CALGARY, July 31, 2014 /PRNewswire/ - Vermilion Energy
Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE:
VET) is pleased to report operating and unaudited financial results
for the three and six months ended June 30,
2014.
HIGHLIGHTS
- Achieved average production of 52,089 boe/d during the second
quarter of 2014, an increase of 12% as compared to 46,677 boe/d in
the prior quarter and an increase of 22% compared to 42,813 boe/d
in the second quarter of 2013. Increased production was
largely attributable to a 27% increase in Canadian production
versus the prior quarter, led by robust performance in both our
Mannville condensate-rich natural
gas and Cardium light-oil development programs, which achieved
production increases of 50% and 17% respectively. Canadian
volumes also increased due to approximately two months of
production contribution from our S.E. Saskatchewan acquisition, which we closed at
the end of April 2014. European
volumes benefitted from a full quarter of contribution from our
German acquisition, which we closed in February 2014.
- Based on the continued strength of our operations during the
second quarter of 2014, we are increasing our full-year 2014
production guidance from the current range of 48,000-49,000 boe/d
to 48,500-49,500 boe/d.
- Generated fund flows from operations(1) in the
second quarter of 2014 of $216.1
million ($2.05/basic share),
as compared to $205.4 million
($2.01/basic share) in the prior
quarter and $174.6 million
($1.73/basic share) in the second
quarter of 2013. The increase was primarily attributable to
improved oil pricing and significantly higher volumes in
Canada.
- On April 29, 2014, we announced
completion of our acquisition of Elkhorn Resources Inc., a private S.E.
Saskatchewan producer, for total
consideration of approximately $427
million. The assets consist of high netback, light oil
producing assets in the Northgate region of southeast Saskatchewan and include approximately 57,000
net acres of land (approximately 80% undeveloped), seven oil
batteries, and preferential access to 50% or greater capacity at a
solution gas facility that is currently under construction.
- On May 22, 2014, we announced the
completion of tunnel boring operations beneath Sruwaddacon Bay at
our Corrib project in Ireland. The tunnel boring machine has
been demobilized from the tunnel, and the remaining tunnel
outfitting, gas plant preparation and offshore well work activities
are progressing. We anticipate first gas from Corrib in
approximately mid-2015, with peak production estimated at
approximately 58 mmcf/d (approximately 9,700 boe/d) net to
Vermilion.
- We are celebrating our 20th Anniversary as a
publicly traded company in 2014. This has been a rewarding
period of growth and achievement for Vermilion, and we are proud of our progress to
date. Most importantly, we are honored to have provided our
shareholders with a compound average total return including
dividends, as of June 30, 2014, of
36.8% per annum since our inception. Looking forward, with
the consistent strength of our operations, our extensive
opportunity base, and anticipated growth of our fund flows from
operations in the current commodity environment, we will strive to
provide continued strong financial performance, and a reliable and
growing dividend stream to investors.
(1) |
Additional GAAP Financial Measure. Please see the
"Additional and Non-GAAP Financial Measures" section of
Management's Discussion and Analysis. |
Vermilion Energy Inc. Second Quarter 2014 Conference Call and
Audio Webcast Details
Vermilion will
discuss these results in a conference call to be held on
Thursday, July 31, 2014 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 65722904. The replay will be available
until midnight eastern time on
August 7, 2014.
You may also listen to the audio webcast by clicking
http://event.on24.com/r.htm?e=813553&s=1&k=D1BE33AF46B4AC5B296C96983A231587
or visit Vermilion's website at
www.vermilionenergy.com/ir/eventspresentations.cfm.
DISCLAIMER
Certain statements included or incorporated by
reference in this document may constitute forward looking
statements or financial outlooks under applicable securities
legislation. Such forward looking statements or information
typically contain statements with words such as "anticipate",
"believe", "expect", "plan", "intend", "estimate", "propose", or
similar words suggesting future outcomes or statements regarding an
outlook. Forward looking statements or information in this
document may include, but are not limited to: capital expenditures;
business strategies and objectives; operational and financial
performance; estimated reserve quantities and the discounted
present value of future net cash flows from such reserves;
petroleum and natural gas sales; future production levels
(including the timing thereof) and rates of average annual
production growth; estimated contingent resources and prospective
resources; exploration and development plans; acquisition and
disposition plans and the timing thereof; operating and other
expenses, including the payment and amount of future dividends;
royalty and income tax rates; the timing of regulatory proceedings
and approvals; and the timing of first commercial natural gas and
the estimate of Vermilion's share
of the expected natural gas production from the Corrib field.
Such forward looking statements or information
are based on a number of assumptions all or any of which may prove
to be incorrect. In addition to any other assumptions
identified in this document, assumptions have been made regarding,
among other things: the ability of Vermilion to obtain equipment, services and
supplies in a timely manner to carry out its activities in
Canada and internationally; the
ability of Vermilion to market
crude oil, natural gas liquids and natural gas successfully to
current and new customers; the timing and costs of pipeline and
storage facility construction and expansion and the ability to
secure adequate product transportation; the timely receipt of
required regulatory approvals; the ability of Vermilion to obtain financing on acceptable
terms; foreign currency exchange rates and interest rates; future
crude oil, natural gas liquids and natural gas prices; and
management's expectations relating to the timing and results of
exploration and development activities.
Although Vermilion believes that the expectations
reflected in such forward looking statements or information are
reasonable, undue reliance should not be placed on forward looking
statements because Vermilion can
give no assurance that such expectations will prove to be
correct. Financial outlooks are provided for the purpose of
understanding Vermilion's
financial position and business objectives and the information may
not be appropriate for other purposes. Forward looking
statements or information are based on current expectations,
estimates and projections that involve a number of risks and
uncertainties which could cause actual results to differ materially
from those anticipated by Vermilion and described in the forward looking
statements or information. These risks and uncertainties
include but are not limited to: the ability of management to
execute its business plan; the risks of the oil and gas industry,
both domestically and internationally, such as operational risks in
exploring for, developing and producing crude oil, natural gas
liquids and natural gas; risks and uncertainties involving geology
of crude oil, natural gas liquids and natural gas deposits; risks
inherent in Vermilion's marketing
operations, including credit risk; the uncertainty of reserves
estimates and reserves life and estimates of resources and
associated expenditures; the uncertainty of estimates and
projections relating to production and associated expenditures;
potential delays or changes in plans with respect to exploration or
development projects; Vermilion's
ability to enter into or renew leases on acceptable terms;
fluctuations in crude oil, natural gas liquids and natural gas
prices, foreign currency exchange rates and interest rates; health,
safety and environmental risks; uncertainties as to the
availability and cost of financing; the ability of Vermilion to add production and reserves
through exploration and development activities; the possibility
that government policies or laws may change or governmental
approvals may be delayed or withheld; uncertainty in amounts and
timing of royalty payments; risks associated with existing and
potential future law suits and regulatory actions against
Vermilion; and other risks and
uncertainties described elsewhere in this document or in
Vermilion's other filings with
Canadian securities regulatory authorities.
The forward looking statements or information
contained in this document are made as of the date hereof and
Vermilion undertakes no obligation
to update publicly or revise any forward looking statements or
information, whether as a result of new information, future events
or otherwise, unless required by applicable securities laws.
All oil and natural gas reserve information
contained in this document has been prepared and presented in
accordance with National Instrument 51-101 Standards of Disclosure
for Oil and Gas Activities. The actual 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 oil and natural gas reserves
does not represent the fair market value of these reserves.
Natural gas volumes have been converted on the
basis of six thousand cubic feet of natural gas to one barrel of
oil equivalent. Barrels of oil equivalent (boe) may be
misleading, particularly if used in isolation. A boe
conversion ratio of six thousand cubic feet to one barrel of oil is
based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value
equivalency at the wellhead.
Financial data contained within this document are reported in
Canadian dollars, unless otherwise stated.
ABBREVIATIONS
$M |
|
thousand dollars |
$MM |
|
million dollars |
AECO |
|
the daily average benchmark price for natural gas at the AECO
'C' hub in southeast Alberta |
bbl(s) |
|
barrel(s) |
bbls/d |
|
barrels per day |
bcf |
|
billion cubic feet |
boe |
|
barrel of oil equivalent, including: crude oil, natural gas
liquids and natural gas (converted on the basis of one boe for six
mcf of natural gas) |
boe/d |
|
barrel of oil equivalent per day |
GJ |
|
gigajoules |
mbbls |
|
thousand barrels |
mboe |
|
thousand barrel of oil equivalent |
mcf |
|
thousand cubic feet |
mcf/d |
|
thousand cubic feet per day |
mmboe |
|
million barrel of oil equivalent |
mmcf |
|
million cubic feet |
mmcf/d |
|
million cubic feet per day |
MWh |
|
megawatt hour |
NGLs |
|
natural gas liquids |
PRRT |
|
Petroleum Resource Rent Tax, a profit based tax levied on
petroleum projects in Australia |
TTF |
|
the day-ahead price for natural gas in the Netherlands, quoted
in MWh of natural gas, at the Title Transfer Facility Virtual
Trading Point operated by Dutch TSO Gas Transport Services |
WTI |
|
West Texas Intermediate, the reference price paid for crude oil
of standard grade in US dollars at Cushing, Oklahoma |
HIGHLIGHTS
|
|
|
Three
Months Ended |
|
Six
Months Ended |
($M except as indicated) |
|
|
Jun 30, |
|
Mar 31, |
|
Jun 30, |
|
Jun 30, |
|
Jun 30, |
Financial |
|
|
2014 |
|
2014 |
|
2013 |
|
2014 |
|
2013 |
Petroleum and natural gas sales |
|
|
387,684 |
|
381,183 |
|
311,966 |
|
768,867 |
|
621,542 |
Fund flows from operations
(1) |
|
|
216,076 |
|
205,363 |
|
174,592 |
|
421,439 |
|
338,221 |
|
Fund flows from operations ($/basic share) |
|
|
2.05 |
|
2.01 |
|
1.73 |
|
4.05 |
|
3.38 |
|
Fund flows from operations ($/diluted share) |
|
|
2.01 |
|
1.97 |
|
1.71 |
|
3.99 |
|
3.33 |
Net earnings |
|
|
53,993 |
|
102,788 |
|
106,198 |
|
156,781 |
|
158,335 |
|
Net earnings ($/basic share) |
|
|
0.51 |
|
1.00 |
|
1.05 |
|
1.51 |
|
1.58 |
Capital expenditures |
|
|
135,073 |
|
196,375 |
|
78,118 |
|
331,448 |
|
258,587 |
Acquisitions |
|
|
381,139 |
|
178,227 |
|
- |
|
559,366 |
|
- |
Asset retirement obligations
settled |
|
|
2,381 |
|
2,651 |
|
2,370 |
|
5,032 |
|
3,758 |
Cash dividends ($/share) |
|
|
0.645 |
|
0.645 |
|
0.600 |
|
1.290 |
|
1.200 |
Dividends declared |
|
|
68,710 |
|
66,007 |
|
60,776 |
|
134,717 |
|
120,388 |
|
% of fund flows from operations |
|
|
32% |
|
32% |
|
35% |
|
32% |
|
36% |
Net dividends (1) |
|
|
49,561 |
|
47,122 |
|
42,146 |
|
96,683 |
|
86,226 |
|
% of fund flows from operations |
|
|
23% |
|
23% |
|
24% |
|
23% |
|
25% |
Payout (1) |
|
|
187,015 |
|
246,148 |
|
122,634 |
|
433,163 |
|
348,571 |
|
% of fund flows from operations |
|
|
87% |
|
120% |
|
70% |
|
103% |
|
103% |
|
% of fund flows from operations
(excluding the Corrib project) |
|
|
73% |
|
111% |
|
55% |
|
92% |
|
90% |
Net debt (1) |
|
|
1,168,998 |
|
966,310 |
|
674,368 |
|
1,168,998 |
|
674,368 |
Ratio of net debt to annualized fund
flows from operations (1) |
|
|
1.4 |
|
1.2 |
|
1.0 |
|
1.4 |
|
1.0 |
Operational |
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
|
30,184 |
|
27,318 |
|
26,638 |
|
28,759 |
|
25,119 |
|
NGLs (bbls/d) |
|
|
2,892 |
|
2,140 |
|
1,775 |
|
2,518 |
|
1,604 |
|
Natural gas (mmcf/d) |
|
|
114.08 |
|
103.32 |
|
86.40 |
|
108.73 |
|
84.29 |
|
Total (boe/d) |
|
|
52,089 |
|
46,677 |
|
42,813 |
|
49,398 |
|
40,772 |
Average realized prices |
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and NGLs ($/bbl) |
|
|
109.89 |
|
111.62 |
|
98.95 |
|
110.73 |
|
101.42 |
|
Natural gas ($/mcf) |
|
|
6.19 |
|
7.99 |
|
7.22 |
|
7.04 |
|
7.00 |
Production mix (% of production) |
|
|
|
|
|
|
|
|
|
|
|
|
% priced with reference to WTI |
|
|
30% |
|
25% |
|
25% |
|
27% |
|
24% |
|
% priced with reference to AECO |
|
|
18% |
|
17% |
|
17% |
|
18% |
|
18% |
|
% priced with reference to TTF |
|
|
18% |
|
19% |
|
17% |
|
19% |
|
17% |
|
% priced with reference to Dated Brent |
|
|
34% |
|
39% |
|
41% |
|
36% |
|
41% |
Netbacks ($/boe) (1) |
|
|
|
|
|
|
|
|
|
|
|
|
Operating netback |
|
|
59.52 |
|
63.20 |
|
59.30 |
|
61.29 |
|
59.24 |
|
Fund flows from operations netback |
|
|
46.24 |
|
47.76 |
|
44.90 |
|
46.98 |
|
44.40 |
|
Operating expenses |
|
|
12.46 |
|
13.49 |
|
12.36 |
|
12.95 |
|
13.21 |
Average reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl) |
|
|
102.99 |
|
98.68 |
|
94.22 |
|
100.84 |
|
94.30 |
|
Edmonton Sweet index (US $/bbl) |
|
|
96.85 |
|
90.43 |
|
90.56 |
|
93.65 |
|
88.99 |
|
Dated Brent (US $/bbl) |
|
|
109.63 |
|
108.22 |
|
102.44 |
|
108.93 |
|
107.50 |
|
AECO ($/GJ) |
|
|
4.44 |
|
5.42 |
|
3.35 |
|
4.93 |
|
3.19 |
|
TTF ($/GJ) |
|
|
7.91 |
|
10.19 |
|
10.14 |
|
9.02 |
|
10.23 |
Average foreign currency exchange
rates |
|
|
|
|
|
|
|
|
|
|
|
|
CDN $/US $ |
|
|
1.09 |
|
1.10 |
|
1.02 |
|
1.10 |
|
1.02 |
|
CDN $/Euro |
|
|
1.50 |
|
1.51 |
|
1.34 |
|
1.50 |
|
1.33 |
Share information ('000s) |
|
|
|
|
|
|
|
|
|
|
|
Shares outstanding - basic |
|
|
106,620 |
|
102,453 |
|
101,418 |
|
106,620 |
|
101,418 |
Shares outstanding - diluted
(1) |
|
|
109,371 |
|
105,167 |
|
103,735 |
|
109,371 |
|
103,735 |
Weighted average shares outstanding -
basic |
|
|
105,577 |
|
102,278 |
|
100,964 |
|
103,936 |
|
100,137 |
Weighted average shares outstanding -
diluted (1) |
|
|
107,330 |
|
104,171 |
|
102,223 |
|
105,531 |
|
101,578 |
(1) |
The above table includes additional GAAP and non-GAAP financial
measures which may not be comparable to other companies.
Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section
of Management's Discussion and Analysis. |
MESSAGE TO SHAREHOLDERS
In 2014, we are celebrating Vermilion's 20th anniversary as a
publicly traded company. It has been a demanding, but also
tremendously rewarding 20 years. During this time, we have
witnessed significant change and encountered many challenges to the
industry, and we are particularly proud of our demonstrated ability
to effectively navigate those challenges to the benefit of our
shareholders. During this time, we have remained committed to
stewarding our Company in the best interests of our
shareholders. We are pleased that our efforts have been both
recognized and supported by our shareholders, resulting in a
compound average total return including dividends, as of
June 30, 2014, of 36.8% per annum
since inception. We are also proud of the consistency of
those returns. Over the last one, three, five, ten and 15
calendar-year periods, we have reliably delivered double-digit
compound average total returns of 24.6%, 14.5%, 24.0%, 18.6% and
25.5%, respectively.
Perhaps more important to both our current and
prospective shareholders, it is our belief that Vermilion is better situated for continued
growth than at any other time in our history. With the
anticipated growth of fund flows from operations(1), the
consistent strength of our operations and our expansive and growing
opportunity base, we remain confident that we are positioned to
deliver continued strong operational and financial performance in
the future, while continuing to provide a reliable and growing
dividend stream to our shareholders.
While we are confident that the assets in our
current portfolio contain significant opportunity for growth for
years to come, we also find ourselves uniquely positioned to
advantageously grow and further diversify our opportunity base
through potential acquisition activity in both North American and
international markets. In North America, we are faced with an
active asset market and we continue to see technology unlocking new
opportunities for development. With Vermilion's access to
relatively low cost capital, our conservative balance sheet, and
significant near-term free cash flow(1) growth on the
horizon (including from Corrib, which is slated to come on
production in mid-2015), we are uniquely positioned to compete and
transact should suitable opportunities arise. While
international asset markets remain substantially less liquid than
in North America, we similarly
find ourselves well-positioned for assets that do become available
in our selective regions of interest.
The second quarter of 2014 marks another quarter of high activity and
effective operational execution for our Company. We achieved
significant quarter-over-quarter production growth largely
attributable to strong results from our successful Mannville condensate-rich gas and Cardium
light-oil development programs in Canada. Production volumes from
our Mannville development program
averaged more than 4,600 boe/d, an increase of 50% during the
second quarter, while Cardium production averaged more than 12,000
boe/d, an increase of 17% from the prior quarter. Operating
netbacks(1) for our Cardium production averaged more
than $70/boe in the second
quarter. Our strong Cardium results reflect continued
improvements in completions design and better-than-forecasted
production volumes on several of our two-mile extended reach
horizontal Cardium wells. With improving efficiencies and
productivity, we will require less capital and approximately five
fewer Cardium wells than originally anticipated to meet our
objectives for our 2014 Cardium program. As a result, we are
diverting a portion of our previously planned Cardium expenditures
to our Mannville development
program which also generates very robust economics. With the
incremental capital, we now plan to drill approximately 15 (9 net)
Mannville wells in 2014, up from
eight (5.7 net) wells in our original budget. Looking
forward, we anticipate our Mannville drilling activity will continue to
increase in future years as we develop our substantial inventory of
highly economic prospects.
We continue to appraise our position in the
Duvernay condensate-rich resource
play, where we have amassed 317 net sections at the relatively low
cost of approximately $76 million
($375/acre). Our position
comprises three largely contiguous blocks in the Edson, West Pembina and Niton areas. To
date, we have drilled three vertical stratigraphic test wells, and
have completed drilling operations on two horizontal appraisal
wells. The first horizontal appraisal well is located in the
downdip part of our Edson block
where condensate yields are expected to be lower than the average
in our overall land position. We selected this location
because of its proximity to one of our vertical stratigraphic test
wells, allowing us to conduct microseismic monitoring in the
stratigraphic test well when we frac the horizontal well (expected
later in the third quarter of 2014). Our second horizontal
appraisal well, which we operate at a 34.8% working interest, is
located along a shared lease-line in the Pembina block to allow
partner participation. Completion of this second well, also
employing microseismic monitoring, is expected during the third
quarter. During drilling operations, both the Edson and West Pembina wells encountered
stability issues in the build section of the wellbore near the heel
of the horizontal well. Both wells were ultimately
sidetracked to reach total measured depths of slightly more than
4,700 metres. Drilling operations lasted approximately 100
days per well, double our original estimate. The
longer-than-expected drilling time took us past break-up, resulting
in wet lease conditions and further contributed to higher
costs. As a result of these drilling challenges, we are now
forecasting total net well costs for the two horizontal wells of
approximately $40 million, including
completion, equip and tie-in, microseismic and related
monitoring-well workovers. Our development-phase target for
well costs (including drill, complete, equip and tie-in) is
$12 to $15 million. We believe
that development-phase savings will be achievable through
learning-curve improvements, lower lease construction costs,
economies of scale in procurement and lower evaluation expenditures
(such as the elimination of microseismic monitoring). We
anticipate that the production results and interpreted fracture
geometries from the microseismic data on these appraisal wells will
assist us in optimizing completions on future development-phase
horizontal wells. We are confident that we will be able to
project the appraisal well results to higher condensate yield
locations as we move to the northeast in our acreage position,
which encompasses the entire breadth of the condensate-rich
window. Our Duvernay rights generally underlie our Cardium
oil and Mannville condensate-rich
gas rights, which creates the potential for infrastructure,
operational, and timing advantages if we progress to full
development of the Duvernay
resource play. In combination, our Cardium, Mannville, and Duvernay positions provide us with exploration
and development opportunities in our core Canadian operating region
that have the potential to deliver strong production and reserve
growth into the latter half of the decade.
On April 29, 2014,
we announced the completion of our acquisition of Elkhorn Resources
Inc., a private southeast Saskatchewan producer, for total consideration
of $427 million. The assets
consist of high netback, light oil producing assets in the
Northgate region of southeast Saskatchewan and include approximately 57,000
net acres of land (approximately 80% undeveloped), seven oil
batteries, and preferential access to 50% or greater capacity at a
solution gas facility that is currently under construction.
More than 90% of the current production base is operated by
Vermilion. Production from
the assets was moderately impacted by recent flooding in S.E.
Saskatchewan and are projected to
average approximately 3,750 boe/d (97% crude oil) during the
remainder of 2014. We have currently identified approximately
175 (152 net) potential drilling locations targeting the
Midale, Frobisher, Bakken, and Three
Forks/Torquay formations. We
began a two-rig, 13-well Midale
drilling program in June 2014.
We were also active in Europe during the second quarter of 2014 with
drilling operations in both France
and the Netherlands. In
France, we drilled two of five
planned wells in Champotran in follow-up to our highly successful
2013 drilling campaign. These first two wells have been put
on production during July at initial rates averaging 275 bbls/d per
well. The remaining three wells at Champotran will be drilled
before the end of the third quarter. Our first well in the
Parentis field has been put on production at a rate of 20
bbls/d. A new pool exploratory test at Cazaux North has been
evaluated as dry and will be abandoned. We currently plan a
seven-well drilling program in France during 2014, with two previously
planned wells deferred to later-year programs to optimize surface
access and reduce rig move costs. During the second quarter
of 2014, we advanced preparations for the phased transfer of our
shut-in Vic Bihl natural gas
production from the Lacq gas processing facility where it was
previously handled to a new third party facility. Delays in
receiving required permit transfers have pushed our original plans
to bring approximately 850 mcf/d of solution gas back on-stream
from the third quarter of 2014 to early 2015. The remainder
of the shut-in gas production, approximately 3,400 mcf/d of gas cap
gas, is expected to be back on production in late-2015.
In the
Netherlands, we drilled two additional wells during the
second quarter of 2014. The Havelte-01 well in the Steenwijk
concession in Friesland (50% working interest) came in low to
prognosis and was plugged and abandoned. However, as part of
the Havelte-01 project, we will tie-in a previously-stranded gas
discovery at Eesveen-01. First gas is anticipated to occur from
Eesveen in early 2015 at an anticipated rate of 3 mmcf/d net to
Vermilion. The
Lambertschaag-02 well was non-commercial in its primary objective
but did encounter other zones of interest with significant gas
shows that will be further evaluated during the third quarter of
2014. There are three wells remaining in our 2014 Netherlands
drilling program with one planned during the third quarter and two
in the fourth quarter. Late in the second quarter, we
initiated production from the Zechstein carbonate formation of the
previously-idle DeHoeve-01 well (42% working interest), at a rate
of 3 mmcf/d, net to Vermilion. Our undeveloped land base in
the Netherlands now totals more
than 800,000 net acres, and it is our intention to generally
increase annual activity levels to maintain a rolling inventory of
projects so that each year's capital program will involve a
combination of drilling new wells and the tie-in of previous
successes.
In Germany, we
have now established an office in Berlin, placed an experienced Managing
Director, and are progressing well with recruiting a supporting
technical team to oversee both our existing assets and potential
new opportunities. Our current position in Germany enables us to participate, on a
non-operated basis, in the exploration, development, production and
transportation of natural gas from four gas producing fields across
11 production licenses. The assets are expected to contribute
approximately 2,300 boe/d of production for calendar 2014, and
include both exploration and production licenses that comprise a
total of 207,000 gross acres, of which 85% is in the exploration
license. Germany is a
producing region with a long history of oil and gas development
activity, low political risk, and strong marketing
fundamentals. Our position provides us with entry into this
sizable market, in the form of free cash flow(1)
generating, low-decline assets with near-term development inventory
in addition to longer-term, low-permeability gas
prospectivity. We believe that our conventional and
unconventional expertise, coupled with new access to proprietary
technical data, will position us for future development and
expansion opportunities in both Germany and the greater European region.
