CALGARY, Aug. 9, 2017 /CNW/ - OBSIDIAN ENERGY LTD.
(TSX/NYSE – OBE) ("Obsidian Energy", the "Company",
"we", "us" or "our") announces its financial
and operational results for the three months ended June 30, 2017.
"This is a quarterly release with mixed emotion," commented
David French, President and Chief
Executive Officer. "We have lost a dear friend and leader in the
passing of Rick George, the Chairman
of the Board. His guidance and courage throughout Obsidian
Energy's restructuring and re-emergence was instrumental to forging
our new path. He leaves us with an imprint of the highest
integrity and dedication to task that we will carry forward as a
new Company. We wish his family peace through their
immeasurable loss.
As our first quarter formally as Obsidian Energy, we are off to
a solid start. Despite limited activity in seasonal breakup
conditions, we continued our operational momentum through the
second quarter of 2017 to deliver strong production volumes and
robust funds flow from operations.
As we look forward to our second half development program, we
elected to reallocate and reduce our capital budget by $20 million to fit the current price environment
yet our strong base production and early development results allow
us to maintain production guidance. Company financials are stable
with long term debt below $400
million, and we continue to actively extend our hedge book
to underpin 2017 and 2018 development with a deep portfolio of
investable projects across Alberta
that work in a $45 to $55 West Texas
Intermediate world.
The next several months will be very important as we embark on
our most active development program in three years. We are well
positioned to manage the current commodity environment and look
forward to updating the market through the new lens of Obsidian
Energy: disciplined, relentless, and accountable.
George Brookman, head of Obsidian
Energy's Governance Committee, has assumed the role of Acting
Chairman while the Board of Directors evaluates candidate
options."
Obsidian Energy Results for the Three and Six Months Ended
June 30, 2017
|
|
|
|
Three months ended
June 30
|
Six months ended June
30
|
|
2017
|
2016
|
% change
|
2017
|
2016
|
% change
|
Financial
(millions, except per share amounts)
|
|
|
|
|
|
|
|
|
Gross revenues
(1)
|
$
|
111
|
$
|
209
|
(47)
|
$
|
243
|
$
|
440
|
(45)
|
Funds flow from
operations (2)
|
|
43
|
|
55
|
(22)
|
|
100
|
|
102
|
(2)
|
|
Basic per share
(2)
|
|
0.09
|
|
0.11
|
(18)
|
|
0.20
|
|
0.20
|
-
|
|
Diluted per share
(2)
|
|
0.09
|
|
0.11
|
(18)
|
|
0.20
|
|
0.20
|
-
|
Net income
(loss)
|
|
(9)
|
|
(132)
|
(93)
|
|
18
|
|
(232)
|
>(100)
|
|
Basic per
share
|
|
(0.02)
|
|
(0.26)
|
(92)
|
|
0.04
|
|
(0.46)
|
>(100)
|
|
Diluted per
share
|
|
(0.02)
|
|
(0.26)
|
(92)
|
|
0.04
|
|
(0.46)
|
>(100)
|
Capital expenditures
(3)
|
|
24
|
|
1
|
>100
|
|
50
|
|
19
|
>100
|
Long-term
debt
|
$
|
392
|
$
|
1,535
|
(74)
|
$
|
392
|
$
|
1,535
|
(74)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
|
|
|
|
|
|
|
|
|
|
|
Daily
production
|
|
|
|
|
|
|
|
|
|
|
|
Light oil and NGL
(bbls/d)
|
|
13,396
|
|
30,421
|
(56)
|
|
14,966
|
|
35,497
|
(58)
|
|
Heavy oil
(bbls/d)
|
|
5,636
|
|
11,427
|
(51)
|
|
5,423
|
|
11,934
|
(55)
|
|
Natural gas
(mmcf/d)
|
|
68
|
|
130
|
(48)
|
|
75
|
|
137
|
(45)
|
Total production
(boe/d) (4)
|
|
30,436
|
|
63,568
|
(52)
|
|
32,655
|
|
70,289
|
(54)
|
Average sales
price
|
|
|
|
|
|
|
|
|
|
|
|
Light oil and NGL
(per bbl)
|
$
|
56.12
|
$
|
49.66
|
13
|
$
|
56.60
|
$
|
40.99
|
38
|
|
Heavy oil (per
bbl)
|
|
31.61
|
|
25.18
|
26
|
|
32.37
|
|
19.75
|
64
|
|
Natural gas (per
mcf)
|
$
|
3.10
|
$
|
1.42
|
>100
|
$
|
3.16
|
$
|
1.70
|
86
|
Netback per boe
(4)
|
|
|
|
|
|
|
|
|
|
|
|
Sales
price
|
$
|
37.51
|
$
|
31.20
|
20
|
$
|
38.11
|
$
|
27.38
|
39
|
|
Risk management
gain
|
|
2.21
|
|
4.27
|
(48)
|
|
2.91
|
|
5.08
|
(43)
