Gran Tierra to Host Fourth Quarter 2014 Earnings Conference Call

CALGARY , Feb. 28, 2015 /CNW/ - Gran Tierra Energy Inc. (NYSE MKT; TSX: GTE) (" Gran Tierra" ) , a company focused on oil and gas exploration and production in South America , today announced that it plans to host its earnings conference call on March 2, 2015 at 10:00 a.m. Eastern Time .

Executive Chairman, Jeffrey Scott , Interim President and CEO, Duncan Nightingale and CFO, James Rozon will assume the results are reviewed by participants prior to the call and immediately take questions from securities analysts and institutional shareholders.

Interested parties may access the conference call by dialing 1 (800) 688-0836 (domestic) or 1 (617) 614-4072 (international), passcode 98393662. The call will also be available via web cast at www.grantierra.com or www.streetevents.com .

If you are unable to participate, an audio replay of the call will be available beginning at 1:00 p.m. Eastern Time on March 2, 2015 until 11:59 p.m. Eastern Time on April 3, 2015 . To access the replay dial 1 (888) 286 8010 (domestic) or 1 (617) 801 6888 (international) pass code 51686433.

Please connect at least 15 minutes prior to the conference call to ensure adequate time for any software to download that may be required to join the webcast.

About Gran Tierra Energy Inc.

Gran Tierra is an international oil and gas exploration and production company, headquartered in Calgary, Canada , incorporated in the United States , trading on the NYSE MKT (GTE) and the Toronto Stock Exchange (GTE), and operating in South America . Gran Tierra holds interests in producing and prospective properties in Colombia , Peru and Brazil . Gran Tierra has a strategy that focuses on establishing a portfolio of producing properties, plus production enhancement and exploration opportunities to provide a base for future growth.

Gran Tierra's Securities and Exchange Commission filings are available on a web site maintained by the Securities and Exchange Commission at http://www.sec.gov and on SEDAR at http://www.sedar.com .

SOURCE Gran Tierra Energy Inc.

Calvalley Petroleum Inc., (TSX: CVI.A) announces results for the fourth quarter and year ended December 31, 2014 and provides operations update

CALGARY , Feb. 27, 2015 /CNW/ -

Highlights

  • During 2014 the Company was unable to carry out many elements of its development plan for the Yemen assets due to restrictions on the availability of services. Yemen has been subject to significant political uncertainty during the year and the situation has yet to stabilize. The safety and security of staff in the region is of critical importance to the Company. The uncertain security situation in the country has made it very difficult to mobilize the necessary equipment and personnel into Yemen and, as a result, development projects are being deferred indefinitely.
  • Due in part to the decline in world oil prices, the Company's results for both the quarter and the year have been significantly impacted by a non-cash impairment provision. The calculation for the impairment provision has been based on the Company's production profile under its proved plus probable reserve development case, a price forecast based on prices indicated by the forward pricing curve as at January 7, 2015 , and a discount rate of 30%. If the Company had used as a basis the proved developed producing reserve volume forecast, the price forecast adopted by the independent engineering firm for the Company's reserve evaluation, and a discount rate of 20%, the non-cash impairment amount would not be significantly different.
  • Excluding the impairment provision of $88.1 million , the Company incurred a loss of $0.00 per share ( $0.3 million ) in the fourth quarter of 2014 compared to earnings of $0.08 per share ( $6.0 million ) in the fourth quarter of 2013. For the year ended December 31, 2014 , excluding the impairment provision, earnings were $0.00 per share ( $0.2 million ) compared to $0.28 per share ( $23.2 million ) in 2013. Inventory of crude oil at the end of December 31, 2014 was approximately 46,200 barrels and represents an increase of 16,600 barrels from December 31, 2013 .
  • The Company's working interest share of production volumes before royalties and taxes averaged 1,430 barrels per day for the year representing a 43 per cent decline from 2,520 barrels per day for 2013. For the fourth quarter of 2014 production volumes were 1,760 barrels per day compared to 2,390 barrels per day in the comparable period of 2013. The decline in production year over year is due to a combination of the shut-in of the Al Roidhat field, due to marketing restrictions, and production curtailments experienced during the year. During the fourth quarter of 2014, production operations were curtailed for ten days due to a labour dispute.

  • In the fourth quarter of 2014 the Company sold an average of 2,920 barrels per day of crude oil compared to 2,460 barrels per day in the comparable period of 2013. For the year ended December 31, 2014 crude oil exports have averaged 1,260 barrels per day compared to 2,330 barrels per day in the comparable period of 2013. For the fourth quarter of 2014, the average sale price received was $74.23 per barrel which represents a discount of $2.35 to the Dated Brent Crude price of $76.58 for the quarter. The product netback for the last quarter of 2014 was $16.82 per barrel, and for the year ended December 31, 2014 , the netback of $22.49 per barrel represents a decrease of 47 per cent from $42.13 per barrel for 2013 reflecting both lower realized prices for crude oil and higher operating costs.

  • Funds flow from operations ("Cash Flow") for the fourth quarter was $0.03 per share ( $2.6 million ) compared to $0.10 per share ( $8.0 million ) in the prior year period. For the year ended December 31, 2014 Cash Flow was $0.07 per share ( $5.2 million ) down 82 per cent from $0.38 per share ( $31.2 million ) in the prior year period.

  • Capital expenditures in the fourth quarter of $2.3 million include the costs of equipment ordered earlier in 2014 for the planned capital program and received in Yemen in the quarter and project services and are down from $2.8 million in the fourth quarter of 2013. Capital expenditures for the year of $6.8 million are down 29 per cent from capital expenditures of $9.6 million for 2013.

  • During the fourth quarter the Company purchased for cancellation 3,403,837 shares at an average price of $1.12 (CAD$1.27) per share under the Company's normal course issuer bid ("NCIB"). For the year ended December 31, 2014 the Company has purchased for cancellation a total of 3,655,006 shares at an average price of $1.14 (CAD$1.29) per share under the NCIB.

  • The annual "per share" calculations included in this release are based on 77,217,884 weighted average number of shares outstanding. The fourth quarter "per share" amounts are based on 75,126,232 weighted average number of shares outstanding. The Company had 74,386,820 shares outstanding at December 31, 2014 .

  • On August 18, 2014 the Board of directors declared a special dividend of C$0.07 per common share payable to shareholders of record on August 29, 2014 . The dividend was paid in cash on September 15, 2014 .

  • Calvalley has a strong balance sheet with approximately $75 million in working capital at December 31, 2014 . The value of the volumes of crude oil held in inventory at December 31, 2014 reflect market value.

Operations Update

In early February, 2015 members of the cabinet of the Government of Yemen resigned and, more recently, several foreign embassies have closed their offices and suspended diplomatic services. Amidst the significant concerns for the safety and security of all Yemen staff, contractors and foreign workers and the uncertain political environment the Company is maintaining production operations, however, all activity on capital projects is being deferred until the business and operating environment improves.

The Company has recently closed its technical office in London and is reducing working hours and salaries for all management and staff in the Calgary office to reduce its fixed costs of operation.

The Company's agreement in Yemen is a production sharing agreement. The agreement effectively defines each party's interest in each barrel of oil sold. Management uses this production sharing entitlement as an indicator for decision making to ensure profitability under the agreement is optimized both in the short term and the long term.

To optimize profitability, it is advantageous to ensure that the total cost incurred to produce a barrel of oil is less than the effective cost of the pro-rata entitlement under the production sharing agreement allocated for the recovery of costs, which is referred to as "Cost Oil". The agreement effectively allows 45 percent of each barrel sold as Cost Oil to cover allowable operating costs, G&A costs and current and historical capital costs incurred. As noted in the highlight section, operating costs of $26.45 per barrel in Yemen were up significantly in 2014 due mainly to the lower volume of crude oil produced. Incorporating estimated G&A costs to establish an estimate for total allowable costs incurred (excluding capital costs), total estimated allowable costs incurred in 2014 exceeded $33 on a per barrel basis.

To ensure the Company is capable of recovering current and historical operating, G&A and capital costs under the agreement, using the referenced estimated allowable cost per barrel of $33 per barrel (operating and G&A costs only), and grossing this per barrel cost using a denominator of 45%, the calculated required sales price for a barrel of crude oil is approximately $73 per barrel.

Using an estimated allowable cost per barrel to cover operating and G&A costs (excluding capital costs) of $25 per barrel, the calculated required sales price for a barrel of crude oil, which ensures the Company is effectively recovering its costs incurred, is approximately $55 per barrel.

To ensure the Company manages through an extended period of anticipated low crude oil prices, the Company is making every effort to work with all stakeholders in Block 9 to manage costs effectively in order that the impact of reduced revenues is shared fairly by all stakeholders.

Corporate Update

The Company has reviewed several diversification opportunities outside Yemen . No potential transactions have been identified to date.

Calvalley has a healthy balance of cash and working capital for investment purposes and will continue to review investment, diversification and other opportunities that can optimize shareholder value.

The Company welcomes Nabil Nassef , P. Eng. to the Board of Directors of Calvalley. Nabil is a graduate in Civil Engineering from the University of Alberta . Nabil has over 35 years of experience in the oil and gas industry in both Western Canada and more recently in Yemen . Nabil represented Calvalley as General Manager in Yemen during the years 2000 to 2009. Nabil is fluent in speaking, writing and translating the Arabic language. Nabil currently provides consulting services to Calvalley in an advisory capacity.

On February 23, 2015 the Alberta Securities Commission (the "ASC"), released its decision and dismissed all allegations against the Company and former employees.  A copy of the decision is available on the ASC website.  The ASC alleged that in early 2009 the Company purchased shares pursuant to a normal course issuer bid while in possession of material information relating to its reserves which had not been disclosed to the public.  The Commission found that the information in question was not material.  With respect to allegations against the Chairman and CEO of the Company, the ASC found that his conduct breached section 221.1(2) of the Securities Act ( Alberta ) and was contrary to the public interest by making a misleading or untrue statement to ASC Staff during a formal investigative interview.  The Commission's conclusion is set out at page 85 of the ASC decision.  The matter will now move to a second phase to determine whether (and, if so, what) orders for sanctions and costs ought to be made.  The ASC decision also commented on various practices followed by the Company at the material time.  The Company is currently reviewing the decision to determine whether additional modifications to current practices are advisable. The Board of Directors fully supports this initiative.

Financial information

Significant financial information is included in the table below and is discussed further in the Company's Management Discussion and Analysis.

Three months ended
December 31

Year ended
December 31

(in thousands of US dollars except per share amounts)

2014

2013

2014

2013

Revenue (Gross)

19,964

25,065

39,851

92,960

Revenue from crude oil sales (net of royalties)

12,511

15,707

24,984

58,264

Adjusted EBITDA (1)

3,739

9,451

7,133

36,477

Operating income (loss) (1)

(87,207)

7,524

(85,720)

29,063

Earnings (loss)

(88,444)

5,999

(87,911)

23,176

Per share

(1.18)

0.08

(1.14)

0.28

Capital expenditures

2,332

2,815

6,784

9,588

Funds flow from operations (1)

2,598

8,042

5,163

31,179

Per share

0.03

0.10

0.07

0.38

Cash flow from operating activities

5,056

6,267

5,564

30,360

(1)

See "Non-IFRS Measures" disclosure in December 31, 2014 MD&A filed on www.sedar.com which is incorporated herein by reference

FILING OF REPORTS ON SEDAR

Calvalley's Management's Discussion and Analysis and Audited Condensed Consolidated Financial Statements for the year ended December 31, 2014 can be found for viewing by electronic means on The System for Electronic Document Analysis and Retrieval at www.sedar.com . They can also be found on the Company's website at www.calvalleypetroleum.com .

Calvalley is an international oil and gas company, with offices in Calgary, Alberta, Canada , that operates its 50% working interest in Block 9 of the Masila Basin, in The Republic of Yemen .

Forward-looking Information
This press release may contain forward-looking information. Words such as "may", "will", "should", "could", "anticipate", "believe", "expect", "intend", "plan", "potential", "continue", and similar expressions may have been used to identify this forward-looking information. These statements reflect management's current beliefs and are based on information currently available to management. In particular, statements in respect to deferring development projects in Yemen , and reviewing investment, diversification and other opportunities to optimize shareholder value contain forward looking information. Forward-looking information involves significant risk and uncertainties. A number of factors could cause actual results to differ materially from the results discussed in the forward-looking information including, but not limited to, operational risks, availability of supplies and services, potential delays or changes in plans with respect to exploration or development projects or capital expenditures, delays and interruptions in drilling and completion activities for undetermined periods, success in drilling activities, changes in general economic and market conditions and other risk factors. Although the forward-looking information contained herein are based upon what management believes to be reasonable assumptions, management cannot assure that actual results will be consistent with this forward-looking information. Investors should not place undue reliance on forward-looking information. The forward-looking information contained herein is expressly qualified in its entirety by this cautionary statement. The forward-looking information included in this press release is made as of the date of this press release and Calvalley assumes no obligation to update or revise it to reflect new events or circumstances except as expressly required by applicable securities law.

SOURCE Calvalley Petroleum Inc.

MATRRIX Provides Operations Update and Announces Grant of Stock Options

CALGARY , Feb. 27, 2015 /CNW/ - MATRRIX Energy Technologies Inc. ("MATRRIX" or the "Corporation") (TSX-V: MXX) is pleased to provide an operations update and announce the grant of stock options to certain directors, officers and employees.

Operations Update

Current oil and gas commodity price weakness continues to create uncertainty regarding capital expenditures for oil and gas clients in Western Canada , the Corporation's primary operating area. With this uncertainty, the severity and length of the downturn in client activity levels is difficult to predict. The Corporation anticipates materially lower activity levels in the first quarter of 2015 compared to the same period in 2014, and compared to the last quarter of 2014.

As a result, the Corporation remains committed to its previously announced minimal capital expenditure budget for 2015 which the Corporation believes reflects a prudent use of its capital while ensuring sufficient financial flexibility in the event of a prolonged downturn in industry activity levels.

MATRRIX will continuously evaluate the needs of its clients and its operations, and will adjust capital budgets as required to meet client needs and activity levels.

MATRRIX has reduced costs through adjustments to staffing levels and wages in the office and field, consolidated offices and facilities where practical, and reduced costs through analysis and negotiation with current and prospective vendors.

The Corporation remains committed to its program of innovative technology initiatives core to exceptional service delivery for its clients, while providing field data quality and efficiency improvements to clients and the Corporation.

The Corporation has a strong working capital position, and no debt.

Appointment of Interim Chief Financial Officer

MATRRIX is pleased to announce the appointment of Jeff Schab as the Corporation's Interim Chief Financial Officer. Mr. Schab, a Certified Accountant, previously held the role of Manager, Financial Reporting and Tax with the Corporation.

Grant of Stock Options

The Corporation announces that it has granted an aggregate of 492,000 stock options (the "Options") to certain directors, officers and employees pursuant to the Corporation's incentive stock option plan, at an exercise price of $0.36 per share, being the closing price of MATRRIX stock on Friday February, 27, 2015. All Options are subject to vesting as to one third a year from the date of grant, one third two years from the date of grant and the remaining third vesting three years from the date of grant. Once vested, the options can be exercised and have an expiration date that is one year from the date of vesting. The grant of Options is subject to applicable stock exchange and regulatory approvals.

FORWARD-LOOKING INFORMATION

This press release contains certain statements or disclosures relating to MATRRIX that are based on the expectations of MATRRIX as well as assumptions made by and information currently available to MATRRIX which may constitute forward-looking information under applicable securities laws. In particular, this press release contains forward-looking information related to the Corporation's 2015 capital budget, lower industry activity levels resulting uncertainty related to commodity price weakness, the amount, if any, drawn on its credit facility, the ability of the Corporation to manage liquidity, seasonal cash flows and the ability to anticipate and react to customer activity levels, the anticipated benefits of cost reduction measures, including reduced staffing levels, office and facility consolidations and negotiations with vendors.  Such forward-looking information involves material assumptions and known and unknown risks and uncertainties, certain of which are beyond MATRRIX's control.  Many factors could cause the performance or achievement by MATRRIX to be materially different from any future results, performance or achievements that may be expressed or implied by such forward looking information, which could have a material impact on the Corporation's working capital position and its ability to meet its obligations under the terms of the credit facility. MATRRIX's documents filed with securities regulatory authorities (accessible through the SEDAR website www.sedar.com ) describe the risks, material assumptions and other factors that could influence actual results and which are incorporated herein by reference. Accordingly, readers should not place undue reliance on forward-looking statements.  MATRRIX disclaims any intention or obligation to publicly update or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as may be expressly required by applicable securities laws.

ABOUT MATRRIX

MATRRIX provides horizontal and directional drilling services for the oil and gas industry in western Canada and vertical well monitoring and performance drilling services for the oil and gas industry in the Permian basin in the United States .

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

SOURCE MATRRIX Energy Technologies Inc.

Africa Oil Updated Share Capital and Voting Rights

VANCOUVER, BRITISH COLUMBIA--(Marketwired - Feb. 27, 2015) - Africa Oil Corp. ("Africa Oil" or the "Company") (TSX:AOI)(OMX:AOI) reports that in accordance with the Swedish Financial Instruments Trading Act, the Company announces the following:

As a result of the issuance of shares pursuant to closing a private placement and the exercise of employee stock options, as at February 27, 2015, the number of issued and outstanding shares of the Company is 369,954,649 common shares with voting rights.

About Africa Oil Corp.

