CALGARY, Nov. 10, 2017 /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 third quarter ended
September 30, 2017 and 2018 Budget.
All figures are in Canadian dollars unless otherwise stated.
David French, President & CEO
commented, "I am quite proud of the Obsidian Energy team in the
third quarter, successfully executing our busiest drilling campaign
in years and generating quality results across our key development
areas. We are excited about the outlook for the Company and
determined to continue operational delivery into 2018.
Deep Basin results are liquids rich and wells are flowing
strong while choked back
We are encouraged with the results of our first foray into the
Deep Basin. Our three Mannville
wells are producing a combined 2,000 boe per day with average
liquids rates of approximately 60 bbl per mmcf. These liquid yields
are substantially above expectations and improve the already
attractive play economics. We look forward to further 2018
development.
The Q3 program is beating forecast and reaffirms production
guidance
Second half projects in the Cardium, Alberta Viking, and
Peace River are delivering strong
rates and reinforcing the value of our disciplined project funding
and execution. As a result of production management and new well
delivery, we are forecasting full year 2017 production at the high
end of our 30,500 – 31,500 boe per day guidance range.
Waterflood performance is impressive
Waterflood investment is starting to bear fruit with meaningful
decline mitigation across our Cardium assets. The base decline in
our total Cardium business is only five percent year to date
resulting from waterflood and base optimization projects initiated
in 2016.
2018 delivers five percent growth at 80 percent
reinvestment
We anticipate five percent production growth in 2018 while
investing only 80 percent of Funds Flow from Operations. We have
the operational flexibility and drill ready prospects to deliver
north of five percent by adjusting our second half program as
commodity prices allow. We have clear downside protection and
growth confidence through our robust hedge book. Our Board has
approved a $135 million 2018 budget
which leverages the primary drilling opportunity set within our
portfolio. We have targeted our capital to be short cycle focused
while maintaining our base decline rate through efficient, low cost
waterflood management.
Our 2018 plan offers a solid and scalable liquids weighted
growth profile, and the third quarter and 2018 outlook are great
signs for what is ahead of us as a Company."
Financial and Operating Highlights
|
|
|
|
Three months ended
September 30
|
Nine months ended
September 30
|
|
2017
|
2016
|
% change
|
2017
|
2016
|
% change
|
Financial
(millions, except per share amounts)
|
|
|
|
|
|
|
|
|
Gross revenues
(1,2)
|
$
|
98
|
$
|
136
|
(28)
|
$
|
341
|
$
|
576
|
(41)
|
Funds flow from
operations (2)
|
|
40
|
|
32
|
25
|
|
140
|
|
134
|
4
|
|
Basic per share
(2)
|
|
0.08
|
|
0.06
|
33
|
|
0.28
|
|
0.27
|
4
|
|
Diluted per share
(2)
|
|
0.08
|
|
0.06
|
33
|
|
0.28
|
|
0.27
|
4
|
Net loss
|
|
(44)
|
|
(232)
|
(81)
|
|
(26)
|
|
(464)
|
(94)
|
|
Basic per
share
|
|
(0.09)
|
|
(0.46)
|
(80)
|
|
(0.05)
|
|
(0.92)
|
(95)
|
|
Diluted per
share
|
|
(0.09)
|
|
(0.46)
|
(80)
|
|
(0.05)
|
|
(0.92)
|
(95)
|
Capital expenditures
(3)
|
|
55
|
|
13
