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

CALGARY, Feb. 28, 2019 /PRNewswire/ - 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 www.sedar.com, on EDGAR at www.sec.gov/edgar.shtml, and on Vermilion's website at www.vermilionenergy.com.

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 guidance range.
  • 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 production volumes 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 million in 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:
  • 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 reserve additions, 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 of capital 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


5

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 (% of production)











% 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

(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

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 production acquisition, 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 Saskatchewan light 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 million in 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 production associated 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 http://sustainability.vermilionenergy.com.

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)

5

(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 www.vermilionenergy.com and on SEDAR at www.sedar.com.

(signed "Anthony Marino")

Anthony Marino
President & Chief Executive Officer
February 27, 2019

(1)

Non-GAAP Financial Measure.  Please see the "Non-GAAP Financial Measures" section of 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 attributable to the assets 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 of capital efficiency and are calculated by dividing the applicable capital expenditures for the period, including the change in undiscounted future development capital ("FDC"), 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.

 

Guidance

On October 30, 2017, we released our 2018 capital expenditure guidance of $315 million and associated production guidance of between 74,500 to 76,500 boe/d.  On January 15, 2018, we increased our capital expenditure guidance to $325 million and production guidance to between 75,000 to 77,500 boe/d to reflect the post-closing impact of the acquisition of a private southeast Saskatchewan and southwest Manitoba light oil producer.  On April 16, 2018, we increased our capital expenditure guidance to $430 million and production guidance to between 86,000 to 90,000 boe/d to reflect the post-closing impact of the acquisition of Spartan Energy Corp.  On July 30, 2018, we increased our capital expenditure guidance to $500 million to reflect the acceleration of our Australia drilling campaign into Q4 2018, and to a lesser extent to account for the impact of foreign exchange fluctuations on our Canadian dollar capital levels.  On October 25, 2018, we increased our capital expenditure guidance to $510 million to reflect additional capital activity associated with the assets acquired in the Powder River Basin in August of 2018.  Actual 2018 capital spending of $518 million was within 2% of our guidance and 2018 average production of 87,270 boe/d was within 1% of the mid-point of our guidance range.

On October 25, 2018, we released our 2019 capital budget and related guidance.  The 2019 total budget and production guidance remain unchanged, although we have deferred some activity to later in the year and reallocated capital between business units, the breakdown of which can be found in our corporate presentation located on our website.

The following table summarizes our guidance:








Date


Capital Expenditures ($MM)


Production (boe/d)

2018 Guidance






2018 Guidance

October 30, 2017


315


74,500 to 76,500

2018 Guidance

January 15, 2018


325


75,000 to 77,500

2018 Guidance

April 16, 2018


430


86,000 to 90,000

2018 Guidance

July 30, 2018


500


86,000 to 90,000

2018 Guidance

October 25, 2018


510


86,000 to 90,000

2018 Actual Results



518


87,270

2019 Guidance






2019 Guidance

October 25, 2018


530


101,000 to 106,000

 

Conference Call and Webcast Details

Vermilion will discuss these results in a conference call and webcast presentation on Thursday, February 28, 2019 at 9:00 AM MST (11:00 AM EST). To participate, call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area).  A recording of the conference call will be available for replay by calling 1-855-859-2056 and using the conference ID 7955826 from February 28, 2019 at 12:00 PM MST to March 14, 2019 at 9:59 PM MST.

You may also access the webcast at  https://event.on24.com/wcc/r/1924756/BAC3FC6A211842CA79D33D2B88BCFBA6. The webcast link, along with conference call slides, can be found on Vermilion's website at http://www.vermilionenergy.com/invest-with-us/events--presentations.cfm under Upcoming Events prior to the conference call.

About Vermilion

Vermilion is an international energy producer that seeks to create value through the acquisition, exploration, development and optimization of producing properties in North America, Europe and Australia.  Our business model emphasizes organic production growth augmented with value-adding acquisitions, along with providing reliable and increasing dividends to investors.  Vermilion is targeting growth in production primarily through the exploitation of light oil and liquids-rich natural gas conventional resource plays in Canada and the United States, the exploration and development of high impact natural gas opportunities in the Netherlands and Germany, and through oil drilling and workover programs in France and Australia.  Vermilion holds a 20% working interest in the Corrib gas field in Ireland.  Vermilion pays a monthly dividend of Canadian $0.23 per share, which provides a current yield of approximately 8.0%.

Vermilion's priorities are health and safety, the environment, and profitability, in that order.  Nothing is more important to us than the safety of the public and those who work with us, and the protection of our natural surroundings.  We have been recognized as a top decile performer amongst Canadian publicly listed companies in governance practices, as a Climate Leadership level (A-) performer by the CDP, and a Best Workplace in the Great Place to Work® Institute's annual rankings in Canada, the Netherlands and Germany.  In addition, Vermilion emphasizes strategic community investment in each of our operating areas.

Employees and directors hold approximately 5% of our fully diluted shares, are committed to consistently delivering superior rewards for all stakeholders, and have delivered over 20 years of market outperformance.  Vermilion trades on the Toronto Stock Exchange and the New York Stock Exchange under the symbol VET.

Disclaimer

Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation.  Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook.  Forward looking statements or information in this document may include, but are not limited to: capital expenditures and Vermilion's ability to fund such expenditures;  Vermilion's additional debt capacity providing it with additional working capital; the flexibility of Vermilion's capital program and operations; business strategies and objectives; operational and financial performance; estimated volumes of reserves and resources; petroleum and natural gas sales; future production levels and the timing thereof, including Vermilion's 2019 guidance, and rates of average annual production growth; the effect of changes in crude oil and natural gas prices, changes in exchange rates and significant declines in production or sales volumes due to unforeseen circumstances; the effect of possible changes in critical accounting estimates; statements regarding the growth and size of Vermilion's future project inventory, and the wells expected to be drilled in 2019; exploration and development plans and the timing thereof; Vermilion's ability to reduce its debt, including its ability to redeem senior unsecured notes prior to maturity; statements regarding Vermilion's hedging program, its plans to add to its hedging positions, and the anticipated impact of Vermilion's hedging program on project economics and free cash flows; the potential financial impact of climate-related risks; 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 and Vermilion's expectations regarding future taxes and taxability; and the timing of regulatory proceedings and approvals.

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 crude oil and natural gas reserve and resource 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 and the Canadian Oil and Gas Evaluation Handbook.  Reserves estimates have been made assuming that development of each property in respect of which the estimate is made will occur, without regard to the likely availability of funding required for such development. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document.

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.

Cision

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