CALGARY, March 3, 2014 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We",
"Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report
operating and audited financial results for the fourth quarter and year
ended December 31, 2013.
HIGHLIGHTS
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We achieved record average annual production of 41,005 boe/d during
2013, an increase of 8% as compared to 37,803 boe/d in 2012.
Approximately 75% of our year-over-year production growth was achieved
organically through continued development of our Cardium and Mannville
resource plays in Canada, and successful conventional drilling programs
in France and Australia. The remaining 25% of production growth came
from our December 2012 acquisition in France and our October 2013
acquisition in the Netherlands.
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Strong operational and drilling execution underpinned our ability to
deliver organic growth in production and reserves in each of our
producing business units in 2013. Reliable operational performance in
all regions enabled us to increase production guidance three times
during the year and to achieve production levels at the top end of our
final guidance range.
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We grew both proved ("1P") and proved plus probable ("2P") reserves by
more than 20% in 2013, our highest level of reserves growth in more
than 10 years. Our independent GLJ 2013 Reserves Evaluation(1) assessed an increase of 23% in total 1P reserves to 129.0(1) mmboe, while total 2P reserves increased 20% to 198.6(1) mmboe.
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After-tax net present value discounted at 10% ("NPV10") of 2P reserves
increased 29% to $3.9 billion in the GLJ 2013 Reserves Evaluation from
$3.0 billion in GLJ 2012 Reserves Evaluation(2).
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Our independent GLJ 2013 Resource Assessment(3) indicates low, best, and high estimates for contingent resources of
74.4(3) mmboe, 233.5(3) mmboe, and 351.7(3) mmboe, a decrease of 11% and an increase of 45% and 52%, respectively,
compared to our GLJ 2012 Resource Assessment(4). Prospective resources were assessed at low, best and high estimates
of 59.4(3) mmboe, 498.7(3) mmboe, and 818.8(3) mmboe, an increase of 518%, 100%, and 51%, respectively versus our GLJ
2012 Resource Assessment. Importantly, the GLJ 2013 Resource
Assessment reflects a significant increase in the assessment of best
estimate contingent and prospective resources across our Canadian and
European business units.
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GLJ 2013 Resource Assessment estimated after-tax NPV10 of low, best and
high estimate contingent resources of $0.4 billion, $1.3 billion, and
$2.6 billion, respectively. GLJ 2013 Resource Assessment estimated
after-tax NPV10 of low, best and high estimate prospective resources of
$0.2 billion, $1.8 billion, and $5.3 billion, respectively.
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We generated record fund flows from operations(5) in 2013 of $667.5 million ($6.61/basic share), an increase of 20% as
compared to $557.7 million ($5.69/basic share) in 2012. The increase
was primarily attributable to higher production volumes in all
regions. Fund flows from operations in 2013 also benefitted from
higher price realizations for our North American oil and gas production
as well as our European gas.
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In 2013, improved pricing in Canada for both oil and gas production
resulted in higher company-total realized prices as compared to 2012.
WTI pricing improved 4% year-over-year to US$97.97/bbl, while Edmonton
Sweet Index pricing, against which the majority of our Canadian-based
crude production is priced, increased nearly 5% to US$90.40/bbl in
2013. Average AECO index pricing, against which our Canadian natural
gas production is priced, increased by 33% in 2013 to $3.01/GJ compared
to $2.26/GJ in 2012.
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We remain advantaged by our international exposure to Brent-based crude
oil and European natural gas pricing. Our Brent-based crude production
represents 43% of total oil-equivalent production (67% of total crude
oil production) and continues to attract a consolidated premium to the
quoted Dated Brent reference price. This premium provides further
support to our comparative price advantage over North American
producers as Dated Brent continued to trade at an average premium in
2013 of US$10.69/bbl and US$18.26/bbl versus WTI and the Edmonton Sweet
Index pricing, respectively. Our European gas production also
continues to attract strong relative pricing. During 2013, our
Netherlands gas production received an average of $10.29/GJ, an
increase of over 8% relative to 2012, and a premium of $7.28/GJ
compared to Canadian-based AECO gas pricing.
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In October 2013, we completed our acquisition from Northern Petroleum
PLC, of interests in nine concessions in the Netherlands. The
acquisition added approximately 100 boe/d of annualized production in
2013 and is expected to add average production of approximately 400
boe/d in 2014. The acquisition added 2.4(1) mmboe of 2P reserves and 298,500 net acres of land, of which 98% is
currently undeveloped. This accretive acquisition brings operating
synergies with our legacy assets, helps consolidate our position in the
northeast Netherlands, and opens up new development opportunities in
the central region of the Netherlands.
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In November 2013, we announced an agreement to acquire a 25% contractual
participation interest in a four partner consortium in Germany from GDF
Suez S.A. The acquisition enables us to participate in the
exploration, development, production and transportation of natural gas
from the assets, which include four gas producing fields across 11
production licenses. The acquisition closed in February 2014. We are
guiding to a contribution of approximately 2,300 boe/d of production
from our new German assets in 2014. In addition to the production
licenses, a surrounding exploration license was also acquired pursuant
to the acquisition. The exploration and production licenses comprise
204,000 gross acres, of which 85% is in the exploration license.
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In Ireland, Corrib tunneling operations are more than 70% completed with
approximately 1.4 kilometres of tunneling remaining. Based on the
current deterministic schedule for remaining construction and
commissioning activities, we anticipate first gas from Corrib in
approximately mid-2015. Successful 2013 subsea well operations
conducted on one of the production wells facilitated an increase to our
peak production estimate at Corrib from 54 mmcf/d (9,000 boe/d) to
approximately 58 mmcf/d (approximately 9,700 boe/d) net to Vermilion.
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Subsequent to the end of 2013, we were conditionally awarded the
Battonya South concession in Hungary, subject to successful execution
of a definitive agreement acceptable to both Vermilion and the
Hungarian Ministry of National Development. The concession consists of
116,000 gross acres located in the southern part of Hungary. The term
of the concession is for 20 years, subject to continuation of
development in a manner acceptable to both parties.
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In early 2014, we informed the Moroccan government of our intention to
relinquish our rights to the Haouz block in central Morocco. Based on
our analysis of seismic data, we concluded that due to the structural
complexity of the block, we would be unable to pursue a definitive
appraisal and exploration program that would fit within the constraints
of our predetermined new venture capital and risk parameters. The
relinquishment terminates our activities in Morocco after cumulative
spending of $0.9 million to evaluate the 2.3 million acre block.
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In 2013, we provided our shareholders with a total return, including
dividends, of 24.6%. Over the last three, five, ten and 15 years we
have provided our shareholders with a compound average total return of
14.5%, 24.0%, 18.6% and 25.5%, respectively. Since our inception in
1994, we have provided a compound average total return to our
shareholders of 35.8% per year.
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In keeping with our objective of providing reliable and growing
dividends, in November 2013 we announced a 7.5% increase to our monthly
cash dividend to $0.215 per share ($2.58 per year) beginning in 2014.
This followed a previous 5.3% increase announced in November 2012.
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Our Board of Directors has approved an amendment to our Dividend
Reinvestment Plan ("DRIP") to decrease the amount of additional shares
participants in the DRIP are eligible to receive to 3% of their cash
dividends from the current level of 5%. All other terms and conditions
related to participation in our DRIP remain unchanged. This amendment
is expected to be effective for the April dividend payable on May 15,
2014. The record date for the April dividend is April 30, 2014.
(1)
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Estimated proved plus probable reserves attributable to the assets as
evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated
February 4, 2014 with an effective date of December 31, 2013 (the "2013
GLJ Reserves Evaluation")
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(2)
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Estimated proved plus probable reserves attributable to the assets as
evaluated by GLJ in a report dated February 14, 2013 with an effective
date of December 31, 2012 (the "2012 GLJ Reserves Evaluation")
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(3)
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Vermilion retained GLJ to conduct an independent resource evaluation to
assess contingent and prospective resources across all of the Company's
key operating regions with an effective date of December 31, 2013 (the
"GLJ 2013 Resource Assessment")
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(4)
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Vermilion retained GLJ to conduct an independent resource evaluation to
assess contingent and prospective resources across all of the Company's
key operating regions with an effective date of December 31, 2012 (the
"GLJ 2012 Resource Assessment")
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(5)
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Additional GAAP Financial Measure. Please see the "Additional and
Non-GAAP Financial Measures" section of Management's Discussion and
Analysis.
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Reserves and resources information in this news release is a summary
only and is subject to the reserves and resources information set forth
in Vermilion's annual information form for the year ended December 31,
2013, a summary of which is set forth in Vermilion's news release dated
March 3, 2014 entitled "Vermilion Energy Inc. Announces 2013 Year-end
Summary Reserves and Resource Information", which will be filed and
available on SEDAR at www.sedar.com and on the SEC's EDGAR system at www.sec.gov.
ORGANIZATIONAL UPDATE
President and Chief Operating Officer Appointment
Vermilion is pleased to announce the appointment of Anthony Marino to
the position of President and Chief Operating Officer effective March
3, 2014. This appointment is in consideration of Mr. Marino's
significant contributions towards Vermilion's success over the last two
years since joining the organization.
Mr. Marino and the rest of the executive team will continue to report to
Lorenzo Donadeo in his capacity as Chief Executive Officer. Our
management team looks forward to leading the organization to achieve
the objectives we have set out in our long range plan, which seeks to
provide sustainable production growth and a reliable and growing
dividend.
Mr. Marino is an accomplished senior executive with a proven track
record of high performance during his 30-year career in the energy
industry. Mr. Marino joined Vermilion in June, 2012 as Chief Operating
Officer. Prior to this, Mr. Marino held the position of President and
Chief Executive Officer of Baytex Energy Corporation, after initially
serving as Baytex's Chief Operating Officer. Prior to joining Baytex,
Mr. Marino held the role of President and Chief Executive Officer of
Dominion Exploration Canada Ltd. Earlier in his career, Mr. Marino held
a variety of technical and management positions with AEC Oil and Gas
(USA) Inc., Santa Fe Snyder Corp. and Atlantic Richfield Company. Mr.
Marino brings strong experience in production operations and the
development of oil and gas resource plays to Vermilion. In addition to
his operating experience, Mr. Marino also has an extensive background
in business development and oil and gas marketing.
Mr. Marino has a Bachelor of Science degree with Highest Distinction in
Petroleum Engineering from the University of Kansas and a Master of
Business Administration degree from California State University at
Bakersfield. He is a registered professional engineer and holds the
Chartered Financial Analyst designation.
Conference Call and Audio Webcast Details
Vermilion will discuss these results in a conference call to be held on
Monday, March 3, 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 39159856. The replay will be available until midnight eastern
time on March 10, 2014.
You may also listen to the audio webcast by clicking http://event.on24.com/r.htm?e=742286&s=1&k=23F1F279149D62557A72E55CA7C5400A
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; 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 and 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 strength 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 the disclosed 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
bbl(s)
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barrel(s)
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mbbls
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thousand barrels
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bbls/d
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barrels per day
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mcf
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thousand cubic feet
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mmcf
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million cubic feet
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bcf
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billion cubic feet
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mcf/d
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thousand cubic feet per day
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mmcf/d
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million cubic feet per day
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GJ
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gigajoules
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MWh
|
megawatt hour
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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)
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mboe
|
thousand barrel of oil equivalent
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mmboe
|
million barrel of oil equivalent
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boe/d
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barrel of oil equivalent per day
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NGLs
|
natural gas liquids
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WTI
|
West Texas Intermediate, the reference price paid for crude oil of
standard grade in U.S. dollars at Cushing, Oklahoma
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AECO
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the daily average benchmark price for natural gas at the AECO 'C' hub in
southeast Alberta
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TTF
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the price for natural gas in the Netherlands, quoted in MWh of natural
gas per hour per day, at the Title Transfer Facility Virtual Trading
Point operated by Dutch TSO Gas Transport Services
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$M
|
thousand dollars
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$MM
|
million dollars
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PRRT
|
Petroleum Resource Rent Tax, a profit based tax levied on petroleum
projects in Australia
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MESSAGE TO SHAREHOLDERS
Dear Shareholders:
By all accounts, 2013 was a year of significant achievement for
Vermilion. We realized organic growth across all of our operating
business units, attained record company-total production levels,
generated record fund flows from operations, achieved record drilling
results in Australia, recorded our highest level of reserves growth
since converting to a distribution/dividend paying business model,
provided a 24.6% total return to our shareholders, and announced a 7.5%
increase to our monthly cash dividend.
Solid operational and drilling execution was the foundation for
delivering strong organic growth in both production and reserves in
2013. Reliable operational performance across all of our business
units allowed us to actively manage the composition of our produced
volumes, increase production guidance three times during the year, and
achieve the top end of our final guidance of 41,000 boe/d.
Canada
We remained focused on the continued development of our successful
Cardium light oil play. Well performance remains predictable,
reflective of the high quality, consistent nature of the reservoir
underlying our land position in the West Pembina region. Since
entering the play in 2009, we have brought a total of 223 (158.9 net)
Cardium wells on production and grown Cardium related production
volumes to more than 9,000 boe/d as at the end of 2013. Entering 2014,
we have an inventory of nearly 200 net economic one-mile equivalent
wells remaining to be drilled. In addition, we continue to review our
significant inventory of more than 120 additional locations that may
become economic as we expand our use of extended reach horizontal wells
(greater than one mile in length) and further optimize completion
technology and well design. We have also initiated a water injection
pilot to test applicability of water-flooding to this reservoir as a
means to increase potential recoveries. During 2014, we anticipate
drilling more than 30 net Cardium wells.
In addition to the Cardium, we have also begun development of our
significant inventory of Mannville condensate-rich natural gas wells in
the West Pembina area. In 2013, we drilled a total of six (3.7 net)
condensate-rich gas wells. Drilling results to-date have exceeded our
initial expectations with respect to both gas production rates and
associated liquids yields. This has resulted in robust economics and
anticipated rates of return in excess of 100%. Results from our 2013
drilling activities, and those of other operators, demonstrated the
strong economics and prospectivity of the Mannville, allowing GLJ, our
independent reserves evaluator, to recognize significant additional
reserves. Our year-end 2013 2P reserves report includes an additional
40 (28.4 net) undeveloped drilling locations and increased reserves of
19.8(1) mmboe attributable to our Mannville condensate-rich play, including
upward technical revisions. In 2014, we plan to drill 8 (5.7 net)
Mannville wells, and we expect drilling activity to increase in future
years as we continue to develop the play and expand our inventory of
economic prospects.
We are also appraising 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, Drayton Valley
and Niton areas. To date, we have drilled three vertical stratigraphic
test wells, and are currently drilling our first horizontal well. The
first horizontal test is in the down-dip 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 micro-seismic monitoring while we frac the horizontal well
after break-up. We anticipate that the horizontal well production
results and fracture geometries from the micro-seismic data will assist
us in optimizing completions on future horizontal wells. We are
confident we will be able to project the results to higher condensate
yield drilling 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.
France
We completed a highly successful five-well drilling campaign in the
Champotran field in the Paris Basin in 2013, adding nearly 5.5(1) mmboe of 2P reserves and confirming 20 potential well locations for
future drilling. During the fourth quarter of 2013, the five wells
produced at an average rate per well of 250 bbls/d at an average water
cut of only 3%. Late in 2013, we converted a previous producing well
at Champotran to water injection to add additional injection capacity
to our previously-existing waterflood program in the field. Based on
positive initial results from this most recent conversion to injection,
we believe that expanded waterflooding may lead to significantly
improved recoveries from the Champotran field over time. In late
September, 2013 the third-party Lacq gas processing facility, which
processed our gas production from the Vic Bihl field in the Aquitaine
Basin, was permanently shut-in. As a result, we have temporarily
shut-in natural gas production of approximately 700 boe/d from the
field while we complete preparations for a phased transfer of our
production to an alternative third party facility. We currently
anticipate approximately 140 boe/d of our Vic Bihl gas production will
be back on-steam in the third quarter of 2014. The remainder of the
shut-in gas production at Vic Bihl is not expected to be back on
production until late 2015. With the full integration of our 2012
acquisitions complete, our French business is now positioned as a key
organic oil growth asset featuring low base decline rates, high
netbacks from Brent-based production, strong cash flow generation and
high capital efficiencies on development projects. As a result, we
have been actively increasing our France-based technical staff to
identify and execute additional investment opportunities in these
large, complex, conventional light oil fields in both the Paris and
Aquitaine Basins.
Netherlands
In 2013, we continued permitting and drilling preparations in advance of
a six-well drilling campaign for 2014 that was initiated in January
2014. We also completed a debottlenecking project at Garijp and
construction and commissioning of surface facilities for our multi-zone
Langezwaag-1 well (42% working interest) in 2013. Early in the fourth
quarter of 2013, we closed our acquisition of Northern Petroleum Plc's
operating interests in the Netherlands. The acquisition added
interests in nine operated onshore concessions (six concessions on
production or in development and three exploration concessions) and a
non-operated interest in one offshore concession. This accretive
acquisition brings synergies with our legacy assets and consolidates
our position in northeast Netherlands, while also opening up new
development opportunities in the central part of the Netherlands.
Production from the acquired assets is expected to average
approximately 400 boe/d in 2014. The assets added 2.4(2) mmboe of 2P reserves and 298,500 net acres of land, of which 98% is
currently undeveloped. Subsequent to year-end 2013, we were awarded
the Ijsselmuiden exploration concession, which consists of
approximately 110,500 net undeveloped acres, further increasing our
undeveloped land base in the Netherlands to more than 800,000 net
acres. We have identified several development opportunities on the new
assets that increase our already significant inventory of investment
projects in the Netherlands. Given our increased land position and our
continued drilling success in the Netherlands, we now view our
Netherlands Business Unit as an organic growth business. We are
increasing our technical staff in the Netherlands to support our
efforts to convert our substantial inventory of prospect leads into
drillable projects. Beginning in 2014, we intend to increase activity
levels in the Netherlands each year 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.
Ireland
Construction of the five-kilometre land-based portion of the onshore
pipeline, offshore umbilical-laying, seismic acquisition and workover
activities were conducted in 2013. Construction of the 4.9 kilometre
tunnel portion of the onshore pipeline is more than 70% complete with
approximately 1.4 kilometres of tunneling remaining. Based on review
of the current deterministic schedule for remaining construction and
commissioning activities, we continue to anticipate first gas from
Corrib in approximately mid-2015. Following successful subsea well
operations conducted during the third quarter of 2013, we increased our
peak production estimate at Corrib from 54 mmcf/d (9,000 boe/d) to
approximately 58 mmcf/d (approximately 9,700 boe/d) net to Vermilion.
Australia
Vermilion drilled two sidetracks off existing wells during the first
half of 2013. The program included the drilling of a 3,400 metre
horizontal leg, the longest horizontal section drilled to-date at
Wandoo. The 2013 drilling program has been our most successful effort
yet in Australia. Both sidetracks were brought on production at
restricted rates in April, demonstrating initial productive capacities
in excess of 6,000 bbls/d and 3,000 bbls/d, respectively. 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 next drilling program is expected to occur in 2015.
Wandoo's 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, leading to high netbacks.
Germany
In November, 2013, we announced an agreement to acquire a 25%
contractual participation interest in a four-partner consortium in
Germany from GDF Suez S.A. The acquisition was subsequently completed
in February of 2014, and will enable us to participate in the
exploration, development, production and transportation of natural gas
from the assets held by the consortium. The assets are comprised of
four gas producing fields across eleven production licenses and are
characterized by a low effective decline rate of approximately 16%
annually. The acquired assets are expected to contribute approximately
2,300 boe/d of production in 2014, and include both exploration and
production licenses that comprise a total of 204,000 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. The acquisition provides us
with entry into this sizable market, in the form of free cash flow(3) generating, low-decline assets with near-term development inventory in
addition to longer-term, low-permeability gas prospectivity. Entry
into Germany is in keeping with our European focus, and will increase
our exposure to the strong fundamentals and pricing of European natural
gas markets. We believe that our conventional and unconventional
expertise, coupled with new access to proprietary technical data, will
position us strongly for future development and expansion opportunities
in both Germany and the greater European region.
General Outlook
Development capital for 2014 is currently estimated at $555 million. Our
operations continue to perform strongly, generating organic production
growth in a capital-efficient manner. With the contribution of
production associated with both our Netherlands and Germany
acquisitions, we are guiding to full year 2014 average annual
production volumes of 45,000 to 46,000 boe/d. Assuming commodity
prices remain near current levels for the remainder of 2014, the
Company anticipates that it will fully fund its net dividends(3) and development capital expenditures (excluding capital investment at
Corrib) with fund flows from operations(3) during 2014.
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 5-7% along
with providing reliable and growing dividends. Near term production
and fund flows from operations(3) 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 growth and free cash flow(3) growth is expected from Corrib beginning approximately mid-2015 with
the first full year of production from the project in 2016. Our
Australian Business Unit is expected to provide steady production as
well as significant free cash flow(3).
With the anticipated growth of fund flows from operations(3), the continued strength of our operations and our expansive opportunity
base, we are confident we can achieve our future growth objectives and
continue to provide reliable growth and a growing dividend stream to
investors. We believe the Company's balance sheet remains well
positioned to execute its capital-efficient growth-and-income model and
fund Corrib development through to first gas while remaining within an
acceptable net debt-to-fund flows from operations(3) ratio. Corrib is expected to provide a further significant increase to
the Company's projected free cash flow(3) upon first gas production.
The management and directors of Vermilion continue to hold approximately
8% 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 fourth consecutive year by the Great Place to Work® Institute in
both Canada and France in 2013. We ranked as the 22nd Best Workplace
in Canada among more than 315 companies. Our French unit ranked as the
27th Best Workplace in the country.
(signed "Lorenzo Donadeo")
Lorenzo Donadeo
Chief Executive Officer
March 3, 2014
(1)
|
Estimated proved plus probable reserves attributable to the assets as
evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated
February 4, 2014 , with an effective date of December 31, 2013 (the
"2013 GLJ Reserves Evaluation").
|
(2)
|
Estimated proved plus probable reserves attributable to the assets as
evaluated by GLJ in a report dated September 16, 2013, with an
effective date of December 31, 2012.
|
(3)
|
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.
|
HIGHLIGHTS
|
Three Months Ended
|
|
|
Year Ended
|
($M except as indicated)
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
|
Dec 31,
|
Dec 31,
|
Financial
|
2013
|
2013
|
2012
|
|
|
2013
|
2012
|
Petroleum and natural gas sales
|
325,108
|
327,185
|
241,233
|
|
|
1,273,835
|
1,083,103
|
Fund flows from operations (1)
|
163,660
|
165,645
|
141,737
|
|
|
667,526
|
557,728
|
|
Fund flows from operations ($/basic share)
|
1.61
|
1.63
|
1.43
|
|
|
6.61
|
5.69
|
|
Fund flows from operations ($/diluted share)
|
1.58
|
1.61
|
1.41
|
|
|
6.51
|
5.62
|
Net earnings
|
101,510
|
67,796
|
56,914
|
|
|
327,641
|
190,622
|
|
Net earnings per share ($/basic share)
|
1.00
|
0.67
|
0.58
|
|
|
3.24
|
1.94
|
Capital expenditures
|
148,478
|
135,661
|
157,035
|
|
|
542,726
|
452,538
|
Acquisitions
|
29,103
|
7,586
|
209,254
|
|
|
36,689
|
315,438
|
Asset retirement obligations settled
|
5,426
|
2,738
|
8,424
|
|
|
11,922
|
13,739
|
Cash dividends ($/share)
|
0.60
|
0.60
|
0.57
|
|
|
2.40
|
2.28
|
Dividends declared
|
61,208
|
61,003
|
56,435
|
|
|
242,599
|
223,717
|
|
% of fund flows from operations
|
37%
|
37%
|
40%
|
|
|
36%
|
40%
|
Net dividends (1)
|
42,433
|
41,649
|
37,967
|
|
|
170,308
|
151,659
|
|
% of fund flows from operations
|
26%
|
25%
|
27%
|
|
|
26%
|
27%
|
Payout (1)
|
196,337
|
180,048
|
203,426
|
|
|
724,956
|
617,936
|
|
% of fund flows from operations
|
120%
|
109%
|
144%
|
|
|
109%
|
111%
|
|
% of fund flows from operations (excluding the Corrib project)
|
111%
|
87%
|
129%
|
|
|
94%
|
99%
|
Net debt (1)
|
749,685
|
700,286
|
677,231
|
|
|
749,685
|
677,231
|
Ratio of net debt to annualized fund flows from operations (1)
|
1.1
|
1.1
|
1.2
|
|
|
1.1
|
1.2
|
Operational
|
Production
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
26,039
|
26,664
|
23,699
|
|
|
25,741
|
23,971
|
|
NGLs (bbls/d)
|
1,761
|
1,945
|
1,176
|
|
|
1,730
|
1,299
|
|
Natural gas (mmcf/d)
|
78.96
|
77.41
|
68.34
|
|
|
81.21
|
75.20
|
|
Total (boe/d)
|
40,960
|
41,510
|
36,265
|
|
|
41,005
|
37,803
|
Average realized prices
|
|
|
|
|
|
|
|
|
Crude oil and NGLs ($/bbl)
|
106.00
|
108.87
|
96.74
|
|
|
104.46
|
101.07
|
|
Natural gas ($/mcf)
|
7.29
|
6.00
|
7.15
|
|
|
6.83
|
6.17
|
Production mix (% of production)
|
|
|
|
|
|
|
|
|
% priced with reference to WTI
|
25%
|
24%
|
25%
|
|
|
25%
|
24%
|
|
% priced with reference to AECO
|
17%
|
17%
|
14%
|
|
|
16%
|
16%
|
|
% priced with reference to TTF
|
15%
|
14%
|
17%
|
|
|
16%
|
17%
|
|
% priced with reference to Dated Brent
|
43%
|
45%
|
44%
|
|
|
43%
|
43%
|
Netbacks ($/boe) (1)
|
|
|
|
|
|
|
|
|
Operating netback
|
61.35
|
61.91
|
57.54
|
|
|
60.43
|
55.48
|
|
Fund flows from operations netback
|
43.32
|
43.60
|
46.07
|
|
|
43.94
|
40.96
|
|
Operating expenses
|
12.74
|
12.17
|
14.18
|
|
|
12.84
|
13.10
|
Average reference prices
|
|
|
|
|
|
|
|
|
WTI (US $/bbl)
|
97.46
|
105.82
|
88.18
|
|
|
97.97
|
94.20
|
|
Edmonton Sweet index (US $/bbl)
|
82.53
|
101.10
|
84.86
|
|
|
90.40
|
86.42
|
|
Dated Brent (US $/bbl)
|
109.27
|
110.37
|
110.02
|
|
|
108.66
|
111.58
|
|
AECO ($/GJ)
|
3.35
|
2.31
|
3.05
|
|
|
3.01
|
2.26
|
|
TTF ($/GJ)
|
10.65
|
9.94
|
9.78
|
|
|
10.29
|
9.51
|
Average foreign currency exchange rates
|
|
|
|
|
|
|
|
|
CDN $/US $
|
1.05
|
1.04
|
0.99
|
|
|
1.03
|
1.00
|
|
CDN $/Euro
|
1.43
|
1.38
|
1.29
|
|
|
1.37
|
1.29
|
Share information ('000s)
|
Shares outstanding - basic
|
102,123
|
101,787
|
99,135
|
|
|
102,123
|
99,135
|
Shares outstanding - diluted (1)
|
104,869
|
104,195
|
101,913
|
|
|
104,869
|
101,913
|
Weighted average shares outstanding - basic
|
101,961
|
101,613
|
98,944
|
|
|
100,969
|
98,016
|
Weighted average shares outstanding - diluted (1)
|
103,426
|
102,763
|
100,425
|
|
|
102,467
|
99,294
|
(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.
|
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is Management's Discussion and Analysis ("MD&A"), dated
February 27, 2014, of Vermilion Energy Inc.'s ("Vermilion", "we",
"our", "us" or the "Company") operating and financial results as at and
for the three months and year ended December 31, 2013 compared with the
corresponding periods in the prior year.