|
>100
|
|
105
|
|
32
|
>100
|
Net Debt
(2,4)
|
$
|
410
|
$
|
484
|
(15)
|
$
|
410
|
$
|
484
|
(15)
|
|
|
|
|
|
|
|
|
|
|
|
Operations
|
|
|
|
|
|
|
|
|
|
|
Daily
production
|
|
|
|
|
|
|
|
|
|
|
|
Light oil and NGL
(bbls/d)
|
|
13,324
|
|
17,644
|
(24)
|
|
14,218
|
|
29,502
|
(52)
|
|
Heavy oil
(bbls/d)
|
|
5,456
|
|
5,711
|
(4)
|
|
5,434
|
|
9,844
|
(45)
|
|
Natural gas
(mmcf/d)
|
|
68
|
|
107
|
(36)
|
|
73
|
|
127
|
(43)
|
Total production
(boe/d) (5)
|
|
30,166
|
|
41,233
|
(27)
|
|
31,816
|
|
60,533
|
(47)
|
Average sales
price
|
|
|
|
|
|
|
|
|
|
|
|
Light oil and NGL
(per bbl)
|
$
|
51.06
|
$
|
47.01
|
9
|
$
|
54.85
|
$
|
42.20
|
30
|
|
Heavy oil (per
bbl)
|
|
30.36
|
|
21.67
|
40
|
|
31.69
|
|
20.12
|
58
|
|
Natural gas (per
mcf)
|
$
|
2.35
|
$
|
2.46
|
(4)
|
$
|
2.91
|
$
|
1.92
|
52
|
Netback per boe
(5)
|
|
|
|
|
|
|
|
|
|
|
|
Sales
price
|
$
|
33.37
|
$
|
29.50
|
13
|
$
|
36.60
|
$
|
27.86
|
31
|
|
Risk management
gain
|
|
2.24
|
|
5.58
|
(60)
|
|
2.69
|
|
5.19
|
(48)
|
|
Net sales
price
|
|
35.61
|
|
35.08
|
2
|
|
39.29
|
|
33.05
|
19
|
|
Royalties
|
|
(2.27)
|
|
(1.63)
|
39
|
|
(2.54)
|
|
(1.04)
|
>100
|
|
Operating expenses
(6)
|
|
(12.26)
|
|
(13.40)
|
(9)
|
|
(13.70)
|
|
(12.99)
|
5
|
|
Transportation
|
|
(2.38)
|
|
(1.71)
|
39
|
|
(2.50)
|
|
(1.74)
|
44
|
|
Netback
(2)
|
$
|
18.70
|
$
|
18.34
|
2
|
$
|
20.55
|
$
|
17.28
|
19
|
|
|
(1)
|
Includes realized
gains and losses on commodity contracts.
|
(2)
|
The terms "gross
revenues", "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.
|
(3)
|
Includes the benefit
of capital carried by partners.
|
(4)
|
Net debt includes
long-term debt and includes the effects of working capital and all
cash held on hand.
|
(5)
|
Please refer to the
"Oil and Gas Information Advisory" section below for information
regarding the term "boe".
|
(6)
|
Includes the benefit
of carried operating expenses from its partner under the Peace
River Oil Partnership of $5 million or $1.79 per boe (2016 – $4
million or $1.04 per boe) for the three months ended and $15
million or $1.75 per boe (2016 – $11 million or $0.66 per boe) for
the nine months ended on a combined basis.
|
- Funds Flow from Operations for the third quarter was
$40 million, reflecting lower
realized pricing due to a decrease in the CAD/USD exchange rate,
which was partially offset by lower operating costs.
- Average liquids sales prices were $45.05 per boe and average natural gas sales
prices were $2.35 per mcf. Realized
natural gas prices were at a premium to AECO in the quarter,
resulting from a portion of our volumes marketed at alternative
sales points. We expect our gas realizations to maintain a slight
premium to AECO through 2018.
- Third quarter operating costs were $12.26 per boe, net of carried expenses. As
expected, operating costs were lower than the second quarter of
2017 due to lower maintenance and turnaround activity. We continue
to target annual 2017 operating costs of approximately $13.00 to $13.50 per boe, net of carried
expenses.
- Invested $55 million of capital
expenditures across our key development areas and remain on track
to meet full year 2017 capital guidance.
- Total Net Debt was approximately $410
million at the end of the third quarter, including
$251 million drawn on our
$410 million revolving credit
facility and $113 million of Senior
Notes.
