CALGARY, Nov. 10, 2014 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We",
"Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report
operating and unaudited financial results for the three and nine months
ended September 30, 2014.
HIGHLIGHTS
-
Achieved average production of 49,920 boe/d during Q3 2014, a decrease
of 4% as compared to 52,089 boe/d in the prior quarter and an increase
of 20% compared to 41,510 boe/d in Q3 2013. Lower quarter-over-quarter
production was primarily due to a 7% decrease in Canada resulting from
lower levels of drilling and completions activity during spring
breakup, and managed production in Australia and the Netherlands
consistent with overall corporate production targets.
Quarter-over-quarter declines from lower Canadian activity were
partially offset by inclusion of a full quarter of production from our
southeast Saskatchewan acquisition, which closed in late April 2014.
Q3 production volumes in the Netherlands were also affected by
unscheduled downtime at our Garijp treating facility.
-
Generated fund flows from operations(1) in Q3 2014 of $197.9 million ($1.85/basic share), as compared to $216.1
million ($2.05/basic share) in the prior quarter and $165.6 million
($1.63/basic share) in Q3 2013. The quarter-over-quarter decrease was
primarily attributable to lower commodity pricing during Q3 2014, and a
combined build in crude oil inventories in France and Australia of
approximately 104,000 bbls.
-
Completed our first Duvernay horizontal appraisal well (35% working
interest), which is located along a shared lease-line in the Pembina
block. This three-quarter mile long well was brought on production
subsequent to the end of the third quarter and has produced for 16
days. Raw gas rate has averaged 2.2 mmcf/d (expected sales gas rate of
1.8 mmcf/d after liquids shrink and plant fuel) with an estimated
hydrocarbon liquids rate of approximately 180 bbls/d (approximately 60%
pentanes plus). The well is producing at restricted rates using a
12/64 inch downhole choke to generate an estimated flowing bottomhole
pressure of 4,200 psi (approximately 55% drawdown). Our second
Duvernay horizontal appraisal well (100% working interest), located in
the Edson block, is expected to be brought on production late in Q4
2014.
-
Drilled our first well in the Netherlands on lands acquired in October
2013. The Diever-02 exploration well (45% working interest), in the
Drenthe IIIb concession, encountered two well-developed gas bearing
intervals (Akkrum and Slochteren) with a net pay thickness of
approximately 36 metres. A three-hour clean-up test was conducted on
the Slochteren formation which delivered 25.7 mmcf/d of gas on a 40/64
inch choke with 2,615 psi flowing tubing pressure with no indications
of pressure drop during the test(3). The flow rate was limited by the 3.5 inch diameter of the tubing and
the capacity of the test equipment. The well is expected to be tied-in
with production from the Slochteren formation in Q4 2015 at an
estimated rate of approximately 1,000 boe/d, net to Vermilion. The
Akkrum formation will be perforated at a later date once the Slochteren
formation has been fully produced.
-
Subsequent to the end of the third quarter, drilled a gas discovery well
in the Netherlands at the Langezwaag-02 location (42.3% working
interest) in the Gorredijk concession. This extended reach well
recorded significant gas shows in two metres of Vlieland Sandstone and
21 metres of Zechstein-2 Carbonate. Open hole logs could not be run in
the highly deviated well. The Langezwaag-02 well was first flow tested
from the Zechstein-2 Carbonate at 12.4 mmcf/d through a 48/64 inch
choke at a flowing tubing pressure of approximately 1,300 psi. A second
flow test in the Vlieland Sandstone yielded rates of 2.7 mmcf/d through
a 32/64 inch choke at a flowing tubing pressure of approximately 960
psi.
-
Subsequent to the end of the third quarter, recorded first production
from the Deblinghausen Z7a well (25% working interest) in Germany.
This well was drilled earlier in 2014 by operator ExxonMobil Production
Deutschland GmbH, and encountered 81 metres of Zechstein Carbonate
pay. Initial gross production rates are approximately 16.5 mmcf/d of
raw gas at a flowing tubing pressure of approximately 1,300 psi.
-
Successfully expanded our southeast Saskatchewan land base through the
purchase at Crown land sales of an additional approximately 15,000 net
acres of undeveloped land to the northwest of our existing lands at an
average cost of approximately $1,860 per acre.
-
Completed our first acquisition in the United States at a cost of
approximately $11.1 million. Through the transaction, we acquired
approximately 68,000 acres of land (98% undeveloped) in the Powder
River basin of northeastern Wyoming with current working interest
production of approximately 200 bbls/d (100% oil), proved plus probable
reserves estimated at 2.22 million boe (82% oil) and contingent resource of 10.02 million boe (82% oil). Transaction metrics, with no deduction for land
value, equate to approximately $56,000 per boe/d and $20.98 per boe,
including future development costs of approximately $35.3 million. The
land base includes 53,000 net acres at an average operated working
interest of 70% in a promising tight oil project in the Turner Sand at
a depth of approximately 1,500 metres.
-
Our Corrib project in Ireland has continued to progress on schedule
following the completion of tunnel boring operations in May 2014.
Project operator Shell Exploration & Production Ireland Ltd. (SEPIL)
successfully completed offshore workover and pipeline operations during
the third quarter. SEPIL also significantly advanced tunnel
outfitting, which is now estimated to be approximately 95% complete.
Remaining activities include completion of tunnel outfitting and
grouting, commissioning of the gas processing facility, and
finalization of operating permits. We anticipate first gas from Corrib
in approximately mid-2015, with peak production estimated at
approximately 58 mmcf/d (approximately 9,700 boe/d) net to Vermilion.
-
We are revising our 2014 average annual production guidance from the
previous range of 48,500-49,500 boe/d to a range of 49,000-49,500
boe/d, and expect full year production to be near the upper end of this
new range. We currently anticipate providing 2015 production and
capital expenditure guidance in early December 2014.
-
We celebrated our 20th Anniversary as a publicly traded company in 2014. This has been a
rewarding period of growth and achievement for our company, and we are
proud of our progress to date. Most importantly, we are honored to
have provided our shareholders with a compound average total return
including dividends, as of September 30, 2014, of 36.4% per annum since
our inception. With the consistent strength of our operations and our
extensive opportunity base, we will strive to provide continued strong
financial performance, and a reliable and growing dividend stream to
investors.
(1)
|
Additional GAAP Financial Measure. Please see the "Additional and
Non-GAAP Financial Measures" section of Management's Discussion and
Analysis.
|
(2)
|
Estimated proved plus probable reserves and contingent resources
attributable to the assets as evaluated by GLJ Petroleum Consultants
Ltd. in a report dated October 28, 2014, with an effective date of July
1, 2014, using the GLJ (2014-07) price forecast.
|
(3)
|
Test results are not necessarily indicative of long-term production
performance or of ultimate recovery.
|
Vermilion Energy Inc. Third Quarter 2014 Conference Call and Audio
Webcast Details
Vermilion will discuss these results in a conference call to be held on
Monday, November 10, 2014 at 9:00 AM MST (11:00 AM EST). To
participate, you may call 1-888-231-8191 (Canada and US Toll Free) or
1-647-427-7450 (International and Toronto Area). The conference call
will also be available on replay by calling 1-855-859-2056 using
conference ID number 6117964. The replay will be available until
midnight eastern time on November 17, 2014.
You may also listen to the audio webcast at http://event.on24.com/r.htm?e=852632&s=1&k=79DE9E8E7910A2E76368C9BFBF328E76 or visit Vermilion's website at www.vermilionenergy.com/ir/eventspresentations.cfm.
DISCLAIMER
Certain statements included or incorporated by reference in this
document may constitute forward looking statements or financial
outlooks under applicable securities legislation. Such forward looking
statements or information typically contain statements with words such
as "anticipate", "believe", "expect", "plan", "intend", "estimate",
"propose", or similar words suggesting future outcomes or statements
regarding an outlook. Forward looking statements or information in
this document may include, but are not limited to: capital
expenditures; business strategies and objectives; operational and
financial performance; estimated reserve quantities and the discounted
present value of future net cash flows from such reserves; petroleum
and natural gas sales; future production levels (including the timing
thereof) and rates of average annual production growth; estimated
contingent resources and prospective resources; exploration and
development plans; acquisition and disposition plans and the timing
thereof; operating and other expenses, including the payment and amount
of future dividends; royalty and income tax rates; the timing of
regulatory proceedings and approvals; and the timing of first
commercial natural gas and the estimate of Vermilion's share of the
expected natural gas production from the Corrib field.
Such forward looking statements or information are based on a number of
assumptions all or any of which may prove to be incorrect. In addition
to any other assumptions identified in this document, assumptions have
been made regarding, among other things: the ability of Vermilion to
obtain equipment, services and supplies in a timely manner to carry out
its activities in Canada and internationally; the ability of Vermilion
to market crude oil, natural gas liquids and natural gas successfully
to current and new customers; the timing and costs of pipeline and
storage facility construction and expansion and the ability to secure
adequate product transportation; the timely receipt of required
regulatory approvals; the ability of Vermilion to obtain financing on
acceptable terms; foreign currency exchange rates and interest rates;
future crude oil, natural gas liquids and natural gas prices; and
management's expectations relating to the timing and results of
exploration and development activities.
Although Vermilion believes that the expectations reflected in such
forward looking statements or information are reasonable, undue
reliance should not be placed on forward looking statements because
Vermilion can give no assurance that such expectations will prove to be
correct. Financial outlooks are provided for the purpose of
understanding Vermilion's financial position and business objectives
and the information may not be appropriate for other purposes. Forward
looking statements or information are based on current expectations,
estimates and projections that involve a number of risks and
uncertainties which could cause actual results to differ materially
from those anticipated by Vermilion and described in the forward
looking statements or information. These risks and uncertainties
include but are not limited to: the ability of management to execute
its business plan; the risks of the oil and gas industry, both
domestically and internationally, such as operational risks in
exploring for, developing and producing crude oil, natural gas liquids
and natural gas; risks and uncertainties involving geology of crude
oil, natural gas liquids and natural gas deposits; risks inherent in
Vermilion's marketing operations, including credit risk; the
uncertainty of reserves estimates and reserves life and estimates of
resources and associated expenditures; the uncertainty of estimates and
projections relating to production and associated expenditures;
potential delays or changes in plans with respect to exploration or
development projects; Vermilion's ability to enter into or renew leases
on acceptable terms; fluctuations in crude oil, natural gas liquids and
natural gas prices, foreign currency exchange rates and interest rates;
health, safety and environmental risks; uncertainties as to the
availability and cost of financing; the ability of Vermilion to add
production and reserves through exploration and development activities;
the possibility that government policies or laws may change or
governmental approvals may be delayed or withheld; uncertainty in
amounts and timing of royalty payments; risks associated with existing
and potential future law suits and regulatory actions against
Vermilion; and other risks and uncertainties described elsewhere in
this document or in Vermilion's other filings with Canadian securities
regulatory authorities.
The forward looking statements or information contained in this document
are made as of the date hereof and Vermilion undertakes no obligation
to update publicly or revise any forward looking statements or
information, whether as a result of new information, future events or
otherwise, unless required by applicable securities laws.
All oil and natural gas reserve information contained in this document
has been prepared and presented in accordance with National Instrument
51-101 Standards of Disclosure for Oil and Gas Activities. The actual
oil and natural gas reserves and future production will be greater than
or less than the estimates provided in this document. The estimated
future net revenue from the production of oil and natural gas reserves
does not represent the fair market value of these reserves.
Natural gas volumes have been converted on the basis of six thousand
cubic feet of natural gas to one barrel of oil equivalent. Barrels of
oil equivalent (boe) may be misleading, particularly if used in
isolation. A boe conversion ratio of six thousand cubic feet to one
barrel of 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.
Financial data contained within this document are reported in Canadian
dollars, unless otherwise stated.
ABBREVIATIONS
$M
|
|
thousand dollars
|
$MM
|
|
million dollars
|
AECO
|
|
the daily average benchmark price for natural gas at the AECO 'C' hub in
southeast Alberta
|
bbl(s)
|
|
barrel(s)
|
bbls/d
|
|
barrels per day
|
bcf
|
|
billion cubic feet
|
boe
|
|
barrel of oil equivalent, including: crude oil, natural gas liquids and
natural gas (converted on the basis of one boe for
|
|
|
six mcf of natural gas)
|
boe/d
|
|
barrel of oil equivalent per day
|
GJ
|
|
gigajoules
|
mbbls
|
|
thousand barrels
|
mboe
|
|
thousand barrel of oil equivalent
|
mcf
|
|
thousand cubic feet
|
mcf/d
|
|
thousand cubic feet per day
|
mmboe
|
|
million barrel of oil equivalent
|
mmcf
|
|
million cubic feet
|
mmcf/d
|
|
million cubic feet per day
|
MWh
|
|
megawatt hour
|
NGLs
|
|
natural gas liquids
|
PRRT
|
|
Petroleum Resource Rent Tax, a profit based tax levied on petroleum
projects in Australia
|
TTF
|
|
the day-ahead price for natural gas in the Netherlands, quoted in MWh of
natural gas, at the Title Transfer Facility
|
|
|
Virtual Trading Point operated by Dutch TSO Gas Transport Services
|
WTI
|
|
West Texas Intermediate, the reference price paid for crude oil of
standard grade in US dollars at Cushing, Oklahoma
|
|
|
|
HIGHLIGHTS
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
($M except as indicated)
|
|
|
|
Sep 30,
|
|
Jun 30,
|
|
|
Sep 30,
|
|
|
Sep 30,
|
|
|
Sep 30,
|
Financial
|
|
|
|
2014
|
|
2014
|
|
|
2013
|
|
|
2014
|
|
|
2013
|
Petroleum and natural gas sales
|
|
|
|
344,688
|
|
387,684
|
|
|
327,185
|
|
|
1,113,555
|
|
|
948,727
|
Fund flows from operations (1)
|
|
|
|
197,898
|
|
216,076
|
|
|
165,645
|
|
|
619,337
|
|
|
503,866
|
|
Fund flows from operations ($/basic share)
|
|
|
|
1.85
|
|
2.05
|
|
|
1.63
|
|
|
5.90
|
|
|
5.01
|
|
Fund flows from operations ($/diluted share)
|
|
|
|
1.83
|
|
2.01
|
|
|
1.61
|
|
|
5.81
|
|
|
4.94
|
Net earnings
|
|
|
|
53,903
|
|
53,993
|
|
|
67,796
|
|
|
210,684
|
|
|
226,131
|
|
Net earnings ($/basic share)
|
|
|
|
0.50
|
|
0.51
|
|
|
0.67
|
|
|
2.01
|
|
|
2.25
|
Capital expenditures
|
|
|
|
190,033
|
|
135,073
|
|
|
135,661
|
|
|
521,481
|
|
|
394,248
|
Acquisitions
|
|
|
|
40,847
|
|
381,139
|
|
|
7,586
|
|
|
600,213
|
|
|
7,586
|
Asset retirement obligations settled
|
|
|
|
4,677
|
|
2,381
|
|
|
2,738
|
|
|
9,709
|
|
|
6,496
|
Cash dividends ($/share)
|
|
|
|
0.645
|
|
0.645
|
|
|
0.600
|
|
|
1.935
|
|
|
1.800
|
Dividends declared
|
|
|
|
68,896
|
|
68,710
|
|
|
61,003
|
|
|
203,613
|
|
|
181,391
|
|
% of fund flows from operations
|
|
|
|
35%
|
|
32%
|
|
|
37%
|
|
|
33%
|
|
|
36%
|
Net dividends (1)
|
|
|
|
48,480
|
|
49,561
|
|
|
41,649
|
|
|
145,163
|
|
|
127,875
|
|
% of fund flows from operations
|
|
|
|
24%
|
|
23%
|
|
|
25%
|
|
|
23%
|
|
|
25%
|
Payout (1)
|
|
|
|
243,190
|
|
187,015
|
|
|
180,048
|
|
|
676,353
|
|
|
528,619
|
|
% of fund flows from operations
|
|
|
|
123%
|
|
87%
|
|
|
109%
|
|
|
109%
|
|
|
105%
|
|
% of fund flows from operations (excluding the Corrib project)
|
|
|
|
107%
|
|
73%
|
|
|
87%
|
|
|
97%
|
|
|
89%
|
Net debt (1)
|
|
|
|
1,243,438
|
|
1,168,998
|
|
|
700,286
|
|
|
1,243,438
|
|
|
700,286
|
Ratio of net debt to annualized fund flows from operations (1)
|
|
|
|
1.6
|
|
1.4
|
|
|
1.1
|
|
|
1.5
|
|
|
1.0
|
Operational
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
|
29,147
|
|
30,184
|
|
|
26,664
|
|
|
28,890
|
|
|
25,640
|
|
NGLs (bbls/d)
|
|
|
|
2,354
|
|
2,892
|
|
|
1,945
|
|
|
2,463
|
|
|
1,719
|
|
Natural gas (mmcf/d)
|
|
|
|
110.52
|
|
114.08
|
|
|
77.41
|
|
|
109.33
|
|
|
81.97
|
|
Total (boe/d)
|
|
|
|
49,920
|
|
52,089
|
|
|
41,510
|
|
|
49,574
|
|
|
41,020
|
Average realized prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and NGLs ($/bbl)
|
|
|
|
102.49
|
|
109.89
|
|
|
108.87
|
|
|
108.02
|
|
|
103.95
|
|
Natural gas ($/mcf)
|
|
|
|
5.74
|
|
6.19
|
|
|
6.00
|
|
|
6.60
|
|
|
6.68
|
Production mix (% of production)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% priced with reference to WTI
|
|
|
|
28%
|
|
30%
|
|
|
24%
|
|
|
27%
|
|
|
24%
|
|
% priced with reference to AECO
|
|
|
|
18%
|
|
18%
|
|
|
17%
|
|
|
18%
|
|
|
17%
|
|
% priced with reference to TTF
|
|
|
|
18%
|
|
18%
|
|
|
14%
|
|
|
18%
|
|
|
16%
|
|
% priced with reference to Dated Brent
|
|
|
|
36%
|
|
34%
|
|
|
45%
|
|
|
37%
|
|
|
43%
|
Netbacks ($/boe) (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating netback
|
|
|
|
54.25
|
|
59.52
|
|
|
61.91
|
|
|
58.95
|
|
|
60.12
|
|
Fund flows from operations netback
|
|
|
|
44.08
|
|
46.24
|
|
|
43.60
|
|
|
46.02
|
|
|
44.13
|
|
Operating expenses
|
|
|
|
12.53
|
|
12.46
|
|
|
12.17
|
|
|
12.81
|
|
|
12.87
|
Average reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl)
|
|
|
|
97.17
|
|
102.99
|
|
|
105.82
|
|
|
99.61
|
|
|
98.14
|
|
Edmonton Sweet index (US $/bbl)
|
|
|
|
89.24
|
|
96.85
|
|
|
101.10
|
|
|
92.17
|
|
|
93.03
|
|
Dated Brent (US $/bbl)
|
|
|
|
101.85
|
|
109.63
|
|
|
110.37
|
|
|
106.57
|
|
|
108.45
|
|
AECO ($/GJ)
|
|
|
|
3.81
|
|
4.44
|
|
|
2.31
|
|
|
4.56
|
|
|
2.89
|
|
TTF ($/GJ)
|
|
|
|
7.26
|
|
7.91
|
|
|
9.94
|
|
|
8.41
|
|
|
10.17
|
Average foreign currency exchange rates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CDN $/US $
|
|
|
|
1.09
|
|
1.09
|
|
|
1.04
|
|
|
1.09
|
|
|
1.02
|
|
CDN $/Euro
|
|
|
|
1.44
|
|
1.50
|
|
|
1.38
|
|
|
1.48
|
|
|
1.35
|
Share information ('000s)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares outstanding - basic
|
|
|
|
106,921
|
|
106,620
|
|
|
101,787
|
|
|
106,921
|
|
|
101,787
|
Shares outstanding - diluted (1)
|
|
|
|
109,749
|
|
109,371
|
|
|
104,195
|
|
|
109,749
|
|
|
104,195
|
Weighted average shares outstanding - basic
|
|
|
|
106,768
|
|
105,577
|
|
|
101,613
|
|
|
104,891
|
|
|
100,634
|
Weighted average shares outstanding - diluted (1)
|
|
|
|
108,290
|
|
107,330
|
|
|
102,763
|
|
|
106,582
|
|
|
102,083
|
(1)
|
The above table includes additional GAAP and non-GAAP financial measures
which may not be comparable to other companies. Please see the
"ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of Management's
Discussion and Analysis.
|
MESSAGE TO SHAREHOLDERS
In 2014, we celebrated Vermilion's 20th anniversary as a publicly traded company. It has been a demanding, but
also a tremendously rewarding 20 years. During this time, we have
witnessed significant change and encountered many challenges to the
industry, and we are particularly proud of our demonstrated ability to
effectively navigate those challenges to the benefit of our
shareholders. Today's environment is no different. The recent
volatility in the capital markets, and more particularly in the energy
sector (due to a rapid fall in commodity prices and near term price
expectations), creates yet another opportunity for us to demonstrate
the sustainability of our business model and the advantages of our
diversified portfolio. Vermilion's relative performance during this
period has once again demonstrated the stable and defensive nature of
our business, our strong positioning within the industry, and our
shareholders' continued confidence in our ability to prosper. Our
balance sheet remains strong and we believe our longer-term focus,
combined with our conservative approach and patience, will allow us to
create further opportunity for our shareholders in the current
environment.
Reflecting on Vermilion's record, we are pleased that our previous
efforts have resulted in a compound average total return including
dividends, as of September 30, 2014, of 36.4% per annum since
inception. We are also proud of the consistency of those returns. Over
the last one, three, five, ten and 15 calendar-year periods, we have
reliably delivered double-digit compound average total returns of
24.6%, 14.5%, 24.0%, 18.6% and 25.5%, respectively.
In spite of current commodity price weakness, we continue to believe
that Vermilion is better situated for continued growth than at any
other time in our history. With the consistent performance of our
operations and our expansive and growing opportunity base, we remain
confident that we are positioned to deliver continued strong
operational and financial performance in the future, while also
providing a reliable and growing dividend stream to our shareholders.
We are confident that the assets in our current portfolio contain
significant opportunity for growth for years to come. In the current
environment, we also find ourselves positioned to enhance growth in
shareholder value and further diversify our opportunity base through
acquisition activity in both North American and international markets.
In February 2014 we announced our entry into Germany. Germany has a
long history of oil and gas development activity, low political risk
and strong marketing fundamentals. The acquisition provides us with
entry into this sizable market, in the form of free cash flow(1) generating, low-decline assets with near-term development inventory in
addition to longer-term, low-permeability gas prospectivity. We
believe that our conventional and unconventional expertise, coupled
with new access to proprietary technical data, will position us for
future development and expansion opportunities in both Germany and the
greater European region.
In late April 2014 we announced the completion of our acquisition of
Elkhorn Resources Inc., a private southeast Saskatchewan producer. The
acquired assets consist of high netback, light oil production in the
Northgate region of southeast Saskatchewan and include approximately
57,000 net acres of land (approximately 80% undeveloped), seven oil
batteries, and preferential access to 50% or greater capacity at a
solution gas facility that is currently under construction.
In addition, we recently completed an $11.1 million transaction which
marks our first acquisition in the United States, representing a
low-cost entry position in the prolific Powder River Basin of
northeastern Wyoming. The transaction provides a promising tight oil
development project, and we have put in place the human resources
necessary to support future organic growth and acquisitions in the
region. Through the transaction, we acquired approximately 68,000 acres
of land (98% undeveloped) with current working interest production of
approximately 200 bbls/d (100% oil), proved plus probable reserves
estimated at 2.2(2) million boe (82% oil) and contingent resource of 10.0(2) million boe (82% oil). Transaction metrics, with no deduction for land
value, equate to approximately $56,000 per boe/d and $20.98 per boe,
including future development costs of approximately $35.3 million. The
land base includes 53,000 net acres at a 70% operated working interest
in a promising tight oil project in the Turner Sand at a depth of
approximately 1,500 metres. The most recently completed well on this
land block (70% working interest) is currently producing approximately
220 bbls/d of oil in its fourth month of production, from an
approximately 1,100 metre hydraulically-fractured horizontal lateral.
Looking ahead we see continued opportunity for expansion. In North
America, we are faced with an active asset market and we continue to
see technology unlocking new opportunities for development. With
Vermilion's access to relatively low cost capital, our conservative
balance sheet, and significant near-term free cash flow growth on the
horizon (including from Corrib, which is expected to commence
production in mid-2015), we are well positioned to compete and transact
should suitable opportunities arise. While international asset markets
remain substantially less liquid than in North America, we similarly
find ourselves well-positioned for assets that do become available in
our selective regions of interest.
The third quarter of 2014 marks another quarter of consistent
operational execution for our Company. We continue to achieve strong
results from our successful Mannville condensate-rich gas and Cardium
light-oil development programs in Canada. Our strong Cardium results
reflect continued improvements in completions design and
better-than-forecasted production volumes on several of our two-mile
extended reach horizontal Cardium wells. With improving efficiencies
and productivity, we will require less capital than originally
anticipated to meet our development objectives for the Cardium. As a
result, we are able to increase our current focus on development of our
extensive Mannville resource base which has generated very robust
economics to-date. Looking forward, we anticipate our Mannville
drilling activity will continue to increase in future years as we
continue to develop our substantial inventory of highly economic
prospects. During the quarter we also initiated a two-rig, 12-well
Midale drilling program in southeast Saskatchewan. We have currently
identified approximately 190 net potential drilling locations targeting
the Midale, Frobisher, Bakken, and Three Forks/Torquay formations on
our southeast Saskatchewan lands. In addition, we have expanded our
southeast Saskatchewan land base during the quarter through the
purchase at Crown land sales of approximately 15,000 net acres of
undeveloped land to the northwest of our existing lands, adding an
estimated 60 new development locations.
The appraisal of our position in the Duvernay condensate-rich resource
play continues. To-date, we have amassed 317 net sections at the
relatively low cost of $76 million ($375/acre). Our position comprises
three largely contiguous blocks in the Edson, West Pembina and Niton
areas. To date, we have drilled three vertical stratigraphic test
wells, and have completed drilling operations on two horizontal
appraisal wells. The first horizontal appraisal well drilled (1,180
meters horizontal length) is located in the downdip part of our Edson
block where condensate yields are expected to be lower than the average
of our overall land position. We selected this location because of its
proximity to one of our vertical stratigraphic test wells, allowing us
to conduct microseismic monitoring in the stratigraphic test well when
we frac the horizontal well (expected to occur during the fourth
quarter of 2014). Our second horizontal appraisal well (1,280 meters
horizontal length), which we operate at a 34.8% working interest, is
located along a shared lease-line in the Pembina block to allow partner
participation. Completion activities on the Pembina well, including
microseismic monitoring, were completed during the third quarter. The
well was brought on production in October 2014 and has produced for 16
days. Raw gas rate has averaged 2.2 mmcf/d (expected sales gas rate of
1.8 mmcf/d after liquids shrink and plant fuel) with an estimated
hydrocarbon liquids rate of approximately 180 bbls/d (approximately 60%
pentanes plus). The well is producing at restricted rates using a 12/64
inch downhole choke to generate an estimated flowing bottomhole
pressure of 4,200 psi (approximately 55% drawdown). Our Edson Duvernay
horizontal appraisal well (100% working interest) is expected to be
brought on production late in Q4 2014.
