CALGARY, May 6, 2016 /PRNewswire/ - Vermilion Energy
Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE:
VET) is pleased to report operating and unaudited financial results
for the three months ended March 31, 2016.
HIGHLIGHTS
- Achieved average production of 65,389 boe/d during the first
quarter of 2016, an increase of 7% as compared to 61,058 boe/d in
the prior quarter, with significant increases recorded in our Irish
and Canadian operations. Production increased 30% from 50,386 boe/d
in the first quarter of 2015, with higher volumes from our Irish,
French, Netherlands, Australian,
Canadian and U.S. business units.
- Fund flows from operations ("FFO") for Q1 2016 of $93.7 million ($0.83/basic share(1)) represented a
decrease of 31% quarter-over-quarter and 22% year-over-year. The
quarter-over-quarter decrease in FFO was attributable to lower
commodity prices and an inventory build in Australia (due to the timing of crude
liftings), partially offset by lower operating expenses from our
ongoing focus on cost reduction.
- During Q1, we announced a reduction in our 2016 E&D capital
budget from $285 million to $235
million. Despite the $50
million reduction in capital investment, we still anticipate
delivering nearly 10% per share production growth on a
year-over-year basis. Our production guidance for 2016 remains
62,500 to 63,500 boe/d.
- Since the initiation of first gas on December 30, 2015, Corrib has produced strongly,
with robust well deliverability and minimal downtime. Net
production for Q1 2016 averaged approximately 34 mmcf/d (5,650
boe/d). Five of the six wells are capable of production with the
remaining well to be brought online in the third quarter of 2016
following conclusion of our offshore work program. Production
remains subject to limitations on maximum pipeline operating
pressures while previously-planned certification activities are
conducted on the Irish distribution pipeline network. Upon
completion of the recertification process, production levels at
Corrib are expected to rise to an estimated peak rate of 58 mmcf/d
(9,700 boe/d), net to Vermilion.
- We continue to prioritize the strength of our balance sheet and
the long-term profitability of our business through our
Profitability Enhancement Program ("PEP") initiative. PEP cost
savings related to capital spending, operating expenses and G&A
expenditures reached nearly $90
million for full-year 2015. For 2016, we expect to deliver a
further $30 to $40 million of cost
reductions.
- We redeemed the senior unsecured notes that were due
February 10, 2016 by using funds from
our revolving credit facility. Our revolving credit facility limit
of $2.0 billion remains unchanged and
we have approximately $520 million of
borrowing capacity available. We were in compliance with all
covenants as of March 31, 2016 and
expect to remain in compliance based on commodity strip
pricing.
- Vermilion was recognized by
the Great Place to Work® Institute as a Best Workplace in
Canada, France, the
Netherlands and Germany in
2016. Vermilion was the only
energy company to rank on the Best Workplaces lists in Canada and France. The Great Place to Work awards
recognize Vermilion's strong
corporate culture, a key driver of Vermilion's leading long-term corporate
performance.
- Vermilion was recently ranked
9th by Corporate Knights on the Future 40 Responsible
Corporate Leaders in Canada list,
an improvement over last year's ranking of 15th. We are
the highest rated oil and gas company on the list of top
sustainability performers. This recognition reflects Vermilion's focus on financial results
combined with exemplary environmental, social and governance
performance. Please refer to our Sustainability Report at
http://sustainability.vermilionenergy.com/ for more information
about our environmental and social stewardship.
(1)
|
Non-GAAP Financial
Measure. Please see the "Non-GAAP Financial Measures" section
of Management's Discussion and Analysis.
|
ANNUAL GENERAL MEETING WEBCAST
As Vermilion's Annual General
Shareholders Meeting is being held today, May 6, 2016 at 10:00 AM
MST at the Metropolitan Centre, 333 – 4th Avenue S.W.,
Calgary, Alberta, there will not
be a first quarter conference call. In lieu of the conference call,
a presentation will be given by Mr. Anthony
Marino, President & Chief Executive Officer at the end
of the meeting. Questions from the public can be submitted
via the webcast.
Please visit
http://event.on24.com/r.htm?e=1160062&s=1&k=7AC4E39F48A74F6596F60B059A660FC5
or Vermilion's website at
http://www.vermilionenergy.com/ir/eventspresentations.cfm and click
on webcast under the upcoming events to view the webcast which will
commence at approximately 10:15 AM
MST.
HIGHLIGHTS
|
|
|
|
|
|
|
|
Three Months
Ended
|
($M except as
indicated)
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
Financial
|
|
2016
|
2015
|
2015
|
Petroleum and natural
gas sales
|
|
177,385
|
234,319
|
195,885
|
Fund flows from
operations
|
|
93,667
|
136,441
|
120,795
|
|
Fund flows from
operations ($/basic share) (1)
|
|
0.83
|
1.22
|
1.12
|
|
Fund flows from
operations ($/diluted share) (1)
|
|
0.82
|
1.21
|
1.11
|
Net (loss)
earnings
|
|
(85,848)
|
(142,080)
|
1,275
|
|
Net (loss) earnings
($/basic share)
|
|
(0.76)
|
(1.28)
|
0.01
|
Capital
expenditures
|
|
62,773
|
128,996
|
174,311
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Acquisitions
|
|
870
|
6,227
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35
|
Asset retirement
obligations settled
|
|
2,024
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4,921
|
3,107
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Cash dividends
($/share)
|
|
0.645
|
0.645
|
0.645
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Dividends
declared
|
|
72,847
|
71,965
|
69,390
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% of fund flows from
operations
|
|
78%
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53%
|
57%
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Net dividends
(1)
|
|
24,857
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25,201
|
48,012
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% of fund flows from
operations
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27%
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18%
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40%
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Payout
(1)
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89,654
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159,118
|
225,430
|
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% of fund flows from
operations
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96%
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117%
|
187%
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% of fund flows from
operations (excluding the Corrib project) (1)
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|
N/A
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106%
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173%
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Net debt
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1,367,063
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1,381,951
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1,388,603
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Ratio of net debt to
annualized fund flows from operations
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3.6
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2.5
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2.9
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Operational
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Production
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Crude oil and
condensate (bbls/d)
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29,199
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31,304
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29,514
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NGLs
(bbls/d)
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|
2,672
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2,739
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1,706
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Natural gas
(mmcf/d)
|
|
201.11
|
162.09
|
115.00
|
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Total
(boe/d)
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|
65,389
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61,058
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50,386
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Average realized
prices
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|
|
|
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Crude oil, condensate
and NGLs ($/bbl)
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39.35
|
51.64
|
58.25
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Natural gas
($/mmbtu)
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|
3.76
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4.55
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5.26
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Production mix (% of
production)
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% priced with
reference to WTI
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20%
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21%
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28%
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% priced with
reference to AECO
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25%
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24%
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20%
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% priced with
reference to TTF and NBP
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26%
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20%
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18%
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% priced with
reference to Dated Brent
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29%
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35%
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34%
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Netbacks
($/boe)
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|
|
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Operating
netback
|
|
21.63
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28.44
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31.30
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Fund flows from
operations netback
|
|
16.12
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23.91
|
29.07
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Operating
expenses
|
|
9.58
|
11.50
|
10.56
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Average reference
prices
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|
|
|
|
|
WTI (US
$/bbl)
|
|
33.45
|
42.18
|
48.63
|
|
Edmonton Sweet index
(US $/bbl)
|
|
29.76
|
39.72
|
41.83
|
|
Dated Brent (US
$/bbl)
|
|
33.89
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43.69
|
53.97
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AECO
($/mmbtu)
|
|
1.83
|
2.46
|
2.75
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TTF
($/mmbtu)
|
|
5.70
|
7.28
|
8.70
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Average foreign
currency exchange rates
|
|
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CDN $/US $
|
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1.37
|
1.34
|
1.24
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CDN $/Euro
|
|
1.52
|
1.46
|
1.40
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Share information
('000s)
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|
|
|
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Shares outstanding -
basic
|
|
113,451
|
111,991
|
107,718
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Shares outstanding -
diluted (1)
|
|
116,491
|
115,025
|
110,761
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Weighted average
shares outstanding - basic
|
|
112,725
|
111,393
|
107,513
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Weighted average
shares outstanding - diluted (1)
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|
114,110
|
112,543
|
109,305
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(1)
|
The above table
includes non-GAAP financial measures which may not be comparable to
other companies. Please see the "NON-GAAP FINANCIAL MEASURES"
section of Management's Discussion and Analysis.
|
DISCLAIMER
Certain statements included or incorporated by reference in this
document may constitute forward looking statements or financial
outlooks under applicable securities legislation. Such
forward looking statements or information typically contain
statements with words such as "anticipate", "believe", "expect",
"plan", "intend", "estimate", "propose", or similar words
suggesting future outcomes or statements regarding an
outlook. Forward looking statements or information in this
document may include, but are not limited to: capital expenditures;
business strategies and objectives; operational and financial
performance; estimated reserve quantities and the discounted net
present value of future net revenue from such reserves; petroleum
and natural gas sales; future production levels (including the
timing thereof) and rates of average annual production growth;
estimated contingent resources; exploration and development plans;
acquisition and disposition plans and the timing thereof; operating
and other expenses, including the payment and amount of future
dividends; royalty and income tax rates; and the timing of
regulatory proceedings and approvals.
Such forward looking statements or information are based on a
number of assumptions, all or any of which may prove to be
incorrect. In addition to any other assumptions identified in
this document, assumptions have been made regarding, among other
things: the ability of Vermilion
to obtain equipment, services and supplies in a timely manner to
carry out its activities in Canada
and internationally; the ability of Vermilion to market crude oil, natural gas
liquids, and natural gas successfully to current and new customers;
the timing and costs of pipeline and storage facility construction
and expansion and the ability to secure adequate product
transportation; the timely receipt of required regulatory
approvals; the ability of Vermilion to obtain financing on acceptable
terms; foreign currency exchange rates and interest rates; future
crude oil, natural gas liquids, and natural gas prices; and
management's expectations relating to the timing and results of
exploration and development activities.
Although Vermilion believes
that the expectations reflected in such forward looking statements
or information are reasonable, undue reliance should not be placed
on forward looking statements because Vermilion can give no assurance that such
expectations will prove to be correct. Financial outlooks are
provided for the purpose of understanding Vermilion's financial position and business
objectives, and the information may not be appropriate for other
purposes. Forward looking statements or information are based
on current expectations, estimates, and projections that involve a
number of risks and uncertainties which could cause actual results
to differ materially from those anticipated by Vermilion and described in the forward looking
statements or information. These risks and uncertainties
include, but are not limited to: the ability of management to
execute its business plan; the risks of the oil and gas industry,
both domestically and internationally, such as operational risks in
exploring for, developing and producing crude oil, natural gas
liquids, and natural gas; risks and uncertainties involving geology
of crude oil, natural gas liquids, and natural gas deposits; risks
inherent in Vermilion's marketing
operations, including credit risk; the uncertainty of reserves
estimates and reserves life and estimates of resources and
associated expenditures; the uncertainty of estimates and
projections relating to production and associated expenditures;
potential delays or changes in plans with respect to exploration or
development projects; Vermilion's
ability to enter into or renew leases on acceptable terms;
fluctuations in crude oil, natural gas liquids, and natural gas
prices, foreign currency exchange rates and interest rates; health,
safety, and environmental risks; uncertainties as to the
availability and cost of financing; the ability of Vermilion to add production and reserves
through exploration and development activities; the possibility
that government policies or laws may change or governmental
approvals may be delayed or withheld; uncertainty in amounts and
timing of royalty payments; risks associated with existing and
potential future law suits and regulatory actions against
Vermilion; and other risks and
uncertainties described elsewhere in this document or in
Vermilion's other filings with
Canadian securities regulatory authorities.
The forward looking statements or information contained in this
document are made as of the date hereof and Vermilion undertakes no obligation to update
publicly or revise any forward looking statements or information,
whether as a result of new information, future events, or
otherwise, unless required by applicable securities laws.
Natural gas volumes have been converted on the basis of six
thousand cubic feet of natural gas to one barrel of oil
equivalent. Barrels of oil equivalent (boe) may be
misleading, particularly if used in isolation. A boe
conversion ratio of six thousand cubic feet to one barrel of oil is
based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value
equivalency at the wellhead.
Financial data contained within this document are reported in
Canadian dollars, unless otherwise stated.
ABBREVIATIONS
$M
|
thousand
dollars
|
$MM
|
million
dollars
|
AECO
|
the daily average
benchmark price for natural gas at the AECO 'C' hub in southeast
Alberta
|
bbl(s)
|
barrel(s)
|
bbls/d
|
barrels per
day
|
bcf
|
billion cubic
feet
|
boe
|
barrel of oil
equivalent, including: crude oil, condensate, natural gas liquids,
and natural gas (converted on the basis of one boe for six mcf of
natural gas)
|
boe/d
|
barrel of oil
equivalent per day
|
btu
|
British thermal
units
|
CGU
|
Cash generating unit,
the basis upon which Vermilion's assets are evaluated for potential
impairments
|
DRIP
|
Dividend Reinvestment
Plan
|
GJ
|
gigajoules
|
HH
|
Henry Hub, a
reference price paid for natural gas in US dollars at Erath,
Louisiana
|
mbbls
|
thousand
barrels
|
mboe
|
thousand barrel of
oil equivalent
|
mcf
|
thousand cubic
feet
|
mcf/d
|
thousand cubic feet
per day
|
mmboe
|
million barrel of oil
equivalent
|
mmbtu
|
million British
thermal units
|
mmcf
|
million cubic
feet
|
mmcf/d
|
million cubic feet
per day
|
MWh
|
megawatt
hour
|
NBP
|
the reference price
paid for natural gas in the United Kingdom, quoted in pence per
therm, at the National Balancing Point Virtual Trading Point
operated by National Grid. Our production in Ireland is priced with
reference to NBP.
|
NGLs
|
natural gas liquids,
which includes butane, propane, and ethane
|
PRRT
|
Petroleum Resource
Rent Tax, a profit based tax levied on petroleum projects in
Australia
|
TTF
|
the day-ahead price
for natural gas in the Netherlands, quoted in MWh of natural gas,
at the Title Transfer Facility
|
|
Virtual Trading Point
operated by Dutch TSO Gas Transport Services
|
WTI
|
West Texas
Intermediate, the reference price paid for crude oil of standard
grade in US dollars at Cushing, Oklahoma
|
MESSAGE TO SHAREHOLDERS
While oil prices have now risen from the lows reached in Q1
2016, we continue to experience significant volatility in energy
commodity prices and uncertainty as to the timing of a sustained
price recovery. During this period of challenging economic
conditions in the energy sector, a number of companies have been
forced to undertake asset sales and dividend reductions or
cancellations to remain viable. At Vermilion, we have always taken a conservative
approach to managing our balance sheet, historically maintaining
significantly lower leverage than many of our peers. Consequently,
we entered the commodity price downturn in a position of relative
financial strength, allowing us to maintain an adequate balance
sheet through cost and investment reductions without the need to
undertake asset sale or dividend reduction measures. Our first
priority remains the protection of our balance sheet, followed by
protection of our dividend. We believe our Company remains well
positioned on both accounts. At the same time, we have been making
very capital-efficient investments in our business to continue to
record strong production growth per share.
We remain committed to preserving this sustainable business
model. We are basing our cost and investment structure on the
current commodity price strip, ensuring that fund flows from
operations exceed our cash outflows for net dividends and
exploration and development ("E&D") capital expenditures.
During the first quarter, we reduced our planned E&D capital
budget by $50 million to enhance
Vermilion's sustainability in the
falling commodity price environment. The resulting $235 million E&D budget represents a decrease
of over 50% from 2015 levels and more than 65% from 2014 levels.
Despite this significant reduction in capital investment, we still
anticipate delivering production of between 62,500 to 63,500 boe/d,
reflecting year-over-year production growth of 15%, or nearly 10%
on a per share basis. Production additions from Corrib plus growth
in other business units made possible through significantly
improved capital efficiencies have enabled this strong per share
growth despite significantly lower capital investment levels.
For 2016, we intend to adhere closely to our $235 million E&D capital budget. Using recent
commodity strip pricing and taking into account this planned level
of spending, we expect to incur only minimal cash taxes, estimated
at $10 to $20 million, and project a
total payout ratio of less than 80%. Should a meaningful recovery
in commodity prices occur in 2016, we expect to direct the vast
majority of incremental cash flow to debt reduction rather than
increasing capital spending. Conversely, if there is significant
deterioration in commodity prices, we would seek to reduce our
expenditures further to avoid incurring additional debt on our
balance sheet.
Our international diversification provides structural pricing
advantages that differentiate Vermilion from its peers. While European
natural gas prices have been under pressure in 2016, they remain
substantially above North American gas prices. In addition, our
overseas oil production is indexed to Dated Brent, which continues
to trade at a premium to WTI. Overall, the prices realized for our
international production exceed those received by most North
American producers and most particularly by our Canadian peers. Our
price-advantaged Brent crude oil and European natural gas business
units are anticipated to generate approximately 80% of Vermilion's 2016 fund flows from operations,
and the majority of our 2016 capital expenditures are directed to
these business units to exploit this advantage.
Vermilion's international
exposure and diversified project inventory also provide flexibility
to react to changing conditions and selectively allocate capital to
the highest rate of return projects for a given commodity
environment. This advantage is even more evident when capital
availability is restricted. Since the announcement of our
$235 million capital budget, we have
further revised some of our planned activities including the
reinstatement of a two (0.9 net) well drilling program in
the Netherlands, finding
investment and cost reductions elsewhere in our budget to fund
the Netherlands wells.
We have included the two Netherlands wells in our 2016 capital program
because of the prolific productivity of our Netherlands gas reservoirs and the premium
price received for our European natural gas. We plan to drill the
Langezwaag-03 (42% working interest) and Andel-6ST (45% working
interest) wells during Q3 2016. If successful, we expect to bring
the wells on-stream late in the third and fourth quarters of 2016,
respectively. Activities in France
will continue to focus on our highly-economic workover and
optimization activities. In Germany, the majority of our capital in 2016
will be directed to permitting and pre-drill activities for the
planned drilling of the Burgmoor Z5 well and two potential
exploration prospects in 2017.
Since the initiation of first gas at Corrib in Ireland on December 30,
2015, we have experienced robust well deliverability and
minimal downtime. Net production in Q1 2016 averaged approximately
34 mmcf/d (5,650 boe/d). Field production is subject to limitations
on maximum pipeline operating pressures that will remain in effect
until the planned recertification process for the third party sales
gas distribution pipeline network is concluded. Five of the six
wells are capable of producing, with the remaining well to be
brought online in the third quarter of 2016 following the
conclusion of our offshore work program to lay a pipeline to the
sixth well. Upon completion of the recertification process,
production levels at Corrib are expected to rise to an estimated
peak rate of 58 mmcf/d (9,700 boe/d), net to Vermilion. Corrib remains one of the drivers
of our 2016 and 2017 production growth, and is expected to be an
important contributor to free cash flow(1) in this and coming
years.
Following our successful sidetrack well drilled from the Wandoo
A platform in Q4 2015, we are planning a two-well drilling program
in Q2 2016. Offshore drilling in Australia requires a great deal of advance
contracting and logistical planning, which means that full-cycle
costs are minimized by maintaining funding for this project in 2016
despite current oil price weakness. Furthermore, with service costs
near their lows, it is an advantageous time to drill these
high-quality sidetrack wells.
In Canada, our Mannville condensate-rich gas assets performed
strongly in the first quarter with average production of 13,000
boe/d, an increase of 18% percent over the prior quarter. This
significant production increase resulted from the combination of
both operated and non-operated drilling and completion activity, as
well as the re-start of non-operated wells that were previously
shut-in due to infrastructure capacity constraints. Our drilling,
completion, equip and tie-in ("DCET") costs continue to improve as
a result of our ongoing focus on operational and process
improvements and continued service cost reductions. Our DCET costs
in the Mannville averaged
$3.6 million per well in the first
quarter of 2016, a nearly 15% reduction as compared to our average
DCET of $4.2 million per well in
2015, and approximately a 40% reduction from our cost level when we
imitated this play three years ago.
Similarly, cycle times and costs continue to trend lower in our
Midale light oil development in
southeast Saskatchewan. Since
assuming operations in 2014, we have achieved more than a 35%
reduction in average drilling days per well, as well as benefitting
from lower service costs. Expected DCET costs for a typical
one-mile Midale horizontal well
are now $1.9 million, down 35% as
compared to $2.9 million in 2014. In
the first quarter we drilled six (4.5 net) oil wells in the
Midale, including three (3.0 net)
operated wells, to prevent mineral land expiries. All three
operated wells had strong oil indicators, but we have elected to
leave these wells standing uncompleted. While the wells are
economic to complete, we believe that net present value will be
enhanced by delaying completion and tie-in until oil prices
improve.
In the United States, we are
disclosing results for several wells drilled in our shallow Turner
Sand play on the eastern flank of the Powder River Basin in
Wyoming. The Seedy Draw North
Federal 1H well was completed in Q3 2015 in the Turner Shurley Sand
in the southern part of our contiguous 83,250 acre lease block.
This well is significantly outperforming our 275 mbbl oil type
curve established from a nearby well drilled by the previous
operator. Peak production of approximately 300 bbls/d of oil was
recorded in the third through fifth months of production. The Seedy
Draw North Federal 1H is currently producing 200 bbls/d of oil (240
boed/d including gas production) in its ninth month of production,
with cumulative oil production to-date of 63 mbbls.