This discussion should be read in conjunction with the audited
consolidated financial statements for the year ended December 31, 2013
and 2012, together with the 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 audited consolidated financial statements for the year ended
December 31, 2013 and comparative information have been prepared in
Canadian dollars, except where another currency has been indicated, and
in accordance with International Financial Reporting Standards ("IFRS"
or, alternatively, "GAAP") as issued by the International Accounting
Standards Board.
This MD&A includes references to certain financial measures which do not
have standardized meanings prescribed by IFRS. 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: Includes revenues and expenditures related
directly to our assets in Alberta.
-
France business unit: Relates to our operations in France in the Paris
and Aquitaine Basins.
-
Australia business unit: Relates to our operations in the Wandoo
offshore crude oil field.
-
Netherlands business unit: Relates to our operations in the Netherlands.
-
Ireland business unit: Relates to our 18.5% non-operated interest in the
offshore Corrib natural gas 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.
NEW COUNTRY ENTRY
In November, 2013, we announced an agreement to acquire a 25%
contractual participation interest in a four-partner consortium in
Germany from GDF Suez S.A. The acquisition was subsequently completed
in February of 2014, and will enable us to participate in the
exploration and development, production and transportation of natural
gas from the assets held by the consortium. The assets are comprised
of four gas producing fields across eleven production licenses and are
characterized by a low effective decline rate of approximately 16%
annually. The acquired assets are expected to contribute approximately
2,300 boe/d of production in 2014, and include both exploration and
production licenses that comprise a total of 204,000 gross acres, of
which 85% is in the exploration license. The acquisition represents
Vermilion's entry into the German exploration and production business,
a producing region with a long history of oil and gas development
activity, low political risk, and strong marketing fundamentals. The
acquisition provides us with entry into this sizable market, in the
form of free cash flow generating, low-decline assets with near-term
development inventory in addition to longer-term, low-permeability gas
prospectivity. Entry into Germany is in keeping with our European
focus, and will increase our exposure to the strong fundamentals and
pricing of European natural gas markets. We believe that our
conventional and unconventional expertise, coupled with new access to
proprietary technical data, will position us strongly for future
development and expansion opportunities in both Germany and the greater
European region.
2013 REVIEW AND 2014 GUIDANCE
On November 7, 2013, concurrent with our release of 2014 guidance and
our announcement of the dividend increase, we updated our 2013 capital
expenditure guidance to $530 million. This represented an increase of
approximately $45 million from our original guidance of $485 million.
The increase was attributable primarily to the impact of a weaker
Canadian dollar as compared to foreign exchange rates at the time of
our original guidance, a delay in the timing of rig arrival for our
Australian drill program (originally anticipated to occur in late
2012), and minor additions to our capital work scope during 2013 (such
as the addition of the Champotran southern extension well in France).
The difference between 2013 guidance of $530 million and 2013 actual
capital expenditures of $543 million was largely due to increased
Cardium activity partially offset by activity delays in the
Netherlands.
Following both the first and second quarters, we increased our original
production guidance of 39,000-40,500 boe/d to guidance of 39,500-40,500
boe/d and 40,500-41,000 boe/d, respectively. The guidance increases
were primarily driven by better-than-expected results from our capital
program.
The following table summarizes our 2013 actual results compared to
guidance and our 2014 guidance:
|
|
|
Date
|
Capital Expenditures ($MM)
|
Production (boe/d)
|
2013 Guidance
|
|
|
November 14, 2012
|
485
|
39,000 to 40,500
|
2013 Guidance - Update
|
|
|
May 1, 2013
|
485
|
39,500 to 40,500
|
2013 Guidance - Update
|
|
|
August 1, 2013
|
485
|
40,500 to 41,000
|
2013 Guidance - Update
|
|
|
November 7, 2013
|
530
|
40,500 to 41,000
|
2013 Actual
|
|
|
February 27, 2014
|
543
|
41,005
|
2014 Guidance
|
|
|
November 7, 2013
|
555
|
45,000 to 46,000
|
SHAREHOLDER RETURN
Vermilion strives to provide investors with reliable and growing
dividends in addition to sustainable, global production growth. The
following table, as of December 31, 2013, 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
|
$2.40
|
|
$6.96
|
|
$11.52
|
Capital appreciation per Vermilion share
|
$10.38
|
|
$16.13
|
|
$37.16
|
Total return per Vermilion share
|
24.6%
|
|
50.0%
|
|
193.3%
|
Annualized total return per Vermilion share
|
24.6%
|
|
14.5%
|
|
24.0%
|
Annualized total return on the S&P TSX High Income Energy Index
|
13.8%
|
|
(6.1%)
|
|
5.9%
|
(1)
|
The above table includes non-GAAP financial measures which may not be
comparable to other companies. Please see the "ADDITIONAL AND NON-GAAP
FINANCIAL MEASURES" section.
|
CONSOLIDATED RESULTS OVERVIEW
|
|
Three Months Ended
|
|
% change
|
|
|
Year Ended
|
|
% change
|
|
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
Q4/13 vs.
|
Q4/13 vs.
|
|
|
Dec 31,
|
Dec 31,
|
|
2013 vs.
|
|
|
2013
|
2013
|
2012
|
|
Q3/13
|
Q4/12
|
|
|
2013
|
2012
|
|
2012
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
26,039
|
26,664
|
23,699
|
|
(2%)
|
10%
|
|
|
25,741
|
23,971
|
|
7%
|
|
NGLs (bbls/d)
|
1,761
|
1,945
|
1,176
|
|
(9%)
|
50%
|
|
|
1,730
|
1,299
|
|
33%
|
|
Natural gas (mmcf/d)
|
78.96
|
77.41
|
68.34
|
|
2%
|
16%
|
|
|
81.21
|
75.20
|
|
8%
|
|
Total (boe/d)
|
40,960
|
41,510
|
36,265
|
|
(1%)
|
13%
|
|
|
41,005
|
37,803
|
|
8%
|
|
Build (draw) in inventory (bbl)
|
(10,192)
|
18,946
|
259,481
|
|
|
|
|
|
(228,954)
|
213,472
|
|
|
Financial metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fund flows from operations ($M)
|
163,660
|
165,645
|
141,737
|
|
(1%)
|
15%
|
|
|
667,526
|
557,728
|
|
20%
|
|
|
Per share ($/basic share)
|
1.61
|
1.63
|
1.43
|
|
(1%)
|
13%
|
|
|
6.61
|
5.69
|
|
16%
|
|
Net earnings ($M)
|
101,510
|
67,796
|
56,914
|
|
50%
|
78%
|
|
|
327,641
|
190,622
|
|
72%
|
|
|
Per share ($/basic share)
|
1.00
|
0.67
|
0.58
|
|
49%
|
72%
|
|
|
3.24
|
1.94
|
|
67%
|
|
Cash flows from operating activities ($M)
|
177,003
|
158,236
|
99,907
|
|
12%
|
77%
|
|
|
705,025
|
496,580
|
|
42%
|
|
Net debt ($M)
|
749,685
|
700,286
|
677,231
|
|
7%
|
11%
|
|
|
749,685
|
677,231
|
|
11%
|
|
Cash dividends ($/share)
|
0.60
|
0.60
|
0.57
|
|
-
|
5%
|
|
|
2.40
|
2.28
|
|
5%
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
148,478
|
135,661
|
157,035
|
|
9%
|
(5%)
|
|
|
542,726
|
452,538
|
|
20%
|
|
Acquisitions ($M)
|
29,103
|
7,586
|
209,254
|
|
|
|
|
|
36,689
|
315,438
|
|
|
|
Gross wells drilled
|
21.00
|
21.00
|
26.00
|
|
|
|
|
|
76.00
|
78.00
|
|
|
|
Net wells drilled
|
16.65
|
16.26
|
17.70
|
|
|
|
|
|
64.21
|
56.10
|
|
|
Operational review
-
Recorded average production of 41,005 boe/d during 2013, reflecting
production growth in all of our producing regions and year-over-year
consolidated production growth of 8%. Production growth was achieved
through continued development in the Cardium and Mannville plays in
Canada, production additions from the 2013 drilling programs in France
and Australia, and incremental production in the Netherlands from our
Q4 2013 acquisition.
-
Activity during the year included capital expenditures of $542.7 million
and acquisitions of $36.7 million. The majority of the capital
expenditures related to continued development of the Cardium and
Mannville plays in Canada, successful drilling campaigns in France and
Australia, and tunneling in Ireland. In addition, during Q4 2013,
Vermilion completed a small acquisition in the Netherlands for $27.5
million which included nine operated onshore concessions (six in
production or development and three exploration) and a non-operated
interest in one offshore concession.
Financial review
Net earnings
-
For the three months and year ended December 31, 2013, consolidated net
earnings was $101.5 million ($1.00/basic share) and $327.6 million
($3.24/basic share), an increase of 78% and 72% versus the same periods
in 2012.
-
The year-over-year increases resulted primarily from higher production
in all our producing business units, draws in inventory during the
year, stronger Canadian pricing for crude oil and natural gas,
unrealized foreign exchange gains, and an impairment recovery. These
increases were partially offset by increased current income taxes as a
result of increased taxable income combined with tax provisions
recorded for tax assessments in France.
-
Net earnings for Q4 2013 increased by approximately 50% versus Q3 2013.
The quarter-over-quarter increase occurred despite relatively
consistent operating results due to increased unrealized foreign
exchange gains and the aforementioned impairment recovery, partially
offset by increased equity based compensation and deferred tax expense.
-
Unrealized foreign exchange gains of $22.3 million and $52.0 million for
the three months and year ended December 31, 2013 were the result of
the Euro strengthening significantly versus the Canadian dollar and the
resulting impact on our Euro denominated financial assets.
-
The impairment recovery recognized during Q4 2013 of $47.4 million
related to impairment charges previously recognized in 2011 and 2012.
The impairment recovery resulted from increased proved and probable
reserves of natural gas and natural gas liquids, due primarily to the
successful application of horizontal drilling and multi-stage
fracturing technology to the previously impaired cash generating unit.
Cash flows from operating activities
-
Increased cash flow from operating activities by 42% year-over year.
This increase resulted from increased production in all of Vermilion's
producing regions, stronger Canadian pricing for crude oil and natural
gas, and timing differences pertaining to working capital.
-
Increased cash flow from operating activities for Q4 2013 by 77% as
compared to Q4 2012. The year-over-year increase was primarily the
result of higher production in all our producing business units,
increases in all relevant commodity prices, timing differences
pertaining to working capital, and the absence of a large build in
inventory which occurred in Q4 2012.
Fund flows from operations
-
Generated fund flows from operations of $667.5 million ($6.61/basic
share) during 2013, an increase of 20% year-over-year. This increase
in fund flows from operations resulted from increased production in all
of Vermilion's producing regions coupled with stronger Canadian pricing
for crude oil and natural gas.
Net debt
-
Maintained a strong balance sheet with closing net debt of $749.7
million, representing 1.1 times fund flows from operations. The
year-over-year increase in net debt was primarily a result of our
aforementioned acquisition in the Netherlands coupled with current year
development capital expenditures in Ireland.
Dividends
-
Paid a dividend of $0.20 per common share per month during 2013 and in
November 2013 announced a 7.5% increase in the monthly dividend to
$0.215 per common share per month (effective for the January 2014
dividend paid on February 17, 2014). This was our second consecutive
annual dividend increase.
COMMODITY PRICES
|
Three Months Ended
|
|
% change
|
|
|
Year Ended
|
|
% change
|
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
Q4/13 vs.
|
Q4/13 vs.
|
|
|
Dec 31,
|
Dec 31,
|
|
2013 vs.
|
|
2013
|
2013
|
2012
|
|
Q3/13
|
Q4/12
|
|
|
2013
|
2012
|
|
2012
|
Average reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl)
|
97.46
|
105.82
|
88.18
|
|
(8%)
|
11%
|
|
|
97.97
|
94.20
|
|
4%
|
Edmonton Sweet index (US $/bbl)
|
82.53
|
101.10
|
84.86
|
|
(18%)
|
(3%)
|
|
|
90.40
|
86.42
|
|
5%
|
Dated Brent (US $/bbl)
|
109.27
|
110.37
|
110.02
|
|
(1%)
|
(1%)
|
|
|
108.66
|
111.58
|
|
(3%)
|
AECO ($/GJ)
|
3.35
|
2.31
|
3.05
|
|
45%
|
10%
|
|
|
3.01
|
2.26
|
|
33%
|
TTF ($/GJ)
|
10.65
|
9.94
|
9.78
|
|
7%
|
9%
|
|
|
10.29
|
9.51
|
|
8%
|
TTF (€/GJ)
|
7.45
|
7.20
|
7.58
|
|
3%
|
(2%)
|
|
|
7.51
|
7.37
|
|
2%
|
Average realized prices ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
61.10
|
63.56
|
58.80
|
|
(4%)
|
4%
|
|
|
61.14
|
54.89
|
|
11%
|
France
|
112.84
|
107.08
|
102.26
|
|
5%
|
10%
|
|
|
106.26
|
105.13
|
|
1%
|
Netherlands
|
67.88
|
61.44
|
60.96
|
|
10%
|
11%
|
|
|
64.08
|
58.69
|
|
9%
|
Australia
|
124.63
|
120.95
|
115.22
|
|
3%
|
8%
|
|
|
119.38
|
117.03
|
|
2%
|
Consolidated
|
86.04
|
86.10
|
78.40
|
|
-
|
10%
|
|
|
83.83
|
79.51
|
|
5%
|
Production mix (% of production)
|
|
|
|
|
|
|
|
|
|
|
|
|
% priced with reference to WTI
|
25%
|
24%
|
25%
|
|
|
|
|
|
25%
|
24%
|
|
|
% priced with reference to AECO
|
17%
|
17%
|
14%
|
|
|
|
|
|
16%
|
16%
|
|
|
% priced with reference to TTF
|
15%
|
14%
|
17%
|
|
|
|
|
|
16%
|
17%
|
|
|
% priced with reference to Dated Brent
|
43%
|
45%
|
44%
|
|
|
|
|
|
43%
|
43%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reference prices
-
Dated Brent remained relatively consistent from Q3 2013 to Q4 2013 while
WTI and the Edmonton Sweet index decreased by 8% and 18%,
respectively. The decreases in WTI and the Edmonton Sweet index were
attributable to refinery outages and increasing supply.
-
AECO increased 45% from Q3 2013 to Q4 2013 as a result of strong winter
demand for natural gas in North America.
-
TTF in Canadian dollar terms increased by 7% from Q3 2013 to Q4 2013,
benefiting from the strengthening of the Euro.
Realized prices
-
Our consolidated realized price remained relatively consistent
quarter-over-quarter at $86.04/boe. While North American crude oil
pricing decreased in Q4 2013, the impact of this decrease was mostly
offset by higher pricing for our Canadian and Netherlands natural gas
production and continued strong pricing for our crude oil production in
Australia.
-
Our consolidated realized price increased by 5% for 2013 as compared to
2012. This increase was primarily due to stronger North American crude
oil and natural gas pricing coupled with foreign exchange benefits
resulting from the weakening of the Canadian dollar versus both the
Euro and the US dollar.
FUND FLOWS FROM OPERATIONS
|
Three Months Ended
|
|
|
Year Ended
|
|
Dec 31, 2013
|
|
Sept 30, 2013
|
|
Dec 31, 2012
|
|
|
Dec 31, 2013
|
|
Dec 31, 2012
|
|
$M
|
$/boe
|
|
$M
|
$/boe
|
|
$M
|
$/boe
|
|
|
$M
|
$/boe
|
|
$M
|
$/boe
|
Petroleum and natural gas sales
|
325,108
|
86.04
|
|
327,185
|
86.10
|
|
241,233
|
78.40
|
|
|
1,273,835
|
83.83
|
|
1,083,103
|
79.51
|
Royalties
|
(17,616)
|
(4.66)
|
|
(18,730)
|
(4.93)
|
|
(11,938)
|
(3.88)
|
|
|
(67,936)
|
(4.47)
|
|
(52,084)
|
(3.82)
|
Petroleum and natural gas revenues
|
307,492
|
81.38
|
|
308,455
|
81.17
|
|
229,295
|
74.52
|
|
|
1,205,899
|
79.36
|
|
1,031,019
|
75.69
|
Transportation expense
|
(9,081)
|
(2.40)
|
|
(6,549)
|
(1.72)
|
|
(5,458)
|
(1.77)
|
|
|
(28,924)
|
(1.90)
|
|
(24,113)
|
(1.77)
|
Operating expense
|
(48,140)
|
(12.74)
|
|
(46,246)
|
(12.17)
|
|
(43,634)
|
(14.18)
|
|
|
(195,043)
|
(12.84)
|
|
(178,442)
|
(13.10)
|
General and administration
|
(13,954)
|
(3.69)
|
|
(12,033)
|
(3.17)
|
|
(8,888)
|
(2.89)
|
|
|
(49,910)
|
(3.28)
|
|
(43,773)
|
(3.21)
|
Corporate income taxes
|
(43,065)
|
(11.40)
|
|
(46,453)
|
(12.22)
|
|
(21,470)
|
(6.98)
|
|
|
(161,794)
|
(10.65)
|
|
(121,843)
|
(8.94)
|
PRRT
|
(17,173)
|
(4.55)
|
|
(15,649)
|
(4.12)
|
|
(1,598)
|
(0.52)
|
|
|
(56,565)
|
(3.72)
|
|
(60,070)
|
(4.41)
|
Interest expense
|
(10,049)
|
(2.66)
|
|
(10,109)
|
(2.66)
|
|
(7,656)
|
(2.49)
|
|
|
(38,183)
|
(2.51)
|
|
(27,586)
|
(2.03)
|
Realized loss on derivative instruments
|
(1,300)
|
(0.34)
|
|
(4,765)
|
(1.25)
|
|
(1,559)
|
(0.51)
|
|
|
(7,082)
|
(0.47)
|
|
(12,737)
|
(0.93)
|
Realized foreign exchange (loss) gain
|
(1,294)
|
(0.34)
|
|
(1,227)
|
(0.32)
|
|
2,459
|
0.81
|
|
|
(1,866)
|
(0.12)
|
|
2,804
|
0.21
|
Realized other income (expense)
|
224
|
0.06
|
|
221
|
0.06
|
|
246
|
0.08
|
|
|
994
|
0.07
|
|
(7,531)
|
(0.55)
|
Fund flows from operations
|
163,660
|
43.32
|
|
165,645
|
43.60
|
|
141,737
|
46.07
|
|
|
667,526
|
43.94
|
|
557,728
|
40.96
|
The following table shows a reconciliation of the change in fund flows
from operations:
($M)
|
Q4/13 vs. Q3/13
|
Q4/13 vs. Q4/12
|
2013 vs. 2012
|
Fund flows from operations - Comparative period
|
165,645
|
141,737
|
557,728
|
Sales volume variance:
|
|
|
|
|
Canada
|
4,476
|
13,090
|
38,747
|
|
France
|
(15,471)
|
12,675
|
60,108
|
|
Netherlands
|
8,324
|
4,113
|
4,215
|
|
Australia
|
(3,984)
|
26,888
|
26,091
|
Pricing variance on sold volumes:
|
|
|
|
|
WTI
|
(10,805)
|
6,136
|
25,464
|
|
AECO
|
3,696
|
665
|
13,592
|
|
Dated Brent
|
7,942
|
16,230
|
10,688
|
|
TTF
|
3,745
|
4,078
|
11,827
|
Changes in:
|
|
|
|
|
Realized derivatives
|
3,465
|
259
|
5,655
|
|
Royalties
|
1,114
|
(5,678)
|
(15,852)
|
|
Operating expense
|
(1,894)
|
(4,506)
|
(16,601)
|
|
Transportation
|
(2,532)
|
(3,623)
|
(4,811)
|
|
Interest
|
60
|
(2,393)
|
(10,597)
|
|
General and administration
|
(1,921)
|
(5,066)
|
(6,137)
|
|
Realized other income
|
3
|
(22)
|
8,525
|
|
Realized foreign exchange
|
(67)
|
(3,753)
|
(4,670)
|
|
Corporate income taxes
|
3,388
|
(21,595)
|
(39,951)
|
|
PRRT
|
(1,524)
|
(15,575)
|
3,505
|
Fund flows from operations - Current Period
|
163,660
|
163,660
|
667,526
|
Fund flows from operations for Q4 2013 was approximately 1% ($2.0
million) lower than Q3. This slight decrease occurred as a result of
declines in the Edmonton Sweet index, which was partially offset by
increased pricing for natural gas and for our crude oil production in
Australia.
Fund flows from operations for the three months and year ended December
31, 2013 was approximately 15% ($21.9 million) and 20% ($109.8 million)
higher, respectively, than the same periods in 2012. These increases
were primarily the result of higher production in all our producing
business units, large draws in inventory during the quarter and full
year periods, and increases in all relevant commodity prices. These
increases were partially offset by increased current income taxes as a
result of increased taxable income combined with tax provisions
recorded for tax assessments in France.
Fluctuations in fund flows from operations (and correspondingly net
earnings and cash flows from operating activities) may occur as a
result of changes in commodity prices and costs to produce petroleum
and natural gas. In addition, fund flows from operations may be highly
affected by the timing of crude oil shipments in Australia and France.
When crude oil inventory is built up, the related operating expense,
royalties, and depletion expense are deferred and carried as inventory
on 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 Alberta at West Pembina near Drayton
Valley, Slave Lake and Central Alberta.
-
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 liquids-rich gas (3,200m depth) - in appraisal phase
-
Canadian cash flows are fully tax-sheltered for the foreseeable future.
Operational review
|
|
Three Months Ended
|
|
% change
|
|
|
Year Ended
|
|
% change
|
|
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
Q4/13 vs.
|
Q4/13 vs.
|
|
|
Dec 31,
|
Dec 31,
|
|
2013 vs.
|
Canada business unit
|
2013
|
2013
|
2012
|
|
Q3/13
|
Q4/12
|
|
|
2013
|
2012
|
|
2012
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
8,719
|
7,969
|
7,983
|
|
9%
|
9%
|
|
|
8,387
|
7,659
|
|
10%
|
|
NGLs (bbls/d)
|
1,699
|
1,897
|
1,106
|
|
(10%)
|
54%
|
|
|
1,666
|
1,232
|
|
35%
|
|
Natural gas (mmcf/d)
|
41.43
|
43.40
|
31.41
|
|
(5%)
|
32%
|
|
|
42.39
|
37.50
|
|
13%
|
|
Total (boe/d)
|
17,322
|
17,099
|
14,323
|
|
1%
|
21%
|
|
|
17,117
|
15,142
|
|
13%
|
Production mix (% of total)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
50%
|
47%
|
56%
|
|
|
|
|
|
49%
|
51%
|
|
|
|
NGLs
|
10%
|
11%
|
8%
|
|
|
|
|
|
10%
|
8%
|
|
|
|
Natural gas
|
40%
|
42%
|
36%
|
|
|
|
|
|
41%
|
41%
|
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
77,245
|
62,270
|
82,844
|
|
24%
|
(7%)
|
|
|
241,197
|
271,774
|
|
(11%)
|
|
Acquisitions ($M)
|
1,603
|
7,586
|
-
|
|
|
|
|
|
9,189
|
69
|
|
|
|
Gross wells drilled
|
21.00
|
21.00
|
26.00
|
|
|
|
|
|
69.00
|
76.00
|
|
|
|
Net wells drilled
|
16.65
|
16.26
|
17.70
|
|
|
|
|
|
57.21
|
54.70
|
|
|
Production
-
Production in Canada increased by 1% quarter-over-quarter and by 13%
year-over-year.
-
Year-over-year increase was largely attributable to continued
development in the Cardium, supplemented by Mannville wells brought on
production during the year.
Activity review
-
Vermilion drilled 21 (16.6 net) wells during Q4 2013.
-
In 2013, Vermilion drilled 69 (57.2 net) wells.
Cardium
-
In the Cardium, we drilled 19 (15.6 net) wells and brought 16 gross
operated wells on production during Q4 2013. Eight of the wells
drilled during Q4 2013 were long reach wells (four 1.5-mile, three
2-mile, and one 2.3-mile long well).
-
Since 2009, we have drilled or participated in 238 (170.9 net) wells in
the Cardium.
-
Average well costs, normalized on a per section basis, are approximately
$3.0 million per section (2009 - $5.0 million per section).
-
Per boe operating costs are less than $5.25/boe for operated production.
-
In 2014, we plan to drill or participate in 36 (30.3 net) Cardium wells.
-
Cardium expenditures are expected to represent approximately 60% of
planned Canadian development expenditures in 2014.
Mannville
-
During Q4 2013, in the Mannville, we drilled two (1.0 net) wells and
brought 1.2 net wells on production. In 2013, we drilled and placed on
production six (3.7 net) Mannville wells.
-
In 2014, we plan to drill eight (5.7 net) Mannville wells.
-
Mannville expenditures are expected to represent approximately 20% of
planned Canadian development expenditures in 2014.
Duvernay
-
To date, we have drilled three vertical stratigraphic test wells, which
confirmed our placement inside the condensate-rich window.
-
In 2014, we plan to drill two horizontal Duvernay wells, the first of
which is currently in progress.
Financial review
|
|
Three Months Ended
|
|
% change
|
|
|
Year Ended
|
|
% change
|
Canada business unit
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
Q4/13 vs.
|
Q4/13 vs.
|
|
|
Dec 31,
|
Dec 31,
|
|
2013 vs.
|
($M except as indicated)
|
2013
|
2013
|
2012
|
|
Q3/13
|
Q4/12
|
|
|
2013
|
2012
|
|
2012
|
|
Sales
|
97,367
|
100,000
|
77,476
|
|
(3%)
|
26%
|
|
|
382,005
|
304,202
|
|
26%
|
|
Royalties
|
(11,039)
|
(11,156)
|
(7,401)
|
|
(1%)
|
49%
|
|
|
(40,891)
|
(31,667)
|
|
29%
|
|
Transportation expense
|
(4,102)
|
(3,272)
|
(1,922)
|
|
25%
|
113%
|
|
|
(12,254)
|
(8,321)
|
|
47%
|
|
Operating expense
|
(13,218)
|
(12,770)
|
(14,514)
|
|
4%
|
(9%)
|
|
|
(55,804)
|
(55,418)
|
|
1%
|
|
General and administration
|
(2,478)
|
(2,675)
|
(1,765)
|
|
(7%)
|
40%
|
|
|
(12,979)
|
(12,344)
|
|
5%
|
|
Fund flows from operations
|
66,530
|
70,127
|
51,874
|
|
(5%)
|
28%
|
|
|
260,077
|
196,452
|
|
32%
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
61.10
|
63.56
|
58.80
|
|
(4%)
|
4%
|
|
|
61.14
|
54.89
|
|
11%
|
|
Royalties
|
(6.93)
|
(7.09)
|
(5.62)
|
|
(2%)
|
23%
|
|
|
(6.55)
|
(5.71)
|
|
15%
|
|
Transportation expense
|
(2.57)
|
(2.08)
|
(1.46)
|
|
24%
|
76%
|
|
|
(1.96)
|
(1.50)
|
|
31%
|
|
Operating expense
|
(8.29)
|
(8.12)
|
(11.01)
|
|
2%
|
(25%)
|
|
|
(8.93)
|
(10.00)
|
|
(11%)
|
|
General and administration
|
(1.60)
|
(2.04)
|
(1.34)
|
|
(22%)
|
19%
|
|
|
(2.24)
|
(2.23)
|
|
-
|
|
Fund flows from operations netback
|
41.71
|
44.23
|
39.37
|
|
(6%)
|
6%
|
|
|
41.46
|
35.45
|
|
17%
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI (US $/bbl)
|
97.46
|
105.82
|
88.18
|
|
(8%)
|
11%
|
|
|
97.97
|
94.20
|
|
4%
|
|
Edmonton Sweet index (US $/bbl)
|
82.53
|
101.10
|
84.86
|
|
(18%)
|
(3%)
|
|
|
90.40
|
86.42
|
|
5%
|
|
AECO ($/GJ)
|
3.35
|
2.31
|
3.05
|
|
45%
|
10%
|
|
|
3.01
|
2.26
|
|
33%
|
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 U.S. The realized
price of our natural gas in Canada is based on the AECO spot price in
Canada.
