CALGARY, Nov. 9, 2015 /CNW/ - Vermilion Energy Inc.
("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET)
is pleased to report operating and unaudited financial results for
the three and nine months ended September
30, 2015.
HIGHLIGHTS
- Record quarterly production of 56,280 boe/d for Q3 2015
exceeded prior quarter production of 51,831 boe/d by 9%. This
quarter-over-quarter increase was primarily attributable to higher
production in the Netherlands due
to recent drilling success, with additional contributions from the
Canadian Mannville drilling program and increased Australian oil
production. Canadian third-party facility restrictions
negatively impacted average production by approximately 900 boe/d
during Q3.
- Fund flows from operations ("FFO")(1) for Q3 2015 of
$129.4 million ($1.17/basic share) were in-line with $129.5 million ($1.18/basic share) for the prior quarter despite
a quarter-over-quarter decrease in oil prices of nearly 20%.
Production growth in advantageously-priced European natural gas
enabled us to deliver consistent financial results, demonstrating a
key benefit of our international diversification.
- Vermilion was recently named
to the CDP Climate Disclosure Leadership Index ("CDLI"),
recognizing the depth and quality of our climate-related disclosure
as compared to the 200 largest companies listed on the TSX.
CDP (formerly Carbon Disclosure Project), is a global,
not-for-profit organization that manages the world's only global
environmental disclosure system. To be named to the CDLI, a
company must have a disclosure score within the top 10% of surveyed
companies. Vermilion has
voluntarily reported to CDP since 2012. We believe that by
measuring and understanding our current environmental profile, we
can adapt our business strategy to operate in an even more
environmentally and socially sustainable manner in the future.
- Vermilion is pleased to
confirm that the Irish Environmental Protection Agency issued its
final determination in support of the Corrib Industrial Emissions
License on October 8, 2015.
Previously, on September 1, 2015 the
operator, Shell E&P Ireland Limited declared the project ready
for service. As a result, the sole remaining requirement
prior to commencing gas production at Corrib is the receipt of
Ministerial Consent from Ireland's
Department of Communications, Energy and Natural Resources.
Following start-up, production levels at Corrib are expected to
rise over a period of approximately six months to a peak rate
estimated at 58 mmcf/d (9,700 boe/d), net to Vermilion by mid-2016. While the final
regulatory approvals have taken longer than we originally expected,
we believe that the regulatory process for Corrib is near
completion, and still expect to achieve first production in
approximately mid-Q4 2015. We believe that our ability to
maintain our 2015 production guidance (originally set in
March 2014) and achieve more than 10%
annual production growth, despite the later-than-expected start-up
of Corrib and 30% lower year-over-year capital expenditures, is
indicative of the operational strength of our Company.
- Responding to the continued weakness in oil prices, we expect
that our exploration and development ("E&D") capital program
will be approximately $350 million in
2016. This would represent a year-over-year reduction of more
than 25% from our forecasted 2015 E&D capital expenditures of
$485 million and nearly 50% from our
E&D capital program in 2014. At current prices, we would
expect to be able to more than fully fund our 2016 capital
expenditures and net dividends from fund flows from
operations. We are maintaining the 2016 production guidance
of 63,000 to 65,000 boe/d that we set in March 2014. Production in this range would
represent year-over-year growth of 14% to 18% as compared to 2015,
largely weighted to European natural gas. We plan to provide
detailed 2016 capital expenditure guidance prior to year-end
2015.
- Our Profitability Enhancement Program ("PEP") initiative
continues to provide significant benefits in this challenging
industry environment. Prior installments of PEP achieved
strong results in both the 1998 industry downturn and the financial
crisis of 2008-2009. We expect that our third installment of
PEP will result in cost savings related to capital spending,
operating expense and G&A expenditures estimated at between
$70 and $80 million for full-year
2015.
(1) |
Additional GAAP Financial Measure. Please see the
"Additional and Non-GAAP Financial Measures" section of
Management's Discussion and Analysis. |
Conference Call and Audio Webcast Details
Vermilion will
discuss these results in a conference call to be held on
Monday, November 9, 2015 at
9:00 AM MST (11:00 AM EST). To participate, you may call
1-888-231-8191 (Canada and US Toll
Free) or 1-647-427-7450 (International and Toronto Area). The conference call will
also be available on replay by calling 1-855-859-2056 using
conference ID number 49495111. The replay will be available
until midnight mountain time on
November 16, 2015.
You may also listen to the audio webcast by going to
http://event.on24.com/r.htm?e=1056685&s=1&k=8F525422649C891C089BC59110D715CC
or visit Vermilion's website at
www.vermilionenergy.com/ir/eventspresentations.cfm.
HIGHLIGHTS |
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Three Months Ended |
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Nine Months Ended |
($M except as indicated) |
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Sep 30, |
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Jun 30, |
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Sep 30, |
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Sep 30, |
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Sep 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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245,051 |
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264,331 |
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344,688 |
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705,267 |
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1,113,555 |
Fund flows from operations
(1) |
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129,435 |
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129,496 |
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197,898 |
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379,726 |
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619,337 |
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Fund flows from operations
($/basic share) |
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1.17 |
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1.18 |
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1.85 |
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3.48 |
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5.90 |
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Fund flows from operations
($/diluted share) |
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1.16 |
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1.17 |
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1.83 |
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3.44 |
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5.81 |
Net earnings (loss) |
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(83,310) |
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6,813 |
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53,903 |
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(75,222) |
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210,684 |
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Net earnings (loss) ($/basic
share) |
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(0.76) |
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0.06 |
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0.50 |
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(0.69) |
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2.01 |
Capital expenditures |
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93,381 |
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90,173 |
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190,033 |
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357,865 |
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521,481 |
Acquisitions |
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22,155 |
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480 |
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40,847 |
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22,670 |
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600,213 |
Asset retirement obligations
settled |
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2,123 |
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1,218 |
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4,677 |
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6,448 |
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9,709 |
Cash dividends ($/share) |
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0.645 |
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0.645 |
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0.645 |
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1.935 |
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1.935 |
Dividends declared |
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71,244 |
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70,976 |
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68,896 |
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211,610 |
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203,613 |
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% of fund flows from
operations |
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55% |
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55% |
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35% |
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56% |
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33% |
Net dividends (1) |
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26,654 |
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28,675 |
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48,480 |
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103,341 |
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145,163 |
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% of fund flows from
operations |
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21% |
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22% |
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24% |
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27% |
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23% |
Payout (1) |
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122,158 |
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120,066 |
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243,190 |
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467,654 |
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676,353 |
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% of fund flows from
operations |
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94% |
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93% |
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123% |
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123% |
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109% |
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% of fund flows from operations
(excluding the Corrib project) |
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77% |
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76% |
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107% |
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107% |
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97% |
Net debt (1) |
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1,363,043 |
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1,377,902 |
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1,243,438 |
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1,363,043 |
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1,243,438 |
Ratio of net debt to annualized fund
flows from operations (1) |
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2.6 |
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2.7 |
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1.6 |
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2.7 |
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1.5 |
Operational |
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Production |
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Crude oil (bbls/d) |
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28,164 |
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28,916 |
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29,147 |
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28,420 |
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28,890 |
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NGLs (bbls/d) |
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4,622 |
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3,867 |
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2,354 |
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3,849 |
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2,463 |
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Natural gas (mmcf/d) |
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140.97 |
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114.29 |
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110.52 |
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123.51 |
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109.33 |
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Total (boe/d) |
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56,280 |
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51,831 |
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49,920 |
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52,854 |
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49,574 |
Average realized prices |
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Crude oil and NGLs ($/bbl) |
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56.57 |
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68.90 |
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102.49 |
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61.48 |
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108.02 |
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Natural gas ($/mcf) |
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5.36 |
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4.86 |
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5.74 |
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5.18 |
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6.60 |
Production mix (% of production) |
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% priced with reference to
WTI |
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24% |
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27% |
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28% |
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26% |
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27% |
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% priced with reference to
AECO |
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22% |
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21% |
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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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20% |
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16% |
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18% |
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18% |
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18% |
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% priced with reference to Dated
Brent |
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34% |
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36% |
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36% |
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35% |
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37% |
Netbacks ($/boe) (1) |
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Operating netback |
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32.25 |
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36.89 |
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54.25 |
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33.55 |
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58.95 |
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Fund flows from operations
netback |
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24.58 |
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26.76 |
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44.08 |
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26.64 |
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46.02 |
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Operating expenses |
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10.99 |
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12.12 |
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12.53 |
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11.25 |
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12.81 |
Average reference prices |
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WTI (US $/bbl) |
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46.43 |
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57.94 |
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97.17 |
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51.00 |
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99.61 |
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Edmonton Sweet index (US
$/bbl) |
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43.01 |
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55.08 |
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89.24 |
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46.64 |
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92.17 |
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Dated Brent (US $/bbl) |
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50.26 |
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61.92 |
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101.85 |
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55.39 |
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106.57 |
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AECO ($/GJ) |
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2.75 |
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2.52 |
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3.81 |
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2.62 |
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4.56 |
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TTF ($/GJ) |
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8.04 |
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7.94 |
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7.26 |
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8.08 |
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8.41 |
Average foreign currency exchange
rates |
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CDN $/US $ |
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1.31 |
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1.23 |
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1.09 |
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1.26 |
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1.09 |
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CDN $/Euro |
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1.46 |
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1.36 |
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1.44 |
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1.40 |
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1.48 |
Share information
('000s) |
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Shares outstanding - basic |
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110,818 |
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109,806 |
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106,921 |
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110,818 |
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106,921 |
Shares outstanding - diluted
(1) |
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113,643 |
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112,626 |
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109,749 |
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113,643 |
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109,749 |
Weighted average shares outstanding -
basic |
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110,293 |
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109,319 |
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106,768 |
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109,052 |
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104,891 |
Weighted average shares outstanding -
diluted |
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111,193 |
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110,746 |
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108,290 |
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110,433 |
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106,582 |
(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 |
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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 |
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barrel of oil equivalent per day |
GJ |
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gigajoules |
HH |
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Henry Hub, a reference price paid for natural gas in US dollars
at Erath, Louisiana |
mbbls |
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thousand barrels |
mboe |
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thousand barrel of oil equivalent |
mcf |
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thousand cubic feet |
mcf/d |
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thousand cubic feet per day |
mmboe |
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million barrel of oil equivalent |
mmcf |
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million cubic feet |
mmcf/d |
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million cubic feet per day |
MWh |
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megawatt hour |
NGLs |
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natural gas liquids |
NGTL |
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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 |
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Petroleum Resource Rent Tax, a profit based tax levied on
petroleum projects in Australia |
TTF |
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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 |
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|
West Texas Intermediate, the reference price paid for crude oil
of standard grade in US dollars at Cushing, Oklahoma |
MESSAGE TO SHAREHOLDERS
Crude oil prices once again came under
significant pressure during the third quarter of 2015 with WTI
reaching its lowest level since the financial crisis of
2008-2009. This continued price volatility, coupled with an
emerging consensus that we are in a "lower for longer" price
environment, provides an opportunity to share our perspective on
Vermilion's strengths in today's
challenging conditions.
Sustainability
Since inception, we have remained highly disciplined in our
approach to financial management. We have historically
targeted our cash outflows (net cash dividends, capital
expenditures plus abandonment and reclamation costs) at levels
equal to, or less than, our cash inflows (fund flows from
operations.) In addition, we have targeted moderate leverage
ratios, enabling us to manage through lower commodity price
environments and take advantage of compelling business
opportunities. This conservative approach allowed us to enter
the current commodity price downturn in a position of relative
financial strength as compared to many of our peers and to avoid
large equity issues during this part of the commodity cycle.
Sustainability has always been paramount in our
dividend policy. We have raised the dividend three times
since it was initiated in 2003. We have never reduced our
dividend, and we do not foresee the need to do so in the
future.
We have proactively managed our credit capacity
to ensure sufficient liquidity to meet the expected requirements of
our business, irrespective of the financial environment.
Vermilion has a 4-year revolving
credit facility totalling $2.0
billion and more than $700
million of borrowing capacity available at the end of the
quarter. We are, and expect to continue to remain, in
compliance with all applicable debt covenants. We currently
intend to use our revolving credit facility to retire $225 million in senior unsecured notes that
mature in February 2016 as we
continue to evaluate options for long-term refinancing.
Vermilion's
management approach allows us to quickly adapt to changes in the
external environment. Following the unexpected commodity
downturn in 2014, we acted decisively to reduce our 2015 capital
program by 30% from 2014 levels. We are once again taking
action to preserve our financial flexibility and maintain a
sustainable business model by targeting a preliminary capital
expenditure level for 2016 of approximately $350MM, a nearly 50%
reduction from 2014 expenditures levels. In the latter part
of 2014, we introduced the third installment of our Profitability
Enhancement Program ("PEP") to identify opportunities to reduce
costs to support the long-term profitability of our Company.
Prior installments of PEP achieved strong results in both the 1998
industry downturn and the financial crisis of 2008-2009. We
expect that our third installment of PEP will result in cost
savings related to capital spending, operating expense and G&A
expenditures estimated at between $70 and
$80 million for full-year 2015.
Diversification
Vermilion's international
diversification has played a significant role in our success, and
is a key advantage differentiating us from our peer group.
Over the past number of years, we have benefitted from the premium
that our Brent-priced oil production has received as compared to
WTI-based oil production in North
America. More recently, our growing exposure to
European natural gas has supported our ability to continue to
deliver strong financial results in the current commodity price
environment. As European natural gas prices remain at levels
approximately three times those in North
America, a significant part of our strategic focus has been
on maximizing our exposure to this advantageously-priced
commodity. In addition, our growing exposure to European
natural gas also helps to reduce the volatility of our composite
revenue stream. This, in turn, reduces the volatility of our
internally-generated cash flow which funds our capital program and
cash dividends.
Another key benefit of Vermilion's geographic diversity is that it
provides the Company with a large inventory of potential capital
investment opportunities. This allows us to select and fund
projects that will generate the highest return in a given economic
environment. This advantage is even more important in a low
commodity price environment in which available capital funding is
highly restricted.
Opportunity
Vermilion has a large resource
base in its three operating regions which present a number of
diverse, high-return, organic investment opportunities. We
believe that this resource base leaves us well-positioned for
long-term, value-adding, organic growth. In addition, our
strong asset and operating positions result in significant
advantages over our competitors in a number of jurisdictions,
particularly in onshore Europe. This "franchise" has
historically led to enhanced returns on acquisition opportunities
as compared to what can typically be achieved in North America alone. We believe
Vermilion remains positioned to
deliver both continued organic growth and the potential for
opportunistic, high return acquisitions, while maintaining
sustainable and growing dividends to our shareholders.
Third Quarter Review
Record quarterly production of 56,280 boe/d for Q3 2015 exceeded
prior quarter production of 51,831 boe/d by 9%. This
quarter-over-quarter increase was primarily attributable to higher
production in the Netherlands due
to recent drilling success, with additional contributions from the
Canadian Mannville drilling program and increased Australian oil
production. Canadian third-party facility restrictions
impacted average production by approximately 900 boe/d during
Q3.
In July, we placed two Netherlands wells (Slootdorp-06/07 - 92.8%
working interest) on production for an extended production
test. The two wells, drilled in the prior quarter,
contributed approximately 24 mmcf/d (4,000 boe/d) to the quarter's
average production rate. We also executed various
debottlenecking activities, both during and after the quarter, to
enhance deliverability from these wells. The Diever-02
exploration well (45% working interest), drilled in 2014, came on
production in early November for an extended production test at a
gross rate of 28.5 mmcf/d (4,750 boe/d). Because of current
pipeline constraints in the multi-well system that Diever-02
produces into, Vermilion's net
incremental production increase from this well is limited to
approximately 6 mmcf/d (1,000 boe/d), net to Vermilion.
In France,
production from the four (4.0 net) well Champotran drilling program
executed in Q1 2015 continues to exceed expectations. After
converting one of the wells to a waterflood injector, total oil
production from the remaining three producing wells was
approximately 820 bbls/d at the end of the quarter. Results
from other activities directed at our Champotran field have also
been highly positive. Our Champotran waterflood program has
continued to provide strong results, delivering highly capital
efficient production growth. We recorded an increase of
approximately 300 bbls/d over the course of Q3 due to new response
from the waterflood, increasing total Champotran field production
by approximately 10%.
With respect to the German farm-in agreement
that we signed in July, all joint venture partners have now
approved Vermilion as a new
partner, allowing for the transfer of operatorship where applicable
and access to the proprietary geologic data associated with the
underlying assets. We continue to expect to close the farm-in
toward the end of the year, once all government consents have been
received. During Q3, the Burgmoor Z3a sidetrack well that was
drilled in the second quarter (25% Vermilion working interest) was placed on
production and is currently producing at a rate of approximately
1.7 mmcf/d (280 boe/d), net to Vermilion.
Our Australian horizontal sidetrack drill
program commenced in early October after the arrival of the
drilling rig at the Wandoo A platform in late September.
Vermilion expects that the well
will be completed and placed on production during the fourth
quarter of 2015.
Vermilion is
pleased to confirm that the Irish Environmental Protection Agency
issued its final determination in support of the Corrib Industrial
Emissions License on October 8,
2015. Previously, on September
1, 2015 the operator, Shell E&P Ireland Limited declared
the project ready for service. As a result, the sole
remaining requirement prior to commencing gas production at Corrib
is the receipt of Ministerial Consent from Ireland's Department of Communications, Energy
and Natural Resources. Following start-up, production levels
at Corrib are expected to rise over a period of approximately six
months to a peak rate estimated at 58 mmcf/d (9,700 boe/d), net to
Vermilion by mid-2016. While
the final regulatory approvals have taken longer than we originally
expected, we believe that the regulatory process for Corrib is near
completion, and still expect to achieve first production in
approximately mid-Q4 2015. We believe that our ability to
maintain our 2015 production guidance (originally set in
March 2014) and achieve more than 10%
annual production growth, despite the later-than-expected start-up
of Corrib and 30% lower year-over-year capital expenditures, is
indicative of the operational strength of our Company.
In the United
States, we completed and began testing one (1 net)
Turner Shurley Sand well in the
eastern Powder River Basin of
Wyoming. During the third
quarter, we consolidated our ownership of this project area to 100%
working interest through the acquisition of the remaining 30%
interest that was previously outstanding. The purchase price
of US $9.6 million provides
Vermilion with an estimated 0.9
mmboe of 2P reserves plus substantial contingent resource
opportunity, another 22,000 net acres of land, and a nominal amount
of incremental production.
In Canada, we
drilled five (4.5 net) operated, and participated in six (2.4 net)
non-operated, Mannville wells
during Q3 2015. A total of 10 (5.5 net) operated and
non-operated Mannville wells were
brought on production. Subsequent to the quarter, a recently
completed two-mile Mannville well
targeting the Notikewin formation flowed at a restricted rate of
10.7 mmcf/d (1,780 boe/d) on a production test with casing pressure
of 4,700 psi(2). Based on available processing and
transportation capacity, we expect to put this well on production
in Q4 at a rate of between 12 to 14 mmcf/d (2,000 to 2,300
boe/d). This level of productivity would rank this well
amongst the top gas wells currently producing in Alberta. Although access to natural gas
processing and takeaway capacity is modestly improving in
Alberta, we continue to be
negatively impacted by third party plant capacity restrictions,
with approximately 900 boe/d of primarily non-operated production
offline throughout Q3. In addition, we expect that
approximately 2,400 boe/d of productive capacity will be equipped
and tied-in during Q4, but will remain shut-in until processing
capacity becomes available.
Subsequent to the quarter, Vermilion was named to the CDP Climate
Disclosure Leadership Index ("CDLI"), recognizing the depth and
quality of our climate-related disclosure as compared to the 200
largest companies listed on the TSX. CDP (formerly Carbon
Disclosure Project), is a global, not-for-profit organization that
manages the world's only global environmental disclosure
system. To be named to the CDLI, a company must have a
disclosure score within the top 10% of surveyed companies.
Vermilion has voluntarily reported
to CDP since 2012. We believe that by measuring and
understanding our current environmental profile, we can direct our
business strategy to operate in an even more environmentally and
socially sustainable manner in the future.
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 long-term organic growth, and
in the current environment, we also find ourselves well-positioned
to take advantage of potential acquisition activity in North
American and international markets. Our 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.
(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) |
Production test was performed over a 6-day test period at a
maximum choke of 21"/64" with approximately 5% 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 November 5,
2015, of Vermilion Energy Inc.'s ("Vermilion", "We", "Our",
"Us" or the "Company") operating and financial results as at and
for the three and nine months ended September 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 nine months ended September 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 nine months ended
September 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 operations 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 program. 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 program 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. On November 9, 2015 we announced preliminary 2016
capital expenditure guidance of $350
million and affirmed production guidance of between
63,000-65,000 boe/d.
