CALGARY, July 31, 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 six months
ended June 30, 2014.
HIGHLIGHTS
-
Achieved average production of 52,089 boe/d during the second quarter of
2014, an increase of 12% as compared to 46,677 boe/d in the prior
quarter and an increase of 22% compared to 42,813 boe/d in the second
quarter of 2013. Increased production was largely attributable to a
27% increase in Canadian production versus the prior quarter, led by
robust performance in both our Mannville condensate-rich natural gas
and Cardium light-oil development programs, which achieved production
increases of 50% and 17% respectively. Canadian volumes also increased
due to approximately two months of production contribution from our
S.E. Saskatchewan acquisition, which we closed at the end of April
2014. European volumes benefitted from a full quarter of contribution
from our German acquisition, which we closed in February 2014.
-
Based on the continued strength of our operations during the second
quarter of 2014, we are increasing our full-year 2014 production
guidance from the current range of 48,000-49,000 boe/d to 48,500-49,500
boe/d.
-
Generated fund flows from operations(1) in the second quarter of 2014 of $216.1 million ($2.05/basic share), as
compared to $205.4 million ($2.01/basic share) in the prior quarter and
$174.6 million ($1.73/basic share) in the second quarter of 2013. The
increase was primarily attributable to improved oil pricing and
significantly higher volumes in Canada.
-
On April 29, 2014, we announced completion of our acquisition of Elkhorn
Resources Inc., a private S.E. Saskatchewan producer, for total
consideration of approximately $427 million. The assets consist of
high netback, light oil producing assets 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.
-
On May 22, 2014, we announced the completion of tunnel boring operations
beneath Sruwaddacon Bay at our Corrib project in Ireland. The tunnel
boring machine has been demobilized from the tunnel, and the remaining
tunnel outfitting, gas plant preparation and offshore well work
activities are progressing. 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 celebrating our 20th Anniversary as a publicly traded company in 2014. This has been a
rewarding period of growth and achievement for Vermilion, 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 June 30, 2014, of 36.8% per annum since our
inception. Looking forward, with the consistent strength of our
operations, our extensive opportunity base, and anticipated growth of
our fund flows from operations in the current commodity environment, 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.
|
Vermilion Energy Inc. Second Quarter 2014 Conference Call and Audio
Webcast Details
Vermilion will discuss these results in a conference call to be held on
Thursday, July 31, 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 65722904. The replay will be available until midnight eastern
time on August 7, 2014.
You may also listen to the audio webcast by clicking http://event.on24.com/r.htm?e=813553&s=1&k=D1BE33AF46B4AC5B296C96983A231587 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
|
|
$MM
|
|
million dollars
|
|
AECO
|
|
the daily average benchmark price for natural gas at the AECO 'C' hub in
southeast Alberta
|
|
bbl(s)
|
|
barrel(s)
|
|
bbls/d
|
|
barrels per day
|
|
bcf
|
|
billion cubic feet
|
|
boe
|
|
barrel of oil equivalent, including: crude oil, natural gas liquids and
natural gas (converted on the basis of one boe for six mcf of natural
gas)
|
|
boe/d
|
|
barrel of oil equivalent per day
|
|
GJ
|
|
gigajoules
|
|
mbbls
|
|
thousand barrels
|
|
mboe
|
|
thousand barrel of oil equivalent
|
|
mcf
|
|
thousand cubic feet
|
|
mcf/d
|
|
thousand cubic feet per day
|
|
mmboe
|
|
million barrel of oil equivalent
|
|
mmcf
|
|
million cubic feet
|
|
mmcf/d
|
|
million cubic feet per day
|
|
MWh
|
|
megawatt hour
|
|
NGLs
|
|
natural gas liquids
|
|
PRRT
|
|
Petroleum Resource Rent Tax, a profit based tax levied on petroleum
projects in Australia
|
|
TTF
|
|
the day-ahead price for natural gas in the Netherlands, quoted in MWh of
natural gas, at the Title Transfer Facility Virtual Trading Point
operated by Dutch TSO Gas Transport Services
|
|
WTI
|
|
West Texas Intermediate, the reference price paid for crude oil of
standard grade in US dollars at Cushing, Oklahoma
|
HIGHLIGHTS
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
($M except as indicated)
|
|
|
Jun 30,
|
|
Mar 31,
|
|
Jun 30,
|
|
Jun 30,
|
|
Jun 30,
|
|
Financial
|
|
|
2014
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
Petroleum and natural gas sales
|
|
|
387,684
|
|
381,183
|
|
311,966
|
|
768,867
|
|
621,542
|
|
Fund flows from operations (1)
|
|
|
216,076
|
|
205,363
|
|
174,592
|
|
421,439
|
|
338,221
|
|
|
Fund flows from operations ($/basic share)
|
|
|
2.05
|
|
2.01
|
|
1.73
|
|
4.05
|
|
3.38
|
|
|
Fund flows from operations ($/diluted share)
|
|
|
2.01
|
|
1.97
|
|
1.71
|
|
3.99
|
|
3.33
|
|
Net earnings
|
|
|
53,993
|
|
102,788
|
|
106,198
|
|
156,781
|
|
158,335
|
|
|
Net earnings ($/basic share)
|
|
|
0.51
|
|
1.00
|
|
1.05
|
|
1.51
|
|
1.58
|
|
Capital expenditures
|
|
|
135,073
|
|
196,375
|
|
78,118
|
|
331,448
|
|
258,587
|
|
Acquisitions
|
|
|
381,139
|
|
178,227
|
|
-
|
|
559,366
|
|
-
|
|
Asset retirement obligations settled
|
|
|
2,381
|
|
2,651
|
|
2,370
|
|
5,032
|
|
3,758
|
|
Cash dividends ($/share)
|
|
|
0.645
|
|
0.645
|
|
0.600
|
|
1.290
|
|
1.200
|
|
Dividends declared
|
|
|
68,710
|
|
66,007
|
|
60,776
|
|
134,717
|
|
120,388
|
|
|
% of fund flows from operations
|
|
|
32%
|
|
32%
|
|
35%
|
|
32%
|
|
36%
|
|
Net dividends (1)
|
|
|
49,561
|
|
47,122
|
|
42,146
|
|
96,683
|
|
86,226
|
|
|
% of fund flows from operations
|
|
|
23%
|
|
23%
|
|
24%
|
|
23%
|
|
25%
|
|
Payout (1)
|
|
|
187,015
|
|
246,148
|
|
122,634
|
|
433,163
|
|
348,571
|
|
|
% of fund flows from operations
|
|
|
87%
|
|
120%
|
|
70%
|
|
103%
|
|
103%
|
|
|
% of fund flows from operations (excluding the Corrib project)
|
|
|
73%
|
|
111%
|
|
55%
|
|
92%
|
|
90%
|
|
Net debt (1)
|
|
|
1,168,998
|
|
966,310
|
|
674,368
|
|
1,168,998
|
|
674,368
|
|
Ratio of net debt to annualized fund flows from operations (1)
|
|
|
1.4
|
|
1.2
|
|
1.0
|
|
1.4
|
|
1.0
|
|
Operational
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
30,184
|
|
27,318
|
|
26,638
|
|
28,759
|
|
25,119
|
|
|
NGLs (bbls/d)
|
|
|
2,892
|
|
2,140
|
|
1,775
|
|
2,518
|
|
1,604
|
|
|
Natural gas (mmcf/d)
|
|
|
114.08
|
|
103.32
|
|
86.40
|
|
108.73
|
|
84.29
|
|
|
Total (boe/d)
|
|
|
52,089
|
|
46,677
|
|
42,813
|
|
49,398
|
|
40,772
|
|
Average realized prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and NGLs ($/bbl)
|
|
|
109.89
|
|
111.62
|
|
98.95
|
|
110.73
|
|
101.42
|
|
|
Natural gas ($/mcf)
|
|
|
6.19
|
|
7.99
|
|
7.22
|
|
7.04
|
|
7.00
|
|
Production mix (% of production)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% priced with reference to WTI
|
|
|
30%
|
|
25%
|
|
25%
|
|
27%
|
|
24%
|
|
|
% priced with reference to AECO
|
|
|
18%
|
|
17%
|
|
17%
|
|
18%
|
|
18%
|
|
|
% priced with reference to TTF
|
|
|
18%
|
|
19%
|
|
17%
|
|
19%
|
|
17%
|
|
|
% priced with reference to Dated Brent
|
|
|
34%
|
|
39%
|
|
41%
|
|
36%
|
|
41%
|
|
Netbacks ($/boe) (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating netback
|
|
|
59.52
|
|
63.20
|
|
59.30
|
|
61.29
|
|
59.24
|
|
|
Fund flows from operations netback
|
|
|
46.24
|
|
47.76
|
|
44.90
|
|
46.98
|
|
44.40
|
|
|
Operating expenses
|
|
|
12.46
|
|
13.49
|
|
12.36
|
|
12.95
|
|
13.21
|
|
Average reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl)
|
|
|
102.99
|
|
98.68
|
|
94.22
|
|
100.84
|
|
94.30
|
|
|
Edmonton Sweet index (US $/bbl)
|
|
|
96.85
|
|
90.43
|
|
90.56
|
|
93.65
|
|
88.99
|
|
|
Dated Brent (US $/bbl)
|
|
|
109.63
|
|
108.22
|
|
102.44
|
|
108.93
|
|
107.50
|
|
|
AECO ($/GJ)
|
|
|
4.44
|
|
5.42
|
|
3.35
|
|
4.93
|
|
3.19
|
|
|
TTF ($/GJ)
|
|
|
7.91
|
|
10.19
|
|
10.14
|
|
9.02
|
|
10.23
|
|
Average foreign currency exchange rates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CDN $/US $
|
|
|
1.09
|
|
1.10
|
|
1.02
|
|
1.10
|
|
1.02
|
|
|
CDN $/Euro
|
|
|
1.50
|
|
1.51
|
|
1.34
|
|
1.50
|
|
1.33
|
|
Share information ('000s)
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares outstanding - basic
|
|
|
106,620
|
|
102,453
|
|
101,418
|
|
106,620
|
|
101,418
|
|
Shares outstanding - diluted (1)
|
|
|
109,371
|
|
105,167
|
|
103,735
|
|
109,371
|
|
103,735
|
|
Weighted average shares outstanding - basic
|
|
|
105,577
|
|
102,278
|
|
100,964
|
|
103,936
|
|
100,137
|
|
Weighted average shares outstanding - diluted (1)
|
|
|
107,330
|
|
104,171
|
|
102,223
|
|
105,531
|
|
101,578
|
|
(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 are celebrating Vermilion's 20th anniversary as a publicly traded company. It has been a demanding, but
also 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. During this time, we have remained committed to
stewarding our Company in the best interests of our shareholders. We
are pleased that our efforts have been both recognized and supported by
our shareholders, resulting in a compound average total return
including dividends, as of June 30, 2014, of 36.8% 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.
Perhaps more important to both our current and prospective shareholders,
it is our belief that Vermilion is better situated for continued growth
than at any other time in our history. With the anticipated growth of
fund flows from operations(1), the consistent strength 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 continuing to provide a reliable and growing dividend
stream to our shareholders.
While we are confident that the assets in our current portfolio contain
significant opportunity for growth for years to come, we also find
ourselves uniquely positioned to advantageously grow and further
diversify our opportunity base through potential acquisition activity
in both North American and international markets. 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(1) growth on the horizon (including from Corrib, which is slated to come
on production in mid-2015), we are uniquely 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 second quarter of 2014 marks another quarter of high activity and
effective operational execution for our Company. We achieved
significant quarter-over-quarter production growth largely attributable
to strong results from our successful Mannville condensate-rich gas and
Cardium light-oil development programs in Canada. Production volumes
from our Mannville development program averaged more than 4,600 boe/d,
an increase of 50% during the second quarter, while Cardium production
averaged more than 12,000 boe/d, an increase of 17% from the prior
quarter. Operating netbacks(1) for our Cardium production averaged more than $70/boe in the second
quarter. 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
and approximately five fewer Cardium wells than originally anticipated
to meet our objectives for our 2014 Cardium program. As a result, we
are diverting a portion of our previously planned Cardium expenditures
to our Mannville development program which also generates very robust
economics. With the incremental capital, we now plan to drill
approximately 15 (9 net) Mannville wells in 2014, up from eight (5.7
net) wells in our original budget. Looking forward, we anticipate our
Mannville drilling activity will continue to increase in future years
as we develop our substantial inventory of highly economic prospects.
We continue to appraise our position in the Duvernay condensate-rich
resource play, where we have amassed 317 net sections at the relatively
low cost of approximately $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 is located in the
downdip part of our Edson block where condensate yields are expected to
be lower than the average in 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 later in the third quarter of 2014). Our second
horizontal appraisal well, 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 of this second well, also
employing microseismic monitoring, is expected during the third
quarter. During drilling operations, both the Edson and West Pembina
wells encountered stability issues in the build section of the wellbore
near the heel of the horizontal well. Both wells were ultimately
sidetracked to reach total measured depths of slightly more than 4,700
metres. Drilling operations lasted approximately 100 days per well,
double our original estimate. The longer-than-expected drilling time
took us past break-up, resulting in wet lease conditions and further
contributed to higher costs. As a result of these drilling challenges,
we are now forecasting total net well costs for the two horizontal
wells of approximately $40 million, including completion, equip and
tie-in, microseismic and related monitoring-well workovers. Our
development-phase target for 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 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 latter half of the decade.
On April 29, 2014, we announced the completion of our acquisition of
Elkhorn Resources Inc., a private southeast Saskatchewan producer, for
total consideration of $427 million. The assets consist of high
netback, light oil producing assets 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. More than 90% of the
current production base is operated by Vermilion. Production from the
assets was moderately impacted by recent flooding in S.E. Saskatchewan
and are projected to average approximately 3,750 boe/d (97% crude oil)
during the remainder of 2014. We have currently identified
approximately 175 (152 net) potential drilling locations targeting the
Midale, Frobisher, Bakken, and Three Forks/Torquay formations. We
began a two-rig, 13-well Midale drilling program in June 2014.
We were also active in Europe during the second quarter of 2014 with
drilling operations in both France and the Netherlands. In France, we
drilled two of five planned wells in Champotran in follow-up to our
highly successful 2013 drilling campaign. These first two wells have
been put on production during July at initial rates averaging 275
bbls/d per well. The remaining three wells at Champotran will be
drilled before the end of the third quarter. Our first well in the
Parentis field has been put on production at a rate of 20 bbls/d. A
new pool exploratory test at Cazaux North has been evaluated as dry and
will be abandoned. We currently plan a seven-well drilling program in
France during 2014, with two previously planned wells deferred to
later-year programs to optimize surface access and reduce rig move
costs. During the second quarter of 2014, we advanced preparations for
the phased transfer of our shut-in Vic Bihl 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
late-2015.
In the Netherlands, we drilled two additional wells during the second
quarter of 2014. The Havelte-01 well in the Steenwijk concession in
Friesland (50% working interest) came in low to prognosis and was
plugged and abandoned. However, as part of the Havelte-01 project, we
will tie-in a previously-stranded gas discovery at Eesveen-01. First
gas is anticipated to occur from Eesveen in early 2015 at an
anticipated rate of 3 mmcf/d net to Vermilion. The Lambertschaag-02
well was non-commercial in its primary objective but did encounter
other zones of interest with significant gas shows that will be further
evaluated during the third quarter of 2014. There are three wells
remaining in our 2014 Netherlands drilling program with one planned
during the third quarter and two in the fourth quarter. Late in the
second quarter, we initiated production from the Zechstein carbonate
formation of the previously-idle DeHoeve-01 well (42% working
interest), at a rate of 3 mmcf/d, net to Vermilion. Our undeveloped
land base in the Netherlands now totals more than 800,000 net acres,
and it is our intention to generally increase annual activity levels to
maintain a rolling inventory of projects so that each year's capital
program will involve a combination of drilling new wells and the tie-in
of previous successes.
In Germany, we have now established an office in Berlin, placed an
experienced Managing Director, and are progressing well with recruiting
a supporting technical team to oversee both our existing assets and
potential new opportunities. Our current 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 are expected
to contribute approximately 2,300 boe/d of production for calendar
2014, and include both exploration and production licenses that
comprise a total of 207,000 gross acres, of which 85% is in the
exploration license. Germany is a producing region with a long history
of oil and gas development activity, low political risk, and strong
marketing fundamentals. Our position 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. During the first quarter of 2014, we
participated in the drilling of one (0.25 net) development well in
Germany. This well logged 81 metres of net pay and is expected to be
tested and put on production during the second half of 2014.
On May 22, 2014, we announced the completion of tunnel boring operations
beneath Sruwaddacon Bay at our Corrib project in Ireland. The tunnel
boring machine has now been demobilized and the project is progressing
well with respect to several key activities that remain to be completed
prior to initial production at Corrib. These activities include the
installation of flow and umbilical lines within the tunnel, grouting of
the tunnel, certain offshore well workover activities, and receipt of
final authorizations for start-up of the Bellanaboy gas facility. The
most significant remaining offshore workover activity at our Corrib
field was successfully completed subsequent to the end of the quarter.
The Corrib P6 well was flow tested for 24 hours at a final flow rate of
112 mmcf/d at a flowing bottom hole pressure of 3260 psi, representing
an approximate 44 percent drawdown from reservoir pressure. The test
rates were within expectations, reconfirming previous test rates. The
well was still "cleaning up" at the end of the test, exhibiting an
increasing flow rate at increasing flowing bottom hole pressure when
the test period ended. The P6 test confirms that all five wells
required for start-up at Corrib are ready to flow. Based on the current
deterministic schedule for the project, 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 the 2015
drilling program, as well as re-lifing and maintenance projects on our
two platforms. In order to meet current marketing agreements and
provide long-term certainty to our customers, 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 approximately 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. Given the strength of
our operations, we have elected to increase our previous 2014 average
annual production guidance from a range of 48,000-49,000 boe/d to a
range of 48,500-49,500 boe/d. Assuming commodity prices remain near
current levels for the remainder of 2014, we anticipate that we can
fully fund our net dividends(1) and development capital expenditures (excluding capital investment at
Corrib) with fund flows from operations during 2014. With the shifts
in capital spending outlined previously, we currently anticipate full
year 2014 capital expenditure to total approximately $650 million, an
increase from our previous guidance of $635 million. This increase
largely reflects a shift in spending to increase Mannville development
drilling as well as higher costs for our Duvernay appraisal wells.
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 approximately 5% to 7% along
with 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.
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.
|
(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.
|
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is Management's Discussion and Analysis ("MD&A"), dated
July 30, 2014, of Vermilion Energy Inc.'s ("Vermilion" or the
"Company") operating and financial results as at and for the three and
six months ended June 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
six months ended June 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 six months ended June 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 are further increasing our full-year 2014
production and capital expenditure guidance to 48,500-49,500 boe/d and
$650 million, respectively. The increase in capital expenditures is due
to increased Mannville development drilling and higher than anticipated
costs associated with the Duvernay appraisal program.
