CALGARY, Aug. 10, 2015 /PRNewswire/ - 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 |
($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, |
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 |
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 |
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 |
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 ($/basic share) |
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0.06 |
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0.01 |
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0.51 |
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0.07 |
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1.51 |
Capital expenditures |
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90,173 |
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174,311 |
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135,073 |
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264,484 |
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331,448 |
Acquisitions |
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480 |
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35 |
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381,139 |
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|
515 |
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559,366 |
Asset retirement obligations
settled |
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1,218 |
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3,107 |
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2,381 |
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4,325 |
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|
5,032 |
Cash dividends ($/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 |
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% |
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% |
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% |
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 |
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 |
Operational |
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 |
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 |
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% |
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 |
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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100.84 |
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Edmonton Sweet index (US
$/bbl) |
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55.08 |
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41.83 |
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96.85 |
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48.46 |
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93.65 |
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Dated Brent (US $/bbl) |
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61.92 |
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53.97 |
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109.63 |
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57.95 |
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108.93 |
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AECO ($/GJ) |
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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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4.93 |
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TTF ($/GJ) |
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7.94 |
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8.25 |
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7.91 |
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8.10 |
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9.02 |
Average foreign currency exchange
rates |
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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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|
1.24 |
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|
1.10 |
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CDN $/Euro |
|
|
1.36 |
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|
1.40 |
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|
1.50 |
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|
1.38 |
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|
1.50 |
Share information
('000s) |
Shares outstanding - basic |
|
|
109,806 |
|
|
107,718 |
|
|
106,620 |
|
|
109,806 |
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|
106,620 |
Shares outstanding -
diluted(1) |
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|
112,626 |
|
|
110,761 |
|
|
109,371 |
|
|
112,626 |
|
|
109,371 |
Weighted average shares outstanding -
basic |
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|
109,319 |
|
|
107,513 |
|
|
105,577 |
|
|
108,421 |
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|
103,936 |
Weighted average shares outstanding -
diluted |
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110,746 |
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|
109,305 |
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|
107,330 |
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|
109,792 |
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|
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 |
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thousand dollars |
$MM |
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|
million dollars |
AECO |
|
|
the daily average benchmark price for natural gas at the AECO
'C' hub in southeast Alberta |
bbl(s) |
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barrel(s) |
bbls/d |
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|
barrels per day |
bcf |
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billion cubic feet |
boe
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|
|
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.