Two additional wells drilled in the Turner Shurley Sand in Q4
2015 were completed during the first quarter. Both wells were
completed with 20-stage fracturing treatments along 1,400 meter
horizontal laterals at a vertical depth of approximately 1,500
meters. One of the wells (the Coyote Draw Federal 1H), located in
the north part of our lease block, has been on production for one
month at a current oil rate of 150 bbls/d, and is expected to
continue to increase in production as load water is recovered and
the well cleans up. The second well (the Reed Federal 17-1H) was
drilled in the southern area, approximately one mile from our Seedy
Draw North Federal 1H well. The Reed Federal 17-1H was successfully
fracture stimulated, but we unfortunately junked almost the entire
horizontal liner section when we attempted to drill out the frac
plugs. The well is producing 65 bbls/d of oil from approximately
10% of the completed horizontal section. Despite the mechanical
failure of the Reed Federal 17-1H, we consider these well results
very encouraging in terms of productivity as we begin development
of this large contiguous lease block in the Turner Sand.
We entered the current commodity downturn in a position of
relative financial strength, and we took a number of actions
throughout 2015 to preserve our balance sheet. During Q1 2016, we
redeemed our senior unsecured notes that came due on February 10, 2016 using funds drawn against our
revolving credit facility. Following the redemption, all of our
debt is now classified as senior debt pursuant to the terms of the
revolving credit facility. As a result, we requested, and received
amendments from our lending syndicate to eliminate the consolidated
total senior debt to consolidated EBITDA(2) financial covenant and
increase the ratio of consolidated total senior debt to total
capitalization financial covenant from 50% to 55%. The revolving
credit facility limit of $2.0 billion
remains unchanged and we have approximately $520 million of borrowing capacity available. We
were in compliance with all covenants as of March 31, 2016 and expect, based on 2016
commodity strip pricing, to remain in compliance with the amended
financial covenants.
We continue to prioritize the strength of our balance sheet and
the long-term profitability of our business through our
Profitability Enhancement Program ("PEP") initiative. Associated
PEP cost savings related to capital spending, operating expense and
G&A expenditures reached nearly $90
million for full-year 2015. For 2016, we expect to deliver a
further $30 to $40 million of cost
reductions. Our focus on driving down costs has generated tangible
results. Finding and development costs(3), as estimated at year-end
2015, were down 48% year-over-year and our unit operating expenses
for Q1 2016 are down 17% quarter-over-quarter and 9%
year-over-year, reflecting both increased volumes and our reduced
cost structure.
Vermilion was recently ranked
9th by Corporate Knights on the Future 40 Responsible Corporate
Leaders in Canada list, an
improvement over last year's ranking of 15th. We are also the
highest rated oil and gas company on the list of top sustainability
performers. This recognition reflects Vermilion's focus on financial results
combined with exemplary environmental, social and governance
performance.
Vermilion was recognized by the
Great Place to Work® Institute as a Best Workplace in Canada, France, the
Netherlands and Germany in
2016. Vermilion was the only
energy company to rank on the Best Workplaces lists in Canada and in France. The Great Place to Work® awards
recognize Vermilion's strong
corporate culture, a key driver of Vermilion's leading long-term corporate
performance.
In spite of the challenges posed by the current commodity
environment, we continue to believe our long-term strategy will
position Vermilion to exit this
downturn stronger than ever. All Vermilion employees are shareholders, and
management and directors hold approximately 6% of our outstanding
shares, ensuring alignment of interests to deliver long-term value.
We believe that our diversified asset portfolio and operational
capabilities position us to protect our balance sheet, defend our
dividend, and continue long-term growth.
(1)
|
Non-GAAP Financial
Measure. Please see the "Non-GAAP Financial Measures" section
of Management's Discussion and Analysis.
|
(2)
|
Our covenants include
financial measures defined within our revolving credit facility.
Please see the "Financial Position Review" section of the
Management's Discussion and Analysis.
|
(3)
|
Finding and
development costs are used as a measure of capital efficiency and
are calculated by dividing the applicable capital costs for the
period, including the change in undiscounted future development
capital, by the change in the reserves, incorporating revisions and
production, for the same period.
|
ORGANIZATIONAL UPDATE
We wish to acknowledge that Joe
Killi and Kevin Reinhart are
not standing for re-election as directors at the May 6, 2016 Annual General Meeting. Both
individuals have been key contributors to Vermilion's success during their tenures with
the Board and we would like to take this opportunity to thank them
for their valuable counsel and wish them all the best in their
future endeavours.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is Management's Discussion and Analysis
("MD&A"), dated May 5, 2016, of
Vermilion Energy Inc.'s ("Vermilion", "We", "Our", "Us" or the
"Company") operating and financial results as at and for the three
months ended March 31, 2016 compared
with the corresponding period in the prior year.
This discussion should be read in conjunction with the unaudited
condensed consolidated interim financial statements for the three
months ended March 31, 2016 and the
audited consolidated financial statements for the year ended
December 31, 2015 and 2014, together
with accompanying notes. Additional information relating to
Vermilion, including its Annual
Information Form, is available on SEDAR at www.sedar.com or on
Vermilion's website at
www.vermilionenergy.com.
The unaudited condensed consolidated interim financial
statements for the three months ended March
31, 2016 and comparative information have been prepared in
Canadian dollars, except where another currency is indicated, and
in accordance with IAS 34, "Interim Financial Reporting", as issued
by the International Accounting Standard Board ("IASB").
This MD&A includes references to certain financial measures
which do not have standardized meanings prescribed by International
Financial Reporting Standards ("IFRS"). These financial
measures include:
- Fund flows from operations: This financial measure is
calculated as cash flows from operating activities before changes
in non-cash operating working capital and asset retirement
obligations settled. We analyze fund flows from operations both on
a consolidated basis and on a business unit basis in order to
assess the contribution of each business unit to our ability to
generate cash necessary to pay dividends, repay debt, fund asset
retirement obligations and make capital investments.
- Netbacks: These financial measures are per boe and per mcf
measures used in the analysis of operational activities. We assess
netbacks both on a consolidated basis and on a business unit basis
in order to compare and assess the operational and financial
performance of each business unit versus other business units and
third party crude oil and natural gas producers.
In addition, this MD&A includes references to certain
financial measures which do not have standardized meanings
prescribed by IFRS and are not disclosed in our financial
statements. As such, these financial measures are considered
non-GAAP financial measures and therefore are unlikely to be
comparable with similar financial measures presented by other
issuers. For a full description of these non-GAAP financial
measures and a reconciliation of these measures to their most
directly comparable GAAP measures, please refer to "NON-GAAP
FINANCIAL MEASURES".
VERMILION'S BUSINESS
Vermilion is a Calgary, Alberta based international oil and
gas producer focused on the acquisition, exploration, development
and optimization of producing properties in North America, Europe, and Australia. We manage our
business through our Calgary head
office and our international business unit offices.
This MD&A separately discusses each of our business units in
addition to our corporate segment.
- Canada business unit: Relates
to our assets in Alberta and
Saskatchewan.
- France business unit: Relates
to our operations in France in the
Paris and Aquitaine Basins.
- Netherlands business unit:
Relates to our operations in the
Netherlands.
- Germany business unit: Relates
to our operations in Germany.
- Ireland business unit: Relates
to our 18.5% non-operated interest in the Corrib offshore natural
gas field.
- Australia business unit:
Relates to our operations in the Wandoo offshore crude oil
field.
- United States business unit:
Relates to our operations in Wyoming in the Powder River Basin.
- Corporate: Includes expenditures related to our global hedging
program, financing expenses, and general and administration
expenses that are primarily incurred in Canada and are not directly related to the
operations of a specific business unit.
CHANGE IN PRESENTATION
Prior to 2016, we reported our condensate production in
Canada and the Netherlands business units within the NGLs
production line. Beginning in Q1 2016, we now report condensate
production within the crude oil and condensate production
line. We believe that this presentation better reflects the
historical and forecasted pricing for condensate, which is more
closely correlated with crude oil pricing than with pricing for
propane, butane and ethane (collectively "NGLs" for the purposes of
this report). Comparative periods have been adjusted to reflect
this change.
2015 REVIEW AND 2016 GUIDANCE
On November 9, 2015 we announced
preliminary 2016 capital expenditure guidance of $350 million and production guidance of between
63,000-65,000 boe/d. On January 5,
2016, in response to the continued weakness in commodity
prices we adjusted our 2016 capital expenditure guidance to
$285 million with corresponding
production guidance of 62,500-63,500 boe/d. On February 29, 2016, we further revised our 2016
capital expenditure guidance to $235
million as a result of continued commodity price
deterioration. We maintained our production guidance of
62,500-63,500 boe/d. The February 29,
2016 reduction primarily reflects lower expected
non-operated drilling activity in Canada, fewer workovers in France, and a deferral of our Netherlands pipeline twinning program.
The following table summarizes our 2016 guidance:
|
|
Date
|
|
Capital
Expenditures ($MM)
|
|
Production
(boe/d)
|
2016
Guidance
|
|
|
|
|
|
|
2016
Guidance
|
|
November 9,
2015
|
|
350
|
|
63,000 to
65,000
|
2016
Guidance
|
|
January 5,
2016
|
|
285
|
|
62,500 to
63,500
|
2016
Guidance
|
|
February 29,
2016
|
|
235
|
|
62,500 to
63,500
|
CONSOLIDATED RESULTS OVERVIEW
|
|
|
Three Months
Ended
|
|
%
change
|
|
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
|
Q1/16
vs.
|
Q1/16
vs.
|
|
|
|
2016
|
2015
|
2015
|
|
Q4/15
|
Q1/15
|
Production
|
|
|
|
|
|
|
|
|
Crude oil and
condensate (bbls/d)
|
|
29,199
|
31,304
|
29,514
|
|
(7%)
|
(1%)
|
|
NGLs
(bbls/d)
|
|
2,672
|
2,739
|
1,706
|
|
(2%)
|
57%
|
|
Natural gas
(mmcf/d)
|
|
201.11
|
162.09
|
115.00
|
|
24%
|
75%
|
|
Total
(boe/d)
|
|
65,389
|
61,058
|
50,386
|
|
7%
|
30%
|
|
Build (draw) in
inventory (mbbls)
|
|
142
|
(93)
|
383
|
|
|
|
Financial
metrics
|
|
|
|
|
|
|
|
|
Fund flows from
operations ($M)
|
|
93,667
|
136,441
|
120,795
|
|
(31%)
|
(22%)
|
|
Per
share ($/basic share)
|
|
0.83
|
1.22
|
1.12
|
|
(32%)
|
(26%)
|
|
Net (loss)
earnings
|
|
(85,848)
|
(142,080)
|
1,275
|
|
(40%)
|
(6,833%)
|
|
Per
share ($/basic share)
|
|
(0.76)
|
(1.28)
|
0.01
|
|
(41%)
|
(7,700%)
|
|
Cash flows from
operating activities ($M)
|
|
73,883
|
164,863
|
22,647
|
|
(55%)
|
226%
|
|
Net debt
($M)
|
|
1,367,063
|
1,381,951
|
1,388,603
|
|
(1%)
|
(2%)
|
|
Cash dividends
($/share)
|
|
0.645
|
0.645
|
0.645
|
|
-
|
-
|
Activity
|
|
|
|
|
|
|
|
|
Capital expenditures
($M)
|
|
62,773
|
128,996
|
174,311
|
|
(51%)
|
(64%)
|
|
Acquisitions
($M)
|
|
870
|
6,227
|
35
|
|
(86%)
|
2,386%
|
|
Gross wells
drilled
|
|
12.00
|
8.00
|
29.00
|
|
|
|
|
Net wells
drilled
|
|
8.26
|
5.56
|
20.04
|
|
|
|
Operational review
- Recorded consolidated average production of 65,389 boe/d in Q1
2016, which was a 7% increase over Q4 2015. This
quarter-over-quarter increase was driven by a full quarter of
production from Corrib and increased production in Canada.
- Increased consolidated average production from Q1 2015 by 30%,
primarily due to the addition of Corrib production in Ireland, as well as production growth in all
our business units except Germany,
where production modestly declined.
- Executed capital expenditures totalling $62.8 million, primarily in Canada and France. In Canada, capital expenditures of $29.8 million were 8% higher than Q4 2015 and
related to the drilling of 8.3 net wells (2.6 net wells in Q4
2015). In France, capital
expenditures of $13.5 million were
44% lower than Q4 2015 and related primarily to accretive workovers
and subsurface activity.
Financial review
Net (loss) earnings
- The net loss for Q1 2016 was $85.8
million ($0.76/basic share),
as compared to a net loss of $142.1
million ($1.28/basic share) in
Q4 2015. The decrease in the net loss was primarily attributable to
a lower impairment charge recognized in the quarter, partially
offset by lower petroleum and natural gas sales due to weakening
commodity prices.
- The net loss in Q1 2016 represented a decrease of $87.1 million versus the comparable period in
2015. This decrease was driven primarily by lower petroleum and
natural gas sales as a result of lower commodity prices, the impact
of the de-recognition of certain deferred tax assets, an impairment
charge recognized in Ireland, and
the absence of a $31.8 million
court-awarded recovery recognized in Q1 2015. The impact of
weakened commodity prices was partially offset by significant
production growth, global cost reductions (including a 9% reduction
in per unit operating expense), and gains on derivative
instruments.
Cash flows from operating activities
- Absent changes in working capital, cash flows from operating
activities decreased by 30% quarter-over-quarter due to lower
petroleum and natural gas sales driven by lower commodity
prices.
- Absent changes in working capital, cash flows from operating
activities decreased by 22% for the three months ended March 31, 2016, versus the comparable period in
2015. This decrease was primarily related to lower petroleum and
natural gas sales due to lower commodity prices, partially offset
by realized gains on derivative instruments and lower current
taxes.
Fund flows from operations
- Generated fund flows from operations of $93.7 million during Q1 2016, a decrease of 31%
from Q4 2015. This quarter-over-quarter decrease was primarily
driven by unfavourable pricing variances on all commodities and
lower volumes sold in Australia
due to a build in inventory. The impact of lower pricing was
minimized by a full quarter of production from Corrib and decreased
operating costs resulting from global cost reductions.
- Fund flows from operations decreased by 22% versus Q1 2015.
This decrease was the result of lower pricing on all commodities
and the absence of the $31.8 million
court-awarded recovery recognized in Q1 2015, partially offset by
global cost reductions, realized gains on derivative instruments,
and lower current taxes.
Net debt
- Net debt decreased by $14.9
million to $1.37 billion for
the three months ended March 31,
2016, as we maintained a payout ratio of 96%.
Dividends
- Declared dividends of $0.215 per
common share per month during the first quarter of 2016, totalling
$0.645 per common share for the
quarter.
COMMODITY PRICES
|
|
Three Months
Ended
|
|
%
change
|
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
|
Q1/16
vs.
|
Q1/16
vs.
|
|
|
2016
|
2015
|
2015
|
|
Q4/15
|
Q1/15
|
Average reference
prices
|
|
|
|
|
|
|
|
Crude oil
|
|
|
|
|
|
|
|
|
WTI (US
$/bbl)
|
|
33.45
|
42.18
|
48.63
|
|
(21%)
|
(31%)
|
|
Edmonton Sweet index
(US $/bbl)
|
|
29.76
|
39.72
|
41.83
|
|
(25%)
|
(29%)
|
|
Dated Brent (US
$/bbl)
|
|
33.89
|
43.69
|
53.97
|
|
(22%)
|
(37%)
|
Natural
gas
|
|
|
|
|
|
|
|
|
AECO
($/mmbtu)
|
|
1.83
|
2.46
|
2.75
|
|
(26%)
|
(33%)
|
|
TTF
($/mmbtu)
|
|
5.70
|
7.28
|
8.70
|
|
(22%)
|
(34%)
|
|
TTF
(€/mmbtu)
|
|
3.76
|
4.98
|
6.23
|
|
(24%)
|
(40%)
|
|
NBP
($/mmbtu)
|
|
5.97
|
7.41
|
9.01
|
|
(19%)
|
(34%)
|
|
NBP
(€/mmbtu)
|
|
3.94
|
5.07
|
6.45
|
|
(22%)
|
(39%)
|
|
Henry Hub
($/mmbtu)
|
|
2.87
|
3.03
|
3.70
|
|
(5%)
|
(22%)
|
|
Henry Hub (US
$/mmbtu)
|
|
2.09
|
2.27
|
2.98
|
|
(8%)
|
(30%)
|
Average foreign
currency exchange rates
|
|
|
|
|
|
|
|
CDN $/US $
|
|
1.37
|
1.34
|
1.24
|
|
2%
|
10%
|
CDN $/Euro
|
|
1.52
|
1.46
|
1.40
|
|
4%
|
9%
|
Average realized
prices ($/boe)
|
|
|
|
|
|
|
|
Canada
|
|
21.16
|
28.94
|
35.81
|
|
(27%)
|
(41%)
|
France
|
|
43.16
|
54.20
|
64.33
|
|
(20%)
|
(33%)
|
Netherlands
|
|
33.26
|
42.61
|
48.60
|
|
(22%)
|
(32%)
|
Germany
|
|
31.78
|
39.68
|
45.21
|
|
(20%)
|
(30%)
|
Ireland
|
|
33.07
|
-
|
-
|
|
100%
|
100%
|
Australia
|
|
46.93
|
58.74
|
83.80
|
|
(20%)
|
(44%)
|
United
States
|
|
30.10
|
41.94
|
48.79
|
|
(28%)
|
(38%)
|
Consolidated
|
|
30.53
|
41.04
|
47.17
|
|
(26%)
|
(35%)
|
Production mix (%
of production)
|
|
|
|
|
|
|
|
% priced with
reference to WTI
|
|
20%
|
22%
|
28%
|
|
|
|
% priced with
reference to AECO
|
|
25%
|
24%
|
20%
|
|
|
|
% priced with
reference to TTF and NBP
|
|
26%
|
20%
|
18%
|
|
|
|
% priced with
reference to Dated Brent
|
|
29%
|
34%
|
34%
|
|
|
|
- Oil benchmarks continued to move lower throughout Q1 2016,
pressured by the ongoing fundamental conditions. For Q1 2016, Dated
Brent and WTI prices decreased by approximately 20% versus Q4 2015.
On a year-over-year basis, WTI was down 31% and Dated Brent was
down 37%.
- Crude oil prices set at Edmonton were equally as volatile during Q1
2016, averaging the quarter at US $29.76/bbl, 25% lower quarter-over-quarter, and
29% lower year-over-year.
- AECO natural gas prices declined in Q1 2016 due to the
warmer-than-normal winter which lessened demand. For Q1 2016, AECO
averaged $1.83/mmbtu, 26% lower
quarter-over-quarter and down 33% year-over-year.
- A warmer winter in Europe
combined with ample supply caused European natural gas prices to
post a 22% quarter-over-quarter decline to average $5.70/mmbtu at TTF. NBP performed slightly better
than TTF, with a quarter-over-quarter loss of 19%. The smaller
decrease was due to stronger demand from coal-to-gas switching for
power generation in the UK. On a year-over-year basis, both TTF and
NBP were down 34%.
- Despite exiting the first quarter with a stronger Canadian
dollar versus the US dollar, the average exchange rate for the
quarter still favoured a stronger US dollar. The Canadian dollar
also weakened against the Euro, with Q1 2016 averaging 1.52 versus
1.46 in Q4 2015 and 1.40 in Q1 2015.
FUND FLOWS FROM OPERATIONS
|
|
Three Months
Ended
|
|
|
Mar 31,
2016
|
Dec 31,
2015
|
Mar 31,
2015
|
|
|
$M
|
$/boe
|
$M
|
$/boe
|
$M
|
$/boe
|
Petroleum and natural
gas sales
|
|
177,385
|
30.53
|
234,319
|
41.04
|
195,885
|
47.17
|
Royalties
|
|
(13,961)
|
(2.40)
|
(16,285)
|
(2.85)
|
(16,424)
|
(3.95)
|
Petroleum and natural
gas revenues
|
|
163,424
|
28.13
|
218,034
|
38.19
|
179,461
|
43.22
|
Transportation
|
|
(10,390)
|
(1.79)
|
(10,147)
|
(1.78)
|
(9,540)
|
(2.30)
|
Operating
|
|
(55,628)
|
(9.58)
|
(65,645)
|
(11.50)
|
(43,851)
|
(10.56)
|
General and
administration
|
|
(13,577)
|
(2.34)
|
(12,431)
|
(2.18)
|
(13,560)
|
(3.27)
|
PRRT
|
|
(128)
|
(0.02)
|
(1,054)
|
(0.18)
|
(2,354)
|
(0.57)
|
Corporate income
taxes
|
|
(3,160)
|
(0.54)
|
3,113
|
0.55
|
(17,623)
|
(4.24)
|
Interest
expense
|
|
(14,750)
|
(2.54)
|
(16,584)
|
(2.90)
|
(13,298)
|
(3.20)
|
Realized gain on
derivative instruments
|
|
28,423
|
4.89
|
21,164
|
3.71
|
6,257
|
1.51
|
Realized foreign
exchange (loss) gain
|
|
(652)
|
(0.11)
|
(252)
|
(0.04)
|
3,306
|
0.78
|
Realized other
income
|
|
105
|
0.02
|
243
|
0.04
|
31,997
|
7.70
|
Fund flows from
operations
|
|
93,667
|
16.12
|
136,441
|
23.91
|
120,795
|
29.07
|
The following table shows a reconciliation of the change in fund
flows from operations:
($M)
|
|
|
Q1/16 vs.
Q4/15
|
|
Q1/16 vs.