The following table summarizes our 2014 guidance:
|
|
|
|
|
Date
|
|
|
|
|
|
Capital Expenditures ($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
|
SHAREHOLDER RETURN
Vermilion strives to provide investors with reliable and growing
dividends in addition to sustainable, global production growth. The
following table, as of June 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
|
|
|
$2.49
|
|
|
|
$7.11
|
|
|
|
$11.67
|
|
Capital appreciation per Vermilion share
|
|
|
$22.84
|
|
|
|
$23.25
|
|
|
|
$45.02
|
|
Total return per Vermilion share
|
|
|
49.3%
|
|
|
|
59.5%
|
|
|
|
193.9%
|
|
Annualized total return per Vermilion share
|
|
|
49.3%
|
|
|
|
16.8%
|
|
|
|
24.1%
|
|
Annualized total return on the S&P TSX High Income Energy Index
|
|
|
29.3%
|
|
|
|
6.2%
|
|
|
|
11.5%
|
|
(1)
|
The above table includes non-GAAP financial measures which may not be
comparable to other companies. Please see the
"ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of this MD&A.
|
CONSOLIDATED RESULTS OVERVIEW
|
|
|
Three Months Ended
|
|
% change
|
|
Six Months Ended
|
|
% change
|
|
|
|
Jun 30,
|
|
Mar 31,
|
|
Jun 30,
|
|
Q2/14 vs.
|
|
Q2/14 vs.
|
|
Jun 30,
|
|
Jun 30,
|
|
2014 vs.
|
|
|
|
2014
|
|
2014
|
|
2013
|
|
Q1/14
|
|
Q2/13
|
|
2014
|
|
2013
|
|
2013
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
30,184
|
|
27,318
|
|
26,638
|
|
10%
|
|
13%
|
|
28,759
|
|
25,119
|
|
14%
|
|
|
NGLs (bbls/d)
|
|
2,892
|
|
2,140
|
|
1,775
|
|
35%
|
|
63%
|
|
2,518
|
|
1,604
|
|
57%
|
|
|
Natural gas (mmcf/d)
|
|
114.08
|
|
103.32
|
|
86.40
|
|
10%
|
|
32%
|
|
108.73
|
|
84.29
|
|
29%
|
|
|
Total (boe/d)
|
|
52,089
|
|
46,677
|
|
42,813
|
|
12%
|
|
22%
|
|
49,398
|
|
40,772
|
|
21%
|
|
|
Build (draw) in inventory (mbbl)
|
|
67
|
|
(98)
|
|
6
|
|
|
|
|
|
(31)
|
|
(238)
|
|
|
|
Financial metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fund flows from operations ($M)
|
|
216,076
|
|
205,363
|
|
174,592
|
|
5%
|
|
24%
|
|
421,439
|
|
338,221
|
|
25%
|
|
|
Per share ($/basic share)
|
|
2.05
|
|
2.01
|
|
1.73
|
|
2%
|
|
18%
|
|
4.05
|
|
3.38
|
|
20%
|
|
|
Net earnings ($M)
|
|
53,993
|
|
102,788
|
|
106,198
|
|
(47%)
|
|
(49%)
|
|
156,781
|
|
158,335
|
|
(1%)
|
|
|
Per share ($/basic share)
|
|
0.51
|
|
1.00
|
|
1.05
|
|
(49%)
|
|
(51%)
|
|
1.51
|
|
1.58
|
|
(4%)
|
|
|
Cash flows from operating activities ($M)
|
|
149,592
|
|
178,238
|
|
179,074
|
|
(16%)
|
|
(16%)
|
|
327,830
|
|
369,786
|
|
(11%)
|
|
|
Net debt ($M)
|
|
1,168,998
|
|
966,310
|
|
674,368
|
|
21%
|
|
73%
|
|
1,168,998
|
|
674,368
|
|
73%
|
|
|
Cash dividends ($/share)
|
|
0.645
|
|
0.645
|
|
0.600
|
|
-
|
|
8%
|
|
1.290
|
|
1.200
|
|
8%
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
|
135,073
|
|
196,375
|
|
78,118
|
|
(31%)
|
|
73%
|
|
331,448
|
|
258,587
|
|
28%
|
|
|
Acquisitions ($M)
|
|
381,139
|
|
178,227
|
|
-
|
|
114%
|
|
100%
|
|
559,366
|
|
-
|
|
100%
|
|
|
Gross wells drilled
|
|
13.00
|
|
24.00
|
|
6.00
|
|
|
|
|
|
37.00
|
|
34.00
|
|
|
|
|
Net wells drilled
|
|
6.72
|
|
18.83
|
|
4.86
|
|
|
|
|
|
25.55
|
|
31.36
|
|
|
Operational review
-
Recorded consolidated average production of 52,089 boe/d during Q2 2014,
a 12% increase compared to Q1 2014 and a 22% increase as compared to Q2
2013. The growth quarter-over-quarter and year-over-year was primarily
driven by production growth in Canada, resulting from our continued
development of the Cardium and Mannville plays in Alberta coupled with
approximately two months of incremental production from southeast
Saskatchewan (approximately 2,000 boe/d during the quarter) following
our acquisition of Elkhorn Resources Inc. and a full quarter of
incremental production from our acquisition in Germany.
-
Recorded consolidated average production of 49,398 boe/d for the six
months ended June 30, 2014, a 21% increase versus the same period in
2013 as a result of production growth in Canada and the Netherlands.
In Canada, production growth of 32% year-over-year was achieved through
continued development of the Cardium and Mannville plays in Alberta,
coupled with two months of incremental production from southeast
Saskatchewan. In the Netherlands, production increased to 7,040 boe/d
resulting from incremental production from our acquisition in the
Netherlands in Q4 2013 and increased volumes following completion of
the Middenmeer Treatment Centre retrofit in the latter part of 2013.
In addition, we maintained Australia production at 6,795 boe/d
year-to-date and added incremental volumes from our acquisition in
Germany, which closed in February of 2014. These increases were
partially offset by a 1% decrease in production in France, which
occurred despite a 5% increase in crude oil production volumes, due to
the temporary shut-in of natural gas production.
-
Activity during the quarter included capital expenditures totalling
$135.1 million incurred primarily in Canada, France, the Netherlands,
and Ireland. In Canada, capital expenditures of $37.0 million were
significantly lower than the $114.9 million from Q1 2014 due to spring
breakup and were related to the drilling of 3.29 net wells. In France,
$37.6 million of capital expenditures were incurred during the quarter
relating to the drilling of 2.0 net wells in the Champotran field in
Paris. In the Netherlands, $21.5 million of capital expenditures were
incurred during the quarter relating to the drilling of 1.4 net wells.
In Ireland, $27.2 million of capital expenditures were incurred
relating to the completion of tunnel boring operations, offshore well
workover and various facility activities.
-
Acquisition expenditures for the quarter totalling $381.1 million
related primarily to our acquisition of Elkhorn Resources Inc. on April
29, 2014. This included approximately $205.0 million attributed to
approximately 2.8 million Vermilion common shares issued to Elkhorn's
shareholders. Acquisitions in the year-to-date period also included
our acquisition in Germany, which closed in February of 2014, for total
cash consideration of $172.9 million.
Financial review
Net earnings
-
Net earnings for Q2 2014 were $54.0 million ($0.51/basic share) as
compared to net earnings of $102.8 million ($1.00/basic share) in Q1
2014 and $106.2 million ($1.05/basic share) in Q2 2013. The decrease
to net earnings quarter-over-quarter and year-over-year occurred
despite production and sales growth, due largely to the reversal of
unrealized foreign exchange gains recognized during Q1 2014 and Q2
2013. The unrealized foreign exchange gains recognized during the
comparable quarters related to the Euro strengthening versus the
Canadian dollar and the resulting impact on our Euro denominated
financial assets. In Q1 2014 and Q2 2013, the Euro strengthened by
approximately 4% and 5%, respectively, versus a 4% weakening in the
current quarter.
-
Net earnings for the six months ended June 30, 2014 decreased by 1% (4%
per share). This slight decrease occurred as increased sales were
offset by the absence of unrealized foreign exchange gains and
increased depreciation expense.
Cash flows from operating activities
-
Cash flow from operations decreased by 16% and 11% for the three and six
months ended June 30, 2014 as compared to the same periods in 2013.
These decreases occurred despite increased production and favourable
Canadian dollar commodity prices due to the offsetting impacts of
timing differences pertaining to working capital.
Fund flows from operations
-
Generated fund flows from operations of $216.1 million ($2.05/basic
share) during Q2 2014, an increase of $10.7 million (5%) versus Q1
2014. This quarter-over-quarter increase was largely driven by
increased sales volumes in Canada, following production growth in the
Cardium, Mannville, and incremental production in southeast
Saskatchewan.
-
Fund flows from operations increased by 24% and 25% for the three and
six months ended June 30, 2014, respectively, versus the comparable
periods in 2013. These increases in fund flows from operations
resulted from increased sales volumes in Canada, incremental volumes
from our Germany acquisition, coupled with favorable Canadian dollar
crude oil and Canadian natural gas pricing, partially offset by lower
sales volumes in Australia and a decline in TTF pricing. Impacting fund
flows from operations, and included in general and administration costs
for 2014, are charges relating to our acquisitions in Canada ($1.1
million) and Germany ($0.8 million).
Net debt
-
As a result of funding our 2014 acquisitions in Germany and
Saskatchewan, net debt increased to $1.2 billion as at June 30, 2014.
As year-to-date fund flows from operations includes only two months of
contribution from the acquisition in Saskatchewan, the ratio of net
debt to annualized fund flows from operations increased to 1.4 times.
Dividends
-
Declared dividends of $0.215 per common share per month during 2014,
totalling $0.645 per common share over the quarter, an increase of 7.5%
versus the 2013 comparable periods.
COMMODITY PRICES
|
|
|
Three Months Ended
|
|
% change
|
|
Six Months Ended
|
|
% change
|
|
|
|
Jun 30,
|
|
Mar 31,
|
|
Jun 30,
|
|
Q2/14 vs.
|
|
Q2/14 vs.
|
|
Jun 30,
|
|
Jun 30,
|
|
2014 vs.
|
|
|
|
2014
|
|
2014
|
|
2013
|
|
Q1/14
|
|
Q2/13
|
|
2014
|
|
2013
|
|
2013
|
|
Average reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl)
|
|
102.99
|
|
98.68
|
|
94.22
|
|
4%
|
|
9%
|
|
100.84
|
|
94.30
|
|
7%
|
|
Edmonton Sweet index (US $/bbl)
|
|
96.85
|
|
90.43
|
|
90.56
|
|
7%
|
|
7%
|
|
93.65
|
|
88.99
|
|
5%
|
|
Dated Brent (US $/bbl)
|
|
109.63
|
|
108.22
|
|
102.44
|
|
1%
|
|
7%
|
|
108.93
|
|
107.50
|
|
1%
|
|
AECO ($/GJ)
|
|
4.44
|
|
5.42
|
|
3.35
|
|
(18%)
|
|
33%
|
|
4.93
|
|
3.19
|
|
55%
|
|
TTF ($/GJ)
|
|
7.91
|
|
10.19
|
|
10.14
|
|
(22%)
|
|
(22%)
|
|
9.02
|
|
10.23
|
|
(12%)
|
|
TTF (€/GJ)
|
|
5.27
|
|
6.75
|
|
7.57
|
|
(22%)
|
|
(30%)
|
|
6.01
|
|
7.69
|
|
(22%)
|
|
Average foreign currency exchange rates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CDN $/US $
|
|
1.09
|
|
1.10
|
|
1.02
|
|
(1%)
|
|
7%
|
|
1.10
|
|
1.02
|
|
8%
|
|
CDN $/Euro
|
|
1.50
|
|
1.51
|
|
1.34
|
|
(1%)
|
|
12%
|
|
1.50
|
|
1.33
|
|
13%
|
|
Average realized prices ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
71.56
|
|
69.26
|
|
62.00
|
|
3%
|
|
15%
|
|
70.55
|
|
59.93
|
|
18%
|
|
France
|
|
117.29
|
|
117.54
|
|
98.04
|
|
-
|
|
20%
|
|
117.41
|
|
102.84
|
|
14%
|
|
Netherlands
|
|
48.14
|
|
63.60
|
|
65.08
|
|
(24%)
|
|
(26%)
|
|
56.06
|
|
63.19
|
|
(11%)
|
|
Germany
|
|
45.36
|
|
55.85
|
|
-
|
|
(19%)
|
|
100%
|
|
49.50
|
|
-
|
|
100%
|
|
Australia
|
|
126.87
|
|
127.26
|
|
111.54
|
|
-
|
|
14%
|
|
127.11
|
|
115.89
|
|
10%
|
|
Consolidated
|
|
82.96
|
|
88.67
|
|
80.21
|
|
(6%)
|
|
3%
|
|
85.70
|
|
81.60
|
|
5%
|
|
Production mix (% of production)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% priced with reference to WTI
|
|
30%
|
|
25%
|
|
25%
|
|
|
|
|
|
27%
|
|
24%
|
|
|
|
% priced with reference to AECO
|
|
18%
|
|
17%
|
|
17%
|
|
|
|
|
|
18%
|
|
18%
|
|
|
|
% priced with reference to TTF
|
|
18%
|
|
19%
|
|
17%
|
|
|
|
|
|
19%
|
|
17%
|
|
|
|
% priced with reference to Dated Brent
|
|
34%
|
|
39%
|
|
41%
|
|
|
|
|
|
36%
|
|
41%
|
|
|
Reference prices
-
Oil outperformed natural gas in Q2 2014 as a result of heightened
geopolitical tensions and a generally tighter fundamental balance.
Averaging the quarter at US $109.63/bbl, Dated Brent was 1% higher
quarter-over-quarter and 7% above the same period last year.
-
WTI's advance quarter-over-quarter was more pronounced, up 4% from Q1
2014 and 9% higher than Q2 2013. Sliding oil inventories at Cushing,
Oklahoma and elevated refining demand contributed to the oil
benchmark's advance. Edmonton Sweet prices also increased in Q2 2014,
up 7% from both Q1 2014 and Q2 2013.
-
AECO natural gas fell 18% quarter-over-quarter to average C$4.44/GJ in
Q2. While seasonal factors weighed heavily on a quarter-over-quarter
basis, AECO still managed to post a strong 33% increase over the same
quarter last year and a 55% increase for the first half of 2014 over
the first half of 2013 from a colder-than-normal winter.
-
Increased storage levels and weaker seasonal demand led TTF to fall 22%
in Q2 versus Q1, averaging C$7.91/GJ, and down 30% versus the same
quarter last year.
-
The Canadian dollar posted a small increase versus both the US dollar
and Euro in Q2 2014 versus Q1 2014, however, versus the same period
last year the Canadian dollar has weakened by 7% versus the US dollar
and 12% versus the Euro.
Realized prices
-
Consolidated realized price decreased by 6% for Q2 2014 as compared to
Q1 2014. This decrease was the result of a change in Vermilion's
production mix coupled with a 22% decrease in TTF pricing.
Quarter-over-quarter, production growth in Alberta and incremental
production from our Q2 2014 acquisition in Saskatchewan increased our
percentage of WTI priced production from 25% to 30% of consolidated
production. As WTI continues to trade at a discount to Dated Brent,
this resulted in an overall decrease to our consolidated realized
price.
-
Consolidated realized price for the three and six months ended June 30,
2014 increased by 3% and 5% as compared to the same periods in the
prior year. These increases were the result of stronger crude oil and
Canadian natural gas pricing coupled with the weakness of the Canadian
dollar. These increases were partially offset by the aforementioned
changes in production mix and TTF pricing.
FUND FLOWS FROM OPERATIONS
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
|
Jun 30, 2014
|
|
Mar 31, 2014
|
|
Jun 30, 2013
|
|
Jun 30, 2014
|
|
Jun 30, 2013
|
|
|
|
$M
|
|
$/boe
|
|
$M
|
|
$/boe
|
|
$M
|
|
$/boe
|
|
$M
|
|
$/boe
|
|
$M
|
|
$/boe
|
|
Petroleum and natural gas sales
|
|
387,684
|
|
82.96
|
|
381,183
|
|
88.67
|
|
311,966
|
|
80.21
|
|
768,867
|
|
85.70
|
|
621,542
|
|
81.60
|
|
Royalties
|
|
(29,013)
|
|
(6.21)
|
|
(24,024)
|
|
(5.59)
|
|
(15,800)
|
|
(4.06)
|
|
(53,037)
|
|
(5.91)
|
|
(31,590)
|
|
(4.15)
|
|
Petroleum and natural gas revenues
|
|
358,671
|
|
76.75
|
|
357,159
|
|
83.08
|
|
296,166
|
|
76.15
|
|
715,830
|
|
79.79
|
|
589,952
|
|
77.45
|
|
Transportation expense
|
|
(12,032)
|
|
(2.57)
|
|
(9,861)
|
|
(2.29)
|
|
(6,653)
|
|
(1.71)
|
|
(21,893)
|
|
(2.44)
|
|
(13,294)
|
|
(1.75)
|
|
Operating expense
|
|
(58,213)
|
|
(12.46)
|
|
(57,986)
|
|
(13.49)
|
|
(48,082)
|
|
(12.36)
|
|
(116,199)
|
|
(12.95)
|
|
(100,657)
|
|
(13.21)
|
|
General and administration
|
|
(17,762)
|
|
(3.80)
|
|
(14,467)
|
|
(3.37)
|
|
(11,313)
|
|
(2.91)
|
|
(32,229)
|
|
(3.59)
|
|
(23,923)
|
|
(3.14)
|
|
Corporate income taxes
|
|
(32,635)
|
|
(6.98)
|
|
(38,603)
|
|
(8.98)
|
|
(36,719)
|
|
(9.44)
|
|
(71,238)
|
|
(7.94)
|
|
(72,276)
|
|
(9.49)
|
|
PRRT
|
|
(12,699)
|
|
(2.72)
|
|
(20,239)
|
|
(4.71)
|
|
(12,590)
|
|
(3.24)
|
|
(32,938)
|
|
(3.67)
|
|
(23,743)
|
|
(3.12)
|
|
Interest expense
|
|
(12,334)
|
|
(2.64)
|
|
(11,460)
|
|
(2.67)
|
|
(9,336)
|
|
(2.40)
|
|
(23,794)
|
|
(2.65)
|
|
(18,025)
|
|
(2.37)
|
|
Realized gain (loss) on derivative instruments
|
|
2,419
|
|
0.52
|
|
2,640
|
|
0.61
|
|
1,770
|
|
0.46
|
|
5,059
|
|
0.56
|
|
(1,017)
|
|
(0.13)
|
|
Realized foreign exchange gain (loss)
|
|
587
|
|
0.12
|
|
(2,041)
|
|
(0.47)
|
|
1,272
|
|
0.33
|
|
(1,454)
|
|
(0.16)
|
|
655
|
|
0.09
|
|
Realized other income
|
|
74
|
|
0.02
|
|
221
|
|
0.05
|
|
77
|
|
0.02
|
|
295
|
|
0.03
|
|
549
|
|
0.07
|
|
Fund flows from operations
|
|
216,076
|
|
46.24
|
|
205,363
|
|
47.76
|
|
174,592
|
|
44.90
|
|
421,439
|
|
46.98
|
|
338,221
|
|
44.40
|
The following table shows a reconciliation of the change in fund flows
from operations:
|
($M)
|
|
|
Q2/14 vs. Q1/14
|
|
Q2/14 vs. Q2/13
|
|
2014 vs. 2013
|
|
Fund flows from operations - Comparative period
|
|
|
205,363
|
|
174,592
|
|
338,221
|
|
Sales volume variance:
|
|
|
|
|
|
|
|
|
Canada
|
|
|
39,771
|
|
44,135
|
|
63,154
|
|
France
|
|
|
7,323
|
|
6,669
|
|
(4,579)
|
|
Netherlands
|
|
|
(1,936)
|
|
2,166
|
|
7,799
|
|
Germany
|
|
|
4,751
|
|
11,097
|
|
20,012
|
|
Australia
|
|
|
(30,964)
|
|
(20,562)
|
|
(6,516)
|
|
Pricing variance on sold volumes:
|
|
|
|
|
|
|
|
|
WTI
|
|
|
5,026
|
|
14,192
|
|
24,876
|
|
AECO
|
|
|
(4,717)
|
|
3,983
|
|
13,772
|
|
Dated Brent
|
|
|
(447)
|
|
24,639
|
|
37,907
|
|
TTF
|
|
|
(12,306)
|
|
(10,601)
|
|
(9,100)
|
|
Changes in:
|
|
|
|
|
|
|
|
|
Realized derivatives
|
|
|
(221)
|
|
649
|
|
6,076
|
|
Royalties
|
|
|
(4,989)
|
|
(13,213)
|
|
(21,447)
|
|
Operating expense
|
|
|
(227)
|
|
(10,131)
|
|
(15,542)
|
|
Transportation
|
|
|
(2,171)
|
|
(5,379)
|
|
(8,599)
|
|
Interest
|
|
|
(874)
|
|
(2,998)
|
|
(5,769)
|
|
General and administration
|
|
|
(3,295)
|
|
(6,449)
|
|
(8,306)
|
|
Realized other income
|
|
|
(147)
|
|
(3)
|
|
(254)
|
|
Realized foreign exchange
|
|
|
2,628
|
|
(685)
|
|
(2,109)
|
|
Corporate income taxes
|
|
|
5,968
|
|
4,084
|
|
1,038
|
|
PRRT
|
|
|
7,540
|
|
(109)
|
|
(9,195)
|
|
Fund flows from operations - Current Period
|
|
|
216,076
|
|
216,076
|
|
421,439
|
Fund flows from operations of $216.1 million during Q2 2014 was an
increase of $10.7 million (5%) versus Q1 2014. The majority of this
increase resulted from $6.5 million of increased sales. The increase
in sales was due to favourable sales volume variances, partially offset
by unfavourable pricing variances. Sales volume variances included
$39.8 million relating to higher production volumes in Canada following
continued development of the Cardium and Mannville plays in Alberta and
incremental production from our southeast Saskatchewan acquisition and
$7.3 million relating to a draw in inventory in France. These
favourable sales volume variances were partially offset by a $31.0
million unfavourable variance relating to a build in inventory in
Australia. The unfavourable pricing variance was the result of a
quarter-over-quarter decline in natural gas prices, offset partially by
an increase in the WTI reference price.
