CALGARY, Aug. 10, 2015 /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, 2015.
HIGHLIGHTS
-
Average production of 51,831 boe/d for Q2 2015 exceeded prior quarter
production of 50,386 boe/d by 3%. The quarter-over-quarter increase
was primarily due to successful drilling and workovers in France.
Canadian operations also contributed to the production increase through
successful drilling and higher volumes from the commissioning of a
natural gas processing facility in Saskatchewan in the prior quarter.
Partially offsetting these favorable impacts was the planned
maintenance shutdown at our largest natural gas processing facility in
the Netherlands. Mid-stream and facility restrictions in Canada
continued to negatively impact our production volumes in the second
quarter of 2015.
-
Fund flows from operations ("FFO")(1) for Q2 2015 of $129.5 million ($1.18/basic share) represented an
increase of 7% quarter-over-quarter. The increase in FFO from the prior
quarter was attributable to higher oil prices, an inventory draw in
Australia (due to the timing of crude liftings) as well as higher
production in France, Australia and Canada.
-
Following a comprehensive review of 2015 development capital
opportunities, Vermilion has elected to proceed with a two-well
Australian sidetrack program and to also provide modest incremental
capital funding for projects in Canada and France. The Australian
drilling program was previously deferred as part of our reduction in
planned 2015 capital expenditures for exploration and development
("E&D). Despite the recent renewed downturn in oil prices, the strong
economics and operational efficiencies now associated with the
Australia sidetrack program are sufficiently compelling to reinstate
funding for the project. Accordingly, Vermilion now expects E&D
capital spending for 2015 of approximately $485 million, an increase of
$70 million from our previous capital guidance of $415 million (but
less than our original 2015 E&D capital budget of $525 million and 2014
E&D capital expenditures of $688 million). We are maintaining our
original production guidance of between 55,000 and 57,000 boe/d,
assuming a mid-fourth quarter start-up for Corrib natural gas
production and only modest production contributions in late 2015 from
the incremental capital.
-
At our non-operated Corrib project in Ireland, all natural gas terminal
systems have now been commissioned. Following minor remaining
compressor maintenance, operator Shell E&P Ireland Limited ("SEPIL")
expects to declare all wells, facilities and transport systems (both
offshore and onshore) ready for service by the end of August. SEPIL
conducted a workover and production test of the Corrib P2 well during
July, achieving a stabilized flow rate of 107 mmcf/d (17,830 boe/d)(3) gross. The P2 well is expected be tied-in to the subsea production
system during August, providing additional back-up to augment the
deliverability of the other five wells in the Corrib field. With
respect to remaining regulatory approvals, a Final Determination for
the Corrib Industrial Emissions License ("IEL") from the Irish
Environmental Protection Agency ("EPA") and a Ministerial Consent from
Ireland's Department of Communications, Energy and Natural Resources
must be received prior to commencing natural gas production. In
accordance with statutory guidelines on applicable review periods, the
EPA is expected to issue its Final Determination on the IEL on or
before mid-September. We now estimate that the Ministerial Consent
process will be completed, and that production will commence, in the
early-to-mid fourth quarter of 2015. Production at Corrib is expected
to increase over the first six months after first gas to peak
production levels estimated at approximately 58 mmcf/d (approximately
9,700 boe/d), net to Vermilion. While the final regulatory approvals
are taking longer than we expected, we believe that we are very near
the end of the regulatory process for Corrib. Our ability to maintain
our 2015 production guidance (originally set in March 2014), despite
foregoing approximately 3,000 net boe/d of planned calendar year
average production from Corrib, is indicative of the operational and
asset strength of our company. Moreover, we have maintained this
production guidance while reducing 2015 capital expenditures by more
than $200 million (over 30%) from 2014 levels.
-
During the second quarter, we drilled and completed two (1.9 net)
successful extension wells in the Netherlands. These 93% working
interest natural gas wells are located in the province of North
Holland. The first well, Slootdorp-06, targeted the Slochteren
formation of the Rotliegend group, while the second well, Slootdorp-07,
targeted two separate intervals of the Zechstein formation. Gross
stabilized test flow rates(2) were 23.1 mmcf/d (3,850 boe/d) for Slootdorp-06 and 11.9 mmcf/d (2,000
boe/d) and 2.4 mmcf/d (400 boe/d), respectively, for the lower and
upper zones of Slootdorp-07. The two wells are currently on sales at a
combined facility-restricted rate of 21 mmcf/d (3,500 boe/d), net to
Vermilion.
-
In late April, we started production from the successful four (4.0 net)
well program in the Champotran field in the Paris Basin in France,
executed in the first quarter. These wells contributed approximately
800 bbls/d to our second quarter average production rate. This was our
third successive Champotran drilling program since 2013, with a
cumulative total of 13 wells at a 100% success rate.
-
Subsequent to the end of the second quarter, we entered into a
significant farm-in agreement in northwest Germany. The farm-in
provides Vermilion with participating interest in 850,000 net
undeveloped acres in the North German Basin, in exchange for carrying
50% of the costs associated with the drilling and testing of six net
exploration wells over the next five years. The agreement also
provides for the transfer to Vermilion of operatorship for the
exploration phase and data spanning these lands. A large number of
crude oil and natural gas prospects and leads, primarily in the
Rotliegend and Zechstein formations, have been identified on the
lands. The farm-in is consistent with our objective of steadily
increasing our position in the sizable German exploration and
production industry, and represents our first operated position in
Germany. The farm-in remains subject to customary conditions and
regulatory approvals.
-
On June 3, 2015, we were conditionally awarded four exploration blocks
in northeast Croatia near the Hungarian border, by the Croatian
Hydrocarbon Agency. This award remains subject to successful execution
of a definitive contract acceptable to both Vermilion and the
Government of the Republic of Croatia. The four exploration blocks
consist of approximately 2.35 million gross acres with a substantial
portion of the acreage located near existing crude oil and natural gas
fields. Capital commitments on the four blocks are modest and
back-loaded. The initial 5-year exploration period consists of two
phases with an option to relinquish the blocks following the initial
3-year phase. In aggregate, our capital commitments, excluding an
initial bonus payment of €1.3 million, total approximately €7.3 million
over the three-year mandatory phase, followed by an additional €11.6
million during the remaining two-year optional phase.
-
We continue to direct considerable focus to our Profitability
Enhancement Program ("PEP") initiative which supports the long-term
profitability of our business. Prior installments of PEP achieved
strong results in both the 1998 industry downturn and the financial
crisis of 2008-2009. Based on savings identified to-date, our third
installment of PEP will result in cost savings related to capital
spending, operating expense and G&A expenditures estimated at between
$60 and $70 million for full-year 2015.
-
During the quarter, we negotiated a further expansion and extension of
our existing revolving credit facilities from $1.75 billion to $2
billion. In Q1 2015, we had previously increased our credit facility
from $1.5 billion to $1.75 billion. After the most recent expansion to
our credit facility, we have approximately $775 million of borrowing
capacity available. The facility, which matures in May 2019, is fully
revolving up to the date of maturity and is subject to standard form
covenants. We are, and we expect to continue to remain, in compliance
with all applicable debt covenants and expect to maintain our current
dividend of $0.215 per share per month ($2.58 per share per year).
-
During the second quarter, Vermilion was recognized by the Great Place
to Work® Institute as a Best Workplace in Canada and France for the sixth
consecutive year. Vermilion was also recognized for a second
consecutive year as a Best Workplace in the Netherlands in 2015, after
becoming eligible for ranking in 2014. Vermilion is the only energy
company in its category to rank on the Best Workplaces lists in Canada
and the Netherlands, and the highest scoring energy company on the Best
Workplaces list in France.
-
Vermilion was recently ranked 15th by Corporate Knights on the Future 40
Responsible Corporate Leaders in Canada list (the highest ranking for
an oil and gas company, and an increase over the Company's debut
ranking of 32nd last year), and we were also named Top International
Producer of the year by the Explorers and Producers Association of
Canada. This recognition reflects Vermilion's continued focus on
financial results combined with exemplary environmental, social and
governance performance. Strong workplace practices and a culture that
respects both people and communities are key elements in our success.
Please refer to our Sustainability Report at http://www.vermilionenergy.com/sustainability for more information about our environmental and social stewardship.
|
(1)
|
Additional GAAP Financial Measure. Please see the "Additional and
Non-GAAP Financial Measures" section of Management's Discussion and
Analysis.
|
|
(2)
|
Slootdorp-06 (Slochteren) production test was performed over an 18-day
period at a maximum choke of 64/64" with approximately 45% drawdown
over the test period. Slootdorp-07 (lower zone - Z2) production test
was performed over a 4-hour test period at a maximum choke of 36/64"
with approximately 35% drawdown over the test period. Slootdorp-07
(upper zone - Z3) production test was performed over a 12-hour test
period at a maximum choke of 16/64" with approximately 40% drawdown
over the test period. This test result is not necessarily indicative of
long-term performance or of ultimate recovery.
|
|
(3)
|
Corrib P2 well produces from the Sherwood sandstones. The production
test was performed over a 12-hour period at a maximum choke of 80/64",
achieving a peak production rate of 113 mmcf/d and a stabilized flow
rate of 107 mmcf/d with approximately 30% drawdown over the test
period. This test result is not necessarily indicative of long-term
performance or of ultimate recovery.
|
Conference Call and Audio Webcast Details
Vermilion will discuss these results in a conference call to be held on
Monday, August 10, 2015 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 61285178. The replay will be available until midnight mountain
time on August 17, 2015.
You may also listen to the audio webcast by going to http://event.on24.com/r.htm?e=1008324&s=1&k=F4CB45E944014BE7D369F641D1A3B805 or visit Vermilion's website at www.vermilionenergy.com/ir/eventspresentations.cfm.
|
HIGHLIGHTS
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Three Months Ended
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Six Months Ended
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($M except as indicated)
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Jun 30,
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Mar 31,
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Jun 30,
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Jun 30,
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Jun 30,
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Financial
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2015
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2015
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2014
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2015
|
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2014
|
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Petroleum and natural gas sales
|
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264,331
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195,885
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387,684
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460,216
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768,867
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Fund flows from operations (1)
|
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129,496
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120,795
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216,076
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250,291
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421,439
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Fund flows from operations ($/basic share)
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1.18
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1.12
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2.05
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2.31
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4.05
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Fund flows from operations ($/diluted share)
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1.17
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1.11
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2.01
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2.28
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3.99
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Net earnings
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6,813
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1,275
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53,993
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8,088
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156,781
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Net earnings ($/basic share)
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0.06
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0.01
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0.51
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0.07
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1.51
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Capital expenditures
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90,173
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174,311
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135,073
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264,484
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331,448
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Acquisitions
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480
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35
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381,139
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515
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559,366
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Asset retirement obligations settled
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1,218
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3,107
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2,381
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4,325
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5,032
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Cash dividends ($/share)
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0.645
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0.645
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0.645
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1.290
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1.290
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Dividends declared
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70,976
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69,390
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68,710
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140,366
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134,717
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% of fund flows from operations
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55%
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57%
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32%
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56%
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32%
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Net dividends (1)
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28,675
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48,012
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49,561
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76,687
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96,683
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% of fund flows from operations
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22%
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40%
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23%
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31%
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23%
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Payout (1)
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120,066
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225,430
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187,015
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345,496
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433,163
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% of fund flows from operations
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93%
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187%
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87%
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138%
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103%
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% of fund flows from operations (excluding the Corrib project)
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76%
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173%
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73%
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123%
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92%
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Net debt (1)
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1,377,902
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1,388,603
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1,168,998
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1,377,902
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1,168,998
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Ratio of net debt to annualized fund flows from operations (1)
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2.7
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2.9
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1.4
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2.8
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1.4
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Operational
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Production
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Crude oil (bbls/d)
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28,916
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28,181
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30,184
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28,550
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28,759
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NGLs (bbls/d)
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3,867
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3,039
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2,892
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3,455
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2,518
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Natural gas (mmcf/d)
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114.29
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115.00
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114.08
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114.64
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108.73
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Total (boe/d)
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51,831
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50,386
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52,089
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51,113
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49,398
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Average realized prices
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Crude oil and NGLs ($/bbl)
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68.90
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58.25
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109.89
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64.23
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110.73
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Natural gas ($/mcf)
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4.86
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5.26
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6.19
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5.06
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7.04
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Production mix (% of production)
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% priced with reference to WTI
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27%
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28%
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30%
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27%
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27%
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% priced with reference to AECO
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21%
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20%
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18%
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21%
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18%
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% priced with reference to TTF
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16%
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18%
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18%
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17%
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19%
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% priced with reference to Dated Brent
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36%
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34%
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34%
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35%
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36%
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Netbacks ($/boe) (1)
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Operating netback
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36.89
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31.30
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59.52
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34.30
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61.29
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Fund flows from operations netback
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26.76
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29.07
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46.24
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27.83
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46.98
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Operating expenses
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12.12
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10.56
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12.46
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11.40
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12.95
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Average reference prices
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WTI (US $/bbl)
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57.94
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48.63
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102.99
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53.29
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|
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100.84
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Edmonton Sweet index (US $/bbl)
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|
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55.08
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41.83
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|
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96.85
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|
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48.46
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|
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93.65
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Dated Brent (US $/bbl)
|
|
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61.92
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|
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53.97
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|
|
109.63
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|
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57.95
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|
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108.93
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AECO ($/GJ)
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|
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2.52
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|
2.60
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4.44
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|
|
2.56
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|
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4.93
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TTF ($/GJ)
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|
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7.94
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8.25
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|
|
7.91
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|
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8.10
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9.02
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Average foreign currency exchange rates
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|
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|
|
|
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|
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CDN $/US $
|
|
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1.23
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|
|
1.24
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|
|
1.09
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|
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1.24
|
|
|
1.10
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CDN $/Euro
|
|
|
1.36
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|
|
1.40
|
|
|
1.50
|
|
|
1.38
|
|
|
1.50
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Share information ('000s)
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|
Shares outstanding - basic
|
|
|
109,806
|
|
|
107,718
|
|
|
106,620
|
|
|
109,806
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|
|
106,620
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Shares outstanding - diluted(1)
|
|
|
112,626
|
|
|
110,761
|
|
|
109,371
|
|
|
112,626
|
|
|
109,371
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Weighted average shares outstanding - basic
|
|
|
109,319
|
|
|
107,513
|
|
|
105,577
|
|
|
108,421
|
|
|
103,936
|
|
Weighted average shares outstanding - diluted
|
|
|
110,746
|
|
|
109,305
|
|
|
107,330
|
|
|
109,792
|
|
|
105,531
|
|
(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.
|
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
crude 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 crude 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
|
|
HH
|
|
|
Henry Hub, a reference price paid for natural gas in US dollars at
Erath, Louisiana
|
|
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
|
|
NGTL
|
|
|
NOVA Gas Transmission Ltd., a wholly owned subsidiary of TransCanada is
the owner of a gas transmission system known as the NGTL system. The
NGTL system is a 23,500 km pipeline that gathers natural gas for both
use in Alberta, and to deliver it to provincial border points for
export to North American markets.
|
|
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
|
MESSAGE TO SHAREHOLDERS
After appearing to reach some degree of range-bound stability during the
second quarter, crude oil prices have recently come under renewed
pressure as a result of a number of macroeconomic uncertainties.
Although this price environment poses significant challenges for many
energy sector participants, Vermilion remains comparatively
well-positioned given our disciplined approach to financial management
and our commodity diversification. In particular, our exposure to
European natural gas markets, where fundamentals and pricing remain
strong, is a key advantage differentiating Vermilion from its
competitors.
As current European natural gas prices remain nearly triple those in
Canada, a significant part of our strategic focus has been on
maximizing our exposure to this advantageously priced commodity. In
2014, we expanded our European natural gas production by nearly 50%
with our entry into Germany, a producing region with a long history of
development activity and strong market fundamentals. As detailed later
in this Message (see German Farm-In), we have further expanded our
European natural gas opportunities by entering into an 850,000 acre
farm-in in the key German producing basin. In addition, we have
received a conditional award for a 2.35 million acre position in the
underexploited Croatian portion of the Pannonian basin (see Croatian
Exploration Block Award). With continued organic growth in Netherlands
natural gas production, combined with forthcoming natural gas
production from our Corrib project in Ireland, European natural gas
will continue to increase in prominence for Vermilion.
Our international diversification and associated exposure to Brent-based
crude oil pricing continues to favorably distinguish us from our North
America-focused competitors. This advantage is illustrated by the
second quarter's operating netback for our Brent-based crude oil sales
in Australia and France, which was a blended $51.89/boe, as compared to
the operating netback of $48.41/boe for our WTI-based crude oil sales
in North America.
In February 2015, we announced a reduction in our 2015 exploration and
development ("E&D") capital program to $415 million in response to the
significant decrease in crude oil prices that began in mid-2014.
Following a comprehensive review of our E&D capital opportunities, we
have elected to increase our 2015 E&D capital program to $485 million,
an increase of $70 million from our previous capital guidance of $415
million (but less than our original 2015 E&D capital budget of $525
million and 2014 E&D capital expenditures of $688 million). The
majority of this increase is associated with the reinstatement of a
two-well Australia sidetrack program. The strong economics of this
program, coupled with current services pricing advantages and
operational efficiencies associated with drilling the wells outside of
cyclone season, support our decision to proceed with this project.
Vermilion also intends to drill and complete two additional (1.8 net)
Mannville condensate-rich natural gas wells and tie-in a third
Mannville well. Modest incremental funding has been made available for
additional highly economic workovers in France and Canada, and the
revised capital program also reflects a minor increase in capital for
Ireland as we ramp up for first gas production. We remain on target to
achieve our original full year 2015 production guidance of 55,000 to
57,000 boe/d. Based on a mid-fourth quarter start-up for Corrib natural
gas production and only modest production contributions in 2015 from
our incremental capital, we consider it more likely that annual
production will come in closer to the lower end of our guidance range.
This would still represent year-over-year production growth exceeding
10%, supported by consolidated organic production growth in each
successive quarter of 2015.
In late 2014, we initiated a Profitability Enhancement Program ("PEP")
to systematically identify cost savings and efficiency opportunities
company-wide. Prior installments of PEP achieved strong results in
both the 1998 industry downturn and the financial crisis of 2008-2009.
Based on savings identified to-date, this iteration of PEP is expected
to result in cost savings related to capital spending, operating
expense and G&A estimated at between $60 and $70 million for full-year
2015.
Results from our European development activities have exceeded our
expectations. In late April, we started production from the four (4.0
net) wells we drilled in the Champotran field in the Paris Basin in
France in Q1 2015. These wells contributed approximately 800 boe/d to
our second quarter average production rate, and are producing at rates
that are better than anticipated. This was our third drilling program
in the Champotran field since 2013, with a cumulative total of 13
wells, at a 100% success rate. After-tax rates of return associated
with our Champotran oil drilling program remain in excess of 100%(2) at today's oil prices. The remainder of our 2015 capital activities in
France will continue to focus on highly economic workovers and
optimization projects, as well as infrastructure and facility
maintenance. During the second quarter, we successfully restored
approximately 2 mmcf/d (330 boe/d) of shut-in natural gas production
from our Vic Bilh field.
In the Netherlands, we drilled two (1.9 net) wells during the quarter on
the Slootdorp concession, in the province of North Holland. Both wells
were successful, encountering more natural gas pay than expected. The
first well, Slootdorp-06, encountered 70 meters of net natural gas pay
in the Slochteren formation of the Rotliegend group. The second well,
Slootdorp-07, encountered 41 meters of net natural gas pay in two
separate intervals in the Zechstein Carbonate. Gross stabilized test
flow rates(3) were 23.1 mmcf/d (3,850 boe/d) for Slootdorp-06 and 11.9 mmcf/d (2,000
boe/d) and 2.4 mmcf/d (400 boe/d), respectively, for the lower and
upper Zechstein intervals of Slootdorp-07. Both wells are on sales
during an extended production test to size additional production
equipment. The wells are producing at a facility-restricted combined
rate of 21 mmcf/d (3,500 boe/d) net. We completed planned major
facility maintenance at the Garijp Treatment Centre in late June, which
reduced production in the quarter by approximately 2,400 mcf/d (400
boe/d). The shutdown went as intended and the facility returned to
service in late June.
In our non-operated German producing assets, our partner (ExxonMobil
Production Deutschland GmbH) finished drilling and completing the
Burgmoor Z3a well (25% net interest to Vermilion). The well was placed
on production subsequent to the quarter and is currently producing at a
rate of approximately 1.4 mmcf/d (230 boe/d), net to Vermilion.
At our non-operated Corrib project in Ireland, all natural gas terminal
systems have now been commissioned. Following minor remaining
compressor maintenance, operator Shell E&P Ireland Limited ("SEPIL")
expects to declare all wells, facilities and transport systems (both
offshore and onshore) ready for service by the end of August. SEPIL
conducted a workover and production test of the Corrib P2 well during
July, achieving a stabilized flow rate of 107 mmcf/d (17,830 boe/d)(4) gross. The P2 well is expected to be tied-in to the subsea production
system during August, providing additional back-up to augment the
deliverability of the other five wells in the Corrib field. With
respect to remaining regulatory approvals, a Final Determination for
the Corrib Industrial Emissions License ("IEL") from the Irish
Environmental Protection Agency ("EPA") and a Ministerial Consent from
Ireland's Department of Communications, Energy and Natural Resources
must be received prior to commencing natural gas production. In
accordance with statutory guidelines on applicable review periods, the
EPA is expected to issue its Final Determination on the IEL on or
before mid-September. We now estimate that the Ministerial Consent
process will be completed, and that production will commence, in the
early-to-mid fourth quarter of 2015. Production at Corrib is expected
to increase over the first six months after first gas to peak
production levels estimated at approximately 58 mmcf/d (approximately
9,700 boe/d), net to Vermilion.
While the final regulatory approvals are taking longer than we expected,
we believe that we are very near the end of the regulatory process for
Corrib. Our ability to maintain our 2015 production guidance
(originally set in March 2014), despite foregoing approximately 3,000
net boe/d of planned calendar year average production from Corrib, is
indicative of the operational and asset strength of our company.
Moreover, we have maintained this production guidance while reducing
2015 capital expenditures by more than $200 million (over 30%) from
2014 levels. Upon commencement, Corrib production will further increase
Vermilion's exposure to advantageously priced European natural gas.
With the compelling opportunities inherent in our overseas business
units, and the significant operating flexibility offered by our
Canadian asset base, planned activity levels for Canada in 2015 are
less than in prior years. That being said, our Canadian opportunities
continue to offer robust economics with the Cardium light-oil resource
play generating capital investment rates of return of approximately 30%(2). Results to-date have been strong, with better-than-forecasted
production volumes on our two-mile extended reach horizontal wells. In
Q1 2015, we participated in the drilling of only seven (3.1 net)
Cardium wells, which represented our planned Cardium drilling
activities for 2015 (compared to 30 to 50 net wells in previous years).
During Q2, we focused predominately on the completion and tie-in of
previously drilled wells. Our Mannville condensate-rich conventional
natural gas play remains the most economic play in our Canadian
portfolio with current rates of return in excess of 100%(2). During Q1 2015, we participated in drilling 13 (8.9 net) wells
followed by an additional one (0.5 net) well in Q2. In total, we plan
on drilling approximately 30 (17.8 net) Mannville wells in 2015.
During the second quarter, we also concluded a significant
infrastructure project that included the expansion of a compressor
station as well as the construction of a 22 km pipeline. This
infrastructure will play a critical role in supporting the continued
growth of the Mannville play. In Saskatchewan, we had previously
reduced our drilling activity to five (4.1 net) wells for 2015, all of
which were drilled in the first quarter. New well results in our
downdip Midale play in southeast Saskatchewan have been better than we
expected at the time we entered this area in 2014. Duvernay drilling
activities have been deferred to beyond 2015 as we monitor the
performance of our two appraisal wells drilled in 2014. In Alberta, we
continue to be negatively impacted by plant capacity restrictions and
interruptible service curtailments on the NGTL system, with
approximately 1,700 boe/d of production offline during the second
quarter.
In the United States, we drilled one gross (1 net) well in our Turner
Sand resource play in the eastern Powder River Basin during the second
quarter. We expect to complete this well during the third quarter of
2015.
To maintain financial flexibility in this commodity price environment,
we further increased our existing revolving credit facilities from
$1.75 billion to $2 billion during the second quarter. Taking into
account this most recent expansion to our credit facility, we have
approximately $775 million of borrowing capacity available. The
facility, which matures in May 2019, is fully revolving up to the date
of maturity and is subject to standard form covenants (discussed in the
"Financial Position Review" section of our MD&A). We are, and we
expect to continue to remain, in compliance with all applicable debt
covenants, and expect to maintain our current dividend of $0.215 per
share per month ($2.58 per share per year). We currently anticipate
our balance sheet leverage to remain at current levels assuming
consistent commodity prices, and then to naturally de-lever with the
addition of FFO from our Corrib asset starting in the fourth quarter of
2015 and into 2016. While our current debt-to-cash flow ratio is higher
than our targeted levels, it remains lower than the average debt ratio
of our peer group. Our conservative financial management continues to
provide us with the flexibility to manage our business effectively and
provide continued growth and returns for shareholders in this
challenging price environment.
During Q2, Vermilion was pleased to announce that for a sixth
consecutive year, it has been recognized by the Great Place to Work®
Institute as a Best Workplace in Canada and France. Vermilion was also
recognized for a second consecutive year as a Best Workplace in the
Netherlands in 2015, after becoming eligible for ranking in 2014.
Vermilion is the only energy company in its category to rank on the
Best Workplaces lists in Canada and the Netherlands, and the highest
scoring energy company on the Best Workplaces list in France.
Vermilion was recently ranked 15th by Corporate Knights on the Future 40
Responsible Corporate Leaders in Canada list (the highest ranking for
an oil and gas company, and improved from our debut ranking of 32nd
last year). We were also named Top International Producer of the year
by the Explorers and Producers Association of Canada. This recognition
reflects Vermilion's continued focus on achieving robust shareholder
returns combined with environmental, social and governance performance.
Our non-financial initiatives and performance are also articulated in
the Company's annual Carbon Disclosure Project (CDP) submissions and in
our Sustainability Report (http://www.vermilionenergy.com/sustainability). Strong workplace practices and a culture that respects both people
and communities are key elements in our success.
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. In spite of the challenges posed
by the current business environment, we continue to believe that
Vermilion is situated for long-term, diversified growth. We remain
confident that the assets in our portfolio can support organic growth
for future years, and in the current environment, we also find
ourselves well positioned to take advantage of potential acquisition
activity in both North American and international markets. Our
long-term focus on the creation of real value through our technical
capabilities, combined with our conservative financial approach and
patience, should allow us to compete and transact for the benefit of
our existing shareholders if suitable opportunities arise.