During the first quarter of 2014, we participated in the drilling
of one (0.25 net) development well in Germany. This well logged 81 metres of
net pay and is expected to be tested and put on production during
the second half of 2014.
On May 22, 2014,
we announced the completion of tunnel boring operations beneath
Sruwaddacon Bay at our Corrib project in Ireland. The tunnel boring machine has
now been demobilized and the project is progressing well with
respect to several key activities that remain to be completed prior
to initial production at Corrib. These activities include the
installation of flow and umbilical lines within the tunnel,
grouting of the tunnel, certain offshore well workover activities,
and receipt of final authorizations for start-up of the Bellanaboy
gas facility. The most significant remaining offshore workover
activity at our Corrib field was successfully completed subsequent
to the end of the quarter. The Corrib P6 well was flow tested
for 24 hours at a final flow rate of 112 mmcf/d at a flowing bottom
hole pressure of 3260 psi, representing an approximate 44 percent
drawdown from reservoir pressure. The test rates were within
expectations, reconfirming previous test rates. The well was
still "cleaning up" at the end of the test, exhibiting an
increasing flow rate at increasing flowing bottom hole pressure
when the test period ended. The P6 test confirms that all
five wells required for start-up at Corrib are ready to flow. Based
on the current deterministic schedule for the project, we
anticipate first gas from Corrib in approximately mid-2015, with
peak production estimated at approximately 58 mmcf/d (approximately
9,700 boe/d) net to Vermilion.
In Australia,
we remain focused on completing preparations for the 2015 drilling
program, as well as re-lifing and maintenance projects on our two
platforms. In order to meet current marketing agreements and
provide long-term certainty to our customers, our current plan is
to maintain field-total production levels within our prior guidance
of between 6,000 bbls/d and 8,000 bbls/d. We anticipate
maintaining these production levels in Australia for the foreseeable future with
drilling programs approximately every two years. Our Australian oil
currently garners a premium of approximately US $7.00 to the Dated Brent index and incurs no
transportation cost as production is sold directly at the
platform.
Our operations continue to perform strongly,
generating organic production growth in a capital-efficient
manner. Given the strength of our operations, we have elected
to increase our previous 2014 average annual production guidance
from a range of 48,000-49,000 boe/d to a range of 48,500-49,500
boe/d. Assuming commodity prices remain near current levels
for the remainder of 2014, we anticipate that we can fully fund our
net dividends(1) and development capital expenditures
(excluding capital investment at Corrib) with fund flows from
operations during 2014. With the shifts in capital spending
outlined previously, we currently anticipate full year 2014 capital
expenditure to total approximately $650
million, an increase from our previous guidance of
$635 million. This increase
largely reflects a shift in spending to increase Mannville development drilling as well as
higher costs for our Duvernay
appraisal wells.
We believe we remain positioned to deliver
strong operational and financial performance over the next several
years. We continue to target annual organic production growth
of approximately 5% to 7% along with providing reliable and growing
dividends. Near term production and fund flows from
operations growth is expected to be driven by continued Cardium and
Mannville development in
Canada, oil development activities
in France, and high-netback
natural gas drilling in the
Netherlands. A significant increment of production,
fund flows from operations and free cash flow growth is expected
from Corrib beginning in approximately mid-2015 with the first full
year of production from the project in 2016. Our Australian
and German business units are expected to provide relatively steady
production as well as strong free cash flow.
The management and directors of Vermilion continue to hold approximately 6% of
the outstanding shares and remain committed to delivering superior
rewards to all stakeholders. Continuing to be acknowledged
for excellence in our business practices, Vermilion was recognized for the fifth
consecutive year by the Great Place to Work® Institute in both
Canada and France in 2014. In Canada, Vermilion was ranked 5th Best
Workplace in its category for 2014. More than 300 Canadian
companies participated in the survey and Vermilion was the only energy company in
Canada to be recognized as a Best
Workplace. In France,
Vermilion received a special award
for corporate social responsibility and was ranked 13th
Best Workplace in its category for 2014. Vermilion's Netherlands business unit became eligible to
participate in the competition for the first time in 2014 and was
ranked 10th Best Workplace in its category, the highest
score of any energy company in the survey.
(1) |
The above discussion includes additional GAAP and non-GAAP
measures which may not be comparable to other companies.
Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section
of Management's Discussion and Analysis. |
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is Management's Discussion and
Analysis ("MD&A"), dated July 30,
2014, of Vermilion Energy Inc.'s ("Vermilion" or the
"Company") operating and financial results as at and for the three
and six months ended June 30, 2014
compared with the corresponding periods in the prior year.
This discussion should be read in conjunction
with the unaudited condensed consolidated interim financial
statements for the three and six months ended June 30, 2014 and the audited consolidated
financial statements for the year ended December 31, 2013 and 2012, together with
accompanying notes. Additional information relating to
Vermilion, including its Annual
Information Form, is available on SEDAR at www.sedar.com or on
Vermilion's website at
www.vermilionenergy.com.
The unaudited condensed consolidated interim
financial statements for the three and six months ended
June 30, 2014 and comparative
information have been prepared in Canadian dollars, except where
another currency is indicated, and in accordance with IAS 34,
"Interim financial reporting", as issued by the International
Accounting Standard Board ("IASB").
This MD&A includes references to certain
financial measures which do not have standardized meanings
prescribed by International Financial Reporting Standards
("IFRS"). As such, these financial measures are considered
additional GAAP or non-GAAP financial measures and therefore are
unlikely to be comparable with similar financial measures presented
by other issuers. These additional GAAP and non-GAAP
financial measures include:
- Fund flows from operations: This additional GAAP financial
measure is calculated as cash flows from operating activities
before changes in non-cash operating working capital and asset
retirement obligations settled. We analyze fund flows from
operations both on a consolidated basis and on a business unit
basis in order to assess the contribution of each business unit to
our ability to generate cash necessary to pay dividends, repay
debt, fund asset retirement obligations and make capital
investments.
- Netbacks: These non-GAAP financial measures are per boe and per
mcf measures used in the analysis of operational activities.
We assess netbacks both on a consolidated basis and on a business
unit basis in order to compare and assess the operational and
financial performance of each business unit versus other business
units and third party crude oil and natural gas producers.
For a full description of these and other
non-GAAP financial measures and a reconciliation of these measures
to their most directly comparable GAAP measures, please refer to
"ADDITIONAL AND NON-GAAP FINANCIAL MEASURES".
VERMILION'S
BUSINESS
Vermilion is a
Calgary, Alberta based
international oil and gas producer focused on the acquisition,
development and optimization of producing properties in
Western Canada, Europe, and Australia. We manage our business
through our Calgary head office
and our international business unit offices.
This MD&A separately discusses each of our
business units in addition to our corporate segment.
- Canada business unit: Relates
to our assets in Alberta and
Saskatchewan.
- France business unit: Relates
to our operations in France in the
Paris and Aquitaine Basins.
- Netherlands business unit:
Relates to our operations in the
Netherlands.
- Germany business unit: Relates
to our 25% contractual participation interest in a four-partner
consortium in Germany.
- Ireland business unit: Relates
to our 18.5% non-operated interest in the offshore Corrib natural
gas field.
- Australia business unit:
Relates to our operations in the Wandoo offshore crude oil
field.
- 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.
Prior to December 31,
2013, Vermilion combined
the operating and financial results of the Canada business unit and the Corporate segment
and presented the combined results as Canada.
GUIDANCE
We first issued 2014 capital expenditure
guidance of $555 million on
November 7, 2013. We
subsequently increased our 2014 capital expenditure guidance to
$590 million on March 18, 2014, to reflect an additional
$35 million of 2014 development
capital expected to be incurred in association with our acquisition
of Elkhorn Resources Inc. Concurrent with the release of our
first quarter 2014 financial and operating results on May 2, 2014, we further updated our 2014 capital
expenditure guidance to $635 million,
reflecting the expected full-year rise in the cost to Vermilion, in Canadian dollar terms, of both
actual and anticipated international capital expenditures as a
result of the devaluation of the Canadian dollar against both the
U.S. dollar and the Euro, and the addition of approximately
$15 million of anticipated spending
associated with drilling activities. We also increased our
original production guidance from 47,500-48,500 boe/d to
48,000-49,000 boe/d.
Based on the continued strength of our
operations during the second quarter of 2014, we are further
increasing our full-year 2014 production and capital expenditure
guidance to 48,500-49,500 boe/d and $650
million, respectively. The increase in capital expenditures
is due to increased Mannville
development drilling and higher than anticipated costs associated
with the Duvernay appraisal
program.
The following table summarizes our 2014
guidance:
|
|
|
|
Date |
|
|
|
|
|
Capital Expenditures
($MM) |
|
|
|
|
|
Production (boe/d) |
2014 Guidance |
|
|
|
November 7, 2013 |
|
|
|
|
|
555 |
|
|
|
|
|
45,000 to 46,000 |
2014 Guidance - Update |
|
|
|
March 18, 2014 |
|
|
|
|
|
590 |
|
|
|
|
|
47,500 to 48,500 |
2014 Guidance - Update |
|
|
|
May 2, 2014 |
|
|
|
|
|
635 |
|
|
|
|
|
48,000 to 49,000 |
2014 Guidance - Update |
|
|
|
July 31, 2014 |
|
|
|
|
|
650 |
|
|
|
|
|
48,500 to 49,500 |
SHAREHOLDER RETURN
Vermilion
strives to provide investors with reliable and growing dividends in
addition to sustainable, global production growth. The
following table, as of June 30, 2014,
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 |
|
|
$2.49 |
|
|
|
$7.11 |
|
|
|
$11.67 |
Capital appreciation per Vermilion share |
|
|
$22.84 |
|
|
|
$23.25 |
|
|
|
$45.02 |
Total return per Vermilion share |
|
|
49.3% |
|
|
|
59.5% |
|
|
|
193.9% |
Annualized total return per Vermilion share |
|
|
49.3% |
|
|
|
16.8% |
|
|
|
24.1% |
Annualized total return on the
S&P TSX High Income Energy Index |
|
|
29.3% |
|
|
|
6.2% |
|
|
|
11.5% |
(1)
|
The above table includes non-GAAP financial measures which may
not be comparable to other companies. Please see the
"ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of this
MD&A. |
CONSOLIDATED RESULTS OVERVIEW
|
|
Three
Months Ended |
|
%
change |
|
Six
Months Ended |
|
% change |
|
|
Jun 30, |
|
Mar 31, |
|
Jun 30, |
|
Q2/14 vs. |
|
Q2/14 vs. |
|
Jun 30, |
|
Jun 30, |
|
2014 vs. |
|
|
2014 |
|
2014 |
|
2013 |
|
Q1/14 |
|
Q2/13 |
|
2014 |
|
2013 |
|
2013 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
30,184 |
|
27,318 |
|
26,638 |
|
10% |
|
13% |
|
28,759 |
|
25,119 |
|
14% |
|
NGLs (bbls/d) |
|
2,892 |
|
2,140 |
|
1,775 |
|
35% |
|
63% |
|
2,518 |
|
1,604 |
|
57% |
|
Natural gas (mmcf/d) |
|
114.08 |
|
103.32 |
|
86.40 |
|
10% |
|
32% |
|
108.73 |
|
84.29 |
|
29% |
|
Total (boe/d) |
|
52,089 |
|
46,677 |
|
42,813 |
|
12% |
|
22% |
|
49,398 |
|
40,772 |
|
21% |
|
Build (draw) in inventory (mbbl) |
|
67 |
|
(98) |
|
6 |
|
|
|
|
|
(31) |
|
(238) |
|
|
Financial metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fund flows from operations ($M) |
|
216,076 |
|
205,363 |
|
174,592 |
|
5% |
|
24% |
|
421,439 |
|
338,221 |
|
25% |
|
Per share ($/basic share) |
|
2.05 |
|
2.01 |
|
1.73 |
|
2% |
|
18% |
|
4.05 |
|
3.38 |
|
20% |
|
Net earnings ($M) |
|
53,993 |
|
102,788 |
|
106,198 |
|
(47%) |
|
(49%) |
|
156,781 |
|
158,335 |
|
(1%) |
|
Per share ($/basic share) |
|
0.51 |
|
1.00 |
|
1.05 |
|
(49%) |
|
(51%) |
|
1.51 |
|
1.58 |
|
(4%) |
|
Cash flows from operating activities ($M) |
|
149,592 |
|
178,238 |
|
179,074 |
|
(16%) |
|
(16%) |
|
327,830 |
|
369,786 |
|
(11%) |
|
Net debt ($M) |
|
1,168,998 |
|
966,310 |
|
674,368 |
|
21% |
|
73% |
|
1,168,998 |
|
674,368 |
|
73% |
|
Cash dividends ($/share) |
|
0.645 |
|
0.645 |
|
0.600 |
|
- |
|
8% |
|
1.290 |
|
1.200 |
|
8% |
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
|
135,073 |
|
196,375 |
|
78,118 |
|
(31%) |
|
73% |
|
331,448 |
|
258,587 |
|
28% |
|
Acquisitions ($M) |
|
381,139 |
|
178,227 |
|
- |
|
114% |
|
100% |
|
559,366 |
|
- |
|
100% |
|
Gross wells drilled |
|
13.00 |
|
24.00 |
|
6.00 |
|
|
|
|
|
37.00 |
|
34.00 |
|
|
|
Net wells drilled |
|
6.72 |
|
18.83 |
|
4.86 |
|
|
|
|
|
25.55 |
|
31.36 |
|
|
Operational review
- Recorded consolidated average production of 52,089 boe/d during
Q2 2014, a 12% increase compared to Q1 2014 and a 22% increase as
compared to Q2 2013. The growth quarter-over-quarter and
year-over-year was primarily driven by production growth in
Canada, resulting from our
continued development of the Cardium and Mannville plays in Alberta coupled with approximately two months
of incremental production from southeast Saskatchewan (approximately 2,000 boe/d during
the quarter) following our acquisition of Elkhorn Resources Inc.
and a full quarter of incremental production from our acquisition
in Germany.
- Recorded consolidated average production of 49,398 boe/d for
the six months ended June 30, 2014, a
21% increase versus the same period in 2013 as a result of
production growth in Canada and
the Netherlands. In
Canada, production growth of 32%
year-over-year was achieved through continued development of the
Cardium and Mannville plays in
Alberta, coupled with two months
of incremental production from southeast Saskatchewan. In the Netherlands, production increased to 7,040
boe/d resulting from incremental production from our acquisition in
the Netherlands in Q4 2013 and
increased volumes following completion of the Middenmeer Treatment
Centre retrofit in the latter part of 2013. In addition, we
maintained Australia production at
6,795 boe/d year-to-date and added incremental volumes from our
acquisition in Germany, which
closed in February of 2014. These increases were partially
offset by a 1% decrease in production in France, which occurred despite a 5% increase
in crude oil production volumes, due to the temporary shut-in of
natural gas production.
- Activity during the quarter included capital expenditures
totalling $135.1 million incurred
primarily in Canada, France, the
Netherlands, and Ireland. In Canada, capital expenditures of $37.0 million were significantly lower than the
$114.9 million from Q1 2014 due to
spring breakup and were related to the drilling of 3.29 net
wells. In France,
$37.6 million of capital expenditures
were incurred during the quarter relating to the drilling of 2.0
net wells in the Champotran field in Paris. In the
Netherlands, $21.5 million of
capital expenditures were incurred during the quarter relating to
the drilling of 1.4 net wells. In Ireland, $27.2
million of capital expenditures were incurred relating to
the completion of tunnel boring operations, offshore well workover
and various facility activities.
- Acquisition expenditures for the quarter totalling $381.1 million related primarily to our
acquisition of Elkhorn Resources Inc. on April 29, 2014. This included approximately
$205.0 million attributed to
approximately 2.8 million Vermilion common shares issued to Elkhorn's shareholders. Acquisitions in
the year-to-date period also included our acquisition in
Germany, which closed in February
of 2014, for total cash consideration of $172.9 million.
Financial review
Net earnings
- Net earnings for Q2 2014 were $54.0
million ($0.51/basic share) as
compared to net earnings of $102.8
million ($1.00/basic share) in
Q1 2014 and $106.2 million
($1.05/basic share) in Q2 2013.
The decrease to net earnings quarter-over-quarter and
year-over-year occurred despite production and sales growth, due
largely to the reversal of unrealized foreign exchange gains
recognized during Q1 2014 and Q2 2013. The unrealized foreign
exchange gains recognized during the comparable quarters related to
the Euro strengthening versus the Canadian dollar and the resulting
impact on our Euro denominated financial assets. In Q1 2014
and Q2 2013, the Euro strengthened by approximately 4% and 5%,
respectively, versus a 4% weakening in the current quarter.
- Net earnings for the six months ended June 30, 2014 decreased by 1% (4% per
share). This slight decrease occurred as increased sales were
offset by the absence of unrealized foreign exchange gains and
increased depreciation expense.
Cash flows from operating activities
- Cash flow from operations decreased by 16% and 11% for the
three and six months ended June 30,
2014 as compared to the same periods in 2013. These
decreases occurred despite increased production and favourable
Canadian dollar commodity prices due to the offsetting impacts of
timing differences pertaining to working capital.
Fund flows from operations
- Generated fund flows from operations of $216.1 million ($2.05/basic share) during Q2 2014, an increase of
$10.7 million (5%) versus Q1
2014. This quarter-over-quarter increase was largely driven
by increased sales volumes in Canada, following production growth in the
Cardium, Mannville, and
incremental production in southeast Saskatchewan.
- Fund flows from operations increased by 24% and 25% for the
three and six months ended June 30,
2014, respectively, versus the comparable periods in
2013. These increases in fund flows from operations resulted
from increased sales volumes in Canada, incremental volumes from our
Germany acquisition, coupled with
favorable Canadian dollar crude oil and Canadian natural gas
pricing, partially offset by lower sales volumes in Australia and a decline in TTF pricing.
Impacting fund flows from operations, and included in general and
administration costs for 2014, are charges relating to our
acquisitions in Canada
($1.1 million) and Germany ($0.8
million).
Net debt
- As a result of funding our 2014 acquisitions in Germany and Saskatchewan, net debt increased to
$1.2 billion as at June 30, 2014. As year-to-date fund flows
from operations includes only two months of contribution from the
acquisition in Saskatchewan, the
ratio of net debt to annualized fund flows from operations
increased to 1.4 times.
Dividends
- Declared dividends of $0.215 per
common share per month during 2014, totalling $0.645 per common share over the quarter, an
increase of 7.5% versus the 2013 comparable periods.
COMMODITY PRICES
|
|
Three
Months Ended |
|
%
change |
|
Six
Months Ended |
|
% change |
|
|
Jun 30, |
|
Mar 31, |
|
Jun 30, |
|
Q2/14 vs. |
|
Q2/14 vs. |
|
Jun 30, |
|
Jun 30, |
|
2014 vs. |
|
|
2014 |
|
2014 |
|
2013 |
|
Q1/14 |
|
Q2/13 |
|
2014 |
|
2013 |
|
2013 |
Average reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl) |
|
102.99 |
|
98.68 |
|
94.22 |
|
4% |
|
9% |
|
100.84 |
|
94.30 |
|
7% |
Edmonton Sweet index (US $/bbl) |
|
96.85 |
|
90.43 |
|
90.56 |
|
7% |
|
7% |
|
93.65 |
|
88.99 |
|
5% |
Dated Brent (US $/bbl) |
|
109.63 |
|
108.22 |
|
102.44 |
|
1% |
|
7% |
|
108.93 |
|
107.50 |
|
1% |
AECO ($/GJ) |
|
4.44 |
|
5.42 |
|
3.35 |
|
(18%) |
|
33% |
|
4.93 |
|
3.19 |
|
55% |
TTF ($/GJ) |
|
7.91 |
|
10.19 |
|
10.14 |
|
(22%) |
|
(22%) |
|
9.02 |
|
10.23 |
|
(12%) |
TTF (€/GJ) |
|
5.27 |
|
6.75 |
|
7.57 |
|
(22%) |
|
(30%) |
|
6.01 |
|
7.69 |
|
(22%) |
Average foreign currency
exchange rates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CDN $/US $ |
|
1.09 |
|
1.10 |
|
1.02 |
|
(1%) |
|
7% |
|
1.10 |
|
1.02 |
|
8% |
CDN $/Euro |
|
1.50 |
|
1.51 |
|
1.34 |
|
(1%) |
|
12% |
|
1.50 |
|
1.33 |
|
13% |
Average realized prices ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
71.56 |
|
69.26 |
|
62.00 |
|
3% |
|
15% |
|
70.55 |
|
59.93 |
|
18% |
France |
|
117.29 |
|
117.54 |
|
98.04 |
|
- |
|
20% |
|
117.41 |
|
102.84 |
|
14% |
Netherlands |
|
48.14 |
|
63.60 |
|
65.08 |
|
(24%) |
|
(26%) |
|
56.06 |
|
63.19 |
|
(11%) |
Germany |
|
45.36 |
|
55.85 |
|
- |
|
(19%) |
|
100% |
|
49.50 |
|
- |
|
100% |
Australia |
|
126.87 |
|
127.26 |
|
111.54 |
|
- |
|
14% |
|
127.11 |
|
115.89 |
|
10% |
Consolidated |
|
82.96 |
|
88.67 |
|
80.21 |
|
(6%) |
|
3% |
|
85.70 |
|
81.60 |
|
5% |
Production mix (% of production) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% priced with reference to WTI |
|
30% |
|
25% |
|
25% |
|
|
|
|
|
27% |
|
24% |
|
|
% priced with reference to AECO |
|
18% |
|
17% |
|
17% |
|
|
|
|
|
18% |
|
18% |
|
|
% priced with reference to TTF |
|
18% |
|
19% |
|
17% |
|
|
|
|
|
19% |
|
17% |
|
|
% priced with reference to Dated Brent |
|
34% |
|
39% |
|
41% |
|
|
|
|
|
36% |
|
41% |
|
|
Reference prices
- Oil outperformed natural gas in Q2 2014 as a result of
heightened geopolitical tensions and a generally tighter
fundamental balance. Averaging the quarter at US $109.63/bbl, Dated Brent was 1% higher
quarter-over-quarter and 7% above the same period last year.
- WTI's advance quarter-over-quarter was more pronounced, up 4%
from Q1 2014 and 9% higher than Q2 2013. Sliding oil inventories at
Cushing, Oklahoma and elevated
refining demand contributed to the oil benchmark's advance.
Edmonton Sweet prices also increased in Q2 2014, up 7% from both Q1
2014 and Q2 2013.
- AECO natural gas fell 18% quarter-over-quarter to average
C$4.44/GJ in Q2. While seasonal
factors weighed heavily on a quarter-over-quarter basis, AECO still
managed to post a strong 33% increase over the same quarter last
year and a 55% increase for the first half of 2014 over the first
half of 2013 from a colder-than-normal winter.
- Increased storage levels and weaker seasonal demand led TTF to
fall 22% in Q2 versus Q1, averaging C$7.91/GJ, and down 30% versus the same quarter
last year.
- The Canadian dollar posted a small increase versus both the US
dollar and Euro in Q2 2014 versus Q1 2014, however, versus the same
period last year the Canadian dollar has weakened by 7% versus the
US dollar and 12% versus the Euro.
Realized prices
- Consolidated realized price decreased by 6% for Q2 2014 as
compared to Q1 2014. This decrease was the result of a change
in Vermilion's production mix
coupled with a 22% decrease in TTF pricing.
Quarter-over-quarter, production growth in Alberta and incremental production from our Q2
2014 acquisition in Saskatchewan
increased our percentage of WTI priced production from 25% to 30%
of consolidated production. As WTI continues to trade at a
discount to Dated Brent, this resulted in an overall decrease to
our consolidated realized price.
- Consolidated realized price for the three and six months ended
June 30, 2014 increased by 3% and 5%
as compared to the same periods in the prior year. These
increases were the result of stronger crude oil and Canadian
natural gas pricing coupled with the weakness of the Canadian
dollar. These increases were partially offset by the
aforementioned changes in production mix and TTF pricing.