Our development-phase target for Duvernay well costs (including drill,
complete, equip and tie-in) is $12 to $15 million. We believe that
development-phase savings will be achievable through learning-curve
improvements, lower lease construction costs, economies of scale in
procurement and lower evaluation expenditures (such as the elimination
of microseismic monitoring). We anticipate that the production results
and interpreted fracture geometries from the microseismic data on these
appraisal wells will assist us in optimizing completions on future
development-phase horizontal wells. We are confident that we will be
able to project the appraisal well results to higher condensate yield
locations as we move to the northeast in our acreage position, which
encompasses the entire breadth of the condensate-rich window. Our
Duvernay rights generally underlie our Cardium oil and Mannville
condensate-rich gas rights, which creates the potential for
infrastructure, operational, and timing advantages if we progress to
full development of the Duvernay condensate-rich resource play. In
combination, our Cardium, Mannville, and Duvernay positions provide us
with exploration and development opportunities in our core Canadian
operating region that have the potential to deliver strong production
and reserve growth into the next decade.
We were also active in Europe during the third quarter of 2014 with
ongoing drilling operations in both France and the Netherlands. In
France, we completed our five-well Champotran drilling campaign in the
Paris Basin during the quarter. The five wells were brought on
production at various times during the third quarter and are producing
at oil rates averaging approximately 200 bbls/d per well. The final
well of our 2014 drilling campaign in France (Tamaris in the Aquitaine
Basin) is anticipated to be drilled and completed during the fourth
quarter. During the third quarter of 2014, we furthered preparations
for the phased transfer of our shut-in Vic Bilh natural gas production
from the Lacq gas processing facility where it was previously handled
to a new third party facility. Delays in receiving required permit
transfers have pushed our original plans to bring approximately 850
mcf/d of solution gas back on-stream from the third quarter of 2014 to
early 2015. The remainder of the shut-in gas production, approximately
3,400 mcf/d of gas cap gas, is expected to be back on production in
early 2016.
In the Netherlands, we drilled the Diever-02 exploratory well (45%
working interest) during the third quarter in the Drenthe IIIb
concession on lands acquired in October 2013. This well primarily
targeted the Rotliegend Group (Permian sandstones) and encountered two
well-developed gas bearing intervals (Akkrum and Slochteren) with a net
pay thickness of approximately 36 metres. A three-hour clean-up test
was conducted on the Slochteren formation which delivered 25.7 mmcf/d
of gas on a 40/64 inch choke with 2,615 psi flowing tubing pressure
with no indications of pressure drop during the test(3). The flow rate was limited by the 3.5 inch diameter of the tubing and
the capacity of the test equipment. The well is expected to be tied-in
with production from the Slochteren formation in Q4 2015 at an
estimated rate of approximately 1,000 boe/d, net to Vermilion. The
Akkrum formation is anticipated to be perforated at a later date once
the Slochteren formation has been fully produced.
Subsequent to the end of the third quarter, we drilled a gas discovery
well in the Netherlands at the Langezwaag-02 location (42.3% working
interest) in the Gorredijk concession. This extended reach well
recorded significant gas shows in two metres of Vlieland Sandstone and
21 metres of Zechstein-2 Carbonate. Open hole logs could not be run in
the highly deviated well. The Langezwaag-02 well was first flow tested
from the Zechstein-2 Carbonate at 12.4 mmcf/d through a 48/64 inch
choke at a flowing tubing pressure of approximately 1,300 psi. A
second flow test in the Vlieland Sandstone yielded rates of 2.7 mmcf/d
through a 32/64 inch choke at a flowing tubing pressure of
approximately 960 psi. The remaining well of the 2014 drilling campaign
is expected to be drilled and completed during the fourth quarter of
2014.
Our newly acquired position in Germany enables us to participate, on a
non-operated basis, in the exploration, development, production and
transportation of natural gas from four gas producing fields across 11
production licenses. The assets include both exploration and
production licenses that comprise a total of 207,000 gross acres, of
which 85% is in the exploration license. During the first quarter of
2014, we participated in the drilling of the Deblinghausen Z7a
development well (25% working interest) in Germany. The well logged 81
metres of net pay in the Zechstein Carbonate, and was tested in late
September 2014 for a period of 17 days. During production testing, the
well produced at an average rate of 10.2 mmcf/d at a flowing tubing
pressure of 1,840 psi(3). Subsequent to the end of the quarter, this well was placed on
production at an initial gross production rate of 16.5 mmcf/d of raw
gas at a flowing tubing pressure of approximately 1,300 psi.
Our Corrib project in Ireland has continued to progress on schedule
following the completion of tunnel boring operations in May 2014.
Project operator Shell Exploration & Production Ireland Ltd. (SEPIL)
successfully completed offshore workover and pipeline operations during
the third quarter and the wells are ready for operation. SEPIL also
significantly advanced tunnel outfitting, which is now estimated to be
approximately 95% complete following installation of flow and umbilical
lines in the 4.9 km tunnel. Remaining activities include final cable
installation, hydro-testing and grouting, as well as commissioning of
the gas processing facility and finalization of operating permits. We
anticipate first gas from Corrib in approximately mid-2015, with peak
production estimated at approximately 58 mmcf/d (approximately 9,700
boe/d) net to Vermilion.
In Australia, we remain focused on completing preparations for a
two-well drilling program in 2015, as well as re-lifing and maintenance
projects on our two platforms. In order to provide long-term certainty
to purchasers of the high-value oil from Wandoo, our current plan is to
maintain field-total production levels within our prior guidance of
between 6,000 bbls/d and 8,000 bbls/d. We anticipate maintaining these
production levels in Australia for the foreseeable future with drilling
programs approximately every two years. Our Australian oil currently
garners a premium of up to US$7.00 to the Dated Brent index and incurs
no transportation cost as production is sold directly at the platform.
Our operations continue to perform strongly, generating organic
production growth in a capital-efficient manner. We are moving up our
2014 average annual production guidance from the previous range of
48,500-49,500 boe/d to a range of 49,000-49,500 boe/d, and expect full
year production to be near the upper end of this refined range.
Assuming commodity prices remain near current levels for the remainder
of 2014, we continue to anticipate that we can fully fund our net
dividends(1) and development capital expenditures (excluding capital investment at
Corrib) with fund flows from operations(1) during 2014.
We believe we remain positioned to deliver strong operational and
financial performance over the next several years. We continue to
target annual organic production growth of 5% to 7% while providing
reliable and growing dividends. Near term production and fund flows
from operations growth is expected to be driven by continued Cardium
and Mannville development in Canada, oil development activities in
France, and high-netback natural gas drilling in the Netherlands. A
significant increment of production, fund flows from operations and
free cash flow growth is expected from Corrib beginning in
approximately mid-2015 with the first full year of production from the
project in 2016. Our Australian and German business units are expected
to provide relatively steady production as well as strong free cash
flow.
In keeping with our strategy of pursuing long-term growth in our three
core regions in North America, Europe and Australia, we have
established two new offices led by locally-experienced management with
strong track records of success. As the operating headquarters of our
new U.S. Business Unit, we have opened an office in Denver, Colorado.
Daniel Anderson has joined Vermilion as Managing Director for our U.S.
subsidiary. Mr. Anderson has 30 years of experience in the upstream
and midstream energy sectors throughout the U.S. He was formerly
President of Baytex Energy USA, with previous management and technical
roles at Berry Petroleum, Williams Companies, Santa Fe Snyder and
ConocoPhillips. Mr. Anderson has a Bachelor of Science degree in
Petroleum Engineering from the Colorado School of Mines. Further
strengthening our capabilities for growth in the U.S., Timothy Morris
has joined Vermilion as Director of U.S. Business Development. Mr.
Morris has more than 30 years of experience in land management and
business development in the U.S. He was formerly Vice President of
U.S. Business Development for Baytex Energy Corporation, with previous
management and land roles at Berco Resources, Santa Fe Snyder and
Sohio. Mr. Morris has a Bachelor of Science degree in Minerals Land
Management from the University of Colorado and is a Certified Petroleum
Landman.
As the operating headquarters of our German Business Unit, we have
established an office in Berlin. Albrecht Möhring has been appointed
Managing Director of Vermilion's German Business Unit. Mr. Möhring
brings 30 years of diverse experience in the energy business to
Vermilion. He was formerly Managing Director for Germany with GDF
Suez, with previous roles as Group Exploration and Operations Manager
in Paris for GDF Suez and in management with Preussag Energie in
Germany (the predecessor of GDF Suez in Germany). Mr. Möhring has a
Master of Science degree in Petroleum Engineering from the University
of Clausthal.
The management and directors of Vermilion continue to hold approximately
6% of the outstanding shares and remain committed to delivering
superior rewards to all stakeholders. Continuing to be acknowledged
for excellence in our business practices, Vermilion was recognized for
the fifth consecutive year by the Great Place to Work® Institute in
both Canada and France in 2014. In Canada, Vermilion was ranked 5th Best Workplace in its category for 2014. More than 300 Canadian
companies participated in the survey and Vermilion was the only energy
company in Canada to be recognized as a Best Workplace. In France,
Vermilion received a special award for corporate social responsibility
and was ranked 13th Best Workplace in its category for 2014. Vermilion's Netherlands
business unit became eligible to participate in the competition for the
first time in 2014 and was ranked 10th Best Workplace in its category, the highest score of any energy company
in the survey. In October 2014 Vermilion was ranked second out of 13
in our peer group by the Carbon Disclosure Project (CDP) for our
disclosure in 2014, our inaugural year of participation with Vermilion
scoring 87 out of 100 (10 points higher than any peer group company
achieved in its inaugural year of participation).
(1)
|
The above discussion includes additional GAAP and non-GAAP measures
which may not be comparable to other companies. Please see the
"ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of Management's
Discussion and Analysis.
|
(2)
|
Estimated proved plus probable reserves and contingent resources
attributable to the assets as evaluated by GLJ Petroleum Consultants
Ltd. in a report dated October 28, 2014, with an effective date of July
1, 2014, using the GLJ (2014-07) price forecast.
|
(3)
|
Test results are not necessarily indicative of long-term production
performance or of ultimate recovery.
|
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is Management's Discussion and Analysis ("MD&A"), dated
November 6, 2014, of Vermilion Energy Inc.'s ("Vermilion" or the
"Company") operating and financial results as at and for the three and
nine months ended September 30, 2014 compared with the corresponding
periods in the prior year.
This discussion should be read in conjunction with the unaudited
condensed consolidated interim financial statements for the three and
nine months ended September 30, 2014 and the audited consolidated
financial statements for the year ended December 31, 2013 and 2012,
together with accompanying notes. Additional information relating to
Vermilion, including its Annual Information Form, is available on SEDAR
at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.
The unaudited condensed consolidated interim financial statements for
the three and nine months ended September 30, 2014 and comparative
information have been prepared in Canadian dollars, except where
another currency is indicated, and in accordance with IAS 34, "Interim
financial reporting", as issued by the International Accounting
Standard Board ("IASB").
This MD&A includes references to certain financial measures which do not
have standardized meanings prescribed by International Financial
Reporting Standards ("IFRS"). As such, these financial measures are
considered additional GAAP or non-GAAP financial measures and therefore
are unlikely to be comparable with similar financial measures presented
by other issuers. These additional GAAP and non-GAAP financial
measures include:
-
Fund flows from operations: This additional GAAP financial measure is
calculated as cash flows from operating activities before changes in
non-cash operating working capital and asset retirement obligations
settled. We analyze fund flows from operations both on a consolidated
basis and on a business unit basis in order to assess the contribution
of each business unit to our ability to generate cash necessary to pay
dividends, repay debt, fund asset retirement obligations and make
capital investments.
-
Netbacks: These non-GAAP financial measures are per boe and per mcf
measures used in the analysis of operational activities. We assess
netbacks both on a consolidated basis and on a business unit basis in
order to compare and assess the operational and financial performance
of each business unit versus other business units and third party crude
oil and natural gas producers.
For a full description of these and other non-GAAP financial measures
and a reconciliation of these measures to their most directly
comparable GAAP measures, please refer to "ADDITIONAL AND NON-GAAP
FINANCIAL MEASURES".
VERMILION'S BUSINESS
Vermilion is a Calgary, Alberta based international oil and gas producer
focused on the acquisition, development and optimization of producing
properties in Western Canada, Europe, and Australia. We manage our
business through our Calgary head office and our international business
unit offices.
This MD&A separately discusses each of our business units in addition to
our corporate segment.
-
Canada business unit: Relates to our assets in Alberta and Saskatchewan.
-
France business unit: Relates to our operations in France in the Paris
and Aquitaine Basins.
-
Netherlands business unit: Relates to our operations in the Netherlands.
-
Germany business unit: Relates to our 25% contractual participation
interest in a four-partner consortium in Germany.
-
Ireland business unit: Relates to our 18.5% non-operated interest in the
offshore Corrib natural gas field.
-
Australia business unit: Relates to our operations in the Wandoo
offshore crude oil field.
-
Corporate: Includes expenditures related to our global hedging program,
financing expenses, and general and administration expenses, primarily
incurred in Canada and not directly related to the operations of a
specific business unit.
Prior to December 31, 2013, Vermilion combined the operating and
financial results of the Canada business unit and the Corporate segment
and presented the combined results as Canada.
GUIDANCE
We first issued 2014 capital expenditure guidance of $555 million on
November 7, 2013. We subsequently increased our 2014 capital
expenditure guidance to $590 million on March 18, 2014, to reflect an
additional $35 million of 2014 development capital expected to be
incurred in association with our acquisition of Elkhorn Resources Inc.
Concurrent with the release of our first quarter 2014 financial and
operating results on May 2, 2014, we further updated our 2014 capital
expenditure guidance to $635 million, reflecting the expected full-year
rise in the cost to Vermilion, in Canadian dollar terms, of both actual
and anticipated international capital expenditures as a result of the
devaluation of the Canadian dollar against both the U.S. dollar and the
Euro, and the addition of approximately $15 million of anticipated
spending associated with drilling activities. We also increased our
original production guidance from 47,500-48,500 boe/d to 48,000-49,000
boe/d.
Based on the continued strength of our operations during the second
quarter of 2014, we further increased our full-year 2014 production and
capital expenditure guidance to 48,500-49,500 boe/d and $650 million,
respectively. The increase in capital expenditures was attributed to
increased Mannville development drilling and higher than anticipated
costs associated with the Duvernay development program.
We are further revising our 2014 full year production guidance from the
previous range of 48,500-49,500 boe/d to a range of 49,000-49,500 boe/d
and currently expect to achieve production near the upper end of this
refined range for 2014.
The following table summarizes our 2014 guidance:
|
|
|
|
Date
|
|
|
|
|
|
Capital Expenditures ($MM)
|
|
|
|
|
|
Production (boe/d)
|
2014 Guidance
|
|
|
|
November 7, 2013
|
|
|
|
|
|
555
|
|
|
|
|
|
45,000 to 46,000
|
2014 Guidance - Update
|
|
|
|
March 18, 2014
|
|
|
|
|
|
590
|
|
|
|
|
|
47,500 to 48,500
|
2014 Guidance - Update
|
|
|
|
May 2, 2014
|
|
|
|
|
|
635
|
|
|
|
|
|
48,000 to 49,000
|
2014 Guidance - Update
|
|
|
|
July 31, 2014
|
|
|
|
|
|
650
|
|
|
|
|
|
48,500 to 49,500
|
2014 Guidance - Update
|
|
|
|
November 10, 2014
|
|
|
|
|
|
650
|
|
|
|
|
|
49,000 to 49,500
|
SHAREHOLDER RETURN
Vermilion strives to provide investors with reliable and growing
dividends in addition to sustainable, global production growth. The
following table, as of September 30, 2014, reflects our trailing one,
three, and five year performance:
Total return (1)
|
|
|
Trailing One Year
|
|
|
|
Trailing Three Year
|
|
|
|
Trailing Five Year
|
Dividends per Vermilion share
|
|
|
$2.54
|
|
|
|
$7.19
|
|
|
|
$11.75
|
Capital appreciation per Vermilion share
|
|
|
$11.56
|
|
|
|
$24.14
|
|
|
|
$38.60
|
Total return per Vermilion share
|
|
|
24.9%
|
|
|
|
71.1%
|
|
|
|
170.2%
|
Annualized total return per Vermilion share
|
|
|
24.9%
|
|
|
|
19.6%
|
|
|
|
22.0%
|
Annualized total return on the S&P TSX High Income Energy Index
|
|
|
13.2%
|
|
|
|
7.6%
|
|
|
|
7.5%
|
(1)
|
The above table includes non-GAAP financial measures which may not be
comparable to other companies. Please see the "ADDITIONAL AND NON-GAAP
FINANCIAL MEASURES" section of this MD&A.
|
CONSOLIDATED RESULTS OVERVIEW
|
|
|
|
Three Months Ended
|
|
% change
|
|
Nine Months Ended
|
|
% change
|
|
|
|
|
Sep 30,
|
|
Jun 30,
|
|
|
Sep 30,
|
|
Q3/14 vs.
|
|
Q3/14 vs.
|
|
Sep 30,
|
|
|
Sep 30,
|
|
2014 vs.
|
|
|
|
|
2014
|
|
2014
|
|
|
2013
|
|
Q2/14
|
|
Q3/13
|
|
2014
|
|
|
2013
|
|
2013
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
29,147
|
|
30,184
|
|
|
26,664
|
|
(3%)
|
|
9%
|
|
28,890
|
|
|
25,640
|
|
13%
|
|
NGLs (bbls/d)
|
|
|
2,354
|
|
2,892
|
|
|
1,945
|
|
(19%)
|
|
21%
|
|
2,463
|
|
|
1,719
|
|
43%
|
|
Natural gas (mmcf/d)
|
|
|
110.52
|
|
114.08
|
|
|
77.41
|
|
(3%)
|
|
43%
|
|
109.33
|
|
|
81.97
|
|
33%
|
|
Total (boe/d)
|
|
|
49,920
|
|
52,089
|
|
|
41,510
|
|
(4%)
|
|
20%
|
|
49,574
|
|
|
41,020
|
|
21%
|
|
Build (draw) in inventory (mbbl)
|
|
|
104
|
|
67
|
|
|
20
|
|
|
|
|
|
74
|
|
|
(218)
|
|
|
Financial metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fund flows from operations ($M)
|
|
|
197,898
|
|
216,076
|
|
|
165,645
|
|
(8%)
|
|
19%
|
|
619,337
|
|
|
503,866
|
|
23%
|
|
Per share ($/basic share)
|
|
|
1.85
|
|
2.05
|
|
|
1.63
|
|
(10%)
|
|
13%
|
|
5.90
|
|
|
5.01
|
|
18%
|
|
Net earnings ($M)
|
|
|
53,903
|
|
53,993
|
|
|
67,796
|
|
-
|
|
(20%)
|
|
210,684
|
|
|
226,131
|
|
(7%)
|
|
Per share ($/basic share)
|
|
|
0.50
|
|
0.51
|
|
|
0.67
|
|
(2%)
|
|
(25%)
|
|
2.01
|
|
|
2.25
|
|
(11%)
|
|
Cash flows from operating activities ($M)
|
|
|
235,010
|
|
149,592
|
|
|
158,236
|
|
57%
|
|
49%
|
|
562,840
|
|
|
528,022
|
|
7%
|
|
Net debt ($M)
|
|
|
1,243,438
|
|
1,168,998
|
|
|
700,286
|
|
6%
|
|
78%
|
|
1,243,438
|
|
|
700,286
|
|
78%
|
|
Cash dividends ($/share)
|
|
|
0.645
|
|
0.645
|
|
|
0.600
|
|
-
|
|
8%
|
|
1.935
|
|
|
1.800
|
|
8%
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
|
|
190,033
|
|
135,073
|
|
|
135,661
|
|
41%
|
|
40%
|
|
521,481
|
|
|
394,248
|
|
32%
|
|
Acquisitions ($M)
|
|
|
40,847
|
|
381,139
|
|
|
7,586
|
|
(89%)
|
|
438%
|
|
600,213
|
|
|
7,586
|
|
7,812%
|
|
Gross wells drilled
|
|
|
26.00
|
|
13.00
|
|
|
21.00
|
|
|
|
|
|
63.00
|
|
|
55.00
|
|
|
|
Net wells drilled
|
|
|
20.31
|
|
6.72
|
|
|
16.26
|
|
|
|
|
|
45.86
|
|
|
47.62
|
|
|
Operational review
-
Recorded consolidated average production of 49,920 boe/d during Q3 2014,
a 4% decrease as compared to Q2 2014. This decrease was primarily
driven by a 7% quarter-over-quarter decrease in production in Canada
following reduced activity during spring breakup in Q2 2014.
-
Increased consolidated average production for the three and nine months
ended September 30, 2014 by approximately 20% versus the comparable
periods in 2013, primarily due to growth in Canada, the Netherlands,
and incremental production from our acquisition in Germany. In Canada,
production growth of 36% and 33% for the three and nine months ended
September 30, 2014 versus the comparable periods in 2013 resulted from
our continued development of the Cardium and Mannville plays in Alberta
coupled with incremental production from southeast Saskatchewan
following our acquisition in April 2014 of Elkhorn Resources Inc.
(1,524 boe/d in the year-to-date period). In the Netherlands,
production growth of 32% and 17% for the three and nine months ended
September 30, 2014 versus the comparable periods in 2013 resulted from
incremental production from our acquisition in the Netherlands in Q4
2013, increased volumes following completion of the Middenmeer
Treatment Centre retrofit in the latter part of 2013, and ongoing
recompletion and production optimization activities. These production
increases were partially offset by decreased production in France due
primarily to the temporary shut-in of natural gas production from the
Vic Bilh field for the entirety of 2014.
-
Activity during the quarter included capital expenditures totalling
$190.0 million, incurred primarily in Canada, France, and Ireland. In
Canada, capital expenditures totalling $97.4 million were significantly
higher than the $37.0 million incurred in Q2 2014 and related to the
drilling of 16.86 net wells (3.29 net wells in Q2 2014), with activity
influenced by spring breakup in Q2 2014. In France, capital
expenditures of $35.1 million related to the drilling of 3.0 net wells
in the Champotran field. In Ireland, $30.1 million of capital
expenditures were incurred relating to various tunnel outfitting and
offshore workover activities.
-
Acquisition expenditures for the quarter totalling $40.8 million related
to our acquisition in the U.S. and crown land sales, primarily in
southeast Saskatchewan, with the purchase of approximately 15,000 net
acres.
Financial review
Net earnings
-
Net earnings for Q3 2014 was $53.9 million ($0.50/basic share) as
compared to $54.0 million ($0.51/basic share) for Q2 2014.
Quarter-over-quarter net earnings were relatively consistent as lower
petroleum and natural gas sales ("sales") and operating income were
offset by gains on derivative instruments (including $7.8 million of
unrealized gains due to lower forecasted pricing for the remainder of
2014 and the impact on the valuation of our crude oil derivative
positions) and lower unrealized foreign exchange losses. Unrealized
foreign exchange losses primarily resulted from the weakening of the
Euro versus the Canadian dollar and the resulting impact on our Euro
denominated financial assets. In Q3 2014, the Euro weakened by 3%
versus 4% in Q2 2014.
-
Net earnings for the three and nine months ended September 30, 2014 were
20% and 7% lower versus the respective comparable periods in 2013.
These decreases occurred despite significantly increased revenue due to
the impact of the aforementioned unrealized foreign exchange losses,
increased depletion expense associated with higher production, and
higher deferred tax expense due to the utilization of tax losses in
Canada.
Cash flows from operating activities
-
Cash flow from operations increased by 49% and 7% for the three and nine
months ended September 30, 2014 as compared to the same period in
2013. Both increases were the result of higher produced volumes and
the resulting increase in fund flows from operations. For the nine
months ended September 30, 2014, this increase in fund flows from
operations was partially offset by timing differences pertaining to
working capital balances.
Fund flows from operations
-
Generated fund flows from operations of $197.9 million during Q3 2014, a
decrease of $18.2 million (8%) versus Q2 2014. This
quarter-over-quarter decrease was the result of lower sales partially
offset by increased realized derivative gains and decreases in
corporate income taxes. Lower sales were driven largely by weaker
commodity pricing coupled with lower sold volumes in Canada and an
inventory build in France, partially offset by increased sold volumes
in Australia. Lower corporate income taxes was the result of lower
taxable income resulting from decreased sales and revisions to the
estimated 2014 effective tax rate in France.
-
Fund flows from operations increased by 19% and 23% for the three and
nine months ended September 30, 2014, respectively, versus the
comparable periods in 2013. These increases were primarily the result
of increased sales volumes in Canada and the Netherlands coupled with
incremental production following our Q1 2014 acquisition in Germany,
partially offset by a build in inventory in Australia for both the
three and nine months ended September 30, 2014.
Net debt
-
As a result of funding our 2014 acquisitions in Germany and
Saskatchewan, net debt increased to $1.2 billion or 1.5 times
annualized cash flow as at September 30, 2014.
Dividends
-
Declared dividends of $0.215 per common share per month during 2014,
totalling $0.645 per common share for the quarter and $1.935 per common
share for the year-to-date period.
