Advantage Announces 2017 Year-end Reserves & Operations Update

Source Press Release
Company Advantage Oil & Gas Ltd. 
Tags Strategy - Corporate, Guidance, Financial & Operating Data
Date February 12, 2019

Advantage Oil & Gas Ltd. ("Advantage" or the "Corporation") is pleased to report that the Corporation's 2017 Montney development program replaced 433% of annual production, generated low cost reserve additions in each reserve category and extended liquids rich reserve bookings beyond Glacier to our Valhallaland block.  Reserve additions at Glacier were led by new location bookings in the liquids rich Middle Montney, prolific natural gas well results in the Lower Montney and positive technical revisions resulting from better long term producing well performance.  At Valhalla, successful drilling results confirmed strong natural gas rates and high liquid yields in the Upper and Middle Montney formations. This resulted in Advantage's first bookings of undeveloped locations at Valhallawhich has further increased our significant liquids rich drilling inventory.    

Advantage achieved record fourth quarter production of 245 mmcfe/d (40,857 boe/d) and increased our annual production by 16% (14% per share) to a record 236 mmcfe/d (39,315 boe/d).  Advantage's annual cash flow increased 10% to $183 million, supported by a 50% increase in liquids revenue and the Corporation's proactive market diversification and hedging initiatives.  These initiatives resulted in a 16% exposure to AECO natural gas prices and an average realized natural gas price of $2.69/mcf as compared to an AECO daily price of $1.69/mcf in the fourth quarter.  Furthermore, these initiatives are expected to result in the Corporation's 2018 revenue exposure to AECO prices of 4% and 28% for the first quarter and calendar 2018, respectively.  The Corporation successfully reduced 2017 total cash costs to $0.88/mcfe including operating costs of $0.25/mcfe which helped contribute to a year-end total debt to cash flow ratio of 1.2.

Advantage's 2017 operating activities included liquids rich drilling successes, the acquisition of 37 sections of additional liquids rich Montney lands and the commencement of a major expansion of our 100% owned Glacier gas plant which further enhances our operational flexibility. These achievements position Advantage to increase its focus on liquids development in 2018 and beyond with the ability to respond promptly and responsibly to market conditions.

Highlights of our year-end reserve additions are:

  • Replaced 433% and 455% of 2017 annual production on a 2P and 1P basis, respectively
  • Proved developed producing ("PDP") reserves increased by 27% (24% on a per share basis) at a finding and development ("F&D") cost of $1.32/mcfe ($7.92/boe) and a PDP recycle ratio of 1.6. The three year average PDP F&D cost is $1.30/mcfe ($7.80/boe)
  • Proved ("1P") reserves increased by 20% (17% on a per share basis) at a F&D cost of $0.98/mcfe ($5.88/boe) including the change in future development capital ("FDC")
  • Proved plus probable ("2P") reserve additions increased by 13% (11% on a per share basis) at a F&D cost of $0.84/mcfe ($5.01/boe) including the change in FDC. The 3 year average F&D cost is $0.52/mcfe ($3.11/boe)
  • 2P reserves increased 13% to 2.49 Tcfe (413.8 million boe) including natural gas liquids which increased by 35% to 31.8 million barrels
  • Recycle ratios of 2.5, 2.1 and 1.6 were achieved for 2P, 1P and PDP reserve additions, respectively
  • Strong longer term well production performance has reduced our corporate base production decline estimate to approximately 26% per annum for 2018
  • Valhalla liquids rich gas reserve booking increased to 18 mmboe resulting from successful wells

Highlights of our operating and financial results in 2017 are:

  • Increased fourth quarter 2017 production by 11% to a record 245 mmcfe/d (40,857 boe/d) compared to the same period in 2016
  • Increased annual production by 16% (14% per share) to a record 236 mmcfe/d (39,315 boe/d) in a safe and environmentally responsible manner despite significant third party sales gas pipeline take-away restrictions which impacted the majority of western Canadian producers through 2017
  • Reduced 2017 total cash costs by 8% to $0.88/mcfe ($5.28/boe), outperforming original guidance of $0.96/mcfe (cash costs include transportation)
  • Increased annual cash flow by 10% (8% on a per share basis) to $183 million including $28 millon of hedging gains
  • Achieved a 3 year all-in capital efficiency of $15,333/boe/d. Advantage's 2017 all-in annual capital efficiency of $17,000/boe/d includes $80 million for our Glacier gas plant expansion and $7 million for land acquisitions and $11,100/boe/d when these expenditures are excluded
  • Preserved a strong balance sheet with a 2017 year-end total debt to trailing cash flow ratio of 1.2 times
  • Continued market diversification such that only 28% of our estimated 2018 revenue is exposed to AECO prices
  • Opportunistically acquired 37 sections of complementary Montney acreage and successfully extended liquids rich delineation drilling within and outside Glacier