FUND FLOWS FROM OPERATIONS
|
|
Three
Months Ended |
|
Six
Months Ended |
|
|
Jun 30, 2014 |
|
Mar 31, 2014 |
|
Jun 30, 2013 |
|
Jun 30, 2014 |
|
Jun 30, 2013 |
|
|
$M |
|
$/boe |
|
$M |
|
$/boe |
|
$M |
|
$/boe |
|
$M |
|
$/boe |
|
$M |
|
$/boe |
Petroleum and natural gas sales |
|
387,684 |
|
82.96 |
|
381,183 |
|
88.67 |
|
311,966 |
|
80.21 |
|
768,867 |
|
85.70 |
|
621,542 |
|
81.60 |
Royalties |
|
(29,013) |
|
(6.21) |
|
(24,024) |
|
(5.59) |
|
(15,800) |
|
(4.06) |
|
(53,037) |
|
(5.91) |
|
(31,590) |
|
(4.15) |
Petroleum and natural gas revenues |
|
358,671 |
|
76.75 |
|
357,159 |
|
83.08 |
|
296,166 |
|
76.15 |
|
715,830 |
|
79.79 |
|
589,952 |
|
77.45 |
Transportation expense |
|
(12,032) |
|
(2.57) |
|
(9,861) |
|
(2.29) |
|
(6,653) |
|
(1.71) |
|
(21,893) |
|
(2.44) |
|
(13,294) |
|
(1.75) |
Operating expense |
|
(58,213) |
|
(12.46) |
|
(57,986) |
|
(13.49) |
|
(48,082) |
|
(12.36) |
|
(116,199) |
|
(12.95) |
|
(100,657) |
|
(13.21) |
General and administration |
|
(17,762) |
|
(3.80) |
|
(14,467) |
|
(3.37) |
|
(11,313) |
|
(2.91) |
|
(32,229) |
|
(3.59) |
|
(23,923) |
|
(3.14) |
Corporate income taxes |
|
(32,635) |
|
(6.98) |
|
(38,603) |
|
(8.98) |
|
(36,719) |
|
(9.44) |
|
(71,238) |
|
(7.94) |
|
(72,276) |
|
(9.49) |
PRRT |
|
(12,699) |
|
(2.72) |
|
(20,239) |
|
(4.71) |
|
(12,590) |
|
(3.24) |
|
(32,938) |
|
(3.67) |
|
(23,743) |
|
(3.12) |
Interest expense |
|
(12,334) |
|
(2.64) |
|
(11,460) |
|
(2.67) |
|
(9,336) |
|
(2.40) |
|
(23,794) |
|
(2.65) |
|
(18,025) |
|
(2.37) |
Realized gain (loss) on derivative
instruments |
|
2,419 |
|
0.52 |
|
2,640 |
|
0.61 |
|
1,770 |
|
0.46 |
|
5,059 |
|
0.56 |
|
(1,017) |
|
(0.13) |
Realized foreign exchange gain (loss) |
|
587 |
|
0.12 |
|
(2,041) |
|
(0.47) |
|
1,272 |
|
0.33 |
|
(1,454) |
|
(0.16) |
|
655 |
|
0.09 |
Realized other income |
|
74 |
|
0.02 |
|
221 |
|
0.05 |
|
77 |
|
0.02 |
|
295 |
|
0.03 |
|
549 |
|
0.07 |
Fund flows from operations |
|
216,076 |
|
46.24 |
|
205,363 |
|
47.76 |
|
174,592 |
|
44.90 |
|
421,439 |
|
46.98 |
|
338,221 |
|
44.40 |
The following table shows a reconciliation of
the change in fund flows from operations:
($M) |
|
|
Q2/14 vs. Q1/14 |
|
Q2/14 vs. Q2/13 |
|
2014 vs. 2013 |
Fund flows from operations -
Comparative period |
|
|
205,363 |
|
174,592 |
|
338,221 |
Sales volume variance: |
|
|
|
|
|
|
|
Canada |
|
|
39,771 |
|
44,135 |
|
63,154 |
France |
|
|
7,323 |
|
6,669 |
|
(4,579) |
Netherlands |
|
|
(1,936) |
|
2,166 |
|
7,799 |
Germany |
|
|
4,751 |
|
11,097 |
|
20,012 |
Australia |
|
|
(30,964) |
|
(20,562) |
|
(6,516) |
Pricing variance on sold volumes: |
|
|
|
|
|
|
|
WTI |
|
|
5,026 |
|
14,192 |
|
24,876 |
AECO |
|
|
(4,717) |
|
3,983 |
|
13,772 |
Dated Brent |
|
|
(447) |
|
24,639 |
|
37,907 |
TTF |
|
|
(12,306) |
|
(10,601) |
|
(9,100) |
Changes in: |
|
|
|
|
|
|
|
Realized derivatives |
|
|
(221) |
|
649 |
|
6,076 |
Royalties |
|
|
(4,989) |
|
(13,213) |
|
(21,447) |
Operating expense |
|
|
(227) |
|
(10,131) |
|
(15,542) |
Transportation |
|
|
(2,171) |
|
(5,379) |
|
(8,599) |
Interest |
|
|
(874) |
|
(2,998) |
|
(5,769) |
General and administration |
|
|
(3,295) |
|
(6,449) |
|
(8,306) |
Realized other income |
|
|
(147) |
|
(3) |
|
(254) |
Realized foreign exchange |
|
|
2,628 |
|
(685) |
|
(2,109) |
Corporate income taxes |
|
|
5,968 |
|
4,084 |
|
1,038 |
PRRT |
|
|
7,540 |
|
(109) |
|
(9,195) |
Fund flows from operations - Current
Period |
|
|
216,076 |
|
216,076 |
|
421,439 |
Fund flows from operations of $216.1 million during Q2 2014 was an increase of
$10.7 million (5%) versus Q1
2014. The majority of this increase resulted from
$6.5 million of increased
sales. The increase in sales was due to favourable sales
volume variances, partially offset by unfavourable pricing
variances. Sales volume variances included $39.8 million relating to higher production
volumes in Canada following
continued development of the Cardium and Mannville plays in Alberta and incremental production from our
southeast Saskatchewan acquisition
and $7.3 million relating to a draw
in inventory in France.
These favourable sales volume variances were partially offset by a
$31.0 million unfavourable variance
relating to a build in inventory in Australia. The unfavourable pricing
variance was the result of a quarter-over-quarter decline in
natural gas prices, offset partially by an increase in the WTI
reference price.
Fund flows from operations increased by 24% and
25% for the three and six months ended June
30, 2014, respectively, versus the comparable periods in
2013. These increases in fund flows from operations resulted
primarily from the combined impacts of favourable sales volume and
pricing variances. Favourable sales volume variances occurred
primarily in Canada (contributing
an additional $44.1 million in Q2
2014 and $63.2 million year-to-date
2014 versus the comparable periods) and were aided by incremental
production in Germany
(contributing $11.1 million in the
quarter and $20.0 million in the
year-to-date period).
Fluctuations in fund flows from operations (and
correspondingly net earnings and cash flows from operating
activities) may occur as a result of changes in commodity prices
and costs to produce petroleum and natural gas. In addition,
fund flows from operations may be highly affected by the timing of
crude oil shipments in Australia
and France. When crude oil
inventory is built up, the related operating expense, royalties,
and depletion expense are deferred and carried as inventory on our
balance sheet. When the crude oil inventory is subsequently
drawn down, the related expenses are recognized in fund flows from
operations.
CANADA
BUSINESS UNIT
Overview
- Production and assets focused in West Pembina near Drayton Valley, Alberta and Northgate in
southeast Saskatchewan
- Potential for three significant resource plays sharing the same
surface infrastructure in the West Pembina region:
-
- Cardium light oil (1,800m depth) - in development phase
- Mannville condensate-rich gas
(2,400 - 2,700m depth) - in development phase
- Duvernay condensate-rich gas
(3,200 - 3,400m depth) - in appraisal phase
- Canadian cash flows are fully tax-sheltered for the foreseeable
future.
Operational review
|
|
Three
Months Ended |
|
%
change |
|
Six
Months Ended |
|
% change |
|
|
Jun 30, |
|
Mar 31, |
|
Jun 30, |
|
Q2/14 vs. |
|
Q2/14 vs. |
|
Jun 30, |
|
Jun 30, |
|
2014 vs. |
Canada business unit |
|
2014 |
|
2014 |
|
2013 |
|
Q1/14 |
|
Q2/13 |
|
2014 |
|
2013 |
|
2013 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
12,676 |
|
9,437 |
|
8,885 |
|
34% |
|
43% |
|
11,065 |
|
8,428 |
|
31% |
|
NGLs (bbls/d) |
|
2,796 |
|
2,071 |
|
1,725 |
|
35% |
|
62% |
|
2,435 |
|
1,531 |
|
59% |
|
Natural gas (mmcf/d) |
|
57.59 |
|
49.53 |
|
43.69 |
|
16% |
|
32% |
|
53.58 |
|
42.37 |
|
26% |
|
Total (boe/d) |
|
25,070 |
|
19,763 |
|
17,892 |
|
27% |
|
40% |
|
22,430 |
|
17,021 |
|
32% |
Production mix (%
of total) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil |
|
51% |
|
48% |
|
50% |
|
|
|
|
|
49% |
|
50% |
|
|
|
NGLs |
|
11% |
|
10% |
|
10% |
|
|
|
|
|
11% |
|
9% |
|
|
|
Natural gas |
|
38% |
|
42% |
|
40% |
|
|
|
|
|
40% |
|
41% |
|
|
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
|
36,968 |
|
114,939 |
|
16,553 |
|
(68%) |
|
123% |
|
151,907 |
|
101,682 |
|
49% |
|
Acquisitions ($M) |
|
381,326 |
|
4,768 |
|
- |
|
|
|
|
|
386,094 |
|
- |
|
|
|
Gross wells drilled |
|
9.00 |
|
20.00 |
|
3.00 |
|
|
|
|
|
29.00 |
|
27.00 |
|
|
|
Net wells drilled |
|
3.29 |
|
14.97 |
|
1.86 |
|
|
|
|
|
18.26 |
|
24.36 |
|
|
Production
- Production in Canada increased
by 27% quarter-over-quarter and by 40% year-over-year.
- Quarter-over-quarter and year-over-year increases were largely
attributable to production additions from our southeast
Saskatchewan acquisition,
supplemented by strong production from our Mannville program and continued development in
the Cardium.
- Cardium production averaged more than 12,100 boe/d in Q2
2014.
- Mannville production averaged
more than 4,600 boe/d in Q2 2014.
- Saskatchewan production
averaged approximately 2,000 boe/d in Q2 2014, taking into account
an effective acquisition date of April 29,
2014.
Activity review
- Vermilion drilled nine (3.3
net) wells during Q2 2014.
Cardium
- In the Cardium, we drilled one (1.0 net) operated well and
brought five (5.0 net) operated wells on production during Q2 2014,
all of which were long reach wells with horizontal lengths between
1.5 and 2.0 miles. Year-to-date we have drilled 12 (11.5 net)
operated wells and brought 18 (18.0 net) operated wells on
production.
- Since 2009, we have drilled or participated in 258 (183.7 net)
wells in the Cardium.
- Operating netbacks averaged approximately $70/boe year-to-date for Cardium production.
- In 2014, we plan to drill or participate in 37 (24.5 net)
Cardium wells.
Mannville
- During Q2 2014, in the Mannville, we brought two (1.5 net) operated
wells on production that were drilled in the previous
quarter. Year-to-date we have drilled and brought on
production five (3.7 net) operated wells.
- In 2014, we plan to drill 15 (9 net) Mannville wells.
Duvernay
- We drilled two (1.3 net) horizontal Duvernay wells, with completion of the wells
anticipated for Q3 2014.
Saskatchewan
- We spud two wells in the second quarter, with completions
scheduled for Q3 2014.
- A 13 well Midale program is
planned for 2014.
Financial review
|
|
Three
Months Ended |
|
%
change |
|
Six
Months Ended |
|
% change |
Canada business unit |
|
Jun 30, |
|
Mar 31, |
|
Jun 30, |
|
Q2/14 vs. |
|
Q2/14 vs. |
|
Jun 30, |
|
Jun 30, |
|
2014 vs. |
($M except as indicated) |
|
2014 |
|
2014 |
|
2013 |
|
Q1/14 |
|
Q2/13 |
|
2014 |
|
2013 |
|
2013 |
Sales |
|
163,261 |
|
123,180 |
|
100,950 |
|
33% |
|
62% |
|
286,441 |
|
184,638 |
|
55% |
Royalties |
|
(18,240) |
|
(12,663) |
|
(9,707) |
|
44% |
|
88% |
|
(30,903) |
|
(18,696) |
|
65% |
Transportation expense |
|
(4,024) |
|
(3,098) |
|
(2,611) |
|
30% |
|
54% |
|
(7,122) |
|
(4,880) |
|
46% |
Operating expense |
|
(21,179) |
|
(16,610) |
|
(15,975) |
|
28% |
|
33% |
|
(37,789) |
|
(29,816) |
|
27% |
General and administration |
|
(6,560) |
|
(2,868) |
|
(3,948) |
|
129% |
|
66% |
|
(9,428) |
|
(7,017) |
|
34% |
Fund flows from operations |
|
113,258 |
|
87,941 |
|
68,709 |
|
29% |
|
65% |
|
201,199 |
|
124,229 |
|
62% |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
71.56 |
|
69.26 |
|
62.00 |
|
3% |
|
15% |
|
70.55 |
|
59.93 |
|
18% |
Royalties |
|
(7.99) |
|
(7.12) |
|
(5.96) |
|
12% |
|
34% |
|
(7.61) |
|
(6.07) |
|
25% |
Transportation expense |
|
(1.76) |
|
(1.74) |
|
(1.60) |
|
1% |
|
10% |
|
(1.75) |
|
(1.58) |
|
11% |
Operating expense |
|
(9.28) |
|
(9.34) |
|
(9.81) |
|
(1%) |
|
(5%) |
|
(9.31) |
|
(9.68) |
|
(4%) |
General and administration |
|
(2.88) |
|
(1.61) |
|
(2.42) |
|
79% |
|
19% |
|
(2.32) |
|
(2.28) |
|
2% |
Fund flows from operations
netback |
|
49.65 |
|
49.45 |
|
42.21 |
|
- |
|
18% |
|
49.56 |
|
40.32 |
|
23% |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl) |
|
102.99 |
|
98.68 |
|
94.22 |
|
4% |
|
9% |
|
100.84 |
|
94.30 |
|
7% |
Edmonton Sweet index (US $/bbl) |
|
96.85 |
|
90.43 |
|
90.56 |
|
7% |
|
7% |
|
93.65 |
|
88.99 |
|
5% |
AECO ($/GJ) |
|
4.44 |
|
5.42 |
|
3.35 |
|
(18%) |
|
33% |
|
4.93 |
|
3.19 |
|
55% |
Sales
- The realized price for our crude oil production in Canada is directly linked to WTI but is
subject to market conditions in Western
Canada. These market conditions can result in
fluctuations in the pricing differential, as reflected by the
Edmonton Sweet index price. The realized price of our NGLs in
Canada is based on product
specific differentials pertaining to trading hubs in the United States. The realized price of
our natural gas in Canada is based
on the AECO spot price in Canada.
- Sales per boe increased by 3% quarter-over-quarter as a result
of a 7% increase in Edmonton Sweet index pricing, partially offset
by an 18% decrease in AECO pricing.
- On a year-over-year basis, sales per boe increased by 15% and
18% for the three and six months ended June
30, 2014, largely as a result of the strengthening of the
Edmonton Sweet index and AECO reference price, coupled with a
higher mix of crude oil and NGL production.
- The increases in the Edmonton Sweet index combined with
incremental production from our Saskatchewan acquisition and production growth
in the Cardium and Mannville
resource plays resulted in a 33% and 62% increase in sales for Q2
2014 versus Q1 2014 and Q2 2013, respectively.
Royalties
- Royalty expense as a percentage of sales increased to 11.2% for
Q2 2014 from 9.6% in Q2 2013 and 10.3% in Q1 2014. Royalty
expense as a percentage of sales increased to 10.8% for the six
months ended June 30, 2014 as
compared to 10.1% for the same period of the prior year.
- All periods are affected by the timing of placing wells on
production due to royalty incentives on initial production
volumes. Royalties as a percentage of sales were slightly
higher in the second quarter partially as a result of slightly
higher average royalty rates associated with Vermilion's Saskatchewan production. In addition,
increased commodity prices have contributed to the year-over-year
increases in royalty rates as a percentage of sales.
Transportation
- Transportation expense relates to the delivery of crude oil and
natural gas production to major pipelines where legal title
transfers.
- Transportation expense per boe remained consistent between Q2
2014 and Q1 2014 as higher trucking costs in the second quarter
associated with Vermilion's
Saskatchewan acquisition offset
trucking costs incurred in the first quarter which were related to
a Pembina pipeline outage.
- Transportation expense per boe increased for the three and six
months ended June 30, 2014 as
compared to the same periods of the prior year due to trucking
costs associated with Vermilion's
recently acquired Saskatchewan
assets as well as pipeline tariff increases.
Operating expense
- Operating expense per boe was lower for the three and six
months ended June 30, 2014 as
compared to the prior periods presented due to a larger increase in
production volumes than expenditures.
General and administration
- General and administration expense increased in the current
quarter as compared to the prior quarter largely due to
higher legal and consultant costs related to the Saskatchewan acquisition ($1.1MM), additional salary allocations from our
Corporate segment to our Canadian Business Unit to reflect
internal integration effort associated with the Saskatchewan acquisition ($0.7MM), lower third party overhead recoveries as
a result of less capital activity in the second quarter due to
spring break-up ($1.0MM) as well as
higher salary costs quarter-over-quarter resulting from increased
staffing levels. These same items are the significant drivers for
the year-over-year increases in general and administration expense
for the periods presented, partially offset by expenditure
timing.
FRANCE
BUSINESS UNIT
Overview
- Entered France in 1997 and
completed three subsequent acquisitions, including two in
2012.
- Largest oil producer by volume.
- Producing assets include large conventional fields with high
working interests located in the Aquitaine and Paris Basins with an
identified inventory of workover, infill drilling, and secondary
recovery opportunities.
- Production is characterized by Brent-based crude pricing and
low base decline rates.
Operational review
|
|
Three
Months Ended |
|
%
change |
|
Six
Months Ended |
|
% change |
|
|
Jun 30, |
|
Mar 31, |
|
Jun 30, |
|
Q2/14 vs. |
|
Q2/14 vs. |
|
Jun 30, |
|
Jun 30, |
|
2014 vs. |
France business unit |
|
2014 |
|
2014 |
|
2013 |
|
Q1/14 |
|
Q2/13 |
|
2014 |
|
2013 |
|
2013 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
11,025 |
|
10,771 |
|
10,390 |
|
2% |
|
6% |
|
10,899 |
|
10,360 |
|
5% |
Natural gas (mmcf/d) |
|
- |
|
- |
|
4.19 |
|
- |
|
(100%) |
|
- |
|
4.20 |
|
(100%) |
Total (boe/d) |
|
11,025 |
|
10,771 |
|
11,088 |
|
2% |
|
(1%) |
|
10,899 |
|
11,060 |
|
(1%) |
Inventory (mbbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Opening crude oil
inventory |
|
238 |
|
269 |
|
218 |
|
|
|
|
|
269 |
|
354 |
|
|
Adjustments |
|
- |
|
- |
|
- |
|
|
|
|
|
- |
|
5 |
|
|
Crude oil production |
|
1,003 |
|
969 |
|
945 |
|
|
|
|
|
1,973 |
|
1,875 |
|
|
Crude oil sales |
|
(1,062) |
|
(1,000) |
|
(961) |
|
|
|
|
|
(2,063) |
|
(2,032) |
|
|
Closing crude oil inventory |
|
179 |
|
238 |
|
202 |
|
|
|
|
|
179 |
|
202 |
|
|
Production mix (% of
total) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil |
|
100% |
|
100% |
|
94% |
|
|
|
|
|
100% |
|
94% |
|
|
Natural gas |
|
- |
|
- |
|
6% |
|
|
|
|
|
- |
|
6% |
|
|
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
|
37,614 |
|
37,967 |
|
23,223 |
|
(1%) |
|
62% |
|
75,581 |
|
44,815 |
|
69% |
Gross wells drilled |
|
2.00 |
|
2.00 |
|
3.00 |
|
|
|
|
|
4.00 |
|
5.00 |
|
|
Net wells drilled |
|
2.00 |
|
2.00 |
|
3.00 |
|
|
|
|
|
4.00 |
|
5.00 |
|
|
Production
- Quarter-over-quarter production increased 2% and year-over-year
production decreased 1%. Year-over-year production of crude oil
increased 6%.
- In late September 2013, the third
party Lacq processing facility that processed our Vic Bihl gas production was permanently
closed. As a result, our Vic
Bihl gas production has been temporarily shut-in while
preparations to transfer to an alternative facility are
completed. We expect approximately 850 mcf/d will be back
on-stream in early 2015, with the remaining approximately 3,400
mcf/d not anticipated to be back on production until
late-2015.
- Production remains 100% weighted to Brent crude due to the
shut-in of Vic Bihl gas
production.
Activity review
- Vermilion drilled two (2.0
net) wells in the Champotran field in the Paris Basin during Q2 2014, with production
from these wells anticipated to come on-line in Q3.
- During Q2 2014, we also completed a number of seismic and
facility integrity projects.
- Our Parentis (PS-224) well, drilled in Q2 2014, is producing 20
bbls/d. The Cazaux North well drilled in Q1 2014 is dry and
will be abandoned.
- In 2014, we are planning a seven-well drilling program in the
Champotran, Cazaux, and Parentis fields.
Financial review
|
|
|
Three
Months Ended |
|
%
change |
|
Six
Months Ended |
|
% change |
France business unit |
|
|
Jun 30, |
|
Mar 31, |
|
Jun 30, |
|
Q2/14 vs. |
|
Q2/14 vs. |
|
Jun 30, |
|
Jun 30, |
|
2014 vs. |
($M except as indicated) |
|
|
2014 |
|
2014 |
|
2013 |
|
Q1/14 |
|
Q2/13 |
|
2014 |
|
2013 |
|
2013 |
Sales |
|
|
124,617 |
|
117,560 |
|
100,418 |
|
6% |
|
24% |
|
242,177 |
|
221,984 |
|
9% |
Royalties |
|
|
(7,796) |
|
(7,351) |
|
(6,093) |
|
6% |
|
28% |
|
(15,147) |
|
(12,894) |
|
17% |
Transportation expense |
|
|
(5,385) |
|
(4,753) |
|
(2,416) |
|
13% |
|
123% |
|
(10,138) |
|
(5,170) |
|
96% |
Operating expense |
|
|
(16,550) |
|
(16,420) |
|
(16,935) |
|
1% |
|
(2%) |
|
(32,970) |
|
(36,874) |
|
(11%) |
General and administration |
|
|
(5,559) |
|
(5,194) |
|
(3,927) |
|
7% |
|
42% |
|
(10,753) |
|
(9,613) |
|
12% |
Current income taxes |
|
|
(24,761) |
|
(25,264) |
|
(16,124) |
|
(2%) |
|
54% |
|
(50,025) |
|
(34,783) |
|
44% |
Fund flows from operations |
|
|
64,566 |
|
58,578 |
|
54,923 |
|
10% |
|
18% |
|
123,144 |
|
122,650 |
|
- |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
117.29 |
|
117.54 |
|
98.04 |
|
- |
|
20% |
|
117.41 |
|
102.84 |
|
14% |
Royalties |
|
|
(7.34) |
|
(7.35) |
|
(5.95) |
|
- |
|
23% |
|
(7.34) |
|
(5.97) |
|
23% |
Transportation expense |
|
|
(5.07) |
|
(4.75) |
|
(2.36) |
|
7% |
|
115% |
|
(4.91) |
|
(2.39) |
|
105% |
Operating expense |
|
|
(15.58) |
|
(16.42) |
|
(16.53) |
|
(5%) |
|
(6%) |
|
(15.98) |
|
(17.08) |
|
(6%) |
General and administration |
|
|
(5.24) |
|
(5.19) |
|
(3.83) |
|
1% |
|
37% |
|
(5.21) |
|
(4.45) |
|
17% |
Current income taxes |
|
|
(23.30) |
|
(25.26) |
|
(15.74) |
|
(8%) |
|
48% |
|
(24.25) |
|
(16.11) |
|
51% |
Fund flows from operations
netback |
|
|
60.76 |
|
58.57 |
|
53.63 |
|
4% |
|
13% |
|
59.72 |
|
56.84 |
|
5% |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated Brent (US $/bbl) |
|
|
109.63 |
|
108.22 |
|
102.44 |
|
1% |
|
7% |
|
108.93 |
|
107.50 |
|
1% |
Sales
- Crude oil production in France
is priced with reference to Dated Brent.
- Sales per boe for Q2 2014 was relatively unchanged versus Q1
2014 as the 1% increase in the US dollar Dated Brent reference
price was largely offset by a 1% strengthening of the Canadian
dollar.
- Sales per boe for the three and six months ended June 30, 2014 were 20% and 14% higher than the
respective periods in the previous year. This increase was
primarily the result of increases in the Dated Brent reference
price and the weakening of the Canadian dollar. These
changes, coupled with increased crude oil production, resulted in
increased sales for both the three and six month periods ended
June 30, 2014 of 24% and 9%,
respectively.
Royalties
- Royalties in France relate to
two components: RCDM (levied on units of production and not subject
to changes in commodity prices) and R31 (based on a percentage of
revenue).
- As a percentage of sales, royalties for the periods presented
remained relatively constant.
