CALGARY, Feb. 29, 2016 /PRNewswire/ - Vermilion Energy
Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE:
VET) is pleased to report operating and audited financial results
for the year ended December 31,
2015.
HIGHLIGHTS
- Vermilion's annual production
volumes increased by 11% in 2015 to 54,922 boe/d. This strong
production performance was achieved despite a nearly 4,000 boe/d
shortfall in anticipated Corrib volumes associated with regulatory
delays and a 30% decrease in exploration and development
("E&D") capital spending as compared to the prior year.
- Production volumes for Q4 2015 increased by 8% as compared to
the prior quarter to a record 61,058 boe/d. Each of
Vermilion's business units
increased production, with the most significant increases driven by
drilling successes in Canada,
Australia and the Netherlands.
- Fund flows from operations in 2015 was $516.2 million ($4.71/basic share(1)) as compared to
$804.9 million ($7.63/basic share) in 2014. Higher
production in 2015 partially offset the impact of a 48% decrease in
oil prices. Q4 2015 fund flows from operations of
$136.4 million ($1.22/basic share) was higher than the
$129.4 million ($1.17/basic share) in Q3 2015 as a result of
higher production volumes, realized hedging gains and lower taxes,
partially offset by lower commodity pricing.
- Subsequent to the end of the year, we released a $285 million E&D capital budget for 2016 that
represented a decrease in spending of over 40% from 2015 levels and
a decrease of nearly 60% from 2014 levels. Since that
time, we have further reduced our E&D budget by another
$50 million in response to still
lower commodity prices. Our new E&D capital budget for
2016 is $235 million, with the
flexibility to restore certain projects if commodity prices
improve. We still expect to deliver nearly 15% production
growth year-over-year with only a modest impact expected in 2016
from this further reduction in capital.
- Following the receipt of final regulatory approval, first gas
production started at our Corrib project in Ireland on December 30,
2015. Corrib is expected to provide significant
high-margin production growth and generate meaningful free cash
flow(1) in 2016. To date, production has been
in-line with forecasts, with well deliverability better than our
expectations. Production levels at Corrib are expected to rise over
a period of approximately six months to an estimated peak rate of
58 mmcf/d (9,700 boe/d), net to Vermilion.
- Total proved ("1P") reserves increased 6% to
160.7(2) mmboe, while total proved plus probable ("2P")
reserves also increased 6% to 260.9(2) mmboe. This
represents year-over-year 1P and 2P per share reserves growth of 2%
and 1%, respectively.
- Finding and Development ("F&D")(3) and Finding,
Development and Acquisition ("FD&A")(3) costs,
including Future Development Capital ("FDC")(3) for 2015
on a 2P basis decreased 48% to $8.98/boe and 55% to $10.03/boe, respectively. Similarly, our
three-year F&D and FD&A, including FDC, on a 2P basis were
$14.82/boe and $17.81/boe, respectively.
- Recycle ratio(5) (including FDC) was 3.6x during
2015, an increase over 3.2x achieved during 2014, indicating that
we were able to not only maintain but improve our high level of
investment efficiency in 2015 despite the decline in commodity
prices. We increased Proved Developed Producing reserves (net of
production) by 25% at an average F&D cost (including FDC) of
$10.67/boe generating a recycle ratio
(including FDC) of 3.0x.
- Our independent GLJ 2015 Resource Assessment(4)
indicates low, best, and high estimates for contingent resources in
the Development Pending category are 95.1 mmboe, 160.7 mmboe, and
254.7 mmboe, respectively. Approximately 80% of our best
estimate contingent resources evaluated reside in the Development
Pending category, reflecting the high quality nature of our
contingent resource base.
- In Q4 2015 we drilled and completed a horizontal sidetrack well
at the Wandoo A platform in Australia. The well was successfully
brought on production in mid-November. We produced the well
through December 31, 2015 at an
average rate of approximately 3,900 boe/d.
- The Diever-02 exploration well in the
Netherlands (45% working interest), drilled in 2014, came on
production at the end of October 2015
at a gross rate of 28.5 mmcf/d (4,750 boe/d). Our net
incremental production increase from this well is presently limited
to approximately 6 mmcf/d (1,000 boe/d) due to current pipeline
constraints in the multi-well system that Diever-02 produces
into.
- We continued to make progress in mitigating the impact of
third-party plant capacity and transportation restrictions on our
Canadian production volumes. At the end of Q4, approximately
1,600 boe/d remained shut-in, pending capacity availability.
- Vermilion was recently awarded
two additional exploration licenses in Germany, adding approximately 110,000 net
acres to our land position.
- We continued to prioritize preserving the strength of our
balance sheet through our Profitability Enhancement Program ("PEP")
initiative. Associated cost savings related to capital
spending, operating expense and G&A expenditures reached nearly
$90 million for full-year 2015.
(1) |
Non-GAAP Financial Measure. Please see the "Non-GAAP
Financial Measures" section of Management's Discussion and
Analysis. |
(2) |
Estimated proved and proved plus probable reserves attributable
to the assets as evaluated by GLJ Petroleum Consultants Ltd.
("GLJ") in a report dated February 8, 2016 with an effective date
of December 31, 2015 (the "2015 GLJ Reserves Evaluation") |
(3) |
F&D (finding and development) and FD&A (finding,
development and acquisition) costs are used as a measure of capital
efficiency and are calculated by dividing the applicable capital
costs for the period, including the change in undiscounted future
development capital ("FDC"), by the change in the reserves,
incorporating revisions and production, for the same period. |
(4) |
Vermilion retained GLJ to conduct an independent resource
evaluation dated February 8, 2016 to assess contingent resources
across all of the Company's key operating regions with an effective
date of December 31, 2015 (the "GLJ 2015 Resource
Assessment"). The associated chance of development for each
of the low, best, and high estimate for contingent resources in the
Development Pending category are 83%, 82%, and 81%, respectively.
There is uncertainty that it will be commercially viable to produce
any portion of the resources. |
(5) |
Recycle ratio is Operating Netback divided by F&D
(including FDC) |
ORGANIZATIONAL UPDATE
As announced on November
30, 2015, Mr. Lorenzo Donadeo
will be retiring as Chief Executive Officer ("CEO"), effective
March 1, 2016, at which time he will
become Chair of the Board of Directors. Mr. Anthony Marino, currently President and Chief
Operating Officer ("COO"), will assume the role of President and
CEO. Mr. Larry Macdonald, the
Board of Director's current Chair, will transition to the newly
created role of Lead Independent Director.
Concurrent with those changes, Vermilion is pleased to announce the
appointments of Mr. Michael Kaluza
to the position of Executive Vice President and COO, and Mr.
Dion Hatcher to the position of Vice
President of our Canadian Business Unit.
Mr. Kaluza joined Vermilion in February
2013 as Director of our Canadian Business Unit, and was
promoted to Vice President of our Canadian Business Unit in
May 2014. Mr. Kaluza has over
30 years of operations and executive management experience, and has
a Bachelor of Science in Petroleum Engineering (Honors) from the
Montana College of Mineral,
Science and Technology.
Mr. Hatcher joined Vermilion in 2006 and has over 18 years of
industry experience focused on operations engineering and project
management. He has a Bachelor of Science in Mechanical Engineering
(Honors) from Memorial University of
Newfoundland.
Conference Call and Audio Webcast Details
Vermilion will
discuss these results in a conference call to be held on
Monday, February 29, 2016 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 21667130. The replay will be available
until midnight mountain time on
March 7, 2016.
You may also listen to the audio webcast by clicking
http://event.on24.com/r.htm?e=1117164&s=1&k=1F2188A24FF5A3DA8F83BE1F0C213F7B
or visit Vermilion's website at
www.vermilionenergy.com/ir/eventspresentations.cfm.
HIGHLIGHTS |
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Three
Months Ended |
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Year Ended |
($M except as indicated) |
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Dec 31, |
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Sep 30, |
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Dec 31, |
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Dec 31, |
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Dec 31, |
Financial |
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2015 |
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2015 |
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2014 |
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2015 |
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2014 |
Petroleum and natural gas sales |
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234,319 |
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245,051 |
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306,073 |
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939,586 |
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1,419,628 |
Fund flows from operations |
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136,441 |
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129,435 |
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185,528 |
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516,167 |
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804,865 |
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Fund flows from operations ($/basic share)
(1) |
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1.22 |
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1.17 |
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1.73 |
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4.71 |
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7.63 |
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Fund flows from operations ($/diluted share)
(1) |
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1.21 |
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1.16 |
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1.71 |
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4.65 |
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7.51 |
Net earnings (loss) |
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(142,080) |
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(83,310) |
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58,642 |
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(217,302) |
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269,326 |
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Net earnings (loss) ($/basic share) |
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(1.28) |
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(0.76) |
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0.55 |
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(1.98) |
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2.55 |
Capital expenditures |
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128,996 |
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93,381 |
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166,243 |
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486,861 |
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687,724 |
Acquisitions |
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6,227 |
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22,155 |
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1,652 |
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28,897 |
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601,865 |
Asset retirement obligations
settled |
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4,921 |
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2,123 |
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6,247 |
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11,369 |
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15,956 |
Cash dividends ($/share) |
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0.645 |
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0.645 |
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0.645 |
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2.580 |
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2.580 |
Dividends declared |
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71,965 |
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71,244 |
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69,119 |
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283,575 |
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272,732 |
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% of fund flows from operations |
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53% |
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55% |
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37% |
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55% |
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34% |
Net dividends (1) |
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25,201 |
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26,654 |
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48,139 |
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128,542 |
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193,302 |
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% of fund flows from operations |
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18% |
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21% |
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26% |
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25% |
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24% |
Payout (1) |
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159,118 |
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122,158 |
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220,629 |
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626,772 |
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896,982 |
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% of fund flows from operations |
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117% |
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94% |
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119% |
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121% |
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111% |
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% of fund flows from operations (excluding the
Corrib project) (1) |
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106% |
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77% |
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106% |
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107% |
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99% |
Net debt |
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1,381,951 |
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1,363,043 |
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1,265,650 |
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1,381,951 |
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1,265,650 |
Ratio of net debt to annualized fund
flows from operations |
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2.5 |
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2.6 |
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1.7 |
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2.7 |
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1.6 |
Operational |
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Production |
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Crude oil (bbls/d) |
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28,745 |
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28,164 |
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28,846 |
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28,502 |
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28,879 |
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NGLs (bbls/d) |
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5,298 |
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4,622 |
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2,822 |
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4,214 |
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2,553 |
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Natural gas (mmcf/d) |
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162.09 |
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140.97 |
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107.42 |
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133.24 |
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108.85 |
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Total (boe/d) |
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61,058 |
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56,280 |
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49,571 |
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54,922 |
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49,573 |
Average realized prices |
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Crude oil and NGLs ($/bbl) |
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51.64 |
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56.57 |
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78.64 |
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58.80 |
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100.06 |
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Natural gas ($/mcf) |
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4.55 |
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5.36 |
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5.90 |
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4.98 |
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6.42 |
Production mix (% of production) |
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% priced with reference to WTI |
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21% |
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24% |
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28% |
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25% |
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28% |
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% priced with reference to AECO |
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24% |
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22% |
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20% |
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22% |
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18% |
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% priced with reference to TTF |
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20% |
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20% |
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16% |
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19% |
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18% |
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% priced with reference to Dated Brent |
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35% |
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34% |
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36% |
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34% |
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36% |
Netbacks ($/boe) |
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Operating netback |
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28.44 |
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32.25 |
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45.85 |
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32.09 |
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55.50 |
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Fund flows from operations netback |
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23.91 |
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24.58 |
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38.67 |
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25.86 |
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44.09 |
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Operating expenses |
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11.50 |
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10.99 |
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12.48 |
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11.32 |
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12.72 |
Average reference prices |
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WTI (US $/bbl) |
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42.18 |
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46.43 |
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73.15 |
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48.80 |
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93.00 |
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Edmonton Sweet index (US $/bbl) |
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39.72 |
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43.01 |
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66.79 |
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44.91 |
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85.83 |
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Dated Brent (US $/bbl) |
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43.69 |
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50.26 |
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76.27 |
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52.46 |
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98.99 |
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AECO ($/mmbtu) |
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2.46 |
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2.90 |
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3.60 |
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2.69 |
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4.50 |
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TTF ($/mmbtu) |
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7.28 |
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8.48 |
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9.16 |
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8.23 |
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8.96 |
Average foreign currency exchange
rates |
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CDN $/US $ |
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1.34 |
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1.31 |
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1.14 |
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1.28 |
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1.10 |
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CDN $/Euro |
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1.46 |
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1.46 |
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1.42 |
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1.42 |
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1.47 |
Share information
('000s) |
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Shares outstanding - basic |
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111,991 |
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110,818 |
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107,303 |
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111,991 |
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107,303 |
Shares outstanding - diluted
(1) |
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115,025 |
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113,643 |
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110,334 |
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115,025 |
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110,334 |
Weighted average shares outstanding -
basic |
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111,393 |
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110,293 |
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107,102 |
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109,642 |
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105,448 |
Weighted average shares outstanding -
diluted (1) |
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112,543 |
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111,193 |
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108,646 |
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111,051 |
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107,187 |
(1) |
The above table includes non-GAAP financial measures which may
not be comparable to other companies. Please see the
"NON-GAAP FINANCIAL MEASURES" section of Management's Discussion
and Analysis. |
DISCLAIMER
Certain statements included or incorporated by
reference in this document may constitute forward looking
statements or financial outlooks under applicable securities
legislation. Such forward looking statements or information
typically contain statements with words such as "anticipate",
"believe", "expect", "plan", "intend", "estimate", "propose", or
similar words suggesting future outcomes or statements regarding an
outlook. Forward looking statements or information in this
document may include, but are not limited to: capital expenditures;
business strategies and objectives; operational and financial
performance; estimated reserve quantities and the discounted net
present value of future net revenue 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; 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; and the timing of
regulatory proceedings and approvals.
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 and the Canadian Oil
and Gas Evaluation Handbook. The actual crude oil and
natural gas reserves and future production will be greater than or
less than the estimates provided in this document. The
estimated future net revenue from the production of crude oil and
natural gas reserves does not represent the fair market value of
these reserves.
Natural gas volumes have been converted on the
basis of six thousand cubic feet of natural gas to one barrel of
oil equivalent. Barrels of oil equivalent (boe) may be
misleading, particularly if used in isolation. A boe
conversion ratio of six thousand cubic feet to one barrel of oil is
based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value
equivalency at the wellhead.
Financial data contained within this document are reported in
Canadian dollars, unless otherwise stated.
ABBREVIATIONS
$M |
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thousand dollars |
$MM |
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million dollars |
AECO |
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the daily average benchmark price for natural gas at the AECO
'C' hub in southeast Alberta |
bbl(s) |
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barrel(s) |
bbls/d |
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barrels per day |
bcf |
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billion cubic feet |
boe |
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barrel of oil equivalent, including: crude oil, natural gas
liquids and natural gas (converted on the basis of one boe for six
mcf of natural gas) |
boe/d |
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barrel of oil equivalent per day |
btu |
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British thermal units |
GJ |
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gigajoules |
HH |
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Henry Hub, a reference price paid for natural gas in US dollars
at Erath, Louisiana |
mbbls |
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thousand barrels |
mboe |
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thousand barrel of oil equivalent |
mcf |
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thousand cubic feet |
mcf/d |
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thousand cubic feet per day |
mmboe |
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million barrel of oil equivalent |
mmbtu |
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million British thermal units |
mmcf |
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million cubic feet |
mmcf/d |
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million cubic feet per day |
MWh |
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megawatt hour |
NBP |
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the reference price paid for natural gas in the United Kingdom,
quoted in pence per therm, at the National Balancing Point Virtual
Trading Point operated by National Grid. Our production in Ireland
is priced with reference to NBP. |
NGLs |
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natural gas liquids |
PRRT |
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Petroleum Resource Rent Tax, a profit based tax levied on
petroleum projects in Australia |
TTF |
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the day-ahead price for natural gas in the Netherlands, quoted
in MWh of natural gas, at the Title Transfer Facility Virtual
Trading Point operated by Dutch TSO Gas Transport Services |
WTI |
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West Texas Intermediate, the reference price paid for crude oil
of standard grade in US dollars at Cushing, Oklahoma |
CGU |
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Cash generating unit, the basis upon which Vermilions assets
are evaluated for potential impairments |
DRIP |
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Dividend Reinvestment Plan |
MESSAGE TO SHAREHOLDERS
Commodity price volatility continued unabated
through 2015, and it does not appear that 2016 will provide any
immediate relief. Although the current economic environment
poses significant challenges for all industry participants,
including Vermilion, we believe
that continued adherence to our long-term strategy will enable us
to emerge from this price cycle stronger than ever.
Our long-term strategy is focused on three main
priorities, presented in order of importance:
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1) |
Preserving the strength of our balance sheet; |
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2) |
Protecting our dividend; and |
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3) |
Investing to fund production growth. |
Preserving the Strength of Our Balance Sheet
We have always been highly disciplined in the
management of our balance sheet, historically maintaining leverage
ratios that are significantly more conservative than most of our
peers. This has allowed us to effectively manage through
prior low commodity price environments. We entered the current
commodity downturn in a position of relative financial strength,
and we took a number of purposeful actions throughout 2015 to
preserve our balance sheet.
We have significantly reduced capital investment
to support our sustainability in this price environment. Our
2016 E&D budget is now $235
million, representing a decrease of over 50% from 2015
levels and a decrease of more than 65% from 2014 levels. Our
intent is to balance cash outlays in 2016 for net dividends and
E&D capital investment with our fund flows from operations.
During 2015 we increased our credit facility
capacity by $500 million to $2.0
billion and extended the term to May
2019, providing additional financial certainty. At
year-end 2015, we had $837 million of
undrawn capacity which allowed us to retire the $225 million of 6.5% Senior Unsecured Notes that
came due on February 10, 2016 with
funds from the credit facility. While we are continuing to
assess opportunities to diversify our debt structure, our credit
facility is currently our most cost-effective method of
borrowing.
In early 2015 we amended our existing Dividend
Reinvestment Plan ("DRIP") to include a Premium Dividend™
Component. The Premium Dividend™ Component, when combined
with our legacy Dividend Reinvestment Plan, significantly expands
our access to the lowest cost source of equity capital
available. The program can be suspended or prorated at our
discretion, offering considerable flexibility. We view the
implementation of the Premium Dividend™ as a short-term measure and
we will actively monitor our ongoing needs and manage our continued
use of each component as circumstances dictate. In the event
of a commodity price recovery, it is our intent to reduce, and
ultimately eliminate, the Premium Dividend™ Component.
We have hedged a meaningful component of our
natural gas production, particularly European natural gas, which
remains a significantly stronger market than North American natural
gas. At present, we have 25% of our total 2016 net-of-royalty
production hedged, including 44% of our anticipated natural gas
volumes.
Protecting Our Dividend
We have never reduced our dividend since it was
initiated in 2003. We are constantly monitoring both our
dividend and accompanying capital program, taking into
consideration prevailing and expected commodity prices and equity
issued under our DRIP program. Although this commodity
downturn has been more pronounced than we anticipated when it began
in mid-2014, we believe that our existing dividend remains
manageable with the actions we have taken to date. We remain
committed to first prioritizing our balance sheet and preserving
our financial flexibility. To safeguard our long-term
sustainability, we are managing our business based on the current
commodity price strip, with the objective that our funds from
operations will approximately balance or exceed our cash outflows
for net dividends and capital expenditures. Should commodity
conditions arise under which we can no longer expect to balance
outflows and inflows over longer periods of time, we would protect
our balance sheet through further modifications of our capital
investment and dividend programs.
Investing to Fund Production Growth
We believe our inventory of organic growth
projects is strong and each of our business units is capable of
delivering production growth. The diversity of our asset base
and commodity and currency exposures allows us to select and fund
projects that will generate the highest return in a given economic
environment. This advantage is even more pronounced in a low
commodity price environment in which available capital funding is
highly restricted. Our improved recycle ratio at year-end
2015, despite lower commodity prices, is indicative of the
improvement of our project inventory and execution over the past
few years.
With the start-up of production at Corrib in
Ireland in late 2015, we are
positioned to provide strong per share production growth of
approximately 10% for our shareholders in 2016. We expect
Corrib to meaningfully contribute to production growth in 2017 as
well, with a full year of production following the ramp-up to peak
rates during the first half of 2016. With production
commencing at Corrib plus the improvement in capital efficiencies
in our other business units, we have been able to significantly
reduce our planned capital investment program to preserve the
strength of our balance sheet and protect our dividend. These
structural advantages in our production profile position
Vermilion to achieve all three
priorities outlined above despite the commodity downturn. At
such time as commodity market fundamentals warrant additional
capital investment, we have the project inventory to provide
long-term organic production growth.
2015 Review
We delivered 11% year-over-year production
growth, despite a nearly 4,000 boe/d shortfall in anticipated
Corrib volumes associated with regulatory delays. We believe
that this accomplishment demonstrates the depth of our operational
and project capacity. In addition, despite the prevailing
commodity price environment, we continued to deliver extremely
strong performance across all segments of our business, achieving a
number of important milestones.
Europe
Following the receipt of final regulatory
approval, first gas production started at Corrib on December 30, 2015. Corrib is expected to
provide significant high-margin production growth and generate
meaningful free cash flow(1) in 2016 - unique attributes
in our industry in the current price environment. To date,
Corrib has been producing in-line with expectations, with well
deliverability better than anticipated and no significant downtime
events. Production initially started with one well before year-end,
and a second well was brought on-line in early January 2016. Current production levels are
approximately 33 mmcf/d (5,500 boe/d) net to Vermilion. 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.
In France, we
completed a successful four (4.0 net) well drilling program at
Champotran during Q1 2015. This was our third successive drilling
campaign at Champotran since 2013. We have achieved 100%
drilling success across a cumulative 13 wells during that
period. Incorporating the impact of our waterflood program,
our 2015 drilling program delivered incremental exit production of
approximately 1,000 boe/d. Our other activities in
France during the year centered
around workovers and optimization projects, as well as
infrastructure and facility maintenance. In 2016, we intend
to continue with workover and optimization activities in
France.
In the
Netherlands, we drilled two (1.9 net) wells during Q2 2015
on the Slootdorp concession in the province of North Holland. Both wells were successful and
encountered more natural gas pay than expected. The wells are
currently on sales during an extended production test to size
permanent production equipment and are currently producing at a
facility-restricted combined rate of 25.8 mmcf/d (4,300 boe/d) net
to Vermilion. The Diever-02
exploration well (45% working interest), drilled in 2014, came on
production in late October 2015 for
an extended production test and continues to produce at a gross
rate of 28.5 mmcf/d (4,750 boe/d). Our net incremental production
increase from this well is presently limited to approximately 6
mmcf/d (1,000 boe/d) due to current pipeline constraints in the
multi-well system that Diever-02 produces into. Activity in
the Netherlands during 2016 will
focus on permitting and the optimization of existing assets.
In Germany, our
partner ExxonMobil Production Deutschland GmbH drilled and
completed the Burgmoor Z3a well (25% net interest to Vermilion) in the first half of 2015, which
began producing at a sales gas rate of approximately 1.7 mmcf/d
(280 boe/d) net to Vermilion. In July 2015, we entered into a farm-in agreement
that provides us with participating interest in 19 onshore
exploration licenses in northwest Germany and associated proprietary data.
The licenses comprise approximately 850,000 net acres of
undeveloped oil and natural gas rights in the prolific North German
Basin. More recently, we were awarded two additional
exploration licenses in Germany
adding approximately 110,000 net acres to our land position.
Further bolstering our presence in the country, we have taken over
the drilling operatorship for the Burgmoor Z5 well in our
Dumersee-Uchte producing concession, which is scheduled to be
drilled in 2017. The majority of our capital in 2016 will be
directed to permitting and pre-drill activities for Burgmoor Z5 and
two exploration prospects. In addition, we will continue our
ongoing analysis of the geologic and geophysical data acquired with
the farm-in assets.
North America
During 2015, we drilled or participated in nine
(3.4 net) Cardium wells, 28 (18.5 net) Mannville wells, and five (4.1 net)
Midale wells. Overall
activity levels in Canada were
significantly lower than in prior years as a result of reduced
capital availability. Nevertheless, we achieved a number of
successes in our Mannville
play. One such success was the drilling of a two-mile well
that targeted the Notikewin formation and came on production at an
infrastructure limited rate of approximately 14 mmcf/d (2,300
boe/d). The productive capability demonstrated by this well
ranks it among the top natural gas wells currently producing in
Alberta.
In Q2 2015, we completed an infrastructure
project that included the expansion of a compressor station as well
as the construction of a 22 km pipeline. This infrastructure
will play a critical role in supporting the continued growth of our
Mannville play over the next few
years.
Throughout 2015, we made significant progress in
addressing the impact of third-party plant capacity and
transportation restrictions on our production volumes. At the
end of December, total volumes impacted by capacity issues had been
reduced to 1,600 boe/d.
Canadian drilling activities in 2016 will be
limited to operated expiry wells and capital commitments on
non-operated wells.
In the United
States, we completed and began testing one (1 net)
Turner Shurley Sand well in the
eastern Powder River Basin of
Wyoming in Q3 2015. During the
year, we consolidated our ownership of this project area to 100%
working interest through the acquisition of the remaining 30%
interest. We also drilled two additional wells in Q4 2015
which will be completed and tied-in in 2016. We intend to
drill one (1.0 net) additional expiry well in 2016. We expect
to increase our investment in this play when commodity prices
improve.
Australia
In Q4 2015 we completed and placed on production
the horizontal sidetrack well that was drilled at the Wandoo A
platform. Well performance has been strong at approximately
3,900 boe/d over the last six weeks of 2015. Following this
success, we are planning a two-well drilling program in
Australia for 2016. Offshore
drilling in Australia requires a
great deal of advance contracting and logistical planning, which
means that full-cycle costs are minimized by proceeding with this
program in 2016 despite current oil price weakness.
Furthermore, we expect service costs to be near their lows in 2016
at the time of drilling, making this a desirable time to drill
these high-quality sidetrack locations.
External Recognition
Vermilion's
Board of Directors was recently recognized as a TopGun Board in
Canada for 2015/2016 by Brendan
Wood International ("BWI") reflecting the high degree of confidence
major institutional investors have in Vermilion's Board. The voting panel,
which was comprised of over 500 institutional investors and
sell-side professionals considered a short-list of 323 potential
companies and awarded TopGun status to only 27 companies, less than
10% of those nominated.
Lorenzo Donadeo,
Chief Executive Officer and Curtis W.
Hicks, Executive Vice President and Chief Financial Officer
were also recognized in BWI's Shareholder Confidence survey as a
Top Gun CEO and CFO, respectively, reflecting continuing
institutional investor confidence in Vermilion's strategic execution, financial
practices and investor communications.
During Q4 2015, we were 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. We
have 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.
As previously announced, we have been recognized
by the Great Place to Work® Institute as a Best Workplace in
Canada and France for a sixth consecutive year. We
were also recognized for a second consecutive year as a Best
Workplace in the Netherlands in
2015, after becoming eligible for ranking in 2014. We are the
only energy company in our category to rank on the Best Workplaces
lists in Canada and the Netherlands, and the highest scoring
energy company on the Best Workplaces list in France.
During 2015, we were ranked 15th by Corporate
Knights on the Future 40 Responsible Corporate Leaders in
Canada list (the highest ranking
for an oil and gas company, and improved from our debut ranking of
32nd last year). We were also named Top International
Producer of the year by the Explorers and Producers Association of
Canada. This recognition
reflects our continued focus on achieving robust shareholder
returns combined with environmental, social and governance
performance.
Outlook
This is an extraordinarily challenging time for
the energy industry. The commodity downturn was largely
unexpected, has been breathtaking in its depth and breadth and will
leave an impact on the industry that will be felt for years to
come. At Vermilion, we are committed to maintaining our focus
on delivering a capital markets model that benefits our
shareholders over the long-term. We believe that our
diversified asset portfolio and operational capabilities position
us to protect our balance sheet, defend our dividend, and continue
long-term growth. Our management and directors hold
approximately 6% of the outstanding shares of Vermilion, ensuring
alignment of interests with our shareholders. We look forward
to meeting the current challenges, and believe that this business
environment will illustrate the differentiating benefits of our
global operating, capital markets and cultural model.
CEO Succession
As announced in November
2015, I will be retiring as CEO on March 1, 2016 at which time I will become Chair
of the Board of Directors. Since co-founding Vermilion some 22 years ago, we have had
great success and it has been an exciting and personally rewarding
experience. I want to thank our staff, our executive team, our
Board of Directors and our shareholders for their contributions and
support over the years. I look forward to working with
Anthony Marino as our new CEO, the
executive team, and the Board of Directors in taking Vermilion to new and exciting heights.
(1) |
The above discussion includes non-GAAP measures which may not
be comparable to other companies. Please see the "NON-GAAP
FINANCIAL MEASURES" section of Management's Discussion and
Analysis. |
(2) |
Corrib P2 well produces from the Sherwood sandstones. The
production test was performed over a 12-hour period at a maximum
choke of 80/64", achieving a peak production rate of 113 mmcf/d and
a stabilized flow rate of 107 mmcf/d with approximately 30%
drawdown over the test period. This test result is not
necessarily indicative of long-term performance or of ultimate
recovery. |
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is Management's Discussion and
Analysis ("MD&A"), dated February 25,
2016, of Vermilion Energy Inc.'s ("Vermilion", "we", "our",
"us" or the "Company") operating and financial results as at and
for the three months and year ended December
31, 2015 compared with the corresponding periods in the
prior year.
This discussion should be read in conjunction
with the audited consolidated financial statements for the year
ended December 31, 2015 and 2014,
together with the accompanying notes. Additional information
relating to Vermilion, including
its Annual Information Form, will be available on or after
March 4, 2016 on SEDAR at
www.sedar.com or on Vermilion's
website at www.vermilionenergy.com.
The audited consolidated financial statements
for the year ended December 31, 2015
and comparative information have been prepared in Canadian dollars,
except where another currency has been indicated, and in accordance
with International Financial Reporting Standards ("IFRS" or,
alternatively, "GAAP") as issued by the International Accounting
Standards Board.
This MD&A includes references to certain
financial measures which do not have standardized meanings
prescribed by IFRS. These financial measures include:
- Fund flows from operations: This 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 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.
In addition, this MD&A includes references
to certain financial measures which do not have standardized
meanings prescribed by IFRS and are not disclosed in our audited
financial statements. As such, these financial measures are
considered non-GAAP financial measures and therefore are unlikely
to be comparable with similar financial measures presented by other
issuers. For a full description of these non-GAAP financial
measures and a reconciliation of these measures to their most
directly comparable GAAP measures, please refer to "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.
2015 REVIEW AND 2016 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 maintained 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. Actual 2015 capital spending
of $486.9 million was within 1% of
guidance. Production for 2015 proved to be within 0.1% of the
guidance range.
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. On
January 5, 2016, in response to the
continued weakness in commodity prices we adjusted our 2016 capital
expenditure guidance to $285 million
with corresponding production guidance of 62,500-63,500
boe/d. On February 29, 2016, we
further revised our 2016 capital expenditure guidance to
$235 million as a result of continued
commodity price deterioration. We maintained our production
guidance of 62,500-63,500 boe/d. The February 29, 2016 reduction primarily reflects
lower expected non-operated drilling activity in Canada, fewer workovers in France, and a deferral of our Netherlands drilling and pipeline twinning
programs.