2017 Reserves Related Commentary and Analysis

Sproule Associates Ltd. ("Sproule") was engaged as an independent qualified reserve evaluator to evaluate Advantage's year-end reserves as of December 31, 2017 ("Sproule 2017 reserve report") in accordance with National Instrument 51-101 ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook").  Reserves are stated on a gross (before royalties) working interest basis unless otherwise indicated.  Additional details are provided in the accompanying tables to this release and additional reserve information as required under NI 51-101 will be included in our Annual Information Form which will be filed on SEDAR on or before March 31, 2018.  All references to 2017 operational and financial results are estimates only and have not been reviewed or audited by our independent auditor.  Advantage is expected to release its fourth quarter and year-end results after markets close onMarch 5, 2018.

Advantage's 2017 reserve additions include contributions from Glacier and Valhalla. The Corporation's Valhalla land block is located approximately 16 kilometers east of Glacier and is pipeline connected to our 100% owned Glacier gas plant.  In 2017, a 4 well Montney pad was drilled as a follow-up to 3 wells that were placed on production in 2016.  This new 4 well pad demonstrated a combined initial production test rate of 6,410 boe/d comprised of 32 mmcf/d gas and 1,075 bbls/d of liquids (based on Glacier gas plant shallow cut extraction process).  Individual well C3+ liquid yields of 20 bbls/mmcf to in-excess of 100 bbls/mmcf with free condensate and/or oil compositions of up to 90% were recovered.  These wells will be placed on restricted production through the first half of 2018 due to the need to install additional liquids handling facilities at Valhalla. All wells are expected to be produced unrestricted when the new Valhallacompressor and liquids handling equipment is installed by the fourth quarter of 2018.

At Glacier, our activity was focused in the Lower and Middle Montney during 2017 and continued to demonstrate technology improvements in well operations and results. Advantage's eight well pad that was put on production in early 2017 included five Lower Montney wells which produced at rates of approximately 8 mmcf/d after more than a year of production.  In the Middle Montney, several wells were drilled in previously undrilled areas of Glacier and proved up additional liquids rich reserves and demonstrated production rates above type curve expectations.    

At our Wembley and Progress land blocks, one well at Progress and one well at Wembley have been fracture stimulated and flow results are expected to be available once production testing is completed.

Additional comments pertaining to each of the reserve categories are included below:

PDP reserves increased 27% due to the recognition of 27 new Glacier wells that were brought on production through 2017 and higher reserves assignments on historical producing wells due to stronger performance than previously forecast.

1P reserves increased 20% resulting from technical revisions which accounted for 45% of the 1P reserve additions.  The remaining reserve additions resulted from the conversion of probable locations to the proved reserves category and the booking of new proven undeveloped locations. 

2P reserves increased 13% through the addition of 56 new wells and locations (40 Glacier and 16 Valhalla).   Of the 56 new wells and locations, 30 were proved undeveloped locations.  A total of 337 undeveloped locations were booked in the 2017 reserve report.  Management estimates in-excess of 1,200 total Montney locations remains undrilled at Glacier and Valhalla.

2P FDC increased by $62 million to $1.66 billion as the reduction in facilities capital expenditures in the reserve report were offset by the cost of booking additional future well locations.

The strong recycle ratios reinforces the benefit of Advantage's industry leading low cost structure which continues to support strong netbacks and profit margins. These recycle ratios included the Corporation's hedges and were achieved in the environment where the AECO daily natural gas price averaged Cdn $2.15/mcf in 2017. 

Since Advantage's Montney development program began in 2008, 2P reserves have grown at an average compound annual growth rate ("CAGR") of 13% per year to 2.49 Tcfe (413.8 million boe) with a 2P and 1P reserve Net Present Value of $2.55 billion and $1.77 billion, respectively as at December 31, 2017 (10% discount factor on a pre-tax basis).

