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CALGARY, Oct. 25, 2018 /CNW/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and condensed financial results for the three and nine months ended September 30, 2018.
The unaudited financial statements and management discussion and analysis for the three and nine months ended September 30, 2018, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.
(1) Non-GAAP Financial Measure. Please see the "Non-GAAP Financial Measures" section of Management's Discussion and Analysis.
($M except as indicated)
Petroleum and natural gas sales
Fund flows from operations
Fund flows from operations ($/basic share) (1)
Fund flows from operations ($/diluted share) (1)
Net (loss) earnings
Net (loss) earnings ($/basic share)
Asset retirement obligations settled
Cash dividends ($/share)
% of fund flows from operations
Net dividends (1)
% of fund flows from operations
% of fund flows from operations
Ratio of net debt to annualized fund flows from operations
Crude oil and condensate (bbls/d)
Natural gas (mmcf/d)
Average realized prices
Crude oil and condensate ($/bbl)
Natural gas ($/mcf)
Production mix (% of production)
% priced with reference to WTI
% priced with reference to Dated Brent
% priced with reference to AECO
% priced with reference to TTF and NBP
Operating netback (1)
Fund flows from operations netback
Average reference prices
WTI (US $/bbl)
Edmonton Sweet index (US $/bbl)
Saskatchewan LSB index (US $/bbl)
Dated Brent (US $/bbl)
Average foreign currency exchange rates
CDN $/US $
Share information ('000s)
Shares outstanding - basic
Shares outstanding - diluted (1)
Weighted average shares outstanding - basic
Weighted average shares outstanding - diluted (1)
(1) The above table includes non-GAAP financial measures which may not be comparable to other companies. Please see the "NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis.
Message to Shareholders
We delivered record quarterly production of 96,222 boe/d in Q3 2018, marking our first full quarter with the integration of the Spartan assets and our first quarter with production and cash flow contribution from our Central and Eastern European ("CEE") business unit. We also completed another acquisition in the quarter, expanding our land base in the Turner Sand fairway. We expect both of these acquisitions and ongoing development in our CEE business unit to contribute to our long-term growth profile, while generating free cash to support our growth-and-income capital markets model.
Our Q3 2018 FFO increased 34% quarter-over-quarter to $261 million, which is twice the amount we generated in Q3 2017. The Q3 2018 results included a $37 million realized hedging loss largely driven by the recent strength in global oil prices and European natural gas prices. On a year-to date basis, we have generated $616 million in FFO, which includes the impact of an $83 million realized hedging loss.
Our Board of Directors has approved a 2019 capital budget of $530 million with associated production guidance of 101,000 to 106,000 boe/d. The midpoint of this guidance range represents year-over-year production growth of 18%, or 7% on a per share basis. Including our projected 2018 results, Vermilion will have delivered compounded average production-per-share-growth of 9% over the past 5 years, coming primarily from high margin barrels, as the majority of our production receives premium or advantaged pricing relative to our peers. The oil and gas produced from our international assets is indexed to Brent oil and European gas benchmarks, both of which trade at significant premiums to their North American counterparts. In turn, the vast majority of our North American oil is produced in areas that have relative pricing advantages to most Canadian oil streams, enhancing netbacks and free cash flow generation.
With our growing production base, continued discipline in capital spending, and the current strength in commodity prices, our free cash flow profile has never been better. Based on the mid-point of our 2019 production guidance and the current commodity strip at October 15, 2018, we expect to more than fully fund our $530 million capital program and annual dividend, resulting in a total payout ratio of approximately 82% and over $200 million in surplus cash beyond our needs for our capital program and dividends.
As part of our annual budgeting process and ongoing strategic planning for the company, we continuously update our long-range development plans. On this note, we have recently updated the investor presentation on our website to reflect our longer-term drilling plans in the Netherlands and Germany. In Germany, we have identified several future exploration prospects (working interests from 46% to 100%) which we believe may range in size from 300 Bcf to over 1 Tcf of recoverable gas (unrisked) if successful. We plan to drill these prospects over the next five years. In the Netherlands, we have outlined a preliminary drilling schedule that calls for acceleration of our annual drilling activity to six or more wells by 2021. We continue to work to identify ways to streamline our permitting process in the Netherlands, and are increasingly confident that this accelerated drilling pace can be achieved over time. Our 2019 budget includes a ten (7.0 net) well drilling program in Central and Eastern Europe, which is an area in which we have recently initiated production and expect to continue to expand in the years ahead. In aggregate, our European drilling plan calls for 19 (13.7 net) wells next year, the largest drilling program we have conducted in our 21-year history in that region. We will discuss many of these future growth prospects in greater detail at our upcoming investor day in Toronto on November 27, 2018.
