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.