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CALGARY, July 31, 2014 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and unaudited financial results for the three and six months ended June 30, 2014.
|(1)||Additional GAAP Financial Measure. Please see the "Additional and Non-GAAP Financial Measures" section of Management's Discussion and Analysis.|
Vermilion Energy Inc. Second Quarter 2014 Conference Call and Audio Webcast Details
Vermilion will discuss these results in a conference call to be held on Thursday, July 31, 2014 at 9:00 AM MST (11:00 AM EST). To participate, you may call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). The conference call will also be available on replay by calling 1-855-859-2056 using conference ID number 65722904. The replay will be available until midnight eastern time on August 7, 2014.
You may also listen to the audio webcast by clicking http://event.on24.com/r.htm?e=813553&s=1&k=D1BE33AF46B4AC5B296C96983A231587 or visit Vermilion's website at www.vermilionenergy.com/ir/eventspresentations.cfm.
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.
|AECO||the daily average benchmark price for natural gas at the AECO 'C' hub in southeast Alberta|
|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|
|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|
|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|
|Three Months Ended||Six Months Ended|
|($M except as indicated)||Jun 30,||Mar 31,||Jun 30,||Jun 30,||Jun 30,|
|Petroleum and natural gas sales||387,684||381,183||311,966||768,867||621,542|
|Fund flows from operations (1)||216,076||205,363||174,592||421,439||338,221|
|Fund flows from operations ($/basic share)||2.05||2.01||1.73||4.05||3.38|
|Fund flows from operations ($/diluted share)||2.01||1.97||1.71||3.99||3.33|
|Net earnings ($/basic share)||0.51||1.00||1.05||1.51||1.58|
|Asset retirement obligations settled||2,381||2,651||2,370||5,032||3,758|
|Cash dividends ($/share)||0.645||0.645||0.600||1.290||1.200|
|% of fund flows from operations||32%||32%||35%||32%||36%|
|Net dividends (1)||49,561||47,122||42,146||96,683||86,226|
|% of fund flows from operations||23%||23%||24%||23%||25%|
|% of fund flows from operations||87%||120%||70%||103%||103%|
|% of fund flows from operations (excluding the Corrib project)||73%||111%||55%||92%||90%|
|Net debt (1)||1,168,998||966,310||674,368||1,168,998||674,368|
|Ratio of net debt to annualized fund flows from operations (1)||1.4||1.2||1.0||1.4||1.0|
|Crude oil (bbls/d)||30,184||27,318||26,638||28,759||25,119|
|Natural gas (mmcf/d)||114.08||103.32||86.40||108.73||84.29|
|Average realized prices|
|Crude oil and NGLs ($/bbl)||109.89||111.62||98.95||110.73||101.42|
|Natural gas ($/mcf)||6.19||7.99||7.22||7.04||7.00|
|Production mix (% of production)|
|% priced with reference to WTI||30%||25%||25%||27%||24%|
|% priced with reference to AECO||18%||17%||17%||18%||18%|
|% priced with reference to TTF||18%||19%||17%||19%||17%|
|% priced with reference to Dated Brent||34%||39%||41%||36%||41%|
|Netbacks ($/boe) (1)|
|Fund flows from operations netback||46.24||47.76||44.90||46.98||44.40|
|Average reference prices|
|WTI (US $/bbl)||102.99||98.68||94.22||100.84||94.30|
|Edmonton Sweet index (US $/bbl)||96.85||90.43||90.56||93.65||88.99|
|Dated Brent (US $/bbl)||109.63||108.22||102.44||108.93||107.50|
|Average foreign currency exchange rates|
|CDN $/US $||1.09||1.10||1.02||1.10||1.02|
|Share information ('000s)|
|Shares outstanding - basic||106,620||102,453||101,418||106,620||101,418|
|Shares outstanding - diluted (1)||109,371||105,167||103,735||109,371||103,735|
|Weighted average shares outstanding - basic||105,577||102,278||100,964||103,936||100,137|
|Weighted average shares outstanding - diluted (1)||107,330||104,171||102,223||105,531||101,578|
The above table includes additional GAAP and non-GAAP financial measures
which may not be comparable to other companies.
Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis.