|
|
Net sales
price
|
|
39.72
|
|
35.47
|
12
|
|
41.02
|
|
32.46
|
26
|
|
Royalties
|
|
(2.67)
|
|
(0.63)
|
>100
|
|
(2.68)
|
|
(0.87)
|
>100
|
|
Operating expenses
(5)
|
|
(14.27)
|
|
(12.70)
|
12
|
|
(14.38)
|
|
(12.87)
|
12
|
|
Transportation
|
|
(2.82)
|
|
(1.89)
|
49
|
|
(2.55)
|
|
(1.75)
|
46
|
|
Netback
(2)
|
$
|
19.96
|
$
|
20.25
|
(1)
|
$
|
21.41
|
$
|
16.97
|
26
|
(1)
|
Includes realized
gains and losses on commodity contracts.
|
(2)
|
The terms "funds flow
from operations" and their applicable per share amounts, and
"netback" are non-GAAP measures. Please refer to the "Non-GAAP
Measures" advisory section below for further details.
|
(3)
|
Includes the effect
of capital carried from its partner under the Peace River Oil
Partnership.
|
(4)
|
Please refer to the
"Oil and Gas Information Advisory" section below for information
regarding the term "boe".
|
(5)
|
Includes the effect
of carried operating expenses from its partner under the Peace
River Oil Partnership of $6 million or $2.17 per boe (2016 – $3
million or $0.52 per boe) for the three months ended June 30, 2017
and $10 million or $1.69 per boe (2016 – $7 million or $0.55 per
boe) for the six months ended June 30, 2017.
|
Second Quarter Operational and Financial Highlights
Delivering on Production and Operating Cost Guidance
- Corporate production averaged 30,436 boe per day during the
second quarter, including 29,983 boe per day in our key development
and legacy areas. Production in our key development areas was
essentially in-line from the first quarter, as successful
optimization and workover projects offset production declines
during the seasonal breakup period.
- Second quarter operating costs were $14.27 per boe, net of carried expenses. In
addition to most annual maintenance and turnarounds normally
occurring during the second quarter, this year we had additional
expenses stemming from our very limited ability to spend in the
second quarter of last year. We forecast spending to trend down
through the second half of the year, and continue to target annual
2017 operating costs of approximately $13.00
to $13.50 per boe, net of carried expenses.
- Funds flow from operations for the second quarter was
$43 million ($0.09 per share) reflecting strong sales prices
across our product streams and realized risk management gains.
Capital Realigned for the Current Price Environment
- In light of softening commodity prices over the past several
months, we believe it is financially prudent to realign our capital
spend in the second half of the year. Accordingly, we are adjusting
some of our 2017 development activity to reduce our full-year
capital budget by $20 million to $160
million. Most of the capital changes are on projects that
were intended to extend our double-digit percent growth through to
next year.
- Due to continued high production volumes from last winter's
drilling program and a strong outlook for our second half
development program, we do not expect the capital reductions to
have a material effect on our full-year operational results. We
remain confident in our ability to demonstrate self-funded
double-digit percent growth from the fourth quarter of 2016 to the
fourth quarter of 2017 and to meet our full year 2017 production
guidance of 30,500 to 31,500 boe per day.
Financials are Stable and Strong
- In the second quarter, we transitioned to a reserve-based
syndicated credit facility with a group of nine lenders. The
underlying borrowing base is $550
million, less the amount of outstanding pari passu senior
notes, such that the Company will have $410
million of availability under the credit facility as at
today's date.
- Our senior debt was $392 million
at the end of the second quarter, including $275 million drawn on our $410 million revolving credit facility. Senior
debt to EBITDA was 1.9 times as of June 30,
2017.
