Vermilion Energy Inc. Announces Results for the Year Ended December 31, 2018 and 2018 Reserves and Resources Information

Source Press Release
Company Vermilion Energy Inc. 
Tags Hedging, Strategy - Upstream, Strategy - Corporate, Financial & Operating Data
Date February 28, 2019

 Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX,NYSE: VET) is pleased to report operating and financial results for the year ended December 31, 2018 along with our 2018 reserves and resources information.

The audited financial statements, management discussion and analysis, and annual information form for the year ended December 31, 2018, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR") at , on EDGAR at , and on Vermilion's website at .

Highlights

  • Q4 2018 production averaged 101,621 boe/d, representing a 6% increase over the prior quarter, primarily due to strong performance from our Netherlands, Canadian and US business units.
  • 2018 production increased by 28% year-over-year to 87,270 boe/d (10% on a per share basis), within 1% of the mid-point of our guidancerange.
  • Fund flows from operations ("FFO")(1) for Q4 2018 was $222 million($1.46/basic share(1)), down 15% from the previous quarter as higher production was more than offset by lower commodity prices. FFO in 2018 was $839 million ($5.96/basic share(1)), an increase of 39% from the prior year (19% on a per share basis), due to higher productionvolumes and commodity prices, which were partially offset by $111 million of realized hedging losses.
  • Net earnings in 2018 were $272 million ($1.93/basic share), representing a 336% increase over the prior year (271% on a per share basis). We generated a Return on Capital Employed(1) ("ROCE") of 9%, compared to our 5-year average ROCE of 4%.
  • Production in the Netherlands in Q4 2018 averaged 8,749 boe/d, an increase of 17% from the prior quarter. The increase is primarily due to the benefit of a full quarter contribution from the Eesveen-02 well (60% working interest), which we brought on production late in the third quarter at a restricted rate of 10 mmcf/d net.
  • In Ireland, production from the Corrib Natural Gas Project (the "Corrib Project") averaged 52 mmcf/d (8,672 boe/d) in Q4 2018, an increase of 1% from the prior quarter. On November 30, 2018, we assumed operatorship of the Corrib Project and completed the transfer of Shell E&P Ireland Limited ("SEPIL") along with an incremental 1.5% working interest in the Corrib Project to Vermilion from Nephin Energy Holdings Limited, a wholly owned subsidiary of Canada Pension Plan Investment Board ("CPPIB"). Cash consideration at closing was $9 million, which was more than offset by the assumption of $15 millionin positive net working capital associated with the acquisition.
  • In Canada, production averaged a record 60,814 boe/d in Q4 2018, representing an increase of 6% from the previous quarter. The increase was primarily due to new well completions in both our southeast Saskatchewan assets and Alberta assets.
  • In the United States, Q4 2018 production averaged 3,545 boe/d, an increase of 19% from the prior quarter, due to a full quarter of production associated with the Powder River Basin acquisition completed in the prior quarter.
  • In Australia, production averaged 4,174 bbl/d in Q4 2018, down 11% from the previous quarter primarily due to a planned shutdown for maintenance and other downtime which was required to allow drilling of two new wells. We commenced drilling of the B15 and B16 wells in early November 2018 and completed the wells in late January 2019. The wells were tested in February 2019. The B15 well tested at an oil rate of 8,800 bbls/d over a 48-hour period and the B16 well tested at an oil rate of 7,600 bbls/d over a 36-hour period(2). We plan to intermittently produce the new wells at restricted rates to maximize long-term value.
  • Our 2018 reserves as evaluated by GLJ as at December 31, 2018 are as follows:
    • Proved plus probable ("2P") reserves increased 63% from year-end 2017 to 488.1(3) mmboe. We replaced 187% of 2P reserves through development activities and 695% including acquisitions. Our 2P finding and development ("F&D") cost(4) was $7.79 per boe, including future development capital ("FDC")(4), resulting in an organic 2P Operating Recycle Ratio(5) (including FDC) of 4.1x compared to 2.8x in 2017.
    • Proved ("1P") reserves increased 69% from year-end 2017 to 298.2(3) mmboe. We replaced 157% of 1P reserves through development activities and 481% including acquisitions. Our 1P F&D cost was $13.49 per boe, including FDC, resulting in an organic 1P Operating Recycle Ratio(5) (including FDC) of 2.3x.
    • Proved developed producing ("PDP") reserves increased 55% from year-end 2017 to 192.1(3) mmboe. We replaced 130% of PDP reserves through development activities and 314% including acquisitions. Our PDP F&D cost was $15.65 per boe, including FDC, resulting in an organic PDP Operating Recycle Ratio(5)(including FDC) of 2.0x.
  • Our independent 2018 GLJ Resources Report(6) indicates risked low, best, and high estimates for contingent resources in the Development Pending category of 156(6) mmboe, 240(6) mmboe, and 334(6) mmboe respectively, increases of 45%, 36% and 32% from year-end 2017. The GLJ 2018 Resources Report also indicates risked low, best, and high estimates for contingent resources in the Development Unclarified category of 11(6) mmboe, 37(6) mmboe, and 53(6) mmboe respectively, increases of 47%, 13% and 15% from year-end 2017. Over 86% of our risked contingent resources reside in the Development Pending category. Prospective resources were assessed at risked low, best and high estimates of 55(6) mmboe, 161(6) mmboe, and 284(6) mmboe respectively, increases of 7%, 5% and 9% from year-end 2017. Our contingent and prospective resource bases remain a source of reserveadditions, with 17 mmboe of contingent resources converted to 2P reserves during 2018.(6)
  • Vermilion was named to the CDP Climate Leadership Level (-A) for the second consecutive year in 2018. We were the only Canadian oil and gas company and one of only two North American oil and gas companies to receive this designation, ranking Vermilion in the top 5% of oil and gas companies globally. Vermilion ranked second within the oil and gas sector, and was among the top quartile of all companies in the S&P/TSX Composite Index in the annual Globe and Mail Board Games evaluation for 2018. We were also a finalist for the Finance and Sustainability Initiative's award for Best Sustainability Report in the Non-Renewable Resources - Oil and Gas category for our 2017 Sustainability Report, an award which we won last year for our 2016 Sustainability Report.