Q1/15
|
Fund flows from
operations – Comparative period
|
|
|
136,441
|
|
120,795
|
Sales volume
variance:
|
|
|
|
|
|
|
Canada
|
|
|
684
|
|
6,322
|
|
France
|
|
|
(2,470)
|
|
11,538
|
|
Netherlands
|
|
|
(2,473)
|
|
12,812
|
|
Germany
|
|
|
(245)
|
|
(464)
|
|
Ireland
|
|
|
16,947
|
|
17,004
|
|
Australia
|
|
|
(23,000)
|
|
16,313
|
|
United
States
|
|
|
(229)
|
|
545
|
Pricing variance on
sold volumes:
|
|
|
|
|
|
|
WTI
|
|
|
(13,270)
|
|
(18,885)
|
|
AECO
|
|
|
(5,658)
|
|
(9,195)
|
|
Dated
Brent
|
|
|
(17,833)
|
|
(38,907)
|
|
TTF and
NBP
|
|
|
(9,387)
|
|
(15,583)
|
Changes
in:
|
|
|
|
|
|
|
Royalties
|
|
|
2,324
|
|
2,463
|
|
Transportation
|
|
|
(243)
|
|
(850)
|
|
Operating
|
|
|
10,017
|
|
(11,777)
|
|
General and
administration
|
|
|
(1,146)
|
|
(17)
|
|
PRRT
|
|
|
926
|
|
2,226
|
|
Corporate income
taxes
|
|
|
(6,273)
|
|
14,463
|
|
Interest
|
|
|
1,834
|
|
(1,452)
|
|
Realized
derivatives
|
|
|
7,259
|
|
22,166
|
|
Realized foreign
exchange
|
|
|
(400)
|
|
(3,958)
|
|
Realized other
income
|
|
|
(138)
|
|
(31,892)
|
Fund flows from
operations – Current period
|
|
|
93,667
|
|
93,667
|
Fund flows from operations of $93.7
million during Q1 2016 represented a decrease of 31% versus
Q4 2015. This decrease relates primarily to lower pricing on all
commodities and a 138,000 bbls build in inventory in Australia (compared to a draw of 97,000 bbls
in Q4 2015). The impact of lower pricing was minimized by a full
quarter of production from Corrib and global cost reductions,
including a 15% decrease in operating costs.
Fund flows from operations decreased 22% for the three months
ended March 31, 2016, versus the
comparable period in 2015. The decrease was the result of lower
pricing for all commodities and the absence of a $31.8 million court-awarded recovery recognized
in Q1 2015. The decrease in pricing was partially offset by global
cost reductions (including a 9% reduction in per unit operating
expense), realized gains on derivative instruments, and lower
current taxes.
Fluctuations in fund flows from operations (and correspondingly
net (loss) earnings and cash flows from operating activities) may
occur as a result of changes in commodity prices and costs to
produce petroleum and natural gas. In addition, fund flows
from operations may be highly affected by the timing of crude oil
shipments in Australia and
France. When crude oil inventory is built up, the related
operating expense, royalties, and depletion expense are deferred
and carried as inventory on the consolidated balance sheet.
When the crude oil inventory is subsequently drawn down, the
related expenses are recognized in income.
CANADA BUSINESS UNIT
Overview
- Production and assets focused in West Pembina near Drayton Valley, Alberta and Northgate in
southeast Saskatchewan.
- Potential for three significant resource plays sharing the same
surface infrastructure in the West Pembina region in Alberta:
- Cardium light oil (1,800m depth) – in development phase
- Mannville condensate-rich gas
(2,400 – 2,700m depth) – in development phase
- Duvernay condensate-rich gas
(3,200 – 3,400m depth) – in appraisal phase
- Canadian cash flows are fully tax-sheltered for the foreseeable
future.
Operational review
|
|
|
Three Months
Ended
|
|
%
change
|
|
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
|
Q1/16
vs.
|
Q1/16
vs.
|
Canada business
unit
|
|
2016
|
2015
|
2015
|
|
Q4/15
|
Q1/15
|
Production
|
|
|
|
|
|
|
|
|
Crude oil and
condensate (bbls/d)
|
|
10,317
|
10,413
|
12,163
|
|
(1%)
|
(15%)
|
|
NGLs
(bbls/d)
|
|
2,633
|
2,710
|
1,706
|
|
(3%)
|
54%
|
|
Natural gas
(mmcf/d)
|
|
97.16
|
87.90
|
61.78
|
|
11%
|
57%
|
|
Total
(boe/d)
|
|
29,141
|
27,773
|
24,165
|
|
5%
|
21%
|
Production mix (%
of total)
|
|
|
|
|
|
|
|
|
Crude oil and
condensate
|
|
35%
|
38%
|
50%
|
|
|
|
|
NGLs
|
|
9%
|
10%
|
7%
|
|
|
|
|
Natural
gas
|
|
56%
|
52%
|
43%
|
|
|
|
Activity
|
|
|
|
|
|
|
|
|
Capital expenditures
($M)
|
|
29,771
|
27,554
|
114,849
|
|
8%
|
(74%)
|
|
Acquisitions
($M)
|
|
755
|
6,169
|
35
|
|
|
|
|
Gross wells
drilled
|
|
12.00
|
5.00
|
25.00
|
|
|
|
|
Net wells
drilled
|
|
8.26
|
2.56
|
16.04
|
|
|
|
Production
- Q1 2016 average production in Canada increased by 5% quarter-over-quarter
and 21% year-over-year, primarily attributable to strong organic
production growth in our Mannville
condensate-rich gas resource play.
- Cardium production averaged more than 7,500 boe/d in Q1 2016, a
5% decrease quarter-over-quarter.
- Mannville production averaged
approximately 13,000 boe/d in Q1 2016, an 18% increase
quarter-over-quarter and more than 2.5 times Q1 2015 production of
approximately 4,850 boe/d.
- Production from our southeast Saskatchewan assets averaged approximately
2,700 boe/d in Q1 2016, an increase of 6%
quarter-over-quarter.
Activity review
- Vermilion drilled six (5.7
net) operated wells and participated in the drilling of six (2.6
net) non-operated wells during Q1 2016.
Cardium
- In Q1 2016, no new operated wells were drilled, completed or
brought on production. Two (0.31 net) non-operated wells were
brought on production during the quarter.
- 2016 activity will focus on the optimization of existing
assets.
Mannville
- During Q1 2016, we participated in a total of six (3.8 net)
wells, including three (2.7 net) operated wells. Three (2.7 net)
operated wells and four (1.5 net) non-operated wells were brought
on production during the quarter.
- We completed a 3D seismic program in the northern portion of
our Drayton Valley lands. The
program covered 34 net sections, including lands acquired in
2015.
- Our 2016 program to drill or participate in six (3.8 net) wells
was completed in the first quarter.
Saskatchewan
- We drilled three (3.0 net) operated Midale wells during Q1 2016 and participated
in the drilling of three (1.5 net) non-operated Midale wells. Completion and tie-in of the
three operated wells is currently planned for Q1 2017. Two of the
three non-operated wells were placed on production in Q1 2016, with
the remaining non-operated well to be placed on production in Q2
2016.
- Q1 2016 activity included the acquisition and processing of 3D
seismic of 16 net sections (100% Vermilion interest) in the West Pinto
area
- In 2016, we plan to drill or participate in seven (5.5 net)
wells.
Financial review
|
|
|
Three Months
Ended
|
%
change
|
Canada business
unit
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
Q1/16
vs.
|
Q1/16
vs.
|
($M except as
indicated)
|
|
2016
|
2015
|
2015
|
Q4/15
|
Q1/15
|
|
Sales
|
|
56,110
|
73,952
|
77,884
|
(24%)
|
(28%)
|
|
Royalties
|
|
(5,498)
|
(7,146)
|
(8,592)
|
(23%)
|
(36%)
|
|
Transportation
|
|
(4,151)
|
(3,784)
|
(3,942)
|
10%
|
5%
|
|
Operating
|
|
(21,343)
|
(24,575)
|
(19,099)
|
(13%)
|
12%
|
|
General and
administration
|
|
(2,476)
|
(3,669)
|
(4,015)
|
(33%)
|
(38%)
|
|
Fund flows from
operations
|
|
22,642
|
34,778
|
42,236
|
(35%)
|
(46%)
|
Netbacks
($/boe)
|
|
|
|
|
|
|
|
Sales
|
|
21.16
|
28.94
|
35.81
|
(27%)
|
(41%)
|
|
Royalties
|
|
(2.07)
|
(2.80)
|
(3.95)
|
(26%)
|
(48%)
|
|
Transportation
|
|
(1.57)
|
(1.48)
|
(1.81)
|
6%
|
(13%)
|
|
Operating
|
|
(8.05)
|
(9.62)
|
(8.78)
|
(16%)
|
(8%)
|
|
General and
administration
|
|
(0.94)
|
(1.44)
|
(1.85)
|
(35%)
|
(49%)
|
|
Fund flows from
operations netback
|
|
8.53
|
13.60
|
19.42
|
(37%)
|
(56%)
|
Realized
prices
|
|
|
|
|
|
|
|
Crude oil and
condensate ($/bbl)
|
|
39.69
|
53.44
|
52.91
|
(26%)
|
(25%)
|
|
NGLs
($/bbl)
|
|
7.31
|
7.89
|
22.37
|
(7%)
|
(67%)
|
|
Natural gas
($/mmbtu)
|
|
1.93
|
2.57
|
2.97
|
(25%)
|
(35%)
|
|
Total
($/boe)
|
|
21.16
|
28.94
|
35.81
|
(27%)
|
(41%)
|
Reference
prices
|
|
|
|
|
|
|
|
WTI (US
$/bbl)
|
|
33.45
|
42.18
|
48.63
|
(21%)
|
(31%)
|
|
Edmonton Sweet index
(US $/bbl)
|
|
29.76
|
39.72
|
41.83
|
(25%)
|
(29%)
|
|
Edmonton Sweet index
($/bbl)
|
|
40.91
|
53.04
|
51.92
|
(23%)
|
(21%)
|
|
AECO
($/mmbtu)
|
|
1.83
|
2.46
|
2.75
|
(26%)
|
(33%)
|
Sales
- The realized price for our crude oil and condensate production
in Canada is directly linked to
WTI, but is also subject to market conditions in Western Canada. These market conditions can
result in fluctuations in the pricing differential to WTI, as
reflected by the Edmonton Sweet index price. The realized price of
our NGLs in Canada is based on
product specific differentials pertaining to trading hubs in
the United States. The realized
price of our natural gas in Canada
is based on the AECO spot price in Canada.
- Q1 2016 sales per boe decreased versus all comparable periods,
largely as the result of weakening crude oil and natural gas
pricing.
Royalties
- Royalties as a percentage of sales for Q1 2016 of 9.8% was
consistent with the rate of 9.7% for Q4 2015.
- Royalties as a percentage of sales for Q1 2016 was lower than
Q1 2015 (11.0%) due to the impact of lower reference prices on the
sliding scale used to determine crude oil royalty rates.
Transportation
- Transportation expense relates to the delivery of crude oil and
natural gas production to major pipelines where legal title
transfers.
- Transportation expense for Q1 2016 was higher than Q4 2015 and
Q1 2015 as a result of increased natural gas production. On a
year-over-year basis, the 13% decrease in per unit costs is due to
an increased gas weighting and the lower per unit transportation
costs associated with gas production.
Operating
- Operating expense reductions of 13% were achieved in Q1 2016
versus Q4 2015 while growing production by 5%. The diligent focus
on cost control and cost-cutting initiatives, including service
cost negotiations impacting numerous cost drivers, has resulted in
a 16% per unit reduction in costs from Q4 2015 and 8% from Q1
2015.
General and administration
- General and administration expense decreased by 35% and 49%
from Q4 2015 and Q1 2015 respectively. The decreases are consistent
with continued cost-cutting initiatives to reduce our cost
structure and preserve balance sheet strength.
FRANCE BUSINESS UNIT
Overview
- Entered France in 1997 and
completed three subsequent acquisitions, including two in
2012.
- Largest oil producer in France, constituting approximately
three-quarters of domestic oil production.
- Producing assets include large conventional fields with high
working interests located in the Aquitaine and Paris Basins with an
identified inventory of workover, infill drilling, and secondary
recovery opportunities.
- Production is characterized by Brent-based crude pricing and
low base decline rates.
Operational review
|
|
|
|
Three Months
Ended
|
|
%
change
|
|
|
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
|
Q1/16
vs.
|
Q1/16
vs.
|
France business
unit
|
|
|
2016
|
2015
|
2015
|
|
Q4/15
|
Q1/15
|
Production
|
|
|
|
|
|
|
|
|
|
Crude oil
(bbls/d)
|
|
|
12,220
|
12,537
|
11,463
|
|
(3%)
|
7%
|
|
Natural gas
(mmcf/d)
|
|
|
0.44
|
1.36
|
-
|
|
(68%)
|
100%
|
|
Total
(boe/d)
|
|
|
12,293
|
12,763
|
11,463
|
|
(4%)
|
7%
|
Inventory
(mbbls)
|
|
|
|
|
|
|
|
|
|
Opening crude oil
inventory
|
|
|
243
|
239
|
197
|
|
|
|
|
Crude oil
production
|
|
|
1,112
|
1,153
|
1,032
|
|
|
|
|
Crude oil
sales
|
|
|
(1,108)
|
(1,149)
|
(930)
|
|
|
|
|
Closing crude oil
inventory
|
|
|
247
|
243
|
299
|
|
|
|
Production mix (%
of total)
|
|
|
|
|
|
|
|
|
|
Crude oil
|
|
|
99%
|
98%
|
100%
|
|
|
|
|
Natural
gas
|
|
|
1%
|
2%
|
-
|
|
|
|
Activity
|
|
|
|
|
|
|
|
|
|
Capital expenditures
($M)
|
|
|
13,463
|
24,085
|
34,114
|
|
(44%)
|
(61%)
|
|
Acquisitions
($M)
|
|
|
-
|
79
|
-
|
|
|
|
|
Gross wells
drilled
|
|
|
-
|
-
|
4.00
|
|
|
|
|
Net wells
drilled
|
|
|
-
|
-
|
4.00
|
|
|
|
Production
- Production decreased 4% versus the prior quarter, mainly due to
a reduced capital program. Gas production from Vic Bilh was
negatively impacted by third party restrictions at the SOBEGI
terminal.
- Year-over-year production increased 7% due to production
additions from our 2015 Champotran drilling program.
Activity review
- During the quarter we completed a number of workover and
optimization programs in the Aquitaine and Paris Basins.
- In 2016, our planned capital activity includes a program of
approximately 15 well workovers.
Financial review
|
|
|
Three Months
Ended
|
%
change
|
France business
unit
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
Q1/16
vs.
|
Q1/16
vs.
|
($M except as
indicated)
|
|
2016
|
2015
|
2015
|
Q4/15
|
Q1/15
|
|
Sales
|
|
48,125
|
63,411
|
59,832
|
(24%)
|
(20%)
|
|
Royalties
|
|
(6,766)
|
(7,198)
|
(5,102)
|
(6%)
|
33%
|
|
Transportation
|
|
(3,713)
|
(4,275)
|
(3,011)
|
(13%)
|
23%
|
|
Operating
|
|
(14,320)
|
(15,792)
|
(10,826)
|
(9%)
|
32%
|
|
General and
administration
|
|
(4,676)
|
(4,894)
|
(5,111)
|
(4%)
|
(9%)
|
|
Other
income
|
|
-
|
-
|
31,775
|
-
|
(100%)
|
|
Current income
taxes
|
|
(34)
|
4,529
|
(14,281)
|
(101%)
|
(100%)
|
|
Fund flows from
operations
|
|
18,616
|
35,781
|
53,276
|
(48%)
|
(65%)
|
Netbacks
($/boe)
|
|
|
|
|
|
|
|
Sales
|
|
43.16
|
54.20
|
64.33
|
(20%)
|
(33%)
|
|
Royalties
|
|
(6.07)
|
(6.15)
|
(5.49)
|
(1%)
|
11%
|
|
Transportation
|
|
(3.33)
|
(3.65)
|
(3.24)
|
(9%)
|
3%
|
|
Operating
|
|
(12.84)
|
(13.50)
|
(11.64)
|
(5%)
|
10%
|
|
General and
administration
|
|
(4.19)
|
(4.18)
|
(5.49)
|
-
|
(24%)
|
|
Other
income
|
|
-
|
-
|
34.16
|
-
|
(100%)
|
|
Current income
taxes
|
|
(0.03)
|
3.87
|
(15.35)
|
(101%)
|
(100%)
|
|
Fund flows from
operations netback
|
|
16.70
|
30.59
|
57.28
|
(45%)
|
(71%)
|
Realized
prices
|
|
|
|
|
|
|
|
Crude oil
($/bbl)
|
|
43.36
|
54.88
|
64.33
|
(21%)
|
(33%)
|
|
Natural gas
($/mmbtu)
|
|
1.66
|
2.81
|
-
|
(41%)
|
100%
|
|
Total
($/boe)
|
|
43.16
|
54.20
|
64.33
|
(20%)
|
(33%)
|
Reference
prices
|
|
|
|
|
|
|
|
Dated Brent (US
$/bbl)
|
|
33.89
|
43.69
|
53.97
|
(22%)
|
(37%)
|
|
Dated Brent
($/bbl)
|
|
46.59
|
58.34
|
66.98
|
(20%)
|
(30%)
|
Sales
- Crude oil in France is priced
with reference to Dated Brent.
- Sales per boe decreased relative to all comparable periods,
consistent with a decrease in the Dated Brent reference price.
Compared to Q1 2015, the decrease in price was partially offset by
increased sales volumes, resulting in a relatively lower decrease
to sales.
Royalties
- Royalties in France relate to
two components: RCDM (levied on units of production and not subject
to changes in commodity prices) and R31 (based on a percentage of
sales).
- Royalties as a percentage of sales was 14.1% for Q1 2016, an
increase over both Q4 2015 (11.4%) and Q1 2015 (8.5%) as a result
of the impact of fixed RCDM royalties coupled with lower realized
pricing.
Transportation
- Transportation expense for Q1 2016 was lower versus Q4 2015 due
to successful vessel cost renegotiations and a lower level of
project activity at the Ambès terminal.
- Transportation expense increased year-over-year primarily due
to an unfavorable foreign exchange impact and increased sales. When
excluding the impact of foreign exchange, per unit costs decreased
by 5% as a result of ongoing cost reduction initiatives.
Operating
- Operating expense decreased in Q1 2016 versus Q4 2015 as a
result of a continued emphasis on cost reduction initiatives and
savings from service contract renegotiations resulting in lower
costs related to electricity, maintenance and labour usage. These
cost reduction initiatives more than offset the unfavorable foreign
exchange impact of a weakening Canadian dollar.
- Year-over-year, operating expenses increased on a dollar and
per boe basis. The 7% increase in production over this period
partially contributed to the increase, and, to a larger extent, the
weakening of the Canadian dollar versus the Euro resulted in
increased expense. After normalizing for the unfavorable foreign
exchange impact, per unit costs were essentially flat
year-over-year.
General and administration
- General and administration expense for Q1 2016 was 4% lower
than Q4 2015 and 9% lower than Q1 2015 as a result of cost-cutting
initiatives.
Current income taxes
- Current income taxes in France
are applied to taxable income, after eligible deductions, at a
statutory rate of 34.4% for 2016. Our France Business Unit is
expected to incur minimal current income taxes for 2016. This is
subject to change in response to commodity price fluctuations, the
timing of capital expenditures, and other eligible in-country
adjustments.
NETHERLANDS BUSINESS
UNIT
Overview
- Entered the Netherlands in
2004.
- Second largest onshore gas producer.
- Interests include 24 onshore licenses and two offshore
licenses.
- Licenses include more than 800,000 net acres of land, 95% of
which is undeveloped.
Operational review
|
|
|
|
Three Months
Ended
|
|
%
change
|
|
|
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
|
Q1/16
vs.
|
Q1/16
vs.
|
Netherlands
business unit
|
|
|
2016
|
2015
|
2015
|
|
Q4/15
|
Q1/15
|
Production
|
|
|
|
|
|
|
|
|
|
Condensate
(bbls/d)
|
|
|
114
|
110
|
63
|
|
4%
|
81%
|
|
Natural gas
(mmcf/d)
|
|
|
53.40
|
56.34
|
36.41
|
|
(5%)
|
47%
|
|
Total
(boe/d)
|
|
|
9,015
|
9,500
|
6,132
|
|
(5%)
|
47%
|
Activity
|
|
|
|
|
|
|
|
|
|
Capital expenditures
($M)
|
|
|
2,996
|
18,810
|
4,333
|
|
(84%)
|
(31%)
|
Production
- Q1 2016 production decreased 5% versus the prior quarter mainly
due to a decline in gas production from our Slootdorp-07 well.
- Year-over-year production increased 47%, primarily due to
production additions from Diever-02 and Slootdorp-06/07 wells, and
enhanced by debottlenecking at our Garijp Treatment Centre. The
Diever-02 exploration well (45% working interest), which came on an
extended production test in late October
2015, continues to produce approximately 13 mmcf/d (2,200
boe/d), net to Vermilion.
Slootdorp-06/07, which are also on extended production tests, are
currently producing approximately 23 mmcf/d (3,900 boe/d) net to
Vermilion, combined.
- Production in the Netherlands
is actively managed to optimize facility use and regulate
declines.
Activity review
- Production and reservoir testing on our Slootdorp-06/07 wells
will continue into Q2 2016, when permanent facility installation
should be complete.
- Planning activities for the drilling of Langezwaag-03 (42%
working interest) and Andel-6ST (45% working interest) were carried
out during the quarter. We expect to drill these wells in Q3 2016,
and if successful, we expect to have the wells on production prior
to year end.
- In addition to the two (0.9 net) well drilling program, we are
also planning permitting and optimization activities in 2016.