- We continued to layer in additional hedges for the second half
of 2018 to increase the certainty of our revenues as we plan our
activity for the next year. Our crude oil exposure, net of
royalties, is hedged approximately 50 percent through the second
quarter of 2018, 30 percent in the third quarter of 2018, and 25
percent in the fourth quarter of 2018. Our natural gas exposure, is
hedged on average 30 percent through the end of 2018, with
additional hedged volumes in the first and second quarter of 2018
to support incremental gas production associated with our
Mannville activity.
- A previously-announced minor asset disposition for $10 million successfully closed at the end of
May. We also closed a minor previously-announced acquisition in
Peace River, with our joint
venture partner under the Peace River Oil Partnership.
Early Development Wins are Setting a Solid Stage for
2018
- In the Cardium, we drilled 4 vertical injectors and brought
on-line 17 injectors in Willesden Green to re-pressurize the
reservoir around high performing wells drilled in late 2015 and
early 2016. As we implement water injection over the last 15
months, we are seeing positive indications in several waterflood
sites, including early indications of Gas Oil Ratio ("GOR")
response and arresting decline. In PCU #9, vertical injector
reactivations have resulted in GOR suppression and oil rate
response in offsetting horizontal producers. We are currently
running 1 rig in PCU #9 drilling 3 horizontal producers and will
move another rig to Willesden Green near the end of the third
quarter.
- During the second quarter, we restarted over 800 boe per day of
production that was shut-in last year due to ongoing issues at
third-party processing facility. The facility was repaired ahead of
schedule and we upgraded our gathering system in the area to ensure
ongoing production reliability. This has also contributed to second
quarter incremental operating costs incurred earlier than the
budgeted on-stream date.
- In Peace River, favorable
weather conditions allowed us to continue development into breakup,
drilling and bringing on production 5 wells in the second quarter.
We currently have two rigs running in the area, and plan to drill
12 wells in the second half of the year. Work continues on our gas
gathering infrastructure to meet the new Alberta Energy Regulator
Directive 084 requirements.
- In the Alberta Viking, we resolved minor artificial lift issues
on select wells drilled in the fourth quarter of 2016, and saw
Viking well performance increase back to our industry-leading type
curve. We restarted development in the area in June, and have now
finished drilling all 10 wells in our second half program. We
expect these wells to be all on production by the end of September.
Early flowback results on the first 4 wells look encouraging, and
on average are exceeding last year's industry leading performance
by approximately 20%.
- In the Mannville, we are
encouraged by continued positive industry results offsetting our
acreage. We increased the average working interest in our operated
3 well program by approximately 10% to 80%. We successfully drilled
our first Mannville well in July,
targeting the Upper Mannville, and plan to have the well on
production in September. We expect the remaining two Mannville wells to be on production early in
the fourth quarter. The gas volumes will be processed at our nearby
operated Crimson gas plant to minimize processing costs.
Operational Metrics
Obsidian Energy holds a focused portfolio with industry leading
positions in the Cardium, Peace
River, and Alberta Viking areas. The table below outlines
select metrics in our key development and legacy areas for the
three and six months ended June 30,
2017 and excludes the impact of hedging:
|
|
|
|
|
Area
|
Select Metrics –
Three Months Ended June 30, 2017
|
Production
|
Liquids
Weighting
|
Operating
Cost
|
Netback
|
Cardium
|
18,430
boe/d
|
63%
|
$14/boe
|
$27/boe
|
Alberta
Viking
|
1,976
boe/d
|
51%
|
$12/boe
|
$22/boe
|
Peace
River(1)
|
4,928
boe/d
|
99%
|
<$1/boe
|
$24/boe
|
Key Development
Areas
|
25,334
boe/d
|
69%
|
$11/boe
|
$26/boe
|
Legacy
Areas
|
4,649
boe/d
|
25%
|
$27/boe
|
($10)/boe
|
Key Development
& Legacy Areas(2)
|
29,983
boe/d
|
62%
|
$13/boe
|
$20/boe
|
(1)
|
Net of carried
operating costs
|
(2)
|
Excludes the impact
of properties sold during the quarter
|
The table below provides a summary of our operated activity
during the second quarter:
|
|
|
|
|
Number of
Wells
|
|
|
Drilled
|
Completed
|
On
production
|
|
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
Cardium
|
|
4
|
4
|
8
|
8
|
17
|
17
|
|
Producer
|
|
0
|
0
|
0
|
0
|
0
|
0
|
|
Injector
|
|
4
|
4
|
8
|
8
|
17
|
17
|
Alberta
Viking
|
|
4
|
4
|
0
|
0
|
0
|
0
|
Peace
River
|
|
5
|
3
|
5
|
3
|
5
|
3
|
Total
|
|
13
|
11
|
13
|
11
|
22
|
20
|
Maintaining Production Guidance and Re-Aligning Capital
Spending
We are adjusting our 2017 development plans to reduce our
full-year capital budget by $20 million to
$160 million. Most of the capital changes are related to
projects that were intended to extend our double-digit percent
growth trajectory through next year.