COMMODITY PRICES
|
|
|
Three Months Ended
|
|
% change
|
|
Nine Months Ended
|
|
% change
|
|
|
|
Sep 30,
|
|
|
Jun 30,
|
|
|
Sep 30,
|
|
Q3/14 vs.
|
|
Q3/14 vs.
|
|
Sep 30,
|
|
Sep 30,
|
|
2014 vs.
|
|
|
|
2014
|
|
|
2014
|
|
|
2013
|
|
Q2/14
|
|
Q3/13
|
|
2014
|
|
2013
|
|
2013
|
Average reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl)
|
|
|
97.17
|
|
|
102.99
|
|
|
105.82
|
|
(6%)
|
|
(8%)
|
|
99.61
|
|
98.14
|
|
1%
|
Edmonton Sweet index (US $/bbl)
|
|
|
89.24
|
|
|
96.85
|
|
|
101.10
|
|
(8%)
|
|
(12%)
|
|
92.17
|
|
93.03
|
|
(1%)
|
Dated Brent (US $/bbl)
|
|
|
101.85
|
|
|
109.63
|
|
|
110.37
|
|
(7%)
|
|
(8%)
|
|
106.57
|
|
108.45
|
|
(2%)
|
AECO ($/GJ)
|
|
|
3.81
|
|
|
4.44
|
|
|
2.31
|
|
(14%)
|
|
65%
|
|
4.56
|
|
2.89
|
|
58%
|
TTF ($/GJ)
|
|
|
7.26
|
|
|
7.91
|
|
|
9.94
|
|
(8%)
|
|
(27%)
|
|
8.41
|
|
10.17
|
|
(17%)
|
TTF (€/GJ)
|
|
|
5.04
|
|
|
5.27
|
|
|
7.20
|
|
(4%)
|
|
(30%)
|
|
5.68
|
|
7.53
|
|
(25%)
|
Average foreign currency exchange rates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CDN $/US $
|
|
|
1.09
|
|
|
1.09
|
|
|
1.04
|
|
-
|
|
5%
|
|
1.09
|
|
1.02
|
|
7%
|
CDN $/Euro
|
|
|
1.44
|
|
|
1.50
|
|
|
1.38
|
|
(4%)
|
|
4%
|
|
1.48
|
|
1.35
|
|
10%
|
Average realized prices ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
64.85
|
|
|
71.56
|
|
|
63.56
|
|
(9%)
|
|
2%
|
|
68.58
|
|
61.16
|
|
12%
|
France
|
|
|
107.99
|
|
|
117.29
|
|
|
107.08
|
|
(8%)
|
|
1%
|
|
114.36
|
|
104.29
|
|
10%
|
Netherlands
|
|
|
45.73
|
|
|
48.14
|
|
|
61.44
|
|
(5%)
|
|
(26%)
|
|
52.80
|
|
62.70
|
|
(16%)
|
Germany
|
|
|
36.43
|
|
|
45.36
|
|
|
-
|
|
(20%)
|
|
100%
|
|
44.68
|
|
-
|
|
100%
|
Australia
|
|
|
119.07
|
|
|
126.87
|
|
|
120.95
|
|
(6%)
|
|
(2%)
|
|
124.59
|
|
117.65
|
|
6%
|
Consolidated
|
|
|
76.80
|
|
|
82.96
|
|
|
86.10
|
|
(7%)
|
|
(11%)
|
|
82.73
|
|
83.10
|
|
-
|
Production mix (% of production)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% priced with reference to WTI
|
|
|
28%
|
|
|
30%
|
|
|
24%
|
|
|
|
|
|
27%
|
|
24%
|
|
|
% priced with reference to AECO
|
|
|
18%
|
|
|
18%
|
|
|
17%
|
|
|
|
|
|
18%
|
|
17%
|
|
|
% priced with reference to TTF
|
|
|
18%
|
|
|
18%
|
|
|
14%
|
|
|
|
|
|
18%
|
|
16%
|
|
|
% priced with reference to Dated Brent
|
|
|
36%
|
|
|
34%
|
|
|
45%
|
|
|
|
|
|
37%
|
|
43%
|
|
|
Reference prices
-
Weakening global oil fundamentals, marked by a growing supply surplus,
prompted a decline in oil prices throughout Q3 2014. Averaging the
quarter at US $101.85/bbl, Dated Brent was 7% lower
quarter-over-quarter and 8% below the same period last year.
-
WTI also suffered downward price pressure throughout Q3 2014 despite
strong refining runs and averaged US $97.17/bbl or 6% lower than Q2
2014 and 8% lower year-over-year.
-
AECO natural gas fell 14% quarter-over-quarter to average $3.81/GJ in Q3
2014. Even as seasonal factors weighed on prices on a
quarter-over-quarter basis, low storage levels and relatively strong
flows on export pipelines led prices up 65% year-over-year.
-
European natural gas continued to weaken over the quarter as
above-normal storage levels, LNG weakness and modest summer demand led
prices lower by 8% quarter-over-quarter and 27% versus the same period
last year.
-
The Canadian dollar was relatively flat quarter-over-quarter but 5%
weaker to the US dollar year-over-year.
Realized prices
-
Consolidated realized price decreased by 7% for Q3 2014 as compared to
Q2 2014 and 11% as compared to Q3 2013. These decreases were primarily
the result of weaker commodity reference prices during Q3 2014 versus
the comparable quarters.
-
Consolidated realized price for the nine months ended September 30, 2014
was relatively unchanged versus the same period in 2013 as the impact
of weaker TTF pricing was offset by stronger AECO pricing and a weaker
Canadian dollar.
FUND FLOWS FROM OPERATIONS
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
Sep 30, 2014
|
|
Jun 30, 2014
|
|
Sep 30, 2013
|
|
Sep 30, 2014
|
|
Sep 30, 2013
|
|
|
$M
|
|
$/boe
|
|
$M
|
|
$/boe
|
|
$M
|
|
$/boe
|
|
$M
|
|
$/boe
|
|
$M
|
|
$/boe
|
Petroleum and natural gas sales
|
|
344,688
|
|
76.80
|
|
387,684
|
|
82.96
|
|
327,185
|
|
86.10
|
|
1,113,555
|
|
82.73
|
|
948,727
|
|
83.10
|
Royalties
|
|
(29,000)
|
|
(6.46)
|
|
(29,013)
|
|
(6.21)
|
|
(18,730)
|
|
(4.93)
|
|
(82,037)
|
|
(6.09)
|
|
(50,320)
|
|
(4.41)
|
Petroleum and natural gas revenues
|
|
315,688
|
|
70.34
|
|
358,671
|
|
76.75
|
|
308,455
|
|
81.17
|
|
1,031,518
|
|
76.64
|
|
898,407
|
|
78.69
|
Transportation expense
|
|
(10,979)
|
|
(2.45)
|
|
(12,032)
|
|
(2.57)
|
|
(6,549)
|
|
(1.72)
|
|
(32,872)
|
|
(2.44)
|
|
(19,843)
|
|
(1.74)
|
Operating expense
|
|
(56,227)
|
|
(12.53)
|
|
(58,213)
|
|
(12.46)
|
|
(46,246)
|
|
(12.17)
|
|
(172,426)
|
|
(12.81)
|
|
(146,903)
|
|
(12.87)
|
General and administration
|
|
(16,262)
|
|
(3.62)
|
|
(17,762)
|
|
(3.80)
|
|
(12,033)
|
|
(3.17)
|
|
(48,491)
|
|
(3.60)
|
|
(35,956)
|
|
(3.15)
|
PRRT
|
|
(13,834)
|
|
(3.08)
|
|
(12,699)
|
|
(2.72)
|
|
(15,649)
|
|
(4.12)
|
|
(46,772)
|
|
(3.47)
|
|
(39,392)
|
|
(3.45)
|
Corporate income taxes
|
|
(17,454)
|
|
(3.89)
|
|
(32,635)
|
|
(6.98)
|
|
(46,453)
|
|
(12.22)
|
|
(88,692)
|
|
(6.59)
|
|
(118,729)
|
|
(10.40)
|
Interest expense
|
|
(12,918)
|
|
(2.88)
|
|
(12,334)
|
|
(2.64)
|
|
(10,109)
|
|
(2.66)
|
|
(36,712)
|
|
(2.73)
|
|
(28,134)
|
|
(2.46)
|
Realized gain (loss) on derivative instruments
|
|
8,837
|
|
1.97
|
|
2,419
|
|
0.52
|
|
(4,765)
|
|
(1.25)
|
|
13,896
|
|
1.03
|
|
(5,782)
|
|
(0.51)
|
Realized foreign exchange gain (loss)
|
|
812
|
|
0.17
|
|
587
|
|
0.12
|
|
(1,227)
|
|
(0.32)
|
|
(642)
|
|
(0.05)
|
|
(572)
|
|
(0.05)
|
Realized other income
|
|
235
|
|
0.05
|
|
74
|
|
0.02
|
|
221
|
|
0.06
|
|
530
|
|
0.04
|
|
770
|
|
0.07
|
Fund flows from operations
|
|
197,898
|
|
44.08
|
|
216,076
|
|
46.24
|
|
165,645
|
|
43.60
|
|
619,337
|
|
46.02
|
|
503,866
|
|
44.13
|
The following table shows a reconciliation of the change in fund flows
from operations:
($M)
|
|
|
|
Q3/14 vs. Q2/14
|
|
|
|
Q3/14 vs. Q3/13
|
|
|
|
2014 vs. 2013
|
Fund flows from operations - Comparative period
|
|
|
|
216,076
|
|
|
|
165,645
|
|
|
|
503,866
|
Sales volume variance:
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
(13,984)
|
|
|
|
38,597
|
|
|
|
101,499
|
France
|
|
|
|
(8,863)
|
|
|
|
(11,373)
|
|
|
|
(15,669)
|
Netherlands
|
|
|
|
(1,638)
|
|
|
|
8,838
|
|
|
|
16,748
|
Germany
|
|
|
|
(398)
|
|
|
|
8,591
|
|
|
|
28,603
|
Australia
|
|
|
|
9,052
|
|
|
|
(14,515)
|
|
|
|
(20,740)
|
Pricing variance on sold volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI
|
|
|
|
(9,583)
|
|
|
|
(8,722)
|
|
|
|
16,434
|
AECO
|
|
|
|
(840)
|
|
|
|
8,979
|
|
|
|
22,723
|
Dated Brent
|
|
|
|
(13,351)
|
|
|
|
(3,631)
|
|
|
|
33,703
|
TTF
|
|
|
|
(3,391)
|
|
|
|
(9,261)
|
|
|
|
(18,473)
|
Changes in:
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties
|
|
|
|
13
|
|
|
|
(10,270)
|
|
|
|
(31,717)
|
Transportation
|
|
|
|
1,053
|
|
|
|
(4,430)
|
|
|
|
(13,029)
|
Operating expense
|
|
|
|
1,986
|
|
|
|
(9,981)
|
|
|
|
(25,523)
|
General and administration
|
|
|
|
1,500
|
|
|
|
(4,229)
|
|
|
|
(12,535)
|
PRRT
|
|
|
|
(1,135)
|
|
|
|
1,815
|
|
|
|
(7,380)
|
Corporate income taxes
|
|
|
|
15,181
|
|
|
|
28,999
|
|
|
|
30,037
|
Interest
|
|
|
|
(584)
|
|
|
|
(2,809)
|
|
|
|
(8,578)
|
Realized derivatives
|
|
|
|
6,418
|
|
|
|
13,602
|
|
|
|
19,678
|
Realized foreign exchange
|
|
|
|
225
|
|
|
|
2,039
|
|
|
|
(70)
|
Realized other income
|
|
|
|
161
|
|
|
|
14
|
|
|
|
(240)
|
Fund flows from operations - Current Period
|
|
|
|
197,898
|
|
|
|
197,898
|
|
|
|
619,337
|
Fund flows from operations of $197.9 million during Q3 2014 represented
a decrease of $18.2 million (8%) versus Q2 2014. This
quarter-over-quarter decrease was the result of a $43.0 million
decrease in sales, partially offset by a $6.4 million increase in
hedging proceeds (following weaker commodity prices during the quarter)
and a $15.2 million decrease in corporate income taxes. The decrease
in sales included $27.2 million of pricing variance due to a decrease
in all relevant commodity prices and $15.8 million of sales volume
variance due primarily to lower sales volumes in Canada (resulting from
operational declines) and France (due to a build in inventory during Q3
2014), partially offset by higher produced and sold volumes in
Australia. The decrease in corporate income taxes was due to lower
taxable income resulting from decreased sales and revisions to the
estimated 2014 effective tax rate in France.
On a year-over-year basis, fund flows from operations increased 19% and
23% for the three and nine months ended September 30, 2014,
respectively, versus the comparable periods in 2013. These increases
were primarily the result of favorable sales volume variances in Canada
and the Netherlands coupled with incremental production following our
Q1 2014 acquisition in Germany. These favorable sales volume
variances were partially offset by a build in inventory in Australia.
On a quarterly basis, the year-over-year change in fund flows from
operations includes an unfavorable pricing variance of $12.6 million
due to weaker crude oil and TTF pricing. For the nine months ended
September 30, 2014 versus the same period in 2013, fund flows from
operations includes a favorable variance of $54.4 million due to the
impact of the weakening Canadian dollar on crude oil pricing coupled
with stronger AECO natural gas pricing, offset partially by lower TTF
pricing.
Fluctuations in fund flows from operations (and correspondingly net
earnings and cash flows from operating activities) may occur as a
result of changes in commodity prices and costs to produce petroleum
and natural gas. In addition, fund flows from operations may be highly
affected by the timing of crude oil shipments in Australia and France.
When crude oil inventory is built up, the related operating expense,
royalties, and depletion expense are deferred and carried as inventory
on our balance sheet. When the crude oil inventory is subsequently
drawn down, the related expenses are recognized in fund flows from
operations.
CANADA BUSINESS UNIT
Overview
-
Production and assets focused in West Pembina near Drayton Valley,
Alberta and Northgate in southeast Saskatchewan
-
Potential for three significant resource plays sharing the same surface
infrastructure in the West Pembina region:
-
Cardium light oil (1,800m depth) - in development phase
-
Mannville condensate-rich gas (2,400 - 2,700m depth) - in development
phase
-
Duvernay condensate-rich gas (3,200 - 3,400m depth) - in appraisal phase
-
Canadian cash flows are fully tax-sheltered for the foreseeable future.
Operational review
|
|
|
|
|
Three Months Ended
|
|
% change
|
|
Nine Months Ended
|
|
% change
|
|
|
|
|
|
Sep 30,
|
|
|
Jun 30,
|
|
|
Sep 30,
|
|
Q3/14 vs.
|
|
Q3/14 vs.
|
|
Sep 30,
|
Sep 30,
|
|
2014 vs.
|
Canada business unit
|
|
|
|
2014
|
|
|
2014
|
|
|
2013
|
|
Q2/14
|
|
Q3/13
|
|
2014
|
2013
|
|
2013
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
|
11,469
|
|
|
12,676
|
|
|
7,969
|
|
(10%)
|
|
44%
|
|
11,202
|
8,274
|
|
35%
|
|
NGLs (bbls/d)
|
|
|
|
2,291
|
|
|
2,796
|
|
|
1,897
|
|
(18%)
|
|
21%
|
|
2,387
|
1,654
|
|
44%
|
|
Natural gas (mmcf/d)
|
|
|
|
57.07
|
|
|
57.59
|
|
|
43.40
|
|
(1%)
|
|
31%
|
|
54.76
|
42.72
|
|
28%
|
|
Total (boe/d)
|
|
|
|
23,272
|
|
|
25,070
|
|
|
17,099
|
|
(7%)
|
|
36%
|
|
22,714
|
17,047
|
|
33%
|
Production mix (% of total)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
|
49%
|
|
|
51%
|
|
|
47%
|
|
|
|
|
|
49%
|
49%
|
|
|
|
NGLs
|
|
|
|
10%
|
|
|
11%
|
|
|
11%
|
|
|
|
|
|
11%
|
10%
|
|
|
|
Natural gas
|
|
|
|
41%
|
|
|
38%
|
|
|
42%
|
|
|
|
|
|
40%
|
41%
|
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
|
|
|
97,393
|
|
|
36,968
|
|
|
62,270
|
|
163%
|
|
56%
|
|
249,300
|
163,952
|
|
52%
|
|
Acquisitions ($M)
|
|
|
|
27,883
|
|
|
381,326
|
|
|
7,586
|
|
|
|
|
|
413,977
|
7,586
|
|
|
|
Gross wells drilled
|
|
|
|
22.00
|
|
|
9.00
|
|
|
21.00
|
|
|
|
|
|
51.00
|
48.00
|
|
|
|
Net wells drilled
|
|
|
|
16.86
|
|
|
3.29
|
|
|
16.26
|
|
|
|
|
|
35.12
|
40.62
|
|
|
Production
-
Production in Canada of 23,272 boe/d during Q3 2014 represented a
decrease of 7% quarter-over-quarter and an increase of 36%
year-over-year. Year-to-date average production of 22,714 boe/d
represents an increase of 33% versus the same period in 2013.
-
Quarter-over-quarter decrease in production was largely due to the
effect of lower activity levels during spring breakup.
-
The strong year-over-year increase was primarily attributable to
production additions from our southeast Saskatchewan acquisition.
Production growth was further supplemented by strong volume additions
from our Mannville and Cardium development programs over the same
period.
-
Cardium production averaged more than 10,600 boe/d in Q3 2014, and more
than 11,000 boe/d year-to-date 2014.
-
Mannville production averaged more than 3,700 boe/d in Q3 2014, and
nearly 3,800 boe/d year-to-date 2014.
-
Saskatchewan production averaged approximately 2,600 boe/d in Q3 2014, a
31% increase over the Q2 2014, taking into account an effective
acquisition date of April 29, 2014.
Activity review
-
Vermilion drilled a total of 16 (14.7 net) operated wells during Q3
2014.
Cardium
-
We drilled five (4.5 net) operated wells and brought two (2.0 net)
operated wells on production during Q3 2014. Year-to-date we have
drilled 17 (16.0 net) operated wells and brought 20 (20.0 net) operated
wells on production, of which 15 were long-reach wells with horizontal
lengths greater than one mile.
-
Since 2009, we have drilled or participated in 264 (188.7 net) wells.
-
Operating netbacks have averaged approximately $67/boe year-to-date.
-
In 2014, we plan to drill or participate in approximately 40 (27.5 net)
wells.
Mannville
-
During Q3 2014, we drilled one (1.0 net) well. Year-to-date we have
drilled six (4.7 net) operated wells and brought on production five
(3.7 net) operated wells.
-
In 2014, we expect to drill or participate in up to 20 (11.4 net) wells.
Duvernay
-
In Q2 2014, we drilled two (1.3 net) horizontal wells. One (0.3 net)
well was completed in Q3 2014, and the other is anticipated to be
completed in Q4 2014. The first well was brought on production
subsequent to the third quarter and the second well is anticipated to
be on production prior to year-end 2014.
Saskatchewan
-
We drilled 10 (9.2 net) operated Midale wells in Saskatchewan and
brought seven gross (6.3 net) operated wells on production during Q3
2014.
-
In 2014, we plan to drill or participate in 12 (10.4 net) Midale wells.
Financial review
|
|
|
|
|
Three Months Ended
|
|
% change
|
|
Nine Months Ended
|
|
% change
|
Canada business unit
|
|
|
|
Sep 30,
|
|
Jun 30,
|
|
Sep 30,
|
|
Q3/14 vs.
|
|
Q3/14 vs.
|
|
Sep 30,
|
Sep 30,
|
|
2014 vs.
|
($M except as indicated)
|
|
|
|
2014
|
|
2014
|
|
2013
|
|
Q2/14
|
|
Q3/13
|
|
2014
|
2013
|
|
2013
|
|
Sales
|
|
|
|
138,853
|
|
163,261
|
|
100,000
|
|
(15%)
|
|
39%
|
|
425,294
|
284,638
|
|
49%
|
|
Royalties
|
|
|
|
(19,034)
|
|
(18,240)
|
|
(11,156)
|
|
4%
|
|
71%
|
|
(49,937)
|
(29,852)
|
|
67%
|
|
Transportation expense
|
|
|
|
(4,048)
|
|
(4,024)
|
|
(3,272)
|
|
1%
|
|
24%
|
|
(11,170)
|
(8,152)
|
|
37%
|
|
Operating expense
|
|
|
|
(19,074)
|
|
(21,179)
|
|
(12,770)
|
|
(10%)
|
|
49%
|
|
(56,863)
|
(42,586)
|
|
34%
|
|
General and administration
|
|
|
|
(4,523)
|
|
(6,560)
|
|
(3,484)
|
|
(31%)
|
|
30%
|
|
(13,951)
|
(10,501)
|
|
33%
|
|
Fund flows from operations
|
|
|
|
92,174
|
|
113,258
|
|
69,318
|
|
(19%)
|
|
33%
|
|
293,373
|
193,547
|
|
52%
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
|
64.85
|
|
71.56
|
|
63.56
|
|
(9%)
|
|
2%
|
|
68.58
|
61.16
|
|
12%
|
|
Royalties
|
|
|
|
(8.89)
|
|
(7.99)
|
|
(7.09)
|
|
11%
|
|
25%
|
|
(8.05)
|
(6.41)
|
|
26%
|
|
Transportation expense
|
|
|
|
(1.89)
|
|
(1.76)
|
|
(2.08)
|
|
7%
|
|
(9%)
|
|
(1.80)
|
(1.75)
|
|
3%
|
|
Operating expense
|
|
|
|
(8.91)
|
|
(9.28)
|
|
(8.12)
|
|
(4%)
|
|
10%
|
|
(9.17)
|
(9.15)
|
|
-
|
|
General and administration
|
|
|
|
(2.11)
|
|
(2.88)
|
|
(2.21)
|
|
(27%)
|
|
(5%)
|
|
(2.25)
|
(2.26)
|
|
-
|
|
Fund flows from operations netback
|
|
|
|
43.05
|
|
49.65
|
|
44.06
|
|
(13%)
|
|
(2%)
|
|
47.31
|
41.59
|
|
14%
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl)
|
|
|
|
97.17
|
|
102.99
|
|
105.82
|
|
(6%)
|
|
(8%)
|
|
99.61
|
98.14
|
|
1%
|
|
Edmonton Sweet index (US $/bbl)
|
|
|
|
89.24
|
|
96.85
|
|
101.10
|
|
(8%)
|
|
(12%)
|
|
92.17
|
93.03
|
|
(1%)
|
|
AECO ($/GJ)
|
|
|
|
3.81
|
|
4.44
|
|
2.31
|
|
(14%)
|
|
65%
|
|
4.56
|
2.89
|
|
58%
|
Sales
-
The realized price for our crude oil production in Canada is directly
linked to WTI but is subject to market conditions in Western Canada.
These market conditions can result in fluctuations in the pricing
differential, as reflected by the Edmonton Sweet index price. The
realized price of our NGLs in Canada is based on product specific
differentials pertaining to trading hubs in the United States. The
realized price of our natural gas in Canada is based on the AECO spot
price in Canada.
-
Sales per boe decreased by 9% quarter-over-quarter as a result of an 8%
decrease in Edmonton Sweet index pricing and a 14% decrease in AECO
pricing. This decrease coupled with lower production volumes resulting
from reduced activity over spring breakup resulted in a 15% decrease in
sales.
-
On a year-over-year basis, sales per boe increased by 2% and 12% for the
three and nine months ended September 30, 2014 versus the same periods
in 2013. Sales increased despite declining Edmonton Sweet index
pricing due to higher AECO pricing and increased production mix towards
crude oil and NGLs. These increases coupled with incremental
production from our Saskatchewan acquisition and production growth in
the Cardium and Mannville resource plays resulted in sales growth of
39% and 49% for the three and nine months ended September 30, 2014,
respectively.
Royalties
-
Royalty expense as a percentage of sales increased to 13.7% for Q3 2014
from 11.2% in both Q3 2013 and Q2 2014. Royalty expense as a
percentage of sales increased to 11.7% for the year-to-date period
ended Q3 2014 as compared to 10.5% for the same period of the prior
year.
-
The quarter-over-quarter increase is largely associated with wells
coming off of incentive royalty rates after reaching specified
production thresholds. In addition, the year-over-year increase in
royalty rates as a percentage of sales is partially attributable to
increased gas prices as well as slightly higher average royalty rates
associated with Vermilion's Saskatchewan production.
Transportation
-
Transportation expense relates to the delivery of crude oil and natural
gas production to major pipelines where legal title transfers.
-
Transportation expense per boe increased for the year-to-date period
ended Q3 2014 as compared to the same period in the prior year due to
trucking costs associated with Vermilion's recently acquired
Saskatchewan assets as well as pipeline tariff increases.
Operating expense
-
Operating expense per boe for Q3 2014 was slightly lower than the prior
quarter due to favorable equalization adjustments received in the
current quarter. The increase in operating expense per boe for the
current quarter as compared to the same quarter in 2013 is attributable
to higher operating expenses associated with the Saskatchewan
properties Vermilion acquired in the second quarter of 2014.
Year-to-date operating expense per boe is consistent with the prior
year due to project timing, partially offset by the higher costs
associated with Vermilion's Saskatchewan production.
General and administration
-
General and administration expense decreased in the current quarter as
compared to the prior quarter largely due to higher costs in the
previous quarter related to the Saskatchewan acquisition including
legal and consultant costs ($1.1MM) and additional salary allocations
from our Corporate segment to our Canadian business unit associated
with the integration process ($0.7MM).
-
Year-over-year, the increase in general and administration expense is
associated with incremental expense associated with the Saskatchewan
acquisition, higher staffing levels and the timing of expenditures.
FRANCE BUSINESS UNIT
Overview
-
Entered France in 1997 and completed three subsequent acquisitions,
including two in 2012.
-
Largest oil producer in France.
-
Producing assets include large conventional fields with high working
interests located in the Aquitaine and Paris Basins with an identified
inventory of workover, infill drilling, and secondary recovery
opportunities.
-
Production is characterized by Brent-based crude pricing and low base
decline rates.
Operational review
|
|
|
|
|
Three Months Ended
|
|
% change
|
|
Nine Months Ended
|
|
% change
|
|
|
|
|
|
Sep 30,
|
|
|
Jun 30,
|
|
|
Sep 30,
|
|
Q3/14 vs.
|
|
Q3/14 vs.
|
|
Sep 30,
|
|
Sep 30,
|
|
2014 vs.
|
France business unit
|
|
|
|
2014
|
|
|
2014
|
|
|
2013
|
|
Q2/14
|
|
Q3/13
|
|
2014
|
|
2013
|
|
2013
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
|
11,111
|
|
|
11,025
|
|
|
11,625
|
|
1%
|
|
(4%)
|
|
10,970
|
|
10,786
|
|
2%
|
|
Natural gas (mmcf/d)
|
|
|
|
-
|
|
|
-
|
|
|
5.23
|
|
-
|
|
(100%)
|
|
-
|
|
4.54
|
|
(100%)
|
|
Total (boe/d)
|
|
|
|
11,111
|
|
|
11,025
|
|
|
12,496
|
|
1%
|
|
(11%)
|
|
10,970
|
|
11,544
|
|
(5%)
|
Inventory (mbbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Opening crude oil inventory
|
|
|
|
179
|
|
|
238
|
|
|
202
|
|
|
|
|
|
268
|
|
354
|
|
|
|
Adjustments
|
|
|
|
-
|
|
|
|
|
|
-
|
|
|
|
|
|
-
|
|
5
|
|
|
|
Crude oil production
|
|
|
|
1,022
|
|
|
1,003
|
|
|
1,069
|
|
|
|
|
|
2,995
|
|
2,945
|
|
|
|
Crude oil sales
|
|
|
|
(987)
|
|
|
(1,062)
|
|
|
(1,045)
|
|
|
|
|
|
(3,049)
|
|
(3,078)
|
|
|
|
Closing crude oil inventory
|
|
|
|
214
|
|
|
179
|
|
|
226
|
|
|
|
|
|
214
|
|
226
|
|
|
Production mix (% of total)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
|
100%
|
|
|
100%
|
|
|
93%
|
|
|
|
|
|
100%
|
|
93%
|
|
|
|
Natural gas
|
|
|
|
-
|
|
|
-
|
|
|
7%
|
|
|
|
|
|
-
|
|
7%
|
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
|
|
|
35,082
|
|
|
37,614
|
|
|
23,664
|
|
(7%)
|
|
48%
|
|
110,663
|
|
68,479
|
|
62%
|
|
Gross wells drilled
|
|
|
|
3.00
|
|
|
2.00
|
|
|
-
|
|
|
|
|
|
7.00
|
|
5.00
|
|
|
|
Net wells drilled
|
|
|
|
3.00
|
|
|
2.00
|
|
|
-
|
|
|
|
|
|
7.00
|
|
5.00
|
|
|
Production
-
Q3 production increased 1% on a quarter-over-quarter basis but remained
11% lower year-over-year. Year-to-date production was 5% lower versus
the same period of 2013. Year-over-year and year-to-date production
volumes were lower due to the shut-in of gas volumes at Vic Bilh.