(1)  Non-GAAP Financial Measure.  Please see the "Non-GAAP Financial Measures" section of the accompanying Management's Discussion and Analysis. 
   
(2)  B15ST1 well tested oil at an average rate of 8,769 bbls/d and zero barrels of water per day ("bwpd") over a 48-hour period at a flowing wellhead pressure of 900 kpa (130 psi) on a 100% open choke (130 mm or 5.1 inch diameter) with applied gas-lift of 22,000 m3/d (775 mcf/d).  The well was estimated to be flowing with a 30% drawdown of reservoir pressure. 
   
  B16ST2 well tested oil at an average rate of 7,600 bbls/d and 770 bwpd over a 36-hour period at a flowing wellhead pressure of 900 kpa (130 psi) on a 100% open choke (130 mm or 5.1 inch diameter) with applied gas-lift of 45,000 m3/d (1,590 mcf/d).  The well was estimated to be flowing with a 15% drawdown of reservoir pressure. 
   
(3)  Estimated proved and proved plus probable reserves as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") in a report dated February 7, 2019 with an effective date of December 31, 2018 (the "2018 GLJ Reserves Report"). 
   
(4)  F&D (finding and development) and FD&A (finding, development and acquisition) costs are used as a measure ofcapital efficiency and are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted FDC (future development capital), by the change in the reserves, incorporating revisions and production, for the same period. 
   
(5)  Operating Recycle Ratio is a measure of capital efficiency calculated by dividing the Operating Netback by the cost of adding reserves (F&D cost).  Operating Netback is calculated as sales less royalties, operating expense, transportation costs, PRRT and realized hedging gains and losses presented on a per unit basis. 
   