|
|
|
Capital
Category
|
# of Operated
Wells
|
Net
Capital
|
Cardium Waterflood
Platform
|
7 Producers, 26
Vertical Injectors
|
$80
million
|
Manufacture Cold
Flow
|
21 Producers, 5
Stratigraphic
|
$5 million
|
Optimize Volumes with
Viking
|
10
Producers
|
$20
million
|
Pursue New
Ventures
|
3
Producers
|
$12
million
|
Total
Development
|
41 Producers, 26
Vertical Injectors
|
$117
million
|
Base
Capital
|
|
$28
million
|
Total E&D
Capital Expenditures
|
|
$145
million
|
Decommissioning
Expenditures
|
|
$15
million
|
Total Capital
Expenditures
|
|
$160
million
|
Due to continued high production volumes from last winter's
drilling program and a strong outlook for our second half
development program, we do not expect the capital reductions to
have a material effect on our full-year operational results. In our
second half development program, we expect the majority of our new
wells will be brought on production late in the third quarter or
early in the fourth quarter. We remain confident in our ability to
demonstrate self-funded double-digit percent growth from the fourth
quarter of 2016 to the fourth quarter of 2017 and to meet our full
year 2017 production guidance of 30,500 to 31,500 boe per day.
2017 Annual
Guidance
|
|
Updated
Guidance
|
Previous
Guidance
|
Change
|
Production
|
30,500 to 31,500 boe
per day
|
30,500 to 31,500 boe
per day
|
No Change
|
Operating Costs, net
of carried expenses(1)
|
$13.00 to $13.50 per
boe
|
$13.00 to $13.50 per
boe
|
No Change
|
E&D Capital
Expenditures
|
$145
million
|
$160
million
|
($15)
|
Decommissioning
Expenditures
|
$15
million
|
$20
million
|
($5)
|
Total Capital
Expenditures
|
$160
million
|
$180
million
|
($20)
|
(1)
|
Net of carried
operating expenses from the Company's partner under the Peace River
Oil Partnership.
|
Updated Hedging Position
Our hedging program helps reduce the volatility of our funds
flow from operations, and thereby improves our ability to manage
our ongoing capital programs. We target having hedges in place for
approximately 25 percent to 50 percent of our crude oil exposure,
net of royalties, and 20 percent to 50 percent of our gas exposure,
net of royalties. Refer to the "Financials are Stable and Strong"
section for more information on our current hedging levels.
Our positions as of August 8, 2017
are as follows:
|
|
Q3
2017
|
Q4
2017
|
Q1
2018
|
Q2
2018
|
Q3
2018
|
Q4
2018
|
Oil Volume
(bbl/d)
|
|
7,400
|
7,900
|
8,000
|
8,000
|
5,000
|
4,000
|
US$ WTI Price
(US$/bbl) (1)
|
|
US$51.96
|
US$52.17
|
US$51.31
|
US$50.59
|
US$49.96
|
US$49.07
|
Gas Volume
(mcf/d)
|
|
19,000
|
20,900
|
28,400
|
22,700
|
17,100
|
15,200
|
AECO Price
(C$/mcf)
|
|
$2.84
|
$3.00
|
$2.83
|
$2.72
|
$2.67
|
$2.67
|
(1)
|
US$ price implied
using foreign exchange rates as at June 30, 2017.
|
|
Conference Call Details
A conference call will be held to discuss the second quarter
results above at 6:30 am Mountain
Time (8:30 am Eastern Time) on
Wednesday, August 9, 2017.