Africa Oil Corp. is a Canadian oil and gas company with assets in Kenya and Ethiopia as well as Puntland (Somalia) through its 45% equity interest in Horn Petroleum Corporation. The Company is listed on the Toronto Stock Exchange and on Nasdaq Stockholm under the symbol "AOI".

ON BEHALF OF THE BOARD

Keith C. Hill, President and CEO

Africa Oil Corp.
Sophia Shane
Corporate Development
(604) 689-7842
(604) 689-4250 (FAX)
[email protected]
www.africaoilcorp.com

PetroMaroc Announces Resignation of a Director

CALGARY, ALBERTA--(Marketwired - Feb. 27, 2015) - PetroMaroc Corporation plc (TSX VENTURE:PMA) (the "Company" or "PetroMaroc") today announced the resignation of Yogeshwar Sharma from the board of directors (the "Board") of the Company effective immediately. Due to Mr. Sharma's continuing commitments and time constraints, he has concluded that he would not be able to devote sufficient time to the Company and exercise his director duties diligently.

Dennis A. Sharp, Chairman of the Board, stated "PetroMaroc's Board sincerely thanks Mr. Sharma for all of his efforts and continuing support of the Company and wishes him well in his future endeavours."

About PetroMaroc

PetroMaroc is an independent oil and gas company focused on its significant land position in Morocco. The Company has a 50 percent operated interest in the Sidi Moktar licence area covering 2,683 square kilometres and is working closely with Morocco's National Office of Hydrocarbons and Mines (ONHYM) as a committed long-term partner to unlock the hydrocarbon potential of the region. Morocco offers a politically stable environment to work within and has favourable fiscal terms to energy producers. PetroMaroc is a public company listed on the TSX Venture Exchange under the symbol "PMA".

Additional information about the Company can be found at www.petromaroc.co and under the Company's SEDAR profile at www.sedar.com .

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

PetroMaroc Corporation plc
Tom Feuchtwanger
President and Chief Executive Officer
+1 403 474 2775

PetroMaroc Corporation plc
Martin Arch
Chief Financial Officer and Secretary
+44 (0) 20 3137 7756

EmberClear Corp. Announces Second Quarter 2015 Results

CALGARY , Feb. 27, 2015 /CNW/ - EmberClear Corp. (TSXV: EMB) ("EMB" or "EmberClear") today announced its unaudited financial results for the six and three month periods ended December 31, 2014 .

EMB's net loss for the six month period decreased by 47.9% to $1,142,388 from a loss of $2,194,322 for the same period in the prior year.

David Anderson , CEO, commented: "We continue to see the positive results of our cost cutting measures while we add to our portfolio of projects that use natural gas as a feedstock."

EMB's financial statements, management's discussion and analysis, and related information can be found on SEDAR at www.sedar.com .

About EmberClear
EmberClear is an energy developer focused on low emission commercial scale projects primarily in North America . Developing facilities using natural gas as inputs to create electricity or transportation fuels characterizes our plants. We utilize our proven expertise in permitting, site control and engineering feasibility to develop projects that are sold to investors interested in purchasing, constructing and operating such energy projects. EmberClear is developing gas to liquids (GTL) and gas to power (NGCC) generating facilities in North America . Our NGCC Projects benefit from a favorable geographic location that offers access to abundant natural gas reserves and a power market that is served primarily by older, coal fired, electric generation facilities, expected to be phased out over time.  EmberClear also holds surface and mineral rights in Schuylkill County, Pennsylvania . This property is situated in the Southern Anthracite coalfield of eastern Pennsylvania, USA . Mineral rights held by the company include Anthracite/PCI coal suitable for the steel making industry. EmberClear's shares are listed on the TSX Venture Exchange under the trading symbol "EMB". For more information, please visit www.emberclear.com

Forward-Looking Statement Disclaimer
Certain statements contained in this document constitute forward-looking statements or information (collectively "forward-looking statements") within the meaning of applicable securities legislation. Forward-looking statements are typically identified by words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "could", "plan", "intend", "should", "believe", "outlook", "potential", "target", "seek", "budget", "predict", "might" and similar words suggesting future events or future performance. All statements other than statements of historical fact may be forward-looking statements.  In particular, this document contains forward-looking statements pertaining to, without limitation, the following: our intention and ability through a 50:50 partnership to complete Good Spring I and II natural gas combined cycle ("NGCC") 337 MW power plants and economically create power from natural gas; the intention to tie the power into the PJM electricity market; our ability to progress the NGCC power plant to the construction stage and sell the remaining 50% stake to TYR; the potential to begin construction as early as June 2014 ; the NGCC plants will have access to affordable natural gas; the high efficiency power plant will produce low cost, reliable power; and the NGCC projects have the potential to create hundreds of jobs.  With respect to forward-looking statements contained in this document, we have made assumptions regarding, among other things, the following: the timing of construction; the economic impact on the region; estimates of employment opportunities; access to affordable natural gas; the economic viability and performance of the NGCC power plants; favourable market conditions for natural gas power plants; positive trends in capital markets for natural gas projects; stable investment conditions in North America ; and the production of two plants at 337 MW each into the PJM market.  Although we believe that the expectations reflected in the forward-looking statements contained in this document, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements.  These risks and uncertainties include, among other things, the following: the possibility that EmberClear will not have the financial or other resources to co-develop the NGCC power plants; and, the possibility that EmberClear will not be able to take advantage of the market trends such as the availability and price of natural gas and electricity pricing. Readers are cautioned that this list of risk factors should not be construed as exhaustive.  The forward-looking statements contained in this document speak only as of the date of this document. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this document are expressly qualified by this cautionary statement.

Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

SOURCE EmberClear Corp.

Stonehaven Reports Issuance of Stock Options

CALGARY, ALBERTA--(Marketwired - Feb. 27, 2015) - Stonehaven Exploration Ltd. (" Stonehaven " or the " Company ") (TSX VENTURE: SE ) reports that it has issued an aggregate of 715,200 options to purchase common shares of the Company to certain directors, officers and employees of the Company in accordance with the Company's stock option plan. The options are exercisable at a price of $1.40 per share and expire five years from the date of grant.

Stonehaven holds an interest in 20 gross sections (7.34 net sections) of petroleum and natural gas rights at Bigstone and Fir, Alberta. Further information relating to Stonehaven is also available on its website at www.stonehavenexp.com .

For further information, please contact Malcolm Todd, President and Chief Executive Officer.

NEITHER TSX VENTURE EXCHANGE NOR ITS REGULATION SERVICES PROVIDER (AS THAT TERM IS DEFINED IN THE POLICIES OF THE TSX VENTURE EXCHANGE) ACCEPTS RESPONSIBILITY FOR THE ADEQUACY OR ACCURACY OF THIS NEWS RELEASE.

Malcolm Todd
President and Chief Executive Officer
Telephone: (403) 237-5700
Email: [email protected]

Vermilion Energy Inc. Announces 2014 Year-End Summary Reserves and Resource Information

CALGARY , Feb. 27, 2015 /CNW/ - Vermilion Energy Inc. ("Vermilion", the "Company", "We" or "Our") (TSX, NYSE: VET) is pleased to announce summary 2014 year-end reserves and resource information.  The estimates of reserves and resources and other oil and gas information contained in this news release has been estimated by GLJ Petroleum Consultants Ltd. ("GLJ") and prepared in accordance with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" of the Canadian Securities Administrators ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGEH"). For additional information about Vermilion, including Vermilion's statement of reserves data and other information in Form 51-101F1, report on reserves data by independent qualified reserves evaluator or auditor in Form 51-101F2 and report of management and directors on oil and gas disclosure in Form 51-101F3, please review the Company's Annual Information Form for the year ended December 31, 2014 , to be filed on March 6, 2015 and available on SEDAR at www.sedar.com and on the SEC's EDGAR system at www.sec.gov .

HIGHLIGHTS

  • Total proved ("1P") reserves increased 17% to 151.5 mmboe (1) , while total proved plus probable ("2P") reserves increased 24% to 246.9 mmboe (1) . This represents year-over-year 1P and 2P per share reserves growth of 12% and 18%, respectively.
  • Finding and Development ("F&D") and Finding, Development and Acquisition ("FD&A") costs, including Future Development Capital ("FDC") for 2014 on a 2P basis were $17.37 /boe and $22.38 /boe, resulting in Recycle Ratios of 3.2 and 2.5, respectively.  Similarly, our three-year F&D and FD&A, including FDC, on a 2P basis were $19.26 /boe and $20.83 /boe, respectively.
  • In 2014, we added 66.5 mmboe of 2P reserves with 37.7 mmboe (57%) of additions coming from exploration and development ("E&D") activities and 28.8 mmboe (43%) of additions through acquisitions.  This represents production replacement at the 2P level of 208% through E&D related activities and 367% including acquisitions.  At a 1P level, we replaced 125% and 225% of 2014 production, respectively.
  • Our independent GLJ 2014 Resource Assessment (1) indicates low, best, and high estimates for contingent resources of 103.1 (1) mmboe, 293.4 (1) mmboe, and 408.0 (1) mmboe, an increase of 39%, 26% and 16%, respectively, compared to our GLJ 2013 Resource Assessment (2) .  Prospective resources were assessed at low, best and high estimates of 308.3 (1) mmboe, 601.6 (1) mmboe, and 900.3 (1) mmboe, an increase of 419%, 21%, and 10%, respectively versus our GLJ 2013 Resource Assessment.  Importantly, the GLJ 2014 Resource Assessment reflects a significant increase in even the most conservative "Low Estimate" for both contingent and prospective resources in Canada , as well as incremental increases across our European asset base.
  • At year-end 2014, 2P reserves were comprised of 30% Brent-based light crude, 18% Canadian-based light crude, 10% natural gas liquids, 20% European natural gas and 22% Canadian natural gas.
  • Reserve life index for 2P reserves increased to 13.6 years for year-end 2014 reserves based on annualized Q4 2014 production, compared to 13.3 years at year-end 2013. Year-end 2014 reserve life index for 1P reserves was 8.4 years, as compared to 8.6 years at year-end 2013.
  • Following on our successful 2013 program, our 2014 drilling activity resulted in an additional 22 (16.8 net) undeveloped wells booked at the 2P level in the Mannville liquids-rich gas play in Alberta , with average reserves of approximately 790 mboe/well.
  • The successful drilling of Deblinghausen Z7 well in Germany added 1.3 mmboe of 2P reserves for Vermilion's 25% working interest.
  • Our Diever-2 discovery in the Netherlands added 1.3 mmboe of 2P reserves for Vermilion's 33.1% working interest (projected average interest over well life).
(1) Vermilion retained GLJ to conduct an independent resource evaluation to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2014 (the "GLJ 2014 Resource Assessment")
(2) Vermilion retained GLJ to conduct an independent resource evaluation to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2013 (the "GLJ 2013 Resource Assessment")

DISCLAIMER

Certain statements included or incorporated by reference in this news release 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 news release may include, but are not limited to:

  • capital expenditures;
  • business strategies and objectives;
  • estimated reserve quantities and the discounted present value of future net cash flows from such reserves;
  • petroleum and natural gas sales;
  • future production levels (including the timing thereof) and rates of average annual production growth, estimated contingent resources and prospective resources;
  • exploration and development plans;
  • acquisition and disposition plans and the timing thereof;
  • operating and other expenses, including the payment of future dividends;
  • royalty and income tax rates;
  • the timing of regulatory proceedings and approvals;
  • the timing of first commercial gas from the Corrib field; 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 the Company to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally;
  • the ability of the Company 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 the Company 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 development activities.

Although the Company 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 the Company can give no assurance that such expectations will prove to be correct.  Financial outlooks are provided for the purpose of understanding the Company's financial strength and business objectives and the information may not be appropriate for other purposes.  Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company 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 the Company'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, costs and expenses;
  • potential delays or changes in plans with respect to exploration or development projects or capital expenditures;
  • the Company'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 the Company to add production and reserves through exploration and development activities;
  • general economic and business conditions;
  • 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 the Company; and
  • other risks and uncertainties described elsewhere in the annual information form of the Company for the year ended December 31, 2014 or in the Company's other filings with Canadian securities authorities.

The forward-looking statements or information contained in this news release are made as of the date hereof and the Company 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.

RESERVES, FUTURE NET REVENUE AND OTHER OIL AND GAS INFORMATION

The following is a summary of the oil and natural gas reserves and the value of future net revenue of Vermilion as evaluated by GLJ, independent petroleum engineering consultants in Calgary in a report dated February 6, 2015 with an effective date of December 31, 2014 (the "GLJ 2014 Reserves Evaluation").  The GLJ 2014 Reserves Evaluation was prepared in accordance with National Instrument 51-101 and COGEH.

Reserves and other oil and gas information in this news release is effective December 31, 2014 unless otherwise stated.

All evaluations of future net production revenue set forth in the tables below are stated after overriding and lessor royalties, Crown royalties, freehold royalties, mineral taxes, direct lifting costs, normal allocated overhead and future capital investments, including abandonment and reclamation obligations. Future net production revenues estimated by the GLJ 2014 Reserves Evaluation do not represent the fair market value of the reserves.  Other assumptions relating to the costs, prices for future production and other matters are included in the GLJ 2014 Reserve Evaluation.  There is no assurance that the future price and cost assumptions used in the GLJ 2014 Reserves Evaluation will prove accurate and variances could be material.

Reserves for Australia , Canada , France , Germany , Ireland , the Netherlands and the United States are established using deterministic methodology.  Total proved reserves are established at the 90 percent probability (P90) level.  There is a 90 percent probability that the actual reserves recovered will be equal to or greater than the P90 reserves.  Total proved plus probable reserves are established at the 50 percent probability (P50) level.  There is a 50 percent probability that the actual reserves recovered will be equal to or greater than the P50 reserves.

Estimates of reserves have been made assuming that development of each property, in respect of which estimates have been made, will occur without regard to the availability of funding required for that development.

With respect to finding and development costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.

Pricing used in the forecast price estimates is set forth in the table below and referenced in the notes to subsequent tables.

Table 1: Forecast Prices used in Estimates (1)

Natural Gas Natural Gas Natural Gas Inflation Exchange Exchange
Light and Medium Crude Oil Crude Oil Canada Europe Liquids Rate Rate Rate
WTI Edmonton Cromer Brent Blend National Balancing
Cushing Par Price Medium FOB AECO Point FOB
Oklahoma 40˚ API 29.3˚ API North Sea Gas Price (UK) Field Gate Percent
Year ($US/bbl) ($Cdn/bbl) ($Cdn/bbl) ($US/bbl) ($Cdn/MMBtu) ($US/MMBtu) ($Cdn/bbl) Per Year ($US/$Cdn) (EUR/$Cdn)
2014 93.06 94.77 89.86 99.89 4.52 8.26 72.59 2.0 0.905 1.467
Forecast
2015 62.50 64.71 61.47 67.50 3.31 7.50 38.13 2.0 0.850 1.450
2016 75.00 80.00 76.00 82.50 3.77 8.25 47.68 2.0 0.875 1.450
2017 80.00 85.71 81.43 87.50 4.02 8.75 52.15 2.0 0.875 1.450
2018 85.00 91.43 86.86 90.00 4.27 9.00 55.62 2.0 0.875 1.450
2019 90.00 97.14 92.29 95.00 4.53 9.50 59.10 2.0 0.875 1.450
Thereafter 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 0.875 1.450
Note:
(1) The pricing assumptions used in the GLJ Report  with respect to net values of future net revenue (forecast) as well as the inflation rates used for operating
and capital costs are set forth above. The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable
evaluation. GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101.

All forecast prices in the table above are provided by GLJ.  For 2014, the price of Vermilion's natural gas in the Netherlands was 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 purchases all natural gas produced by Vermilion in the Netherlands .  The price of Vermilion's natural gas in Germany is based on the TTF month-ahead index, as determined on the Title Transfer Facility Virtual Trading Point operated by Dutch TSO Gas Transport Services, plus various fees.  The benchmark price for Australia and France crude oil was Dated Brent. The benchmark price for Canadian crude oil was Edmonton Par and Canadian natural gas was priced against AECO.  For the year ended December 31, 2014 , the average realized sales prices before hedging were $113.80 per bbl ( Australia ), $8.70 per Mcf ( Netherlands ), $7.67 per Mcf ( Germany ), $105.43 per bbl ( France ) for Brent-based crude oil, $74.08 per bbl ( United States ) for WTI, $88.98 per bbl for Canadian-based crude oil and NGLs and $4.53 per Mcf for Canadian natural gas.

The following table summarizes the capital expenditures made by Vermilion on oil and natural gas properties for the year ended December 31, 2014 :

Table 2: Capital Costs Incurred

Acquisition Costs
Proved Unproved Exploration Development Total
(M$) Properties Properties Costs Costs Costs
Australia - - - 44,283 44,283
Canada 249,485 168,334 45,157 291,046 754,022
France - - 11,833 136,019 147,852
Germany 156,806 16,065 - 2,747 175,618
Ireland - - - 94,439 94,439
Netherlands - - 12,045 49,695 61,740
United States 11,175 - - 460 11,635
Total 417,466 184,399 69,035 618,689 1,289,589

The following table sets forth the reserve life index based on total proved and proved plus probable reserve and fourth quarter 2014 production of 49,571 boe/d.