- Realized $2.24 per boe of
realized commodity gains in the quarter, driven by our strong crude
oil and natural gas swap positions.
Production Update
Average corporate production for the third quarter was 30,166
boe per day, consistent with the second quarter of 2017.
Base production continues to exceed expectations, driven by
continued waterflood response across our Cardium acreage and
reliability of our base infrastructure and gathering systems. We
ran a successful campaign this year to optimize existing wellbores,
which has contributed nearly 800 boe per day to our base
production. The Company did not encounter any meaningful production
impact resulting from the third-party service restrictions in the
quarter.
The table below outlines select metrics in our key development
and legacy areas for the three months ended September 30, 2017 and excludes the impact of
hedging:
|
|
Area
|
Select Metrics –
Three Months Ended September 30, 2017
|
Production
|
Liquids
Weighting
|
Operating
Cost
|
Netback
|
Cardium
|
18,876
boe/d
|
64%
|
$13/boe
|
$20/boe
|
Alberta
Viking
|
1,766
boe/d
|
49%
|
$7/boe
|
$22/boe
|
Peace
River(1)
|
4,823
boe/d
|
99%
|
$2/boe
|
$23/boe
|
Key Development
Areas(2)
|
25,465
boe/d
|
69%
|
$10/boe
|
$21/boe
|
Legacy
Areas
|
4,701
boe/d
|
23%
|
$22/boe
|
($3)/boe
|
Key Development
& Legacy Area
|
30,166
boe/d
|
62%
|
$12/boe
|
$19/boe
|
|
(1)
Net of carried operating
costs.
|
(2) Deep Basin
results for the quarter were negligible, and therefore included
within the Cardium metrics.
|
Cardium Drilling Update
Our three well horizontal pad in PCU #9 came on production in
October, and early rate indications are above type curve, currently
producing nearly 200 boe per day, per well. We are currently
drilling our four horizontal producers in Willesden Green and
expect the pad to turn over to production prior to year-end.
We continue to see positive indications of Gas Oil Ratio ("GOR")
suppression and decline mitigation in our Cardium development area.
Our decline rate has shallowed to approximately five percent this
year, from approximately 20 percent in 2016. The observed oil rate
decline shallowing is driven by our low-cost waterflood
optimization and base management projects that began in the third
quarter of 2016.
Alberta Viking Drilling Update
Our 10 well Alberta Viking program continues to exceed
expectations, with initial production results confirming early
flowback rates. All 10 wells are on production, including the
100/2-18 well with a peak IP of 704 boe per day and producing day
IP30 of 295 boe per day. We continue to evolve our development
strategy in the area to enhance overall economics; including
trucking clean oil through design change at our multi-well
batteries and optimizing stage count to maximize capital
efficiency.
Peace River Drilling Update
Our second half 2017 Peace River program returned to the heart of
the Harmon Valley South field, and preliminary results of the
program are encouraging. Daily total production from the first nine
wells of our second half 2017 program is currently averaging
approximately 190 boe per day, per well. At present, 10 of 12
second half wells are on production, and two under facility
construction. Obsidian Energy set another record in the third
quarter for meters drilled with a single bit and bottom hole
assembly, whereby we drilled 17,278 meters of open hole for an
overall cost of $76 per meter
drilled.
Deep Basin Drilling Update
We successfully drilled our three well Mannville program in the third quarter, with
one well on production as of September 30,
2017 and the remaining two wells by the end of October. This
is the Company's first foray into our significant Deep Basin
position and we designed a program that tests different Upper
Mannville targets. The overall program is delivering value
meaningfully ahead of expectations, driven by significant initial
liquids rates and high pressure from the second and third wells in
the program. While the first well encountered lower permeability
and pressure than expected, our second and third wells moved to a
high-pressure portion of the reservoir and have significant initial
liquids rates. These wells are showing free condensate rates of 35
bbl per mmcf and overall liquids rates of 60 bbl per mmcf, more
than double type curve expectations. We estimate the value uptick
from the strong liquids rates will increase rates of return by
approximately 20 percent. We are maximizing the liquids potential
of these wells by utilizing a down-hole choke mechanism to
stabilize gas rates at approximately 4,000 mcf per day. Our average
working interest on these wells is 80 percent.