Financial review
|
|
|
Three Months
Ended
|
%
change
|
Netherlands
business unit
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
Q1/16
vs.
|
Q1/16
vs.
|
($M except as
indicated)
|
|
2016
|
2015
|
2015
|
Q4/15
|
Q1/15
|
|
Sales
|
|
27,286
|
37,243
|
26,818
|
(27%)
|
2%
|
|
Royalties
|
|
(460)
|
(224)
|
(926)
|
105%
|
(50%)
|
|
Operating
|
|
(5,976)
|
(6,263)
|
(5,826)
|
(5%)
|
3%
|
|
General and
administration
|
|
(773)
|
(813)
|
(737)
|
(5%)
|
5%
|
|
Current income
taxes
|
|
(2,200)
|
(2,930)
|
(2,388)
|
(25%)
|
(8%)
|
|
Fund flows from
operations
|
|
17,877
|
27,013
|
16,941
|
(34%)
|
6%
|
Netbacks
($/boe)
|
|
|
|
|
|
|
|
Sales
|
|
33.26
|
42.61
|
48.60
|
(22%)
|
(32%)
|
|
Royalties
|
|
(0.56)
|
(0.26)
|
(1.68)
|
115%
|
(67%)
|
|
Operating
|
|
(7.28)
|
(7.17)
|
(10.56)
|
2%
|
(31%)
|
|
General and
administration
|
|
(0.94)
|
(0.93)
|
(1.34)
|
1%
|
(30%)
|
|
Current income
taxes
|
|
(2.68)
|
(3.35)
|
(4.33)
|
(20%)
|
(38%)
|
|
Fund flows from
operations netback
|
|
21.80
|
30.90
|
30.69
|
(29%)
|
(29%)
|
Realized
prices
|
|
|
|
|
|
|
|
Condensate
($/bbl)
|
|
32.24
|
48.30
|
52.93
|
(33%)
|
(39%)
|
|
Natural gas
($/mmbtu)
|
|
5.55
|
7.09
|
8.09
|
(22%)
|
(31%)
|
|
Total
($/boe)
|
|
33.26
|
42.61
|
48.60
|
(22%)
|
(32%)
|
Reference
prices
|
|
|
|
|
|
|
|
TTF
($/mmbtu)
|
|
5.70
|
7.28
|
8.70
|
(22%)
|
(34%)
|
|
TTF
(€/mmbtu)
|
|
3.76
|
4.98
|
6.23
|
(24%)
|
(40%)
|
Sales
- The price of our natural gas in the
Netherlands is based on the TTF day-ahead index. GasTerra, a
state owned entity, continues to purchase all of the natural gas we
produce in the Netherlands.
- Sales per boe decreased versus all comparable periods,
consistent with a decrease in the TTF reference price. Compared to
Q1 2015, the decrease in price was entirely offset by increased
production.
Royalties
- In the Netherlands, we pay
overriding royalties on certain wells associated with an
acquisition completed by the
Netherlands business unit in October
2013. As such, fluctuations in royalty expense in the
periods presented relate to the amount of production from those
wells subject to overriding royalties.
Transportation
- Our production in the
Netherlands is not subject to transportation expense as gas
is sold at the plant gate.
Operating
- Operating expense decreased versus Q4 2015 on a dollar basis
and increased slightly on a per unit basis. The dollar decrease was
achieved as reduced maintenance activity levels more than offset a
weaker Canadian dollar versus the Euro.
- Year-over-year, operating expense increases have been limited
to 3% while growing production by 47%, resulting in a 31% per unit
decrease in costs. When normalizing for the impact of the weaker
Canadian dollar relative to the Euro for this period, absolute
costs have decreased by 6% while per unit costs have decreased by
36% due to cost reduction initiatives being achieved while
executing on significant production additions.
General and administration
- Variances in general and administration expense generally
relate to timing of expenditures, including the timing of
allocations from Vermilion's
Corporate segment.
Current income taxes
- Current income taxes in the
Netherlands apply to taxable income after eligible
deductions at an implied tax rate of approximately 46%. For 2016,
the effective rate on current taxes is expected to be between
approximately 10% and 12% of pre-tax fund flows from operations.
This rate is subject to change in response to commodity price
fluctuations, the timing of capital expenditures, and other
eligible in-country adjustments.
- Current income taxes in Q1 2016 were lower compared to Q4 2015
as decreased revenues were offset by additional tax deductions
taken for depletion in Q4 2015.
GERMANY BUSINESS
UNIT
Overview
- Vermilion entered Germany in February
2014.
- Hold a 25% interest in a four partner consortium. Associated
assets include four gas producing fields spanning 11 production
licenses as well as an exploration license in surrounding fields.
Total license area comprises 204,000 gross acres, of which 85% is
in the exploration license.
- Entered into a farm-in agreement in July
2015 that provides Vermilion with participating interest in 18
onshore exploration licenses in northwest Germany, comprising approximately 850,000 net
undeveloped acres of oil and natural gas rights. Vermilion will assume operatorship for 11 of
the 18 licenses during the exploration phase.
- Awarded 110,000 net acres (100% working interest) across two
exploration licenses in Lower Saxony in 2016.
Operational review
|
|
|
|
Three Months
Ended
|
|
%
change
|
|
|
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
|
Q1/16
vs.
|
Q1/16
vs.
|
Germany business
unit
|
|
|
2016
|
2015
|
2015
|
|
Q4/15
|
Q1/15
|
Production
|
|
|
|
|
|
|
|
|
|
Natural gas
(mmcf/d)
|
|
|
15.96
|
16.17
|
16.80
|
|
(1%)
|
(5%)
|
|
Total
(boe/d)
|
|
|
2,660
|
2,695
|
2,801
|
|
(1%)
|
(5%)
|
Activity
|
|
|
|
|
|
|
|
|
|
Capital expenditures
($M)
|
|
|
539
|
(441)
|
968
|
|
(222%)
|
(44%)
|
Production
- Q1 2016 production was relatively unchanged versus the prior
quarter. Year-over-year production decreased 5%.
Activity review
- In 2016, the majority of activity will be associated with
permitting and pre-drill activities for Burgmoor Z5 and two farm-in
prospects, which are planned for 2017. In addition, we will
continue our ongoing analysis of the proprietary geologic data
associated with the farm-in assets.
Financial review
|
|
|
Three Months
Ended
|
|
%
change
|
Germany business
unit
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
|
Q1/16
vs.
|
Q1/16
vs.
|
($M except as
indicated)
|
|
2016
|
2015
|
2015
|
|
Q4/15
|
Q1/15
|
|
Sales
|
|
7,692
|
9,840
|
11,395
|
|
(22%)
|
(32%)
|
|
Royalties
|
|
(867)
|
(1,166)
|
(1,598)
|
|
(26%)
|
(46%)
|
|
Transportation
|
|
(887)
|
(508)
|
(894)
|
|
75%
|
(1%)
|
|
Operating
|
|
(2,593)
|
(4,788)
|
(1,999)
|
|
(46%)
|
30%
|
|
General and
administration
|
|
(2,428)
|
(3,032)
|
(1,608)
|
|
(20%)
|
51%
|
|
Fund flows from
operations
|
|
917
|
346
|
5,296
|
|
165%
|
(83%)
|
Netbacks
($/boe)
|
|
|
|
|
|
|
|
|
Sales
|
|
31.78
|
39.68
|
45.21
|
|
(20%)
|
(30%)
|
|
Royalties
|
|
(3.58)
|
(4.70)
|
(6.34)
|
|
(24%)
|
(44%)
|
|
Transportation
|
|
(3.67)
|
(2.05)
|
(3.55)
|
|
79%
|
3%
|
|
Operating
|
|
(10.71)
|
(19.31)
|
(7.93)
|
|
(45%)
|
35%
|
|
General and
administration
|
|
(10.03)
|
(12.22)
|
(6.38)
|
|
(18%)
|
57%
|
|
Fund flows from
operations netback
|
|
3.79
|
1.40
|
21.01
|
|
171%
|
(82%)
|
Reference
prices
|
|
|
|
|
|
|
|
|
TTF
($/mmbtu)
|
|
5.70
|
7.28
|
8.70
|
|
(22%)
|
(34%)
|
|
TTF
(€/mmbtu)
|
|
3.76
|
4.98
|
6.23
|
|
(24%)
|
(40%)
|
Sales
- The price of our natural gas in Germany is based on the TTF month-ahead
index.
- Sales per boe decreased versus all comparable periods,
consistent with a decrease in the TTF reference price.
Royalties
- Our production in Germany is
subject to state and private royalties on sales after certain
eligible deductions.
- Q1 2016 royalties as a percentage of sales of 11.3% was
consistent with the Q4 2015 rate of 11.9% and lower than the Q1
2015 rate of 14.0%. The reduced rate year-over-year is a result of
a reduction in state royalty rates.
Transportation
- Transportation expense in Germany relates to costs incurred to deliver
natural gas from the processing facility to the customer.
- Q1 2016 transportation expense increased on an absolute dollar
and per unit basis versus Q4 2015 due to a favourable annual
adjustment recorded in Q4 2015.
- Transportation costs for the quarter relative to Q1 2015 are
consistent on an absolute and per unit basis.
Operating
- Operating expenses for Germany
primarily relate to tariffs charged for facility operations and gas
processing.
- Q1 2016 operating expense was lower than Q4 2015 due in equal
parts to charges for prior period maintenance expenditures and the
inclusion of a full year gas processing tariff adjustment, both
recorded in Q4 2015.
- Operating expense increased in Q1 2016 from Q1 2015 on an
absolute and per unit basis due to increased maintenance
activity.
General and administration
- Q1 2016 general and administration expenses were lower than Q4
2015 and higher than Q1 2015. The reduction from Q4 2015 is due to
timing of expenditures, while the increase from Q1 2015 is due to
higher staffing levels and office costs incurred to support our
farm-in agreement.
Current income taxes
- Current income taxes in Germany apply to taxable income after eligible
deductions at a statutory tax rate of approximately 24.2%. As a
function of tax pools in Germany,
Vermilion does not presently pay
taxes in Germany.
IRELAND BUSINESS
UNIT
Overview
- 18.5% non-operating interest in the offshore Corrib gas field
located approximately 83 km off the northwest coast of Ireland.
- Project comprises six offshore wells, offshore and onshore
sales and transportation pipeline segments as well as a natural gas
processing facility.
- Corrib is expected to produce approximately 58 mmcf/d (9,700
boe/d) net to Vermilion at peak
production rates.
Operational and financial review
|
|
|
|
|
Three Months
Ended
|
Ireland business
unit
|
|
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
($M except as
indicated)
|
|
|
|
2016
|
2015
|
2015
|
Production
|
|
|
|
|
|
|
|
Natural gas
(mmcf/d)
|
|
|
|
33.90
|
0.12
|
-
|
|
Total
(boe/d)
|
|
|
|
5,650
|
20
|
-
|
Activity
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
|
3,076
|
12,493
|
12,955
|
Financial
Results
|
|
|
|
|
|
|
|
Sales
|
|
|
|
17,004
|
57
|
-
|
|
Transportation
|
|
|
|
(1,639)
|
(1,580)
|
(1,693)
|
|
Operating
|
|
|
|
(3,626)
|
(15)
|
-
|
|
General and
administration
|
|
|
|
(1,188)
|
(714)
|
(512)
|
|
Fund flows from
operations
|
|
|
|
10,551
|
(2,252)
|
(2,205)
|
Netbacks
($/boe)
|
|
|
|
|
|
|
|
Sales
|
|
|
|
33.07
|
-
|
-
|
|
Transportation
|
|
|
|
(3.19)
|
-
|
-
|
|
Operating
|
|
|
|
(7.05)
|
-
|
-
|
|
General and
administration
|
|
|
|
(2.31)
|
-
|
-
|
|
Fund flows from
operations netback
|
|
|
|
20.52
|
-
|
-
|
Reference
prices
|
|
|
|
|
|
|
|
NBP
($/mmbtu)
|
|
|
|
5.97
|
7.41
|
9.01
|
|
NBP
(€/mmbtu)
|
|
|
|
3.94
|
5.07
|
6.45
|
Production
- Natural gas began to flow from our Corrib gas project on
December 30, 2015 and to date, well
performance and facility runtimes have exceeded expectations.
- Production averaged 34 mmcf/d (5,650 boe/d) net to Vermilion, during Q1 2016.
- Following the completion of previously planned recertification
activities associated with the third party gas distribution
pipeline network, production volumes at Corrib are expected to rise
to an estimated peak rate of approximately 58 mmcf/d (9,700 boe/d),
net to Vermilion.
Activity review
- The export gas sales pipeline underwent intelligent pigging in
Q1 2016. As part of the recertification process, confirmatory
inspection digs on the export sales pipeline are planned for Q2
2016.
- Some subsea inspections, maintenance and repairs on the subsea
systems are scheduled to take place in Q2 2016.
- Five of the six wells are capable of producing, with the
remaining well to be brought online in the third quarter of 2016
following the conclusion of our offshore work program to lay a
pipeline to the sixth well.
Sales
- The price of our natural gas in Ireland is based on the NBP index.
- Q1 2016 represented the first full quarter of sales from
Corrib.
Royalties
- Our production in Ireland is
not subject to royalties.
Transportation
- Transportation expense in Ireland relates to payments under a ship or
pay agreement related to the Corrib project.
- Q1 2016 transportation expense is slightly higher than Q4 2015
due to foreign exchange. The expense is lower than Q1 2015 due to
lower tariffs for the current gas year, which began in October 2015, under the ship or pay
agreement.
Operating
- We expect per unit costs to decrease as production ramps
up.
General and administration
- General and administration expense increased
quarter-over-quarter and year-over-year due to increased corporate
allocations as a result of achieving our first full quarter of
production.
AUSTRALIA BUSINESS
UNIT
Overview
- Entered Australia in
2005.
- Hold a 100% operated working interest in the Wandoo field,
located approximately 80 km offshore on the northwest shelf of
Australia.
- Production is operated from two off-shore platforms, and
originates from 18 well bores and four lateral sidetrack
wells.
- Wells that utilize horizontal legs (ranging in length from 500
to 3,000 plus metres) are located 600 metres below the seabed in
approximately 55 metres of water depth.
Operational review
|
|
|
Three Months
Ended
|
|
%
change
|
|
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
|
Q1/16
vs.
|
Q1/16
vs.
|
Australia business
unit
|
|
2016
|
2015
|
2015
|
|
Q4/15
|
Q1/15
|
Production
|
|
|
|
|
|
|
|
|
Crude oil
(bbls/d)
|
|
6,180
|
7,824
|
5,672
|
|
(21%)
|
9%
|
Inventory
(mbbls)
|
|
|
|
|
|
|
|
|
Opening crude oil
inventory
|
|
75
|
172
|
37
|
|
|
|
|
Crude oil
production
|
|
562
|
720
|
511
|
|
|
|
|
Crude oil
sales
|
|
(424)
|
(817)
|
(230)
|
|
|
|
|
Closing crude oil
inventory
|
|
213
|
75
|
318
|
|
|
|
Activity
|
|
|
|
|
|
|
|
|
Capital expenditures
($M)
|
|
7,827
|
40,852
|
6,455
|
|
(81%)
|
21%
|
|
Gross wells
drilled
|
|
-
|
1.00
|
-
|
|
|
|
|
Net wells
drilled
|
|
-
|
1.00
|
-
|
|
|
|
Production
- Q1 2016 quarterly production decreased 21% quarter-over-quarter
and increased 9% year-over-year.
- Production volumes are managed within corporate targets while
meeting customer demands and the requirements of long-term supply
agreements.
- We continue to plan for long-term production levels of between
6,000 and 8,000 bbls/d.
Activity review
- In Q1 2016, efforts were largely focused on facilities
enhancement, including work relating to platform life extension,
and preparation activities in advance of our upcoming drilling
program.
- We plan to drill a two-well sidetrack program in Q2 2016.
Financial review
|
|
|
Three Months
Ended
|
|
%
change
|
Australia business
unit
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
|
Q1/16
vs.
|
Q1/16
vs.
|
($M except as
indicated)
|
|
2016
|
2015
|
2015
|
|
Q4/15
|
Q1/15
|
|
Sales
|
|
19,935
|
47,952
|
19,284
|
|
(58%)
|
3%
|
|
Operating
|
|
(7,491)
|
(13,941)
|
(5,886)
|
|
(46%)
|
27%
|
|
General and
administration
|
|
(1,325)
|
(1,768)
|
(1,454)
|
|
(25%)
|
(9%)
|
|
PRRT
|
|
(128)
|
(1,054)
|
(2,354)
|
|
(88%)
|
(95%)
|
|
Corporate income
taxes
|
|
(777)
|
1,201
|
(577)
|
|
(165%)
|
35%
|
|
Fund flows from
operations
|
|
10,214
|
32,390
|
9,013
|
|
(68%)
|
13%
|
Netbacks
($/boe)
|
|
|
|
|
|
|
|
|
Sales
|
|
46.93
|
58.74
|
83.80
|
|
(20%)
|
(44%)
|
|
Operating
|
|
(17.63)
|
(17.08)
|
(25.58)
|
|
3%
|
(31%)
|
|
General and
administration
|
|
(3.12)
|
(2.17)
|
(6.32)
|
|
44%
|
(51%)
|
|
PRRT
|
|
(0.30)
|
(1.29)
|
(10.23)
|
|
(77%)
|
(97%)
|
|
Corporate income
taxes
|
|
(1.83)
|
1.47
|
(2.51)
|
|
(224%)
|
(27%)
|
|
Fund flows from
operations netback
|
|
24.05
|
39.67
|
39.16
|
|
(39%)
|
(39%)
|
Reference
prices
|
|
|
|
|
|
|
|
|
Dated Brent (US
$/bbl)
|
|
33.89
|
43.69
|
53.97
|
|
(22%)
|
(37%)
|
|
Dated Brent
($/bbl)
|
|
46.59
|
58.34
|
66.98
|
|
(20%)
|
(30%)
|
Sales
- Crude oil in Australia is
priced with reference to Dated Brent.
- Sales per boe decreased versus all comparable periods,
consistent with a decrease in the Dated Brent reference price.
Compared to Q4 2015, the decrease in price was combined with lower
sales volumes, resulting in a larger decrease to sales. Compared to
Q1 2015, the decrease in price was offset by higher sales volumes,
resulting in relatively consistent sales.
Royalties and transportation
- Our production in Australia is
not subject to royalties or transportation expense as crude oil is
sold directly at the Wandoo B platform.
Operating
- Operating expense on a dollar basis decreased in Q1 2016 from
Q4 2015 primarily due to a decrease in sold volumes. After
adjusting for inventory, per unit costs were in-line with Q4
2015.
- Year-over-year, operating expense increased by 27%, however a
significant increase in sales volumes resulted in per unit costs
decreasing by 31%. The decrease in per unit costs is driven by a
continued focus on cost reduction initiatives, including reduced
helicopter and vessel costs.
General and administration
- Q1 2016 general and administration costs decreased versus Q4
2015 and Q1 2015 due to cost-cutting initiatives.
PRRT and corporate income taxes
- In Australia, current income
taxes include both PRRT and corporate income taxes. PRRT is a
profit based tax applied at a rate of 40% on sales less eligible
expenditures, including operating expenses and capital
expenditures. Corporate income taxes are applied at a rate of 30%
on taxable income after eligible deductions, which include
PRRT.
- For 2016, the effective tax rate for corporate income tax is
expected to be between approximately 6% to 8% of pre-tax fund flows
from operations and PRRT is expected to be between approximately 0%
to 2% of pre-tax fund flows from operations. This is subject to
change in response to commodity price fluctuations, the timing of
capital expenditures and other eligible in-country
adjustments.
- Q1 2016 combined corporate income taxes and PRRT were higher
compared to Q4 2015, as decreased revenues were offset by
additional tax deductions taken for corporate income tax depletion
in Q4 2015.
- Q1 2016 combined corporate income taxes and PRRT were lower
compared to Q1 2015 due to the recognition of increased capital
spending deductions for PRRT purposes in Q1 2016.
UNITED STATES BUSINESS
UNIT
Overview
- Entered the United States in
September 2014.
- Interests include approximately 96,200 acres of land (98%
undeveloped) in the Powder River Basin of northeastern Wyoming.
- Tight oil development targeting the Turner Sand at a depth of
approximately 1,500 metres.
Operational and financial review
|
|
|
Three Months
Ended
|
%
change
|
United States
business unit
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
Q1/16
vs.
|
Q1/16
vs.
|
($M except as
indicated)
|
|
2016
|
2015
|
2015
|
Q4/15
|
Q1/15
|
Production
|
|
|
|
|
|
|
|
Crude oil
(bbls/d)
|
|
368
|
420
|
153
|
(12%)
|
141%
|
|
NGLs
(bbls/d)
|
|
39
|
29
|
-
|
34%
|
100%
|
|
Natural gas
(mmcf/d)
|
|
0.26
|
0.20
|
-
|
30%
|
100%
|
|
Total
(boe/d)
|
|
450
|
483
|
153
|
(7%)
|
194%
|
Activity
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
5,101
|
5,643
|
637
|
(10%)
|
701%
|
|
Acquisitions
|
|
115
|
(21)
|
-
|
|
|
|
Gross wells
drilled
|
|
-
|
2.00
|
-
|
|
|
|
Net wells
drilled
|
|
-
|
2.00
|
-
|
|
|
Financial
Results
|
|
|
|
|
|
|
|
Sales
|
|
1,233
|
1,864
|
672
|
(34%)
|
83%
|
|
Royalties
|
|
(370)
|
(551)
|
(206)
|
(33%)
|
80%
|
|
Operating
|
|
(279)
|
(271)
|
(215)
|
3%
|
30%
|
|
General and
administration
|
|
(1,132)
|
(897)
|
(1,080)
|
26%
|
5%
|
|
Fund flows from
operations
|
|
(548)
|
145
|
(829)
|
(478%)
|
(34%)
|
Netbacks
($/boe)
|
|
|
|
|
|
|
|
Sales
|
|
30.10
|
41.94
|
48.79
|
(28%)
|
(38%)
|
|
Royalties
|
|
(9.03)
|
(12.40)
|
(14.98)
|
(27%)
|
(40%)
|
|
Operating
|
|
(6.82)
|
(6.11)
|
(15.61)
|
12%
|
(56%)
|
|
General and
administration
|
|
(27.65)
|
(20.18)
|
(78.41)
|
37%
|
(65%)
|
|
Fund flows from
operations netback
|
|
(13.40)
|
3.25
|
(60.21)
|
(512%)
|
(78%)
|
Realized
prices
|
|
|
|
|
|
|
|
Crude oil
($/bbl)
|
|
35.80
|
47.59
|
48.79
|
(25%)
|
(27%)
|
|
NGLs
($/bbl)
|
|
4.81
|
5.13
|
-
|
(6%)
|
100%
|
|
Natural gas
($/mmbtu)
|
|
0.67
|
0.52
|
-
|
29%
|
100%
|
|
Total
($/boe)
|
|
30.10
|
41.94
|
48.79
|
(28%)
|
(38%)
|
Reference
prices
|
|
|
|
|
|
|
|
WTI (US
$/bbl)
|
|
33.45
|
42.18
|
48.63
|
(21%)
|
(31%)
|
|
WTI
($/bbl)
|
|
45.99
|
56.32
|
60.35
|
(18%)
|
(24%)
|
|
Henry Hub (US
$/mmbtu)
|
|
2.09
|
2.27
|
2.98
|
(8%)
|
(30%)
|
|
Henry Hub
($/mmbtu)
|
|
2.87
|
3.03
|
3.70
|
(5%)
|
(22%)
|
Production
- Q1 2016 production was relatively unchanged versus the prior
quarter and nearly triple that of Q1 2015 due to production from
our Seedy Draw well, which was drilled and completed in 2015.