Table 3: Reserve Life Index

Commodity Production Reserve Life Index (years)
Fourth Quarter 2014 Total Proved Proved Plus Probable
Oil and natural gas liquids (bbl/d) 31,668 7.8 12.4
Natural gas (mmcf/d) 107.42 9.5 15.9
Oil Equivalent (boe/d) 49,571 8.4 13.6

The following tables provide reserves data and a breakdown of future net revenue by component and production group using forecast prices and costs.  For Canada , the tables following include Alberta gas cost allowance.

The following tables may not total due to rounding.

Table 4: Oil and Gas Reserves - Based on Forecast Prices and Costs (1)

Light and Medium Crude Oil Heavy Oil Natural Gas Natural Gas Liquids BOE BOE
Gross (2) Net (2) Gross (2) Net (2) Gross (2) Net (2) Gross (2) Net (2) Gross Net
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (MMcf) (MMcf) (Mbbl) (Mbbl) (Mboe) (Mboe)
Proved Developed Producing (3) (5) (6)
Australia 10,434 10,434 - - - - - - 10,434 10,434
Canada 16,174 13,206 10 9 94,264 85,967 5,150 3,804 37,046 31,347
France 31,650 29,431 - - 9,875 9,430 - - 33,297 31,003
Germany - - - - 29,432 25,245 - - 4,905 4,208
Ireland - - - - - - - - - -
Netherlands - - - - 14,123 13,450 28 25 2,382 2,267
United States 165 137 - - 61 51 2 2 177 148
Total Proved Developed Producing 58,423 53,208 10 9 147,755 134,143 5,180 3,831 88,241 79,407
Proved Developed Non-Producing (3) (5) (7)
Australia - - - - - - - - - -
Canada 1,227 1,099 - - 12,561 11,248 476 322 3,797 3,296
France 977 874 - - - - - - 977 874
Germany - - - - 10,324 8,806 - - 1,721 1,468
Ireland - - - - - - - - - -
Netherlands - - - - 17,863 17,863 16 16 2,993 2,993
United States - - - - - - - - - -
Total Proved Developed Non-Producing 2,204 1,973 - - 40,748 37,917 492 338 9,488 8,631
Proved Undeveloped (3) (8)
Australia 2,100 2,100 - - - - - - 2,100 2,100
Canada 10,077 8,789 - - 70,589 64,886 7,924 6,542 29,766 26,145
France 2,975 2,780 - - - - - - 2,975 2,780
Germany - - - - 502 (39) - - 84 (7)
Ireland - - - - 105,931 105,931 - - 17,655 17,655
Netherlands - - - - 5,169 2,584 10 5 872 436
United States 284 234 - - 182 150 8 6 322 265
Total Proved Undeveloped 15,436 13,903 - - 182,373 173,512 7,942 6,553 53,774 49,374
Proved (3)
Australia 12,534 12,534 - - - - - - 12,534 12,534
Canada 27,478 23,094 10 9 177,414 162,101 13,550 10,668 70,609 60,788
France 35,602 33,085 - - 9,875 9,430 - - 37,249 34,657
Germany - - - - 40,258 34,012 - - 6,710 5,669
Ireland - - - - 105,931 105,931 - - 17,655 17,655
Netherlands - - - - 37,155 33,897 54 46 6,246 5,696
United States 449 371 - - 243 201 10 8 500 413
Total Proved 76,063 69,084 10 9 370,876 345,572 13,614 10,722 151,502 137,412
Probable (4)
Australia 5,449 5,449 - - - - - - 5,449 5,449
Canada 14,797 12,175 2 2 141,032 126,232 11,331 8,689 49,635 41,905
France 20,288 18,848 - - 2,582 2,465 - - 20,719 19,259
Germany - - - - 21,301 17,816 - - 3,550 2,969
Ireland - - - - 38,707 38,707 - - 6,451 6,451
Netherlands - - - - 47,076 41,987 103 85 7,949 7,083
United States 1,338 1,104 - - 1,402 1,159 58 48 1,630 1,345
Total Probable 41,872 37,576 2 2 252,100 228,366 11,492 8,822 95,383 84,461
Proved Plus Probable (3) (4)
Australia 17,983 17,983 - - - - - - 17,983 17,983
Canada 42,275 35,269 12 11 318,446 288,333 24,881 19,357 120,244 102,693
France 55,890 51,933 - - 12,457 11,895 - - 57,967 53,916
Germany - - - - 61,559 51,828 - - 10,260 8,638
Ireland - - - - 144,638 144,638 - - 24,106 24,106
Netherlands - - - - 84,231 75,884 157 131 14,195 12,779
United States 1,787 1,475 - - 1,645 1,360 68 56 2,129 1,758
Total Proved Plus Probable 117,935 106,660 12 11 622,976 573,938 25,106 19,544 246,884 221,873
Notes:
(1) The pricing assumptions used in the GLJ Report with respect to net values of future net revenue (forecast) as well as the inflation rates used for operating and capital
costs are set forth above.  See "Forecast Prices used in Estimates".  The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved
plus Probable evaluation.  GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101.
(2) "Gross Reserves" are Vermilion's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Vermilion.
"Net Reserves" are Vermilion's working interest (operating or non-operating) share after deduction of royalty obligations, plus Vermilion's royalty interests in reserves.
(3) "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable.  It is likely that the actual remaining quantities recovered
will exceed the estimated proved reserves.
(4) "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves.  It is equally likely that the actual remaining quantities
recovered will be greater or less than the sum of the estimated proved plus probable reserves.
(5) "Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would
involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.
(6) "Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may
be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
(7) "Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date
of resumption of production is unknown.
(8) "Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost
of drilling a well) is required to render them capable of production.  They must fully meet the requirements of the reserves classification (proved, probable, possible) to which
they are assigned.

Table 5: Net Present Values of Future Net Revenue - Based on Forecast Prices and Costs (1)

Before Deducting Future Income Taxes Discounted At After Deducting Future Income Taxes Discounted At
(M$) 0% 5% 10% 15% 20% 0% 5% 10% 15% 20%
Proved Developed Producing (2) (4) (5)
Australia 291,164 263,104 239,218 218,979 201,803 280,825 242,543 213,082 189,932 171,394
Canada 1,262,154 972,328 790,894 668,312 580,565 1,262,155 972,328 790,895 668,312 580,565
France 2,054,566 1,447,105 1,120,222 918,238 781,399 1,655,535 1,184,551 921,918 755,890 641,911
Germany 104,703 88,743 76,967 68,031 61,063 104,703 88,743 76,967 68,031 61,063
Ireland - - - - - - - - - -
Netherlands 44,934 46,660 46,565 45,756 44,670 44,726 46,457 46,366 45,563 44,480
United States 8,235 6,662 5,619 4,885 4,343 8,235 6,662 5,619 4,885 4,343
Total Proved Developed Producing 3,765,756 2,824,602 2,279,485 1,924,201 1,673,843 3,356,179 2,541,284 2,054,847 1,732,613 1,503,756
Proved Developed Non-Producing (2) (4) (6)
Australia - - - - - - - - - -
Canada 101,096 72,953 56,758 46,332 39,099 54,946 50,000 44,899 39,996 35,611
France 57,393 38,340 27,990 21,760 17,681 37,650 24,928 18,020 13,868 11,154
Germany 46,636 32,713 23,976 18,295 14,442 46,636 32,713 23,976 18,295 14,442
Ireland - - - - - - - - - -
Netherlands 61,915 45,630 34,900 27,543 22,322 60,340 44,093 33,399 26,075 20,884
United States - - - - - - - - - -
Total Proved Developed Non-Producing 267,040 189,636 143,624 113,930 93,544 199,572 151,734 120,294 98,234 82,091
Proved Undeveloped (2) (7)
Australia 71,575 47,975 31,079 18,724 9,524 25,361 12,037 2,650 (4,084) (8,989)
Canada 681,560 465,275 327,825 235,860 171,712 508,412 345,509 242,605 173,718 125,419
France 197,047 145,815 109,125 83,358 64,840 128,782 92,384 66,709 48,918 36,283
Germany 831 1,201 991 566 125 831 1,201 991 566 125
Ireland 774,335 642,348 534,368 451,049 387,017 774,335 642,348 534,368 451,049 387,017
Netherlands 14,875 12,536 10,658 9,129 7,868 14,704 12,369 10,495 8,969 7,712
United States 8,855 4,795 2,502 1,084 141 7,367 3,917 1,939 696 (139)
Total Proved Undeveloped 1,749,078 1,319,945 1,016,548 799,770 641,227 1,459,792 1,109,765 859,757 679,832 547,428
Proved (2)
Australia 362,739 311,079 270,297 237,703 211,327 306,187 254,580 215,732 185,848 162,405
Canada 2,044,810 1,510,556 1,175,477 950,504 791,376 1,825,513 1,367,837 1,078,399 882,026 741,595
France 2,309,006 1,631,260 1,257,337 1,023,356 863,920 1,821,967 1,301,863 1,006,647 818,676 689,348
Germany 152,170 122,657 101,934 86,892 75,630 152,170 122,657 101,934 86,892 75,630
Ireland 774,335 642,348 534,368 451,049 387,017 774,335 642,348 534,368 451,049 387,017
Netherlands 121,724 104,826 92,123 82,428 74,860 119,770 102,919 90,260 80,607 73,076
United States 17,090 11,457 8,121 5,969 4,484 15,602 10,579 7,558 5,581 4,204
Total Proved 5,781,874 4,334,183 3,439,657 2,837,901 2,408,614 5,015,544 3,802,783 3,034,898 2,510,679 2,133,275
Probable (3)
Australia 344,309 273,659 222,624 185,158 157,114 196,770 151,343 119,726 97,200 80,756
Canada 1,473,018 920,352 628,307 455,987 345,800 1,102,943 680,073 458,267 328,291 245,822
France 1,561,454 867,399 562,195 397,231 296,268 1,022,105 555,401 349,205 238,204 170,866
Germany 95,306 62,229 43,077 31,263 23,563 85,929 56,977 39,975 29,351 22,344
Ireland 430,350 269,590 183,438 133,486 102,376 430,350 269,590 183,438 133,486 102,376
Netherlands 302,536 222,307 172,861 140,087 117,110 259,231 184,444 138,913 109,209 88,748
United States 68,675 36,091 21,316 13,434 8,723 46,431 23,501 12,945 7,264 3,865
Total Probable 4,275,648 2,651,627 1,833,818 1,356,646 1,050,954 3,143,759 1,921,329 1,302,469 943,005 714,777
Proved Plus Probable (2) (3)
Australia 707,048 584,738 492,921 422,861 368,441 502,957 405,923 335,458 283,048 243,161
Canada 3,517,828 2,430,908 1,803,784 1,406,491 1,137,176 2,928,456 2,047,910 1,536,666 1,210,317 987,417
France 3,870,460 2,498,659 1,819,532 1,420,587 1,160,188 2,844,072 1,857,264 1,355,852 1,056,880 860,214
Germany 247,476 184,886 145,011 118,155 99,193 238,099 179,634 141,909 116,243 97,974
Ireland 1,204,685 911,938 717,806 584,535 489,393 1,204,685 911,938 717,806 584,535 489,393
Netherlands 424,260 327,133 264,984 222,515 191,970 379,001 287,363 229,173 189,816 161,824
United States 85,765 47,548 29,437 19,403 13,207 62,033 34,080 20,503 12,845 8,069
Total Proved Plus Probable 10,057,522 6,985,810 5,273,475 4,194,547 3,459,568 8,159,303 5,724,112 4,337,367 3,453,684 2,848,052
Notes:
(1) The pricing assumptions used in the GLJ Report with respect to net values of future net revenue (forecast) as well as the inflation rates used for operating and capital
costs are set forth above.  See "Forecast Prices used in Estimates".  The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved
plus Probable evaluation.  GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101.
(2) "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable.  It is likely that the actual remaining quantities recovered
will exceed the estimated proved reserves.
(3) "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves.  It is equally likely that the actual remaining quantities
recovered will be greater or less than the sum of the estimated proved plus probable reserves.
(4) "Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would
involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.
(5) "Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may
be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
(6) "Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date
of resumption of production is unknown.
(7) "Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost
of drilling a well) is required to render them capable of production.  They must fully meet the requirements of the reserves classification (proved, probable, possible) to which
they are assigned.

Table 6: Total Future Net Revenue (Undiscounted) Based on Forecast Prices and Costs (1)

Abandonment Future Net Future Net
Capital and Revenue Revenue
Operating Development Reclamation Before Future After
(M$) Revenue Royalties Costs Costs Costs Income Taxes Income Taxes Income Taxes
Proved (2)
Australia 1,360,391 - 712,428 245,532 39,691 362,740 56,553 306,187
Canada 4,302,228 648,056 1,026,393 534,106 48,863 2,044,810 219,297 1,825,513
France 3,982,049 279,641 1,083,549 124,021 185,833 2,309,005 487,038 1,821,967
Germany 374,000 57,252 147,030 8,056 9,492 152,170 - 152,170
Ireland 1,149,786 - 218,436 89,042 67,973 774,335 - 774,335
Netherlands 378,250 32,084 135,382 44,893 44,167 121,724 1,954 119,770
United States 43,127 11,043 6,605 8,190 199 17,090 1,488 15,602
Total Proved 11,589,831 1,028,076 3,329,823 1,053,840 396,218 5,781,874 766,330 5,015,544
Proved Plus Probable (2) (3)
Australia 2,035,436 - 1,039,962 245,532 42,893 707,049 204,092 502,957
Canada 7,407,493 1,181,971 1,715,243 931,517 60,935 3,517,827 589,371 2,928,456
France 6,504,904 456,374 1,596,847 342,728 238,496 3,870,459 1,026,387 2,844,072
Germany 598,427 93,266 234,697 12,180 10,808 247,476 9,377 238,099
Ireland 1,656,494 - 294,794 89,042 67,973 1,204,685 - 1,204,685
Netherlands 918,290 90,017 262,155 87,177 54,681 424,260 45,259 379,001
United States 198,397 50,816 26,673 34,589 554 85,765 23,732 62,033
Total Proved Plus Probable 19,319,441 1,872,444 5,170,371 1,742,765 476,340 10,057,521 1,898,218 8,159,303
Notes:
(1) The pricing assumptions used in the GLJ Report with respect to net values of future net revenue (forecast) as well as the inflation rates used for operating
and capital costs are set forth above.  See "Forecast Prices used in Estimates".  The NGL price is an aggregate of the individual natural gas liquids prices
used in the Total Proved plus Probable evaluation.  GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101.
(2) "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable.  It is likely that the actual remaining quantities
recovered will exceed the estimated proved reserves.
(3) "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves.  It is equally likely that the actual remaining
quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Table 7: Future Net Revenue by Production Group Based on Forecast Prices and Costs (1)

Future Net Revenue
Before Income Taxes (2)
(Discounted at 10% Per Year) Unit Value
Proved Developed Producing (M$) ($/boe)
Light and medium crude oil (3) 1,993,508 33.44
Heavy Oil (3) 197 14.45
Natural gas (4) 278,281 15.12
Shale Gas 6,234 17.02
Coal Bed Methane 1,265 1.26
Total Proved Developed Producing 2,279,485 28.71
Proved Developed Non-Producing
Light and medium crude oil (3) 55,301 26.31
Heavy Oil (3) - -
Natural gas (4) 84,921 14.46
Shale Gas - -
Coal Bed Methane 3,402 5.19
Total Proved Developed Non-Producing 143,624 16.64
Proved Undeveloped
Light and medium crude oil (3) 338,689 18.97
Heavy Oil (3) - -
Natural gas (4) 671,645 22.60
Shale Gas - -
Coal Bed Methane 6,214 3.44
Total Proved Undeveloped 1,016,548 20.59
Proved
Light and medium crude oil (3) 2,387,498 29.76
Heavy Oil (3) 197 14.22
Natural gas (4) 1,034,847 19.52
Shale Gas 6,234 16.75
Coal Bed Methane 10,881 3.22
Total Proved 3,439,657 25.03
Probable
Light and medium crude oil (3) 1,192,527 27.46
Heavy Oil (3) 107 24.80
Natural gas (4) 632,758 16.07
Shale Gas 1,912 18.54
Coal Bed Methane 6,514 4.15
Total Probable 1,833,818 21.71
Proved Plus Probable
Light and medium crude oil (3) 3,580,025 28.97
Heavy Oil (3) 304 16.75
Natural gas (4) 1,667,605 18.04
Shale Gas 8,146 17.24
Coal Bed Methane 17,395 3.50
Total Proved Plus Probable 5,273,475 23.77
Notes:
(1) The pricing assumptions used in the GLJ 2014 Reserves Evaluation with respect to net values
of future net revenue (forecast) as well as the inflation rates used for operating and capital costs
are set forth above.  See "Forecast Prices used in Estimates".  The NGL price is an aggregate
of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation.
GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101.
(2) Other Company revenue and costs not related to a specific production group have been allocated
proportionately to production groups.  Unit values are based on Company Net Reserves.  Net
present values of reserves categories are an approximation based on major products.
(3) Including solution gas and other by-products.
(4) Including by-products but excluding solution gas.

Reconciliations of Changes in Reserves

The following tables set forth a reconciliation of the changes in Vermilion's gross light and medium crude oil, heavy oil and associated and non-associated gas (combined) reserves as at December 31, 2014 compared to such reserves as at December 31, 2013 .