The following table summarizes our 2015 and 2016
guidance:
|
|
|
|
Date |
|
|
|
|
|
Capital Expenditures
($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 |
2016 - Guidance |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 Guidance |
|
|
|
November 9, 2015 |
|
|
|
|
|
350 |
|
|
|
|
|
63,000 to 65,000 |
SHAREHOLDER RETURN
Vermilion
strives to provide investors with reliable and growing dividends in
addition to sustainable, global production growth. The
following table, as of September 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 |
|
|
|
$7.49 |
|
|
|
$12.05 |
Capital appreciation per Vermilion share |
|
|
|
-$25.21 |
|
|
|
-$3.23 |
|
|
|
$4.35 |
Total return per Vermilion share |
|
|
|
-33.2% |
|
|
|
9.2% |
|
|
|
42.5% |
Annualized total return per Vermilion share |
|
|
|
-33.2% |
|
|
|
3.0% |
|
|
|
7.3% |
Annualized total return on the S&P TSX High
Income Energy Index |
|
|
|
-42.4% |
|
|
|
-12.5% |
|
|
|
-5.7% |
(1)
|
The above table includes non-GAAP financial measures which may
not be comparable to other companies. Please see the
"ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of this
MD&A. |
CONSOLIDATED RESULTS OVERVIEW
|
|
|
|
Three
Months Ended |
|
|
%
change |
|
|
Nine
Months Ended |
|
|
% change |
|
|
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Q3/15 vs. |
|
|
Q3/15 vs. |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
2015 vs. |
|
|
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
Q2/15 |
|
|
Q3/14 |
|
|
2015 |
|
|
2014 |
|
|
2014 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
|
28,164 |
|
|
28,916 |
|
|
29,147 |
|
|
(3%) |
|
|
(3%) |
|
|
28,420 |
|
|
28,890 |
|
|
(2%) |
|
NGLs (bbls/d) |
|
|
4,622 |
|
|
3,867 |
|
|
2,354 |
|
|
20% |
|
|
96% |
|
|
3,849 |
|
|
2,463 |
|
|
56% |
|
Natural gas (mmcf/d) |
|
|
140.97 |
|
|
114.29 |
|
|
110.52 |
|
|
23% |
|
|
28% |
|
|
123.51 |
|
|
109.33 |
|
|
13% |
|
Total (boe/d) |
|
|
56,280 |
|
|
51,831 |
|
|
49,920 |
|
|
9% |
|
|
13% |
|
|
52,854 |
|
|
49,574 |
|
|
7% |
|
Build (draw) in inventory (mbbl) |
|
|
(85) |
|
|
(121) |
|
|
104 |
|
|
|
|
|
|
|
|
177 |
|
|
74 |
|
|
|
Financial metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fund flows from operations ($M) |
|
|
129,435 |
|
|
129,496 |
|
|
197,898 |
|
|
- |
|
|
(35%) |
|
|
379,726 |
|
|
619,337 |
|
|
(39%) |
|
Per share ($/basic
share) |
|
|
1.17 |
|
|
1.18 |
|
|
1.85 |
|
|
(1%) |
|
|
(37%) |
|
|
3.48 |
|
|
5.90 |
|
|
(41%) |
|
Net earnings (loss) |
|
|
(83,310) |
|
|
6,813 |
|
|
53,903 |
|
|
(1,323%) |
|
|
(255%) |
|
|
(75,222) |
|
|
210,684 |
|
|
(136%) |
|
Per share ($/basic
share) |
|
|
(0.76) |
|
|
0.06 |
|
|
0.50 |
|
|
(1,367%) |
|
|
(252%) |
|
|
(0.69) |
|
|
2.01 |
|
|
(134%) |
|
Cash flows from
operating activities ($M) |
|
|
122,230 |
|
|
134,668 |
|
|
235,010 |
|
|
(9%) |
|
|
(48%) |
|
|
279,545 |
|
|
562,840 |
|
|
(50%) |
|
Net debt ($M) |
|
|
1,363,043 |
|
|
1,377,902 |
|
|
1,243,438 |
|
|
(1%) |
|
|
10% |
|
|
1,363,043 |
|
|
1,243,438 |
|
|
10% |
|
Cash dividends ($/share) |
|
|
0.645 |
|
|
0.645 |
|
|
0.645 |
|
|
- |
|
|
- |
|
|
1.935 |
|
|
1.935 |
|
|
- |
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
|
|
93,381 |
|
|
90,173 |
|
|
190,033 |
|
|
4% |
|
|
(51%) |
|
|
357,865 |
|
|
521,481 |
|
|
(31%) |
|
Acquisitions ($M) |
|
|
22,155 |
|
|
480 |
|
|
40,847 |
|
|
4,516% |
|
|
(46%) |
|
|
22,670 |
|
|
600,213 |
|
|
(96%) |
|
Gross wells drilled |
|
|
11.00 |
|
|
5.00 |
|
|
26.00 |
|
|
|
|
|
|
|
|
45.00 |
|
|
63.00 |
|
|
|
|
Net wells drilled |
|
|
6.91 |
|
|
3.61 |
|
|
20.31 |
|
|
|
|
|
|
|
|
30.56 |
|
|
45.86 |
|
|
|
Operational review
- Recorded consolidated average production of 56,280 boe/d during
Q3 2015, which was a 9% increase over Q2 2015 as a result of
production growth in the
Netherlands, Australia, and
Canada, driven primarily by new
wells on production.
- Increased consolidated average production for the three and
nine months ended September 30, 2015
by 13% and 7%, respectively, versus the comparable periods in 2014,
primarily due to growth in the
Netherlands, Canada, and
France.
- Activity during the quarter included capital expenditures
totalling $93.4 million, incurred
primarily in Canada, Ireland, and France. In Canada, capital expenditures totalling
$37.2 million were 70% higher than
the $21.9 million incurred in Q2 2015
and related to the drilling of 6.91 net wells (0.5 net wells in Q2
2015), with activity influenced by spring breakup in Q2 2015. In
Ireland, capital expenditures of
$20.7 million were incurred, the
majority of which related to subsurface activities and facility
commissioning. In France, capital
expenditures of $17.4 million were
consistent with the $16.7 million
incurred in Q2 2015 and related to accretive workovers and
subsurface activity.
Financial review
Net earnings (loss)
- The net loss for Q3 2015 was $83.3
million ($0.76/basic share) as
compared to net earnings of $6.8
million ($0.06/basic share) in
Q2 2015. The decrease in net earnings (loss) was primarily
attributable to a non-cash impairment charge ($104.0 million after-tax) recognized in Q3 2015
following a steep decline in forward commodity prices. In
addition, the change in net earnings (loss) for Q3 2015 saw lower
petroleum and natural gas sales driven by lower commodity prices,
partially offset by higher sold volumes, impacts from unrealized
gains on derivative instruments and foreign exchange, and lower
current income taxes.
- The net loss incurred for the three and nine months ended
September 30, 2015 represented
decreases of $137.2 million and
$285.9 million, respectively, versus
the comparative periods in 2014. These decreases were driven
primarily by the aforementioned impairment charge recognized in the
current period and lower petroleum and natural gas sales as a
result of lower commodity prices. These declines were
partially offset by decreases in royalties and taxes, as well as
gains on derivative instruments and the impact of unrealized
foreign exchange gains. In the nine months ended September 30, 2015, the decrease in net earnings
was partially offset by the recovery of $31.8 million (before taxes) recognized in Q1
2015 following a judgment in favor of Vermilion for costs incurred as a result of a
2007 oil spill at the Ambès oil terminal in France that occurred shortly after
Vermilion acquired the asset.
Cash flows from operating activities
- Cash flows from operating activities decreased by 48% and 50%
for the three and nine months ended September 30, 2015, respectively, versus the
comparable periods in 2014. These decreases primarily relate to
lower revenue due to lower commodity prices and timing differences
pertaining to working capital, partially offset by foreign exchange
gains and lower current taxes.
- Absent changes in working capital, cash flows from operating
activities was consistent quarter-over-quarter.
Fund flows from operations
- Generated fund flows from operations of $129.4 million during Q3 2015, consistent with
fund flows from operations generated in Q2 2015. Fund flows from
operations were impacted by lower sales, driven by lower realized
prices but partially offset by higher volumes sold, a realized gain
on derivative instruments, and a favorable current tax
variance.
- Fund flows from operations decreased 35% and 39% for the three
and nine months ended September 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 as well as
favorable royalty and current tax variances, consistent with lower
commodity prices. The decrease in fund flows from operations
for the nine months ended September 30,
2015 was partially offset by the previously mentioned
recovery of costs in France.
Net debt
- Net debt increased by $97.4
million to $1.36 billion for
the nine months ended September 30,
2015 due to capital expenditures in Canada, Ireland and Australia, partially offset by fund flows from
operations which were comparatively lower due to weaker commodity
prices in 2015.
Dividends
- Declared dividends remained consistent at $0.215 per common share per month during the
third quarter of 2015, totalling $0.645 per common share and $1.935 per common share for the three and nine
months ended September 30, 2015,
respectively.
COMMODITY PRICES
|
|
|
Three
Months Ended |
|
|
%
change |
|
|
Nine
Months Ended |
|
|
%
change |
|
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Q3/15 vs. |
|
|
Q3/15 vs. |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
2015 vs. |
|
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
Q2/15 |
|
|
Q3/14 |
|
|
2015 |
|
|
2014 |
|
|
2014 |
Average reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl) |
|
|
46.43 |
|
|
57.94 |
|
|
97.17 |
|
|
(20%) |
|
|
(52%) |
|
|
51.00 |
|
|
99.61 |
|
|
(49%) |
Edmonton Sweet index (US $/bbl) |
|
|
43.01 |
|
|
55.08 |
|
|
89.24 |
|
|
(22%) |
|
|
(52%) |
|
|
46.64 |
|
|
92.17 |
|
|
(49%) |
Dated Brent (US $/bbl) |
|
|
50.26 |
|
|
61.92 |
|
|
101.85 |
|
|
(19%) |
|
|
(51%) |
|
|
55.39 |
|
|
106.57 |
|
|
(48%) |
AECO ($/GJ) |
|
|
2.75 |
|
|
2.52 |
|
|
3.81 |
|
|
9% |
|
|
(28%) |
|
|
2.62 |
|
|
4.56 |
|
|
(43%) |
TTF ($/GJ) |
|
|
8.04 |
|
|
7.94 |
|
|
7.26 |
|
|
1% |
|
|
11% |
|
|
8.08 |
|
|
8.41 |
|
|
(4%) |
TTF (€/GJ) |
|
|
5.52 |
|
|
5.84 |
|
|
5.04 |
|
|
(5%) |
|
|
10% |
|
|
5.76 |
|
|
5.68 |
|
|
1% |
Average foreign currency exchange
rates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CDN $/US $ |
|
|
1.31 |
|
|
1.23 |
|
|
1.09 |
|
|
7% |
|
|
20% |
|
|
1.26 |
|
|
1.09 |
|
|
15% |
CDN $/Euro |
|
|
1.46 |
|
|
1.36 |
|
|
1.44 |
|
|
7% |
|
|
1% |
|
|
1.40 |
|
|
1.48 |
|
|
(5%) |
Average realized prices ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
32.78 |
|
|
40.59 |
|
|
64.85 |
|
|
(19%) |
|
|
(49%) |
|
|
36.34 |
|
|
68.58 |
|
|
(47%) |
France |
|
|
60.96 |
|
|
71.96 |
|
|
107.99 |
|
|
(15%) |
|
|
(44%) |
|
|
65.66 |
|
|
114.36 |
|
|
(43%) |
Netherlands |
|
|
49.42 |
|
|
47.63 |
|
|
45.73 |
|
|
4% |
|
|
8% |
|
|
48.70 |
|
|
52.80 |
|
|
(8%) |
Germany |
|
|
44.36 |
|
|
43.31 |
|
|
36.43 |
|
|
2% |
|
|
22% |
|
|
44.30 |
|
|
44.68 |
|
|
(1%) |
Australia |
|
|
68.20 |
|
|
80.87 |
|
|
119.07 |
|
|
(16%) |
|
|
(43%) |
|
|
76.46 |
|
|
124.59 |
|
|
(39%) |
United States |
|
|
51.60 |
|
|
60.57 |
|
|
- |
|
|
(15%) |
|
|
100% |
|
|
52.95 |
|
|
- |
|
|
100% |
Consolidated |
|
|
46.56 |
|
|
54.65 |
|
|
76.80 |
|
|
(15%) |
|
|
(39%) |
|
|
49.48 |
|
|
82.73 |
|
|
(40%) |
Production mix (% of production) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% priced with reference to WTI |
|
|
24% |
|
|
27% |
|
|
28% |
|
|
|
|
|
|
|
|
26% |
|
|
27% |
|
|
|
% priced with reference to AECO |
|
|
22% |
|
|
21% |
|
|
18% |
|
|
|
|
|
|
|
|
21% |
|
|
18% |
|
|
|
% priced with reference to TTF |
|
|
20% |
|
|
16% |
|
|
18% |
|
|
|
|
|
|
|
|
18% |
|
|
18% |
|
|
|
% priced with reference to Dated Brent |
|
|
34% |
|
|
36% |
|
|
36% |
|
|
|
|
|
|
|
|
35% |
|
|
37% |
|
|
|
Reference prices
- Despite higher demand, crude oil markets moved lower over the
three months ended September 30, 2015
as global production edged higher. As compared to Q2 2015,
WTI fell by 20% to average US $46.43/bbl while Dated Brent was down 19% to
average US $50.26/bbl.
- Crude oil prices set at Edmonton were volatile in Q3 2015 due to
fluctuations in supply and refining demand, with the reference
price declining by 22% over the prior quarter to average US
$43.01/bbl.
- Pipeline constraints and a relatively warm summer proved to be
supportive factors for AECO natural gas, with prices increasing 9%
quarter-over-quarter to average $2.75/GJ.
- European natural gas held firm in Canadian dollar terms
quarter-over-quarter, averaging $8.04/GJ for the three months ended September 30, 2015, up 1% over the previous
quarter, while TTF natural gas pricing, based on Euro per
gigajoule, was down 5% quarter-over-quarter.
- The US dollar continued to strengthen against the Canadian
dollar during Q3 2015 driven by the combination of weakening crude
oil prices and larger interest rate spreads. For the three
months ended September 30, 2015,
1 US dollar bought 1.31 Canadian dollars, which is 7% more than the
previous quarter and 20% more than the same period in 2014.
Realized prices
- Consolidated realized price decreased by 15% for Q3 2015 as
compared to Q2 2015. This decrease was the result of
weakening crude oil pricing, partially offset by a slight
improvement in North American natural gas pricing.
- Consolidated realized price for the three and nine months ended
September 30, 2015 decreased by 39%
and 40%, respectively, as compared to the comparable periods in
2014. These decreases were driven by a weakening of crude oil
and North American natural gas pricing, as well as changes in
production mix, which included increased relative NGL and natural
gas volume on the production mix in Canada.
FUND FLOWS FROM OPERATIONS
|
|
|
Three
Months Ended |
|
Nine
Months Ended |
|
|
|
Sep 30, 2015 |
|
Jun 30, 2015 |
|
Sep 30, 2014 |
|
Sep 30, 2015 |
|
Sep 30, 2014 |
|
|
|
$M |
|
|
$/boe |
|
$M |
|
|
$/boe |
|
$M |
|
|
$/boe |
|
$M |
|
|
$/boe |
|
$M |
|
|
$/boe |
Petroleum and natural gas sales |
|
|
245,051 |
|
|
46.56 |
|
264,331 |
|
|
54.65 |
|
344,688 |
|
|
76.80 |
|
705,267 |
|
|
49.48 |
|
1,113,555 |
|
|
82.73 |
Royalties |
|
|
(17,100) |
|
|
(3.25) |
|
(16,111) |
|
|
(3.33) |
|
(29,000) |
|
|
(6.46) |
|
(49,635) |
|
|
(3.48) |
|
(82,037) |
|
|
(6.09) |
Petroleum and natural gas revenues |
|
|
227,951 |
|
|
43.31 |
|
248,220 |
|
|
51.32 |
|
315,688 |
|
|
70.34 |
|
655,632 |
|
|
46.00 |
|
1,031,518 |
|
|
76.64 |
Transportation expense |
|
|
(11,090) |
|
|
(2.11) |
|
(10,883) |
|
|
(2.25) |
|
(10,979) |
|
|
(2.45) |
|
(31,513) |
|
|
(2.21) |
|
(32,872) |
|
|
(2.44) |
Operating expense |
|
|
(57,826) |
|
|
(10.99) |
|
(58,616) |
|
|
(12.12) |
|
(56,227) |
|
|
(12.53) |
|
(160,293) |
|
|
(11.25) |
|
(172,426) |
|
|
(12.81) |
General and administration |
|
|
(13,088) |
|
|
(2.49) |
|
(14,505) |
|
|
(3.00) |
|
(16,262) |
|
|
(3.62) |
|
(41,153) |
|
|
(2.89) |
|
(48,491) |
|
|
(3.60) |
PRRT |
|
|
(99) |
|
|
(0.02) |
|
(3,371) |
|
|
(0.70) |
|
(13,834) |
|
|
(3.08) |
|
(5,824) |
|
|
(0.41) |
|
(46,772) |
|
|
(3.47) |
Corporate income taxes |
|
|
(12,383) |
|
|
(2.35) |
|
(17,344) |
|
|
(3.59) |
|
(17,454) |
|
|
(3.89) |
|
(47,350) |
|
|
(3.32) |
|
(88,692) |
|
|
(6.59) |
Interest expense |
|
|
(15,420) |
|
|
(2.93) |
|
(14,550) |
|
|
(3.01) |
|
(12,918) |
|
|
(2.88) |
|
(43,268) |
|
|
(3.04) |
|
(36,712) |
|
|
(2.73) |
Realized gain on derivative
instruments |
|
|
10,854 |
|
|
2.06 |
|
3,081 |
|
|
0.64 |
|
8,837 |
|
|
1.97 |
|
20,192 |
|
|
1.42 |
|
13,896 |
|
|
1.03 |
Realized foreign exchange gain (loss) |
|
|
309 |
|
|
0.06 |
|
(2,740) |
|
|
(0.57) |
|
812 |
|
|
0.17 |
|
875 |
|
|
0.06 |
|
(642) |
|
|
(0.05) |
Realized other income |
|
|
227 |
|
|
0.04 |
|
204 |
|
|
0.04 |
|
235 |
|
|
0.05 |
|
32,428 |
|
|
2.28 |
|
530 |
|
|
0.04 |
Fund flows from operations |
|
|
129,435 |
|
|
24.58 |
|
129,496 |
|
|
26.76 |
|
197,898 |
|
|
44.08 |
|
379,726 |
|
|
26.64 |
|
619,337 |
|
|
46.02 |
The following table shows a reconciliation of
the change in fund flows from operations:
($M) |
|
|
|
Q3/15 vs. Q2/15 |
|
|
|
Q3/15 vs. Q3/14 |
|
|
|
2015 vs. 2014 |
Fund flows from
operations - Comparative period |
|
|
|
129,496 |
|
|
|
197,898 |
|
|
|
619,337 |
Sales volume variance: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
1,563 |
|
|
|
5,575 |
|
|
|
21,485 |
|
France |
|
|
|
8,590 |
|
|
|
27,004 |
|
|
|
27,133 |
|
Netherlands |
|
|
|
15,660 |
|
|
|
11,159 |
|
|
|
1,418 |
|
Germany |
|
|
|
(1,322) |
|
|
|
(768) |
|
|
|
3,240 |
|
Australia |
|
|
|
(9,574) |
|
|
|
4,948 |
|
|
|
(25,421) |
|
United States |
|
|
|
585 |
|
|
|
1,075 |
|
|
|
2,424 |
Pricing variance on sold volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI |
|
|
|
(16,203) |
|
|
|
(56,611) |
|
|
|
(165,078) |
|
AECO |
|
|
|
662 |
|
|
|
(10,324) |
|
|
|
(35,040) |
|
Dated Brent |
|
|
|
(20,970) |
|
|
|
(86,359) |
|
|
|
(230,151) |
|
TTF |
|
|
|
1,729 |
|
|
|
4,664 |
|
|
|
(8,298) |
Changes in: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties |
|
|
|
(989) |
|
|
|
11,900 |
|
|
|
32,402 |
|
Transportation |
|
|
|
(207) |
|
|
|
(111) |
|
|
|
1,359 |
|
Operating expense |
|
|
|
790 |
|
|
|
(1,599) |
|
|
|
12,133 |
|
General and administration |
|
|
|
1,417 |
|
|
|
3,174 |
|
|
|
7,338 |
|
PRRT |
|
|
|
3,272 |
|
|
|
13,735 |
|
|
|
40,948 |
|
Corporate income taxes |
|
|
|
4,961 |
|
|
|
5,071 |
|
|
|
41,342 |
|
Interest |
|
|
|
(870) |
|
|
|
(2,502) |
|
|
|
(6,556) |
|
Realized derivatives |
|
|
|
7,773 |
|
|
|
2,017 |
|
|
|
6,296 |
|
Realized foreign exchange |
|
|
|
3,049 |
|
|
|
(503) |
|
|
|
1,517 |
|
Realized other income |
|
|
|
23 |
|
|
|
(8) |
|
|
|
31,898 |
Fund flows from operations -
Current period |
|
|
|
129,435 |
|
|
|
129,435 |
|
|
|
379,726 |
Fund flows from operations of $129.4 million during Q3 2015 was consistent with
fund flows from operations generated in Q2 2015. Fund flows from
operations was impacted by weaker crude oil pricing, offset by
higher sales volumes and favorable current tax variances. Sales
decreased by $19.3 million, which
included a $34.8 million unfavorable
pricing variance driven by weaker crude oil prices partially offset
by a $15.5 million sales volumes
variance driven by increased sales in the
Netherlands and France. In France, the increase in sold volumes resulted
from a draw in inventory of 101,000 bbls (as compared to a build of
41,000 bbls in Q2 2015). This decrease in sales was offset by
lower PRRT and corporate income taxes, as well as realized gains on
both derivatives and foreign exchange.
Fund flows from operations decreased by 35% and
39% for the three and nine months ended September 30, 2015, respectively, versus the
comparable periods in the prior year. These decreases were
primarily driven by unfavorable crude oil and natural gas pricing
variances, partially offset by favorable royalty and current income
tax variances. For the three months ended September 30, 2015, the decrease in fund flows
from operations was further offset by a favorable sales volume
variance of $49.0 million including
an increase in sold volumes in France of $27.0
million. For the nine months ended September 30, 2015, the decrease in fund flows
from operations was partially offset by a $30.3 million favorable sales volume variance
driven by France and Canada, as well as the recognition of the
$31.8 million (before taxes) recovery
in France recognized in Q1
2015.
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 |
|
|
Nine
Months Ended |
|
|
% change |
|
|
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Q3/15 vs. |
|
|
Q3/15 vs. |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
2015 vs. |
Canada business unit |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
Q2/15 |
|
|
Q3/14 |
|
|
2015 |
|
|
2014 |
|
|
2014 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
|
9,195 |
|
|
10,182 |
|
|
11,469 |
|
|
(10%) |
|
|
(20%) |
|
|
10,083 |
|
|
11,202 |
|
|
(10%) |
|
NGLs (bbls/d) |
|
|
4,513 |
|
|
3,755 |
|
|
2,291 |
|
|
20% |
|
|
97% |
|
|
3,754 |
|
|
2,387 |
|
|
57% |
|
Natural gas (mmcf/d) |
|
|
71.94 |
|
|
64.66 |
|
|
57.07 |
|
|
11% |
|
|
26% |
|
|
66.16 |
|
|
54.76 |
|
|
21% |
|
Total (boe/d) |
|
|
25,698 |
|
|
24,713 |
|
|
23,272 |
|
|
4% |
|
|
10% |
|
|
24,864 |
|
|
22,714 |
|
|
9% |
Production mix (% of
total) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil |
|
|
36% |
|
|
41% |
|
|
49% |
|
|
|
|
|
|
|
|
41% |
|
|
49% |
|
|
|
|
NGLs |
|
|
18% |
|
|
15% |
|
|
10% |
|
|
|
|
|
|
|
|
15% |
|
|
11% |
|
|
|
|
Natural gas |
|
|
46% |
|
|
44% |
|
|
41% |
|
|
|
|
|
|
|
|
44% |
|
|
40% |
|
|
|
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
|
|
37,224 |
|
|
21,881 |
|
|
97,393 |
|
|
70% |
|
|
(62%) |
|
|
173,954 |
|
|
249,300 |
|
|
(30%) |
|
Acquisitions ($M) |
|
|
8,062 |
|
|
384 |
|
|
27,883 |
|
|
|
|
|
|
|
|
8,481 |
|
|
413,977 |
|
|
|
|
Gross wells drilled |
|
|
11.00 |
|
|
1.00 |
|
|
22.00 |
|
|
|
|
|
|
|
|
37.00 |
|
|
51.00 |
|
|
|
|
Net wells drilled |
|
|
6.91 |
|
|
0.50 |
|
|
16.86 |
|
|
|
|
|
|
|
|
23.45 |
|
|
35.12 |
|
|
|
Production
- Average production in Canada
increased by 4% quarter-over-quarter, 10% year-over-year and 9%
year-to-date, primarily due to strong organic production growth in
our Mannville condensate-rich gas
resource play. Q3 2015 volumes were negatively impacted by
approximately 900 boe/d of production offline as a result of
third-party plant capacity restrictions. Approximately 2,400
boe/d is awaiting equip and tie in, which is anticipated to be
completed in Q4 2015, but this production is expected to remain
shut-in due to third party processing constraints.