(6)  Vermilion retained GLJ to conduct an independent resource evaluation dated February 7, 2019 to assess contingent and prospective resources across all of the Company's key operating regions with an effective date of December 31, 2018 (the "GLJ 2018 Resources Report").  The aggregate associated chance of development for each of the low, best and high estimate for contingent resources in the Development Pending category are 82%, 81% and 81%, respectively.  The aggregate associated chance of commerciality for each of the low, best and high estimate for prospective resources in the Prospect category are 24%, 23% and 24%, respectively.  There is uncertainty that it will be commercially viable to produce any portion of the resources.  Project maturity subclass development pending is defined as contingent resources where resolution of the final conditions for development is being actively pursued (high chance of development.  Project maturity subclass development unclarified is defined as contingent resources when the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties.  Prospective resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from unknown accumulations by application of future development projects.  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.  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.  Please refer to Vermilion's 2018 Annual Information Form for further information on Vermilion's contingent resources and prospectus resources. 
($M except as indicated)  Q4 2018    Q3 2018    Q4 2017      2018    2017 
Financial                     
Petroleum and natural gas sales  456,939    508,411    317,341      1,678,117    1,098,838 
Fund flows from operations  222,342    260,705    181,253      838,652    602,565 
Fund flows from operations ($/basic share) (1)  1.46    1.71    1.49      5.96   
Fund flows from operations ($/diluted share) (1)  1.44    1.69    1.47      5.89    4.92 
Net earnings (loss)  323,373    (15,099)    8,645      271,650    62,258 
Net earnings (loss) ($/basic share)  2.12    (0.1)    0.07      1.93    0.52 
Capital expenditures  163,580    146,185    74,303      518,214    320,449 
Acquisitions  2,689    198,173    3,048      1,759,425    27,637 
Asset retirement obligations settled  6,562    2,986    3,216      15,765    9,334 
Cash dividends ($/share)  0.690    0.690    0.645      2.715    2.580 
Dividends declared  105,310    105,192    78,653      388,111    311,397 
% of fund flows from operations    47%      40%      43%        46%      52% 
Net dividends (1)  100,195    100,872    56,836      339,060    200,904 
% of fund flows from operations    45%      39%      31%        40%      33% 
Payout (1)  270,337    250,043    134,355      873,039    530,687 
% of fund flows from operations    122%      96%      74%        104%      88% 
Net debt  1,929,529    2,034,086    1,371,790      1,929,529    1,371,790 
Ratio of net debt to annualized fund flows from operations  2.17    1.95    1.89      2.30    2.28 
Operational 
Production                     
Crude oil and condensate (bbls/d)  47,678    47,152    27,830      39,182    27,721 
NGLs (bbls/d)  7,815    6,839    5,279      6,366    4,194 
Natural gas (mmcf/d)  276.77    253.38    238.27      250.33    216.64 
Total (boe/d)  101,621    96,222    72,821      87,270    68,021 
Average realized prices                     
Crude oil and condensate ($/bbl)  66.19    85.84    74.12      79.16    67.00 
NGLs ($/bbl)  25.69    27.97    29.28      26.33    25.00 
Natural gas ($/mcf)  5.83    5.35    5.23      5.45    4.91 
Production mix (% ofproduction)                     
% priced with reference to WTI    37%      37%      21%        32%      20% 
% priced with reference to Dated Brent    18%      18%      24%        20%      26% 
% priced with reference to AECO    26%      26%      25%        26%      25% 
% priced with reference to TTF and NBP    19%      19%      30%        22%      29% 
Netbacks ($/boe)                     
Operating netback (1)  27.58    34.85    30.77      31.59    29.24 
Fund flows from operations netback  23.79    29.69    27.13      26.47    24.34 
Operating expenses  12.04    11.13    9.76      11.26    9.79 
Average reference prices                     
WTI (US $/bbl)  58.81    69.50    55.40      64.77    50.95 
Edmonton Sweet index (US $/bbl)  32.51    62.68    54.26      53.65    48.49 
Saskatchewan LSB index (US $/bbl)  44.03    63.35    54.04      56.46    47.85 
Dated Brent (US $/bbl)  67.76    75.27    61.39      71.04    54.27 
AECO ($/mcf)  1.56    1.19    1.69      1.50    2.16 
NBP ($/mcf)  11.03    10.95    8.70      10.35    7.49 
TTF ($/mcf)  10.91    10.92    8.36      10.23    7.43 
Average foreign currency exchange rates                     
CDN $/US $  1.32    1.31    1.27      1.30    1.30 
CDN $/Euro  1.51    1.52    1.50      1.53    1.46 
Share information ('000s) 
Shares outstanding - basic  152,704    152,497    122,119      152,704    122,119 
Shares outstanding - diluted (1)  156,173    155,747    125,140      156,173    125,140 
Weighted average shares outstanding - basic  152,588    152,432    121,858      140,619    120,582 
Weighted average shares outstanding - diluted (1)  153,880    153,839    123,450      142,335    122,408 