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/1477193/2D92047EF3170543402318FDBF2EF764
A digital recording will be available for replay two hours after
the call's completion, and will remain available until August 23, 2017 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 62923353,
followed by the pound (#) key.
An updated corporate presentation, the second quarter
management's discussion and analysis and the unaudited consolidated
financial statements will be available on the Company's website
at www.obsidianenergy.com, on SEDAR at www.sedar.com, and
on EDGAR at www.sec.gov on the same date.
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, EBITDA, netback and gross revenues
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. EBITDA is cash flow from
operations excluding the impact of changes in non-cash working
capital, decommissioning expenditures, financing expenses, realized
gains and losses on foreign exchange hedges on prepayments,
realized foreign exchange gains and losses on debt prepayments and
restructuring expenses. Additionally, under the syndicated credit
facility, realized foreign exchange gains or losses related to debt
maturities are excluded from the calculation. EBITDA as defined by
Obsidian Energy's debt agreements excludes the EBITDA contribution
from assets sold in the prior 12 months and is used within Obsidian
Energy's covenant calculations related to its syndicated credit
facility and senior notes.
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
"Results of Operations – Netbacks" above for a calculation of the
Company's netbacks. Gross revenue is total revenues including
realized risk management gains and losses on commodity contracts
and is used to assess the cash realizations on commodity sales.
Calculation of Funds Flow from Operations
(millions, except per
share amounts)
|
Three months
ended
June 30
|
Six months
ended
June 30
|
2017
|
2016
|
2017
|
2016
|
Cash flow from
operating activities
|
$
|
19
|
$
|
(56)
|
$
|
57
|
$
|
5
|
Change in non-cash
working capital
|
|
14
|
|
61
|
|
16
|
|
87
|
Decommissioning
expenditures
|
|
3
|
|
2
|
|
7
|
|
4
|
Office lease
settlements
|
|
4
|
|
-
|
|
8
|
|
-
|
Monetization of
foreign exchange contracts
|
|
-
|
|
-
|
|
-
|
|
(32)
|
Settlements of normal
course foreign exchange contracts
|
|
(8)
|
|
6
|
|
(8)
|
|
6
|
Monetization of
transportation commitment
|
|
-
|
|
-
|
|
-
|
|
(20)
|
Realized foreign
exchange loss – debt maturities
|
|
1
|
|
36
|
|
4
|
|
36
|
Carried operating
expenses (1)
|
|
6
|
|
3
|
|
10
|
|
7
|
Restructuring
charges
|
|
4
|
|
3
|
|
6
|
|
9
|
Funds flow from
operations
|
$
|
43
|
$
|
55
|
$
|
100
|
$
|
102
|
|
|
|
|
|
|
|
|
|
Per share
|
|
|
|
|
|
|
|
|
|
Basic per
share
|
$
|
0.09
|
$
|
0.11
|
$
|
0.20
|
$
|
0.20
|
|
Diluted per
share
|
$
|
0.09
|
$
|
0.11
|
$
|
0.20
|
$
|
0.20
|
(1)
|
The effect of carried
operating expenses from the Company's partner under the Peace River
Oil Partnership.
|
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. In particular, this document contains forward-looking
statements pertaining to, without limitation, the following: that
we are well positioned to manage the current commodity
environment; our expected percentage production growth rate;
our expected approach to development including the area-specific
asset development plans described herein; our expectations for
operating costs during the year and the associated target range for
those costs per boe (net of carried expenses); our capital spending
plans in 2017 and that: (i) most of the capital changes are on
projects that were intended to extend our double digit growth
through the next year and (ii) we do not expect the capital
reductions to have a material effect on our full-year operational
results; the timing of development and operational activities; the
expectations for timing for certain wells to be on
production; how certain gas wells will be processed which
will minimize processing costs; that we remain confident in our
ability to demonstrate self-funded double digit percentage growth
from the fourth quarter of 2016 to the fourth quarter of 2017 and
meeting our full year 2017 production guidance; and our hedging
program and its ability to reduce the volatility of our funds flow
from operations and thereby improves our ability to manage our
ongoing capital programs.
With respect to forward-looking statements contained in this
document, we have made assumptions regarding, among other things:
2017 prices of US$54.07 per barrel of
West Texas Intermediate light sweet oil and C$3.32 per mcf AECO gas, and a C$/US$ foreign
exchange rate of $1.32; 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.