The Sproule 2017 reserve report demonstrates the continued efficient conversion of identified natural gas and natural gas liquids resources into 2P reserves. The reserves by category and year over year changes compared to 2016 are indicated below:  

Reserve 
Category 
Conventional 
Natural Gas
Tcf 
NGLs
Million bbls 
Total Gas 
Equivalent
Tcfe 
% Change from 
2016 
PDP  0.46  4.48  0.48  27% 
1P  1.70  23.06  1.84  20% 
2P  2.29  31.77  2.48  13% 

The total number of 2P future well locations booked and the 2P estimated ultimate recoverable ("EUR") conventional natural gas volumes per well assigned by Sproule in the  Sproule 2017 reserve report are illustrated in the following table:

  Sproule
# of Gross Horizontal
Wells Booked 
Sproule
Average EUR/well
(bcf raw /well) 
  Developed  Undeveloped  Undeveloped 
Upper  115  138  5.9 
Middle  31  118  5.2 
Lower  51  81  6.5 
Total  197  337   

Advantage's 1P reserve life index is 21 years and its 2P reserve life index is 28 years based on the Corporation's average fourth quarter 2017 production rate of approximately 245 mmcfe/d.

2017 Operating Results Summary
(References to 2017 operational and financial results are estimates only and have not been reviewed or audited by our independent auditor.  Advantage is expected to release its fourth quarter and year-end results after markets close on March 5, 2018)

Key operational results during the fourth quarter of 2017 and for calendar 2017 are indicated below:

  Q4 2017E  2017E 
Production (mmcfe/d)  245  236 
Royalties %  2.9%  2.8% 
Operating Cost ($/mcfe)  $0.26  $0.25 
Transportation Cost ($/mcfe)  $0.50  $0.40 
Operating netback ($/mcfe)   $2.08  $2.29 
Capital Expenditures ($ millions)  $74  $249 
Total Debt including working 
capital ($ millions) 
$223  $223 

Capital expenditures in 2017 were $7 million higher than our guidance range due to our decision to add two incremental process equipment units as part of our plant expansion and the rig release of 4 additional wells as drillingtimes were faster than scheduled on our year-end well pad.  One of the process units added was  an electric power generator which will provide surplus electricity sales (2.4 MW) into the Alberta grid and the other process unit is a gas exchanger which will provide more flexibility and efficiency in the plant operation.

Looking Forward

The Sproule 2017 reserve report demonstrates another year of highly efficient reserve additions at Glacier reinforcing the exceptional quality of our Montney asset and the outstanding achievements of our team who accomplished this in a safe and environmentally responsible manner.  Advantage's disciplined approach has and continues to be critically important in advancing our Montney natural gas and liquids development such that attractive returns are generated over the long term for our shareholders.  We look forward to reporting on our progress through 2018.   

RESERVE SUMMARY TABLES

Company Gross (before royalties) Working Interest Reserves 
Summary as at December 31, 2017

  Light & Medium 
Oil (mbbl) 
Natural Gas Liquids (mbbl)  Conventional 
Natural Gas (mmcf) 
Total Oil Equivalent (mboe) 
Proved         
Developed Producing  4,482  455,763  80,454 
Developed Non-producing  1,018  45,049  8,526 
Undeveloped  17,557  1,197,147  217,082 
Total Proved  23,057  1,697,959  306,062 
Probable  8,711  594,258  107,757 
Total Proved + Probable  31,768  2,292,218  413,819 

(1)  Tables may not add due to rounding. 

Company Net Present Value of Future Net Revenue using Sproule price and cost forecasts (1)(2)(3)($000)

  Before Income Taxes Discounted at 
  0%  10%  15% 
Proved       
Developed Producing  1,291,370  835,646  705,904 
Developed Non-producing  172,031  91,582  75,218 
Undeveloped  3,110,192  842,153  464,582 
       
Total Proved  4,573,594  1,769,381  1,245,703 
       
Probable  2,297,267  780,609  543,675 
       
Total Proved + Probable  6,870,860  2,549,991  1,789,379 
         

(1)  Advantage's light and medium oil, conventional natural gas and natural gas liquid reserves were evaluated using Sproule's product price forecast effective December 31, 2017 prior to the provision for income taxes, interests, debt services charges and general and administrative expenses. It should not be assumed that the discounted future net revenue estimated by Sproule represents the fair market value of the reserves. 
(2)  Assumes that development of Glacier and Valhalla will occur, without regard to the likely availability to the Corporation of funding required for that development. 
(3)  Future Net Revenue incorporates Managements' estimates of required abandonment and reclamation costs, including expected timing such costs will be incurred, associated with all wells, facilities and infrastructure. No abandonment and reclamation costs have been excluded. 
(4)   Tables may not add due to rounding. 

