Vermilion Energy Inc. Announces Results for the Three and Nine Months Ended September 30, 2014

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Nov 10, 2014, 02:10 ET

CALGARY, Nov. 10, 2014 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and unaudited financial results for the three and nine months ended September 30, 2014.

HIGHLIGHTS

Achieved average production of 49,920 boe/d during Q3 2014, a decrease of 4% as compared to 52,089 boe/d in the prior quarter and an increase of 20% compared to 41,510 boe/d in Q3 2013. Lower quarter-over-quarter production was primarily due to a 7% decrease in Canada resulting from lower levels of drilling and completions activity during spring breakup, and managed production in Australia and the Netherlands consistent with overall corporate production targets. Quarter-over-quarter declines from lower Canadian activity were partially offset by inclusion of a full quarter of production from our southeast Saskatchewan acquisition, which closed in late April 2014. Q3 production volumes in the Netherlands were also affected by unscheduled downtime at our Garijp treating facility.
Generated fund flows from operations⁽¹⁾ in Q3 2014 of $197.9 million ($1.85/basic share), as compared to $216.1 million ($2.05/basic share) in the prior quarter and $165.6 million ($1.63/basic share) in Q3 2013. The quarter-over-quarter decrease was primarily attributable to lower commodity pricing during Q3 2014, and a combined build in crude oil inventories in France and Australia of approximately 104,000 bbls.
Completed our first Duvernay horizontal appraisal well (35% working interest), which is located along a shared lease-line in the Pembina block. This three-quarter mile long well was brought on production subsequent to the end of the third quarter and has produced for 16 days. Raw gas rate has averaged 2.2 mmcf/d (expected sales gas rate of 1.8 mmcf/d after liquids shrink and plant fuel) with an estimated hydrocarbon liquids rate of approximately 180 bbls/d (approximately 60% pentanes plus). The well is producing at restricted rates using a 12/64 inch downhole choke to generate an estimated flowing bottomhole pressure of 4,200 psi (approximately 55% drawdown). Our second Duvernay horizontal appraisal well (100% working interest), located in the Edson block, is expected to be brought on production late in Q4 2014.
Drilled our first well in the Netherlands on lands acquired in October 2013. The Diever-02 exploration well (45% working interest), in the Drenthe IIIb concession, encountered two well-developed gas bearing intervals (Akkrum and Slochteren) with a net pay thickness of approximately 36 metres. A three-hour clean-up test was conducted on the Slochteren formation which delivered 25.7 mmcf/d of gas on a 40/64 inch choke with 2,615 psi flowing tubing pressure with no indications of pressure drop during the test⁽³⁾. The flow rate was limited by the 3.5 inch diameter of the tubing and the capacity of the test equipment. The well is expected to be tied-in with production from the Slochteren formation in Q4 2015 at an estimated rate of approximately 1,000 boe/d, net to Vermilion. The Akkrum formation will be perforated at a later date once the Slochteren formation has been fully produced.
Subsequent to the end of the third quarter, drilled a gas discovery well in the Netherlands at the Langezwaag-02 location (42.3% working interest) in the Gorredijk concession. This extended reach well recorded significant gas shows in two metres of Vlieland Sandstone and 21 metres of Zechstein-2 Carbonate. Open hole logs could not be run in the highly deviated well. The Langezwaag-02 well was first flow tested from the Zechstein-2 Carbonate at 12.4 mmcf/d through a 48/64 inch choke at a flowing tubing pressure of approximately 1,300 psi. A second flow test in the Vlieland Sandstone yielded rates of 2.7 mmcf/d through a 32/64 inch choke at a flowing tubing pressure of approximately 960 psi.
Subsequent to the end of the third quarter, recorded first production from the Deblinghausen Z7a well (25% working interest) in Germany. This well was drilled earlier in 2014 by operator ExxonMobil Production Deutschland GmbH, and encountered 81 metres of Zechstein Carbonate pay. Initial gross production rates are approximately 16.5 mmcf/d of raw gas at a flowing tubing pressure of approximately 1,300 psi.
Successfully expanded our southeast Saskatchewan land base through the purchase at Crown land sales of an additional approximately 15,000 net acres of undeveloped land to the northwest of our existing lands at an average cost of approximately $1,860 per acre.
Completed our first acquisition in the United States at a cost of approximately $11.1 million. Through the transaction, we acquired approximately 68,000 acres of land (98% undeveloped) in the Powder River basin of northeastern Wyoming with current working interest production of approximately 200 bbls/d (100% oil), proved plus probable reserves estimated at 2.2² million boe (82% oil) and contingent resource of 10.0²million boe (82% oil). Transaction metrics, with no deduction for land value, equate to approximately $56,000 per boe/d and $20.98 per boe, including future development costs of approximately $35.3 million. The land base includes 53,000 net acres at an average operated working interest of 70% in a promising tight oil project in the Turner Sand at a depth of approximately 1,500 metres.
Our Corrib project in Ireland has continued to progress on schedule following the completion of tunnel boring operations in May 2014. Project operator Shell Exploration & Production Ireland Ltd. (SEPIL) successfully completed offshore workover and pipeline operations during the third quarter. SEPIL also significantly advanced tunnel outfitting, which is now estimated to be approximately 95% complete. Remaining activities include completion of tunnel outfitting and grouting, commissioning of the gas processing facility, and finalization of operating permits. We anticipate first gas from Corrib in approximately mid-2015, with peak production estimated at approximately 58 mmcf/d (approximately 9,700 boe/d) net to Vermilion.
We are revising our 2014 average annual production guidance from the previous range of 48,500-49,500 boe/d to a range of 49,000-49,500 boe/d, and expect full year production to be near the upper end of this new range. We currently anticipate providing 2015 production and capital expenditure guidance in early December 2014.
We celebrated our 20^th Anniversary as a publicly traded company in 2014. This has been a rewarding period of growth and achievement for our company, and we are proud of our progress to date. Most importantly, we are honored to have provided our shareholders with a compound average total return including dividends, as of September 30, 2014, of 36.4% per annum since our inception. With the consistent strength of our operations and our extensive opportunity base, we will strive to provide continued strong financial performance, and a reliable and growing dividend stream to investors.

⁽¹⁾	Additional GAAP Financial Measure. Please see the "Additional and Non-GAAP Financial Measures" section of Management's Discussion and Analysis.
⁽²⁾	Estimated proved plus probable reserves and contingent resources attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. in a report dated October 28, 2014, with an effective date of July 1, 2014, using the GLJ (2014-07) price forecast.
⁽³⁾	Test results are not necessarily indicative of long-term production performance or of ultimate recovery.

Vermilion Energy Inc. Third Quarter 2014 Conference Call and Audio Webcast Details

Vermilion will discuss these results in a conference call to be held on Monday, November 10, 2014 at 9:00 AM MST (11:00 AM EST). To participate, you may call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). The conference call will also be available on replay by calling 1-855-859-2056 using conference ID number 6117964. The replay will be available until midnight eastern time on November 17, 2014.

You may also listen to the audio webcast at http://event.on24.com/r.htm?e=852632&s=1&k=79DE9E8E7910A2E76368C9BFBF328E76 or visit Vermilion's website at www.vermilionenergy.com/ir/eventspresentations.cfm.

DISCLAIMER

Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted present value of future net cash flows from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; estimated contingent resources and prospective resources; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; the timing of regulatory proceedings and approvals; and the timing of first commercial natural gas and the estimate of Vermilion's share of the expected natural gas production from the Corrib field.

Such forward looking statements or information are based on a number of assumptions all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.

Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids and natural gas prices, foreign currency exchange rates and interest rates; health, safety and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.

The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.

All oil and natural gas reserve information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. The actual oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document. The estimated future net revenue from the production of oil and natural gas reserves does not represent the fair market value of these reserves.

Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.

ABBREVIATIONS

$M		thousand dollars
$MM		million dollars
AECO		the daily average benchmark price for natural gas at the AECO 'C' hub in southeast Alberta
bbl(s)		barrel(s)
bbls/d		barrels per day
bcf		billion cubic feet
boe		barrel of oil equivalent, including: crude oil, natural gas liquids and natural gas (converted on the basis of one boe for
		six mcf of natural gas)
boe/d		barrel of oil equivalent per day
GJ		gigajoules
mbbls		thousand barrels
mboe		thousand barrel of oil equivalent
mcf		thousand cubic feet
mcf/d		thousand cubic feet per day
mmboe		million barrel of oil equivalent
mmcf		million cubic feet
mmcf/d		million cubic feet per day
MWh		megawatt hour
NGLs		natural gas liquids
PRRT		Petroleum Resource Rent Tax, a profit based tax levied on petroleum projects in Australia
TTF		the day-ahead price for natural gas in the Netherlands, quoted in MWh of natural gas, at the Title Transfer Facility
		Virtual Trading Point operated by Dutch TSO Gas Transport Services
WTI		West Texas Intermediate, the reference price paid for crude oil of standard grade in US dollars at Cushing, Oklahoma

HIGHLIGHTS

		Three Months Ended			Nine Months Ended
($M except as indicated)		Sep 30,	Jun 30,	Sep 30,	Sep 30,	Sep 30,
Financial		2014	2014	2013	2014	2013
Petroleum and natural gas sales		344,688	387,684	327,185	1,113,555	948,727
Fund flows from operations⁽¹⁾		197,898	216,076	165,645	619,337	503,866
	Fund flows from operations ($/basic share)	1.85	2.05	1.63	5.90	5.01
	Fund flows from operations ($/diluted share)	1.83	2.01	1.61	5.81	4.94
Net earnings		53,903	53,993	67,796	210,684	226,131
	Net earnings ($/basic share)	0.50	0.51	0.67	2.01	2.25
Capital expenditures		190,033	135,073	135,661	521,481	394,248
Acquisitions		40,847	381,139	7,586	600,213	7,586
Asset retirement obligations settled		4,677	2,381	2,738	9,709	6,496
Cash dividends ($/share)		0.645	0.645	0.600	1.935	1.800
Dividends declared		68,896	68,710	61,003	203,613	181,391
	% of fund flows from operations	35%	32%	37%	33%	36%
Net dividends⁽¹⁾		48,480	49,561	41,649	145,163	127,875
	% of fund flows from operations	24%	23%	25%	23%	25%
Payout⁽¹⁾		243,190	187,015	180,048	676,353	528,619
	% of fund flows from operations	123%	87%	109%	109%	105%
	% of fund flows from operations (excluding the Corrib project)	107%	73%	87%	97%	89%
Net debt⁽¹⁾		1,243,438	1,168,998	700,286	1,243,438	700,286
Ratio of net debt to annualized fund flows from operations⁽¹⁾		1.6	1.4	1.1	1.5	1.0
Operational
Production
	Crude oil (bbls/d)	29,147	30,184	26,664	28,890	25,640
	NGLs (bbls/d)	2,354	2,892	1,945	2,463	1,719
	Natural gas (mmcf/d)	110.52	114.08	77.41	109.33	81.97
	Total (boe/d)	49,920	52,089	41,510	49,574	41,020
Average realized prices
	Crude oil and NGLs ($/bbl)	102.49	109.89	108.87	108.02	103.95
	Natural gas ($/mcf)	5.74	6.19	6.00	6.60	6.68
Production mix (% of production)
	% priced with reference to WTI	28%	30%	24%	27%	24%
	% priced with reference to AECO	18%	18%	17%	18%	17%
	% priced with reference to TTF	18%	18%	14%	18%	16%
	% priced with reference to Dated Brent	36%	34%	45%	37%	43%
Netbacks ($/boe)⁽¹⁾
	Operating netback	54.25	59.52	61.91	58.95	60.12
	Fund flows from operations netback	44.08	46.24	43.60	46.02	44.13
	Operating expenses	12.53	12.46	12.17	12.81	12.87
Average reference prices
	WTI (US $/bbl)	97.17	102.99	105.82	99.61	98.14
	Edmonton Sweet index (US $/bbl)	89.24	96.85	101.10	92.17	93.03
	Dated Brent (US $/bbl)	101.85	109.63	110.37	106.57	108.45
	AECO ($/GJ)	3.81	4.44	2.31	4.56	2.89
	TTF ($/GJ)	7.26	7.91	9.94	8.41	10.17
Average foreign currency exchange rates
	CDN $/US $	1.09	1.09	1.04	1.09	1.02
	CDN $/Euro	1.44	1.50	1.38	1.48	1.35
Share information ('000s)
Shares outstanding - basic		106,921	106,620	101,787	106,921	101,787
Shares outstanding - diluted⁽¹⁾		109,749	109,371	104,195	109,749	104,195
Weighted average shares outstanding - basic		106,768	105,577	101,613	104,891	100,634
Weighted average shares outstanding - diluted⁽¹⁾		108,290	107,330	102,763	106,582	102,083

⁽¹⁾	The above table includes additional GAAP and non-GAAP financial measures which may not be comparable to other companies. Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis.

MESSAGE TO SHAREHOLDERS

In 2014, we celebrated Vermilion's 20^th anniversary as a publicly traded company. It has been a demanding, but also a tremendously rewarding 20 years. During this time, we have witnessed significant change and encountered many challenges to the industry, and we are particularly proud of our demonstrated ability to effectively navigate those challenges to the benefit of our shareholders. Today's environment is no different. The recent volatility in the capital markets, and more particularly in the energy sector (due to a rapid fall in commodity prices and near term price expectations), creates yet another opportunity for us to demonstrate the sustainability of our business model and the advantages of our diversified portfolio. Vermilion's relative performance during this period has once again demonstrated the stable and defensive nature of our business, our strong positioning within the industry, and our shareholders' continued confidence in our ability to prosper. Our balance sheet remains strong and we believe our longer-term focus, combined with our conservative approach and patience, will allow us to create further opportunity for our shareholders in the current environment.

Reflecting on Vermilion's record, we are pleased that our previous efforts have resulted in a compound average total return including dividends, as of September 30, 2014, of 36.4% per annum since inception. We are also proud of the consistency of those returns. Over the last one, three, five, ten and 15 calendar-year periods, we have reliably delivered double-digit compound average total returns of 24.6%, 14.5%, 24.0%, 18.6% and 25.5%, respectively.

In spite of current commodity price weakness, we continue to believe that Vermilion is better situated for continued growth than at any other time in our history. With the consistent performance of our operations and our expansive and growing opportunity base, we remain confident that we are positioned to deliver continued strong operational and financial performance in the future, while also providing a reliable and growing dividend stream to our shareholders.

We are confident that the assets in our current portfolio contain significant opportunity for growth for years to come. In the current environment, we also find ourselves positioned to enhance growth in shareholder value and further diversify our opportunity base through acquisition activity in both North American and international markets.

In February 2014 we announced our entry into Germany. Germany has a long history of oil and gas development activity, low political risk and strong marketing fundamentals. The acquisition provides us with entry into this sizable market, in the form of free cash flow⁽¹⁾ generating, low-decline assets with near-term development inventory in addition to longer-term, low-permeability gas prospectivity. We believe that our conventional and unconventional expertise, coupled with new access to proprietary technical data, will position us for future development and expansion opportunities in both Germany and the greater European region.

In late April 2014 we announced the completion of our acquisition of Elkhorn Resources Inc., a private southeast Saskatchewan producer. The acquired assets consist of high netback, light oil production in the Northgate region of southeast Saskatchewan and include approximately 57,000 net acres of land (approximately 80% undeveloped), seven oil batteries, and preferential access to 50% or greater capacity at a solution gas facility that is currently under construction.

In addition, we recently completed an $11.1 million transaction which marks our first acquisition in the United States, representing a low-cost entry position in the prolific Powder River Basin of northeastern Wyoming. The transaction provides a promising tight oil development project, and we have put in place the human resources necessary to support future organic growth and acquisitions in the region. Through the transaction, we acquired approximately 68,000 acres of land (98% undeveloped) with current working interest production of approximately 200 bbls/d (100% oil), proved plus probable reserves estimated at 2.2⁽²⁾ million boe (82% oil) and contingent resource of 10.0⁽²⁾ million boe (82% oil). Transaction metrics, with no deduction for land value, equate to approximately $56,000 per boe/d and $20.98 per boe, including future development costs of approximately $35.3 million. The land base includes 53,000 net acres at a 70% operated working interest in a promising tight oil project in the Turner Sand at a depth of approximately 1,500 metres. The most recently completed well on this land block (70% working interest) is currently producing approximately 220 bbls/d of oil in its fourth month of production, from an approximately 1,100 metre hydraulically-fractured horizontal lateral.

Looking ahead we see continued opportunity for expansion. In North America, we are faced with an active asset market and we continue to see technology unlocking new opportunities for development. With Vermilion's access to relatively low cost capital, our conservative balance sheet, and significant near-term free cash flow growth on the horizon (including from Corrib, which is expected to commence production in mid-2015), we are well positioned to compete and transact should suitable opportunities arise. While international asset markets remain substantially less liquid than in North America, we similarly find ourselves well-positioned for assets that do become available in our selective regions of interest.

The third quarter of 2014 marks another quarter of consistent operational execution for our Company. We continue to achieve strong results from our successful Mannville condensate-rich gas and Cardium light-oil development programs in Canada. Our strong Cardium results reflect continued improvements in completions design and better-than-forecasted production volumes on several of our two-mile extended reach horizontal Cardium wells. With improving efficiencies and productivity, we will require less capital than originally anticipated to meet our development objectives for the Cardium. As a result, we are able to increase our current focus on development of our extensive Mannville resource base which has generated very robust economics to-date. Looking forward, we anticipate our Mannville drilling activity will continue to increase in future years as we continue to develop our substantial inventory of highly economic prospects. During the quarter we also initiated a two-rig, 12-well Midale drilling program in southeast Saskatchewan. We have currently identified approximately 190 net potential drilling locations targeting the Midale, Frobisher, Bakken, and Three Forks/Torquay formations on our southeast Saskatchewan lands. In addition, we have expanded our southeast Saskatchewan land base during the quarter through the purchase at Crown land sales of approximately 15,000 net acres of undeveloped land to the northwest of our existing lands, adding an estimated 60 new development locations.

The appraisal of our position in the Duvernay condensate-rich resource play continues. To-date, we have amassed 317 net sections at the relatively low cost of $76 million ($375/acre). Our position comprises three largely contiguous blocks in the Edson, West Pembina and Niton areas. To date, we have drilled three vertical stratigraphic test wells, and have completed drilling operations on two horizontal appraisal wells. The first horizontal appraisal well drilled (1,180 meters horizontal length) is located in the downdip part of our Edson block where condensate yields are expected to be lower than the average of our overall land position. We selected this location because of its proximity to one of our vertical stratigraphic test wells, allowing us to conduct microseismic monitoring in the stratigraphic test well when we frac the horizontal well (expected to occur during the fourth quarter of 2014). Our second horizontal appraisal well (1,280 meters horizontal length), which we operate at a 34.8% working interest, is located along a shared lease-line in the Pembina block to allow partner participation. Completion activities on the Pembina well, including microseismic monitoring, were completed during the third quarter. The well was brought on production in October 2014 and has produced for 16 days. Raw gas rate has averaged 2.2 mmcf/d (expected sales gas rate of 1.8 mmcf/d after liquids shrink and plant fuel) with an estimated hydrocarbon liquids rate of approximately 180 bbls/d (approximately 60% pentanes plus). The well is producing at restricted rates using a 12/64 inch downhole choke to generate an estimated flowing bottomhole pressure of 4,200 psi (approximately 55% drawdown). Our Edson Duvernay horizontal appraisal well (100% working interest) is expected to be brought on production late in Q4 2014.

Our development-phase target for Duvernay well costs (including drill, complete, equip and tie-in) is $12 to $15 million. We believe that development-phase savings will be achievable through learning-curve improvements, lower lease construction costs, economies of scale in procurement and lower evaluation expenditures (such as the elimination of microseismic monitoring). We anticipate that the production results and interpreted fracture geometries from the microseismic data on these appraisal wells will assist us in optimizing completions on future development-phase horizontal wells. We are confident that we will be able to project the appraisal well results to higher condensate yield locations as we move to the northeast in our acreage position, which encompasses the entire breadth of the condensate-rich window. Our Duvernay rights generally underlie our Cardium oil and Mannville condensate-rich gas rights, which creates the potential for infrastructure, operational, and timing advantages if we progress to full development of the Duvernay condensate-rich resource play. In combination, our Cardium, Mannville, and Duvernay positions provide us with exploration and development opportunities in our core Canadian operating region that have the potential to deliver strong production and reserve growth into the next decade.