Fund flows from operations increased by 24% and 25% for the three and
six months ended June 30, 2014, respectively, versus the comparable
periods in 2013. These increases in fund flows from operations
resulted primarily from the combined impacts of favourable sales volume
and pricing variances. Favourable sales volume variances occurred
primarily in Canada (contributing an additional $44.1 million in Q2
2014 and $63.2 million year-to-date 2014 versus the comparable periods)
and were aided by incremental production in Germany (contributing $11.1
million in the quarter and $20.0 million in the year-to-date period).
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
|
|
Six Months Ended
|
|
% change
|
|
|
|
Jun 30,
|
|
Mar 31,
|
|
Jun 30,
|
|
Q2/14 vs.
|
|
Q2/14 vs.
|
|
Jun 30,
|
|
Jun 30,
|
|
2014 vs.
|
|
Canada business unit
|
|
2014
|
|
2014
|
|
2013
|
|
Q1/14
|
|
Q2/13
|
|
2014
|
|
2013
|
|
2013
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
12,676
|
|
9,437
|
|
8,885
|
|
34%
|
|
43%
|
|
11,065
|
|
8,428
|
|
31%
|
|
|
NGLs (bbls/d)
|
|
2,796
|
|
2,071
|
|
1,725
|
|
35%
|
|
62%
|
|
2,435
|
|
1,531
|
|
59%
|
|
|
Natural gas (mmcf/d)
|
|
57.59
|
|
49.53
|
|
43.69
|
|
16%
|
|
32%
|
|
53.58
|
|
42.37
|
|
26%
|
|
|
Total (boe/d)
|
|
25,070
|
|
19,763
|
|
17,892
|
|
27%
|
|
40%
|
|
22,430
|
|
17,021
|
|
32%
|
|
Production mix (% of total)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
51%
|
|
48%
|
|
50%
|
|
|
|
|
|
49%
|
|
50%
|
|
|
|
|
NGLs
|
|
11%
|
|
10%
|
|
10%
|
|
|
|
|
|
11%
|
|
9%
|
|
|
|
|
Natural gas
|
|
38%
|
|
42%
|
|
40%
|
|
|
|
|
|
40%
|
|
41%
|
|
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
|
36,968
|
|
114,939
|
|
16,553
|
|
(68%)
|
|
123%
|
|
151,907
|
|
101,682
|
|
49%
|
|
|
Acquisitions ($M)
|
|
381,326
|
|
4,768
|
|
-
|
|
|
|
|
|
386,094
|
|
-
|
|
|
|
|
Gross wells drilled
|
|
9.00
|
|
20.00
|
|
3.00
|
|
|
|
|
|
29.00
|
|
27.00
|
|
|
|
|
Net wells drilled
|
|
3.29
|
|
14.97
|
|
1.86
|
|
|
|
|
|
18.26
|
|
24.36
|
|
|
Production
-
Production in Canada increased by 27% quarter-over-quarter and by 40%
year-over-year.
-
Quarter-over-quarter and year-over-year increases were largely
attributable to production additions from our southeast Saskatchewan
acquisition, supplemented by strong production from our Mannville
program and continued development in the Cardium.
-
Cardium production averaged more than 12,100 boe/d in Q2 2014.
-
Mannville production averaged more than 4,600 boe/d in Q2 2014.
-
Saskatchewan production averaged approximately 2,000 boe/d in Q2 2014,
taking into account an effective acquisition date of April 29, 2014.
Activity review
-
Vermilion drilled nine (3.3 net) wells during Q2 2014.
Cardium
-
In the Cardium, we drilled one (1.0 net) operated well and brought five
(5.0 net) operated wells on production during Q2 2014, all of which
were long reach wells with horizontal lengths between 1.5 and 2.0
miles. Year-to-date we have drilled 12 (11.5 net) operated wells and
brought 18 (18.0 net) operated wells on production.
-
Since 2009, we have drilled or participated in 258 (183.7 net) wells in
the Cardium.
-
Operating netbacks averaged approximately $70/boe year-to-date for
Cardium production.
-
In 2014, we plan to drill or participate in 37 (24.5 net) Cardium wells.
Mannville
-
During Q2 2014, in the Mannville, we brought two (1.5 net) operated
wells on production that were drilled in the previous quarter.
Year-to-date we have drilled and brought on production five (3.7 net)
operated wells.
-
In 2014, we plan to drill 15 (9 net) Mannville wells.
Duvernay
-
We drilled two (1.3 net) horizontal Duvernay wells, with completion of
the wells anticipated for Q3 2014.
Saskatchewan
-
We spud two wells in the second quarter, with completions scheduled for
Q3 2014.
-
A 13 well Midale program is planned for 2014.
Financial review
|
|
|
Three Months Ended
|
|
% change
|
|
Six Months Ended
|
|
% change
|
|
Canada business unit
|
|
Jun 30,
|
|
Mar 31,
|
|
Jun 30,
|
|
Q2/14 vs.
|
|
Q2/14 vs.
|
|
Jun 30,
|
|
Jun 30,
|
|
2014 vs.
|
|
($M except as indicated)
|
|
2014
|
|
2014
|
|
2013
|
|
Q1/14
|
|
Q2/13
|
|
2014
|
|
2013
|
|
2013
|
|
Sales
|
|
163,261
|
|
123,180
|
|
100,950
|
|
33%
|
|
62%
|
|
286,441
|
|
184,638
|
|
55%
|
|
Royalties
|
|
(18,240)
|
|
(12,663)
|
|
(9,707)
|
|
44%
|
|
88%
|
|
(30,903)
|
|
(18,696)
|
|
65%
|
|
Transportation expense
|
|
(4,024)
|
|
(3,098)
|
|
(2,611)
|
|
30%
|
|
54%
|
|
(7,122)
|
|
(4,880)
|
|
46%
|
|
Operating expense
|
|
(21,179)
|
|
(16,610)
|
|
(15,975)
|
|
28%
|
|
33%
|
|
(37,789)
|
|
(29,816)
|
|
27%
|
|
General and administration
|
|
(6,560)
|
|
(2,868)
|
|
(3,948)
|
|
129%
|
|
66%
|
|
(9,428)
|
|
(7,017)
|
|
34%
|
|
Fund flows from operations
|
|
113,258
|
|
87,941
|
|
68,709
|
|
29%
|
|
65%
|
|
201,199
|
|
124,229
|
|
62%
|
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
71.56
|
|
69.26
|
|
62.00
|
|
3%
|
|
15%
|
|
70.55
|
|
59.93
|
|
18%
|
|
Royalties
|
|
(7.99)
|
|
(7.12)
|
|
(5.96)
|
|
12%
|
|
34%
|
|
(7.61)
|
|
(6.07)
|
|
25%
|
|
Transportation expense
|
|
(1.76)
|
|
(1.74)
|
|
(1.60)
|
|
1%
|
|
10%
|
|
(1.75)
|
|
(1.58)
|
|
11%
|
|
Operating expense
|
|
(9.28)
|
|
(9.34)
|
|
(9.81)
|
|
(1%)
|
|
(5%)
|
|
(9.31)
|
|
(9.68)
|
|
(4%)
|
|
General and administration
|
|
(2.88)
|
|
(1.61)
|
|
(2.42)
|
|
79%
|
|
19%
|
|
(2.32)
|
|
(2.28)
|
|
2%
|
|
Fund flows from operations netback
|
|
49.65
|
|
49.45
|
|
42.21
|
|
-
|
|
18%
|
|
49.56
|
|
40.32
|
|
23%
|
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl)
|
|
102.99
|
|
98.68
|
|
94.22
|
|
4%
|
|
9%
|
|
100.84
|
|
94.30
|
|
7%
|
|
Edmonton Sweet index (US $/bbl)
|
|
96.85
|
|
90.43
|
|
90.56
|
|
7%
|
|
7%
|
|
93.65
|
|
88.99
|
|
5%
|
|
AECO ($/GJ)
|
|
4.44
|
|
5.42
|
|
3.35
|
|
(18%)
|
|
33%
|
|
4.93
|
|
3.19
|
|
55%
|
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 increased by 3% quarter-over-quarter as a result of a 7%
increase in Edmonton Sweet index pricing, partially offset by an 18%
decrease in AECO pricing.
-
On a year-over-year basis, sales per boe increased by 15% and 18% for
the three and six months ended June 30, 2014, largely as a result of
the strengthening of the Edmonton Sweet index and AECO reference price,
coupled with a higher mix of crude oil and NGL production.
-
The increases in the Edmonton Sweet index combined with incremental
production from our Saskatchewan acquisition and production growth in
the Cardium and Mannville resource plays resulted in a 33% and 62%
increase in sales for Q2 2014 versus Q1 2014 and Q2 2013, respectively.
Royalties
-
Royalty expense as a percentage of sales increased to 11.2% for Q2 2014
from 9.6% in Q2 2013 and 10.3% in Q1 2014. Royalty expense as a
percentage of sales increased to 10.8% for the six months ended June
30, 2014 as compared to 10.1% for the same period of the prior year.
-
All periods are affected by the timing of placing wells on production
due to royalty incentives on initial production volumes. Royalties as
a percentage of sales were slightly higher in the second quarter
partially as a result of slightly higher average royalty rates
associated with Vermilion's Saskatchewan production. In addition,
increased commodity prices have contributed to the year-over-year
increases in royalty rates as a percentage of sales.
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 remained consistent between Q2 2014 and
Q1 2014 as higher trucking costs in the second quarter associated with
Vermilion's Saskatchewan acquisition offset trucking costs incurred in
the first quarter which were related to a Pembina pipeline outage.
-
Transportation expense per boe increased for the three and six months
ended June 30, 2014 as compared to the same periods of 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 was lower for the three and six months ended
June 30, 2014 as compared to the prior periods presented due to a
larger increase in production volumes than expenditures.
General and administration
-
General and administration expense increased in the current quarter as
compared to the prior quarter largely due to higher legal and
consultant costs related to the Saskatchewan acquisition ($1.1MM),
additional salary allocations from our Corporate segment to our
Canadian Business Unit to reflect internal integration effort
associated with the Saskatchewan acquisition ($0.7MM), lower third
party overhead recoveries as a result of less capital activity in the
second quarter due to spring break-up ($1.0MM) as well as higher salary
costs quarter-over-quarter resulting from increased staffing levels.
These same items are the significant drivers for the year-over-year
increases in general and administration expense for the periods
presented, partially offset by expenditure timing.
FRANCE BUSINESS UNIT
Overview
-
Entered France in 1997 and completed three subsequent acquisitions,
including two in 2012.
-
Largest oil producer by volume.
-
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
|
|
Six Months Ended
|
|
% change
|
|
|
|
Jun 30,
|
|
Mar 31,
|
|
Jun 30,
|
|
Q2/14 vs.
|
|
Q2/14 vs.
|
|
Jun 30,
|
|
Jun 30,
|
|
2014 vs.
|
|
France business unit
|
|
2014
|
|
2014
|
|
2013
|
|
Q1/14
|
|
Q2/13
|
|
2014
|
|
2013
|
|
2013
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
11,025
|
|
10,771
|
|
10,390
|
|
2%
|
|
6%
|
|
10,899
|
|
10,360
|
|
5%
|
|
Natural gas (mmcf/d)
|
|
-
|
|
-
|
|
4.19
|
|
-
|
|
(100%)
|
|
-
|
|
4.20
|
|
(100%)
|
|
Total (boe/d)
|
|
11,025
|
|
10,771
|
|
11,088
|
|
2%
|
|
(1%)
|
|
10,899
|
|
11,060
|
|
(1%)
|
|
Inventory (mbbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Opening crude oil inventory
|
|
238
|
|
269
|
|
218
|
|
|
|
|
|
269
|
|
354
|
|
|
|
Adjustments
|
|
-
|
|
-
|
|
-
|
|
|
|
|
|
-
|
|
5
|
|
|
|
Crude oil production
|
|
1,003
|
|
969
|
|
945
|
|
|
|
|
|
1,973
|
|
1,875
|
|
|
|
Crude oil sales
|
|
(1,062)
|
|
(1,000)
|
|
(961)
|
|
|
|
|
|
(2,063)
|
|
(2,032)
|
|
|
|
Closing crude oil inventory
|
|
179
|
|
238
|
|
202
|
|
|
|
|
|
179
|
|
202
|
|
|
|
Production mix (% of total)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
100%
|
|
100%
|
|
94%
|
|
|
|
|
|
100%
|
|
94%
|
|
|
|
Natural gas
|
|
-
|
|
-
|
|
6%
|
|
|
|
|
|
-
|
|
6%
|
|
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
|
37,614
|
|
37,967
|
|
23,223
|
|
(1%)
|
|
62%
|
|
75,581
|
|
44,815
|
|
69%
|
|
Gross wells drilled
|
|
2.00
|
|
2.00
|
|
3.00
|
|
|
|
|
|
4.00
|
|
5.00
|
|
|
|
Net wells drilled
|
|
2.00
|
|
2.00
|
|
3.00
|
|
|
|
|
|
4.00
|
|
5.00
|
|
|
Production
-
Quarter-over-quarter production increased 2% and year-over-year
production decreased 1%. Year-over-year production of crude oil
increased 6%.
-
In late September 2013, the third party Lacq processing facility that
processed our Vic Bihl gas production was permanently closed. As a
result, our Vic Bihl gas production has been temporarily shut-in while
preparations to transfer to an alternative facility are completed. We
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 late-2015.
-
Production remains 100% weighted to Brent crude due to the shut-in of
Vic Bihl gas production.
Activity review
-
Vermilion drilled two (2.0 net) wells in the Champotran field in the
Paris Basin during Q2 2014, with production from these wells
anticipated to come on-line in Q3.
-
During Q2 2014, we also completed a number of seismic and facility
integrity projects.
-
Our Parentis (PS-224) well, drilled in Q2 2014, is producing 20 bbls/d.
The Cazaux North well drilled in Q1 2014 is dry and will be abandoned.
-
In 2014, we are planning a seven-well drilling program in the
Champotran, Cazaux, and Parentis fields.
Financial review
|
|
|
|
Three Months Ended
|
|
% change
|
|
Six Months Ended
|
|
% change
|
|
France business unit
|
|
|
Jun 30,
|
|
Mar 31,
|
|
Jun 30,
|
|
Q2/14 vs.
|
|
Q2/14 vs.
|
|
Jun 30,
|
|
Jun 30,
|
|
2014 vs.
|
|
($M except as indicated)
|
|
|
2014
|
|
2014
|
|
2013
|
|
Q1/14
|
|
Q2/13
|
|
2014
|
|
2013
|
|
2013
|
|
Sales
|
|
|
124,617
|
|
117,560
|
|
100,418
|
|
6%
|
|
24%
|
|
242,177
|
|
221,984
|
|
9%
|
|
Royalties
|
|
|
(7,796)
|
|
(7,351)
|
|
(6,093)
|
|
6%
|
|
28%
|
|
(15,147)
|
|
(12,894)
|
|
17%
|
|
Transportation expense
|
|
|
(5,385)
|
|
(4,753)
|
|
(2,416)
|
|
13%
|
|
123%
|
|
(10,138)
|
|
(5,170)
|
|
96%
|
|
Operating expense
|
|
|
(16,550)
|
|
(16,420)
|
|
(16,935)
|
|
1%
|
|
(2%)
|
|
(32,970)
|
|
(36,874)
|
|
(11%)
|
|
General and administration
|
|
|
(5,559)
|
|
(5,194)
|
|
(3,927)
|
|
7%
|
|
42%
|
|
(10,753)
|
|
(9,613)
|
|
12%
|
|
Current income taxes
|
|
|
(24,761)
|
|
(25,264)
|
|
(16,124)
|
|
(2%)
|
|
54%
|
|
(50,025)
|
|
(34,783)
|
|
44%
|
|
Fund flows from operations
|
|
|
64,566
|
|
58,578
|
|
54,923
|
|
10%
|
|
18%
|
|
123,144
|
|
122,650
|
|
-
|
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
117.29
|
|
117.54
|
|
98.04
|
|
-
|
|
20%
|
|
117.41
|
|
102.84
|
|
14%
|
|
Royalties
|
|
|
(7.34)
|
|
(7.35)
|
|
(5.95)
|
|
-
|
|
23%
|
|
(7.34)
|
|
(5.97)
|
|
23%
|
|
Transportation expense
|
|
|
(5.07)
|
|
(4.75)
|
|
(2.36)
|
|
7%
|
|
115%
|
|
(4.91)
|
|
(2.39)
|
|
105%
|
|
Operating expense
|
|
|
(15.58)
|
|
(16.42)
|
|
(16.53)
|
|
(5%)
|
|
(6%)
|
|
(15.98)
|
|
(17.08)
|
|
(6%)
|
|
General and administration
|
|
|
(5.24)
|
|
(5.19)
|
|
(3.83)
|
|
1%
|
|
37%
|
|
(5.21)
|
|
(4.45)
|
|
17%
|
|
Current income taxes
|
|
|
(23.30)
|
|
(25.26)
|
|
(15.74)
|
|
(8%)
|
|
48%
|
|
(24.25)
|
|
(16.11)
|
|
51%
|
|
Fund flows from operations netback
|
|
|
60.76
|
|
58.57
|
|
53.63
|
|
4%
|
|
13%
|
|
59.72
|
|
56.84
|
|
5%
|
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated Brent (US $/bbl)
|
|
|
109.63
|
|
108.22
|
|
102.44
|
|
1%
|
|
7%
|
|
108.93
|
|
107.50
|
|
1%
|
Sales
-
Crude oil production in France is priced with reference to Dated Brent.