Activity review
- In Q1 2016, we completed the two (2.0 net) wells drilled in the
East Finn prospect during the prior quarter. One of the wells was
placed on production at the end of Q1 2016. The other well
experienced a mechanical failure during the completion operation
which resulted in only 8% of the horizontal section being open to
production. That well was placed on production subsequent to the
quarter.
Sales
- The price of crude oil in the United
States is directly linked to WTI, subject to market
conditions in the United
States.
Royalties
- Our production in the United
States is subject to federal and private royalties,
severance tax, and ad valorem tax.
- Royalties as a percentage of sales for Q1 2016 of approximately
30.0% was consistent with the rate for Q4 2015 (29.6%) and Q1 2015
(30.7%).
Operating
- Operating expense increased on an absolute dollar and per unit
basis in Q1 2016 from Q4 2015. The increase is primarily due to the
weakening of the Canadian dollar relative to the US dollar. On a
per unit basis, costs are flat once adjusted for the impact of
foreign exchange.
- Year-over-year the increase in operating expense has been held
at 30% while production has increased 194%. As a result, per unit
costs have decreased by 56%.
General and administration
- General and administration expenses increased in Q1 2016 by 26%
from Q4 2015 and 5% from Q1 2015 due to timing of
expenditures.
CORPORATE
Overview
- Our Corporate segment includes costs related to our global
hedging program, financing expenses, and general and administration
expenses that are primarily incurred in Canada and are not directly related to the
operations of our business units.
Financial review
|
|
|
|
Three Months
Ended
|
CORPORATE
|
|
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
($M)
|
|
|
|
2016
|
2015
|
2015
|
General and
administration recovery
|
|
|
|
421
|
3,356
|
957
|
Current income
taxes
|
|
|
|
(149)
|
313
|
(377)
|
Interest
expense
|
|
|
|
(14,750)
|
(16,584)
|
(13,298)
|
Realized gain on
derivatives
|
|
|
|
28,423
|
21,164
|
6,257
|
Realized foreign
exchange (loss) gain
|
|
|
|
(652)
|
(252)
|
3,306
|
Realized other
income
|
|
|
|
105
|
243
|
222
|
Fund flows from
operations
|
|
|
|
13,398
|
8,240
|
(2,933)
|
General and administration
- The decrease in the recovery of general and administration
costs for Q1 2016 versus Q4 2015 is due to the timing of
expenditures and salary allocations to the various business unit
segments.
Current income taxes
- Taxes in our corporate segment relate to holding companies that
pay current taxes in foreign jurisdictions.
Interest expense
- The decrease in interest expense versus Q4 2015 is primarily
due to the retiring of our 6.5% senior unsecured notes in February
using funds from our revolving credit facility, which has a
marginal rate of 3.3%.
- The increase in interest expense for Q1 2016 versus Q1 2015 is
due to increased average 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 (loss)
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) up to
50% of net of royalty volumes through a portfolio of forward
collars, swaps, and physical fixed price arrangements. We currently
have European gas contracts up to 36 months forward as an exception
to our typical horizon.
- We believe that our hedging philosophy and approach increases
the stability of revenues, cash flows, and future dividends while
also assisting us in the execution of our capital and development
plans.
- The realized gain in Q1 2016 related primarily to amounts
received on our crude oil and European natural gas hedges.
- A listing of derivative positions as at March 31, 2016 is included in "Supplemental Table
2" of this MD&A.
FINANCIAL PERFORMANCE REVIEW
|
|
Three Months
Ended
|
|
|
Mar
31,
|
Dec
31,
|
Sep
30,
|
Jun
30,
|
Mar
31,
|
Dec
31,
|
Sep
30,
|
Jun
30,
|
($M except per
share)
|
2016
|
2015
|
2015
|
2015
|
2015
|
2014
|
2014
|
2014
|
Petroleum and natural
gas sales
|
177,385
|
234,319
|
245,051
|
264,331
|
195,885
|
306,073
|
344,688
|
387,684
|
Net (loss)
earnings
|
(85,848)
|
(142,080)
|
(83,310)
|
6,813
|
1,275
|
58,642
|
53,903
|
53,993
|
Net (loss) earnings
per share
|
|
|
|
|
|
|
|
|
|
Basic
|
(0.76)
|
(1.28)
|
(0.76)
|
0.06
|
0.01
|
0.55
|
0.50
|
0.51
|
|
Diluted
|
(0.76)
|
(1.28)
|
(0.76)
|
0.06
|
0.01
|
0.54
|
0.50
|
0.50
|
The following table shows a reconciliation of the change in net
(loss) earnings:
($M)
|
|
|
|
Q1/16 vs.
Q4/15
|
|
Q1/16 vs.
Q1/15
|
Net (loss)
earnings - Comparative period
|
|
|
|
(142,080)
|
|
1,275
|
Changes
in:
|
|
|
|
|
|
|
Fund flows from
operations
|
|
|
|
(42,774)
|
|
(27,128)
|
Equity based
compensation
|
|
|
|
696
|
|
(1,797)
|
Unrealized gain or
loss on derivative instruments
|
|
|
|
(18,339)
|
|
29,024
|
Unrealized foreign
exchange gain or loss
|
|
|
|
7,927
|
|
6,415
|
Unrealized other
expense or income
|
|
|
|
147
|
|
174
|
Accretion
|
|
|
|
215
|
|
(434)
|
Depletion and
depreciation
|
|
|
|
(17,986)
|
|
(34,841)
|
Deferred
tax
|
|
|
|
9,485
|
|
(43,774)
|
Impairment
|
|
|
|
116,861
|
|
(14,762)
|
Net loss - Current
period
|
|
|
|
(85,848)
|
|
(85,848)
|
The fluctuations in net (loss) earnings from period-to-period
are caused by changes in both cash and non-cash based income and
charges. Cash based items are reflected in fund flows from
operations and include: sales, royalties, operating expenses,
transportation, general and administration expense, current tax
expense, interest expense, realized gains and losses on derivative
instruments, and realized foreign exchange gains and losses.
Non-cash items include: equity based compensation expense,
unrealized gains and losses on derivative instruments, unrealized
foreign exchange gains and losses, accretion, depletion and
depreciation expense, and deferred taxes. In addition,
non-cash items may also include amounts resulting from acquisitions
or charges resulting from impairment or impairment recoveries.
Equity based compensation
Equity based compensation expense relates primarily to non-cash
compensation expense attributable to long-term incentives granted
to directors, officers, and employees under the Vermilion Incentive
Plan ("VIP"). The expense is recognized over the vesting
period based on the grant date fair value of awards, adjusted for
the ultimate number of awards that actually vest as determined by
the Company's achievement of performance conditions.
Equity based compensation in Q1 2016 was relatively consistent
with Q4 2015. The increase of $1.8
million as compared to Q1 2015 is due to the settlement of
the employee bonus plan with equity in Q1 2016.
Unrealized gain or loss on derivative
instruments
Unrealized gain or loss on derivative instruments arise as a result
of changes in forecasted future commodity prices. As
Vermilion uses derivative instruments to manage the commodity price
exposure of our future crude oil and natural gas production, we
will normally recognize unrealized gains on derivative instruments
when forecasted future commodity prices decline and vice-versa.
For the three months ended March
31 2016, we recognized an unrealized gain on derivative
instruments of $9.1 million, relating
primarily to a gain on our global natural gas hedges, partially
offset by a decrease in the value of crude oil and interest rate
hedges. As at March 31, 2016,
we have a net derivative asset position of $77.4 million.
Unrealized foreign exchange gain or loss
As a result of Vermilion's
international operations, Vermilion conducts business in currencies
other than the Canadian dollar and has monetary assets and
liabilities (including cash, receivables, payables, long-term debt,
derivative assets and liabilities, and intercompany loans)
denominated in such currencies. Vermilion's exposure to foreign currencies
includes the US dollar, the Euro, and the Australian Dollar.
Unrealized foreign exchange gains and losses are the result of
translating monetary assets and liabilities held in non-functional
currencies to the respective functional currencies of Vermilion and its subsidiaries.
Unrealized foreign exchange primarily results from the translation
of Euro denominated financial assets and US dollar denominated
financial liabilities. As such, an appreciation in the Euro
against the Canadian dollar will result in an unrealized foreign
exchange gain while an appreciation in the US dollar against the
Canadian dollar will result in an unrealized foreign exchange loss
(and vice-versa).
For the three months ended March 31,
2016, the Canadian dollar strengthened more significantly
against the US dollar than the Euro, resulting in an unrealized
foreign exchange gain of $1.6
million.
Accretion
Fluctuations in accretion expense are primarily the result of
changes in discount rates applicable to the balance of asset
retirement obligations and additions resulting from drilling and
acquisitions.
Q1 2016 accretion expense was relatively consistent with all
comparative periods.
Depletion and depreciation
Fluctuations in depletion and depreciation expense are primarily
the result of changes in produced crude oil and natural gas
volumes.
Depletion and depreciation on a per boe basis for Q1 2016 of
$21.65 was higher as compared to
$18.88 in Q4 2015. The increase
quarter-over-quarter is primarily due to a full quarter of Corrib
production in Q1 2016. Depletion and depreciation on a per boe
basis for Q1 2016 remained relatively consistent with the
$21.90 in Q1 2015 as the impact of a
full quarter of Corrib production was offset with higher production
from natural gas properties in Canada.
Deferred tax
Deferred tax expense (recovery) arises primarily as a result of
changes in the accounting basis and tax basis for capital assets
and asset retirement obligations and changes in available tax
losses. The deferred tax expense for Q1 2016 largely pertains
to the de-recognition of certain deferred tax assets.
Impairment
For the three months ended March 31,
2016, Vermilion recorded a
non-cash impairment charge of $14.8
million in Ireland as a
result of a decline in the price forecast for European natural
gas.
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), issue equity,
or by reducing some or all categories of expenditures to ensure
that total expenditures do not exceed available funds.
To ensure that we maintain a conservative balance sheet, we
monitor the ratio of net debt to fund flows from operations and
typically strive to maintain an internally targeted ratio of
approximately 1.0 to 1.5 in a normalized commodity price
environment. Where prices trend higher, we may target a lower
ratio and conversely, in a lower commodity price environment, the
acceptable ratio may be higher. At times, we will use our
balance sheet to finance acquisitions and, in these situations, we
are prepared to accept a higher ratio in the short term but will
implement a strategy to reduce the ratio to acceptable levels
within a reasonable period of time, usually considered to be no
more than 12 to 24 months. This plan could potentially
include an increase in hedging activities, a reduction in capital
expenditures, an issuance of equity or the utilization of excess
fund flows from operations to reduce outstanding indebtedness.
In the current low commodity price environment, Vermilion's net debt to fund flows ratio is
expected to be higher than the internally targeted ratio.
During this period, Vermilion will
remain focused on maintaining a strong balance sheet by aligning
capital expenditures within forecasted fund flows from operations,
which is continually monitored for revised forward price estimates,
as well as by hedging additional European natural gas volumes to
maintain a diversified commodity portfolio.
Long-term debt
Our long-term debt as at March 31,
2016 consists entirely of borrowings against our revolving
credit facility. We redeemed the senior unsecured notes that
came due on February 10, 2016 using
funds drawn against the revolving credit facility. Following
the redemption, all of Vermilion's
debt is now classified as senior debt pursuant to the terms of the
revolving credit facility. As a result, Vermilion requested and received amendments
from its lending syndicate to eliminate the consolidated total
senior debt to consolidated EBITDA financial covenant and increase
the ratio of consolidated total senior debt to total capitalization
financial covenant from 50% to 55%. The revolving credit
facility limit of $2.0 billion
remains unchanged. Vermilion
was in compliance with all covenants as of March 31, 2016 and expects to remain in
compliance based on 2016 commodity strip pricing as of May 5, 2016.
The applicable annual interest rates and the balances recognized
on our balance sheet are as follows:
|
|
|
|
Annual Interest
Rate
|
|
As
at
|
|
|
|
|
Mar
31,
|
Dec
31,
|
|
Mar
31,
|
Dec
31,
|
($M)
|
|
|
|
2016
|
2015
|
|
2016
|
2015
|
Revolving credit
facility
|
|
|
|
3.3%
|
3.1%
|
|
1,429,988
|
1,162,998
|
Senior unsecured
notes
|
|
|
|
6.5%
|
6.5%
|
|
-
|
224,901
|
Long-term
debt
|
|
|
|
3.5%
|
3.7%
|
|
1,429,988
|
1,387,899
|
Revolving Credit Facility
The following table outlines the current terms of our revolving
credit facility:
|
|
|
|
|
|
As
at
|
|
|
|
|
|
|
Mar
31,
|
Dec
31,
|
|
|
|
|
|
|
2016
|
2015
|
Total facility
amount
|
|
|
|
|
|
$2.0
billion
|
$2.0
billion
|
Amount
drawn
|
|
|
|
|
|
$1.4
billion
|
$1.2
billion
|
Letters of credit
outstanding
|
|
|
|
|
|
$24.7
million
|
$25.2
million
|
Facility maturity
date
|
|
|
|
|
|
31-May-19
|
31-May-19
|
In addition, the revolving credit facility was subject to the
following covenants:
|
|
|
As
at
|
|
|
|
Mar
31,
|
Dec
31,
|
Financial
covenant
|
Limit
|
|
2016
|
2015
|
Consolidated total
debt to consolidated EBITDA
|
4.0
|
|
2.47
|
2.23
|
Consolidated total
senior debt to consolidated EBITDA
|
3.0
|
|
2.42
|
1.83
|
Consolidated total
senior debt to total capitalization
|
50%
|
|
45%
|
36%
|
Our covenants include financial measures defined within our
revolving credit facility agreement that are not defined under
IFRS. These financial measures are defined by our revolving
credit facility agreement as follows:
- Consolidated total debt: Includes all amounts classified as
"Long-term debt", "Current portion of long-term debt", and "Finance
lease obligation" on our balance sheet.
- Consolidated total senior debt: Defined as consolidated total
debt excluding unsecured and subordinated debt.
- Consolidated EBITDA: Defined as consolidated net earnings
before interest, income taxes, depreciation, accretion and certain
other non-cash items.
- Total capitalization: Includes all amounts on our balance sheet
classified as "Shareholders' equity" plus consolidated total debt
as defined above.
Net debt
Net debt is reconciled to long-term debt, as follows:
|
|
|
As
at
|
|
|
|
Mar
31,
|
Dec
31,
|
($M)
|
|
|
2016
|
2015
|
Long-term
debt
|
|
|
1,429,988
|
1,162,998
|
Current liabilities
(1)
|
|
|
221,225
|
503,731
|
Current
assets
|
|
|
(284,150)
|
(284,778)
|
Net debt
|
|
|
1,367,063
|
1,381,951
|
|
|
|
|
|
Ratio of net debt to
annualized fund flows from operations
|
|
|
3.6
|
2.7
|
(1)
|
Current liabilities
at December 31, 2015 includes $224,901 relating to the current
portion of long-term debt.
|
As at March 31, 2016, long term
debt, including the current portion, increased to $1.43 billion (December
31, 2015 - $1.39 billion) as a
result of draws on the revolving credit facility during the current
year to fund capital expenditures. The increase in long-term
debt was offset by working capital changes, such that net debt
remained relatively consistent at $1.37
billion. Weaker commodity prices versus the prior periods
decreased fund flows from operations, resulting in the ratio of net
debt to annualized fund flows from operations increasing.
Shareholders' capital
During the three months ended March 31,
2016, we maintained monthly dividends at $0.215 per share and declared dividends which
totalled $72.8 million.
The following table outlines our dividend payment history:
Date
|
|
|
|
Monthly dividend
per unit or share
|
January 2003 to
December 2007
|
|
|
|
$0.170
|
January 2008 to
December 2012
|
|
|
|
$0.190
|
January 2013 to
December 31, 2013
|
|
|
|
$0.200
|
January 2014 to
Present
|
|
|
|
$0.215
|
Our policy with respect to dividends is to be conservative and
maintain a low ratio of dividends to fund flows from
operations. During low commodity price cycles, we will
initially maintain dividends and allow the ratio to rise.
Should low commodity price cycles remain for an extended period of
time, we will evaluate the necessity of changing the level of
dividends, taking into consideration capital development
requirements, debt levels, and acquisition opportunities.
As a further step to preserve our financial flexibility and
conservatively exercise our access to capital, we amended our
existing dividend reinvestment plan to include a Premium Dividend™
Component in February 2015. The Premium Dividend™ Component,
when combined with our continuing Dividend Reinvestment Component,
increases our access to the lowest cost sources of equity capital
available. While the Premium Dividend™ results in a modest
amount of equity issuance, we believe it represents the most
prudent approach to preserving near-term balance sheet
strength. We view implementation of a Premium Dividend™ as a
short-term measure to maintain our financial flexibility while we
continue to lower our unit costs and await further clarity on the
direction of commodity prices. Both components of our program
can be reduced or eliminated at the company's discretion, offering
considerable flexibility. We will actively monitor our
ongoing needs and manage our continued use of each component as
circumstances dictate.
Although we expect to be able to maintain our current dividend,
fund flows from operations may not be sufficient during this low
commodity price environment to fund cash dividends, capital
expenditures, and asset retirement obligations. We will
evaluate our ability to finance any shortfalls with debt, issuances
of equity, or by reducing some or all categories of expenditures to
ensure that total expenditures do not exceed available
funds.
The following table reconciles the change in shareholders'
capital:
Shareholders'
Capital
|
|
|
|
Number of Shares
('000s)
|
|
Amount
($M)
|
Balance as at
December 31, 2015
|
|
|
|
111,991
|
|
2,181,089
|
Shares issued for the
DRIP(1)
|
|
|
|
1,354
|
|
47,990
|
Shares issued for
equity based compensation
|
|
|
|
106
|
|
4,128
|
Balance as at
March 31, 2016
|
|
|
|
113,451
|
|
2,233,207
|
(1)
|
DRIP Refers to
Vermilion's dividend reinvestment and Premium DividendTM
plans.
|
As at March 31, 2016, there were
approximately 1.7 million VIP awards outstanding. As at
May 5, 2016, there were approximately
113.9 million common shares issued and outstanding.
ASSET RETIREMENT OBLIGATIONS
As at March 31, 2016, asset
retirement obligations were $319.0
million compared to $305.6
million as at December 31,
2015.
The increase in asset retirement obligations is largely
attributable to an overall decrease in the discount rates applied
to the abandonment obligations, as well as accretion and additions
from new wells drilled year-to-date.
OFF BALANCE SHEET ARRANGEMENTS
We have certain lease agreements that are entered into in the
normal course of operations, including operating leases for which
no asset or liability value has been assigned to the consolidated
balance sheet as at March 31,
2016.
We have not entered into any guarantee or off balance sheet
arrangements that would materially impact our financial position or
results of operations.
RISK MANAGEMENT
Vermilion is exposed to various
market and operational risks. For a detailed discussion of
these risks, please see Vermilion's Annual Report for the year ended
December 31, 2015.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with IFRS
requires management to make estimates, judgments and assumptions
that affect reported assets, liabilities, revenues and expenses,
gains and losses, and disclosures of any possible
contingencies. These estimates and assumptions are developed
based on the best available information which management believed
to be reasonable at the time such estimates and assumptions were
made. As such, these assumptions are uncertain at the time
estimates are made and could change, resulting in a material impact
on Vermilion's consolidated
financial statements. Estimates are reviewed by management on
an ongoing basis and as a result may change from period to period
due to the availability of new information or changes in
circumstances. Additionally, as a result of the unique
circumstances of each jurisdiction that Vermilion operates in, the critical accounting
estimates may affect one or more jurisdictions. There have
been no material changes to our critical accounting estimates used
in applying accounting policies for the three months ended
March 31, 2016. Further
information, including a discussion of critical accounting
estimates, can be found in the notes to the Consolidated Financial
Statements and annual MD&A for the year ended December 31, 2015, available on SEDAR at
www.sedar.com or on Vermilion's
website at www.vermilionenergy.com.