German Farm-In
Subsequent to the end of the second quarter, we entered into a
definitive farm-in agreement (the "Farm-in" or the "Agreement") with
Mobil Erdgas-Erdӧl GmbH ("MEEG") and BEB Erdgas und Erdӧl GmbH & Co.KG
("BEB"). MEEG is 100% held by ExxonMobil and BEB is jointly held by
ExxonMobil and Royal Dutch Shell. ExxonMobil Production Deutschland
GmbH ("EMPG") currently operates and manages both MEEG's and BEB's
interests in the exploration licenses involved in the Farm-in. The
Agreement, signed July 27, 2015 and with an anticipated closing date of
January 1, 2016, remains subject to customary conditions and regulatory
approvals.
The Farm-in will provide Vermilion participating interest in 19 onshore
exploration licenses in northwest Germany, comprising approximately
850,000 net acres of oil and natural gas rights (100% undeveloped) (the
"Assets"). Under the terms of the Agreement, Vermilion will acquire
the Assets (which represent 50% of MEEG's and BEB's current interests
in these licenses) in exchange for committing to the financial carry of
the remaining 50% of MEEG's and BEB's interests in 11 gross (6 net)
exploratory wells over the next five years. At present, approximately
75 exploratory and semi-exploratory leads and prospects have been
identified in the Rotliegend, Carboniferous, Triassic and Zechstein
formations on these lands. Eleven of the 19 licenses are currently
operated by EMPG, which will transfer operatorship for the exploration
phase to Vermilion. The Agreement also grants Vermilion proportional
ownership to EMPG proprietary data spanning the Assets. No existing
oil or natural gas production is being acquired by Vermilion in the
Farm-in.
The Farm-in provides Vermilion with a large, nearly contiguous land
block in the heart of the North German Basin. This basin has
cumulative production of more than two billion barrels of oil and 34
trillion cubic feet of natural gas since its discovery, representing
approximately 97% of Germany's historical onshore production. We
believe that the Assets are prospective for both oil and natural gas.
The Farm-in follows our entry in early 2014 into the exploration and
production business in Germany, a jurisdiction with a long history of
oil and natural gas development activity, a consistent fiscal framework
and low political risk. The Assets are a natural and synergistic
expansion to our existing German and Netherlands portfolios, and share
the same subsurface genre and development approach. We believe that
our capability in conventional oil and natural gas exploration and
production in onshore Europe, coupled with our track record of
accretive European consolidation, positions us for future development
and expansion opportunities in both Germany and the greater European
region.
Croatian Exploration Block Award
On June 3, 2015, we were conditionally awarded four exploration blocks
in northeast Croatia near the Hungarian border, by the Croatian
Hydrocarbon Agency. This award remains subject to successful execution
of a definitive contract acceptable to both Vermilion and the
Government of the Republic of Croatia. The four exploration blocks
consist of approximately 2.35 million gross acres with a substantial
portion of the acreage located near existing crude oil and natural gas
fields. Capital commitments on the four blocks are modest and
back-loaded. The initial 5-year exploration period consists of two
phases with an option to relinquish the blocks following the initial
3-year phase. In aggregate, our capital commitments, excluding an
initial bonus payment of €1.3 million, total approximately €7.3 million
over the three-year mandatory phase, followed by an additional €11.6
million during the remaining two-year optional phase.
|
(1)
|
The above discussion includes additional GAAP and non-GAAP measures
which may not be comparable to other companies. Please see the
"ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of Management's
Discussion and Analysis.
|
|
(2)
|
Economics calculated using the following commodity price deck
assumptions: $50/bbl WTI; $55/bbl Dated Brent; $2.85/mmbtu AECO;
CAD/USD 1.30; CAD/EUR 1.40.
|
|
(3)
|
Slootdorp-06 (Slochteren) production test was performed over an 18-day
test period at a maximum choke of 64/64" with approximately 45%
drawdown over the test period. Slootdorp-07 (lower zone - Z2)
production test was performed over a 4-hour test period at a maximum
choke of 36/64" with approximately 35% drawdown over the test period.
Slootdorp-07 (upper zone - Z3) production test was performed over a
12-hour test period at a maximum choke of 16/64" with approximately 40%
drawdown over the test period. This test result is not necessarily
indicative of long-term performance or of ultimate recovery.
|
|
(4)
|
Corrib P2 well produces from the Sherwood sandstones. The production
test was performed over a 12-hour period at a maximum choke of 80/64",
achieving a peak production rate of 113 mmcf/d and a stabilized flow
rate of 107 mmcf/d with approximately 30% drawdown over the test
period. This test result is not necessarily indicative of long-term
performance or of ultimate recovery.
|
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is Management's Discussion and Analysis ("MD&A"), dated
August 6, 2015, of Vermilion Energy Inc.'s ("Vermilion", "We", "Our",
"Us" or the "Company") operating and financial results as at and for
the three and six months ended June 30, 2015 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, 2015 and the audited consolidated financial
statements for the year ended December 31, 2014 and 2013, 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, 2015 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 North America, 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
Corrib offshore natural gas field.
-
Australia business unit: Relates to our operations in the Wandoo
offshore crude oil field.
-
United States business unit: Relates to our operations in Wyoming in the
Powder River Basin.
-
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.
GUIDANCE
We first issued 2015 capital expenditure guidance of $525 million on
December 8, 2014. We subsequently adjusted our 2015 capital
expenditure guidance to $415 million on February 27, 2015, in response
to the continued weakness in commodity prices. That reduction
reflected lower planned activity levels, including the deferral of our
Australian drilling campaign. On August 10, 2015 we announced an
increase in our capital expenditure guidance of $70 million to $485
million following the reinstatement of the Australian drilling campaign
as well as additional funding for projects in Canada, France and
Ireland. We are maintaining our previous production guidance of
55,000-57,000 boe/d, albeit towards the lower end of our guidance range
due to later-than-originally expected first gas from Corrib.
The following table summarizes our 2015 guidance:
|
|
|
|
|
Date
|
|
|
|
|
|
Capital Expenditures ($MM)
|
|
|
|
|
|
Production (boe/d)
|
|
2015 - Guidance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015 Guidance
|
|
|
|
December 8, 2014
|
|
|
|
|
|
525
|
|
|
|
|
|
55,000 to 57,000
|
|
2015 Guidance
|
|
|
|
February 27, 2015
|
|
|
|
|
|
415
|
|
|
|
|
|
55,000 to 57,000
|
|
2015 Guidance
|
|
|
|
August 10, 2015
|
|
|
|
|
|
485
|
|
|
|
|
|
55,000 to 57,000
|
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, 2015, 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
|
|
|
|
$2.58
|
|
|
|
$7.41
|
|
|
|
$11.97
|
|
Capital appreciation per Vermilion share
|
|
|
|
-$20.30
|
|
|
|
$7.98
|
|
|
|
$20.28
|
|
Total return per Vermilion share
|
|
|
|
-23.9%
|
|
|
|
33.5%
|
|
|
|
95.8%
|
|
Annualized total return per Vermilion share
|
|
|
|
-23.9%
|
|
|
|
10.1%
|
|
|
|
14.4%
|
|
Annualized total return on the S&P TSX High Income Energy Index
|
|
|
|
-32.2%
|
|
|
|
-2.9%
|
|
|
|
0.4%
|
|
(1)
|
The above table includes non-GAAP financial measures which may not be
comparable to other companies. Please see the
"ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of this MD&A.
|
CONSOLIDATED RESULTS OVERVIEW
|
|
|
|
|
Three Months Ended
|
|
|
% change
|
|
|
Six Months Ended
|
|
|
% change
|
|
|
|
|
|
Jun 30,
|
|
|
Mar 31,
|
|
|
Jun 30,
|
|
|
Q2/15 vs.
|
|
|
Q2/15 vs.
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
|
2015 vs.
|
|
|
|
|
|
2015
|
|
|
2015
|
|
|
2014
|
|
|
Q1/15
|
|
|
Q2/14
|
|
|
2015
|
|
|
2014
|
|
|
2014
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
28,916
|
|
|
28,181
|
|
|
30,184
|
|
|
3%
|
|
|
(4%)
|
|
|
28,550
|
|
|
28,759
|
|
|
(1%)
|
|
|
NGLs (bbls/d)
|
|
|
3,867
|
|
|
3,039
|
|
|
2,892
|
|
|
27%
|
|
|
34%
|
|
|
3,455
|
|
|
2,518
|
|
|
37%
|
|
|
Natural gas (mmcf/d)
|
|
|
114.29
|
|
|
115.00
|
|
|
114.08
|
|
|
(1%)
|
|
|
-
|
|
|
114.64
|
|
|
108.73
|
|
|
5%
|
|
|
Total (boe/d)
|
|
|
51,831
|
|
|
50,386
|
|
|
52,089
|
|
|
3%
|
|
|
-
|
|
|
51,113
|
|
|
49,398
|
|
|
3%
|
|
|
Build (draw) in inventory (mbbl)
|
|
|
(121)
|
|
|
383
|
|
|
67
|
|
|
|
|
|
|
|
|
262
|
|
|
(31)
|
|
|
|
|
Financial metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fund flows from operations ($M)
|
|
|
129,496
|
|
|
120,795
|
|
|
216,076
|
|
|
7%
|
|
|
(40%)
|
|
|
250,291
|
|
|
421,439
|
|
|
(41%)
|
|
|
Per share ($/basic share)
|
|
|
1.18
|
|
|
1.12
|
|
|
2.05
|
|
|
5%
|
|
|
(42%)
|
|
|
2.31
|
|
|
4.05
|
|
|
(43%)
|
|
|
Net earnings ($M)
|
|
|
6,813
|
|
|
1,275
|
|
|
53,993
|
|
|
434%
|
|
|
(87%)
|
|
|
8,088
|
|
|
156,781
|
|
|
(95%)
|
|
|
Per share ($/basic share)
|
|
|
0.06
|
|
|
0.01
|
|
|
0.51
|
|
|
500%
|
|
|
(88%)
|
|
|
0.07
|
|
|
1.51
|
|
|
(95%)
|
|
|
Cash flows from operating activities ($M)
|
|
|
134,668
|
|
|
22,647
|
|
|
149,592
|
|
|
495%
|
|
|
(10%)
|
|
|
157,315
|
|
|
327,830
|
|
|
(52%)
|
|
|
Net debt ($M)
|
|
|
1,377,902
|
|
|
1,388,603
|
|
|
1,168,998
|
|
|
(1%)
|
|
|
18%
|
|
|
1,377,902
|
|
|
1,168,998
|
|
|
18%
|
|
|
Cash dividends ($/share)
|
|
|
0.645
|
|
|
0.645
|
|
|
0.645
|
|
|
-
|
|
|
-
|
|
|
1.290
|
|
|
1.290
|
|
|
-
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
|
|
90,173
|
|
|
174,311
|
|
|
135,073
|
|
|
(48%)
|
|
|
(33%)
|
|
|
264,484
|
|
|
331,448
|
|
|
(20%)
|
|
|
Acquisitions ($M)
|
|
|
480
|
|
|
35
|
|
|
381,139
|
|
|
1,271%
|
|
|
(100%)
|
|
|
515
|
|
|
559,366
|
|
|
(100%)
|
|
|
Gross wells drilled
|
|
|
5.00
|
|
|
29.00
|
|
|
13.00
|
|
|
|
|
|
|
|
|
34.00
|
|
|
37.00
|
|
|
|
|
|
Net wells drilled
|
|
|
3.61
|
|
|
20.04
|
|
|
6.72
|
|
|
|
|
|
|
|
|
23.65
|
|
|
25.55
|
|
|
|
Operational review
-
Recorded consolidated average production of 51,831 boe/d during Q2 2015,
which was a 3% increase over Q1 2015 as a result of production growth
in France and Canada driven primarily by new wells on production,
partially offset by decreased production in the Netherlands due to
planned facility maintenance. As compared to Q2 2014, production
remained relatively consistent. Steady production, coupled with a draw
in inventory of 121,000 bbls in Q2 2015, resulted in higher volumes
sold versus the comparable quarters.
-
Increased consolidated average production to 51,113 for the six months
ended June 30, 2015, a 3% increase versus the same period in 2014
primarily due to production growth in Canada and France, partially
offset by decreased production in the Netherlands and Australia. In
Canada, production growth of 9% year-over-year was achieved through
continued development of the Cardium and Mannville plays in Alberta,
combined with six months of production from southeast Saskatchewan, as
compared to two months of production included in the 2014 period
following our acquisition in April 2014 of Elkhorn Resources Inc. In
France, production increased 12% following our successful Champotran
drilling program and workovers, as well as the resumption of a portion
of previously shut-in natural gas production at Vic Bilh. These
increases were offset by production decreases in the Netherlands and
Australia due to the planned maintenance shutdown at our largest gas
processing facility in the Netherlands, as well as active management to
control inventory levels and meet marketing schedules in Australia.
-
Activity during the quarter included capital expenditures totalling
$90.2 million, evenly distributed between Canada, Ireland, France, and
the Netherlands. In Canada, capital expenditures totalling $21.9
million were 81% lower than the $114.8 million incurred in Q1 2015 due
to spring breakup and were related to facility work and the drilling of
one (0.5 net) well compared to 16.0 net wells in Q1 2015. In France,
capital expenditures totalled $16.7 million with activity focused on
the completion of the Champotran drilling campaign and accretive
workovers. In Ireland, capital expenditures of $20.3 million were
incurred, the majority of which related to facility commissioning and
subsurface activities. In the Netherlands, capital expenditures of
$18.9 million were significantly higher than the $4.3 million incurred
in Q1 2015 and related to the drilling of 1.9 net wells, while no wells
were drilled in Q1 2015.
Financial review
Net earnings
-
Net earnings for Q2 2015 were $6.8 million ($0.06/basic share) as
compared to net earnings of $1.3 million ($0.01/basic share) in Q1
2015. The increase is attributable to higher petroleum and natural gas
sales driven by higher commodity prices and higher sales volumes, as
well as a $7.2 million gain on derivative instruments (compared to a
loss of $13.7 million in Q1 2015). These increases were partially
offset by higher operating costs and depletion and depreciation, both
of which were driven by inventory drawdowns in Australia, and the
absence of the Q1 2015 recognition of the recovery of costs in France.
In Q1 2015, Vermilion recognized $31.8 million (before taxes) following
a judgment which awarded Vermilion costs incurred as a result of an oil
spill at the Ambès oil terminal in France that occurred in 2007 shortly
after Vermilion acquired the asset.
-
Net earnings for the three and six months ended June 30, 2015 decreased
by $47.2 million and $148.7 million, respectively, versus the
comparative periods in 2014. These decreases were driven primarily by
lower petroleum and natural gas sales as a result of lower commodity
prices, and were partially offset by decreases in royalties and taxes.
In the six months ended June 30, 2015, the decrease in net earnings was
also minimized by the recovery of costs in France recognized in Q1
2015.
Cash flows from operating activities
-
Cash flows from operating activities increased as compared to Q1 2015,
driven primarily by higher volumes sold and higher realized prices, as
well as significant timing differences pertaining to working capital.
-
Cash flows from operating activities decreased by 10% and 52% for the
three and six months ended June 30, 2015, respectively, versus the
comparable periods in 2014. The decreases primarily related to lower
sales due to lower commodity prices, partially offset by timing
differences pertaining to working capital, foreign exchange gains and
lower royalties.
Fund flows from operations
-
Generated fund flows from operations of $129.5 million during Q2 2015,
an increase of 7% versus Q1 2015. This quarter-over-quarter increase
was the result of higher sales, driven by higher volumes and prices,
and lower tax expense. This was partially offset by higher operating
expenses, as well as the absence of the recovery of costs resulting
from the oil spill at the Ambès terminal in France that occurred in
2007, which was recognized in Q1 2015.
-
Fund flows from operations decreased 40% and 41% for the three and six
months ended June 30, 2015, respectively, versus the comparable periods
in 2014. These decreases were primarily driven by lower crude oil
pricing, partially offset by higher sold volumes in Australia (due to
an inventory draw in Q2 2015), as well as favorable royalty and tax
variances, consistent with lower commodity prices. The decrease in
fund flows from operations for the six months ended June 30, 2015, was
further minimized by the previously mentioned recovery of costs in
France.
Net debt
-
Net debt increased by $112.3 million to $1.38 billion for the period
ended June 30, 2015 due to capital expenditures in Canada and Ireland
coupled with the decrease in fund flows from operations, driven by
weaker commodity prices in the first half of 2015.
Dividends
-
Declared dividends remained consistent at $0.215 per common share per
month during the second quarter of 2015, totalling $0.645 per common
share and $1.290 per common share for the three and six months ended
June 30, 2015, respectively.
COMMODITY PRICES
|
|
|
|
Three Months Ended
|
|
|
% change
|
|
|
Six Months Ended
|
|
|
% change
|
|
|
|
|
Jun 30,
|
|
|
Mar 31,
|
|
|
Jun 30,
|
|
|
Q2/15 vs.
|
|
|
Q2/15 vs.
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
|
2015 vs.
|
|
|
|
|
2015
|
|
|
2015
|
|
|
2014
|
|
|
Q1/15
|
|
|
Q2/14
|
|
|
2015
|
|
|
2014
|
|
|
2014
|
|
Average reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl)
|
|
|
57.94
|
|
|
48.63
|
|
|
102.99
|
|
|
19%
|
|
|
(44%)
|
|
|
53.29
|
|
|
100.84
|
|
|
(47%)
|
|
Edmonton Sweet index (US $/bbl)
|
|
|
55.08
|
|
|
41.83
|
|
|
96.85
|
|
|
32%
|
|
|
(43%)
|
|
|
48.46
|
|
|
93.65
|
|
|
(48%)
|
|
Dated Brent (US $/bbl)
|
|
|
61.92
|
|
|
53.97
|
|
|
109.63
|
|
|
15%
|
|
|
(44%)
|
|
|
57.95
|
|
|
108.93
|
|
|
(47%)
|
|
AECO ($/GJ)
|
|
|
2.52
|
|
|
2.60
|
|
|
4.44
|
|
|
(3%)
|
|
|
(43%)
|
|
|
2.56
|
|
|
4.93
|
|
|
(48%)
|
|
TTF ($/GJ)
|
|
|
7.94
|
|
|
8.25
|
|
|
7.91
|
|
|
(4%)
|
|
|
-
|
|
|
8.10
|
|
|
9.02
|
|
|
(10%)
|
|
TTF (€/GJ)
|
|
|
5.84
|
|
|
5.91
|
|
|
5.27
|
|
|
(1%)
|
|
|
11%
|
|
|
5.87
|
|
|
6.01
|
|
|
(2%)
|
|
Average foreign currency exchange rates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CDN $/US $
|
|
|
1.23
|
|
|
1.24
|
|
|
1.09
|
|
|
(1%)
|
|
|
13%
|
|
|
1.24
|
|
|
1.10
|
|
|
13%
|
|
CDN $/Euro
|
|
|
1.36
|
|
|
1.40
|
|
|
1.50
|
|
|
(3%)
|
|
|
(9%)
|
|
|
1.38
|
|
|
1.50
|
|
|
(8%)
|
|
Average realized prices ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
40.59
|
|
|
35.81
|
|
|
71.56
|
|
|
13%
|
|
|
(43%)
|
|
|
38.24
|
|
|
70.55
|
|
|
(46%)
|
|
France
|
|
|
71.96
|
|
|
64.33
|
|
|
117.29
|
|
|
12%
|
|
|
(39%)
|
|
|
68.52
|
|
|
117.41
|
|
|
(42%)
|
|
Netherlands
|
|
|
47.63
|
|
|
48.60
|
|
|
48.14
|
|
|
(2%)
|
|
|
(1%)
|
|
|
48.13
|
|
|
56.06
|
|
|
(14%)
|
|
Germany
|
|
|
43.31
|
|
|
45.21
|
|
|
45.36
|
|
|
(4%)
|
|
|
(5%)
|
|
|
44.27
|
|
|
49.50
|
|
|
(11%)
|
|
Australia
|
|
|
80.87
|
|
|
83.80
|
|
|
126.87
|
|
|
(3%)
|
|
|
(36%)
|
|
|
81.60
|
|
|
127.11
|
|
|
(36%)
|
|
United States
|
|
|
60.57
|
|
|
48.79
|
|
|
-
|
|
|
24%
|
|
|
100%
|
|
|
54.07
|
|
|
-
|
|
|
100%
|
|
Consolidated
|
|
|
54.65
|
|
|
47.17
|
|
|
82.96
|
|
|
16%
|
|
|
(34%)
|
|
|
51.19
|
|
|
85.70
|
|
|
(40%)
|
|
Production mix (% of production)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% priced with reference to WTI
|
|
|
27%
|
|
|
28%
|
|
|
30%
|
|
|
|
|
|
|
|
|
27%
|
|
|
27%
|
|
|
|
|
% priced with reference to AECO
|
|
|
21%
|
|
|
20%
|
|
|
18%
|
|
|
|
|
|
|
|
|
21%
|
|
|
18%
|
|
|
|
|
% priced with reference to TTF
|
|
|
16%
|
|
|
18%
|
|
|
18%
|
|
|
|
|
|
|
|
|
17%
|
|
|
19%
|
|
|
|
|
% priced with reference to Dated Brent
|
|
|
36%
|
|
|
34%
|
|
|
34%
|
|
|
|
|
|
|
|
|
35%
|
|
|
36%
|
|
|
|
Reference prices
-
Evidence of slowing production growth and stronger demand helped support
oil prices in the second quarter of 2015. Compared to Q1 2015, the
three months ended June 30, 2015 showed a 19% increase for WTI and a
15% increase for Dated Brent.
-
The second quarter of 2015 proved to be a particularly strong quarter
for Edmonton Sweet index pricing as strong refining demand and
maintenance work combined to tighten supply/demand fundamentals. For
the three months ending June 30, 2015, the Edmonton Sweet index was up
32% versus the previous quarter, but was still 43% lower
year-over-year.
-
AECO natural gas prices were relatively flat quarter-over-quarter, but
were below last year's levels. AECO averaged C$2.52/GJ in Q2 2015,
which is just 3% lower than the previous three months, but 43% lower
year-over-year.
-
TTF natural gas averaged just slightly lower in Q2 2015 versus Q1 2015
despite seasonal dynamics. Lower inventories and maintenance were the
main factors that helped to keep TTF natural gas prices firm throughout
the second quarter, ending just 1% lower quarter-over-quarter and 11%
higher versus the same quarter last year in Euro terms.
-
Despite a rather volatile quarter, the Canadian dollar averaged nearly
the same in Q2 2015 as in Q1 2015 versus the US dollar at 1.23
CDN$/US$. The low commodity price environment and broader US dollar
strength continues to limit Canadian dollar strength; however, versus
the Euro, the Canadian dollar posted a modest increase
quarter-over-quarter. In Q2 2015, the CDN $/Euro averaged 1.36 versus
1.40 in Q1 2015 and 1.50 in Q2 2014.
Realized prices
-
Consolidated realized price increased by 16% for Q2 2015 as compared to
Q1 2015. This increase was the result of improving crude oil pricing,
coupled with relatively consistent natural gas pricing.
-
Consolidated realized price for the three and six months ended June 30,
2015 decreased by 34% and 40%, respectively, as compared to the
comparable periods in 2014. These decreases were driven by a decrease
in crude oil pricing, as well as a decrease in North American natural
gas pricing.