Message to Shareholders

In 2018, we drilled a total of 148.9 net wells and completed four acquisitions within our existing core areas, including the acquisition of Spartan Energy during Q2 2018, making this our most active year ever in terms of both organic and M&A activity.  As a result, we delivered record annual production of 87,270 boe/d, representing a year-over-year increase of 28%, or 10% on a per share basis.  Similarly, we increased our proved plus probable reserves by 63% to 488.1 mmboe(3), reflecting a year-over-year increase of 31% on a per share basis.

Our 2018 acquisitions added high netback, low decline and free cash flow(1)generating producing assets while also significantly expanding our future project inventory.  We are very disciplined in our M&A approach and apply a rigorous strategic framework, comprehensive technical evaluation methodology, and consistent decision criteria for any assets that we consider in our three operating regions.  Prior to 2018, we had been less active in M&A in North America due to the overly competitive nature of the North American market and consequent lower M&A returns as compared to Europe.  However, market conditions became more favourable under our criteria in North America in 2018, and we were able to opportunistically conclude the Spartan acquisition, a Saskatchewan/Manitoba waterflood purchase, a Powder River Basin stacked zone land and productionacquisition, and the consolidation of additional Corrib interest.  These important acquisitions enhanced our margins, reduced risk in our operating and financial profiles, expanded our development project inventory, increased our operating control, and diversified our asset base away from Alberta, with its particularly-challenged product pricing.  As a result of our organic and acquisition activities, we generated a ROCE of 9% in 2018, compared to our five-year average ROCE of 4%.

We achieved a significant operational milestone in Q4 2018 as our production exceeded 100,000 boe/d for the first time in our history.  Q4 2018 production increased 6% from the prior quarter to an average of 101,621 boe/d, primarily as a result of organic activities which were aided by a full quarter of the Powder River Basin acquisition and a minor contribution from our increased ownership in Corrib.  Looking forward, we are pleased with the continued expansion of project inventory arising from our acquisition of Spartan.  As we noted at our Investor Day in November 2018, we have increased our internally-estimated drilling inventory from the Spartan assets by approximately 50% to over 1,500 locations.  At our Investor Day, we also related that we have internally-estimated the potential for approximately 60 mmbbls of net waterflood recovery potential on the Spartan assets, which is a project class we did not count in our original evaluation of the Spartan deal.  Our year-end reserve and resources reports(6) recognizes 11.8 mmboe of 2P reserves and 30.0 mmboe of best-estimate contingent resources, respectively, for the new waterflood projects that came with Spartan.