INTERNAL CONTROL OVER FINANCIAL REPORTING
There was no change in Vermilion's internal control over financial
reporting that occurred during the period covered by this MD&A
that has materially affected, or is reasonably likely to materially
affect, its internal control over financial reporting.
Supplemental Table 1: Netbacks
The following table includes financial statement information on
a per unit basis by business unit. Natural gas sales volumes
have been converted on a basis of six thousand cubic feet of
natural gas to one barrel of oil equivalent.
|
Three Months Ended
March 31, 2016
|
|
Three Months Ended
March 31, 2015
|
|
Oil,
Condensate
|
|
|
|
|
Oil,
Condensate
|
|
|
|
|
&
NGLs
|
Natural
Gas
|
|
Total
|
|
&
NGLs
|
Natural
Gas
|
|
Total
|
|
$/bbl
|
$/mcf
|
|
$/boe
|
|
$/bbl
|
$/mcf
|
|
$/boe
|
Canada
|
|
|
|
|
|
|
|
|
|
Sales
|
33.11
|
1.93
|
|
21.16
|
|
49.15
|
2.97
|
|
35.81
|
Royalties
|
(4.03)
|
(0.08)
|
|
(2.07)
|
|
(5.87)
|
(0.23)
|
|
(3.95)
|
Transportation
|
(2.30)
|
(0.16)
|
|
(1.57)
|
|
(2.42)
|
(0.16)
|
|
(1.81)
|
Operating
|
(7.32)
|
(1.44)
|
|
(8.05)
|
|
(9.02)
|
(1.41)
|
|
(8.78)
|
Operating
netback
|
19.46
|
0.25
|
|
9.47
|
|
31.84
|
1.17
|
|
21.27
|
General and
administration
|
|
|
|
(0.94)
|
|
|
|
|
(1.85)
|
Fund flows from
operations netback
|
|
|
|
8.53
|
|
|
|
|
19.42
|
France
|
|
|
|
|
|
|
|
|
|
Sales
|
43.36
|
1.66
|
|
43.16
|
|
64.33
|
-
|
|
64.33
|
Royalties
|
(6.09)
|
(0.29)
|
|
(6.07)
|
|
(5.48)
|
-
|
|
(5.49)
|
Transportation
|
(3.35)
|
-
|
|
(3.33)
|
|
(3.24)
|
-
|
|
(3.24)
|
Operating
|
(12.84)
|
(2.24)
|
|
(12.84)
|
|
(11.64)
|
-
|
|
(11.64)
|
Operating
netback
|
21.08
|
(0.87)
|
|
20.92
|
|
43.97
|
-
|
|
43.96
|
General and
administration
|
|
|
|
(4.19)
|
|
|
|
|
(5.49)
|
Other
income
|
|
|
|
-
|
|
|
|
|
34.16
|
Current income
taxes
|
|
|
|
(0.03)
|
|
|
|
|
(15.35)
|
Fund flows from
operations netback
|
|
|
|
16.70
|
|
|
|
|
57.28
|
Netherlands
|
|
|
|
|
|
|
|
|
|
Sales
|
32.24
|
5.55
|
|
33.26
|
|
52.93
|
8.09
|
|
48.60
|
Royalties
|
-
|
(0.09)
|
|
(0.56)
|
|
-
|
(0.28)
|
|
(1.68)
|
Operating
|
-
|
(1.23)
|
|
(7.28)
|
|
-
|
(1.78)
|
|
(10.56)
|
Operating
netback
|
32.24
|
4.23
|
|
25.42
|
|
52.93
|
6.03
|
|
36.36
|
General and
administration
|
|
|
|
(0.94)
|
|
|
|
|
(1.34)
|
Current income
taxes
|
|
|
|
(2.68)
|
|
|
|
|
(4.33)
|
Fund flows from
operations netback
|
|
|
|
21.80
|
|
|
|
|
30.69
|
Germany
|
|
|
|
|
|
|
|
|
|
Sales
|
-
|
5.30
|
|
31.78
|
|
-
|
7.53
|
|
45.21
|
Royalties
|
-
|
(0.60)
|
|
(3.58)
|
|
-
|
(1.06)
|
|
(6.34)
|
Transportation
|
-
|
(0.61)
|
|
(3.67)
|
|
-
|
(0.59)
|
|
(3.55)
|
Operating
|
-
|
(1.79)
|
|
(10.71)
|
|
-
|
(1.32)
|
|
(7.93)
|
Operating
netback
|
-
|
2.30
|
|
13.82
|
|
-
|
4.56
|
|
27.39
|
General and
administration
|
|
|
|
(10.03)
|
|
|
|
|
(6.38)
|
Fund flows from
operations netback
|
|
|
|
3.79
|
|
|
|
|
21.01
|
Ireland
|
|
|
|
|
|
|
|
|
|
Sales
|
-
|
5.51
|
|
33.07
|
|
-
|
-
|
|
-
|
Transportation
|
-
|
(0.53)
|
|
(3.19)
|
|
-
|
-
|
|
-
|
Operating
|
-
|
(1.18)
|
|
(7.05)
|
|
-
|
-
|
|
-
|
Operating
netback
|
-
|
3.80
|
|
22.83
|
|
-
|
-
|
|
-
|
General and
administration
|
|
|
|
(2.31)
|
|
|
|
|
-
|
Fund flows from
operations netback
|
|
|
|
20.52
|
|
|
|
|
-
|
Australia
|
|
|
|
|
|
|
|
|
|
Sales
|
46.93
|
-
|
|
46.93
|
|
83.80
|
-
|
|
83.80
|
Operating
|
(17.63)
|
-
|
|
(17.63)
|
|
(25.58)
|
-
|
|
(25.58)
|
PRRT
(1)
|
(0.30)
|
-
|
|
(0.30)
|
|
(10.23)
|
-
|
|
(10.23)
|
Operating
netback
|
29.00
|
-
|
|
29.00
|
|
47.99
|
-
|
|
47.99
|
General and
administration
|
|
|
|
(3.12)
|
|
|
|
|
(6.32)
|
Corporate income
taxes
|
|
|
|
(1.83)
|
|
|
|
|
(2.51)
|
Fund flows from
operations netback
|
|
|
|
24.05
|
|
|
|
|
39.16
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31, 2016
|
|
Three Months Ended
March 31, 2015
|
|
Oil,
Condensate
|
|
|
|
|
Oil,
Condensate
|
|
|
|
|
&
NGLs
|
Natural
Gas
|
|
Total
|
|
&
NGLs
|
Natural
Gas
|
|
Total
|
|
$/bbl
|
$/mcf
|
|
$/boe
|
|
$/bbl
|
$/mcf
|
|
$/boe
|
United
States
|
|
|
|
|
|
|
|
|
|
Sales
|
32.84
|
0.67
|
|
30.10
|
|
48.79
|
-
|
|
48.79
|
Royalties
|
(9.73)
|
(0.40)
|
|
(9.03)
|
|
(14.98)
|
-
|
|
(14.98)
|
Operating
|
(7.54)
|
-
|
|
(6.82)
|
|
(15.61)
|
-
|
|
(15.61)
|
Operating
netback
|
15.57
|
0.27
|
|
14.25
|
|
18.20
|
-
|
|
18.20
|
General and
administration
|
|
|
|
(27.65)
|
|
|
|
|
(78.41)
|
Fund flows from
operations netback
|
|
|
|
(13.40)
|
|
|
|
|
(60.21)
|
Total
Company
|
|
|
|
|
|
|
|
|
|
Sales
|
39.35
|
3.76
|
|
30.53
|
|
58.25
|
5.26
|
|
47.17
|
Realized hedging
gain
|
3.18
|
1.07
|
|
4.89
|
|
0.75
|
0.43
|
|
1.51
|
Royalties
|
(4.30)
|
(0.11)
|
|
(2.40)
|
|
(5.21)
|
(0.37)
|
|
(3.95)
|
Transportation
|
(2.33)
|
(0.22)
|
|
(1.79)
|
|
(2.49)
|
(0.34)
|
|
(2.30)
|
Operating
|
(11.10)
|
(1.37)
|
|
(9.58)
|
|
(11.61)
|
(1.51)
|
|
(10.56)
|
PRRT
(1)
|
(0.05)
|
-
|
|
(0.02)
|
|
(0.97)
|
-
|
|
(0.57)
|
Operating
netback
|
24.75
|
3.13
|
|
21.63
|
|
38.72
|
3.47
|
|
31.30
|
General and
administration
|
|
|
|
(2.34)
|
|
|
|
|
(3.27)
|
Interest
expense
|
|
|
|
(2.54)
|
|
|
|
|
(3.20)
|
Realized foreign
exchange (loss) gain
|
|
|
|
(0.11)
|
|
|
|
|
0.78
|
Other
income
|
|
|
|
0.02
|
|
|
|
|
7.70
|
Corporate income
taxes (1)
|
|
|
|
(0.54)
|
|
|
|
|
(4.24)
|
Fund flows from
operations netback
|
|
|
|
16.12
|
|
|
|
|
29.07
|
(1)
|
Vermilion considers
Australian PRRT to be an operating item and, accordingly, has
included PRRT in the calculation of operating netbacks.
Current income taxes presented above excludes PRRT.
|
Supplemental Table 2: Hedges
The following tables outline Vermilion's outstanding risk management
positions as at March 31, 2016:
|
|
|
|
Note
|
|
Volume
|
|
Strike
Price(s)
|
Crude
Oil
|
|
|
|
|
|
|
|
|
WTI -
Collar
|
|
|
|
|
|
|
|
|
July 2015 - June
2016
|
|
|
|
1
|
|
500 bbls/d
|
|
75.50 - 85.08 CAD
$
|
April 2016 -
September 2016
|
|
|
|
1
|
|
500 bbls/d
|
|
52.25 - 64.40 CAD
$
|
April 2016 -
September 2016
|
|
|
|
2
|
|
750 bbls/d
|
|
40.50 - 50.40 US
$
|
Dated Brent -
Collar
|
|
|
|
|
|
|
|
|
July 2015 - June
2016
|
|
|
|
3
|
|
1,000
bbls/d
|
|
80.50 - 93.49 CAD
$
|
July 2015 - June
2016
|
|
|
|
4
|
|
500 bbls/d
|
|
64.50 - 75.48 US
$
|
October 2015 - June
2016
|
|
|
|
5
|
|
250 bbls/d
|
|
82.00 - 94.55 CAD
$
|
January 2016 - June
2016
|
|
|
|
6
|
|
250 bbls/d
|
|
84.00 - 93.70 CAD
$
|
April 2016 -
September 2016
|
|
|
|
5
|
|
250 bbls/d
|
|
52.00 - 64.80 CAD
$
|
|
|
|
|
|
|
|
|
|
North American
Natural Gas
|
|
|
|
|
|
|
|
|
AECO -
Collar
|
|
|
|
|
|
|
|
|
November 2015 -
October 2016
|
|
|
|
|
|
10,000
GJ/d
|
|
2.56 - 3.23 CAD
$
|
January 2016 -
December 2016
|
|
|
|
|
|
10,000
GJ/d
|
|
2.53 - 3.29 CAD
$
|
March 2016 - December
2016
|
|
|
|
7
|
|
5,000 GJ/d
|
|
2.05 - 2.77 CAD
$
|
April 2016 - October
2016
|
|
|
|
|
|
5,000 GJ/d
|
|
2.30 - 2.80 CAD
$
|
April 2016 - December
2016
|
|
|
|
8
|
|
2,500 GJ/d
|
|
2.10 - 2.92 CAD
$
|
November 2016 -
October 2017
|
|
|
|
7
|
|
7,500 GJ/d
|
|
2.07 - 2.71 CAD
$
|
November 2016 -
December 2017
|
|
|
|
|
|
10,000
GJ/d
|
|
2.21 - 2.86 CAD
$
|
January 2017 -
December 2017
|
|
|
|
|
|
5,000 GJ/d
|
|
2.25 - 3.09 CAD
$
|
AECO -
Swap
|
|
|
|
|
|
|
|
|
April 2016 - October
2016
|
|
|
|
9
|
|
5,000 GJ/d
|
|
2.59 CAD $
|
(1)
|
The contracted
volumes increase to 1,250 bbls/d for any monthly settlement periods
above the contracted ceiling price and is settled on the monthly
average price (monthly average US$/bbl multiplied by the Bank of
Canada monthly average noon day rate).
|
(2)
|
The contracted
volumes increase to 2,000 bbls/d for any monthly settlement periods
above the contracted ceiling price.
|
(3)
|
The contracted
volumes increase to 2,500 bbls/d for any monthly settlement periods
above the contracted ceiling price and is settled on the monthly
average price (monthly average US$/bbl multiplied by the Bank of
Canada monthly average noon day rate).
|
(4)
|
The contracted
volumes increase to 1,000 bbls/d for any monthly settlement periods
above the contracted ceiling price.
|
(5)
|
The contracted
volumes increase to 750 bbls/d for any monthly settlement periods
above the contracted ceiling price and is settled on the monthly
average price (monthly average US$/bbl multiplied by the Bank of
Canada monthly average noon day rate).
|
(6)
|
The contracted
volumes increase to 500 bbls/d for any monthly settlement periods
above the contracted ceiling price and is settled on the monthly
average price (monthly average US$/bbl multiplied by the Bank of
Canada monthly average noon day rate).
|
(7)
|
The contracted
volumes increase to 10,000 GJ/d for any monthly settlement periods
above the contracted ceiling price.
|
(8)
|
The contracted
volumes increase to 7,500 GJ/d for any monthly settlement periods
above the contracted ceiling price.
|
(9)
|
On the last business
day of each month, the counterparty has the option to increase the
contracted volumes to 10,000 GJ/d at the contracted price, for the
following month.
|
|
|
|
Note
|
|
Volume
|
|
Strike
Price(s)
|
European Natural
Gas
|
|
|
|
|
|
|
|
NBP -
Call
|
|
|
|
|
|
|
|
October 2016 - March
2017
|
|
|
|
|
2,638 GJ/d
|
|
4.64 GBP £
|
NBP -
Collar
|
|
|
|
|
|
|
|
April 2016 - March
2017
|
|
|
|
|
2,638 GJ/d
|
|
3.79 - 4.53 GBP
£
|
July 2016 - December
2016
|
|
|
1
|
|
2,638 GJ/d
|
|
2.84 - 4.08 GBP
£
|
October 2016 - March
2017
|
|
|
2
|
|
2,638 GJ/d
|
|
3.13 - 3.53 GBP
£
|
October 2016 -
December 2017
|
|
|
2
|
|
2,638 GJ/d
|
|
2.84 - 3.70 GBP
£
|
January 2017 -
December 2017
|
|
|
1
|
|
5,275 GJ/d
|
|
3.13 - 3.62 GBP
£
|
January 2018 -
December 2018
|
|
|
|
|
2,638 GJ/d
|
|
2.99 - 3.63 GBP
£
|
NBP -
Put
|
|
|
|
|
|
|
|
April 2016 -
September 2016
|
|
|
|
|
2,638 GJ/d
|
|
3.79 GBP £
|
NBP -
Swap
|
|
|
|
|
|
|
|
January 2016 - June
2016
|
|
|
|
|
5,184 GJ/d
|
|
6.24 EUR €
|
January 2016 - June
2016
|
|
|
|
|
2,592 GJ/d
|
|
6.82 US $
|
July 2016 - March
2017
|
|
|
|
|
2,592 GJ/d
|
|
5.43 EUR €
|
October 2016 -
December 2016
|
|
|
|
|
2,638 GJ/d
|
|
3.24 GBP £
|
January 2017 -
December 2017
|
|
|
3
|
|
2,638 GJ/d
|
|
4.00 GBP £
|
January 2018 -
December 2018
|
|
|
4
|
|
2,638 GJ/d
|
|
3.83 GBP £
|
TTF -
Call
|
|
|
|
|
|
|
|
October 2016 - March
2017
|
|
|
|
|
2,592 GJ/d
|
|
6.03 EUR €
|
TTF -
Collar
|
|
|
|
|
|
|
|
January 2016 -
December 2016
|
|
|
5
|
|
2,592 GJ/d
|
|
5.76 - 6.50 EUR
€
|
April 2016 - December
2016
|
|
|
6
|
|
12,960
GJ/d
|
|
5.58 - 6.21 EUR
€
|
April 2016 - March
2017
|
|
|
7
|
|
5,184 GJ/d
|
|
5.28 - 6.35 EUR
€
|
July 2016 - December
2016
|
|
|
|
|
2,592 GJ/d
|
|
5.00 - 5.63 EUR
€
|
July 2016 - March
2017
|
|
|
5
|
|
2,592 GJ/d
|
|
5.07 - 6.56 EUR
€
|
July 2016 - March
2018
|
|
|
5
|
|
2,592 GJ/d
|
|
5.32 - 6.54 EUR
€
|
October 2016 -
December 2017
|
|
|
|
|
2,592 GJ/d
|
|
5.00 - 5.89 EUR
€
|
January 2017 -
December 2017
|
|
|
8
|
|
7,776 GJ/d
|
|
5.00 - 6.15 EUR
€
|
April 2017 -
September 2017
|
|
|
5
|
|
2,592 GJ/d
|
|
3.61 - 4.24 EUR
€
|
January 2018 -
December 2018
|
|
|
|
|
5,184 GJ/d
|
|
4.17 - 5.03 EUR
€
|
TTF -
Put
|
|
|
|
|
|
|
|
April 2016 -
September 2016
|
|
|
|
|
2,592 GJ/d
|
|
5.21 EUR €
|
TTF -
Swap
|
|
|
|
|
|
|
|
January 2015 - June
2016
|
|
|
|
|
2,592 GJ/d
|
|
6.07 EUR €
|
January 2016 - June
2016
|
|
|
|
|
5,184 GJ/d
|
|
5.94 EUR €
|
April 2016 - December
2016
|
|
|
|
|
2,592 GJ/d
|
|
5.91 EUR €
|
July 2016 - June
2018
|
|
|
|
|
2,700 GJ/d
|
|
5.58 EUR €
|
October 2016 -
December 2016
|
|
|
|
|
2,592 GJ/d
|
|
5.45 EUR €
|
January 2017 -
December 2017
|
|
|
5
|
|
2,592 GJ/d
|
|
5.04 EUR €
|
|
|
|
|
|
|
|
|
Fuel and
Electricity
|
|
|
|
|
|
|
|
GasOil -
Swap
|
|
|
|
|
|
|
|
March 2016 - December
2016
|
|
|
|
|
125 bbls/d
|
|
42.55 US $
|
AESO -
Swap
|
|
|
|
|
|
|
|
January 2016 -
December 2016
|
|
|
|
|
93.6 MWh/d
|
|
38.58 CAD
$
|
|
|
|
|
|
|
|
|
Interest
Rate
|
|
|
|
|
|
|
|
CDOR to fixed -
Swap
|
|
|
|
|
|
|
|
September 2015 -
September 2019
|
|
|
|
|
100,000,000 CAD
$/year
|
|
1.00 %
|
October 2015 -
October 2019
|
|
|
|
|
100,000,000 CAD
$/year
|
|
1.10 %
|
(1)
|
The contracted
volumes increase to 7,913 GJ/d for any monthly settlement periods
above the contracted ceiling price.
|
(2)
|
The contracted
volumes increase to 5,275 GJ/d for any monthly settlement periods
above the contracted ceiling price.
|
(3)
|
On the last business
day of each month, the counterparty has the option to increase the
contracted volumes by an additional 2,638 GJ/d at the contracted
price, for the following month.
|
(4)
|
On the last business
day of each month, the counterparty has the option to increase the
contracted volumes to 7,913 GJ/d at the contracted price, for the
following month.
|
(5)
|
The contracted
volumes increase to 5,184 GJ/d for any monthly settlement periods
above the contracted ceiling price.
|
(6)
|
The contracted
volumes increase to 15,552 GJ/d for any monthly settlement periods
above the contracted ceiling price.
|
(7)
|
The contracted
volumes increase to 10,368 GJ/d for any monthly settlement periods
above the contracted ceiling price.
|
(8)
|
The contracted
volumes increase to 18,144 GJ/d for any monthly settlement periods
above the contracted ceiling price.