The table below provides a summary of our operated activity in
the third quarter.
|
|
Number of Wells Q3
2017
|
|
Drilled
|
Completed
|
On
production
|
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
Cardium
|
|
|
|
|
|
|
|
Producer
|
4
|
3.7
|
3
|
2.7
|
0
|
0.0
|
|
Injector
|
5
|
4.5
|
0
|
0.0
|
5
|
5.0
|
Mannville
|
3
|
2.4
|
3
|
2.4
|
1
|
0.7
|
Alberta
Viking
|
6
|
6.0
|
10
|
10.0
|
6
|
6.0
|
Peace
River
|
8
|
4.4
|
7
|
3.9
|
7
|
3.9
|
Total
|
26
|
21.0
|
23
|
19.0
|
19
|
15.6
|
Updated Hedging Position
We continued our active hedging program and began to extend our
hedge book into the second quarter of 2019. We also took advantage
of the October decline in the CAD relative to the USD and hedged
approximately two thirds of our foreign exchange exposure
on our 2018 USD WTI hedges.
Our liquids exposure, net of royalties, is hedged approximately
65 percent through 2018 and our natural gas exposure, net of
royalties, is hedged approximately 40 percent through the end of
2018. We have expanded our 2018 hedge volumes to capitalize on
recent price improvements that support a fully funded 2018 capital
program.
Currently, the Company has the following crude oil hedges in
place:
|
Q4 2017
|
Q1 2018
|
Q2 2018
|
Q3 2018
|
Q4 2018
|
Q1 2019
|
Q2 2019
|
|
WTI $USD
|
-
|
$50.82
|
$50.00
|
$50.05
|
$49.78
|
$50.02
|
-
|
|
|
bbl/day
|
-
|
7,000
|
7,000
|
8,000
|
8,000
|
3,000
|
-
|
|
WTI $CAD
|
$67.70
|
$71.03
|
$71.03
|
$71.04
|
$71.04
|
$66.90
|
$67.30
|
|
|
bbl/day
|
7,900
|
5,000
|
5,000
|
4,000
|
4,000
|
4,000
|
2,000
|
|
Total
|
|
|
|
|
|
|
|
|
|
bbl/day
|
7,900
|
12,000
|
12,000
|
12,000
|
12,000
|
7,000
|
2,000
|
Additionally, the Company has the following foreign exchange
contracts in place for 2018:
- Foreign exchange swaps at an average of 1.261 on notional
US$6 million per month
- Foreign exchange collar at an average of 1.210 – 1.272 on
notional US$2 million per
month
Currently, the Company has the following natural gas hedges in
place:
|
Q4 2017
|
Q1 2018
|
Q2 2018
|
Q3 2018
|
Q4 2018
|
|
AECO $CAD
|
$3.00
|
$2.83
|
$2.72
|
$2.67
|
$2.67
|
|
|
mcf/day
|
20,900
|
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
|
20,900
|
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.
Recent transportation deductions for the Company to bring product
to the Ventura market have been approximately $0.55 per
mcf.
|
Disposition Highlights Subsequent to the Third
Quarter
The Company entered into an agreement in late October for the
sale of our royalty interests in Eastern
Alberta for $40 million. The
transaction capitalizes on the premium valuation associated with
royalty assets and puts us in a solid liquidity position heading
into 2018. Proceeds from the transaction will be used to reduce
borrowings on our syndicated credit facility and therefore has a
neutral effect on 2018 Funds Flow from Operations. Key metrics
associated with the assets are as follows (1):
Production
|
181 boe per
day
|
Implied Production
Multiple
|
$221,000 per boe per
day
|
Net Operating Income
(NOI)
|
$2.7
million
|
Implied NOI
Multiple
|
15x
|
(1)
|
Based on lease
operating statements for the twelve months prior to the effective
date
|
This royalty interest transaction is expected to close prior to
the end of 2017 and is subject to closing adjustments customary in
transactions of this nature.