-
Sales per boe for Q2 2014 was relatively unchanged versus Q1 2014 as the
1% increase in the US dollar Dated Brent reference price was largely
offset by a 1% strengthening of the Canadian dollar.
-
Sales per boe for the three and six months ended June 30, 2014 were 20%
and 14% higher than the respective periods in the previous year. This
increase was primarily the result of increases in the Dated Brent
reference price and the weakening of the Canadian dollar. These
changes, coupled with increased crude oil production, resulted in
increased sales for both the three and six month periods ended June 30,
2014 of 24% and 9%, respectively.
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 constant.
Transportation
-
Historically, transportation expense in France related to the 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 Bihl 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 for Q2 2014 was consistent with the Q1 2014 and Q2
2013 expense. The decrease in the expense per boe for Q2 2014 as
compared to the prior periods is associated with higher volumes in the
current period.
General and administration
-
General and administration expense was consistent among the periods
presented. Minor variances are largely attributable to the timing of
expenditures.
Current income taxes
-
Current income taxes in France apply to taxable income after eligible
deductions at a statutory rate of 38.1% for 2014. Following the
expiration of a temporary surtax, the statutory tax rate is expected to
decrease to 34.4% for the tax year 2016. For 2014, the effective rate
on current taxes is expected to be between approximately 28% and 31%.
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 Q2 2014 was slightly lower versus Q1 2014 as
increased pre-tax fund flows from operations was offset by an increase
in eligible tax deductions for depreciation.
-
On a year-over-year basis, current taxes increased by 54% and 44% for
the three and six months ended June 30, 2014 versus the same periods in
2013. These increases were the result of the absence of certain
interest deductions, lower depletion for tax purposes, and higher tax
rates following a December 2013 corporate tax legislation enacted by
the France government which increased the rate of a temporary surtax.
NETHERLANDS BUSINESS UNIT
Overview
-
Entered the Netherlands in 2004.
-
Second largest onshore gas producer by volume.
-
Interests include 16 licenses in the northeast region, five licenses in
the central region, and two offshore licenses.
-
Licenses include more than 800,000 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
|
|
Six Months Ended
|
|
% change
|
|
|
|
|
Jun 30,
|
|
Mar 31,
|
|
Jun 30,
|
|
Q2/14 vs.
|
|
Q2/14 vs.
|
|
Jun 30,
|
|
Jun 30,
|
|
2014 vs.
|
|
Netherlands business unit
|
|
|
2014
|
|
2014
|
|
2013
|
|
Q1/14
|
|
Q2/13
|
|
2014
|
|
2013
|
|
2013
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d)
|
|
|
96
|
|
69
|
|
50
|
|
39%
|
|
92%
|
|
83
|
|
73
|
|
14%
|
|
Natural gas (mmcf/d)
|
|
|
40.35
|
|
43.15
|
|
38.52
|
|
(6%)
|
|
5%
|
|
41.74
|
|
37.72
|
|
11%
|
|
Total (boe/d)
|
|
|
6,822
|
|
7,260
|
|
6,470
|
|
(6%)
|
|
5%
|
|
7,040
|
|
6,360
|
|
11%
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
|
|
21,513
|
|
20,118
|
|
4,157
|
|
7%
|
|
418%
|
|
41,631
|
|
4,529
|
|
819%
|
|
Gross wells drilled
|
|
|
2.00
|
|
2.00
|
|
-
|
|
|
|
|
|
4.00
|
|
-
|
|
|
|
Net wells drilled
|
|
|
1.43
|
|
1.86
|
|
-
|
|
|
|
|
|
3.29
|
|
-
|
|
|
Production
-
Quarter-over-quarter production decrease of 6% and year-over-year
production growth of 5%.
-
Production in the Netherlands is currently being managed to meet
corporate targets, optimize facility use and regulate declines.
Activity review
-
Vermilion drilled two (1.4 net) wells during Q2 2014. The Havelte-01
well (50% working interest) had no gas shows from the Zechstein and
Vlieland targets, however the lease site of the Havelte-01 well will
enable the tie in of Eesveen-01, a well located in a previously
stranded gas field discovered in 1986. The Lambertschaag-02 well (93%
working interest) in the Slootdorp concession was determined to be not
gas bearing in its primary target zone. Lambertschaag-02 did encounter
secondary zones of interest with gas shows which will be further
evaluated in Q3 2014.
-
Late during Q2 2014, we initiated production from the Zechstein
carbonate formation of the DeHoeve-01 well at a rate of 3 mmcf/d net to
Vermilion. The DeHoeve well was drilled in 2009 and had previously
produced from the Slochteren sandstone (Rotliegend).
-
An additional three wells are planned for the 2014 drilling program in
the Netherlands, one is planned for the third quarter and the remaining
two wells are planned for the fourth quarter. The drilling program will
include our first new well on the lands acquired in October 2013.
Financial review
|
|
|
|
Three Months Ended
|
|
% change
|
|
|
Six Months Ended
|
|
% change
|
|
Netherlands business unit
|
|
|
Jun 30,
|
|
Mar 31,
|
|
Jun 30,
|
|
Q2/14 vs.
|
|
Q2/14 vs.
|
|
|
Jun 30,
|
|
Jun 30,
|
|
2014 vs.
|
|
($M except as indicated)
|
|
|
2014
|
|
2014
|
|
2013
|
|
Q1/14
|
|
Q2/13
|
|
|
2014
|
|
2013
|
|
2013
|
|
Sales
|
|
|
29,881
|
|
41,554
|
|
38,316
|
|
(28%)
|
|
(22%)
|
|
|
71,435
|
|
72,737
|
|
(2%)
|
|
Royalties
|
|
|
(693)
|
|
(2,208)
|
|
-
|
|
(69%)
|
|
100%
|
|
|
(2,901)
|
|
-
|
|
100%
|
|
Operating expense
|
|
|
(6,390)
|
|
(6,042)
|
|
(5,260)
|
|
6%
|
|
21%
|
|
|
(12,432)
|
|
(9,229)
|
|
35%
|
|
General and administration
|
|
|
(326)
|
|
(598)
|
|
(426)
|
|
(45%)
|
|
(23%)
|
|
|
(924)
|
|
(838)
|
|
10%
|
|
Current income taxes
|
|
|
(1,301)
|
|
(3,788)
|
|
(9,621)
|
|
(66%)
|
|
(86%)
|
|
|
(5,089)
|
|
(19,055)
|
|
(73%)
|
|
Fund flows from operations
|
|
|
21,171
|
|
28,918
|
|
23,009
|
|
(27%)
|
|
(8%)
|
|
|
50,089
|
|
43,615
|
|
15%
|
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
48.14
|
|
63.60
|
|
65.08
|
|
(24%)
|
|
(26%)
|
|
|
56.06
|
|
63.19
|
|
(11%)
|
|
Royalties
|
|
|
(1.12)
|
|
(3.38)
|
|
-
|
|
(67%)
|
|
100%
|
|
|
(2.28)
|
|
-
|
|
100%
|
|
Operating expense
|
|
|
(10.29)
|
|
(9.25)
|
|
(8.93)
|
|
11%
|
|
15%
|
|
|
(9.76)
|
|
(8.02)
|
|
22%
|
|
General and administration
|
|
|
(0.53)
|
|
(0.91)
|
|
(0.72)
|
|
(42%)
|
|
(26%)
|
|
|
(0.73)
|
|
(0.73)
|
|
-
|
|
Current income taxes
|
|
|
(2.10)
|
|
(5.80)
|
|
(16.34)
|
|
(64%)
|
|
(87%)
|
|
|
(3.99)
|
|
(16.55)
|
|
(76%)
|
|
Fund flows from operations netback
|
|
|
34.10
|
|
44.26
|
|
39.09
|
|
(23%)
|
|
(13%)
|
|
|
39.30
|
|
37.89
|
|
4%
|
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TTF ($/GJ)
|
|
|
7.91
|
|
10.19
|
|
10.14
|
|
(22%)
|
|
(22%)
|
|
|
9.02
|
|
10.23
|
|
(12%)
|
|
TTF (€/GJ)
|
|
|
5.27
|
|
6.75
|
|
7.57
|
|
(22%)
|
|
(30%)
|
|
|
6.01
|
|
7.69
|
|
(22%)
|
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 and sales per boe in Q2 2014 versus Q1 2014 and
Q2 2013 were largely in-line with the change in the Canadian dollar TTF
reference price.
-
On a year-over-year basis, sales declined by 2% as a result of the 12%
decrease in the TTF reference price offset by an 11% 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 increased in Q2 2014 from Q1 2014 due to the timing of
major project expense. Lower volumes quarter-over-quarter also
contributed to the increase in operating costs on a per boe basis.
-
Year-over-year, operating expense increased for both the quarter and
year to date periods 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 decreased in Q2 2014 from Q1 2014 due
to a reduction in project-related consultant costs. As compared to the
prior year, general and administration expense for the current quarter
and year to date periods remained consistent.
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 as compared to both Q1 2014 and Q2 2013
as a result of decreased revenues, lower TTF reference prices and an
increase in tax deductions for depletion during the current quarter.
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
|
|
|
Six Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jun 30,
|
Mar 31,
|
|
|
Q2/14 vs.
|
|
|
Jun 30,
|
|
Germany business unit
|
|
|
|
|
|
|
|
|
|
|
2014
|
2014
|
|
|
Q1/14
|
|
|
2014
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
|
|
|
|
|
|
|
|
|
|
16.13
|
10.64
|
|
|
52%
|
|
|
13.40
|
|
|
Total (boe/d)
|
|
|
|
|
|
|
|
|
|
|
2,689
|
1,773
|
|
|
52%
|
|
|
2,234
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
|
|
|
|
|
|
|
|
|
|
630
|
196
|
|
|
221%
|
|
|
826
|
|
|
Acquisitions ($M)
|
|
|
|
|
|
|
|
|
|
|
-
|
172,871
|
|
|
|
|
|
172,871
|
Production
-
Achieved Q2 2014 production of 2,689 boe/d, an increase of 52% as
compared to 1,773 boe/d in Q1 2014, taking into account an effective
date for production of February 1, 2014.
Activity review
-
Continued the integration of the German business with our working
interest partners and have commenced planning for future wells.
-
In Q1 2014, we participated in the drilling of one (0.25 net)
development well, which logged 81 metres of net pay and is expected to
be tested and put on production during the second half of 2014.
-
We have hired a Managing Director for the German business unit and have
opened an office outside of Berlin, which we are currently outfitting
and staffing.
Financial review
|
|
|
|
|
Three Months Ended
|
|
|
% change
|
|
|
Six Months Ended
|
|
Germany business unit
|
|
|
Jun 30,
|
Mar 31,
|
|
|
Q2/14 vs.
|
|
|
Jun 30,
|
|
($M except as indicated)
|
|
|
2014
|
2014
|
|
|
Q1/14
|
|
|
2014
|
|
|
Sales
|
|
|
11,097
|
8,915
|
|
|
24%
|
|
|
20,012
|
|
|
Royalties
|
|
|
(2,284)
|
(1,802)
|
|
|
27%
|
|
|
(4,086)
|
|
|
Transportation expense
|
|
|
(1,052)
|
(422)
|
|
|
149%
|
|
|
(1,474)
|
|
|
Operating expense
|
|
|
(2,043)
|
(1,554)
|
|
|
31%
|
|
|
(3,597)
|
|
|
General and administration
|
|
|
(830)
|
(568)
|
|
|
46%
|
|
|
(1,398)
|
|
|
Current income taxes
|
|
|
(506)
|
(537)
|
|
|
(6%)
|
|
|
(1,043)
|
|
|
Fund flows from operations
|
|
|
4,382
|
4,032
|
|
|
9%
|
|
|
8,414
|
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
45.36
|
55.85
|
|
|
(19%)
|
|
|
49.50
|
|
|
Royalties
|
|
|
(9.34)
|
(11.29)
|
|
|
(17%)
|
|
|
(10.11)
|
|
|
Transportation expense
|
|
|
(4.30)
|
(2.64)
|
|
|
63%
|
|
|
(3.65)
|
|
|
Operating expense
|
|
|
(8.35)
|
(9.74)
|
|
|
(14%)
|
|
|
(8.90)
|
|
|
General and administration
|
|
|
(3.39)
|
(3.56)
|
|
|
(5%)
|
|
|
(3.46)
|
|
|
Current income taxes
|
|
|
(2.07)
|
(3.36)
|
|
|
(38%)
|
|
|
(2.58)
|
|
|
Fund flows from operations netback
|
|
|
17.91
|
25.26
|
|
|
(29%)
|
|
|
20.80
|
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
TTF ($/GJ)
|
|
|
7.91
|
10.19
|
|
|
(22%)
|
|
|
9.02
|
|
|
TTF (€/GJ)
|
|
|
5.27
|
6.75
|
|
|
(22%)
|
|
|
6.01
|
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 for Q2 2014 were 24% higher due to the inclusion of a full quarter
of production in Q2 2014 versus two months of production in Q1 2014.
-
Sales per boe decreased by 19% from Q1 2014 due to a decrease in the TTF
reference price.
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 is billed monthly by the joint venture
operator and is expected to be similar to our Netherlands operating
costs per boe.
General and administration
-
Included in general and administration costs are expenditures totalling
$0.8 million relating to legal and consulting costs associated with the
acquisition.
Current income taxes
-
Current income taxes in Germany apply to taxable income after eligible
deductions at a statutory tax rate of approximately 23%. For 2014, the
effective rate on current taxes is expected to be between approximately
10% and 12%. This rate is subject to change in response to commodity
price fluctuations, the timing of capital expenditures and other
eligible in-country adjustments.
IRELAND BUSINESS UNIT
Overview
-
18.5% non-operating interest in the offshore Corrib gas field located
approximately 83km off the northwest coast of Ireland.
-
Project comprises six offshore wells, both offshore and onshore pipeline
segments as well as a natural gas processing facility.
-
Production from Corrib is expected to increase Vermilion's volumes by
approximately 58 mmcf/d (9,700 boe/d) once the field reaches peak
production.
Operational and financial review
|
|
|
|
|
Three Months Ended
|
|
% change
|
|
|
Six Months Ended
|
|
% change
|
|
Ireland business unit
|
|
|
|
Jun 30,
|
|
|
Mar 31,
|
|
|
Jun 30,
|
|
Q2/14 vs.
|
|
Q2/14 vs.
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
2014 vs.
|
|
($M)
|
|
|
|
2014
|
|
|
2014
|
|
|
2013
|
|
Q1/14
|
|
Q2/13
|
|
|
2014
|
|
|
2013
|
|
2013
|
|
Transportation expense
|
|
|
|
(1,571)
|
|
|
(1,588)
|
|
|
(1,626)
|
|
(1%)
|
|
(3%)
|
|
|
(3,159)
|
|
|
(3,244)
|
|
(3%)
|
|
General and administration
|
|
|
|
(252)
|
|
|
(282)
|
|
|
(410)
|
|
(11%)
|
|
(39%)
|
|
|
(534)
|
|
|
(647)
|
|
(17%)
|
|
Fund flows from operations
|
|
|
|
(1,823)
|
|
|
(1,870)
|
|
|
(2,036)
|
|
(3%)
|
|
(10%)
|
|
|
(3,693)
|
|
|
(3,891)
|
|
(5%)
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
|
27,221
|
|
|
16,236
|
|
|
24,878
|
|
68%
|
|
9%
|
|
|
43,457
|
|
|
41,398
|
|
5%
|
Activity review
-
Completed tunnel boring operations beneath Sruwaddacon Bay on May 21,
2014. The tunnel boring machine has been demobilized and we are
progressing with remaining activities to bring the project on
production, including the installation of flow and umbilical lines
within the tunnel, grouting of the tunnel, and certain offshore well
workover activities.
-
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
|
|
|
Six Months Ended
|
|
% change
|
|
|
|
|
|
Jun 30,
|
|
|
Mar 31,
|
|
|
Jun 30,
|
|
Q2/14 vs.
|
|
Q2/14 vs.
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
2014 vs.
|
|
Australia business unit
|
|
|
|
2014
|
|
|
2014
|
|
|
2013
|
|
Q1/14
|
|
Q2/13
|
|
|
2014
|
|
|
2013
|
|
2013
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
|
6,483
|
|
|
7,110
|
|
|
7,363
|
|
(9%)
|
|
(12%)
|
|
|
6,795
|
|
|
6,331
|
|
7%
|
|
Inventory (mbbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Opening crude oil inventory
|
|
|
|
63
|
|
|
130
|
|
|
165
|
|
|
|
|
|
|
130
|
|
|
268
|
|
|
|
Crude oil production
|
|
|
|
590
|
|
|
640
|
|
|
670
|
|
|
|
|
|
|
1,230
|
|
|
1,146
|
|
|
|
Crude oil sales
|
|
|
|
(464)
|
|
|
(707)
|
|
|
(648)
|
|
|
|
|
|
|
(1,171)
|
|
|
(1,227)
|
|
|
|
Closing crude oil inventory
|
|
|
|
189
|
|
|
63
|
|
|
187
|
|
|
|
|
|
|
189
|
|
|
187
|
|
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
|
|
|
10,991
|
|
|
5,691
|
|
|
8,282
|
|
93%
|
|
33%
|
|
|
16,682
|
|
|
63,631
|
|
(74%)
|
|
Gross wells drilled
|
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
-
|
|
|
2.00
|
|
|
|
Net wells drilled
|
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
-
|
|
|
2.00
|
|
|
Production
-
Wandoo production decreased by 9% quarter-over-quarter and 12%
year-over-year.
-
Production volumes are managed to meet customer demands and long-term
supply agreements. We continue to plan for production levels of
between 6,000 and 8,000 bbls/d.
-
Production continues to reflect strong well results from the 2013
drilling program, more than offsetting natural declines. We continue
to produce the wells at restricted rates below their demonstrated
productive capacity.
Activity review
-
In Q2 2014, efforts were focused on facilities repairs and engineering
studies, including the expansion of accommodation quarters on the
Wandoo B platform and repair of the A5 conductor on Wandoo A.
-
2014 planned activities include ongoing facilities maintenance,
enhancement, and refurbishment along with preparation and permitting
activities in advance of our planned 2015 drilling program.