- Cardium production averaged approximately 9,300 boe/d in Q3
2015, essentially flat quarter-over-quarter.
- Mannville production averaged
more than 7,000 boe/d in Q3 2015, a 25% increase
quarter-over-quarter.
- Production from our southeast Saskatchewan assets averaged approximately
3,000 boe/d in Q3 2015, a decrease of 9%
quarter-over-quarter. The North Portal Gas Plant was
commissioned late in Q1 2015. The plant enables the processing of
approximately 5,500 mcf/d (920 boe/d) net of natural gas which was
previously being flared.
Activity review
- Vermilion drilled five (4.5
net) operated wells and participated in the drilling of six (2.4
net) non-operated wells during Q3 2015.
Cardium
- During Q3 2015, no new wells were drilled or brought on
production.
- Year-to-date, we have drilled or participated in seven (3.1
net) wells and 18 (11.9 net) wells were placed on production. For
the remainder of the year, we plan to participate in the drilling
of two (0.3 net) non-operated wells.
Mannville
- During Q3 2015, we drilled five (4.5 net) operated wells and
brought four (3.0 net) operated wells on production. We also
participated in the drilling of six (2.4 net) non-operated wells
and six (2.5 net) non-operated wells were placed on
production.
- Year-to-date, we have drilled or participated in 25 (16.3 net)
wells and 19 (12.0 net) wells were placed on production. For the
remainder of the year, we plan to drill two (0.6 net) operated
wells, and place two (2.0 net) operated and three (1.3 net)
non-operated wells on production.
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 |
|
|
Nine
Months Ended |
|
|
% change |
Canada business unit |
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Q3/15 vs. |
|
|
Q3/15 vs. |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
2015 vs. |
($M except as indicated) |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
Q2/15 |
|
|
Q3/14 |
|
|
2015 |
|
|
2014 |
|
|
2014 |
|
Sales |
|
|
77,493 |
|
|
91,284 |
|
|
138,853 |
|
|
(15%) |
|
|
(44%) |
|
|
246,661 |
|
|
425,294 |
|
|
(42%) |
|
Royalties |
|
|
(6,638) |
|
|
(5,768) |
|
|
(19,034) |
|
|
15% |
|
|
(65%) |
|
|
(20,998) |
|
|
(49,937) |
|
|
(58%) |
|
Transportation expense |
|
|
(4,131) |
|
|
(4,469) |
|
|
(4,048) |
|
|
(8%) |
|
|
2% |
|
|
(12,542) |
|
|
(11,170) |
|
|
12% |
|
Operating expense |
|
|
(23,877) |
|
|
(21,534) |
|
|
(19,074) |
|
|
11% |
|
|
25% |
|
|
(64,510) |
|
|
(56,863) |
|
|
13% |
|
General and administration |
|
|
(3,694) |
|
|
(5,510) |
|
|
(4,523) |
|
|
(33%) |
|
|
(18%) |
|
|
(13,219) |
|
|
(13,951) |
|
|
(5%) |
|
Fund flows from operations |
|
|
39,153 |
|
|
54,003 |
|
|
92,174 |
|
|
(27%) |
|
|
(58%) |
|
|
135,392 |
|
|
293,373 |
|
|
(54%) |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
32.78 |
|
|
40.59 |
|
|
64.85 |
|
|
(19%) |
|
|
(49%) |
|
|
36.34 |
|
|
68.58 |
|
|
(47%) |
|
Royalties |
|
|
(2.81) |
|
|
(2.56) |
|
|
(8.89) |
|
|
10% |
|
|
(68%) |
|
|
(3.09) |
|
|
(8.05) |
|
|
(62%) |
|
Transportation expense |
|
|
(1.75) |
|
|
(1.99) |
|
|
(1.89) |
|
|
(12%) |
|
|
(7%) |
|
|
(1.85) |
|
|
(1.80) |
|
|
3% |
|
Operating expense |
|
|
(10.10) |
|
|
(9.58) |
|
|
(8.91) |
|
|
5% |
|
|
13% |
|
|
(9.50) |
|
|
(9.17) |
|
|
4% |
|
General and administration |
|
|
(1.56) |
|
|
(2.45) |
|
|
(2.11) |
|
|
(36%) |
|
|
(26%) |
|
|
(1.95) |
|
|
(2.25) |
|
|
(13%) |
|
Fund flows from operations
netback |
|
|
16.56 |
|
|
24.01 |
|
|
43.05 |
|
|
(31%) |
|
|
(62%) |
|
|
19.95 |
|
|
47.31 |
|
|
(58%) |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl) |
|
|
46.43 |
|
|
57.94 |
|
|
97.17 |
|
|
(20%) |
|
|
(52%) |
|
|
51.00 |
|
|
99.61 |
|
|
(49%) |
|
Edmonton Sweet index (US $/bbl) |
|
|
43.01 |
|
|
55.08 |
|
|
89.24 |
|
|
(22%) |
|
|
(52%) |
|
|
46.64 |
|
|
92.17 |
|
|
(49%) |
|
Edmonton Sweet index ($/bbl) |
|
|
56.32 |
|
|
67.72 |
|
|
97.21 |
|
|
(17%) |
|
|
(42%) |
|
|
58.77 |
|
|
100.87 |
|
|
(42%) |
|
AECO ($/GJ) |
|
|
2.75 |
|
|
2.52 |
|
|
3.81 |
|
|
9% |
|
|
(28%) |
|
|
2.62 |
|
|
4.56 |
|
|
(43%) |
Sales
- The realized price for our crude oil production in Canada is directly linked to WTI, but is also
subject to market conditions in Western
Canada. These market conditions can result in
fluctuations in the pricing differential to WTI, as reflected by
the Edmonton Sweet index price. The realized price of our
NGLs in Canada is based on product
specific differentials pertaining to trading hubs in the United States. The realized price of
our natural gas in Canada is based
on the AECO spot price in Canada.
- Sales per boe decreased by 19% quarter-over-quarter as a result
of a 17% decrease in Edmonton Sweet index pricing in Canadian
dollar terms offset by a 9% increase in AECO pricing. The
pricing decrease for crude oil production, coupled with the
increased relative NGL and natural gas volume on the production
mix, more than offset a 4% increase in Canadian production volumes,
resulting in a 15% decrease in sales.
- On a year-over-year basis, sales per boe decreased by 49% and
47% for the three and nine months ended September 30, 2015, largely as the result of
weakening crude oil and natural gas pricing. In both periods,
the lower pricing was slightly offset by an increase in production
volumes of approximately 10%, resulting in a decrease in sales of
44% and 42% for the three and nine months ended September 30, 2015, respectively.
Royalties
- Royalties as a percentage of sales for Q3 2015 increased to
8.6% as compared to Q2 2015 of 6.3% despite lower reference prices
(which would typically result in lower 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 and higher crude oil royalty rates for Q3
2015. In addition, an annual favorable gas cost allowance
("GCA") adjustment in Alberta
resulted in gas royalties being in a recovery position for the
second quarter.
- Royalties as a percentage of sales for the three and nine
months ended September 30, 2015
decreased to 8.6% and 8.5% versus 13.7% and 11.7% 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.
Transportation
- Transportation expense relates to the delivery of crude oil and
natural gas production to major pipelines where legal title
transfers.
- Transportation expense for Q3 2015 was lower than Q2 2015 as a
result of lower transportation rates for our Alberta natural gas liquids production.
- Transportation expense for the nine months ended September 30, 2015 was higher than the same
period in the prior year as a result of incremental trucking costs
from Vermilion's Saskatchewan properties, which were acquired
in April 2014.
Operating expense
- Operating expenses were higher on a dollar and per boe basis
for Q3 2015 versus both Q2 2015 and Q3 2014 as a result of higher
gas processing fees attributable to increased production being
processed at third party facilities.
- Year-over-year operating expense increased on a dollar basis by
approximately 13% due to incremental operating expense associated
with Vermilion's Saskatchewan properties acquired in Q2 2014
and the aforementioned higher gas processing fees. This
dollar increase was partially offset by increased production,
resulting in a 4% increase in operating expense per boe.
General and administration
- General and administration expense decreased for Q3 2015 versus
both Q2 2015 and Q3 2014 as a result of timing of
expenditures.
- Year-over-year, general and administration expense for the nine
months ended September 30, 2015 were
5% lower than 2014 due to a focus on cost reduction
initiatives.
Impairment
- For the three months ended September 30,
2015, Vermilion recorded an
impairment charge of $143.0 million
related to the light crude oil play in Saskatchewan, Canada. These impairment
charges were a result of declines in the price forecasts for crude
oil in Canada which decreased the
expected future cash flows from the cash generating unit
("CGU").
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 |
|
|
Nine
Months Ended |
|
|
% change |
|
|
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Q3/15 vs. |
|
|
Q3/15 vs. |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
2015 vs. |
France business unit |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
Q2/15 |
|
|
Q3/14 |
|
|
2015 |
|
|
2014 |
|
|
2014 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
|
12,310 |
|
|
12,746 |
|
|
11,111 |
|
|
(3%) |
|
|
11% |
|
|
12,176 |
|
|
10,970 |
|
|
11% |
|
Natural gas (mmcf/d) |
|
|
1.47 |
|
|
1.03 |
|
|
- |
|
|
43% |
|
|
100% |
|
|
0.84 |
|
|
- |
|
|
100% |
|
Total (boe/d) |
|
|
12,555 |
|
|
12,917 |
|
|
11,111 |
|
|
(3%) |
|
|
13% |
|
|
12,316 |
|
|
10,970 |
|
|
12% |
Inventory (mbbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Opening crude oil inventory |
|
|
340 |
|
|
299 |
|
|
179 |
|
|
|
|
|
|
|
|
197 |
|
|
268 |
|
|
|
|
Crude oil production |
|
|
1,133 |
|
|
1,160 |
|
|
1,022 |
|
|
|
|
|
|
|
|
3,324 |
|
|
2,995 |
|
|
|
|
Crude oil sales |
|
|
(1,234) |
|
|
(1,119) |
|
|
(987) |
|
|
|
|
|
|
|
|
(3,282) |
|
|
(3,049) |
|
|
|
|
Closing crude oil inventory |
|
|
239 |
|
|
340 |
|
|
214 |
|
|
|
|
|
|
|
|
239 |
|
|
214 |
|
|
|
Production mix (% of
total) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil |
|
|
98% |
|
|
99% |
|
|
100% |
|
|
|
|
|
|
|
|
99% |
|
|
100% |
|
|
|
|
Natural gas |
|
|
2% |
|
|
1% |
|
|
- |
|
|
|
|
|
|
|
|
1% |
|
|
- |
|
|
|
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
|
|
17,369 |
|
|
16,697 |
|
|
35,082 |
|
|
4% |
|
|
(50%) |
|
|
68,180 |
|
|
110,663 |
|
|
(38%) |
|
Acquisitions ($M) |
|
|
142 |
|
|
96 |
|
|
- |
|
|
|
|
|
|
|
|
238 |
|
|
- |
|
|
|
|
Gross wells drilled |
|
|
- |
|
|
- |
|
|
3.00 |
|
|
|
|
|
|
|
|
4.00 |
|
|
7.00 |
|
|
|
|
Net wells drilled |
|
|
- |
|
|
- |
|
|
3.00 |
|
|
|
|
|
|
|
|
4.00 |
|
|
7.00 |
|
|
|
Production
- Ongoing workover and optimization activities resulted in stable
quarter-over-quarter production. Production increased for the
current quarter and year-to-date periods as compared to the same
periods in the prior year due to production additions from our 2015
Champotran drilling program and workovers.
Activity review
- Vermilion drilled four (4.0
net) wells in the Champotran field in the Paris Basin in Q1 2015, completing our planned
France drilling program for
2015.
- In 2015, additional activity includes a 26-well workover
program and the resumption of sales from a portion of our shut-in
natural gas at Vic Bilh, which was brought on-line in Q2 2015.
Financial review
|
|
|
|
Three
Months Ended |
|
|
%
change |
|
|
Nine
Months Ended |
|
|
% change |
France business unit |
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Q3/15 vs. |
|
|
Q3/15 vs. |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
2015 vs. |
($M except as indicated) |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
Q2/15 |
|
|
Q3/14 |
|
|
2015 |
|
|
2014 |
|
|
2014 |
|
Sales |
|
|
76,552 |
|
|
81,627 |
|
|
106,576 |
|
|
(6%) |
|
|
(28%) |
|
|
218,011 |
|
|
348,753 |
|
|
(37%) |
|
Royalties |
|
|
(8,038) |
|
|
(6,620) |
|
|
(6,978) |
|
|
21% |
|
|
15% |
|
|
(19,760) |
|
|
(22,125) |
|
|
(11%) |
|
Transportation expense |
|
|
(4,566) |
|
|
(3,526) |
|
|
(4,741) |
|
|
29% |
|
|
(4%) |
|
|
(11,103) |
|
|
(14,879) |
|
|
(25%) |
|
Operating expense |
|
|
(11,998) |
|
|
(12,102) |
|
|
(15,215) |
|
|
(1%) |
|
|
(21%) |
|
|
(34,926) |
|
|
(48,185) |
|
|
(28%) |
|
General and administration |
|
|
(5,338) |
|
|
(4,874) |
|
|
(6,411) |
|
|
10% |
|
|
(17%) |
|
|
(15,323) |
|
|
(17,164) |
|
|
(11%) |
|
Other income |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
31,775 |
|
|
- |
|
|
100% |
|
Current income taxes |
|
|
(4,696) |
|
|
(9,316) |
|
|
(10,744) |
|
|
(50%) |
|
|
(56%) |
|
|
(28,293) |
|
|
(60,769) |
|
|
(53%) |
|
Fund flows from operations |
|
|
41,916 |
|
|
45,189 |
|
|
62,487 |
|
|
(7%) |
|
|
(33%) |
|
|
140,381 |
|
|
185,631 |
|
|
(24%) |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
60.96 |
|
|
71.96 |
|
|
107.99 |
|
|
(15%) |
|
|
(44%) |
|
|
65.66 |
|
|
114.36 |
|
|
(43%) |
|
Royalties |
|
|
(6.40) |
|
|
(5.84) |
|
|
(7.07) |
|
|
10% |
|
|
(9%) |
|
|
(5.95) |
|
|
(7.26) |
|
|
(18%) |
|
Transportation expense |
|
|
(3.64) |
|
|
(3.11) |
|
|
(4.80) |
|
|
17% |
|
|
(24%) |
|
|
(3.34) |
|
|
(4.88) |
|
|
(32%) |
|
Operating expense |
|
|
(9.55) |
|
|
(10.67) |
|
|
(15.42) |
|
|
(10%) |
|
|
(38%) |
|
|
(10.52) |
|
|
(15.80) |
|
|
(33%) |
|
General and administration |
|
|
(4.25) |
|
|
(4.30) |
|
|
(6.50) |
|
|
(1%) |
|
|
(35%) |
|
|
(4.61) |
|
|
(5.63) |
|
|
(18%) |
|
Other income |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
9.57 |
|
|
- |
|
|
100% |
|
Current income taxes |
|
|
(3.74) |
|
|
(8.21) |
|
|
(10.89) |
|
|
(54%) |
|
|
(66%) |
|
|
(8.52) |
|
|
(19.93) |
|
|
(57%) |
|
Fund flows from operations
netback |
|
|
33.38 |
|
|
39.83 |
|
|
63.31 |
|
|
(16%) |
|
|
(47%) |
|
|
42.29 |
|
|
60.86 |
|
|
(31%) |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated Brent (US $/bbl) |
|
|
50.26 |
|
|
61.92 |
|
|
101.85 |
|
|
(19%) |
|
|
(51%) |
|
|
55.39 |
|
|
106.57 |
|
|
(48%) |
|
Dated Brent ($/bbl) |
|
|
65.81 |
|
|
76.12 |
|
|
110.95 |
|
|
(14%) |
|
|
(41%) |
|
|
69.79 |
|
|
116.63 |
|
|
(40%) |
Sales
- Crude oil in France is priced
with reference to Dated Brent.
- Sales per boe decreased by 15% quarter-over-quarter, consistent
with a 14% decrease in the Canadian dollar equivalent of the Dated
Brent reference price. This decrease was partially offset by
a 101,000 bbls draw in inventory during the quarter, resulting in a
6% decrease in sales.
- On a year-over-year basis, sales decreased by 28% and 37% for
the three and nine months ended September
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 sold volumes, largely driven
by increases in production.
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 10.5% for Q3 2015 versus
8.1% for Q2 2015 due to the impact of fixed RCDM royalties coupled
with lower realized pricing.
- Royalties as a percentage of sales was 10.5% and 9.1% for the
three and nine months ended September 30,
2015, an increase over both comparable periods in 2014 as a
result of the impact of fixed RCDM royalties coupled with lower
realized pricing.
Transportation
- Transportation expense increased for Q3 2015 as compared to Q2
2015 due to a higher number of shipments from the Ambès terminal
during the current quarter.
- Transportation expense decreased for both the three and nine
months ended September 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 and per boe basis, Q3 2015 operating expense was
lower than Q2 2015 despite unfavorable foreign exchange impacts of
a weaker Canadian dollar and an inventory draw during the current
quarter as a result of lower electricity costs and reduced major
project activity.
- Operating expense on a dollar and per boe basis decreased for
the three and nine months ended September
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
year-to-date 2015 period.
General and administration
- General and administration expense for Q3 2015 was 10% higher
than Q2 2015 and 17% lower than Q3 2014. These fluctuations in
general and administration expense for the quarters presented
primarily result from variances in the timing of spending,
including the timing of allocations from our Corporate
segment.
- Year-to-date 2015 general and administration expense was 11%
lower than the 2014 period due to the impact of a number of cost
reduction initiatives undertaken in response to commodity price
weakness, including a reduction in third party consultant
expenditures.
Other income
- Included in the results for the nine months ended September 30, 2015 is a judgment award 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 13% and 15%. This
rate is subject to change in response to commodity price
fluctuations, the timing of capital expenditures, and other
eligible in-country adjustments.
- Q3 2015 current income taxes decreased compared to Q2 2015 and
Q3 2014 due to decreased revenues and additional tax deductions
taken for depletion.
- Current income taxes for the nine months ended September 30, 2015 decreased versus the
comparative period in 2014 mainly due to 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 |
|
|
Nine
Months Ended |
|
|
% change |
|
|
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Q3/15 vs. |
|
|
Q3/15 vs. |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
2015 vs. |
Netherlands business unit |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
Q2/15 |
|
|
Q3/14 |
|
|
2015 |
|
|
2014 |
|
|
2014 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d) |
|
|
109 |
|
|
112 |
|
|
63 |
|
|
(3%) |
|
|
73% |
|
|
95 |
|
|
76 |
|
|
25% |
|
Natural gas (mmcf/d) |
|
|
53.56 |
|
|
32.43 |
|
|
38.07 |
|
|
65% |
|
|
41% |
|
|
40.86 |
|
|
40.50 |
|
|
1% |
|
Total (boe/d) |
|
|
9,035 |
|
|
5,517 |
|
|
6,407 |
|
|
64% |
|
|
41% |
|
|
6,905 |
|
|
6,827 |
|
|
1% |
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
|
|
5,297 |
|
|
18,885 |
|
|
10,087 |
|
|
(72%) |
|
|
(47%) |
|
|
28,515 |
|
|
51,718 |
|
|
(45%) |
|
Gross wells drilled |
|
|
- |
|
|
2.00 |
|
|
1.00 |
|
|
|
|
|
|
|
|
2.00 |
|
|
5.00 |
|
|
|
|
Net wells drilled |
|
|
- |
|
|
1.86 |
|
|
0.45 |
|
|
|
|
|
|
|
|
1.86 |
|
|
3.74 |
|
|
|
Production
- Q3 production represented a new record for our Netherlands
Business Unit at 9,035 boe/d which is an increase of 64% from the
prior quarter. This increase is primarily attributable to
placing two wells (Slootdorp-06/07 - 92.8% working interest) on
production for an extended production test. These two wells,
drilled in the prior quarter, contributed approximately 24 mmcf/d
(4,000 boe/d) to the average production rate during the
quarter.
- Production for Q3 2015 increased by 41%, as compared to Q3 2014
due to the Sloopdorp-06/07 wells. For the year to date
period, production was consistent with the prior year as the third
quarter production additions from Slootdorp-06/07 were largely
offset by the 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 further impacted current year
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.
- During the quarter, we continued to execute numerous
debottlenecking activities to enhance deliverability from the
Slootdorp wells.
- The Diever-02 exploration well (45% working interest), drilled
in 2014, came on production in early November for an extended
production test at a gross rate of 28.5 mmcf/d (4,750 boe/d).
Because of current pipeline constraints in the multi-well system
that Diever-02 produces into, Vermilion's net incremental production
increase from this well is limited to approximately 6 mmcf/d (1,000
boe/d), net to Vermilion.
Financial review
|
|
|
|
Three
Months Ended |
|
|
%
change |
|
|
Nine
Months Ended |
|
|
% change |
Netherlands business unit |
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Q3/15 vs. |
|
|
Q3/15 vs. |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
2015 vs. |
($M except as indicated) |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
Q2/15 |
|
|
Q3/14 |
|
|
2015 |
|
|
2014 |
|
|
2014 |
|
Sales |
|
|
41,083 |
|
|
23,913 |
|
|
26,960 |
|
|
72% |
|
|
52% |
|
|
91,814 |
|
|
98,395 |
|
|
(7%) |
|
Royalties |
|
|
(638) |
|
|
(1,294) |
|
|
(942) |
|
|
(51%) |
|
|
(32%) |
|
|
(2,858) |
|
|
(3,843) |
|
|
(26%) |
|
Operating expense |
|
|
(5,243) |
|
|
(5,414) |
|
|
(5,409) |
|
|
(3%) |
|
|
(3%) |
|
|
(16,483) |
|
|
(17,841) |
|
|
(8%) |
|
General and administration |
|
|
(2,154) |
|
|
(454) |
|
|
(204) |
|
|
374% |
|
|
956% |
|
|
(3,345) |
|
|
(1,128) |
|
|
197% |
|
Current income taxes |
|
|
(4,487) |
|
|
(2,347) |
|
|
(1,189) |
|
|
91% |
|
|
277% |
|
|
(9,222) |
|
|
(6,278) |
|
|
47% |
|
Fund flows from operations |
|
|
28,561 |
|
|
14,404 |
|
|
19,216 |
|
|
98% |
|
|
49% |
|
|
59,906 |
|
|
69,305 |
|
|
(14%) |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
49.42 |
|
|
47.63 |
|
|
45.73 |
|
|
4% |
|
|
8% |
|
|
48.70 |
|
|
52.80 |
|
|
(8%) |
|
Royalties |
|
|
(0.77) |
|
|
(2.58) |
|
|
(1.60) |
|
|
(70%) |
|
|
(52%) |
|
|
(1.52) |
|
|
(2.06) |
|
|
(26%) |
|
Operating expense |
|
|
(6.31) |
|
|
(10.78) |
|
|
(9.18) |
|
|
(41%) |
|
|
(31%) |
|
|
(8.74) |
|
|
(9.57) |
|
|
(9%) |
|
General and administration |
|
|
(2.59) |
|
|
(0.90) |
|
|
(0.35) |
|
|
188% |
|
|
640% |
|
|
(1.77) |
|
|
(0.61) |
|
|
190% |
|
Current income taxes |
|
|
(5.40) |
|
|
(4.67) |
|
|
(2.02) |
|
|
16% |
|
|
167% |
|
|
(4.89) |
|
|
(3.37) |
|
|
45% |
|
Fund flows from operations
netback |
|
|
34.35 |
|
|
28.70 |
|
|
32.58 |
|
|
20% |
|
|
5% |
|
|
31.78 |
|
|
37.19 |
|
|
(15%) |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TTF ($/GJ) |
|
|
8.04 |
|
|
7.94 |
|
|
7.26 |
|
|
1% |
|
|
11% |
|
|
8.08 |
|
|
8.41 |
|
|
(4%) |
|
TTF (€/GJ) |
|
|
5.52 |
|
|
5.84 |
|
|
5.04 |
|
|
(5%) |
|
|
10% |
|
|
5.76 |
|
|
5.68 |
|
|
1% |
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 increased by 4% quarter-over-quarter, consistent
with a slight increase in the Canadian dollar equivalent TTF
reference price. This increase in sales per boe combined with a 64%
increase in production resulted in a 72% increase in sales.