-
In late September 2013, the third party Lacq processing facility that
processed our Vic Bilh gas production was permanently closed. As a
result, our Vic Bilh gas production has been temporarily shut-in while
preparations to transfer to an alternative facility are completed. We
currently expect approximately 850 mcf/d will be back on-stream in
early 2015, with the remaining approximately 3,400 mcf/d not
anticipated to be back on production until early 2016.
-
As a result, current production volumes remain 100% weighted to
Brent-based crude.
Activity review
-
Vermilion drilled three (3.0 net) wells in the Champotran field in the
Paris Basin during Q3 2014.
-
During Q3 2014, we also completed a number of workovers, as well as
seismic and facility integrity projects.
-
The five wells drilled in the Champotran field in 2014 were brought on
production at various times during the third quarter and are currently
producing approximately 200 bbls/d per well.
Financial review
|
|
|
|
|
Three Months Ended
|
|
% change
|
|
Nine Months Ended
|
|
% change
|
France business unit
|
|
|
|
Sep 30,
|
|
|
Jun 30,
|
|
|
Sep 30,
|
|
Q3/14 vs.
|
|
Q3/14 vs.
|
|
Sep 30,
|
|
Sep 30,
|
|
2014 vs.
|
($M except as indicated)
|
|
|
|
2014
|
|
|
2014
|
|
|
2013
|
|
Q2/14
|
|
Q3/13
|
|
2014
|
|
2013
|
|
2013
|
|
Sales
|
|
|
|
106,576
|
|
|
124,617
|
|
|
120,574
|
|
(14%)
|
|
(12%)
|
|
348,753
|
|
342,558
|
|
2%
|
|
Royalties
|
|
|
|
(6,978)
|
|
|
(7,796)
|
|
|
(7,574)
|
|
(10%)
|
|
(8%)
|
|
(22,125)
|
|
(20,468)
|
|
8%
|
|
Transportation expense
|
|
|
|
(4,741)
|
|
|
(5,385)
|
|
|
(2,713)
|
|
(12%)
|
|
75%
|
|
(14,879)
|
|
(7,883)
|
|
89%
|
|
Operating expense
|
|
|
|
(15,215)
|
|
|
(16,550)
|
|
|
(14,599)
|
|
(8%)
|
|
4%
|
|
(48,185)
|
|
(51,473)
|
|
(6%)
|
|
General and administration
|
|
|
|
(6,411)
|
|
|
(5,559)
|
|
|
(4,964)
|
|
15%
|
|
29%
|
|
(17,164)
|
|
(14,577)
|
|
18%
|
|
Current income taxes
|
|
|
|
(10,744)
|
|
|
(24,761)
|
|
|
(31,717)
|
|
(57%)
|
|
(66%)
|
|
(60,769)
|
|
(66,500)
|
|
(9%)
|
|
Fund flows from operations
|
|
|
|
62,487
|
|
|
64,566
|
|
|
59,007
|
|
(3%)
|
|
6%
|
|
185,631
|
|
181,657
|
|
2%
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
|
107.99
|
|
|
117.29
|
|
|
107.08
|
|
(8%)
|
|
1%
|
|
114.36
|
|
104.29
|
|
10%
|
|
Royalties
|
|
|
|
(7.07)
|
|
|
(7.34)
|
|
|
(6.73)
|
|
(4%)
|
|
5%
|
|
(7.26)
|
|
(6.23)
|
|
17%
|
|
Transportation expense
|
|
|
|
(4.80)
|
|
|
(5.07)
|
|
|
(2.41)
|
|
(5%)
|
|
99%
|
|
(4.88)
|
|
(2.40)
|
|
103%
|
|
Operating expense
|
|
|
|
(15.42)
|
|
|
(15.58)
|
|
|
(12.97)
|
|
(1%)
|
|
19%
|
|
(15.80)
|
|
(15.67)
|
|
1%
|
|
General and administration
|
|
|
|
(6.50)
|
|
|
(5.24)
|
|
|
(4.41)
|
|
24%
|
|
47%
|
|
(5.63)
|
|
(4.44)
|
|
27%
|
|
Current income taxes
|
|
|
|
(10.89)
|
|
|
(23.30)
|
|
|
(28.17)
|
|
(53%)
|
|
(61%)
|
|
(19.93)
|
|
(20.25)
|
|
(2%)
|
|
Fund flows from operations netback
|
|
|
|
63.31
|
|
|
60.76
|
|
|
52.39
|
|
4%
|
|
21%
|
|
60.86
|
|
55.30
|
|
10%
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated Brent (US $/bbl)
|
|
|
|
101.85
|
|
|
109.63
|
|
|
110.37
|
|
(7%)
|
|
(8%)
|
|
106.57
|
|
108.45
|
|
(2%)
|
Sales
-
Crude oil production in France is priced with reference to Dated Brent.
-
Sales per boe for Q3 2014 decreased by 8%, consistent with the 7%
decrease in the Dated Brent reference price. This decrease, coupled
with a build in inventory during Q3 2014, resulted in a 14% decrease in
sales.
-
On a year-over-year basis, sales per boe increased by 1% and 10% for the
three and nine months ended September 30, 2014 as compared to the same
periods in 2013. This sales increase occurred despite an 8% and 2%
decrease in Dated Brent reference price for the three and nine months
ended September 30, 2014 due to the offsetting impact of the weakening
of the Canadian dollar versus the US dollar. On a year-to-date basis,
the aforementioned increase in sales per boe was mostly offset by the
shut-in of natural gas production, resulting in a 2% increase in sales.
Royalties
-
Royalties in France relate to two components: RCDM (levied on units of
production and not subject to changes in commodity prices) and R31
(based on a percentage of revenue).
-
As a percentage of sales, royalties for the periods presented remained
relatively consistent.
Transportation
-
Historically, transportation expense in France related to shipments of
crude oil by tanker from the Aquitaine Basin to third party
refineries. As a result of the closure of the Lacq processing facility
in Q3 2013, Vermilion began incurring additional transportation charges
to ship Vic Bilh crude oil production to market. Accordingly,
transportation expense per boe for the 2014 periods presented is higher
than the expense per boe for the comparative periods from the prior
year.
Operating expense
-
Operating expense per boe for Q3 2014 was consistent with the prior
quarter. The increases in operating expense per boe for the three and
nine months ended September 30, 2014 versus the same periods in 2013
are related to a weaker Canadian dollar relative to the Euro in 2014
versus 2013 and the timing of expenditures.
General and administration
-
General and administration expense increased in Q3 2014 versus the prior
quarter as a result of higher allocations from Vermilion's Corporate
segment. These higher allocations, coupled with increased staffing
costs and the weaker Canadian dollar relative to the Euro, resulted in
an increase in general and administrative expense for the three and
nine months ended September 30, 2014.
Current income taxes
-
Current income taxes in France apply to taxable income after eligible
deductions at a statutory rate of 34.4% for 2014. In addition, a 10.7%
temporary surtax is applicable for tax year 2014 and 2015 if annual
revenue exceeds 250 million €. For 2014, the effective rate on current
taxes is expected to be between approximately 22% and 26% This rate is
subject to change in response to commodity price fluctuations, the
timing of capital expenditures and other eligible in-country
adjustments.
-
Current income taxes for Q3 2014 were lower than both Q2 2014 and Q3
2013 as Q3 2014 current income taxes reflects our revised expectation
of the effective tax rate given the declining Dated Brent reference
price. Based on current expectations for Q4 2014 Dated Brent pricing,
the France business unit is not expected to be subject to the 10.7%
temporary surtax for 2014.
-
On a year-to-date basis, current income taxes for the nine months ended
September 30, 2014 represents an effective tax rate of 25%. This
decrease versus the 27% effective tax rate for the nine months ended
September 30, 2013 reflects our revised expectations on the effective
tax rate given the declining Dated Brent reference price.
NETHERLANDS BUSINESS UNIT
Overview
-
Entered the Netherlands in 2004.
-
Second largest onshore gas producer.
-
Interests include 16 licenses in the northeast region, five licenses in
the central region, and two offshore licenses.
-
Licenses include more than 820,000 net acres of undeveloped land.
-
High impact natural gas drilling and development.
-
Natural gas produced in the Netherlands is priced off the TTF index,
which receives a significant premium over North American gas prices.
Operational review
|
|
|
|
|
Three Months Ended
|
|
% change
|
|
Nine Months Ended
|
|
% change
|
|
|
|
|
|
Sep 30,
|
|
|
Jun 30,
|
|
|
Sep 30,
|
|
Q3/14 vs.
|
|
Q3/14 vs.
|
|
Sep 30,
|
|
Sep 30,
|
|
2014 vs.
|
Netherlands business unit
|
|
|
|
2014
|
|
|
2014
|
|
|
2013
|
|
Q2/14
|
|
Q3/13
|
|
2014
|
|
2013
|
|
2013
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d)
|
|
|
|
63
|
|
|
96
|
|
|
48
|
|
(34%)
|
|
31%
|
|
76
|
|
65
|
|
17%
|
|
Natural gas (mmcf/d)
|
|
|
|
38.07
|
|
|
40.35
|
|
|
28.78
|
|
(6%)
|
|
32%
|
|
40.50
|
|
34.71
|
|
17%
|
|
Total (boe/d)
|
|
|
|
6,407
|
|
|
6,822
|
|
|
4,845
|
|
(6%)
|
|
32%
|
|
6,827
|
|
5,849
|
|
17%
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
|
|
|
10,087
|
|
|
21,513
|
|
|
8,316
|
|
(53%)
|
|
21%
|
|
51,718
|
|
12,845
|
|
303%
|
|
Gross wells drilled
|
|
|
|
1.00
|
|
|
2.00
|
|
|
-
|
|
|
|
|
|
5.00
|
|
-
|
|
|
|
Net wells drilled
|
|
|
|
0.45
|
|
|
1.43
|
|
|
-
|
|
|
|
|
|
3.74
|
|
-
|
|
|
Production
-
Production was 6% lower quarter-over-quarter while year-over-year
production growth exceeded 32%. Year-to-date production volumes have
increased 17% versus the same period of 2013. Both year-over-year and
year-to-date production volumes benefited from the addition of
production from the DeHoeve-01 well during the second quarter and
increased throughput capacity following a retrofit at our Middenmeer
Treatment Centre completed in late 2013.
-
Production in the Netherlands is managed to meet corporate targets,
optimize facility use and regulate declines.
Activity review
-
Vermilion drilled the Diever-02 well (45% working interest), in the
Drenthe IIIb concession, during Q3 2014. The well primarily targeted
the Rotliegend Group (Permian sandstones) where it encountered two
well-developed gas bearing intervals (Akkrum and Slochteren) with a net
pay thickness of approximately 36 metres.
-
A subsequent three hour clean-up test conducted on the Slochteren
formation delivered 25.7 mmcf/d of gas on a 40/64 inch choke with 2,615
psi of wellhead flowing pressure with no indications of pressure drop
during the test(1). The flow rate was limited by the 3.5 inch diameter of the tubing and
the capacity of the test equipment. The Akkrum formation is anticipated
to be perforated at a later date once the Slochteren formation has been
fully produced.
-
The Diever-02 well marked the first well drilled by Vermilion on the
lands acquired in October 2013.
-
An additional two wells (Langezwaag-02 and Sonnega-02) are planned for
drilling during Q4 2014.
(1)
|
Test result is not necessarily indicative of long-term performance or of
ultimate recovery.
|
Financial review
|
|
Three Months Ended
|
|
% change
|
|
|
Nine Months Ended
|
|
% change
|
Netherlands business unit
|
Sep 30,
|
Jun 30,
|
Sep 30,
|
|
Q3/14 vs.
|
Q3/14 vs.
|
|
|
Sep 30,
|
Sep 30,
|
|
2014 vs.
|
($M except as indicated)
|
2014
|
2014
|
2013
|
|
Q2/14
|
Q3/13
|
|
|
2014
|
2013
|
|
2013
|
|
Sales
|
26,960
|
29,881
|
27,382
|
|
(10%)
|
(2%)
|
|
|
98,395
|
100,119
|
|
(2%)
|
|
Royalties
|
(942)
|
(693)
|
-
|
|
36%
|
100%
|
|
|
(3,843)
|
-
|
|
100%
|
|
Operating expense
|
(5,409)
|
(6,390)
|
(5,209)
|
|
(15%)
|
4%
|
|
|
(17,841)
|
(14,438)
|
|
24%
|
|
General and administration
|
(204)
|
(326)
|
(333)
|
|
(37%)
|
(39%)
|
|
|
(1,128)
|
(1,171)
|
|
(4%)
|
|
Current income taxes
|
(1,189)
|
(1,301)
|
(6,810)
|
|
(9%)
|
(83%)
|
|
|
(6,278)
|
(25,865)
|
|
(76%)
|
|
Fund flows from operations
|
19,216
|
21,171
|
15,030
|
|
(9%)
|
28%
|
|
|
69,305
|
58,645
|
|
18%
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
45.73
|
48.14
|
61.44
|
|
(5%)
|
(26%)
|
|
|
52.80
|
62.70
|
|
(16%)
|
|
Royalties
|
(1.60)
|
(1.12)
|
-
|
|
43%
|
100%
|
|
|
(2.06)
|
-
|
|
100%
|
|
Operating expense
|
(9.18)
|
(10.29)
|
(11.69)
|
|
(11%)
|
(21%)
|
|
|
(9.57)
|
(9.04)
|
|
6%
|
|
General and administration
|
(0.35)
|
(0.53)
|
(0.75)
|
|
(34%)
|
(53%)
|
|
|
(0.61)
|
(0.73)
|
|
(16%)
|
|
Current income taxes
|
(2.02)
|
(2.10)
|
(15.28)
|
|
(4%)
|
(87%)
|
|
|
(3.37)
|
(16.20)
|
|
(79%)
|
|
Fund flows from operations netback
|
32.58
|
34.10
|
33.72
|
|
(4%)
|
(3%)
|
|
|
37.19
|
36.73
|
|
1%
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TTF ($/GJ)
|
7.26
|
7.91
|
9.94
|
|
(8%)
|
(27%)
|
|
|
8.41
|
10.17
|
|
(17%)
|
|
TTF (€/GJ)
|
5.04
|
5.27
|
7.20
|
|
(4%)
|
(30%)
|
|
|
5.68
|
7.53
|
|
(25%)
|
Sales
-
The price of our natural gas in the Netherlands is based on the TTF
day-ahead index, as determined on the Title Transfer Facility Virtual
Trading Point operated by Dutch TSO Gas Transport Services, plus
various fees. GasTerra, a state owned entity, continues to purchase
all of the natural gas we produce in the Netherlands.
-
The decreases in sales per boe in Q3 2014 versus Q2 2014 and Q3 2013 was
largely in-line with the change in the Canadian dollar equivalent of
the TTF reference price.
-
On a year-over-year basis, sales declined by 2% as a result of the 17%
decrease in the TTF reference price offset by a 17% increase in
production.
Royalties
-
Historically, we have not paid royalties in the Netherlands, however,
certain wells associated with an acquisition completed by Vermilion's
Netherlands business unit in October 2013 have reached payout and are
now subject to an overriding royalty.
Transportation expense
-
Our production in the Netherlands is not subject to transportation
expense as gas is sold at the plant gate.
Operating expense
-
Operating expense per boe decreased in Q3 2014 from Q2 2014 due to the
timing of project work.
-
Operating expense per boe decreased in Q3 2014 as compared to Q3 2013
due to significantly higher volumes year-over-year.
-
For the year-to-date period ended Q3 2014, operating expense per boe
increased as compared to the prior year due to the strengthening of the
Euro versus the Canadian dollar as well as higher salary costs
associated with continued organic growth in the Netherlands business
unit.
General and administration
-
General and administration expense remained relatively consistent for
the periods presented, although the quarterly periods are impacted by
the timing of expenditures.
Current income taxes
-
Current income taxes in the Netherlands apply to taxable income after
eligible deductions at a statutory tax rate of approximately 46%. For
2014, the effective rate on current taxes is expected to be between
approximately 6% and 8%. This rate is subject to change in response to
commodity price fluctuations, the timing of capital expenditures and
other eligible in-country adjustments.
-
Current income taxes decreased for the nine months ended September 30,
2014 as compared to the same period in 2013 as a result of decreased
revenues, lower TTF reference prices and an increase in tax deductions
for depletion during the current year.
GERMANY BUSINESS UNIT
Overview
-
Vermilion entered Germany in February 2014 with the purchase of a 25%
participation interest in a four-partner consortium.
-
The assets of the four-partner consortium include four gas producing
fields across 11 production licenses and an exploration license in
surrounding fields.
-
Production licenses comprising 207,000 gross acres, of which 85% is in
the exploration license.
Operational review
|
|
Three Months Ended
|
|
% change
|
|
|
Nine Months Ended
|
|
|
Sep 30,
|
Jun 30,
|
|
Q3/14 vs.
|
|
|
Sep 30,
|
Germany business unit
|
2014
|
2014
|
|
Q2/14
|
|
|
2014
|
Production
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
15.38
|
16.13
|
|
(5%)
|
|
|
14.07
|
|
Total (boe/d)
|
2,563
|
2,689
|
|
(5%)
|
|
|
2,345
|
Activity
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
1,358
|
630
|
|
116%
|
|
|
2,184
|
|
Acquisitions ($M)
|
-
|
-
|
|
|
|
|
172,871
|
Production
-
Achieved Q3 2014 production of 2,563 boe/d, a decrease of 5% as compared
to 2,689 boe/d in Q2 2014. Year-to-date production has averaged 2,345
boe/d, taking into account an effective date for production of February
1, 2014.
Activity review
-
Continued the integration of the German business unit and commenced
planning with our working interest partners for future drilling
operations.
-
During the first quarter of 2014, we participated in the drilling of the
Deblinghausen Z7a development well (25% working interest) in Germany.
The well logged 81 metres of net pay in the Zechstein Carbonate, and
was production tested by the operator in late September for a period of
17 days. During the test, the Deblinghausen Z7a well produced raw gas
at rates of 10.2 mmcf/d at a flowing tubing pressure of 1,840 psi(1). Subsequent to the end of the quarter, this well was placed on
production at an initial gross production rate of 16.5 mmcf/d of raw
gas at a flowing tubing pressure of approximately 1,300 psi.
-
We have hired a Managing Director for the German business unit and have
opened an office outside of Berlin, which we are currently outfitting
and staffing.
(1)
|
Test result is not necessarily indicative of long-term performance or of
ultimate recovery.
|
Financial review
|
|
Three Months Ended
|
|
% change
|
|
|
Nine Months Ended
|
Germany business unit
|
Sep 30,
|
Jun 30,
|
|
Q3/14 vs.
|
|
|
Sep 30,
|
($M except as indicated)
|
2014
|
2014
|
|
Q2/14
|
|
|
2014
|
|
Sales
|
8,591
|
11,097
|
|
(23%)
|
|
|
28,603
|
|
Royalties
|
(2,046)
|
(2,284)
|
|
(10%)
|
|
|
(6,132)
|
|
Transportation expense
|
(675)
|
(1,052)
|
|
(36%)
|
|
|
(2,149)
|
|
Operating expense
|
(2,227)
|
(2,043)
|
|
9%
|
|
|
(5,824)
|
|
General and administration
|
(1,090)
|
(830)
|
|
31%
|
|
|
(2,488)
|
|
Current income taxes
|
(146)
|
(506)
|
|
(71%)
|
|
|
(1,189)
|
|
Fund flows from operations
|
2,407
|
4,382
|
|
(45%)
|
|
|
10,821
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
Sales
|
36.43
|
45.36
|
|
(20%)
|
|
|
44.68
|
|
Royalties
|
(8.68)
|
(9.34)
|
|
(7%)
|
|
|
(9.58)
|
|
Transportation expense
|
(2.86)
|
(4.30)
|
|
(33%)
|
|
|
(3.36)
|
|
Operating expense
|
(9.44)
|
(8.35)
|
|
13%
|
|
|
(9.10)
|
|
General and administration
|
(4.62)
|
(3.39)
|
|
36%
|
|
|
(3.89)
|
|
Current income taxes
|
(0.62)
|
(2.07)
|
|
(70%)
|
|
|
(1.86)
|
|
Fund flows from operations netback
|
10.21
|
17.91
|
|
(43%)
|
|
|
16.89
|
Reference prices
|
|
|
|
|
|
|
|
|
TTF ($/GJ)
|
7.26
|
7.91
|
|
(8%)
|
|
|
8.41
|
|
TTF (€/GJ)
|
5.04
|
5.27
|
|
(4%)
|
|
|
5.68
|
Sales
-
The price of our natural gas in Germany is based on the TTF month-ahead
index, as determined on the Title Transfer Facility Virtual Trading
Point operated by Dutch TSO Gas Transport Services, plus various fees.
-
Sales per boe decreased by 20% from Q2 2014 due to a decrease in the TTF
reference price. This decrease, coupled with lower production volumes,
resulted in a 23% quarter-over-quarter decrease in sales.
Royalties expense
-
Our production in Germany is subject to royalties at a rate of
approximately 20% of natural gas sales revenue.
Transportation expense
-
Transportation expense relates to costs incurred to deliver natural gas
from the processing facility to the customer.
Operating expense
-
Operating expenses for Germany are billed monthly by the joint venture
operator and are similar on a per boe basis to our Netherlands business
unit.
General and administration
-
General and administration expense increased quarter-over-quarter as a
result of adding staff to the German business unit.
Current income taxes
-
Current income taxes in Germany apply to taxable income after eligible
deductions at a statutory tax rate of approximately 23%. For 2014, the
effective rate on current taxes is expected to be between approximately
4% and 8%. This rate is subject to change in response to commodity
price fluctuations, the timing of capital expenditures and other
eligible in-country adjustments.
IRELAND BUSINESS UNIT
Overview
-
18.5% non-operating interest in the offshore Corrib gas field located
approximately 83km off the northwest coast of Ireland.
-
Project comprises six offshore wells, both offshore and onshore pipeline
segments as well as a natural gas processing facility.
-
Production from Corrib is expected to increase Vermilion's volumes by
approximately 58 mmcf/d (9,700 boe/d) once the field reaches peak
production.
Operational and financial review
|
|
Three Months Ended
|
|
% change
|
|
|
Nine Months Ended
|
|
% change
|
Ireland business unit
|
Sep 30,
|
Jun 30,
|
Sep 30,
|
|
Q3/14 vs.
|
Q3/14 vs.
|
|
|
Sep 30,
|
Sep 30,
|
|
2014 vs.
|
($M)
|
2014
|
2014
|
2013
|
|
Q2/14
|
Q3/13
|
|
|
2014
|
2013
|
|
2013
|
|
Transportation expense
|
(1,515)
|
(1,571)
|
(564)
|
|
(4%)
|
169%
|
|
|
(4,674)
|
(3,808)
|
|
23%
|
|
General and administration
|
(334)
|
(252)
|
(312)
|
|
33%
|
7%
|
|
|
(868)
|
(959)
|
|
(9%)
|
|
Fund flows from operations
|
(1,849)
|
(1,823)
|
(876)
|
|
1%
|
111%
|
|
|
(5,542)
|
(4,767)
|
|
16%
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
30,050
|
27,221
|
35,028
|
|
10%
|
(14%)
|
|
|
73,507
|
76,426
|
|
(4%)
|
Activity review
-
Completed tunnel boring operations beneath Sruwaddacon Bay on May 21,
2014. Installation of flow and umbilical lines has been completed in
the 4.9 km tunnel, with remaining work including final cable
installation, hydro-testing and grouting. Offshore well and flow line
activities are complete and the wells are ready for operation.
-
Based on our deterministic schedule for remaining construction and
commissioning activities, we anticipate first gas in approximately
mid-2015 with peak production of approximately 58 mmcf/d (9,700 boe/d),
net to Vermilion.
Transportation expense
-
Transportation expense in Ireland relates to payments under a ship or
pay agreement related to the Corrib project.
AUSTRALIA BUSINESS UNIT
Overview
-
Entered Australia in 2005.
-
Hold title to a 100% working interest in the Wandoo field, located
approximately 80 km offshore on the northwest shelf of Australia.
-
Production is operated from two off-shore platforms, and originates from
21 producing well bores.
-
Wells are located 600 metres below the sea bed with 500 to 3,000 plus
metre horizontal lengths.
-
Contracted crude oil production is priced with reference to Dated Brent.
Operational review
|
|
Three Months Ended
|
|
% change
|
|
|
Nine Months Ended
|
|
% change
|
|
|
Sep 30,
|
Jun 30,
|
Sep 30,
|
|
Q3/14 vs.
|
Q3/14 vs.
|
|
|
Sep 30,
|
Sep 30,
|
|
2014 vs.
|
Australia business unit
|
2014
|
2014
|
2013
|
|
Q2/14
|
Q3/13
|
|
|
2014
|
2013
|
|
2013
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
6,567
|
6,483
|
7,070
|
|
1%
|
(7%)
|
|
|
6,718
|
6,580
|
|
2%
|
Inventory (mbbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Opening crude oil inventory
|
189
|
63
|
187
|
|
|
|
|
|
130
|
268
|
|
|
|
Crude oil production
|
604
|
590
|
650
|
|
|
|
|
|
1,834
|
1,796
|
|
|
|
Crude oil sales
|
(535)
|
(464)
|
(654)
|
|
|
|
|
|
(1,706)
|
(1,881)
|
|
|
|
Closing crude oil inventory
|
258
|
189
|
183
|
|
|
|
|
|
258
|
183
|
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
15,985
|
10,991
|
5,880
|
|
45%
|
172%
|
|
|
32,667
|
69,511
|
|
(53%)
|
|
Gross wells drilled
|
-
|
-
|
-
|
|
|
|
|
|
-
|
2.00
|
|
|
|
Net wells drilled
|
-
|
-
|
-
|
|
|
|
|
|
-
|
2.00
|
|
|
Production
-
Quarterly production increased 1% quarter-over-quarter and was 7% lower
year-over-year. Year-to-date 2014 production has increased 2% versus
the same period 2013.
-
Production volumes are managed to meet customer demands and long-term
supply agreements. We continue to plan for production levels of
between 6,000 and 8,000 bbls/d.
-
Production continues to reflect strong well results from the 2013
drilling program, more than offsetting natural declines. We continue
to produce the wells at restricted rates below their current productive
capacity.
Activity review
-
In Q3 2014, efforts were largely focused on facilities repairs and
engineering studies, including the expansion of accommodation quarters
on the Wandoo B platform.
-
2014 planned activities include ongoing facilities maintenance,
enhancement, and refurbishment along with preparation and permitting
activities in advance of our planned two-well 2015 drilling program.