Table 8: Reconciliation of Company Gross Reserves by Principal Product Type - Based on Forecast Prices and Costs (3)

AUSTRALIA Total Crude Oil Light and Medium Crude Oil Heavy Oil Natural Gas Liquids
Proved + Proved + Proved + Proved +
Proved Probable P+P (1) (2) Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
At December 31, 2013 14,024 5,439 19,463 14,024 5,439 19,463 - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 900 (900) - 900 (900) - - - - - - -
Technical Revisions 8 910 918 8 910 918 - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production (2,398) - (2,398) (2,398) - (2,398) - - - - - -
At December 31, 2014 12,534 5,449 17,983 12,534 5,449 17,983 - - - - - -
Total Natural Gas Conventional Natural Gas Unconventional Natural Gas BOE
Proved + Proved + Proved + Proved +
Proved Probable P+P (1) (2) Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable
Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (Mboe) (Mboe) (Mboe)
At December 31, 2013 - - - - - - - - - 14,024 5,439 19,463
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery - - - - - - - - - 900 (900) -
Technical Revisions - - - - - - - - - 8 910 918
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production - - - - - - - - - (2,398) - (2,398)
At December 31, 2014 - - - - - - - - - 12,534 5,449 17,983
CANADA Total Crude Oil Light and Medium Crude Oil Heavy Oil Natural Gas Liquids
Proved + Proved + Proved + Proved +
Proved Probable P+P (1) (2) Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
At December 31, 2013 20,863 10,453 31,316 20,850 10,450 31,300 13 3 16 8,167 5,685 13,852
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 2,105 2,013 4,118 2,105 2,013 4,118 - - - 2,654 2,889 5,543
Technical Revisions 1,544 (1,950) (406) 1,543 (1,949) (406) 1 (1) - 2,368 1,970 4,338
Acquisitions 7,081 4,283 11,364 7,081 4,283 11,364 - - - 1,265 787 2,052
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production (4,105) - (4,105) (4,101) - (4,101) (4) - (4) (904) - (904)
At December 31, 2014 27,488 14,799 42,287 27,478 14,797 42,275 10 2 12 13,550 11,331 24,881
Total Natural Gas Conventional Natural Gas Unconventional Natural Gas BOE
Proved + Proved + Proved + Proved +
Proved Probable P+P (1) (2) Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable
Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (Mboe) (Mboe) (Mboe)
At December 31, 2013 154,961 90,663 245,624 131,058 80,536 211,594 23,903 10,127 34,030 54,857 31,249 86,105
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 28,466 47,945 76,411 26,811 47,525 74,336 1,656 420 2,076 9,503 12,893 22,396
Technical Revisions 2,716 (4,631) (1,915) 1,296 (4,536) (3,240) 1,420 (95) 1,325 4,365 (752) 3,613
Acquisitions 11,589 7,055 18,644 11,589 7,055 18,644 - - - 10,278 6,246 16,524
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production (20,318) - (20,318) (17,191) - (17,191) (3,127) - (3,127) (8,395) - (8,395)
At December 31, 2014 177,414 141,032 318,446 153,563 130,580 284,143 23,852 10,452 34,304 70,608 49,635 120,243

FRANCE Total Crude Oil Light and Medium Crude Oil Heavy Oil Natural Gas Liquids
Proved + Proved + Proved + Proved +
Proved Probable P+P (1) (2) Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
At December 31, 2013 34,391 18,394 52,785 34,391 18,394 52,785 - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 1,049 2,195 3,244 1,049 2,195 3,244 - - - - - -
Technical Revisions 4,181 (301) 3,880 4,181 (301) 3,880 - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production (4,019) - (4,019) (4,019) - (4,019) - - - - - -
At December 31, 2014 35,602 20,288 55,890 35,602 20,288 55,890 - - - - - -
Total Natural Gas Conventional Natural Gas Unconventional Natural Gas BOE
Proved + Proved + Proved + Proved +
Proved Probable P+P (1) (2) Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable
Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (Mboe) (Mboe) (Mboe)
At December 31, 2013 11,031 3,269 14,300 11,031 3,269 14,300 - - - 36,230 18,939 55,168
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery - - - - - - - - - 1,049 2,195 3,244
Technical Revisions (1,156) (687) (1,843) (1,156) (687) (1,843) - - - 3,989 (415) 3,574
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production - - - - - - - - - (4,019) - (4,019)
At December 31, 2014 9,875 2,582 12,457 9,875 2,582 12,457 - - - 37,249 20,719 57,967
GERMANY Total Crude Oil Light and Medium Crude Oil Heavy Oil Natural Gas Liquids
Proved + Proved + Proved + Proved +
Proved Probable P+P (1) (2) Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
At December 31, 2013 - - - - - - - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery - - - - - - - - - - - -
Technical Revisions - - - - - - - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production - - - - - - - - - - - -
At December 31, 2014 - - - - - - - - - - - -
Total Natural Gas Conventional Natural Gas Unconventional Natural Gas BOE
Proved + Proved + Proved + Proved +
Proved Probable P+P (1) (2) Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable
Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (Mboe) (Mboe) (Mboe)
At December 31, 2013 - - - - - - - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 2,784 3,856 6,640 2,784 3,856 6,640 - - - 464 643 1,107
Technical Revisions 21 6 27 21 6 27 - - - 4 1 5
Acquisitions 42,923 17,439 60,362 42,923 17,439 60,362 - - - 7,154 2,906 10,060
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production (5,470) - (5,470) (5,470) - (5,470) - - - (912) - (912)
At December 31, 2014 40,258 21,301 61,559 40,258 21,301 61,559 - - - 6,710 3,550 10,260

IRELAND Total Crude Oil Light and Medium Crude Oil Heavy Oil Natural Gas Liquids
Proved + Proved + Proved + Proved +
Proved Probable P+P (1) (2) Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
At December 31, 2013 - - - - - - - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery - - - - - - - - - - - -
Technical Revisions - - - - - - - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production - - - - - - - - - - - -
At December 31, 2014 - - - - - - - - - - - -
Total Natural Gas Conventional Natural Gas Unconventional Natural Gas BOE
Proved + Proved + Proved + Proved +
Proved Probable P+P (1) (2) Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable
Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (Mboe) (Mboe) (Mboe)
At December 31, 2013 105,931 38,707 144,638 105,931 38,707 144,638 - - - 17,655 6,451 24,106
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery - - - - - - - - - - - -
Technical Revisions - - - - - - - - - - - -
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production - - - - - - - - - - - -
At December 31, 2014 105,931 38,707 144,638 105,931 38,707 144,638 - - - 17,655 6,451 24,106
NETHERLANDS Total Crude Oil Light and Medium Crude Oil Heavy Oil Natural Gas Liquids
Proved + Proved + Proved + Proved +
Proved Probable P+P (1) (2) Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
At December 31, 2013 - - - - - - - - - 61 99 160
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery - - - - - - - - - 14 9 23
Technical Revisions - - - - - - - - - 7 (5) 2
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production - - - - - - - - - (28) - (28)
At December 31, 2014 - - - - - - - - - 54 103 157
Total Natural Gas Conventional Natural Gas Unconventional Natural Gas BOE
Proved + Proved + Proved + Proved +
Proved Probable P+P (1) (2) Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable
Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (Mboe) (Mboe) (Mboe)
At December 31, 2013 36,750 44,592 81,342 36,750 44,592 81,342 - - - 6,186 7,531 13,717
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 6,741 4,950 11,691 6,741 4,950 11,691 - - - 1,138 834 1,972
Technical Revisions 7,606 (2,466) 5,140 7,606 (2,466) 5,140 - - - 1,275 (416) 859
Acquisitions - - - - - - - - - - - -
Dispositions - - - - - - - - - - - -
Economic Factors - - - - - - - - - - - -
Production (13,942) - (13,942) (13,942) - (13,942) - - - (2,352) - (2,352)
At December 31, 2014 37,155 47,076 84,231 37,155 47,076 84,231 - - - 6,247 7,949 14,196

UNITED STATES Total Crude Oil Light and Medium Crude Oil Heavy Oil Natural Gas Liquids
Proved + Proved + Proved + Proved +
Proved Probable P+P (1) (2) Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
At December 31, 2013 - - - - - - - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery - - - - - - - - - - - -
Technical Revisions - - - - - - - - - - - -
Acquisitions 477 1,340 1,817 477 1,340 1,817 - - - 12 66 78
Dispositions - - - - - - - - - - - -
Economic Factors (10) (2) (12) (10) (2) (12) - - - (2) (8) (10)
Production (18) - (18) (18) - (18) - - - - - -
At December 31, 2014 449 1,338 1,787 449 1,338 1,787 - - - 10 58 68
Total Natural Gas Conventional Natural Gas Unconventional Natural Gas BOE
Proved + Proved + Proved + Proved +
Proved Probable P+P (1) (2) Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable
Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (Mboe) (Mboe) (Mboe)
At December 31, 2013 - - - - - - - - - - - -
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery - - - - - - - - - - - -
Technical Revisions - - - - - - - - - - - -
Acquisitions 297 1,605 1,902 297 1,605 1,902 - - - 539 1,674 2,212
Dispositions - - - - - - - - - - - -
Economic Factors (54) (203) (257) (54) (203) (257) - - - (21) (44) (65)
Production - - - - - - - - - (18) - (18)
At December 31, 2014 243 1,402 1,645 243 1,402 1,645 - - - 500 1,630 2,129
TOTAL COMPANY Total Crude Oil Light and Medium Crude Oil Heavy Oil Natural Gas Liquids
Proved + Proved + Proved + Proved +
Proved Probable P+P (1) (2) Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable
Factors (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
At December 31, 2013 69,278 34,286 103,564 69,265 34,283 103,548 13 3 16 8,228 5,784 14,012
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 4,054 3,308 7,362 4,054 3,308 7,362 - - - 2,668 2,898 5,566
Technical Revisions 5,733 (1,341) 4,392 5,732 (1,340) 4,392 1 (1) - 2,375 1,965 4,340
Acquisitions 7,558 5,623 13,181 7,558 5,623 13,181 - - - 1,277 853 2,130
Dispositions - - - - - - - - - - - -
Economic Factors (10) (2) (12) (10) (2) (12) - - - (2) (8) (10)
Production (10,540) - (10,540) (10,536) - (10,536) (4) - (4) (932) - (932)
At December 31, 2014 76,073 41,874 117,947 76,063 41,872 117,935 10 2 12 13,614 11,492 25,106
Total Natural Gas Conventional Natural Gas Unconventional Natural Gas BOE
Proved + Proved + Proved + Proved +
Proved Probable P+P (1) (2) Proved Probable Probable Proved Probable Probable Proved Probable Probable Proved Probable Probable
Factors (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (Mboe) (Mboe) (Mboe)
At December 31, 2013 308,673 177,231 485,904 284,770 167,104 451,874 23,903 10,127 34,030 128,952 69,609 198,559
Discoveries - - - - - - - - - - - -
Extensions & Improved Recovery 37,991 56,751 94,742 36,336 56,331 92,667 1,656 420 2,076 13,054 15,665 28,719
Technical Revisions 9,187 (7,778) 1,409 7,767 (7,683) 84 1,420 (95) 1,325 9,640 (672) 8,969
Acquisitions 54,809 26,099 80,908 54,809 26,099 80,908 - - - 17,971 10,825 28,796
Dispositions - - - - - - - - - - - -
Economic Factors (54) (203) (257) (54) (203) (257) - - - (21) (44) (65)
Production (39,730) - (39,730) (36,603) - (36,603) (3,127) - (3,127) (18,094) - (18,094)
At December 31, 2014 370,876 252,100 622,976 347,025 241,648 588,673 23,852 10,452 34,304 151,502 95,383 246,884
Notes:
(1) "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable.  It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
(2) "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves.  It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
(3) The pricing assumptions used in the GLJ Report with respect to net values of future net revenue (forecast) as well as the inflation rates used for operating and capital costs are set forth above.  See "Forecast Prices used in Estimates".  The NGL price is an aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation.  GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101.

The table below sets out the future development costs deducted in the estimation of future net revenue attributable to total proved reserves and total proved plus probable reserves (using forecast prices and costs).

Table 9: Future Development Costs (1)

Total Proved Total Proved Plus Probable
(M$) Estimated Using Forecast Prices and Costs Estimated Using Forecast Prices and Costs
Australia
2015 81,700 81,700
2016 78,438 78,438
2017 21,120 21,120
2018 36,506 36,506
2019 13,747 13,747
Remainder 14,021 14,021
Total for all years undiscounted 245,532 245,532
Canada
2015 166,244 200,656
2016 192,500 269,800
2017 98,904 265,047
2018 55,131 156,202
2019 11,784 25,639
Remainder 9,543 14,173
Total for all years undiscounted 534,106 931,517
France
2015 31,772 67,540
2016 32,483 73,283
2017 10,032 83,687
2018 19,018 52,090
2019 6,395 41,807
Remainder 24,321 24,321
Total for all years undiscounted 124,021 342,728
Germany
2015 653 4,778
2016 6,887 6,887
2017 384 384
2018 65 65
2019 67 67
Remainder - (1)
Total for all years undiscounted 8,056 12,180
Ireland
2015 60,029 60,029
2016 9,450 9,450
2017 - -
2018 - -
2019 1,882 1,882
Remainder 17,681 17,681
Total for all years undiscounted 89,042 89,042
Netherlands
2015 6,920 7,795
2016 1,871 6,934
2017 416 18,628
2018 28,678 35,767
2019 433 11,479
Remainder 6,575 6,574
Total for all years undiscounted 44,893 87,177
United States
2015 8,190 10,920
2016 - 23,669
2017 - -
2018 - -
2019 - -
Remainder - -
Total for all years undiscounted 8,190 34,589
Total Company
2015 355,508 433,418
2016 321,629 468,461
2017 130,856 388,866
2018 139,398 280,630
2019 34,308 94,621
Remainder 72,141 76,769
Total for all years undiscounted 1,053,840 1,742,765
Note:
(1) The pricing assumptions used in the GLJ Report with respect to net values of future net revenue (forecast) as well as the inflation
rates used for operating and capital costs are set forth above.  See "Forecast Prices used in Estimates".  The NGL price is an
aggregate of the individual natural gas liquids prices used in the Total Proved plus Probable evaluation.  GLJ is an independent
qualified reserves evaluator appointed pursuant to NI 51-101.

Vermilion expects to source its capital expenditure requirements from internally generated cash flow and, as appropriate, from Vermilion's existing credit facility, equity or debt financing.  It is anticipated that costs of funding the future development costs will not impact development of its properties or Vermilion's reserves or future net revenue.

CONTINGENT AND PROSPECTIVE RESOURCES

Vermilion retained GLJ to conduct an independent resource evaluation to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2014 (the "GLJ 2014 Resources Assessment").

All contingent and prospective resources evaluated in the GLJ 2014 Resources Assessment were deemed economic at the effective date of December 31, 2014 .

The estimates of volumes of, and the net present value of the future net revenue attributable to, contingent resources and prospective resources in this news release are derived from the GLJ 2014 Resources Assessment.  The GLJ 2014 Resources Assessment was prepared in accordance with COGEH and NI 51-101 by GLJ, an independent qualified reserve evaluator.

A range of contingent and prospective resources estimates (low, best and high) were prepared by GLJ.  See notes 5 to 8 of following Table 11 in this section for a description of low estimate, best estimate and high estimate.

Contingent Resources

"Contingent resources" are not, and should not be confused with, petroleum and natural gas reserves. "Contingent resources" are defined in COGEH as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resource the estimated discovered recoverable quantities associated with a project in the early evaluation stage.

The primary contingencies which currently prevent the classification of Vermilion's contingent resource as reserves include but are not limited to:

  • preparation of firm development plans, including determination of the specific scope and timing of projects;
  • project sanction;
  • access to capital markets;
  • shareholder and regulatory approvals;
  • access to required services and field development infrastructure;
  • oil and natural gas prices in Canada and internationally in jurisdictions in which Vermilion operates;
  • demonstration of economic viability;
  • future drilling program and testing results;
  • further reservoir delineation and studies;
  • facility design work;
  • limitations to development based on adverse topography or other surface restrictions; and
  • the uncertainty regarding marketing and transportation of petroleum from development areas.

There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that Vermilion will produce any portion of the volumes currently classified as contingent resources. The estimates of contingent resources involve implied assessment, based on certain estimates and assumptions, that the resources described exists in the quantities predicted or estimated and that the resources can be profitably produced in the future. The net present value of the future net revenue from the contingent resources does not necessarily represent the fair market value of the contingent resources .  Actual contingent resources (and any volumes that may be reclassified as reserves) and future production therefrom may be greater than or less than the estimates provided herein.

Prospective Resources

Prospective resources are not, and should not be confused with, petroleum and natural gas reserves. "Prospective resources" are defined in COGEH as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.

There is no certainty that any portion of the prospective resources will be discovered.  If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources or that Vermilion will produce any portion of the volumes currently classified as prospective resources. The estimates of prospective resources involve implied assessment, based on certain estimates and assumptions, that the resources described exists in the quantities predicted or estimated and that the resources can be profitably produced in the future. The net present value of the future net revenue from the prospective resources does not necessarily represent the fair market value of the prospective resources. The recovery and resources estimates provided herein are estimates only.  Actual prospective resources (and any volumes that may be reclassified as reserves or contingent resources) and future production from such prospective resources may be greater than or less than the estimates provided herein.