Sproule Price Forecasts

The net present value of future net revenue at December 31, 2017 was based upon natural gas and natural gas liquids pricing assumptions prepared by Sproule effective December 31, 2017. These forecasts are adjusted for reserve quality, transportation charges and the provision of any applicable sales contracts. The price assumptions used over the next seven years are summarized in the table below:

Year  Alberta AECO-C Natural Gas ($Cdn/mmbtu)  Henry Hub Natural Gas ($US/mmbtu)  Edmonton Propane ($Cdn/bbl)  Edmonton Butane ($Cdn/bbl)  Edmonton Pentanes Plus ($Cdn/bbl)  Exchange Rate ($US/$Cdn) 
2018  2.85  3.25  26.06  48.73  67.72  0.79 
2019  3.11  3.50  32.84  55.49  75.61  0.82 
2020  3.65  4.00  35.41  57.65  78.82  0.85 
2021  3.80  4.08  37.85  60.12  82.35  0.85 
2022  3.95  4.16  39.29  61.32  84.07  0.85 
2023  4.05  4.24  40.25  62.55  85.82  0.85 
2024  4.15  4.33  41.23  63.80  87.61  0.85 
             

Company Gross (before royalties) Working Interest Reserves Reconciliation (1):

Proved  Light & 
Medium Oil (mbbl) 
Natural Gas Liquids (mbbl)  Conventional 
Natural Gas (mmcf) 
Total Oil Equivalent (mboe) 
         
Opening balance Dec. 31, 2016  8.4  15,524  1,437,149  255,057 
Extensions  1,274  30,677  6,387 
Infill Drilling  61  9,610  1,663 
Infill Future Offset  5,557  155,679  31,504 
Improved recovery 
Technical revisions  (7.8)  1,242  169,399  29,468 
Discoveries 
Acquisitions  4.5  14 
Royalty Changes  (166)  (20,901)  (3,650) 
Economic factors  (222)  (31) 
Production  (0.7)  (444)  (83,432)  (14,350) 
         
Closing balance at Dec. 31, 2017  4.4  23,057  1,697,959  306,062 
         
Proved Plus Probable  Light & 
Medium Oil (mbbl) 
Natural Gas Liquids (mbbl)  Conventional 
Natural Gas (mmcf) 
Total Oil Equivalent (mboe) 
         
Opening balance Dec. 31, 2016  11.1  23,529  2,055,398  366,106 
Extensions  1,988  51,520  10,574 
Infill Drilling  77  11,987  2,074 
Infill Future Offset  7,455  204,522  41,542 
Improved recovery 
Technical revisions  (10.5)  (949)  68,541  10,464 
Discoveries 
Acquisitions  5.7  17 
Royalty Changes  106  (15,929)  (2,549) 
Economic factors  (389)  (60) 
Production  (0.7)  (444)  (83,432)  (14,350) 
         
Closing balance at Dec. 31, 2017  5.6  31,768  2,292,218  413,819 

   
(1)  Technical revisions accounted for 45% of the total proved additions and 17% of the total proved plus probable additions. Percentage of each category calculated by dividing the technical revisions in the category by the total reserve additions in the same category before production. 
(2)  Tables may not add due to rounding. 

Company Finding & Development Costs ("F&D")

Company 2017 F&D Costs – Gross (before royalties) Working Interest Reserves including Future Development Capital(1)(2)(3)    

  Proved  Proved + Probable 
Capital expenditures ($000)  248,774  248,774 
Net change in Future Development Capital ($000)  135,279  62,202 
Total capital ($000)  384,053  310,976 
     
Total mboe, end of year  306,062  413,819 
Total mboe, beginning of year  255,057  366,106 
Production, mboe  14,350  14,350 
Reserve additions, mboe  65,355  62,063 
     
2017 F&D costs ($/boe)  $5.88  $5.01 
2016 F&D costs ($/boe)  $1.49  ($0.06) 
Three-year average F&D costs ($/boe)  $4.15  $3.11 

   
(1)  F&D costs are calculated by dividing total capital by reserve additions during the applicable period. Total capital includes both capital expenditures incurred and changes in FDC required to bring the proved undeveloped and probable reserves to production during the applicable period. Reserve additions is calculated as the change in reserves from the beginning to the ending of the applicable period excluding production. 
(2)  The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated FDC generally will not reflect total finding and development costs related to reserves additions for that year. Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capitalcost estimates that reflect Sproule's best estimate of what it will cost to bring the proved undeveloped and probable reserves on production. 
(3)  The change in FDC is primarily from incremental undeveloped locations. 

Source: EvaluateEnergy® ©2019 EvaluateEnergy Ltd