Financial review
|
|
Three Months Ended
|
|
% change
|
|
|
Nine Months Ended
|
|
% change
|
Australia business unit
|
Sep 30,
|
Jun 30,
|
Sep 30,
|
|
Q3/14 vs.
|
Q3/14 vs.
|
|
|
Sep 30,
|
Sep 30,
|
|
2014 vs.
|
($M except as indicated)
|
2014
|
2014
|
2013
|
|
Q2/14
|
Q3/13
|
|
|
2014
|
2013
|
|
2013
|
|
Sales
|
63,708
|
58,828
|
79,229
|
|
8%
|
(20%)
|
|
|
212,510
|
221,412
|
|
(4%)
|
|
Operating expense
|
(14,302)
|
(12,051)
|
(13,668)
|
|
19%
|
5%
|
|
|
(43,713)
|
(38,406)
|
|
14%
|
|
General and administration
|
(1,378)
|
(1,661)
|
(1,414)
|
|
(17%)
|
(3%)
|
|
|
(4,245)
|
(4,310)
|
|
(2%)
|
|
PRRT
|
(13,834)
|
(12,699)
|
(15,649)
|
|
9%
|
(12%)
|
|
|
(46,772)
|
(39,392)
|
|
19%
|
|
Corporate income taxes
|
(5,148)
|
(5,689)
|
(7,666)
|
|
(10%)
|
(33%)
|
|
|
(19,678)
|
(25,525)
|
|
(23%)
|
|
Fund flows from operations
|
29,046
|
26,728
|
40,832
|
|
9%
|
(29%)
|
|
|
98,102
|
113,779
|
|
(14%)
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
119.07
|
126.87
|
120.95
|
|
(6%)
|
(2%)
|
|
|
124.59
|
117.65
|
|
6%
|
|
Operating expense
|
(26.73)
|
(25.99)
|
(20.86)
|
|
3%
|
28%
|
|
|
(25.63)
|
(20.41)
|
|
26%
|
|
General and administration
|
(2.58)
|
(3.58)
|
(2.16)
|
|
(28%)
|
19%
|
|
|
(2.49)
|
(2.29)
|
|
9%
|
|
PRRT
|
(25.86)
|
(27.39)
|
(23.89)
|
|
(6%)
|
8%
|
|
|
(27.42)
|
(20.93)
|
|
31%
|
|
Corporate income taxes
|
(9.62)
|
(12.27)
|
(11.70)
|
|
(22%)
|
(18%)
|
|
|
(11.54)
|
(13.56)
|
|
(15%)
|
|
Fund flows from operations netback
|
54.28
|
57.64
|
62.34
|
|
(6%)
|
(13%)
|
|
|
57.51
|
60.46
|
|
(5%)
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated Brent (US $/bbl)
|
101.85
|
109.63
|
110.37
|
|
(7%)
|
(8%)
|
|
|
106.57
|
108.45
|
|
(2%)
|
Sales
-
Our production in Australia currently receives a premium to Dated Brent.
-
Sales per boe for Q3 2014 decreased by 6% versus Q2 2014 as a result of
a decrease in the Dated Brent reference price. This decrease was
offset by larger sales volumes resulting in an 8% increase in sales.
-
Sales per boe for the three and nine months ended September 30, 2014
versus the same periods in 2013 reflect the decrease in the Dated Brent
reference price offset by the weakening of the Canadian dollar versus
the US dollar. These changes, coupled with lower sales volumes,
resulted in a 20% and 4% decrease in sales in the three and nine months
ended September 30, 2014 versus the same periods in 2013.
Royalties and transportation expense
-
Our production in Australia is not subject to royalties or
transportation expense as crude oil is sold directly from the Wandoo B
platform.
Operating expense
-
Operating expense per boe for Q3 2014 remained consistent with the
expense for Q2 2014.
-
Operating expense per boe for the three and nine months ended September
30, 2014 was higher than the expense for the comparative periods in the
prior year due to increased diesel usage and higher salary costs.
-
Operating expense for the three and nine months ended September 30, 2014
were 5% and 14% higher, respectively, than the comparable periods in
2013 as a result of increased diesel usage and higher salary costs,
partially offset by a build in inventory in the current periods. When
crude oil inventory is built up, the related operating expense is
deferred and carried as inventory on our balance sheet.
General and administration
-
General and administration expense decreased slightly during Q3 2014 as
compared to Q2 2014 and Q3 2013 due to timing of expenditures. For the
year-to-date period ended September 30, 2014, general and
administration expense remained consistent with the expense for the
same period of the prior year.
PRRT and corporate income taxes
-
In Australia, current income taxes include both PRRT and corporate
income taxes. PRRT is a profit based tax applied at a rate of 40% on
sales less eligible expenditures, including operating expenses and
capital expenditures. Corporate income taxes are applied at a rate of
30% on taxable income after eligible deductions, which include PRRT.
-
For 2014, the combined corporate income tax and PRRT effective rate is
expected to be between approximately 38% and 42%. This rate is subject
to change in response to commodity price fluctuations, the timing of
capital expenditures and other eligible in-country adjustments.
-
Combined corporate income taxes and PRRT movements for the three and
nine months ended September 30, 2014 versus the comparable periods was
largely consistent with the fluctuations in sales. On a year-over-year
basis, PRRT for 2014 increased versus the 2013 periods as a result of
the lower capital spending in 2014.
CORPORATE
Overview
-
Our Corporate segment includes costs related to our global hedging
program, financing expenses, and general and administration expenses,
primarily incurred in Canada and not directly related to the operations
of our business units.
Financial review
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
Sep 30,
|
Jun 30,
|
Sep 30,
|
|
|
Sep 30,
|
Sep 30,
|
($M)
|
2014
|
2014
|
2013
|
|
|
2014
|
2013
|
General and administration
|
(2,322)
|
(2,574)
|
(1,526)
|
|
|
(8,647)
|
(4,438)
|
Current income taxes
|
(227)
|
(378)
|
(260)
|
|
|
(778)
|
(839)
|
Interest expense
|
(12,918)
|
(12,334)
|
(10,109)
|
|
|
(36,712)
|
(28,134)
|
Realized gain (loss) on derivatives
|
8,837
|
2,419
|
(4,765)
|
|
|
13,896
|
(5,782)
|
Realized foreign exchange gain (loss)
|
812
|
587
|
(1,227)
|
|
|
(642)
|
(572)
|
Realized other income
|
235
|
74
|
221
|
|
|
530
|
770
|
Fund flows from operations
|
(5,583)
|
(12,206)
|
(17,666)
|
|
|
(32,353)
|
(38,995)
|
|
|
|
|
|
|
|
|
General and administration
-
General and administration expense was largely consistent in Q3 2014 as
compared to Q2 2014.
-
On a year-over-year basis, the increase in general and administration
costs for the three and nine months ended September 30, 2014 as
compared to the same period in 2013 was a result of the impact of
certain outstanding Vermilion Incentive Plan ("VIP") awards to be
settled partially in cash.
Current income taxes
-
Taxes in our corporate segment relates to holding companies that pay
current taxes in foreign jurisdictions.
Interest expense
-
Interest expense is incurred on our senior unsecured notes and on
borrowings under our revolving credit facility. The increase in 2014
versus the comparable periods is due to increased borrowings under our
revolving credit facility.
Hedging
-
The nature of our operations results in exposure to fluctuations in
commodity prices, interest rates and foreign currency exchange rates.
We monitor and, when appropriate, use derivative financial instruments
to manage our exposure to these fluctuations. All transactions of this
nature entered into are related to an underlying financial position or
to future crude oil and natural gas production. We do not use
derivative financial instruments for speculative purposes. We have
elected not to designate any of our derivative financial instruments as
accounting hedges and thus account for changes in fair value in net
earnings at each reporting period. We have not obtained collateral or
other security to support our financial derivatives as we review the
creditworthiness of our counterparties prior to entering into
derivative contracts.
-
Our hedging philosophy is to hedge solely for the purposes of risk
mitigation. Our approach is to hedge centrally to manage our global
risk (typically with an outlook of 12 to 18 months) with a goal of
securing pricing for up to 50% of net of royalty volumes through a
portfolio of forward collars, swaps, and physical fixed price
arrangements.
-
We believe that our hedging philosophy and approach increases the
stability of revenues, cash flows and future dividends while also
assisting us in the execution of our capital and development plans.
-
The realized gain in 2014 related primarily to amounts received on our
TTF and Dated Brent derivatives, partially offset by payments made on
our AECO derivatives.
-
A listing of derivative positions as at September 30, 2014 is included
in "Supplemental Table 2" in this MD&A.
FINANCIAL PERFORMANCE REVIEW
|
Three Months Ended
|
|
Sep 30,
|
Jun 30,
|
Mar 31,
|
Dec 31,
|
Sep 30,
|
Jun 30,
|
Mar 31,
|
Dec 31,
|
($M except per share)
|
2014
|
2014
|
2014
|
2013
|
2013
|
2013
|
2013
|
2012
|
Petroleum and natural gas sales
|
344,688
|
387,684
|
381,183
|
325,108
|
327,185
|
311,966
|
309,576
|
241,233
|
Net earnings
|
53,903
|
53,993
|
102,788
|
101,510
|
67,796
|
106,198
|
52,137
|
56,914
|
Net earnings per share
|
|
|
|
|
|
|
|
|
|
Basic
|
0.50
|
0.51
|
1.00
|
1.00
|
0.67
|
1.05
|
0.53
|
0.58
|
|
Diluted
|
0.50
|
0.50
|
0.99
|
0.98
|
0.66
|
1.04
|
0.51
|
0.57
|
The following table shows a reconciliation of the change in net
earnings:
($M)
|
Q3/14 vs. Q2/14
|
Q3/14 vs. Q3/13
|
2014 vs. 2013
|
Net earnings - Comparative period
|
53,993
|
67,796
|
226,131
|
Changes in:
|
|
|
|
Fund flows from operations
|
(18,178)
|
32,253
|
115,471
|
Equity based compensation
|
3,497
|
(1,941)
|
(9,770)
|
Unrealized gain or loss on derivative instruments
|
9,321
|
11,499
|
6,375
|
Unrealized foreign exchange gain or loss
|
11,879
|
(16,099)
|
(43,351)
|
Unrealized other income
|
(701)
|
(321)
|
282
|
Accretion
|
(114)
|
150
|
312
|
Depletion and depreciation
|
743
|
(25,333)
|
(69,821)
|
Deferred tax
|
(6,537)
|
(14,101)
|
(14,945)
|
Net earnings - Current Period
|
53,903
|
53,903
|
210,684
|
The fluctuations in net earnings from quarter-to-quarter and from
year-to-year are caused by changes in both cash and non-cash based
income and charges. Cash based items are reflected in fund flows from
operations and include: sales, royalties, operating expenses,
transportation, general and administration expense, current tax
expense, interest expense, realized gains and losses on derivative
instruments, and realized foreign exchange gains and losses. Non-cash
items include: equity based compensation expense, unrealized gains and
losses on derivative instruments, unrealized foreign exchange gains and
losses, accretion, depletion and depreciation expense, and deferred
taxes. In addition, non-cash items may also include amounts resulting
from acquisitions or charges resulting from impairment or impairment
recoveries.
Equity based compensation
Equity based compensation expense relates to non-cash compensation
expense attributable to long-term incentives granted to directors,
officers and employees under the VIP. The expense is recognized over
the vesting period based on the grant date fair value of awards,
adjusted for the ultimate number of awards that actually vest as
determined by the Company's achievement of performance conditions.
Equity based compensation expense for the three and nine months ended
September 30, 2014 was higher than the same periods in 2013 as a result
of an upward revision of future performance condition assumptions
during Q2 2014. Equity based compensation expense was lower for Q3
2014 as compared to Q2 2014 due to aforementioned upward revision of
future performance condition assumptions during Q2 2014.
Unrealized gain or loss on derivative instruments
Unrealized gain or loss on derivative instruments arise as a result of
changes in forecasted future commodity prices. As Vermilion uses
derivative instruments to manage the commodity price exposure of our
future crude oil and natural gas production, we will normally recognize
unrealized gains on derivative instruments when forecasted future
commodity prices decline and vice-versa.
In the nine months ended September 30, 2014, we recognized an unrealized
gain on derivative instruments of $10.1 million, relating primarily to
our crude oil swaps and collars. As at September 30, 2014, we have a
net derivative asset position of $7.6 million.
Unrealized foreign exchange gain or loss
As a result of Vermilion's international operations, Vermilion conducts
business in currencies other than the Canadian dollar and has monetary
assets and liabilities (including cash, receivables, payables,
derivative assets and liabilities, and intercompany loans) denominated
in such currencies. Vermilion's exposure to foreign currencies
includes the US dollar, the Euro and the Australian Dollar.
Unrealized foreign exchange gains and losses are the result of
translating monetary assets and liabilities held in non-functional
currencies to the respective functional currencies of Vermilion and its
subsidiaries. Unrealized foreign exchange primarily results from the
translation of Euro denominated financial assets. As such, an
appreciation in the Euro against the Canadian dollar will result in an
unrealized foreign exchange gain, and vice-versa.
For the three and nine months ended September 30, 2014, the Canadian
dollar strengthened versus the Euro resulting in unrealized foreign
exchange losses of $11.9 million and $13.6 million, respectively.
Accretion
Fluctuations in accretion expense is primarily the result of changes in
discount rates applicable to the balance of asset retirement
obligations and additions resulting from drilling and acquisitions.
Q3 2014 accretion expense was relatively consistent as compared to Q2
2014 and the comparable periods in 2013.
Depletion and depreciation
Fluctuations in depletion and depreciation expense are primarily the
result of changes in produced crude oil and natural gas volumes.
Depletion and depreciation on a per boe basis for Q3 2014 of $23.21 was
higher as compared to Q2 2014 of $22.45/boe as a result of lower
production in Canada. Depletion and depreciation on a per boe basis
increased for the three and nine month periods ended September 30, 2014
to $23.21/boe and $22.92/boe, respectively, as compared to the same
periods in 2013 of $20.74/boe and $20.91/boe, respectively. The
increase on a per boe basis was largely due to Vermilion's increased
capital and acquisition activity which results in higher per boe
amounts when compared to legacy producing assets.
Deferred tax
Deferred tax expense arises primarily as a result of changes in the
accounting basis and tax basis for capital assets and asset retirement
obligations and changes in available tax losses.
FINANCIAL POSITION REVIEW
Balance sheet strategy
We believe that our balance sheet supports our defined growth
initiatives and our focus is on managing and maintaining a conservative
balance sheet. To ensure that our balance sheet continues to support
our defined growth initiatives, we regularly review whether forecasted
fund flows from operations is sufficient to finance planned capital
expenditures, dividends, and abandonment and reclamation expenditures.
To the extent that forecasted fund flows from operations is not
expected to be sufficient to fulfill such expenditures, we will
evaluate our ability to finance any excess with debt (including
borrowing using the unutilized capacity of our existing revolving
credit facility) or issue equity.
To ensure that we maintain a conservative balance sheet, we monitor the
ratio of net debt to fund flows from operations and typically strive to
maintain an internally targeted ratio of approximately 1.0 to 1.3. In
a commodity price environment where prices trend higher, we may target
a lower ratio and conversely, in a lower commodity price environment,
the acceptable ratio may be higher. At times, we will use our balance
sheet to finance acquisitions and, in these situations, we are prepared
to accept a higher ratio in the short term but will implement a
strategy to reduce the ratio to acceptable levels within a reasonable
period of time, usually considered to be no more than 12 to 24 months.
This plan could potentially include an increase in hedging activities,
a reduction in capital expenditures, an issuance of equity or the
utilization of excess fund flows from operations to reduce outstanding
indebtedness.
Absent additional material acquisitions, Vermilion currently expects the
net debt to fund flows ratio to return to our internally targeted ratio
over the next 12 to 24 months as a result of incremental cash flows
from Corrib and our acquisitions in Germany and Canada.
Long-term debt
Our long-term debt consists of our revolving credit facility and our
senior unsecured notes. The applicable annual interest rates and the
balances recognized on our balance sheet are as follows:
|
Annual Interest Rate
|
|
|
As At
|
|
Sep 30,
|
Dec 31,
|
|
|
Sep 30,
|
Dec 31,
|
($M)
|
2014
|
2013
|
|
|
2014
|
2013
|
Revolving credit facility
|
3.3%
|
3.3%
|
|
|
974,857
|
766,898
|
Senior unsecured notes
|
6.5%
|
6.5%
|
|
|
223,791
|
223,126
|
Long-term debt
|
3.9%
|
4.7%
|
|
|
1,198,648
|
990,024
|
Revolving Credit Facility
Our revolving credit facility bears interest at rates applicable to
demand loans plus applicable margins. The following table outlines the
terms of our revolving credit facility:
|
As At
|
|
Sep 30,
|
Dec 31,
|
|
2014
|
2013
|
Total facility amount 1
|
$1.50 billion
|
$1.20 billion
|
Amount drawn
|
$974.9 million
|
$766.9 million
|
Letters of credit outstanding
|
$10.3 million
|
$8.1 million
|
Facility maturity date
|
31-May-17
|
31-May-16
|
|
|
|
(1)
|
We may, by adding lenders or seeking an increase to an existing lender's
commitment, increase the total committed facility amount to no more
than $1.75 billion.
|
In addition, the revolving credit facility is subject to the following
covenants:
|
|
As At
|
|
|
Sep 30,
|
Dec 31,
|
Financial covenant
|
Limit
|
2014
|
2013
|
Consolidated total debt to consolidated EBITDA
|
4.0
|
1.16
|
1.06
|
Consolidated total senior debt to consolidated EBITDA
|
3.0
|
0.94
|
0.82
|
Consolidated total senior debt to total capitalization
|
50%
|
31%
|
28%
|
Our covenants include financial measures defined within our revolving
credit facility agreement that are not defined under GAAP. These
financial measures are defined by our revolving credit facility
agreement as follows:
-
Consolidated total debt: Includes all amounts classified as "Long-term
debt" on our balance sheet.
-
Consolidated total senior debt: Defined as consolidated total debt
excluding unsecured and subordinated debt.
-
Consolidated EBITDA: Defined as consolidated net earnings before
interest, income taxes, depreciation, accretion and certain other
non-cash items.
-
Total capitalization: Includes all amounts on our balance sheet
classified as "Long-term debt" and "Shareholders' equity".
Vermilion was in compliance with its financial covenants for all periods
presented.
Senior Unsecured Notes
We have outstanding senior unsecured notes that are senior unsecured
obligations and rank pari passu with all our other present and future
unsecured and unsubordinated indebtedness. The following table
outlines the terms of these notes:
|
|
Total issued and outstanding amount
|
$225.0 million
|
Interest rate
|
6.5% per annum
|
Issued date
|
February 10, 2011
|
Maturity date
|
February 10, 2016
|
Prior to February 10, 2015, Vermilion may redeem all or part of the
senior unsecured notes at 103.25% of their principal amount plus any
accrued and unpaid interest. Subsequent to February 10, 2015,
Vermilion may redeem all or part of the senior unsecured notes at 100%
of their principal amount plus any accrued and unpaid interest. The
notes were initially recognized at fair value net of transaction costs
and are subsequently measured at amortized cost using an effective
interest rate of 7.1%.
Net debt
Net debt is reconciled to its most directly comparable GAAP measure,
long-term debt, as follows:
|
As At
|
|
Sep 30,
|
Dec 31,
|
($M)
|
2014
|
2013
|
Long-term debt
|
1,198,648
|
990,024
|
Current liabilities
|
431,175
|
347,444
|
Current assets
|
(386,385)
|
(587,783)
|
Net debt
|
1,243,438
|
749,685
|
|
|
|
Ratio of net debt to annualized fund flows from operations
|
1.5
|
1.1
|
Long-term debt as at September 30, 2014 increased to $1.2 billion from
$990.0 million as at December 31, 2013 as a result of draws on the
revolving credit facility during the current year to fund our
acquisitions in Germany and Saskatchewan coupled with the assumption of
$47.5 million of long-term debt pursuant to the latter acquisition.
This increase in long-term debt resulted in an increase to net debt
from $749.7 million to $1.2 billion. As a result of this increase to
long-term debt, the year-to-date ratio of net debt to annualized fund
flows from operations increased from 1.1 as at December 31, 2013 to 1.5
as at September 30, 2014.
Shareholders' capital
Beginning with the January 2014 dividend paid on February 18, 2014, we
increased our monthly dividend by 7.5%. This was our second
consecutive annual increase.
During the nine months ended September 30, 2014, we maintained monthly
dividends at $0.215 per share and declared dividends totalled $203.6
million.
The following table outlines our dividend payment history:
Date
|
Monthly dividend per unit or share
|
January 2003 to December 2007
|
$0.17
|
January 2008 to December 2012
|
$0.19
|
January 2013 to December 31, 2013
|
$0.20
|
Beginning January 2014
|
$0.215
|
Our policy with respect to dividends is to be conservative and maintain
a low ratio of dividends to fund flows from operations. During low
price commodity cycles, we will initially maintain dividends and allow
the ratio to rise. Should low commodity price cycles remain for an
extended period of time, we will evaluate the necessity of changing the
level of dividends, taking into consideration capital development
requirements, debt levels and acquisition opportunities.
Over the next two years, we anticipate that Corrib, Cardium and other
exploration and development activities will require significant capital
investment. Although we currently expect to be able to maintain our
current dividend, fund flows from operations may not be sufficient
during this period to fund cash dividends, capital expenditures and
asset retirement obligations. We will evaluate our ability to finance
any shortfalls with debt, issuances of equity or by reducing some or
all categories of expenditures to ensure that total expenditures do not
exceed available funds.
The following table reconciles the change in shareholders' capital:
Shareholders' Capital
|
Number of Shares ('000s)
|
|
Amount ($M)
|
Balance as at December 31, 2013
|
|
102,123
|
|
1,618,443
|
Shares issued pursuant to corporate acquisition
|
|
2,827
|
|
204,960
|
Issuance of shares pursuant to the dividend reinvestment plan
|
|
902
|
|
58,450
|
Vesting of equity based awards
|
|
950
|
|
47,657
|
Share-settled dividends on vested equity based awards
|
|
108
|
|
7,519
|
Shares issued pursuant to the bonus plan
|
|
11
|
|
721
|
Balance as at September 30, 2014
|
|
106,921
|
|
1,937,750
|
As at September 30, 2014, there were approximately 1.7 million VIP
awards outstanding. As at November 6, 2014, there were approximately
107.0 million shares outstanding.
ASSET RETIREMENT OBLIGATIONS
As at September 30, 2014, asset retirement obligations were $397.9
million compared to $326.2 million as at December 31, 2013.
The increase in asset retirement obligations is largely attributable to
an overall decrease in the discount rates applied to the abandonment
obligations, accretion, and additions from new wells drilled during the
year and abandonment obligations associated with the assets acquired in
Germany and Canada.
OFF BALANCE SHEET ARRANGEMENTS
We have certain lease agreements that are entered into in the normal
course of operations, all of which are operating leases and accordingly
no asset or liability value has been assigned to the consolidated
balance sheet as at September 30, 2014.
We have not entered into any guarantee or off balance sheet arrangements
that would materially impact our financial position or results of
operations.
Accounting pronouncements not yet adopted
The impact of the adoption of the following pronouncements are currently
being evaluated.
IFRS 9 "Financial Instruments"
On July 24, 2014, the IASB issued the final element of its comprehensive
response to the financial crisis by issuing IFRS 9 "Financial
Instruments". The improvements introduced by IFRS 9 includes a logical
model for classification and measurement, a single, forward-looking
'expected loss' impairment model and a substantially-reformed approach
to hedge accounting. Vermilion will adopt the standard for reporting
periods beginning January 1, 2018.
IFRS 15 "Revenue from Contracts with Customers"
On May 28, 2014, the IASB issued IFRS 15 "Revenue from Contracts with
Customers", a new standard that specifies recognition requirements for
revenue as well as requiring entities to provide the users of financial
statements with more informative and relevant disclosures. The
standard replaces IAS 11 "Construction Contracts" and IAS 18 "Revenue"
as well as a number of revenue-related interpretations. Vermilion will
adopt the standard for reporting periods beginning January 1, 2017.
RISK MANAGEMENT
Vermilion is exposed to various market and operational risks. For a
detailed discussion of these risks, please see Vermilion's Annual
Report for the year ended December 31, 2013.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with IFRS requires
management to make estimates, judgments and assumptions that affect
reported assets, liabilities, revenues and expenses, gains and losses,
and disclosures of any possible contingencies. These estimates and
assumptions are developed based on the best available information which
management believed to be reasonable at the time such estimates and
assumptions were made. As such, these assumptions are uncertain at the
time estimates are made and could change, resulting in a material
impact on Vermilion's consolidated financial statements. Estimates are
reviewed by management on an ongoing basis and as a result may change
from period to period due to the availability of new information or
changes in circumstances. Additionally, as a result of the unique
circumstances of each jurisdiction that Vermilion operates in, the
critical accounting estimates may affect one or more jurisdictions.
The following outlines what management believes to be the most critical
accounting policies involving the use of estimates and assumptions:
i.
|
Depletion and depreciation charges are based on estimates of total
proven and probable reserves that Vermilion expects to recover in the
future.
|
ii.
|
Asset retirement obligations are based on past experience and current
economic factors which management believes are reasonable.
|
iii.
|
Impairment tests are performed at the cash generating unit (CGU) level,
which is determined based on management's judgment. The calculation of
the recoverable amount of a CGU is based on market factors as well as
estimates of PNG reserves and future costs required to develop
reserves.
|
iv.
|
Deferred tax amounts recognized in the consolidated financial statements
are based on management's assessment of the tax positions at the end of
each reporting period.
|
INTERNAL CONTROL OVER FINANCIAL REPORTING
There was no change in Vermilion's internal control over financial
reporting that occurred during the period covered by this MD&A that has
materially affected, or is reasonably likely to materially affect, its
internal control over financial reporting.
