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Advantage Announces 2017 Year-End Reserves & Operations Update


Low Cost Reserve Additions and Record
2017 Production & Operating Performance

(TSX: AAV, NYSE: AAV)

CALGARYFeb. 12, 2018 /PRNewswire/ – 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 Valhalla land 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 Valhalla which 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 on March 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 Valhalla compressor 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 drilling times 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

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

4

23,057

1,697,959

306,062

Probable

1

8,711

594,258

107,757

Total Proved + Probable

6

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

2

14

Royalty Changes

(166)

(20,901)

(3,650)

Economic factors

6

(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

2

17

Royalty Changes

106

(15,929)

(2,549)

Economic factors

5

(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 capital cost 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.

 

Advisory
The information in this press release contains certain forward-looking statements, including within the meaning of the United States Private Securities Litigation Reform Act of 1995. These statements relate to future events or our future intentions or performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as “seek”, “anticipate”, “plan”, “continue”, “estimate”, “demonstrate”, “expect”, “may”, “can”, “will”, “project”, “predict”, “potential”, “target”, “intend”, “could”, “might”, “should”, “guidance”, “believe”, “would” and similar expressions and include statements relating to, among other things, Advantage’s expectation with respect to its liquid development, hedge positions, market diversification and low cost structure; the timing of when wells will be placed on restricted production and expectations as to when they will be produced unrestricted; timing of the installation of new infrastructure; the benefits associated with Advantage’s infrastructure; Advantage’s belief that its Glacier development will continue to be an industry leading North American low cost natural gas supply source; the expected timing of release of Advantage’s 2017 financial and operational results; estimated number of drilling locations; Advantage’s estimated fourth quarter and full year 2017 financial and operating results including production, royalties, operating costs, transportation cost, operating netback, capital expenditures and total debt including working capital; and Advantage’s focus on advancing its Montney natural gas and liquids development to generate long term attractive investment returns.  In addition, statements relating to “reserves” are by their nature forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future. The recovery and reserve estimates of Advantage’s reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Advantage’s actual decisions, activities, results, performance or achievement could differ materially from those expressed in, or implied by, such forward-looking statements and accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur or, if any of them do, what benefits that Advantage will derive from them.

These statements involve substantial known and unknown risks and uncertainties, certain of which are beyond Advantage’s control, including, but not limited to: changes in general economic, market and business conditions; industry conditions; actions by governmental or regulatory authorities including increasing taxes and changes in investment or other regulations; changes in tax laws, royalty regimes and incentive programs relating to the oil and gas industry; the effect of acquisitions; Advantage’s success at acquisition, exploitation and development of reserves; unexpected drilling results; changes in commodity prices, currency exchange rates, capital expenditures, reserves or reserves estimates and debt service requirements; the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas properties, including hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; changes or fluctuations in production levels; delays in anticipated timing of drilling and completion of wells; delays in completion of the expansion of the Glacier gas plant; individual well productivity; competition from other producers; the lack of availability of qualified personnel or management; credit risk; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; our ability to comply with current and future environmental or other laws; stock market volatility and market valuations; liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; ability to obtain required approvals of regulatory authorities; and ability to access sufficient capital from internal and external sources. Many of these risks and uncertainties and additional risk factors are described in the Corporation’s Annual Information Form which is available atwww.sedar.com (“SEDAR”) and www.advantageog.com. Readers are also referred to risk factors described in other documents Advantage files with Canadian securities authorities.

With respect to forward-looking statements contained in this press release, Advantage has made assumptions regarding, but not limited to: conditions in general economic and financial markets; effects of regulation by governmental agencies; current and future commodity prices and royalty regimes; future exchange rates; royalty rates; future operating costs; availability of skilled labor; availability of drilling and related equipment; timing and amount of capital expenditures; the impact of increasing competition; the price of crude oil and natural gas; that the Corporation will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that the Corporation’s conduct and results of operations will be consistent with its expectations; that the Corporation will have the ability to develop the Corporation’s properties in the manner currently contemplated; current or, where applicable, proposed assumed industry conditions, laws and regulations will continue in effect or as anticipated; and the estimates of the Corporation’s production and reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects.

Management has included the above summary of assumptions and risks related to forward-looking information above and in its continuous disclosure filings on SEDAR in order to provide shareholders with a more complete perspective on Advantage’s future operations and such information may not be appropriate for other purposes. Advantage’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Advantage will derive there from. Readers are cautioned that the foregoing lists of factors are not exhaustive. These forward-looking statements are made as of the date of this news release and Advantage disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

Barrels of oil equivalent (boe) and thousand cubic feet of natural gas equivalent (mcfe) may be misleading, particularly if used in isolation. Boe and mcfe conversion ratios have been calculated using a conversion rate of six thousand cubic feet of natural gas equivalent to one barrel of oil. A boe and mcfe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