Financial review
|
|
|
|
Three Months Ended
|
|
% change
|
|
Six Months Ended
|
|
% change
|
|
Australia business unit
|
|
|
Jun 30,
|
|
Mar 31,
|
|
Jun 30,
|
|
Q2/14 vs.
|
|
Q2/14 vs.
|
|
Jun 30,
|
|
Jun 30,
|
|
2014 vs.
|
|
($M except as indicated)
|
|
|
2014
|
|
2014
|
|
2013
|
|
Q1/14
|
|
Q2/13
|
|
2014
|
|
2013
|
|
2013
|
|
Sales
|
|
|
58,828
|
|
89,974
|
|
72,282
|
|
(35%)
|
|
(19%)
|
|
148,802
|
|
142,183
|
|
5%
|
|
Operating expense
|
|
|
(12,051)
|
|
(17,360)
|
|
(9,912)
|
|
(31%)
|
|
22%
|
|
(29,411)
|
|
(24,738)
|
|
19%
|
|
General and administration
|
|
|
(1,661)
|
|
(1,206)
|
|
(1,378)
|
|
38%
|
|
21%
|
|
(2,867)
|
|
(2,896)
|
|
(1%)
|
|
Corporate income taxes
|
|
|
(5,689)
|
|
(8,841)
|
|
(10,646)
|
|
(36%)
|
|
(47%)
|
|
(14,530)
|
|
(17,859)
|
|
(19%)
|
|
PRRT
|
|
|
(12,699)
|
|
(20,239)
|
|
(12,590)
|
|
(37%)
|
|
1%
|
|
(32,938)
|
|
(23,743)
|
|
39%
|
|
Fund flows from operations
|
|
|
26,728
|
|
42,328
|
|
37,756
|
|
(37%)
|
|
(29%)
|
|
69,056
|
|
72,947
|
|
(5%)
|
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
126.87
|
|
127.26
|
|
111.54
|
|
-
|
|
14%
|
|
127.11
|
|
115.89
|
|
10%
|
|
Operating expense
|
|
|
(25.99)
|
|
(24.55)
|
|
(15.30)
|
|
6%
|
|
70%
|
|
(25.12)
|
|
(20.16)
|
|
25%
|
|
General and administration
|
|
|
(3.58)
|
|
(1.71)
|
|
(2.13)
|
|
109%
|
|
68%
|
|
(2.45)
|
|
(2.36)
|
|
4%
|
|
Corporate income taxes
|
|
|
(12.27)
|
|
(12.51)
|
|
(16.43)
|
|
(2%)
|
|
(25%)
|
|
(12.41)
|
|
(14.56)
|
|
(15%)
|
|
PRRT
|
|
|
(27.39)
|
|
(28.63)
|
|
(19.43)
|
|
(4%)
|
|
41%
|
|
(28.14)
|
|
(19.35)
|
|
45%
|
|
Fund flows from operations netback
|
|
|
57.64
|
|
59.86
|
|
58.25
|
|
(4%)
|
|
(1%)
|
|
58.99
|
|
59.46
|
|
(1%)
|
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated Brent (US $/bbl)
|
|
|
109.63
|
|
108.22
|
|
102.44
|
|
1%
|
|
7%
|
|
108.93
|
|
107.50
|
|
1%
|
Sales
-
Our production in Australia currently receives a premium to Dated Brent.
-
Sales per boe increased for the three and six months ended June 30, 2014
versus the comparable periods in the prior year as a result of an
increase in the Dated Brent reference price combined with the impact of
the weakening Canadian dollar.
-
Sales increased for the six months ended June 30, 2014 versus 2013,
despite slightly lower sold volumes, primarily as a result of the
impacts of the weakening of the Canadian dollar, which resulted in a
10% increase in sales per boe.
-
Sales for Q2 2014 versus Q1 2014 and Q2 2013 were 35% and 19% lower,
respectively, primarily as a result of a build in crude oil inventory
(126,000 bbl) during Q2 2014.
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 Q2 2014 remained consistent with the
expense for Q1 2014.
-
Operating expense per boe for the three and six months ended June 30,
2014 was higher than the expense for the comparative periods in the
prior year due to increased diesel usage and higher salary costs.
General and administration
-
General and administration expense increased slightly during Q2 2014 as
compared to Q1 2014 and Q2 2013 due to timing of expenditures.
-
For the year to date period ended June 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 six
months ended June 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
|
|
Six Months Ended
|
|
|
|
|
|
Jun 30,
|
|
|
Mar 31,
|
|
|
Jun 30,
|
|
Jun 30,
|
|
|
Jun 30,
|
|
($M)
|
|
|
|
2014
|
|
|
2014
|
|
|
2013
|
|
2014
|
|
|
2013
|
|
General and administration
|
|
|
|
(2,574)
|
|
|
(3,751)
|
|
|
(1,224)
|
|
(6,325)
|
|
|
(2,912)
|
|
Current income taxes
|
|
|
|
(378)
|
|
|
(173)
|
|
|
(328)
|
|
(551)
|
|
|
(579)
|
|
Interest expense
|
|
|
|
(12,334)
|
|
|
(11,460)
|
|
|
(9,336)
|
|
(23,794)
|
|
|
(18,025)
|
|
Realized gain (loss) on derivatives
|
|
|
|
2,419
|
|
|
2,640
|
|
|
1,770
|
|
5,059
|
|
|
(1,017)
|
|
Realized foreign exchange gain (loss)
|
|
|
|
587
|
|
|
(2,041)
|
|
|
1,272
|
|
(1,454)
|
|
|
655
|
|
Realized other income
|
|
|
|
74
|
|
|
221
|
|
|
77
|
|
295
|
|
|
549
|
|
Fund flows from operations
|
|
|
|
(12,206)
|
|
|
(14,564)
|
|
|
(7,769)
|
|
(26,770)
|
|
|
(21,329)
|
General and administration
-
The decrease in general and administration costs for Q2 2014 versus Q1
2014 was primarily the result of the Q1 2014 impact of certain
outstanding VIP awards to be settled partially in cash.
-
On a year-over-year basis, the increase in general and administration
costs for the six months ended June 30, 2013 to the same period in 2014
was a result of the impact of certain outstanding 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 assisting
in the execution of our capital and development plans.
-
The realized gain in 2014 related primarily to amounts received on our
TTF derivatives, partially offset by payments made on our crude oil and
AECO derivatives.
-
A listing of derivative positions as at June 30, 2014 is included in
"Supplemental Table 2" in this MD&A.
FINANCIAL PERFORMANCE REVIEW
|
|
|
|
|
Three Months Ended
|
|
|
|
|
|
Jun 30,
|
|
Mar 31,
|
|
Dec 31,
|
|
Sep 30,
|
|
Jun 30,
|
|
Mar 31,
|
|
Dec 31,
|
|
Sep 30,
|
|
($M except per share)
|
|
|
|
2014
|
|
2014
|
|
2013
|
|
2013
|
|
2013
|
|
2013
|
|
2012
|
|
2012
|
|
Petroleum and natural gas sales
|
|
|
|
387,684
|
|
81,183
|
|
325,108
|
|
327,185
|
|
311,966
|
|
309,576
|
|
241,233
|
|
284,838
|
|
Net earnings
|
|
|
|
53,993
|
|
102,788
|
|
101,510
|
|
67,796
|
|
106,198
|
|
52,137
|
|
56,914
|
|
30,798
|
|
Net earnings per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
0.51
|
|
1.00
|
|
1.00
|
|
0.67
|
|
1.05
|
|
0.53
|
|
0.58
|
|
0.31
|
|
Diluted
|
|
|
|
0.50
|
|
0.99
|
|
0.98
|
|
0.66
|
|
1.04
|
|
0.51
|
|
0.57
|
|
0.31
|
The following table shows a reconciliation of the change in net
earnings:
|
($M)
|
|
|
|
|
|
Q2/14 vs. Q1/14
|
|
|
|
Q2/14 vs. Q2/13
|
|
|
|
|
2014 vs. 2013
|
|
Net earnings - Comparative period
|
|
|
|
|
|
102,788
|
|
|
|
106,198
|
|
|
|
|
158,335
|
|
Changes in:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fund flows from operations
|
|
|
|
|
|
10,713
|
|
|
|
41,484
|
|
|
|
|
83,218
|
|
Equity based compensation
|
|
|
|
|
|
(1,745)
|
|
|
|
(7,493)
|
|
|
|
|
(7,829)
|
|
Unrealized gain or loss on derivative instruments
|
|
|
|
|
|
(5,456)
|
|
|
|
(10,172)
|
|
|
|
|
(5,124)
|
|
Unrealized foreign exchange gain or loss
|
|
|
|
|
|
(45,746)
|
|
|
|
(51,771)
|
|
|
|
|
(27,252)
|
|
Unrealized other income
|
|
|
|
|
|
358
|
|
|
|
452
|
|
|
|
|
603
|
|
Accretion
|
|
|
|
|
|
(238)
|
|
|
|
50
|
|
|
|
|
162
|
|
Depletion and depreciation
|
|
|
|
|
|
(5,450)
|
|
|
|
(26,484)
|
|
|
|
|
(44,488)
|
|
Deferred tax
|
|
|
|
|
|
(1,231)
|
|
|
|
1,729
|
|
|
|
|
(844)
|
|
Net earnings - Current Period
|
|
|
|
|
|
53,993
|
|
|
|
53,993
|
|
|
|
|
156,781
|
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 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 Vermilion Incentive Plan ("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 six months ended
June 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 is also higher for Q2 2014
as compared to Q1 2014 as the impact of the revision in future
performance condition assumptions was partially offset by awards vested
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 six months ended June 30, 2014, we recognized an unrealized gain
of $2.4 million, relating primarily to our TTF derivative instruments,
partially offset by our crude oil and Canadian natural gas derivative
instruments. As at June 30, 2014, we have a net current derivative
liability of approximately $0.2 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 six months ended June 30, 2014, the Canadian dollar
strengthened versus the Euro resulting in unrealized foreign exchange
losses of $23.7 million and $1.7 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.
Q2 2014 accretion expense was relatively consistent as compared to Q1
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.
Q2 2014 production as compared to Q1 2014 and the comparable periods in
2013 increased by 12%, 22% and 21%, respectively, resulting in higher
depletion and depreciation expense of 5%, 33% and 28%, respectively.
Depletion and depreciation on a per boe basis for Q2 2014 of $22.45/boe
was lower as compared to Q1 2014 of $23.13/boe as a result of increased
production in Canada. Depletion and depreciation on a per boe basis
increased for the three and six month periods ended June 30, 2014 to
$22.45/boe and $22.78/boe, respectively, as compared to the same
periods in 2013 of $20.16/boe and $20.99/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 as 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
|
|
|
|
|
|
|
|
Jun 30,
|
|
Dec 31,
|
|
|
Jun 30,
|
|
Dec 31,
|
|
($M)
|
|
|
|
|
|
2014
|
|
2013
|
|
|
2014
|
|
2013
|
|
Revolving credit facility
|
|
|
|
|
|
3.3%
|
|
3.3%
|
|
|
975,297
|
|
766,898
|
|
Senior unsecured notes
|
|
|
|
|
|
6.5%
|
|
6.5%
|
|
|
223,569
|
|
223,126
|
|
Long-term debt
|
|
|
|
|
|
3.9%
|
|
4.7%
|
|
|
1,198,866
|
|
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
|
|
|
|
|
|
|
|
Jun 30,
|
|
Dec 31,
|
|
|
|
|
|
|
|
2014
|
|
2013
|
|
Total facility amount 1
|
|
|
|
|
|
$1.50 billion
|
|
$1.20 billion
|
|
Amount drawn
|
|
|
|
|
|
$975.3 million
|
|
$766.9 million
|
|
Letters of credit outstanding
|
|
|
|
|
|
$10.2 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
|
|
|
|
|
|
|
|
|
|
Jun 30,
|
|
|
Dec 31,
|
|
Financial covenant
|
|
|
|
Limit
|
|
|
|
2014
|
|
|
2013
|
|
Consolidated total debt to consolidated EBITDA
|
|
|
|
4.0
|
|
|
|
1.17
|
|
|
1.06
|
|
Consolidated total senior debt to consolidated EBITDA
|
|
|
|
3.0
|
|
|
|
0.95
|
|
|
0.82
|
|
Consolidated total senior debt to total capitalization
|
|
|
|
50%
|
|
|
|
30%
|
|
|
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
|
|
|
|
|
|
$225.0 million
|
|
Interest rate
|
|
|
|
|
|
6.5% per annum
|
|
Issued date
|
|
|
|
|
|
February 10, 2011
|
|
Maturity date
|
|
|
|
|
|
February 10, 2016
|
We may redeem all or part of the notes at fixed redemption prices plus
in each case, accrued and unpaid interest, if any, to the applicable
redemption date. The notes were initially recognized at fair value net
of transaction costs and are subsequently measured at amortized cost
using an effective interest rate of 7.1%.
Net debt
Net debt is reconciled to its most directly comparable GAAP measure,
long-term debt, as follows:
|
|
|
|
|
As At
|
|
|
|
|
|
Jun 30,
|
|
Dec 31,
|
|
($M)
|
|
|
|
2014
|
|
2013
|
|
Long-term debt
|
|
|
|
1,198,866
|
|
990,024
|
|
Current liabilities
|
|
|
|
377,710
|
|
347,444
|
|
Current assets
|
|
|
|
(407,578)
|
|
(587,783)
|
|
Net debt
|
|
|
|
1,168,998
|
|
749,685
|
|
|
|
|
|
|
|
|
|
Ratio of net debt to annualized fund flows from operations
|
|
|
|
1.4
|
|
1.1
|
Long-term debt as at June 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 the increase to long-term debt occurred to fund acquisitions, which
contributed to fund flows from operations for only a portion of 2014,
the year-to-date ratio of net debt to annualized fund flows from
operations increased from 1.1 as at December 31, 2013 to 1.4 as at June
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 six months ended June 30, 2014, we maintained monthly
dividends at $0.215 per share and declared dividends totalled $134.7
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
|
|
|
|
601
|
|
|
|
38,034
|
|
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 June 30, 2014
|
|
|
|
106,620
|
|
|
|
1,917,334
|
As at June 30, 2014, there were approximately 1.7 million VIP awards
outstanding. As at July 30, 2014, there were approximately 106.7
million shares outstanding.
ASSET RETIREMENT OBLIGATIONS
As at June 30, 2014, asset retirement obligations were $390.1 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 June 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 pronouncement is currently
being evaluated.