Summary information regarding contingent and prospective resources and net present values of future net revenues from contingent and prospective resources are set forth below

Table 10: Company Gross and Net Contingent and Prospective Resources as at December 31, 2014 (1) (2) - Forecast Prices and Costs (3) (4)

Gross Gross Net
Reserves Contingent Resources Prospective Resources Contingent Resources Prospective Resources
P+P Low Best High Low Best High Low Best High Low Best High
Crude Oil and NGLs (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
Australia 17,983 1,350 3,950 6,200 - 1,207 3,046 1,350 3,950 6,200 - 1,207 3,046
Canada 67,168 38,923 109,571 151,394 99,092 215,169 335,029 30,165 83,004 113,008 77,132 165,088 253,483
France 55,890 16,714 32,640 49,379 3,478 12,512 34,866 15,797 30,639 46,388 3,325 11,553 33,074
Germany - - - - - - - - - - - - -
Ireland - - - - - - - - - - - - -
Netherlands 157 14 44 1,116 149 264 1,262 14 44 1,116 149 264 1,262
United States 1,855 - 8,482 8,482 - - - - 6,998 6,998 - - -
Total 143,053 57,001 154,687 216,571 102,719 229,152 374,203 47,326 124,635 173,710 80,606 178,112 290,865
Gross Gross Net
Reserves Contingent Resources Prospective Resources Contingent Resources Prospective Resources
P+P Low Best High Low Best High Low Best High Low Best High
Natural Gas (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf) (MMcf)
Australia - - - - - - - - - - - - -
Canada 318,446 260,803 772,308 1,055,506 1,031,549 1,869,590 2,475,894 238,734 703,634 952,492 958,760 1,730,748 2,283,476
France 12,457 475 1,330 2,613 - - - 449 1,257 2,469 - - -
Germany 61,559 - - - - - - - - - - - -
Ireland 144,638 6,359 23,842 35,734 - - - 6,359 23,842 35,734 - - -
Netherlands 84,231 8,704 27,539 47,394 202,035 365,182 680,499 8,704 27,539 47,394 202,035 365,182 680,499
United States 1,645 - 7,300 7,300 - - - - 6,022 6,022 - - -
Total 622,976 276,341 832,319 1,148,547 1,233,584 2,234,772 3,156,393 254,246 762,294 1,044,111 1,160,795 2,095,930 2,963,975
Gross Gross Net
Reserves Contingent Resources Prospective Resources Contingent Resources Prospective Resources
P+P Low Best High Low Best High Low Best High Low Best High
Total Oil Equivalent (Mboe) (Mboe) (Mboe) (Mboe) (Mboe) (Mboe) (Mboe) (Mboe) (Mboe) (Mboe) (Mboe) (Mboe) (Mboe)
Australia 17,983 1,350 3,950 6,200 - 1,207 3,046 1,350 3,950 6,200 - 1,207 3,046
Canada 120,243 82,390 238,290 327,312 271,016 526,767 747,678 69,954 200,276 271,757 236,925 453,546 634,062
France 57,967 16,793 32,862 49,814 3,478 12,512 34,866 15,871 30,849 46,800 3,325 11,553 33,074
Germany 10,260 - - - - - - - - - - - -
Ireland 24,106 1,060 3,974 5,956 - - - 1,060 3,974 5,956 - - -
Netherlands 14,196 1,464 4,634 9,015 33,822 61,128 114,679 1,464 4,634 9,015 33,822 61,128 114,679
United States 2,129 - 9,698 9,698 - - - - 8,001 8,001 - - -
Total 246,884 103,057 293,408 407,995 308,316 601,614 900,269 89,699 251,684 347,729 274,072 527,434 784,861

Table 11: Summary of Net Present Value of Future Net Revenues as at December 31, 2014 - Forecast Prices and Costs (3)

Contingent Resources Before Income Taxes, Discounted at (5) After Income Taxes, Discounted at (5)
(M$) 0% 5% 8% 10% 0% 5% 8% 10%
Low Estimate (C1) (6)
Australia 53,588 36,337 28,793 24,638 9,903 3,796 1,318 26
Canada 2,095,806 1,211,845 901,127 747,500 1,563,303 873,722 634,037 516,572
France 1,204,380 661,229 474,985 384,557 789,158 410,775 283,929 223,171
Germany - - - - - - - -
Ireland 26,010 13,311 8,376 5,846 26,010 13,311 8,376 5,846
Netherlands 30,396 16,766 11,216 8,274 15,020 4,981 1,049 (979)
United States - - - - - - - -
Total Low Estimate 3,410,180 1,939,488 1,424,497 1,170,815 2,403,394 1,306,585 928,709 744,636
Best Estimate (C2) (7)
Australia 284,255 200,400 164,163 144,286 103,353 68,354 53,704 45,831
Canada 6,459,393 3,570,683 2,589,387 2,111,760 4,818,494 2,586,094 1,831,852 1,466,556
France 2,360,314 1,292,886 932,442 758,266 1,547,524 807,329 562,967 446,486
Germany - - - - - - - -
Ireland 154,048 63,672 39,612 29,455 154,048 63,672 39,612 29,455
Netherlands 148,184 93,040 70,699 58,839 78,990 42,647 28,323 20,855
United States 374,344 181,832 122,734 95,296 243,284 115,575 76,064 57,643
Total Best Estimate 9,780,538 5,402,513 3,919,037 3,197,902 6,945,693 3,683,671 2,592,522 2,066,826
High Estimate (C3) (8)
Australia 553,551 390,331 320,676 282,676 222,157 151,267 121,670 105,741
Canada 9,925,528 5,423,537 3,955,769 3,252,645 7,404,229 3,961,260 2,843,018 2,309,361
France 3,948,744 2,142,264 1,549,595 1,265,979 2,589,524 1,357,470 959,971 771,728
Germany - - - - - - - -
Ireland 346,330 128,788 80,411 61,194 346,330 128,788 80,411 61,194
Netherlands 369,732 241,527 189,883 162,531 198,799 118,282 86,830 70,491
United States 374,344 181,832 122,734 95,296 243,284 115,575 76,064 57,643
Total High Estimate 15,518,229 8,508,279 6,219,068 5,120,321 11,004,323 5,832,642 4,167,964 3,376,158
Prospective Resources Before Income Taxes, Discounted at (5) After Income Taxes, Discounted at (5)
(M$) 0% 5% 8% 10% 0% 5% 8% 10%
Low Estimate (Pr1) (6)
Australia - - - - - - - -
Canada 5,138,207 1,799,192 942,409 596,896 3,827,943 1,216,719 565,019 308,857
France 240,765 108,770 68,603 50,665 149,458 62,138 36,495 25,322
Germany - - - - - - - -
Ireland - - - - - - - -
Netherlands 1,569,880 707,181 475,734 374,648 840,417 344,972 211,133 153,483
United States - - - - - - - -
Total Low Estimate 6,948,852 2,615,143 1,486,746 1,022,209 4,817,818 1,623,829 812,647 487,662
Best Estimate (Pr2) (7)
Australia 115,650 73,506 56,869 48,203 46,695 28,681 21,730 18,160
Canada 15,779,806 6,480,938 3,975,248 2,911,534 11,769,017 4,661,647 2,770,999 1,977,330
France 822,384 388,117 254,918 194,691 533,257 234,616 146,329 107,336
Germany - - - - - - - -
Ireland - - - - - - - -
Netherlands 3,529,396 1,693,769 1,196,675 975,168 1,904,042 881,861 602,841 479,314
United States - - - - - - - -
Total Best Estimate 20,247,236 8,636,330 5,483,710 4,129,596 14,253,011 5,806,805 3,541,899 2,582,140
High Estimate (Pr3) (8)
Australia 356,273 214,338 162,747 136,788 148,981 88,333 66,497 55,578
Canada 28,841,614 11,940,966 7,525,330 5,652,671 21,515,226 8,730,765 5,414,330 4,016,964
France 2,663,885 1,204,684 784,942 600,089 1,745,296 748,687 471,094 351,229
Germany - - - - - - - -
Ireland - - - - - - - -
Netherlands 7,454,176 3,747,532 2,709,105 2,236,659 4,053,657 2,003,614 1,427,834 1,166,840
United States - - - - - - - -
Total High Estimate 39,315,948 17,107,520 11,182,124 8,626,207 27,463,160 11,571,399 7,379,755 5,590,611
Notes:
(1) The contingent and prospective resource assessments were prepared by GLJ in accordance with the definitions, standards and procedures contained in the COGEH and NI 51-101. Contingent resource is defined in the COGEH as those quantities of petroleum estimated to be potentially recoverable from known accumulations using established technology or technology under development, but which do not currently qualify as reserves or commercially recoverable due to one or more contingencies.  See "Presentation of Oil and Gas Reserves and Production Information - Contingent Resources" for the primary contingencies which prevent the classification of the resources as reserves. There is no certainty that it will be commercially viable to produce any portion of the contingent resources or that Vermilion will produce any portion of the volumes currently classified as contingent resources. The estimates of contingent resources involve implied assessment, based on certain estimates and assumptions, that the resources described exists in the quantities predicted or estimated, as at a given date, and that the resources can be profitably produced in the future. The net present value of the future net revenue from the contingent resources does not necessarily represent the fair market value of the contingent resources . Actual contingent resources (and any volumes that may be reclassified as reserves) and future production therefrom may be greater than or less than the estimates provided herein.   Prospective resource is defined in the COGEH are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.  There is no certainty that any portion of the prospective resources will be discovered.  If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources or that Vermilion will produce any portion of the volumes currently classified as prospective resources. The estimates of prospective resources involve implied assessment, based on certain estimates and assumptions, that the resources described exists in the quantities predicted or estimated and that the resources can be profitably produced in the future. The net present value of the future net revenue from the prospective resources does not necessarily represent the fair market value of the prospective resources . The recovery and resources estimates provided herein are estimates only.  Actual prospective resources (and any volumes that may be reclassified as reserves or contingent resources) and future production from such prospective resources may be greater than or less than the estimates provided herein.
(2) GLJ prepared the estimates of contingent and prospective resources shown for each property using deterministic principles and methods. Probabilistic aggregation of the low and high property estimates shown in the table might produce different total volumes than the arithmetic sums shown in the table.
(3) The forecast price and cost assumptions utilized in the year-end 2014 reserves report were also utilized by GLJ in preparing the contingent resource and prospective resource assessments. See "GLJ December 31, 2014 Forecast Prices" in Vermilion's Annual Information Form for the year ended December 31, 2014.
(4) "Gross" Reserves or Contingent Resources or Prospective Resources are Vermilion's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Vermilion.  "Net" Reserves or Contingent Resources or Prospective Resources are Vermilion's working interest (operating or non-operating) share after deduction of royalty obligations, plus Vermilion's royalty interests in Reserves or Contingent Resources or Prospective Resources.
(5) The net present value of future net revenue attributable to the contingent or prospective resources does not necessarily represent the fair market value of the contingent or prospective resources. Estimated abandonment and reclamation costs have been included in the evaluation.
(6) Low estimate is considered to be a conservative estimate of the quantity of contingent (C1) or prospective (Pr1) resources that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate.  Those contingent or prospective resources at the low end of the estimate range have the highest degree of certainty - a 90% confidence level - that the actual quantities recovered will be equal or exceed the estimate.
(7) Best estimate is considered to be the best estimate of the quantity of contingent (C2) or prospective (Pr2) resources that will actually be recovered.  It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate.  Those contingent or prospective resources that fall within the best estimate have a 50% confidence level that the actual quantities recovered will be equal or exceed the estimate.
(8) High estimate is considered to be an optimistic estimate of the quantity of contingent (C3) or prospective (Pr3) resources that will actually be recovered. It is unlikely that the actual remaining quantities of contingent or prospective resources recovered will meet or exceed the high estimate. Those contingent or prospective resources at the high end of the estimate range have a lower degree of certainty - a 10% confidence level - that the actual quantities recovered will equal or exceed the estimate.

ABOUT VERMILION

Vermilion is an oil-leveraged producer that adheres to a value creation strategy through the execution of full cycle exploration and production programs focused on the acquisition, exploration, development and optimization of producing properties in Western Canada , Europe and Australia . Our business model targets annual organic production growth of approximately 5% along with providing reliable and increasing dividends to investors.  Vermilion is targeting growth in production primarily through the exploitation of conventional resource plays in Western Canada , including Cardium light oil and liquids rich natural gas, the exploration and development of high impact natural gas opportunities in the Netherlands and through drilling and workover programs in France and Australia . Vermilion also holds an 18.5% working interest in the Corrib gas field in Ireland . In addition, Vermilion pays a monthly dividend of Canadian $0.215 per share, which provides a current yield in excess of 4%.  Management and directors of Vermilion hold approximately 8% of the outstanding shares and are dedicated to consistently delivering superior rewards for all stakeholders, featuring an 20-year history of market outperformance. Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.

Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel equivalent of oil.  Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation.  A boe conversion ratio of six thousand cubic feet of natural gas 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.

Fund flows from operations and recycle ratio are non-GAAP (as defined herein) measures that do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS" or, alternatively, "GAAP") and therefore may not be comparable with the calculations of similar measures for other entities. "Fund flows from operations" represents cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled. Management considers fund flows from operations and fund flows from operations per share to be key measures as they demonstrate Vermilion's ability to generate the cash necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, fund flows from operations provides a useful measure of Vermilion's ability to generate cash that is not subject to short-term movements in non-cash operating working capital. "Recycle Ratio" means a measure of capital efficiency calculated by dividing the operating netback of production by the cost of adding reserves. "Netbacks" are per boe and per Mcf measures used in operational and capital allocation decisions. After-tax cash flow netbacks are calculated as cash flow from operating activities (determined in accordance with GAAP) expressed on a per boe basis.

SOURCE Vermilion Energy Inc.

CALGARY , Feb. 27, 2015 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and audited financial results for the year ended December 31, 2014 .

HIGHLIGHTS

  • Strong operational execution resulted in annual production that exceeded the top end of our guidance range following three upward revisions during the year.  Average annual production for 2014 was 49,573 boe/d, an increase of 21% as compared to 41,005 boe/d in 2013.  Production for Q4 2014 averaged 49,571 boe/d, down slightly from 49,920 boe/d in the prior quarter.  Full year Canadian production volumes grew 34% year-over-year.  Canadian production growth was attributable to a 20% increase in average production from our Cardium light oil resource play, a near tripling of Mannville condensate-rich gas production and the addition of approximately 1,900 boe/d of production (based on a late April 2014 closing) from our southeast Saskatchewan assets. In Europe , full year production growth of 8% in the Netherlands and the addition of approximately 2,500 boe/d (based on a February 2014 closing) from our Germany acquisition also contributed meaningfully.
  • Increased fund flows from operations ("FFO") (1) in 2014 by 21% to $804.9 million ( $7.63 /basic share), as compared to $667.5 million ( $6.61 /basic share) in 2013. Year-over-year growth in FFO was largely attributable to the growth in production as well as a higher liquids weighting compared to 2013, partially offset by generally weaker pricing overall.  Q4 2014 FFO was $185.5 million ( $1.73 /basic share) down from $197.9 million ( $1.85 /basic share) in the prior quarter.  The quarter-over-quarter decrease was primarily attributable to substantially lower commodity pricing during Q4 2014 compared to the prior quarter, partially offset by lower corporate income taxes and higher realized hedging gains.
  • Achieved growth in both proved ("1P") and proved plus probable ("2P") reserves in 2014.  Our independent GLJ 2014 Reserves Evaluation (2) assessed an increase of 18% in 1P reserves to 151.5 (2) mmboe, while 2P reserves increased by 24% to 246.9 (2) mmboe.   This represents year-over-year 1P and 2P per share reserves growth of 12% and 18%, respectively. (For additional reserves information see today's separate news release entitled " Vermilion Energy Inc. Announces 2014 Year-End Summary Reserves and Resource Information").
  • Finding and Development ("F&D") and Finding, Development and Acquisition ("FD&A") costs, including Future Development Capital ("FDC") for 2014 on a 2P basis were $17.37 /boe and $22.38 /boe, respectively.  Similarly, our three-year F&D and FD&A, including FDC, on a 2P basis were $19.26 /boe and $20.83 /boe, respectively.
  • Our independent GLJ 2014 Resource Assessment (3) indicates low, best, and high estimates for contingent resources of 103.1 (3) mmboe, 293.4 (3) mmboe, and 408.0 (3) mmboe, an increase of 39%, 26% and 16%, respectively, compared to our GLJ 2013 Resource Assessment (4) .  Prospective resources were assessed at low, best and high estimates of 308.3 (3) mmboe, 601.6 (3) mmboe, and 900.3 (3) mmboe, an increase of 419%, 21%, and 10%, respectively versus our GLJ 2013 Resource Assessment.  Importantly, the GLJ 2014 Resource Assessment reflects a significant increase in the most conservative "Low Estimate" for both contingent resources and prospective resources in Canada , as well as incremental increases across our European asset base.  (For additional resource information please see today's separate news release entitled "Vermilion Energy Inc. Announces 2014 Year-End Summary Reserves and Resource Information").
  • During the year we realized successful entry into new asset areas in Germany , Hungary , Southeastern Saskatchewan and the United States .  Each asset addition adheres to our strategy of balanced and diversified growth, increasing our exposure to both European natural gas and light-oil development opportunities.