2017 Guidance
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, adjusted for A&D, and believe
production will be near the high end of our full year 2017 guidance
of 30,500 – 31,500 boe per day.
|
2017 Annual
Guidance
|
Production
|
30,500 to 31,500 boe
per day
|
Operating Costs, net
of carried expenses(1)
|
$13.00 to $13.50 per
boe
|
|
|
E&D Capital
Expenditures
|
$145
million
|
Decommissioning
Expenditures
|
$15
million
|
Total Capital
Expenditures
|
$160
million
|
(1)
|
Net of carried
operating expenses from the Company's partner under the Peace River
Oil Partnership.
|
2018 Outlook
We are excited about the outlook for the Company, which combines
a predictable, low decline asset base with a robust development
opportunity set. Our extensive portfolio optionality allows us to
shift capital allocation in response to various commodity price
scenarios and deliver a returns focused capital program entirely
supported by Funds Flow from Operations.
We plan to deliver approximately five percent production growth
relative to full year 2017, adjusted for 2017 A&D activity.
This will be accomplished by continuing our second half 2017
momentum, drilling producing wells through the first quarter of
2018. Our 2018 program is approximately 60 percent weighted to
first half of 2018 and we maintain the operational flexibility to
accelerate spending based on the commodity price outlook within the
year. Furthermore, our hedge position provides certainty to our
cash flow outlook whereby our capital program can withstand more
than a 10 percent decline in Canadian dollar realized oil and gas
pricing relative to current strip prices before exceeding our Funds
Flow from Operations.
Our 2018 capital investment of $135
million includes $86 million
associated with development and existing wellbore optimization,
$25 million of infrastructure
and corporate capital, $10
million of decommissioning expenditures and $14 million of capital associated with meeting
the AER Directive 84 requirements for Hydrocarbon Emission Controls
and Gas Conservation in the Peace
River area. We are on track to meet the AER requirements and
the Company will gather, process, and sell natural gas from its
Peace River operations beginning
in September 2018. We do not expect a
material cash flow stream from natural gas in this area.
Our 2018 plans have an increased focus on shorter cycle
opportunities within our portfolio. Our development capital program
is approximately 50 percent weighted to the Cardium, employing a
quicker payout program that balances primary drilling with targeted
low capital integrated waterflood opportunities. The remainder of
our development capital program has allocations of 10-15 percent
each between our Deep Basin, Alberta Viking and Peace River Assets,
and an additional 15 percent to capital efficient volume
optimization of existing wellbores throughout our key development
areas. The projected capital efficiency of our 2018 Development
capital is approximately $15,000 per
boe per day, based on the 12 month forward production associated
with each project.
Cardium Development
We plan to spend approximately $44
million to develop our high netback, low decline Cardium
asset, drilling eight horizontal producers (gross operated wells)
amongst our Pembina and Willesden Green assets. Continuing our
approach from the last several years, we place our horizontal wells
in the bioturbated rock just below the upper good quality reservoir
to ensure we access both reserves in the cleaner intervals, as well
as tapping into undrained reservoir in the lower bioturbated
interval. Six of our horizontal wells are in Pembina and two are in
Willesden Green.
Additionally, we expect to spend approximately $5 million on integrated waterflood and
optimization opportunities. This includes supporting our Pembina
drills with inexpensive conversions of low producing vertical wells
to injection, rather than new drills, employing a hybrid approach
between our Type I & Type IV waterflood inventory. Our Cardium
budget will also allocate approximately $12
million to Non-Operated primary drilling by our working
interest partners in the area, and $4
million to land consolidation opportunities and seismic
data. This shorter cycle focused Cardium program limits spending on
new injection while still optimizing our waterflood fields and
mitigating decline on horizontal wells.