- On a year-over-year basis, sales per boe increased by 8% and
decreased by 8% for the three and nine months ended September 30, 2015, respectively, consistent with
movements in the Canadian dollar equivalent of the TTF reference
price for the respective periods. For the three months ended
September 30, 2015, the 11% increase
in the Canadian dollar equivalent of the TTF reference price was
coupled with a 41% increase in production, resulting in a 52%
increase in sales. For the nine months ended September 30, 2015, a 4% decrease in the Canadian
dollar equivalent of the TTF reference price was combined with
consistent production volumes, resulting in a 7% 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 slightly for Q3
2015 versus both Q2 2015 and Q3 2014 primarily as a result of the
timing of expenditures. These slight decreases, coupled with
significantly higher production from our Slootdorp-06 and
Slootdorp-07 wells, resulted in a 41% decrease in operating expense
per boe quarter-over-quarter (31% year-over-year).
- On a year-to-date basis, operating expense on a dollar and per
boe basis decreased approximately 8% due to the favorable foreign
exchange impact of a stronger Canadian dollar coupled with reduced
facility operation expenditures following cost reduction
initiatives undertaken in response to commodity price
weakness.
General and administration
- Variances in general and administration expense generally
relate 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 11% and 13%. 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 Q3 2015 were higher compared to Q2 2015
and Q3 2014 due to increased revenues and accelerated tax
deductions recognized in 2014.
- Current income taxes for the nine months ended September 30, 2015 were higher compared to 2014
as decreased revenues in 2015 were offset with accelerated tax
deductions recognized in 2014.
GERMANY
BUSINESS UNIT
Overview
- Vermilion entered Germany in February
2014.
- Holds a 25% interest in a four partner consortium. Associated
assets include four gas producing fields spanning 11 production
licenses as well as an exploration license in surrounding fields.
Total license area comprises 204,000 gross acres, of which 85% is
in the exploration license.
- Entered into a farm-in agreement in Q3 2015 that will provide
Vermilion with participating
interest in 19 onshore exploration licenses in northwest
Germany, comprising approximately
850,000 net undeveloped acres of oil and natural gas rights.
Vermilion will assume operatorship
for 11 of the 19 licenses during the exploration phase. The
farm-in agreement is expected to close around year-end.
Operational review
|
|
|
|
Three
Months Ended |
|
|
%
change |
|
|
Nine
Months Ended |
|
|
% change |
|
|
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Q3/15 vs. |
|
|
Q3/15 vs. |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
2015 vs. |
Germany business unit |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
Q2/15 |
|
|
Q3/14 |
|
|
2015 |
|
|
2014 |
|
|
2014 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d) |
|
|
14.00 |
|
|
16.18 |
|
|
15.38 |
|
|
(13%) |
|
|
(9%) |
|
|
15.65 |
|
|
14.07 |
|
|
11% |
|
Total (boe/d) |
|
|
2,333 |
|
|
2,696 |
|
|
2,563 |
|
|
(13%) |
|
|
(9%) |
|
|
2,608 |
|
|
2,345 |
|
|
11% |
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
|
|
1,605 |
|
|
3,231 |
|
|
1,358 |
|
|
(50%) |
|
|
18% |
|
|
5,804 |
|
|
2,184 |
|
|
166% |
|
Acquisitions ($M) |
|
|
- |
|
|
- |
|
|
- |
|
|
|
|
|
|
|
|
- |
|
|
172,871 |
|
|
|
|
Gross wells drilled |
|
|
- |
|
|
1.00 |
|
|
- |
|
|
|
|
|
|
|
|
1.00 |
|
|
- |
|
|
|
|
Net wells drilled |
|
|
- |
|
|
0.25 |
|
|
- |
|
|
|
|
|
|
|
|
0.25 |
|
|
- |
|
|
|
Production
- Q3 2015 production of 2,333 boe/d represented a decrease of 13%
quarter-over-quarter and a decrease of 9% year-over-year due to a
planned maintenance shutdown during the quarter. Year-to-date
production increased 11% versus prior year, due to 2014 volumes
only reflecting production from the acquisition's effective date of
February 1, 2014.
Activity review
- The Burgmoor Z3a sidetrack well (25% working interest), which
was completed in Q2 2015, was tied-in and placed on production in
Q3 2015.
Financial review
|
|
|
|
Three
Months Ended |
|
|
%
change |
|
|
Nine
Months Ended |
|
|
% change |
Germany business unit |
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Q3/15 vs. |
|
|
Q3/15 vs. |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
2015 vs. |
($M except as indicated) |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
Q2/15 |
|
|
Q3/14 |
|
|
2015 |
|
|
2014 |
|
|
2014 |
|
Sales |
|
|
9,523 |
|
|
10,626 |
|
|
8,591 |
|
|
(10%) |
|
|
11% |
|
|
31,544 |
|
|
28,603 |
|
|
10% |
|
Royalties |
|
|
(1,477) |
|
|
(2,238) |
|
|
(2,046) |
|
|
(34%) |
|
|
(28%) |
|
|
(5,313) |
|
|
(6,132) |
|
|
(13%) |
|
Transportation expense |
|
|
(627) |
|
|
(1,240) |
|
|
(675) |
|
|
(49%) |
|
|
(7%) |
|
|
(2,761) |
|
|
(2,149) |
|
|
28% |
|
Operating expense |
|
|
(2,796) |
|
|
(1,373) |
|
|
(2,227) |
|
|
104% |
|
|
26% |
|
|
(6,168) |
|
|
(5,824) |
|
|
6% |
|
General and administration |
|
|
(1,311) |
|
|
(1,435) |
|
|
(1,090) |
|
|
(9%) |
|
|
20% |
|
|
(4,354) |
|
|
(2,488) |
|
|
75% |
|
Current income taxes |
|
|
- |
|
|
- |
|
|
(146) |
|
|
- |
|
|
(100%) |
|
|
- |
|
|
(1,189) |
|
|
(100%) |
|
Fund flows from operations |
|
|
3,312 |
|
|
4,340 |
|
|
2,407 |
|
|
(24%) |
|
|
38% |
|
|
12,948 |
|
|
10,821 |
|
|
20% |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
44.36 |
|
|
43.31 |
|
|
36.43 |
|
|
2% |
|
|
22% |
|
|
44.30 |
|
|
44.68 |
|
|
(1%) |
|
Royalties |
|
|
(6.88) |
|
|
(9.12) |
|
|
(8.68) |
|
|
(25%) |
|
|
(21%) |
|
|
(7.46) |
|
|
(9.58) |
|
|
(22%) |
|
Transportation expense |
|
|
(2.92) |
|
|
(5.05) |
|
|
(2.86) |
|
|
(42%) |
|
|
2% |
|
|
(3.88) |
|
|
(3.36) |
|
|
15% |
|
Operating expense |
|
|
(13.03) |
|
|
(5.60) |
|
|
(9.44) |
|
|
133% |
|
|
38% |
|
|
(8.66) |
|
|
(9.10) |
|
|
(5%) |
|
General and administration |
|
|
(6.11) |
|
|
(5.85) |
|
|
(4.62) |
|
|
4% |
|
|
32% |
|
|
(6.12) |
|
|
(3.89) |
|
|
57% |
|
Current income taxes |
|
|
- |
|
|
- |
|
|
(0.62) |
|
|
- |
|
|
(100%) |
|
|
- |
|
|
(1.86) |
|
|
(100%) |
|
Fund flows from operations
netback |
|
|
15.42 |
|
|
17.69 |
|
|
10.21 |
|
|
(13%) |
|
|
51% |
|
|
18.18 |
|
|
16.89 |
|
|
8% |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TTF ($/GJ) |
|
|
8.04 |
|
|
7.94 |
|
|
7.26 |
|
|
1% |
|
|
11% |
|
|
8.08 |
|
|
8.41 |
|
|
(4%) |
|
TTF (€/GJ) |
|
|
5.52 |
|
|
5.84 |
|
|
5.04 |
|
|
(5%) |
|
|
10% |
|
|
5.76 |
|
|
5.68 |
|
|
1% |
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 10% decrease in sales quarter-over-quarter is due to a 13%
decrease in production, partially offset by a 2% increase in sales
per boe, consistent with a slight increase in the Canadian dollar
equivalent of the TTF reference price.
- On a year-over-year basis, sales per boe increased by 22% and
declined by 1% for the three and nine months ended September 30, 2015, respectively, consistent with
movements in the Canadian dollar equivalent of the TTF reference
price in the respective periods. For the three months ended
September 30, 2015, the increase in
sales per boe was partially offset by a 9% decrease in production,
resulting in an 11% increase in sales. For the nine months ended
September 30, 2015, production
increased by 11% which, coupled with consistent sales per boe,
resulted 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.
- Q3 2015 royalties as a percentage of sales of 15.5% were lower
than the 21.1% for Q2 2015 due to adjustments for prior period
royalties recorded in the second quarter. Year-to-date
royalties as a percentage of sales of 16.8% were lower than the
21.4% for the comparable periods 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.
- Q3 2015 transportation expense was lower than Q2 2015 due to
final adjustments for 2014 recorded in the second quarter.
Year-to-date transportation expense was higher than the comparable
period in 2014 due to the aforementioned adjustments and the
inclusion of only eight 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 facility operations and gas
processing.
- Q3 2015 had higher operating expense versus both Q2 2015 and Q3
2014 due to a higher level of project activity during the current
quarter. Year-to-date operating expense was higher on a
dollar basis than the comparable period in 2014 due to the
inclusion of only eight months of expense in 2014 due to the timing
of our Germany acquisition.
General and administration
- General and administration expense increased
quarter-over-quarter and year-over-year due to staffing and
expenditures relating to our Germany farm-in agreement.
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 tax pools in Germany,
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 |
|
|
Nine
Months Ended |
|
|
% change |
Ireland business unit |
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
Q3/15 vs. |
|
|
Q3/15 vs. |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
2015 vs. |
($M) |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
Q2/15 |
|
|
Q3/14 |
|
|
2015 |
|
|
2014 |
|
|
2014 |
|
Transportation expense |
|
|
(1,766) |
|
|
(1,648) |
|
|
(1,515) |
|
7% |
|
|
17% |
|
|
(5,107) |
|
|
(4,674) |
|
|
9% |
|
General and administration |
|
|
(663) |
|
|
(628) |
|
|
(334) |
|
6% |
|
|
99% |
|
|
(1,803) |
|
|
(868) |
|
|
108% |
|
Fund flows from operations |
|
|
(2,429) |
|
|
(2,276) |
|
|
(1,849) |
|
7% |
|
|
31% |
|
|
(6,910) |
|
|
(5,542) |
|
|
25% |
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
20,694 |
|
|
20,267 |
|
|
30,050 |
|
2% |
|
|
(31%) |
|
|
53,916 |
|
|
73,507 |
|
|
(27%) |
Activity review
- On September 1, 2015, the
operator, Shell E&P Ireland Limited declared the project ready
for service.
- On October 8, 2015, the Irish
Environmental Protection Agency issued its final determination in
support of the Corrib Industrial Emissions License.
- Prior to commencing gas production, receipt of Ministerial
Consent is required from Ireland's
Department of Communications, Environment, and Natural
Resources.
- Following first gas production, expected in approximately
mid-Q4 2015, volumes at Corrib are expected to rise over a period
of approximately six months to a peak rate of approximately 58
mmcf/d (9,700 boe/d) net to Vermilion by mid-2016.
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 |
|
|
Nine
Months Ended |
|
|
% change |
|
|
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Q3/15 vs. |
|
|
Q3/15 vs. |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
2015 vs. |
Australia business unit |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
Q2/15 |
|
|
Q3/14 |
|
|
2015 |
|
|
2014 |
|
|
2014 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
|
6,433 |
|
|
5,865 |
|
|
6,567 |
|
|
10% |
|
|
(2%) |
|
|
5,993 |
|
|
6,718 |
|
|
(11%) |
Inventory (mbbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Opening crude oil inventory |
|
|
156 |
|
|
318 |
|
|
189 |
|
|
|
|
|
|
|
|
37 |
|
|
130 |
|
|
|
|
Crude oil production |
|
|
592 |
|
|
534 |
|
|
604 |
|
|
|
|
|
|
|
|
1,636 |
|
|
1,834 |
|
|
|
|
Crude oil sales |
|
|
(576) |
|
|
(696) |
|
|
(535) |
|
|
|
|
|
|
|
|
(1,501) |
|
|
(1,706) |
|
|
|
|
Closing crude oil inventory |
|
|
172 |
|
|
156 |
|
|
258 |
|
|
|
|
|
|
|
|
172 |
|
|
258 |
|
|
|
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
|
|
7,966 |
|
|
6,468 |
|
|
15,985 |
|
|
23% |
|
|
(50%) |
|
|
20,889 |
|
|
32,667 |
|
|
(36%) |
Production
- Quarterly production increased 10% quarter-over-quarter and
decreased 2% 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 Q3 2015, efforts were largely focused on maintenance work,
facilities enhancement and preparations for the 2015 drilling
program.
- The horizontal sidetrack drill program commenced in early
October after the arrival of the drilling rig at the Wandoo A
platform in late September. Vermilion expects that the well will be
completed and placed on production during the fourth quarter.
- Additional 2015 planned activities include ongoing facilities
maintenance, enhancement, and refurbishment.
Financial review
|
|
Three Months Ended |
|
% change |
|
|
Nine
Months Ended |
|
%
change |
Australia business unit |
Sep 30, |
|
Jun 30, |
|
Sep 30, |
|
Q3/15 vs. |
|
Q3/15 vs. |
|
|
Sep 30, |
|
Sep 30, |
|
2015 vs. |
($M except as indicated) |
2015 |
|
2015 |
|
2014 |
|
Q2/15 |
|
Q3/14 |
|
|
2015 |
|
2014 |
|
2014 |
|
Sales |
39,325 |
|
56,204 |
|
63,708 |
|
(30%) |
|
(38%) |
|
|
114,813 |
|
212,510 |
|
(46%) |
|
Operating expense |
(13,766) |
|
(18,083) |
|
(14,302) |
|
(24%) |
|
(4%) |
|
|
(37,735) |
|
(43,713) |
|
(14%) |
|
General and administration |
(1,391) |
|
(1,141) |
|
(1,378) |
|
22% |
|
1% |
|
|
(3,986) |
|
(4,245) |
|
(6%) |
|
PRRT |
(99) |
|
(3,371) |
|
(13,834) |
|
(97%) |
|
(99%) |
|
|
(5,824) |
|
(46,772) |
|
(88%) |
|
Corporate income taxes |
(2,720) |
|
(5,134) |
|
(5,148) |
|
(47%) |
|
(47%) |
|
|
(8,431) |
|
(19,678) |
|
(57%) |
|
Fund flows from operations |
21,349 |
|
28,475 |
|
29,046 |
|
(25%) |
|
(26%) |
|
|
58,837 |
|
98,102 |
|
(40%) |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
68.20 |
|
80.87 |
|
119.07 |
|
(16%) |
|
(43%) |
|
|
76.46 |
|
124.59 |
|
(39%) |
|
Operating expense |
(23.87) |
|
(26.02) |
|
(26.73) |
|
(8%) |
|
(11%) |
|
|
(25.13) |
|
(25.63) |
|
(2%) |
|
General and administration |
(2.41) |
|
(1.64) |
|
(2.58) |
|
47% |
|
(7%) |
|
|
(2.65) |
|
(2.49) |
|
6% |
|
PRRT |
(0.17) |
|
(4.85) |
|
(25.86) |
|
(96%) |
|
(99%) |
|
|
(3.88) |
|
(27.42) |
|
(86%) |
|
Corporate income taxes |
(4.72) |
|
(7.39) |
|
(9.62) |
|
(36%) |
|
(51%) |
|
|
(5.61) |
|
(11.54) |
|
(51%) |
|
Fund flows from operations
netback |
37.03 |
|
40.97 |
|
54.28 |
|
(10%) |
|
(32%) |
|
|
39.19 |
|
57.51 |
|
(32%) |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated Brent (US $/bbl) |
50.26 |
|
61.92 |
|
101.85 |
|
(19%) |
|
(51%) |
|
|
55.39 |
|
106.57 |
|
(48%) |
|
Dated Brent ($/bbl) |
65.81 |
|
76.12 |
|
110.95 |
|
(14%) |
|
(41%) |
|
|
69.79 |
|
116.63 |
|
(40%) |
Sales
- Crude oil in Australia is
priced with reference to Dated Brent.
- During Q3 2015, inventory increased by 16,000 bbls, compared to
a draw of 162,000 bbls in Q2 2015 and a build of 69,000 bbls in Q3
2014.
- Sales per boe decreased 16% in Q3 2015 versus Q2 2015,
consistent with a 14% decrease in the Canadian dollar equivalent of
the Dated Brent reference price. This decrease in sales per boe,
combined with a decrease in sales volumes due to the absence of a
significant inventory draw in the period, resulted in a 30%
decrease in sales.
- On a year-over-year basis, sales per boe decreased by 43% and
39% for the three and nine months ended September 30, 2015, consistent with a decrease in
the Canadian dollar equivalent of the Dated Brent reference price.
For the three months ended September 30,
2015, the decline in pricing was slightly offset by higher
sold volumes (due to a higher inventory build in the comparative
period), resulting in a 38% decrease in sales. For the nine months
ended September 30, 2015, the decline
in pricing was coupled with a decrease in sold volumes driven by
decreased production, resulting in a 46% 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
- Operating expense decreased in Q3 2015 versus Q2 2015 as a
result of a slight build in inventory during the third quarter
versus a 162,000 bbl draw in inventory during the second
quarter.
- Year-over-year, operating expense decreased on both a dollar
and per barrel basis largely as the result of savings from cost
reduction initiatives, including reduced vessel usage, lower diesel
consumption, and reduced staffing costs. These favorable
variances were further enhanced by the impact of a weaker
Australian dollar in 2015.
General and administration
- Fluctuations in general and administration expense for the
three and nine months versus the comparable periods were 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 15% and 17%.
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 three and nine
months ended September 30, 2015 were
lower than the comparable periods as a result of decreased revenues
and increased capital spending in the 2015 periods.
UNITED
STATES BUSINESS UNIT
Overview
- Entered the United States in
September 2014.
- Interests include approximately 90,700 acres of land (98%
undeveloped) in the Powder River Basin of northeastern Wyoming.
- Tight oil development targeting the Turner Sand at a depth of
approximately 1,500 metres.
Operational and financial review
|
|
Three Months Ended |
|
|
%
change |
|
|
Nine Months
Ended |
United States business
unit |
Sep 30, |
|
|
Jun 30, |
|
|
Q3/15 vs. |
|
|
Sep 30, |
($M except as indicated) |
2015 |
|
|
2015 |
|
|
Q2/15 |
|
|
2015 |
|
Sales |
1,075 |
|
|
677 |
|
|
59% |
|
|
2,424 |
|
Royalties |
(309) |
|
|
(191) |
|
|
62% |
|
|
(706) |
|
Operating expense |
(146) |
|
|
(110) |
|
|
33% |
|
|
(471) |
|
General and administration |
(896) |
|
|
(963) |
|
|
(7%) |
|
|
(2,939) |
|
Fund flows from operations |
(276) |
|
|
(587) |
|
|
(53%) |
|
|
(1,692) |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
Sales |
51.60 |
|
|
60.57 |
|
|
(15%) |
|
|
52.95 |
|
Royalties |
(14.83) |
|
|
(17.08) |
|
|
(13%) |
|
|
(15.42) |
|
Operating expense |
(6.98) |
|
|
(9.88) |
|
|
(29%) |
|
|
(10.28) |
|
General and administration |
(43.03) |
|
|
(86.12) |
|
|
(50%) |
|
|
(64.20) |
|
Fund flows from operations
netback |
(13.24) |
|
|
(52.51) |
|
|
(75%) |
|
|
(36.95) |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl) |
46.43 |
|
|
57.94 |
|
|
(20%) |
|
|
51.00 |
|
WTI ($/bbl) |
60.80 |
|
|
71.23 |
|
|
(15%) |
|
|
64.26 |
Production |
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
226 |
|
|
123 |
|
|
84% |
|
|
168 |
Activity |
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
3,226 |
|
|
2,744 |
|
|
18% |
|
|
6,607 |
|
Acquisitions |
12,785 |
|
|
- |
|
|
|
|
|
12,785 |
|
Gross wells drilled |
- |
|
|
1.00 |
|
|
|
|
|
- |
|
Net wells drilled |
- |
|
|
1.00 |
|
|
|
|
|
- |
Activity review
- Vermilion completed the Seedy
Draw North well (100% working interest) in the East Finn prospect
area in Q3 2015, which was drilled in Q2 2015.
- During the quarter, we consolidated our ownership interest in
the eastern Powder River Basin of
Wyoming to a 100% working interest
through the US $9.6 million
acquisition of the remaining 30% interest that was previously
outstanding. The acquisition encompassed an estimated 0.9 mmboe of
2P reserves and an additional 22,000 net acres.
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. Q3 2015 royalties as a
percentage of sales of 28.7% was relatively consistent with Q2 2015
(28.2%).
Operating expense
- Operating expense on a dollar basis was higher than the
previous quarter due to incremental fuel and electricity purchases
for the Seedy Draw North well, which was brought on line at the end
of August. As a result of incremental production from this
well, operating expense on a per barrel basis decreased
quarter-over-quarter from $9.88/boe
to $6.98/boe.
General and administration
- General and administration expense decreased slightly by 7%
quarter-over-quarter due to the timing of expenditures.
CORPORATE
Overview
- Our Corporate segment includes costs related to our global
hedging program, financing expenses, and general and administration
expenses, primarily incurred in Canada and not directly related to the
operations of our business units.
