	820
Total Probable	1,417	674	408	282	212
Total Proved plus Probable	4,191	2,466	1,702	1,288	1,032

Future Development Capital

As at December 31, 2018
Future Development Capital
$ millions	Total Proved	Total Proved Plus Probable
2019	112	117
2020	113	131
2021	118	155
2022	127	154
2023	42	61
2024 and subsequent	0	0
Total, Undiscounted	511	618
Total, Discounted @ 10%	416	498

Summary of Pricing and Inflation Rate Assumptions

			Canadian Light		Natural Gas
	WTI		Sweet Crude		AECO-C		Exchange
As at December 31, 2018^(1)	Cushing, Oklahoma		40° API		Spot		Rate
Sproule Forecast	($US/bbl)		($Cdn/bbl)		($Cdn/MMbtu)		($US/$Cdn)
Year	2018	2017	2018	2017	2018	2017	2018	2017
Forecast
2019	63.00	65.00	75.27	74.51	1.95	3.11	0.77	0.82
2020	67.00	70.00	77.89	78.24	2.44	3.65	0.80	0.85
2021	70.00	73.00	82.25	82.45	3.00	3.80	0.80	0.85
2022	71.40	74.46	84.79	84.10	3.21	3.95	0.80	0.85
2023	72.83	75.95	87.39	85.78	3.30	4.05	0.80	0.85
2024	74.28	77.47	89.14	87.49	3.39	4.15	0.80	0.85
2025	75.77	79.02	90.92	89.24	3.49	4.25	0.80	0.85
2026	77.29	80.60	92.74	91.03	3.58	4.36	0.80	0.85
2027	78.83	82.21	94.60	92.85	3.68	4.46	0.80	0.85
2028	80.41	83.85	96.49	94.71	3.78	4.57	0.80	0.85
2029	82.02		98.42		3.88		0.80
^(1)Prices Escalate at two percent after 2029, with the exception of foreign exchange which stays flat

All figures contained in this release are in Canadian dollars unless otherwise noted.   

The financial and operating information in this press release is based on estimates and is unaudited. Some of the terms below do not have standardized meanings. Further detail can be found in the "Oil and Gas Advisory" section contained in this release. Additional reserve information as required under NI 51-101 will be included in our Annual Information Form which will be filed on SEDAR, EDGAR, and posted to our website in March. All numbers are shown prior to the impact of 2019 disposition activity unless otherwise noted.

Oil and Gas Advisory

This press release contains a number of oil and gas metrics, including "FDC", "F&D costs", and "RLI" which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods. FDC is the sum of all booked capital. F&D costs are the sum of exploration and development costs incurred in the period, plus the change in estimated FDC for the reserves category, all divided by the change in reserves during the period. F&D costs exclude the impact of acquisitions and divestitures. NPV per share, adjusted for debt, is synonymous for NAV, and is based on the present value of future net revenues discounted at 10% before tax, adjusted for unaudited net debt as at December 31, 2018. The NPV per share is divided by the number of Obsidian Energy shares outstanding as at December 31, 2018. RLI is calculated as total Company gross reserves divided by Sproule's forecasted 2019 production for the associated reserve category. Under NI 51-101, proved reserves estimates are defined as having a high degree of certainty to be recoverable with a targeted 90 percent probability in aggregate that actual reserves recovered over time will equal or exceed proved reserve estimates. For proved plus probable reserves under NI 51-101, the targeted probability is an equal (50 percent) likelihood that the actual reserves to be recovered will be greater or less than the proved plus probable reserve estimate. The reserve estimates set forth above are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.

Non-GAAP

Certain financial measures including 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. Net Debt includes long-term debt and includes the effects of working capital and all cash held on hand.

Abbreviations Contained in the Press Release

Oil and Natural Gas Liquids		Natural Gas
bbl	barrel or barrels	GJ	gigajoule
bbl/d	barrels per day	GJ/d	gigajoules per day
mbbl	thousand barrels	mcf	thousand cubic feet
mmbbl	million barrels	mmcf	million cubic feet
NGLs	natural gas liquids	bcf	billion cubic feet
mmboe	million barrels of oil equivalent	mcf/d	thousand cubic feet per day
mboe	thousand barrels of oil equivalent	mmcf/d	million cubic feet per day
boe/d	barrels of oil equivalent per day	m^3	cubic metres
		mmbtu	million British thermal units

Other
AECO	the Alberta benchmark price for natural gas.
BOE or boe	barrel of oil equivalent, using the conversion factor of 6 mcf of natural gas being equivalent to one barrel of oil.
WTI	West Texas Intermediate, the reference price paid in United States dollars at Cushing, Oklahoma for crude oil of standard grade.
API	American Petroleum Institute.
°API	the measure of the density or gravity of liquid petroleum products derived from a specific gravity.
MM$	million dollars.

Forward-Looking Statements

Certain statements contained in this press release 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 we are excited about the future development opportunities, specifically in our Cardium assets, which will allow us to create long term value for our shareholders; expectations for when certain wells will come online; our expectations for deferring certain wells, when they are expected to come online, the impact those actions have on first half 2019 expenditures and drilling program and on production dates; our expectation for first quarter 2019 light and heavy oil production, and total production net to Obsidian Energy, which reflects that curtailment requirements for the quarter; when we will bring certain volumes on after the curtailment requirements are lifted; that the Company continues to evaluate its capital allocation decisions on an ongoing basis; the updated 2019 guidance for production, capital expenditure including decommissioning expenditures, production growth grate, operating and general and administrative cost ranges; that additional reserve information, as required under NI 51-101, will be included in our Annual Information Form which will be filed on SEDAR, EDGAR and our website in March ; and our expected RLIs, FDCs.

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; the impact of Curtailment; 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); that due to Curtailment and second half capital shift, that there will be follow-on affects to operating and general & administrative cost per boe; 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.

Obsidian Energy shares are listed on both the Toronto Stock Exchange and New York Stock Exchange under the symbol "OBE" and "OBE.BC" respectively. All figures are in Canadian dollars unless otherwise stated.

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]

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