Deep Basin Development
We plan to spend approximately $11
million to continue development of our Deep Basin position
in 2018. Using the learnings from our 2017 development program and
targeting high pressure areas of the reservoir with strategic
positions close to our operated processing facilities, we plan to
drill three wells through the year. Given the negative outlook for
natural gas pricing in Alberta, we
have high-graded our 2018 inventory to target liquids rich
locations that generate robust rates of return.
Peace River Development
The Peace River area continues
to be a key development area for the Company. Designing simpler
wells to mitigate risk and increasing the length of individual legs
to drill faster has driven cost savings that attract capital,
despite the expected JV operating and capital cost carry expiry by
year-end 2017. We plan to invest approximately $8 million to drill five (2.75 net) primary cold
flow wells in 2018.
Alberta Viking Development
The Company plans to invest approximately $9 million to drill six wells in our Alberta
Viking development area. All six wells are close to our 10 well
program from 2017, and we expect similar production results. We
expect slightly enhanced economics on our 2018 program using multi
well pads close to existing infrastructure and by continuing to
truck clean oil which enhance netbacks by approximately
$1.50/bbl.
Optimization of Existing Wellbores
We plan to spend approximately $14
million on the optimization of existing well bores within
our portfolio. This capital consists of over 50 individual projects
to enhance field production by reactivating or re-fracking existing
wells, debottlenecking, consolidating batteries, and testing
additional zone potential in old vertical wells. This is some of
the most capital efficient spend in our 2018 budget, projected at
less than $10,000 per boe, per day.
Our 2017 optimization projects contributed volumes at approximately
$6,500 per boe, per day. We do not
expect the same quantum of capital to be allocated to optimization
past 2018.
Summary of 2018 Guidance
|
2018 Annual
Guidance
|
Production
|
31,000 to 32,000 boe
per day
|
Production Growth
Rate (1)
|
5%
|
Operating
Costs
|
$13.50 to $14.00 per
boe
|
General &
Administrative
|
$2.00 to $2.50 per
boe
|
(1) Relative to full
year 2017 production, adjusted for A&D, of between 29,000 –
30,000 boe per day
|
Our 2018 plans are based on full year 2018 pricing of
US$55 WTI, $1.28 CAD/USD & C$2.25 AECO.
|
|
|
Capital
Category
|
# of Operated
Wells
|
Net
Capital
|
Cardium
|
8
Producers
|
$44
million
|
Deep Basin
|
3
Producers
|
$11
million
|
Peace
River
|
5
Producers
|
$8 million
|
Alberta
Viking
|
6
Producers
|
$9 million
|
Existing Wellbore
Optimization
|
>50
Projects
|
$14
million
|
Total
Development
|
22
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
|
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 Friday,
November 10, 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/1535576/E0A4361CC5204AE7C0052F290A83ABE9
A digital recording will be available for replay two hours after
the call's completion, and will remain available until November 24, 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 4299386,
followed by the pound (#) key.
An updated corporate presentation, the third 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, gross revenues 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. 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. Net
debt includes long-term debt and includes the effects of working
capital and all cash held on hand.