FUND FLOWS FROM OPERATIONS
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
|
Jun 30, 2015
|
|
|
Mar 31, 2015
|
|
|
Jun 30, 2014
|
|
|
Jun 30, 2015
|
|
|
Jun 30, 2014
|
|
|
|
|
$M
|
|
|
$/boe
|
|
|
$M
|
|
|
$/boe
|
|
|
$M
|
|
|
$/boe
|
|
|
$M
|
|
|
$/boe
|
|
|
$M
|
|
|
$/boe
|
|
Petroleum and natural gas sales
|
|
|
264,331
|
|
|
54.65
|
|
|
195,885
|
|
|
47.17
|
|
|
387,684
|
|
|
82.96
|
|
|
460,216
|
|
|
51.19
|
|
|
768,867
|
|
|
85.70
|
|
Royalties
|
|
|
(16,111)
|
|
|
(3.33)
|
|
|
(16,424)
|
|
|
(3.95)
|
|
|
(29,013)
|
|
|
(6.21)
|
|
|
(32,535)
|
|
|
(3.62)
|
|
|
(53,037)
|
|
|
(5.91)
|
|
Petroleum and natural gas revenues
|
|
|
248,220
|
|
|
51.32
|
|
|
179,461
|
|
|
43.22
|
|
|
358,671
|
|
|
76.75
|
|
|
427,681
|
|
|
47.57
|
|
|
715,830
|
|
|
79.79
|
|
Transportation expense
|
|
|
(10,883)
|
|
|
(2.25)
|
|
|
(9,540)
|
|
|
(2.30)
|
|
|
(12,032)
|
|
|
(2.57)
|
|
|
(20,423)
|
|
|
(2.27)
|
|
|
(21,893)
|
|
|
(2.44)
|
|
Operating expense
|
|
|
(58,616)
|
|
|
(12.12)
|
|
|
(43,851)
|
|
|
(10.56)
|
|
|
(58,213)
|
|
|
(12.46)
|
|
|
(102,467)
|
|
|
(11.40)
|
|
|
(116,199)
|
|
|
(12.95)
|
|
General and administration
|
|
|
(14,505)
|
|
|
(3.00)
|
|
|
(13,560)
|
|
|
(3.27)
|
|
|
(17,762)
|
|
|
(3.80)
|
|
|
(28,065)
|
|
|
(3.12)
|
|
|
(32,229)
|
|
|
(3.59)
|
|
PRRT
|
|
|
(3,371)
|
|
|
(0.70)
|
|
|
(2,354)
|
|
|
(0.57)
|
|
|
(12,699)
|
|
|
(2.72)
|
|
|
(5,725)
|
|
|
(0.64)
|
|
|
(32,938)
|
|
|
(3.67)
|
|
Corporate income taxes
|
|
|
(17,344)
|
|
|
(3.59)
|
|
|
(17,623)
|
|
|
(4.24)
|
|
|
(32,635)
|
|
|
(6.98)
|
|
|
(34,967)
|
|
|
(3.89)
|
|
|
(71,238)
|
|
|
(7.94)
|
|
Interest expense
|
|
|
(14,550)
|
|
|
(3.01)
|
|
|
(13,298)
|
|
|
(3.20)
|
|
|
(12,334)
|
|
|
(2.64)
|
|
|
(27,848)
|
|
|
(3.10)
|
|
|
(23,794)
|
|
|
(2.65)
|
|
Realized gain on derivative instruments
|
|
|
3,081
|
|
|
0.64
|
|
|
6,257
|
|
|
1.51
|
|
|
2,419
|
|
|
0.52
|
|
|
9,338
|
|
|
1.04
|
|
|
5,059
|
|
|
0.56
|
|
Realized foreign exchange (loss) gain
|
|
|
(2,740)
|
|
|
(0.57)
|
|
|
3,306
|
|
|
0.78
|
|
|
587
|
|
|
0.12
|
|
|
566
|
|
|
0.06
|
|
|
(1,454)
|
|
|
(0.16)
|
|
Realized other income
|
|
|
204
|
|
|
0.04
|
|
|
31,997
|
|
|
7.70
|
|
|
74
|
|
|
0.02
|
|
|
32,201
|
|
|
3.58
|
|
|
295
|
|
|
0.03
|
|
Fund flows from operations
|
|
|
129,496
|
|
|
26.76
|
|
|
120,795
|
|
|
29.07
|
|
|
216,076
|
|
|
46.24
|
|
|
250,291
|
|
|
27.83
|
|
|
421,439
|
|
|
46.98
|
The following table shows a reconciliation of the change in fund flows
from operations:
|
($M)
|
|
|
|
Q2/15 vs. Q1/15
|
|
|
|
Q2/15 vs. Q2/14
|
|
|
|
|
2015 vs. 2014
|
|
Fund flows from operations - Comparative period
|
|
|
|
120,795
|
|
|
|
216,076
|
|
|
|
|
421,439
|
|
Sales volume variance:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
1,950
|
|
|
|
(10,845)
|
|
|
|
|
15,826
|
|
|
France
|
|
|
|
12,285
|
|
|
|
6,751
|
|
|
|
|
(1,469)
|
|
|
Netherlands
|
|
|
|
(2,407)
|
|
|
|
(5,585)
|
|
|
|
|
(12,187)
|
|
|
Germany
|
|
|
|
(313)
|
|
|
|
30
|
|
|
|
|
4,606
|
|
|
Australia
|
|
|
|
38,956
|
|
|
|
29,345
|
|
|
|
|
(31,213)
|
|
|
United States
|
|
|
|
(127)
|
|
|
|
677
|
|
|
|
|
1,349
|
|
Pricing variance on sold volumes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI
|
|
|
|
12,700
|
|
|
|
(50,424)
|
|
|
|
|
(108,609)
|
|
|
AECO
|
|
|
|
(1,118)
|
|
|
|
(10,708)
|
|
|
|
|
(24,490)
|
|
|
Dated Brent
|
|
|
|
7,474
|
|
|
|
(81,710)
|
|
|
|
|
(141,350)
|
|
|
TTF
|
|
|
|
(954)
|
|
|
|
(884)
|
|
|
|
|
(11,114)
|
|
Changes in:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties
|
|
|
|
313
|
|
|
|
12,902
|
|
|
|
|
20,502
|
|
|
Transportation
|
|
|
|
(1,343)
|
|
|
|
1,149
|
|
|
|
|
1,470
|
|
|
Operating expense
|
|
|
|
(14,765)
|
|
|
|
(403)
|
|
|
|
|
13,732
|
|
|
General and administration
|
|
|
|
(945)
|
|
|
|
3,257
|
|
|
|
|
4,164
|
|
|
PRRT
|
|
|
|
(1,017)
|
|
|
|
9,328
|
|
|
|
|
27,213
|
|
|
Corporate income taxes
|
|
|
|
279
|
|
|
|
15,291
|
|
|
|
|
36,271
|
|
|
Interest
|
|
|
|
(1,252)
|
|
|
|
(2,216)
|
|
|
|
|
(4,054)
|
|
|
Realized derivatives
|
|
|
|
(3,176)
|
|
|
|
662
|
|
|
|
|
4,279
|
|
|
Realized foreign exchange
|
|
|
|
(6,046)
|
|
|
|
(3,327)
|
|
|
|
|
2,020
|
|
|
Realized other income
|
|
|
|
(31,793)
|
|
|
|
130
|
|
|
|
|
31,906
|
|
Fund flows from operations - Current period
|
|
|
|
129,496
|
|
|
|
129,496
|
|
|
|
|
250,291
|
Fund flows from operations of $129.5 million during Q2 2015 represented
an increase of 7% versus Q1 2015. This quarter-over-quarter increase
was principally the result of higher sales volumes and stronger crude
oil pricing. Sales increased by $68.4 million, which included a $50.3
million sales volumes variance driven by increased sales in Australia
($39.0 million) and France ($12.3 million). Both Australia and France
were impacted by inventory variances, where Australia had an inventory
draw of 162,000 bbls (as compared to a build of 281,000 bbls) and
France's inventory increased by 41,000 bbls (as compared to a build of
102,000 bbls). The increase in fund flows from operations was further
impacted by an $18.1 million favorable pricing variance driven by
higher crude oil prices. Higher sold volumes and crude oil pricing was
partially offset by higher operating expenses resulting from the
recognition of inventoried operating costs in Australia, as well as the
absence of the previously mentioned recovery of costs in France.
Fund flows from operations decreased by 40% and 41% for the three and
six months ended June 30, 2015, respectively, versus the comparable
periods in the prior year. This decrease was primarily driven by
unfavorable crude oil and natural gas pricing variances, partially
offset by favorable royalty and tax variances. For the three months
ended June 30, 2015, the decrease in fund flows from operations was
further offset by a favorable sales variance of $20.4 million driven by
increased sold volume in Australia. For the six months ended June 30,
2015, the decrease in fund flows from operations was further impacted
by a $23.1 million unfavorable sales variance, driven by a build in
inventory of 262,000 bbls (as compared to a draw of 31,000 bbls in the
comparative period), partially offset by the previously mentioned
recovery of costs in France.
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 the 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,
|
|
|
Q2/15 vs.
|
|
|
Q2/15 vs.
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
|
2015 vs.
|
|
Canada business unit
|
|
|
|
2015
|
|
|
2015
|
|
|
2014
|
|
|
Q1/15
|
|
|
Q2/14
|
|
|
2015
|
|
|
2014
|
|
|
2014
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
|
10,182
|
|
|
10,893
|
|
|
12,676
|
|
|
(7%)
|
|
|
(20%)
|
|
|
10,535
|
|
|
11,065
|
|
|
(5%)
|
|
|
NGLs (bbls/d)
|
|
|
|
3,755
|
|
|
2,976
|
|
|
2,796
|
|
|
26%
|
|
|
34%
|
|
|
3,367
|
|
|
2,435
|
|
|
38%
|
|
|
Natural gas (mmcf/d)
|
|
|
|
64.66
|
|
|
61.78
|
|
|
57.59
|
|
|
5%
|
|
|
12%
|
|
|
63.23
|
|
|
53.58
|
|
|
18%
|
|
|
Total (boe/d)
|
|
|
|
24,713
|
|
|
24,165
|
|
|
25,070
|
|
|
2%
|
|
|
(1%)
|
|
|
24,441
|
|
|
22,430
|
|
|
9%
|
|
Production mix (% of total)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
|
41%
|
|
|
45%
|
|
|
51%
|
|
|
|
|
|
|
|
|
43%
|
|
|
49%
|
|
|
|
|
|
NGLs
|
|
|
|
15%
|
|
|
12%
|
|
|
11%
|
|
|
|
|
|
|
|
|
14%
|
|
|
11%
|
|
|
|
|
|
Natural gas
|
|
|
|
44%
|
|
|
43%
|
|
|
38%
|
|
|
|
|
|
|
|
|
43%
|
|
|
40%
|
|
|
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
|
|
|
21,881
|
|
|
114,849
|
|
|
36,968
|
|
|
(81%)
|
|
|
(41%)
|
|
|
136,730
|
|
|
151,907
|
|
|
(10%)
|
|
|
Acquisitions ($M)
|
|
|
|
384
|
|
|
35
|
|
|
381,326
|
|
|
|
|
|
|
|
|
419
|
|
|
386,094
|
|
|
|
|
|
Gross wells drilled
|
|
|
|
1.00
|
|
|
25.00
|
|
|
9.00
|
|
|
|
|
|
|
|
|
26.00
|
|
|
29.00
|
|
|
|
|
|
Net wells drilled
|
|
|
|
0.50
|
|
|
16.04
|
|
|
3.29
|
|
|
|
|
|
|
|
|
16.54
|
|
|
18.26
|
|
|
|
Production
-
Production in Canada increased by 2% quarter-over-quarter and decreased
by 1% year-over-year. Year-to-date average production increased by 9%,
primarily attributable to strong organic production growth in our
Mannville condensate-rich gas resource play and production associated
with our acquisition of Elkhorn Resources Inc. completed in April 2014.
Q2 2015 volumes were negatively impacted by approximately 1,700 boe/d
of production offline as a result of plant capacity restrictions and
interruptible service curtailments on the NGTL system. We anticipate
having the majority of the curtailed volumes online during Q3 2015 with
full productive capability expected to be achieved during Q4 2015.
-
Cardium production averaged more than 9,300 boe/d in Q2 2015, a 5%
decrease quarter-over-quarter, with some non-operated volume currently
constrained due to pipeline restrictions.
-
Mannville production averaged more than 5,600 boe/d in Q2 2015, a 15%
increase quarter-over-quarter. As with Cardium production,
non-operated Mannville volume was constrained due to pipeline
restrictions.
-
Production from our southeast Saskatchewan assets averaged approximately
3,300 boe/d in Q2 2015, an increase of 15% quarter-over-quarter
attributable to increased natural gas and NGL sales. The North Portal
Gas Plant was commissioned late in Q1 2015. The plant will enable the
processing of approximately 5,500 mcf/d (920 boe/d) net of natural gas
which was previously being flared.
Activity review
-
Vermilion participated in the drilling of one (0.5 net) non-operated
well during Q2 2015.
Cardium
-
During Q2 2015, three (1.5 net) non-operated wells were brought on
production.
-
In 2015, we plan to drill or participate in seven (3.1 net) wells
executed in Q1 2015, and complete, equip and tie-in an additional 8.2
net wells which were drilled in 2014.
Mannville
-
During Q2 2015, we completed four (3.5 net) operated wells and brought
three (3.0 net) operated wells on production. We also participated in
the drilling of one (0.5 net) non-operated well and one (0.4 net)
non-operated well was placed on production.
-
In 2015, we expect to drill or participate in approximately 30 (17.8
net) wells and complete, equip and tie-in an additional 1.0 net well
which was drilled in 2014.
Saskatchewan
-
We drilled and brought on production five (4.1 net) operated Midale
wells during Q1 2015, completing our 2015 drilling activity in
Saskatchewan.
Financial review
|
|
|
|
|
Three Months Ended
|
|
|
% change
|
|
|
Six Months Ended
|
|
|
% change
|
|
Canada business unit
|
|
|
Jun 30,
|
|
|
Mar 31,
|
|
|
Jun 30,
|
|
|
Q2/15 vs.
|
|
|
Q2/15 vs.
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
|
2015 vs.
|
|
($M except as indicated)
|
|
|
2015
|
|
|
2015
|
|
|
2014
|
|
|
Q1/15
|
|
|
Q2/14
|
|
|
2015
|
|
|
2014
|
|
|
2014
|
|
|
Sales
|
|
|
91,284
|
|
|
77,884
|
|
|
163,261
|
|
|
17%
|
|
|
(44%)
|
|
|
169,168
|
|
|
286,441
|
|
|
(41%)
|
|
|
Royalties
|
|
|
(5,768)
|
|
|
(8,592)
|
|
|
(18,240)
|
|
|
(33%)
|
|
|
(68%)
|
|
|
(14,360)
|
|
|
(30,903)
|
|
|
(54%)
|
|
|
Transportation expense
|
|
|
(4,469)
|
|
|
(3,942)
|
|
|
(4,024)
|
|
|
13%
|
|
|
11%
|
|
|
(8,411)
|
|
|
(7,122)
|
|
|
18%
|
|
|
Operating expense
|
|
|
(21,534)
|
|
|
(19,099)
|
|
|
(21,179)
|
|
|
13%
|
|
|
2%
|
|
|
(40,633)
|
|
|
(37,789)
|
|
|
8%
|
|
|
General and administration
|
|
|
(5,510)
|
|
|
(4,015)
|
|
|
(6,560)
|
|
|
37%
|
|
|
(16%)
|
|
|
(9,525)
|
|
|
(9,428)
|
|
|
1%
|
|
|
Fund flows from operations
|
|
|
54,003
|
|
|
42,236
|
|
|
113,258
|
|
|
28%
|
|
|
(52%)
|
|
|
96,239
|
|
|
201,199
|
|
|
(52%)
|
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
40.59
|
|
|
35.81
|
|
|
71.56
|
|
|
13%
|
|
|
(43%)
|
|
|
38.24
|
|
|
70.55
|
|
|
(46%)
|
|
|
Royalties
|
|
|
(2.56)
|
|
|
(3.95)
|
|
|
(7.99)
|
|
|
(35%)
|
|
|
(68%)
|
|
|
(3.25)
|
|
|
(7.61)
|
|
|
(57%)
|
|
|
Transportation expense
|
|
|
(1.99)
|
|
|
(1.81)
|
|
|
(1.76)
|
|
|
10%
|
|
|
13%
|
|
|
(1.90)
|
|
|
(1.75)
|
|
|
9%
|
|
|
Operating expense
|
|
|
(9.58)
|
|
|
(8.78)
|
|
|
(9.28)
|
|
|
9%
|
|
|
3%
|
|
|
(9.19)
|
|
|
(9.31)
|
|
|
(1%)
|
|
|
General and administration
|
|
|
(2.45)
|
|
|
(1.85)
|
|
|
(2.88)
|
|
|
32%
|
|
|
(15%)
|
|
|
(2.15)
|
|
|
(2.32)
|
|
|
(7%)
|
|
|
Fund flows from operations netback
|
|
|
24.01
|
|
|
19.42
|
|
|
49.65
|
|
|
24%
|
|
|
(52%)
|
|
|
21.75
|
|
|
49.56
|
|
|
(56%)
|
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl)
|
|
|
57.94
|
|
|
48.63
|
|
|
102.99
|
|
|
19%
|
|
|
(44%)
|
|
|
53.29
|
|
|
100.84
|
|
|
(47%)
|
|
|
Edmonton Sweet index (US $/bbl)
|
|
|
55.08
|
|
|
41.83
|
|
|
96.85
|
|
|
32%
|
|
|
(43%)
|
|
|
48.46
|
|
|
93.65
|
|
|
(48%)
|
|
|
Edmonton Sweet index ($/bbl)
|
|
|
67.72
|
|
|
51.92
|
|
|
105.61
|
|
|
30%
|
|
|
(36%)
|
|
|
59.86
|
|
|
102.73
|
|
|
(42%)
|
|
|
AECO ($/GJ)
|
|
|
2.52
|
|
|
2.60
|
|
|
4.44
|
|
|
(3%)
|
|
|
(43%)
|
|
|
2.56
|
|
|
4.93
|
|
|
(48%)
|
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 13% quarter-over-quarter as a result of a 30%
increase in Edmonton Sweet index pricing in Canadian dollar terms
offset by a 3% decrease in AECO pricing. This increase, coupled with
relatively consistent production volumes, resulted in a 17% increase in
sales.
-
On a year-over-year basis, sales per boe decreased by 43% and 46% for
the three and six months ended June 30, 2015, largely as the result of
weakening crude oil and natural gas pricing. For the three months
ended June 30, 2015, the lower pricing was combined with consistent
production volumes, resulting in a 44% decrease in sales. For the six
months ended June 30, 2015, the decline in commodity prices was
partially offset by a 9% increase in production, resulting in a 41%
decrease in sales.
Royalties
-
Royalties as a percentage of sales for Q2 2015 decreased to 6.3% as
compared to Q1 2015 of 11.0% despite higher reference prices (which
would typically result in higher royalty rates) due to the timing of
when par prices used in the royalty calculations were set. This timing
difference resulted in lower crude oil royalty rates for Q2 2015. In
addition, an annual favorable gas cost allowance ("GCA") adjustment in
Alberta resulted in gas royalties being in a recovery position for the
current quarter.
-
Royalties as a percentage of sales for the three and six months ended
June 30, 2015 decreased to 6.3% and 8.5% versus 11.2% and 10.8% for the
same periods in 2014 due to the impact of lower reference prices on the
sliding scale used to determine crude oil royalty rates and the
aforementioned favorable GCA adjustment.
Transportation
-
Transportation expense relates to the delivery of crude oil and natural
gas production to major pipelines where legal title transfers.
-
Transportation expense for Q2 2015 was higher than Q1 2015 as a result
of higher natural gas liquids and natural gas production.
-
Transportation expense for the three and six months ended June 30, 2015
was higher than the same periods in the prior year as a result of
incremental trucking costs from Vermilion's Saskatchewan properties,
which were acquired in April of 2014.
Operating expense
-
Operating expenses were higher for Q2 2015 versus Q1 2015 on both a
dollar and per boe basis due to higher road use fees and a higher level
of facilities maintenance activity in Saskatchewan.
-
Operating expenses were higher on a dollar basis for the three and six
months ended June 30, 2015 compared to the same periods in 2014 due to
incremental operating expenses associated with Vermilion's Saskatchewan
properties, acquired in Q2 2014. This dollar increase resulting from
the acquisition was largely offset by a wide range of cost reduction
initiatives undertaken in response to commodity price weakness
resulting in reduced operating expense on a per boe basis for
year-to-date 2015.
General and administration
-
General and administration expense fluctuations in Q2 2015 as compared
to both Q1 2015 and Q2 2014 were a result of the timing of
expenditures.
-
Year-over-year, general and administration expense for the six months
ended June 30, 2015 was consistent with 2014.
FRANCE BUSINESS UNIT
Overview
-
Entered France in 1997 and completed three subsequent acquisitions,
including two in 2012.
-
Largest oil producer in France, constituting approximately
three-quarters of domestic oil production.
-
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,
|
|
|
Q2/15 vs.
|
|
|
Q2/15 vs.
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
|
2015 vs.
|
|
France business unit
|
|
|
|
2015
|
|
|
2015
|
|
|
2014
|
|
|
Q1/15
|
|
|
Q2/14
|
|
|
2015
|
|
|
2014
|
|
|
2014
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
|
12,746
|
|
|
11,463
|
|
|
11,025
|
|
|
11%
|
|
|
16%
|
|
|
12,108
|
|
|
10,899
|
|
|
11%
|
|
|
Natural gas (mmcf/d)
|
|
|
|
1.03
|
|
|
-
|
|
|
-
|
|
|
100%
|
|
|
100%
|
|
|
0.52
|
|
|
-
|
|
|
100%
|
|
|
Total (boe/d)
|
|
|
|
12,917
|
|
|
11,463
|
|
|
11,025
|
|
|
13%
|
|
|
17%
|
|
|
12,194
|
|
|
10,899
|
|
|
12%
|
|
Inventory (mbbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Opening crude oil inventory
|
|
|
|
299
|
|
|
197
|
|
|
238
|
|
|
|
|
|
|
|
|
197
|
|
|
269
|
|
|
|
|
|
Crude oil production
|
|
|
|
1,160
|
|
|
1,032
|
|
|
1,003
|
|
|
|
|
|
|
|
|
2,192
|
|
|
1,973
|
|
|
|
|
|
Crude oil sales
|
|
|
|
(1,119)
|
|
|
(930)
|
|
|
(1,062)
|
|
|
|
|
|
|
|
|
(2,049)
|
|
|
(2,063)
|
|
|
|
|
|
Closing crude oil inventory
|
|
|
|
340
|
|
|
299
|
|
|
179
|
|
|
|
|
|
|
|
|
340
|
|
|
179
|
|
|
|
|
Production mix (% of total)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
|
99%
|
|
|
100%
|
|
|
100%
|
|
|
|
|
|
|
|
|
99%
|
|
|
100%
|
|
|
|
|
|
Natural gas
|
|
|
|
1%
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
1%
|
|
|
-
|
|
|
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
|
|
|
16,697
|
|
|
34,114
|
|
|
37,614
|
|
|
(51%)
|
|
|
(56%)
|
|
|
50,811
|
|
|
75,581
|
|
|
(33%)
|
|
|
Acquisitions ($M)
|
|
|
|
96
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
96
|
|
|
-
|
|
|
|
|
|
Gross wells drilled
|
|
|
|
-
|
|
|
4.00
|
|
|
2.00
|
|
|
|
|
|
|
|
|
4.00
|
|
|
4.00
|
|
|
|
|
|
Net wells drilled
|
|
|
|
-
|
|
|
4.00
|
|
|
2.00
|
|
|
|
|
|
|
|
|
4.00
|
|
|
4.00
|
|
|
|
Production
-
Quarter-over-quarter and year-over-year production growth of 13% and
17%, respectively, due to production additions from our 2015 Champotran
drilling program and workovers.
-
In late September 2013, the third party Lacq processing facility that
processed our Vic Bilh gas production was permanently closed. As a
result, our Vic Bilh gas production was temporarily shut-in while
preparations to transfer to an alternative facility were completed.
During Q2 2015, approximately 2 mmcf/d (330 boe/d) of Vic Bilh gas
production was restored.
Activity review
-
Vermilion drilled four (4.0 net) wells in the Champotran field in the
Paris Basin in Q1 2015, completing our planned France drilling program
for 2015.
-
In 2015, additional activity includes a 26-well workover program and the
resumption of sales from a portion of our shut-in natural gas at Vic
Bilh, which was brought on-line in Q2 2015.
Financial review
|
|
|
|
|
Three Months Ended
|
|
|
% change
|
|
|
Six Months Ended
|
|
|
% change
|
|
France business unit
|
|
|
Jun 30,
|
|
|
Mar 31,
|
|
|
Jun 30,
|
|
|
Q2/15 vs.
|
|
|
Q2/15 vs.
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
|
2015 vs.
|
|
($M except as indicated)
|
|
|
2015
|
|
|
2015
|
|
|
2014
|
|
|
Q1/15
|
|
|
Q2/14
|
|
|
2015
|
|
|
2014
|
|
|
2014
|
|
|
Sales
|
|
|
81,627
|
|
|
59,832
|
|
|
124,617
|
|
|
36%
|
|
|
(34%)
|
|
|
141,459
|
|
|
242,177
|
|
|
(42%)
|
|
|
Royalties
|
|
|
(6,620)
|
|
|
(5,102)
|
|
|
(7,796)
|
|
|
30%
|
|
|
(15%)
|
|
|
(11,722)
|
|
|
(15,147)
|
|
|
(23%)
|
|
|
Transportation expense
|
|
|
(3,526)
|
|
|
(3,011)
|
|
|
(5,385)
|
|
|
17%
|
|
|
(35%)
|
|
|
(6,537)
|
|
|
(10,138)
|
|
|
(36%)
|
|
|
Operating expense
|
|
|
(12,102)
|
|
|
(10,826)
|
|
|
(16,550)
|
|
|
12%
|
|
|
(27%)
|
|
|
(22,928)
|
|
|
(32,970)
|
|
|
(30%)
|
|
|
General and administration
|
|
|
(4,874)
|
|
|
(5,111)
|
|
|
(5,559)
|
|
|
(5%)
|
|
|
(12%)
|
|
|
(9,985)
|
|
|
(10,753)
|
|
|
(7%)
|
|
|
Other income
|
|
|
-
|
|
|
31,775
|
|
|
-
|
|
|
(100%)
|
|
|
-
|
|
|
31,775
|
|
|
-
|
|
|
100%
|
|
|
Current income taxes
|
|
|
(9,316)
|
|
|
(14,281)
|
|
|
(24,761)
|
|
|
(35%)
|
|
|
(62%)
|
|
|
(23,597)
|
|
|
(50,025)
|
|
|
(53%)
|
|
|
Fund flows from operations
|
|
|
45,189
|
|
|
53,276
|
|
|
64,566
|
|
|
(15%)
|
|
|
(30%)
|
|
|
98,465
|
|
|
123,144
|
|
|
(20%)
|
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
71.96
|
|
|
64.33
|
|
|
117.29
|
|
|
12%
|
|
|
(39%)
|
|
|
68.52
|
|
|
117.41
|
|
|
(42%)
|
|
|
Royalties
|
|
|
(5.84)
|
|
|
(5.49)
|
|
|
(7.34)
|
|
|
6%
|
|
|
(20%)
|
|
|
(5.68)
|
|
|
(7.34)
|
|
|
(23%)
|
|
|
Transportation expense
|
|
|
(3.11)
|
|
|
(3.24)
|
|
|
(5.07)
|
|
|
(4%)
|
|
|
(39%)
|
|
|
(3.17)
|
|
|
(4.91)
|
|
|
(35%)
|
|
|
Operating expense
|
|
|
(10.67)
|
|
|
(11.64)
|
|
|
(15.58)
|
|
|
(8%)
|
|
|
(32%)
|
|
|
(11.11)
|
|
|
(15.98)
|
|
|
(30%)
|
|
|
General and administration
|
|
|
(4.30)
|
|
|
(5.49)
|
|
|
(5.24)
|
|
|
(22%)
|
|
|
(18%)
|
|
|
(4.84)
|
|
|
(5.21)
|
|
|
(7%)
|
|
|
Other income
|
|
|
-
|
|
|
34.16
|
|
|
-
|
|
|
(100%)
|
|
|
-
|
|
|
15.39
|
|
|
-
|
|
|
100%
|
|
|
Current income taxes
|
|
|
(8.21)
|
|
|
(15.35)
|
|
|
(23.30)
|
|
|
(47%)
|
|
|
(65%)
|
|
|
(11.43)
|
|
|
(24.25)
|
|
|
(53%)
|
|
|
Fund flows from operations netback
|
|
|
39.83
|
|
|
57.28
|
|
|
60.76
|
|
|
(30%)
|
|
|
(34%)
|
|
|
47.68
|
|
|
59.72
|
|
|
(20%)
|
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated Brent (US $/bbl)
|
|
|
61.92
|
|
|
53.97
|
|
|
109.63
|
|
|
15%
|
|
|
(44%)
|
|
|
57.95
|
|
|
108.93
|
|
|
(47%)
|
|
|
Dated Brent ($/bbl)
|
|
|
76.12
|
|
|
66.98
|
|
|
119.55
|
|
|
14%
|
|
|
(36%)
|
|
|
71.59
|
|
|
119.50
|
|
|
(40%)
|
Sales
-
Crude oil production in France is priced with reference to Dated Brent.
-
Sales per boe increased by 12% quarter-over-quarter, consistent with a
14% increase in the Canadian dollar equivalent of the Dated Brent
reference price. This increase, coupled with a smaller inventory build
in the quarter, resulted in a 36% increase in sales.