The following table summarizes our 2015 and 2016
guidance:
|
|
|
|
Date |
|
|
|
|
|
Capital Expenditures
($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 |
2016 Guidance |
|
|
|
January 5, 2016 |
|
|
|
|
|
285 |
|
|
|
|
|
62,500 to 63,500 |
2016 Guidance |
|
|
|
February 29, 2016 |
|
|
|
|
|
235 |
|
|
|
|
|
62,500 to 63,500 |
SHAREHOLDER RETURN
Vermilion
strives to provide investors with reliable and growing dividends in
addition to sustainable, global production growth. The
following table, as of December 31,
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 |
|
|
|
$7.56 |
|
|
|
$12.12 |
Capital appreciation per Vermilion share |
|
|
|
($19.39) |
|
|
|
($14.36) |
|
|
|
($8.61) |
Total return per Vermilion share |
|
|
|
(29.5%) |
|
|
|
(13.1%) |
|
|
|
7.6% |
Annualized total return per Vermilion share |
|
|
|
(29.5%) |
|
|
|
(4.6%) |
|
|
|
1.5% |
Annualized total return on the
S&P TSX High Income Energy Index |
|
|
|
(31.2%) |
|
|
|
(13.1%) |
|
|
|
(8.5%) |
(1) |
The above table includes non-GAAP financial measures which may
not be comparable to other companies. Please see the
"NON-GAAP FINANCIAL MEASURES" section of this MD&A. |
CONSOLIDATED RESULTS OVERVIEW
|
|
Three
Months Ended |
|
%
change |
|
Year
Ended |
|
%
change |
|
|
Dec 31, |
|
Sep 30, |
|
Dec 31, |
|
Q4/15 vs. |
|
Q4/15 vs. |
|
Dec 31, |
|
Dec 31, |
|
2015 vs. |
|
|
2015 |
|
2015 |
|
2014 |
|
Q3/15 |
|
Q4/14 |
|
2015 |
|
2014 |
|
2014 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
28,745 |
|
28,164 |
|
28,846 |
|
2% |
|
- |
|
28,502 |
|
28,879 |
|
(1%) |
|
NGLs (bbls/d) |
|
5,298 |
|
4,622 |
|
2,822 |
|
15% |
|
88% |
|
4,214 |
|
2,553 |
|
65% |
|
Natural gas (mmcf/d) |
|
162.09 |
|
140.97 |
|
107.42 |
|
15% |
|
51% |
|
133.24 |
|
108.85 |
|
22% |
|
Total (boe/d) |
|
61,058 |
|
56,280 |
|
49,571 |
|
8% |
|
23% |
|
54,922 |
|
49,573 |
|
11% |
|
Build (draw) in inventory (mbbl) |
|
(93) |
|
(85) |
|
(238) |
|
|
|
|
|
84 |
|
(165) |
|
|
Financial metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fund flows from operations ($M) |
|
136,441 |
|
129,435 |
|
185,528 |
|
5% |
|
(26%) |
|
516,167 |
|
804,865 |
|
(36%) |
|
Per share ($/basic share) |
|
1.22 |
|
1.17 |
|
1.73 |
|
4% |
|
(29%) |
|
4.71 |
|
7.63 |
|
(38%) |
|
Net earnings (loss) |
|
(142,080) |
|
(83,310) |
|
58,642 |
|
71% |
|
(342%) |
|
(217,302) |
|
269,326 |
|
(181%) |
|
Per share ($/basic share) |
|
(1.28) |
|
(0.76) |
|
0.55 |
|
68% |
|
(333%) |
|
(1.98) |
|
2.55 |
|
(178%) |
|
Cash flows from operating activities ($M) |
|
164,863 |
|
122,230 |
|
229,146 |
|
35% |
|
(28%) |
|
444,408 |
|
791,986 |
|
(44%) |
|
Net debt ($M) |
|
1,381,951 |
|
1,363,043 |
|
1,265,650 |
|
1% |
|
9% |
|
1,381,951 |
|
1,265,650 |
|
9% |
|
Cash dividends ($/share) |
|
0.645 |
|
0.645 |
|
0.645 |
|
- |
|
- |
|
2.580 |
|
2.580 |
|
- |
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
|
128,996 |
|
93,381 |
|
166,243 |
|
38% |
|
(22%) |
|
486,861 |
|
687,724 |
|
(29%) |
|
Acquisitions ($M) |
|
6,227 |
|
22,155 |
|
1,652 |
|
(72%) |
|
277% |
|
28,897 |
|
601,865 |
|
(95%) |
|
Gross wells drilled |
|
8.00 |
|
11.00 |
|
26.00 |
|
|
|
|
|
53.00 |
|
89.00 |
|
|
|
Net wells drilled |
|
5.56 |
|
6.91 |
|
16.58 |
|
|
|
|
|
36.12 |
|
62.43 |
|
|
Operational review
- Recorded consolidated average production of 61,058 boe/d in Q4
2015, which was an 8% increase over Q3 2015. This
quarter-over-quarter increase was the result of production growth
in all of our business units, including a 2,075 boe/d increase in
Canada, largely attributable to
growth in our Mannville
condensate-rich gas play, and a 1,391 boe/d increase from
Australia driven by our sidetrack
well drilled in Q4 2015.
- Increased consolidated average production for the three months
and year ended December 31, 2015 by
23% and 11%, respectively, versus the comparable periods in 2014,
primarily due to growth in Canada,
the Netherlands, and France.
- Activity during the quarter included capital expenditures
totalling $129.0 million, incurred
primarily in Australia,
Canada, and France. In Australia, capital expenditures totalling
$40.9 million related to the
horizontal sidetrack drilling program. In Canada, capital expenditures totalling
$27.6 million were 26% lower than the
$37.2 million incurred during Q3 2015
and related to the drilling of 2.6 net wells (6.9 net wells in Q3
2015). In France, capital
expenditures of $24.1 million were
39% higher than the $17.4 million
incurred in Q3 2015 and related primarily to facility maintenance,
accretive workovers, and subsurface activity.
Financial review
Net earnings (loss)
- The net loss for Q4 2015 was $142.1
million ($1.28/basic share) as
compared to a net loss of $83.3
million ($0.76/basic share) in
Q3 2015. The increase in the net loss was primarily
attributable to unfavourable foreign exchange variances and the
impact of a valuation allowance recorded on deferred tax
assets. The valuation allowance relates to certain
non-capital losses for which there is uncertainty as to the
Company's ability to fully utilize such losses when applying
forecasted commodity prices in effect as at December 31, 2015.
- The net loss for the three months and year ended December 31, 2015 represented decreases of
$200.7 million and $486.6 million, respectively, versus the
comparative periods in 2014. These decreases were driven
primarily by lower petroleum and natural gas sales as a result of
lower commodity prices, as well as impairment charges recognized in
Canada and a valuation allowance
recorded on deferred tax assets due to declines in commodity price
forecasts. The impacts of weakened commodity prices were
partially offset by significant production growth and global cost
reductions, including an 8% and 11% reduction in per unit operating
expense for the three months and year ended December 31, 2015, respectively. The year
ended December 31, 2015 was also
positively impacted by the recovery of $31.8
million (before taxes) recognized in Q1 2015 following a
judgment in favour 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
- Absent changes in working capital, cash flows from operating
activities increased by 3% quarter-over-quarter, despite
significantly lower commodity prices, due to production growth in
every business unit, coupled with increased realized gains from our
commodity hedges.
- Cash flows from operating activities decreased by 28% and 44%
for the three months and year ended December
31, 2015, respectively, versus the comparable periods in
2014. These decreases were primarily related to lower revenue due
to lower commodity prices, as well as timing differences pertaining
to working capital, partially offset by lower royalties and current
taxes.
Fund flows from operations
- Generated fund flows from operations of $136.4 million during Q4 2015, an increase of 5%
over Q3 2015. This quarter-over-quarter increase occurred despite
lower commodity pricing, driven primarily by production growth in
all business units, lower current taxes, and higher receipts from
commodity hedges.
- Fund flows from operations decreased by 26% and 36% for the
three months and year ended December 31,
2015, respectively, versus the comparable periods in 2014.
These decreases were primarily driven by lower crude oil pricing,
partially offset by higher sold volumes resulting from significant
production growth, global cost reductions, and favourable current
tax and royalty variances. The decrease in fund flows from
operations for the year ended December 31,
2015 was also partially offset by the previously mentioned
recovery of costs in France.
Net debt
- Net debt increased by $116.3
million to $1.38 billion for
the year ended December 31, 2015 due
to capital expenditures in Canada,
France, and Ireland, partially offset by fund flows from
operations.
Dividends
- Declared dividends of $0.215 per
common share per month during the fourth quarter of 2015, totalling
$2.58 per common share for the year
ended December 31, 2015.
COMMODITY PRICES
|
|
Three
Months Ended |
|
%
change |
|
Year
Ended |
|
% change |
|
|
Dec 31, |
|
|
Sep 30, |
|
|
Dec 31, |
|
Q4/15 vs. |
|
Q4/15 vs. |
|
Dec 31, |
|
|
Dec 31, |
|
2015 vs. |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
Q3/15 |
|
Q4/14 |
|
2015 |
|
|
2014 |
|
2014 |
Average reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl) |
|
42.18 |
|
|
46.43 |
|
|
73.15 |
|
(9%) |
|
(42%) |
|
48.80 |
|
|
93.00 |
|
(48%) |
|
Edmonton Sweet index (US $/bbl) |
|
39.72 |
|
|
43.01 |
|
|
66.79 |
|
(8%) |
|
(41%) |
|
44.91 |
|
|
85.83 |
|
(48%) |
|
Dated Brent (US $/bbl) |
|
43.69 |
|
|
50.26 |
|
|
76.27 |
|
(13%) |
|
(43%) |
|
52.46 |
|
|
98.99 |
|
(47%) |
Natural gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
AECO ($/mmbtu) |
|
2.46 |
|
|
2.90 |
|
|
3.60 |
|
(15%) |
|
(32%) |
|
2.69 |
|
|
4.50 |
|
(40%) |
|
TTF ($/mmbtu) |
|
7.28 |
|
|
8.48 |
|
|
9.16 |
|
(14%) |
|
(21%) |
|
8.23 |
|
|
8.96 |
|
(8%) |
|
TTF (€/mmbtu) |
|
4.98 |
|
|
5.82 |
|
|
6.46 |
|
(14%) |
|
(23%) |
|
5.80 |
|
|
6.11 |
|
(5%) |
|
NBP ($/mmbtu) |
|
7.41 |
|
|
8.40 |
|
|
9.52 |
|
(12%) |
|
(22%) |
|
8.33 |
|
|
9.10 |
|
(8%) |
|
NBP (€/mmbtu) |
|
5.07 |
|
|
5.77 |
|
|
6.71 |
|
(12%) |
|
(24%) |
|
5.87 |
|
|
6.20 |
|
(5%) |
|
Henry Hub ($/mmbtu) |
|
3.03 |
|
|
3.62 |
|
|
4.54 |
|
(16%) |
|
(33%) |
|
3.41 |
|
|
4.88 |
|
(30%) |
|
Henry Hub (US $/mmbtu) |
|
2.27 |
|
|
2.77 |
|
|
4.00 |
|
(18%) |
|
(43%) |
|
2.66 |
|
|
4.41 |
|
(40%) |
Average foreign currency
exchange
rates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CDN $/US $ |
|
1.34 |
|
|
1.31 |
|
|
1.14 |
|
2% |
|
18% |
|
1.28 |
|
|
1.10 |
|
16% |
CDN $/Euro |
|
1.46 |
|
|
1.46 |
|
|
1.42 |
|
- |
|
3% |
|
1.42 |
|
|
1.47 |
|
(3%) |
Average realized prices
($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
28.94 |
|
|
32.78 |
|
|
51.27 |
|
(12%) |
|
(44%) |
|
34.32 |
|
|
64.06 |
|
(46%) |
France |
|
54.20 |
|
|
60.96 |
|
|
79.25 |
|
(11%) |
|
(32%) |
|
62.67 |
|
|
105.43 |
|
(41%) |
Netherlands |
|
42.61 |
|
|
49.42 |
|
|
52.07 |
|
(14%) |
|
(18%) |
|
46.77 |
|
|
52.65 |
|
(11%) |
Germany |
|
39.68 |
|
|
44.36 |
|
|
49.19 |
|
(11%) |
|
(19%) |
|
43.10 |
|
|
46.03 |
|
(6%) |
Australia |
|
58.74 |
|
|
68.20 |
|
|
90.37 |
|
(14%) |
|
(35%) |
|
70.22 |
|
|
113.80 |
|
(38%) |
United States |
|
41.94 |
|
|
51.60 |
|
|
74.08 |
|
(19%) |
|
(43%) |
|
47.53 |
|
|
74.08 |
|
(36%) |
Consolidated |
|
41.04 |
|
|
46.56 |
|
|
63.79 |
|
(12%) |
|
(36%) |
|
47.07 |
|
|
77.75 |
|
(39%) |
Production mix (% of
production) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% priced with reference to WTI |
|
22% |
|
|
24% |
|
|
28% |
|
|
|
|
|
25% |
|
|
28% |
|
|
% priced with reference to AECO |
|
24% |
|
|
22% |
|
|
20% |
|
|
|
|
|
22% |
|
|
18% |
|
|
% priced with reference to TTF |
|
20% |
|
|
20% |
|
|
16% |
|
|
|
|
|
19% |
|
|
18% |
|
|
% priced with reference to Dated
Brent |
|
34% |
|
|
34% |
|
|
36% |
|
|
|
|
|
34% |
|
|
36% |
|
|
Reference prices
- Oil benchmarks faced strong headwinds throughout the fourth
quarter, causing both WTI and Dated Brent to average the quarter at
US $42.18/bbl and US $43.69/bbl respectively. Compared to the previous
quarter, WTI was down an additional 9% whereas Dated Brent averaged
13% lower versus the previous quarter. On a year-over-year
basis, WTI was down 48% and Dated Brent was down 47%.
- Crude oil prices set at Edmonton were less volatile during the fourth
quarter, but still tracked lower to average the quarter at US
$39.72/bbl, or 8% lower
quarter-over-quarter, and 41% lower year-over-year.
- AECO natural gas suffered a 15% quarter-over-quarter decline as
high levels of gas-in-storage, strong field receipts, and
below-normal demand weighed on the market. Averaging $2.46/mmbtu for the three months ending
December 31, 2015, AECO was down 32%
versus the same quarter in 2014.
- Despite having lower gas-in-storage, a mild start to winter and
the anticipation of increasing LNG supply reduced European natural
gas prices in Q4 2015, driving similar movements in TTF and NBP
reference prices. For the fourth quarter, TTF averaged $7.28/mmbtu, which was 14% lower versus the
previous quarter and 21% lower versus the same quarter in the prior
year. In Euro terms, TTF averaged the quarter at €4.98/mmbtu,
which was a 14% decrease versus Q3 2015, and 23% lower
year-over-year.
- Weakness in the price of oil and a rate hike by the US Federal
Reserve in December kept the Canadian dollar on its declining path
against the US dollar; however, a similar impact was felt by the
Euro versus the US dollar, causing CDN $/Euro to remain flat
quarter-over-quarter.
Realized prices
- Consolidated realized price decreased by 12% for Q4 2015 as
compared to Q3 2015. This decrease was primarily the result
of weakening crude oil and natural gas pricing.
- Consolidated realized price for the three months and year ended
December 31, 2015 decreased by 36%
and 39%, respectively, as compared to the comparable periods in
2014. These decreases were due to weakening commodity prices,
primarily driven by a weakening of crude oil and North American
natural gas prices, as well as changes in production mix, which
included increased relative NGL and natural gas volumes in
Canada.
FUND FLOWS FROM OPERATIONS
|
|
Three
Months Ended |
|
Year
Ended |
|
|
Dec 31, 2015 |
|
Sep 30, 2015 |
|
Dec 31, 2014 |
|
Dec 31, 2015 |
|
Dec 31, 2014 |
|
|
$M |
|
|
$/boe |
|
$M |
|
|
$/boe |
|
$M |
|
|
$/boe |
|
$M |
|
|
$/boe |
|
$M |
|
|
$/boe |
Petroleum and natural gas sales |
|
234,319 |
|
|
41.04 |
|
245,051 |
|
|
46.56 |
|
306,073 |
|
|
63.79 |
|
939,586 |
|
|
47.07 |
|
1,419,628 |
|
|
77.75 |
Royalties |
|
(16,285) |
|
|
(2.85) |
|
(17,100) |
|
|
(3.25) |
|
(25,963) |
|
|
(5.41) |
|
(65,920) |
|
|
(3.30) |
|
(108,000) |
|
|
(5.92) |
Petroleum and natural gas revenues |
|
218,034 |
|
|
38.19 |
|
227,951 |
|
|
43.31 |
|
280,110 |
|
|
58.38 |
|
873,666 |
|
|
43.77 |
|
1,311,628 |
|
|
71.83 |
Transportation expense |
|
(10,147) |
|
|
(1.78) |
|
(11,090) |
|
|
(2.11) |
|
(9,489) |
|
|
(1.98) |
|
(41,660) |
|
|
(2.09) |
|
(42,361) |
|
|
(2.32) |
Operating expense |
|
(65,645) |
|
|
(11.50) |
|
(57,826) |
|
|
(10.99) |
|
(59,881) |
|
|
(12.48) |
|
(225,938) |
|
|
(11.32) |
|
(232,307) |
|
|
(12.72) |
General and administration |
|
(12,431) |
|
|
(2.18) |
|
(13,088) |
|
|
(2.49) |
|
(13,236) |
|
|
(2.76) |
|
(53,584) |
|
|
(2.68) |
|
(61,727) |
|
|
(3.38) |
PRRT |
|
(1,054) |
|
|
(0.18) |
|
(99) |
|
|
(0.02) |
|
(13,568) |
|
|
(2.83) |
|
(6,878) |
|
|
(0.34) |
|
(60,340) |
|
|
(3.30) |
Corporate income taxes |
|
3,113 |
|
|
0.55 |
|
(12,383) |
|
|
(2.35) |
|
(8,304) |
|
|
(1.73) |
|
(44,237) |
|
|
(2.22) |
|
(96,996) |
|
|
(5.31) |
Interest expense |
|
(16,584) |
|
|
(2.90) |
|
(15,420) |
|
|
(2.93) |
|
(12,943) |
|
|
(2.70) |
|
(59,852) |
|
|
(3.00) |
|
(49,655) |
|
|
(2.72) |
Realized gain on derivative instruments |
|
21,164 |
|
|
3.71 |
|
10,854 |
|
|
2.06 |
|
22,816 |
|
|
4.76 |
|
41,356 |
|
|
2.07 |
|
36,712 |
|
|
2.01 |
Realized foreign exchange (loss) gain |
|
(252) |
|
|
(0.04) |
|
309 |
|
|
0.06 |
|
(179) |
|
|
(0.03) |
|
623 |
|
|
0.03 |
|
(821) |
|
|
(0.04) |
Realized other income |
|
243 |
|
|
0.04 |
|
227 |
|
|
0.04 |
|
202 |
|
|
0.04 |
|
32,671 |
|
|
1.64 |
|
732 |
|
|
0.04 |
Fund flows from operations |
|
136,441 |
|
|
23.91 |
|
129,435 |
|
|
24.58 |
|
185,528 |
|
|
38.67 |
|
516,167 |
|
|
25.86 |
|
804,865 |
|
|
44.09 |
The following table shows a reconciliation of
the change in fund flows from operations:
($M) |
|
|
|
|
|
Q4/15 vs. Q3/15 |
|
|
|
Q4/15 vs. Q4/14 |
|
|
|
|
2015 vs. 2014 |
Fund flows from operations -
Comparative period |
|
|
|
|
|
129,435 |
|
|
|
185,528 |
|
|
|
|
804,865 |
Sales volume variance: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
|
|
1,779 |
|
|
|
3,636 |
|
|
|
|
24,239 |
|
France |
|
|
|
|
|
(5,232) |
|
|
|
8,916 |
|
|
|
|
36,817 |
|
Netherlands |
|
|
|
|
|
2,104 |
|
|
|
20,038 |
|
|
|
|
21,601 |
|
Germany |
|
|
|
|
|
1,478 |
|
|
|
(1,153) |
|
|
|
|
2,245 |
|
Ireland |
|
|
|
|
|
57 |
|
|
|
57 |
|
|
|
|
57 |
|
Australia |
|
|
|
|
|
16,350 |
|
|
|
2,802 |
|
|
|
|
(19,697) |
|
United States |
|
|
|
|
|
1,051 |
|
|
|
524 |
|
|
|
|
2,948 |
Pricing variance on sold volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI |
|
|
|
|
|
(3,075) |
|
|
|
(32,707) |
|
|
|
|
(195,644) |
|
AECO |
|
|
|
|
|
(2,507) |
|
|
|
(9,461) |
|
|
|
|
(45,760) |
|
Dated Brent |
|
|
|
|
|
(15,632) |
|
|
|
(53,825) |
|
|
|
|
(287,666) |
|
TTF |
|
|
|
|
|
(7,105) |
|
|
|
(10,581) |
|
|
|
|
(19,182) |
Changes in: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalties |
|
|
|
|
|
815 |
|
|
|
9,678 |
|
|
|
|
42,080 |
|
Transportation |
|
|
|
|
|
943 |
|
|
|
(658) |
|
|
|
|
701 |
|
Operating expense |
|
|
|
|
|
(7,819) |
|
|
|
(5,764) |
|
|
|
|
6,369 |
|
General and administration |
|
|
|
|
|
657 |
|
|
|
805 |
|
|
|
|
8,143 |
|
PRRT |
|
|
|
|
|
(955) |
|
|
|
12,514 |
|
|
|
|
53,462 |
|
Corporate income taxes |
|
|
|
|
|
15,496 |
|
|
|
11,417 |
|
|
|
|
52,759 |
|
Interest |
|
|
|
|
|
(1,164) |
|
|
|
(3,641) |
|
|
|
|
(10,197) |
|
Realized derivatives |
|
|
|
|
|
10,310 |
|
|
|
(1,652) |
|
|
|
|
4,644 |
|
Realized foreign exchange |
|
|
|
|
|
(561) |
|
|
|
(73) |
|
|
|
|
1,444 |
|
Realized other income |
|
|
|
|
|
16 |
|
|
|
41 |
|
|
|
|
31,939 |
Fund flows from operations -
Current period |
|
|
|
|
|
136,441 |
|
|
|
136,441 |
|
|
|
|
516,167 |
Fund flows from operations of $136.4 million during Q4 2015 represented an
increase of 5% versus Q3 2015. Quarter-over-quarter, the
increase was achieved, despite significant commodity price
declines, as a result of higher sold volumes driven by production
growth in every business unit, lower current taxes, and increased
receipts from commodity hedges.
Fund flows from operations decreased 26% and 36%
for the three months and year ended December
31, 2015, respectively, versus the comparable periods in
2014. The 2015 decreases were primarily driven by
unfavourable crude oil and natural gas price variances, partially
offset by higher sold volumes resulting from significant production
growth and global cost reductions, most notably in per unit
operating expense which decreased 8% and 11% for the quarter and
full year, respectively. The full year decrease in fund flows
from operations was partially offset by the previously mentioned
recovery of costs in France.
Fluctuations in fund flows from operations (and
correspondingly net earnings (loss) 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
consolidated balance sheet. When the crude oil inventory is
subsequently drawn down, the related expenses are recognized in
income.
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 |
|
Year
Ended |
|
% change |
|
|
|
Dec 31, |
|
|
Sep 30, |
|
|
Dec 31, |
|
Q4/15 vs. |
|
Q4/15 vs. |
|
Dec 31, |
|
|
Dec 31, |
|
2015 vs. |
Canada business unit |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
Q3/15 |
|
Q4/14 |
|
2015 |
|
|
2014 |
|
2014 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
|
7,964 |
|
|
9,195 |
|
|
11,384 |
|
(13%) |
|
(30%) |
|
9,550 |
|
|
11,248 |
|
(15%) |
|
NGLs (bbls/d) |
|
|
5,159 |
|
|
4,513 |
|
|
2,741 |
|
14% |
|
88% |
|
4,108 |
|
|
2,476 |
|
66% |
|
Natural gas (mmcf/d) |
|
|
87.90 |
|
|
71.94 |
|
|
58.36 |
|
22% |
|
51% |
|
71.65 |
|
|
55.67 |
|
29% |
|
Total (boe/d) |
|
|
27,773 |
|
|
25,698 |
|
|
23,851 |
|
8% |
|
16% |
|
25,598 |
|
|
23,001 |
|
11% |
Production mix (% of
total) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil |
|
|
29% |
|
|
36% |
|
|
48% |
|
|
|
|
|
37% |
|
|
49% |
|
|
|
NGLs |
|
|
19% |
|
|
18% |
|
|
11% |
|
|
|
|
|
16% |
|
|
11% |
|
|
|
Natural gas |
|
|
52% |
|
|
46% |
|
|
41% |
|
|
|
|
|
47% |
|
|
40% |
|
|
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
|
|
27,554 |
|
|
37,224 |
|
|
85,442 |
|
(26%) |
|
(68%) |
|
201,508 |
|
|
334,742 |
|
(40%) |
|
Acquisitions ($M) |
|
|
6,169 |
|
|
8,062 |
|
|
1,671 |
|
|
|
|
|
14,650 |
|
|
415,648 |
|
|
|
Gross wells drilled |
|
|
5.00 |
|
|
11.00 |
|
|
23.00 |
|
|
|
|
|
42.00 |
|
|
74.00 |
|
|
|
Net wells drilled |
|
|
2.56 |
|
|
6.91 |
|
|
15.16 |
|
|
|
|
|
26.01 |
|
|
50.27 |
|
|
Production
- Q4 2015 average production in Canada increased by 8% quarter-over-quarter
and 16% year-over-year. Full year average production increased 11%
versus 2014. Quarterly and annual increases were primarily due to
strong organic production growth in our Mannville condensate-rich gas resource
play.
- In early December 2015, some
transportation restrictions were lifted, resulting in approximately
1,000 boe/d of non-operated volumes being brought online. At
the end of Q4 2015, approximately 1,600 boe/d of production was
shut-in due to a lack of field compression capacity, but the
majority of these volumes are expected to be brought online in Q1
2016.
- Cardium production averaged approximately 8,000 boe/d in Q4
2015, a 14% decrease quarter-over-quarter. Full year 2015 average
production of approximately 9,100 boe/d represented a decrease of
16% versus 2014.
- Mannville production averaged
approximately 11,000 boe/d in Q4 2015, a 57% increase
quarter-over-quarter and more than 2.5 times Q4 2014 production of
approximately 4,300 boe/d. Full year 2015 production averaged
more than 7,100 boe/d, representing an 82% increase versus
2014.
- Production from our southeast Saskatchewan assets averaged approximately
2,500 boe/d in Q4 2015, a decrease of 17%
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 two (2.0
net) operated wells and participated in the drilling of three (0.6
net) non-operated wells during Q4 2015. During 2015, Vermilion drilled 20 (17.6 net) operated wells
and participated in the drilling of 22 (8.4 net) non-operated wells
in Canada.
Cardium
- During Q4 2015, we participated in the drilling of two (0.3
net) non-operated wells; no wells were placed on production.
- In 2015, we drilled one (1.0 net) operated well and brought ten
(9.3 net) operated wells on production. We also participated in the
drilling of eight (2.4 net) non-operated wells and six (2.1 net)
non-operated wells were brought on production.
- 2016 activity will focus on the optimization of existing
assets.
Mannville
- During Q4 2015, we drilled two (2.0 net) operated wells and
brought one (1.0 net) operated well on production. We also
participated in the drilling of one (0.3 net) non-operated well and
one (0.4 net) non-operated well was placed on production.
- In 2015, we drilled 14 (12.5 net) operated wells and brought 11
(9.5 net) operated wells on production. We also participated in the
drilling of 14 (6.0 net) non-operated wells and ten (3.8 net)
non-operated wells were placed on production.
- In 2016, we plan to drill or participate in approximately six
(4.0 net) wells.
Saskatchewan
- We drilled and brought on production five (4.1 net) operated
Midale wells during Q1 2015,
completing our 2015 drilling activity in Saskatchewan.
- In 2016, we plan to drill or participate in six (5.5 net)
wells.
Financial review
|
|
|
Three
Months Ended |
|
%
change |
|
Year
Ended |
|
% change |
Canada business unit |
|
|
Dec 31, |
|
|
Sep 30, |
|
|
Dec 31, |
|
Q4/15 vs. |
|
Q4/15 vs. |
|
Dec 31, |
|
|
Dec 31, |
|
2015 vs. |
($M except as indicated) |
|
|
2015 |
|
|
2015 |
|
|
2014 |
|
Q3/15 |
|
Q4/14 |
|
2015 |
|
|
2014 |
|
2014 |
|
Sales |
|
|
73,952 |
|
|
77,493 |
|
|
112,494 |
|
(5%) |
|
(34%) |
|
320,613 |
|
|
537,788 |
|
(40%) |
|
Royalties |
|
|
(7,146) |
|
|
(6,638) |
|
|
(15,626) |
|
8% |
|
(54%) |
|
(28,144) |
|
|
(65,563) |
|
(57%) |
|
Transportation expense |
|
|
(3,784) |
|
|
(4,131) |
|
|
(3,455) |
|
(8%) |
|
10% |
|
(16,326) |
|
|
(14,625) |
|
12% |
|
Operating expense |
|
|
(24,575) |
|
|
(23,877) |
|
|
(19,315) |
|
3% |
|
27% |
|
(89,085) |
|
|
(76,178) |
|
17% |
|
General and administration |
|
|
(3,669) |
|
|
(3,694) |
|
|
(2,840) |
|
(1%) |
|
29% |
|
(16,888) |
|
|
(16,791) |
|
1% |
|
Fund flows from operations |
|
|
34,778 |
|
|
39,153 |
|
|
71,258 |
|
(11%) |
|
(51%) |
|
170,170 |
|
|
364,631 |
|
(53%) |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
28.94 |
|
|
32.78 |
|
|
51.27 |
|
(12%) |
|
(44%) |
|
34.32 |
|
|
64.06 |
|
(46%) |
|
Royalties |
|
|
(2.80) |
|
|
(2.81) |
|
|
(7.12) |
|
- |
|
(61%) |
|
(3.01) |
|
|
(7.81) |
|
(61%) |
|
Transportation expense |
|
|
(1.48) |
|
|
(1.75) |
|
|
(1.57) |
|
(15%) |
|
(6%) |
|
(1.75) |
|
|
(1.74) |
|
1% |
|
Operating expense |
|
|
(9.62) |
|
|
(10.10) |
|
|
(8.80) |
|
(5%) |
|
9% |
|
(9.54) |
|
|
(9.07) |
|
5% |
|
General and administration |
|
|
(1.44) |
|
|
(1.56) |
|
|
(1.29) |
|
(8%) |
|
12% |
|
(1.81) |
|
|
(2.00) |
|
(10%) |
|
Fund flows from operations netback |
|
|
13.60 |
|
|
16.56 |
|
|
32.49 |
|
(18%) |
|
(58%) |
|
18.21 |
|
|
43.44 |
|
(58%) |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl) |
|
|
42.18 |
|
|
46.43 |
|
|
73.15 |
|
(9%) |
|
(42%) |
|
48.80 |
|
|
93.00 |
|
(48%) |
|
Edmonton Sweet index (US $/bbl) |
|
|
39.72 |
|
|
43.01 |
|
|
66.79 |
|
(8%) |
|
(41%) |
|
44.91 |
|
|
85.83 |
|
(48%) |
|
Edmonton Sweet index ($/bbl) |
|
|
53.04 |
|
|
56.32 |
|
|
75.85 |
|
(6%) |
|
(30%) |
|
57.43 |
|
|
94.82 |
|
(39%) |
|
AECO ($/mcf) |
|
|
2.46 |
|
|
2.90 |
|
|
3.60 |
|
(15%) |
|
(32%) |
|
2.69 |
|
|
4.50 |
|
(40%) |
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.