Financial review
|
Three
Months Ended |
|
|
Nine
Months Ended |
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
Sep 30, |
($M) |
2015 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
General and administration recovery (expense) |
2,359 |
|
|
500 |
|
|
(2,322) |
|
|
3,816 |
|
|
(8,647) |
Current income taxes |
(480) |
|
|
(547) |
|
|
(227) |
|
|
(1,404) |
|
|
(778) |
Interest expense |
(15,420) |
|
|
(14,550) |
|
|
(12,918) |
|
|
(43,268) |
|
|
(36,712) |
Realized gain on derivatives |
10,854 |
|
|
3,081 |
|
|
8,837 |
|
|
20,192 |
|
|
13,896 |
Realized foreign exchange gain (loss) |
309 |
|
|
(2,740) |
|
|
812 |
|
|
875 |
|
|
(642) |
Realized other income |
227 |
|
|
204 |
|
|
235 |
|
|
653 |
|
|
530 |
Fund flows from operations |
(2,151) |
|
|
(14,052) |
|
|
(5,583) |
|
|
(19,136) |
|
|
(32,353) |
General and administration
- The increase in the recovery of general and administration
costs for the three and nine months ended September 30, 2015 versus the comparable periods
in the prior year is due to a decrease in staff-related
expenditures, general cost saving initiatives in response to
declining crude oil prices, and increased salary allocations to the
various business unit segments.
Current income taxes
- Taxes in our corporate segment relate to holding companies that
pay current taxes in foreign jurisdictions.
Interest expense
- The increase in interest expense in Q3 2015 versus the
comparable periods in the prior year is primarily due to increased
borrowings under our revolving credit facility. The increase in
interest expense for the three and nine months ended September 30, 2015 versus the comparable periods
in 2014 was further driven by interest expense related to the
finance lease recognized in Q1 2015.
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 (loss) 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 Q3 2015 related primarily to amounts
received on our Dated Brent, WTI, and TTF derivatives, partially
offset by payments made on our foreign exchange derivatives.
- A listing of derivative positions as at September 30, 2015 is included in "Supplemental
Table 2" in this MD&A.
FINANCIAL PERFORMANCE REVIEW
|
Three
Months Ended |
|
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Mar 31, |
|
|
Dec 31, |
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Mar 31, |
|
|
Dec 31, |
($M except per share) |
|
|
2015 |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
2014 |
|
|
2014 |
|
|
2014 |
|
|
2013 |
Petroleum and natural gas sales |
|
|
245,051 |
|
|
264,331 |
|
|
195,885 |
|
|
306,073 |
|
|
344,688 |
|
|
387,684 |
|
|
381,183 |
|
|
325,108 |
Net earnings (loss) |
|
|
(83,310) |
|
|
6,813 |
|
|
1,275 |
|
|
58,642 |
|
|
53,903 |
|
|
53,993 |
|
|
102,788 |
|
|
101,510 |
Net earnings (loss) per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
(0.76) |
|
|
0.06 |
|
|
0.01 |
|
|
0.55 |
|
|
0.50 |
|
|
0.51 |
|
|
1.00 |
|
|
1.00 |
|
Diluted |
|
|
(0.76) |
|
|
0.06 |
|
|
0.01 |
|
|
0.54 |
|
|
0.50 |
|
|
0.50 |
|
|
0.99 |
|
|
0.98 |
The following table shows a reconciliation of
the change in net earnings (loss):
($M) |
|
|
Q3/15 vs. Q2/15 |
|
|
Q3/15 vs. Q3/14 |
|
|
2015 vs. 2014 |
Net earnings - Comparative period |
|
|
6,813 |
|
|
53,903 |
|
|
210,684 |
Changes in: |
|
|
|
|
|
|
|
|
|
Fund flows from operations |
|
|
(61) |
|
|
(68,463) |
|
|
(239,611) |
Equity based compensation |
|
|
1,113 |
|
|
(2,053) |
|
|
(4,290) |
Unrealized gain or loss on derivative
instruments |
|
|
27,915 |
|
|
24,220 |
|
|
5,941 |
Unrealized foreign exchange gain or loss |
|
|
9,927 |
|
|
26,825 |
|
|
28,757 |
Unrealized other expense |
|
|
(105) |
|
|
288 |
|
|
(27) |
Accretion |
|
|
(486) |
|
|
(135) |
|
|
139 |
Depletion and depreciation |
|
|
(37,697) |
|
|
(44,684) |
|
|
(42,433) |
Deferred tax |
|
|
52,271 |
|
|
69,789 |
|
|
108,618 |
Impairment |
|
|
(143,000) |
|
|
(143,000) |
|
|
(143,000) |
Net loss - Current period |
|
|
(83,310) |
|
|
(83,310) |
|
|
(75,222) |
The fluctuations in net earnings (loss) 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 Q3 2015 was
lower than Q2 2015 due to a lower number of awards outstanding. For
the three and nine months ended September
30, 2015, equity based compensation expense was higher
versus the comparable periods in 2014 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 nine months ended September 30, 2015, we recognized an unrealized
gain on derivative instruments of $16.2
million, relating primarily to our TTF, Dated Brent, and WTI
swaps and collars. As at September 30,
2015, we have a net derivative asset position of
$40.9 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 and nine months ended September 30, 2015, the Canadian dollar weakened
versus the Euro and the US dollar, resulting in an unrealized
foreign exchange gain of $15.0
million and $15.1 million,
respectively.
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.
Q3 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 Q3 2015 of $28.28 was higher as
compared to $22.98 in Q2 2015. The
increase is primarily due to increased production from natural gas
properties in the Netherlands
which have higher per boe depletion expense. For the three and nine
months ended September 30, 2015,
depletion and depreciation on a per boe basis increased from
$23.21 to $28.28 for the three month period and from
$22.92 to $24.62 for the nine month period. These increases
were primarily driven by the aforementioned increased production
from natural gas properties in the
Netherlands, as well as increased light crude oil production
from Saskatchewan, Canada which
was acquired in April of 2014.
Deferred tax
Deferred tax expense (recovery) 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. The increase in deferred tax recovery largely
pertains to the tax effect on the $143.0
million impairment charge recorded in Q3 2015 and increased
depletion primarily associated with higher global production.
Impairment
For the three months ended September 30, 2015, Vermilion recorded an impairment charge of
$143.0 million related to the light
crude oil play in Saskatchewan,
Canada. These impairment charges were a result of
declines in the price forecasts for crude oil in Canada which decreased the expected future
cash flows from the CGU.
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 |
|
|
|
Sep 30, |
|
|
Dec 31, |
|
|
Sep 30, |
|
|
Dec 31, |
($M) |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
Revolving credit facility |
|
|
2.9% |
|
|
3.1% |
|
|
1,270,154 |
|
|
1,014,067 |
Senior unsecured notes (1) |
|
|
6.5% |
|
|
6.5% |
|
|
224,679 |
|
|
224,013 |
Long-term debt |
|
|
3.5% |
|
|
3.8% |
|
|
1,494,833 |
|
|
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 September 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 |
|
|
|
Sep 30, |
|
|
Dec 31, |
|
|
|
2015 |
|
|
2014 |
Total facility amount |
|
|
$2.0 billion |
|
|
$1.5 billion |
Amount drawn |
|
|
$1.3 billion |
|
|
$1.0 billion |
Letters of credit outstanding |
|
|
$29.3 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 |
|
|
|
|
|
|
Sep 30, |
|
|
Dec 31, |
Financial covenant |
|
|
Limit |
|
|
2015 |
|
|
2014 |
Consolidated total debt to consolidated
EBITDA |
|
|
4.0 |
|
|
2.16 |
|
|
1.21 |
Consolidated total senior debt to consolidated
EBITDA |
|
|
3.0 |
|
|
1.80 |
|
|
0.99 |
Consolidated total senior debt to total
capitalization |
|
|
50% |
|
|
36% |
|
|
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 |
|
|
$225.0 million |
Interest rate |
|
|
6.5% per annum |
Issued date |
|
|
February 10, 2011 |
Maturity date |
|
|
February 10, 2016 |
Vermilion may
redeem all or part of the senior unsecured notes at 100% of their
principal amount plus any accrued and unpaid interest. The
notes were initially recognized at fair value net of transaction
costs and are subsequently measured at amortized cost using an
effective interest rate of 7.1%.
Net debt
Net debt is reconciled to its most directly
comparable GAAP measure, long-term debt, as follows:
|
As
at |
|
|
|
Sep 30, |
|
|
Dec 31, |
($M) |
|
|
2015 |
|
|
2014 |
Long-term debt |
|
|
1,270,154 |
|
|
1,238,080 |
Current liabilities (1) |
|
|
474,885 |
|
|
365,729 |
Current assets |
|
|
(381,996) |
|
|
(338,159) |
Net debt |
|
|
1,363,043 |
|
|
1,265,650 |
|
|
|
|
|
|
|
Ratio of net debt to annualized fund flows from
operations |
|
|
2.7 |
|
|
1.6 |
(1) Includes the current portion of long-term
debt, which, as at September 30, 2015, represents the senior
unsecured notes that will mature on February 10, 2016. |
Long term debt, including the current portion,
as at September 30, 2015, increased
to $1.49 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, Ireland and Australia. The increase in long-term
debt resulted in an increase to net debt from $1.27 billion to $1.36
billion. As a result of this increase to long-term
debt coupled with weak commodity prices, the ratio of net debt to
fund flows from operations increased from 1.6 times as at
December 31, 2014 to 2.7 times for
the nine months ended September 30,
2015.
Shareholders' capital
During the nine months ended September 30, 2015, we maintained monthly
dividends at $0.215 per share and
declared dividends which totalled $211.6
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.
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 |
|
|
2,188 |
|
|
108,269 |
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 |
|
|
34 |
|
|
1,658 |
Balance as at September 30, 2015 |
|
|
110,818 |
|
|
2,133,364 |
As at September 30,
2015, there were approximately 1.7 million VIP awards
outstanding. As at November 5,
2015, there were approximately 111.2 million common shares
issued and outstanding.
ASSET RETIREMENT OBLIGATIONS
As at September 30,
2015, asset retirement obligations were $384.3 million compared to $350.8 million as at December 31, 2014.
The increase in asset retirement obligations is
largely attributable to accretion and additions from new
wells drilled year-to-date, as well as changes in foreign
exchange.
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 September 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 nine months ended
September 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 September 30,
2015 |
|
Nine Months Ended September 30,
2015 |
|
|
Three Months
Ended
September 30,
2014 |
|
Nine Months
Ended
September 30,
2014 |
|
|
|
Oil & NGLs |
|
|
Natural Gas |
|
|
Total |
|
|
Oil & NGLs |
|
|
Natural Gas |
|
|
Total |
|
|
Total |
|
|
Total |
|
|
|
$/bbl |
|
|
$/mcf |
|
|
$/boe |
|
|
$/bbl |
|
|
$/mcf |
|
|
$/boe |
|
|
$/boe |
|
|
$/boe |
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
46.36 |
|
|
2.88 |
|
|
32.78 |
|
|
51.54 |
|
|
2.88 |
|
|
36.34 |
|
|
64.85 |
|
|
68.58 |
Royalties |
|
|
(4.72) |
|
|
(0.10) |
|
|
(2.81) |
|
|
(5.30) |
|
|
(0.05) |
|
|
(3.09) |
|
|
(8.89) |
|
|
(8.05) |
Transportation |
|
|
(2.37) |
|
|
(0.17) |
|
|
(1.75) |
|
|
(2.49) |
|
|
(0.17) |
|
|
(1.85) |
|
|
(1.89) |
|
|
(1.80) |
Operating |
|
|
(11.37) |
|
|
(1.44) |
|
|
(10.10) |
|
|
(10.31) |
|
|
(1.41) |
|
|
(9.50) |
|
|
(8.91) |
|
|
(9.17) |
Operating netback |
|
|
27.90 |
|
|
1.17 |
|
|
18.12 |
|
|
33.44 |
|
|
1.25 |
|
|
21.90 |
|
|
45.16 |
|
|
49.56 |
General and administration |
|
|
|
|
|
|
|
|
(1.56) |
|
|
|
|
|
|
|
|
(1.95) |
|
|
(2.11) |
|
|
(2.25) |
Fund flows from operations netback |
|
|
|
|
|
|
|
|
16.56 |
|
|
|
|
|
|
|
|
19.95 |
|
|
43.05 |
|
|
47.31 |
France |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
61.75 |
|
|
2.93 |
|
|
60.96 |
|
|
66.26 |
|
|
2.36 |
|
|
65.66 |
|
|
107.99 |
|
|
114.36 |
Royalties |
|
|
(6.46) |
|
|
(0.55) |
|
|
(6.40) |
|
|
(6.00) |
|
|
(0.33) |
|
|
(5.95) |
|
|
(7.07) |
|
|
(7.26) |
Transportation |
|
|
(3.70) |
|
|
- |
|
|
(3.64) |
|
|
(3.38) |
|
|
- |
|
|
(3.34) |
|
|
(4.80) |
|
|
(4.88) |
Operating |
|
|
(9.62) |
|
|
(0.95) |
|
|
(9.55) |
|
|
(10.57) |
|
|
(1.04) |
|
|
(10.52) |
|
|
(15.42) |
|
|
(15.80) |
Operating netback |
|
|
41.97 |
|
|
1.43 |
|
|
41.37 |
|
|
46.31 |
|
|
0.99 |
|
|
45.85 |
|
|
80.70 |
|
|
86.42 |
General and administration |
|
|
|
|
|
|
|
|
(4.25) |
|
|
|
|
|
|
|
|
(4.61) |
|
|
(6.50) |
|
|
(5.63) |
Other income |
|
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
|
9.57 |
|
|
- |
|
|
- |
Current income taxes |
|
|
|
|
|
|
|
|
(3.74) |
|
|
|
|
|
|
|
|
(8.52) |
|
|
(10.89) |
|
|
(19.93) |
Fund flows from operations
netback |
|
|
|
|
|
|
|
|
33.38 |
|
|
|
|
|
|
|
|
42.29 |
|
|
63.31 |
|
|
60.86 |
Netherlands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
46.65 |
|
|
8.24 |
|
|
49.42 |
|
|
50.63 |
|
|
8.11 |
|
|
48.70 |
|
|
45.73 |
|
|
52.80 |
Royalties |
|
|
- |
|
|
(0.13) |
|
|
(0.77) |
|
|
- |
|
|
(0.26) |
|
|
(1.52) |
|
|
(1.60) |
|
|
(2.06) |
Operating |
|
|
- |
|
|
(1.06) |
|
|
(6.31) |
|
|
- |
|
|
(1.48) |
|
|
(8.74) |
|
|
(9.18) |
|
|
(9.57) |
Operating netback |
|
|
46.65 |
|
|
7.05 |
|
|
42.34 |
|
|
50.63 |
|
|
6.37 |
|
|
38.44 |
|
|
34.95 |
|
|
41.17 |
General and administration |
|
|
|
|
|
|
|
|
(2.59) |
|
|
|
|
|
|
|
|
(1.77) |
|
|
(0.35) |
|
|
(0.61) |
Current income taxes |
|
|
|
|
|
|
|
|
(5.40) |
|
|
|
|
|
|
|
|
(4.89) |
|
|
(2.02) |
|
|
(3.37) |
Fund flows from operations netback |
|
|
|
|
|
|
|
|
34.35 |
|
|
|
|
|
|
|
|
31.78 |
|
|
32.58 |
|
|
37.19 |
Germany |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
- |
|
|
7.39 |
|
|
44.36 |
|
|
- |
|
|
7.38 |
|
|
44.30 |
|
|
36.43 |
|
|
44.68 |
Royalties |
|
|
- |
|
|
(1.15) |
|
|
(6.88) |
|
|
- |
|
|
(1.24) |
|
|
(7.46) |
|
|
(8.68) |
|
|
(9.58) |
Transportation |
|
|
- |
|
|
(0.49) |
|
|
(2.92) |
|
|
- |
|
|
(0.65) |
|
|
(3.88) |
|
|
(2.86) |
|
|
(3.36) |
Operating |
|
|
- |
|
|
(2.17) |
|
|
(13.03) |
|
|
- |
|
|
(1.44) |
|
|
(8.66) |
|
|
(9.44) |
|
|
(9.10) |
Operating netback |
|
|
- |
|
|
3.58 |
|
|
21.53 |
|
|
- |
|
|
4.05 |
|
|
24.30 |
|
|
15.45 |
|
|
22.64 |
General and administration |
|
|
|
|
|
|
|
|
(6.11) |
|
|
|
|
|
|
|
|
(6.12) |
|
|
(4.62) |
|
|
(3.89) |
Current income taxes |
|
|
|
|
|
|
|
|
- |
|
|
|
|
|
|
|
|
- |
|
|
(0.62) |
|
|
(1.86) |
Fund flows from operations netback |
|
|
|
|
|
|
|
|
15.42 |
|
|
|
|
|
|
|
|
18.18 |
|
|
10.21 |
|
|
16.89 |
Australia |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
68.20 |
|
|
- |
|
|
68.20 |
|
|
76.46 |
|
|
- |
|
|
76.46 |
|
|
119.07 |
|
|
124.59 |
Operating |
|
|
(23.87) |
|
|
- |
|
|
(23.87) |
|
|
(25.13) |
|
|
- |
|
|
(25.13) |
|
|
(26.73) |
|
|
(25.63) |
PRRT (1) |
|
|
(0.17) |
|
|
- |
|
|
(0.17) |
|
|
(3.88) |
|
|
- |
|
|
(3.88) |
|
|
(25.86) |
|
|
(27.42) |
Operating netback |
|
|
44.16 |
|
|
- |
|
|
44.16 |
|
|
47.45 |
|
|
- |
|
|
47.45 |
|
|
66.48 |
|
|
71.54 |
General and administration |
|
|
|
|
|
|
|
|
(2.41) |
|
|
|
|
|
|
|
|
(2.65) |
|
|
(2.58) |
|
|
(2.49) |
Corporate income taxes |
|
|
|
|
|
|
|
|
(4.72) |
|
|
|
|
|
|
|
|
(5.61) |
|
|
(9.62) |
|
|
(11.54) |
Fund flows from operations netback |
|
|
|
|
|
|
|
|
37.03 |
|
|
|
|
|
|
|
|
39.19 |
|
|
54.28 |
|
|
57.51 |
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
51.60 |
|
|
- |
|
|
51.60 |
|
|
52.95 |
|
|
- |
|
|
52.95 |
|
|
- |
|
|
- |
Royalties |
|
|
(14.83) |
|
|
- |
|
|
(14.83) |
|
|
(15.42) |
|
|
- |
|
|
(15.42) |
|
|
- |
|
|
- |
Operating |
|
|
(6.98) |
|
|
- |
|
|
(6.98) |
|
|
(10.28) |
|
|
- |
|
|
(10.28) |
|
|
- |
|
|
- |
Operating netback |
|
|
29.79 |
|
|
- |
|
|
29.79 |
|
|
27.25 |
|
|
- |
|
|
27.25 |
|
|
- |
|
|
- |
General and administration |
|
|
|
|
|
|
|
|
(43.03) |
|
|
|
|
|
|
|
|
(64.20) |
|
|
- |
|
|
- |
Fund flows from operations netback |
|
|
|
|
|
|
|
|
(13.24) |
|
|
|
|
|
|
|
|
(36.95) |
|
|
- |
|
|
- |
Total Company |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
56.57 |
|
|
5.36 |
|
|
46.56 |
|
|
61.48 |
|
|
5.18 |
|
|
49.48 |
|
|
76.80 |
|
|
82.73 |
Realized hedging gain |
|
|
1.78 |
|
|
0.41 |
|
|
2.06 |
|
|
0.81 |
|
|
0.39 |
|
|
1.42 |
|
|
1.97 |
|
|
1.03 |
Royalties |
|
|
(4.59) |
|
|
(0.22) |
|
|
(3.25) |
|
|
(4.68) |
|
|
(0.27) |
|
|
(3.48) |
|
|
(6.46) |
|
|
(6.09) |
Transportation |
|
|
(2.44) |
|
|
(0.27) |
|
|
(2.11) |
|
|
(2.38) |
|
|
(0.33) |
|
|
(2.21) |
|
|
(2.45) |
|
|
(2.44) |
Operating |
|
|
(12.94) |
|
|
(1.36) |
|
|
(10.99) |
|
|
(12.96) |
|
|
(1.44) |
|
|
(11.25) |
|
|
(12.53) |
|
|
(12.81) |
PRRT (1) |
|
|
(0.03) |
|
|
- |
|
|
(0.02) |
|
|
(0.67) |
|
|
- |
|
|
(0.41) |
|
|
(3.08) |
|
|
(3.47) |
Operating netback |
|
|
38.35 |
|
|
3.92 |
|
|
32.25 |
|
|
41.60 |
|
|
3.53 |
|
|
33.55 |
|
|
54.25 |
|
|
58.95 |
General and administration |
|
|
|
|
|
|
|
|
(2.49) |
|
|
|
|
|
|
|
|
(2.89) |
|
|
(3.62) |
|
|
(3.60) |
Interest expense |
|
|
|
|
|
|
|
|
(2.93) |
|
|
|
|
|
|
|
|
(3.04) |
|
|
(2.88) |
|
|
(2.73) |
Realized foreign exchange gain
(loss) |
|
|
|
|
|
|
|
|
0.06 |
|
|
|
|
|
|
|
|
0.06 |
|
|
0.17 |
|
|
(0.05) |
Other income |
|
|
|
|
|
|
|
|
0.04 |
|
|
|
|
|
|
|
|
2.28 |
|
|
0.05 |
|
|
0.04 |
Corporate income taxes (1) |
|
|
|
|
|
|
|
|
(2.35) |
|
|
|
|
|
|
|
|
(3.32) |
|
|
(3.89) |
|
|
(6.59) |
Fund flows from operations netback |
|
|
|
|
|
|
|
|
24.58 |
|
|
|
|
|
|
|
|
26.64 |
|
|
44.08 |
|
|
46.02 |
(1) |
Vermilion considers Australian PRRT
to be an operating item and accordingly has included PRRT in the
calculation of operating netbacks.