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 June 30, 2014
|
|
Six Months Ended June 30, 2014
|
|
Three Months
Ended June
30, 2013
|
|
Six Months
Ended June
30, 2013
|
|
|
|
Oil & NGLs
|
|
Natural Gas
|
|
Total
|
|
Oil & NGLs
|
|
Natural Gas
|
|
Total
|
|
Total
|
|
Total
|
|
|
|
$/bbl
|
|
$/mcf
|
|
$/boe
|
|
$/bbl
|
|
$/mcf
|
|
$/boe
|
|
$/boe
|
|
$/boe
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
98.82
|
|
4.60
|
|
71.56
|
|
97.30
|
|
5.02
|
|
70.55
|
|
62.00
|
|
59.93
|
|
Royalties
|
|
(11.84)
|
|
(0.30)
|
|
(7.99)
|
|
(11.38)
|
|
(0.32)
|
|
(7.61)
|
|
(5.96)
|
|
(6.07)
|
|
Transportation
|
|
(2.22)
|
|
(0.17)
|
|
(1.76)
|
|
(2.24)
|
|
(0.17)
|
|
(1.75)
|
|
(1.60)
|
|
(1.58)
|
|
Operating
|
|
(9.29)
|
|
(1.55)
|
|
(9.28)
|
|
(10.01)
|
|
(1.37)
|
|
(9.31)
|
|
(9.81)
|
|
(9.68)
|
|
Operating netback
|
|
75.47
|
|
2.58
|
|
52.53
|
|
73.67
|
|
3.16
|
|
51.88
|
|
44.63
|
|
42.60
|
|
General and administration
|
|
|
|
|
|
(2.88)
|
|
|
|
|
|
(2.32)
|
|
(2.42)
|
|
(2.28)
|
|
Fund flows from operations netback
|
|
|
|
|
|
49.65
|
|
|
|
|
|
49.56
|
|
42.21
|
|
40.32
|
|
France
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
117.29
|
|
-
|
|
117.29
|
|
117.41
|
|
-
|
|
117.41
|
|
98.04
|
|
102.84
|
|
Royalties
|
|
(7.34)
|
|
-
|
|
(7.34)
|
|
(7.34)
|
|
-
|
|
(7.34)
|
|
(5.95)
|
|
(5.97)
|
|
Transportation
|
|
(5.07)
|
|
-
|
|
(5.07)
|
|
(4.91)
|
|
-
|
|
(4.91)
|
|
(2.36)
|
|
(2.39)
|
|
Operating
|
|
(15.58)
|
|
-
|
|
(15.58)
|
|
(15.98)
|
|
-
|
|
(15.98)
|
|
(16.53)
|
|
(17.08)
|
|
Operating netback
|
|
89.30
|
|
-
|
|
89.30
|
|
89.18
|
|
-
|
|
89.18
|
|
73.20
|
|
77.40
|
|
General and administration
|
|
|
|
|
|
(5.24)
|
|
|
|
|
|
(5.21)
|
|
(3.83)
|
|
(4.45)
|
|
Current income taxes
|
|
|
|
|
|
(23.30)
|
|
|
|
|
|
(24.25)
|
|
(15.74)
|
|
(16.11)
|
|
Fund flows from operations netback
|
|
|
|
|
|
60.76
|
|
|
|
|
|
59.72
|
|
53.63
|
|
56.84
|
|
Netherlands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
93.76
|
|
7.91
|
|
48.14
|
|
99.23
|
|
9.26
|
|
56.06
|
|
65.08
|
|
63.19
|
|
Royalties
|
|
-
|
|
(0.19)
|
|
(1.12)
|
|
-
|
|
(0.38)
|
|
(2.28)
|
|
-
|
|
-
|
|
Operating
|
|
-
|
|
(1.74)
|
|
(10.29)
|
|
-
|
|
(1.65)
|
|
(9.76)
|
|
(8.93)
|
|
(8.02)
|
|
Operating netback
|
|
93.76
|
|
5.98
|
|
36.73
|
|
99.23
|
|
7.23
|
|
44.02
|
|
56.15
|
|
55.17
|
|
General and administration
|
|
|
|
|
|
(0.53)
|
|
|
|
|
|
(0.73)
|
|
(0.72)
|
|
(0.73)
|
|
Current income taxes
|
|
|
|
|
|
(2.10)
|
|
|
|
|
|
(3.99)
|
|
(16.34)
|
|
(16.55)
|
|
Fund flows from operations netback
|
|
|
|
|
|
34.10
|
|
|
|
|
|
39.30
|
|
39.09
|
|
37.89
|
|
Germany
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
-
|
|
7.56
|
|
45.36
|
|
-
|
|
8.25
|
|
49.50
|
|
-
|
|
-
|
|
Royalties
|
|
-
|
|
(1.56)
|
|
(9.34)
|
|
-
|
|
(1.68)
|
|
(10.11)
|
|
-
|
|
-
|
|
Transportation
|
|
-
|
|
(0.72)
|
|
(4.30)
|
|
-
|
|
(0.61)
|
|
(3.65)
|
|
-
|
|
-
|
|
Operating
|
|
-
|
|
(1.39)
|
|
(8.35)
|
|
-
|
|
(1.48)
|
|
(8.90)
|
|
-
|
|
-
|
|
Operating netback
|
|
-
|
|
3.89
|
|
23.37
|
|
-
|
|
4.48
|
|
26.84
|
|
-
|
|
-
|
|
General and administration
|
|
|
|
|
|
(3.39)
|
|
|
|
|
|
(3.46)
|
|
-
|
|
-
|
|
Current income taxes
|
|
|
|
|
|
(2.07)
|
|
|
|
|
|
(2.58)
|
|
-
|
|
-
|
|
Fund flows from operations netback
|
|
|
|
|
|
17.91
|
|
|
|
|
|
20.80
|
|
-
|
|
-
|
|
Australia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
126.87
|
|
-
|
|
126.87
|
|
127.11
|
|
-
|
|
127.11
|
|
111.54
|
|
115.89
|
|
Operating
|
|
(25.99)
|
|
-
|
|
(25.99)
|
|
(25.12)
|
|
-
|
|
(25.12)
|
|
(15.30)
|
|
(20.16)
|
|
PRRT (1)
|
|
(27.39)
|
|
-
|
|
(27.39)
|
|
(28.14)
|
|
-
|
|
(28.14)
|
|
(19.43)
|
|
(19.35)
|
|
Operating netback
|
|
73.49
|
|
-
|
|
73.49
|
|
73.85
|
|
-
|
|
73.85
|
|
76.81
|
|
76.38
|
|
General and administration
|
|
|
|
|
|
(3.58)
|
|
|
|
|
|
(2.45)
|
|
(2.13)
|
|
(2.36)
|
|
Corporate income taxes
|
|
|
|
|
|
(12.27)
|
|
|
|
|
|
(12.41)
|
|
(16.43)
|
|
(14.56)
|
|
Fund flows from operations netback
|
|
|
|
|
|
57.64
|
|
|
|
|
|
58.99
|
|
58.25
|
|
59.46
|
|
Total Company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
109.89
|
|
6.19
|
|
82.96
|
|
110.73
|
|
7.04
|
|
85.70
|
|
80.21
|
|
81.60
|
|
Realized hedging (loss) gain
|
|
(0.66)
|
|
0.42
|
|
0.52
|
|
(0.21)
|
|
0.32
|
|
0.56
|
|
0.46
|
|
(0.13)
|
|
Royalties
|
|
(8.31)
|
|
(0.44)
|
|
(6.21)
|
|
(7.54)
|
|
(0.51)
|
|
(5.91)
|
|
(4.06)
|
|
(4.15)
|
|
Transportation
|
|
(2.89)
|
|
(0.34)
|
|
(2.57)
|
|
(2.74)
|
|
(0.32)
|
|
(2.44)
|
|
(1.71)
|
|
(1.75)
|
|
Operating
|
|
(14.16)
|
|
(1.59)
|
|
(12.46)
|
|
(15.26)
|
|
(1.49)
|
|
(12.95)
|
|
(12.36)
|
|
(13.21)
|
|
PRRT (1)
|
|
(4.32)
|
|
-
|
|
(2.72)
|
|
(5.79)
|
|
-
|
|
(3.67)
|
|
(3.24)
|
|
(3.12)
|
|
Operating netback
|
|
79.55
|
|
4.24
|
|
59.52
|
|
79.19
|
|
5.04
|
|
61.29
|
|
59.30
|
|
59.24
|
|
General and administration
|
|
|
|
|
|
(3.80)
|
|
|
|
|
|
(3.59)
|
|
(2.91)
|
|
(3.14)
|
|
Interest expense
|
|
|
|
|
|
(2.64)
|
|
|
|
|
|
(2.65)
|
|
(2.40)
|
|
(2.37)
|
|
Realized foreign exchange gain (loss)
|
|
|
|
|
|
0.12
|
|
|
|
|
|
(0.16)
|
|
0.33
|
|
0.09
|
|
Other income
|
|
|
|
|
|
0.02
|
|
|
|
|
|
0.03
|
|
0.02
|
|
0.07
|
|
Corporate income taxes (1)
|
|
|
|
|
|
(6.98)
|
|
|
|
|
|
(7.94)
|
|
(9.44)
|
|
(9.49)
|
|
Fund flows from operations netback
|
|
|
|
|
|
46.24
|
|
|
|
|
|
46.98
|
|
44.90
|
|
44.40
|
|
(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 table summarizes Vermilion's outstanding risk management
positions as at June 30, 2014:
|
|
|
Note
|
|
Volume
|
|
Strike Price(s)
|
|
Crude Oil
|
|
|
|
|
|
|
|
WTI - Swap
|
|
|
|
|
|
|
|
May 2014 - July 2014
|
|
1
|
|
500 bbl/d
|
|
101.12 CAD $
|
|
July 2014 - December 2014
|
|
|
|
750 bbl/d
|
|
99.00 USD $
|
|
July 2014
|
|
|
|
1,000 bbl/d
|
|
99.95 USD $
|
|
July 2014
|
|
2
|
|
1,000 bbl/d
|
|
103.63 USD $
|
|
July 2014 - September 2014
|
|
|
|
1,250 bbl/d
|
|
108.53 CAD $
|
|
July 2014 - September 2014
|
|
3
|
|
1,250 bbl/d
|
|
101.33 USD $
|
|
May 2014 - November 2014
|
|
1
|
|
250 bbl/d
|
|
97.25 CAD $
|
|
Dated Brent - Collar
|
|
|
|
|
|
|
|
April 2014 - September 2014
|
|
|
|
1,000 bbl/d
|
|
105.00 - 112.00 USD $
|
|
April 2014 - December 2014
|
|
|
|
1,000 bbl/d
|
|
106.00 - 110.73 USD $
|
|
Dated Brent - Swap
|
|
|
|
|
|
|
|
January 2014 - December 2014
|
|
|
|
500 bbl/d
|
|
108.28 USD $
|
|
July 2014 - September 2014
|
|
|
|
350 bbl/d
|
|
111.75 USD $
|
|
July 2014 - September 2014
|
|
3
|
|
1,000 bbl/d
|
|
110.00 USD $
|
|
July 2014 - December 2014
|
|
|
|
1,000 bbl/d
|
|
109.64 USD $
|
|
July 2014 - December 2014
|
|
4
|
|
500 bbl/d
|
|
109.40 USD $
|
|
ICE Brent less WTI - Fixed Spread
|
|
|
|
|
|
|
|
July 2014 - September 2014
|
|
|
|
500 bbl/d
|
|
5.99 USD $
|
|
MSW - Fixed Price Differential (Physical)
|
|
|
|
|
|
|
|
April 2014 - December 2014
|
|
|
|
1,030 bbl/d
|
|
WTI less 8.20 USD $
|
|
July 2014 - December 2014
|
|
|
|
2,052 bbl/d
|
|
WTI less 8.68 USD $
|
|
|
|
|
|
|
|
|
|
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 - Swap
|
|
|
|
|
|
|
|
March 2014 - September 2014
|
|
|
|
5,400 GJ/d
|
|
6.62 EUR €
|
|
April 2014 - September 2014
|
|
|
|
16,200 GJ/d
|
|
6.74 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
|
|
|
|
|
|
|
|
July 2014 - September 2014
|
|
|
|
5,000,000 USD $/month
|
|
1.070 - 1.116 CAD $
|
|
July 2014 - September 2014
|
|
5
|
|
4,500,000 USD $/month
|
|
1.077 - 1.099 CAD $
|
|
(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 August 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 December 31, 2014 at the contracted volume and
price.
|
|
(4)
|
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.
|
|
(5)
|
Vermilion has upside participation on this hedge up to the limit price
of 1.152 CAD; above which, settlement will occur at the conditional
call level of 1.099CAD.
|
Supplemental Table 3: Capital Expenditures
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
By classification
|
|
Jun 30,
|
Mar 31,
|
Jun 30,
|
|
Jun 30,
|
Jun 30,
|
|
($M)
|
|
2014
|
2014
|
2013
|
|
2014
|
2013
|
|
Drilling and development
|
|
117,975
|
168,840
|
75,005
|
|
286,815
|
254,525
|
|
Dispositions
|
|
-
|
-
|
-
|
|
-
|
(8,627)
|
|
Exploration and evaluation
|
|
17,098
|
27,535
|
3,113
|
|
44,633
|
12,689
|
|
Capital expenditures
|
|
135,073
|
196,375
|
78,118
|
|
331,448
|
258,587
|
|
Property acquisition
|
|
-
|
178,227
|
-
|
|
178,227
|
-
|
|
Corporate acquisition
|
|
381,139
|
-
|
-
|
|
381,139
|
-
|
|
Acquisitions
|
|
381,139
|
178,227
|
-
|
|
559,366
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
By category
|
|
Jun 30,
|
Mar 31,
|
Jun 30,
|
|
Jun 30,
|
Jun 30,
|
|
($M)
|
|
2014
|
2014
|
2013
|
|
2014
|
2013
|
|
Land
|
|
950
|
4,753
|
2,307
|
|
5,703
|
5,436
|
|
Seismic
|
|
1,869
|
3,432
|
5,569
|
|
5,301
|
9,382
|
|
Drilling and completion
|
|
42,083
|
106,536
|
20,235
|
|
148,619
|
146,420
|
|
Production equipment and facilities
|
|
60,547
|
68,755
|
40,819
|
|
129,302
|
90,761
|
|
Recompletions
|
|
13,459
|
4,226
|
4,510
|
|
17,685
|
8,641
|
|
Other
|
|
16,165
|
8,673
|
4,678
|
|
24,838
|
6,574
|
|
Dispositions
|
|
-
|
-
|
-
|
|
-
|
(8,627)
|
|
Capital expenditures
|
|
135,073
|
196,375
|
78,118
|
|
331,448
|
258,587
|
|
Acquisitions
|
|
381,139
|
178,227
|
-
|
|
559,366
|
-
|
|
Total capital expenditures and acquisitions
|
|
516,212
|
374,602
|
78,118
|
|
890,814
|
258,587
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
By country
|
|
Jun 30,
|
Mar 31,
|
Jun 30,
|
|
Jun 30,
|
Jun 30,
|
|
($M)
|
|
2014
|
2014
|
2013
|
|
2014
|
2013
|
|
Canada
|
|
418,294
|
119,707
|
16,553
|
|
538,001
|
101,682
|
|
France
|
|
37,614
|
37,967
|
23,223
|
|
75,581
|
44,815
|
|
Netherlands
|
|
21,513
|
20,118
|
4,157
|
|
41,631
|
4,529
|
|
Germany
|
|
630
|
173,067
|
-
|
|
173,697
|
-
|
|
Ireland
|
|
27,221
|
16,236
|
24,878
|
|
43,457
|
41,398
|
|
Australia
|
|
10,991
|
5,691
|
8,282
|
|
16,682
|
63,631
|
|
Corporate
|
|
(51)
|
1,816
|
1,025
|
|
1,765
|
2,532
|
|
Total capital expenditures and acquisitions
|
|
516,212
|
374,602
|
78,118
|
|
890,814
|
258,587
|
Supplemental Table 4: Production
|
|
|
Q2/14
|
|
Q1/14
|
|
Q4/13
|
|
Q3/13
|
|
Q2/13
|
|
Q1/13
|
|
Q4/12
|
|
Q3/12
|
|
Q2/12
|
|
Q1/12
|
|
Q4/11
|
|
Q3/11
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
12,676
|
|
9,437
|
|
8,719
|
|
7,969
|
|
8,885
|
|
7,966
|
|
7,983
|
|
7,322
|
|
7,757
|
|
7,574
|
|
6,591
|
|
4,526
|
|
|
NGLs (bbls/d)
|
|
2,796
|
|
2,071
|
|
1,699
|
|
1,897
|
|
1,725
|
|
1,335
|
|
1,106
|
|
1,204
|
|
1,321
|
|
1,302
|
|
1,246
|
|
1,305
|
|
|
Natural gas (mmcf/d)
|
|
57.59
|
|
49.53
|
|
41.43
|
|
43.40
|
|
43.69
|
|
41.04
|
|
31.41
|
|
35.54
|
|
41.32
|
|
41.83
|
|
43.96
|
|
42.94
|
|
|
Total (boe/d)
|
|
25,070
|
|
19,763
|
|
17,322
|
|
17,099
|
|
17,892
|
|
16,140
|
|
14,323
|
|
14,449
|
|
15,965
|
|
15,848
|
|
15,163
|
|
12,987
|
|
|
% of consolidated
|
|
49%
|
|
42%
|
|
43%
|
|
41%
|
|
42%
|
|
41%
|
|
40%
|
|
40%
|
|
40%
|
|
40%
|
|
41%
|
|
38%
|
|
France
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
11,025
|
|
10,771
|
|
11,131
|
|
11,625
|
|
10,390
|
|
10,330
|
|
9,843
|
|
9,767
|
|
9,931
|
|
10,270
|
|
7,819
|
|
7,946
|
|
|
Natural gas (mmcf/d)
|
|
-
|
|
-
|
|
-
|
|
5.23
|
|
4.19
|
|
4.21
|
|
3.91
|
|
3.39
|
|
3.57
|
|
3.48
|
|
0.94
|
|
0.97
|
|
|
Total (boe/d)
|
|
11,025
|
|
10,771
|
|
11,131
|
|
12,496
|
|
11,088
|
|
11,032
|
|
10,495
|
|
10,333
|
|
10,526
|
|
10,850
|
|
7,976
|
|
8,108
|
|
|
% of consolidated
|
|
21%
|
|
23%
|
|
27%
|
|
30%
|
|
26%
|
|
29%
|
|
29%
|
|
28%
|
|
27%
|
|
28%
|
|
22%
|
|
23%
|
|
Netherlands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d)
|
|
96
|
|
69
|
|
62
|
|
48
|
|
50
|
|
96
|
|
70
|
|
41
|
|
84
|
|
72
|
|
66
|
|
64
|
|
|
Natural gas (mmcf/d)
|
|
40.35
|
|
43.15
|
|
37.53
|
|
28.78
|
|
38.52
|
|
36.91
|
|
33.03
|
|
34.59
|
|
33.74
|
|
35.08
|
|
34.58
|
|
33.15
|
|
|
Total (boe/d)
|
|
6,822
|
|
7,260
|
|
6,318
|
|
4,845
|
|
6,470
|
|
6,248
|
|
5,574
|
|
5,806
|
|
5,707
|
|
5,919
|
|
5,829
|
|
5,589
|
|
|
% of consolidated
|
|
13%
|
|
16%
|
|
15%
|
|
12%
|
|
15%
|
|
16%
|
|
15%
|
|
16%
|
|
15%
|
|
15%
|
|
16%
|
|
16%
|
|
Germany
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
|
16.13
|
|
10.64
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
|
Total (boe/d)
|
|
2,689
|
|
1,773
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
|
% of consolidated
|
|
5%
|
|
4%
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
Australia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
6,483
|
|
7,110
|
|
6,189
|
|
7,070
|
|
7,363
|
|
5,287
|
|
5,873
|
|
5,958
|
|
6,970
|
|
6,648
|
|
7,686
|
|
7,992
|
|
|
% of consolidated
|
|
12%
|
|
15%
|
|
15%
|
|
17%
|
|
17%
|
|
14%
|
|
16%
|
|
16%
|
|
18%
|
|
17%
|
|
21%
|
|
23%
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil & NGLs (bbls/d)
|
|
33,076
|
|
29,458
|
|
27,800
|
|
28,609
|
|
28,413
|
|
25,014
|
|
24,875
|
|
24,292
|
|
26,063
|
|
25,866
|
|
23,408
|
|
21,833
|
|
|
% of consolidated
|
|
63%
|
|
63%
|
|
68%
|
|
69%
|
|
66%
|
|
65%
|
|
69%
|
|
66%
|
|
67%
|
|
66%
|
|
64%
|
|
63%
|
|
|
Natural gas (mmcf/d)
|
|
114.08
|
|
103.32
|
|
78.96
|
|
77.41
|
|
86.40
|
|
82.16
|
|
68.34
|
|
73.52
|
|
78.63
|
|
80.39
|
|
79.48
|
|
77.06
|
|
|
% of consolidated
|
|
37%
|
|
37%
|
|
32%
|
|
31%
|
|
34%
|
|
35%
|
|
31%
|
|
34%
|
|
33%
|
|
34%
|
|
36%
|
|
37%
|
|
|
Total (boe/d)
|
|
52,089
|
|
46,677
|
|
40,960
|
|
41,510
|
|
42,813
|
|
38,707
|
|
36,265
|
|
36,546
|
|
39,168
|
|
39,265
|
|
36,654
|
|
34,676
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
YTD 2014
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
11,065
|
|
8,387
|
|
7,659
|
|
4,701
|
|
2,778
|
|
2,137
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d)
|
|
2,435
|
|
1,666
|
|
1,232
|
|
1,297
|
|
1,427
|
|
1,518
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
|
53.58
|
|
42.39
|
|
37.50
|
|
43.38
|
|
43.91
|
|
47.85
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (boe/d)
|
|
22,430
|
|
17,117
|
|
15,142
|
|
13,227
|
|
11,524
|
|
11,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated
|
|
45%
|
|
41%
|
|
40%
|
|
38%
|
|
36%
|
|
37%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
France
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
10,899
|
|
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)
|
|
10,899
|
|
11,440
|
|
10,550
|
|
8,269
|
|
8,501
|
|
8,421
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated
|
|
22%
|
|
28%
|
|
28%
|
|
23%
|
|
26%
|
|
27%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Netherlands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d)
|
|
83
|
|
64
|
|
67
|
|
58
|
|
35
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
|
41.74
|
|
35.42
|
|
34.11
|
|
32.88
|
|
28.31
|
|
21.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (boe/d)
|
|
7,040
|
|
5,967
|
|
5,751
|
|
5,538
|
|
4,753
|
|
3,533
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated
|
|
14%
|
|
15%
|
|
15%
|
|
16%
|
|
15%
|
|
11%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Germany
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
|
13.40
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (boe/d)
|
|
2,234
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated
|
|
5%
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
6,795
|
|
6,481
|
|
6,360
|
|
8,168
|
|
7,354
|
|
7,812
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated
|
|
14%
|
|
16%
|
|
17%
|
|
23%
|
|
23%
|
|
25%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil & NGLs (bbls/d)
|
|
31,277
|
|
27,471
|
|
25,270
|
|
22,334
|
|
19,941
|