Calculation of Funds Flow from Operations
(millions, except per
share amounts)
|
Three months
ended
September
30
|
Nine months
ended
September
30
|
2017
|
2016
|
2017
|
2016
|
Cash flow from
operating activities
|
$
|
61
|
$
|
(98)
|
$
|
118
|
$
|
(93)
|
Change in non-cash
working capital
|
|
(34)
|
|
16
|
|
(18)
|
|
103
|
Decommissioning
expenditures
|
|
2
|
|
1
|
|
9
|
|
5
|
Office lease
settlements
|
|
3
|
|
-
|
|
11
|
|
-
|
Monetization of
foreign exchange contracts
|
|
-
|
|
-
|
|
-
|
|
(32)
|
Settlements of normal
course foreign exchange contracts
|
|
-
|
|
(9)
|
|
(8)
|
|
(3)
|
Monetization of
transportation commitment
|
|
-
|
|
-
|
|
-
|
|
(20)
|
Realized foreign
exchange loss – debt prepayments
|
|
-
|
|
113
|
|
-
|
|
113
|
Realized foreign
exchange loss – debt maturities
|
|
-
|
|
-
|
|
4
|
|
36
|
Carried operating
expenses (1)
|
|
5
|
|
4
|
|
15
|
|
11
|
Restructuring
charges
|
|
3
|
|
5
|
|
9
|
|
14
|
Funds flow from
operations
|
$
|
40
|
$
|
32
|
$
|
140
|
$
|
134
|
|
|
|
|
|
|
|
|
|
Per share
|
|
|
|
|
|
|
|
|
|
Basic per
share
|
$
|
0.08
|
$
|
0.06
|
$
|
0.28
|
$
|
0.27
|
|
Diluted per
share
|
$
|
0.08
|
$
|
0.06
|
$
|
0.28
|
$
|
0.27
|
(1)
|
The benefit 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: our
excitement about the Company outlook and our determination to
continue operational delivery into 2018; our forecasted full year
2017 production at the high end of our guidance; our expected 2018
production, percentage production growth rate for 2018 and
associated investment level of Funds Flow from Operations,
operating and general and administration cost ranges for 2018; that
we have the operational flexibility and drilling prospects to
deliver greater production growth by adjusting our second half
program as commodity prices allow; that we have clear downside
protection and confidence in growth through our hedging program;
our capital spending plans in 2018; the expectation that our gas
realizations will maintain a slight premium to AECO through 2018;
our expectations for 2017 operating costs and the associated target
range for those costs per boe (net of carried expenses); that we
remain on track to meet full year 2017 capital guidance; our
expected approach to development including the area-specific asset
development plans described herein; the timing of development and
operational activities; the expectations for timing for certain
wells to be on production; the estimated value uptick in the Deep
Basin from strong liquid rates; the expected closing date of the
royalty interest transaction; our confidence in our ability to
demonstrate self-funded double digit percentage growth from the
fourth quarter of 2016 to the fourth quarter of 2017, adjusted for
A&D; that we can accomplish our production growth estimates by
continuing our second half 2017 momentum, by drilling producing
wells through the first quarter of 2018; our ability to meet the
AER requirements for Directive 84 in the Peace River Area and the Company will gather,
process, and sell natural gas from its Peace River operations beginning in
September 2018; the projected capital
efficiency of our 2018 development capital, based on the 12 month
forward production associated with each project; our intention to
high-grade our 2018 inventory to target liquids rich locations that
generate robust rates of return; that we expect slightly enhanced
economics on our 2018 programs using multi well pads close to
existing infrastructure and by continuing to truck clean oil which
enhance netbacks; and that we do not expect the same quantum of
capital to be allocated to existing wellbore optimization past
2018.
The key metrics for the Company set forth in this
presentation may be considered to be future-oriented financial
information or a financial outlook for the purposes of applicable
Canadian securities laws. Financial outlook and future-oriented
financial information contained in this presentation are based on
assumptions about future events based on management's assessment of
the relevant information currently available. In particular, this
presentation contains projected operational and financial
information for end of 2017, 2018 and beyond for the Company. The
future-oriented financial information and financial outlooks
contained in this presentation have been approved by management as
of the date of this presentation. Readers are cautioned that any
such financial outlook and future-oriented financial information
contained herein should not be used for purposes other than those
for which it is disclosed herein.
With respect to forward-looking statements contained in this
document, we have made assumptions regarding, among other things:
2018 prices of US$55.00 per barrel of
West Texas Intermediate light sweet oil and C$2.25 per mcf AECO gas, and a C$/US$ foreign
exchange rate of $1.28; 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 security holders 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.