- Q4 2015 and full year 2015 sales per boe decreased versus all
comparable periods, largely as the result of weakening crude oil
and natural gas pricing.
Royalties
- Royalties as a percentage of sales for Q4 2015 of 9.7% was
slightly higher than the 8.6% for Q3 2015 due to the absence of
certain royalty credits recorded in the third quarter.
- Royalties as a percentage of sales for the three months and
year ended December 31, 2015
decreased to 9.7% and 8.8% versus the same periods in 2014 (13.9%
and 12.2%, respectively) 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 the three months and year ended
December 31, 2015 was higher than the
comparable periods in 2014 due to increased natural gas and natural
gas liquids volumes produced in 2015. In addition, full year
2015 expense includes incremental trucking costs from Vermilion's Saskatchewan properties, which were acquired
in April 2014.
Operating expense
- Operating expense was higher in Q4 2015 versus Q4 2014 due to
higher gas gathering and processing expenditures following
significantly increased natural gas and natural gas liquids
production. For Q4 2015 versus Q3 2015, this increase was
largely offset by cost reduction initiatives including reduced
major project, transportation and other costs, resulting in a 5%
reduction in per unit costs.
- Full year operating expense increased on a spend basis by
approximately 17% due to incremental operating expense associated
with Vermilion's Saskatchewan properties acquired in Q2 2014
and higher gas gathering and processing fees following increased
natural gas and natural gas liquids production in Alberta. This increase in spending was
partially offset by increased production volumes, resulting in a 5%
increase in operating expense per boe.
General and administration
- General and administration expense increased from Q4 2014
primarily due to a decrease in recoveries, which more than offset
lower gross costs.
- Year-over-year, 2015 general and administrative expense were
essentially flat due to lower current year recoveries more than
offsetting a decrease in gross costs.
Impairment
- For the three months and year ended December 31, 2015, Vermilion recorded an impairment charge of
$131.6 million and $274.6 million, respectively, related to the
light crude oil play in Saskatchewan,
Canada ($267.9 million in
2015) and the shallow coal bed methane gas properties in
Alberta, Canada ($6.7 million in 2015). These impairment charges
were a result of declines in the price forecasts for crude oil and
natural gas in Canada which
decreased the expected future cash flows from the respective cash
generating units.
FRANCE
BUSINESS UNIT
Overview
- Entered France in 1997 and
completed three subsequent acquisitions, including two in
2012.
- Largest oil producer in France, constituting approximately
three-quarters of domestic oil production.
- Producing assets include large conventional fields with high
working interests located in the Aquitaine and Paris Basins with an
identified inventory of workover, infill drilling, and secondary
recovery opportunities.
- Production is characterized by Brent-based crude pricing and
low base decline rates.
Operational review
|
|
Three Months Ended |
|
% change |
|
|
Year Ended |
|
% change |
|
|
Dec 31, |
Sep 30, |
Dec 31, |
|
Q4/15 vs. |
Q4/15 vs. |
|
|
Dec 31, |
Dec 31, |
|
2015 vs. |
France business unit |
2015 |
2015 |
2014 |
|
Q3/15 |
Q4/14 |
|
|
2015 |
2014 |
|
2014 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
12,537 |
12,310 |
11,133 |
|
2% |
13% |
|
|
12,267 |
11,011 |
|
11% |
|
Natural gas (mmcf/d) |
1.36 |
1.47 |
- |
|
(7%) |
100% |
|
|
0.97 |
- |
|
100% |
|
Total (boe/d) |
12,763 |
12,555 |
11,133 |
|
2% |
15% |
|
|
12,429 |
11,011 |
|
13% |
Inventory (mbbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Opening crude oil inventory |
239 |
340 |
214 |
|
|
|
|
|
197 |
269 |
|
|
|
Crude oil production |
1,153 |
1,133 |
1,024 |
|
|
|
|
|
4,477 |
4,019 |
|
|
|
Crude oil sales |
(1,149) |
(1,234) |
(1,041) |
|
|
|
|
|
(4,431) |
(4,091) |
|
|
|
Closing crude oil inventory |
243 |
239 |
197 |
|
|
|
|
|
243 |
197 |
|
|
Production mix (% of
total) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil |
98% |
98% |
100% |
|
|
|
|
|
99% |
100% |
|
|
|
Natural gas |
2% |
2% |
- |
|
|
|
|
|
1% |
- |
|
|
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
24,085 |
17,369 |
37,189 |
|
39% |
(35%) |
|
|
92,265 |
147,852 |
|
(38%) |
|
Acquisitions ($M) |
79 |
142 |
- |
|
|
|
|
|
317 |
- |
|
|
|
Gross wells drilled |
- |
- |
1.00 |
|
|
|
|
|
4.00 |
8.00 |
|
|
|
Net wells drilled |
- |
- |
0.50 |
|
|
|
|
|
4.00 |
7.50 |
|
|
Production
- Ongoing workover and optimization activities in Q4 2015
resulted in stable quarter-over-quarter production.
Production increased versus 2014, for both the quarter and full
year periods, due to production additions from our 2015 Champotran
drilling program and workovers.
Activity review
- Vermilion drilled four (4.0
net) wells in the Champotran field in the Paris Basin in Q1 2015, completing our planned
France drilling program for
2015.
- In 2015, additional activity included workover and optimization
programs in the Aquitaine and Paris Basins, and the resumption of
sales from a portion of our shut-in natural gas at Vic Bilh, which
was brought back on-line in Q2 2015.
- In 2016, our planned capital activity includes a program of
approximately 15 well workovers.
Financial review
|
|
Three Months Ended |
|
% change |
|
|
Year Ended |
|
% change |
France business unit |
Dec 31, |
Sep 30, |
Dec 31, |
|
Q4/15 vs. |
Q4/15 vs. |
|
|
Dec 31, |
Dec 31, |
|
2015 vs. |
($M except as indicated) |
2015 |
2015 |
2014 |
|
Q3/15 |
Q4/14 |
|
|
2015 |
2014 |
|
2014 |
|
Sales |
63,411 |
76,552 |
82,499 |
|
(17%) |
(23%) |
|
|
281,422 |
431,252 |
|
(35%) |
|
Royalties |
(7,198) |
(8,038) |
(6,319) |
|
(10%) |
14% |
|
|
(26,958) |
(28,444) |
|
(5%) |
|
Transportation expense |
(4,275) |
(4,566) |
(4,096) |
|
(6%) |
4% |
|
|
(15,378) |
(18,975) |
|
(19%) |
|
Operating expense |
(15,792) |
(11,998) |
(13,544) |
|
32% |
17% |
|
|
(50,718) |
(61,729) |
|
(18%) |
|
General and administration |
(4,894) |
(5,338) |
(3,765) |
|
(8%) |
30% |
|
|
(20,217) |
(20,929) |
|
(3%) |
|
Other income |
- |
- |
- |
|
- |
- |
|
|
31,775 |
- |
|
100% |
|
Current income taxes |
4,529 |
(4,696) |
(6,132) |
|
(196%) |
(174%) |
|
|
(23,764) |
(66,901) |
|
(64%) |
|
Fund flows from operations |
35,781 |
41,916 |
48,643 |
|
(15%) |
(26%) |
|
|
176,162 |
234,274 |
|
(25%) |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
54.20 |
60.96 |
79.25 |
|
(11%) |
(32%) |
|
|
62.67 |
105.43 |
|
(41%) |
|
Royalties |
(6.15) |
(6.40) |
(6.07) |
|
(4%) |
1% |
|
|
(6.00) |
(6.95) |
|
(14%) |
|
Transportation expense |
(3.65) |
(3.64) |
(3.94) |
|
- |
(7%) |
|
|
(3.42) |
(4.64) |
|
(26%) |
|
Operating expense |
(13.50) |
(9.55) |
(13.01) |
|
41% |
4% |
|
|
(11.30) |
(15.09) |
|
(25%) |
|
General and administration |
(4.18) |
(4.25) |
(3.62) |
|
(2%) |
15% |
|
|
(4.50) |
(5.12) |
|
(12%) |
|
Other income |
- |
- |
- |
|
- |
- |
|
|
7.08 |
- |
|
100% |
|
Current income taxes |
3.87 |
(3.74) |
(5.89) |
|
(203%) |
(166%) |
|
|
(5.29) |
(16.36) |
|
(68%) |
|
Fund flows from operations
netback |
30.59 |
33.38 |
46.72 |
|
(8%) |
(35%) |
|
|
39.24 |
57.27 |
|
(31%) |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated Brent (US $/bbl) |
43.69 |
50.26 |
76.27 |
|
(13%) |
(43%) |
|
|
52.46 |
98.99 |
|
(47%) |
|
Dated Brent ($/bbl) |
58.34 |
65.81 |
86.62 |
|
(11%) |
(33%) |
|
|
67.09 |
109.36 |
|
(39%) |
Sales
- Crude oil in France is priced
with reference to Dated Brent.
- Sales per boe decreased quarter-over-quarter, consistent with a
decrease in the Dated Brent reference price. This decrease in price
was combined with decreased sales volumes due to a slight build in
inventory of 4,000 bbls in Q4 (versus a draw in Q3 2015).
- On a year-over-year basis, sales decreased for the three months
and year ended December 31, 2015,
consistent with a decline in the Dated Brent reference price, and
was partially offset by increased sales volumes driven by
production growth.
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
sales).
- Royalties as a percentage of sales of 11.4% and 9.6% for the
three months and year ended December 31,
2015 was higher than Q3 2015 (10.5%) and the 2014 periods
(7.7% and 6.6%, respectively) as a result of the impact of fixed
RCDM royalties coupled with lower realized pricing.
Transportation
- Transportation expense for Q4 2015 was relatively consistent
with both Q3 2015 and Q4 2014.
- Transportation expense decreased by 19% for 2015 versus 2014
due to a lower level of maintenance and project activity at the
Ambès terminal coupled with the favourable foreign exchange impact
of the strengthening of the Canadian dollar versus the Euro.
Operating expense
- Operating expense on a dollar and per boe basis increased in Q4
2015 versus both Q3 2015 and Q4 2014 due to increased electricity
usage and costs coupled with a higher level of project activity in
the current quarter.
- Operating expense on a dollar and per boe basis decreased in
2015 versus 2014 due largely to the successful implementation of
cost reduction initiatives undertaken in response to commodity
price weakness. These cost reduction initiatives included
lower costs on downhole and other maintenance activities, lower
labour usage and costs and savings from service contract
renegotiations. These cost cutting initiatives were delivered
while growing production during the year by 13%, resulting in a 25%
decrease in unit costs.
General and administration
- General and administration expense for Q4 2015 was 8% lower
than Q3 2015 and 30% higher than Q4 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-over-year, 2015 general and administration expense was 3%
lower than 2014 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 year ended December 31, 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, $31.8 million (before taxes) was recognized as
other income.
Current income taxes
- Current income taxes in France
are applied to taxable income, after eligible deductions, at a
statutory rate of 34.4% for 2015. France is not expected to incur any current
income taxes for 2016. This is subject to change in response to
commodity price fluctuations, the timing of capital expenditures,
and other eligible in-country adjustments.
- Q4 2015 current income taxes decreased compared to Q3 2015 and
Q4 2014 due to decreased revenues and additional tax deductions
taken for depletion.
- Current income taxes for the full year ended December 31, 2015 decreased versus the
comparative period in 2014 mainly due to lower fund flows from
operations as a result of the decline in the Dated Brent reference
price and additional tax deductions taken for depletion.
NETHERLANDS
BUSINESS UNIT
Overview
- Entered the Netherlands in
2004.
- Second largest onshore gas producer.
- Interests include 24 onshore licenses and two offshore
licenses.
- Licenses include more than 800,000 net acres of undeveloped
land.
- Natural gas drilling and development.
- Natural gas produced in the
Netherlands is priced off the TTF index, which receives a
significant premium over North American gas prices.
Operational review
|
|
Three
Months Ended |
|
%
change |
|
|
Year
Ended |
|
%
change |
|
|
Dec 31, |
Sep 30, |
Dec 31, |
|
Q4/15 vs. |
Q4/15 vs. |
|
|
Dec 31, |
Dec 31, |
|
2015 vs. |
Netherlands business unit |
2015 |
2015 |
2014 |
|
Q3/15 |
Q4/14 |
|
|
2015 |
2014 |
|
2014 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d) |
110 |
109 |
81 |
|
1% |
36% |
|
|
99 |
77 |
|
29% |
|
Natural gas (mmcf/d) |
56.34 |
53.56 |
31.35 |
|
5% |
80% |
|
|
44.76 |
38.20 |
|
17% |
|
Total (boe/d) |
9,500 |
9,035 |
5,306 |
|
5% |
79% |
|
|
7,559 |
6,443 |
|
17% |
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
18,810 |
5,297 |
10,022 |
|
255% |
88% |
|
|
47,325 |
61,740 |
|
(23%) |
|
Gross wells drilled |
- |
- |
2.00 |
|
|
|
|
|
2.00 |
7.00 |
|
|
|
Net wells drilled |
- |
- |
0.92 |
|
|
|
|
|
1.86 |
4.66 |
|
|
Production
- Q4 2015 production represented a new record for our Netherlands
Business Unit at 9,500 boe/d, which is an increase of 5% from the
prior quarter. This increase is primarily attributable to
production from the Diever-02 exploration well (45% working
interest), coming on an extended production test in late October.
Diever-02 is currently producing approximately 13.2 mmcf/d (2,200
boe/d) net to Vermilion.
- Q4 2015 production increased 79% year-over-year, mainly driven
by the extended production test of three wells: Slootdorp-06/07
(92.8% working interest) and Diever-02 (45% working interest).
Slootdorp-06/07 were drilled in Q2 2015 and placed on an extended
production test in the following quarter. Slootdorp-06/07 are
currently producing approximately 25.8 mmcf/d (4,300 boe/d) net to
Vermilion.
- 2015 average production increased 17% versus 2014. Production
additions from the Slootdorp-06/07 and Diever-02 wells later in the
year were partially 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 2015, Vermilion
drilled two (1.9 net) wells, Slootdorp-06 and Slootdorp-07. These
wells are currently on sales during an extended production test to
size additional production equipment.
- The Diever-02 exploration well (45% working interest), drilled
in 2014, came on production in late October for an extended
production test
- During the year, we executed numerous debottlenecking
activities to enhance deliverability from the Slootdorp wells as
well as a turnaround at the Garijp Treatment Centre.
- Activity in 2016 will focus on permitting and optimization
initiatives.
Financial review
|
|
Three
Months Ended |
|
%
change |
|
|
Year
Ended |
|
%
change |
Netherlands business unit |
Dec 31, |
Sep 30, |
Dec 31, |
|
Q4/15 vs. |
Q4/15 vs. |
|
|
Dec 31, |
Dec 31, |
|
2015 vs. |
($M except as indicated) |
2015 |
2015 |
2014 |
|
Q3/15 |
Q4/14 |
|
|
2015 |
2014 |
|
2014 |
|
Sales |
37,243 |
41,083 |
25,420 |
|
(9%) |
47% |
|
|
129,057 |
123,815 |
|
4% |
|
Royalties |
(224) |
(638) |
(1,171) |
|
(65%) |
(81%) |
|
|
(3,082) |
(5,014) |
|
(39%) |
|
Operating expense |
(6,263) |
(5,243) |
(6,200) |
|
19% |
1% |
|
|
(22,746) |
(24,041) |
|
(5%) |
|
General and administration |
(813) |
(2,154) |
(2,489) |
|
(62%) |
(67%) |
|
|
(4,158) |
(3,617) |
|
15% |
|
Current income taxes |
(2,930) |
(4,487) |
2,124 |
|
(35%) |
(238%) |
|
|
(12,152) |
(4,154) |
|
193% |
|
Fund flows from operations |
27,013 |
28,561 |
17,684 |
|
(5%) |
53% |
|
|
86,919 |
86,989 |
|
- |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
42.61 |
49.42 |
52.07 |
|
(14%) |
(18%) |
|
|
46.77 |
52.65 |
|
(11%) |
|
Royalties |
(0.26) |
(0.77) |
(2.40) |
|
(66%) |
(89%) |
|
|
(1.12) |
(2.13) |
|
(47%) |
|
Operating expense |
(7.17) |
(6.31) |
(12.70) |
|
14% |
(44%) |
|
|
(8.24) |
(10.22) |
|
(19%) |
|
General and administration |
(0.93) |
(2.59) |
(5.10) |
|
(64%) |
(82%) |
|
|
(1.51) |
(1.54) |
|
(2%) |
|
Current income taxes |
(3.35) |
(5.40) |
4.35 |
|
(38%) |
(177%) |
|
|
(4.40) |
(1.77) |
|
149% |
|
Fund flows from operations
netback |
30.90 |
34.35 |
36.22 |
|
(10%) |
(15%) |
|
|
31.50 |
36.99 |
|
(15%) |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
TTF ($/mmbtu) |
7.28 |
8.48 |
9.16 |
|
(14%) |
(21%) |
|
|
8.23 |
8.96 |
|
(8%) |
|
TTF (€/mmbtu) |
4.98 |
5.82 |
6.46 |
|
(14%) |
(23%) |
|
|
5.80 |
6.11 |
|
(5%) |
Sales
- The price of our natural gas in the
Netherlands is based on the TTF day-ahead index, as
determined on the Title Transfer Facility Virtual Trading Point
operated by Dutch TSO Gas Transport Services, plus various
fees. GasTerra, a state owned entity, continues to purchase
all of the natural gas we produce in the
Netherlands.
- Sales per boe decreased 14% quarter-over-quarter, consistent
with a decrease in the TTF reference price. The decrease in price
was partially offset by a 5% increase in production, resulting in a
9% decrease in sales.
- On a year-over-year basis, sales per boe decreased, consistent
with declines in the TTF reference price for the respective
periods. For the three months ended December
31, 2015, the decrease in price was more than offset by a
79% increase in production. For the year ended December 31, 2015, the decrease in price was
offset by a 17% increase in production.
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
- Q4 2015 operating expenses on a dollar and per boe basis
increased versus Q3 2015 as a result of higher power usage and gas
processing tariffs associated with our Diever-02 exploration well,
which came on production in late October
2015.
- 2015 operating expenses decreased by 5% on a dollar basis
compared to 2014 due in equal parts to the favourable 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. These cost reduction initiatives were executed
while growing production 17%, resulting in a 19% reduction in per
unit costs.
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 an implied tax rate of approximately 46%. For
2016, the effective rate on current 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.
- Current income taxes in Q4 2015 were lower compared to Q3 2015
due to decreased revenues. Current income taxes in Q4 2015 compared
to Q4 2014 were higher due to increased revenues.
- Current income taxes for the full year ended December 31, 2015 were higher compared to 2014 as
increased revenues in 2015 were combined with comparatively lower
tax depletion due to 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 July
2015 that provides 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.
- Awarded 110,000 net acres (100% working interest) across two
exploration licenses in Lower Saxony.
Operational review
|
|
Three
Months Ended |
|
%
change |
|
|
Year
Ended |
|
%
change |
|
|
Dec 31, |
Sep 30, |
Dec 31, |
|
Q4/15 vs. |
Q4/15 vs. |
|
|
Dec 31, |
Dec 31, |
|
2015 vs. |
Germany business unit |
2015 |
2015 |
2014 |
|
Q3/15 |
Q4/14 |
|
|
2015 |
2014 |
|
2014 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d) |
16.17 |
14.00 |
17.71 |
|
16% |
(9%) |
|
|
15.78 |
14.99 |
|
5% |
|
Total (boe/d) |
2,695 |
2,333 |
2,952 |
|
16% |
(9%) |
|
|
2,630 |
2,498 |
|
5% |
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
(441) |
1,605 |
563 |
|
(127%) |
(178%) |
|
|
5,363 |
2,747 |
|
95% |
|
Acquisitions ($M) |
- |
- |
- |
|
|
|
|
|
- |
172,871 |
|
|
|
Gross wells drilled |
- |
- |
- |
|
|
|
|
|
1.00 |
- |
|
|
|
Net wells drilled |
- |
- |
- |
|
|
|
|
|
0.25 |
- |
|
|
Production
- Q4 2015 production increased by 16% quarter-over-quarter due to
a planned maintenance shutdown in Q3 2015 and decreased 9%
year-over-year due to additions from the Deblinghausen Z7a well
that was brought on production in Q4 2014. Full year
production increased 5% versus prior year, due to 2014 volumes only
reflecting production from the acquisition's effective date of
February 1, 2014.
Activity review
- The Burgmoor Z3a sidetrack well (25% working interest), was
completed in Q2 2015 and was tied-in and placed on production in Q3
2015.
- In 2016, the majority of activity will be associated with
permitting and pre-drill activities for Burgmoor Z5 and two farm-in
prospects. In addition, we will continue our ongoing analysis
of the proprietary geologic data associated with the farm-in
assets.
Financial review
|
|
Three
Months Ended |
|
%
change |
|
|
Year
Ended |
|
%
change |
Germany business unit |
Dec 31, |
Sep 30, |
Dec 31, |
|
Q4/15 vs. |
Q4/15 vs. |
|
|
Dec 31, |
Dec 31, |
|
2015 vs. |
($M except as indicated) |
2015 |
2015 |
2014 |
|
Q3/15 |
Q4/14 |
|
|
2015 |
2014 |
|
2014 |
|
Sales |
9,840 |
9,523 |
13,359 |
|
3% |
(26%) |
|
|
41,384 |
41,962 |
|
(1%) |
|
Royalties |
(1,166) |
(1,477) |
(2,481) |
|
(21%) |
(53%) |
|
|
(6,479) |
(8,613) |
|
(25%) |
|
Transportation expense |
(508) |
(627) |
(218) |
|
(19%) |
133% |
|
|
(3,269) |
(2,367) |
|
38% |
|
Operating expense |
(4,788) |
(2,796) |
(2,862) |
|
71% |
67% |
|
|
(10,956) |
(8,686) |
|
26% |
|
General and administration |
(3,032) |
(1,311) |
(2,200) |
|
131% |
38% |
|
|
(7,386) |
(4,688) |
|
58% |
|
Current income taxes |
- |
- |
1,145 |
|
- |
(100%) |
|
|
- |
(44) |
|
(100%) |
|
Fund flows from operations |
346 |
3,312 |
6,743 |
|
(90%) |
(95%) |
|
|
13,294 |
17,564 |
|
(24%) |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
39.68 |
44.36 |
49.19 |
|
(11%) |
(19%) |
|
|
43.10 |
46.03 |
|
(6%) |
|
Royalties |
(4.70) |
(6.88) |
(9.13) |
|
(32%) |
(49%) |
|
|
(6.75) |
(9.45) |
|
(29%) |
|
Transportation expense |
(2.05) |
(2.92) |
(0.80) |
|
(30%) |
156% |
|
|
(3.41) |
(2.60) |
|
31% |
|
Operating expense |
(19.31) |
(13.03) |
(10.54) |
|
48% |
83% |
|
|
(11.41) |
(9.53) |
|
20% |
|
General and administration |
(12.22) |
(6.11) |
(8.10) |
|
100% |
51% |
|
|
(7.69) |
(5.14) |
|
50% |
|
Current income taxes |
- |
- |
4.21 |
|
- |
(100%) |
|
|
- |
(0.05) |
|
(100%) |
|
Fund flows from operations
netback |
1.40 |
15.42 |
24.83 |
|
(91%) |
(94%) |
|
|
13.84 |
19.26 |
|
(28%) |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
TTF ($/mmbtu) |
7.28 |
8.48 |
9.16 |
|
(14%) |
(21%) |
|
|
8.23 |
8.96 |
|
(8%) |
|
TTF (€/mmbtu) |
4.98 |
5.82 |
6.46 |
|
(14%) |
(23%) |
|
|
5.80 |
6.11 |
|
(5%) |
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 3% increase in sales quarter-over-quarter is due to an
increase in production, partially offset by decreases in the TTF
reference price.
- On a year-over-year basis, sales per boe decreased for the
three months and year ended December 31,
2015 consistent with movements in the TTF reference price.
For the three months ended December 31,
2015, this pricing decline was combined with a decrease in
production. For the year ended December 31, 2015, the decrease in price was
almost entirely offset by an increase in production.
Royalties
- Our production in Germany is
subject to state and private royalties on sales after certain
eligible deductions.
- In Q4 2015, royalties as a percentage of sales was 11.8%, a
decrease versus both the 15.5% for Q3 2015 and 18.6% for Q4
2014. The decrease in Q4 2015 versus both comparable quarters
was a result of adjustments to Q3 2015 royalties following
preliminary royalty submissions recorded in the current
quarter.
- Full year 2015 royalties as a percentage of sales was 15.7%
versus 20.5% for 2014 as a result of lower state royalty rates in
the current year.
Transportation expense
- Transportation expense in Germany relates to costs incurred to deliver
natural gas from the processing facility to the customer.
- Q4 2015 transportation expense was lower than Q3 2015 due to
seasonal changes in levels of transportation facility maintenance,
which are typically higher at the beginning of the year. Q4
2015 transportation expense was higher than Q4 2014 due to the
impact of prior period adjustments recorded in the 2014
period.
- Year-over-year, transportation expense has increased as 2014
included only eleven months of expense due to the timing of our
Germany acquisition. In
addition, 2015 included a prior period adjustment payment related
to 2014.
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.
- Q4 2015 operating expense was higher than both Q3 2015 and Q4
2014 due in equal parts to charges for prior period maintenance
expenditures and the inclusion of a full year gas processing tariff
adjustment recorded in the current quarter.
- Full year operating expense was higher on a dollar basis versus
2014 due to the inclusion of only eleven months of expense in 2014
due to the timing of our Germany
acquisition and additional charges from the operator relating to
2014.
General and administration
- Q4 2015 general and administration expenses were higher than
both Q3 2015 and Q4 2014 due largely to increased allocations from
our Corporate segment in addition to higher staffing levels and
office extension costs incurred to support our farm-in
agreement.
- Full year 2015 general and administration expense increased in
2015 versus 2014 due to the aforementioned increased allocations
coupled with higher staffing levels and expenditures relating to
our 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 24.2%. 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 |
|
|
Year
Ended |
|
%
change |
Ireland business unit |
Dec 31, |
Sep 30, |
Dec 31, |
|
Q4/15 vs. |
Q4/15 vs. |
|
|
Dec 31, |
Dec 31, |
|
2015 vs. |
($M except as indicated) |
2015 |
2015 |
2014 |
|
Q3/15 |
Q4/14 |
|
|
2015 |
2014 |
|
2014 |
|
Sales |
57 |
- |
- |
|
100% |
100% |
|
|
57 |
- |
|
100% |
|
Transportation expense |
(1,580) |
(1,766) |
(1,720) |
|
(11%) |
(8%) |
|
|
(6,687) |
(6,394) |
|
5% |
|
Operating expense |
(15) |
- |
- |
|
100% |
100% |
|
|
(15) |
- |
|
100% |
|
General and administration |
(714) |
(663) |
(579) |
|
8% |
23% |
|
|
(2,517) |
(1,447) |
|
74% |
|
Fund flows from operations |
(2,252) |
(2,429) |
(2,299) |
|
(7%) |
(2%) |
|
|
(9,162) |
(7,841) |
|
17% |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
NBP ($/mmbtu) |
7.41 |
8.40 |
9.52 |
|
(12%) |
(22%) |
|
|
8.33 |
9.10 |
|
(8%) |
|
NBP (€/mmbtu) |
5.07 |
5.77 |
6.71 |
|
(12%) |
(24%) |
|
|
5.87 |
6.20 |
|
(5%) |
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
12,493 |
20,694 |
20,932 |
|
(40%) |
(40%) |
|
|
66,409 |
94,439 |
|
(30%) |
Activity review
- On December 29, 2015, the
operator, Shell E&P Ireland Limited received consent from the
office of Ireland's Minister for
Communication, Energy and Natural Resources.
- On December 30, 2015, natural gas
began to flow from our Corrib gas project.
- Production 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.
Transportation expense
- Transportation expense in Ireland relates to payments under a ship or
pay agreement related to the Corrib project.
- Q4 2015 transportation expense is lower than Q3 2015 due to
lower tariffs for the current gas year, which began in October of
2015, under the ship or pay agreement.
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 |
|
|
Year
Ended |
%
change |
|
|
Dec 31, |
Sep 30, |
Dec 31, |
|
Q4/15 vs. |
Q4/15 vs. |
|
|
Dec 31, |
Dec 31, |
2015 vs. |
Australia business unit |
2015 |
2015 |
2014 |
|
Q3/15 |
Q4/14 |
|
|
2015 |
2014 |
2014 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
7,824 |
6,433 |
6,134 |
|
22% |
28% |
|
|
6,454 |
6,571 |
(2%) |
Inventory (mbbls) |
|
|
|
|
|
|
|
|
|
|
|
|
Opening crude oil inventory |
172 |
156 |
258 |
|
|
|
|
|
37 |
130 |
|
|
Crude oil production |
720 |
592 |
564 |
|
|
|
|
|
2,356 |
2,398 |
|
|
Crude oil sales |
(817) |
(576) |
(785) |
|
|
|
|
|
(2,318) |
(2,491) |
|
|
Closing crude oil inventory |
75 |
172 |
37 |
|
|
|
|
|
75 |
37 |
|
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
40,852 |
7,966 |
11,616 |
|
413% |
252% |
|
|
61,741 |
44,283 |
39% |
|
Gross wells drilled |
1.00 |
- |
- |
|
|
|
|
|
1.00 |
- |
|
|
Net wells drilled |
1.00 |
- |
- |
|
|
|
|
|
1.00 |
- |
|
Production
- Q4 2015 quarterly production increased 22% quarter-over-quarter
and 28% year-over-year, due to production additions from the
horizontal sidetrack well drilled in the quarter. The well was
brought on production in mid-November and exhibited strong well
performance, producing approximately 3,900 bbls/d through the end
of Q4. Full year 2015 production decreased 2% versus the prior
year.
- Production volumes are managed within corporate targets while
meeting customer demands and the requirements of long-term supply
agreements.
- We continue to plan for long-term production levels of between
6,000 and 8,000 bbls/d.
Activity review
- In Q4 2015, we completed a horizontal sidetrack drilling
program and placed the well on production.
- Additional 2015 activities included ongoing facilities
maintenance, enhancement, and refurbishment.
- We plan to drill a two-well sidetrack program in Q2 2016.