Q3 2018 Operations Review
In France, Q3 2018 production averaged 11,407 boe/d, a decrease of 2% from the prior quarter. The three (3.0 net) wells from our early 2018 drilling program in the Champotran field continue to outperform, contributing 750 boe/d in the third quarter, while other workover and maintenance activities continue to progress as planned.
In the Netherlands, Q3 2018 production averaged 7,479 boe/d, an increase of 2% from the prior quarter. In mid-September, we brought the Eesveen-02 well (60% working interest) on production. The well is currently flowing at a restricted rate of 10 mmcf/d net, pursuant to the conditions of the environmental permit. The well is expected to produce at this rate through 2019. Additional activity during the third quarter was focused on maintenance and well workovers, and planning for our 2019 drilling campaign. We were recently granted a positive decision on the EIA (Environmental Impact Assessment) judgment for the two wells included in our 2019 drilling plans and are now awaiting final approval of the drilling permits before proceeding. As mentioned above, we continue to work on advancing our future drilling permits, in part by reducing our surface footprint through long departure wells from existing well pads where feasible, in preparation for an accelerated drilling program in the years ahead. As previously noted, we intend to accelerate our annual drilling program to six or more wells per year by 2021.
In Ireland, production from Corrib averaged 51 mmcf/d (8,563 boe/d) in Q3 2018, a 9% decrease from the prior quarter, primarily due to a planned plant turnaround in September, which reduced production by approximately 450 boe/d net to Vermilion. Natural declines accounted for approximately 400 boe/d of the quarter-over-quarter decrease, which is consistent with our numerical simulation of reservoir performance. Our reservoir simulation model projects an average annual decline rate of approximately 15%, with a slightly higher decline rate in the early years and a slightly lower decline rate in the later years. Based on the model, we expect the field to decline at approximately 17% in 2019, decrease to 15% in 2020, and then level off to approximately 14% thereafter. We continue to focus on activities associated with the transition of ownership and operatorship from Shell to Canada Pension Plan Investment Board ("CPPIB") and Vermilion. We anticipate receiving final approvals from the necessary authorities and closing the transaction before the end of 2018. As noted in our Q2 2018 release, although the longer than anticipated closing of this transaction will have a modest impact on our booked production from Ireland, Vermilion will still benefit from all interim period cash flows from January 1, 2017 to closing as a reduction of purchase price. We now anticipate the closing price for our incremental 1.5% working interest to be approximately €6 million, compared to €19.4 million as announced in July 2017.
In Germany, production in Q3 2018 averaged 3,498 boe/d, little changed from the prior quarter. Restoration of gas processing at a non-operated gas processing facility during the quarter was largely offset by other minor unplanned downtime events. Our capital activity in Germany continues to focus on well and facility maintenance and preparatory work related to the drilling of our first operated well in Germany, the Burgmoor Z5 well (46% working interest), which is expected to commence drilling in Q1 2019.
In Central and Eastern Europe, first gas production commenced from our Hungarian Mh-Ny-07 natural gas well (100% working interest) in the South Battonya concession. The well, which was drilled and tested in the first quarter of this year, was brought on production mid-August and contributed 195 boe/d to our Q3 2018 results. The production rate from this well has recently been increased to 5.3 mmcf/d (880 boe/d), which compares to our original test flow rate of approximately 5.8 mmcf/d (970 boe/d). Permitting activities have been initiated in preparation for our 2019 drilling campaign across Hungary, Slovakia and Croatia where we plan to drill ten (7.0 net) wells. The permitting process is progressing well as we work collaboratively with regulatory bodies in all three countries who continue to exhibit strong levels of support for our activities. In Hungary, further 3D seismic interpretation performed in the quarter revealed a new Pannonian gas prospect in our Ebes license, with seismic attributes analogous to our Mh-Ny-07 discovery in South Battonya. In Croatia, we initiated seismic permitting for a new 2D seismic data acquisition to be carried out in Q4 2018, following the positive results achieved on the first phase of our 2D seismic data acquisition in Q2 2018.