-
On a year-over-year basis, sales per boe decreased by 39% and 42% for
the three and six months ended June 30, 2015, respectively. In both
periods, this was consistent with a decrease in the Dated Brent
reference price, and was partially offset by increases in production.
This resulted in a decrease in sales for both the three and six month
periods ended June 30, 2015 of 34% and 42%, 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).
-
Royalties as a percentage of sales was 8.1% and 8.3% for the three and
six months ended June 30, 2015, relatively consistent with 8.5% in Q1
2015, and an increase over both comparable periods in 2014. The
year-over-year increase was due to the impact of fixed RCDM royalties
coupled with lower realized pricing.
Transportation
-
Transportation expense increased slightly for Q2 2015 as compared to Q1
2015 due to a higher number of shipments from the Ambès terminal during
the current quarter.
-
Transportation expense decreased for both the three and six months ended
June 30, 2015 as compared to the same periods in 2014 due to a lower
level of maintenance and project activity at the Ambès terminal coupled
with cost savings associated with fewer shipments at the terminal due
to the usage of larger shipping vessels.
Operating expense
-
On a dollar basis, Q2 2015 operating expense was higher than Q1 2015 due
to increased electricity costs and a higher level of well intervention
activities.
-
Operating expense on a dollar and per boe basis decreased for the three
and six months ended June 30, 2015 versus the same periods in 2014 due
to a number of cost reduction initiatives undertaken in response to
commodity price weakness. These cost reduction initiatives included
lower costs on downhole and other activities, lower labour usage and
costs, as well as savings from service contract renegotiations.
-
In addition, on a year-over-year basis, operating expenses further
decreased due to the favorable foreign exchange impact of the
strengthening of the Canadian dollar versus the Euro and the deferral
of costs following a build in crude oil inventory in the 2015 periods.
General and administration
-
Fluctuations in general and administration expense for the three and six
months ended June 30, 2015 versus all comparable periods was primarily
the result of the favorable foreign exchange impact of a stronger
Canadian dollar versus the Euro.
Other income
-
In the six months ended June 30, 2015, Vermilion was awarded a judgment
pertaining to costs incurred as a result of an oil spill at the Ambès
oil terminal in France that occurred in 2007. As a result of the
award, $31.8 million (before taxes) was recognized as other income.
Current income taxes
-
Current income taxes in France are applied to taxable income, after
eligible deductions, at a statutory rate of 34.4% for 2015. In
addition, a 10.7% temporary surtax (as a percentage of the statutory
rate) is applicable for tax year 2015 if annual revenue exceeds €250
million. For 2015, the effective rate on current income taxes is
expected to be between approximately 17% and 19%. This rate is subject
to change in response to commodity price fluctuations, the timing of
capital expenditures, and other eligible in-country adjustments.
-
Absent of the taxes recognized in Q1 2015 for the previously mentioned
recovery of costs in France, Q2 2015 current income taxes increased
compared to Q1 2015 due to increased revenues.
-
Current income taxes for the three and six months ended June 30, 2015
decreased versus the comparative periods in 2014. The decrease was the
result of lower funds from operations as a result of the decline in the
Dated Brent reference price.
NETHERLANDS BUSINESS UNIT
Overview
-
Entered the Netherlands in 2004.
-
Second largest onshore gas producer.
-
Interests include 16 licenses in the northeast region, five licenses in
the central region, and two offshore licenses.
-
Licenses include more than 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,
|
|
|
Q2/15 vs.
|
|
|
Q2/15 vs.
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
|
2015 vs.
|
|
Netherlands business unit
|
|
|
|
2015
|
|
|
2015
|
|
|
2014
|
|
|
Q1/15
|
|
|
Q2/14
|
|
|
2015
|
|
|
2014
|
|
|
2014
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d)
|
|
|
|
112
|
|
|
63
|
|
|
96
|
|
|
78%
|
|
|
17%
|
|
|
88
|
|
|
83
|
|
|
6%
|
|
|
Natural gas (mmcf/d)
|
|
|
|
32.43
|
|
|
36.41
|
|
|
40.35
|
|
|
(11%)
|
|
|
(20%)
|
|
|
34.41
|
|
|
41.74
|
|
|
(18%)
|
|
|
Total (boe/d)
|
|
|
|
5,517
|
|
|
6,132
|
|
|
6,822
|
|
|
(10%)
|
|
|
(19%)
|
|
|
5,823
|
|
|
7,040
|
|
|
(17%)
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
|
|
|
18,885
|
|
|
4,333
|
|
|
21,513
|
|
|
336%
|
|
|
(12%)
|
|
|
23,218
|
|
|
41,631
|
|
|
(44%)
|
|
|
Gross wells drilled
|
|
|
|
2.00
|
|
|
-
|
|
|
2.00
|
|
|
|
|
|
|
|
|
2.00
|
|
|
4.00
|
|
|
|
|
|
Net wells drilled
|
|
|
|
1.86
|
|
|
-
|
|
|
1.43
|
|
|
|
|
|
|
|
|
1.86
|
|
|
3.29
|
|
|
|
Production
-
Production decreased 10% quarter-over-quarter due to a planned major
facility maintenance at our Garijp Treatment Centre which negatively
impacted Q2 production by approximately 2,400 mcf/d (400 boe/d).
-
Year-over-year and year-to-date production decreased 19% and 17%
respectively due to loss of production from our Middenmeer-3 well,
which was fully depleted and taken offline in February 2015. The
depletion of this well occurred as expected. The turnaround at the
Garijp Treatment Centre during Q2 2015 contributed to the decrease in
production
-
Production in the Netherlands is actively managed to optimize facility
use and regulate declines.
Activity review
-
During Q2, Vermilion drilled two (1.9 net) wells, Slootdorp-06 and
Slootdorp-07. These wells are currently on sales during an extended
production test to size additional production equipment. The wells are
currently producing at facility-restricted rates totaling 21 mmcf/d
(3,500 boe/d) net.
-
Capital previously allocated to a planned third well has been redeployed
to support a highly economic debottlenecking project in our Garijp
Treatment Centre and associated gathering system.
-
During the second half of 2015, we expect to equip and tie-in the
Diever-02 discovery well drilled in 2014.
Financial review
|
|
|
|
|
Three Months Ended
|
|
|
% change
|
|
|
Six Months Ended
|
|
|
% change
|
|
Netherlands business unit
|
|
|
Jun 30,
|
|
|
Mar 31,
|
|
|
Jun 30,
|
|
|
Q2/15 vs.
|
|
|
Q2/15 vs.
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
|
2015 vs.
|
|
($M except as indicated)
|
|
|
2015
|
|
|
2015
|
|
|
2014
|
|
|
Q1/15
|
|
|
Q2/14
|
|
|
2015
|
|
|
2014
|
|
|
2014
|
|
|
Sales
|
|
|
23,913
|
|
|
26,818
|
|
|
29,881
|
|
|
(11%)
|
|
|
(20%)
|
|
|
50,731
|
|
|
71,435
|
|
|
(29%)
|
|
|
Royalties
|
|
|
(1,294)
|
|
|
(926)
|
|
|
(693)
|
|
|
40%
|
|
|
87%
|
|
|
(2,220)
|
|
|
(2,901)
|
|
|
(23%)
|
|
|
Operating expense
|
|
|
(5,414)
|
|
|
(5,826)
|
|
|
(6,390)
|
|
|
(7%)
|
|
|
(15%)
|
|
|
(11,240)
|
|
|
(12,432)
|
|
|
(10%)
|
|
|
General and administration
|
|
|
(454)
|
|
|
(737)
|
|
|
(326)
|
|
|
(38%)
|
|
|
39%
|
|
|
(1,191)
|
|
|
(924)
|
|
|
29%
|
|
|
Current income taxes
|
|
|
(2,347)
|
|
|
(2,388)
|
|
|
(1,301)
|
|
|
(2%)
|
|
|
80%
|
|
|
(4,735)
|
|
|
(5,089)
|
|
|
(7%)
|
|
|
Fund flows from operations
|
|
|
14,404
|
|
|
16,941
|
|
|
21,171
|
|
|
(15%)
|
|
|
(32%)
|
|
|
31,345
|
|
|
50,089
|
|
|
(37%)
|
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
47.63
|
|
|
48.60
|
|
|
48.14
|
|
|
(2%)
|
|
|
(1%)
|
|
|
48.13
|
|
|
56.06
|
|
|
(14%)
|
|
|
Royalties
|
|
|
(2.58)
|
|
|
(1.68)
|
|
|
(1.12)
|
|
|
54%
|
|
|
130%
|
|
|
(2.11)
|
|
|
(2.28)
|
|
|
(7%)
|
|
|
Operating expense
|
|
|
(10.78)
|
|
|
(10.56)
|
|
|
(10.29)
|
|
|
2%
|
|
|
5%
|
|
|
(10.66)
|
|
|
(9.76)
|
|
|
9%
|
|
|
General and administration
|
|
|
(0.90)
|
|
|
(1.34)
|
|
|
(0.53)
|
|
|
(33%)
|
|
|
70%
|
|
|
(1.13)
|
|
|
(0.73)
|
|
|
55%
|
|
|
Current income taxes
|
|
|
(4.67)
|
|
|
(4.33)
|
|
|
(2.10)
|
|
|
8%
|
|
|
122%
|
|
|
(4.49)
|
|
|
(3.99)
|
|
|
13%
|
|
|
Fund flows from operations netback
|
|
|
28.70
|
|
|
30.69
|
|
|
34.10
|
|
|
(6%)
|
|
|
(16%)
|
|
|
29.74
|
|
|
39.30
|
|
|
(24%)
|
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TTF ($/GJ)
|
|
|
7.94
|
|
|
8.25
|
|
|
7.91
|
|
|
(4%)
|
|
|
-
|
|
|
8.10
|
|
|
9.02
|
|
|
(10%)
|
|
|
TTF (€/GJ)
|
|
|
5.84
|
|
|
5.91
|
|
|
5.27
|
|
|
(1%)
|
|
|
11%
|
|
|
5.87
|
|
|
6.01
|
|
|
(2%)
|
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.
-
Sales per boe decreased by 2% quarter-over-quarter, consistent with a 4%
decrease in the Canadian dollar equivalent TTF reference price. This
was coupled with a 10% decrease in production, resulting in an 11%
decrease in sales.
-
On a year-over-year basis, sales per boe declined by 1% and 14% for the
three and six months ended June 30, 2015, respectively. For the three
months ended June 30, 2015, the 20% decrease in sales was entirely
attributable to the decrease in production. For the six months ended
June 30, 2015, a decrease in sales per boe of 14% was consistent with a
10% decrease in the Canadian dollar equivalent of TTF, and, combined
with a 17% decrease in production, resulted in a 29% decrease in sales.
Royalties
-
In the Netherlands, we pay overriding royalties on certain wells
associated with an acquisition completed by the Netherlands business
unit in October 2013. As such, fluctuations in royalty expense in the
periods presented relate to the amount of production from those wells
subject to overriding royalties.
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 on a dollar basis decreased for the three and six
months ended June 30, 2015 versus all comparable periods primarily as a
result of a stronger Canadian dollar versus the Euro coupled with lower
facility operations expenditures due to cost reduction initiatives
undertaken in response to commodity price weakness.
-
However, as production in the Netherlands was lower in the current year,
operating expense per boe for the three and six months ended June 30,
2015 was higher versus all comparable periods.
General and administration
-
Variances in general and administration expense generally relates to
timing of expenditures, including the timing of allocations from
Vermilion's Corporate segment.
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
2015, the effective rate on current taxes is expected to be between
approximately 12% and 14%. 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 in Q2 2015 were comparable to Q1 2015.
-
Current income taxes in Q2 2015 were higher than Q2 2014 as higher
revenues were offset with accelerated tax deductions in the current
quarter.
GERMANY BUSINESS UNIT
Overview
-
Vermilion entered Germany in February 2014.
-
Assets include four gas producing fields across 11 production licenses
and an exploration license in surrounding fields. Our working interest
is 25%.
-
Total license area comprises 204,000 gross acres, of which 85% is in the
exploration license.
Operational review
|
|
|
|
|
|
|
Three Months Ended
|
|
|
% change
|
|
|
Six Months Ended
|
|
|
% change
|
|
|
|
|
|
|
|
Jun 30,
|
|
|
Mar 31,
|
|
|
Jun 30,
|
|
|
Q2/15 vs.
|
|
|
Q2/15 vs.
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
|
2015 vs.
|
|
Germany business unit
|
|
|
|
|
2015
|
|
|
2015
|
|
|
2014
|
|
|
Q1/15
|
|
|
Q2/14
|
|
|
2015
|
|
|
2014
|
|
|
2014
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
|
|
|
|
16.18
|
|
|
16.80
|
|
|
16.13
|
|
|
(4%)
|
|
|
-
|
|
|
16.49
|
|
|
13.40
|
|
|
23%
|
|
|
Total (boe/d)
|
|
|
|
|
2,696
|
|
|
2,801
|
|
|
2,689
|
|
|
(4%)
|
|
|
-
|
|
|
2,748
|
|
|
2,234
|
|
|
23%
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
|
|
|
|
3,231
|
|
|
968
|
|
|
630
|
|
|
234%
|
|
|
413%
|
|
|
4,199
|
|
|
826
|
|
|
408%
|
|
|
Acquisitions ($M)
|
|
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
-
|
|
|
172,871
|
|
|
|
|
|
Gross wells drilled
|
|
|
|
|
1.00
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
1.00
|
|
|
-
|
|
|
|
|
|
Net wells drilled
|
|
|
|
|
0.25
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
0.25
|
|
|
-
|
|
|
|
Production
-
Q2 2015 production of 2,696 boe/d represented a decrease of 4% as
compared to the prior quarter while year-over-year production was
flat. Year-to-date production increased 23% versus prior year, due to
2014 volumes only reflecting production from the acquisition's
effective date of February 1, 2014.
Activity review
-
Participated in the drilling of the Burgmoor Z3a sidetrack well (25%
working interest), which was completed in Q2 2015. Subsequent to the
quarter, the well was tied-in and placed on production.
Financial review
|
|
|
|
|
Three Months Ended
|
|
|
% change
|
|
|
Six Months Ended
|
|
|
% change
|
|
Germany business unit
|
|
|
Jun 30,
|
|
|
Mar 31,
|
|
|
Jun 30,
|
|
|
Q2/15 vs.
|
|
|
Q2/15 vs.
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
|
2015 vs.
|
|
($M except as indicated)
|
|
|
2015
|
|
|
2015
|
|
|
2014
|
|
|
Q1/15
|
|
|
Q2/14
|
|
|
2015
|
|
|
2014
|
|
|
2014
|
|
|
Sales
|
|
|
10,626
|
|
|
11,395
|
|
|
11,097
|
|
|
(7%)
|
|
|
(4%)
|
|
|
22,021
|
|
|
20,012
|
|
|
10%
|
|
|
Royalties
|
|
|
(2,238)
|
|
|
(1,598)
|
|
|
(2,284)
|
|
|
40%
|
|
|
(2%)
|
|
|
(3,836)
|
|
|
(4,086)
|
|
|
(6%)
|
|
|
Transportation expense
|
|
|
(1,240)
|
|
|
(894)
|
|
|
(1,052)
|
|
|
39%
|
|
|
18%
|
|
|
(2,134)
|
|
|
(1,474)
|
|
|
45%
|
|
|
Operating expense
|
|
|
(1,373)
|
|
|
(1,999)
|
|
|
(2,043)
|
|
|
(31%)
|
|
|
(33%)
|
|
|
(3,372)
|
|
|
(3,597)
|
|
|
(6%)
|
|
|
General and administration
|
|
|
(1,435)
|
|
|
(1,608)
|
|
|
(830)
|
|
|
(11%)
|
|
|
73%
|
|
|
(3,043)
|
|
|
(1,398)
|
|
|
118%
|
|
|
Current income taxes
|
|
|
-
|
|
|
-
|
|
|
(506)
|
|
|
-
|
|
|
(100%)
|
|
|
-
|
|
|
(1,043)
|
|
|
(100%)
|
|
|
Fund flows from operations
|
|
|
4,340
|
|
|
5,296
|
|
|
4,382
|
|
|
(18%)
|
|
|
(1%)
|
|
|
9,636
|
|
|
8,414
|
|
|
15%
|
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
43.31
|
|
|
45.21
|
|
|
45.36
|
|
|
(4%)
|
|
|
(5%)
|
|
|
44.27
|
|
|
49.50
|
|
|
(11%)
|
|
|
Royalties
|
|
|
(9.12)
|
|
|
(6.34)
|
|
|
(9.34)
|
|
|
44%
|
|
|
(2%)
|
|
|
(7.71)
|
|
|
(10.11)
|
|
|
(24%)
|
|
|
Transportation expense
|
|
|
(5.05)
|
|
|
(3.55)
|
|
|
(4.30)
|
|
|
42%
|
|
|
17%
|
|
|
(4.29)
|
|
|
(3.65)
|
|
|
18%
|
|
|
Operating expense
|
|
|
(5.60)
|
|
|
(7.93)
|
|
|
(8.35)
|
|
|
(29%)
|
|
|
(33%)
|
|
|
(6.78)
|
|
|
(8.90)
|
|
|
(24%)
|
|
|
General and administration
|
|
|
(5.85)
|
|
|
(6.38)
|
|
|
(3.39)
|
|
|
(8%)
|
|
|
73%
|
|
|
(6.12)
|
|
|
(3.46)
|
|
|
77%
|
|
|
Current income taxes
|
|
|
-
|
|
|
-
|
|
|
(2.07)
|
|
|
-
|
|
|
(100%)
|
|
|
-
|
|
|
(2.58)
|
|
|
(100%)
|
|
|
Fund flows from operations netback
|
|
|
17.69
|
|
|
21.01
|
|
|
17.91
|
|
|
(16%)
|
|
|
(1%)
|
|
|
19.37
|
|
|
20.80
|
|
|
(7%)
|
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TTF ($/GJ)
|
|
|
7.94
|
|
|
8.25
|
|
|
7.91
|
|
|
(4%)
|
|
|
-
|
|
|
8.10
|
|
|
9.02
|
|
|
(10%)
|
|
|
TTF (€/GJ)
|
|
|
5.84
|
|
|
5.91
|
|
|
5.27
|
|
|
(1%)
|
|
|
11%
|
|
|
5.87
|
|
|
6.01
|
|
|
(2%)
|
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.
-
The 7% decrease in sales quarter-over-quarter is due to a 4% decrease in
sales per boe, consistent with the decrease in the Canadian dollar
equivalent of the TTF reference price, and a 4% decrease in production.
-
On a year-over-year basis, sales per boe declined by 5% and 11% for the
three and six months ended June 30, 2015, respectively. For the three
months ended June 30, 2015, production remained relatively consistent,
resulting in a 4% decrease in sales. For the six months ended June 30,
2015, production increased by 23% but was partially offset by a
stronger CAD versus the Euro, resulting in a 10% increase in sales.
Royalties
-
Our production in Germany is subject to state and private royalties on
sales after certain eligible deductions. As a percentage of sales,
royalties are expected to range from 15% to 20% in 2015.
-
Q2 2015 royalties as a percentage of sales of 21.1% were higher than the
14.0% for Q1 2015 due to adjustments for prior period royalties.
Year-to-date royalties as a percentage of sales of 17.4% were lower
than the 20.4% for the comparable period in 2014 as a result of lower
state royalty rates for 2015.
Transportation expense
-
Transportation expense in Germany relates to costs incurred to deliver
natural gas from the processing facility to the customer.
-
Q2 2015 transportation expense was higher than Q1 2015 and Q2 2014 due
to final adjustments recorded for 2014 during the current quarter.
Year-to-date transportation expense was higher than the comparable
period in 2014 due to the aforementioned adjustments and the inclusion
of only 5 months of expense in 2014 due to the timing of our Germany
acquisition.
Operating expense
-
Operating expenses for Germany are billed monthly by the joint venture
operator and primarily relate to tariffs charged for gas processing.
-
Q2 2015 had lower operating expenses on a dollar and per boe basis
versus both Q1 2015 and Q2 2014 due to lower levels of project activity
during the current quarter.
-
Operating expense for the six months ended June 30, 2015 decreased on a
dollar and per boe basis versus the same period in 2014 due to the
timing of the acquisition and reduced gas processing tariffs in 2015.
General and administration
-
General and administration expense decreased quarter-over-quarter as a
result of the timing of allocations from Vermilion's Corporate segment.
Current income taxes
-
Current income taxes in Germany apply to taxable income after eligible
deductions at a statutory tax rate of approximately 24%. As a function
of Germany's tax pools, Vermilion does not presently pay taxes in
Germany.
IRELAND BUSINESS UNIT
Overview
-
18.5% non-operating interest in the offshore Corrib gas field located
approximately 83 km off the northwest coast of Ireland.
-
Project comprises six offshore wells, offshore and onshore sales and
transportation pipeline segments as well as a natural gas processing
facility.
-
Corrib is expected to produce approximately 58 mmcf/d (9,700 boe/d) net
to Vermilion at peak production rates.
Operational and financial review
|
|
|
|
|
|
|
Three Months Ended
|
|
|
% change
|
|
|
Six Months Ended
|
|
|
% change
|
|
Ireland business unit
|
|
|
|
|
Jun 30,
|
|
|
Mar 31,
|
|
|
Jun 30,
|
|
|
Q2/15 vs.
|
|
|
Q2/15 vs.
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
|
2015 vs.
|
|
($M)
|
|
|
|
|
2015
|
|
|
2015
|
|
|
2014
|
|
|
Q1/15
|
|
|
Q2/14
|
|
|
2015
|
|
|
2014
|
|
|
2014
|
|
|
Transportation expense
|
|
|
|
|
(1,648)
|
|
|
(1,693)
|
|
|
(1,571)
|
|
|
(3%)
|
|
|
5%
|
|
|
(3,341)
|
|
|
(3,159)
|
|
|
6%
|
|
|
General and administration
|
|
|
|
|
(628)
|
|
|
(512)
|
|
|
(252)
|
|
|
23%
|
|
|
149%
|
|
|
(1,140)
|
|
|
(534)
|
|
|
113%
|
|
|
Fund flows from operations
|
|
|
|
|
(2,276)
|
|
|
(2,205)
|
|
|
(1,823)
|
|
|
3%
|
|
|
25%
|
|
|
(4,481)
|
|
|
(3,693)
|
|
|
21%
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
|
|
20,267
|
|
|
12,955
|
|
|
27,221
|
|
|
56%
|
|
|
(26%)
|
|
|
33,222
|
|
|
43,457
|
|
|
(24%)
|
Activity review
-
Following minor remaining compressor maintenance, operator Shell E&P
Ireland Limited expects to declare all wells, facilities and transport
systems ready for service by the end of August. Prior to commencing
gas production, the Irish Environmental Protection Agency ("EPA") must
issue its Final Determination for the Corrib Industrial Emissions
Licence ("IEL") and Ministerial Consent is required from the Department
of Communications, Environment, and Natural Resources. The EPA issued
its Proposed Determination for the Corrib IEL in April 2015, and
following statutory consultation and review periods is expected to
issue its Final Determination on the IEL on or before mid-September. We
now estimate that the Ministerial Consent process will be completed,
and that production will commence, in early-to-mid fourth quarter of
2015.
-
Capital expenditures at Corrib total $33 million year-to-date in 2015.
We currently expect to incur an additional $30 to $35 million of
capital expenditures at Corrib prior to achieving first gas in early to
mid-Q4 2015.
-
Production at Corrib is expected to increase over the first few months
toward peak production levels estimated at approximately 58 mmcf/d
(approximately 9,700 boe/d), net to Vermilion.
Transportation expense
-
Transportation expense in Ireland relates to payments under a ship or
pay agreement related to the Corrib project.
AUSTRALIA BUSINESS UNIT
Overview
-
Entered Australia in 2005.
-
Hold a 100% operated working interest in the Wandoo field, located
approximately 80 km offshore on the northwest shelf of Australia.
-
Production is operated from two off-shore platforms, and originates from
21 producing well bores.
-
Wells that utilize horizontal legs (ranging in length from 500 to 3,000
plus metres) are located 600 metres below the seabed in approximately
55 metres of water depth.
-
Contracted crude oil production is priced with reference to Dated Brent.
Operational review
|
|
|
|
|
Three Months Ended
|
|
% change
|
|
|
Six Months Ended
|
|
% change
|
|
|
|
|
|
Jun 30,
|
|
Mar 31,
|
|
Jun 30,
|
|
Q2/15 vs.
|
Q2/15 vs.
|
|
|
Jun 30,
|
Jun 30,
|
|
2015 vs.
|
|
Australia business unit
|
|
|
2015
|
|
2015
|
|
2014
|
|
Q1/15
|
Q2/14
|
|
|
2015
|
2014
|
|
2014
|
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
5,865
|
|
5,672
|
|
6,483
|
|
3%
|
(10%)
|
|
|
5,769
|
6,795
|
|
(15%)
|
|
Inventory (mbbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Opening crude oil inventory
|
|
|
318
|
|
37
|
|
63
|
|
|
|
|
|
37
|
130
|
|
|
|
|
Crude oil production
|
|
|
534
|
|
511
|
|
590
|
|
|
|
|
|
1,044
|
1,230
|
|
|
|
|
Crude oil sales
|
|
|
(696)
|
|
(230)
|
|
(464)
|
|
|
|
|
|
(925)
|
(1,171)
|
|
|
|
|
Closing crude oil inventory
|
|
|
156
|
|
318
|
|
189
|
|
|
|
|
|
156
|
189
|
|
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
|
|
6,468
|
|
6,455
|
|
10,991
|
|
-
|
(41%)
|
|
|
12,923
|
16,682
|
|
(23%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production
-
Quarterly production increased 3% quarter-over-quarter and decreased 10%
year-over-year. Production volumes are managed within corporate
targets while meeting customer demands and the requirements of
long-term supply agreements.
-
We continue to plan for long-term production levels of between 6,000 and
8,000 bbls/d.
Activity review
-
In Q2 2015, efforts were largely focused on maintenance work, facilities
enhancement and preparations for 2015 and 2016 drilling programs.
-
We have reinstated the previously-deferred two-well sidetrack drilling
program for 2015.
-
Additional 2015 planned activities include ongoing facilities
maintenance, enhancement, and refurbishment, as well as preparation and
permitting activities in advance of our 2016 drilling program.