Current income taxes presented above excludes PRRT. |
Supplemental Table 2: Hedges
The following tables outline Vermilion's outstanding risk management
positions as at September 30,
2015:
|
|
|
Note |
|
|
Volume |
|
|
Strike Price(s) |
Crude Oil |
|
|
|
|
|
|
|
|
|
WTI - Collar |
|
|
|
|
|
|
|
|
|
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 $ |
Dated Brent - Collar |
|
|
|
|
|
|
|
|
|
July 2015 - October 2015 |
|
|
5 |
|
|
250 bbl/d |
|
|
65.00 - 74.40 US $ |
July 2015 - June 2016 |
|
|
6 |
|
|
1,000 bbl/d |
|
|
80.50 - 93.49 CAD $ |
July 2015 - June 2016 |
|
|
7 |
|
|
500 bbl/d |
|
|
64.50 - 75.48 US $ |
October 2015 - December 2015 |
|
|
8 |
|
|
1,000 bbl/d |
|
|
79.38 - 92.45 CAD $ |
October 2015 - June 2016 |
|
|
9 |
|
|
250 bbl/d |
|
|
82.00 - 94.55 CAD $ |
January 2016 - June 2016 |
|
|
3 |
|
|
250 bbl/d |
|
|
84.00 - 93.70 CAD $ |
|
|
|
|
|
|
|
|
|
|
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 $ |
November 2015 - October 2016 |
|
|
|
|
|
10,000 GJ/d |
|
|
2.56 - 3.23 CAD $ |
January 2016 - December 2016 |
|
|
|
|
|
10,000 GJ/d |
|
|
2.53 - 3.29 CAD $ |
April 2016 - October 2016 |
|
|
|
|
|
2,500 GJ/d |
|
|
2.50 - 2.88 CAD $ |
AECO - Swap |
|
|
|
|
|
|
|
|
|
April 2015 - October 2015 |
|
|
10 |
|
|
10,000 GJ/d |
|
|
2.98 CAD $ |
April 2015 - December 2015 |
|
|
11 |
|
|
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 |
|
|
12 |
|
|
5,000 mmbtu/d |
|
|
3.25 - 3.86 US $ |
(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 contracted volumes increase to
500 boe/d for any monthly settlement periods above the contracted
ceiling price. |
(6) |
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). |
(7) |
The contracted volumes increase to
1,000 boe/d for any monthly settlement periods above the contracted
ceiling price. |
(8) |
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). |
(9) |
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). |
(10) |
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. |
(11) |
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. |
(12) |
The contracted volumes increase to
10,000 mmbtu/d for any monthly settlement periods above the
contracted ceiling price. |
|
|
|
Note |
|
|
Volume |
|
|
Strike Price(s) |
European Natural Gas |
|
|
|
|
|
|
|
|
|
NBP - Call |
|
|
|
|
|
|
|
|
|
October 2016 - March 2017 |
|
|
|
|
|
2,638 GJ/d |
|
|
4.64 GBP £ |
NBP - Collar |
|
|
|
|
|
|
|
|
|
April 2016 - March 2017 |
|
|
|
|
|
2,638 GJ/d |
|
|
3.79 - 4.53 GBP £ |
NBP - Put |
|
|
|
|
|
|
|
|
|
April 2016 - September 2016 |
|
|
|
|
|
2,638 GJ/d |
|
|
3.79 GBP £ |
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 $ |
July 2016 - March 2017 |
|
|
|
|
|
2,592 GJ/d |
|
|
5.43 EUR € |
TTF - Call |
|
|
|
|
|
|
|
|
|
October 2016 - March 2017 |
|
|
|
|
|
2,592 GJ/d |
|
|
6.03 EUR € |
TTF - Collar |
|
|
|
|
|
|
|
|
|
January 2015 - December 2015 |
|
|
|
|
|
2,592 GJ/d |
|
|
6.11 - 6.83 EUR € |
January 2016 - December 2016 |
|
|
1 |
|
|
2,592 GJ/d |
|
|
5.76 - 6.50 EUR € |
April 2016 - December 2016 |
|
|
2 |
|
|
12,960 GJ/d |
|
|
5.58 - 6.21 EUR € |
April 2016 - March 2017 |
|
|
3 |
|
|
5,184 GJ/d |
|
|
5.28 - 6.35 EUR € |
July 2016 - December 2016 |
|
|
|
|
|
2,592 GJ/d |
|
|
5.00 - 5.63 EUR € |
July 2016 - March 2017 |
|
|
1 |
|
|
2,592 GJ/d |
|
|
5.07 - 6.56 EUR € |
July 2016 - March 2018 |
|
|
1 |
|
|
2,592 GJ/d |
|
|
5.32 - 6.54 EUR € |
October 2016 - December 2017 |
|
|
|
|
|
2,592 GJ/d |
|
|
5.00 - 5.89 EUR € |
January 2017 - December 2017 |
|
|
|
|
|
2,592 GJ/d |
|
|
5.00 - 5.63 EUR € |
TTF - Put |
|
|
|
|
|
|
|
|
|
April 2016 - September 2016 |
|
|
|
|
|
2,592 GJ/d |
|
|
5.21 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 |
|
|
|
|
|
5,184 GJ/d |
|
|
5.94 EUR € |
April 2016 - December 2016 |
|
|
|
|
|
2,592 GJ/d |
|
|
5.91 EUR € |
July 2016 - June 2018 |
|
|
|
|
|
2,700 GJ/d |
|
|
5.58 EUR € |
October 2016 - December 2016 |
|
|
|
|
|
2,592 GJ/d |
|
|
5.45 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 $ |
|
|
|
|
|
|
|
|
|
|
Interest Rate |
|
|
|
|
|
|
|
|
|
CDOR to fixed - Swap |
|
|
|
|
|
|
|
|
|
September 2015 - September 2019 |
|
|
|
|
|
100,000,000 CAD $/year |
|
|
1.00 % |
(1) |
The contracted volumes increase to
5,184 GJ/d for any monthly settlement periods above the contracted
ceiling price. |
(2) |
The contracted volumes increase to
15,552 GJ/d for any monthly settlement periods above the contracted
ceiling price. |
(3) |
The contracted volumes increase to
10,368 GJ/d for any monthly settlement periods above the contracted
ceiling price. |
Supplemental Table 3: Capital
Expenditures
|
Three
Months Ended |
|
|
Nine
Months Ended |
By classification |
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
Sep 30, |
($M) |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
Drilling and development |
|
|
93,381 |
|
|
90,173 |
|
|
180,479 |
|
|
357,865 |
|
|
467,294 |
Exploration and evaluation |
|
|
- |
|
|
- |
|
|
9,554 |
|
|
- |
|
|
54,187 |
Capital expenditures |
|
|
93,381 |
|
|
90,173 |
|
|
190,033 |
|
|
357,865 |
|
|
521,481 |
Property acquisition |
|
|
22,155 |
|
|
480 |
|
|
40,847 |
|
|
22,670 |
|
|
219,074 |
Corporate acquisition |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
381,139 |
Acquisitions |
|
|
22,155 |
|
|
480 |
|
|
40,847 |
|
|
22,670 |
|
|
600,213 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended |
|
|
Nine
Months Ended |
By category |
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
Sep 30, |
($M) |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
Land |
|
|
763 |
|
|
1,469 |
|
|
2,346 |
|
|
2,974 |
|
|
8,049 |
Seismic |
|
|
810 |
|
|
1,723 |
|
|
6,135 |
|
|
4,026 |
|
|
11,436 |
Drilling and completion |
|
|
39,712 |
|
|
31,976 |
|
|
93,386 |
|
|
154,031 |
|
|
242,005 |
Production equipment and facilities |
|
|
44,589 |
|
|
43,957 |
|
|
68,964 |
|
|
163,301 |
|
|
198,266 |
Recompletions |
|
|
3,948 |
|
|
9,288 |
|
|
10,853 |
|
|
20,351 |
|
|
28,538 |
Other |
|
|
3,559 |
|
|
1,760 |
|
|
8,349 |
|
|
13,182 |
|
|
33,187 |
Capital expenditures |
|
|
93,381 |
|
|
90,173 |
|
|
190,033 |
|
|
357,865 |
|
|
521,481 |
Acquisitions |
|
|
22,155 |
|
|
480 |
|
|
40,847 |
|
|
22,670 |
|
|
600,213 |
Total capital expenditures and acquisitions |
|
|
115,536 |
|
|
90,653 |
|
|
230,880 |
|
|
380,535 |
|
|
1,121,694 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended |
|
|
Nine
Months Ended |
By country |
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
Sep 30, |
($M) |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
Canada |
|
|
45,286 |
|
|
22,265 |
|
|
125,276 |
|
|
182,435 |
|
|
663,277 |
France |
|
|
17,511 |
|
|
16,793 |
|
|
35,082 |
|
|
68,418 |
|
|
110,663 |
Netherlands |
|
|
5,297 |
|
|
18,885 |
|
|
10,087 |
|
|
28,515 |
|
|
51,718 |
Germany |
|
|
1,605 |
|
|
3,231 |
|
|
1,358 |
|
|
5,804 |
|
|
175,055 |
Ireland |
|
|
20,694 |
|
|
20,267 |
|
|
30,050 |
|
|
53,916 |
|
|
73,507 |
Australia |
|
|
7,966 |
|
|
6,468 |
|
|
15,985 |
|
|
20,889 |
|
|
32,667 |
United States |
|
|
16,011 |
|
|
2,744 |
|
|
11,175 |
|
|
19,392 |
|
|
11,175 |
Corporate |
|
|
1,166 |
|
|
- |
|
|
1,867 |
|
|
1,166 |
|
|
3,632 |
Total capital expenditures and acquisitions |
|
|
115,536 |
|
|
90,653 |
|
|
230,880 |
|
|
380,535 |
|
|
1,121,694 |
Supplemental Table 4: Production
|
|
|
|
Q3/15 |
|
|
Q2/15 |
|
|
Q1/15 |
|
|
Q4/14 |
|
|
Q3/14 |
|
|
Q2/14 |
|
|
Q1/14 |
|
|
Q4/13 |
|
|
Q3/13 |
|
|
Q2/13 |
|
|
Q1/13 |
|
|
Q4/12 |
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
|
9,195 |
|
|
10,182 |
|
|
10,893 |
|
|
11,384 |
|
|
11,469 |
|
|
12,676 |
|
|
9,437 |
|
|
8,719 |
|
|
7,969 |
|
|
8,885 |
|
|
7,966 |
|
|
7,983 |
|
NGLs (bbls/d) |
|
|
4,513 |
|
|
3,755 |
|
|
2,976 |
|
|
2,741 |
|
|
2,291 |
|
|
2,796 |
|
|
2,071 |
|
|
1,699 |
|
|
1,897 |
|
|
1,725 |
|
|
1,335 |
|
|
1,106 |
|
Natural gas (mmcf/d) |
|
|
71.94 |
|
|
64.66 |
|
|
61.78 |
|
|
58.36 |
|
|
57.07 |
|
|
57.59 |
|
|
49.53 |
|
|
41.43 |
|
|
43.40 |
|
|
43.69 |
|
|
41.04 |
|
|
31.41 |
|
Total (boe/d) |
|
|
25,698 |
|
|
24,713 |
|
|
24,165 |
|
|
23,851 |
|
|
23,272 |
|
|
25,070 |
|
|
19,763 |
|
|
17,322 |
|
|
17,099 |
|
|
17,892 |
|
|
16,140 |
|
|
14,323 |
|
% of
consolidated |
|
|
47% |
|
|
48% |
|
|
48% |
|
|
49% |
|
|
47% |
|
|
49% |
|
|
42% |
|
|
43% |
|
|
41% |
|
|
42% |
|
|
41% |
|
|
40% |
France |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
|
12,310 |
|
|
12,746 |
|
|
11,463 |
|
|
11,133 |
|
|
11,111 |
|
|
11,025 |
|
|
10,771 |
|
|
11,131 |
|
|
11,625 |
|
|
10,390 |
|
|
10,330 |
|
|
9,843 |
|
Natural gas (mmcf/d) |
|
|
1.47 |
|
|
1.03 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
5.23 |
|
|
4.19 |
|
|
4.21 |
|
|
3.91 |
|
Total (boe/d) |
|
|
12,555 |
|
|
12,917 |
|
|
11,463 |
|
|
11,133 |
|
|
11,111 |
|
|
11,025 |
|
|
10,771 |
|
|
11,131 |
|
|
12,496 |
|
|
11,088 |
|
|
11,032 |
|
|
10,495 |
|
% of consolidated |
|
|
22% |
|
|
25% |
|
|
23% |
|
|
22% |
|
|
22% |
|
|
21% |
|
|
23% |
|
|
27% |
|
|
30% |
|
|
26% |
|
|
29% |
|
|
29% |
Netherlands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d) |
|
|
109 |
|
|
112 |
|
|
63 |
|
|
81 |
|
|
63 |
|
|
96 |
|
|
69 |
|
|
62 |
|
|
48 |
|
|
50 |
|
|
96 |
|
|
70 |
|
Natural gas (mmcf/d) |
|
|
53.56 |
|
|
32.43 |
|
|
36.41 |
|
|
31.35 |
|
|
38.07 |
|
|
40.35 |
|
|
43.15 |
|
|
37.53 |
|
|
28.78 |
|
|
38.52 |
|
|
36.91 |
|
|
33.03 |
|
Total (boe/d) |
|
|
9,035 |
|
|
5,517 |
|
|
6,132 |
|
|
5,306 |
|
|
6,407 |
|
|
6,822 |
|
|
7,260 |
|
|
6,318 |
|
|
4,845 |
|
|
6,470 |
|
|
6,248 |
|
|
5,574 |
|
% of consolidated |
|
|
16% |
|
|
11% |
|
|
12% |
|
|
11% |
|
|
13% |
|
|
13% |
|
|
16% |
|
|
15% |
|
|
12% |
|
|
15% |
|
|
16% |
|
|
15% |
Germany |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
(mmcf/d) |
|
|
14.00 |
|
|
16.18 |
|
|
16.80 |
|
|
17.71 |
|
|
15.38 |
|
|
16.13 |
|
|
10.64 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
Total (boe/d) |
|
|
2,333 |
|
|
2,696 |
|
|
2,801 |
|
|
2,952 |
|
|
2,563 |
|
|
2,689 |
|
|
1,773 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
% of consolidated |
|
|
4% |
|
|
5% |
|
|
6% |
|
|
6% |
|
|
5% |
|
|
5% |
|
|
4% |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
Australia |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
|
6,433 |
|
|
5,865 |
|
|
5,672 |
|
|
6,134 |
|
|
6,567 |
|
|
6,483 |
|
|
7,110 |
|
|
6,189 |
|
|
7,070 |
|
|
7,363 |
|
|
5,287 |
|
|
5,873 |
|
% of consolidated |
|
|
11% |
|
|
11% |
|
|
11% |
|
|
12% |
|
|
13% |
|
|
12% |
|
|
15% |
|
|
15% |
|
|
17% |
|
|
17% |
|
|
14% |
|
|
16% |
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
|
226 |
|
|
123 |
|
|
153 |
|
|
195 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil & NGLs
(bbls/d) |
|
|
32,786 |
|
|
32,783 |
|
|
31,220 |
|
|
31,668 |
|
|
31,501 |
|
|
33,076 |
|
|
29,458 |
|
|
27,800 |
|
|
28,609 |
|
|
28,413 |
|
|
25,014 |
|
|
24,875 |
|
% of consolidated |
|
|
58% |
|
|
63% |
|
|
62% |
|
|
64% |
|
|
63% |
|
|
63% |
|
|
63% |
|
|
68% |
|
|
69% |
|
|
66% |
|
|
65% |
|
|
69% |
|
Natural gas (mmcf/d) |
|
|
140.97 |
|
|
114.29 |
|
|
115.00 |
|
|
107.42 |
|
|
110.52 |
|
|
114.08 |
|
|
103.32 |
|
|
78.96 |
|
|
77.41 |
|
|
86.40 |
|
|
82.16 |
|
|
68.34 |
|
% of consolidated |
|
|
42% |
|
|
37% |
|
|
38% |
|
|
36% |
|
|
37% |
|
|
37% |
|
|
37% |
|
|
32% |
|
|
31% |
|
|
34% |
|
|
35% |
|
|
31% |
|
Total (boe/d) |
|
|
56,280 |
|
|
51,831 |
|
|
50,386 |
|
|
49,571 |
|
|
49,920 |
|
|
52,089 |
|
|
46,677 |
|
|
40,960 |
|
|
41,510 |
|
|
42,813 |
|
|
38,707 |
|
|
36,265 |
|
|
|
|
YTD 2015 |
|
|
2014 |
|
|
2013 |
|
|
2012 |
|
|
2011 |
|
|
2010 |
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
|
10,083 |
|
|
11,248 |
|
|
8,387 |
|
|
7,659 |
|
|
4,701 |
|
|
2,778 |
|
NGLs (bbls/d) |
|
|
3,754 |
|
|
2,476 |
|
|
1,666 |
|
|
1,232 |
|
|
1,297 |
|
|
1,427 |
|
Natural gas (mmcf/d) |
|
|
66.16 |
|
|
55.67 |
|
|
42.39 |
|
|
37.50 |
|
|
43.38 |
|
|
43.91 |
|
Total (boe/d) |
|
|
24,864 |
|
|
23,001 |
|
|
17,117 |
|
|
15,142 |
|
|
13,227 |
|
|
11,524 |
|
% of consolidated |
|
|
47% |
|
|
47% |
|
|
41% |
|
|
40% |
|
|
38% |
|
|
36% |
France |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
|
12,176 |
|
|
11,011 |
|
|
10,873 |
|
|
9,952 |
|
|
8,110 |
|
|
8,347 |
|
Natural gas (mmcf/d) |
|
|
0.84 |
|
|
- |
|
|
3.40 |
|
|
3.59 |
|
|
0.95 |
|
|
0.92 |
|
Total (boe/d) |
|
|
12,316 |
|
|
11,011 |
|
|
11,440 |
|
|
10,550 |
|
|
8,269 |
|
|
8,501 |
|
% of consolidated |
|
|
23% |
|
|
22% |
|
|
28% |
|
|
28% |
|
|
23% |
|
|
26% |
Netherlands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d) |
|
|
95 |
|
|
77 |
|
|
64 |
|
|
67 |
|
|
58 |
|
|
35 |
|
Natural gas (mmcf/d) |
|
|
40.86 |
|
|
38.20 |
|
|
35.42 |
|
|
34.11 |
|
|
32.88 |
|
|
28.31 |
|
Total (boe/d) |
|
|
6,905 |
|
|
6,443 |
|
|
5,967 |
|
|
5,751 |
|
|
5,538 |
|
|
4,753 |
|
% of consolidated |
|
|
13% |
|
|
13% |
|
|
15% |
|
|
15% |
|
|
16% |
|
|
15% |
Germany |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d) |
|
|
15.65 |
|
|
14.99 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
Total (boe/d) |
|
|
2,608 |
|
|
2,498 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
% of consolidated |
|
|
5% |
|
|
5% |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
Australia |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
|
5,993 |
|
|
6,571 |
|
|
6,481 |
|
|
6,360 |
|
|
8,168 |
|
|
7,354 |
|
% of consolidated |
|
|
12% |
|
|
13% |
|
|
16% |
|
|
17% |
|
|
23% |
|
|
23% |
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
|
168 |
|
|
49 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil & NGLs (bbls/d) |
|
|
32,269 |
|
|
31,432 |
|
|
27,471 |
|
|
25,270 |
|
|
22,334 |
|
|
19,941 |
|
% of consolidated |
|
|
61% |
|
|
63% |
|
|
67% |
|
|
67% |
|
|
63% |
|
|
62% |
|
Natural gas (mmcf/d) |
|
|
123.51 |
|
|
108.85 |
|
|
81.21 |
|
|
75.20 |
|
|
77.21 |
|
|
73.14 |
|
% of consolidated |
|
|
39% |
|
|
37% |
|
|
33% |
|
|
33% |
|
|
37% |
|
|
38% |
|
Total (boe/d) |
|
|
52,854 |
|
|
49,573 |
|
|
41,005 |
|
|
37,803 |
|
|
35,202 |
|
|
32,132 |
Supplemental Table 5: Segmented Financial
Results
|
Three
Months Ended September 30, 2015 |
($M) |
|
|
Canada |
|
|
France |
|
|
Netherlands |
|
|
Germany |
|
|
Ireland |
|
|
Australia |
|
|
United States |
|
|
Corporate |
|
|
Total |
Drilling and development |
|
|
37,224 |
|
|
17,369 |
|
|
5,297 |
|
|
1,605 |
|
|
20,694 |
|
|
7,966 |
|
|
3,226 |
|
|
- |
|
|
93,381 |
Oil and gas sales to external
customers |
|
|
77,493 |
|
|
76,552 |
|
|
41,083 |
|
|
9,523 |
|
|
- |
|
|
39,325 |
|
|
1,075 |
|
|
- |
|
|
245,051 |
Royalties |
|
|
(6,638) |
|
|
(8,038) |
|
|
(638) |
|
|
(1,477) |
|
|
- |
|
|
- |
|
|
(309) |
|
|
- |
|
|
(17,100) |
Revenue from external customers |
|
|
70,855 |
|
|
68,514 |
|
|
40,445 |
|
|
8,046 |
|
|
- |
|
|
39,325 |
|
|
766 |
|
|
- |
|
|
227,951 |
Transportation expense |
|
|
(4,131) |
|
|
(4,566) |
|
|
- |
|
|
(627) |
|
|
(1,766) |
|
|
- |
|
|
- |
|
|
- |
|
|
(11,090) |
Operating expense |
|
|
(23,877) |
|
|
(11,998) |
|
|
(5,243) |
|
|
(2,796) |
|
|
- |
|
|
(13,766) |
|
|
(146) |
|
|
- |
|
|
(57,826) |
General and administration |
|
|
(3,694) |
|
|
(5,338) |
|
|
(2,154) |
|
|
(1,311) |
|
|
(663) |
|
|
(1,391) |
|
|
(896) |
|
|
2,359 |
|
|
(13,088) |
PRRT |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(99) |
|
|
- |
|
|
- |
|
|
(99) |
Corporate income taxes |
|
|
- |
|
|
(4,696) |
|
|
(4,487) |
|
|
- |
|
|
- |
|
|
(2,720) |
|
|
- |
|
|
(480) |
|
|
(12,383) |
Interest expense |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(15,420) |
|
|
(15,420) |
Realized gain on derivative instruments |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
10,854 |
|
|
10,854 |
Realized foreign exchange gain |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
309 |
|
|
309 |
Realized other income |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
227 |
|
|
227 |
Fund flows from operations |
|
|
39,153 |
|
|
41,916 |
|
|
28,561 |
|
|
3,312 |
|
|
(2,429) |
|
|
21,349 |
|
|
(276) |
|
|
(2,151) |
|
|
129,435 |
|
Nine
Months Ended September 30, 2015 |
($M) |
|
|
Canada |
|
|
France |
|
|
Netherlands |
|
|
Germany |
|
|
Ireland |
|
|
Australia |
|
|
United States |
|
|
Corporate |
|
|
Total |
Total assets |
|
|
1,769,222 |
|
|
902,777 |
|
|
219,221 |
|
|
172,664 |
|
|
947,592 |
|
|
223,261 |
|
|
36,955 |
|
|
231,009 |
|
|
4,502,701 |
Drilling and development |
|
|
173,954 |
|
|
68,180 |
|
|
28,515 |
|
|
5,804 |
|
|
53,916 |
|
|
20,889 |
|
|
6,607 |
|
|
- |
|
|
357,865 |
Oil and gas sales to external
customers |
|
|
246,661 |
|
|
218,011 |
|
|
91,814 |
|
|
31,544 |
|
|
- |
|
|
114,813 |
|
|
2,424 |
|
|
- |
|
|
705,267 |
Royalties |
|
|
(20,998) |
|
|
(19,760) |
|
|
(2,858) |
|
|
(5,313) |
|
|
- |
|
|
- |
|
|
(706) |
|
|
- |
|
|
(49,635) |
Revenue from external customers |
|
|
225,663 |
|
|
198,251 |
|
|
88,956 |
|
|
26,231 |
|
|
- |
|
|
114,813 |
|
|
1,718 |
|
|
- |
|
|
655,632 |
Transportation expense |
|
|
(12,542) |
|
|
(11,103) |
|
|
- |
|
|
(2,761) |
|
|
(5,107) |
|
|
- |
|
|
- |
|
|
- |
|
|
(31,513) |
Operating expense |
|
|
(64,510) |
|
|
(34,926) |
|
|
(16,483) |
|
|
(6,168) |
|
|
- |
|
|
(37,735) |
|
|
(471) |
|
|
- |
|
|
(160,293) |
General and administration |
|
|
(13,219) |
|
|
(15,323) |
|
|
(3,345) |
|
|
(4,354) |
|
|
(1,803) |
|
|
(3,986) |
|
|
(2,939) |
|
|
3,816 |
|
|
(41,153) |
PRRT |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(5,824) |
|
|
- |
|
|
- |
|
|
(5,824) |
Corporate income taxes |
|
|
- |
|
|
(28,293) |
|
|
(9,222) |
|
|
- |
|
|
- |
|
|
(8,431) |
|
|
- |
|
|
(1,404) |
|
|
(47,350) |
Interest expense |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(43,268) |
|
|
(43,268) |
Realized gain on derivative
instruments |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
20,192 |
|
|
20,192 |
Realized foreign exchange gain |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
875 |
|
|
875 |
Realized other income |
|
|
- |
|
|
31,775 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
653 |
|
|
32,428 |
Fund flows from operations |
|
|
135,392 |
|
|
140,381 |
|
|
59,906 |
|
|
12,948 |
|
|
(6,910) |
|
|
58,837 |
|
|
(1,692) |
|
|
(19,136) |
|
|
379,726 |
ADDITIONAL AND NON-GAAP FINANCIAL
MEASURES
This MD&A includes references to certain
financial measures which do not have standardized meanings
prescribed by IFRS. As such, these financial measures are
considered additional GAAP or non-GAAP financial measures and
therefore may not be comparable with similar measures presented by
other issuers.