Financial review
|
|
Three
Months Ended |
|
%
change |
|
|
Year
Ended |
|
%
change |
Australia business unit |
Dec 31, |
Sep 30, |
Dec 31, |
|
Q4/15 vs. |
Q4/15 vs. |
|
|
Dec 31, |
Dec 31, |
|
2015 vs. |
($M except as indicated) |
2015 |
2015 |
2014 |
|
Q3/15 |
Q4/14 |
|
|
2015 |
2014 |
|
2014 |
|
Sales |
47,952 |
39,325 |
70,971 |
|
22% |
(32%) |
|
|
162,765 |
283,481 |
|
(43%) |
|
Operating expense |
(13,941) |
(13,766) |
(17,719) |
|
1% |
(21%) |
|
|
(51,676) |
(61,432) |
|
(16%) |
|
General and administration |
(1,768) |
(1,391) |
(1,628) |
|
27% |
9% |
|
|
(5,754) |
(5,873) |
|
(2%) |
|
PRRT |
(1,054) |
(99) |
(13,568) |
|
965% |
(92%) |
|
|
(6,878) |
(60,340) |
|
(89%) |
|
Corporate income taxes |
1,201 |
(2,720) |
(4,799) |
|
(144%) |
(125%) |
|
|
(7,230) |
(24,477) |
|
(70%) |
|
Fund flows from operations |
32,390 |
21,349 |
33,257 |
|
52% |
(3%) |
|
|
91,227 |
131,359 |
|
(31%) |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
58.74 |
68.20 |
90.37 |
|
(14%) |
(35%) |
|
|
70.22 |
113.80 |
|
(38%) |
|
Operating expense |
(17.08) |
(23.87) |
(22.56) |
|
(28%) |
(24%) |
|
|
(22.29) |
(24.66) |
|
(10%) |
|
General and administration |
(2.17) |
(2.41) |
(2.07) |
|
(10%) |
5% |
|
|
(2.48) |
(2.36) |
|
5% |
|
PRRT |
(1.29) |
(0.17) |
(17.28) |
|
659% |
(93%) |
|
|
(2.97) |
(24.22) |
|
(88%) |
|
Corporate income taxes |
1.47 |
(4.72) |
(6.11) |
|
(131%) |
(124%) |
|
|
(3.12) |
(9.83) |
|
(68%) |
|
Fund flows from operations
netback |
39.67 |
37.03 |
42.35 |
|
7% |
(6%) |
|
|
39.36 |
52.73 |
|
(25%) |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated Brent (US $/bbl) |
43.69 |
50.26 |
76.27 |
|
(13%) |
(43%) |
|
|
52.46 |
98.99 |
|
(47%) |
|
Dated Brent ($/bbl) |
58.34 |
65.81 |
86.62 |
|
(11%) |
(33%) |
|
|
67.09 |
109.36 |
|
(39%) |
Sales
- Crude oil in Australia is
priced with reference to Dated Brent.
- Sales per boe decreased 14% in Q4 2015 versus Q3 2015,
consistent with a decrease in the Dated Brent reference price. This
decrease in sales per boe was more than offset by an increase in
sold volumes, resulting in a 22% increase in sales
- Year-over-year, sales on a dollar and on a per boe basis
decreased for the three months and year ended December 31, 2015, consistent with
decreases in Dated Brent reference price.
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 on a dollar basis remained relatively
consistent between Q3 and Q4 2015. The flat cost profile was
achieved while crude volumes sold increased by 42% as a result of
strong production growth and a 97,000 bbl inventory draw, which led
to increase recognition of deferred operating expense. A
continued focus on cost reduction initiatives resulted in reduced
helicopter and vessel costs, contributing to a 28% decrease in per
unit costs.
- Operating expense on a dollar basis decreased for the three
months and year ended December 31,
2015 versus 2014 due to cost-cutting initiatives, favourable
foreign exchange from a weaker Australian dollar during 2015, and
inventory variances. On a per boe basis, operating expense
decreased by 24% and 10% during the three months and year ended
2015 versus 2014 as a result of savings from cost reduction
initiatives undertaken in response to commodity price weakness -
these initiatives included reduced vessel usage, lower diesel
consumption, and reduced staffing costs.
General and administration
- Fluctuations in general and administration expense for Q4 2015
versus the comparable quarters is largely the result of the timing
of expenditures. Full year 2015 general and administration
expense was relatively consistent with 2014.
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.
- Australia is not expected to
incur any corporate income tax or PRRT for 2016. This 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 months
and full year ended December 31, 2015
were lower than the comparable periods as a result of decreased
revenues and increased capital spending in the 2015 periods.
Q4 2015 combined taxes were lower compared to Q3 2015 as increased
sales were offset by increased capital spending.
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 |
|
|
Year
Ended |
%
change |
United States business
unit |
Dec 31, |
Sep 30, |
Dec 31, |
Q4/15 vs. |
Q4/15 vs. |
|
|
Dec 31, |
Dec 31, |
2015 vs. |
($M except as indicated) |
2015 |
2015 |
2014 |
Q3/15 |
Q4/14 |
|
|
2015 |
2014 |
2014 |
Production |
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
420 |
226 |
195 |
86% |
115% |
|
|
231 |
49 |
371% |
|
NGLs (bbls/d) |
29 |
- |
- |
100% |
100% |
|
|
7 |
- |
100% |
|
Natural gas (mmcf/d) |
0.20 |
- |
- |
100% |
100% |
|
|
0.05 |
- |
100% |
|
Total (boe/d) |
483 |
226 |
195 |
114% |
148% |
|
|
247 |
49 |
404% |
Activity |
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
5,643 |
3,226 |
460 |
75% |
1,127% |
|
|
12,250 |
460 |
2,563% |
|
Acquisitions |
(21) |
12,785 |
- |
|
|
|
|
12,764 |
11,175 |
|
|
Gross wells drilled |
2.00 |
- |
- |
|
|
|
|
3.00 |
- |
|
|
Net wells drilled |
2.00 |
- |
- |
|
|
|
|
3.00 |
- |
|
|
Sales |
1,864 |
1,075 |
1,330 |
73% |
40% |
|
|
4,288 |
1,330 |
222% |
|
Royalties |
(551) |
(309) |
(366) |
78% |
51% |
|
|
(1,257) |
(366) |
243% |
|
Operating expense |
(271) |
(146) |
(241) |
86% |
12% |
|
|
(742) |
(241) |
208% |
|
General and administration |
(897) |
(896) |
(959) |
- |
(6%) |
|
|
(3,836) |
(959) |
300% |
|
Fund flows from operations |
145 |
(276) |
(236) |
153% |
161% |
|
|
(1,547) |
(236) |
556% |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
Sales |
41.94 |
51.60 |
74.08 |
(19%) |
(43%) |
|
|
47.53 |
74.08 |
(36%) |
|
Royalties |
(12.40) |
(14.83) |
(20.38) |
(16%) |
(39%) |
|
|
(13.93) |
(20.38) |
(32%) |
|
Operating expense |
(6.11) |
(6.98) |
(13.44) |
(12%) |
(55%) |
|
|
(8.23) |
(13.44) |
(39%) |
|
General and administration |
(20.18) |
(43.03) |
(53.44) |
(53%) |
(62%) |
|
|
(42.51) |
(53.44) |
(20%) |
|
Fund flows from operations netback |
3.25 |
(13.24) |
(13.18) |
125% |
125% |
|
|
(17.14) |
(13.18) |
30% |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl) |
42.18 |
46.43 |
73.15 |
(9%) |
(42%) |
|
|
48.80 |
93.00 |
(48%) |
|
WTI ($/bbl) |
56.32 |
60.80 |
83.08 |
(7%) |
(32%) |
|
|
62.41 |
102.75 |
(39%) |
|
Henry Hub (US $/mmbtu) |
2.27 |
2.77 |
4.00 |
(18%) |
(43%) |
|
|
2.66 |
4.41 |
(40%) |
|
Henry Hub ($/mmbtu) |
3.03 |
3.62 |
4.54 |
(16%) |
(33%) |
|
|
3.41 |
4.88 |
(30%) |
Activity review
- Vermilion drilled two (2.0
net) wells in the East Finn prospect area in Q4 2015 with well
completions planned for Q1 2016.
- In Q4 2015, we initiated sales of associated natural gas from
our East Finn wells, enabled by the completion of construction of a
gas gathering system in the area.
- During the year, 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.
- In 2016, we plan to drill one (1.0 net) well and tie-in an
additional two (2.0 net) wells drilled in Q4 2015.
Sales
- The price of crude oil in the United
States is directly linked to WTI, subject to market
conditions in the United
States.
Royalties
- Our production in the United
States is subject to federal and private royalties,
severance tax, and ad valorem tax.
- Royalties as a percentage of sales for the three months and
year ended December 31, 2015 of
approximately 29.6% was slightly higher than Q3 2015 (28.7%) and
the 2014 periods (27.5%) due to nominally higher royalty rates on
the well we brought online in August
2015.
Operating expense
- Operating expense decreased quarter-over-quarter by 12% from
$6.98/boe to $6.11/boe.
General and administration
- General and administration expense was relatively consistent
quarter-over-quarter. Full year 2015 expenditures were higher
than 2014 due to the timing of the formation of the US business
unit in Q4 2014.
CORPORATE
Overview
- Our Corporate segment includes costs related to our global
hedging program, financing expenses, and general and administration
expenses, primarily incurred in Canada and not directly related to the
operations of our business units.
Financial review
|
Three
Months Ended |
|
|
Year
Ended |
|
Dec 31, |
Sep 30, |
Dec 31, |
|
|
Dec 31, |
Dec 31, |
($M) |
2015 |
2015 |
2014 |
|
|
2015 |
2014 |
General and administration recovery (expense) |
3,356 |
2,359 |
1,224 |
|
|
7,172 |
(7,423) |
Current income taxes |
313 |
(480) |
(642) |
|
|
(1,091) |
(1,420) |
Interest expense |
(16,584) |
(15,420) |
(12,943) |
|
|
(59,852) |
(49,655) |
Realized gain on derivatives |
21,164 |
10,854 |
22,816 |
|
|
41,356 |
36,712 |
Realized foreign exchange (loss) gain |
(252) |
309 |
(179) |
|
|
623 |
(821) |
Realized other income |
243 |
227 |
202 |
|
|
896 |
732 |
Fund flows from operations |
8,240 |
(2,151) |
10,478 |
|
|
(10,896) |
(21,875) |
General and administration
- The increase in the recovery of general and administration
costs for the three months and year ended December 31, 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 Q4 2015 versus all
comparable periods is primarily due to increased average borrowings
under our revolving credit facility. In addition, interest
expense for the three months and year ended December 31, 2015 versus the comparable periods
in 2014 was higher due to interest expense related to a 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 Q4 2015 related primarily to amounts
received on our TTF, WTI, and Dated Brent derivatives, partially
offset by payments made on our foreign exchange derivatives.
- A listing of derivative positions as at December 31, 2015 is included in "Supplemental
Table 2" of this MD&A.
FINANCIAL PERFORMANCE REVIEW
|
|
|
|
|
|
Year
Ended |
|
|
|
|
|
|
Dec 31, |
Dec 31, |
Dec 31, |
($M except per share) |
|
|
|
|
|
2015 |
2014 |
2013 |
Total assets |
|
|
|
|
|
4,209,220 |
4,386,091 |
3,708,719 |
Long-term debt |
|
|
|
|
|
1,162,998 |
1,238,080 |
990,024 |
Petroleum and natural gas sales |
|
|
|
|
|
939,586 |
1,419,628 |
1,273,835 |
Net earnings (loss) |
|
|
|
|
|
(217,302) |
269,326 |
327,641 |
Net earnings (loss) per share |
|
|
|
|
|
|
|
|
|
Basic |
|
|
|
|
|
(1.98) |
2.55 |
3.24 |
|
Diluted |
|
|
|
|
|
(1.98) |
2.51 |
3.20 |
Cash dividends ($/share) |
|
|
|
|
|
2.58 |
2.58 |
2.40 |
|
|
|
|
|
|
|
|
|
|
Three
Months Ended |
|
Dec 31, |
Sep 30, |
Jun 30, |
Mar 31, |
Dec 31, |
Sep 30, |
Jun 30, |
Mar 31, |
($M except per share) |
2015 |
2015 |
2015 |
2015 |
2014 |
2014 |
2014 |
2014 |
Petroleum and natural gas sales |
234,319 |
245,051 |
264,331 |
195,885 |
306,073 |
344,688 |
387,684 |
381,183 |
Net earnings (loss) |
(142,080) |
(83,310) |
6,813 |
1,275 |
58,642 |
53,903 |
53,993 |
102,788 |
Net earnings (loss) per share |
|
|
|
|
|
|
|
|
|
Basic |
(1.28) |
(0.76) |
0.06 |
0.01 |
0.55 |
0.50 |
0.51 |
1.00 |
|
Diluted |
(1.28) |
(0.76) |
0.06 |
0.01 |
0.54 |
0.50 |
0.50 |
0.99 |
The following table shows a reconciliation of
the change in net earnings (loss):
($M) |
Q4/15 vs. Q3/15 |
Q4/15 vs. Q4/14 |
2015 vs. 2014 |
Net earnings (loss) - Comparative
period |
(83,310) |
58,642 |
269,326 |
Changes in: |
|
|
|
Fund flows from operations |
7,006 |
(49,087) |
(288,698) |
Equity based compensation |
(4,760) |
(3,140) |
(7,430) |
Unrealized gain or loss on derivative
instruments |
(4,627) |
10,236 |
16,177 |
Unrealized foreign exchange gain or loss |
(21,315) |
(2,371) |
26,386 |
Unrealized other expense |
75 |
511 |
484 |
Accretion |
(125) |
(137) |
2 |
Depletion and depreciation |
41,031 |
9,369 |
(33,064) |
Deferred tax |
(87,432) |
(34,480) |
74,138 |
Impairment |
11,377 |
(131,623) |
(274,623) |
Net loss - Current period |
(142,080) |
(142,080) |
(217,302) |
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 for the three
months and year ended December 31,
2015 was higher versus the comparable periods in 2014 due to
a higher average number of awards outstanding and higher grant
value.
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 year ended December 31, 2015, we recognized an unrealized
gain on derivative instruments of $43.5
million, relating primarily to our TTF, Dated Brent, and WTI
swaps and collars. As at December 31,
2015, we have a net derivative asset position of
$68.3 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 and US
dollar denominated financial liabilities. As such, an
appreciation in the Euro against the Canadian dollar will result in
an unrealized foreign exchange gain while an appreciation in the US
dollar against the Canadian dollar will result in an unrealized
foreign exchange loss (and vice-versa).
For the three months ended December 31, 2015, the Canadian dollar weakened
against the US dollar and remained relatively flat against the
Euro, leading to an unrealized foreign exchange loss of
$6.4 million. During the year ended
December 31, 2015, the Canadian
dollar weakened significantly versus the US dollar, but was offset
by a strengthening in the Canadian dollar against the Euro
resulting in an unrealized foreign exchange gain of $8.8 million.
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.
Q4 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 Q4 2015 of $18.88 was lower as
compared to $28.28 in Q3 2015 and
$24.42 for Q4 2014. This
decrease is primarily due to increased production natural gas
properties in Drayton Valley,
Canada which have a lower per boe depletion expense. For the
year ended December 31, 2015,
depletion and depreciation on a per boe basis of $22.98 was relatively consistent with
$23.31 for the comparable period in
2014 as increased production from natural gas properties in
the Netherlands and light crude
oil properties in Saskatchewan,
Canada, which both have relatively higher per boe depletion
expense, was offset with higher production from natural gas
properties in Drayton Valley,
Canada, which have a relatively lower per boe depletion
expense.
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 $274.6
million impairment charge recorded in 2015, increased
accounting basis depletion primarily associated with higher global
production, partially offset by a valuation allowance recorded on
deferred tax assets. The valuation allowance relates to
certain non-capital losses for which there is uncertainty as to the
Company's ability to fully utilize such losses when applying
forecasted commodity prices in effect as at December 31, 2015.
Impairment
For the three months and year ended December
31, 2015, Vermilion
recorded impairment charges of $131.6
million and $274.6 million,
respectively, related to the light crude oil play in Saskatchewan, Canada ($267.9 million in 2015) and the shallow coal bed
methane gas properties in Alberta,
Canada ($6.7 million in
2015). These impairment charges were a result of declines in
the price forecasts for crude oil and natural gas in Canada which decreased the expected future
cash flows from the CGU.
TAXES
Corporate income tax rates
Vermilion pays corporate income
taxes in France, the Netherlands, and Australia. In addition, Vermilion pays PRRT in Australia. PRRT is a profit based tax
applied at a rate of 40% on sales less operating expenses, capital
expenditures, and other eligible expenditures. PRRT is
deductible in the calculation of taxable income in Australia.
Taxable income was subject to corporate income tax at the
following rates:
Jurisdiction |
2015 |
2014 |
Canada (1) |
25.5% / 27.0% |
25.5% |
France |
34.4% |
34.4% |
Netherlands |
46.0% |
46.0% |
Germany |
24.2% |
22.8% |
Ireland |
25.0% |
25.0% |
Australia |
30.0% |
30.0% |
United States |
35.0% |
35.0% |
(1) Alberta corporate income tax rates increased
from 10% to 12% effective July 1, 2015. |
In 2012, the France government enacted a new 3% tax on
dividend distributions made by entities subject to corporate income
tax in France. The tax applies to
any dividends paid on or after April 17,
2012 and is not recovered by any tax treaties or deductible
for French corporate income tax purposes. Vermilion did not pay any dividends from its
French entities in 2015.
Tax pools
As at December 31, 2015, we had the
following tax pools:
($M) |
Oil & Gas Assets |
|
Tax Losses
(4) |
Other |
Total |
Canada |
1,176,574 (1) |
|
341,445 |
2,448 |
1,520,467 |
France |
430,735 (2) |
|
14,171 |
- |
444,906 |
Netherlands |
54,104 (3) |
|
- |
- |
54,104 |
Germany |
112,038 (3) |
|
43,360 |
18,977 |
174,375 |
Ireland |
1,028,986 (4) |
|
429,987 |
- |
1,458,973 |
Australia |
265,743 (1) |
|
- |
- |
265,743 |
United States |
28,950 (1) |
|
15,767 |
- |
44,717 |
Total |
3,097,130 (1) |
|
844,730 |
21,425 |
3,963,285 |
(1) |
Deduction calculated using various declining
balance rates |
(2) |
Deduction calculated using a combination of
straight-line over the assets life and unit of production
method |
(3) |
Deduction calculated using a unit of production
method |
(4) |
Deduction for current development expenditures and
tax losses at 100% against taxable income |
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. When prices trend higher, we may target a lower
ratio and conversely, in a lower commodity price environment, the
debt ratio may prove to 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 by aligning capital expenditures within
forecasted fund flows from operations, which is continually
monitored for revised forward price estimates, as well as by
hedging additional European natural gas volumes to maintain a
diversified commodity portfolio.
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 |
|
Dec 31, |
Dec 31, |
|
|
Dec 31, |
Dec 31, |
($M) |
2015 |
2014 |
|
|
2015 |
2014 |
Revolving credit facility |
3.1% |
3.1% |
|
|
1,162,998 |
1,014,067 |
Senior unsecured notes (1) |
6.5% |
6.5% |
|
|
224,901 |
224,013 |
Long-term debt |
3.7% |
3.8% |
|
|
1,387,899 |
1,238,080 |
(1) |
The senior unsecured notes, which
matured on February 10, 2016, are included in the current portion
of long-term debt as at December 31, 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. This allowed Vermilion to redeem the senior unsecured
notes, which matured on February 10,
2016, with a portion of the credit facility. 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 |
|
Dec 31, |
Dec 31, |
|
2015 |
2014 |
Total facility amount |
$2.0 billion |
$1.5 billion |
Amount drawn |
$1.2 billion |
$1.0 billion |
Letters of credit outstanding |
$25.2 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 |
|
|
Dec 31, |
Dec 31, |
Financial covenant |
Limit |
2015 |
2014 |
Consolidated total debt to consolidated
EBITDA |
4.0 |
2.23 |
1.21 |
Consolidated total senior debt to consolidated
EBITDA |
3.0 |
1.83 |
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 "Shareholders' equity" plus consolidated total debt
as defined above.
Vermilion was
in compliance with its financial covenants for all periods
presented.
Senior Unsecured Notes
As at December 31, 2015, we had
outstanding senior unsecured notes that were senior unsecured
obligations and ranked pari passu with all our unsecured and
unsubordinated indebtedness. The following table outlines the
terms of these notes:
|
|
Total issued and outstanding amount |
$225.0 million |
Interest rate |
6.5% per annum |
Issued date |
February 10, 2011 |
Maturity date |
February 10, 2016 |
Vermilion
redeemed the full principal outstanding of the notes on
February 10, 2016 using available
capacity under the revolving credit facility. The notes were
initially recognized at fair value net of transaction costs and
were subsequently measured at amortized cost using an effective
interest rate of 7.1%.
Net debt
Net debt is reconciled to its most directly comparable GAAP
measure, long-term debt, as follows:
|
As
at |
|
Dec 31, |
Dec 31, |
($M) |
2015 |
2014 |
Long-term debt |
1,162,998 |
1,238,080 |
Current liabilities (1) |
503,731 |
365,729 |
Current assets |
(284,778) |
(338,159) |
Net debt |
1,381,951 |
1,265,650 |
|
|
|
Ratio of net debt to fund flows from
operations |
2.7 |
1.6 |
(1) |
Includes the current
portion of long-term debt, which, as at December 31, 2015,
represented the senior unsecured notes that matured on February 10,
2016. |
Long term debt, including the current portion,
as at December 31, 2015, increased to
$1.39 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, France, Ireland, and Australia. The increase in long-term
debt resulted in an increase to net debt from $1.27 billion to $1.38
billion. As a result of this increase to long-term
debt 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 year ended December 31, 2015.
Shareholders' capital
During the year ended December 31,
2015, we maintained monthly dividends at $0.215 per share and declared dividends which
totalled $283.6 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. As a
further step to preserve our financial flexibility and
conservatively exercise our access to capital, we amended our
existing DRIP to include a Premium Dividend™ Component 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 reduced or eliminated 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 |
|
3,338 |
|
155,033 |
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 |
|
57 |
|
2,619 |
Balance as at December 31, 2015 |
|
111,991 |
|
2,181,089 |
As at December 31,
2015, there were approximately 1.7 million VIP awards
outstanding. As at February 25,
2016, there were approximately 113.0 million common shares
issued and outstanding.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
As at December 31, 2015, we had
the following contractual obligations and commitments:
($M) |
Less than 1 year |
1 - 3 years |
3 - 5 years |
After 5 years |
Total |
Long-term debt |
226,625 |
- |
1,171,620 |
- |
1,398,245 |
Operating lease obligations |
12,535 |
22,049 |
16,617 |
9,288 |
60,489 |
Ship or pay agreement relating to the Corrib
project |
8,215 |
8,893 |
7,292 |
40,446 |
64,846 |
Purchase obligations |
17,897 |
4,071 |
3,156 |
- |
25,124 |
Drilling and service agreements |
23,205 |
2,480 |
- |
- |
25,685 |
Total contractual obligations and commitments |
288,477 |
37,493 |
1,198,685 |
49,734 |
1,574,389 |
ASSET RETIREMENT OBLIGATIONS
As at December 31,
2015, asset retirement obligations were $305.6 million compared to $350.8 million as at December 31, 2014.
The decrease in asset retirement obligations is
largely attributable to an overall increase in the discount rates
applied to the abandonment obligations.
RISKS AND UNCERTAINTIES
Crude oil and natural gas exploration,
production, acquisition and marketing operations involve a number
of risks and uncertainties including financial risks and
uncertainties. These include fluctuations in commodity
prices, exchange rates and interest rates as well as uncertainties
associated with reserve and resource volumes, sales volumes and
government regulatory and income tax regime changes. These
and other related risks and uncertainties are discussed in
additional detail below.
Commodity prices
Our operational results and financial condition is dependent on the
prices received for crude oil and natural gas production. Crude oil
and natural gas prices have fluctuated significantly during recent
years and are determined by supply and demand factors, including
weather and general economic conditions as well as conditions in
other crude oil and natural gas producing regions.
Exchange rates
Much of our revenue stream is priced in U.S. dollars and as such an
increase in the strength of the Canadian dollar relative to the
U.S. dollar may result in the receipt of fewer Canadian dollars
with respect to our production. In addition, we incur expenses and
capital costs in U.S. dollars, Euros and Australian dollars and
accordingly, the Canadian dollar equivalent of these expenditures
as reported in our financial results is impacted by the prevailing
exchange rates at the time the transaction occurs. We monitor risks
associated with exchange rates and, when appropriate, use
derivative financial instruments to manage our exposure to these
risks.
Production and sales volumes
The operation of crude oil and natural gas wells and facilities
involves a number of operating and natural hazards which may result
in blowouts, environmental damage and other unexpected or dangerous
conditions resulting in damage to us and possible liability to
third parties. We maintain liability insurance, where
available, in amounts consistent with industry standards. Business
interruption insurance may also be purchased for selected
operations, to the extent that such insurance is commercially
viable. We may become liable for damages arising from such events
against which we cannot insure or against which we may elect not to
insure because of high premium costs or other reasons. Costs
incurred to repair such damage or pay such liabilities may
materially impact our financial results.
Continuing production from a property, and to
some extent the marketing of produced volumes, is largely dependent
upon the ability of the operator of the property. To the extent the
operator fails to perform these functions properly, revenue may be
reduced. Payments from production generally flow through the
operator and there is a risk of delay and additional expense in
receiving such revenues if the operator becomes insolvent. Although
satisfactory title reviews are generally conducted in accordance
with industry standards, such reviews do not guarantee or certify
that a defect in the chain of title may not arise to defeat our
claim to certain properties. Such circumstances could negatively
affect our financial results.
An increase in operating costs or a decline in
our production level could have an adverse effect on our financial
results. The level of production may decline at rates greater than
anticipated due to unforeseen circumstances, many of which are
beyond our control. A significant decline in production could
result in materially lower revenues.
Interest rates
An increase in interest rates could result in a significant
increase in the amount we pay to service debt.
Reserve volumes
Our reserve volumes and related reserve values support the carrying
value of our crude oil and natural gas assets on the consolidated
balance sheets and provide the basis to calculate the depletion of
those assets. There are numerous uncertainties inherent in
estimating quantities of reserves and future net revenues to be
derived therefrom, including many factors beyond our control. These
include a number of assumptions relating to factors such as initial
production rates, production decline rates, ultimate recovery of
reserves, timing and amount of capital expenditures, marketability
of production, future prices of crude oil, NGLs and natural gas,
operating expenses, well abandonment and salvage values, royalties
and any government levies that may be imposed over the producing
life of the reserves. These assumptions were based on estimated
prices in use at the date the evaluation was prepared, and many of
these assumptions are subject to change and are beyond our
control. Actual production and income derived therefrom will
vary from these evaluations, and such variations could be
material.
Asset retirement obligations
Our asset retirement obligations are based on environmental
regulations and estimates of future costs and the timing of
expenditures. Changes in environmental regulations, the
estimated costs associated with reclamation activities and the
related timing may impact our financial position and results of
operations.
Government regulation and income tax regime
Our operations are governed by many levels of government, including
municipal, state, provincial and federal governments, in
Canada, France, the
Netherlands, Australia,
Germany, Ireland and the
United States. We are subject to laws and regulations
regarding environment, health and safety issues, lease interests,
taxes and royalties, among others. Failure to comply with the
applicable laws can result in significant increases in costs,
penalties and even losses of operating licences. The regulatory
process involved in each of the countries in which we operate is
not uniform and regulatory regimes vary as to complexity,
timeliness of access to, and response from, regulatory bodies and
other matters specific to each jurisdiction. If regulatory
approvals or permits are delayed or not obtained, there can also be
delays or abandonment of projects and decreases in production and
increases in costs, potentially resulting in us being unable to
fully execute our strategy. Governments may also amend or create
new legislation and regulatory bodies may also amend regulations or
impose additional requirements which could result in increased
capital, operating and compliance costs.
There can be no assurance that income tax laws
and government incentive programs relating to the crude oil and
natural gas industry in Canada and
the foreign jurisdictions in which we operate, will not be changed
in a manner which adversely affects the results of our
operations.
A change in the royalty regime resulting in an
increase in royalties would reduce our net earnings and could make
future capital expenditures or our operations uneconomic and could,
in the event of a material increase in royalties, make it more
difficult to service and repay outstanding debt. Any material
increase in royalties would also significantly reduce the value of
the associated assets.
FINANCIAL RISK MANAGEMENT
To mitigate the aforementioned risks whenever
possible, we seek to hire personnel with experience in specific
areas. In addition, we provide continued training and development
to staff to further develop their skills. When appropriate, we use
third party consultants with relevant experience to augment our
internal capabilities with respect to certain risks.
We consider our commodity price risk management
program as a form of insurance that protects our cash flow and rate
of return. The primary objective of the risk management program is
to support our dividends and our internal capital development
program. The level of commodity price risk management that occurs
is highly dependent on the amount of debt that is carried. When
debt levels are higher, we will be more active in protecting our
cash flow stream through our commodity price risk management
strategy.
When executing our commodity price risk
management programs, we use derivative financial instruments
encompassing over-the-counter financial structures as well as
fixed/collar structures to economically hedge a part of our
physical crude oil and natural gas production. We have strict
controls and guidelines in relation to these activities and
contract principally with counterparties that have investment grade
credit ratings.
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 our consolidated financial
statements or financial performance. Estimates are reviewed
by management on an ongoing basis, and as a result, certain
estimates 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 in which we
operate, the critical accounting estimates may affect one or more
jurisdictions.
The following discussion outlines what
management believes to be the most critical accounting policies
involving the use of estimates and assumptions.
Depletion and depreciation
We classify our assets into depletion units, which are groups of
assets or properties that are within a specific production area and
have similar economic lives. The depletion units represent
the lowest level of disaggregation for which we accumulate costs
for the purposes of calculating and recording depletion and
depreciation.
The net carrying value of each depletion unit is
depleted using the unit of production method by reference to the
ratio of production in the period to the total proven and probable
reserves, taking into account the future development costs
necessary to bring the applicable reserves into production.
As a result, depletion and depreciation charges are based on
estimates of total proven and probable reserves that we expect to
recover in the future. The reserve estimates are reviewed annually
by management or when material changes occur to the underlying
assumptions.
Asset retirement obligations
Our estimate of asset retirement obligations are based on past
experience and current economic factors which management believes
are reasonable. The estimates include assumptions of environmental
regulations, legal requirements, technological advances, inflation
and the timing of expenditures, all of which impact our measurement
of the present value of the obligations. Due to these
estimates, the actual cost of the obligation may change from period
to period due to new information being available. Several or
all of these estimates are subject to change and such changes could
have a material impact on our financial position and net
earnings.
Assessment of impairments
Impairment tests are performed at the level of the cash generating
unit ("CGU"), which are determined based on management's judgment
of the lowest level at which there are identifiable cash inflows
which are largely independent of the cash inflows of other groups
of assets or properties. The factors used to determine CGUs
vary by country due to the unique operating and geographic
circumstances in each jurisdiction. However, in general, we
will assess the following factors in determining whether a group of
assets generate largely independent cash inflows: geographic
proximity of the assets within a group to one another, geographic
proximity of the group of assets to other groups of assets,
homogeneity of the production from the group of assets and the
sharing of infrastructure used to process or transport
production.
The calculation of the recoverable amount of
CGUs is based on market factors as well as estimates of reserves
and resources and future costs required to develop reserves and
resources. Our reserve and resource estimates and the related
future cash flows are subject to measurement uncertainty, and the
impact on the consolidated financial statements in future periods
could be material. Considerable judgment is used in
determining the recoverable amount of petroleum and natural gas
assets as well as exploration and evaluation assets, including
determining the quantity of reserves and resources, the time
horizon to develop and produce such reserves and resources, and the
estimated revenues and expenditures from such production.
Taxes
Tax interpretations, regulations and legislation in the various
jurisdictions in which we operate are subject to change. Such
changes can affect the timing of the reversal of temporary tax
differences, the tax rates in effect when such differences reverse
and our ability to use tax losses and other credits in the
future. The determination of deferred tax amounts recognized
in the consolidated financial statements was based on management's
assessment of the tax positions, including consideration of their
technical merits and communications with tax authorities. The
effect of a change in income tax rates or legislation on tax assets
and liabilities is recognized in net earnings in the period in
which the change is enacted.
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 December 31, 2015.
We have not entered into any guarantee or off
balance sheet arrangements that would materially impact our
financial position or results of operations.
ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
The impacts of the adoption of the following
pronouncements are currently being evaluated.
IFRS 9 "Financial Instruments"
On July 24, 2014, the IASB issued the
final element of its comprehensive response to the financial crisis
by issuing IFRS 9 "Financial Instruments". The improvements
introduced by IFRS 9 includes a model for classification and
measurement, a single, forward-looking 'expected loss' impairment
model and a substantially-reformed approach to hedge
accounting. Vermilion will
adopt the standard for reporting periods beginning January 1, 2018.