Our international diversification provided a significant strategic advantage to Vermilion in Q4 2018.  Oil prices weakened during Q4 2018, especially Canadian benchmarks, as differentials for both heavy and light oil widened substantially due to a combination of factors which included above average refinery turnaround activity in PADD 2 and resulting high storage levels in western Canada.  While Vermilion's Canadian oil production was affected by these wider differentials, it was impacted to a lesser degree than Alberta light and heavy oil, as our Alberta condensate and Saskatchewanlight oil displayed relative pricing advantages over the Alberta black oil products.  This is most evident when comparing the Saskatchewan LSB index price versus the Edmonton Sweet (MSW) index price.  During Q4 2018, LSB traded at an US$11.52/bbl premium over MSW, compared to a US$0.22/bbl discount in Q4 2017.  Approximately 41% of our total 2019 oil production is indexed to LSB while only 8% is indexed to MSW.  In additional contrast, Brent oil traded at nearly a US$9/bbl premium over WTI and European natural gas traded at an approximate $9.40/mcf premium over AECO during Q4 2018.  Approximately 36% of our total 2019 oil production is price referenced to Brent while roughly 45% of our total 2019 natural gas production is price referenced to European gas benchmarks.

Despite the volatile commodity prices, we delivered strong financial results in Q4 2018 with FFO of $222 million ($1.46/basic share(1)) and net earnings of $323 million ($2.12/basic share).  Realized  hedging losses were $28 millionin Q4 2018.  We estimate that cash dividends will constitute approximately $400 million in 2019.  Our capital budget of $530 million for 2019 is designed to deliver a production range of 101,000 to 106,000 boe/d, resulting in year-over-year production per share growth of 8% at the mid-point of guidance.  At current differentials and using the current commodity strip for Brent, WTI and European natural gas, we estimate that we will be more than self-funded for our dividends and capital program for 2019, with excess cash generation earmarked for further debt reduction.  As we have noted in the past, we have significant flexibility in our capital program and could reduce capital spending if commodity prices weaken substantially.  In that event, we would reduce our growth capital first in order to protect the balance sheet and the dividend.  We believe this level of organic growth combined with a dividend yield over 8% represents an attractive option for investors.

Q4 2018 Operations Review

Europe

In France, Q4 2018 production averaged 11,454 boe/d, which was up slightly from the prior quarter.  Production from our 2018 three (3.0 net) well drilling program in the Champotran field continued to outperform expectations, contributing 725 boe/d of production in the fourth quarter.

In the Netherlands, Q4 2018 production averaged 8,749 boe/d, an increase of 17% from the prior quarter.  The increase is primarily due to the benefit of a full quarter contribution from the Eesveen-02 well (60% working interest), which we brought on production late in the third quarter at a restricted rate of 10 mmcf/d net.

In Ireland, production from the Corrib Project averaged 52 mmcf/d (8,672 boe/d) in Q4 2018, an increase of 1% from the prior quarter.  On November 30, we assumed operatorship of the Corrib Project and completed the transfer of SEPIL along with an incremental 1.5% working interest in the Corrib Project to Vermilion from Nephin Energy Holdings Limited, a wholly owned subsidiary of CPPIB.  Cash consideration at closing was $9 million, which was more than offset by the assumption of $15 million in positive net working capital as a result of the acquisition.  Integration of the staff, processes and systems have been completed, and we welcome the addition of former-Shell employees to Vermilion.  Most importantly, Vermilion now has operating control of the Corrib Project, bringing the proportion of our production that we operate to approximately 90% on a worldwide basis.

In Germany, production in Q4 2018 averaged 3,736 boe/d, an increase of 7% from the prior quarter, primarily due to the restoration of gas processing at a non-operated gas processing facility during the third quarter.  During the fourth quarter, we completed site construction for the Burgmoor Z5 well (46% working interest) and have secured all drilling permits necessary to proceed.  Drilling is expected to commence by the end of Q1 2019.

In Central and Eastern Europe ("CEE"), production averaged 477 boe/d in Q4 2018, an increase of 145% over the prior quarter due to production from the well drilled earlier in 2018 on the South Battonya concession in Hungary.  In Croatia, we acquired an additional 150 linear kilometres of 2D seismic data in our DR-04 license to expand on the first phase of 2D seismic data we acquired in Q2 2018.  We continued to progress the permitting activities associated with our 10.0 (7.0 net) well program for 2019 in the CEE business unit, and have received all the permits for our second well in Hungary.  In Slovakia, we were granted the Topolcany license which is adjacent to our existing Trnava license.  The Topolcany license is owned 50/50 with our partner in Slovakia (NAFTA) and adds 301,000 acres (150,500 net) to our portfolio.