Transportation
- Historically, transportation expense in France related to the shipments of crude oil
by tanker from the Aquitaine Basin to third party refineries.
As a result of the closure of the Lacq processing facility in Q3
2013, Vermilion began incurring
additional transportation charges to ship Vic Bihl production to market.
Accordingly, transportation expense per boe for the 2014 periods
presented is higher than the expense per boe for the comparative
periods from the prior year.
Operating expense
- Operating expense for Q2 2014 was consistent with the Q1 2014
and Q2 2013 expense. The decrease in the expense per boe for
Q2 2014 as compared to the prior periods is associated with higher
volumes in the current period.
General and administration
- General and administration expense was consistent among the
periods presented. Minor variances are largely attributable
to the timing of expenditures.
Current income taxes
- Current income taxes in France
apply to taxable income after eligible deductions at a statutory
rate of 38.1% for 2014. Following the expiration of a
temporary surtax, the statutory tax rate is expected to decrease to
34.4% for the tax year 2016. For 2014, the effective rate on
current taxes is expected to be between approximately 28% and 31%.
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 for Q2 2014 was slightly lower versus Q1
2014 as increased pre-tax fund flows from operations was offset by
an increase in eligible tax deductions for depreciation.
- On a year-over-year basis, current taxes increased by 54% and
44% for the three and six months ended June
30, 2014 versus the same periods in 2013. These
increases were the result of the absence of certain interest
deductions, lower depletion for tax purposes, and higher tax rates
following a December 2013 corporate
tax legislation enacted by the France government which increased the rate of
a temporary surtax.
NETHERLANDS
BUSINESS UNIT
Overview
- Entered the Netherlands in
2004.
- Second largest onshore gas producer by volume.
- Interests include 16 licenses in the northeast region, five
licenses in the central region, and two offshore licenses.
- Licenses include more than 800,000 net acres of undeveloped
land.
- High impact natural gas drilling and development.
- Natural gas produced in the
Netherlands is priced off the TTF index, which receives a
significant premium over North American gas prices.
Operational review
|
|
|
Three
Months Ended |
|
%
change |
|
Six
Months Ended |
|
% change |
|
|
|
Jun 30, |
|
Mar 31, |
|
Jun 30, |
|
Q2/14 vs. |
|
Q2/14 vs. |
|
Jun 30, |
|
Jun 30, |
|
2014 vs. |
Netherlands business
unit |
|
|
2014 |
|
2014 |
|
2013 |
|
Q1/14 |
|
Q2/13 |
|
2014 |
|
2013 |
|
2013 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d) |
|
|
96 |
|
69 |
|
50 |
|
39% |
|
92% |
|
83 |
|
73 |
|
14% |
Natural gas (mmcf/d) |
|
|
40.35 |
|
43.15 |
|
38.52 |
|
(6%) |
|
5% |
|
41.74 |
|
37.72 |
|
11% |
Total (boe/d) |
|
|
6,822 |
|
7,260 |
|
6,470 |
|
(6%) |
|
5% |
|
7,040 |
|
6,360 |
|
11% |
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
|
|
21,513 |
|
20,118 |
|
4,157 |
|
7% |
|
418% |
|
41,631 |
|
4,529 |
|
819% |
Gross wells drilled |
|
|
2.00 |
|
2.00 |
|
- |
|
|
|
|
|
4.00 |
|
- |
|
|
Net wells drilled |
|
|
1.43 |
|
1.86 |
|
- |
|
|
|
|
|
3.29 |
|
- |
|
|
Production
- Quarter-over-quarter production decrease of 6% and
year-over-year production growth of 5%.
- Production in the Netherlands
is currently being managed to meet corporate targets, optimize
facility use and regulate declines.
Activity review
- Vermilion drilled two (1.4
net) wells during Q2 2014. The Havelte-01 well (50% working
interest) had no gas shows from the Zechstein and Vlieland targets,
however the lease site of the Havelte-01 well will enable the tie
in of Eesveen-01, a well located in a previously stranded gas field
discovered in 1986. The Lambertschaag-02 well (93% working
interest) in the Slootdorp concession was determined to be not gas
bearing in its primary target zone. Lambertschaag-02 did encounter
secondary zones of interest with gas shows which will be further
evaluated in Q3 2014.
- Late during Q2 2014, we initiated production from the Zechstein
carbonate formation of the DeHoeve-01 well at a rate of 3 mmcf/d
net to Vermilion. The DeHoeve well
was drilled in 2009 and had previously produced from the Slochteren
sandstone (Rotliegend).
- An additional three wells are planned for the 2014 drilling
program in the Netherlands, one is
planned for the third quarter and the remaining two wells are
planned for the fourth quarter. The drilling program will include
our first new well on the lands acquired in October 2013.
Financial review
|
|
|
Three
Months Ended |
|
%
change |
|
|
Six
Months Ended |
|
% change |
Netherlands business unit |
|
|
Jun 30, |
|
Mar 31, |
|
Jun 30, |
|
Q2/14 vs. |
|
Q2/14 vs. |
|
|
Jun 30, |
|
Jun 30, |
|
2014 vs. |
($M except as indicated) |
|
|
2014 |
|
2014 |
|
2013 |
|
Q1/14 |
|
Q2/13 |
|
|
2014 |
|
2013 |
|
2013 |
Sales |
|
|
29,881 |
|
41,554 |
|
38,316 |
|
(28%) |
|
(22%) |
|
|
71,435 |
|
72,737 |
|
(2%) |
Royalties |
|
|
(693) |
|
(2,208) |
|
- |
|
(69%) |
|
100% |
|
|
(2,901) |
|
- |
|
100% |
Operating expense |
|
|
(6,390) |
|
(6,042) |
|
(5,260) |
|
6% |
|
21% |
|
|
(12,432) |
|
(9,229) |
|
35% |
General and administration |
|
|
(326) |
|
(598) |
|
(426) |
|
(45%) |
|
(23%) |
|
|
(924) |
|
(838) |
|
10% |
Current income taxes |
|
|
(1,301) |
|
(3,788) |
|
(9,621) |
|
(66%) |
|
(86%) |
|
|
(5,089) |
|
(19,055) |
|
(73%) |
Fund flows from operations |
|
|
21,171 |
|
28,918 |
|
23,009 |
|
(27%) |
|
(8%) |
|
|
50,089 |
|
43,615 |
|
15% |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
48.14 |
|
63.60 |
|
65.08 |
|
(24%) |
|
(26%) |
|
|
56.06 |
|
63.19 |
|
(11%) |
Royalties |
|
|
(1.12) |
|
(3.38) |
|
- |
|
(67%) |
|
100% |
|
|
(2.28) |
|
- |
|
100% |
Operating expense |
|
|
(10.29) |
|
(9.25) |
|
(8.93) |
|
11% |
|
15% |
|
|
(9.76) |
|
(8.02) |
|
22% |
General and administration |
|
|
(0.53) |
|
(0.91) |
|
(0.72) |
|
(42%) |
|
(26%) |
|
|
(0.73) |
|
(0.73) |
|
- |
Current income taxes |
|
|
(2.10) |
|
(5.80) |
|
(16.34) |
|
(64%) |
|
(87%) |
|
|
(3.99) |
|
(16.55) |
|
(76%) |
Fund flows from operations
netback |
|
|
34.10 |
|
44.26 |
|
39.09 |
|
(23%) |
|
(13%) |
|
|
39.30 |
|
37.89 |
|
4% |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TTF ($/GJ) |
|
|
7.91 |
|
10.19 |
|
10.14 |
|
(22%) |
|
(22%) |
|
|
9.02 |
|
10.23 |
|
(12%) |
TTF (€/GJ) |
|
|
5.27 |
|
6.75 |
|
7.57 |
|
(22%) |
|
(30%) |
|
|
6.01 |
|
7.69 |
|
(22%) |
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.
- The decreases in sales and sales per boe in Q2 2014 versus Q1
2014 and Q2 2013 were largely in-line with the change in the
Canadian dollar TTF reference price.
- On a year-over-year basis, sales declined by 2% as a result of
the 12% decrease in the TTF reference price offset by an 11%
increase in production.
Royalties
- Historically, we have not paid royalties in the Netherlands, however, certain wells
associated with an acquisition completed by Vermilion's Netherlands Business Unit in
October 2013 have reached payout and
are now subject to an overriding royalty.
Transportation expense
- Our production in the
Netherlands is not subject to transportation expense as gas
is sold at the plant gate.
Operating expense
- Operating expense increased in Q2 2014 from Q1 2014 due to the
timing of major project expense. Lower volumes
quarter-over-quarter also contributed to the increase in operating
costs on a per boe basis.
- Year-over-year, operating expense increased for both the
quarter and year to date periods due to the strengthening of the
Euro versus the Canadian dollar as well as higher salary costs
associated with continued organic growth in the Netherlands business unit.
General and administration
- General and administration expense decreased in Q2 2014 from Q1
2014 due to a reduction in project-related consultant costs.
As compared to the prior year, general and administration expense
for the current quarter and year to date periods remained
consistent.
Current income taxes
- Current income taxes in the
Netherlands apply to taxable income after eligible
deductions at a statutory tax rate of approximately 46%. For 2014,
the effective rate on current taxes is expected to be between
approximately 6% and 8%. 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 decreased as compared to both Q1 2014 and
Q2 2013 as a result of decreased revenues, lower TTF reference
prices and an increase in tax deductions for depletion during the
current quarter.
GERMANY
BUSINESS UNIT
Overview
- Vermilion entered Germany in February
2014 with the purchase of a 25% participation interest in a
four-partner consortium.
- The assets of the four-partner consortium include four gas
producing fields across 11 production licenses and an exploration
license in surrounding fields.
- Production licenses comprising 207,000 gross acres, of which
85% is in the exploration license.
Operational review
|
|
|
|
|
|
|
|
|
|
|
|
Three
Months Ended |
|
|
% change |
|
|
Six Months
Ended |
|
|
|
|
|
|
|
|
|
|
|
|
Jun 30, |
Mar 31, |
|
|
Q2/14 vs. |
|
|
Jun 30, |
Germany business unit |
|
|
|
|
|
|
|
|
|
|
2014 |
2014 |
|
|
Q1/14 |
|
|
2014 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d) |
|
|
|
|
|
|
|
|
|
|
16.13 |
10.64 |
|
|
52% |
|
|
13.40 |
|
Total (boe/d) |
|
|
|
|
|
|
|
|
|
|
2,689 |
1,773 |
|
|
52% |
|
|
2,234 |
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
|
|
|
|
|
|
|
|
|
|
630 |
196 |
|
|
221% |
|
|
826 |
|
Acquisitions ($M) |
|
|
|
|
|
|
|
|
|
|
- |
172,871 |
|
|
|
|
|
172,871 |
Production
- Achieved Q2 2014 production of 2,689 boe/d, an increase of 52%
as compared to 1,773 boe/d in Q1 2014, taking into account an
effective date for production of February 1,
2014.
Activity review
- Continued the integration of the German business with our
working interest partners and have commenced planning for future
wells.
- In Q1 2014, we participated in the drilling of one (0.25 net)
development well, which logged 81 metres of net pay and is expected
to be tested and put on production during the second half of
2014.
- We have hired a Managing Director for the German business unit
and have opened an office outside of Berlin, which we are currently outfitting and
staffing.
Financial review
|
|
|
|
Three Months Ended |
|
|
%
change |
|
|
Six
Months Ended |
Germany business unit |
|
|
Jun 30, |
Mar 31, |
|
|
Q2/14 vs. |
|
|
Jun 30, |
($M except as indicated) |
|
|
2014 |
2014 |
|
|
Q1/14 |
|
|
2014 |
|
Sales |
|
|
11,097 |
8,915 |
|
|
24% |
|
|
20,012 |
|
Royalties |
|
|
(2,284) |
(1,802) |
|
|
27% |
|
|
(4,086) |
|
Transportation expense |
|
|
(1,052) |
(422) |
|
|
149% |
|
|
(1,474) |
|
Operating expense |
|
|
(2,043) |
(1,554) |
|
|
31% |
|
|
(3,597) |
|
General and administration |
|
|
(830) |
(568) |
|
|
46% |
|
|
(1,398) |
|
Current income taxes |
|
|
(506) |
(537) |
|
|
(6%) |
|
|
(1,043) |
|
Fund flows from operations |
|
|
4,382 |
4,032 |
|
|
9% |
|
|
8,414 |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
45.36 |
55.85 |
|
|
(19%) |
|
|
49.50 |
|
Royalties |
|
|
(9.34) |
(11.29) |
|
|
(17%) |
|
|
(10.11) |
|
Transportation expense |
|
|
(4.30) |
(2.64) |
|
|
63% |
|
|
(3.65) |
|
Operating expense |
|
|
(8.35) |
(9.74) |
|
|
(14%) |
|
|
(8.90) |
|
General and administration |
|
|
(3.39) |
(3.56) |
|
|
(5%) |
|
|
(3.46) |
|
Current income taxes |
|
|
(2.07) |
(3.36) |
|
|
(38%) |
|
|
(2.58) |
|
Fund flows from
operations netback |
|
|
17.91 |
25.26 |
|
|
(29%) |
|
|
20.80 |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
TTF ($/GJ) |
|
|
7.91 |
10.19 |
|
|
(22%) |
|
|
9.02 |
|
TTF (€/GJ) |
|
|
5.27 |
6.75 |
|
|
(22%) |
|
|
6.01 |
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.
- Sales for Q2 2014 were 24% higher due to the inclusion of a
full quarter of production in Q2 2014 versus two months of
production in Q1 2014.
- Sales per boe decreased by 19% from Q1 2014 due to a decrease
in the TTF reference price.
Royalties expense
- Our production in Germany is
subject to royalties at a rate of approximately 20% of natural gas
sales revenue.
Transportation expense
- Transportation expense relates to costs incurred to deliver
natural gas from the processing facility to the customer.
Operating expense
- Operating expenses for Germany
is billed monthly by the joint venture operator and is expected to
be similar to our Netherlands
operating costs per boe.
General and administration
- Included in general and administration costs are expenditures
totalling $0.8 million relating to
legal and consulting costs associated with the acquisition.
Current income taxes
- Current income taxes in Germany apply to taxable income after eligible
deductions at a statutory tax rate of approximately 23%. For 2014,
the effective rate on current taxes is expected to be between
approximately 10% and 12%. This rate is subject to change in
response to commodity price fluctuations, the timing of capital
expenditures and other eligible in-country adjustments.
IRELAND
BUSINESS UNIT
Overview
- 18.5% non-operating interest in the offshore Corrib gas field
located approximately 83km off the northwest coast of Ireland.
- Project comprises six offshore wells, both offshore and onshore
pipeline segments as well as a natural gas processing
facility.
- Production from Corrib is expected to increase Vermilion's volumes by approximately 58 mmcf/d
(9,700 boe/d) once the field reaches peak production.
Operational and financial review
|
|
|
|
Three
Months Ended |
|
%
change |
|
|
Six
Months Ended |
|
% change |
Ireland business unit |
|
|
|
Jun 30, |
|
|
Mar 31, |
|
|
Jun 30, |
|
Q2/14 vs. |
|
Q2/14 vs. |
|
|
Jun 30, |
|
|
Jun 30, |
|
2014 vs. |
($M) |
|
|
|
2014 |
|
|
2014 |
|
|
2013 |
|
Q1/14 |
|
Q2/13 |
|
|
2014 |
|
|
2013 |
|
2013 |
Transportation expense |
|
|
|
(1,571) |
|
|
(1,588) |
|
|
(1,626) |
|
(1%) |
|
(3%) |
|
|
(3,159) |
|
|
(3,244) |
|
(3%) |
General and
administration |
|
|
|
(252) |
|
|
(282) |
|
|
(410) |
|
(11%) |
|
(39%) |
|
|
(534) |
|
|
(647) |
|
(17%) |
Fund flows from
operations |
|
|
|
(1,823) |
|
|
(1,870) |
|
|
(2,036) |
|
(3%) |
|
(10%) |
|
|
(3,693) |
|
|
(3,891) |
|
(5%) |
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
|
27,221 |
|
|
16,236 |
|
|
24,878 |
|
68% |
|
9% |
|
|
43,457 |
|
|
41,398 |
|
5% |
Activity review
- Completed tunnel boring operations beneath Sruwaddacon Bay on
May 21, 2014. The tunnel boring
machine has been demobilized and we are progressing with remaining
activities to bring the project on production, including the
installation of flow and umbilical lines within the tunnel,
grouting of the tunnel, and certain offshore well workover
activities.
- Based on our deterministic schedule for remaining construction
and commissioning activities, we anticipate first gas in
approximately mid-2015 with peak production 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.
AUSTRALIA
BUSINESS UNIT
Overview
- Entered Australia in
2005.
- Hold title to a 100% 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 are located 600 metres below the sea bed with 500 to
3,000 plus metre horizontal lengths.
- Contracted crude oil production is priced with reference to
Dated Brent.
Operational review
|
|
|
|
Three
Months Ended |
|
%
change |
|
|
Six
Months Ended |
|
% change |
|
|
|
|
Jun 30, |
|
|
Mar 31, |
|
|
Jun 30, |
|
Q2/14 vs. |
|
Q2/14 vs. |
|
|
Jun 30, |
|
|
Jun 30, |
|
2014 vs. |
Australia business unit |
|
|
|
2014 |
|
|
2014 |
|
|
2013 |
|
Q1/14 |
|
Q2/13 |
|
|
2014 |
|
|
2013 |
|
2013 |
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
|
|
6,483 |
|
|
7,110 |
|
|
7,363 |
|
(9%) |
|
(12%) |
|
|
6,795 |
|
|
6,331 |
|
7% |
Inventory (mbbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Opening crude oil
inventory |
|
|
|
63 |
|
|
130 |
|
|
165 |
|
|
|
|
|
|
130 |
|
|
268 |
|
|
Crude oil production |
|
|
|
590 |
|
|
640 |
|
|
670 |
|
|
|
|
|
|
1,230 |
|
|
1,146 |
|
|
Crude oil sales |
|
|
|
(464) |
|
|
(707) |
|
|
(648) |
|
|
|
|
|
|
(1,171) |
|
|
(1,227) |
|
|
Closing crude oil inventory |
|
|
|
189 |
|
|
63 |
|
|
187 |
|
|
|
|
|
|
189 |
|
|
187 |
|
|
Activity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M) |
|
|
|
10,991 |
|
|
5,691 |
|
|
8,282 |
|
93% |
|
33% |
|
|
16,682 |
|
|
63,631 |
|
(74%) |
Gross wells drilled |
|
|
|
- |
|
|
- |
|
|
- |
|
|
|
|
|
|
- |
|
|
2.00 |
|
|
Net wells drilled |
|
|
|
- |
|
|
- |
|
|
- |
|
|
|
|
|
|
- |
|
|
2.00 |
|
|
Production
- Wandoo production decreased by 9% quarter-over-quarter and 12%
year-over-year.
- Production volumes are managed to meet customer demands and
long-term supply agreements. We continue to plan for
production levels of between 6,000 and 8,000 bbls/d.
- Production continues to reflect strong well results from the
2013 drilling program, more than offsetting natural declines.
We continue to produce the wells at restricted rates below their
demonstrated productive capacity.
Activity review
- In Q2 2014, efforts were focused on facilities repairs and
engineering studies, including the expansion of accommodation
quarters on the Wandoo B platform and repair of the A5 conductor on
Wandoo A.
- 2014 planned activities include ongoing facilities maintenance,
enhancement, and refurbishment along with preparation and
permitting activities in advance of our planned 2015 drilling
program.
Financial review
|
|
|
Three
Months Ended |
|
%
change |
|
Six
Months Ended |
|
% change |
Australia business unit |
|
|
Jun 30, |
|
Mar 31, |
|
Jun 30, |
|
Q2/14 vs. |
|
Q2/14 vs. |
|
Jun 30, |
|
Jun 30, |
|
2014 vs. |
($M except as indicated) |
|
|
2014 |
|
2014 |
|
2013 |
|
Q1/14 |
|
Q2/13 |
|
2014 |
|
2013 |
|
2013 |
Sales |
|
|
58,828 |
|
89,974 |
|
72,282 |
|
(35%) |
|
(19%) |
|
148,802 |
|
142,183 |
|
5% |
Operating expense |
|
|
(12,051) |
|
(17,360) |
|
(9,912) |
|
(31%) |
|
22% |
|
(29,411) |
|
(24,738) |
|
19% |
General and administration |
|
|
(1,661) |
|
(1,206) |
|
(1,378) |
|
38% |
|
21% |
|
(2,867) |
|
(2,896) |
|
(1%) |
Corporate income taxes |
|
|
(5,689) |
|
(8,841) |
|
(10,646) |
|
(36%) |
|
(47%) |
|
(14,530) |
|
(17,859) |
|
(19%) |
PRRT |
|
|
(12,699) |
|
(20,239) |
|
(12,590) |
|
(37%) |
|
1% |
|
(32,938) |
|
(23,743) |
|
39% |
Fund flows from operations |
|
|
26,728 |
|
42,328 |
|
37,756 |
|
(37%) |
|
(29%) |
|
69,056 |
|
72,947 |
|
(5%) |
Netbacks ($/boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
|
126.87 |
|
127.26 |
|
111.54 |
|
- |
|
14% |
|
127.11 |
|
115.89 |
|
10% |
Operating expense |
|
|
(25.99) |
|
(24.55) |
|
(15.30) |
|
6% |
|
70% |
|
(25.12) |
|
(20.16) |
|
25% |
General and administration |
|
|
(3.58) |
|
(1.71) |
|
(2.13) |
|
109% |
|
68% |
|
(2.45) |
|
(2.36) |
|
4% |
Corporate income taxes |
|
|
(12.27) |
|
(12.51) |
|
(16.43) |
|
(2%) |
|
(25%) |
|
(12.41) |
|
(14.56) |
|
(15%) |
PRRT |
|
|
(27.39) |
|
(28.63) |
|
(19.43) |
|
(4%) |
|
41% |
|
(28.14) |
|
(19.35) |
|
45% |
Fund flows from operations
netback |
|
|
57.64 |
|
59.86 |
|
58.25 |
|
(4%) |
|
(1%) |
|
58.99 |
|
59.46 |
|
(1%) |
Reference prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated Brent (US $/bbl) |
|
|
109.63 |
|
108.22 |
|
102.44 |
|
1% |
|
7% |
|
108.93 |
|
107.50 |
|
1% |
Sales
- Our production in Australia
currently receives a premium to Dated Brent.
- Sales per boe increased for the three and six months ended
June 30, 2014 versus the comparable
periods in the prior year as a result of an increase in the Dated
Brent reference price combined with the impact of the weakening
Canadian dollar.
- Sales increased for the six months ended June 30, 2014 versus 2013, despite slightly lower
sold volumes, primarily as a result of the impacts of the weakening
of the Canadian dollar, which resulted in a 10% increase in sales
per boe.
- Sales for Q2 2014 versus Q1 2014 and Q2 2013 were 35% and 19%
lower, respectively, primarily as a result of a build in crude oil
inventory (126,000 bbl) during Q2 2014.
Royalties and transportation expense
- Our production in Australia is
not subject to royalties or transportation expense as crude oil is
sold directly from the Wandoo B platform.
Operating expense
- Operating expense per boe for Q2 2014 remained consistent with
the expense for Q1 2014.
- Operating expense per boe for the three and six months ended
June 30, 2014 was higher than the
expense for the comparative periods in the prior year due to
increased diesel usage and higher salary costs.
General and administration
- General and administration expense increased slightly during Q2
2014 as compared to Q1 2014 and Q2 2013 due to timing of
expenditures.
- For the year to date period ended June
30, 2014, general and administration expense remained
consistent with the expense for the same period of the prior
year.
PRRT and corporate income taxes
- In Australia, current income
taxes include both PRRT and corporate income taxes. PRRT is a
profit based tax applied at a rate of 40% on sales less eligible
expenditures, including operating expenses and capital
expenditures. Corporate income taxes are applied at a rate of
30% on taxable income after eligible deductions, which include
PRRT.
- For 2014, the combined corporate income tax and PRRT effective
rate is expected to be between approximately 38% and 42%.
This rate is subject to change in response to commodity price
fluctuations, the timing of capital expenditures and other eligible
in-country adjustments.