We were also active in Europe during the third quarter of 2014 with ongoing drilling operations in both France and the Netherlands. In France, we completed our five-well Champotran drilling campaign in the Paris Basin during the quarter. The five wells were brought on production at various times during the third quarter and are producing at oil rates averaging approximately 200 bbls/d per well. The final well of our 2014 drilling campaign in France (Tamaris in the Aquitaine Basin) is anticipated to be drilled and completed during the fourth quarter. During the third quarter of 2014, we furthered preparations for the phased transfer of our shut-in Vic Bilh natural gas production from the Lacq gas processing facility where it was previously handled to a new third party facility. Delays in receiving required permit transfers have pushed our original plans to bring approximately 850 mcf/d of solution gas back on-stream from the third quarter of 2014 to early 2015. The remainder of the shut-in gas production, approximately 3,400 mcf/d of gas cap gas, is expected to be back on production in early 2016.

In the Netherlands, we drilled the Diever-02 exploratory well (45% working interest) during the third quarter in the Drenthe IIIb concession on lands acquired in October 2013. This well primarily targeted the Rotliegend Group (Permian sandstones) and encountered two well-developed gas bearing intervals (Akkrum and Slochteren) with a net pay thickness of approximately 36 metres. A three-hour clean-up test was conducted on the Slochteren formation which delivered 25.7 mmcf/d of gas on a 40/64 inch choke with 2,615 psi flowing tubing pressure with no indications of pressure drop during the test⁽³⁾. The flow rate was limited by the 3.5 inch diameter of the tubing and the capacity of the test equipment. The well is expected to be tied-in with production from the Slochteren formation in Q4 2015 at an estimated rate of approximately 1,000 boe/d, net to Vermilion. The Akkrum formation is anticipated to be perforated at a later date once the Slochteren formation has been fully produced.

Subsequent to the end of the third quarter, we drilled a gas discovery well in the Netherlands at the Langezwaag-02 location (42.3% working interest) in the Gorredijk concession. This extended reach well recorded significant gas shows in two metres of Vlieland Sandstone and 21 metres of Zechstein-2 Carbonate. Open hole logs could not be run in the highly deviated well. The Langezwaag-02 well was first flow tested from the Zechstein-2 Carbonate at 12.4 mmcf/d through a 48/64 inch choke at a flowing tubing pressure of approximately 1,300 psi. A second flow test in the Vlieland Sandstone yielded rates of 2.7 mmcf/d through a 32/64 inch choke at a flowing tubing pressure of approximately 960 psi. The remaining well of the 2014 drilling campaign is expected to be drilled and completed during the fourth quarter of 2014.

Our newly acquired position in Germany enables us to participate, on a non-operated basis, in the exploration, development, production and transportation of natural gas from four gas producing fields across 11 production licenses. The assets include both exploration and production licenses that comprise a total of 207,000 gross acres, of which 85% is in the exploration license. During the first quarter of 2014, we participated in the drilling of the Deblinghausen Z7a development well (25% working interest) in Germany. The well logged 81 metres of net pay in the Zechstein Carbonate, and was tested in late September 2014 for a period of 17 days. During production testing, the well produced at an average rate of 10.2 mmcf/d at a flowing tubing pressure of 1,840 psi⁽³⁾. Subsequent to the end of the quarter, this well was placed on production at an initial gross production rate of 16.5 mmcf/d of raw gas at a flowing tubing pressure of approximately 1,300 psi.

Our Corrib project in Ireland has continued to progress on schedule following the completion of tunnel boring operations in May 2014. Project operator Shell Exploration & Production Ireland Ltd. (SEPIL) successfully completed offshore workover and pipeline operations during the third quarter and the wells are ready for operation. SEPIL also significantly advanced tunnel outfitting, which is now estimated to be approximately 95% complete following installation of flow and umbilical lines in the 4.9 km tunnel. Remaining activities include final cable installation, hydro-testing and grouting, as well as commissioning of the gas processing facility and finalization of operating permits. We anticipate first gas from Corrib in approximately mid-2015, with peak production estimated at approximately 58 mmcf/d (approximately 9,700 boe/d) net to Vermilion.

In Australia, we remain focused on completing preparations for a two-well drilling program in 2015, as well as re-lifing and maintenance projects on our two platforms. In order to provide long-term certainty to purchasers of the high-value oil from Wandoo, our current plan is to maintain field-total production levels within our prior guidance of between 6,000 bbls/d and 8,000 bbls/d. We anticipate maintaining these production levels in Australia for the foreseeable future with drilling programs approximately every two years. Our Australian oil currently garners a premium of up to US$7.00 to the Dated Brent index and incurs no transportation cost as production is sold directly at the platform.

Our operations continue to perform strongly, generating organic production growth in a capital-efficient manner. We are moving up our 2014 average annual production guidance from the previous range of 48,500-49,500 boe/d to a range of 49,000-49,500 boe/d, and expect full year production to be near the upper end of this refined range. Assuming commodity prices remain near current levels for the remainder of 2014, we continue to anticipate that we can fully fund our net dividends⁽¹⁾and development capital expenditures (excluding capital investment at Corrib) with fund flows from operations⁽¹⁾ during 2014.

We believe we remain positioned to deliver strong operational and financial performance over the next several years. We continue to target annual organic production growth of 5% to 7% while providing reliable and growing dividends. Near term production and fund flows from operations growth is expected to be driven by continued Cardium and Mannville development in Canada, oil development activities in France, and high-netback natural gas drilling in the Netherlands. A significant increment of production, fund flows from operations and free cash flow growth is expected from Corrib beginning in approximately mid-2015 with the first full year of production from the project in 2016. Our Australian and German business units are expected to provide relatively steady production as well as strong free cash flow.

In keeping with our strategy of pursuing long-term growth in our three core regions in North America, Europe and Australia, we have established two new offices led by locally-experienced management with strong track records of success. As the operating headquarters of our new U.S. Business Unit, we have opened an office in Denver, Colorado. Daniel Anderson has joined Vermilion as Managing Director for our U.S. subsidiary. Mr. Anderson has 30 years of experience in the upstream and midstream energy sectors throughout the U.S. He was formerly President of Baytex Energy USA, with previous management and technical roles at Berry Petroleum, Williams Companies, Santa Fe Snyder and ConocoPhillips. Mr. Anderson has a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines. Further strengthening our capabilities for growth in the U.S., Timothy Morris has joined Vermilion as Director of U.S. Business Development. Mr. Morris has more than 30 years of experience in land management and business development in the U.S. He was formerly Vice President of U.S. Business Development for Baytex Energy Corporation, with previous management and land roles at Berco Resources, Santa Fe Snyder and Sohio. Mr. Morris has a Bachelor of Science degree in Minerals Land Management from the University of Colorado and is a Certified Petroleum Landman.

As the operating headquarters of our German Business Unit, we have established an office in Berlin. Albrecht Möhring has been appointed Managing Director of Vermilion's German Business Unit. Mr. Möhring brings 30 years of diverse experience in the energy business to Vermilion. He was formerly Managing Director for Germany with GDF Suez, with previous roles as Group Exploration and Operations Manager in Paris for GDF Suez and in management with Preussag Energie in Germany (the predecessor of GDF Suez in Germany). Mr. Möhring has a Master of Science degree in Petroleum Engineering from the University of Clausthal.

The management and directors of Vermilion continue to hold approximately 6% of the outstanding shares and remain committed to delivering superior rewards to all stakeholders. Continuing to be acknowledged for excellence in our business practices, Vermilion was recognized for the fifth consecutive year by the Great Place to Work® Institute in both Canada and France in 2014. In Canada, Vermilion was ranked 5^th Best Workplace in its category for 2014. More than 300 Canadian companies participated in the survey and Vermilion was the only energy company in Canada to be recognized as a Best Workplace. In France, Vermilion received a special award for corporate social responsibility and was ranked 13^th Best Workplace in its category for 2014. Vermilion's Netherlands business unit became eligible to participate in the competition for the first time in 2014 and was ranked 10^th Best Workplace in its category, the highest score of any energy company in the survey. In October 2014 Vermilion was ranked second out of 13 in our peer group by the Carbon Disclosure Project (CDP) for our disclosure in 2014, our inaugural year of participation with Vermilion scoring 87 out of 100 (10 points higher than any peer group company achieved in its inaugural year of participation).

⁽¹⁾	The above discussion includes additional GAAP and non-GAAP measures which may not be comparable to other companies. Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis.
⁽²⁾	Estimated proved plus probable reserves and contingent resources attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. in a report dated October 28, 2014, with an effective date of July 1, 2014, using the GLJ (2014-07) price forecast.
⁽³⁾	Test results are not necessarily indicative of long-term production performance or of ultimate recovery.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following is Management's Discussion and Analysis ("MD&A"), dated November 6, 2014, of Vermilion Energy Inc.'s ("Vermilion" or the "Company") operating and financial results as at and for the three and nine months ended September 30, 2014 compared with the corresponding periods in the prior year.

This discussion should be read in conjunction with the unaudited condensed consolidated interim financial statements for the three and nine months ended September 30, 2014 and the audited consolidated financial statements for the year ended December 31, 2013 and 2012, together with accompanying notes. Additional information relating to Vermilion, including its Annual Information Form, is available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.

The unaudited condensed consolidated interim financial statements for the three and nine months ended September 30, 2014 and comparative information have been prepared in Canadian dollars, except where another currency is indicated, and in accordance with IAS 34, "Interim financial reporting", as issued by the International Accounting Standard Board ("IASB").

This MD&A includes references to certain financial measures which do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS"). As such, these financial measures are considered additional GAAP or non-GAAP financial measures and therefore are unlikely to be comparable with similar financial measures presented by other issuers. These additional GAAP and non-GAAP financial measures include:

Fund flows from operations: This additional GAAP financial measure is calculated as cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled. We analyze fund flows from operations both on a consolidated basis and on a business unit basis in order to assess the contribution of each business unit to our ability to generate cash necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments.
Netbacks: These non-GAAP financial measures are per boe and per mcf measures used in the analysis of operational activities. We assess netbacks both on a consolidated basis and on a business unit basis in order to compare and assess the operational and financial performance of each business unit versus other business units and third party crude oil and natural gas producers.

For a full description of these and other non-GAAP financial measures and a reconciliation of these measures to their most directly comparable GAAP measures, please refer to "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES".

VERMILION'S BUSINESS

Vermilion is a Calgary, Alberta based international oil and gas producer focused on the acquisition, development and optimization of producing properties in Western Canada, Europe, and Australia. We manage our business through our Calgary head office and our international business unit offices.

This MD&A separately discusses each of our business units in addition to our corporate segment.

Canada business unit: Relates to our assets in Alberta and Saskatchewan.
France business unit: Relates to our operations in France in the Paris and Aquitaine Basins.
Netherlands business unit: Relates to our operations in the Netherlands.
Germany business unit: Relates to our 25% contractual participation interest in a four-partner consortium in Germany.
Ireland business unit: Relates to our 18.5% non-operated interest in the offshore Corrib natural gas field.
Australia business unit: Relates to our operations in the Wandoo offshore crude oil field.
Corporate: Includes expenditures related to our global hedging program, financing expenses, and general and administration expenses, primarily incurred in Canada and not directly related to the operations of a specific business unit.

Prior to December 31, 2013, Vermilion combined the operating and financial results of the Canada business unit and the Corporate segment and presented the combined results as Canada.

GUIDANCE

We first issued 2014 capital expenditure guidance of $555 million on November 7, 2013. We subsequently increased our 2014 capital expenditure guidance to $590 million on March 18, 2014, to reflect an additional $35 million of 2014 development capital expected to be incurred in association with our acquisition of Elkhorn Resources Inc. Concurrent with the release of our first quarter 2014 financial and operating results on May 2, 2014, we further updated our 2014 capital expenditure guidance to $635 million, reflecting the expected full-year rise in the cost to Vermilion, in Canadian dollar terms, of both actual and anticipated international capital expenditures as a result of the devaluation of the Canadian dollar against both the U.S. dollar and the Euro, and the addition of approximately $15 million of anticipated spending associated with drilling activities. We also increased our original production guidance from 47,500-48,500 boe/d to 48,000-49,000 boe/d.

Based on the continued strength of our operations during the second quarter of 2014, we further increased our full-year 2014 production and capital expenditure guidance to 48,500-49,500 boe/d and $650 million, respectively. The increase in capital expenditures was attributed to increased Mannville development drilling and higher than anticipated costs associated with the Duvernay development program.

We are further revising our 2014 full year production guidance from the previous range of 48,500-49,500 boe/d to a range of 49,000-49,500 boe/d and currently expect to achieve production near the upper end of this refined range for 2014.

The following table summarizes our 2014 guidance:

Date

Capital Expenditures ($MM)

Production (boe/d)

2014 Guidance

November 7, 2013

555

45,000 to 46,000

2014 Guidance - Update

March 18, 2014

590

47,500 to 48,500

2014 Guidance - Update

May 2, 2014

635

48,000 to 49,000

2014 Guidance - Update

July 31, 2014

650

48,500 to 49,500

2014 Guidance - Update

November 10, 2014

650

49,000 to 49,500

SHAREHOLDER RETURN

Vermilion strives to provide investors with reliable and growing dividends in addition to sustainable, global production growth. The following table, as of September 30, 2014, reflects our trailing one, three, and five year performance:

Total return⁽¹⁾	Trailing One Year	Trailing Three Year	Trailing Five Year
Dividends per Vermilion share	$2.54	$7.19	$11.75
Capital appreciation per Vermilion share	$11.56	$24.14	$38.60
Total return per Vermilion share	24.9%	71.1%	170.2%
Annualized total return per Vermilion share	24.9%	19.6%	22.0%
Annualized total return on the S&P TSX High Income Energy Index	13.2%	7.6%	7.5%

⁽¹⁾	The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of this MD&A.

CONSOLIDATED RESULTS OVERVIEW

		Three Months Ended			% change		Nine Months Ended		% change
		Sep 30,	Jun 30,	Sep 30,	Q3/14 vs.	Q3/14 vs.	Sep 30,	Sep 30,	2014 vs.
		2014	2014	2013	Q2/14	Q3/13	2014	2013	2013
Production
	Crude oil (bbls/d)	29,147	30,184	26,664	(3%)	9%	28,890	25,640	13%
	NGLs (bbls/d)	2,354	2,892	1,945	(19%)	21%	2,463	1,719	43%
	Natural gas (mmcf/d)	110.52	114.08	77.41	(3%)	43%	109.33	81.97	33%
	Total (boe/d)	49,920	52,089	41,510	(4%)	20%	49,574	41,020	21%
	Build (draw) in inventory (mbbl)	104	67	20			74	(218)
Financial metrics
	Fund flows from operations ($M)	197,898	216,076	165,645	(8%)	19%	619,337	503,866	23%
	Per share ($/basic share)	1.85	2.05	1.63	(10%)	13%	5.90	5.01	18%
	Net earnings ($M)	53,903	53,993	67,796	-	(20%)	210,684	226,131	(7%)
	Per share ($/basic share)	0.50	0.51	0.67	(2%)	(25%)	2.01	2.25	(11%)
	Cash flows from operating activities ($M)	235,010	149,592	158,236	57%	49%	562,840	528,022	7%
	Net debt ($M)	1,243,438	1,168,998	700,286	6%	78%	1,243,438	700,286	78%
	Cash dividends ($/share)	0.645	0.645	0.600	-	8%	1.935	1.800	8%
Activity
	Capital expenditures ($M)	190,033	135,073	135,661	41%	40%	521,481	394,248	32%
	Acquisitions ($M)	40,847	381,139	7,586	(89%)	438%	600,213	7,586	7,812%
	Gross wells drilled	26.00	13.00	21.00			63.00	55.00
	Net wells drilled	20.31	6.72	16.26			45.86	47.62

Operational review

Recorded consolidated average production of 49,920 boe/d during Q3 2014, a 4% decrease as compared to Q2 2014. This decrease was primarily driven by a 7% quarter-over-quarter decrease in production in Canada following reduced activity during spring breakup in Q2 2014.
Increased consolidated average production for the three and nine months ended September 30, 2014 by approximately 20% versus the comparable periods in 2013, primarily due to growth in Canada, the Netherlands, and incremental production from our acquisition in Germany. In Canada, production growth of 36% and 33% for the three and nine months ended September 30, 2014 versus the comparable periods in 2013 resulted from our continued development of the Cardium and Mannville plays in Alberta coupled with incremental production from southeast Saskatchewan following our acquisition in April 2014 of Elkhorn Resources Inc. (1,524 boe/d in the year-to-date period). In the Netherlands, production growth of 32% and 17% for the three and nine months ended September 30, 2014 versus the comparable periods in 2013 resulted from incremental production from our acquisition in the Netherlands in Q4 2013, increased volumes following completion of the Middenmeer Treatment Centre retrofit in the latter part of 2013, and ongoing recompletion and production optimization activities. These production increases were partially offset by decreased production in France due primarily to the temporary shut-in of natural gas production from the Vic Bilh field for the entirety of 2014.
Activity during the quarter included capital expenditures totalling $190.0 million, incurred primarily in Canada, France, and Ireland. In Canada, capital expenditures totalling $97.4 million were significantly higher than the $37.0 million incurred in Q2 2014 and related to the drilling of 16.86 net wells (3.29 net wells in Q2 2014), with activity influenced by spring breakup in Q2 2014. In France, capital expenditures of $35.1 million related to the drilling of 3.0 net wells in the Champotran field. In Ireland, $30.1 million of capital expenditures were incurred relating to various tunnel outfitting and offshore workover activities.
Acquisition expenditures for the quarter totalling $40.8 million related to our acquisition in the U.S. and crown land sales, primarily in southeast Saskatchewan, with the purchase of approximately 15,000 net acres.

Financial review

Net earnings

Net earnings for Q3 2014 was $53.9 million ($0.50/basic share) as compared to $54.0 million ($0.51/basic share) for Q2 2014. Quarter-over-quarter net earnings were relatively consistent as lower petroleum and natural gas sales ("sales") and operating income were offset by gains on derivative instruments (including $7.8 million of unrealized gains due to lower forecasted pricing for the remainder of 2014 and the impact on the valuation of our crude oil derivative positions) and lower unrealized foreign exchange losses. Unrealized foreign exchange losses primarily resulted from the weakening of the Euro versus the Canadian dollar and the resulting impact on our Euro denominated financial assets. In Q3 2014, the Euro weakened by 3% versus 4% in Q2 2014.
Net earnings for the three and nine months ended September 30, 2014 were 20% and 7% lower versus the respective comparable periods in 2013. These decreases occurred despite significantly increased revenue due to the impact of the aforementioned unrealized foreign exchange losses, increased depletion expense associated with higher production, and higher deferred tax expense due to the utilization of tax losses in Canada.

Cash flows from operating activities

Cash flow from operations increased by 49% and 7% for the three and nine months ended September 30, 2014 as compared to the same period in 2013. Both increases were the result of higher produced volumes and the resulting increase in fund flows from operations. For the nine months ended September 30, 2014, this increase in fund flows from operations was partially offset by timing differences pertaining to working capital balances.

Fund flows from operations

Generated fund flows from operations of $197.9 million during Q3 2014, a decrease of $18.2 million (8%) versus Q2 2014. This quarter-over-quarter decrease was the result of lower sales partially offset by increased realized derivative gains and decreases in corporate income taxes. Lower sales were driven largely by weaker commodity pricing coupled with lower sold volumes in Canada and an inventory build in France, partially offset by increased sold volumes in Australia. Lower corporate income taxes was the result of lower taxable income resulting from decreased sales and revisions to the estimated 2014 effective tax rate in France.
Fund flows from operations increased by 19% and 23% for the three and nine months ended September 30, 2014, respectively, versus the comparable periods in 2013. These increases were primarily the result of increased sales volumes in Canada and the Netherlands coupled with incremental production following our Q1 2014 acquisition in Germany, partially offset by a build in inventory in Australia for both the three and nine months ended September 30, 2014.

Net debt

As a result of funding our 2014 acquisitions in Germany and Saskatchewan, net debt increased to $1.2 billion or 1.5 times annualized cash flow as at September 30, 2014.

