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Vermilion Energy Inc. Announces Results for the Three and Six Months Ended June 30, 2013

August 1, 2013

CALGARY, Aug. 1, 2013 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report interim operating and unaudited financial results for the three and six months ended June 30, 2013.


  • We recorded the strongest operating quarter in our history in the second quarter of 2013.  Thus far, our capital program has achieved better than anticipated results, generating production growth in all four of our business units.  The Company previously increased production guidance following the first quarter of 2013. However, in view of our operational performance, we are further increasing our production guidance for 2013 to between 40,500 and 41,000 boe/d, up from previous guidance of 39,500 to 40,500 boe/d and original guidance of 39,000 to 40,500 boe/d.

  • Achieved record average production of 42,813 boe/d during the second quarter of 2013, compared to 38,707 boe/d in the first quarter of 2013 and 39,168 boe/d in the second quarter of 2012. Quarter-over-quarter growth resulted primarily from strong production additions from our Cardium and Mannville drilling in Canada and high productivity from our two-well sidetrack program in Australia.

  • Increased quarter-over-quarter production by 13% to over 9,500 boe/d during the second quarter of 2013 from our Cardium light oil play in Western Canada.

  • Continued our Mannville liquids-rich gas horizontal development program by drilling our third Ellerslie well and bringing on production from the second well which was drilled and completed during the first quarter.  In their third and fourth months of production, the first two wells are averaging approximately 4.0 mmcf/d of sales gas and over 400 bbls/d of natural gas liquids (75% condensate) per well.

  • Completed a two-well sidetrack drilling program in Australia.  The wells were brought on production at restricted rates and have demonstrated productive capacity in excess of 6,000 bbls/d and 3,000 bbls/d, respectively.  These wells are currently being produced intermittently to match production to marketing arrangements and to maintain our long-term Wandoo field production rate at between 6,000 and 8,000 bbls/d.

  • Concluded a five-well drilling program in the Champotran field in France in the second quarter.  Four of the wells were infill wells and the fifth well was an approximately two-kilometer step-out well to test southern extension of the field.  All five of the wells were successful, with the four infill wells completed in June and the extension well completed in July.  All five wells currently have per-well production rates in excess of 300 bbls/d at low water cuts.  In aggregate, current production from the wells is approximately 1,800 bbls/d at a 4% water cut.

  • Generated fund flows from operations of $174.6 million ($1.73 per share) in the second quarter of 2013, as compared to $163.6 million ($1.65 per share) in the first quarter of 2013 and $127.8 million ($1.30 per share) in the second quarter of 2012.  Fund flows from operations for the second quarter of 2013 increased 7% on a quarter-over-quarter basis and 37% on a year-over-year basis.

  • We continue to benefit from strong pricing driven by our significant exposure to Brent-based crude oil, WTI-based crude oil and European gas. Vermilion's Brent-based crude production, representing 41% of total production, averaged $105.25 per bbl in the quarter.  WTI crude, representing 25% of our production, averaged $94.22 per bbl. Vermilion's natural gas production in the Netherlands, representing approximately 15% of production, received an average price of $10.82 per mcf during the second quarter of 2013, a premium of $7.29 per mcf as compared to AECO.

  • Increased our significant position in the Duvernay liquids-rich natural gas resource play with the acquisition of an additional 46 sections since the first quarter, bringing our total land position to 318 net sections. This land position, which spans the breadth of the liquids-rich natural gas fairway in two largely-contiguous blocks, was assembled for approximately $76 million dollars ($375 per acre). We currently anticipate drilling our first horizontal Duvernay well prior to year-end 2013, with completion planned for early 2014.

  • In Ireland, tunneling, onshore pipelining, offshore umbilical-laying, and offshore seismic acquisition activities for our Corrib project continued during the second quarter.  Based on our deterministic schedule for remaining construction and commissioning activities, first gas production is anticipated to occur between the end of 2014 and early 2015.