-
The decrease in sales per boe for Q4 2013 as compared to Q3 2013 was
primarily the result of 18% lower Edmonton Sweet index pricing,
partially offset by a 45% increase in the AECO reference price.
-
The increase in sales per boe for the three months and year ended
December 31, 2013 as compared to the same periods in 2012 was primarily
the result of a 10% and 33% increase, respectively, in the AECO
reference price.
Royalties
-
Royalty expense as a percentage of sales was consistent
quarter-over-quarter.
-
The increase in royalty expense as a percentage of sales from 10% to 11%
for the three months and year ended December 31, 2013 as compared to
the same periods in 2012 was the result of the timing of placing
Cardium wells on production due to the associated royalty incentive on
initial production volumes.
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 increased for the three months and year
ended December 31, 2013 compared to the same periods in 2012 as a
result of increased crude oil production subject to transportation
costs.
Operating expense
-
Operating expense per boe was lower for the year ended December 31, 2013
as operating expense remained relatively stable while production
increased by 13% year-over-year.
-
Operating expense for Q4 2013 was lower than Q4 2012 as the 2012 period
operating expense included higher turnaround activity and downhole
work.
General and administration
-
Year-over-year, general and administration expense per boe remained
steady. Fluctuations in the presented quarters relates primarily to the
timing of expenditures.
FRANCE BUSINESS UNIT
Overview
-
Entered France in 1997 and completed three subsequent acquisitions,
including two in 2012.
-
Largest independent 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
|
|
|
Year Ended
|
|
% change
|
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
Q4/13 vs.
|
Q4/13 vs.
|
|
|
Dec 31,
|
Dec 31,
|
|
2013 vs.
|
France business unit
|
2013
|
2013
|
2012
|
|
Q3/13
|
Q4/12
|
|
|
2013
|
2012
|
|
2012
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
11,131
|
11,625
|
9,843
|
|
(4%)
|
13%
|
|
|
10,873
|
9,952
|
|
9%
|
|
Natural gas (mmcf/d)
|
-
|
5.23
|
3.91
|
|
(100%)
|
(100%)
|
|
|
3.40
|
3.59
|
|
(5%)
|
|
Total (boe/d)
|
11,131
|
12,496
|
10,495
|
|
(11%)
|
6%
|
|
|
11,440
|
10,550
|
|
8%
|
Inventory (mbbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Opening crude oil inventory
|
226
|
202
|
246
|
|
|
|
|
|
354
|
187
|
|
|
|
Adjustments
|
-
|
-
|
-
|
|
|
|
|
|
5
|
-
|
|
|
|
Crude oil production
|
1,024
|
1,069
|
906
|
|
|
|
|
|
3,969
|
3,642
|
|
|
|
Crude oil sales
|
(981)
|
(1,045)
|
(798)
|
|
|
|
|
|
(4,059)
|
(3,475)
|
|
|
|
Closing crude oil inventory
|
269
|
226
|
354
|
|
|
|
|
|
269
|
354
|
|
|
Production mix (% of total)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
|
100%
|
93%
|
94%
|
|
|
|
|
|
95%
|
94%
|
|
|
|
Natural gas
|
-
|
7%
|
6%
|
|
|
|
|
|
5%
|
6%
|
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
31,899
|
23,664
|
20,958
|
|
35%
|
52%
|
|
|
100,378
|
47,382
|
|
112%
|
|
Acquisitions ($M)
|
-
|
-
|
74,947
|
|
|
|
|
|
-
|
181,062
|
|
|
|
Gross wells drilled
|
-
|
-
|
-
|
|
|
|
|
|
5.00
|
-
|
|
|
|
Net wells drilled
|
-
|
-
|
-
|
|
|
|
|
|
5.00
|
-
|
|
|
Production
-
Quarter-over-quarter production decrease of 11% and year-over-year
production growth of 8%.
-
Q4 2013 vs. Q3 2013 decrease was mainly due to our gas production being
shut-in at Vic Bihl. In late September 2013, the third party Lacq
processing facility, which processed our Vic Bihl production of
approximately 700 boe/d, was permanently shut in. As a result, our Vic
Bihl gas production has been temporarily shut in while preparations to
transfer an alternative facility are completed. We expect approximately
140 boe/d will be back on-stream in Q3, with the remainder not
anticipated to be back on production until late-2015.
-
Year-over-year growth driven by production from our five-well drilling
program in Champotran, which was brought on late in the second quarter,
and production additions from the ZaZa acquisition at the end of 2012.
-
The five wells drilled in 2013 produced at an average rate per well of
250 bbls/d with minimal water during the fourth quarter of 2013.
-
Production remained predominately weighted to Brent crude at
approximately 95% of production for 2013, and 100% in Q4 2013.
Activity review
-
During Q4 2013, we converted a previous producing well to an injection
well to add additional injection capacity to our waterflood program at
Champotran.
-
During Q4 2013, we also completed a number of workovers, pipeline and
facility integrity projects, and prepared for our 2014 capital program.
-
In 2013, we started increasing our France-based technical staff to
identify and execute additional investment opportunities.
-
In 2013, we completed a successful five-well drilling campaign in the
Champotran field, adding significant production, reserves, and
confirming 20 potential future drilling locations.
-
In 2014, we are planning a nine-well drilling program in the Champotran,
Cazaux, Parentis, and Tamaris fields. In addition, we are planning an
estimated 18-well workover program.
Financial review
|
|
Three Months Ended
|
|
% change
|
|
|
Year Ended
|
|
% change
|
France business unit
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
Q4/13 vs.
|
Q4/13 vs.
|
|
|
Dec 31,
|
Dec 31,
|
|
2013 vs.
|
($M except as indicated)
|
2013
|
2013
|
2012
|
|
Q3/13
|
Q4/12
|
|
|
2013
|
2012
|
|
2012
|
|
Sales
|
110,757
|
120,574
|
87,702
|
|
(8%)
|
26%
|
|
|
453,315
|
388,410
|
|
17%
|
|
Royalties
|
(6,577)
|
(7,574)
|
(4,537)
|
|
(13%)
|
45%
|
|
|
(27,045)
|
(20,417)
|
|
32%
|
|
Transportation expense
|
(4,622)
|
(2,713)
|
(1,854)
|
|
70%
|
149%
|
|
|
(12,505)
|
(8,236)
|
|
52%
|
|
Operating expense
|
(15,524)
|
(14,599)
|
(13,699)
|
|
6%
|
13%
|
|
|
(66,997)
|
(54,907)
|
|
22%
|
|
General and administration
|
(5,080)
|
(4,964)
|
(4,779)
|
|
2%
|
6%
|
|
|
(19,657)
|
(15,009)
|
|
31%
|
|
Current income taxes
|
(28,024)
|
(31,717)
|
(13,335)
|
|
(12%)
|
110%
|
|
|
(94,524)
|
(63,006)
|
|
50%
|
|
Fund flows from operations
|
50,930
|
59,007
|
49,498
|
|
(14%)
|
3%
|
|
|
232,587
|
226,835
|
|
3%
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
112.84
|
107.08
|
102.26
|
|
5%
|
10%
|
|
|
106.26
|
105.13
|
|
1%
|
|
Royalties
|
(6.70)
|
(6.73)
|
(5.29)
|
|
-
|
27%
|
|
|
(6.34)
|
(5.53)
|
|
15%
|
|
Transportation expense
|
(4.71)
|
(2.41)
|
(2.16)
|
|
95%
|
118%
|
|
|
(2.93)
|
(2.23)
|
|
31%
|
|
Operating expense
|
(15.82)
|
(12.97)
|
(15.97)
|
|
22%
|
(1%)
|
|
|
(15.70)
|
(14.86)
|
|
6%
|
|
General and administration
|
(5.18)
|
(4.41)
|
(5.57)
|
|
17%
|
(7%)
|
|
|
(4.61)
|
(4.06)
|
|
14%
|
|
Current income taxes
|
(28.55)
|
(28.17)
|
(15.55)
|
|
1%
|
84%
|
|
|
(22.16)
|
(17.05)
|
|
30%
|
|
Fund flows from operations netback
|
51.88
|
52.39
|
57.72
|
|
(1%)
|
(10%)
|
|
|
54.52
|
61.40
|
|
(11%)
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated Brent (US $/bbl)
|
109.27
|
110.37
|
110.02
|
|
(1%)
|
(1%)
|
|
|
108.66
|
111.58
|
|
(3%)
|
Sales
-
Crude oil production in France is priced with reference to Dated Brent.
-
Sales for the three months and year ended December 31, 2013 increased
versus the same periods in 2012, despite a decrease in the Dated Brent
reference price, due to an increase in sold volumes resulting from new
production brought on from the 2013 drilling campaign in addition to
the weakening of the Canadian dollar.
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).
-
The increase in royalties expense for the three months and year ended
December 31, 2013 versus the same periods in 2012 was primarily the
result of increased R31 royalties associated with incremental
production from our Q4 2012 acquisition as well as production from
wells drilled during our 2013 drilling campaign.
Transportation
-
Transportation expense in France pertains to the shipments of crude oil
by tanker from the Aquitaine Basin to third party refineries.
-
The increase in transportation expense per boe for the three months and
year ended December 31, 2013 versus the comparable periods resulted
from an increased number of shipments from the Aquitaine Basin.
Operating expense
-
The increase in operating expense per boe from Q3 to Q4 2013 was
primarily the result of lower production. Overall operating expense
was 6% higher from Q3 to Q4 2013 primarily as a result of higher
electricity prices.
-
On a year-over-year basis, operating expense per boe increased by 6%
largely as a result of the foreign exchange impact of a weakening
Canadian dollar versus the Euro. Overall operating expense increased
by 22% year-over-year due to the aforementioned foreign exchange
impacts and increased activity associated with higher production.
General and administration
-
General and administration expense per boe for the three months and year
ended December 31, 2013 increased versus the same periods in 2012 due
to additional staffing levels, including staff from our Q4 2012
acquisition as well as additional technical staff to support our
growing operational activities in France.
Current income taxes
-
The year-over-year increase in current income taxes for the three months
and year ended December 31, 2013 as compared to the same periods in
2012 was the result of the increase in fund flows from operations
combined with provisions recognized relating to tax assessments from
tax authorities for prior period tax positions.
NETHERLANDS BUSINESS UNIT
Overview
-
Entered the Netherlands in 2004.
-
Second largest onshore gas producer by volume.
-
Interests includes 16 licenses in the northeast region, 5 licenses in
the central region, and 2 offshore licenses.
-
Licenses include more than 780,000 net acres of undeveloped land.
-
High impact natural gas drilling and development with royalty-free
production.
-
Natural gas produced in the Netherlands is priced off the TTF index,
which receives a significant premium over North American gas prices.
Operational review
|
|
Three Months Ended
|
|
% change
|
|
|
Year Ended
|
|
% change
|
|
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
Q4/13 vs.
|
Q4/13 vs.
|
|
|
Dec 31,
|
Dec 31,
|
|
2013 vs.
|
Netherlands business unit
|
2013
|
2013
|
2012
|
|
Q3/13
|
Q4/12
|
|
|
2013
|
2012
|
|
2012
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d)
|
62
|
48
|
70
|
|
29%
|
(11%)
|
|
|
64
|
67
|
|
(4%)
|
|
Natural gas (mmcf/d)
|
37.53
|
28.78
|
33.03
|
|
30%
|
14%
|
|
|
35.42
|
34.11
|
|
4%
|
|
Total (boe/d)
|
6,318
|
4,845
|
5,574
|
|
30%
|
13%
|
|
|
5,967
|
5,751
|
|
4%
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
15,698
|
8,316
|
8,118
|
|
89%
|
93%
|
|
|
28,543
|
21,324
|
|
34%
|
|
Acquisitions ($M)
|
27,500
|
-
|
-
|
|
|
|
|
|
27,500
|
-
|
|
|
|
Gross wells drilled
|
-
|
-
|
-
|
|
|
|
|
|
-
|
2.00
|
|
|
|
Net wells drilled
|
-
|
-
|
-
|
|
|
|
|
|
-
|
1.40
|
|
|
Production
-
Achieved record annual production with 5,967 boe/d.
-
Quarter-over-quarter production growth of 30% and year-over-year
production growth of 4%.
-
Q4 2013 vs. Q3 2013 increase in production was mainly attributable to
completion of the retrofit of the Middenmeer Treatment Centre and the
associated volumes processed through the 35 mmcf/d facility.
Activity
-
In October 2013, we acquired additional operating interests in nine
operated onshore concessions (six in production or development and
three exploration) and a non-operated interest in one offshore
concession in the Netherlands for approximately $27.5 million.
-
Four of the onshore concessions are located in the northeastern part of
the Netherlands, adjacent to or in close proximity to our existing
concessions. The remaining onshore licenses provide new opportunities
for Vermilion in the central region of the Netherlands.
-
Production from the acquired assets is expected to average approximately
400 boe/d in 2014. The production is comprised of 99% natural gas.
-
The acquisition also added 2.4(1) mmboe of proved plus probable reserves and 298,500 net acres of land, of which approximately 98% is currently
undeveloped.
-
We are currently planning and preparing for a six-well drilling program
in the Netherlands in 2014. The drilling program will include our first
new well on the lands acquired in October 2013.
-
Subsequent to year-end 2013, we were awarded the Ijsselmuiden
exploration concession consisting of approximately 110,500 net
undeveloped acres, increasing our total position in the country to over
800,000 net undeveloped acres.
(1)
|
Estimated proved plus probable reserves attributable to the assets as
evaluated by GLJ in a report dated September 16, 2013, with an
effective date of December 31, 2012.
|
Financial review
|
|
Three Months Ended
|
|
% change
|
|
|
Year Ended
|
|
% change
|
Netherlands business unit
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
Q4/13 vs.
|
Q4/13 vs.
|
|
|
Dec 31,
|
Dec 31,
|
|
2013 vs.
|
($M except as indicated)
|
2013
|
2013
|
2012
|
|
Q3/13
|
Q4/12
|
|
|
2013
|
2012
|
|
2012
|
|
Sales
|
39,451
|
27,382
|
31,260
|
|
44%
|
26%
|
|
|
139,570
|
123,528
|
|
13%
|
|
Operating expense
|
(6,179)
|
(5,209)
|
(5,713)
|
|
19%
|
8%
|
|
|
(20,617)
|
(19,149)
|
|
8%
|
|
General and administration
|
(1,553)
|
(333)
|
(625)
|
|
366%
|
148%
|
|
|
(2,724)
|
(1,329)
|
|
105%
|
|
Current income taxes
|
(8,267)
|
(6,810)
|
(1,102)
|
|
21%
|
650%
|
|
|
(34,132)
|
(25,648)
|
|
33%
|
|
Fund flows from operations
|
23,452
|
15,030
|
23,820
|
|
56%
|
(2%)
|
|
|
82,097
|
77,402
|
|
6%
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
67.88
|
61.44
|
60.96
|
|
10%
|
11%
|
|
|
64.08
|
58.69
|
|
9%
|
|
Operating expense
|
(10.63)
|
(11.69)
|
(11.14)
|
|
(9%)
|
(5%)
|
|
|
(9.47)
|
(9.10)
|
|
4%
|
|
General and administration
|
(2.67)
|
(0.75)
|
(1.22)
|
|
256%
|
119%
|
|
|
(1.25)
|
(0.63)
|
|
98%
|
|
Current income taxes
|
(14.22)
|
(15.28)
|
(2.15)
|
|
(7%)
|
561%
|
|
|
(15.67)
|
(12.18)
|
|
29%
|
|
Fund flows from operations netback
|
40.36
|
33.72
|
46.45
|
|
20%
|
(13%)
|
|
|
37.69
|
36.78
|
|
2%
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TTF ($/GJ)
|
10.65
|
9.94
|
9.78
|
|
7%
|
9%
|
|
|
10.29
|
9.51
|
|
8%
|
|
TTF (€/GJ)
|
7.45
|
7.20
|
7.58
|
|
3%
|
(2%)
|
|
|
7.51
|
7.37
|
|
2%
|
Sales
-
As of January 1, 2013, 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. Prior to 2013, the natural gas price we received in the
Netherlands was calculated using a formula based on the trailing
average of Dated Brent and natural gas prices from European trading
hubs.
-
The increase in sales per boe for the three months and year ended
December 31, 2013 versus the comparable periods was due to the
strengthening of the Euro against the Canadian dollar, resulting in
translation to higher Canadian dollar TTF reference prices.
Royalties and transportation expense
-
Our production in the Netherlands is not subject to royalties or
transportation expense as gas is sold at the plant gate.
Operating expense
-
Operating expense per boe for Q4 2013 was lower than Q3 2013 and Q4 2012
as a result of increased production volumes on largely fixed operating
expense.
-
Overall operating expense for the three months and year ended December
31, 2013 versus the same periods in 2012 increased primarily as a
result of the stronger Euro versus the Canadian dollar.
General and administration
-
Fluctuations in general and administration expense per boe for the
quarters presented were driven by the timing of expenditures and
partner recoveries. The increase for Q4 2013 was primarily driven by
the aforementioned acquisition during the quarter.
-
On a year-over-year basis, the increase in general and administration
expense was primarily the result of increased technical staffing in the
Netherlands in support of the development of our inventory of
undeveloped acreage in addition to the aforementioned acquisition.
Current income taxes
-
Current income taxes in the Netherlands apply to taxable income after
eligible deductions at an effective tax rate of approximately 46%.
-
Current income taxes per boe increased for the three months and year
ended December 31, 2013 as compared to the same periods in 2012 due to
a change in deductions for asset retirement obligations and depletion
recorded during the 2012 period as compared to 2013.
AUSTRALIA BUSINESS UNIT
Overview
-
Entered Australia in 2005.
-
Hold title to a 100% working interest in Wandoo field, located
approximately 80km northwest of Australia.
-
Production is operated from two off-shore platforms, and originates from
21 producing well bores.
-
Wells are located 600m below the sea bed with 500 to 3,000 plus meter
horizontal lengths.
-
Contracted crude oil production is priced with reference to Dated Brent.
Operational review
|
|
Three Months Ended
|
|
% change
|
|
|
Year Ended
|
|
% change
|
|
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
Q4/13 vs.
|
Q4/13 vs.
|
|
|
Dec 31,
|
Dec 31,
|
|
2013 vs.
|
Australia business unit
|
2013
|
2013
|
2012
|
|
Q3/13
|
Q4/12
|
|
|
2013
|
2012
|
|
2012
|
Production
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
6,189
|
7,070
|
5,873
|
|
(12%)
|
5%
|
|
|
6,481
|
6,360
|
|
2%
|
Inventory (mbbls)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Opening crude oil inventory
|
183
|
187
|
117
|
|
|
|
|
|
268
|
222
|
|
|
|
Crude oil production
|
569
|
650
|
540
|
|
|
|
|
|
2,366
|
2,328
|
|
|
|
Crude oil sales
|
(622)
|
(654)
|
(389)
|
|
|
|
|
|
(2,504)
|
(2,282)
|
|
|
|
Closing crude oil inventory
|
130
|
183
|
268
|
|
|
|
|
|
130
|
268
|
|
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($M)
|
8,420
|
5,880
|
25,257
|
|
43%
|
(67%)
|
|
|
77,931
|
49,389
|
|
58%
|
|
Gross wells drilled
|
-
|
-
|
-
|
|
|
|
|
|
2.00
|
-
|
|
|
|
Net wells drilled
|
-
|
-
|
-
|
|
|
|
|
|
2.00
|
-
|
|
|
Production
-
Quarter-over-quarter production decreased by 12% and year-over-year
production growth of 2%.
-
Q4 2013 production impacted by planned shutdown in October for platform
maintenance and due to impacts from Cyclone Christine in late December.
-
Production volumes are managed to meet customer demands and long term
supply agreements, and we continue to plan to produce between 6,000 and
8,000 bbls/d.
-
2013 production reflects strong well results, more than offsetting
natural declines, and we continue to produce the wells at restricted
rates below their demonstrated productive capacity.
Activity review
-
Drilled two sidetracks off existing wells during the first half of 2013,
including the longest horizontal section to date at Wandoo at 3,400
metres.
-
In Q4 2013, efforts were focused on facilities repairs and engineering
studies.
-
In 2014, planned activities include ongoing facilities maintenance,
enhancement and refurbishment along with preparation and permitting
activities in advance of our planned 2015 drilling program.
Financial review
|
|
Three Months Ended
|
|
% change
|
|
|
Year Ended
|
|
% change
|
Australia business unit
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
Q4/13 vs.
|
Q4/13 vs.
|
|
|
Dec 31,
|
Dec 31,
|
|
2013 vs.
|
($M except as indicated)
|
2013
|
2013
|
2012
|
|
Q3/13
|
Q4/12
|
|
|
2013
|
2012
|
|
2012
|
|
Sales
|
77,533
|
79,229
|
44,795
|
|
(2%)
|
73%
|
|
|
298,945
|
266,963
|
|
12%
|
|
Operating expense
|
(13,219)
|
(13,668)
|
(9,708)
|
|
(3%)
|
36%
|
|
|
(51,625)
|
(48,968)
|
|
5%
|
|
General and administration
|
(1,442)
|
(1,414)
|
(619)
|
|
2%
|
133%
|
|
|
(5,752)
|
(3,715)
|
|
55%
|
|
PRRT
|
(17,173)
|
(15,649)
|
(1,598)
|
|
10%
|
975%
|
|
|
(56,565)
|
(60,070)
|
|
(6%)
|
|
Corporate income taxes
|
(6,210)
|
(7,666)
|
(6,774)
|
|
(19%)
|
(8%)
|
|
|
(31,735)
|
(31,607)
|
|
-
|
|
Fund flows from operations
|
39,489
|
40,832
|
26,096
|
|
(3%)
|
51%
|
|
|
153,268
|
122,603
|
|
25%
|
Netbacks ($/boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
124.63
|
120.95
|
115.22
|
|
3%
|
8%
|
|
|
119.38
|
117.03
|
|
2%
|
|
Operating expense
|
(21.25)
|
(20.86)
|
(24.97)
|
|
2%
|
(15%)
|
|
|
(20.62)
|
(21.47)
|
|
(4%)
|
|
General and administration expense
|
(2.32)
|
(2.16)
|
(1.59)
|
|
7%
|
46%
|
|
|
(2.30)
|
(1.63)
|
|
41%
|
|
PRRT
|
(27.60)
|
(23.89)
|
(4.11)
|
|
16%
|
572%
|
|
|
(22.59)
|
(26.33)
|
|
(14%)
|
|
Corporate income taxes
|
(9.98)
|
(11.70)
|
(17.42)
|
|
(15%)
|
(43%)
|
|
|
(12.67)
|
(13.86)
|
|
(9%)
|
|
Fund flows from operations netback
|
63.48
|
62.34
|
67.13
|
|
2%
|
(5%)
|
|
|
61.20
|
53.74
|
|
14%
|
Reference prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated Brent (US $/bbl)
|
109.27
|
110.37
|
110.02
|
|
(1%)
|
(1%)
|
|
|
108.66
|
111.58
|
|
(3%)
|
Sales
-
Our production in Australia currently receives a premium to Dated
Brent. This premium, coupled with the weakening of the Canadian dollar
versus the US dollar, resulted in an increase in sales per boe despite
slight declines in Dated Brent.
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 the three months and year ended December
31, 2013 was relatively consistent with the three months ended
September 30, 2013 and the year ended December 31, 2012.
-
The year-over-year decrease in operating expense per boe was primarily
the result of an increase in produced volumes resulting in lower fixed
operating expense per bbl.
General and administration
-
The increase in general and administration expense for the three months
and year ended December 31, 2013 as compared to the same periods in
2012 was primarily the result of increased staffing expenditures to
support operational requirements.
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
approximately 30% on taxable income after eligible deductions, which
include PRRT.
-
PRRT for Q4 2013 was significantly higher than Q4 2012 as the 2012
period included higher capital expenditures, which related to
preparation for the 2013 Australian drilling campaign. The
expenditures relating to the drilling campaign, which were primarily
incurred during Q1 2013, resulted in a decrease in PRRT for the year
ended December 31, 2013 as compared to the same period in 2012.
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.
-
Acquired interest on July 30, 2009 for cash consideration of $136.8
million. Pursuant to the terms of the acquisition agreement, Vermilion
made an additional payment to the vendor of $134.3 million (US$135
million) at the end of 2012.
-
Production from Corrib is expected to increase Vermilion's volumes by
approximately 58 mmcf/d (9,700 boe/d) once the field reaches peak
production.
-
The Corrib field is expected to constitute 95% of Ireland's natural gas
production and approximately 60% to 65% of Ireland's domestic gas
consumption.
Operational and financial review
|
Three Months Ended
|
|
% change
|
|
|
Year Ended
|
|
% change
|
Ireland business unit
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
Q4/13 vs.
|
Q4/13 vs.
|
|
|
Dec 31,
|
Dec 31,
|
|
2013 vs.
|
($M)
|
2013
|
2013
|
2012
|
|
Q3/13
|
Q4/12
|
|
|
2013
|
2012
|
|
2012
|
Transportation expense
|
(357)
|
(564)
|
(1,682)
|
|
(37%)
|
(79%)
|
|
|
(4,165)
|
(7,556)
|
|
(45%)
|
General and administration
|
(482)
|
(313)
|
(341)
|
|
54%
|
41%
|
|
|
(1,442)
|
(1,346)
|
|
7%
|
Fund flows from operations
|
(839)
|
(877)
|
(2,023)
|
|
(4%)
|
(59%)
|
|
|
(5,607)
|
(8,902)
|
|
(37%)
|
Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
14,472
|
35,028
|
18,093
|
|
(59%)
|
(20%)
|
|
|
90,898
|
58,764
|
|
55%
|
Activity review
-
Various onshore and offshore activities have progressed over 2013,
including umbilical lays to the offshore wells, onshore pipelining in
segments that are not within the tunnel, construction of the tunnel
boring machine reception site and gas plant pre-commissioning, in
addition to the tunneling process.
-
To date, the land-based onshore pipeline is complete (approximately
5km), and there is approximately 1.4km of the 4.9km tunnel beneath
Sruwaddacon Bay remaining to be tunneled.
-
Tunneling operations were re-started on November 3, 2013 after being
suspended following an industrial accident, which resulted in a
fatality at the project worksite on September 8, 2013.
-
Onshore pipelining, offshore umbilical lays, seismic processing and
workover activities for our Corrib project were not impacted by the
suspension.
-
Based on an early review of our deterministic schedule for remaining
construction and commissioning activities, we revised our expectations
for timing of first gas to approximately mid-2015 from earlier
expectations for start-up at the end of 2014 or early 2015.
-
Following successful subsea well operations conducted on one of the
production wells during the third quarter of 2013, we increased our
peak production estimate at Corrib from 54 mmcf/d (9,000 boe/d) to
approximately 58 mmcf/d (approximately 9,700 boe/d) net to Vermilion.
Transportation expense
-
Transportation expense in Ireland relates to payments under a ship or
pay agreement related to the Corrib project. Required payments under
this agreement were lower year-over-year.
CORPORATE
Overview
-
Our Corporate segment includes costs related to our global hedging
program, financing expenses, and general and administration expenses,
primarily incurred in Canada and not directly related to the operations
of our business units.