  • Concluded a highly successful seven (4.7 net) well drilling program in the Netherlands .  In addition, we were awarded the Ijsselmuiden exploration concession consisting of approximately 110,500 gross (66,300 net) undeveloped acres, increasing our undeveloped land base in the Netherlands to more than 800,000 net acres.  The Sonnega-2 exploration well (50% working interest), drilled in Q4 2014, encountered natural gas in the Vlieland formation and achieved a stabilized flow rate of 15.8 mmcf/d on a 52/64 inch choke with a flowing well head pressure of 1,060 psi during a seven-hour flow test (5) .  This well is expected to be brought on production during Q2 2015.
  • Completed our first two (1.35 net) Duvernay horizontal appraisal wells during 2014.  Our Pembina well (35% working interest), which is located along a shared lease-line, has a 1,280 metre long horizontal leg and was brought on production subsequent to the end of the third quarter.  The raw gas rate over the first 30 days of production averaged 1.8 mmcf/d (sales gas rate of 1.6 mmcf/d after liquids shrink and plant fuel) with a hydrocarbon liquids rate of approximately 180 bbls/d (approximately 50% pentanes plus).  Our second Duvernay horizontal appraisal well (100% working interest), located in the Edson block, was brought on production late in Q4 2014.  The raw gas rate over the first 30 days of production averaged 2.9 mmcf/d (sales gas rate of 2.5 mmcf/d after liquids shrink and plant fuel) with a hydrocarbon liquids rate of approximately 145 bbls/d (approximately 40% pentanes plus).
  • Our Corrib project in Ireland has continued to progress on schedule following the completion of tunnel boring operations in May 2014. During the remainder of 2014, project operator Shell Exploration & Production Ireland Ltd. successfully completed offshore workover and pipeline operations as well as outfitting of the 4.9 km tunnel, including installation of flow and umbilical lines, hydro-testing and dewatering, with the final weld completed in December 2014. Grouting of the tunnel was completed subsequent to year end 2014.  Natural gas from the national sales grid was safely introduced into the processing facility in Q4 2014 as part of the commencement of operations at the plant. Remaining work includes the testing of all systems and processes required for the safe operation of the Bellanaboy gas processing terminal and the 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 response to continued weakness in commodity prices, we are revising our previous 2015 capital expenditure guidance to reflect a further reduction in planned expenditures of approximately $110 million .  This will reduce our planned 2015 capital expenditures to $415 million from the original $525 million announced in December 2014 , a 40% reduction as compared to 2014.  The reduction in capital reflects both lower planned activity levels, including the deferral of our Australian drilling campaign, as well as strong results-to-date from our company-wide Profitability Enhancement Program ("PEP") which was launched in November 2014 to support Vermilion's long-term profitability.  This is the third installment of our PEP program in our 20-year history with the prior two initiatives having achieved strong results in both the 1998 industry downturn and during the financial crisis of 2008-2009.  Our PEP program ensures that our people remain acutely focused on enhancing revenues, and reducing capital costs, operating expenses and general and administrative outlays, as well as improving efficiencies to maximize profitability throughout our organization.  Despite the reduction in our capital budget, we are maintaining our previous production guidance of 55,000-57,000 boe/d.
  • Vermilion ended 2014 with a net debt-to-2014 FFO ratio of 1.6 times.  Subsequent to year-end 2014, Vermilion exercised its option to expand its available credit under its revolving credit facility to $1.75 billion , the maximum available under the existing agreement.  Following the expansion of the revolving credit facility, Vermilion has approximately $730 million of borrowing capacity available.  The facility, which matures in May 2017 , is fully revolving up to the date of maturity and subject to standard form covenants (discussed in the notes to the Consolidated Financial Statements). Vermilion expects it will continue to be in compliance with all applicable debt covenants and to maintain our current dividend of $0.215 per share per month ( $2.58 per share per year).

  • Subsequent to year end 2014, Vermilion was awarded a recovery of costs resulting from an oil spill at the Ambes oil terminal in France that occurred in 2007. The French court awarded Vermilion approximately €25 million (before taxes), of which 50% is due now, with the remainder due upon conclusion of the appeal process. Based on the recent court decision and the conclusions of an expert engaged by the French court, Vermilion is confident that the award will be upheld.
  • To preserve our financial flexibility while conservatively exercising our access to equity capital, we have amended our existing Dividend Reinvestment Plan to include a Premium Dividend™ Component.  Under the new Premium Dividend™ and Dividend Reinvestment Plan (the "Plan") (6) , Eligible Shareholders who elect to participate in the Dividend Reinvestment Component can continue to reinvest their dividends in common shares at an effective 3% discount to the Average Market Price (with no broker commissions or trading costs), as in our previous Dividend Reinvestment Plan.  With the addition of a new Premium Dividend™ Component, Eligible Shareholders will also have the option to receive a premium cash payment equal to 101.5% of the reinvested dividends.  Shareholders who have not elected to participate in the Plan will continue to receive their regular dividends in the usual manner. The total cost of equity to Vermilion under each component of the Plan will be 3% and 3.5%, respectively.  The Premium Dividend™ Component, when combined with the Dividend Reinvestment Component, is expected to  increase our access to the lowest cost sources of equity capital available. We believe the Premium Dividend™  represents the most prudent approach to preserving near-term balance sheet strength and is expected to reduce cash dividends by approximately $55 million during the remainder of 2015.  We view implementation of a Premium Dividend™ as a short term measure to maintain our financial strength, and both components of our program can be suspended or prorated at the company's discretion, offering considerable flexibility.  We will actively monitor our ongoing needs and manage our continued use of each component as circumstances dictate.
  • 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 December 31, 2014 , of 33.6% per annum since our inception.  As of December 31, 2014 , Vermilion has distributed dividends of $26.43 per share since initiating the first monthly payment in March 2003. Vermilion has increased the dividend three times, and has never cut its dividend.  With the consistent strength of our operations, an extensive and diversified opportunity base, a strong balance sheet and continued access to capital, we are well positioned to exit the current cycle stronger than when we entered it.  We will strive to provide continued operational and financial performance, and a reliable and growing dividend stream to investors, as we proceed with our company's growth plans.
(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 attributable to the assets as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 6, 2015 with an effective date of December 31, 2014 (the "2014 GLJ Reserves Evaluation")
(3) Vermilion retained GLJ to conduct an independent resource evaluation to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2014 (the "GLJ 2014 Resource Assessment")
(4) Vermilion retained GLJ to conduct an independent resource evaluation to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2013 (the "GLJ 2013 Resource Assessment")
(5) Test results are not necessarily indicative of long-term production performance or of ultimate recovery.

ORGANIZATIONAL CHANGES

Vermilion is pleased to announce the appointment of Mr. Kevin Reinhart and Ms. Cathy Williams to our Board of Directors effective March 2, 2015 .

Mr. Reinhart brings over 20 years of oil and gas industry experience, with an extensive background in leadership, strategy and growth, finance, international activities, exploration, sustainability, corporate relations and marketing. In 2012, Mr. Reinhart was named interim President and CEO as well as Director of Nexen Inc. Following the sale of Nexen Inc. in 2013, he was promoted to the role of President and CEO (for Nexen Energy, a CNOOC Limited Company), a position he held up until his retirement in 2014.  Prior to 2012, Mr. Reinhart had held the roles of Executive Vice President and CFO (2009-2012) and Senior Vice President, Corporate Planning and Business Development (2002-2009).  Prior to 2002, Mr. Reinhart served in various capacities as a member of Nexen's executive management team including Controller, Director of Risk Management and Treasurer. From 2005 to 2010, Mr. Reinhart served as a Director of Canexus Ltd. Mr. Reinhart holds a Bachelor of Commerce degree from Saint Mary's University in Halifax . He earned his Chartered Accountant designation in 1985 and is a member of Institute of Chartered Accountants of Alberta .

Ms. Williams brings 30 years of oil and gas industry experience, with an extensive background in finance and business management. Ms. Williams is currently the Owner and Managing Director of Options Canada Ltd. (since 2007) and serves as a Board member of Enbridge Inc. (since 2007) and Chairs their Human Resources and Compensation Committee (since 2010). She was a Board member of Alberta Investment Management Corporation from 2009 to 2014 and Tim Hortons Inc. from 2009 to 2012. From 2003 to 2007, Ms. Williams held the role of Chief Financial Officer for Shell Canada Ltd., prior to which she held various positions with Shell Canada Limited, Shell Europe Oil Products, Shell Canada Oil Products and Shell International (1984 to 2003). Ms. Williams has a Bachelor of Arts degree from University of Western Ontario and a Masters in Business Administration from Queen's University.

Further, Mr. Kenneth Davidson has advised that he will not be standing for re-election to Vermilion's Board of Directors in 2015.  Mr. Davidson has been a Director since December 2005. We wish to thank Mr. Davidson for his contribution to the Board and for his service as Chair of Vermilion's Audit Committee and as a member of the Governance and Human Resources Committee since 2007.

PREMIUM DIVIDEND™ AND DIVIDEND REINVESTMENT PLAN

To preserve our financial flexibility and conservatively exercise our access to capital, we have amended our existing Dividend Reinvestment Plan to include a Premium Dividend™ Component.  Under the new Premium Dividend™ and Dividend Reinvestment Plan (the "Plan"), Eligible Shareholders who elect to participate in the Dividend Reinvestment Component can continue to reinvest their dividends in common shares at an effective 3% discount to the Average Market Price (with no broker commissions or trading costs), similar to our previous Dividend Reinvestment Plan ( Vermilion's Amended and Restated Dividend Reinvestment Plan dated effective September 1, 2010 as amended effective February 27, 2014 (the "Previous DRIP").

With the addition of a new Premium Dividend™ Component, Eligible Shareholders will also have the option to reinvest their dividends in new common shares which will be exchanged for a premium cash payment equal to 101.5% of the reinvested dividends.  Under the Premium Dividend™ Component, shares will be issued at a 3.5% discount to the Average Market Price.  The shares will be presold at prevailing market prices by the Plan Broker (Canaccord Genuity Corporation), who will then provide participating Shareholders with a premium cash payment equal to 101.5% of their dividends, while the Plan Broker retains the balance of the discount as its fee.

Eligible Shareholders are not required to participate in the Plan.  Eligible Shareholders who have not elected to participate in the Plan will continue to receive their regular cash dividends in the usual manner.

The total cost of equity issuance to Vermilion under the Dividend Reinvestment Component and the Premium Dividend™ Component of the Plan will be 3% and 3.5%, respectively.  The Premium Dividend™ Component, when combined with the Dividend Reinvestment Component, is expected to increase our access to the lowest cost sources of equity capital available.  While the Premium Dividend™ is expected to result in a modest amount of equity issuance (estimated to be less than 1% of shares outstanding in 2015), we believe it represents the most prudent approach to preserving near-term balance sheet strength.  We expect the Premium Dividend™ to reduce cash dividends by approximately $55 million during the remainder of 2015.  We view implementation of a Premium Dividend™ as a short term measure to maintain our financial strength.  Both components of our program can be suspended or prorated at the company's discretion, offering considerable flexibility.  We will actively monitor our ongoing needs and manage our continued use of each component as circumstances dictate.

To effect the change, Vermilion's Board of Directors has approved amendments to the Previous DRIP to include a Premium Dividend™ Component.  The new Plan will allow Eligible Shareholders to elect to participate in the Plan, commencing with the March distribution, payable to Shareholders on April 15, 2015 (the "March Dividend").  The March Dividend will have a Dividend Record Date of March 31, 2015 , however all Dividend Record Dates for subsequent 2015 dividend payments will be adjusted, from those previously published, to facilitate the operation of the Premium Dividend TM Component of the Plan.  The amended Dividend Record Dates are now published and available on Vermilion's website at www.vermilionenergy.com (under the heading "Investor Relations" subheading "Dividends") and will be included in the applicable news release announcing the approval and declaration of any future dividend payments by Vermilion's Board of Directors.

Each component of the Plan, which is explained in greater detail in the complete Plan document available on Vermilion's corporate website at www.vermilionenergy.com (under the heading "Investor Relations" subheading "DRIP"), is subject to eligibility restrictions, applicable withholding taxes, prorating as provided for in the Plan, and other limitations on the availability of common shares to be issued or purchased in certain events. Only Canadian-resident Shareholders may participate in the Premium Dividend TM Component of the Plan. The Dividend Reinvestment Component of the Plan is available to Canadian residents and non-U.S. resident foreign Shareholders who meet certain eligibility criteria as set forth in the complete Plan. U.S. resident Shareholders are not currently permitted to participate in either component of the Plan.  This is due to the requirement, under U.S. securities regulations, to maintain a continuous shelf registration for issuance of new equity to U.S. Shareholders.  At this time, Vermilion has not put in place the required shelf registration due to the  high cost of establishing and maintaining such a shelf registration.  We will continue to monitor the relative cost-benefit of such a registration as we go forward.

In order to participate in either the Premium Dividend™ Component or the Dividend Reinvestment Component, an Eligible Shareholder must enroll, or be deemed to have enrolled (in the case of the Dividend Reinvestment Component), in the Plan at least five business days prior to the relevant Dividend Record Date directly (in the case of registered Shareholders) or indirectly through the broker, investment dealer, financial institution or other nominee who holds common shares on the Eligible Shareholder's behalf.

A registered Eligible Shareholder who was enrolled in the Previous DRIP will automatically be deemed to be a participant in the Dividend Reinvestment Component of the Plan, without any further action on their part. A beneficial owner of common shares (i.e., a holder of common shares that are not registered in the beneficial owner's name but are instead held through a broker, investment dealer, financial institution or other nominee) who was validly enrolled, through the nominee holder, in the Previous DRIP should contact such nominee holder to confirm continued participation in the Dividend Reinvestment Component of the Plan.

For more information on the Plan, defined meanings for capitalized terms above, eligibility restrictions and enrollment information among other details of the Plan, please refer to the complete copy of the Plan as well as a related series of Questions and Answers available on Vermilion's website at www.vermilionenergy.com (under the heading "Investor Relations" subheading "DRIP").

™ denotes trademark of Canaccord Genuity Capital Corporation.

Conference Call and Audio Webcast Details

Vermilion will discuss these results in a conference call to be held on Monday, March 2, 2015 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 66942576.  The replay will be available until midnight mountain time on March 9, 2015 .

You may also listen to the audio webcast by clicking http://event.on24.com/r.htm?e=925534&s=1&k=AC0268657BEFCE6AEC7F0AB205FB2A4F 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
HH Henry Hub, a reference price paid for natural gas in US dollars at Erath, Louisiana
mbbls thousand barrels
mboe thousand barrel of oil equivalent
mcf thousand cubic feet
mcf/d thousand cubic feet per day
mmboe million barrel of oil equivalent
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

MESSAGE TO SHAREHOLDERS

Dear Shareholders:

The upstream energy environment continues to be challenging following the dramatic decline in global crude oil prices that began in mid-2014.  While both West Texas Intermediate ("WTI") blend and to a greater extent Brent based crudes have realized modest rebounds from their respective lows reached in January 2015 , we are in a new commodity cycle that may feature lower crude oil prices for an extended period of time.  We have always believed that our strategy, to build a global asset base with diversified commodity exposures and project fundamentals, is the best and most balanced approach to reducing risk and providing the necessary flexibility to adapt to changing commodity cycles and ensure the long-term sustainability of our Company.

Today, more than ever, we believe that our global asset base and diversified commodity exposure, particularly our growing exposure to the strong fundamentals and pricing of European natural gas markets, leaves us competitively advantaged compared to the majority of our North American peers.  In 2014 we actively expanded this exposure with our entry into Germany , a producing region with a long history of crude oil and natural gas development activity, low political risk, and strong market fundamentals.  Our Germany acquisition increased our existing European natural gas production base by nearly 50% in 2014.  Looking to mid-2015, with production forthcoming from our Corrib project in Ireland , we believe European gas may represent approximately 25% of our total oil-equivalent production and generate as much as 35% of our 2015 FFO based on recent strip pricing.  In 2016, with a full year of Corrib production and assuming constant pricing, European natural gas may generate as much as 45% of Vermilion's FFO (1) .  Today's fundamentals and outlook for European natural gas markets remain robust with current prices approximately triple those in North America .  We will continue to consider further opportunities to profitably increase our European natural gas exposure.

During 2014, we realized successful entry into four new areas within our existing core regions.  As previously mentioned, in February we announced our entry into Germany , expanding our exposure to European natural gas markets and establishing a strong foundation for organic growth and possible future acquisitions.  In April, we closed the purchase of a private company with light-oil assets in Southeast Saskatchewan .  We believe we can add significant value to these assets by applying our expertise from horizontal development of our Cardium project.  The transaction established a new light-oil focused core area in Canada for organic growth and land expansion.  To that end, subsequent to the transaction, we expanded our land base by leasing an additional 15,000 net acres of undeveloped land at an average cost of $1,860 per acre.  In September, we announced a small entry into the United States with the purchase of assets located in the Powder River Basin in northeastern Wyoming for $11.1 million .  This accretive acquisition provides a significant undeveloped land block for horizontal development of a promising Turner Sand light oil target.  Finally during 2014, we announced the establishment of a significant land position in Hungary that offers potential for long-term natural gas development with minimal near-term capital commitments.

In December 2014 , we announced our initial 2015 capital budget of $525 million , a 24% reduction from our 2014 capital expenditures.  In view of continued weakness in oil prices since that time,  we are now further reducing our planned capital activity levels in 2015 by an additional $110 million to $415 million , a reduction of approximately 40% as compared to 2014.  These capital budget activities include reductions in planned spending in our Canadian and French business units, and the deferral and potential cancellation of our 2015 Australian drilling program.  We are also directing considerable focus to our PEP initiative to support Vermilion's long-term and sustainable profitability.  Prior installments of PEP achieved strong results in both the 1998 industry downturn and the financial crisis of 2008-2009.  Despite the significant reduction in planned capital expenditures, we are maintaining our previous 2015 production guidance of 55,000 - 57,000 boe/d.