IFRS 15 "Revenue from Contracts with
Customers"
On May 28, 2014, the IASB issued IFRS
15 "Revenue from Contracts with Customers", a new standard that
specifies recognition requirements for revenue as well as requiring
entities to provide the users of financial statements with more
informative and relevant disclosures. The standard replaces
IAS 11 "Construction Contracts" and IAS 18 "Revenue" as well as a
number of revenue-related interpretations. Vermilion will adopt the standard for
reporting periods beginning January 1,
2018.
IFRS 16 "Leases"
On January 13, 2016, the IASB issued
IFRS 16, "Leases", a new standard which will replace IAS 17,
"Leases". Under IFRS 16, a single recognition and measurement
model will apply for lessees which will require recognition of
assets and liabilities for most leases. Vermilion will adopt the standard for
reporting periods beginning January 1,
2019.
HEALTH, SAFETY AND ENVIRONMENT
We are committed to ensuring we conduct our
activities in a manner that will protect the health and safety of
our employees, contractors, and the public. Our health,
safety, and environment ("HSE") vision is to fully integrate
health, safety, and environment into our business, where our
culture is recognized as a model by industry and stakeholders,
resulting in a workplace free of incidents. Our mantra is HSE:
Everywhere. Everyday. Everyone.
We maintain health, safety and environmental
practices and procedures that comply with or exceed regulatory
requirements and industry standards. It is a condition of
employment that our personnel work safely and in accordance with
established regulations and procedures.
In 2015, we remained committed to the principles
of the Responsible Canadian Energy™ program set out by the Canadian
Association of Petroleum Producers. Responsible Canadian
Energy™ is an association-wide performance reporting program to
demonstrate progress in environmental, health, safety, and social
performance.
We uphold our commitment to keep our people safe
and to reduce impacts to land, water and air, as policies and
procedures demonstrating leadership in these areas, were maintained
and further developed in 2015. Examples of our
accomplishments during the year included:
- Maintained clear priorities around 5 key focus areas of HSE
Culture, Communication and Knowledge Management, Technical Safety
Management, Incident Prevention and Operational Stewardship &
Sustainability;
- Completed and published our Corporate Sustainability
Report;
- Reported our CO2e emissions to the Carbon Disclosure
Project, achieving a 100% score and a CDLI ranking;
- Emphasized improving energy efficiency, greenhouse gas
emissions reduction and water efficiency optimization;
- Further refined and expanded our enterprise wide corporate risk
register;
- Developed a robust organizational wide HSE leadership training
program to improve hazard identification and risk reduction;
- Implemented a fair culture policy to ensure transparency in our
processes;
- Developed a robust risk mitigation program around our top fatal
risk and energy type exposures;
- Developed a robust hazard identification and risk mitigation
program specific to environmentally sensitive areas;
- Audited our HSE and asset integrity management systems;
- Updated various key Corporate HSE Standards such as our process
hazards analysis;
- Reduced long-term environmental liabilities through
decommissioning, abandoning and reclaiming well leases and
facilities;
- Performed continuous auditing, management inspections and
workforce observations to identify potential hazards and apply risk
reduction measures;
- Developed, communicated and measured against leading and
lagging HSE key performance indicators;
- Further enhanced of our competency and training programs;
- Managed our waste products by reducing, recycling and
recovering; and
- Continued risk management efforts in addition to detailed
emergency-response planning.
We are a member of several organizations
concerned with environment, health and safety, including numerous
regional co-operatives and synergy groups. In the area of
stakeholder relations, we work to build long-term relationships
with environmental stakeholders and communities.
CORPORATE GOVERNANCE
We are committed to a high standard of corporate
governance practices, a dedication that begins at the Board level
and extends throughout the Company. We believe good corporate
governance is in the best interest of our shareholders, and that
successful companies are those that deliver growth and a
competitive return along with a commitment to the environment, to
the communities where they operate and to their employees.
We comply with the objectives and guidelines
relating to corporate governance adopted by the Canadian Securities
Administrators and the Toronto Stock Exchange. In addition,
the Board monitors and considers the implementation of corporate
governance standards proposed by various regulatory and
non-regulatory authorities in Canada. A discussion of corporate
governance policies will be provided in our Management Proxy
Circular, which will be filed on SEDAR (www.sedar.com) and mailed
to all shareholders on April 6,
2016.
A summary of the significant differences between
the governance practices of the Company and those required of U.S.
domestic companies under the New York Stock Exchange listing
standards can be found in the Governance section of the Company's
website at http://www.vermilionenergy.com/about/governance.cfm.
DISCLOSURE CONTROLS AND PROCEDURES
Our officers have established and maintained
disclosure controls and procedures and evaluated the effectiveness
of these controls in conjunction with our filings.
As of December 31,
2015, we have evaluated the effectiveness of the design and
operation of our disclosure controls and procedures. Based on
this evaluation, the Chief Executive Officer and Chief Financial
Officer have concluded and certified that our disclosure controls
and procedures are effective.
INTERNAL CONTROL OVER FINANCIAL REPORTING
A company's internal control over financial
reporting is a process to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A company's
internal control over financial reporting includes those policies
and procedures that (1) pertain to the maintenance of records that,
in reasonable detail, accurately and fairly reflect the
transactions of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of
management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company's assets that could
have a material effect on the financial statements.
The Chief Executive Officer and the Chief
Financial Officer of Vermilion
have assessed the effectiveness of Vermilion's internal control over financial
reporting as defined in Rule 13a-15 under the US Securities
Exchange Act of 1934 and as defined in Canada by National Instrument 52-109,
Certification of Disclosure in Issuers' Annual and Interim
Filings. The assessment was based on the framework in
Internal Control - Integrated Framework (2013) issued by the
Committee of Sponsoring Organizations of the Treadway Commission.
The Chief Executive Officer and the Chief Financial Officer of
Vermilion have concluded that
Vermilion's internal control over
financial reporting was effective as of December 31, 2015. The effectiveness of
Vermilion's internal control over
financial reporting as of December 31,
2015 has been audited by Deloitte LLP, as reflected in their
report included in the 2015 audited annual financial statements
filed with the US Securities and Exchange Commission. No
changes were made to Vermilion's
internal control over financial reporting during the year ended
December 31, 2015, that have
materially affected, or are reasonably likely to materially affect,
the internal controls 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 December 31,
2015 |
|
Year Ended December 31, 2015 |
|
|
Three Months
Ended
December 31,
2014 |
|
Year Ended
December 31,
2014 |
|
Oil & NGLs |
Natural Gas |
Total |
|
Oil & NGLs |
Natural Gas |
Total |
|
|
Total |
|
Total |
|
$/bbl |
$/mcf |
$/boe |
|
$/bbl |
$/mcf |
$/boe |
|
|
$/boe |
|
$/boe |
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
44.03 |
2.57 |
28.94 |
|
49.73 |
2.78 |
34.32 |
|
|
51.27 |
|
64.06 |
Royalties |
(5.15) |
(0.12) |
(2.80) |
|
(5.26) |
(0.07) |
(3.01) |
|
|
(7.12) |
|
(7.81) |
Transportation |
(2.04) |
(0.16) |
(1.48) |
|
(2.38) |
(0.17) |
(1.75) |
|
|
(1.57) |
|
(1.74) |
Operating |
(10.97) |
(1.40) |
(9.62) |
|
(10.47) |
(1.41) |
(9.54) |
|
|
(8.80) |
|
(9.07) |
Operating netback |
25.87 |
0.89 |
15.04 |
|
31.62 |
1.13 |
20.02 |
|
|
33.78 |
|
45.44 |
General and administration |
|
|
(1.44) |
|
|
|
(1.81) |
|
|
(1.29) |
|
(2.00) |
Fund flows from operations
netback |
|
|
13.60 |
|
|
|
18.21 |
|
|
32.49 |
|
43.44 |
France |
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
54.88 |
2.81 |
54.20 |
|
63.31 |
2.52 |
62.67 |
|
|
79.25 |
|
105.43 |
Royalties |
(6.23) |
(0.32) |
(6.15) |
|
(6.06) |
(0.33) |
(6.00) |
|
|
(6.07) |
|
(6.95) |
Transportation |
(3.72) |
- |
(3.65) |
|
(3.47) |
- |
(3.42) |
|
|
(3.94) |
|
(4.64) |
Operating |
(13.55) |
(1.81) |
(13.50) |
|
(11.34) |
(1.31) |
(11.30) |
|
|
(13.01) |
|
(15.09) |
Operating netback |
31.38 |
0.68 |
30.90 |
|
42.44 |
0.88 |
41.95 |
|
|
56.23 |
|
78.75 |
General and administration |
|
|
(4.18) |
|
|
|
(4.50) |
|
|
(3.62) |
|
(5.12) |
Other income |
|
|
- |
|
|
|
7.08 |
|
|
- |
|
- |
Current income taxes |
|
|
3.87 |
|
|
|
(5.29) |
|
|
(5.89) |
|
(16.36) |
Fund flows from operations netback |
|
|
30.59 |
|
|
|
39.24 |
|
|
46.72 |
|
57.27 |
Netherlands |
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
48.30 |
7.09 |
42.61 |
|
49.98 |
7.79 |
46.77 |
|
|
52.07 |
|
52.65 |
Royalties |
- |
(0.04) |
(0.26) |
|
- |
(0.19) |
(1.12) |
|
|
(2.40) |
|
(2.13) |
Operating |
- |
(1.21) |
(7.17) |
|
- |
(1.39) |
(8.24) |
|
|
(12.70) |
|
(10.22) |
Operating netback |
48.30 |
5.84 |
35.18 |
|
49.98 |
6.21 |
37.41 |
|
|
36.97 |
|
40.30 |
General and administration |
|
|
(0.93) |
|
|
|
(1.51) |
|
|
(5.10) |
|
(1.54) |
Current income taxes |
|
|
(3.35) |
|
|
|
(4.40) |
|
|
4.35 |
|
(1.77) |
Fund flows from operations netback |
|
|
30.90 |
|
|
|
31.50 |
|
|
36.22 |
|
36.99 |
Germany |
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
- |
6.61 |
39.68 |
|
- |
7.18 |
43.10 |
|
|
49.19 |
|
46.03 |
Royalties |
- |
(0.78) |
(4.70) |
|
- |
(1.12) |
(6.75) |
|
|
(9.13) |
|
(9.45) |
Transportation |
- |
(0.34) |
(2.05) |
|
- |
(0.57) |
(3.41) |
|
|
(0.80) |
|
(2.60) |
Operating |
- |
(3.22) |
(19.31) |
|
- |
(1.90) |
(11.41) |
|
|
(10.54) |
|
(9.53) |
Operating netback |
- |
2.27 |
13.62 |
|
- |
3.59 |
21.53 |
|
|
28.72 |
|
24.45 |
General and administration |
|
|
(12.22) |
|
|
|
(7.69) |
|
|
(8.10) |
|
(5.14) |
Current income taxes |
|
|
- |
|
|
|
- |
|
|
4.21 |
|
(0.05) |
Fund flows from operations netback |
|
|
1.40 |
|
|
|
13.84 |
|
|
24.83 |
|
19.26 |
Australia |
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
58.74 |
- |
58.74 |
|
70.22 |
- |
70.22 |
|
|
90.37 |
|
113.80 |
Operating |
(17.08) |
- |
(17.08) |
|
(22.29) |
- |
(22.29) |
|
|
(22.56) |
|
(24.66) |
PRRT (1) |
(1.29) |
- |
(1.29) |
|
(2.97) |
- |
(2.97) |
|
|
(17.28) |
|
(24.22) |
Operating netback |
40.37 |
- |
40.37 |
|
44.96 |
- |
44.96 |
|
|
50.53 |
|
64.92 |
General and administration |
|
|
(2.17) |
|
|
|
(2.48) |
|
|
(2.07) |
|
(2.36) |
Corporate income taxes |
|
|
1.47 |
|
|
|
(3.12) |
|
|
(6.11) |
|
(9.83) |
Fund flows from operations netback |
|
|
39.67 |
|
|
|
39.36 |
|
|
42.35 |
|
52.73 |
United States |
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
44.83 |
0.52 |
41.94 |
|
49.10 |
0.52 |
47.53 |
|
|
74.08 |
|
74.08 |
Royalties |
(13.19) |
(0.30) |
(12.40) |
|
(14.36) |
(0.30) |
(13.93) |
|
|
(20.38) |
|
(20.38) |
Operating |
(6.56) |
- |
(6.11) |
|
(8.52) |
- |
(8.23) |
|
|
(13.44) |
|
(13.44) |
Operating netback |
25.08 |
0.22 |
23.43 |
|
26.22 |
0.22 |
25.37 |
|
|
40.26 |
|
40.26 |
General and administration |
|
|
(20.18) |
|
|
|
(42.51) |
|
|
(53.44) |
|
(53.44) |
Fund flows from operations netback |
|
|
3.25 |
|
|
|
(17.14) |
|
|
(13.18) |
|
(13.18) |
Total Company |
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
51.64 |
4.55 |
41.04 |
|
58.80 |
4.98 |
47.07 |
|
|
63.79 |
|
77.75 |
Realized hedging gain |
2.69 |
0.84 |
3.71 |
|
1.32 |
0.53 |
2.07 |
|
|
4.76 |
|
2.01 |
Royalties |
(4.32) |
(0.16) |
(2.85) |
|
(4.58) |
(0.24) |
(3.30) |
|
|
(5.41) |
|
(5.92) |
Transportation |
(2.09) |
(0.23) |
(1.78) |
|
(2.30) |
(0.30) |
(2.09) |
|
|
(1.98) |
|
(2.32) |
Operating |
(13.35) |
(1.52) |
(11.50) |
|
(13.06) |
(1.46) |
(11.32) |
|
|
(12.48) |
|
(12.72) |
PRRT (1) |
(0.33) |
- |
(0.18) |
|
(0.58) |
- |
(0.34) |
|
|
(2.83) |
|
(3.30) |
Operating netback |
34.24 |
3.48 |
28.44 |
|
39.60 |
3.51 |
32.09 |
|
- |
45.85 |
- |
55.50 |
General and administration |
|
|
(2.18) |
|
|
|
(2.68) |
|
|
(2.76) |
|
(3.38) |
Interest expense |
|
|
(2.90) |
|
|
|
(3.00) |
|
|
(2.70) |
|
(2.72) |
Realized foreign exchange (loss) gain |
|
|
(0.04) |
|
|
|
0.03 |
|
|
(0.03) |
|
(0.04) |
Other income |
|
|
0.04 |
|
|
|
1.64 |
|
|
0.04 |
|
0.04 |
Corporate income taxes (1) |
|
|
0.55 |
|
|
|
(2.22) |
|
|
(1.73) |
|
(5.31) |
Fund flows from operations netback |
|
|
23.91 |
|
|
|
25.86 |
|
|
38.67 |
|
44.09 |
(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 December 31,
2015:
|
Note |
Volume |
Strike Price(s) |
Crude Oil |
|
|
|
WTI - Collar |
|
|
|
July 2015 - March 2016 |
1 |
250 bbl/d |
75.00 - 83.45 CAD $ |
July 2015 - June 2016 |
2 |
500 bbl/d |
75.50 - 85.08 CAD $ |
Dated Brent - Collar |
|
|
|
July 2015 - June 2016 |
3 |
1,000 bbl/d |
80.50 - 93.49 CAD $ |
July 2015 - June 2016 |
4 |
500 bbl/d |
64.50 - 75.48 US $ |
October 2015 - June 2016 |
5 |
250 bbl/d |
82.00 - 94.55 CAD $ |
January 2016 - June 2016 |
1 |
250 bbl/d |
84.00 - 93.70 CAD $ |
|
|
|
|
North American Natural Gas |
|
|
|
AECO - Collar |
|
|
|
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 |
|
5,000 GJ/d |
2.30 - 2.80 CAD $ |
AECO Basis - Fixed Price Differential |
|
|
|
November 2015 - March 2016 |
|
2,500 mmbtu/d |
Nymex HH less 0.47 US $ |
Nymex HH - Collar |
|
|
|
November 2015 - March 2016 |
6 |
5,000 mmbtu/d |
3.25 - 3.86 US $ |
(1) |
The contracted volumes increase to
500 boe/d for any monthly settlement periods above the contracted
ceiling price and are settled on the monthly average price (monthly
average US$/bbl multiplied by the Bank of Canada monthly average
noon day rate). |
(2) |
The contracted volumes increase to
1,250 boe/d for any monthly settlement periods above the contracted
ceiling price and are settled on the monthly average price (monthly
average US$/bbl multiplied by the Bank of Canada monthly average
noon day rate). |
(3) |
The contracted volumes increase to
2,500 boe/d for any monthly settlement periods above the contracted
ceiling price and are settled on the monthly average price (monthly
average US$/bbl multiplied by the Bank of Canada monthly average
noon day rate). |
(4) |
The contracted volumes increase to
1,000 boe/d for any monthly settlement periods above the contracted
ceiling price. |
(5) |
The contracted volumes increase to
750 boe/d for any monthly settlement periods above the contracted
ceiling price and are settled on the monthly average price (monthly
average US$/bbl multiplied by the Bank of Canada monthly average
noon day rate). |
(6) |
The contracted volumes increase to
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 £ |
January 2017 - December 2017 |
|
2,638 GJ/d |
3.22 - 3.75 GBP £ |
January 2018 - December 2018 |
|
2,638 GJ/d |
2.99 - 3.63 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 € |
January 2017 - December 2017 |
1 |
2,638 GJ/d |
4.00 GBP £ |
January 2018 - December 2018 |
2 |
2,638 GJ/d |
3.83 GBP £ |
TTF - Call |
|
|
|
October 2016 - March 2017 |
|
2,592 GJ/d |
6.03 EUR € |
TTF - Collar |
|
|
|
January 2016 - December 2016 |
3 |
2,592 GJ/d |
5.76 - 6.50 EUR € |
April 2016 - December 2016 |
4 |
12,960 GJ/d |
5.58 - 6.21 EUR € |
April 2016 - March 2017 |
5 |
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 |
3 |
2,592 GJ/d |
5.07 - 6.56 EUR € |
July 2016 - March 2018 |
3 |
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 |
6 |
7,776 GJ/d |
5.00 - 6.15 EUR € |
January 2018 - December 2018 |
|
5,184 GJ/d |
4.17 - 5.03 EUR € |
TTF - Put |
|
|
|
April 2016 - September 2016 |
|
2,592 GJ/d |
5.21 EUR € |
TTF - Swap |
|
|
|
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 - March 2016 |
|
5,832 GJ/d |
6.18 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 € |
January 2017 - December 2017 |
7 |
2,592 GJ/d |
5.04 EUR € |
|
|
|
|
Electricity |
|
|
|
AESO - Swap |
|
|
|
January 2016 - December 2016 |
|
93.6 MWh/d |
38.58 CAD $ |
|
|
|
|
Interest Rate |
|
|
|
CDOR to fixed - Swap |
|
|
|
September 2015 - September 2019 |
|
100,000,000 CAD $/year |
1.00 % |
October 2015 - October 2019 |
|
100,000,000 CAD $/year |
1.10 % |
(1) |
On the last business day of each
month, the counterparty has the option to increase the contracted
volumes by an additional 2,638 GJ/d at the contracted price, for
the following month. |
(2) |
On the last business day of each
month, the counterparty has the option to increase the contracted
volumes to 7,913 GJ/d at the contracted price, for the following
month. |
(3) |
The contracted volumes increase to
5,184 GJ/d for any monthly settlement periods above the contracted
ceiling price. |
(4) |
The contracted volumes increase to
15,552 GJ/d for any monthly settlement periods above the contracted
ceiling price. |
(5) |
The contracted volumes increase to
10,368 GJ/d for any monthly settlement periods above the contracted
ceiling price. |
(6) |
The contracted volumes increase to
18,144 GJ/d for any monthly settlement periods above the contracted
ceiling price. |
(7) |
On the last business day of each
month, the counterparty has the option to increase the contracted
volumes by an additional 5,184 GJ/d at the contracted price, for
the following month. |
Supplemental Table 3: Capital
Expenditures
|
Three
Months Ended |
|
|
Year
Ended |
By classification |
Dec 31, |
Sep 30, |
Dec 31, |
|
|
Dec 31, |
Dec 31, |
($M) |
2015 |
2015 |
2014 |
|
|
2015 |
2014 |
Drilling and development |
128,996 |
93,381 |
151,395 |
|
|
486,861 |
618,689 |
Exploration and evaluation |
- |
- |
14,848 |
|
|
- |
69,035 |
Capital expenditures |
128,996 |
93,381 |
166,243 |
|
|
486,861 |
687,724 |
Property acquisition |
6,227 |
22,155 |
1,652 |
|
|
28,897 |
220,726 |
Corporate acquisition |
- |
- |
- |
|
|
- |
381,139 |
Acquisitions |
6,227 |
22,155 |
1,652 |
|
|
28,897 |
601,865 |
|
|
|
|
|
|
|
|
|
Three
Months Ended |
|
|
Year
Ended |
By category |
Dec 31, |
Sep 30, |
Dec 31, |
|
|
Dec 31, |
Dec 31, |
($M) |
2015 |
2015 |
2014 |
|
|
2015 |
2014 |
Land |
819 |
763 |
1,457 |
|
|
3,793 |
9,506 |
Seismic |
4,217 |
810 |
7,598 |
|
|
8,243 |
19,034 |
Drilling and completion |
58,327 |
39,712 |
69,691 |
|
|
212,358 |
311,696 |
Production equipment and facilities |
55,662 |
44,589 |
77,272 |
|
|
218,963 |
275,538 |
Recompletions |
6,338 |
3,948 |
7,696 |
|
|
26,689 |
36,234 |
Other |
3,633 |
3,559 |
2,529 |
|
|
16,815 |
35,716 |
Capital expenditures |
128,996 |
93,381 |
166,243 |
|
|
486,861 |
687,724 |
Acquisitions |
6,227 |
22,155 |
1,652 |
|
|
28,897 |
601,865 |
Total capital expenditures and acquisitions |
135,223 |
115,536 |
167,895 |
|
|
515,758 |
1,289,589 |
|
|
|
|
|
|
|
|
|
Three
Months Ended |
|
|
Year
Ended |
By country |
Dec 31, |
Sep 30, |
Dec 31, |
|
|
Dec 31, |
Dec 31, |
($M) |
2015 |
2015 |
2014 |
|
|
2015 |
2014 |
Canada |
33,723 |
45,286 |
87,113 |
|
|
216,158 |
750,390 |
France |
24,164 |
17,511 |
37,189 |
|
|
92,582 |
147,852 |
Netherlands |
18,810 |
5,297 |
10,022 |
|
|
47,325 |
61,740 |
Germany |
(441) |
1,605 |
563 |
|
|
5,363 |
175,618 |
Ireland |
12,493 |
20,694 |
20,932 |
|
|
66,409 |
94,439 |
Australia |
40,852 |
7,966 |
11,616 |
|
|
61,741 |
44,283 |
United States |
5,622 |
16,011 |
460 |
|
|
25,014 |
11,635 |
Corporate |
- |
1,166 |
- |
|
|
1,166 |
3,632 |
Total capital expenditures and acquisitions |
135,223 |
115,536 |
167,895 |
|
|
515,758 |
1,289,589 |
Supplemental Table 4: Production
|
|
Q4/15 |
Q3/15 |
Q2/15 |
Q1/15 |
Q4/14 |
Q3/14 |
Q2/14 |
Q1/14 |
Q4/13 |
Q3/13 |
Q2/13 |
Q1/13 |
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
7,964 |
9,195 |
10,182 |
10,893 |
11,384 |
11,469 |
12,676 |
9,437 |
8,719 |
7,969 |
8,885 |
7,966 |
|
NGLs (bbls/d) |
5,159 |
4,513 |
3,755 |
2,976 |
2,741 |
2,291 |
2,796 |
2,071 |
1,699 |
1,897 |
1,725 |
1,335 |
|
Natural gas (mmcf/d) |
87.90 |
71.94 |
64.66 |
61.78 |
58.36 |
57.07 |
57.59 |
49.53 |
41.43 |
43.40 |
43.69 |
41.04 |
|
Total (boe/d) |
27,773 |
25,698 |
24,713 |
24,165 |
23,851 |
23,272 |
25,070 |
19,763 |
17,322 |
17,099 |
17,892 |
16,140 |
|
% of consolidated |
45% |
47% |
48% |
48% |
49% |
47% |
49% |
42% |
43% |
41% |
42% |
41% |
France |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
12,537 |
12,310 |
12,746 |
11,463 |
11,133 |
11,111 |
11,025 |
10,771 |
11,131 |
11,625 |
10,390 |
10,330 |
|
Natural gas (mmcf/d) |
1.36 |
1.47 |
1.03 |
- |
- |
- |
- |
- |
- |
5.23 |
4.19 |
4.21 |
|
Total (boe/d) |
12,763 |
12,555 |
12,917 |
11,463 |
11,133 |
11,111 |
11,025 |
10,771 |
11,131 |
12,496 |
11,088 |
11,032 |
|
% of consolidated |
21% |
22% |
25% |
23% |
22% |
22% |
21% |
23% |
27% |
30% |
26% |
29% |
Netherlands |
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d) |
110 |
109 |
112 |
63 |
81 |
63 |
96 |
69 |
62 |
48 |
50 |
96 |
|
Natural gas (mmcf/d) |
56.34 |
53.56 |
32.43 |
36.41 |
31.35 |
38.07 |
40.35 |
43.15 |
37.53 |
28.78 |
38.52 |
36.91 |
|
Total (boe/d) |
9,500 |
9,035 |
5,517 |
6,132 |
5,306 |
6,407 |
6,822 |
7,260 |
6,318 |
4,845 |
6,470 |
6,248 |
|
% of consolidated |
16% |
16% |
11% |
12% |
11% |
13% |
13% |
16% |
15% |
12% |
15% |
16% |
Germany |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d) |
16.17 |
14.00 |
16.18 |
16.80 |
17.71 |
15.38 |
16.13 |
10.64 |
- |
- |
- |
- |
|
Total (boe/d) |
2,695 |
2,333 |
2,696 |
2,801 |
2,952 |
2,563 |
2,689 |
1,773 |
- |
- |
- |
- |
|
% of consolidated |
4% |
4% |
5% |
6% |
6% |
5% |
5% |
4% |
- |
- |
- |
- |
Ireland |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d) |
0.12 |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
|
Total (boe/d) |
20 |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
|
% of consolidated |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Australia |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
7,824 |
6,433 |
5,865 |
5,672 |
6,134 |
6,567 |
6,483 |
7,110 |
6,189 |
7,070 |
7,363 |
5,287 |
|
% of consolidated |
13% |
11% |
11% |
11% |
12% |
13% |
12% |
15% |
15% |
17% |
17% |
14% |
United States |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
420 |
226 |
123 |
153 |
195 |
- |
- |
- |
- |
- |
- |
- |
|
NGLs (bbls/d) |
29 |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
|
Natural gas (mmcf/d) |
0.20 |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
|
Total (boe/d) |
483 |
226 |
123 |
153 |
195 |
- |
- |
- |
- |
- |
- |
- |
|
% of consolidated |
1% |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
- |
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil & NGLs (bbls/d) |
34,043 |
32,786 |
32,783 |
31,220 |
31,668 |
31,501 |
33,076 |
29,458 |
27,800 |
28,609 |
28,413 |
25,014 |
|
% of consolidated |
56% |
58% |
63% |
62% |
64% |
63% |
63% |
63% |
68% |
69% |
66% |
65% |
|
Natural gas (mmcf/d) |
162.09 |
140.97 |
114.29 |
115.00 |
107.42 |
110.52 |
114.08 |
103.32 |
78.96 |
77.41 |
86.40 |
82.16 |
|
% of consolidated |
44% |
42% |
37% |
38% |
36% |
37% |
37% |
37% |
32% |
31% |
34% |
35% |
|
Total (boe/d) |
61,058 |
56,280 |
51,831 |
50,386 |
49,571 |
49,920 |
52,089 |
46,677 |
40,960 |
41,510 |
42,813 |
38,707 |
|
|
2015 |
2014 |
2013 |
2012 |
2011 |
2010 |
Canada |
|
|
|
|
|
|
|
Crude oil (bbls/d) |
9,550 |
11,248 |
8,387 |
7,659 |
4,701 |
2,778 |
|
NGLs (bbls/d) |
4,108 |
2,476 |
1,666 |
1,232 |
1,297 |
1,427 |
|
Natural gas (mmcf/d) |
71.65 |
55.67 |
42.39 |
37.50 |
43.38 |
43.91 |
|
Total (boe/d) |
25,598 |
23,001 |
17,117 |
15,142 |
13,227 |
11,524 |
|
% of consolidated |
46% |
47% |
41% |
40% |
38% |
36% |
France |
|
|
|
|
|
|
|
Crude oil (bbls/d) |
12,267 |
11,011 |
10,873 |
9,952 |
8,110 |
8,347 |
|
Natural gas (mmcf/d) |
0.97 |
- |
3.40 |
3.59 |
0.95 |
0.92 |
|
Total (boe/d) |
12,429 |
11,011 |
11,440 |
10,550 |
8,269 |
8,501 |
|
% of consolidated |
23% |
22% |
28% |
28% |
23% |
26% |
Netherlands |
|
|
|
|
|
|
|
NGLs (bbls/d) |
99 |
77 |
64 |
67 |
58 |
35 |
|
Natural gas (mmcf/d) |
44.76 |
38.20 |
35.42 |
34.11 |
32.88 |
28.31 |
|
Total (boe/d) |
7,559 |
6,443 |
5,967 |
5,751 |
5,538 |
4,753 |
|
% of consolidated |
14% |
13% |
15% |
15% |
16% |
15% |
Germany |
|
|
|
|
|
|
|
Natural gas (mmcf/d) |
15.78 |
14.99 |
- |
- |
- |
- |
|
Total (boe/d) |
2,630 |
2,498 |
- |
- |
- |
- |
|
% of consolidated |
5% |
5% |
- |
- |
- |
- |
Ireland |
|
|
|
|
|
|
|
Natural gas (mmcf/d) |
0.03 |
- |
- |
- |
- |
- |
|
Total (boe/d) |
5 |
- |
- |
- |
- |
- |
|
% of consolidated |
- |
- |
- |
- |
- |
- |
Australia |
|
|
|
|
|
|
|
Crude oil (bbls/d) |
6,454 |
6,571 |
6,481 |
6,360 |
8,168 |
7,354 |
|
% of consolidated |
12% |
13% |
16% |
17% |
23% |
23% |
United States |
|
|
|
|
|
|
|
Crude oil (bbls/d) |
231 |
49 |
- |
- |
- |
- |
|
NGLs (bbls/d) |
7 |
- |
|
|
|
|
|
Natural gas (mmcf/d) |
0.05 |
- |
- |
- |
- |
- |
|
Total (boe/d) |
247 |
49 |
- |
- |
- |
- |
|
% of consolidated |
- |
- |
- |
- |
- |
- |
Consolidated |
|
|
|
|
|
|
|
Crude oil & NGLs (bbls/d) |
32,716 |
31,432 |
27,471 |
25,270 |
22,334 |
19,941 |
|
% of consolidated |
60% |
63% |
67% |
67% |
63% |
62% |
|
Natural gas (mmcf/d) |
133.24 |
108.85 |
81.21 |
75.20 |
77.21 |
73.14 |
|
% of consolidated |
40% |
37% |
33% |
33% |
37% |
38% |
|
Total (boe/d) |
54,922 |
49,573 |
41,005 |
37,803 |
35,202 |
32,132 |
Supplemental Table 5: Segmented Financial
Results
|
Three
Months Ended December 31, 2015 |
($M) |
Canada |
|
France |
|
Netherlands |
|
Germany |
|
Ireland |
|
Australia |
|
United States |
|
Corporate |
|
Total |
Drilling and development |
27,554 |
|
24,085 |
|
18,810 |
|
(441) |
|
12,493 |
|
40,852 |
|
5,643 |
|
- |
|
128,996 |
Oil and gas sales to external
customers |
73,952 |
|
63,411 |
|
37,243 |
|
9,840 |
|
57 |
|
47,952 |
|
1,864 |
|
- |
|
234,319 |
Royalties |
(7,146) |
|
(7,198) |
|
(224) |
|
(1,166) |
|
- |
|
- |
|
(551) |
|
- |
|
(16,285) |
Revenue from external customers |
66,806 |
|
56,213 |
|
37,019 |
|
8,674 |
|
57 |
|
47,952 |
|
1,313 |
|
- |
|
218,034 |
Transportation expense |
(3,784) |
|
(4,275) |
|
- |
|
(508) |
|
(1,580) |
|
- |
|
- |
|
- |
|
(10,147) |
Operating expense |
(24,575) |
|
(15,792) |
|
(6,263) |
|
(4,788) |
|
(15) |
|
(13,941) |
|
(271) |
|
- |
|
(65,645) |
General and administration |
(3,669) |
|
(4,894) |
|
(813) |
|
(3,032) |
|
(714) |
|
(1,768) |
|
(897) |
|
3,356 |
|
(12,431) |
PRRT |
- |
|
- |
|
- |
|
- |
|
- |
|
(1,054) |
|
- |
|
- |
|
(1,054) |
Corporate income taxes |
- |
|
4,529 |
|
(2,930) |
|
- |
|
- |
|
1,201 |
|
- |
|
313 |
|
3,113 |
Interest expense |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(16,584) |
|
(16,584) |
Realized gain on derivative instruments |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
21,164 |
|
21,164 |
Realized foreign exchange loss |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(252) |
|
(252) |
Realized other income |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
243 |
|
243 |
Fund flows from operations |
34,778 |
|
35,781 |
|
27,013 |
|
346 |
|
(2,252) |
|
32,390 |
|
145 |
|
8,240 |
|
136,441 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31, 2015 |
($M) |
Canada |
|
France |
|
Netherlands |
|
Germany |
|
Ireland |
|
Australia |
|
United States |
|
Corporate |
|
Total |
Total assets |
1,609,180 |
|
863,304 |
|
212,749 |
|
167,908 |
|
908,453 |
|
235,139 |
|
42,927 |
|
169,560 |
|
4,209,220 |
Drilling and development |
201,508 |
|
92,265 |
|
47,325 |
|
5,363 |
|
66,409 |
|
61,741 |
|
12,250 |
|
- |
|
486,861 |
Oil and gas sales to external customers |
320,613 |
|
281,422 |
|
129,057 |
|
41,384 |
|
57 |
|
162,765 |
|
4,288 |
|
- |
|
939,586 |
Royalties |
(28,144) |
|
(26,958) |
|
(3,082) |
|
(6,479) |
|
- |
|
- |
|
(1,257) |
|
- |
|
(65,920) |
Revenue from external customers |
292,469 |
|
254,464 |
|
125,975 |
|
34,905 |
|
57 |
|
162,765 |
|
3,031 |
|
- |
|
873,666 |
Transportation expense |
(16,326) |
|
(15,378) |
|
- |
|
(3,269) |
|
(6,687) |
|
- |
|
- |
|
- |
|
(41,660) |
Operating expense |
(89,085) |
|
(50,718) |
|
(22,746) |
|
(10,956) |
|
(15) |
|
(51,676) |
|
(742) |
|
- |
|
(225,938) |
General and administration |
(16,888) |
|
(20,217) |
|
(4,158) |
|
(7,386) |
|
(2,517) |
|
(5,754) |
|
(3,836) |
|
7,172 |
|
(53,584) |
PRRT |
- |
|
- |
|
- |
|
- |
|
- |
|
(6,878) |
|
- |
|
- |
|
(6,878) |
Corporate income taxes |
- |
|
(23,764) |
|
(12,152) |
|
- |
|
- |
|
(7,230) |
|
- |
|
(1,091) |
|
(44,237) |
Interest expense |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(59,852) |
|
(59,852) |
Realized gain on derivative instruments |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
41,356 |
|
41,356 |
Realized foreign exchange gain |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
623 |
|
623 |
Realized other income |
- |
|
31,775 |
|
- |
|
- |
|
- |
|
- |
|
- |
|
896 |
|
32,671 |
Fund flows from operations |
170,170 |
|
176,162 |
|
86,919 |
|
13,294 |
|
(9,162) |
|
91,227 |
|
(1,547) |
|
(10,896) |
|
516,167 |
NON-GAAP FINANCIAL MEASURES
This MD&A includes references to certain
financial measures which do not have standardized meanings
prescribed by IFRS and are not disclosed in our audited
consolidated financial statements. As such, these financial
measures are considered non-GAAP financial measures and therefore
may not be comparable with similar measures presented by other
issuers.