Financial review
|
|
|
Three Months Ended
|
|
% change
|
|
|
Six Months Ended
|
|
% change
|
|
Australia business unit
|
Jun 30,
|
Mar 31,
|
Jun 30,
|
|
Q2/15 vs.
|
Q2/15 vs.
|
|
|
Jun 30,
|
Jun 30,
|
|
2015 vs.
|
|
($M except as indicated)
|
2015
|
2015
|
2014
|
|
Q1/15
|
Q2/14
|
|
|
2015
|
2014
|
|
2014
|
|
|
Sales
|
56,204
|
19,284
|
58,828
|
|
191%
|
(4%)
|
|
|
75,488
|
148,802
|
|
(49%)
|
|
|
Operating expense
|
(18,083)
|
(5,886)
|
(12,051)
|
|
207%
|
50%
|
|
|
(23,969)
|
(29,411)
|
|
(19%)
|
|
|
General and administration
|
(1,141)
|
(1,454)
|
(1,661)
|
|
(22%)
|
(31%)
|
|
|
(2,595)
|
(2,867)
|
|
(9%)
|
|
|
PRRT
|
(3,371)
|
(2,354)
|
(12,699)
|
|
43%
|
(73%)
|
|
|
(5,725)
|
(32,938)
|
|
(83%)
|
|
|
Corporate income taxes
|
(5,134)
|
(577)
|
(5,689)
|
|
790%
|
(10%)
|
|
|
(5,711)
|
(14,530)
|
|
(61%)
|
|
|
Fund flows from operations
|
28,475
|
9,013
|
26,728
|
|
216%
|
7%
|
|
|
37,488
|
69,056
|
|
(46%)
|
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
80.87
|
83.80
|
126.87
|
|
(3%)
|
(36%)
|
|
|
81.60
|
127.11
|
|
(36%)
|
|
|
Operating expense
|
(26.02)
|
(25.58)
|
(25.99)
|
|
2%
|
-
|
|
|
(25.91)
|
(25.12)
|
|
3%
|
|
|
General and administration
|
(1.64)
|
(6.32)
|
(3.58)
|
|
(74%)
|
(54%)
|
|
|
(2.81)
|
(2.45)
|
|
15%
|
|
|
PRRT
|
(4.85)
|
(10.23)
|
(27.39)
|
|
(53%)
|
(82%)
|
|
|
(6.19)
|
(28.14)
|
|
(78%)
|
|
|
Corporate income taxes
|
(7.39)
|
(2.51)
|
(12.27)
|
|
194%
|
(40%)
|
|
|
(6.17)
|
(12.41)
|
|
(50%)
|
|
|
Fund flows from operations netback
|
40.97
|
39.16
|
57.64
|
|
5%
|
(29%)
|
|
|
40.52
|
58.99
|
|
(31%)
|
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated Brent (US $/bbl)
|
61.92
|
53.97
|
109.63
|
|
15%
|
(44%)
|
|
|
57.95
|
108.93
|
|
(47%)
|
|
|
Dated Brent ($/bbl)
|
76.12
|
66.98
|
119.55
|
|
14%
|
(36%)
|
|
|
71.59
|
119.50
|
|
(40%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
-
Our production in Australia currently receives a premium to Dated Brent.
-
During Q2 2015, inventory decreased by 162,000 bbls versus builds of
281,000 bbls and 126,000 bbls in Q1 2015 and Q2 2014, respectively.
For the six months ended June 30, 2015, inventory increased by 119,000
bbls, as compared to a build of 59,000 bbls in the comparable period in
2014.
-
Sales per boe decreased 3% in Q2 2015 versus Q1 2015 despite an increase
of 14% in the Canadian dollar equivalent of the Dated Brent reference
price due to the timing of sales. This was more than offset by a
significant increase in sales volumes driven by the draw in inventory,
resulting in a 191% increase in sales.
-
On a year-over-year basis, sales per boe decreased by 36% for both the
three and six months ended June 30, 2015, consistent with a decrease in
the Dated Brent reference price. For the three months ended June 30,
2015, this was almost entirely offset by a significant increase in
sales volumes driven by a draw in inventory, resulting in a 4% decrease
in sales. For the six months ended June 30, 2015, a greater build in
inventory led to a 49% decrease in sales.
Royalties and transportation expense
-
Our production in Australia is not subject to royalties or
transportation expense as crude oil is sold directly at the Wandoo B
platform.
Operating expense
-
The increase in operating expense for Q2 2015 as compared to Q1 2015 and
Q2 2014 was largely the result of a drawdown of inventory during the
quarter versus a build in the comparable periods. Operating expense
per boe for Q2 2015 versus both Q1 2015 and Q2 2014 was largely
unchanged.
-
The decrease in operating expense for the year-to-date 2015 period
versus 2014 was largely the result of savings from a wide range of cost
reduction initiatives undertaken in response to commodity price
weakness including reduced vessel usage, lower diesel consumption, and
reduced staffing costs. On a per boe basis, these cost reductions were
offset by lower production volumes causing increased per barrel costs.
General and administration
-
Fluctuations in general and administration expense for the three and six
months versus the comparable periods was largely a result of the timing
of expenditures.
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 2015, the combined corporate income tax and PRRT effective rate is
expected to be between approximately 22% and 24%. 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 for the six months ended June
30, 2015 was lower than the comparable period in 2014. The decrease
was due to a more significant decrease in revenues in the current year
as compared to capital spending.
UNITED STATES BUSINESS UNIT
Overview
-
Entered the United States in September 2014.
-
Interests include approximately 68,000 acres of land (98% undeveloped)
in the Powder River Basin of northeastern Wyoming.
-
Promising tight oil development targeting the Turner Sand at a depth of
approximately 1,500 metres.
Operational and financial review
|
|
|
|
|
Three Months Ended
|
|
% change
|
|
United States business unit
|
|
|
Jun 30,
|
Mar 31,
|
|
Q2/15 vs.
|
|
($M except as indicated)
|
|
|
2015
|
2015
|
|
Q1/15
|
|
|
Sales
|
|
|
677
|
672
|
|
1%
|
|
|
Royalties
|
|
|
(191)
|
(206)
|
|
(7%)
|
|
|
Operating expense
|
|
|
(110)
|
(215)
|
|
(49%)
|
|
|
General and administration
|
|
|
(963)
|
(1,080)
|
|
(11%)
|
|
|
Fund flows from operations
|
|
|
(587)
|
(829)
|
|
(29%)
|
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
Sales
|
|
|
60.57
|
48.79
|
|
24%
|
|
|
Royalties
|
|
|
(17.08)
|
(14.98)
|
|
14%
|
|
|
Operating expense
|
|
|
(9.88)
|
(15.61)
|
|
(37%)
|
|
|
General and administration
|
|
|
(86.12)
|
(78.41)
|
|
10%
|
|
|
Fund flows from operations netback
|
|
|
(52.51)
|
(60.21)
|
|
(13%)
|
|
Reference prices
|
|
|
|
|
|
|
|
|
WTI (US $/bbl)
|
|
|
57.94
|
48.63
|
|
19%
|
|
|
WTI ($/bbl)
|
|
|
71.23
|
60.35
|
|
18%
|
|
Production
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
123
|
153
|
|
(20%)
|
|
Activity
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
2,744
|
637
|
|
331%
|
|
|
Gross wells drilled
|
|
|
1.00
|
-
|
|
|
|
|
Net wells drilled
|
|
|
1.00
|
-
|
|
|
|
|
|
|
|
|
|
|
|
Activity review
-
Vermilion drilled the Seedy Draw North well (100% working interest) in
the East Finn prospect area in Q2 2015, with completion of the well
planned in Q3 2015.
Sales
-
The price of crude oil in the United States is directly linked to WTI,
subject to market conditions in the United States.
Royalties
-
Our production in the United States is subject to federal and private
royalties, severance tax, and ad valorem tax at a combined rate of
approximately 27.5% of sales.
Operating expense
-
Operating expense was lower than the previous quarter due to lower fuel
and salt water disposal costs.
General and administration
-
General and administration expense was consistent with the prior
quarter.
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)
|
|
|
2015
|
2015
|
2014
|
|
|
2015
|
2014
|
|
General and administration
|
|
|
500
|
957
|
(2,574)
|
|
|
1,457
|
(6,325)
|
|
Current income taxes
|
|
|
(547)
|
(377)
|
(378)
|
|
|
(924)
|
(551)
|
|
Interest expense
|
|
|
(14,550)
|
(13,298)
|
(12,334)
|
|
|
(27,848)
|
(23,794)
|
|
Realized gain on derivatives
|
|
|
3,081
|
6,257
|
2,419
|
|
|
9,338
|
5,059
|
|
Realized foreign exchange (loss) gain
|
|
|
(2,740)
|
3,306
|
587
|
|
|
566
|
(1,454)
|
|
Realized other income
|
|
|
204
|
222
|
74
|
|
|
426
|
295
|
|
Fund flows from operations
|
|
|
(14,052)
|
(2,933)
|
(12,206)
|
|
|
(16,985)
|
(26,770)
|
|
|
|
|
|
|
|
|
General and administration
-
The decrease in general and administration costs for the three and six
months ended June 30, 2015 versus the comparable periods in 2014 is due
to a decrease in staff-related expenditures, general cost saving
initiatives in response to declining crude prices, and increased salary
allocations to the various segments.
Current income taxes
-
Taxes in our corporate segment relate to holding companies that pay
current taxes in foreign jurisdictions.
Interest expense
-
Interest expense increased in Q2 2015 versus Q1 2015 and Q2 2014
primarily due to the recognition of a full quarter of interest expense
related to the finance lease recognized in Q1 2015. For the six months
ended June 30, 2015, the increase versus the comparable period in 2014
is due to increased borrowings under our revolving credit facility, as
well as the aforementioned interest on the finance lease.
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) up to 50% of net of
royalty volumes through a portfolio of forward collars, swaps, and
physical fixed price arrangements.
-
We believe that our hedging philosophy and approach increases the
stability of revenues, cash flows and future dividends while also
assisting us in the execution of our capital and development plans.
-
The realized gain in Q2 2015 related primarily to amounts received on
our Dated Brent, WTI, and AECO derivatives, partially offset by
payments made on our foreign exchange derivatives.
-
A listing of derivative positions as at June 30, 2015 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)
|
|
|
2015
|
2015
|
2014
|
2014
|
2014
|
2014
|
2013
|
2013
|
|
Petroleum and natural gas sales
|
|
|
264,331
|
195,885
|
306,073
|
344,688
|
387,684
|
381,183
|
325,108
|
327,185
|
|
Net earnings
|
|
|
6,813
|
1,275
|
58,642
|
53,903
|
53,993
|
102,788
|
101,510
|
67,796
|
|
Net earnings per share
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
0.06
|
0.01
|
0.55
|
0.50
|
0.51
|
1.00
|
1.00
|
0.67
|
|
|
Diluted
|
|
|
0.06
|
0.01
|
0.54
|
0.50
|
0.50
|
0.99
|
0.98
|
0.66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table shows a reconciliation of the change in net
earnings:
|
($M)
|
Q2/15 vs. Q1/15
|
Q2/15 vs. Q2/14
|
2015 vs. 2014
|
|
Net earnings - Comparative period
|
1,275
|
53,993
|
156,781
|
|
Changes in:
|
|
|
|
|
Fund flows from operations
|
8,701
|
(86,580)
|
(171,148)
|
|
Equity based compensation
|
1,154
|
331
|
(2,237)
|
|
Unrealized gain or loss on derivative instruments
|
24,075
|
5,626
|
(18,279)
|
|
Unrealized foreign exchange gain or loss
|
9,876
|
28,777
|
1,932
|
|
Unrealized other expense
|
57
|
(308)
|
(315)
|
|
Accretion
|
(38)
|
237
|
274
|
|
Depletion and depreciation
|
(20,189)
|
(6,244)
|
2,251
|
|
Deferred tax
|
(18,098)
|
10,981
|
38,829
|
|
Net earnings - Current period
|
6,813
|
6,813
|
8,088
|
|
|
|
|
|
|
|
|
The fluctuations in net earnings from quarter-to-quarter and from
year-to-year are caused by changes in both cash and non-cash based
income and charges. Cash based items are reflected in fund flows from
operations and include: sales, royalties, operating expenses,
transportation, general and administration expense, current tax
expense, interest expense, realized gains and losses on derivative
instruments, and realized foreign exchange gains and losses. Non-cash
items include: equity based compensation expense, unrealized gains and
losses on derivative instruments, unrealized foreign exchange gains and
losses, accretion, depletion and depreciation expense, and deferred
taxes. In addition, non-cash items may also include amounts resulting
from acquisitions or charges resulting from impairment or impairment
recoveries.
Equity based compensation
Equity based compensation expense relates to non-cash compensation
expense attributable to long-term incentives granted to directors,
officers, and employees under the 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 in Q2 2015 was lower than Q1 2015 as a
result of awards that vested during Q2 2015 with higher actual
performance conditions. For the six months ended June 30, 2015, equity
based compensation expense was higher versus the comparable period due
to a higher number of awards outstanding.
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.
For the six months ended June 30, 2015, we recognized an unrealized loss
on derivative instruments of $15.9 million, relating primarily to our
TTF, Dated Brent, and WTI swaps and collars. As at June 30, 2015, we
have a net derivative asset position of $8.9 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 months ended June 30, 2015, the Canadian dollar weakened
versus the Euro and the US dollar, resulting in an unrealized foreign
exchange gain of $5.0 million. For the six months ended June 30, 2015,
the foreign exchange gain of $0.2 million was driven by a significant
weakening of the Canadian dollar against the US dollar, offset by a
slight strengthening of the Canadian dollar relative to the Euro.
Accretion
Fluctuations in accretion expense are primarily the result of changes in
discount rates applicable to the balance of asset retirement
obligations and additions resulting from drilling and acquisitions.
Q2 2015 accretion expense was relatively consistent with all comparative
periods.
Depletion and depreciation
Fluctuations in depletion and depreciation expense are primarily the
result of changes in produced crude oil and natural gas volumes.
Depletion and depreciation on a per boe basis for Q2 2015 of $22.98 was
slightly higher as compared to $21.90 and $22.45 in Q1 2015 and Q2
2014, respectively. The increase is due to increased production from
light crude oil properties in Saskatchewan, Canada which has higher per
boe depletion expense, and decreased production from natural gas
properties in Drayton Valley, Canada and in the Netherlands, which have
lower per boe depletion expense. On a year-over-year basis, depletion
and depreciation on a per boe decreased to $22.48 per boe for the six
months ended June 30, 2015, as compared to $22.78 in the comparable
period in the prior year. This decrease is primarily due to lower
production in the Cardium light crude oil resource play in Canada and
in Australia, which experience higher per boe amounts.
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
normalized 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.
In the current low commodity price environment, Vermilion's net debt to
fund flows ratio is expected to be higher than the longer term target
ratio. During this period, Vermilion will remain focused on
maintaining a strong balance sheet and will manage its business
accordingly.
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)
|
|
|
|
2015
|
2014
|
|
|
2015
|
2014
|
|
Revolving credit facility
|
|
|
|
3.0%
|
3.1%
|
|
|
1,200,077
|
1,014,067
|
|
Senior unsecured notes (1)
|
|
|
|
6.5%
|
6.5%
|
|
|
224,457
|
224,013
|
|
Long-term debt
|
|
|
|
3.6%
|
3.8%
|
|
|
1,424,534
|
1,238,080
|
|
(1)
|
The senior unsecured notes, which will mature on February 10, 2016, are
included in the current portion of long-term debt as at June 30, 2015.
|
Revolving Credit Facility
On January 30, 2015, Vermilion increased its credit facility from $1.5
billion to $1.75 billion. During Q2 2015, we negotiated a further
expansion and extension of our existing revolving credit facilities
from $1.75 billion to $2 billion with a maturity of May 2019. The
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,
|
|
|
|
|
2015
|
|
|
2014
|
|
Total facility amount
|
|
|
$2.0 billion
|
|
|
$1.5 billion
|
|
Amount drawn
|
|
|
$1.2 billion
|
|
|
$1.0 billion
|
|
Letters of credit outstanding
|
|
|
$26.5 million
|
|
|
$8.6 million
|
|
Facility maturity date
|
|
|
31-May-19
|
|
|
31-May-17
|
|
|
|
|
|
|
|
|
In addition, the revolving credit facility is subject to the following
covenants:
|
|
|
|
|
|
|
|
As at
|
|
|
|
|
|
|
|
|
Jun 30,
|
|
|
Dec 31,
|
|
Financial covenant
|
|
|
|
Limit
|
|
|
2015
|
|
|
2014
|
|
Consolidated total debt to consolidated EBITDA
|
|
|
|
4.0
|
|
|
1.84
|
|
|
1.21
|
|
Consolidated total senior debt to consolidated EBITDA
|
|
|
|
3.0
|
|
|
1.52
|
|
|
0.99
|
|
Consolidated total senior debt to total capitalization
|
|
|
|
50%
|
|
|
35%
|
|
|
31%
|
|
|
|
|
|
|
|
|
|
|
|
|
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", "Current portion of long-term debt", and "Finance lease
obligation" 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", "Current portion of long-term debt",
"Finance lease obligation", 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
|
|
|
|
|
|
$225.0 million
|
|
Interest rate
|
|
|
|
|
|
6.5% per annum
|
|
Issued date
|
|
|
|
|
|
February 10, 2011
|
|
Maturity date
|
|
|
|
|
|
February 10, 2016
|
|
|
|
|
|
|
|
|
Vermilion may redeem all or part of the senior unsecured notes at 100%
of their principal amount plus any accrued and unpaid interest. The
notes were initially recognized at fair value net of transaction costs
and are subsequently measured at amortized cost using an effective
interest rate of 7.1%.
Net debt
Net debt is reconciled to its most directly comparable GAAP measure,
long-term debt, as follows:
|
|
|
|
|
As at
|
|
|
|
|
|
Jun 30,
|
|
|
Dec 31,
|
|
($M)
|
|
|
|
2015
|
|
|
2014
|
|
Long-term debt
|
|
|
|
1,200,077
|
|
|
1,238,080
|
|
Current liabilities(1)
|
|
|
|
479,848
|
|
|
365,729
|
|
Current assets
|
|
|
|
(302,023)
|
|
|
(338,159)
|
|
Net debt
|
|
|
|
1,377,902
|
|
|
1,265,650
|
|
|
|
|
|
|
|
|
|
|
Ratio of net debt to annualized fund flows from operations
|
|
|
|
2.8
|
|
|
1.6
|
|
(1)
|
Includes the current portion of long-term debt, which, as at June 30,
2015, represents
the senior unsecured notes that will mature on February 10, 2016.
|
Long term debt, including the current portion, as at June 30, 2015
increased to $1.42 billion from $1.24 billion as at December 31, 2014
as a result of draws on the revolving credit facility during the
current year to fund capital expenditures, particularly relating to
development expenditures in Canada and Ireland. The increase in
long-term debt resulted in an increase to net debt from $1.27 billion
to $1.38 billion. As a result of this increase to long-term debt and
weak commodity prices, the ratio of net debt to fund flows from
operations increased from 1.6 times as at December 31, 2014 to 2.8
times for the six months ended June 30, 2015.
Shareholders' capital
During the six months ended June 30, 2015, we maintained monthly
dividends at $0.215 per share and declared dividends which totalled
$140.4 million.
The following table outlines our dividend payment history:
|
Date
|
|
|
|
|
|
Monthly dividend per unit or share
|
|
January 2003 to December 2007
|
|
|
|
|
|
$0.170
|
|
January 2008 to December 2012
|
|
|
|
|
|
$0.190
|
|
January 2013 to December 31, 2013
|
|
|
|
|
|
$0.200
|
|
January 2014 to Present
|
|
|
|
|
|
$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
commodity price 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. In a further
step to preserve our financial flexibility and conservatively exercise
our access to capital, an amendment to our existing DRIP to include a
Premium Dividend™ Component was announced in February 2015. The
Premium Dividend™ Component, when combined with our continuing Dividend
Reinvestment Component, increases our access to the lowest cost sources
of equity capital available. While the Premium Dividend™ results in a
modest amount of equity issuance, we believe it represents the most
prudent approach to preserving near-term balance sheet strength. We
view implementation of a Premium Dividend™ as a short-term measure to
maintain our financial flexibility while we continue to lower our unit
costs and await further clarity on the direction of commodity prices.
Both components of our program can be turned off at the company's
discretion, offering considerable flexibility. We will actively
monitor our ongoing needs and manage our continued use of each
component as circumstances dictate. It is not currently expected that
Vermilion will be required to change its dividend in 2015.
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, 2014
|
|
107,303
|
|
|
1,959,021
|
|
Issuance of shares pursuant to the dividend reinvestment and Premium
DividendTM plans
|
|
1,195
|
|
|
63,679
|
|
Vesting of equity based awards
|
|
1,158
|
|
|
56,855
|
|
Share-settled dividends on vested equity based awards
|
|
135
|
|
|
7,561
|
|
Shares issued pursuant to the employee savings and bonus plans
|
|
15
|
|
|
816
|
|
Balance as at June 30, 2015
|
|
109,806
|
|
|
2,087,932
|
As at June 30, 2015, there were approximately 1.7 million VIP awards
outstanding. As at August 6, 2015, there were approximately 110.1
million common shares issued and outstanding.
ASSET RETIREMENT OBLIGATIONS
As at June 30, 2015, asset retirement obligations were $351.3 million
compared to $350.8 million as at December 31, 2014.
The slight increase in asset retirement obligations is largely
attributable to accretion and additions from new wells drilled
year-to-date, offset by an overall increase in the discount rates
applied to the abandonment obligations.
OFF BALANCE SHEET ARRANGEMENTS
We have certain lease agreements that are entered into in the normal
course of operations, including operating leases for which no asset or
liability value has been assigned to the consolidated balance sheet as
at June 30, 2015.
We have not entered into any guarantee or off balance sheet arrangements
that would materially impact our financial position or results of
operations.
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, 2014.
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.
There have been no material changes to our critical accounting
estimates used in applying accounting policies for the six months ended
June 30, 2015. Further information, including a discussion of critical
accounting estimates, can be found in the notes to the Consolidated
Financial Statements and annual MD&A for the year ended December 31,
2014, available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.