Fund flows from operations: We
define fund flows from operations as cash flows from operating
activities before changes in non-cash operating working capital and
asset retirement obligations settled. Management believes
that by excluding the temporary impact of changes in non-cash
operating working capital, fund flows from operations provides a
measure of our ability to generate cash (that is not subject to
short-term movements in non-cash operating working capital)
necessary to pay dividends, repay debt, fund asset retirement
obligations and make capital investments. As we have presented fund
flows from operations in the "Segmented Information" note of our
unaudited condensed consolidated interim financial statements for
the three and nine months ended September
30, 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 |
|
|
Nine
Months Ended |
|
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
Sep 30, |
($M) |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
Cash flows from operating
activities |
|
|
122,230 |
|
|
134,668 |
|
|
235,010 |
|
|
279,545 |
|
|
562,840 |
Changes in non-cash operating working
capital |
|
|
5,082 |
|
|
(6,390) |
|
|
(41,789) |
|
|
93,733 |
|
|
46,788 |
Asset retirement obligations
settled |
|
|
2,123 |
|
|
1,218 |
|
|
4,677 |
|
|
6,448 |
|
|
9,709 |
Fund flows from operations |
|
|
129,435 |
|
|
129,496 |
|
|
197,898 |
|
|
379,726 |
|
|
619,337 |
Expenses related to Corrib |
|
|
2,429 |
|
|
2,276 |
|
|
1,849 |
|
|
6,910 |
|
|
5,542 |
Fund flows from operations (excluding
Corrib) |
|
|
131,864 |
|
|
131,772 |
|
|
199,747 |
|
|
386,636 |
|
|
624,879 |
|
Three
Months Ended |
|
|
Nine
Months Ended |
|
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
|
|
Sep 30, |
|
|
Sep 30, |
($M) |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
|
2015 |
|
|
2014 |
Dividends declared |
|
|
71,244 |
|
|
70,976 |
|
|
68,896 |
|
|
211,610 |
|
|
203,613 |
Issuance of shares
pursuant to the dividend reinvestment and Premium
DividendTM plans |
|
|
(44,590) |
|
|
(42,301) |
|
|
(20,416) |
|
|
(108,269) |
|
|
(58,450) |
Net dividends |
|
|
26,654 |
|
|
28,675 |
|
|
48,480 |
|
|
103,341 |
|
|
145,163 |
Drilling and development |
|
|
93,381 |
|
|
90,173 |
|
|
180,479 |
|
|
357,865 |
|
|
467,294 |
Exploration and evaluation |
|
|
- |
|
|
- |
|
|
9,554 |
|
|
- |
|
|
54,187 |
Asset retirement obligations
settled |
|
|
2,123 |
|
|
1,218 |
|
|
4,677 |
|
|
6,448 |
|
|
9,709 |
Payout |
|
|
122,158 |
|
|
120,066 |
|
|
243,190 |
|
|
467,654 |
|
|
676,353 |
Corrib drilling and development |
|
|
(20,694) |
|
|
(20,267) |
|
|
(30,050) |
|
|
(53,916) |
|
|
(73,507) |
Payout (excluding Corrib) |
|
|
101,464 |
|
|
99,799 |
|
|
213,140 |
|
|
413,738 |
|
|
602,846 |
|
As
at |
|
|
|
Sep 30, |
|
|
Jun 30, |
|
|
Sep 30, |
('000s of shares) |
|
|
2015 |
|
|
2015 |
|
|
2014 |
Shares outstanding |
|
|
110,818 |
|
|
109,806 |
|
|
106,921 |
Potential shares issuable pursuant to the VIP |
|
|
2,825 |
|
|
2,820 |
|
|
2,828 |
Diluted shares outstanding |
|
|
113,643 |
|
|
112,626 |
|
|
109,749 |
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)
|
|
September 30, |
December 31, |
|
|
|
Note |
|
|
2015 |
|
|
2014 |
ASSETS |
|
|
|
|
|
|
|
|
|
Current |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
|
|
|
148,816 |
|
|
120,405 |
Accounts receivable |
|
|
|
|
|
158,375 |
|
|
171,820 |
Crude oil inventory |
|
|
|
|
|
17,451 |
|
|
9,510 |
Derivative instruments |
|
|
|
|
|
39,418 |
|
|
23,391 |
Prepaid expenses |
|
|
|
|
|
17,936 |
|
|
13,033 |
|
|
|
|
|
|
381,996 |
|
|
338,159 |
|
|
|
|
|
|
|
|
|
|
Derivative instruments |
|
|
|
|
|
3,580 |
|
|
1,403 |
Deferred taxes |
|
|
|
|
|
181,767 |
|
|
154,816 |
Exploration and evaluation assets |
|
|
3 |
|
|
311,851 |
|
|
380,621 |
Capital assets |
|
|
2 |
|
|
3,623,507 |
|
|
3,511,092 |
|
|
|
|
|
|
4,502,701 |
|
|
4,386,091 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES |
|
|
|
|
|
|
|
|
|
Current |
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities |
|
|
|
|
|
204,326 |
|
|
298,196 |
Current portion of long-term debt |
|
|
5 |
|
|
224,679 |
|
|
- |
Dividends payable |
|
|
6 |
|
|
23,825 |
|
|
23,070 |
Derivative instruments |
|
|
|
|
|
2,049 |
|
|
- |
Income taxes payable |
|
|
|
|
|
20,006 |
|
|
44,463 |
|
|
|
|
|
|
474,885 |
|
|
365,729 |
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
5 |
|
|
1,270,154 |
|
|
1,238,080 |
Finance lease obligation |
|
|
2 |
|
|
24,648 |
|
|
- |
Asset retirement obligations |
|
|
4 |
|
|
384,269 |
|
|
350,753 |
Deferred taxes |
|
|
|
|
|
362,931 |
|
|
410,183 |
|
|
|
|
|
|
2,516,887 |
|
|
2,364,745 |
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS' EQUITY |
|
|
|
|
|
|
|
|
|
Shareholders' capital |
|
|
6 |
|
|
2,133,364 |
|
|
1,959,021 |
Contributed surplus |
|
|
|
|
|
87,374 |
|
|
92,188 |
Accumulated other comprehensive income |
|
|
|
|
|
95,054 |
|
|
5,722 |
Deficit |
|
|
|
|
|
(329,978) |
|
|
(35,585) |
|
|
|
|
|
|
1,985,814 |
|
|
2,021,346 |
|
|
|
|
|
|
4,502,701 |
|
|
4,386,091 |
CONSOLIDATED STATEMENTS OF NET EARNINGS (LOSS) AND
COMPREHENSIVE INCOME
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE
AMOUNTS, UNAUDITED)
|
|
|
Three
Months Ended |
|
Nine
Months Ended |
|
|
Sep 30, |
|
Sep 30, |
|
Sep 30, |
|
Sep 30, |
Note |
2015 |
|
2014 |
|
2015 |
|
2014 |
REVENUE |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Petroleum and natural gas sales |
|
|
|
|
|
245,051 |
|
|
344,688 |
|
|
705,267 |
|
|
1,113,555 |
Royalties |
|
|
|
|
|
(17,100) |
|
|
(29,000) |
|
|
(49,635) |
|
|
(82,037) |
Petroleum and natural gas revenue |
|
|
|
|
|
227,951 |
|
|
315,688 |
|
|
655,632 |
|
|
1,031,518 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating |
|
|
|
|
|
57,826 |
|
|
56,227 |
|
|
160,293 |
|
|
172,426 |
Transportation |
|
|
|
|
|
11,090 |
|
|
10,979 |
|
|
31,513 |
|
|
32,872 |
Equity based compensation |
|
|
7 |
|
|
16,773 |
|
|
14,720 |
|
|
53,699 |
|
|
49,409 |
Gain on derivative instruments |
|
|
|
|
|
(42,874) |
|
|
(16,637) |
|
|
(36,347) |
|
|
(24,110) |
Interest expense |
|
|
|
|
|
15,420 |
|
|
12,918 |
|
|
43,268 |
|
|
36,712 |
General and administration |
|
|
|
|
|
13,088 |
|
|
16,262 |
|
|
41,153 |
|
|
48,491 |
Foreign exchange (gain) loss |
|
|
|
|
|
(15,267) |
|
|
11,055 |
|
|
(16,019) |
|
|
14,255 |
Other expense (income) |
|
|
|
|
|
82 |
|
|
362 |
|
|
(31,654) |
|
|
217 |
Accretion |
|
|
4 |
|
|
6,199 |
|
|
6,064 |
|
|
17,587 |
|
|
17,726 |
Depletion and depreciation |
|
|
2, 3 |
|
|
148,843 |
|
|
104,159 |
|
|
350,946 |
|
|
308,513 |
Impairment |
|
|
2, 3 |
|
|
143,000 |
|
|
- |
|
|
143,000 |
|
|
- |
|
|
|
|
|
|
354,180 |
|
|
216,109 |
|
|
757,439 |
|
|
656,511 |
EARNINGS (LOSS) BEFORE INCOME TAXES |
|
|
|
|
|
(126,229) |
|
|
99,579 |
|
|
(101,807) |
|
|
375,007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME TAXES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred |
|
|
|
|
|
(55,401) |
|
|
14,388 |
|
|
(79,759) |
|
|
28,859 |
Current |
|
|
|
|
|
12,482 |
|
|
31,288 |
|
|
53,174 |
|
|
135,464 |
|
|
|
|
|
|
(42,919) |
|
|
45,676 |
|
|
(26,585) |
|
|
164,323 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS (LOSS) |
|
|
|
|
|
(83,310) |
|
|
53,903 |
|
|
(75,222) |
|
|
210,684 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER COMPREHENSIVE INCOME (LOSS) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Currency translation adjustments |
|
|
|
|
|
101,923 |
|
|
(36,143) |
|
|
89,332 |
|
|
(33,402) |
COMPREHENSIVE INCOME |
|
|
|
|
|
18,613 |
|
|
17,760 |
|
|
14,110 |
|
|
177,282 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET EARNINGS (LOSS) PER SHARE |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
|
|
|
(0.76) |
|
|
0.50 |
|
|
(0.69) |
|
|
2.01 |
Diluted |
|
|
|
|
|
(0.76) |
|
|
0.50 |
|
|
(0.69) |
|
|
1.98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING
('000s) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
|
|
|
110,293 |
|
|
106,768 |
|
|
109,052 |
|
|
104,891 |
Diluted |
|
|
|
|
|
110,293 |
|
|
108,290 |
|
|
109,052 |
|
|
106,582 |
CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)
|
|
|
Three
Months Ended |
|
Nine
Months Ended |
|
|
|
Sep 30, |
|
Sep 30, |
|
Sep 30, |
|
Sep 30, |
|
Note |
|
2015 |
|
2014 |
|
2015 |
|
2014 |
OPERATING |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
|
|
|
|
|
(83,310) |
|
|
53,903 |
|
|
(75,222) |
|
|
210,684 |
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion |
|
|
4 |
|
|
6,199 |
|
|
6,064 |
|
|
17,587 |
|
|
17,726 |
|
Depletion and depreciation |
|
|
2, 3 |
|
|
148,843 |
|
|
104,159 |
|
|
350,946 |
|
|
308,513 |
|
Impairment |
|
|
2, 3 |
|
|
143,000 |
|
|
- |
|
|
143,000 |
|
|
- |
|
Unrealized gain on derivative instruments |
|
|
|
|
|
(32,020) |
|
|
(7,800) |
|
|
(16,155) |
|
|
(10,214) |
|
Equity based compensation |
|
|
7 |
|
|
16,773 |
|
|
14,720 |
|
|
53,699 |
|
|
49,409 |
|
Unrealized foreign exchange (gain) loss |
|
|
|
|
|
(14,958) |
|
|
11,867 |
|
|
(15,144) |
|
|
13,613 |
|
Unrealized other expense |
|
|
|
|
|
309 |
|
|
597 |
|
|
774 |
|
|
747 |
|
Deferred taxes |
|
|
|
|
|
(55,401) |
|
|
14,388 |
|
|
(79,759) |
|
|
28,859 |
Asset retirement obligations
settled |
|
|
4 |
|
|
(2,123) |
|
|
(4,677) |
|
|
(6,448) |
|
|
(9,709) |
Changes in non-cash operating working
capital |
|
|
|
|
|
(5,082) |
|
|
41,789 |
|
|
(93,733) |
|
|
(46,788) |
Cash flows from operating
activities |
|
|
|
|
|
122,230 |
|
|
235,010 |
|
|
279,545 |
|
|
562,840 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INVESTING |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and development |
|
|
2 |
|
|
(93,381) |
|
|
(180,479) |
|
|
(357,865) |
|
|
(467,294) |
Exploration and evaluation |
|
|
3 |
|
|
- |
|
|
(9,554) |
|
|
- |
|
|
(54,187) |
Property acquisitions |
|
|
2, 3 |
|
|
(22,155) |
|
|
(40,847) |
|
|
(22,670) |
|
|
(219,074) |
Corporate acquisitions, net of cash
acquired |
|
|
|
|
|
- |
|
|
- |
|
|
- |
|
|
(176,179) |
Changes in non-cash investing working
capital |
|
|
|
|
|
646 |
|
|
24,539 |
|
|
(26,516) |
|
|
40,002 |
Cash flows used in investing
activities |
|
|
|
|
|
(114,890) |
|
|
(206,341) |
|
|
(407,051) |
|
|
(876,732) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FINANCING |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in long-term
debt |
|
|
|
|
|
63,328 |
|
|
(1,600) |
|
|
251,189 |
|
|
204,127 |
Decrease in finance lease
obligation |
|
|
|
|
|
(1,297) |
|
|
- |
|
|
(1,297) |
|
|
- |
Cash dividends |
|
|
|
|
|
(26,437) |
|
|
(48,415) |
|
|
(102,586) |
|
|
(142,600) |
Cash flows from (used in) financing
activities |
|
|
|
|
|
35,594 |
|
|
(50,015) |
|
|
147,306 |
|
|
61,527 |
Foreign exchange gain
(loss) on cash held in foreign currencies |
|
|
|
|
|
7,844 |
|
|
(1,631) |
|
|
8,611 |
|
|
5,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash
equivalents |
|
|
|
|
|
50,778 |
|
|
(22,977) |
|
|
28,411 |
|
|
(247,039) |
Cash and cash equivalents, beginning
of period |
|
|
|
|
|
98,038 |
|
|
165,497 |
|
|
120,405 |
|
|
389,559 |
Cash and cash equivalents, end of
period |
|
|
|
|
|
148,816 |
|
|
142,520 |
|
|
148,816 |
|
|
142,520 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplementary
information for operating activities - cash payments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid |
|
|
|
|
|
18,464 |
|
|
15,132 |
|
|
49,219 |
|
|
40,947 |
|
Income taxes paid |
|
|
|
|
|
19,501 |
|
|
28,617 |
|
|
78,329 |
|
|
106,177 |
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 |
|
|
|
|
|
- |
|
|
- |
|
|
- |
|
|
210,684 |
|
|
210,684 |
Currency translation
adjustments |
|
|
|
|
|
- |
|
|
- |
|
|
(33,402) |
|
|
- |
|
|
(33,402) |
Equity based
compensation expense |
|
|
|
|
|
- |
|
|
48,688 |
|
|
- |
|
|
- |
|
|
48,688 |
Dividends declared |
|
|
6 |
|
|
- |
|
|
- |
|
|
- |
|
|
(203,613) |
|
|
(203,613) |
Shares issued pursuant to the |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
dividend reinvestment plan |
|
|
6 |
|
|
58,450 |
|
|
- |
|
|
- |
|
|
- |
|
|
58,450 |
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 September 30, 2014 |
|
|
|
|
|
1,937,750 |
|
|
74,063 |
|
|
13,740 |
|
|
(25,085) |
|
|
2,000,468 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
Total |
|
|
|
Shareholders' |
|
Contributed |
|
Comprehensive |
|
|
|
Shareholders' |
|
Note |
|
Capital |
|
Surplus |
|
|
Income |
|
Deficit |
|
Equity |
Balances as at January 1, 2015 |
|
|
|
|
|
1,959,021 |
|
|
92,188 |
|
|
5,722 |
|
|
(35,585) |
|
|
2,021,346 |
Net loss |
|
|
|
|
|
- |
|
|
- |
|
|
- |
|
|
(75,222) |
|
|
(75,222) |
Currency translation adjustments |
|
|
|
|
|
- |
|
|
- |
|
|
89,332 |
|
|
- |
|
|
89,332 |
Equity based compensation expense |
|
|
7 |
|
|
- |
|
|
52,041 |
|
|
- |
|
|
- |
|
|
52,041 |
Dividends declared |
|
|
6 |
|
|
- |
|
|
- |
|
|
- |
|
|
(211,610) |
|
|
(211,610) |
Shares issued pursuant to the |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
dividend reinvestment and Premium |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DividendTM plans |
|
|
6 |
|
|
108,269 |
|
|
- |
|
|
- |
|
|
- |
|
|
108,269 |
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 |
|
|
1,658 |
|
|
- |
|
|
- |
|
|
- |
|
|
1,658 |
Balances as at September 30, 2015 |
|
|
|
|
|
2,133,364 |
|
|
87,374 |
|
|
95,054 |
|
|
(329,978) |
|
|
1,985,814 |
DESCRIPTION OF EQUITY RESERVES
Shareholders' capital
Represents the recognized amount for common
shares when issued, net of equity issuance costs and deferred
taxes.
Contributed surplus
Represents the recognized value of employee
awards which are settled in shares. Once vested, the value of
the awards is transferred to shareholders' capital.
Accumulated other comprehensive
income
Represents the cumulative income and expenses
which are not recorded immediately in net earnings and are
accumulated until an event triggers recognition in net
earnings. The current balance consists of currency
translation adjustments resulting from translating financial
statements of subsidiaries with a foreign functional currency to
Canadian dollars at period-end rates.
Deficit
Represents the cumulative net earnings less
distributed earnings of Vermilion Energy Inc.
NOTES TO THE CONDENSED CONSOLIDATED INTERIM
FINANCIAL STATEMENTS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 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
November 5, 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 |
|
|
356,253 |
|
|
1,612 |
|
|
357,865 |
Property acquisitions |
|
|
21,504 |
|
|
- |
|
|
21,504 |
Changes in estimate for asset retirement
obligations |
|
|
7,638 |
|
|
- |
|
|
7,638 |
Depletion and depreciation |
|
|
(329,729) |
|
|
(3,288) |
|
|
(333,017) |
Recognition of finance lease obligation |
|
|
31,028 |
|
|
- |
|
|
31,028 |
Impairment |
|
|
(91,976) |
|
|
- |
|
|
(91,976) |
Effect of movements in foreign exchange rates |
|
|
118,822 |
|
|
551 |
|
|
119,373 |
Balance at September 30, 2015 |
|
|
3,604,735 |
|
|
18,772 |
|
|
3,623,507 |
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 was 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).
Impairments
On a quarterly basis, Vermilion performs an assessment as to whether
any cash generating units ("CGUs") have indicators of
impairment. When indicators of impairment are identified,
Vermilion assesses the recoverable
amount of the applicable CGU based on the higher of the estimated
fair value less costs to sell and value in use as at the reporting
date. The estimated fair value takes into account the most
recent commodity price forecasts, expected production and estimated
costs and timing of development.
For the three months ended September 30, 2015, Vermilion recorded an impairment charge of
$143.0 million related to the light
crude oil play in Saskatchewan,
Canada. These impairment charges were a result of
declines in the price forecasts for crude oil in Canada which decreased the expected cash flows
from the CGU. The recoverable amount was determined using a
range of fair value estimates encompassing before-tax discount
rates of 8% to 10% for proved and probable reserves and 10% to 15%
on resources carried within exploration and evaluation assets.
The following table outlines the forward
commodity price estimates that were used in the calculation of
recoverable amounts:
|
|
|
WTI Oil
(US $/bbl) |
|
|
AECO Gas
(CDN $/mmbtu) |
|
|
Blended NGLs
(CDN $/bbl) |
2016 |
|
|
53.55 |
|
|
3.35 |
|
|
30.78 |
2017 |
|
|
57.20 |
|
|
3.70 |
|
|
36.62 |
2018 |
|
|
63.65 |
|
|
3.85 |
|
|
41.38 |
2019 |
|
|
70.35 |
|
|
4.20 |
|
|
45.95 |
2020 |
|
|
77.30 |
|
|
4.45 |
|
|
50.68 |
2021 |
|
|
84.45 |
|
|
4.80 |
|
|
55.84 |
2022 |
|
|
91.90 |
|
|
5.05 |
|
|
61.02 |
Average increase thereafter |
|
|
2.0% |
|
|
2.0% |
|
|
2.0% |
3. EXPLORATION AND EVALUATION ASSETS
The following table reconciles the change in Vermilion's exploration and evaluation
assets:
($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 |
|
|
(8) |
Property acquisitions |
|
|
1,166 |
Depreciation |
|
|
(21,893) |
Impairment |
|
|
(51,024) |
Effect of movements in foreign
exchange rates |
|
|
2,989 |
Balance at September 30,
2015 |
|
|
311,851 |
4. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the change in
Vermilion's asset retirement
obligations:
($M) |
Asset Retirement Obligations |
Balance at January 1, 2014 |
|
|
326,162 |
Additional obligations recognized |
|
|
22,565 |
Changes in estimates for asset retirement
obligations |
|
|
(3,434) |
Obligations settled |
|
|
(15,956) |
Accretion |
|
|
23,913 |
Changes in discount rates |
|
|
9,404 |
Effect of movements in foreign exchange rates |
|
|
(11,901) |
Balance at December 31, 2014 |
|
|
350,753 |
Additional obligations recognized |
|
|
3,657 |
Obligations settled |
|
|
(6,448) |
Accretion |
|
|
17,587 |
Changes in discount rates |
|
|
3,973 |
Effect of movements in foreign exchange rates |
|
|
14,747 |
Balance at September 30, 2015 |
|
|
384,269 |
5. LONG-TERM DEBT
The following table summarizes Vermilion's outstanding long-term debt:
|
As
at |
($M) |
|
|
Sept 30, 2015 |
|
|
Dec 31, 2014 |
Revolving credit facility |
|
|
1,270,154 |
|
|
1,014,067 |
Senior unsecured notes (1) |
|
|
224,679 |
|
|
224,013 |
Long-term debt |
|
|
1,494,833 |
|
|
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
September 30, 2015. |
Revolving Credit Facility
At September 30,
2015, Vermilion had in
place a bank revolving credit facility totalling $2 billion, of which approximately $1.27 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 nine months ended September 30, 2015, the interest rate on the
revolving credit facility was approximately 3.5% (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 $29.3 million as at September 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 September 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 |
|
|
2,188 |
|
|
108,269 |
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 |
|
|
34 |
|
|
1,658 |
Balance as at September 30, 2015 |
|
|
110,818 |
|
|
2,133,364 |
Dividends declared to shareholders for the nine
months ended September 30, 2015 were
$211.6 million (2014 - $203.6 million).