- Combined corporate income taxes and PRRT movements for the
three and six months ended June 30,
2014 versus the comparable periods was largely consistent
with the fluctuations in sales. On a year-over-year basis,
PRRT for 2014 increased versus the 2013 periods as a result of the
lower capital spending in 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 |
|
Six
Months Ended |
|
|
|
|
Jun 30, |
|
|
Mar 31, |
|
|
Jun 30, |
|
Jun 30, |
|
|
Jun 30, |
($M) |
|
|
|
2014 |
|
|
2014 |
|
|
2013 |
|
2014 |
|
|
2013 |
General and administration |
|
|
|
(2,574) |
|
|
(3,751) |
|
|
(1,224) |
|
(6,325) |
|
|
(2,912) |
Current income taxes |
|
|
|
(378) |
|
|
(173) |
|
|
(328) |
|
(551) |
|
|
(579) |
Interest expense |
|
|
|
(12,334) |
|
|
(11,460) |
|
|
(9,336) |
|
(23,794) |
|
|
(18,025) |
Realized gain (loss) on derivatives |
|
|
|
2,419 |
|
|
2,640 |
|
|
1,770 |
|
5,059 |
|
|
(1,017) |
Realized foreign exchange gain
(loss) |
|
|
|
587 |
|
|
(2,041) |
|
|
1,272 |
|
(1,454) |
|
|
655 |
Realized other income |
|
|
|
74 |
|
|
221 |
|
|
77 |
|
295 |
|
|
549 |
Fund flows from operations |
|
|
|
(12,206) |
|
|
(14,564) |
|
|
(7,769) |
|
(26,770) |
|
|
(21,329) |
General and administration
- The decrease in general and administration costs for Q2 2014
versus Q1 2014 was primarily the result of the Q1 2014 impact of
certain outstanding VIP awards to be settled partially in
cash.
- On a year-over-year basis, the increase in general and
administration costs for the six months ended June 30, 2013 to the same period in 2014 was a
result of the impact of certain outstanding VIP awards to be
settled partially in cash.
Current income taxes
- Taxes in our corporate segment relates to holding companies
that pay current taxes in foreign jurisdictions.
Interest expense
- Interest expense is incurred on our senior unsecured notes and
on borrowings under our revolving credit facility. The
increase in 2014 versus the comparable periods is due to increased
borrowings under our revolving credit facility.
Hedging
- The nature of our operations results in exposure to
fluctuations in commodity prices, interest rates and foreign
currency exchange rates. We monitor and, when appropriate,
use derivative financial instruments to manage our exposure to
these fluctuations. All transactions of this nature entered
into are related to an underlying financial position or to future
crude oil and natural gas production. We do not use derivative
financial instruments for speculative purposes. We have
elected not to designate any of our derivative financial
instruments as accounting hedges and thus account for changes in
fair value in net earnings at each reporting period. We have
not obtained collateral or other security to support our financial
derivatives as we review the creditworthiness of our counterparties
prior to entering into derivative contracts.
- Our hedging philosophy is to hedge solely for the purposes of
risk mitigation. Our approach is to hedge centrally to manage
our global risk (typically with an outlook of 12 to 18 months) with
a goal of securing pricing for 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
assisting in the execution of our capital and development
plans.
- The realized gain in 2014 related primarily to amounts received
on our TTF derivatives, partially offset by payments made on our
crude oil and AECO derivatives.
- A listing of derivative positions as at June 30, 2014 is included in "Supplemental Table
2" in this MD&A.
FINANCIAL PERFORMANCE REVIEW
|
|
|
|
Three
Months Ended |
|
|
|
|
Jun 30, |
|
Mar 31, |
|
Dec 31, |
|
Sep 30, |
|
Jun 30, |
|
Mar 31, |
|
Dec 31, |
|
Sep 30, |
($M except per share) |
|
|
|
2014 |
|
2014 |
|
2013 |
|
2013 |
|
2013 |
|
2013 |
|
2012 |
|
2012 |
Petroleum and natural gas
sales |
|
|
|
387,684 |
|
81,183 |
|
325,108 |
|
327,185 |
|
311,966 |
|
309,576 |
|
241,233 |
|
284,838 |
Net earnings |
|
|
|
53,993 |
|
102,788 |
|
101,510 |
|
67,796 |
|
106,198 |
|
52,137 |
|
56,914 |
|
30,798 |
Net earnings per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
|
0.51 |
|
1.00 |
|
1.00 |
|
0.67 |
|
1.05 |
|
0.53 |
|
0.58 |
|
0.31 |
Diluted |
|
|
|
0.50 |
|
0.99 |
|
0.98 |
|
0.66 |
|
1.04 |
|
0.51 |
|
0.57 |
|
0.31 |
The following table shows a reconciliation of
the change in net earnings:
($M) |
|
|
|
|
|
Q2/14 vs. Q1/14 |
|
|
|
Q2/14 vs. Q2/13 |
|
|
|
|
2014 vs. 2013 |
Net earnings - Comparative period |
|
|
|
|
|
102,788 |
|
|
|
106,198 |
|
|
|
|
158,335 |
Changes in: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fund flows from operations |
|
|
|
|
|
10,713 |
|
|
|
41,484 |
|
|
|
|
83,218 |
Equity based compensation |
|
|
|
|
|
(1,745) |
|
|
|
(7,493) |
|
|
|
|
(7,829) |
Unrealized gain or loss on
derivative instruments |
|
|
|
|
|
(5,456) |
|
|
|
(10,172) |
|
|
|
|
(5,124) |
Unrealized foreign exchange gain or loss |
|
|
|
|
|
(45,746) |
|
|
|
(51,771) |
|
|
|
|
(27,252) |
Unrealized other income |
|
|
|
|
|
358 |
|
|
|
452 |
|
|
|
|
603 |
Accretion |
|
|
|
|
|
(238) |
|
|
|
50 |
|
|
|
|
162 |
Depletion and depreciation |
|
|
|
|
|
(5,450) |
|
|
|
(26,484) |
|
|
|
|
(44,488) |
Deferred tax |
|
|
|
|
|
(1,231) |
|
|
|
1,729 |
|
|
|
|
(844) |
Net earnings - Current Period |
|
|
|
|
|
53,993 |
|
|
|
53,993 |
|
|
|
|
156,781 |
The fluctuations in net earnings from
quarter-to-quarter and from year-to-year are caused by changes in
both cash and non-cash based income and charges. Cash 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
and six months ended June 30, 2014
was higher than the same periods in 2013 as a result of an upward
revision of future performance condition assumptions during Q2
2014. Equity based compensation expense is also higher for Q2
2014 as compared to Q1 2014 as the impact of the revision in future
performance condition assumptions was partially offset by awards
vested during Q2 2014.
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.
In the six months ended June 30, 2014, we recognized an unrealized gain
of $2.4 million, relating primarily
to our TTF derivative instruments, partially offset by our crude
oil and Canadian natural gas derivative instruments. As at
June 30, 2014, we have a net current
derivative liability of approximately $0.2
million.
Unrealized foreign exchange gain or
loss
As a result of Vermilion's
international operations, Vermilion conducts business in currencies
other than the Canadian dollar and has monetary assets and
liabilities (including cash, receivables, payables, derivative
assets and liabilities, and intercompany loans) denominated in such
currencies. Vermilion's
exposure to foreign currencies includes the US dollar, the Euro and
the Australian Dollar.
Unrealized foreign exchange gains and losses are
the result of translating monetary assets and liabilities held in
non-functional currencies to the respective functional currencies
of Vermilion and its
subsidiaries. Unrealized foreign exchange primarily results
from the translation of Euro denominated financial assets. As
such, an appreciation in the Euro against the Canadian dollar will
result in an unrealized foreign exchange gain, and vice-versa.
For the three and six months ended June 30, 2014, the Canadian dollar strengthened
versus the Euro resulting in unrealized foreign exchange losses of
$23.7 million and $1.7 million, respectively.
Accretion
Fluctuations in accretion expense is primarily the result of
changes in discount rates applicable to the balance of asset
retirement obligations and additions resulting from drilling and
acquisitions.
Q2 2014 accretion expense was relatively
consistent as compared to Q1 2014 and the comparable periods in
2013.
Depletion and depreciation
Fluctuations in depletion and depreciation expense are primarily
the result of changes in produced crude oil and natural gas
volumes.
Q2 2014 production as compared to Q1 2014 and
the comparable periods in 2013 increased by 12%, 22% and 21%,
respectively, resulting in higher depletion and depreciation
expense of 5%, 33% and 28%, respectively.
Depletion and depreciation on a per boe basis
for Q2 2014 of $22.45/boe was lower
as compared to Q1 2014 of $23.13/boe
as a result of increased production in Canada. Depletion and depreciation on a
per boe basis increased for the three and six month periods ended
June 30, 2014 to $22.45/boe and $22.78/boe, respectively, as compared to the same
periods in 2013 of $20.16/boe and
$20.99/boe, respectively. The
increase on a per boe basis was largely due to Vermilion's increased capital and acquisition
activity which results in higher per boe amounts as compared to
legacy producing assets.
Deferred tax
Deferred tax expense arises primarily as a result of changes in the
accounting basis and tax basis for capital assets and asset
retirement obligations and changes in available tax losses.
FINANCIAL POSITION REVIEW
Balance sheet strategy
We believe that our balance sheet supports our defined growth
initiatives and our focus is on managing and maintaining a
conservative balance sheet. To ensure that our balance sheet
continues to support our defined growth initiatives, we regularly
review whether forecasted fund flows from operations is sufficient
to finance planned capital expenditures, dividends, and abandonment
and reclamation expenditures. To the extent that forecasted
fund flows from operations is not expected to be sufficient to
fulfill such expenditures, we will evaluate our ability to finance
any excess with debt (including borrowing using the unutilized
capacity of our existing revolving credit facility) or issue
equity.
To ensure that we maintain a conservative
balance sheet, we monitor the ratio of net debt to fund flows from
operations and typically strive to maintain an internally targeted
ratio of approximately 1.0 to 1.3. In a commodity price
environment where prices trend higher, we may target a lower ratio
and conversely, in a lower commodity price environment, the
acceptable ratio may be higher. At times, we will use our
balance sheet to finance acquisitions and, in these situations, we
are prepared to accept a higher ratio in the short term but will
implement a strategy to reduce the ratio to acceptable levels
within a reasonable period of time, usually considered to be no
more than 12 to 24 months. This plan could potentially
include an increase in hedging activities, a reduction in capital
expenditures, an issuance of equity or the utilization of excess
fund flows from operations to reduce outstanding indebtedness.
Absent additional material acquisitions,
Vermilion currently expects the
net debt to fund flows ratio to return to our internally targeted
ratio over the next 12 to 24 months as a result of incremental cash
flows from Corrib and our acquisitions in Germany and Canada.
Long-term debt
Our long-term debt consists of our revolving credit facility and
our senior unsecured notes. The applicable annual interest
rates and the balances recognized on our balance sheet are as
follows:
|
|
|
|
|
|
Annual
Interest Rate |
|
|
As
At |
|
|
|
|
|
|
Jun 30, |
|
Dec 31, |
|
|
Jun 30, |
|
Dec 31, |
($M) |
|
|
|
|
|
2014 |
|
2013 |
|
|
2014 |
|
2013 |
Revolving credit facility |
|
|
|
|
|
3.3% |
|
3.3% |
|
|
975,297 |
|
766,898 |
Senior unsecured notes |
|
|
|
|
|
6.5% |
|
6.5% |
|
|
223,569 |
|
223,126 |
Long-term debt |
|
|
|
|
|
3.9% |
|
4.7% |
|
|
1,198,866 |
|
990,024 |
Revolving Credit Facility
Our revolving credit facility bears interest at
rates applicable to demand loans plus applicable margins. The
following table outlines the terms of our revolving credit
facility:
|
|
|
|
|
|
As At |
|
|
|
|
|
|
Jun 30, |
|
Dec 31, |
|
|
|
|
|
|
2014 |
|
2013 |
Total facility amount 1 |
|
|
|
|
|
$1.50 billion |
|
$1.20 billion |
Amount drawn |
|
|
|
|
|
$975.3 million |
|
$766.9 million |
Letters of credit outstanding |
|
|
|
|
|
$10.2 million |
|
$8.1 million |
Facility maturity date |
|
|
|
|
|
31-May-17 |
|
31-May-16 |
(1) |
|
We may, by adding lenders or seeking an increase to an existing
lender's commitment, increase the total committed facility amount
to no more than $1.75 billion. |
In addition, the revolving credit facility is
subject to the following covenants:
|
|
|
|
|
|
As
At |
|
|
|
|
|
|
|
|
Jun 30, |
|
|
Dec 31, |
Financial covenant |
|
|
|
Limit |
|
|
|
2014 |
|
|
2013 |
Consolidated total debt to consolidated
EBITDA |
|
|
|
4.0 |
|
|
|
1.17 |
|
|
1.06 |
Consolidated total senior debt to consolidated
EBITDA |
|
|
|
3.0 |
|
|
|
0.95 |
|
|
0.82 |
Consolidated total senior debt to total
capitalization |
|
|
|
50% |
|
|
|
30% |
|
|
28% |
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" on our balance sheet.
- Consolidated total senior debt: Defined as consolidated total
debt excluding unsecured and subordinated debt.
- Consolidated EBITDA: Defined as consolidated net earnings
before interest, income taxes, depreciation, accretion and certain
other non-cash items.
- Total capitalization: Includes all amounts on our balance sheet
classified as "Long-term debt" and "Shareholders' Equity".
Vermilion was
in compliance with its financial covenants for all periods
presented.
Senior Unsecured Notes
We have outstanding senior unsecured notes that are senior
unsecured obligations and rank pari passu with all our other
present and future unsecured and unsubordinated indebtedness.
The following table outlines the terms of these notes:
|
|
|
|
|
|
|
Total issued and outstanding amount |
|
|
|
|
|
$225.0 million |
Interest rate |
|
|
|
|
|
6.5% per annum |
Issued date |
|
|
|
|
|
February 10, 2011 |
Maturity date |
|
|
|
|
|
February 10, 2016 |
We may redeem all or part of the notes at fixed
redemption prices plus in each case, accrued and unpaid interest,
if any, to the applicable redemption date. The notes were
initially recognized at fair value net of transaction costs and are
subsequently measured at amortized cost using an effective interest
rate of 7.1%.
Net debt
Net debt is reconciled to its most directly comparable GAAP
measure, long-term debt, as follows:
|
|
|
|
As
At |
|
|
|
|
Jun 30, |
|
Dec 31, |
($M) |
|
|
|
2014 |
|
2013 |
Long-term debt |
|
|
|
1,198,866 |
|
990,024 |
Current liabilities |
|
|
|
377,710 |
|
347,444 |
Current assets |
|
|
|
(407,578) |
|
(587,783) |
Net debt |
|
|
|
1,168,998 |
|
749,685 |
|
|
|
|
|
|
|
Ratio of net debt to annualized fund flows from
operations |
|
|
|
1.4 |
|
1.1 |
Long-term debt as at June
30, 2014 increased to $1.2
billion from $990.0 million as
at December 31, 2013 as a result of
draws on the revolving credit facility during the current year to
fund our acquisitions in Germany
and Saskatchewan coupled with the
assumption of $47.5 million of
long-term debt pursuant to the latter acquisition. This
increase in long-term debt resulted in an increase to net debt from
$749.7 million to $1.2 billion.
As the increase to long-term debt occurred to
fund acquisitions, which contributed to fund flows from operations
for only a portion of 2014, the year-to-date ratio of net debt to
annualized fund flows from operations increased from 1.1 as at
December 31, 2013 to 1.4 as at
June 30, 2014.
Shareholders' capital
Beginning with the January 2014
dividend paid on February 18, 2014,
we increased our monthly dividend by 7.5%. This was our
second consecutive annual increase.
During the six months ended June 30, 2014, we maintained monthly dividends at
$0.215 per share and declared
dividends totalled $134.7
million.
The following table outlines our dividend
payment history:
Date |
|
|
|
|
|
Monthly dividend per unit or share |
January 2003 to December 2007 |
|
|
|
|
|
$0.17 |
January 2008 to December 2012 |
|
|
|
|
|
$0.19 |
January 2013 to December 31, 2013 |
|
|
|
|
|
$0.20 |
Beginning January 2014 |
|
|
|
|
|
$0.215 |
Our policy with respect to dividends is to be
conservative and maintain a low ratio of dividends to fund flows
from operations. During low price commodity cycles, we will
initially maintain dividends and allow the ratio to rise.
Should low commodity price cycles remain for an extended period of
time, we will evaluate the necessity of changing the level of
dividends, taking into consideration capital development
requirements, debt levels and acquisition opportunities.
Over the next two years, we anticipate that
Corrib, Cardium and other exploration and development activities
will require significant capital investment. Although we
currently expect to be able to maintain our current dividend, fund
flows from operations may not be sufficient during this period to
fund cash dividends, capital expenditures and asset retirement
obligations. We will evaluate our ability to finance any
shortfalls with debt, issuances of equity or by reducing some or
all categories of expenditures to ensure that total expenditures do
not exceed available funds.
The following table reconciles the change in
shareholders' capital:
Shareholders' Capital |
|
|
|
Number of Shares
('000s) |
|
|
|
Amount ($M) |
Balance as at December 31, 2013 |
|
|
|
102,123 |
|
|
|
1,618,443 |
Shares issued pursuant to corporate
acquisition |
|
|
|
2,827 |
|
|
|
204,960 |
Issuance of shares pursuant to the dividend
reinvestment plan |
|
|
|
601 |
|
|
|
38,034 |
Vesting of equity based awards |
|
|
|
950 |
|
|
|
47,657 |
Share-settled dividends on vested equity based
awards |
|
|
|
108 |
|
|
|
7,519 |
Shares issued pursuant to the bonus plan |
|
|
|
11 |
|
|
|
721 |
Balance as at June 30, 2014 |
|
|
|
106,620 |
|
|
|
1,917,334 |
As at June 30,
2014, there were approximately 1.7 million VIP awards
outstanding. As at July 30,
2014, there were approximately 106.7 million shares
outstanding.
ASSET RETIREMENT OBLIGATIONS
As at June 30,
2014, asset retirement obligations were $390.1 million compared to $326.2 million as at December 31, 2013.
The increase in asset retirement obligations is
largely attributable to an overall decrease in the discount rates
applied to the abandonment obligations, accretion, and additions
from new wells drilled during the year and abandonment obligations
associated with the assets acquired in Germany and Canada.
OFF BALANCE SHEET ARRANGEMENTS
We have certain lease agreements that are
entered into in the normal course of operations, all of which are
operating leases and accordingly no asset or liability value has
been assigned to the consolidated balance sheet as at June 30, 2014.
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 impact of the adoption of the following
pronouncement is currently being evaluated.
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,
2017.
RISK MANAGEMENT
Vermilion is
exposed to various market and operational risks. For a
detailed discussion of these risks, please see Vermilion's Annual Report for the year ended
December 31, 2013.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in
accordance with IFRS requires management to make estimates,
judgments and assumptions that affect reported assets, liabilities,
revenues and expenses, gains and losses, and disclosures of any
possible contingencies. These estimates and assumptions are
developed based on the best available information which management
believed to be reasonable at the time such estimates and
assumptions were made. As such, these assumptions are
uncertain at the time estimates are made and could change,
resulting in a material impact on Vermilion's consolidated financial
statements. Estimates are reviewed by management on an
ongoing basis and as a result may change from period to period due
to the availability of new information or changes in circumstances.
Additionally, as a result of the unique circumstances of each
jurisdiction that Vermilion
operates in, the critical accounting estimates may affect one or
more jurisdictions.
The following outlines what management believes
to be the most critical accounting policies involving the use of
estimates and assumptions:
i. |
|
Depletion and depreciation charges are based on estimates of
total proven and probable reserves that Vermilion expects to
recover in the future. |
ii. |
|
Asset retirement obligations are based on past experience and
current economic factors which management believes are
reasonable. |
iii. |
|
Impairment tests are performed at the cash generating unit
(CGU) level, which is determined based on management's
judgment. The calculation of the recoverable amount of a CGU
is based on market factors as well as estimates of PNG reserves and
future costs required to develop reserves. |
iv. |
|
Deferred tax amounts recognized in the consolidated financial
statements are based on management's assessment of the tax
positions at the end of each reporting period. |
INTERNAL CONTROL OVER FINANCIAL REPORTING
There was no change in Vermilion's internal control over financial
reporting that occurred during the period covered by this MD&A
that has materially affected, or is reasonably likely to materially
affect, its internal control over financial reporting.
Supplemental Table 1: Netbacks
The following table includes financial statement
information on a per unit basis by business unit. Natural gas
sales volumes have been converted on a basis of six thousand cubic
feet of natural gas to one barrel of oil equivalent.