North America

In Canada, production averaged a record 60,814 boe/d in Q4 2018, representing an increase of 6% from the previous quarter.  The increase was primarily due to strong operating performance and new well completions in both Saskatchewan and Alberta.  The strong production results were partially restrained by a system-wide power outage in Saskatchewan in December, which reduced production volumes by approximately 500 boe/d for the quarter.  We drilled or participated in 72 (44.1 net) wells and brought on production 86 (56.6 net) wells in the fourth quarter.  We executed a five rig program in Saskatchewan, drilling or participating in 61 (34.8 net) wells across our combined Spartan and legacy land bases.  In Alberta, we drilled nine (7.3 net) Mannville wells and two (2.0 net) long-reach Cardium wells.

In the United States, Q4 2018 production averaged 3,545 boe/d, an increase of 19% from the prior quarter, due to a full quarter of productionassociated with the Powder River Basin acquisition completed in Q3.  We drilled and completed our first (1.0 net) well on the newly acquired Hilight assets late in the fourth quarter.  Production from this well commenced in mid-December.  We elected to use a rod pump artificial lift system on this well, which offers lower pump displacement than previously-utilized electrical submersible pumps on new wells at Hilight, but reduces sand flowback and pump failure frequency.  As a result, the current rate is 290 boe/d (86% oil) and is increasing as the well cleans up.

Australia

In Australia, production averaged 4,174 bbl/d in Q4 2018, down 11% from the previous quarter primarily due to a planned shutdown for maintenance and other downtime which was required to allow drilling of two new wells.  We began drilling the two wells in early November 2018 and completed the wells in late January 2019.  These were the most technically challenging wells ever executed at Vermilion.  Both wells were drilled at vertical depths of approximately 650 meters, but with measured depths of 4,960 meters and 3,697 meters for the B15 and B16 wells respectively, making these some of the most extreme extended reach wells at shallow depth in the world.  The B15 well also featured an approximately 180 degree turn to allow drainage of oil trapped against the updip bounding fault for the Wandoo field.  We achieved our reservoir and mechanical objectives on both wells, and the wells were successfully tested in February 2019.  The B15 well tested at an oil rate of 8,800 bbl/d over a 48-hour period and the B16 well tested at an oil rate of 7,600 bbl/d over a 36-hour period(2).  We plan to intermittently produce the new wells at restricted rates to maximize long-term value.  The total cost of the program was $75 million, which is approximately $10 million over budget due to slower-than-expected drilling in the vertical sections of the wells, lost circulation in part of the B15 horizontal section along the bounding fault, and a cyclone which required down-manning of the drilling rig for approximately a week.

Commodity Hedging

Vermilion hedges to manage commodity price exposures and increase the stability of cash flows, providing additional certainty with regard to the execution of our dividend and capital programs.  In aggregate, we currently have 34% of our expected net-of-royalty production hedged for Q1 2019.  Over half of the Q1 2019 corporate hedge position consists of two-way collars and three-way structures, which allow participation in price increases, up to contract ceilings.

We have currently hedged 67% of anticipated European natural gas volumes for Q1 2019.  In view of the compelling longer-term forward market for European natural gas, we have also hedged 66% and 38% of our anticipated full-year 2019 and 2020 volumes at prices which will provide for strong project economics and free cash flows.  As of February 26, 2019, 29% of our Q1 2019, and 21% of our full year 2019 oil production is hedged.  We will continue to add to our hedge positions in all products as suitable opportunities arise.  For Q1 2019, 30% of our North American natural gas production is priced away from AECO, by virtue of diversification hedges to sell at the SoCal Border, Chicago and Henry Hub for a portion of our Alberta gas production, and because 14% of our production comes from Saskatchewan and Wyoming.

