Vermilion Energy Inc. Announces Results for the Three and Nine Months Ended September 30, 2015
Vermilion Energy Inc. Announces Results for the Three and Nine Months Ended September 30, 2015
Vermilion Energy Inc. Announces Results for the Three and Nine Months Ended September 30, 2015
Canada NewsWire
CALGARY, Nov. 9, 2015
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
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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.
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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.
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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.
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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.
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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 $80 million for full-year 2015.
(1)
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Additional GAAP Financial Measure. Please see the "Additional and
Non-GAAP Financial Measures" section of Management's Discussion and
Analysis.
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Conference Call and Audio Webcast Details
Vermilion will discuss these results in a conference call to be held on
Monday, November 9, 2015 at 9:00 AM MST (11:00 AM EST). To
participate, you may call 1-888-231-8191 (Canada and US Toll Free) or
1-647-427-7450 (International and Toronto Area). The conference call
will also be available on replay by calling 1-855-859-2056 using
conference ID number 49495111. The replay will be available until
midnight mountain time on November 16, 2015.
You may also listen to the audio webcast by going to http://event.on24.com/r.htm?e=1056685&s=1&k=8F525422649C891C089BC59110D715CC or visit Vermilion's website at www.vermilionenergy.com/ir/eventspresentations.cfm.
HIGHLIGHTS
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Three Months Ended
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Nine Months Ended
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($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,
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Financial
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2015
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2015
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2014
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2015
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2014
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Petroleum and natural gas sales
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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
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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
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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) ($/basic share)
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(0.76)
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0.06
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0.50
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(0.69)
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2.01
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Capital expenditures
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93,381
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90,173
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190,033
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357,865
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521,481
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Acquisitions
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22,155
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480
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40,847
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22,670
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600,213
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Asset retirement obligations settled
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2,123
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1,218
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4,677
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6,448
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9,709
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Cash dividends ($/share)
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0.645
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0.645
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0.645
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1.935
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1.935
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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%
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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%
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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%
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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
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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
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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
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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
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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%
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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
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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
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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
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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
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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
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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
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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
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(1)
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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.
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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
$M
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thousand dollars
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$MM
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million dollars
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AECO
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the daily average benchmark price for natural gas at the AECO 'C' hub in
southeast Alberta
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bbl(s)
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barrel(s)
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bbls/d
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barrels per day
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bcf
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billion cubic feet
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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)
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boe/d
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barrel of oil equivalent per day
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GJ
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gigajoules
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HH
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Henry Hub, a reference price paid for natural gas in US dollars at
Erath, Louisiana
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mbbls
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thousand barrels
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mboe
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thousand barrel of oil equivalent
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mcf
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thousand cubic feet
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mcf/d
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thousand cubic feet per day
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mmboe
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million barrel of oil equivalent
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mmcf
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million cubic feet
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mmcf/d
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million cubic feet per day
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MWh
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megawatt hour
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NGLs
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natural gas liquids
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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.
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PRRT
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Petroleum Resource Rent Tax, a profit based tax levied on petroleum
projects in Australia
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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
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WTI
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West Texas Intermediate, the reference price paid for crude oil of
standard grade in US dollars at Cushing, Oklahoma
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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.
Lorenzo Donadeo, CEO; Anthony Marino, President & COO; Curtis W. Hicks, C.A., Executive VP & CFO; and/or Dean Morrison, Director Investor Relations TEL (403) 269-4884 IR TOLL FREE 1-866-895-8101 investor_relations@vermilionenergy.com www.vermilionenergy.com Copyright CNW Group 2015
Source: Canada Newswire
(November 9, 2015 - 2:10 AM EST)
News by QuoteMedia
www.quotemedia.com
|