Financial review
|
Three Months Ended
|
|
|
Year Ended
|
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
|
Dec 31,
|
Dec 31,
|
($M)
|
2013
|
2013
|
2012
|
|
|
2013
|
2012
|
General and administration
|
(2,919)
|
(2,334)
|
(759)
|
|
|
(7,356)
|
(10,030)
|
Current income taxes
|
(564)
|
(260)
|
(259)
|
|
|
(1,403)
|
(1,582)
|
Interest expense
|
(10,049)
|
(10,109)
|
(7,656)
|
|
|
(38,183)
|
(27,586)
|
Realized loss on derivatives
|
(1,300)
|
(4,765)
|
(1,559)
|
|
|
(7,082)
|
(12,737)
|
Realized foreign exchange (loss) gain
|
(1,294)
|
(1,227)
|
2,459
|
|
|
(1,866)
|
2,804
|
Realized other income (expense)
|
224
|
221
|
246
|
|
|
994
|
(7,531)
|
Fund flows from operations
|
(15,902)
|
(18,474)
|
(7,528)
|
|
|
(54,896)
|
(56,662)
|
General and administration
-
On a year-over-year basis, general and administration expense incurred
in the Corporate segment was lower as a result of an increase in the
staff involved in the operational activity of our business units.
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 the
2013 periods versus the 2012 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 also
assisting us in the execution of our capital and development plans.
-
The realized loss in the fourth quarter and full year 2013 relate
primarily to payments on our crude oil derivatives. In the current
quarter, these payments were offset partially by realized gains on our
natural gas derivative instruments while over the full year, these
payments were further offset by realized gains on our crude oil
derivatives during Q2 2013.
-
A listing of derivative positions as at December 31, 2013 is included in
"Supplemental Table 2".
Other income
-
In 2012, other expense included $8.5 million of expense relating to
transfer taxes resulting from our acquisition of certain working
interests in the Paris and Aquitaine Basins in France.
FINANCIAL PERFORMANCE REVIEW
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
Dec 31,
|
Dec 31,
|
Dec 31,
|
($M except per share)
|
|
|
|
|
|
2013
|
2012
|
2011
|
Total assets
|
|
|
|
|
|
3,708,719
|
3,076,257
|
2,735,187
|
Long-term debt
|
|
|
|
|
|
990,024
|
642,022
|
373,436
|
Petroleum and natural gas sales
|
|
|
|
|
|
1,273,835
|
1,083,103
|
1,031,570
|
Net earnings
|
|
|
|
|
|
327,641
|
190,622
|
142,821
|
Net earnings per share
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
|
|
3.24
|
1.94
|
1.57
|
Diluted
|
|
|
|
|
|
3.20
|
1.92
|
1.55
|
Cash dividends ($/share)
|
|
|
|
|
|
2.40
|
2.28
|
2.28
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Dec 31,
|
Sept 30,
|
Jun 30,
|
Mar 31,
|
Dec 31,
|
Sept 30,
|
Jun 30,
|
Mar 31,
|
($M except per share)
|
2013
|
2013
|
2013
|
2013
|
2012
|
2012
|
2012
|
2012
|
Petroleum and natural gas sales
|
325,108
|
327,185
|
311,966
|
309,576
|
241,233
|
284,838
|
246,544
|
310,488
|
Net earnings
|
101,510
|
67,796
|
106,198
|
52,137
|
56,914
|
30,798
|
37,816
|
65,094
|
Net earnings per share
|
|
|
|
|
|
|
|
|
Basic
|
1.00
|
0.67
|
1.05
|
0.53
|
0.58
|
0.31
|
0.39
|
0.67
|
Diluted
|
0.98
|
0.66
|
1.04
|
0.51
|
0.57
|
0.31
|
0.38
|
0.66
|
The following table shows a reconciliation of the change in net
earnings:
($M)
|
Q4/13 vs. Q3/13
|
Q4/13 vs. Q4/12
|
2013 vs. 2012
|
Net earnings - Comparative period
|
67,796
|
56,914
|
190,622
|
Changes in:
|
|
|
|
Fund flows from operations
|
(1,985)
|
21,923
|
109,798
|
Equity based compensation
|
(8,427)
|
(2,722)
|
(13,741)
|
Unrealized gain or loss on derivative instruments
|
4,971
|
(3,524)
|
(640)
|
Unrealized foreign exchange gain or loss
|
18,058
|
8,417
|
56,378
|
Unrealized other income
|
(146)
|
284
|
(231)
|
Accretion
|
(313)
|
(408)
|
(1,525)
|
Depletion and depreciation
|
(4,868)
|
(17,052)
|
(26,443)
|
Deferred tax
|
(20,976)
|
(9,722)
|
(54,468)
|
Gain on acquisition
|
-
|
-
|
(45,309)
|
Impairment (recovery)
|
47,400
|
47,400
|
113,200
|
Net earnings - Current Period
|
101,510
|
101,510
|
327,641
|
The fluctuations in net earnings from quarter-to-quarter and from
year-to-year are caused by changes in both cash and non-cash charges.
Cash charges 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 charges 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 charges may also include non-recurring charges resulting from
acquisitions or charges resulting from impairment or impairment
recoveries.
Equity based compensation expense
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.
Fluctuations in equity based compensation expense primarily result from
revisions in the future performance conditions related to the VIP
estimated forfeiture rates, and the overall number of VIP outstanding.
In general, future performance conditions and estimated forfeiture
rates are revised during the fourth quarter as information becomes more
readily available relating to the Company's performance during the
fiscal year.
Equity based compensation expense increased in 2013 as compared to 2012
as a result of the revision of future performance condition assumptions
in both Q4 2012 and Q4 2013. Equity based compensation expense was
higher for Q3 2013 as compared to Q4 2013 as the revision of
performance condition assumptions was partially offset by an increase
in the estimated forfeiture rate, from 5.37% to 6.61%.
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 vise-versa.
In the three months and year ended December 31, 2013, Vermilion
recognized an unrealized gain on derivative instruments of $1.3 million
and $5.1 million, respectively. These unrealized gains on derivative
instruments were primarily the result of the reversal of unrealized
losses on contracts settled during the respective periods. As at
December 31, 2013, Vermilion had a net current derivative liability
position of $1.3 million relating primarily to crude oil derivative
instruments for the first half of 2014.
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 U.S. 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.
During the three months and year ended December 31, 2013, the Euro
strengthened significantly versus the Canadian dollar resulting in
unrealized foreign exchange gains of $22.3 million and $52.0 million,
respectively.
Accretion
Fluctuations in accretion expense are primarily the result of changes in
the balance of asset retirement obligations. The increase in accretion
expense for 2013 as compared to 2012 was primarily the result of
accretion on new wells drilled during 2013 and on wells acquired in an
acquisition in France late in 2012.
Depletion and depreciation
Fluctuations in depletion and depreciation expense are primarily the
result of changes in produced crude oil and natural gas volumes. For
the three months and year ended December 31, 2013, production as
compared to the same periods in 2012 increased by 13% and 8%,
respectively, resulting in higher depletion and depreciation expense of
26% and 9%, respectively.
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 fluctuations in tax losses. The year-over-year
increase in deferred tax expense resulted primarily from an increase in
the temporary differences relating to asset retirement obligations.
For accounting purposes, asset retirement obligations decreased due to
a change in discount and inflation rates while there was no
corresponding decrease in the tax basis.
Impairment (recovery)
During Q1 2012, we recorded impairment losses of $65.8 million
pertaining to our conventional deep gas and shallow coal bed methane
natural gas plays in Canada. These impairment charges were the result
of significant declines in the forward pricing assumptions for natural
gas in Canada.
In 2013, we recognized a recovery of a portion of the impairment charges
previously recorded. The impairment recovery resulted from increased
proved and probable reserves of natural gas and natural gas liquids,
due primarily to the successful application of horizontal drilling and
multi-stage fracturing technology to the previously impaired cash
generating unit.
Gain on acquisition
During the 2012 period, we recognized a gain on acquisition of $45.3
million and other expense of $8.5 million relating to transfer taxes
resulting from our acquisition of certain working interests in the
Paris and Aquitaine Basins in France. The gain on acquisition arose as
a result of the increase in the fair value of the acquired petroleum
and natural gas reserves from the time when the acquisition was
negotiated to the acquisition date. The increase resulted from a
change in the underlying commodity price forecasts used to determine
the fair value of the acquired reserves.
TAXES
Corporate income tax rates
Vermilion pays corporate income taxes in France, the Netherlands, and
Australia. In addition, Vermilion pays PRRT in Australia. PRRT is a
profit based tax applied at a rate of 40% on sales less operating
expenses, capital expenditures, and other eligible expenditures. PRRT
is deductible in the calculation of taxable income in Australia.
Taxable income was subject to corporate income tax at the following
rates:
Jurisdiction
|
|
|
|
|
|
|
2013
|
|
|
|
|
|
|
2012
|
Canada
|
|
|
|
|
|
|
25.0%
|
|
|
|
|
|
|
25.0%
|
France
|
|
|
|
|
|
|
38.0%
|
|
|
|
|
|
|
36.1%
|
Netherlands
|
|
|
|
|
|
|
46.0%
|
|
|
|
|
|
|
46.0%
|
Australia
|
|
|
|
|
|
|
30.0%
|
|
|
|
|
|
|
30.0%
|
Ireland
|
|
|
|
|
|
|
25.0%
|
|
|
|
|
|
|
25.0%
|
France tax legislation
In December 2013, the France government enacted corporate tax
legislation that will lead to increases in current tax for companies
operating in France, including a temporary surtax of 10.7% (with the
surtax levied as a percent of base corporate income tax payable). The
new surtax rate is applicable for companies which have annual revenue
in excess of €250 million and effectively increases the statutory rate
applicable to our French operations to 38.0%, with retrospective
application to January 1, 2013. The surtax is only applicable to tax
years ending up to December 30, 2015 and as a result our French
operations tax rate will decrease to 34.4% for the tax year 2015.
In addition, the legislation adds a new test to the existing rules
governing interest deductions for related party financing. Under the
legislation, interest deductions would be allowed only if the French
borrower demonstrates that the lender is subject to corporate tax on
interest income that equals 25% or more of the corporate tax that would
otherwise be due under French tax rules. This legislation, among other
changes, may reduce the effectiveness of our existing international
corporate financing structures and could result in a reduction of
certain eligible deductions in our French operating companies.
Tax assessments
As at December 31, 2013, Income Taxes Payable includes a provision
relating to tax assessments from tax authorities for prior period tax
positions. We have determined the provision based on our best estimate
of the amount required to settle the tax assessments and we have
classified the provision as a current liability. The amounts
ultimately paid and the timing of settlement could differ from our best
estimate and, therefore, could have an impact on future net earnings
and cash flows.
Tax pools
As at December 31, 2013, we had the following tax pools:
($M)
|
Oil & Gas Assets
|
|
|
Tax Losses (4)
|
Other
|
Total
|
Canada
|
856,023
|
(1)
|
|
385,105
|
8,110
|
1,249,238
|
France
|
388,549
|
(2)
|
|
12,144
|
-
|
400,693
|
Netherlands
|
61,868
|
(3)
|
|
-
|
-
|
61,868
|
Australia
|
217,069
|
(1)
|
|
-
|
-
|
217,069
|
Ireland
|
844,761
|
(4)
|
|
272,201
|
-
|
1,116,962
|
Total
|
2,368,270
|
|
|
669,450
|
8,110
|
3,045,830
|
(1)
|
Deduction calculated using various declining balance rates
|
(2)
|
Deduction calculated using a combination of straight-line over the
assets life and unit of production method
|
(3)
|
Deduction calculated using a unit of production method
|
(4)
|
Development expenditures and losses are deductible at 100% against
taxable income
|
FINANCIAL POSITION REVIEW
Balance sheet strategy
We believe that our balance sheet supports our defined growth
initiatives and our focus is on managing and maintaining a conservative
balance sheet. To ensure that our balance sheet continues to support
our defined growth initiatives, we regularly review whether forecasted
fund flows from operations is sufficient to finance planned capital
expenditures, dividends, and abandonment and reclamation expenditures.
To the extent that forecasted fund flows from operations is not
expected to be sufficient to fulfill such expenditures, we will
evaluate our ability to finance any excess with debt (including
borrowing using the unutilized capacity of our existing revolving
credit facility) or issue equity.
To ensure that we maintain a conservative balance sheet, we monitor the
ratio of net debt to fund flows from operations and typically strive to
maintain a ratio of near 1.0. 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.
Long-term debt
Our long-term debt consists of our revolving credit facility and our
senior unsecured notes. The applicable annual interest rates and the
balances recognized on our balance sheet are as follows:
|
Annual Interest Rate
|
|
|
As At
|
|
Dec 31,
|
Dec 31,
|
|
|
Dec 31,
|
Dec 31,
|
($M)
|
2013
|
2012
|
|
|
2013
|
2012
|
Revolving credit facility
|
3.3%
|
3.3%
|
|
|
766,898
|
419,784
|
Senior unsecured notes
|
6.5%
|
6.5%
|
|
|
223,126
|
222,238
|
Long-term debt
|
4.2%
|
4.7%
|
|
|
990,024
|
642,022
|
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
|
|
Dec 31,
|
Dec 31,
|
|
2013
|
2012
|
Total facility amount
|
$1.20 billion
|
$0.95 billion
|
Amount drawn
|
$766.9 million
|
$419.8 million
|
Letters of credit outstanding
|
$8.1 million
|
$49.2 million
|
Facility maturity date
|
31-May-16
|
31-May-15
|
In addition, the revolving credit facility is subject to the following
covenants:
|
|
Year Ended
|
|
|
Dec 31,
|
Dec 31,
|
Financial covenant
|
Limit
|
2013
|
2012
|
Consolidated total debt to consolidated EBITDA
|
4.0
|
1.06
|
0.83
|
Consolidated total senior debt to consolidated EBITDA
|
3.0
|
0.82
|
0.54
|
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.
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 amount
|
|
|
|
|
$225.0 million
|
Interest
|
|
|
|
|
6.5% per annum
|
Issued date
|
|
|
|
|
February 10, 2011
|
Maturity date
|
|
|
|
|
February 10, 2016
|
We may redeem all or part of the notes at fixed redemption prices plus
in each case, accrued and unpaid interest, if any, to the applicable
redemption date. The notes were initially recognized at fair value net
of transaction costs and are subsequently measured at amortized cost
using an effective interest rate of 7.1%.
Net debt
Net debt is reconciled to its most directly comparable GAAP measure,
long-term debt, as follows:
|
As At
|
|
Dec 31,
|
Dec 31,
|
($M)
|
2013
|
2012
|
Long-term debt
|
990,024
|
642,022
|
Current liabilities
|
347,444
|
355,711
|
Current assets
|
(587,783)
|
(320,502)
|
Net debt
|
749,685
|
677,231
|
|
|
|
Ratio of net debt to fund flows from operations
|
1.1
|
1.2
|
Long-term debt as at December 31, 2013 increased to $990.0 million from
$642.0 million as at December 31, 2012 as a result of increased
borrowings on the revolving credit facility. Additional borrowings
were used to fund current year development capital expenditures in
Ireland and also reflect borrowings in anticipation of the closing of
our acquisition in Germany. In Ireland, development activities related
to tunneling, onshore pipelining, offshore umbilical-laying and
offshore seismic acquisition activities.
As our acquisition in Germany did not close prior to year-end,
borrowings on our revolving credit facility during the fourth quarter
of 2013 were largely held as cash and cash equivalents, which increased
$287.4 million to $389.6 million as at December 31, 2013. As a result,
the increase to net debt was limited to $72.5 million as compared to
the $348.0 million increase in long-term debt.
Overall, we continue to maintain a strong financial position, with a net
debt to fund flows from operations of 1.1.
Shareholders' capital
During the year ended December 31, 2013, we maintained monthly dividends
at $0.20 per share and declared dividends totalled $242.6 million. In
November of 2013, we announced a 7.5% increase in the monthly dividend
to $0.215 per common share per month (effective for the January 2014
dividend and paid on February 17, 2014). This dividend increase is our
second consecutive annual increase.
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
|
$0.215
|
As at December 31, 2013, there were 1.7 million VIP awards outstanding.
As at February 27, 2014, there were 102.3 million shares outstanding.
Our policy with respect to dividends is to be conservative and maintain
a low ratio of dividends to fund flows from operations. During low
price commodity cycles, we will initially maintain dividends and allow
the ratio to rise. Should low commodity price cycles remain for an
extended period of time, we will evaluate the necessity of changing the
level of dividends, taking into consideration capital development
requirements, debt levels and acquisition opportunities.
Over the next two years, we anticipate that Corrib, Cardium and other
exploration and development activities will require significant capital
investment. Although we currently expect to be able to maintain our
current dividend, fund flows from operations may not be sufficient
during this period to fund cash dividends, capital expenditures and
asset retirement obligations. We will evaluate our ability to finance
any shortfalls with debt, issuances of equity or by reducing some or
all categories of expenditures to ensure that total expenditures do not
exceed available funds.
The following table reconciles the change in shareholders' capital:
|
Number of Shares ('000s)
|
|
Amount ($M)
|
Balance as at December 31, 2012
|
|
99,135
|
|
1,481,345
|
Issuance of shares 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
|
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
As at December 31, 2013, we had the following contractual obligations
and commitments:
($M)
|
Less than 1 year
|
1 - 3 years
|
3 - 5 years
|
After 5 years
|
Total
|
Long-term debt
|
13,406
|
1,008,148
|
-
|
-
|
1,021,554
|
Operating lease obligations
|
12,881
|
19,189
|
15,565
|
26,466
|
74,101
|
Ship or pay agreement relating to the Corrib project
|
6,157
|
10,300
|
8,354
|
35,745
|
60,556
|
Purchase obligations
|
25,775
|
18,456
|
15
|
-
|
44,246
|
Drilling and service agreements
|
13,648
|
16,152
|
-
|
-
|
29,800
|
Total contractual obligations and commitments
|
71,867
|
1,072,245
|
23,934
|
62,211
|
1,230,257
|
ASSET RETIREMENT OBLIGATIONS
As at December 31, 2013, asset retirement obligations were $326.2
million compared to $371.1 million as at December 31, 2012.
The increase in asset retirement obligations is largely attributable to
an overall decrease in the inflation rates applied to the abandonment
obligations.
RISKS AND UNCERTAINTIES
Crude oil and natural gas exploration, production, acquisition and
marketing operations involve a number of risks and uncertainties
including financial risks and uncertainties. These include fluctuations
in commodity prices, exchange rates and interest rates as well as
uncertainties associated with reserve and resource volumes, sales
volumes and government regulatory and income tax regime changes. These
and other related risks and uncertainties are discussed in additional
detail below.
Commodity prices
Our operational results and financial condition is dependent on the
prices received for crude oil and natural gas production. Crude oil and
natural gas prices have fluctuated significantly during recent years
and are determined by supply and demand factors, including weather and
general economic conditions as well as conditions in other crude oil
and natural gas producing regions.
Exchange rates
Much of our revenue stream is priced in U.S. dollars and as such an
increase in the strength of the Canadian dollar relative to the U.S.
dollar may result in the receipt of fewer Canadian dollars with respect
to our production. In addition, we incur expenses and capital costs in
U.S. dollars, Euros and Australian dollars and accordingly, the
Canadian dollar equivalent of these expenditures as reported in our
financial results is impacted by the prevailing foreign currency
exchange rates at the time the transaction occurs. We monitor risks
associated with exchange rates and, when appropriate, uses derivative
financial instruments to manage our exposure to these risks.
Production and sales volumes
The operation of crude oil and natural gas wells and facilities involves
a number of operating and natural hazards which may result in blowouts,
environmental damage and other unexpected or dangerous conditions
resulting in damage to us and possible liability to third parties. We
maintain liability insurance, where available, in amounts consistent
with industry standards. Business interruption insurance may also be
purchased for selected operations, to the extent that such insurance is
commercially viable. We may become liable for damages arising from such
events against which it cannot insure or against which it may elect not
to insure because of high premium costs or other reasons. Costs
incurred to repair such damage or pay such liabilities may materially
impact our financial results.
Continuing production from a property, and to some extent the marketing
of produced volumes, is largely dependent upon the ability of the
operator of the property. To the extent the operator fails to perform
these functions properly, revenue may be reduced. Payments from
production generally flow through the operator and there is a risk of
delay and additional expense in receiving such revenues if the operator
becomes insolvent. Although satisfactory title reviews are generally
conducted in accordance with industry standards, such reviews do not
guarantee or certify that a defect in the chain of title may not arise
to defeat our claim to certain properties. Such circumstances could
negatively affect our financial results.
An increase in operating costs or a decline in our production level
could have an adverse effect on our financial results. The level of
production may decline at rates greater than anticipated due to
unforeseen circumstances, many of which are beyond our control. A
significant decline in production could result in materially lower
revenues.
Interest rates
An increase in interest rates could result in a significant increase in
the amount we pay to service debt.
Reserve volumes
Our reserve volumes and related reserve values support the carrying
value of our crude oil and natural gas assets on the consolidated
balance sheets and provide the basis to calculate the depletion of
those assets. There are numerous uncertainties inherent in estimating
quantities of reserves and future net revenues to be derived therefrom,
including many factors beyond our control. These include a number of
assumptions relating to factors such as initial production rates,
production decline rates, ultimate recovery of reserves, timing and
amount of capital expenditures, marketability of production, future
prices of crude oil, NGLs and natural gas, operating expenses, well
abandonment and salvage values, royalties and any government levies
that may be imposed over the producing life of the reserves. These
assumptions were based on estimated prices in use at the date the
evaluation was prepared, and many of these assumptions are subject to
change and are beyond our control. Actual production and income
derived therefrom will vary from these evaluations, and such variations
could be material.
Asset retirement obligations
Our asset retirement obligations are based on environmental regulations
and estimates of future costs and the timing of expenditures. Changes
in environmental regulations, the estimated costs associated with
reclamation activities and the related timing may impact our financial
position and results of operations.
Government regulation and income tax regime
Our operations are governed by many levels of government, including
municipal, state, provincial and federal governments, in Canada,
France, the Netherlands, Australia and Ireland. We are subject to laws
and regulations regarding environment, health and safety issues, lease
interests, taxes and royalties, among others. Failure to comply with
the applicable laws can result in significant increases in costs,
penalties and even losses of operating licences. The regulatory process
involved in each of the countries in which we operate is not uniform
and regulatory regimes vary as to complexity, timeliness of access to,
and response from, regulatory bodies and other matters specific to each
jurisdiction. If regulatory approvals or permits are delayed or not
obtained, there can also be delays or abandonment of projects and
decreases in production and increases in costs, potentially resulting
in us being unable to fully execute our strategy. Governments may also
amend or create new legislation and regulatory bodies may also amend
regulations or impose additional requirements which could result in
increased capital, operating and compliance costs.
There can be no assurance that income tax laws and government incentive
programs relating to the crude oil and natural gas industry in Canada
and the foreign jurisdictions in which we operate, will not be changed
in a manner which adversely affects the results of our operations.
A change in the royalty regime resulting in an increase in royalties
would reduce our net earnings and could make future capital
expenditures or our operations uneconomic and could, in the event of a
material increase in royalties, make it more difficult to service and
repay outstanding debt. Any material increase in royalties would also
significantly reduce the value of the associated assets.
FINANCIAL RISK MANAGEMENT
To mitigate the aforementioned risks whenever possible, we seek to hire
personnel with experience in specific areas. In addition, we provide
continued training and development to staff to further develop their
skills. When appropriate, we use third party consultants with relevant
experience to augment our internal capabilities with respect to certain
risks.
We consider our commodity price risk management program as a form of
insurance that protects our cash flow and rate of return. The primary
objective of the risk management program is to support our dividends
and our internal capital development program. The level of commodity
price risk management that occurs is highly dependent on the amount of
debt that is carried. When debt levels are higher, we will be more
active in protecting our cash flow stream through our commodity price
risk management strategy.
When executing our commodity price risk management programs, we use
derivative financial instruments encompassing over-the-counter
financial structures as well as fixed/collar structures to economically
hedge a part of our physical crude oil and natural gas production. We
have strict controls and guidelines in relation to these activities and
contract principally with counterparties that have investment grade
credit ratings.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with IFRS requires
management to make estimates, judgments and assumptions that affect
reported assets, liabilities, revenues and expenses, gains and losses,
and disclosures of any possible contingencies. These estimates and
assumptions are developed based on the best available information which
management believed to be reasonable at the time such estimates and
assumptions were made. As such, these assumptions are uncertain at the
time estimates are made and could change, resulting in a material
impact on our consolidated financial statements or financial
performance. Estimates are reviewed by management on an ongoing basis,
and as a result, certain estimates may change from period to period due
to the availability of new information. Additionally, as a result of
the unique circumstances of each jurisdiction in which we operate, the
critical accounting estimates may affect one or more jurisdictions.
The following discussion outlines what management believes to be the
most critical accounting policies involving the use of estimates and
assumptions.
Depletion and depreciation
We classify our assets into depletion units, which are groups of assets
or properties that are within a specific production area and have
similar economic lives. The depletion units represent the lowest level
of disaggregation for which we accumulate costs for the purposes of
calculating and recording depletion and depreciation.
The net carrying value of each depletion unit is depleted using the unit
of production method by reference to the ratio of production in the
period to the total proven and probable reserves, taking into account
the future development costs necessary to bring the applicable reserves
into production. As a result, depletion and depreciation charges are
based on estimates of total proven and probable reserves that we expect
to recover in the future. The reserve estimates are reviewed annually
by management or when material changes occur to the underlying
assumptions.
Asset retirement obligations
Our estimate of asset retirement obligations are based on past
experience and current economic factors which management believes are
reasonable. The estimates include assumptions of environmental
regulations, legal requirements, technological advances, inflation and
the timing of expenditures, all of which impact our measurement of the
present value of the obligations. Due to these estimates, the actual
cost of the obligation may change from period to period due to new
information being available. Several or all of these estimates are
subject to change and such changes could have a material impact on our
financial position and net earnings.
Assessment of impairments
Impairment tests are performed at the level of the cash generating unit
("CGU"), which are determined based on management's judgment of the
lowest level at which there are identifiable cash inflows which are
largely independent of the cash inflows of other groups of assets or
properties. The factors used to determine CGUs vary by country due to
the unique operating and geographic circumstances in each
jurisdiction. However, in general, we will assess the following
factors in determining whether a group of assets generate largely
independent cash inflows: geographic proximity of the assets within a
group to one another, geographic proximity of the group of assets to
other groups of assets, homogeneity of the production from the group of
assets and the sharing of infrastructure used to process or transport
production.
The calculation of the recoverable amount of CGUs is based on market
factors as well as estimates of reserves and future costs required to
develop reserves. Our reserves estimates and the related future cash
flows are subject to measurement uncertainty, and the impact on the
consolidated financial statements in future periods could be material.
Considerable judgment is used in determining the recoverable amount of
petroleum and natural gas assets, including determining the quantity of
reserves, the time horizon to develop and produce such reserves and the
estimated revenues and expenditures from such production.
Taxes
Tax interpretations, regulations and legislation in the various
jurisdictions in which we operate are subject to change. Such changes
can affect the timing of the reversal of temporary tax differences, the
tax rates in effect when such differences reverse and our ability to
use tax losses and other credits in the future. The determination of
deferred tax amounts recognized in the consolidated financial
statements was based on management's assessment of the tax positions,
including consideration of their technical merits and communications
with tax authorities. The effect of a change in income tax rates or
legislation on tax assets and liabilities is recognized in net earnings
in the period in which the change is enacted.
OFF BALANCE SHEET ARRANGEMENTS
We have certain lease agreements that are entered into in the normal
course of operations, all of which are operating leases and accordingly
no asset or liability value has been assigned to the consolidated
balance sheet as at December 31, 2013.
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 pronouncements are currently
being evaluated, but are not expected to have a material impact on
Vermilion's consolidated financial statements:
IFRIC 21 "Levies"
On May 20, 2013, IASB issued guidance on IFRIC 21, which provides
guidance 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.