For 2015, our Canadian operational plans reflect a significant reduction in activity levels as we seek to preserve our financial flexibility and balance sheet strength.  While our conventional plays in Canada continue to generate strong returns, the dynamic nature of Canada's service sector and the limited expiry profile of our Canadian asset base provide significant flexibility to moderate near-term capital spending.  As a result, our 2015 Canadian capital activities will be focused predominately on only those activities required to maintain the net asset value of our existing asset base as we work with our vendors to drive down costs across our business.  Our Cardium light-oil resource play continues to generate strong rates of return in excess of 30% (2) , reflecting our relatively low operating costs, continued improvements in completions design and better-than-forecasted production volumes on our two-mile extended reach horizontal wells.  Nevertheless, given limited expiries and our high level of operatorship in the play, we have the flexibility to reduce capital investment levels.  In 2015, we expect to drill or participate in only eight (3.0 net) wells, a significant reduction from previous activity levels of 30 to 50 wells per year.  Our Mannville condensate-rich conventional natural gas play remains the most economic play in our Canadian portfolio  with current rates of return in excess of 85% (2) . For 2015, we anticipate drilling or participating in 28 (16.0 net) wells, up from 20 (10.6 net) wells in 2014.  Our Saskatchewan land base has limited expiries, allowing us to reduce drilling activity on these assets to five (4.1 net) wells in 2015.  In our Duvernay unconventional liquids-rich gas play, we will monitor the performance of our two appraisal wells that we drilled in 2014.  We have deferred further Duvernay drilling activities to beyond 2015.

In France , we have maintained plans for our four-well drilling program at Champotran during Q1 2015 as after-tax rates of return remain robust at more than 100% (2) .  The remainder of our capital expenditures in France will target highly economic workovers and optimization projects, as well as infrastructure and facilities maintenance.  We continue to anticipate that a portion of our 4 mmcf/d of shut-in natural gas production at Vic Bilh will be back on-stream by mid-2015.  In the Netherlands , we are planning for a three (2.4 net) well drilling campaign that is expected to begin in Q2 2015.  The fundamentals and pricing for European gas remain robust, and we will continue to focus significant attention on identifying profitable opportunities to increase our exposure to this market.  In Germany , our operating partner is planning a one (0.25 net) well program.  In Ireland , our Corrib project has continued to progress on schedule following the completion of tunnel boring operations in May 2014. During 2014, project operator Shell Exploration & Production Ireland Ltd. successfully completed offshore workover and pipeline operations as well as outfitting of the 4.9 km tunnel, including installation of flow and umbilical lines, hydro-testing and dewatering, with the final weld completed in December.  Grouting of the tunnel was concluded in January 2015. Natural gas from the national sales grid was safely introduced into the processing facility in November 2014 as part of the commissioning process for the gas plant.  Remaining work includes the completion of gas plant commissioning activities and the 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 spite of the challenges posed by the current business environment, we continue to believe that Vermilion is situated for long-term, diversified growth.  We remain confident that the assets in our portfolio can support organic growth for years to come, and in the current environment, we also find ourselves well positioned to take advantage of potential acquisition activity in both North American and international markets.  Our long-term focus on the creation of real value through our technical capabilities, combined with our conservative financial approach and patience, should allow us to compete and transact for the benefit of our existing shareholders if suitable opportunities arise.

Our balance sheet remains a source of strength.  We have recently exercised our option to expand our credit facilities to $1.75 billion , giving us approximately $730 million of available capacity on our bank line.  In a further step to preserve our financial flexibility and conservatively exercise our access to capital, we have also announced an amendment to our existing DRIP to include a Premium Dividend™ Component.  The Premium Dividend™ Component, when combined with our continuing Dividend Reinvestment Component, is expected to increase our access, at the election of shareholders, to the lowest cost sources of equity capital available.  While the Premium Dividend™ is expected to result in a modest amount of equity issuance, we believe it represents the most prudent approach to preserving near-term balance sheet strength.  We view implementation of a Premium Dividend™ as a short-term measure to maintain our financial flexibility while we continue to lower our unit costs and await further clarity on the direction of commodity prices.  Both components of our program can be turned off at the company's discretion, offering considerable flexibility.  We will actively monitor our ongoing needs and manage our continued use of each component as circumstances dictate.

In 2014, we celebrated Vermilion's 20 th anniversary as a publicly traded company.  It was a demanding, but also a tremendously rewarding, twenty years during which we have experienced previous commodity cycles that were not wholly unlike today's.  Over the years, 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.  The recent decline in crude prices 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.

Reflecting on Vermilion's record, we are pleased that our previous efforts have resulted in a compound average total return including dividends, as of December 31, 2014 , of 33.6% per annum since inception. We are also proud of the consistency of those returns over longer periods.  Over the last  three, five, ten and 15 calendar-year periods, we have reliably delivered double-digit compound average total returns of 12.3%, 16.2%, 14.7% and 21.6%, respectively.

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. 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) Economics calculated using the following commodity price deck assumptions: $55/bbl WTI; $60/bbl Dated Brent; $2.75/mmbtu AECO; US$3.00/mmbtu Nymex; $9.00/mmbtu Title Transfer Facility (Netherlands); CAD/USD 1.20; CAD/EUR 1.40

HIGHLIGHTS

Three Months Ended Year Ended
($M except as indicated) Dec 31, Sep 30, Dec 31, Dec 31, Dec 31,
Financial 2014 2014 2013 2014 2013
Petroleum and natural gas sales 306,073 344,688 325,108 1,419,628 1,273,835
Fund flows from operations (1) 185,528 197,898 163,660 804,865 667,526
Fund flows from operations ($/basic share) 1.73 1.85 1.61 7.63 6.61
Fund flows from operations ($/diluted share) 1.71 1.83 1.58 7.51 6.51
Net earnings 58,642 53,903 101,510 269,326 327,641
Net earnings ($/basic share) 0.55 0.50 1.00 2.55 3.24
Capital expenditures 166,243 190,033 148,478 687,724 542,726
Acquisitions 1,652 40,847 29,103 601,865 36,689
Asset retirement obligations settled 6,247 4,677 5,426 15,956 11,922
Cash dividends ($/share) 0.645 0.645 0.600 2.580 2.400
Dividends declared 69,119 68,896 61,208 272,732 242,599
% of fund flows from operations 37% 35% 37% 34% 36%
Net dividends (1) 48,139 48,480 42,433 193,302 170,308
% of fund flows from operations 26% 24% 26% 24% 26%
Payout (1) 220,629 243,190 196,337 896,982 724,956
% of fund flows from operations 119% 123% 120% 111% 109%
% of fund flows from operations (excluding the Corrib project) 106% 107% 111% 99% 94%
Net debt (1) 1,265,650 1,243,438 749,685 1,265,650 749,685
Ratio of net debt to annualized fund flows from operations (1) 1.7 1.6 1.1 1.6 1.1
Operational
Production
Crude oil (bbls/d) 28,846 29,147 26,039 28,879 25,741
NGLs (bbls/d) 2,822 2,354 1,761 2,553 1,730
Natural gas (mmcf/d) 107.42 110.52 78.96 108.85 81.21
Total (boe/d) 49,571 49,920 40,960 49,573 41,005
Average realized prices
Crude oil and NGLs ($/bbl) 78.64 102.49 106.00 100.06 104.46
Natural gas ($/mcf) 5.90 5.74 7.29 6.42 6.83
Production mix (% of production)
% priced with reference to WTI 28% 28% 25% 28% 25%
% priced with reference to AECO 20% 18% 17% 18% 16%
% priced with reference to TTF 16% 18% 15% 18% 16%
% priced with reference to Dated Brent 36% 36% 43% 36% 43%
Netbacks ($/boe) (1)
Operating netback 45.85 54.25 61.35 55.50 60.43
Fund flows from operations netback 38.67 44.08 43.32 44.09 43.94
Operating expenses 12.48 12.53 12.74 12.72 12.84
Average reference prices
WTI (US $/bbl) 73.15 97.17 97.46 93.00 97.97
Edmonton Sweet index (US $/bbl) 66.79 89.24 82.53 85.83 90.40
Dated Brent (US $/bbl) 76.27 101.85 109.27 98.99 108.66
AECO ($/GJ) 3.41 3.81 3.35 4.27 3.01
TTF ($/GJ) 8.69 7.26 10.65 8.50 10.29
Average foreign currency exchange rates
CDN $/US $ 1.14 1.09 1.05 1.10 1.03
CDN $/Euro 1.42 1.44 1.43 1.47 1.37
Share information ('000s)
Shares outstanding - basic 107,303 106,921 102,123 107,303 102,123
Shares outstanding - diluted (1) 110,334 109,749 104,869 110,334 104,869
Weighted average shares outstanding - basic 107,102 106,768 101,961 105,448 100,969
Weighted average shares outstanding - diluted (1) 108,646 108,290 103,426 107,187 102,467

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

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following is Management's Discussion and Analysis ("MD&A"), dated February 27, 2015 , of Vermilion Energy Inc.'s ("Vermilion", "we", "our", "us" or the "Company") operating and financial results as at and for the three months and year ended December 31, 2014 compared with the corresponding periods in the prior year.

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

The audited consolidated financial statements for the year ended December 31, 2014 and comparative information have been prepared in Canadian dollars, except where another currency has been indicated, and in accordance with International Financial Reporting Standards ("IFRS" or, alternatively, "GAAP") as issued by the International Accounting Standards Board.

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

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

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

VERMILION'S BUSINESS

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

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

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

NEW COUNTRY ENTRIES

In February 2014 , we acquired a 25% contractual participation interest in a four-partner consortium in Germany from GDF Suez S.A.  The acquisition enables us to participate in the exploration and development, production and transportation of natural gas from the assets held by the consortium.  The assets are comprised of four gas producing fields across eleven production licenses and are characterized by a low effective decline rate of approximately 11% annually.  The acquired assets include both exploration and production licenses that comprise a total of 204,000 gross acres, of which 85% is in the exploration license.  The acquisition represented Vermilion's entry into the German exploration and production business, a producing region with a long history of oil and gas development activity, low political risk, and strong marketing fundamentals.  The acquisition provides us with entry into this sizable market, in the form of free cash flow generating, low-decline assets with near-term development inventory in addition to longer-term, low-permeability gas prospectivity.  Entry into Germany is in keeping with our European focus, and increases our exposure to the strong fundamentals and pricing of European natural gas markets.  We believe that our conventional and unconventional expertise, coupled with new access to proprietary technical data, will position us strongly for future development and expansion opportunities in both Germany and the greater European region.

On November 10, 2014 , we announced an acquisition of assets in the Powder River Basin of northeastern Wyoming for $11.1 million .  The assets cover approximately 68,000 acres of land (98% undeveloped) with current working interest production of approximately 200 bbls/d (100% crude oil).  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.  The acquisition represented a low-cost entry into the prolific Powder River Basin and Vermilion's entry into the sizable United States exploration and production market.  Looking ahead we see continued opportunity for expansion, with an active asset market in North America where technology continues to unlock new opportunities for development.  We have established an office in Denver, Colorado as the operating headquarters for our new United States business unit and have hired to staff this subsidiary.

2014 REVIEW AND 2015 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.

Concurrent with the release of our third quarter 2014 financial and operating results on November 10, 2014 , we further revised 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 announced the expectation of achieving production near the upper end of the range for 2014.

We provided updated 2014 capital expenditure guidance concurrent with the release of our initial 2015 production and capital expenditure guidance on December 8, 2014. The increase in 2014 capital expenditures resulted from a shift in capital priorities, previously unplanned spending and foreign exchange movements.

The following table summarizes our 2014 actual results compared to guidance and our 2015 guidance:

Date Capital Expenditures ($MM) Production (boe/d)
2014 - Guidance
2014 Guidance November 7, 2013 555 45,000 to 46,000
2014 - Guidance Updates
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
2014 Guidance - Update December 8, 2014 675 49,000 to 49,500
2014 - Actual Production
2014 Actual February 27, 2015 688 49,573
2015 - Guidance
2015 Guidance December 8, 2014 525 55,000 to 57,000
2015 Guidance February 27, 2015 415 55,000 to 57,000

SHAREHOLDER RETURN

Vermilion strives to provide investors with reliable and growing dividends in addition to sustainable, global production growth.  The following table, as of December 31, 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 $2.58 $7.26 $11.82
Capital appreciation per Vermilion share -$5.35 $11.63 $24.58
Total return per Vermilion share -4.4% 41.6% 112.3%
Annualized total return per Vermilion share -4.4% 12.3% 16.2%
Annualized total return on the S&P TSX High Income Energy Index -13.6% -3.3% 1.3%

(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 Year Ended % change
Dec 31, Sep 30, Dec 31, Q4/14 vs. Q4/14 vs. Dec 31, Dec 31, 2014 vs.
2014 2014 2013 Q3/14 Q4/13 2014 2013 2013
Production
Crude oil (bbls/d) 28,846 29,147 26,039 (1%) 11% 28,879 25,741 12%
NGLs (bbls/d) 2,822 2,354 1,761 20% 60% 2,553 1,730 48%
Natural gas (mmcf/d) 107.42 110.52 78.96 (3%) 36% 108.85 81.21 34%
Total (boe/d) 49,571 49,920 40,960 (1%) 21% 49,573 41,005 21%
Build (draw) in inventory (mbbl) (238) 104 (10) (164) (229)
Financial metrics
Fund flows from operations ($M) 185,528 197,898 163,660 (6%) 13% 804,865 667,526 21%
Per share ($/basic share) 1.73 1.85 1.61 (6%) 7% 7.63 6.61 15%
Net earnings ($M) 58,642 53,903 101,510 9% (42%) 269,326 327,641 (18%)
Per share ($/basic share) 0.55 0.50 1.00 10% (45%) 2.55 3.24 (21%)
Cash flows from operating activities ($M) 229,146 235,010 177,003 (2%) 29% 791,986 705,025 12%
Net debt ($M) 1,265,650 1,243,438 749,685 2% 69% 1,265,650 749,685 69%
Cash dividends ($/share) 0.645 0.645 0.600 - 8% 2.580 2.400 8%
Activity
Capital expenditures ($M) 166,243 190,033 148,478 (13%) 12% 687,724 542,726 27%
Acquisitions ($M) 1,652 40,847 29,103 (96%) (94%) 601,865 36,689 1,540%
Gross wells drilled 26.00 26.00 21.00 89.00 76.00
Net wells drilled 16.58 20.31 16.65 62.43 64.21

Operational review

  • Recorded consolidated average production of 49,571 boe/d during Q4 2014, which was consistent with Q3 2014.
  • Increased consolidated average production for the three months and year ended December 31, 2014 by 21% versus the comparable periods in 2013, primarily due to growth in Canada , the Netherlands , and incremental production from our acquisitions in Germany , southeast Saskatchewan and the United States .  In Canada , production growth of 38% and 34% for the three months and year ended December 31, 2014 , respectively, 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. In the Netherlands , production growth of 8% for the year ended December 31, 2014 versus the comparable period 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 $166.2 million , incurred primarily in Canada , France , and Ireland .  In Canada , capital expenditures totalling $85.4 million were 12% lower than the $97.4 million incurred in Q3 2014 and related to the drilling of 15.16 net wells compared to 16.86 net wells in Q3 2014. In France , capital expenditures of $37.2 million related to workovers, seismic activity, various facility projects, and the drilling of one (0.5 net) well in the Tamaris field. In Ireland , $20.9 million of capital expenditures were incurred related to offshore workover and pipeline operations, as well as outfitting the 4.9 km tunnel.
  • Acquisition expenditures for the quarter totalling $1.7 million related to crown land sales, primarily in southeast Saskatchewan .

Financial review

Net earnings

  • Net earnings for Q4 2014 were $58.6 million ( $0.55 /basic share) as compared to $53.9 million ( $0.50 /basic share) for Q3 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 $17.2 million of unrealized gains due to lower forecasted pricing for 2015 and the impact on the valuation of our crude oil and natural gas derivative positions).
  • Net earnings for the three months and year ended December 31, 2014 were 42% and 18% lower versus the respective comparable periods in 2013 due to a decrease in realized prices and foreign exchange losses, partially offset by the aforementioned gains on derivative instruments.  For the three months ended December 31, 2014 , revenue decreased by 6% driven by lower commodity prices. Revenue increased by 11% for the year ended December 31, 2014 as the decrease in realized prices was offset by incremental production and a decrease in crude inventory as compared to the same periods in 2013. Unrealized foreign exchange losses of $4.0 million and $17.6 million for the three months and year ended December 31, 2014 were the result of the Euro weakening versus the Canadian dollar and the resulting impact on our Euro denominated financial assets.  In addition, both periods were affected by the absence of the $47.4 million impairment recovery recognized in 2013.

Cash flows from operating activities

  • Cash flows from operations decreased 2% as compared to Q3 2014 as lower sales were offset by higher realized gains on derivative instruments and timing differences pertaining to working capital.
  • Cash flow from operations increased by 29% and 12% for the three months and year ended December 31, 2014 compared to the same periods in 2013. For the three months ended December 31, 2014 , the increase primarily related to timing differences pertaining to working capital, partially offset by lower revenues due to lower commodity prices. For the year ended December 31, 2014 , the increase primarily related to increased revenues driven by incremental production related to our Germany and Saskatchewan acquisitions, partially offset by timing differences pertaining to working capital.