Supplemental Table 1: Netbacks
The following table includes financial statement information on a per
unit basis by business unit. Natural gas sales volumes have been
converted on a basis of six thousand cubic feet of natural gas to one
barrel of oil equivalent.
|
Three Months Ended September 30, 2014
|
|
Nine Months Ended September 30, 2014
|
|
|
Three Months
Ended
September 30,
2013
|
|
Nine Months
Ended
September 30,
2013
|
|
Oil & NGLs
|
Natural Gas
|
Total
|
|
Oil & NGLs
|
Natural Gas
|
Total
|
|
|
Total
|
|
Total
|
|
$/bbl
|
$/mcf
|
$/boe
|
|
$/bbl
|
$/mcf
|
$/boe
|
|
|
$/boe
|
|
$/boe
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
91.25
|
4.44
|
64.85
|
|
95.24
|
4.82
|
68.58
|
|
|
63.56
|
|
61.16
|
Royalties
|
(13.37)
|
(0.40)
|
(8.89)
|
|
(12.06)
|
(0.35)
|
(8.05)
|
|
|
(7.09)
|
|
(6.41)
|
Transportation
|
(2.50)
|
(0.17)
|
(1.89)
|
|
(2.33)
|
(0.17)
|
(1.80)
|
|
|
(2.08)
|
|
(1.75)
|
Operating
|
(9.19)
|
(1.42)
|
(8.91)
|
|
(9.73)
|
(1.39)
|
(9.17)
|
|
|
(8.12)
|
|
(9.15)
|
Operating netback
|
66.19
|
2.45
|
45.16
|
|
71.12
|
2.91
|
49.56
|
|
|
46.27
|
|
43.85
|
General and administration
|
|
|
(2.11)
|
|
|
|
(2.25)
|
|
|
(2.21)
|
|
(2.26)
|
Fund flows from operations netback
|
|
|
43.05
|
|
|
|
47.31
|
|
|
44.06
|
|
41.59
|
France
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
107.99
|
-
|
107.99
|
|
114.36
|
-
|
114.36
|
|
|
107.08
|
|
104.29
|
Royalties
|
(7.07)
|
-
|
(7.07)
|
|
(7.25)
|
-
|
(7.26)
|
|
|
(6.73)
|
|
(6.23)
|
Transportation
|
(4.80)
|
-
|
(4.80)
|
|
(4.88)
|
-
|
(4.88)
|
|
|
(2.41)
|
|
(2.40)
|
Operating
|
(15.42)
|
-
|
(15.42)
|
|
(15.80)
|
-
|
(15.80)
|
|
|
(12.97)
|
|
(15.67)
|
Operating netback
|
80.70
|
-
|
80.70
|
|
86.43
|
-
|
86.42
|
|
|
84.97
|
|
79.99
|
General and administration
|
|
|
(6.50)
|
|
|
|
(5.63)
|
|
|
(4.41)
|
|
(4.44)
|
Current income taxes
|
|
|
(10.89)
|
|
|
|
(19.93)
|
|
|
(28.17)
|
|
(20.25)
|
Fund flows from operations netback
|
|
|
63.31
|
|
|
|
60.86
|
|
|
52.39
|
|
55.30
|
Netherlands
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
90.01
|
7.55
|
45.73
|
|
96.66
|
8.72
|
52.80
|
|
|
61.44
|
|
62.70
|
Royalties
|
-
|
(0.27)
|
(1.60)
|
|
-
|
(0.35)
|
(2.06)
|
|
|
-
|
|
-
|
Operating
|
-
|
(1.54)
|
(9.18)
|
|
-
|
(1.61)
|
(9.57)
|
|
|
(11.69)
|
|
(9.04)
|
Operating netback
|
90.01
|
5.74
|
34.95
|
|
96.66
|
6.76
|
41.17
|
|
|
49.75
|
|
53.66
|
General and administration
|
|
|
(0.35)
|
|
|
|
(0.61)
|
|
|
(0.75)
|
|
(0.73)
|
Current income taxes
|
|
|
(2.02)
|
|
|
|
(3.37)
|
|
|
(15.28)
|
|
(16.20)
|
Fund flows from operations netback
|
|
|
32.58
|
|
|
|
37.19
|
|
|
33.72
|
|
36.73
|
Germany
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
-
|
6.07
|
36.43
|
|
-
|
7.45
|
44.68
|
|
|
-
|
|
-
|
Royalties
|
-
|
(1.45)
|
(8.68)
|
|
-
|
(1.60)
|
(9.58)
|
|
|
-
|
|
-
|
Transportation
|
-
|
(0.48)
|
(2.86)
|
|
-
|
(0.56)
|
(3.36)
|
|
|
-
|
|
-
|
Operating
|
-
|
(1.57)
|
(9.44)
|
|
-
|
(1.52)
|
(9.10)
|
|
|
-
|
|
-
|
Operating netback
|
-
|
2.57
|
15.45
|
|
-
|
3.77
|
22.64
|
|
|
-
|
|
-
|
General and administration
|
|
|
(4.62)
|
|
|
|
(3.89)
|
|
|
-
|
|
-
|
Current income taxes
|
|
|
(0.62)
|
|
|
|
(1.86)
|
|
|
-
|
|
-
|
Fund flows from operations netback
|
|
|
10.21
|
|
|
|
16.89
|
|
|
-
|
|
-
|
Australia
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
119.07
|
-
|
119.07
|
|
124.59
|
-
|
124.59
|
|
|
120.95
|
|
117.65
|
Operating
|
(26.73)
|
-
|
(26.73)
|
|
(25.63)
|
-
|
(25.63)
|
|
|
(20.86)
|
|
(20.41)
|
PRRT (1)
|
(25.86)
|
-
|
(25.86)
|
|
(27.42)
|
-
|
(27.42)
|
|
|
(23.89)
|
|
(20.93)
|
Operating netback
|
66.48
|
-
|
66.48
|
|
71.54
|
-
|
71.54
|
|
|
76.20
|
|
76.31
|
General and administration
|
|
|
(2.58)
|
|
|
|
(2.49)
|
|
|
(2.16)
|
|
(2.29)
|
Corporate income taxes
|
|
|
(9.62)
|
|
|
|
(11.54)
|
|
|
(11.70)
|
|
(13.56)
|
Fund flows from operations netback
|
|
|
54.28
|
|
|
|
57.51
|
|
|
62.34
|
|
60.46
|
Total Company
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
102.49
|
5.74
|
76.80
|
|
108.02
|
6.60
|
82.73
|
|
|
86.10
|
|
83.10
|
Realized hedging gain (loss)
|
1.57
|
0.44
|
1.97
|
|
0.37
|
0.36
|
1.03
|
|
|
(1.25)
|
|
(0.51)
|
Royalties
|
(8.56)
|
(0.50)
|
(6.46)
|
|
(7.88)
|
(0.51)
|
(6.09)
|
|
|
(4.93)
|
|
(4.41)
|
Transportation
|
(2.83)
|
(0.30)
|
(2.45)
|
|
(2.77)
|
(0.31)
|
(2.44)
|
|
|
(1.72)
|
|
(1.74)
|
Operating
|
(14.73)
|
(1.48)
|
(12.53)
|
|
(15.08)
|
(1.49)
|
(12.81)
|
|
|
(12.17)
|
|
(12.87)
|
PRRT (1)
|
(4.95)
|
-
|
(3.08)
|
|
(5.51)
|
-
|
(3.47)
|
|
|
(4.12)
|
|
(3.45)
|
Operating netback
|
72.99
|
3.90
|
54.25
|
|
77.15
|
4.65
|
58.95
|
|
|
61.91
|
|
60.12
|
General and administration
|
|
|
(3.62)
|
|
|
|
(3.60)
|
|
|
(3.17)
|
|
(3.15)
|
Interest expense
|
|
|
(2.88)
|
|
|
|
(2.73)
|
|
|
(2.66)
|
|
(2.46)
|
Realized foreign exchange gain (loss)
|
|
|
0.17
|
|
|
|
(0.05)
|
|
|
(0.32)
|
|
(0.05)
|
Other income
|
|
|
0.05
|
|
|
|
0.04
|
|
|
0.06
|
|
0.07
|
Corporate income taxes (1)
|
|
|
(3.89)
|
|
|
|
(6.59)
|
|
|
(12.22)
|
|
(10.40)
|
Fund flows from operations netback
|
|
|
44.08
|
|
|
|
46.02
|
|
|
43.60
|
|
44.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Vermilion considers Australian PRRT to be an operating item and
accordingly has included PRRT in the calculation of operating
netbacks. Current income taxes presented above excludes PRRT.
|
Supplemental Table 2: Hedges
The following tables outline Vermilion's outstanding risk management
positions as at September 30, 2014:
|
Note
|
Volume
|
Strike Price(s)
|
Crude Oil
|
|
|
|
WTI - Collar
|
|
|
|
October 2014 - December 2014
|
|
250 bbl/d
|
90.00 - 101.10 US $
|
WTI - Swap
|
|
|
|
May 2014 - November 2014
|
1
|
250 bbl/d
|
97.25 CAD $
|
July 2014 - December 2014
|
|
750 bbl/d
|
99.00 US $
|
September 2014 - October 2014
|
2
|
500 bbl/d
|
96.05 US $
|
October 2014 - November 2014
|
3
|
500 bbl/d
|
92.90 US $
|
October 2014 - December 2014
|
4
|
1,750 bbl/d
|
94.89 US $
|
MSW - Fixed Price Differential
|
|
|
|
October 2014 - December 2014
|
|
1,000 bbl/d
|
WTI less 8.40 US $
|
Dated Brent - Collar
|
|
|
|
April 2014 - December 2014
|
|
1,000 bbl/d
|
106.00 - 110.73 US $
|
October 2014 - December 2014
|
|
800 bbl/d
|
95.00 - 121.60 US $
|
Dated Brent - Swap
|
|
|
|
January 2014 - December 2014
|
|
500 bbl/d
|
108.28 US $
|
July 2014 - December 2014
|
|
1,000 bbl/d
|
109.64 US $
|
July 2014 - December 2014
|
5
|
500 bbl/d
|
109.40 US $
|
September 2014 - December 2014
|
5
|
500 bbl/d
|
108.08 US $
|
October 2014 - December 2014
|
4
|
700 bbl/d
|
104.48 US $
|
January 2015
|
6
|
250 bbl/d
|
107.45 US $
|
February 2015
|
7
|
250 bbl/d
|
109.00 US $
|
March 2015
|
8
|
250 bbl/d
|
110.40 US $
|
MSW - Fixed Price Differential (Physical)
|
|
|
|
April 2014 - December 2014
|
|
1,030 bbl/d
|
WTI less 8.20 US $
|
July 2014 - December 2014
|
|
2,052 bbl/d
|
WTI less 8.68 US $
|
November 2014 - March 2015
|
|
1,042 bbl/d
|
WTI less 6.85 US $
|
January 2015 - March 2015
|
|
1,573 bbl/d
|
WTI less 7.43 US $
|
LSB - Fixed Price Differential (Physical)
|
|
|
|
October 2014 - December 2014
|
|
513 bbl/d
|
WTI less 9.00 US $
|
October 2014 - March 2015
|
|
830 bbl/d
|
WTI less 10.00 US $
|
January 2015 - March 2015
|
|
524 bbl/d
|
WTI less 8.60 US $
|
|
|
|
|
(1)
|
Assumed as part of Vermilion's April 29, 2014 acquisition of Elkhorn
Resources Inc.
|
(2)
|
Prior to the expiration of this swap, the counterparty has the option to
extend the swap to December 31, 2014 at the contracted volume and
price.
|
(3)
|
Prior to the expiration of this swap, the counterparty has the option to
extend the swap to January 31, 2015 at the contracted volume and price.
|
(4)
|
Prior to the expiration of this swap, the counterparty has the option to
extend the swap to March 31, 2015 at the contracted volume and price.
|
(5)
|
Prior to the expiration of this swap, the counterparty has the option to
extend the swap to June 30, 2015 at the contracted volume and price.
|
(6)
|
On March 31, 2015, the counterparty has the option to extend the swap
for the period of April to June 2015 for 500 boe/d at the contracted
price.
|
(7)
|
On June 30, 2015, the counterparty has the option to extend the swap for
the period of July to September 2015 for 500 boe/d at the contracted
price.
|
(8)
|
On September 30, 2015, the counterparty has the option to extend the
swap for the period of October to December 2015 for 500 boe/d at the
contracted price.
|
|
Note
|
Volume
|
Strike Price(s)
|
Canadian Natural Gas
|
|
|
|
AECO - Collar
|
|
|
|
January 2014 - December 2014
|
|
10,000 GJ/d
|
3.18 - 3.81 CAD $
|
April 2014 - December 2014
|
|
1,000 GJ/d
|
3.60 - 3.96 CAD $
|
April 2014 - March 2015
|
|
2,500 GJ/d
|
3.60 - 4.08 CAD $
|
November 2014 - March 2015
|
|
2,500 GJ/d
|
3.60 - 4.27 CAD $
|
AECO - Swap
|
|
|
|
January 2014 - December 2014
|
|
5,000 GJ/d
|
3.71 CAD $
|
April 2014 - October 2014
|
|
8,000 GJ/d
|
4.00 CAD $
|
|
|
|
|
European Natural Gas
|
|
|
|
TTF - Collar
|
|
|
|
October 2014 - December 2014
|
|
1,800 GJ/d
|
6.11 - 7.08 EUR €
|
TTF - Swap
|
|
|
|
October 2014 - December 2014
|
|
3,600 GJ/d
|
6.71 EUR €
|
|
|
|
|
Electricity
|
|
|
|
AESO - Swap
|
|
|
|
January 2014 - December 2014
|
|
7.2 MWh/d
|
54.75 CAD $
|
AESO - Swap (Physical)
|
|
|
|
January 2013 - December 2015
|
|
72.0 MWh/d
|
53.17 CAD $
|
|
|
|
|
US Dollar
|
|
|
|
USD - Collar
|
|
|
|
October 2014 - December 2014
|
|
1,500,000 USD $/month
|
1.075 - 1.145 CAD $
|
October 2014 - December 2014
|
1
|
7,500,000 USD $/month
|
1.092 - 1.114 CAD $
|
|
|
|
|
(1)
|
Vermilion has upside participation on this hedge up to the limit price
of 1.176 CAD; above which, settlement will occur at the conditional
call level of 1.114 CAD.
|
Supplemental Table 3: Capital Expenditures
|
Three Months Ended
|
|
|
Nine Months Ended
|
By classification
|
Sep 30,
|
Jun 30,
|
Sep 30,
|
|
|
Sep 30,
|
Sep 30,
|
($M)
|
2014
|
2014
|
2013
|
|
|
2014
|
2013
|
Drilling and development
|
180,479
|
117,975
|
135,110
|
|
|
467,294
|
389,635
|
Dispositions
|
-
|
-
|
-
|
|
|
-
|
(8,627)
|
Exploration and evaluation
|
9,554
|
17,098
|
551
|
|
|
54,187
|
13,240
|
Capital expenditures
|
190,033
|
135,073
|
135,661
|
|
|
521,481
|
394,248
|
Property acquisition
|
40,847
|
-
|
7,586
|
|
|
219,074
|
7,586
|
Corporate acquisition
|
-
|
381,139
|
-
|
|
|
381,139
|
-
|
Acquisitions
|
40,847
|
381,139
|
7,586
|
|
|
600,213
|
7,586
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
By category
|
Sep 30,
|
Jun 30,
|
Sep 30,
|
|
|
Sep 30,
|
Sep 30,
|
($M)
|
2014
|
2014
|
2013
|
|
|
2014
|
2013
|
Land
|
2,346
|
950
|
(4,450)
|
|
|
8,049
|
986
|
Seismic
|
6,135
|
1,869
|
5,284
|
|
|
11,436
|
14,666
|
Drilling and completion
|
93,386
|
42,083
|
63,590
|
|
|
242,005
|
210,010
|
Production equipment and facilities
|
68,964
|
60,547
|
47,665
|
|
|
198,266
|
138,426
|
Recompletions
|
10,853
|
13,459
|
15,650
|
|
|
28,538
|
24,291
|
Other
|
8,349
|
16,165
|
7,922
|
|
|
33,187
|
14,496
|
Dispositions
|
-
|
-
|
-
|
|
|
-
|
(8,627)
|
Capital expenditures
|
190,033
|
135,073
|
135,661
|
|
|
521,481
|
394,248
|
Acquisitions
|
40,847
|
381,139
|
7,586
|
|
|
600,213
|
7,586
|
Total capital expenditures and acquisitions
|
230,880
|
516,212
|
143,247
|
|
|
1,121,694
|
401,834
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
By country
|
Sep 30,
|
Jun 30,
|
Sep 30,
|
|
|
Sep 30,
|
Sep 30,
|
($M)
|
2014
|
2014
|
2013
|
|
|
2014
|
2013
|
Canada
|
125,276
|
418,294
|
69,856
|
|
|
663,277
|
171,538
|
France
|
35,082
|
37,614
|
23,664
|
|
|
110,663
|
68,479
|
Netherlands
|
10,087
|
21,513
|
8,316
|
|
|
51,718
|
12,845
|
Germany
|
1,358
|
630
|
-
|
|
|
175,055
|
-
|
Ireland
|
30,050
|
27,221
|
35,028
|
|
|
73,507
|
76,426
|
Australia
|
15,985
|
10,991
|
5,880
|
|
|
32,667
|
69,511
|
Corporate
|
13,042
|
(51)
|
503
|
|
|
14,807
|
3,035
|
Total capital expenditures and acquisitions
|
230,880
|
516,212
|
143,247
|
|
|
1,121,694
|
401,834
|
Supplemental Table 4: Production
|
|
Q3/14
|
Q2/14
|
Q1/14
|
Q4/13
|
Q3/13
|
Q2/13
|
Q1/13
|
Q4/12
|
Q3/12
|
Q2/12
|
Q1/12
|
Q4/11
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
11,469
|
12,676
|
9,437
|
8,719
|
7,969
|
8,885
|
7,966
|
7,983
|
7,322
|
7,757
|
7,574
|
6,591
|
|
NGLs (bbls/d)
|
2,291
|
2,796
|
2,071
|
1,699
|
1,897
|
1,725
|
1,335
|
1,106
|
1,204
|
1,321
|
1,302
|
1,246
|
|
Natural gas (mmcf/d)
|
57.07
|
57.59
|
49.53
|
41.43
|
43.40
|
43.69
|
41.04
|
31.41
|
35.54
|
41.32
|
41.83
|
43.96
|
|
Total (boe/d)
|
23,272
|
25,070
|
19,763
|
17,322
|
17,099
|
17,892
|
16,140
|
14,323
|
14,449
|
15,965
|
15,848
|
15,163
|
|
% of consolidated
|
47%
|
49%
|
42%
|
43%
|
41%
|
42%
|
41%
|
40%
|
40%
|
40%
|
40%
|
41%
|
France
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
11,111
|
11,025
|
10,771
|
11,131
|
11,625
|
10,390
|
10,330
|
9,843
|
9,767
|
9,931
|
10,270
|
7,819
|
|
Natural gas (mmcf/d)
|
-
|
-
|
-
|
-
|
5.23
|
4.19
|
4.21
|
3.91
|
3.39
|
3.57
|
3.48
|
0.94
|
|
Total (boe/d)
|
11,111
|
11,025
|
10,771
|
11,131
|
12,496
|
11,088
|
11,032
|
10,495
|
10,333
|
10,526
|
10,850
|
7,976
|
|
% of consolidated
|
22%
|
21%
|
23%
|
27%
|
30%
|
26%
|
29%
|
29%
|
28%
|
27%
|
28%
|
22%
|
Netherlands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d)
|
63
|
96
|
69
|
62
|
48
|
50
|
96
|
70
|
41
|
84
|
72
|
66
|
|
Natural gas (mmcf/d)
|
38.07
|
40.35
|
43.15
|
37.53
|
28.78
|
38.52
|
36.91
|
33.03
|
34.59
|
33.74
|
35.08
|
34.58
|
|
Total (boe/d)
|
6,407
|
6,822
|
7,260
|
6,318
|
4,845
|
6,470
|
6,248
|
5,574
|
5,806
|
5,707
|
5,919
|
5,829
|
|
% of consolidated
|
13%
|
13%
|
16%
|
15%
|
12%
|
15%
|
16%
|
15%
|
16%
|
15%
|
15%
|
16%
|
Germany
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
15.38
|
16.13
|
10.64
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Total (boe/d)
|
2,563
|
2,689
|
1,773
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
|
% of consolidated
|
5%
|
5%
|
4%
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Australia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
6,567
|
6,483
|
7,110
|
6,189
|
7,070
|
7,363
|
5,287
|
5,873
|
5,958
|
6,970
|
6,648
|
7,686
|
|
% of consolidated
|
13%
|
12%
|
15%
|
15%
|
17%
|
17%
|
14%
|
16%
|
16%
|
18%
|
17%
|
21%
|
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil & NGLs (bbls/d)
|
31,501
|
33,076
|
29,458
|
27,800
|
28,609
|
28,413
|
25,014
|
24,875
|
24,292
|
26,063
|
25,866
|
23,408
|
|
% of consolidated
|
63%
|
63%
|
63%
|
68%
|
69%
|
66%
|
65%
|
69%
|
66%
|
67%
|
66%
|
64%
|
|
Natural gas (mmcf/d)
|
110.52
|
114.08
|
103.32
|
78.96
|
77.41
|
86.40
|
82.16
|
68.34
|
73.52
|
78.63
|
80.39
|
79.48
|
|
% of consolidated
|
37%
|
37%
|
37%
|
32%
|
31%
|
34%
|
35%
|
31%
|
34%
|
33%
|
34%
|
36%
|
|
Total (boe/d)
|
49,920
|
52,089
|
46,677
|
40,960
|
41,510
|
42,813
|
38,707
|
36,265
|
36,546
|
39,168
|
39,265
|
36,654
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
YTD 2014
|
2013
|
2012
|
2011
|
2010
|
2009
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
11,202
|
8,387
|
7,659
|
4,701
|
2,778
|
2,137
|
|
|
|
|
|
|
|
NGLs (bbls/d)
|
2,387
|
1,666
|
1,232
|
1,297
|
1,427
|
1,518
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
54.76
|
42.39
|
37.50
|
43.38
|
43.91
|
47.85
|
|
|
|
|
|
|
|
Total (boe/d)
|
22,714
|
17,117
|
15,142
|
13,227
|
11,524
|
11,629
|
|
|
|
|
|
|
|
% of consolidated
|
45%
|
41%
|
40%
|
38%
|
36%
|
37%
|
|
|
|
|
|
|
France
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
10,970
|
10,873
|
9,952
|
8,110
|
8,347
|
8,246
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
-
|
3.40
|
3.59
|
0.95
|
0.92
|
1.05
|
|
|
|
|
|
|
|
Total (boe/d)
|
10,970
|
11,440
|
10,550
|
8,269
|
8,501
|
8,421
|
|
|
|
|
|
|
|
% of consolidated
|
22%
|
28%
|
28%
|
23%
|
26%
|
27%
|
|
|
|
|
|
|
Netherlands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d)
|
76
|
64
|
67
|
58
|
35
|
23
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
40.50
|
35.42
|
34.11
|
32.88
|
28.31
|
21.06
|
|
|
|
|
|
|
|
Total (boe/d)
|
6,827
|
5,967
|
5,751
|
5,538
|
4,753
|
3,533
|
|
|
|
|
|
|
|
% of consolidated
|
14%
|
15%
|
15%
|
16%
|
15%
|
11%
|
|
|
|
|
|
|
Germany
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
14.07
|
-
|
-
|
-
|
-
|
-
|
|
|
|
|
|
|
|
Total (boe/d)
|
2,345
|
-
|
-
|
-
|
-
|
-
|
|
|
|
|
|
|
|
% of consolidated
|
5%
|
-
|
-
|
-
|
-
|
-
|
|
|
|
|
|
|
Australia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
6,718
|
6,481
|
6,360
|
8,168
|
7,354
|
7,812
|
|
|
|
|
|
|
|
% of consolidated
|
14%
|
16%
|
17%
|
23%
|
23%
|
25%
|
|
|
|
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil & NGLs (bbls/d)
|
31,353
|
27,471
|
25,270
|
22,334
|
19,941
|
19,735
|
|
|
|
|
|
|
|
% of consolidated
|
63%
|
67%
|
67%
|
63%
|
62%
|
63%
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
109.33
|
81.21
|
75.20
|
77.21
|
73.14
|
69.96
|
|
|
|
|
|
|
|
% of consolidated
|
37%
|
33%
|
33%
|
37%
|
38%
|
37%
|
|
|
|
|
|
|
|
Total (boe/d)
|
49,574
|
41,005
|
37,803
|
35,202
|
32,132
|
31,395
|
|
|
|
|
|
|
Supplemental Table 5: Segmented Financial Results
|
|
|
Three Months Ended September 30, 2014
|
($M)
|
Canada
|
|
France
|
|
Netherlands
|
|
Germany
|
|
Ireland
|
|
Australia
|
|
Corporate
|
|
Total
|
Drilling and development
|
88,116
|
|
34,883
|
|
10,087
|
|
1,358
|
|
30,050
|
|
15,985
|
|
-
|
|
180,479
|
Exploration and evaluation
|
9,277
|
|
199
|
|
-
|
|
-
|
|
-
|
|
-
|
|
78
|
|
9,554
|
Oil and gas sales to external customers
|
138,853
|
|
106,576
|
|
26,960
|
|
8,591
|
|
-
|
|
63,708
|
|
-
|
|
344,688
|
Royalties
|
(19,034)
|
|
(6,978)
|
|
(942)
|
|
(2,046)
|
|
-
|
|
-
|
|
-
|
|
(29,000)
|
Revenue from external customers
|
119,819
|
|
99,598
|
|
26,018
|
|
6,545
|
|
-
|
|
63,708
|
|
-
|
|
315,688
|
Transportation expense
|
(4,048)
|
|
(4,741)
|
|
-
|
|
(675)
|
|
(1,515)
|
|
-
|
|
-
|
|
(10,979)
|
Operating expense
|
(19,074)
|
|
(15,215)
|
|
(5,409)
|
|
(2,227)
|
|
-
|
|
(14,302)
|
|
-
|
|
(56,227)
|
General and administration
|
(4,523)
|
|
(6,411)
|
|
(204)
|
|
(1,090)
|
|
(334)
|
|
(1,378)
|
|
(2,322)
|
|
(16,262)
|
PRRT
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(13,834)
|
|
-
|
|
(13,834)
|
Corporate income taxes
|
-
|
|
(10,744)
|
|
(1,189)
|
|
(146)
|
|
-
|
|
(5,148)
|
|
(227)
|
|
(17,454)
|
Interest expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(12,918)
|
|
(12,918)
|
Realized gain on derivative instruments
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
8,837
|
|
8,837
|
Realized foreign exchange gain
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
812
|
|
812
|
Realized other income
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
235
|
|
235
|
Fund flows from operations
|
92,174
|
|
62,487
|
|
19,216
|
|
2,407
|
|
(1,849)
|
|
29,046
|
|
(5,583)
|
|
197,898
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2014
|
($M)
|
Canada
|
|
France
|
|
Netherlands
|
|
Germany
|
|
Ireland
|
|
Australia
|
|
Corporate
|
|
Total
|
Total assets
|
1,857,012
|
|
894,060
|
|
237,070
|
|
164,025
|
|
809,296
|
|
269,959
|
|
206,305
|
|
4,437,727
|
Drilling and development
|
215,860
|
|
99,564
|
|
43,512
|
|
2,184
|
|
73,507
|
|
32,667
|
|
-
|
|
467,294
|
Exploration and evaluation
|
33,440
|
|
11,099
|
|
8,206
|
|
-
|
|
-
|
|
-
|
|
1,442
|
|
54,187
|
Oil and gas sales to external customers
|
425,294
|
|
348,753
|
|
98,395
|
|
28,603
|
|
-
|
|
212,510
|
|
-
|
|
1,113,555
|
Royalties
|
(49,937)
|
|
(22,125)
|
|
(3,843)
|
|
(6,132)
|
|
-
|
|
-
|
|
-
|
|
(82,037)
|
Revenue from external customers
|
375,357
|
|
326,628
|
|
94,552
|
|
22,471
|
|
-
|
|
212,510
|
|
-
|
|
1,031,518
|
Transportation expense
|
(11,170)
|
|
(14,879)
|
|
-
|
|
(2,149)
|
|
(4,674)
|
|
-
|
|
-
|
|
(32,872)
|
Operating expense
|
(56,863)
|
|
(48,185)
|
|
(17,841)
|
|
(5,824)
|
|
-
|
|
(43,713)
|
|
-
|
|
(172,426)
|
General and administration
|
(13,951)
|
|
(17,164)
|
|
(1,128)
|
|
(2,488)
|
|
(868)
|
|
(4,245)
|
|
(8,647)
|
|
(48,491)
|
PRRT
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(46,772)
|
|
-
|
|
(46,772)
|
Corporate income taxes
|
-
|
|
(60,769)
|
|
(6,278)
|
|
(1,189)
|
|
-
|
|
(19,678)
|
|
(778)
|
|
(88,692)
|
Interest expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(36,712)
|
|
(36,712)
|
Realized gain on derivative instruments
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
13,896
|
|
13,896
|
Realized foreign exchange loss
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(642)
|
|
(642)
|
Realized other income
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
530
|
|
530
|
Fund flows from operations
|
293,373
|
|
185,631
|
|
69,305
|
|
10,821
|
|
(5,542)
|
|
98,102
|
|
(32,353)
|
|
619,337
|
ADDITIONAL AND NON-GAAP FINANCIAL MEASURES
This MD&A includes references to certain financial measures which do not
have standardized meanings prescribed by IFRS. As such, these
financial measures are considered additional GAAP or non-GAAP financial
measures and therefore may not be comparable with similar measures
presented by other issuers.