Dividends

Declared dividends of $0.215 per common share per month during 2014, totalling $0.645 per common share for the quarter and $1.935 per common share for the year-to-date period.

COMMODITY PRICES

	Three Months Ended			% change		Nine Months Ended		% change
	Sep 30,	Jun 30,	Sep 30,	Q3/14 vs.	Q3/14 vs.	Sep 30,	Sep 30,	2014 vs.
	2014	2014	2013	Q2/14	Q3/13	2014	2013	2013
Average reference prices
WTI (US $/bbl)	97.17	102.99	105.82	(6%)	(8%)	99.61	98.14	1%
Edmonton Sweet index (US $/bbl)	89.24	96.85	101.10	(8%)	(12%)	92.17	93.03	(1%)
Dated Brent (US $/bbl)	101.85	109.63	110.37	(7%)	(8%)	106.57	108.45	(2%)
AECO ($/GJ)	3.81	4.44	2.31	(14%)	65%	4.56	2.89	58%
TTF ($/GJ)	7.26	7.91	9.94	(8%)	(27%)	8.41	10.17	(17%)
TTF (€/GJ)	5.04	5.27	7.20	(4%)	(30%)	5.68	7.53	(25%)
Average foreign currency exchange rates
CDN $/US $	1.09	1.09	1.04	-	5%	1.09	1.02	7%
CDN $/Euro	1.44	1.50	1.38	(4%)	4%	1.48	1.35	10%
Average realized prices ($/boe)
Canada	64.85	71.56	63.56	(9%)	2%	68.58	61.16	12%
France	107.99	117.29	107.08	(8%)	1%	114.36	104.29	10%
Netherlands	45.73	48.14	61.44	(5%)	(26%)	52.80	62.70	(16%)
Germany	36.43	45.36	-	(20%)	100%	44.68	-	100%
Australia	119.07	126.87	120.95	(6%)	(2%)	124.59	117.65	6%
Consolidated	76.80	82.96	86.10	(7%)	(11%)	82.73	83.10	-
Production mix (% of production)
% priced with reference to WTI	28%	30%	24%			27%	24%
% priced with reference to AECO	18%	18%	17%			18%	17%
% priced with reference to TTF	18%	18%	14%			18%	16%
% priced with reference to Dated Brent	36%	34%	45%			37%	43%

Reference prices

Weakening global oil fundamentals, marked by a growing supply surplus, prompted a decline in oil prices throughout Q3 2014. Averaging the quarter at US $101.85/bbl, Dated Brent was 7% lower quarter-over-quarter and 8% below the same period last year.
WTI also suffered downward price pressure throughout Q3 2014 despite strong refining runs and averaged US $97.17/bbl or 6% lower than Q2 2014 and 8% lower year-over-year.
AECO natural gas fell 14% quarter-over-quarter to average $3.81/GJ in Q3 2014. Even as seasonal factors weighed on prices on a quarter-over-quarter basis, low storage levels and relatively strong flows on export pipelines led prices up 65% year-over-year.
European natural gas continued to weaken over the quarter as above-normal storage levels, LNG weakness and modest summer demand led prices lower by 8% quarter-over-quarter and 27% versus the same period last year.
The Canadian dollar was relatively flat quarter-over-quarter but 5% weaker to the US dollar year-over-year.

Realized prices

Consolidated realized price decreased by 7% for Q3 2014 as compared to Q2 2014 and 11% as compared to Q3 2013. These decreases were primarily the result of weaker commodity reference prices during Q3 2014 versus the comparable quarters.
Consolidated realized price for the nine months ended September 30, 2014 was relatively unchanged versus the same period in 2013 as the impact of weaker TTF pricing was offset by stronger AECO pricing and a weaker Canadian dollar.

FUND FLOWS FROM OPERATIONS

	Three Months Ended						Nine Months Ended
	Sep 30, 2014		Jun 30, 2014		Sep 30, 2013		Sep 30, 2014		Sep 30, 2013
	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe	$M	$/boe
Petroleum and natural gas sales	344,688	76.80	387,684	82.96	327,185	86.10	1,113,555	82.73	948,727	83.10
Royalties	(29,000)	(6.46)	(29,013)	(6.21)	(18,730)	(4.93)	(82,037)	(6.09)	(50,320)	(4.41)
Petroleum and natural gas revenues	315,688	70.34	358,671	76.75	308,455	81.17	1,031,518	76.64	898,407	78.69
Transportation expense	(10,979)	(2.45)	(12,032)	(2.57)	(6,549)	(1.72)	(32,872)	(2.44)	(19,843)	(1.74)
Operating expense	(56,227)	(12.53)	(58,213)	(12.46)	(46,246)	(12.17)	(172,426)	(12.81)	(146,903)	(12.87)
General and administration	(16,262)	(3.62)	(17,762)	(3.80)	(12,033)	(3.17)	(48,491)	(3.60)	(35,956)	(3.15)
PRRT	(13,834)	(3.08)	(12,699)	(2.72)	(15,649)	(4.12)	(46,772)	(3.47)	(39,392)	(3.45)
Corporate income taxes	(17,454)	(3.89)	(32,635)	(6.98)	(46,453)	(12.22)	(88,692)	(6.59)	(118,729)	(10.40)
Interest expense	(12,918)	(2.88)	(12,334)	(2.64)	(10,109)	(2.66)	(36,712)	(2.73)	(28,134)	(2.46)
Realized gain (loss) on derivative instruments	8,837	1.97	2,419	0.52	(4,765)	(1.25)	13,896	1.03	(5,782)	(0.51)
Realized foreign exchange gain (loss)	812	0.17	587	0.12	(1,227)	(0.32)	(642)	(0.05)	(572)	(0.05)
Realized other income	235	0.05	74	0.02	221	0.06	530	0.04	770	0.07
Fund flows from operations	197,898	44.08	216,076	46.24	165,645	43.60	619,337	46.02	503,866	44.13

The following table shows a reconciliation of the change in fund flows from operations:

($M)	Q3/14 vs. Q2/14	Q3/14 vs. Q3/13	2014 vs. 2013
Fund flows from operations - Comparative period	216,076	165,645	503,866
Sales volume variance:
Canada	(13,984)	38,597	101,499
France	(8,863)	(11,373)	(15,669)
Netherlands	(1,638)	8,838	16,748
Germany	(398)	8,591	28,603
Australia	9,052	(14,515)	(20,740)
Pricing variance on sold volumes:
WTI	(9,583)	(8,722)	16,434
AECO	(840)	8,979	22,723
Dated Brent	(13,351)	(3,631)	33,703
TTF	(3,391)	(9,261)	(18,473)
Changes in:
Royalties	13	(10,270)	(31,717)
Transportation	1,053	(4,430)	(13,029)
Operating expense	1,986	(9,981)	(25,523)
General and administration	1,500	(4,229)	(12,535)
PRRT	(1,135)	1,815	(7,380)
Corporate income taxes	15,181	28,999	30,037
Interest	(584)	(2,809)	(8,578)
Realized derivatives	6,418	13,602	19,678
Realized foreign exchange	225	2,039	(70)
Realized other income	161	14	(240)
Fund flows from operations - Current Period	197,898	197,898	619,337

Fund flows from operations of $197.9 million during Q3 2014 represented a decrease of $18.2 million (8%) versus Q2 2014. This quarter-over-quarter decrease was the result of a $43.0 million decrease in sales, partially offset by a $6.4 million increase in hedging proceeds (following weaker commodity prices during the quarter) and a $15.2 million decrease in corporate income taxes. The decrease in sales included $27.2 million of pricing variance due to a decrease in all relevant commodity prices and $15.8 million of sales volume variance due primarily to lower sales volumes in Canada (resulting from operational declines) and France (due to a build in inventory during Q3 2014), partially offset by higher produced and sold volumes in Australia. The decrease in corporate income taxes was due to lower taxable income resulting from decreased sales and revisions to the estimated 2014 effective tax rate in France.

On a year-over-year basis, fund flows from operations increased 19% and 23% for the three and nine months ended September 30, 2014, respectively, versus the comparable periods in 2013. These increases were primarily the result of favorable sales volume variances in Canada and the Netherlands coupled with incremental production following our Q1 2014 acquisition in Germany. These favorable sales volume variances were partially offset by a build in inventory in Australia. On a quarterly basis, the year-over-year change in fund flows from operations includes an unfavorable pricing variance of $12.6 million due to weaker crude oil and TTF pricing. For the nine months ended September 30, 2014 versus the same period in 2013, fund flows from operations includes a favorable variance of $54.4 million due to the impact of the weakening Canadian dollar on crude oil pricing coupled with stronger AECO natural gas pricing, offset partially by lower TTF pricing.

Fluctuations in fund flows from operations (and correspondingly net earnings and cash flows from operating activities) may occur as a result of changes in commodity prices and costs to produce petroleum and natural gas. In addition, fund flows from operations may be highly affected by the timing of crude oil shipments in Australia and France. When crude oil inventory is built up, the related operating expense, royalties, and depletion expense are deferred and carried as inventory on our balance sheet. When the crude oil inventory is subsequently drawn down, the related expenses are recognized in fund flows from operations.

CANADA BUSINESS UNIT

Overview

Production and assets focused in West Pembina near Drayton Valley, Alberta and Northgate in southeast Saskatchewan
Potential for three significant resource plays sharing the same surface infrastructure in the West Pembina region:

Cardium light oil (1,800m depth) - in development phase
Mannville condensate-rich gas (2,400 - 2,700m depth) - in development phase
Duvernay condensate-rich gas (3,200 - 3,400m depth) - in appraisal phase

Canadian cash flows are fully tax-sheltered for the foreseeable future.

Operational review

		Three Months Ended			% change		Nine Months Ended		% change
		Sep 30,	Jun 30,	Sep 30,	Q3/14 vs.	Q3/14 vs.	Sep 30,	Sep 30,	2014 vs.
Canada business unit		2014	2014	2013	Q2/14	Q3/13	2014	2013	2013
Production
	Crude oil (bbls/d)	11,469	12,676	7,969	(10%)	44%	11,202	8,274	35%
	NGLs (bbls/d)	2,291	2,796	1,897	(18%)	21%	2,387	1,654	44%
	Natural gas (mmcf/d)	57.07	57.59	43.40	(1%)	31%	54.76	42.72	28%
	Total (boe/d)	23,272	25,070	17,099	(7%)	36%	22,714	17,047	33%
Production mix (% of total)
	Crude oil	49%	51%	47%			49%	49%
	NGLs	10%	11%	11%			11%	10%
	Natural gas	41%	38%	42%			40%	41%
Activity
	Capital expenditures ($M)	97,393	36,968	62,270	163%	56%	249,300	163,952	52%
	Acquisitions ($M)	27,883	381,326	7,586			413,977	7,586
	Gross wells drilled	22.00	9.00	21.00			51.00	48.00
	Net wells drilled	16.86	3.29	16.26			35.12	40.62

Production

Production in Canada of 23,272 boe/d during Q3 2014 represented a decrease of 7% quarter-over-quarter and an increase of 36% year-over-year. Year-to-date average production of 22,714 boe/d represents an increase of 33% versus the same period in 2013.
Quarter-over-quarter decrease in production was largely due to the effect of lower activity levels during spring breakup.
The strong year-over-year increase was primarily attributable to production additions from our southeast Saskatchewan acquisition. Production growth was further supplemented by strong volume additions from our Mannville and Cardium development programs over the same period.
Cardium production averaged more than 10,600 boe/d in Q3 2014, and more than 11,000 boe/d year-to-date 2014.
Mannville production averaged more than 3,700 boe/d in Q3 2014, and nearly 3,800 boe/d year-to-date 2014.
Saskatchewan production averaged approximately 2,600 boe/d in Q3 2014, a 31% increase over the Q2 2014, taking into account an effective acquisition date of April 29, 2014.

Activity review

Vermilion drilled a total of 16 (14.7 net) operated wells during Q3 2014.

Cardium

We drilled five (4.5 net) operated wells and brought two (2.0 net) operated wells on production during Q3 2014. Year-to-date we have drilled 17 (16.0 net) operated wells and brought 20 (20.0 net) operated wells on production, of which 15 were long-reach wells with horizontal lengths greater than one mile.
Since 2009, we have drilled or participated in 264 (188.7 net) wells.
Operating netbacks have averaged approximately $67/boe year-to-date.
In 2014, we plan to drill or participate in approximately 40 (27.5 net) wells.

Mannville

During Q3 2014, we drilled one (1.0 net) well. Year-to-date we have drilled six (4.7 net) operated wells and brought on production five (3.7 net) operated wells.
In 2014, we expect to drill or participate in up to 20 (11.4 net) wells.

Duvernay

In Q2 2014, we drilled two (1.3 net) horizontal wells. One (0.3 net) well was completed in Q3 2014, and the other is anticipated to be completed in Q4 2014. The first well was brought on production subsequent to the third quarter and the second well is anticipated to be on production prior to year-end 2014.

Saskatchewan

We drilled 10 (9.2 net) operated Midale wells in Saskatchewan and brought seven gross (6.3 net) operated wells on production during Q3 2014.
In 2014, we plan to drill or participate in 12 (10.4 net) Midale wells.

Financial review

		Three Months Ended			% change		Nine Months Ended		% change
Canada business unit		Sep 30,	Jun 30,	Sep 30,	Q3/14 vs.	Q3/14 vs.	Sep 30,	Sep 30,	2014 vs.
($M except as indicated)		2014	2014	2013	Q2/14	Q3/13	2014	2013	2013
	Sales	138,853	163,261	100,000	(15%)	39%	425,294	284,638	49%
	Royalties	(19,034)	(18,240)	(11,156)	4%	71%	(49,937)	(29,852)	67%
	Transportation expense	(4,048)	(4,024)	(3,272)	1%	24%	(11,170)	(8,152)	37%
	Operating expense	(19,074)	(21,179)	(12,770)	(10%)	49%	(56,863)	(42,586)	34%
	General and administration	(4,523)	(6,560)	(3,484)	(31%)	30%	(13,951)	(10,501)	33%
	Fund flows from operations	92,174	113,258	69,318	(19%)	33%	293,373	193,547	52%
Netbacks ($/boe)
	Sales	64.85	71.56	63.56	(9%)	2%	68.58	61.16	12%
	Royalties	(8.89)	(7.99)	(7.09)	11%	25%	(8.05)	(6.41)	26%
	Transportation expense	(1.89)	(1.76)	(2.08)	7%	(9%)	(1.80)	(1.75)	3%
	Operating expense	(8.91)	(9.28)	(8.12)	(4%)	10%	(9.17)	(9.15)	-
	General and administration	(2.11)	(2.88)	(2.21)	(27%)	(5%)	(2.25)	(2.26)	-
	Fund flows from operations netback	43.05	49.65	44.06	(13%)	(2%)	47.31	41.59	14%
Reference prices
	WTI (US $/bbl)	97.17	102.99	105.82	(6%)	(8%)	99.61	98.14	1%
	Edmonton Sweet index (US $/bbl)	89.24	96.85	101.10	(8%)	(12%)	92.17	93.03	(1%)
	AECO ($/GJ)	3.81	4.44	2.31	(14%)	65%	4.56	2.89	58%

Sales

The realized price for our crude oil production in Canada is directly linked to WTI but is subject to market conditions in Western Canada. These market conditions can result in fluctuations in the pricing differential, as reflected by the Edmonton Sweet index price. The realized price of our NGLs in Canada is based on product specific differentials pertaining to trading hubs in the United States. The realized price of our natural gas in Canada is based on the AECO spot price in Canada.
Sales per boe decreased by 9% quarter-over-quarter as a result of an 8% decrease in Edmonton Sweet index pricing and a 14% decrease in AECO pricing. This decrease coupled with lower production volumes resulting from reduced activity over spring breakup resulted in a 15% decrease in sales.
On a year-over-year basis, sales per boe increased by 2% and 12% for the three and nine months ended September 30, 2014 versus the same periods in 2013. Sales increased despite declining Edmonton Sweet index pricing due to higher AECO pricing and increased production mix towards crude oil and NGLs. These increases coupled with incremental production from our Saskatchewan acquisition and production growth in the Cardium and Mannville resource plays resulted in sales growth of 39% and 49% for the three and nine months ended September 30, 2014, respectively.

Royalties

Royalty expense as a percentage of sales increased to 13.7% for Q3 2014 from 11.2% in both Q3 2013 and Q2 2014. Royalty expense as a percentage of sales increased to 11.7% for the year-to-date period ended Q3 2014 as compared to 10.5% for the same period of the prior year.
The quarter-over-quarter increase is largely associated with wells coming off of incentive royalty rates after reaching specified production thresholds. In addition, the year-over-year increase in royalty rates as a percentage of sales is partially attributable to increased gas prices as well as slightly higher average royalty rates associated with Vermilion's Saskatchewan production.

Transportation

Transportation expense relates to the delivery of crude oil and natural gas production to major pipelines where legal title transfers.
Transportation expense per boe increased for the year-to-date period ended Q3 2014 as compared to the same period in the prior year due to trucking costs associated with Vermilion's recently acquired Saskatchewan assets as well as pipeline tariff increases.

Operating expense

Operating expense per boe for Q3 2014 was slightly lower than the prior quarter due to favorable equalization adjustments received in the current quarter. The increase in operating expense per boe for the current quarter as compared to the same quarter in 2013 is attributable to higher operating expenses associated with the Saskatchewan properties Vermilion acquired in the second quarter of 2014. Year-to-date operating expense per boe is consistent with the prior year due to project timing, partially offset by the higher costs associated with Vermilion's Saskatchewan production.

General and administration

General and administration expense decreased in the current quarter as compared to the prior quarter largely due to higher costs in the previous quarter related to the Saskatchewan acquisition including legal and consultant costs ($1.1MM) and additional salary allocations from our Corporate segment to our Canadian business unit associated with the integration process ($0.7MM).
Year-over-year, the increase in general and administration expense is associated with incremental expense associated with the Saskatchewan acquisition, higher staffing levels and the timing of expenditures.

FRANCE BUSINESS UNIT

Overview

Entered France in 1997 and completed three subsequent acquisitions, including two in 2012.
Largest oil producer in France.
Producing assets include large conventional fields with high working interests located in the Aquitaine and Paris Basins with an identified inventory of workover, infill drilling, and secondary recovery opportunities.
Production is characterized by Brent-based crude pricing and low base decline rates.

Operational review

		Three Months Ended			% change		Nine Months Ended		% change
		Sep 30,	Jun 30,	Sep 30,	Q3/14 vs.	Q3/14 vs.	Sep 30,	Sep 30,	2014 vs.
France business unit		2014	2014	2013	Q2/14	Q3/13	2014	2013	2013
Production
	Crude oil (bbls/d)	11,111	11,025	11,625	1%	(4%)	10,970	10,786	2%
	Natural gas (mmcf/d)	-	-	5.23	-	(100%)	-	4.54	(100%)
	Total (boe/d)	11,111	11,025	12,496	1%	(11%)	10,970	11,544	(5%)
Inventory (mbbls)
	Opening crude oil inventory	179	238	202			268	354
	Adjustments	-		-			-	5
	Crude oil production	1,022	1,003	1,069			2,995	2,945
	Crude oil sales	(987)	(1,062)	(1,045)			(3,049)	(3,078)
	Closing crude oil inventory	214	179	226			214	226
Production mix (% of total)
	Crude oil	100%	100%	93%			100%	93%
	Natural gas	-	-	7%			-	7%
Activity
	Capital expenditures ($M)	35,082	37,614	23,664	(7%)	48%	110,663	68,479	62%
	Gross wells drilled	3.00	2.00	-			7.00	5.00
	Net wells drilled	3.00	2.00	-			7.00	5.00

Production

Q3 production increased 1% on a quarter-over-quarter basis but remained 11% lower year-over-year. Year-to-date production was 5% lower versus the same period of 2013. Year-over-year and year-to-date production volumes were lower due to the shut-in of gas volumes at Vic Bilh.
In late September 2013, the third party Lacq processing facility that processed our Vic Bilh gas production was permanently closed. As a result, our Vic Bilh gas production has been temporarily shut-in while preparations to transfer to an alternative facility are completed. We currently expect approximately 850 mcf/d will be back on-stream in early 2015, with the remaining approximately 3,400 mcf/d not anticipated to be back on production until early 2016.
As a result, current production volumes remain 100% weighted to Brent-based crude.