Fund flows from operations

  • Generated fund flows from operations of $185.5 million during Q4 2014, a decrease of $12.4 million (6%) versus Q3 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 and general and administration expenses. Lower sales were driven by weaker commodity pricing coupled with a decrease in Netherlands production, as production in that country is managed to optimize facility use and regulate declines.
  • Fund flows from operations increased by 13% and 21% for the three months and year ended December 31, 2014 , respectively, versus the comparable periods in 2013. These increases were primarily the result of increased sales volumes in Canada coupled with incremental production following our Q1 2014 acquisition in Germany , our Q2 2014 acquisition in southeast Saskatchewan , and a draw in Australia inventory in both periods.

Net debt

  • As a result of funding our 2014 acquisitions in Germany , Canada , and the United States , net debt increased to $1.27 billion or 1.6 times fund flows from operations for the year ended December 31, 2014 .

Dividends

  • Declared dividends of $0.215 per common share per month during 2014, totalling $0.645 per common share for the quarter and $2.58 per common share for the year ended December 31, 2014. Dividends were higher in the 2014 periods versus the comparable periods in 2013 due to our increase in dividends per share starting with the January 31, 2014 dividend paid on February 18, 2014 .

COMMODITY PRICES

Three Months Ended % change Year Ended % change
Dec 31, Sep 30, Dec 31, Q4/14 vs. Q4/14 vs. Dec 31, Dec 31, 2014 vs.
2014 2014 2013 Q3/14 Q4/13 2014 2013 2013
Average reference prices
WTI (US $/bbl) 73.15 97.17 97.46 (25%) (25%) 93.00 97.97 (5%)
Edmonton Sweet index (US $/bbl) 66.79 89.24 82.53 (25%) (19%) 85.83 90.40 (5%)
Dated Brent (US $/bbl) 76.27 101.85 109.27 (25%) (30%) 98.99 108.66 (9%)
AECO ($/GJ) 3.41 3.81 3.35 (10%) 2% 4.27 3.01 42%
TTF ($/GJ) 8.69 7.26 10.65 20% (18%) 8.50 10.29 (17%)
TTF (€/GJ) 6.12 5.04 7.45 21% (18%) 5.79 7.51 (23%)
Average foreign currency exchange rates
CDN $/US $ 1.14 1.09 1.05 5% 9% 1.10 1.03 7%
CDN $/Euro 1.42 1.44 1.43 (1%) (1%) 1.47 1.37 7%
Average realized prices ($/boe)
Canada 51.27 64.85 61.10 (21%) (16%) 64.06 61.14 5%
France 79.25 107.99 112.84 (27%) (30%) 105.43 106.26 (1%)
Netherlands 52.07 45.73 67.88 14% (23%) 52.65 64.08 (18%)
Germany 49.19 36.43 - 35% 100% 46.03 - 100%
Australia 90.37 119.07 124.63 (24%) (27%) 113.80 119.38 (5%)
United States 74.08 - - 100% 100% 74.08 - 100%
Consolidated 63.79 76.80 86.04 (17%) (26%) 77.75 83.83 (7%)
Production mix (% of production)
% priced with reference to WTI 28% 28% 25% 28% 25%
% priced with reference to AECO 20% 18% 17% 18% 16%
% priced with reference to TTF 16% 18% 15% 18% 16%
% priced with reference to Dated Brent 36% 36% 43% 36% 43%

Reference prices

  • The growing global surplus of crude oil put considerable downside pressure on global crude oil prices in the fourth quarter of 2014, with Dated Brent falling 25% quarter-over-quarter and 9% year-over-year.
  • North American crude oil prices were not immune to the global oversupply situation as both WTI and Edmonton Sweet index declined by 25% quarter-over-quarter and 5% year-over-year.
  • Natural gas prices at AECO suffered a 10% quarter-over-quarter decline as weather-driven demand was not sufficient to tighten the fundamental balance; however, on a year-over-year basis, AECO increased by 42%.
  • European natural gas prices recovered from a weaker summer.  Aided by both seasonality and concerns over winter supplies from Russia , TTF saw a 20% quarter-over-quarter gain, but with ample gas-in-storage and little weather demand during the early stages of the winter season, the TTF price was down 17% year-over-year.
  • A weak crude oil market and general strengthening of the US dollar saw the Canadian dollar weaken throughout the quarter, but against the Euro, the Canadian dollar was relatively unchanged.

Realized prices

  • Consolidated realized price decreased by 17% for Q4 2014 as compared to Q3 2014 and 26% as compared to Q4 2013.  These decreases were primarily the result of weaker crude oil prices, partially offset by stronger TTF pricing and a weaker Canadian dollar versus the US dollar during Q4 2014 versus the comparable quarters.
  • Consolidated realized price for the year ended December 31, 2014 decreased by 7% as compared to the prior year. This decrease was driven by weaker crude oil and TTF pricing, partially offset by stronger AECO pricing and a weaker Canadian dollar.

FUND FLOWS FROM OPERATIONS

Three Months Ended Year Ended
Dec 31, 2014 Sep 30, 2014 Dec 31, 2013 Dec 31, 2014 Dec 31, 2013
$M $/boe $M $/boe $M $/boe $M $/boe $M $/boe
Petroleum and natural gas sales 306,073 63.79 344,688 76.80 325,108 86.04 1,419,628 77.75 1,273,835 83.83
Royalties (25,963) (5.41) (29,000) (6.46) (17,616) (4.66) (108,000) (5.92) (67,936) (4.47)
Petroleum and natural gas revenues 280,110 58.38 315,688 70.34 307,492 81.38 1,311,628 71.83 1,205,899 79.36
Transportation expense (9,489) (1.98) (10,979) (2.45) (9,081) (2.40) (42,361) (2.32) (28,924) (1.90)
Operating expense (59,881) (12.48) (56,227) (12.53) (48,140) (12.74) (232,307) (12.72) (195,043) (12.84)
General and administration (13,236) (2.76) (16,262) (3.62) (13,954) (3.69) (61,727) (3.38) (49,910) (3.28)
PRRT (13,568) (2.83) (13,834) (3.08) (17,173) (4.55) (60,340) (3.30) (56,565) (3.72)
Corporate income taxes (8,304) (1.73) (17,454) (3.89) (43,065) (11.40) (96,996) (5.31) (161,794) (10.65)
Interest expense (12,943) (2.70) (12,918) (2.88) (10,049) (2.66) (49,655) (2.72) (38,183) (2.51)
Realized gain (loss) on derivative instruments 22,816 4.76 8,837 1.97 (1,300) (0.34) 36,712 2.01 (7,082) (0.47)
Realized foreign exchange (loss) gain (179) (0.03) 812 0.17 (1,294) (0.34) (821) (0.04) (1,866) (0.12)
Realized other income 202 0.04 235 0.05 224 0.06 732 0.04 994 0.07
Fund flows from operations 185,528 38.67 197,898 44.08 163,660 43.32 804,865 44.09 667,526 43.94

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

($M) Q4/14 vs. Q3/14 Q4/14 vs. Q4/13 2014 vs. 2013
Fund flows from operations - Comparative period 197,898 163,660 667,526
Sales volume variance:
Canada 3,545 35,366 136,832
France 5,839 6,706 (9,302)
Netherlands (4,524) (6,216) 11,132
Germany 1,297 13,359 41,962
Australia 29,803 20,345 (1,564)
United States 1,330 1,330 1,330
Pricing variance on sold volumes:
WTI (26,146) (20,454) (4,007)
AECO (3,758) 215 22,959
Dated Brent (52,457) (61,872) (26,662)
TTF 6,456 (7,814) (26,887)
Changes in:
Royalties 3,037 (8,347) (40,064)
Transportation 1,490 (408) (13,437)
Operating expense (3,654) (11,741) (37,264)
General and administration 3,026 718 (11,817)
PRRT 266 3,605 (3,775)
Corporate income taxes 9,150 34,761 64,798
Interest (25) (2,894) (11,472)
Realized derivatives 13,979 24,116 43,794
Realized foreign exchange (991) 1,115 1,045
Realized other income (33) (22) (262)
Fund flows from operations - Current Period 185,528 185,528 804,865

Fund flows from operations of $185.5 million during Q4 2014 represented a decrease of $12.4 million (6%) versus Q3 2014.  This quarter-over-quarter decrease was the result of a $38.6 million decrease in sales, partially offset by a $14.0 million increase in hedging proceeds (following weaker commodity prices during the quarter) and a $9.2 million decrease in corporate income taxes.  The decrease in sales included $75.9 million of pricing variance primarily due to a decrease in crude oil prices, partially offset by $37.3 million of sales volume variance primarily due to higher volumes in Australia (due to inventory draws in the period). The decrease in corporate income taxes was due to lower taxable income resulting from decreased sales.

On a year-over-year basis, fund flows from operations increased 13% and 21% for the three months and year ended December 31, 2014 , respectively, versus the comparable periods in 2013.  These increases were primarily the result of favorable sales volume variances in Canada coupled with incremental production following our Q1 2014 acquisition in Germany .  The impact of increased AECO pricing, hedging proceeds and lower income taxes also contributed favorably to fund flows from operations.  These favorable increases were partially offset by weaker crude oil and 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 the 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 Year Ended % change
Dec 31, Sep 30, Dec 31, Q4/14 vs. Q4/14 vs. Dec 31, Dec 31, 2014 vs.
Canada business unit 2014 2014 2013 Q3/14 Q4/13 2014 2013 2013
Production
Crude oil (bbls/d) 11,384 11,469 8,719 (1%) 31% 11,248 8,387 34%
NGLs (bbls/d) 2,741 2,291 1,699 20% 61% 2,476 1,666 49%
Natural gas (mmcf/d) 58.36 57.07 41.43 2% 41% 55.67 42.39 31%
Total (boe/d) 23,851 23,272 17,322 2% 38% 23,001 17,117 34%
Production mix (% of total)
Crude oil 48% 49% 50% 49% 49%
NGLs 11% 10% 10% 11% 10%
Natural gas 41% 41% 40% 40% 41%
Activity
Capital expenditures ($M) 85,442 97,393 77,245 (12%) 11% 334,742 241,197 39%
Acquisitions ($M) 1,671 27,883 1,603 415,648 9,189
Gross wells drilled 23.00 22.00 21.00 74.00 69.00
Net wells drilled 15.16 16.86 16.65 50.27 57.21

Production

  • The year-over-year increase in full year average production volumes was primarily attributable to strong organic production growth in each of our Cardium light crude oil resource play and Mannville condensate-rich gas play as well as incremental production volumes from our southeast Saskatchewan assets acquired in April 2014 .
  • Cardium production averaged more than 10,000 boe/d in Q4 2014 and more than 10,800 boe/d in 2014.  The 20% increase in average annual production volumes was driven by better-than-forecasted production from long-reach wells and improved completion design.
  • Mannville production averaged more than 4,300 boe/d in Q4 2014, a 17% increase quarter-over-quarter.  Full year 2014 production averaged in excess of 3,900 boe/d.
  • Production from our southeast Saskatchewan assets averaged approximately 3,000 boe/d in Q4 2014, an increase of 15% over Q3 2014.  Full year 2014 production averaged approximately 1,900 boe/d taking into account a closing date for the acquisition of April 29, 2014 .

Activity review

  • Vermilion drilled a total of 18 (13.6 net) operated wells during Q4 2014 and 53 (44.8 net) operated wells during 2014.

Cardium

  • We drilled 13 (9.9 net) operated wells and brought 10 (7.0 net) operated wells on production during Q4 2014.  During 2014, we drilled 30 (25.9 net) operated wells and brought 30 (27.0 net) operated wells on production, of which 17 were long-reach wells with horizontal lengths greater than one mile.
  • Since 2009, we have drilled or participated in 278 (198.8 net) wells.
  • Operating netbacks averaged approximately $62.50 /boe in 2014.
  • In 2015, we plan to drill or participate in approximately eight (3.0 net) wells and complete, equip and tie-in an additional 8.2 net wells which were drilled in 2014.

Mannville

  • During Q4 2014, we drilled four (3.0 net) operated wells and brought three (2.5 net) operated wells on production.  In 2014, we drilled 10 (7.7 net) operated wells and brought eight (6.2 net) operated wells on production.
  • In 2015, we expect to drill or participate in approximately 28 (16.0 net) wells and complete, equip and tie-in an additional 1.0 net well which was drilled in 2014.

Duvernay

  • During the second half of 2014 we drilled two (1.3 net) horizontal wells.  One (0.3 net) well was completed and brought on production during Q3 2014.  The second well was completed and brought on production during Q4 2014.

Saskatchewan

  • We drilled one (0.7 net) operated Midale well and brought three (2.6 net) operated wells on production during Q4 2014.
  • In 2014, we drilled or participated in 12 (10.4 net) Midale wells.
  • In 2015, we plan to drill or participate in five (4.1 net) wells in Saskatchewan .

Financial review

Three Months Ended % change Year Ended % change
Canada business unit Dec 31, Sep 30, Dec 31, Q4/14 vs. Q4/14 vs. Dec 31, Dec 31, 2014 vs.
($M except as indicated) 2014 2014 2013 Q3/14 Q4/13 2014 2013 2013
Sales 112,494 138,853 97,367 (19%) 16% 537,788 382,005 41%
Royalties (15,626) (19,034) (11,039) (18%) 42% (65,563) (40,891) 60%
Transportation expense (3,455) (4,048) (4,102) (15%) (16%) (14,625) (12,254) 19%
Operating expense (19,315) (19,074) (13,218) 1% 46% (76,178) (55,804) 37%
General and administration (2,840) (4,523) (2,478) (37%) 15% (16,791) (12,979) 29%
Fund flows from operations 71,258 92,174 66,530 (23%) 7% 364,631 260,077 40%
Netbacks ($/boe)
Sales 51.27 64.85 61.10 (21%) (16%) 64.06 61.14 5%
Royalties (7.12) (8.89) (6.93) (20%) 3% (7.81) (6.55) 19%
Transportation expense (1.57) (1.89) (2.57) (17%) (39%) (1.74) (1.96) (11%)
Operating expense (8.80) (8.91) (8.29) (1%) 6% (9.07) (8.93) 2%
General and administration (1.29) (2.11) (1.60) (39%) (19%) (2.00) (2.24) (11%)
Fund flows from operations netback 32.49 43.05 41.71 (25%) (22%) 43.44 41.46 5%
Reference prices
WTI (US $/bbl) 73.15 97.17 97.46 (25%) (25%) 93.00 97.97 (5%)
Edmonton Sweet index (US $/bbl) 66.79 89.24 82.53 (25%) (19%) 85.83 90.40 (5%)
Edmonton Sweet index ($/bbl) 75.85 97.21 86.64 (22%) (12%) 94.82 93.12 2%
AECO ($/GJ) 3.41 3.81 3.35 (10%) 2% 4.27 3.01 42%

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 21% quarter-over-quarter as a result of a 25% decrease in Edmonton Sweet index pricing and a 10% decrease in AECO pricing.  This decrease coupled with relatively consistent production volumes resulted in a 19% decrease in sales.
  • On a year-over-year basis, sales per boe decreased by 16% for the three months ended December 31, 2014 and increased by 5% for the year ended December 31, 2014 versus the same periods in 2013.  Sales increased for the current year periods despite the decline in the Edmonton Sweet index price that occurred in the latter half of 2014 due to higher production, including incremental production from our Saskatchewan acquisition and production growth in the Cardium and Mannville resource plays, and higher AECO pricing.

Royalties

  • Royalty expense as a percentage of sales increased to 13.9% and 12.2% for the three months and year ended December 31, 2014 (versus 11.3% and 10.7% for the comparable periods in 2013).  The increase is associated with wells coming off of incentive royalty rates after reaching specified production thresholds, increased natural gas prices, and slightly higher average royalty rates associated with Vermilion's Saskatchewan production.
  • On a quarter-over-quarter basis, royalties as a percentage of sales for Q4 2014 was unchanged versus Q3 2014.

Transportation

  • Transportation expense relates to the delivery of crude oil and natural gas production to major pipelines where legal title transfers.
  • Transportation expense for Q4 2014 was lower than Q3 2014 and Q4 2013 as a result of lower crude oil production subject to transportation costs.
  • Transportation expense increased for 2014 as compared to 2013 due to incremental trucking costs from Vermilion's Saskatchewan properties, which were acquired in Q2 2014.

Operating expense

  • On a per boe basis, operating expenses were relatively unchanged quarter-over-quarter and year-over-year.  In dollar terms, the year-over-year increase is a result of increased facilities maintenance expenditures and gas processing costs coupled with incremental operating expenses associated with Vermilion's Saskatchewan properties.

General and administration

  • Year-over-year, the increase in general and administration expense is associated with incremental expense associated with the Saskatchewan acquisition and higher staffing levels. The quarter-over-quarter decrease relates to 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 Year Ended % change
Dec 31, Sep 30, Dec 31, Q4/14 vs. Q4/14 vs. Dec 31, Dec 31, 2014 vs.
France business unit 2014 2014 2013 Q3/14 Q4/13 2014 2013 2013
Production
Crude oil (bbls/d) 11,133 11,111 11,131 - - 11,011 10,873 1%
Natural gas (mmcf/d) - - - - - - 3.40 (100%)