|
19,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated
|
|
63%
|
|
67%
|
|
67%
|
|
63%
|
|
62%
|
|
63%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
|
108.73
|
|
81.21
|
|
75.20
|
|
77.21
|
|
73.14
|
|
69.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated
|
|
37%
|
|
33%
|
|
33%
|
|
37%
|
|
38%
|
|
37%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (boe/d)
|
|
49,398
|
|
41,005
|
|
37,803
|
|
35,202
|
|
32,132
|
|
31,395
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Table 5: Segmented Financial Results
|
|
|
Three Months Ended June 30, 2014
|
|
($M)
|
|
Canada
|
|
France
|
|
Netherlands
|
|
Germany
|
|
Ireland
|
|
Australia
|
|
Corporate
|
|
Total
|
|
Drilling and development
|
|
26,071
|
|
34,828
|
|
18,234
|
|
630
|
|
27,221
|
|
10,991
|
|
-
|
|
117,975
|
|
Exploration and evaluation
|
|
10,897
|
|
2,786
|
|
3,279
|
|
-
|
|
-
|
|
-
|
|
136
|
|
17,098
|
|
Oil and gas sales to external customers
|
|
163,261
|
|
124,617
|
|
29,881
|
|
11,097
|
|
-
|
|
58,828
|
|
-
|
|
387,684
|
|
Royalties
|
|
(18,240)
|
|
(7,796)
|
|
(693)
|
|
(2,284)
|
|
-
|
|
-
|
|
-
|
|
(29,013)
|
|
Revenue from external customers
|
|
145,021
|
|
116,821
|
|
29,188
|
|
8,813
|
|
-
|
|
58,828
|
|
-
|
|
358,671
|
|
Transportation expense
|
|
(4,024)
|
|
(5,385)
|
|
-
|
|
(1,052)
|
|
(1,571)
|
|
-
|
|
-
|
|
(12,032)
|
|
Operating expense
|
|
(21,179)
|
|
(16,550)
|
|
(6,390)
|
|
(2,043)
|
|
-
|
|
(12,051)
|
|
-
|
|
(58,213)
|
|
General and administration
|
|
(6,560)
|
|
(5,559)
|
|
(326)
|
|
(830)
|
|
(252)
|
|
(1,661)
|
|
(2,574)
|
|
(17,762)
|
|
PRRT
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(12,699)
|
|
-
|
|
(12,699)
|
|
Corporate income taxes
|
|
-
|
|
(24,761)
|
|
(1,301)
|
|
(506)
|
|
-
|
|
(5,689)
|
|
(378)
|
|
(32,635)
|
|
Interest expense
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(12,334)
|
|
(12,334)
|
|
Realized gain on derivative instruments
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
2,419
|
|
2,419
|
|
Realized foreign exchange gain
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
587
|
|
587
|
|
Realized other income
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
74
|
|
74
|
|
Fund flows from operations
|
|
113,258
|
|
64,566
|
|
21,171
|
|
4,382
|
|
(1,823)
|
|
26,728
|
|
(12,206)
|
|
216,076
|
|
|
|
Six Months Ended June 30, 2014
|
|
($M)
|
|
Canada
|
|
France
|
|
Netherlands
|
|
Germany
|
|
Ireland
|
|
Australia
|
|
Corporate
|
|
Total
|
|
Total assets
|
|
1,854,501
|
|
916,712
|
|
235,723
|
|
174,735
|
|
799,394
|
|
277,624
|
|
125,726
|
|
4,384,415
|
|
Drilling and development
|
|
127,744
|
|
64,681
|
|
33,425
|
|
826
|
|
43,457
|
|
16,682
|
|
-
|
|
286,815
|
|
Exploration and evaluation
|
|
24,163
|
|
10,900
|
|
8,206
|
|
-
|
|
-
|
|
-
|
|
1,364
|
|
44,633
|
|
Oil and gas sales to external customers
|
|
286,441
|
|
242,177
|
|
71,435
|
|
20,012
|
|
-
|
|
148,802
|
|
-
|
|
768,867
|
|
Royalties
|
|
(30,903)
|
|
(15,147)
|
|
(2,901)
|
|
(4,086)
|
|
-
|
|
-
|
|
-
|
|
(53,037)
|
|
Revenue from external customers
|
|
255,538
|
|
227,030
|
|
68,534
|
|
15,926
|
|
-
|
|
148,802
|
|
-
|
|
715,830
|
|
Transportation expense
|
|
(7,122)
|
|
(10,138)
|
|
-
|
|
(1,474)
|
|
(3,159)
|
|
-
|
|
-
|
|
(21,893)
|
|
Operating expense
|
|
(37,789)
|
|
(32,970)
|
|
(12,432)
|
|
(3,597)
|
|
-
|
|
(29,411)
|
|
-
|
|
(116,199)
|
|
General and administration
|
|
(9,428)
|
|
(10,753)
|
|
(924)
|
|
(1,398)
|
|
(534)
|
|
(2,867)
|
|
(6,325)
|
|
(32,229)
|
|
PRRT
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(32,938)
|
|
-
|
|
(32,938)
|
|
Corporate income taxes
|
|
-
|
|
(50,025)
|
|
(5,089)
|
|
(1,043)
|
|
-
|
|
(14,530)
|
|
(551)
|
|
(71,238)
|
|
Interest expense
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(23,794)
|
|
(23,794)
|
|
Realized gain on derivative instruments
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
5,059
|
|
5,059
|
|
Realized foreign exchange loss
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(1,454)
|
|
(1,454)
|
|
Realized other income
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
295
|
|
295
|
|
Fund flows from operations
|
|
201,199
|
|
123,144
|
|
50,089
|
|
8,414
|
|
(3,693)
|
|
69,056
|
|
(26,770)
|
|
421,439
|
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 six months ended June 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
|
|
|
Six Months Ended
|
|
|
|
|
Jun 30,
|
|
Mar 31,
|
|
Jun 30,
|
|
|
Jun 30,
|
|
Jun 30,
|
|
($M)
|
|
|
|
2014
|
|
2014
|
|
2013
|
|
|
2014
|
|
2013
|
|
Cash flows from operating activities
|
|
|
|
149,592
|
|
178,238
|
|
179,074
|
|
|
327,830
|
|
369,786
|
|
Changes in non-cash operating working capital
|
|
|
|
64,103
|
|
24,474
|
|
(6,852)
|
|
|
88,577
|
|
(35,323)
|
|
Asset retirement obligations settled
|
|
|
|
2,381
|
|
2,651
|
|
2,370
|
|
|
5,032
|
|
3,758
|
|
Fund flows from operations
|
|
|
|
216,076
|
|
205,363
|
|
174,592
|
|
|
421,439
|
|
338,221
|
|
Expenses related to Corrib
|
|
|
|
1,823
|
|
1,870
|
|
2,036
|
|
|
3,693
|
|
3,891
|
|
Fund flows from operations (excluding Corrib)
|
|
|
|
217,899
|
|
207,233
|
|
176,628
|
|
|
425,132
|
|
342,112
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
|
Jun 30,
|
Mar 31,
|
Jun 30,
|
|
Jun 30,
|
Jun 30,
|
|
($M)
|
2014
|
2014
|
2013
|
|
2014
|
2013
|
|
Dividends declared
|
68,710
|
66,007
|
60,776
|
|
134,717
|
120,388
|
|
Issuance of shares pursuant to the dividend reinvestment plan
|
(19,149)
|
(18,885)
|
(18,630)
|
|
(38,034)
|
(34,162)
|
|
Net dividends
|
49,561
|
47,122
|
42,146
|
|
96,683
|
86,226
|
|
Drilling and development
|
117,975
|
168,840
|
75,005
|
|
286,815
|
254,525
|
|
Dispositions
|
-
|
-
|
-
|
|
-
|
(8,627)
|
|
Exploration and evaluation
|
17,098
|
27,535
|
3,113
|
|
44,633
|
12,689
|
|
Asset retirement obligations settled
|
2,381
|
2,651
|
2,370
|
|
5,032
|
3,758
|
|
Payout
|
187,015
|
246,148
|
122,634
|
|
433,163
|
348,571
|
|
Corrib drilling and development
|
(27,221)
|
(16,236)
|
(24,878)
|
|
(43,457)
|
(41,398)
|
|
Payout (excluding Corrib)
|
159,794
|
229,912
|
97,756
|
|
389,706
|
307,173
|
|
|
As At
|
('000s of shares)
|
Jun 30,
2014
|
Mar 31,
2014
|
Jun 30,
2013
|
|
Shares outstanding
|
106,620
|
102,453
|
101,418
|
|
Potential shares issuable pursuant to the VIP
|
2,751
|
2,714
|
2,317
|
|
Diluted shares outstanding
|
109,371
|
105,167
|
103,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)
|
|
June 30,
|
December 31,
|
|
|
Note
|
|
2014
|
|
2013
|
|
ASSETS
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
165,497
|
|
389,559
|
|
Accounts receivable
|
|
|
199,251
|
|
167,618
|
|
Crude oil inventory
|
|
|
17,952
|
|
17,143
|
|
Derivative instruments
|
|
|
7,624
|
|
2,285
|
|
Prepaid expenses
|
|
|
17,254
|
|
11,178
|
|
|
|
|
407,578
|
|
587,783
|
|
|
|
|
|
|
|
|
Deferred taxes
|
|
|
148,173
|
|
184,832
|
|
Exploration and evaluation assets
|
5
|
|
332,122
|
|
136,259
|
|
Capital assets
|
4
|
|
3,496,542
|
|
2,799,845
|
|
|
|
|
4,384,415
|
|
3,708,719
|
|
|
|
|
|
|
|
|
LIABILITIES
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
|
264,249
|
|
267,832
|
|
Dividends payable
|
8
|
|
22,923
|
|
20,425
|
|
Derivative instruments
|
|
|
7,787
|
|
3,572
|
|
Income taxes payable
|
|
|
82,751
|
|
55,615
|
|
|
|
|
377,710
|
|
347,444
|
|
|
|
|
|
|
|
|
Long-term debt
|
7
|
|
1,198,866
|
|
990,024
|
|
Asset retirement obligations
|
6
|
|
390,054
|
|
326,162
|
|
Deferred taxes
|
|
|
401,317
|
|
328,714
|
|
|
|
|
2,367,947
|
|
1,992,344
|
|
|
|
|
|
|
|
|
SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
Shareholders' capital
|
8
|
|
1,917,334
|
|
1,618,443
|
|
Contributed surplus
|
|
|
59,343
|
|
75,427
|
|
Accumulated other comprehensive income
|
|
|
49,883
|
|
47,142
|
|
Deficit
|
|
|
(10,092)
|
|
(24,637)
|
|
|
|
|
2,016,468
|
|
1,716,375
|
|
|
|
|
4,384,415
|
|
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
|
|
Six Months Ended
|
|
|
|
|
Jun 30,
|
|
Jun 30,
|
|
Jun 30,
|
|
Jun 30,
|
|
|
Note
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
REVENUE
|
|
|
|
|
|
|
|
|
|
|
Petroleum and natural gas sales
|
|
|
387,684
|
|
311,966
|
|
768,867
|
|
621,542
|
|
Royalties
|
|
|
(29,013)
|
|
(15,800)
|
|
(53,037)
|
|
(31,590)
|
|
Petroleum and natural gas revenue
|
|
|
358,671
|
|
296,166
|
|
715,830
|
|
589,952
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
58,213
|
|
48,082
|
|
116,199
|
|
100,657
|
|
Transportation
|
|
|
12,032
|
|
6,653
|
|
21,893
|
|
13,294
|
|
Equity based compensation
|
9
|
|
18,217
|
|
10,724
|
|
34,689
|
|
26,860
|
|
Gain on derivative instruments
|
|
|
(898)
|
|
(10,421)
|
|
(7,473)
|
|
(6,521)
|
|
Interest expense
|
|
|
12,334
|
|
9,336
|
|
23,794
|
|
18,025
|
|
General and administration
|
|
|
17,762
|
|
11,313
|
|
32,229
|
|
23,923
|
|
Foreign exchange loss (gain)
|
|
|
23,159
|
|
(29,297)
|
|
3,200
|
|
(26,161)
|
|
Other (income) expense
|
|
|
(178)
|
|
271
|
|
(145)
|
|
204
|
|
Accretion
|
6
|
|
5,950
|
|
6,000
|
|
11,662
|
|
11,824
|
|
Depletion and depreciation
|
4, 5
|
|
104,902
|
|
78,418
|
|
204,354
|
|
159,866
|
|
|
|
|
251,493
|
|
131,079
|
|
440,402
|
|
321,971
|
|
EARNINGS BEFORE INCOME TAXES
|
|
|
107,178
|
|
165,087
|
|
275,428
|
|
267,981
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME TAXES
|
|
|
|
|
|
|
|
|
|
|
Deferred
|
|
|
7,851
|
|
9,580
|
|
14,471
|
|
13,627
|
|
Current
|
|
|
45,334
|
|
49,309
|
|
104,176
|
|
96,019
|
|
|
|
|
53,185
|
|
58,889
|
|
118,647
|
|
109,646
|
|
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS
|
|
|
53,993
|
|
106,198
|
|
156,781
|
|
158,335
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER COMPREHENSIVE (LOSS) INCOME
|
|
|
|
|
|
|
|
|
|
|
Currency translation adjustments
|
|
|
(42,794)
|
|
18,955
|
|
2,741
|
|
17,623
|
|
COMPREHENSIVE INCOME
|
|
|
11,199
|
|
125,153
|
|
159,522
|
|
175,958
|
|
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS PER SHARE
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
0.51
|
|
1.05
|
|
1.51
|
|
1.58
|
|
Diluted
|
|
|
0.50
|
|
1.04
|
|
1.49
|
|
1.56
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING ('000s)
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
105,577
|
|
100,964
|
|
103,936
|
|
100,137
|
|
Diluted
|
|
|
107,330
|
|
102,223
|
|
105,531
|
|
101,578
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
|
|
Jun 30,
|
|
Jun 30,
|
|
Jun 30,
|
|
Jun 30,
|
|
|
Note
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
OPERATING
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
|
53,993
|
|
106,198
|
|
156,781
|
|
158,335
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
Accretion
|
6
|
|
5,950
|
|
6,000
|
|
11,662
|
|
11,824
|
|
Depletion and depreciation
|
4, 5
|
|
104,902
|
|
78,418
|
|
204,354
|
|
159,866
|
|
Unrealized loss (gain) on derivative instruments
|
|
|
1,521
|
|
(8,651)
|
|
(2,414)
|
|
(7,538)
|
|
Equity based compensation
|
9
|
|
18,217
|
|
10,724
|
|
34,689
|
|
26,860
|
|
Unrealized foreign exchange loss (gain)
|
|
|
23,746
|
|
(28,025)
|
|
1,746
|
|
(25,506)
|
|
Unrealized other (income) expense
|
|
|
(104)
|
|
348
|
|
150
|
|
753
|
|
Deferred taxes
|
|
|
7,851
|
|
9,580
|
|
14,471
|
|
13,627
|
|
Asset retirement obligations settled
|
6
|
|
(2,381)
|
|
(2,370)
|
|
(5,032)
|
|
(3,758)
|
|
Changes in non-cash operating working capital
|
|
|
(64,103)
|
|
6,852
|
|
(88,577)
|
|
35,323
|
|
Cash flows from operating activities
|
|
|
149,592
|
|
179,074
|
|
327,830
|
|
369,786
|
|
INVESTING
|
|
|
|
|
|
|
|
|
|
|
Drilling and development
|
4
|
|
(117,975)
|
|
(75,005)
|
|
(286,815)
|
|
(254,525)
|
|
Exploration and evaluation
|
5
|
|
(17,098)
|
|
(3,113)
|
|
(44,633)
|
|
(12,689)
|
|
Property acquisitions
|
3, 4, 5
|
|
-
|
|
-
|
|
(178,227)
|
|
-
|
|
Dispositions
|
4
|
|
-
|
|
-
|
|
-
|
|
8,627
|
|
Corporate acquisitions, net of cash acquired
|
3
|
|
(176,179)
|
|
-
|
|
(176,179)
|
|
-
|
|
Changes in non-cash investing working capital
|
|
|
(24,010)
|
|
(75,613)
|
|
15,463
|
|
(37,403)
|
|
Cash flows used in investing activities
|
|
|
(335,262)
|
|
(153,731)
|
|
(670,391)
|
|
(295,990)
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING
|
|
|
|
|
|
|
|
|
|
|
Increase in long-term debt
|
|
|
255,727
|
|
70,000
|
|
205,727
|
|
139,429
|
|
Cash dividends
|
|
|
(48,665)
|
|
(41,754)
|
|
(94,185)
|
|
(84,778)
|
|
Cash flows from financing activities
|
|
|
207,062
|
|
28,246
|
|
111,542
|
|
54,651
|
|
Foreign exchange (loss) gain on cash held in foreign currencies
|
|
|
(7,232)
|
|
5,496
|
|
6,957
|
|
5,026
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
14,160
|
|
59,085
|
|
(224,062)
|
|
133,473
|
|
Cash and cash equivalents, beginning of period
|
|
|
151,337
|
|
176,513
|
|
389,559
|
|
102,125
|
|
Cash and cash equivalents, end of period
|
|
|
165,497
|
|
235,598
|
|
165,497
|
|
235,598
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplementary information for operating activities - cash payments
|
|
|
|
|
|
|
|
|
|
|
Interest paid
|
|
|
11,721
|
|
8,417
|
|
25,815
|
|
20,509
|
|
Income taxes paid
|
|
|
56,486
|
|
18,669
|
|
77,560
|
|
51,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
-
|
|
-
|
|
-
|
|
158,335
|
|
158,335
|
|
Currency translation adjustments
|
|
|
-
|
|
-
|
|
17,623
|
|
-
|
|
17,623
|
|
Equity based compensation expense
|
9
|
|
-
|
|
26,231
|
|
-
|
|
-
|
|
26,231
|
|
Dividends declared
|
8
|
|
-
|
|
-
|
|
-
|
|
(120,388)
|
|
(120,388)
|
|
Shares issued pursuant to the
|
|
|
|
|
|
|
|
|
|
|
|
|
dividend reinvestment plan
|
8
|
|
34,162
|
|
-
|
|
-
|
|
-
|
|
34,162
|
|
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 June 30, 2013
|
|
|
1,580,314
|
|
41,442
|
|
(14,786)
|
|
(71,732)
|
|
1,535,238
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
-
|
|
-
|
|
-
|
|
156,781
|
|
156,781
|
|
Currency translation adjustments
|
|
|
-
|
|
-
|
|
2,741
|
|
-
|
|
2,741
|
|
Equity based compensation expense
|
9
|
|
-
|
|
33,968
|
|
-
|
|
-
|
|
33,968
|
|
Dividends declared
|
8
|
|
-
|
|
-
|
|
-
|
|
(134,717)
|
|
(134,717)
|
|
Shares issued pursuant to the
|
|
|
|
|
|
|
|
|
|
|
|
|
dividend reinvestment plan
|
8
|
|
38,034
|
|
-
|
|
-
|
|
-
|
|
38,034
|
|
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 June 30, 2014
|
|
|
1,917,334
|
|
59,343
|
|
49,883
|
|
(10,092)
|
|
2,016,468
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 SIX MONTHS ENDED JUNE 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
July 30, 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 pronouncement is currently
being evaluated.
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 $20.0 million and net earnings
$0.4 million for the six months ended June 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 six months ended June 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. Vermilion funded this acquisition with
existing credit facilities.
Total consideration was comprised of $180.4 million of cash 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 $16.0 million and operating income of
$13.0 million for the six months ended June 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 $7.0
million for the six months ended June 30, 2014. In determining the
pro-forma amounts, management has assumed that the fair value
adjustments, determined provisionally, that arose at the date of
acquisition would have been the same if the acquisition had occurred on
January 1, 2014. It is impracticable to derive all amounts necessary to
determine the increase to net earnings from the acquisition as the
acquired company was immediately merged with Vermilion's operations.