Activity review

Vermilion drilled three (3.0 net) wells in the Champotran field in the Paris Basin during Q3 2014.
During Q3 2014, we also completed a number of workovers, as well as seismic and facility integrity projects.
The five wells drilled in the Champotran field in 2014 were brought on production at various times during the third quarter and are currently producing approximately 200 bbls/d per well.

Financial review

		Three Months Ended			% change		Nine Months Ended		% change
France business unit		Sep 30,	Jun 30,	Sep 30,	Q3/14 vs.	Q3/14 vs.	Sep 30,	Sep 30,	2014 vs.
($M except as indicated)		2014	2014	2013	Q2/14	Q3/13	2014	2013	2013
	Sales	106,576	124,617	120,574	(14%)	(12%)	348,753	342,558	2%
	Royalties	(6,978)	(7,796)	(7,574)	(10%)	(8%)	(22,125)	(20,468)	8%
	Transportation expense	(4,741)	(5,385)	(2,713)	(12%)	75%	(14,879)	(7,883)	89%
	Operating expense	(15,215)	(16,550)	(14,599)	(8%)	4%	(48,185)	(51,473)	(6%)
	General and administration	(6,411)	(5,559)	(4,964)	15%	29%	(17,164)	(14,577)	18%
	Current income taxes	(10,744)	(24,761)	(31,717)	(57%)	(66%)	(60,769)	(66,500)	(9%)
	Fund flows from operations	62,487	64,566	59,007	(3%)	6%	185,631	181,657	2%
Netbacks ($/boe)
	Sales	107.99	117.29	107.08	(8%)	1%	114.36	104.29	10%
	Royalties	(7.07)	(7.34)	(6.73)	(4%)	5%	(7.26)	(6.23)	17%
	Transportation expense	(4.80)	(5.07)	(2.41)	(5%)	99%	(4.88)	(2.40)	103%
	Operating expense	(15.42)	(15.58)	(12.97)	(1%)	19%	(15.80)	(15.67)	1%
	General and administration	(6.50)	(5.24)	(4.41)	24%	47%	(5.63)	(4.44)	27%
	Current income taxes	(10.89)	(23.30)	(28.17)	(53%)	(61%)	(19.93)	(20.25)	(2%)
	Fund flows from operations netback	63.31	60.76	52.39	4%	21%	60.86	55.30	10%
Reference prices
	Dated Brent (US $/bbl)	101.85	109.63	110.37	(7%)	(8%)	106.57	108.45	(2%)

Sales

Crude oil production in France is priced with reference to Dated Brent.
Sales per boe for Q3 2014 decreased by 8%, consistent with the 7% decrease in the Dated Brent reference price. This decrease, coupled with a build in inventory during Q3 2014, resulted in a 14% decrease in sales.
On a year-over-year basis, sales per boe increased by 1% and 10% for the three and nine months ended September 30, 2014 as compared to the same periods in 2013. This sales increase occurred despite an 8% and 2% decrease in Dated Brent reference price for the three and nine months ended September 30, 2014 due to the offsetting impact of the weakening of the Canadian dollar versus the US dollar. On a year-to-date basis, the aforementioned increase in sales per boe was mostly offset by the shut-in of natural gas production, resulting in a 2% increase in 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 revenue).
As a percentage of sales, royalties for the periods presented remained relatively consistent.

Transportation

Historically, transportation expense in France related to shipments of crude oil by tanker from the Aquitaine Basin to third party refineries. As a result of the closure of the Lacq processing facility in Q3 2013, Vermilion began incurring additional transportation charges to ship Vic Bilh crude oil production to market. Accordingly, transportation expense per boe for the 2014 periods presented is higher than the expense per boe for the comparative periods from the prior year.

Operating expense

Operating expense per boe for Q3 2014 was consistent with the prior quarter. The increases in operating expense per boe for the three and nine months ended September 30, 2014 versus the same periods in 2013 are related to a weaker Canadian dollar relative to the Euro in 2014 versus 2013 and the timing of expenditures.

General and administration

General and administration expense increased in Q3 2014 versus the prior quarter as a result of higher allocations from Vermilion's Corporate segment. These higher allocations, coupled with increased staffing costs and the weaker Canadian dollar relative to the Euro, resulted in an increase in general and administrative expense for the three and nine months ended September 30, 2014.

Current income taxes

Current income taxes in France apply to taxable income after eligible deductions at a statutory rate of 34.4% for 2014. In addition, a 10.7% temporary surtax is applicable for tax year 2014 and 2015 if annual revenue exceeds 250 million €. For 2014, the effective rate on current taxes is expected to be between approximately 22% and 26% This rate is subject to change in response to commodity price fluctuations, the timing of capital expenditures and other eligible in-country adjustments.
Current income taxes for Q3 2014 were lower than both Q2 2014 and Q3 2013 as Q3 2014 current income taxes reflects our revised expectation of the effective tax rate given the declining Dated Brent reference price. Based on current expectations for Q4 2014 Dated Brent pricing, the France business unit is not expected to be subject to the 10.7% temporary surtax for 2014.
On a year-to-date basis, current income taxes for the nine months ended September 30, 2014 represents an effective tax rate of 25%. This decrease versus the 27% effective tax rate for the nine months ended September 30, 2013 reflects our revised expectations on the effective tax rate given the declining Dated Brent reference price.

NETHERLANDS BUSINESS UNIT

Overview

Entered the Netherlands in 2004.
Second largest onshore gas producer.
Interests include 16 licenses in the northeast region, five licenses in the central region, and two offshore licenses.
Licenses include more than 820,000 net acres of undeveloped land.
High impact natural gas drilling and development.
Natural gas produced in the Netherlands is priced off the TTF index, which receives a significant premium over North American gas prices.

Operational review

		Three Months Ended			% change		Nine Months Ended		% change
		Sep 30,	Jun 30,	Sep 30,	Q3/14 vs.	Q3/14 vs.	Sep 30,	Sep 30,	2014 vs.
Netherlands business unit		2014	2014	2013	Q2/14	Q3/13	2014	2013	2013
Production
	NGLs (bbls/d)	63	96	48	(34%)	31%	76	65	17%
	Natural gas (mmcf/d)	38.07	40.35	28.78	(6%)	32%	40.50	34.71	17%
	Total (boe/d)	6,407	6,822	4,845	(6%)	32%	6,827	5,849	17%
Activity
	Capital expenditures ($M)	10,087	21,513	8,316	(53%)	21%	51,718	12,845	303%
	Gross wells drilled	1.00	2.00	-			5.00	-
	Net wells drilled	0.45	1.43	-			3.74	-

Production

Production was 6% lower quarter-over-quarter while year-over-year production growth exceeded 32%. Year-to-date production volumes have increased 17% versus the same period of 2013. Both year-over-year and year-to-date production volumes benefited from the addition of production from the DeHoeve-01 well during the second quarter and increased throughput capacity following a retrofit at our Middenmeer Treatment Centre completed in late 2013.
Production in the Netherlands is managed to meet corporate targets, optimize facility use and regulate declines.

Activity review

Vermilion drilled the Diever-02 well (45% working interest), in the Drenthe IIIb concession, during Q3 2014. The well primarily targeted the Rotliegend Group (Permian sandstones) where it encountered two well-developed gas bearing intervals (Akkrum and Slochteren) with a net pay thickness of approximately 36 metres.
A subsequent three hour clean-up test conducted on the Slochteren formation delivered 25.7 mmcf/d of gas on a 40/64 inch choke with 2,615 psi of wellhead flowing pressure with no indications of pressure drop during the test⁽¹⁾. The flow rate was limited by the 3.5 inch diameter of the tubing and the capacity of the test equipment. The Akkrum formation is anticipated to be perforated at a later date once the Slochteren formation has been fully produced.
The Diever-02 well marked the first well drilled by Vermilion on the lands acquired in October 2013.
An additional two wells (Langezwaag-02 and Sonnega-02) are planned for drilling during Q4 2014.

⁽¹⁾	Test result is not necessarily indicative of long-term performance or of ultimate recovery.

Financial review

		Three Months Ended			% change		Nine Months Ended		% change
Netherlands business unit		Sep 30,	Jun 30,	Sep 30,	Q3/14 vs.	Q3/14 vs.	Sep 30,	Sep 30,	2014 vs.
($M except as indicated)		2014	2014	2013	Q2/14	Q3/13	2014	2013	2013
	Sales	26,960	29,881	27,382	(10%)	(2%)	98,395	100,119	(2%)
	Royalties	(942)	(693)	-	36%	100%	(3,843)	-	100%
	Operating expense	(5,409)	(6,390)	(5,209)	(15%)	4%	(17,841)	(14,438)	24%
	General and administration	(204)	(326)	(333)	(37%)	(39%)	(1,128)	(1,171)	(4%)
	Current income taxes	(1,189)	(1,301)	(6,810)	(9%)	(83%)	(6,278)	(25,865)	(76%)
	Fund flows from operations	19,216	21,171	15,030	(9%)	28%	69,305	58,645	18%
Netbacks ($/boe)
	Sales	45.73	48.14	61.44	(5%)	(26%)	52.80	62.70	(16%)
	Royalties	(1.60)	(1.12)	-	43%	100%	(2.06)	-	100%
	Operating expense	(9.18)	(10.29)	(11.69)	(11%)	(21%)	(9.57)	(9.04)	6%
	General and administration	(0.35)	(0.53)	(0.75)	(34%)	(53%)	(0.61)	(0.73)	(16%)
	Current income taxes	(2.02)	(2.10)	(15.28)	(4%)	(87%)	(3.37)	(16.20)	(79%)
	Fund flows from operations netback	32.58	34.10	33.72	(4%)	(3%)	37.19	36.73	1%
Reference prices
	TTF ($/GJ)	7.26	7.91	9.94	(8%)	(27%)	8.41	10.17	(17%)
	TTF (€/GJ)	5.04	5.27	7.20	(4%)	(30%)	5.68	7.53	(25%)

Sales

The price of our natural gas in the Netherlands is based on the TTF day-ahead index, as determined on the Title Transfer Facility Virtual Trading Point operated by Dutch TSO Gas Transport Services, plus various fees. GasTerra, a state owned entity, continues to purchase all of the natural gas we produce in the Netherlands.
The decreases in sales per boe in Q3 2014 versus Q2 2014 and Q3 2013 was largely in-line with the change in the Canadian dollar equivalent of the TTF reference price.
On a year-over-year basis, sales declined by 2% as a result of the 17% decrease in the TTF reference price offset by a 17% increase in production.

Royalties

Historically, we have not paid royalties in the Netherlands, however, certain wells associated with an acquisition completed by Vermilion's Netherlands business unit in October 2013 have reached payout and are now subject to an overriding royalty.

Transportation expense

Our production in the Netherlands is not subject to transportation expense as gas is sold at the plant gate.

Operating expense

Operating expense per boe decreased in Q3 2014 from Q2 2014 due to the timing of project work.
Operating expense per boe decreased in Q3 2014 as compared to Q3 2013 due to significantly higher volumes year-over-year.
For the year-to-date period ended Q3 2014, operating expense per boe increased as compared to the prior year due to the strengthening of the Euro versus the Canadian dollar as well as higher salary costs associated with continued organic growth in the Netherlands business unit.

General and administration

General and administration expense remained relatively consistent for the periods presented, although the quarterly periods are impacted by the timing of expenditures.

Current income taxes

Current income taxes in the Netherlands apply to taxable income after eligible deductions at a statutory tax rate of approximately 46%. For 2014, the effective rate on current taxes is expected to be between approximately 6% and 8%. This rate is subject to change in response to commodity price fluctuations, the timing of capital expenditures and other eligible in-country adjustments.
Current income taxes decreased for the nine months ended September 30, 2014 as compared to the same period in 2013 as a result of decreased revenues, lower TTF reference prices and an increase in tax deductions for depletion during the current year.

GERMANY BUSINESS UNIT

Overview

Vermilion entered Germany in February 2014 with the purchase of a 25% participation interest in a four-partner consortium.
The assets of the four-partner consortium include four gas producing fields across 11 production licenses and an exploration license in surrounding fields.
Production licenses comprising 207,000 gross acres, of which 85% is in the exploration license.

Operational review

		Three Months Ended		% change	Nine Months Ended
		Sep 30,	Jun 30,	Q3/14 vs.	Sep 30,
Germany business unit		2014	2014	Q2/14	2014
Production
	Natural gas (mmcf/d)	15.38	16.13	(5%)	14.07
	Total (boe/d)	2,563	2,689	(5%)	2,345
Activity
	Capital expenditures ($M)	1,358	630	116%	2,184
	Acquisitions ($M)	-	-		172,871

Production

Achieved Q3 2014 production of 2,563 boe/d, a decrease of 5% as compared to 2,689 boe/d in Q2 2014. Year-to-date production has averaged 2,345 boe/d, taking into account an effective date for production of February 1, 2014.

Activity review

Continued the integration of the German business unit and commenced planning with our working interest partners for future drilling operations.
During the first quarter of 2014, we participated in the drilling of the Deblinghausen Z7a development well (25% working interest) in Germany. The well logged 81 metres of net pay in the Zechstein Carbonate, and was production tested by the operator in late September for a period of 17 days. During the test, the Deblinghausen Z7a well produced raw gas at rates of 10.2 mmcf/d at a flowing tubing pressure of 1,840 psi⁽¹⁾. Subsequent to the end of the quarter, this well was placed on production at an initial gross production rate of 16.5 mmcf/d of raw gas at a flowing tubing pressure of approximately 1,300 psi.
We have hired a Managing Director for the German business unit and have opened an office outside of Berlin, which we are currently outfitting and staffing.

⁽¹⁾	Test result is not necessarily indicative of long-term performance or of ultimate recovery.

Financial review

		Three Months Ended		% change	Nine Months Ended
Germany business unit		Sep 30,	Jun 30,	Q3/14 vs.	Sep 30,
($M except as indicated)		2014	2014	Q2/14	2014
	Sales	8,591	11,097	(23%)	28,603
	Royalties	(2,046)	(2,284)	(10%)	(6,132)
	Transportation expense	(675)	(1,052)	(36%)	(2,149)
	Operating expense	(2,227)	(2,043)	9%	(5,824)
	General and administration	(1,090)	(830)	31%	(2,488)
	Current income taxes	(146)	(506)	(71%)	(1,189)
	Fund flows from operations	2,407	4,382	(45%)	10,821
Netbacks ($/boe)
	Sales	36.43	45.36	(20%)	44.68
	Royalties	(8.68)	(9.34)	(7%)	(9.58)
	Transportation expense	(2.86)	(4.30)	(33%)	(3.36)
	Operating expense	(9.44)	(8.35)	13%	(9.10)
	General and administration	(4.62)	(3.39)	36%	(3.89)
	Current income taxes	(0.62)	(2.07)	(70%)	(1.86)
	Fund flows from operations netback	10.21	17.91	(43%)	16.89
Reference prices
	TTF ($/GJ)	7.26	7.91	(8%)	8.41
	TTF (€/GJ)	5.04	5.27	(4%)	5.68

Sales

The price of our natural gas in Germany is based on the TTF month-ahead index, as determined on the Title Transfer Facility Virtual Trading Point operated by Dutch TSO Gas Transport Services, plus various fees.
Sales per boe decreased by 20% from Q2 2014 due to a decrease in the TTF reference price. This decrease, coupled with lower production volumes, resulted in a 23% quarter-over-quarter decrease in sales.

Royalties expense

Our production in Germany is subject to royalties at a rate of approximately 20% of natural gas sales revenue.

Transportation expense

Transportation expense relates to costs incurred to deliver natural gas from the processing facility to the customer.

Operating expense

Operating expenses for Germany are billed monthly by the joint venture operator and are similar on a per boe basis to our Netherlands business unit.

General and administration

General and administration expense increased quarter-over-quarter as a result of adding staff to the German business unit.

Current income taxes

Current income taxes in Germany apply to taxable income after eligible deductions at a statutory tax rate of approximately 23%. For 2014, the effective rate on current taxes is expected to be between approximately 4% and 8%. This rate is subject to change in response to commodity price fluctuations, the timing of capital expenditures and other eligible in-country adjustments.

IRELAND BUSINESS UNIT

Overview

18.5% non-operating interest in the offshore Corrib gas field located approximately 83km off the northwest coast of Ireland.
Project comprises six offshore wells, both offshore and onshore pipeline segments as well as a natural gas processing facility.
Production from Corrib is expected to increase Vermilion's volumes by approximately 58 mmcf/d (9,700 boe/d) once the field reaches peak production.

Operational and financial review

		Three Months Ended			% change		Nine Months Ended		% change
Ireland business unit		Sep 30,	Jun 30,	Sep 30,	Q3/14 vs.	Q3/14 vs.	Sep 30,	Sep 30,	2014 vs.
($M)		2014	2014	2013	Q2/14	Q3/13	2014	2013	2013
	Transportation expense	(1,515)	(1,571)	(564)	(4%)	169%	(4,674)	(3,808)	23%
	General and administration	(334)	(252)	(312)	33%	7%	(868)	(959)	(9%)
	Fund flows from operations	(1,849)	(1,823)	(876)	1%	111%	(5,542)	(4,767)	16%
Activity
	Capital expenditures	30,050	27,221	35,028	10%	(14%)	73,507	76,426	(4%)

Activity review

Completed tunnel boring operations beneath Sruwaddacon Bay on May 21, 2014. Installation of flow and umbilical lines has been completed in the 4.9 km tunnel, with remaining work including final cable installation, hydro-testing and grouting. Offshore well and flow line activities are complete and the wells are ready for operation.
Based on our deterministic schedule for remaining construction and commissioning activities, we anticipate first gas in approximately mid-2015 with peak production of approximately 58 mmcf/d (9,700 boe/d), net to Vermilion.

Transportation expense

Transportation expense in Ireland relates to payments under a ship or pay agreement related to the Corrib project.

AUSTRALIA BUSINESS UNIT

Overview

Entered Australia in 2005.
Hold title to a 100% working interest in the Wandoo field, located approximately 80 km offshore on the northwest shelf of Australia.
Production is operated from two off-shore platforms, and originates from 21 producing well bores.
Wells are located 600 metres below the sea bed with 500 to 3,000 plus metre horizontal lengths.
Contracted crude oil production is priced with reference to Dated Brent.

Operational review

		Three Months Ended			% change		Nine Months Ended		% change
		Sep 30,	Jun 30,	Sep 30,	Q3/14 vs.	Q3/14 vs.	Sep 30,	Sep 30,	2014 vs.
Australia business unit		2014	2014	2013	Q2/14	Q3/13	2014	2013	2013
Production
	Crude oil (bbls/d)	6,567	6,483	7,070	1%	(7%)	6,718	6,580	2%
Inventory (mbbls)
	Opening crude oil inventory	189	63	187			130	268
	Crude oil production	604	590	650			1,834	1,796
	Crude oil sales	(535)	(464)	(654)			(1,706)	(1,881)
	Closing crude oil inventory	258	189	183			258	183
Activity
	Capital expenditures ($M)	15,985	10,991	5,880	45%	172%	32,667	69,511	(53%)
	Gross wells drilled	-	-	-			-	2.00
	Net wells drilled	-	-	-			-	2.00

Production

Quarterly production increased 1% quarter-over-quarter and was 7% lower year-over-year. Year-to-date 2014 production has increased 2% versus the same period 2013.
Production volumes are managed to meet customer demands and long-term supply agreements. We continue to plan for production levels of between 6,000 and 8,000 bbls/d.
Production continues to reflect strong well results from the 2013 drilling program, more than offsetting natural declines. We continue to produce the wells at restricted rates below their current productive capacity.

Activity review

In Q3 2014, efforts were largely focused on facilities repairs and engineering studies, including the expansion of accommodation quarters on the Wandoo B platform.
2014 planned activities include ongoing facilities maintenance, enhancement, and refurbishment along with preparation and permitting activities in advance of our planned two-well 2015 drilling program.