Fund flows from operations per basic and
diluted share: Management assesses fund flows from operations
on a per share basis as we believe this provides a measure of our
operating performance after taking into account the issuance and
potential future issuance of Vermilion common shares. Fund flows from
operations per basic share is calculated by dividing fund flows
from operations by the basic weighted average shares outstanding as
defined under IFRS. Fund flows from operations per diluted
share is calculated by dividing fund flows from operations by the
sum of basic weighted average shares outstanding and incremental
shares issuable under our equity based compensation plans as
determined using the treasury stock method.
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 (a non-GAAP financial measure) and payout in order
to assess our ability to generate cash and finance organic growth
from our current producing assets.
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.
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 (excluding Corrib), net dividends, payout, and diluted
shares outstanding to their most directly comparable GAAP measures
as presented in our financial statements:
|
Three
Months Ended |
|
|
Year
Ended |
|
Dec 31, |
Sep 30, |
Dec 31, |
|
|
Dec 31, |
Dec 31, |
($M) |
2015 |
2015 |
2014 |
|
|
2015 |
2014 |
Cash flows from operating
activities |
164,863 |
122,230 |
229,146 |
|
|
444,408 |
791,986 |
Changes in non-cash operating working
capital |
(33,343) |
5,082 |
(49,865) |
|
|
60,390 |
(3,077) |
Asset retirement obligations
settled |
4,921 |
2,123 |
6,247 |
|
|
11,369 |
15,956 |
Fund flows from operations |
136,441 |
129,435 |
185,528 |
|
|
516,167 |
804,865 |
Expenses related to Corrib |
2,252 |
2,429 |
2,299 |
|
|
9,162 |
7,841 |
Fund flows from operations (excluding
Corrib) |
138,693 |
131,864 |
187,827 |
|
|
525,329 |
812,706 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended |
|
|
Year
Ended |
|
Dec 31, |
Sep 30, |
Dec 31, |
|
|
Dec 31, |
Dec 31, |
($M) |
2015 |
2015 |
2014 |
|
|
2015 |
2014 |
Dividends declared |
71,965 |
71,244 |
69,119 |
|
|
283,575 |
272,732 |
Issuance of shares pursuant to the
dividend
reinvestment and Premium DividendTM plans |
(46,764) |
(44,590) |
(20,980) |
|
|
(155,033) |
(79,430) |
Net dividends |
25,201 |
26,654 |
48,139 |
|
|
128,542 |
193,302 |
Drilling and development |
128,996 |
93,381 |
151,395 |
|
|
486,861 |
618,689 |
Exploration and evaluation |
- |
- |
14,848 |
|
|
- |
69,035 |
Asset retirement obligations
settled |
4,921 |
2,123 |
6,247 |
|
|
11,369 |
15,956 |
Payout |
159,118 |
122,158 |
220,629 |
|
|
626,772 |
896,982 |
Corrib drilling and development |
(12,493) |
(20,694) |
(20,932) |
|
|
(66,409) |
(94,439) |
Payout (excluding Corrib) |
146,625 |
101,464 |
199,697 |
|
|
560,363 |
802,543 |
|
|
|
|
|
|
|
|
|
As
at |
|
Dec 31, |
Sep 30, |
Dec 31, |
('000s of shares) |
2015 |
2015 |
2014 |
Shares outstanding |
111,991 |
110,818 |
107,303 |
Potential shares issuable pursuant to
the VIP |
3,033 |
2,825 |
3,031 |
Diluted shares outstanding |
115,024 |
113,643 |
110,334 |
MANAGEMENT'S REPORT TO SHAREHOLDERS
Management's Responsibility for Financial Statements
The accompanying consolidated financial
statements of Vermilion Energy Inc. are the responsibility of
management and have been approved by the Board of Directors of
Vermilion Energy Inc. The consolidated financial statements have
been prepared in accordance with the accounting policies detailed
in the notes to the consolidated financial statements and are
prepared in accordance with International Financial Reporting
Standards as issued by the International Accounting Standards
Board. Where necessary, management has made informed judgments and
estimates of transactions that were not yet completed at the
balance sheet date. Financial information throughout the Annual
Report is consistent with the consolidated financial
statements.
Management ensures the integrity of the
consolidated financial statements by maintaining high-quality
systems of internal control. Procedures and policies are designed
to provide reasonable assurance that assets are safeguarded and
transactions are properly recorded, and that the financial records
are reliable for preparation of the consolidated financial
statements. Deloitte LLP, Vermilion's external auditors, have conducted
an audit of the consolidated financial statements in accordance
with Canadian generally accepted auditing standards and the
standards of the Public Company Accounting Oversight Board
(United States) and have provided
their report.
The Board of Directors is responsible for
ensuring that management fulfills its responsibility for financial
reporting and internal control. The Board carries out this
responsibility principally through the Audit Committee, which is
appointed by the Board and is comprised entirely of independent
Directors. The Committee meets periodically with management and
Deloitte LLP to satisfy itself that each party is properly
discharging its responsibilities and to review the consolidated
financial statements, the Management's Discussion and Analysis and
the external Auditor's Report before they are presented to the
Board of Directors.
Management's Report on Internal Control Over Financial
Reporting
Management is responsible for establishing and
maintaining an adequate system of internal control over financial
reporting. Management conducted an evaluation of the effectiveness
of the system of internal control over financial reporting based on
the criteria established in "Internal Control - Integrated
Framework (2013)" issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this
evaluation, management has assessed the effectiveness of
Vermilion's internal control over
financial reporting as defined in Rule 13a-15 under the US
Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109,
Certification of Disclosure in Issuers' Annual and Interim
Filings. Management concluded that Vermilion's internal control over financial
reporting was effective as of December 31,
2015. The effectiveness of Vermilion's internal control over financial
reporting as of December 31, 2015 has
been audited by Deloitte LLP, the Company's Independent Registered
Public Accounting Firm, who also audited the Company's consolidated
financial statements for the year ended December 31, 2015.
("Lorenzo Donadeo")
|
|
|
|
|
|
|
|
|
("Curtis W. Hicks") |
|
|
|
|
|
|
|
|
|
|
Lorenzo Donadeo
Chief Executive Officer
February 25, 2016 |
|
|
|
|
|
|
|
|
Curtis W. Hicks
Executive Vice President & Chief Financial Officer
|
|
|
|
|
|
|
|
|
|
|
Report of Independent Registered Public Accounting
Firm
To the Board of Directors and Shareholders of
Vermilion Energy Inc.
We have audited the internal control over
financial reporting of Vermilion Energy Inc. and subsidiaries (the
"Company") as of December 31, 2015,
based on the criteria established in Internal Control—Integrated
Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission. The Company's
management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting,
included in the accompanying Management's Report on Internal
Control over Financial Reporting. Our responsibility is to
express an opinion on the Company's internal control over financial
reporting based on our audit.
We conducted our audit in accordance with the
standards of the Public Company Accounting Oversight Board
(United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over
financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control
over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a
reasonable basis for our opinion.
A company's internal control over financial
reporting is a process designed by, or under the supervision of,
the company's principal executive and principal financial officers,
or persons performing similar functions, and effected by the
company's board of directors, management, and other personnel to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with International Financial Reporting
Standards as issued by the International Accounting Standards
Board. A company's internal control over financial reporting
includes those policies and procedures that (1) pertain to the
maintenance of records that, in reasonable detail, accurately and
fairly reflect the transactions and dispositions of the assets of
the company; (2) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements
in accordance with International Financial Reporting Standards as
issued by the International Accounting Standards Board, and that
receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention
or timely detection of unauthorized acquisition, use, or
disposition of the company's assets that could have a material
effect on the financial statements.
Because of the inherent limitations of internal
control over financial reporting, including the possibility of
collusion or improper management override of controls, material
misstatements due to error or fraud may not be prevented or
detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over
financial reporting to future periods are subject to the risk that
the controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our opinion, the Company maintained, in all
material respects, effective internal control over financial
reporting as of December 31, 2015,
based on the criteria established in Internal Control —
Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with
Canadian generally accepted auditing standards and the standards of
the Public Company Accounting Oversight Board (United States), the consolidated financial
statements as of and for the year ended December 31, 2015 of the Company and our report
dated February 26, 2016 expressed an
unqualified opinion on those financial statements.
("/s/Deloitte LLP") |
|
Chartered Professional Accountants, Chartered Accountants
February 26, 2016
Calgary, Canada |
|
Report of Independent Registered Public Accounting
Firm
To the Board of Directors and Shareholders of
Vermilion Energy Inc.
We have audited the accompanying consolidated
financial statements of Vermilion Energy Inc. and subsidiaries (the
"Company"), which comprise the consolidated balance sheets as at
December 31, 2015 and December 31, 2014, and the consolidated
statements of net earnings (loss) and comprehensive income (loss),
cash flows, and changes in shareholders' equity for the years then
ended, and a summary of significant accounting policies and other
explanatory information.
Management's Responsibility for the
Consolidated Financial Statements
Management is responsible for the preparation
and fair presentation of these consolidated financial statements in
accordance with International Financial Reporting Standards as
issued by the International Accounting Standards Board, and for
such internal control as management determines is necessary to
enable the preparation of consolidated financial statements that
are free from material misstatement, whether due to fraud or
error.
Auditor's Responsibility
Our responsibility is to express an opinion on
these consolidated financial statements based on our audits. We
conducted our audits in accordance with Canadian generally accepted
auditing standards and the standards of the Public Company
Accounting Oversight Board (United
States). Those standards require that we comply with ethical
requirements and plan and perform the audit to obtain reasonable
assurance about whether the consolidated financial statements are
free from material misstatement.
An audit involves performing procedures to
obtain audit evidence about the amounts and disclosures in the
consolidated financial statements. The procedures selected depend
on the auditor's judgment, including the assessment of the risks of
material misstatement of the consolidated financial statements,
whether due to fraud or error. In making those risk assessments,
the auditor considers internal control relevant to the entity's
preparation and fair presentation of the consolidated financial
statements in order to design audit procedures that are appropriate
in the circumstances. An audit also includes evaluating the
appropriateness of accounting policies used and the reasonableness
of accounting estimates made by management, as well as evaluating
the overall presentation of the consolidated financial
statements.
We believe that the audit evidence we have
obtained in our audits is sufficient and appropriate to provide a
basis for our audit opinion.
Opinion
In our opinion, the consolidated financial
statements present fairly, in all material respects, the financial
position of Vermilion Energy Inc. and subsidiaries as at
December 31, 2015 and December 31, 2014, and their financial
performance and their cash flows for the years then ended in
accordance with International Financial Reporting Standards as
issued by the International Accounting Standards Board.
Other Matter
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the Company's internal control
over financial reporting as of December 31,
2015, based on the criteria established in Internal
Control — Integrated Framework (2013) issued by the Committee
of Sponsoring Organizations of the Treadway Commission and our
report dated February 26, 2016
expressed an unmodified opinion on the Company's internal control
over financial reporting.
(To be signed "/s/Deloitte LLP") |
|
Chartered Professional Accountants, Chartered Accountants
February 26, 2016
Calgary, Canada |
|
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF CANADIAN DOLLARS)
|
|
December 31, |
December 31, |
|
Note |
|
2015 |
|
2014 |
ASSETS |
|
|
|
|
|
Current |
|
|
|
|
|
Cash and cash equivalents |
17 |
|
41,676 |
|
120,405 |
Accounts receivable |
|
|
160,499 |
|
171,820 |
Crude oil inventory |
|
|
13,079 |
|
9,510 |
Derivative instruments |
13 |
|
55,214 |
|
23,391 |
Prepaid expenses |
|
|
14,310 |
|
13,033 |
|
|
|
284,778 |
|
338,159 |
|
|
|
|
|
|
Derivative instruments |
13 |
|
13,128 |
|
1,403 |
Deferred taxes |
9 |
|
135,753 |
|
154,816 |
Exploration and evaluation assets |
6 |
|
308,192 |
|
380,621 |
Capital assets |
5 |
|
3,467,369 |
|
3,511,092 |
|
|
|
4,209,220 |
|
4,386,091 |
|
|
|
|
|
|
LIABILITIES |
|
|
|
|
|
Current |
|
|
|
|
|
Accounts payable and accrued liabilities |
|
|
248,747 |
|
298,196 |
Current portion of long-term debt |
8 |
|
224,901 |
|
- |
Dividends payable |
10 |
|
24,077 |
|
23,070 |
Income taxes payable |
9 |
|
6,006 |
|
44,463 |
|
|
|
503,731 |
|
365,729 |
|
|
|
|
|
|
Long-term debt |
8 |
|
1,162,998 |
|
1,238,080 |
Finance lease obligation |
16 |
|
23,565 |
|
- |
Asset retirement obligations |
7 |
|
305,613 |
|
350,753 |
Deferred taxes |
9 |
|
354,654 |
|
410,183 |
|
|
|
2,350,561 |
|
2,364,745 |
|
|
|
|
|
|
SHAREHOLDERS' EQUITY |
|
|
|
|
|
Shareholders' capital |
10 |
|
2,181,089 |
|
1,959,021 |
Contributed surplus |
|
|
107,946 |
|
92,188 |
Accumulated other comprehensive income |
|
|
113,647 |
|
5,722 |
Deficit |
|
|
(544,023) |
|
(35,585) |
|
|
|
1,858,659 |
|
2,021,346 |
|
|
|
4,209,220 |
|
4,386,091 |
APPROVED BY THE BOARD |
|
|
|
|
|
|
|
|
|
|
|
|
|
(Signed "Joseph F.
Killi") |
|
|
|
|
|
(Signed "Lorenzo Donadeo") |
Joseph F. Killi,
Director |
|
|
|
|
|
Lorenzo Donadeo, Director |
CONSOLIDATED STATEMENTS OF NET EARNINGS (LOSS) AND
COMPREHENSIVE INCOME (LOSS)
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE
AMOUNTS)
|
|
|
Year
Ended |
|
|
December 31, |
|
December 31, |
Note |
2015 |
|
2014 |
REVENUE |
|
|
|
|
|
Petroleum and natural gas sales |
|
|
939,586 |
|
1,419,628 |
Royalties |
|
|
(65,920) |
|
(108,000) |
Petroleum and natural gas revenue |
|
|
873,666 |
|
1,311,628 |
|
|
|
|
|
|
EXPENSES |
|
|
|
|
|
Operating |
21 |
|
225,938 |
|
232,307 |
Transportation |
|
|
41,660 |
|
42,361 |
Equity based compensation |
11 |
|
75,232 |
|
67,802 |
Gain on derivative instruments |
13 |
|
(84,904) |
|
(64,083) |
Interest expense |
|
|
59,852 |
|
49,655 |
General and administration |
21 |
|
53,584 |
|
61,727 |
Foreign exchange (gain) loss |
|
|
(9,410) |
|
18,420 |
Other (income) expense |
|
|
(31,663) |
|
760 |
Accretion |
7 |
|
23,911 |
|
23,913 |
Depletion and depreciation |
5, 6 |
|
458,758 |
|
425,694 |
Impairment |
5, 6 |
|
274,623 |
|
- |
|
|
|
1,087,581 |
|
858,556 |
EARNINGS (LOSS) BEFORE INCOME TAXES |
|
|
(213,915) |
|
453,072 |
|
|
|
|
|
|
INCOME TAXES |
9 |
|
|
|
|
Deferred |
|
|
(47,728) |
|
26,410 |
Current |
|
|
51,115 |
|
157,336 |
|
|
|
3,387 |
|
183,746 |
|
|
|
|
|
|
NET EARNINGS (LOSS) |
|
|
(217,302) |
|
269,326 |
|
|
|
|
|
|
OTHER COMPREHENSIVE (LOSS) INCOME |
|
|
|
|
|
Currency translation adjustments |
|
|
107,925 |
|
(41,420) |
COMPREHENSIVE (LOSS) INCOME |
|
|
(109,377) |
|
227,906 |
|
|
|
|
|
|
NET EARNINGS (LOSS) PER SHARE |
12 |
|
|
|
|
Basic |
|
|
(1.98) |
|
2.55 |
Diluted |
|
|
(1.98) |
|
2.51 |
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING
('000s) |
12 |
|
|
|
|
Basic |
|
|
109,642 |
|
105,448 |
Diluted |
|
|
109,642 |
|
107,187 |
CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF CANADIAN DOLLARS)
|
|
|
Year
Ended |
|
|
|
December 31, |
|
December 31, |
|
Note |
|
2015 |
|
2014 |
OPERATING |
|
|
|
|
|
Net earnings (loss) |
|
|
(217,302) |
|
269,326 |
Adjustments: |
|
|
|
|
|
|
Accretion |
7 |
|
23,911 |
|
23,913 |
|
Depletion and depreciation |
5, 6 |
|
458,758 |
|
425,694 |
|
Impairment |
5, 6 |
|
274,623 |
|
- |
|
Unrealized gain on derivative instruments |
13 |
|
(43,548) |
|
(27,371) |
|
Equity based compensation |
11 |
|
75,232 |
|
67,802 |
|
Unrealized foreign exchange (gain) loss |
|
|
(8,787) |
|
17,599 |
|
Unrealized other expense |
|
|
1,008 |
|
1,492 |
|
Deferred taxes |
9 |
|
(47,728) |
|
26,410 |
Asset retirement obligations
settled |
7 |
|
(11,369) |
|
(15,956) |
Changes in non-cash operating working
capital |
14 |
|
(60,390) |
|
3,077 |
Cash flows from operating
activities |
|
|
444,408 |
|
791,986 |
|
|
|
|
|
|
INVESTING |
|
|
|
|
|
Drilling and development |
5 |
|
(486,861) |
|
(618,689) |
Exploration and evaluation |
6 |
|
- |
|
(69,035) |
Property acquisitions |
4, 5, 6 |
|
(28,897) |
|
(220,726) |
Corporate acquisitions, net of cash
acquired |
4 |
|
- |
|
(176,179) |
Changes in non-cash investing working
capital |
14 |
|
(25,980) |
|
12,365 |
Cash flows used in investing
activities |
|
|
(541,738) |
|
(1,072,264) |
|
|
|
|
|
|
FINANCING |
|
|
|
|
|
Increase in long-term debt |
8 |
|
138,341 |
|
196,387 |
Decrease in finance lease
obligation |
16 |
|
(2,246) |
|
- |
Cash dividends |
10 |
|
(127,535) |
|
(190,657) |
Cash flows from financing
activities |
|
|
8,560 |
|
5,730 |
Foreign exchange gain on cash held in
foreign currencies |
|
|
10,041 |
|
5,394 |
|
|
|
|
|
|
Net change in cash and cash
equivalents |
|
|
(78,729) |
|
(269,154) |
Cash and cash equivalents, beginning
of year |
|
|
120,405 |
|
389,559 |
Cash and cash equivalents, end of
year |
17 |
|
41,676 |
|
120,405 |
|
|
|
|
|
|
Supplementary information for
operating activities - cash payments |
|
|
|
|
|
|
Interest paid |
|
|
62,911 |
|
50,801 |
|
Income taxes paid |
|
|
92,907 |
|
166,993 |
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS'
EQUITY
(THOUSANDS OF CANADIAN DOLLARS)
|
|
|
|
|
|
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 |
|
|
- |
|
- |
|
- |
|
269,326 |
|
269,326 |
Currency translation adjustments |
|
|
- |
|
- |
|
(41,420) |
|
- |
|
(41,420) |
Equity based compensation expense |
11 |
|
- |
|
67,081 |
|
- |
|
- |
|
67,081 |
Dividends declared |
10 |
|
- |
|
- |
|
- |
|
(272,732) |
|
(272,732) |
Shares issued pursuant to the |
|
|
|
|
|
|
|
|
|
|
|
|
dividend reinvestment plan |
10 |
|
79,430 |
|
- |
|
- |
|
- |
|
79,430 |
Shares issued pursuant to |
|
|
|
|
|
|
|
|
|
|
|
|
corporate acquisition |
4, 10 |
|
204,960 |
|
- |
|
- |
|
- |
|
204,960 |
Modification of equity based
awards |
11 |
|
- |
|
(2,395) |
|
- |
|
- |
|
(2,395) |
Vesting of equity based awards |
10, 11 |
|
47,925 |
|
(47,925) |
|
- |
|
- |
|
- |
Share-settled dividends |
|
|
|
|
|
|
|
|
|
|
|
|
on vested equity based awards |
10, 11 |
|
7,542 |
|
- |
|
- |
|
(7,542) |
|
- |
Shares issued pursuant
to the bonus plan |
10 |
|
721 |
|
- |
|
- |
|
- |
|
721 |
Balances as at December 31, 2014 |
|
|
1,959,021 |
|
92,188 |
|
5,722 |
|
(35,585) |
|
2,021,346 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
- |
|
- |
|
- |
|
(217,302) |
|
(217,302) |
Currency translation adjustments |
|
|
- |
|
- |
|
107,925 |
|
- |
|
107,925 |
Equity based compensation expense |
11 |
|
- |
|
72,613 |
|
- |
|
- |
|
72,613 |
Dividends declared |
10 |
|
- |
|
- |
|
- |
|
(283,575) |
|
(283,575) |
Shares issued pursuant to the |
|
|
|
|
|
|
|
|
|
|
|
|
dividend reinvestment and Premium |
|
|
|
|
|
|
|
|
|
|
|
|
DividendTM plans |
10 |
|
155,033 |
|
- |
|
- |
|
- |
|
155,033 |
Vesting of equity based awards |
10, 11 |
|
56,855 |
|
(56,855) |
|
- |
|
- |
|
- |
Share-settled dividends |
|
|
|
|
|
|
|
|
|
|
|
|
on vested equity based awards |
10, 11 |
|
7,561 |
|
- |
|
- |
|
(7,561) |
|
- |
Shares issued pursuant to the
employee |
|
|
|
|
|
|
|
|
|
|
|
|
savings and bonus plans |
10 |
|
2,619 |
|
- |
|
- |
|
- |
|
2,619 |
Balances as at December 31, 2015 |
|
|
2,181,089 |
|
107,946 |
|
113,647 |
|
(544,023) |
|
1,858,659 |
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 (loss) and are accumulated
until an event triggers recognition in net earnings (loss).
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 (loss) less distributed
earnings of Vermilion Energy Inc.
NOTES TO THE CONSOLIDATED FINANCIAL
STATEMENTS
FOR THE YEAR ENDED DECEMBER 31,
2015 AND 2014
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE
AND PER SHARE AMOUNTS)
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 consolidated financial statements were
approved and authorized for issuance by the Board of Directors of
Vermilion on February 25, 2016.
2. SIGNIFICANT ACCOUNTING POLICIES
Accounting Framework
The consolidated financial statements have been prepared in
accordance with International Financial Reporting Standards
("IFRS") as issued by the International Accounting Standards Board
("IASB").
Principles of Consolidation
Subsidiaries that are directly controlled by the parent company or
indirectly controlled through other consolidated subsidiaries are
fully consolidated. Vermilion accounts for joint operations by
recognizing its share of assets, liabilities, income and
expenses. All significant intercompany balances,
transactions, income and expenses are eliminated upon
consolidation.
Vermilion
currently has no special purpose entities of which it retains
control and accordingly the consolidated financial statements do
not include the accounts of any such entities.
Exploration and Evaluation
Assets
Vermilion accounts for exploration
and evaluation of petroleum and natural gas property ("E&E")
costs in accordance with IFRS 6 "Exploration for and Evaluation of
Mineral Resources". Costs incurred are classified as E&E
costs when they relate to exploring and evaluating a property for
which the Company has the licence or right to explore and extract
resources.
E&E costs related to each license or
prospect area are initially capitalized within E&E
assets. E&E costs that are capitalized may include costs
of licence acquisitions, technical services and studies, seismic
acquisitions, exploration drilling and testing, directly
attributable overhead and administration expenses and, if
applicable, the estimated costs of retiring the assets. Any
costs incurred prior to the acquisition of the legal rights to
explore an area are expensed as incurred.
E&E assets are not initially depleted and
are carried at cost until technical feasibility and commercial
viability of the area can be determined. The technical
feasibility and commercial viability of extracting the reserves is
considered to be determinable when proven and probable reserves are
identified. If proven and probable reserves are identified as
recoverable, the related E&E costs are reclassified to
Petroleum and Natural Gas ("PNG") assets pending an impairment
test. If reserves are not found within the license area or
the area is abandoned, the related E&E costs are amortized over
a period not greater than five years.
Petroleum and Natural Gas
Assets
Vermilion recognizes PNG assets at
cost less accumulated depletion, depreciation and impairment
losses. Directly attributable costs incurred for the drilling
of development wells and for the construction of production
facilities are capitalized together with the discounted value of
estimated future costs of asset retirement obligations. When
components of PNG assets are replaced, disposed of, or no longer in
use, they are derecognized.
Gains and losses on disposal of a component of
PNG assets, including oil and gas interests, are determined by
comparing the proceeds of disposal with the carrying amount of the
component, and are recognized in net earnings (loss).
Depletion and Depreciation
Vermilion classifies its assets
into PNG depletion units, which are groups of assets or properties
that are within a specific production area and have similar
economic lives. The PNG depletion units represent the lowest
level of disaggregation for which Vermilion accumulates costs for the purposes
of calculating and recording depletion and depreciation.
The net carrying value of each PNG depletion
unit is depleted using the unit of production method by reference
to the ratio of production in the period to the total proven and
probable reserves, taking into account the future development costs
necessary to bring the applicable reserves into production.
The reserve estimates are reviewed annually by management or when
material changes occur to the underlying assumptions.
For the purposes of the depletion calculations,
oil and gas reserves are converted to a common unit of measure on
the basis of their relative energy content based on a conversion
ratio of six thousand cubic feet of natural gas to one barrel of
oil equivalent.
Furniture and office equipment are recorded at
cost and are depreciated on a declining-balance basis.
Impairment of Long-Lived
Assets
E&E assets are tested for impairment when reclassified to PNG
assets or when indicators of impairment are identified. If
indicators of impairment are identified, E&E assets are tested
for impairment as part of the group of Cash Generating Units
("CGUs") attributable to the jurisdiction in which the exploration
area resides.
PNG depletion units are aggregated into CGUs for
impairment testing. The determination of CGUs is based on
management's judgment and represents the lowest level at which
there are identifiable cash inflows that are largely independent of
the cash inflows of other groups of assets or properties.
CGUs are reviewed for indicators that the carrying value of the CGU
may exceed its recoverable amount. If an indication of
impairment exists, the CGU's recoverable amount is then
estimated. A CGU's recoverable amount is defined as the
higher of the fair value less costs to sell and its value in
use. If the carrying amount exceeds its recoverable amount,
an impairment loss is recorded to net earnings (loss) in the period
to reduce the carrying value of the CGU to its recoverable
amount.