Subsequent to the end of the period and prior to
the condensed consolidated interim financial statements being
authorized for issue on November 5,
2015, Vermilion declared
dividends totalling $23.9 million or
$0.215 per share.
7. EQUITY BASED COMPENSATION
The following table summarizes the number of
awards outstanding under the Vermilion Incentive Plan ("VIP"):
|
|
|
Nine Months |
|
|
Full Year |
Number of Awards ('000s) |
|
|
2015 |
|
|
2014 |
Opening balance |
|
|
1,775 |
|
|
1,665 |
Granted |
|
|
595 |
|
|
707 |
Vested |
|
|
(587) |
|
|
(515) |
Modified |
|
|
- |
|
|
(21) |
Forfeited |
|
|
(65) |
|
|
(61) |
Closing balance |
|
|
1,718 |
|
|
1,775 |
|
|
|
|
|
|
|
The fair value of a VIP award is determined on
the grant date at the closing price of Vermilion's common shares on the Toronto Stock
Exchange, adjusted by the estimated performance factor that will
ultimately be achieved.
8. SEGMENTED INFORMATION
Vermilion has
operations in three core areas: North
America, Europe, and
Australia. Vermilion's operating activities in each
country relate solely to the exploration, development and
production of petroleum and natural gas. Vermilion has a Corporate head office located
in Calgary, Alberta. Costs
incurred in the Corporate segment relate to Vermilion's global hedging program and
expenses incurred in financing and managing our operating business
units.
Vermilion's
chief operating decision maker reviews the financial performance of
the Company by assessing the fund flows from operations of each
country individually. Fund flows from operations provides a
measure of each business unit's ability to generate cash (that is
not subject to short-term movements in non-cash operating working
capital) necessary to pay dividends, fund asset retirement
obligations, and make capital investments.
|
Three
Months Ended September 30, 2015 |
($M) |
|
|
Canada |
|
|
France |
|
|
Netherlands |
|
|
Germany |
|
|
Ireland |
|
|
Australia |
|
|
United States |
|
|
Corporate |
|
|
Total |
Drilling and development |
|
|
37,224 |
|
|
17,369 |
|
|
5,297 |
|
|
1,605 |
|
|
20,694 |
|
|
7,966 |
|
|
3,226 |
|
|
- |
|
|
93,381 |
Oil and gas sales to external
customers |
|
|
77,493 |
|
|
76,552 |
|
|
41,083 |
|
|
9,523 |
|
|
- |
|
|
39,325 |
|
|
1,075 |
|
|
- |
|
|
245,051 |
Royalties |
|
|
(6,638) |
|
|
(8,038) |
|
|
(638) |
|
|
(1,477) |
|
|
- |
|
|
- |
|
|
(309) |
|
|
- |
|
|
(17,100) |
Revenue from external customers |
|
|
70,855 |
|
|
68,514 |
|
|
40,445 |
|
|
8,046 |
|
|
- |
|
|
39,325 |
|
|
766 |
|
|
- |
|
|
227,951 |
Transportation expense |
|
|
(4,131) |
|
|
(4,566) |
|
|
- |
|
|
(627) |
|
|
(1,766) |
|
|
- |
|
|
- |
|
|
- |
|
|
(11,090) |
Operating expense |
|
|
(23,877) |
|
|
(11,998) |
|
|
(5,243) |
|
|
(2,796) |
|
|
- |
|
|
(13,766) |
|
|
(146) |
|
|
- |
|
|
(57,826) |
General and administration |
|
|
(3,694) |
|
|
(5,338) |
|
|
(2,154) |
|
|
(1,311) |
|
|
(663) |
|
|
(1,391) |
|
|
(896) |
|
|
2,359 |
|
|
(13,088) |
PRRT |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(99) |
|
|
- |
|
|
- |
|
|
(99) |
Corporate income taxes |
|
|
- |
|
|
(4,696) |
|
|
(4,487) |
|
|
- |
|
|
- |
|
|
(2,720) |
|
|
- |
|
|
(480) |
|
|
(12,383) |
Interest expense |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(15,420) |
|
|
(15,420) |
Realized gain on derivative instruments |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
10,854 |
|
|
10,854 |
Realized foreign exchange gain |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
309 |
|
|
309 |
Realized other income |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
227 |
|
|
227 |
Fund flows from operations |
|
|
39,153 |
|
|
41,916 |
|
|
28,561 |
|
|
3,312 |
|
|
(2,429) |
|
|
21,349 |
|
|
(276) |
|
|
(2,151) |
|
|
129,435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended September 30, 2014 |
($M) |
|
|
Canada |
|
|
France |
|
|
Netherlands |
|
|
Germany |
|
|
Ireland |
|
|
Australia |
|
|
United States |
|
|
Corporate |
|
|
Total |
Drilling and development |
|
|
88,116 |
|
|
34,883 |
|
|
10,087 |
|
|
1,358 |
|
|
30,050 |
|
|
15,985 |
|
|
- |
|
|
- |
|
|
180,479 |
Exploration and evaluation |
|
|
9,277 |
|
|
199 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
78 |
|
|
9,554 |
Oil and gas sales to external customers |
|
|
138,853 |
|
|
106,576 |
|
|
26,960 |
|
|
8,591 |
|
|
- |
|
|
63,708 |
|
|
- |
|
|
- |
|
|
344,688 |
Royalties |
|
|
(19,034) |
|
|
(6,978) |
|
|
(942) |
|
|
(2,046) |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(29,000) |
Revenue from external customers |
|
|
119,819 |
|
|
99,598 |
|
|
26,018 |
|
|
6,545 |
|
|
- |
|
|
63,708 |
|
|
- |
|
|
- |
|
|
315,688 |
Transportation expense |
|
|
(4,048) |
|
|
(4,741) |
|
|
- |
|
|
(675) |
|
|
(1,515) |
|
|
- |
|
|
- |
|
|
- |
|
|
(10,979) |
Operating expense |
|
|
(19,074) |
|
|
(15,215) |
|
|
(5,409) |
|
|
(2,227) |
|
|
- |
|
|
(14,302) |
|
|
- |
|
|
- |
|
|
(56,227) |
General and administration |
|
|
(4,523) |
|
|
(6,411) |
|
|
(204) |
|
|
(1,090) |
|
|
(334) |
|
|
(1,378) |
|
|
- |
|
|
(2,322) |
|
|
(16,262) |
PRRT |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(13,834) |
|
|
- |
|
|
- |
|
|
(13,834) |
Corporate income taxes |
|
|
- |
|
|
(10,744) |
|
|
(1,189) |
|
|
(146) |
|
|
- |
|
|
(5,148) |
|
|
- |
|
|
(227) |
|
|
(17,454) |
Interest expense |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(12,918) |
|
|
(12,918) |
Realized gain on derivative instruments |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
8,837 |
|
|
8,837 |
Realized foreign exchange gain |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
812 |
|
|
812 |
Realized other income |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
235 |
|
|
235 |
Fund flows from operations |
|
|
92,174 |
|
|
62,487 |
|
|
19,216 |
|
|
2,407 |
|
|
(1,849) |
|
|
29,046 |
|
|
- |
|
|
(5,583) |
|
|
197,898 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2015 |
($M) |
|
|
Canada |
|
|
France |
|
|
Netherlands |
|
|
Germany |
|
|
Ireland |
|
|
Australia |
|
|
United States |
|
|
Corporate |
|
|
Total |
Total assets |
|
|
1,769,222 |
|
|
902,777 |
|
|
219,221 |
|
|
172,664 |
|
|
947,592 |
|
|
223,261 |
|
|
36,955 |
|
|
231,009 |
|
|
4,502,701 |
Drilling and development |
|
|
173,954 |
|
|
68,180 |
|
|
28,515 |
|
|
5,804 |
|
|
53,916 |
|
|
20,889 |
|
|
6,607 |
|
|
- |
|
|
357,865 |
Oil and gas sales to external customers |
|
|
246,661 |
|
|
218,011 |
|
|
91,814 |
|
|
31,544 |
|
|
- |
|
|
114,813 |
|
|
2,424 |
|
|
- |
|
|
705,267 |
Royalties |
|
|
(20,998) |
|
|
(19,760) |
|
|
(2,858) |
|
|
(5,313) |
|
|
- |
|
|
- |
|
|
(706) |
|
|
- |
|
|
(49,635) |
Revenue from external customers |
|
|
225,663 |
|
|
198,251 |
|
|
88,956 |
|
|
26,231 |
|
|
- |
|
|
114,813 |
|
|
1,718 |
|
|
- |
|
|
655,632 |
Transportation expense |
|
|
(12,542) |
|
|
(11,103) |
|
|
- |
|
|
(2,761) |
|
|
(5,107) |
|
|
- |
|
|
- |
|
|
- |
|
|
(31,513) |
Operating expense |
|
|
(64,510) |
|
|
(34,926) |
|
|
(16,483) |
|
|
(6,168) |
|
|
- |
|
|
(37,735) |
|
|
(471) |
|
|
- |
|
|
(160,293) |
General and administration |
|
|
(13,219) |
|
|
(15,323) |
|
|
(3,345) |
|
|
(4,354) |
|
|
(1,803) |
|
|
(3,986) |
|
|
(2,939) |
|
|
3,816 |
|
|
(41,153) |
PRRT |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(5,824) |
|
|
- |
|
|
- |
|
|
(5,824) |
Corporate income taxes |
|
|
- |
|
|
(28,293) |
|
|
(9,222) |
|
|
- |
|
|
- |
|
|
(8,431) |
|
|
- |
|
|
(1,404) |
|
|
(47,350) |
Interest expense |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(43,268) |
|
|
(43,268) |
Realized gain on derivative instruments |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
20,192 |
|
|
20,192 |
Realized foreign exchange gain |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
875 |
|
|
875 |
Realized other income |
|
|
- |
|
|
31,775 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
653 |
|
|
32,428 |
Fund flows from operations |
|
|
135,392 |
|
|
140,381 |
|
|
59,906 |
|
|
12,948 |
|
|
(6,910) |
|
|
58,837 |
|
|
(1,692) |
|
|
(19,136) |
|
|
379,726 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine
Months Ended September 30, 2014 |
($M) |
|
|
Canada |
|
|
France |
|
|
Netherlands |
|
|
Germany |
|
|
Ireland |
|
|
Australia |
|
|
United States |
|
|
Corporate |
|
|
Total |
Total assets |
|
|
1,857,012 |
|
|
894,060 |
|
|
237,070 |
|
|
164,025 |
|
|
809,296 |
|
|
269,959 |
|
|
- |
|
|
206,305 |
|
|
4,437,727 |
Drilling and development |
|
|
215,860 |
|
|
99,564 |
|
|
43,512 |
|
|
2,184 |
|
|
73,507 |
|
|
32,667 |
|
|
- |
|
|
- |
|
|
467,294 |
Exploration and evaluation |
|
|
33,440 |
|
|
11,099 |
|
|
8,206 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
1,442 |
|
|
54,187 |
Oil and gas sales to external customers |
|
|
425,294 |
|
|
348,753 |
|
|
98,395 |
|
|
28,603 |
|
|
- |
|
|
212,510 |
|
|
- |
|
|
- |
|
|
1,113,555 |
Royalties |
|
|
(49,937) |
|
|
(22,125) |
|
|
(3,843) |
|
|
(6,132) |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(82,037) |
Revenue from external customers |
|
|
375,357 |
|
|
326,628 |
|
|
94,552 |
|
|
22,471 |
|
|
- |
|
|
212,510 |
|
|
- |
|
|
- |
|
|
1,031,518 |
Transportation expense |
|
|
(11,170) |
|
|
(14,879) |
|
|
- |
|
|
(2,149) |
|
|
(4,674) |
|
|
- |
|
|
- |
|
|
- |
|
|
(32,872) |
Operating expense |
|
|
(56,863) |
|
|
(48,185) |
|
|
(17,841) |
|
|
(5,824) |
|
|
- |
|
|
(43,713) |
|
|
- |
|
|
- |
|
|
(172,426) |
General and administration |
|
|
(13,951) |
|
|
(17,164) |
|
|
(1,128) |
|
|
(2,488) |
|
|
(868) |
|
|
(4,245) |
|
|
- |
|
|
(8,647) |
|
|
(48,491) |
PRRT |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(46,772) |
|
|
- |
|
|
- |
|
|
(46,772) |
Corporate income taxes |
|
|
- |
|
|
(60,769) |
|
|
(6,278) |
|
|
(1,189) |
|
|
- |
|
|
(19,678) |
|
|
- |
|
|
(778) |
|
|
(88,692) |
Interest expense |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(36,712) |
|
|
(36,712) |
Realized gain on derivative instruments |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
13,896 |
|
|
13,896 |
Realized foreign exchange loss |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(642) |
|
|
(642) |
Realized other income |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
530 |
|
|
530 |
Fund flows from operations |
|
|
293,373 |
|
|
185,631 |
|
|
69,305 |
|
|
10,821 |
|
|
(5,542) |
|
|
98,102 |
|
|
- |
|
|
(32,353) |
|
|
619,337 |
Reconciliation of fund flows from operations to net earnings
(loss)
|
Three
Months Ended |
|
Nine
Months Ended |
|
|
|
Sep 30, |
|
|
Sep 30, |
|
|
|
Sep 30, |
|
|
Sep 30, |
($M) |
|
|
2015 |
|
|
2014 |
|
|
|
2015 |
|
|
2014 |
Fund flows from operations |
|
|
129,435 |
|
|
197,898 |
|
|
|
379,726 |
|
|
619,337 |
Equity based compensation |
|
|
(16,773) |
|
|
(14,720) |
|
|
|
(53,699) |
|
|
(49,409) |
Unrealized gain on derivative instruments |
|
|
32,020 |
|
|
7,800 |
|
|
|
16,155 |
|
|
10,214 |
Unrealized foreign exchange gain (loss) |
|
|
14,958 |
|
|
(11,867) |
|
|
|
15,144 |
|
|
(13,613) |
Unrealized other expense |
|
|
(309) |
|
|
(597) |
|
|
|
(774) |
|
|
(747) |
Accretion |
|
|
(6,199) |
|
|
(6,064) |
|
|
|
(17,587) |
|
|
(17,726) |
Depletion and depreciation |
|
|
(148,843) |
|
|
(104,159) |
|
|
|
(350,946) |
|
|
(308,513) |
Deferred taxes |
|
|
55,401 |
|
|
(14,388) |
|
|
|
79,759 |
|
|
(28,859) |
Impairment |
|
|
(143,000) |
|
|
- |
|
|
|
(143,000) |
|
|
- |
Net earnings (loss) |
|
|
(83,310) |
|
|
53,903 |
|
|
|
(75,222) |
|
|
210,684 |
9. CAPITAL DISCLOSURES
|
Three
Months Ended |
|
Nine
Months Ended |
($M except as
indicated) |
|
|
Sep 30, 2015 |
|
|
Sep 30, 2014 |
|
|
|
Sep 30, 2015 |
|
|
Sep 30, 2014 |
Long-term debt |
|
|
1,270,154 |
|
|
1,198,648 |
|
|
|
1,270,154 |
|
|
1,198,648 |
Current liabilities
(1) |
|
|
474,885 |
|
|
431,175 |
|
|
|
474,885 |
|
|
431,175 |
Current assets |
|
|
(381,996) |
|
|
(386,385) |
|
|
|
(381,996) |
|
|
(386,385) |
Net debt [1] |
|
|
1,363,043 |
|
|
1,243,438 |
|
|
|
1,363,043 |
|
|
1,243,438 |
Cash flows from operating
activities |
|
|
122,230 |
|
|
235,010 |
|
|
|
279,545 |
|
|
562,840 |
Changes in non-cash operating
working capital |
|
|
5,082 |
|
|
(41,789) |
|
|
|
93,733 |
|
|
46,788 |
Asset retirement obligations
settled |
|
|
2,123 |
|
|
4,677 |
|
|
|
6,448 |
|
|
9,709 |
Fund flows from
operations |
|
|
129,435 |
|
|
197,898 |
|
|
|
379,726 |
|
|
619,337 |
Annualized fund
flows from operations [2] |
|
|
517,740 |
|
|
791,592 |
|
|
|
506,301 |
|
|
825,783 |
Ratio of net debt
to annualized fund flows from operations ([1] ÷ [2]) |
|
|
2.6 |
|
|
1.6 |
|
|
|
2.7 |
|
|
1.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
Includes the current portion of long-term debt, which, as at
September 30, 2015, represents the senior unsecured notes that will
mature on February 10, 2016. |
Long-term debt, including the current portion,
as at September 30, 2015 increased to
$1.49 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 nine months ended September 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 as at December 31, 2015 to $1.36
billion.
Driven primarily by the weakness in crude oil
prices, the ratio of net debt to fund flows from operations
increased to 2.7 for the nine months ended September 30, 2015.
10. FINANCIAL INSTRUMENTS
Classification of Financial Instruments
The following table summarizes information relating to
Vermilion's financial instruments
as at September 30, 2015 and
December 31, 2014:
|
|
|
|
|
|
|
|
|
|
|
|
As at Sep 30, 2015 |
|
|
As at Dec 31, 2014 |
|
|
|
Class of
financial
instrument |
|
|
Consolidated
balance
sheet caption |
|
|
Accounting
designation |
|
|
Related caption
on Statement of Net
Earnings (Loss) |
|
|
Carrying
value ($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 |
|
|
148,816 |
|
|
148,816 |
|
|
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 |
|
|
158,375 |
|
|
158,375 |
|
|
171,820 |
|
171,820 |
|
|
Not applicable |
Derivative assets |
|
|
Derivative instruments |
|
|
HFT |
|
|
Gain on derivative instruments |
|
|
42,998 |
|
|
42,998 |
|
|
24,794 |
|
24,794 |
|
|
Level 2 |
Derivative liabilities |
|
|
Derivative instruments |
|
|
HFT |
|
|
Gain on derivative
instruments |
|
|
(2,049) |
|
|
(2,049) |
|
|
- |
|
- |
|
|
Level 2 |
Payables |
|
|
Accounts payable and
accrued liabilities |
|
|
OTH |
|
|
Gains and losses on foreign exchange
are included in foreign exchange (gain)
loss |
|
|
(228,151) |
|
|
(228,151) |
|
|
(321,266) |
|
(321,266) |
|
|
Not applicable |
|
|
|
Dividends payable |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
Long-term debt |
|
|
OTH |
|
|
Interest expense |
|
|
(1,494,833) |
|
|
(1,494,592) |
|
|
(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 (loss).
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 (loss).
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 (loss) using the effective interest
method. Foreign exchange gains and losses are recognized in
net earnings (loss).
Level 1 - Fair value measurement is determined
by reference to unadjusted quoted prices in active markets for
identical assets or liabilities.
Level 2 - Fair value measurement is determined
based on inputs other than unadjusted quoted prices that are
observable, either directly or indirectly.
Level 3 - Fair value measurement is based on
inputs for the asset or liability that are not based on observable
market data.
Determination of Fair Values
The level in the fair value hierarchy into which
the fair value measurements are categorized is determined on the
basis of the lowest level input that is significant to the fair
value measurement. Transfers between levels on the fair value
hierarchy are deemed to have occurred at the end of the reporting
period.
Fair values for derivative assets and derivative
liabilities are determined using pricing models incorporating
future prices that are based on assumptions which are supported by
prices from observable market transactions and are adjusted for
credit risk.
The carrying value of receivables approximate
their fair value due to their short maturities.
The carrying value of long-term debt outstanding
on the revolving credit facility approximates its fair value due to
the use of short-term borrowing instruments at market rates of
interest.
The fair value of the senior unsecured notes
changes in response to changes in the market rates of interest
payable on similar instruments and was determined with reference to
prevailing market rates for such instruments.
Nature and Extent of Risks Arising from Financial
Instruments
Market risk:
Vermilion's
financial instruments are exposed to currency risk related to
changes in foreign currency denominated financial instruments and
commodity price risk related to outstanding derivative
positions. The following table summarizes what the impact on
comprehensive income before tax would be for the nine months ended
September 30, 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 |
September
30,
2015 |
Currency risk - Euro to Canadian |
|
|
Increase in
strength of the Canadian dollar against the Euro by 5% over the
relevant closing rates |
|
|
(3,254) |
|
|
|
|
|
|
|
|
|
|
Decrease in
strength of the Canadian dollar against the Euro by 5% over the
relevant closing rates |
|
|
3,254 |
|
|
|
|
|
|
|
Currency risk - US $ to
Canadian |
|
|
Increase in
strength of the Canadian dollar against the US $ by 5% over the
relevant closing rates |
|
|
(7,014) |
|
|
|
|
|
|
|
|
|
|
Decrease in
strength of the Canadian dollar against the US $ by 5% over the
relevant closing rates |
|
|
7,014 |
|
|
|
|
|
|
|
Commodity price risk |
|
|
Increase in relevant oil
reference price within option pricing models used to determine |
|
|
(5,929) |
|
|
|
the fair value of
financial derivatives by US $5.00/bbl at the relevant valuation
dates |
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in relevant oil
reference price within option pricing models used to determine |
|
|
6,053 |
|
|
|
the fair value of financial
derivatives by US $5.00/bbl at the relevant valuation dates |
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in relevant TTF
reference price within option pricing models used to determine |
|
|
(7,995) |
|
|
|
the fair value of financial
derivatives by € 0.5/GJ at the relevant valuation dates |
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in relevant TTF
reference price within option pricing models used to determine |
|
|
13,510 |
|
|
|
the fair value of financial
derivatives by € 0.5/GJ at the relevant valuation dates |
|
|
|
|
|
|
|
|
|
|
Interest rate risk |
|
|
Increase in average
Canadian prime interest rate by 100 basis points during the
relevant periods |
|
|
(7,691) |
|
|
|
|
|
|
|
|
|
|
Decrease in average
Canadian prime interest rate by 100 basis points during the
relevant periods |
|
|
7,691 |
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.