MESSAGE TO SHAREHOLDERS
In 2014, we are celebrating Vermilion's 20th anniversary as a publicly traded company. It has been a demanding, but also tremendously rewarding 20 years. During this time, we have witnessed significant change and encountered many challenges to the industry, and we are particularly proud of our demonstrated ability to effectively navigate those challenges to the benefit of our shareholders. During this time, we have remained committed to stewarding our Company in the best interests of our shareholders. We are pleased that our efforts have been both recognized and supported by our shareholders, resulting in a compound average total return including dividends, as of June 30, 2014, of 36.8% per annum since inception. We are also proud of the consistency of those returns. Over the last one, three, five, ten and 15 calendar-year periods, we have reliably delivered double-digit compound average total returns of 24.6%, 14.5%, 24.0%, 18.6% and 25.5%, respectively.
Perhaps more important to both our current and prospective shareholders, it is our belief that Vermilion is better situated for continued growth than at any other time in our history. With the anticipated growth of fund flows from operations(1), the consistent strength of our operations and our expansive and growing opportunity base, we remain confident that we are positioned to deliver continued strong operational and financial performance in the future, while continuing to provide a reliable and growing dividend stream to our shareholders.
While we are confident that the assets in our current portfolio contain significant opportunity for growth for years to come, we also find ourselves uniquely positioned to advantageously grow and further diversify our opportunity base through potential acquisition activity in both North American and international markets. In North America, we are faced with an active asset market and we continue to see technology unlocking new opportunities for development. With Vermilion's access to relatively low cost capital, our conservative balance sheet, and significant near-term free cash flow(1) growth on the horizon (including from Corrib, which is slated to come on production in mid-2015), we are uniquely positioned to compete and transact should suitable opportunities arise. While international asset markets remain substantially less liquid than in North America, we similarly find ourselves well-positioned for assets that do become available in our selective regions of interest.
The second quarter of 2014 marks another quarter of high activity and effective operational execution for our Company. We achieved significant quarter-over-quarter production growth largely attributable to strong results from our successful Mannville condensate-rich gas and Cardium light-oil development programs in Canada. Production volumes from our Mannville development program averaged more than 4,600 boe/d, an increase of 50% during the second quarter, while Cardium production averaged more than 12,000 boe/d, an increase of 17% from the prior quarter. Operating netbacks(1) for our Cardium production averaged more than $70/boe in the second quarter. Our strong Cardium results reflect continued improvements in completions design and better-than-forecasted production volumes on several of our two-mile extended reach horizontal Cardium wells. With improving efficiencies and productivity, we will require less capital and approximately five fewer Cardium wells than originally anticipated to meet our objectives for our 2014 Cardium program. As a result, we are diverting a portion of our previously planned Cardium expenditures to our Mannville development program which also generates very robust economics. With the incremental capital, we now plan to drill approximately 15 (9 net) Mannville wells in 2014, up from eight (5.7 net) wells in our original budget. Looking forward, we anticipate our Mannville drilling activity will continue to increase in future years as we develop our substantial inventory of highly economic prospects.
We continue to appraise our position in the Duvernay condensate-rich resource play, where we have amassed 317 net sections at the relatively low cost of approximately $76 million ($375/acre). Our position comprises three largely contiguous blocks in the Edson, West Pembina and Niton areas. To date, we have drilled three vertical stratigraphic test wells, and have completed drilling operations on two horizontal appraisal wells. The first horizontal appraisal well is located in the downdip part of our Edson block where condensate yields are expected to be lower than the average in our overall land position. We selected this location because of its proximity to one of our vertical stratigraphic test wells, allowing us to conduct microseismic monitoring in the stratigraphic test well when we frac the horizontal well (expected later in the third quarter of 2014). Our second horizontal appraisal well, which we operate at a 34.8% working interest, is located along a shared lease-line in the Pembina block to allow partner participation. Completion of this second well, also employing microseismic monitoring, is expected during the third quarter. During drilling operations, both the Edson and West Pembina wells encountered stability issues in the build section of the wellbore near the heel of the horizontal well. Both wells were ultimately sidetracked to reach total measured depths of slightly more than 4,700 metres. Drilling operations lasted approximately 100 days per well, double our original estimate. The longer-than-expected drilling time took us past break-up, resulting in wet lease conditions and further contributed to higher costs. As a result of these drilling challenges, we are now forecasting total net well costs for the two horizontal wells of approximately $40 million, including completion, equip and tie-in, microseismic and related monitoring-well workovers. Our development-phase target for well costs (including drill, complete, equip and tie-in) is $12 to $15 million. We believe that development-phase savings will be achievable through learning-curve improvements, lower lease construction costs, economies of scale in procurement and lower evaluation expenditures (such as the elimination of microseismic monitoring). We anticipate that the production results and interpreted fracture geometries from the microseismic data on these appraisal wells will assist us in optimizing completions on future development-phase horizontal wells. We are confident that we will be able to project the appraisal well results to higher condensate yield locations as we move to the northeast in our acreage position, which encompasses the entire breadth of the condensate-rich window. Our Duvernay rights generally underlie our Cardium oil and Mannville condensate-rich gas rights, which creates the potential for infrastructure, operational, and timing advantages if we progress to full development of the Duvernay resource play. In combination, our Cardium, Mannville, and Duvernay positions provide us with exploration and development opportunities in our core Canadian operating region that have the potential to deliver strong production and reserve growth into the latter half of the decade.