IFRS 9 "Financial Instruments"
The IASB has undertaken a three-phase project to replace IAS 39,
"Financial Instruments: Recognition and Measurement". The new standard
replaces the current multiple classification and measurement models for
financial assets and liabilities with a single model that has only two
classification categories: amortized cost and fair value. In February
of 2014, the IASB confirmed that the mandatory effective date of IFRS 9
shall be January 1, 2018.
HEALTH, SAFETY AND ENVIRONMENT
We are committed to ensuring we conduct our activities in a manner that
will protect the health and safety of our employees, contractors and
the public. Our health, safety and environment vision is to fully
integrate health, safety and environment into our business, where our
culture is recognized as a model by industry and stakeholders,
resulting in a workplace free of incidents. Our mantra is HSE:
Everywhere. Everyday. Everyone.
We maintain health, safety and environmental practices and procedures
that comply or exceed regulatory requirements and industry standards.
It is a condition of employment that our personnel work safely and in
accordance with established regulations and procedures.
In 2013, we remained committed to the principles of the Responsible
Canadian Energy™ program set out by the Canadian Association of
Petroleum Producers. Responsible Canadian Energy™ is an
association-wide performance reporting program to demonstrate progress
in environmental, health, safety, and social performance.
We continued our commitment to reduce impacts to land, water and air, as
policies and procedures demonstrating leadership in these areas, were
maintained and further developed in 2013. Examples of our
accomplishments during the year included:
-
Receiving a National Ecology award in France for our tomato greenhouse
partnership;
-
Clear priorities around 5 key focus areas of HSE Culture, Communication
and Knowledge Management, Technical Safety Management, Incident
Prevention and Operational Stewardship & Sustainability;
-
Completed a detailed, corporate wide HSE perception survey to ensure
organizational engagement, define areas of strength and identify areas
to focus on;
-
Reducing long-term environmental liabilities through decommissioning,
abandoning and reclaiming well leases and facilities;
-
Continuous auditing and management inspections;
-
Development, communication and measurement against leading and lagging
HSE key performance indicators;
-
Further enhancement of our competency and training programs;
-
Managing our waste products by reducing, recycling and recovering; and
-
Continuing risk management efforts in addition to detailed
emergency-response planning.
We are a member of several organizations concerned with environment,
health and safety, including numerous regional co-operatives and
synergy groups. In the area of stakeholder relations, we work to build
long-term relationships with environmental stakeholders and
communities.
CORPORATE GOVERNANCE
We are committed to a high standard of corporate governance practices, a
dedication that begins at the Board level and extends throughout the
Company. We believe good corporate governance is in the best interest
of our shareholders, and that successful companies are those that
deliver growth and a competitive return along with a commitment to the
environment, to the communities where they operate and to their
employees.
We comply with the objectives and guidelines relating to corporate
governance adopted by the Canadian Securities Administrators and the
Toronto Stock Exchange. In addition, the Board monitors and considers
the implementation of corporate governance standards proposed by
various regulatory and non-regulatory authorities in Canada. A
discussion of corporate governance policies will be provided in our
Management Proxy Circular, which will be filed on SEDAR (www.sedar.com)
and mailed to all shareholders on April 8, 2014.
A summary of the significant differences between the governance
practices of the Company and those required of U.S. domestic companies
under the New York Stock Exchange listing standards can be found in the
Governance section of the Company's website at http://www.vermilionenergy.com/about/governance.cfm.
DISCLOSURE CONTROLS AND PROCEDURES
Our officers have established and maintained disclosure controls and
procedures and evaluated the effectiveness of these controls in
conjunction with our filings.
As of December 31, 2013, we have evaluated the effectiveness of the
design and operation of our disclosure controls and procedures. Based
on this evaluation, the Chief Executive Officer and Chief Financial
Officer have concluded and certified that our disclosure controls and
procedures are effective.
INTERNAL CONTROL OVER FINANCIAL REPORTING
A company's internal control over financial reporting is a process to
provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles.
A company's internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance of records
that, in reasonable detail, accurately and fairly reflect the
transactions of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being
made only in accordance with authorizations of management and directors
of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or
disposition of the company's assets that could have a material effect
on the financial statements.
The Chief Executive Officer and the Chief Financial Officer of Vermilion
have assessed the effectiveness of Vermilion's internal control over
financial reporting as defined in Rule 13a-15 under the US Securities
Exchange Act of 1934 and as defined in Canada by National Instrument
52-109, Certification of Disclosure in Issuers' Annual and Interim
Filings. The Chief Executive Officer and the Chief Financial Officer
of Vermilion have concluded that Vermilion's internal control over
financial reporting was effective as of December 31, 2013. The
effectiveness of Vermilion's internal control over financial reporting
as of December 31, 2013 has been audited by Deloitte LLP, as reflected
in their report included in the 2013 audited annual financial
statements filed with the US Securities and Exchange Commission. No
changes were made to Vermilion's internal control over financial
reporting during the year ending December 31, 2013, that have
materially affected, or are reasonably likely to materially affect, the
internal controls over financial reporting.
Supplemental Table 1: Netbacks
The following table includes financial statement information on a per
unit basis by business unit. Natural gas sales volumes have been
converted on a basis of six thousand cubic feet of natural gas to one
barrel of oil equivalent.
|
Three Months Ended Dec 31, 2013
|
|
Year Ended Dec 31, 2013
|
|
|
Three Months
Ended Dec 31, 2012
|
|
Year Ended
Dec 31, 2012
|
|
Oil & NGLs
|
Natural Gas
|
Total
|
|
Oil & NGLs
|
Natural Gas
|
Total
|
|
|
Total
|
|
Total
|
|
$/bbl
|
$/mcf
|
$/boe
|
|
$/bbl
|
$/mcf
|
$/boe
|
|
|
$/boe
|
|
$/boe
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
86.87
|
3.70
|
61.10
|
|
89.78
|
3.40
|
61.14
|
|
|
58.80
|
|
54.89
|
Royalties
|
(10.67)
|
(0.21)
|
(6.93)
|
|
(10.42)
|
(0.17)
|
(6.55)
|
|
|
(5.62)
|
|
(5.71)
|
Transportation
|
(3.57)
|
(0.18)
|
(2.57)
|
|
(2.64)
|
(0.17)
|
(1.96)
|
|
|
(1.46)
|
|
(1.50)
|
Operating
|
(10.50)
|
(0.83)
|
(8.29)
|
|
(9.24)
|
(1.42)
|
(8.93)
|
|
|
(11.01)
|
|
(10.00)
|
Operating netback
|
62.13
|
2.48
|
43.31
|
|
67.48
|
1.64
|
43.70
|
|
|
40.71
|
|
37.68
|
General and administration
|
|
|
(1.60)
|
|
|
|
(2.24)
|
|
|
(1.34)
|
|
(2.23)
|
Fund flows from operations netback
|
|
|
41.71
|
|
|
|
41.46
|
|
|
39.37
|
|
35.45
|
France
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
112.84
|
-
|
112.84
|
|
108.55
|
10.20
|
106.26
|
|
|
102.26
|
|
105.13
|
Royalties
|
(6.70)
|
-
|
(6.70)
|
|
(6.57)
|
(0.29)
|
(6.34)
|
|
|
(5.29)
|
|
(5.53)
|
Transportation
|
(4.71)
|
-
|
(4.71)
|
|
(3.08)
|
-
|
(2.93)
|
|
|
(2.16)
|
|
(2.23)
|
Operating
|
(15.82)
|
-
|
(15.82)
|
|
(16.04)
|
(1.52)
|
(15.70)
|
|
|
(15.97)
|
|
(14.86)
|
Operating netback
|
85.61
|
-
|
85.61
|
|
82.86
|
8.39
|
81.29
|
|
|
78.84
|
|
82.51
|
General and administration
|
|
|
(5.18)
|
|
|
|
(4.61)
|
|
|
(5.57)
|
|
(4.06)
|
Current income taxes
|
|
|
(28.55)
|
|
|
|
(22.16)
|
|
|
(15.55)
|
|
(17.05)
|
Fund flows from operations netback
|
|
|
51.88
|
|
|
|
54.52
|
|
|
57.72
|
|
61.40
|
Netherlands
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
111.00
|
11.24
|
67.88
|
|
100.49
|
10.61
|
64.08
|
|
|
60.96
|
|
58.69
|
Operating
|
-
|
(1.79)
|
(10.63)
|
|
-
|
(1.59)
|
(9.47)
|
|
|
(11.14)
|
|
(9.10)
|
Operating netback
|
111.00
|
9.45
|
57.25
|
|
100.49
|
9.02
|
54.61
|
|
|
49.82
|
|
49.59
|
General and administration
|
|
|
(2.67)
|
|
|
|
(1.25)
|
|
|
(1.22)
|
|
(0.63)
|
Current income taxes
|
|
|
(14.22)
|
|
|
|
(15.67)
|
|
|
(2.15)
|
|
(12.18)
|
Fund flows from operations netback
|
|
|
40.36
|
|
|
|
37.69
|
|
|
46.45
|
|
36.78
|
Australia
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
124.63
|
-
|
124.63
|
|
119.38
|
-
|
119.38
|
|
|
115.22
|
|
117.03
|
Operating
|
(21.25)
|
-
|
(21.25)
|
|
(20.62)
|
-
|
(20.62)
|
|
|
(24.97)
|
|
(21.47)
|
PRRT (1)
|
(27.60)
|
-
|
(27.60)
|
|
(22.59)
|
-
|
(22.59)
|
|
|
(4.11)
|
|
(26.33)
|
Operating netback
|
75.78
|
-
|
75.78
|
|
76.17
|
-
|
76.17
|
|
|
86.14
|
|
69.23
|
General and administration
|
|
|
(2.32)
|
|
|
|
(2.30)
|
|
|
(1.59)
|
|
(1.63)
|
Corporate income taxes
|
|
|
(9.98)
|
|
|
|
(12.67)
|
|
|
(17.42)
|
|
(13.86)
|
Fund flows from operations netback
|
|
|
63.48
|
|
|
|
61.20
|
|
|
67.13
|
|
53.74
|
Total Company
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales
|
106.00
|
7.29
|
86.04
|
|
104.46
|
6.83
|
83.83
|
|
|
78.40
|
|
79.51
|
Realized hedging loss
|
|
|
(0.34)
|
|
|
|
(0.47)
|
|
|
(0.51)
|
|
(0.93)
|
Royalties
|
(6.55)
|
(0.11)
|
(4.66)
|
|
(6.33)
|
(0.10)
|
(4.47)
|
|
|
(3.88)
|
|
(3.82)
|
Transportation
|
(3.13)
|
(0.14)
|
(2.40)
|
|
(2.16)
|
(0.23)
|
(1.90)
|
|
|
(1.77)
|
|
(1.77)
|
Operating
|
(15.11)
|
(1.28)
|
(12.74)
|
|
(14.69)
|
(1.50)
|
(12.84)
|
|
|
(14.18)
|
|
(13.10)
|
PRRT (1)
|
(6.69)
|
-
|
(4.55)
|
|
(5.52)
|
-
|
(3.72)
|
|
|
(0.52)
|
|
(4.41)
|
Operating netback
|
74.52
|
5.76
|
61.35
|
|
75.76
|
5.00
|
60.43
|
|
|
57.54
|
|
55.48
|
General and administration
|
|
|
(3.69)
|
|
|
|
(3.28)
|
|
|
(2.89)
|
|
(3.21)
|
Interest expense
|
|
|
(2.66)
|
|
|
|
(2.51)
|
|
|
(2.49)
|
|
(2.03)
|
Realized foreign exchange (loss) gain
|
|
|
(0.34)
|
|
|
|
(0.12)
|
|
|
0.81
|
|
0.21
|
Other income (expense)
|
0.06
|
|
|
|
0.07
|
|
|
0.08
|
|
(0.55)
|
Corporate income taxes (1)
|
|
|
(11.40)
|
|
|
|
(10.65)
|
|
|
(6.98)
|
|
(8.94)
|
Fund flows from operations netback
|
|
|
43.32
|
|
|
|
43.94
|
|
|
46.07
|
|
40.96
|
(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 December 31, 2013:
|
Note
|
|
|
|
Daily Volume
|
|
|
|
Strike Price(s)
|
Crude Oil
|
|
|
|
|
|
|
|
|
|
WTI - Collar
|
|
|
|
|
|
|
|
|
|
January 2014 - March 2014
|
|
|
|
|
1,000 bbl/d
|
|
|
|
97.50 - 104.69 USD $
|
WTI - Swap
|
|
|
|
|
|
|
|
|
|
January 2014 - March 2014
|
|
|
|
|
500 bbl/d
|
|
|
|
101.22 USD $
|
January 2014 - March 2014
|
(1)
|
|
|
|
250 bbl/d
|
|
|
|
105.45 USD $
|
January 2014 - June 2014
|
|
|
|
|
250 bbl/d
|
|
|
|
100.05 USD $
|
January 2014 - June 2014
|
(2)
|
|
|
|
1,000 bbl/d
|
|
|
|
100.07 USD $
|
Dated Brent - Collar
|
|
|
|
|
|
|
|
|
|
January 2014 - March 2014
|
|
|
|
|
2,500 bbl/d
|
|
|
|
104.00 - 110.46 USD $
|
January 2014 - June 2014
|
|
|
|
|
1,250 bbl/d
|
|
|
|
103.20 - 110.24 USD $
|
April 2014 - June 2014
|
|
|
|
|
1,000 bbl/d
|
|
|
|
105.00 - 115.00 USD $
|
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 - March 2014
|
|
|
|
|
2,000 bbl/d
|
|
|
|
107.80 USD $
|
January 2014 - June 2014
|
|
|
|
|
1,000 bbl/d
|
|
|
|
107.25 USD $
|
January 2014 - June 2014
|
(2)
|
|
|
|
1,500 bbl/d
|
|
|
|
110.32 USD $
|
April 2014 - June 2014
|
|
|
|
|
1,250 bbl/d
|
|
|
|
109.74 USD $
|
January 2014 - December 2014
|
|
|
|
|
500 bbl/d
|
|
|
|
108.28 USD $
|
MSW - Fixed Price Sale (Physical)
|
|
|
|
|
|
|
|
|
|
January 2014 - March 2014
|
|
|
|
|
1,000 bbl/d
|
|
|
|
93.37 CAD $
|
April 2014 - June 2014
|
|
|
|
|
1,000 bbl/d
|
|
|
|
92.85 CAD $
|
Canadian Natural Gas
|
|
|
|
|
|
|
|
|
|
AECO - Collar
|
|
|
|
|
|
|
|
|
|
January 2014 - December 2014
|
|
|
|
|
10,000 GJ/d
|
|
|
|
3.18 - 3.81 CAD $
|
AECO - Swap
|
|
|
|
|
|
|
|
|
|
January 2014 - December 2014
|
|
|
|
|
5,000 GJ/d
|
|
|
|
3.71 CAD $
|
AECO - Collar (Physical)
|
(3)
|
|
|
|
|
|
|
|
|
April 2012 - March 2014
|
|
|
|
|
5,500 GJ/d
|
|
|
|
2.60 - 3.78 CAD $
|
June 2012 - March 2014
|
|
|
|
|
3,000 GJ/d
|
|
|
|
2.30 - 3.75 CAD $
|
European Natural Gas
|
|
|
|
|
|
|
|
|
|
TTF - Swap
|
|
|
|
|
|
|
|
|
|
January 2014 - March 2014
|
|
|
|
|
16,200 GJ/d
|
|
|
|
7.88 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 $
|
(1)
|
Prior to the expiration of this swap, the counterparty has the option to
extend the swap to June 30, 2014 at the contracted volume and price.
|
(2)
|
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.
|
(3)
|
Physical AECO collars have a funded cost of $0.10/GJ.
|
Supplemental Table 3: Capital expenditures
|
Three Months Ended
|
|
|
Year Ended
|
By classification
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
|
Dec 31,
|
Dec 31,
|
($M)
|
2013
|
2013
|
2012
|
|
|
2013
|
2012
|
Drilling and development
|
147,929
|
135,110
|
151,157
|
|
|
537,564
|
413,221
|
Dispositions
|
-
|
-
|
-
|
|
|
(8,627)
|
-
|
Exploration and evaluation
|
549
|
551
|
5,878
|
|
|
13,789
|
39,317
|
Capital expenditures
|
148,478
|
135,661
|
157,035
|
|
|
542,726
|
452,538
|
Property acquisition
|
1,603
|
7,586
|
-
|
|
|
9,189
|
106,184
|
Corporate acquisition
|
27,500
|
-
|
74,947
|
|
|
27,500
|
74,947
|
Payment of amount due pursuant to acquisition
|
-
|
-
|
134,307
|
|
|
-
|
134,307
|
Acquisitions
|
29,103
|
7,586
|
209,254
|
|
|
36,689
|
315,438
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Year Ended
|
By category
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
|
Dec 31,
|
Dec 31,
|
($M)
|
2013
|
2013
|
2012
|
|
|
2013
|
2012
|
Land
|
2,676
|
(4,450)
|
462
|
|
|
3,662
|
46,508
|
Seismic
|
1,942
|
5,284
|
3,963
|
|
|
16,608
|
8,742
|
Drilling and completion
|
68,993
|
63,590
|
76,774
|
|
|
279,003
|
215,261
|
Production equipment and facilities
|
63,420
|
47,665
|
64,232
|
|
|
201,846
|
150,396
|
Recompletions
|
3,309
|
15,650
|
5,040
|
|
|
27,600
|
12,044
|
Other
|
8,138
|
7,922
|
6,564
|
|
|
22,634
|
19,587
|
Dispositions
|
-
|
-
|
-
|
|
|
(8,627)
|
-
|
Capital expenditures
|
148,478
|
135,661
|
157,035
|
|
|
542,726
|
452,538
|
Acquisitions
|
29,103
|
7,586
|
209,254
|
|
|
36,689
|
315,438
|
Total capital expenditures and acquisitions
|
177,581
|
143,247
|
366,289
|
|
|
579,415
|
767,976
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Year Ended
|
By country
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
|
Dec 31,
|
Dec 31,
|
($M)
|
2013
|
2013
|
2012
|
|
|
2013
|
2012
|
Canada
|
78,848
|
69,856
|
82,844
|
|
|
250,386
|
271,843
|
France
|
31,899
|
23,664
|
95,905
|
|
|
100,378
|
228,444
|
Netherlands
|
43,198
|
8,316
|
8,118
|
|
|
56,043
|
21,324
|
Australia
|
8,420
|
5,880
|
25,257
|
|
|
77,931
|
49,389
|
Ireland
|
14,472
|
35,028
|
152,400
|
|
|
90,898
|
193,071
|
Corporate
|
744
|
503
|
1,765
|
|
|
3,779
|
3,905
|
Total capital expenditures and acquisitions
|
177,581
|
143,247
|
366,289
|
|
|
579,415
|
767,976
|
Supplemental Table 4: Production
|
|
Q4/13
|
Q3/13
|
Q2/13
|
Q1/13
|
Q4/12
|
Q3/12
|
Q2/12
|
Q1/12
|
Q4/11
|
Q3/11
|
Q2/11
|
Q1/11
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
8,719
|
7,969
|
8,885
|
7,966
|
7,983
|
7,322
|
7,757
|
7,574
|
6,591
|
4,526
|
3,856
|
3,801
|
|
NGLs (bbls/d)
|
1,699
|
1,897
|
1,725
|
1,335
|
1,106
|
1,204
|
1,321
|
1,302
|
1,246
|
1,305
|
1,353
|
1,285
|
|
Natural gas (mmcf/d)
|
41.43
|
43.40
|
43.69
|
41.04
|
31.41
|
35.54
|
41.32
|
41.83
|
43.96
|
42.94
|
43.30
|
43.31
|
|
Total (boe/d)
|
17,322
|
17,099
|
17,892
|
16,140
|
14,323
|
14,449
|
15,965
|
15,848
|
15,163
|
12,987
|
12,426
|
12,304
|
|
% of consolidated
|
43%
|
41%
|
42%
|
41%
|
40%
|
40%
|
40%
|
40%
|
41%
|
38%
|
35%
|
36%
|
France
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
11,131
|
11,625
|
10,390
|
10,330
|
9,843
|
9,767
|
9,931
|
10,270
|
7,819
|
7,946
|
8,273
|
8,411
|
|
Natural gas (mmcf/d)
|
-
|
5.23
|
4.19
|
4.21
|
3.91
|
3.39
|
3.57
|
3.48
|
0.94
|
0.97
|
0.88
|
1.02
|
|
Total (boe/d)
|
11,131
|
12,496
|
11,088
|
11,032
|
10,495
|
10,333
|
10,526
|
10,850
|
7,976
|
8,108
|
8,419
|
8,582
|
|
% of consolidated
|
27%
|
30%
|
26%
|
29%
|
29%
|
28%
|
27%
|
28%
|
22%
|
23%
|
24%
|
25%
|
Netherlands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d)
|
62
|
48
|
50
|
96
|
70
|
41
|
84
|
72
|
66
|
64
|
54
|
46
|
|
Natural gas (mmcf/d)
|
37.53
|
28.78
|
38.52
|
36.91
|
33.03
|
34.59
|
33.74
|
35.08
|
34.58
|
33.15
|
33.77
|
29.96
|
|
Total (boe/d)
|
6,318
|
4,845
|
6,470
|
6,248
|
5,574
|
5,806
|
5,707
|
5,919
|
5,829
|
5,589
|
5,682
|
5,039
|
|
% of consolidated
|
15%
|
12%
|
15%
|
16%
|
15%
|
16%
|
15%
|
15%
|
16%
|
16%
|
16%
|
15%
|
Australia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
6,189
|
7,070
|
7,363
|
5,287
|
5,873
|
5,958
|
6,970
|
6,648
|
7,686
|
7,992
|
8,692
|
8,309
|
|
% of consolidated
|
15%
|
17%
|
17%
|
14%
|
16%
|
16%
|
18%
|
17%
|
21%
|
23%
|
25%
|
24%
|
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil & NGLs (bbls/d)
|
27,800
|
28,609
|
28,413
|
25,014
|
24,875
|
24,292
|
26,063
|
25,866
|
23,408
|
21,833
|
22,228
|
21,852
|
|
% of consolidated
|
68%
|
69%
|
66%
|
65%
|
69%
|
66%
|
67%
|
66%
|
64%
|
63%
|
63%
|
64%
|
|
Natural gas (mmcf/d)
|
78.96
|
77.41
|
86.40
|
82.16
|
68.34
|
73.52
|
78.63
|
80.39
|
79.48
|
77.06
|
77.95
|
74.29
|
|
% of consolidated
|
32%
|
31%
|
34%
|
35%
|
31%
|
34%
|
33%
|
34%
|
36%
|
37%
|
37%
|
36%
|
|
Total (boe/d)
|
40,960
|
41,510
|
42,813
|
38,707
|
36,265
|
36,546
|
39,168
|
39,265
|
36,654
|
34,676
|
35,219
|
34,234
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2013
|
2012
|
2011
|
2010
|
2009
|
2008
|
|
|
|
|
|
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
8,387
|
7,659
|
4,701
|
2,778
|
2,137
|
2,620
|
|
|
|
|
|
|
|
NGLs (bbls/d)
|
1,666
|
1,232
|
1,297
|
1,427
|
1,518
|
1,551
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
42.39
|
37.50
|
43.38
|
43.91
|
47.85
|
51.15
|
|
|
|
|
|
|
|
Total (boe/d)
|
17,117
|
15,142
|
13,227
|
11,524
|
11,629
|
12,696
|
|
|
|
|
|
|
|
% of consolidated
|
41%
|
40%
|
38%
|
36%
|
37%
|
38%
|
|
|
|
|
|
|
France
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
10,873
|
9,952
|
8,110
|
8,347
|
8,246
|
8,514
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
3.40
|
3.59
|
0.95
|
0.92
|
1.05
|
1.17
|
|
|
|
|
|
|
|
Total (boe/d)
|
11,440
|
10,550
|
8,269
|
8,501
|
8,421
|
8,710
|
|
|
|
|
|
|
|
% of consolidated
|
28%
|
28%
|
23%
|
26%
|
27%
|
27%
|
|
|
|
|
|
|
Netherlands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (bbls/d)
|
64
|
67
|
58
|
35
|
23
|
24
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
35.42
|
34.11
|
32.88
|
28.31
|
21.06
|
27.23
|
|
|
|
|
|
|
|
Total (boe/d)
|
5,967
|
5,751
|
5,538
|
4,753
|
3,533
|
4,562
|
|
|
|
|
|
|
|
% of consolidated
|
15%
|
15%
|
16%
|
15%
|
11%
|
14%
|
|
|
|
|
|
|
Australia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil (bbls/d)
|
6,481
|
6,360
|
8,168
|
7,354
|
7,812
|
6,773
|
|
|
|
|
|
|
|
% of consolidated
|
16%
|
17%
|
23%
|
23%
|
25%
|
21%
|
|
|
|
|
|
|
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil & NGLs (bbls/d)
|
27,471
|
25,270
|
22,334
|
19,941
|
19,735
|
19,483
|
|
|
|
|
|
|
|
% of consolidated
|
67%
|
67%
|
63%
|
62%
|
63%
|
60%
|
|
|
|
|
|
|
|
Natural gas (mmcf/d)
|
81.21
|
75.20
|
77.21
|
73.14
|
69.96
|
79.55
|
|
|
|
|
|
|
|
% of consolidated
|
33%
|
33%
|
37%
|
38%
|
37%
|
40%
|
|
|
|
|
|
|
|
Total (boe/d)
|
41,005
|
37,803
|
35,202
|
32,132
|
31,395
|
32,741
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Table 5: Segmented Financial Results
|
Three Months Ended December 31, 2013
|
($M)
|
Canada
|
|
France
|
|
Netherlands
|
|
Australia
|
|
Ireland
|
|
Corporate
|
|
Total
|
Oil and gas sales to external customers
|
97,367
|
|
110,757
|
|
39,451
|
|
77,533
|
|
-
|
|
-
|
|
325,108
|
Royalties
|
(11,039)
|
|
(6,577)
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(17,616)
|
Revenue from external customers
|
86,328
|
|
104,180
|
|
39,451
|
|
77,533
|
|
-
|
|
-
|
|
307,492
|
Transportation expense
|
(4,102)
|
|
(4,622)
|
|
-
|
|
-
|
|
(357)
|
|
-
|
|
(9,081)
|
Operating expense
|
(13,218)
|
|
(15,524)
|
|
(6,179)
|
|
(13,219)
|
|
-
|
|
-
|
|
(48,140)
|
General and administration
|
(2,478)
|
|
(5,080)
|
|
(1,553)
|
|
(1,442)
|
|
(482)
|
|
(2,919)
|
|
(13,954)
|
Corporate income taxes
|
-
|
|
(28,024)
|
|
(8,267)
|
|
(6,210)
|
|
-
|
|
(564)
|
|
(43,065)
|
PRRT
|
-
|
|
-
|
|
-
|
|
(17,173)
|
|
-
|
|
-
|
|
(17,173)
|
Interest expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(10,049)
|
|
(10,049)
|
Realized loss on derivative instruments
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(1,300)
|
|
(1,300)
|
Realized foreign exchange loss
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(1,294)
|
|
(1,294)
|
Realized other income
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
224
|
|
224
|
Fund flows from operations
|
66,530
|
|
50,930
|
|
23,452
|
|
39,489
|
|
(839)
|
|
(15,902)
|
|
163,660
|
|
|
|
Year Ended December 31, 2013
|
($M)
|
Canada
|
|
France
|
|
Netherlands
|
|
Australia
|
|
Ireland
|
|
Corporate
|
|
Total
|
Total assets
|
1,212,056
|
|
901,582
|
|
228,869
|
|
322,773
|
|
747,882
|
|
295,557
|
|
3,708,719
|
Drilling and development
|
232,858
|
|
96,479
|
|
28,543
|
|
77,931
|
|
90,898
|
|
2,228
|
|
528,937
|
Exploration and evaluation
|
8,339
|
|
3,899
|
|
-
|
|
-
|
|
-
|
|
1,551
|
|
13,789
|
Oil and gas sales to external customers
|
382,005
|
|
453,315
|
|
139,570
|
|
298,945
|
|
-
|
|
-
|
|
1,273,835
|
Royalties
|
(40,891)
|
|
(27,045)
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(67,936)
|
Revenue from external customers
|
341,114
|
|
426,270
|
|
139,570
|
|
298,945
|
|
-
|
|
-
|
|
1,205,899
|
Transportation expense
|
(12,254)
|
|
(12,505)
|
|
-
|
|
-
|
|
(4,165)
|
|
-
|
|
(28,924)
|
Operating expense
|
(55,804)
|
|
(66,997)
|
|
(20,617)
|
|
(51,625)
|
|
-
|
|
-
|
|
(195,043)
|
General and administration
|
(12,979)
|
|
(19,657)
|
|
(2,724)
|
|
(5,752)
|
|
(1,442)
|
|
(7,356)
|
|
(49,910)
|
Corporate income taxes
|
-
|
|
(94,524)
|
|
(34,132)
|
|
(31,735)
|
|
-
|
|
(1,403)
|
|
(161,794)
|
PRRT
|
-
|
|
-
|
|
-
|
|
(56,565)
|
|
-
|
|
-
|
|
(56,565)
|
Interest expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(38,183)
|
|
(38,183)
|
Realized loss on derivative instruments
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(7,082)
|
|
(7,082)
|
Realized foreign exchange loss
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(1,866)
|
|
(1,866)
|
Realized other income
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
994
|
|
994
|
Fund flows from operations
|
260,077
|
|
232,587
|
|
82,097
|
|
153,268
|
|
(5,607)
|
|
(54,896)
|
|
667,526
|
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 are unlikely to 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 audited consolidated financial statements for
the year ended December 31, 2013, 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
|
|
|
Year Ended
|
|
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
|
Dec 31,
|
Dec 31,
|
($M)
|
2013
|
2013
|
2012
|
|
|
2013
|
2012
|
Cash flows from operating activities
|
177,003
|
158,236
|
99,907
|
|
|
705,025
|
496,580
|
Changes in non-cash operating working capital
|
(18,769)
|
4,671
|
33,406
|
|
|
(49,421)
|
47,409
|
Asset retirement obligations settled
|
5,426
|
2,738
|
8,424
|
|
|
11,922
|
13,739
|
Fund flows from operations
|
163,660
|
165,645
|
141,737
|
|
|
667,526
|
557,728
|
Expenses related to Corrib
|
839
|
876
|
2,023
|
|
|
5,607
|
8,902
|
Fund flows from operations (excluding Corrib)
|
164,499
|
166,521
|
143,760
|
|
|
673,133
|
566,630
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
|
Year Ended
|
|
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
|
|
Dec 31,
|
Dec 31,
|
($M)
|
2013
|
2013
|
2012
|
|
|
2013
|
2012
|
Dividends declared
|
61,208
|
61,003
|
56,435
|
|
|
242,599
|
223,717
|
Issuance of shares pursuant to the dividend reinvestment plan
|
(18,775)
|
(19,354)
|
(18,468)
|
|
|
(72,291)
|
(72,058)
|
Net dividends
|
42,433
|
41,649
|
37,967
|
|
|
170,308
|
151,659
|
Drilling and development
|
147,929
|
135,110
|
151,157
|
|
|
537,564
|
413,221
|
Dispositions
|
-
|
-
|
-
|
|
|
(8,627)
|
-
|
Exploration and evaluation
|
549
|
551
|
5,878
|
|
|
13,789
|
39,317
|
Asset retirement obligations settled
|
5,426
|
2,738
|
8,424
|
|
|
11,922
|
13,739
|
Payout
|
196,337
|
180,048
|
203,426
|
|
|
724,956
|
617,936
|
Payout relating to Corrib
|
(14,472)
|
(35,028)
|
(18,092)
|
|
|
(90,898)
|
(58,666)
|
Payout (excluding Corrib)
|
181,865
|
145,020
|
185,334
|
|
|
634,058
|
559,270
|
|
As At
|
|
Dec 31,
|
Sept 30,
|
Dec 31,
|
('000s of shares)
|
2013
|
2013
|
2012
|
Shares outstanding
|
102,123
|
101,787
|
99,135
|
Potential shares issuable pursuant to the VIP
|
2,746
|
2,408
|
2,778
|
Diluted shares outstanding
|
104,869
|
104,195
|
101,913
|
|
|
|
|
MANAGEMENT'S REPORT TO SHAREHOLDERS
Management's Responsibility for Financial Statements
The accompanying consolidated financial statements of Vermilion Energy
Inc. are the responsibility of management and have been approved by the
Board of Directors of Vermilion Energy Inc. The consolidated financial
statements have been prepared in accordance with the accounting
policies detailed in the notes to the consolidated financial statements
and are prepared in accordance with International Financial Reporting
Standards as issued by the International Accounting Standards Board.