Financial review

		Three Months Ended			% change		Nine Months Ended		% change
Australia business unit		Sep 30,	Jun 30,	Sep 30,	Q3/14 vs.	Q3/14 vs.	Sep 30,	Sep 30,	2014 vs.
($M except as indicated)		2014	2014	2013	Q2/14	Q3/13	2014	2013	2013
	Sales	63,708	58,828	79,229	8%	(20%)	212,510	221,412	(4%)
	Operating expense	(14,302)	(12,051)	(13,668)	19%	5%	(43,713)	(38,406)	14%
	General and administration	(1,378)	(1,661)	(1,414)	(17%)	(3%)	(4,245)	(4,310)	(2%)
	PRRT	(13,834)	(12,699)	(15,649)	9%	(12%)	(46,772)	(39,392)	19%
	Corporate income taxes	(5,148)	(5,689)	(7,666)	(10%)	(33%)	(19,678)	(25,525)	(23%)
	Fund flows from operations	29,046	26,728	40,832	9%	(29%)	98,102	113,779	(14%)
Netbacks ($/boe)
	Sales	119.07	126.87	120.95	(6%)	(2%)	124.59	117.65	6%
	Operating expense	(26.73)	(25.99)	(20.86)	3%	28%	(25.63)	(20.41)	26%
	General and administration	(2.58)	(3.58)	(2.16)	(28%)	19%	(2.49)	(2.29)	9%
	PRRT	(25.86)	(27.39)	(23.89)	(6%)	8%	(27.42)	(20.93)	31%
	Corporate income taxes	(9.62)	(12.27)	(11.70)	(22%)	(18%)	(11.54)	(13.56)	(15%)
	Fund flows from operations netback	54.28	57.64	62.34	(6%)	(13%)	57.51	60.46	(5%)
Reference prices
	Dated Brent (US $/bbl)	101.85	109.63	110.37	(7%)	(8%)	106.57	108.45	(2%)

Sales

Our production in Australia currently receives a premium to Dated Brent.
Sales per boe for Q3 2014 decreased by 6% versus Q2 2014 as a result of a decrease in the Dated Brent reference price. This decrease was offset by larger sales volumes resulting in an 8% increase in sales.
Sales per boe for the three and nine months ended September 30, 2014 versus the same periods in 2013 reflect the decrease in the Dated Brent reference price offset by the weakening of the Canadian dollar versus the US dollar. These changes, coupled with lower sales volumes, resulted in a 20% and 4% decrease in sales in the three and nine months ended September 30, 2014 versus the same periods in 2013.

Royalties and transportation expense

Our production in Australia is not subject to royalties or transportation expense as crude oil is sold directly from the Wandoo B platform.

Operating expense

Operating expense per boe for Q3 2014 remained consistent with the expense for Q2 2014.
Operating expense per boe for the three and nine months ended September 30, 2014 was higher than the expense for the comparative periods in the prior year due to increased diesel usage and higher salary costs.
Operating expense for the three and nine months ended September 30, 2014 were 5% and 14% higher, respectively, than the comparable periods in 2013 as a result of increased diesel usage and higher salary costs, partially offset by a build in inventory in the current periods. When crude oil inventory is built up, the related operating expense is deferred and carried as inventory on our balance sheet.

General and administration

General and administration expense decreased slightly during Q3 2014 as compared to Q2 2014 and Q3 2013 due to timing of expenditures. For the year-to-date period ended September 30, 2014, general and administration expense remained consistent with the expense for the same period of the prior year.

PRRT and corporate income taxes

In Australia, current income taxes include both PRRT and corporate income taxes. PRRT is a profit based tax applied at a rate of 40% on sales less eligible expenditures, including operating expenses and capital expenditures. Corporate income taxes are applied at a rate of 30% on taxable income after eligible deductions, which include PRRT.
For 2014, the combined corporate income tax and PRRT effective rate is expected to be between approximately 38% and 42%. This rate is subject to change in response to commodity price fluctuations, the timing of capital expenditures and other eligible in-country adjustments.
Combined corporate income taxes and PRRT movements for the three and nine months ended September 30, 2014 versus the comparable periods was largely consistent with the fluctuations in sales. On a year-over-year basis, PRRT for 2014 increased versus the 2013 periods as a result of the lower capital spending in 2014.

CORPORATE

Overview

Our Corporate segment includes costs related to our global hedging program, financing expenses, and general and administration expenses, primarily incurred in Canada and not directly related to the operations of our business units.

Financial review

	Three Months Ended			Nine Months Ended
	Sep 30,	Jun 30,	Sep 30,	Sep 30,	Sep 30,
($M)	2014	2014	2013	2014	2013
General and administration	(2,322)	(2,574)	(1,526)	(8,647)	(4,438)
Current income taxes	(227)	(378)	(260)	(778)	(839)
Interest expense	(12,918)	(12,334)	(10,109)	(36,712)	(28,134)
Realized gain (loss) on derivatives	8,837	2,419	(4,765)	13,896	(5,782)
Realized foreign exchange gain (loss)	812	587	(1,227)	(642)	(572)
Realized other income	235	74	221	530	770
Fund flows from operations	(5,583)	(12,206)	(17,666)	(32,353)	(38,995)

General and administration

General and administration expense was largely consistent in Q3 2014 as compared to Q2 2014.
On a year-over-year basis, the increase in general and administration costs for the three and nine months ended September 30, 2014 as compared to the same period in 2013 was a result of the impact of certain outstanding Vermilion Incentive Plan ("VIP") awards to be settled partially in cash.

Current income taxes

Taxes in our corporate segment relates to holding companies that pay current taxes in foreign jurisdictions.

Interest expense

Interest expense is incurred on our senior unsecured notes and on borrowings under our revolving credit facility. The increase in 2014 versus the comparable periods is due to increased borrowings under our revolving credit facility.

Hedging

The nature of our operations results in exposure to fluctuations in commodity prices, interest rates and foreign currency exchange rates. We monitor and, when appropriate, use derivative financial instruments to manage our exposure to these fluctuations. All transactions of this nature entered into are related to an underlying financial position or to future crude oil and natural gas production. We do not use derivative financial instruments for speculative purposes. We have elected not to designate any of our derivative financial instruments as accounting hedges and thus account for changes in fair value in net earnings at each reporting period. We have not obtained collateral or other security to support our financial derivatives as we review the creditworthiness of our counterparties prior to entering into derivative contracts.
Our hedging philosophy is to hedge solely for the purposes of risk mitigation. Our approach is to hedge centrally to manage our global risk (typically with an outlook of 12 to 18 months) with a goal of securing pricing for up to 50% of net of royalty volumes through a portfolio of forward collars, swaps, and physical fixed price arrangements.
We believe that our hedging philosophy and approach increases the stability of revenues, cash flows and future dividends while also assisting us in the execution of our capital and development plans.
The realized gain in 2014 related primarily to amounts received on our TTF and Dated Brent derivatives, partially offset by payments made on our AECO derivatives.
A listing of derivative positions as at September 30, 2014 is included in "Supplemental Table 2" in this MD&A.

FINANCIAL PERFORMANCE REVIEW

		Three Months Ended
		Sep 30,	Jun 30,	Mar 31,	Dec 31,	Sep 30,	Jun 30,	Mar 31,	Dec 31,
($M except per share)		2014	2014	2014	2013	2013	2013	2013	2012
Petroleum and natural gas sales		344,688	387,684	381,183	325,108	327,185	311,966	309,576	241,233
Net earnings		53,903	53,993	102,788	101,510	67,796	106,198	52,137	56,914
Net earnings per share
	Basic	0.50	0.51	1.00	1.00	0.67	1.05	0.53	0.58
	Diluted	0.50	0.50	0.99	0.98	0.66	1.04	0.51	0.57

The following table shows a reconciliation of the change in net earnings:

($M)	Q3/14 vs. Q2/14	Q3/14 vs. Q3/13	2014 vs. 2013
Net earnings - Comparative period	53,993	67,796	226,131
Changes in:
Fund flows from operations	(18,178)	32,253	115,471
Equity based compensation	3,497	(1,941)	(9,770)
Unrealized gain or loss on derivative instruments	9,321	11,499	6,375
Unrealized foreign exchange gain or loss	11,879	(16,099)	(43,351)
Unrealized other income	(701)	(321)	282
Accretion	(114)	150	312
Depletion and depreciation	743	(25,333)	(69,821)
Deferred tax	(6,537)	(14,101)	(14,945)
Net earnings - Current Period	53,903	53,903	210,684

The fluctuations in net earnings from quarter-to-quarter and from year-to-year are caused by changes in both cash and non-cash based income and charges. Cash based items are reflected in fund flows from operations and include: sales, royalties, operating expenses, transportation, general and administration expense, current tax expense, interest expense, realized gains and losses on derivative instruments, and realized foreign exchange gains and losses. Non-cash items include: equity based compensation expense, unrealized gains and losses on derivative instruments, unrealized foreign exchange gains and losses, accretion, depletion and depreciation expense, and deferred taxes. In addition, non-cash items may also include amounts resulting from acquisitions or charges resulting from impairment or impairment recoveries.

Equity based compensation
Equity based compensation expense relates to non-cash compensation expense attributable to long-term incentives granted to directors, officers and employees under the VIP. The expense is recognized over the vesting period based on the grant date fair value of awards, adjusted for the ultimate number of awards that actually vest as determined by the Company's achievement of performance conditions.

Equity based compensation expense for the three and nine months ended September 30, 2014 was higher than the same periods in 2013 as a result of an upward revision of future performance condition assumptions during Q2 2014. Equity based compensation expense was lower for Q3 2014 as compared to Q2 2014 due to aforementioned upward revision of future performance condition assumptions during Q2 2014.

Unrealized gain or loss on derivative instruments
Unrealized gain or loss on derivative instruments arise as a result of changes in forecasted future commodity prices. As Vermilion uses derivative instruments to manage the commodity price exposure of our future crude oil and natural gas production, we will normally recognize unrealized gains on derivative instruments when forecasted future commodity prices decline and vice-versa.

In the nine months ended September 30, 2014, we recognized an unrealized gain on derivative instruments of $10.1 million, relating primarily to our crude oil swaps and collars. As at September 30, 2014, we have a net derivative asset position of $7.6 million.

Unrealized foreign exchange gain or loss
As a result of Vermilion's international operations, Vermilion conducts business in currencies other than the Canadian dollar and has monetary assets and liabilities (including cash, receivables, payables, derivative assets and liabilities, and intercompany loans) denominated in such currencies. Vermilion's exposure to foreign currencies includes the US dollar, the Euro and the Australian Dollar.

Unrealized foreign exchange gains and losses are the result of translating monetary assets and liabilities held in non-functional currencies to the respective functional currencies of Vermilion and its subsidiaries. Unrealized foreign exchange primarily results from the translation of Euro denominated financial assets. As such, an appreciation in the Euro against the Canadian dollar will result in an unrealized foreign exchange gain, and vice-versa.

For the three and nine months ended September 30, 2014, the Canadian dollar strengthened versus the Euro resulting in unrealized foreign exchange losses of $11.9 million and $13.6 million, respectively.

Accretion
Fluctuations in accretion expense is primarily the result of changes in discount rates applicable to the balance of asset retirement obligations and additions resulting from drilling and acquisitions.

Q3 2014 accretion expense was relatively consistent as compared to Q2 2014 and the comparable periods in 2013.

Depletion and depreciation
Fluctuations in depletion and depreciation expense are primarily the result of changes in produced crude oil and natural gas volumes.

Depletion and depreciation on a per boe basis for Q3 2014 of $23.21 was higher as compared to Q2 2014 of $22.45/boe as a result of lower production in Canada. Depletion and depreciation on a per boe basis increased for the three and nine month periods ended September 30, 2014 to $23.21/boe and $22.92/boe, respectively, as compared to the same periods in 2013 of $20.74/boe and $20.91/boe, respectively. The increase on a per boe basis was largely due to Vermilion's increased capital and acquisition activity which results in higher per boe amounts when compared to legacy producing assets.

Deferred tax
Deferred tax expense arises primarily as a result of changes in the accounting basis and tax basis for capital assets and asset retirement obligations and changes in available tax losses.

FINANCIAL POSITION REVIEW

Balance sheet strategy
We believe that our balance sheet supports our defined growth initiatives and our focus is on managing and maintaining a conservative balance sheet. To ensure that our balance sheet continues to support our defined growth initiatives, we regularly review whether forecasted fund flows from operations is sufficient to finance planned capital expenditures, dividends, and abandonment and reclamation expenditures. To the extent that forecasted fund flows from operations is not expected to be sufficient to fulfill such expenditures, we will evaluate our ability to finance any excess with debt (including borrowing using the unutilized capacity of our existing revolving credit facility) or issue equity.

To ensure that we maintain a conservative balance sheet, we monitor the ratio of net debt to fund flows from operations and typically strive to maintain an internally targeted ratio of approximately 1.0 to 1.3. In a commodity price environment where prices trend higher, we may target a lower ratio and conversely, in a lower commodity price environment, the acceptable ratio may be higher. At times, we will use our balance sheet to finance acquisitions and, in these situations, we are prepared to accept a higher ratio in the short term but will implement a strategy to reduce the ratio to acceptable levels within a reasonable period of time, usually considered to be no more than 12 to 24 months. This plan could potentially include an increase in hedging activities, a reduction in capital expenditures, an issuance of equity or the utilization of excess fund flows from operations to reduce outstanding indebtedness.

Absent additional material acquisitions, Vermilion currently expects the net debt to fund flows ratio to return to our internally targeted ratio over the next 12 to 24 months as a result of incremental cash flows from Corrib and our acquisitions in Germany and Canada.

Long-term debt
Our long-term debt consists of our revolving credit facility and our senior unsecured notes. The applicable annual interest rates and the balances recognized on our balance sheet are as follows:

	Annual Interest Rate		As At
	Sep 30,	Dec 31,	Sep 30,	Dec 31,
($M)	2014	2013	2014	2013
Revolving credit facility	3.3%	3.3%	974,857	766,898
Senior unsecured notes	6.5%	6.5%	223,791	223,126
Long-term debt	3.9%	4.7%	1,198,648	990,024

Revolving Credit Facility
Our revolving credit facility bears interest at rates applicable to demand loans plus applicable margins. The following table outlines the terms of our revolving credit facility:

	As At
	Sep 30,	Dec 31,
	2014	2013
Total facility amount¹	$1.50 billion	$1.20 billion
Amount drawn	$974.9 million	$766.9 million
Letters of credit outstanding	$10.3 million	$8.1 million
Facility maturity date	31-May-17	31-May-16


⁽¹⁾	We may, by adding lenders or seeking an increase to an existing lender's commitment, increase the total committed facility amount to no more than $1.75 billion.

In addition, the revolving credit facility is subject to the following covenants:

		As At
		Sep 30,	Dec 31,
Financial covenant	Limit	2014	2013
Consolidated total debt to consolidated EBITDA	4.0	1.16	1.06
Consolidated total senior debt to consolidated EBITDA	3.0	0.94	0.82
Consolidated total senior debt to total capitalization	50%	31%	28%

Our covenants include financial measures defined within our revolving credit facility agreement that are not defined under GAAP. These financial measures are defined by our revolving credit facility agreement as follows:

Consolidated total debt: Includes all amounts classified as "Long-term debt" on our balance sheet.
Consolidated total senior debt: Defined as consolidated total debt excluding unsecured and subordinated debt.
Consolidated EBITDA: Defined as consolidated net earnings before interest, income taxes, depreciation, accretion and certain other non-cash items.
Total capitalization: Includes all amounts on our balance sheet classified as "Long-term debt" and "Shareholders' equity".

Vermilion was in compliance with its financial covenants for all periods presented.

Senior Unsecured Notes
We have outstanding senior unsecured notes that are senior unsecured obligations and rank pari passu with all our other present and future unsecured and unsubordinated indebtedness. The following table outlines the terms of these notes:


Total issued and outstanding amount	$225.0 million
Interest rate	6.5% per annum
Issued date	February 10, 2011
Maturity date	February 10, 2016

Prior to February 10, 2015, Vermilion may redeem all or part of the senior unsecured notes at 103.25% of their principal amount plus any accrued and unpaid interest. Subsequent to February 10, 2015, Vermilion may redeem all or part of the senior unsecured notes at 100% of their principal amount plus any accrued and unpaid interest. The notes were initially recognized at fair value net of transaction costs and are subsequently measured at amortized cost using an effective interest rate of 7.1%.

Net debt
Net debt is reconciled to its most directly comparable GAAP measure, long-term debt, as follows:

	As At
	Sep 30,	Dec 31,
($M)	2014	2013
Long-term debt	1,198,648	990,024
Current liabilities	431,175	347,444
Current assets	(386,385)	(587,783)
Net debt	1,243,438	749,685

Ratio of net debt to annualized fund flows from operations	1.5	1.1

Long-term debt as at September 30, 2014 increased to $1.2 billion from $990.0 million as at December 31, 2013 as a result of draws on the revolving credit facility during the current year to fund our acquisitions in Germany and Saskatchewan coupled with the assumption of $47.5 million of long-term debt pursuant to the latter acquisition. This increase in long-term debt resulted in an increase to net debt from $749.7 million to $1.2 billion. As a result of this increase to long-term debt, the year-to-date ratio of net debt to annualized fund flows from operations increased from 1.1 as at December 31, 2013 to 1.5 as at September 30, 2014.

Shareholders' capital
Beginning with the January 2014 dividend paid on February 18, 2014, we increased our monthly dividend by 7.5%. This was our second consecutive annual increase.

During the nine months ended September 30, 2014, we maintained monthly dividends at $0.215 per share and declared dividends totalled $203.6 million.

The following table outlines our dividend payment history:

Date	Monthly dividend per unit or share
January 2003 to December 2007	$0.17
January 2008 to December 2012	$0.19
January 2013 to December 31, 2013	$0.20
Beginning January 2014	$0.215

Our policy with respect to dividends is to be conservative and maintain a low ratio of dividends to fund flows from operations. During low price commodity cycles, we will initially maintain dividends and allow the ratio to rise. Should low commodity price cycles remain for an extended period of time, we will evaluate the necessity of changing the level of dividends, taking into consideration capital development requirements, debt levels and acquisition opportunities.

Over the next two years, we anticipate that Corrib, Cardium and other exploration and development activities will require significant capital investment. Although we currently expect to be able to maintain our current dividend, fund flows from operations may not be sufficient during this period to fund cash dividends, capital expenditures and asset retirement obligations. We will evaluate our ability to finance any shortfalls with debt, issuances of equity or by reducing some or all categories of expenditures to ensure that total expenditures do not exceed available funds.

The following table reconciles the change in shareholders' capital:

Shareholders' Capital	Number of Shares ('000s)		Amount ($M)
Balance as at December 31, 2013		102,123	1,618,443
Shares issued pursuant to corporate acquisition		2,827	204,960
Issuance of shares pursuant to the dividend reinvestment plan		902	58,450
Vesting of equity based awards		950	47,657
Share-settled dividends on vested equity based awards		108	7,519
Shares issued pursuant to the bonus plan		11	721
Balance as at September 30, 2014		106,921	1,937,750

As at September 30, 2014, there were approximately 1.7 million VIP awards outstanding. As at November 6, 2014, there were approximately 107.0 million shares outstanding.

ASSET RETIREMENT OBLIGATIONS

As at September 30, 2014, asset retirement obligations were $397.9 million compared to $326.2 million as at December 31, 2013.

The increase in asset retirement obligations is largely attributable to an overall decrease in the discount rates applied to the abandonment obligations, accretion, and additions from new wells drilled during the year and abandonment obligations associated with the assets acquired in Germany and Canada.

OFF BALANCE SHEET ARRANGEMENTS

We have certain lease agreements that are entered into in the normal course of operations, all of which are operating leases and accordingly no asset or liability value has been assigned to the consolidated balance sheet as at September 30, 2014.

We have not entered into any guarantee or off balance sheet arrangements that would materially impact our financial position or results of operations.

Accounting pronouncements not yet adopted

The impact of the adoption of the following pronouncements are currently being evaluated.

IFRS 9 "Financial Instruments"
On July 24, 2014, the IASB issued the final element of its comprehensive response to the financial crisis by issuing IFRS 9 "Financial Instruments". The improvements introduced by IFRS 9 includes a logical model for classification and measurement, a single, forward-looking 'expected loss' impairment model and a substantially-reformed approach to hedge accounting. Vermilion will adopt the standard for reporting periods beginning January 1, 2018.