For PNG assets and E&E assets, when there
has been an impairment loss recognized, at each reporting date an
assessment is performed as to whether the circumstances which led
to the impairment loss have reversed. If the change in
circumstances leads to the recoverable amount being higher than the
carrying value after recognition of an impairment, that impairment
loss is reversed, with such reversal not to exceed the depreciated
value of the asset had no impairment loss been previously
recognized.
Finance leases
Finance leases, which transfer substantially all the risks and
rewards incidental to legal ownership, are recognized at the
commencement of the least term. The lease obligation and
corresponding capitalized lease asset are measured at the lower of
fair value of the leased property or the present value of the
minimum lease payments, which are determined at the inception of
the lease. Capitalized leased assets are depreciated over the
shorter of the estimated useful life of the asset or the lease
term.
Cash and Cash Equivalents
Cash and cash equivalents include monies on deposit and short-term
investments, which are comprised primarily of guaranteed investment
certificates.
Crude Oil Inventory
Inventories of crude oil, consisting of production for which title
has not yet transferred to the customer, are valued at the lower of
cost or net realizable value. Cost is determined on a
weighted-average basis and includes related operating expenses,
royalties, and depletion.
Provisions and Asset Retirement
Obligations
Vermilion recognizes a provision
or asset retirement obligation in the consolidated financial
statements when an event gives rise to an obligation of uncertain
timing or amount.
The estimated present value of the asset
retirement obligation is recorded as a long-term liability, with a
corresponding increase in the carrying amount of the related
asset. This increase is depleted with the related depletion
unit and is allocated to a CGU for impairment testing. The
liability recorded is increased each reporting period due to the
passage of time and this change is charged to net earnings (loss)
in the period as accretion expense. The asset retirement
obligation can also increase or decrease due to changes in the
estimated timing of cash flows, changes in the discount rate and/or
changes in the original estimated undiscounted costs. Increases or
decreases in the obligation will result in a corresponding change
in the carrying amount of the related asset. Actual costs
incurred upon settlement of the asset retirement obligation are
charged against the asset retirement obligation to the extent of
the liability recorded. Vermilion
discounts the costs related to asset retirement obligations using
the discount rate that reflects current market assessment of the
time value of money and risks specific to the liabilities that have
not been reflected in the cash flow estimates. Vermilion applies discount rates applicable to
each of the jurisdictions in which it has future asset retirement
obligations. Asset retirement obligations are remeasured at each
reporting period in order to reflect the discount rates in effect
at that time.
A provision for onerous contracts is recognized
when the expected benefits to be derived by Vermilion from a contract are lower than the
unavoidable cost of meeting the obligations under the contract. The
provision is measured at the lower of the expected cost of
terminating the contract and the present value of the expected net
cost of the remaining term of the contract. Before a
provision is established, Vermilion first recognizes any impairment loss
on assets associated with the onerous contract. For the periods
presented in the consolidated financial statements, there were no
onerous contracts recognized.
Revenue Recognition
Revenues associated with the sale of crude oil, natural gas and
natural gas liquids are recorded when title passes to the
customer. For the majority of Canadian oil and natural gas
production, legal title transfers upon delivery to major
pipelines. In Australia, oil
is sold at the Wandoo B Platform. In the
Netherlands, natural gas is sold at the plant gate. In
Germany, natural gas is sold upon
delivery to major pipelines. In France, oil is sold either when delivered to
the refinery by pipeline or when delivered to the refinery via
tanker. In the United States, oil
is sold when transferred to the truck from the tank and natural gas
is sold at a custody transfer meter on location.
Financial Instruments
Cash and cash equivalents are classified as held for trading and
are measured at fair value. A gain or loss arising from a
change in the fair value is recognized in net earnings (loss) in
the period in which it occurs.
Accounts receivable are classified as loans and
receivables and are initially measured at fair value and are then
subsequently measured at amortized cost. The carrying value
of accounts receivable approximates the fair value due to the
short-term nature of these instruments.
Accounts payable and accrued liabilities,
dividends payable, finance lease, and long-term debt have been
classified as other financial liabilities and are initially
recognized at fair value and are subsequently measured at amortized
cost. Transaction costs and discounts are recorded against
the fair value of long-term debt on initial recognition.
All derivative instruments have been classified
as held for trading and are measured at fair value. A gain or
loss arising from a change in the fair value is recognized in net
earnings (loss) in the period in which it occurs.
Equity Based Compensation
Vermilion has long-term equity
based compensation plans for directors, officers and employees of
Vermilion and its
subsidiaries. Equity based compensation expense is recognized
in net earnings (loss) over the vesting period of the awards with a
corresponding adjustment to contributed surplus. Upon
vesting, the amount previously recognized in contributed surplus is
reclassified to shareholders' capital.
The expense recognized is based on the grant
date fair value of the awards and incorporates an estimate of the
forfeiture rate based on historical vesting data. The grant
date fair value of the awards is determined as the grant date
closing price of Vermilion's
common shares on the Toronto Stock Exchange, adjusted by the
Company's estimate of the performance factor that will ultimately
be achieved.
Per Share Amounts
Net earnings (loss) per share is calculated using the
weighted-average number of shares outstanding during the
period. Diluted net earnings per share is calculated using
the diluted weighted-average number of shares outstanding during
the period. The diluted weighted-average number of shares is
determined by considering whether equity based compensation plans,
if converted during the year, would result in reduced net earnings
per share.
The treasury stock method is used to determine
the dilutive effect of equity based compensation plans. The
treasury stock method assumes that the deemed proceeds related to
unrecognized equity based compensation expense are used to
repurchase shares at the average market price during the
period. Equity based awards outstanding are included in the
calculation of diluted net earnings per share based on estimated
performance factors.
Foreign Currency Translation
The consolidated financial statements are presented in Canadian
dollars, which is Vermilion's
reporting currency. As several of Vermilion's subsidiaries transact and operate
primarily in countries other than Canada, they accordingly have functional
currencies other than the Canadian dollar.
Transactions denominated in currencies other
than the functional currency of the subsidiary are translated to
the functional currency at the prevailing rates on the date of the
transaction. Non-monetary assets or liabilities that result
from such transactions are held at the prevailing rate on the date
of the transaction. Monetary items denominated in
non-functional currencies are translated to the functional currency
of the subsidiary at the prevailing rate at the balance sheet
date. All translations associated with currencies other than
the respective functional currencies are recorded in net earnings
(loss).
Translation of all assets and liabilities from
the respective functional currencies to the reporting currency are
performed using the rates prevailing at the balance sheet
date. The differences arising upon translation from the
functional currency to the reporting currency are recorded as
currency translation adjustments in other comprehensive income
(loss) and are held within accumulated other comprehensive income
(loss) until a disposal or partial disposal of a subsidiary. A
disposal or partial disposal may give rise to a realized gain or
loss, which is recorded in net earnings (loss).
Within the consolidated group there are
outstanding intercompany loans which in substance represent
investments in certain subsidiaries. When these loans are
identified as part of the net investment in a foreign subsidiary,
any exchange differences arising on those loans are recorded to
currency translation adjustments within other comprehensive income
(loss) until the disposal or partial disposal of the
subsidiary.
Income Taxes
Deferred taxes are calculated using the liability method of
accounting. Under this method, deferred tax is recognized for
the estimated effect of any temporary differences between the
amounts recognized on Vermilion's
consolidated balance sheets and respective tax basis. This
calculation uses enacted or substantively enacted tax rates that
will be in effect when the temporary differences are expected to
reverse. The effect of a change in tax rates on deferred
taxes is recognized in net earnings (loss) in the period in which
the related legislation is substantively enacted.
Deferred tax assets are reviewed each reporting
period and a valuation allowance is recognized if available
evidence indicates that it is not probable that all or a part of a
deferred tax asset will be utilized in future periods. A
previously recognized valuation allowance is removed when available
evidence indicates that all or a part of the valuation allowance is
no longer required.
Vermilion is
subject to current income taxes based on the tax legislation of
each respective country in which Vermilion conducts business.
Borrowing Costs
Borrowing costs that are directly attributable to the acquisition
or construction of an asset that necessarily takes a substantial
period of time to prepare for its intended use are capitalized as
part of the cost of that asset. Borrowing costs are
capitalized by applying interest rates attributable to the project
being financed and could include both general and/or specific
borrowings. Interest rates applied from general borrowings are
computed using the weighted average borrowing rate for the
period.
Measurement Uncertainty
The preparation of the consolidated financial statements requires
management to make estimates and assumptions that affect the
reported amounts of assets and liabilities, disclosure of
contingent assets and liabilities at the date of the consolidated
financial statements and the reported amounts of revenues and
expenses for the periods presented.
Key areas where management has made complex or
subjective judgments include asset retirement obligations,
assessment of impairment or recovery of impairment of long-lived
assets and income taxes. Actual results could differ
significantly from these and other estimates.
Asset Retirement Obligations
Vermilion's asset retirement
obligations are based on the expected cost of adherence to
environmental regulations and estimates of the amount and timing of
future expenditures. Changes in environmental regulations,
the estimated costs associated with reclamation activities, the
discount rate applied and the timing of expenditures could
materially impact Vermilion's
measurement of the obligations and, correspondingly, impact
Vermilion's financial position and
net earnings (loss).
Assessment of Impairments or Recovery of
Previous Impairments
Impairment tests are performed at a CGU level. CGUs are
determined based on management's judgment of the lowest level at
which there is identifiable cash inflows that are largely
independent of the cash inflows of other groups of assets or
properties. The factors used by Vermilion to determine CGUs may vary by
country due to the unique operating and geographic circumstances in
each country. However, in general, Vermilion will assess the following factors in
determining whether a group of assets generate largely independent
cash inflows: geographic proximity of the assets within a group to
one another, geographic proximity of the group of assets to other
groups of assets, homogeneity of the production from the group of
assets and the sharing of infrastructure used to process and/or
transport production.
The calculation of the recoverable amount of the
CGUs is based on market factors, estimates of PNG reserves and
future costs required to develop reserves. Vermilion's reserve estimates and the related
future cash flows are subject to measurement uncertainty, and the
impact on the consolidated financial statements of future periods
could be material. Considerable management judgment is used
in determining the recoverable amount of PNG assets, including
determining the quantity of reserves, the time horizon to develop
and produce such reserves and the estimated revenues and
expenditures of such production.
Income Taxes
Tax interpretations, regulations, and legislation in the various
jurisdictions in which Vermilion
and its subsidiaries operate are subject to change and
interpretation. Such changes can affect the timing of the
reversal of temporary tax differences, the tax rates in effect when
such differences reverse and Vermilion's ability to use tax losses and
other tax pools in the future. The Company's income tax
filings are subject to audit by taxation authorities in numerous
jurisdictions and the results of such audits may increase or
decrease the tax liability. The determination of
current and deferred tax amounts recognized in the consolidated
financial statements are based on management's assessment of the
tax positions, which includes consideration of their technical
merits, communications with tax authorities and management's view
of the most likely outcome.
3. CHANGES TO ACCOUNTING PRONOUNCEMENTS
Accounting pronouncements not yet adopted
The impacts of the adoption of the following
pronouncements are currently being evaluated.
IFRS 9 "Financial Instruments"
On July 24, 2014, the IASB issued the
final element of its comprehensive response to the financial crisis
by issuing IFRS 9 "Financial Instruments". The improvements
introduced by IFRS 9 includes a model for classification and
measurement, a single, forward-looking 'expected loss' impairment
model and a substantially-reformed approach to hedge
accounting. Vermilion will
adopt the standard for reporting periods beginning January 1, 2018.
IFRS 15 "Revenue from Contracts with
Customers"
On May 28, 2014, the IASB issued IFRS
15 "Revenue from Contracts with Customers", a new standard that
specifies recognition requirements for revenue as well as requiring
entities to provide the users of financial statements with more
informative and relevant disclosures. The standard replaces
IAS 11 "Construction Contracts" and IAS 18 "Revenue" as well as a
number of revenue-related interpretations. Vermilion will adopt the standard for
reporting periods beginning January 1,
2018.
IFRS 16 "Leases"
On January 13, 2016, the IASB issued
IFRS 16, "Leases", a new standard which will replace IAS 17,
"Leases". Under IFRS 16, a single recognition and measurement
model will apply for lessees which will require recognition of
assets and liabilities for most leases. Vermilion will adopt the standard for
reporting periods beginning January 1,
2019.
4. BUSINESS COMBINATIONS
Property acquisition:
Germany
In February of 2014, Vermilion acquired, through a wholly-owned
subsidiary, GDF's 25% interest in four producing natural gas fields
and a surrounding exploration license located in northwest
Germany. GDF is an affiliate of
GDF Suez S.A., a publicly traded, French multinational utility. The
acquisition represented Vermilion's entry into the German E&P
business, a producing region with a long history of oil and gas
development activity, low political risk and strong marketing
fundamentals. The acquisition was well aligned with Vermilion's European focus, and has increased
the company's exposure to the strong fundamentals and pricing of
the European natural gas markets. The acquisition closed in
February of 2014 for cash proceeds of $172.9
million. Vermilion funded
this acquisition with existing credit facilities.
The acquired assets were comprised of four gas
producing fields across eleven production licenses and included
both exploration and production licenses that comprised a total of
207,000 gross acres, of which 85% was in the exploration
license.
The acquisition was accounted for as a business
combination with the fair value of the assets acquired and
liabilities assumed at the date of acquisition summarized as
follows:
($M) |
Consideration |
Cash paid to vendor |
|
172,871 |
Total consideration |
|
172,871 |
|
|
|
($M) |
Allocation of
Consideration |
Petroleum and natural gas assets |
|
158,840 |
Exploration and evaluation |
|
16,065 |
Asset retirement obligations assumed |
|
(2,030) |
Deferred tax liabilities |
|
(4) |
Net assets acquired |
|
172,871 |
The results of operations from the assets
acquired were included in Vermilion's consolidated financial statements
beginning February of 2014 and had contributed net revenues of
$33.3 million and a net loss of
$0.3 million for the year ended
December 31, 2014.
Had the acquisition occurred on January 1, 2014, management estimates that
consolidated revenues would have increased by an additional
$4.6 million and consolidated net
earnings would have increased by $0.9
million for the year ended December
31, 2014.
Corporate acquisitions:
a) Elkhorn Resources Inc.
On April 29, 2014,
Vermilion acquired Elkhorn
Resources Inc., a private southeast Saskatchewan producer. The acquisition
created a new core area for Vermilion in the Williston Basin.
The acquired assets included approximately
57,000 net acres of land (approximately 80% undeveloped), seven oil
batteries, and preferential access to a minimum of 50% of capacity
at a solution gas facility.
Total consideration was comprised of
$180.4 million of cash, which was
funded with existing credit facilities, and the issuance of 2.8
million Vermilion common shares
valued at approximately $205.0
million (based on the closing price per Vermilion common share of $72.50 on the Toronto Stock Exchange on
April 29, 2014).
The acquisition was accounted for as a business
combination with the fair value of the assets acquired and
liabilities assumed at the date of acquisition summarized as
follows:
($M) |
Consideration |
Cash paid to shareholders of Elkhorn Resources
Inc. |
|
180,353 |
Shares issued pursuant to corporate
acquisition |
|
204,960 |
Total consideration |
|
385,313 |
|
|
|
($M) |
Allocation of
Consideration |
Petroleum and natural gas assets |
|
390,523 |
Exploration and evaluation |
|
138,264 |
Asset retirement obligations assumed |
|
(5,974) |
Deferred tax liabilities |
|
(89,437) |
Long-term debt assumed |
|
(47,526) |
Cash acquired |
|
4,174 |
Acquired non-cash working capital deficiency |
|
(4,711) |
Net assets acquired |
|
385,313 |
The results of operations from the assets
acquired were included in Vermilion's consolidated financial statements
beginning April 29, 2014 and
contributed revenues of $50.6 million
and operating income of $39.8 million
for the year ended December 31,
2014.
Had the acquisition occurred on January 1, 2014, management estimates that
consolidated revenues would have increased by an additional
$8.8 million and consolidated
operating income would have increased by $7.0 million for the year ended December 31, 2014. In determining the pro-forma
amounts, management had assumed that the fair value adjustments,
determined provisionally, that arose at the date of acquisition
would have been the same if the acquisition had occurred on
January 1, 2014. It is
impracticable to derive all amounts necessary to determine the
impact on net earnings from the acquisition as the acquired company
was immediately merged with Vermilion's operations.
5. CAPITAL ASSETS
The following table reconciles the change in Vermilion's capital assets:
|
Petroleum and |
Furniture and |
|
Total |
($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 |
|
482,574 |
|
4,287 |
|
486,861 |
Property acquisitions |
|
27,731 |
|
- |
|
27,731 |
Changes in estimate for asset retirement
obligations |
|
(78,429) |
|
- |
|
(78,429) |
Depletion and depreciation |
|
(431,889) |
|
(6,453) |
|
(438,342) |
Recognition of finance lease asset
(1) |
|
31,028 |
|
- |
|
31,028 |
Impairment (2) |
|
(219,808) |
|
- |
|
(219,808) |
Effect of movements in foreign exchange rates |
|
146,641 |
|
595 |
|
147,236 |
Balance at December 31, 2015 |
|
3,449,043 |
|
18,326 |
|
3,467,369 |
|
|
|
|
|
|
|
Cost |
|
5,114,188 |
|
54,723 |
|
5,168,911 |
Accumulated depletion and depreciation |
|
(1,622,993) |
|
(34,826) |
|
(1,657,819) |
Carrying amount at December 31, 2014 |
|
3,491,195 |
|
19,897 |
|
3,511,092 |
|
|
|
|
|
|
|
Cost |
|
5,624,809 |
|
57,652 |
|
5,682,461 |
Accumulated depletion and depreciation |
|
(2,175,766) |
|
(39,326) |
|
(2,215,092) |
Carrying amount at December 31, 2015 |
|
3,449,043 |
|
18,326 |
|
3,467,369 |
|
|
(1) |
Refer to Financial Statement Note 16 - Leases |
(2) |
Refer to Financial Statement Note 6 - Exploration and
Evaluation Assets |
Depletion and depreciation rates
PNG assets (unit of production method)
Furniture and office equipment (declining balance at rates of 5% to
25%)
Capitalized overhead
During the year ended December 31,
2015, Vermilion capitalized
$5.1 million (2014 - $7.7 million) of overhead costs directly
attributable to PNG activities.
Impairments
On a quarterly basis, Vermilion
performs an assessment as to whether any 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 recoverable amount takes into account
commodity price forecasts, expected production, estimated costs and
timing of development, and undeveloped land values.
As a result of declines in commodity price
forecasts, which decreased expected cash flows, Vermilion recorded a non-cash impairment
charge of $131.6 million in the
Canada segment for the three
months ended December 31, 2015
($274.6 million for the year ended
December 31, 2015, of which
$219.8 million related to PNG assets
and $54.8 million related to E&E
assets). The recoverable amount of each CGU was determined using a
value in use approach based on 2015 year end reserves and resource
data, an after-tax discount rate of 9% for proved and probable
reserves, and an after-tax discount rate of 15% on resources
carried within exploration and evaluation assets.
This impairment charge in the year ended
December 31, 2015 related to the
light crude oil play in Saskatchewan,
Canada ($267.9 million based
on a recoverable amount of $266.8
million) and the shallow coal bed methane properties in
Alberta, Canada ($6.7 million based on a recoverable amount of
$19.7 million). The determination of
impairment is sensitive to changes in key judgments, including
reserve or resource revisions, changes in forward commodity prices
and exchange rates, and changes in costs and timing of development.
Changes in these key judgments would impact the recoverable amount
of CGUs, therefore resulting in additional impairment charges or
recoveries. For the year ended December 31,
2015, a one percent increase in the assumed discount rate on
expected cash flows of the Saskatchewan light crude oil and Alberta shallow coal bed methane CGUs would
result in an additional impairment of $19.5
million, and a five percent decrease in commodity prices
would result in an additional impairment of $33.3 million.
Vermilion also
identified indicators of impairment on the Ireland CGU which
consists of Vermilion's
non-operating interest in offshore Corrib natural gas field, but
determined that the recoverable amount exceeded its carrying value
and accordingly, no impairment charge was recorded. For the year
ended December 31, 2015, a one
percent increase in the assumed discount rate on expected cash
flows of the Ireland CGU would have resulted in impairment of
$21.9 million, and a five percent
decrease in commodity prices would result in an impairment of
$33.6 million.
The following table outlines the forward
commodity price estimates that were used in the calculation of
recoverable amounts:
Forward Commodity Price
Assumptions (1) |
|
|
WTI Oil
(US $/bbl) |
|
AECO Gas
(CDN $/mmbtu) |
|
Blended NGLs (2)
(CDN $/bbl) |
|
NBP Gas
(US $/mmbtu) |
|
CDN $/US $
Exchange Rate |
2016 |
|
44.00 |
|
2.76 |
|
30.27 |
|
5.55 |
|
0.73 |
2017 |
|
52.00 |
|
3.27 |
|
35.76 |
|
5.68 |
|
0.75 |
2018 |
|
58.00 |
|
3.45 |
|
39.04 |
|
6.10 |
|
0.78 |
2019 |
|
64.00 |
|
3.63 |
|
42.96 |
|
6.70 |
|
0.80 |
2020 |
|
70.00 |
|
3.81 |
|
45.85 |
|
7.30 |
|
0.83 |
2021 |
|
75.00 |
|
3.90 |
|
47.86 |
|
7.80 |
|
0.85 |
2022 |
|
80.00 |
|
4.10 |
|
51.23 |
|
8.30 |
|
0.85 |
2023 |
|
85.00 |
|
4.30 |
|
54.59 |
|
8.80 |
|
0.85 |
2024 |
|
87.88 |
|
4.50 |
|
56.05 |
|
9.14 |
|
0.85 |
2025 |
|
89.63 |
|
4.60 |
|
57.18 |
|
9.32 |
|
0.85 |
Thereafter |
|
+2.0% per year |
|
+2.0% per year |
|
+2.0% per year |
|
+2.0% per year |
|
0.85 |
|
|
(1) |
Source: GLJ Petroleum Consultants price forecast, effective
January 1, 2016. |
(2) |
The price of blended NGLs shown above is determined used a
simple average for Ethane, Propane, Butane, and C5+. |
6. EXPLORATION AND EVALUATION ASSETS
The following table reconciles the change in Vermilion's exploration and evaluation
assets:
($M) |
Exploration and Evaluation
Assets |
Balance at January 1, 2014 |
|
136,259 |
Additions |
|
69,035 |
Changes in estimate
for asset retirement obligations |
|
22 |
Property acquisitions |
|
46,135 |
Corporate acquisitions |
|
|
138,264 |
Depreciation |
|
(5,038) |
Effect of movements in
foreign exchange rates |
|
(4,056) |
Balance at December 31,
2014 |
|
380,621 |
Changes in estimate
for asset retirement obligations |
|
(130) |
Property acquisitions |
|
1,166 |
Depreciation |
|
(21,893) |
Impairment
(1) |
|
(54,815) |
Effect of movements in foreign
exchange rates |
|
3,243 |
Balance at December
31, 2015 |
|
308,192 |
|
|
|
|
|
Cost |
|
399,348 |
Accumulated depreciation |
|
(18,727) |
Carrying amount at
December 31, 2014 |
|
380,621 |
|
|
|
|
|
Cost |
|
362,919 |
Accumulated depreciation |
|
(54,727) |
Carrying amount at
December 31, 2015 |
|
308,192 |
|
|
(1) |
Refer to Financial Statement Note 5 - Capital Assets |
7. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the change in
Vermilion's asset retirement
obligations:
($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 |
|
|
3,550 |
Changes in estimates for asset
retirement obligations |
|
|
1,117 |
Obligations settled |
|
|
(11,369) |
Accretion |
|
|
23,911 |
Changes in discount rates |
|
|
(83,226) |
Effect of movements in foreign exchange rates |
|
|
20,877 |
Balance at December 31, 2015 |
|
|
305,613 |
Vermilion has
estimated the net present value of its asset retirement obligations
to be $305.6 million as at
December 31, 2015 (2014 -
$350.8 million) based on a total
undiscounted future liability, after inflation adjustment, of
$1.3 billion (2014 - $1.3 billion). These payments are expected
to be made between 2016 and 2064. Vermilion calculated the present value of the
obligations using discount rates between 7.1% and 10.3% (2014 -
between 5.7% and 7.9%) to reflect the market assessment of the time
value of money as well as risks specific to the liabilities that
have not been included in the cash flow estimates. Inflation
rates used in determining the cash flow estimates were between 0.6%
and 2.4% (2014 - between 0.8% and 2.4%).
Vermilion
reviews annually its estimates of the expected costs to reclaim the
net interest in its wells and facilities. The resulting
changes are categorized as changes in estimates for existing
obligations in the preceding table. The decrease in the
liability for the year ended December 31,
2015 primarily resulted from an overall increase in the
discount rates applied to the abandonment obligations.
8. LONG-TERM DEBT
The following table summarizes Vermilion's outstanding long-term debt:
|
|
|
|
|
As
at |
($M) |
|
|
|
|
Dec 31, 2015 |
|
Dec 31, 2014 |
Revolving credit facility |
|
|
|
|
1,162,998 |
|
1,014,067 |
Senior unsecured notes
(1) |
|
|
|
|
224,901 |
|
224,013 |
Long-term debt |
|
|
|
|
1,387,899 |
|
1,238,080 |
|
|
(1) |
The senior unsecured notes, which matured on February 10, 2016,
are included in the current portion of long-term debt as at
December 31, 2015. |
Revolving Credit Facility
At December 31,
2015, Vermilion had in
place a bank revolving credit facility totalling $2 billion, of which approximately $1.16 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 year ended December
31, 2015, the interest rate on the revolving credit facility
was approximately 3.1% (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 $25.2 million as at December 31, 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 borrowings (defined as amounts classified as
"Long-term debt", "Current portion of long term debt", and "Finance
lease obligation" on the balance sheet and referred to collectively
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 "Shareholders'
equity" on the balance sheet plus consolidated total senior debt as
defined above) of not greater than 50%.
As at December 31,
2015, Vermilion was in
compliance with all financial covenants.
Senior Unsecured Notes
On February 10,
2011, Vermilion issued
$225.0 million of senior unsecured
notes at par. The notes bear interest at a rate of 6.5% per
annum and matured on February 10,
2016. As direct senior unsecured obligations of
Vermilion, the notes ranked pari
passu with all other present and future unsecured and
unsubordinated indebtedness of the Company. The notes were
initially recognized at fair value net of transaction costs and
were subsequently measured at amortized cost using an effective
interest rate of 7.1%.
Subsequent to December
31, 2015, Vermilion repaid
the senior unsecured notes using funds from the revolving credit
facility.
9. INCOME TAXES
Deferred taxes
The net deferred income tax liability at December 31, 2015 and 2014 is comprised of the
following:
|
|
Year
Ended |
($M) |
Dec 31, 2015 |
Dec 31, 2014 |
Deferred income tax liabilities: |
|
|
|
|
|
Derivative contracts |
|
(18,452) |
|
(5,965) |
|
Capital assets |
|
(349,664) |
|
(445,457) |
|
Asset retirement obligations |
|
(130,904) |
|
(96,616) |
|
Unrealized foreign exchange |
|
(16,300) |
|
(14,507) |
|
Other |
|
(10,767) |
|
(13,164) |
Deferred income tax assets: |
|
|
|
|
|
Capital assets |
|
77,343 |
|
72,821 |
|
Non-capital losses |
|
175,477 |
|
178,222 |
|
Asset retirement obligations |
|
51,958 |
|
65,760 |
|
Unrealized foreign exchange |
|
- |
|
720 |
|
Other |
|
2,408 |
|
2,819 |
Net deferred income tax liability |
|
(218,901) |
|
(255,367) |
Comprised of: |
|
|
|
|
|
Deferred income tax assets |
|
135,753 |
|
154,816 |
|
Deferred income tax liability |
|
(354,654) |
|
(410,183) |
Net deferred income tax liability |
|
(218,901) |
|
(255,367) |
Income tax expense differs from the amount that would have been
expected if the reported earnings had been subject only to the
statutory Canadian income tax rate of 26.2% (2014 - 25.5%), as
follows:
|
|
Year
Ended |
($M) |
Dec 31, 2015 |
|
Dec 31, 2014 |
Earnings (loss) before income
taxes |
|
(213,915) |
|
453,072 |
Canadian corporate tax
rate |
|
26.2% (1) |
|
25.5% |
Expected tax expense (recovery) |
|
(56,046) |
|
115,533 |
Increase (decrease) in taxes resulting
from: |
|
|
|
|
|
Petroleum resource rent tax rate
(PRRT) differential (2) |
|
8,310 |
|
37,035 |
|
Foreign tax rate differentials
(2), (3) |
|
(8,096) |
|
3,492 |
|
Equity based compensation expense |
|
14,000 |
|
17,290 |
|
Amended returns and changes to estimated tax pools
and tax positions |
|
(6,856) |
|
(7,512) |
|
Changes in statutory tax rates and the estimated
reversal rates associated with temporary differences |
|
1,733 |
|
16,429 |
|
Valuation allowance |
|
51,736 |
|
- |
|
Other non-deductible items |
|
(1,394) |
|
1,479 |
Provision for income taxes |
|
3,387 |
|
183,746 |
|
|
(1) |
The corporate tax rate increased to 26.2% in 2015 from 25.5% in
2014 due to the Alberta corporate tax rate increase of 2.0%
effective July 1, 2015. |
(2) |
In Australia, current taxes include both corporate income tax
rates and PRRT. Corporate income tax rates were applied at a rate
of 30% and PRRT was applied at a rate of 40%. |
(3) |
The combined tax rate was 34.4% in France, 46.0% in the
Netherlands, 24.2% in Germany, 25% in Ireland, and 35% in the
United States. |
|
The corporate tax rate for Germany increased to 24.2% (2014 -
22.8%) due to a trade tax increase of 1.4% effective January
2015. |
10. SHAREHOLDERS' CAPITAL
The following table reconciles the change in
Vermilion's shareholders'
capital:
Shareholders' Capital |
Number of Shares
('000s) |
|
Amount ($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 |
|
3,338 |
|
155,033 |
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 |
|
57 |
|
2,619 |
Balance as at December 31, 2015 |
|
111,991 |
|
2,181,089 |
Vermilion is
authorized to issue an unlimited number of common shares with no
par value.
Dividends
Dividends declared to shareholders for the year
ended December 31, 2015 were
$283.6 million (2014 - $272.7 million). Dividends are approved by
the Board of Directors and are paid monthly. Vermilion has a dividend reinvestment plan
("DRIP") which allows eligible holders of common shares to purchase
additional common shares at a 3% discount to market by reinvesting
their cash dividends. Additionally, an amendment to the existing
DRIP to include a Premium Dividend™ Component was announced in
February 2015. With the addition of
the Premium Dividend™ Component eligible shareholders have the
option to reinvest their dividends in new common shares which are
exchanged for a premium cash payment equal to 101.5% of the
reinvested dividends.
Subsequent to the end of year-end and prior to
the consolidated financial statements being authorized for issue on
February 25, 2016, Vermilion declared dividends totalling
$48.5 million or $0.215 per share for each of January and February
of 2016.