Where necessary, management has made informed judgements and estimates
of transactions that were not yet completed at the balance sheet date.
Financial information throughout the Annual Report is consistent with
the consolidated financial statements.
Management ensures the integrity of the consolidated financial
statements by maintaining high-quality systems of internal control.
Procedures and policies are designed to provide reasonable assurance
that assets are safeguarded and transactions are properly recorded, and
that the financial records are reliable for preparation of the
consolidated financial statements. Deloitte LLP, Vermilion's external
auditors, have conducted an audit of the consolidated financial
statements in accordance with Canadian generally accepted auditing
standards and the standards of the Public Company Accounting Oversight
Board (United States) and have provided their report.
The Board of Directors is responsible for ensuring that management
fulfills its responsibility for financial reporting and internal
control. The Board carries out this responsibility principally through
the Audit Committee, which is appointed by the Board and is comprised
entirely of independent Directors. The Committee meets periodically
with management and Deloitte LLP to satisfy itself that each party is
properly discharging its responsibilities and to review the
consolidated financial statements, the Management's Discussion and
Analysis and the external Auditor's Report before they are presented to
the Board of Directors.
Management's Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining an adequate
system of internal control over financial reporting. Management
conducted an evaluation of the effectiveness of the system of internal
control over financial reporting based on the criteria established in
"Internal Control - Integrated Framework (1992)" issued by the
Committee of Sponsoring Organizations of the Treadway Commission.
Based on this evaluation, management has assessed the effectiveness of
Vermilion's internal control over financial reporting as defined in
Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined
in Canada by National Instrument 52-109, Certification of Disclosure in
Issuers' Annual and Interim Filings. Management concluded that
Vermilion's internal control over financial reporting was effective as
of December 31, 2013. The effectiveness of Vermilion's internal control
over financial reporting as of December 31, 2013 has been audited by
Deloitte LLP, the Company's Independent Registered Public Accounting
Firm, who also audited the Company's consolidated financial statements
for the year ended December 31, 2013.
("Lorenzo Donadeo")
|
|
|
|
("Curtis W. Hicks")
|
|
|
|
|
|
Lorenzo Donadeo
|
|
|
|
Curtis W. Hicks
|
Chief Executive Officer
|
|
|
|
Chief Financial Officer
|
February 27, 2014
|
|
|
|
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Vermilion Energy Inc.
We have audited the internal control over financial reporting of
Vermilion Energy Inc. and subsidiaries (the "Company") as of December 31, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway
Commission. The Company's management is responsible for maintaining
effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial
reporting, included in the accompanying Management's Report on Internal
Control over Financial Reporting. Our responsibility is to express an
opinion on the Company's internal control over financial reporting
based on our audit.
We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over financial
reporting was maintained in all material respects. Our audit included
obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, testing
and evaluating the design and operating effectiveness of internal
control based on the assessed risk, and performing such other
procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process
designed by, or under the supervision of, the company's principal
executive and principal financial officers, or persons performing
similar functions, and effected by the company's board of directors,
management, and other personnel to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
International Financial Reporting Standards. A company's internal
control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions
of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of
financial statements in accordance with International Financial
Reporting Standards, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and
directors of the company; and (3) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition,
use, or disposition of the company's assets that could have a material
effect on the financial statements.
Because of the inherent limitations of internal control over financial
reporting, including the possibility of collusion or improper
management override of controls, material misstatements due to error or
fraud may not be prevented or detected on a timely basis. Also,
projections of any evaluation of the effectiveness of the internal
control over financial reporting to future periods are subject to the
risk that the controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31,
2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway
Commission.
We have also audited, in accordance with Canadian generally accepted
auditing standards and the standards of the Public Company Accounting
Oversight Board (United States), the consolidated financial statements
as at and for the year ended December 31, 2013 of the Company and our
report dated February 27, 2014 expressed an unqualified opinion on
those financial statements.
("Deloitte LLP")
Chartered Accountants
|
|
February 27, 2014
Calgary, Canada
|
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Vermilion Energy Inc.
We have audited the accompanying consolidated financial statements of
Vermilion Energy Inc. and subsidiaries (the "Company"), which comprise
the consolidated balance sheets as at December 31, 2013 and 2012, and
the consolidated statements of net earnings and comprehensive income,
consolidated statements of changes in shareholders' equity and
consolidated statements of cash flows for the years then ended, and
notes to the consolidated financial statements.
Management's Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of
these consolidated financial statements in accordance with
International Financial Reporting Standards as issued by the
International Accounting Standards Board, and for such internal control
as management determines is necessary to enable the preparation of
consolidated financial statements that are free from material
misstatement, whether due to fraud or error.
Auditor's Responsibility
Our responsibility is to express an opinion on these consolidated
financial statements based on our audits. We conducted our audits in
accordance with Canadian generally accepted auditing standards and the
standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we comply with ethical
requirements and plan and perform the audit to obtain reasonable
assurance about whether the consolidated financial statements are free
from material misstatement.
An audit involves performing procedures to obtain audit evidence about
the amounts and disclosures in the consolidated financial statements.
The procedures selected depend on the auditor's judgment, including the
assessment of the risks of material misstatement of the consolidated
financial statements, whether due to fraud or error. In making those
risk assessments, the auditor considers internal control relevant to
the entity's preparation and fair presentation of the consolidated
financial statements in order to design audit procedures that are
appropriate in the circumstances. An audit also includes evaluating the
appropriateness of accounting policies used and the reasonableness of
accounting estimates made by management, as well as evaluating the
overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is
sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in
all material respects, the financial position of Vermilion Energy Inc.
and subsidiaries as at December 31, 2013 and 2012, and their financial
performance and their cash flows for the years then ended in accordance
with International Financial Reporting Standards as issued by the
International Accounting Standards Board.
Other Matter
We have also audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the Company's
internal control over financial reporting as of December 31, 2013,
based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated February 27, 2014 expressed an unqualified opinion on the Company's internal control over
financial reporting.
("Deloitte LLP")
Chartered Accountants
|
|
February 27, 2014
Calgary, Canada
|
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF CANADIAN DOLLARS)
|
|
December 31,
|
December 31,
|
|
Note
|
|
2013
|
|
2012
|
ASSETS
|
|
|
|
|
|
Current
|
|
|
|
|
|
Cash and cash equivalents
|
17
|
|
389,559
|
|
102,125
|
Accounts receivable
|
|
|
167,618
|
|
180,064
|
Crude oil inventory
|
|
|
17,143
|
|
25,719
|
Derivative instruments
|
13
|
|
2,285
|
|
2,086
|
Prepaid expenses
|
|
|
11,178
|
|
10,508
|
|
|
|
587,783
|
|
320,502
|
|
|
|
|
|
|
Deferred taxes
|
9
|
|
184,832
|
|
193,354
|
Exploration and evaluation assets
|
6
|
|
136,259
|
|
117,161
|
Capital assets
|
5
|
|
2,799,845
|
|
2,445,240
|
|
|
|
3,708,719
|
|
3,076,257
|
|
|
|
|
|
|
LIABILITIES
|
|
|
|
|
|
Current
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
|
267,832
|
|
300,682
|
Dividends payable
|
10
|
|
20,425
|
|
18,836
|
Derivative instruments
|
13
|
|
3,572
|
|
8,484
|
Income taxes payable
|
9
|
|
55,615
|
|
27,709
|
|
|
|
347,444
|
|
355,711
|
|
|
|
|
|
|
Long-term debt
|
8
|
|
990,024
|
|
642,022
|
Asset retirement obligations
|
7
|
|
326,162
|
|
371,063
|
Deferred taxes
|
9
|
|
328,714
|
|
288,815
|
|
|
|
1,992,344
|
|
1,657,611
|
|
|
|
|
|
|
SHAREHOLDERS' EQUITY
|
|
|
|
|
|
Shareholders' capital
|
10
|
|
1,618,443
|
|
1,481,345
|
Contributed surplus
|
|
|
75,427
|
|
69,581
|
Accumulated other comprehensive income (loss)
|
|
|
47,142
|
|
(32,409)
|
Deficit
|
|
|
(24,637)
|
|
(99,871)
|
|
|
|
1,716,375
|
|
1,418,646
|
|
|
|
3,708,719
|
|
3,076,257
|
APPROVED BY THE BOARD
(Signed "Kenneth Davidson")
|
|
|
|
|
|
(Signed "Lorenzo Donadeo")
|
W. Kenneth Davidson, Director
|
|
|
|
|
|
Lorenzo Donadeo, Director
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF NET EARNINGS AND COMPREHENSIVE INCOME
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS)
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
December 31,
|
|
Note
|
|
2013
|
|
2012
|
REVENUE
|
|
|
|
|
|
Petroleum and natural gas sales
|
|
|
1,273,835
|
|
1,083,103
|
Royalties
|
|
|
(67,936)
|
|
(52,084)
|
Petroleum and natural gas revenue
|
|
|
1,205,899
|
|
1,031,019
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
Operating
|
21
|
|
195,043
|
|
178,442
|
Transportation
|
|
|
28,924
|
|
24,113
|
Equity based compensation
|
11
|
|
60,845
|
|
47,104
|
Loss on derivative instruments
|
13
|
|
1,971
|
|
6,986
|
Interest expense
|
|
|
38,183
|
|
27,586
|
General and administration
|
21
|
|
49,910
|
|
43,773
|
Foreign exchange (gain) loss
|
|
|
(50,162)
|
|
1,546
|
Other expense
|
4
|
|
457
|
|
8,751
|
Accretion
|
7
|
|
24,565
|
|
23,040
|
Depletion and depreciation
|
5, 6
|
|
322,386
|
|
295,943
|
Impairment (recovery)
|
5
|
|
(47,400)
|
|
65,800
|
Gain on acquisition
|
4
|
|
-
|
|
(45,309)
|
|
|
|
624,722
|
|
677,775
|
EARNINGS BEFORE INCOME TAXES
|
|
|
581,177
|
|
353,244
|
|
|
|
|
|
|
INCOME TAXES
|
9
|
|
|
|
|
Deferred
|
|
|
35,177
|
|
(19,291)
|
Current
|
|
|
218,359
|
|
181,913
|
|
|
|
253,536
|
|
162,622
|
|
|
|
|
|
|
NET EARNINGS
|
|
|
327,641
|
|
190,622
|
|
|
|
|
|
|
OTHER COMPREHENSIVE INCOME
|
|
|
|
|
|
Currency translation adjustments
|
|
|
79,551
|
|
978
|
COMPREHENSIVE INCOME
|
|
|
407,192
|
|
191,600
|
|
|
|
|
|
|
NET EARNINGS PER SHARE
|
12
|
|
|
|
|
Basic
|
|
|
3.24
|
|
1.94
|
Diluted
|
|
|
3.20
|
|
1.92
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING ('000s)
|
12
|
|
|
|
|
Basic
|
|
|
100,969
|
|
98,016
|
Diluted
|
|
|
102,467
|
|
99,294
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF CANADIAN DOLLARS)
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
December 31,
|
|
Note
|
|
2013
|
|
2012
|
OPERATING
|
|
|
|
|
|
Net earnings
|
|
|
327,641
|
|
190,622
|
Adjustments:
|
|
|
|
|
|
|
Accretion
|
7
|
|
24,565
|
|
23,040
|
|
Depletion and depreciation
|
5, 6
|
|
322,386
|
|
295,943
|
|
Impairment (recovery)
|
5
|
|
(47,400)
|
|
65,800
|
|
Gain on acquisition
|
4
|
|
-
|
|
(45,309)
|
|
Unrealized gain on derivative instruments
|
13
|
|
(5,111)
|
|
(5,751)
|
|
Equity based compensation
|
11
|
|
60,845
|
|
47,104
|
|
Unrealized foreign exchange (gain) loss
|
|
|
(52,028)
|
|
4,350
|
|
Unrealized other expense
|
|
|
1,451
|
|
1,220
|
|
Deferred taxes
|
9
|
|
35,177
|
|
(19,291)
|
Asset retirement obligations settled
|
7
|
|
(11,922)
|
|
(13,739)
|
Changes in non-cash operating working capital
|
14
|
|
49,421
|
|
(47,409)
|
Cash flows from operating activities
|
|
|
705,025
|
|
496,580
|
|
|
|
|
|
|
INVESTING
|
|
|
|
|
|
Drilling and development
|
5
|
|
(537,564)
|
|
(413,221)
|
Exploration and evaluation
|
6
|
|
(13,789)
|
|
(39,317)
|
Property acquisitions
|
4, 6
|
|
(9,189)
|
|
(106,184)
|
Dispositions
|
5
|
|
8,627
|
|
-
|
Corporate acquisitions, net of cash acquired
|
4
|
|
(24,124)
|
|
(63,482)
|
Payment of amount due pursuant to acquisition
|
|
|
-
|
|
(134,307)
|
Changes in non-cash investing working capital
|
14
|
|
(41,691)
|
|
16,588
|
Cash flows used in investing activities
|
|
|
(617,730)
|
|
(739,923)
|
|
|
|
|
|
|
FINANCING
|
|
|
|
|
|
Increase in long-term debt
|
8
|
|
347,284
|
|
265,395
|
Issuance of shares pursuant to the dividend reinvestment plan
|
10
|
|
-
|
|
36,339
|
Cash dividends
|
10
|
|
(168,719)
|
|
(187,484)
|
Cash flows from financing activities
|
|
|
178,565
|
|
114,250
|
Foreign exchange gain (loss) on cash held in foreign currencies
|
|
|
21,574
|
|
(3,289)
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
287,434
|
|
(132,382)
|
Cash and cash equivalents, beginning of year
|
|
|
102,125
|
|
234,507
|
Cash and cash equivalents, end of year
|
17
|
|
389,559
|
|
102,125
|
|
|
|
|
|
|
Supplementary information for operating activities - cash payments
|
|
|
|
|
|
|
Interest paid
|
|
|
37,562
|
|
30,792
|
|
Income taxes paid
|
|
|
192,865
|
|
190,611
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(THOUSANDS OF CANADIAN DOLLARS)
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
Total
|
|
|
Shareholders'
|
Contributed
|
Comprehensive
|
|
Shareholders'
|
|
Note
|
Capital
|
Surplus
|
|
Loss
|
Deficit
|
Equity
|
Balances as at January 1, 2012
|
|
|
1,368,145
|
|
56,468
|
|
(33,387)
|
|
(59,625)
|
|
1,331,601
|
Net earnings
|
|
|
-
|
|
-
|
|
-
|
|
190,622
|
|
190,622
|
Currency translation adjustments
|
|
|
-
|
|
-
|
|
978
|
|
-
|
|
978
|
Equity based compensation expense
|
11
|
|
-
|
|
46,468
|
|
-
|
|
-
|
|
46,468
|
Dividends declared
|
10
|
|
-
|
|
-
|
|
-
|
|
(223,717)
|
|
(223,717)
|
Issuance of shares pursuant to the dividend reinvestment plan
|
10
|
|
72,058
|
|
-
|
|
-
|
|
-
|
|
72,058
|
Vesting of equity based awards
|
10, 11
|
|
33,355
|
|
(33,355)
|
|
-
|
|
-
|
|
-
|
Share-settled dividends on vested equity based awards
|
10, 11
|
|
7,151
|
|
-
|
|
-
|
|
(7,151)
|
|
-
|
Shares issued pursuant to the bonus plan
|
10
|
|
636
|
|
-
|
|
-
|
|
-
|
|
636
|
Balances as at December 31, 2012
|
|
|
1,481,345
|
|
69,581
|
|
(32,409)
|
|
(99,871)
|
|
1,418,646
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
Total
|
|
|
Shareholders'
|
Contributed
|
Comprehensive
|
|
Shareholders'
|
|
Note
|
Capital
|
Surplus
|
|
Income
|
Deficit
|
Equity
|
Balances as at January 1, 2013
|
|
|
1,481,345
|
|
69,581
|
|
(32,409)
|
|
(99,871)
|
|
1,418,646
|
Net earnings
|
|
|
-
|
|
-
|
|
-
|
|
327,641
|
|
327,641
|
Currency translation adjustments
|
|
|
-
|
|
-
|
|
79,551
|
|
-
|
|
79,551
|
Equity based compensation expense
|
11
|
|
-
|
|
60,216
|
|
-
|
|
-
|
|
60,216
|
Dividends declared
|
10
|
|
-
|
|
-
|
|
-
|
|
(242,599)
|
|
(242,599)
|
Issuance of shares pursuant to the dividend reinvestment plan
|
10
|
|
72,291
|
|
-
|
|
-
|
|
-
|
|
72,291
|
Vesting of equity based awards
|
10, 11
|
|
54,370
|
|
(54,370)
|
|
-
|
|
-
|
|
-
|
Share-settled dividends on vested equity based awards
|
10, 11
|
|
9,808
|
|
-
|
|
-
|
|
(9,808)
|
|
-
|
Shares issued pursuant to the bonus plan
|
10
|
|
629
|
|
-
|
|
-
|
|
-
|
|
629
|
Balances as at December 31, 2013
|
|
|
1,618,443
|
|
75,427
|
|
47,142
|
|
(24,637)
|
|
1,716,375
|
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 (loss)
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 CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2013 AND 2012
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER
SHARE AMOUNTS)
1. BASIS OF PRESENTATION
Vermilion Energy Inc. (the "Company" or "Vermilion") is a corporation
governed by the laws of the Province of Alberta and is actively engaged
in the business of crude oil and natural gas exploration, development,
acquisition and production.
These consolidated financial statements were approved and authorized for
issuance by the Board of Directors of Vermilion on February 27, 2014.
2. SIGNIFICANT ACCOUNTING POLICIES
Accounting Framework
The consolidated financial statements have been prepared in accordance
with International Financial Reporting Standards ("IFRS") as issued by
the International Accounting Standards Board ("IASB").
Principles of Consolidation
Subsidiaries that are directly controlled by the parent company or
indirectly controlled through other consolidated subsidiaries are fully
consolidated. Vermilion accounts for joint operations by recognizing
its share of assets, liabilities, income and expenses. All significant
intercompany balances, transactions, income and expenses are eliminated
upon consolidation.
Vermilion currently has no special purpose entities of which it retains
control and accordingly the consolidated financial statements do not
include the accounts of any such entities.
Exploration and Evaluation Assets
Vermilion accounts for exploration and evaluation of petroleum and
natural gas property ("E&E") costs in accordance with IFRS 6
"Exploration for and Evaluation of Mineral Resources". Costs incurred
are classified as E&E costs when they relate to exploring and
evaluating a property for which the Company has the licence or right to
explore and extract resources.
E&E costs related to each license or prospect area are initially
capitalized within E&E assets. E&E costs that are capitalized may
include costs of licence acquisitions, technical services and studies,
seismic acquisitions, exploration drilling and testing, directly
attributable overhead and administration expenses and, if applicable,
the estimated costs of retiring the assets. Any costs incurred prior
to the acquisition of the legal rights to explore an area are expensed
as incurred.
E&E assets are not initially depleted and are carried at cost until
technical feasibility and commercial viability of the area can be
determined. The technical feasibility and commercial viability of
extracting the reserves is considered to be determinable when proven
and probable reserves are identified. If proven and probable reserves
are identified as recoverable, the related E&E costs are reclassified
to Petroleum and Natural Gas ("PNG") assets pending an impairment
test. If reserves are not found within the license area or the area is
abandoned, the related E&E costs are amortized over a period not
greater than five years.
Petroleum and Natural Gas Assets
Vermilion recognizes PNG assets at cost less accumulated depletion,
depreciation and impairment losses. Directly attributable costs
incurred for the drilling of development wells and for the construction
of production facilities are capitalized together with the discounted
value of estimated future costs of asset retirement obligations. When
components of PNG assets are replaced, disposed of, or no longer in
use, they are derecognized.
Gains and losses on disposal of a component of PNG assets, including oil
and gas interests, are determined by comparing the proceeds of disposal
with the carrying amount of the component, and are recognized in net
earnings.
Depletion and Depreciation
Vermilion classifies its assets into PNG depletion units, which are
groups of assets or properties that are within a specific production
area and have similar economic lives. The PNG depletion units
represent the lowest level of disaggregation for which Vermilion
accumulates costs for the purposes of calculating and recording
depletion and depreciation.
The net carrying value of each PNG depletion unit is depleted using the
unit of production method by reference to the ratio of production in
the period to the total proven and probable reserves, taking into
account the future development costs necessary to bring the applicable
reserves into production. The reserve estimates are reviewed annually
by management or when material changes occur to the underlying
assumptions.
For the purposes of the depletion calculations, oil and gas reserves are
converted to a common unit of measure on the basis of their relative
energy content based on a conversion ratio of six thousand cubic feet
of natural gas to one barrel of oil equivalent.
Furniture and office equipment are recorded at cost and are depreciated
on a declining-balance basis.
Impairment of Long-Lived Assets
E&E assets are tested for impairment when reclassified to PNG assets or
when indicators of impairment are identified. If indicators of
impairment are identified, E&E assets are tested for impairment as part
of the group of Cash Generating Units ("CGU's") attributable to the
jurisdiction in which the exploration area resides.
PNG depletion units are aggregated into CGUs for impairment testing.
The determination of CGU's is based on managements' judgement and
represents the lowest level at which there are identifiable cash
inflows that are largely independent of the cash inflows of other
groups of assets or properties. CGUs are reviewed for indicators that
the carrying value of the CGU may exceed its recoverable amount. If an
indication of impairment exists, the CGU's recoverable amount is then
estimated. A CGU's recoverable amount is defined as the higher of the
fair value less costs to sell and its value in use. If the carrying
amount exceeds its recoverable amount, an impairment loss is recorded
to net earnings in the period to reduce the carrying value of the CGU
to its recoverable amount.
For PNG assets and E&E assets, when there has been an impairment loss
recognized, at each reporting date an assessment is performed as to
whether the circumstances which led to the impairment loss have
reversed. If the change in circumstances leads to the recoverable
amount being higher than the carrying value after recognition of an
impairment, that impairment loss is reversed, with such reversal not to
exceed the depreciated value of the asset had no impairment loss been
previously recognized.
Cash and Cash Equivalents
Cash and cash equivalents include monies on deposit and short-term
investments, which are comprised primarily of guaranteed investment
certificates.
Crude Oil Inventory
Inventories of crude oil, consisting of production for which title has
not yet transferred to the buyer, are valued at the lower of cost or
net realizable value. Cost is determined on a weighted-average basis
and includes related operating expenses, royalties, and depletion.
Provisions and Asset Retirement Obligations
Vermilion recognizes a provision or asset retirement obligation in the
consolidated financial statements when an event gives rise to an
obligation of uncertain timing or amount.