|
Supplemental Table 3: Capital Expenditures
|
|
|
|
|
|
Three Months
Ended
|
By
classification
|
|
|
|
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
($M)
|
|
|
|
|
|
2016
|
2015
|
2015
|
Drilling and
development
|
|
|
|
|
|
62,773
|
128,996
|
174,311
|
Exploration and
evaluation
|
|
|
|
|
|
-
|
-
|
-
|
Capital
expenditures
|
|
|
|
|
|
62,773
|
128,996
|
174,311
|
Property
acquisition
|
|
|
|
|
|
870
|
6,227
|
35
|
Acquisitions
|
|
|
|
|
|
870
|
6,227
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
By
category
|
|
|
|
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
($M)
|
|
|
|
|
|
2016
|
2015
|
2015
|
Land
|
|
|
|
|
|
1,039
|
819
|
742
|
Seismic
|
|
|
|
|
|
6,268
|
4,217
|
1,493
|
Drilling and
completion
|
|
|
|
|
|
27,853
|
58,327
|
82,343
|
Production equipment
and facilities
|
|
|
|
|
|
6,238
|
55,662
|
74,755
|
Recompletions
|
|
|
|
|
|
3,598
|
6,338
|
7,115
|
Other
|
|
|
|
|
|
17,777
|
3,633
|
7,863
|
Capital
expenditures
|
|
|
|
|
|
62,773
|
128,996
|
174,311
|
Acquisitions
|
|
|
|
|
|
870
|
6,227
|
35
|
Total capital
expenditures and acquisitions
|
|
|
|
|
|
63,643
|
135,223
|
174,346
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
By
country
|
|
|
|
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
($M)
|
|
|
|
|
|
2016
|
2015
|
2015
|
Canada
|
|
|
|
|
|
30,526
|
33,723
|
114,884
|
France
|
|
|
|
|
|
13,463
|
24,164
|
34,114
|
Netherlands
|
|
|
|
|
|
2,996
|
18,810
|
4,333
|
Germany
|
|
|
|
|
|
539
|
(441)
|
968
|
Ireland
|
|
|
|
|
|
3,076
|
12,493
|
12,955
|
Australia
|
|
|
|
|
|
7,827
|
40,852
|
6,455
|
United
States
|
|
|
|
|
|
5,216
|
5,622
|
637
|
Total capital
expenditures and acquisitions
|
|
|
|
|
|
63,643
|
135,223
|
174,346
|
Supplemental Table 4: Production
|
|
Q1/16
|
Q4/15
|
Q3/15
|
Q2/15
|
Q1/15
|
Q4/14
|
Q3/14
|
Q2/14
|
Q1/14
|
Q4/13
|
Q3/13
|
Q2/13
|
Canada
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil &
condensate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(bbls/d)
|
10,317
|
10,413
|
11,030
|
11,843
|
12,163
|
12,681
|
12,755
|
14,108
|
10,390
|
8,719
|
7,969
|
8,885
|
|
NGLs
(bbls/d)
|
2,633
|
2,710
|
2,678
|
2,094
|
1,706
|
1,444
|
1,005
|
1,364
|
1,118
|
1,699
|
1,897
|
1,725
|
|
Natural gas
(mmcf/d)
|
97.16
|
87.90
|
71.94
|
64.66
|
61.78
|
58.36
|
57.07
|
57.59
|
49.53
|
41.43
|
43.40
|
43.69
|
|
Total
(boe/d)
|
29,141
|
27,773
|
25,698
|
24,713
|
24,165
|
23,851
|
23,272
|
25,070
|
19,763
|
17,322
|
17,099
|
17,892
|
|
% of
consolidated
|
44%
|
45%
|
47%
|
48%
|
48%
|
49%
|
47%
|
49%
|
42%
|
43%
|
41%
|
42%
|
France
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
(bbls/d)
|
12,220
|
12,537
|
12,310
|
12,746
|
11,463
|
11,133
|
11,111
|
11,025
|
10,771
|
11,131
|
11,625
|
10,390
|
|
Natural gas
(mmcf/d)
|
0.44
|
1.36
|
1.47
|
1.03
|
-
|
-
|
-
|
-
|
-
|
-
|
5.23
|
4.19
|
|
Total
(boe/d)
|
12,293
|
12,763
|
12,555
|
12,917
|
11,463
|
11,133
|
11,111
|
11,025
|
10,771
|
11,131
|
12,496
|
11,088
|
|
% of
consolidated
|
19%
|
21%
|
22%
|
25%
|
23%
|
22%
|
22%
|
21%
|
23%
|
27%
|
30%
|
26%
|
Netherlands
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Condensate
(bbls/d)
|
114
|
110
|
109
|
112
|
63
|
81
|
63
|
96
|
69
|
62
|
48
|
50
|
|
Natural gas
(mmcf/d)
|
53.40
|
56.34
|
53.56
|
32.43
|
36.41
|
31.35
|
38.07
|
40.35
|
43.15
|
37.53
|
28.78
|
38.52
|
|
Total
(boe/d)
|
9,015
|
9,500
|
9,035
|
5,517
|
6,132
|
5,306
|
6,407
|
6,822
|
7,260
|
6,318
|
4,845
|
6,470
|
|
% of
consolidated
|
14%
|
16%
|
16%
|
11%
|
12%
|
11%
|
13%
|
13%
|
16%
|
15%
|
12%
|
15%
|
Germany
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
(mmcf/d)
|
15.96
|
16.17
|
14.00
|
16.18
|
16.80
|
17.71
|
15.38
|
16.13
|
10.64
|
-
|
-
|
-
|
|
Total
(boe/d)
|
2,660
|
2,695
|
2,333
|
2,696
|
2,801
|
2,952
|
2,563
|
2,689
|
1,773
|
-
|
-
|
-
|
|
% of
consolidated
|
4%
|
4%
|
4%
|
5%
|
6%
|
6%
|
5%
|
5%
|
4%
|
-
|
-
|
-
|
Ireland
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
(mmcf/d)
|
33.90
|
0.12
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Total
(boe/d)
|
5,650
|
20
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
|
% of
consolidated
|
9%
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Australia
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
(bbls/d)
|
6,180
|
7,824
|
6,433
|
5,865
|
5,672
|
6,134
|
6,567
|
6,483
|
7,110
|
6,189
|
7,070
|
7,363
|
|
% of
consolidated
|
9%
|
13%
|
11%
|
11%
|
11%
|
12%
|
13%
|
12%
|
15%
|
15%
|
17%
|
17%
|
United
States
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil
(bbls/d)
|
368
|
420
|
226
|
123
|
153
|
195
|
-
|
-
|
-
|
-
|
-
|
-
|
|
NGLs
(bbls/d)
|
39
|
29
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Natural gas
(mmcf/d)
|
0.26
|
0.20
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
|
Total
(boe/d)
|
450
|
483
|
226
|
123
|
153
|
195
|
-
|
-
|
-
|
-
|
-
|
-
|
|
% of
consolidated
|
1%
|
1%
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
Consolidated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil,
condensate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
& NGLs
(bbls/d)
|
31,871
|
34,043
|
32,786
|
32,783
|
31,220
|
31,668
|
31,501
|
33,076
|
29,458
|
27,800
|
28,609
|
28,413
|
|
% of
consolidated
|
49%
|
56%
|
58%
|
63%
|
62%
|
64%
|
63%
|
63%
|
63%
|
68%
|
69%
|
66%
|
|
Natural gas
(mmcf/d)
|
201.11
|
162.09
|
140.97
|
114.29
|
115.00
|
107.42
|
110.52
|
114.08
|
103.32
|
78.96
|
77.41
|
86.40
|
|
% of
consolidated
|
51%
|
44%
|
42%
|
37%
|
38%
|
36%
|
37%
|
37%
|
37%
|
32%
|
31%
|
34%
|
|
Total
(boe/d)
|
65,389
|
61,058
|
56,280
|
51,831
|
50,386
|
49,571
|
49,920
|
52,089
|
46,677
|
40,960
|
41,510
|
42,813
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
2015
|
2014
|
2013
|
2012
|
2011
|
Canada
|
|
|
|
|
|
|
|
Crude oil and
condensate
|
|
|
|
|
|
|
|
(bbls/d)
|
10,317
|
11,357
|
12,491
|
8,387
|
7,659
|
4,701
|
|
NGLs
(bbls/d)
|
2,633
|
2,301
|
1,233
|
1,666
|
1,232
|
1,297
|
|
Natural gas
(mmcf/d)
|
97.16
|
71.65
|
55.67
|
42.39
|
37.50
|
43.38
|
|
Total
(boe/d)
|
29,141
|
25,598
|
23,001
|
17,117
|
15,142
|
13,227
|
|
% of
consolidated
|
44%
|
46%
|
47%
|
41%
|
40%
|
38%
|
France
|
|
|
|
|
|
|
|
Crude oil
(bbls/d)
|
12,220
|
12,267
|
11,011
|
10,873
|
9,952
|
8,110
|
|
Natural gas
(mmcf/d)
|
0.44
|
0.97
|
-
|
3.40
|
3.59
|
0.95
|
|
Total
(boe/d)
|
12,293
|
12,429
|
11,011
|
11,440
|
10,550
|
8,269
|
|
% of
consolidated
|
19%
|
23%
|
22%
|
28%
|
28%
|
23%
|
Netherlands
|
|
|
|
|
|
|
|
Condensate
(bbls/d)
|
114
|
99
|
77
|
64
|
67
|
58
|
|
Natural gas
(mmcf/d)
|
53.40
|
44.76
|
38.20
|
35.42
|
34.11
|
32.88
|
|
Total
(boe/d)
|
9,015
|
7,559
|
6,443
|
5,967
|
5,751
|
5,538
|
|
% of
consolidated
|
14%
|
14%
|
13%
|
15%
|
15%
|
16%
|
Germany
|
|
|
|
|
|
|
|
Natural gas
(mmcf/d)
|
15.96
|
15.78
|
14.99
|
-
|
-
|
-
|
|
Total
(boe/d)
|
2,660
|
2,630
|
2,498
|
-
|
-
|
-
|
|
% of
consolidated
|
4%
|
5%
|
5%
|
-
|
-
|
-
|
Ireland
|
|
|
|
|
|
|
|
Natural gas
(mmcf/d)
|
33.90
|
0.03
|
-
|
-
|
-
|
-
|
|
Total
(boe/d)
|
5,650
|
5
|
-
|
-
|
-
|
-
|
|
% of
consolidated
|
9%
|
-
|
-
|
-
|
-
|
-
|
Australia
|
|
|
|
|
|
|
|
Crude oil
(bbls/d)
|
6,180
|
6,454
|
6,571
|
6,481
|
6,360
|
8,168
|
|
% of
consolidated
|
9%
|
12%
|
13%
|
16%
|
17%
|
23%
|
United
States
|
|
|
|
|
|
|
|
Crude oil
(bbls/d)
|
368
|
231
|
49
|
-
|
-
|
-
|
|
NGLs
(bbls/d)
|
39
|
7
|
-
|
-
|
-
|
-
|
|
Natural gas
(mmcf/d)
|
0.26
|
0.05
|
-
|
-
|
-
|
-
|
|
Total
(boe/d)
|
450
|
247
|
49
|
-
|
-
|
-
|
|
% of
consolidated
|
1%
|
-
|
-
|
-
|
-
|
-
|
Consolidated
|
|
|
|
|
|
|
|
Crude oil, condensate
&
|
|
|
|
|
|
|
|
NGLs
(bbls/d)
|
31,871
|
32,716
|
31,432
|
27,471
|
25,270
|
22,334
|
|
% of
consolidated
|
49%
|
60%
|
63%
|
67%
|
67%
|
63%
|
|
Natural gas
(mmcf/d)
|
201.11
|
133.24
|
108.85
|
81.21
|
75.20
|
77.21
|
|
% of
consolidated
|
51%
|
40%
|
37%
|
33%
|
33%
|
37%
|
|
Total
(boe/d)
|
65,389
|
54,922
|
49,573
|
41,005
|
37,803
|
35,202
|
Supplemental Table 5: Segmented Financial Results
|
Three Months Ended
March 31, 2016
|
($M)
|
Canada
|
France
|
Netherlands
|
Germany
|
Ireland
|
Australia
|
United
States
|
Corporate
|
Total
|
Total
assets
|
1,584,947
|
833,145
|
195,413
|
159,522
|
838,240
|
240,352
|
44,585
|
176,136
|
4,072,340
|
Drilling and
development
|
29,771
|
13,463
|
2,996
|
539
|
3,076
|
7,827
|
5,101
|
-
|
62,773
|
Oil and gas sales to
external customers
|
56,110
|
48,125
|
27,286
|
7,692
|
17,004
|
19,935
|
1,233
|
-
|
177,385
|
Royalties
|
(5,498)
|
(6,766)
|
(460)
|
(867)
|
-
|
-
|
(370)
|
-
|
(13,961)
|
Revenue from external
customers
|
50,612
|
41,359
|
26,826
|
6,825
|
17,004
|
19,935
|
863
|
-
|
163,424
|
Transportation
|
(4,151)
|
(3,713)
|
-
|
(887)
|
(1,639)
|
-
|
-
|
-
|
(10,390)
|
Operating
|
(21,343)
|
(14,320)
|
(5,976)
|
(2,593)
|
(3,626)
|
(7,491)
|
(279)
|
-
|
(55,628)
|
General and
administration
|
(2,476)
|
(4,676)
|
(773)
|
(2,428)
|
(1,188)
|
(1,325)
|
(1,132)
|
421
|
(13,577)
|
PRRT
|
-
|
-
|
-
|
-
|
-
|
(128)
|
-
|
-
|
(128)
|
Corporate income
taxes
|
-
|
(34)
|
(2,200)
|
-
|
-
|
(777)
|
-
|
(149)
|
(3,160)
|
Interest
expense
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
(14,750)
|
(14,750)
|
Realized gain on
derivative instruments
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
28,423
|
28,423
|
Realized foreign
exchange loss
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
(652)
|
(652)
|
Realized other
income
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
105
|
105
|
Fund flows from
operations
|
22,642
|
18,616
|
17,877
|
917
|
10,551
|
10,214
|
(548)
|
13,398
|
93,667
|
NON-GAAP FINANCIAL MEASURES
This MD&A includes references to certain financial measures
which do not have standardized meanings prescribed by IFRS and are
not disclosed in our consolidated financial statements. As
such, these financial measures are considered non-GAAP financial
measures and therefore may not be comparable with similar measures
presented by other issuers.
Fund flows from operations per basic and diluted share:
Management assesses fund flows from operations on a per share basis
as we believe this provides a measure of our operating performance
after taking into account the issuance and potential future
issuance of Vermilion common
shares. Fund flows from operations per basic share is
calculated by dividing fund flows from operations by the basic
weighted average shares outstanding as defined under IFRS.
Fund flows from operations per diluted share is calculated by
dividing fund flows from operations by the sum of basic weighted
average shares outstanding and incremental shares issuable under
our equity based compensation plans as determined using the
treasury stock method.
Free cash flow: Represents fund flows from operations in
excess of drilling and development and exploration and evaluation
costs (collectively referred to as 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 and Premium Dividend™ plans.
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 costs, exploration and evaluation costs,
dispositions, and asset retirement obligations settled.
Management uses payout to assess the amount of cash distributed
back to shareholders and re-invested in the business for
maintaining production and organic growth.
Fund flows from operations (excluding Corrib) and Payout
(excluding Corrib): Management excludes expenditures
relating to the Corrib project in assessing fund flows from
operations (a non-GAAP financial measure) and payout in order to
assess our ability to generate cash and finance organic growth from
our current producing assets. Beginning in Q1 2016, the Corrib
project is considered a producing asset, so these financial
measures are not applicable for the current period.
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.
The following tables reconcile fund flows from operations (and
excluding Corrib), net dividends, payout (and excluding Corrib),
and diluted shares outstanding to their most directly comparable
GAAP measures as presented in our financial statements:
|
|
Three Months
Ended
|
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
($M)
|
|
2016
|
2015
|
2015
|
Cash flows from
operating activities
|
|
73,883
|
164,863
|
22,647
|
Changes in non-cash
operating working capital
|
|
17,760
|
(33,343)
|
95,041
|
Asset retirement
obligations settled
|
|
2,024
|
4,921
|
3,107
|
Fund flows from
operations
|
|
93,667
|
136,441
|
120,795
|
Expenses related to
Corrib
|
|
N/A
|
2,252
|
2,205
|
Fund flows from
operations (excluding Corrib)
|
|
N/A
|
138,693
|
123,000
|
|
|
|
|
Three Months
Ended
|
|
|
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
($M)
|
|
|
|
2016
|
2015
|
2015
|
Dividends
declared
|
|
|
|
72,847
|
71,965
|
69,390
|
Shares issued for the
DRIP(1)
|
|
|
|
(47,990)
|
(46,764)
|
(21,378)
|
Net
dividends
|
|
|
|
24,857
|
25,201
|
48,012
|
Drilling and
development
|
|
|
|
62,773
|
128,996
|
174,311
|
Asset retirement
obligations settled
|
|
|
|
2,024
|
4,921
|
3,107
|
Payout
|
|
|
|
89,654
|
159,118
|
225,430
|
Corrib drilling and
development
|
|
|
|
N/A
|
(12,493)
|
(12,955)
|
Payout (excluding
Corrib)
|
|
|
|
N/A
|
146,625
|
212,475
|
(1)
|
DRIP Refers to
Vermilion's dividend reinvestment and Premium DividendTM
plans.
|
|
|
As
at
|
|
|
Mar
31,
|
Dec
31,
|
Mar
31,
|
('000s of
shares)
|
|
2016
|
2015
|
2015
|
Shares
outstanding
|
|
113,451
|
111,991
|
107,718
|
Potential shares
issuable pursuant to the VIP
|
|
3,040
|
3,033
|
3,043
|
Diluted shares
outstanding
|
|
116,491
|
115,024
|
110,761
|
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
(THOUSANDS OF
CANADIAN DOLLARS, UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March
31,
|
|
December
31,
|
|
|
Note
|
|
2016
|
|
2015
|
ASSETS
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
|
|
63,246
|
|
41,676
|
Accounts
receivable
|
|
|
|
127,531
|
|
160,499
|
Crude oil
inventory
|
|
|
|
17,340
|
|
13,079
|
Derivative
instruments
|
|
|
|
62,381
|
|
55,214
|
Prepaid
expenses
|
|
|
|
13,652
|
|
14,310
|
|
|
|
|
284,150
|
|
284,778
|
|
|
|
|
|
|
|
Derivative
instruments
|
|
|
|
15,015
|
|
13,128
|
Deferred
taxes
|
|
6
|
|
99,174
|
|
135,753
|
Exploration and
evaluation assets
|
|
3
|
|
304,033
|
|
308,192
|
Capital
assets
|
|
2
|
|
3,369,968
|
|
3,467,369
|
|
|
|
|
4,072,340
|
|
4,209,220
|
|
|
|
|
|
|
|
LIABILITIES
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
Accounts payable and
accrued liabilities
|
|
|
|
189,811
|
|
248,747
|
Current portion of
long-term debt
|
|
5
|
|
-
|
|
224,901
|
Dividends
payable
|
|
7
|
|
24,392
|
|
24,077
|
Income taxes
payable
|
|
|
|
7,022
|
|
6,006
|
|
|
|
|
221,225
|
|
503,731
|
|
|
|
|
|
|
|
Long-term
debt
|
|
5
|
|
1,429,988
|
|
1,162,998
|
Finance lease
obligation
|
|
|
|
23,028
|
|
23,565
|
Asset retirement
obligations
|
|
4
|
|
318,981
|
|
305,613
|
Deferred
taxes
|
|
|
|
337,657
|
|
354,654
|
|
|
|
|
2,330,879
|
|
2,350,561
|
|
|
|
|
|
|
|
SHAREHOLDERS'
EQUITY
|
|
|
|
|
|
|
Shareholders'
capital
|
|
7
|
|
2,233,207
|
|
2,181,089
|
Contributed
surplus
|
|
|
|
124,655
|
|
107,946
|
Accumulated other
comprehensive income
|
|
|
|
86,317
|
|
113,647
|
Deficit
|
|
|
|
(702,718)
|
|
(544,023)
|
|
|
|
|
1,741,461
|
|
1,858,659
|
|
|
|
|
4,072,340
|
|
4,209,220
|
CONSOLIDATED
STATEMENTS OF NET (LOSS) EARNINGS AND COMPREHENSIVE
LOSS
|
(THOUSANDS OF
CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS,
UNAUDITED)
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
|
|
March
31,
|
|
March
31,
|
|
|
Note
|
|
2016
|
|
2015
|
REVENUE
|
|
|
|
|
|
|
Petroleum and natural
gas sales
|
|
|
|
177,385
|
|
195,885
|
Royalties
|
|
|
|
(13,961)
|
|
(16,424)
|
Petroleum and
natural gas revenue
|
|
|
|
163,424
|
|
179,461
|
|
|
|
|
|
|
|
EXPENSES
|
|
|
|
|
|
|
Operating
|
|
|
|
55,628
|
|
43,851
|
Transportation
|
|
|
|
10,390
|
|
9,540
|
Equity based
compensation
|
|
|
|
20,837
|
|
19,040
|
(Gain) loss on
derivative instruments
|
|
|
|
(37,477)
|
|
13,713
|
Interest
expense
|
|
|
|
14,750
|
|
13,298
|
General and
administration
|
|
|
|
13,577
|
|
13,560
|
Foreign exchange
(gain) loss
|
|
|
|
(918)
|
|
1,539
|
Other
income
|
|
|
|
(18)
|
|
(31,736)
|
Accretion
|
|
4
|
|
6,109
|
|
5,675
|
Depletion and
depreciation
|
|
2, 3
|
|
125,798
|
|
90,957
|
Impairment
|
|
2
|
|
14,762
|
|
-
|
|
|
|
|
223,438
|
|
179,437
|
(LOSS) EARNINGS
BEFORE INCOME TAXES
|
|
|
|
(60,014)
|
|
24
|
|
|
|
|
|
|
|
INCOME
TAXES
|
|
|
|
|
|
|
Deferred
|
|
6
|
|
22,546
|
|
(21,228)
|
Current
|
|
|
|
3,288
|
|
19,977
|
|
|
|
|
25,834
|
|
(1,251)
|
|
|
|
|
|
|
|
NET (LOSS)
EARNINGS
|
|
|
|
(85,848)
|
|
1,275
|
|
|
|
|
|
|
|
OTHER
COMPREHENSIVE LOSS
|
|
|
|
|
|
|
Currency translation
adjustments
|
|
|
|
(27,330)
|
|
(40,134)
|
COMPREHENSIVE
LOSS
|
|
|
|
(113,178)
|
|
(38,859)
|
|
|
|
|
|
|
|
NET (LOSS)
EARNINGS PER SHARE
|
|
|
|
|
|
|
Basic
|
|
|
|
(0.76)
|
|
0.01
|
Diluted
|
|
|
|
(0.76)
|
|
0.01
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE
SHARES OUTSTANDING ('000s)
|
|
|
|
|
|
|
Basic
|
|
|
|
112,725
|
|
107,513
|
Diluted
|
|
|
|
112,725
|
|
109,305
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
(THOUSANDS OF
CANADIAN DOLLARS, UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
|
|
March
31,
|
|
March
31,
|
|
|
Note
|
|
2016
|
|
2015
|
OPERATING
|
|
|
|
|
|
|
Net (loss)
earnings
|
|
|
|
(85,848)
|
|
1,275
|
Adjustments:
|
|
|
|
|
|
|
|
Accretion
|
|
4
|
|
6,109
|
|
5,675
|
|
Depletion and
depreciation
|
|
2, 3
|
|
125,798
|
|
90,957
|
|
Impairment
|
|
2
|
|
14,762
|
|
-
|
|
Unrealized (gain)
loss on derivative instruments
|
|
|
|
(9,054)
|
|
19,970
|
|
Equity based
compensation
|
|
|
|
20,837
|
|
19,040
|
|
Unrealized foreign
exchange (gain) loss
|
|
|
|
(1,570)
|
|
4,845
|
|
Unrealized other
expense
|
|
|
|
87
|
|
261
|
|
Deferred
taxes
|
|
6
|
|
22,546
|
|
(21,228)
|
Asset retirement
obligations settled
|
|
4
|
|
(2,024)
|
|
(3,107)
|
Changes in non-cash
operating working capital
|
|
|
|
(17,760)
|
|
(95,041)
|
Cash flows from
operating activities
|
|
|
|
73,883
|
|
22,647
|
|
|
|
|
|
|
|
INVESTING
|
|
|
|
|
|
|
Drilling and
development
|
|
2
|
|
(62,773)
|
|
(174,311)
|
Property
acquisitions
|
|
2
|
|
(870)
|
|
(35)
|
Changes in non-cash
investing working capital
|
|
|
|
(4,087)
|
|
12,143
|
Cash flows used in
investing activities
|
|
|
|
(67,730)
|
|
(162,203)
|
|
|
|
|
|
|
|
FINANCING
|
|
|
|
|
|
|
Increase in long-term
debt
|
|
|
|
269,560
|
|
154,914
|
Repayment of senior
unsecured notes
|
|
5
|
|
(225,000)
|
|
-
|
Decrease in finance
lease obligation
|
|
|
|
(895)
|
|
-
|
Cash
dividends
|
|
|
|
(24,542)
|
|
(47,923)
|
Cash flows from
financing activities
|
|
|
|
19,123
|
|
106,991
|
Foreign exchange
(loss) gain on cash held in foreign currencies
|
|
|
|
(3,706)
|
|
352
|
|
|
|
|
|
|
|
Net change in cash
and cash equivalents
|
|
|
|
21,570
|
|
(32,213)
|
Cash and cash
equivalents, beginning of period
|
|
|
|
41,676
|
|
120,405
|
Cash and cash
equivalents, end of period
|
|
|
|
63,246
|
|
88,192
|
|
|
|
|
|
|
|
Supplementary
information for operating activities - cash payments
|
|
|
|
|
|
|
|
Interest
paid
|
|
|
|
21,311
|
|
18,245
|
|
Income taxes
paid
|
|
|
|
2,390
|
|
70,513
|
CONSOLIDATED
STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
|
(THOUSANDS OF
CANADIAN DOLLARS, UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
|
|
|
|
|
March
31,
|
|
March
31,
|
|
|
|
|
|
Note
|
|
2016
|
|
2015
|
SHAREHOLDERS'
CAPITAL
|
|
|
|
|
|
|
|
|
|
Balance, beginning of
period
|
|
|
|
|
|
2,181,089
|
|
1,959,021
|
|
Equity based
compensation
|
|
|
|
|
|
4,128
|
|
532
|
|
Shares issued for the
DRIP (1)
|
|
|
|
|
|
47,990
|
|
21,378
|
|
Balance, end of
period
|
|
|
|
7
|
|
2,233,207
|
|
1,980,931
|
CONTRIBUTED
SURPLUS
|
|
|
|
|
|
|
|
|
|
Balance, beginning of
period
|
|
|
|
|
|
107,946
|
|
92,188
|
|
Equity based
compensation
|
|
|
|
|
|
16,709
|
|
18,508
|
|
Balance, end of
period
|
|
|
|
|
|
124,655
|
|
110,696
|
ACCUMULATED OTHER
COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
Balance, beginning of
period
|
|
|
|
|
|
113,647
|
|
5,722
|
|
Currency translation
adjustments
|
|
|
|
|
|
(27,330)
|
|
(40,134)
|
|
Balance, end of
period
|
|
|
|
|
|
86,317
|
|
(34,412)
|
DEFICIT
|
|
|
|
|
|
|
|
|
|
Balance, beginning of
period
|
|
|
|
|
|
(544,023)
|
|
(35,585)
|
|
Net (loss)
earnings
|
|
|
|
|
|
(85,848)
|
|
1,275
|
|
Dividends
declared
|
|
|
|
7
|
|
(72,847)
|
|
(69,390)
|
|
Balance, end of
period
|
|
|
|
|
|
(702,718)
|
|
(103,700)
|
|
|
|
|
|
|
|
|
|
|
TOTAL
SHAREHOLDERS' EQUITY
|
|
|
|
|
|
1,741,461
|
|
1,953,515
|
(1)
|
DRIP Refers to
Vermilion's dividend reinvestment and Premium DividendTM
plans.