IFRS 15 "Revenue from Contracts with Customers"
On May 28, 2014, the IASB issued IFRS 15 "Revenue from Contracts with Customers", a new standard that specifies recognition requirements for revenue as well as requiring entities to provide the users of financial statements with more informative and relevant disclosures. The standard replaces IAS 11 "Construction Contracts" and IAS 18 "Revenue" as well as a number of revenue-related interpretations. Vermilion will adopt the standard for reporting periods beginning January 1, 2017.

RISK MANAGEMENT

Vermilion is exposed to various market and operational risks. For a detailed discussion of these risks, please see Vermilion's Annual Report for the year ended December 31, 2013.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with IFRS requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues and expenses, gains and losses, and disclosures of any possible contingencies. These estimates and assumptions are developed based on the best available information which management believed to be reasonable at the time such estimates and assumptions were made. As such, these assumptions are uncertain at the time estimates are made and could change, resulting in a material impact on Vermilion's consolidated financial statements. Estimates are reviewed by management on an ongoing basis and as a result may change from period to period due to the availability of new information or changes in circumstances. Additionally, as a result of the unique circumstances of each jurisdiction that Vermilion operates in, the critical accounting estimates may affect one or more jurisdictions.

The following outlines what management believes to be the most critical accounting policies involving the use of estimates and assumptions:

i.	Depletion and depreciation charges are based on estimates of total proven and probable reserves that Vermilion expects to recover in the future.
ii.	Asset retirement obligations are based on past experience and current economic factors which management believes are reasonable.
iii.	Impairment tests are performed at the cash generating unit (CGU) level, which is determined based on management's judgment. The calculation of the recoverable amount of a CGU is based on market factors as well as estimates of PNG reserves and future costs required to develop reserves.
iv.	Deferred tax amounts recognized in the consolidated financial statements are based on management's assessment of the tax positions at the end of each reporting period.

INTERNAL CONTROL OVER FINANCIAL REPORTING

There was no change in Vermilion's internal control over financial reporting that occurred during the period covered by this MD&A that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

Supplemental Table 1: Netbacks

The following table includes financial statement information on a per unit basis by business unit. Natural gas sales volumes have been converted on a basis of six thousand cubic feet of natural gas to one barrel of oil equivalent.

	Three Months Ended September 30, 2014			Nine Months Ended September 30, 2014			Three Months Ended September 30, 2013	Nine Months Ended September 30, 2013
	Oil & NGLs	Natural Gas	Total	Oil & NGLs	Natural Gas	Total	Total	Total
	$/bbl	$/mcf	$/boe	$/bbl	$/mcf	$/boe	$/boe	$/boe
Canada
Sales	91.25	4.44	64.85	95.24	4.82	68.58	63.56	61.16
Royalties	(13.37)	(0.40)	(8.89)	(12.06)	(0.35)	(8.05)	(7.09)	(6.41)
Transportation	(2.50)	(0.17)	(1.89)	(2.33)	(0.17)	(1.80)	(2.08)	(1.75)
Operating	(9.19)	(1.42)	(8.91)	(9.73)	(1.39)	(9.17)	(8.12)	(9.15)
Operating netback	66.19	2.45	45.16	71.12	2.91	49.56	46.27	43.85
General and administration			(2.11)			(2.25)	(2.21)	(2.26)
Fund flows from operations netback			43.05			47.31	44.06	41.59
France
Sales	107.99	-	107.99	114.36	-	114.36	107.08	104.29
Royalties	(7.07)	-	(7.07)	(7.25)	-	(7.26)	(6.73)	(6.23)
Transportation	(4.80)	-	(4.80)	(4.88)	-	(4.88)	(2.41)	(2.40)
Operating	(15.42)	-	(15.42)	(15.80)	-	(15.80)	(12.97)	(15.67)
Operating netback	80.70	-	80.70	86.43	-	86.42	84.97	79.99
General and administration			(6.50)			(5.63)	(4.41)	(4.44)
Current income taxes			(10.89)			(19.93)	(28.17)	(20.25)
Fund flows from operations netback			63.31			60.86	52.39	55.30
Netherlands
Sales	90.01	7.55	45.73	96.66	8.72	52.80	61.44	62.70
Royalties	-	(0.27)	(1.60)	-	(0.35)	(2.06)	-	-
Operating	-	(1.54)	(9.18)	-	(1.61)	(9.57)	(11.69)	(9.04)
Operating netback	90.01	5.74	34.95	96.66	6.76	41.17	49.75	53.66
General and administration			(0.35)			(0.61)	(0.75)	(0.73)
Current income taxes			(2.02)			(3.37)	(15.28)	(16.20)
Fund flows from operations netback			32.58			37.19	33.72	36.73
Germany
Sales	-	6.07	36.43	-	7.45	44.68	-	-
Royalties	-	(1.45)	(8.68)	-	(1.60)	(9.58)	-	-
Transportation	-	(0.48)	(2.86)	-	(0.56)	(3.36)	-	-
Operating	-	(1.57)	(9.44)	-	(1.52)	(9.10)	-	-
Operating netback	-	2.57	15.45	-	3.77	22.64	-	-
General and administration			(4.62)			(3.89)	-	-
Current income taxes			(0.62)			(1.86)	-	-
Fund flows from operations netback			10.21			16.89	-	-
Australia
Sales	119.07	-	119.07	124.59	-	124.59	120.95	117.65
Operating	(26.73)	-	(26.73)	(25.63)	-	(25.63)	(20.86)	(20.41)
PRRT⁽¹⁾	(25.86)	-	(25.86)	(27.42)	-	(27.42)	(23.89)	(20.93)
Operating netback	66.48	-	66.48	71.54	-	71.54	76.20	76.31
General and administration			(2.58)			(2.49)	(2.16)	(2.29)
Corporate income taxes			(9.62)			(11.54)	(11.70)	(13.56)
Fund flows from operations netback			54.28			57.51	62.34	60.46
Total Company
Sales	102.49	5.74	76.80	108.02	6.60	82.73	86.10	83.10
Realized hedging gain (loss)	1.57	0.44	1.97	0.37	0.36	1.03	(1.25)	(0.51)
Royalties	(8.56)	(0.50)	(6.46)	(7.88)	(0.51)	(6.09)	(4.93)	(4.41)
Transportation	(2.83)	(0.30)	(2.45)	(2.77)	(0.31)	(2.44)	(1.72)	(1.74)
Operating	(14.73)	(1.48)	(12.53)	(15.08)	(1.49)	(12.81)	(12.17)	(12.87)
PRRT⁽¹⁾	(4.95)	-	(3.08)	(5.51)	-	(3.47)	(4.12)	(3.45)
Operating netback	72.99	3.90	54.25	77.15	4.65	58.95	61.91	60.12
General and administration			(3.62)			(3.60)	(3.17)	(3.15)
Interest expense			(2.88)			(2.73)	(2.66)	(2.46)
Realized foreign exchange gain (loss)			0.17			(0.05)	(0.32)	(0.05)
Other income			0.05			0.04	0.06	0.07
Corporate income taxes⁽¹⁾			(3.89)			(6.59)	(12.22)	(10.40)
Fund flows from operations netback			44.08			46.02	43.60	44.13

⁽¹⁾

Vermilion considers Australian PRRT to be an operating item and accordingly has included PRRT in the calculation of operating netbacks. Current income taxes presented above excludes PRRT.

Supplemental Table 2: Hedges

The following tables outline Vermilion's outstanding risk management positions as at September 30, 2014:

	Note	Volume	Strike Price(s)
Crude Oil
WTI - Collar
October 2014 - December 2014		250 bbl/d	90.00 - 101.10 US $
WTI - Swap
May 2014 - November 2014	1	250 bbl/d	97.25 CAD $
July 2014 - December 2014		750 bbl/d	99.00 US $
September 2014 - October 2014	2	500 bbl/d	96.05 US $
October 2014 - November 2014	3	500 bbl/d	92.90 US $
October 2014 - December 2014	4	1,750 bbl/d	94.89 US $
MSW - Fixed Price Differential
October 2014 - December 2014		1,000 bbl/d	WTI less 8.40 US $
Dated Brent - Collar
April 2014 - December 2014		1,000 bbl/d	106.00 - 110.73 US $
October 2014 - December 2014		800 bbl/d	95.00 - 121.60 US $
Dated Brent - Swap
January 2014 - December 2014		500 bbl/d	108.28 US $
July 2014 - December 2014		1,000 bbl/d	109.64 US $
July 2014 - December 2014	5	500 bbl/d	109.40 US $
September 2014 - December 2014	5	500 bbl/d	108.08 US $
October 2014 - December 2014	4	700 bbl/d	104.48 US $
January 2015	6	250 bbl/d	107.45 US $
February 2015	7	250 bbl/d	109.00 US $
March 2015	8	250 bbl/d	110.40 US $
MSW - Fixed Price Differential (Physical)
April 2014 - December 2014		1,030 bbl/d	WTI less 8.20 US $
July 2014 - December 2014		2,052 bbl/d	WTI less 8.68 US $
November 2014 - March 2015		1,042 bbl/d	WTI less 6.85 US $
January 2015 - March 2015		1,573 bbl/d	WTI less 7.43 US $
LSB - Fixed Price Differential (Physical)
October 2014 - December 2014		513 bbl/d	WTI less 9.00 US $
October 2014 - March 2015		830 bbl/d	WTI less 10.00 US $
January 2015 - March 2015		524 bbl/d	WTI less 8.60 US $


⁽¹⁾	Assumed as part of Vermilion's April 29, 2014 acquisition of Elkhorn Resources Inc.
⁽²⁾	Prior to the expiration of this swap, the counterparty has the option to extend the swap to December 31, 2014 at the contracted volume and price.
⁽³⁾	Prior to the expiration of this swap, the counterparty has the option to extend the swap to January 31, 2015 at the contracted volume and price.
⁽⁴⁾	Prior to the expiration of this swap, the counterparty has the option to extend the swap to March 31, 2015 at the contracted volume and price.
⁽⁵⁾	Prior to the expiration of this swap, the counterparty has the option to extend the swap to June 30, 2015 at the contracted volume and price.
⁽⁶⁾	On March 31, 2015, the counterparty has the option to extend the swap for the period of April to June 2015 for 500 boe/d at the contracted price.
⁽⁷⁾	On June 30, 2015, the counterparty has the option to extend the swap for the period of July to September 2015 for 500 boe/d at the contracted price.
⁽⁸⁾	On September 30, 2015, the counterparty has the option to extend the swap for the period of October to December 2015 for 500 boe/d at the contracted price.

	Note	Volume	Strike Price(s)
Canadian Natural Gas
AECO - Collar
January 2014 - December 2014		10,000 GJ/d	3.18 - 3.81 CAD $
April 2014 - December 2014		1,000 GJ/d	3.60 - 3.96 CAD $
April 2014 - March 2015		2,500 GJ/d	3.60 - 4.08 CAD $
November 2014 - March 2015		2,500 GJ/d	3.60 - 4.27 CAD $
AECO - Swap
January 2014 - December 2014		5,000 GJ/d	3.71 CAD $
April 2014 - October 2014		8,000 GJ/d	4.00 CAD $

European Natural Gas
TTF - Collar
October 2014 - December 2014		1,800 GJ/d	6.11 - 7.08 EUR €
TTF - Swap
October 2014 - December 2014		3,600 GJ/d	6.71 EUR €

Electricity
AESO - Swap
January 2014 - December 2014		7.2 MWh/d	54.75 CAD $
AESO - Swap (Physical)
January 2013 - December 2015		72.0 MWh/d	53.17 CAD $

US Dollar
USD - Collar
October 2014 - December 2014		1,500,000 USD $/month	1.075 - 1.145 CAD $
October 2014 - December 2014	1	7,500,000 USD $/month	1.092 - 1.114 CAD $


⁽¹⁾	Vermilion has upside participation on this hedge up to the limit price of 1.176 CAD; above which, settlement will occur at the conditional call level of 1.114 CAD.

Supplemental Table 3: Capital Expenditures

	Three Months Ended			Nine Months Ended
By classification	Sep 30,	Jun 30,	Sep 30,	Sep 30,	Sep 30,
($M)	2014	2014	2013	2014	2013
Drilling and development	180,479	117,975	135,110	467,294	389,635
Dispositions	-	-	-	-	(8,627)
Exploration and evaluation	9,554	17,098	551	54,187	13,240
Capital expenditures	190,033	135,073	135,661	521,481	394,248
Property acquisition	40,847	-	7,586	219,074	7,586
Corporate acquisition	-	381,139	-	381,139	-
Acquisitions	40,847	381,139	7,586	600,213	7,586

	Three Months Ended			Nine Months Ended
By category	Sep 30,	Jun 30,	Sep 30,	Sep 30,	Sep 30,
($M)	2014	2014	2013	2014	2013
Land	2,346	950	(4,450)	8,049	986
Seismic	6,135	1,869	5,284	11,436	14,666
Drilling and completion	93,386	42,083	63,590	242,005	210,010
Production equipment and facilities	68,964	60,547	47,665	198,266	138,426
Recompletions	10,853	13,459	15,650	28,538	24,291
Other	8,349	16,165	7,922	33,187	14,496
Dispositions	-	-	-	-	(8,627)
Capital expenditures	190,033	135,073	135,661	521,481	394,248
Acquisitions	40,847	381,139	7,586	600,213	7,586
Total capital expenditures and acquisitions	230,880	516,212	143,247	1,121,694	401,834

	Three Months Ended			Nine Months Ended
By country	Sep 30,	Jun 30,	Sep 30,	Sep 30,	Sep 30,
($M)	2014	2014	2013	2014	2013
Canada	125,276	418,294	69,856	663,277	171,538
France	35,082	37,614	23,664	110,663	68,479
Netherlands	10,087	21,513	8,316	51,718	12,845
Germany	1,358	630	-	175,055	-
Ireland	30,050	27,221	35,028	73,507	76,426
Australia	15,985	10,991	5,880	32,667	69,511
Corporate	13,042	(51)	503	14,807	3,035
Total capital expenditures and acquisitions	230,880	516,212	143,247	1,121,694	401,834

Supplemental Table 4: Production

		Q3/14	Q2/14	Q1/14	Q4/13	Q3/13	Q2/13	Q1/13	Q4/12	Q3/12	Q2/12	Q1/12	Q4/11
Canada
	Crude oil (bbls/d)	11,469	12,676	9,437	8,719	7,969	8,885	7,966	7,983	7,322	7,757	7,574	6,591
	NGLs (bbls/d)	2,291	2,796	2,071	1,699	1,897	1,725	1,335	1,106	1,204	1,321	1,302	1,246
	Natural gas (mmcf/d)	57.07	57.59	49.53	41.43	43.40	43.69	41.04	31.41	35.54	41.32	41.83	43.96
	Total (boe/d)	23,272	25,070	19,763	17,322	17,099	17,892	16,140	14,323	14,449	15,965	15,848	15,163
	% of consolidated	47%	49%	42%	43%	41%	42%	41%	40%	40%	40%	40%	41%
France
	Crude oil (bbls/d)	11,111	11,025	10,771	11,131	11,625	10,390	10,330	9,843	9,767	9,931	10,270	7,819
	Natural gas (mmcf/d)	-	-	-	-	5.23	4.19	4.21	3.91	3.39	3.57	3.48	0.94
	Total (boe/d)	11,111	11,025	10,771	11,131	12,496	11,088	11,032	10,495	10,333	10,526	10,850	7,976
	% of consolidated	22%	21%	23%	27%	30%	26%	29%	29%	28%	27%	28%	22%
Netherlands
	NGLs (bbls/d)	63	96	69	62	48	50	96	70	41	84	72	66
	Natural gas (mmcf/d)	38.07	40.35	43.15	37.53	28.78	38.52	36.91	33.03	34.59	33.74	35.08	34.58
	Total (boe/d)	6,407	6,822	7,260	6,318	4,845	6,470	6,248	5,574	5,806	5,707	5,919	5,829
	% of consolidated	13%	13%	16%	15%	12%	15%	16%	15%	16%	15%	15%	16%
Germany
	Natural gas (mmcf/d)	15.38	16.13	10.64	-	-	-	-	-	-	-	-	-
	Total (boe/d)	2,563	2,689	1,773	-	-	-	-	-	-	-	-	-
	% of consolidated	5%	5%	4%	-	-	-	-	-	-	-	-	-
Australia
	Crude oil (bbls/d)	6,567	6,483	7,110	6,189	7,070	7,363	5,287	5,873	5,958	6,970	6,648	7,686
	% of consolidated	13%	12%	15%	15%	17%	17%	14%	16%	16%	18%	17%	21%
Consolidated
	Crude oil & NGLs (bbls/d)	31,501	33,076	29,458	27,800	28,609	28,413	25,014	24,875	24,292	26,063	25,866	23,408
	% of consolidated	63%	63%	63%	68%	69%	66%	65%	69%	66%	67%	66%	64%
	Natural gas (mmcf/d)	110.52	114.08	103.32	78.96	77.41	86.40	82.16	68.34	73.52	78.63	80.39	79.48
	% of consolidated	37%	37%	37%	32%	31%	34%	35%	31%	34%	33%	34%	36%
	Total (boe/d)	49,920	52,089	46,677	40,960	41,510	42,813	38,707	36,265	36,546	39,168	39,265	36,654

		YTD 2014	2013	2012	2011	2010	2009
Canada
	Crude oil (bbls/d)	11,202	8,387	7,659	4,701	2,778	2,137
	NGLs (bbls/d)	2,387	1,666	1,232	1,297	1,427	1,518
	Natural gas (mmcf/d)	54.76	42.39	37.50	43.38	43.91	47.85
	Total (boe/d)	22,714	17,117	15,142	13,227	11,524	11,629
	% of consolidated	45%	41%	40%	38%	36%	37%
France
	Crude oil (bbls/d)	10,970	10,873	9,952	8,110	8,347	8,246
	Natural gas (mmcf/d)	-	3.40	3.59	0.95	0.92	1.05
	Total (boe/d)	10,970	11,440	10,550	8,269	8,501	8,421
	% of consolidated	22%	28%	28%	23%	26%	27%
Netherlands
	NGLs (bbls/d)	76	64	67	58	35	23
	Natural gas (mmcf/d)	40.50	35.42	34.11	32.88	28.31	21.06
	Total (boe/d)	6,827	5,967	5,751	5,538	4,753	3,533
	% of consolidated	14%	15%	15%	16%	15%	11%
Germany
	Natural gas (mmcf/d)	14.07	-	-	-	-	-
	Total (boe/d)	2,345	-	-	-	-	-
	% of consolidated	5%	-	-	-	-	-
Australia
	Crude oil (bbls/d)	6,718	6,481	6,360	8,168	7,354	7,812
	% of consolidated	14%	16%	17%	23%	23%	25%
Consolidated
	Crude oil & NGLs (bbls/d)	31,353	27,471	25,270	22,334	19,941	19,735
	% of consolidated	63%	67%	67%	63%	62%	63%
	Natural gas (mmcf/d)	109.33	81.21	75.20	77.21	73.14	69.96
	% of consolidated	37%	33%	33%	37%	38%	37%
	Total (boe/d)	49,574	41,005	37,803	35,202	32,132	31,395

Supplemental Table 5: Segmented Financial Results


	Three Months Ended September 30, 2014
($M)	Canada	France	Netherlands	Germany	Ireland	Australia	Corporate	Total
Drilling and development	88,116	34,883	10,087	1,358	30,050	15,985	-	180,479
Exploration and evaluation	9,277	199	-	-	-	-	78	9,554
Oil and gas sales to external customers	138,853	106,576	26,960	8,591	-	63,708	-	344,688
Royalties	(19,034)	(6,978)	(942)	(2,046)	-	-	-	(29,000)
Revenue from external customers	119,819	99,598	26,018	6,545	-	63,708	-	315,688
Transportation expense	(4,048)	(4,741)	-	(675)	(1,515)	-	-	(10,979)
Operating expense	(19,074)	(15,215)	(5,409)	(2,227)	-	(14,302)	-	(56,227)
General and administration	(4,523)	(6,411)	(204)	(1,090)	(334)	(1,378)	(2,322)	(16,262)
PRRT	-	-	-	-	-	(13,834)	-	(13,834)
Corporate income taxes	-	(10,744)	(1,189)	(146)	-	(5,148)	(227)	(17,454)
Interest expense	-	-	-	-	-	-	(12,918)	(12,918)
Realized gain on derivative instruments	-	-	-	-	-	-	8,837	8,837
Realized foreign exchange gain	-	-	-	-	-	-	812	812
Realized other income	-	-	-	-	-	-	235	235
Fund flows from operations	92,174	62,487	19,216	2,407	(1,849)	29,046	(5,583)	197,898


	Nine Months Ended September 30, 2014
($M)	Canada	France	Netherlands	Germany	Ireland	Australia	Corporate	Total
Total assets	1,857,012	894,060	237,070	164,025	809,296	269,959	206,305	4,437,727
Drilling and development	215,860	99,564	43,512	2,184	73,507	32,667	-	467,294
Exploration and evaluation	33,440	11,099	8,206	-	-	-	1,442	54,187
Oil and gas sales to external customers	425,294	348,753	98,395	28,603	-	212,510	-	1,113,555
Royalties	(49,937)	(22,125)	(3,843)	(6,132)	-	-	-	(82,037)
Revenue from external customers	375,357	326,628	94,552	22,471	-	212,510	-	1,031,518
Transportation expense	(11,170)	(14,879)	-	(2,149)	(4,674)	-	-	(32,872)
Operating expense	(56,863)	(48,185)	(17,841)	(5,824)	-	(43,713)	-	(172,426)
General and administration	(13,951)	(17,164)	(1,128)	(2,488)	(868)	(4,245)	(8,647)	(48,491)
PRRT	-	-	-	-	-	(46,772)	-	(46,772)
Corporate income taxes	-	(60,769)	(6,278)	(1,189)	-	(19,678)	(778)	(88,692)
Interest expense	-	-	-	-	-	-	(36,712)	(36,712)
Realized gain on derivative instruments	-	-	-	-	-	-	13,896	13,896
Realized foreign exchange loss	-	-	-	-	-	-	(642)	(642)
Realized other income	-	-	-	-	-	-	530	530
Fund flows from operations	293,373	185,631	69,305	10,821	(5,542)	98,102	(32,353)	619,337

ADDITIONAL AND NON-GAAP FINANCIAL MEASURES

This MD&A includes references to certain financial measures which do not have standardized meanings prescribed by IFRS. As such, these financial measures are considered additional GAAP or non-GAAP financial measures and therefore may not be comparable with similar measures presented by other issuers.