Environmental, Social and Governance ("ESG")

Vermilion was named to the CDP Climate Leadership Level (A-) for the second consecutive year in 2018.  We were the only Canadian oil and gas company and one of only two North American oil and gas companies to receive this designation, ranking Vermilion in the top 5% of oil and gas companies globally.  We are proud of this achievement and believe this ranking is a reflection of our responsible operating practices and positive track record of reducing emissions on our oil and gas assets.  We will continue to seek new and innovative ways to improve our overall operating performance while reducing the emission intensity of our assets.

In February 2019, we were a finalist for the Finance and Sustainability Initiative's ("FSI") award for Best Sustainability Report in the Non-Renewable Resources - Oil and Gas category for our 2017 Sustainability Report.  Last year, we received this award for our 2016 Sustainability Report.  Based in Montreal, the FSI is a non-profit organization dedicated to promoting sustainable finance and, more specifically, responsible investment to financial institutions, companies, and universities.  Sustainability reports were graded on a number of criteria, including transparency and balance, reliability and completeness, and the use of ESG materiality.  We firmly believe in the importance of measuring and understanding our current environmental impact.  Furthermore, we believe the integration of sustainability principles into our business strategy increases shareholder returns and reduces long-term risks to our business model.  Our recently published 2018 Sustainability Report is available now on our corporate website at .

Vermilion ranked second within the oil and gas sector, and among the top quartile of companies in the S&P/TSX Composite Index in the annual Globe and Mail Board Games evaluation for 2018.  The evaluation uses a rigorous set of governance criteria that goes beyond minimum mandatory rules imposed by regulators and validates our commitment to, and execution of, best governance practices.

2018 Reserves and Resources

In 2018 we significantly increased our reserves and resources through a combination of development and acquisition activities.  Based on the 2018 GLJ Reserves Report, our 2P reserves increased 63% from year-end 2017 to 488.1(3) mmboe, while our 1P reserves increased 69% from year-end 2017 to 298.2(3) mmboe in 2018.  PDP reserves increased 55% from year-end 2017 to 192.1(3) mmboe.  Our PDP reserves represent 64% of our 1P reserves.

The following table provides a summary of company interest reserves by reserve category and country on an oil equivalent basis.  Please refer to Vermilion's 2018 Annual Information Form for detailed by product type information.

             
BOE (Mboe)  Proved Developed
Producing 
Proved Developed
Non-Producing 
Proved Undeveloped  Proved  Probable  Proved Plus
Probable 
Australia  8,048  1,620  —  9,668  4,812  14,480 
Canada  103,992  9,496  68,451  181,939  102,897  284,836 
France  37,596  441  5,429  43,466  20,452  63,918 
Germany  9,879  2,043  1,069  12,991  12,744  25,735 
Hungary  131  —  —  131  59  191 
Ireland  13,093  —  —  13,093  7,482  20,575 
Netherlands  7,629  3,469  705  11,802  10,395  22,196 
United States  11,705  —  13,442  25,147  31,068  56,214 
Vermilion  192,073  17,069  89,096  298,237  189,909  488,145 

Through development activities, we replaced 187% of 2P reserves, 157% of 1P reserves and 130% of PDP reserves, respectively.  Including acquisitions, we replaced 695% of 2P reserves, 481% of 1P reserves and 314% of PDP reserves, respectively.

Our Operating Recycle Ratio(5) (including FDC) at the 2P level increased to 4.1x in 2018, compared to 2.8x in 2017, as a result of higher operating netbacks and a significant decrease to our F&D costs (including FDC).  Organic F&D costs (including FDC) decreased 26% in 2018 to $7.79/boe, compared to $10.57/boe in 2017.  These metrics remain strong relative to historical industry averages, and reflect the significant improvement in our capital efficiencies over the last several years.