|
|
Three Months Ended June 30, 2014 |
|
Six Months Ended June 30, 2014 |
|
Three Months
Ended June
30, 2013 |
|
Six Months
Ended June
30, 2013 |
|
|
Oil &
NGLs |
|
Natural
Gas |
|
Total |
|
Oil &
NGLs |
|
Natural
Gas |
|
Total |
|
Total |
|
Total |
|
|
$/bbl |
|
$/mcf |
|
$/boe |
|
$/bbl |
|
$/mcf |
|
$/boe |
|
$/boe |
|
$/boe |
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
98.82 |
|
4.60 |
|
71.56 |
|
97.30 |
|
5.02 |
|
70.55 |
|
62.00 |
|
59.93 |
Royalties |
|
(11.84) |
|
(0.30) |
|
(7.99) |
|
(11.38) |
|
(0.32) |
|
(7.61) |
|
(5.96) |
|
(6.07) |
Transportation |
|
(2.22) |
|
(0.17) |
|
(1.76) |
|
(2.24) |
|
(0.17) |
|
(1.75) |
|
(1.60) |
|
(1.58) |
Operating |
|
(9.29) |
|
(1.55) |
|
(9.28) |
|
(10.01) |
|
(1.37) |
|
(9.31) |
|
(9.81) |
|
(9.68) |
Operating netback |
|
75.47 |
|
2.58 |
|
52.53 |
|
73.67 |
|
3.16 |
|
51.88 |
|
44.63 |
|
42.60 |
General and administration |
|
|
|
|
|
(2.88) |
|
|
|
|
|
(2.32) |
|
(2.42) |
|
(2.28) |
Fund flows from operations
netback |
|
|
|
|
|
49.65 |
|
|
|
|
|
49.56 |
|
42.21 |
|
40.32 |
France |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
117.29 |
|
- |
|
117.29 |
|
117.41 |
|
- |
|
117.41 |
|
98.04 |
|
102.84 |
Royalties |
|
(7.34) |
|
- |
|
(7.34) |
|
(7.34) |
|
- |
|
(7.34) |
|
(5.95) |
|
(5.97) |
Transportation |
|
(5.07) |
|
- |
|
(5.07) |
|
(4.91) |
|
- |
|
(4.91) |
|
(2.36) |
|
(2.39) |
Operating |
|
(15.58) |
|
- |
|
(15.58) |
|
(15.98) |
|
- |
|
(15.98) |
|
(16.53) |
|
(17.08) |
Operating netback |
|
89.30 |
|
- |
|
89.30 |
|
89.18 |
|
- |
|
89.18 |
|
73.20 |
|
77.40 |
General and administration |
|
|
|
|
|
(5.24) |
|
|
|
|
|
(5.21) |
|
(3.83) |
|
(4.45) |
Current income taxes |
|
|
|
|
|
(23.30) |
|
|
|
|
|
(24.25) |
|
(15.74) |
|
(16.11) |
Fund flows from operations
netback |
|
|
|
|
|
60.76 |
|
|
|
|
|
59.72 |
|
53.63 |
|
56.84 |
Netherlands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
93.76 |
|
7.91 |
|
48.14 |
|
99.23 |
|
9.26 |
|
56.06 |
|
65.08 |
|
63.19 |
Royalties |
|
- |
|
(0.19) |
|
(1.12) |
|
- |
|
(0.38) |
|
(2.28) |
|
- |
|
- |
Operating |
|
- |
|
(1.74) |
|
(10.29) |
|
- |
|
(1.65) |
|
(9.76) |
|
(8.93) |
|
(8.02) |
Operating netback |
|
93.76 |
|
5.98 |
|
36.73 |
|
99.23 |
|
7.23 |
|
44.02 |
|
56.15 |
|
55.17 |
General and administration |
|
|
|
|
|
(0.53) |
|
|
|
|
|
(0.73) |
|
(0.72) |
|
(0.73) |
Current income taxes |
|
|
|
|
|
(2.10) |
|
|
|
|
|
(3.99) |
|
(16.34) |
|
(16.55) |
Fund flows from operations
netback |
|
|
|
|
|
34.10 |
|
|
|
|
|
39.30 |
|
39.09 |
|
37.89 |
Germany |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
- |
|
7.56 |
|
45.36 |
|
- |
|
8.25 |
|
49.50 |
|
- |
|
- |
Royalties |
|
- |
|
(1.56) |
|
(9.34) |
|
- |
|
(1.68) |
|
(10.11) |
|
- |
|
- |
Transportation |
|
- |
|
(0.72) |
|
(4.30) |
|
- |
|
(0.61) |
|
(3.65) |
|
- |
|
- |
Operating |
|
- |
|
(1.39) |
|
(8.35) |
|
- |
|
(1.48) |
|
(8.90) |
|
- |
|
- |
Operating netback |
|
- |
|
3.89 |
|
23.37 |
|
- |
|
4.48 |
|
26.84 |
|
- |
|
- |
General and administration |
|
|
|
|
|
(3.39) |
|
|
|
|
|
(3.46) |
|
- |
|
- |
Current income taxes |
|
|
|
|
|
(2.07) |
|
|
|
|
|
(2.58) |
|
- |
|
- |
Fund flows from operations
netback |
|
|
|
|
|
17.91 |
|
|
|
|
|
20.80 |
|
- |
|
- |
Australia |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
126.87 |
|
- |
|
126.87 |
|
127.11 |
|
- |
|
127.11 |
|
111.54 |
|
115.89 |
Operating |
|
(25.99) |
|
- |
|
(25.99) |
|
(25.12) |
|
- |
|
(25.12) |
|
(15.30) |
|
(20.16) |
PRRT (1) |
|
(27.39) |
|
- |
|
(27.39) |
|
(28.14) |
|
- |
|
(28.14) |
|
(19.43) |
|
(19.35) |
Operating netback |
|
73.49 |
|
- |
|
73.49 |
|
73.85 |
|
- |
|
73.85 |
|
76.81 |
|
76.38 |
General and administration |
|
|
|
|
|
(3.58) |
|
|
|
|
|
(2.45) |
|
(2.13) |
|
(2.36) |
Corporate income taxes |
|
|
|
|
|
(12.27) |
|
|
|
|
|
(12.41) |
|
(16.43) |
|
(14.56) |
Fund flows from operations
netback |
|
|
|
|
|
57.64 |
|
|
|
|
|
58.99 |
|
58.25 |
|
59.46 |
Total Company |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales |
|
109.89 |
|
6.19 |
|
82.96 |
|
110.73 |
|
7.04 |
|
85.70 |
|
80.21 |
|
81.60 |
Realized hedging (loss) gain |
|
(0.66) |
|
0.42 |
|
0.52 |
|
(0.21) |
|
0.32 |
|
0.56 |
|
0.46 |
|
(0.13) |
Royalties |
|
(8.31) |
|
(0.44) |
|
(6.21) |
|
(7.54) |
|
(0.51) |
|
(5.91) |
|
(4.06) |
|
(4.15) |
Transportation |
|
(2.89) |
|
(0.34) |
|
(2.57) |
|
(2.74) |
|
(0.32) |
|
(2.44) |
|
(1.71) |
|
(1.75) |
Operating |
|
(14.16) |
|
(1.59) |
|
(12.46) |
|
(15.26) |
|
(1.49) |
|
(12.95) |
|
(12.36) |
|
(13.21) |
PRRT (1) |
|
(4.32) |
|
- |
|
(2.72) |
|
(5.79) |
|
- |
|
(3.67) |
|
(3.24) |
|
(3.12) |
Operating netback |
|
79.55 |
|
4.24 |
|
59.52 |
|
79.19 |
|
5.04 |
|
61.29 |
|
59.30 |
|
59.24 |
General and administration |
|
|
|
|
|
(3.80) |
|
|
|
|
|
(3.59) |
|
(2.91) |
|
(3.14) |
Interest expense |
|
|
|
|
|
(2.64) |
|
|
|
|
|
(2.65) |
|
(2.40) |
|
(2.37) |
Realized foreign exchange gain
(loss) |
|
|
|
|
|
0.12 |
|
|
|
|
|
(0.16) |
|
0.33 |
|
0.09 |
Other income |
|
|
|
|
|
0.02 |
|
|
|
|
|
0.03 |
|
0.02 |
|
0.07 |
Corporate income taxes
(1) |
|
|
|
|
|
(6.98) |
|
|
|
|
|
(7.94) |
|
(9.44) |
|
(9.49) |
Fund flows from operations
netback |
|
|
|
|
|
46.24 |
|
|
|
|
|
46.98 |
|
44.90 |
|
44.40 |
(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 table summarizes Vermilion's outstanding risk management
positions as at June 30, 2014:
|
|
Note |
|
Volume |
|
Strike Price(s) |
Crude Oil |
|
|
|
|
|
|
WTI - Swap |
|
|
|
|
|
|
May 2014 - July 2014 |
|
1 |
|
500 bbl/d |
|
101.12 CAD $ |
July 2014 - December 2014 |
|
|
|
750 bbl/d |
|
99.00 USD $ |
July 2014 |
|
|
|
1,000 bbl/d |
|
99.95 USD $ |
July 2014 |
|
2 |
|
1,000 bbl/d |
|
103.63 USD $ |
July 2014 - September 2014 |
|
|
|
1,250 bbl/d |
|
108.53 CAD $ |
July 2014 - September 2014 |
|
3 |
|
1,250 bbl/d |
|
101.33 USD $ |
May 2014 - November 2014 |
|
1 |
|
250 bbl/d |
|
97.25 CAD $ |
Dated Brent - Collar |
|
|
|
|
|
|
April 2014 - September 2014 |
|
|
|
1,000 bbl/d |
|
105.00 - 112.00 USD $ |
April 2014 - December 2014 |
|
|
|
1,000 bbl/d |
|
106.00 - 110.73 USD $ |
Dated Brent - Swap |
|
|
|
|
|
|
January 2014 - December 2014 |
|
|
|
500 bbl/d |
|
108.28 USD $ |
July 2014 - September 2014 |
|
|
|
350 bbl/d |
|
111.75 USD $ |
July 2014 - September 2014 |
|
3 |
|
1,000 bbl/d |
|
110.00 USD $ |
July 2014 - December 2014 |
|
|
|
1,000 bbl/d |
|
109.64 USD $ |
July 2014 - December 2014 |
|
4 |
|
500 bbl/d |
|
109.40 USD $ |
ICE Brent less WTI - Fixed Spread |
|
|
|
|
|
|
July 2014 - September 2014 |
|
|
|
500 bbl/d |
|
5.99 USD $ |
MSW - Fixed Price Differential
(Physical) |
|
|
|
|
|
|
April 2014 - December 2014 |
|
|
|
1,030 bbl/d |
|
WTI less 8.20 USD $ |
July 2014 - December 2014 |
|
|
|
2,052 bbl/d |
|
WTI less 8.68 USD $ |
|
|
|
|
|
|
|
Canadian Natural Gas |
|
|
|
|
|
|
AECO - Collar |
|
|
|
|
|
|
January 2014 - December 2014 |
|
|
|
10,000 GJ/d |
|
3.18 - 3.81 CAD $ |
April 2014 - December 2014 |
|
|
|
1,000 GJ/d |
|
3.60 - 3.96 CAD $ |
April 2014 - March 2015 |
|
|
|
2,500 GJ/d |
|
3.60 - 4.08 CAD $ |
November 2014 - March 2015 |
|
|
|
2,500 GJ/d |
|
3.60 - 4.27 CAD $ |
AECO - Swap |
|
|
|
|
|
|
January 2014 - December 2014 |
|
|
|
5,000 GJ/d |
|
3.71 CAD $ |
April 2014 - October 2014 |
|
|
|
8,000 GJ/d |
|
4.00 CAD $ |
|
|
|
|
|
|
|
European Natural Gas |
|
|
|
|
|
|
TTF - Swap |
|
|
|
|
|
|
March 2014 - September 2014 |
|
|
|
5,400 GJ/d |
|
6.62 EUR € |
April 2014 - September 2014 |
|
|
|
16,200 GJ/d |
|
6.74 EUR € |
|
|
|
|
|
|
|
Electricity |
|
|
|
|
|
|
AESO - Swap |
|
|
|
|
|
|
January 2014 - December 2014 |
|
|
|
7.2 MWh/d |
|
54.75 CAD $ |
AESO - Swap (Physical) |
|
|
|
|
|
|
January 2013 - December 2015 |
|
|
|
72.0 MWh/d |
|
53.17 CAD $ |
|
|
|
|
|
|
|
US Dollar |
|
|
|
|
|
|
USD - Collar |
|
|
|
|
|
|
July 2014 - September 2014 |
|
|
|
5,000,000 USD $/month |
|
1.070 - 1.116 CAD $ |
July 2014 - September 2014 |
|
5 |
|
4,500,000 USD $/month |
|
1.077 - 1.099 CAD $ |
(1) |
Assumed as part of Vermilion's April
29, 2014 acquisition of Elkhorn Resources Inc. |
(2) |
Prior to the expiration of this swap,
the counterparty has the option to extend the swap to August 31,
2014 at the contracted volume and price. |
(3) |
Prior to the expiration of this swap,
the counterparty has the option to extend the swap to December 31,
2014 at the contracted volume and price. |
(4) |
Prior to the expiration of this swap,
the counterparty has the option to extend the swap to June 30, 2015
at the contracted volume and price. |
(5) |
Vermilion has upside participation on
this hedge up to the limit price of 1.152 CAD; above which,
settlement will occur at the conditional call level of
1.099CAD. |
Supplemental Table 3: Capital
Expenditures
|
|
Three Months Ended |
|
Six Months Ended |
By classification |
|
Jun 30, |
Mar 31, |
Jun 30, |
|
Jun 30, |
Jun 30, |
($M) |
|
2014 |
2014 |
2013 |
|
2014 |
2013 |
Drilling and development |
|
117,975 |
168,840 |
75,005 |
|
286,815 |
254,525 |
Dispositions |
|
- |
- |
- |
|
- |
(8,627) |
Exploration and evaluation |
|
17,098 |
27,535 |
3,113 |
|
44,633 |
12,689 |
Capital expenditures |
|
135,073 |
196,375 |
78,118 |
|
331,448 |
258,587 |
Property acquisition |
|
- |
178,227 |
- |
|
178,227 |
- |
Corporate acquisition |
|
381,139 |
- |
- |
|
381,139 |
- |
Acquisitions |
|
381,139 |
178,227 |
- |
|
559,366 |
- |
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
By category |
|
Jun 30, |
Mar 31, |
Jun 30, |
|
Jun 30, |
Jun 30, |
($M) |
|
2014 |
2014 |
2013 |
|
2014 |
2013 |
Land |
|
950 |
4,753 |
2,307 |
|
5,703 |
5,436 |
Seismic |
|
1,869 |
3,432 |
5,569 |
|
5,301 |
9,382 |
Drilling and completion |
|
42,083 |
106,536 |
20,235 |
|
148,619 |
146,420 |
Production equipment and facilities |
|
60,547 |
68,755 |
40,819 |
|
129,302 |
90,761 |
Recompletions |
|
13,459 |
4,226 |
4,510 |
|
17,685 |
8,641 |
Other |
|
16,165 |
8,673 |
4,678 |
|
24,838 |
6,574 |
Dispositions |
|
- |
- |
- |
|
- |
(8,627) |
Capital expenditures |
|
135,073 |
196,375 |
78,118 |
|
331,448 |
258,587 |
Acquisitions |
|
381,139 |
178,227 |
- |
|
559,366 |
- |
Total capital expenditures and
acquisitions |
|
516,212 |
374,602 |
78,118 |
|
890,814 |
258,587 |
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
By country |
|
Jun 30, |
Mar 31, |
Jun 30, |
|
Jun 30, |
Jun 30, |
($M) |
|
2014 |
2014 |
2013 |
|
2014 |
2013 |
Canada |
|
418,294 |
119,707 |
16,553 |
|
538,001 |
101,682 |
France |
|
37,614 |
37,967 |
23,223 |
|
75,581 |
44,815 |
Netherlands |
|
21,513 |
20,118 |
4,157 |
|
41,631 |
4,529 |
Germany |
|
630 |
173,067 |
- |
|
173,697 |
- |
Ireland |
|
27,221 |
16,236 |
24,878 |
|
43,457 |
41,398 |
Australia |
|
10,991 |
5,691 |
8,282 |
|
16,682 |
63,631 |
Corporate |
|
(51) |
1,816 |
1,025 |
|
1,765 |
2,532 |
Total capital expenditures and
acquisitions |
|
516,212 |
374,602 |
78,118 |
|
890,814 |
258,587 |
Supplemental Table 4: Production
|
|
Q2/14 |
|
Q1/14 |
|
Q4/13 |
|
Q3/13 |
|
Q2/13 |
|
Q1/13 |
|
Q4/12 |
|
Q3/12 |
|
Q2/12 |
|
Q1/12 |
|
Q4/11 |
|
Q3/11 |
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
12,676 |
|
9,437 |
|
8,719 |
|
7,969 |
|
8,885 |
|
7,966 |
|
7,983 |
|
7,322 |
|
7,757 |
|
7,574 |
|
6,591 |
|
4,526 |
|
NGLs (bbls/d) |
|
2,796 |
|
2,071 |
|
1,699 |
|
1,897 |
|
1,725 |
|
1,335 |
|
1,106 |
|
1,204 |
|
1,321 |
|
1,302 |
|
1,246 |
|
1,305 |
|
Natural gas (mmcf/d) |
|
57.59 |
|
49.53 |
|
41.43 |
|
43.40 |
|
43.69 |
|
41.04 |
|
31.41 |
|
35.54 |
|
41.32 |
|
41.83 |
|
43.96 |
|
42.94 |
|
Total (boe/d) |
|
25,070 |
|
19,763 |
|
17,322 |
|
17,099 |
|
17,892 |
|
16,140 |
|
14,323 |
|
14,449 |
|
15,965 |
|
15,848 |
|
15,163 |
|
12,987 |
|
% of consolidated |
|
49% |
|
42% |
|
43% |
|
41% |
|
42% |
|
41% |
|
40% |
|
40% |
|
40% |
|
40% |
|
41% |
|
38% |
France |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
11,025 |
|
10,771 |
|
11,131 |
|
11,625 |
|
10,390 |
|
10,330 |
|
9,843 |
|
9,767 |
|
9,931 |
|
10,270 |
|
7,819 |
|
7,946 |
|
Natural gas (mmcf/d) |
|
- |
|
- |
|
- |
|
5.23 |
|
4.19 |
|
4.21 |
|
3.91 |
|
3.39 |
|
3.57 |
|
3.48 |
|
0.94 |
|
0.97 |
|
Total (boe/d) |
|
11,025 |
|
10,771 |
|
11,131 |
|
12,496 |
|
11,088 |
|
11,032 |
|
10,495 |
|
10,333 |
|
10,526 |
|
10,850 |
|
7,976 |
|
8,108 |
|
% of consolidated |
|
21% |
|
23% |
|
27% |
|
30% |
|
26% |
|
29% |
|
29% |
|
28% |
|
27% |
|
28% |
|
22% |
|
23% |
Netherlands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d) |
|
96 |
|
69 |
|
62 |
|
48 |
|
50 |
|
96 |
|
70 |
|
41 |
|
84 |
|
72 |
|
66 |
|
64 |
|
Natural gas (mmcf/d) |
|
40.35 |
|
43.15 |
|
37.53 |
|
28.78 |
|
38.52 |
|
36.91 |
|
33.03 |
|
34.59 |
|
33.74 |
|
35.08 |
|
34.58 |
|
33.15 |
|
Total (boe/d) |
|
6,822 |
|
7,260 |
|
6,318 |
|
4,845 |
|
6,470 |
|
6,248 |
|
5,574 |
|
5,806 |
|
5,707 |
|
5,919 |
|
5,829 |
|
5,589 |
|
% of consolidated |
|
13% |
|
16% |
|
15% |
|
12% |
|
15% |
|
16% |
|
15% |
|
16% |
|
15% |
|
15% |
|
16% |
|
16% |
Germany |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d) |
|
16.13 |
|
10.64 |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
Total (boe/d) |
|
2,689 |
|
1,773 |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
% of consolidated |
|
5% |
|
4% |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
Australia |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
6,483 |
|
7,110 |
|
6,189 |
|
7,070 |
|
7,363 |
|
5,287 |
|
5,873 |
|
5,958 |
|
6,970 |
|
6,648 |
|
7,686 |
|
7,992 |
|
% of consolidated |
|
12% |
|
15% |
|
15% |
|
17% |
|
17% |
|
14% |
|
16% |
|
16% |
|
18% |
|
17% |
|
21% |
|
23% |
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil & NGLs (bbls/d) |
|
33,076 |
|
29,458 |
|
27,800 |
|
28,609 |
|
28,413 |
|
25,014 |
|
24,875 |
|
24,292 |
|
26,063 |
|
25,866 |
|
23,408 |
|
21,833 |
|
% of consolidated |
|
63% |
|
63% |
|
68% |
|
69% |
|
66% |
|
65% |
|
69% |
|
66% |
|
67% |
|
66% |
|
64% |
|
63% |
|
Natural gas (mmcf/d) |
|
114.08 |
|
103.32 |
|
78.96 |
|
77.41 |
|
86.40 |
|
82.16 |
|
68.34 |
|
73.52 |
|
78.63 |
|
80.39 |
|
79.48 |
|
77.06 |
|
% of consolidated |
|
37% |
|
37% |
|
32% |
|
31% |
|
34% |
|
35% |
|
31% |
|
34% |
|
33% |
|
34% |
|
36% |
|
37% |
|
Total (boe/d) |
|
52,089 |
|
46,677 |
|
40,960 |
|
41,510 |
|
42,813 |
|
38,707 |
|
36,265 |
|
36,546 |
|
39,168 |
|
39,265 |
|
36,654 |
|
34,676 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
YTD 2014 |
|
2013 |
|
2012 |
|
2011 |
|
2010 |
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
11,065 |
|
8,387 |
|
7,659 |
|
4,701 |
|
2,778 |
|
2,137 |
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d) |
|
2,435 |
|
1,666 |
|
1,232 |
|
1,297 |
|
1,427 |
|
1,518 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d) |
|
53.58 |
|
42.39 |
|
37.50 |
|
43.38 |
|
43.91 |
|
47.85 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (boe/d) |
|
22,430 |
|
17,117 |
|
15,142 |
|
13,227 |
|
11,524 |
|
11,629 |
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated |
|
45% |
|
41% |
|
40% |
|
38% |
|
36% |
|
37% |
|
|
|
|
|
|
|
|
|
|
|
|
France |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
10,899 |
|
10,873 |
|
9,952 |
|
8,110 |
|
8,347 |
|
8,246 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d) |
|
- |
|
3.40 |
|
3.59 |
|
0.95 |
|
0.92 |
|
1.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (boe/d) |
|
10,899 |
|
11,440 |
|
10,550 |
|
8,269 |
|
8,501 |
|
8,421 |
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated |
|
22% |
|
28% |
|
28% |
|
23% |
|
26% |
|
27% |
|
|
|
|
|
|
|
|
|
|
|
|
Netherlands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d) |
|
83 |
|
64 |
|
67 |
|
58 |
|
35 |
|
23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d) |
|
41.74 |
|
35.42 |
|
34.11 |
|
32.88 |
|
28.31 |
|
21.06 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (boe/d) |
|
7,040 |
|
5,967 |
|
5,751 |
|
5,538 |
|
4,753 |
|
3,533 |
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated |
|
14% |
|
15% |
|
15% |
|
16% |
|
15% |
|
11% |
|
|
|
|
|
|
|
|
|
|
|
|
Germany |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d) |
|
13.40 |
|
- |
|
- |
|
- |
|
- |
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (boe/d) |
|
2,234 |
|
- |
|
- |
|
- |
|
- |
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated |
|
5% |
|
- |
|
- |
|
- |
|
- |
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
Australia |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d) |
|
6,795 |
|
6,481 |
|
6,360 |
|
8,168 |
|
7,354 |
|
7,812 |
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated |
|
14% |
|
16% |
|
17% |
|
23% |
|
23% |
|
25% |
|
|
|
|
|
|
|
|
|
|
|
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil & NGLs (bbls/d) |
|
31,277 |
|
27,471 |
|
25,270 |
|
22,334 |
|
19,941 |
|
19,735 |
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated |
|
63% |
|
67% |
|
67% |
|
63% |
|
62% |
|
63% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (mmcf/d) |
|
108.73 |
|
81.21 |
|
75.20 |
|
77.21 |
|
73.14 |
|
69.96 |
|
|
|
|
|
|
|
|
|
|
|
|
|
% of consolidated |
|
37% |
|
33% |
|
33% |
|
37% |
|
38% |
|
37% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (boe/d) |
|
49,398 |
|
41,005 |
|
37,803 |
|
35,202 |
|
32,132 |
|
31,395 |
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Table 5: Segmented Financial
Results
|
|
Three
Months Ended June 30, 2014 |
($M) |
|
Canada |
|
France |
|
Netherlands |
|
Germany |
|
Ireland |
|
Australia |
|
Corporate |
|
Total |
Drilling and development |
|
26,071 |
|
34,828 |
|
18,234 |
|
630 |
|
27,221 |
|
10,991 |
|
- |
|
117,975 |
Exploration and evaluation |
|
10,897 |
|
2,786 |
|
3,279 |
|
- |
|
- |
|
- |
|
136 |
|
17,098 |
Oil and gas sales to external
customers |
|
163,261 |
|
124,617 |
|
29,881 |
|
11,097 |
|
- |
|
58,828 |
|
- |
|
387,684 |
Royalties |
|
(18,240) |
|
(7,796) |
|
(693) |
|
(2,284) |
|
- |
|
- |
|
- |
|
(29,013) |
Revenue from external
customers |
|
145,021 |
|
116,821 |
|
29,188 |
|
8,813 |
|
- |
|
58,828 |
|
- |
|
358,671 |
Transportation expense |
|
(4,024) |
|
(5,385) |
|
- |
|
(1,052) |
|
(1,571) |
|
- |
|
- |
|
(12,032) |
Operating expense |
|
(21,179) |
|
(16,550) |
|
(6,390) |
|
(2,043) |
|
- |
|
(12,051) |
|
- |
|
(58,213) |
General and administration |
|
(6,560) |
|
(5,559) |
|
(326) |
|
(830) |
|
(252) |
|
(1,661) |
|
(2,574) |
|
(17,762) |
PRRT |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(12,699) |
|
- |
|
(12,699) |
Corporate income taxes |
|
- |
|
(24,761) |
|
(1,301) |
|
(506) |
|
- |
|
(5,689) |
|
(378) |
|
(32,635) |
Interest expense |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(12,334) |
|
(12,334) |
Realized gain on derivative
instruments |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
2,419 |
|
2,419 |
Realized foreign exchange
gain |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
587 |
|
587 |
Realized other income |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
74 |
|
74 |
Fund flows from operations |
|
113,258 |
|
64,566 |
|
21,171 |
|
4,382 |
|
(1,823) |
|
26,728 |
|
(12,206) |
|
216,076 |
|
|
Six
Months Ended June 30, 2014 |
($M) |
|
Canada |
|
France |
|
Netherlands |
|
Germany |
|
Ireland |
|
Australia |
|
Corporate |
|
Total |
Total assets |
|
1,854,501 |
|
916,712 |
|
235,723 |
|
174,735 |
|
799,394 |
|
277,624 |
|
125,726 |
|
4,384,415 |
Drilling and development |
|
127,744 |
|
64,681 |
|
33,425 |
|
826 |
|
43,457 |
|
16,682 |
|
- |
|
286,815 |
Exploration and evaluation |
|
24,163 |
|
10,900 |
|
8,206 |
|
- |
|
- |
|
- |
|
1,364 |
|
44,633 |
Oil and gas sales to external
customers |
|
286,441 |
|
242,177 |
|
71,435 |
|
20,012 |
|
- |
|
148,802 |
|
- |
|
768,867 |
Royalties |
|
(30,903) |
|
(15,147) |
|
(2,901) |
|
(4,086) |
|
- |
|
- |
|
- |
|
(53,037) |
Revenue from external
customers |
|
255,538 |
|
227,030 |
|
68,534 |
|
15,926 |
|
- |
|
148,802 |
|
- |
|
715,830 |
Transportation expense |
|
(7,122) |
|
(10,138) |
|
- |
|
(1,474) |
|
(3,159) |
|
- |
|
- |
|
(21,893) |
Operating expense |
|
(37,789) |
|
(32,970) |
|
(12,432) |
|
(3,597) |
|
- |
|
(29,411) |
|
- |
|
(116,199) |
General and administration |
|
(9,428) |
|
(10,753) |
|
(924) |
|
(1,398) |
|
(534) |
|
(2,867) |
|
(6,325) |
|
(32,229) |
PRRT |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(32,938) |
|
- |
|
(32,938) |
Corporate income taxes |
|
- |
|
(50,025) |
|
(5,089) |
|
(1,043) |
|
- |
|
(14,530) |
|
(551) |
|
(71,238) |
Interest expense |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(23,794) |
|
(23,794) |
Realized gain on derivative
instruments |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
5,059 |
|
5,059 |
Realized foreign exchange
loss |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(1,454) |
|
(1,454) |
Realized other income |
|
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
295 |
|
295 |
Fund flows from operations |
|
201,199 |
|
123,144 |
|
50,089 |
|
8,414 |
|
(3,693) |
|
69,056 |
|
(26,770) |
|
421,439 |
ADDITIONAL AND NON-GAAP FINANCIAL MEASURES
This MD&A includes references to certain
financial measures which do not have standardized meanings
prescribed by IFRS. As such, these financial measures are
considered additional GAAP or non-GAAP financial measures and
therefore may not be comparable with similar measures presented by
other issuers.