Fund flows from operations: We define fund flows from operations as cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, fund flows from operations provides a measure of our ability to generate cash (that is not subject to short-term movements in non-cash operating working capital) necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. As we have presented fund flows from operations in the "Segmented Information" note of our unaudited condensed consolidated interim financial statements for the three and nine months ended September 30, 2014, we consider fund flows from operations to be an additional GAAP financial measure.

Free cash flow: Represents fund flows from operations in excess of capital expenditures. We consider free cash flow to be a key measure as it is used to determine the funding available for investing and financing activities, including payment of dividends, repayment of long-term debt, reallocation to existing business units, and deployment into new ventures.

Net dividends: We define net dividends as dividends declared less proceeds received for the issuance of shares pursuant to the dividend reinvestment plan. Management monitors net dividends and net dividends as a percentage of fund flows from operations to assess our ability to pay dividends.

Payout: We define payout as net dividends plus drilling and development, exploration and evaluation, dispositions and asset retirement obligations settled. Management uses payout to assess the amount of cash distributed back to shareholders and re-invested in the business for maintaining production and organic growth.

Fund flows from operations (excluding Corrib) and Payout (excluding Corrib): Management excludes expenditures relating to the Corrib project in assessing fund flows from operations (an additional GAAP financial measure) and payout in order to assess our ability to generate cash and finance organic growth from our current producing assets.

Net debt: We define net debt as the sum of long-term debt and working capital. Management uses net debt, and the ratio of net debt to fund flows from operations, to analyze our financial position and leverage. Please refer to the preceding "Net Debt" section for a reconciliation of the net debt non-GAAP financial measure.

Diluted shares outstanding: Is the sum of shares outstanding at the period end plus outstanding awards under the VIP, based on current estimates of future performance factors and forfeiture rates.

Cash dividends per share: Represents cash dividends declared per share.

Netbacks: Per boe and per mcf measures used in the analysis of operational activities.

Total returns: Includes cash dividends per share and the change in Vermilion's share price on the Toronto Stock Exchange.

The following tables reconcile fund flows from operations, net dividends, payout, and diluted shares outstanding to their most directly comparable GAAP measures as presented in our financial statements:

	Three Months Ended			Nine Months Ended
	Sep 30,	Jun 30,	Sep 30,	Sep 30,	Sep 30,
($M)	2014	2014	2013	2014	2013
Cash flows from operating activities	235,010	149,592	158,236	562,840	528,022
Changes in non-cash operating working capital	(41,789)	64,103	4,671	46,788	(30,652)
Asset retirement obligations settled	4,677	2,381	2,738	9,709	6,496
Fund flows from operations	197,898	216,076	165,645	619,337	503,866
Expenses related to Corrib	1,849	1,823	876	5,542	4,767
Fund flows from operations (excluding Corrib)	199,747	217,899	166,521	624,879	508,633

	Three Months Ended			Nine Months Ended
	Sep 30,	Jun 30,	Sep 30,	Sep 30,	Sep 30,
($M)	2014	2014	2013	2014	2013
Dividends declared	68,896	68,710	61,003	203,613	181,391
Issuance of shares pursuant to the dividend reinvestment plan	(20,416)	(19,149)	(19,354)	(58,450)	(53,516)
Net dividends	48,480	49,561	41,649	145,163	127,875
Drilling and development	180,479	117,975	135,110	467,294	389,635
Dispositions	-	-	-	-	(8,627)
Exploration and evaluation	9,554	17,098	551	54,187	13,240
Asset retirement obligations settled	4,677	2,381	2,738	9,709	6,496
Payout	243,190	187,015	180,048	676,353	528,619
Corrib drilling and development	(30,050)	(27,221)	(35,028)	(73,507)	(76,426)
Payout (excluding Corrib)	213,140	159,794	145,020	602,846	452,193

	As At
	Sep 30,	Jun 30,	Sep 30,
('000s of shares)	2014	2014	2013
Shares outstanding	106,921	106,620	101,787
Potential shares issuable pursuant to the VIP	2,828	2,751	2,408
Diluted shares outstanding	109,749	109,371	104,195

CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)

		September 30,		December 31,
	Note		2014		2013
ASSETS
Current
Cash and cash equivalents			142,520		389,559
Accounts receivable			199,574		167,618
Crude oil inventory			19,781		17,143
Derivative instruments			9,341		2,285
Prepaid expenses			15,169		11,178
			386,385		587,783

Deferred taxes			148,124		184,832
Exploration and evaluation assets	5		380,266		136,259
Capital assets	4		3,522,952		2,799,845
			4,437,727		3,708,719

LIABILITIES
Current
Accounts payable and accrued liabilities			323,747		267,832
Dividends payable	8		22,988		20,425
Derivative instruments			1,704		3,572
Income taxes payable			82,736		55,615
			431,175		347,444

Long-term debt	7		1,198,648		990,024
Asset retirement obligations	6		397,920		326,162
Deferred taxes			409,516		328,714
			2,437,259		1,992,344

SHAREHOLDERS' EQUITY
Shareholders' capital	8		1,937,750		1,618,443
Contributed surplus			74,063		75,427
Accumulated other comprehensive income			13,740		47,142
Deficit			(25,085)		(24,637)
			2,000,468		1,716,375
			4,437,727		3,708,719

CONSOLIDATED STATEMENTS OF NET EARNINGS AND COMPREHENSIVE INCOME
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS, UNAUDITED)

		Three Months Ended		Nine Months Ended
		Sep 30,	Sep 30,	Sep 30,	Sep 30,
	Note	2014	2013	2014	2013
REVENUE
Petroleum and natural gas sales		344,688	327,185	1,113,555	948,727
Royalties		(29,000)	(18,730)	(82,037)	(50,320)
Petroleum and natural gas revenue		315,688	308,455	1,031,518	898,407

EXPENSES
Operating		56,227	46,246	172,426	146,903
Transportation		10,979	6,549	32,872	19,843
Equity based compensation	9	14,720	12,779	49,409	39,639
(Gain) loss on derivative instruments		(16,637)	8,464	(24,110)	1,943
Interest expense		12,918	10,109	36,712	28,134
General and administration		16,262	12,033	48,491	35,956
Foreign exchange loss (gain)		11,055	(3,005)	14,255	(29,166)
Other expense		362	55	217	259
Accretion	6	6,064	6,214	17,726	18,038
Depletion and depreciation	4, 5	104,159	78,826	308,513	238,692
		216,109	178,270	656,511	500,241
EARNINGS BEFORE INCOME TAXES		99,579	130,185	375,007	398,166

INCOME TAXES
Deferred		14,388	287	28,859	13,914
Current		31,288	62,102	135,464	158,121
		45,676	62,389	164,323	172,035

NET EARNINGS		53,903	67,796	210,684	226,131

OTHER COMPREHENSIVE (LOSS) INCOME
Currency translation adjustments		(36,143)	14,621	(33,402)	32,244
COMPREHENSIVE INCOME		17,760	82,417	177,282	258,375

NET EARNINGS PER SHARE
Basic		0.50	0.67	2.01	2.25
Diluted		0.50	0.66	1.98	2.22

WEIGHTED AVERAGE SHARES OUTSTANDING ('000s)
Basic		106,768	101,613	104,891	100,634
Diluted		108,290	102,763	106,582	102,083

CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)

			Three Months Ended		Nine Months Ended
			Sep 30,	Sep 30,	Sep 30,	Sep 30,
		Note	2014	2013	2014	2013
OPERATING
Net earnings			53,903	67,796	210,684	226,131
Adjustments:
	Accretion	6	6,064	6,214	17,726	18,038
	Depletion and depreciation	4, 5	104,159	78,826	308,513	238,692
	Unrealized (gain) loss on derivative instruments		(7,800)	3,699	(10,214)	(3,839)
	Equity based compensation	9	14,720	12,779	49,409	39,639
	Unrealized foreign exchange loss (gain)		11,867	(4,232)	13,613	(29,738)
	Unrealized other expense		597	276	747	1,029
	Deferred taxes		14,388	287	28,859	13,914
Asset retirement obligations settled		6	(4,677)	(2,738)	(9,709)	(6,496)
Changes in non-cash operating working capital			41,789	(4,671)	(46,788)	30,652
Cash flows from operating activities			235,010	158,236	562,840	528,022

INVESTING
Drilling and development		4	(180,479)	(135,110)	(467,294)	(389,635)
Exploration and evaluation		5	(9,554)	(551)	(54,187)	(13,240)
Property acquisitions		3, 4, 5	(40,847)	(7,586)	(219,074)	(7,586)
Dispositions		4	-	-	-	8,627
Corporate acquisitions, net of cash acquired		3	-	-	(176,179)	-
Changes in non-cash investing working capital			24,539	44,876	40,002	7,473
Cash flows used in investing activities			(206,341)	(98,371)	(876,732)	(394,361)

FINANCING
(Decrease) increase in long-term debt			(1,600)	-	204,127	139,429
Cash dividends			(48,415)	(41,576)	(142,600)	(126,354)
Cash flows (used in) from financing activities			(50,015)	(41,576)	61,527	13,075
Foreign exchange (loss) gain on cash held in foreign currencies			(1,631)	2,248	5,326	7,274

Net change in cash and cash equivalents			(22,977)	20,537	(247,039)	154,010
Cash and cash equivalents, beginning of period			165,497	235,598	389,559	102,125
Cash and cash equivalents, end of period			142,520	256,135	142,520	256,135

Supplementary information for operating activities - cash payments
	Interest paid		15,132	13,544	40,947	34,053
	Income taxes paid		28,617	50,203	106,177	101,507

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)

						Accumulated
							Other			Total
		Shareholders'		Contributed		Comprehensive				Shareholders'
	Note	Capital		Surplus			Loss	Deficit		Equity
Balances as at January 1, 2013			1,481,345		69,581		(32,409)		(99,871)		1,418,646
Net earnings			-		-		-		226,131		226,131
Currency translation adjustments			-		-		32,244		-		32,244
Equity based compensation expense	9		-		39,010		-		-		39,010
Dividends declared	8		-		-		-		(181,391)		(181,391)
Shares issued pursuant to the dividend reinvestment plan	8		53,516		-		-		-		53,516
Vesting of equity based awards	8, 9		54,370		(54,370)		-		-		-
Share-settled dividends on vested equity based awards	8, 9		9,808		-		-		(9,808)		-
Shares issued pursuant to the bonus plan	8		629		-		-		-		629
Balances as at September 30, 2013			1,599,668		54,221		(165)		(64,939)		1,588,785

						Accumulated
							Other			Total
		Shareholders'		Contributed		Comprehensive				Shareholders'
	Note	Capital		Surplus			Income	Deficit		Equity
Balances as at January 1, 2014			1,618,443		75,427		47,142		(24,637)		1,716,375
Net earnings			-		-		-		210,684		210,684
Currency translation adjustments			-		-		(33,402)		-		(33,402)
Equity based compensation expense	9		-		48,688		-		-		48,688
Dividends declared	8		-		-		-		(203,613)		(203,613)
Shares issued pursuant to the dividend reinvestment plan	8		58,450		-		-		-		58,450
Shares issued pursuant to corporate acquisition	3		204,960		-		-		-		204,960
Modification of equity based awards	9		-		(2,395)						(2,395)
Vesting of equity based awards	8, 9		47,657		(47,657)		-		-		-
Share-settled dividends on vested equity based awards	8, 9		7,519		-		-		(7,519)		-
Shares issued pursuant to the bonus plan	8		721		-		-		-		721
Balances as at September 30, 2014			1,937,750		74,063		13,740		(25,085)		2,000,468

DESCRIPTION OF EQUITY RESERVES

Shareholders' capital
Represents the recognized amount for common shares when issued, net of equity issuance costs and deferred taxes.

Contributed surplus
Represents the recognized value of employee awards which are settled in shares. Once vested, the value of the awards is transferred to shareholders' capital.

Accumulated other comprehensive income
Represents the cumulative income and expenses which are not recorded immediately in net earnings and are accumulated until an event triggers recognition in net earnings. The current balance consists of currency translation adjustments resulting from translating financial statements of subsidiaries with a foreign functional currency to Canadian dollars at period-end rates.

Deficit
Represents the cumulative net earnings less distributed earnings of Vermilion Energy Inc.

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2014 AND 2013
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS, UNAUDITED)

1. BASIS OF PRESENTATION

Vermilion Energy Inc. (the "Company" or "Vermilion") is a corporation governed by the laws of the Province of Alberta and is actively engaged in the business of crude oil and natural gas exploration, development, acquisition and production.

These condensed consolidated interim financial statements are in compliance with IAS 34, "Interim financial reporting" and have been prepared using the same accounting policies and methods of computation as Vermilion's consolidated financial statements for the year ended December 31, 2013, except as discussed in Note 2.

These condensed consolidated interim financial statements should be read in conjunction with Vermilion's consolidated financial statements for the year ended December 31, 2013, which are contained within Vermilion's Annual Report for the year ended December 31, 2013 and are available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.

These condensed consolidated interim financial statements were approved and authorized for issuance by the Board of Directors of Vermilion on November 6, 2014.

2. RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

On January 1, 2014, Vermilion adopted the following pronouncements as issued by the IASB. The adoption of these standards did not have a material impact on Vermilion's consolidated financial statements.

IFRIC 21 "Levies"
On May 20, 2013, the IASB issued guidance under IFRIC 21, which provides clarification on accounting for levies in accordance with the requirements of IAS 37 "Provisions, Contingent Liabilities and Contingent Assets". The interpretation defines a levy as an outflow from an entity imposed by a government in accordance with legislation and confirms that a liability for a levy is recognized only when the triggering event specified in the legislation occurs. The interpretation is effective for annual periods beginning on or after January 1, 2014.

IAS 36 "Impairment of Assets"
On May 29, 2013, the IASB issued amendments to IAS 36 "Impairment of Assets" which reduce the circumstances in which the recoverable amount of CGUs is required to be disclosed and clarify the disclosures required when an impairment loss has been recognized or reversed in the period. This amendment is effective for annual periods beginning on or after January 1, 2014.

Accounting pronouncements not yet adopted

The impact of the adoption of the following pronouncements are currently being evaluated.

3. BUSINESS COMBINATIONS

Property acquisition:

Germany

In February of 2014, Vermilion acquired, through a wholly-owned subsidiary, GDF's 25% interest in four producing natural gas fields and a surrounding exploration license located in northwest Germany. GDF is an affiliate of GDF Suez S.A., a publicly traded, French multinational utility. The acquisition represents Vermilion's entry into the German E&P business, a producing region with a long history of oil and gas development activity, low political risk and strong marketing fundamentals. The acquisition is well aligned with Vermilion's European focus, and will increase its exposure to the strong fundamentals and pricing of the European natural gas markets. The acquisition closed in February of 2014 for cash proceeds of $172.9 million. Vermilion funded this acquisition with existing credit facilities.

The acquired assets comprise of four gas producing fields across eleven production licenses and include both exploration and production licenses that comprise a total of 207,000 gross acres, of which 85% is in the exploration license.

The acquisition has been accounted for as a business combination with the fair value of the assets acquired and liabilities assumed at the date of acquisition summarized as follows:

($M)	Consideration
Cash paid to vendor		172,871
Total consideration		172,871

($M)	Allocation of Consideration
Petroleum and natural gas assets		158,840
Exploration and evaluation		16,065
Asset retirement obligations assumed		(2,030)
Deferred tax liabilities		(4)
Net assets acquired		172,871

The results of operations from the assets acquired have been included in Vermilion's consolidated financial statements beginning February of 2014 and have contributed revenues of $22.5 million and net earnings $2.2 million for the nine months ended September 30, 2014.

Had the acquisition occurred on January 1, 2014, management estimates that consolidated revenues would have increased by an additional $4.6 million and consolidated net earnings would have increased by $0.9 million for the nine months ended September 30, 2014.

Corporate acquisition:

Elkhorn Resources Inc.

On April 29, 2014, Vermilion acquired Elkhorn Resources Inc., a private southeast Saskatchewan producer. The acquisition creates a new core area for Vermilion in the Williston Basin.

The acquired assets include approximately 57,000 net acres of land (approximately 80% undeveloped), seven oil batteries, and preferential access to 50% or greater capacity at a solution gas facility that is currently under construction.

Total consideration was comprised of $180.4 million of cash, which was funded with existing credit facilities, and the issuance of 2.8 million Vermilion common shares valued at approximately $205.0 million (based on the closing price per Vermilion common share of $72.50 on the Toronto Stock Exchange on April 29, 2014).

The acquisition has been accounted for as a business combination with the fair value of the assets acquired and liabilities assumed at the date of acquisition summarized as follows:

($M)	Consideration
Cash paid to shareholders of Elkhorn Resources Inc.		180,353
Shares issued pursuant to corporate acquisition		204,960
Total consideration		385,313

($M)	Allocation of Consideration
Petroleum and natural gas assets		390,523
Exploration and evaluation		138,264
Asset retirement obligations assumed		(5,974)
Deferred tax liabilities		(89,437)
Long-term debt assumed		(47,526)
Cash acquired		4,174
Acquired non-cash working capital deficiency		(4,711)
Net assets acquired⁽¹⁾		385,313


⁽¹⁾	The above amounts are estimates made by management at the time of the preparation of these condensed consolidated interim financial statements based on information then available. Amendments may be made as amounts subject to estimates are finalized.

The results of operations from the assets acquired have been included in Vermilion's consolidated financial statements beginning April 29, 2014 and have contributed revenues of $34.7 million and operating income of $27.9 million for the nine months ended September 30, 2014.

Had the acquisition occurred on January 1, 2014, management estimates that consolidated revenues would have increased by an additional $8.8 million and consolidated operating income would have increased by $7.0 million for the nine months ended September 30, 2014. In determining the pro-forma amounts, management has assumed that the fair value adjustments, determined provisionally, that arose at the date of acquisition would have been the same if the acquisition had occurred on January 1, 2014. It is impracticable to derive all amounts necessary to determine the increase to net earnings from the acquisition as the acquired company was immediately merged with Vermilion's operations.