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, 2015
|
|
|
|
Six Months Ended June 30, 2015
|
|
|
Three Months
Ended June
30, 2014
|
|
Six Months
Ended June
30, 2014
|
|
|
|
|
Oil & NGLs
|
|
|
Natural Gas
|
|
|
Total
|
|
|
|
Oil & NGLs
|
|
|
Natural Gas
|
|
|
Total
|
|
|
Total
|
|
Total
|
|
|
|
|
$/bbl
|
|
|
$/mcf
|
|
|
$/boe
|
|
|
|
$/bbl
|
|
|
$/mcf
|
|
|
$/boe
|
|
|
$/boe
|
|
$/boe
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
59.06
|
|
|
2.78
|
|
|
40.59
|
|
|
|
54.14
|
|
|
2.88
|
|
|
38.24
|
|
|
71.56
|
|
70.55
|
|
Royalties
|
|
|
(5.31)
|
|
|
0.17
|
|
|
(2.56)
|
|
|
|
(5.59)
|
|
|
(0.03)
|
|
|
(3.25)
|
|
|
(7.99)
|
|
(7.61)
|
|
Transportation
|
|
|
(2.67)
|
|
|
(0.18)
|
|
|
(1.99)
|
|
|
|
(2.55)
|
|
|
(0.17)
|
|
|
(1.90)
|
|
|
(1.76)
|
|
(1.75)
|
|
Operating
|
|
|
(10.53)
|
|
|
(1.39)
|
|
|
(9.58)
|
|
|
|
(9.78)
|
|
|
(1.40)
|
|
|
(9.19)
|
|
|
(9.28)
|
|
(9.31)
|
|
Operating netback
|
|
|
40.55
|
|
|
1.38
|
|
|
26.46
|
|
|
|
36.22
|
|
|
1.28
|
|
|
23.90
|
|
|
52.53
|
|
51.88
|
|
General and administration
|
|
|
|
|
|
|
|
|
(2.45)
|
|
|
|
|
|
|
|
|
|
(2.15)
|
|
|
(2.88)
|
|
(2.32)
|
|
Fund flows from operations netback
|
|
|
|
|
|
|
|
|
24.01
|
|
|
|
|
|
|
|
|
|
21.75
|
|
|
49.65
|
|
49.56
|
|
France
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
72.83
|
|
|
1.53
|
|
|
71.96
|
|
|
|
68.97
|
|
|
1.53
|
|
|
68.52
|
|
|
117.29
|
|
117.41
|
|
Royalties
|
|
|
(5.92)
|
|
|
(0.01)
|
|
|
(5.84)
|
|
|
|
(5.72)
|
|
|
(0.01)
|
|
|
(5.68)
|
|
|
(7.34)
|
|
(7.34)
|
|
Transportation
|
|
|
(3.15)
|
|
|
-
|
|
|
(3.11)
|
|
|
|
(3.19)
|
|
|
-
|
|
|
(3.17)
|
|
|
(5.07)
|
|
(4.91)
|
|
Operating
|
|
|
(10.72)
|
|
|
(1.16)
|
|
|
(10.67)
|
|
|
|
(11.14)
|
|
|
(1.16)
|
|
|
(11.11)
|
|
|
(15.58)
|
|
(15.98)
|
|
Operating netback
|
|
|
53.04
|
|
|
0.36
|
|
|
52.34
|
|
|
|
48.92
|
|
|
0.36
|
|
|
48.56
|
|
|
89.30
|
|
89.18
|
|
General and administration
|
|
|
|
|
|
|
|
|
(4.30)
|
|
|
|
|
|
|
|
|
|
(4.84)
|
|
|
(5.24)
|
|
(5.21)
|
|
Other income
|
|
|
|
|
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
15.39
|
|
|
-
|
|
-
|
|
Current income taxes
|
|
|
|
|
|
|
|
|
(8.21)
|
|
|
|
|
|
|
|
|
|
(11.43)
|
|
|
(23.30)
|
|
(24.25)
|
|
Fund flows from operations netback
|
|
|
|
|
|
|
|
|
39.83
|
|
|
|
|
|
|
|
|
|
47.68
|
|
|
60.76
|
|
59.72
|
|
Netherlands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
53.28
|
|
|
7.92
|
|
|
47.63
|
|
|
|
53.15
|
|
|
8.01
|
|
|
48.13
|
|
|
48.14
|
|
56.06
|
|
Royalties
|
|
|
-
|
|
|
(0.44)
|
|
|
(2.58)
|
|
|
|
-
|
|
|
(0.36)
|
|
|
(2.11)
|
|
|
(1.12)
|
|
(2.28)
|
|
Operating
|
|
|
-
|
|
|
(1.83)
|
|
|
(10.78)
|
|
|
|
-
|
|
|
(1.80)
|
|
|
(10.66)
|
|
|
(10.29)
|
|
(9.76)
|
|
Operating netback
|
|
|
53.28
|
|
|
5.65
|
|
|
34.27
|
|
|
|
53.15
|
|
|
5.85
|
|
|
35.36
|
|
|
36.73
|
|
44.02
|
|
General and administration
|
|
|
|
|
|
|
|
|
(0.90)
|
|
|
|
|
|
|
|
|
|
(1.13)
|
|
|
(0.53)
|
|
(0.73)
|
|
Current income taxes
|
|
|
|
|
|
|
|
|
(4.67)
|
|
|
|
|
|
|
|
|
|
(4.49)
|
|
|
(2.10)
|
|
(3.99)
|
|
Fund flows from operations netback
|
|
|
|
|
|
|
|
|
28.70
|
|
|
|
|
|
|
|
|
|
29.74
|
|
|
34.10
|
|
39.30
|
|
Germany
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
-
|
|
|
7.22
|
|
|
43.31
|
|
|
|
-
|
|
|
7.38
|
|
|
44.27
|
|
|
45.36
|
|
49.50
|
|
Royalties
|
|
|
-
|
|
|
(1.52)
|
|
|
(9.12)
|
|
|
|
-
|
|
|
(1.29)
|
|
|
(7.71)
|
|
|
(9.34)
|
|
(10.11)
|
|
Transportation
|
|
|
-
|
|
|
(0.84)
|
|
|
(5.05)
|
|
|
|
-
|
|
|
(0.72)
|
|
|
(4.29)
|
|
|
(4.30)
|
|
(3.65)
|
|
Operating
|
|
|
-
|
|
|
(0.93)
|
|
|
(5.60)
|
|
|
|
-
|
|
|
(1.13)
|
|
|
(6.78)
|
|
|
(8.35)
|
|
(8.90)
|
|
Operating netback
|
|
|
-
|
|
|
3.93
|
|
|
23.54
|
|
|
|
-
|
|
|
4.24
|
|
|
25.49
|
|
|
23.37
|
|
26.84
|
|
General and administration
|
|
|
|
|
|
|
|
|
(5.85)
|
|
|
|
|
|
|
|
|
|
(6.12)
|
|
|
(3.39)
|
|
(3.46)
|
|
Current income taxes
|
|
|
|
|
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
-
|
|
|
(2.07)
|
|
(2.58)
|
|
Fund flows from operations netback
|
|
|
|
|
|
|
|
|
17.69
|
|
|
|
|
|
|
|
|
|
19.37
|
|
|
17.91
|
|
20.80
|
|
Australia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
80.87
|
|
|
-
|
|
|
80.87
|
|
|
|
81.60
|
|
|
-
|
|
|
81.60
|
|
|
126.87
|
|
127.11
|
|
Operating
|
|
|
(26.02)
|
|
|
-
|
|
|
(26.02)
|
|
|
|
(25.91)
|
|
|
-
|
|
|
(25.91)
|
|
|
(25.99)
|
|
(25.12)
|
|
PRRT (1)
|
|
|
(4.85)
|
|
|
-
|
|
|
(4.85)
|
|
|
|
(6.19)
|
|
|
-
|
|
|
(6.19)
|
|
|
(27.39)
|
|
(28.14)
|
|
Operating netback
|
|
|
50.00
|
|
|
-
|
|
|
50.00
|
|
|
|
49.50
|
|
|
-
|
|
|
49.50
|
|
|
73.49
|
|
73.85
|
|
General and administration
|
|
|
|
|
|
|
|
|
(1.64)
|
|
|
|
|
|
|
|
|
|
(2.81)
|
|
|
(3.58)
|
|
(2.45)
|
|
Corporate income taxes
|
|
|
|
|
|
|
|
|
(7.39)
|
|
|
|
|
|
|
|
|
|
(6.17)
|
|
|
(12.27)
|
|
(12.41)
|
|
Fund flows from operations netback
|
|
|
|
|
|
|
|
|
40.97
|
|
|
|
|
|
|
|
|
|
40.52
|
|
|
57.64
|
|
58.99
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
60.57
|
|
|
-
|
|
|
60.57
|
|
|
|
54.07
|
|
|
-
|
|
|
54.07
|
|
|
-
|
|
-
|
|
Royalties
|
|
|
(17.08)
|
|
|
-
|
|
|
(17.08)
|
|
|
|
(15.92)
|
|
|
-
|
|
|
(15.92)
|
|
|
-
|
|
-
|
|
Operating
|
|
|
(9.88)
|
|
|
-
|
|
|
(9.88)
|
|
|
|
(13.04)
|
|
|
-
|
|
|
(13.04)
|
|
|
-
|
|
-
|
|
Operating netback
|
|
|
33.61
|
|
|
-
|
|
|
33.61
|
|
|
|
25.11
|
|
|
-
|
|
|
25.11
|
|
|
-
|
|
-
|
|
General and administration
|
|
|
|
|
|
|
|
|
(86.12)
|
|
|
|
|
|
|
|
|
|
(81.87)
|
|
|
-
|
|
-
|
|
Fund flows from operations netback
|
|
|
|
|
|
|
|
|
(52.51)
|
|
|
|
|
|
|
|
|
|
(56.76)
|
|
|
-
|
|
-
|
|
Total Company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
|
|
68.90
|
|
|
4.86
|
|
|
54.65
|
|
|
|
64.23
|
|
|
5.06
|
|
|
51.19
|
|
|
82.96
|
|
85.70
|
|
Realized hedging (loss) gain
|
|
|
(0.13)
|
|
|
0.33
|
|
|
0.64
|
|
|
|
0.26
|
|
|
0.38
|
|
|
1.04
|
|
|
0.52
|
|
0.56
|
|
Royalties
|
|
|
(4.37)
|
|
|
(0.25)
|
|
|
(3.33)
|
|
|
|
(4.73)
|
|
|
(0.31)
|
|
|
(3.62)
|
|
|
(6.21)
|
|
(5.91)
|
|
Transportation
|
|
|
(2.23)
|
|
|
(0.38)
|
|
|
(2.25)
|
|
|
|
(2.34)
|
|
|
(0.36)
|
|
|
(2.27)
|
|
|
(2.57)
|
|
(2.44)
|
|
Operating
|
|
|
(14.03)
|
|
|
(1.45)
|
|
|
(12.12)
|
|
|
|
(12.97)
|
|
|
(1.48)
|
|
|
(11.40)
|
|
|
(12.46)
|
|
(12.95)
|
|
PRRT (1)
|
|
|
(1.09)
|
|
|
-
|
|
|
(0.70)
|
|
|
|
(1.03)
|
|
|
-
|
|
|
(0.64)
|
|
|
(2.72)
|
|
(3.67)
|
|
Operating netback
|
|
|
47.05
|
|
|
3.11
|
|
|
36.89
|
|
|
|
43.42
|
|
|
3.29
|
|
|
34.30
|
|
|
59.52
|
|
61.29
|
|
General and administration
|
|
|
|
|
|
|
|
|
(3.00)
|
|
|
|
|
|
|
|
|
|
(3.12)
|
|
|
(3.80)
|
|
(3.59)
|
|
Interest expense
|
|
|
|
|
|
|
|
|
(3.01)
|
|
|
|
|
|
|
|
|
|
(3.10)
|
|
|
(2.64)
|
|
(2.65)
|
|
Realized foreign exchange (loss) gain
|
|
|
|
|
|
|
|
|
(0.57)
|
|
|
|
|
|
|
|
|
|
0.06
|
|
|
0.12
|
|
(0.16)
|
|
Other income
|
|
|
|
|
|
|
|
|
0.04
|
|
|
|
|
|
|
|
|
|
3.58
|
|
|
0.02
|
|
0.03
|
|
Corporate income taxes (1)
|
|
|
|
|
|
|
|
|
(3.59)
|
|
|
|
|
|
|
|
|
|
(3.89)
|
|
|
(6.98)
|
|
(7.94)
|
|
Fund flows from operations netback
|
|
|
|
|
|
|
|
|
26.76
|
|
|
|
|
|
|
|
|
|
27.83
|
|
|
46.24
|
|
46.98
|
|
(1)
|
Vermilion considers Australian PRRT to be an operating item and
accordingly has included PRRT in the calculation of operating
netbacks. Current income taxes
presented above excludes PRRT.
|
Supplemental Table 2: Hedges
The following tables outline Vermilion's outstanding risk management
positions as at June 30, 2015:
|
|
|
|
Note
|
|
|
Volume
|
|
|
Strike Price(s)
|
|
Crude Oil
|
|
|
|
|
|
|
|
|
|
|
WTI - Collar
|
|
|
|
|
|
|
|
|
|
|
July 2015 - September 2015
|
|
|
1
|
|
|
250 bbl/d
|
|
|
60.00 - 68.60 US $
|
|
July 2015 - October 2015
|
|
|
1
|
|
|
250 bbl/d
|
|
|
60.00 - 72.40 US $
|
|
July 2015 - December 2015
|
|
|
2
|
|
|
750 bbl/d
|
|
|
75.00 - 82.60 CAD $
|
|
July 2015 - December 2015
|
|
|
1
|
|
|
250 bbl/d
|
|
|
61.00 - 69.75 US $
|
|
July 2015 - March 2016
|
|
|
3
|
|
|
250 bbl/d
|
|
|
75.00 - 83.45 CAD $
|
|
July 2015 - June 2016
|
|
|
4
|
|
|
500 bbl/d
|
|
|
75.50 - 85.08 CAD $
|
|
October 2015 - December 2015
|
|
|
3
|
|
|
250 bbl/d
|
|
|
70.00 - 82.95 CAD $
|
|
WTI - Swap
|
|
|
|
|
|
|
|
|
|
|
July 2015 - September 2015
|
|
|
5
|
|
|
250 bbl/d
|
|
|
75.71 CAD $
|
|
MSW - Fixed Price Differential
|
|
|
|
|
|
|
|
|
|
|
July 2015 - September 2015
|
|
|
|
|
|
250 bbl/d
|
|
|
WTI less 2.65 US $
|
|
Dated Brent - Collar
|
|
|
|
|
|
|
|
|
|
|
April 2015 - September 2015
|
|
|
1
|
|
|
250 bbl/d
|
|
|
60.00 - 74.15 US $
|
|
July 2015 - September 2015
|
|
|
1
|
|
|
250 bbl/d
|
|
|
65.00 - 75.05 US $
|
|
July 2015 - October 2015
|
|
|
6
|
|
|
250 bbl/d
|
|
|
65.00 - 74.40 US $
|
|
July 2015 - June 2016
|
|
|
7
|
|
|
1,000 bbl/d
|
|
|
80.50 - 93.49 CAD $
|
|
July 2015 - June 2016
|
|
|
8
|
|
|
500 bbl/d
|
|
|
64.50 - 75.48 US $
|
|
October 2015 - December 2015
|
|
|
9
|
|
|
1,000 bbl/d
|
|
|
79.38 - 92.45 CAD $
|
|
October 2015 - June 2016
|
|
|
10
|
|
|
250 bbl/d
|
|
|
82.00 - 94.55 CAD $
|
|
January 2016 - June 2016
|
|
|
3
|
|
|
250 bbl/d
|
|
|
84.00 - 93.70 CAD $
|
|
(1)
|
The contracted volumes increase to 750 boe/d for any monthly settlement
periods above the contracted ceiling price.
|
|
(2)
|
The contracted volumes increase to 1,500 boe/d for any monthly
settlement
periods above the contracted ceiling price and is settled on the monthly
average price (monthly average US$/bbl multiplied by the Bank of Canada
monthly average noon day rate).
|
|
(3)
|
The contracted volumes increase to 500 boe/d for any monthly settlement
periods above the contracted ceiling price and is settled on the monthly
average price (monthly average US$/bbl multiplied by the Bank of Canada
monthly average noon day rate).
|
|
(4)
|
The contracted volumes increase to 1,250 boe/d for any monthly
settlement
periods above the contracted ceiling price and is settled on the monthly
average price (monthly average US$/bbl multiplied by the Bank of Canada
monthly average noon day rate).
|
|
(5)
|
The contract is settled on the monthly average price (monthly average
US$/bbl multiplied by the Bank of Canada monthly average noon day
rate).
|
|
(6)
|
The contracted volumes increase to 500 boe/d for any monthly settlement
periods above the contracted ceiling price.
|
|
(7)
|
The contracted volumes increase to 2,500 boe/d for any monthly
settlement
periods above the contracted ceiling price and is settled on the monthly
average price (monthly average US$/bbl multiplied by the Bank of Canada
monthly average noon day rate).
|
|
(8)
|
The contracted volumes increase to 1,000 boe/d for any monthly
settlement
periods above the contracted ceiling price.
|
|
(9)
|
The contracted volumes increase to 2,000 boe/d for any monthly
settlement
periods above the contracted ceiling price and is settled on the monthly
average price (monthly average US$/bbl multiplied by the Bank of Canada
monthly average noon day rate).
|
|
(10)
|
The contracted volumes increase to 750 boe/d for any monthly settlement
periods above the contracted ceiling price and is settled on the monthly
average price (monthly average US$/bbl multiplied by the Bank of Canada
monthly average noon day rate).
|
|
|
|
|
Note
|
|
|
Volume
|
|
|
|
|
Strike Price(s)
|
|
North American Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
AECO - Collar
|
|
|
|
|
|
|
|
|
|
|
|
|
April 2015 - October 2015
|
|
|
|
|
|
2,500 GJ/d
|
|
|
|
|
2.75 - 3.52 CAD $
|
|
April 2015 - December 2015
|
|
|
|
|
|
2,500 GJ/d
|
|
|
|
|
2.75 - 3.52 CAD $
|
|
October 2015 - December 2015
|
|
|
|
|
|
2,500 GJ/d
|
|
|
|
|
2.55 - 3.19 CAD $
|
|
November 2015 - March 2016
|
|
|
|
|
|
2,500 GJ/d
|
|
|
|
|
2.50 - 3.76 CAD $
|
|
January 2016 - December 2016
|
|
|
|
|
|
7,500 GJ/d
|
|
|
|
|
2.53 - 3.34 CAD $
|
|
April 2016 - October 2016
|
|
|
|
|
|
2,500 GJ/d
|
|
|
|
|
2.50 - 2.88 CAD $
|
|
AECO - Swap
|
|
|
|
|
|
|
|
|
|
|
|
|
April 2015 - October 2015
|
|
|
1
|
|
|
10,000 GJ/d
|
|
|
|
|
2.98 CAD $
|
|
April 2015 - December 2015
|
|
|
2
|
|
|
2,500 GJ/d
|
|
|
|
|
2.99 CAD $
|
|
AECO Basis - Fixed Price Differential
|
|
|
|
|
|
|
|
|
|
|
|
|
January 2015 - December 2015
|
|
|
|
|
|
5,000 mmbtu/d
|
|
|
|
|
Nymex HH less 0.68 US $
|
|
April 2015 - October 2015
|
|
|
|
|
|
7,500 mmbtu/d
|
|
|
|
|
Nymex HH less 0.62 US $
|
|
Nymex HH - Collar
|
|
|
|
|
|
|
|
|
|
|
|
|
April 2015 - October 2015
|
|
|
|
|
|
10,000 mmbtu/d
|
|
|
|
|
3.36 - 4.01 US $
|
|
April 2015 - December 2015
|
|
|
|
|
|
2,500 mmbtu/d
|
|
|
|
|
3.50 - 4.11 US $
|
|
November 2015 - March 2016
|
|
|
3
|
|
|
5,000 mmbtu/d
|
|
|
|
|
3.25 - 3.86 US $
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
European Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
NBP - Swap
|
|
|
|
|
|
|
|
|
|
|
|
|
July 2015 - March 2016
|
|
|
|
|
|
2,592 GJ/d
|
|
|
|
|
6.42 EUR €
|
|
October 2015 - March 2016
|
|
|
|
|
|
10,368 GJ/d
|
|
|
|
|
6.54 EUR €
|
|
January 2016 - June 2016
|
|
|
|
|
|
5,184 GJ/d
|
|
|
|
|
6.24 EUR €
|
|
January 2016 - June 2016
|
|
|
|
|
|
2,592 GJ/d
|
|
|
|
|
6.82 US $
|
|
TTF - Collar
|
|
|
|
|
|
|
|
|
|
|
|
|
January 2015 - December 2015
|
|
|
|
|
|
2,592 GJ/d
|
|
|
|
|
6.11 - 6.83 EUR €
|
|
April 2016 - December 2016
|
|
|
|
|
|
7,776 GJ/d
|
|
|
|
|
5.56 - 6.16 EUR €
|
|
TTF - Swap
|
|
|
|
|
|
|
|
|
|
|
|
|
January 2015 - December 2015
|
|
|
|
|
|
11,664 GJ/d
|
|
|
|
|
6.45 EUR €
|
|
January 2015 - March 2016
|
|
|
|
|
|
5,184 GJ/d
|
|
|
|
|
6.40 EUR €
|
|
January 2015 - June 2016
|
|
|
|
|
|
2,592 GJ/d
|
|
|
|
|
6.07 EUR €
|
|
February 2015 - March 2016
|
|
|
|
|
|
5,184 GJ/d
|
|
|
|
|
6.24 EUR €
|
|
April 2015 - December 2015
|
|
|
|
|
|
2,592 GJ/d
|
|
|
|
|
6.30 EUR €
|
|
April 2015 - March 2016
|
|
|
|
|
|
5,832 GJ/d
|
|
|
|
|
6.18 EUR €
|
|
October 2015 - December 2015
|
|
|
|
|
|
2,592 GJ/d
|
|
|
|
|
5.69 EUR €
|
|
October 2015 - March 2016
|
|
|
|
|
|
2,592 GJ/d
|
|
|
|
|
6.64 EUR €
|
|
January 2016 - June 2016
|
|
|
|
|
|
2,592 GJ/d
|
|
|
|
|
6.10 EUR €
|
|
April 2016 - December 2016
|
|
|
|
|
|
2,592 GJ/d
|
|
|
|
|
5.91 EUR €
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Electricity
|
|
|
|
|
|
|
|
|
|
|
|
|
AESO - Swap
|
|
|
|
|
|
|
|
|
|
|
|
|
January 2016 - December 2016
|
|
|
|
|
|
62.4 MWh/d
|
|
|
|
|
37.13 CAD $
|
|
AESO - Swap (Physical)
|
|
|
|
|
|
|
|
|
|
|
|
|
January 2013 - December 2015
|
|
|
|
|
|
72.0 MWh/d
|
|
|
|
|
53.17 CAD $
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
US Dollar
|
|
|
|
|
|
|
|
|
|
|
|
|
USD - Collar
|
|
|
|
|
|
|
|
|
|
|
|
|
February 2015 - December 2015
|
|
|
|
|
|
2,500,000 US $/month
|
|
|
|
|
1.180 - 1.223 CAD $
|
|
USD - Forward
|
|
|
|
|
|
|
|
|
|
|
|
|
February 2015 - December 2015
|
|
|
|
|
|
2,500,000 US $/month
|
|
|
|
|
1.198 CAD $
|
|
(1)
|
On the last business day of each month, the counterparty has the option
to increase the contracted
volumes by an additional 10,000 GJ/d at the contracted price, for the
following month.
|
|
(2)
|
On the last business day of each month, the counterparty has the option
to increase the contracted
volumes by an additional 2,500 GJ/d at the contracted price, for the
following month.
|
|
(3)
|
The contracted volumes increase to 10,000 mmbtu/d for any monthly
settlement periods above the
contracted ceiling price.