This press release contains a number of oil and gas metrics, including F&D, operating netback, recycle ratio, EUR, reserve replacement and reserve life index, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Corporation’s performance; however, such measures are not reliable indicators of the future performance of the Corporation and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon. Management uses these oil and gas metrics for its own performance measurements and to provide securityholders with measures to compare Advantage’s operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment or other purposes. Operating netback is calculated by adding natural gas and liquids sales with realized gains on derivatives and subtracting royalty expense, operating expense and transportation expense. Recycle ratio is calculated by dividing Advantage’s fourth quarter operating netback by the calculated F&D of the applicable year and expressed as a ratio. Reserve replacement is calculated by dividing reserves net volume additions by the current annual production and expressed as a percentage. Reserve life index is calculated by dividing the total volume of reserves by the fourth quarter production rate and expressed in years. Reserves per share is calculated as the total volume of reserves divided by the number of common shares issued and outstanding at year end. Reserves per debt-adjusted share assumes the issuance of additional common shares at the closing trading price on the TSX necessary to extinguish outstanding debt at year end and is calculated as the total volume of reserves divided by the sum of the number of common shares issued and outstanding at year end and the debt at year end divided by the Corporation’s closing trading price on the TSX at year end.

The recovery and reserve estimates of reserves provided in this news release are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual reserves may eventually prove to be greater than, or less than, the estimates provided herein.

This press release discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the Corporation’s most recent independent reserves evaluation as prepared by Sproule as of December 31, 2017 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Corporation’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Corporation will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

The Corporation discloses several financial measures that do not have any standardized meaning prescribed under International Financial Reporting Standards (“IFRS”). These financial measures include total debt to trailing cash flow ratio and operating netback. Total debt to trailing cash flow ratio is calculated as bank indebtedness under the Corporation’s credit facilities plus working capital deficit divided by funds from operations for the prior twelve month period. Funds from operations is based on cash provided by operating activities, before expenditures on decommissioning liability and changes in non-cash working capital, reduced for finance expense excluding accretion. Operating netback is calculated by adding natural gas and liquids sales with realized gains on derivatives and subtracting royalty expense, operating expense and transportation expense. Management believes that these financial measures are useful supplemental information to analyze operating performance and provide an indication of the results generated by the Corporation’s principal business activities. Investors should be cautioned that these measures should not be construed as an alternative to net income or other measures of financial performance as determined in accordance with IFRS. Advantage’s method of calculating these measures may differ from other companies, and accordingly, they may not be comparable to similar measures used by other companies. Please see the Corporation’s most recent Management’s Discussion and Analysis, which is available at www.sedar.com and www.advantageog.com for additional information about these financial measures.

References in this press release to short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicitative of long-term performance, or of ultimate recovery.  Additionally, some rates may also include recovered “load oil” fluids used in well completion stimulation.  While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production of Advantage.

This press release and, in particular the information in respect of the Corporation’s expected 2017 operating costs, capital expenditures and total debt and operating netback, may contain future oriented financial information (“FOFI”) within the meaning of applicable securities laws. The FOFI has been prepared by management to provide an outlook of the Corporation’s activities and results and may not be appropriate for other purposes. The FOFI has been prepared based on a number of assumptions, including the assumptions discussed above, and assumptions with respect to the costs and expenditures to be incurred by the Corporation, capital equipment and operating costs, foreign exchange rates, taxation rates for the Corporation, general and administrative expenses and the prices to be paid for the Corporation’s production. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the FOFI or assurance that such operating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. The actual results of operations of the Corporation and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. The Corporation and management believe that the FOFI has been prepared on a reasonable basis, reflecting management’s best estimates and judgments. However, because this information is highly subjective and subject to numerous risks including the risks discussed above, it should not be relied on as necessarily indicative of future results. FOFI contained in this press release was made as of the date of this press release and the Corporation disclaims any intention or obligations to update or revise any FOFI contained in this press release, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law.

Certain financial and operating results included in this news release including production, operating costs, operating netback, capital expenditures and total debt including working capital are based on unaudited estimated results. These estimated results are subject to change upon completion of the Corporation’s audited financial statements for the year ended December 31, 2017, and changes could be material. Advantage anticipates filing its audited financial statements and related management’s discussion and analysis for the year ended December 31, 2017 on SEDAR on March 5, 2018.

The following abbreviations used in this press release have the meanings set forth below:

bbl

one barrel

bbls

barrels

bbls/d

barrels per day

bcf

bllion cubic feet

boe

barrels of oil equivalent of natural gas, on the basis of one barrel of oil or NGLs for six thousand cubic feet of natural gas

boe/d

barrels of oil equivalent of natural gas per day

mbbl

thousand barrels

mboe

thousand barrels of oil equivalent of natural gas

mcf

thousand cubic feet

mcfe

thousand cubic feet equivalent on the basis of six thousand cubic feet of natural gas for one barrel of oil or NGLs

mmcf

million cubic feet

mmbtu

million British thermal units

mmcf/d

million cubic feet per day

mmcfe/d

million cubic feet equivalent per day

tcf

trillion cubic feet

tcfe

trillion cubic feet equivalent

 

SOURCE Advantage Oil & Gas Ltd.

CONTACT: Craig Blackwood, Vice President, Finance and Chief Financial Officer, (403) 718-8005 OR Investor Relations: Toll free: 1-866-393-0393, Advantage Oil & Gas Ltd., 300, 440 – 2nd Avenue SW, Calgary, Alberta T2P 5E9, Phone: (403) 718-8000, Fax: (403) 718-8332, Web Site: www.advantageog.com, E-mail: ir@advantageog.com

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