4. CAPITAL ASSETS

The following table reconciles the change in Vermilion's capital assets:

	Petroleum and		Furniture and		Total
($M)	Natural Gas Assets		Office Equipment		Capital Assets
Balance at January 1, 2013		2,430,121		15,119	2,445,240
Additions		531,760		5,804	537,564
Transfers from exploration and evaluation assets		1,508		-	1,508
Corporate acquisitions		47,743		-	47,743
Dispositions		(8,627)		-	(8,627)
Changes in estimate for asset retirement obligations		(91,527)		-	(91,527)
Depletion and depreciation		(310,370)		(6,138)	(316,508)
Impairment recovery		47,400		-	47,400
Effect of movements in foreign exchange rates		136,626		426	137,052
Balance at December 31, 2013		2,784,634		15,211	2,799,845
Additions		462,136		5,158	467,294
Property acquisitions		163,600		-	163,600
Corporate acquisitions		390,523		-	390,523
Changes in estimate for asset retirement obligations		63,400		-	63,400
Depletion and depreciation		(303,634)		(2,672)	(306,306)
Effect of movements in foreign exchange rates		(55,281)		(123)	(55,404)
Balance at September 30, 2014		3,505,378		17,574	3,522,952

5. EXPLORATION AND EVALUATION ASSETS

The following table reconciles the change in Vermilion's exploration and evaluation assets:

($M)	Exploration and Evaluation Assets
Balance at January 1, 2013		117,161
Additions		13,789
Property acquisitions		9,189
Transfers to petroleum and natural gas assets		(1,508)
Depreciation		(3,712)
Effect of movements in foreign exchange rates		1,340
Balance at December 31, 2013		136,259
Additions		54,187
Changes in estimate for asset retirement obligations		97
Property acquisitions		57,508
Corporate acquisitions		138,264
Depreciation		(4,076)
Effect of movements in foreign exchange rates		(1,973)
Balance at September 30, 2014		380,266

6. ASSET RETIREMENT OBLIGATIONS

The following table reconciles the change in Vermilion's asset retirement obligations:

($M)	Asset Retirement Obligations
Balance at January 1, 2013		371,063
Additional obligations recognized		15,655
Changes in estimates for existing obligations		(21,068)
Obligations settled		(11,922)
Accretion		24,565
Changes in discount rates		(73,675)
Effect of movements in foreign exchange rates		21,544
Balance at December 31, 2013		326,162
Additional obligations recognized		19,919
Obligations settled		(9,709)
Accretion		17,726
Changes in discount rates		51,582
Effect of movements in foreign exchange rates		(7,760)
Balance at September 30, 2014		397,920

7. LONG-TERM DEBT

The following table summarizes Vermilion's outstanding long-term debt:

	As At
($M)	Sept 30, 2014		Dec 31, 2013
Revolving credit facility		974,857		766,898
Senior unsecured notes		223,791		223,126
Long-term debt		1,198,648		990,024

Revolving Credit Facility

At September 30, 2014, Vermilion had in place a bank revolving credit facility totalling $1.5 billion, of which approximately $974.9 million was drawn. In addition, Vermilion may, by adding lenders or seeking an increase to an existing lender's commitment, increase the total committed facility amount to no more than $1.75 billion. The facility, which matures on May 31, 2017, is fully revolving up to the date of maturity.

The facility is extendable from time to time, but not more than once per year, for a period not longer than three years, at the option of the lenders and upon notice from Vermilion. If no extension is granted by the lenders, the amounts owing pursuant to the facility are repayable on the maturity date. This facility bears interest at a rate applicable to demand loans plus applicable margins. For the nine months ended September 30, 2014, the interest rate on the revolving credit facility was approximately 3.2%.

The amount available to Vermilion under this facility is reduced by certain outstanding letters of credit associated with Vermilion's operations totalling $10.3 million as at September 30, 2014 (December 31, 2013 - $8.1 million).

The facility is secured by various fixed and floating charges against the subsidiaries of Vermilion. Under the terms of the facility, Vermilion must maintain:

A ratio of total bank borrowings (defined as consolidated total debt), to consolidated net earnings before interest, income taxes, depreciation, accretion and other certain non-cash items (defined as consolidated EBITDA) of not greater than 4.0.
A ratio of consolidated total senior debt (defined as consolidated total debt excluding unsecured and subordinated debt) to consolidated EBITDA of not greater than 3.0.
A ratio of consolidated total senior debt to total capitalization (defined as amounts classified as "Long-term debt" and "Shareholders' Equity" on the balance sheet) of less than 50%.

As at September 30, 2014, Vermilion was in compliance with all financial covenants.

Senior Unsecured Notes

On February 10, 2011, Vermilion issued $225.0 million of senior unsecured notes at par. The notes bear interest at a rate of 6.5% per annum and will mature on February 10, 2016. As direct senior unsecured obligations of Vermilion, the notes rank pari passu with all other present and future unsecured and unsubordinated indebtedness of the Company.

8. SHAREHOLDERS' CAPITAL

The following table reconciles the change in Vermilion's shareholders' capital:

Shareholders' Capital	Number of Shares ('000s)		Amount ($M)
Balance as at January 1, 2013		99,135	1,481,345
Shares issued pursuant to the dividend reinvestment plan		1,402	72,291
Vesting of equity based awards		1,372	54,370
Share-settled dividends on vested equity based awards		202	9,808
Shares issued pursuant to the bonus plan		12	629
Balance as at December 31, 2013		102,123	1,618,443
Shares issued pursuant to corporate acquisition		2,827	204,960
Shares issued pursuant to the dividend reinvestment plan		902	58,450
Vesting of equity based awards		950	47,657
Share-settled dividends on vested equity based awards		108	7,519
Shares issued pursuant to the bonus plan		11	721
Balance as at September 30, 2014		106,921	1,937,750

Dividends declared to shareholders for the nine months ended September 30, 2014 were $203.6 million (2013 - $181.4 million).

Subsequent to the end of the period and prior to the condensed consolidated interim financial statements being authorized for issue on November 6, 2014, Vermilion declared dividends totalling $23.0 million or $0.215 per share.

9. EQUITY BASED COMPENSATION

The following table summarizes the number of awards outstanding under the Vermilion Incentive Plan ("VIP"):

Number of Awards ('000s)	2014	2013
Opening balance	1,665	1,690
Granted	616	832
Vested	(512)	(749)
Modified	(21)	-
Forfeited	(53)	(108)
Closing balance	1,695	1,665

The fair value of a VIP award is determined on the grant date at the closing price of Vermilion's common shares on the Toronto Stock Exchange, adjusted by the estimated performance factor that will ultimately be achieved.

On March 31, 2014, Vermilion modified the accounting for certain outstanding VIP awards to be settled by purchasing Vermilion common shares on the Toronto Stock Exchange upon vesting rather than by issuing common shares through treasury. Pursuant to this modification, $2.4 million was reclassified from "Contributed surplus" to "Accounts payable and accrued liabilities". Subsequent period expense relating to these outstanding awards will be recognized in "General and administration expense".

10. SEGMENTED INFORMATION

Vermilion has operations principally in Canada, France, the Netherlands, Germany, Ireland, and Australia. Vermilion's operating activities in each country relate solely to the exploration, development and production of petroleum and natural gas. Vermilion has a Corporate head office located in Calgary, Alberta. Costs incurred in the Corporate segment relate to Vermilion's global hedging program and expenses incurred in financing and managing our operating business units.

Vermilion's chief operating decision maker reviews the financial performance of the Company by assessing the fund flows from operations of each country individually. Fund flows from operations provides a measure of each business unit's ability to generate cash (that is not subject to short-term movements in non-cash operating working capital) necessary to pay dividends, fund asset retirement obligations, and make capital investments.

	Three Months Ended September 30, 2014
($M)	Canada	France	Netherlands	Germany	Ireland	Australia	Corporate	Total
Drilling and development	88,116	34,883	10,087	1,358	30,050	15,985	-	180,479
Exploration and evaluation	9,277	199	-	-	-	-	78	9,554
Oil and gas sales to external customers	138,853	106,576	26,960	8,591	-	63,708	-	344,688
Royalties	(19,034)	(6,978)	(942)	(2,046)	-	-	-	(29,000)
Revenue from external customers	119,819	99,598	26,018	6,545	-	63,708	-	315,688
Transportation expense	(4,048)	(4,741)	-	(675)	(1,515)	-	-	(10,979)
Operating expense	(19,074)	(15,215)	(5,409)	(2,227)	-	(14,302)	-	(56,227)
General and administration	(4,523)	(6,411)	(204)	(1,090)	(334)	(1,378)	(2,322)	(16,262)
PRRT	-	-	-	-	-	(13,834)	-	(13,834)
Corporate income taxes	-	(10,744)	(1,189)	(146)	-	(5,148)	(227)	(17,454)
Interest expense	-	-	-	-	-	-	(12,918)	(12,918)
Realized gain on derivative instruments	-	-	-	-	-	-	8,837	8,837
Realized foreign exchange gain	-	-	-	-	-	-	812	812
Realized other income	-	-	-	-	-	-	235	235
Fund flows from operations	92,174	62,487	19,216	2,407	(1,849)	29,046	(5,583)	197,898


	Three Months Ended September 30, 2013
($M)	Canada	France	Netherlands	Germany	Ireland	Australia	Corporate	Total
Drilling and development	61,719	23,664	8,316	-	35,028	5,880	503	135,110
Exploration and evaluation	551	-	-	-	-	-	-	551
Oil and gas sales to external customers	100,000	120,574	27,382	-	-	79,229	-	327,185
Royalties	(11,156)	(7,574)	-	-	-	-	-	(18,730)
Revenue from external customers	88,844	113,000	27,382	-	-	79,229	-	308,455
Transportation expense	(3,272)	(2,713)	-	-	(564)	-	-	(6,549)
Operating expense	(12,770)	(14,599)	(5,209)	-	-	(13,668)	-	(46,246)
General and administration	(3,484)	(4,964)	(333)	-	(312)	(1,414)	(1,526)	(12,033)
PRRT	-	-	-	-	-	(15,649)	-	(15,649)
Corporate income taxes	-	(31,717)	(6,810)	-	-	(7,666)	(260)	(46,453)
Interest expense	-	-	-	-	-	-	(10,109)	(10,109)
Realized loss on derivative instruments	-	-	-	-	-	-	(4,765)	(4,765)
Realized foreign exchange loss	-	-	-	-	-	-	(1,227)	(1,227)
Realized other income	-	-	-	-	-	-	221	221
Fund flows from operations	69,318	59,007	15,030	-	(876)	40,832	(17,666)	165,645


	Nine Months Ended September 30, 2014
($M)	Canada	France	Netherlands	Germany	Ireland	Australia	Corporate	Total
Total assets	1,857,012	894,060	237,070	164,025	809,296	269,959	206,305	4,437,727
Drilling and development	215,860	99,564	43,512	2,184	73,507	32,667	-	467,294
Exploration and evaluation	33,440	11,099	8,206	-	-	-	1,442	54,187
Oil and gas sales to external customers	425,294	348,753	98,395	28,603	-	212,510	-	1,113,555
Royalties	(49,937)	(22,125)	(3,843)	(6,132)	-	-	-	(82,037)
Revenue from external customers	375,357	326,628	94,552	22,471	-	212,510	-	1,031,518
Transportation expense	(11,170)	(14,879)	-	(2,149)	(4,674)	-	-	(32,872)
Operating expense	(56,863)	(48,185)	(17,841)	(5,824)	-	(43,713)	-	(172,426)
General and administration	(13,951)	(17,164)	(1,128)	(2,488)	(868)	(4,245)	(8,647)	(48,491)
PRRT	-	-	-	-	-	(46,772)	-	(46,772)
Corporate income taxes	-	(60,769)	(6,278)	(1,189)	-	(19,678)	(778)	(88,692)
Interest expense	-	-	-	-	-	-	(36,712)	(36,712)
Realized gain on derivative instruments	-	-	-	-	-	-	13,896	13,896
Realized foreign exchange loss	-	-	-	-	-	-	(642)	(642)
Realized other income	-	-	-	-	-	-	530	530
Fund flows from operations	293,373	185,631	69,305	10,821	(5,542)	98,102	(32,353)	619,337


	Nine Months Ended September 30, 2013
($M)	Canada	France	Netherlands	Germany	Ireland	Australia	Corporate	Total
Total assets	1,141,499	930,568	144,813	-	697,120	301,350	209,075	3,424,425
Drilling and development	158,519	68,479	14,472	-	76,426	69,511	2,228	389,635
Exploration and evaluation	12,433	-	-	-	-	-	807	13,240
Oil and gas sales to external customers	284,638	342,558	100,119	-	-	221,412	-	948,727
Royalties	(29,852)	(20,468)	-	-	-	-	-	(50,320)
Revenue from external customers	254,786	322,090	100,119	-	-	221,412	-	898,407
Transportation expense	(8,152)	(7,883)	-	-	(3,808)	-	-	(19,843)
Operating expense	(42,586)	(51,473)	(14,438)	-	-	(38,406)	-	(146,903)
General and administration	(10,501)	(14,577)	(1,171)	-	(959)	(4,310)	(4,438)	(35,956)
PRRT	-	-	-	-	-	(39,392)	-	(39,392)
Corporate income taxes	-	(66,500)	(25,865)	-	-	(25,525)	(839)	(118,729)
Interest expense	-	-	-	-	-	-	(28,134)	(28,134)
Realized loss on derivative instruments	-	-	-	-	-	-	(5,782)	(5,782)
Realized foreign exchange loss	-	-	-	-	-	-	(572)	(572)
Realized other income	-	-	-	-	-	-	770	770
Fund flows from operations	193,547	181,657	58,645	-	(4,767)	113,779	(38,995)	503,866

Reconciliation of fund flows from operations to net earnings

	Three Months Ended		Nine Months Ended
	Sep 30,	Sep 30,	Sep 30,	Sep 30,
($M)	2014	2013	2014	2013
Fund flows from operations	197,898	165,645	619,337	503,866
Equity based compensation	(14,720)	(12,779)	(49,409)	(39,639)
Unrealized gain (loss) on derivative instruments	7,800	(3,699)	10,214	3,839
Unrealized foreign exchange (loss) gain	(11,867)	4,232	(13,613)	29,738
Unrealized other expense	(597)	(276)	(747)	(1,029)
Accretion	(6,064)	(6,214)	(17,726)	(18,038)
Depletion and depreciation	(104,159)	(78,826)	(308,513)	(238,692)
Deferred taxes	(14,388)	(287)	(28,859)	(13,914)
Net earnings	53,903	67,796	210,684	226,131

11. CAPITAL DISCLOSURES

	Three Months Ended		Nine Months Ended
($M except as indicated)	September 30, 2014	September 30, 2013	September 30, 2014	September 30, 2013
Long-term debt	1,198,648	781,074	1,198,648	781,074
Current liabilities	431,175	389,757	431,175	389,757
Current assets	(386,385)	(470,545)	(386,385)	(470,545)
Net debt [1]	1,243,438	700,286	1,243,438	700,286

Cash flows from operating activities	235,010	158,236	562,840	528,022
Changes in non-cash operating working capital	(41,789)	4,671	46,788	(30,652)
Asset retirement obligations settled	4,677	2,738	9,709	6,496
Fund flows from operations	197,898	165,645	619,337	503,866
Annualized fund flows from operations [2]	791,592	662,580	825,783	671,821

Ratio of net debt to annualized fund flows from operations ([1] ÷ [2])	1.6	1.1	1.5	1.0

As year-to-date fund flows does not include a full year of fund flows from the acquisitions in Germany and Saskatchewan, the ratio of net debt to annualized fund flows increased to 1.5.

12. FINANCIAL INSTRUMENTS

Classification of Financial Instruments

The following table summarizes information relating to Vermilion's financial instruments as at September 30, 2014 and December 31, 2013:

As at Sep 30, 2014

As at Dec 31, 2013

Class of financial
instrument

Consolidated balance
sheet caption

Accounting
designation

Related caption on Statement of Net
Earnings

Carrying
value ($M)

Fair value
($M)

Carrying
value ($M)

Fair value
($M)

Fair value
measurement
hierarchy

Cash

Cash and cash equivalents

HFT

Gains and losses on foreign exchange are included in foreign exchange loss (gain)

142,520

389,559

Level 1

Receivables

Accounts receivable

LAR

Gains and losses on foreign exchange are included in foreign exchange loss (gain) and impairments are recognized as general and administration expense

199,574

167,618

Not applicable

Derivative assets

Derivative instruments

HFT

(Gain) loss on derivative instruments

9,341

2,285

Level 2

Derivative liabilities

Derivative instruments

HFT

(Gain) loss on derivative instruments

(1,704)

(3,572)

Level 2

Payables

Accounts payable and accrued liabilities

OTH

Gains and losses on foreign exchange are included in foreign exchange loss (gain)

(346,735)

(288,257)

Not applicable

Dividends payable

Long-term debt

OTH

Interest expense

(1,198,648)

(1,199,295)

(990,024)

(998,648)

Level 2

The accounting designations used in the above table refer to the following:

HFT - Classified as "Held for trading" in accordance with International Accounting Standard 39 "Financial Instruments: Recognition and Measurement". These financial assets and liabilities are carried at fair value on the consolidated balance sheets with associated gains and losses reflected in net earnings.

LAR - "Loans and receivables" are initially recognized at fair value and are subsequently measured at amortized cost. Impairments and foreign exchange gains and losses are recognized in net earnings.

OTH - "Other financial liabilities" are initially recognized at fair value net of transaction costs directly attributable to the issuance of the instrument and subsequently are measured at amortized cost. Interest is recognized in net earnings using the effective interest method. Foreign exchange gains and losses are recognized in net earnings.

Level 1 - Fair value measurement is determined by reference to unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 - Fair value measurement is determined based on inputs other than unadjusted quoted prices that are observable, either directly or indirectly.

Level 3 - Fair value measurement is based on inputs for the asset or liability that are not based on observable market data.

Determination of Fair Values

The level in the fair value hierarchy into which the fair value measurements are categorized is determined on the basis of the lowest level input that is significant to the fair value measurement. Transfers between levels on the fair value hierarchy are deemed to have occurred at the end of the reporting period.

Fair values for derivative assets and derivative liabilities are determined using pricing models incorporating future prices that are based on assumptions which are supported by prices from observable market transactions and are adjusted for credit risk.

The carrying value of receivables approximate their fair value due to their short maturities.

The carrying value of long-term debt outstanding on the revolving credit facility approximates its fair value due to the use of short-term borrowing instruments at market rates of interest.

The fair value of the senior unsecured notes changes in response to changes in the market rates of interest payable on similar instruments and was determined with reference to prevailing market rates for such instruments.

Nature and Extent of Risks Arising from Financial Instruments

Market risk:
Vermilion's financial instruments are exposed to currency risk related to changes in foreign currency denominated financial instruments and commodity price risk related to outstanding derivative positions. The following table summarizes what the impact on comprehensive income before tax would be for the nine months ended September 30, 2014 given changes in the relevant risk variables that Vermilion considers were reasonably possible at the balance sheet date. The impact on comprehensive income before tax associated with changes in these risk variables for assets and liabilities that are not considered financial instruments are excluded from this analysis. This analysis does not attempt to reflect any interdependencies between the relevant risk variables.

	Before tax effect on comprehensive
	income - increase (decrease)
Risk ($M)	Description of change in risk variable	September 30, 2014
Currency risk - Euro to Canadian	Increase in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates	(4,565)

	Decrease in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates	4,565

Currency risk - US $ to Canadian	Increase in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates	(4,029)

	Decrease in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates	4,029

Commodity price risk	Increase in relevant oil reference price within option pricing models used to determine	(5,015)
	the fair value of financial derivatives by US $5.00/bbl at the relevant valuation dates

	Decrease in relevant oil reference price within option pricing models used to determine	4,686
	the fair value of financial derivatives by US $5.00/bbl at the relevant valuation dates

Interest rate risk	Increase in average Canadian prime interest rate by 100 basis points during the relevant periods	(6,519)

	Decrease in average Canadian prime interest rate by 100 basis points during the relevant periods	6,519

SOURCE: Vermilion Energy Inc.

Lorenzo Donadeo, Chief Executive Officer;
Anthony Marino, President & COO;
Curtis W. Hicks, Executive VP & CFO; and/or
Dean Morrison, Director Investor Relations
TEL (403) 269-4884
IR TOLL FREE 1-866-895-8101
[email protected]
www.vermilionenergy.com

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