The estimated present value of the asset retirement obligation is
recorded as a long term liability, with a corresponding increase in the
carrying amount of the related asset. This increase is depleted with
the related depletion unit and is allocated to a CGU for impairment
testing. The liability recorded is increased each reporting period due
to the passage of time and this change is charged to net earnings in
the period as accretion expense. The asset retirement obligation can
also increase or decrease due to changes in the estimated timing of
cash flows, changes in the discount rate and/or changes in the original
estimated undiscounted costs. Increases or decreases in the obligation
will result in a corresponding change in the carrying amount of the
related asset. Actual costs incurred upon settlement of the asset
retirement obligation are charged against the asset retirement
obligation to the extent of the liability recorded. Vermilion discounts
the costs related to asset retirement obligations using the discount
rate that reflects current market assessment of time value of money and
risks specific to the liabilities that have not been reflected in the
cash flow estimates. Vermilion applies discount rates applicable to
each of the jurisdictions in which it has future asset retirement
obligations. Asset retirement obligations are remeasured at each
reporting period in order to reflect the discount rates in effect at
that time.
A provision for onerous contracts is recognized when the expected
benefits to be derived by Vermilion from a contract are lower than the
unavoidable cost of meeting the obligations under the contract. The
provision is measured at the lower of the expected cost of terminating
the contract and the present value of the expected net cost of the
remaining term of the contract. Before a provision is established,
Vermilion first recognizes any impairment loss on assets associated
with the onerous contract. For the periods presented in the
consolidated financial statements there were no onerous contracts
recognized.
Revenue Recognition
Revenues associated with the sale of crude oil, natural gas and natural
gas liquids are recorded when title passes to the customer. For the
majority of Canadian oil and natural gas production, legal title
transfers upon delivery to major pipelines. In Australia, oil is sold
at the Wandoo B Platform. In the Netherlands, natural gas is sold at
the plant gate. In France, oil is sold either when delivered to the
refinery by pipeline or when delivered to the refinery via tanker.
Financial Instruments
Cash and cash equivalents are classified as held for trading and are
measured at fair value. A gain or loss arising from a change in the
fair value is recognized in net earnings in the period in which it
occurs.
Accounts receivable are classified as loans and receivables and are
initially measured at fair value and are then subsequently measured at
amortized cost. The carrying value of accounts receivable approximates
the fair value due to the short-term nature of these instruments.
Accounts payable and accrued liabilities, dividends payable, and
long-term debt have been classified as other financial liabilities and
are initially recognized at fair value and are subsequently measured at
amortized cost. Transaction costs and discounts are recorded against
the fair value of long-term debt on initial recognition.
All derivative instruments have been classified as held for trading and
are measured at fair value. A gain or loss arising from a change in
the fair value is recognized in net earnings in the period in which it
occurs.
Equity Based Compensation
Vermilion has long-term equity based compensation plans for directors,
officers and employees of Vermilion and its subsidiaries. Equity based
compensation expense is recognized in net earnings over the vesting
period of the awards with a corresponding adjustment to contributed
surplus. Upon vesting, the amount previously recognized in contributed
surplus is reclassified to shareholders' capital.
The expense recognized is based on the grant date fair value of the
awards and incorporates an estimate of the forfeiture rate based on
historical vesting data. The grant date fair value of the awards is
determined as the grant date closing price of Vermilion's common shares
on the Toronto Stock Exchange, adjusted by the Company's estimate of
the performance factor that will ultimately be achieved.
Per Share Amounts
Net earnings per share is calculated using the weighted-average number
of shares outstanding during the period. Diluted net earnings per
share is calculated using the diluted weighted-average number of shares
outstanding during the period. The diluted weighted-average number of
shares is determined by considering whether equity based compensation
plans, if converted during the year, would result in reduced net
earnings per share.
The treasury stock method is used to determine the dilutive effect of
equity based compensation plans. The treasury stock method assumes
that the deemed proceeds related to unrecognized equity based
compensation expense are used to repurchase shares at the average
market price during the period. Equity based awards outstanding are
included in the calculation of diluted net earnings per share based on
estimated performance factors.
Foreign Currency Translation
The consolidated financial statements are presented in Canadian dollars,
which is Vermilion's reporting currency. As several of Vermilion's
subsidiaries transact and operate primarily in countries other than
Canada, they accordingly have functional currencies other than the
Canadian dollar.
Transactions denominated in currencies other than the functional
currency of the subsidiary are translated to the functional currency at
the prevailing rates on the date of the transaction. Non-monetary
assets or liabilities that result from such transactions are held at
the prevailing rate on the date of the transaction. Monetary items
denominated in non-functional currencies are translated to the
functional currency of the subsidiary at the prevailing rate at the
balance sheet date. All translations associated with currencies other
than the respective functional currencies are recorded in net earnings.
Translation of all assets and liabilities from the respective functional
currencies to the reporting currency are performed using the rates
prevailing at the balance sheet date. The differences arising upon
translation from the functional currency to the reporting currency are
recorded as currency translation adjustments in other comprehensive
income (loss) and are held within accumulated other comprehensive
income (loss) until a disposal or partial disposal of a subsidiary. A
disposal or partial disposal may give rise to a realized gain or loss,
which is recorded in net earnings.
Within the consolidated group there are outstanding intercompany loans
which in substance represent investments in certain subsidiaries. When
these loans are identified as part of the net investment in a foreign
subsidiary, any exchange differences arising on those loans are
recorded to currency translation adjustments within other comprehensive
income (loss) until the disposal or partial disposal of the subsidiary.
Income Taxes
Deferred taxes are calculated using the liability method of accounting.
Under this method, deferred tax is recognized for the estimated effect
of any temporary differences between the amounts recognized on
Vermilion's consolidated balance sheets and respective tax basis. This
calculation uses enacted or substantively enacted tax rates that will
be in effect when the temporary differences are expected to reverse.
The effect of a change in tax rates on deferred taxes is recognized in
net earnings in the period in which the related legislation is
substantively enacted.
Vermilion is subject to current income taxes based on the tax
legislation of each respective country in which Vermilion conducts
business.
Borrowing Costs
Borrowing costs that are directly attributable to the acquisition or
construction of an asset that necessarily takes a substantial period of
time to prepare for its intended use are capitalized as part of the
cost of that asset. Borrowing costs are capitalized by applying
interest rates attributable to the project being financed and could
include both general and/or specific borrowings. Interest rates applied
from general borrowings are computed using the weighted average
borrowing rate for the period.
Measurement Uncertainty
The preparation of the consolidated financial statements requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities; disclosure of contingent assets and
liabilities at the date of the consolidated financial statements and
the reported amounts of revenues and expenses for the periods
presented.
Key areas where management has made complex or subjective judgements
include asset retirement obligations, assessment of impairment or
recovery of impairment of long-lived assets and income taxes. Actual
results could differ significantly from these and other estimates.
Asset Retirement Obligations
Vermilion's asset retirement obligations are based on environmental
regulations and estimates of the amount and timing of future
expenditures. Changes in environmental regulations, the estimated
costs associated with reclamation activities, the discount rate applied
and the timing of expenditures could materially impact Vermilion's
measurement of the obligations and, correspondingly, impact Vermilion's
financial position and net earnings.
Assessment of Impairments or Recovery of Previous Impairments
Impairment tests are performed at a CGU level. CGUs are determined
based on management's judgment of the lowest level at which there is
identifiable cash inflows that are largely independent of the cash
inflows of other groups of assets or properties. The factors used by
Vermilion to determine CGUs may vary by country due to the unique
operating and geographic circumstances in each country. However, in
general, Vermilion will assess the following factors in determining
whether a group of assets generate largely independent cash inflows:
geographic proximity of the assets within a group to one another,
geographic proximity of the group of assets to other groups of assets,
homogeneity of the production from the group of assets and the sharing
of infrastructure used to process and/or transport production.
The calculation of the recoverable amount of the CGUs is based on market
factors, estimates of PNG reserves and future costs required to develop
reserves. Vermilion's reserve estimates and the related future cash
flows are subject to measurement uncertainty, and the impact on the
consolidated financial statements of future periods could be material.
Considerable management judgment is used in determining the recoverable
amount of PNG assets, including determining the quantity of reserves,
the time horizon to develop and produce such reserves and the estimated
revenues and expenditures of such production.
Income Taxes
Tax interpretations, regulations, and legislation in the various
jurisdictions in which Vermilion and its subsidiaries operate are
subject to change and interpretation. Such changes can affect the
timing of the reversal of temporary tax differences, the tax rates in
effect when such differences reverse and Vermilion's ability to use tax
losses and other tax pools in the future. The Company's income tax
filings are subject to audit by taxation authorities in numerous
jurisdictions and the results of such audits may increase or decrease
our tax liability. The determination of current and deferred tax amounts recognized in the
consolidated financial statements was based on management's assessment
of the tax positions, which includes consideration of their technical
merits, communications with tax authorities and management's view of
the most likely outcome.
3. RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS
On January 1, 2013, 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.
IFRS 10 "Consolidated Financial Statements"
IFRS 10 replaced Standing Interpretations Committee 12, "Consolidation -
Special Purpose Entities" and the consolidation requirements of IAS 27
"Consolidated and Separate Financial Statements". The new standard
replaces the existing risk and rewards based approaches and establishes
control as the determining factor when determining whether an interest
in another entity should be included in the consolidated financial
statements.
IFRS 11 "Joint Arrangements"
IFRS 11 replaced IAS 31 "Interests in Joint Ventures". The new standard
focuses on the rights and obligations of an arrangement, rather than
its legal form. The standard redefines joint operations and joint
ventures and requires joint operations to be proportionately
consolidated and joint ventures to be equity accounted.
IFRS 12 "Disclosure of Interests in Other Entities"
IFRS 12 provides comprehensive disclosure requirements for interests in
other entities, including joint arrangements, associates, and special
purpose entities. The new disclosures are intended to assist financial
statement users in evaluating the nature, risks and financial effects
of an entity's interest in subsidiaries and joint arrangements.
IFRS 13 "Fair Value Measurement"
IFRS 13 provides a common definition of fair value within IFRS. The new
standard provides measurement and disclosure guidance and applies when
another IFRS requires or permits an item to be measured at fair value,
with limited exceptions.
Accounting pronouncements not yet adopted
The impact of the adoption of the following pronouncements are currently
being evaluated, but are not expected to have a material impact on
Vermilion's consolidated financial statements:
IFRIC 21 "Levies"
On May 20, 2013, IASB issued guidance on IFRIC 21, which provides
guidance 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.
IFRS 9 "Financial Instruments"
The IASB has undertaken a three-phase project to replace IAS 39,
"Financial Instruments: Recognition and Measurement". The new standard
replaces the current multiple classification and measurement models for
financial assets and liabilities with a single model that has only two
classification categories: amortized cost and fair value. In February
of 2014, the IASB confirmed that the mandatory effective date of IFRS 9
shall be January 1, 2018.
4. BUSINESS COMBINATIONS
Property acquisition:
France
On January 19, 2012, Vermilion acquired, through its wholly owned
subsidiaries, working interests in six producing fields located in the
Paris and Aquitaine Basins in France, for total consideration of $106.1
million before closing adjustments. The acquired working interests
expanded Vermilion's existing interests and was a natural addition to
the Company's existing France asset base.
The acquired assets include land, wells, facilities, and inventory
located in the Company's core producing basins in France. The fair
value of the acquired identifiable assets and liabilities assumed at
the date of acquisition was $151.4 million. A gain of $45.3 million
was recognized as a result of an increase in the fair value of the
acquired petroleum and natural gas reserves from the time when the
acquisition was negotiated to the acquisition date. The increase
resulted from a change in the underlying commodity price forecasts used
to determine the fair value of the acquired reserves.
The acquisition has been accounted for as a business combination with
the fair value of the assets acquired and liabilities assumed at the
date of acquisition summarized as follows:
($M)
|
Consideration
|
Cash paid to vendor
|
|
106,115
|
Total consideration
|
|
106,115
|
|
|
|
($M)
|
Allocation of Consideration
|
Petroleum and natural gas assets
|
|
206,191
|
Asset retirement obligations assumed
|
|
(27,518)
|
Deferred tax liabilities
|
|
(23,151)
|
Acquired non-cash working capital deficiencies
|
|
(4,098)
|
Net assets acquired
|
|
151,424
|
Gain on acquisition
|
|
(45,309)
|
Net assets acquired, net of gain on acquisition
|
|
106,115
|
|
|
|
Transfer taxes associated with this acquisition totalling $8.5 million
have been excluded from the consideration and have been recognized as
an expense in the year ended December 31, 2012 within "Other expense"
in the consolidated statements of net earnings and comprehensive
income.
Corporate acquisitions:
a) Netherlands
On October 10, 2013, Vermilion acquired, through its wholly-owned
subsidiary, 100% of the shares of Northern Petroleum Nederland B.V., a
subsidiary of UK-based Northern Petroleum Plc. ("Northern") for total
consideration of $27.5 million. The acquisition is a complementary
addition to the existing Netherlands asset base, including interests in
six onshore licences in production or development, three onshore
exploration licenses, and one offshore production license in the
Netherlands. Vermilion funded this acquisition from cash on hand.
The acquisition has been accounted for as a business combination with
the fair value of the assets acquired and liabilities assumed at the
date of acquisition summarized as follows:
($M)
|
Consideration
|
Cash paid to vendor
|
|
27,500
|
Total consideration
|
|
27,500
|
|
|
|
($M)
|
Allocation of Consideration
|
Petroleum and natural gas assets
|
|
47,743
|
Asset retirement obligations assumed
|
|
(12,439)
|
Deferred tax liabilities
|
|
(10,412)
|
Cash acquired
|
|
3,376
|
Acquired non-cash working capital
|
|
(768)
|
Net assets acquired
|
|
27,500
|
The results of operations from the assets acquired have been included in
Vermilion's consolidated financial statements beginning October 10,
2013 and have contributed revenues of $2.7 million and operating income
of $1.0 million for the year ended December 31, 2013.
Had the acquisition occurred on January 1, 2013, management estimates
that consolidated revenues would have increased by an additional $13.5
million and consolidated operating income would have increased by $6.3
million for the year ended December 31, 2013. 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, 2013. It is impracticable to derive all amounts necessary to
determine the increase to net earnings from the acquired working
interests as operations were immediately merged with Vermilion's
operations.
b) France
On December 21, 2012, Vermilion acquired, through its wholly owned
subsidiaries, 100% of the shares of ZaZa Energy France S.A.S for total
consideration of $74.9 million. The acquired company holds operating
interests covering approximately 24,300 acres with 100% working
interests in the Saint Firmin, Chateaurenard, Courtenay, Chuelles, and
Charmottes fields in the Paris Basin. The acquired company expands
Vermilion's existing operations in France and is aligned with
Vermilion's objective to consolidate assets within the Company's core
operating areas.
The acquisition has been accounted for as a business combination with
the fair value of the assets acquired and liabilities assumed at the
date of acquisition summarized as follows:
($M)
|
Consideration
|
Cash paid to vendor
|
|
74,947
|
Total consideration
|
|
74,947
|
|
|
|
($M)
|
Allocation of Consideration
|
Petroleum and natural gas assets
|
|
136,297
|
Asset retirement obligations assumed
|
|
(22,623)
|
Deferred tax liabilities
|
|
(40,046)
|
Cash acquired
|
|
11,465
|
Acquired non-cash working capital
|
|
(10,146)
|
Net assets acquired
|
|
74,947
|
|
|
|
5. CAPITAL ASSETS
The following table reconciles the change in Vermilion's capital assets:
|
Petroleum and
|
Furniture and
|
|
Total
|
($M)
|
Natural Gas Assets
|
Office Equipment
|
|
Capital Assets
|
Balance at January 1, 2012
|
|
2,016,611
|
|
15,071
|
|
2,031,682
|
Additions
|
|
407,973
|
|
5,248
|
|
413,221
|
Transfers from exploration and evaluation assets
|
|
10,528
|
|
-
|
|
10,528
|
Property acquisitions
|
|
206,260
|
|
-
|
|
206,260
|
Corporate acquisitions
|
|
136,297
|
|
-
|
|
136,297
|
Borrowing costs capitalized
|
|
9,994
|
|
-
|
|
9,994
|
Changes in estimate for asset retirement obligations
|
|
1,334
|
|
-
|
|
1,334
|
Depletion and depreciation
|
|
(289,194)
|
|
(5,165)
|
|
(294,359)
|
Impairments
|
|
(65,800)
|
|
-
|
|
(65,800)
|
Effect of movements in foreign exchange rates
|
|
(3,882)
|
|
(35)
|
|
(3,917)
|
Balance at December 31, 2012
|
|
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)
|
Impairment recovery
|
|
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
|
|
|
|
|
|
|
|
|
Cost
|
|
3,260,772
|
|
35,268
|
|
3,296,040
|
Accumulated depletion and depreciation
|
|
(830,651)
|
|
(20,149)
|
|
(850,800)
|
Carrying amount at December 31, 2012
|
|
2,430,121
|
|
15,119
|
|
2,445,240
|
|
|
|
|
|
|
|
|
Cost
|
|
3,938,986
|
|
43,932
|
|
3,982,918
|
Accumulated depletion and depreciation
|
|
(1,154,352)
|
|
(28,721)
|
|
(1,183,073)
|
Carrying amount at December 31, 2013
|
|
2,784,634
|
|
15,211
|
|
2,799,845
|
Depletion and depreciation rates
PNG assets (unit of production method)
Furniture and office equipment (declining balance at rates of 5% to 25%)
Capitalized overhead
During the year ended December 31, 2013, Vermilion capitalized $8.5
million (2012 - $4.8 million) of overhead costs directly attributable
to PNG activities.
Impairments and recovery of previous impairments
On a quarterly basis, Vermilion performs an assessment as to whether any
CGUs have indicators of impairment. When indicators of impairment are
identified, Vermilion assesses the recoverable amount of the applicable
CGU based on the estimated fair value less costs to sell as at the
reporting date. The estimated fair value takes into account the most
recent commodity price forecasts, expected production and estimated
costs of development.
During the years ended December 31, 2013 and 2012, Vermilion performed
assessments as to whether any cash generating units ("CGU") had
indicators of impairment or recovery of previous impairment. In the
fourth quarter of 2013, Vermilion identified indicators of impairment
recovery for a Canadian CGU where impairment charges were previously
recorded for the three months ended December 31, 2011 and March 31,
2012. The impairment recovery resulted from increased proved and
probable reserves of natural gas and natural gas liquids, due primarily
to the successful application of horizontal drilling and multi-stage
fracturing technology to the previously impaired cash generating unit.
Benchmark prices used in the calculations of recoverable amounts were
determined by multiplying the mix of oil, natural gas and NGLs inherent
in the reserves of the conventional deep natural gas and shallow coal
bed methane CGUs by the price forecasts for each year. The blended
price per barrel of oil equivalent (BOE) forecasts were:
$/BOE
|
December 31, 2013
|
March 31, 2012
|
December 31, 2011
|
2014
|
42.09
|
35.78
|
37.12
|
2015
|
44.18
|
38.23
|
39.52
|
2016
|
45.39
|
40.68
|
41.95
|
2017
|
45.41
|
43.13
|
44.34
|
2018
|
45.43
|
45.61
|
45.82
|
2019
|
45.50
|
46.53
|
46.79
|
2020
|
45.86
|
47.51
|
47.72
|
2021
|
46.78
|
48.44
|
48.71
|
Average increase thereafter
|
2.0%
|
2.0%
|
2.0%
|
|
|
|
|
|
|
|
|
6. EXPLORATION AND EVALUATION ASSETS
The following table reconciles the change in Vermilion's exploration and
evaluation assets:
($M)
|
Exploration and Evaluation Assets
|
Balance at January 1, 2012
|
|
92,301
|
Additions
|
|
39,317
|
Transfers to petroleum and natural gas assets
|
|
(10,528)
|
Depreciation
|
|
(3,485)
|
Effect of movements in foreign exchange rates
|
|
(444)
|
Balance at December 31, 2012
|
|
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
|
|
|
|
|
|
Cost
|
|
125,165
|
Accumulated depreciation
|
|
(8,004)
|
Carrying amount at December 31, 2012
|
|
117,161
|
|
|
|
|
|
Cost
|
|
149,175
|
Accumulated depreciation
|
|
(12,916)
|
Carrying amount at December 31, 2013
|
|
136,259
|
7. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the change in Vermilion's asset
retirement obligations:
($M)
|
Asset Retirement Obligations
|
Balance at January 1, 2012
|
|
|
310,531
|
Additional obligations recognized
|
|
|
55,228
|
Changes in estimates for existing obligations
|
|
|
(26,560)
|
Obligations settled
|
|
|
(13,739)
|
Accretion
|
|
|
23,040
|
Changes in discount rates
|
|
|
22,807
|
Effect of movements in foreign exchange rates
|
|
|
(244)
|
Balance at December 31, 2012
|
|
|
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
|
Vermilion has estimated the net present value of its asset retirement
obligations to be $326.2 million as at December 31, 2013 (2012 - $371.1
million) based on a total undiscounted future liability, after
inflation adjustment, of $1.3 billion (2012 - $1.3 billion). These
payments are expected to be made between 2014 and 2063. Vermilion
calculated the present value of the obligations using discount rates
between 6.4% and 8.3% (2012 - between 5.8% and 7.5%) to reflect the
market assessment of the time value of money as well as risks specific
to the liabilities that have not been included in the cash flow
estimates. Inflation rates used in determining the cash flow estimates
were between 1.1% and 2.5% (2012 - between 1.4% and 2.5%).
Vermilion reviews annually its estimates of the expected costs to
reclaim the net interest in its wells and facilities. The resulting
changes are categorized as changes in estimates for existing
obligations in the preceding table. The significant changes in the
liability for the year ended December 31, 2013 primarily resulted from
an overall decrease in the inflation rates applied to the abandonment
obligations.
8. LONG-TERM DEBT
The following table summarizes Vermilion's outstanding long-term debt:
|
As At
|
($M)
|
Dec 31, 2013
|
Dec 31, 2012
|
Revolving credit facility
|
|
766,898
|
|
419,784
|
Senior unsecured notes
|
|
223,126
|
|
222,238
|
Long-term debt
|
|
990,024
|
|
642,022
|
|
|
|
|
|
Revolving Credit Facility
At December 31, 2013, Vermilion had in place a bank revolving credit
facility totalling $1.2 billion, of which approximately $766.9 million
was drawn. The facility, which matures on May 31, 2016, 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 year ended
December 31, 2013, the interest rate on the revolving credit facility
was approximately 3.3% (2012 - 3.3%).
The amount available to Vermilion under this facility is reduced by
certain outstanding letters of credit associated with Vermilion's
operations totalling $8.1 million as at December 31, 2013 (2012 - $49.2
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. In addition,
Vermilion must maintain 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.
As at December 31, 2013, Vermilion was in compliance with its financial
covenants.
Senior Unsecured Notes
On February 10, 2011, Vermilion issued $225.0 million of senior
unsecured notes at par. The notes bear interest at a rate of 6.5% per
annum and will mature on February 10, 2016. As direct senior unsecured
obligations of Vermilion, the notes rank pari passu with all other
present and future unsecured and unsubordinated indebtedness of the
Company.
Vermilion may, at its option, prior to February 10, 2014, redeem up to
35% of the notes with net proceeds of equity offerings by the Company
at a redemption price equal to 106.5% of the principal amount of the
notes to be redeemed, plus accrued and unpaid interest, if any, to the
applicable redemption date. Subsequently, Vermilion may, on or after
February 10, 2014, redeem all or part of the notes at fixed redemption
prices, plus, in each case, accrued and unpaid interest, if any, to the
applicable redemption date. The notes were initially recognized at
fair value net of transaction costs and are subsequently measured at
amortized cost using an effective interest rate of 7.1%.
9. INCOME TAXES
Deferred taxes
The net deferred income tax liability at December 31, 2013 and 2012 is
comprised of the following:
|
|
Year Ended
|
($M)
|
Dec 31, 2013
|
Dec 31, 2012
|
Deferred income tax liabilities:
|
|
|
|
|
|
Capital assets
|
|
(332,740)
|
|
(322,620)
|
|
Asset retirement obligations
|
|
(87,888)
|
|
(45,362)
|
|
Basis difference of investments
|
|
(189)
|
|
(330)
|
|
Unrealized foreign exchange
|
|
(13,017)
|
|
(22,603)
|
|
Other
|
|
(12,383)
|
|
(11,502)
|
Deferred income tax assets:
|
|
|
|
|
|
Derivative contracts
|
|
323
|
|
1,600
|
|
Capital assets
|
|
75,352
|
|
67,310
|
|
Non-capital losses
|
|
170,625
|
|
167,230
|
|
Asset retirement obligations
|
|
54,037
|
|
69,359
|
|
Other
|
|
1,998
|
|
1,457
|
Net deferred income tax liability
|
|
(143,882)
|
|
(95,461)
|
Comprised of:
|
|
|
|
|
|
Deferred income tax assets
|
|
184,832
|
|
193,354
|
|
Deferred income tax liability
|
|
(328,714)
|
|
(288,815)
|
Net deferred income tax liability
|
|
(143,882)
|
|
(95,461)
|
Income tax expense differs from the amount that would have been expected
if the reported earnings had been subject only to the statutory
Canadian income tax rate of 25.0% (2012 - 25.0%), as follows:
|
|
Year Ended
|
($M)
|
Dec 31, 2013
|
Dec 31, 2012
|
Earnings before income taxes
|
|
581,177
|
|
353,244
|
Canadian corporate tax rate
|
|
25.0%
|
|
25.0%
|
Expected tax expense
|
|
145,294
|
|
88,311
|
Increase (decrease) in taxes resulting from:
|
|
|
|
|
|
Petroleum resource rent tax rate (PRRT) differential (1)
|
|
50,585
|
|
44,605
|
|
Foreign tax rate differentials (1) (2)
|
|
1,875
|
|
18,539
|
|
Equity based compensation expense
|
|
15,211
|
|
11,776
|
|
Amended returns and changes to estimated tax pools and tax positions
|
|
38,197
|
|
3,478
|
|
Changes in statutory tax rates and the estimated reversal rates
associated with temporary differences
|
|
5,299
|
|
7,506
|
|
Gain on acquisition
|
|
-
|
|
(12,389)
|
|
Other non-deductible items
|
|
(2,925)
|
|
796
|
Provision for income taxes
|
|
253,536
|
|
162,622
|
|
|
|
|
|
(1) In Australia, current taxes included both corporate income tax rates and
PRRT. Corporate income tax rates were applied at a rate of 30% and
PRRT was applied at a rate of 40%.
(2) The effective corporate tax rate was 38.0% in France, 46.0% in the
Netherlands and 25.0% in Ireland.
Tax assessments
As at December 31, 2013, Income Taxes Payable includes a provision
relating to tax assessments from tax authorities for prior period tax
positions. Vermilion has determined the provision based on
management's best estimate of the amount required to settle the tax
assessments and has classified the provision as a current liability.
The amounts ultimately paid and the timing of settlement could differ
from our best estimate and, therefore, could have an impact on future
net earnings and cash flows.
10. SHAREHOLDERS' CAPITAL
The following table reconciles the change in Vermilion's shareholders'
capital:
Shareholders' Capital
|
Number of Shares ('000s)
|
|
Amount ($M)
|
Balance as at January 1, 2012
|
|
96,430
|
|
1,368,145
|
Issuance of shares pursuant to the dividend reinvestment plan
|
|
1,631
|
|
72,058
|
Vesting of equity based awards
|
|
904
|
|
33,355
|
Share-settled dividends on vested equity based awards
|
|
157
|
|
7,151
|
Shares issued pursuant to the bonus plan
|
|
13
|
|
636
|
Balance as at December 31, 2012
|
|
99,135
|
|
1,481,345
|
Issuance of shares 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
|
|
|
|
|
|
Vermilion is authorized to issue an unlimited number of common shares
with no par value.
Dividends
Dividends declared to shareholders for the year ended December 31, 2013
were $242.6 million (2012 - $223.7 million). Dividends are approved by
the Board of Directors and are paid monthly. Vermilion has a dividend
reinvestment plan which allows eligible holders of common shares to
purchase additional common shares at a 5% discount to market by
reinvesting their cash dividends. Subsequent to the end of the period
and prior to the consolidated financial statements being authorized for
issue on February 27, 2014, Vermilion declared dividends totalling
$44.0 million or $0.215 per share for each of January and February of
2014.