|
NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL
STATEMENTS
FOR THE THREE MONTHS ENDED MARCH 31,
2016 AND 2015
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE
AND PER SHARE AMOUNTS, UNAUDITED)
1. BASIS OF PRESENTATION
Vermilion Energy Inc. (the "Company" or "Vermilion") is a
corporation governed by the laws of the Province of Alberta and is actively engaged in the
business of crude oil and natural gas exploration, development,
acquisition and production.
These condensed consolidated interim financial statements are in
compliance with IAS 34, "Interim financial reporting" and have been
prepared using the same accounting policies and methods of
computation as Vermilion's
consolidated financial statements for the year ended December 31, 2015.
These condensed consolidated interim financial statements should
be read in conjunction with Vermilion's consolidated financial statements
for the year ended December 31, 2015,
which are contained within Vermilion's Annual Report for the year ended
December 31, 2015 and are available
on SEDAR at www.sedar.com or on Vermilion's website at
www.vermilionenergy.com.
These condensed consolidated interim financial statements were
approved and authorized for issuance by the Board of Directors of
Vermilion on May 5, 2016.
2. CAPITAL ASSETS
The following table reconciles the change in Vermilion's capital assets:
($M)
|
|
|
|
Capital
Assets
|
Balance at
December 31, 2015
|
|
|
|
3,467,369
|
Additions
|
|
|
|
62,773
|
Property
acquisitions
|
|
|
|
870
|
Changes in estimate
for asset retirement obligations
|
|
|
|
13,312
|
Depletion and
depreciation
|
|
|
|
(124,663)
|
Recognition of
finance lease asset
|
|
|
|
708
|
Impairment
|
|
|
|
(14,762)
|
Foreign
exchange
|
|
|
|
(35,639)
|
Balance at March
31, 2016
|
|
|
|
3,369,968
|
Impairment
On a quarterly basis, Vermilion
performs an assessment as to whether any cash generating units
("CGUs") have indicators of impairment. When indicators of
impairment are identified, Vermilion assesses the recoverable amount of
the applicable CGU based on the higher of the estimated fair value
less costs to sell and value in use as at the reporting date.
The estimated recoverable amount takes into account commodity price
forecasts, expected production, estimated costs and timing of
development, and undeveloped land values.
As a result of declines in the European natural gas price
forecast, which decreased expected cash flows, Vermilion recorded a non-cash impairment
charge of $14.8 million in the
Ireland segment for the three
months ended March 31, 2016. The
recoverable amount of the CGU was determined using a value in use
approach based on forecasted reserves and expected cash flows and
an after-tax discount rate of 9%.
The determination of impairment is sensitive to changes in key
judgments, including reserve revisions, changes in forward
commodity prices and exchange rates, and changes in costs and
timing of development. Changes in these key judgments would impact
the recoverable amount of CGUs, therefore resulting in additional
impairment charges or recoveries. For the three months ended
March 31, 2016, a one percent
increase in the assumed discount rate on expected cash flows of the
Ireland CGU would result in an additional impairment of
$33.7 million, and a five percent
decrease in forward commodity prices would result in an additional
impairment of $50.1 million.
The following table outlines the forward commodity price
estimates that were used in the calculation of the recoverable
amount:
Forward Commodity
Price Assumptions (1)
|
|
|
2016
|
2017
|
2018
|
2019
|
2020
|
2021
|
2022
|
2023
|
2024
|
2025
(2)
|
NBP
(EUR/mmbtu)
|
|
4.55
|
5.39
|
5.95
|
6.47
|
6.68
|
6.81
|
7.03
|
7.10
|
7.18
|
7.37
|
(1)
|
Source: Average of
GLJ Petroleum Consultants and Sproule price forecasts, effective
April 1, 2016.
|
(2)
|
Escalated at 1.75%
per year thereafter.
|
3. EXPLORATION AND EVALUATION ASSETS
The following table reconciles the change in Vermilion's exploration and evaluation
assets:
($M)
|
|
|
Exploration and
Evaluation Assets
|
Balance at
December 31, 2015
|
|
|
308,192
|
Changes in estimate
for asset retirement obligations
|
|
|
8
|
Depreciation
|
|
|
(3,343)
|
Foreign
exchange
|
|
|
(824)
|
Balance at March
31, 2016
|
|
|
304,033
|
4. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the change in Vermilion's asset retirement obligations:
($M)
|
|
|
|
|
|
|
Asset Retirement
Obligations
|
Balance at
December 31, 2015
|
|
|
|
|
|
|
305,613
|
Additional
obligations recognized
|
|
|
|
|
|
|
176
|
Obligations
settled
|
|
|
|
|
|
|
(2,024)
|
Accretion
|
|
|
|
|
|
|
6,109
|
Changes in discount
rates
|
|
|
|
|
|
|
13,144
|
Foreign
exchange
|
|
|
|
|
|
|
(4,037)
|
Balance at March
31, 2016
|
|
|
|
|
|
|
318,981
|
5. LONG-TERM DEBT
The following table summarizes Vermilion's outstanding long-term debt:
|
|
|
|
|
|
As
at
|
($M)
|
|
|
|
|
|
Mar 31,
2016
|
|
Dec 31,
2015
|
Revolving credit
facility
|
|
|
|
|
|
1,429,988
|
|
1,162,998
|
Senior unsecured
notes (1)
|
|
|
|
|
|
-
|
|
224,901
|
Long-term
debt
|
|
|
|
|
|
1,429,988
|
|
1,387,899
|
(1)
|
The senior unsecured
notes, which had a principal balance of $225.0 million, matured and
were repaid on February 10, 2016 and were included in the current
portion of long-term debt as at December 31, 2015.
|
Revolving Credit Facility
At March 31, 2016, Vermilion had in place a bank revolving credit
facility totalling $2 billion, of
which approximately $1.43 billion was
drawn. The facility, which matures on May 31, 2019, is fully revolving up to the date
of maturity.
The facility is extendable from time to time, but not more than
once per year, for a period not longer than four years, at the
option of the lenders and upon notice from Vermilion. If no
extension is granted by the lenders, the amounts owing pursuant to
the facility are due at the maturity date. This facility
bears interest at a rate applicable to demand loans plus applicable
margins. For the three months ended March 31, 2016, the interest rate on the
revolving credit facility was approximately 3.3% (2015 – 3.1%).
The amount available to Vermilion under this facility is reduced by
certain outstanding letters of credit associated with Vermilion's operations totalling $24.7 million as at March
31, 2016 (December 31, 2015 -
$25.2 million).
The facility is secured by various fixed and floating charges
against the subsidiaries of Vermilion. As at March 31, 2016, under the terms of the facility,
Vermilion must maintain:
- A ratio of total borrowings (defined as amounts classified as
"Long-term debt", "Current portion of long term debt", and "Finance
lease obligation" on the balance sheet and referred to collectively
as consolidated total debt), to consolidated net earnings before
interest, income taxes, depreciation, accretion and other certain
non-cash items (defined as consolidated EBITDA) of not greater than
4.0.
- A ratio of consolidated total senior debt (defined as
consolidated total debt excluding unsecured and subordinated debt)
to consolidated EBITDA of not greater than 3.0.
- A ratio of consolidated total senior debt to total
capitalization (defined as amounts classified as "Shareholders'
equity" on the balance sheet plus consolidated total senior debt as
defined above) of not greater than 50%.
As at March 31, 2016, Vermilion was in compliance with all financial
covenants.
6. DEFERRED INCOME TAXES
For the three months ended March 31,
2016, Vermilion
de-recognized an additional $40.3
million (year ended December 31,
2015 - $51.7 million) of
deferred tax assets, relating to certain non-capital losses for
which there is uncertainty as to the Company's ability to fully
utilize such losses when applying forecasted commodity prices in
effect as at March 31, 2016.
7. SHAREHOLDERS' CAPITAL
The following table reconciles the change in Vermilion's shareholders' capital:
Shareholders'
Capital
|
|
|
|
Number of Shares
('000s)
|
|
Amount
($M)
|
Balance as at
December 31, 2015
|
|
|
|
111,991
|
|
2,181,089
|
Shares issued for the
DRIP
|
|
|
|
1,354
|
|
47,990
|
Shares issued for
equity based compensation
|
|
|
|
106
|
|
4,128
|
Balance as at
March 31, 2016
|
|
|
|
113,451
|
|
2,233,207
|
Dividends declared to shareholders for the three months ended
March 31, 2016 were $72.8 million (2015 - $69.4 million).
Subsequent to the end of the period and prior to the condensed
consolidated interim financial statements being authorized for
issue, Vermilion declared
dividends totalling $24.5 million or
$0.215 per share.
8. SEGMENTED INFORMATION
Vermilion's operating
activities in each business unit relate solely to the exploration,
development and production of petroleum and natural gas.
Vermilion has a Corporate head
office located in Calgary,
Alberta. Costs incurred in the Corporate segment relate to
Vermilion's global hedging program
and expenses incurred in financing and managing the Company's
operating business units.
Vermilion's chief operating
decision maker reviews the financial performance of the Company by
assessing the fund flows from operations of each business unit
individually. Fund flows from operations provides a measure
of each business unit's ability to generate cash (that is not
subject to short-term movements in non-cash operating working
capital) necessary to pay dividends, fund asset retirement
obligations, and make capital investments.
|
Three Months Ended
March 31, 2016
|
($M)
|
Canada
|
France
|
Netherlands
|
Germany
|
Ireland
|
Australia
|
United
States
|
Corporate
|
Total
|
Total
assets
|
1,584,947
|
833,145
|
195,413
|
159,522
|
838,240
|
240,352
|
44,585
|
176,136
|
4,072,340
|
Drilling and
development
|
29,771
|
13,463
|
2,996
|
539
|
3,076
|
7,827
|
5,101
|
-
|
62,773
|
Oil and gas sales to
external
|
|
|
|
|
|
|
|
|
|
customers
|
56,110
|
48,125
|
27,286
|
7,692
|
17,004
|
19,935
|
1,233
|
-
|
177,385
|
Royalties
|
(5,498)
|
(6,766)
|
(460)
|
(867)
|
-
|
-
|
(370)
|
-
|
(13,961)
|
Revenue from external
customers
|
50,612
|
41,359
|
26,826
|
6,825
|
17,004
|
19,935
|
863
|
-
|
163,424
|
Transportation
|
(4,151)
|
(3,713)
|
-
|
(887)
|
(1,639)
|
-
|
-
|
-
|
(10,390)
|
Operating
|
(21,343)
|
(14,320)
|
(5,976)
|
(2,593)
|
(3,626)
|
(7,491)
|
(279)
|
-
|
(55,628)
|
General and
administration
|
(2,476)
|
(4,676)
|
(773)
|
(2,428)
|
(1,188)
|
(1,325)
|
(1,132)
|
421
|
(13,577)
|
PRRT
|
-
|
-
|
-
|
-
|
-
|
(128)
|
-
|
-
|
(128)
|
Corporate income
taxes
|
-
|
(34)
|
(2,200)
|
-
|
-
|
(777)
|
-
|
(149)
|
(3,160)
|
Interest
expense
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
(14,750)
|
(14,750)
|
Realized gain on
derivative
|
|
|
|
|
|
|
|
|
|
instruments
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
28,423
|
28,423
|
Realized foreign
exchange loss
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
(652)
|
(652)
|
Realized other
income
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
105
|
105
|
Fund flows from
operations
|
22,642
|
18,616
|
17,877
|
917
|
10,551
|
10,214
|
(548)
|
13,398
|
93,667
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
March 31, 2015
|
($M)
|
Canada
|
France
|
Netherlands
|
Germany
|
Ireland
|
Australia
|
United
States
|
Corporate
|
Total
|
Total
assets
|
1,968,024
|
905,476
|
202,428
|
161,455
|
817,638
|
256,003
|
15,317
|
136,057
|
4,462,398
|
Drilling and
development
|
114,849
|
34,114
|
4,333
|
968
|
12,955
|
6,455
|
637
|
-
|
174,311
|
Oil and gas sales to
external
|
|
|
|
|
|
|
|
|
|
customers
|
77,884
|
59,832
|
26,818
|
11,395
|
-
|
19,284
|
672
|
-
|
195,885
|
Royalties
|
(8,592)
|
(5,102)
|
(926)
|
(1,598)
|
-
|
-
|
(206)
|
-
|
(16,424)
|
Revenue from external
customers
|
69,292
|
54,730
|
25,892
|
9,797
|
-
|
19,284
|
466
|
-
|
179,461
|
Transportation
|
(3,942)
|
(3,011)
|
-
|
(894)
|
(1,693)
|
-
|
-
|
-
|
(9,540)
|
Operating
|
(19,099)
|
(10,826)
|
(5,826)
|
(1,999)
|
-
|
(5,886)
|
(215)
|
-
|
(43,851)
|
General and
administration
|
(4,015)
|
(5,111)
|
(737)
|
(1,608)
|
(512)
|
(1,454)
|
(1,080)
|
957
|
(13,560)
|
PRRT
|
-
|
-
|
-
|
-
|
-
|
(2,354)
|
-
|
-
|
(2,354)
|
Corporate income
taxes
|
-
|
(14,281)
|
(2,388)
|
-
|
-
|
(577)
|
-
|
(377)
|
(17,623)
|
Interest
expense
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
(13,298)
|
(13,298)
|
Realized gain on
derivative
|
|
|
|
|
|
|
|
|
|
instruments
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
6,257
|
6,257
|
Realized foreign
exchange gain
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
3,306
|
3,306
|
Realized other
income
|
-
|
31,775
|
-
|
-
|
-
|
-
|
-
|
222
|
31,997
|
Fund flows from
operations
|
42,236
|
53,276
|
16,941
|
5,296
|
(2,205)
|
9,013
|
(829)
|
(2,933)
|
120,795
|
Reconciliation of fund flows from operations to net (loss)
earnings
|
|
|
|
Three Months
Ended
|
|
|
|
|
Mar
31,
|
Mar
31,
|
($M)
|
|
|
|
2016
|
2015
|
Fund flows from
operations
|
|
|
|
93,667
|
120,795
|
Equity based
compensation
|
|
|
|
(20,837)
|
(19,040)
|
Unrealized gain
(loss) on derivative instruments
|
|
|
|
9,054
|
(19,970)
|
Unrealized foreign
exchange gain (loss)
|
|
|
|
1,570
|
(4,845)
|
Unrealized other
expense
|
|
|
|
(87)
|
(261)
|
Accretion
|
|
|
|
(6,109)
|
(5,675)
|
Depletion and
depreciation
|
|
|
|
(125,798)
|
(90,957)
|
Deferred
taxes
|
|
|
|
(22,546)
|
21,228
|
Impairment
|
|
|
|
(14,762)
|
-
|
Net (loss)
earnings
|
|
|
|
(85,848)
|
1,275
|
9. FINANCIAL INSTRUMENTS
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.
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.
Cash and cash equivalents are classified as Level 1
measurements. Cash and cash equivalents, receivables, and payables
approximate their value due to the short-term nature of those
instruments.
Derivative assets, derivative liabilities, and the fair value of
long-term debt outstanding on the revolving credit facility are
classified as Level 2 measurements. The fair value 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 fair value of long-term debt
on the revolving credit facility approximates carrying value due to
the use of short-term borrowing instruments at market rates of
interest.
Vermilion does not have any
financial instruments classified as Level 3 measurements.
Nature and Extent of Risks Arising from Financial
Instruments
Market risk:
Vermilion's financial instruments
are exposed to currency risk related to changes in foreign currency
denominated financial instruments and commodity price risk related
to outstanding derivatives. The following table summarizes
the impact on comprehensive income before tax for the three months
ended March 31, 2016 given changes in
the relevant risk variables that Vermilion considers 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
|
March 31,
2016
|
Currency risk - Euro
to Canadian
|
5% increase in
strength of the Canadian dollar against the Euro
|
(3,535)
|
|
5% decrease in
strength of the Canadian dollar against the Euro
|
3,535
|
|
|
|
Currency risk - US $
to Canadian
|
5% increase in
strength of the Canadian dollar against the US $
|
2,323
|
|
5% decrease in
strength of the Canadian dollar against the US $
|
(2,323)
|
|
|
|
Commodity price
risk
|
US $5.00/bbl
increase in crude oil price used to determine the fair value of
derivatives
|
(3,330)
|
|
US $5.00/bbl
decrease in crude oil price used to determine the fair value of
derivatives
|
3,330
|
|
|
|
|
€ 0.5/GJ
increase in European natural gas price used to determine the
fair value of derivatives
|
(23,184)
|
|
€ 0.5/GJ
decrease in European natural gas price used to determine the
fair value of derivatives
|
23,184
|
|
|
|
Interest rate
risk
|
1% increase in
average Canadian prime interest rate
|
(2,329)
|
|
1% decrease in
average Canadian prime interest rate
|
2,329
|
SOURCE Vermilion Energy Inc.