Fund flows from operations: We define fund flows from operations as cash flows from operating
activities before changes in non-cash operating working capital and
asset retirement obligations settled. Management believes that by
excluding the temporary impact of changes in non-cash operating working
capital, fund flows from operations provides a measure of our ability
to generate cash (that is not subject to short-term movements in
non-cash operating working capital) necessary to pay dividends, repay
debt, fund asset retirement obligations and make capital investments.
As we have presented fund flows from operations in the "Segmented
Information" note of our unaudited condensed consolidated interim
financial statements for the three and nine months ended September 30,
2014, we consider fund flows from operations to be an additional GAAP
financial measure.
Free cash flow: Represents fund flows from operations in excess of capital
expenditures. We consider free cash flow to be a key measure as it is
used to determine the funding available for investing and financing
activities, including payment of dividends, repayment of long-term
debt, reallocation to existing business units, and deployment into new
ventures.
Net dividends: We define net dividends as dividends declared less proceeds received for
the issuance of shares pursuant to the dividend reinvestment plan.
Management monitors net dividends and net dividends as a percentage of
fund flows from operations to assess our ability to pay dividends.
Payout: We define payout as net dividends plus drilling and development,
exploration and evaluation, dispositions and asset retirement
obligations settled. Management uses payout to assess the amount of
cash distributed back to shareholders and re-invested in the business
for maintaining production and organic growth.
Fund flows from operations (excluding Corrib) and Payout (excluding
Corrib): Management excludes expenditures relating to the Corrib project in
assessing fund flows from operations (an additional GAAP financial
measure) and payout in order to assess our ability to generate cash and
finance organic growth from our current producing assets.
Net debt: We define net debt as the sum of long-term debt and working capital.
Management uses net debt, and the ratio of net debt to fund flows from operations, to analyze our financial position and leverage. Please refer to the
preceding "Net Debt" section for a reconciliation of the net debt
non-GAAP financial measure.
Diluted shares outstanding: Is the sum of shares outstanding at the period end plus outstanding
awards under the VIP, based on current estimates of future performance
factors and forfeiture rates.
Cash dividends per share: Represents cash dividends declared per share.
Netbacks: Per boe and per mcf measures used in the analysis of operational
activities.
Total returns: Includes cash dividends per share and the change in Vermilion's share
price on the Toronto Stock Exchange.
The following tables reconcile fund flows from operations, net
dividends, payout, and diluted shares outstanding to their most
directly comparable GAAP measures as presented in our financial
statements:
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
Sep 30,
|
Jun 30,
|
Sep 30,
|
|
|
Sep 30,
|
Sep 30,
|
($M)
|
2014
|
2014
|
2013
|
|
|
2014
|
2013
|
Cash flows from operating activities
|
235,010
|
149,592
|
158,236
|
|
|
562,840
|
528,022
|
Changes in non-cash operating working capital
|
(41,789)
|
64,103
|
4,671
|
|
|
46,788
|
(30,652)
|
Asset retirement obligations settled
|
4,677
|
2,381
|
2,738
|
|
|
9,709
|
6,496
|
Fund flows from operations
|
197,898
|
216,076
|
165,645
|
|
|
619,337
|
503,866
|
Expenses related to Corrib
|
1,849
|
1,823
|
876
|
|
|
5,542
|
4,767
|
Fund flows from operations (excluding Corrib)
|
199,747
|
217,899
|
166,521
|
|
|
624,879
|
508,633
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
Sep 30,
|
Jun 30,
|
Sep 30,
|
|
|
Sep 30,
|
Sep 30,
|
($M)
|
2014
|
2014
|
2013
|
|
|
2014
|
2013
|
Dividends declared
|
68,896
|
68,710
|
61,003
|
|
|
203,613
|
181,391
|
Issuance of shares pursuant to the dividend reinvestment plan
|
(20,416)
|
(19,149)
|
(19,354)
|
|
|
(58,450)
|
(53,516)
|
Net dividends
|
48,480
|
49,561
|
41,649
|
|
|
145,163
|
127,875
|
Drilling and development
|
180,479
|
117,975
|
135,110
|
|
|
467,294
|
389,635
|
Dispositions
|
-
|
-
|
-
|
|
|
-
|
(8,627)
|
Exploration and evaluation
|
9,554
|
17,098
|
551
|
|
|
54,187
|
13,240
|
Asset retirement obligations settled
|
4,677
|
2,381
|
2,738
|
|
|
9,709
|
6,496
|
Payout
|
243,190
|
187,015
|
180,048
|
|
|
676,353
|
528,619
|
Corrib drilling and development
|
(30,050)
|
(27,221)
|
(35,028)
|
|
|
(73,507)
|
(76,426)
|
Payout (excluding Corrib)
|
213,140
|
159,794
|
145,020
|
|
|
602,846
|
452,193
|
|
As At
|
|
Sep 30,
|
Jun 30,
|
Sep 30,
|
('000s of shares)
|
2014
|
2014
|
2013
|
Shares outstanding
|
106,921
|
106,620
|
101,787
|
Potential shares issuable pursuant to the VIP
|
2,828
|
2,751
|
2,408
|
Diluted shares outstanding
|
109,749
|
109,371
|
104,195
|
|
|
|
|
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)
|
|
September 30,
|
December 31,
|
|
Note
|
|
2014
|
|
2013
|
ASSETS
|
|
|
|
|
|
Current
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
142,520
|
|
389,559
|
Accounts receivable
|
|
|
199,574
|
|
167,618
|
Crude oil inventory
|
|
|
19,781
|
|
17,143
|
Derivative instruments
|
|
|
9,341
|
|
2,285
|
Prepaid expenses
|
|
|
15,169
|
|
11,178
|
|
|
|
386,385
|
|
587,783
|
|
|
|
|
|
|
Deferred taxes
|
|
|
148,124
|
|
184,832
|
Exploration and evaluation assets
|
5
|
|
380,266
|
|
136,259
|
Capital assets
|
4
|
|
3,522,952
|
|
2,799,845
|
|
|
|
4,437,727
|
|
3,708,719
|
|
|
|
|
|
|
LIABILITIES
|
|
|
|
|
|
Current
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
|
323,747
|
|
267,832
|
Dividends payable
|
8
|
|
22,988
|
|
20,425
|
Derivative instruments
|
|
|
1,704
|
|
3,572
|
Income taxes payable
|
|
|
82,736
|
|
55,615
|
|
|
|
431,175
|
|
347,444
|
|
|
|
|
|
|
Long-term debt
|
7
|
|
1,198,648
|
|
990,024
|
Asset retirement obligations
|
6
|
|
397,920
|
|
326,162
|
Deferred taxes
|
|
|
409,516
|
|
328,714
|
|
|
|
2,437,259
|
|
1,992,344
|
|
|
|
|
|
|
SHAREHOLDERS' EQUITY
|
|
|
|
|
|
Shareholders' capital
|
8
|
|
1,937,750
|
|
1,618,443
|
Contributed surplus
|
|
|
74,063
|
|
75,427
|
Accumulated other comprehensive income
|
|
|
13,740
|
|
47,142
|
Deficit
|
|
|
(25,085)
|
|
(24,637)
|
|
|
|
2,000,468
|
|
1,716,375
|
|
|
|
4,437,727
|
|
3,708,719
|
CONSOLIDATED STATEMENTS OF NET EARNINGS AND COMPREHENSIVE INCOME
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS,
UNAUDITED)
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
Sep 30,
|
|
Sep 30,
|
|
Sep 30,
|
|
Sep 30,
|
Note
|
2014
|
|
2013
|
|
2014
|
|
2013
|
REVENUE
|
|
|
|
|
|
|
|
|
|
Petroleum and natural gas sales
|
|
|
344,688
|
|
327,185
|
|
1,113,555
|
|
948,727
|
Royalties
|
|
|
(29,000)
|
|
(18,730)
|
|
(82,037)
|
|
(50,320)
|
Petroleum and natural gas revenue
|
|
|
315,688
|
|
308,455
|
|
1,031,518
|
|
898,407
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
56,227
|
|
46,246
|
|
172,426
|
|
146,903
|
Transportation
|
|
|
10,979
|
|
6,549
|
|
32,872
|
|
19,843
|
Equity based compensation
|
9
|
|
14,720
|
|
12,779
|
|
49,409
|
|
39,639
|
(Gain) loss on derivative instruments
|
|
|
(16,637)
|
|
8,464
|
|
(24,110)
|
|
1,943
|
Interest expense
|
|
|
12,918
|
|
10,109
|
|
36,712
|
|
28,134
|
General and administration
|
|
|
16,262
|
|
12,033
|
|
48,491
|
|
35,956
|
Foreign exchange loss (gain)
|
|
|
11,055
|
|
(3,005)
|
|
14,255
|
|
(29,166)
|
Other expense
|
|
|
362
|
|
55
|
|
217
|
|
259
|
Accretion
|
6
|
|
6,064
|
|
6,214
|
|
17,726
|
|
18,038
|
Depletion and depreciation
|
4, 5
|
|
104,159
|
|
78,826
|
|
308,513
|
|
238,692
|
|
|
|
216,109
|
|
178,270
|
|
656,511
|
|
500,241
|
EARNINGS BEFORE INCOME TAXES
|
|
|
99,579
|
|
130,185
|
|
375,007
|
|
398,166
|
|
|
|
|
|
|
|
|
|
|
INCOME TAXES
|
|
|
|
|
|
|
|
|
|
Deferred
|
|
|
14,388
|
|
287
|
|
28,859
|
|
13,914
|
Current
|
|
|
31,288
|
|
62,102
|
|
135,464
|
|
158,121
|
|
|
|
45,676
|
|
62,389
|
|
164,323
|
|
172,035
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS
|
|
|
53,903
|
|
67,796
|
|
210,684
|
|
226,131
|
|
|
|
|
|
|
|
|
|
|
OTHER COMPREHENSIVE (LOSS) INCOME
|
|
|
|
|
|
|
|
|
|
Currency translation adjustments
|
|
|
(36,143)
|
|
14,621
|
|
(33,402)
|
|
32,244
|
COMPREHENSIVE INCOME
|
|
|
17,760
|
|
82,417
|
|
177,282
|
|
258,375
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS PER SHARE
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
0.50
|
|
0.67
|
|
2.01
|
|
2.25
|
Diluted
|
|
|
0.50
|
|
0.66
|
|
1.98
|
|
2.22
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING ('000s)
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
106,768
|
|
101,613
|
|
104,891
|
|
100,634
|
Diluted
|
|
|
108,290
|
|
102,763
|
|
106,582
|
|
102,083
|
CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)
|
|
|
Three Months Ended
|
|
Nine Months Ended
|
|
|
|
Sep 30,
|
|
Sep 30,
|
|
Sep 30,
|
|
Sep 30,
|
|
Note
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
OPERATING
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
|
53,903
|
|
67,796
|
|
210,684
|
|
226,131
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
Accretion
|
6
|
|
6,064
|
|
6,214
|
|
17,726
|
|
18,038
|
|
Depletion and depreciation
|
4, 5
|
|
104,159
|
|
78,826
|
|
308,513
|
|
238,692
|
|
Unrealized (gain) loss on derivative instruments
|
|
|
(7,800)
|
|
3,699
|
|
(10,214)
|
|
(3,839)
|
|
Equity based compensation
|
9
|
|
14,720
|
|
12,779
|
|
49,409
|
|
39,639
|
|
Unrealized foreign exchange loss (gain)
|
|
|
11,867
|
|
(4,232)
|
|
13,613
|
|
(29,738)
|
|
Unrealized other expense
|
|
|
597
|
|
276
|
|
747
|
|
1,029
|
|
Deferred taxes
|
|
|
14,388
|
|
287
|
|
28,859
|
|
13,914
|
Asset retirement obligations settled
|
6
|
|
(4,677)
|
|
(2,738)
|
|
(9,709)
|
|
(6,496)
|
Changes in non-cash operating working capital
|
|
|
41,789
|
|
(4,671)
|
|
(46,788)
|
|
30,652
|
Cash flows from operating activities
|
|
|
235,010
|
|
158,236
|
|
562,840
|
|
528,022
|
|
|
|
|
|
|
|
|
|
|
INVESTING
|
|
|
|
|
|
|
|
|
|
Drilling and development
|
4
|
|
(180,479)
|
|
(135,110)
|
|
(467,294)
|
|
(389,635)
|
Exploration and evaluation
|
5
|
|
(9,554)
|
|
(551)
|
|
(54,187)
|
|
(13,240)
|
Property acquisitions
|
3, 4, 5
|
|
(40,847)
|
|
(7,586)
|
|
(219,074)
|
|
(7,586)
|
Dispositions
|
4
|
|
-
|
|
-
|
|
-
|
|
8,627
|
Corporate acquisitions, net of cash acquired
|
3
|
|
-
|
|
-
|
|
(176,179)
|
|
-
|
Changes in non-cash investing working capital
|
|
|
24,539
|
|
44,876
|
|
40,002
|
|
7,473
|
Cash flows used in investing activities
|
|
|
(206,341)
|
|
(98,371)
|
|
(876,732)
|
|
(394,361)
|
|
|
|
|
|
|
|
|
|
|
FINANCING
|
|
|
|
|
|
|
|
|
|
(Decrease) increase in long-term debt
|
|
|
(1,600)
|
|
-
|
|
204,127
|
|
139,429
|
Cash dividends
|
|
|
(48,415)
|
|
(41,576)
|
|
(142,600)
|
|
(126,354)
|
Cash flows (used in) from financing activities
|
|
|
(50,015)
|
|
(41,576)
|
|
61,527
|
|
13,075
|
Foreign exchange (loss) gain on cash held in foreign currencies
|
|
|
(1,631)
|
|
2,248
|
|
5,326
|
|
7,274
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
(22,977)
|
|
20,537
|
|
(247,039)
|
|
154,010
|
Cash and cash equivalents, beginning of period
|
|
|
165,497
|
|
235,598
|
|
389,559
|
|
102,125
|
Cash and cash equivalents, end of period
|
|
|
142,520
|
|
256,135
|
|
142,520
|
|
256,135
|
|
|
|
|
|
|
|
|
|
|
Supplementary information for operating activities - cash payments
|
|
|
|
|
|
|
|
|
|
|
Interest paid
|
|
|
15,132
|
|
13,544
|
|
40,947
|
|
34,053
|
|
Income taxes paid
|
|
|
28,617
|
|
50,203
|
|
106,177
|
|
101,507
|
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
Total
|
|
|
Shareholders'
|
Contributed
|
Comprehensive
|
|
Shareholders'
|
|
Note
|
Capital
|
Surplus
|
|
Loss
|
Deficit
|
Equity
|
Balances as at January 1, 2013
|
|
|
1,481,345
|
|
69,581
|
|
(32,409)
|
|
(99,871)
|
|
1,418,646
|
Net earnings
|
|
|
-
|
|
-
|
|
-
|
|
226,131
|
|
226,131
|
Currency translation adjustments
|
|
|
-
|
|
-
|
|
32,244
|
|
-
|
|
32,244
|
Equity based compensation expense
|
9
|
|
-
|
|
39,010
|
|
-
|
|
-
|
|
39,010
|
Dividends declared
|
8
|
|
-
|
|
-
|
|
-
|
|
(181,391)
|
|
(181,391)
|
Shares issued pursuant to the dividend reinvestment plan
|
8
|
|
53,516
|
|
-
|
|
-
|
|
-
|
|
53,516
|
Vesting of equity based awards
|
8, 9
|
|
54,370
|
|
(54,370)
|
|
-
|
|
-
|
|
-
|
Share-settled dividends on vested equity based awards
|
8, 9
|
|
9,808
|
|
-
|
|
-
|
|
(9,808)
|
|
-
|
Shares issued pursuant to the bonus plan
|
8
|
|
629
|
|
-
|
|
-
|
|
-
|
|
629
|
Balances as at September 30, 2013
|
|
|
1,599,668
|
|
54,221
|
|
(165)
|
|
(64,939)
|
|
1,588,785
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
Other
|
|
Total
|
|
Shareholders'
|
Contributed
|
Comprehensive
|
|
Shareholders'
|
Note
|
Capital
|
Surplus
|
|
Income
|
Deficit
|
Equity
|
Balances as at January 1, 2014
|
|
|
1,618,443
|
|
75,427
|
|
47,142
|
|
(24,637)
|
|
1,716,375
|
Net earnings
|
|
|
-
|
|
-
|
|
-
|
|
210,684
|
|
210,684
|
Currency translation adjustments
|
|
|
-
|
|
-
|
|
(33,402)
|
|
-
|
|
(33,402)
|
Equity based compensation expense
|
9
|
|
-
|
|
48,688
|
|
-
|
|
-
|
|
48,688
|
Dividends declared
|
8
|
|
-
|
|
-
|
|
-
|
|
(203,613)
|
|
(203,613)
|
Shares issued pursuant to the dividend reinvestment plan
|
8
|
|
58,450
|
|
-
|
|
-
|
|
-
|
|
58,450
|
Shares issued pursuant to corporate acquisition
|
3
|
|
204,960
|
|
-
|
|
-
|
|
-
|
|
204,960
|
Modification of equity based awards
|
9
|
|
-
|
|
(2,395)
|
|
|
|
|
|
(2,395)
|
Vesting of equity based awards
|
8, 9
|
|
47,657
|
|
(47,657)
|
|
-
|
|
-
|
|
-
|
Share-settled dividends on vested equity based awards
|
8, 9
|
|
7,519
|
|
-
|
|
-
|
|
(7,519)
|
|
-
|
Shares issued pursuant to the bonus plan
|
8
|
|
721
|
|
-
|
|
-
|
|
-
|
|
721
|
Balances as at September 30, 2014
|
|
|
1,937,750
|
|
74,063
|
|
13,740
|
|
(25,085)
|
|
2,000,468
|
DESCRIPTION OF EQUITY RESERVES
Shareholders' capital
Represents the recognized amount for common shares when issued, net of
equity issuance costs and deferred taxes.
Contributed surplus
Represents the recognized value of employee awards which are settled in
shares. Once vested, the value of the awards is transferred to
shareholders' capital.
Accumulated other comprehensive income
Represents the cumulative income and expenses which are not recorded
immediately in net earnings and are accumulated until an event triggers
recognition in net earnings. The current balance consists of currency
translation adjustments resulting from translating financial statements
of subsidiaries with a foreign functional currency to Canadian dollars
at period-end rates.
Deficit
Represents the cumulative net earnings less distributed earnings of
Vermilion Energy Inc.
NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2014 AND 2013
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER
SHARE AMOUNTS, UNAUDITED)
1. BASIS OF PRESENTATION
Vermilion Energy Inc. (the "Company" or "Vermilion") is a corporation
governed by the laws of the Province of Alberta and is actively engaged
in the business of crude oil and natural gas exploration, development,
acquisition and production.
These condensed consolidated interim financial statements are in
compliance with IAS 34, "Interim financial reporting" and have been
prepared using the same accounting policies and methods of computation
as Vermilion's consolidated financial statements for the year ended
December 31, 2013, except as discussed in Note 2.
These condensed consolidated interim financial statements should be read
in conjunction with Vermilion's consolidated financial statements for
the year ended December 31, 2013, which are contained within
Vermilion's Annual Report for the year ended December 31, 2013 and are
available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.
These condensed consolidated interim financial statements were approved
and authorized for issuance by the Board of Directors of Vermilion on
November 6, 2014.
2. RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
On January 1, 2014, Vermilion adopted the following pronouncements as
issued by the IASB. The adoption of these standards did not have a
material impact on Vermilion's consolidated financial statements.
IFRIC 21 "Levies"
On May 20, 2013, the IASB issued guidance under IFRIC 21, which provides
clarification on accounting for levies in accordance with the
requirements of IAS 37 "Provisions, Contingent Liabilities and
Contingent Assets". The interpretation defines a levy as an outflow
from an entity imposed by a government in accordance with legislation
and confirms that a liability for a levy is recognized only when the
triggering event specified in the legislation occurs. The
interpretation is effective for annual periods beginning on or after
January 1, 2014.
IAS 36 "Impairment of Assets"
On May 29, 2013, the IASB issued amendments to IAS 36 "Impairment of
Assets" which reduce the circumstances in which the recoverable amount
of CGUs is required to be disclosed and clarify the disclosures
required when an impairment loss has been recognized or reversed in the
period. This amendment is effective for annual periods beginning on or
after January 1, 2014.
Accounting pronouncements not yet adopted
The impact of the adoption of the following pronouncements are currently
being evaluated.
IFRS 9 "Financial Instruments"
On July 24, 2014, the IASB issued the final element of its comprehensive
response to the financial crisis by issuing IFRS 9 "Financial
Instruments". The improvements introduced by IFRS 9 includes a logical
model for classification and measurement, a single, forward-looking
'expected loss' impairment model and a substantially-reformed approach
to hedge accounting. Vermilion will adopt the standard for reporting
periods beginning January 1, 2018.
IFRS 15 "Revenue from Contracts with Customers"
On May 28, 2014, the IASB issued IFRS 15 "Revenue from Contracts with
Customers", a new standard that specifies recognition requirements for
revenue as well as requiring entities to provide the users of financial
statements with more informative and relevant disclosures. The
standard replaces IAS 11 "Construction Contracts" and IAS 18 "Revenue"
as well as a number of revenue-related interpretations. Vermilion will
adopt the standard for reporting periods beginning January 1, 2017.
3. BUSINESS COMBINATIONS
Property acquisition:
Germany
In February of 2014, Vermilion acquired, through a wholly-owned
subsidiary, GDF's 25% interest in four producing natural gas fields and
a surrounding exploration license located in northwest Germany. GDF is
an affiliate of GDF Suez S.A., a publicly traded, French multinational
utility. The acquisition represents Vermilion's entry into the German
E&P business, a producing region with a long history of oil and gas
development activity, low political risk and strong marketing
fundamentals. The acquisition is well aligned with Vermilion's European
focus, and will increase its exposure to the strong fundamentals and
pricing of the European natural gas markets. The acquisition closed in
February of 2014 for cash proceeds of $172.9 million. Vermilion funded
this acquisition with existing credit facilities.
The acquired assets comprise of four gas producing fields across eleven
production licenses and include both exploration and production
licenses that comprise a total of 207,000 gross acres, of which 85% is
in the exploration license.
The acquisition has been accounted for as a business combination with
the fair value of the assets acquired and liabilities assumed at the
date of acquisition summarized as follows:
($M)
|
Consideration
|
Cash paid to vendor
|
|
172,871
|
Total consideration
|
|
172,871
|
|
|
|
($M)
|
Allocation of Consideration
|
Petroleum and natural gas assets
|
|
158,840
|
Exploration and evaluation
|
|
16,065
|
Asset retirement obligations assumed
|
|
(2,030)
|
Deferred tax liabilities
|
|
(4)
|
Net assets acquired
|
|
172,871
|
The results of operations from the assets acquired have been included in
Vermilion's consolidated financial statements beginning February of
2014 and have contributed revenues of $22.5 million and net earnings
$2.2 million for the nine months ended September 30, 2014.
Had the acquisition occurred on January 1, 2014, management estimates
that consolidated revenues would have increased by an additional $4.6
million and consolidated net earnings would have increased by $0.9
million for the nine months ended September 30, 2014.
Corporate acquisition:
Elkhorn Resources Inc.
On April 29, 2014, Vermilion acquired Elkhorn Resources Inc., a private
southeast Saskatchewan producer. The acquisition creates a new core
area for Vermilion in the Williston Basin.
The acquired assets include approximately 57,000 net acres of land
(approximately 80% undeveloped), seven oil batteries, and preferential
access to 50% or greater capacity at a solution gas facility that is
currently under construction.
Total consideration was comprised of $180.4 million of cash, which was
funded with existing credit facilities, and the issuance of 2.8 million
Vermilion common shares valued at approximately $205.0 million (based
on the closing price per Vermilion common share of $72.50 on the
Toronto Stock Exchange on April 29, 2014).
The acquisition has been accounted for as a business combination with
the fair value of the assets acquired and liabilities assumed at the
date of acquisition summarized as follows:
($M)
|
Consideration
|
Cash paid to shareholders of Elkhorn Resources Inc.
|
|
180,353
|
Shares issued pursuant to corporate acquisition
|
|
204,960
|
Total consideration
|
|
385,313
|
|
|
|
($M)
|
Allocation of Consideration
|
Petroleum and natural gas assets
|
|
390,523
|
Exploration and evaluation
|
|
138,264
|
Asset retirement obligations assumed
|
|
(5,974)
|
Deferred tax liabilities
|
|
(89,437)
|
Long-term debt assumed
|
|
(47,526)
|
Cash acquired
|
|
4,174
|
Acquired non-cash working capital deficiency
|
|
(4,711)
|
Net assets acquired (1)
|
|
385,313
|
|
|
|
(1)
|
The above amounts are estimates made by management at the time of the
preparation of these condensed consolidated interim financial
statements based on information then available. Amendments may be made
as amounts subject to estimates are finalized.
|
The results of operations from the assets acquired have been included in
Vermilion's consolidated financial statements beginning April 29, 2014
and have contributed revenues of $34.7 million and operating income of
$27.9 million for the nine months ended September 30, 2014.
Had the acquisition occurred on January 1, 2014, management estimates
that consolidated revenues would have increased by an additional $8.8
million and consolidated operating income would have increased by $7.0
million for the nine months ended September 30, 2014. In determining
the pro-forma amounts, management has assumed that the fair value
adjustments, determined provisionally, that arose at the date of
acquisition would have been the same if the acquisition had occurred on
January 1, 2014. It is impracticable to derive all amounts necessary
to determine the increase to net earnings from the acquisition as the
acquired company was immediately merged with Vermilion's operations.