4. CAPITAL ASSETS
The following table reconciles the change in Vermilion's capital assets:
|
|
Petroleum and
|
Furniture and
|
|
Total
|
|
($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)
|
|
Impairments
|
|
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
|
|
284,616
|
|
2,199
|
|
286,815
|
|
Property acquisitions
|
|
163,599
|
|
|
|
163,599
|
|
Corporate acquisitions
|
|
390,523
|
|
|
|
390,523
|
|
Changes in estimate for asset retirement obligations
|
|
46,998
|
|
|
|
46,998
|
|
Depletion and depreciation
|
|
(199,050)
|
|
(1,908)
|
|
(200,958)
|
|
Effect of movements in foreign exchange rates
|
|
9,632
|
|
88
|
|
9,720
|
|
Balance at June 30, 2014
|
|
3,480,952
|
|
15,590
|
|
3,496,542
|
5. EXPLORATION AND EVALUATION ASSETS
The following table reconciles the change in Vermilion's exploration and
evaluation assets:
|
($M)
|
Exploration and Evaluation Assets
|
|
Balance at January 1, 2013
|
|
117,161
|
|
Additions
|
|
13,789
|
|
Property acquisitions
|
|
9,189
|
|
Transfers to petroleum and natural gas assets
|
|
(1,508)
|
|
Depreciation
|
|
(3,712)
|
|
Effect of movements in foreign exchange rates
|
|
1,340
|
|
Balance at December 31, 2013
|
|
136,259
|
|
Additions
|
|
44,633
|
|
Changes in estimate for asset retirement obligations
|
|
85
|
|
Property acquisitions
|
|
16,662
|
|
Corporate acquisitions
|
|
138,264
|
|
Depreciation
|
|
(3,098)
|
|
Effect of movements in foreign exchange rates
|
|
(683)
|
|
Balance at June 30, 2014
|
|
332,122
|
|
|
|
|
6. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the change in Vermilion's asset
retirement obligations:
|
($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
|
|
|
18,675
|
|
Obligations settled
|
|
|
(5,032)
|
|
Accretion
|
|
|
11,662
|
|
Changes in discount rates
|
|
|
36,412
|
|
Effect of movements in foreign exchange rates
|
|
|
2,175
|
|
Balance at June 30, 2014
|
|
|
390,054
|
7. LONG-TERM DEBT
The following table summarizes Vermilion's outstanding long-term debt:
|
|
As At
|
|
($M)
|
June 30, 2014
|
Dec 31, 2013
|
|
Revolving credit facility
|
|
975,297
|
|
766,898
|
|
Senior unsecured notes
|
|
223,569
|
|
223,126
|
|
Long-term debt
|
|
1,198,866
|
|
990,024
|
Revolving Credit Facility
At June 30, 2014, Vermilion had in place a bank revolving credit
facility totalling $1.5 billion, of which approximately $975.3 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 six months
ended June 30, 2014, the interest rate on the revolving credit facility
was approximately 3.1%.
The amount available to Vermilion under this facility is reduced by
certain outstanding letters of credit associated with Vermilion's
operations totalling $10.2 million as at June 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 June 30, 2014, Vermilion was in compliance with its financial
covenants.
Senior Unsecured Notes
On February 10, 2011, Vermilion issued $225.0 million of senior
unsecured notes at par. The notes bear interest at a rate of 6.5% per
annum and will mature on February 10, 2016. As direct senior unsecured
obligations of Vermilion, the notes rank pari passu with all other
present and future unsecured and unsubordinated indebtedness of the
Company.
Vermilion may redeem all or part of the notes at fixed redemption
prices, plus accrued and unpaid interest, if any, to the applicable
redemption date. The notes were initially recognized at fair value net
of transaction costs and are subsequently measured at amortized cost
using an effective interest rate of 7.1%.
8. SHAREHOLDERS' CAPITAL
The following table reconciles the change in Vermilion's shareholders'
capital:
|
Shareholders' Capital
|
Number of Shares ('000s)
|
|
Amount ($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
|
|
601
|
|
38,034
|
|
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 June 30, 2014
|
|
106,620
|
|
1,917,334
|
Dividends declared to shareholders for the six months ended June 30,
2014 were $134.7 million (2013 - $120.4 million).
Subsequent to the end of the period and prior to the condensed
consolidated interim financial statements being authorized for issue on
July 30, 2014, Vermilion declared dividends totalling $22.9 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
|
563
|
|
832
|
|
Vested
|
(512)
|
|
(749)
|
|
Modified
|
(21)
|
|
-
|
|
Forfeited
|
(21)
|
|
(108)
|
|
Closing balance
|
1,674
|
|
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,
$2.4 million was reclassified from "Contributed surplus" to "Accounts
payable and accrued liabilities". Subsequent period expense relating
to these outstanding awards will be recognized in "General and
administration expense".
10. SEGMENTED INFORMATION
Vermilion has operations principally in Canada, France, the Netherlands,
Germany, Ireland, and Australia. Vermilion's operating activities in
each country relate solely to the exploration, development and
production of petroleum and natural gas. Vermilion has a Corporate
head office located in Calgary, Alberta. Costs incurred in the
Corporate segment relate to Vermilion's global hedging program and
expenses incurred in financing and managing our operating business
units.
Vermilion's chief operating decision maker reviews the financial
performance of the Company by assessing the fund flows from operations
of each country individually. Fund flows from operations provides a
measure of each business unit's ability to generate cash (that is not
subject to short-term movements in non-cash operating working capital)
necessary to pay dividends, fund asset retirement obligations, and make
capital investments.
|
|
Three Months Ended June 30, 2014
|
|
($M)
|
Canada
|
|
France
|
|
Netherlands
|
|
Germany
|
|
Ireland
|
|
Australia
|
|
Corporate
|
|
Total
|
|
Drilling and development
|
26,071
|
|
34,828
|
|
18,234
|
|
630
|
|
27,221
|
|
10,991
|
|
-
|
|
117,975
|
|
Exploration and evaluation
|
10,897
|
|
2,786
|
|
3,279
|
|
-
|
|
-
|
|
-
|
|
136
|
|
17,098
|
|
Oil and gas sales to external customers
|
163,261
|
|
124,617
|
|
29,881
|
|
11,097
|
|
-
|
|
58,828
|
|
-
|
|
387,684
|
|
Royalties
|
(18,240)
|
|
(7,796)
|
|
(693)
|
|
(2,284)
|
|
-
|
|
-
|
|
-
|
|
(29,013)
|
|
Revenue from external customers
|
145,021
|
|
116,821
|
|
29,188
|
|
8,813
|
|
-
|
|
58,828
|
|
-
|
|
358,671
|
|
Transportation expense
|
(4,024)
|
|
(5,385)
|
|
-
|
|
(1,052)
|
|
(1,571)
|
|
-
|
|
-
|
|
(12,032)
|
|
Operating expense
|
(21,179)
|
|
(16,550)
|
|
(6,390)
|
|
(2,043)
|
|
-
|
|
(12,051)
|
|
-
|
|
(58,213)
|
|
General and administration
|
(6,560)
|
|
(5,559)
|
|
(326)
|
|
(830)
|
|
(252)
|
|
(1,661)
|
|
(2,574)
|
|
(17,762)
|
|
PRRT
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(12,699)
|
|
-
|
|
(12,699)
|
|
Corporate income taxes
|
-
|
|
(24,761)
|
|
(1,301)
|
|
(506)
|
|
-
|
|
(5,689)
|
|
(378)
|
|
(32,635)
|
|
Interest expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(12,334)
|
|
(12,334)
|
|
Realized gain on derivative instruments
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
2,419
|
|
2,419
|
|
Realized foreign exchange gain
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
587
|
|
587
|
|
Realized other income
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
74
|
|
74
|
|
Fund flows from operations
|
113,258
|
|
64,566
|
|
21,171
|
|
4,382
|
|
(1,823)
|
|
26,728
|
|
(12,206)
|
|
216,076
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2013
|
|
($M)
|
Canada
|
|
France
|
|
Netherlands
|
|
Germany
|
|
Ireland
|
|
Australia
|
|
Corporate
|
|
Total
|
|
Drilling and development
|
14,059
|
|
23,223
|
|
4,157
|
|
-
|
|
24,878
|
|
8,282
|
|
406
|
|
75,005
|
|
Exploration and evaluation
|
2,494
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
619
|
|
3,113
|
|
Oil and gas sales to external customers
|
100,950
|
|
100,418
|
|
38,316
|
|
-
|
|
-
|
|
72,282
|
|
-
|
|
311,966
|
|
Royalties
|
(9,707)
|
|
(6,093)
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(15,800)
|
|
Revenue from external customers
|
91,243
|
|
94,325
|
|
38,316
|
|
-
|
|
-
|
|
72,282
|
|
-
|
|
296,166
|
|
Transportation expense
|
(2,611)
|
|
(2,416)
|
|
-
|
|
-
|
|
(1,626)
|
|
-
|
|
-
|
|
(6,653)
|
|
Operating expense
|
(15,975)
|
|
(16,935)
|
|
(5,260)
|
|
-
|
|
-
|
|
(9,912)
|
|
-
|
|
(48,082)
|
|
General and administration
|
(3,948)
|
|
(3,927)
|
|
(426)
|
|
-
|
|
(410)
|
|
(1,378)
|
|
(1,224)
|
|
(11,313)
|
|
PRRT
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(12,590)
|
|
-
|
|
(12,590)
|
|
Corporate income taxes
|
-
|
|
(16,124)
|
|
(9,621)
|
|
-
|
|
-
|
|
(10,646)
|
|
(328)
|
|
(36,719)
|
|
Interest expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(9,336)
|
|
(9,336)
|
|
Realized gain on derivative instruments
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
1,770
|
|
1,770
|
|
Realized foreign exchange gain
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
1,272
|
|
1,272
|
|
Realized other income
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
77
|
|
77
|
|
Fund flows from operations
|
68,709
|
|
54,923
|
|
23,009
|
|
-
|
|
(2,036)
|
|
37,756
|
|
(7,769)
|
|
174,592
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2014
|
|
($M)
|
Canada
|
|
France
|
|
Netherlands
|
|
Germany
|
|
Ireland
|
|
Australia
|
|
Corporate
|
|
Total
|
|
Total assets
|
1,854,501
|
|
916,712
|
|
235,723
|
|
174,735
|
|
799,394
|
|
277,624
|
|
125,726
|
|
4,384,415
|
|
Drilling and development
|
127,744
|
|
64,681
|
|
33,425
|
|
826
|
|
43,457
|
|
16,682
|
|
-
|
|
286,815
|
|
Exploration and evaluation
|
24,163
|
|
10,900
|
|
8,206
|
|
-
|
|
-
|
|
-
|
|
1,364
|
|
44,633
|
|
Oil and gas sales to external customers
|
286,441
|
|
242,177
|
|
71,435
|
|
20,012
|
|
-
|
|
148,802
|
|
-
|
|
768,867
|
|
Royalties
|
(30,903)
|
|
(15,147)
|
|
(2,901)
|
|
(4,086)
|
|
-
|
|
-
|
|
-
|
|
(53,037)
|
|
Revenue from external customers
|
255,538
|
|
227,030
|
|
68,534
|
|
15,926
|
|
-
|
|
148,802
|
|
-
|
|
715,830
|
|
Transportation expense
|
(7,122)
|
|
(10,138)
|
|
-
|
|
(1,474)
|
|
(3,159)
|
|
-
|
|
-
|
|
(21,893)
|
|
Operating expense
|
(37,789)
|
|
(32,970)
|
|
(12,432)
|
|
(3,597)
|
|
-
|
|
(29,411)
|
|
-
|
|
(116,199)
|
|
General and administration
|
(9,428)
|
|
(10,753)
|
|
(924)
|
|
(1,398)
|
|
(534)
|
|
(2,867)
|
|
(6,325)
|
|
(32,229)
|
|
PRRT
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(32,938)
|
|
-
|
|
(32,938)
|
|
Corporate income taxes
|
-
|
|
(50,025)
|
|
(5,089)
|
|
(1,043)
|
|
-
|
|
(14,530)
|
|
(551)
|
|
(71,238)
|
|
Interest expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(23,794)
|
|
(23,794)
|
|
Realized gain on derivative instruments
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
5,059
|
|
5,059
|
|
Realized foreign exchange loss
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(1,454)
|
|
(1,454)
|
|
Realized other income
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
295
|
|
295
|
|
Fund flows from operations
|
201,199
|
|
123,144
|
|
50,089
|
|
8,414
|
|
(3,693)
|
|
69,056
|
|
(26,770)
|
|
421,439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2013
|
|
($M)
|
Canada
|
|
France
|
|
Netherlands
|
|
Germany
|
|
Ireland
|
|
Australia
|
|
Corporate
|
|
Total
|
|
Total assets
|
1,105,026
|
|
873,242
|
|
142,317
|
|
-
|
|
646,366
|
|
311,415
|
|
220,641
|
|
3,299,007
|
|
Drilling and development
|
96,800
|
|
44,815
|
|
6,156
|
|
-
|
|
41,398
|
|
63,631
|
|
1,725
|
|
254,525
|
|
Exploration and evaluation
|
11,882
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
807
|
|
12,689
|
|
Oil and gas sales to external customers
|
184,638
|
|
221,984
|
|
72,737
|
|
-
|
|
-
|
|
142,183
|
|
-
|
|
621,542
|
|
Royalties
|
(18,696)
|
|
(12,894)
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(31,590)
|
|
Revenue from external customers
|
165,942
|
|
209,090
|
|
72,737
|
|
-
|
|
-
|
|
142,183
|
|
-
|
|
589,952
|
|
Transportation expense
|
(4,880)
|
|
(5,170)
|
|
-
|
|
-
|
|
(3,244)
|
|
-
|
|
-
|
|
(13,294)
|
|
Operating expense
|
(29,816)
|
|
(36,874)
|
|
(9,229)
|
|
-
|
|
-
|
|
(24,738)
|
|
-
|
|
(100,657)
|
|
General and administration
|
(7,017)
|
|
(9,613)
|
|
(838)
|
|
-
|
|
(647)
|
|
(2,896)
|
|
(2,912)
|
|
(23,923)
|
|
PRRT
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(23,743)
|
|
-
|
|
(23,743)
|
|
Corporate income taxes
|
-
|
|
(34,783)
|
|
(19,055)
|
|
-
|
|
-
|
|
(17,859)
|
|
(579)
|
|
(72,276)
|
|
Interest expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(18,025)
|
|
(18,025)
|
|
Realized loss on derivative instruments
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(1,017)
|
|
(1,017)
|
|
Realized foreign exchange gain
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
655
|
|
655
|
|
Realized other income
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
549
|
|
549
|
|
Fund flows from operations
|
124,229
|
|
122,650
|
|
43,615
|
|
-
|
|
(3,891)
|
|
72,947
|
|
(21,329)
|
|
338,221
|
Reconciliation of fund flows from operations to net earnings
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
Jun 30,
|
Jun 30,
|
|
Jun 30,
|
Jun 30,
|
|
($M)
|
2014
|
2013
|
|
2014
|
2013
|
|
Fund flows from operations
|
216,076
|
174,592
|
|
421,439
|
338,221
|
|
Equity based compensation
|
(18,217)
|
(10,724)
|
|
(34,689)
|
(26,860)
|
|
Unrealized (loss) gain on derivative instruments
|
(1,521)
|
8,651
|
|
2,414
|
7,538
|
|
Unrealized foreign exchange (loss) gain
|
(23,746)
|
28,025
|
|
(1,746)
|
25,506
|
|
Unrealized other income (expense)
|
104
|
(348)
|
|
(150)
|
(753)
|
|
Accretion
|
(5,950)
|
(6,000)
|
|
(11,662)
|
(11,824)
|
|
Depletion and depreciation
|
(104,902)
|
(78,418)
|
|
(204,354)
|
(159,866)
|
|
Deferred taxes
|
(7,851)
|
(9,580)
|
|
(14,471)
|
(13,627)
|
|
Net earnings
|
53,993
|
106,198
|
|
156,781
|
158,335
|
|
|
|
|
|
|
|
11. CAPITAL DISCLOSURES
|
|
Three Months Ended
|
|
Six Months Ended
|
|
($M except as indicated)
|
June 30, 2014
|
June 30, 2013
|
|
June 30, 2014
|
June 30, 2013
|
|
Long-term debt
|
1,198,866
|
780,470
|
|
1,198,866
|
780,470
|
|
Current liabilities
|
377,710
|
325,912
|
|
377,710
|
325,912
|
|
Current assets
|
(407,578)
|
(432,014)
|
|
(407,578)
|
(432,014)
|
|
Net debt [1]
|
1,168,998
|
674,368
|
|
1,168,998
|
674,368
|
|
|
|
|
|
|
|
|
Cash flows from operating activities
|
149,592
|
179,074
|
|
327,830
|
369,786
|
|
Changes in non-cash operating working capital
|
64,103
|
(6,852)
|
|
88,577
|
(35,323)
|
|
Asset retirement obligations settled
|
2,381
|
2,370
|
|
5,032
|
3,758
|
|
Fund flows from operations
|
216,076
|
174,592
|
|
421,439
|
338,221
|
|
Annualized fund flows from operations [2]
|
864,304
|
698,368
|
|
842,878
|
676,442
|
|
|
|
|
|
|
|
|
Ratio of net debt to annualized fund flows from operations ([1] ÷ [2])
|
1.4
|
1.0
|
|
1.4
|
1.0
|
Long-term debt as at June 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 $1.2 billion.
As year-to-date fund flows includes only 2 months of contribution from
the acquisition in Saskatchewan, the ratio of net debt to annualized
fund flows increased to 1.4.
12. FINANCIAL INSTRUMENTS
Classification of Financial Instruments
The following table summarizes information relating to Vermilion's
financial instruments as at June 30, 2014 and December 31, 2013:
|
|
|
|
|
|
As at Jun 30, 2014
|
|
As at Dec 31, 2013
|
|
|
Class of financial
instrument
|
Consolidated balance
sheet caption
|
Accounting
designation
|
Related caption on Statement of Net
Earnings
|
|
Carrying
value ($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)
|
|
165,497
|
|
165,497
|
|
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
|
|
199,251
|
|
199,251
|
|
167,618
|
|
167,618
|
|
Not applicable
|
|
Derivative assets
|
Derivative instruments
|
HFT
|
Gain on derivative instruments
|
|
7,624
|
|
7,624
|
|
2,285
|
|
2,285
|
|
Level 2
|
|
Derivative liabilities
|
Derivative instruments
|
HFT
|
Gain on derivative instruments
|
|
(7,787)
|
|
(7,787)
|
|
(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)
|
|
(287,172)
|
|
(287,172)
|
|
(288,257)
|
|
(288,257)
|
|
Not applicable
|
|
|
|
Dividends payable
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
Long-term debt
|
OTH
|
Interest expense
|
|
(1,198,866)
|
|
(1,207,610)
|
|
(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 six months ended June 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
|
June 30, 2014
|
|
Currency risk - Euro to Canadian
|
Increase in strength of the Canadian dollar against the Euro by 5% over the
relevant closing rates
|
(3,580)
|
|
|
|
|
|
Decrease in strength of the Canadian dollar against the Euro by 5% over the
relevant closing rates
|
3,580
|
|
|
|
|
Currency risk - US $ to Canadian
|
Increase in strength of the Canadian dollar against the US $ by 5% over the
relevant closing rates
|
(2,866)
|
|
|
|
|
|
Decrease in strength of the Canadian dollar against the US $ by 5% over the
relevant closing rates
|
2,866
|
|
|
|
|
|
|
|
|
|
Commodity price risk
|
Increase in relevant oil reference price within option pricing models used to
determine
|
(7,593)
|
|
|
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
|
6,893
|
|
|
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
|
(4,063)
|
|
|
|
|
|
Decrease in average Canadian prime interest rate by 100 basis points during the
relevant periods
|
4,063
|
SOURCE Vermilion Energy Inc.