11. EQUITY BASED COMPENSATION
The following table summarizes the number of
awards outstanding under the Vermilion Incentive Plan ("VIP"):
|
|
|
|
|
|
|
|
|
|
Number of Awards ('000s) |
|
|
|
|
|
2015 |
|
|
2014 |
Opening balance |
|
|
|
|
|
1,775 |
|
|
1,665 |
Granted |
|
|
|
|
|
609 |
|
|
707 |
Vested |
|
|
|
|
|
(587) |
|
|
(515) |
Modified |
|
|
|
|
|
- |
|
|
(21) |
Forfeited |
|
|
|
|
|
(86) |
|
|
(61) |
Closing balance |
|
|
|
|
|
1,711 |
|
|
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. Dividends, which notionally accrue to
the awards during the vesting period, are not included in the
determination of grant date fair values. For the year ended
December 31, 2015, the awards granted
had a weighted average fair value of $80.70 (2014 - $101.63).
The performance factor is determined by the
Board of Directors after consideration of Company performance using
Vermilion's balanced scorecard
metrics including, but not limited to, relative total shareholder
return, financial and operational performance, and performance on
strategic objectives.
The expense recognized is based on the grant
date fair value of the awards and incorporates an estimate of
forfeiture rate based on historical vesting data. For the
year ended December 31, 2015,
Vermilion incorporated an
estimated forfeiture rate of 4.8% (2014 - 5.8%). Equity based
compensation expense of $72.6 million
was recorded during the year ended December
31, 2015 (2014 - $67.1
million) related to the VIP.
12. PER SHARE AMOUNTS
Basic and diluted net earnings (loss) per share have been
determined based on the following:
|
|
|
|
Year
Ended |
($M except per share
amounts) |
|
|
Dec 31, 2015 |
|
Dec 31, 2014 |
Net (loss) earnings [1] |
|
|
(217,302) |
|
269,326 |
Basic weighted average shares
outstanding [2] |
|
|
109,642 |
|
105,448 |
Dilutive impact of equity based
awards |
|
|
- |
|
1,739 |
Diluted weighted average shares
outstanding [3] |
|
|
109,642 |
|
107,187 |
Basic (loss) earnings per share ([1] ÷
[2]) |
|
|
(1.98) |
|
2.55 |
Diluted (loss) earnings per share ([1]
÷ [3]) |
|
|
(1.98) |
|
2.51 |
13. DERIVATIVE INSTRUMENTS
The nature of Vermilion's operations results in exposure to
fluctuations in commodity prices, interest rates and foreign
currency exchange rates. Vermilion monitors and, when appropriate, uses
derivative financial instruments to manage its exposure to these
fluctuations. All transactions of this nature entered into by
Vermilion are related to an
underlying financial position or to future crude oil and natural
gas production. Vermilion
does not use derivative financial instruments for speculative
purposes. Vermilion has
elected not to designate any of its derivative financial
instruments as accounting hedges and thus accounts for changes in
fair value in net earnings at each reporting period.
Vermilion has not obtained
collateral or other security to support its financial derivatives
as management reviews the creditworthiness of its counterparties
prior to entering into derivative contracts.
During the normal course of business,
Vermilion may enter into fixed
price arrangements to sell a portion of its production or purchase
commodities for operational use. Vermilion does not apply fair value accounting
on these contracts as they were entered into and continue to be
held for the sale of production or operational use in accordance
with the Company's expected requirements.
The following tables summarize Vermilion's outstanding risk management
positions as at December 31,
2015:
|
|
|
Note |
|
|
Volume |
|
|
Strike Price(s) |
Crude Oil |
|
|
|
|
|
|
|
|
|
WTI - Collar |
|
|
|
|
|
|
|
|
|
July 2015 - March 2016 |
|
|
1 |
|
|
250 bbl/d |
|
|
75.00 - 83.45 CAD $ |
July 2015 - June 2016 |
|
|
2 |
|
|
500 bbl/d |
|
|
75.50 - 85.08 CAD $ |
Dated Brent - Collar |
|
|
|
|
|
|
|
|
|
July 2015 - June 2016 |
|
|
3 |
|
|
1,000 bbl/d |
|
|
80.50 - 93.49 CAD $ |
July 2015 - June 2016 |
|
|
4 |
|
|
500 bbl/d |
|
|
64.50 - 75.48 US $ |
October 2015 - June 2016 |
|
|
5 |
|
|
250 bbl/d |
|
|
82.00 - 94.55 CAD $ |
January 2016 - June 2016 |
|
|
1 |
|
|
250 bbl/d |
|
|
84.00 - 93.70 CAD $ |
|
|
|
|
|
|
|
|
|
|
North American Natural Gas |
|
|
|
|
|
|
|
|
|
AECO - Collar |
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
5,000 GJ/d |
|
|
2.30 - 2.80 CAD $ |
AECO Basis - Fixed Price Differential |
|
|
|
|
|
|
|
|
|
November 2015 - March 2016 |
|
|
|
|
|
2,500 mmbtu/d |
|
|
Nymex HH less 0.47 US $ |
Nymex HH - Collar |
|
|
|
|
|
|
|
|
|
November 2015 - March 2016 |
|
|
6 |
|
|
5,000 mmbtu/d |
|
|
3.25 - 3.86 US $ |
|
|
(1) |
The contracted volumes increase to 500 boe/d
for any monthly settlement periods above the contracted ceiling
price and are settled on the monthly average
price (monthly average US$/bbl multiplied by the Bank of Canada
monthly average noon day rate). |
(2) |
The contracted volumes increase to 1,250 boe/d
for any monthly settlement periods above the contracted ceiling
price and are settled on the monthly average
price (monthly average US$/bbl multiplied by the Bank of Canada
monthly average noon day rate). |
(3) |
The contracted volumes increase to 2,500 boe/d
for any monthly settlement periods above the contracted ceiling
price and are settled on the monthly average
price (monthly average US$/bbl multiplied by the Bank of Canada
monthly average noon day rate). |
(4) |
The contracted volumes increase to 1,000 boe/d
for any monthly settlement periods above the contracted ceiling
price. |
(5) |
The contracted volumes increase to 750 boe/d
for any monthly settlement periods above the contracted ceiling
price and are settled on the monthly average
price (monthly average US$/bbl multiplied by the Bank of Canada
monthly average noon day rate). |
(6) |
The contracted volumes increase to 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 £ |
January 2017 - December 2017 |
|
|
|
|
|
2,638 GJ/d |
|
|
3.22 - 3.75 GBP £ |
January 2018 - December 2018 |
|
|
|
|
|
2,638 GJ/d |
|
|
2.99 - 3.63 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 € |
January 2017 - December 2017 |
|
|
1 |
|
|
2,638 GJ/d |
|
|
4.00 GBP £ |
January 2018 - December 2018 |
|
|
2 |
|
|
2,638 GJ/d |
|
|
3.83 GBP £ |
TTF - Call |
|
|
|
|
|
|
|
|
|
October 2016 - March 2017 |
|
|
|
|
|
2,592 GJ/d |
|
|
6.03 EUR € |
TTF - Collar |
|
|
|
|
|
|
|
|
|
January 2016 - December 2016 |
|
|
3 |
|
|
2,592 GJ/d |
|
|
5.76 - 6.50 EUR € |
April 2016 - December 2016 |
|
|
4 |
|
|
12,960 GJ/d |
|
|
5.58 - 6.21 EUR € |
April 2016 - March 2017 |
|
|
5 |
|
|
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 |
|
|
3 |
|
|
2,592 GJ/d |
|
|
5.07 - 6.56 EUR € |
July 2016 - March 2018 |
|
|
3 |
|
|
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 |
|
|
6 |
|
|
7,776 GJ/d |
|
|
5.00 - 6.15 EUR € |
January 2018 - December 2018 |
|
|
|
|
|
5,184 GJ/d |
|
|
4.17 - 5.03 EUR € |
TTF - Put |
|
|
|
|
|
|
|
|
|
April 2016 - September 2016 |
|
|
|
|
|
2,592 GJ/d |
|
|
5.21 EUR € |
TTF - Swap |
|
|
|
|
|
|
|
|
|
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 - March 2016 |
|
|
|
|
|
5,832 GJ/d |
|
|
6.18 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 € |
January 2017 - December 2017 |
|
|
7 |
|
|
2,592 GJ/d |
|
|
5.04 EUR € |
|
|
|
|
|
|
|
|
|
|
Electricity |
|
|
|
|
|
|
|
|
|
AESO - Swap |
|
|
|
|
|
|
|
|
|
January 2016 - December 2016 |
|
|
|
|
|
93.6 MWh/d |
|
|
38.58 CAD $ |
|
|
|
|
|
|
|
|
|
|
Interest Rate |
|
|
|
|
|
|
|
|
|
CDOR to fixed - Swap |
|
|
|
|
|
|
|
|
|
September 2015 - September 2019 |
|
|
|
|
|
100,000,000 CAD $/year |
|
|
1.00 % |
October 2015 - October 2019 |
|
|
|
|
|
100,000,000 CAD $/year |
|
|
1.10 % |
|
|
(1) |
On the last business day of each month, the counterparty has
the option to increase the contracted volumes by an additional
2,638 GJ/d at the contracted price, for the following month. |
(2) |
On the last business day of each month, the counterparty has
the option to increase the contracted volumes to 7,913 GJ/d at the
contracted price, for the following month. |
(3) |
The contracted volumes increase to 5,184 GJ/d for any monthly
settlement periods above the contracted ceiling price. |
(4) |
The contracted volumes increase to 15,552 GJ/d for any monthly
settlement periods above the contracted ceiling price. |
(5) |
The contracted volumes increase to 10,368 GJ/d for any monthly
settlement periods above the contracted ceiling price. |
(6) |
The contracted volumes increase to 18,144 GJ/d for any monthly
settlement periods above the contracted ceiling price. |
(7) |
On the last business day of each month, the counterparty has
the option to increase the contracted volumes by an additional
5,184 GJ/d at the contracted price, for the following month. |
The following table reconciles the change in the
fair value of Vermilion's
derivative instruments:
|
|
|
|
|
|
|
|
|
|
Year ended |
($M) |
|
|
Dec 31, 2015 |
|
|
Dec 31, 2014 |
Fair value of contracts, beginning of
year |
|
|
24,794 |
|
|
(1,287) |
Reversal of opening contracts settled
during the year |
|
|
(23,391) |
|
|
1,287 |
Acquired derivative contracts |
|
|
- |
|
|
(1,290) |
Realized gain on contracts settled
during the year |
|
|
41,356 |
|
|
36,712 |
Unrealized gain during the year on
contracts outstanding at the end of the year |
|
|
66,939 |
|
|
26,084 |
Net receipt from counterparties on
contract settlements during the year |
|
|
(41,356) |
|
|
(36,712) |
Fair value of contracts, end of
year |
|
|
68,342 |
|
|
24,794 |
Comprised of: |
|
|
|
|
|
|
|
Current derivative asset |
|
|
55,214 |
|
|
23,391 |
|
Non-current derivative asset |
|
|
13,128 |
|
|
1,403 |
Fair value of contracts, end of
year |
|
|
68,342 |
|
|
24,794 |
The gain on derivative instruments for 2015 and 2014 were
comprised of the following:
|
|
|
|
|
|
|
Year
Ended |
($M) |
Dec 31, 2015 |
|
|
Dec 31, 2014 |
Realized gain on contracts settled
during the year |
(41,356) |
|
|
(36,712) |
Reversal of opening contracts settled
during the year |
23,391 |
|
|
(1,287) |
Unrealized gain during the year on
contracts outstanding at the end of the year |
(66,939) |
|
|
(26,084) |
Gain on derivative instruments |
(84,904) |
|
|
(64,083) |
14. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in non-cash working capital is comprised of the
following:
|
Year Ended |
($M) |
|
|
Dec 31, 2015 |
|
|
Dec 31, 2014 |
Changes in: |
|
|
|
|
|
|
|
Accounts receivable |
|
|
11,321 |
|
|
(4,202) |
|
Crude oil inventory |
|
|
(3,569) |
|
|
7,633 |
|
Prepaid expenses |
|
|
2,577 |
|
|
1,400 |
|
Accounts payable and accrued
liabilities |
|
|
(49,449) |
|
|
30,364 |
|
Income taxes payable |
|
|
(38,457) |
|
|
(11,152) |
|
Movements in foreign exchange
rates |
|
|
(8,793) |
|
|
(8,601) |
Changes in non-cash working
capital |
|
|
(86,370) |
|
|
15,442 |
Changes in non-cash operating working
capital |
|
|
(60,390) |
|
|
3,077 |
Changes in non-cash investing working
capital |
|
|
(25,980) |
|
|
12,365 |
Changes in non-cash working
capital |
|
|
(86,370) |
|
|
15,442 |
15. 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.
|
Year
Ended December 31, 2015 |
($M) |
Canada |
|
France |
|
Netherlands |
|
Germany |
|
Ireland |
|
Australia |
|
United States |
|
Corporate |
|
Total |
Total assets |
1,609,180 |
|
863,304 |
|
212,749 |
|
167,908 |
|
908,453 |
|
235,139 |
|
42,927 |
|
169,560 |
|
4,209,220 |
Drilling and development |
201,508 |
|
92,265 |
|
47,325 |
|
5,363 |
|
66,409 |
|
61,741 |
|
12,250 |
|
- |
|
486,861 |
Oil and gas sales to external customers |
320,613 |
|
281,422 |
|
129,057 |
|
41,384 |
|
57 |
|
162,765 |
|
4,288 |
|
- |
|
939,586 |
Royalties |
(28,144) |
|
(26,958) |
|
(3,082) |
|
(6,479) |
|
- |
|
- |
|
(1,257) |
|
- |
|
(65,920) |
Revenue from external customers |
292,469 |
|
254,464 |
|
125,975 |
|
34,905 |
|
57 |
|
162,765 |
|
3,031 |
|
- |
|
873,666 |
Transportation expense |
(16,326) |
|
(15,378) |
|
- |
|
(3,269) |
|
(6,687) |
|
- |
|
- |
|
- |
|
(41,660) |
Operating expense |
(89,085) |
|
(50,718) |
|
(22,746) |
|
(10,956) |
|
(15) |
|
(51,676) |
|
(742) |
|
- |
|
(225,938) |
General and administration |
(16,888) |
|
(20,217) |
|
(4,158) |
|
(7,386) |
|
(2,517) |
|
(5,754) |
|
(3,836) |
|
7,172 |
|
(53,584) |
PRRT |
- |
|
- |
|
- |
|
- |
|
- |
|
(6,878) |
|
- |
|
- |
|
(6,878) |
Corporate income taxes |
- |
|
(23,764) |
|
(12,152) |
|
- |
|
- |
|
(7,230) |
|
- |
|
(1,091) |
|
(44,237) |
Interest expense |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(59,852) |
|
(59,852) |
Realized gain on derivative instruments |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
41,356 |
|
41,356 |
Realized foreign exchange gain |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
623 |
|
623 |
Realized other income |
- |
|
31,775 |
|
- |
|
- |
|
- |
|
- |
|
- |
|
896 |
|
32,671 |
Fund flows from operations |
170,170 |
|
176,162 |
|
86,919 |
|
13,294 |
|
(9,162) |
|
91,227 |
|
(1,547) |
|
(10,896) |
|
516,167 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31, 2014 |
($M) |
Canada |
|
France |
|
Netherlands |
|
Germany |
|
Ireland |
|
Australia |
|
United States |
|
Corporate |
|
Total |
Total assets |
1,865,942 |
|
874,163 |
|
220,100 |
|
170,237 |
|
822,756 |
|
240,614 |
|
14,731 |
|
177,548 |
|
4,386,091 |
Drilling and development |
291,046 |
|
136,019 |
|
49,695 |
|
2,747 |
|
94,439 |
|
44,283 |
|
460 |
|
- |
|
618,689 |
Exploration and evaluation |
43,696 |
|
11,833 |
|
12,045 |
|
- |
|
- |
|
- |
|
- |
|
1,461 |
|
69,035 |
Oil and gas sales to external customers |
537,788 |
|
431,252 |
|
123,815 |
|
41,962 |
|
- |
|
283,481 |
|
1,330 |
|
- |
|
1,419,628 |
Royalties |
(65,563) |
|
(28,444) |
|
(5,014) |
|
(8,613) |
|
- |
|
- |
|
(366) |
|
- |
|
(108,000) |
Revenue from external customers |
472,225 |
|
402,808 |
|
118,801 |
|
33,349 |
|
- |
|
283,481 |
|
964 |
|
- |
|
1,311,628 |
Transportation expense |
(14,625) |
|
(18,975) |
|
- |
|
(2,367) |
|
(6,394) |
|
- |
|
- |
|
- |
|
(42,361) |
Operating expense |
(76,178) |
|
(61,729) |
|
(24,041) |
|
(8,686) |
|
- |
|
(61,432) |
|
(241) |
|
- |
|
(232,307) |
General and administration |
(16,791) |
|
(20,929) |
|
(3,617) |
|
(4,688) |
|
(1,447) |
|
(5,873) |
|
(959) |
|
(7,423) |
|
(61,727) |
PRRT |
- |
|
- |
|
- |
|
- |
|
- |
|
(60,340) |
|
- |
|
- |
|
(60,340) |
Corporate income taxes |
- |
|
(66,901) |
|
(4,154) |
|
(44) |
|
- |
|
(24,477) |
|
- |
|
(1,420) |
|
(96,996) |
Interest expense |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(49,655) |
|
(49,655) |
Realized gain on derivative instruments |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
36,712 |
|
36,712 |
Realized foreign exchange loss |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(821) |
|
(821) |
Realized other income |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
732 |
|
732 |
Fund flows from operations |
364,631 |
|
234,274 |
|
86,989 |
|
17,564 |
|
(7,841) |
|
131,359 |
|
(236) |
|
(21,875) |
|
804,865 |
Reconciliation of fund flows from operations to net earnings
(loss)
|
Year
Ended |
|
|
|
Dec 31, |
|
|
Dec 31, |
($M) |
|
|
2015 |
|
|
2014 |
Fund flows from operations |
|
|
516,167 |
|
|
804,865 |
Equity based compensation |
|
|
(75,232) |
|
|
(67,802) |
Unrealized gain on derivative instruments |
|
|
43,548 |
|
|
27,371 |
Unrealized foreign exchange loss |
|
|
8,787 |
|
|
(17,599) |
Unrealized other expense |
|
|
(1,008) |
|
|
(1,492) |
Accretion |
|
|
(23,911) |
|
|
(23,913) |
Depletion and depreciation |
|
|
(458,758) |
|
|
(425,694) |
Deferred taxes |
|
|
47,728 |
|
|
(26,410) |
Impairment |
|
|
(274,623) |
|
|
- |
Net earnings (loss) |
|
|
(217,302) |
|
|
269,326 |
Vermilion has
two major customers with revenues in excess of 10% within the
France and Netherlands segments. Substantially all sales
in the France and Netherlands segments for the years ended
December 31, 2015 and 2014 were to
one customer in each respective segment.
16. LEASES
Vermilion had the following
future commitments associated with its operating and finance leases
as at December 31, 2015:
($M) |
|
Less than 1 year |
|
|
1 - 3 years |
|
|
4 - 5 years |
|
|
After 5 years |
|
|
Total |
Operating lease
payments by period |
|
20,750 |
|
|
30,942 |
|
|
23,909 |
|
|
49,734 |
|
|
125,335 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Finance lease minimum
lease payments by period |
|
6,285 |
|
|
12,571 |
|
|
9,515 |
|
|
6,984 |
|
|
35,355 |
|
Interest |
|
2,079 |
|
|
3,077 |
|
|
1,521 |
|
|
907 |
|
|
7,584 |
|
Present value of minimum lease payments |
|
6,029 |
|
|
10,746 |
|
|
7,069 |
|
|
4,148 |
|
|
27,992 |
In addition, Vermilion has various other commitments
associated with its business operations; none of which, in
management's view, are significant in relation to Vermilion's financial position.
As part of an acquisition in April of 2014,
Vermilion assumed an agreement for
the use of a solution gas facility. The substance of the
arrangement was determined to be a lease and has been classified as
a finance lease. The assets are to be used for a minimum period of
10 years, with an option to renew. As at December 31, 2015, the carrying amount of the
asset included in capital assets is $28.4
million, and the current portion of the finance lease
obligation included in accrued liabilities in $5.9 million.
17. CASH AND CASH EQUIVALENTS
Cash and cash equivalents was comprised of the following:
($M) |
|
|
|
Dec 31,
2015 |
|
Dec 31,
2014 |
Money on deposit with financial institutions |
|
|
|
|
31,175 |
|
|
116,643 |
Short-term investments |
|
|
|
|
10,501 |
|
|
3,762 |
Cash and cash equivalents |
|
|
|
|
41,676 |
|
|
120,405 |
18. CAPITAL DISCLOSURES
Vermilion
defines capital as net debt (a non-standardized measure, which is
defined by management as long-term debt as shown on the
consolidated balance sheets plus net working capital) and
shareholders' capital.
In managing capital, Vermilion reviews whether fund flows from
operations (a non-standardized measure, defined by management as
cash flows from operating activities before changes in non-cash
operating working capital and asset retirement obligations
settled), is sufficient to pay for all capital expenditures,
dividends and abandonment and reclamation expenditures. To
the extent that the forecasted fund flows from operations is not
expected to be sufficient in relation to these expenditures,
Vermilion will evaluate its
ability to finance any excess with debt, an issuance of equity or
by reducing some or all categories of expenditures to ensure that
total expenditures do not exceed available funds.
Additionally, Vermilion monitors the ratio of net debt
to fund flows from operations. Vermilion typically strives to maintain an
internally targeted ratio of net debt to fund flows from operations
of 1.0 to 1.3 in a normalized commodity price environment. Where
prices trend higher, Vermilion may
target a lower ratio and conversely, in a lower commodity price
environment, the acceptable ratio may be higher. At times,
Vermilion will use its balance
sheet to finance acquisitions and, in these situations,
Vermilion is prepared to accept a
higher ratio in the short term but will implement a plan to reduce
the ratio to acceptable levels within a reasonable period of time,
usually considered to be no more than 12 to 18 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,
the net debt to fund flows ratio is expected to be higher than the
longer term ratio. During this period, Vermilion is managing the higher debt level by
aligning capital expenditures within forecasted fund flows from
operations, which is continually monitored for revised forward
price estimates, as well as by hedging additional European natural
gas volumes to maintain a diversified commodity portfolio.
The following table calculates Vermilion's ratio of net debt to fund flows
from operations:
|
|
|
Year
Ended |
($M except as indicated) |
|
|
Dec 31, 2015 |
|
|
Dec 31, 2014 |
Long-term debt |
|
|
1,162,998 |
|
|
1,238,080 |
Current liabilities(1) |
|
|
503,731 |
|
|
365,729 |
Current assets |
|
|
(284,778) |
|
|
(338,159) |
Net debt [1] |
|
|
1,381,951 |
|
|
1,265,650 |
Cash flows from operating activities |
|
|
444,408 |
|
|
791,986 |
Changes in non-cash operating working capital |
|
|
60,390 |
|
|
(3,077) |
Asset retirement obligations settled |
|
|
11,369 |
|
|
15,956 |
Fund flows from operations [2] |
|
|
516,167 |
|
|
804,865 |
Ratio of net debt to fund flows from operations
([1] ÷ [2]) |
|
|
2.7 |
|
|
1.6 |
|
|
(1) |
Includes the current portion of long-term debt, which, as at
December 31, 2015, represents the senior unsecured notes that
matured on February 10, 2016. |
Long-term debt, including the current portion,
as at December 31, 2015 increased to
$1.39 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 year ended December 31, 2015 were lower due to weakening
crude oil and natural gas prices. The increase in long-term
debt resulted in an increase in net debt from $1.27 billion as at December 31, 2014 to $1.38
billion as at December 31,
2015.
Driven primarily by the weakness in crude oil
prices, the ratio of net debt to fund flows from operations
increased to 2.7 times for the year ended December 31, 2015.
19. FINANCIAL INSTRUMENTS
Classification of Financial Instruments
The following table summarizes information relating to
Vermilion's financial instruments
as at December 31, 2015 and
December 31, 2014:
|
|
|
|
|
|
As at Dec 31, 2015 |
|
|
As at
Dec 31, 2014 |
|
|
|
Class of
financial
instrument |
Consolidated
balance
sheet caption |
Accounting
designation |
Related caption
on Statement of Net
Earnings (Loss) |
|
|
Carrying
value ($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 |
|
|
41,676 |
|
41,676 |
|
|
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 |
|
|
160,499 |
|
160,499 |
|
|
171,820 |
|
171,820 |
|
|
Not applicable |
Derivative assets |
Derivative instruments |
HFT |
Gain on derivative instruments |
|
|
68,342 |
|
68,342 |
|
|
24,794 |
|
24,794 |
|
|
Level 2 |
Payables |
Accounts payable and
accrued liabilities |
OTH |
Gains and losses on foreign
exchange
are included in foreign exchange (gain)
loss |
|
|
(272,824) |
|
(272,824) |
|
|
(321,266) |
|
(321,266) |
|
|
Not applicable |
|
Dividends payable |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
Long-term debt |
OTH |
Interest expense |
|
|
(1,387,899) |
|
(1,387,998) |
|
|
(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
Vermilion is
exposed to the following types of risks in relation to its
financial instruments:
Credit risk:
Vermilion
extends credit to customers and is due amounts from counterparties
in relation to derivative instruments. Accordingly, there is
a risk of financial loss in the event that a counterparty fails to
discharge its obligation. For transactions that are
financially significant, Vermilion
reviews third-party credit ratings and may require additional forms
of security. Cash held on behalf of the Company by financial
institutions is also subject to credit risk.
Liquidity risk:
Liquidity risk is the risk that Vermilion will encounter difficulty in meeting
obligations associated with its financial liabilities. Vermilion does not consider this to be a
significant risk as its financial position and available committed
borrowing facility provide significant financial flexibility and
allow Vermilion to meet its
obligations as they come due.
Currency risk:
Vermilion
conducts business in foreign currencies in addition to Canadian
dollars and accordingly is subject to currency risk associated with
changes in foreign exchange rates in relation to cash and cash
equivalents, receivables, payables and derivative assets and
liabilities. The impact related to working capital is
somewhat mitigated as a result of the offsetting effects of foreign
exchange fluctuations on assets and liabilities. Vermilion monitors its exposure to currency
risk and reviews whether the use of derivative financial
instruments is appropriate to manage potential fluctuations in
foreign exchange rates.
Commodity price risk:
Vermilion uses
derivative financial instruments as part of its risk management
program to mitigate the effects of changes in commodity prices on
future cash flows. Changes in the underlying commodity prices
impact the fair value and future cash flows related to these
derivatives.
Interest rate risk:
Vermilion's
long-term debt is comprised of borrowings under the revolving
credit facility and the Company's senior unsecured notes.
Borrowings under the revolving credit facility bear interest at
market rates plus applicable margins and as such changes in
interest rates could result in an increase or decrease in the
amount Vermilion pays to service
this debt. In 2015, Vermilion had interest rate swaps to mitigate
the effects of changes in variable interest rates. The senior
unsecured notes bear interest at a fixed 6.5% interest rate and as
such, changes in prevailing interest rates would affect the fair
value of these notes. However, as Vermilion does not intend to settle this debt
prior to maturity, the notes are carried at amortized cost and
changes in fair value do not affect net earnings.
Summarized Quantitative Data Associated with
the Risks Arising from Financial Instruments
Credit risk:
As at December 31,
2015, Vermilion's maximum
exposure to receivable credit risk was $228.8 million (December
31, 2014 - $196.6 million)
which is the aggregate value of receivables and derivative assets
at the balance sheet date. Vermilion's receivables are primarily due from
counterparties that have investment grade third party credit
ratings or, in the absence of the availability of such ratings,
have been satisfactorily reviewed by Vermilion for creditworthiness.
Additionally, cash and cash equivalents consist of moneys on
deposit and short-term investments which may be subject to
counterparty credit risk. Vermilion mitigates this risk by transacting
with North American institutions with high third party credit
ratings.
As at the balance sheet date the amount of
financial assets that were past due or impaired was not
material.
Liquidity risk:
Vermilion's
derivative financial instruments settle on a monthly basis.
The following table summarizes Vermilion's undiscounted non-derivative
financial liabilities and their contractual maturities as at
December 31, 2015 and December 31, 2014:
|
|
|
|
|
|
Later than |
|
|
Later than |
|
|
Later than |
|
|
|
|
|
|
one month and |
|
|
three months and |
|
|
one year and |
|
|
|
Due in |
|
|
not later than |
|
|
not later than |
|
|
not later than |
($M) |
|
|
one month |
|
|
three months |
|
|
one year |
|
|
five years |
December 31, 2015 |
|
|
112,890 |
|
|
353,934 |
|
|
33,663 |
|
|
1,180,486 |
December 31, 2014 |
|
|
162,127 |
|
|
138,823 |
|
|
20,314 |
|
|
1,239,067 |
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 year ended
December 31, 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 |
|
|
December 31,
2015 |
|
|
December 31,
2014 |
Currency risk -
Euro to Canadian |
|
|
Increase in
strength of the Canadian dollar against the Euro by 5% over the
relevant closing rates |
|
|
(1,986) |
|
|
(4,030) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in strength of the
Canadian dollar against the Euro by 5% over the relevant closing
rates |
|
|
1,986 |
|
|
4,030 |
|
|
|
|
|
|
|
|
|
|
Currency risk - US
$ to Canadian |
|
|
Increase in strength of the
Canadian dollar against the US $ by 5% over the relevant closing
rates |
|
|
3,423 |
|
|
(5,739) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in strength of the
Canadian dollar against the US $ by 5% over the relevant closing
rates |
|
|
(3,423) |
|
|
5,739 |
|
|
|
|
|
|
|
|
|
|
Commodity price
risk |
|
|
Increase in relevant oil
reference price within option pricing models used to determine |
|
|
(3,262) |
|
|
(1,072) |
|
|
|
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 |
|
|
3,263 |
|
|
1,048 |
|
|
|
the fair value of financial
derivatives by US $5.00/bbl at the relevant valuation dates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in relevant
European natural gas reference price within option pricing models
used to |
|
|
(23,813) |
|
|
(10,279) |
|
|
|
determine the fair value of
financial derivatives by € 0.5/GJ at the relevant valuation
dates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in relevant
European natural gas reference price within option pricing models
used to |
|
|
21,754 |
|
|
10,085 |
|
|
|
determine the fair value of
financial derivatives by € 0.5/GJ at the relevant valuation
dates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate risk |
|
|
Increase in average
Canadian prime interest rate by 100 basis points during the
relevant periods |
|
|
(10,543) |
|
|
(9,032) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in
average Canadian prime interest rate by 100 basis points during the
relevant periods |
|
|
10,543 |
|
|
9,032 |
Reasonably possible changes in North American
natural gas prices would not have had a material impact on
comprehensive income for the years ended December 31, 2015 and 2014.
20. RELATED PARTY DISCLOSURES
The compensation of directors and management are reviewed
annually by the independent Governance and Human Resources
Committee against industry practices for oil and gas companies of
similar size and scope.
The following table summarizes the compensation of directors and
other members of key management personnel during the years ended
December 31, 2015 and December 31, 2014:
|
|
|
|
Year Ended |
($M) |
|
|
|
Dec 31. 2015 |
|
|
Dec 31, 2014 |
Short-term benefits |
|
|
|
|
5,460 |
|
|
|
5,684 |
Share-based payments |
|
|
|
|
20,310 |
|
|
|
16,414 |
|
|
|
|
|
25,770 |
|
|
|
22,098 |
Number of individuals included in the above
amounts |
|
|
|
|
20 |
|
|
|
18 |
21. WAGES AND BENEFITS
Included in operating expenses and general and
administrative expenses for the year ended December 31, 2015 were $47.7 million and $40.4
million of wages and benefits, respectively (2014 -
$56.2 million and $47.2 million, respectively).
22. 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.
PDF available at:
http://stream1.newswire.ca/media/2016/02/29/20160229_C9875_DOC_EN_44636.pdf