|
Supplemental Table 3: Capital Expenditures
|
|
|
|
Three Months Ended
|
|
|
|
Six Months Ended
|
|
By classification
|
|
|
Jun 30,
|
|
|
Mar 31,
|
|
|
Jun 30,
|
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
($M)
|
|
|
2015
|
|
|
2015
|
|
|
2014
|
|
|
|
2015
|
|
|
2014
|
|
Drilling and development
|
|
|
90,173
|
|
|
174,311
|
|
|
117,975
|
|
|
|
264,484
|
|
|
286,815
|
|
Exploration and evaluation
|
|
|
-
|
|
|
-
|
|
|
17,098
|
|
|
|
-
|
|
|
44,633
|
|
Capital expenditures
|
|
|
90,173
|
|
|
174,311
|
|
|
135,073
|
|
|
|
264,484
|
|
|
331,448
|
|
Property acquisition
|
|
|
480
|
|
|
35
|
|
|
-
|
|
|
|
515
|
|
|
178,227
|
|
Corporate acquisition
|
|
|
-
|
|
|
-
|
|
|
381,139
|
|
|
|
-
|
|
|
381,139
|
|
Acquisitions
|
|
|
480
|
|
|
35
|
|
|
381,139
|
|
|
|
515
|
|
|
559,366
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
Six Months Ended
|
|
By category
|
|
|
Jun 30,
|
|
|
Mar 31,
|
|
|
Jun 30,
|
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
($M)
|
|
|
2015
|
|
|
2015
|
|
|
2014
|
|
|
|
2015
|
|
|
2014
|
|
Land
|
|
|
1,469
|
|
|
742
|
|
|
950
|
|
|
|
2,211
|
|
|
5,703
|
|
Seismic
|
|
|
1,723
|
|
|
1,493
|
|
|
1,869
|
|
|
|
3,216
|
|
|
5,301
|
|
Drilling and completion
|
|
|
31,976
|
|
|
82,343
|
|
|
42,083
|
|
|
|
114,319
|
|
|
148,619
|
|
Production equipment and facilities
|
|
|
43,957
|
|
|
74,755
|
|
|
60,547
|
|
|
|
118,712
|
|
|
129,302
|
|
Recompletions
|
|
|
9,288
|
|
|
7,115
|
|
|
13,459
|
|
|
|
16,403
|
|
|
17,685
|
|
Other
|
|
|
1,760
|
|
|
7,863
|
|
|
16,165
|
|
|
|
9,623
|
|
|
24,838
|
|
Capital expenditures
|
|
|
90,173
|
|
|
174,311
|
|
|
135,073
|
|
|
|
264,484
|
|
|
331,448
|
|
Acquisitions
|
|
|
480
|
|
|
35
|
|
|
381,139
|
|
|
|
515
|
|
|
559,366
|
|
Total capital expenditures and acquisitions
|
|
|
90,653
|
|
|
174,346
|
|
|
516,212
|
|
|
|
264,999
|
|
|
890,814
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
|
Six Months Ended
|
|
By country
|
|
|
Jun 30,
|
|
|
Mar 31,
|
|
|
Jun 30,
|
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
($M)
|
|
|
2015
|
|
|
2015
|
|
|
2014
|
|
|
|
2015
|
|
|
2014
|
|
Canada
|
|
|
22,265
|
|
|
114,884
|
|
|
418,294
|
|
|
|
137,149
|
|
|
538,001
|
|
France
|
|
|
16,793
|
|
|
34,114
|
|
|
37,614
|
|
|
|
50,907
|
|
|
75,581
|
|
Netherlands
|
|
|
18,885
|
|
|
4,333
|
|
|
21,513
|
|
|
|
23,218
|
|
|
41,631
|
|
Germany
|
|
|
3,231
|
|
|
968
|
|
|
630
|
|
|
|
4,199
|
|
|
173,697
|
|
Ireland
|
|
|
20,267
|
|
|
12,955
|
|
|
27,221
|
|
|
|
33,222
|
|
|
43,457
|
|
Australia
|
|
|
6,468
|
|
|
6,455
|
|
|
10,991
|
|
|
|
12,923
|
|
|
16,682
|
|
United States
|
|
|
2,744
|
|
|
637
|
|
|
-
|
|
|
|
3,381
|
|
|
-
|
|
Corporate
|
|
|
-
|
|
|
-
|
|
|
(51)
|
|
|
|
-
|
|
|
1,765
|
|
Total capital expenditures and acquisitions
|
|
|
90,653
|
|
|
174,346
|
|
|
516,212
|
|
|
|
264,999
|
|
|
890,814
|
Supplemental Table 4: Production
|
|
|
|
|
Q2/15
|
|
|
Q1/15
|
|
|
Q4/14
|
|
|
Q3/14
|
|
|
Q2/14
|
|
|
Q1/14
|
|
|
|
|
Q4/13
|
|
|
Q3/13
|
|
|
Q2/13
|
|
|
Q1/13
|
|
|
Q4/12
|
|
|
Q3/12
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
10,182
|
|
|
10,893
|
|
|
11,384
|
|
|
11,469
|
|
|
12,676
|
|
|
9,437
|
|
|
|
|
8,719
|
|
|
7,969
|
|
|
8,885
|
|
|
7,966
|
|
|
7,983
|
|
|
7,322
|
|
|
NGLs (bbls/d)
|
|
|
3,755
|
|
|
2,976
|
|
|
2,741
|
|
|
2,291
|
|
|
2,796
|
|
|
2,071
|
|
|
|
|
1,699
|
|
|
1,897
|
|
|
1,725
|
|
|
1,335
|
|
|
1,106
|
|
|
1,204
|
|
|
Natural gas (mmcf/d)
|
|
|
64.66
|
|
|
61.78
|
|
|
58.36
|
|
|
57.07
|
|
|
57.59
|
|
|
49.53
|
|
|
|
|
41.43
|
|
|
43.40
|
|
|
43.69
|
|
|
41.04
|
|
|
31.41
|
|
|
35.54
|
|
|
Total (boe/d)
|
|
|
24,713
|
|
|
24,165
|
|
|
23,851
|
|
|
23,272
|
|
|
25,070
|
|
|
19,763
|
|
|
|
|
17,322
|
|
|
17,099
|
|
|
17,892
|
|
|
16,140
|
|
|
14,323
|
|
|
14,449
|
|
|
% of consolidated
|
|
|
48%
|
|
|
48%
|
|
|
49%
|
|
|
47%
|
|
|
49%
|
|
|
42%
|
|
|
|
|
43%
|
|
|
41%
|
|
|
42%
|
|
|
41%
|
|
|
40%
|
|
|
40%
|
|
France
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
12,746
|
|
|
11,463
|
|
|
11,133
|
|
|
11,111
|
|
|
11,025
|
|
|
10,771
|
|
|
|
|
11,131
|
|
|
11,625
|
|
|
10,390
|
|
|
10,330
|
|
|
9,843
|
|
|
9,767
|
|
|
Natural gas (mmcf/d)
|
|
|
1.03
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
-
|
|
|
5.23
|
|
|
4.19
|
|
|
4.21
|
|
|
3.91
|
|
|
3.39
|
|
|
Total (boe/d)
|
|
|
12,917
|
|
|
11,463
|
|
|
11,133
|
|
|
11,111
|
|
|
11,025
|
|
|
10,771
|
|
|
|
|
11,131
|
|
|
12,496
|
|
|
11,088
|
|
|
11,032
|
|
|
10,495
|
|
|
10,333
|
|
|
% of consolidated
|
|
|
25%
|
|
|
23%
|
|
|
22%
|
|
|
22%
|
|
|
21%
|
|
|
23%
|
|
|
|
|
27%
|
|
|
30%
|
|
|
26%
|
|
|
29%
|
|
|
29%
|
|
|
28%
|
|
Netherlands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d)
|
|
|
112
|
|
|
63
|
|
|
81
|
|
|
63
|
|
|
96
|
|
|
69
|
|
|
|
|
62
|
|
|
48
|
|
|
50
|
|
|
96
|
|
|
70
|
|
|
41
|
|
|
Natural gas (mmcf/d)
|
|
|
32.43
|
|
|
36.41
|
|
|
31.35
|
|
|
38.07
|
|
|
40.35
|
|
|
43.15
|
|
|
|
|
37.53
|
|
|
28.78
|
|
|
38.52
|
|
|
36.91
|
|
|
33.03
|
|
|
34.59
|
|
|
Total (boe/d)
|
|
|
5,517
|
|
|
6,132
|
|
|
5,306
|
|
|
6,407
|
|
|
6,822
|
|
|
7,260
|
|
|
|
|
6,318
|
|
|
4,845
|
|
|
6,470
|
|
|
6,248
|
|
|
5,574
|
|
|
5,806
|
|
|
% of consolidated
|
|
|
11%
|
|
|
12%
|
|
|
11%
|
|
|
13%
|
|
|
13%
|
|
|
16%
|
|
|
|
|
15%
|
|
|
12%
|
|
|
15%
|
|
|
16%
|
|
|
15%
|
|
|
16%
|
|
Germany
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
|
|
16.18
|
|
|
16.80
|
|
|
17.71
|
|
|
15.38
|
|
|
16.13
|
|
|
10.64
|
|
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
Total (boe/d)
|
|
|
2,696
|
|
|
2,801
|
|
|
2,952
|
|
|
2,563
|
|
|
2,689
|
|
|
1,773
|
|
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
% of consolidated
|
|
|
5%
|
|
|
6%
|
|
|
6%
|
|
|
5%
|
|
|
5%
|
|
|
4%
|
|
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Australia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
5,865
|
|
|
5,672
|
|
|
6,134
|
|
|
6,567
|
|
|
6,483
|
|
|
7,110
|
|
|
|
|
6,189
|
|
|
7,070
|
|
|
7,363
|
|
|
5,287
|
|
|
5,873
|
|
|
5,958
|
|
|
% of consolidated
|
|
|
11%
|
|
|
11%
|
|
|
12%
|
|
|
13%
|
|
|
12%
|
|
|
15%
|
|
|
|
|
15%
|
|
|
17%
|
|
|
17%
|
|
|
14%
|
|
|
16%
|
|
|
16%
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
123
|
|
|
153
|
|
|
195
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil & NGLs (bbls/d)
|
|
|
32,783
|
|
|
31,220
|
|
|
31,668
|
|
|
31,501
|
|
|
33,076
|
|
|
29,458
|
|
|
|
|
27,800
|
|
|
28,609
|
|
|
28,413
|
|
|
25,014
|
|
|
24,875
|
|
|
24,292
|
|
|
% of consolidated
|
|
|
63%
|
|
|
62%
|
|
|
64%
|
|
|
63%
|
|
|
63%
|
|
|
63%
|
|
|
|
|
68%
|
|
|
69%
|
|
|
66%
|
|
|
65%
|
|
|
69%
|
|
|
66%
|
|
|
Natural gas (mmcf/d)
|
|
|
114.29
|
|
|
115.00
|
|
|
107.42
|
|
|
110.52
|
|
|
114.08
|
|
|
103.32
|
|
|
|
|
78.96
|
|
|
77.41
|
|
|
86.40
|
|
|
82.16
|
|
|
68.34
|
|
|
73.52
|
|
|
% of consolidated
|
|
|
37%
|
|
|
38%
|
|
|
36%
|
|
|
37%
|
|
|
37%
|
|
|
37%
|
|
|
|
|
32%
|
|
|
31%
|
|
|
34%
|
|
|
35%
|
|
|
31%
|
|
|
34%
|
|
|
Total (boe/d)
|
|
|
51,831
|
|
|
50,386
|
|
|
49,571
|
|
|
49,920
|
|
|
52,089
|
|
|
46,677
|
|
|
|
|
40,960
|
|
|
41,510
|
|
|
42,813
|
|
|
38,707
|
|
|
36,265
|
|
|
36,546
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
YTD 2015
|
|
|
2014
|
|
|
2013
|
|
|
2012
|
|
|
2011
|
|
|
2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
10,535
|
|
|
11,248
|
|
|
8,387
|
|
|
7,659
|
|
|
4,701
|
|
|
2,778
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d)
|
|
|
3,367
|
|
|
2,476
|
|
|
1,666
|
|
|
1,232
|
|
|
1,297
|
|
|
1,427
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
|
|
63.23
|
|
|
55.67
|
|
|
42.39
|
|
|
37.50
|
|
|
43.38
|
|
|
43.91
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (boe/d)
|
|
|
24,441
|
|
|
23,001
|
|
|
17,117
|
|
|
15,142
|
|
|
13,227
|
|
|
11,524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated
|
|
|
48%
|
|
|
47%
|
|
|
41%
|
|
|
40%
|
|
|
38%
|
|
|
36%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
France
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
12,108
|
|
|
11,011
|
|
|
10,873
|
|
|
9,952
|
|
|
8,110
|
|
|
8,347
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
|
|
0.52
|
|
|
-
|
|
|
3.40
|
|
|
3.59
|
|
|
0.95
|
|
|
0.92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (boe/d)
|
|
|
12,194
|
|
|
11,011
|
|
|
11,440
|
|
|
10,550
|
|
|
8,269
|
|
|
8,501
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated
|
|
|
24%
|
|
|
22%
|
|
|
28%
|
|
|
28%
|
|
|
23%
|
|
|
26%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Netherlands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d)
|
|
|
88
|
|
|
77
|
|
|
64
|
|
|
67
|
|
|
58
|
|
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
|
|
34.41
|
|
|
38.20
|
|
|
35.42
|
|
|
34.11
|
|
|
32.88
|
|
|
28.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (boe/d)
|
|
|
5,823
|
|
|
6,443
|
|
|
5,967
|
|
|
5,751
|
|
|
5,538
|
|
|
4,753
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated
|
|
|
11%
|
|
|
13%
|
|
|
15%
|
|
|
15%
|
|
|
16%
|
|
|
15%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Germany
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
|
|
16.49
|
|
|
14.99
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (boe/d)
|
|
|
2,748
|
|
|
2,498
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated
|
|
|
5%
|
|
|
5%
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
5,769
|
|
|
6,571
|
|
|
6,481
|
|
|
6,360
|
|
|
8,168
|
|
|
7,354
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated
|
|
|
11%
|
|
|
13%
|
|
|
16%
|
|
|
17%
|
|
|
23%
|
|
|
23%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
|
|
138
|
|
|
49
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil & NGLs (bbls/d)
|
|
|
32,005
|
|
|
31,432
|
|
|
27,471
|
|
|
25,270
|
|
|
22,334
|
|
|
19,941
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated
|
|
|
63%
|
|
|
63%
|
|
|
67%
|
|
|
67%
|
|
|
63%
|
|
|
62%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
|
|
114.64
|
|
|
108.85
|
|
|
81.21
|
|
|
75.20
|
|
|
77.21
|
|
|
73.14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated
|
|
|
37%
|
|
|
37%
|
|
|
33%
|
|
|
33%
|
|
|
37%
|
|
|
38%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (boe/d)
|
|
|
51,113
|
|
|
49,573
|
|
|
41,005
|
|
|
37,803
|
|
|
35,202
|
|
|
32,132
|
Supplemental Table 5: Segmented Financial Results
|
|
Three Months Ended June 30, 2015
|
|
($M)
|
Canada
|
|
France
|
|
Netherlands
|
|
Germany
|
|
Ireland
|
|
Australia
|
|
United States
|
|
Corporate
|
|
Total
|
|
Drilling and development
|
21,881
|
|
16,697
|
|
18,885
|
|
3,231
|
|
20,267
|
|
6,468
|
|
2,744
|
|
-
|
|
90,173
|
|
Oil and gas sales to external customers
|
91,284
|
|
81,627
|
|
23,913
|
|
10,626
|
|
-
|
|
56,204
|
|
677
|
|
-
|
|
264,331
|
|
Royalties
|
(5,768)
|
|
(6,620)
|
|
(1,294)
|
|
(2,238)
|
|
-
|
|
-
|
|
(191)
|
|
-
|
|
(16,111)
|
|
Revenue from external customers
|
85,516
|
|
75,007
|
|
22,619
|
|
8,388
|
|
-
|
|
56,204
|
|
486
|
|
-
|
|
248,220
|
|
Transportation expense
|
(4,469)
|
|
(3,526)
|
|
-
|
|
(1,240)
|
|
(1,648)
|
|
-
|
|
-
|
|
-
|
|
(10,883)
|
|
Operating expense
|
(21,534)
|
|
(12,102)
|
|
(5,414)
|
|
(1,373)
|
|
-
|
|
(18,083)
|
|
(110)
|
|
-
|
|
(58,616)
|
|
General and administration
|
(5,510)
|
|
(4,874)
|
|
(454)
|
|
(1,435)
|
|
(628)
|
|
(1,141)
|
|
(963)
|
|
500
|
|
(14,505)
|
|
PRRT
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(3,371)
|
|
-
|
|
-
|
|
(3,371)
|
|
Corporate income taxes
|
-
|
|
(9,316)
|
|
(2,347)
|
|
-
|
|
-
|
|
(5,134)
|
|
-
|
|
(547)
|
|
(17,344)
|
|
Interest expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(14,550)
|
|
(14,550)
|
|
Realized gain on derivative instruments
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
3,081
|
|
3,081
|
|
Realized foreign exchange loss
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(2,740)
|
|
(2,740)
|
|
Realized other income
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
204
|
|
204
|
|
Fund flows from operations
|
54,003
|
|
45,189
|
|
14,404
|
|
4,340
|
|
(2,276)
|
|
28,475
|
|
(587)
|
|
(14,052)
|
|
129,496
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2015
|
|
($M)
|
Canada
|
|
France
|
|
Netherlands
|
|
Germany
|
|
Ireland
|
|
Australia
|
|
United States
|
|
Corporate
|
|
Total
|
|
Total assets
|
1,931,640
|
|
854,608
|
|
211,587
|
|
163,069
|
|
856,739
|
|
233,956
|
|
18,785
|
|
158,430
|
|
4,428,814
|
|
Drilling and development
|
136,730
|
|
50,811
|
|
23,218
|
|
4,199
|
|
33,222
|
|
12,923
|
|
3,381
|
|
-
|
|
264,484
|
|
Oil and gas sales to external customers
|
169,168
|
|
141,459
|
|
50,731
|
|
22,021
|
|
-
|
|
75,488
|
|
1,349
|
|
-
|
|
460,216
|
|
Royalties
|
(14,360)
|
|
(11,722)
|
|
(2,220)
|
|
(3,836)
|
|
-
|
|
-
|
|
(397)
|
|
-
|
|
(32,535)
|
|
Revenue from external customers
|
154,808
|
|
129,737
|
|
48,511
|
|
18,185
|
|
-
|
|
75,488
|
|
952
|
|
-
|
|
427,681
|
|
Transportation expense
|
(8,411)
|
|
(6,537)
|
|
-
|
|
(2,134)
|
|
(3,341)
|
|
-
|
|
-
|
|
-
|
|
(20,423)
|
|
Operating expense
|
(40,633)
|
|
(22,928)
|
|
(11,240)
|
|
(3,372)
|
|
-
|
|
(23,969)
|
|
(325)
|
|
-
|
|
(102,467)
|
|
General and administration
|
(9,525)
|
|
(9,985)
|
|
(1,191)
|
|
(3,043)
|
|
(1,140)
|
|
(2,595)
|
|
(2,043)
|
|
1,457
|
|
(28,065)
|
|
PRRT
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(5,725)
|
|
-
|
|
-
|
|
(5,725)
|
|
Corporate income taxes
|
-
|
|
(23,597)
|
|
(4,735)
|
|
-
|
|
-
|
|
(5,711)
|
|
-
|
|
(924)
|
|
(34,967)
|
|
Interest expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(27,848)
|
|
(27,848)
|
|
Realized gain on derivative instruments
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
9,338
|
|
9,338
|
|
Realized foreign exchange gain
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
566
|
|
566
|
|
Realized other income
|
-
|
|
31,775
|
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
426
|
|
32,201
|
|
Fund flows from operations
|
96,239
|
|
98,465
|
|
31,345
|
|
9,636
|
|
(4,481)
|
|
37,488
|
|
(1,416)
|
|
(16,985)
|
|
250,291
|
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, 2015,
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)
|
2015
|
|
|
2015
|
|
|
2014
|
|
|
2015
|
|
|
2014
|
|
Cash flows from operating activities
|
134,668
|
|
|
22,647
|
|
|
149,592
|
|
|
157,315
|
|
|
327,830
|
|
Changes in non-cash operating working capital
|
(6,390)
|
|
|
95,041
|
|
|
64,103
|
|
|
88,651
|
|
|
88,577
|
|
Asset retirement obligations settled
|
1,218
|
|
|
3,107
|
|
|
2,381
|
|
|
4,325
|
|
|
5,032
|
|
Fund flows from operations
|
129,496
|
|
|
120,795
|
|
|
216,076
|
|
|
250,291
|
|
|
421,439
|
|
Expenses related to Corrib
|
2,276
|
|
|
2,205
|
|
|
1,823
|
|
|
4,481
|
|
|
3,693
|
|
Fund flows from operations (excluding Corrib)
|
131,772
|
|
|
123,000
|
|
|
217,899
|
|
|
254,772
|
|
|
425,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
Jun 30,
|
|
|
Mar 31,
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
|
Jun 30,
|
|
($M)
|
2015
|
|
|
2015
|
|
|
2014
|
|
|
2015
|
|
|
2014
|
|
Dividends declared
|
70,976
|
|
|
69,390
|
|
|
68,710
|
|
|
140,366
|
|
|
134,717
|
|
Issuance of shares pursuant to the dividend reinvestment and Premium
DividendTM
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
plans
|
(42,301)
|
|
|
(21,378)
|
|
|
(19,149)
|
|
|
(63,679)
|
|
|
(38,034)
|
|
Net dividends
|
28,675
|
|
|
48,012
|
|
|
49,561
|
|
|
76,687
|
|
|
96,683
|
|
Drilling and development
|
90,173
|
|
|
174,311
|
|
|
117,975
|
|
|
264,484
|
|
|
286,815
|
|
Exploration and evaluation
|
-
|
|
|
-
|
|
|
17,098
|
|
|
-
|
|
|
44,633
|
|
Asset retirement obligations settled
|
1,218
|
|
|
3,107
|
|
|
2,381
|
|
|
4,325
|
|
|
5,032
|
|
Payout
|
120,066
|
|
|
225,430
|
|
|
187,015
|
|
|
345,496
|
|
|
433,163
|
|
Corrib drilling and development
|
(20,267)
|
|
|
(12,955)
|
|
|
(27,221)
|
|
|
(33,222)
|
|
|
(43,457)
|
|
Payout (excluding Corrib)
|
99,799
|
|
|
212,475
|
|
|
159,794
|
|
|
312,274
|
|
|
389,706
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at
|
|
|
|
|
|
|
|
|
Jun 30,
|
|
|
Mar 31,
|
|
|
Jun 30,
|
|
('000s of shares)
|
|
|
|
|
|
|
2015
|
|
|
2015
|
|
|
2014
|
|
Shares outstanding
|
|
|
|
|
|
|
109,806
|
|
|
107,718
|
|
|
106,620
|
|
Potential shares issuable pursuant to the VIP
|
|
|
|
|
|
|
2,820
|
|
|
3,043
|
|
|
2,751
|
|
Diluted shares outstanding
|
|
|
|
|
|
|
112,626
|
|
|
110,761
|
|
|
109,371
|
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
|
December 31,
|
|
|
Note
|
|
|
2015
|
|
|
2014
|
|
ASSETS
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
|
98,038
|
|
|
120,405
|
|
Accounts receivable
|
|
|
|
154,843
|
|
|
171,820
|
|
Crude oil inventory
|
|
|
|
20,559
|
|
|
9,510
|
|
Derivative instruments
|
|
|
|
11,098
|
|
|
23,391
|
|
Prepaid expenses
|
|
|
|
17,485
|
|
|
13,033
|
|
|
|
|
|
302,023
|
|
|
338,159
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments
|
|
|
|
-
|
|
|
1,403
|
|
Deferred taxes
|
|
|
|
163,997
|
|
|
154,816
|
|
Exploration and evaluation assets
|
3
|
|
|
376,051
|
|
|
380,621
|
|
Capital assets
|
2
|
|
|
3,586,743
|
|
|
3,511,092
|
|
|
|
|
|
4,428,814
|
|
|
4,386,091
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
|
|
203,519
|
|
|
298,196
|
|
Current portion of long-term debt
|
5
|
|
|
224,457
|
|
|
-
|
|
Dividends payable
|
6
|
|
|
23,608
|
|
|
23,070
|
|
Derivative instruments
|
|
|
|
2,169
|
|
|
-
|
|
Income taxes payable
|
|
|
|
26,095
|
|
|
44,463
|
|
|
|
|
|
479,848
|
|
|
365,729
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
5
|
|
|
1,200,077
|
|
|
1,238,080
|
|
Finance lease obligation
|
2
|
|
|
25,710
|
|
|
-
|
|
Asset retirement obligations
|
4
|
|
|
351,291
|
|
|
350,753
|
|
Deferred taxes
|
|
|
|
394,806
|
|
|
410,183
|
|
|
|
|
|
2,451,732
|
|
|
2,364,745
|
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS' EQUITY
|
|
|
|
|
|
|
|
|
Shareholders' capital
|
6
|
|
|
2,087,932
|
|
|
1,959,021
|
|
Contributed surplus
|
|
|
|
71,443
|
|
|
92,188
|
|
Accumulated other comprehensive (loss) income
|
|
|
|
(6,869)
|
|
|
5,722
|
|
Deficit
|
|
|
|
(175,424)
|
|
|
(35,585)
|
|
|
|
|
|
1,977,082
|
|
|
2,021,346
|
|
|
|
|
|
4,428,814
|
|
|
4,386,091
|
CONSOLIDATED STATEMENTS OF NET EARNINGS AND COMPREHENSIVE INCOME (LOSS)
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS,
UNAUDITED)
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
|
|
|
|
June 30,
|
|
June 30,
|
|
|
June 30,
|
|
June 30,
|
|
|
|
|
Note
|
|
|
2015
|
|
2014
|
|
|
2015
|
|
2014
|
|
REVENUE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum and natural gas sales
|
|
|
|
|
|
264,331
|
|
387,684
|
|
|
460,216
|
|
768,867
|
|
Royalties
|
|
|
|
|
|
(16,111)
|
|
(29,013)
|
|
|
(32,535)
|
|
(53,037)
|
|
Petroleum and natural gas revenue
|
|
|
|
|
|
248,220
|
|
358,671
|
|
|
427,681
|
|
715,830
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
|
|
|
|
|
|
58,616
|
|
58,213
|
|
|
102,467
|
|
116,199
|
|
Transportation
|
|
|
|
|
|
10,883
|
|
12,032
|
|
|
20,423
|
|
21,893
|
|
Equity based compensation
|
|
|
7
|
|
|
17,886
|
|
18,217
|
|
|
36,926
|
|
34,689
|
|
(Gain) loss on derivative instruments
|
|
|
|
|
|
(7,186)
|
|
(898)
|
|
|
6,527
|
|
(7,473)
|
|
Interest expense
|
|
|
|
|
|
14,550
|
|
12,334
|
|
|
27,848
|
|
23,794
|
|
General and administration
|
|
|
|
|
|
14,505
|
|
17,762
|
|
|
28,065
|
|
32,229
|
|
Foreign exchange (gain) loss
|
|
|
|
|
|
(2,291)
|
|
23,159
|
|
|
(752)
|
|
3,200
|
|
Other expense (income)
|
|
|
|
|
|
-
|
|
(178)
|
|
|
(31,736)
|
|
(145)
|
|
Accretion
|
|
|
4
|
|
|
5,713
|
|
5,950
|
|
|
11,388
|
|
11,662
|
|
Depletion and depreciation
|
|
|
2, 3
|
|
|
111,146
|
|
104,902
|
|
|
202,103
|
|
204,354
|
|
|
|
|
|
|
|
223,822
|
|
251,493
|
|
|
403,259
|
|
440,402
|
|
EARNINGS BEFORE INCOME TAXES
|
|
|
|
|
|
24,398
|
|
107,178
|
|
|
24,422
|
|
275,428
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME TAXES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
|
|
|
|
|
|
(3,130)
|
|
7,851
|
|
|
(24,358)
|
|
14,471
|
|
Current
|
|
|
|
|
|
20,715
|
|
45,334
|
|
|
40,692
|
|
104,176
|
|
|
|
|
|
|
|
17,585
|
|
53,185
|
|
|
16,334
|
|
118,647
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS
|
|
|
|
|
|
6,813
|
|
53,993
|
|
|
8,088
|
|
156,781
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER COMPREHENSIVE INCOME (LOSS)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Currency translation adjustments
|
|
|
|
|
|
27,543
|
|
(42,794)
|
|
|
(12,591)
|
|
2,741
|
|
COMPREHENSIVE INCOME (LOSS)
|
|
|
|
|
|
34,356
|
|
11,199
|
|
|
(4,503)
|
|
159,522
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS PER SHARE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
0.06
|
|
0.51
|
|
|
0.07
|
|
1.51
|
|
Diluted
|
|
|
|
|
|
0.06
|
|
0.50
|
|
|
0.07
|
|
1.49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING ('000s)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
109,319
|
|
105,577
|
|
|
108,421
|
|
103,936
|
|
Diluted
|
|
|
|
|
|
110,746
|
|
107,330
|
|
|
109,792
|
|
105,531
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
|
|
|
|
June 30,
|
|
June 30,
|
|
|
June 30,
|
|
June 30,
|
|
|
|
|
Note
|
|
|
2015
|
|
2014
|
|
|
2015
|
|
2014
|
|
OPERATING
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
|
|
|
|
|
|
6,813
|
|
53,993
|
|
|
8,088
|
|
156,781
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion
|
|
|
4
|
|
|
5,713
|
|
5,950
|
|
|
11,388
|
|
11,662
|
|
|
Depletion and depreciation
|
|
|
2, 3
|
|
|
111,146
|
|
104,902
|
|
|
202,103
|
|
204,354
|
|
|
Unrealized (gain) loss on derivative instruments
|
|
|
|
|
|
(4,105)
|
|
1,521
|
|
|
15,865
|
|
(2,414)
|
|
|
Equity based compensation
|
|
|
7
|
|
|
17,886
|
|
18,217
|
|
|
36,926
|
|
34,689
|
|
|
Unrealized foreign exchange (gain) loss
|
|
|
|
|
|
(5,031)
|
|
23,746
|
|
|
(186)
|
|
1,746
|
|
|
Unrealized other expense (income)
|
|
|
|
|
|
204
|
|
(104)
|
|
|
465
|
|
150
|
|
|
Deferred taxes
|
|
|
|
|
|
(3,130)
|
|
7,851
|
|
|
(24,358)
|
|
14,471
|
|
Asset retirement obligations settled
|
|
|
4
|
|
|
(1,218)
|
|
(2,381)
|
|
|
(4,325)
|
|
(5,032)
|
|
Changes in non-cash operating working capital
|
|
|
|
|
|
6,390
|
|
(64,103)
|
|
|
(88,651)
|
|
(88,577)
|
|
Cash flows from operating activities
|
|
|
|
|
|
134,668
|
|
149,592
|
|
|
157,315
|
|
327,830
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and development
|
|
|
2
|
|
|
(90,173)
|
|
(117,975)
|
|
|
(264,484)
|
|
(286,815)
|
|
Exploration and evaluation
|
|
|
3
|
|
|
-
|
|
(17,098)
|
|
|
-
|
|
(44,633)
|
|
Property acquisitions
|
|
|
2, 3
|
|
|
(480)
|
|
-
|
|
|
(515)
|
|
(178,227)
|
|
Corporate acquisitions, net of cash acquired
|
|
|
|
|
|
-
|
|
(176,179)
|
|
|
-
|
|
(176,179)
|
|
Changes in non-cash investing working capital
|
|
|
|
|
|
(39,305)
|
|
(24,010)
|
|
|
(27,162)
|
|
15,463
|
|
Cash flows used in investing activities
|
|
|
|
|
|
(129,958)
|
|
(335,262)
|
|
|
(292,161)
|
|
(670,391)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in long-term debt
|
|
|
|
|
|
32,947
|
|
255,727
|
|
|
187,861
|
|
205,727
|
|
Cash dividends
|
|
|
|
|
|
(28,226)
|
|
(48,665)
|
|
|
(76,149)
|
|
(94,185)
|
|
Cash flows from financing activities
|
|
|
|
|
|
4,721
|
|
207,062
|
|
|
111,712
|
|
111,542
|
|
Foreign exchange gain (loss) on cash held in foreign currencies
|
|
|
|
|
|
415
|
|
(7,232)
|
|
|
767
|
|
6,957
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
|
|
|
9,846
|
|
14,160
|
|
|
(22,367)
|
|
(224,062)
|
|
Cash and cash equivalents, beginning of period
|
|
|
|
|
|
88,192
|
|
151,337
|
|
|
120,405
|
|
389,559
|
|
Cash and cash equivalents, end of period
|
|
|
|
|
|
98,038
|
|
165,497
|
|
|
98,038
|
|
165,497
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplementary information for operating activities - cash payments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid
|
|
|
|
|
|
12,510
|
|
11,721
|
|
|
30,755
|
|
25,815
|
|
|
Income taxes paid (refunded)
|
|
|
|
|
|
(11,685)
|
|
56,486
|
|
|
58,828
|
|
77,560
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
-
|
|
|
33,968
|
|
|
-
|
|
|
-
|
|
|
33,968
|
|
Dividends declared
|
|
|
6
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(134,717)
|
|
|
(134,717)
|
|
Shares issued pursuant to the dividend reinvestment plan
|
|
|
6
|
|
|
38,034
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
38,034
|
|
Shares issued pursuant to corporate acquisition
|
|
|
|
|
|
204,960
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
204,960
|
|
Modification of equity based awards
|
|
|
|
|
|
-
|
|
|
(2,395)
|
|
|
-
|
|
|
-
|
|
|
(2,395)
|
|
Vesting of equity based awards
|
|
|
6, 7
|
|
|
47,657
|
|
|
(47,657)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Share-settled dividends on vested equity based awards
|
|
|
6, 7
|
|
|
7,519
|
|
|
-
|
|
|
-
|
|
|
(7,519)
|
|
|
-
|
|
Shares issued pursuant to the bonus plan
|
|
|
6
|
|
|
721
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
721
|
|
Balances as at June 30, 2014
|
|
|
|
|
|
1,917,334
|
|
|
59,343
|
|
|
49,883
|
|
|
(10,092)
|
|
|
2,016,468
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
Shareholders'
|
|
|
Contributed
|
|
|
Comprehensive
|
|
|
|
|
|
Shareholders'
|
|
|
|
|
Note
|
|
|
Capital
|
|
|
Surplus
|
|
|
Income (Loss)
|
|
|
Deficit
|
|
|
Equity
|
|
Balances as at January 1, 2015
|
|
|
|
|
|
1,959,021
|
|
|
92,188
|
|
|
5,722
|
|
|
(35,585)
|
|
|
2,021,346
|
|
Net earnings
|
|
|
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
8,088
|
|
|
8,088
|
|
Currency translation adjustments
|
|
|
|
|
|
-
|
|
|
-
|
|
|
(12,591)
|
|
|
-
|
|
|
(12,591)
|
|
Equity based compensation expense
|
|
|
7
|
|
|
-
|
|
|
36,110
|
|
|
-
|
|
|
-
|
|
|
36,110
|
|
Dividends declared
|
|
|
6
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(140,366)
|
|
|
(140,366)
|
|
Shares issued pursuant to the dividend reinvestment and Premium DividendTM plans
|
|
|
6
|
|
|
63,679
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
63,679
|
|
Vesting of equity based awards
|
|
|
6, 7
|
|
|
56,855
|
|
|
(56,855)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
Share-settled dividends on vested equity based awards
|
|
|
6, 7
|
|
|
7,561
|
|
|
-
|
|
|
-
|
|
|
(7,561)
|
|
|
-
|
|
Shares issued pursuant to the employee savings and bonus plans
|
|
|
6
|
|
|
816
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
816
|
|
Balances as at June 30, 2015
|
|
|
|
|
|
2,087,932
|
|
|
71,443
|
|
|
(6,869)
|
|
|
(175,424)
|
|
|
1,977,082
|
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 (loss) 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, 2015 AND 2014
(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, 2014.