In Australia, production averaged 4,704 bbl/d in Q3 2018, representing a 14% increase from the previous quarter primarily due to reinstatement of production following well workover activity that was successfully completed in Q2 2018. Another key well workover, which is part of our electrical submersible pump/increased fluid handling project, was completed at the end of Q3 2018 and should restore additional production in Q4 2018. Subsequent to end of the third quarter, we successfully completed a planned platform turnaround. In addition to the workover activity in Q3 2018, we continued to focus on preparatory activities associated with our upcoming two (2.0 net) well drilling campaign in Q4 2018. We have secured all necessary third party contracts and regulatory permits to drill and have prepared the majority of the materials needed for the load-out offshore. The rig is scheduled to arrive by the end of October, which should enable us to complete the planned wells by early January. As stated in our Q2 release, the early drilling is not expected to contribute any production to our 2018 results, but will allow us to save approximately $12 million in capital compared to drilling in 2019.
In Canada, production averaged 57,397 boe/d in Q3 2018, representing a 31% increase from the previous quarter, primarily due to a full quarter of contribution from the Spartan assets. Production was partially offset by downtime due to third party gas plant maintenance, rate restrictions on certain wells and weather-related project delays. We drilled or participated in 65 (59.0 net) wells and brought on production 53 (49.8 net) wells in Q3 2018. We successfully executed a five rig drilling program in Saskatchewan in the quarter, drilling or participating in 60 (54.6 net) wells across our combined land base. We also operated one rig in Alberta during the quarter which included the drilling of four (4.0 net) Mannville wells and one (0.4 net) Cardium well. Results from all programs have been in line with our expectations.
Canadian oil differentials widened towards the end of the quarter, which had a modestly negative impact on our realized pricing. The majority of our Canadian liquids production receives significantly advantaged pricing relative to Alberta-based light crude oil. We have no heavy crude (WCS) in our Canadian oil mix. Approximately 70% of our Canadian oil is produced in southeast Saskatchewan and receives a price referenced to LSB (Light Sour Blend). The remaining 30% of our Canadian oil production is comprised of a combination of condensate and light oil in west-central Alberta and the Kerrobert area of Saskatchewan which is price referenced to the C5+ and MSW (Mixed Sweet Blend) benchmarks respectively. In the forward market for the balance of the year, the discount on all Canadian oil products has widened significantly. However, LSB and C5+ have widened to a much lesser extent than WCS and MSW. For example, LSB in the current prompt market has strengthened by approximately US$11.00/bbl relative to MSW compared to the average for Q3 2018.
Although we do not actively target natural gas in our Canadian operations, we still produce gas from high margin condensate-rich and liquids-rich gas wells and associated gas from our light oil assets. Subsequent to the quarter, AECO gas prices have improved significantly, with the forward curve indicating a Q4 2018 price that is nearly double the Q3 2018 price, representing a potential $1.00/mcf quarter-over-quarter improvement should the forward curve be realized. For every $1.00/mcf increase in AECO gas prices, we estimate an additional annual FFO contribution of approximately $50 million.
In the United States, Q3 2018 production averaged 2,979 boe/d, an increase of 280% from the prior quarter, due to the production associated with the Powder River Basin acquisition and development activities during the quarter. Third quarter production also increased following the completion of our first half 2018 drilling program, as we brought the final two (2.0 net) wells of the five (5.0 net) well program on production.
Powder River Basin Acquisition
During the third quarter, we acquired mineral land and producing assets in the Powder River Basin in Wyoming (the "Acquisition") for total cash consideration of approximately $186 million (the "Purchase Price").
The Acquisition is comprised of low base decline, light oil-weighted production and high-quality mineral leasehold in the Powder River Basin in Campbell County, Wyoming (the "Assets"), approximately 40 miles (65 kilometres) northwest of Vermilion's existing operations. The Assets include approximately 55,700 net acres of land (approximately 96% working interest) and approximately 2,500 boe/d (63% oil and NGLs) of production with an estimated annual base decline rate of 13%. Approximately half of the current production comes from three federal secondary recovery units in the Muddy formation, with the remainder coming from higher-netback production from Turner Sand horizontal producers.