Fund flows from operations: We
define fund flows from operations as cash flows from operating
activities before changes in non-cash operating working capital and
asset retirement obligations settled. Management believes
that by excluding the temporary impact of changes in non-cash
operating working capital, fund flows from operations provides a
measure of our ability to generate cash (that is not subject to
short-term movements in non-cash operating working capital)
necessary to pay dividends, repay debt, fund asset retirement
obligations and make capital investments. As we have presented fund
flows from operations in the "Segmented Information" note of our
unaudited condensed consolidated interim financial statements for
the three and six months ended June 30,
2014, we consider fund flows from operations to be an
additional GAAP financial measure.
Free cash flow: Represents fund flows
from operations in excess of capital expenditures. We
consider free cash flow to be a key measure as it is used to
determine the funding available for investing and financing
activities, including payment of dividends, repayment of long-term
debt, reallocation to existing business units, and deployment into
new ventures.
Net dividends: We define net
dividends as dividends declared less proceeds received for the
issuance of shares pursuant to the dividend reinvestment
plan. Management monitors net dividends and net dividends as
a percentage of fund flows from operations to assess our ability to
pay dividends.
Payout: We define payout as net
dividends plus drilling and development, exploration and
evaluation, dispositions and asset retirement obligations
settled. Management uses payout to assess the amount of cash
distributed back to shareholders and re-invested in the business
for maintaining production and organic growth.
Fund flows from operations (excluding Corrib)
and Payout (excluding Corrib): Management excludes
expenditures relating to the Corrib project in assessing fund flows
from operations (an additional GAAP financial measure) and payout
in order to assess our ability to generate cash and finance organic
growth from our current producing assets.
Net debt: We define net debt as the
sum of long-term debt and working capital. Management uses
net debt, and the ratio of net debt to fund flows from
operations, to analyze our financial position and
leverage. Please refer to the preceding "Net Debt" section
for a reconciliation of the net debt non-GAAP financial
measure.
Diluted shares outstanding: Is the sum of
shares outstanding at the period end plus outstanding awards under
the VIP, based on current estimates of future performance factors
and forfeiture rates.
Cash dividends per share: Represents cash dividends
declared per share.
Netbacks: Per boe and per mcf measures used in the
analysis of operational activities.
Total returns: Includes cash dividends per share and the
change in Vermilion's share price
on the Toronto Stock Exchange.
The following tables reconcile fund flows from operations, net
dividends, payout, and diluted shares outstanding to their most
directly comparable GAAP measures as presented in our financial
statements:
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
|
Jun 30, |
|
Mar 31, |
|
Jun 30, |
|
|
Jun 30, |
|
Jun 30, |
($M) |
|
|
|
2014 |
|
2014 |
|
2013 |
|
|
2014 |
|
2013 |
Cash flows from operating activities |
|
|
|
149,592 |
|
178,238 |
|
179,074 |
|
|
327,830 |
|
369,786 |
Changes in non-cash operating working capital |
|
|
|
64,103 |
|
24,474 |
|
(6,852) |
|
|
88,577 |
|
(35,323) |
Asset retirement obligations settled |
|
|
|
2,381 |
|
2,651 |
|
2,370 |
|
|
5,032 |
|
3,758 |
Fund flows from operations |
|
|
|
216,076 |
|
205,363 |
|
174,592 |
|
|
421,439 |
|
338,221 |
Expenses related to Corrib |
|
|
|
1,823 |
|
1,870 |
|
2,036 |
|
|
3,693 |
|
3,891 |
Fund flows from operations (excluding Corrib) |
|
|
|
217,899 |
|
207,233 |
|
176,628 |
|
|
425,132 |
|
342,112 |
|
|
Three Months Ended |
|
Six Months Ended |
|
|
Jun 30, |
Mar 31, |
Jun 30, |
|
Jun 30, |
Jun 30, |
($M) |
2014 |
2014 |
2013 |
|
2014 |
2013 |
Dividends declared |
68,710 |
66,007 |
60,776 |
|
134,717 |
120,388 |
Issuance of shares pursuant to the
dividend reinvestment plan |
(19,149) |
(18,885) |
(18,630) |
|
(38,034) |
(34,162) |
Net dividends |
49,561 |
47,122 |
42,146 |
|
96,683 |
86,226 |
Drilling and development |
117,975 |
168,840 |
75,005 |
|
286,815 |
254,525 |
Dispositions |
- |
- |
- |
|
- |
(8,627) |
Exploration and evaluation |
17,098 |
27,535 |
3,113 |
|
44,633 |
12,689 |
Asset retirement obligations
settled |
2,381 |
2,651 |
2,370 |
|
5,032 |
3,758 |
Payout |
187,015 |
246,148 |
122,634 |
|
433,163 |
348,571 |
Corrib drilling and
development |
(27,221) |
(16,236) |
(24,878) |
|
(43,457) |
(41,398) |
Payout (excluding Corrib) |
159,794 |
229,912 |
97,756 |
|
389,706 |
307,173 |
|
As At |
('000s of shares) |
Jun 30,
2014 |
Mar 31,
2014 |
Jun 30,
2013 |
Shares outstanding |
106,620 |
102,453 |
101,418 |
Potential shares issuable pursuant to the
VIP |
2,751 |
2,714 |
2,317 |
Diluted shares outstanding |
109,371 |
105,167 |
103,735 |
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)
|
|
June 30, |
December 31, |
|
Note |
|
2014 |
|
2013 |
ASSETS |
|
|
|
|
|
Current |
|
|
|
|
|
Cash and cash equivalents |
|
|
165,497 |
|
389,559 |
Accounts receivable |
|
|
199,251 |
|
167,618 |
Crude oil inventory |
|
|
17,952 |
|
17,143 |
Derivative instruments |
|
|
7,624 |
|
2,285 |
Prepaid expenses |
|
|
17,254 |
|
11,178 |
|
|
|
407,578 |
|
587,783 |
|
|
|
|
|
|
Deferred taxes |
|
|
148,173 |
|
184,832 |
Exploration and evaluation assets |
5 |
|
332,122 |
|
136,259 |
Capital assets |
4 |
|
3,496,542 |
|
2,799,845 |
|
|
|
4,384,415 |
|
3,708,719 |
|
|
|
|
|
|
LIABILITIES |
|
|
|
|
|
Current |
|
|
|
|
|
Accounts payable and accrued liabilities |
|
|
264,249 |
|
267,832 |
Dividends payable |
8 |
|
22,923 |
|
20,425 |
Derivative instruments |
|
|
7,787 |
|
3,572 |
Income taxes payable |
|
|
82,751 |
|
55,615 |
|
|
|
377,710 |
|
347,444 |
|
|
|
|
|
|
Long-term debt |
7 |
|
1,198,866 |
|
990,024 |
Asset retirement obligations |
6 |
|
390,054 |
|
326,162 |
Deferred taxes |
|
|
401,317 |
|
328,714 |
|
|
|
2,367,947 |
|
1,992,344 |
|
|
|
|
|
|
SHAREHOLDERS' EQUITY |
|
|
|
|
|
Shareholders' capital |
8 |
|
1,917,334 |
|
1,618,443 |
Contributed surplus |
|
|
59,343 |
|
75,427 |
Accumulated other comprehensive income |
|
|
49,883 |
|
47,142 |
Deficit |
|
|
(10,092) |
|
(24,637) |
|
|
|
2,016,468 |
|
1,716,375 |
|
|
|
4,384,415 |
|
3,708,719 |
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF NET EARNINGS AND COMPREHENSIVE
INCOME
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE
AMOUNTS, UNAUDITED)
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
|
Jun 30, |
|
Jun 30, |
|
Jun 30, |
|
Jun 30, |
|
Note |
|
2014 |
|
2013 |
|
2014 |
|
2013 |
REVENUE |
|
|
|
|
|
|
|
|
|
Petroleum and natural gas sales |
|
|
387,684 |
|
311,966 |
|
768,867 |
|
621,542 |
Royalties |
|
|
(29,013) |
|
(15,800) |
|
(53,037) |
|
(31,590) |
Petroleum and natural gas revenue |
|
|
358,671 |
|
296,166 |
|
715,830 |
|
589,952 |
|
|
|
|
|
|
|
|
|
|
EXPENSES |
|
|
|
|
|
|
|
|
|
Operating |
|
|
58,213 |
|
48,082 |
|
116,199 |
|
100,657 |
Transportation |
|
|
12,032 |
|
6,653 |
|
21,893 |
|
13,294 |
Equity based compensation |
9 |
|
18,217 |
|
10,724 |
|
34,689 |
|
26,860 |
Gain on derivative instruments |
|
|
(898) |
|
(10,421) |
|
(7,473) |
|
(6,521) |
Interest expense |
|
|
12,334 |
|
9,336 |
|
23,794 |
|
18,025 |
General and administration |
|
|
17,762 |
|
11,313 |
|
32,229 |
|
23,923 |
Foreign exchange loss (gain) |
|
|
23,159 |
|
(29,297) |
|
3,200 |
|
(26,161) |
Other (income) expense |
|
|
(178) |
|
271 |
|
(145) |
|
204 |
Accretion |
6 |
|
5,950 |
|
6,000 |
|
11,662 |
|
11,824 |
Depletion and depreciation |
4, 5 |
|
104,902 |
|
78,418 |
|
204,354 |
|
159,866 |
|
|
|
251,493 |
|
131,079 |
|
440,402 |
|
321,971 |
EARNINGS BEFORE INCOME TAXES |
|
|
107,178 |
|
165,087 |
|
275,428 |
|
267,981 |
|
|
|
|
|
|
|
|
|
|
INCOME TAXES |
|
|
|
|
|
|
|
|
|
Deferred |
|
|
7,851 |
|
9,580 |
|
14,471 |
|
13,627 |
Current |
|
|
45,334 |
|
49,309 |
|
104,176 |
|
96,019 |
|
|
|
53,185 |
|
58,889 |
|
118,647 |
|
109,646 |
|
|
|
|
|
|
|
|
|
|
NET EARNINGS |
|
|
53,993 |
|
106,198 |
|
156,781 |
|
158,335 |
|
|
|
|
|
|
|
|
|
|
OTHER COMPREHENSIVE (LOSS) INCOME |
|
|
|
|
|
|
|
|
|
Currency translation adjustments |
|
|
(42,794) |
|
18,955 |
|
2,741 |
|
17,623 |
COMPREHENSIVE INCOME |
|
|
11,199 |
|
125,153 |
|
159,522 |
|
175,958 |
|
|
|
|
|
|
|
|
|
|
NET EARNINGS PER SHARE |
|
|
|
|
|
|
|
|
|
Basic |
|
|
0.51 |
|
1.05 |
|
1.51 |
|
1.58 |
Diluted |
|
|
0.50 |
|
1.04 |
|
1.49 |
|
1.56 |
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING
('000s) |
|
|
|
|
|
|
|
|
|
Basic |
|
|
105,577 |
|
100,964 |
|
103,936 |
|
100,137 |
Diluted |
|
|
107,330 |
|
102,223 |
|
105,531 |
|
101,578 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
|
Jun 30, |
|
Jun 30, |
|
Jun 30, |
|
Jun 30, |
|
Note |
|
2014 |
|
2013 |
|
2014 |
|
2013 |
OPERATING |
|
|
|
|
|
|
|
|
|
Net earnings |
|
|
53,993 |
|
106,198 |
|
156,781 |
|
158,335 |
Adjustments: |
|
|
|
|
|
|
|
|
|
|
Accretion |
6 |
|
5,950 |
|
6,000 |
|
11,662 |
|
11,824 |
|
Depletion and depreciation |
4, 5 |
|
104,902 |
|
78,418 |
|
204,354 |
|
159,866 |
|
Unrealized loss (gain) on derivative
instruments |
|
|
1,521 |
|
(8,651) |
|
(2,414) |
|
(7,538) |
|
Equity based compensation |
9 |
|
18,217 |
|
10,724 |
|
34,689 |
|
26,860 |
|
Unrealized foreign exchange loss (gain) |
|
|
23,746 |
|
(28,025) |
|
1,746 |
|
(25,506) |
|
Unrealized other (income) expense |
|
|
(104) |
|
348 |
|
150 |
|
753 |
|
Deferred taxes |
|
|
7,851 |
|
9,580 |
|
14,471 |
|
13,627 |
Asset retirement obligations
settled |
6 |
|
(2,381) |
|
(2,370) |
|
(5,032) |
|
(3,758) |
Changes in non-cash operating
working capital |
|
|
(64,103) |
|
6,852 |
|
(88,577) |
|
35,323 |
Cash flows from operating
activities |
|
|
149,592 |
|
179,074 |
|
327,830 |
|
369,786 |
INVESTING |
|
|
|
|
|
|
|
|
|
Drilling and development |
4 |
|
(117,975) |
|
(75,005) |
|
(286,815) |
|
(254,525) |
Exploration and evaluation |
5 |
|
(17,098) |
|
(3,113) |
|
(44,633) |
|
(12,689) |
Property acquisitions |
3, 4, 5 |
|
- |
|
- |
|
(178,227) |
|
- |
Dispositions |
4 |
|
- |
|
- |
|
- |
|
8,627 |
Corporate acquisitions, net of cash
acquired |
3 |
|
(176,179) |
|
- |
|
(176,179) |
|
- |
Changes in non-cash investing
working capital |
|
|
(24,010) |
|
(75,613) |
|
15,463 |
|
(37,403) |
Cash flows used in investing
activities |
|
|
(335,262) |
|
(153,731) |
|
(670,391) |
|
(295,990) |
|
|
|
|
|
|
|
|
|
|
FINANCING |
|
|
|
|
|
|
|
|
|
Increase in long-term debt |
|
|
255,727 |
|
70,000 |
|
205,727 |
|
139,429 |
Cash dividends |
|
|
(48,665) |
|
(41,754) |
|
(94,185) |
|
(84,778) |
Cash flows from financing
activities |
|
|
207,062 |
|
28,246 |
|
111,542 |
|
54,651 |
Foreign exchange (loss) gain on
cash held in foreign currencies |
|
|
(7,232) |
|
5,496 |
|
6,957 |
|
5,026 |
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash
equivalents |
|
|
14,160 |
|
59,085 |
|
(224,062) |
|
133,473 |
Cash and cash equivalents,
beginning of period |
|
|
151,337 |
|
176,513 |
|
389,559 |
|
102,125 |
Cash and cash equivalents, end of
period |
|
|
165,497 |
|
235,598 |
|
165,497 |
|
235,598 |
|
|
|
|
|
|
|
|
|
|
Supplementary
information for operating activities - cash payments |
|
|
|
|
|
|
|
|
|
|
Interest paid |
|
|
11,721 |
|
8,417 |
|
25,815 |
|
20,509 |
|
Income taxes paid |
|
|
56,486 |
|
18,669 |
|
77,560 |
|
51,304 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS'
EQUITY
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
Other |
|
Total |
|
|
Shareholders' |
Contributed |
Comprehensive |
|
Shareholders' |
|
Note |
Capital |
Surplus |
|
Loss |
Deficit |
Equity |
Balances as at January 1, 2013 |
|
|
1,481,345 |
|
69,581 |
|
(32,409) |
|
(99,871) |
|
1,418,646 |
Net earnings |
|
|
- |
|
- |
|
- |
|
158,335 |
|
158,335 |
Currency translation adjustments |
|
|
- |
|
- |
|
17,623 |
|
- |
|
17,623 |
Equity based compensation expense |
9 |
|
- |
|
26,231 |
|
- |
|
- |
|
26,231 |
Dividends declared |
8 |
|
- |
|
- |
|
- |
|
(120,388) |
|
(120,388) |
Shares issued pursuant to the |
|
|
|
|
|
|
|
|
|
|
|
dividend reinvestment plan |
8 |
|
34,162 |
|
- |
|
- |
|
- |
|
34,162 |
Vesting of equity based awards |
8, 9 |
|
54,370 |
|
(54,370) |
|
- |
|
- |
|
- |
Share-settled dividends |
|
|
|
|
|
|
|
|
|
|
|
on vested equity based awards |
8, 9 |
|
9,808 |
|
- |
|
- |
|
(9,808) |
|
- |
Shares issued pursuant to the bonus plan |
8 |
|
629 |
|
- |
|
- |
|
- |
|
629 |
Balances as at June 30, 2013 |
|
|
1,580,314 |
|
41,442 |
|
(14,786) |
|
(71,732) |
|
1,535,238 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
Other |
|
Total |
|
|
Shareholders' |
Contributed |
Comprehensive |
|
Shareholders' |
|
Note |
Capital |
Surplus |
|
Income |
Deficit |
Equity |
Balances as at January 1, 2014 |
|
|
1,618,443 |
|
75,427 |
|
47,142 |
|
(24,637) |
|
1,716,375 |
Net earnings |
|
|
- |
|
- |
|
- |
|
156,781 |
|
156,781 |
Currency translation adjustments |
|
|
- |
|
- |
|
2,741 |
|
- |
|
2,741 |
Equity based compensation expense |
9 |
|
- |
|
33,968 |
|
- |
|
- |
|
33,968 |
Dividends declared |
8 |
|
- |
|
- |
|
- |
|
(134,717) |
|
(134,717) |
Shares issued pursuant to the |
|
|
|
|
|
|
|
|
|
|
|
dividend reinvestment plan |
8 |
|
38,034 |
|
- |
|
- |
|
- |
|
38,034 |
Shares issued pursuant to |
|
|
|
|
|
|
|
|
|
|
|
corporate acquisition |
3 |
|
204,960 |
|
- |
|
- |
|
- |
|
204,960 |
Modification of equity based awards |
9 |
|
- |
|
(2,395) |
|
|
|
|
|
(2,395) |
Vesting of equity based awards |
8, 9 |
|
47,657 |
|
(47,657) |
|
- |
|
- |
|
- |
Share-settled dividends |
|
|
|
|
|
|
|
|
|
|
|
on vested equity based awards |
8, 9 |
|
7,519 |
|
- |
|
- |
|
(7,519) |
|
- |
Shares issued pursuant to the bonus plan |
8 |
|
721 |
|
- |
|
- |
|
- |
|
721 |
Balances as at June 30, 2014 |
|
|
1,917,334 |
|
59,343 |
|
49,883 |
|
(10,092) |
|
2,016,468 |
|
|
|
|
|
|
|
|
|
|
|
|
DESCRIPTION OF EQUITY RESERVES
Shareholders' capital
Represents the recognized amount for common shares when issued, net
of equity issuance costs and deferred taxes.
Contributed surplus
Represents the recognized value of employee awards which are
settled in shares. Once vested, the value of the awards is
transferred to shareholders' capital.
Accumulated other comprehensive income
Represents the cumulative income and expenses which are not
recorded immediately in net earnings and are accumulated until an
event triggers recognition in net earnings. The current balance
consists of currency translation adjustments resulting from
translating financial statements of subsidiaries with a foreign
functional currency to Canadian dollars at period-end rates.
Deficit
Represents the cumulative net earnings less distributed earnings of
Vermilion Energy Inc.
NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL
STATEMENTS
FOR THE THREE AND SIX MONTHS ENDED JUNE
30, 2014 AND 2013
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE
AND PER SHARE AMOUNTS, UNAUDITED)
1. BASIS OF PRESENTATION
Vermilion Energy Inc. (the "Company" or "Vermilion") is a
corporation governed by the laws of the Province of Alberta and is actively engaged in the
business of crude oil and natural gas exploration, development,
acquisition and production.
These condensed consolidated interim financial statements are in
compliance with IAS 34, "Interim financial reporting" and have been
prepared using the same accounting policies and methods of
computation as Vermilion's
consolidated financial statements for the year ended December 31, 2013, except as discussed in Note
2.
These condensed consolidated interim financial statements should
be read in conjunction with Vermilion's consolidated financial statements
for the year ended December 31, 2013,
which are contained within Vermilion's Annual Report for the year ended
December 31, 2013 and are available
on SEDAR at www.sedar.com or on Vermilion's website at
www.vermilionenergy.com.
These condensed consolidated interim financial statements were
approved and authorized for issuance by the Board of Directors of
Vermilion on July 30, 2014.
2. RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
On January 1, 2014, Vermilion adopted the following pronouncements
as issued by the IASB. The adoption of these standards did
not have a material impact on Vermilion's consolidated financial
statements.
IFRIC 21 "Levies"
On May 20, 2013, the IASB issued
guidance under IFRIC 21, which provides clarification on accounting
for levies in accordance with the requirements of IAS 37
"Provisions, Contingent Liabilities and Contingent Assets". The
interpretation defines a levy as an outflow from an entity imposed
by a government in accordance with legislation and confirms that a
liability for a levy is recognized only when the triggering event
specified in the legislation occurs. The interpretation is
effective for annual periods beginning on or after January 1, 2014.
IAS 36 "Impairment of Assets"
On May 29, 2013, the IASB issued
amendments to IAS 36 "Impairment of Assets" which reduce the
circumstances in which the recoverable amount of CGUs is required
to be disclosed and clarify the disclosures required when an
impairment loss has been recognized or reversed in the
period. This amendment is effective for annual periods
beginning on or after January 1,
2014.
Accounting pronouncements not yet adopted
The impact of the adoption of the following pronouncement is
currently being evaluated.
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,
2017.
3. 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
represents 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 is well aligned with
Vermilion's European focus, and
will increase its exposure to the strong fundamentals and pricing
of the European natural gas markets. The acquisition closed in
February of 2014 for cash proceeds of $172.9
million. Vermilion funded
this acquisition with existing credit facilities.
The acquired assets comprise of four gas producing fields across
eleven production licenses and include both exploration and
production licenses that comprise a total of 207,000 gross acres,
of which 85% is in the exploration license.
The acquisition has been accounted for as a business combination
with the fair value of the assets acquired and liabilities assumed
at the date of acquisition summarized as follows:
($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 have been
included in Vermilion's
consolidated financial statements beginning February of 2014 and
have contributed revenues of $20.0
million and net earnings $0.4
million for the six months ended June
30, 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 six months
ended June 30, 2014.
Corporate acquisition:
Elkhorn Resources Inc.
On April 29, 2014, Vermilion acquired Elkhorn Resources Inc., a
private southeast Saskatchewan
producer. The acquisition creates a new core area for
Vermilion in the Williston
Basin.
The acquired assets include approximately 57,000 net acres of
land (approximately 80% undeveloped), seven oil batteries, and
preferential access to 50% or greater capacity at a solution gas
facility that is currently under construction. Vermilion funded this acquisition with
existing credit facilities.
Total consideration was comprised of $180.4 million of cash 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 $72.50 on the Toronto Stock Exchange on
April 29, 2014).
The acquisition has been accounted for as a business combination
with the fair value of the assets acquired and liabilities assumed
at the date of acquisition summarized as follows:
($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 (1) |
|
385,313 |
(1) |
The above amounts are estimates made by management at the time
of the preparation of these condensed consolidated interim
financial statements based on information then available.
Amendments may be made as amounts subject to estimates are
finalized. |
The results of operations from the assets acquired have been
included in Vermilion's
consolidated financial statements beginning April 29, 2014 and have contributed revenues of
$16.0 million and operating income of
$13.0 million for the six months
ended June 30, 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 $7.0 million for the six months ended
June 30, 2014. In determining the
pro-forma amounts, management has assumed that the fair value
adjustments, determined provisionally, that arose at the date of
acquisition would have been the same if the acquisition had
occurred on January 1, 2014. It is
impracticable to derive all amounts necessary to determine the
increase to net earnings from the acquisition as the acquired
company was immediately merged with Vermilion's operations.