On April 29, 2014, we announced the completion of our acquisition of Elkhorn Resources Inc., a private southeast Saskatchewan producer, for total consideration of $427 million. The assets consist of high netback, light oil producing assets in the Northgate region of southeast Saskatchewan and include approximately 57,000 net acres of land (approximately 80% undeveloped), seven oil batteries, and preferential access to 50% or greater capacity at a solution gas facility that is currently under construction. More than 90% of the current production base is operated by Vermilion. Production from the assets was moderately impacted by recent flooding in S.E. Saskatchewan and are projected to average approximately 3,750 boe/d (97% crude oil) during the remainder of 2014. We have currently identified approximately 175 (152 net) potential drilling locations targeting the Midale, Frobisher, Bakken, and Three Forks/Torquay formations. We began a two-rig, 13-well Midale drilling program in June 2014.
We were also active in Europe during the second quarter of 2014 with drilling operations in both France and the Netherlands. In France, we drilled two of five planned wells in Champotran in follow-up to our highly successful 2013 drilling campaign. These first two wells have been put on production during July at initial rates averaging 275 bbls/d per well. The remaining three wells at Champotran will be drilled before the end of the third quarter. Our first well in the Parentis field has been put on production at a rate of 20 bbls/d. A new pool exploratory test at Cazaux North has been evaluated as dry and will be abandoned. We currently plan a seven-well drilling program in France during 2014, with two previously planned wells deferred to later-year programs to optimize surface access and reduce rig move costs. During the second quarter of 2014, we advanced preparations for the phased transfer of our shut-in Vic Bihl natural gas production from the Lacq gas processing facility where it was previously handled to a new third party facility. Delays in receiving required permit transfers have pushed our original plans to bring approximately 850 mcf/d of solution gas back on-stream from the third quarter of 2014 to early 2015. The remainder of the shut-in gas production, approximately 3,400 mcf/d of gas cap gas, is expected to be back on production in late-2015.
In the Netherlands, we drilled two additional wells during the second quarter of 2014. The Havelte-01 well in the Steenwijk concession in Friesland (50% working interest) came in low to prognosis and was plugged and abandoned. However, as part of the Havelte-01 project, we will tie-in a previously-stranded gas discovery at Eesveen-01. First gas is anticipated to occur from Eesveen in early 2015 at an anticipated rate of 3 mmcf/d net to Vermilion. The Lambertschaag-02 well was non-commercial in its primary objective but did encounter other zones of interest with significant gas shows that will be further evaluated during the third quarter of 2014. There are three wells remaining in our 2014 Netherlands drilling program with one planned during the third quarter and two in the fourth quarter. Late in the second quarter, we initiated production from the Zechstein carbonate formation of the previously-idle DeHoeve-01 well (42% working interest), at a rate of 3 mmcf/d, net to Vermilion. Our undeveloped land base in the Netherlands now totals more than 800,000 net acres, and it is our intention to generally increase annual activity levels 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 Germany, we have now established an office in Berlin, placed an experienced Managing Director, and are progressing well with recruiting a supporting technical team to oversee both our existing assets and potential new opportunities. Our current position in Germany enables us to participate, on a non-operated basis, in the exploration, development, production and transportation of natural gas from four gas producing fields across 11 production licenses. The assets are expected to contribute approximately 2,300 boe/d of production for calendar 2014, and include both exploration and production licenses that comprise a total of 207,000 gross acres, of which 85% is in the exploration license. Germany is a producing region with a long history of oil and gas development activity, low political risk, and strong marketing fundamentals. Our position provides us with entry into this sizable market, in the form of free cash flow(1) generating, low-decline assets with near-term development inventory in addition to longer-term, low-permeability gas prospectivity. We believe that our conventional and unconventional expertise, coupled with new access to proprietary technical data, will position us for future development and expansion opportunities in both Germany and the greater European region. During the first quarter of 2014, we participated in the drilling of one (0.25 net) development well in Germany. This well logged 81 metres of net pay and is expected to be tested and put on production during the second half of 2014.