11. EQUITY BASED COMPENSATION
The following table summarizes the number of awards outstanding under
the Vermilion Incentive Plan ("VIP"):
Number of Awards ('000s)
|
2013
|
|
2012
|
Opening balance
|
1,690
|
|
1,750
|
Granted
|
832
|
|
681
|
Vested
|
(749)
|
|
(596)
|
Forfeited
|
(108)
|
|
(145)
|
Closing balance
|
1,665
|
|
1,690
|
The fair value of a VIP award is determined on the grant date at the
closing price of Vermilion's common shares on the Toronto Stock
Exchange, adjusted by the estimated performance factor that will
ultimately be achieved. Dividends, which notionally accrue to the
awards during the vesting period, are not included in the determination
of grant date fair values. For the year ended December 31, 2013, the
awards granted had a weighted average fair value of $80.79 (2012 -
$61.08).
The performance factor is determined by the Board of Directors after
consideration of a number of key corporate performance measures
including, but not limited to, shareholder return, capital efficiency
metrics, production and reserves growth and health, safety and
environment performance.
The expense recognized is based on the grant date fair value of the
awards and incorporates an estimate of forfeiture rate based on
historical vesting data. For the year ended December 31, 2013,
Vermilion incorporated an estimated forfeiture rate of 6.61% (2012 -
5.37%). Equity based compensation expense of $60.2 million was
recorded during the year ended December 31, 2013 (2012 - $46.5 million)
related to the VIP.
12. PER SHARE AMOUNTS
Basic and diluted net earnings per share have been determined based on
the following:
|
|
Year Ended
|
($M except per share amounts)
|
Dec 31, 2013
|
Dec 31, 2012
|
Net earnings [1]
|
327,641
|
|
190,622
|
Basic weighted average shares outstanding [2]
|
100,969
|
|
98,016
|
Dilutive impact of equity based award plans
|
1,498
|
|
1,278
|
Diluted weighted average shares outstanding [3]
|
102,467
|
|
99,294
|
Basic earnings per share ([1] ÷ [2])
|
3.24
|
|
1.94
|
Diluted earnings per share ([1] ÷ [3])
|
3.20
|
|
1.92
|
|
|
|
|
|
|
|
|
13. DERIVATIVE INSTRUMENTS
The nature of Vermilion's operations results in exposure to fluctuations
in commodity prices, interest rates and foreign currency exchange
rates. Vermilion monitors and, when appropriate, uses derivative
financial instruments to manage its exposure to these fluctuations.
All transactions of this nature entered into by Vermilion are related
to an underlying financial position or to future crude oil and natural
gas production. Vermilion does not use derivative financial instruments
for speculative purposes. Vermilion has elected not to designate any
of its derivative financial instruments as accounting hedges and thus
accounts for changes in fair value in net earnings at each reporting
period. Vermilion has not obtained collateral or other security to
support its financial derivatives as management reviews the
creditworthiness of its counterparties prior to entering into
derivative contracts.
During the normal course of business, Vermilion may enter into fixed
price arrangements to sell a portion of its production or purchase
commodities for operational use. Vermilion does not apply fair value
accounting on these contracts as they were entered into and continue to
be held for the sale of production or operational use in accordance
with the Company's expected requirements.
The following tables summarize Vermilion's outstanding risk management
positions as at December 31, 2013:
|
Note
|
Daily Volume
|
|
|
Strike Price(s)
|
Crude Oil
|
|
|
|
|
|
WTI - Collar
|
|
|
|
|
|
January 2014 - March 2014
|
|
1,000 bbl/d
|
|
|
97.50 - 104.69 USD $
|
WTI - Swap
|
|
|
|
|
|
January 2014 - March 2014
|
|
500 bbl/d
|
|
|
101.22 USD $
|
January 2014 - March 2014
|
(1)
|
250 bbl/d
|
|
|
105.45 USD $
|
January 2014 - June 2014
|
|
250 bbl/d
|
|
|
100.05 USD $
|
January 2014 - June 2014
|
(2)
|
1,000 bbl/d
|
|
|
100.07 USD $
|
Dated Brent - Collar
|
|
|
|
|
|
January 2014 - March 2014
|
|
2,500 bbl/d
|
|
|
104.00 - 110.46 USD $
|
January 2014 - June 2014
|
|
1,250 bbl/d
|
|
|
103.20 - 110.24 USD $
|
April 2014 - June 2014
|
|
1,000 bbl/d
|
|
|
105.00 - 115.00 USD $
|
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 - March 2014
|
|
2,000 bbl/d
|
|
|
107.80 USD $
|
January 2014 - June 2014
|
|
1,000 bbl/d
|
|
|
107.25 USD $
|
January 2014 - June 2014
|
(2)
|
1,500 bbl/d
|
|
|
110.32 USD $
|
April 2014 - June 2014
|
|
1,250 bbl/d
|
|
|
109.74 USD $
|
January 2014 - December 2014
|
|
500 bbl/d
|
|
|
108.28 USD $
|
MSW - Fixed Price Sale (Physical)
|
|
|
|
|
|
January 2014 - March 2014
|
|
1,000 bbl/d
|
|
|
93.37 CAD $
|
April 2014 - June 2014
|
|
1,000 bbl/d
|
|
|
92.85 CAD $
|
Canadian Natural Gas
|
|
|
|
|
|
AECO - Collar
|
|
|
|
|
|
January 2014 - December 2014
|
|
10,000 GJ/d
|
|
|
3.18 - 3.81 CAD $
|
AECO - Swap
|
|
|
|
|
|
January 2014 - December 2014
|
|
5,000 GJ/d
|
|
|
3.71 CAD $
|
AECO - Collar (Physical)
|
(3)
|
|
|
|
|
April 2012 - March 2014
|
|
5,500 GJ/d
|
|
|
2.60 - 3.78 CAD $
|
June 2012 - March 2014
|
|
3,000 GJ/d
|
|
|
2.30 - 3.75 CAD $
|
European Natural Gas
|
|
|
|
|
|
TTF - Swap
|
|
|
|
|
|
January 2014 - March 2014
|
|
16,200 GJ/d
|
|
|
7.88 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 $
|
|
|
|
|
|
|
(1)
|
Prior to the expiration of this swap, the counterparty has the option to
extend the swap to June 30, 2014 at the contracted volume and price.
|
(2)
|
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.
|
(3)
|
Physical AECO collars have a funded cost of $0.10/GJ.
|
|
|
The following table reconciles the change in the fair value of
Vermilion's derivative instruments:
|
|
|
Year ended
|
($M)
|
Dec 31, 2013
|
Dec 31, 2012
|
Fair value of contracts, beginning of year
|
|
(6,398)
|
|
(12,149)
|
Reversal of opening contracts settled during the year
|
|
6,398
|
|
12,149
|
Realized loss on contracts settled during the year
|
|
(7,082)
|
|
(12,737)
|
Unrealized loss during the year on contracts outstanding at the end of
the year
|
|
(1,287)
|
|
(6,398)
|
Net payment to counterparties on contract settlements during the year
|
|
7,082
|
|
12,737
|
Fair value of contracts, end of year
|
|
(1,287)
|
|
(6,398)
|
Comprised of:
|
|
|
|
|
|
Current derivative asset
|
|
2,285
|
|
2,086
|
|
Current derivative liability
|
|
(3,572)
|
|
(8,484)
|
Fair value of contracts, end of year
|
|
(1,287)
|
|
(6,398)
|
|
|
|
|
|
The loss on derivative instruments for 2013 and 2012 are comprised of
the following:
|
|
|
Year Ended
|
($M)
|
Dec 31, 2013
|
Dec 31, 2012
|
Realized loss on contracts settled during the year
|
|
7,082
|
|
12,737
|
Reversal of opening contracts settled during the year
|
|
(6,398)
|
|
(12,149)
|
Unrealized loss during the year on contracts outstanding at the end of
the year
|
|
1,287
|
|
6,398
|
Loss on derivative instruments
|
|
1,971
|
|
6,986
|
|
|
|
|
|
14. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in non-cash working capital is comprised of the following:
|
Year Ended
|
($M)
|
Dec 31, 2013
|
|
Dec 31, 2012
|
Changes in:
|
|
|
|
|
Accounts receivable
|
12,446
|
|
(818)
|
|
Crude oil inventory
|
8,576
|
|
(11,661)
|
|
Prepaid expenses
|
(840)
|
|
2,375
|
|
Accounts payable and accrued liabilities and income taxes payable
|
(4,944)
|
|
(18,836)
|
|
Movements in foreign exchange rates
|
(7,508)
|
|
(1,881)
|
Changes in non-cash working capital
|
7,730
|
|
(30,821)
|
Changes in non-cash operating working capital
|
49,421
|
|
(47,409)
|
Changes in non-cash investing working capital
|
(41,691)
|
|
16,588
|
Changes in non-cash working capital
|
7,730
|
|
(30,821)
|
|
|
|
|
15. SEGMENTED INFORMATION
Vermilion has operations principally in Canada, France, the Netherlands,
Australia and Ireland. 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 Calgary, Alberta. Costs incurred in the Corporate segment
relate to our 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.
Prior to the year ended December 31, 2013, Vermilion's segmented
disclosure provided a breakdown by country of operating income, which
excluded general and administration expense, current income taxes,
interest expense, realized foreign exchange, and realized other
income. In addition, the prior year disclosure presented the results
of the Canada and Corporate segments as a combined segment. The 2013
presentation is now expanded to reflect all of the directly
attributable revenue and expenditures for each of Vermilion's business
units in addition to the newly segregated corporate segment.
|
Year Ended December 31, 2013
|
($M)
|
Canada
|
|
France
|
|
Netherlands
|
|
Australia
|
|
Ireland
|
|
Corporate
|
|
Total
|
Total assets
|
1,212,056
|
|
901,582
|
|
228,869
|
|
322,773
|
|
747,882
|
|
295,557
|
|
3,708,719
|
Drilling and development
|
232,858
|
|
96,479
|
|
28,543
|
|
77,931
|
|
90,898
|
|
2,228
|
|
528,937
|
Exploration and evaluation
|
8,339
|
|
3,899
|
|
-
|
|
-
|
|
-
|
|
1,551
|
|
13,789
|
Oil and gas sales to external customers
|
382,005
|
|
453,315
|
|
139,570
|
|
298,945
|
|
-
|
|
-
|
|
1,273,835
|
Royalties
|
(40,891)
|
|
(27,045)
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(67,936)
|
Revenue from external customers
|
341,114
|
|
426,270
|
|
139,570
|
|
298,945
|
|
-
|
|
-
|
|
1,205,899
|
Transportation expense
|
(12,254)
|
|
(12,505)
|
|
-
|
|
-
|
|
(4,165)
|
|
-
|
|
(28,924)
|
Operating expense
|
(55,804)
|
|
(66,997)
|
|
(20,617)
|
|
(51,625)
|
|
-
|
|
-
|
|
(195,043)
|
General and administration
|
(12,979)
|
|
(19,657)
|
|
(2,724)
|
|
(5,752)
|
|
(1,442)
|
|
(7,356)
|
|
(49,910)
|
Corporate income taxes
|
-
|
|
(94,524)
|
|
(34,132)
|
|
(31,735)
|
|
-
|
|
(1,403)
|
|
(161,794)
|
PRRT
|
-
|
|
-
|
|
-
|
|
(56,565)
|
|
-
|
|
-
|
|
(56,565)
|
Interest expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(38,183)
|
|
(38,183)
|
Realized loss on derivative instruments
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(7,082)
|
|
(7,082)
|
Realized foreign exchange loss
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(1,866)
|
|
(1,866)
|
Realized other income
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
994
|
|
994
|
Fund flows from operations
|
260,077
|
|
232,587
|
|
82,097
|
|
153,268
|
|
(5,607)
|
|
(54,896)
|
|
667,526
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2012
|
($M)
|
Canada
|
|
France
|
|
Netherlands
|
|
Australia
|
|
Ireland
|
|
Corporate
|
|
Total
|
Total assets
|
1,112,335
|
|
868,300
|
|
156,620
|
|
296,169
|
|
576,904
|
|
65,929
|
|
3,076,257
|
Drilling and development
|
232,903
|
|
47,382
|
|
21,052
|
|
49,389
|
|
58,764
|
|
3,731
|
|
413,221
|
Exploration and evaluation
|
38,871
|
|
-
|
|
272
|
|
-
|
|
-
|
|
174
|
|
39,317
|
Oil and gas sales to external customers
|
304,202
|
|
388,410
|
|
123,528
|
|
266,963
|
|
-
|
|
-
|
|
1,083,103
|
Royalties
|
(31,667)
|
|
(20,417)
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(52,084)
|
Revenue from external customers
|
272,535
|
|
367,993
|
|
123,528
|
|
266,963
|
|
-
|
|
-
|
|
1,031,019
|
Transportation expense
|
(8,321)
|
|
(8,236)
|
|
-
|
|
-
|
|
(7,556)
|
|
-
|
|
(24,113)
|
Operating expense
|
(55,418)
|
|
(54,907)
|
|
(19,149)
|
|
(48,968)
|
|
-
|
|
-
|
|
(178,442)
|
General and administration
|
(12,344)
|
|
(15,009)
|
|
(1,329)
|
|
(3,715)
|
|
(1,346)
|
|
(10,030)
|
|
(43,773)
|
Corporate income taxes
|
-
|
|
(63,006)
|
|
(25,648)
|
|
(31,607)
|
|
-
|
|
(1,582)
|
|
(121,843)
|
PRRT
|
-
|
|
-
|
|
-
|
|
(60,070)
|
|
-
|
|
-
|
|
(60,070)
|
Interest expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(27,586)
|
|
(27,586)
|
Realized loss on derivative instruments
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(12,737)
|
|
(12,737)
|
Realized foreign exchange gain
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
2,804
|
|
2,804
|
Realized other expense
|
-
|
|
-
|
|
-
|
|
-
|
|
-
|
|
(7,531)
|
|
(7,531)
|
Fund flows from operations
|
196,452
|
|
226,835
|
|
77,402
|
|
122,603
|
|
(8,902)
|
|
(56,662)
|
|
557,728
|
Reconciliation of fund flows from operations to net earnings
|
|
Year Ended
|
($M)
|
|
Dec 31, 2013
|
|
Dec 31, 2012
|
Fund flows from operations
|
|
667,526
|
|
557,728
|
Equity based compensation
|
|
(60,845)
|
|
(47,104)
|
Unrealized gain on derivative instruments
|
|
5,111
|
|
5,751
|
Unrealized foreign exchange gain (loss)
|
|
52,028
|
|
(4,350)
|
Unrealized other expense
|
|
(1,451)
|
|
(1,220)
|
Accretion
|
|
(24,565)
|
|
(23,040)
|
Depletion and depreciation
|
|
(322,386)
|
|
(295,943)
|
Deferred taxes
|
|
(35,177)
|
|
19,291
|
Impairment (recovery)
|
|
47,400
|
|
(65,800)
|
Gain on acquisition
|
|
-
|
|
45,309
|
Net earnings
|
|
327,641
|
|
190,622
|
|
|
|
|
|
Vermilion has two major customers with revenues in excess of 10% within
the France and Netherlands segments. Sales to the major customer in
the France segment for year ended December 31, 2013 were $453.3 million
(2012 - $380.6 million). All sales in the Netherlands segment were to
one customer.
16. COMMITMENTS
Vermilion had the following future commitments associated with its
operating leases as at December 31, 2013:
($M)
|
Less than 1 year
|
1 - 3 years
|
4 - 5 years
|
After 5 years
|
Total
|
Payments by period
|
19,038
|
29,489
|
23,919
|
62,211
|
134,657
|
|
|
|
|
|
|
In addition, Vermilion has various other commitments associated with its
business operations; none of which, in management's view, are
significant in relation to Vermilion's financial position.
17. CASH AND CASH EQUIVALENTS
Cash and cash equivalents was comprised of the following:
($M)
|
Dec 31, 2013
|
Dec 31, 2012
|
Money on deposit with financial institutions
|
|
379,936
|
|
78,396
|
Short-term investments
|
|
9,623
|
|
23,729
|
Cash and cash equivalents
|
|
389,559
|
|
102,125
|
|
|
|
|
|
18. CAPITAL DISCLOSURES
Vermilion defines capital as net debt (a non-standardized measure, which
is defined by management as long-term debt as shown on the consolidated
balance sheets plus net working capital) and shareholders' capital.
In managing capital, Vermilion reviews whether fund flows from
operations (a non-standardized measure, defined by management as cash
flows from operating activities before changes in non-cash operating
working capital and asset retirement obligations settled), is
sufficient to pay for all capital expenditures, dividends and
abandonment and reclamation expenditures. To the extent that the
forecasted fund flows from operations is not expected to be sufficient
in relation to these expenditures, Vermilion will evaluate its ability
to finance any excess with debt, an issuance of equity or by reducing
some or all categories of expenditures to ensure that total
expenditures do not exceed available funds.
Additionally, Vermilion monitors the ratio of net debt to fund flows
from operations. Vermilion typically strives to maintain a ratio of
net debt to fund flows from operations near 1.0. In a commodity price
environment where prices trend higher, Vermilion may target a lower
ratio and conversely, in a lower commodity price environment, the
acceptable ratio may be higher. At times, Vermilion will use its
balance sheet to finance acquisitions and, in these situations,
Vermilion is prepared to accept a higher ratio in the short term but
will implement a plan to reduce the ratio to acceptable levels within a
reasonable period of time, usually considered to be no more than 12 to
18 months. This plan could potentially include an increase in hedging
activities, a reduction in capital expenditures, an issuance of equity
or the utilization of excess fund flows from operations to reduce
outstanding indebtedness.
The following table calculates Vermilion's ratio of net debt to fund
flows from operations:
|
|
Year Ended
|
($M except as indicated)
|
|
Dec 31, 2013
|
Dec 31, 2012
|
Long-term debt
|
|
990,024
|
642,022
|
Current liabilities
|
|
347,444
|
355,711
|
Current assets
|
|
(587,783)
|
(320,502)
|
Net debt [1]
|
|
749,685
|
677,231
|
Cash flows from operating activities
|
|
705,025
|
496,580
|
Changes in non-cash operating working capital
|
|
(49,421)
|
47,409
|
Asset retirement obligations settled
|
|
11,922
|
13,739
|
Fund flows from operations [2]
|
|
667,526
|
557,728
|
Ratio of net debt to fund flows from operations ([1] ÷ [2])
|
|
1.1
|
1.2
|
The ratio of net debt to fund flows from operations for the year ended
December 31, 2013 was relatively consistent with same period in 2012 as
fund flows from operations increased proportionately with net debt.
The increase in net debt was the result of the Northern acquisition in
the fourth quarter of 2013 and current year capital expenditures
pertaining to the Ireland assets, which are currently under
development.
19. FINANCIAL INSTRUMENTS
Classification of Financial Instruments
The following table summarizes information relating to Vermilion's
financial instruments as at December 31, 2013 and December 31, 2012:
|
|
|
|
|
|
|
As at Dec 31, 2013
|
|
|
As at Dec 31, 2012
|
|
|
|
Class of financial instrument
|
Consolidated balance sheet caption
|
Accounting designation
|
Related caption on Statement of Net
Earnings
|
|
|
Carrying value ($M)
|
Fair value ($M)
|
|
|
Carrying value ($M)
|
|
Fair value ($M)
|
|
|
Fair value measurement hierarchy
|
Cash
|
Cash and cash equivalents
|
HFT
|
Gains and losses on foreign exchange are included in foreign exchange
(gain) loss
|
|
|
389,559
|
|
389,559
|
|
|
102,125
|
|
102,125
|
|
|
Level 1
|
Receivables
|
Accounts receivable
|
LAR
|
Gains and losses on foreign exchange are included in foreign exchange
(gain) loss and impairments are recognized as general and
administration expense
|
|
|
167,618
|
|
167,618
|
|
|
180,064
|
|
180,064
|
|
|
Not applicable
|
Derivative assets
|
Derivative instruments
|
HFT
|
Loss on derivative instruments
|
|
|
2,285
|
|
2,285
|
|
|
2,086
|
|
2,086
|
|
|
Level 2
|
Derivative liabilities
|
Derivative instruments
|
HFT
|
Loss on derivative instruments
|
|
|
(3,572)
|
|
(3,572)
|
|
|
(8,484)
|
|
(8,484)
|
|
|
Level 2
|
Payables
|
Accounts payable and accrued liabilities
|
OTH
|
Gains and losses on foreign exchange are included in foreign exchange
(gain) loss
|
|
|
(288,257)
|
|
(288,257)
|
|
|
(319,518)
|
|
(319,518)
|
|
|
Not applicable
|
|
|
Dividends payable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
Long-term debt
|
OTH
|
Interest expense
|
|
|
(990,024)
|
|
(998,648)
|
|
|
(642,022)
|
|
(656,315)
|
|
|
Not applicable
|
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
Vermilion is exposed to the following types of risks in relation to its
financial instruments:
Credit risk:
Vermilion extends credit to customers and may, from time-to-time, be due
amounts from counterparties in relation to derivative instruments.
Accordingly, there is a risk of financial loss in the event that a
counterparty fails to discharge its obligation. For transactions that
are financially significant, Vermilion reviews third-party credit
ratings and may require additional forms of security. Cash held on
behalf of the Company by financial institutions is also subject to
credit risk.
Liquidity risk:
Liquidity risk is the risk that Vermilion will encounter difficulty in
meeting obligations associated with its financial liabilities.
Vermilion does not consider this to be a significant risk as its
financial position and available committed borrowing facility provide
significant financial flexibility and allow Vermilion to meet its
obligations as they come due.
Currency risk:
Vermilion conducts business in foreign currencies in addition to
Canadian dollars and accordingly is subject to currency risk associated
with changes in foreign exchange rates in relation to cash and cash
equivalents, receivables, payables and derivative assets and
liabilities. The impact related to working capital is somewhat
mitigated as a result of the offsetting effects of foreign exchange
fluctuations on assets and liabilities. Vermilion monitors its
exposure to currency risk and reviews whether the use of derivative
financial instruments is appropriate to manage potential fluctuations
in foreign exchange rates. During the period covered by these
consolidated financial statements, Vermilion did not use derivative
financial instruments to manage potential fluctuations in foreign
exchange rates.
Commodity price risk:
Vermilion uses derivative financial instruments as part of its risk
management program to mitigate the effects of changes in commodity
prices on future cash flows. Changes in the underlying commodity
prices impact the fair value and future cash flows related to these
derivatives.
Interest rate risk:
Vermilion's long-term debt is comprised of borrowings under the
revolving credit facility and the Company's senior unsecured notes.
Borrowings under the revolving credit facility bear interest at market
rates plus applicable margins and as such changes in interest rates
could result in an increase or decrease in the amount Vermilion pays to
service this debt. The senior unsecured notes bear interest at a fixed
6.5% interest rate and as such, changes in prevailing interest rates
would affect the fair value of these notes. However, as Vermilion does
not intend to settle this debt prior to maturity, the notes are carried
at amortized cost and changes in fair value do not affect net earnings.
The nature of these risks and Vermilion's strategy for managing these
risks has not changed significantly from the prior period.
Summarized Quantitative Data Associated with the Risks Arising from
Financial Instruments
Credit risk:
As at December 31, 2013, Vermilion's maximum exposure to receivable
credit risk was $169.9 million (December 31, 2012 - $182.2 million)
which is the aggregate value of receivables and derivative assets at
the balance sheet date. Vermilion's receivables are primarily due from
counterparties that have investment grade third party credit ratings
or, in the absence of the availability of such ratings, have been
satisfactorily reviewed by Vermilion for creditworthiness.
Additionally, cash and cash equivalents consist of moneys on deposit
and short-term investments which may be subject to counterparty credit
risk. Vermilion mitigates this risk by transacting with North American
institutions with high third party credit ratings.
As at the balance sheet date the amount of financial assets that were
past due or impaired was not material.
Liquidity risk:
Vermilion's derivative financial instruments settle on a monthly basis.
The following table summarizes Vermilion's undiscounted non-derivative
financial liabilities and their contractual maturities as at December
31, 2013 and December 31, 2012:
|
|
Later than
|
Later than
|
Later than
|
|
|
one month and
|
three months and
|
one year and
|
|
Due in
|
not later than
|
not later than
|
not later than
|
($M)
|
one month
|
three months
|
one year
|
five years
|
December 31, 2013
|
154,176
|
118,764
|
15,317
|
991,898
|
December 31, 2012
|
109,312
|
209,783
|
423
|
644,784
|
Market risk:
Vermilion's financial instruments are exposed to currency risk related
to changes in foreign currency denominated financial instruments and
commodity price risk related to outstanding derivative positions. The
following table summarizes what the impact on comprehensive income
before tax would be for the year ended December 31, 2013 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
|
Dec 31, 2013
|
Dec 31, 2012
|
Currency risk - Euro to Canadian
|
Increase in strength of the Canadian dollar against the
|
(14,276)
|
(6,476)
|
|
Euro by 5% over the relevant closing rates
|
|
|
|
Decrease in strength of the Canadian dollar against the
|
14,276
|
6,476
|
|
Euro by 5% over the relevant closing rates
|
|
|
Currency risk - US $ to Canadian
|
Increase in strength of the Canadian dollar against the
|
(4,420)
|
(1,971)
|
|
US$ by 5% over the relevant closing rates
|
|
|
|
Decrease in strength of the Canadian dollar against the
|
4,420
|
1,971
|
|
US$ by 5% over the relevant closing rates
|
|
|
Commodity price risk
|
Increase in relevant oil reference price within option pricing models used to
determine
|
(12,291)
|
(12,908)
|
|
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
|
11,376
|
12,296
|
|
the fair value of financial derivatives by US$5.00/bbl at the relevant
valuation dates
|
|
|
Interest rate risk
|
Increase in average Canadian prime interest rate
|
(4,945)
|
(2,007)
|
|
by 100 basis points during the relevant periods
|
|
|
|
Decrease in average Canadian prime interest rate
|
4,945
|
2,007
|
|
by 100 basis points during the relevant periods
|
|
|
Reasonably possible changes in natural gas prices would not have had a
material impact on comprehensive income for the years ended December
31, 2013 and 2012.
20. RELATED PARTY DISCLOSURES
The compensation of directors and management are reviewed annually by
the independent Governance and Human Resources Committee against
industry practices for oil and gas companies of similar size and
scope.
The following table summarizes the compensation of directors and other
members of key management personnel during the years ended December 31,
2013 and December 31, 2012:
|
|
Year Ended
|
($M)
|
Dec 31, 2013
|
Dec 31, 2012
|
Short-term benefits
|
|
6,308
|
|
6,545
|
Share-based payments
|
|
19,302
|
|
15,428
|
|
|
25,610
|
|
21,973
|
Number of individuals included in the above amounts
|
|
17
|
|
19
|
|
|
|
|
|
21. WAGES AND BENEFITS
Included in operating expenses and general and administrative expenses
for the year ended December 31, 2013 were $53.2 million and $45.9
million of wages and benefits, respectively (2012 - $45.3 million and
$30.9 million, respectively).
22. SUBSEQUENT EVENTS
Purchase and Sale Agreement with GDF Suez E&P Deutschland GmbH
On November 6, 2013, Vermilion announced that it entered into a
definitive purchase and sale agreement with GDF Suez E&P Deutschland
GmbH ("GDF") whereby Vermilion, through its wholly-owned subsidiary,
will acquire 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. In addition, the acquisition also includes the
purchase of 0.4% of the equity of Ergas Munster GmbH ("EGM"), a joint
venture created in 1959 to jointly transport, process, and market gas
in northwest Germany. 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
approximately $172.0 million plus customary working capital
adjustments.
Given the recent timing of the acquisition, the Company has not yet
completed the accounting for the acquisition and accordingly not all
relevant disclosures are available for the business combination. The
Company will report the purchase price allocation in the Company's
consolidated financial statements for the three months ended March 31,
2014.
SOURCE Vermilion Energy Inc.