Vermilion has identified 93 future drilling locations targeting light oil in the Turner and Parkman tight sandstones, which are expected to be developed using horizontal wells with multi-stage fracs. In these future development zones, the production and reserves are expected to be comprised of approximately 75% crude oil and NGLs. Significant infrastructure already exists in the area, including gas gathering and water source and disposal, which is expected to simplify future development. All of the production on the acquired land is operated and 93% is held-by-production (HBP), giving us control over the pace of development.
The Acquisition is accretive on a per share basis for all pertinent metrics including production, debt-adjusted cash flow(2) and reserves. Making no deduction for land value, transaction metrics equate to $5.40 per boe of proved plus probable ("2P") reserves, and $74,400 per flowing barrel of production. Alternatively, ascribing zero value to the acquired production, the total Acquisition cost is approximately $3,400 per net acre or US$2,600 per net acre. Total 2P reserves attributed to the Assets at an effective date of December 31, 2017 are 34.4(3) mmboe (67% crude oil and NGL), based on an independent evaluation by GLJ Petroleum Consultants Ltd. Using WTI strip pricing of US$72.20/bbl for the remainder of 2018 at October 15, 2018, the operating netback for the current production is estimated at approximately $28.32(1) per boe. Using a 2P finding, development and acquisition cost (based on the reserves in the GLJ report) of $11.80 per boe (including future development capital), the Assets are expected to deliver a 2P after-tax fund flows recycle ratio(2) of 2.4 times. It is anticipated that future netbacks, cash flows and recycle ratios will be enhanced by more highly oil-weighted production additions from the Turner and Parkman Sands.
Using the same strip pricing assumptions as above, the cost of the Acquisition is approximately 6.4 times debt-adjusted cash flow(2) based on 2018 annualized cash flow. The transaction was financed by drawing on our revolving credit facility. Following the Acquisition, we have expanded our credit facility commitment level to $1.8 billion from $1.6 billion, maintaining unutilized revolver capacity at approximately $450 million. Pro-forma the acquisition, our projected year-end 2019 debt-to-fund flows from operations ("FFO") ratio is forecast to be 1.43 times on October 15, 2018 strip pricing, as compared to 1.33 times prior to the acquisition.
The Acquisition expands our presence in a highly-prospective basin where we already operate and are familiar with the land, regulatory, reservoir and geologic characteristics. The Acquisition also increases scale in our US business unit, providing for operational synergies with our existing Turner Sand position, a significant inventory of semi-conventional locations in a well-delineated productive area, and potential for additional consolidation and organic growth in the region. Finally, the Acquisition aligns with our sustainable growth-and-income model by accretively adding low risk assets with strong free cash flow, high netbacks, low base decline rates and strong capital efficiencies on future development.
Our Board of Directors have approved an E&D capital budget of $530 million for 2019, with associated production guidance of 101,000 to 106,000 boe/d. The midpoint of our 2019 production guidance reflects year-over-year growth of 18%, or 7% on a per share basis, compared to 2018.
Our 2019 capital budget will fund additional activity in all countries except Australia, where we accelerated the originally planned 2019 two-well program into Q4 2018. The 2019 program reflects a full year of development on the Spartan assets, additional capital associated with the recently acquired assets in the Powder River Basin, and also incorporates a significantly expanded drilling program in Europe.
In Europe, we expect to resume drilling in the Netherlands, significantly expand our drilling program in Central and Eastern Europe, commence our inaugural drilling campaign in Germany, and continue with our low risk development plans in France. The majority of the new wells we plan to drill in Europe during 2019 will be targeting natural gas which continues to sell at a significant premium to North American gas prices. In total, we plan to drill 19 (13.7 net) wells in Europe in 2019, representing our most active drilling program in Europe over our 21-year history. This is more than three times the number of wells we drilled in 2018 and over 25% more than our previous high in Europe.
In North America, our activity will continue to focus on our three core areas of west-central Alberta (condensate-rich gas), southeast Saskatchewan (light oil) and the Powder River Basin in Wyoming (light oil), all of which are products with advantaged market access and resulting lower basis differentials. We plan to drill 19.0 (16.7 net) condensate-rich wells in west-central Alberta, 143 (129.0 net) light oil wells in southeas