  • In June 2013, Vermilion's syndicate of lenders agreed to increase the Company's 3-year revolving borrowing base from $950 million to $1.2 billion. At the end of the second quarter, Vermilion had available capacity under the borrowing base of $591 million and a net debt to annualized second quarter fund flows from operations ratio of 0.97 times.

Conference Call and Audio Webcast Details

Vermilion will discuss these results in a conference call to be held on Thursday, August 1, 2013 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 78595598.  The replay will be available until midnight eastern time on August 8, 2013.

You may also listen to the audio webcast by clicking or visit Vermilion's website at


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


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;
  • 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;
  • 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; 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 strength and business objectives and the information may not be appropriate for other purposes.  Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information.  These risks and uncertainties include but are not limited to:

  • the ability of management to execute its business plan;
  • the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids and natural gas;
  • risks and uncertainties involving geology of crude oil, natural gas liquids and natural gas deposits;
  • risks inherent in Vermilion's marketing operations, including credit risk;
  • the uncertainty of reserves estimates and reserves life;
  • 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.

In accordance with National Instruments 51-101, 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.

      Three Months Ended     Six Months Ended
($M except as indicated)     June 30,     March 31,     June 30,     June 30,     June 30,
Financial     2013     2013     2012     2013     2012
Petroleum and natural gas sales     311,966     309,576     246,544     621,542     557,032
Fund flows from operations 1     174,592     163,629     127,775     338,221     278,897
  Fund flows from operations ($/basic share)     1.73     1.65     1.30     3.38     2.87
  Fund flows from operations ($/diluted share)     1.71     1.61     1.28     3.33     2.82
Net earnings     106,198     52,137     37,816     158,335     102,910
  Net earnings per share ($/basic share)     1.05     0.53     0.39     1.58     1.06
Capital expenditures     78,118     180,469     94,888     258,587     189,248
Acquisitions     -     -     -     -     106,184
Asset retirement obligations settled     2,370     1,388     2,581     3,758     3,347
Cash dividends ($/share)     0.60     0.60     0.57     1.20     1.14
Dividends declared     60,776     59,612     55,962     120,388     111,086
Net dividends 1     42,146     44,080     37,181     86,226     74,747
  % of fund flows from operations, gross     35%     36%     44%     36%     40%
  % of fund flows from operations, net     24%     27%     29%     25%     27%
Total net dividends, capital expenditures and asset retirement obligations     122,634     225,937     134,650     348,571     267,342
  % of fund flows from operations     70%     138%     105%     103%     96%
  % of fund flows from operations (excluding the Corrib project)     55%     127%     93%     90%     86%
Net debt 1     674,368     744,762     524,610     674,368     524,610
  Crude oil (bbls/d)     26,638     23,583     24,658     25,119     24,576
  NGLs (bbls/d)     1,775     1,431     1,405     1,604     1,389
  Natural gas (mmcf/d)     86.40     82.16     78.63     84.29     79.51
  Total (boe/d)     42,813     38,707     39,168     40,772     39,217
Average realized prices                              
  Crude oil and NGLs ($/bbl)     98.95     103.98     100.07     101.42     103.17
  Natural gas ($/mcf)     7.22     6.77     5.79     7.00     5.78
Production mix (% of production)                              
  % priced with reference to WTI     25%     24%     23%     24%     23%
  % priced with reference to AECO     17%     18%     18%     18%     18%
  % priced with reference to European gas     17%     18%     16%     17%     16%
  % priced with reference to Dated Brent     41%     40%     43%     41%     43%
Netbacks ($/boe) 1                              
  Operating netback     59.30     59.18     53.88     59.24     54.79
  Fund flows netback     44.90     43.89     39.40     44.40     39.85
  Operating expenses     12.36     14.10     12.41     13.21     12.54
Average reference prices                              
  WTI (US $/bbl)     94.22     94.37     93.49     94.30     98.21
  Edmonton Sweet index (US $/bbl)     90.56     87.42     83.29     88.99     87.86
  Dated Brent (US $/bbl)     102.44     112.55     108.19     107.50     113.34
  AECO ($/GJ)     3.35     3.03     1.80     3.19     1.92
  Netherlands gas price ($/GJ)     10.14     10.40     9.45     10.23     9.50
Share information ('000s)                              
Shares outstanding - basic     101,418     99,462     98,330     101,418     98,330
Shares outstanding - diluted 1     103,735     102,380     101,249     103,735     101,249
Weighted average shares outstanding - basic     100,964     99,301     97,937     100,137     97,291
Weighted average shares outstanding - diluted     102,223     101,349     99,923     101,578     99,000
The above table includes non-GAAP measures which may not be comparable to other companies.  Please see the "Non-GAAP
Measures" section of Management's Discussion and Analysis.