4. CAPITAL ASSETS
The following table reconciles the change in Vermilion's capital assets:
|
Petroleum and
|
Furniture and
|
|
Total
|
($M)
|
Natural Gas Assets
|
Office Equipment
|
|
Capital Assets
|
Balance at January 1, 2013
|
|
2,430,121
|
|
15,119
|
|
2,445,240
|
Additions
|
|
531,760
|
|
5,804
|
|
537,564
|
Transfers from exploration and evaluation assets
|
|
1,508
|
|
-
|
|
1,508
|
Corporate acquisitions
|
|
47,743
|
|
-
|
|
47,743
|
Dispositions
|
|
(8,627)
|
|
-
|
|
(8,627)
|
Changes in estimate for asset retirement obligations
|
|
(91,527)
|
|
-
|
|
(91,527)
|
Depletion and depreciation
|
|
(310,370)
|
|
(6,138)
|
|
(316,508)
|
Impairment recovery
|
|
47,400
|
|
-
|
|
47,400
|
Effect of movements in foreign exchange rates
|
|
136,626
|
|
426
|
|
137,052
|
Balance at December 31, 2013
|
|
2,784,634
|
|
15,211
|
|
2,799,845
|
Additions
|
|
462,136
|
|
5,158
|
|
467,294
|
Property acquisitions
|
|
163,600
|
|
-
|
|
163,600
|
Corporate acquisitions
|
|
390,523
|
|
-
|
|
390,523
|
Changes in estimate for asset retirement obligations
|
|
63,400
|
|
-
|
|
63,400
|
Depletion and depreciation
|
|
(303,634)
|
|
(2,672)
|
|
(306,306)
|
Effect of movements in foreign exchange rates
|
|
(55,281)
|
|
(123)
|
|
(55,404)
|
Balance at September 30, 2014
|
|
3,505,378
|
|
17,574
|
|
3,522,952
|
5. EXPLORATION AND EVALUATION ASSETS
The following table reconciles the change in Vermilion's exploration and
evaluation assets:
($M)
|
Exploration and Evaluation Assets
|
Balance at January 1, 2013
|
|
117,161
|
Additions
|
|
13,789
|
Property acquisitions
|
|
9,189
|
Transfers to petroleum and natural gas assets
|
|
(1,508)
|
Depreciation
|
|
(3,712)
|
Effect of movements in foreign exchange rates
|
|
1,340
|
Balance at December 31, 2013
|
|
136,259
|
Additions
|
|
54,187
|
Changes in estimate for asset retirement obligations
|
|
97
|
Property acquisitions
|
|
57,508
|
Corporate acquisitions
|
|
138,264
|
Depreciation
|
|
(4,076)
|
Effect of movements in foreign exchange rates
|
|
(1,973)
|
Balance at September 30, 2014
|
|
380,266
|
6. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the change in Vermilion's asset
retirement obligations:
($M)
|
Asset Retirement Obligations
|
Balance at January 1, 2013
|
|
|
371,063
|
Additional obligations recognized
|
|
|
15,655
|
Changes in estimates for existing obligations
|
|
|
(21,068)
|
Obligations settled
|
|
|
(11,922)
|
Accretion
|
|
|
24,565
|
Changes in discount rates
|
|
|
(73,675)
|
Effect of movements in foreign exchange rates
|
|
|
21,544
|
Balance at December 31, 2013
|
|
|
326,162
|
Additional obligations recognized
|
|
|
19,919
|
Obligations settled
|
|
|
(9,709)
|
Accretion
|
|
|
17,726
|
Changes in discount rates
|
|
|
51,582
|
Effect of movements in foreign exchange rates
|
|
|
(7,760)
|
Balance at September 30, 2014
|
|
|
397,920
|
7. LONG-TERM DEBT
The following table summarizes Vermilion's outstanding long-term debt:
|
As At
|
($M)
|
Sept 30, 2014
|
Dec 31, 2013
|
Revolving credit facility
|
|
974,857
|
|
766,898
|
Senior unsecured notes
|
|
223,791
|
|
223,126
|
Long-term debt
|
|
1,198,648
|
|
990,024
|
Revolving Credit Facility
At September 30, 2014, Vermilion had in place a bank revolving credit
facility totalling $1.5 billion, of which approximately $974.9 million
was drawn. In addition, Vermilion may, by adding lenders or seeking an
increase to an existing lender's commitment, increase the total
committed facility amount to no more than $1.75 billion. The facility,
which matures on May 31, 2017, is fully revolving up to the date of
maturity.
The facility is extendable from time to time, but not more than once per
year, for a period not longer than three years, at the option of the
lenders and upon notice from Vermilion. If no extension is granted by
the lenders, the amounts owing pursuant to the facility are repayable
on the maturity date. This facility bears interest at a rate
applicable to demand loans plus applicable margins. For the nine
months ended September 30, 2014, the interest rate on the revolving
credit facility was approximately 3.2%.
The amount available to Vermilion under this facility is reduced by
certain outstanding letters of credit associated with Vermilion's
operations totalling $10.3 million as at September 30, 2014 (December
31, 2013 - $8.1 million).
The facility is secured by various fixed and floating charges against
the subsidiaries of Vermilion. Under the terms of the facility,
Vermilion must maintain:
-
A ratio of total bank borrowings (defined as consolidated total debt),
to consolidated net earnings before interest, income taxes,
depreciation, accretion and other certain non-cash items (defined as
consolidated EBITDA) of not greater than 4.0.
-
A ratio of consolidated total senior debt (defined as consolidated total
debt excluding unsecured and subordinated debt) to consolidated EBITDA
of not greater than 3.0.
-
A ratio of consolidated total senior debt to total capitalization
(defined as amounts classified as "Long-term debt" and "Shareholders'
Equity" on the balance sheet) of less than 50%.
As at September 30, 2014, Vermilion was in compliance with all financial
covenants.
Senior Unsecured Notes
On February 10, 2011, Vermilion issued $225.0 million of senior
unsecured notes at par. The notes bear interest at a rate of 6.5% per
annum and will mature on February 10, 2016. As direct senior unsecured
obligations of Vermilion, the notes rank pari passu with all other
present and future unsecured and unsubordinated indebtedness of the
Company.
Prior to February 10, 2015, Vermilion may redeem all or part of the
senior unsecured notes at 103.25% of their principal amount plus any
accrued and unpaid interest. Subsequent to February 10, 2015,
Vermilion may redeem all or part of the senior unsecured notes at 100%
of their principal amount plus any accrued and unpaid interest. The
notes were initially recognized at fair value net of transaction costs
and are subsequently measured at amortized cost using an effective
interest rate of 7.1%.
8. SHAREHOLDERS' CAPITAL
The following table reconciles the change in Vermilion's shareholders'
capital:
Shareholders' Capital
|
Number of Shares ('000s)
|
|
Amount ($M)
|
Balance as at January 1, 2013
|
|
99,135
|
|
1,481,345
|
Shares issued pursuant to the dividend reinvestment plan
|
|
1,402
|
|
72,291
|
Vesting of equity based awards
|
|
1,372
|
|
54,370
|
Share-settled dividends on vested equity based awards
|
|
202
|
|
9,808
|
Shares issued pursuant to the bonus plan
|
|
12
|
|
629
|
Balance as at December 31, 2013
|
|
102,123
|
|
1,618,443
|
Shares issued pursuant to corporate acquisition
|
|
2,827
|
|
204,960
|
Shares issued pursuant to the dividend reinvestment plan
|
|
902
|
|
58,450
|
Vesting of equity based awards
|
|
950
|
|
47,657
|
Share-settled dividends on vested equity based awards
|
|
108
|
|
7,519
|
Shares issued pursuant to the bonus plan
|
|
11
|
|
721
|
Balance as at September 30, 2014
|
|
106,921
|
|
1,937,750
|
Dividends declared to shareholders for the nine months ended September
30, 2014 were $203.6 million (2013 - $181.4 million).
Subsequent to the end of the period and prior to the condensed
consolidated interim financial statements being authorized for issue on
November 6, 2014, Vermilion declared dividends totalling $23.0 million
or $0.215 per share.
9. EQUITY BASED COMPENSATION
The following table summarizes the number of awards outstanding under
the Vermilion Incentive Plan ("VIP"):
Number of Awards ('000s)
|
2014
|
|
2013
|
Opening balance
|
1,665
|
|
1,690
|
Granted
|
616
|
|
832
|
Vested
|
(512)
|
|
(749)
|
Modified
|
(21)
|
|
-
|
Forfeited
|
(53)
|
|
(108)
|
Closing balance
|
1,695
|
|
1,665
|
The fair value of a VIP award is determined on the grant date at the
closing price of Vermilion's common shares on the Toronto Stock
Exchange, adjusted by the estimated performance factor that will
ultimately be achieved.
On March 31, 2014, Vermilion modified the accounting for certain
outstanding VIP awards to be settled by purchasing Vermilion common
shares on the Toronto Stock Exchange upon vesting rather than by
issuing common shares through treasury. Pursuant to this modification,
$2.4 million was reclassified from "Contributed surplus" to "Accounts
payable and accrued liabilities". Subsequent period expense relating
to these outstanding awards will be recognized in "General and
administration expense".
10. SEGMENTED INFORMATION
Vermilion has operations principally in Canada, France, the Netherlands,
Germany, Ireland, and Australia. Vermilion's operating activities in
each country relate solely to the exploration, development and
production of petroleum and natural gas. Vermilion has a Corporate
head office located in Calgary, Alberta. Costs incurred in the
Corporate segment relate to Vermilion's global hedging program and
expenses incurred in financing and managing our operating business
units.
Vermilion's chief operating decision maker reviews the financial
performance of the Company by assessing the fund flows from operations
of each country individually. Fund flows from operations provides a
measure of each business unit's ability to generate cash (that is not
subject to short-term movements in non-cash operating working capital)
necessary to pay dividends, fund asset retirement obligations, and make
capital investments.
|
Three Months Ended September 30, 2014
|
($M)
|
Canada
|
|
France
|
|
Netherlands
|
|
Germany
|
|
Ireland
|
|
Australia
|
|
Corporate
|
|
Total
|
Drilling and development
|
88,116
|
|
34,883
|
|
10,087
|
|
1,358
|
|
30,050
|
|
15,985
|
|
-
|
|
180,479
|
Exploration and evaluation
|
9,277
|
|
199
|
|
-
|
|
-
|
|
-
|
|
-
|
|
78
|
|
9,554
|
Oil and gas sales to external customers
|
138,853
|
|
106,576
|
|
26,960
|
|
8,591
|
|
-
|
|
63,708
|
|
-
|
|
344,688
|
Royalties
|
(19,034)
|
|
(6,978)
|
|
(942)
|
|
(2,046)
|
|
-
|
|
-
|
|
-
|
|
(29,000)
|
Revenue from external customers
|
119,819
|
|
99,598
|
|
26,018
|
|
6,545
|
|
-
|
|
63,708
|
|
-
|
|
315,688
|
Transportation expense
|
(4,048)
|
|
(4,741)
|
|
-
|
|
(675)
|
|
(1,515)
|
|
-
|
|
-
|
|
(10,979)
|
Operating expense
|
(19,074)
|
|
(15,215)
|
|
(5,409)
|
|
(2,227)
|
|
-
|
|
(14,302)
|
|
-
|
|
(56,227)
|
General and administration
|
(4,523)
|
|
(6,411)
|
|
(204)
|
|
(1,090)
|
|
(334)
|
|
(1,378)
|
|
(2,322)
|
|
(16,262)
|
PRRT
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(13,834)
|
|
-
|
|
(13,834)
|
Corporate income taxes
|
-
|
|
(10,744)
|
|
(1,189)
|
|
(146)
|
|
-
|
|
(5,148)
|
|
(227)
|
|
(17,454)
|
Interest expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(12,918)
|
|
(12,918)
|
Realized gain on derivative instruments
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
8,837
|
|
8,837
|
Realized foreign exchange gain
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
812
|
|
812
|
Realized other income
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
235
|
|
235
|
Fund flows from operations
|
92,174
|
|
62,487
|
|
19,216
|
|
2,407
|
|
(1,849)
|
|
29,046
|
|
(5,583)
|
|
197,898
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2013
|
($M)
|
Canada
|
|
France
|
|
Netherlands
|
|
Germany
|
|
Ireland
|
|
Australia
|
|
Corporate
|
|
Total
|
Drilling and development
|
61,719
|
|
23,664
|
|
8,316
|
|
-
|
|
35,028
|
|
5,880
|
|
503
|
|
135,110
|
Exploration and evaluation
|
551
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
551
|
Oil and gas sales to external customers
|
100,000
|
|
120,574
|
|
27,382
|
|
-
|
|
-
|
|
79,229
|
|
-
|
|
327,185
|
Royalties
|
(11,156)
|
|
(7,574)
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(18,730)
|
Revenue from external customers
|
88,844
|
|
113,000
|
|
27,382
|
|
-
|
|
-
|
|
79,229
|
|
-
|
|
308,455
|
Transportation expense
|
(3,272)
|
|
(2,713)
|
|
-
|
|
-
|
|
(564)
|
|
-
|
|
-
|
|
(6,549)
|
Operating expense
|
(12,770)
|
|
(14,599)
|
|
(5,209)
|
|
-
|
|
-
|
|
(13,668)
|
|
-
|
|
(46,246)
|
General and administration
|
(3,484)
|
|
(4,964)
|
|
(333)
|
|
-
|
|
(312)
|
|
(1,414)
|
|
(1,526)
|
|
(12,033)
|
PRRT
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(15,649)
|
|
-
|
|
(15,649)
|
Corporate income taxes
|
-
|
|
(31,717)
|
|
(6,810)
|
|
-
|
|
-
|
|
(7,666)
|
|
(260)
|
|
(46,453)
|
Interest expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(10,109)
|
|
(10,109)
|
Realized loss on derivative instruments
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(4,765)
|
|
(4,765)
|
Realized foreign exchange loss
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(1,227)
|
|
(1,227)
|
Realized other income
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
221
|
|
221
|
Fund flows from operations
|
69,318
|
|
59,007
|
|
15,030
|
|
-
|
|
(876)
|
|
40,832
|
|
(17,666)
|
|
165,645
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2014
|
($M)
|
Canada
|
|
France
|
|
Netherlands
|
|
Germany
|
|
Ireland
|
|
Australia
|
|
Corporate
|
|
Total
|
Total assets
|
1,857,012
|
|
894,060
|
|
237,070
|
|
164,025
|
|
809,296
|
|
269,959
|
|
206,305
|
|
4,437,727
|
Drilling and development
|
215,860
|
|
99,564
|
|
43,512
|
|
2,184
|
|
73,507
|
|
32,667
|
|
-
|
|
467,294
|
Exploration and evaluation
|
33,440
|
|
11,099
|
|
8,206
|
|
-
|
|
-
|
|
-
|
|
1,442
|
|
54,187
|
Oil and gas sales to external customers
|
425,294
|
|
348,753
|
|
98,395
|
|
28,603
|
|
-
|
|
212,510
|
|
-
|
|
1,113,555
|
Royalties
|
(49,937)
|
|
(22,125)
|
|
(3,843)
|
|
(6,132)
|
|
-
|
|
-
|
|
-
|
|
(82,037)
|
Revenue from external customers
|
375,357
|
|
326,628
|
|
94,552
|
|
22,471
|
|
-
|
|
212,510
|
|
-
|
|
1,031,518
|
Transportation expense
|
(11,170)
|
|
(14,879)
|
|
-
|
|
(2,149)
|
|
(4,674)
|
|
-
|
|
-
|
|
(32,872)
|
Operating expense
|
(56,863)
|
|
(48,185)
|
|
(17,841)
|
|
(5,824)
|
|
-
|
|
(43,713)
|
|
-
|
|
(172,426)
|
General and administration
|
(13,951)
|
|
(17,164)
|
|
(1,128)
|
|
(2,488)
|
|
(868)
|
|
(4,245)
|
|
(8,647)
|
|
(48,491)
|
PRRT
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(46,772)
|
|
-
|
|
(46,772)
|
Corporate income taxes
|
-
|
|
(60,769)
|
|
(6,278)
|
|
(1,189)
|
|
-
|
|
(19,678)
|
|
(778)
|
|
(88,692)
|
Interest expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(36,712)
|
|
(36,712)
|
Realized gain on derivative instruments
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
13,896
|
|
13,896
|
Realized foreign exchange loss
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(642)
|
|
(642)
|
Realized other income
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
530
|
|
530
|
Fund flows from operations
|
293,373
|
|
185,631
|
|
69,305
|
|
10,821
|
|
(5,542)
|
|
98,102
|
|
(32,353)
|
|
619,337
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2013
|
($M)
|
Canada
|
|
France
|
|
Netherlands
|
|
Germany
|
|
Ireland
|
|
Australia
|
|
Corporate
|
|
Total
|
Total assets
|
1,141,499
|
|
930,568
|
|
144,813
|
|
-
|
|
697,120
|
|
301,350
|
|
209,075
|
|
3,424,425
|
Drilling and development
|
158,519
|
|
68,479
|
|
14,472
|
|
-
|
|
76,426
|
|
69,511
|
|
2,228
|
|
389,635
|
Exploration and evaluation
|
12,433
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
807
|
|
13,240
|
Oil and gas sales to external customers
|
284,638
|
|
342,558
|
|
100,119
|
|
-
|
|
-
|
|
221,412
|
|
-
|
|
948,727
|
Royalties
|
(29,852)
|
|
(20,468)
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(50,320)
|
Revenue from external customers
|
254,786
|
|
322,090
|
|
100,119
|
|
-
|
|
-
|
|
221,412
|
|
-
|
|
898,407
|
Transportation expense
|
(8,152)
|
|
(7,883)
|
|
-
|
|
-
|
|
(3,808)
|
|
-
|
|
-
|
|
(19,843)
|
Operating expense
|
(42,586)
|
|
(51,473)
|
|
(14,438)
|
|
-
|
|
-
|
|
(38,406)
|
|
-
|
|
(146,903)
|
General and administration
|
(10,501)
|
|
(14,577)
|
|
(1,171)
|
|
-
|
|
(959)
|
|
(4,310)
|
|
(4,438)
|
|
(35,956)
|
PRRT
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(39,392)
|
|
-
|
|
(39,392)
|
Corporate income taxes
|
-
|
|
(66,500)
|
|
(25,865)
|
|
-
|
|
-
|
|
(25,525)
|
|
(839)
|
|
(118,729)
|
Interest expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(28,134)
|
|
(28,134)
|
Realized loss on derivative instruments
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(5,782)
|
|
(5,782)
|
Realized foreign exchange loss
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(572)
|
|
(572)
|
Realized other income
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
770
|
|
770
|
Fund flows from operations
|
193,547
|
|
181,657
|
|
58,645
|
|
-
|
|
(4,767)
|
|
113,779
|
|
(38,995)
|
|
503,866
|
Reconciliation of fund flows from operations to net earnings
|
Three Months Ended
|
|
Nine Months Ended
|
|
Sep 30,
|
Sep 30,
|
|
Sep 30,
|
Sep 30,
|
($M)
|
2014
|
2013
|
|
2014
|
2013
|
Fund flows from operations
|
197,898
|
165,645
|
|
619,337
|
503,866
|
Equity based compensation
|
(14,720)
|
(12,779)
|
|
(49,409)
|
(39,639)
|
Unrealized gain (loss) on derivative instruments
|
7,800
|
(3,699)
|
|
10,214
|
3,839
|
Unrealized foreign exchange (loss) gain
|
(11,867)
|
4,232
|
|
(13,613)
|
29,738
|
Unrealized other expense
|
(597)
|
(276)
|
|
(747)
|
(1,029)
|
Accretion
|
(6,064)
|
(6,214)
|
|
(17,726)
|
(18,038)
|
Depletion and depreciation
|
(104,159)
|
(78,826)
|
|
(308,513)
|
(238,692)
|
Deferred taxes
|
(14,388)
|
(287)
|
|
(28,859)
|
(13,914)
|
Net earnings
|
53,903
|
67,796
|
|
210,684
|
226,131
|
11. CAPITAL DISCLOSURES
|
Three Months Ended
|
|
Nine Months Ended
|
($M except as indicated)
|
September 30,
2014
|
September 30,
2013
|
|
September 30,
2014
|
September 30,
2013
|
Long-term debt
|
1,198,648
|
781,074
|
|
1,198,648
|
781,074
|
Current liabilities
|
431,175
|
389,757
|
|
431,175
|
389,757
|
Current assets
|
(386,385)
|
(470,545)
|
|
(386,385)
|
(470,545)
|
Net debt [1]
|
1,243,438
|
700,286
|
|
1,243,438
|
700,286
|
|
|
|
|
|
|
Cash flows from operating activities
|
235,010
|
158,236
|
|
562,840
|
528,022
|
Changes in non-cash operating working capital
|
(41,789)
|
4,671
|
|
46,788
|
(30,652)
|
Asset retirement obligations settled
|
4,677
|
2,738
|
|
9,709
|
6,496
|
Fund flows from operations
|
197,898
|
165,645
|
|
619,337
|
503,866
|
Annualized fund flows from operations [2]
|
791,592
|
662,580
|
|
825,783
|
671,821
|
|
|
|
|
|
|
Ratio of net debt to annualized fund flows from operations ([1] ÷ [2])
|
1.6
|
1.1
|
|
1.5
|
1.0
|
Long-term debt as at September 30, 2014 increased to $1.2 billion from
$990.0 million as at December 31, 2013 as a result of draws on the
revolving credit facility during the current year to fund the
acquisitions in Germany and Saskatchewan coupled with the assumption of
$47.5 million of long-term debt pursuant to the latter acquisition.
This increase in long-term debt resulted in an increase to net debt
from $749.7 million to $1.2 billion.
As year-to-date fund flows does not include a full year of fund flows
from the acquisitions in Germany and Saskatchewan, the ratio of net
debt to annualized fund flows increased to 1.5.
12. FINANCIAL INSTRUMENTS
Classification of Financial Instruments
The following table summarizes information relating to Vermilion's
financial instruments as at September 30, 2014 and December 31, 2013:
|
|
|
|
|
|
|
As at Sep 30, 2014
|
|
|
As at Dec 31, 2013
|
|
|
|
Class of financial
instrument
|
Consolidated balance
sheet caption
|
Accounting
designation
|
Related caption on Statement of Net
Earnings
|
|
|
Carrying
value ($M)
|
Fair value
($M)
|
|
|
Carrying
value ($M)
|
|
Fair value
($M)
|
|
|
Fair value
measurement
hierarchy
|
Cash
|
Cash and cash equivalents
|
HFT
|
Gains and losses on foreign exchange are included in foreign exchange
loss (gain)
|
|
|
142,520
|
|
142,520
|
|
|
389,559
|
|
389,559
|
|
|
Level 1
|
Receivables
|
Accounts receivable
|
LAR
|
Gains and losses on foreign exchange are included in foreign exchange
loss (gain) and impairments are recognized as general and
administration expense
|
|
|
199,574
|
|
199,574
|
|
|
167,618
|
|
167,618
|
|
|
Not applicable
|
Derivative assets
|
Derivative instruments
|
HFT
|
(Gain) loss on derivative instruments
|
|
|
9,341
|
|
9,341
|
|
|
2,285
|
|
2,285
|
|
|
Level 2
|
Derivative liabilities
|
Derivative instruments
|
HFT
|
(Gain) loss on derivative instruments
|
|
|
(1,704)
|
|
(1,704)
|
|
|
(3,572)
|
|
(3,572)
|
|
|
Level 2
|
Payables
|
Accounts payable and accrued liabilities
|
OTH
|
Gains and losses on foreign exchange are included in foreign exchange
loss (gain)
|
|
|
(346,735)
|
|
(346,735)
|
|
|
(288,257)
|
|
(288,257)
|
|
|
Not applicable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends payable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
Long-term debt
|
OTH
|
Interest expense
|
|
|
(1,198,648)
|
|
(1,199,295)
|
|
|
(990,024)
|
|
(998,648)
|
|
|
Level 2
|
The accounting designations used in the above table refer to the
following:
HFT - Classified as "Held for trading" in accordance with International
Accounting Standard 39 "Financial Instruments: Recognition and
Measurement". These financial assets and liabilities are carried at
fair value on the consolidated balance sheets with associated gains and
losses reflected in net earnings.
LAR - "Loans and receivables" are initially recognized at fair value and
are subsequently measured at amortized cost. Impairments and foreign
exchange gains and losses are recognized in net earnings.
OTH - "Other financial liabilities" are initially recognized at fair
value net of transaction costs directly attributable to the issuance of
the instrument and subsequently are measured at amortized cost.
Interest is recognized in net earnings using the effective interest
method. Foreign exchange gains and losses are recognized in net
earnings.
Level 1 - Fair value measurement is determined by reference to
unadjusted quoted prices in active markets for identical assets or
liabilities.
Level 2 - Fair value measurement is determined based on inputs other
than unadjusted quoted prices that are observable, either directly or
indirectly.
Level 3 - Fair value measurement is based on inputs for the asset or
liability that are not based on observable market data.
Determination of Fair Values
The level in the fair value hierarchy into which the fair value
measurements are categorized is determined on the basis of the lowest
level input that is significant to the fair value measurement.
Transfers between levels on the fair value hierarchy are deemed to have
occurred at the end of the reporting period.
Fair values for derivative assets and derivative liabilities are
determined using pricing models incorporating future prices that are
based on assumptions which are supported by prices from observable
market transactions and are adjusted for credit risk.
The carrying value of receivables approximate their fair value due to
their short maturities.
The carrying value of long-term debt outstanding on the revolving credit
facility approximates its fair value due to the use of short-term
borrowing instruments at market rates of interest.
The fair value of the senior unsecured notes changes in response to
changes in the market rates of interest payable on similar instruments
and was determined with reference to prevailing market rates for such
instruments.
Nature and Extent of Risks Arising from Financial Instruments
Market risk:
Vermilion's financial instruments are exposed to currency risk related
to changes in foreign currency denominated financial instruments and
commodity price risk related to outstanding derivative positions. The
following table summarizes what the impact on comprehensive income
before tax would be for the nine months ended September 30, 2014 given
changes in the relevant risk variables that Vermilion considers were
reasonably possible at the balance sheet date. The impact on
comprehensive income before tax associated with changes in these risk
variables for assets and liabilities that are not considered financial
instruments are excluded from this analysis. This analysis does not
attempt to reflect any interdependencies between the relevant risk
variables.
|
Before tax effect on comprehensive
|
|
income - increase (decrease)
|
Risk ($M)
|
Description of change in risk variable
|
September 30, 2014
|
Currency risk - Euro to Canadian
|
Increase in strength of the Canadian dollar against the Euro by 5% over the
relevant closing rates
|
(4,565)
|
|
|
|
|
Decrease in strength of the Canadian dollar against the Euro by 5% over the
relevant closing rates
|
4,565
|
|
|
|
Currency risk - US $ to Canadian
|
Increase in strength of the Canadian dollar against the US $ by 5% over the
relevant closing rates
|
(4,029)
|
|
|
|
|
Decrease in strength of the Canadian dollar against the US $ by 5% over the
relevant closing rates
|
4,029
|
|
|
|
Commodity price risk
|
Increase in relevant oil reference price within option pricing models used to
determine
|
(5,015)
|
|
the fair value of financial derivatives by US $5.00/bbl at the relevant
valuation dates
|
|
|
|
|
|
Decrease in relevant oil reference price within option pricing models used to
determine
|
4,686
|
|
the fair value of financial derivatives by US $5.00/bbl at the relevant
valuation dates
|
|
|
|
|
Interest rate risk
|
Increase in average Canadian prime interest rate by 100 basis points during the
relevant periods
|
(6,519)
|
|
|
|
|
Decrease in average Canadian prime interest rate by 100 basis points during the
relevant periods
|
6,519
|
SOURCE Vermilion Energy Inc.