These condensed consolidated interim financial statements should be read
in conjunction with Vermilion's consolidated financial statements for
the year ended December 31, 2014, which are contained within
Vermilion's Annual Report for the year ended December 31, 2014 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
August 6, 2015.
2. 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, 2014
|
|
|
2,784,634
|
|
|
15,211
|
|
|
2,799,845
|
|
Additions
|
|
|
608,709
|
|
|
9,980
|
|
|
618,689
|
|
Property acquisitions
|
|
|
176,625
|
|
|
-
|
|
|
176,625
|
|
Corporate acquisitions
|
|
|
390,523
|
|
|
-
|
|
|
390,523
|
|
Changes in estimate for asset retirement obligations
|
|
|
19,107
|
|
|
-
|
|
|
19,107
|
|
Depletion and depreciation
|
|
|
(412,768)
|
|
|
(5,072)
|
|
|
(417,840)
|
|
Effect of movements in foreign exchange rates
|
|
|
(75,635)
|
|
|
(222)
|
|
|
(75,857)
|
|
Balance at December 31, 2014
|
|
|
3,491,195
|
|
|
19,897
|
|
|
3,511,092
|
|
Additions
|
|
|
263,466
|
|
|
1,018
|
|
|
264,484
|
|
Property acquisitions
|
|
|
515
|
|
|
-
|
|
|
515
|
|
Changes in estimate for asset retirement obligations
|
|
|
(5,773)
|
|
|
-
|
|
|
(5,773)
|
|
Depletion and depreciation
|
|
|
(201,193)
|
|
|
(2,335)
|
|
|
(203,528)
|
|
Recognition of finance lease obligation
|
|
|
31,028
|
|
|
-
|
|
|
31,028
|
|
Effect of movements in foreign exchange rates
|
|
|
(11,065)
|
|
|
(10)
|
|
|
(11,075)
|
|
Balance at June 30, 2015
|
|
|
3,568,173
|
|
|
18,570
|
|
|
3,586,743
|
As part of the Elkhorn acquisition in April of 2014, Vermilion assumed
an agreement for the construction and use of a solution gas facility
which was under construction at the time of acquisition. The substance
of the arrangement has been determined to be a lease and has been
classified as a finance lease. The carrying amount of the asset and
liability at the commencement date in the first quarter of 2015 was
$31.0 million, with the liability being apportioned between current
($3.9 million) and long-term ($27.1 million).
3. EXPLORATION AND EVALUATION ASSETS
The following table reconciles the change in Vermilion's exploration and
evaluation assets:
|
($M)
|
|
|
|
|
Exploration and Evaluation Assets
|
|
Balance at January 1, 2014
|
|
|
|
|
136,259
|
|
Additions
|
|
|
|
|
69,035
|
|
Changes in estimate for asset retirement obligations
|
|
|
|
|
22
|
|
Property acquisitions
|
|
|
|
|
46,135
|
|
Corporate acquisitions
|
|
|
|
|
138,264
|
|
Depreciation
|
|
|
|
|
(5,038)
|
|
Effect of movements in foreign exchange rates
|
|
|
|
|
(4,056)
|
|
Balance at December 31, 2014
|
|
|
|
|
380,621
|
|
Changes in estimate for asset retirement obligations
|
|
|
|
|
(21)
|
|
Depreciation
|
|
|
|
|
(4,117)
|
|
Effect of movements in foreign exchange rates
|
|
|
|
|
(432)
|
|
Balance at June 30, 2015
|
|
|
|
|
376,051
|
|
|
|
|
|
|
|
4. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the change in Vermilion's asset
retirement obligations:
|
($M)
|
|
|
|
|
Asset Retirement Obligations
|
|
Balance at January 1, 2014
|
|
|
|
|
326,162
|
|
Additional obligations recognized
|
|
|
|
|
22,565
|
|
Changes in estimates for asset retirement obligations
|
|
|
|
|
(3,434)
|
|
Obligations settled
|
|
|
|
|
(15,956)
|
|
Accretion
|
|
|
|
|
23,913
|
|
Changes in discount rates
|
|
|
|
|
9,404
|
|
Effect of movements in foreign exchange rates
|
|
|
|
|
(11,901)
|
|
Balance at December 31, 2014
|
|
|
|
|
350,753
|
|
Additional obligations recognized
|
|
|
|
|
3,395
|
|
Obligations settled
|
|
|
|
|
(4,325)
|
|
Accretion
|
|
|
|
|
11,388
|
|
Changes in discount rates
|
|
|
|
|
(9,189)
|
|
Effect of movements in foreign exchange rates
|
|
|
|
|
(731)
|
|
Balance at June 30, 2015
|
|
|
|
|
351,291
|
|
|
|
|
|
|
|
5. LONG-TERM DEBT
The following table summarizes Vermilion's outstanding long-term debt:
|
|
|
|
|
|
As at
|
|
($M)
|
|
|
|
|
June 30, 2015
|
|
|
Dec 31, 2014
|
|
Revolving credit facility
|
|
|
|
|
1,200,077
|
|
|
1,014,067
|
|
Senior unsecured notes (1)
|
|
|
|
|
224,457
|
|
|
224,013
|
|
Long-term debt
|
|
|
|
|
1,424,534
|
|
|
1,238,080
|
|
(1)
|
The senior unsecured notes, which will mature on February 10,
2016, are included in the current portion of long-term debt as
at June 30, 2015.
|
Revolving Credit Facility
At June 30, 2015, Vermilion had in place a bank revolving credit
facility totalling $2 billion, of which approximately $1.20 billion was
drawn. The facility, which matures on May 31, 2019, 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 four 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 due at the
maturity date. This facility bears interest at a rate applicable to
demand loans plus applicable margins. For the six months ended June
30, 2015, the interest rate on the revolving credit facility was
approximately 3.0% (2014 - 3.1%).
The amount available to Vermilion under this facility is reduced by
certain outstanding letters of credit associated with Vermilion's
operations totalling $26.5 million as at June 30, 2015 (December 31,
2014 - $8.6 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", "Current portion of
long-term debt", "Finance lease obligation", and "Shareholders' equity"
on the balance sheet) of less than 50%.
As at June 30, 2015, Vermilion was in compliance with all financial
covenants.
Senior Unsecured Notes
On February 10, 2011, Vermilion issued $225.0 million of senior
unsecured notes at par. The notes bear interest at a rate of 6.5% per
annum and will mature on February 10, 2016. As direct senior unsecured
obligations of Vermilion, the notes rank pari passu with all other
present and future unsecured and unsubordinated indebtedness of the
Company. Vermilion may redeem all or part of the senior unsecured
notes at 100% of their principal amount plus any accrued and unpaid
interest. The notes were initially recognized at fair value net of
transaction costs and are subsequently measured at amortized cost using
an effective interest rate of 7.1%.
6. SHAREHOLDERS' CAPITAL
The following table reconciles the change in Vermilion's shareholders'
capital:
|
Shareholders' Capital
|
|
|
|
Number of Shares ('000s)
|
|
|
|
Amount ($M)
|
|
Balance as at January 1, 2014
|
|
|
|
102,123
|
|
|
|
1,618,443
|
|
Shares issued pursuant to corporate acquisition
|
|
|
|
2,827
|
|
|
|
204,960
|
|
Shares issued pursuant to the dividend reinvestment plan
|
|
|
|
1,279
|
|
|
|
79,430
|
|
Vesting of equity based awards
|
|
|
|
955
|
|
|
|
47,925
|
|
Share-settled dividends on vested equity based awards
|
|
|
|
108
|
|
|
|
7,542
|
|
Shares issued pursuant to the bonus plan
|
|
|
|
11
|
|
|
|
721
|
|
Balance as at December 31, 2014
|
|
|
|
107,303
|
|
|
|
1,959,021
|
|
Shares issued pursuant to the dividend reinvestment and Premium DividendTM plans
|
|
|
|
1,195
|
|
|
|
63,679
|
|
Vesting of equity based awards
|
|
|
|
1,158
|
|
|
|
56,855
|
|
Share-settled dividends on vested equity based awards
|
|
|
|
135
|
|
|
|
7,561
|
|
Shares issued pursuant to the employee savings and bonus plans
|
|
|
|
15
|
|
|
|
816
|
|
Balance as at June 30, 2015
|
|
|
|
109,806
|
|
|
|
2,087,932
|
Dividends declared to shareholders for the six months ended June 30,
2015 were $140.4 million (2014 - $134.7 million).
Subsequent to the end of the period and prior to the condensed
consolidated interim financial statements being authorized for issue on
August 6, 2015, Vermilion declared dividends totalling $23.7 million or
$0.215 per share.
7. EQUITY BASED COMPENSATION
The following table summarizes the number of awards outstanding under
the Vermilion Incentive Plan ("VIP"):
|
|
|
|
|
Six Months
|
|
|
|
Full Year
|
|
Number of Awards ('000s)
|
|
|
|
2015
|
|
|
|
2014
|
|
Opening balance
|
|
|
|
1,775
|
|
|
|
1,665
|
|
Granted
|
|
|
|
585
|
|
|
|
707
|
|
Vested
|
|
|
|
(587)
|
|
|
|
(515)
|
|
Modified
|
|
|
|
-
|
|
|
|
(21)
|
|
Forfeited
|
|
|
|
(44)
|
|
|
|
(61)
|
|
Closing balance
|
|
|
|
1,729
|
|
|
|
1,775
|
The fair value of a VIP award is determined on the grant date at the
closing price of Vermilion's common shares on the Toronto Stock
Exchange, adjusted by the estimated performance factor that will
ultimately be achieved.
8. SEGMENTED INFORMATION
Vermilion has operations in three core areas: North America, Europe, and
Australia. Vermilion's operating activities in each country relate
solely to the exploration, development and production of petroleum and
natural gas. Vermilion has a Corporate head office located in Calgary,
Alberta. Costs incurred in the Corporate segment relate to Vermilion's
global hedging program and expenses incurred in financing and managing
our operating business units.
Vermilion's chief operating decision maker reviews the financial
performance of the Company by assessing the fund flows from operations
of each country individually. Fund flows from operations provides a
measure of each business unit's ability to generate cash (that is not
subject to short-term movements in non-cash operating working capital)
necessary to pay dividends, fund asset retirement obligations, and make
capital investments.
|
|
|
Three Months Ended June 30, 2015
|
|
($M)
|
|
Canada
|
|
|
France
|
|
|
Netherlands
|
|
|
Germany
|
|
|
Ireland
|
|
|
Australia
|
|
|
United
States
|
|
|
Corporate
|
|
|
Total
|
|
Drilling and development
|
|
21,881
|
|
|
16,697
|
|
|
18,885
|
|
|
3,231
|
|
|
20,267
|
|
|
6,468
|
|
|
2,744
|
|
|
-
|
|
|
90,173
|
|
Oil and gas sales to external customers
|
|
91,284
|
|
|
81,627
|
|
|
23,913
|
|
|
10,626
|
|
|
-
|
|
|
56,204
|
|
|
677
|
|
|
-
|
|
|
264,331
|
|
Royalties
|
|
(5,768)
|
|
|
(6,620)
|
|
|
(1,294)
|
|
|
(2,238)
|
|
|
-
|
|
|
-
|
|
|
(191)
|
|
|
-
|
|
|
(16,111)
|
|
Revenue from external customers
|
|
85,516
|
|
|
75,007
|
|
|
22,619
|
|
|
8,388
|
|
|
-
|
|
|
56,204
|
|
|
486
|
|
|
-
|
|
|
248,220
|
|
Transportation expense
|
|
(4,469)
|
|
|
(3,526)
|
|
|
-
|
|
|
(1,240)
|
|
|
(1,648)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(10,883)
|
|
Operating expense
|
|
(21,534)
|
|
|
(12,102)
|
|
|
(5,414)
|
|
|
(1,373)
|
|
|
-
|
|
|
(18,083)
|
|
|
(110)
|
|
|
-
|
|
|
(58,616)
|
|
General and administration
|
|
(5,510)
|
|
|
(4,874)
|
|
|
(454)
|
|
|
(1,435)
|
|
|
(628)
|
|
|
(1,141)
|
|
|
(963)
|
|
|
500
|
|
|
(14,505)
|
|
PRRT
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(3,371)
|
|
|
-
|
|
|
-
|
|
|
(3,371)
|
|
Corporate income taxes
|
|
-
|
|
|
(9,316)
|
|
|
(2,347)
|
|
|
-
|
|
|
-
|
|
|
(5,134)
|
|
|
-
|
|
|
(547)
|
|
|
(17,344)
|
|
Interest expense
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(14,550)
|
|
|
(14,550)
|
|
Realized gain on derivative instruments
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
3,081
|
|
|
3,081
|
|
Realized foreign exchange loss
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(2,740)
|
|
|
(2,740)
|
|
Realized other income
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
204
|
|
|
204
|
|
Fund flows from operations
|
|
54,003
|
|
|
45,189
|
|
|
14,404
|
|
|
4,340
|
|
|
(2,276)
|
|
|
28,475
|
|
|
(587)
|
|
|
(14,052)
|
|
|
129,496
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2014
|
|
($M)
|
|
Canada
|
|
|
France
|
|
|
Netherlands
|
|
|
Germany
|
|
|
Ireland
|
|
|
Australia
|
|
|
United
States
|
|
|
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, 2015
|
|
($M)
|
|
Canada
|
|
|
France
|
|
|
Netherlands
|
|
|
Germany
|
|
|
Ireland
|
|
|
Australia
|
|
|
United
States
|
|
|
Corporate
|
|
|
Total
|
|
Total assets
|
|
1,931,640
|
|
|
854,608
|
|
|
211,587
|
|
|
163,069
|
|
|
856,739
|
|
|
233,956
|
|
|
18,785
|
|
|
158,430
|
|
|
4,428,814
|
|
Drilling and development
|
|
136,730
|
|
|
50,811
|
|
|
23,218
|
|
|
4,199
|
|
|
33,222
|
|
|
12,923
|
|
|
3,381
|
|
|
-
|
|
|
264,484
|
|
Oil and gas sales to external customers
|
|
169,168
|
|
|
141,459
|
|
|
50,731
|
|
|
22,021
|
|
|
-
|
|
|
75,488
|
|
|
1,349
|
|
|
-
|
|
|
460,216
|
|
Royalties
|
|
(14,360)
|
|
|
(11,722)
|
|
|
(2,220)
|
|
|
(3,836)
|
|
|
-
|
|
|
-
|
|
|
(397)
|
|
|
-
|
|
|
(32,535)
|
|
Revenue from external customers
|
|
154,808
|
|
|
129,737
|
|
|
48,511
|
|
|
18,185
|
|
|
-
|
|
|
75,488
|
|
|
952
|
|
|
-
|
|
|
427,681
|
|
Transportation expense
|
|
(8,411)
|
|
|
(6,537)
|
|
|
-
|
|
|
(2,134)
|
|
|
(3,341)
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(20,423)
|
|
Operating expense
|
|
(40,633)
|
|
|
(22,928)
|
|
|
(11,240)
|
|
|
(3,372)
|
|
|
-
|
|
|
(23,969)
|
|
|
(325)
|
|
|
-
|
|
|
(102,467)
|
|
General and administration
|
|
(9,525)
|
|
|
(9,985)
|
|
|
(1,191)
|
|
|
(3,043)
|
|
|
(1,140)
|
|
|
(2,595)
|
|
|
(2,043)
|
|
|
1,457
|
|
|
(28,065)
|
|
PRRT
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(5,725)
|
|
|
-
|
|
|
-
|
|
|
(5,725)
|
|
Corporate income taxes
|
|
-
|
|
|
(23,597)
|
|
|
(4,735)
|
|
|
-
|
|
|
-
|
|
|
(5,711)
|
|
|
-
|
|
|
(924)
|
|
|
(34,967)
|
|
Interest expense
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
(27,848)
|
|
|
(27,848)
|
|
Realized gain on derivative instruments
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
9,338
|
|
|
9,338
|
|
Realized foreign exchange gain
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
566
|
|
|
566
|
|
Realized other income
|
|
-
|
|
|
31,775
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
-
|
|
|
426
|
|
|
32,201
|
|
Fund flows from operations
|
|
96,239
|
|
|
98,465
|
|
|
31,345
|
|
|
9,636
|
|
|
(4,481)
|
|
|
37,488
|
|
|
(1,416)
|
|
|
(16,985)
|
|
|
250,291
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2014
|
|
($M)
|
|
Canada
|
|
|
France
|
|
|
Netherlands
|
|
|
Germany
|
|
|
Ireland
|
|
|
Australia
|
|
|
United
States
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of fund flows from operations to net earnings
|
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
|
|
|
June 30,
|
|
|
June 30,
|
|
|
June 30,
|
|
|
June 30,
|
|
($M)
|
|
|
|
2015
|
|
|
2014
|
|
|
2015
|
|
|
2014
|
|
Fund flows from operations
|
|
|
|
129,496
|
|
|
216,076
|
|
|
250,291
|
|
|
421,439
|
|
Equity based compensation
|
|
|
|
(17,886)
|
|
|
(18,217)
|
|
|
(36,926)
|
|
|
(34,689)
|
|
Unrealized gain (loss) on derivative instruments
|
|
|
|
4,105
|
|
|
(1,521)
|
|
|
(15,865)
|
|
|
2,414
|
|
Unrealized foreign exchange gain (loss)
|
|
|
|
5,031
|
|
|
(23,746)
|
|
|
186
|
|
|
(1,746)
|
|
Unrealized other (expense) income
|
|
|
|
(204)
|
|
|
104
|
|
|
(465)
|
|
|
(150)
|
|
Accretion
|
|
|
|
(5,713)
|
|
|
(5,950)
|
|
|
(11,388)
|
|
|
(11,662)
|
|
Depletion and depreciation
|
|
|
|
(111,146)
|
|
|
(104,902)
|
|
|
(202,103)
|
|
|
(204,354)
|
|
Deferred taxes
|
|
|
|
3,130
|
|
|
(7,851)
|
|
|
24,358
|
|
|
(14,471)
|
|
Net earnings
|
|
|
|
6,813
|
|
|
53,993
|
|
|
8,088
|
|
|
156,781
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9. CAPITAL DISCLOSURES
|
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
($M except as indicated)
|
|
|
June 30, 2015
|
|
|
June 30, 2014
|
|
|
June 30, 2015
|
|
|
June 30, 2014
|
|
Long-term debt
|
|
|
1,200,077
|
|
|
1,198,866
|
|
|
1,200,077
|
|
|
1,198,866
|
|
Current liabilities(1)
|
|
|
479,848
|
|
|
377,710
|
|
|
479,848
|
|
|
377,710
|
|
Current assets
|
|
|
(302,023)
|
|
|
(407,578)
|
|
|
(302,023)
|
|
|
(407,578)
|
|
Net debt [1]
|
|
|
1,377,902
|
|
|
1,168,998
|
|
|
1,377,902
|
|
|
1,168,998
|
|
Cash flows from operating activities
|
|
|
134,668
|
|
|
149,592
|
|
|
157,315
|
|
|
327,830
|
|
Changes in non-cash operating working capital
|
|
|
(6,390)
|
|
|
64,103
|
|
|
88,651
|
|
|
88,577
|
|
Asset retirement obligations settled
|
|
|
1,218
|
|
|
2,381
|
|
|
4,325
|
|
|
5,032
|
|
Fund flows from operations
|
|
|
129,496
|
|
|
216,076
|
|
|
250,291
|
|
|
421,439
|
|
Annualized fund flows from operations [2]
|
|
|
517,984
|
|
|
864,304
|
|
|
500,582
|
|
|
842,878
|
|
Ratio of net debt to annualized fund flows from operations ([1] ÷ [2])
|
|
|
2.7
|
|
|
1.4
|
|
|
2.8
|
|
|
1.4
|
|
(1)
|
Includes the current portion of long-term debt, which, as at June 30,
2015, represents the senior unsecured notes that will mature on
February 10, 2016.
|
Long-term debt, including the current portion, as at June 30, 2015
increased to $1.42 billion from $1.24 billion as at December 31, 2014,
primarily as a result of draws on the revolving credit facility to fund
capital expenditures as fund flows from operations for the six months
ended June 30, 2015 were lower due to weakening crude oil and North
American natural gas prices. The increase in long-term debt resulted
in an increase in net debt from $1.27 billion to $1.38 billion.
Due to this increase in net debt as well as the lower commodity price
environment, lower sales volumes, and the aforementioned capital
expenditures, the ratio of net debt to fund flows from operations
increased to 2.8 for the six months ended June 30, 2015.
10. FINANCIAL INSTRUMENTS
Classification of Financial Instruments
The following table summarizes information relating to Vermilion's
financial instruments as at June 30, 2015 and December 31, 2014:
|
|
|
|
|
|
|
|
|
As at Jun 30, 2015
|
|
As at Dec 31, 2014
|
|
|
Class of financial
instrument
|
|
Consolidated balance
sheet caption
|
|
Accounting
designation
|
|
Related caption on Statement of
Net Earnings
|
|
Carrying
value ($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 (gain)
loss
|
|
98,038
|
|
98,038
|
|
120,405
|
|
120,405
|
|
Level 1
|
|
Receivables
|
|
Accounts receivable
|
|
LAR
|
|
Gains and losses on foreign exchange
are included in foreign exchange (gain)
loss and impairments are recognized
as general and administration expense
|
|
154,843
|
|
154,843
|
|
171,820
|
|
171,820
|
|
Not applicable
|
|
Derivative assets
|
|
Derivative instruments
|
|
HFT
|
|
(Gain) loss on derivative instruments
|
|
11,098
|
|
11,098
|
|
24,794
|
|
24,794
|
|
Level 2
|
|
Derivative liabilities
|
|
Derivative instruments
|
|
HFT
|
|
(Gain) loss on derivative instruments
|
|
(2,169)
|
|
(2,169)
|
|
-
|
|
-
|
|
Level 2
|
|
Payables
|
|
Accounts payable and
accrued liabilities
|
|
OTH
|
|
Gains and losses on foreign exchange
are included in foreign exchange (gain)
loss
|
|
(227,127)
|
|
(227,127)
|
|
(321,266)
|
|
(321,266)
|
|
Not applicable
|
|
|
|
Dividends payable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
Long-term debt
|
|
OTH
|
|
Interest expense
|
|
(1,424,534)
|
|
(1,425,921)
|
|
(1,238,080)
|
|
(1,238,505)
|
|
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, 2015 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, 2015
|
|
Currency risk - Euro to Canadian
|
|
|
Increase in strength of the Canadian dollar against the Euro by 5%
over the relevant closing rates
|
|
|
(2,390)
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in strength of the Canadian dollar against the Euro by 5%
over the relevant closing rates
|
|
|
2,390
|
|
|
|
|
|
|
|
|
|
Currency risk - US $ to Canadian
|
|
|
Increase in strength of the Canadian dollar against the US $ by 5%
over the relevant closing rates
|
|
|
(5,147)
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in strength of the Canadian dollar against the US $ by 5%
over the relevant closing rates
|
|
|
5,147
|
|
|
|
|
|
|
|
|
|
Commodity price risk
|
|
|
Increase in relevant oil reference price within option pricing models
used to determine the fair value of financial derivatives by US
$5.00/bbl
at the relevant valuation dates
|
|
|
(1,742)
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in relevant oil reference price within option pricing models
used to determine the fair value of financial derivatives by US
$5.00/bbl
at the relevant valuation dates
|
|
|
1,888
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in relevant TTF reference price within option pricing models
used to determine the fair value of financial derivatives by € 0.5/GJ
at the relevant valuation dates
|
|
|
(8,404)
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in relevant TTF reference price within option pricing models
used to determine the fair value of financial derivatives by € 0.5/GJ
at the relevant valuation dates
|
|
|
8,399
|
|
|
|
|
|
|
|
|
|
Interest rate risk
|
|
|
Increase in average Canadian prime interest rate by 100 basis points
during the relevant periods
|
|
|
(5,506)
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in average Canadian prime interest rate by 100 basis points
during the relevant periods
|
|
|
5,506
|
11. SIGNIFICANT TRANSACTIONS
During Q1 2015, Vermilion was awarded a recovery of costs resulting from
an oil spill at the Ambès oil terminal in France that occurred in 2007.
The French court awarded Vermilion approximately €25 million (before
taxes), of which 50% was due immediately to Vermilion upon posting a
surety bond. The payment was received in Q2 2015, with the remainder
due upon conclusion of the appeal process. Based on the recent court
decision and the conclusions of the expert engaged by the French court,
Vermilion is virtually certain that the award will be upheld.
SOURCE Vermilion Energy Inc.