Vermilion's strong performance during the second quarter illustrates our consistent operational execution and the advantages of our global diversification strategy. Thus far in 2013, we have achieved growth across all four of our operating regions resulting in record consolidated three and six-month production volumes of 42,813 and 40,772 boe/d, respectively.

Our diversified product mix continues to afford a significant competitive advantage. In the second quarter, 66% of production volumes were Brent and WTI-based crude oil and liquids and 17% was high-netback European gas. Our Brent-based crude (41% of production) continues to receive a premium to the Dated Brent index, resulting in an average realized price of $105.25 per barrel for the second quarter. In addition, our Netherlands natural gas production received an average price of $10.82 per mcf, a premium of $7.29 per mcf compared to an average second quarter price of $3.53 per mcf for AECO natural gas in Canada. Our consistent production growth and increasing exposure to liquids and European gas enabled fund flows from operations to grow 7% quarter-over-quarter and 37% year-over-year.

The majority of our Canadian development activities continued to be focused on the development of our Cardium light oil play. Well performance continues to outpace that of our peers in the area, demonstrating the quality of our land position in the West Pembina region. Since entering the play in 2009, we have drilled 202 gross wells (141 net) in the Cardium and increased production to over 9,500 boe/d. We continue to optimize completion technology and well designs, and remain one of few companies in our producing area to employ long reach wells (greater than one mile in length). After demonstrating production improvement and a significant reduction in per-section costs by drilling long-reach 1.5-mile horizontal wells, we are now planning on drilling a higher percentage of 1.5-mile wells and several 2.0-mile pilot wells over the remainder of 2013. The optimization of frac design and fluids, multi-well pads and drilling longer horizontal wells has enabled us to reduce well costs from more than $5 million per section at the outset of development in 2009 to approximately $3 million per section in the second quarter of 2013. Furthermore, in pursuit of ongoing well cost reduction and enhanced environmental stewardship, we are testing several alternative processes for the recycling of frac flowback water. We also initiated a water injection pilot to test applicability of water-flooding to this reservoir. We anticipate our Cardium drilling inventory will last five to six years at a drilling rate of 40 to 60 wells per year. Our per unit operating costs remain less than $6 per boe for our operated production, resulting in strong operating netbacks of approximately $65 per boe during the second quarter.

In addition to the Cardium, we have also identified a significant inventory of Mannville condensate-rich natural gas targets in the Drayton Valley area. During 2013, our plans are to drill a total of six gross (3.2 net) Mannville wells targeting the Ellerslie formation. During the second quarter, we drilled and completed our third Ellerslie well and brought on production from our second well, which was drilled and completed during the first quarter. In its fourth month of production, the first well is producing at a rate of approximately 3.5 mmcf/d of sales gas with 496 barrels per day condensate and natural gas liquids (79% condensate).  In its third month of production, the second well is producing at approximately 4.5 mmcf/d of sales gas with 322 barrels per day of natural gas liquids (70% condensate).  The third well was brought on production in July and has averaged approximately 1.3 mmcf/d of sales gas with 466 barrels per day of associated natural gas liquids (77% condensate) at an average flowing tubing pressure of 1,125 pounds per square inch during the first two weeks of production.