On May 22, 2014, we announced the completion of tunnel boring operations beneath Sruwaddacon Bay at our Corrib project in Ireland. The tunnel boring machine has now been demobilized and the project is progressing well with respect to several key activities that remain to be completed prior to initial production at Corrib. These activities include the installation of flow and umbilical lines within the tunnel, grouting of the tunnel, certain offshore well workover activities, and receipt of final authorizations for start-up of the Bellanaboy gas facility. The most significant remaining offshore workover activity at our Corrib field was successfully completed subsequent to the end of the quarter. The Corrib P6 well was flow tested for 24 hours at a final flow rate of 112 mmcf/d at a flowing bottom hole pressure of 3260 psi, representing an approximate 44 percent drawdown from reservoir pressure. The test rates were within expectations, reconfirming previous test rates. The well was still "cleaning up" at the end of the test, exhibiting an increasing flow rate at increasing flowing bottom hole pressure when the test period ended. The P6 test confirms that all five wells required for start-up at Corrib are ready to flow. Based on the current deterministic schedule for the project, we anticipate first gas from Corrib in approximately mid-2015, with peak production estimated at approximately 58 mmcf/d (approximately 9,700 boe/d) net to Vermilion.
In Australia, we remain focused on completing preparations for the 2015 drilling program, as well as re-lifing and maintenance projects on our two platforms. In order to meet current marketing agreements and provide long-term certainty to our customers, our current plan is to maintain field-total production levels within our prior guidance of between 6,000 bbls/d and 8,000 bbls/d. We anticipate maintaining these production levels in Australia for the foreseeable future with drilling programs approximately every two years. Our Australian oil currently garners a premium of approximately US $7.00 to the Dated Brent index and incurs no transportation cost as production is sold directly at the platform.
Our operations continue to perform strongly, generating organic production growth in a capital-efficient manner. Given the strength of our operations, we have elected to increase our previous 2014 average annual production guidance from a range of 48,000-49,000 boe/d to a range of 48,500-49,500 boe/d. Assuming commodity prices remain near current levels for the remainder of 2014, we anticipate that we can fully fund our net dividends(1) and development capital expenditures (excluding capital investment at Corrib) with fund flows from operations during 2014. With the shifts in capital spending outlined previously, we currently anticipate full year 2014 capital expenditure to total approximately $650 million, an increase from our previous guidance of $635 million. This increase largely reflects a shift in spending to increase Mannville development drilling as well as higher costs for our Duvernay appraisal wells.
We believe we remain positioned to deliver strong operational and financial performance over the next several years. We continue to target annual organic production growth of approximately 5% to 7% along with providing reliable and growing dividends. Near term production and fund flows from operations growth is expected to be driven by continued Cardium and Mannville development in Canada, oil development activities in France, and high-netback natural gas drilling in the Netherlands. A significant increment of production, fund flows from operations and free cash flow growth is expected from Corrib beginning in approximately mid-2015 with the first full year of production from the project in 2016. Our Australian and German business units are expected to provide relatively steady production as well as strong free cash flow.
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 5th 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 13th 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 10th Best Workplace in its category, the highest score of any energy company in the survey.
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
PDF available at: http://www.vermilionenergy.com/files/historical-press-releases/2014/2014-07-31 - Second Quarter Earnings Results.pdf
Vermilion Energy Inc.
3500, 520 3rd Avenue SW
Calgary, Alberta T2P 0R3