The following table summarizes the finding and development costs and associated operating recycle ratios by reserve category for the year ended December 31, 2018:

     
  2018  3-Year Average 
  PDP  1P  2P  PDP  1P  2P 
Finding and Development Costs, including FDC (F&D)(3)($/boe)  $15.65  $13.49  $7.79  $11.94  $10.96  $7.85 
Finding, Development and Acquisition Costs, including FDC (FD&A)(3) ($/boe)  $23.92  $19.95  $14.99  $18.71  $16.87  $13.16 
             
F&D Operating Recycle Ratio(4) *  2.0  2.3  4.1  2.5  2.7  3.8 
FD&A Operating Recycle Ratio(4) *  1.3  1.6  2.1  1.6  1.8  2.2 

In addition to increasing our reserve base, we pursued various initiatives to expand our resource base to support our longer-term growth profile.  According to the 2018 GLJ Resources Report, risked low, best, and high estimates for our contingent resources in the Development Pending category we evaluated as 156(6) mmboe, 240(6) mmboe, and 334(6) mmboe, respectively.  The 2018 GLJ Resources Report also indicates risked low, best, and high estimates for contingent resources in the Development Unclarified category of 11(6) mmboe, 37(6) mmboe, and 53(6) mmboe, respectively.  Over 86% of our risked contingent resources reside in the Development Pending category.  Prospective resources were assessed at risked low, best and high estimates of 55(6) mmboe, 161(6) mmboe, and 284(6) mmboe, respectively.  Our contingent and prospective resource bases remain a source of reserve additions, with 17 mmboe of contingent resources converted to 2P reserves during 2018.(6)

The following table provides a reconciliation of changes in reserves by reserve category and country.  Please refer to Vermilion's 2018 Annual Information Form for detailed by product type information.

                   
1P (Mboe)  Australia  Canada  France  Germany  Hungary  Ireland  Netherlands  United 
States 
Vermilion 
December 31, 2017  10,915  81,388  42,094  12,640  —  13,634  10,347  5,613  176,631 
Discoveries  —  —  —  —  193  —  —  —  193 
Extensions & Improved Recovery  —  31,289  2,249  673  —  —  256  1,359  35,826 
Technical Revisions  393  6,977  3,244  979  —  1,575  206  298  13,671 
Acquisitions  —  81,328  —  —  —  1,241  3,838  18,604  105,012 
Dispositions  —  (134)  —  —  —  —  —  —  (134) 
Economic Factors  —  (1,162)  40  17  —  —  (4)  (1)  (1,110) 
Production  (1,640)  (17,750)  (4,160)  (1,319)  (62)  (3,356)  (2,839)  (727)  (31,853) 
December 31, 2018  9,668  181,938  43,467  12,990  131  13,094  11,804  25,146  298,236 
                   
                   
2P (Mboe)  Australia  Canada  France  Germany  Hungary  Ireland  Netherlands  United 
States 
Vermilion 
December 31, 2017  15,565  139,294  64,189  24,496  —  22,199  17,863  14,969  298,575 
Discoveries  —  —  —  —  252  —  —  —  252 
Extensions & Improved Recovery  —  37,024  1,934  2,158  —  —  2,201  6,265  49,581 
Technical Revisions  555  5,573  2,713  393  —  (253)  16  1,880  10,875 
Acquisitions  —  121,537  —  —  —  1,986  4,973  33,828  162,324 
Dispositions  —  (227)  —  —  —  —  —  —  (227) 
Economic Factors  —  (616)  (758)  —  —  (14)  (2)  (1,383) 
Production  (1,640)  (17,750)  (4,160)  (1,319)  (62)  (3,356)  (2,839)  (727)  (31,853) 
December 31, 2018  14,480  284,835  63,918  25,733  190  20,576  22,200  56,213  488,145 

Additional information about our 2018 GLJ Reserves Report and GLJ 2018 Resources Report can be found in our 2018 Annual Information Form on our website at  and on SEDAR at  .

Source: EvaluateEnergy® ©2019 EvaluateEnergy Ltd