4. CAPITAL ASSETS
The following table reconciles the change in Vermilion's capital assets:
|
Petroleum
and |
Furniture
and |
|
Total |
($M) |
Natural Gas
Assets |
Office Equipment |
|
Capital Assets |
Balance at January 1, 2013
|
|
2,430,121 |
|
15,119 |
|
2,445,240 |
Additions |
|
531,760 |
|
5,804 |
|
537,564 |
Transfers from exploration and
evaluation assets |
|
1,508 |
|
|
|
1,508 |
Corporate acquisitions |
|
47,743 |
|
|
|
47,743 |
Dispositions |
|
(8,627) |
|
|
|
(8,627) |
Changes in estimate for asset
retirement obligations |
|
(91,527) |
|
|
|
(91,527) |
Depletion and
depreciation |
|
(310,370) |
|
(6,138) |
|
(316,508) |
Impairments |
|
47,400 |
|
|
|
47,400 |
Effect of movements in foreign
exchange rates |
|
136,626 |
|
426 |
|
137,052 |
Balance at December 31,
2013 |
|
2,784,634 |
|
15,211 |
|
2,799,845 |
Additions |
|
284,616 |
|
2,199 |
|
286,815 |
Property acquisitions |
|
163,599 |
|
|
|
163,599 |
Corporate acquisitions |
|
390,523 |
|
|
|
390,523 |
Changes in estimate for asset
retirement obligations |
|
46,998 |
|
|
|
46,998 |
Depletion and
depreciation |
|
(199,050) |
|
(1,908) |
|
(200,958) |
Effect of movements in foreign
exchange rates |
|
9,632 |
|
88 |
|
9,720 |
Balance at June 30, 2014
|
|
3,480,952 |
|
15,590 |
|
3,496,542 |
5. EXPLORATION AND EVALUATION ASSETS
The following table reconciles the change in Vermilion's exploration and evaluation
assets:
($M) |
Exploration and
Evaluation Assets |
Balance at January 1,
2013 |
|
117,161 |
Additions |
|
13,789 |
Property acquisitions |
|
9,189 |
Transfers to petroleum and natural
gas assets |
|
(1,508) |
Depreciation |
|
(3,712) |
Effect of movements in foreign
exchange rates |
|
1,340 |
Balance at December 31,
2013 |
|
136,259 |
Additions |
|
44,633 |
Changes in estimate for asset
retirement obligations |
|
85 |
Property acquisitions |
|
16,662 |
Corporate acquisitions |
|
138,264 |
Depreciation |
|
(3,098) |
Effect of movements in foreign
exchange rates |
|
(683) |
Balance at June 30,
2014 |
|
332,122 |
|
|
|
6. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the change in
Vermilion's asset retirement
obligations:
($M) |
Asset
Retirement Obligations |
Balance at January 1, 2013 |
|
|
371,063 |
Additional obligations recognized |
|
|
15,655 |
Changes in estimates for existing obligations |
|
|
(21,068) |
Obligations settled |
|
|
(11,922) |
Accretion |
|
|
24,565 |
Changes in discount rates |
|
|
(73,675) |
Effect of movements in foreign exchange rates |
|
|
21,544 |
Balance at December 31, 2013 |
|
|
326,162 |
Additional obligations recognized |
|
|
18,675 |
Obligations settled |
|
|
(5,032) |
Accretion |
|
|
11,662 |
Changes in discount rates |
|
|
36,412 |
Effect of movements in foreign exchange rates |
|
|
2,175 |
Balance at June 30, 2014 |
|
|
390,054 |
7. LONG-TERM DEBT
The following table summarizes Vermilion's outstanding long-term debt:
|
As At |
($M) |
June 30,
2014 |
Dec 31, 2013 |
Revolving credit facility |
|
975,297 |
|
766,898 |
Senior unsecured notes |
|
223,569 |
|
223,126 |
Long-term debt |
|
1,198,866 |
|
990,024 |
Revolving Credit Facility
At June 30, 2014,
Vermilion had in place a bank
revolving credit facility totalling $1.5
billion, of which approximately $975.3 million was drawn. In addition,
Vermilion may, by adding lenders
or seeking an increase to an existing lender's commitment, increase
the total committed facility amount to no more than $1.75 billion. The facility, which matures
on May 31, 2017, 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 three
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 repayable on the maturity date. This facility
bears interest at a rate applicable to demand loans plus applicable
margins. For the six months ended June
30, 2014, the interest rate on the revolving credit facility
was approximately 3.1%.
The amount available to Vermilion under this facility is reduced by
certain outstanding letters of credit associated with Vermilion's operations totalling $10.2 million as at June
30, 2014 (December 31, 2013 -
$8.1 million).
The facility is secured by various fixed and floating charges
against the subsidiaries of Vermilion. Under the terms of the
facility, Vermilion must
maintain:
- A ratio of total bank borrowings (defined as consolidated total
debt), to consolidated net earnings before interest, income taxes,
depreciation, accretion and other certain non-cash items (defined
as consolidated EBITDA) of not greater than 4.0.
- A ratio of consolidated total senior debt (defined as
consolidated total debt excluding unsecured and subordinated debt)
to consolidated EBITDA of not greater than 3.0.
- A ratio of consolidated total senior debt to total
capitalization (defined as amounts classified as "Long-term debt"
and "Shareholders' Equity" on the balance sheet) of less than
50%.
As at June 30, 2014, Vermilion was in compliance with its financial
covenants.
Senior Unsecured Notes
On February 10,
2011, Vermilion issued
$225.0 million of senior unsecured
notes at par. The notes bear interest at a rate of 6.5% per
annum and will mature on February 10,
2016. As direct senior unsecured obligations of
Vermilion, the notes rank pari
passu with all other present and future unsecured and
unsubordinated indebtedness of the Company.
Vermilion may
redeem all or part of the notes at fixed redemption prices, plus
accrued and unpaid interest, if any, to the applicable redemption
date. The notes were initially recognized at fair value net
of transaction costs and are subsequently measured at amortized
cost using an effective interest rate of 7.1%.
8. SHAREHOLDERS' CAPITAL
The following table reconciles the change in
Vermilion's shareholders'
capital:
Shareholders' Capital |
Number of Shares
('000s) |
|
Amount ($M) |
Balance as at January 1, 2013 |
|
99,135 |
|
1,481,345 |
Shares issued pursuant to the dividend
reinvestment plan |
|
1,402 |
|
72,291 |
Vesting of equity based awards |
|
1,372 |
|
54,370 |
Share-settled dividends on vested equity based
awards |
|
202 |
|
9,808 |
Shares issued pursuant to the bonus plan |
|
12 |
|
629 |
Balance as at December 31, 2013 |
|
102,123 |
|
1,618,443 |
Shares issued pursuant to corporate
acquisition |
|
2,827 |
|
204,960 |
Shares issued pursuant to the dividend
reinvestment plan |
|
601 |
|
38,034 |
Vesting of equity based awards |
|
950 |
|
47,657 |
Share-settled dividends on vested equity based
awards |
|
108 |
|
7,519 |
Shares issued pursuant to the bonus plan |
|
11 |
|
721 |
Balance as at June 30, 2014 |
|
106,620 |
|
1,917,334 |
Dividends declared to shareholders for the six months ended
June 30, 2014 were $134.7 million (2013 - $120.4 million).
Subsequent to the end of the period and prior to the condensed
consolidated interim financial statements being authorized for
issue on July 30, 2014, Vermilion declared dividends totalling
$22.9 million or $0.215 per share.
9. EQUITY BASED COMPENSATION
The following table summarizes the number of
awards outstanding under the Vermilion Incentive Plan ("VIP"):
Number of Awards ('000s) |
2014 |
|
2013 |
Opening balance |
1,665 |
|
1,690 |
Granted |
563 |
|
832 |
Vested |
(512) |
|
(749) |
Modified |
(21) |
|
- |
Forfeited |
(21) |
|
(108) |
Closing balance |
1,674 |
|
1,665 |
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.
On March 31, 2014, Vermilion modified the accounting for certain
outstanding VIP awards to be settled by purchasing Vermilion common shares on the Toronto Stock
Exchange upon vesting rather than by issuing common shares through
treasury. Pursuant to this modification, $2.4 million was reclassified from "Contributed
surplus" to "Accounts payable and accrued liabilities".
Subsequent period expense relating to these outstanding awards will
be recognized in "General and administration expense".
10. SEGMENTED INFORMATION
Vermilion has
operations principally in Canada,
France, the Netherlands, Germany, Ireland, and Australia. Vermilion's operating activities in each
country relate solely to the exploration, development and
production of petroleum and natural gas. Vermilion has a Corporate head office located
in Calgary, Alberta. Costs
incurred in the Corporate segment relate to Vermilion's global hedging program and
expenses incurred in financing and managing our operating business
units.
Vermilion's
chief operating decision maker reviews the financial performance of
the Company by assessing the fund flows from operations of each
country individually. Fund flows from operations provides a
measure of each business unit's ability to generate cash (that is
not subject to short-term movements in non-cash operating working
capital) necessary to pay dividends, fund asset retirement
obligations, and make capital investments.
|
Three Months Ended June 30, 2014 |
($M) |
Canada |
|
France |
|
Netherlands |
|
Germany |
|
Ireland |
|
Australia |
|
Corporate |
|
Total |
Drilling and development |
26,071 |
|
34,828 |
|
18,234 |
|
630 |
|
27,221 |
|
10,991 |
|
- |
|
117,975 |
Exploration and evaluation |
10,897 |
|
2,786 |
|
3,279 |
|
- |
|
- |
|
- |
|
136 |
|
17,098 |
Oil and gas sales to external customers |
163,261 |
|
124,617 |
|
29,881 |
|
11,097 |
|
- |
|
58,828 |
|
- |
|
387,684 |
Royalties |
(18,240) |
|
(7,796) |
|
(693) |
|
(2,284) |
|
- |
|
- |
|
- |
|
(29,013) |
Revenue from external customers |
145,021 |
|
116,821 |
|
29,188 |
|
8,813 |
|
- |
|
58,828 |
|
- |
|
358,671 |
Transportation expense |
(4,024) |
|
(5,385) |
|
- |
|
(1,052) |
|
(1,571) |
|
- |
|
- |
|
(12,032) |
Operating expense |
(21,179) |
|
(16,550) |
|
(6,390) |
|
(2,043) |
|
- |
|
(12,051) |
|
- |
|
(58,213) |
General and administration |
(6,560) |
|
(5,559) |
|
(326) |
|
(830) |
|
(252) |
|
(1,661) |
|
(2,574) |
|
(17,762) |
PRRT |
- |
|
- |
|
- |
|
- |
|
- |
|
(12,699) |
|
- |
|
(12,699) |
Corporate income taxes |
- |
|
(24,761) |
|
(1,301) |
|
(506) |
|
- |
|
(5,689) |
|
(378) |
|
(32,635) |
Interest expense |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(12,334) |
|
(12,334) |
Realized gain on derivative instruments |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
2,419 |
|
2,419 |
Realized foreign exchange gain |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
587 |
|
587 |
Realized other income |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
74 |
|
74 |
Fund flows from operations |
113,258 |
|
64,566 |
|
21,171 |
|
4,382 |
|
(1,823) |
|
26,728 |
|
(12,206) |
|
216,076 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2013 |
($M) |
Canada |
|
France |
|
Netherlands |
|
Germany |
|
Ireland |
|
Australia |
|
Corporate |
|
Total |
Drilling and development |
14,059 |
|
23,223 |
|
4,157 |
|
- |
|
24,878 |
|
8,282 |
|
406 |
|
75,005 |
Exploration and evaluation |
2,494 |
|
- |
|
- |
|
- |
|
- |
|
- |
|
619 |
|
3,113 |
Oil and gas sales to external customers |
100,950 |
|
100,418 |
|
38,316 |
|
- |
|
- |
|
72,282 |
|
- |
|
311,966 |
Royalties |
(9,707) |
|
(6,093) |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(15,800) |
Revenue from external customers |
91,243 |
|
94,325 |
|
38,316 |
|
- |
|
- |
|
72,282 |
|
- |
|
296,166 |
Transportation expense |
(2,611) |
|
(2,416) |
|
- |
|
- |
|
(1,626) |
|
- |
|
- |
|
(6,653) |
Operating expense |
(15,975) |
|
(16,935) |
|
(5,260) |
|
- |
|
- |
|
(9,912) |
|
- |
|
(48,082) |
General and administration |
(3,948) |
|
(3,927) |
|
(426) |
|
- |
|
(410) |
|
(1,378) |
|
(1,224) |
|
(11,313) |
PRRT |
- |
|
- |
|
- |
|
- |
|
- |
|
(12,590) |
|
- |
|
(12,590) |
Corporate income taxes |
- |
|
(16,124) |
|
(9,621) |
|
- |
|
- |
|
(10,646) |
|
(328) |
|
(36,719) |
Interest expense |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(9,336) |
|
(9,336) |
Realized gain on derivative instruments |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
1,770 |
|
1,770 |
Realized foreign exchange gain |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
1,272 |
|
1,272 |
Realized other income |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
77 |
|
77 |
Fund flows from operations |
68,709 |
|
54,923 |
|
23,009 |
|
- |
|
(2,036) |
|
37,756 |
|
(7,769) |
|
174,592 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2014 |
($M) |
Canada |
|
France |
|
Netherlands |
|
Germany |
|
Ireland |
|
Australia |
|
Corporate |
|
Total |
Total assets |
1,854,501 |
|
916,712 |
|
235,723 |
|
174,735 |
|
799,394 |
|
277,624 |
|
125,726 |
|
4,384,415 |
Drilling and development |
127,744 |
|
64,681 |
|
33,425 |
|
826 |
|
43,457 |
|
16,682 |
|
- |
|
286,815 |
Exploration and evaluation |
24,163 |
|
10,900 |
|
8,206 |
|
- |
|
- |
|
- |
|
1,364 |
|
44,633 |
Oil and gas sales to external customers |
286,441 |
|
242,177 |
|
71,435 |
|
20,012 |
|
- |
|
148,802 |
|
- |
|
768,867 |
Royalties |
(30,903) |
|
(15,147) |
|
(2,901) |
|
(4,086) |
|
- |
|
- |
|
- |
|
(53,037) |
Revenue from external customers |
255,538 |
|
227,030 |
|
68,534 |
|
15,926 |
|
- |
|
148,802 |
|
- |
|
715,830 |
Transportation expense |
(7,122) |
|
(10,138) |
|
- |
|
(1,474) |
|
(3,159) |
|
- |
|
- |
|
(21,893) |
Operating expense |
(37,789) |
|
(32,970) |
|
(12,432) |
|
(3,597) |
|
- |
|
(29,411) |
|
- |
|
(116,199) |
General and administration |
(9,428) |
|
(10,753) |
|
(924) |
|
(1,398) |
|
(534) |
|
(2,867) |
|
(6,325) |
|
(32,229) |
PRRT |
- |
|
- |
|
- |
|
- |
|
- |
|
(32,938) |
|
- |
|
(32,938) |
Corporate income taxes |
- |
|
(50,025) |
|
(5,089) |
|
(1,043) |
|
- |
|
(14,530) |
|
(551) |
|
(71,238) |
Interest expense |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(23,794) |
|
(23,794) |
Realized gain on derivative instruments |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
5,059 |
|
5,059 |
Realized foreign exchange loss |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(1,454) |
|
(1,454) |
Realized other income |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
295 |
|
295 |
Fund flows from operations |
201,199 |
|
123,144 |
|
50,089 |
|
8,414 |
|
(3,693) |
|
69,056 |
|
(26,770) |
|
421,439 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2013 |
($M) |
Canada |
|
France |
|
Netherlands |
|
Germany |
|
Ireland |
|
Australia |
|
Corporate |
|
Total |
Total assets |
1,105,026 |
|
873,242 |
|
142,317 |
|
- |
|
646,366 |
|
311,415 |
|
220,641 |
|
3,299,007 |
Drilling and development |
96,800 |
|
44,815 |
|
6,156 |
|
- |
|
41,398 |
|
63,631 |
|
1,725 |
|
254,525 |
Exploration and evaluation |
11,882 |
|
- |
|
- |
|
- |
|
- |
|
- |
|
807 |
|
12,689 |
Oil and gas sales to external customers |
184,638 |
|
221,984 |
|
72,737 |
|
- |
|
- |
|
142,183 |
|
- |
|
621,542 |
Royalties |
(18,696) |
|
(12,894) |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(31,590) |
Revenue from external customers |
165,942 |
|
209,090 |
|
72,737 |
|
- |
|
- |
|
142,183 |
|
- |
|
589,952 |
Transportation expense |
(4,880) |
|
(5,170) |
|
- |
|
- |
|
(3,244) |
|
- |
|
- |
|
(13,294) |
Operating expense |
(29,816) |
|
(36,874) |
|
(9,229) |
|
- |
|
- |
|
(24,738) |
|
- |
|
(100,657) |
General and administration |
(7,017) |
|
(9,613) |
|
(838) |
|
- |
|
(647) |
|
(2,896) |
|
(2,912) |
|
(23,923) |
PRRT |
- |
|
- |
|
- |
|
- |
|
- |
|
(23,743) |
|
- |
|
(23,743) |
Corporate income taxes |
- |
|
(34,783) |
|
(19,055) |
|
- |
|
- |
|
(17,859) |
|
(579) |
|
(72,276) |
Interest expense |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(18,025) |
|
(18,025) |
Realized loss on derivative instruments |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(1,017) |
|
(1,017) |
Realized foreign exchange gain |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
655 |
|
655 |
Realized other income |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
549 |
|
549 |
Fund flows from operations |
124,229 |
|
122,650 |
|
43,615 |
|
- |
|
(3,891) |
|
72,947 |
|
(21,329) |
|
338,221 |
Reconciliation of fund flows from operations to net
earnings
|
Three Months Ended |
|
Six Months Ended |
|
Jun 30, |
Jun 30, |
|
Jun 30, |
Jun 30, |
($M) |
2014 |
2013 |
|
2014 |
2013 |
Fund flows from operations |
216,076 |
174,592 |
|
421,439 |
338,221 |
Equity based compensation |
(18,217) |
(10,724) |
|
(34,689) |
(26,860) |
Unrealized (loss) gain on derivative
instruments |
(1,521) |
8,651 |
|
2,414 |
7,538 |
Unrealized foreign exchange (loss) gain |
(23,746) |
28,025 |
|
(1,746) |
25,506 |
Unrealized other income (expense) |
104 |
(348) |
|
(150) |
(753) |
Accretion |
(5,950) |
(6,000) |
|
(11,662) |
(11,824) |
Depletion and depreciation |
(104,902) |
(78,418) |
|
(204,354) |
(159,866) |
Deferred taxes |
(7,851) |
(9,580) |
|
(14,471) |
(13,627) |
Net earnings |
53,993 |
106,198 |
|
156,781 |
158,335 |
|
|
|
|
|
|
11. CAPITAL DISCLOSURES
|
Three Months Ended |
|
Six Months Ended |
($M except as indicated) |
June 30, 2014 |
June 30, 2013 |
|
June 30, 2014 |
June 30, 2013 |
Long-term debt |
1,198,866 |
780,470 |
|
1,198,866 |
780,470 |
Current liabilities |
377,710 |
325,912 |
|
377,710 |
325,912 |
Current assets |
(407,578) |
(432,014) |
|
(407,578) |
(432,014) |
Net debt [1] |
1,168,998 |
674,368 |
|
1,168,998 |
674,368 |
|
|
|
|
|
|
Cash flows from operating activities |
149,592 |
179,074 |
|
327,830 |
369,786 |
Changes in non-cash operating working
capital |
64,103 |
(6,852) |
|
88,577 |
(35,323) |
Asset retirement obligations settled |
2,381 |
2,370 |
|
5,032 |
3,758 |
Fund flows from operations |
216,076 |
174,592 |
|
421,439 |
338,221 |
Annualized fund flows from operations [2] |
864,304 |
698,368 |
|
842,878 |
676,442 |
|
|
|
|
|
|
Ratio of net debt to annualized fund flows from
operations ([1] ÷ [2]) |
1.4 |
1.0 |
|
1.4 |
1.0 |
Long-term debt as at June
30, 2014 increased to $1.2
billion from $990.0 million as
at December 31, 2013 as a result of
draws on the revolving credit facility during the current year to
fund the acquisitions in Germany
and Saskatchewan coupled with the
assumption of $47.5 million of
long-term debt pursuant to the latter acquisition. This
increase in long-term debt resulted in an increase to net debt from
$749.7 million to $1.2 billion.
As year-to-date fund flows includes only 2 months of
contribution from the acquisition in Saskatchewan, the ratio of net debt to
annualized fund flows increased to 1.4.
12. FINANCIAL INSTRUMENTS
Classification of Financial Instruments
The following table summarizes information relating to
Vermilion's financial instruments
as at June 30, 2014 and December 31, 2013:
|
|
|
|
|
|
As at Jun 30, 2014 |
|
As at Dec 31, 2013 |
|
|
Class of
financial
instrument |
Consolidated balance
sheet caption |
Accounting
designation |
Related caption on Statement
of Net
Earnings |
|
Carrying
value ($M) |
Fair value
($M) |
|
Carrying
value ($M) |
|
Fair value
($M) |
|
Fair value
measurement
hierarchy |
Cash |
Cash and cash equivalents |
HFT |
Gains and losses on foreign exchange
are included in foreign exchange loss (gain) |
|
165,497 |
|
165,497 |
|
389,559 |
|
389,559 |
|
Level 1 |
Receivables |
Accounts receivable |
LAR |
Gains and losses on foreign exchange are included
in foreign exchange loss (gain) and impairments are recognized as
general and administration expense |
|
199,251 |
|
199,251 |
|
167,618 |
|
167,618 |
|
Not applicable |
Derivative assets |
Derivative instruments |
HFT |
Gain on derivative instruments |
|
7,624 |
|
7,624 |
|
2,285 |
|
2,285 |
|
Level 2 |
Derivative liabilities |
Derivative instruments |
HFT |
Gain on derivative instruments |
|
(7,787) |
|
(7,787) |
|
(3,572) |
|
(3,572) |
|
Level 2 |
Payables |
Accounts payable and accrued liabilities |
OTH |
Gains and losses on foreign exchange
are included in foreign exchange loss (gain) |
|
(287,172) |
|
(287,172) |
|
(288,257) |
|
(288,257) |
|
Not applicable |
|
|
Dividends payable
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
Long-term debt |
OTH |
Interest expense |
|
(1,198,866) |
|
(1,207,610) |
|
(990,024) |
|
(998,648) |
|
Level 2 |
The accounting designations used in the above table refer to the
following:
HFT - Classified as "Held for trading" in accordance with
International Accounting Standard 39 "Financial Instruments:
Recognition and Measurement". These financial assets and
liabilities are carried at fair value on the consolidated balance
sheets with associated gains and losses reflected in net
earnings.
LAR - "Loans and receivables" are initially recognized at fair
value and are subsequently measured at amortized cost.
Impairments and foreign exchange gains and losses are recognized in
net earnings.
OTH - "Other financial liabilities" are initially recognized at
fair value net of transaction costs directly attributable to the
issuance of the instrument and subsequently are measured at
amortized cost. Interest is recognized in net earnings using
the effective interest method. Foreign exchange gains and
losses are recognized in net earnings.
Level 1 - Fair value measurement is determined by reference to
unadjusted quoted prices in active markets for identical assets or
liabilities.
Level 2 - Fair value measurement is determined based on inputs
other than unadjusted quoted prices that are observable, either
directly or indirectly.
Level 3 - Fair value measurement is based on inputs for the
asset or liability that are not based on observable market
data.
Determination of Fair Values
The level in the fair value hierarchy into which the fair value
measurements are categorized is determined on the basis of the
lowest level input that is significant to the fair value
measurement. Transfers between levels on the fair value
hierarchy are deemed to have occurred at the end of the reporting
period.
Fair values for derivative assets and derivative liabilities are
determined using pricing models incorporating future prices that
are based on assumptions which are supported by prices from
observable market transactions and are adjusted for credit
risk.
The carrying value of receivables approximate their fair value
due to their short maturities.
The carrying value of long-term debt outstanding on the
revolving credit facility approximates its fair value due to the
use of short-term borrowing instruments at market rates of
interest.
The fair value of the senior unsecured notes changes in response
to changes in the market rates of interest payable on similar
instruments and was determined with reference to prevailing market
rates for such instruments.
Nature and Extent of Risks Arising from Financial
Instruments
Market risk:
Vermilion's financial instruments
are exposed to currency risk related to changes in foreign currency
denominated financial instruments and commodity price risk related
to outstanding derivative positions. The following table
summarizes what the impact on comprehensive income before tax would
be for the six months ended June 30,
2014 given changes in the relevant risk variables that
Vermilion considers were
reasonably possible at the balance sheet date. The impact on
comprehensive income before tax associated with changes in these
risk variables for assets and liabilities that are not considered
financial instruments are excluded from this analysis. This
analysis does not attempt to reflect any interdependencies between
the relevant risk variables.
|
Before tax effect
on comprehensive |
|
income - increase
(decrease)
|
Risk ($M) |
Description of change in risk
variable |
June 30, 2014 |
Currency risk - Euro to Canadian |
Increase in strength of the
Canadian dollar against the Euro by 5% over the relevant closing
rates |
(3,580) |
|
|
|
|
Decrease in strength of the
Canadian dollar against the Euro by 5% over the relevant closing
rates |
3,580 |
|
|
|
Currency risk - US $ to Canadian |
Increase in strength of the Canadian
dollar against the US $ by 5% over the relevant closing rates |
(2,866) |
|
|
|
|
Decrease in strength of the Canadian
dollar against the US $ by 5% over the relevant closing
rates
|
2,866 |
|
|
|
|
|
|
Commodity price risk |
Increase in relevant oil reference price
within option pricing models used to determine |
(7,593) |
|
the fair value of financial derivatives by US
$5.00/bbl at the relevant valuation dates |
|
|
|
|
|
Decrease in relevant oil
reference price within option pricing models used to determine |
6,893 |
|
the fair value of financial
derivatives by US $5.00/bbl at the relevant valuation dates |
|
|
|
Interest rate risk |
Increase in average Canadian prime
interest rate by 100 basis points during the relevant periods |
(4,063) |
|
|
|
|
Decrease in average Canadian
prime interest rate by 100 basis points during the relevant
periods |
4,063
|
SOURCE Vermilion Energy Inc.