We continue to expand our position in the Duvernay liquids-rich natural gas resource play with an additional 36.6 net sections acquired in the second quarter and nine net sections acquired subsequent to quarter end. In total, we have amassed 318 net sections in the Edson and Drayton Valley areas spanning the breadth of the liquids-rich natural gas fairway, at a cost of approximately $76 million ($375 per acre).  To date, we have drilled three vertical stratigraphic test wells and plan to drill our first horizontal well late in 2013, with completion to occur in 2014. Our Duvernay rights generally underlie our Cardium and Mannville liquids-rich gas positions, allowing for potential infrastructure, operational and timing advantages should full field development of the Duvernay be pursued.  Combined, our Cardium, Mannville and Duvernay positions provide us with exploration and development opportunities in our core Canadian operating region that have the potential to deliver strong production and reserve growth into the latter half of the decade.

Our Australian activities during the first half of 2013 were focused on completion of the drilling program at Wandoo. We drilled two sidetracks off existing wells, including the longest horizontal section yet drilled at Wandoo to-date of 3,400 metres. The 2013 drilling program has been our most successful effort yet in Australia.  Both sidetracks were brought on production at restricted rates in April, demonstrating productive capacities in excess of 6,000 bbls/d and 3,000 bbls/d, respectively.  To meet current marketing agreements and provide long-term certainty to our customers, our current plan is to maintain production levels within our prior guidance of between 6,000 bbls/d and 8,000 bbls/d. We anticipate maintaining these production levels in Australia for the foreseeable future with drilling programs approximately every two years. Wandoo oil garners a premium to the Dated Brent index and incurs no transportation cost as production is sold directly from the platform, leading to very high netbacks.

During the second quarter, we concluded an initial four-well infill drilling program in the Champotran field in France. The program was subsequently expanded to five wells to drill a two-kilometer step-out well to the south of the existing field.  All five of the wells were successful, with the four infill wells completed in June and the extension well completed in July.  All five wells currently have per-well production rates in excess of 300 bbls/d at low water cuts.  In aggregate, current production from the wells is approximately 1,800 bbls/d at a 4% water cut.  Additional activities in France included workovers, recompletions and facilities upgrades in both the Paris and Aquitaine Basins. In 2012, we completed two acquisitions that were natural additions to our asset base in France and further secured our position as the leading oil producer in the country. We continue to integrate these assets and to identify further opportunities to increase production through seismic data acquisition, workovers, optimized water-flood management and development drilling. Our French business is now an organic growth asset, featuring low base decline rates, high netbacks from Brent-indexed production, strong cash flow generation and high capital efficiencies on development projects. We are increasing our France-based technical staffing to identify and execute additional investment opportunities in these large, complex, conventional light oil fields in both the Paris and Aquitaine Basins.

We continued permitting and drilling preparations in the Netherlands for a three-well drilling campaign in the second half of 2013. Our Garijp debottlenecking project was completed in the first quarter of 2013, enabling incremental production from two wells previously drilled at Vinkega.  Surface facilities for the multi-zone Langezwaag-1 well (42% working interest) were completed and commissioned mid-way through the second quarter.  Langezwaag-1 is currently producing from the Vlieland zone at an average rate of 3.0 mmcf/d, net to Vermilion.  We intend to increase activity in the Netherlands each year to maintain a rolling inventory of projects so that each year's capital program will involve a combination of drilling new wells and the tie-in of previous successes. In March, we were awarded an exploration license for the Akkrum concess

Vermilion Energy Inc.
3500, 520 3rd Avenue SW
Calgary, Alberta T2P 0R3
Phone: 1-403-269-4884
Fax: 1-403-476-8100
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